Colombia - Power Market Development Project

Document of The World Bank Report No. 13621-CO STAFF APPRAISAL REPORT COLOMBIA POWER MARKET DEVELOPMENT PROJECT OCTOBER 23, 1995 Infrastructure and Operations Division Country Department III Latin America and the Caribbean Regional Office CURRENCY EQUIVALENTS (as of November 1994) Currency Unit = Colombian Peso US$ 1 = 840 Pesos 1 Col$ = US$ 0.00119 Fiscal Year January 1 to December 31 ENERGY CONVERSION FACTORS 1 TOE = 7.3 bbl I MTOE = 12.4 TWh (heat content equivalent) 1 kcal 3.968 Btu I CF of gas = 1000 Btu 1 kWh = 860 kcal 1 m3 gas = 9000 kcal ACRONYMS CARBOCOL Carbones de Colombia (Coals of Colombia) CH-B Central HI-droel6ctrica de Betania (Betania Hydroelectric Plant) CONPES Consejo Nacional de Politica Econ6mica y Social CORELCA Corporaci6n El6ctrica de la Costa Atlintica CYC Corporaci6n Aut6noma del Valle del Cauca DNP Departamento Nacional de Planeaci6n. (National Planning Department) ECC Energy Control Center ECOCARBON Empresa Colombiana de Carb6n ECOPETROL Empresa Colombiana de Petr6leos EEB Empresa de Energia de Bogoti EMCALI Empresas Municipales de Cali EPM Empresas P6blicas de Medellin ERC Energy Regulatory Commission ESMAP Energy Sector Management Assistance Program FEN Financiera Energ6tica Nacional FSC Financial Settlement Center IDB Interamerican Development Bank Interconexi6n El6ctrica Former generation and transmission company ISA Interconexi6n E16ctrica S.A. "E.S.P." (ISA) - the new transmission company' ISAGEN ISAGEN S.A. - the new generation company LRMC Long-run-marginal-cost MHCP Ministry of Finance and Public Credit MME Ministry of Mines and Energy OED Operations Evaluation Department, World Bank ABBREVIATIONS BOE Barrels of oil equivalent Col $ Colombian pesos GDP Gross domestic product kV Kilovolt (I thousand V) kW Kilowatt (Ithousand W) LRMC Long-run marginal cost Mbbl Million barrels MBOE Million barrels of oil equivalent MW Megawatt (I million W) Mt Megatons (1 million metric tons) Tcal Tera calories (1 trillion Calories) TWh Terawatt-hour (1 trillion W ) To avoid confusion this report will refer to Interconexi6n Elctrica when naming the former generation and transmission company, which was also formerly known as ISA.  COLOMBIA POWER MARKET DEVELOPMENT PROJECT Table of Contents 1. THE ENERGY SECTOR AND THE POWER SUBSECTOR.......................................................... 1 A. BACKGROUND ......................................................................1 B. THE ENERGY SECTOR .................................................................1 C. THE POWER SUBSECTOR ..............................................................4 D. POWER SUBSECTOR POLICY AND ISSUES .....................................................7 2. TH E PROJECT................................................................................................................................. 11 A. PROJECT CONTEXT................................................................. . B. PROJECT OBJECTIVES AND DESCRIPTION.................... .............................1. C. PROJECT COST AND FINANCING........................................................13 D. INSTITUTIONAL ARRANGEMENTS.......................................................15 E. PROJECT IMPLEMENTATION...........................................................15 F. ENVIRONMENTAL CONSIDERATIONS..................................................... 19 3. ECONOMIC ANALYSIS..................................................... 21 A. ECONOMIC EVALUATION............................................................. 21 B. RISK ANALYSIS .................................................................... 23 4. THE BORROWER SIS.................................................................................................................. 25 A. ISA ........ ........................................................................................................................... 25 B. FINANCIAL ANALYSIS ...............................................................27 5. AGREEMENTS REACHED AND RECOMMENDATION ...................................................... 31 This report was prepared by Messrs. Jayme Porto Carreiro (Task Manager), HernAn Garcia (Power Engineer), Ricardo Klockner (Financial Analyst), Fernando Lecaros (Tariff Specialist), Robert Bacon (Economist), and Ms. Maria Clara Mejia (Environment Specialist). Messrs. Winston Hay and Luis Vaca- Soto were peer reviewers, and Mr. Robert Crown was the Project Advisor. Supervision Managers include: Mr. Peter Ludwig, Division Chief, and Mr.Yoshiaki Abe, Department Director. Table of Contents ANNEXES 1. POWER SECTOR REGULATORY FRAMEWORK................................................................ 33 2. ENERGY POLICY LETTER.......................................................................................................... 47 3. ENERGY SUPPLY AND DEMAND ...........................................................................................55 4. ELECTRICITY PRICES ................................................................................................................. 57 5. ECONOMIC PERSPECTIVES FOR COLOMBIA ................................................................... 58 6. ELECTRICITY DEMAND .............................................................................................................. 61 7. INDICATIVE EXPANSION PLAN.............................................................................................. 65 8. FINANCIAL PERFORMANCE OF THE POWER SECTOR.................................................. 68 9. ISA'S ORGANIZATION CHART ............................................................................................. 82 10. PROJECT DESCRIPTION, COSTS AND IMPLEMENTATION PLAN ...............................83 11. PROJECT ECONOMIC ANALYSIS.......................................................................................... 115 12. ASSUMPTIONS FOR ISA'S FINANCIAL PROJECTIONS......................................................132 13. ENVIRONMENTAL EVALUATION ......................................................................................... 141 14. TERMS OF REFERENCE FOR TECHNICAL ASSISTANCE.................................................146 15. ISA - MONITORING INDICATORS ......................................................................................... 149 16. SUPERVISION PLAN ................................................................................................................. 153 17. ALLOCATION OF LOAN PROCEEDS .................................................................................... 154 18. SELECTED DOCUMENTS AND DATE AVAILABLE IN THE PROJECT FILES...............155 19. MAPIBRD 26929 ......................................................................................................................... 156 COLOMBIA POWER MARKET DEVELOPMENT PROJECT LOAN AND PROJECT SUMMARY Borrower: Interconexi6n Electrica S.A. - "E.S.P." (ISA) Guarantor: Republic of Colombia Beneficiary: N/A Poverty: Not applicable Amount: A package of two loans: (i) a US$145 million US dollar single currency laon; and (ii) a US$104.3 million equivalent currency pool loan. Terms: (i) repayable in 17 years, including four years' grace, at the standard LIBOR-based interest rate for US dollar single currency loans; and (ii) repayable in 17 years, including four year's grace, at the standard variable rate for currency pool loans. Commitment Fee: 0.75% on undisbursed loan balances, beginning 60 days after signing, less any waivers. Financing Plan: 1BRD: 249.3 ISA: 160.7 TOTAL: 410.0 Environmental Classification: B Estimated Economic Rate of Return: ISA's 1994-99 investment program, which includes a number of small investments not included in the project, has an estimated net present value of US$64 million and a benefit/cost ratio of 1.34 at a discount rate of 12%. The estimated economic rate of return is 27%. Map: IBRD 26929 Project Identification Number: CO-PA-6887  COLOMBIA POWER MARKET DEVELOPMENT PROJECT 1. THE ENERGY SECTOR AND THE POWER SUBSECTOR A. Background 1.1 Colombia's prudent macroeconomic management enabled it to achieve one of the highest and most stable growth rates in Latin America during the 1980s (3.7%). Solid economic growth of about 4.5 percent per year for the past four decades, combined with a drop in the population growth rate to 2.0 percent per year, have facilitated substantial improvement in social conditions. 1.2 The Government sought to further improve the economy's performance during the 1990s through appropriate institutional reforms. In order to spur growth, the Barco administration (1986-90) launched an economic reform program during the last year of its tenure which was vigorously pursued during the Gaviria government years (1990-94). It involved opening trade, exposing economic agents to competition and fostering private sector participation in areas where the public sector traditionally prevailed (e.g. ports, railways, state-owned banking, state- controlled industrial enterprises, the energy sector in general, and the power subsector in particular). The Samper government's (1994-98) policies have emphasized socially-oriented priorities, but it has continued to support the Gaviria-era structural reforms. Its major economic challenge will consist of taking advantage (and avoiding the pitfalls) of the large foreign currency revenues associated with massive increases in oil production which have the potential for putting the economy (GDP per capita of US$1620) on a faster growth path with sustained GDP growth of more than 5 percent per year. B. The Energy Sector 1.3 Within the last decade the energy sector has become the single most important agent in the Colombian economy. It has replaced coffee as the prime source of foreign exchange and will continue to grow in importance during the next ten to fifteen years. Energy Sector Organization 1.4 The energy sector has been characterized by the predominance of large public enterprises in the power, coal, and hydrocarbon industries. Empresa Colombiana de Petr6leos, ECOPETROL, the state oil enterprise, has been responsible for oil and gas exploration, for running the refineries and for importing oil products. In the coal subsector, Carbones de Colombia, CARBOCOL owns, together with EXXON, the Cerrej6n coal mine and Empresa Colombia de Carb6n, ECOCARBON is responsible for managing mining concessions and policy. The power subsector is characterized by a more decentralized structure with a large number of utilities which until recently were owned by the central or local governments. -2- 1.5 In the power subsector, a major reorganization has been taking place since 1991: a competitive market at the generation level is being organized, an Energy Regulatory Commission has been set up and Interconexi6n El6ctrica S.A., the major generation and transmission enterprise, has been split into a transmission and dispatch enterprise which kept the name ISA', and a generation company (ISAGEN). 1.6 The energy sector is under the jurisdiction of the Ministry of Mines and Energy (MME). The Ministry is in charge of overall sector policy making; the independent Energy Regulatory Commission is in charge of regulating prices for electricity and natural gas. 1.7 Other major government agencies involved in the energy sector are the National Planning Department (DNP), the National Energy Finance Corporation (FEN) and the Ministry of Finance (MHCP). The latter became the owner of a number of power plants together with substantial equity in the sector's enterprises due to a financial restructuring operation which took place in 1991-92. It is now a major stockholder in the sector and it intends to divest its holdings which amount to as much as 50% of the power sector's assets. DNP is in charge of approving major publicly funded investments in the energy sector. FEN lends to companies in the energy sector. It raises funds in the capital market and it also manages sector loans. Energy Reserves and Consumption 1.8 Colombia has abundant energy resources: proven oil reserves are currently on the order of 3.2 billion barrels, equivalent to a Reserves/Production (R/P) ratio of around 20 years; proven (8.3 trillion cubic feet ) and probable gas reserves amount to around 12.5 trillion cubic feet, equivalent to a R/P ratio of about 70 years; coal reserves are estimated to be on the order of 2.2 billion tones (R/P in excess of 100 years); the hydroelectric potential is around 90 Gigawatt (GW), of which less than 10% (about 8 GW) has been installed. 1.9 Final energy consumption in Colombia amounted to 244,00OTcal (17 1MBOE) in 1994, which is equivalent to around 5BOE per capita. This amount is low when compared to the Latin American average (around 8BOE) and is less than a quarter of the European per capita consumption. The vigor exhibited by the increased energy production in the last decade, which grew at 6% per year in the last decade, was not followed by a corresponding increase in consumption. Between 1984 and 1994, internal demand grew by less than 3% per year, slightly belowN the rate of GDP growth. (See Annex 3 for details.) Lessons from Previous Bank Involvement 1.10 The Bank has lent more than US$2 billion in 32 operations to support the Colombian energy sector, mainly by financing investments in power generation and transmission. Bank borrowers for power projects in Colombia since 1970 include Interconexi6n Elctrica (3 loans, 'To avoid confusion, this report will refer to "Interconexi6n Eldctrica" when naming the former generation and transmission company, which was also formerly known as ISA. -3- US$ 250 million), EPM (4 loans, US$ 430 million), EEB (4 loans, US$ 700 million), Government (3 loans, US$ 362 million), FEN and CORELCA (1 loan each for US$ 170 and US$ 36 million, respectively). The last investment loan to the sector became effective in May 1987 and corresponded to a US$ 172 million credit to EEB ("BogotA Power Distribution II Project" Loan 2643 CO). 1.11 In 1990 an extensive OED study2 found that the Bank supported projects generally met their physical objectives, and helped advance technical capabilities in the beneficiary agencies, but failed to establish a sustainable institutional and financial framework for the sector. It identified weaknesses in the power subsector and recommended its restructuring through the introduction of adequate regulation and private sector participation. 1.12 Despite its institutional problems, overall experience with project execution in the Colombian power sector has been positive, with the exception of (a) two loans to Empresa de Energia de Bogota - EEB (the Guavio project loan supported a hydroelectric project with major construction delays and problems, and the Distribution II project was partially canceled by mutual agreement due to non-achievement of the project's institutional objectives) and (b) the FEN Power Development Finance Project. The Project Completion Report for the latter project (June 1993) points out that the financial problems of the sector could not be solved by creating a specialized financial intermediary such as FEN, and that its potential for mobilizing resources was not effective unless the utilities it lent to were restructured and became credit-worthy borrowers. These problems, coupled with the OED findings, led to the Bank's support for institutional restructuring before new operations could be contemplated. 1.13 Having achieved the major institutional reforms required for restructuring the energy sector, the Bank is now providing support for their implementation through the Energy Sector Technical Assistance Project (Loan 3827-CO) which was approved by the Board in December, 1994. 1.14 Key lessons which have been learned from other Bank loans include the need to ka) position infrastructure projects within a sector-wide institutional context; (b) complement investments with technical assistance components to ensure that projects do not fail due to an inadequate institutional framework; (c) systematically assess the economic and financial sustainability of tariff levels; and (d) embed projects within a balanced investment program. The project will internalize these lessons by: (a) coordinating the proposed actions with the umbrella Energy Sector Technical Assistance project currently under execution; (b) providing specif c specialized training and technical assistance in the power planning, dispatch and operations areas to complement the latter; and (c) by designing the project to support the overall institutiona, framework of the sector. 2 OED, Colombia-The Power Sector and the World Bank, 1970-1987, Report No. 8893 (June 28, 1990). -4- C. The Power Subsector Electricity Demand and Supply 1.15 During 1994 gross generation reached 39 TWh with a peak demand of around 6900 MW. Until the late seventies, electricity demand grew at rates in excess of 10% per year. During the early 1980s demand growth decreased to rates on the order of 5% per year. A number of economic and social factors explain this change: economic growth diminished and new service extensions decreased with the saturation of coverage. Starting in the late eighties and continuing into the 1990s, the substitution of electricity by natural gas and LPG has been actively promoted and exerted a moderating influence on electricity growth. This effect is expected to continue in future years with the extension of natural gas supplies to major cities like Medellin and Cali. Finally, tariff adjustments in electricity are expected to continue until they reach marginal cost levels, and will also contribute to restrain demand growth. 1.16 Forecasts for electricity demand have been made within the context of overall energy requirements, considering such factors as population growth, economic growth, relative prices and interifuel substitution. In 1995, the Ministry of Mines and Energy prepared a forecast using a base scenario corresponding to an economic growth rate of 5.1 -5.3% until 2000, stabilizing at the 5% level thereafter (these values are slightly lower than the Bank's own projections). On this basis, electricity requirements are expected to increase at about 5.3% for the same period. 1.17 Total effective generation capacity amounts to 10100 MW of which 7900 MW correspond to hydro facilities. The major generation enterprise is ISAGEN (2600 MW) followed by the municipal utilities of Bogota (EEB - 2200 MW) and Medellin (EPM - 1500 MW); regional utilities on the Atlantic Coast (CORELCA), in the South West (CVC and CHB), and several distribution companies, which also operate power plants, account for another 3000 MW; the Ministry of Finance owns 272 MW in four plants which are operated by local utilities. Finally, 240 MW of private generation are in service. 1.18 System dispatch is performed by ISA, which also operates the principal transmission lines. Electricity distribution is accomplished by three major municipal utilities in Bogota, Medellin and Cali, by 24 regional distribution companies owned by the National Government, and by smaller municipal companies, one of which was recently privatized. System Expansion 1.19 System expansion is taking place within the new commercial and institutional framework whereby compulsory planning has been replaced by "indicative" planning. In this context, future plans are drawn up with the purpose of serving as guidelines for interested investors (which include both existing companies as well as prospective entrepreneurs). 1.20 The incorporation of new investors in the power business (both as a consequence of the new institutional framework and the drought-induced emergency) has been successful as -5- evidenced by projects such as a 90 MW generation plant in Cartagena developed with local capital (Proel6ctrica), the 100 MW combined cycle gas plant in Barranquilla operated by Sevillana de Electricidad, and the ongoing construction of an aggregate 1129 MW of thermal generation with the participation of foreign investors. 1.21 Power plants under construction which are expected to come on line by 2000 include': (a) 747 MW of combined cycle gas-fired turbines in the Atlantic Coast owned by ABB/Distral and 232 MW in the Valle Region owned by Enron/Propal; (b) 450 MW of coal-fired plants to be developed by private independent power producers (150 MW of which have already been awarded); (c) the 390 MW Porce II hydro plant under construction by EPM (a municipal utility); (d) the 340 MW Urri I and the 375 MW Miel I hydro plants under construction by two mixed capital consortia and (e) 400 MW (probably gas-fueled) for which potential investors will be sought. The response to requests for providing this additional capacity is expected to be highly competitive: 21 private sector consortia have expressed interest in developing different power plants. Interested investors include existing private generators, oil companies, and industrial and agricultural enterprises. The prospective developments include a variety of plant types encompassing a large proportion of gas-fueled units, together with coal, fuel oil, heavy crude, bagasse and small hydro stations. 1.22 The expansion of the transmission system is to be developed by ISA. The capacity expansion will be achieved by strengthening transmission links through a combination of 500 kV and 230 kV lines in order to avoid potential bottlenecks which could lead to either peak rationing or to higher operating costs in the system. Furthermore, the development of the transmission system is essential for a competitive energy market to operate. Electricity Pricing 1.23 Until 1994, electricity prices were regulated at both the wholesale and retail levels. This pricing system was replaced, under the new institutional arrangements, by a competitive market for bulk (wholesale) supplies where distribution companies and major consumers (with loads in excess of 2 MW) enter into contracts with generation enterprises at freely agreed prices. On a day to day basis, generators are reimbursed for sales to the power pool at system marginal cost. In addition, regulated transmission charges are levied to remunerate ISA, the interconnection company. 1.24 Final user prices are set by the Energy Regulatory Commission. During the 1970s and early 1980's important cross-subsidies were incorporated into retail prices, by charging relatively high prices to industrial and commercial users in order to maintain low prices for domestic consumers. This policy became financially untenable but tariffs were not reformed and massive subsidies were required from the central government. As part of the power sector's financial restructuring, tariffs charged to final customers maintained an increasing trend during 1991-94. Towards the end of 1994, sector average electricity rates amounted to about 90% of long-run 3"Plan de Expansi6n de Referencia Generaci6n-Transmisi6n", Ministerio de Minas y Energia- Unidad de Planeaci6n Minero-Energ6tica and ISA, April 1995. -6- marginal costs. The average rate applied to final customers ranged between 6 and 10 UScent/kWh. 1.25 In 1994 the Public Services Law and the Electricity Law provided directives for price adjustment by setting strict limits on cross-subsidies and mandating that cost based rates be put into place by July 2000 at the latest. Improvements regarding pricing can be expected to continue due to (a) the fact that bulk supply prices (which account for over 50% of retail supply costs) are to respond to market forces thereby exerting pressure on distribution companies and Government to support the ERC in achieving pricing goals; (b) the policy to incorporate private capital into the distribution business, which will require sound pricing assurances; (c) the functioning of the Energy Regulatory Commission where independent regulators outnumber Government representatives and can be expected to resist attempts to freeze prices or otherwise imperil the sector's financial health; and (d) provisos in the.Domiciliary Public Services Law which explicitly require public agencies, which frequently fail to pay their bills, to budget funds for paying for public services such as electricity. Power Subsector Financial Performance 1.26 The 1984-90 period was characterized by a considerable deterioration of the subsector's financial indicators (see Annex 8 for details). This decline took place because of short-sighted policies that prevented electricity prices from keeping up with inflation and the devaluation of the Colombian peso. The power sector was heavily subsidized by the Government and average rates during 1980-84 covered only about 50-60% of marginal costs. 1.27 As a result of overbuilding power plants, utilities incurred significant amounts of external debt to fund new investments. The consolidated indebtedness of the power subsector amounted to about US$5.2 billion in 1990, roughly equivalent to one third of the country's total external debt. The devaluation of the local currency, coupled with low prices, forced many utilities to seek Government support for servicing their debt. 1.28 The sector also showed signs of administrative, financial and commercial mismanagement. Power losses, ranging between 14% and 32% in 1990, were out of control in many companies. Arrears of energy bills from distributors to generators, and from government agencies and private customers to distributors exceeded 6 months in many utilities. 1.29 As part of the Economic Adjustment Program implemented in 1991, the Government defined a long-term strategy to improve both efficiency and the financial situation of power utilities. This strategy aimed at: (a) reducing the utilities' foreign debt service; (b) establishing a rational tariff structure and a sustainable rate level; and (c) improving managerial efficiency of distribution companies. 1.30 The debt issue was successfully dealt with through a debt/equity swap and a debt/asset swap whereby the Government took charge of many company debts in exchange for assets or for equity shares in the enterprises. Pricing reforms were implemented in order to reflect economic costs and to reduce subsidies to residential customers by following a well-defined plan. Finally, -7- the Government established performance contracts with utilities profiting from Government loans and guarantees; although there have been some positive gains in efficiency, there remains vast room for improvement in most distribution utilities. Power Sector Financial Perspectives 1.31 As a result of the actions taken during the 1991-94 period, most power sector companies now exhibit satisfactory indicators. Rates of return exceed 8% in the large companies as well as many smaller, solvent and profitable companies. Future performance will depend on a continued application of pricing adjustments together with efficiency improvements to keep costs under control. 1.32 Financial projections for the sector indicate that the performance of most enterprises in the sector is satisfactory, with the exception of a few small distribution companies whose assets only account for about 4% of total subsector assets, and who would still remain insolvent and unprofitable. The latter group includes utilities with a predominantly residential market structure of low income customers. A number of such utilities are expected to require support due to the cross-subsidization applied to retail sales. Under LRMC pricing levels, the support required from the Government in 1995 would amount to around US$56 million, or less than 5% of the sector's revenues. 1.33 At current average price levels, on the order of 90% of marginal costs, most companies exhibit a healthy financial position. However, there is room for efficiency improvements particularly in regard to lowering commercial losses and controlling theft which are only possible through strong management action. For example, if commercial losses could be reduced, through metering controls, from their present level of 22% to levels on the order of 10% to 12%, the increase in gross revenues would have the same financial effect of an immediate increase in prices to marginal cost levels. D. Power Subsector Policy and Issues 1.34 Energy Sector Policy. The Government's overall policy regarding the energy sector consists of implementing the mandates contained in the Public Service Law and the Electricity Law. The general orientation consists of: (a) limiting the state's intervention in the sector to the formulation of general policy guidelines and to regulation, thereby allowing the private sector to undertake investment and operational tasks; (b) stimulating competition; (c) encouraging private sector participation; and (d) establishing cost-reflective tariffs with due consideration to low income users. 1.35 The sector is emerging from a traumatic supply crisis which curtailed energy demand by as much as 15% during the period February 1992-March 1993. This crisis provided additional See Annex 2 - Minister of Mines and Energy policy letter of November, 1994, COMPES Document No. 2763 (2/15/1995) "Strategies for the Expansion of the Power Sector, 1995-2007, and Law No. 188 (6/2/1995) "National Development Plan". -8- impetus for reform by forcing the installation of emergency generation with hitherto nonexistent private sector participation. 1.36 The Bank has supported the Government since 1991 in the process of power sector institutional reform. The Bank has helped to shape and to define a new vision for the energy sector by: (a) supporting analyses of the sector's problems and identifying the issues; (b) exploring the options for addressing them; (c) fostering constructive debate concerning past conceptual and systemic deficiencies attributable to inadequate institutions; (d) designing a reform program; and (e) by supporting the implementation of this program. 1.37 The sector was gradually reorganized, with Bank support, during the 1991-94 period. The process incorporated efficiency, accountability and financial responsibility incentives into sector corporations. Financial restructuring whereby the Government injected massive resources into the sector was accompanied by tariff reforms which have steadily raised electricity prices with a view to reaching economic cost levels by 1998. Power Subsector Reform Program 1.38 The major elements of the restructuring process culminated in 1994 with the approval by Congress of two major statutes: a Public Services Law which provides a general framework for the supply and pricing of electricity, water, natural gas and local telephone services; and an Electricity Law which spells out sector-specific provisions regarding organization, responsibilities and functions of different entities. Both of these laws emphasize the introduction of competitive incentives and provide for the regulation of non-competitive supplies. The Government anticipated the approval of these laws by creating the required regulatory institutions, by fostering the incorporation of private capital into the generation business and by reorganizing some of the major companies in the sector in order for them to operate according to the proposed structure. 1.39 The objectives behind the Government's power subsector institutional reforms include: (a) fostering efficiency through competition together with a strong, transparent and independent regulatory framework; (b) an institutional restructuring involving the separation of national transmission from generation and the corporatization of existing state power companies by ultimately transforming them into joint stock corporations; (c) completing the financial restructuring and rehabilitation of the subsector through tariff and subsidy reforms;(d) promoting the participation of private sector capital in new projects; and (e) the divestment of existing power plants and utilities. 1.40 The implementation of these reforms has proceeded successfully: the Energy Regulatory Commission (ERC) has been operating since 1993; the conditions for a competitive market at the generation level have been defined and their implementation was initiated in early 1995. Private sector participation has been concentrated mainly in generation through the installation of more than 1000 MW of thermal capacity. These developments were followed by the organization of the open access network operated by ISA (the borrower) as an independent, regulated, transmission company, following provisions in the Electricity Law. -9- Current Reform Implementation Issues 1.41 The major hurdles regarding the power sector's reorganization and financial rehabilitation were cleared during 1991-94, and the system can be characterized as entering a period of institutional consolidation which will require assistance while experience is gained under the ne rules, as well as putting in place supportive infrastructure. Some of the issues to be addressed in this new phase are: (a) Power Market and System Expansion. Since early 1995 a market for bulk energy and capacity has been operating. The final objective of this market is to create an environment whereby private producers will engage in generation investments based on the income they can derive either from the spot market or from long term contracts with large users (such as major consumers or distribution companies). This has enabled the Government to limit its commitments and exposure to the transmission and distribution components of the industry. Although no major investments in new capacity are required in addition to those already planned or in execution until 2000, beyond that date the system will have to prove that it can survive as a mature, competitive, industry. Until now the private sector's response has been encouraging, as evidenced by the numerous proposals, both local and foreign, for new plant development. (b) Transmission and Dispatch. A major responsibility for enabling the market concept to be successful has been vested in ISA, the transmission and dispatch enterprise. ISA is in the process of upgrading its system in order to fulfill the required dispatching and clearing house functions for the market to function smoothly. The interconnection network will also require reinforcements in order to allow an unimpeded flow of energy between generators and demand centers. These investments are to be partially financed by the proposed loans and paid through adequate, regulated, network charges. (c) Distribution. At the distribution level, private sector participation has been less successful. Since the initiation of the reform process only one small distribution company has been privatized. This can be partially explained by the reluctance of local politicians to relinquish the power they exert over a number of these companies. However, the possibilities for the ultimate privatization of distribution companies have improved with the approval of the Public Services Law and will continue to do so with planned tariff increases. Through the Energy Sector Technical Assistance Project, the Bank is assisting the Government to evaluate options and formulate a strategy to introduce private management and equity in distribution companies, and to increase their overall efficiency. In addition, the Government has requested Bank assistance in the preparation of a Power Distribution Project to reduce costs,to adopt main distribution companies' structure to the reformed sector organization and to improve and expand distribution services. - 10- (d) Tariff Adjustment Program. The proposed tariff adjustment path appears to be sound and strikes a balance between financial objectives and a constitutional mandate to provide subsidies to lower income consumers (see the financial projections in Annex 8). The adjustment is taking place within the context of the new sector laws promulgated in 1994 which allow a six-year period for executing it. Nevertheless, Government plans are to reach the full economic cost levels by 1998. 1.42 The most pressing short term implementation problem facing the sector consists of setting up the competitive market for bulk supplies. This involves regulatory issues, which constitute a major challenge for the Energy Regulation Commission and transmission and dispatch issues under responsibility of ISA. 1.43 The sound functioning of the bulk power market, under the reformed legal and regulatory framework requires that appropriate procedures are set in place to: (a) avoid monopolistic pricing, collusion and other price-distorting behavior and (b) allow price signals to operate so that they attract investors to the generation business. This issue is being addressed with support from the Technical Assistance Loan for the energy sector, which has a component exclusively oriented towards ERC support. 1.44 The transmission and dispatch issues involve the need for upgrading dispatching procedures and implementing financial clearing house functions that are acceptable to participants in the bulk market. This upgrading will require investments in both telecommunications and computing equipment and software. For the market to function effectively, transmission bottlenecks should be lifted in order to allow free energy flows between generators and bulk consumers. The proposed project will support ISA in addressing these issues by: (a) financing the required control center hardware and software; (b) financing transmission lines and substations; and (c) complementing the Technical Assistance Project with an additional training component oriented towards dispatch and clearing-house functions. - 11 - 2. THE PROJECT A. Project Context 2.1 The country's prospects for economic development and the Bank's assistance strategy were discussed by the Board on December 16, 1993. The country assistance program seeks to help the Government consolidate and increase its structural reforms, to support private-sector-led growth, to improve the delivery of basic services, to protect the environment, and to strengthen institutional capabilities. It proposes to maintain a lending program with emphasis on technical assistance and it explicitly endorses support for a comprehensive reform of the power sector which would create an environment which attracts private capital into the sector. The proposed project responds to this strategy by supporting the implementation of the ongoing power sector reform program. It is also the first major lending operation for the power subsector since 1987 and the first loan to ISA since 1978. 2.2 Over the past four years, the Bank has had an active role in promoting institutional reform in the Power Sector in Colombia. During this period, substantial changes have been made to the legal/regulatory and the institutional frameworks to introduce competition and transparent regulation. Two complementary approaches have been adopted for this support: (a) provision of technical assistance in preparing and implementing the sector reform program, and institutional strengthening; and (b) lending support for specific projects and investments which will consolidate the reform process and promote the effective operation of key sector institutions. 2.3 Technical assistance will continue to be provided through the Energy Sector Technical Assistance Project which has supported institutional reform within the energy sector as a whole. It includes: (a) assistance in setting up regulatory agencies and developing pricing policies for power and gas; (b) assistance to the power and gas sectors in the process of incorporating private capital and introducing competitive incentives; (c) assistance in developing environmental regulations and guidelines for the energy sector; and (d) development of a demand side management strategy. 2.4 Processing of the proposed project would be a continuation in the implementation of Bank-endorsed policies: It will advance the power sector reform program by consolidating a stronger national transmission system and by supporting the organization of a bulk supply market for electricity. B. Project Objectives and Description 2.5 The project's overall objective is to support power sector reform by facilitating the operation of a competitive bulk supply market for electricity. Specifically, the project seeks to lift transmission constraints that hinder an open access of publicly as well as privately owned power generators to the grid and to support ISA in its role as transmission network operator, system generation dispatcher and commercial transactions coordinator. The project will be a key component of the comprehensive power sector restructuring that is being put in place with Bank assistance. - 12 - 2.6 The project consists of three components (see also Annex 10 - Project Description, Costs and Implementation Plan): PART A: Energy Control Center (ECC) and Financial Settlement Center (FSC). 2.7 This component includes the upgrading of the data acquisition and control functions of ISA's existing ECC and the installation of a FSC. The project will finance the purchase of measurement, data acquisition, telecommunications, data processing equipment and software. PART B: Strengthening and Expansion of the Interconnected Transmission System. 2.8 This component includes investments to strengthen and expand the national transmission system; the following is a summarized list of major elements: (i) San Carlos-San Marcos System. (a) construction of a single circuit, 384 km, 500 kV transmission line interconnecting the East Antioquia hydroelectric complex to the Valle del Cauca Department; (b) construction of a single circuit, 30 km, 230 kV transmission line interconnecting the La Virginia and La Hermosa substations; (c) expansion of the San Marcos 500/230 kV substation; (d) construction of the La Virginia 500/230 kV substation; and (e) construction of the San Carlos 500/230 kV substation. (ii) Atlantic Coast System: (a) reactive compensation for the Chini substation; (b) expansion of the Cerromatoso 500/230 kV substation; (c) construction of the Urabi 230/115 kV substation; (d) construction of the double circuit, 80 km, 230 kV La Loma- El Copey transmission line; (e) expansion of the 500/115 kV Chinu substation; (f) expansion of the 500/230 kV Sabanalarga substation. (iii) Other Transmission Components: (a) reactive compensation for the Cafio Lim6n substation; (b) construction of the single circuit, 160 km, 230 kV transmission line between Paipa and Bucaramanga; (c) construction of the Paipa 230 kV substation; (d) construction of the Bucaramanga 230 kV substation; and (e) construction of a link between the San Felipe substation and the 230 kV Esmeralda-La Mesa transmission line; PART C: Technical Assistance: 2.9 This part includes the provision of consulting services and training programs to assist ISA in the strengthening of its capabilities to assume its roles of: (i) transmission network operator, (ii) power dispatch coordinator and (iii) bulk electricity transaction clearing house all in the areas of power market, planning and engineering, systems operations and dispatch, management of financial matters and environmental issues and other areas agreed with the Bank. Corresponding activities will be agreed upon between ISA and the Bank subject to an annual plan to be approved - 13 - by the Bank. An initial list of studies and training activities for the first year of execution of the project is included in Annex 10. C. Project Cost and Financing 2.10 The cost estimate for the project is summarized in Table 1, details are in Annex 10. The project's total cost including taxes, duties, physical contingencies, price contingencies and interest during construction is estimated at US$ 410.0 million, of which US$ 249.3 million (60%) corresponds to direct plus indirect foreign costs and US$ 160.7 million (40%) corresponds to local costs. Taxes and import duties are estimated at US$43.9 million. Cost estimates are in December 1994 prices. 2.11 Costs are based on ISA's estimates, which have been reviewed by the Bank and found acceptable. ISA maintains a database of transmission and substation costs with similar characteristics to those of the project; it was updated during project preparation on the basis of recent international bids for similar projects. Physical contingencies, which amount on average to 12%, were estimated based upon the type of project and the status of its design. Price contingencies assume: (a) a project execution period of six years based on the 1994 Bank standard disbursement schedule for power projects in LAC, and (b) escalation rates over and above base cost plus physical contingencies of 2.6% for 1995-2001. - 14 - TABLE I COLOMBIA - POWER MARKET DEVELOPMENT PROJECT COST ESTIMATE (US$ thousand) SUBTOTAL TOTAL FC LC PART A: Energy Control Center and Financial Settlement Center 1. Engineering and Administration 6,323 2,380 8,703 1.1 Engineering 6,323 2,061 8,384 1.2 Administration 0 319 319 2. Direct Construction Cost 10,096 1,686 11,782 Subtotal 16,419 4,066 20,485 3. Physical Contingencies 2,463 610 3,073 SUBTOTAL PART A 18,882 4,676 23,558 PART B: Expansion of the Inter-connected Transmission System 1. Engineering and Administration 530 21,204 21,734 1.1 Engineering 530 14,887 15,417 1.2 Administration 0 6,317 6,317 2. Direct Construction Cost 153,370 94,502 247,872 2.1 Land Purchase 0 6,507 6,507 2.2 Lines and Substations Construction 153,370 87,995 241,365 Subtotal 153,900 115,706 269,606 3. Physical Contingencies 23,085 17,356 40,441 SUBTOTAL PART B 176,985 133,062 310,047 PART C: Technical Assistance to ISA 1. Technical Assistance 1,927 1,021 2,948 1.1 Studies 964 443 1,407 1.2 Training 964 578 1,542 Subtotal 1,927 1,021 2,948 3. Physical Contingencies 289 153 442 SUBTOTAL PART C 2,216 1,175 3,391 Total A+B+C 1. Engineering, Administration and Technical Assistance 8,780 24,606 33,386 2. Direct Construction Cost 163,466 96,188 259,654 Subtotal 172,246 120,794 293,040 3. Physical Contingencies 25,837 18,119 43,956 SUBTOTAL A+B+C 198,083 138,913 336,996 Escalation 14,460 6,807 21,267 Subtotal (Including Escalation) 212,544 145,719 358,263 Interests During Construction 36,770 15,009 51,779 TOTAL PROJECT INCLUDING TAXES AND DUTIES 249,314 160.729 410,042 Taxes and Duties 0 43,908 43,908 TOTAL PROJECT WITHOUT TAXES AND DUTIES 249,314 116,821 366,134 2.12 To estimate total required financing, the Bank's interest rate of 7.1% per annum (effective at the time of the appraisal) and a 0.25% p.a. commitment fee were used for the foreign component. Interest during construction for the local currency was estimated at 5% per annum in constant terms, which is equivalent to the rate applied by FEN to loans to utilities for power projects. Bank loans for a total of US$ 249.3 million are proposed to cover the foreign currency component. Local financing would be provided by ISA's own cash generation (see Financial Analysis). - 15 - Financing Plan (US$ million) LC FC TOTAL IBRD 0 249.3 249.3 ISA 160.7 0 160.7 TOTAL 160.7 249.3 410.0 2.13 The proposed loan package comprises two loans. A first loan for US$145 million (58% of total) would be a LIBOR-based US$ Single Currency Loan, with 17 years repayment including a grace period of 4 years. A second loan equivalent to US$104.3 million (42% of total) would be a Currency Pool Loan involving 17 years repayment, including a grace period of 4 years. D. Institutional Arrangements 2.14 Responsibility for overall oversight of ISA's expansion plans is vested in the Ministry of Mines and Energy (MIME) and the National Planning Department (Department Nacional de Planeaci6n, DNP). MME and DNP are responsible for evaluating ISA's proposals and making recommendations to the CONPES. The proposed project, which is part of the Third Transmission Expansion Plan of ISA, has been reviewed by MIME and DNP and approved by CONPES (National Council for Economic and Social Policy). CONPES's approval includes authorization to enter into financial arrangements for internal and external financing for the project. 2.15 The project would be implemented under Loan Agreements between the Bank and the Borrower and Guarantee Agreements between the Bank and the Government. E. Project Implementation 2.16 The project will be implemented by ISA. Interconexi6n El6ctrica, ISA's predecessor had extensive, lengthy experience and performed well in implementing Bank financed projects. Part A of the project (Energy Control Center and Financial Settlement Center) would be the responsibility of ISA's National Dispatch Directorate. Implementation of Parts B (Expansion of the Interconnected Transmission System) and C (Technical Assistance) of the project would be the responsibility of a Project Executing Unit (PEU) under the Transmission Directorate. The PEU is well staffed with experienced professionals and has enough resources and autonomy to seek consultant support whenever this is needed. The Project Execution Directorate has successfully carried out several projects financed by loans from the Bank and IDB and has proven implementation capabilities. 2.17 Project preparation is well advanced. Pre-feasibility studies for the ECC and FSC centers have been prepared by ISA, have been reviewed by the Bank and found satisfactory. Additionally, ISA has procured and will finance from its own resources the participation of a specialized consulting firm for completing the project design and the preparation of bidding documents for the implementation of the ECC and the FSC. These are expected to be ready by - 16 - end 1995; before any procurement for this project component takes place. However, to ensure that designs for the ECC and the FSC are completed in time, during negotiations agreements were reached with ISA that, as a condition for disbursement for goods and services under part A of the project, ISA will provide satisfactory final design of the ECC and the FSC. Planning and engineering design studies for the transmission component, which accounts for about 95% of the total project cost, have been prepared by ISA. ISA will procure in due time and will finance with own resources specialized support from engineering firms for the preparation of executive design and bidding documents and for the supervision of the construction for each subcomponents of part B of the project in accordance with corresponding execution schedules. Implementation procedures submitted by ISA have been reviewed by the Bank and found satisfactory. 2.18 In view of the new functions assigned to the company, the appraisal team reviewed with ISA those areas that require strengthening. These include: (a) the modification of dispatch rules and the establishment of clearing house functions; (b) power system planning; (c) training for the use of new dispatch and settlement models; and (d) development of costing tools to calculate network costs and network charges. 2.19 To deal with the latter subjects, Part C of the project would provide technical assistance in the form of studies by specialized consultants and training --mostly abroad-- for ISA's professional staff During negotiations ISA and the Bank agreed that ISA will prepare two annual plans for the carrying out of Parts Cl (studies) and C2 (training) of the Project to be approved by the Bank before the end of the preceding year. A list of the activities comprised in the studies program for the first year of execution of the Project was agreed upon, including the terms of reference for the consultant services and is available in the project file (see Annex 14). 2.20 Project Implementation Plan (PIP): During appraisal ISA submitted a satisfactory Project Implementation Plan (PIP). The PIP details the project management and implementation arrangements, is part of the project file and is referenced in the loan documents. For each component of the project the PIP addresses its principal features: scope and objectives, implementation plan, and implementation and disbursement schedules. The PIP will be the basic reference for ISA's management in order to monitor project implementation. The PIP will also provide the reference benchmarks for Bank supervision of the project's components. 2.21 Procurement arrangements for the proposed project are summarized in Table 2 '. Purchase of goods and equipment and contracting of construction works to be financed with proceeds of the loans for the following activities would be carried out in accordance with the Bank procurement guidelines, Bank Guidelines for Procurement under IBRD Loans and IDA Credits (January 1995). Purchases of goods and equipment for transmission lines and substations for a total of US$129.0 million would be procured under International Competitive Bidding (ICB). Computers and other electronic equipment for implementing the ECC and FSC for a total amount of US$ 12.3 million would be procured through Limited International Bidding (LIB) because there is only a limited number of potential suppliers. Works for construction of ISA is exempted from application of Law 80, which regulates contracts involving public entities, in respect to all aspects of Project execution, including procurement. (See Annex 1, Electricity Law.) -17- transmission lines and substations for a total of US$31.6 million would be procured under ICB. Equipment and installation services for substations and transmission lines for a total amount of US$50.0 million would be procured under ICB. Procurement of consultant services for a total amount of US$5.0 million will be carried out in accordance with the Bank Guidelines for the Use of Consultants (August 1981). An aggregate amount of US$1.0 million would be used to reimburse foreign expenditures incurred by ISA in its training abroad of ISA staff, such as tuition fees and travel expenses for attending courses and seminars. Bank issued standard bidding documents would be used for all procurement of goods and works. For complex time-based consulting assignments Bank issued standard form of contract for consulting services will be used. To expedite procurement, an initial list of procurement packages was agreed with ISA and is available in Annex 10. Procurement packages under ICB arrangements would be about 30 with an average cost of about US$ 7.4 million, a minimum cost of US$ 1.0 million and a maximum cost of about US$ 38 million. There would also be about 50 locally procured packages not financed by the Bank with an average cost of about US$500,000; these packages are not likely to attract foreign bidders and local procurement is considered to be the most efficient procedure. Goods and services not financed with proceeds of the loans would be procured locally under ISA's established procurement practices, which have been reviewed by the Bank and found to be satisfactory. Table 2: Procurement Arrangements (US$ million) A. Procurement ICB(2) NCB OTHER NBF6' TOTAL Method"' Goods 129.0 12.3 50.0 191.3 (113.6) (10.0) (123.6) Works 31.6 12.5 43.4 (25.0) (25.0) Equipment and 50.0 34.6 84.5 installation (43.0) (43.0) Consultant services 28.6 8.4 37.0 (5.0) (5.0) Training courses 1.9 1.9 (1.0) (1.0) Total 210.0 42.8 105.4 358.3 (181.6) (16.0) (197.5) * Figures in parentheses are amounts financed by the proposed Bank Loan, including contigencies. Table does not include US$ 51.8 million of interest during construction. (2) Goods and services to be procured by International Competitive Bidding in accordance with Bank guidelines () Limited International Bidding only for Part A. (4) Contracting of Consultants in accordance to Bank guidelines. ( Training: reimbursement of foreign currency expenses. ()Not Bank financed. To be procured locally under ISA's established procurement practices. - 18 - 2.22 Prior Review. All contracts for goods and works under ICB and LIB and all contracts related to training services (other than consultant services) equal or exceeding US$ 300,000 would be subject to the Bank's prior review. The provisions of the Consultant Guidelines requiring prior Bank review or approval of budgets, short lists, selection procedures, letters of invitation, proposals, evaluation reports and contracts, shall not apply to: (a) contracts for the employment of consulting firms estimated to cost less than US$100,000 equivalent each; or (b) contracts for the employment of individuals estimated to cost less than US$50,000 equivalent each. However, said exceptions to prior Bank review shall not apply to: (a) the terms of reference for such contracts; (b) single-source selection of consulting firms; (c) assignments of a critical nature, as reasonably determined by the Bank; (d) amendments to contracts for the employment of consulting firms raising the contract value to US$100,000 equivalent or above; or (e) amendments to contracts for the employment of individual consultants raising the contract value to US$50,000 equivalent or above. Contracts subject to prior review would cover about 85% of Bank financed goods and services. The balance of contracts would be subject to ex-post review by the Bank after contracts are awarded. When evaluating bids for goods, qualified domestic manufacturers would be eligible for a 15% margin of preference, or the import duty, whichever is lower. 2.23 Disbursements. ISA expects to complete project implementation in four years. However, under the 1994 standard disbursement profile for power projects implemented in the LAC region, !he loans would be disbursed over a seven years period. The disbursement schedule is attached in Annex 10. Proceeds from the loans would be applied to finance following estimated amounts of project expenditures: (a) 90% of expenditures for works (US $25.0 million); (b) 100% of foreign expenditures and 90% of local expenditures (ex-factory cost) for the purchase of goods (US$ 10.0 million for part A of the Project and US$ 103.6 million for parts B and C of the Project); (c) 95% of expenditures for contracts for the supply of equipment and installation thereof (US$ 43.0 million); (d) 100% of foreign expenditures for consultant services (US$ 0.5 million for part A of the Project and US$ 4.5 million for parts B and C of the Project); (e) 100% of foreign expenditures for training of ISA staff abroad and training fees (US$ 1.0 million); and (f) interest and other charges under the Bank loan, (US$ 36.8 million); (g) unallocated expenditures (US$ 24.9 million). 2.24 Disbursements against statement of expenses (SOE) will be made in respect of training service contracts costing less than US$ 300,000 and for consultant services not subject to prior - 19- review. Retroactive financing of up to US$ 10 million for eligible expenditures (made after March 31, 1995, but no more than 12 months before signing) would be provided for under each loan. Eligible expenditures would have to follow procurement procedures acceptable to the Bank. The Project is expected to be substantially completed by 2001 with a closing date of December 31, 2002. 2.25 The Borrower would establish for each loan Special Accounts in US dollars with a commercial bank acceptable to the Bank to cover eligible Bank expenditures under the loan. The authorized allocation to the Special Accounts would be US$8 million for each loan. However, they should not exceed US$4 million during the start-up of the project. The balance could be requested when the total amount disbursed from each loan account plus outstanding commitments has reached US$20 million. Subsequent replenishment by the Bank into the Special Accounts would follow the procedures by which Bank funds are disbursed against actual expenditures. 2.26 Monitoring. With regard to the overall company's performance, ISA and the Bank have agreed on a set of operational and financial performance indicators, which are attached as Annex 15. During negotiations agreement was reached that ISA would comply with these indicators. ISA would also be required to submit biannual reports on the progress of implementing the project together with an evaluation of its performance measured against targets defined in the PIP. Arrangements for auditing are discussed in para. 4.9. ISA and the Government will conduct with the Bank formal project review meetings within four months of the close of ISA's fiscal year starting in 1996, for the purpose of discussing project progress, overall project execution during the preceding year, and ISA's financial situation and local funding capability in subsequent years. The meeting to be held not later than April 30, 1998, will be the Mid-term Review of the project. F. Environmental Considerations 2.27 Over the past years ISA has demonstrated a noteworthy commitment to incorporating environmental issues within the decision making process to select optimal expansion plans. ISA's methodology for taking into account socio-environmental aspects is considered by the Bank to be "state of the art" in the planning and management of its transmission system. During project preparation, following World Bank guidelines, ISA carried out a Sectoral Environmental Assessment (SEA) of the Colombian Power Sector6. The SEA included among others, a general evaluation of the status of socio-environmental issues at the sectoral level, a diagnosis of environmental impacts derived from the existing transmission system as well as the impact expected from the new transmission lines foreseen in the expansion plan. 2.28 The civil works to be financed include power transmission lines and substations which will involve small potential environmental risks. ISA prepared an environmental analysis7 which 6 Evaluaci6n Ambiental Sectorial. Sector Electrico Colombiano. Ministerio de Minas y Energia - ISA, 1994. This report is available from the Bank's Public Information Center. Informe de Restricciones Ambientales - Tercer Plan de Transmision. ISA. This report is available from the Bank's Public Information Center. - 20 - identifies the main environmental and social constraints within the proposed transmission corridors. The environmental constraints identified by the ISA report were incorporated in the design, construction and operation of the transmission lines. 2.29 The corridors do not affect indigenous reserves, cultural protected areas, densely populated settlements, natural reserves, national parks, water supply facilities or important productive activities. About 60 households currently located along the corridors will require relocation. This is usually simpler for transmission lines as compared to other types of infrastructure construction, as buildings only require a few meters displacement and in most cases land can continue to be used for agriculture or grazing. In this case it will consist of building new houses, and in most cases families will be able to remain on their land. In 1991 the Colombian Electric Power Sector, under ISA's leadership, approved a Resettlement Policy (RP) that meets the Bank's requirements. By applying the RP, ISA has successfully undertaken the resettlement of scattered populations through a participative approach; the concerned families have been contacted and informed of ISA's resettlement policies as well as their rights in terms of compensation and indemnity. According to Bank policy, a resettlement plan is not required for projects with this number of displacements; nonetheless, ISA is preparing resettlement plans and environmental management plans which will be submitted for Bank approval before opening the bidding process for the civil works of each transmission line (see para. 2.30 bellow). 2.30 The project has been rated in the "B" environmental category, i.e. no major environmental impacts are expected as a result of either construction or operation of the new transmission facilities. Although the project was rated with environmental category "B", the borrower was required to prepare a project-specific environmental report for each transmission line. Each report must contain a detailed Environmental Management Plan (EMP) to mitigate undesirable effects on human populations and natural resources during construction and operation of the project. Once the EMP and resettlement plan for each line have been agreed with the Bank, and before authorizing any contractor to initiate the construction and assembly phase of each transmission line, ISA will provide each of the persons affected by the works enforceable rights to a new home or adequate compensation or both, according to the corresponding resettlement plan. 2.31 It is worth noting that ISA has put in place an Environmental Management System (EMS) specially designed for transmission projects, which is being successfully applied to the existing 500kV system and to other 230kV lines. The current EMS designed by ISA has been applied in other electric power sectors in Latin America, particularly in Ecuador and Uruguay where ISA is providing technical assistance. Finally, by encouraging more efficient power generation and by helping to reduce electricity losses, the project will promote energy efficiency and thereby have a positive indirect environmental impact. -21 - 3. ECONOMIC ANALYSIS A. Economic Evaluation Control Center and TA Benefits 3.1 The benefits of the new dispatch and financial settlement centers, and of the technical assistance to help in their operation, are not directly quantified because of the difficulties associated with estimating the corresponding benefits. They are essential for the power market to develop. Without such new equipment and the requisite training, the existing dispatch center, which is based on equipment that is substantially out of date, will be unable to either operate the network efficiently or to create proper financial accounting for the settlements required under the new commercial rules. It is recognized worldwide that energy management control centers represent a small portion of sector investments while their benefits are high. Transmission Component Benefits and Costs 3.2 The project for the investment in new transmission plant would help Colombia to reduce the costs of electricity supply through increasing both its quantity and quality by: (a) reducing transmission losses by upgrading certain sections of the grid from 230 kV to 500 kV; (b) allowing more power and energy to be transmitted and delivered to consumers; and (c) allowing generation to take place at lower cost plants than would otherwise be possible, hence leading to a reduction in total fuel costs for the system as a whole. In addition, the strengthening of the national grid will promote competition between generators by reducing the likelihood that, because of transmission bottlenecks, high cost plants may operate when lower cost plants are available. The stronger transmission system will therefore act as an increased stimulus to the entry of private power producers by ensuring that they will be able to fully utilize any cost advantages that they possess. 3.3 The economic analysis consists of: (a) a cost-effectiveness analysis whereby it is shown that the components of the project are (i) the least cost alternative for accomplishing their objective and (ii) each element of the project is more economic than its second best alternative which would provide equivalent services; and (b) an economic analysis which shows that the resources used in the proposed investment program provide an acceptable rate of return. The detailed results are included in Annex 11 and are summarized below. Cost-effectiveness analysis. 3.4 In February 1995 the Ministry of Mines and Energy and Interconexi6n Electrica prepared a least cost generation and transmission expansion plan, covering the period up to 2007, based on a detailed macroeconomic scenario and an associated electricity demand forecast. This plan defined reliability criteria for both generation and transmission and then estimated costs of a number of alternative scenarios for expanding generating capacity and the transmission system, in order to determine the least cost program. The transmission lines and substations included in the - 22 - project are part of the least cost expansion plan which was reviewed by the Bank and found satisfactory. This indicative expansion plan was officially endorsed by the Government on 15 February 1995'. 3.5 The two main components of the project, namely the San Carlos-San Marcos system and the Loma-El Copey system were evaluated. The approved expansion plan provides a joint generation/transmission optimization and the analysis performed for the appraisal seeks to verify that they constitute a least cost solution by comparing them with second-best alternatives. 3.6 San Carlos-San Marcos Component. The second-best alternative to the San Carlos-San Marcos project consists of relocating gas-based generation plants to the Southwest of the country where they would supply the equivalent load carried by the project. The tradeoff involved consists of comparing the costs of the project (i.e. electricity transportation) with the alternative of transporting natural gas. The analysis yielded an Equalizing Discount Rate (EDR) of 20%, i.e. the discount rate whereby the project becomes equivalent to the second-best alternative; this discount rate exceeds the benchmark discount rate (12%). The ratio between the project's costs and the savings provided against the second-best alternative yields a Benefit/Cost (B/C) ratio of 1.6. These results confirm the San Carlos-San Marcos project as the best technical alternative for supplying electricity to the Southwest of the system. 3.7 Loma-Copey Component. The Loma-Copey project will provide an additional interconnection between the central and Atlantic Coast subsystems. It is also closely associated with evacuating energy from the 300 MW Termocesar coal-based power plant which is included in the approved expansion plans for 1995-2000 and which will provide fuel diversification in the future. The second-best alternative to the Loma-Copey project would require replacing this coal plant by equivalent coal-based generation in the Northeast and Atlantic Coast regions. Two alternatives were identified; however, they require higher investments compared to the Termocesar/Loma-Copey project, and although their fuel costs are slightly lower they do not compensate for the additional investment. The cost ratio between the project and the alternatives is on the order of 1.04. The Equalizing Discount Rate is higher than 50%. The results confirm the Loma-Copey project as a required component of the expansion plan. It should be noted that the project will provide additional benefits by strengthening the Central-Atlantic Coast links which are critical under low-runoff conditions. 3.8 Economic Analysis. This phase of the analysis consists of evaluating the rate of return for ISA's overall investment program. The benefits associated with the program consist of (a) operating benefits due to lower generating costs associated with lifting bottlenecks in the transmission system and (b) incremental energy benefits which can be provided to consumers. Operating benefits were quantified by comparing operating costs with and without the investment program. Incremental energy benefits were quantified using as proxy the increased sales at the price of electricity (which provides a lower bound to consumer surplus) minus the subtransmission and distribution investment costs required to reach the consumer. ""Estrategias para el Desarrollo y la Expansi6n del Sector El6ctrico 1995-2007", Documento CONPES 2763, 15 February 1995. - 23 - 3.9 The results of the analysis yield an Internal Rate of Return for ISA's investment program of 27% which exceeds the 12% benchmark discount rate. It should be noted that the proposed project accounts for a large portion (over 90%) of ISA's investment program. Over 90% of the benefits associated with the project are operating benefits associated with the lower running costs of thermal plants which the transmission reinforcements will achieve. This confirms the role of the project as a major element required to facilitate the operation of the bulk market for electricity. B. Risk Analysis 3.10 This is a low risk project. Implementation risks will be minimized by the use of experienced consultants in the preparation and evaluation of bids, and contracting the execution of critical components of the project through "erect and build" schemes. 3.11 Regarding the institutional risk, the execution of the proposed project is essential for the success of the overall power sector reform process, which hinges on the satisfactory implementation of the new Public Services and Electricity Law approved by Congress in July, 1994. The new law establishes sound principles, but opposition from regional and other interest groups, such as unions, management of a number of existing utilities, and some local governments could slow down its enforcement. However, since the approval of the Electricity Law, no major problems of this nature have appeared and the Government intends to continue with its implementation. 3.12 Other risks which could impact negatively on the project include: (a) insufficient institutional capabilities in government to develop and enforce the regulations needed for the successful implementation of the competitive power market; (b) sluggish private sector response; and (c) political reluctance to implement the mechanisms for tariff and transmission charge adjustments. The Energy Sector Technical Assistance Project is addressing the issue of institutional weakness. Regarding (b), the private sector has responded positively by investing in over 1000 MW of power generation and by expressing interest in developing another 1700- 2600MW. Regarding the price adjustment risk, although the Government has lost its discretionary power and can no longer set prices by flat, it is conceivable that it could pressure the Regulatory Commission in order to reduce the rate of adjustment of electricity prices for the sake of achieving short term macroeconomic goals or fulfilling political commitments. Three safeguards exist for avoiding this contingency: (i) the terms of the Public Services Law itself, (ii) the attitude of the regulators who may be amenable to marginal revisions but would oppose major changes to the price adjustment plan due inter alia to the personal legal risks involved, including penal risks, in disregarding the mandates of the Law and (iii) pressures from private sector interests in the generation business who form a constituency in favour of a sound tariff policy to protect their revenues from the consequences of uneconomic pricing. Environmental risks are small and hedged. 3.13 ISA selected US dollar single currency loan terms to the maximum extent possible to reduce its currency risk. ISA has substantial yen liabilities and has chosen US dollar to achieve a - 24 - better overall balance in its foreign currency exposure. ISA's choice of a LEBOR interest rate basis marginally increases interest rate risk since ISA's tariff level is subject to a cap imposed by the Regulatory Commission. ISA has capacity to bear this risk, however, as most of its liabilities carry stable interest rates. 3.14 A series of sensitivity analyses against less favorable cases are considered in order to determine the robustness of the conclusion that the transmission components of the project are economically justified. In the case of the cost-effectiveness analysis, increases in investment costs and decreases in gas transportation and coal costs were analyzed. The projects are justified under reasonable variations of these critical variables. 3.15 Similarly, the Internal Rate of Return for ISA's transmission investment program continues to be justified (IRR of 19%) when investment costs are increased by 10% or when operating benefits are decreased by 10%. The IRR shows negligible sensitivity to changes in the value of incremental energy benefits. If demand fails to develop as expected (e.g. a 4.3% average growth rate), the investment program yields a lower IRR of 18% which still exceeds the 12% benchmark. Finally, the project risks becoming uneconomic in the unlikely event that operating savings decrease by around 27% over the program's lifetime with respect to their estimated values, or that investment costs increase by 30% with respect to their budgeted amounts. - 25 - 4. THE BORROWER A. ISA 4.1 The borrower of the proposed loans would be ISA, one of the two companies which originated from Interconexion Electrica. ISA has kept the full name of the former Interconexi6n Electrica S.A. and the alternative denomination of the acronym ISA9. Interconexi6n Electrica was established in 1967 with Bank sponsorship in order to interconnect the regional electricity companies, to develop future generation projects and to coordinate system dispatch. It was a stock company (Sociedad An6nima) whose assets by end 1994 were estimated at US$ 2.7 billion, constituted by generation plants for a total of 2,542 MW of installed capacity, about 6,300 km of transmission lines, about 8,000 MVA of installed capacity in transformer facilities, and headquarters offices and other facilities in Medellin. In December 1994, Interconexion Electrica employed a total of 1380 skilled and well trained staff. 4.2 Interconexi6n Electrica was initially owned by three regional companies and a government institute. In subsequent years, ownership was expanded to include CORELCA, the Atlantic Coast utility. With the financial restructuring that took place in 1991-92, the Government became the major shareholder in the company. The Bank has supported the development of Interconexi6n Electrica since 1968 through four loans totaling US$ 300 million which financed the national interconnection grid and three power stations. The execution of all these projects was successful. The company also executed the 500 kV interconnection project between the central region and the Atlantic Coast, partially financed by a US$ 50 million Bank loan. 4.3 The development of Interconexi6n Electrica can be traced through four distinct periods: (a) during 1967-76 it accomplished the 230 kV interconnection of the generation companies in the central region of the country and established itself as the sector's leader, by assuming responsibility for sector planning and implementing most of the sector's expansion; (b) during 1976-90 Interconexi6n Elctrica reinforced the national interconnection by implementing the 500 kV Sabanalarga-San Carlos system and became the major generator with the development (with Bank support) of the Chivor, San Carlos and Jaguas hydro power plants, together with smaller thermal units; (c) in 1990 it initiated a four-year period of financial consolidation which improved and strengthened the company's finances; and (d) in 1994 it initiated a major reorganization which eventually facilitated the unbundling of generation and transmission services in Colombia in line with the newly established regulatory reform. 4.4 As part of the power subsector reform program, Interconexi6n Electrica was split into two autonomous corporations in 1995: a generation company (ISAGEN) which is now in charge of the generation facilities and a transmission company which has continued to be known as ISA. ISA will constitute the backbone of the power market, responsible for transmission and dispatch functions, and, by delegation, will operate the commercial settlement facilities of the newly 9To avoid confusion this report refers to Interconexi6n Electrica when naming the former generation and transmission company, which was also formerly known as ISA. - 26 - established power market. ISA's assets have been defined at the vesting date as US$ 690 million or 26% of the total assets of Interconexi6n Eldctrica. ISA and ISAGEN are controlled by the National Government, who owns 76% of their shares. Currently the Government is considering alternatives for privatizing ISAGEN, while privatization of ISA will eventually take place only when both the company and the commercial system have further consolidated. 4.5 When Interconexi6n El6ctrica was split, its assets were assigned to ISA and ISAGEN according to their function; a similar process was performed for long term debts, whereby the latter were allocated according to which company owned the assets financed by a given credit. Formalizing this process requires lenders' cooperation, mainly from the Bank, IDB and FEN who are creditors for over 95% of Interconexi6n Elctrica's debt. ISA and ISAGEN are in the process of petitioning their respective creditors to concur with its proposed division of liabilities and to implement the required modifications in the outstanding loan agreements; in principle, the banks' operational management have agreed to submit in due time this proposal to their boards. In the interim ISA and ISAGEN have maintained joint and several liability with respect to the former Interconexi6n Electrica's debts, contracted on or before April 30, 1995. In those cases where the original borrower Interconexi6n Elctrica received the guarantee of Colombia, both ISA and ISAGEN expect to be released from the joint and several liability, to complete the seperation of the companies. ISA has shown satisfactory evidence that any residual liability it may have with respect to ISAGEN's debts will not imperil the performance indicators agreed during negotiations. 4.6 Structure. ISA is structured along business centers: transmission, dispatch and telecommunications, duly supported by financial, administrative, legal and environmental services. As part of the restructuring of Interconexi6n El&ctrica, ISA has sustained a major reorganization aimed at: (i) improving the efficiency of the technical development process; (ii) separating accounts and establishing performance indicators to identify sources of income and room for improvement; (iii) improving planning methods; and (iv) instituting a client oriented attitude. Interconexi6n Electrica was an efficient, well run utility and prospects are that ISA, which has kept 959 staff from the former utility, will follow suit. ISA's current organization chart is shown in Annex 9. 4.7 Accounting. ISA keeps its accounts in accordance with generally accepted accounting principles regulated by decree #2649 issued in December 1993, which are consistent with those of international accounting standards. Since 1992 ISA's accounting system is adjusted monthly due to inflation in accordance with decrees #2911 and #2912. ISA has a well developed computerized system for financial, inventory, and budget control, billing, banking, and payroll. 4.8 Financial Planning. Since December 1989, ISA's budget has been submitted to the National Council for Fiscal Policy (CONFIS - Consejo Nacional de Politica Fiscal) for inclusion in the National Budget. In addition to the annual budget, ISA prepares a corporate budget in November of each year. A preliminary ten-year investment plan is also prepared with its corresponding financial projections. MME revises the plan and presents it to CONPES for approval. ISA has adopted adequate long-term financial planning software based on a model - 27 - developed by IDB to provide management with a reliable long-term view of the expected financial performance of the utility. 4.9 Audits. ISA's financial statements are audited by Paez y Asociados, an independent auditing firm. Audit regulations and standards are based on international auditing practices. During negotiations, agreement was reached with ISA that: (i) ISA's annual and Bank-financed project accounts will be audited by independent auditors acceptable to the Bank; (ii) ISA will maintain separate accounts for the project; and (iii) ISA will provide the Bank, within four months after the end of each fiscal year, audits covering project accounts, the special accounts, the statement of expenditures, and the company's financial statements. 4.10 Internal Audit. The Internal Audit Unit reports to the general manager; it is in charge of periodically examining the operational, financial and accounting procedures, the management controls, and making a security assessment of the computational software system. Currently, ISA is developing an internal auditing control plan, which would include periodic operational and financial auditing to improve efficiency in the use of ISA's resources, based on the recommendations made by a consultant firm. 4.11 Insurance. ISA follows sound insurance practices, generally consistent with power utilities practices. 39% of ISA's transmission power sub-stations are insured against fire, explosion, and flooding. For cost reasons, ISA's transmission lines are not insured. Replacement of transmission assets eventually damaged becomes part of the operating costs, which is normal practice for large utilities. 4.12 Taxes. As a result of the Public Services Law, ISA is taxed under conditions similar to other sector companies. ISA is now required to pay 37.5% income tax. ISA must pay 15% custom duties, 14% VAT on imported goods and engineering consultant services, and on profits of construction and assembly services. VAT paid for capital expenditures is discounted from income tax at the commissioning year. B. Financial Analysis 4.13 ISA was recently created on a sound financial footing. Most of Interconexi6n Electrica's financial problems were related to the generation business and were inherited by ISAGEN. ISAs financial performance is expected to continue being satisfactory as long as the ERC's rules are applied consistently. In particular, ISA's income hinges on a periodic adjustment of transmission charges as well as its regulated revenue ceiling. The rules for adjusting these values provide for keeping up with inflation as measured by the Wholesale Price Index, plus an additional allowed real growth rate to generate cash needed for expansion investments. 4.14 ISA's projected financial statements for 1995-2004 are presented in Annex 12, and are summarized in Table 3 for the disbursement period. The rate of return on revalued assets between 1995 and 2004 is expected to average 6-8% depending on the depreciation method. The cash operating ratio (total cash operating expenses/total gross revenues) would improve from 21% in 1995 to about 20% in 2001, indicating that annual revenues tend to increase more rapidly than - 28 - operating costs. The self-financing ratio is expected to be over 50% during the period. The debt service coverage is expected to vary between 1.7 and 2.3 and to exceed the benchmark value of 1.5. Table 3: ISA- Projected Financial Performance (Col$ billirn) 1995 1996 1997 1998 1999 2000 2001 Total Operating Revenues 129.8 166.7 201.0 239.6 288.3 354.2 418.2 Total Operating Expenses 88.1 105.4 124.1 149.2 186.0 233.5 255.2 Net Operating Income 41.7 61.3 76.9 90.4 102.3 120.6 163.0 Annual Capital Expenditure 85.0 107.8 182.3 272.9 78.6 52.4 321.2 Borrowings 93.9 59.3 107.6 165.1 15.9 0.0 116.8 Net Debt Service 56.7 70.5 82.7 75.6 91.5 144.7 151.9 Net Fixed Operating Assets 930.1 1092.1 1235.0 1673.8 1810.1 2267.6 2425.6 Total Long-Term Debt 312.5 369.2 486.2 668.8 675.0 653.6 744.1 Rate of Return 4.9 6.1 6.6 6.2 5.9 5.9 6.9 accelerated depreciation (%) 8.2 8.9 9.1 8.2 8.0 8.0 8.3 linear depreciation (%) Cash Operating Ratio% 20.6 19.5 19.1 21.2 20.2 20.5 19.7 Self Financing Ratio (%) 34.4 75.0 30.1 30.4 110.3 224.0 54.2 Debt Service Coverage 1.7 1.8 1.9 2.1 2.2 2.0 2.2 Debt as / of (Debt + Equity) 32.8 32.5 33.6 36.6 34.2 30.5 29.6 4.15 Sensitivity analyses of the financial projections were carried out for the following cases: (A) revenues are not adjusted according to the regulatory provisions to provide for increase of investment made after 1999; (B) same as case A plus a delay in the execution of the investment program, which forces ISA to pay penalty charges; (C) same as case A plus higher inflation (local inflation 3 percentage points higher and foreign inflation 1 point higher). Cases DI and DII simulate an eventual delay in payment by the weaker distribution companies; the case corresponds to a one-year cessation of payments during 1997 (a year when ISA's cash flow is more demanding), followed by a resumption of payments and a settlement of arrears. Case DI assumes that 'tmall and unsolvent utilities" (see Annex 8, Table 8-7) delay payments. Case DII assumes that in addition to the arrears supposed in DI 'tmall and under recovery utilities" also delay payments, resulting in a shortfall of 20% of ISA's revenues. Case D is unlikely to materialize: the Energy Regulatory Commission has set stiff penalties for non-payment of transmission charges; the delinquent company must settle its debts and tender a bank guarantee covering the next year's payments; otherwise, if the company does not comply, fines can be imposed and managers can be discharged and denied employment in utility companies for a ten year period. Annex 12, Attachment 6 shows the results of this analysis for 1995-99 and for 2000-04. The results for the coming five years (1995-99) are summarized in Table 4. - 29 - COLOMBIA POWER MARKET DEVELOPMENT PROJECT Table 4 Financial Sensitivity Analysis (Current US$ million) Base Case Case A Case B Case C Case DI Case DII Period Period Period Period Year 1997 Financial Indicators (95- 99) (95-99) (95-99) (95-99) D-1 D-II Operating Revenues 868 865 865 878 174 174 Operating expenses 554 554 554 575 107 107 Net Income 314 312 312 302 67 67 Gross Internal Cash Generation 714 711 683 714 153 153 Debt Service (excludes IDC) 325 326 328 327 71 71 Internal Cash Generation 388 385 355 387 82 82 Borrowings 395 395 395 413 93 93 Investment (includes IDC) 624 623 623 639 158 158 Average Rate of Return% 8.5 8.5 8.5 8.3 9.1 9.1 Average Cash Operating Ratio % 20.2 20.2 20.2 20.7 19.0 19.0 Average Debt Service Ratio 1.9 1.9 1.8 1.9 1.9 1.9 Average Self-financing Ratio % 37 37 35 35 16 16 Debt as of % of (Debt plus Equity) 34 34 34 34 34 34 4.16 These indicators show that ISA's financial performance would remain sound even under these scenarios. Even in the event of a higher foreign inflation, which would affect debt service payment and the amount of capital expenditure, ISA internal cash generation would be sufficient to fund over 30% of the investment program. The cash operating ratio, average rate of return, and the debt service coverage ratio also remain at an acceptable level (under 21%, over 8.0% and 1.5, respectively). Among the information to be routinely provided by ISA once a year would be the results concerning the monitoring indicators shown in Annex 15. 4.17 To ensure a sound financial performance during project implementation, agreement was reached at negotiations with ISA and the Government that: (a) ISA's cash operating ratio be no higher than 23%; -30- (b) ISA incur additional debt only if its debt service coverage ratio exceeds 1.5; (c) ISA's self financing ratio remain equal to or above 30%; (d) ISA provide the Bank by June 30 of each year with updated financial reports for the previous year and projections for the next five years, including monitoring indicators (Annex 15). 4.18 Another source of financial risk could consist of the Government's desire to pressure the Regulatory Commission in order to reduce the rate of adjustment of electricity prices for the sake of achieving short term macroeconomic or political goals. This risk has been considerably reduced as the Government has lost its discretionary power and would have to overcome the following obstacles: (a) the terms of the Public Services Law which would require revising its conditions in Congress; (b) the attitude of the regulators who may eventually agree to marginal changes but would oppose major adjustments due, among other, to long term penal risks involved in disregarding the mandates of the Law; and (c) pressures from private sector generators who form a constituency in favour of sound pricing policies. 4.19 The nominal rate of adjustment of regulated tariffs decreased in 1995 relative to 1994, but prices have continued to rise with the objective of reaching marginal cost levels. Furthermore, the slower adjustment rate has been compensated by two factors: (a) the lower devaluation of the colombian peso as compared to inflation (which is significant as most power system costs are dollar-denominated) and (b) lower generation prices (10-15% below 1994 levels) which have emerged from the competitive market in 1995. -31 - 5. AGREEMENTS REACHED AND RECOMMENDATION 5.1 During negotiations, agreement on the following arrangements were obtained: (a) ISA will complete the final design of the Energy Control Center and the Financial Settlement Center before disbursements for goods and services under part A of the project are made (see para. 2.17). ISA will prepare before the end of each year two annual plans, one for studies and one for training (see para. 2.19). (b) ISA will use Bank standard documents for procurement of the goods and services financed under the Bank loans (see para. 2.21) (c) ISA and the Government will conduct with the Bank formal project review meetings within four months of the close of each of ISA's fiscal year starting in 1996, for the purpose of discussing project progress, overall project execution during the preceding year, and ISA's financial situation and local funding capability in subsequent years. The meeting to be held not later than April 30, 1998, is expected to be the Mid-term Review of the project. (see para. 2.26.) (d) Prior to inviting bids for construction of each transmission line, ISA will submit a resettlement plan and an environmental management plan to the Bank for approval. ISA may invite bids for the construction and erection of the transmission lines after resettlement plans and environmental management plans have been agreed with the Bank and thus the contractor could start manufacturing of the equipment to be used in the construction of the transmission lines. However, before authorizing any contractor to initiate the line construction and assembly phase, all corresponding rights on land shall have been acquired and each of the persons affected by the works shall have been provided, according to the corresponding resettlement plan, with enforceable rights to have a new home or adequate compensation, or both (see para. 2.29 and 2.30). (e) ISA will execute in a timely manner all actions determined in the resettlement plans and environmental management plan (see para. 2.30). (f) ISA will: (i) have its annual and Bank-financed project accounts audited by independent auditors acceptable to the Bank; (ii) maintain separate accounts for the project; and (iii) furnish to the Bank within four months after the end of each fiscal year the audited project accounts, special accounts, statement of expenditures, and ISA's financial statements (see para. 4.9). (g) All necessary measures will be taken to ensure that from 1996 onwards ISA's cash operating ratio does not exceed 23% (see para. 4.17). -32- (h) ISA may incur additional debt only if its debt service coverage ratio exceeds 1.5 of its projected debt service obligations (see para. 4.17). (i) ISA's self financing ratio will be not lower than 30% from 1996 onwards (see para. 4.17). (j) ISA will furnish the Bank by June 30 of each year, updated financial reports for the previous year and projections for the next five years for its revenues, capital expenditures, borrowing and debt service, accounts receivable, and finances (see para. 4.17). (k) ISA will implement the project in accordance with the agreed Project Implementation Plan (Annex 10) and coordinated through a project unit, with an adequate implementation structure. Recommendations: On the basis of the agreements reached, two Bank loans are recommended: (i) a US$145 million LIBOR-based US dollar single currency loan; and (ii) a US$104.3 million equivalent currency pool loan. - 33 - ANNEX 1 COLOMBIA POWER MARKET DEVELOPMENT PROJECT POWER SECTOR REGULATORY FRAMEWORK A. Background 1. The Colombian power sector underwent a major restructuring during the 1991-94 period. The restructuring was initiated by the government after the Operations Evaluation Department (OED) reviewed 1970-87 Bank lending to the power sector in Colombia and concluded that the sector was a source of chronic administrative and financial problems for the government and an obstacle to development'. The power rationing suffered by the country in 1992, as a consequence of inadequate system reliability and severe drought deepened the perception by the government and the public at large that major reforms should be introduced in the sector. 2. The major elements of the restructuring process culminated in 1994 with the approval by Congress of primary legislation in the form of two major statutes: a Public Services Law which provides a general framework for the supply and pricing of electricity, water, natural gas and local telephone services, and an Electricity Law which defines the sector structure and the organization, responsibilities and functions of different entities. Both laws emphasize the introduction of competition and provide appropriate regulation of non-competitive supplies. 3. Based on provision of the Public Services law, a regulatory entity, the Superintendency of Domiciliary Public Services (SSP), was created and, in accordance with provisions of the Electricity Law, the electricity and gas regulator (the Regulatory Commission for Electricity and Gas) is also in place. In addition to the primary legislation, these entities are in charge of issuing secondary legislation as appropriate. B. Primary Legislation The Domiciliary Public Services Law 4. This "umbrella-type" law covers the following main subjects: * Responsibilities entrusted to different government levels; * Corporate organization of public service enterprises; * Taxes; * Concessions for use of public goods; 'The World Bank 1990. Colombia - The Power Sector and the World bank, 1970-1987, Operations Evaluation Department, Report No. 8839. - 34 - * Market structure and regulation; * Regulatory organizations; * Pricing rules and subsidies; * Conditions for supplying public services; and * Special short term provisos for evolving from the then current setup. 5. Government Rsponsibilities. The central government is assigned the responsibility for overall policy making. Sector objectives are: to make electricity available to the population at reasonable prices, to increase service coverage, and to enhance quality of service. Government responsibilities are to assign concessions for the use of public goods (water sources and the electromagnetic spectrum) through the different Ministries (Ministry of Development for water, Ministry of Mines and Energy and Ministry of Telecommunications). The municipalities are entrusted with the primary responsibility of ensuring the provision of public services within their jurisdiction. Public enterprises are constrained to incorporating adequate funding for the payment of public services in their budgets, and to paying for them. Disciplinary penalties for non- compliance are set. 6. Corporate Oganization. Organizations that provide public services are constrained to operate in the form of stock corporations, with the exception of publicly owned companies which can either become stock corporations or "industrial and commercial state enterprises". In any case, the emphasis is on assuring that the regulated companies operate as corporations with no links to political bodies such as city councils or other government entities. In particular, municipalities are limited to providing public services directly only as a last resort, which would presumably apply to small communities for services such as water supply. The budget for public service enterprises is to be approved by their Boards, thereby eliminating the interference of city councils which have traditionally used this power to influence corporate decisions. Public service corporations are constrained as far as possible to being "single purpose" in order to avoid conflicts of interest and monopolistic practices. 7. Taxes. Public service corporations are constrained to be taxed in conditions similar to other private sector companies. The existing municipal companies are exempted for a period of seven years from this requirement. 8. Concessions. This type of contract is required for using public goods such as water resources or the electromagnetic waves for communications. These concessions are to be negotiated with the Government. All providers of public services are subject to performance controls by the Regulatory Commissions set up by the law and are required to retain external auditors. 9. Market Sructure and Regulation. Contracts regarding the supply of public services are to be treated as private sector contracts. The law seeks explicitly to promote competition whenever possible and emphasizes the limitation of monopolies or monopolistic practices. "Exclusive service areas" are acknowledged as necessary for supplying certain services. They are constrained to being assigned by the municipalities using competitive bidding procedures and are subject to Regulatory Commission approval. Such rights must have a termination date. The law - 35 - acknowledges the right for alternative suppliers to challenge the exclusivity to provide services by offering lower cost services. 10. Regulatory Organizations. The law establishes three Regulatory Commissions (water, telecommunications and energy) and a Superintendency of Public Services. The Regulatory Commissions are composed by the Minister responsible for a given service, three commissioners and the director of DNP. The role of the Regulatory Commissions consists of supervising the supply condition of services, resolving conflicts between suppliers, supervising market operations to prevent non-competitive behavior on the part of suppliers, establishing prices for regulated services and, when necessary, ordering the liquidation of deficient official organizations. The Superintendency evaluates the performance of public service suppliers in accordance with guidelines furnished by the Regulatory Commissions. The Superintendency and the Regulatory Commissions are to be funded from levies on the suppliers of public services. 11. Pricing. Prices fall into two categories: regulated supplies and those that respond to market supply and demand, which are allowed to fluctuate. The Regulatory Commissions can establish optional tariff categories and consumers are allowed to choose between different options subject to paying for the required metering equipment. Prices for regulated supplies are established following "tariff formulae" defined by the Regulatory Commission. The resulting tariffs should have a five-year application span with periodic updating using the CPI index. 12. Subsidies. Subsidies and cross subsidies are regulated according to the following guidelines: * Funds for cross subsidies can be levied by charging prices above service costs, as long as they do not exceed 20%; * Subsidies are to be channeled to users of strata 1, 2 and 3. Limits for subsidy allocation, as a percentage of service costs are 50%, 40% and 15% for strata 1, 2 and 3, respectively. * In any case, the prices charged should cover the operations, maintenance and administrative costs of the service. * Subsidies can be assigned by the national government or by local governments. 13. The Ministries are responsible for assessing the overall subsidy requirements to be paid by the Government and incorporating them in the National Budget. 14. Supply Conditions. The law sets out detailed rules concerning the relationships between suppliers and consumers, regarding billing and measurement procedures and consumer rights. 15. Short Term Provisos. The law orders the division of Interconexi6n El6ctrica into a transmission company and a generation company. The law allows a maximum period of six years for the adjustment of existing tariffs to the guidelines concerning pricing and subsidies. - 36 - The Electricity Law 16. This sector-specific statute covers the following subjects: (a) Sector policy and planning; (b) Regulation (c) Electricity generation (d) Interconnection functions (e) Operations (f) Network charges (g) Pricing (h) Environment (i) Legislation applicable to contracts (ij) Concession contracts (jk) Energy conservation and demand management (kl) Short term and transitory provisos 17. Policy. The law entrusts the definition of electricity policy to the Policy and Planning Unit of the Ministry of Mines and Energy; the functions assigned to this unit consist of assessing overall energy requirements and formulating strategies and policies for assuring efficient energy supplies. Expansion plans determined by the unit are of a non-compulsory character and the corresponding investments are open to be executed by any interested party. 18. Subsidiary Role of the State. The Government is entrusted with the ultimate responsibility for executing projects which do not elicit interest from other parties. 19. Regulation. The Regulatory Commission for energy consists of the Minister of Mines and Energy, the Minister of Finance, the director of DNP and five experts. The Commission's budget will be underwritten by the regulated enterprises. Its functions consist of gradually putting in place a competitive market, defining network charges, defining a methodology for calculating regulated tariff and setting regulated prices, setting the Operations Rules for the electricity system, overseeing the operation of the market and resolving conflicts between suppliers. 20. Electricity Generation. The generation activity is open to all economic agents who will be subject to the operating rules of the system. Generators can participate in the system either within a spot market or within a regulated mode whereby they strike contracts with distributors or unregulated consumers. Prices in the latter mode are freely established between the parties to the contract. 21. Interconnection. Owners of transmission lines will continue to own them but must comply with the operations rules. The transmission system will be operated by ISA once it is reorganized as a single-purpose interconnection enterprise. 22. System Operations. The law defines the functions of the national dispatch center and the national operations council. -37- 23. Pricing. The law allows prices for contracts between generators and bulk consumers to be freely agreed upon. It establishes the obligation of network owners to allow access of unregulated consumers to the bulk market and spells out penalties for impeding it, and defines the structure of regulated network charges. 24. Subsidies. The law ratifies the sources of cross-subsidies (up to 20% in excess of costs) and establishes the obligation of the government to provide any subsidy shortfall from the national budget. It also ratifies the obligation of public and government enterprises to provide funds for payment of electricity bills from their budgets and to pay their bills. 25. Legislation Applicable to Contracts. The legislation applicable to contracts involving power utilities, including those owned by the state, is the same applied to private companies. 26. Concession Contracts. The law spells out the terms of a concession contract whereby the supplier acquires an obligation to serve within a given service area for those cases in which supplies are not forthcoming as a result of market forces. 27. Final Provisos. The Regulatory Commission is allowed a period of three years for putting in place a competitive market at the generation level. Public enterprises at the national level are given six months to be transformed into mixed capital enterprises. C. Secondary Legislation 28. Secondary legislation for the power sector is constituted by detailed by-laws (Reglamentos) issued by the Regulatory Commission and any other regulations which might be specifically delegated by the commission to particular Agents (any enterprise of person engaged in generation, transmission, distribution or commercialization of electric energy). Regulations issued by the ERC, so far cover the following aspects: - General provisions for public service, Resolution (Resoluci6n, Res.) 56, - Generation, Res. 55, - Transmission in the National Interconnected System, Res. 1, - Transmission in regional networks and distribution, Res. 3, - Commercialization, Res. 54, - Transmission access and tariffs, Res. 2, - Distribution access and tariffs, Res. 4, - 38 - - Maximum tariff schedules to be charged by distribution companies, Ress. 38 though 43, - Long term contracts by distribution companies, Res 9, - Energy purchases by vertically integrated utilities, Ress. 10 trough 37, - Firm capacity payments by the Pool, Res. 53, and - 1995 tariff schedules to final users, Ress. 57 and 58, 29. Following there is a summarized content of the main regulations issued by the ERC. Resoluci6n No. 56, December 28, 1994, General Dispositions on Electricity Services - Definitions for this and any other regulations on the main industry parameters and actors. - Only duly registered electric enterprises can act in the sector as public utilities. - Separation of activities for any enterprise constituted after the enactment of the electricity law (EL). However, current vertically integrated enterprises can continue doing so, provided they separate accounts no later than January 1, 1996, under procedures and accounting practices to be issued by the SSP. - Obligation to provide to the ERC information on all contracts subscribed by public utilities. - Specific provisions to protect competition. - Obligation to publish tariffs and prohibition of discrimination. - All Agents to collaborate with authorities in cases of emergency, as declared by the ERC. - All Agents to abide by provision of the Grid Code and all other relevant regulations (technical, industrial, municipal, environmental, water concessions and usage). Resoluci6n 55, December 28, 1994, Generation Activities in the National Interconnected System (NIS). - All generators (over 10 MW of installed capacity) that are connected to ihe NIS must become members of the Pool, participate in the bulk market transactions and coordinate their operations with the National Dispatch Center (NDC). - 39 - - Defines the Commercial Transactions System (CTS) associated to the Pool. - Energy offered to the Pool should be based on short term marginal cost: (i) for thermal units: fuel incremental cost plus variable operational incremental costs, and (ii) for hydro plants: opportunity cost of water. - Ancillary services to be quoted at NDC request. - The NDC to be responsible for operational planning and dispatch based on least cost principles and define the opportunity cost of water and other parameters; all the above information should be disclosed to all Pool participants. - Dispatch to be made by merit order on the basis of offered prices; the NDC is responsible for instructing generators and Regional Dispatch Centers (RDCs) on how to operate their equipment and for supervising compliance. - Pool marginal price to be calculated hourly as the variable cost of the last unit in the load curve. - NDC can take discretionary actions with regard to dispatching in cases of emergency - The CTS to be responsible to settlement of commercial transactions. Resoluci6n No. 1, November 2, 1994, Transmission Access and Charges. - Defines access to the grids, interconnections and Grid Code. - Only Transmission Companies (TCs), duly registered, can provide transmission services publicly - TCs are obliged to provide indiscriminate access to their systems to all users, under technical conditions to be set by the ERC; TCs should maintain records. - The expansion plan for the National Transmission System will be carried out by ISA, and other TCs in their respective regions; reference plans to be defined by the Energy and Mining Planning Unit at the Ministry of Mines and Energy (UPME). - Defines purpose and content of the Grid Code. - Obligations of TCs to adhere to the Grid Code. - 40 - - Defines maximum tariffs to be charged for transmission. These are: (i) connection fees, (ii) use of system, (iii) charges due to system restrictions, and (iv) ancillary services. - Losses to be borne by the Agents; ERC to define distribution method for charging losses. Resoluci6n No. 3, Transmission in Regional Systems and Distribution - Defines conditions for providing distribution services. - Ensures free access to networks of local distributors for any user, retailer (comercializador) or generator. - Establishes rules and obligations to ensure free competitiveness. - Defines technical criteria for designing regional transmission and distribution networks, in particular details aspects that should be included in the grid code. - Defines general basis and procedures for establishing connection and user charges and for solicitation, quotation, and connection of consumers. Resoluci6n 54, 28 December 1994, Commercialization of Electric Power. - With the exemption of currently existing vertically integrated utilities, transmission enterprises can not carry out commercialization activities. - Suppliers (comercializadores) are obliged to trade energy in the Pool, but distribution companies can be represented in the Pool by a third party - Suppliers are obliged to supply energy to all those who request services under regulated regime. - Suppliers are obliged to collect subsidies and transfer them to a special fund. - Suppliers must maintain and publish power purchase tariffs which should be estimated on the basis of avoided costs. - Agents who perform activities in generation and commercialization must have separate accounts for both activities (exception, utilities existing at the date of enacting of the Law). - Suppliers acting in the regulated market must contract energy through competitive bidding. - 41 - Resoluci6n 2, 2 November 1994, Access to and Use of Transmission Networks; Methodology and Procedures for Setting Tariffs for Use of System and Connection. - Defines methodology and procedures for the payment by generators and suppliers to the transmission company for accessing and using the NIS. Such method is based on the costs imposed on the networks during peak hours computed as the investment, operations and maintenance costs of a system able to transport flows produced at peak hours. - The total revenues to the transmission company are, however, reviewed and, if granted, revised to provide for the financial requirements of the network operator for operating, maintaining and expanding the networks in accordance to expected demand. - Charges are separated as use of system and connection charges. - The above charges are defined by regions and sub-regions (nodes). - Use of system charges will be levied: (i) for generators on the basis of installed capacity and in service for six or more months during the year, and (ii) for suppliers on the basis of effective demand measured for particular times and seasons to reflect the stress imposed on the network by their respective loads. - Connection charges are paid by generators, large consumers, regional transmission companies or distributors in accordance with rates defined by the ERC, which are based on the investment costs required to connect the loads. Resoluci6n 4, November 2, 1994, Access to and Use of Distribution Systems, Methodology for Estimating Charges for Connection and Use of System and Procedures for Payments. - Defines charges for use of system to be paid by suppliers (and large consumers through suppliers) to local distributors. These charges include costs associated to the electrical systems required to provide the service. They do not include the cost of electrical losses, which should be paid by the suppliers. There are charges for energy and for power. - Estimates of charges are based on the assets of the corresponding company, assuming 10% discount rate and 25 years useful life for the equipment. - Operating costs are estimated at 2% of the investment costs. Charges for connection of new generator or large consumer are to be set by the REC. - 42 - COLOMBIA POWER SECTOR COMMERCIAL TRANSACTIONS Large Consumers PRODUCER Central Pooling Distribution Companies Small Consumers NOTE: Transmission companies CAN NOT buy or sell; only transport - 43 - COLOMBIA POWER SECTOR USE OF PHYSICAL INSTALLATIONS (:_Generators >C Large Dusers Generators ISA TRANSMISSION NETWORK Regional Grids Distribution Company Distribution Company Finaluser smal) ) Lrge Uers inlaluser (ml Colombian Power Utilities Generation Utilities CEDELCA Centrales Eléctricas del Cauca CEDENAR Centrales Eléctricas de Nariño CENS Centrales Eléctricas de Norte de Santander CET Compañia de Electricidad de Tuluá CHB Central Hidroeléctrica de Betania CHEC Central Hidroeléctrica de Caldas CHIDRAL Central Hidroeléctrica del Alto Anchicayá CORELCA Corporación Eléctrica de la Costa Atlántica EBSA Electrificadora de Boyacá S.A. EDEQ Empresa de Energía del Quindío EEB Empresa de Energía de Bogotá EEC Empresa de Energía de Cundinamarca EEPPML Empresas Públicas de Medellin - 44 - ELECTRANTA Electrificadora del Atlántico ELECTRIBOL Electrificador de Bolívar ELECTROCORDOBA Electrificadora de Córdoba ELECTROLIMA Electrificadora del Tolima EEP Empresas Públicas de Pereira EPSA Empresa de Energía del Pacífico S.A. ESSA Electrificadora de Santander SA. ICEL Instituto Colombiano de Energía Eléctrica PROELECTRICA Proeléctrica S.A. ISAGEN Distribution Utilities CEDELCA Centrales Eléctricas del Cauca CEDENAR Centrales Eléctricas de Nariño CENS Centrales Eléctricas de Norte de Santander CET Compañia de Electricidad de Tuluá CHEC Central Hidroeléctrica de Caldas CORELCA Corporación Eléctrica de la Costa Atlántica EADE Empresa Antioqueña de Energía EBSA Electrificadora de Boyacá S.A. EDEQ Empresa de Energía del Quindío EEB Empresa de Energía de Bogotá EEC Empresa de Energía de Cundinamarca EEM Empresa de Energía de Magangué EEPPM Empresas Públicas de Medellín ELECTRANTA Electrificadora del Atlántico ELECTRIBOL Electrificadora de Bolívar ELECTROCAQUETA Electrificadora del Caquetá ELECTROCESAR Electrificadora del Cesar ELECTROCHOCO Eeltrificadora del Chocó ELECTROCORDOBA Electrificadora de Córdoba ELECTROGUAJIRA Electrificadora de la Guajira ELECTROHUILA Electrificadora de Huila ELECTROLIMA Electrificadora del Tolima ELECTROMAGDALENA Electrificadora del Magdalena ELECTROSUCRE Electrificadora de Sucre EMCALI Empresas Municipales de Cali EMCARTAGO Empresas Municipales de Cartago EMSA Electrificadora del Meta SA. ENELAR Empresa de Energía del Arauca EEP Empresas Públicas de Pereira EPSA Empresa de Energía del Pacífico S.A. ESSA Electrificadora de Santander SA. PROELECTRICA Proeléctrica S.A. - 45 - Utilities that own Transmission fines: CENS Centrales Eléctricas del Norte de Santander CORELCA Corporación Eléctrica de la Costa Atlántica EEB Empresa de Energía de Bogotá EPPM Empresas Públicas de Medellín EPSA Empresa de Energía del Pacífico S.A. ESSA Electrificadora de Santander S.A. ISA Interconexión Eléctrica SA. - 46- D. Power Sector - Government Entities MME MHCP DNP MUNICIPALITIES FE EPSAE EPM ECL CORELCA 9 Local 15 Local CHB Distribution distribution ISA/ISAGEN Companies Companies - 47 - ANNEX 2 COLOMBIA POWER MARKET DEVELOPMENT PROJECT ENERGY POLICY LETTER Ministry of Mines and Energy The Minister Mr. Yoshiaki Akbe November 23, 1994 Latin America and the Caribbean Region IBRD Washington, D.C. Subject: Energy Policy Letter Dear Mr. Abe: I have pleasure in setting out below the principal aspects of the Colombian Government's Energy Policy, dealing specifically with aspects of the power sector. POWER POLICY OUTLINE The following general strategies have been formulated for Colombia's power sector: A. Efficient demand management and rational use of energy within a framework of social equity. This strategy includes the definition of a coherent pricing policy and the development of a number of energy substitution programs, designed to bring the structure of consumption into line with the economic cost and availability of the sources. A subsidy structure will be set up as provided in the Power Sector Law. In particular, the use of CNG and LPG will be promoted for urban and highway transport, as will programs ensuring a rational use of electricity in its various applications. B. Full and efficient energy supply, with appropriate infrastructure and optimum resource allocation among energy subsectors, taking account of the vulnerability of the systems and promoting private sector participation in the expansion programs. - 48 - C. Maintain and increase levels of energy source production and participation in the external market. It is particularly important to promote oil exploration and develop mechanisms for promoting Colombian coal as part of foreign trade policy. D. Supply energy to rural areas and contribute to regional development. Efforts will be made to step up grassroots participation, and the use of such fuels as LPG will be boosted as substitutes for wood, as well as the use of unconventional energy sources in the country's most remote regions, such as micro hydro plants, where such installations are feasible. E. Improve and preserve the quality of the environment. Action will be taken to strengthen the capabilities of the utilities to meet present-day environmental standards, and various programs will be promoted to lessen the environmental impact in the different basins. F. Provide effective stimulus to research and scientific and technological development, strengthening existing subsectoral research centers and forging stronger ties with university programs and with Colciencias concerning specific topics. G. Consolidate the sector's institutional modernization. While competition will continue to be regarded as crucial to efficient performance, attention will also be given to the need for a regulatory framework that guarantees consumer protection and controls dominant market positions. The Government's basic aim in formulating the above strategies is to bring its energy policies into line with macroeconomic policy goals and with the country's economic and social development targets. Within this framework, the following medium and long term objectives will be sought: a more reliable and efficient composition of energy source supply, rationalization of resource use, cost reduction, expanded coverage, and increased production. POWER SECTOR STRATEGY The focal points of this strategy are as follows: * Concentrate government action on the basic functions of regulation, planning and oversight of sectoral activities, leaving the business side to be managed by other economic agents. * Stimulate competition so as to achieve appropriate levels of sectoral efficiency. * Open up the sector to private investment as a means of strengthening competition, enhancing efficiency, and bringing in fresh development capital. * Make the sector's expansion plans less complex and diversify energy supply. - 49 - * Set tariffs reflecting the economic cost of power service delivery in the sectors where this is possible, and adopt a system of direct and explicit subsidies to meet the basic consumption requirements of low-income groups. * Promote financial rehabilitation of the government power companies to strengthen their net worth and improve their operational performance. ROLE OF THE GOVERNMENT In the specific case of the power sector, restructuring is now proceeding within the framework of Law 142 "governing residential utilities and enacting other provisions" of July 11, 1994, and Law 143 of the same date "governing the generation, interconnection, transmission, distribution and marketing of electricity throughout the national territory, ..." As provided in these two laws, the Government will: (a) promote free competition; (b) prohibit practices representing unfair competition or the abuse of a dominant market position; (c) regulate those situations where, because of the existence of a natural monopoly, free competition cannot guarantee efficient service delivery in economic terms; (d) ensure the protection of users' rights and the performance of their obligations; (e) incorporate environmental aspects into the sector's activities; (f) ensure adequate electricity service coverage in the country's different regions to meet the basic needs of lower-income consumers; (g) make available the necessary resources to cover the subsidies granted to those consumers for basic electricity coverage. The above laws ratify and supplement the functions assigned to the Energy and Gas Regulatory Board [Comisi6n de Regulaci6n de Energiay Gas - ERC] and the Mining and Energy Planning Unit [ Unidad de Planeaci6n Minero Energgtica - UPME] under Decree 2119 of 1992. Also to be borne in mind is the creation of the Utilities Superintendency [Superintendencia de Servicios Piblicos] as a technical agency under the Ministry of Economic Development, with juridical personality, administrative autonomy, and ownership of its assets. PRIVATE SECTOR PARTICIPATION To promote competition, improve efficiency, and bring in fresh development capital, private investment in the power sector will be promoted, especially in connection with the expansion programs. The basic conditions for such participation will be created with adoption of the implementing regulations to the Electricity Law and completion of the process of financial rehabilitation of the enterprises in the sector. The following strategies will apply to private capital participation: * Promote the participation of private investors in development of the generation projects included in the expansion plan, preferably through an energy supply contract or through association in a mixed enterprise. - 50 - * Encourage private individuals to develop projects on their own initiative as additional agents in the competitive market for large blocks of energy, and to assume the respective transaction risks. * Encourage the purchase of equity participations in the various generating companies to be set up using generating plant presently owned by ISA or the Government. ENVIRONMENTAL ISSUES Law 56 of 1981, its Regulatory Decree (2024 of 1982), and Law 99 of 1993 represent the most significant pieces of legislation for the electricity subsector in terms of environment-related provisions. The environmental variable in electricity projects has become extremely important, a fact reflected in the newly-created Power Sector Environmental Committee [ComitW Ambiental del Sector Elctrico - CA SEC]. Since 1986, the appraisal of projects under the power sector expansion plan has included the costs of environmental protection, based in general on a multipurpose, integrated project approach covering technical, social and environmental components. For this reason (and as a requirement for approval of loans from the multilateral banks), new generation, transmission and distribution projects are now factoring in environmental costs. During 1993, a Sectoral Environmental Assessment was conducted for the power sector, based on the World Bank's terms of reference and general guidelines for an assessment of this type. This study resulted in the identification of a number of strategies and actions that will be implemented to improve the sector's environmental performance. The National Energy Plan proposes the creation in the Ministry of Mining and Energy of an Environmental Unit, with Special Administrative Unit status, to propose and coordinate the energy sector's environmental policy and serve as its authorized spokesman vis-A-vis the environmental authorities. This proposal is currently under study, and should be finalized during the first half of 1995. PROGRESS OF RESTRUCTURING PLAN Institutional restructuring is progressing satisfactorily. At end-1992, the Ministry of Mines and Energy was restructured under Decree-Law 2119, which set up three new units: the Energy Regulation Board [Comisi6n de Regulaci6n Energ9tica], the UPME, and the Mining and Energy Information Unit [Unidadde Iformaci6n Minero Energ9tica], while also redefining the role of the Nuclear Affairs Institute [Instituto de Asuntos Nucleares - IAN], changing its name to Institute of Nuclear Science and Alternative Energy Sources [Instituto de Ciencias Nuclearesy EnergiasAlternativas - INEA]. In addition, Decree-Laws 2120 and 2121 provided for conversion of the Colombian Electricity Institute [Instituto Colombiano de Energia Elctrica - ICEL] and the Atlantic Coast Electricity Corporation [Corporaci6n El9ctrica de la Costa .4tlantica - CORELCA] into state commercial and industrial enterprises. The Cauca Valley Corporation [Corporaci6n del Valle del Cauca - CVC] was subdivided, its electricity side being converted into an independent company - 51 - Under the restructuring legislation, ISA is to be subdivided into two parts. Its General Meeting of Shareholders has already approved the subdivision, which will take place during the first months of the coming year. Using its existing generating plant and related administrative capabilities, ISA will set up a new generating company, eventually giving birth to a number of independent companies that will be progressively opened up to private capital. ISA's remaining units will be combined into another company, which will be responsible for high-voltage transmission and optimum load dispatch in accordance with ERC criteria and parameters, acting completely independently of its shareholder companies. ERC ACTIVITIES ERC became operational in September 1993. It was initially responsible for supervising the Colombian Energy Sector Restructuring Program study carried out by Coopers & Lybrand in 1992 and. 1993, and on the basis of the study's findings and recommendations it embarked on a course of action to deregulate the market. In December 1993, ERC enacted Resolution No. 010 deregulating the market for large industrial and commercial consumers. Large consumers were initially identified as those with requirements in excess of 2 MW. This threshold could be lowered over time. A few days ago, a resolution was published setting out the charges for use of the transmission and interconnection network. ERC is also working on the transmission and distribution code, operating regulations, and other pieces of secondary legislation essential to the creation of a free energy market. The regulations will basically address the establishment of standards to promote competition in the electricity market and private-sector participation in the expansion of generating capacity. The policy will be geared to the strengthening of ERC, since together with the standards now being prepared it represents the basic instrument for stimulating private-sector participation, modernizing companies, and establishing competition in the electricity market. UPME ACTIVITIES UPME became operational in September 1993. In early 1994 it started work on a study for formulation of a first National Energy Plan. During the first six months of this year it completed the first integrated energy demand study. It took over the planning functions that the former National Energy Board [Comisi6n Nacional de Energia - CNE] had been carrying out for the power sector, and is responsible for devising a reference plan for the expansion of generation and transmission, which is required by law "... to seek to direct and rationalize both government and private-sector efforts to meet the domestic demand for electricity in a manner consistent with the National Development Plan and the National Energy Plan." It is currently reviewing the Power Sector Expansion Plan. - 52 - Pursuant to the government guidelines, based on the Power Sector Law, UMPE is the instrument that will facilitate the development of integrated energy planning, and on that basis give the appropriate signals to the enterprises that design and implement subsectoral policies. Consequently, the Government proposes to provide UMPE with those integrated and subsectoral planning tools that will enable it to properly perform its functions. TARIFF POLICY Law 143 addresses the need for a stratified tariff policy to reflect conditions in the municipalities and rural areas. A major tariff adjustment program was initiated in 1990, designed to achieve targets consistent with the economic costs of delivering the service. Through a combination of isolated adjustments to certain tariff categories and monthly adjustments in excess of inflation in all categories, the average charge to the final consumer was successfully brought up from US$0.041/kWh in 1990 to US$0.054/kWh in 1992. In 1993, Resolutions 13, 14 and 15/93 were adopted, introducing an adjustment strategy whereby the reference cost based on the economic cost of service delivery would be achieved by 1997-98. The program of monthly adjustments will be continued over the next few years, with introduction of a direct and explicit subsidy system for low-income consumers and introduction of the cross-subsidy system provided for in the Power Sector Law and the Residential Utilities Law. Such measures are essential to facilitate the operation of a free market of large blocks of energy, and to ensure the financial health of efficient enterprises with weak markets, with a high proportion of low-income group consumption. FINANCIAL SITUATION The Government has taken action in terms of capitalization, debt restructuring, and debtlequity swaps to address the difficulties of those of the sector's major enterprises which had fallen into insolvency or bankruptcy as a result, generally speaking, of stagnating electricity tariffs, accelerated devaluation of the peso, and their own high debt levels. During the past few years, the Government has contributed over US$1.5 billion to enterprises such as ISA, CHB, ICEL, CORELCA, and EEB, and in return has received productive assets and share capital in ISA and the ICEL subsidiaries. These measures succeeded in bringing about a substantial recovery in the sector's finances, although some of the enterprises still face certain isolated and cyclical cash flow problems for which additional measures need to be enacted. An analysis is currently in progress, and an additional financial recovery plan is expected to be launched by July 1995. To ensure the financial viability of the enterprises, their financial recovery will be supplemented by the following actions: - 53 - * Capitalization and refinancing of certain liabilities. * Setting of tariffs reflecting the economic costs of service delivery, gradually eliminating cross-subsidies to the level prescribed by law, and progressively introducing a system of explicit direct subsidies for low-income residential consumers. * Improved efficiency for the enterprises in the power sector, through energy loss and delinquent portfolio control and reduction of operating costs. As regards efficiency improvements, the former system has been amended by law and placed on a more solid legal footing. Based on their strategic plans and on the criteria developed by ERC, the enterprises are required to propose a management control plan, which will need to be approved by UPME. This plan will form the basis for the preparation of management contracts to be signed with the Superintendency of Public Services, which will also supervise their performance. This Superintendency will remain in operation until June 1995. EXPANSION OF ELECTRICITY SUPPLY The demand for electricity will be met within the context of an integrated energy policy, which will ensure that consumption is oriented toward those uses for which it is the most efficient energy source. Energy diversification will be a priority, with emphasis on the widespread use of natural gas in urban residential areas and of LPG in the remote rural areas. The generation and transmission plan, currently being overhauled to bring it into line with the new demand forecasts, should be completed by the end of this year. The generation expansion capacity projected for the period 1993-2000, before the present updating, consisted in the installation of 750 MW (gas), 450 MW (coal), and 1,000 MW (hydro), all projects that can easily be replaced. For transmission, the plan was to construct 1,800 km of 230- and 500-kW lines. Through flexible indicative planning, the policy will seek to give appropriate signals to encourage the private sector to implement the new minimum-cost expansion plan projects, so that the Government will execute projects only when it is not possible to obtain private-sector collaboration. Particular attention will need to be paid to project execution, to avoid delays that could cause future restrictions on supply. The projects included in the strategy approved for the generation expansion program are: - 54 - PROJECT CAPACITY COMMISSIONING (MW) DATE (quarter) 1. Barranquilla capacity upgrade (g) 747 240 MW IV 1995 507 MW 1996-97 2. Termo Valle (g) 212 212 MW II 1996 3. Termo Cesar (c) 300 IV 1999 4. Termo Paipa IV (c) 150 III 1997 5. Central region hydro station (g) 150 100 MW IV 1996 50 MW IV 1997 6. Porce 11 (h) 392 III 1999 7. Urra (h) 340 III 1999 8. La Miel (h)(*) 375 2001-2004 (g): gas-fired thermal station (c): coal-fired thermal station (h): hydro station (*): recommended as part of the strategy for 2001-2004 One of the basic aims of the power policy is to upgrade distribution through attention to infrastructure as well as to the utilities' institutional and administrative aspects. Energy losses within the electricity distribution system are equivalent to over 20% of energy demand, and around 13% of potential users have no access to the service. The distribution system is thus to be modernized, with a view to improving service quality and expanding coverage. The modernization program, together with the actions set down in the management contracts to be discussed below, will help to reduce the level of losses. CONCLUSIONS This overall strategy has produced successful results, the planned actions having been accomplished to the extent described above. The sector has overcome its rationing crisis, and has made progress in handling its financial predicament, with a significant drop in the utilities' energy arrears to Interconexi6n Electrica S.A., private-sector participation has been achieved through mechanisms such as BOOM in thermal generation projects of over 1,000 MW, and laws have been enacted regulating the delivery of public services in general and the supply of electrical energy in particular. It may be affirmed that the restructuring process, having passed through the stages of implementation and institutional organization, is now entering the consolidation phase. Very truly yours, /s/ Jorge Eduardo Cock London Minister of Mines and Energy - 55 - ANNEX 3 ENERGY SUPPLY AND DEMAND Table 3.1 - Energy Supply (Teracalories) Average annual Sectors 1975 1980 1985 1990 1991 1992 1993 growth rate Production 188,781 189,327 268,133 483,762 494,684 496,633 496,926 5.9% Hydroelectricity(') 18,286 13,427 21,224 29,566 28,287 21,567 21,569 1.0% Natural Gas 21,173 33,973 41,033 42,173 43,354 42,227 42,244 4.1% Petroleum 83,978 67,530 95,836 220,776 214,354 221,549 221,680 5.9% Carbon 20,978 25,362 58,331 133,042 153,400 154,544 154,737 12.5% Fuelwood/bagasse 44,366 49,035 51,709 58,205 55,289 56,746 56,755 1.5% Imports Hydrocarbons 2,324 27,964 22,078 12,354 11,601 17,920 17,943 12.8% Exports Hydrocarbons 12,863 14,044 29,085 136,425 123,638 121,617 121,788 14.1% Coal 213 922 23,146 94,848 105,830 108,205 108,684 44.3% Change in stocks 372 (504) 3,890 2,010 4,488 5,963 - Notused2) 16,456 10,854 11,127 5,959 5,166 5,388 5,3881 Total Supply 161,201 191,975 222,963 256,871 267,163 273,380 279,008 Adjustments 483 (2,767) 2,298 (1,661) 8,813 4,714 - Total demand 160,718 194,742 220,665 258,532 258,350 268,666 279,008 3.1% Self Consumption 8,246 8,144 10,420 6,993 8,448 18,549 10,133 Losses 27,714 38,224 42,986 48,163 42,274 28,645 38,001 Final Consumption 124,758 148,374 167,259 203,376 207,628 221,472 230,874 3.4% 1>7Conversion coefficient 0.86 Tcal/Gwh a) Mainly bagasse Source: PEN (Plan Energ6tico Nacional Ministerio de Energia y Minas) and mission estimates. - 56 - COLOMBIA POWER MARKET DEVELOPMENT PROJECT Table 3.2 Final Energy Consumption by Sector (Teracalories) Average Annual Growth rate Sectors 1975 1980 1985 1990 1991 1992 1993 (%) Residential 1.6 42,365 45,356 49,273 55,747 56,751 55,947 56,842 Commercial 6.9 2,654 3,352 6,252 7,384 7,793 8,206 8,772 Industrial 3.8 31,376 37,485 44,104 57,521 62,863 59,154 61,402 Transport 3.9 34,269 43,392 51,194 59,757 60,931 65,554 66,200 Agriculture 23.0 10,049 12,370 11,589 16,014 13,007 14,890 18,315 Construction 6.8 901 1,957 2,075 2,443 2,508 2,762 2,950 Others 9.6 3,144 4,462 2,772 4,511 3,775 14,958 16,394 Total 124,758 148,374 167,259 203,377 207,628 221,471 230,874 3.4 Source: MME-UIME. - 57 - ANNEX 4 COLOMBIA POWER MARKET DEVELOPMENT PROJECT ELECTRICITY PRICES Average Tariff and Subsidies Utility June 1993 December 1993 December 1994 Tariff Subsidies (%) Tariff Subsidies (%) Tariff Subsidies (%) (ColS/kWh) (Col$/kWh) (ColS/kWh) Atlintico 54.06 2.83 59.74 2.34 70.15 1.68 Bolivar 54.85 2.51 60.93 1.51 72.31 (0.22) Cesar 51.23 21.25 57.48 19.65 69.47 16.72 C6rdoba 49.42 27.80 55.72 25.98 66.83 23.87 Guajira 50.13 22.90 55.96 21.72 68.03 18.41 Magdalena 51.64 14.63 57.56 13.47 68.43 11.80 Sucre 49.55 21.52 55.36 20.25 65.68 18.88 Magangui 44.79 37.10 50.49 35.51 63.34 30.64 Medellin 45.63 17.08 50.70 16.21 60.71 13.97 Antioquia 38.59 41.67 43.41 40.34 55.17 34.99 Choc6 35.70 51.53 40.47 50.03 52.35 44.58 Boyac 43.41 21.07 49.02 18.95 58.58 16.96 Santander 44.21 29.91 50.14 27.70 64.16 20.67 Nte de Sant. 44.46 29.94 49.97 28.39 62.08 23.72 Caldas 41.47 39.61 47.05 37.68 60.16 31.69 Pereira 46.66 24.29 52.52 22.49 65.26 17.43 Quindio 47.06 27.00 53.18 24.97 65.77 20.43 Emcali 49.17 12.40 54.94 10.98 66.50 7.62 CVC 45.73 23.47 51.23 22.03 62.87 17.95 Tului 44.51 38.74 50.08 37.32 63.16 32.22 Cartago 40.59 43.13 46.04 41.32 59.47 35.02 Tolima 47.05 24.62 53.26 22.40 65.93 17.63 Huila 46.25 29.77 52.20 27.90 63.97 24.25 CaquetA 50.16 30.08 57.00 27.74 73.16 2047 Cauca 37.90 48.24 42.87 46.75 54.75 41.69 Nariflo 34.69 46.91 39.29 45.33 50.02 40.32 Celgac 51.40 16.38 57.35 15.16 67.30 14.62 Meta 56.84 14.46 63.82 12.67 78.23 8.21 Bogot! 52.24 13.40 57.19 13.78 69.62 1000 National Total 46.53 19.01 53.62 18.07 64.78 15.12 Source: CREG - 58 - ANNEX 5 COLOMBIA POWER MARKET DEVELOPMENT PROJECT ECONOMIC PERSPECTIVES FOR COLOMBIA Background 1. Colombia's population, 35.7 million according to the 1993 census, occupies an area of just over a million square kilometers with about three-quarters of the population living in urban areas. Colombia has plentiful natural resources and coasts on both the Atlantic and Pacific Oceans. Mountainous terrain, however, makes internal transportation costly and slows down physical and social integration. Solid growth of about 4.5 percent per year for the past four decades, combined with a drop in the population growth rate to 1.8 percent per year, have facilitated substantial improvement in social conditions. Rich physical resources, a literate and dependable work force, a robust private sector, competent macroeconomic management, and political stability are factors explaining Colombia's good record of economic development and social improvement over the last thirty years. 2. During the 1980s Colombia achieved one of the highest and most stable growth paths in Latin America. Its prudent and gradual approach to macroeconomic management yielded positive GDP per capita growth at a time of decline for most countries in the region. Productivity in most sectors, however, remained stagnant. Recognizing this shortfall, the Barco Administration launched in 1990 the Economic Modernization Program (EMP)--a set of structural reforms to improve efficiency of resource allocation and use. 3. President Gaviria's Administration (1990-94). President Gaviria's election in March 1990, marked the entry of a new generation in government. During his tenure, which concluded in August, 1994, the Government implemented a large number of additional structural reforms and reoriented the role of the state to focus on the social sectors, infrastructure, and environmental protection, and set the framework for the private sector to be the main driving force in the economy. The centerpiece of the structural reforms was trade liberalization, but this was accompanied with reforms in the financial sector, tax system, foreign exchange market and regulations on direct foreign investment. Congress approved a new central bank law giving the monetary authorities greater autonomy. The labor regime was modified to reduce labor rigidities and facilitate industrial restructuring. Public monopolies were eliminated in sectors critical to trade flows, including railways, ports, shipping, and agricultural marketing. Most of the government's non-oil industrial holdings were divested, as were the five banks nationalized during the banking crisis of 1982-85. On the political front, the constitutional reform of 1991 advanced the process of decentralization mandating the delegation of both central government revenues and responsibilities for the provision of basic social services to subnational governments. International capital markets - 59 - have reacted positively to Colombia's development granting it one of the highest ratings in Latin America. 4. President Samper's Administration (1994-98). The Samper Administration, inaugurated on August 7, 1994, put forward its policy agenda in the recently completed 1994- 98 national development plan now being discussed in Congress. The four-year plan, which is known as the Salto Social (the Social Leap), focused on four critical areas of action: (i) social development; (ii) competitiveness of the economy; (iii) environment; and (iv) decentralization and institutional strengthening. All four elements of the strategy are to be pursued in tandem. Among the policy initiatives launched during the first six months of the Administration, probably the most important one was the negotiation of a social pact with labor unions and the business sector. The social pact, signed on December 9, 1994, was proposed to underpin the Government's effort to reduce inflation. Preliminary results are encouraging. Other policy initiatives of the new Administration were a series of measures to support agriculture-- including increased protection through the introduction of domestic procurement agreements for key crops--and a proposal submitted to Congress to establish an oil stabilization fund to smooth the spending of oil revenues. Recent Economic Development 5. Preliminary data indicate that output expanded by 5.7 percent in 1994 led by buoyant investment expenditures and a continued strong performance in the construction, commerce, finance, and transport sectors. With the buoyancy of economic activity, the unemployment rate dropped to 7.4 percent in the third quarter of 1994, the lowest rate observed in recent years. Inflation remained at the same level of 1993, with consumer prices rising by 22.9 percent in 1994. 6. The strength of economic activity and sustained private capital inflows--despite increased restrictions on external borrowing--sparked a rapid increase in imports (with equally strong growth of capital and consumer goods imports). Notwithstanding a 14 percent increase in export value--reflecting the surge in coffee export prices in the second half of the year--the external current account deficit remained wide at around 5 percent of GDP in 1994. Overall, there was a small decrease in net international reserves for the year as a whole of around US$330 million, bringing net reserves to US$7.5 billion, or nearly 6 months of imports of goods and services. Medium Term Economic Perspectives 7. Colombia is starting to face an oil boom derived from the newly-discovered Cusiana and Cupiagua oil fields that could put the economy on a faster growth path--sustained GDP growth of almost 6 percent per year is within reach in the medium term. Overall oil production is expected to increase from approximately 480,000 bpd in 1993 to around 1,000,000 bpd in 1997 effectively doubling the participation of the oil sector in total GDP by the end of the - 60 - decade. The present value of the net income flows to be generated by the new oil discoveries between 1993 and 2005 amount to approximately US$15 billion, equivalent to 28% of GDP. 8. Colombia is expected to consolidate the gains of the structural reform of the past four years and accelerate the pace of economic growth. In response to the newly-created incentive structure, the implementation of an appropriate regulatory framework, and the foreign exchange revenues from higher oil exports, productivity is expected to improve and per capita GDP growth to rise above 3 percent per year. For the second half of this decade, private investment is expected to average 14 percent of GDP and public investment 9 percent of GDP, a combined average of more than 5 percentage points of GDP higher than the 1980s average. Table 2: COLOMBIA - Summary of National Accounts (As percentage of GDP) 1990 1991 1992 1993 1994p 1995p 1996p 1997p 2000p I. Sources of Demand Total Consumption 77.0% 78.0% 80.6% 82.8% 78.8% 77.5% 77.1% 77.0% 75.7% Private Consumption 67.5% 68.7% 71.1% 72.2% 67.0% 65.6% 65.3% 65.1% 63.9% Public Consumption 9.4% 9.3% 9.5% 10.6% 11.8% 11.8% 11.8% 11.8% 11.8% Investment 18.5% 16.0% 17.2% 20.5% 24.1% 24.1% 23.8% 22.9% 25.4% Private 12.2% 9.4% 9.1% 11.1% 15.1% 14.6% 13.5% 12.1% 13.8% Public 6.4% 6.5% 8.1% 9.4% 8.9% 9.5% 10.3% 10.8% 11.6% Exports 24.4% 22.1% 20.6% 19.0% 18.8% 20.0% 20.3% 21.0% 19.4% Imports 19.9% 16.1% 18.4% 22.2% 21.7% 21.6% 21.2% 20.9% 20.4% II. Savings-Investment Balances Public Sector 0.4% -0.4% 0.0% 0.0% 0.7% 1.0% -0.7% -0.7% 0.7% Private Sector 1.2% 6.0% 1.6% -4.2% -5.1% -4.9% -2.5% -1.5% -4.2% Current Account 1.6% 5.6% 1.6% -4.2% -4.3% -3.9% -3.2% -2.2% -3.5% Balance Public Savings 6.8% 6.1% 8.2% 9.3% 9.7% 10.5% 9.6% 10.1% 12.3% Private Savings 13.4% 15.4% 10.7% 6.9% 10.0% 9.7% 11.0% 10.6% 9.5% Memorandum Items: Real GDP, % Change 4.3% 2.0% 3.8% 5.3% 5.3% 5.5% 5.5% 5.5% 6.0% Real GDP Per Capita, % 2.4% 0.3% 2.1% 3.5% 3.5% 3.7% 3.7% 3.7% 4.2% Change GDP in US$ (millions) 40,274 42,519 48,712 53,368 64,371 72,573 79,201 86,826 110,121 Real Private Consumption, 2.3% 3.0% -0.9% 6.0% 9.3% 3.6% 5.1% 5.3% 7.0% % Change Real Total Investment, % -1.2% -8.7% 39.0% 27.7% -1.1% 6.3% 4.6% 2.3% 4.0% Change p - projected - 61 - ANNEX 6 COLOMBIA POWER MARKET DEVELOPMENT PROJECT ELECTRICITY DEMAND 1. Historical Data: The electricity sector's historical net generation of electricity for the 1975-94 period is shown in Table 6-1. Net generation grew at an average rate of 6.4% per annum. However, the actual growth rate has been uneven: during 1975-80 it averaged 9.8%; during 1980-90 it averaged 5.8% and during 1990-94 it averaged 3.7% per annum. There have also been a number of atypical years characterized by negative or zero growth due to power rationing, such as 1981 and 1992/93. The latter explains the low growth rate during the last four years, the reason being that, after a period of significant power cuts, demand does not recuperate because substitution practices (including backup generation), as well as conservation habits, become permanent. Table 6-1 COLOMBIA - Total Electricity Generation Growth (Twh) (%) 1975 12.2 1976 13.5 10.7 1977 14.2 5.2 1978 16.2 14.1 1979 17.9 10.5 1980 19.5 8.9 1981 19.5 0.00) 1982 21.5 10.3 1983 23.1 7.4 1984 24.6 6.5 1985 25.7 4.5 1986 27.6 7.4 1987 29.5 6.9 1988 31.2 5.8 1989 32.6 4.5 1990 34.1 4.6 1991 35.1 2.9 1992 31.8 -9.4() 1993 36.4 14.5(1) 1994 39.5 8.5 < Values are atypical due to severe power rationing in 1981 and 1992-3. - 62 - 2. Market Structure: Final demand for electricity has remained relatively stable during the past decade, with predominantly residential sales (48%), followed by the industrial (30%) and commercial (10%) subsectors, as shown in Table 6-2. Losses exhibited an increasing trend until 1988 when they reached a maximum of 24%. Since then there have been efforts to curb them, but they have only succeeded in reducing them to around 20%. 3. Forecast of Future Power Sales. The principal variables influencing power sector demand are: * Population growth and service coverage; * Economic growth * Electricity prices and tariff policy * The supply of substitutes Regarding these factors, the outlook as of 1995 appears as follows: (a) Service coverage by electricity utilities is estimated to be around 70-75%; this percentage is not expected to increase significantly in the near future as extending service to currently isolated communities is not economical (these areas may have electricity service from local generation); (b) Economic growth is expected to fluctuate between 5% and 6.3% between 1995 and 2010; (c) Prices for electricity are expected to increase, and current plans are to reach economic cost levels by 1997; (d) Substitutes are expected to exert a major influence on electricity growth: on one hand, electricity price increases will induce its substitution by lower price and cost alternatives (LPG, natural gas) and, on the other, increases in the supply of natural gas and the construction of pipelines to major urban centers which have hitherto lacked this service will require the development of a significant market to justify these investments; this can be expected to lead to an aggressive marketing approach that would impact the electricity market; (e) Expected reductions in losses will also exert a moderating influence in demand: by legalizing connections and detecting theft, consumers can be expected to moderate their consumption; (f) Finally, energy conservation programs can also be expected to reduce demand growth - 63 - COLOMBIA National Interconnected System Table 6.-2: Electricity Supply and Deniaiid 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 Total Generatioh 19448 19479 21511 23034 24558 25733 27548 29411 30973 32347 33839 35193 31847 36588 39455 Hydro . 14308 14065 15024 15184 16850 18291 21087 23072 24217 26473 27456 27590 22039 27639 31841 Thermal 5140 5414 6487 7850 7708 7442 6461 6339 6756 5874 6383 7603 9808 8949 7614 Imports 33 40 38 39 30 5 3 82 179 226 241 213 337 303 144 Available Energy 19481 19519 21549 23073 24588 25738 27551 29493 31152 32573 34080 35406 32184 36891 39599 Exports 0 01 0 0 0 0 0 0 0 0 0 0 0 0 0 Demand (GWh) 19481 19519 21549 23073 24588 25778 27551 29493 31152 32573 34080 35406 32184 36891 39599 Consumption sales 15159 15327 16466 17275 18252 19109 20420 21793 22958 24350 26048 27375 25209 27963 29939 Residential 7092 7224 7923 8272 8779 9293 9849 10378 11086 11809 12488 12962 11696 13173 14041 Commercial 1901 1853 1959 2043 2012 2112 2146 2244 2281 2450 2575 2695 2424 2756 3078 Industrial 4537 4519 4719 4901 5286 5449 6130 6679 7008 7482 7880 8389 8041 8871 9729 GovernmentyA.P. 1390 1517 1562 1705 1793 1863 1945 2135 2203 2402 2565 2714 2573 1758 2007 Others 239 214 303 354 382 392 350 357 380 207 540 615 475 1405 1084 Utilities consumption 407 419 510 575 590 595 572 588 623 601 648 715 370 751 701 Transmission and Distribution Losses. 3915 3773 4574 5223 5746 6034 6559 7113 7571 7492 7384 7496 6405 8243 9102 Rationing 900 5183 973 172 % of losses 20.1 19.3 21.2 22.6 23.4 23.4 23.8 24.1 24.3 23 21.7 21.2 19.9 22.3 22.9 MaximumDemand (MW) 35681 3404 3855 4040 4230 4436 4838 5150 5443 5731 5915 6184 6098 6455 6896 Load factor 0.62 0.66 0.64 0.65 0.66 0.66 0.65 0.66 0.65 0.65 0.66 0.65 0.65 0.65 0.66 Source: ISA - 64 - 4. The Policy Unit of the Ministry of Mines and Energy, UPME, has the responsibility for overseeing the energy sector's evolution. In order to structure the indicative expansion plan, it developed a sector- wide approach for structuring overall energy projections. The first phase of this study was executed during the first half of 1994; its methodology is based on econometric models together with analytic models which are combined to produce integrated energy projections. 5. Three scenarios were considered for projecting electricity demand during 1995-2007 which depend on (a) the degree of penetration of natural gas; (b) the adjustment of electricity prices; (c) economic development; and (d) energy conservation and demand management programs. Table 6-3 summarizes the assumptions and results obtained under the three demand scenarios. Table 6-3 Electricity Demand Projections Scenario Criteria Low Base High Electricity Substitution Maximum substitution Gradual substitution Low substitution program by natural gas until 2001, vegetative 1993-2010 1993-2010 and LPG in residential growth thereafter Subsector Electricity prices residential Average prices' Average prices' Low prices 2 other ' constant prices constant prices constant prices Energy conservation and savings program Successful Slow acceptance Unsuccessful GDP growth 1995-2010 5.13% 5.13% 6.26% 1995-2000 5.35% 5.35% 6.29% 2000-2010 5.00% 5.50% 6.25% Demand growth 1993-2010 4.84% 6.10% 6.77% 1993-2000 3.63% 5.86% 6.39% 2000-2010 5.70% 6.28% 7.04% Average prices evolve as approved in 1995 by the social pact; cost levels are reached in 1998. 2 Residential prices reach the target cost in 2000; thereafter they do not grow in real terns Other sub sectors have already reached the target cost level The change in the growth rate is explained by the change in pricing increases and a stabilization in natural gas growth. 6. The assumptions underlying the projections were analyzed during appraisal. The estimated growth rates for the economy largely coincide with the Bank's projections and the overall approach to estimating future demand is based on sound principles. The results yield higher growth rates than those observed during the last decade. On one hand, the strong expected economic performance will provide a demand-stimulating factor given that the income elasticity of demand is greater than unity; on the other hand, there is a major element of uncertainty related to the substitution of electricity by natural gas. The latter, characterized by its low cost and its environmentally friendly characteristics is likely to be widely sought after by consumers, even at the current price levels; this incentive is likely to intensify with the expected readjustment of electricity prices. The base case scenario assumes a gradual substitution of natural gas for electricity, and in this aspect is a conservative scenario. - 65 - ANNEX 7 COLOMBIA POWER MARKET DEVELOPMENT PROJECT INDICATIVE EXPANSION PLAN Background 1. The Electricity Law approved in July, 1994 as well as the Domiciliary Public Services Law assign the Government the responsibility for assuring adequate supplies of electricity by taking measures to prevent major disruptions. 2. In the context of a market-driven development, this responsibility consists of foreseeing the generation and transmission requirements of the electricity sector, following-up the development of new facilities determining the need for additional incentives to the private sector and, ultimately, taking corrective action directly to prevent rationing on a large scale. 3. The objective of the indicative expansion plan is to respond to these requirements by (a) informing investors on desirable resources to be developed, including their location, size and timing, (b) informing Government of potential risks regarding supply disruptions; and (c) identifying the decision agenda regarding projects to be promoted through private sector investment as well as those that require decisions from Public Sector agencies. 4. The responsibility for developing the indicative expansion plan was assigned to the Policy Unit (UPME2). Given that this function had been executed in the past by Interconexi6n Electrica, and that the expertise regarding the structure of expansion plans was concentrated in that company, UPME delegated to ISA this responsibility in 1993; in the 1994/95 revision of the plan, ISA has continued to execute a major proportion of the plan with the help of UPME. The 1993 Expansion Plan 5. The first plan executed under the new institutional arrangement can be briefly summarized as follows: * It assumed a growth rate for electricity demand within the 4.2%-4.7% range (see annex 6 electricity demand); * For 1995-2000 it identified the need for a total of 1950MW of new generation distributed between 750MW in gas-based plants, 450MW in coal plants and 750MW of hydro generation; 2 Unidad de Planeacion Minero Energetica - 66 - * For 2001-2004 it identified 2050MW of which 1200MW would be gas-based, 150MW coal and 700MW hydro. 6. The plan exhibits the following progress: * 742MW net additions of gas-based generation are under development with private sector participation (ABB and ENRON in Termobarranquilla and Termovalle, respectively); * 150MW coal-based generation has been awarded to a private consortium (Paipa IV); * The Porce II hydro project is under construction by EPM; * The Urra I hydro is under construction and is expected to start operating towards the end of 1999; * The Miel I hydro project was launched and a consortium was formed to build it. The 1994/95 Update 7. The 1993 plan was updated in 1994/95 in order to (a) extend the planning horizon to 2007 and (b) take into account revised demand growth which is expected to be in the 5-6% range for the near and medium future. 8. Both the 1993 plan and the 1994/95 were structured in order to provide an energy supply reliability of 95%, i.e. the plan assures that the variations in runoff would lead to a disruption of supplies in 5% or less of the available hydrological simulation sequences. In order to accomplish this, the update confirms the need for reinforcing the thermal component of the system in order to manage possible drought conditions, and in particular those arising with the so-called "El Nino" phenomenon. 9. For the 1995-2000 period, the update recommends an additional 700MW in thermal plants which were identified as 400MW gas-based and 300MW coal-based (which corresponds to the Termocesar coal plant recommended in the previous plan). This plan was endorsed by CONPES in February, 1995. The principal action to be taken consists of identifying sponsors and investors for the 400MW thermal plants. The Termocesar plant feasibility is expected to be contracted by ISAGEN. 10. The private sector has so far responded aggressively to the new opportunities: there are at present 22 consortia which have expressed their interest in developing a total of 1700MW to 2600MW in thermal and hydro plants. The range of these proposals varies from 10MW in small hydro to 100-500MW proposals by both major energy companies and large industrial Colombian conglomerates. 11. For the longer term (2001-2007), the decision agenda calls for furthering studies related to five possible hydro plants; the hydro capacity to be installed during this period is on the order of 1200MW to 1500MW. Given the construction time required for these plants, further studies are required in order to make a decision to proceed with their construction and to initiate their promotion in 1996-97. - 67 - 12. Regarding transmission expansion, the major developments include the reinforcements between the Central region and the Southwest and the new interconnection between the Atlantic region and the Northeast, i.e. the principal investment component of the project being financed by the Bank. 13. The cost of new projects in the proposed expansion plan for the 1995-2007 period has an expected present value of US$4.6 billion at December, 1994 price levels. 14. The plan was reviewed and its assumptions and conclusions were considered to be adequate by the Appraisal Mission. - 68 - ANNEX 8 COLOMBIA POWER MARKET DEVELOPMENT PROJECT FINANCIAL PERFORMANCE OF THE POWER SECTOR 1. This annex analyzes the Colombian power sector's past financial performance and its expected performance during project implementation. Section A describes the financial situation of the power sector during 1984-1990, before the implementation of the power sector reform program. Section B summarizes the actions taken by the government during 1991-1994. Section C assesses the financial prospects of the power sector during 1995-2003. A. Financial Performance During 1984-90 2. This period is characterized by a considerable deterioration of the sector's finances due to (a) slow tariff increases which did not keep up with inflation; (b) large increases in debt service due to plant overbuilding in the early 1980s; (c) periods of strong devaluation which further increased the already heavy burden of dollar-denominated debts; and (d) increased inefficiency due to administrative, financial, and commercial mismanagement. Average Tariff charged to Final Consumers Final Consumers 60- so- -- 0 EEB * EPM 40 O CVC 3o .E- EMCALI 0 ATLANTICO 20 0 EADE 10 E BOLIVAR 0 EO OHEO l'84 1986 1988 1990 Soucer FEN 3. Prior to 1984, the power sector was heavily subsidized and tariffs did not reflect costs. During 1980-84, average tariffs charged to final customers covered only about 50% to 60% of marginal costs and induced over consumption and waste. This low tariff level extended from the bulk level to the retail level during the 1984-90 period. In 1986, only 82% of average marginal costs were covered. Although the average tariff applied to final customers increased by 15% during the period, the retail tariff for each - 69 - utility was not uniform, and, depending on market composition, average prices varied considerably from one company to another, as shown in figure 8. 13. Most of the variation can be explained because the subsidized residential tariff was considerably below the overpriced commercial and industrial tariffs; consequently, distribution utilities with large numbers of residential customers were worse off than others. In 1990, the average tariff applied to final customers ranged between 3.7 and 6.8 UScent/kWh at 1993 price levels. 4. As a result of the rapid growth in power generation and distribution over the past twenty years, the power utilities incurred significant amounts of external debt to fund new investments as shown in Table 8.1. The consolidated indebtedness of the power sector amounted to about US$5.2 billion in 1990, of which US$2.9 billion was foreign debt and US$2.3 billion was internal debt. Consolidated internal cash generation of the power sector was insufficient to finance the corresponding debt service for 1990, which was partially financed with government contributions (see Table 8.2). In 1990, Government contributions were mainly used to finance guaranteed external debt totaling about US$130 million. It was also used to pay arrears from distributors due to energy purchased from ISA and to partially finance ICEL and CORELCA's investment program. Table 8.1: EVOLUTION OF POWER SECTOR DEBT (US$ million) Total Debt External Debt Local Debt Utility 1986 1990 1986 1990 1986 1990 ISA 1254 1232 812 732 442 500 Guavio 794 1066 727 943 67 123 CORELCA 523 568 327 172 196 396 EEB 607 496 461 247 146 249 CHB 400 476 268 163 132 313 EPM 534 465 424 358 110 107 ICEL 339 444 248 150 91 293 CVC 378 418 239 133 139 285 OTHERS 97 78 39 19 58 59 TOTAL 4,926 5,243 3,545 2,918 1,381 2,325 3 The utilities included in this figure cover over 75% ofthe retail market. - 70 - Table 8.2: CONSOLIDATED SOURCE AND APPLICATION OF FUNDS (US$ million) 1984 1987 1990 Gross Cash Generation 614 753 598 Gross revenue 894 948 1043 Cash operating expenses -422 -350 -467 Depreciation and others 142 155 22 Debt Service 480 749 899 Amortization 320 469 509 Interest 160 280 390 Net Internal Cash Generation 134 4 (301) Government contributions 69 125 148 Borrowings and others 1051 618 951 Total Sources 1254 748 815 Investment 1278 627 605 Other applications (24) 121 210 Debt Service Coverage Ratio 1.3 1.0 0.7 Self Financing Ratio (%) 10.0 1.0 0.0 5. The rapid devaluation of the Colombian peso with respect to the dollar which took place between 1982 and 1986, together with low price levels which were not adjusted in line either with inflation or the devaluation, severely impacted the sector's financial position whose long-term debt was denominated in foreign currency. 6. The lack of corporate accountability and autonomy in most of the utilities led to a deterioration of administrative, financial, and commercial practices. Power losses were out of control and ranged between 14% and 32% in 1990. Arrears of energy bills from distributors to generators, and from government agencies and private customers to distributors exceeded 6 months in most utilities. 7. Table 8.3 summarizes the financial performance of the utilities during 1984-90. The utilities have been grouped into three categories: (a) large companies (with total assets in excess of US$700 million), which include most of the generation utilities; (b) small power utilities, which were profitable and solvent at the end of 1990; and (c) small power utilities (mainly ICEL and CORELCA subsidiaries), which were unprofitable and insolvent at the end of 1990. - 71 - COLOMBIA POWER MARKET DEVELOPMENT PROJECT POWER SECTOR Table 8.3: SUMMARY OF FINANCIAL PERFORMANCE - PERIOD 1984 - 1990 Cash Oper.ting Debt Service Debt/Assets Net Cash Generation (USS million) GWh Consumers Employee A/B COMPANY Ratio (%) Coverage (%) 1984 1987 1990 Total Gross Net Sold A B Assets Revenue Income 1984 1987 1990 1984 1987 1990 1984 1987 1990 (USS million) 1990 1990 1990 1990 1990 1990 1990 LARGE COMPANIES 10,767 1,141 (105) 45,337 1,821,795 11,890 153 Fipresa de Energia de Bogota EEB 55 35 51 1.8 1.4 0.7 47 74 59 71.0 58.5 8.2 3,255 317 67 6,057 1,023,206 4,374 234 Interconexi6n ElWctrica S..A. ISA 36 26 26 0.9 0.8 0.7 45 69 56 23.5 (20.1) (50.9) 2,630 240 10 14,527 7 1,387 Corp. Electr. de la Costs Atlintica CORELCA 59 46 61 0.7 0.6 0.6 42 64 64 (13.9) (53.0) (42.5) 1,121 129 (26) 4,869 10 1,621 Empresas P6blicas de Medellin EPM 42 39 47 1.4 1.3 1.0 37 62 53 41.5 45.7 4.9 1,100 189 24 7,640 531,464 3,070 171 Instituto Colombiano de Energia Elictrica ICEL 91 90 98 0.3 0.6 0.1 38 51 81(21.8) (21.8) (72.1) 1,026 108 (61) 5,331 13 369 Corp. Aut6noma Regional del Cauca CVC 53 48 60 0.8 0.8 0.5 44 76 70 0.4 4.3 (0.0) 890 120 (43) 4,630 267,093 1,018 262 Central Ilidroelectrica de Betania CHB 0 4 21 0.0 0.1 0.1 73 73 75 (0.0) (29.0) (83.7) 744 38 (74) 2,283 2 51 SMALL, PROFITAliLE, AND 976 302 30 5,739 1,797,381 7,806 230 SOLVENT Central Hidroelctrica de Caldas S.A. CIEC 90 99 91 0.8 1.2 1.8 23 26 26 (1.4) (0.6) 2.9 193 39 3 1,273 234,689 1,438 163 Hectrificadora de Santander S.A. ESSA >100 95 88 >2.0 >2.0 >2.0 17 15 24 6.7 3.2 9.8 171 33 2 828 261,644 1,249 209 Empresa Anfioquia dce Energia EADE 96 86 84 >2.0 >2.0 >2 0 6 9 12 2.7 3.8 4.7 154 34 3 1,169 293,189 1,290 227 ElectrificadoradeBoyaciS.A. EBSA 77 70 73 >2.0 >2.0 >2.0 20 14 27 4.4 7.9 7.3 147 26 7 752 191,250 970 197 Fnpresas -funicipalesdeCali EMCALI 91 87 94 0.8 >2.0 >2.0 55 48 28 (2.2) 17.5 12.3 127 102 11 315,121 787 400 Fmpresa I lectnca de Cundinanarca S.A. EEC 85 93 92 >2.0 >2.0 >2.0 52 46 36 2.4 2.5 3.0 64 20 2 445 110,618 609 182 C. Electr del Norte de Santander S.A. CENS >100 93 100 0.0 >2.0 >2.0 32 28 41 (1.0) 2.8 1.7 45 22 1 599 166,520 536 311 Flectrilicadora del lluila S.A. 97 110 94 1.0 1.1 >2.0 22 26 44 0.3 0.2 2.0 45 13 1 319 119,347 485 246 Electrificadora del Meta S.A. >100 >100 98 >2.0 >2.0 1.2 52 62 57 0.3 0.3 0.4 20 9 0 226 64,893 221 294 Electrficadora del Caqueti S.A. >100 >100 93 0.9 >2.0 1.9 20 17 73 (0.0) 0.2 0.2 6 2 0 54 21,657 104 208 ElectrificadoradelChocoS.A. >100 84 87 0.0 >2.0 >2.0 29 19 59 (0.2) 0.3 0.2 5 2 0 74 18,453 117 158 SMALL, UNPROFITABLE, AND/OR INSOLVENT 728 215 (49) 5,189 1,161,929 6,904 168 Liectrificadora del Atlaintico SA. >100 >100 >100 2.0 1.1 0.0 46 73 63 2.4 0.7 (14.3) 204 72 (16)1 1,623 251,026 1,531 164 Electnticadora del Tolima S.A. >100 >100 >100 0.7 0.0 0.0 20 23 34 (0.6) (2.9) (247.0) 155 22 (5) 611 164,350 933 176 Electnficadora de Nariho S.A. CEDENAR >100 >100 >100 0.0 0.0 0.0 55 53 47 (3.2) (2.2) (3.8) 73 12 (5) 375 139,385 638 218 Electrificadora de Bolivar S.A. >100 96 99 0.3 0.0 0.0 49 58 50 (1.9) (1.1) (2.1) 66 44 (4) 969 129,600 879 147 Centraies Electricas del Cauca S.A. CEDELCA >100 >100 >100 1.0 0.0 0.0 16 24 45 0.0 (1.0) (0.7) 51 8 (2) 267 92,516 539 172 ElectrificadoradeCordobaS.A >100 >100 >100 0.0 0.2 0.0 43 52 40 (1.5) (0.8) (1.9) 49 12 (5) 301 98,721 620 159 Electinficadoradel MagdalenaS.A. >100 96 >100 0.0 0.0 0.0 97 93 64 (0.8) (1.4) (1.6) 33 16 (3) 386 96,772 523 185 hiectrilicadora del Sucre S.A. >100 >100 >100 0.0 0.0 0.0 66 71 48 (1.0) (0.6) (0.3) 33 9 (1) 221 69,580 444 157 Electrificadora del Cesar S.A >100 >100 >100 0.0 0.0 0.0 58 77 41 (0.4) (0.4) (0.3) 25 9 (1) 212 70,441 302 233 Electrificadora de la Guajira S.A. >100 >100 >100 0.0 0.0 00 64 110 80 (1.3) (2 3) (1.2) 17 6 (3) 145 40.120 294 136 Hectrificadora de San Andres >)00 >100 >100 0.0 0.0 0.0 20 20 18 (2.6) (0.7) (0.7) 22 5 (3) 79 9,418 201 47 TOTALPOll ER SECTOR(CONSOLIDATED) 47 37 45 1.0 0.9 0.6 41 63 61 118.1 3.6 (265.6) 9,102 1,043 (127) 25,155 4,781.105 26,680 179 Note ( onsolidated values for the total power sector do not always correspond to the sun of the vlaues for each company because of inter-company trade and the fact that a number of :ompanies base parlicipation in the uit of other power utilities. - 72 - 8. The first group represents 81% of total power sector assets, and includes the main generation and distribution utilities. Of these, CORELCA, ICEL, CVC and CHB exhibit a deteriorating trend during 1984-1990. Net income was negative, debt service coverage was lower than 0.7, and the debt/assets ratio was higher than 60/40. ISA's net cash generation was also negative due to the heavy load of its debt service. The second group, which accounts for 11% of total power sector assets, had a satisfactory financial situation. The third group, with about 8% of the power sector assets, had an unsatisfactory financial situation. Net income and net cash generation were negative. Most of these distribution companies were more than 13 months in arrears in payment of the energy purchased from generation utilities. Their accounts receivable ranged between 66 days and 400 days; many of the clients in arrears were government agencies (water companies, hospitals, schools, government offices, etc.) whose debts are difficult to collect as power cannot be readily cut off without giving rise to social and political conflicts. B. Financial Performance During 1991-94 9. As part of its 1991 adjustment program, the Government defined a long-term strategy to improve efficiency and to rehabilitate the power utilities' finances. This strategy aimed at: (a) establishing a rational tariff structure and rate level; (b) setting the utilities on a sound financial footing; and (c) increasing their efficiency. 10. Tariff Adjustment. Tariffs charged to final customers maintained an increasing trend during this period. This adjustment was particularly important in dollar terms as the rate of devaluation of the Colombian peso during 1991-94 was considerably lower than the rate of inflation (and lower than the rate of increase in electricity prices). During this period, the government made changes to the level and tariff structure in order to reflect economic costs and to reduce subsidies to residential customers. By the end of 1994, the average electricity price applied to final customers ranged between 6.0 and 10.0 UScent/kWh and the sector's average tariff was estimated to cover around 90% of LRMC. 11. Financial Rehabilitation. By far the most important step toward the implementation of the Government's strategy was the debt relief granted by the National Government to the large power utilities in exchange for assets and equity shares. This was made through a number of financial operations which consisted of: (a) A Debt/Equity Swap. In October 1991, the Government increased its participation in Interconexi6n El6ctrica!s equity, through capitalization of US$342.3 million owed by the utilities to Interconexi6n Eldctrica, and by US$318.5 million owed by Interconexi6n Eldctrica to the Government. As a result of this operation, debt service was reduced, and the Government became Interconexi6n E16ctrica's main stockholder. Table 8.4. summarizes the financial operation: - 73 - Table 8.4: Debt/Equity Swap (US$ million) Utilities' Debt to Interconexi6n Eldctrica's Debt Total Utility Interconexi6n to Government Capitalized Elctrica Debt CORELCA 150.8 45.0 195.8 EEB 28.2 140.0 168.2 ICEL 134.1 9.7 143.8 CVC 27.6 92.5 120.1 EPM .5 30.3 30.8 CHEC 1.1 0.9 2.0 Total 342.3 318.5 660.8 (b) A Debt/Asset Swap. In 1992, the Government implemented measures to improve the financial situation of CORELCA, CHB, ICEL, and CVC. The Government took charge of these utilities' foreign debt and canceled other debts amounting to about US$1.1 billion, as shown in Table 8.5. In return, the Government received operating assets for the same amount (Termocartagena - 220MW, Termotasajero - 150MW, and Termopalenque V - 20MW, among others). Table 8.5 Actions Tken in large Government-Owned Utilities 1992 (US$ million) Utility Resolution Debt Swaps: Bills owed Guaranteed Debts with Internal Interconexi6n Total foreign debt Government debt Electrica CORELCA #124, dated 10.14.92 94.7 90.0 184.7 CHB #11, dated 9.14.92 97.9 259.1 357.0 ICEL #130, dated 11.14.92 112.9 50.2 215.5 96.0' 3786 CVC #137, dated 11.15.94 63.8 68.1 131.9 Total 369.3 467.4 215.5 96 1052.2 12. In 1992, the Government also defined a strategy to improve the financial situation of ICEL's and CORELCA's subsidiaries (electrificadoras). This strategy included the implementation of: (a) a plan to alleviate the short- and medium-term financial situation of the electrificadoras. Arrears due to energy purchased by the electrificadoras to ICEL 4Resolutions #153 and #121, dated 11.4.93 and 10.13.94, respectively - 74 - (US$76 million) and CORELCA (US$125 million) were refinanced through long- term debts, with a maturity between 20 and 30 years, 4 years grace period, and 5% and 10% interest rate; (b) a mechanism to transfer subsidies to the electrificadoras through budget appropriations in order to cover the deficit resulting from the supply of electricity to low income residential users at below-cost tariffs. This budget allocation amounted to about US$89 million during 1992-94. 13. Performance Contracts. These contracts were signed between the Government (through the Consejo Superior de Politica Fiscal and FEN), and all those utilities profiting from government loans and guarantees. The contracts set: (i) limits to the intervention of the Board in the utility; (ii) specific corporate targets; and (iii) administrative, commercial and financial performance targets to managers. In turn, the Government provides financial support through budget allocations. Lack of compliance with the committed objectives would cause disbursement suspension, credit accelerations, and firing of managers. 25 performance contracts' were signed during 1992 and 1993, and 20 of them induced a positive recovery, which resulted in net income and profit increases (see Table 8.6). Although these performance contracts will contribute to improve the utilities' financial situation, further actions are required to solve the problem and to improve management and ownership responsiveness. 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As a result of the re-structuring reform initiated by the Government in 1991, the prospects for the power sector have changed radically: " Bulk electricity prices have been deregulated, thereby introducing an element that will pressure final user prices to be adjusted accordingly; " A regulatory commission is in charge of setting regulated prices; although the Commission has Government officials sitting on it, it also has independent regulators who outnumber the former and can prevent tariff erosion; " The Domiciliary Public Services Law mandates that prices be adjusted to cost levels within the next five years, thereby pressuring the Government to maintain the real level of electricity prices; it also mandates that Government agencies include provisions in their budgets for paying public service bills, thereby helping to keep electricity companies' receivable under control; " The Government has recognized that allowing the sector to deteriorate financially, as in the 1980s, leads ultimately to project delays, neglect in equipment maintenance, costly bailouts and, eventually, power cuts; and " In accordance with the principles set out in the Public Services Law, the Government has effectively appropriated National Budget funds to finance the subsidies it awards certain categories of residential customers, thereby facing a tradeoff between allowing tariffs to be adjusted or imposing greater pressure on the Budget. 15. The financial performance of the power sector as whole for 1995-2003 is expected to be satisfactory. Table 8.7 summarizes the forecast financial performance of the utilities during 1994- 2003. Projected tariffs were gradually adjusted to reflect economic costs, as indicated by the regulatory commission's guidelines and targets. Despite the overall satisfactory performance, the results are not uniform. In order to analyze them, the utilities have been grouped into four categories, as follows (a) Large generation and distribution companies. This group includes ISAGEN, EPM, EPSA, CHB, EEB, and CORELCA, whose projected financial performance is generally good., except for the last two utilities. EEB and CORELCA show a weak financial situation in the short and medium term, with a positive trend towards recuperation. EEB has a heavy debt service due to the construction of Guavio, which will become progressively lighter, CORELCA would need additional financing of about US$700 million (including the corresponding financial cost) to cover its debt service and investments due to the operation of new independent producers (such as PROELECTRICA and eventually the - 77 - Termocartagena and Las Flores plants if they are privatized) which would participate in the bulk power market, thereby displacing CORELCA's sales. (b) Small power utilities, which are expected to be profitable and solvent during the period. These utilities present an improving financial trend during the periUd. Most of the utilities have a strong tariff structure and an acceptable administrative management. This group also includes some utilities (Magdalena, Cesar, and Guajira), which in spite of having had financial problems during 1984-90, are expected to recover during the period. (c) Small power utilities under financial recovery during the period. This group includes utilities having financial difficulties only during the first three years. These companies, which account for about 4% of the sector's net fixed assets, deteriorated during 1991-94 with the exception of SUCRE (see Tables 8.3 and 8.6). The financial recovery of BOYACA, SUCRE and CAQUETA is partially due to the enforcement of a performance contract signed in 1992; EADE entered into a performance contract only in 1994. (d) Small power utilities with scarce hope of becoming either profitable or solvent. This group includes utilities with a predominantly residential market structure of low income customers. They account for around 2% of the sector's net fixed assets and about 4% of total supply. Electrificadora de Bolivar recently lost most of its industrial customers to Proel6ctrica, an independent private generator; Choc6, Nariio, and CEDELCA serve mainly rural customers. - 78 - COLOMBIA POWER MARKET DEVELOPMENT PROJECT POWER SECTOR Table 8.7: SUMMARY OF FORECAST FINANCIAL PROJECTIONS - PERIOD 1994 - 2003 Net Faxed Rale of Return Deb Servite Coverage Self-finaning Ratio Liabihty Veru Asmete (%) (ra6o) (%) Total Asets (%) COMPANY in 1994 1994 1997 2000 2003 1994 1997 2000 2003 1994 1997 2000 2003 1994 1997 2000 2003 (USSrudlion) LARGE COMPANIES 9638,0 EE. deBogota - EEB 3728,1 9,0 9,B 10,4 6,4 0,8 0,7 1,0 1" -90 <100 '100 >100 59 53 38 25 ISAGEN and ISA 1812,0 7,4 6,4 -,3 1,7 >2.0 >2.0 >00 >100 >[00 >100 22 21 28 E. Pd. Mdelhn - EPM 1 810,5 13,8 15,8 14,6 17,5 0,2 >2 0 '2.0 >20 >100 56 >100 100 26 26 22 19 E. E del Pacioo * EPSA 863,5 9,5 15.3 18,6 24.7 0,5 1,1 1,3 >20 '100 46 >200 >100 35 37 32 23 C. H de Betaran - CHB 776.2 8,0 16.9 18,6 21,7 1,9 >20 >2.0 >2.0 not applicable 26 5 2 0 CORELCA 647,7 12,2 (9,6) 7.3 9.2 2,2 0,7 0,9 1,2 >100 -71 -25 50 44 56 55 50 SMALL, SOLVENT, AND PROFITABLE _ 0_ C.H delCaldas-CHEC 292,3 5,4 7,3 9,8 10,7 >20 '20 '20 '2.0 55 '100 >100 >100 18 25 27 24 E. de Santander - ESSA 170,5 1,9 10,4 26,6 20,7 1,9 '20 '20 '2.0 >100 78 >100 >200 24 28 26 23 E. delAtlantico 170,0 (2,8) B,2 15.3 13,1 0,1 2,2 1,2 1, -284 51 90 89 67 56 41 27 E. del Tolorme 228, (6,8) 13.4 23,5 30,5 0,4 1,8 >2.0 '20 -163 >100 >100 >200 72 53 38 28 C.E. Norte Santander- CENS 82,1 7,4 28,9 45,3 46,5 >20 >2 0 >2.0 >2.0 33 >100 >100 >100 39 32 30 25 E. del Hmnla (1) 45,1 (4,5) 8,5 22,6 25.6 1,9 0,8 '20 -24 37 77 '100 44 46 36 24 E.E de Cundirnara - EEC 40,4 (4,9) 1.0 22,7 37,0 1.1 1,9 2,0 >2.0 0 66 >100 >100 62 77 78 70 E. P. de Pera - EPP 37,7 22,0 21,5 12,4 12.0 1,8 >2 0 1,4 0.9 89 33 43 56 31 36 34 21 E. del Meta,1) 22, 29.6 37,1 35.2 36,9 >2.0 >20 '2.0 >2.0 >100 '100 >100 >100 48 42 33 25 EdelMagdalena(1) 24,6 8,1 32,7 41,0 41,7 1,4 2,7 2,1 >20 21 '100 >100 >]00 73 60 42 31 E. del Quindio - EDEQ 23.9 7,6 18,6 25,0 24,7 >2 0 >2 0 2,0 >2 0 0 64 >100 >100 29 40 30 20 E del Cear (1) 18,3 (19,1) 11,2 26,0 28,0 0,0 >2.0 >20 1,8 -134 >100 >100 >100 86 76 71 71 E delaGuajira(1) 9,5 3,4 25,8 34,0 32,0 >2.0 >20 >20 >2.0 119 >200 >100 >100 23 31 30 24 SMALL UNDER FINANCIAL RECOVERY 490,2 E E Antoquea- EADE(1) 186,6 0,2 (0,7) 15,3 15.9 2,3 0,3 0,8 0,9 27 28 11 9 28 63 58 45 E deBoyaa - EBSA 261.3 15.4 3,0 15,6 27,5 >2 0 0,2 1.3 >20 101 -52 96 >100 19 30 25 20 EMCALI (1) 123,1 27,1 5,6 16,7 20, >20 0,8 0.9 0,7 51 -19 67 56 60 74 66 5D E deSucre (1) 12,7 10,8 16.9 19,6 20,0 0,8 0,7 0,8 0,9 -19 -12 27 89 76 58 37 E del Caqeta (1) 6,5 (14,3) 0,6 33.2 38,3 0,0 0,5 1,0 '2.0 0 -39 >100 >100 36 32 39 26 SMALL, INSOLVENT. AND UNPROFITABLE 267,4 CEDELCA 104,0 (5,9) 4,5 7,1 7.1 0,0 1,3 1,1 0,9 -47 13 10 -17 40 42 41 37 E de BoIor 73,7 0,9 (2,0) 4,5 4,3 0,5 0,4 0,6 0.0 -911 -46 -99 <200 46 68 73 95 E deNanflo 62,7 (5,0) 0,6 7,7 7,2 0,2 0.6 0,8 0,7 -28 -18 -25 -69 87 90 89 87 E deCo>dt. 15,7 (33,1) (6.9) 21.3 25.0 0.0 0,7 0,8 >20 0 -42 27 >100 96 124 112 97 E del (ho(1) 7,7 (8,1) (1,8) 9,6 8,6 0,5 0,9 1,0 1,2 -8 -0 22 23 93 95 103 112 E deMaganpue(I) 3,6 11,2 (3,4) 3,3 6.2 >20 0,0 0,2 0,2 529 '100 <100 <100 63 84 >103 >100 16. National Budget Appropriations. The financial vulnerability of weak distribution companies is expected to persist as long as (a) the policy of subsidizing low income users is maintained and (b) their market structure in terms of residential/commercial/industrial users does not change. Therefore, they can be expected to require continued Government support. For 1995, the budgeted support for the sector amounts to Col$60 billion (US$70 million). - 79 - 7. The issue consists of determining the appropriate amount of Government subsidy which is required by these companies; it can be examined under two alternative approaches: * By quantifying subsidies (positive or negative) as the difference between prices and LRMC and by calculating the net subsidies li Ohe sector and for each company; of * By recognizing that equating prices and LRMC is a condition for efficiency but not a condition for financial equilibrium and by setting Government contributions at a level that compensates utilities according to the financial shortfall associated with residential subsidies. 18. The first approach provides an upper bound to the subsidies required by any given distribution company by comparing actual prices to the LRMC: * Under the existing tariff schedules (1995), required subsidies amount to Col$ 240 billion, and cross subsidies generate Col$ 192 billion for a net requirement of Col$ 48 billion (US$176 million); * Under the planned targeted subsidies, there would be a gross requirement of ColS 47 billion and cross-subsidies of Col$ 60 billion for a net excess of Col$ 13 billion (US$15 million). Consequently, under planned tariff adjustments, overall cross-subsidies are expected to exceed subsidies to lower income users. However the net position is positive for only six out of 29 distribution companies; as a consequence, 23 companies would still require support amounting to Col $ 47 billion (US$56 million). The financial subsidy required from Government once prices reach the level targeted by the regulatory commission is relatively modest and will amount to less than 5% of the sector's revenues. 19. The second approach recognizes that equating prices and LRMC is neither a necessary nor a sufficient condition of financial equilibrium; the existing average tariff level, on the order of 90% of LRMC, can generate sufficient funds for distribution companies to operate adequately, particularly when facing decreasing returns to scale. 20. Furthermore, many of the problems faced by the distribution utilities also originate in weak management; in this sense, the most pressing problem consists of controlling losses which amount to around 20% of generation. It is estimated that at least 10% correspond to unbilled consumption and reducing them should increase revenues significantly. 21. Sensitivity Analysis. The following scenarios were assumed: (a) An increase of 3 and I percentage points in local and external inflation respectively, over the level of the base case. There is no appreciable effect in sector finance, due to the following factors: (i) revenues and most of the expenses are adjusted with inflation; (ii) external inflation has only an effect on large companies, whose investment programs have a foreign component, and who have the capacity - 80 - to obtain new loans; (iii) smaller companies who only have distribution investments in local currency exhibit cash surpluses under this scenario; (b) Local inflation identical to that used in the base case, and external inflation according to the Bank's OP 6.50 Annex B 1 (October, 1994) (annual inflation increases of 1.5% in 1995, 1.8% in 1996, 2.6% in 1997, 2.5% in 1998-2001, 2.4% in 2002, and 2.1% in 2003). This scenario shows a decrease of about US$100 million in investment requirements due to the reduction of the foreign component of the investment program of large power utilities. D. Assumptions For Power Sector Financial Projections General 22. Financial projections for the period 1994-2003 have been prepared by FEN in current prices and are expressed in US$ million. Expected inflation and exchange rates are detailed in the following table: Table 8.8: Financial Projection Assumptions 1994 1995 1996 1997 1998-2003 Local inflation (%) 22.0 18.0 15.0 12. 10.0 External inflation (%) 5.5 3.8 3.5 3.5 3.5 Average exchange rate 814 876 979 1072 1150 in 1998, (Col $/US$) maintaining parity thereafter Exchange rate at the end 825 927 1030 1115 1185 in 1998, of the year (Col $/US$) maintaining parity thereafter - 81 - 23. The forecast was based on the following main assumptions: Item Assumption Energy Sales Energy sales are based on the demand projections used in the Preference Generation and Transmission Expansion Plan of 1995. It considered an average 6.1% sales growth during the period, assuming a reduction of power losses from 23% in 1994 to 19% in 2000 over net power generation. Power Sector The power revenues of each utility are based on existing tariffs in 1993. Tariff Tariffs projected for the period were increased in accordance with the resolutions issued by JNT and ERC for 1994 and maintained constant in real terms. For 1995, sector tariff increases were set at 18% according to resolution #057 of December 1994, and take into account the policy set in the Pacto Social implemented by the current Government. Total increases in real terms during 1996-2000 for the four largest distribution companies in the sector were assumed as: EEB (2.3%), EPM (13%), EMCALI (7.9%) and Electrificadora del AtlAntico (-2.8%); increases for the remaining distribution companies ranged between 10% and 20% with the exception of Magdalena (-6%) and CaquetA (57%). Energy Transmission tariffs are based on the ERC's resolution #001 and #004 of Purchased by December 1994, which sets wheeling charges applied to distributors. the Distribution These tariffs were maintained constant in real terms during the period. Utilities The tariff to be paid to the generators is based on ERC's resolutions #010 to #030, and was set as the average tariff paid the distributors less toll tariff. Investment New generation is assumed to be installed by the private sector. Current Program investment in generation only includes the completion of existing projects. - 82 - ANNEX 9 COLOMBIA POWER MARKET DEVELOPMENT PROJECT ISA's ORGANIZATION CHART General Manager Geea Secretary S[ ectorial Services Internal Audit 1- - Communications _ Telecommunications National Center of Transmission Administrative Financial Management Environmental Dispatch Management Management Management 83 ANNEX 10 COLOMBIA POWER MARKET DEVELOPMENT PROJECT PROJECT DESCRIPTION, COSTS AND IMPLEMENTATION PLAN A. Purpose 1. This Annex contains the Project Implementation Plan (PIP). The PIP details the project management and implementation arrangements, and is referenced in the loan documents. The PIP addresses the principal features of the project: scope and objectives, costs, implementation arrangements, implementation schedule and procurement and disbursement schedules. The PIP will be the basic reference for ISA's management for measuring progress and success in project implementation. The PIP will also provide the reference benchmarks for Bank supervision of the project's components. 2. Given the large number of components of the Project, the PIP is a summary of a more detailed document prepared by ISA and the Bank during project appraisal which is available in the project file (3 Project Implementation Plan, Spanish Version). This document details the above features for each of the sub-components of the Project and would be used for reference as appropriate, during project implementation. B. Project Objectives and Description 3. The project's overall objective is to support power sector reform by facilitating the operation of a competitive bulk supply market for electricity. Specifically, the project seeks to lift transmission constraints that hinder an open access of publicly as well as privately owned power generators to the grid and to support ISA in its role as transmission network operator, system generation dispatcher and commercial transactions coordinator. The project will be a key component of the comprehensive power sector restructuring that is being put in place with Bank assistance. 4. The project consists of three components: PART A: Energy Control Center (ECC) and Financial Settlement Center (FSC). 5. This component includes the upgrading of the data acquisition and control functions of ISA's existing ECC and the installation of a FSC. The project will finance the purchase of measurement, data acquisition, telecommunications, data processing equipment and software. 84 PART B: Expansion of the Interconnected Transmission System. 6. This component includes investments to strengthen and expand the national transmission system; the following is a summarized list of major elements: (i) San Carlos-San Marcos System. (a) construction of a single circuit, 384 kin, 500 kV transmission line interconnecting the East Antioquia hydroelectric complex to the Valle del Cauca Department; (b) construction of a single circuit, 30 km, 230 kV transmission line interconnecting the La Virginia and La Hermosa substations; (c) expansion of the San Marcos 500/230 kV substation; (d) construction of the La Virginia 500/230 kV substation; and (e) construction of the San Carlos 500/230 kV substation. (ii) Atlantic Coast System: (a) reactive compensation for the Chinu substation; (b) expansion of the Cerromatoso 500/230 kV substation; (c) construction of the Uraba 230/115 kV substation; (d) construction of the double circuit, 80 km, 230 kV La Loma- El Copey transmission line; (e) expansion of the 500/115 kV Chinua substation; (f) expansion of the 500/230 kV Sabanalarga substation. (iii) Other Transmission Components: (a) reactive compensation for the Cailo Lim6n substation; (b) construction of the single circuit, 160 km, 230 kV transmission line between Paipa and Bucaramanga; (c) construction of the Paipa 230 kV substation; (d) construction of the Bucaramanga 230 kV substation; and (e) construction of a link between the San Felipe substation and the 230 kV Esmeralda-La Mesa transmission line; PART C: Technical Assistance: 7. This part includes the provision of consulting services and training programs to assist ISA in the strengthening of its capabilities to assume its roles of: (i) transmission network operator, (ii) power dispatch coordinator and (iii) bulk electricity transaction clearing house. These activities will be agreed upon between ISA and the Bank subject to an annual plan to be approved by the Bank. An initial list of studies and training activities for the first year of execution is presented below: Studies: (a) Final design and technical specification for computing and data acquisition systems and the corresponding software for the ECC and the FSC; (b) Determination and specification of methods to transmit data collected by remote meters to the ECC and the FSC; 85 (c) Identification of the characteristics of transmission power losses in ISA's network and specification of mechanisms for loss monitoring and control; (d) Review and update of ISA's power substation design manual; (e) Development of methodology for technical and economical assessment of width of corridors for transmission lines; (f) Standardization of steel structures for single circuit 230 kV lines; (g) Development of a comprehensive quality control data acquisition system; (h) Evaluation of telecommunications infrastructure and equipment needs for power transmission projects; (i) Development and acquisition of computer software to prepare construction budgets for power substations; (j) Feasibility study of the application of synchronized operation of circuit breakers on ISA substations; (k) Review of power transformer technical specifications used by ISA; (1) Methodology for load curve forecast. Subjects for Training: (a) Operation of the interconnected power system, and recording and settlement of financial transactions among users of the power pool; (b) Power system planning; (c) Telecommunications; (d) Environmental impact assessment and monitoring of power transmission lines; (e) Marketing; (f) Power transmission contract negotiation. C. Project Cost 8. Two different sets of project costs were developed during appraisal: one, in accordance to Bank rules for presentation in SARs, the other based on ISA's accounting practices for easy follow up of the project execution. The differences are in the treatment of the foreign cost component, and the assumptions for estimating physical and price contingencies. 86 9. Cost Estimate in Accordance with Bank Rules. This cost estimate for the project is summarized in Table 1, and is identical to the one included in the main text of this report. The project's total cost including taxes, duties, physical contingencies, price contingencies and interest during construction is estimated at US$ 410.0 million, of which US$ 249.3 million (60%) corresponds to direct plus indirect foreign costs and US$ 170.1 million (40%) corresponds to local costs. Taxes and import duties are estimated at US$43.9 million. Cost estimates are in December 1994 prices. 10. Costs are based on ISA's estimates, which have been reviewed by the Bank and found acceptable. ISA maintains a database of transmission and substation costs with similar characteristics to those of the project; it was updated during project preparation on the basis of recent international bids for similar projects. Physical contingencies, which amount on average to 12%, were estimated based upon the type of project and the status of its design. Price contingencies assume: (a) a project execution period of six years based on the 1994 Bank standard disbursement schedule for power projects in LAC, and (b) escalation rates over and above base cost plus physical contingencies of 2.6% for 1995-2001. 87 TABLE 1 COLOMBIA - POWER MARKET DEVELOPMENT PROJECT COST ESTIMATE (US$ thousand; price level end 1994) SUBTOTAL TOTAL FC LC PART A: Energy Control Center and Financial Settlement Center 1. Engineering and Administration 6,323 2,380 8,703 1.1 Engineering 6,323 2,061 8,384 1.2 Administration 0 319 319 2. Direct Construction Cost 10,096 1,686 11,782 Subtotal 16,419 4,066 20,485 3. Physical Contingencies 2,463 610 3,073 SUBTOTAL PART A 18,882 4,676 23,558 PART B: Expansion of the Interconnected Transmission System I. Engineering and Administration 530 21,204 21,734 1.1 Engineering 530 14,887 15,417 1.2 Administration 0 6,317 6,317 2. Direct Construction Cost 153,370 94,502 247,872 2.1 Land Purchase 0 6,507 6,507 2.2 Lines and Substations Construction 153,370 87,995 241,365 Subtotal 153,900 115,706 269,606 3. Physical Contingencies 23,085 17,356 40,441 SUBTOTAL PART B 176,985 133,062 310,047 PART C: Technical Assistance to ISA 1. Technical Assistance 1,927 1,021 2,948 1.1 Studies 964 443 1,407 1.2 Training 964 578 1,542 Subtotal 1,927 1,021 2,948 3. Physical Contingencies 289 153 442 SUBTOTAL PART C 2,216 1,175 3,391 Total A+B+C 1. Engineering, Administration and Technical Assistance 8,780 24,606 33,386 2. Direct Construction Cost 163,466 96,188 259,654 Subtotal 172,246 120,794 293,040 3. Physical Contingencies 25,837 18,119 43,956 SUBTOTAL A+B+C 198,083 138,913 336,996 Escalation 14,460 6,807 21,267 Subtotal (Including Escalation) 212,544 145,719 358,263 Interests During Construction 36,770 15,009 51,779 TOTAL PROJECT INCLUDING TAXES AND DUTIES 249,314 160,729 410,041 Taxes and Duties 0 43,908 43,908 TOTAL PROJECT WITHOUT TAXES AND DUTIES 249,314 116,821 366,134 11. Project Cost Adjustment for Purposes of Supervision. For purposes of project implementation, the appraisal team and ISA worked on the basis of costs estimates which can be easily supervised and monitored during project implementation. Such data should be consistent with ISA accounting procedures, which include as foreign component only direct imports of materials, equipment and consulting and contractor services, (expenditures directly done by ISA in foreign currency), while the table presented in the SAR considers foreign component also the indirect foreign costs (the import component embodied in goods and services which are provided domestically). On the above basis, the project's total cost, including duties, taxes, price 88 contingencies and interest during construction is estimated at US$ 397.4 million, of which US$ 236.7 million corresponds to direct only foreign costs and US$ 160.7 million corresponds to local costs. Physical contingencies weighting, in average 10% has been estimated by ISA in accordance with its own internal procedures. Price contingencies assume: (a) a project execution based on ISA's detailed schedule for each one of the components of the project, and (b) escalation rates over and above base cost plus physical contingencies in accordance with guidelines provided to ISA by DNP. It was assumed that the exchange rate variations would compensate for the difference between the local and international inflation rates. Total project cost is summarized in Table 2. 89 COLOMBIA - POWER MARKET DEVELOPMENT PROJECT Table 2 - COST ESTIMATE AND BUDGET EXECUTION SCHEDULE (US$ thousand) UP TO 1994 19 95 19 96 19 97 19 98 19 99 SUBTOTAL TOTAL FC LC FC LC FC LC FC LC FC LC FC LC FC LC Part A 1. Engineering and Administration 0 702 4149 690 1817 476 0 0 0 0 0 0 5965 1868 7833 1.1 Engineering 581 4149 600 1817 386 5965 1567 7532 1.2 Administration 120 90 90 0 301 301 2. Construction Direct Costs 0 167 4879 850 4645 813 0 0 0 0 0 0 9525 1830 11355 2.2 Equipment 167 4879 850 4645 813 9525 1830 11355 Subtotal 0 869 9028 1541 6462 1289 0 0 0 0 0 0 15490 3699 19188 3. Physical Contingencies 0 13 531 93 516 90 1047 196 1243 Subtotal 0 882 9559 1634 6978 1380 0 0 0 0 0 0 16537 3895 20432 4. Price Contingencies 148 458 336 586 342 1044 826 1870 Subtotal Part A 0 1030 10017 1970 7564 1722 0 0 0 0 0 0 17581 4721 22302 VAT (Engineering) 81 84 54 0 219 219 Import Duties (Equipment) 611 581 0 1192 1192 Total Taxes 0 81 0 695 0 635 0 0 0 0 0 0 0 1412 1412 SubtotalPartAw/oTaxes 0 948 10017 1274 7564 1087 0 0 0 0 0 0 17581 3309 20890 Part B 1. Engineering and Administration 0 3552 0 4689 250 3006 250 5947 0 3617 0 992 500 21802 22302 1.1 Engineering 0 2577 0 3712 250 2056 250 4415 0 2552 0 530 500 15841 16341 1.2 Administration 0 975 0 977 0 950 0 1532 0 1065 0 462 0 5960 5960 2. Construction Direct Costs 93 785 8520 4579 21115 16789 44159 33755 59727 42861 2113 3360 135727 102128 237854 2.1 Infrastructure 0 755 0 2354 0 2759 0 271 0 0 0 0 0 6139 6139 2.2 Equipment 93 30 8512 2077 19371 7814 40426 19817 56707 30597 0 0 125108 60335 185444 2.3 Construction And Erection 0 0 7 148 1744 6216 3733 13666 3020 12264 2113 3360 10618 35654 46272 Subtotal 93 4336 8520 9267 21365 19795 44409 39701 59727 46478 2113 4351 136227 123929 260156 3. Physical Contingencies 9 116 852 567 2089 2055 4641 4116 6065 4783 317 504 13974 12141 26115 Subtotal 102 4453 9372 9834 23453 21850 49051 43817 65792 51261 2430 4855 150200 136070 286271 4. Price Contingencies 2 52 449 449 1971 1792 6096 5428 11152 8666 466 876 20136 17263 37399 Subtotal Part B I4 4505 9821 10283 25424 23642 55147 49245 76944 59927 2896 5731 170336 153333 323670 VAT(Engineering) 0 315 0 446 0 238 0 546 0 313 0 65 0 1923 1923 VAT (Civil Works) 0 0 0 3 0 121 0 256 0 239 0 7 0 626 626 VAT (Materials And Equipment) 0 13 0 660 0 3215 0 6967 0 9670 0 0 0 20525 20525 VAT (Erection) 0 0 0 0 0 2 0 130 0 260 0 299 0 691 691 Total Vat 0 328 0 1109 0 3576 0 7899 0 10482 0 371 0 23765 23765 Import Duties 0 12 0 601 0 2982 0 6244 0 8766 0 0 0 18604 18604 Total Taxes 0 340 0 1710 0 6557 0 14143 0 19248 0 371 0 42369 42369 Subtotal Part B w/o Taxes 104 4165 9821 8573 25424 17085 55147 35103 76944 40679 2896 5360 170336 110964 281301 Part C I. Technical Assistance 0 0 455 227 909 455 455 227 0 0 0 0 1818 909 2727 1.1 Studies 227 114 455 227 227 114 909 455 1364 1.2 Training 227 114 455 227 227 114 909 455 1364 Sub-Total 0 0 455 227 909 455 455 227 0 0 0 0 1818 909 2727 3. Physical Contingencies 45 23 91 45 45 23 182 91 273 Sub-Total 0 0 500 250 1000 500 500 250 0 0 0 0 2000 1000 3000 4. Price Contingencies 0 0 0 Subtotal Part C 0 0 500 250 1000 500 500 250 0 0 0 0 2000 1000 3000 VAT (Technical Assistance) 32 64 32 0 127 127 Total Taxes 0 0 0 32 0 64 0 32 0 0 0 0 0 127 127 Subtotal Part C w/o Taxes 0 0 500 218 1000 436 500 218 0 0 0 0 2000 873 2872 Total Project 1. Engineering and Administration 0 4253 4603 5606 2976 3937 705 6174 0 3617 0 992 8283 24579 32862 1.1 Engineering 0 3158 4603 4539 2976 2897 705 4642 0 2552 0 530 8283 18318 26601 1.2 Administration 0 1095 0 1067 0 1040 0 1532 0 1065 0 462 0 6261 6261 2. Direct Construction Costs 93 952 13399 5429 25760 17602 44159 33755 59727 42861 2113 3360 145251 103958 249209 2.1 Infrastructure 0 755 0 2354 0 2759 0 271 0 0 0 0 0 6139 6139 2.2 Equipment 93 197 13392 2927 24016 8627 40426 19817 56707 30597 0 0 134633 62166 196799 90 continued COLOMBIA - POWER MARKET DEVELOPMENT PROJECT Table 2 - COST ESTIMATE AND BUDGET EXECUTION SCHEDULE (US$ thousand) UP TO 1994 19 95 19 96 19 97 19 98 19 99 SUBTOTAL TOTAL FC LC FC LC FC LC FC LC FC LC FC LC FC LC 2.3 Construction and Erection 0 0 7 148 1744 o216 3733 13666 3020 12264 2113 3360 10618 35654 46272 Sub-Total 93 5205 18002 11035 28735 21539 44864 39929 59727 46478 2113 4351 153534 128537 282071 3. Physical Contingencies 9 129 1429 682 2696 2191 4687 4139 6065 4783 317 504 15203 12428 27631 Subtotal 102 5334 19431 11718 31431 23730 49551 44067 65792 51261 2430 4855 168737 140965 309702 4. Price Contingencies 2 200 907 785 2557 2134 6096 5428 11152 8666 466 876 21180 18089 39269 Total Project 104 5534 20338 12503 33988 25864 55647 49495 76944 59927 2896 5731 189917 159054 348971 Interests during Implementation 2764 155 4895 572 9472 440 15107 316 14544 185 46782 1668 48450 Total Project Financial 104 5534 23102 12658 38883 26436 65119 49935 92051 60243 17440 5916 236699 160722 397421 Required Taxes Break-down VAT Engineering 0 396 0 562 0 356 0 578 0 313 0 65 0 2270 2270 VAT Civil Works 0 0 0 3 0 121 0 256 0 239 0 7 0 626 626 VAT Materials And Equipment 0 13 0 1271 0 3796 0 6967 0 9670 0 0 0 21717 21717 VAT Erection 0 0 0 0 0 2 0 130 0 260 0 299 0 691 691 Total Vat 0 409 0 1836 0 4274 0 7931 0 10482 0 371 0 25304 25304 Import Duties 0 12 0 601 0 2982 0 6244 0 8766 0 0 0 18604 18604 Total Taxes 0 421 0 2437 0 7256 0 14175 0 19248 0 371 0 43908 43908 TotalProjectCostw/oTaxes 104 5113 23102 10221 38883 19180 65119 35761 92051 40995 17440 5545 236699 116814 353513 D. Financing On the basis of Table 1, total required financing is estimated at US$ 410.0 million. A Bank loan of US$ 249.3 million is proposed to cover the foreign currency component. Local financing, amounting at US$ 160.7 million, would be provided by ISA's own cash generation (see Financial Analysis). Financing Plan (US$ million) LC FC TOTAL IBRD 0 249.3 249.3 ISA 160.7 0 160.7 TOTAL 160.7 249.3 410.0 E. Implementation Arrangements 12. The project will be implemented by ISA. ISA has long experience and has performed well in implementing Bank financed projects. Implementation of the project would be the responsibility of a Project Executing Unit (PEU) under the Transmission Directorate. The PEU is well staffed with experienced professionals and has enough resources and autonomy to seek consultant support whenever this is needed. The Project Execution Unit has successfully carried out several projects financed by loans from the Bank and IDB and has proven good implementation capabilities. 13. ISA will require support from specialized consultants for developing specific tasks, as follows: Part A of the Project: ISA has procured and will finance with its own resources the 91 participation of a specialized consulting firm for completing the feasibility study and the preparation of bidding documents for the implementation of the ECC and the FSC. Part B of the Project: ISA will procure, in accordance with the procurement schedule, several contracts for design and supervision during construction for lines and substations to be implemented under this component. Most of consultant contracts will be locally procured and financed with ISA's own funds. Part C of the Project. Under the TA component of the Project, ISA will contract under procedures acceptable to the Bank and with bank financing several consultant contracts as indicated in the procurement schedule. 14. The PEU's specific activities covers the following: * preparation of terms of reference, solicitation of proposals, contractual arrangements and supervision of consultant work for studies, design and inspection of works (manufacturer's tests for equipment and supervision of construction and erection of lines and substations), * preparation and solicitation of bids for procurement of equipment and materials, * preparation and solicitation of proposals for construction of civil works and for the erection of electromechanical equipment, * organization and procurement of certification of acceptance tests and commissioning, * follow up of Project budget and management of disbursement applications, * internal reporting to ISA's management and to ISA's internal audit system, * follow up of implementation of environmental programs, * external reporting (1DB, IBRD, FEN, MME, others). 15. The PEU is organized along functional groups as shown in Schedule 1. F. Implementation Schedule 16. In accordance with the aggregate schedule of the various components of the project, execution is expected to be completed by the end 1999. ISA's official execution schedule is presented in Schedule 2. 17. Procurement arrangements for the proposed project are summarized in Table 2 2 Purchase of goods and equipment and contracting of construction works to be financed with ISA is exempted from application of Law 80, which regulates contracts involving public entities, in respect to all aspects of Project execution, including procurement. (See Annex 1, Electricity Law.) 92 proceeds of the loan would be carried out in accordance with the Bank procurement guidelines, Bank Guidelines for Procurement under IBRD Loans and IDA Credits (January 1995). Purchases of goods and equipment for transmission lines and substations for a total of US$129.0 million would be procured under International Competitive Bidding (ICB). Computers and other electronic equipment for implementing the ECC and FSC for a total amount of US$ 12.3 million would be procured through Limited International Bidding (LEB) because there is only a limited number of potential suppliers. Works for construction of transmission lines and substations for a total of US$31.0 would be procured under ICB. Equipment and installation services for substations and transmission lines for a total amount of US$50.0 million would be procured under ICB. Procurement of consultant services for a total amount of US$5.0 million will be carried out in accordance with the Bank Guidelines for the Use of Consultants (August 1981). An aggregate amount of US$1.0 million would be used to reimburse foreign expenditures incurred by ISA in its training abroad of ISA staff, such as tuition fees and travel expenses for attending courses and seminars. Bank issued standard bidding documents would be used for all procurement of goods and works. For complex time-based consulting assignments Bank issued standard form of contract for consulting services will be used. To expedite procurement, an initial list of procurement packages was agreed with ISA and is presented as Attachment 3 (Procurement Schedule). Procurement packages under ICB arrangements would be about 30 with an average cost of about US$ 7.4 million, a minimum cost of US$ 1.0 million and a maximum cost of about US$ 38 million. There would also be about 50 locally procured packages not financed by the Bank with an average cost of about US$500,000; these packages are not likely to attract foreign bidders and local procurement is considered to be the most efficient procedure. Goods and services not financed with proceeds of the loan would be procured locally under ISA's established procurement practices, which have been reviewed by the Bank and found to be satisfactory. 93 Table 2: Procurement Arrangements (US$ million) A. Procurement ICB(2' NCB OTHER NBF6o TOTAL Method' Equipment 129.0 12.3 50.0 191.3 (113.6) (10.0) (123.6) Works 31.6 12.5 43.4 (25.0) (25.0) Equipment and 50.0 34.6 84.5 installation (43.0) (43.0) Consultant services 28.6 8.4 37.0 (5.0) (5.0) Training courses 1.9 1.9 (1.0) (1.0) Total 210.0 42.8 105.4 358.3 (181.6) (16.0) (197.5) m Figures in parentheses are amounts financed by the proposed Bank Loan, including contingencies. Table does not include US$ 51.8 million of interest during construction. () Goods and services to be procured by International Competitive Bidding in accordance with Bank guidelines (3Limited International Bidding * Contracting of Consultants in accordance to Bank guidelines. <5 Training: reimbursement of foreign currency expenses. (6Not Bank financed. To be procured locally under ISA's established procurement practices. 18. Prior Review. All contracts for goods and works under ICB and all contracts related to training (other than consultant services) equal or exceeding US$ 300,000 would be subject to the Bank's prior review. The provisions of the Consultant Guidelines requiring prior Bank review or approval of budgets, short lists, selection procedures, letters of invitation, proposals, evaluation reports and contracts, shall not apply to: (a) contracts for the employment of consulting firms estimated to cost less than US$100,000 equivalent each; or (b) contracts for the employment of individuals estimated to cost less than US$50,000 equivalent each. However, said exceptions to prior Bank review shall not apply to: (a) the terms of reference for such contracts; (b) single- source selection of consulting firms; (c) assignments of a critical nature, as reasonably determined by the Bank; (d) amendments to contracts for the employment of consulting firms raising the contract value to US$100,000 equivalent or above; or (e) amendments to contracts for the employment of individual consultants raising the contract value to US$50,000 equivalent or above. Contracts subject to prior review would cover about 85% of Bank financed goods and services. The balance of contracts would be subject to ex-post review by the Bank after contracts are awarded. When evaluating bids for goods, qualified domestic manufacturers would be eligible for a 15% margin of preference, or the import duty, whichever is lower. 94 19. Disbursements. ISA expects to substantially complete project implementation in four years, but the disbursements period should extend to six years. ISA expects to complete project implementation in four years. However, under the 1994 standard disbursement profile for power projects implemented in the LAC region, the loans would be disbursed over a seven years period. The disbursement schedule is attached in Annex 10. Proceeds from the loans would be applied to finance following estimated amounts of project expenditures: (a) 90% of expenditures for works (US $25.0 million); (b) 100% of foreign expenditures and 90% of local expenditures (ex-factory cost) for the purchase of goods (US$ 10.0 million for part A of the Project and US$ 103.6 million for parts B and C of the Project); (c) 95% of expenditures for contracts for the supply of equipment and installation thereof (US$ 43.0 million); (d) 100% of foreign expenditures for consultant services (US$ 0.5 million for part A of the Project and US$ 4.5 million for parts B and C of the Project); (e) 100% of foreign expenditures for training of ISA staff abroad and training fees (US$ 1.0 million); and (f) interest and other charges under the Bank loan, (US$ 36.8 million); (g) unallocated expenditures (US$ 24.9 million). 20. Disbursements against statement of expenses (SOE) will be made in respect of training service contracts costing less than US$ 300,000 and for consultant services not subject to prior review. Retroactive financing of up to US$ 10 million for eligible expenditures (made after March 31, 1995, but no more than 12 months before signing) would be provided for under each loan. Eligible expenditures would have to follow procurement procedures acceptable to the Bank. The Project is expected to be substantially completed by 2001 with a closing date of December 31, 2002. 21. The Borrower would establish for each loan Special Accounts in US dollars with a commercial bank acceptable to the Bank to cover eligible Bank expenditures under the loan. The authorized allocation to the Special Accounts would be US$8 million for each loan. However, they should not exceed US$4 million during the start-up of the project. The balance could be requested when the total amount disbursed from each loan account plus outstanding commitments has reached US$20 million. Subsequent replenishment by the Bank into the Special Accounts would follow the procedures by which Bank funds are disbursed against actual expenditures. 22. Disbursements from the loan, in accordance with LAC's standard profile would be as follow: 95 Estimated Disbursements (Bank FY) (US $ million) Calendar Year 1996 1997 1998 1999 2000 2001 Annual 14.9 39.9 69.8 69.9 49.8 5.0 Cumulative 14.9 54.8 124.6 194.5 244.3 249.3 Schedule 1 - 96 - Project Execution Unit Organization chart General Manage Auditor General Secretary (LEGAL) Financial Environmental Manager Manager Distpatch Administration ....... ....... Manager Manager Transmission Manager Support Coordination Project Implementation Unit Director Secretary Project Adviser Natinal Dispatch Engineering La Loma Cerro-Uraba Oriente Valle Center Department Project Project Project Project ANNEX 10 - ATTACHMENT 2 9/11/95 COLOMBIA - POWER MARKET DEVELOPMENT PROJECT EXECUTION SCHEDULE 1993 1994 1995 1996 1997 1998 1099 Code Ach"ty Q1 Q2 Q3 Q4 Ql Q2 Q3 Q4 QQ Q2 Q3 Q4 QI Q Q 1 Q2 Q3 Q4 I Q2 Q3 Q4 Q1i Q2 Q3 Q4 I PART A t_ _ 2 ENERGY CONTROL CENT. AND FINANCIAL SETTL. CENT. 3 CONSULTANT WORKS 4 Conttract-u AntingeCI,ews Execution of Studies 6 IMPLEMENTATION OF PHYSICAL FACILITIES 7 Procurement 8 SCADAIAGC System 9 Applhcations Development 10 DATA ACQUISITION SYSTEM II Procurement 12 Manufacturung and Delvenng 13 Tests and Como,sonu,g 14 NETWORK ANALYSIS SOFTWARE 15 Defiwton of Reqormementu 16 Plan Prepurhon 17 Plan Iplcunent.tuon 18 FINANCIALSETTLEMENI CENTER 19 Requirements Deflmnon- 20 Accouiting Admnsration System 21 Telemettng Systems 1 Dw Disk@LA31N@WORLDBANK\JAYME\COPMARKT\GREEN\EXE1SCHE MPP 汗 ANNEX 10 - ATTACHMENT 2 9111m COLOMBIA - POWER MARKET DEVELOPMENT PROJECT EXECUTION SCHEDULE 1993 19,1 1997 99 1999 _ým, Ad-fy I Q2 Q3 Q4 ol Q2 1 (."3 93 Q4 QI Q2 Q3 Q4 43 LINFL4 I.O.NIA Fl. CUPEV 44 45 ýd Eq,.pent C -d Tests '16 -S 1 -1,0 N LA LØNIA Y EL COFEY A8 --K.n 9 A~.t.. f ..terial -d Eq.pm,.t 50 51 KFAcIný 52 k,,gn 53 A~m,, f M.t"w -d Eq.Pent 54 Erech.. -d T"t. 55 Exrk.NSIONOFSIUSSTATIONCHINU 57 Acq-t- ofmt.,J &M E~ nt E,e,tim md Tests 59 SI "STAI I(IN SABANALARGA 10 61 A,q~. fýiý.Wmdeq.p~ 62 C-buctim, ElectIon "Tests L3 IIISC.LLXNEØUSWORKS 3 Drv Disk@LA3IN@WORLDBANKUf. YMEMPMARKT\GREEMEXE1SCHE MPP ANNEX 10 - ATTACHMENT 2 9/11/95 COLOMBIA - POWER MARKET DEVELOPMENT PROJECT EXECUTION SCHEDULE 993 1994 -995 1996 1997 999g 9 9 r-ak ActQry Q Q2 Q4 A 2 94Q1 Q21Q3 Q4 Q2 Q3 04 Q Q3 Q4 QI Q2 Q3 Q4 Q] Q2 Q3 Q1 64 RFACTIVE OIPENSAFION SUESTATION CA.NO LIMON - - _ LDesign ---- - - 66 A~ 1on of matenalandEqupment C trucon, Ere,on and Tests 69 LINEPAMPk BUCARAMIANGA - _ __ -- 69 Des gn 1 II V 1 70 A 01.a.alrmaleIal and eqLup ent 7 - ni -n, ecCn and Gcs1 73 Desig -- -- - 74 Acqmsrataon of Matenal and eqwpment 11 75 (-onstrucIon, Erecion and Test1 1 ~J 1___1__ 76 INTIL CONNFT ION S [S FATIO SAN FFLII -- - --- 77 Desugn._-- --- - 78 Acqrunbon of Matnal and Eq,pmn-t 79 Constmchon, Erechon and Testa 80 PART C at TECILNICAL. SISTANCE R2 mF ådeg, for he ECC & he FSC - 93 Metlids 0o umnsni data to ECC ad FSC 84 Ddeuficano BofAthe chaUactensucs of tbansmmEpow osses m ISA 4 Div Disk@LA3IN@WORLDBANK\JA YME\COPMARKJT\GREEN\EXE1SCHE MPP t~ ANNEX 10 -ATTACHMENT 2 9/11/95 COLOMBIA - POWER MARKET DEVELOPMENT PROJECT EXECUTION SCHEDULE 1"3 1994 1995 1996 pay a99 Code -Actnvity Q1 Q2 03 04 Q1 O2 03 04 01 O2 _2 4 Q 85 Rew and update of ISAs power ubstation desg manual Be. Widthaofpowerulnecomedor 87 Standanzation ofsterl sructwes for aiger ciarl 2M0kV knes Development ofa comprchensive quality control data vaiiio system 89 Evaluam Dficreammurucalbuns needs for "cwr tranmissmo projet 90 Power tons constrcton budget saltwae 91 Fessaboy study otsynchronized opratin of circuir breaker; 92 Rew of power nasformer tldical spectficatio ased by ISA 93 McshdWWy fo lpad eme forgcasa C 5E 5 Div Dtsk@LA31N@WORLBANKUAYMECQ-WMTREE)ESCVk MPP Schedule 3 - 102 - Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total PART A ECC Consultant Technology Update 385 756 1141 385 756 1141 (International) Shopping 385 756 1141 World Bank 385 385 ISA 756 756 Purchase Of Rtus, Expansion Of Ecc 1961 343 2304 1961 343 2304 Coverage (International) Competitive Bidding 1961 343 2304 World Bank 1498 1498 ISA 463 343 806 Restructuring Of Ecc Information Network 191 33 224 191 33 224 (International) Shopping 191 33 224 World Bank 146 146 ISA 45 33 78 Update Of Scada / Agc /Ems System 12359 2572 14931 12359 2572 14931 (International) Competitive Bidding 12359 2572 14931 World Bank 7701 7701 ISA 4658 2572 7230 Financial Settlement Center 150 191 341 150 191 341 (National) Shopping 150 191 341 World Bank 119 119 ISA 31 191 222 Methodology, Training And Assistance 1491 0 1491 1491 0 1491 (International) Shopping 1491 1491 World Bank 969 969 ISA 522 522 Total Procedures 16537 3895 20432 16537 3895 20432 World Bank 10818 0 10818 ISA 5719 3895 9614 Indexing 1044 827 1871 1044 827 1871 World Bank 0 ISA 1044 827 1871 Total 17581 4722 22303 17581 4722 22303 World Bank 10818 0 10818 ISA 6763 4722 11485 World Bank 0 0 0 ISA 0 0 0 PART B San Carlos - San Marcos System San Carlos - San Marcos Line TPL-501 Supply OfSan-Carlos- 13640 4911 18551 13640 4911 18551 Schedule 3 - 103 - Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total (International) San Marcos 500-kV Line Insulators, Ancillary Equipment 13640 4911 18551 World Bank 13640 682 14323 ISA 4229 4229 TPL-502 Supply Of 500-kV Line 13443 4839 18282 13443 4839 18282 (International) San Carlos - San Marcos Cables, Including Lightning Protector 13443 4839 18282 World Bank 13443 672 14115 Cable ISA 4167 4167 TPL-571 Construction And Erection Of 16497 18479 34976 16497 18478 34975 (International) San Carlos-San Marcos 500-kV Line Structures, Construction And Erection 16497 18479 34976 World Bank 16497 14837 31334 ISA 3641 3641 - Structures 11747 4229 15976 -Construction And Erection 4750 14250 19000 T-004 External Supervision 0 3315 3315 0 3315 3315 (National) San Carlos-San Marcos 500-kV Line External Supervision Of Construction And 3315 3315 ISA 3315 3315 Erection T-003 Design Of San Carlos-San Marcos 0 1790 1790 0 1790 1790 (National) 500-kV Line Design 1790 1790 ISA 1790 1790 Land And Easements Land And Easements 0 4000 4000 0 4000 4000 4000 4000 ISA 0 4000 4000 La Virginia - La Hermosa Line TPL-201 Supply And Construction Of 1585 1692 3277 1585 1692 3277 (International) La Virginia-La Hermosa Line Design, Materials Supply 1585 1692 3277 World Bank 1492 1088 2580 Construction And Erection ISA 93 604 697 T-015 External Supervision 0 201 201 0 201 201 (National) External Supervision Of Construction And 0 201 201 ISA 0 201 201 Erection 92 92 Land And Easements0 9220 Schedule 3 - 104 - Procurement Schedule (US$ thousand) Code Description FC LC I Total I Financing FC LC Total Land And Easements 921 92 ISA 1 0 921 92 San Carlos, La Virginia, San Marcos (Phase 1i) Substations TPS-202 Supply S.Marcos (Phase Ii), La Virginia 8468 5203 13671 8468 5204 13672 (International) AND SAN CARLOS 230-kV SUBSTATIONS Supply Of Equipment 7927 5203 13130 World Bank 8468 355 8823 Supervision Of Erection 541 541 ISA 4849 4849 TPS-262 Civil Engineering S. Macros (Phase li), La 0 1084 1084 0 1083 1083 (National) Virginia And San Carlos 230-kV Substations Civil Engineering, Substations: 0 1084 1084 ISA 0 1083 1083 -Construction (1) 0 87 87 -Construction (2) 0 910 910 -Construction (3) 0 87 87 TPS-282 Erection S.Marcos (Phase li), La 180 541 721 180 541 721 (International) Virginia And San Carlos 230-kV Substations Erection Of Substations: 180 541 721 World Bank 180 541 721 -Erection (1) 15 44 58 -Erection (2) 151 454 605 -Erection (3) 15 44 58 T-006 External Supervision S. Marcos (Phase Ii), 0 371 371 0 371 371 La (National) Virginia And San Carlos 230-kV Substations External Supervision Of Construction And 0 371 371 ISA 0 371 371 Erection T-005 Design And Consultancy S. Marcos (Phase 0 688 688 0 688 688 (National) li), La Virginia And San Carlos 230-kV Substations Design And Consultancy 0 688 688 ISA 0 688 688 Infrastructure 0 755 755 0 755 755 Infrastructure 755 755 ISA 0 755 755 San Carlos, La Virginia, San Marcos (Phase Ill) Susbstations TPS-502 Supply S.Marcos (Phase 111), La 26305 12958 39263 26304 12951 39262 (International) Virginia And San Carlos Substations 500 Schedule 3 - 105 - Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total kV Supply Of Equipment 24758 12958 37716 World Bank 26304 1105 27409 Supervision Of Erection 1547 1547 ISA 0 11853 11853 TPS-562 Civil Engineering S.Marcos (Phase Iii), 0 3094 3094 0 3094 3094 (National) La Virginia And San Carlos 500-kV Substations Substation Civil Engineering 0 3094 3094 ISA 0 3094 3094 -Construction (1) 0 922 922 -Construction (2) 0 1517 1517 -Construction (3) 0 655 655 TPS-582 Erection S.Marcos (Phase lii), La 514 1543 2057 514 1543 2057 (International) Virginia And San Carlos 500-kV Substations Erection Of Substations 514 1543 2057 World Bank 514 1543 2057 -Erection (1) 153 460 613 -Erection (2) 252 757 1009 -Erection (3) 109 326 435 T-014 External Supervision 0 1003 1003 0 1003 1003 (National) External Supervision Of Construction And 0 1003 1003 Recuros ISA 0 1003 1003 Erection T-005 Design And Consultancy S Marcos (Phase 0 1861 1861 0 1861 1861 Ii), (National) La Virginia And San Carlos 500-kV Susbstations Design And Consultancy 0 1861 1861 ISA 0 1861 1861 Chinu Compensation Substation TPS-504 Supply Of Substation 12657 4959 17616 12657 4959 17616 (International) Materials And Equipment 11983 4959 16942 World Bank 12657 617 13274 Supervision Of Erection 674 674 ISA 4342 4342 TPS-584 Erection Of Substation 0 896 896 0 896 896 Erection 896 896 World Bank 896 896 TPS-564 Substation Civil Engineering 0 1348 1348 0 1348 1348 (National) Construction 1348 1348 ISA 1348 1348 Schedule 3 - 106 - Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total T-010 External Supervision 0 511 511 0 511 511 (National) External Supervision 511 511 ISA 511 511 T-009 Design And Consultancy 0 1111 1111 0 1111 1111 (National) Design And Consultancy ill lill ISA 1111 1111 Cerromatoso Substation TPS-203 Supply Of Substation 5478 3043 8521 5478 3043 8521 (International) Materials And Equipment 5142 3043 8185 World Bank 5478 865 6343 Supervision Of Erection 336 336 ISA 2178 2178 (International) Erection 446 446 World Bank 446 446 TPS-263 Substation Civil Engineering 0 671 671 0 671 671 (National) Construction 671 671 ISA 671 671 T-008 External Supervision 0 248 248 0 248 248 (National) Extemal Supervision 248 248 ISA 248 248 T-007 Design And Consultancy 0 461 461 0 461 461 (National) Design And Consultancy 461 461 ISA 461 461 Uraba Substation TPS-203 Supply Of Substation 1151 757 1908 1151 757 1908 (International) Materials And Equipment 1075 757 1832 World Bank 1151 282 1433 Supervision Of Erection 76 76 ISA 475 475 TPS-283 Erection Of Substation 0 101 101 0 101 101 (International) Schedule 3 - 107 - Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total Erection 101 101 World Bank 101 101 TPS-263 Substation Civil Engineering 0 318 318 0 318 318 (National) Construction 318 318 ISA 318 318 T-008 External Supervision 0 61 61 0 61 61 (National) External Supervision 61 61 ISA 61 61 T-007 Design And Consultancy 0 113 113 0 113 113 (National) Design And Consultancy 113 113 ISA 113 113 La Loma- El Copey Line LLL-201 Cables 2303 806 3109 2303 806 3109 (International) Cables 2060 721 2781 World Bank 2303 115 2418 Lightning Protector Cable 243 85 328 ISA 691 691 LLL-202 Insulators And Accessories 977 342 1319 976 342 1318 (International) Insulators 357 125 482 World Bank 976 49 1025 Accessories 292 102 395 ISA 293 293 Accessories And Grounding Equipment 114 441 LLL-271 Structures, Construction And Erection 1964 2118 4082 1964 2118 4082 (International) Structures 1424 498 1922 World Bank 1964 1691 3655 Construction And Erection 540 1620 2160 ISA 427 427 L-001 Design And Impact Assessment 0 396 396 0 396 396 (National) El Copey - La Loma - Ocafia Line -Design And Impact Assessment 396 396 ISA 396 396 1_002 External Supervision Of Line Works 0 264 264 0 264 264 (National) -External Supervision 264 264 ISA 264 264 Schedule 3 - 108 - Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total Land And Easements 0 160 160 0 160 160 Land And Easements 160 160 ISA 0 160 160 La Loma And El Copey Substations LLS-201 Materials And Equipment 3791 2444 6235 3790 2444 6234 (International) La Loma Substation 1264 814 2078 World Bank 3790 872 4662 ISA 1572 1572 Bay Equipment 696 251 947 Structures 109 109 Miscellaneous Equipment 540 454 994 Supervision Of Erection 28 28 El Copey Substation 2527 1630 4157 Bay Equipment 1391 502 1893 Structures 219 219 Miscellaneous Equipment 1080 909 1989 Supervision Of Erection 56 56 LLS-261 Civil Engineering 265 795 1060 265 795 1060 (International) Civil Engineering La Loma Substation 88 265 353 World Bank 265 265 Civil Engineering El Copey Substation 177 530 707 ISA 795 795 LLS-281 Erection 0 254 254 0 254 254 (National) Erection Of La Loma Substation 85 85 ISA 254 254 Erection Of El Copey Substation 169 169 L-003 Design 0 323 323 0 323 323 (National) -Design Of La Loma Substation 109 109 ISA 323 323 -Design Of El Copey Substation 214 214 L,004 External Supervision 0 174 174 0 174 174 (National) I -External Supervision Of La Loma 59 59 ISA 174 174 Substation -External Supervision Of El Copey 115 115 Substation Schedule 3 - 109- Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total Infrastructure 0 72 72 0 72 72 Infrastructure 72 72 ISA 0 72 72 Expansion Of Chinu Substation Transformation Capacity CHS-501 Materials And Equipment 1895 1373 3268 1895 1373 3268 (International) -Bay Equipment 875 317 1192 ISA 1895 1373 3268 -Structures, Cables And Connection 0 720 720 Equipment -Transformers 931 336 1267 -Supervision 89 0 89 CHS-561 Civil Engineering 0 133 133 0 133 133 (National) Civil Engineering 133 133 ISA 133 133 CHS-581 Erection 0 101 101 0 101 101 (National) Erection 101 101 ISA 101 101 CD Design 0 47 47 0 47 47 (National) Design 47 47 ISA 47 47 C-001 Engineering And Consultarcy 0 25 25 0 25 25 (National) Engineering And Consultancy 25 25 ISA 25 25 C-002 Extemal Supervision 0 39 39 0 39 39 (National) External Supervision 39 39 ISA 39 39 Transformation Capacity, Sabana TPS-504 Substation Supply 4454 2713 7167 4454 2713 7167 (International) Schedule 3 -110- Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total Materials And Equipment 4169 2713 6882 World Bank 4454 289 4743 Supervision Of Erection 285 285 ISA 2424 2424 TPS-585 Substation Erection 0 379 379 0 379 379 (National) Erection 379 379 ISA 379 379 TPS-565 Civil Engineering. Substation 0 570 570 0 570 570 (National) Construction 570 570 ISA 570 570 T-012 External Supervision 0 217 217 0 217 217 (National) External Supervision 217 217 ISA 217 217 T-010 Design And Consultancy 0 404 404 0 404 404 (National) Design And Consultancy 404 404 ISA 404 404 Infrastructure 0 250 250 0 250 250 Infrastructure 250 250 ISA 0 250 250 Misc. Transmission Works Cafto Lhmon Substation TPS-204 Substation Supply 415 142 557 415 142 557 (International) Materials And Equipment 394 142 536 World Bank 415 20 435 Supervision Of Erection 21 21 ISA 122 122 TPS-284 Substation Erection 0 28 28 0 28 28 Erection 28 28 World Bank 28 28 (International) TPS-264 Civil Engineering. Substation 0 42 42 0 42 42 (National) Construction 42 42 ISA 42 42 T-010 External Supervision 0 16 16 0 16 16 Schedule 3 - 111 - Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total (National) External Supervision 16 16 ISA 16 16 T-009 Design And Consultancy 0 30 30 0 30 30 (National) Design And Consultancy 30 30 ISA 30 30 Palpa - Bucaramanga Line P68-L210 Structures, Construction And Erection 3638 3451 7089 3638 3451 7089 (International) -Structures 2318 811 3129 World Bank 3638 2756 6394 -Construction And Erection 1320 2640 3960 ISA 695 695 P68-L220 Cables, Including Lightning Protector 2619 917 3536 2619 917 3536 Cable (International) -Cables, Including Lightning Protector 2619 917 3536 World Bank 2619 131 2750 Cable ISA 786 786 P68-L230 Insulators And Accessories 1210 423 1633 1210 423 1633 (International) - Insulators And Accessories 1210 423 1633 World Bank 1210 60 1270 ISA 363 363 P68-Ll21 External Supervision 0 558 558 0 558 558 (National) External Supervision 558 558 ISA 558 558 P68-L120 Design And Consultancy 0 300 300 0 300 300 (National) Design And Consultancy 300 300 ISA 300 300 Land And Easements 0 360 360 0 360 360 Land And Easements 360 360 ISA 0 360 360 Palpa And Bucaramanga 230-kV Substations P68-L310 Supply Of Paipa And Bucaramanga 7413 4233 11646 7413 4233 11646 Schedule 3 -112- Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total Substations (International) Paipa Substation Bay Equipment 2435 879 3314 World Bank 1253 37 1290 Paipa Substation Misc. Equipment 1889 1590 3479 ISA 6160 4196 10356 Buacaramanga Substation Bay Equipment 1739 628 2367 Bucaramanga Substation Misc. Equipment 1350 1136 2486 P68-L350 Erection Of Paipa And Bucaramanga 0 677 677 0 677 677 Substations (National) Erection Of Paipa Substation 395 395 ISA 677 677 Erection Of Bucaramanga Substation 282 282 P68-L410 Communications 1300 1450 2750 1300 1451 2751 (International) Communications Equipment 1300 1450 2750 World Bank 1300 1300 ISA 1451 1451 P68-1340 Supply Of Paipa And Bucaramanga 0 657 657 0 657 657 Substations (National) Paipa Substation Structures 383 383 ISA 657 657 Bucaramanga Substation Structures 274 274 P68-L360 Paipa And Bucaramanga Substations Civil 0 2120 2120 0 2120 2120 Engineering (National) Paipa Substation Civil Engineering 1237 1237 ISA 2120 2120 Bucaramanga Substation Civil Engineering 883 883 P68-LI31 External Supervision 0 350 350 0 350 350 (National) External Supervision 350 350 ISA 350 350 P68-L130 Design And Consultancy 0 649 649 0 649 649 (National) Design And Consultancy 649 649 ISA 649 649 Schedule 3 - 113 - Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total Infrastructure 0 200 200 0 200 200 Infrastructure 200 200 ISA 0 200 200 Connection Between San Felipe Substation And La Esmeralda - La Mesa Line 1262 956 2218 1262 956 2218 TPS-205 Supply Of Substation (International) Materials And Equipment 1172 956 2128 World Bank 1262 188 1450 Supervision Of Erection 90 90 ISA 768 768 TPS-285 Substation Erection 0 119 119 0 119 119 (National) Erection 119 119 ISA 119 119 TPS-265 San Felipe Substation Civil Engineering 0 179 179 0 179 179 (National) Construction 179 179 ISA 179 179 T-020 External Supervision 0 73 73 0 73 73 (National) External Supervision 73 73 ISA 73 73 T-011 Design And Consultancy 0 136 136 0 136 136 (National) Design And Consultancy 136 136 ISA 136 136 Infrastructure 0 250 250 0 250 250 Infrastructure 250 250 ISA 0 250 250 Transportation Equipment 1500 600 2100 1500 600 2100 Transportation Equipment 1500 600 2100 World Bank 1500 1500 ISA 600 600 Computer Equipment 1500 500 2000 1500 500 2000 Schedule 3 -114- Procurement Schedule (US$ thousand) Code Description FC LC Total Financing FC LC Total Computer Equipment 1500 500 2000 World Bank 1500 1500 STUDIES ISA 500 500 500 0 500 500 0 500 Studies 500 500 World Bank 500 500 Management 5960 5960 ISA 5960 5960 Contingencies 13974 12141 26115 13973 12140 26113 World Bank 12995 3982 16977 ISA 978 8158 9136 Indexing 20136 17263 37399 20135 17264 37399 World Bank 18899 4740 23639 ISA 1236 12524 13760 Financial Costs 46782 1668 48450 46782 1668 48450 World Bank 39526 39526 ISA 7256 1668 8924 Total Procedures Part B 217815 154311 372126 217811 154311 372122 World Bank 200193 38988 239181 ISA 17618 115323 132941 Revision Part B, Erection San Marcos, La Virginia, San Carlos Substations 694 694 RevisedTotal 217121 155005 372126 217117 155005 37 2122 Total Without Financial Costs 170339 153337 323676 World Bank 199499 39682 239181 ISA 17618 115323 132941 PARTE C 2000 1000 3000 2000 1000 3000 Technical Assistance 2000 1000 3000 World Bank 2000 2000 ISA 1000 1000 115 ANNEX 11 COLOMBIA POWER MARKET DEVELOPMENT PROJECT PROJECT ECONOMIC ANALYSIS 1. The proposed project consists of three components: (a) Control Center upgrading to support the sector's new institutional structure; (b) Expansion of the interconnected system to allow ISA to accomplish its role of supporting a competitive generation-level market by allowing energy transactions between generators and suppliers to take place; and (c) Technical Assistance to ensure a good start and smooth operation of ISA in its new role. 2. The economic analysis consists of: * A cost-effectiveness analysis to verify that: (i) the project as a whole is part of the sector least cost expansion plan, and (ii) its components are the least cost alternative for accomplishing their objective; and * An economic analysis which verifies that the resources used in the proposed investments provide an acceptable economic rate of return. Cost-effectiveness Analysis 3. Expansion Plan. The Government recently approved a strategy for the 1995-2007 expansion of the power subsector'. The strategy is based on an updated expansion plan prepared by MME and ISA in February, 1995; economic growth for 1995-2010 is assumed to vary within the 5.13%-6.3% range depending on the scenario being examined, i.e. roughly within current Bank projections which are in the 5.5%-6% range; electricity demand for these years is expected to grow correspondingly at rates which range between 4.8% and 6.77% per annum. The transmission lines and substations included in the project are part of the least cost expansion plan and all components are needed in order to meet the desired reliability criteria. 4. The following analysis verifies that the proposed investments are indeed the least cost solution by comparing their costs and benefits with those of the next best alternatives. This analysis was performed for the transmission components of the project (the San Carlos- San Marcos System, and the La Loma-Copey and Paipa-Bucaramanga System) which account for the bulk of the proposed investments. The Control Center and Technical Assistance components are required for the power market to develop; without such new equipment and the requisite training, the existing dispatch center, which is based on equipment that is substantially out of date, will be unable to operate the network efficiently or to create proper financial accounting for the '"Estrategias para el Desarrollo y la Expansion del Sector Eldctrico 1995-2007", Documento CONPES 2763, 15 February 1995. 116 settlements required under the new commercial rules. For these two components of the project there does not appear to be a second-best alternative against which they can be compared. 5. From the purely technical standpoint the second-best alternative to the transmission components could consist of a different design, e.g. a lower or higher voltage for the transmission lines and a different combination of 230/500kV lines. ISA's technical analyses provide assurance that alternative designs are not economical. Furthermore, it should be noted that the expansion plan is designed within a joint generation/transmission optimization perspective, including an optimized sitting of future gas plants. 6. Adopting a more global approach, the next-best alternatives used to verify the cost- effectiveness of the project consist of studying alternatives whereby the proposed transmission reinforcements (including any design variations) are substituted by installing generating capacity to provide equivalent service. In practical terms, within the context of the generation and transmission expansion plan, this would require relocating new generating facilities. The generating facilities identified in the plan are: * 1995-2000: - 747MW repowering of gas-based plants on the Atlantic Coast (commissioned) which will add 507MW net to the system; - 232MW gas-based generation in the Southwest (commissioned) - 400MW gas-based generation in the Central region, - 1100MW hydro generation; - 450MW coal-based (150MW commissioned, 300MW on the Atlantic Coast). * 2001-2007: - 3700MW gas-based plants - 2068MW hydro plants 7. San Carlos-San Marcos System. The lines and substations included in this component are a necessary reinforcement to supply the demand for power in the Southwestern area of the country. This region is relatively energy-poor and has fewer generation resources compared to other areas; its supply is particularly vulnerable during the dry months as it lacks significant storage facilities in its hydro plants. 8. Although substantial thermal generation is planned to be located in the region (232MW in the 1995-2000 period), a second best alternative to the proposed transmission reinforcements would consist of relocating around 400MW of gas-based generation to the Southwest in the 1995-2000 period, and a further 100MW around 2001. Consequently, given the equivalence in overall capacity (and assuming that dispatch conditions are roughly similar), the least cost tradeoff consists of transporting electricity through the proposed transmission facilities or transporting gas through a gas pipeline in order to feed the relocated plant. There would be no cost differences regarding generation investments. 117 9. The cash flows associated with the project are shown in Table 11-1. They consist of * Investment Costs; * Operation and maintenance (O&M) costs of the project, estimated to be 2% of investment per year, which corresponds to ISA's previous experience with transmission facilities; * Savings due to lower losses with the project; and * Savings associated with the reduction of incremental gas transportation costs for supplying the relocated plant. 10. The savings in gas transport were based on a heat rate of 9544 Btu/kWh for the relocated plant, against 9733 Btu/kWh for the original plant (due to lower ambient temperatures prevailing in Cali). The energy delivered by the plant corresponds to the energy originally supplied by the thermal plant before relocation, with an average plant factor of 50%. The incremental transportation cost is based on the price quoted by ECOPETROL for transporting gas to the Cali area (US$2.4/MBtu) less the price for transporting gas to the original location in the central region (US$1.0/MBtu). Taking into account the efficiency difference, the incremental transportation cost is equivalent to savings on the order of US$13/MWh. 11. At a 12% discount rate, the present value of the investment and incremental operational and maintenance (O&M) costs of the proposed San Carlos-San Marcos reinforcements amounts to US$106 million. The present value of project benefits, quantified as savings due to reduced losses and reduced gas transportation costs, amounts to US$171million. Consequently the project yields a net present value of US$65 million and a Benefit/Cost (B/C) ratio of 1.6. The Equalizing Discount Rate (EDR), i.e. the discount rate that yields a B/C ratio of 1.0, amounts to 20%, which exceeds the acceptable rate of return (12%), thereby justifying the project as part of the least cost plan. 12. Regarding the timing of the San Carlos-San Marcos component, its benefits could be reduced due to lower demand in the Cali area. Under a low demand growth scenario (on the order of 4.3% p.a.), the project would yield no benefits for the first two years of operation; in this case, the EDR would decrease to 15%, which is still above the benchmark discount rate of 12%. 13. La Loma-Copey and Paipa-Bucaramanga System. The purpose of this system is to (a) connect the 300MW Cesar coal plant to the Atlantic Coast and Central Region systems and (b) to increase the transmission system reliability by creating an additional interconnection between the Atlantic Coast and Central Region systems. 14. The 300MW coal plant was decided on the basis of fuel diversification and to reduce the risk of supply shortfall. Consequently, a second best alternative in this case would consist of an equivalent coal plant (in order to preserve the fuel diversification policy dictated by existing 118 constraints on gas supply), located at a site where the proposed transmission reinforcement is no longer needed. 15. Two possible alternatives to the La Loma-Copey and Paipa-Bucaramanga System were identified: * Tasajero 11 (300MW) located in the general area served by the Paipa-Bucaramanga line; or * Tasajero 11 (150MW) and Cartagena IV (150MW), the latter being located in the Atlantic Coast region. 16. The base case comparison is shown in Table 11-4. The alternatives were analyzed by comparing the total generation and transmission costs (including fuel costs) associated with the proposed project and the second best alternatives: * Investment costs are lower for the proposed project (Cesar-Loma-Copey); * There are slightly lower fuel costs associated with the second-best alternative consisting of Tasajero 11 150MW and Cartagena IV 150MW. 17. The overall result shows a cost ratio of 1.04 whereby the second-best alternative exceeds the proposed project costs at 12% discount (the fuel savings do not compensate for the extra investment cost). The equalizing discount rate whereby the fuel savings are enough to justify the second-best alternative is over 50%. 18. Sensitivity Analysis. The previous results were subjected to the following sensitivity tests: * A: 10% increase in investment costs; * B: 10% decrease in gas transportation costs for the San Carlos-San Marcos transmission project; * C: 10% decrease in coal costs for the Loma-Copey project and its second-best alternatives; * D: discount rates of 10% and 14% 19. The sensitivity results are shown in Tables 11-2 and 11-3 (San Carlos-San Marcos) and 11-5 and 11-6 (Loma-Copey); they are summarized as follows: 119 San Carlos-San Marcos Project Sensitivity Case EDR B/C ratio Base Case 20% 1.6 +10% Investment Costs 18% 1.5 -10% Gas Transportation 18% 1.5 10% Discount Rate N.A. 1.8 14% Discount Rate N.A. 1.4 Loma-Copey and Paipa-Bucaramanga Project Sensitivity Case EDR B/C ratio Base Case >50% 1.04 +10% Investment Costs ----- 1.04 -10% Coal Costs ----- 1.04 10% Discount Rate N.A. 1.04 14% Discount Rate N.A. 1.04 The results show that the projects' cost-effectiveness characteristics are robust in relation with changes in the underlying assumptions. 20. Shifts in some of the key variables were identified which would lead to preferring the second-best alternatives to the proposed project components. For the San Carlos-San Marcos component, the transportation cost to Cali would need to decrease to around Col $1.7/MBtu for the EDR to become 12%; this would imply a 29% decrease in the gas transport cost. Similarly, a break-even fuel cost is obtained for the Loma-Copey component when fuel costs for the Cesar coal plant increase by 35%. Economic Analysis 21. The economic analysis consists of evaluating the rate of return for ISA's overall investment plan. Although most of the components for the Third Transmission Plan are part of the Bank-financed project, the analysis includes a small number of additional investments which are not part of the project. 22. Costs consist of the investment costs for the 1994-99 period, together with O&M costs associated with these investments until year 2022. Benefits are calculated by comparing the operating conditions with and without the proposed investment program: * Without the program, demand growth leads to a progressive saturation of ISA's network at which point demand and operating conditions are kept constant; 120 * With the program, additional energy and capacity are delivered through the network until network saturation occurs, at which point demand and operating conditions are again kept constant. 23. The benefits attributable to the investment program are then valued as follows * The difference in operating costs with and without the program are benefits attributable to the lower cost dispatch (due to the lifting of transmission bottlenecks) made possible by network reinforcements; and * The difference in energy supplied to consumers with and without the program is valued according to a proxy for their willingness to pay. 24. The additional revenue generated by sales to final consumers, less the required subtransmission and distribution costs incurred to deliver the energy, was used as a proxy for the willingness to pay. (The cost of the incremental energy delivered is included when the net operating benefits of the project are computed.) The incremental revenue serves as a lower bound for the willingness to pay of final consumers located at the lower voltage level, as it ignores the consumer surplus over and above the cash revenues associated with incremental sales. 25. The O&M costs associated with the program were calculated as 2% of the investment cost, which is consistent with ISA's past experience. 26. The capacity and energy delivered through the network were calculated through a Monte Carlo generation-transmission simulation program; the operating costs were obtained using the Hydrothermal Dispatch module of the SUPER/OLADE-BID program. These dispatch costs are calculated on the basis of a losses interconnection network, and therefore require an adjustment to take into account the loss increase or decrease associated with the program. 27. The results are summarized in Table 11-7. Most of the benefits associated with the investment program relate to the decrease in operating costs (i.e. savings in thermal generation) made possible through the proposed interconnection reinforcements. Without the project, the operating cost of the system increases because of a more intensive use of high-cost thermal plants due to transmission constraints as well as higher network losses. This confirms the project's overall objective which seeks to lift transmission bottlenecks in order to facilitate the operation of the bulk energy market. 28. The analysis yields the following benchmark values: * Net Present Value of Costs (12% discount rate): US$186 million * Net Present Value of Benefits: US$250 million * B/C ratio 1.34 * Economic Internal Rate of Return (EIRR). 27% 121 29. Sensitivity Analysis. The economic analysis was subjected to the following sensitivity variations: A- First and Second year reduction of benefits. These benefits are associated with short term network reinforcements (such as compensation equipment in the San Marcos substation); B- Increase of 10% in investment program costs; C- Decrease of 10% in operating benefits; and D- Lower demand growth rates; this case was calculated assuming a 4.3% per annum average growth rate for electricity demand. 30. The sensitivity cases are shown in Tables 11-8 to 11-11; they yield the following results: Sensitivity Analysis (US$ million) Sensitivity Case NPV of Costs NPV of Benefits EIRR B/C ratio Base 186 250 27 1.34 A 186 200 13 1.08 B 204 250 19 1.23 C 186 226 19 1.22 D 186 214 18 1.15 31. The results show that the investment program provides an adequate rate of return under conservative evaluation conditions: (a) as only energy-related benefits were quantified, and capacity-related benefits were disregarded due to the analytical difficulties associated with their evaluation; and (b) the net consumer surplus associated with the additional supplies enabled by the program was not quantified due to the uncertainty associated with parameters such as the price elasticity of demand. 32. The sensitivity analysis allows the identification of shifts in the principal variables which could reduce the benefits of the project. The principal source of benefits consists of fuel savings and loss reduction which can be achieved with the transmission investment program. If these are reduced by around 27%, the net present value of the project at 12% discount becomes zero. Similarly, an increase in program costs on the order of 35% with respect to the budgeted values would also lead to a zero net present value. These "safety margins" are unlikely to be consistently exceeded during the program's lifetime (benefits) or during its construction phase (investment costs). 122 Table 11-1 Cost Comparison San Carlos - San Marcos and AternativeProject BASE CASE Costs Benefits Difference (US$ thousand) (US$ thousand) Loss Total Reduction Savings from Year Investment O&M Cost Savings Gas Transp. 1994 3573 0 3573 0 0 -3573 1995 8428 0 8428 0 0 -8428 1996 33129 0 33129 0 0 -33129 1997 53277 0 53277 0 0 -53277 1998 40406 1977 42383 595 23078 -18710 1999 5341 2883 8758 3395 23078 18250 2000 2883 2883 4581 23078 24776 2001 2883 2883 8070 28848 34035 2002 2883 2883 9845 28848 35810 2003 2883 2883 9048 28848 35013 2004 2883 2883 9370 28848 35335 2005 2883 2883 9370 28848 35335 2006 2883 2883 9370 28848 35335 2007 2883 2883 9370 28848 35335 2008 2883 2883 9370 28848 35335 2009 2883 2883 9370 28848 35335 2010 2883 2883 9370 28848 35335 2011 2883 2883 9370 28848 35335 2012 2883 2883 9370 28848 35335 2013 2883 2883 9370 28848 35335 2014 2883 2883 9370 28848 35335 2015 2883 2883 9370 28848 35335 2016 2883 2883 9370 28848 35335 2017 2883 2883 9370 28848 35335 2018 2883 2883 9370 28848 35335 2019 2883 2883 9370 28848 35335 2020 2883 2883 9370 28848 35335 2021 2883 2883 9370 28848 35335 2022 2883 2883 9370 28848 35335 Discount Rate PRESENT VALUE B/C Ratio 14o 86944 11262 98205 28540 109461 1.41 10% 99596 17312 116909 46285 169050 1.84 12% 92981 13857 106838 36075 134985 1.60 16% 80435 8957 89392 21980 86844 1.22 Equalizing IRR 18% NOTE: Evaluation in constant Dec'93 dollars Present Values as of Dec'93 123 Table 11-2 Cost Comparison San Carlos - San Marcos and Alternative Project INCREASE IN INVESTMENT COSTS 10% Costs Benefits Difference (US$ thousand) (US$ thousand) Loss Total Reductions Savings from Year Investment O&M Cost Savings Gas Transp. 1994 3930 0 3930 0 0 -3930 1995 9271 0 9271 0 0 -9271 1996 36442 0 36442 0 0 -36442 1997 58605 0 58605 0 0 -58605 1998 44447 1977 46424 595 23078 -22751 1999 5875 2883 8758 3395 23078 17716 2000 2883 2883 4581 23078 24776 2001 2883 2883 8070 28848 34035 2002 2883 2883 9845 28848 35810 2003 2883 2883 9048 28848 35013 2004 2883 2883 9370 28848 35335 2005 2883 2883 9370 28848 35335 2006 2883 2883 9370 28848 35335 2007 2883 2883 9370 28848 35335 2008 2883 2883 9370 28848 35335 2009 2883 2883 9370 28848 35335 2010 2883 2883 9370 28848 35335 2011 2883 2883 9370 28848 35335 2012 2883 2883 9370 28848 35335 2013 2883 2883 9370 28848 35335 2014 2883 2883 9370 28848 35335 2015 2883 2883 9370 28848 35335 2016 2883 2883 9370 28848 35335 2017 2883 2883 9370 28848 35335 2018 2883 2883 9370 28848 35335 2019 2883 2883 9370 28848 35335 2020 2883 2883 9370 28848 35335 2021 2883 2883 9370 28848 35335 2022 2883 2883 9370 28848 35335 Discount Rate PRESENT VALUE B/C Ratio 8% 117544 22005 139549 60375 215420 1.98 10% 109556 17312 126868 46285 169050 1.70 12% 102279 13857 116136 36075 134985 1.47 15% 92860 10312 103171 25819 100133 1.22 Equalizing IRR 18% NOTE: Evaluation in constant Dec93 dollars Present Values as of Dec93 124 TABLE 11-3 Cost Comparison San Carlos - San Marcos Project REDUCTION IN GAS TRANSPORT COSTS -10% Costs Benefits Difference (US$ thousand) (US$ thousand) Loss Re- Savings From Total duction Gas Transp. Year Investment O&M Cost Savings Costs 1994 3573 0 3573 0 0 -3573 1995 8428 0 8428 0 0 -8428 1996 33129 0 33129 0 0 -33129 1997 53277 0 53277 0 0 -53277 1998 40406 1977 42383 595 20771 -21018 1999 5341 2883 8224 3395 20771 15942 2000 2883 2883 4581 20771 22468 2001 2883 2883 8070 25963 31151 2002 2883 2883 9845 25963 32925 2003 2883 2883 9048 25963 32128 2004 2883 2883 9370 25963 32450 2005 2883 2883 9370 25963 32450 2006 2883 2883 9370 25963 32450 2007 2883 2883 9370 25963 32450 2008 2883 2883 9370 25963 32450 2009 2883 2883 9370 25963 32450 2010 2883 2883 9370 25963 32450 2011 2883 2883 9370 25963 32450 2012 2883 2883 9370 25963 32450 2013 2883 2883 9370 25963 32450 2014 2883 2883 9370 25963 32450 2015 2883 2883 9370 25963 32450 2016 2883 2883 9370 25963 32450 2017 2883 2883 9370 25963 32450 2018 2883 2883 9370 25963 32450 2019 2883 2883 9370 25963 32450 2020 2883 2883 9370 25963 32450 2021 2883 2883 9370 25963 32450 2022 2883 2883 9370 25963 32450 Discount Rate PRESENT VALUE B/C Ratio 8% 106858 22005 128864 60375 193878 1.97 10% 99596 17312 116909 46285 152145 1.70 12% 92981 13857 106838 36075 121486 1.47 15% 84072 10188 94260 25465 89022 1.21 Equalizing IRR 18.4% NOTE: Evaluation in constant Dec93 dollars Present Values as of Dec'93 125 Table 11-4: Cost Comparison La Loma-Copey And Alternative Projects (US$ millions Dec'93, Present Values) 10% DISCOUNT RATE Generation Transmission Cost Projects Invest. Fuel O&M Total. Invest. O&M Total TOTAL Ratio La Loma -Copey and 251.5 66.0 77.6 395.1 31.5 6.0 37.5 432.6 Paipa-Bucaramangal Tasajero 11 (2) 265.8 60.4 85.9 412.2 32.8 6.2 39.0 451.2 1.043 TASAJERO I And 137.1 30.6 43.1 210.7 27.6 5.3 32.9 243.6 Cartagena IV 3) 136.0 29.5 33.9 199.3 5.8 1.0 6.8 206.1 Total 273.1 60.0 76.9 410.0 33.4 6.3 39.7 449.7 1.040 12% DISCOUNT RATE Generation Transmission Cost Projects Invest. Fuel O&M Total Invest. O&M Total TOTAL Ratio La Loma -Copey and 233.4 52.3 61.4 347.0 29.0 4.8 33.7 380.8 Paipa-Bucaramanga(l) Tasajero 11 (2) 245.8 48.0 68.0 361.8 30.3 4.9 35.2 396.9 1.042 Tasajero I and 126.7 24.3 34.1 185.0 25.5 4.2 29.6 214.6 Cartagena IV 3) 125.7 23.2 26.7 175.6 5.3 0.8 6.1 181.7 Total 252.3 47.5 60.8 360.6 30.8 5.0 35.7 396.4 1.041 14% DISCOUNT RATE Geneneration Transmission Cost Projects Invest. Fuel O&M Total Inv. O&M Total TOTAL Ratio La Loma -Copey and 216.9 42.0 49.2 308.1 7.8 0.3 8.2 316.3 Paipa-Bucaramanga(l) Tasajero 11 (2) 227.6 38.6 54.6 320.8 8.3 0.4 8.7 329.4 1.04 Tasajero I and 117.2 19.5 27.4 164.1 7.0 0.3 7.3 171.4 Cartagena IV 3) 116.3 18.5 21.4 156.2 1.4 0.05 1.4 157.7 Total 233.5 38.0 48.7 320.3 8.4 0.4 8.8 329.1 1.04 (1) Transmission includes the Loma-Copey and Paipa - Bucaramanga project (2) Transmission includes the Palos - Tasajero (double circuit) and Paipa - Bucaramanga projects (3) Transmission includes the Palos - Tasajero (one circuit), Paipa - Bucaramanga and Caragena - Sabanalarga lines 126 TABLE 11-5: SENSITIVITY ANALYSIS LOMA - COPEY AND PAIPA - BUCARAMANGA PROJECT 10% INCREASE IN INVESTMENT COSTS (US$ millions Dec'93) 12% DISCOUNT RATE Generation Transmission Cost Projects Invest. Fuel O&M Total Invest. O&M Total TOTAL Ratio La Loma -Copey and 256.7 52.3 61.4 370.4 31.9 4.8 36.6 407.0 Paipa-Bucaramanga_ Tasajero II(2) 270.4 48.0 68.0 386.3 33.3 4.9 38.2 424.5 1.043 Tasajero I and 139.3 24.3 34.1 197.7 28.0 4.2 32.2 229.9 Cartagena IV3) 138.3 23.2 26.7 188.2 5.8 0.8 6.6 194.8 Total 277.6 47.5 60.8 385.8 33.8 5.0 38.8 424.7 1.043 (1) Transmission includes the Loma-Copey and Paipa - Bucaramanga project (2) Transmission includes the Palos - Tasajero (double circuit) and Paipa - Bucaramanga projects (3) Transmission includes the Palos - Tasajero (one circuit), Paipa - Bucaramanga and Cartagena - Sabanalarga lines TABLE 11-6: SENSITIVITY ANALYSIS LOMA - COPEY AND PAIPA - BUCARAMANGA PROJECT 10 % DECREASE IN FUEL COSTS (US$ million Dec'93) 12% DISCOUNT RATE Generation Transmission Cost Projects Invest. Fuel O&M Total Inv. O&M Total TOTAL Ratio La Loma -Copey and 233.4 47.0 61.4 341.8 29.0 4.8 33.7 375.6 Paipa-Bucaramanga_) Tasajero 11 (2) 245.8 43.2 68.0 357.0 30.3 4.9 35.2 392.1 1.044 Tasajero I and 126.7 21.8 34.1 182.6 25.5 4.2 29.6 212.2 Cartagena IV") 125.7 20.9 26.7 173.3 5.3 0.8 6.1 179.4 Total 252.3 42.7 60.8 355.9 30.8 5.0 35.7 391.6 1.043 (I) Transmission includes the Loma-Copey and Paipa - Bucaramanga project (2) Transmission includes the Palos - Tasajero (double circuit) and Paipa - Bucaramanga projects (3) Transmission includes the Palos - Tasajero (one circuit), Paipa - Bucaramanga and Cartagena - Sabanalarga lines 127 TABLE 11-7 BASE CASE EVALUATION OF INVESTMENT PROGRAM BENEFITS THERMAL ENERGY SAVINGS INCREMENTAL ENERGY SUPPLY Gross Net Gross Incrementul Net Program Costs (M S) Cost ofThermal Total Incrmental Incren Incementl Distribotion incremental Total Net Cash Total G eneraton (MU SS) Opeiating Energy Energy Benefit Costs B enefits B enefits Flow Year Investment OAM Cost WIOProgram W/Program Saving%(MS) (GWh) (GWh) (MS) (MS) (MS) (MS) (M S) 1993 5 - $ - s 5 - $ - 1994 4.8 4.8 $ 46 $ 14 $ 32 $ 32 $ 27 1995 14.0 0.4 14.4 $ 54 5 28 S 27 1 0.6 0.04 0 02 0 03 S 27 S 12 1996 37.9 1.1 39.0 5 61 S 41 S 19 3 2.5 0.18 0 06 0.1 $ 19 $ (20) 1997 83.1 2 8 85.9 $ 79 S 56 S 24 0 00 0.00 0 00 0.0 $ 24 S (62) 1998 104.1 4 9 109.0 $ 98 S 73 5 25 3 2 5 0 18 0 06 0.1 S 25 S (84) 1999 7.8 5 0 12.8 S 120 S 95 S 22 8 7.1 0.49 0 18 0.3 $ 22 S 10 2000 5 0 5.0 $ 143 $ 117 5 20 6 5.2 0.36 0 13 0.2 S 21 $ 16 200 5.0 5.0 $ 157 S 124 $ 29 133 122.0 8.54 3 05 5.5 $ 34 $ 29 2002 5.0 5.0 $ 185 $ 147 S 39 242 222.7 15.59 5 57 10 0 S 49 $ 44 2003 5.0 5.0 $ 240 $ 198 $ 42 42 38.4 2.69 0 96 1.7 $ 44 S 39 2004 5.0 5.0 $ 258 $ 213 $ 37 55 50.4 3.53 1 26 2.3 $ 40 5 35 2005 5.0 5.0 S 40 $ 35 2006 5 0 5.0 $ 40 S 35 2007 5.0 5 0 S 40 S 35 200s 5.0 5.0 $ 40 $ 35 2009 5.0 5.0 $ 40 S 35 2010 5.0 5.0 $ 40 S 35 2011 5.0 5.0 S 40 $ 35 2012 5.0 5.0 5 40 S 35 2013 5.0 5.0 S 40 S 35 2014 5.0 5.0 $ 40 S 35 2015 5.0 5.0 S 40 $ 35 2016 5.0 5.0 $ 40 $ 35 2017 5.0 5.0 S 40 5 35 2018 5.0 5.0 $ 40 S 35 2019 5.0 5.0 5 40 S 35 2020 5.0 5.0 S 40 S 35 12% NPV: $186 $163 $8.37 $250 $64 IRR= 27% WIO- Without Program WI- With Program Total Operating Benefits= Thermal Costs WIProgram - Thermal Costs W/G Program +Adjustment for lower losses Net Incremental Energy-Gross Incremental Energy - Distribution Losses Distribution Losses (%)- 8 Gross Incremental Benefit- Net Incremental Energy * Price Average Price (I/MW h)= 70 Net Incremental Benefit= Oross Incr. Benefit - Incr. Distribution Costs Incremental Dist. Cott (/IM Wh)- 25 Total Benefits- Total Operating Benefit, + Net Incremental Bonet-ts 128 rABLE 11-8 SENSITIVITY ANALYSIS OF INVESTMENT PROGRAM: REDUCED INITIAL YEAR BENEFITS BENEFITS THERMAL ENERGY SAVINGS INCREMENTAL ENERGY SUPPLY Gross Net Gross Incremental Net Program Costs (MS) Cost of Therm al Total Incremental Incremental Incremental Distribution Incremental Total Net Cash Total Generation (MUSS) Loss Adjustment OPerating Energy Energy Benefit Costs Benefits Benefits Flow Year Investment O&M Cost W/OProlW/Progra GWh MS avings (M (GWh) (GWh) (MS) (MS) (MS) (MS) (MS) 1993 S - S - S - S- S - 1994 4.8 4.8 S 46 S 14 S $ - S (5) !995 14.0 0.4 14.4 S 54 S 28 S - I 0.6 0.04 0.02 0.03 S 0 S (14) 1996 37.9 1.1 39.0 S 61 S 41 S 19 3 2.5 0.18 0.06 0.1 $ 19 S (20) 1997 83.1 2.8 15.9 S 79 S 56 S 24 0 0.0 0.00 0.00 0.0 S 24 S (62) 1998 104.1 4.9 109.0 S 98 S 73 4 0.1 S 25 3 2.5 0.18 0.06 0.1 S 25 S (14) 1999 7.8 5.0 12.8 S 120 S 95 73 2.4 S 22 8 7.1 0.49 0.18 0.3 S 22 s 10 2000 5.0 5.0 S 143 S 117 181 5.9 S 20 6 5.2 0.36 0.13 0.2 S 21 $ 16 2001 5.0 5.0 S 157 S 124 135 4.4 S 29 133 122.0 8.54 3.05 5.5 S 34 S 29 2002 5.0 5.0 S 185 S 147 -13 -0.4 S 39 242 222.7 15.59 5.57 10.0 $ 49 $ 44 2003 5.0 5.0 S 240 S 198 4 0.1 S 42 42 38.4 2.69 0.96 1.7 S 44 $ 39 2004 5.0 5.0 S 258 S 213 224 7.3 S 37 55 50.4 3.53 1.26 2.3 S 40 $ 35 2005 5.0 5.0 S 40 S 35 2006 5.0 5.0 5 40 $ 35 2007 5.0 5.0 S 40 S 35 2008 5.0 5.0 S 40 $ 35 2009 5.0 5.0 S 40 S 35 2010 5.0 5.0 $ 40 S 35 2011 5.0 5.0 S 40 $ 35 2012 5.0 5.0 S 40 S 35 2013 5.0 5.0 S 40 S 35 2014 5.0 5.0 $ 40 S 35 2015 5.0 5.0 $ 40 S 35 2016 5.0 5.0 S 40 $ 35 2017 5.0 5.0 S 40 $ 35 2018 5.0 5.0 $ 40 S 35 2019 5.0 5.0 $ 40 S 35 2020 5.0 5.0 S 40 S 35 12% NPV: S186 SI13 S8.37 $200 S15 IIRR= 13% W/O= Without Program W/= With Program Total Operating Benefits=Thermal Costs W,Program - Thermal Costs W!O Program -Adjustment for lower losses Net Incremental Encrgy=Gross Incremental Energy - Distribution Losses Distribution Losses (%) 8 Gross Incremental Benefit= Net Incremental Energy * Price Average Price (S/MWh) 70 Net Incremental Benefit= Gross Iner. Benefit - Incr. Distribution Costs Incremental Dist. Cost (S'MWh)= 25 Total Benefits= Total Operating Benefits + Net Incremental Benefits 129 TABLE 11-9 SENSITIVITY ANALYSIS OF INVESTMENT PROGRAM 10% INCREASE IN INVESTMENT COSTS BENEFITS THERMAL ENERGY SAVINGS INCREMENTAL ENERGY SUPPLY Gross Net Gross Incremental Net Program Costs (MS) Cost of Thermal Total Incremental Incremental Incremental Distribution Incremental Total Net Cash Total Generation (MUSS) Operating Energy Energy Benefit Costs Benefits Benefits Flow Year Investment O&M Cost W/O Program W/ Program Savings (MS) (GWh) (GWh) (MS) (MS) (MS) (MS) (MS) 1993 S - S - S - - $ - 1994 4.8 4.8 S 46 $ 14 S 32 S 32 5 27 1995 14.0 0.4 14.4 S 54 S 28 S 27 1 0.6 0.04 0.02 0.03 S 27 S 12 1996 37.9 1.1 39.0 $ 61 S 41 S 19 3 2.5 0.18 0.06 0.1 S 19 S (20) 1997 83.1 2.8 85.9 S 79 $ 56 5 24 0 0.0 0.00 0.00 0.0 $ 24 S (62) 1998 104.1 4.9 109.0 S 98 S 73 S 25 3 2.5 0.18 0.06 0.1 S 25 S (84) 1999 7.8 5.0 12.8 S 120 S 95 S 22 8 7.1 0.49 0.18 0.3 S 22 $ 10 2000 0.0 5.0 5.0 S 143 5 117 S 20 6 5.2 0.36 0.13 0.2 $ 21 S 16 2001 0.0 5.0 5.0 S 157 S 124 $ 29 133 122.0 8.54 3.05 5.5 S 34 S 29 2002 0.0 5.0 5.0 S 185 S 147 5 39 242 222.7 15.59 5.57 10.0 5 49 $ 44 2003 0.0 5.0 5.0 S 240 5 198 $ 42 42 38.4 2.69 0.96 1.7 $ 44 S 39 2004 0.0 5.0 5.0 $ 258 $ 213 S 37 55 50.4 3.53 1.26 2.3 $ 40 S 35 2005 0.0 5.0 5.0 S 40 $ 35 2006 0.0 5.0 5.0 $ 40 S 35 2007 0.0 5.0 5.0 5 40 S 35 2008 0.0 5.0 5.0 S 40 S 35 2009 0.0 5.0 5.0 5 40 S 35 2010 0.0 5.0 5.0 5 40 S 35 2011 0.0 5.0 5.0 S 40 5 35 2012 0.0 5.0 5.0 S 40 5 35 2013 0.0 5.0 5.0 5 40 $ 35 2014 0.0 5.0 5.0 $ 40 $ 35 2015 0.0 5.0 5.0 $ 40 S 35 2016 0.0 5.0 5.0 $ 40 $ 35 2017 0.0 5.0 5.0 $ 40 5 35 2018 0.0 5.0 5.0 5 40 $ 35 2019 0.0 5.0 5.0 $ 40 S 35 2020 0.0 5.0 5.0 5 40 S 35 12% NPV: $186 5163 S8.37 S250 $64 I IRR= 27%/ W/O= Without Program W/= With Program Total Operating Benefits=Thermal Costs W/Program - Thermal Costs W/O Program +Adjustment for lower losses Net Incremental Energy=Gross Incremental Energy - Distribution Loss Distribution Losses (%)= 8 Gross Incremental Benefit= Net Incremental Energy * Price Average Price (S/MWh)= 70 Net Incremental Benefit= Gross Incr. Benefit - Iner. Distribution Costs Incremental Dist. Cost (5/MWh)= 25 Total Benefits= Total Operating Benefits + Net Incremental Benefits 130 TABLE 11-10 BASE CASE EVALUATION OF INVESTMENT PROGRAM 10% DECREASE IN OPERATING BENEFITS BENEFITS THERMAL ENERGY SAVINGS INCREMENTAL ENERGY SUPPLY Gross Net Gross Incremental Net Program Costs (MS) Cost of Thermal Total Incremental Incremental Incremental Distribution Incremental Total Net Cash Total Generation (MUSS) Operating Energy Energy Benefit Costs Benefits Benefits Flow Year Investment O&M Cost W/O Program W/ Program Savings (MS (GWh) (GWh) (MS) (MS) (MS) (MS) (MS) 1993 S - $ . S - S - . 1994 4.8 4.8 S 46 $ 14 $ 29 S 29 $ 24 1995 14.0 0.4 14.4 S 54 S 28 S 24 1 0.6 0.04 0.02 0.03 S 24 S 10 1996 37.9 1.1 39.0 $ 61 S 41 S 17 3 2.5 0.18 0.06 0.1 S 17 $ (22) 1997 83.1 2.8 85.9 $ 79 $ 56 S 21 0 0.0 0.00 0.00 0.0 $ 21 $ (65) 1998 104.1 4.9 109.0 $ 98 $ 73 $ 22 3 2.5 0.18 0.06 0.1 S 23 S (86) 1999 7.8 5.0 12.8 $ 120 S 95 S 20 8 7.1 0.49 0.18 0.3 $ 20 $ 7 2000 5.0 5.0 $ 143 S 117 $ 18 6 5.2 0.36 0.13 0.2 S 19 $ 14 2001 5.0 5.0 $ 157 $ 124 $ 26 133 122.0 8.54 3.05 5.5 $ 32 $ 27 2002 5.0 5.0 S 185 $ 147 S 35 242 222.7 15.59 5.57 10.0 S 45 $ 40 2003 5.0 5.0 $ 240 S 198 $ 38 42 38.4 2.69 0.96 1.7 $ 39 S 34 2004 5.0 5.0 S 258 S 213 S 34 55 50.4 3.53 1.26 2.3 $ 36 $ 31 2005 5.0 5.0 S - $ 36 S 31 2006 5.0 5.0 $ - S 36 S 31 2007 5.0 5.0 $ - S 36 S 31 2008 5.0 5.0 $ - $ 36 $ 31 2009 5.0 5.0 $ - $ 36 S 31 2010 5.0 5.0 S - S 36 $ 31 2011 5.0 5.0 $ - S 36 $ 31 2012 5.0 5.0 $ - S 36 S 31 2013 5.0 5.0 $ - $ 36 $ 31 2014 5.0 5.0 S - $ 36 S 31 2015 5.0 5.0 S - $ 36 $ 31 2016 5.0 5.0 $ - $ 36 $ 31 2017 5.0 5.0 $ - $ 36 $ 31 2018 5.0 5.0 S - $ 36 $ 31 2019 5.0 5.0 $ - S 36 S 31 2020 5.0 5.0 $ - $ 36 5 31 12% NPV: $186 S147 $8.37 $226 540 IRR= 19% W/O= Without Program W/= With Program Total Operating Benefits=Thermal Costs W,Program - Thermal Costs W/O Program +Adjustment for lower losses Net Incremental Encrgy=Gross incremental Energy - Distribution Loss Distribution Losses (%)= 8 Gross Incremental Benefit= Net Incremental Energy * Price Average Price (S/MWh)- 70 Net Incremental Benefit= Gross Incr. Benefit - Incr. Distribution Costs Incremental Dist. Cost ($/MWh)= 25 Total Benefits= Total Operating Benefits - Net Incremental Benefits 131 TABLE 11-11 OVERALL INVESTMENT PROGRAM: SENSIVITY TO LOWER DEMAND SCENARIO 10% DECREASE IN OPERATING BENEFITS BENEFITS THERMAL ENERGY SAVINGS INCREMENTAL ENERGY SUPPLY Gross Net Gross Incremental Net Program Costs (MS) Cost of Thermal Total Incremental Incremental Incremental Distribution Incremental Total Net Cash Total Generation (MUSS) Operating Energy Energy Benefit Costs Benefits Benefits Flow Year Inveltment O&M Cost W/O Program W/ Program avings (MS (GWh) (GWh) (MS) (M$) (MS) (M$) (MS) 1993 $ - S - S - $ - $ - I 19 t 4.8 4.8 S 41 $ 10 S 31 $ 31 S 26 1995 14.0 0.4 14.4 S 48 $ 19 S 29 0 0.0 0.00 0.00 0.0 S 29 $ 15 1996 37.9 1.1 39.0 $ 50 $ 30 $ 20 0 0.1 0.01 0.00 0.0 S 20 $ (19) 1997 83.1 2.8 85.9 S 61 $ 40 $ 21 1 0.7 0.05 0.02 0.0 S 21 S (65) 1998 104.1 4.9 109.0 $ 74 S 51 S 23 2 1.4 0.10 0.03 0.1 $ 23 $ (86) 1999 7.8 5.0 12.8 S 94 S 69 $ 23 3 2.9 0.21 0.07 0.1 $ 23 $ 10 2000 5.0 5.0 S 104 $ 84 $ 14 0 0.3 0.02 0.01 0.0 $ 14 $ 9 2001 5.0 5.0 $ 117 S 84 S 29 39 36.0 2.52 0.90 1.6 $ 30 S 25 2002 5.0 5.0 $ 135 S 100 $ 35 79 72.5 5.07 1.81 3.3 S 39 $ 34 2003 5.0 5.0 S 152 S 117 S 35 28 25.5 1.78 0.64 1.1 $ 36 S 31 2004 5.0 5.0 $ 169 $ 134 $ 28 38 35.1 2.46 0.88 1.6 $ 29 S 24 2005 5.0 5.0 $ - S 29 $ 24 2006 5.0 5.0 S - $ 29 S 24 2007 5.0 5.0 S S 29 S 24 2008 5.0 5.0 $ - $ 29 S 24 2009 5.0 5.0 $ S 29 S 24 2010 5.0 5.0 S - $ 29 $ 24 2011 5.0 5.0 S - $ 29 S 24 2012 5.0 5.0 $ S $ 29 $ 24 2013 5.0 5.0 $ . S 29 $ 24 2014 5.0 5.0 $ - S 29 $ 24 2015 5.0 5.0 $ - $ 29 S 24 2016 5.0 5.0 S - $ 29 $ 24 2017 5.0 5.0 S - S 29 S 24 2018 5.0 5.0 $ S S 29 S 24 2019 5.0 5.0 S S 29 S 24 2020 5.0 5.0 $ - $ 29 S 24 12% NPV: $186 $153 $3.12 $214 S28 IRR= 13/% W/0= Without Program W/= With Program To's. uperating Benefits=Thermal Costs W/Program - Thermal Costs W/O Program +Adjustment for lower losses (not shown) Net in.remental Energy=Gross Incremental Energy - Distribution Losses Distribution Losses (%)= 8 ';rovs ln.remental Bencfit= Net Incremental Energy * Price Average Price ($/MWh)= 70 \ct incremental Benefit- (iross Incr. Benefit - In.r Distribution Costs Incremental Dist. Cost ($/MWh)= 25 . ts Hencfits Total fl ane Ienefits + Net Tncremental Benefits 132 ANNEX 12 COLOMBIA POWER MARKET DEVELOPMENT PROJECT Assumptions For ISA's Financial Projections General 1 . Financial projections for 1995-2004 were prepared by ISA in current prices and are expressed in millions of Colombian pesos (Col $ million). Expected inflation rates and exchange rates used are detailed in the following table: Table 1 1994 1995 1996 1997 1998 1999-2004 Local Inflation (%) 22.5 17.0 16.0 15.0 14.0 13.5 in 1999 and 13.0 from 2000 onwards External Inflation %) 3.0 1.5 1.8 2.6 2.5 2.5% for 1999-2001, 2.4% for 2002, and 2.1% from 2003 onwards Average Exchange 814 895 1025 1158 1292 1434 form 1999 onwards Rate (Col $/US$) parity remains constant Exchange Rate at the 831 958 1092 1224 1361 Col $1507 from 1999 end of thL year (Col onwards parity remains $/US$) constant The other main assumptions adopted to prepare the financial projections are summarized in Table 2: Table 2 Item Assumption INCOME FORECAST Transmission Revenues See para. 3 below. Operations and Estimated at 1.5% of gross fixed assets in operation. Maintenance Administrative and Estimated at 0. 5% of gross fixed assets in operation. General Expenses Depreciation In accordance with the current accounting standards, ISA applies a 6.6% accelerated depreciation. Taxes ISA pays custom duties and VAT taxes. In accordance with Law #142, dated July 11, 94, ISA pays income tax (37.5%). Starting in 1996, ISA will pay in advance income taxes as follows: 25% in 1996, 50% in 1997, and 75% from 1998 onwards. VAT paid for capital expenditures is discounted from the income tax at the commissioning year. Other Non-operational Include interest earned on deposits. Income (expenses) Dividend Payment. No dividend payments are considered, so net income is capitalized. FLOW of FUNDS Investment Program M1ME prepared demand projections dated January, 1995. They consider an average 6.1% sales growth during the period, assuming and average 3.7% transmission losses over net power generation. The investment program is based on the Indicative Generation and Transmission Expansion Plan approved by CONPES for the period 1995-2007. 133 Item Assumption Financing of Investment See Table 12.4 and Annex 10 - Project Description, Costs, and Implementation Program Plan. Reasonable availability of external financing from international institutions, commercial banks - through FEN or directly - and from suppliers of foreign components of the investment program have been assumed. No local credits have been considered. BALANCE STATEMENT Revaluation of Assets Fixed assets are revalued with internal inflation, taking into account the useful life of the installation. Accounts Receivable Are based on sixty days of billing for distribution utilities and other direct customers. Inventory Projected as 0.5% of fixed assets in operation. Accounts payable Are estimated as percentage of cash operating expenses, and local costs of the investment program. 2. Calculation of Transmission revenues. The transmission revenues are composed of: (a) usage of the transmission system wheeling charges and (b) connection fees, and are based on the regulated rates defined in the Public Service Law and rules #00 1 through #004, issued by the ERC in 11.02.94 3. Wheeling Charges. ISA transmission revenues due to the use of the system are defined in accordance with the following formulae: ISA Revenue= a*M M,= R+ K, and R, = R,.,*[(IPP/IPP,-,) + (X/100)] where, M. = regulated revenue due for the whole of the transmission system during year t; Ro= Regulated revenue in 1994 equal to Col $138,595 million (at September 1994 prices); IPP Wholesale Price Index; X = growth factor of the regulated revenues. Currently fixed at 5% for the next 5 years. (This factor is revised every five years). K,= Correction factor (positive or negative) applied to the regulated revenues, depending on the actual variation of the IPP. a 72.7% of the transmission system assigned to ISA during 1995-1997, and 72.5% from 1998 onwards. 4. Connection fees. Calculated taking into account the inventory of assets connected to the distribution utilities, valued at replacement cost and adjusted according to the variation of the power sector cost index. The assets included in this calculation correspond to a transformation module at 230/500 kV and 230/500 kV power transformers. Connection fees are estimated to amount to US$ 15 million at June 1993 prices. 134 COLOMBIA Table 12-1 ISA's Financial Projections Actual and Forecast Income Statements (ColS billion) 19950) 1996 1997 1998 1999 2000 2001 2002 2003 2004 Gross Operating Revenues 129.8 166.7 201.0 239.6 288.3 354.2 418.2 493.9 583.5 689.5 Operating Expenses 88.1 105.4 124.1 149.1 186.0 233.6 255.2 278.4 299.6 328.4 O & M Expenses 17.7 21.8 26.0 35.1 40.4 51.3 58.5 66.6 76.0 86.6 Venezuelan Transm. Line Charges 3.2 3.5 3.8 4.0 4.2 4.4 4.5 4.6 0.0 0.0 Aministration and General 5.9 7.3 8.7 11.7 13.5 17.1 19.5 22.2 25.3 28.9 Expenses D,piL.iation (general assets) 0.4 0.5 0.7 0.9 1.2 1.5 1.8 2.2 2.6 3.2 Dzpreciation (assets in operation) 60.9 72.3 84.9 97.4 126.7 159.3 170.9 182.8 195.7 209.7 Operatin-, Income 41.7 61.3 76.9 90.5 102.3 120.6 163.0 215.5 283.9 361.1 Non-onerating Income (net) -1.8 1.7 4.2 -2.0 -2.8 -3.5 9.2 -4.5 -5.1 -5.7 Income before Interest 39.9 63.0 81.1 88.5 99.5 117.1 172.2 211.0 278.8 355.4 Interest charged to Operation 20.3 25.7 30.2 32.2 43.6 58.5 56.9 54.5 51.2 48.4 Monetary Correction 5.8 6.4 14.5 21.6 24.7 29.2 26.4 37.2 44.8 51.1 Income Tax 9.0 16.0 24.5 29.2 30.2 32.9 53.2 72.6 102.2 134.3 NET INCOME 16.4 27.7 40.9 48.7 50.4 54.8 88.5 121.1 170.2 223.8 Financial Indicators Rate ot Return With accelerated depreciation 4.9% 6.1% 6.6% 6.2% 5.9% 5.9% 6.9% 8.6% 10.6% 12.5% With linear depreciation 8.3% 8.9% 9.2% 8.2% 8.0% 8.0% 8.4% 9.3% 10.5% 11.7% Cash Operation Ratio 20.7% 19.6% 19.2% 21.2% 20.2% 20.6% 19.7% 18.9% 17.4% 16.8% (t1 It includes the estimate for the whole year. although the ISA was legally split in May 1, 1995. 135 COLOMBIA Table 12-2 ISA's Financial Projections Source and Application of Funds Statement (Col$ billion) 19950) 1996 1997 1998 1999 2000 2001 2002 2003 2004 Gross Internal Cash Generation 104.8 140.0 171.5 192.3 233.6 284.9 352.9 405.0 487.3 579.7 Income before Interest 39.9 63.0 81.1 88.4 99.5 117.1 172.3 211.0 278.8 355.5 Depreciation 61.3 72.8 85.6 98.4 127.9 160.8 172.7 185.0 198.4 212.8 Other non-Cash Expenses 3.6 4.2 4.8 5.5 6.2 7.0 7.9 9.0 10.1 11.4 Less: Net debt service 56.7 70.5 82.7 75.6 91.6 144.8 151.9 158.7 172.8 182.9 Amortization 36.4 44.8 52.5 43.4 48.0 86.3 95.0 104.2 121.6 134.6 Interest Charges 26.3 33.5 39.1 48.6 57.0 58.5 66.6 74.1 87.6 102.8 Total Debt Service 62.7 78.3 91.6 92.0 105.0 144.8 161.6 178.3 209.2 237.4 Less: Interest during Construction 6.0 7.8 8.9 16.4 13.4 0.0 9.7 19.6 36.4 54.5 Net Internal Cash Generation 48.1 69.5 88.8 116.7 142.0 140.1 201.0 246.3 314.5 396.8 Borrowings 93.9 59.3 107.7 165.1 15.9 0.0 116.8 109.1 316.5 69.5 IBRD 16.1 42.4 80.7 115.7 15.9 0.0 0.0 0.0 0.0 0.0 Existing Loans in FC 74.3 15.4 2.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Existing Local Loans in LC 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Future Loans in FC 0.0 1.1 24.9 49.4 0.0 0.0 116.8 109.1 316.5 69.5 Future Local loans in LC 3.5 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Sources 142.0 128.8 196.5 281.8 157.9 140.1 317.8 355.4 631.0 466.3 Applications In,estment Program 84.9 107.9 182.2 272.8 78.6 52.4 321.2 318.9 502.4 320.1 Construction Program 2 78.9 100.1 173.3 256.4 65.2 52.4 311.5 299.3 466.0 265.6 Foreign Component 41.6 52.9 93.8 154.9 21.4 35.0 153.0 128.2 218.9 96.1 Local Component 35.7 45.3 77.4 99.1 41.0 14.3 155.0 167.1 242.6 164.4 Other Investment 1.6 1.9 2.1 2.4 2.8 3.1 3.5 4.0 4.5 5.1 Interest during Construction 6.0 7.8 8.9 16.4 13.4 0.0 9.7 19.6 36.4 54.5 Variation in Working Capital 57.1 21.0 14.1 8.9 79.4 87.7 (3.4) 36.5 128.6 146.3 Other Applicationq 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total applications 142.0 128.9 196.3 281.7 158.0 140.1 317.8 355.4 631.0 466.4 T;nancial Indicators >ch' serviceCoverage (times) 1.7 1.8 1.9 2.1 2.2 2.0 2.2 2.3 2.3 2.4 Self-financing Ratio % 34 75 30 30 110 224 54 48 37 79 Includes the whole year, although ISA was split in May 1, 1995. . <.dcs not include V1AT - 136 - COLOMBIA ISA'S FINANCIAL PROJECTIONS Table 12-3 Balance Sheet (Col$ billion) ASSETS 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 Net Fixed Assets 1,025.1 1,232.8 1,528.0 1,935.6 2,152.9 2,336.1 2,809.1 3,328.8 4,098.2 4,759.0 Fixed Assets in Operation 1,179.5 1,453.6 1,735.7 2,341.9 2,695.1 3,418.7 3,897.2 4,442.4 5,063.5 5,770.9 Less: Accumulated Depreciation 249.3 361.5 500.6 668.1 885.0 1,151.1 1,471.6 1,845.8 2,281.4 2,787.7 Net Fixed Assets in Operation 930.1 1,092.1 1,235.0 1,673.8 1,810.1 2,267.6 2,425.6 2,596.6 2,782.0 2,983.2 Work in Progress 88.1 131.2 280.5 245.9 323.0 44.3 354.2 697.1 1,274.4 1,726.2 Fixed General Assets 7.4 10.6 14.5 19.2 24.7 31.2 39.1 48.4 59.5 72.7 Less: Accumulated Depreciation 0.5 1.2 2.1 3.3 4.9 7.1 9.8 13.3 17.7 23.1 Net Fixed General Assets 6.9 9.5 12.5 15.9 19.8 24.2 29.3 35.1 41.8 49.6 Current Assets 94.8 117.6 123.9 145.5 163.6 225.0 222.7 210.2 264.5 325.7 Cash and Banks 6.4 8.0 8.4 6.6 4.5 5.7 9.9 10.0 11.9 14.1 Temporary surplus 14.8 45.6 25.2 2.2 28.2 92.0 57.4 0.0 0.0 0.0 AQcounts Receivable 21.6 27.8 33.5 39.9 48.1 59.0 69.7 82.3 97.3 114.9 Advance income tax payment 12.0 20.8 38.8 75.5 58.4 38.9 52.3 80.0 112.3 147.8 Inventories 5.9 7.3 8.7 11.7 13.5 17.1 19.5 22.2 25.3 28.9 Other 34.1 8.1 9.3 9.6 10.9 12.3 13.9 15.7 17.7 20.0 Other Assets 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 TOTAL ASSETS 1,127.9 1,358.4 1,659.9 2,089.1 2,324.5 2,569.1 3,039.8 3,547.0 4,370.7 5,092.7 - 137 - ... continued ISA'S FINANCIAL PROJECTIONS Table 12-3 Balance Sheet (Col$ billion) LIABILITIES AND EQUITY 1995 1996 1997 1998 1999 2000 2001 2002 2003 2204 Equity 727.4 871.5 1,043.0 1,237.8 1,455.2 1,699.3 2,008.8 2,391.0 2,872.1 3,469.4 Capital 99.1 99.1 99.1 99.1 99.1 99.1 99.1 99.1 99.1 99.1 Legal Reserve 10.4 12.0 14.8 18.9 23.7 28.8 34.3 43.1 55.2 72.3 Contributions 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 Retained Eanings 40.1 66.2 104.2 148.8 194.3 244.2 327.3 439.5 597.7 804.5 Capital Revaluation 560.4 676.8 807.5 953.6 1,120.7 1,309.8 1,530.7 1,791.9 2,102.7 2,476.1 Long Term Debt 312.5 369.2 486.2 668.8 675.0 653.6 744.1 820.1 1,112.4 1,175.8 Current Liabilities 70.0 95.3 103.8 150.1 155.4 170.4 233.3 273.3 313.7 363.4 Short term Debt 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Current portion of Long Term Debt 41.9 49.5 41.1 45.6 82.1 90.4 99.0 115.4 127.8 128.4 Accounts Payable 1.1 8.4 13.5 42.4 10.1 10.7 39.9 39.0 30.7 40.2 Income Tax 9.0 16.0 24.5 29.2 30.2 32.9 53.2 72.6 102.2 134.3 Other 18.0 21.4 24.7 32.9 33.0 36.4 41.2 46.3 53.0 60.5 Other Liabilities 18.0 22.1 26.9 32.4 38.6 45.6 53.5 62.5 72.6 84.0 TOTAL LIABILITIES AND EQUITY 1,127.9 1,358.1 1,659.9 2,089.1 2,324.2 2,568.9 3,039.7 3,546.9 4,370.8 5,092.6 FINANCIAL INDICATORS 1,995 1,996 1,997 1,998 1,999 2,000 2,001 2,002 2,003 2,004 Debt/Equity Ratio 33 32 34 37 34 30 30 28 30 27 Liability/Assets 36 36 37 41 37 34 34 33 34 32 - 138- COLOMBIA POWER MARKET DEVELOPMENT PROJECT Table 12-4 ISA: LONG-TERM DEBT SCHEDULE Original Commit- Outstanding Debt Under Project Signing Date Amount Grace Re-payment ment (US$ thousand) (Currency Notes Period Period Interest Fee Current thousand) (year) (month/year) (%) (%) Total Portion LISTING LOANS kAx ot December 31, 1994) External Debt IDB Loan 195 1ransmission reinforcement December 86 US$ 115,80 (1/) 6 06/95 - 12/0 Variabl 1.25 130,97 11,38 IDB Loan 242 11 dnsmission reinforcement December 87 US$ 86,60 4 12/91 - 12/9 Variabl 0.50 39,96 13,32 Ansaldo liansinission reinforcement. January 90 Li 35,233,00 5 12/95 -06/1 1.7 0.00 17,41 86 Fxn, r)evelopment Corp. iruca-Butaramanga T. Line November 87 Can$ 45,00 2 1/2 06/90- 12/9 8.7 0.50 15,80 3,16 Credit I.y'onnais Canada irauca-HJucaramanga T. Line November 87 US$ 16,00 3 1/2 05/91 - 11/9 L+1+ 0.50 3,20 3,20 1at Debt in Foreien Currenc FEN FCII-009 Ocbt Service August 90 US$ 30,77 4 1/2 03/95 -09/0 L+7/8+3/4 30,79 2,79 FEN-Eximbank FEX-003 Venezuela Interconnection Line February 92 US$ 80,00 (5)/ 3Years+ 07/93 - 01/0 JPR+0.75% 0.50 43,76 4,30 1 0nonths qan Marcos S/S - Ist. stage Cerromatoso - Uraba Transm. Line 3etania-Mirolindo T.Line rransmission System Reinforcement cond Transmission Plan IDB Loan 687 3an Marcos S/S and December 92 US$ 69,70 (4/) 3Years+ 08/97 - 08/1 Variabl 0.75 7,69 2months .ines: Cerromatoso-Uraba Betania- Mirolindo FEX -006 ucaramanga-Oca±a-Cucuta T.Line June 92 Yen 1,538,56 (2/) 07/95 - 01/0 JPR+0.7 15,40 1,30 - 139 - COLOMBIA POWER MARKET DEVELOPMENT PROJECT Table 12-4 ISA: LONG-TERM DEBT SCHEDULE Original Commit- Outstanding debt Lender Project Signing Date Amount Grace Re-payment ment (US$ thousand) (currency Notes Period Period Interest Fee Current thousand) (year) (month/year) (%) (%) Total Portion Local Debt in Local Currency IONADE -702 Second Transmission Plan February 91 C$ 50,00 2Years+ 06/93 - 03/9 23.0 1.5 4months FONADE -703 Second Transmission Plan February 91 C$ 39,00 4months 06/92 - 0319 23.0 1.5 1 1 FONADE -704 Second Transmission Plan February 91 CS 133,00 4months 06/92 - 03/9 230 1.5 2 1 FEN -87 Transmission reinforcement October 87 C$ 1,500,00 1 04/89 - 04/9 27.0 0.5 15 15 FEN -88 ransinission reinforcement January 88 CS 1,700,00 1 04/90 - 01/9 29.0 0.5 72 20 Second Transmission Plan & Studies FUTURE LOANS IBRD Proposed Power market development Project under preparation US$ 230,00 5 7.3 0.25 , ommercial Credit (several) Fourth Transmission Plan To be contracted US$ 80,00 (3) 8.7 0.5 Multilateral loans (several) Future expansion To be contracted US$ 421,00 (3) 8.5 1 25 'OTAL 305,93 40,73 Notes: (1) USS 250,000 were canceled (2) This loan was transferred frorn ICEL to ISA .' .,Aal amount to be cornracted corresponds to the financing requirement during the period (4) 1 ast Disbursement expected in March, 97 i i Japanese Preferential Rate - 140 - COLOMBIA POWER MARKET DEVELOPMENT PROJECT Table 12- 5 Financial Sensitivity Analysis (Current US$ Million) Base Case Case A Case B Case C Case D Period Period Period Period Year 1997 Financial indicators (95- 99) (2000-04) (95-99) (2000-04) (95-99) (2000-04) (95-99) (2000-04) DI DII Operating Revenues 868 1286 865 1222 865 1222 878 1301 174 174 Operating Expenses 554 718 554 718 554 718 575 784 107 107 Net Income 314 568 312 504 312 504 302 517 67 67 I-ross Internal Cash Generation 714 1067 711 1004 683 954 714 1067 153 153 Debt Service (excludes IDC) 325 420 326 413 328 517 327 443 71 71 Internal Cash Generation 388 647 385 591 355 437 387 624 82 82 Borrowings 395 302 395 351 395 351 413 414 93 93 Investment (Includes IDC) 624 754 623 767 623 767 639 831 158 158 Average Rate of Return (%) 8.5 9.6 8.5 8.7 8.5 8.7 8.3 8.6 9.1 9.1 Average Cash Operating Ratio (%) 20.2 18.5 20.2 19.5 20.2 19.5 20.7 20.0 19.0 19.0 Average Debt Service Ratio 1.9 2.2 1.9 2.1 1.8 1.9 1.9 2.1 19 1.9 Average Self-Financing Ratio (%) 37 58 37 54 35 47 35 50 16 16 debt plus equity 34 29 34 32 34 31 34 31 34 34 CASE A: Tariffs are not adjusted to take into account increase of investment needs after 1999. CASE B: Same as case A plus delay in execution o investment program, which obliges ISA to pay penalty charges, plus a 10% increase in energy losses. CASE C: Same as case A plus higher local (+3%) and external inflation (+1%) than that used in the base case. CASE DI: Assumes that "small and unsolvent utilities" (see Annex 8, Table 8-7) delay payments. Di: Case DII assumes that in addition to the arrears supposed in DI "small and under recovery utilities" also delay payments, resulting in a shortfall of 20% of ISA's revenues - 141 - ANNEX 13 COLOMBIA POWER MARKET DEVELOPMENT PROJECT ENVIRONMENTAL EVALUATION Main Environmental Issues Associated with the Three Transmission Lines 1. Over the past years, ISA has demonstrated a noteworthy commitment to incorporating environmental issues within the decision making process to select optimal transmission projects. Since 1992, ISA has being developing the "Metodologia para el Estudio de Restricciones Ambientales y Selecci6n de Alternativas de Ruta". The methodology combines a Geographical Information System (ILWIS) for data gathering as well as photo interpretation, field work, and secondary data. It was applied to the San Carlos-San Marcos (500 kV) Transmission Line. The methodology represents a significant advance in environmental assessment starting with the earliest stage of the transmission project cycle. It permits selection of the corridor by weighting socio-economic, cultural, political and physic-biotic factors with electrical, technical and economic objectives. The main environmental restrictions are automatically incorporated within the designs, thereby assuring that highly complex environmental effects will be avoided. 2. ISA prepared and submitted to the Bank the report "Estudio de Restricciones Ambientales - Tercer Plan de Transmision", which identifies the main environmental and social constraints that are being used to select the optimal corridor and to be taken into account within the design of the three transmission lines. This report also contains the sequence of steps followed by ISA to incorporate environmental and social considerations within the entire project cycle. The report was approved by the Bank. Based on lessons learned in construction and operation of the present national interconnected system, the following environmental issues have been analyzed: (a) Abiotic Environment: geomorphology, erosion, soil alteration and destabilization of slopes as a consequence of construction of roads; mining activities and current and potential morphodynamic processes resulting from human intervention. (b) Biotic Environment: unique ecosystems of high biodiversity or high fragility; natural resources affected (especially water); loss of vegetative cover, effects on protected areas (e.g., national parks, natural reserves and areas with special jurisdiction). (c) Socio-economic and Socio-cultural Environment: restriction to the right- of-way derived from indigenous reserves or national minorities settlements; - 142 - special cultural and archaeological regions; highly populated areas; economic activities; land tenure; conflict related to the use of scarce natural resources; socio-political conflict in the area of influence of the transmission line. San Carlos-San Marcos. Main Environmental Restrictions 3. This 500 kV line (380 km; 24 meter right-of-way) will be developed to supply energy to the southwest region of the interconnected system. For this line, several alternatives were assessed. The alignment selected is expected to generate low environmental impacts mainly related to vegetation clearance, access paths and use of sensitive terrain (e.g., river crossings). Impacts on human settlements, cultivated lands, critical wildlife habitat, sites of archaeological interest, human health and visual landscape have been rated low. Special care of avoiding negative impacts on sugar cane plantations were taken during corridor selection. The designs will be finalized during the first quarter in 1995. Consultoria Colombiana, the firm in charge of the designs, is carrying out, in parallel, a project-specific environmental report containing the environmental mitigation plan. 4. A plan for the identification of potential archaeological sites that can be affected by the construction of the towers, and the sequential rescue of the archaeological heritage has been scheduled to start prior to construction and will be extended until excavations in tower-sitting and paths are finished. La Loma-Copey and Paipa-Bucaramanga. Main Environmental Restrictions 5. According to the current expansion plan and demand scenario, the two lines are required to start operating after 1997. The specific Study of Environmental Impacts will be undertaken by a consultant firm during 1995-96. Detailed mitigation measures and a monitoring system will be prepared while detailed engineering, definitive route alignment and field surveys are carried out prior to 1996. The preliminary studies for these 230 kV lines have identified some critical environmental aspects in a 4 km wide corridor. They are: (a) potential effects on a forestry reserve a native forest known as "Robledales" in the Virolin region, the status of which is currently being reviewed; and (b) impacts on the urban population living around the final substation in Bucaramanga. To avoid impacts on the Robledales forest ISA will use the existing corridor that was opened for the 500 kV line. ISA is also contemplating alternatives to avoid undesirable impacts on the neighborhood located around the substation in Bucaramanga. Other constraints are related to the socio-political conflicts in Santander. The Bank will carefully review the study when available to ensure conformity with Bank environmental guidelines and will supervise the environmental performance during the implementation of the two mentioned lines. Environmental Management Plan 6. Along with the current scheme to assess environmental impacts associated with transmission lines, a complete Environmental Management Plan to mitigate and compensate undesirable effects on human and natural systems is being prepared. It - 143 - embraces programs dealing with social communication and negotiation with affected and benefited communities; compensation for physical losses; reforestation or grass-planting; archaeological rescue; resettlement of displaced population; rural electrification, policy on local employment and supplies for contractor camps; creation of preserved areas; mitigation of impacts derived from access construction; path maintenance; monitoring of migratory species; and micro-basin management and environmental monitoring. ISA will prepare project-specific environmental reports satisfactory to the Bank for each of the project's transmission lines before the bidding process. In addition, general procedures to incorporate environmental standards and safeguards have been included within the bidding documents for contractors of main civil works. Resettlement 7. Relocation from transmission lines is usually much simpler compared to other kinds of infrastructure construction due to the fact that houses and assets can be displaced just a few meters away from the corridor and in many cases land can be utilized for agriculture or grazing (except for forestry and tall fruit trees). The three lines do not affect concentrated communities. In 1991, the Colombian Electric Power Sector prepared and approved an official Resettlement Policy which is consistent with World Bank resettlement policy. ISA has undertaken successful experiences in applying a participative approach to resettlement of scattered populations living along the right-of-way of the lines of the existing interconnected system. Individual solutions for housing, land and economic activities restoration have been designed and implemented in conjunction with each affected family. 8. In the case of the San Carlos-San Marcos transmission line, the population to be displaced along the corridor comprises 42 families (176 persons). Due to the small size of the right-of-way that is necessary to raise the towers, many affected families will be able to remain on their lots and will be given a new house. Regardless of the small number of people that will be displaced by these lines, the borrower will prepare a resettlement plan for Bank approval before opening the bidding process. The ISA social team has already contacted the affected families to inform them about the project, the expected environmental and social effects, the ISA's resettlement policy, and their rights in terms of compensation and indemnization. The families' expectations and preferences are being included in the resettlement plan. 9. In the case of the transmission lines foreseen to reinforce the Atlantic Coast Region, design is scheduled to start in 1996 and construction will begin in 1998. Therefore, definite figures for displacement of population will not be available until detailed engineering designs are finished. Moreover, the final centerline can be changed even during the construction phase. Although the selected corridors avoid human settlements, a small number of families living within the right-of-way corridor might be displaced. Regardless the number of people that will be displaced by these lines, the borrower will prepare a resettlement plan for Bank approval and will follow the same procedures agreed for the San Carlos-San Marcos transmission line. - 144 - Institutional Capacity for Environmental Assessment and Management 10. The recent institutional reforms in the Colombian Electric Power Sector and the restructuring of ISA as an independent transmission company, emphasize ISA's role in planning, implementation and operation of the existing and planned expansion of the national transmission system. Therefore, ISA is responsible for implementing environmental management plans for the current and new transmission lines and for directly monitoring compliance with national and sectoral environmental norms and proposed mitigation measures. Monitoring and evaluation is to be undertaken by the Direcci6n de Proyectos de la Gerencia de Transmisi6n de ISA. 11. Gradually moving from corrective to preventive management is improving ISA's institutional capacity. The studies of alternative alignments and environmental constraints are carried out by an interdisciplinary team comprising ecologists, anthropologists, sociologists, economists, geologists, and environmental engineers. The interdisciplinary team works in conjunction with the electric and civil engineers in charge of project design, in order to achieve the optimal electrical, technical, economic and environmental decisions. Occasionally other environmental specialists can be brought in as needed. Finally, the recently created Ministry of Environment is responsible for providing the environmental licenses once ISA presents the Report on Environmental Impact for each transmission line and fulfills all requirements to demonstrate their environmental feasibility. Legal Framework 12. In recent years, the government has been making a significant effort to strengthen the regulatory framework in order to promote an environmentally sustainable development in the Electric Power Sector. Since the creation of the Ministry of Environment (ME) and the approval of the National Environmental Law (NEL)2, specific regulations for environmental assessment and licensing for electric power projects have been established. 13. The recently approved National Environmental Law establishes a new procedure according to which an Environmental Diagnosis of Alternatives (EDA) should be presented to the ME. The EDA should present several alternatives for each project and assess their advantages and drawbacks. The ME will select the optimal alternative and will request a detailed Environmental Assessment before providing the corresponding permit to build the project. The new legal procedure is intended to ensure optimal decisions in selecting environmentally sound projects. 14. The new Electricity Law approved by Congress in July 1994 explicitly establishes the adequate protection of the environment, consultation with affected communities and relevant social groups involved in all operations of the electric power sector (See Chapter X: de la Conservaci6n del Medio Ambiente, art. 50 to 53). Sound environmental planning, execution and operation of the transmission lines is widely recognized as a condition for privatization of the electric power facilities. In addition, the regulation of the recently approved NEL explicitly 2 Ley 99 de Diciembre de 1993 - 145 - requires an Environmental Assessment of alternatives for transmission lines among other projects (see Chapter IV art. 17 to 20 of Law 99/93: Diagn6stico Ambiental de Alternativas). The NEL also establishes the new processes for clearance and environmental licensing. 15. Non-governmental organizations, both at the local and national levels, as well as private consulting firms, have participated in the environmental assessment and design of the planned transmission system. Active discussions on methodologies to incorporate environmental considerations since the earliest stage in the planning process, have been put in place at both the regional and sectoral level. 146 ANNEX 14 COLOMBIA POWER MARKET DEVELOPMENT PROJECT TERMS OF REFERENCE FOR TECHNICAL ASSISTANCE Part C of the project includes the provision of consulting services to assist ISA in the strengthening of its capabilities to assume its roles of: (i) transmission network operator, (ii) power dispatch coordinator and (iii) bulk electricity transaction clearing house. These activities will be agreed upon between ISA and the Bank subject to an annual plan to be approved by the Bank. A summary of the terms of reference for technical assistance studies to be started in 1996 is presented below. The corresponding implementation timetable is in Annex 10, together with the Project's Execution Schedule. The terms of reference presented by ISA are in the project files. (a) Final design and technical specification for computing and data acquisition systems and the corresponding software for the ECC and the FSC. Objective: improve performance of ISA's ECC and FSC. Scope: design and specify the hardware and software necessary for the effective functioning of the ECC and the FSC. Product: bidding documents for the international competitive bidding for the supply of hardware and software. (b) Determination and specification of methods to transmit data collected by remote meters to the ECC and the FSC. Objective: improve performance of ISA's ECC and FSC. Scope: identify a practical and reliable mean for the transmission of data between remote meters and the ECC. Product: specification of the hardware and software needed. (c) Identification of the characteristics of transmission power losses in ISA's network and specification of mechanisms for loss monitoring and control. Objective: reduce ISA's power losses to economic levels. Scope: prepare a diagnose of electricity transmission losses during typical demand pattern cycles that occur during the year. Product: a power loss reduction plan. (d) Review and update of ISA's power substation design manual. Objective: improve the design of power substations with the ultimate objective of reducing costs and improving reliability. Scope: review existing manual to include new technology in the areas of compensation, 147 transformer overload protection and telecommunications; extend manual to cover 500 kV substations. Product: updated manual. (e) Development of methodology for technical and economical assessment of width of corridors for transmission lines. Objective: reduce costs of transmission line construction and insure public safety. Scope: review existing literature on the subject, and evaluate existing software; if necessary adapt methodology for ISA's use. Product: adequate methodology and software to determine the width of corridors for transmission lines. (f) Standardization of steel structures for single circuit 230 kV lines. Objective: reduce costs of construction and maintenance of single circuit 230 kV lines. Scope: update ISA's metereological data base and normalize the dimension of transmission towers. Product: set of standard blueprints for transmission towers adequate to Colombian topology and meteorology. (g) Development of a comprehensive quality control data acquisition system. Objective: improve power transmission reliability. Scope: diagnose of existing quality control system, design upgraded system, draft technical specifications for metering equipment and software for analysis of failures. Product: plan to improve ISA's power transmission reliability and bidding documents for the purchase of the necessary equipment. (h) Evaluation of telecommunications infrastructure and equipment needs for power transmission projects. Objective: improve power transmission reliability and minimize construction costs. Scope: prepare a manual on telecommunication infrastructure requirements with the specifications and costs of the necessary equipment. Product: manual on telecommunications requirement for power transmission projects. (i) Development and acquisition of computer software to prepare construction budgets for power substations. Objective: reduce time and cost of preparing construction budgets. Scope: develop a cost data base and computer software to prepare budgets for the construction of substations. Product: substation components cost data base and computer software. (j) Feasibility study of the application of synchronized operation of circuit breakers on ISA substations. Objective: reduce transmission losses and improve transmission system reliability. Scope: specification of schemes for the synchronized operation of circuit breakers. Products: (i) report identifying which nodes of ISA's transmission network require breakers synchronized operation, and description of the appropriate 148 operation technique in each case; and (ii) bidding documents for the purchase of the required equipment. (k) Review of power transformer technical specifications used by ISA. Objective: reduce power transformation costs and increase system reliability. Scope: evaluate the adequacy to Colombian conditions of the use of new power transformation technology. Product: report specifying which types of transformers should be used in ISA's substations, their technical specifications and cost curves. (1) Methodology for load curve forecast. Objective: improve power plant economic dispatch and increase system reliability. Scope: review ISA's load curve forecast techniques and recommend which set of forecasting tools (e.g. time series forecast techniques combined to energy end-use models) are most suitable to ISA; specify the required software to be implemented. Product: Report prescribing load curve forecast methods and corresponding software. 149 ANNEX 15 COLOMBIA POWER MARKET DEVELOPMENT PROJECT ISA - MONITORING INDICATORS 1. Indicators: The following indicators would be used during project supervision to monitor ISA performance: (a) Weighted Average Frequency of Interruption (Fi) Fi = (Y Pi) / CEM Pi = Interrupted power in MW CEM = Average capacity of the transmission network in MW (b) Weighted Average Length of Interruptions (Di) Di = Y,(PixDHi)/ZP Pi = Interrupted power in MW DHi = Length of interruption in hours. (c) Average Interruption Time (TEI) TEI = Y (Pix DHI)/CEM Pi: Interrupted power in MW DHi: Length of interruption in hours CEM: Average capacity of the transmission network in MW (d) Reliability Index (IC) IC = I - (TEI/T) TEI = Average interruption time T = 8760 hrs (e) Total Transmission Losses (Loss): defined as the ratio: Loss = (NG-DG)/NG (%) where NG = Net energy supplied to ISA's grid DG = Energy delivered by ISA to its clients 150 (f) Cash Operating Ratio: defined as the ratio between total cash operating expenses and total gross revenues. Total cash operating expenses refers to all expenses related to operations, including operation, maintenance and administrative expenses, taxes and payments in lieu of taxes, but excluding provision for depreciation, income taxes, and other non-cash operating charges, interest and other charges on debts. Gross operating revenue refers to revenues from all sources related to operations; (g) Self-Financing Ratio: defined as the ratio between funds from internal sources and capital expenditures. Funds from internal sources are the difference between the sum of revenues from all sources, excluding borrowing, and the sum of all expenses related to operations, debt service requirements, income taxes, all cash dividends, transfers to the Treasury, and variation in working capital other than cash excluding provision for depreciation and other non-cash operating charges. Capital expenditures means the sum of all expenditures incurred on account of fixed assets, including interest charged to construction; (h) Debt Service Coverage: defined as the ratio between gross internal cash generation (excluding customer contribution and consumer deposits) and total debt service requirements. 2. Monitoring: Attachment I shows the expected evolution of these indicators. 151 Attachment 1 COLOMBIA POWER MARKET DEVELOPMENT PROJECT MONITORING INDICATORS - EXPECTED VALUES Indicator 1995 1996 1997 1998 1999 2000 2001 2002 2003 Weighted Average frequency of <2.0 <2.0 <2.0 <2.0 <2.0 <2.0 <2.0 <2.0 <2.0 Interruption Weighted Average Length of <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 <1.0 Interruptions (hrs.) Average Interruption time (hrs.) 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 Reliability Index (%) 98.6 98.6 98.7 98.8 98.8 98.8 98.8 98.8 98.8 Total Transmission Losses (%) <2.5 <2.5 <2.5 <2.5 <2.5 <2.5 <2.5 <2.5 <2.5 Debt Service 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 Coverage (" Cash operating ratio(l) 20 20 20 20 20 20 20 20 20 (%) Self-financing Ratio ( 30 30 30 30 30 30 30 30 30 (%) Accounts Receivable 60 60 60 60 60 60 60 60 60 (days) (1) Indicator covered by legal covenant. (The cash operating ratio agreed in the covenant ratio is 23%). 152 COLOMBIA ISA POWER MARKET DEVELOPMENT PROJECT ENVIRONMENTAL MONITORING INDICATORS Indicators 1995 1996 1997 1998 1999 2000 2001 2003 1. Completion of Environmental Assessment (EA) for each transmission line before inviting Yes Yes Yes Yes Yes Yes Yes Yes bids for construction. 2. Preparation of an Environmental Project Implementation Manual for 100% Transmission Lines 1 3. Execution of all actions determined in the Environmental Management Yes Yes Yes Yes Yes Yes Yes Plan (EMP) 4. Ratio families relocated/displaced 100% 100% 100% 100% 100% 100% 100% The Project Implementation Manual should be prepared prior to starting construction of the San Carlos-San Marcos transmission lines. 153 ANNEX 16 COLOMBIA POWER MARKET DEVELOPMENT PROJECT SUPERVISION PLAN Approx. Dates Special Activity in the Staff (Month/ Supervision Mission Skill Requirements Input Year) (SW) Jan/96 Project Launch Power Engineer, Financial Analyst, 6 Environmental Specialist Apr/96 Annual Formal Review Meeting Power Engineer, Financial Analyst, 5 Review Project Implementation Environmental Specialist Program Oct/96 Review Procurement Plan Power Engineer, Financial Analyst, 5 Review TA development Environmental Specialist Apr/97 Annual Formal Review Meeting Power Engineer, Financial Analyst, 5 Review Project Implementation Environmental Specialist Program Oct/97 Review Project Implementation Power Engineer, Financial Analyst, 5 Review TA development Environmental Specialist Apr/98 Mid-term Review Meeting Power Engineer, Financial Analyst, 5 Review Procurement Plan Environmental Specialist Oct/98 Review Project Implementation Power Engineer, Financial Analyst, 5 Review TA Development Environmental Specialist Apr/99 Annual Formal Review Meeting Power Engineer, Financial Analyst, 5 Review Project Implementation Environmental Specialist Oct/99 Review Project Implementation Power Engineer, Financial Analyst, 5 Review TA Development Environmental Specialist Apr/2000 Annual Formal Review Meeting Power Engineer, Financial Analyst, 5 Project Implementation Environmental Specialist Oct/2000 Review Project Implementation Power Engineer, Financial Analyst, 5 Environmental Specialist Apr/01 Annual formal Review Meeting Power Engineer, Financial Analyst, 5 Project Implementation Environmental Specialist Oct/01 Review Project Implementation Power Engineer, Financial Analyst, 5 Environmental Specialist ANNEX 17 COLOMBIA POWER MARKET DEVELOPMENT PROJECT Allocation of Loan Proceeds The proposed disbursement categories, the allocation of loan funds for each of the fixed and floating rate single currency loans, and the disbursement percentages are as follows: Category Floating Rate Currency Pool % Expenditure to be Financed Loan Loan Total (USS million) Works 24.0 17% 1.0 1% 25.0 90% Goods (Part A)(') 0.1 0.1% 9.9 9% 10.0 100% of foreign exp. and 90% of local ex-factory Goods (except Part A) 60.0 41% 43.6 42% 103.6 100% of foreign exp. and 90% of local ex-factory(2) Equipment and Instalation 25.0 17% 18.0 17% 43.0 95% of foreign exp. Consultant Services (Part A) 0.1 0.1% 0.4 0.5% 0.5 100% of foreign exp. Consultant Services 0.1 0.1% 4.4 4% 4.5 100% of foreign exp. (except Part A) Training 0.1 0.1% 0.9 1% 1.0 100% of foreign exp. Interest and other changes under 21.4 14.8% 15.4 15% 36.8 100% the Bank loans Unallocated 14.2 9.8% 10.7 11% 24.9 TOTAL 145.0 100% 104.3 100% 249.3 ( Part A: Energy Control Center and Financial Settlement Center (2) Except equipment. 155 ANNEX 18 COLOMBIA POWER MARKET DEVELOPMENT PROJECT SELECTED DOCUMENTS AND DATE AVAILABLE IN THE PROJECT FILES 1 PEN - Plano Energético Nacional, Unidad de Planeación Minero Energética - mayo de 1994 2 ISA - Informe Anual 1993; Informe Anual 1994 3 Sistema Eléctrico Colombiano - Balance Energético Histórico 1977-92, ISA - junio de 1994 4 Estrategias para el Desarrollo y la Expansión del Sector Eléctrico 1995-2007, documento COMPES - 2763, febrero de 1995 5 Plan de Expansión de Referencia Generación y Transmisión1995-2004, MME- 1993 6 Informe de Restricciones Ambientales - Tercer Plan de Transmisión y Proyecto La Loma, ISA, abril de 1994 7 Evaluación Sectorial Ambiental - Sector Eléctrico Colombiano, ISA-MME - 1994 8 Metodología para la Previsión de la Demanda de Energía Eléctrica, Documento UPME-E-004/95 -enero de 1995 9 Estrategia Tarifaria de Energía Eléctrica - Objetivos a mediano y corto plazo, documento JNT- 1215, mayo de 1993 10 COLOMBIA - The Financial Conditions of the Electric Sector and Actions Needed to Reach Creditworthiness, Xavier Nogales (consultant), November, 1993 11 PIP - Project Implementation Plan - Plan de Implementación del Proyecto de Expansión de la Transmisión, ISA - mayo de 1995 12 Desarrollo de las Medidas Tomadas por el Gobierno en el Sector Eléctrico Colombiano Durante los Ultimos Años, MHCP - septiembre de 1994. 13 Terms of Reference for technical assistance.  iBRD 26929 78- 74 COLOMBIA NICARAGUA POWER TRANSMISSION SYSTEM COSTARICA VENEZUELA r 12 POWER MARKET DEVELOPMENT 12..A L ;-- - '¯OLOMBI ( TERMOc F-ESTE -TAS S,; a rë, SANTA 'ARTA GUAJiRA i de Bogo. c flARR ANOUJlllA0- UATRI ECUADOR? II FUIN[DA N 1-FNTEtJARý LARTAGENA SABANA E r- B R A Z l L LARGA U -1 PANAMA P E R CHiNU BOLIVIA LÅRÅ 70 -_ ~'~A E \) MA0 50 100 15 MILES @------ /ERROMATC/',-r______________ -8° URABA 8 TA' R 'EF, FL_¯-F ZC 0 100 200 K|LOMETERS Et SA,T UMADAL R C p ~EANA A r_N aggRA Rec VENEZUELA M,RAFLORES / ENA ANCON ÅVÅ l CU D ENTE E 9. . 4Ls\ VIRGýNiA CARTAGO SELEGTEOCIIES BRAZI ALTO ANCHICAYA T N IERNARD N I JUNIN E C U 0 A D ONDR c' -0 0 ®NATIONAL CAPITAL •SELECTED CITIES RIVERS B R A Z l L ----INTERNATIONAL BOUNDARIES EXPANDED UNDER UNDER PER PROJECT PROJECT FUTURE CONSTRUC-I N EVICt/ ,.T C, PLIRU . 0 * SUBSTATIONS * 0 * GENERATION PLANTS 4 - --- - 500 kV TRANSMlSSON LINES 4 'h, dounda,aries co, enominalion, and any olhe, informeco 230 kV TRANSMISSION LINES , ,,, t' ,op d-ot oply on ihe oto f Thre world Bsc , f u Group n Idgment c, the ego| Ious ol any, tertitor, or any 78 74 - 70 endor,emedt ot o:eplan:c o/ sucr hbondar e' MAY 1995   INAGING Report No: 13621 CO Type: SAR