Ecuador - INECEL Power Transmission Project

Document of The World Bank FOR OFFICIAL USE ONLY t tA Report No. 3340b-EC STAFF APPRAISAL REPORT ECUADOR INECEL POWER TRANSMISSION PROJECT June 23, 1981 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 Sucre (S/.) SI. 1.00 = 100 centavos = US$0.04 S/. 1,000,000 = US$40,000 US$1.00 = SI. 25.00 1/ US$1,000,000 = SI. 25,000,000 1/ US$ mill 1 = SI. 0.0250 1/ ACRONYMS CENAFE Centro Nacional Franco-Ecuatoriano CEPE Corporacion Estatal Petrolera Ecuatoriana CONADE Consejo Nacional de Desarrollo EEQ Empresa Electrica de Quito S.A. EMELEC Empresa Electrica del Ecuador Inc. FONAPRE = Fondo Nacional de Preinversion IDB Inter-American Development Bank IECO International Engineering Co. - U.S.A. INE Instituto Nacional de Energia INECEL Instituto Ecuatoriano de Electrificacion MRNE Ministerio de Recursos Naturales y Energeticos OLADE Organizacion Latinoamericana de Energia SNI Sistema Nacional Interconectado ABBREVIATIONS, UNITS AND MEASURES kcal kilocalorie (1,000 calories = 1.163 kWh) kW kilowatt Mw megawatt (1,000 kW) kWh kilowatt hour GWh gigawatt hour (1,000,000 kWh) kV kilovolt (1,000 volts) MVA megavolt-ampere (1,000 kVA) km2 kilometer (0.6214 mile) km square kilometer (0.386 sq. mi) ha hectare (0.01 km = 2.471 7acres) TOE = ton of oil equivalent (10 kcal) FISCAL YEAR INECEL's fiscal year ends December 31 1/ Commercial exchange rate as of March 31, 1981, which was used to compute currency equivalents in this report.  FOR OFFICIAL USE ONLY ECUADOR STAFF APPRAISAL REPORT INECEL Power Transmission Project Table of Contents Page No. 1. THE ENERGY SECTOR Energy Resources ...................................... 1 Energy Demand and Supply .............................. 1 Hydroelectric Resources ............................... 2 Hydrocarbons and other Fossil Fuels ................... 2 Non-Conventional Sources of Energy .................... 3 Energy Sector Organization ............................ 3 Fuel Prices .......... ................................. 4 Power Sector Organization ............................. 4 Power Sector Regulation ............................... 5 Existing Facilities ................................... 5 Bank Group Participation in the Power Sector .... ...... 6 Electricity Tariffs .................................... 6 Marginal Cost Studies ................................. 8 Constraints on Sector Development ..................... 8 2. THE BORROWER Organization and Management ........................... 9 Supervision of Electric Power Companies .... ........... 9 Staffing ............ .................................. 10 Training .............................................. 11 Procurement .......... ................................. 11 Accounting ........... ................................. 12 Auditing ............ .................................. 13 Insurance ........... .................................. 13 Dam Safety ........... ................................. 14 3. THE POWER MARKET The Present Power Market .............................. 14 The Future Power Market ............................... 15 Energy and Capacity Balances .......................... 17 Distribution Losses ................................... 17 This report is based on the findings of an appraisal mission which visited Ecuador during November 1980. The mission comprised Messrs. Jorge Larrieu and Ricardo Halperin. The report also draws on the findings of a sector mission (composed of Ms. Ursula Weimper and Messrs. Larrieu and Halperin) which visited Ecuador in July 1980. This documnent has a restricted distribution and ray be used by recipients only in the Performance of Jtheir official duties. Its contents may not otherwise be disclosed without World Bank authorization,  TABLE OF CONTENTS (Continued) Page No. 4. PROGRAM AND PROJECT Background ............................................ 18 Construction Program .................................. 18 Generation Expansion Program .......................... 19 Transmission Expansion Program ........................ 20 Subtransmission and Distribution Expansion Programs ... 20 Sector Investment Requirements ........................ 21 The Project ........................................... 21 Project Cost Estimates ................................ 22 Project Financing Scheme .............................. 24 Engineering and Consultants' Services .... ............. 24 Procurement and Disbursements ......................... 25 Project Execution ..................................... 25 Environmental Aspects ................................. 26 Project Risks ......................................... 26 5. FINANCE Introduction .......................................... 26 Financial History ..................................... 27 Tariffs and Rate of Return ............................ 28 Consolidated Investment and Financing Plan .... ........ 29 Future Finances ....................................... 31 Financial and Performance Indicators .... .............. 32 6. ECONOMIC ANALYSIS Least-Cost Solution ................................... 32 Return on Investment ................................... 33 Sensitivity Analyses .................................. 34 7. SUMMARY OF PROPOSED AGREEMENTS AND RECOMMENDATIONS .... 35  TABLE OF CONTENTS (Continued) LIST OF ANNEXES Page No. Annex 1 Power Sector Organization Table 1.1 INECEL's Participation in the Capital of the Electric Power Companies ............... - 38 Annex 2 Organization h Table 2.1 INECEL's Organization Chart .39 Annex 3 The Power Market Table 3.1 National and SNI Energy Forecast (GWh) 40 Table 3.2 National and SNI Demand Forecast (MW) 41 Table 3.3 SNI 1980-1990 Power Balance (MW) .42 Table 3.4 SNI 1980-1990 Energy Balance (GWh)-Average Year 43 Table 3.5 SNI 1980-1990 Energy Balance (GWh)-Dry Year 44 Table 3.6 1978 Gross Generation/Purchases, Sales and Losses (GWh) .45 Annex 4 Program and Project Attachment 4.1 Ongoing and Future Development Projects .46 Table 4.1 Ecuador's Installed Capacity (MW) .47 Attachment 4.2 Main Characteristics of Future Power Plants 48 Attachment 4.3 Single Line Diagram .51 Table 4.2 1980-1985 Investment Program .52 Table 4.3 Summary of Project Cost Estimates .53 Table 4.4 Estimated Loan Disbursement Schedule .54 Attachment 4.4 Project Implementation Schedule .55 Table 4.5 Performance Indicators ..... .................. 56 Annex 5 Finance Table 5.1 Consolidated Income Statements, 1978-1985 .... 57 Table 5.2 Consolidated Balance Sheet, 1978-1985 .... .... 58 Table 5.3 Consolidated Sources and Applications of Funds Statements, 1980-1985 .... ............ 60 Table 5.4 Construction Program, 1980-1985 .... .......... 61 Table 5.5 Schedule of Existing and Proposed Long Term Debt 62 Table 5.6 Forecast Long Term Loan Disbursement Schedule 63 Table 5.7 Forecast Long Term Debt Amortization Schedule 64 Table 5.8 Financial Indicators .65 Annex 6 Economic Analysis Table 6.1 Least Cost Solution .66 Table 6.2 Cost/Benefit Streams and Rate of Return on Investment .67 Table 6.3 Return on Investment-Sensitivity .68 Annex 7 Selected Documents and Data Available in the Project File 69 MAP  - A  1. THE ENERGY SECTOR Energy Resources 1.01 Ecuador has large reserves of hydrocarbons, significant hydro- electric resources and potential geothermal reservoirs. Hydrocarbons and hydroelectric energy are currently commercially exploited, while forests and vegetable wastes (charcoal and sugarcane bagasse) are the main non- commercial sources of energy. Energy Demand and Supply 1.02 Total output of primary energy has been adequate to meet domestic requirements and has provided ample exportable surpluses of crude oil. The table below illustrates the 1978 structure of primary energy output. Supply TOE x 10 1/ Primary energy output 10,752.3 Imports 152.7 Decrease in stocks 199.4 Total Supply 11,104.4 Demand Exports 7,514.8 Internal energy consumption: - Petroleum and derivatives 2,162.5 - Natural gas 2/ 31.6 - Vegetable fuels (firewood, sugarcane, bagasse) 693.9 - Hydroelectricity 54.4 2,942.4 Own consumption and transformation losses 647.2 Total demand 11,104.4 The National Energy Institute (INE) is currently preparing Energy Balance Forecasts, including actual figures for 1979 and 1980. Source: Mission estimates. 1/ TOE = ton of oil equivalent. 2/ Includes only the amount of liquified petroleum gas (LPG) produced from natural gas.  - 2 - 1.03 Between 1969 and 1978, commercial energy consumption 1/increased at an average annual rate of about 11%, from 872,000 TOE in 1969 to 2,220,000 TOE in 1978 and yearly energy consumption per capita doubled, from 0.15 TOE in 1969 to 0.29 TOE in 1978. In 1978, commercial energy consumption by sectors was as follows: transportation and fishing, about 60%; commerce and households, 23%; and industry, about 17%. About 97% of the total final commercial consump- tion was from hydrocarbon derivatives and 3% from hydroelectricity. Hydroelectric Resources 1.04 The hydroelectric potential is estimated to be 22,000 MW, mainly contained in the Pastaza, Santiago and Napo basins. If fully developed, the firm energy would be about 90,000 GWh/year (which if thermally generated would require more than 150 million barrels of oil per year). It is presently esti- mated that about 12,000 MW could be economically developed (based on prevailing international fuel prices). At present, only about 2% of this potential has been realized. The 1980-84 Development Plan has set as an objective the intensified development of hydroelectric resources, and by 1985 it is estimated that 72% of electricity requirements will be provided by this source, as compared with about 25% at present. Hydrocarbons and other Fossil Fuels 1.05 Sedimentary basins extend over an area of 17 million ha. In the seventies only limited new reserves were found, and the level of proven reserves decreased from about 1.6 billion barrels in 1972 to about 1.0 billion barrels in 1980. Addition to proven reserves thus is of the highest priority. The national development plan forecasts a 730-million-barrel increase in reserves over the 1980-84 period, 570 million from secondary recovery and 160 million from new fields. Current oil production amounts to about 220,000 barrels/day, which covers all of the country's requirements, estimated at about 75,000 barrels/day, and leaves a substantial balance for export. 1.06 Associated natural gas at the different oil fields is not available for power generation purposes. Currently, some gas is reinjected into the reservoirs to maintain field production conditions and the remainder is flared. By 1982, the gas now flared is to be processed at a new liquefaction plant (under construction at Shushufindi) and will be used for domestic consumption at major centers. The Corporacion Estatal Petrolera Ecuatoriana (CEPE) is presently evaluating the off-shore reserves at the gulf of Guayaquil. Con- siderable amounts of natural gas are expected to be available from this site. The Master Plan Studies (para. 3.04) will look into the use of gas for electricity generation purposes. 1/ Includes only final consumption of petroleum and hydroelectricity.  - 3- Non-Conventional Sources of Energy 1.07 Ecuador has favorable prospects for geothermal development. Super- ficial prospection surveys have detected geothermal activities in Tungurahua, Pichincha and Azuay. The Ecuadorean Electrification Institute (INECEL), the Borrower of the proposed loan, has undertaken the responsibility for evaluating the geothermal potential and in the first stage, presently in execution, has received technical assistance from the Latin American Energy Organization (OLADE). A preliminary report, which includes the results of these prospects, is currently under preparation. 1.08 In rural areas, fuel-wood is an important source of energy. The country has important forestry resources, mainly in the Amazonas region and in the province of Esmeraldas. However, the lack of a reforestation policy and the indiscriminate use of wood for industrial and energy purposes has reduced considerably the forest area, and rural areas are facing shortages of fuel-wood. The National Energy Institute (INE) is attempting to address the problem through the development of improved wood-fueled cooking stoves. 1.09 The possible use of solar energy, windpower, and other non- conventional sources is being studied by INE. In addition, OLADE is promoting the construction of biodigestors, in which animal and vegetable waste is converted into methane. A demonstration plant has been built jointly with the Provincial Council of Pichincha and OLADE is also providing technical assis- tance to other provinces for similar purposes. Energy Sector Organization 1.10 National economic planning is performed by the National Development Council (CONADE), which has prepared a National Development Plan for 1980-84. This plan, mandatory for public sector institutions, is intended to help ensure the coherence in investment programs in all areas of the economy. It is to be reviewed each year. 1.11 The Ministry of Natural and Energy Resources (MRNE) is the executing and controlling agency for national energy policy. Under its jurisdiction are INECEL, CEPE (a public sector corporation through which the Government participates in the petroleum industry 1/), and INE, a research institute created in 1978 which is presently assessing Ecuador's energy resources, developing energy balances, and evaluating alternative energy technologies. 1.12 The present organization is satisfactory and results in a reasonable level of decentralization of decision making, while also generally ensuring the coordination of the policies implemented by the respective executing agencies. However, there are some problems. MRNE is relatively poorly staffed and has experienced high personnel turnover, and CEPE has faced both organizational 1/ Several foreign oil companies also operate in Ecuador, in exploration, production and refining. The Government has recently developed new contractual formulas which are expected to attract increased foreign participation in exploration activities.  - 4 - strains as well as conflicts of authority with MRNE and of coordination with other agencies. This situation has been improving recently, and the problems discussed are not expected to affect the proposed project. Fuel Prices 1.13 Until early 1981, the prices of petroleum products in Ecuador were among the lowest in the world. In 1980 the implicit subsidy to consumers, given by the difference between internal and world market prices, represented an amount estimated to be close to 8% of GDP. 1.14 In the 1980-84 National Development Plan, the Government explicitly stated that it would adjust the prices of hydrocarbons, and some increases (for jet fuel and for fuel oil for ships) were approved in early 1980. Subsequently, a new "high test" gasoline was introduced at a price of US$0.73 per gallon (regular gasoline was then selling at US$0.19 per gallon) and in early 1981 the price of all petroleum products was increased, in some cases, such as regular gasoline, by over 200%. Present retail prices approxi- mately average 55%-60% of the wholesale prices in the Caribbean. 1.15 The retail prices of fuels used for electricity generation (mainly Bunker C and diesel) had in 1980 been at level which was 13% to 16% of the world market, and this represented a hidden subsidy to power consumers that exceeded US$100 million a year (roughly equivalent to the value of sector billings). These prices have now also been increased, and currently repre- sent 36% to 42% of prevailing world market levels. Agreement was reached that these prices will be periodically increased so that in 1984 they represent not less than 50% of the world level then prevailing. 1.16 At present the prices for fuels used for electricity generation are sufficiently high to ensure that there is no waste, and that hydro generation is fully utilized while auto-generation is discouraged. Power Sector Organization 1.17 Ecuador's 1961 Electricity Law establishes that the Government, through INECEL, has the monopoly on electricity generation, transmission and distribution, but is empowered to authorize private operations. At present there is only one privately owned company: the Electric Company of Ecuador, Inc. (EMELEC), which operates in Guayaquil under a municipal concession. The contract expires in 1985, after which time the municipality of Guayaquil may -- by first giving appropriate advance notice -- purchase at a fair price the company's facilities. The other 14 power companies are organized as private corporations, with INECEL as the largest shareholder and the balance of shares owned mainly by the local municipalities. In a few cases, there are also individual private shareholders, who own very small participa- tions. Thus, whether in use of its regulatory powers (para. 1.19) or as a majority stockholder, INECEL has the ability to substantially control the activities of all the power companies in the country. Annex 1, Table 1.1, shows INECEL's participation in the capital of each power company. In addition to these companies, INECEL also directly operates two small power systems and 42 municipalities operate small local power installations.  - 5 - 1.18 The organization described above represents a considerable improve- ment over that which prevailed in 1961, when more than 100 companies were in operation. INECEL plans to continue the process of merging and consoli- dating the local power systems, by forming regional companies. This develop- ment is highly desirable as most of the power companies presently face signifi- cant diseconomies of scale. INECEL's present goal is to consolidate all electric services now being provided by the 14 power companies it controls in 10 regional companies. At negotiations, agreement was reached that this will be done by December 31, 1984. Power Sector Regulation 1.19 The Ministry of Natural and Energy Resources is responsible for the formulation of national electrification policy, while INECEL is responsible for power sector regulation and supervision. All power companies are required to submit their capital budgets to INECEL, inform INECEL about external bor- rowing plans, allow INECEL to inspect their facilities and audit their records, and abide by the regulations INECEL's Board approves. INECEL's regulatory performance is discussed in paragraphs 2.04 through 2.06. Existing Facilities 1.20 Ecuador's installed power generating capacity (December 1979) is about 924 MW, of which 700 MW, or 76% of the total, is thermal capacity; the balance is hydroelectric. About 520 MW, or 56% of the total installed capacity, are currently interconnected through the 230 kV Quito-Guayaquil transmission line and the 69/34.5/22 kV Quito-Latacunga-Riobamba-Ambato subtransmission network. Present public service supply (through INECEL, its subsidiaries, EMELEC and municipalities), accounts for about 84% of total power supply. Private generation (self-producers, mostly industrial and agricultural undertakings) accounts for the remaining 16% (about 153 MW capacity, of which 141 MW are diesel generators and 12 MW are hydroelectric plants). A summary description of these installations is shown in the following table (see also Annex 4, Table 4.1). Internal Oil-fired Combustion Steam Plant Hydro Total Gas Turbines Diesel Public Service 173.8 249.4 136.0 212.5 771.7 Self-Producers - 140.6 - 12.1 152.7 Total Ecuador 173.8 390.0 136.0 224.6 924.4  - 6 - Bank Group Participation in the Power Sector 1.21 The Electric Company of Quito (EEQ) has been the main recipient of Bank Group funds within Ecuador's power sector. The first two Bank opera- tions (in 1956 and 1957) helped to finance the 40-MW Cumbaya hydroelectric project, several diesel plants, and extensions of the distribution systems (these works were completed by the end of 1961 and have been operating satis- factorily). 1.22 IDA Credit 286-EC for US$6.8 million was approved in 1972 and covered part of the foreign exchange costs of the 30-MW Nayon hydroplant, *an 18-MW diesel power station, transmission lines, and rural electrification. The PPAR (No. 3003, issued in May 1980) concluded that: (a) the physical objectives of the project were met, albeit with delays and cost overruns; (b) progress towards the institutional objectives of the project was disappointing; (c) most of the covenants related to the financial aspects of the institution were not met; and (d) lack of cooperation adversely affected the effectiveness of IDA supervision efforts, which, however, would also have required more frequent field supervision than actually took place. These lessons were kept in mind when outlining the conditions for the proposed project, even though the proposed borrower is a different entity. 1.23 The only other financing provided by the Bank to the sector has been through Loan S-006-EC to FONAPRE, for the Master Plan studies and the feasibility study of the Paute-Mazar hydro-development which are currently under way (para. 4.01). Electricity Tariffs 1.24 The regulations governing electricity tariffs were approved by decree in 1975 and are based on sound financial criteria. Essentially, they give INECEL the power to set tariffs at a level that allows electric power companies to recover costs and make a reasonable profit, so that they may enjoy a satisfactory financial situation and provide service efficiently. 1.25 To achieve this objective, the regulations authorize electric power companies to achieve a rate of return of 8.5% on a rate base defined as the replacement cost, net of depreciation, of fixed assets in operation plus estimated working capital needs. Annual rate of return surpluses (or deficits) over the 8.5% figure are to be registered in a stabilization account and if surpluses or deficits occur in three consecutive years, tariffs should be revised.  - 7 - 1.26 The regulations also establish a system of tariff adjustments due to cost variations. Automatic adjustments are made when unit labor costs, unit electricity purchase costs, or unit fuel costs vary between 5% and 10% over the level used to determine the existing tariff levels. When the unit costs mentioned above vary by more than 10%, adjustment must be approved by INECEL's Board. 1.27 For political reasons, the regulations were never implemented, which accounts for the financial difficulties faced by the sector (paragraphs 5.01 to 5.04). None of the electric power companies revalued its assets in the manner prescribed, nor were tariffs periodically adjusted in the manner required to achieve the 8.5% rate of return. In this respect, it should be noted that INECEL's Board is controlled by the Government. Subsequent to the fuel price increases implemented in early 1981 (para. 1.13), INECEL's Board approved a policy of monthly tariff increases averaging 3%. At negotiations, agreement was reached that these increases will remain in force until the agreed rate of return targets are achieved. Failure to implement these increases as agreed would be an event of default. Before the loan is declared effective, the Bank will seek confirmation that INECEL is fulfilling its tariff increase commitments. 1.28 The tariff levels and tariff structures of the 15 companies in the sector vary considerably. In 1979, the average sector tariff was US$ mills 44/kWh; however, four systems (including the large EMELEC system and the Latacunga system, directly operated by INECEL) had average tariffs below US$ mills 40/kWh and, in one of these (Riobamba), the average tariff was US$ mills 28/kWh. In contrast, six systems had average tariffs exceeding US$ mills 56/k.wh. The national development plan for 1980-84 sets as a policy goal the attainment of a uniform tariff structure for the national interconnected system, and the 1980 tariff structure changes (para. 1.30) are a modest step in this direction. 1.29 It should be noted that, with the present sector organization, the achievement of a national tariff structure will be a difficult goal to reach. This is because the cost structures of the different power companies differ considerably; while some companies like EEQ and EMELEC operate in predominantly urban areas, where population is heavily concentrated and industry has a significant weight, others operate over larger territories, where popula- tion is dispersed, average income is low, and industrial demand is not signifi- cant. Thus, a mechanism would be required to transfer funds between companies so as to allow them all to meet financing requirements and rate of return targets. At negotiations, agreement was reached with INECEL that it will submit to the Bank, not later than September 30, 1981, a specific proposal (including main operational characteristics and target dates for implementation) for implementing this mechanism; discuss it with the Bank, and put it into operation.  -8- 1.30 The tariff structure prevailing through 1979 encouraged electricity use by establishing an inverse relationship between demand level and unit prices. In 1980 this was changed and, for the residential sector, there are now lower rates for demands below 70 kWh per month and higher (constant) rates when consumption exceeds this figure. Furthermore, rates for residential demands of 70 kWh per month or less are to remain unchanged for a period of three years, as part of the Government's incomes policy. In view of its social objectives, this is justified; however, both the cut-off level of 70 kWh and the rate level should be reviewed when tariff structures are revised (para. 1.32). For commercial and industrial users, the rate structure still favors the larger consumers. This, too, should be reviewed once the marginal cost studies are completed. 1.31 The above analysis and the financing problems faced by the power sector (discussed in Chapter 5) indicate that strong action in the tariff field is required. Such action involves: (a) significantly increasing average tariff levels (para. 5.03), (b) further changing tariff structures so as to bring them in line with true economic costs (para. 1.32), and (c) reducing the present tariff disparities between the various electric power companies (paragraphs 1.28 and 1.29). Marginal Cost Studies 1.32 As part of the Master Plan studies, INECEL's consultants' will prepare an analysis of the marginal cost of electricity generation. At negotiations, agreement was reached that INECEL would furnish to the Bank, no later than October 31, 1982, the results of the study, together with INECEL's own comments and proposals for a comprehensive marginal cost study, which will enable it to revise its structure of retail rates for the sale of electricity and would provide grounds for a review of the financial rate of return requirement, if and when future projects are brought for Bank consideration. Constraints on Sector Development 1.33 The Government has set ambitious goals for the power sector, aiming to substantially replace thermal generation and simultaneously significantly increase access to service. These goals are reflected in the 1982-85 consoli- dated investment program for INECEL and its subsidiaries (para. 5.13), which results in total financing requirements of about US$1.8 billion. The success- ful implementation of this program requires a major funding effort, which includes tariff increases, large amounts of Government equity contributions and sizeable external borrowings. Failure to perform as required in any of these areas will, in all likelihood, result in program implementation delays. In view of the political difficulties associated with increasing tariffs and of the budgetary problems faced by the Government, the risk of such delays should not be underestimated. 1.34 While, as indicated above, the financial issues are presently the most serious ones faced by the sector, other matters of pressing concern are the continuance of fuel subsidies, which distort resource allocation inducing excessive consumption and waste, and the relatively weak control hitherto exercised by INECEL over the activities of the other power companies, which ;s evidenced in poor coordination and in inefficiency. The remedies for these issues involve, in the last instance, difficult political decisions, and, to rtho extent that these are not implemented, present problems will continue.  1.35 To minimize the above risks, the Government and the Bank have been engaged in a prolonged dialogue, which resulted in the implementation of some significant measures (paragraphs 1.14 and 1.27) thus minimizing the difficulties of meeting the loan covenants, once the loan becomes effective. 2. THE BORROWER Organization and Management 2.01 The Borrower of the proposed loan would be INECEL, an autonomous entity of the Government of Ecuador. INECEL was founded in 1961 and is responsible for assessing national power resources, planning power sector expansion, constructing and operating generation and transmission facilities, supervising the other companies in the power sector, and approving tariffs for the sale of electricity. INECEL also owns a major participation in 14 of Ecuador's 15 electric public utilities and directly operates two small local systems. 2.02 INECEL is governed by a Board of Directors presided by the Minister of Natural Resources and Energy. Other board members are the Minister of Finance, the Minister of Industry, the representative of the President of CONADE, the Chief of the Joint Command of the Armed Forces, and one represen- tative from each of the following: the other power companies, the Association of Electrical Engineers, and the power sector workers. Responsibility for day to day operations is delegated to the General Manager, who is assisted by six operating managers. 2.03 INECEL's organization chart is shown in Annex 2, Table 2.1. Although the organization structure is basically reasonable, INECEL faces management problems. Some of these are caused by lack of qualified staff, notably in finance, others by inadequate coordination between the various departments, which operate with a considerable degree of autonomy. Furthermore, the number of operating and staff units directly reporting to the General Manager is high, probably placing excessive demands on his time and on his ability to supervise them adequately. To address these problems, and also to assist INECEL in the upgrading of its information systems, evaluation of data process- ing requirements and conciliation of budgetary and accounting data, the proposed loan would finance consultant services for an organization study and formulation of a program of institutional improvements. Draft terms of reference for this study have already been agreed upon. At negotiations, agreement was reached with INECEL that it will engage the consultants no later than December 31, 1981, will discuss the recommendations of the study with the Bank, and will implement such recommendations as have been mutually agreed upon. Supervision of Electric Power Companies 2.04 Through its Marketing and Distribution Department, INECEL supervises the operations of the electric power companies. The Department's main func- tions involve setting up standards for works and supervising the technical aspects of the companies' operations and maintenance as well as their manag- erial performance. These activities require seeing that norms instituted by INECEL are properly applied and that the work of INECEL's representatives at the subsidiaries' Boards of Directors is properly coordinated.  - 10 - 2.05 Though the Electricity Law vests sector regulatory powers in INECEL (para. 1.19), in practice INECEL's subsidiaries have tended to operate with a large degree of autonomy. Furthermore, despite the fact that INECEL holds the voting power majority in each of the subsidiaries' Boards, it has seldom made its presence felt; on the other hand, the minority Board members, which represent the municipalities in which the subsidiaries operate, have carried a disproportionate weight in decision making, often introducing political con- siderations. This may help to explain some of the management problems which many of these subsidiaries face and which INECEL has had limited success in solving. 2.06 Currently, INECEL's management is striving to shape up its super- visory role. New staff have been appointed to key positions, meetings have been held with the subsidiaries' managers, and minimum periodic information requirements have been set up. The organizational and institutional improve- ments study included in the proposed project, would also look into INECEL's supervisory performance and provide recommendations for its improvement. However, since this study will require a long time to complete 1/, at nego- tiations agreement was reached with INECEL that it would submit to the Bank, an interim program--to be implemented at the earliest and monitored during project supervision--which would include the upgrading of periodic reporting by the subsidiaries, mechanisms for more frequent contact between INECEL's management and those of its subsidiaries, closer evaluation and control of the subsidiaries' capital budgets, and assignment of increased responsi- bilities to INECEL's directors at the subsidaries' boards. That a satis- factory program had been submitted would be a condition of loan effectiveness. Staffing 2.07 At present, INECEL employs about 2,400 people, 500 of whom have professional degrees (nearly 400 of these are engineers, mainly civil and electrical engineers) and has forecast that it will employ about 3,500 people by 1985, which implies an annual growth rate of 8%. INECEL's subsid- iaries employ an additional 3,700 people, and this number would increase at approximately the same rate as INECEL's own staff. It would presently appear that, both in INECEL and in the subsidiaries, there are areas that are over- staffed. For this reason, the performance indicators which were agreed upon at negotiations, reflect a slower pace of growth in employment than INECEL's present forecasts. Furthermore, it has been agreed with INECEL that the organizational and institutional improvements study will address this issue and identify the specific areas that have an excess of personnel so that corrective action may be taken. 2.08 The salaries of INECEL's administrative staff are tied to the public administration structure. Workers are affiliated with several craft unions, each of which bargains separately, and the labor contracts usually run 1/ The first phase of the consultants' work would comprise an evaluation of INECEL's policy making role and control activities and information flows from the subsidiaries. This phase would take about 18 months to be completed.  - 11 - for about two years. Labor relations are generally good and labor disputes not frequent. Salary levels, supplemented by abundant fringe benefits, are adequate and generally competitive with those offered by the private sector. Salary increases are a function of merit and of seniority. Training 2.09 INECEL has established an important and active Training Department which has, over the past seven years, developed a good, if somewhat central- ized, training system. Training services (oriented mainly to technicians and workers in the operational and maintenance areas of the utilities) are avail- able to, and are widely used by, the staff of INECEL and of its subsidiaries. The training system is based upon sound principles and benefits from executive management commitment and support. The following features of the system are indicative of the manner in which training services have been developed and are now being routinely provided. (a) INECEL operates a well established residential training center (French-Ecuatorian National Center, CENAFE, with a present capa- city of 100 trainees), with competent staff and adequate facilities; (b) an annual policy statement on workforce and training is updated and circulated each year; (c) regular workforce planning and forecasting for the complete sector is undertaken as a corporate management exercise; and (d) an annual program is issued to all regional utilities, detailing the training programs to be offered at CENAFE and approved programs of education and training available in Ecuador and externally (for which grants are available). 2.10 The successful implementation of the sector development program and of the managerial and administrative reforms expected to be proposed by the organization and institutional improvements study will require an intensive training effort, which should also include management training. To this end, INECEL and the Bank have agreed to include as part of the proposed project a training component, which would comprise an in-depth evaluation of INECEL's training programs (to be carried out by external consultants whose qualifications and terms of reference are satisfactory to the Bank); specific training programs recommended by the consultants and agreed to by INECEL and the Bank; and training equipment. The draft terms of reference for these consultants have already been agreed with the Bank. At negotiations agreement was reached that these consultants will be hired no later than December 31, 1981. Procurement 2.11 INECEL's procurement procedures are governed by a national procure- ment law. The law's provisions have been found to be, by and large, reasonable though restrictive interpretations sometimes cause excessive delays. To prevent problems in this area, agreement on the contents of the bidding documents for the purchase of equipment and materials for the project has already been reached  - 12 - and the draft documents have been submitted for review by the Bank, and found satisfactory. During negotiations it was also agreed that the Government of Ecuador will take such actions as may be required to expedite procurement authorizations and clearances as to avoid implementation delays. Accounting 2.12 The quality of INECEL's financial statements is extremely poor be- cause of the lack of importance hitherto attached to such information, department head changes, old fashioned recording systems and absence of competent staff. Contributing factors too, have been the insufficient attention given to internal auditing and the delays of the Contraloria General's external auditing interventions, which have limited their usefulness. INECEL is trying to address this issue, and in 1980 it engaged additional qualified staff for its internal auditing unit, which is progressively increasing the scope of the work it carries out. The training programs proposed (para. 2.10) are expected to address the needs of the internal auditing unit. 2.13 The main problems of INECEL's accounting systems and policies are: (a) INECEL does not prepare consolidated financial statements, even though its participation in each of the subsidiaries' capital stock ranges from 54% to 99%. This participation is shown as an invest- ments, at historic cost. Profits (or losses) earned by the subsid- iaries are not recognized, unless collected through dividends; and (b) Fixed assets are shown at cost, despite legal provisions which require their annual revaluation. Other problems arise from the poor quality of some of the figures and from the excessive time taken to produce reports. 2.14 To address these problems, at negotiations agreement was reached with INECEL that it will: (a) implement measures so that it may submit fully consolidated financial statements for 1983, and on interim consolidation targets for 1981 and 1982; (b) revalue its fixed assets annually, and engage qualified experts, not later than December 31, 1981, on terms of reference acceptable to the Bank, to design recording systems such that future fixed asset inven- tories would be up to date and to fully inventory its fixed assets and assess their replacement value, and (promptly upon the receipt of the valuation report) to reflect such valuation in its records and financial statements; and (c) reflect a provisional revaluation 1/ of fixed assets in operation on the basis of inflation indices in the 1980 financial statements. 1/ Until replacement values have been assessed and agreed with the Bank.  - 13 - 2.15 Since the consolidation of financial statements requires that INECEL's subsidiaries submit in time financial statements of satisfactory quality (which at present most cannot do), at negotiations agreement was reached with INECEL that it will furnish to the Bank its programs to achieve this goal in each subsidiary, as per an agreed schedule. The programs should identify the accounting problems faced by each subsidiary, and should propose specific measures to address them. Furthermore, since the asset valuation problem (para. 2.13) is also applicable to INECEL's subsidiaries, at negotiations agreement was reached that INECEL will cause each of its sub- sidiaries to revalue its fixed assets in the same manner as INECEL, per an agreed timetable, and would assist them and supervise them in this exercise. 2.16 The organization and institutional improvements study is to also address the operating problems of the accounting area, particularly data processing and staffing. Auditing 2.17 INECEL's financial statements are presently audited by the Contraloria General de la Nacion, a specialized government agency. Due to the Contraloria's lack of staff, the issuance of the audited statements has been frequently, and seriously, delayed. For instance, the 1978 and 1979 audited statements only became available in January 1981. Furthermore, the scope of the audit does not meet Bank requirements. It has therefore been agreed with INECEL that it will engage private external auditors. At negotiations, it was also agreed that calls for bids would have been issued, and bids evaluated, as a condition of loan effectiveness and that actual engagement would take place not later than March 31, 1982. 2.18 INECEL's subsidiaries are organized as private corporations. Only one, EEQ, has private external auditors. The others are supposed to be audited by the Contraloria, but this only happens in a limited number of cases. Since, as indicated earlier, most of the subsidiaries have significant problem's in their accounting systems, it is imperative that a major improvement effort be made, if consolidated financial statements are to be produced. Thus, in addition to the measures listed in para. 2.15, at negotiations it was agreed that INECEL will cause each of its subsidiaries to engage independent external auditors, by agreed dates. Insurance 2.19 INECEL follows the practice of externally insuring its assets against major risks, such as fire, explosion, hurricanes, tornadoes and flooding. As far as feasible, the insurance policies are based on estimated replacement values. These practices are acceptable and consistent with Bank requirements. At negotiations, agreement was reached to include the standard insurance clause in the loan agreement for the proposed project. Over the past 12 months, INECEL has set up an insurance division and this is already resulting in substantial economies in insurance costs, which previously were too high.  - 14 - Dam Safety 2.20 INECEL is currently completing construction of the Paute-Amaluza dam (one of the highest arch dams in the world). The successful operation of the facilities included in the proposed Bank project would be closely linked to the adequate operation of the Paute hydroelectric development (para 4.07 and Annex 4, Attachment 4.2). It has therefore been agreed with INECEL that the Paute-Amaluza dam will be monitored and inspected at least once a year by qualified and experienced experts and that a copy of the inspection report would be submited to the Bank. 3. THE POWER MARKET The Present Power Market 3.01 During the period 1970-78 Ecuador substantially improved its electrification level as shown by the indicators below: Year Capacity installed/ Consumption/ Electrification inhabitant inhabitant Rate (%) 1970 51 watts 155 kWh/year 28 1975 74 watts 266 kWh/year 32 1978 122 watts 333 kWh/year 38 Despite this favorable trend, per capita installed capacity, energy consumption and access to electricity are among the lowest in South America. 1/ 3.02 Ecuador's electric public utilities (INECEL, its subsidiaries, EMELEC, and 42 small municipal systems) currently supply electricity to about 622,000 customers, representing about 3,200,000 inhabitants. In 1978, total electricity sales amounted to 2,182 GWh, of which about 43% were sold to the Guayaquil area by EMELEC and about 29% to the Quito area by Empresa Electrica de Quito, while INECEL's other subsidiaries and municipalities accounted for the remaining 26.5% and 1.5% respectively. 3.03 Total electricity sales in Ecuador have increased steadily at an average annual rate of over 13%, from 791 GWh in 1970 to 2,182 GWh in 1978 (see Annex 3, Table 3.1). Simultaneously, maximum demand has increased from 224 MW in 1970 to 565 MW in 1978 (see Annex 3, Table 3.2), at an annual average rate of about 12%. Ecuador's 1978 total electricity generation and sales were as follows: 1/ Consumption per capita and electrification rates of some other South American countries are respectively: krgertina, 1,236 kWh and 800%; Brazii, 912 kWh and 62%; Chile, 927 kWh and 87%; Colombia, 621 kWh and 62%; Peru, 523 kWh and 35%; and Uruguay, 1087 kWh and 80%.  - 15 - Category C%n 7 of Total Generation Residential 792 30.7 Commercial 300 11.7 Industrial 864 33.6 Public Lighting and Others 226 8.8 Total Sales 2,182 84.8 Transmission and Distri- bution Losses 392 15.2 Total C-eneration 2,574 100.0 The Future Power Market 3.04 INFCFL, with the assistance of consultants (Lahmayer - Germany and -idroservice - Brazil), is currently preparing the National Electrification Master Plan Studies, with Bank financing through Loan S-006-EC (para. 1.23). One of the main objectives of these studies has been the assessment of the future power market. The load forecast recently completed was developed after an evaluation of alternative projection methodologies: extrapolation of historical consumption trends, correlation with macro-economic indicators and regionalized and national forecasts by sectors. Based on a detailed analysis of the results obtained by using these different methods, INECEL, in consultation with the Bank, decided to adopt the national load forecast by sectors. 3.05 Ecuador's total electric energy requirements, including transmission and distribution losses, are expected to increase from 2,574 GCh in 1978 to 5,600 GWh in 1985 at an average annual growth rate of about 11.7%. 1/ Maximum demand is expected to increase from 565 MW in 1978 to 1,232 MW in 1985 at an average annual growth rate of about 11%. The generation system load factor (non-coincidental peak demand) is expected to improve from 50.5% in 1978 to 51.87 in 1985. Details of the energy and power demand forecasts are given in Annex 3, Tables 3.1 and 3.2. 1/ This growth is in line with Ecuador's economic projections, as out- lined in a Bank's country study of July 1979 (Ecuador: Development Problems and Prospects), and with the macroeconomic forecasts contained in the national five year development plan.  - 16 - 3.06 Specific components of projected 1985 aggregate demand and load growth rates are as follows: Category GWh 1978-85 Growth Rate (%) Domestic 1,757 12.1 Commercial 691 8.6 Industrial 2,071 13.3 Public Lighting and Others 403 8.6 Total Sales 4,922 12.3 Transmission and Distri- bution Losses 677 8.1 Total Generation 5,599 11.7 3.07 The structure of electricity consumption is not expected to change considerably during the period 1978-85; the share of industrial consumption is expected to increase from 34% in 1978 to 37% in 1985, and losses and power station use are expected to decrease by 3% from 15% in 1978 to 12% in 1985. It is reasonable to expect such reduction in energy losses and power station use as: (i) the bulk of the energy will be transferred through- high voltage lines (230 kV and 138 kV); (ii) existing subtransmission and distribution systems are expected to be improved; (iii) INECEL and its subsidiaries are expected to improve the existing methods of energy monitoring and theft control (para. 3.11); (iv) power station use at thermal plants (which accounts for the bulk of this item) is expected to be reduced substantially, as the National Interconnected System's thermal generation requirements will decrease once the Paute hydro-development becomes operational (para. 4.07). The remaining categories are expected to remain basically unchanged. The following table illustrates the structure of electricity consumption by categories: Category % of Total Generation 1978 1985 Residential 30.8 31.4 Commercial 11.7 12.3 Industrial 33.5 37.0 Public Lighting and Others 8.8 7.2 Losses and Power Station Use 15.2 12.1 Total 100.0 100.0 3.08 The analysis carried-out by INECEL and its consultants to determine the sales forecast was comprehensive, and reflects well substantiated trends. The results were reviewed by the Bank and found adequate. The forecasts are consistent with: (i) the probable effect on the consumption pattern  - 17 - of the proposed tariff increases (para. 5.03); (ii) the considerable reduction of electricity generation by auto-producers due to the increase of internal fuel prices (para. 1.15); and (iii) the expected increase in the numbers of consumers. Energy and Capacity Balances 3.09 Based on the market requirements, existing power availability, and the future power development program, system simulation studies were conducted for yearly power and energy allocations during dry (critical) and average precipitation year conditions. Results of these simulations are shown in Annex 3, Tables 3.3, 3.4 and 3.5. 3.10 The simulation studies were used to: (a) determine the commissioning dates of new power plant additions (a new power plant was added to the system when a deficit in peaking capability and/or energy supply occurred; each power plant was pre-selected based on optimization studies, and the generation program was determined using economic criteria and international fuel prices); (b) evaluate probable yearly generation from individual power plants; and (c) derive adequate margins of generation reserves (varying from 20% in 1983 to 5% in 1986, according to system operational characteristics). The selected (least-cost) 1980-1995 expansion program consists only of hydroelectric power schemes. The analysis carried out to define the energy and power balances was comprehensive and based on adequate hypotheses; the premises, assumptions and results of these studies are satisfactory. Distribution Losses 3.11 In 1978, INECEL's subsidiaries' distribution losses (including theft and unaccounted) amounted to nearly 200 GWh, representing about 15% of the utilities' gross generation plus energy purchases. Some subsidiaries have reached unacceptable loss levels (up to 35% in the case of the Latacunga and Azogues utilities), mainly due to inadequacies of their distribution systems and deficiencies of their recording methods. Information on losses by company is given in Annex 3,Table 3.6. During negotiations agreement was reached with INECEL that it will: (a) engage consultants no later than December 31, 1981 (under terms of reference acceptable to the Bank) to carry out a study to improve the overall efficiency of the subsidiaries' distribution systems (including review and standardization of current distribution planning, construction and operational practices, improvement of existing distribution systems, and measures to reduce theft); (b) discuss the conclusions and recom- mendations of the consultants with the Bank; and (c) implement such recommenda- tions as have been agreed upon with the Bank, per an agreed timetable.  - 18 - 4. PROGRAM AND PROJECT Background 4.01 INECEL, with the assistance of consultants financed by Loan S-006-EC (para. 1.23), is currently preparing a National Electrification Master Plan, designed to: (a) assess Ecuador's future power market; (b) select the least-cost program for power generation expansion based on hydroelectric, geothermal and conventional thermal developments; (c) optimize transmission and distribution systems expansion; and (d) formulate the investment programs required to execute and implement the foregoing works. 4.02 The Master Plan studies are being developed in three stages: short- term (1978-85), medium-term (1985-92) and long-term (1992-2000). The following studies are also included under the Master Plan: (a) inventory of Ecuador's hydroelectric 1/ and geothermal 2/ resources, which will collect existing information and will create new information banks containing carto- graphic, hydrological and geological data, as well as information regarding the development stages of hydroelectric sites (identification, evaluation, prefeasibility, feasibility and detail design studies); and (b) development of an Integrated Planning System which will optimize the hydro/geothermal power plants (identified in the inventory of hydro/geothermal resources) and their installation sequence. 4.03 The short-term (1978-85) Master Plan studies have already been completed and the draft reports were found to be adequate. The medium-term and long-term Master Plan studies are currently progressing satisfactorily and draft reports are expected to be available from December 1981 to February 1982. Construction Program 4.04 The main objectives of INECEL's construction program are to: (a) meet the different regional systems' power requirements through the addition of new generating capacity; (b) integrate all of INECEL's subsidiaries and some municipal systems to the National Interconnected System (SNI) through a new 230/138 kV transmission network in order to achieve fuel economies and increase efficiency; and (c) provide electricity to an additional 1,500,000 inhabitants (about 250,000 new customers) through the construction of new sub- transmission and distribution systems. The proposed Bank project would contribute to the achievement of these objectives by: (a) delivering the 2 1/ The inventory is expected to cover about 225,000 km , or about 70% of Ecuador's surface area, and about 80% of Ecuador's estimated hydro- electric potential. Only hydroelectric schemes larger than 30 MW are to be included. 2/ The inventory of geothermal resources, originally to be financed by the Bank, is now being financed through a grant from OLADE.  - 19 - hydroelectricity to be generated by the existing and proposed hydropower plants to the different load centers; (b) incorporating the different isolated systems to the SNI network; and (c) improving INECEL's management and staff skills through comprehensive training programs and assistance from consultants. 4.05 In order to meet energy and power capacity requirements during the period 1980-90, INECEL and its subsidiaries have prepared generation, trans- mission and distribution 1/ construction programs which are based on detailed analyses of the capability of existing generation and transmission facilities and of facilities being added to the existing system and on the results of the short-term Master Plan optimization studies. 4.06 The construction program includes the following major works: (a) about 940 MW and 1,220 MW of new generating capacity to be installed during 1980-85 and 1986-90 respectively; (b) about 860 and 775 circuit- kilometers of 230 kV and 138 kV transmission lines to be commissioned during 1980-82 and 1983-86 respectively; and (c) expansion of subtransmission and distribution systems. Details of capacities and commissioning dates for the different construction program works are given in Annex 4, Attachment 4.1. Generation Expansion Program 4.07 Currently, INECEL is constructing the following generating facilities, which are part of its 1980-85 expansion program: (a) Paute (Phase A and B) hydroelectric power plant, which is expected to be commissioned during 1982 (2 x 100 MW) and 1983 (3 x 100 MW); (b) Esmeraldas thermal plant, consisting of I x 125 MW residual fuel-based steam turbine plant, to be commissioned during 1981; (c) Guayaquil No.3 (73 MW) oil fired steam generator and Quito (60 MW) gas turbines, to be commissioned during 1981; and (d) About 180 MW of small gas turbines and diesel engine generators, to be installed by the different INECEL subsidiaries during the period 1980-82 while the interconnected system becomes operational. Details of these works are provided in Annex 4, Attachment 4.2. 4.08 To meet estimated energy requirements through 1990 and to partially substitute for thermal generation, INECEL prepared a generation expansion program which includes the installation of the following hydroelectric power plants: Agoyan (150 MW), to be operational by 1986; extension of the Paute hydro development (500 MW), to be completed by 1987; the Daule-Peripa multipur- pose development (130 MW), to be commissioned by 1988; the Paute-Mazar (140 MW) 1/ The 1986-90 transmission, subtransmission and distribution work programs have not yet been defined and are not expected to be until February 1982, when the results of the medium-term Master Plan will become available.  - 20 - hydro development, to be commissioned by 1989; and the Toachi (300 MW) hydro- electric plant, to be commissioned by 1990. The characteristics of these plants are given in Annex 4, Attachment 4.2. Transmission Expansion Program 4.09 The existing transmission system is reduced to short links between major consumption centers and the nearby power generating stations. The first National Interconnected System major link was commissioned during August 1980 and ties the two biggest consumption centers, Guayaquil and Quito, through a 654 circuit km - 230 kV transmission line. The following trans- mission lines, part of the 1980-85 expansion program, are currently under construction and are expected to be commissioned before the end of 1982: (a) 366 circuit km - 230 kV, Guayaquil-Paute; (b) 80 circuit km - 138 kV Quito-Ibarra; (c) 308 circuit km - 138 kV, Santo Domingo-Esmeraldas, and (d) 107 circuit km - 138 kV, Quevedo-Puertoviejo. Details of the National Interconnected System are shown in Annex 4, Attachment 4.3 and in the map. Furthermore, during the period 1982-85 INECEL would install and commission about 338 circuit kms of 230 kV transmission lines, 427 circuit kms of 138 kV transmission lines and about 280 MVA step-up/down transformation capacity at different substations (proposed transmission project to be financed by the Bank). Subtransmission and Distribution Expansion Programs 4.10 The majority of the isolated systems (all of INECEL's subsidiaries) would be integrated to the main SNI network through subtransmission lines (69 kV and 34.5 kV). About 1,300 circuit kms of 69 kV and 34.5 kV subtransmission lines and about 450 MVA step-up/down transformation capacity at different substations are to be installed and commissioned during the period 1982-85. 4.11 Since successful completion of the subtransmission component affects the economics of the overall power development program and of the proposed project, appropriate measures regarding work supervision and technical assistance are required. INECEL has already submitted to the Bank a revised 1981-85 subtransmission program, which defines which lines it would erect itself and which would be erected by its subsidiaries and provides updated cost estimates, bidding and implementation schedules and defines the financing arrangements proposed. During negotiations agreement was reached that INECEL will assume full responsibility for the adequate supervision and timely commissioning of the subtransmission works and will submit periodic reports to the Bank on the progress of these works. 4.12 During the period 1982-85, INECEL and its subsidiaries aim to provide electricity to about 1,500,000 additional inhabitants in different areas of Ecuador (this represents about 250,000 new electricity consumer services). This would increase Ecuador's electrification rate from 38% in 1978 to 50% in 1985. For this purpose, INECEL's subsidiaries plan to construct new low voltage distribution circuits and extend and improve existing distribution systems. INECEL also plans to implement a two-stage rural electrification program with assistance from IDB for the first stage. The projected electrifi- cation rate (13% for the period 1982-1985) is somewhat higher than historical trends (11.5% for the period 1972-1978), but INECEL and its subsidiaries have the manpower and equipment capabilities to achieve the proposed target.  - 21 - Sector Investment Requirements 4.13 INECEL has prepared a 1980-85 power sector investment program, which is in line with CONADE's five-year national development plan. The investment requirements for this period (see Annex 4, Table 4.2) are estimated at US$1,636 million, at 1980 price levels. About US$1,377 million are to be invested by INECEL in: (a) SNI generation plants (US$782 million) (b) 138 kV and 230 kV SNI transmission lines (US$304 million); (c) 69 kV and 34.5 SNI subtransmission lines and rural electrification (US$164 million); and (d) studies and general investments (US$127 million). In addition, EMELEC and INECEL's subsidiaries are expected to invest about US$259 million in their distribution systems. A summary of the investment program is given in the following table: Ongoing Works US$ Millions (1980 constant prices) Generation 1/ 352 Transmission 132 Subtransmission and Rural Electrification 60 INECEL Subsidiaries 2/ 120 General Investments 3/ 27 Subtotal 691 Future Works Generation 1/ 477 Transmission 176 Subtransmission and Rural Electrification 109 INECEL's Subsidiaries 2/ 144 General Investments 3/ 39 Subtotal 945 Total 1980-85 Investment Program 1,636 1/ Includes cost of studies (feasibility and detail design). 2/ Includes investments by INECEL's subsidiaries in power generating plant and distribution networks. 3/ Includes general studies, buildings (US$20 million), office equipment, transportation equipment, and the like. The Project 4.14 The project proposed for Bank financing would consist of 230 kV and 138 kV transmission lines and corresponding conversion (step-down) substations. It would also include training and institutional development programs, engineer- ing services for the design of a National Dispatch Center and engineering ser- vices for the supervision of the execution of the transmission/substation works.  - 22 - 4.15 Issuance of bidding documents for the purchase of equipment and materials is expected to start by January 1982 and construction by January 1983. The physical works included in the project are expected to be completed by December 1984 and the studies by June 30, 1985. 4.16 The physical works and consulting services included in the proposed project are described below (see Annex 4, Attachment 4.3 and map): (a) Transmission Lines (i) Construction of about 338 circuit km of 230 kV transmission lines: (a) from the Paute hydroelectric plant to Totoras (near Ambato); and (b) from Milagro to Machala; and (ii) Construction of about 427 circuit km of 138 kV transmission lines: (a) from Guayaquil to Santa Elena; (b) from Cuenca to Loja; (c) from Ibarra to Tulcan; and (d) from Totoras to Ambato. (b) Substations Construction of substations and installation of step-down trans- formers at Machala (60 MVA), Riobamba (60 MVA), Santa Elena (40 MVA), Posorja (20 MVA), Tulcan (60 MVA) and Loja (40 MVA); and extension of Ibarra substation. (c) Training Program Consultants' services for reviewing the existing training program and training facilities of INECEL and its subsidiaries; and costs of specific training programs, additional training facilities, purchase of laboratory and training equipment, and scholarships for technical and administrative staff. (d) Institutional Development Program Consultants' services for reviewing organizational, financial, commercial, and data processing matters and procedures of INECEL and its subsidiaries and purchase of computer software for accounting/ commercial purposes. (e) Engineering/Consultant Services (i) Engineering services for the design (up to bidding documents and their evaluation) and supervision of the installation of the National Dispatch Center, and (ii) consultant services for the supervision of the proposed transmission project during the construction period. Project Cost Estimates 4.17 Project cost is estimated at US$144 million, of which US$86 million is the foreign exchange component. The project cost was estimated by INECEL's planning and construction staff and reviewed and updated by the Bank. The cost estimate is based on recent prices for equipment and materials and on costs for installation and construction obtained from contracts recently  - 23 - awarded by INECEL (230 kV Paute-Guayaquil and 138 kV Esmeraldas-Santo Domingo transmission lines) and from works recently commissioned (230 kV Guayaquil- Quito transmission line). The estimate is considered reasonable. 4.18 The project costs, which are detailed in Annex 4, Table 4.3, are summarized in the following table: Project Cost US$ Million Local Foreign Total Transmission Lines 13 34 47 Substations 5 19 24 Engineering and Administration 11 1 12 Consultants' Services and Studies 1/ 1 5 6 30 59 89 Physical Contingencies 3 6 9 Price Contingencies 25 21 46 Total Project Cost 58 86 144 1/ Includes Training Program (US$2.0 million), Institutional Development Program (US$3.1 million) and Load Dispatch Center design (US$1.6 million). Import duties are not included in these estimates as INECEL is exempt from these levies. 4.19 The project cost estimates are based on prices prevailing in January 1980, escalated to reflect January 1981 price levels. Physical contingencies were calculated at a rate of 10% of direct costs on all project components. In view of the nature of the works involved, the figure is reasonable. Price contingencies were calculated using the following annual escalation rates applied to basic costs and physical contingencies:  - 24 - Percent (%) 1981 1982 1983-85 Local Products and Services 20 15 15 Foreign Products and Services 9 8.5 7.5 Project Financing Scheme 4.20 The financing scheme for the project would be as follows: (a) local costs, amounting to US$57.9 million, would be financed from INECEL's net internal cash generation and from Government contri- butions; (b) foreign exchange costs which amount to US$86.2 million, including indirect foreign exchange costs, and US$13.8 of financial charges would be financed by the proposed US$100 million Bank loan; and (c) the balance of financial charges, amounting to US$11.2 million, would be financed from internally generated funds. Engineering and Consultants' Services 4.21 INECEL's engineering staff is preparing the designs and specifications for equipment, materials and construction works, assisted when necessary by specialized consultants (IECO-USA and individual consultants who are currently under contract with INECEL). The same staff is also preparing the bidding documents for all project items. 4.22 INECEL will engage consultants under terms of reference and contractual conditions acceptable to the Bank for the following tasks. (a) training program, for which a total of 36 consulting staff-months were estimated to be required, at an average cost of US$12,000 per staff-month 1/; (b) institutional development program, expected to require about 126 consulting staff-months at an average cost of US$12,000 per staff-month 1/; (c) load dispatch center, expected to require about 82 engineering staff-months at an average cost of US$12,400 per staff-month 1/; and (d) supervision of project construction during the period June 1982- December 1984, which is expected to require about 80 consultant staff-months at an average cost of US$5,000 per staff-month 1/. 1/ Excluding travel allowance costs.  - 25 - Procurement and Disbursements 4.23 Most contracts for the supply of equipment and materials and their installation (including civil works) to be financed with funds from the proposed loan will be procured through international competitive bidding (ICB) procedures in accordance with Bank guidelines. Competitive bidding in accordance with other procedures satisfactory to the Bank, such as interna- tional shopping, will be appropriate for a few contracts (such as laboratory and training equipment, vehicles and computer software and hardware), each not exceeding US$100,000 and estimated not to exceed US$1,000,000 in total. Most of the equipment and materials to be procured for the transmission lines and substations will be imported, as the local manufacturers either do not have the production capability to meet the quantities required (aluminum conductors) or do not produce the specialized equipment and materials required for the project. Therefore, preference for bid evaluation purposes to local manufac- turers and suppliers has not been requested by the Government. 4.24 The loan would be disbursed over a five-year period (see Annex 4, Table 4.4) against (a) 100% of foreign expenditures for imported goods and 85% of the local expenditures for locally manufactured materials; (b) 14% of the total expenditures on the contracts for civil works and for the installation of the corresponding equipment and materials, representing the estimated in- direct foreign exchange costs of the goods to be provided by the contractors (construction materials, transport, machinery, equipment, furniture); (c) consulting services and related expenses as follows: 100% of foreign expenditures for supervision of project construction, 95% of total costs for training program, 70% of total costs for the institutional development program and load dispatch center studies; and (d) interest and other charges during construction on the Bank loan through mid-1984 up to US$13.8 million. All requests for disbursements of funds from the loan account would be fully documented. Retroactive financing for up to US$1,000,000 is proposed for payment of consultants' fees incurred and paid by the Borrower after June 1, 1981 to cover advanced expenditures directly related to the training and institutional development programs and the design of the load dispatch center. The closing date for the proposed loan would be December 31, 1985. Project Execution 4.25 INECEL will engage contractors for the civil works and for the installation of the equipment and materials of the transmission lines and corresponding substations through international competitive bidding (ICB) in accordance with Bank guidelines. It is expected that these contracts would be awarded to foreign firms with ample experience in similar undertakings. Invitations to bid are expected to be issued by January 1982 (see Annex 4, Attachment 4.4 for complete implementation schedule). 4.26 INECEL's engineering staff, with the assistance of consultants whose experience, terms-of-reference and conditions of employment are accept- able to the Bank (and who will be responsible for the overall supervision of the construction) would be capable of executing the project adequately, as demonstrated by the successful completion of the Quito-Guayaquil transmission line, which was commissioned on schedule in August 1980. During negotiations agreement was reached with INECEL that these consultants will be engaged by September 30, 1982.  - 26 - 4.27 Project execution will be monitored against target dates shown in the project implementation schedule (Annex 4, Attachment 4.4). INECEL's operational, financial and managerial performance will be monitored through performance indicators which were agreed during negotiations (Annex 4, Table 4.5). During negotiations agreement was reached that INECEL will submit such indicators regularly to the Bank. Environmental Aspects 4.28 The proposed project does not present major environmental problems. Transmission line routes are considerably distant from urban centers. Furthermore, substations would be located at urban centers with due regard to environmental and aesthetic considerations and in accordance with urban regulations. INECEL would compensate property owners as required by the national legislation. Clearing of rights-of-way would be kept to a minimum and natural drainage patterns are not expected to be affected. Project Risks 4.29 The project faces no special physical risks. Sector issues or insufficient action on financial matters could, however, negatively affect institutional performance or result in program and project delays (paragraphs 1.33 to 1.35 and 5.02 to 5.04). 5. FINANCE Introduction 5.01 Over the past 15 years, electricity sales have increased at an annual rate exceeding 12% (see Annex 3, table 3.1, for the sales statistics since 1970), thus requiring significant investments in power facilities. Despite this, INECEL has followed a policy of low electricity tariffs, placing a substantial financing burden on the Government. 5.02 In the next five years, investment requirements are expected to be even larger than in the preceding years, so that by 1985 total fixed assets will approximately double their present value in real terms. To accomplish this, a major financing effort will be needed. This will put to a severe test the intentions of the Government and of INECEL to simultaneously reduce fuel subsidies significantly, raise electricity tariffs to adequate levels, and progressively reduce the sector's dependence on Government contributions. 5.03 To meet the consolidated financing requirements of INECEL and of its subsidiaries, average retail electricity tariffs (inclusive of fuel clause) will have to increase from an equivalent of about US$0.05/kWh in 1980 to US$0.154/kWh in 1985. This implies a nominal increase of about 200%; however, after adjusting for estimated domestic inflation the real increase would be about 50%. To achieve this, INECEL has put into effect a policy of monthly tariff increases averaging 3% and has agreed to maintain these increases until the covenanted rates of return have been attained. This policy is expected to  - 27 - result in a December 1981 retail tariff (inclusive of fuel clause) of S/1.74/kWh, which represents an increase of 32% over the December 1980 level. At negotia- tions, it was also agreed that cost increases in excess of those forecast would be automatically reflected in additional tariff adjustments through the implementation of existing legislation (para. 1.26). 5.04 At negotiations, the Government agreed to assign nearly US$900 million equivalent (nearly 70% of which are expected from INECEL's participation in oil royalties) to the power sector between 1981 and 1985. Assurances were also obtained that any shortfall in oil royalties would be made up through other Government equity contributions. If such support were not to materialize, the financial viability of the investment program would disappear. 5.05 Annex 5, tables 5-1 through 5.8, show INECEL's historic and forecast consolidated financial statements and complementary financial information. Since INECEL does not presently prepare consolidated financial statements, such consolidation was done by the appraisal mission. Analogously, fixed assets which had not been hitherto revalued (despite legal provisions which so require) were revalued, on an estimative basis, by the appraisal mission (see Table 5.2, footnote b). For these reasons, and also because the original statements were not audited (paragraphs 2.17 and 2.18) the historic statements should be viewed as estimates. The mission forecasts are expressed in current dollars (internal prices were assumed to increase at an annual rate of 15% and external prices at 9%; fuel price assumptions are discussed in Table 5.1, footnote f). A constant exchange rate of S/. 25 = US$1 was assumed. Financial History 5.06 Though INECEL was legally constituted in 1961, in its early years its scope of activity was very limited and mainly concentrated in planning sector development and promoting the regional integration of the small local systems. In 1973, INECEL commenced to invest in generating plants and its first installations were commissioned in 1976. Investment in a major genera- tion project, Paute (500 MW), started in 1975 and only built up in recent years. 5.07 Thus, INECEL's financial history is, for all relevant purposes, very short and provides little guidance as to its prospects for the future. Some salient factors may, however, be noted: (a) Net internal cash generation has been negative and financing needs (which were not only caused by INECEL's own expansion but also by the requirements posed by INECEL's subsidiaries) were mainly fi- nanced through Government contributions (of which the main source was INECEL's participation in oil royalties) and external loans. (b) INECEL's debt-equity structure has evolved within conservative bounds, keeping well below a 50:50 ratio (based on fully revalued financial statements, as estimated by the Bank mission), thus suggesting that increased reliance on long-term indebtness is viable, provided revenues are increased to ensure adequate debt service coverage.  - 28 - 5.08 Though the above comments pertain only to INECEL, they are also applicable to the consolidated financial performance of INECEL and its sub- sidiaries. The estimated consolidated rate of return on fully revalued assets was negative in 1978 and 1979 and only marginally positive, 2.6% in 1980, despite the sizeable fuel subsidies. It should be noted too that, except for EEQ, the subsidiaries have tended to rely on INECEL for financing, generally limiting their external borrowing to supplier credits. It is estimated that in 1979, INECEL had a debt equity ratio of 40:60 (on a non-consolidated basis), EEQ a ratio of 35:65 and all the other subsidiaries averaged a relation of 8:92. This may be attributed to the limited expertise of local financial managers and also to the red tape involved in obtaining the approval of the government, and to the high cost associated with obtaining the guarantees foreign lenders usually require. 5.09 Thus, there is room for improvement in financial management at the sector level. It is expected that both the organization study and the training component included in the project would address this issue. Further- more, at negotiations it was agreed that INECEL will submit to the Bank, not later than October 31, 1981, a program which inter alia sets up a long-term borrowing strategy for itself and for its subsidiaries, proposes mechanisms to limit the subsidiaries' traditional reliance on INECEL as lender of first resort, and provides the subsidiaries with assistance in obtaining long-term financing. Tariffs and Rate of Return 5.10 As of late 1979, average electricity tariffs stood below the real levels prevailing in the early 1970's, before the major oil price rises. On a comparative basis, tariffs were lower than in any other Latin American country with such a high proportion (about 75%) of thermal generation. Early in 1980, a new tariff structure, which resulted in an average increase of about 20%, was implemented and in November 1980 a policy of monthly increases, averaging about 1.3%, was introduced. In February/March 1981 some rates were selectively increased and in May 1981 a new policy of monthly increases, averaging 3%, was put into effect. Despite these measures, tariffs are not yet providing a reasonable contribution to investment, while from an economic viewpoint they appear to be still below marginal cost (para. 6.05), thereby encouraging excessive use, and waste, of electricity. 5.11 Thus, continuation of the policy of increases currently in force is required. The average electricity tariffs proposed, and their relation to historic values, are shown in the following table.  - 29 - Current Constant 1970 Constant 1970 Sucres 1/ Sucres 2/ US$ mills 3/ 1970 0.56 0.56 27.2 1975 0.78 0.42 22.5 1980 1.28 0.38 23.4 1985 3.85 0.59 46.6 1/ Total sales revenues/sales in kWh. 2/ The deflator used is the index of consumer prices given in IBRD Ecuador: Development Problems and Prospects, page 643, updated to 1979 by the index of consumer prices given in the IMF's International Financial Statistics. For 1980-85 an average annual inflation rate of 15% was assumed. 3/ For calculating the constant US dollar series, an exchange rate of S/.20.9 per dollar in 1970, and of S/.25 thereafter was used. The deflator applied is the US consumer price index, for which increases of 14% in 1980 and of 9% per year thereafter were assumed. 5.12 At negotiations, it was agreed that the need for tariff increases discussed in para. 5.10 could be adressed through progressive action. Thus, it was further agreed that: (a) The consolidated rate of return for INECEL and its subsidiaries will be 4% in 1982, 8% in 1983, and 8.5% in 1984 and thereafter; (b) the rate of return for INECEL alone will be 4% in 1982, 8% in 1983, and 8.5% in 1984 and thereafter; (c) the provisions of the tariff legislation dealing with automatic tariff adjustments to cost variations will be implemented no later than January 1, 1982; (d) INECEL will submit monthly information on retail tariffs actually charged, which the Bank will monitor to ensure that they are consistent with the agreed targets (para 5.03); and (e) until quarterly consolidated financial statements satisfactory to the Bank can be submitted in a timely manner, a quarterly information system covering INECEL and its subsidiaries willd be designed and implemented effective January 1, 1982, so as to enable the Bank to reasonably monitor rate of return performance on a timely basis, and to serve as an information input for automatic tariff adjust- ments. To achieve this, INECEL will submit the quarterly reports within 75 days of the end of the corresponding quarter. Consolidated Investment and Financing Plan 5.13 The consolidated investment and financing plan, detailed in Annex 5, Table 5.3 is summarized as follows:  - 30 - CONSOLIDATED INVESTMENT AND FINANCING PLAN* (In millions of current dollars) 1981 - 1985 1982 - 1985 Amount % Amount % Requirements for Funds Investments 1/ in: Hydro generation 834.6 38.3 694.5 40.4 Transmission 306.1 14.0 209.4 12.2 Other, operational 466.2 21.4 322.5 18.7 Other (non operational), and studies 134.0 6.0 112.5 6.5 Subtotal 1,740.9 79.8 1,338.9 77.8 Interest during construction 217.6 10.0 184.3 10.7 Subtotal 1,958.5 89.8 1,523.2 88.5 Net working capital 3/ 222.2 10.2 197.1 11.5 Total requirements 2,180.7 100.0 1,720.3 100.0 Sources of Funds Net operating income 2/ 621.1 28.4 635.5 36.9 Other income (net) (55.0) (2.5) (49.0) (2.8) Depreciation 2/ 314.4 14.4 281.1 16.3 Total gross cash generation 880.5 40.3 867.6 50.4 Less: Debt service 3/ (681.0) (31.2) (607.1) (35.3) Net internal cash generation 199.5 9.1 260.5 15.1 Equity contributions: 3/ Oil royalties 598.5 27.4 469.1 27.2 Miscellaneous taxes 16.0 0.7 10.5 0.6 Other Government contributions 252.5 11.6 142.0 8.3 Subtotal 1,066.5 48.9 882.1 51.3 Borrowings (gross) 4/ 1,114.2 51.1 838.2 48.7 Total sources 2,180.7 100.0 1,720.3 100.0 *Figures may not add up because they have been rounded off. 1/ See Annex 5, Table 5.4. 2/ See Annex 5, Table 5.1. 3/ See Annex 5, Table 5.3. 41 See Annex 5, Table 5.6. 5.14 The Bank has worked closely with INECEL and with the Government in developing a suitable program financing scheme. As indicated earlier (para. 5.04), substantial funding is expected from the Government, and between 1981 and 1985 new loans amounting to about US$1.6 billion are aLso to be raised from international lending agencies, suppliers and commercial banks (see Annex 5, Table 5.5).  - 31 - 5.15 The financing scheme for the project is discussed in paragraph 4.20. The proposed Bank loan would have a maturity of 17 years, including a four year grace period. These are the standard terms for Ecuador. For financial projection purposes, an interest rate of 10% per year and a commitment fee of 0.75% were assumed. In view of the magnitude of INECEL's investment program and of the major program cofinancing effort envisaged, financing of interest during construction until mid 1984 is recommended. By then Paute is expected to be in full commercial operation, which will allow substantial fuel savings thus providing a large increase in gross internal cash generation. Future Finances 5.16 The consolidated financial projections are based on the assumption that retail tariffs will be progressively increased, so as to achieve rates of return (on a rate base composed of average net revalued fixed assets and a provision for working capital) of 4% in 1982, 8% in 1983 and 8.5% in 1984 and after. This calls for nominal increases in the average retail price (inclusive of fuel clause) paid by consumers of 32% in 1981, 56% in 1982, 18% in 1983, and 23% in 1984. 5.17 The rates of return indicated above would enable INECEL and its subsidiaries to make a contribution of about 15% to their 1982-85 consolidated' investment program, which is reasonable in view of the magnitude of the works involved. Furthermore, by 1985 INECEL's consolidated contribution is expected to have increased to 33%. At negotiations, it was agreed that INECEL will retain all earnings - and further, cause its subsidiaries to retain all earnings - for investment in the sector, unless otherwise agreed by the Bank. 5.18 The debt-equity ratio is expected to fall in the period considered, mainly because of the large amount of Government equity contributions forecast and also because of the heavy debt amortization service through 1985, which reflects the relatively short terms which have characterized INECEL's past borrowings. This suggests that, once tariffs reach reasonable levels, it may be feasible to finance a larger proportion of INECEL's investment needs through long-term borrowings, simultaneously reducing the sector's dependence on Government funds (para. 5.10). Debt service coverage is forecast to be very poor through 1982, but this is substantially offset by the commitments undertaken by the Government to provide equity contributions. At negotiations, it was agreed that INECEL will obtain the Bank's concurrence before incurring additional long-term debt, if its internal cash generation is less than 1.5 times its maximum future debt service requirement. 5.19 The short-term financial position is expected to be fairly comforta- ble during the project construction period. Furthermore, to avoid any delays in project or program implementation caused by transitory financial tightness, at negotiations the Government agreed that it would make its best efforts to deal with requests from INECEL, or from its subsidiaries, for authorization to borrow from local banks, so that processing times do not exceed 30 days. 5.20 Improvements in billing procedures already underway and further review of commercial practices to be carried out as part of the organization study should eventually result in lower collection periods, improving liquidity.  - 32 - Furthermore, at negotiations the Government agreed that it would pay its electricity bills when due and cause its agencies to proceed in the same manner and INECEL agreed that it will institute a satisfactory system of surcharges for late payment, which would be specially relevant for the munici- palities. 1/ Reporting requirements on public sector receivables were also agreed upon. To enable timely monitoring, these reports will be submitted quarterly, within 75 days of the end of the quarter. They will provide information on the aging of receivables from each public sector agency or institution. 5.21 In view of the magnitude of the sector's investment program and the possibility that local interests may wish to alter the timing (thus deviating from the optimum determined from the Master Plan Optimization Studies) of the future hydro-projects, at negotiations agreement was reached with INECEL and the Government that they will (a) consult the Bank before undertaking commitments to any capital expenditure (other than those already included in the Master Plan) which would increase the gross fixed assets in operation of the power sector by 2% or more and furnish a report (satisfactory to the Bank) showing the economic justification and financing plan of the proposed project; and (b) ensure that the expansion of the power sector in Ecuador is carried out in a coordinated manner in order to prevent waste, duplication and unnecessary investment on the basis of economically justified programs within the limits of INECEL's (or other sector agencies, if applicable) financial and managerial capacity. Financial and Performance Indicators 5.22 The historic and forecast values for key financial indicators are shown in Annex 5, table 5.8. Annex 4, table 4.5 presents selected indicators showing INECEL's expected achievements through 1985. At negotiations, agreement was reached on the target values set and on the periodicity with which INECEL will inform the Bank on its performance with respect to each of the indicators listed. 6. ECONOMIC ANALYSIS Least-Cost Solution 6.01 INECEL, with the assistance of individual experts, prepared the 1980-85 transmission expansion program based on a national load forecast covering the period 1979-90 (see paras. 3.05 and 3.06) and on detailed analyses of the projected regional consumption patterns. Furthermore, comparisons of several transmission and local power generating plant alternatives were carried out by them. 1/ The appraisal mission was unable to obtain enough data from INECEL's subsidiaries to evaluate whether overdue public sector accounts posed a significant problem. However, there are indications that some munici- palities experience considerable delays.  - 33 - 6.02 The transmission line parameters (voltage levels, conductor sizes, span lengths and line routings) for the Guayaquil-Santa Elena, Milagro-Machala, Cuenca-Loja, Ibarra-Tulcan and Totoras-Ambato lines and the design of the corresponding substations were optimized in order to determine the corres- ponding least-cost transmission alternative. Subsequently, each optimized transmission line was compared to an equivalent thermo-electric power plant. The comparison of the net present value of capital and operating/maintenance economic costs of the different alternatives demonstrated that the recommended transmission alternatives are the corresponding least-cost solutions at dis- count rates of up to 50% (Annex 6, table 6.1). Sensitivity analyses were also carried out to evaluate the effects of variations in capital costs, variations in fuel costs, and variations in other major costs. These analyses demonstrated that, for reasonable changes in the various parameters, the selected transmis- sion alternatives remain the least-cost solutions. 6.03 The 230 kV, 205 km, Paute-Totoras transmission line would complete the SNI interconnecting ring circuit, thus strengthening and improving the reliability, stability and load flow of the SNI transmission network. This line was originally scheduled to be commissioned in early 1987, when the Paute - Phase C - hydro development is expected to become operational. Recent system load flow and stability studies carried-out by INECEL have shown, however, that the line should be commissioned earlier and an economic evaluation requested by the Bank has demonstrated the merits of advancing its commissioning to early 1985, mainly due to the savings attributable to the re- duction of outage costs, which otherwise will occur. Consequently, the Bank agreed to include this line as a component of the proposed project. Return on Investment 6.04 Since the proposed project is an integral part of INECEL's 1980-85 investment program, its benefits cannot be singled out. Thus, the rate of return on the overall investment program was computed. The rate of return on the investment was estimated as the discount rate which equalizes the present values of the economic net cost and benefit streams associated with the investment program. The economic net cost streams include the associated capital investments and operational and maintenance costs of: (a) generation program - including Esmeraldas (thermal), Agoyan (hydro) and Paute - phase A, B and C (hydro); (b) transmission program (ongoing works and the proposed project); (c) 1980-85 subtransmission, distribution and rural electrification programs; and (d) general investments (studies, buildings, transportation, furniture, and such). The economic net benefit streams were measured by: (a) forecast revenues from incremental sales of electricity (corresponding to the energy to be produced by the new power generating plants being commis- sioned in 1980-85 at the average retail level as of December 31, 1980 and, alternatively, at the forecast tariff levels (para. 5.03); and (b) energy substitution (the hydro-power plants under consideration would substitute for thermal generation, freeing considerable amounts of fuel) valued at current international fuel prices (Annex 6, table 6.2). 6.05 The internal rate of return of the expansion program using pre- vailing tariff levels as of December 31, 1980, was about 7%, which may be compared against the opportunity cost of capital in Ecuador, currently  - 34 - estimated at 11%. However, if benefits are measured on the basis of fore- cast tariff levels, the internal rate of return would be about 13% (Annex 6, table 6.2). These results support the conclusion that current tariff levels are inadequate. They also strengthen the recommended Bank's position that by 1985 present tariffs should be increased to the levels required to provide an 8.5% financial rate of return (para. 5.03). 6.06 The rates obtained understate the real economic return of the program, because revenues from the sales of electricity do not fully reflect some of the benefits to society, industry and commerce, whose welfare, production and employment depend on reliable electricity supply. Furthermore, the following caveats should be noted: (a) no allowance has been made for the degree of over-investment which is naturally built-in to the trans- mission and distribution programs, which have been dimensioned to accommodate expected future demand increases, (b) benefits resulting from outage reduction due to improved system reliability have not been taken into account, and (c) expected benefits from improved system operation when the Load Dispatch Center becomes operational and from management and efficiency improvements expected from the organizational study and training program have not been quantified. However, the preceding considerations do not diminish the validity of the analyses regarding the tariff level increases required. Sensitivity Analyses 6.07 Sensitivity analyses were also carried out to determine the effect on the internal rate of return (with benefits measured both at prevailing and forecast tariff levels) by variations in capital costs, in operational and maintenance costs, and in revenues (Annex 6, table 6.3). The rate of return on the expansion program (with benefits evaluated at forecast tariff levels) would drop to about 10% if costs are 10% higher than estimated and expected revenues are 10% lower. If the investment program costs do not increase but benefits decrease by 10%, the rate-of-return would drop to 11%. Furthermore, the rate-of-return will drop to 12% if costs are 10% higher and benefits remain unchanged. 7. SUMMARY OF PROPOSED AGREEMENTS AND RECOMMENDATIONS 7.01 During negotiations agreements were reached on the following principal points: (a) With the Government that: (i) the prices of fuels used for electricity generation will be progressively increased, so that by 1984 they represent not less than 50% of the world prices then prevailing (para. 1.15); (ii) it will take such actions as may be required to expedite procurement authorizations and clearances, so as to avoid delays in project implementation (para. 2.11);  - 35 - (iii) it will make equity contributions to INECEL in specified amounts, and will also make-up any shortfall in oil royalties through additional equity contributions (para. 5.04); (iv) it will make its best efforts to deal with requests, from INECEL or from its subsidiaries, for authorization to borrow, so that processing time does not exceed 30 days (para. 5.19); (v) it will pay its electricity bills when due, and also cause its agencies to pay their bills when due (para. 5.20); and (vi) projects undertaken in the future will be economically justified and adequately financed (para. 5.21). (b) With INECEL that: (i) all electric services will be consolidated in ten regional companies by December 31, 1984 (para. 1.18); (ii) not later than September 30, 1981, it will submit a proposal on a mechanism (including main operational characteristics and target dates for implementation) to transfer funds between companies, to enable all of them to meet financing require- ments and rate of return targets (para. 1.29); (iii) it will furnish to the Bank, not later than October 31, 1982 the results of a study on the marginal cost of electricity generation and its proposals for a more comprehensive study, which would enable INECEL to revise its tariff structures (para. 1.32); (iv) it will engage management consultants not later than December 31, 1981; discuss their recommendations with the Bank and implement those that are agreed upon (para. 2.03); (v) it will submit to the Bank, prior to loan effectiveness, an interim program to improve the direction and supervision of its subsidiaries (para. 2.06); (vi) it will engage consultants for training on or before December 31, 1981 (para. 2.10); (vii) it will implement measures so that it may submit fully consolidated financial statements by 1983 and be able to meet mutually agreed interim consolidation targets for 1981 and 1982 (para. 2.14(a)); (viii) it will engage qualified experts (on terms of reference acceptable to the Bank, and not later than December 31, 1981) to inventory INECEL's fixed assets, assess their replacement value and design appropriate recording systems; and will reflect such valuations in its records and financial statements (para. 2.14(b));  - 36 - (ix) it will reflect a provisional revaluation of fixed assets in operation, on the basis of inflation indices, in the 1980 financial statements (para. 2.14(c)); (x) it will furnish to the Bank, on or before specific dates programs which identify the accounting problems faced by each subsidiary and contain specific proposals to address them, and, also, that it will cause all its subsidiaries to revalue their fixed assets per an agreed timetable and will assist and supervise them in this exercise (para. 2.15); (xi) it will engage private external auditors by March 31, 1982 (para. 2.17); (xii) it will cause each of its subsidiaries to engage independent external auditors by agreed dates (para. 2.18); (xiii) the Paute-Amaluza dam will be inspected at least once a year by qualified and experienced experts, and a copy of the inspection report will be submitted to the Bank (para. 2.20); (xiv) it will engage consultants to carry out a study of distribution losses not later than December 31, 1981, and will implement such recommendations as subsequently agreed with the Bank per an agreed timetable (para. 3.11); (xv) it will assume responsibility for supervising the sub- transmission works and ensuring their timely completion and will report periodically on work progress (para. 4.11); (xvi) it will engage consultants for the overall supervision of the project on or before September 30, 1982 (para. 4.26); (xvii) it will submit performance indicators regularly to the Bank (para. 4.27); (xviii) not later than October 31, 1981 it will submit a program which sets up a long term borrowing strategy, and will provide assistance to its subsidiaries for obtaining access to credit (para. 5.09); (xix) it will take all measures required to achieve a consoli- dated rate of return for INECEL and its subsidiaries of 4% in 1982, 8% in 1983 and 8.5% in 1984 and thereafter. These same rates of return will also be applicable to INECEL (para. 5.12); (xx) it will implement automatic tariff adjustment legislation no later than January 1, 1982 (para. 5.12);  - 37 - (xxi) it will submit monthly tariff information, to enable the Bank to monitor compliance of the agreements on tariff increases. A quarterly information system to monitor rate of return performance (until quarterly consolidated financial statements can be available on a timely basis), will be designed and implemented by January 1, 1982 (para. 5.12); (xxii) it will retain all its earnings and cause its subsidiaries to retain their earnings for reinvestment in the sector (para. 5.17); (xxiii) it will obtain the Bank's concurrence before incurring in additional long term debt, if its internal cash generation is forecast to be less than 1.5 times its maximum future debt service requirements (para. 5.18); (xxiv) it will institute a satisfactory system of penalties for late payment of electricity bills and will provide the Bank with quarterly information on accounts receivable, to be submitted within 75 days of the end of the quarter (para. 5.20); (xxv) it will consult the Bank before undertaking commitments to any capital expenditure (other than those included in the Master Plan) which would increase the gross fixed assets in operation of the power sector by 2% or more; and ensure that the expansion of the power sector in Ecuador is carried out in a coordinated manner in order to prevent waste, duplication and unnecessary investment on the basis of economically justified programs (para. 5.21). 7.02 Conditions of effectiveness of the proposed loan would be that: (a) a satisfactory preliminary program for improving INECEL's control over its subsidiaries had been submitted (para. 2.06); (b) private external auditors for INECEL had been selected (para. 2.17). 7.03 Failure to implement the recently enacted policy of monthly tariff increases averaging 3% would be an event of default (para. 1.27). 7.04 Retroactive financing for consultants' services since June 1, 1981 in an amount not exceeding US$1,000,000 is recommended (para. 4.24). 7.05 With the above assurances, the project would constitute a suitable basis for a Bank loan of US$100 million, to be repaid over a period of 17 years, including four years of grace. June 23, 1981  - 38 - ECUADOR ANNEX 1 INECEL POWER TRANSMISSION PROJECT Table 1.1 INECEL's Participation in the Capital of the Electric Power Companiesl/ 2/ % of Capital Stock 2 Power Company Name Owned by INECEL -Regional Norte 90.1 Quito 55.8 Santo Domingo 100.0 Ambato 54.5 Riobamba 67.4 Bolivar 93.2 3/ Azogues 4/ 76.2 Cuenca 4/ 88.4 Regional Sur 93.4 Esmeraldas 92.8 Manabi 86.9 Santa Elena 98.4 Milagro 94.9 Los Rios 98.8 El Oro 92.2 Weighted average 85.2 1/ Data as of December 31, 1979 (based on unaudited financial statements). 2/ Percentages are based on issued capital, which in some cases differs from paid in capital. 3/ As of June 30, 1979. 4/ These two companies have now been merged, and form Empresa Regional Centro-Sur.  -39 - ANX 2 Table 2.1 ECUADOR - INECEL ORGANIZATION CHART BOARD OF ~~CON TRA LORI A TARIFFS D TBOARD OF GENERAL (GOVERNMENT) s ^ _ X ~~INTERNA L _ AUDITING GENERAL MANAGER PUBLI C RELATiONS SECRETARIAL SERVICES PLANNING DEPARTMENT J, ,LEGAL DEPARTMENT SYSTEMS & ORGANIZATION .*. ID EVALUATION COMMITTEE TECHNICAL, ADMINISTRATIVE, & FINANCIAL COORDINATION COMMITTEE INDUSTRIAL CONSTRUCTION NTERCONNECTED MARKETING RURAL RE A IN J | ENGINEERING SYSTEM OPERATIONS | FINANCE DISTRIGUT ON DISINGIBUTION PROGRAM World Bank - 21968  -40- ECUADOR ANNEX 3 Table 3.1 INECEL POWER TRANSMISSION PROJECT National and SNI Energy Forecast (GWh) 1/ National Forecast SNI Forecast Public Total Total2 Year Rasidential Coumercial Industrial Lighting Sales Losses Generation Total 1970 279.7 103.4 320.8 87.1 791.0 157.8 948.8 - 1971 306.9 116.5 353.9 97.7 875.0 174.6 1049.6 - 1972 341.6 135.4 375.2 103.5 955-.7 161.4 1117.1 - ( 1973 359.0 147.0 414.7 123.2 1,043.9 220.6 1264.5 - ACTUAL ( 1974 405.9 177.4 464.5 159.0 1,206.8 223.1 1429.9 - 1975 487.2 191.6 528.2 132.9 1,339.9 254.9 1594.8 - 1976 587.7 234.5 590.1 163.9 1,576.2 254.6 1830.8 - 1977 668.4 263.7 693.1 189.7 1,814.9 312.3 2127.2 - 1978 792.4 299.9 863.3 226.2 2,181.8 391.7 2573.5 - 1979 903.6 354.2 989.5 245.5 2,492.8 419.3 2912.1 - 1980 1131.9 405.5 1125.9 266.7 2,930.0 476.9 3406.9 2421.8 1981 1158.7 455.4 1277.7 289.1 3,180.9 500.7 3681.6 2891.0 1982 1295.9 509.3 1447.1 313.6 3,565.9 547.0 4112.9 3644.0 FORECAST 1983 1443.1 567.1 1634.5 341.3 3,986.0 574.6 4560.6 4320.5 1984 1582.5 621.9 1842.4 370.7 4,417.5 608.1 5025.6 4771.2 1985 1756.9 690.5 2071.2 402.7 4,921.3 677.4 5598.7 5598.7 1986 1915.6 752.8 2323.7 437.5 5,429.6 733.4 6163.0 6163.0 1/ The SNI became operational in August 1980. The different isolated systems would be gradually integrated to the SNI during the 1980-1984 period. By end of 1984 it is forecasted that all isolated systems would be integrated to the SNI. Source: 1980-1985 INECEL's short-term Masterplan Studies.  - 41 - ANNEX 3 ECUADOR Ta_le 3.2 INECEL POWER TRANSMISSION PROJECT Natlonal and SNI Demand Forecast (MW) National National SNI Load SNI Demand Demand Factor Load Factor Year (MW) (MW) m(7 (%) ( 1970 224.0 - 48.8 - ( 1971 250.5 - 47.8 - C 1972 262.2 - 48.6 - ( 1973 281.5 - 51.3 - ( 1974 318.5 - 51.2 - ACTUAL ( 1975 358.5 - 50.8 - 1 1976. 413.9 - 50.5 - C 1977 479.8 - 50.6 - ( 1978 564.5 - 52.0 - ( 1979 658.3 - 50.5 - C 1980 767.1 523.5 50.7 52.8 1/ C 1981 827.3 696.5 50.8 47.4 2/ ( 1982 922.4 834.2 50.9 49.9 FORECAST ( ( 1983 1,047.5 966.3 49.7 51.0 ( 1984 1,107.5 1,107.5 51.8 49.2 3/ ( 1985 1,231.5 1,231.5 51.9 51.9 C 1986 1,355.6 1,355.6 51.8 51.9 1/ Guayaquil and Quito, Ecuador's main industrial centers,were interconnected during August 1980. 2/ The SNI load factor decreases as the loads of the isolated systems which will be interconnected to the SNI are mainly domestic, commercial and rural. 3/ The SNI load factor decreases as the bulk of transmission works become opera- tional (transmission works included in Bank financial project), thus inter- connecting mainly domestic and rural loads. Source: 1980-1985 INECEL short-term Masterplan Studies.  ECUADOR INECEL POWER TRANSMISSION PROJECT National Interconnected Syeter (SNI) 1980-1990 Power Balance (MW) 1980 19831 1982 1983 1984 1985 1986 1987 1988 L 1990 1) Maximum Deeand 523.5 696.5 834.2 966.3 1,107.5 1,231.5 1,355.6 1,492.8 1,645.8 1,805.7 1,976.8 2) hiietlng ower Cepability a) Ilydro 149.8 166.9 205.3 205.3 207.4 207.4 207.4 207.14 207.4 207.4 207.4 b) Thjermal 537.6 661.3 686.5 690. 4 734.7 716.9 669.5 642.2 599.9 550.8 474.3 Total gxistiing Capability 687.4 8281.2 891.8 895.7 942.1 924.3 876.9 849.6 807.3 758.2 681.7 3) Future Power Plawt a) Quito - G.T. (60MW) - 1980 59.1 59.1 59.1 59.1 59.1 59.1 59.1 59.1 59.1 59.1 59.1 b) Esrneraildias - Steam (125MW) - 1981 116.0 116.o 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0 c) Paute "A" & "B" (500iMW) - 1982/1983 - - 87.4 349.6 437.0 437 0 437'.0 437.0 437.0 487.0 487.0 d) Agoyanl (150MW) - 1985 - - - - - 138.0 138.0 138.0 138.0 138.0 138.0 e) Paete "C" (500MW) - 1987/1.988 - - - - - 174.8 437.0 487.o 487.0 f) Dalle Peripa (130MW) - 1988 - - - - - 77.0 77.0 77.0 g) Pauite Mazar (140MW) -189/90 - - - - - 77.0 h) T'oachi (300MW) - 1990/1991 - 253.0 Total. Future Planit 59.1 175.1 262.5 524 .7 612.1 750.1 750.1 924.9 1,264.1 1,364.1 1,694.1 14) Available Capacity (2 + 3) 746.5 1,003.3 1,154.3 i,420.4 1,5514.2 1,674.4 1,627.0 1,774.5 2,071.4 2,122.3 2,375.8 5) Prograumned Maint,enance 89.5 159.1 162.6 163.2 173.8 197.4 187.6 180.4 188.7 182.3 200.0 6) -iirm Capacit5y (4 -5) 657.0 844.2 991.7 1,257.2 1,380.4 1,477.0 1,1439.41 1,594.1 1,882.7 1,940.3 2,175.8 7) balarce 6 - 1 133.5 147.7 157.5 290.9 272.9 245.5 83.8 101.3 236.9 134.6 199.0 10~  ECUADOR INECEL POWER TRANSMISSION PROJECT National Interconnected Syste (SNI) 1980-1990 Energy Balance (0141,) - Average Year 1980 1981 1982 1983 19814 195 1987 1988 19898 I) Y 2,1421.8 2,891.0 3,6414.0 4,320.5 4,771.2 5,598.7 6,163.0 6,800.1 7,497.2 8,225.3 9,022.2 2) Exis_~n Generationl a) hydro 615.3 751.8 849.2 855.2 872.1 850.0 884.1 896.6 885.7 865.2 842.2 b) Thermal 1,763.8 1,795.5 1,717.3 839.6 841.3 1,123.3 1,425.7 1,721.5 1,288.2 792.4 605.5 Total Ecisting Generation 2,379.1 2,547.3 2,566.5 1,694.8 1,713.4 1,973.3 2,309.8 2,618.1 2,173.9 1,657.6 1,447.7 3) iutu re Plant Generation a) Quito - a.T. (6oiw) - 19580 42.7 52.4 35.1 15.4 27.2 54.7 38.3 24.1 22.9 15.3 17.0 b) esseraldas-Steam (1251W) -1981 2 - 291.3 812.0 645.1 340.9 406.0 406.0 406.0 754.0 812.8 812.0 ') Paute "A" & "Yt" (50oMWl - 1982/83- - - 230.4 1,965.2 2,689.7 2,543.4 2,734.5 2,804.1 2,743.2 4,305.0 4,305.0 d) Agoyan (150MW) - 985/ 2/ 50 - - 621.3 674.4 693.8 676.8 645.8 609.1 e) PautLe "C" (500rs) - 1987/1988 - 254.0 399.4 236 4 129.2 f) Daule-Peripa (130MW) - 1988 - - 727.0 552-. g) Paute-Mazar (114OMW) - 1989/1 y90 ?- - - 712.0 h) Toachi (300MW) - 1990/19911/ - - 452.7 Total Futuire Generation 42.7 343.7 1,077.5 2,625.7 3,057.8 3,625.4 3,853.2 4,182.0 5,323.3 6,567.7 7,574.5 Total Generation 2,421.8 2,891.0 3,644.0 4,320.5 4,771.2 5,598.7 6,163.0 6,800.1 7,497.2 8,225.3 9,022.2 T The average year system gerneratior) capability is greater than Lhe dispatched gerneration presented in the table. 2/ llydro-elect1ric power planits.  ECUADOR INECEL POWER TRANSMISSION PROJECT National Interconnected System (SNI) 1980-1990 Energy Balance (GWh)Dry Year1! 1980 1981 1982 1983 1984 1985 1986 1987 1988 9 1990 1) Yearly Energy Consumptioon 2,421.8 2,891.0 3,644.o 4,320.5 4,771.2 5,598.7 6,163.0 6,800o1 7,497.2 8,225.3 9,022.2 2) Existing Generation a) Hydro 534.4, 652.2 723.8 795.5 808.5 812.7 812.7 812.7 812.7 812.7 812.7 b) Thermal 1,829.0 1,878.2 1,852.2 838.5 891.5 1,011.4 1,590.4 2,233.5 2,203.2 1,192.3 922.8 Total Existing Generation 2,363.4 2,530.4 2,576.0 1,634.0 1,700.00. 1,824.1 2,403.1 3,o46.2 3,015.9 2,005.0 1,735.5 3) Future PlantGeneration a) Quito - G.T. (60MW) - 1980 58.4 67.8 25.6 8.6 34.8 38.6 23.9 17.9 18.3 13.3 16.2 b) Esmeraldas-Steam (125MW) - 1981 . - 292.8 812.0 715.4 681.8 812.0 812.0 812.0 812.0 812.0 812.0 c) Paute "A & "B" (500MQ - 1982/83 -J - - 230.4 1,962.5 2,355.0 2,355.0 2,355.0 2,355.0 2,355.0 4,305.0 4,305.0 d) Agoyan (150MW) - 1985J - - - - - 569.0 569.0 569.o 569.o 569.0 569.o e) Paute "C" (500MW) - 1987/1988 21 - - - - - f) Daule-PeriPa (130MW) - 1988 i/ - - _ _ _ _ _ _ 727.0 521.0 521.0 g) Paute-Mazar (140MW) - 1989/199oJ _ _ _ _ - - 680.0 h) Toachli (300MW) - 1990/1991 2/ - - - - - - - - 383.5 Total Future Generation 58.4 360.6 1,068.0 2,686.5 3,071.6 3,774.6 3,759.9 3,753.9 4,481.3 6,2?0.3 7,286.7 Total Generation 2,421.8 2,891.0 3,644.o 4,320.5 4,771.6 5,598.7 6,163.0 6,800.1 7,497.2 8,225.3 9,022.2 / The dry year system generation capability is greater thani the dispatched genieratiorn presented in the table. 2/ Hydro-electric power plants. .,  - 45 - ECUADOR ANNEX 3 Table 3.6 INECEL POWER TRANSMISSION PROJECT 1978 Gross Generation/Purchases, Sales, Local Use and Losses (GWh) Gross Losses . Generation & Power Gross Purchases Sales Station Use Losses Generation % Cuenca 90.3 71.0 0.5 18.8 20.8 Bolivar 6.9 5.9 0.2 0.8 11.6 Azogues 6.8 4.3 0.1 2.4 35.2 Norte 49.0 38.6 0.2 10.2 20.8 Latacunga 25.1 17.3 0.1 7.7 30.7 Riobamba 52.0 46.2 0.3 5.5 10.6 Sur 26.8 21.4 0.5 4.9 18.3 Quito 673.2 583.6 4.5 85.1 12.6 Ambato 57.6 45.6 0.3 11.7 20.3 El Oro 48.1 38.4 0.3 9.4 19.5 Esmeraldes 32.2 28.8 0.2 3.2 10.0 Milagro 50.9 41.6 1.8 7.5 14.7 Sta. Elena 26.3 22.1 0.9 3.3 12.5 Los Rios 24.1 19.5 0.8 3.8 15.8 Manabi 114.0 84.9 7.5 21.6 18.9 TOTAL INXCEL SUBSIDIARIES 1,283.3 1,069.2 18.2 195.9 15.3 EMELEC 994.3 869.0 27.6 97.7 9.8 TOTAL POWER SECTOR 2,277.6 1,938.2 45.8 293.6 12.9  - 46 - ANNEX 4 ECUADOR Attachment 4.1 INECEL POWER TRANSMISSION PROJECT Ongoing and Future Development Projects (a) Ongoing Projects Commissioning Project Capacity Dates - Paute hydroelectric plant (Phase A & B) 500 MW 1982/1983 - Guayaquil No.3 (steam) 73 MW 1980 - Esmeraldas No.1 (steam) 125 MW 1981 - Quito (gas turbines) 60 MW 1980 - Regional Systems' generation 186 MW 1980/1982 - SNI transmission system (138 kV & 230 kV) - 1980/1982 Total (b) Future Projects - Agoyan 150 Nw 1986 - Daule-Peripal/ 130 MW 1988 - Paute - Phase C 500 MW 1987 - Paute-Mazar 140 MW 1989 - Toachi 300 MW 1990 - SNI transmission system (230 kV & 138 kV) - 1982/1985 - Regional systems' transmission system (69 kV & 345 kV) 1982/1985 - Distribution & Rural electrification 1982/1985 - Studies, small generation ( stations and general invest- ments 1982/1988 1/ Corporacion de Desarrollo de Guayas (CEDEGE) is carrying out the dev elopment of this multipurpose project. INECEL is not participating in its financing. The power facilities of project are to be leased by CEDEGE in a multi-year agreement with INECEL.  ECUADOR INECEL POWER TRANSMISSION PROJECT Ecuador's Installed Capacity (KW) ZMELEC, INECEL AND 18SIDIARIES MUNICIPAL SELF-PRODUCERS TOTAL Provinces Hydro Thermal Total Hydro Thermal Total Hydro Thermal Total Hydro Thermal Total Azuay 15.725 14.185 29.910 226 111 337 __ 2.666 2.666 15.951 16.962 32.913 Bolivar 840 5.033 5.873 80 15 95 -- _ 920 5.048 5.968 Canlar 840 1.380 2.220 80 80 -- 9.075 9.075 920 1L0.455 11.375 Carchi 1.620 766 2.386 581 -- 581 -- -- 2.201 766 2.9b7 Cotopaxi 4.200 3.388 7.588 405 492 897 4.551 4.551 4.605 8.431 J3.036 Chimborazo 9.117 5.364 14.481 245 202 147 1.900 711 2.611 11.262 6.277 17.539 El Oro -- 18.576 18.576 2.366 275 2.641 - 578 578 2.366 19.429 21.795 Esmecaldas -- 7.192 7.192 -- 164 164 __ 25.603 25.603 -- 32.959 32.959 Galapagos -- -- -- 689 689 __ 285 285 974 74 Guayas 319.783 319.783 -- 676 676 -- 39.551 39.551 -- 360.010 36O. 10 Imbabura 9.622 6.534 16.156 440 -- 440 871 3.041 3.912 10.933 9.575 20.508 Loja 2.560 9.259 11.819 -- 127 127 206 1.096 1.302 2.766 10.482 13.248 Los Rios -- 21.112 21.112 -- 216 216 -- 7.433 7.433 -- 28.761 28.761 Manabi 33.600 33.600 -- 991 991 __ 4.284 4.284 -- 38.875 38.875 Morona Santiago -- -- -- 153 1.066 1i.219 256 -- 256 409 1.066 1.475 Napo -- -- 71 1.171 1.242 1.800 10.382 12.182 1.871 11.553 13.424 Pastaza 110 945 1.055 -- -- -- 570 570 110 1.515 1.625 Pichincha 85.360 94.816 180.176 2.804 _- 2.804 7.050 30.677 37.727 95.214 125.493 220.707 Tungurahua 74.961 10.980 85.941 -- -- -- 98 98 74.961 11.078 86.039 Zamora Chinchipe -- -- _ 154 154 -- -- 154 154 H TOTAL 204.955 552.913 757.868 7.451 6.349 13.800 12.083 140.601 152.684 224.489 699.863 924.352 I  -48- ECUADOR ANNEX 4 Attachment 4.2 INECEL POWER TRANSMISSION PROJECT Page 1 of 3 Main Characteristics of Future Power Plants (A) HYDROELECTRIC DEVELOPMENTS 1. Paute - Phases "A" and "B" - Dam and Reservoir Type: Arch Dam (concrete) Height: 170 m Length: 400 m 3 Volume: Gross: 120 x 106 m Net : 100 x 106 m3 - Powerhouse Turbines: Pelton (net head: 615 m) Installed Capacity: 5 x 100 MW Firm Capacity : 437 MW Firm Energy : 2355 GWh/year Average Energy : 4017 GWh/year 2. Agoyan - Dam and Reservoir Type: Gravity (concrete) Height: 36 m Length: 270 m Volume: Gross: 1.87 x 106 m3 Net : 0.88 x 106 m3 - Powerhouse Turbines: Francis (net head: 155 m) Installed Capacity: 2 x 75 MW Firm Capacity : 138 MW Firm Energy : 569 GWh/year Average Energy : 1031 GWh/year 3. Paute - Phase "C" - This development is an extension of Paute "A" and "B" described in (1). The additional capacity added to Paute is: Installed Capacity: 5 x 100 MW Firm Capacity : 437 MW Firm Energy : 0 Average Energy : 1710 GWh/year  ANNEX 4 - 49 - Attachment 4.2 Page 2 of 3 4. Daule-Peripa - Dam and Reservoir (multi-purpose: power, irrigation and water supply). Type: Earthfill Height: 78 m Length: 230 m9 Volume: Gross: 6 x 109 m3 Net : 4.3 x 109 m3 - Powerhouse Turbines: Francis (net head: 55.7 m) Installed Capacity: 2 x 65 MW Firm Capacity : 77 MW Firm Energy : 521 GWh/year Average Energy : 710 GWh/year 5. Toachi - Dam and Reservoir Type: Rockfill with impermeable core Height: 154 m Length: 370 m Volume: Gross: 139 x Q6 m3 Net : 94 x 10 m3 - Powerhouse Turbines: Pelton (nethead: 292 m) Installed Capacity: 4 x 75 MW Firm Capacity : 253 MW Firm Energy : 767 GWh/year Average Energy : 1587 GWh/year 6. Paute-Mazar - To be constructed upstream of Paute hydro-development. Paute-Mazar dam will control sedimentation of Paute dam and also will increase Paute firm energy by about 1950 GWh/year. Its main features are described below: - Dam and Reservoir- Type: Gravity (concrete) Height: 170 m Length: 420 m 6 3 Volume: Gross: 500 x 10 6m Net : 460 x 106 m - Powerhouse Turbines: Francis (net head 200 m) Installed Capacity: 2 x 70 MW Firm Capacity : 77 MW Firm Energy : 680 GWh/year Average Energy : 1047 GWh/year  ANNEX 4 - 50 - Attachment 4.2 Page 3 of 3 In addition Paute-Mazar will increase Paute (Phases "A", "B" and "C") firm capacity and firm energy by 100 MW and 1950 GWh/year respectively. (B) THERMOELECTRIC DEVELOPMENTS 1. Salitral Thermal Station (Steam) - Installed Capacity: 73 MW Steam Production Capacity: 295 tons/hour (continuous) Fuel: Bunker "C" (also natural gas) Steam Pressure: 105 kg/cm2 at 5130C Speed: 3600 r.p.m. 2. Esmeraldas Thermal Station (Steam) - Installed Capacity: 125 MW Steam Production Capacity: 428 tons/hour (continuous) Fuel: Bunker "C" 2 Steam Pressure: 139 kg/cm at 5380C Speed: 3600 r.p.m. 3. Quito Thermal Station (Gas Turbine) - Installed Capacity: 3 x 20 MW  -51 - ANNEX 4 Attachment 4.3 ECUADOR INECEL POWER TRANSMISSION PROJECT NATIONAL INTERCONNECTED SYSTEM SIMPLIFIED SINGLE-LINE DIAGRAM QUITO ESMERALDAS 138 kv 276 MW 125 MW W 138 kv STO. DOMINGO 230 k~ QUITO QUEVEDO _30 kv (TDTORAS j 3 0 ~~~~~~~~~~~~~~~23kv8 E~ PISAYAMBO o 69 MW 77 km~~~~~~~~~~~~~~~~~~3k 8 8~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~8k E E 2 0 1 3 8 kv8 kv lo o AM BATO QUEVEDO 230 kv (TOTORAS) 20 kv MA.NABI S - 20M 138 kv vE 0 PASCUALES 230 kv MILAGRO v PAUT 230 kv (X)~~~3 kv 138 kX ESTERO SALADO EMELEC 138 kv 172 MW 164 MW 500 MW World Bank- 22319  ECUADOR INECEL POWER TRA8NMISSION PROJECT 1980-1985 Inor-toent P-oatra (in oI11iona of 1980 constant US dollars) __________1980- - -------19881___98___98__ ---------- 198Z-___----- 1984