Report No. 719a-CR ELE COPY Appraisal of the - - Fifth Power Project Costa Rica May 21, 1975 Regional Projects Department Latin America and the Caribbean Regional Office Not for Public Use Document of the International Bank for Reconstruction and Development International Development Association This report was prepared for official use only by the Bank Group. It may not be published, quoted or cited without Bank Group authorization. The Bank Group does not accept responsibility for the accuracy or completeness of the report. Currency Equivalents Official rate prior to March 30, 1974: Free rate prior to March 30, 1974 and off:Lcial rate thereafter: US$1 = 6.65 colones (0) US$1 = ¢8.6o ol = us$o.0 15 1 = us$0.12 ¢1,000 = us$150o 1,000 = US$116 01 million = US$150,376 01 million = US$116,279 Units and Equivalents kW = kilowatt MW = Megawatt = 1,000 kW kWh = kilowatt hour GWAh = Gigawatt hour = 1 million kWh kV = kilovolt kVA = kilovolt - ampere MVA = Megavolt - ampere = 1,000 kVA m = meter = 3.28 feet km = kilometer = 0.62 mile km2 - square kilometer = 0.39 square mile Acronyms and Abbreviations ALCOA - Aluminum Company of America CABEI - Central American Bank for 'Economic Integration CNA - Comision Nacional de Aluminio CNFL - Compania Nacional de Fuerza y Luz DEL - Direct Exchange Line ENALUF - Empresa Nacional de Luz y] Fuerza (Ilicaragua) FIV - Fondo de Inversiones de Venezuela ICE - Instituto Costarricense de Electricidad IDB - Inter-American Development Bank RACSA - Radiografica Costarricense S. A. SNE - Servicio Nacional de Electricidad Fiscal Year Ends December 31 APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE D)E ELECTRICIDAD (ICE) Table of Contents Page no. Summary and Conclusions i 1. Introduction 1 2. The Sector 3 Energy resources 3 Organization of the electric power sector 3 Electricity consumption, rural electrification and tariffs 4 Sector development 5 3. The Program and Project 7 Program through 1982 7 Description of the project 7 Estimated cost and financing 9 Engineering 10 Project execution 10 Procurement and disbursement L1 Environment 11 Project risks 12 4. Justification of the Project 13 Greneral 13 Demand and generation forecast 13 Least cost solution 14 Return on investment 14 5. The Borrower 16 Organization, management, staff and training 16 Organizational separation 16 Construction activities 16 6. Finance 18 Summary 18 Accounting systems and auditors 18 Revaluation 18 Power section financial results 19 CNFL financial results 20 Power section finRncing plan 20 Future financial position of ICE power section and CNFL 22 ICE telecommunications section finances 22 7. Recommendations 24 This report has been prepared by Messrs. John E. Graves, Manfredo Linder and Andre Leoni. List of Annexes 1. Details of Previous Bank Lending to ICE 2. Organization and Regulation of the Electric Power Sector 3. Performance Indicators 4. Electricity Tariffs in Costa Rica 5. Boruca Hydroelectric Development 6. Arenal Hydroelectric Development 7. Description of the Project 8. Estimated Schedule of Loan Disbursements 9. Demand, Generation and Sales Forecast 10. Dry Season Energy Requirements 11. Least Cost Solution 12. Return on Investment 13. Organization, Management and Training 14. Power Section Financial Statements and Forecas,ts 15. CNFL Financial Statements and Forecasts 16. Telecormunications Sectloh Financial Statements and Forecasts Map - World Bank - 11454 APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Summary and Conclusions i. This report appraises the filth power project of the Instituto Costarricense de Electricidad (ICE), which has reqaested Bank assistance in its financing. ii. Since 1961 the Bank has provided major financial assistance to Costa Rican power development through four loar-s to ICE totalling US$39.8 million. The first three projects have been completed, although with delays and cost overruns (see paragraph iv). Most components of the fourth project, which involves no major civil works, are in service. Completion of the rest is expected by year-end 1976, one year be- hind schedule. Through its power lending, the Bank has stimulated improve- ments in 1iJUity regulation in Costa Rica and in ICEts organization. Par- tially as a result of discussions with the Bank, 1CE has recently eompleted Costa Ricats first national riral electrification plan, which wouild ex,ead electric service to about 16,000 customers, increising rural coverage from 50% to 63% by 1979. iii. ICE, a government-owned autonomous institution, is also responsi- ble for telecommunications development, for which it has received four Bank loans totalling US$57 million. The first two of its telecommunications pro- jects have been completed successfully, and the second two are progressing satisfactorily. iv. In the past, the Bank has been particularly concerned about ICEts insistence on planning, engineering and constructing its projects with its own forces and about serious cost overruns and delays in construction works. The most serious overruns were encountered in the Tapanti tunnel financed under the third Bank-financed project. While unforeseeable adverse geological conditions beyond ICE's control were the main cause of overrun, ICE might have lessened the extent of the problem somewhat by hiring consultants before the problem arose. ICEVs experience has resulted in its taking some remedial actions in recent months. Instead of relying solely on its own staff for design and construction of the Arenal development (financed by a US$50.5 million Inter-American Develop- ment Bank loan approved in January 1975), ICE has called for consultantsO assist- ance where it has no experience (e.g., in designing the dam, studying seismologic conditions and using geophysical procedures to analyze subsurface conditions in the tunnel area), and it has or is planning to put the most important Arenal con- struction jobs (viz, the dam and penstock) out to tender. While these steps reduce the possibility of inadequate design and construction of the major project components, it is still expected that the Arenal project will be finishpd a year behind the original schedule and with significant cost overruns. However, ICE's difficulties have been related to major civil works (such as tunnels and dams), not minor ones (such as powerhouse construction or extension), equipment instal- lation or transmission line erection. Because the Bank-financed project described below does not include major civil works, project execution should be well within ICE's capability without the aid of consultants. - ii - v. The project represents ore third of ICE's power construction progran for 1975-78, the largest component of which is the 135 MW first stage of Arenal. The project includes: 62 ThT in extensions to ICE's Rio Macho and Cachi hydro plants, both previously built with Bank- assistance; a new 30 1U diesel plant at Mo_n on the Cari'bbean coast (or a transmission line to interconnect its system with the Nicaraguan utilivty's as an alternative to the diesel plant, if arrangements necessary to build the line can be completed in time); trans- mission worzTs related to both Arenal and the generating facilitles included in the project; extensions of transmission/distribution networks; and stuldies. The project's est'mated cost and f4nancing requirement are IJS$46n and UTS$70 milldon, respectively, including foreign components of US$Lh and JS$52 million respectively. It is scheduled to be completed by year-end 1978. v;. The proposed US$bI1 m;llion loan would cover about 79' of the pro- ject's foreign financing requirement. A US$11 million loan from the Central American Bank of Economic Integration (CA3EI), or supplier :inancing if part of the CAB;Fr loan were not available, would corer the balance. TCI. would lise net internal cash veneration, proceeds of oonds sold to local investors and loans from the Fondo de inversiones de Vene-euela and CABEI to meet the local costs of its program., including the oroject. Its financing plan is satis- factory. vii. ICE's Dower staff will engineer all works incluided in the project and install most of t'hem.. This arrangement is satisfactory, as no major civilt workTs are involved and ICE has experience wiLth the ty,pe of works it proposes to undertake. Xr;ii. Procurement of Bank-financed items wouldl be throlugh international competitive bidding in accordance with the Bankqs guidelines. Because of the need to install the hydro units included in the project as soon as pos- sible to replace costly thermal generation and the lead time involved in the manufacture of su^~h units, TCE might sign contracts for them prior to loan signing; retroactive financinFg of US$1.5 million for their down payments is recormmended. ix. Over the longer term, ICE is expected to participate in regional power development. To this end, ICE and the Nicaraguan utility are studying interconnection of their systems and a large hydro development on the San Juan river, which forms the border between the two countries. For the immediate future, however, most or all of Costa Rica's electricity needs would be served by its own resources, including the project. Tne purposes of the project are to replace as much expensive thermal generation as possible by installing hydro units at existing plarnts, thereby offsetting the adverse mpa_t of the energy crisis, to provide necessary dry season capacity prior to com- pletion of th,e Arenal hydro development, and to improve the quality of elec- tric service 'n Costa Rica. The Bank would alsc cortinr) to pursue its oejectives of stimulating further improvements (see paragraph ii) in ratio- nalizing Costa Rica's powei sector and the regulation thereof, and In providing riral electrification. The generating components of the project represent the 'east-cost solution to meeting Costa Ricats power needs for di.scount rates of up to 21 , and thie t-asnsission components, for all discount rates. The rate of return ora the generation components and associated trans,mission works of the project investmert is estimated to be at least 15 %. - iii - x. For the time being, ICE is able to serve the two sectors - power and telecommunications - reasonably satisfactorily because of the organiza- tional autonomy of its power ard telecommunications departments. xi. ICEts power section has recovered from severe financial difficulties in 1973-714 caused in large part by cost overruns of the third project. The Financlal performance of its telecommunications section has always been strong. To establ4ish power and telecommunications tariffs which adequately reflect recent severe price inflation r Costa Rica, ICE has put into effect a full revaluation of its power and te]. o:rnmunications rate bases and applied for telecom-municat;ions tariff increases (no power tariff increases are necessary now). Assuming that tariff adjustrPor'.s sufficient to produce rates of return of 9' and 12'^ respectively on revalued power and telecommunications rate bases are put into effect as promptly as necessary in the future, the finiaicial per- formance of both sections is expected to .e satisfactory during the project period. xii. The project would form a suitable basis for a US$1l million loan with a term of 25 years including four years of grace. The loan would be made to ICE and guaranteed by the Republic of Costa Rica. I APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) 1. Introduction 1.01 This report appraises the fifth power project in Costa Rica, for which the Instituto Costarricense de Electricidad (ICE) has sought Bank assistance. 1.02 The project represents one third of ICE's power construction pro- gram for 1975-78, the largest component of which is the first stage (135 MW) of the Arenal hydroelectric development, whose foreign cost is to be financed by the Inter-American Development Bank (IDB). The project includes: 62 K4 in extensions to ICE's Rio Macho and Cachi hydro plants, both previously ,uilt with Bank assistance; a new 30 MW diesel plant at Moin on the Caribbean coast (or a transmission line to interconnect its system with the Nicaragivtn utility's as an alternative to the diesel plant, if arrangements necessary tc build the line can be completed in time); transmission works related to both Arenal and the other generating facilities included in the project; extensions of trans- mission/distribution networks; and studies. The project's estimated cost is Us$60.3 million, including a US$44.3 million foreign component. The total financing required for the project is US$70.4 million, including a US$52 mil- lion foreign component. 1.03 The Bank has provided major financial assistance to electric power development in Costa Rica through four power loans totalling US$39.8 million, which have financed most of ICE's hydraulic generating capacity, much of its thermal capacity, and related transmission works (see annex 1 for details). The first three power projects have been completed, although with significant delays and cost overruns (see paragraph 5.05). The fourth project involves no major civil works; its principal components are in se-vice, and completion of its remaining components will be delayed about a year. - 1.04 In addition to financing works, the Bank, particularly in the fourth power project, has attempted to help resolve inefficiencies in Costa Rica's electric power sector, the most prominent of which have been an excessive number of electricity suppliers and regulatory difficulties (see paragral Is 2.05 following) and organizational difficulties within ICE (see paragraph 5.04). Satisfactory pirogress in the resolution of these problems has been made, and further progress is expected. The Bank would seek to extend this progress through the proposed loan by providing assistance in rationalizing the country's electric tariff structures (see paragraph 2.09). 1.05 The Bank has also made four telecommunications loans, also oetailed in annex 1, totalling US$57 million to ICE. The first two telecormmunications projects have been completed successfully, and the second two are proceeding satisfactorily. 1.06 The proposed US$41 million Bark loan would cover about 79% and 39% respectively of the project's and progral's (including Arenal) foreign re- quirements. The Central American Bank for Economic Integration (CABEI), or supplier financing if part of the CABEI loan were not available, would pro- vide the remaining US$11 million foreign financing for the project, ICE's net internal cash generation, sales of bonds to local investors and loans -2- from CABEI and the Fondo de Inversiones de Venezuela (FIV) would provide the program's local-currency requirements. 1.07 This report is based on a feasibility study of the project pre- pared by ICEts power section and on the findings of an appraisal mission composed of Messrs. John E. Graves, R. E. Salazar, Nikola R. Holcer, Manfredo Linder and Andrew Waldrop, which visited Costa Rica in December 1974. -3- 2. The Sector Energy resources 2.01 Costa Rica has no known coal reserves. Minor discoveries of oil have been made near Turrialba and south of Puerto Limon (see map), but these were not commercially significant. The government plans to begin offshore oil exploration in the Caribbean in association with a French firm; the timing of this program will depend on the availability of offshore drilling rigs. 2.02 Surface investigations have revealed the existence of geothermal deposits in Guanacaste. With a US$1 million grant/loan (under whose terms the amount drawn down is considered a loan only if the studies result in eventual construction of a generating facility) from IDB, ICE will engage consultants to study the possibility of using these deposits to generate electricity. The studies, which include subsurface exploration, are sched- uled for completion by year-end 1976. 2.03 Costa Ricats most abandant energy resource is hydroelectric. ICE has identified 37 sites with a potential of 10,000 MW and annual generation of about 50,000 GWh within the country, which represents about 30 times the country's 1973 power and energy demands. ICEts future plans focus on ocevelop- ment of the most economic sites, as discussed in paragraphs 2.10-12. Organization of the electric power sector 2.0h As detailed in anniex 2, ICE and its 92%-owned subsidiary, Compania Nacional de Fuerza y Luz (CNFL), are the largest sector entities; together, they generate 93< of the country's public-service electricity supply. The interconnected system, which serves Costa Ricats most densely populated area (see map), includes 10 other entities, the largest of which are juntas admi- nistrativas de servicios elfctricos of three municipalities near San Jose - Cartago, Heredia and Alajuela. About 35 entities, including ICE, serve iso- lated communities outside the interconnected system. 2.05 Previous Bank appraisal missions have observed that unsatisfactory sector organization and regulation were resulting in a lack of coordinated planning and standardization, inefficiencies associated with an excessive r:mber of utility enterprises and uneconomic tariffs. The fourth power project (loarn 800-CR) included funds for consultants tc study and recommend improvements c--mcerning sector orgarization, efficiency and regulation. The consultantst (TJrw4 ck Tnternational 1 the UK) findings, discussed in detail in annex 2, we>re: that ICE should initiate steps to absorb CLTFL as a first step in sector irTegration; and that Servicio Nacional de Electricidad (SNE), the regulatorr agency, should be disbanded. As indicated in annex 2, ICE, OTTFL and SIJE have begun to inprovre the situation, so that the more drastic stens proposed by Urwick are no longer necessary. 2.06 T;hile many sector problemis remain, the situation is improving. The total number of public-service electricity- entities has been reduced from 57 in 1971 to 45 in 1974, and further consolidation is expected in -4 conneetion with ICE's rural electrification progrEam (see paragraph 2.08). Portions of the interconnected system are prone to outage, sometimes for extended periods. The transmission works and load dispatching system in- cluded in the project are intended to improve this situation (see paragraph 4.01). ICE, through board membership and/or part ownership, participates in the major utilities, which - except in Cartago - provide adequate service. SNEts responsiveness to the utilitiest needs for tariff action has improved noticeably since late 1973; it approved in 197h, with reasonable speed, two electric tariff increases sufficient to provide ICE a reasonable return in the face of high price inflation and currency devaluations, as detailed in annex 2. Continued improvement is expected, particularly after completion of a study needed for rationalization of Costa Rican tariff structures (see paragraph 2.09). Electricity consumption, rural electrification and tariffs 2.07 As shown below, the electricity market cf Costa Ricats largest distributing utilities is predominantly residential. This market distribu- tion, which contrasts with the predominance of industrial sales in other Central American utilities' markets, reflects Costa Rica's higher per-capita income and better income distribution. Actual Estimated Projected GWh 1971 717 GWh 197 T rTWh 1979 GWh __ GWh Frw Residential 493 54 615 53 865 50 Commercial 1h2 16 193 17 314 18 Industrial 257 28 325 28 512 29 Other 23 2 31 25 3 Total 915 100 1,169 100 100 2.08 According to 1973 census data, about 210,000 households were re- ceiving electricity supply, representing over 90% and 505 respectively, of the urban and rural population. In most rural areas, installation of other types of infrastructure has proceeded more rapidly than electric supply faci- lities. To the extent that such facilities have been installed, this has been done without a national program, principally through establishment of co-operatives in silected areas(see annex 2), funded by the US Agency for International Development (USAID), IDM, the government and ICE. As a result of pressure from the Bank and government., ICE, which prior to 1974 had given a low priority to rural electrification, completed in April 1975 a feasibility study of a rural electrification program to provide electric service to over 16,000 new customers by 1979. ICE intends to apply for a loan of about US$13 million from IDBvs Fund for Special Operations to meet most of the US$17 lnl- lion cost of the program's first stage (1976-78); it would meet the balance of the cost from its own resources. As shown in annex 3, ICE expects that the market penetration of urban and rural areas in Costa Rica w111 increase to 94% and 63% respectively by 1979. 2.09 Rational sector development requires an orderly tariff structure. In Costa Rica, however, each distributing entity has its own tariff schedule; this diversity and the underlying reasons for it are described in annex 4. -5- Because ICEts and SNE's staffs lack experience in tariff-structure rational- ization, and because the other utilities might not accept such a study if prepared by ICE staff, the proposed loan includes funds for cpnsultants to study and make recommendations concerning tariffs and tariff structures in Costa Rica. As detailed in paragraph 4 of annex 4, the study would not only analyze tariff structures but also examine, (i) the declining-block-rate approach for residential consumntion, and (ii) prining incentives to stimu- late offpeak electricity consumption. In the proposed loan agreement, ICE would covenant to submit proposed terms of reference for the Bank's review within one month of the loan's effectiveness, to engage consultants within six months of the Bank's approval of the terms of reference, to make the study available to SNE and to discuss the cunsultantst findings with the Bank and SNE promptly upon conclusion of the study. SNE has confirmed that it will cooperate with the consultants and discuss their findings with the Bank pi'omptly upon conclusion of the study. Sector development 2.10 In order to meet its incremental electricity needs in the immediatoŽ future, i.e., until completion of the 135 MW first stage of the Arenal hydro development (see cthapter 3), ICE will need to supplement its hydroelectric resources by thermal generation as required during the dry season. Once Arenal is put into service, ICE would use the country' hydro (and geothermal, if viable) resources to meet its electricity needs fo. the foreseeable future, replacing thermal generation except for peak loads 2.11 Based on presently-available informatior., the next step after Arenal would be the first stage (156 MW) of the Santa Rosa hydro development, down- stream from Arenal and to be put into service in 1982, for which ICE would seek Bank financing in 1977. ICE tentatively plans to have in operation by 1985 the 140 W Angostura hydro development, a run-of-river scheme near Turrialba which was expected to be the next development at the time of the previous power appraisal (as indicated in report PU-77a dated January 19, 1972) but subsequently was found to be a higher-cost alternative than Arenal, which also has the advantage of inter-annual storage capability. 2.12 However, favorable results of studies or negotiations currently in progress or to be carried out in the future could alter ICE's generation plans. These include: a. studies of Costa Rica's geothermal resources (paragraph 2.02); b. conclusion of negotiationis with Aluminum Company of America (Alcoa) on the Boruc) hydr. developmenrt (annex 5), in which ICE is expected to propose that the hydro plant also provide some firm power to Costa Rica's public supply system as well as meeting the needs of the aluminum smelter; c. studies of a possible interconnection of the Costa Rican and Nicaraguan power systems. These studies are to be executed by Kennedy & Donkin of the UK, which was selected by ICE and Empresa Nacional de Luz y Fuerza (ENALUF) of Nicaragua, using a US$100,000 grant/loan from CABEI; and - 6 - d. studies of the Rio San Juan hydro development on the Costa Rica-Nicaragua border, whose output would presumably be used by both countries. -7- 3. The Program and Project Program through 1978 3.01 ICE's power construction program through 1978 includes: a. completion of transmission works included in the fourth power project (loan 800-CR) and other projects financed by IDB and CAREI (mainly the Cachi-Moin transmission line financed by CABEI); b. the first (135 MW) stage of the Arenal hydro development (see annex 6); c. the fifth power project, described below; d. initial construcoion of the first (156 NW) stage of the Santa Rosa hydro plant, downstream from Arenal (see annex 6); and e. miscellaneous transmission, subtransmission, distribution and isolated generating works to be financed and carried out by ICE itself, plus a rural electrification program (paragraph 2.08). As noted in paragraphs 2.11-12 TCE's program for future generating develc- ments is subject to change because of negotiations and studies currently under way. Description of the project (see annex 7 for detailed description of the works) 3.02 The fifth power project consists of the following items: a. Generation facilities: i. extension of the Rio Macho hydro power plant by one 30 MW unit; ii. extension of the Cachi hydro power plant by one 32 MW unit; iii. construction of a 30 MW diesel plant, fuel tank and substa- tion at Moin on the Caribbean coast, or the Costa Rican portion of a transmission line and related substation equip- ment to interconnect ICE's system with ENALUF's (see para- graph 3.03); ana iv. construction of a furl tank at ICE's San Antonio generating plant. b. Transmission works: i. transmission lines and substations related to the Arenal hydro plant; -8- ii. additions to existing transmission lines and substations related to the Rio Macho and Cachi extensions; iii. completion of the transmission-distribution ring around the metropolitan area of San Jose, and related distribution equipment (ICE would acquire certain of the distribution items and subsequently transfer them to CNFL); iv. new transmission facilities to serve new or increased loads outside San Jose; and v. a load dispatching system. c. Studies: i. of Costa Rica's tariff stiucture (paragraph 2..09); ii. of the electric system's stability; and iii. to prepare the specifications for the proposed load- dispatching system. ICE has agreed to engage consultants acceptable to the Bank for the three studies, which are estimated to require forty man-months of consultants' time. 3.03 Electricity demand in Nicaragua has not met expectations princi- pally because of the effects of the December 1972 earthquake. Consequently, ENALUF will have surplus energy and capacity (over and above its own needs and projected sales to Honduras) through 1979, which would be more than sufficient to meet ICE's dry-season needs during those years. If it could be completed in time, construction of a 220 kV 90 km interconnection line between ENALUF's and ICE's systems would be a lower-cost solution than the Moin diesel plant to meet ICE's dry-season power needs until the commis- sioning of Arenal. Substitution of the interconnection for the Moin plant would also increase the break-even discount rate and rate of return of the other project components because it would enable ICE to sell surplus wet- season energy from its run-of-river plants to ENALUF, replacing the latter's thermal generation. Difficulties are foreseen, however, in completing con- tractual arrangements between the two utilities soon -enough to have the line in service by January 1, 1977. Consequently, while the proposed loan agreement provides for the inclusion of either the interconnection line or the Moin plant in the project, the Bank has indicated to ICE that it wiLll select the Moin plant if ICE and the government submit satisfactory evidence that, despite their rea- sonable efforts to finalize arrangements, completion of the transmission line by January 1, 1977 is urnlikely. The Bark would make its decision by October J, 1975, by which date contractual arrangements for the MoiLn plant must be final- ized if it is to be placed in service by the beginning of 1977. - 9 Estimated cost and financing 3.o4 The project's estimated cost is US$60.3 million with a US$44.3 million foreign component. Including interest during construction the corresponding figures are US$70.4 million and US$52.0 million. The base costs were estimated by the Bank together and in agreement with ICE's technical personnel, based on information gathered in the Bank and recent quotations from manufacturers re- ceived by ICE and updated to second quarter 1975. The costs are summarized below: Colones (millions) US$ (millions) Local Foreign Total Local Foreign Total Rio Macho extenbon A.7( 33.06 39.81 o.64 2.97 3.61 Cachi extension 17.10 48.08 65.18 1.65 h.21 5.86 Moin Diesel plant including substation and fuel tank 12.90 81.00 93.90 1.27 7.98 9.25 San Antonio fuel tank 0.h1 1.32 1.73 0.oh 0.13 0.17 Transmission related to Arenal 27.71 90.35 118.o6 2.51 8.07 10.58 Transmission related to Rio Macho and Cachi 6.15 '8.23 24.38 0.59 1.76 2.35 San Jose ring and distribution equipment 17.06 46.25 63.31 1.57 4.49 6.o6 Extension of existing trans- mission equipment 20.68 42.65 63.33 1.83 3.90 5.73 Load dispatching equipment 2.58 13.68 16.26 0.22 1.20 1.42 Consultant studies 2.06 2.06 0.20 0.20 Sub-total 111 .3h 376.68 488. 19,.32 34.91 i5.23 Contingenci-i -physical 11.13 37.67 48.80 1.03 3.49 b.52 -price 51.96 64.75 115.71 h.66 5.91 10.57 Total project costs 174.43 479.10 $T3.53 16.C- 44.31 60.32 Financial charges 28.0' 89.76 117.83 2.39 7.69 10.08 Totnl financing required 202.50 568.86 771.36 18.40 52.00 70.4o 3.05 A physical contingency allowance of 10% was assumed for all project items. This was considered sufficient because no major civil works are in- volved. Local and foreign price inflation, estimated using the annual infla- tion percentages shown below, are reflected in the project cost estimates: International Local 1975 12 25 1976 10 20 177 8 15 1978 8 15 1979 8 10 - 10 - 3.o6 The foreign cost of the project would be financed as below: - - -millions of US$_ - _ IBRD CABEI Total Rio Macho extension 2.97 2.97 Cachi extension 4..21 4i.21 Moin diesel plant including substation and fuel tank 7.98 7.98 San Antonio fuel tank 0.13 0.13 Transmission related to Arenal 2.01 6.06 8.07 Transmission related to Rio Macho and Cachi 0.81 0.95 1.76 San Jose ring and distribution equipment 3.28 1.21 4.149 Extension of existing transmission equipment 3.90 3.90 Load dispatching equipment 1.20 1.20 Consultant studies 0.20 0.20 Sub-total 26.69 8.22 34.91 Contingencies -physical 2.67 0.82 3.49 -price 5.11 0.80 5.91 Financial charges 6.53 1.16 7.69 Total 41.00 11.00 52.00 Engineering 3.07 ICE's own staff will carry out the engineering necessary for the execution of the project. This is acceptable as there are no major civil works involved, and ICE has experience with similar works. Project execution 3.08 The execution of the project will be carried out as follows: a. ICE will request bidders for the diesel plant, fuel tanks and transmission lines to submit offers on both a furnish-and-install basis and a materials-and-equipment-only basis, tl-nreby enabling installation using its cwn forces (under the saperlv ior of sup- pliers, as necessary) when it proves econoznic; b. ICE's own staff under the supervision of suppliers will erect the hydraulic generating and substation equipment;. and c. ICE's construction crew will be in charge of the civil works in- volved in both hydro extensions and the power house of the Moin diesel plant. As detailed in paragraph 5.o5, ICE has experienced considerable delays and cost overruns in executing past projects. However, its difficulties have been related to major civil works (such as tunnels and dams), not minor ones (such as powerhouse construction or extension), equipment installation or transmission line erection. Because the project does not include major civil works, participation of ICE forces in its execution is acceptable. - 11 - The estimated project completion date is December 1978. Completion dates for the individual project components are indicated in annex 7. ICE has confirmed that it will make its best efforts to achieve satisfactory per- formance during the project period, as determined by the performance indi- cators shown in annex 3. Procurement and disbursement 3.09 All contracts for Bank-financed works, plant and equipment would be awarded following international competitive bidding in accordance with the Bank's Guidelines for Procurement. 3.10 Up to US$3.6 million equivalent of goods to be financed by the Bank loan, principally conductors for the transmission lines and construc- tion materials, might be obtained from manufacturers in the Central American Common Market, including Costa Rica. As in past operations Costa Rica has requested that such manmfacturers be granted a preference of 159 of the CIF landed price or 50% of the import duties, whichever is lower. In the case of Costa Rican manufacturers the Bank has agreed to reimburse ICE 95% of the cost of these possible local purchases to exclude t,he element of local taxes. 3.11 Disbursements from the loan account would be made for: a. the C&F cost of imported equipment and materials,including foreign currency costs of supervision erection; b. the foreign exchange costs of contracts awarded according to paragraph 3.08a; I c. the foreign exchange.costs of consultant studies; d. 95% of the ex-factory cost of contracts awarded to Costa Rican manufacturers; and e. financial charges on the Bank loan through September 30, 1978, the semi-annual repayment date preceding the estimated completion date of the project. 3.12 Because of the long delivery periods for hydraulic generating units and ICE's need to have the Cachi and Rio Macho units in operation at the earliest possible moment to replace thermal generation, ICE might sign con- tracts for the units prior to the assumed date (June 1975) of loan signing. Therefore retroactive financing of up to US$1.5 million for the down payments made after January 1, 1975 is recommended. Estimated loan disbursements are shown in annex 8. Because of the ongoing nature of transmision/distribution improvements, any unused loan balance could be applied to transmission/distri- bution extensions similar to those included in the project after consultation with the Bank. Environment 3.13 The physical location of the proposed Moin diesel power plant is in the vicinity of the existing oil refinery and sufficiently far from any existing or planned future urban development. With specifications concern- ing maximum sulfur dioxide emissions and thermal pollution control as _ 12 - suggested by the Bank included in the tender documents, the plant is not expected to cause any additional problems for the urban population or natural environment., With regard to the proposed new transmission lines, ICE intends to take care in routing these lines in order to minimize the visual impact. Project risks 3.14 During its first two to three years of operation, the Arenal plant will be linked to the load center through a transmission system, 86 km of which consists of a single-circuit 220 kV line. Should this single-circuit line fail during the dry season, ICE would have to shed some of its peak load for the period needed for line repair because it lacks alternative dry season generating capacity. ICE decided to accept the risk because: a. a single-circuit 220 kV IB-financed line already exists over 70 km of the route; b. a parallel line would cost about US$5 million; 'and c. double-circuit lines will be constructed in two or three years over a different route to transport electricity from the nearby Santa Rosa project to the load center, and from Arenal to Santa Rosa, providing the necessary security at that time. To minimize the risk for the intervening period ICE is taking the necessary steps to prevent line outages as far as possible. 3.15 As worldwide demand for hydraulic generating units has increased, delivery periods for this type of equipment have lengthened. A six-month delay in the 18-month delivery time estimated for the project's hydro units would require ICE to increase its fuel expenditures by US$2 to 3 million. 3.16 As indicated in annex 6, completion delays of at least one year are expected for the Arenal development. Further delays would necessitate load reduction (see paragraph 4.05). - 13 - 4. Justification of the Project General 4.01 Besides assisting the country in providing facilities to meet its future demand for electricity in the most economic manner (see paragraphs 4.03 ff.), the Bank's objectives in lending for electric power development in Costa Rica are: a. to help offset the adverse impact of the energy crisis on the country's balance of payments (see paragraph 4.02a); b. to improve the quality of electric service through more efficient system operation and more rapid response to outages (see para- graph 4.02d); c. to stimulate the government and ICE to accelerate a rural electri- fication program and consolidate the large number of public-service electricity suppliers (paragraphs2.06 and 2.08);,and d. to develop a rational nationwide tariff structure (paragraph 2.09) while maintaining suitable tariff levels (paragraphs 6.08 and 6.09). 4.02 The purposes of the project are: a. the two hydro extensions will replace expensive thermal generation based on imported fuel and provide peaking capacity; b. the diesel power plant is intended to meet increasing load during the dry season (January to May) in a critical hydrological year until the commissioning of the Arenal hydro power plant in late 1978. After that it is intended to be the main thermal generation reserve for the dry season, replacing the Colima diesel power plant (20 MW) and the San Antonio steam plant (10 MW), both of wiich will have reached the end of their useful life by then. The use of the higher-cost gas turbine power plants (San Antonio- 38 MW and Barrancas-40 MW, the only other thermal plants in the interconnected system) will be for peaking purposes; c. the proposed transmission/distribution works are needed to transport the electricity from the new generating sources to the load centers and to minimize losses, as detailed in annex 7; and d. the load dispatching system is intended to provide a more economic operation of the interconnected system and to obtain faster response to partial or complete system outages. Demand and generation forecast 4.03 Annex 9 gives details for energy generation and maximum demand for the interconnected system, actual and forecast, on an annual basis for 1968 through 1981 as prepared by ICE. This projection, which assumes an average annual 9.1% increase in generation from 1975 through 1981 and an average annual 8.5% increase in maximum demand, is reasonable. To meet these energy and demand requirements, ICE studied different alternatives and defined its installation program of generating facilities as described in paragraph 3.01. - 14 - 4.04 Costa Rica's hydrological conditions show a very clear difference between the rainy season- June through December - and the dry season - Jan- uary through May. Because all existing hydroelectric generation facilities are run-of-river developments, the interconnected system needs thermal sup- port during the dry seaso-n (in 1973, load shedding of 36 Glh was necessary during the dry season due to late commissioning of the San Antonio gas tur- bine plant and a critical hydrological year). Annex 10 shows the necessity for an additional 30 MAW of generating capacity to meet energy demands during the dry season of 1977 and 1978 (under critical hydrological conditions). 4.05 As shown in annex 6, a reasonable estimate for the commissioning of the first unit of Arenal is at the end of 1978. To allow for the contin- gency of a delay in the construction program of Arenal or the failure of any thermal unit during the dry season, ICE has agreed to prepare by the end of 1976 an energy conservation program satisfactory to the Bank, since addition of further thermal generating capacity at that time would be inadvisable (see annex 10). The conservation program might consist of modification of working hours, elimination or reprogramming of television shows, lowering of voltage, and reduction of commercial illumination. Least cost solution 4.06 As shown in annex 11, the Rio Macho and Cachi extensions are the least cost solutions for discount rates of 16.5% and 20.5% respectively when compared to thermal generation supplied by existing units using a crude oil price of US$9/barrel CIF. This corresponds to anFOB Middle East price of US$7.00 - 7.50, which is more than US$1.00 lower than the Bank's estimate of US$8.65 (in 1974 constant dollars) for projected long-term prices. No other hydro units could be installed as quickly as these units. For the proposed 30 MW thermal power plant, it was found that medium-speed diesel engines were the least-cost solution-for discount rates up to above 18% and the same crude oil price. Finally, it was found that the total generation facilities of the project are the least-cost solution for discount rates up to 21% and the same crude oil price when compared with an all-thermal alternative. 4.07 Tn analyzing the transmission works included in the project, it was found that, where alternatives existed, those selected were the least cost solutions for all discount rates. Return on investment 4.08 Two calculations of the rate of return - defined as the discount rate which equalizes the stream of expected revenues with associated costs - were carried out, as detailed in annex 12: i. the first calculation considers the generation components of the project and the associated transmission and distribution works. The rate of return on the project investment is 15.3%; and ii. the second consideis the total investment program, viz, the project plus the Arenal hydro development. The rate of return on the program investment is 11.8%. The economic rate of return is undoubtedly higher because the benefits to the final consumer are not measured adequately by the electricity rates which were used to calculate the benefit streams. These benefits include indirect - 15 - benefits to industry and cor.mmerce, whose production and employment depends on public-service electricity supply as a prime source of motive power and illumination; and the social benefits of residential and public uses of electricity for lightlng and refrigeration. The rate of return on the project investment of 15.3%, which is higher than the opportunity cost of capital in Costa Rica, indicates that even or the basis of current tariffs the prices paid by customers are, on average, greater than the marginal cost of supply. 4.09 The sensitivity analysis in annex 1.2 shows that the rates of return would be 14h6 and 10.7% respectively if investment and operating costs were assumed to rise by 10. - 16 - 5. The Borrower 5.01 The borrower would be ICE, a government-owned autonomous insti- tution originally established in 1949 to plan and carry out a national electrification program. A 1963 law empowered. it to provide telecom- munications service within the country, and subsequent; laws have authori- zed its participation in providing international telecommunications ser- vices. ICE is required to carry out its operations completely indepen- dently of the government, except for approval of tariffs and bond issues and is tax-exempt except for an assessment to pay SNE's operating costs. Organization, management, staff and training 5.02 The only substantial change in ICE's organization, which is described in annex 13, since the most recent appraisa:L report (no. 417a-CR, May 1974) is creation of the new post of executive president. The first appointee's presence in this post has strengthened ICE's top management. 5.03 ICE's total staff numbers approximately 4,0'DO, of which the power section has 1,300. At about 1.5 employees per Gli generated, this is a reasonably-sized staff, considering the need to retain a fairly large number of engineers and supervisors for construction. Unski-Lled construction labor is hired only when required. ICE's technical staff is capable of carrying out its power operations satisfactorily. As detailed in annex 13, ICE has developed a thorough training program for its employees in conjunction with Costa Rican training institutions. Organizational separation 5.04 Previous Bank missions had urged ICE to consider organizational separation of its two principal services, and ICE engaged Urwick to study this matter. As detailed in annex 13, Urwick found that separation offered no immediate overall advantages although it might be desirable in the long run. Independent of Urwick's recommendations, ICE in 1973 took an important step to- wards sectional independence by establishing three sulb-managers - for power, telecommunications and finance/administration - each reporting to the general manager. To allow the two operating sections to continue to have the flexi- bility necessary to meet the needs of their sectors, ICE has agreed to the continuing separate operation of and accounting for its power and telecom- munications sections, repeating similar provisions contained in the fourth telecommunications loan agreement (1006-CR). Construction activities 5.05 In the past, the Bank has been particularly concerned about ICE's insistence on planning, engineering and constructing its projects with its own forces and its deteriorating performance in carrying out construction works. The most serious overruns of those summarized below were encountered in the Tapanti tunnel, where unforeseeable adverse geological conditions were beyond ICE's control. - 17 - Approximate completion delay % cost Loan no. Project months % overrun 276-CR Rio Macho 5 8 16 346-CR Cachi 14 30 46 631-CR Cachi extension 21 58 91 631-CR Rio Macho extension (Tapanti) 18 30 88 800-CR San Antonio gas turbines- L 4 25 1 The above succession of disappointing results has resulted in some remedial actions being taken: instead of relying solely on its own staff for de- sign and construction of the Arenal development. TCE has called for con- sultants' assistance where it has no experience (e.g., in designing the dam, stulyl ng seismologic conditions and using geophys -al procedures to analyze subsurface conditions in the tunnel area), and it has or is planning to put the most important Arenal construction jobs (viz, the dam and penstock) out to tender. While these steps reduce the possibility of inadequate design and construction of certain project components, they provide little assurance that the project will be finished when needed or that its overall cost estimate, if reasonable, will be met. As detailed in annex 6, ICE's com- pletion and cost estimates for Arenal, on which IDB based its appraisal report, were over-optimistic, so that we dlready expect significant comple- tion delays and cost overruns (1 year and 25% respectively), even before principal construction has begun. During project super ision, the Bank would discuss with ICE t1- advisability of engaging an indepenident engineer- ing consultant for overall project planning, sre eduling and .ost es'Lll1ting of any future project involving significant civil construction. * The intended installation of the gas turbines was advanced from the end- 1973 date shown in the appraisal report to beginning-1973 to meet dry- season requirements, but actual commissioning did not take place until April 1973. In any event, the project is not comparable with the others .because no major civil works were involved. - 18 - 6. Finance Summary 6. 01 ICE's power section has recovered from se-vere financial diffi- culties in 1973-74 (paragraph 6.08); but its contribution-to-expansion ratio for the project period is somewhat low, in part because of those difficulties (paragraph 6.10). The financial performance of the telecom- munications section has always been strong (paragraph 6.18). ICE has com- pleted revaluation of its power and telecommunications assets necessary to reflect recent high rates of worldwide and local price inflation, and the proposed loan agreement provides for tariff increases to enable ICE to earn a fair return on its revalued rate bases. Assuming that future re- valuations and tariff adjustments resulting therefrom are put into effect promptly, the financial performance of both of ICE's operating sections is expected to be satisfactory during the project period. Accounting systems and auditors 6.02 ICE's accounting systems are well-designed, enabling it to pre- pare detailed reports reasonably promptly. It is studying Urwick's sug- gestions concerning budgets and financial controls with a view toward improving them. 6.03 ICE's external auditor (Peat, Marwick, Mitchell & Co.) has ob- jected to Bank suggestions that ICE's foreign debt should be valued on the basis of worldwide floating exchange rates existing at the date of statement preparation (on the grounds that floating rates cause such valuation to be valid only momentarily) and that its assets should be revalued to reflect recent sqvere Costa Rican inflation, as detailed below. The firm has suggested that it might qualify its certification of financial statements wnich reflect asset revaluations, other than those to compensate for changes in the exchange rate of the colon with respect to the US dollar; this would be a subject of further conversations during loan supervision. The proposed loan agreement repeats provisions that annual audited financial statements and auditor's reports for both ICE and CNFL will be provided to the Bank within four months of the close of their f'iscal years. Revaluation 6.Q4 The central issue concerning ICE's finances has been revaluation. Beginning in mid-1973, prices in Costa Rica have increased by at least 25% annually, and higher-than-worldwide inflation rates, ar expected to prevail in Costa Rica throughout the project period (paragraph 3.05). The need for revaluation of ICE's assets was recognized by the previous appraisal mission; in the fourth telecom)munications loan agreement (1006-CR), ICE agreed to re- value its telecormunications assets by October 1, 1974. Such revaluation was to have been the basis for a tariff adjustment to increase ICE's telecom- munications revenues by 50%, which was considered necessary by the appraisal mission and ICE. 6.05 However, ICE failed to carry out its telecommunications revaluation by the specified date and requested the 50% tariff increase on the basis of cash needs for its expansion program. It received only about 30%, which was sufficient to give it a 13% return for 1975 on its still-unrevalued rate base but only 10.5% on a revalued rate base. This would be less than the 12% return covenant in the 1006-CRP loan agreement. - 19 - 6.06 After further discussions with the power appraisal mission, ICE has completed a revaluation of all its assets based on the following indices: a. for local costs: consumer price indices prepared by Costa Rica's Direccion General de Estadistica y Censos; b. for foreign costs of electric plant: construction/installation cost indices prepared by the US Bureau of Reclamation; and c. for foreign costs of telecommunications plant: installation cost indices based on its own records. Future use of these broad indices will permit ICE to prepare a reasonably accu- rate estimate of the current value of its power and telecommunications rate bases promptly and to systematize the revaluation process in a consistent man- ner without undue effort. The revaluation, which increased the end-1974 values of ICEts electric and telecommunications rate bases by 48% and 42% respectively, is satisfactory. 6.07 In its revaluation report, ICE has shown that its existing electric rates (which were increased substantially in 1974 -see paragraph 12 of annex 2) are sufficiently high to meet its rate-of-return covenant (see paragraph 6.08) in 1975, but that the telecommunications section would need the balance of the tariff increase - about 20% - which it was not granted in 1974 to meet its rate-of-return covenant. ICE has requested SNE to grant the telecommunications tariff increase as originally requested. W-hile CNFL has begun discussions with SNE concerning methodology to be used in revaluation of its assets, com- pletion of such revaluation is expected to require several months. To ensure that all necessary actions concerning the initial asset revaluation are car- ried out promptly, the Bank should not declare the loan effective until it has been notified that telecommunications tariff increases sufficient to per- mit ICE to earn a 12% return on its revalued telecommunications rate base have been put into effect and that CNFL has revalued its assets in a satis- factory manner. With respect to future revaluations, ICE has agreed to: revalue its power and telecommunications assets, and cause CNFL to revalue its operating assets, annually in a manner satisfactory to the Bank; reflect, and cause CNFL to reflect, such revaluations in its books of account; reflect, and cause CNFL to reflect,in its books of account the value of its foreign debt in accordance with exchange rates prevailing at the date of financial statement preparation. Power section financial results 6.o8 Principally because of third power project cost overruns (para- graph 5.05), ICE's power section was in severe financial difficulties in 1973 and early 1974. As a result of Bank suggestions concerning tariff increases and refinancing its heavy commercial debt burden, its financial situation has improved to acceptable levels by year-end 1974, as detailed in annex 14. Assuming that the power section implemests annual asset revalua- tions sufficient to compensate for expected local inflation (paragraph 3.05) and receives tariff adjustments sufficient to earn 9% on its revalued rate base, its financial performance is expected to improve throughout the pro- ject period. To ensure satisfactory financial performance, the proposed - 20 - loan and guarantee agreements repeat provisiorns conta-ela in e r,ets related to the fourth power project (loan 800-CR), whereby ICE agreed to apply for tariff increases sufficient for it to earn 9<' on its revalued rate base, and the government agreed to take all necessary action to en- sure that tariff-increase applications would be resolved satisfactorily. SNE has indicated that it will approve any tariff increase application designed to enable ICEts power section to earn 9N on its reva-1Jed rate base within 90 days of its submission. CN.i'L financial results 6.09 As detailed in annex 15, CNFL9s previously adequate operating results declined in 197h, when its rate of return was under 5$. CNFL received tariff increases to correct this situation early in 1975. The proposed loan and guarantee agreements repeat existing covenants to the effect that CNFL's tariffs will be set to provide sufficient revenues to comply with its concession agreement,-which is based on cash needs for construction after meeting debt service and dividend requirements. Power section financing plan 6.10 During the four-year project period 1975-78l, the power sectionts net internal cash generation, assuming implementation of required tariff increases, will finance about 21% of its construction program plus additions to working capital. This contribution-to-expansion ratio would be considered too low if it were not for the following factors: a. despite the refinancing of its medium-term debt, originally incurred to meet cost overruns of the third power project, the power sectionts debt service is still abnormally high; and b. its construction program includes transmission works deferred from the early 1970s because of third power project cash re- quirements and hydro units whose planned installation dates have been brought forward because of increases in fuel costs. Were it not for these factors, the power section's contribution-to-expansion ratio would approach a satisfactory 30%. The following table presents a sum- mary financial plan, details of which are shown in the projected funds state- ment included in annex 14. The Boruca hydro development (annex 5) and the rural electrification program (paragraph 2.08) have not been included because separate funding would be established for all of the Boruca project and most of the rural program, and because the latter would incorporate additions to the systems of various cooperatives as well as ICE's. - 21 - Financing plan 1975-78 - - - millions - - - Requirerients of funds Colones US$ % Construction program: Existing projects, continuing works and studies 95 8.6 Arenal hydro project 1,109 100.5 Fifth power project* 769 70.1 Santa Rosa hydro project (partial) 261 21.7 Total construction 2,234 200.9 96 Increase in working capital 95 8.9 4 Total requirements 2,329 209.5 100 Sources of funds Net inco'me before interest plus depreciation 1,155 104.9 Less debt service 666 61.1 Net internal generation 49 21 Contributions 16 1.4 1 Borrowings: Proposed: IBRD 444 41.0 19 CABEI 156 13.5 6 FIV 275 23.8 12 Local 114 10.8 5 Total proposed 989 T9J Existing: IDB (Arenal) 549 50.5 24 Other 148 13.9 7 Future (Santa Rosa) 138 11.1 5 Total borrowings 162.6 277 Total sources 2,329 209. 100 * Project expenditures of 02.7 (US$0.3) million were made in 1974. 6.11 The proposed Bank loan would be made to ICE for a term of 25 years including four years of grace at the current Bank interest rate, assumed to be 8.5% p.a. It would be guaranteed by the Republic of Costa Rica. 6.12 ICE has applied to CABEI for an 8% 15 year (including four years of grace) loan of US$11 million to finance the balance of the project's foreign cost. and for US$2.5 million equivalent in local currency for part of its local cost. CABEI's management has notified the Bank that it will recom- mend to its board of directors that the project be considered for financing. Prior to declaring the loan effective, the Bank should be noti- fied that CABEI has approved at least the foreign-currency component of the loan. If, because of possible other high-priority demands on its limited funds, CABEI were not able to supply the entire US$11 million foreign com- ponent, the Bank would be prepared to consider supplier financing if it could be arranged on satisfactory terms. 6.13 To meet the balance of the 1975-78 financial requirements further financing of 0390 (US$34) million will be necessary, T'hile supplementary IDB financing for Arenal foreign cost overruns and/or contributions from the government could conceivably fill this financing gap, the most likely sources are local sales of ICE bonds and loans from FIV. - 22 - 6.14 Until 17(" i-E sold about ¢30 million of 8% 10- and 20-year bonds annually to local private investors. Because of increases in other borrowers'. interest rates last vear, ICE was unable to sell s-uch bonds until late in the year, when it increased the interest rate of its bonds to 12%. Based on the renewed favorable reception of its bonds by private investors, continued sales of such bonds at prior levels are feasible, although it is conceivable that ICE may have to increase the interest rate further to sell the bonds in an inflationary economy. The proposed loan agreement repeats existing covenants (with which ICE has complied) which limit the portion of bonds subject to re- purchase-prior-to-maturity agreements to 30% of th,e aggregate amount of ICE/ CNFL bonds outstanding. 6.15 In December 1974 Costa Rica reached agreement with Venezuela where- by the Venezuelan government would establish an oi:L facility to finance local costs of certain projects. Both the project and the Arenal development appear eligible for such financing from FIV, which would be long-term (up to 25 years) at interest rates provided by the Bank or IDB. The Costaa Rican government has declared its intention to make up to IJS-24 million of FIV funds availabIe to TCE, w>lch would cover its financing gap for the project. period. Future financial position of ICE power section and CNFL 6.16 Based on the assumptions of satisfactory revaluations and tariff actions, the operating results and financial positions of ICE's power sec- tion and CNFL are expected to be satisfactory, as detailed in annexes 14 and 15 respectively. 6.17 The debt service tests included in existing loan agreements, where- by ICE and CNFL will not incur long-term debt without the Bank's approval unless the most recent 12-month internal cash generation of ICE's power sec- tion and CNFL, respectively, are at least 1.5 times their respective maximum debt service requirement for any succeeding fiscal year, have been repeated in the proposed loan agreement. Because their debt service throughout the project period is expected to be high, Bank approval of future borrowings is expected to be necessary. ICE telecommunications section finances 6.18 As shown in annex 16, the financial performance of ICE's tele- communications section has been strong, with rates of return of 12 to 15% in the early 1970s. This strong performance has enabled it to provide most of the local-cost financing for its ambitious expansion program, relying on the Bank and suppliers for foreign financing. 6.19 Tariff adjustments to increase ICE's telecommunications revenues by about 30%, approved by SNE in December 1974, were less than the 50% in- crease sought by ICE in September. Further tariff increases in 1975 are expected as a result of telecommunications revaluation (paragraphs 6.05-07). - 23 - 6.20 ICE has accelerated the completion date of its Stage IV expansion by one year - from 1980 -to 1979 - and the start of Stage V by two years, from those foreseen in the fourth telecommunications appraisal (report no. 417a-CR, May 1974), but this acceleration is subject to government review. Assuming earnings of 12% on a fully revalued rate base, ICE's 1975-78 contri- bution-to-expansion ratio of 30% would be lower than previously foreseen, and its borrowings, correspondingly higher. This financing plan would still be acceptable. - e4 - 7. Agreements Reached and Recommendations 7.01 In the proposed loan and/or guarantee agreements, the following covenants have been repeated: a. ICE's continued separate operation of and accounting for its power and telecommunications sections (paragraph 5.04); b. submission of audited financial statem-nts and auditor's reports (paragraph 6.03); c. rate of return for ICE's power section (paragraph 6.08); d. tariffs for CNFL (paragraph 6.09); e. restriction of ICE/CNFL bonds outstanding under repurchase agreements (paragraph 6.14); and f. debt-service coverage tests (paragraph 6.17). 7.02 In the proposed loan agreement, ICE would also agree to: a. engage consultants for tariff studies (paragraph 2.09) and technical matters (paragraph 3.02c); b. prepare an energy conservation program (paragraph 4.o5); and c. revalue its power and telecommunications assets and foreign debt annually, record such revaluation in its books of account, and cause CNFL to do the same (paragraph 6.07). 7.03 In supplemental letters: SNE would confirm that it will discuss the tariff study included in the project with the Bank (paragraph 2.09) and would give assurances concerning resolution of tariff-increase applicaLions (paragraph 6.08); and ICE would indicate that it will make its best efforts to meet specified performance indicators (paragraph 3.08). 7.0 Prior to declaring the loan effective, the Bank should receive notification that: a. a telecommunications tariff increase to produce a 12% return on ICE's revalued telecommunications rate base has been put into effect (paragraph 6.07); b. CNFL has revalued its assets satisfactorily (paragraph 6.07); and c. CABEI has approved the foreign-currency component of its loar or ICE has obtained suitable financing elsewhere (paragraph 6.12). 7.05 With the above assurances, the project would constitute a suitable basis for a Bank loan of TS$41 million for a term of 25 years with a f our- year grace period. May 21, 1975 APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Details of Previous Bank Lending to ICE Loan Loan Loan amount Project number date (in US$ millior.-) name Principal project components POWER LOANS 276-CR Feb. 1961 8.8 Rio Macho First stage (2 x 15 MW) of Rio Macho hydro develop- Hydroelectric ment; 2 x 4 MW Colima diesel plant; 2 x 0.5 NW Limon diesel plant; associated transmission. 346-CR July 1963 12.5 Power and (part) Telecom. First stage (2 x 32 MW) of Cachi hydroelectric development; associated transmission. 631-CR July 1969 12.0 Third Power Second stage of Rio Macho development, including the 14.5 km Tapanti tunnel and 2 x 30 MW generating units; second stage, of Cachi plant, including installation of gates to raise the reservoir level ; associated transmission. 800-CR Feb. 1972 6.5 Fourth Power 2 x 19 NW gas turbines at San Antonio; 3 x 1 MW diesel units; associated transmissionr consultants' studies. TELECOMMUNICATIONS LOANS 346-CR (part) July 1963 9.5 Power & Telecom. Stage I: 26,000 DELs (later increased to 33,7CO). 632-CR July 1969 6.5 Second Telecom. Stage II: 22,500 DELs; 300 long-distance circuits. 801-CR rel. 1972 17.5 Third Telecom. Stage III: 25,000 DELs; 1000 long-distance circuits; 600 rural call offiees. 1006-CR June 1974 23.5 Fourth Telecom. Stage IVA: 56,300 DELs; 2500 long-distance circuits; rural services; telex expansion. February 1975 Annex 2 Page 1 of 4 pages APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Organization and Regulation of the Electric Power Sector Legal framework 1. Although it is almost universally accepted that power utilities can only operate to maximum efficiency as monopolies, Costa Rica's electric service law, enacted in 1941, stipulates that electric utilities should not have territorial exclusivity. This unique conceptual aoproach has led to organizational difficulties and inefficiencies in the electric power sector, which have only recently begun to be overcome. Among the most serious of them have been: a. a proliferation of enterprises serving the public and uneconomic competition among entities (see paragraphs 2-9); and b. regulation problems (see paragraphs 10-13). Sector entities: interconnected system 2. In the interconnected system, which presently serves the central plateau and portions of Guanacaste province (see map), there are no fewer than 12 enterprises distributing electricity to the public. Of these, ICE/ CNFL is by far the largest, in terms of both number of customers (71% of the total) and energy sold (i4%). ICE exerts some influence (through board membership in the juntas administrativas and rural co-operatives and part ownership of some co-operatives) over many of the other distribution enterprises, and the relationships between the distribution entities (except Cartago's - see paragraph 6) and ICE have become co-operative. The relative sizes f the distribution entities are shown in attachment 1 to this annex. Expansion of the interconnected system in 1975 to serve Puerto Limon on the Caribbean coast, San Isidro del General in the south and Liberia in the north- west, iqll not increase the number of sector entities, because these localities are already served by ICE. 3. As shown in attachment 2, ICE together with CNFL provides most (94%) of the electric energy requirements of the interconnected system, but four other interconnected-system entities provide a portion of their own requirements. In addition, several captive plants selL. excess energy pro- duction to the interconnected system when it is mutually convenient. W~hile ICE does not directly control the other entities' generating facilities, which are run-of-river hydro installations, it maintains daily communication with them and is able to meet system demands by its up-to-date knowledge of hydrological conditions and available energy. 4. In its review of the electric power sector, lJrwick recommended that ICE absorb CINFL within five years, citing the desirability of increased Annex 2 Page 2 of 4 pages efficiency and of establishing a first step towards sector unification. ICE has begun to overcome some of the inefficiencies associated with dupli- cation of effort by joint performance of similar functions, such as plan- ning distribution expansion and customer billing, with CNFL. Because of the difference in managerial emphasis between a bulk supplier, whose principal concern is long-term provision of energy, and a distribution company, whose principal concerns are more immediate, it can be argued reasonably that the two elements need not be combined under one management; several Latin American electric power sectors are divided in this manner and function reasonably well. Given the problems which ICE faces in providing Costa Rica's medium- and long- term electricity needs, this does not appear to be the appropriate time for it to take on additional problems associated with absorption of CNFL, and it has no immediate plans to do so. 5. Urwick also noted the difficulties in trying to consolidate the rest of the sector. Ahile these are inherent inefficiencies (due to, inter alia, a multiplicity of headquarters staffs, maintenance crews, and stores inventories) associated with a fragmented system, the overall standard of service appears adequate (except in Cartago - see paragraph 6 below). More- over, the relative importance of the municipal entities will decline even if they remain distinct. Their service territories are relatively small and limited, and most new large industrial customers will receive service directly from ICE. 6. Because of strong local or regional feelings, consolidation of the interconnected sector entities, while desirable on a long-term basis, can be accomplished only gradually. Several small municipal electric systems have been absorbed in the early 1970s. A further step in this gradual consolida- tion is to take place this year in the city of Tres Rios, where CNFL expects to acquire public-service supply facilities from the local company (Miller Enos), thereby eliminating the last element of active competition between distributing companies. In Cartago, on the other hand, local authorities have blamed ICE for substandard service for many years (largely without justifi- cation), thereby preventing rational resolution of the problem in the fore- seeable future. 7. The government's stated position is that ICE is to be responsible for development of all new electricity generation, but that, while it will not object to consolidation of interconnected-system distribution companies, neither will it promote such consolidation. Given the political difficulties which the government would face in attempting to unify the sector, this position is realistic. Sector entities: isolated system and captive plants 8. In contrast to the interconnecte system, public-service electri- city supply in isolated areas is generally substandard. About 33 enter- prises - municipal and private - own generating installations, often cld and inefficient, of between 4 and 9,600 kW and sell electricity at average rates of between US¢1 and US019/kWh. In connection with its rural-electri- fication program (paragraph 2.08 of the text), ICE intends to provide a Annex 2 Page 3 of 4 pages plan for imporovement of this situation, either through interconnection of independent isolated systems with the main system, their absorption into a new rural electrification scheme, or their consolidation with other nearby isolated systems. It is expected that the government will support ICE's plan in order to facilitate implementation of rural electrification and improve standards in outlying areas. 9. There are over 300 captive plants, of which 13 are of significant size (500 kW or larger), in Costa Rica. Most are related to agro-industries, the largest - 10,300 kW - belonging to a United Fruit subsidiary. Five provide some electricity to the interconnected system. Regulation 10. The 1941 enabling legislation of SNE, Costa Rica's regulatory authority, permits it to construct and operate public-service electricity supply systems as well as to regulate other electric utilities. Despite this legal anomaly, SNE has since its inception confined its activities to regulation. It also grants concessions for hydroelectric generating plants, but not for thermal. In addition to electric utilities, the agency also (by virtue of subsequent amendments to its enabling legislation) has juris- diction over the tariffs, technical standards and finances of ICE's tele- communications operations and over all entities supplying public water/sewer- age service. 11. According to its law, SNE is almost completely independent from the government: no government representative serves on its bosord of directors, and none of its actions except electric tariff increases are subject to govern- ment review. SNE has in past years delayed tariff increase applications for unwarranted periods - more than a year, in some instances. As a result, re- lations between ICE and SNE have been strained. Perhaps reflecting the atti- tude of ICE management, Urwick recommended that SNE: be abolished and that its regulatory powers be assumed by ICE (in technical end concessional matters) and regional consumers' councils (in tariff, service and financial matters). 12. Beginning in 1974, SNE's attitulde has improved signific3nt1v. It approved in March 1974, after about six months' review, tariff increa-es which increased ICE's electric revenues by 41%. In late 1974, it permitted further tariff increases (which increased ICE's electric revenues by 18% in September and 1% per month for the remaining months of the year) to compen- sate for the March 1974 exchange-rate unification of the colon. It also approved for the distribution utilities tariff increases to pass on their increased costs for energy bought from ICE. In December 1974, SNE approved telephone tariff increases which would raise ICE's telecommunications revenues about 30%. Thile the amount of the tariff increase was less than that sou ht by ICE (see paragraphs 6.04-07 of the text for a full discussion of this problem), the relatively short period of review - -three months - which SNE required reflects the agency's more responsive attitude. Annex 2 Page 4 of 4 pages 13. SNE's improved responsiveness is attributable both to government pressure (which, in turn, reflected Bank concern about ICE's deteriorating financ-al situation in 1973) and to better management. Both developments - SNE's improved dialogue with the government and its own improved perfo-mance are favorable and further improvements, particularly in its technical capacity, are expected. In summary, fragmentation of regulation and disbanding of SNE, as Urwick suggested, does not appear appropriate in a country as small as Costa Rica, especially when SNE's regulatory attitude is becoming more responsible. Attachment 1 Attachment 2 March 1975 Energy Sales and Customers - 1973 Average number Distributing Entity Energy sales in GWh of customers Instituto Costarricense de Electricidad - ICE 206.0 24024 Compania Nacional de Fuerza y Luz - CNFL 675.1 113285 Junta Administrativa de Servicios Electricos de Cartago - JASEC 42.4 13615 Junta Administrativa de Servicios Electricos Municipalidad de Heredia - JASEMH 35.0 9342 Junta Administrativa de Servicios Electricos Municipalidad de Alajuela - JASEMA 44.2 12926 Planta Electrica de Tres Rios, Ltda. - Miller Hnos. 17.6 3998 Municipalidad de Grecia 6.o 3174 Municipalidad de Puriscal (A) 1.2 1490 Municipalidad de Nicoya (B) 1.0 802 Municipalidad de Alvarado 0.4 311 Cooperativa de Electrificacion Rural de San Jose de Naranjo 0.1 142 Cooperativa de Electrificacion Rural de Guanacaste 6.9 3368 Cooperativa de Electrificacion Rural de San Carlos 4.6 2535 Cooperativa de Electrificacion Rural de Los Santos 5.9 4126 Total interconnected system 1046.4 193138 ICE - Puerto Limon system 32.7 6991 Guanacaste system (Liberia) 12.0 3164 Quepos system 1.1 414 San Isidro del General system 3.7 2000 Total ICE 49.5 12569 Others (C) 13.3 3500 (D) Total isolated systems 62.8 16069 Total country 1109.2 209207 Notes: (A) Absorbed by ICE during 1973. (B) Absorbed by Guanacaste co-op. during 1973. (C) Of the 39 others at the begining of 1973, 6 were absorbed by ICE and 2 co-ops. during year c (D) Estimate based on 1972 data. (DO H+ ANqNEX 2 Attachment 2 Installed Generating Capacity and Generation in Costa Rica - 1973 Nameplate capacity year-end Generation during Interconnected system Type - in MW year - in GWh ICE: La Garita H 30.0 186.9 Rio Macho H 90.0 154.4 Cachi H 64.o 484.7 Nagatac H 1.5 5.5 Total ICE hydro 185.5 831.5 San Antonio S 10.0 32.6 San Antonio G 38.1 24.0 Colima D 19.5 41.6 Total ICE 253.1 929.7 CNFL : seven plants H 27.7 195.8 JASEC : four units H 8.5 41.6 JASEMH : two units H 2.3 19.1 Miller Hnos. : four units H 1.7 11.4 JASEMA : one unit H 0.7 5.8 Total interconnected system 294.o 1203.4 Isolated systems ICE: Limon D 12.0 34.2 Liberia D 2.8 12.4 Santa Cruz D 3.3 8.1 San Isidro del General D 2.7 4.4 Five others D 2.5 5.9 Total ICE 23.3 65.0 Others H,D 7.5 14.8 Total isolated systems 30.8 79.8 Total public service 324.8 1283.2 Captive plants : 310 units H,D,S 38.6 NA Total country 363.4 H - Hydroelectric D - Diesel G - Gas turbine S - Steam NA - Data not available Annex 3 APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Performance Indicators 1975 1977 1979 Market penetration indicators Percent of population with access to public electricity supply: Rural (rest of contry) 5 5963 Urban (metropolit.an San Jose area) 54 94 94 New communities served 6 10 12 Efficiency indicators Number of employees: Power section 1,368 1,624 1,928 Telecommunications section 2,50)0 2,680 3,250 Finance/administration section 858 900 944 Total ICE )4,226 5,204 6,122 Power employees/GEh generated 1.57 1.44 1.38 Interconnected system losses (in percent): Transmission 3.4 3.4 3.4 Distribution 10.8 10.8 l0o8 Financial indicators - power section Rate of return on revalued rate base (in percent)9.0 9.4 9.1 Receivables from customers at year-end as a percent of t otal revenues for year 12 12 12 March 1975 Annex 4 Page 1 of 2 pages APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Electricity Tariffs in Costa Rica 1. ICE's principal tariffs are summarized in attachment 1 to this annex. They reflect the traditional cost-of-service approach to tariff- setting and are reasonable from that viewpoint. It should be noted that the electric rates exclude fuel charges. Costa Rican utilities account for their fuel consumption separately, passing on all fuel costs to customers through semi-annual fuel-adjustment revisions. 2. The most significant problem of Costa Rica's electricity tariff structure is not the tariffs of any one enterprise, but the fact that each utility has its own set of tariffs - each with its own distinct definition of service classifications and with individual rates for various classes of service. (CNFL, for example, once had separate residential rates for different sizes of houses, whereas ICE has always had a much simpler tariff structure, which does not even distinguish tariffs among differ- ent types of consumers at consumption levels up to 3000 kIh/month. The disparity among tariff structures is illustrated in attachment 2, which shows the price per kWh of the five largest distributors at various levels of consumption. 3. SNE has made some attempts to improve the siutation, e.g., it has caused CNFL to simplify its extremely cumbersome system. However, because of limitations in its staff's experience with tariff structures and the recent increase in the number of tariff-increase applications, it has been unable to devote sufficient attention to tariff-structure rationalization. Its director and ICE's management both were in accordance with the appraisal mission's observation that a review of Costa Rica's electricity tariffs was desirable, and that it would be necessary for outside consultants to under- take the review. 4. The principal purpose of the tariff-structure review would be to design a uniform definition of service classifications and price/consumption relationships for the interconnected system and for isolated systems in Costa Rica, so that the individual utilities' price/consumption curves, (as per attachment 2) would be parallel. (The differing financial requirements of the various utilities would prevent the adoption of uniform rates.) At the same time, the consultants should analyze the advantages and disadvantages to Costa Rica of: a. replacing the declining-rate approach to residential electricity pricing with either a level-charge or an ascending-rate approach; and b. introducing seasonal or daily variations in charges. Annex 4 Page 2 of 2 pages The former of the above two structural changes would respond to the increased awareness, both worldwide and Costa Rican, of the need for energy conservation and the consequent undesirability of promoting (through lower prices) heavy residential consumption. The latter would respond to a uniquely Costa Rican situation: because hydro installations in the country lack storage, the utilities spill water during the wet season and burn fuel during the dry, especially at peak demand hours. Consequently, measures to improve the system's load factor (on both a seasonal and daily basis) would not only achieve better plant utilization but also reduce fuel consumption. Attachment 1 Attachment 2 March 1975 Annex 4 AtEtacment 1 ICE's R1etail Electricity Rates (effective 1/21/75) (in colones) Tariff 1. Residential, commercial, first 30 kWh or less 9.00 smaller industrial and next 40 kWh 0. 26/kWh small rural electrifica- excess 0.23/kWh tion co-operatives (up to 3,000 kWh/month - both interconnected system and isolated - low tension) 2. Industrial consLmers, demand charge: first 10 kW or less 227.00 and smaller distribution excess 22.7 /kW companies excluding energy charge: first 3,000 kWh or less 444.oo rural electrification excess 0.148/kWh co-operatives (3,001 - 20,000 kWA/month - low tension) 3. Industrial consumers demand charge: first 27 kW or less 612.90 and distribution com- next 40 kW 21.7 /kW panies excluding rural excess 34.5 /kW electrification co- energy charge: first 20,000 kWh or less 2,960.00 operatives (above excess 0.l085/kTh 20,000 kTWh/month and only at high tension, i. e., above normal distribution voltage 3-phase) 4. Block sales to rural demand charge: first 11 kW or less 126.50 electrification co- excess 115.0/kW operatives (3,001 - energy charge: first 3,000 kWn or less 300.00 20,000 kWh/month - excess 0.10/kWh voltages above normal distribution voltags 3-phase) 5. Block sales to rural demand charge: first 27 kW or less 311.00 electrificaticn co- next 40 kW 11650/kW operatives (above excess 21 .00/kW 20,000 kWh/month - energy charge: first 20,000 kWh or less 2,000.00 voltage higher than excess 0.065/kih distribution voltage 3-phase) 6. Public illumination for each 50 W or fraction of 4.oo Note 1: Demand charges are based on a 15 minute interval. Note 2: The tariffs consider special rates for seasonal loads. Note 3: The tariffs also provide for penalties for a power factor lower than 0.95 (tariffs 2, 3, 4 and 5) which have not been applied due to lack of metering equipment. ELECTRICITY PRICES OF LARGEST DISTRIBUTING ENTITIES BASED ON TARIFFS IN EFFECT IN AUGUST 1974 fin colonos) COLONES/kwh - F e 1,- +eZWH v ~~~~~~~22~ ~~~~~~~~I IASEI C~~~~~~~~~~~~~~~~~~~~~AE .44 'IASASE ~~~~~~~~~~~............ r9.. -- 16 CNF,~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~x,, JASFAR r *~~~~~~~~~~~~~~~~~~~~~~~~~~~'S. .10 - flU U II ___ -- -~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~. 1 .10 ----- ____ - - -1 - - .10 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~4 TAHIFF 1 TAIF 2TAIF 2 MONTHLY CONSUMPTION IN klA- FlAld 0#Bk--9SSP Annex 5 Page 1 of 2 pages APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Boruca Hydroelectric Development Background 1. By a contract ratified by the Costa Rican Congress in 1970: the government has given Alcoa a concession for the extraction of 120 million tons of bauxite from an area near San Isidro del General over a period of 40 years; Alcoa has undertaken to build a refinery at Palmares for the oroduction of alumina (A1203) of a minimum capacity of 400,000 tons p.a., and the government has undertaken to build and maintain a port at Punta Uvita and a 30 km road from the Palmares alumina refinery to Punta Uvita. By letter of intent signed in April 1972 and subsequent agreements, the government, Alcoa and ICE agreed to prepare: a feasibility study of a hydroelectric development at Boruca, to be owned and operated by ICE; and (assuming the feasibility of the hydro development) a feasibility study for construction of an aluminum snelter at Punta Uvita with estimated annual capacity of 300,000 tons. 2. The latest developments are the following: a. In March 1974, the final version of the feasibility study for the Boruca hydroelectric development was prepared by Alcoa, ICE and International Epgineering Co. Inc. (USA). b. In May 1974, an agreement was signed by the government, ICE and Alcoa which established the completion and acceptance by Costa Rica of the feasibility study. c. In October 1974, Alcoa submitted to the National Aluminum Com- mission (Comision Nacional de Aluminio - CNA) a project outline document with some element of financial analysis. Contrary to CNA expectations, Alcoa did not present a full feasibility study of the aluminum project, nor did it make a firm offer. In this document, Alcoa assumes that the Costa Rican government will obtain all financing for the Boruca hydro project including any cost overruns and that Alcoa will service the debt and operating expenses. This document also assumes that the only advantages for Costa Rica would be the use of 30 MW of firm power paying only for the corresponding operating costs, and taxes from the smelter operation. d. Because it considered Alcoa's plan unsatisfactory, CNA hired a consultant (Norconsult of Norway) in November 1974, to advise it in further dealings with Alcoa. Together with Norconsult, CNA analyzed Alcoa's project outline, prepared a list of issues that Annex 5 Page 2 of 2 pages Alcoaneeds to clarify and presented them to Alcoa. e. Norconsult submitted the first draft of its analysis in March 1975 which confirmed the feasibility of the project. This analysis contains sufficient information for Costa Rica to start negotiations with Alcoa. Costa Rica expects Alcoa to submit concrete proposals for starting negctiations by the end of May 1975 and has set the end of 1975 as a time limit to reach agreement with Alooa. The power project 3. The h x 190 MW Boruca hydro development would provide annual firm energy production of 5,000 GWh. It would consist of a 260 m rock-fill dam on the Rio Grande de Terraba 15 Ian upstream from Palmar Norte, impounding a reservoir which would cover a surface bf 197 km2 with a volume of 1h,950 million m3, an underground powerhouse, a spillway with a maximum discharge capacity of 1h,200 mi/sec and two double-circuit 220 kV transmission lines, 53 km long to the aluminum smelter at Punta Uvita. The estimated time for construction is 7 years. This rock-fill dam would be among the highest of its type existing in the world but the feasibility study does not foresee any insurmountable difficulties in its construction. Estimated base cost (1973 prices) is US$270 million, of which 31% would 'be local costs and 69% foreign. This estimate includes 10% for physical contingencies. Final cost is estimated to be US$700 million based on the following assumptions: a. 10% price escalation for both foreign and local costs; b. interest during construction based on the assumption of a 50% Bank-type loan at 71% for 30 years and 50% conventional financ- ing at 12% for 15 years to cover the total cost of the hydro project. Conclusion 4. As can be seen from the above it is not possible to judge whether the combined project (hydro plus smelter) is a viable one for Costa Rica. This would finally depend on the benefits for Costa Rica that Alcoa would agree upon and it is premature to venture any opinion of the eventual results of these negotiations. 5. If the results of the negotiations with Alcoa (or other entities, paragraph 2.c.) were to be negative, the Boruca hydro project would be justified for ICE's interconnected system in approximately 20-25 years and would be its second hydro project with interannual regulation. May 1975 Annex 6 Page 1 of 4 pages APPRAISAL CF FIFTH POWfER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Arenal Hydroelectric Development 1. The principal objective of the Arenal hydroelectric project is to build in its first stage a power plant of 135 MW (3 x 45 MW) to meet Costa Rica's future energy demands. At present, the waters of Lake Arenal (515 m above sea level) flow into the Atlantic Ocean. The project provides for diverting these waters into ,he Pacific Ocean, passing through a seasonal- ly very dry region, making possible the irrigation of at least 250,000 acres as an additional benefit. 2. The project consists of building a 68 m high dam, rock filled with an impervious core of volcanic material, blocking the only outflow of Lake Arenal, which will then have live storage of L.200 million i3. The location of the dam site is in the northwest of Costa Rica, 4 km to the west of the Arenal Volcano (still slightly active after an eruption in the year 1968) 20 km from the city of Tilaran and 60 km from Caras (see map). The proposed dam will bring the water level of the lake up to 538 m a.s.l. 3. The lake, when full, will have a surface area of approximately 70 km2, having a length of 26 km and width of 4 km at its widest point . Its waters will flow through an intake structure, tunnel and penstock located at the opposite side of the lake from the dam, to 3 Francis type turbines coupled to 45 MW generators installed in an above-ground power house to be finally discharged into the Santa Rcsa River -which flows into the Pacific Ocean. Average annual generation is expected to be about,640GTAh. 4. The second step of this hydro development will be built about 8 km from the Arenal power house, namely the Santa Rosa power plant. Using the waters discharged from Arenal it will have a capacity of 156 MW (3 x 52 MW) and an annual average generation of 790 GTWh. The final development is plan- ned to double that described above, i.e., 270 MW at Arenal and 312 MW at Santa Rosa. 5. The Arenal hydro development will be the first one to be built in Costa Rica that has interannual regulation. The only other attractive possible interannual regulation developments known in Costa Rica are Talamanca (live storage 4,500 m3) and Boriuca (live storage 4,900 m3, see Annex 5) both near the Panamanian frontier. 6. The dam will use approximately 4 million m3 of material all to be found within aradius of 5 km from the site, and at its crest will be approxi- mately 1,000 m long. It has been designed to withstand an earthquake of 6.5 on the Richter scale at the dam site. The diversion of the river will be effected by a 6.3 m diameter 600 m long concrete-lined tunnel with a capacity of 360 m3/s which is nearing completion at this moment, the construction being done by ICE's own work forces. This tunnel will have gates that will permit it to be used as a discharge tunnel of the reservoir. The main spillway will Annex 6 Page 2 of 4 pages be located on the right sida of the river with a discharge capacity of 300 m3s. It is a free discharge type with an open conduit and ski-jump. 7. The water -will flow through an intake struzture designed for 87.5 m3/s, a concrete-lined tunnel 5.25 m in diameter and 6.5 km long to a steel surge tank, through valves to enter an above ground steel pen- stock of 4.5 m diameter wilth 750 m length. The water will de distributed to the three turbines with a head of approximately 215 m. All these instal- lations are dimensioned for the capacity of the first stage of 135 MW and will have to be duplicated for the second stage of 135 MW. The power house is so designed to make easily the necessary extension for the second stage. 8. The ecological impact was studied by ICE with the help of individual US consultants who found that the design of the dam, roads and excavations would minimize the damage to the environment, and that the lake when full would add beauty to the landscape and give opportunity for tourism. The building of the dam will affect 400 families situated within the area of the reservoir, which will make their relocation necessary. The town of Arenal is the main center of the region with about 160 families, followed by Tronadora, wiith 60 families. The rest of the families are scattered among several vil- lages. A survey taken showed that most of the inhabitants do not wish to settle outside the region, and ICE accordingly has prepared a relocation pro- gram which calls for the construction of two new towns, which will have adequate social services such as water supply, electricity and schools. The total cost of the relocation program is estimated to be the equivalent of US$1,255,000 which is included in the construction cost of the project. 9. The activity of the Arenal volcano was studied by Mr. W. Nelson of the Smithsonian Institution (USA), who recommended geophysical vigilance of the volcano to predict any change in the activity and the construction of a security cabin to protect the lives of the permanent personnel at the dam in case of a repeated eruption. He considered it improbable for an eruption to have an adverse effect on the dam due to the natural barriers between the volcano and dam site. Nevertheless, he recommended the construction of a freeboard several meters high to protect the dam from any wave action that might be caused by volcanic or seismic activities, together with a topo- graphical survey of present lava flows to follow carefully any variations that may occur. 10 The feasibility study and designs were carried out by ICE and the following consultants: W. A. Wahler & Associates (USA) Geoconseil (France) Individual consultants from the University of Texas (USA) Approximately half of the civil works will be contracted by international bids, namely the dam, the roacs, the water intake and the penstock. The other works will be done by force-account. Annex 6 Page 3 of 4 pages 11. According to the project cost estimate developed at the time of IDB appraisal during February and March 1974., the cost of the project will be US$91 million, as shown below: Thousands of US$ Local Foreign Total Engineering and Adnii.-Itratio.- 9,o50 970 10,020 Land and relocation 4,100 - 4,100 Ci Til works 16, 005 19,125 35,130 Electro-mechanical equipment 525 10,685 11,210 Total base cost 29,680 30,780 60,460 Contingencies - physical 2,720 3,235 5,955 - price 7,o85 8,790 15,875 Interest du ing construction 7,190 7,190 Commitment fees 1,025 1,025 IDB inspe ion 5C5 505 39,485 51,525 91,010 The US$50.5 million IDB loan will finance the foreign cost component exclud- ing its commitment fee with 30 years term, 6 years grace period, interest 8%, ] a commitment fee. IDF does not consider interest during construction for local costs. Physical cniltingencies were taken to be 10%. Price esca- lation for foreign costs was -stimated at 8% yearly for the proposed five- year disbursement period. Lu. al costs (including the 10% contingency allow- ance) were escalated 18% for the first year of construction with escalation decreased proportionally thereafter to obtain an average escalation rate of 8% a year. 12. The construction program calls for the first unit to be commissioned before the end of 1977 and the other two units in 1978. T-is program appeared optimistic to the appraisal mission and duritig conversations with ICE's of- ficials it was agreed by them that a more realistic schedule would be for the first unit to be on line at the end of 1978. If the delay were greater ICE could suffer from energy shortage in the dry season of 1979 (January to May). The reasons for estimating this time schedule are the following: a. The program calls for the dam to be built in three dry seasons (February-April) beginning in February 1975. At present (February 1975) only two contractors have offered bids, the lower one of which was about US$6 million higher than the estimated cost and ICE is calling for new bids and plans to begin dam construction by force account with a limited quantity of construction equipmenit. Under the circumstances, and after visiting the site and seeing the mate- rial difficulties involved, such as bad roads,. difficult extraction of material for dam building, etc., the mission feels that the three dry seasons will not allow sufficient time for completion. Annex 6 Page l4of '4 pages b. The program calls for the contract for the electromechanical equipment to be signed by January 1975, but as yet the bid documents have not been issued. This will cause at least a 6-9 month delay with respect to the prograrm. 13. The cost estimate presented in paragraph 11 appears low because: a. delays in the construction schedule will with price escalation increase the project cost; b. as shown by the bids for the dam construction 10e O -hys-iscal contingency allowed for cizil works ap-pears to be too low; and c. base cost estimates for generating equipmenat are considered to be on the low side (US$39/kW - generator + turbine). 14. A revised cost estimate of the projiect was calculated based on the following assum.ptions: a. extension of the construction program by one year; b. 10% physical contingency for engineering and administrative costs, land and relocation and all electromechanical equipment (genera- ting equipment calculated at US$56/kW; c. 30% physical contingency for the tunnel: d. 20% physical contingency for all other civil works; and e. local and foreign cost escalation according to Bank's practice (see paragraph 3.04 of the text). The results of these calculations are shown in the following table: Million of US$ equivalent Local Foreign Total Original estimate 39.5 51.5 91.0 Bank estimate 52.2 61.3 114.0 Increase in US$ 12.7 10.3 23.0 Increase in % 32.0 20.0 25.3 15. These estimated cost overruns are basically due to considering: a. higher physical contingencies b. higher local and foreign cost escalation than those used in the original cost estimate. Due to t,he reasons given in para- graphs 12 and 13, the mission feels tnat it is not possible t,o change the construc- tilon program of Arenal in order to obtain an earlier completion date or lower costs than those estimated. March 1975 Annex 7 Page 1 of '7 pages APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Description of the Project I. Oeneration Facilities Extension of Rio Macho hydro power plant 1. The existing Rio Macho hydro power plant (second stage completed in March 1974) has an installed capacity of 90 MW (2 x 15 MW plus 2 x 30 MW Pelton turbine-generator sets working under a head of 460 m), and uses water drawn from the Macho and Reventazon rivers. The power plant has a small storage reservoir (capacity 470,000 m3) which permits regulation over several housrs only and limits use of the plant during the dry season to peaking pur- poses. The proposed extension consists of the installation of an additional unit of 30 MW, which will be the last stage of this development. The civil works entailed are minor and consist of the following: connection to the tcailrace channel and the extension of the power house to provide the neces- sary space. The unit is planned to be in service by mid-1977. Extension of the Cachi hydro power plant 2. The existing power plant was completed in two stages. The first stage (1967) consisted principally of the building of a thin arch dam on the Reventazon river (height 54 m), a 5.9 km tunnel from the reservoir to the power station, and a power house containing two Francis turbines coupled to generators having a nominal capacity of 32 MW each. The turbines operate on a head varying between 246 and 221 meters. The second stage (completed in 1972) raised the level of the reservoir by 20 m by installing gates on the spillway which increased the storage capacity to 51 million m3. 3. The proposed extension consists of the installation of an additional unit of 32 MW, bringing the installed capacity up to 96 MW. The final develop- ment of the Cachi hydro power plant is planned to provide for two more units of 32 MW, for which additional civil works (tunnels, penstock, etc.) will have to be constructed. For the proposed project the civil works necessary are minor and consist of the following: extension of the power house by 12 meters, slight modification of the tailrace channel and the addition of a bifurca- tion at the bottom of the existing penstock to connect it to the new turbine. The unit is planned to be in service by mid-1977. Moin diesel plant 4. This medium speed diesel power plant of 30 MW will consist of four to six machines of 7.5 to 5 MW running at a velocity of about 450 r.p.m. The fuel used will be basically fuel oil (Bunker C) with a small proportion of Annex 7 Page 2 of 7 pages diesel oil. It was found that the most economical location for this power plant was at MKoIn on the Atlantic coast near the town of Limon, adjacent to the oil refinery of Costa Rica. The plant will be connected to the national interconnected system by the double circuit 138 kV Moin-Cachi transmission line which is under construction. ICE plans to put the plant into service during the first quarter of 1977. Fuel storage tanks 5. The criterion adopted to determine the required fuel storage capaci- ty for the thermal urits is that which permits each of the plants to operate at full load with a plant factor of 85% for E. period of 45 days. Excepted frc this general criterion is the proposed new diesel power plant at Moin where the tank capacity would be sufficient for only 27 days, based on its proximity to the existing oil refinery. On this basis the tanks proposed are: a. a 2 million gallon tank for diesel oil for the San Antonio gas turbine plant. This tank in combiration with the existing ones would permit both the San Antonio steam and gas turbine plants to comply with the criterion mentioned above; and b. a 1 million gallon tank for fuel oil at Mloin for the new diesel power station. Both tanks are scheduled to be completed by y-ear-end 1976. The proposals are the result of studies made jointly by ICE and the local refinery and are reasonable, based on the following: i. the local refinery's capacity covers only about 65% of Costa Rica's needs, and the country must import refined petroleum products, which exposes it to possible unavailability of tankers; ii. fuel oil is transported from the Atlantic coast by railway which has a limited capacity due to insufficient rolling stock. Other fuels are transported from the refinery by a pipeline to the San Jose area; iii. all the fuels imported by Costa Rica through the Pacific coast must also be transported by railway to the San Jose area with the same difficulties as described in (ii); and iv. the storage volume that the refinery has available is only approximately 10 million gallons of diesel oil and less than 2 million gallons of fuel oil. II. Transmission and Distribution Works (to be completed by year-end 1978) Works related to the Arenal hydro power plant Annex 7 Page 3 of 7 pages Arenal step-up substation 6. This substation will step-up the voltage of the power generated by the Arenal hydro power plant to 220 kV and will contain three 60 MVA trans- formers, a 220 kV line bay for the transmission line to Canas and necessary associated equipment. Extension of Canas substation 7. The works included are those related to the installation of two 220 kV line bays for the incoming (from Arena±) and outgoing (to Barrancas) 220 kV circuits and the installation of a 220/138 kV, 30 MVA autotransformer to supply the Guanacaste region. Canas-La Irma transmission line 8. At present the region called Las Juntas de Abangares is supplied from a connection to the Canas-Barrancas transmission line (at the moment energized at 138 kV) through a substation 138/34.5 kV. Due to the fact that in the future this transmission line will operate at 220 kV (see para- graph 11) the most economical solution to supply this region is building a 23 km long line (34.5 kV) from Canas to La Irma. Extension of Barrancas substation 9. This extension provide: for the installation of a 220/138 kV, 60 MVA autotransformer to serve local load and the necessary 220 kV line bays for the incoming (from Ctnas) and outgoing (to La Caja) 220 kV transmission lines plus the associated equipment. Arenal-Canas transmission line 10. This 220 kV, 16 km transmission line is necessary to link the Arenal hydro power station to Canas, where an existing line to Barrancas (financed by IDB) presently operating at 138 kV, but insulated for 220 kV will interconnect the Arenal power plant to the interconnected system. This 86 km single circuit, 220 kV line will be a weak link in ICE's transmission system until the construction (1980-1981) of additional lines to transport the energy from the Santa Rosa project. Barrancas-La Caja transmission line 11. This double circuit 220 kV line, 62 km long, is necessary to transport with a high degree of security the energy of the Barrancas and Arenal power stations to the load center. Extension of La Caja substation 12. This extension of one of the main substations supplying the metro- politan area of San Jose is necessary due to the incoming double circuit 220 kV line from Barrancas and the installation of two 220/138 kV, 60 MVA autotransformers to permit the energy from Arenal to enter the ring to be Annex 7 Page 4 of 7 pages built around San Jose. A third transformer (138/3:4.5 kV) is necessary to meet the increasing load 4n the area. 13. The capacities of the autotransformers mentioned in paragraph 7, 9 and 12 were determined by load flow studies carried out by ICE using its own computer. III. Transmission Related to Generating Facilities in Proposed Project Moin, Cachi, Rio Macho (to be completed by first quarter 1977) Moin step-up substation 14. The works scheduled in this substation consist of the installation of the step-up transformer for the Moin diesel power plant and the two line bays for the two outgoing 138 kV circuits to Cachi.. (The transmission line itself is already under construction with financing from CABEI). Extension of Cachi step-up substation 1, This substation has to be extended to accommodate the step-up transformer for the third 32 MW unit to be installed and uhe tiro line bays necessary for the two circuit 138 kV transmission line to Este substation. Extension of Rio Macho step-up substation 16. This extension is necessary due to the .installation of the step-up transformer for the fifth unit of 30 MW for the Rio Macho oewer olant. Cachi-Este and Rio Macho-Este transmission lines 17. The existing double-circuit 138 kV Rio Macho-Colima transmission line will be replaced by: two circuits to Este substation (one from Rio Macho and the other from Cachi); one circuit from Cachi to Colima; and one circuit from Este substation to Colima (see attachment 1), all at 138 kV. This solution is designed to: a. permit the flow of the total energy from the extended Rio Macho and Cachi hydro plants and the new Moin power plant into the load center; and b. form part of the ring around San Jose. IV. Transmission and Distribution Related to Ring Around San Jose 18. These works, to be completed by year-end 1978, are shown in Attachment 1. They consist of the following: 1/ 1/ The completion of this ring (the northern portion already exists in part) follows the recommendation of Electroconsult (Italy), a Bank-financed consultant (loan 800-CR). Annex 7 Page 5 of7 pages - extension of La Caja substation; - construction of Este substation; - construction of Desamparados substation; - construction of Alajuelita substation; - extension of Colima substation; - transmission lines from Este and Rio Macho substations to La Caja substation passing through Desamparados and Alajuelita substations; - a short transmission line to connect with the Sabanilla (Moravia) substation under construction with financing from loan 800-CR; - construction of a second 138 kV circuit La Caja-Colima; - distribution equipment for use by CNFL consisting of: a. equipment for Alajuelita substation (trarsformer 20/30 MVA, 138/13.8 kV and associated equipment). The equivalent equipment for CNFL's contribution for extensior- of the existing Colima substation and the new Desamparados and Sabanilla (Moravia) sub- stations, has already been procured by CNFL; and b. distribution transformers and meters necessary to meet the in- creasing load of the San Jose area, and for rationalizing the distribution voltage to 13.8 kV. The southern part of the ring (the northern part already exists - see attach- inent 1) has to be built as soon as possible to avoid land purchase and right- of-way problems due to the rapid expansion of urbanization in San Jose. Extension of present transmission system to meet increasing load 19. These works, which are to be completed by year-end 1978, consist of the following: a. extension of the following substations either by adding new transformers or changing the existing ones: Garita, Naranjo, Quezada, Carmen, Cocal, Guayabal, Turrialba, Canas; b. construction of two new 138/34.5 kV substations, to meet increasing load in two areas, namely: Concavas (for the Cartago area, connected to Rio Macho-La Caja transmission line) and Siquirres connected to Cachi-Moin transmission line; c. a short single circuit 138 kV transmission line (17 km) from Garita to Naranjo to reinforce the electric supply of the towns Grecia, Naranjo Palmares, Quezada, San Ramon, and Arenas, presently being supplied by a very old and failure-prone system of 34.5 kV lines; and Annex 7 Page 6 of 7 pages d. an allowaincc, for normal expansion of the transmission system to supply new industries whose definite location has not y-et been defined. V. Load Dispatching Equipment 20. ICE, at present, has practically no load dispatching equipment for telemetering and telecontrol, and a poor internal communication system. ICE proposes to install by year-end 1977 a modern system which will permit it to control the operation of the whole system more efficiently (especial- ly necessary with Arenal due to its interannual regulating capacity) and to obtain faster response to partial or complete system outages, (system out- ages at present last as long as 50 minutes; complet,e system outages occur on an average between 2 and 3 times a year). VI. Cost of Pro.ject and Allocation of Loan Proceeds 21. The estimated project cost and financing requirements are shown below. Physical contingencies were estimated at 10, of the hase cost estl- mate, and price contingencies, in accordance w%th the assumpti -s indicated in paragraph 3.05 of th- text. Colones (millions)_ US$ (millions) Local Foreign Total Local Foreign Total Rio Macho extension 6.75 33.06 39.51 o.64 2.97 3.61 Cachi extension 17.10 48.o8 65.:L8 1.65 h.21 5.86 Moin Diesel plant including substation and fuel tank 12.90 81.00 93.90 1.27 7.98 9.25 San Antonio fuel tank 0.41 1.32 1.73 0.04 0.13 0.17 Transmission related to Arenal 27.71 90.35 118.06 2.51 8.07 10.58 Transmission related to Rio Macho and Cachi 6. i 18.23 2h.38 o.b9 1.76 2.35 San Jose ring and distribution equipment 17.06 46.25 63.31 1.57 4.49 6.06 Extension of existing trans- mission equipment 20.68 42.65 63.33 1.83 3.90 5.73 Load dispatching equipment 2.58 13.68 16.26 0.22 1.20 1.h2 Consultant studies 2.06 2.06 0.20 0.20 Sub-total l11.37 376.68 488.02 10.32 3.91 45.23 Contingencies - physical 11.13 37.67 48.80 1.03 3.49 4.52 - price 51.96 64.75 116.71 4.66 5.91 10.57 Total project costs 174.X3 779.10 k53. 57 16.0] T431 60.32 Financial charges 28.07 89.76 117.83 2.39 7.69 10.08 Total financing required 202.50 568.86 771.36 18.40 52.00 70.40 Annex 7 Page 7 of 7 pages 22. For purposes of presenting the allocation of proceeds of the proposed loan, price contingencies have been limited to 10% of the base- cost estimate of the goods to be financed, and physical contingencies have been included as above. The allocation of proceeds would be: millions of US$ Supply and installation of project works and acquisition of equipment and materials 28.6 Consultantst services 0.2 Interest and other financial charges 6.5 Unallocated 5.7 Total l .0 Attachment . May 1975 COSTA RICA APPRAISAL OF FIFTH POWER PROJECT INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) TRANSMISSION AND DISTRIBUTION RING AROUND METROPOLITAN AREA OF SAN JOSE 8.7 Km. 5.5 Km. > 8.7 Km. 18.5 Km. a---------- 1.1 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~Sabanilla 4~ a t 9 : I 138 KV K _Moravia) 138 KV. La Caja 220IKV 20MVA. CoC olima 2 13.8 KV. 3.8 K. San Bias C2 Cchi 138 KV. _ La______ Caja 34.5KV.L___La Ca-a 138 KV. KV___ I~~ ~ ~~~ ' I______ ?ti!; L ------0 T'Gaia 34.5 KV. L ------------ 1 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~24 Km. 14.6 Km. L- - - - - - 8.5 Km~ San Antonio I Rio Macho 138 KV I * , . 13.8 KV. 4i13.8 KV. 4-13.8 KV. t f t 5* X~~~~~~~~~~~~~~~~~----:Escaz6 138 KV. -r-J Alajuelita 138 KV. T lDesamparados 138 KV, .1@ I \\ ;ca I I I 1 I %, L_ i 14 Km. j L , ,. _2 Km. , o n scaz_ 138m. 9 Ky. jTJTAIeIita 138 K1. Kiam,a 6 138 Ky. I13.8 KV. - EXISTING ---- PROPOSED PROJECT morld B.nk-9513 .......... FUTURE a ANNEX 8 APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) ESTTIA-TED SCHEDULE CF LOAN DISBURSEMEI;TS Assumptions Loan apprcral: June 30, 1975 Effective date: October 31, 1975 Closing date: June 1979 I9RD fiscal year Cumulative disbursements and seme. uer at end of semester (in thousands of US") 1975-197h: December 31, 1?75 3,371 June 30, 1975 12,371 197'S,-1977: December 31, 1907 213,82 June 30, 1977 27,354 1977-1978: December 3 , 1977 37,3,) tune 30, 1978 38,83L 1'378-1 979: December 31, 1978 41 ,000 June 30, 1979 41 ,000 March 1975 Annex 9 APPRAISAL CP FIFTH POWER PROJECT - COSTA RICA INSTITLUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Demand, Generation and Sales Forecast 1. At the end of 1972, ICE revised its previous study of load fore- cast and obtained results for 1973 through 1986 which are realistic and practically coincident with the results of a separate study made by a Bank- financed consultant - Sofrelec (France) (loan 800-CR). 2. The load forecast was based on a detailed analysis of sales in the past ten years, trends for each class of consumer in the different areas of the -country, population growth rates, and projected industrial growth as a result of direct consultation with each industry and the general tendency of economic activity of the cowitry. ICE used a conservative estimate of economic activity of the country for Calculating its salas forecast (and therefore its revenue) denominated as level 2, whic'h assumes an average annual growth rate of 8.6%. To determine its installation program called level 1, ICE assumes a slightly higher average annual growth rate of 9.1% to take into account the -nservative basis, mainly in industrial growth, used for the sales forecasiL. The actual average rate of growth of sales over the past five years was 10.3% p.a., which refliects the conservative basis of the load forecast used by ICE even for leviel 1. The load factor of the system is assumed to increase from 56% in 1973 to 59% in 1986. On these basis the average arnual growth rate of maximum demand is 8.5%. 3. Detailed information for the interconnected system on a yearly basis, covering actual (1968 through 1974) and forecast (1975 through 1981) of sales, generation, maximum demand and required calpacity is shown in attachment 1 to this annex. Attachment 2 shows the forecast made by ICE of generation and maximum demand (based on level 1) on a monthly basis from 1973 through 1986. 4. The reasonableness of ICE's study is indicated by the monthly values of generation and maximum demand obtained for the years 1973 and 1974 (see attachment 3), which are cnly slightly lower than the figures corresponding to the forecast based on level 1 in spite of tariff increases of more than 60% during 1974. Attachment 1 Attachment 2 Attachment 3 March 1975 INTERCONNECTED SYSTEM: ENERGY SALES, LOSSES, GENERATION, MAXIMUM DEMAND ANt) LOAD FACTOR 1968-1981 Actual Projected Description 1968 1969 1970 1971 1972 i 1973 1974 1975 1976 1977 1978 1979 1980 1981 Sales of Energy GWh 639.0 688.2 774.2 878.o 974.o 1039.0 1143.3 1231.2 1368.6 14183.8 1608.5 1741.3 1875.1 2026.5 Transmission Losses GWh 25,2 27.2 31.0 35.1 38.7 41.1 45.4 49.0 54.4 59.0 63.9 69.2 74.6 80.6 Distribution Losses GW0M 73.8 82.2 102.8 113.9 121.3 123.9 143.3 155.8 173.0 187r2 209.6 219.5 238.3 257.9 Generation GWh 738.0 797.6 908.0 1027.0 1134.0 1204.0 2/ 1327.0 - - - - - - Level 2 - - - - - - 1436.0 1596,0 1730.0 1875.0 2030.0 2188.o 2365.0 Level 1 g - - - - - - - 1504.0 1646.0 1813.0 1963.0 212800 2307.0 2500.0 Load Factor (Level 1) .544 .541 .532 .553 .558 .551 .555 .570 .573 .577 .580 .582 .584 .586 Maximum Demand MW (Level 1) 155.0 168.4 195.0 211.9 231.9 249.3 271.0 301.0 328.0 358.0 386.o 417.0 451.0 487.0 Reserve (Largest Unit) 32.0 32.0 32.0 32.0 32.0 32.0 32.0 32.0 32.0 32.0 32.0 45.0 45.0 45.o Reqcuired capacity 187.0 200.4 227.0 243.9 263.9 281.3 306.0 333.0 360.0 390.0 418.0 462.0 496.o 532.0 Available capacity 196.0 196.0 196.0 196.o 256.0 294.0 332.0 332.0 352.0 3/ 444.o / 444.o 579.0 5/ 579.0 579.0 Capacity surplus or (deficit) 9.0 (4.4) (31.0) (47.9) (7.9) 12.7 26.0 (1,o) (8.0) s4.o 26.0 117.0 83.0 47.0 See Annex 13 for explanation of Levels 1 zand 2 Load shedding of 36 GWh 2/ Interconnection of 20 MW of minor thermaol ple it Commissioning of Rio Macho extension (30 MW) Cachi extension (32 MW) Moin Diesel Plant (30 YN) 5/ Commissioning af Arenal Hfydro Power Plant (135 MW) I- PROJECTION OF MAXIMUM DEMAND AND GERATED ENERGY (LEVEL 1) i/ FOR THI- INTERCONNEC(MED SYSTEM Monthly Maximum Demands MW Maximum YEAR Demarnd (MW) Jan. Feb. March April May June July Aug. ,e. Oct. Nov. Dec. 1973 g/ 254 223 ?27 231 229 227 225 228 230 2Po 243 251 ?54 1974 j 27lk 2180 P45 249 247 244 2843 246 2848 "8') 262 271 27(4 1975 301 264 269 274 271 268 2676 2'71 272 (3 288 298 301 1976 328 288 294 298 296 293 291 "95 29'7 Ž9 314 325 328 1977 358 314 320 326 323 319 217 322 324 305 342 354 358 1978 386 339 345 351 348 344 342 347 349 3)0 369 382 386 1979 417 336 3'73 379 3'76 372 369 3'75 377 T(8 399 413 417 1980 451 396 40o) 41o 4o6 402 400 405 408 40o 431 446 451 1981 487 427 436 443 439 434 431 438 441 )8' 466 482 487 1982 52'7 462 472 480 475 470 467 474 477 4783 504 522 527 1983 570 500 510 519 514 508 505 512 516 5L'( 545 564 570 1984 617 541 552 561 556 550 547 555 558 560 590 610 617 1985 668 586 598 608 602 596 592 60 604 6006 639 661 668 1986 724 635 648 659 652 646 641 651 655 657( 692 717 724 Monthly Generated Energy GWh YEAR Total Jan. Feb. March April May June July Aug. Sept. Oct. Nov. Dec. 1973 1248 99 102 97 101 102 105 102 104 105 107 112 111 1974 1361 108 112 106 110 112 114 112 113 114 117 122 121 1975 1504 119 123 117 122 123 126 123 125 126 129 135 134 1976 1646 130 135 128 133 135 138 135 137 138 142 148 146 1977 1811 143 149 141 147 149 152 149 150 1 "" 156 163 161 1978 1863 155 161 153 159 161 165 61l 163 16') 169 177 175 1979 2128 168 174 166 172 174 179 174 177 17) 183 192 189 1980 2307 182 189 180 187 189 194 189 191 194 198 208 205 1981 2500 198 205 195 203 205 210 205 208 21( 215 225 223 1982 2710 214 222 211 220 222 228 222 225 2`8 23 3 244 241 1983 2938 232 241 229 238 2l1 2487 241 244 28,7 253 264 261 1984 3185 252 2(1 248 258 261 268 26] 2684 268 274 28'7 283 1985 3453 273 '83 269 280 283 290 283 287 290 297 311 307 1986 3742 297 3(7 292 303 307 314 307r 311 314 322 337 333 j/ See Annex 13 for explanation of' Level 1 For comparison between forecast and actual resmlts for years 1973, 1974 see Attachment, 3 Annex 9 Attachment 3 Compa-rison of Demand and Energy Forecast (Level 1) and Those Actually Obtained in the Interconnected System Demand MW Generation in GWh Forecast Actual Difference Forecast Actual Difference % 1973 January 223 221 - 0.9 99 98 - 1.0 February 227 224 - 1.3 102 102 0 March 231 225 - 2.6 97 91 - 6.2 1/ April 229 228 -0.4 101 84 -16.8 1/ May 227 221 - 2.6 102 91 -108 1/ June 225 220 - 2.2 105 104 - 1.0 July 228 225 - 1.3 102 100 - 2.0 August 230 228 - 0.9 104 103 - 1.0 September 230 243 - 5.7 105 108 2.9 October 243 242 - 0.4 107 104 - 2,8 November 251 243 -3.2 112 109 - 2.7 December 254 249 - 2.0 111 110 - 0.9 194 January 240 248 + 3.3 108 108 0 February 245 249 + 1.6 112 114 + 1.8 March 249 240 - 3.6 106 100 - 5.7 2/ April 247 239 - 3.2 110 107 - 2.7 May 244 239 - 2.1 112 106 - 5.4 June 243 237 - 2.5 114 112 - 1.8 July 246 245 - 0.4 . 112 107 - 4.5 August 248 244 - 1.6 113 111 - 1.8 September 249 251 + 2.0 114 114 0 October 262 264 + 2.0 117 111 - 6.o 3/ November 271 267 - 1.8 122 120 - 1.8 December 274 271 - 1.0 121 117 - 3.4 Total 1,361 1,327 - 2.5 1/ Load shedding due to late commissioning of San Antonio gas turbines. 2/ New tariffs of 41% authorized. 3/ New tariffs of 18% + 1% per month thereafter authorized. Knnex 10 Page 1 of 2 pages APPRAISAL OF FIFTH P01ER PROJECT - COSTA RICA INSTITUITC COSTARRICENSE DE ELECTRICIDAD (ICE) Dry Season Energy Requirements 1. Costa Rica's hydrological characteristics are somewhat exceptional, due to the nature of the dry season. Due to this, the Bank prompted ICE to carry out in 1973 a detailed study to determine more precisely the nature of Costa Rica's critical hydrological year. 2. The basis for this study was the statistical information of daily water flow for all the rivers where hydroelectric plants exist or may be installed in the future. A computer program was used to process all these data and obtain monthly and seasonal hydraulic generation for different hydrological probabilities. 3. ICE selected as a critical hydrological year that which occurs once every twenty years, i.e., a probability of 5%. Under this assumption, ICE's calculation showed that the monthly hydroelectric generation avail- ability for this critical year was slightly higher than the values obtained from an independent study carried out by Sofrelec at the same time (see annex 9). 4t. Using the results of the study mentioned in the previous paragraph and the load forecast (annex 9), ICE determined the monthly generation avail- ability and requirements for a critical hydrological year during the dry season (January to May). Attachment 1 to this annex shows these values (for the years 1975 through 1981) assuming that the first unit of Arenal is com- missioned at the end of 1978. (The 30 W Moin diesel power plant is not con- sidered in attachments 1 or 2, as these tables are shown-to justify its in- stallation). 5. It is seen that without considering any energy reserve, i.e., all thermal units available with a plant factor of 85S%, additional monthly generation of 14 GWh is required which is equivalent to a capacity of approx- imately 23 MW. The proposed 30 MW thermal plant (18.6 GWh monthly) leaves ICE with a monthly generation reserve of 4.6 GWTh in the worst month of a critical year in 1978. 6. Attachment 2 is a modification of the figures shown in attachment 1 with the assumption that the first unit of Arenal would not be on line by May 1979. On the same basis as above (critical hydrological year and no energy reserve), this table shows that in the worst month of the dry season of 1979 a shortage of 27 Gkh exists (equivalent to 43.5 MW). TAth the installation of the 30 MW diesel plant, the most severe monthly generation shortage would be 8.)4 Gih. 7. On this basis there is a need for the energy conservation program mentioned in paragraph 4.04 of the text. This energy conservation program would also have to be applied in the event of a prolonged outage of any of Annex 10 Page 2 of 2 pages ICE's gas turbine units during the dry season of 1978, and with more sever- ity in 1979 under the assumption of paragraph 6. 8. The installation of more than the proposed 30 MW thermal plant to cover the combination of contingencies described in paragraphs 6 and 7 is not considered justified because the losses to the economy would be minimal if an adequate energy conservation program were put into effect. Attachment 1 Attachment 2 March 1975 ANALYSIS OF THE INTERCONNECTED SYSTEM DURTN^ TH E DRY PERIOD OF CRITICAL YEARS 1975-1981 WITH ARENAL ENTERING END 1976 Difference Requirements Reserve Total Available Total Difference witaeout Hydro Therma-l any reserve, Ye ar Month MW GWh MW j GWh g/ MW GWh M_ GWh MW GWh MI! GWh MW GWh NW GWh 1975 January 264 119 32 12 296 131 224 97 125 78 349 175 53 414 85 56 February 269 123 32 12 301 135 202 75 125 78 327 153 26 18 58 30 March 274 117 32 12 306 129 203 71 125 70 328 141 22 12 54 24 April 271 122 32 12 303 134 192 67 125 78 317 145 14 11 46 23 May 268 123 32 12 300 135 184 66 125 76 309 142 9 7 41 19 1976 January 288 130 32 12 320 142 224 97 125 78 349 175 29 33 61 45 February 294 135 32 12 326 147 207 75 125 78 332 153 6 6 38 18 March 298 128 32 12 330 140 210 66 125 70 335 136 5 - 4 37 8 April 296 133 32 12 328 145 202 67 125 78 327 145 - 1 - 31 12 May 293 135 32 12 325 147 192 66 125 76 317 142 -8 - 5 24 7 1977 January 314 143 32 12 346 155 224 98 125 78 349 176 - 3 21 29 33 February 320 149 32 12 352 161 211 74 125 78 336 152 -16 9 16 21 March 326 141 32 12 359 153 216 76 125 70 341 146 -18 - 7 14 5 April 323 147 32 12 355 159 209 69 125 78 334 147 -21 -12 1 - May 319 149 32 12 351 161 205 71 125 76 330 147 -21 -14 11 - 2 1978 January 339 155 32 12 371 167 255 98 125 78 380 176 + 9 + 9 4i 21 February 345 161 32 12 377 173 222 74 125 78 347 152 -30 -21 2 - 9 March 351 153 32 12 383 165 230 76 125 70 355 146 -28 -19 4 - 7 April 348 159 32 12 380 171 219 69 125 78 344 147 -36 -24 - 4 -12 May 344 161 32 12 376 173 212 71 125 76 337 147 -39 -26 - 7 -14 1979 January 366 168 45 12 411 180 366 168 125 78 491 246 +80 +66 +U2 +78 February 373 174 45 12 418 186 368 171 125 78 493 249 +75 +63 +107 +75 March 379 166 45 12 424 178 366 158 125 70 491 228 +67 +5° + 99 +62 April 376 172 45 12 421 184 360 162 125 78 485 240 +64 +56 + 96 +68 May 372 174 45 12 417 186 356 164 125 76 481 240 +64 +54 + 96 +66 1980 January 396 182 45 12 441 194 397 182 125 78 522 260 +81 +66 126 78 February 404 189 45 12 449 201 380 171 125 78 505 249 +56 +48 101 60 March 410 180 45 12 455 192 374 158 125 (0 499 228 +44 +36 99 448 April 406 187 45 12 451 199 368 162 125 78 493 240 +42 +41 97 53 May 402 189 45 12 447 201 363 164 125 76 488 240 +41 +39 96 51 1981 January 427 198 45 12 472 210 408 188 125 78 533 266 +61 +56 106 68 February 436 205 45 12 481 217 379 171 125 78 504 249 +23 +32 68 44 March 443 195 45 12 488 207 381 158 125 70 506 228 +18 +21 63 33 April 439 203 105 12 484 215 3(6 162 125 78 501 240 +17 +25 62 37 May 434 205 45 12 4q79 217 370 164 125 Y6 1495 240 +16 +23 61 25 Reserve MW capacity is that of largest generating unit. j Energy reserve is that corresponding to largest thermal unit (20 MW) working with a plant factor of 0.85. No overload capacity is considered for the hydraulic units as the problem is lack of water, nor for the thermal units as their overload capacity is only available for short periods. i S O ANALYS.RJ O ITHE INTERPCODNEtrPD ',YSTEM DURFNG THE DRY PERIOD OF CRTT CATC, YEJAS 1975-1981 WTT &DIRAL EATERiNG AFTERR MAY 1979 Difference Requirements Reserve Total Available Total Difference without Hydro Thermal any reserve Year Month MM GWh M,W4 D.GWh LI ME GWh MW (;h MW GWh MW GWh MW GWh MW GWh 1975 January 264 119 32 12 296 131 224 97 125 78 349 175 53 44 85 56 February 269 123 32 12 301 135 202 75 125 78 327 153 26 18 58 30 March 274 117 32 12 306 129 203 71 125 70 328 141 22 12 54 24 April 271 122 32 12 303 134 192 6/ 125 78 317 145 14 11 46 23 May 268 123 32 12 300 135 184 66 125 76 309 142 9 7 41 19 1976 January 288 130 32 12 320 142 224 97 125 78 349 175 29 33 61 45 February 294 135 32 12 326 147 207 75 125 78 332 153 6 6 38 18 March 298 128 32 12 330 140 210 66 125 70 335 136 5 - 4 37 8 April 296 133 32 12 328 145 202 67 125 78 327 i45 - 1 - 31 12 May 293 135 32 12 325 147 192 66 125 76 317 142 -8 - 5 24 7 1977 January 314 143 32 12 346 155 224 98 125 78 349 176 - 3 21 29 33 February 320 149 32 12 352 161 211 74 125 78 336 152 -16 9 16 21 March 326 141 32 12 359 153 216 76 125 70 341 146 -18 - 7 14 5 April 323 147 32 12 355 159 209 69 125 78 334 147 -21 -12 11 - May 319 149 32 12 351 161 205 71 125 76 330 147 -21 -14 11 - 2 1978 January 339 155 32 12 371 167 255 98 125 78 380 176 + 9 + 9 41 21 February 345 161 32 12 377 173 222 74 125 78 347 152 -30 -21 2 - 9 March 351 153 32 12 383 165 230 76 125 70 355 146 -28 -19 4 - 7 April 348 159 32 12 380 171 219 69 125 78 344 1k7 -36 -24 - 4 -12 May 344 161 32 12 376 173 212 71 125 76 337 147 -39 -26 - 7 -14 1979 January 366 168 32 12 398 180 261 98 125 78 491 246 -12 - 4 +20 + 8 February 373 174 32 12 405 186 230 74 125 78 493 2k9 -5 -34 -18 -22 March 379 166 32 12 4k1 178 239 76 125 70 491 228 -47 -32 -15 -20 April 376 172 32 12 4o8 184 228 69 125 78 485 24o -55 -37 -23 -25 May 372 174 32 12 404 186 221 71 125 76 481 240 -q8 -39 -26 -27 1980 January 396 182 45 12 4141 194 397 182 125 78 522 260 +81 +66 126 78 February 404 189 45 12 449 201 380 171 125 78 505 249 +56 +48 101 60 March 410 180 4S 12 45S 192 374 158 125 70 499 228 +44 +36 99 48 April 406 187 45 12 451 199 368 162 125 78 493 240 +42 +41 97 53 May 402 189 45 12 447 201 363 164 125 76 488 240 +41 +39 96 51 1981 January 427 198 45 12 472 210 408 188 125 78 533 266 +61 +56 106 68 February 436 205 45 12 481 217 379 171 125 78 504 249 +23 +32 68 44 March 443 195 45 12 488 207 381 158 125 70 506 228 +18 +21 63 33 April 439 203 45 12 484 215 376 162 125 78 501 240 +17 +25 62 37 May 434 205 45 12 479 217 370 164 125 76 495 240 +16 +23 61 25 0 / Reserve MW capacity is that of largest generating unit. i/ Energy reserve is that correspondirng to largest thermal unit (20 MW) working with a plant factor of 0.85 3/ No overload capacity is considered for the hydraulic units as the problem is lack of water, nor for the thermal units as their overload capacity is only available for short periods. zAnex- 11 P'ag e 1 o` 2 p ages APPEATIS.- OF r ?JF! 7-H ? WF- - A 'A RICA TlT5T;'AIr l.,T0 W CCSLAn2i--o_;H --_ .El..TPRI2ZkiT) \ICE) e _ Ct z So1uti o aIn al the economic z_znkaro-cns carried cut, the fcllowTin- assinmpticnr rn relation to fuel prices were used: a, 3ost- o-F fu& -- Ci re Cj' = 30% of' crudoS oils~ b. c_st of dL,ese oi- = of crude oo_J_i c. cos-t of dieSel G__ = 139% of fuel oil, These -reatic:nshitpe are -_-la at 0ent in costa RicA ang have been aptrc.: lr-a-telv so for the I t s en years. C3le __st _f _'L _ W Ocsta Rica was tk en to be US$9/ fr o-i v t -at-e, corresponds ap.ox_-- l o B 3$ !tar1, rel FzfB PMiddle East. Comparisons made VIrtL r-gher -a c- I b, s sUS$12/barrel 0CIF3 Csta Rica) en-;:eG SljiAer esual°stn2 -ccimt rates for the proposed ge nr_ar a~~ J ~a c 'ie aonoi ,s- i-°-. cat fo th i-:b- a a,nsa tio 3 of thUe Rio Macho ad Cac'ioi extenisio-ns "se --ragrnnh w_ of- teo' 'ae, made cy- -3mnarin t;ee- n ^ ;o 't-h of' ta e :_a8 caz3 i, o-.peation and ra-aItenance cests -Ath -'-at- cf t2i~e C of fuel -necessary to generatte the t'herm-al ereri^-r they _ s_d no a<-n a7,-caze yjeA--y- genera n of 20 GIIi and 70 GWh rCeS-3u-3-I VEI-e 'he ares.l -re p eted in at'dach.re-nts 1 and 2 to this a-:-!e-, ,ihi^h s c-- t1at tohe R` o and Cachi extensions are the least cost d-sount -'-'- to '6.% and 20.5i% respectively. -- -n the est coSt e-J lution foit ie Drcposed thermal e WKI p orer -lt a zrntarison ass carried cutbetween: meadi-m speed diesel unrits - low stee-d diesel ur.its - gas t- rines The capital cost o0 these units were assumed to be: - medium speed diesel = 7r% slow speed diesel - gas !turbines = 50% slow speed diesel Fuel used f or the diIfferent type of machines: Annex 11 Page 2 of 2 pages - medium speed diesel - 70% fuel oil, 30% diesel oil - slow speed diesel - 100% fuel oil - gas turbines - 100% diesel oil The assumptions regarding capital costs and fuel consumption for the medium speed diesel engines are conservative in the sense that they favor the slow speed diesel engines solution. 4. Calculating the present worth of capital, operation and maintenance and fuel costs, it was shown (see attachment 3) that the medium speed diesel engines were the least cost solution for discount rates up to above 18%. A comparison was also made with a steam turbine plant and gave the same result i.e., least cost solution is the medium speed diesel power plant for discount rates up to above 18%. (This comparison is not shown in attachment 3 for clarity of presentation.) 5. The complete generation program of the proposed project was compared with two all-thermal solutions providing for the minimum requirements to meet energy and demand needs. The two alternatives considered were: i. a steam power plant of 50 MW to be installed in 1977 and a gas turbine of 20 MW to be installed in 1981; and ii. a gas turbine plant of 2 x 25 MW to be installed in 1977 with an additional 20 MW gas turbine unit in 1981. A comparison with all diesel or diesel plus gas turbines was felt to be meaningless having already been considered in the justification of the individual project components. 6. The present worth values of the three different solutions (con- sidering capital, operation, maintenance and fuel costs) are shown in attach- ment 4, which justifies the proposed project components for discount rates up to 21%. An additional comparison was made with an all steam power plant solution which justifies the proposed generating facilities for discount rates up to above 25%. 7. In the study carried out by Sofrelec (annexes 9 and 10) an analysis was made comparing the voltages of the future transmission systems for the hydroelectric developments of Arenal-Santa Rosa and Angostura then under consideration. It was found that 220 kV was the least cost solution when compared with 138 kV for all discount rates. The choice of 220 kV has the additional advantage of preparing the Costa Rican system for possible inter- connection of the Central American isthmus. Attachment 1 Attachment 2 Attachment 3 Attachment 4 March 1975 APPRAISAL OF FIFTH POVVER PROJECT - COSTA RICA ECONOMIC JUSTIFICATION OF RIO MACHO EXTENSION 2.2 l 2.0 1.8 0 \ Price of Crude Oil US$ 9/barrel 1.6 1.4F 1.2 1.0 0.8 E I l 6 7 8 9 10 11 12 13 14 15 16 17 18 PO Discount Rate World Bank-9797 APPRAISAL OF FIFTH POWER PROJECT -COSTA RICA ECONOMIC JUSTIFICATION OF CACHI EXTENSION 2.6 - _- - ------------- '--'-'---- 2.4 2.2 Price of Crtidc (0: I '. .Vba;i(,. 2.0 O 1.8 1.6 1.4 1.2 1.0 I I I I I I I I II I. _ __ 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Discount Rate World Bank-9796 I'-) APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA LEAST COST SOLUTION FOR MOIN THERMAL POWER PLANT 180 Price of Crude Oil US$ 9/barrel 170 Gas Turbine 160/ 150 _\ Slow Speed 140 I Medium Speed Diesel Diesel B 130 CO 120- 110 100 _ 90 _ 80 I I I I I I i I I 5 6 7 8 9 10 11 12 13 14 15 16 17 18 C+ Discount Rate OX World Bank-9662 C+ U) APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA ECONOMIC COMPARISON OF PROJECT GENERATION FACILITIES WITH ALL-THERMAL SOLUTIONS 340 320 - Price of Crude Oil US$ 9/barrel 300 - All Gas Turbine (70 MW) 280- 260- 240- 0 240 ~~~~~~~~~~~~~Combined Steam (50 MW) and t) 220 \ ~~~~~~~~~~~~~Gas Turbine (20 MW) 220- a),\ 200 - 180 - Proposed Project 160 - 140 120 - 100 I I I I I I I I I I I I I I L 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 P cD Discount Rate World Bank-9663 9 Ariex 12 Page 1 of 4 pages APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIJID (ICE) Return on Investment 1. Two rates of return were calcalated: a. the rate of return on investment in the project generation facilities and associated transmission and distribution works; and b. the rate of return considering the whole generation program through 1979 (including the Arenal hydroelectric power plant, the transmission works of the project and associated distri- bution facilities. 2. The bases of these calculations are the following: a. construction costs exclude price escalation beyond the first quarter of 1975 and interest during constr^uction; b. incremental cost for distribution equipment was estimated at US$140/kTAT. Distribution equipment for the Rio Macho and Cachi extensions -wPas considered as being necessary in 1988 when it is assuxmed that these units will be utilized to supply new loads rather than to replace generation of existing thermal plants. No distribu- tion investment was considered for the Moin power plant as its intended utilization (see paragraph 4.01 of the text) is that of meeting energy demands during the dry season, therefore, replacing hydro- electric energy for which the distribution networks already exist. c. operation and maintenance costs were calculated based on actual data supplied by ICE. Labor costs were computed at market prices. d. Foreign exchange costs were computed at the free rate of exchange. e. The incremental benefits were calculated using the average retail unit price of electric energy paid by the ultimate consumer and ICE?s estimates of generation (and therefore sales) by the generation components considered in the two alternatives anralyzed. These esti- mates of generation are based on the assunption of normal hydrolo- gical years for the period considered i.e., 50 years - the assumed life of the hydro portion of the project. 3. Based on the information shown in the tables on pages 2 and 3 of return for the two alternatives mentioned in l.a. and lb. are 15.3% and 11.8% respectively. Annex 12 Page 2 of 4 pages ensit±-rtTjV analysis If in`=estrment and operatin2 costs are assumed to rise by lC% the rates of return -would be 111% and 10.?% respectively. Project, ti:ing 5. The possibility of postponing the project generation facilities and associated transmission works for one year was evaluated by comqputing the discount rate which eqalizes the savings in investment and operating costs -which would result' with the benefits that would be lost. Since this ra-ts is aooD-e 71-, it would be uneconomic to postpore the project-. RetLro o,-, ]nuenLu,eul (Project Generation Failitirre) (In Million of Colons) (13 90cRn) ( 4 yeans) (16 yoars) 1974 19W7 19'76 977 1978 1979 1.980 1981 5 932 1983 1984 1985 1986 198'( 1933 1989-oo01 2002 2003-2006 2007 2008-2023 Capital costa of: Generation equipment 1.60 27.40 104.00 28.64 8L.oo Transmission equipment .15 0.23 20.80 1.90 23.00 Distribution equipment (2.00 Operation and maintenance cot- - _ 2.31 2.31 2. 231 2 .31 2.31 2 31 2.31 2.31 2 2.31 4.!7 4. 7 4.47t 4.47 4.47 Total costs 1.75 27.63 124.80 42.85 2.31 2.31 2.31 2.31 2.31 2.31 2.31 2.31 2.31 2.31 76.147 4.47 85.47 4.47 27.47 4.47 Total benefits 39.60 41.10 13.60 20.40 32.40 33.10 11.50 19.70 32.40 38.oo 46.70 55.40 56.90 56.90 56.90 56.90 56.90 Rate of return 15.3% Co,aplcte Progrol th_sogh 1979 Including Arenal (Jn .ilions of Colons) 1974 19(5 1976 19(7 1978 19'f9 1980 1981 l985 1983 1984 1985 1986 1987 ]988 1989-2001 200? 2003-2006 2007 2008-5023 CapitaL costs of: Generation equipment 45.1 127.40 239.00 173.6 ( 129.00 30.00 81.00 Transmaision equipment 0.47 1.31 75.(0 80 93.40 187.00 Distribution equipaeot 31,30 3]30 31.30 3I.3() 31.30 72.00 156. o Operation and naintenance - _ 2,31 3,25 _2213 13.l0 19.0 19.95 19.99 14.95 19.95 l9.L 19.95 l7.11 17.11 17.11 17.11 17.11 17.11 TotaL costa 45.57 128.71 314.00 287.25 251.95 73,43 4494°0 49530 14.95 14.95 14.95 14.95 14.95 14.95 89.11 17.11 98.11 17.11 360.11 17.11 TotaL benefits 39.60 41.10 129-00 132.80 167.'(0 162.60 1 L3.90 153.20 171.60 175.10 185.90 194950 196.3( 196.30 196.30 196.30 196.30 Rate of ret-rs 11" .8 May 1975 0 Annex e3 Pag_ 1 of 3 pages APPRAISAL OF FIFTH PO-VER PROJECT - COSTA RICA INSTITUTO COSTARR7CENSE DE ELECTRIC]7DAD 'ICE) Organlzation7 M aIn+1agement and Training Organization and management 1. ICE has a seven-memTber board of directors, one of wqhom is the Minister of Public Works serving ex-oficio. The other board members are appointed by the government for eight-year terms on a staggered basis and are eligible for re-appointment. Prior to 1970, Costa Rican laws apecified the composition of ICE's board by profession of it;s members; that provision was replaced in that year by another specifying their political affiliation. The political party in power nominates four members of the board, and the opposition, three. wTile this provision might appear unduly restrictive, ICE's board membership has maintained sufficient continaity; two board members have served since ICE's inception, and a third since 1954. 2. Underan April 1974 law the full-time position of executive presidency was created for all autonomous institutions, including ICE. The executive president is nominated by the president of the republic to preside over both board meetings ard the institution's operations, ICEs first executive presi- dent is one of the two origiral mebeSrs of its board and with the additional responsibilities he has begur, to add needed depth and peropective to ICE's policv making and top management. 3. The board appoints ICE's general manager, three dep-aty managers, treasurer and auditor. The general manager appoints other o:icials, sub- ject to board approval for senior posts. 4. Prior to April 1973, seven divisions reported to ICEts general manager. Four cf these related to electric operations, one to telecommuni- cations. and two tO accounting and administrative natters. In 1973, ICE took a large step towards autono-my of its two operating sections boy creat- ing three deputy managers: one each for power, telecoMnmunicaticns and administrative ser-ices. 5. As shown in the attached organization chart, ICE's power section has five divisions: planning, engineering, construction, production and distribution. This organilzation reflects the emphasis which ICE has placed on construction of works but is satisfactory to meet the needs. 6. In theory , ICE should achieve economies of scale by having one finance/administratio-n section nerform all commiercial and support functions, which are basically sirilar for the two operating dvsioins, ITn practice, however, there is a darer th^at the adriniLstrative section may become self- serving. -o _ome degree, this process may have begun: there is evidence of Annex 13 Page 2 of 3 pages the finance/administrative section's non-responsiveness to the needs of the two operating sections; and the increase in its operating expenses have been in excess of ICE's revenues or the operating sections' expenses. The prob- lem can be resolved to some degree by controlling the section's future per- sonnel growth, as would be done by adherence to the performance indicators (paragraph 3.08 of the text and annex 3). Training 7. ICE's personnel training department (in its finance/administration section) conducts surveys to identif. the training needs of all three sec- tions. To provide technical training for its power employees, ICE has de- veloped cooperative training programs in conjunction with Costa Rica's Instituto Nacional de Aprendizaje and Instituto Tecnologico; most technical training will be carried out in cooperation with these institutions. The utility arranges for its professional employees to take courses at the Universidad de Costa Rica or outside the country, depending on the avail- ability of the required training. 8. The program for the next five years provides for training for almost 800 power-section employees, as detailed below: Professional Technical Total 1975 27 108 135 1976 31 113 144 1977 36 121 157 1978 4i 129 170 1979 46 137 183 Total 181 608 789 This training program is adequate. Organizational separation 9. Authorizing ICE, which was at the time a comparatively well- managed and financially viable public institution, to provide telecommunica- tions in addition to power was an effective method of instituting nation- wide telecommunications service in the mid-1960s. However, previous Bank missions have observed that the lack of separation of responsibility for the two services would eventually have detrimental results to one or both of them, particularly as the size of both operations grows, because of: their distinctness from planning, technical, operational and marketing points of view; and the inability of a single board and executive to cope with increasingly complex problems of the two divergent sectors. In negotiations on the fourth power and third telecommunications projects (loans 800- and 801-CR, respectively )ICE agreed to hire management con- sultants to study, inter alia, the degree of autonomy desirable for optimumn provision of each service. Anrex 13 Page 3 of 3 pages 10. The management consultants (Urwick) founrd that: ICE's present organization and management are capable of running both operations satis- factorily; as both operations grow, the need to separate ICE will become apparent to the management and directors; and (in view of the strong.feel- ings of ICE and the government against separation') there is no compelling reason to separate the institution now. 11. While ICE's present organization does not separate the two opera- ting sections as much as previous Bank missions had suggested - e.g., it does not include separate accounting or personnel organizations for each of the operating sections - it does establish reasonable autonomy for each, subject only to the general manager and the board. Responsibilities remain- ing under the deputy manager for finance and administration are only those whichl do not relate directly to provision of electric or telecommunications service, leaving each operating section free to carry out its own planning, engineering, construction and operations. With assurances concerning the continued separate operation of the-two sections (see paragraph 5.04 of the text) the present arrangement is acceptable. Attachment March 1975 INSTIT(I10 COSTARRICENSE DE EEECTRICIDAO (iCEI POWER SECTION GSWFRAT ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~rOENDN ICNIA =OSMS,S BAI COC Lnnex 14 Page 1 of 13 pages ApPFR'TS.L cF EOF T PAOWTER PROJECT - COSTA RIt -~~Xr~~T-h.C CSTA-IChEE DE ELECTRI IDAD (IcE) Dower Section Finarnial Statements and Forecasts Summary 1. This annex includes the following financial statements and fore- casts of ICE's power section for 1972-79: a. key financ-ial ra-l_A - _ 3 b. income statenentS - Fage 14 c. forecast funds statemerts - page 5 d, constructioin programra details - page 6 e. forecast debt service - page 7 f. outstanding debt - nage 8 a. balance sheets - page 9 hK assu,ms-s:n s u se i farecasts - page 10 ff r~-i:P!~r--cr- eama -ran~m coaicon 7~~~~~C rG- Z,;l_ S Slc l-aiJ.t 2. I3B's pow-,^7er section has had satisfactory oper-a-ting res-lts, with nominal rates of return c` 10-13%, since 1968. Revaluation of rate base to reflect local price inflaticn. which hnas beer incre-asing at a-.in-al rates of at least 25% beginning 4n l9-35, wo0ould have decreased its 1973 levels some- w4hat below tnhe 9% rate incluaed in Bank loan agreements, but to seriously low l1vels. 3 ay 20fc-egre-, the generally-adequate earnings levels were ins-ufficient 1Fc C y f-Jcr cost overrins of 90-1'00'a-' on the third power project (see para- g,rapn 5,35 a the tex,,). Because TCE had to resort --to redi-m-term com- mercial fi-nancing to pay for these overruns3 -t enco-ntered sever-e cash problems in 1973 and earliY 1974, so that it wuculd^ have been u,noable to cover its power-section debt sertice in 1974t W1 Zhcut remed-al actions. 4 1hTe remedial actions were twof old: tari&f increases and debt rescheduling, After discussion .a th a Bank supervision mission- in September 19733 ICH applied for an electric tariff increase to raise its power revenues by % .LX SNE apprcrved this increase in '%arch 197v .51 apoved furt-her tariff increases of 18% in ceptenioer 197i and 1% per month fcr each of 1974's remaining months3 which wTere needed -unimarnly to compensate for the March 1971; exchange-rate unification of the colon. In 197L4-75 ICE a'lso refinanced US$30 raillion of short-to-medium-term debt which it contracted for in the early 1970s with lower-cost and longer-term debt. Annex 14 Page 2 of 13 pages 5. With the above actions, the power section's financial performance is expected to be adequate for 1974, showing a rate of return of above 9% and debt-service coverage of 1.4 times. Wth revaluation reflected in the accounts, the power section's debt/equity ratio at year-end 1974 would be an acceptable 56/44. Future financial performance 6. As noted in paragraph 3.05 of the text, Costa Ricar price infla- tion is expected tc conrtinue at high rates throughout the project period. To provide for an adequate pricing mechanism for electricity, it is assumed that ICE's power assets will be revalued annually at the assuimed inflation rates, and that its electricity tariffs will be set so as to produce a 9% annual return cn t.he revalued assets. This will require an increase of about 100% in C!CE bulk and retail tariffs by 1979, the first year after project completicn. 7. Assuming the prompt implementation of necessary tariff increases, the financial performance of ICEts power section is expected to be satis- factory throughout the project period, as indicated by its key financial ratios. Because of its still-heavy debt-service requirements and its ambitious construction program, its contribution-to-expansion ratio for the project period is expected to be low - about 21%. This is acceptable for reasons detailed in paragraph 6.10 of the text. ICE Power Section Key F1nancial Ratios 1972-79 (Amounts expressed in millions of' colones) 1972 1973 1974 1975 1976 197'( 1978 1979 Return on net plant Average net utility plant in operation 421.2 507.3 898.8 1,499 1,859 2,298 2,998 4,285 Operating income 54.4 54.5 84.2 135 172 217 271 386 Percentage return 12.9 10.7 9.4 9.0 9.3 9.4 9.1 9.o Debt Times debt service covered by internal cash generation 1.9 1.3 1.4 1.7 1.4 1.7 2.0 1.8 Debt/equity ratio 54/46 56/44 56/44 52/48 54/46 54/46 52/48 50/50 Working capital Working capital at year-end 55 .4 49.3 65.5 49.5 55.8 60.5 55.6 68.3 t D Current ratio (to 1.0) 1.8 1.4 1,6 1.3 1.3 1.3 1.2 1.2 Ux 0 z Depreciation As a per!entage of' average gross utility plant 2.23 2.51 2.87 2. 94 2. 9!! 2.96 2.'38 2.92 , (D2 (2 ICE Power Section Income Statements 1972-79 (in thousands of colones) ---Actual - - - Estimated - - - - - - - - Projected - - - - - - - - - - - - -- 1972 1973 1974 1975 1976 1977 1978 1979 Energy sales in GWh: Bulk 712.4 785.2 874.5 945.7 1,o48.1 1,160.0 1,281.L 1,409.8 Retail 130.0 154.9 159.5 168.6 182.7 198.7 215.7 234.1 Total 8%i97 940.1 1,034.0- i7,l 3 1,64230.9 TT357 T1V9 Average price per kWh - in colones Bulk 0.109 0.108 0.152 0.210 0.242 0.280 0.322 0.400 Retail 0.151 0.155 0.187 o.260 0.300 0.350 0.403 0.500 Revenues from energy sales - bulk 77,299 84,604 132,904 198,597 253,640 324,800 412,514 563,920 - retail 19,666 23,996 29,830 43,836 54,810 69,545 86,927 117,050 Other operating revenues 397 493 1 200 1,320 1_jL52 1,597 1,757 1,933 Total operating revenues 97,362 109,093 163,934 5309,,02 395,942 501,196 582,903 Operating expenses: Purchased electricity 2,424 24 - _ - - - - Generation 12,107 16,614 17,959 18,411 21,734 30,389 33,679 40,381 Transmission and distribution 6,627 9,454 11,907 15,238 20,386 26,805 35,562 43,591 Institutional 7,903 10,670 14,351 17,415 22,591 29,771 37,103 45,682 Insurance 519 595 2,081 2,367 2,829 3,955 7,351 8,o87 Regulatory expense 1,213 1,497 2,248 2,458 3,543 3,972 5,665 6,132 Depreciation 12 140 15.744 31,217 52,346 66,512 84,267 111 200 152 605 Total operating expenses #-933 54,598 79,976i3 108,235 137,595 179,159 operating income 54,429 54,495 84,171 135,518 172,307 216,783 270,638 386,425 Non-operating expense: Interest paid 29,224 44,o05 53,900 86,573 144,871 178,952 214,800 265,490 Less interest charged to construction 12 351 1913364 5,741 95,971 143 154 105 217 Interest charged to operations 16,873 -%4,920 39,370 73,209 99,130 82,981 646 Less non-operating income 7 943 7,204 11 480 9 350 8,974 7,966 7 677 9 224 Net non-operating expense 819307,71 6 99 - - 75,015 15,969 0549 Net income 45,499 36,779 56,281 '71,659 82,151 141,768 206,669 235,3'76 Capital and surplus at beginning of year 326,138 372,512 410,5'78 704,503 1,009,959 1,393,126 1,870,563 2,528,395 Contributions 909 1,287 1,384 1,430 3,382 5,997 4,917 4,198 Revaluation - - 236,260 232,367 297,634 329,672 446,246 320,400 o Other charges 3- - - - _ __D Capital and surplus at end of year 372,512 410,578 704,503 1,009,959 1,393,126 1,870,563 2,528,395 3,088,369 o - 0) '0 S (D'0 CE lbowcr Sectioh Forecast Sources and Applications of Funds 1975-79 (in thousands of colones) Total 1975 1976 1977 1978 1975-78 1979 SOURCES OF FUNDS Internal cash generatiorn: Net operating income 135,518 172,307 216,783 270,638 795,246 386,425 Depreciation 52,346 66,512 84,267 111,200 314,325 152,605 Other income 9,350 8,974 7,966 7,677 33,967 9,224 Bond repayment by CNF1, 2 ?,662 2 8,19 3 376 1_239 3,655 Total --9,A 250,6751. 312,135 39 1,155,577 551,909 Debt service (see pape 7 for details): Amortization I12,147 79,536 96,48 1''1,3'72 339,503 147,322 Interest charged to operations 71209 99 130 82,98: 71.646 326,966 160 273 'Total debt service 13_,3TI _,__6 17'W9 193,018 666,469 307,95 Net internal casli generation 84,520 72,009 132,706 199,873 489,108 244,314 Borrowings: Existing loans - IBRD 800-CR 818 2,031 - - 2,849 IDB 273 1,018 - - - 1,018 - CABEI loan 7,775 2,264 - - 10,039 Commercial loans, net 7,310 50,985 76,380 - 134 675 _ Total existing 16,302 55,2 0 0 - Proposed loans: Bank loan 30,676 186,543 181,0)55 45,813 444,o87 CABEI loan 7,062 30,828 40,3.85 70,19 156,271 IDB Arenal loan 82,874 165,655 177,988 122,182 548;699 Local bonds 35,000 30,000 25,000 23,500 113,500 30,000 FIV loans - 75,000 75 000 125, 000 275,000 80,000 Total proposed 155*12 3,02 49,22 9 1,537,557 310,000 Future loan: Santa Rosa foreign cost - - 9 140 129,141 13,281 313,904 Total borrowings 172,533 53,36 584,748 523,32 1,82419 423,904 Contributions - from customers and from CNFL for local project costs 1,43 3,382 5,997 4,917 15,26 4,198 Total sources 258483 7 _723,451 4728622 2.329,3 672,416 APPLICATIONS OF FUlNDS Construction program (see page 6 for details): Existing projects and continuing works 33,180 18,625 7,379 9,287 68,471 10,984 Proposed projects: IBRD fifth )15,639 286,109 314,264 12,665 768,67'7 A, eol1 jyd:ro 153,7)13 ?84, 670 330,)418 340,306 1,109,13'7 125,524 Future project: Santa Rosa hydro 3___ 408 ,"6311.i 260,719 503,403 Total const.uction 289, 404 6,6,465 -2 t '2(7,flv Z-3 91~91l Studies of future projects 4,693 5,959 7,351 8,954 26,95'( 10,710 Additiorts to working capital: Cash 753 11,443 10,704 -756 22,144 3,868 Other 20,475 11,891 18,927 21,855 73,148 17,927 Total additions to working capital 21,22. 2333 29,631 ,70 _ 2 21,795 se Total applications of funds 2568897 2345 728,622 2,329,253 672,416 u o z Cash at beginning of year 2,810 3,563 15,006 25,71D 24,954 Cash at end of year 3,563 15,006 25,710 24,954 28, 822 ~ ICE Power Section Construction Program 1975-79 Including Interest Charged to Construction (in thousands of colones) Total 1975 1976 1977 1978 1975-78 1979 Existing projects and continuing works: Fourth IBRD project 7,268 5,262 - - 12,530 - Second IDB project (distribution) 1,605 - 1,605 _ Second CABEI project (Cachi-Moin line) 11,230 6,170 - - 17,400 _ Routine expansion 13,077 7 193 7 379 9,287 36 936 10 984 Total existing and continuing 33,180 7,379 987 1 0, 9o4 Proposed projects: IBRD fifth project: Rio Macho extension 2,484 14,339 22,946 - 39,769 - Cachi extension 4,425 24,652 35,258 _ 64,335 - Moin diesel plant and fuel tanks 15,898 62,214 9,480 - 87,592 - Transmission works: related to Arenal 274 23,746 59,573 34,365 117,958 - related to fifth project generation 247 29,993 1,312 - 31,552 - San Jose ring plus distri- bution 14,272 24,543 17,869 6,106 62,790 - line extensions 411 26,358 26,207 10,290 63,266 - Load dispatching system 47. . -106 14,7583 1,349 16,260o - Studies - 2,o60 - - 2,o60 - Total base cost 37,055 205 187,403 52,110 4U5,582 - Physical contingencies 3,805 20,801 18,740 5,211 48,557 - Price contingencies 2,036 39,.440 64,879 10,356 116,711 - Interest during construction 1,740 17,857 43,242 54 988 117,827 - , d Total fifth project 3206,i9 - Arenal hydro development 153,743 284,670 330 418 340,306 1,109,137 125 524 ox Total proposed 199,382 570,779 644,682 462,971 7H Future project: Santa Rosa hydro development - _ 34,408 226,311 260,719 503,403 > Total construction prograrn 232,562 589,404 686,469 698,569 2,207,004 639,911 m (D ICE Power Section Forecat Debt Service 1975-79 Pa-gr 7-R13 p4ges (in thoumands of colones) INTEREST AND COMI SSIONS 1975 1976 1977 1978 1979 Existing debt: IBRD loans - 276-CR 2,948 3,110 3,169 3,175 3,083 346-CR 4,519 4,793 4,917 5,005 4,973 631-CR 6,803 7,492 8,o48 8,601 9,013 800-CR 4,644 4,8554 5,228 5,550 5,765 Foreign currency revaluation 2 866 3,12L 3 294 3 465 3 562 Total IBRD 2t1Wo 23,370 246 25,79 26, 396 IDB loans 2,308 2,52:L 1,861 1,877 1,845 CABEI loans 1,750 2,457 2,496 2,378 2,171 Total international agencies 25,838 28,348 29,013 30,051 30,412 US Eximbank 1,160 1,31:3 1,453 1,505 1,200 Ebasco loan 5,o83 5,417 5,594 5,704 5,641 Foreign commercial loans 10 101 8 344 5 668 3,163 868 Total foreign 42,182 I,21, 40,423 38,121 ICE bonds 8,841 14,012 11,470 11,268 11,041 Other local loans 3,145 2,75( 2 406 2 161 1 998 Total existing 54,168 60,184 50316 Proposed borrowing: Bank loan 956 12,597 28,398 44,o46 47,745 CABEI loan 273 1,802 5,164 7,460 12,056 IDB loan (Arenal) 10,563 23,987 32,877 35,333 53,328 Local bonds 2,100 5,895 8,895 11,730 14,700 Commercial financing 18,513 37,406 38,027 37,259 32,917 Venezuelan loans - 3 00( 9,210 18 855 28,489 Total proposed 32,405 122,571 154,683 189,235 Future borrowing for foreign cost of Santa Rosa hydro project - - 77 6.265 25,095 Total interest and commissions 86,573 144,87L 178,952 214,800 265,490 AMORTIZATI ON Existing debt: IBRD loans: 276-CR 3,513 4,203 4,925 5,771 6,644 346-CR 5,067 6,058 7,093 8,269 9,458 631-CR 2,776 3,347 3,990 4,725 5,411 8oo-CR - 1,185 2,793 3,339 3,905 Revaluation 1,674 2 152 2 667 3,150 3,616 Total IBRD 13,030 5,2 29,034 IDB loans 2,853 3,229 3,574 3,950 4,295 CABEI loans - 1,948 4,312 4,766 5,182 Total international agencies 22,122 29,354 33,970 38,511 US Eximbank - - - 6,690 7,274 Ebasco loan 3,760 4,592' 5,484 6,540 7,674 Foreign commercial loans 16,926 27,501 28,293 17,766 13,824 Total foreign 36,59 54,215 63,131 64,967 67,283 ICE bonds 957 1,424 1,602 1,804 2,031 Other local loans 4 621 4,4293 3,942 1,939 1,658 Total existing 60,6 68,675 68,709 70,972 Proposed borrowing: Bank loan - - - - 10,056 CABEI loan Venezuelan loan - - - - 5,469 Commercial financing - 17,718 24,523 48,163 54,825 ICE bonds - 1,750 3,253 4,500 6,ooo Total proposed - 19,468 27,773 52,63 76,350 Total amortization 42,147 79,536) 96,448 121,372 147,322 Annex 14 Page of 13 pages ICE Power Section Outstanding Debt at December 31, 1973 (in thousands of colones) IBRD loans - 276-CR 40,71& 346-CR 64,715 631-3?. 790u 800-CR 41,030 Total IBRD 2253553 IDB loans 21,361 CABEI loans 826 Total international agencies 3 Ebasco loar 51S769 Foreign ccmnercial loans 1]3- 38 Tota-l foreign 4 5 47 ICE bords 118,052 Other local loans 26 238 Total 577,'37 Note: The above amounts do not reflect fluctuations in foreign-exchange rates with respect to the US dollar since 1971. Revaluing ICE's IBRD debt to reflect such fluctuations would increase its valuation by about 15%, or 034,000. Almost all other foreign debt is denomi- nated in US dollars. ICE Power Section Balanice Sheets at December 31, 1972-79 (in thousands of colones) - - - -Auidited- - - - EsLimrated - - - - - - - - - - Irojected - - - - - - - - - - - - - - 1972 1973 19(4 1975 19i76 1977 19,78 1979 ASSETS Utility plant in service 591,599 662,035 1,513,247 2,047,739 2,476,912 3,213,030 4,237,718 6,226,355 Less accumulated depreciation IN3 586 150 657 227 121 336 247 4/(o oo8 624 776 829,692 1 065 266 Net utility plant in service l, -I, 3 s3 ,2S6375f l711,42 2, 00)90 2,5E> 3,408l,026 5T11, Construction work in progress 204 016 28%2_13 172 297 26'1 37 883 184 1L338,9?0 1 697237 798 8 Net utility plant 65,029 ^795,091t 1,'45'3 1,973,329 2,,80 3,927,1374 5,105,263 9, 7t Studies of future projects 18,980 17,792 19,583 27,339 38,'766 50,111 64,488 81,6417 Investments 66,164 64,54'7 54,385 51,723 48,841 45,722 42,346 38,691 Current and other assets: Cash and short-term investments 5,741 3,826 2,810 3,563 15,006 25,710 24,954 28,822 Accounts receivable less reserve 14,319 24,734 23,357 3l,0)0o 42,000 52,000 65,000 87,ooo Materials in stock and in transit 94,450 131,934 137,210 157,00) 172,000 191,000 211,000 215,000 Other current assets 230 282 300 300 300 300 300 300 Other assets 12,430 17 96) 18 186 18 500 18,500 18 500 18,500 18,500 Total current and other 127,170 ]E1 23,3 247,806 2 7gyo 319,754 349,622 Total assets 877,343 1,056,170 174254 2265,75 3,225,501 4,310,517 5, 531, 851 6,429,920 LIABILITIES AND CAPITAL Equity 372,512 410,578 704,503 1,009,959 1,393,126 1, 8'0,563 2,528,395 3,088,369 long-terml. debt 470,240 577,137 935,553 1,171,325 1,736,796 2,334,302 2,886,659 3,?16,681 Less current portion 37 199 60 962 42 147 79,356 96 448 121,3'72 47,322 156,438 Net long-term debt 433,01 5165:)75 0 1 1 2,212,930 2,739,337 Current and other liabilities: Current portion of Thng-term debt 37,199 60,962 42,1i.47 79,356 96,448 121,372 147,322 156,438 Accounts payable 9,092 34,531 36,255 115,000 54,000 63,000 72,0(00 79,000 Security deposits 1,538 2,,(49 2,361 2,4'(0 25579 2,65,2 2,'797 2,870 D Other current lisoi.I;ies 1,857 6,1t 6,582 8, oo o(,ooo ll,()0() 13,000 14,000 CO Other credits 22_ 104 25,57____ 25,0() 29,000 2,29 O0 29000 29000 O x Total current and other 71,790 129,417 1:69, I')2,O2' 22,O,0'± 264,319 281,308 o e Total liabilities and capital 877aL 1,1 056,170 14 209 1- (D Annex 14 Page 10 of 13 pages Assumptions Used in Financial Forecasts Revenues 1. ICE's level 2 forecasts (see annex 9) indicate future annual sales growth of 8.6%, which is acceptable, 2. To produce an annua1 rate of return of about 9% on a revalued rate base, annual tariff increases as indicated on the income statement will be necessary, assuming the annual inflation rates indicated in para- graph 3.05 of the text. It has been assumed that average retail tariffs ill be 20% higher than average bulk tariffs, which approximately corre- sponds to recent history. 3. It should be noted that the tariffs and revenues shown do not include provisions for fuel costs. In Costa Rica, fuel costs are passed on to consumers via surcharges which are revised every six months, but both the cost of fuel and revenues received therefor are accounted for separately, outside the ordinary revenue/expense accounts of the utility. Expenses 4. Annual depreciation rates in percent: Fifth project 3.29 Arenal 2.50 All other property 2.94 5. Number of employees and average salary by function (excludes data on employees engaged in studies, engineering or construction): Annex 14 Page 11 of 13 pages Average 1974 salary in thousands Number of employees F-nction of colones 1974 1975 1976 1977 1978 1979 Power Section Eydro generation: Production 27 120 122 123 131 159 166 CLerical 33 12 12 13 14 17 18 Thermal generation: Production 23 137 116 99 114 62 62 Clerical 36 15 13 11 11 6 6 Transmission: Technincal 20 140 154 169 186 205 226 Clerical 25 14 15 17 18 21 23 Distribution: Technical 15 120 166 179 193 207 219 Clerical- 25 9 15 16 17 19 20 Administrative: Production 28 56 58 61 67 70 74 Distribution 25 69 74 80 86 92 99 Finance/Administration Section Professional 50 49 50 51 52 53 54 Clerical 25 450 461 473 484 495 508 Technical 15 338 347 355 364 372 382 Total 837 85 900 2 94 6. The assumed local annual inflation rate (paragraph 3.05 of the text) was applied to all expenses except depreciation. Methods of valuation 7. Until 1974, all ICE's assets and liabilities were carried in its books of account using historical cost values. In 1974, assets and foreign indebtedness were revalued to give effect to the unification of the colon's exchange rate, which was an effective devaluation of about 29% for ICE. Fur-. ther revaluation of both ICE's fixed assets and foreign debt is discussed in paragraphs 6.04-07 of the text. Based on preliminary analyses made by the Bank and ICE's staff during field appraisal, projections incLuded in this report assume that ICE's electric rate base would be increased by about 50% at Decem- ber 31, 1974 to reflect local and worldwide inflation to that date, and its indebtedness to the Bank by about 15% to reflect worldwide currency fluctua- tions. 8. As indicated in paragraph 6.06 of the text, the revaluation calcu- lations completed in April 1975 increase the value of ICE's electric rate base by 48%. As shown below, the April 1975 calcuilations are not sufficiently different from those included in the projections to warrant changing the projections. Annex 14 Page 12 of 13 pages As of December 31, 1974 (in millions of colones) April 1975 Previous calculations calculations (page 9 of this annex) Utility plant in service 1,535 1,513 Accumulated depreciation 289 227 Net plant in service 1,26 1,26 9. Beginning in 1975, annual revaluations of net fixed asset balances (including construction work in progress and studies) are assumed at the local inflation rates shown in paragraph 3.05 of the text and annual re- valuation of foreign debt are assumed at the difference between local and worldwide inflation rates shown in the same paragraph. The difference be- tween the asset and debt revaluations is credited to equity as below: Revaluation in millions of colones Net fixed Foreign assets debt Equity 1975 338 106 232 1976 399 102 297 1977 439 109 330 1978 596 150 446 1979 370 53 317 LIong-term indebtedness 10. The terms of recently-contracted and expected long-term debt follow: Date of Annual Term of loan in years Source loan Amount interest % Total Grace IBRD 1975 US$41 million 8.5 25 4 IDB 1975 us$50.5 million 8 30 6 CABEI 1975 US$ 8.1 million 8 15 4 FIV 1975 0380 million 8 25 4 Local Annual 0150 million/year 12 20 - (030 million/year) Bank of America 1974 Ub$5 million .8 1 Chase Manhattan 1974 US$5 million 8 3 Chemical Bank 1974 US$10 million * 8 1 Dillon, Read 1975 US$10 million * 10 3 * 1.5 to 1.75 percentage points above LIBO Annex 14 Page 13 of 13 pages Investment program 11. The construction program excludes the Boraca hydro development (annex 5) and the rural electrification program (paragraph 2.08 of the text) because separate funding would be established for the Boruca pro- ject and most of the rural program, and because the latter would incorpo- rate additions to the systems of various cooperatives as well as ICE's. 12. Assumed dates of transfer of works from construction work in progress to plant in service: - Fifth project - 50% in 1977, 50% in 1978 - Arenal - 1979 - Minor works - annually 13. Increases in working capital were estimated by establishing the following year-end relationships, based on analyses of actual data: - Accounts receivable - 12% annual revenues, representing 1½- months' sales - Materials and supplies (except materials in transit) - 3 to 3.5% of gross value of plant in service until completion of Arenal, 2% thereafter. May 1975 ANNEX 15 Page 1 of 6 pages APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) CNFL Financial Statements and Forecasts 1. This annex includes the following financial statements and fore- casts for CNFL for 1972-79: a. key financial ratios - page 4 b. income statements - page 5 c. forecast funds statements - page 6. 2. CiNFL had satisfactory operating results, with nominal rates of return of bout 10%, until 197h. Revaluation of rats base to reflect local pr,ice inflation would have decreased its 1972-73 eamings levels somewhat, but not to seriously low levels. Contirnued inflation reduced CNFL's rate of return to unacceptably low levels (6% on an original-cost base and 4.7% on a rate base reflecting an assumed 50% revaluation at year-end) in 1974. During 1974, SNE permitted CNFL to put into effect tariff increases sufficiently high to pass on the increased cost of electricity purchased from ICE, but not high enough to offset the impact of inflation on its own expenses. To remedy this situation, CNFL applied for and received tariff adjustments to increase its revenues by 10% beginning January 1975 and a further 5% beginning June 1975. GiNFL rate determination 3. The financial arrangements for the acquisition of CNFL by ICE were detailed in the third power project appraisal report (no. PU-14a, June 11, 1969). Briefly, they provide that CNFL's revenues are to be sufficient to: cover operating costs and debt service; make payments to ICE enabling it to service the debt incurred for CNFL's acquisition; and carry out necessary investments in CNFL's distribution networks. In practice, CNFL has obtained loans from CABEI and suppliers for the foreign cost of its investment program, financing the local porton internally. Existing loan agreements between ICE and the Bank provide that ICE should take all steps necessary to obtain such adjustments in CNFL's power tariffs to provide sufficient revenues for CNFL in accordance with provisions of Article 16 of its concession agreement, as summarized above. 4. Assuming that CNFL continues its present financing practice (paragraph 3), it will have to earn relatively high returns (12% - 13% on a revalued rate base, t'r comply with the requiremBnts during 1975-76, when its expansion program is relatively large. During loan negotiations, the Bank suggested the possibility of substituting rate-of-return provisions for CNFL which are similar to ICE's, but ICE representatives maintained that the problems associated with changing the concession agreement would outweigh the advantages to be gained. ANNEX 15 Page 2 of 6 pages Revaluation and financial forecasts 5. Regardless of the mechanism used for setting power tariffs, CNFL's rate base should be revalued to reflect severe price inflation in Costa Rica (see paragraph 6.o0 ff. of the text); completion of such revaluation is proposed as a condition of loan effectiveness (see paragraph 6.07 of the text). It is assumed in the financial projections included in this annex that: revaluation to increase the value of CNFL's fixed assets, accumulated depreciation and work in progress balances will be made in a manner consistent with that of ICE's power assets and will at least reflect the local price inflation foreseen in paragraph 3.05 of the text; and 5NFL's rates will be set to enable it to pay for the local cost of its investment program, including additions to working capital (see paragraph 4). Based on the above, CNFL's average tariffs for the period 1975-79 would be almost identical to ICE's average retail tariffs. 6. With revaluation and tariff action as described above, CNFL's financial performance would be satisfactory for the forrf.ast period: its rate of return would equal or exceed 9% (except in 1979, when it would be slightly below that level), and its debt service coverage would exceed two times. Construction program and financing plan 7. CNFL's construction progran is basica'Lly a continuing series of investments in relatively small distribution works. For its own analysis, it breaks the program down by source of financing. Its current program includes: existing projeets financed by CABEI and suppliers, which are to be substantially completed by 1975; and the next expansion program (1976-78), part of which is included as a portion of the fifth project (see annex 7). It plans to seek CABEI financing for the foreign cost of the next expansion program not included in the fifth project. 8. During the four-year project period, CNFL would pay for over 60% of its construction program and working capital additions with net internal generation of funds plus contributions. This contribution-to-expansion ratio is at the high end of the range normally expected for distribution companies. However, the combined ICE/CNFL contribution ratio is only 24%, which is at the low end of the acceptable range for full-spectrum electric utilities. The financing plan is summarized below and detailed in page 3 of this annex. Annex 15 Page 3 of 6 pages Financing plan 1975-78 - - - millions - - - Colones us$ % Requirements of funds Construction program: Existing project 47.4 4.9 Proposed expansion 135.9 11.6 Total construction 183.3 16.5 89 Increase in working capital 21.9 1.9 11 Total requirements 205.2 18.4 100 Sources of funds Net income before interest plus depreciation 183.9 16.8 Less service payments 73.5 6.8 Net internal generation 110.4 10.0 54 Contributions 16.6 1.5 8 Borrowings: Existing loans 6.4 0.7 Proposed ICE loan (IBRD proceeds) 2.9 0 Future CABEI loan 4.9 42 Total borrowings _7__7 __79 38 Total sources 205.2 18.4 100 CNFL Key Financial Ratios 1972-79 (amounts expressed in millions of colones) Actual Estimated Forecast 1972 1973 1974 1975 1976 1977 1978 1979 Return on net plant Average net utility plant in operation 104.7 110.0 127.2 178.9 240.2 306.5 389.6 476.8 Operating income 10.2 9.9 5.9 23.8 28.5 30.2 37.7 41.0 Percentage return 10.3 9.3 4.7 13.3 11.9 9.9 9.7 8.6 Debt Times debt service covered by internal 1.'7 1.8 1.1 2.9 3.4 3.8 3.8 2.4 cash generation Depreciation As a percentage of average gross 2.11 2.24 2.47 3.33 3.33 3.33 3.33 3.33 utility plant CD X 0 G\ Id (D CNFL Income Statements 1972-79 (in thousands of colones) Actual Estimated Forecast, 1972 1973 1974 1975 1976 1977 1978 1979 Energy sales in GWh 635.0 675.1 748.4 813.7 884.0 960.3 1,042.7 1,132.3 Average price per kWb - in colones .133 .134 .169 .257 .307 .349 .406 .493 Revenues: From energy sales 84,457 90,319 126,457 209,425 271,495 335,224 423,816 558,560 Other operating 173 177 232 243 256 269 282 296 Total operating revenues 84,630 90,496 126,689 209W 271,751 335,493 424,098 555,M6 Operating expenses: Energy purchases 56,918 62,352 96,329 151,137 197,479 248,164 315,528 432,680 Generation 3,144 3,o40 3,657 4,126 5,128 6,140 7,235 8,309 Transmission and distribution 4,197 4,731 5,812 7,014 9,241 11,525 14,387 17,489 Customer-related 4,163 4,692 6,581 7,823 10,230 12,892 16,214 19,578 Administrative 2,859 2,276 3,405 5,274 7,356 9,159 11,190 13,346 Id Insurance 56 59 60 86 111 138 172 210 i Taxes 1,077 1,108 1,100 1,196 1,386 1,554 1,720 1,862 Depreciation 3 344 3 585 3 825 9 176 12 288 15,697 19 879 24,366 Total operating expenses L5,10 243,219 517,40° Operating income 8,872 8,653 5,920 23,836 28,532 30,224 37,773 41,016 CNFL Forecast Sources and Applications of Funds 1975-79 (in thousands of colones) Total 1975 1976 1977 1978 1975- 78 1979 SOURCES OF FUNDS Internal generation of cash: Operating income 23,836 28,532 30,224 37,773 120,365 41,016 Depreciation 9,176 12,288 15,697 19,879 57,040 24,366 Other income and bond repayment 1 632 1 632 1 632 1 1 527 1 632 Total 47,53 59FU3 183,932 Less - service payments Amortization 6,052 6,535 6,970 9,641 29,198 15,029 Interest charged to operations 5,838 6,128 5,592 5,893 23,451 12,683 Dividends 5,208 208 5 208 5 208 20,832 5 208 Total service payments 17,095 7O Net internal cash generation 17,546 24,581 29,783 38,541 110,451 34,094 Borrowings: Existing loans - CABEI 6,o49 - - - 6,049 - - Suppliers 310 - - - 310 - Proposed loans - ICE (IBRD proceeds) - 7,669 5,106 10,165 22,940 - - CABEI - 10,751 17,138 20,979 48;868 - Total borrowings 6,359 18,420 22,244 31,144 78,167 - Contributions and deposits: Contributions 3,326 2,300 2,850 3,100 11,576 3,377 Security deposits 1 013 1 165 1,340 1 541 5,059 1,772 4__195 16,635____ ,14 Total contributions and deposits 339 3,45 14,190 4___1 ____51 Total sources 28,244 46,466 56,217 74,326 205,253 39,243 APPLICATIONS OF BENDS Construction program: Existing projects 30,0o43 7,846 9,550 - 47,439 - Proposed expansion - 27,566 41,378 66,984 135,928 - Future works - - - - 23,000 Total constrIucJt. on 30,043 35,412 502 9 G6,4 18,7367 23,000 Increase in vorking capital: 6 , Cash (A) 5,686 6,219 - 329 83 945 615 0 Other than cash 3,887 4,835 _4,960 7,259 20 941 15 628 8 To-tal working capital increase - 1,799 11,054 5,289 7,3142 21,806 1______ Total sources 28,244 46,-6 56,217 714326 205,253 39,243 (A) Includes ¢6,oo0 short-term debt in 1975 to be repaid in 1976. March 1975 Revised May 1975 ANNEX 16 Page 1 of 6 pages APPRAISAL OF FIFTH POWER PROJECT - COSTA RICA INSTITUTO COSTARRICENSE DE ELECTRICIDAD (ICE) Telecommunications Section Financial Statements and Forecasts 1. This annex includes the following financial statements and fore- casts for ICE's telecormunications section for 1972-79: a. key financial ratios - page 4 b. income statements - page 5 c. forecast funds statements - page 6 Earnings record and financial position 2. The telecommunications section had highly satisfactory operating results, with rates of return of 12% to 15%, in the early 1970s. Its high earnings and Bank loans financed most of its large construction program, which approximately doubled its investment in plant in the most recent five-year period. Asset revaluation and tariff increases 3. During the appraisa,l of ICE's fourth telecommunications project (Report no. 417a-CR, May 21, 1974), it was recognized that a significant tariff increase - about 50% effective in January 1975 - would be necessary to offset Costa Rican inflation, continue earning the 12% rate of return stipulated in Bank loan agreements on a fully revalued rate base, and pay for a reasonable portion of ICE's telecommunications expansion program. 4. As explained in paragraphs 6.04-05 of the text, ICE did not revalue its telecommunications assets by October 1, 1974 as it had agreed to. While ICE applied to SNE for a 50% tariff increase in September 1974, its basis for seeking this increase was solely the need to generate sufficient funds to finance a large part of its expansion program. In December SNE released its findings, which permitted tariff increases sufficient to increase ICE's telecommunications revenues by about 30%. ICE filed in January 1975 a second request for the total rate increase which it originally sought on the same contribution-to-expansion basis. SNE's review of the second filing is not complete. 5. ICE has completed the revaluation of its telecommunications rate base, which resulted in a 42% increase in its value, and has applied to SNE for prompt implementation of the entire 50% tariff increase previously requested to earn 12% on the revalued rate base. Effectiveness of such tariff action is a proposed con(lition of loan effectiveness. Assuming that future revaluatior and tariff increases are put into effect reasonably promptly, the financial results of ICE's telecommunications operations are expected to be satisfactory, as shown in the performance indicators. Annex 16 Page 2 of 6 pages Construction program and financing plan 6. To satisfy the increasing demand for new service and relieve congestion in existing facilities, ICE has advanced its expansion plans. ICE now plans to conplete its Stage IV plan (the first half of which, called Stage IVA, is being partially financed by loan 1006-CR) by 1979, instead of 1980, as indicated in the above appraisal report. Moreover, it plans to begin Stage V in 1979, two years earlier than previously foreseen. 7. ICE's telecommunications expansion plans are being reviewed by the government. While no official decision has been made, there are indications (e.g., SNE's decision to give ICE only about two-thirds the tariff increase it had sought) that the government would not look with favor on the accelera- ted expansion program foreseen by ICE. 8. As summarized below and detailed on page 3 of this annex, ICE's net internal cash generation plus customer contributions would pay for 30% of its 1975-78 telecommunications expansion program. This ratio is lower than that previously foreseen; the reasons for it are ICE's more ambitious expansion plans and higher local inflation. Annex 16 Page 3 of 6 pages Financing Plan 1975-78 - - - millions - - - Colones US$ _ Requirements of funds Construction program Stage III 133.9 14.5 Stage IV 925,6 84.2 Other 121.4 11.6 Interest during construction 71.8 6.6 Total construction 1,252.7 116.9 89 Acquisition of fixed assets 19.8 1.7 1 Increase in working capital 133.4 12.2 9 Total requirements 1,4o5.9 130.8 100 Sources of funds Net income before interest plus depreciation 649.1 57.9 Less service payments -35o.o -31.3 Net internal generation 299.1 26.6 21 Borrowings: Existing loans 382.8 37.9 Proposed loans (suppliers) 50.2 5.1 Future loans 555.2 5o.2 Total borrowings 908.2 93.2 70 Other sources 118.6 11.0 9 Total sources 1,4o5.9 130.8 100 9. The above financing plan includes under future loans a fifth Bank loan, currently scheduled for FY78, which ICE might seek to advance. The remaining future borrowings are undetermined; presumably, they would include supplier financing and local borrowing, ICE Telecommunications Section Key Financial Ratios 1972-79 (amounts expressed in millions of colones) Actual Estimated Forecast 1972 1973 19714 1975 1976 1977 1978 1979- Return on net plant Average net utility plant in operation 144.0 190.1 268.4 522.5 680.2 979.8 1,501.5 1,887.5 Operating income 22.2 24.2 40.9 62.7 81.6 117.6 180.2 226.5 Percentage 15.9 12.7 15.2 12.0 12.0 12.0 12.0 12.0 Debt Times debt service covered by internal cash generation 2.2 2.1 1.5 2.1 1.6 1.9 1.9 1.9 Depreciation CD As a percentage of average gross utility plant 14.1 3.9 3.9 3.8 4.o 4.2 4.3 4.7 e ok v0 Vt ICE Telecommunications Section Income Statements 1972-79 (in thousands of colones) -----Actual------- --Unaudited_- -------------------------Forecast--------------------------- 1972 1973 1974 197(5 1976 1977 1978 1979 Operating Revenues 63,840 81,218 117,387 193,264 296,342 471,844 685,128 885,621 Operating Expenses Personnel-related costs 13,864 18,812 21,384 40,418 76,072 114,931 158,308 182,948 Depreciation 7,928 9,474 17,003 25,051 35,081 52,676 81,oo6 113,422 Materials 1,886 2,754 3,338 6,584 10,819 16,090 22,249 28,639 Institutional costs 5,374 8,192 10,287 12,103 13,014 37,397 49,283 68,222 Travelling, energy, publicity, regulatory 9,51414 13,328 12,297 20,753 33,212 47,438 62,089 79,594 Participation expenses _ - 9,444 20,425 37,891 72,919 114,2114 163,261 Other 3,023 4,501 2,689 5,227 8,634 12,813 17,799 23,036 Total operating expenses ,617,061 7,442 130,561 214,723 354,264 504,948 659,122 Operating Earnings 22,221 24,157 40,945 62,703 81,619 117,580 180,180 226,499 Interest paid 10,269 15,279 19,477 37,973 65,513 68,525 96,188 113,554 Less: interest charged to construction 1 981 4 869 9 149 16 029 17 346 14 463 23,949 17,835 Interest expense 8___ 288_ lo'2 4,9_ 54 062 72 239 95 719 Earnings before other income 13,933 30,617 49,759 33,452 Rental of equipment to RACSA - - 3,128 3,519 4,301 - - Dividends received 1,765 2,345 1,291 2,783 4,694 4,226 - Other income 416 288 - - - - _ Total other income 2,181 2,633 4,419 6,302 8,995 4,226 _ Net Income 16 114 16,380 35,036 47,061 42,447 67,744 107,9441 130,780 n0 O FboH a' ICE Telecommunications Section Forecast Sources and Applications of Funds Statements (in thousands of aolones) 1975 1976 1977 1978 1979 SOURCES OF FUNDS Internal cash generation: Net income before interest 69,005 90,614 121,806 180,180 226,499 Depreciation 25 051 35 081 52,676 81 oo6 113,422 Total 5174,482 339,921 Debt service Amortization 20,564 30,379 39,782 62,854 80,973 Interest not capitalized 21 944 48 167 54,062 72,239 95,719 Total debt service _7_ 7,54693,844 135,093 Net internal cash generation 51,548 47,149 80,638 126,093 163,229 Borrowings: Existing loans - IBRD 801-CE 56,560 9,570 129 - - IBRD 1006-CR (Stage TV A) 57,494 119,115 88,809 - - CABEI 237 16 226 26,826 88 - - Total existing loans 155,511 - - Proposed loans: suppliers 25,910 13,373 10,957 - - Future loans: CABEI - - - 3,330 503 IBRD (Stage IV B) _- - 130,901 132,436 Other 90,000 146 ooo 95,000 go9000 90,000 Total future loans 90,000 M95,000 24,231 222,939 Total Loans 246,190 314,884 202,953 224,231 222,939 Other Sources Connection fees 24,600 14,724 15,696 18,807 22,559 Security deposits 4,686 2,765 2,948 3,562 4,235 Miscellaneous contributions 675 894 1,129 1,391 1,666 Capital contributions from RACSA concession expiration - - 26_606 - - Total other sources 29,961 18,383 46,37 23,760 28,460 Total Sources of Funds Zp7,699 380,416 329,970 374,084 4146 APPLICATIONS OF FUNDS Construction program Completion of Stage III 116,347 17,243 267 - _ Stage IV 137,932 260,279 231,149 296,243 285,370 Stage V _ _ - 33,860 Other 29,565 49,818 24,196 17,791 14,921 Interest during construction 16,029 17,346 14,463 23, 17,835 Total construction program 299,873 344,686 270,075 337,983 351,986 Acquisition of RACSA net fixed assets - - 19,834 - - Additions (withdrawals) of working capital other than cash 19,125 33,550 39,345 38,942 62,490 Cash 8,701 2,18 716 (2,841) 152 Total working capital additions 27,826 35,730 40,061 36,lol 62,642 Total Applications of Funds 327,699 380,416 329,970 37 May 1975 IBRD-I11454 S53 8hS 401 a < A RA i. ( i tl MARCH 1975 Gulf of LOne . N. Popoagayo N =S& Sea _1130' _ ,1C0 A~~ _ _ _ R R TIlaRln , i:.; S t t1 ; , tj Are: Co v e ri d~~~~~~~~~~~~~~~~~~~~~A-Co .. aR ada,ao, M., d -'. - ----a a \ a =t ,f ow s tOe /~ ~ ~~~~~~~o Ni.y ;.\\cudaooX t -'> 20; ., tw : i r (t7 * Pacific Ocean - 9030' EXISTING POWER FACILITIES PROPOSED PROJECT FUITURE 11D IV T.-.- U1. 1() k1 I-- W- Li - 11. IVnt-W.j.COSTA RICA ___138 kV Tnos,-W.,o Line 138EkV TtmianLi-s - I38 kV Tns-Im'Wa LiU-scrrIr' rlrnlr-5 8 -r rrrIIu - 4S5kV T-enisAla Lines -- 345Tt.sm.si. Line 0Uubttin INSTIITUTO COSIARRICEINSE LDE ELECTRICIDADML~ t ~ ~~~~~ ~ ~~~~~~~~~~~~~~~~~~~~~~~ PAINAM_ * OubsIeslans 0 Subsosuans U Had, roP-e, Pi..n INTERCONNECTED SYSTEM PANAMA . Hdlo° Po- PIn- U H,da Pafs, Plat- A TVs,ne Paus, PlaIs A Ths-Is Paws Pleats 4neoSnlRanlOs' ? t Garsk M7u"> OMEERO YS 85500 30 30'