12gB* S' EH 012..7 E IB 11 [EI 11 11 E1 1 21 1 S Energy Sector Management Assistance Programme A5r- W3, l Prefeasibility Edutiom Rurd Eletrfia and D em $essmnt Report No. 129/91 JOINT UNDP/WORLD BANK ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) PURPOSE The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) was launched in 1983 to complement the Energy Assessment Program which had been established three years earlier. An international Commission was convened in 1990 to address the creation of ESMAP's role in the Nineties. !t concluded that the Programme had a crucial part to play over the next decade in assisting the developing countries to better manage their energy sectors given that the supply of energy at reasonable prices is a critical determinant of the pace and magnitude of the growth process. The Commission's recommendations received broad endorsement at the November 1990 ESMAP Annual Meeting. Today, ESMAP is carrying out energy assessments, preinvestment and prefeasibility activities and is providing institutional and policy advice. The program aims to strengthen the impact of bilateral and multilateral resources and private sector investment through providing technical assistance to the energy sector of developing countries. The findings and recommendations emerging from ESMAP activities provide governments, donors, and potential investors with the information needed to identify economically and environmentally sound energy projects and to accelerate their preparation and implementation. ESMAP's operational activities are managed by two Divisions within the Industry and Energy Department at the World Bank and an ESMAP Secretariat. * The Programme's activities are governed by the ESMAP Consultative Group which consists of its co- sponsors, the UNDP and the World Bank, the governments which provide financial support and representatives of the recipients of its assistance. The Chairman of the Group is the World Bank's Vice President Sector Policy and Research. He is assisted by a Secretariat headed by the Group's Executive Secretary who is also responsible for relations with the donors and securing funding for the Programme's activities. The Secretariat also gives support and advice to a Technical Advisory Group of independent energy experts which meets periodically to review and scrutinize the Programme's strategic agenda, its work program and other issues related to ESMAP's functioning. * Ihe ESMAP Strategy and Programs Division is responsible for advising on which countries should receive ESMAP assistance, preparing relevant ESMAP programs of technical assistance to these countries and supports the Secretariat on funding issues. It also carries out broadly based studies such as energy assessments. * The ESMAP Operations Division is responsible for the detailed design and implementation of tasks sonsistinR mainly of sub-sectoral strategy formulation, preinvestment work, institutional studies, technical assistance and training within the framework of overall ESMAP country assistance programs. FUNDING The ESMAP represents a cooperative international effort supported by the World Bank, the United Nations Development Programme and other United Nations agencies, the European Community, Organization of American States (OAS), Latin American Energy Organization (OLADE), and a number of countries including Australia, Belgium, Canada, Denmark, the Federal Republic of Germany, Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal, Sweden Switzerland, the United Kingdom and the United States. FURTHER INFORMATION For further information or copies of completed ESMAP reports, contact: Office of the Director Industry and Energy Department The World Bank 1818 H Street N.W. Washington, D.C. 20433 USA OR The Executive Secretary ESMAP Consultative Group The World Bank 1818 H Street N.W. Washington, D.C. 20433 U.SA BOJVIA PREF1ASIBILITY EVALUATION RURAL ELECTRIFICATION AND DEMAND ASSESSMENT ASUNTA VALLEY, BOLIVIA Technical Report Prepared for UNDP/OPS on Rural Elecation i the Asunta Valley APRIL 199 This document has a restricted distrbution. Its contents may not be discosed without authorization from the Governent, the World Bank or the UNDP. FfAL WAR January I to December 31 CURRENCY EQUIALENTS Current Unit: Boliviano (Bs) Exchang Rate - US$1.00 - Bs 3.00 ABBREVIATIONS CEC - Cooperativa Electrica de Chulumani (Rural Electric Cooperative of Chulumani) CESSA * Cooperativa de Electrificacion Sucre SA. Electric Cooperative of Sucre) CEY - Cooperativa Electrica Yungas (Rural Electric Coopeative of the Yungas) COBEE - Compania Boliviana de Energia Electrica (Bolivian Power Company) COFER - Corporacion de Fomento Energetico Rural (Corporation for the Promotion of Rural Energ) CORDEPAZ * Corporacion d Desarrollo Regional de La Paz (Regional Development Corporation of La Paz) CORDEPO - Corporacion de Desarrollo Regional de Potosi (Regional Development Corporation of Potosi) COSELEREC - Cooperativa Servicios Electricos Trinidad (Cooperative of Electric Services Trinidad) COSELECA * Cooperativa Servicios Electricos Camiri (Cooperative of Electric Services Camiri) CORELPAZ * Cooperativa Servicios Electricos La Paz - Altiplano (Rual Electric Cooperative of La Paz) CRE * Coopemtiva Rural do Ele on- Santa Cruz (Rural Electrifiaton Cooperative - Santa Cruz) DINE - Diecion Nacional de Electicidad (National Electricity Directorate) ELFEC a Empres d L y uea Electrica de Cochabamba (ectrb Power Compaq of Cochabamba) ELEFEO e Empress de Luz y Fuena do Omro (Electric Power Company of Oruro) ENDE - Empresa Nacional de Electrcad (National Electric Power Company) ESMAP * Energy Sector Management Assistance Progm INE * Instituto Nacional Estadistica (National Statistics Institute) MACA * Ministerio de Asuntos Campesino y Agopecuarios (Ministry of sino and A lt Airs) MEH - Minlsterio de Energa e Hidrocarburos (Ministry of Enerag and Hydrobons) NRECA * National Rural Electric Cooperative Association of the U.S. OPS - Office for Project Services (UNDP) REA 0 Rural lectrication Adminstrtion (USDA) SEPSA - Servicios Electrioos Potosi SA (lectric Service of Potosi SA) SETAR - Servicios Electricns de Tarija S.A (Electric Service of Tarija SA) UNFDAC - United Nations Fund for Drug Abuse Control USAID - United States Agency for International Development USDA - United States Department of Agriculture UNDP - United Nations Development Progranume * *------ ........ . * . . . . . . . . . . . . . . . .... . . . . . . . . . . . . . *. .~~~~~~~~ .... ;........ :..... .......... ....... .................. .............. ..: ~~~~~~~~* *: -. * - - . . *: .. ...... * ¢t- *. 0** * * * * * * * * * * * ** * * * g i . .... ... -- -* -- -- X -- *- -jjj:8* :- -f ::: * * .- -. .. . *i...... **;- * *~~~~~~~.~ ...* ...******** -** Ca al Ii? >~~~~~~~~ * -* --- -- -- *.- ** @* .. -o { M V. JINANCAJ..ECONONIIC EVAIUAnAION ...... ............................. . 40 Financial-Econonic Viability of crid Scenarios . * ......... 40 Ov iew ... .................................................. 40 Ficonomicbia .An........................................... 40 Eo o nodci Arost.. ....... ........... ....... 9* 9....... 44 Genad4A6ib Pammnte ................................................ 41 Cos e .................................................. 41 lbd5..oaPrioto..........,.................................. 46 FineEiatenefit ....... ............... . 9*9**9**999*9***9...... 42 EononmBeneft .r . ... ............*9***e99***9** . ....... 42 Mo d mi Re istr Unt v aOpndTi cl G iowth Require. ents.................. 44 Obsenatiors ................................................ 44 VL NCSTI.TJMONSL ASPECv N ....IONS........................................ 46 Ru1dba b utiand Otin Yuigrs ......................................... 46 2verdvew ......... ....................................... 46 CEY ..............................a...................... 46 L2a d Pr omotion . .... ..... ..................99.**.*..**.*** *..... 46 l ineD Extension Finanig ............................................ 47 3o itedonsin Pherfojec Area .H ...............ouseCuntan Eecte nnect....*. 48 3Adndminisfotveand Ternal Alestance R. . ements ............... . 49 3IL CONCLUSIONSeAND RECrOMrtNDATIONS .......................... 1 3. otnIm al P.od..ti .e ..n ..Us .s.........................*.......*..... 21 R3.un.rdutie EdeUs. Ativties 3.8 Est iatefCns uinrDbnnd S. ........*.. 21 3.9 DeniandEstimte(k ~ V) ab.. ity.........................*........... 523 4In.1iEtutonalianilitvend c .. ................................ . 52 4.2 tPandad Voltaederani s ............................................ 57 I EWonaued a end opiisi orW t scena............o................ v 43 SumarThiryC nnpax bonu olAt age J)ropan m . . . . . . . . . . . . . . . . . . . . . . 28 42 EtUnitedi on EntinkW .a ........................................... 2 3 . Comarsn ofAlemtive la P"e AIL HuebandEXed Mi ................................... vi 4.6 DcepartmenCOts b 599999999999999999999999 3 4. lootgrnalveScEnaot1*Roj9Zone..... .................... * .. 33 232 Mxafin EDUshi flon EbsndSes .............................................. 17 3A2 Loh Prodctie En id Ussfr in Projectone ....................................... 16 353 Pro"ducivEnd-Usesfo Exte>nud Sales ......................................... 17 3.4 Pruoductive sEnd-Uses for T..ortation................................. 21 3.7 Poteent d us*tries hib an gr nd ustreA6s . ....................................... 19 33 Esdmated Number of Congatm s .......................................... 23 3.9 Dn dEstimate (W) .............................................. 23 4.1 ESMA~Pand CXY Demand Pro30cons ......................................... 26 4.2 S " Voltap RanM .............................................. 27 4.3 Yea Thirty Mbsdmum Voltage Drop ......................................... 28 4A4 Unitized Cos Esthabs .............. ................ 29 45 S oad - Volt Drop .............................................., 31 4.6 Sceario b C Qx ..........................* 32 4.7 Alkanatve Scenado ib vok rkop .................... 33 4.8 AtemnativeScenariolb.Costs .......................................... 34 4.9 Alternative Soenaro U * Volt Drop . ................................... 35 4.10 AlternatieScenario fl -Cost ....... .................................. 35 4.11 Altenative Scenario m Combined System ................................... . 36 4.12 Altenative Scenaio m : Volt Drop . .................................. 37 4.13 AlternativeSenado m l Costs . . . . ...... . .. . . . . . . . . . . . 38 4.14 SuIaL Comparion of Alternatves Ia Ib U, and m .................. ... 39 4.15 First YearSFunnai Requirements-Alternatlve- Sc II ................. . 39 5.1 Pinncia-Econonuc R.lts- Probable . . ...... . . ..... 43 52 Financial-Eoonomic Results - Optinistic . ........ 44 ANNEXES 1 Load Projections-Demand Tables ..................................... 56 2 Unitized Cos t Esdmates ................................. ............ 66 3 V ge op Sheet............ 68 4 VoltageProfile 72 S Etiated Scope of Engeeng S....................... 73 6 7la7nalCostCal on 7 7 ..a.... ........ 79 8 scptionoftheRu Ele fationPlanning Modd.................... 80 9 A Mehodology for Estimating Electric ty's Residential and Productive End-UscEconomicBenefits-Application in the Asunta Valley Rural Electrification Prefeasibility Study ...................... ....... 81 10 Proect Summary - Compute Runs ............................ 99 11 Proposed Prod ve Uses Component ................................. 141 12 Cooperativa Electrica Yungas C.E.Y. - Electrici6n Rural Nor y Sud Yunas.. 143 MP IBRD Map 22437 - UNDP Technical Assistae Proect 4 Plan Maps # 22908 - Agrayuns Estudio Preliminar Altornativo Ia, Ib, I m EXECUTIE SUMMARY Bacground Objectives 1. The overall objectives of the technical assistance activity are twofold. The first is to assist the project Directorate J/ as well as officials in the Ministry of Energy and Hydrocarbons (MEH) and the Ministry of Campesino and Agricultural Affairs (MACA), in two principal afeas: (a) assessing the technical, financial/economic and institutional viability of the proposed 132 kilometers of rural grid extension in the Yungas project area with the goal of developing the least-cost electrification scenario that corresponds to project planning interests; and (b) conduct an analysis of existing and prospective demand in the project zone, with emphasis on the contribution of productive end-uses for enhancing load and the viability of the proposed grid. 2. The second objective is to utilize and demonstrate a more accurate way to develop and incorporate demand estimates for electricity in rural areas into the appraisal of nrral electrification projects. Thi objective is developed through the utilization of a Demand Assessment Model (DAM) which allows for demand and cost input and the calculation of financial-economic viability Related to the second objective, and in terms of a case study for the MEH, the activity seeks to demonstrate the need to coordinated the technical dimensions of rural grid extension with a methodological and field-based evaluation of rural demand. This complementary approach allows for a more aocurate consideration of project viability and development of most appropriate grid design, or alternative energy options. In developing demand estimates, the study also demonstrates the enhanced viability rendered by incorporating produc:ve end-uses development in rural electrification planning. 3. The composite study presents prefeasibility analysis of four scenarios for rural eletrification in the project zone. The first scenario includes a review of a grid extension scenario / U. Pund for Drug Abuse Control (UNFPAC) in Bolivia is completing a pha of a US$2 m ion rural integrated dvelopment project in the Yungas region whic, at the time of this assesent, was AlledAgyungs Theproject is executed by llNDP/OPS. UNDAC's rural pjt npoa in> Insm wt agrilatalw and a-e enterse development. The spec engr mpont of te A_oyus project (as of Januaiy 1, the A project was tned wih any folow-up beig asume by UNFDAC) consits of plans for ural grld eatensdon (apprklately3O kilomets), thughout the Asna valley pject zone. The DAM model is desined for calulating the financald and economic vibity of ural electificaton projes The model aLows for analys of the viabil of alterne tehil scenarios conidering field-basd demand projectons (developed at the vilge level) under categories 'probableW and 'optimistie. in addiion to redeni demand, the model i used to identify and quatiy iotng and potential productive end.uses The model was develWed by the Nadonl Rura Elecr Coopeve Asocion (NRECA) and is curently being utilzed by USA in its Centra America Rural Electifcation Progm for project planning. Te mode's basi methodology is dese in Chapter IV, and Annex 9. -iie prepared for Ag as by the Cooperativa Electrica Yungas (CEY)-a rural distribution entity nearby the project area. Ihe four scenarios developed in the report are outfined below: Scenario Ia * CEY Preliminazy Technical Desin and Demand Estimates. Scenado lb * CEY Prminay Technical Dedgn/ESMAP Demand Projections. Scenario II - ESMAP Alternative Design/ESMAP Demand Projections. Scenario Ell * ESMAP Alternative Design/ESMAP Demand Projections (Scenario Im, in contrast to strict grid ectension of the other scenarios, proposes partial grid extension and an Isolated grid with a hydropower generation facility. Between the grid extension and the isolated system, project planning intere of alt=m*i& cgs would be assured). 4. In addition, scenarios IV. and V. (renewable generation and isolated systems) are briefly discsed but detailed drawings and calculations are not presented. The reasons for this are cost considerations-scenario IV, a proposal for decntrlized generation and an isolated grid, at US $42 million vastly exceeds the cost of grid-eension scenarios-and the interest of the project Directorate to provide comrehbmi gWd covrag in the project zone-given limited demand, scenario V proposes a mini-hydro power site and a small distribution network around one town, satisfing 18% of projected demand. 5. ETde Area The geneal area of the project is approximately 100 kflometers northeast of the capital of La Paz in the Yungas region of BolMia (see IBRD Map 22437). The area dwactized by motous teain, deep valeys and generally poor transportation networks The area, however, holds fertile valleys from which numerous crops (vegetables, fruits, coffee, etc.) are produced. The area is also a prime coca producing region and alternative caop promotion is a main focus of the projecL 6. The specific project area for the rural electifiction component incorporates the Aunta vaey. As contemplated by project planners, the grd exension would be connected to the national grid in the soudtwtern portion of the project area in the town of Chulumani Ihe immediate areas in the Yungas acoining the project zone are princialy served by CEY, which purhases power from Compania Bolilana de Energia Electrica (COBEE), through lines of the Empresa Nacional de Electricidad (ENDE). 7. The technical analyi commenced with a review of a prelmary study on grid extension for the zone 11 prepared originally for Agrytingas. The analys is referred to as scenario Ila. With this analysis as a basis, the general terms of reference for the tecnical assistance were as follows: (a) review existing, prelimlnay technical design and, if necesazy, outline technical areas for cost reductions on the proposed grid; Mm an1s pr.m by Cocpt*va Bed" YUg for A1989) is ,ftd 'Euo .e A-s Ap ype(cemIc 1969). .Hi1. (b) via field re at the vilW level, ystemadcaly identify eisting and potenial demand in the prject zone, including existing and potential productive eand-us for the rral electrction, wi the goal of building load and enhancing th finncllmconoic viabiity of the proposed tem; (c) with the assistan of the DAM planing model, and based upon the demand calculions developed by the study team, conduct a financial-economic analysis on the nrual line ension, as wel as on alternative technical scenarios developed to reflect potential cost savings; and (d) develop an instituional outlne for the grid ex on in the project area-in this case focusing on the viability of the rural electric cooperative in the Yungas-CEY. nand AnEsis 8. For the demand anawysis, and based upon field assessment, residential and productive end-use elecricity demand in the Asunta valley project zone is projected. The demand projections developed by the ESMAP technical consultant team are approximately 65% less than CEY's orWal demand estimates presented for swenario IL For the anasis, residential and productive end-use demand are identified and quantified Residental demand consists primarily of domestic ghtirn Productive enduses of electicity are defined as:ny use of electricity which increases the end-users' ecnomic status by ficilitating production level iceases, production cost savings, and/or incrased product quaity. From the point of view of a utiity, productive end-uses would have the effect of load bulding and generally augmeting the off-peak load. 9. For all scenarios analzed, demand ib estimated in kW and consumption in kWh per month for the reddential ad productive end-use categories The demand estimates for scenarios Ib U and m are projected and considered under both 'probable' and loptimistic demand growth. 10. ResidenXl Demand. Based on the house count conducted in the project zone, geographicl and technical constraints, as well as individual community charactenstics, the technical team estimates the number of houeholds in each of the 39 communities likely to connect in year 1. The sum of the initial connects Is about 56% of the project house count, which constitutes houes in 39 comunitie ndividual arcterics of the communities influence projections for grwth in new resdental connectom over ty years 1I. Based on the field analys, in the zonc, the study projects that residential connecions in year 1 wIl be 937, growing to 3,000 in year 30. Using initial and year 30 totals, a yearly average growth rate in new connections of 4% is expected. Initial residential kWh/month aiv- consunptlon-based on evalvations from similar electrfied zones In Bolhiia and other rural electrification projects-Is conservatively projected at 15 kWh/month. Fo. year 30,40 kWh/month is projected for residential consumption. 9 12. EmdUvAEndUAgJbdlxat=Dlmanud Existing(butnotnecessarilyelectrified) as well as potential productive end-uses are identified for the project area. This identification is carried out via reconnaissance in the specific project zone and In siiar electrified areas in the Yuns, as well as an appraisal of the agro-ecological and mineral potential in the zone. The proposed complementaty integrated development activities of theAgrayungas projet are also taken into account. In all, a total of 37 eistng and pnal produt Md-uses are identifid and considered. 13. In addition to identifying types and quantifying the kWh/month consumption characteristics of the productive end-use activities, estinates are made regarding their number in year 1 and epected rate of growth over the course of 30 years. Different growth rates are considered for various types of identified activities. The number and potential growth in these activities -- ...dered on the general basis of the following factors: - Availability of a reliable electricity supply in the project zone; Natural resources in the project zone; - Existing or potential demand for the product or services; and - Observed xperiences and activities in similar electrified zones in the Yu'igas region. 14. The composite result is a projection in the type, number and growth rate for productive end-use activities that are epected in the project area in year 1 through year 30. The ype, number and expected growth rates are presented under "probable" and "optimistic growth situations. 15. hgA a GrwtRahe. Under the 'probable' growth scenario developed by the technical team, the aggregate average growth rate for all productive end-use activities over 30 years is approdmately 4%. Under the "optimistic growt scenario, the rate is appromiately 5%. hddWRm ba of Cosmers and Esiated Demand 16. Based upon the field data and analysi, the total estimated number of residential and productive end-use consumers under the 'probable" and 'optimistic growth scenario are as follows: ESM tem projeion, basod on fleld sans, arn enswatve yet 8be a ealistc a _umea of vabl. The prjt re is con_el ral with only one smll town La AU a) with vegy litdte infsuu iblS It PRULE AND OPTINISTIC ROW SCEIURIO YEam YAR 30 TIARI WAR1t30 (a) Resfdentl Consumers 93 3,000 3 3,000 (b) Prodectlve Use Conus 22 .. AZ * .221 (C) TOTAL 1,139 3,672 1,190 4,136 Motes The preliminary stucy of C£1 infers 2000 ridentIal coaumrs and 404 productive- usle consumers In year 1. 17. Based upon the estimated consumption in kWh per month, and with the use of demand tables developed for the anaysis, total demand estimates in kW are summariz as follows: Tabte 2: ESTINATED DENAND IN kW Probable Qptfmfstfc Year 1 Year 30 Year I Yer 30 Deand In kW 198 94? 243 1,313 Note: The preLiminary study of CnI Infers 600 kW dmand In year 1, and 2,800 kWD In year 30. Technica Opton 18. The main activities pertaining to the engineering assessment were defined as follows: (a) Review prelimina distribution designs developed by CEY in view of the need to reduce distribution costs and enhance the financial-economic and institutional viability of the proposed grid extension, recommending changes that might contribute to these objectives, eg. types of lines, changes of route, equipment and potential connections to other load centers which might enhance project viability; and (b) Review/revise proposed technical parameters of grid extension based upon demand modifications developed through the field analysis. 19. The technical team projected demand is approxmately 65% less than that projected in the CEY study. CEY demand projections are utilized, however, in the engineering analysis of scenario la to allow comparative analysis with the alternative scenarios presented. Demand projections developed by the technical team remain constant for altenative scenarios Ib, II and m. I vi & 20. Table 3 presents a summary comparison for the technl scenarios for which load and costs are estimated: Tbte 3: SURY COUARAISON OF ALTERNUTIVES la, lb, It, A10 III I Item la lb II III Numer of Consuerse(project.d) 7,384 3.672 3,672 3.672 Peak Demand, kW 2,J86 946 946 946 Primary Distribution line, km 132 132 132 132 Secondary Line, km 130 64.5 6.5 64.5 NHters and Services 6,498 3,224 3,224 3,244 Transformer Capacity, kva 5sm 1,892 1,892 1,892 Generating plant, kV 0 0 0 300 Construction Cost S 2,005,000 1,433,270 1,077,270 1,569,270 Engineering and Admfnistration, 15X 300,750 214,990 161,600 253,390 Contingencies, 10X Z00500 J43 U330 107.J .JOS6930 Total Cost $ 2,506,250 1,791,S90 1,346,600 1,979,590 aI For each of the alternatIves presented, there are 132 kilometers of primary three-phase or single-phase lines. Differences in cost result from varying the type of line or size of conchxtor. 21. Least-Cost Option for Comorehensive Grid. On the basis of technical and financial. economic analysis investigated, scenario II as presented would represent a least-cost scenario for project planning interest of comprhens rura gra Financial-Economic Evaluation 22. Application of the DAM model shows that none of the anayzed options is financially viable under the *probable" or "optimistic" growth scenario, assming the utflity has to bear the entire construction cost. To break-even finacially, the project would require a donation of approximately US$.97 million under the *probable" scenario of alternative IL and US$.82 under the "optimistice scenario. However, all scenarios show a positive economic rate of return. The financial/economic viability of the project for scenario It (considered the least-cost scenario), based upon the DAM model calculations, is presented below: - Scenario I1 - Probable Growth Financial Net Present Value (NPV) = US$-974,401 Financial Benefit/Cost (B/C) - 0.46 Economic NPV n US$678,768 Economic B/C = 131 Econ. Rate of Return - 17.8% vili - Scenaio II Optinistic Growth Financial Net Present Value (NM) US$829,737 Financial Benefit/Cost (B/C) a 0.57 Economic NPV = US$1,153,663 Economic B/C = 1.47 Econ. Rate of Return = 21% 23. On the economic side, scenario U has the grte ecoomic net present value- xcluding scenario Ia with its overstated number of projected consumers and demand. Economic benefit under alternative scenario U is roughly between US$.68 - 1.15 mllion in net present value terms, vawyeg by the productive end-use scenario chosen. 24. The retai residential tariff (above 25 kWh) is US$.052, and US$.056 for productive uses. While the analysis did not portend to conduct a tariff study for CEY, it is evident that the retail tariff structure at the distribution level applied to project area b below the marinal cost, eg. the marginal cost at bulk level for year 1 is estimated at 0.055 kWh (see Annex 6). In addition to the formalized promotion and development of productive end-uses in the project zone, the development and application of a rational tariff regime would enhance the projects overall financial viabililty. nstittional Evaluation 25. Assuming upward tariff adjustments by CEY, coupled with the sustained promotion Of productive end-uses on the part of the project and CEY to enhance the financial viability of the project, the mission considers that the most appropriate institutional administation of the rural grid (given the project's priority in omrehensive gri cva) would be to extend the service area of the existing rural cooperative. Proxiity to, years of operation nearby and famfliarity with electrification in the Yungas leaves CEY as the most appropriate entity for distribution in the proposed project zone. However, detailed institutional analysi would be required with the goal of developing an administrative and technical assistance program for CEY as part of the project. 26. Formed in the late 1970's CEY cwuently serves some 4,000 consumers. Since its formation, the cooperative has received limited technical or institutional assistance. The incorporation of the Asunta valley service area and 132 kms of grid and 1,004 additional connections would be a large addition in terms of management, operation and maintenance. For the financial velfare of the institution and assured operation and maintenance of the proposed grid extension, s- comprehensive institutional analysi of CEY is reowmmended. Specifically, the objectives of this assessment would be to be to analye the following: (a) the current financial situation (including tarff struure); (b) general administative procedures and capabilities; (c) the technical capabilies of CEY to administr the propose grid extension; and; v vii- (d) the costs and capabilities of CEY to develop an instignaLizeroQgram of promotion of productive end-uses. The overall goal would be to strengthen the fiancial and organizational position and guarantee the cooperative's ability to successfl serve its current sevice area and that proposed by the contemplated grid extension. 27. In terms of the objective of completing an analysis for rural grid extension, application of the DAM model to establish the financial-economic viability of the scenarios shows that no scenario is financially viable. This is the case under both the "probable and "optimistice demand growth scenario as developed by the technical team. In contrast, all alternative scenarios are viable in economic terms. In particular, scenario II (as the least-oost option for comprehensive rural grid extension) shows an economic benefit of between US$.69 million in net present value value terms for the "probable growth scenario, and approximately US$1.15 million for the optimistic growth scenario. The economic rate of return for the scenario II is calculated at 17.8% (probable) and 21% (optinistic). 28. From the perspective of the rural distribution entity CEY, the absence of financial viability, despite the development of the least-cost scenario for comprehensive coverage, denotes a negative financial burden on the institution. In sum, the financial viability of the project would have to be increased in order to ensure the institutional viability of CEY. Two complementary ways to augment the financial viability would be: (a) The development and application of a rational tariff regime for CEY that would allow CEY to develop and apply tariffs that cover marginal costs; along with (b) The development and application of an institutionalized promotion of productive end-uses in the project zone on the part of UNFDAC and CEY. The program would have to focus on industry and agro-industrial development in the project zone in order to build load and enhace the return on the project investment). Developed in tandem, points (i) and (ii) would be crucial for enhancing the project' financial viability and, in the long-term, guaranteeing the institutional viability of the grid extension and CEY. Policy Implications for Rural Electrification Planning 29. Finally, there are important policy conclusions that can be derived for rural electrification in terms of the energy planning activity. In addition to points (i) and (ii) on tariff reform and the need to incorporate productive end-uses promotion in rural electrification planning, the following issues are demonstrated in the study: ix - (a) Expenditures at the prefeasibility level is more than justified in the cost savings realized in plant investment, e.. for less than US$ 50,000, the identified cost savings amounted to over US$ 1 million; (b) Significant cost savings resulted from more accurate demand forescasting. The importance, therefore, Is demonstrated of a detailed and field-based demand analysis running parallel and complementary to the technical identificaion of least- cost system design; (c) On the benerits side, the high economic rate of return is dependent, in part, on the connection of the lowest income consumers, Le. candle users To this end, a poliqy of loan financing for connections to this, as well as other consumer groups, would be merited. Such financing might be facilitated through monthly billing charges I INTRODUCTION hwgd 2AR National Enera Planning Activty 1.1 In an effort to address issues of energy sector planning at the national and regional level in Bolivia, the joint UNDP/World Bank Energy Sector Management Assistance Program- ESMAP-is currently working in conjunction with the Ministr of Energy and Hydrocarbons (MEH) and a national energy planning team formed with the MEH to strengthen energy plamning capabilities. One specific outcome of this technical coUlaboration wi be the development of a National Energy Plan within the MEH. 1.2 Within the framework of the composite planning activity-where both the oonventional and non-conventional energy sectors are being evaluated-key issues and prospective investment in the household and rural energy subsectors are being identified. As one component of the household and rural energy analyses, the issue of rural electrification-including weaknesses in national/regional organization, analysis and planning in the subsector, as well as the lack of adequate demand analysis and technical assistance at the site-specific level-is being assessed and institutional and technical recommendations developed. Technical Assistance to UNFDAC and Agroyungas 1.3 Pursuant to a technical assistance mission of ESMAP in September 1989 to the national energy planning team in the MEH-specifically focused on organization and planning in rural electrification-UNFDAC Bolivia and the Directorate of its Agroyungas project V (working in counterpart with the Ministry of Agriculture and Campesino Affairs-MACA) requested ESMAP technical assistance. Specifically, the assistance was solicited for analysis of a rural electrification component of an integrated rural development project under the execution of UNFDAC. lhe areas of the requested assistance-while project specific-complement components being analyzed in the national energy planning activity, ie. an evaluation of the status of rural electrification planning, an evaluation of existing or potential programs for promoting productive end-uses for rural electrification, and an analysis of the institutional viability of rural energy systems. 1.4 In preliminary discussions with the project Directoriate, it was noted that the rural grid component of the project is being designed from a technical/engineering standpoint, with marginal attention to an as.essment of the actual residential or productive end-use demand U.N. Fund for Drug Abuse Contol (UNFDAC) In Bol"ia X oompleting a phas of a USS million rual interted dwelopment project in the Yungas region which, at the time of ts assewnent was called Agroyunps. The projet Is enctedby UNDP/OPS. UNFDACs nrual project Ipoates rural nfstructwr vestment with agul and mol-scal enterpre dewelopment. e spcfic ener component of the A wtas projet ( of Januar 1, the Agroyu pect was termated with any foow-up bei aume by UNFDAC) consi of plansfor ra rid meo (apprnmatet 130 kilmetes), throughout the unta valley project zone -2- in the region (either that whih exists or prospective demand, Including that which will be incorporated as rural development components of the project). In addition, there is little emphasis placed on either the financial-economic viablity of the grid etenon or the Insdtutional viability in terms of the capability of the rural distribution entity In the region (Electric Cooperative of the Yungas-Y) to operate and maintain the proposed extension. The situation, however, is not uncommon in Bolivi (see Para. 2.14 - 2.15). Based upon information being collected for the National Energy Plan, rural elecification projects are found to be lacking an adequate assessment of demand or promotion of productive end-uses, as well as adequate consideration of the fiancial- economic or institutional viability. 1.5 Ihe composite output of this analysis-outlined throughout the following chapters- -has been prepared for review on the part of the Directorate of the project and GOB counterparts. Pursuant to a country overview, the analysis consists of a technical, financial-economic and institutional assessment of rural elecrification in the project area of interest. Given the on-going collaborative assistance between the MEH and ESMAP, the analysis also serves as a case study for project specific rural electrification planning In this regard, the study seeks to demonstrate the utility of a field-based evaluation of rural electricity demand in the project zone complemented by the utilization of a financial-economic model for evaluating the viablity of rural grid extension. In sum, the anabsis wfll provide project decision makers with an overview of the viability of the proposed grid, as well as a planning model for the national energy planning team in the MEH for improving assessment capabilities of rural electrification projects. objectives 1.6 The general objectives of the activity therefore are twofold. The first is a prefeasibility evaluation of a relatively small rural electrification project (132 kiometers). The second objective is to explore for more accurate and methodological ways to quantify and incorporate demand estimates for electricity in rural areas into the appraisal of rural electrification projects. The latter of these objectives is executed through utXiation of a planning model called the Demand Assessment Model (DAM) "'. 1.7 Specificaly, the objectives are defined as follows: (a) assess the technical, financial/economic and institutional viability of the proposed 132 kilometers of rural grid in the project area, with the goal of developing the least- cost scenario that corresponds to project planning interests; and (b) as a case study for ural electrification analysis, conduct a field-based assessment of exsting and potential demand in the project zone (one that at the village-unit level mThe DAM model Is designed for calating the fcial and economic viabil of rual elecificadon projecs The modd aBows for analys of the viablit of aleative teical scenaios conddefing fieldbased demand projctions (deveoped at the vilage vel) under categoris "probable and opmc". In addin to rsdenmtl demand, the model I used to den* and quanr msting and potential productive endu The modd was deeloped by the National Rua Eectic Coopeai Asocation (NRBCA) and Is cwrent being utied by USAI in its Contral Ameica Rural Eerifiaon Proram for project planng The model's bas*c methodology I drbe in Chapter IV, and Agex 9. .3- identifies and measres eisting and prospective residential demand, as well as the contnrbution of existing and potential productive end-use demand) for demand data input and assessment of project viability. 1.8 Related to the latter point, for plannin purpoes the activity seeks to demonstrate the need to coordinated the technical dimensions of rural grid ettension with a financial-economic assessment that incorporates a field-based methodological evaluation of residential and productive end-use demand. As a planng tool, this complementary approach is provided through the uthiztion of the DAM. Ihe model, whose development and methodological assumptions are explained in detail in Annex 9, allows for consideration of a projects financial-ecnomic viability based on ystem desig input and costs and the input of demand esdmates in both residential and productive end-use categories. Of partiular importance, the composite demand estinates are developed at the village unit level. That is, rural electriciy demand estimates are quantified via field-based reconnaissance in the communities throughout the project zone. 1.9 The composite study presents prefeability anabsis for four scenarios (Ia, Ib, II and III) for grid extension rural electrification in the project zone. Soenario m proposes grid extension and a complementary decentralized hydropower generation facilitywith an isolated grid. Scenarios IV. and V. (renewable generation and completely isolated grids) are also brieflY diSCUsed but detailed plan maps and calculations are not presented. The reasons for this are cost considerations- -scenario 1V, by constucting a 12 MW plant and completely isolated grid, is significantly more costly (US$42 milion) than interconnected grid etension, as weUl as the interest of the project Directorate to provide gimpveh gri ge in the rojo oneIren the limited demand as d by the technical team, scenario V. proposes a mini-hydro power site (300 kW) and a limited distribtion network. 1.10 As a startng point, the technical consutant team reviewed the preiminary analysis for grid exension developed orginally the project by the ural distribution entity nearby the project area, CEY. Outlning and building on this study, the tehnical anablis expands to present three alternative technical scenarios for grid exension along with cost estimates. Application of the DAM evaluation model allows for the input of residential and productive end&use demand and, in turn, a financial-economic appraisal of the various scenarios under 'probable and 'optimis load development. Aciiies 1.11 Specifically the terms of reference for the technical team were as follaw: (a) review existing, prelumiy technical desg (scenario 1a) and, if necessary, outline tecnical areas for cost reductions on the proposed grid; (b) via a field-based analysis, systematically identify demand in the project area, inAuding exsting and potential productive end-uses for the rural electicaton; . 4 - (c) based upon the demand caltions developed and Input by the technical team, conduct a financial-economic analysi on the proposed rural line xtension (senario Ia), as well as on alternative technical scenarios (scenarios Ib, II, and Iml) developed to reflect potential cost saving; and (d) develop an institutional outine for the grid extension in the project area focusing on the viabflity of the rural electric cooperative in the Yungas- CEY. 1.12 International expertise for the technical asistan consisted of two electrical engineers (expertise in rural line desig), as well as two rur electrification productive end-use specialists. Te latter two conducted the financial/economic evaluation using the DAM planning model. Two national engineering consultants were hired by the project Directorate as counterpars and particpated in all aspects of the study. This mission was undertaken in cooperation with the National Rural Electric Cooperative Association Oa the U.S. (NRE(^A) -whkh has had experience in the design and implementation of rural electrification activities in Bolivia- operating under funding provided by USAID. The NRECA facilitated the participation of one of the electrical desin engineer and one productive end-use specialist 1.13 The main technical mission was fielded from Januaty 8 through January 31, 1990 Technical and logistical assistance was provided directly from the Agroyungas project Directorate and Staf£ Field visits were made to the project area and interviews conducted with project field personnel, the Directorate of the rural cooperative CEY, throughout numerous communities and with potential productive endusers in the project zone. Meetings were also held with officials in the World Bank office in La Pua UNDP, UNFDAC, the MEH, MACA, as well as with repentaties from ENDE and COBEE. V l report is basd oh findins of "tti msn whici vid Boa. Mm misn membe We Munwqy lon Leader D. Met, AL Manon (Une Dsi Ene). E Vil_n, R. Oreo (Rura Demand and Prodie EndUsU Speists). Tmisino was ated at the nation level by Mourn (Elctl ngeer) and D. Klttebon (Prodce EndUse Selt). D. aers and C. Feinstein f AP a d I the i_ _anayes.* _ Scrtia uppoft wa prowided by N. Leon and D. Balal EL COUNTRY OVERVIEW am-m" AIW dZaUQ Data 2.1 Bolia Is a moderately szed, landlodked ounty In South America covering a urface area of approamatelY 1.1 mllion square kilomet It b bounded to the west by Chie and Peru, to the north and east y Brail, and to the south y Parauy and Argentina. The countly is divided into nie political d epartmentswhich ompr a de range of social, cultural and pyical resouesL he departments can be grouped rough lato three physl aa saing dmatolog6cal and gographical at the pno (high planes) the Val.es (valleys), and the Tropicos (tropical zones)-although some departms rIbutes from all three geographic regins. TobtZikL N-2PARIENS BY KOJON wos~~~~~~..o~*ps~mn Attipltar La Pa Potoi YutteB Cochdbui Chiqusac TropIco Santa CrnR ent Pfo Mirfa: Nftsien assessmiflt. 22 Boliia's poplation is aoatel 7.3 milion It is esmated that 51% (3.7 miion) of the tot populaton lives in towns containig more than 2000 abitants; the National Stal 1ntiu (INE) uses this desigation to ident *urban are. Approximately 70,OOO of the total uan population live in the capital of La Paz Since 1980, the national urban population ha grown at a rate of 2.6% per year. Of the total rural population of 3.5 million, it is esdmat that dsighy under one-half are found in the Altiplano, which occupies about 19% of the national terty. The Valles ontain over 30% of the rural population yet cover 12% of the total rface area. Ihe Tropioos, which occupy 69% of the total land mas, are the least densely popuated areas of the country and hold appom 17% of the rural population. If Nautd for 10 bun an acta Word Bank gattgl for 16(6 alc) and eated pouati growh rt. for 19200(2 % p. a.) .6e ,cD= F&2MQQd=. 2.3 The early 1980's marked Bolivia's worst eoonomic cisis of the century. The artfcial economic boom whih dominated the 1970's, fed by capital n and the discovey of substantial hydrocabon resources, was folowed by a precipitous deteioration beg1ini in 1980. Net foreig tradsfers became strongly negate, real GDP fell each year and capital flight accelerated as economic poldies beme erratic and By September 1985, annual infladon had reached 24,000%, GDP per capita stood at only 80% of its 1980 level and public sector defcits accounted for one-fourth of GDP. 2.4 A wide ranging economic stabizao program was introduced in 1985 which indluded elimination of price controb, dereglation in the trade system and the labor market, establishment of a uniform hange rate (dermined tough daily auions) d policies to reduce public sector deficits Tbis brought an immediate end to hyperinflation; inflation was down to 11% in 1987,22% in 1988 and 6% in the first six months of 1989. Public debt has been brought under control and the exchange rate has remained unified. The impact on economic growth, however, had been somewhat less dramatic due to negative terms of trade during the initial years of the program. Growth in 1987 and 1988 was positive, but not sufficient to balac the growth in the population. As a result, per capita income has continued to decrease and remains under US $600. 2.5 The Bolivian economy remai fundamentally dependent on natual ps and mineral (tin and silver) exports as sources of foreign exchange and for servicing its relatively lae external debt (approximately US $5 blllion.1989). In 1988 these commodities represented 83% of total merchandise exports Thus, the economy remains vulnerable to the vagaries of international commodities markets Even so, the remarkable stability achieved under the 1985 stabilization Program can be maintained should the current Government continue to exercise sound economic policies. Short to medium term support will be needed from multilateral and btral sources and it is exte that debt service payments wi need to be reschedued in order to sustain economic growth. 2.6 Stn. ture of lhe current stucture of GDP reflects an ease in the share of non-factor services, the commerce and finan sectors. Ihe agriciutural sector's contnrbution to GDP has remained relatively fixed throughout the past two decades (24%), whereas the industial ctos share has deeased (from 31% to 23%) whie the service sector has been increasing (from 46% to 52%). Public sector paiciation in the production and provision of services-in the early 1980's the state was involved in 50% to 80% of all natural resource production, fancial services, tansottion and agro-indusial activities-has now been cut drastically under the tbilizio program. Meases have been taken to attract forelg and domestic private capital; the public sec revised role has been limited to the provision of public goods and services. The public sector remains, however, active in the production and marketing of bydrocarbons and electric power. Promotion of joint-ventures in these areas is one of the Government's current objectives. -7- 2.7 The energy ses contribution to ecnomic growth rens cosiderable despite a critical decline in oil production. With the development of naural Ps rerves, hydrocarbons continue to be the main source of hard crenc. In sum, the sector coatrbutes more than 50% of the national teasuz's income and it accounts for over 90% of reonal govemment income in hydrocarbon producing regions. Hydrocrbons currently mak up more than 60% of total eports, as compared to 24% in 1980. 2.8 Hydrocarbon represent Bolis predominant indigenous energy resource. Reserves are more gas than oil-prone. At present, about 60% of total liquids are produced from condensate. Development of hydrocarbon reserves bwn in the 1960's and output peaked in 1973 at 47,400 barrels per day. The subsequent deeline in production (17,700 barres per day in 1986) has resulted from a combination of depleting reserves, lack of new invesment and insufficient exploration due to limited interest on the part of international companies. Oil exports, which averaged 32,000 barrels per day in 1973, have been reduced to spot sales of naphtha and gasoline. Still, urrent domestic production of hydrocabons norully is sufficient to maintain an equilibrium with demand, as domestic energy consumption has stagnated in the recent economic presres. 2.9 Natural gas remains the key element in BoliWs balance of trade. In the aftermath of the decline in the price of tin on international markets, national export earnings were generated primarly from sales of natural gas to Argentina. It is not clear whether these exports wil continue once the current contracts with Argentina expire in 1992. The outcome of current negotiations to sel ga-generated electricity (500 MW) to Brazil thus has maeoeonomic importance. The economy could face a major setback should Bolivia fail to find a market for its surplus gas. Main Power btem and Distrbution 2.10 The bulk of BoiWs electric power is generated and trnsmitted through the interconnected and isolated sems operated by the two major power utflities: ENDE, the national power company, and the privately owned COBEE. ENDE operates the bulk of generation and transmision facilities, whereas COBEE is the county's largest ditrbution company, principally serving the urban area of La Paz and selling bulk power to Oruro. The two utilities are interconnected at 115 kV. ENDE supplies power to COBEE to cover peak demand, and COBEE supplies off-peak energy to ENDE. 2.11 The national interconnected system inludes four princpal load centers: the Norther system (La Paz), the Central system (Cochabamba and Oruro), the Southern system (Potosi and Sucre) and the Eastern sstem (Santa Cruz). The Eastern Vtem, which has thermal (gas) based generation, was just recently connected with the hydro.based, North-Central-South interconnected sytem. Total instlled generation pacity on the interconnected system was 605 MW in 1988. Hydroelectric plants account for 50% of this apacity. COBEE holds just under one. fourth (23%) of total capacity (140 MW) but 46% of the national hydroelectric capacity. .8. 2.12 Several Isolated systems-the laet of w£ich (Trinidad) Is run by ENDE.ae found througbout the country pripalW sng smaller ua areas Tinidad, Tar4a, Cobia, etca). Ther ar lo umerous, independent stm (diel, mlco/minl.hydro) prd throughout rura areas of the countiy witcapacitiesang from 20 kW to 1000 W. A number of these sems seve or have sered miigncommunties lthe Altplano and Valles. In thedeparment of Santa Crz, for ampoe, thee are over 90 small-scale rura dectric cooperatives running on diesel and seig isolated, rural loads. 2.13 D Along with COBEE, which primarily seves the city of La Paz, there ae nine main disibution entitles which supply power principall to urn areas, and, In some instances, the Immediate outling rural regions. Table 2.2 lists the prinal distrbution entities along with thei respecti sevce eas The table also indicates If the entity covrs ral arewas: Tabte 2.2 MAIN DISTRIWTICN ENTITIES Entity Urban Sevice Area Rural Covrage CEA $ucre o Rural Extenion DeE a La Pa No Rtural Extensin CaEsanta C * Extesive Rural ELFIEC Coheburba Litetod Rural Extension ELEFEO Oruro lo Rural Extensin chELREC y g Trinidd * Rural Extensin CKLEA Cairi * Rurl Extensin STR S Tarije * Rural Extension UPam Potosi o tral Extensin (fePAN) A / Cobija CLimitod Rural Extesion) / Rona development corporation In the depertmnt of the Pand. Th genertion sytem Is disl based. b Denotes isolated sstes. I Posess grtion capacity of vwryin levels. fgMs Nission assessment. 2.14 i general, rural de tion has received a low priority in recent energ planning nd ivement actvites in Blia. In addiion to thos urban-based entitiea servng rur areas listed in Tabe 22, in small towns and rual areas numerous commu operate distribution concession or Power for these sstems is either purchased from the national grid (as in the ca with the ral electric cooperatives in the Altiplano-CR[PAZ--and in the Yun_a-CEY) or is generated by snall, isolted sms operated by a cooperative or a small. scale dirbution entity. Wble there is nominl super of rual electric e sn, in practice ruml ebnsin planning and development is the nbilit of the individual disrbtion entity. This lends to a general lack of pIoron, og ni and planning in the subsector. a9. 2.15 W'ie the Cooperadon de Fomento Energetco Rural (COFER) is desigated by the MEH! to provide organition for the rural electric subsetr, in practice there is little national or regional orgnizatio planning, techn or financia assistance provided. At the project specific level there is a general lack of analysis on the financial-economic or institutional viability of contemplated grid eteons (including deentralzed generation and distribution systems). In brieW4 rural elecfcaton planning and eecution is geraly driven by regional or external donor funding and lacks a coherent national, regional or sdte.speciflc anatical framework for planning and evaluation. As outined in Chapter I, it is at the sitespecif level that this ESMAP-assisted tecn analy is foced. 2.16 .urCoe For most households in runl areas, rural elecrfcation simply is not available. Data in 1980 indicated that less than 10% of the rural population in Bolivia had access to electricity. More recent data from the ME1H in 1989 indicates that appraoimately 25% of the rural population b, aMM to electricity. In areas where there is access to power, however, connection costs and low rural incomes and productivity are often deterrents to use. 2.17 For most rural areas the primary use of enerV is for household lighting and cooking. Rural inhabitants have traditionaLy consumed fuelwood, dried dung and other biomass to meet basic energy requenments, while keroene and LPG are the commercial fuels which most frequently displace biomass for the basic energy needs. The esdimated opportunity costs of rural electricity nasumeuniauelv. fo cooking andiiin however, have been estimated as being higher than those of kerosene and LPG v based on the same end-use. While rural electrification can be dificut to justf finandally or economicaly when oriented on household lighting and cookig, the viability of expanding rural grid or enhancng decentralized, rural stems can be augmented if productive end-use loads can be strengthened and/or developed (coupled with rational tariff regimes). The identifcation and development of pWuctive end-uses also holds the potential for complementing rural development plnning and activities. This latter point is generally overlooked in mrral electrifcation planning. gmnead Proec.t Area 2.18 l k _ The general area of this project specific analysi (IBRD Map 22437) is aprxmately 100 kilometes northeast of the capital of La Paz in the Yunps region of Bolivia. The area is dacterized by mountaous terrain, deep valleys and generally poor tansotation networks. The area, however, holds fertie valleys from which numerous crops (vegtables, fuit, coffee, etc.) are produced. Many of the crops are currently sipped to national markets, induding La Paz. 2.19 The Yunps region Is also a traditonal coca produng area. Due to the suitable maes and soils which support the coca production, the area holds the potential for enhanced V The kdtu cas of JiG and erosene for lumino hv bon estinated at 3S50 mis/1000 kea an 35 he magalcosto of nal eletidty was estimated at betwe 1394 mIU/l000 . Al eostmewere calculated In June 1967 by the MH wih dstance fom fte World Bank and UNDP . aua diff ial may qha canged In the Ieve thrOe yas; however mve magne, it I safe to - that LPG and kerose stM reprt enomI locoo ala for combined cooking and ightng in nw rurlre *10- agricWtural development and could supply an abundanc of alenative commodities. At prest, UNFDAC is focused princpaly on promoting alternatives to coca production in the zone, 2.20 Pr3ect Site, The specific project area for the rural lecfication component Incorporates the Astunta vally. The contemplated rual dection would run from the town of Chulumani, northwest along the Rio Tamampaya and Rio Boopi reaching the small town of Colonia San Juan de Cotapata (see Plan Maps la,Ib, I and U). As contemplated by CEY, the mrralgrid extension would be connected to the national gdd in the southwestemn portion of the project area in the town of Chulmani The adjoining area is principally served by the rural distrbution cooperative CEY, which purchases power from COBEE through ENDEs lines. 2.21 Headqua in the small town of Corico, CEY was formed in the late 1970's and cwrently serve some 4,000 consumers. CEYs sevice area borders an the Awnta valley. As envisioned by the original Agroyungas project planners, CEY would be the entity responsible for extending service to the project area. In conducting the tudy, the instiutional capabilities- including technical and administrtive requirements-of CEY are considered. In brief CEY charcterizes many of the instituional, technical and financial problems problems encountered by distnrbution entities in Boliva confronted wift rural grid extension. (See Chapter VL Institutional Aspects). * 11- m EL FRJ6:CIY DEMAND 3.1 This chapter outlnes the technical estimtes for resdential and productive endouse electricity demand in the Asunta valley project zone. Through the field recon and analys, the projections developed are approximately 65% le than CEY's origial demand estimates presented in scenario IL For the analysis, reidental demand consi primariy of domestic lightin& A defnition of productive end-uses of electricity Is: any use of electrty which increas the end-users' economic status by fiailitating production level inreases, production cost savings, and/or increased product quality. From the point of view of a utiliy, productive end-use have the effect of load building and generally, augmenting the off-peak load An example of a productive end-use could be as simple as a single electric sewing machine in a house or as complicated as electric motor-driven industria applications. 32 Demand is estimated in kW and consumption in kWh per month for the residential and productive end-use categories Composite demand estimates are projected and considered under both "probable' and "opthnistie demand growth scenarios Combined with cost estimates for the four technical scenarios evaluated and presented in the engineering analysi in Chapter IV, the residential and productive end-use demand projections are factored in the financial-economic analyses presented in Chapter V. Calcuag Residential Demnd 3.3 In assesing residential demand the technical team counted those houses that could be electified within certain geographical and technical limits in the project zone. Since all of the vfllages with any significant population in the project area are on the western side of the rivers Boopi and Tamampaya, and only isolated and widely dispered dwellings on the eastern side, only the western side of the valley is scheduled to be electrified (see Plan Maps). Throughout the field phase of the study no new evidence of enhanced load surfced to alter the basic boundaries of the proposed project zone. 3.4 The specific project area under study consists of 39 communities. To be included in the project house count, the communities and households had to be within reasonable proximity to the contemplated primary distribution line. Structures that have been abandoned or isolated, or dispersed households distant from the cmmuni are left out of the project house count Further, to be included in the projected connection count, households bad to be within a geographic density of at least 2 per 100 meters of potential secondaey line. Single, isolated houses distant from the community nucleus are excluded from the connection count. a 12- 3.5 Based on the project house count and the gogphical ideratons, the analysi esimates the number of households in each community likel to connect In year 1. Table 3.1 shows the project house and connection count as considered on a communlity-bycommunity basi The sum of the projected initial connects (937) is about 56% of the project house count As outined below, individual dharacteristics of the communites are considered and in_u"e projections for population growth and, in turn, growth In new residential connecdons over thirty yeas 3.6 For projecting growth in new connections over 30 years, ach community is individualy considered on the basis of the following d: - Proximity to and condition of traportation routes; Natural resource base (mainly agricultural); - Past and present economic actiity seen; - The presence of institutions with a commitment to the development of the community and/or region. The growth potential of the 39 individual communities is then graded on the following scale w: = 8gh (5 to 10% per year); - Medium (0 to 5% per year); = slNeutral (0% per year); - Negative (-5 to 0% per year); - Very Negative (-10% to -5% per year). in turn, the aggregate growth for new connections in the project area is calculated weighing estimated individual community growth. The aggregte rate of population wth and growth in new connections is calculated as 5.75% per year. While used as a general guide, this (high) rate is tempered by enhanced field assessment since other observed factors are considered to be of sufficient importance. For example, a ceiling of 3,000 residential connections is placed on the entire valley-yielding an actual growth rate in new connections of 4%-since many of the towms, due to terrain characteristics, have limited physical room to expand beyond this imposed ceiling 3.7 Factors that influence the use of a rate in the medium growth range are epined as follows: Factors Favoring Medium Growth - Asunta valley is a rich agrulural new setdement area where regional growth can be ewected to be above the national average; - The area is presently the focus of various national and international development efforts; and Employment and income opportunities may serve to attract people to the project area. W / In addiion to the technica consultnt team, u projet personel in the projct area provdd Input for asose th rOWth poteto the _d communti * 13 - Tablo 11 COIWJNITIES IN PROJECT AREA HOUSE COUNT AND EXPECTED CONNECTIONS PROJECT HOUSES EXPECTED COStITY COUNT CONNECTIONS (Yer 1) Villa Remedios 60 23 TaSjm 100 60 Pastopata 75 55 CoLopeapa (Nucleo Escolar) 6 0 Arrozal 18 12 Choquechaca 7 S Villa Barrientos 52 46 Centro Tocoroni 20 9 Concha Grands 20 9 Concha Centro 20 9 Totora Pampa 11 2 Cruce de Nercedes 17 6 Lag Nercedes 100 73 Totora Chica 22 9 Totora Grande 40 18 La Calzada 100 73 Santa Rosa 75 SS Colopampa Grande 60 28 Playa Ancha 12 0 Yansmyso 75 3' Chamaca 60 32 Charobamba 27 14 Charoplaya 67 41 Callisays 55 28 Copalani 25 14 Guayabsl 8 3 Asunta 250 165 Charia 40 18 Pichari 30 9 Los Olivos 10 5 Cotapata 35 18 Quinuni 60 4 Santiago Tocoroni 35 9 Santiago Chico 6 4 Villa Santiago 17 9 Santiago Siete Laws 11 S Incapucara 15 7 San Juan 32 18 Narquirivi S_ total 1,678 93? Source: ission assessment. * 14- Factors Mitigating High Growth - Annual population growti in Boli"ia is estimated at 2.6% per year; - hIe topography in the valley limits physical viag expansion; - The introduction of electricity and other improvements to quality of life have been kmown to lower birth rates EM=eded Rslecns 3.8 The projected residential connections in year 1 in each of the 39 communities in the project area appear in Table 3.1. In sum, the techal team estimates that there will be 937 household connections in year 1, growing to 3,000 In year 30. Using initial and year 30 totals, a yearly average growth rate in new connections of 4% is epected. Average Residential Consumption 3.9 An initial residential average consumption of 15 kWh/month is projected on the basis of field analysis in similar electrified zones In the Yungas, as well as comparative figures for other rural electrification projects. In addition, CEY reports an average consumption of 20 kWh/month per new residential user in a rural community. A rural household, as observed by the technical team in electrified regions in the Yungas, typically use two 75 watt bulbs for approximately 3 hours a day for domestic lighting. The result is a basic minimum demand of some 13.6 kWh/month. The size of the bulbs and the time use may vary. Experience in rural areas in Central American countries (El Salvador, Guatemala), places initial consumption for a rural residence around 17 kWh/month 11. The figure of 15 kWh/month, therefore, is projected as the initial monthly consumption for a rural residence in the project zone dedicated prarily towards household lighting. 3.10 Local experience and comparative figures from rural electrification projects (El Salvador, Guatemala) are used in estimating average residential consumption for year 30. The general average for residential consumers of CEY is 36 kWh/month at the end of 10 years. This average however is influenced by users in relatively large vilages and is probably lower for rural areas. On the other hand, given the potential in the project zone for economic growth, it is assumed that demand growth will be slightly higher in 30 years. Comparative figures from rural electrification projects in El Salvador and Guatemala, among others, show consumption of 40 kWh/ month at the end of 15 years in rural areas I. For final consumption in the year 30 in the project zone, the figure of 40 kWh/month is used for projecting residential consumption. Wll NRECA/USAID: Centr Ameulcs Rual Blectrifcon Project,An Economic Review of Electicty in Productive Ue Actvies In Rurl Gustmeala, 1989. W Ibid. 3.11 For the study area, eistg (but not necessarly eectrified) as well as potential productive end-uses are identified. Ti Identfication was carried out via recoaissance in the spec cproject zone and in smilar electrified areas in the Yungas, as we as an appraial of the agro-ecological and mineral potential of the project area. Te proposed complementary activities of the Agyna integrated development project are also taken into account. In all, a total of 37 existing and potential productive end-uses are identified and considered. 3.12 In identifying types of productive end-use acthidvos In and for the project zone, the acdvities are classified under dtee major categories: local, productive uses; productive uses destined primarily for 'external markets, Le. outside the project zone; and productive uses associated with 'transportation'. (Under the 'optimis growth scenario, an 'industrial/agro- industrial' category is also defined). 3.13 In addition to identifying tpes and quantifying the kWh/month consumption chacteristics of the productive end-use activities (see Table 3.6), estimates are made regarding their expected rate of growth over the course of 30 yeas Different growth rates are considered for 'local', "extemal and 'tasportation' oriented productive end-uses. 3.14 The projected number of productive end-uses for year 1 and potential growth in these activities are considered on the general basis of the following fators: - Availability of a reliable electricity supply in the project zone; = N4auNral resources in the project zone; i Existing or potential demand for the product or senrices; and = Observed experiences and activities in the project area and in similar electrified zones in the Yunas. The composite result is a projection in the type, number and growth rate for productive end-use activities that might be expected in the zone in year 1 through year 30. he composite results are presented in Table 3.7. The type, number and epected growth rate for productive end-uses is calculated and presented under the 'probable' and 'optimi growth scenarios. * 16 - Productive EindUe LocaL External and Tran t Related Productive End-Uses 3.15 "Locall productive end-use activities identified are listed in Table 3.2. and are classified as current exsting in the project area but not necessariy electrified and ggMi= identified from simflar electrified zones and/or suggested by agro-ecological conditions in the project area. Tle categorization of "new" and "existing" is utilized in the financial-economic analysis for quantifying and calculating economic benefits. (See Annex 9 for a detailed explanation of the method used for the calculation of economic benefits for residential and productive end- uses): Table 3.2: LOCAL PRODUCTIVE END-USES IN PROJECT ZONE Existing New - store (smatl) - Ielding shop (small) - Tailor shop - Radio station - Nayachaita / - Ceent product factory - General Store (lare) - Ice cream parlor - Video showroom - Animal fed (mill and mixer) - Carpenter shop (small) - Dairy processing plant - Health clinic - Hair dresser shop Small office - Brick factory - Grain mill - Electronic repair shop * Poultry farm - telding shop (large) e Movie theater - Carpenter shop (larg) - Butcher shop ay Mayachasita is a small agro-industrial pilot or demnstration area where n crops and livestock are raised and adapted. They are profit-oriented, comiunity-run associations Which were started and promoted by the Agroyungps project. source: Mission assessment. 3.16 Locl Productive End-Uses and Trobable" Growth. To develop the probable growth scenario for "local" productive end-uses, it is assumed that their growth rates can be related to the expected population and aggregate growth in new residential connections. The aggregate population growth rate of 5.75% (discussed above) is therefore a general guide for projecting the growth in activities in this category. Strict application of this projection is tempered, however, by the following factors: (a) Certain activities are relatively new or do not currently east in the project area and it cannot be assumed that they would come on line and grow as soon as the project zone is electrified; and .17 - (b) The characteristics of individual communites, including population, current social and economic activities, and distances from the main road, can alter the probability that a certain productive end-use will appear. 3.17 Projecting a number and growth rate therefore for a productive end-use activity is fundamentally based upon assessment of the individual communities, including expected growth, perceived on-going productive activities, and activities seen in similar electrified zones in the Yungas. Based upon the individual community assessment, numbers are projected for each of the local use" activities. Table 3.7 shows the projected number for all productive end-use activities for the project zone in year 1 and their expected growth. The data in Table 3.7 shows that the 'local" productive end-use activities of small and large stores, combined, constitute 47% of the total projected end-uses under the 'probable" growth scenario. The average growth projected for these activities over 30 years is 2.8% and 2.9% respectively. 3.18 Extemal Sales End-Uses and "Probable Growth". The second productive use category, "external" sales, are those productive activities whose number and growth can be related to the natural resource base in the community or the zone and whose sales depend mainy on markets outside the region. In the case of the project area, productive end-uses in this category are usuaUly those associated with agricultural activities. 3.19 "External" productive end-use activities for the project zone are listed in Table 3.3 and are also classified as curenty eing in the roject area but not necessariy electrified and those new uses identified from similar electrified zones and/or suggested by agro-ecological conditions of the zone. tasle 3.3: PROUCTIVE END-USES FOR EXTERNAL SALES Existing New - Coffee pulper - Coffee .f1l - Mine (mde.u-sfzed) - Nine (large) - Stall camfing plant (fruits. juices, preserves) Source: Nission assessment. 3.20 According to Agroyungas data and information, coffee and fruits hold the brightest prospect for alternative crop development in the project zone. In the case of coffee, it is being promoted as the main substitute for coca. Using Agroyungas project figures the technical team estimates that Agroyungas efforts have brought about an increase of 10% per year in the number of hectares of coffee planted in the last two year Although coffee is affected worldwide by price fluctuations, it is assumed that groups interested in substituting coffee for coca in the project area will continue to promote its introduction and development in the near future, Le five years It is less probable that they will continue to do so on a ten year term, but the efforts of the next five years should continue to have their effects throughout that period. * 18 - 321 A weighted growth rate of 6.8% is therefore considered as a general guide for growth projections of productive end-use activities related to coffee (pulping and milling). This assumes that coffee production will increase at a 10% rat during the neo five years, at 7.5% the following five years and at 5.75% per year the remang 20 year The strict application of this growth rate for these activities is tempered, however, by the factors used for projections for 'local' productive end-uses. Based upon individual community assments and the natural resources in the zone, the projected number and the growth over 30 years for extrmal' productive end-uses are shown in Table 3.7. The average annual projected growth over 30 years for coffee pulpers (as well as medium sized mines) is 4%. Table 3.7 also shows that in the Oexternalt category, coffee pulpers constitute approximately 30% of the total productive end-uses under the 'probable growth scenario. 3.22 The growth scenario for productive end-use activities related to fruit, ie. small canning plant, is taken to be similar to that of coffee. An additional restrat to growth for this activity is transportation. Transportation of packaging materiaLs from La Paz and the subsequent shipment of products to La Paz markets would be affected by access to and the conditions of roads. (The current travel time from the project zone to La Paz is approximate 7-8 hours in good weather conditions). For 'probable' growth projections, the growth rate utilized for coffee-related activities can be a guide for growth projections for productive end-use related to the production of fruits, juices and preserves, i.e. 6.8%. This general growth factor is also considered for mining activities (medium scale). Based upon field and individual community as ents, however, the rate is tempered downward, eg. for coffee pulpers and medium sized mines, the growth rates over 30 years are approximately 5% and 4%, respectively. The projected number and growth for the 'external' productive end-use activities are shown in Table 3.7. 3.23 Trnpratn Prducdve ETndUses and 'bable Growth! 'Me third category Of productive end-use activities are those related to the flow of vehicles and transportation in the project zone. The growth in these activities is a function of the amount of vehicle and passenger traffic through the project area. The transportation-related uses identified are listed in Table 3.4. These productive end-use activities are also classified as currentl existing but not necessarily Ictrifed or Me. ibnl 3.4: PRODUCTIVE END-USES FOR TRANSPORTATION Existing NW wedlue size hotel G Gasoline station Tire repair shop urme: Nission assesment. 3.24 Based on field observations, the growth of cargo and people movement is assumed to be directly related to local productive end-use activities, as well as general economic activities destined for sales outside the zone. Thus, a general growth rate for productive end-uses related to transportation could be placed between the general growth rates for internal and external productive end-uses activities, Le. between 5.75% and 6.8%. For this resson, a rate of 6% is selected as a guide for growth projections for productive end-uses related to transportation. Although this rate serves as a guide, the same considerations noted for 'local' and 'external' *19- productive end-uses are applied. The strict appliation of this partiular growth rate is therefore modified by field and community asessment Actual projections for the number and growth of these activities are shown in Table 3.7. As observed ini Table 3.7, the calculated average growth rate for the tee activities is 5.6%. 3.25 I The composite data in Table 3.7 reveals that under the probable' growtb senario, the aggregate average growth rato for all productive end-use activities over 30 years is app tely 4% (202 . Year 1, 672 - Year 30). Under the 'optimistice growth scenario, the rate is approximately 5% (253 - Year 1, 1,136. Year 30). Productive End-Uses and the pm Scenario. 3.26 There are three factors which allow for the development of an "optimist' growth scenario for productie end-uses i the project zone. First, the possibility that international donors and/or the government agencies continue to support the development of crops seen as alternatives to coca over the long term. Second, the possibili that private sector becomes interested in investing in industrial/agro-industrial development in the project area-given the natural resource base. And third, the existence of gold mines in the Asunta valley area and the posility that their eanded development within the project area will influence (increase) the use of electicity. The aptmisti scenario is therefore based upon higher growth rates and allows for the creation of a new category of productive end-use activities, Le 'Industrial/agro-industrial. 327 An inspection of the agrcultural and agro-ecologic dcracteritics of the project zone and the area surrounding Asunta allows for several industl and agro-industial development possibilities under the "optimistic' or hi growth scenario. w Based on field observations, it is blieved that the industies and agro-industries listed in Table 3.5, among others, are possible in the Asunta Valley Tlabte 3S: POTENTIAL IDURIES ';iO AO-INDISTRIES - Tuber ST Attl (tLarge scate) - Indsrtriltizatfon of Coa * Processing Essential Oils - citronella (CCdbopoW nsrda), tsuasr (CWbopon citratus), ad vetiver (Vertiverts ziazloides) - Rice Prodction awd Hlltin (large scale) - Growing and Processing of CasheA Nuts - Fruit Procesng (large scale) SKM Hft"fon assessmet. IV Naturd mour chwaa o of the zone (a noted by the tec team) fing nusr and agro-ndtl devlopmtare as followE An altude of aoaty600- m eterssil appit forpennal o raIfa 9-10 months u of the yea ih a total of betw 726 and 1,176 mm (1962); ava e wtemte of 241 C (1987); tmber yieldn fores includin mahogan (s_knte macrtphylla), wanu oungn Cedar (ea)d lawrbd (necauda) and bas wood (hillotere biruts); and low demagaphic denty. a20 - 3.28 The potential sizes of these agroindustries ar estiabted in tms of their kWh consumpdion per month For projecting their estabishment and grwth, the following factors are taken into account- Natural resource base for the potential industry/agro.industrr, Planting period and time frame for Industry development; and - Ipical Sizem 329 In/Aj induar iaLimA.r Asming that the development of alternatives to coca leaf production wil be promoted over a longer term, a growth in productive end-use acities sila to that obtained by the Agroyunps project with coffee is projected under the "optinistice scenario. Agroyungas considers coffee to be the crop that drives alternative development of the zone. Based on Agropungas experience with coffee and team calcuations, the growth rate of 10% for al types of productive end-use activities is used as a guideline for projections of the "optimise scenario over the next 30 years. As in the case of "probable demand rowth, however, this figure is used as a general reference for growth projections. (The annual averag growth used for all productive end-use activities under the "op tic" scenario is apprimately 5%). 330 The establishment of the activities listed in Table 3.5 is considered possible under the "optimist scenario. (There are two exceptions: In the case of the sawmi and fruit processing plant one of each is projected-based upon Agroyungas investment plans-under the "probable" growth scenaDio and factored in the financial/economic analsis). Only in the case of the fruit processing agro-industry and sawmill is more than one of the activities envisaged in the "optimistice scenario. For the other activities, only one productive unit is estimated and the projection consists of esdititng the most probable year for operation to begin. For eample, the cashew plant is estimated for the year 11 under the "optimistie scenario taing into account the fac that, although the potential exists, the crop is relatively unknown in the zone. Based upon agricultural information, it would take at least five years to develop the plantations and another five years to plan and implement a processing plant. IdentiSd and PloWeta Productive End-Uses Projections for Prdcive End-UAes 3.31 The composite list of identified and potential productive end-uses for the project zone, their etimated kWh/month consumption and the estimated economic benefit is presented in Table 3.6. 3.32 Complementing Table 3.6, Table 3.7 presents projections for the number and groth of productive end-wUes that would be eectrified in the project zone. Based upon the data presented, the aBegate peroentage growth projected for the productive end-use actvities over 30 years is 4% under the "probable" scenario, and 5% under the "optimisti .21t XiL.As Pt IAL PW=XTIVE ENDU Conaui*tfon Chharateristics and Economie 5efit g/ consumption Bmetal¢ Profictive use kIA/mont uP/insth Esential ofil Plant SI 3.000 5.72 Cahw Plant / 3,200 141.38 Rice Agro-industry */ 6,400 27.94 Coca Agr-friAntry a/ 1600 72.10 Fruit Aro-indsttry W 6000 349.2 Animal Feed (mil and mixer) I 513 25.03 Cement Product Factory SV 8,300 362.21 smll IV 8,300 362.21 Coffee fitlt S/ 5,000 219.32 Grain Kitt W 175 20.6 Sutcher's Shop / 240 13.21 Carpentry (large) SI 200 11.48 Crpentry (smell) / 100 24.94 Movie Theater a/ 85 6.50 Video Showoom hI 20 47.98 Smatl Caming Plant SI 100 7.15 Coffee Pulper W 6 24.25 Poultry Farm S 171 10.22 sce Crem Parlor I 700 33.13 Nealth Clinic 4t 700 212.35 Mediu size Notel kI 650 ?6.27 Brick Factory SI 20 33.30 Tire Repair shop Al 145 9.10 "ayachasita W 400 136.40 Nine (terse) Al 6,080 266.08 Nine (mdifu sief) M 1,S2S 43.86 ball Office W sO 90.43 Hafr Dresser Shop I 32 3.97 Dairy Processing Plant jS 60 5.42 Riado Station SI 4,000 176.02 Tailor Shop W 45 16.95 da Station SI 153 9.44 Electronic Repa r Shop At 33 4.03 Weldin Sheop (larsg) S/ 1,300 59.11 Welding Shop (smtll) AS 60 30.96 Large Store S 180 30.00 Sbll store 72 15.59 Public Llghting 700 33.33 SI Dnrates new activity. An existing but not necesarily electrified activity. £ Thoch usg Itll ftuctuate throghcut the year for am productiwv us, fgures presented reflect anul conwptfon dividd over 12 mont. (Se mx 9 for daesriptfon of the mthodology used for calculating eomdic benefit.) §IM: Niseson asesement. . 22 - TbL2 1.7s POJICTI WmER OF PRlTIV END-USE ACTIVITIES Proble and Optimistic Growth Estimats V/ Probable optimistic Pt0DUCTIVE USE / VWI 1VW 30 VEI YEAR 30 A EssentialL Ot Plant W 0 0 0 1 A CabwPlant M 0 0 0 1 A RIcO Agro-iindtryg/ 0 0 0 1 ACoco AAro-industry & 0 0 0 1 A Frut Agro-indstry5/ 0 1 0 2 L Animo Fed (mill, mix) M 0 2 0 0 LCemnt Products factory i 0 0 0 1 A SaUillt 0 1 0 2 ECoffee Nill 0 1 0 2 LGrain Mitlt W 0 10 0 16 LButcher's Shop 0 7 0 12 LCarpentry (targ) Al 1 3 1 5 L Carpentry (emtII) bW 6 28 6 49 L Novie theater / I 1 1 2 L Video Showroom W 2 12 2 25 E Sall Cnning Plant / 0 3 0 5 ICoffee Pulper I I S0 196 100 333 LPoultry Famr I 0 3 0 5 Ltce Crea Parlor 5 1 a 1 12 LHeatth Cltnic W 2 3 2 5 T Ndiub Size Hotel hi 2 12 2 21 L:Brck Factory a/ 0 1 0 2 T TTie Repir Shop I 2 11 2 19 LNsyachasit W 1 6 1 10 E Nine( trge) A/ 0 1 0 2 E inr (mdiuu size) 2 6 2 10 LStlt Offtee . 7 20 7 35 LHeir Oressr8hop I 3 10 3 17 LDairy Procesaing Ptant St 1 3 1 5 LfRadio Station i 0 1 0 2 L Taltor's Shop W 10 29 10 50 T anStation / 1 3 1 5 L Electronic Repir Shop / 2 12 2 21 L Welding Shop (tarse) / 0 2 1 4 L Welding Shop (atll)p/ 3 20 3 30 L Large Store y 10 24 10 42 L alsl Store ill U la _ 34 Sub-Total 192 642 243 1.106 (PtbIic Lighting Units) Jd 10 30 10 30 TOTAL 202 6n 253 1,136 5/ Dontes a new activity. y An existing but not ncesserily electrffled activity. Y Takes into account the prootion of pulp removers by the AgroYtogas progrm. di Public lightino units are calculated as approxKitely 1 light per 100 residential conwer and use 7 MA/month. This Is assi as a productive ed-us In the finanisal-ecomic model and factored in the dmd estimtes. St Category of proActive and-use activitys LuLocal, ElExtenal, TuTransport related, A"Pro-indstry. V Applicable to all scenarios apt la. sre: Nfission asses_mnt. -23 - Tota Nubet n Cmmr and PEimate Demand 3.33 From the data in Tables 3.1t 3.6 and 3.7, the total estimated number of residential and productive end-use consumers is presented in Table 3.8 under the 'probable" and 'optimistice growth scenarios. tle 3.8: ESTINATED LMmE OF CONSIDRS PraLs optimistic YEARI YER 30 VEM i Y 1 30 Residential consiAmc 93? 3.000 937 3,000 Productive Use CoIu4mrs (including public tighting units) 202 672 2S3 1,136 Total Cnawmrs 1,139 3,6X2 1,190 4,136 s Nisslon assesamnt. 3.34 Based upon the estimted consumption in kWh per month for residential users and productive end-users (Table 3.6), demand estimates in kW are summarized in Table 3.9 under probable and optimstic growth scenarios. Tabl .9j: DEMAN ESTIMATE (KEW if Probable optimistic Year I YeGr 30 TYar I Year 30 D-mad in kW 196 947 243 1,313 I/ Dewtlopnt of cerposite W demad fI igs are explained in Chapter IV and are based on dand tables adapted to Bolivia. Sorce: i"sion assessnt. -24- IV. LEASTCOST ENGINEERING ANALYSIS 4.1 A pelaiynay engineering anlysi of the original CEY study for grid extension into the Asunta valey is presented here, as well as a prelimlnay engineering assessment for the alternative scenarios. To complete these analses, technical and engineering data was ascertained directly from CEY, as weJl as from COBEE, ENDE and the Empresa de Lu Y Fuerza Electrica Cochabamba SAMK (ELFEC). The enineering prefeasibility analysis required the presentation of tehnical desg chnes and recommendations that would result in lower cost, while enurg system integrity and relability. Based upon the review of the CEY study, three alternative technical scenarios are presented. 42 The main activities pertaining to the engineering assessment were therefore defined as follows: Review prdiminazy distibution des developed by CEY in view of the need to reduce distrution costs and enhance the financial-economic and institutional viabiity of the proposd grid ension, recommending changes that might contribute to these objctives, eg. types of lines, changes of route, equipment and potential connections to other load centers which might enhance project viability, and Review/revise proposed technical parmneters of grid extension based upon demand modifications developed by the technial team working on demand. 43 Given the relatively imited electricity demand in the project area (see Chapter m Table 3.9) as amessed by the technical team, coupled with natual resource potentiai options for decentralized generation (small-scale hydropower) with isolated distnbution systems were discussed and preented during the in-country tedhnical misson. Technical scenarios and financial/economic analyses for these options are not developed given lower cost estimates for grid interconnection and the priority of the project Directorate in anuahm&& gaW coverago in the project area. w WI SoWVevesioed theconstuoofa 12MW dpantnhprw arsw hpm dsbuton 1e ay ded tU th zoe e ay oost e s for the scenaio are 1US$42 milio, not the tutial delopmt ed for t opeato and adminitao of a qsem Sceado V. called for theo m of a mi p (300 kW in one key ded ofaea (mf toaly pt a re a coet estimates are USS 604,000, aot VW yddIt dietopmt e d that t be no fther prefuea dwdq_ f hee sema_;o Scaro° IV. was olmntd on the basis of csa and scnro V. on the basi of a 25 - ko and A mMn LMethod 4.4 Specific actvities for the engineering anals, luded both electical and mechanical (strength) igations, as wel as histoic cost Inmatio s data prvides a basis for the technical and cost projections for the technical scenarlos Data and Information gthering activities rgrdin costs, consumer power usag, projections of usage in both urban and mral areas of Bolivia, as well as Information regardin avaiability of wood and concrete poles, were carried out during the tedcnical assistance mission and continued dateards by national consultants In addition to the report of CEY, a brid report by ENDE (December 1983) for the specific area under study, as wel as reports for electric gid exension Inother pans of Bolvwere reviewed. 4.5 Load and population infomation was dbssed and coordaed with the techical demand ment team and agreements reached on population, prospective loads and projected initial and long-range loads in the project zone. 4.6 Analysis of the prumiay desig prepared by CEY (scenario Ia) was carried out based upon original CEY load estimated_ Te approach utilie an economic conductor size/cost analysis program called ECONCON IV and includes calulating voltage drops for the thirty year projected load. The procedure is used to analyze CEY's preliminary design, as well as the three alternative scenarios developed by the technical team. 4.7 For the orgn plan prepared by CEY and for the alternative soenarios, costs as weli as technical features such as load carying capacity and satisfactory voltage drop performance under projected peak load conditions are anazed. Cos estimates are based on information contained in reviewed reports, as well as on dicussions and data obtaied from local electric sWppliers. Volage drop calculations are based on methods adopted by the Rural Electrification Administraon (REA) of the United States Department of Agiuture (USDA). 4.8 Additonal All alternative technical scearios developed are based upon the wprobable" demand gowth projecdons presented in Chapter m. ITe alternative technical soenarios are desigled, however, to accommodate up to 25% additional demand, e.g the alternative scenarios epectIng 947 kW total demand can acoommodate a 1,200 kW system demand. In the event of the oaptimistic' demand growth, ie. the emergence of major industrial or agro-industrial comer(s) in the project zone, line additions and/or system modifications would be requred. Ag" and lkevelg-me of Technical S=oenro 4.9 Ihe engineeing Inretion commenced with an examination of the pre_iminay report prepaxed by CEY for lectrtion of the project area. Tech information, comments regrding load estimates, voltage conditions and cost for this approach are presented in scenario W ECONCON is compor model for coadut size and coszo It wa deloped by Stal 1 Muscoadn Iowa and udlizod 1he anasls -26- Ia. Alterative scenario Ib maintains the same premnay line desig as presented as CEY, but uses the revised projection of load and demand developed by tie technical team. 4.10 As noted in Chapter II the revised demand s approximatel 65% less than that projected in the CEY report. The revised demand estimates calculate eisting and future population within the sudy area and develop projectin for connections, power usage and demand over a thirty year period. CRY demand projections are utilized to allow comparative analysis with the alternative scenarios presented. The tenical tes demand projections-summaried in Table 4.1 (see Annex 1)-remain constant for al alternative scenarios studied. Tho resed projections, under the 'probable" demand growth are summarized and compared with the original C1Y projections in Table 4.1: IMLE 4.1: E#W AND CEY DEMAND PROJECTIONS TECHNICAL TEAN CEY REPORT ar Om NuIer of Carmunra Reoldmntt Use 937 2,000 Prodat1vo Use ag UK 1,139 2,404 sh atesAinnth tesdmntlat 14,000 56,000 Prodtivo Us 113.S00 42,500 169.500 kWfl Res1dentlet 97 225 Productive Use jga H 197 619 Year Thfr Mud3er of Conrars Rksdsntiat 3.000 6,050 Productive Use 3,672 7,394 kWdh 8tls/lbnth sfdsntdal 120,000 454,000 Prodictive Use 136.500 IJL 256,500 ff6,000 kW MJmd Res1dantlet 546 15,10 Productive Use 6 00 946 2,886 MMga: CRY report mid mison as mesnt. a 27 e Liaw Flws and Volage DroM 4.11 To help determine load flows and voltage drop In various secdons of the systems studied, demand tables have been developed for the various load conditions expected to be encountered during the life of the line (see Annex 1). Demand for Initial and thirty year design conditions for both the CEY and the technicl team demand is developed using methods in the USDA-REA Bulletin 45.2b "Demand Tables. PoFmulas used In this method are based on historic information first gathered from residential areas in the United States. The formulas account for diversity among consumers and differences mn kWh usage for various groups of consumers 4.12 lhe orgal U.S. data is modfied by adjustment of the presumed load fator to represent loads expected in the Asunta project area. The applied ajustment actor was obtained by analysi of historical load factor values in Bolia. The demand table uxs in this study show monthly kWh usage, actual load factor (in addition to the REA US. presumed Load Factor), and the calculated demand for consumer counts ranging from 1 to 10,000. 4.13 Voltage, Dro. Voltage drop calculations were made for each of the technical scenarios by applying the maximum thirty year load to the system desig. The method and values used for voltage drop calculations are prepared so that neither of the alternative arrangements are favored. Voltage drop calculations are based USDA-REA Bulletin 45-1, "Guide for Making Voltage Drop Calculations'. Individual consumers were assigned to line sections according to the technical house count. Voltage drops for the system design project the existing consumer count and locations on a direct ratio basis to the thirty year design level Productie end-use loads are also located on the basis of direct ratio to existing house counts. All loads on single-phase and dtee-phase lines are assumed to be balanced in accordance with good operating practices. 4.14 The generally accepted guideline for rural primary distrbution line voltage drop of 8 volts on a 120 volt base, ie. 6.66%, is used to determine the ability of a given conductor to provide acceptable voltage to connected loads. When coupled with the use of voltage regulators at the source end of a line, a voltage drop of less than 5% of nominal primary line voltage is attainable. This is within the range of acceptable voltage in accordance with guidelines contaied in the American National Standard Publication ANSI C84.1-1982, Table 1: 'Standard Nominal System Voltages and Voltage Ranges'. Voltage variations established in this standard are presented in Table 42: Table 4.2:STDSARD VOLTAGE ANGES MM A (X2 Rm B MX Nominal System Voltaep inx n Nx Nin 240/120 volts 105 95 105.8 92.7 480 volts 105 95 105.8 92.7 13.2Y/7.62 kvolts 105 97.5 105.8 94.7 24.9Y/1i4.4 kvoltt 105 9T.5 105.8 94.9 34.SY/19.92 kyoltt 105 9T.5 105.8 95.0 g=: Amrican NationaL Standrd Publication ANSI C84.1-1982, Table It 'Standard Nminal Sptem Voltae oltaw Ra' *28 4.15 Range A values, as shown In Table 42, are used for normal operation of electical stems whie Range B values are accepted as maxdmum or minimum term voltag values expected to exist during periods of peak loading or during other specal short time oonditions. The values in the standard represent maximum and minimum oonditions for whih equipment and other system components are designed for satsfactozy continuous operation without derating. 4.16 Madmum voltage drops and locations are shown on the maps for the vaious technical scenarios (see Plan Maps: Agroyungas Estudio Prelnr Alternaivo Ia, Ib, AL I). Maximum voltage drops and locations for each of the four scenarios are listed in Table 43 for reference: Iabtle : YEAR THIRTY NASINL WLTAGE NW (ONd 120 VOLT BASE) AND X VOLT DROP cmrative Voltt prog Location ^/ Volt Drop % Volt Drop w Scenarfo to F 16.2 13.5 Altermative lb F 5.3 4.4 Altermtive 11 F 8.9 7.4 Alternative III Do 6.9 5.7 a Reference location on attached Plan Naps. b Excluding voltage regulator improvements. Surce: Nission assessment. 4.17 Unit costs are developed for each of the line types and conditions used in the outlined technical scenarios. Unit cost are summarizd in Table 4.4 below. (Additional details regarding their development are included in Annex 2): . 29-o tlM 4.4s UlNITIZED COST ESTIAMA Principal lines g/ Thrme-phse, #2/0 ACS conductor 8,000/k. Three-pse, #1/0 ACSR conAictor 7,000/I. Threphse, 94 AcS canditor 5,000/k single-phase, #4 ACtS coActor 3,000/k Tnps awd brnch circuits Singe-phase 04 ACSR cowctor 3,000/b Secondary lines, single-pbse or 3,100/1k three-phase; aerwo cost Neters wnd service drops 41.50 easch Tronsformers 60/kh. Nydroelectric plant, installed 2.000/lU Eniolneering and Adainistration 15S (% of estimated construction cost) Continfencies 10O tX of estimted construction cost) &I Costs are fteld-based and cooperable to tosts ineurred by other Bolivian utilities at the tim of study. Soure: Nission assessment. 4.18 Once the unitized costs, initial and projected loads, and voltage drop cal tion are standardize, they are applied equaly to the various scenarios. The following disussion of the technical scenarios includes reference to standardize loads, csts and voltage drops listed in the previously cited Annex 1, 2, as well as Annex 3 (Voltage Drop Sheets). 4.19 Four technical Plan Maps for each scenaio are included for reference. Each senario to be dised has its plan which includes projections for number of consumers, electric demand, distances involved, types and sizes of proposed lines and associated voltage drops. The four technical scenarios have been identified as follows: Scenario Ia - Preliminary Study/Design of CEY 24.9 kV line with source at Chulumani Scenario lb - Preliminaiy Study/Design of CEY with (ESMAP) Technical Team Load Projections 24.9 kV line with source at Chulumani Scenario II - (ESMAP) Technical Team Load Projecdons and Alternative Desig 24.9 kV line with source at Chulumani Scenario III (ESMAP) Tecal Team Load Projections and Alternative Design - 24.9 kV line wth source at Chulumani and 300 kW hydroelectric plant near La Asunta. - 30 - Scenlario ILr- Preliminah*StdyDeig of MRY 4.20 The prdemay study of CEY estimates 6,050 consumers in year tWrty and that the projected residential demand will reach 1,500 kW. The study proposes that a threephase line, totalling 118 mns in length and constructed with #2/0 ACSR conductor, wil be adequate to supply the residential loads plus an unspecfied amount of commercial load. A preiminaty cost estimate of US$ 1,293,255 is presented 'he cost, however, does not include single-phase tap lines, secondary lines, meters nor sevice drops required to distribute the electricity to proposed individual users. 4.21 In order to make a comparative study with the alternative scenarios, single-phase tap lines, secondary lines, and meters and service drops are added to the CEY totals. A total of 132 kms of 24.9 kv three-phase and 14A kv single-phas primay distbution lines are estimated to be necessary in each of the scenarios. Quantities of secondary lines, meters and service drops vary among the four scenarios. Required quantides of these items are directly proportional to the number of consumers and total kW demand projected for each of the scenarios. 4.22 The technical team assumes that the CEYprojection of 6,050 residentIal connections, corresponding to a given demand of 1,500 kW, are for year 30. Using criteria similar to that used in studying the alternative scenarios, it is estimated by the team that 2,000 residential consumers with a demand of 225 kW would correspond to year one projections of CEY. 4.23 The CEY load and demand projections do not include specific numbers and values for productve end-uses or commercial or other categories of users. The CRY report states that the proposed line would be capable of supplying 2,500 to 3,000 kVA to the area of La Asunta and that the difference between the residential demand of 1,500 kW and the capacity of the line, or between 1,000 and 1,500 kva, would be available to serve other load. 4.24 In order to make projections of non-residential uses of electricity for the CEY report, it is necessary to project the number of productive end-use consumers and their demands. This is done on a straight percentage basis as compared to projected productive end-uses in the alternative scenarios. Technical team estimates, applied to the CEY study (see Annex 1), are for 404 productive end-use consumers in year 1 with a demand of 394 kW and for 1,344 productive end-use consumers in year 30. This would contribute a demand of 1,376 kW to the system in year 30. 4.25 The total of the residential and productive end-use demands prepared in this manner results in a total estimated demand of 2,886 kW. This is essentialy equal to the total demand referred to by CEY as a design load (2,500 to 3,000 kva). 4.26 Analysis of the CEY report shows that no study of voltage conditions has been made to determine adequacy of the design conductor size to provide satiactory service to its forecasted load. An investigation by the technical team of voltage conditions associated with the thirty year projected load and conductor design presented by CEY shows an excessive voltage loss of 16.2 volts on a 120 volt base (13.5 %). As stated previously, a voltage drop of approxInately 8 volts on a 120 volt base (6.7%) is a generaly accepted value for primary lines on rural distribution systems (see Annex 3). The calladon shows that the large load projected by CEY cannot be adequately served - 31 e over the proposed #2/0 ACSR liaue. Voltage drops and loads are shown on the Plan Map Ia. 4.27 The information presented on Pln Map Ia provides data correspo ding to both the first year and thirtieth year of projected operation. The rectanguar box cosest to locadon 'AW at the lower left comer of the map states the number of rskientia consumes and thek demands, as well as the number of productive use consums and their demands The total number of consumers and the total demand in kW Is also listed. A smail box with leader aurw between locations 'Al and ' shows the type of line to be 3.phas, the conductor size '#2/0 ACSR', and the distane or line lenth 26 km' between the two points A dd box tied Volt Drop B shows the total volts drop at Point 'B' in year thirty and the total distance of Point 'B' from the starting Point 'A". Each major segment of line is snilarly identified and technical information listing consumers, demands, line type, conductor and distanoe are provided. 4.28 A brief summary showing loads and voltage drops along the main line for projected year 30 design load is shomn in Table 4.5: able 4.S: SCENARIO a - VOLT DROP No. of Carers kV Demwd km. to Volt drop Location beyod point total sourc at polnt A 7.394 2,886 0 0 5 S769 2.262 26 8.1 C 3,905 1,451 42 11.9A/ 0 1.713 676 63 14.9 W E 399 168 75 15.9 W F 0 0 91 16.2 A W Calcutated voltae. drops at locatian C, 0, E1 nd F all eceed the generally accepted value of 8 volts drop by swstantial mrginf. Source: issifon assesmnt. 429 As noted, revised demand estimates do not concurwith the high consumer count and load projections presented by CEY. The line design utizing three-phase #2/0 ACSR conductors, inadequate for such high loads, would be entirely adequate if the projected load is less. (Scenario lb examines the CEY line design with the reduced load projections). 4.30 Inclusion of single-phase tap lines, secondary lines, meters and seices neces- samy to serve 6,050 residential consumers and 1,344 productive use consmers results in a total esimated project cost for scenario Ia of US$2,506,250. w The original estiate presented in the In the egneerwianalys for scenrio soand alernse senarios Ib 1 and lL the q y of resdenIl mots and sve drops is amed to equal the number of redeta osmer Th qutity of prodve enduse conetiona s am med to equd 33.3% of all prducve end.use consumems It is asmed tt.7% of producGve use consumer are small, *# coffee pulper., and wM utie mtes and syvice drops uder tho household conn .Eng r costs re calculat acording. For tr of servi meters In the fnancial/economic anals, see Chapter V, Footnote 17. . 320 CEY report, which omitted singe-phs tap li secondaries, meters and srvice drops is USSI,293,2SS. Uni cos presented in Table 4.4 and Annex 3 ar used to develop the cost summa- ty presaeted In Table 4.6: Me A&..s .anAo to- cm$ Primry kine Three-Phase O A*, 115 km 4,000 Sngtle-Phs taP, 0, 14 kn 48,000 teco tlirm, 130 ms 403.000 Netars,serlAcs, 6,498 connections 269,700 Trumformerm, s5,m be 36.00 subtotal $2.005.000 EngIneering nd Adinfstration, is% 300.750 ContIngences, 1io Totat S2,S06,250 IBar: Mission asessment. 4Ative lenari lb, - Emin= ft*ah" of OX with Techn Tea Lad 431 The technical team's thirty year projection of load includes 3,000 resideatial consumers, creating a demad of 547 kW and 672 productive use consumers creating a demand of 400 kW. The total number of consumers is projected to be 3,672 with an associated total demand of 947 kW. This demand and load projecton are applied to the three-phase #2/0 ACSR distr- ibution line design proposd in the CEY report 432 In order to make a comparative study with scenario la, the required singee-phase primary lines, secondary lines, meters and service drops are also included for scenario Do. Tne total length of primary distribution lines remains the same at 132 kms. The quantity of secondary lines, transformers and ser is reduced in accordance with the number of connections and 30 year demand projected by the technical team. Using criteria identical to that used in developing the alternative scenarios, it is projected that residential consumers the first year of operation would total 937 and that the number of productive end-use consumers would be 202. nitial residential demand of 97 kW plus the initial productive end-use demand of 100 kW results in a total year 1 demand of 197 kW. 4.33 A brief smmaty showing loads and voltage drops along the main line for the projected year thiny desig load for altmative senario lb follows in Table 4.7: . 33 - Table 4.7 ALTEATIVE SCEIO lb - VOLT DN No. of coriues kVD hm km. to Volt drop Location bond point total Sourc at pofnt A 3,67% 96? 0 0 a 2,5 740 26 2.7 C 19m3 506 42 3.9 as 26 a 4.9 E 199 5? i 5.3 f 0 0 91 5.3aV I Calculated voltog dps at lotfon F, te point farthest from the source to well withn actod suideline for allolo volteop drop. urces Nission _seesment. 4.34 An investigtion of voltage conditions associated with the thirty year projected load resuted in a low voltage loss of 5.3 volts on a 120 volt base (4A %). This low voltae drop indic- ates that a reduction in conductor size and a change in line type from threephase to single-phase lines might be desireable. A voltage drop of approximately 8 volts on a 120 volt base (6.7 %) is a normally accepted value. 435 The voltage drop calculation is indluded in Annex 3 for reference. Voltage drops and loads for this alternative scenario are also shown on the Plan Map lb. 4.36 The Lne desig utilizing three-phase #2/0 ACSR conductors, inadequate for the high loads projected by CEY, is more than adequate for load projections and demands forecast by the technical team. Alternative Scenarios II and a, which follow below, present the technical team's preliary desin which take ito account different conductor sizes and line tpe to reduce line cost while maintaning satisfactory voltage levels to all projected consumers. 4.37 Cost. Inclusion of single-phase tap lines, secondary lnes, meters and services neces- ar to serve 3,000 residential consumers and 672 productive use consumers results in a total estimated project cost for alternative soenario Ib of USS 1,791,590. 4.38 Unit cost, presented in Table 4.4 and Annex 3, along with the notes associated with unitzed costs, are used to develop the cost summary in Table 4.&8 *34 - tls..h ALTEATIVE SCNRIO IS8 WSCM Piefery line Thre.*Phae 2/0 ACR, 116 ks 944,000 Single-Ph. tps, #4, 14 kw 42,000 Secondary llns, 6.5 km 199,950 eteors, services, 3,224 comctl on3,6OO Al Transformrs, 1,692 kvo MMll subtotal $1,43,270 Engineering ad AdInistration, 1 214,9O Continoees, 105 ILem Totat $1,1,590 j See footnote 16. s3rs: Ni"sin assesmnt. Alterative Soenario IL. - Technical Team Load Projections and PelMna Desi 439 Load projections in scenario It are identical to those used in scenario lb. For cost- savigs, the line design is changed. The technical team's thirty year projctdon of load includes 3,000 residential consumers and 672 productive end-use consumers in the project area. The residential and productive use loads combine for a total demand of 947 kW. Thi demand and load projection is applied to a combined three-phase and single-phase distnbution system. 4.40 In addition, the size of line conductors is varied in proportion to actual load carried. Three-phase #1/0 ACSR is utlized on the main line up to point VC located 42 kms from the source (see Plan Map II). The following 33 kms of line up to Point TE utlize te-phase construction with #4 ACSR conductor. Beyond Point 'E, a single-phase #4 ACSR conductor is used. As the tnsmitted load is reduced, the conductor size is also reduced and the type of consuction is also varied from three-phase to single-phase. This results in a less costy distribution system while maintaining adequate voltage to all consumers on the system. 4A1 In order to make a direct comparisons with the other scenarios, secondary lines, meters and service drops adequate to serve the projected thirty year load are also included in this design. 4.42 A brief summary showing loads and voltage drops along the main line for the projected year thirty design load follows in Table 4.9: a 35 e Igt1l&. i ALTEIATIVE SCENIO II - VOIT NW No. of Conser k Dhowed m. to Volt drop Location beod point total swo at point A 3,672 94? 0 0 8 2,885 740 26 3.2 C 1,953 506 4a 4.6 D 85? 226 63 7.2 199 S? 75 8.3 F 0 0 91 8.9 A Al Caleulated volte drops at tocation F, the point farthest frm the iwc, is slightly abo th deired accepted guidetins for allowable voltao drop. 1m: Nission assessmmt. 4.43 An investition of voltage conditions associated with the tirty year projected load resul in a voltage loss of 8.9 volts on a 120 volt base (7.4 %) at Point F. Voltage drops slightly in exess of the accepted norm wil not affect operation of the stem or connected equipment. This 0.7% excessive voltage drop is wel within the range of voltage able to be corrected with the use of voltage reglators at the source of the line. 4.44 The voltage drop calcuation is included in detail in Annex 3 for reference. Voltage drops and loads for this scenario are also shown on Plan Map II. The quantity of secondary lines, transformers and services are included in accordance with the projected connections and thirty year demands. 4.45 Qmti Inlbusion of seconday lines, meters and services necesasy to serve 3,672 consmers projected in 30 year with a demand of 947 kW restlted in an estiated cost of US$1,346,600. A cost summary for scenario II is presented in Table 4.10: te 4.10s ALTUNTIVW SCEARIO It - COSTS Primry lInns ThrwePae #1/0 ACR, 42 km 294,000 ThreePhsoe 4 ACR, 33 km 165,000 Single-Phase ts, A4, S5 k 171,000 Secondary line, 64.51k 199,9S0 toers, servfe, 3,224 conncto 133.00 / Tranoformrs, 1,892 kv e_ 3.S20 Sibtotal $1,07,2 Engineerno nd Adintstratfon, 15X 161,600 Contfnences, 105 Total $1,346,600 l See footnote 16. am Nission assesment. a36. 4.46 The estiated total project cost for scenario I1 also utizes assumtions Included in the notes asciated with unitized costs included in Annex 3. For technical puposes, the use of voltag regulators at the source end of the project are proposed. lTe proposed voltage replators funetion to correct voltage tions caused either by loads on the line or by voltage excursions experienced In the generation or transion stem suppl* the line. The clusion of voltage regulators wil stabii the voltae supplied to the consumer throughout the length of the line and allow approximatel 25% greater load (1,200 kW total) than projected to be supplied without disce. mable deterioration In servie 4.47 Annex 4 shows a shematic represntation of voge reglator application displaying voltage profile along a line for varying source voltage and line load conditions. It is with this consideration that the basic design of the line is for a peak load of 947 kW peak demand, with capability to supply 1,200 kW without a discernable deteriortion in quality of electic service. The positive effects of voltage regulators on voltage are not included in voltage drops shown on the Plan Maps. Altemative Soenario - Thnical Team l d Projcions ad Atae h i 4.48 Lead projections in Scnario m are identical to those used in SCariO lb and L The predimay line desin is changed and two separte sources of power are utilized. In addition to grid extension from the exitng power source at Chulumani, supplying aroxmate one-half of the valley, a 300 kW hydropower plant is proposed near the town of La Asunta to serve an isolated sstem 4.49 The technial team's year 30 projection of load includes 3,000 residential consumers and 672 productive use consumers in the project area. ITe combined residential and commercial total demand with the dual systems is esimated to slighty exceed 947 kW due to the tecnical desg Actual projected loads are divided between the two systems as displayed in Table 4.11: Lab&4 4.11 ALTNTIVE SCENARIO III COSINED SYSTU ChUltML ton La AsUwta Plant Re1dutfal Conrs 2,064 936 Prodaottve use Conomrs Z i Total 2,526 Ill6 besIdtfat Demand, kW 37 173 Proittw un Demad. kW m in Total 654 A 310 A #I SW of the dume for the 2 systm is slightly peter than the dman 1n Snarifs lb nd It de to dol sytom design. go= Nissfon assessamnt. .37 - 4.50 In compliance with good engineeing practice, the sie of line conductors b vaied to take advantage of economics nnected with of smaller condcor lines In addition, the number of phases is vaied to reduce cost where load and asociated voltage drop would alow. A bief summary showing loads and voltage drops along the main ina for the projected year thirty design load follows in Table 4.12. The voltap drop calculation is included in Annex 3 for reference. Voltae drop and loads are also sown an Pla Map m3L X*La.si12 ALTlrKi SCEWRIO III - WIt KW i No. of Co_asmr kV Du.d km. to Volt drop Locatton beynd point total soup" at point 5ml ra. ChuIMMI A 2.526 654 0 0 a 1,736 469 26 4.S C 807 213 42 6.2 0 0 0 63 6.9 Sm.Y fran Ptait at La Aamta 5 1.146 310 0 0 b 171 49 12 0.9 D1 0 0 20 1.2 - 0 0 16 0.6 9/ Calcutetod volttge drope at all locatio are within th accepted guidelines for allowable voltta drop. am: Niasson assmm. 4.51 In order to make a comparative sudy with the other alternative scenarios, secondaty lnes, metes and sevice drops adequate to serve the projected drty year load are illuded in the desig The quantity of secondary lines, ormers and services are included in accordance with the projected comnections and year 30 projected demand. 4.52 Due to the reduced power carg requirement of individual line sections inherent to baving two different supWy points on the sstem, conductor sizes and length of thr hase lines is reduced. Singe-phase lines are adequate to provide satisfactory power to alarge portion of the sem. The total length of tee-phase line in this searo is 63 kms and all lines are consuced with #4 ACSR conducto. 4.53 Q& Inclusion of secondary lines, mets and services necessy to serve 3,674 consumers prqected in thirt yeas reults in an eimated cost of US $ 1,979,590. Unit costs presented in Table 4.4, are used to develop the cost smmary presented in Table 4.13. 0 38 - ~~~~.38 X*L9_.&tal ALTERMTIVW SCENAIO 111 - COSTS Primry lines Three-Phae A4 ACSR, 63 km 315,000 SingLepht e 84 Atp069 km 207,000 Secondary ltne, 64.5 bk 199,950 Nters, ervices, 3,2264 coections 133,800 IV Tranform, 1,892 kva 113,520 NdroLectric Plant, 300 kV 600W000 Sutott 31,569.27 Engineering nd Administration, 152 253,390 Contingencies, 102 12fl.M Total 11,979.S90 V See footnote 16. surce: Nfsuion assessmmt. 454 From an engneering Perspective, the addition of voltage regulators at the Chulumani source end of the project would be recommended. The proposed voltage regulators function to correct for voltage variations caused either by loads on the line or by voltage excursions eperienced in the generation or tra on stem supplying the line. The iusion of voltage regulators will stabilize the voltge supplied to the consumer throughout the length of the line and allow up to 25% greater load than projected to be supplied without discernable deterioration in service. Voltage regulators are not required at the La Asunta generating plant as the generators themselves can be used to regulate voltage durig periods of peak loads. 455 As noted Annex 4 is a schematic digram showing voltae profie along a line for vayng source voltage and line load conditions and the effect of voltage regulation on voltage levels supplied to consumers. AditionlAttemative Soenadio 4.56 Tlhe tecal analysi investigated other possle methods of provimng electric sevice to the area. Basicaly, these additional alternatives called for eliminating the connection to the eisting grid and supplying all and partal load with seffsuficient hydroelectric plants. Scenario IV outlined the istalation of small hydower sytm (1.2 MW) and scenario V the insaltion of a mini-ydro unit (300KW) near one key load center. Prdenay costs for these developments were projected as US$4.2 million and US$604,000, respectively. 457 The primy reasons for Apr8aps eliinating the scenarios from further development are financial, as well as strategic Scenario IV was eliminated due to high costs, Le, US $42 million compared to the grid exesion scenarios shows this to be an cessive high cost alternative. In additon this estimated amount does not include institutional and technical costs required for maintenane, operation and adinistrtion of a decenalid ystem Scenario V. was ruled out due to limited grid coverage that would be provided in the project zone (18% of demand) as AgryunWs planning interests are focused on ambmjigcj immg for the project area. - 39 - osite Cmprison of Scenario 4.58 Table 4.14 presents a summaty comparison of the technical scenarPos for which load and costs have been presented: takle 4.4: SUYMARY COWPARISON OF ALTERNATIVES la, tb, tl, AND III I/ I eu I a l1 ILL Number of Consumers 7,384 3,674 3,674 3,674 Peak Demand, kW 2,886 946 946 946 Primary Distribution line, kmn 132 132 132 132 Secondary Line, kim 130 64.5 64.5 64.5 Meters and Services b/ 6,498 3,224 3,224 3,244 Transformer Capacity, kwa 5,7M 1,092 1892 1,892 Generating plant, kV 0 0 0 300 Construction Cost $2,005,000 1,433,270 1,077,270 1,569,270 Engineering and Administration, 15% 300,750 214,990 161,600 253,390 Contingencies, 10X 200.00 1U.330 107.73 156.930 Total Cost $2,506,250 1,791,590 1,346,600 1,979,590 8/ For each of the alternatives presented, there are 132 kilometers of primary three-phase or single phase lines. Differences in cost result from varying the typ, of line or size of conductor. k/ See footnote 16. Source: Mission assessment. 4.59 stCost Scenano for C=rhwsa Grd Covera. On the basis of technical and cost parameters invesited, scenario II would represent a least-cost senario for m=rehensive ua Sard coverage. Gven projected demand, initial year funding requirements from the engineering perspective are estimated in Table 4.15: ITable 4.15: FIRST YEAR FUNDING REJUIRRNENTS-ALTERNATIVE - SCENARIO II Primary Lines, 132 km, 630,000 j/ Secondary Lines, 32 kms 99,200 IV Neters and Services, 1,004 41,600 S/ Transformers, 946 kvt ILa I Sibtotal 827,560 Engineering and Administration, 15% 124,130 Contingencies, 10% 82,760 Total $1,034,450 A/ It is proposed to initfally construct 100% (132 kam) of the ultimately required primary distribution line. kb It Is proposed to inftially construct 50% (32 km.) of the ultimately required 64.5 km of distribution Line. I/ Initfal projectlons require srvfes for 1,004 metered cons4mers In the flrst year of operation. (937 residential, 67 productive end-use). g, It Is estimated that SOX (946 kva) of the ultimately requIred transformer capacity (1,892 kwa) is required to reach the initially connected consumers. g/ Figures are estfmeted and could vary according to actual design execution In year 1. sgrae: Mission assesseant. -40. V. FINANCIALECONOMIC EVALUATION MilladlEcnMMic Vjabflt gf Grid Seenaro Overview 5.1 This chapter preents information necessary for, and the results of, the financial and economic evaluation of the four scenarios previously disssed. Key data such as the number of consumers by type, enerag use levels, and cost of construction have been presented in previous chapters A brief summaty of the analytial methodology is presented here, as well as a discussion of inputs and results. Annex 9 includes a detailed disussion of the evaluation methodolog. 52 Mgdjjug. The DAM rural electrification planning modeL working with field-based data on residential and productive-end-we demand, is used for the financial and economic evaluations With the demand data and cost input, the model calculates both finanial and economic costs and benefits by year associated with each scenario considerecL The resuts presented are Net Present Value (NPV) and the Benefit/Cost (B/C) ratios for the life of the proposed project The model is also used to calculate the Economic Rate of Return on investment but only for demand scenario II, as this wenario represents the least-cost scenario f E iancial Ana"i 53 The financa analyis presented views costs and benefits strcly from the ditribution utility's point-of-view, La what wouid the proposed project cost the utility (up-front oonstruction plus wholesale power cost and operation and maintenance costs) vers what are the revenues that wi:l be generated (tarMtimes the kWh consmpton for residential and productive end-users). The financial analysis reflects the project viability if the utility were paying the full cost of the project Eonmic Ana3mi 5.4 The model's economic analys ansiders costs and benefits on a more macro scale than the financi analys The primary difference is in consideration of benefits. As descrI,ed in Annex 9, the economic analysi considers benefits other than tarff revenue brought about by the introduction of electricit. Such benefits include: (a) Residental cones' tariffpayments plus an estimate of cost savings and consmer surplu8 (b) Actual energyrelated cost savi + naused productivity + increased electricity- induced quality effects for Oexsting productive uses; and (c) Wlinness to pay for electric and related expenditures in the case of new productive end-use activ (see Annex 9). -41- 5S5 Foredg inputs are priced in order proesa and domestic inputs are convted at the ehane rate of Bs. 3 per USS. (The sadov3 rate used in the analysis equals the market rate in Boli"ia). 1h estimated lorun ma a cost of electriciy is used for the cost side of the economic analysis. 5.6 In addition to specific cos and benefit inputs, key parameters used in the analysis are as foows: I= of For NPV and B/C anabes, a teem of project is defined to allow present value calcuations. Based on desgn criteria for the line, a 30-year term is used in all calculations. Discunt Rate. A real discount rate of 12 percent is used in all analyses, based on the esiated oormunity cost of capitaL Producti a a. 'e hviabillty of the scenarios b, and m has been ana*zed using the Vrobable" and 'optimis sienaros for growth in productive end-use activities (see Capter U). Enr= Usxe LeL Residential energy use is a ted at 15 kWh/month for year 1 and 40 kWh/month in year 30. Energy use level for individual producive use activities are outlned in Cap M Table 3.6. lariff The exsng CEY tarff is adjusted for this analysi In light of CEY's current request for a rate increase, a tiff with a similar structure but 20% increase is used in the alyse (see Annex 7, Tariff BOLl). First yea monthly residential cost for 15 kWh are therefore estmted at US$236. Tarff rwenue fom commercial sales to productive end-users of electriity are calated on the basis of projected kWh consumption and application of CEY's exsting commercial tariff sucture with no inrea (see An 7, Tariff BOL2). Street lighting is billed at $3333/month per 100 conumerm 5.7 Cost categories are as folws: Consuuction Gat&l7he cont on cost applied to each scenario are based on the cost presented in the engineering section of this rport. In the case of secondary line costs, hoever, the fncia/economic analysi asmes that 20 percent of these cost wil oocur after inital c thereby creating a smal difference between the construion costs presented in the technical secion and the ki JuLaln9oNJk a1 used in the financial-economic analysis. Also the cost of meters and services are alted throughout the life.ofproject based on number of new consumers per year. -42 . Addg Cnum Connec4 An additional cost of US$4150 is calclated for new consumer whkh represents the cost of connection. w2 QfgnEM. The lontrun marginal costs of electricity (US$0.055/kWh for year 1, US$0.47 kWh for year 30) was derived from World Bank sources w The wholesale cost of power to the utit is based on present wholesale power cuntact figures for CEY from COBEE (US$0.0201/kWh). =Oprtio and Mai c Thes costs as presented in the model are estimated on a per-kilometer of line bass (US$20.00/month) and a per-consumer basis (US$.75/month). IAnDMMu andDlrllian1M. losses are estimated at 12% technical and 3% non-technical for the model analysi Financial eknefit 5.8 The only financial benefits considered in the analysi are revenue from tariff (kWh/month times the appropriate rate stucture for residential, pmductive use, and street lighting consumers) along with an initial, one-time connect fee of $100/consumer as is presently ClEYs policy. Eooi Benfit 5.9 Economic benefit from residential electricity use is estimated as savings in current, non-electric lighting costs (weighted average of LPO, candles and kerosene) minus cost of equivalent electric l*ghtlng plus electrciy taiff payments, plus an estimate of consumer surplus, suming the eistence of a 'demand for lighting services" function (see Annex 4). Lighting cost savingp are estimated at US$438 per consumer, per month. Consumer surplus is US$3.81 per consumer, per month. Tariff is US$235 per consmer per month for year 1, induding pubic lighting charges, and US$331 for year 30. Total economic benefits from eectricity sales to the residential sector are calcuated as US$10.34 per conumer per month for year 1 and US$1150 per consumer per month for year 30. WI For modeling purposes in the 4 to equa th eimatd nmb of OreideAl onectis whi all prodve eaduse av M been coi as A Mfte WdIe th tot amount of sod rMans th same, in th financihl- ecoonomic anali thds iY_ bis upwad apa coo for c l but at the sam tm revenuos fom oonncmo a are aad Te sum differenc hower is ea in Senado =& the anas coslddws 1,004 connetios wih a cost of S41.600 year 1. lw _c oddol-Jc connecdto co of 547,265 year 1. in addon, th onSc anls a ommerial tardff sucure is lWd to a produt endusss while numerous uss would be ran under a rddial conon. is has th eat of a t downwd bia Ienue given th a o of a lower ommeral rte stc 9 13PBAAP Report 'aBu for the Fomation of a Natonl Eher Pln*, November 1967. .43. 5.10 Economic benefit from sale of eleticity to existing productive end-users currently using alternative energ sources (see Chapter m, Tables 3.6) is estimated based upon the methodology used by NRECA in Central Amiierica w reflecting energ savings, production increases and/or increased product quality (see Annex 9). Extensive field interviewing of entrepreneurs in the Yungas region, both within and outside the project area, was carried out in order to gather needed information. 5.11 Economic benefit related to new (presently non-edstent) productive end-uses i estimated simply as the wiUlingness to pay for the electric service, based on projected energy use levels and the commercial tariff (see Chapter m, Table 3.6 for benefit summay). 5.12 Economic benefit from street lighting is estinated based on wiingnes to pay criteria, i.e. US$33.00/month per 100 consumers. 5.13 The results of the analysis based on the model calcuations are presented on Table 5.1: TIl&e 5.1: FIMANCIAL-ECOUGUC RESULTS PR08SL Financial Financial Economc Econormic Internal Scenario Net Present B/C WPV B/C Rate of Value (NPV) Return us$ us$ Scenario IA. 5/ -1,252,124 0.63 1,967,890 1.43 Scenario 18. -1,419,401 0.37 233,768 1.09 Alternative Scenario 11 *974,401 0.46 678,768 1.31 17.8X Alternative Scenario III 1,549.14S 0.35 27n.199 1.10 S/ For modelling purposes in the financial-economic analysis, since CMY did not specifically sub-divide residential and productive and-use demand, 56 kh/=month is utilized for residtfntal consumpion, and 140 kUhImonth for protuctive end uses. In this manmer, the analysis arrives at the total kwh sales per month projected by CEY. The enogneering analysis for scenrio IA projected 28 kWh/onth residential and 281 bIb/month productive use to arrive at total demand projected by CEY). According to the field-basad estimates, however, CMY projections are virtually ifqxssible in nurber of consumers and etaggerated in eneroy consmptlon levels. Thus, the high economic benefits presented are overly optimistic. Source: Mission assessment. NRECA/US D: Ce tad Ame sa Rual Elecnficaton Proect,An Eonomic of Eecic in Producti,e Use Actives in Rural Guatema," 1989. .44 - Model Results Under "Optimti Growh 5.14 The woptimistic" scenario for productive use growth was developed by allowing the number of productive end-use enterprises to grow at a general rate of 10% per year. The starting number of productive end-use activities is taken to the equal to that of the "probable" swenario (except in the case of coffee pulpers and a welding shop) as presented in Chapter m, Table 3.7. By allowing the number of productive end-use activities to grow at a higher rate, financial and economic benefits are enhanced under al options. ( No "optimis growth scenario was developed for scenario IA as the CEY study presents an over optimistic demand). Tabte 5.2: FINANCIAL-ECOONIC RESULTS - OPTINISTIC Financial Financial Economic Economic Internat Scenario Net Prosent B/C NPV B/C Rate of Value (NPV) Return US$ USS Scenario 18 -1,274,737 0.46 708,663 1.25 Alternative Scenario II -829,737 0.57 1,153,663 1.67 21.X Alternative scenario III -1,357,178 0.44 866,702 1.32 -curce: Nission assessment. Observations 5.15 As noted, no scenario is financialy viable under the 'probable" or "optimisE scenario, assuming the utility has to bear the entire construction cost. In alternative scenario II, to break-even financially the project would require a donation of approimately US$.97 million under the "probable" scenario and US$.82 under the "optmistic' productive use scenario. 5.16 As shown for alternative II (probable and optimistic), promotion of productive end- uses enhances the project's viability. Development and application of a rational tariff regime at the project specific level would also help augment the financial viability of the project. While the study does not carry out a specific tariff anawys it is evident that the reta tarif strucure applied to the project (even with the 20% increase) is below marginal cost. The marlinal cost for bulk sales to the dtribution entity for year 1 are estimated at US$0.055 kWh, while the retail residential and productive use tariffs are US$.052 and .043, (above 25 kWh and 50 kWh respectivel). 5.17 Using the "probable" growth cases for comparison, one notes that scenario II has the greatest economic net present value-xcluding scenario Ia with its omeated number of projected consumers and demand. . 45 . 5.18 Economic benefit under scenario II b roughly bween US$.68 1.15 mmion In net present value tems, depending on the productive end-us scenario chosen, Le. probable or optimstic 5.19 While financa viability i not acdeve undr the scenarios a presented, the Input of increased tarffs In the model allow for a prelimia view of the peocntage ine that would be requred to cover the project's total cost, e. B/C = 1.00, using senaro 1 and probable demand. For financial viability, a taff incrase of apprme 10 175% over the present average rate would be necesary. a46 . VL INSTUTIONAL ASPES Overview 6.1 This dhapter discsses the insional framework for rural grid etension in the project zone. Due to the planning objectives of Agroyungas to provide comprehensive coverage, the most immediate arrangement to achieve this objective woud be to exed the service area of the exsting rnual cooperative of the Yungas, CEY, to indlude the project zone. Also, the preiminr study shows that for m hse a decentralized system (hydropower) vastly exeeds the cost of grid extension (US$42 million vs. US$13 milLion). This involvement of CEY would infer CEY's operation, management and maintenance of the proposed line. To assure the institutional viability of this option however-in addition to tariff adjustnents and the formalized promotion of productive end-uses to augme..i financial viability-administrative and technical assistance would be required for CEY as part of the overall project. A prelininary overview of CEY follows, along with an outline of the enhanced instutional asistance that would be required. 6.2 Headquartered in Coroico, and formed in the late 1970's, CEY currently serves some 4,000 consumers in the Yungas in the main towns of Coroico, Coripata and Irupana, as weU as the small villages surrounding Irupana and a commercial district in Chulumani (see Annex 12). 63 Average total consumption for CEYrs consumers is 38 kWh per consumer, per month. The residential average is 30 kWh per consumer, per month. Commercial categories and consumption are broken down accordingl: General 1 (commercial - less than 10 kW) with 151 kWh per consumer, per month; and General 2 (commercial - 10 kW or more) with 320 kWh per consumer, per month (4 consumers only). Industrl users average 780 kWh per consumers. per month (5 consumers only). Many of the small business enterprises in the CEY service area are home-based and are therefore billed at the residential rate dass, although a large percentage of the use is commercial. Strictly residential use in outlying rural areas is in the range of 15-20 kWh per consumer, per month. Public lighting averages 1,000 kWh per community (24 villages). Referring to all General and Industrial accounts as productive end-uses, some 20% of total system revenues are generated by these categories, yet represent 5% of all consumers. Load Promotion 6.4 Productive uses of electricity are not actively promoted by CEY but the financial benefits of such loads are well recognized. Based upon technical team interviews, the attitude in the Cooperative prevais that since the basic system is installed, load development would allow for enhanced returns. 6.5 The Cooperative By-Laws provide for a Commercial Department with responsibility for productive uses and residential load marketing programs. However, there is only limited .47 . activity in this area at present. The Department b equpped with an Apple Macintosh computer through which all billing and consumer reques are processed. (Such data access would greatly faciitate evaluation of market demand and energy use patterns, and could thereby assisting in the development of an effective productive end-uses program). 6.6 A 'Comite de Educacion was recently formed at the initiative of new Board members to promote commercial uses of electy. The committee is composd of volunteers, mostly Board members, who are tying to win approval for an operating budget of 5% of gross revenues to support promotion activities. The 8Comite" membes interviewed realize that this I an insufficient amount to adequately serve the need. The followig isues were also oudined during interviews: (a) connect policy is cumbersome ie., new members must go to La Paz and buy their own meter, and costly, (b) service must be improved in some areas ie. reduced outage time; (c) new markets must be found for end products; and (d) credit for initial investment in productive use equipment b not presently available. Line Extension Financin 6.7 Line extensions from the Cooperative are typically financed by 50% up-front communit contribution and 50% from Cooperative funds, if and when available. The community contribution usualy comes from the regional development corporation CORDEPAZ which is augmented by some direct community collection. Matching Cooperative funds are often not available and, consequently, several projects with approved CORDEPAZ/community funding are pending. 6.8 As noted, members requesting new service are required to purchase their own meter (available only in La Paz) as well as pay for other service entrance equipment (often looking to the regional development corporation for support). Total costs are approximately BsS 300x400, including internal house wiring which accounts for Bs$ 50-60. Service requests are typically held by the Cooperative until 2 or 3 accumulate in an area before the Commercial Department authorizes a lineman to travel to the area to connect. This is due primarily to limited staff and the diffcult travel to many parts of the service territory. 6.9 Serie Area Extension, Recently, CEY has taken-over service in the central commercial ditrct in Chulumani, which is presently served by a smaller distibution entity Cooperativa Electrica de Chulumani (CEC) which possess its own mini-hydropower generation system. This act was in response to commercial enterprises seeking a more reliable source of energy, even at a higher price. ( As asessed by the technical team, a typical commercial enterprise in Chulumani pays approimately Bs$ 45.00 for 300 kWh under CEY tari, while the smaller cooperative CEC charges about Bs $27.00 for the same energy). .48. xtension in the Project Area 6.10 The technical team considers that the most appropriate institutional administration of the rural grid extension in the project area (given Agroyungas priorities in onrehen,siv S extension) would be through CEY. This assumes however that the financial viability of the project would be enhanced via tariff study and reform and a vigorous and institutionalized promotion of productive end-uses in the project area on the part of Agroyungas and CEY. As noted in Chapter IL, CEY currently purchases power from COBEE through the lines of ENDE and distrbutes power through its rural grid nearby the project area. Proximity to, years of operation nearby and familiarity with the project area leaves CEY as the most appropriate entity for distribution in the Project zone. 6.11 CEY's 4,000 consumers have been added in time to the basic system. Since its formation, however, the cooperative has received limited technical or institutional assistance. In addition to the fnancial burden imposed by the project (under the current tariff structure and projected demand it represents a financial loss) the incorporation of the Asunta valley service area and 132 kms of grid and 1,004 additional connections (937 residential and 67 productive end-use) in year 1 would be a large addition for CEY in terms of management, operation and maintenance. For the longevity of the institution and assured operation and maintenance of the proposed grid extension, a comprehensive institutional analysis of CE'Y would be recommended. The objectives of this assessment would be to be to analyze the current financial situation and administrative procedures, as well as the technical capabilities of CEY to administer the proposed grid extension. The goal would be to incorporate an administrative and technical assmistance program to CEY as part of the Agroyungas project, as well as a clear definition of an appropriate tariff structure. 6.12 In a preliminary assessment by the technical team, the following areas were pointed out for follow-up: (a) The Cooperative's admiistration should place more emphasis on business administration and less time on engineering problems, which could be handled more efficiently by trained national engineers or consultants; (b) The Cooperative administration needs to establish written procedural manuals and policies for customer services, employee job descriptions, and operation and maintenance procedures; (c) The operational division should implement a systematic preventative line maintenance program. Likewise a program to maintain line equipment should be established. The quality of materials used in line construction should also be improved. To accomplish this, CEY should adopt internationally accepted material specifications, based on a 25.30 year useful life; (d) CEY's epnsion policy should focus on "backfill,' that is, connecting those consumers under the existing lines. A productive use/consumer services department * 49- should be created if the project is implemented. Along these same lines, consumer credit programs should be developed for housewiring and productive uses; and (e) CEY should prepare comprehensive annual workplans and long-range workplans. Administrative and Technical Assistance Requirement 6.13 To fulfill the goals outlined above and manage the institutional dynamics of an enhanced service area, the following training and institutional support should be implemented simultaneously with any project infrastructure component: Management Training. CEY requires training at all managerial levels of the electrical distribution sector. Management training for maintaining and utilizing improved accounting and operational procedures would be needed in order to integrate the entire system into a cohesive distribution network. Specialized training in utility programming and planning in connection with computer-based management software would also be required. In addition, assistance will be required in the organization and staff training of the consumer services department. Specialized training in productive use equipment promotion, credit services, and consumer relations is paramount to the viability of any follow-up project Technical raining. Technical training should focus on the development of skill improvement courses for the electrical technicians. Test equipment and specialized workshop tool purchases could be included in this component. Specialized training courses would be required to improve equipment maintenance costs and consumer equipment records. Operations Strengthening. A standardized accounting system should be instituted, together with new management control standards and procedures In addition, a standardized workorder procedure and inventorying system must be instituted. Computer equipment and standardized software would be required to improve inventory controL establish and maintain property records, and reorganize consumer, commercial and billing records. Additional Line Maintenance Equiment. This would have to be procured to install, maintain, and service new consumers in the region. Enough equipment would have to be purchased to serve the needs of CEY for five years of operation. *so - VIL CONCLUSIONS AND RECOMENDATIONS 7.1 Application of the DAM model to establish the financial-eonomic viability of the scenarios shows that no scenario Is financialy viable, despie a least-cost approach design Tli is the case under both the "probable" and "optimistic dmad growth sceno as developed by the technical team. In contrast, and ruling out scenaro IA due to over optimistic estimates for consumers and kW demand, all alternative scenarios are viable in economic terms. In partiuar, scenario H (as the least-cost option for aarcwm=C mad g .aiga) shows an economic benefit of between US$.69 million in net present value terms for the probable gowth scenario, and approximately US$1.15 million for the optimistic growth sconario. lhe intenal rate of return for the scenario II is alculated at 17.8% (probable) and 21% (aptmistic). 7.2 The absence of financial viability, considering the investment from the perspective of the rural distribution entity CEY, denotes a negative financial burden on the institution. In sum, the financial viability of the project would have to be increased in order to ensure the institutional viability of CEY. Two complementary methods to augment the financial viability would be: (a) The development and application of a rational tariff regime for CEY that would allow CEY to develop and apply tariffs that cover marginal costs; and (b) The development and application of an institutionalized promotion of productive end-uses in the project .,ne on the part of Agroyungas and CEY. (In particular, the program would have to focus on industry and agro-industrial development in the project zone in order to build load and enhance the return on the project investment). In light of these needs, a detailed institutional evaluation of CEY (including a turiff review and the outline of a formal program for promoting productive end uses) should be included as an initial component in any project follow-up. Developed in tandem, points (i) and (ii) outlined above would be cucial for enhancing project viability and, in the long-tern, guarnteeing the institutional viability of the grid extension and CEY. For the outline of a productive end-use program see Annex 11. Rura Electrifilcation 73 Rural electrification, as noted in Chapter I, has generally received a low priority in energ planning and investment in Bolivia. In most cases, projects lack a methodological evaluation of rural electricity demand and, in turn, a realistic assessment of a project's viability . As demonstrated, projects generaly display an overly optimistic assessment of financial-economic or institutonal viability. As shown in the analsis, and working with a field-based demand evaluation, -51- the proct n plated by UNFDAC Is difficult to just In stri financial terma However, the project demoat posiive economic beneft In this rWerd, projeca planners, working In coordination with the appropriate GOB authorities, should fcus on the development of points (i) and (ii) outlined above. 7A In terms of a cas study for the Nationa Plnnin group within the MSH, the analysis would arge for a more accurate assessment of nural electricity demand based at the village-unit level For the presented anasis, this has taken pla with te asstc of the DAM planning modeL More acurate demand work allows for a prioritization of rural electrification projects based upon a more realistic measure of their financial-economic and instutional viability. 7.5 Tle study alo point out that the viat of rura grid tems (centrizd or decentralied) can be augmented if productive end-use load can be strengthened and developed. In the case of the Yungas, those activities that would build load, i.e. agroindustries, are shown. A formalized promotion of productive end-usesncorporated as a project ponent also holds the potential for complementing rural development activities. Such a component would infer inter- ititutional coordination, including MEH MACA as well as the executing agency and/or donors. CalulatinsgRural Dmd 7.6 The need for-and results of-a field-based evaluation are evident. The estimates developed by the technical team are markedly diferent from those presented to Aryungs in the CEY report (65% reduced kW demand, and 50% reduction in residential and productive use consmers). Based upon more accurate edsting and prospective demand estimates and input, a more appropriate tem can be designed and the financial-economic viability of the project ealculated. 7.7 Demand is idealy quantified at the vilage levl and growth estfimates projected on community characteristc In the cases of residential and productive use demand, the technical valuation held to medium range growth estimates (4% growth in residential connections and between 4 and 5% aggete growth in productive end-uses per year). This is based upon £eld assessment In the project zone and observed acities in electrified regions outside the project zone. In sum, demand esmates (see Chapter ImI Table 3.9) show a relatively limited demand-198 kW demand in year 1, and 947 kW demand year 30 in 'probable growth, and 243 kW in year I and 1,313 year 30 under the 'optimistic growth' scenario. 7.8 Liraited Dnd and A ate tm Dewelpment The limited demand gave rise to the development on the pat of the technical team of alternative scenario V. Scenario V calls for the development of 300 kW mini-hydropower site and a loclzed grid in one site, constituting a xmately 18% of estinated demand in the project zone. The alternative was not developed due to planning interess in - m1 shIn d.nrmgu. n comparison to this option, however, edimat at approximately US$ 604,000 (without the cost of the insdtutional development requred for a decentralied system) the tchnical grid tension design of smiario II (at US$ 13 milion) renders omprehensive grid coverage in the project zone and allows for projected system 52 - growth without izeable capital invements tbru year 30. At the prefeasbw level, the alterative for grid-extension, as opposed to schemes for renewable generation and loclized grids, would appear to be the most cost-effective solution for grid coverae as well as ytem growth 7.9 Based uponi project planning priority in eMonmive sd coeage, alternative scenario II refiects design changes on the ornal CEY stem that result in lower cos" while e ig ystem integrity and reliabilit. Both voage drop and stem pgwth are accounted for in the desi as presented. The basic dep of the lineis for a load of 947 kW peak demand, but maintains a pabiity to supply 1,200 kW without a discernaMe deterioradon in quality of electric service. The estimated cost for this seario is USS 13 million (including egineein administration and contingencies). Initial funding reIements, based upon the engieering estimate, are in the range of US$1.03 milion. 7.10 The development of the field-based demand assessment, ooupled with the design of a technicaloption for rid coverage, allows for the application of the DAM model and, in turn, a view of the financial-economic viability of the various scenarios. The field asesment demonstates that the key obstacle to project viability is the current limited demand for electicity in zone. 7.11 As noted, no scenario is viable in financial term. The financial viabty, based upon naro II (as the least-cost comprehensive grid option), is sightly increased under the optimitc demand growth scenario. Under both scenarios, however, the project shows positive economic benefts (Ecnomic NPV of US$678,768 "probable and US$1,153,663 "optimistie). Ihe objective of augmenting financial vbiit could be accomplished with the application of both tar reform and the development and applicaon of an instutionalied progam of promoting productive end-uses. The latter point would imply a coordinated effort with roles for UNFDAC, CRY, MACA, as well as the regional development corporation, CORDEPA7. Table 3.6 displays the profile of rural agro-indusries that could complement development efforts in the Asunta valey and which are well suited to the natural resource base in the area. 7.12 Based on model runs, of a reta tariff that would cover the project's total cost, ie. B/C = 1.00 reveals that the necessay inreasewould be in the order of l50 - 175% over the present rate. Thbis would refer to scenario II under the "probable demand growth. 7.13 The rural cooperative CEY has received liited technical or administrative assistance since its creation in the 1960's. The inclusion of the Asunta Valley seicearea represents a relativelyrge addition. As a project component, CEY would be best served with an Indepth institudonal analysis, the objecteve of which would be to assess the financial and admInIstraive assistance necessary to ensue the financial and Institutional viability of any project folow-up as wel as CRY. (The technical and administrative welare of CEY has a direct bearing on the suc:ess of any project folow-up on the part of UNFDAC). In addition to a taiff review, a sudy would focus on the administrative, maintnance and operation procdures and standards. .53 - The isituional viiit of CEY is also a key cowmponent to the success of an oranized program In the promotion of productive end-uses. PQoli Considerations 7.14 Since there is reason to believe that the Agroyunga Project is firly representative of rural elecrfication projects in Bolia with rgrd to its costs and its benefits, some wider polfy lessons can be drawn from it. 7.15 On the cost L a key lesson from the piot project b that aipenditures on proper pre-feasibit work are more than justified in tem of resuting cost saviap on plnt investments: The investment in the prefoasility study was less tan USS 50,000, the Idetified Cost savin amounted to over US$ 1 million. 7.16 About 60% of the cost s were caused by a lowering of the demand estiate, the remaini 40% resulted from a switch to a lower cost design lhus, a complementary condiusion is that a carefu anlysi of demand is at least as important in promoting cost savings as the work on the technical identifiation of leas cost desigs 7.17 On the benefit side, the key lesson is that the economic rate of return of the project is cruciay dependent on the possiflity of attracting the lowest income consumers. The first year ecnomic benefit of electrification derived from the replacement of candle consumption is more than twice as high as the benefit from kerosene replacement and more than six times as high as the benefit from LPG sbsiution. Presently, the cost to the household of connecting to CErs distribution line is apprSiately U$ 100. In the absence of grants or loans for low-income households for the connection costs, only a very low percentage of candle consuming households wi be able to conne to the distruion network. In that case, the economic benefit from household coonsmption would be about 40% lower than esimated in the rate-of-retun calculation in the report. 7.18 The case for loan financing of connections is reinforced by a second conclusion from the field work: The monthly bill for lighting services is much higher for candle and for kerosene consumers than for electricity cosu a The former pay about USS 6 a month for lighting serices, electricity conmers US$ 2.50, alough the latters' conumpton of ligng services is much higher. The welfare implications from this situation are evident But for the project authorities, the financal implications a equaly interestng: Low income consumers can afford to pay about US$ 3.50 per month in amortizton on connection costs -54- ANNEX-1 Page 1 of 10 LOAD PROJECrIONS Load No. of Demand KWJMIO kWh/NO/Cons Factor Consumers (KW) TOTAL Technical Team Estimates Residential Load YEAR1 15 0.2 937 97 14,000 YEAR 30 40 0.3 3,000 546 120,000 PROUCTIVE USE YEAR 1 141 0.40 202 100 28,500 YEAR 30 203 0.47 672 400 136,500 TOTAL DENAND. YEAR 30 946 KW CEY EPRfFtT WAT .ESSUETIAL LOW YEAR 1 28 A/ 0.34 2,000 225 56,000 YEAR 30 75 0.41 6,050 1.510 454,000 PROWUCTIYE U YEAR 1 281 a/ 0.40 404 394 113,500 YEAR 30 381 0.51 1.344 1,376 512,000 TOTAL DEMAND. YEAR 30 L2.8 KU p1 For the financial-economic analysis, kWh per month for residential users of 56 kWh and 140 kWh productive use is used in the DAN model. This results in the total kWh demand projected by CEY. fSore: Nission assessment. - 55 - ANNEX I Page 2 of 10 DEMAND TABLES ESNAP PROJECTIONS Table kWh/month/consumer Load F1E&or Residential, year 1 Is 0.20 Residential, year 30 40 0.30 Coiurcial, year 1 141 0.40 Comercial, year 30 203 0.47 CEY PROJECTIONS g/ Table kWh/month/consumer Loafactor Residential, year 1 b/ 28 0.34 Residential, year 30 75 0.41 Coffuercial, year 1 281 0.40 Ceumercial, year 30 381 0.51 t, Peak load projections presented in the CEY report for residential use were converted by the technical team to kWh/Ionth/consumer and load factor values utilizing consistent criteria for all scenarios studied. k/ The orfignal CEY report presented data for long-range residential use only. First year residential loads, all productive use loads, kWh usaoe and demands were also estimated for the engineering analysis using consistent criteria for all scenarios studied. sourcg: Nission assessment. - 56 - Page 3 of 10 TAEt I - ESH4P ProJections - Rsidential UW Yea 1 MM ?TAIL 15s KMI/INQTKCONSUN LF a 0.20 REA * 0.31 (1500 cofhsurs) Special --- 937 96.6 NO.CNS. n KM D NO.CGNS. kV DEMAN NO.CONS. KM OEA I 043 55 6.4 1050 tO8 3 0.8 60 6.9 1100 13 5 1.1 65 7.5 1150 1t8 7 1.4 70 8.0 1200 123 8 1.5 75 8.5 IS0 134 9 1.7 60 9.0 1400 14 1t 1.6 85 9.5 1500 154 It 1.9 90 10.0 1600 164 12 2.0 95 10.5 1700 175 i3 2.1 10 11.0 1800 1s8 14 2.2 11o 12.1 1900 195 15 2.3 120 l3.1 2000 205 16 2.4 130 14.1 2100 215 17 2.5 140 15.1 2200 226 t8 2.6 154 16.1 2300 236 19 2.7 160 17.2 2400 246 20 2.8 1tO 19.2 2500 256 21 2.9 too 19.2 2600 267 22 3.0 190 20.2 2700 277 23 3.2 200 21.3 2600 287 24 3.3 220 23.3 2900 297 25 3.4 240 25.3 . 3000 26 3.5 260 27.4 320 328 27 3.6 280 29.4 3400 348 28 3.7 300 31.5 3600 369 29 3.6 320 33.5 3700 379 30 1.9 340 35.6 360 369 31 4.0 360 37.6 400 410 32 4.1 360 39.7 4200 430 33 4.2 400 41.7 4400 450 34 4.3 450 46.8 4600 471 35 4.4 500 51.9 400 49 36 4.5 550 57.0 5000 512 37 4.6 600 62.1 5500 S53 36 4.7 650 67.2 6000 614 39 4.8 700 72.4 6500 665 40 4.9 75 77.5 7000 716 4 5.1 800 92.6 7m 767 44 5.3 650 87.7 8000 o18 46 5.5 900 92. 6500 69 48 5.7 950 97.9 9000 921 50 5.9 1000 103.0 10000 1023 Lod Factor' (o. of tonsunes I kiwotcoalc ) I (km u 730) - 57 - Page 4 of 10 TALE 2 - ESWAP Projections - esidential Use Yesr 30 MEMI TAER 40 KtUNINOI(UCOtNSlWER LF a 0.30 REA a 0.35 (1500 Cofinhrs) Specil - 30 546.5 *LOuC . K om DEIl NO.cONt. KV 11AND iNLCos. KM EMD 1 0.6 55 11.4 1050 192 S 1.4 60 12.4 tlOo 201 5 2.0 65 13.3 ls 210 7 2.5 70 14.2 1200 219 a 2.7 75 1S.1 1300 238 9 2.9 80 16.0 1400 256 10 3.1 05 16.9 1500 274 il 3.3 90 17.0 1600 292 12 3.5 95 18.7 1700 3lO I3 3.7 ' 19.6 1900 328 14 3.9 110 21.4 19M 347 15 4.1 120 23.3 2000 365 16 4.3 130 25.1 2100 383 17 4.5 140 26.9 2200 401 18 4.7 1S 28.7 230 419 19 4.9 160 30.5 2400 437 20 5.1 170 32.3 2500 46 21 5.2 180 34.2 2600 414 22 5.4 190 3.0 2700 492 23 5.6 200 37.8 2900 510 24 5.6 220 41.4 2900 .528 25 6.0 240 45. 3000 546 26 6.2 260 48.7 3200 593 27 6.3 . 280 52.3 3400 619 26 6.5 300 56.0 3600 655 29 6.7 320 59.6 3700 674 30 6.9 340 63.2 800 692 31 7.1 360 66.9 400 n26 32 7.3 360 70.5 420 765 33 7.4 400 74.1 4400 01 34 7.6 450 63.2 4600 637 35 7.8 50 92.3 400 674 36 8.0 50 101.4 5000 910 37 6.2 600 110.5 550 1OO 36 8.3 650 119.5 00 1092 39 0.5 70 126.6 6500 1162 0 6.7 750 137.7 700 1273 42 9.1 60 146. 7500 1364 44 9.4 650 155.9 000 1455 46 9.6 900 145.0 6500 1546 48 10.2 950 174.0 9000 1637 50 10.5 1000 103.1 10000 1616 Loa Fatw * (No. of Coswnrs x kohleo/coes) I (kVt 7301 58 - Page 5 of 10 TAML 3 - ESW Projetions - Prodtctive Use Yea l DERAD TABLES 141 MHUI/ONTHICONSU(ER LF a 0.40 REA a 0.41 (1500 consurs) Special 202 100.9 lO,COlS. KV DENAND NO.CONs. Km DEMAND NO.CONS. kV DENAND l 1.5 55 30.2 1050 S08 3 3.7 60 32.1 1100 532 5 5.3 65 35.1 1150 556 7 6.6 tO 3I.5 1200 S80 8 1.2 75 39.9 1300 628 9 7.8 80 42.3 1400 676 to 8.3 85 44.1 1500 124 11 8.9 90 47.1 1600 12 12 9.4 95 49.5 1700 820 13 9.9 100 51.9 1s00 868 14 10.4 t11 56.7 1900 916 15 lO.9 120 61.5 2000 964 16 11.4 130 6..3 2100 1013 17 11.9 140 71.1 2200 1061 18 12.4 l50 75.9 2300 109 19 12.9 160 80.7 2400 1157 20 13.4 170 85.5 2500 1205 21 13.8 Lo 90.S 2600 1253 22 14.3 190 95.1 2700 1301 23 14.8 200 99.9 2900 1349 24 15.3 220 109.5 2900 .1397 25 15.8 240 119.1 3000 1445 26 16.3 260 128.7 3200 1541 27 16.0 280 138.3 3400 1637 21 17.2 300 147.9 3600 1733 29 *17.7 320 157.5 3700 lst8 30 18.2 340 167.1 3900 1829 31 18.7 360 176.8 4000 1925 32 19.2 30 186.4 4200 2021 33 19.7 400 196.0 4400 2t17 34 20.1 450 220.0 460 2213 35 20.6 500 244.0 400 2309 34 21.1 550 268.0 5000 2405 37 21.6 600 292.0 5500 2646 36 22.1 650 316.0 6000 2806 39 22.5 700 340.1 6500 3126 40 23.0 750 344.t 7000 336 42 24.0 800 388.1 7500 3606 44 25.0 850 412.1 8000 3844 46 25.9 900 436.1 8500 4087 48 26.9 950 460.1 9000 4327 50 27.9 1000 44.2 10000 4807 Load FCtor * (No. of Conwurs x khlwh/cons) I (kw u 730) _ 59 - Page 6 of 10 TABLE 4- ESWP Projections - Productive Uo Year 30 E1ND TABLS 203 KMN/NO CON8U LF * 0.47 REA a 0.42 11500 consuns) Special - 672 400.2 NG.COS. Km DE"NA NO.CmS. Kl OAD NI0.CQS. K DENAND I 1.9 55, 37.1 1050 623 3 4.6 60 40.0 1100 652 5 6.5 65 43.0 1150 692 7 8.1 70 45.9 1200 711 8 9.8 75 48.8 1300 770 9 9.5 so 51.8 1400 829 10 10.2 85 54.7 1500 887 ll 10.8 90 57.7 1600 946 12 11.5 95 60.6 1700 1005 13 12.1 100 63.6 1800 1064 14 12.7 110 69.4 1900 1123 15 13.3 120 75.3 2000 1182 16 14.0 130 81.2 2100 1241 17 14.6 140 97.1 2200 1299 18 15.2 ISO 93.0 2300 1358 19 IS.9 160 98.9 2400 1417 20 16.4 170. 104.8 2500 1476 21 17.0 180 110.6 2600 1535 22 17.6 190 116.5 2700 1594 23 18.2 200 122.4 2800 1653 24 18.B 220 134.2 2900 1711 25 19.3 240 146.0 30 1170 26 19.9 260 157.7 3200 1888 27 20.5 290 169.5 3400 2006 26 21.1 300 181.3 3600 2123 29 21.7 320 193.0 3700 2182 30 22.3 340 204.8 380 2241 31 22.9 360 216.6 4000 2359 32 23.5 380 228.3 4200 2471 33 24.1 400. 240.1 4400 2594 34 24.? 450 269.5 4600 2712 35 25.3 500 299.0 4800 2830 36 25.9 550 329.4 5000 2947 37 26.4 600 357.8 5500 3242 38 27.0 650 387.2 6000 3S36 39 27.6 70 416.7 6500 3830 40 29.2 750 446.1 7000 4124 42 29.4 800 475.5 7500 4419 44 30.6 850 505.0 8000 4713 46 31.6 900 534.4 8500 500? 48 32.9 950 563.0 9000 5301 50 34.1 1000 593.2 10000 5890 Load Factor * (No. of Consuwen x kuhlno/coas)I (k/ x 7301 _ 60 - Page 7 of 10 TAILE 5 CEY Projetions ResIidetil Uon Yew I NUAO TALES 28 KNIOI/TlThCUIIIIER LF a 044 RE a 0.34 (1500 consrt Special- 2000 225.3 *O.Ce . KMl 0 NO.CONS. Ku DENAND NO.CON. Kg DERAN 1 0.4 55 7.1 1050 119 3 0.9 60 7.6 1100 124 5 1.2 65 8.2 1150 130 7 1.6 70 8.9 1200 136 a 1.7 75 9.3 1300 147 9 1.8 s0 9.9 1400 1S8 10 1.9 95 10.4 1500 169 a1 2.1 90 l1.0 1600 t1o 2 2.2 95 11.6 1700 192 13 2.3 100 12.t t180 203 14 2.4 110 13.2 1900 214 15 2.5 120 14.4 2000 225 16 2.7 130 15.5 2100 23? 17 2.9 140 16.6 2200 248 1o 2.9 150 17.7 2300 259 19 3.0 160 19.9 2400 270 20 3.1 170 20.0 2500 281 21 3.2 190 21.1 2600 293 22 3.3 190 22.2 2700 304 23 3.5 200 23.3 2800 315 24 3.6 220 25.6 2900 .326 25 3.7 240 2.8 3000 33 26 3.8 260 30.1 3200 360 27 3.9 280 32.3 3400 382 28 4.0 300 34.6 360 405 29 4.1 320 36.6 3700 416 30 4.3 340 39.1 3600 427 31 4.4 360 41.3 4000 450 32 4,5 380 43.5 4200 472 3 4.6 400 45.0 4400 49 34 4.7 450 51.4 460 51t 35 4.8 S0 57.0 480 50 36 4.9 550 62.6 5000 562 37 5.0 600 69.2 550 10 38 5.2 650 73.8 6 674 39 5.3 70 79.4 500 730 40 5.4 750 85.1 7000 784 a 5.6 S0 90.7 00 43 44 5.0 ISO 96.3 00 899 46 6.1 900 101.9 050 955 4 4.3 950 107.5 9000 tOll 50 6.5 1000 113.1 1000 1123 Lod Factor * (o. of Cosuus a kwh/eso/cons) / tk a 730) _61 _ h I1 Pagp 8 of 10 TALE 6 - CEY Projections - Residetial Us Vow 30 0M01 tABLES 75 KWH/NONYThCONSWflU LF * 0.41 EA 0.30 (1500 coners) special 60 1510.0 NO.CONS. Kg CNA NO-.CONS. KU DEAN NOCONS. KU DELNO 1 0.8 55 15.7 to1 264 3 1.9 60 16.9 1tOO 276 5 2.9 45 19.2 1150 289 7 3.4 T7 L9.4 1200 301 9 3.7 75 20.7 1300 326 9 4.0 a0 21.9 1400 351 1o 4.3 95 23.2 1500 376 It 4.6 90 24.4 1600 401 12 4.9 95 25.7 1700 426 1 S. I to0 26.9 1900 451 14 5.4 110 29.4 1900 476 iS 5.7 120 31.9 2000 501 16 5.9 130 34.4 2100 525 17 6.2 140 36.9 2200 550 1s 6.4 150 39.4 2300 575 19 6.7 160 41.9 2400 600 20 6.9 lO 44.4 2500 625 21 7.2 180 46.9 2600 650 22 7.4 190 49.4 2700 675 23 7.7 200 51.9 2900 700 24 7.9 220 56.9 2900 725 25 8.2 240 61.9 3000 750 26 8.4 260 66.8 3200 900 27 9.7 290 71.9 , 3400 949 29 9.9 300 76.8 3600 899 29 9.2 320 81.9 3700 924 30 i.5 340 96.7 3800 949 31 9.7 360 91.1 4000 99 32 10.0 380 96.7 4200 1049 33 lO.2 400 101.7 4400 10" 34 10.5 450 114.2 4600 114 35 10.7 500 126.6 4800 1199 36 11.0 550 139.1 5000 124 37 11.2 600 151.5 5500 1373 38 11.5 650 164.0 6000 1499 39 11.7 700 176.5 6500 1622 40 12.0 750 190.9 7000 1747 42 12.5 D0O 201.4 7500 18t1 44 13.0 650 213.9 6Q0 19 46 13.5 90 226.3 9500 2121 4 13.9 950 238.8 9000 2245 50 14.4 1000 251.2 .1000 2495 Load Factor a (No. of Consues x kuhluolcs) (kw ( 7301 62 - Page 9 of 10 TABLE 7 - CEY ProJetios - Prodictive Us Ywa I DERAnD TABLES 261 KIN/MONTN/CONSUMER LF a 0.40 REA a 0.44 I1500 consiers) Special --- 404 394.4 NO.CONS. KU DEMNDO NO.CONS. KU DEdAND NO.CONS. KU DEMaND I 3.0 55 60.3 1050 1013 3 7.5 60 65.1 1100 1061 5 10.6 65 69.9 1150 10t6 7 13.2 70 74.6 1200 1156 8 14.4 75 79.4 1300 1252 9 15.5 GO 84.2 1400 1348 10 16.6 85 89.t 1500 1443 11 17.6 90 93.8 1600 l539 12 18.7 95 98.6 17OO 1635 13 19.7 100 103.4 10OO 1731 14 20.7 110 112.9 1900 1826 15 21.7 120 122.5 2000 1922 16 22.7 130 132.1 2100 2018 17 23.7 140 141.7 2200 2114 18 24.7 150 151.2 2300 2209 19 25.6 160 160.8 2400 2305 20 26.6 170 170.4 2500 2401 21 21.6 180 180.0 2600 2496 22 28.6 190 189.5 2700 2592 23 29.5 200 199.1 2800 2688 24 30.5 220 218.2 2900 2784 25 31.5 240 237.4 3000 2879 26 32.4 260 256.5 3200 3071 27 33.4 280 275.7 3400 3262 28 34.4 300 294.B 3600 3454 29 35.3 320 314.0 3700 3549 30 36.3 340 333.1 3800 3645 31 37.3 360 352.3 4000 3837 32 38.2 380 371.4 4200 4028 33 39.2 400 390.5 4400 4219 34 40.1 450 439.4 4600 4411 35 41.1 500 486.3 4800 4602 36 42.1 550 534.1 5000 4794 37 43.0 600 582.0 5500 5272 38 44.0 650 629.9 6000 5751 39 44.9 70 677.7 6500 6230 40 45.9 750 725.6 7000 6708 42 47.8 900 773.4 7500 7187 44 49.7 850 821.3 8g00 7665 46 51.7 900 869.2 8500 8144 48 53.6 950 917.0 9000 8623 50 55.5 1000 964.9 10000 9590 Lod Factor a (No. of Consuurs x kuh/no/cans) Ikv u 7301 63 - Page 10 of 10 TABLE 8 - CEY Projections - Productive Ui Yeaw 30 OEMND TABLES 381 KNH/ONCTH/CONSUHER Lf a 0.51 R£A a 0.46 (1500 consurs) Special -.. 1344 1376.3 NO.CONS. KM DEMOND NO.CON8. KU DENAND NO.CONS. Ku DENAND 1 3.2 55 64.1 1050 1077 3 7.9 60 69.2 1100 1128 5 11.3 65 74.3 1l50 1179 7 14.1 70 79.4 1200 1230 8 15.3 75 84.5 1300 1331 9 16.5 80 89.6 1400 1433 10 17.6 85 94.7 1.500 1535 I I 18.8 90 99.7 1600 1637 12 19.9 95 104.8 1700 1739 13 20.9 100 109.9 1800 1840 14 22.0 110 120.1 1900 1942 15 23.1 120 130.3 2000 2044 16 24.1 130 140.5 2100 2146 17 25.2 140 150.7 2200 2248 18 26.2 150 160.8 2300 2349 19 27.3 160 171.0 2400 2451 20 28.3 170 181.2 2500 2553 21 29.3 180 191.4 2600 2655 22 30.4 l90 201.5 2700 2751 23 31.4 200 211.7 2800 2858 24 32.4 220 232.1 2900 2960 25 33.5 240 252.4 3000 3062 26 34.5 260 272.9 3200 3266 27 35.5 280 293.2 3400 3469 28 36.5 300 313.5 3600 3673 29 37.6 320 333.9 3700 3775 30 38.6 340 354.2 3800 3876 31 39.6 360 374.6 4000 4080 32 40.6 380 395.0 4200 4283 33 41.7 400 415.3 4400 4487 34 42.7 450 466.2 4600 4691 35 43.7 500 511.1 4800 4894 36 44.7 550 U68.0 5000 5098 37 45.7 600 619.9 5500 5607 38 46.8 650 669.6 6000 6116 39 47.8 700 720.7 6500 6625 40 48.8 750 77.1 7000 7134 42 50.9 800 822.5 7500 7643 44 52.9 950 873.4 8000 8152 46 54.9 900 924.3 8500 8661 4 57.0 950 975.2 9000 9170 50 59.0 1000 1026.1 10000 10188 Load Factor a (No. of Consueru x kwh/so/cons) / 1kw i 730) - 64 - ANNEX 2 Page 1 of 2 UNM1ZED caMsr E STIllS US$ 1. Principal Lines Three-phase, #2/0 ACSR conductor 8,000/km Three-phase, #1/0 ACSR conductor 7,000/km Three-Phase, #4 ACSR conductor 5,000/km Single-phase, #4 ACSR conductor 3,000/km 2. Taps and branch circuits Single-phase #4 ACSR conductor 3,000/km 3. Secondary lines, single-phase or Three-phase; average cost 3,100/km 4. Meters and service drops 41.50 each 5. Transformers 60/kva 6. Hydroelectric plant, installed 2,000/kW 7. Engineering and Administration 15 % (% of estimated construction cost) 8. Contingencies 10 % (% of estimated construction cost) Source Mission assessment. - 65 - Page 2 of 2 a. Kilometers of secondaty lines are determined by dividing the total number of consumers by SO (estimated number of connections per kilometer of line). This is equivalent to 5 consumers per span and spans of 100 meter length. b. Quantity of residential meters and service drops is equal to the number of residential consumers. The quantity of productive use meters and service drops is assumed to equal to 33.3% of all productive use consumers. It is assumed that 66.7% of productive use consumers are very small and will utilize meters and service drops provided under the residential connection category. c. Total kVA transformer capacity installed is estimated to be equal to twice the projected demand in kilowatts. Thus a demand of 1,000 kW would require 2,000 kva of transformer capacity at $60.00 per kVA, installed. Installed capacity of two times the demand is an acceptable normal practice. d. For each of the alternatives presented, there are 132 kilometers of primary three-phase or single-phase lines. Differences in cost result from varying the type of line or size of conductor. e. The method used to estimate costs of the several alternatives utilizing unit costs and constant methods of deriving associated secondary line, metering and transformer costs is designed to eliminate favoritism in the estimating process. An adequate comparison between alternatives and an adequate total cost estimate will result. ANN3X 3 Page 1 of 4 LlERIIIVE la - Y SSTEN VTAGE DROP SE AGROYUNSA, SECTIKula aUIEs CONCENTRATED LINE V, A1 E DRW SWO LOAeD VItIN DEYO EWIV. KUR/N.O PEAK WITHIN BEYOND EW01. PEAK TOTAL CONDUCTOR NO. VOTAGE LENTH TIS AT END ED SECTION SECTION SECTION EON KM SECTION SECTION SECION KN KM SIZE PASS KY FACLOR N1. kVs KNt SECTION TOTAL POINT e fle nea fa~~~~~~~~~~~~~~~~~~~~~~~~--- - ---- A 3 1034 5016 5N3 75 1381 221 1123 1234 1264 2U45 1210 3 14.4 0.110 26 61.9 I. 8.1 3 I I1 276 30 160 75 44 65 5 38 47 91 2/0 3 14.4 0.118 12 1.1 0.1 8.2 e1 B C 1166 3542 4126 75 1030 263 796 928 953 1953 12/0 3 14.4 0.118 16 31.1 3.7 11.9 C t O 145B 1872 2531 75 633 296 419 567 58 1218 1210 3 14.4 0.11 21 25.6 3.0 14.9 D O *1 106 176. 229 75 59 22 38 49 59 11 1210 3 14.4 0.1190 0.9 0.1 15.0 Di * E 24 1373 1390 75 349 5 306 309 323 6b2 U210 3 14.4 0.118 12 9.1 1.0 IS.? E E F 206 II 221 75 57 48 27 51 60 117 1210 3 14.4 0.119 16 1.9 0.2 16.2 F RESIEKNTIAL USE U 7 5 i LOA FACTO a 0.41 PMCIVE UKE IUN tI CN 361 ; L FACO a 0.51 ANNEX 3 Page 2 of 4 SILEMTIVE lb - CE? SISTE VIT EIWt L VOLTAGE DRP SHEET sEcitE CONSU_S cEUTRa LINE VOLTAGE DROW SOIICE LOAU VtHhI I MV. MUNHI PEA VITNII KB EWIV. PEAK TOTAL CONMOCR NO. VOLTAGE LENGTH THIS AT ED ENI SECTIW SECTION SECTION Et _E K SECTION 1 E0T1ON SECTION KU Kg SIZE PPRSES KY FACTOR KNS. K x YN SECTION TOTAL POINT B 3 4m2 2r0 2754 40 502 110 S W 367 86 1210 3 14.4 0.118 26 22.6 2.7 2.7 a 8 Bl 136 IS 4 40 17 32 3 19 16 33 *210 3 14.4 0.118 12 0.4 0.0 2.7 91 * C C54 1n7 2063 0 376 132 3" 464 273 6546210 3 14.4 0.118 16 10.5 1.2 3.9C c e 659 936 1266 0 232 146 210 264 172 4040210 3 14.4 0.118 21 8.5 1.0 4.90 * DI 53 a 115 0 22 It 19 25 19 41 8210 3 14.4 0.118 8 0.3 0.0 4.9 01 * E 12 6- * .6 40 128 3 153 155 96 224 210 3 14.4 0.118 12 2.7 0.3 5.3 E E F 103 9 111 40 22 24 13 25 19 41 1210 3 14.4 0.118 16 0.7 0.1 5.3 F NESIUENTIAL USE KAUNIA IIO ISUIINR 40 LOAD FACT a 0.30 PIIVE USE _ 203t LODN FACTR a 0.47 Page 3 of 4 MLTITIVE 11 - 5m SISEN 311 51 LOU VOLTHGE DRIP SHEE SECTION C CoICERATEI LINE VOLTAE DROP SOU_M LOA V11N1 BEYOID EDU1V. K/I EK VITHIN BISM EOUIV. PEAK TOTAL CODTOR NO. VOLTASE LENGTH THIS AT IN ED SECTIOI SECTION SECTION C KUE l SECTION SETION SECTION KU KU SIZE PHASES KY FACTOR Kl. KM KN SECTION TOTAL POINT A 5 492 250 2154 40502 110 562 f1l 36 9 94/0 3 14.4 0.1" 26 22.6 3.2 3.2 B 9 Di 1n 15 8 0 17 32 3 19 16 33 4 1 14.4 0.903 12 0.4 0.4 3.5 81 I C 56 1771 2063 40 376 132 390 464 278 6 411/0 3 14.4 0.140 16 10.5 1.5 4.6 C C D 659 936 1266 40 2 140 210 204 172 404 04 3 14.4 0.301 21 9.5 2.6 7.2 D * 01 53 0 115 40 22 11 19 25 19 4104 1 14.4 0.903 B 0.3 0.3 7.S 11 D E 12 6 695 40 129 3 153 155 96 224 14 3 14.4 0.301 12 2.7 0.9 0.3 E E F 103 S9 II 40 22 24 13 25 19 410 4 1 14.4 0.903 16 0.7 0.6 8.9 F KSIlfStilEltL USE l aRliUlHla s40 LO FACTOR a 0.30 PNTlYE US£ :IIOIUN1TICONSIB a 203 $ FACtOR a 0.41 maNES 3 Page 4 of 4 ALTETIVE III - ESIW SISTER NIT" ESN1 LOAn HYDRECTIC PLT VOIASE OP SHEET SECTION t 6DIUHERL VOLTAGE DROP Snu LW DItHIN VEW IVN E IIIUM K MITNIN BEYOND EDUIV. PEAK TOTAL CONDUTOR NO. VOTAGE LENGTH THIS AT END END SECTION SECTION SECTION NI SECTION SECTION SECTION K1 KV SIZE PHSS KY FACTOR KNS. KM x z SECTION TOTAL POINT M YL FMN =11NNANI A B 492 1572 l1l1 4 332 110 352. 407 244 576 4 3 14.4 0.301 26 15.0. 4.5 4.5 B 3 BI 139 15 94 0 17 32 3 19 14 344 1 14.4 0.903 12 0.4 0.4 4.9 1 I t 584 335 1127 0 206 132 195 251 152 359 4 3 14.4 0.301 16 5.7 1.7 6.2C C D 65 0 330 0 61 148 0 74 4 109 14 3 14.4 0.301 21 2.3 0.7 6.9 3' SUPLY FRM PFMI SITE AT LA ASUNTAs FM T 12 229 235 40 44 3 51 5336 90 64 1 14.4 0.903 12 1.0 0.9 0.93 E Di 53 a 115 40 22 11 19 25 19 4104 1 14.4 0.903 B 0.3 0.3 1.2 91 PLW F 103 S9 1ll 22 24 19 41 19 414 4 1 14.4 0.903 16 0.7 0.6 0.6 F ESIDENTIAL USE 1UII /CIViN * N a LOAD FCTOR * 0.30 PRDCT1K USE lK INlONTNCONU1EIM 203a LOD FACTOR * 0.47 AT TIE PLANT SITE OF ^AS T 1. OF NESIKENTIAL CNNS x 527 ; 97 U OENII M. I PICIVE USE CNSDR a 113 ; 74 DELN TME POULAION OF LA AMT IS CSIDE LAE E0 TO D C TRE-PHASES OF GETIN PA LOADS. SINKlE-MlSE LINS NLY EITED OUTSIE F LI AMA POLION. - 70 Page 1 of 1 TRA -MSF0M Oa SIUS-STACOW A4EULADOR SVOLT4A PWGTOO K NGULACIOr J= ~~~~~CON COMPIWSADOO SU- STPAISNS aON *o + PRIMER ULT MO 4 ~~~TnAMSFORMA00R TnANSFORMAO C 140 40 335 volta bj¢ I-3 ~13 0 I;.. e | ll \t|1II^izi de t^ 6. i t6 volto tle L8" - 330 \ { 5.4%) W . _ VAPIACION VISTA < § s ) \ _ R~~z OP EL PRIMER 0) 125 . I _ J. tlgs O~~~r §,L_Ji §§ 3.1 %) 325 CAItAD 6.- VOLTAJI VAR CO. V IN CL~~~~~~~ TRANSFORMADOR I Verlelom Viste CARGA P9SAOA Pot @ Ultime lJuorlei llS . .. PERFIL DE VOLTAJES PARA CARSA PESAOA Y CARGA LIGERA MUESTRA EL USO 01 REGULADOR DE VOLTAJE CON ETAPAS * 10% 71 - AS Page 1 of 4 1 IMA=E KMOP OF E:NGiINEE SERVIC;ES The foilowing outlines, as a minimum, an estimate for a prospective scope of engineering services required for any project implementation. Th*, following estimate was developed at the request of UNFDAC. L Eld Investipio a. Field trip is estimated at fourteen (14) days. Additional field time might be required subject to conditions. b. Investigate and assess local wood pole strengths, sizes, and avaiability. Evaluate treating process, testing, and treatment plant capability. Determine other engineering properties of the available poles. C. Assess local concrete pole fabrication, testing, and availability. Determine production plant capability. Determine other engineering properties of the avaible poles. d. Assess whether crossarms are avaiable localy. Determine the sizes, strengths, treatment, and other engineering properties of the available crossarms. e. Evaluate Cooperative Electrica Yunps (CEY) standard materials and consuction standard drawings, conductor and other materials. f Ascertain guy anchorage, soi0 and rock conditions. g. Acertain the avaiabflity of pole transportation, excavation, and construction equipment. h. Determine representative span lengths suitable for the terrain. i Establish design temperature range for the area. j. Determine local labor, transportation, and material costs. 1I. DAiL a. Adapt conductor designs based on: 1. USA National Electrical Safety Code (NESC) light loading ditict. 2 Grade C constuction -72^ Page 2 of 4 3. ALCOA sag and tension limits 4. Temperatures establihed by field investgation. b. Conductor desig nring spans: 1. Two for #1/0 (6/1 ACSR) Raven 2. Two for #4 (7/1 ACSR) Swanate 3. Include information for range of span lengths determined during field investigation. C. Provide long deadend span conductor information for #1/0 and #4 ACSR to allow field desig/staking of indrvidual long spans. Sag and tension limits (initial and final) for loading and temperature conditions and the epoed range of spans determined during field invesgation. 1L Dsuadn J4@Lne le;n a. Provide the following based on U.S. Department of Agriculture Rural Electrification Administation (REA) Specifiations and Drawings for 14.4/24.9 kV Line Constructon (REA Form 803). Engineering design is based on the assumption that suitable wood poles wi be available for the total project. If any concrete or metal sructures or specil dsrutures are required for the dtribution lines, the estimated egineering scope of services and crrespnding compensation will be revised accrdingy. b. STAKING TABLES for ruling spans seected for #1/0 and #4 conductor. Minimum dearances based on NESC requirements 1. Rural pelestian areas: 2.9 meters to neutral and 4.4 meters to phase. 2. Over roads: 4.7 meters to neutral and 5.6 meters to phase. 3. Include a provision for addition of secondary 240-volt conductos 4. Ilude uplift factors c. }GUY LEAD TABLES for selected guy/anchor combinations, for 3-phase L# 1/0 and #4 ACSR, sowndaiy underbid, and secondaiy only lines and long deadend spans. X73 . Page 3 of 4 d. POLE STRENGTH TABLES for maximum span lengths determined by pole type and strength. For use with 3-phase #1/0 and #4 ACSR, 1-phase #4 ACSR, and long deadend spans. Includes span reduction factors to allow small angles without gus and anchors e. MAXIMUM SPAN LIMIT BASED ON CONDUCTOR SEPARATION for tandard pole-top asmbly stuctur and special long span s ues, including altitude correction factors Also for ZROLW type configuration changes (changing from horizontal to vertial conguration within a span). f INSULATOR ASSEMBLY STRENGTH TABLE AND CROSSARM STRENGTH TABLE for maxdmum angle to be supported by standard insuator assemblies based on grade of construction, span length, conductor tensions, and loading Determine crossarm strength required for line tension and maximum vertical loads. g. INTIAL AND FINAL CONDUCIR STRINGING SAG AND TENSION TABLES for all conductors and ruling spans selected, including long spans. h. GUIDES for the use of staking information included in Section m. F. through m F. i GUIDES for stringing sagging, measuring sag, and recording sag measurements during construction for use with guides included in m. F. Stringing tensions for long spas wiM be provided after stuctur are staked and actual horizontal and veical dtances are measured. IV. [&bis mLnkle Stking ln-field primary and secondary line design incuding location of each primary and secondary line pole (stakig) wi be performed. The size and location of the distrbution transformer will be determined. Minimal line of sight dearing for the centerline and pole location suvey wi be performed. V. lZeX ngp Wn49d" and SpcW Documents j. Prepartion, with material breakdown, of specil construction drawings not included in REA Form 803 which would satisfy contruction requirements for long span cosrion. k. Determine material spefition rements for inclusion in United Nations bid documents ig procedures and languap requirements so as to comely with funding institution requirements. .74- AINNEX Page 4 of 4 VI. Other EQjjngA gActivi a. PWpare constucton cost estimate, time schedule for line stakdng and other field engineering activities, Invitation-for-Bid documents covering materials and labor, and other items as required for award of construction contract VII Ctructnagw= or JWmd= After Award a. After award of construction contrat a review of the contractor's work plan, material procwrement procedures, consution schedule, etc. will be performed. During constuton, and monthly progress reports will be prepared and submitted. Construcion will be monitored and inpected on a periodic basis as deemed necessary by the enginees M2: The Estimted Scope of Engineering Consulting Services as descrbd above presents requirements that might be reqired for Phase II subject to (as yet to be established) Terms of Reference. The scope of services for engineering design or consulting servies for Phase II could change depending on the requirements of the Terms of Reference. The total cost for phase II engineering would be calulated accordingly. 75 - Page 1 of 2 MARGINAL COST CALCULATION L Marginal cost at bulk level (High Voltage) 1/ USS 8.90/kW/month US$ 0.014/kWh.month IL Total demand for year 1 of 197 kW and a total consumption of 510,000 kWh in year 1; figures for year 30 are 946 kW total demand and 3,078,000 kWh/month; figures for years 2-29 were interpolated using a linear regression. II. Average marginal cost for year 1: [(8.90 $/kW * 12 months.year * 197 kW) + (510,000 kWh.year * 0.014 $/kWh)]/510,000 kWh.year = US$ 0.055/kWh IV. Average marginal cost for year 30: [(8.90 $/kW * 12 months.year * 946 kW) + (3,078,000 kWh.year * 0.014 $/kWh)]/3,078.000 = US$ 0.047/kWh V. Table A presents margil cost estimates for years 1-30. 1/ (from ESMAP Report "Basis for the Formuation of a National Eneriw Plan', November 1987): ~~ -~~-a I~~~~ I ~~~~~~~~~~~~~ - .77 . AM= 7 CARACITRISTICAS DE LA TARIFA RESIMENCIAL 1/ TARIFA RESIDENCIAL CODIGO TARIFA% BOLI Pam los primeros 0 Kwh 0.0000 Cargo minimo:1S933 Para los siguientes 25 Kwh 0.0312 Para los siguientes 999 Kwh 0.0520 Para los siguientes 999 Kwh 0.0520 Pam los siguientes 999 Kwh 0.0520 Pan el resto complementario 0.0520 TARIFA UTlLIADA PARA LOS USOS PRODUC1IVOS 11 CODIGO TARIFA: BOL2 Pan los prineros 0 Kwh 0.0000 Cargo minimo:21700 Para los siguientes 50 kwh : 0.0563 Pan los siguientes 999 Kwh 0.0433 Pan los siguientes 999 Kwh 0.0433 Pan los siguientes 999 Kwh : 0.0433 Para el resto complementario 0.0433 1/ Tariff struce applied In the DAM model calculations. 78 - ANNES Page 1 of 2 DESCRIPTION OF THE RURAL ELECTRIFCATION PLANNING MODEL (DEMAND ASSESSMENT MODEL DEVELOPED BY NRECA) 1. The Demand Assessment Model (DAM) was developed by a team of NRECA staff and consultants, including rural electrification engineers, economists, sociologists and planners between 1988 and 1990. The model is considered a practical planning tool for evaluating rural electrification projects and aims to meet objectives of formal correctness, field applicability and "user-friendliness". The model is therefore being continually improved. 2. The model was develop to assist utilities from countries participating in USAID NRECA's Central American Rural Electrification Support program in the selection of potential electrification sites. Each county was faced with a large number of potential sites and limited amounts of funds to conduct rural electrification programs. There was a need to provide the utilities with a means for selecting sites with the greatest relative economic benefit potential and give them an idea of each project's financial feasibility. 3. The model was first tested in Guatemala, l'.en in Belize and El Salvador. The first applications showed that it was relatively easy to obtain the necessary information, especially if the objective was to rank projects within the same given area. Nearly 100 rural electrification sites in Guatemala, El Salvador and Bolivia have been evaluated using the modeL For stand-alone applications, data quality requirements increased significantly. Electric utilities in El Salvador and then Guatemala raised the issues and provided the data to refine many of the model's "systems parameters." 4. The model, currently written in D-Base, allows for the financial and economic characterization of a project and its ramifications. It provides the framework for estimating construction, operating and maintenance, service and margnal costs of electricity, transmission and distribution losses in a language accesible to rural electrification planners. Financial benefits are estimated using utlity tariffs, estimated kWh consumption levels and users' contnbutions, when applicable; economic benefits are estimated based on the number of residential users and the number and types of commercial, or "productive end-users" of electricity. Costs and benefits are calculated in present terms using a discretionary discount rate for the purpose of estimating Net Present Value and Benefit/Cost ratio. Internal Rates of Return are estimated using succesive approxinmations. 5. The models inputs fall in two categories: system parameters and project data. System parameters are those which normally do not vary within a given country. Typically, tariffs, existing productive end-uses, construction costs, operation and maintenance costs, costs of connection and the marginal cost of electricity do not vary within the same country. Project- specific parameters include type of line, type of terran, type of pole, kilometers of line by type, improvements up to the line connection point, number of transformers and, occassionally, additional generating capacity. A complete listing of parameters and "screen-dumps" can be obtained from NRECA. 79. Page 2 of 2 6. Outputs include NPV, B/C, IRR and tables showing number of consumers by type (residential and productive end-users), total yearly kWh sold by tpe of user and corresponding kVA demand, construction costs, operation and maintenance costs, generating costs and loses, cost of Inprovements up to the start of the line, economic and fiancial benefits. Summary tables present the financial and economic indicators in a condensed form. 80 - ANgNEX 9 Page 1 of 18 A METHODOLOGY FOR ESTMATING ELECIRICITY'S RESIDENTIAL AND PRODUCTIVE END USE ECONOMIC BENEFiTS AND ITS APPLICATION IN THE ASUNTA VALLEY RURAL ELECTIFICATION PREFEASIBILI'IY STUDY Introduction This annex outlines the methodological approach used for estimating electricity's residential and productive end-use economic benefits, with special emphasis on field applications, using the methodolog known as the Demand Assessment Model (DAM). The specific approach used in the Asunta Valley study is discussed throughout the Annex In addition, enhanced approaches not necessarily applied in this case study are also discussed in this annex. The methodology was prepared by Messrs. Villagran and Orozco of the NRECA with technical assistance from ESMAP. * 81 - AN9X Page 2 of 18 RESIDENTIL BENEFITS: YEAR 1 For year one, residential benefits are calcuated on the basis of substituting electricity for current energy sources used in residential lighting and computing a total "willingness to pay" for electity as a measure of benefits obtained by residential consumers Substitution benefits are calculated as savings in energy costs of an equivalent amount of kilolumen- hours/month produced using electricity intgeadf the alternate fuel (see area B in Graph 1) DlI a measure of the "consumer surplus," arising from the concept that if lighting senvices were available at prices between those of the alternate fuel and the electric tariff there would be consumers wiing to pay those prices and consume intermediate quantities of ldlolumen-hours/month (see area D in Graph 1). The final component of consumers' total "willingness to pay" for electricity (areas A + Cl in Graph 1) is calculated as the electric tariff applied to projected kWh consumption. The curve "Dem(k)" represents the non-electric energy demand function. "A + BW is the current total cost for basic quantity of light in kilolumen-hours/month "Q(O)" at a set price "P(k)r in $/kilolulmen-hour. Substituting electricity for an eqivalent lighting level would cost 'A," yielding cost savings of "B." Since electricity demand is not represented by the same curve as the alternate fuel function (users will more than replae current energy demand), an electricity demand function "Dem(e)' is defined. At a price of electricity OP(e)" the quantity demanded wil be "Q(1)" kilolulmen-hours/month for a total expenditure of "A + C1." This expenditure is the consumer tariff for the newly provided electric service. The consumer surplus is estimated by the triangle "D," assuming the existence of a "Demand for Lighting Services function passing through points X and Y. Let: P(k - Average price of alternate fuel per unit of lighting ($/kilolumenhour) P(e) u Average price of electricity per unit of lighting (Sldolumen.hour) Dem(k) - Demand for alternate fuel lighting services, measurig changes in the quantity of kilolulmen-hours/month as a response to changes in the price of a kIlolumen-hour using the alternate fueL *82. Page 3 of 18 Dem(e) X Demand function for electicis lighng services, measuring changes In the quantity of kilolumen.hours/month as a response to changes in the price of a kilolumen-hour using electricit. When electricity is introduced, people generaly consume more kilolumen-hours/month and pay lower prices per Idlolumen-hour than was previously the case using alternate fuels. A new demand curve for electricity i defined to the right of the demand for lighting using the alternative fuel A 'demand for lighting services curve passing through points X and Y b also postulated. A + B - Current cost of lighting using alternate energy souroe for lighting level 0(O). A Cost of electricity to replace same lighting level B * Savings when replacing alternate energy source with electricity for equal lighting level, Q(O). A + Cl Total cost of electricity for lighting in year 1, ie. tariff payments for quantity Q(l). D - Estimate of consumer surplus [Pk Pe) * (Q1- QO)]/2 hence: Residential Benefit A + B + Cl + D -83 - Page 4 ef 18 GRAPH 1 PRICE (USS/kiloIufan-how) OEM (hk SUPPLY (hi ESTIMATE OF DEMAND FOR UGHTING SERVICES ..........:.... ............. ... __ ..................a- .............. ............DEMAND FOR UGHTING SERVICES D ~~~............ , .................... ....... __...... ........... ..... ... ....................... _, _ ~~~~~~...................... .. . . . Pe > .................. _, _ - ,_ ................... I ~~~~~~~~~OEM (.) ...........:..I .................................................. QUANTITY 00 Q1 (kiloumen hourslmonth) _ ive et..... w.. be/ t tI Clfv_ -84- Page 5 of 18 How To Tbe present cost of alternate fuel for current lighting levels can be determined in the target area based on field surveys. Equivalent, or replacement, cost with elecicity 'B" can be calclated for lightng using conversion tables (see 'A Comparison of Lamps for Domestic Lighting in Developing Countries, World Bank Energy Se ies Paper No. 6 - van der Plas, Graff 1988). The projected level of energy use is typically estimated using (a) utility biling information from electrified communities with simflar characterisics and (b) applicable tariffs. Questioning prospective consumers regarding intended energy use is also an option. Electricity, kerosene, LPG and candle consumption for lighting in the Yungas region of Bolivia was obtained through field surveys. This information is presented in Table 1. Tab* I1 - ENERGY CONSWEPTION FOR DUIESTIC LIGHTING SERVICES, EJIVALENT KILOLUNEN.HOURS/N0N7H, NONTHLY EXPENDITURES AND PRICE PER KILOLUNEN-NOUR USING ELECTRICITY, KEROSENE, LPG AND CANDLES IN T?E YUNGAS PIEGION OF BLIVIA Share of Energy Nonthty Pre-electrIc Consuption Uquivalent Expenditure Price Energy Source Lighting Units/nonth KLU-Hr/Mo US$/onth US$/la-Hr 1. Candes 30% 1.8 kg 3.54 6.08 1.71 2. Kerosene 50% 11.1 kg 13.87 6.08 O.4 3. LPG 20X 7.3 kg 96.75 1.91 0.02 4. Electricity 0% 15.0 kAh 75.00 2.3S 0.03 S. Weighted Averag of 1-3 *- 27.35 5.25 0.19 Mtte: 1. Equivalent conwuptfin in KL-Hr was obtained from the World B*ank tAntry and EnerW Departmnt, 'A Carprison of Laips for Dometic Lightin In tDeveoping Countrfes: (Jurn 1988), p. 12. 2. The but equivatent ws used for LPG. 3. A weight of O.OS8 Wcandle ws estited. 4. Ibe on fietd survey, it was as d that domestic fighting in tho Asunta Vatley of Bolivia is currentty based on kerosene 50M of the times, on LPG 20% and on candtos 30%. Thes prqportfons are used to estfite the weghted verage. Page 6 of 18 Based on these figures, energy cost savin Is: B = (0.19 US$/KLm-Hr - 0.03 US$/kLm-Hr) * 2735 KLm-Hr/Month - 4.38 US$/Month The consumer surplus is: D a (75.00 JLam-H/Month . 27.35 KLm-Hr!Montbo * 0.16 USS/KIm-Hr - 3.81 US$/Month 2 And the tariff payment is: = A + Cl = 2.35 US$/month For a total economic benefit of IOJA USS/mnlth. Since the DAM model calculates A + Cl, only B + D, or US$ 8.19 are entered as average residential economic benefits for year 1. The results are only slightly sensitive to the findings of the field survey of pre-electrification lighting sevies demand, as well as to the assumptions of fuel switching behavior. For esample, suppose instead that the newly-electrified households were formerly using candles, kerosene and LPG in the ratio 10%, 60%, 30% respectively. Then the weighted average monthly consumption figure would be 37.70 KLm-Hr and the weighted average price, US$ 0.13/KLm.Hr. The enery cost savings is then: B - (0.13 US$/KLm-Hr - 0.03 US$/kLm-Hr) * 37.70 KLm-Hr/Month - 3.77 US$/Month The consumer surplus is: D - (7.00 Klm-HroNth - 37.70 Klm.Hr/MonJi)* 0.10 US$/L-Hr - 3.73 US$/Month 2 And the tarM payment irs - A + Cl1 2.35 US$/month For a total economic benefit of 9.85 USImongthb or about 7% lower than under the previous -86, Page 7 of 18 RESIDENTLAL BENEFTM- FUTURE YEARS Ddixions Future economic benefits from residential uses are estimated as i1 benefits for year 1 pkia increased wilingness to pay over the years In other words, areas "AW + B' + '"D remain constant while ara "C grows reflecting displacements in the electricity demand curve "Dem(er (See Graph 2). Since uses other than lighting wil occur, enery use is measured in energy units, such as kilojoules. The benefit of replacing basic lighting quantity demanded under the alternative fuel with electricity, 'B, is attributable to each year of the anabsia since these savings occur each year the residence is electrified. The same applies to the consumer surplus "D', provided in both cases that all energy costs remain constant in real terms over the period of the analysi If electric tariffs or any other energy costs are deemed to increase over and above inflation rates in any one year, areas "B and I"' need to be recalculated and the new figure used in subsequent years. 'D" must also be recalulated if uses other than lighting are taken into account Let: P(k) - Price of alternate fuel P(e) 3 Price of electricity Dem(k) - Demand function for alternate fuel Dem(e)1.n - Demand function for electricity in future years A + B - Current cost of alternate energy source for lighting level Q(0) A - Cost of electricity to replace orinal hting level B - Savingp when replacing alternate energy source with electricity for equal original lighting level, Q(O) B+C(1) + ..C(n) - Total cost of electricity in year n for basic lighting and additional uses, ie. wilignesto-pay for quantity 0(n). D E 1stimate of consumer surplus hence: Residential benefit in year n - A + B + C(1) + C(2) +..C(n) + D - 87 - Page 8 of 18 How To Fuel substitution benefit (T + DI) is calculated as defined for year 1 residential benefit. Future years' wllingeas-to-pay is simply future yes' tariff apied to projected kWh consumption (A + Cl...n). Apnlin In the Agru prefeasibiit study, an estmated 9B + DO - US$ 8.19 is entered as residential economic benefit and the modd I allowed to al tariff times kWh consumption as an estimate of A + C, or wlingess to pay, each year. I -88 - Page 9 of 18 .7 GRAPH 2 RESIDENTIAL BENEFITS PROJECTIONS DO(c) o DOM()Zt D)m(,) l00 q3 . _ Min A T B T mC ... U,waC ..C DEMAD WI RS 1 THROUGH N .89 - Page 10 of 18 EXSTING PRODUCIIVE USES: ASSUMING NO INCREASE IN TOTAL ENERGY USE Inceased entrepri profits attributable to electrcity (suppy side benefits) are calated by adding enera cost savins, bceased productt and ncased product quality estimated by comparing similar entreses with and without electrct (Grph 3). Shaow prices and the margina cost of electicity are to be used for all enerWr-related costs GRAPH 3 L ENERGY COST REDUCIION PRICE Short-team enersV demand cuave PER ENERGY UNIT P(d) A P(e) (B2) B1) Q(0) ENERGY QUANTITY (Brake HP) .90 . ANNEX 9 Page 11 of 18 Let: P(d) - Price per energy unit (such as kilojoules) using alternate fuel P(e) Price per enery unit using electricity A+B(1)+B(2) = Total enerV related cost in the actvity using an alternate fueL B(1) a kWh consumption * Long Run Marginal Cost/kWh) plus other supply side costs in the activity using electricity. B(2) = Annualied cost of electrical equipment investment by entrepreneur. A E Energy cost savings, or the differenco between current alternate energy cost and total energy-related electric energy cost. Q(O) - Replaced energy demand (Brake HP) for cost comparative purp'ses. That is, Brake HP for alternate fuel activity is equivalent to Brake HP supplied to the electrified enterprise. Note: Ihis methodology is applicable n* when electric and alternative fuel powered activities are of slar Bra ze See end of section for Hw to and AgWLiatIin. *91- AHM9 Page 12 of 18 EXISTING PRODUCTIVE USES: ASSUMING NO INCREASE IN TOTAL ENERGY USE I. PRODUCTIVITY EFFECT Enterprises using electricity often experience increased production per unit of energy used. This is attributed to the "formn" value of electricity. Form value is composed of electricitys characterisics above and beyond the sole supply of power and include: instantaneou availability, cleanliness, continuity, noise reduction, electronics and an almost infinite dosificaton of use levels within available range. Th'ese characteristics, not found together in any other energy source, sometimes result in a greater response of output to the same levels of energ use (Oraph 4). Lt: O(e) - Product output level from the electrified activity at equivalent brake HP input level Q(O) 0(k) = Product output level in the alternate fuel activity at equivalent brake HP input level Q(O) = Equal energy input (Brake BP basis) level P = Market price per unit output (assumes no change in market value of product) C(k) = Average cost curve for the alternate fuel activity C(e) Average cost cuve for the electric powered activity Profit(k) 8 Price - production cost per unit output for alternate fuel activity hence: Productivity benefit - (P- C(k)) * (O(e)1 - 0(k)) Therefore, the average cost curve for the altemative fuel activity instead of the cost curve for the electric powered activity is used in the formula for the productivity benefit. Note that the cost savings of energy are already accounted for by the energy cost reduction calculated. * 92 - Page 13 of 18 GRAPH 4 EX[ST[NG PRODUCTIVE USES: PRODUCTIVITY EFFECT . OUTPUT, O.)1. I , \~~~~~~~~~~~~~~~~~P ¢"--^^< 9t $Zb #ib b &~~~~~~~~~~~~~~~~~~~~~~L# IBRD 22437 a,. /, B R A Z I L BOLIVIA P&tvft UNDP TECHNICAL ASSISTANCE PROJECT To RWlo ro/ ' S % RHO J 2 / G DtGLopstilirim |gUNDP Proiect Site ROADS \, 9 DR 9 > \ t - Main ______i Secondory ---- n--- s T2c 0 lawns Hwi s Notional Captial I ^ Departmert Bon ndories LA. y k U / shnii9 ~pt >,>,,Altiplono P E R U dll- V gesws LS g '.+ j ,_ t LVolleys PMW 1> ~~~~~~~~~~~~~~~~~~~~~~~~Lowlands Osourom B i;9 . ' E It 25 g. Arenm Pr*- A1 z mu, F _iet90rfv ! , & A 1 \ / \ _.A1 s B R A Z I L 'vWc' \~~~~~~~YN I %4 P AR AG U AY P=4- fi tr,JA, f .PTBas < abgwtk 9nt q*b l>*mes * 5zjbUPAz 1. P BRAZIL PAC{F(4 C H I L E t P C T O S I 1k et Msa 1/ARGENTINA/ y - < A R\J E I N A - :90 A 1 F v \ baNt=Xt yt'mbd6n > .,.*r. # ~~~~~~~~~~~~~~~~~~~~~~~JUNE 1990 e- I DE NUACHI . C,.-.-' DEPAR.rN DE C C I \ v--- 0 --- 4 :: \ b, . ~~ ~ ~~~ -' 'N ->ro; °4 PROVINCIA ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~~C CiN CU CI V - u . F--~~~~~~~~~~~~~~~~~~~~~~- PR OVNC IN.C. A NOHRWBA YUCNC.A CCC7 NORsoRms "Al DEPARTAMENTO DE COCHAHAMBA DEOM D~~~~~~~~~~~~~ E COCHABAMBSA l~ ~~~~~~~ twlf 17 po '. AR XSTUIO RLIIA f ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~LENTV IsllTAI T8 f ., V ? fS|'_\ - " T" W. bERINOS i WEFElENCTA. , EL ,E& T INEGAL E ,EPRATfM m MfH E T4A 34 - 22: 92 51.1 E : oigfDeoET~~~~~~~~~~~~~~~~YER I4 2 1s1 n0 nY ,O 9r- Kw 32 . 0 ,, } # oEE&svt 7~~~~100 13 715 O.A _ '. ,,-55 '9 F<. _7-- S fS~~~~~~~~~~~~~~~~~~IIW IAIA 1o20 30 17g7 aN| TOTAL Mo. 14 675 .04ff .. a ........ - I |J J -- X7EMTIALla7^ , ,s , - -> P4,; VTNCkiA SU YUNGA Do" | 2tEL, 8 DO ,7 .....!97Y KLW A.w9C5Rt CATO H-CN AG\/ ~ J^ 1ROYUNGiNiASAUT $RUVA / 1/ *xs'i t ~~~~~~~~~ESTUDOPRLIMINAERAiEiJ J R.EV. 1 5~~5~~90 | L. fs SSVITEW ^ rn, 99 -ym~~ I _w3o0wg .~~~~~~~~~~~~~~~~~~~~~ yk ,1 .1 .0 6 - UnIO~~~~~~~~~~~~~~~11N SHANAAUSoU.$S~ w ~ ~b 9 > ~~~~~~\ DE HUACHII) ... MoNT E , Ni -~~~ II *, X> - , Z>< @,^oft N. e a,. tea *.' '' \ \ , .O' f, o V N~~~~~~~ PNOVINOLA NDR YUN3AS t - w*° ' - i , >s u .... _ > ~i .7 \ DEPARTAYENTo D COCHANAUNA e CERS^51 SO, i I ;2 \i . ~~~~~~~~~~~~EiflTIAL 7S tRA .e S- 7 _E COCKARANI NORtGYUNGAS |O371_AS a1 | # 961~~~~~~~~~~~~~~~~~ALTENTV 'lb__ < 51 i ~~~~~~~~~~~~~~~~REEIITIAL 51 0 27 voTepl I ' De COCHABAMBA a J tS -< A -1) -1I--&-- PAmurivE, 9 2 K -RF&-" = 'AL> (3 nir M O N T B S! =3 . . X > | / E * S65i;DITIAL | W 1S3 1 1 YEIIR SO f2 l M XWTOTAL DiO" llm -~, '9~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~EMNSDt REERN PAR a'' 1'' b CNTrALS WANC1NE ,^- | AGROYUNGAS -~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ PR.O.PINCIAt INOUISIYILAPG c~~~~~~~~ ~ 1MBOl OGIm Am &EUMA ,;- / ', -'OLAEE P W % [ {t (.Z z.......D .POtcAtQl L A F~~~~~~~~~ ~~~~~~~~~~~~~~~~~~~~~~~~~~~ROTIEV 2, P V-S-CiA SU YU. .,AS t t|_ -\,@* IWECANg rY.eoo 1,t* CA.T. H.NCN AG _ GA OEQASAN MIGUrJQIA M UACKI Is~w a N \ I1 9 \ - | s < * - : ...'" 0gU ::, N. flOV3NQZ& A DEPAROTAMENTO DE COCHA_ .M'A \ \-:, %''aotX /5wi^M 9 ,,22"K, 219 ml I 0141$ 3g3e s X,i / / NION A ,O;,' '-,07 n' V' \, | \ -- veSt t!'t. < M w4¢" 6. g >-o- U/ , 230 M : iiTiil15 % -,4)>'\''\ el\ I ZIISTEIITIAI 12 W 0 2-S1,5 -s9 \\ '_M. 9 0 35 .~ PROVINCFA SUR YUNGAS I * j A~Lt; - 971230 1-- ( I 8ALTERNATIVO I 1990 usimrtm. P~~~~~~~~~~~~~~ROVINCIA INOUISIV W IAL! 97 MDI'£ 7 , -%- "'j - . / ~~~~~~~~~~~~~~~~~~~~~~SIMBOLOGIA vow."I M-672 M 3a s _ _ I 1 3 Wl/ILYI"D_1107m 5 i _. s - ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~4 ,; \ i ........... \~~~~~~~~~~. ...... Li- SEM-S. PAZA REV.DN 1UNE 5-'-0 |__TRMN_ DE REFERENCIA PAGRAUGA VJTDII8Ph/i\4} / / !~~~~~~~~~~~~~~~~~~~~ETUI IENATEGRA CIIERt DI;L957 |3-o |\\ >/ .\ Esi7lDl W < v w { 69 i2> tfl fa§ /PROVINCIA INOUIStV$LAPA wITIAL J7 Isc7n \ > /ff t-OX; * (t§41 *b) t! d7 ; ? . SiMVB 1 LOGI9 - > CMO - SA u\ XNU CHi \< -' \~~~~ WN7 -- N.t_, , N : "' L.% *t - ,C." NOROtt Y U.! >. ""DP^ST DC COCHABAMBA * ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ - / / co''n-b .:\ \ i ; -.,. ,\ . $iZ - ) z 9 \ *ON j' E's,f.0K'4,A,_,. lwwlna^lN- / -a \~ -I § TVII II § x 5#>\>< \ I' - . V o' ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ c .o "5' N, [ [ KS~~~~ID E \4a -* * , *D\Ef>__*l OPRTAMERTO 0COHRA VM ONTi,, 11 0 211 TIA M Ul 1 1- \ ,t g1"' * ' _ I NOR Y(cR5S F V 2t>1l ^'"> . ~~~~~~~~~~~~AGROYUNGAS CANTMIX 141 H UA~cANg , ^9 4P1 .ESTUDIO PRELIMINAR ,AL 5w M 27 2 7/, *- _#_- ALTERNATIVO I1 POI4IINUSV L PA J TIVE 3 S2 Jg / . . TIV ff~~~~~~~~~~1= IL 191 mIA ! IN 15 KW Ta XC. t73 2.s2b / y J I Jsl t eSR i ~YAR: II s I, __ i , I T1/ 'E R - _ ' _TA - _ _ 9; a-=6 VE 14E 1 5-5S90 PaI %,/ .D 1-*|MIARLEGO LASUT| RESIDENTI'AL,/| ESUIONTGALEEEGI (_ ta{ j__.......^ ¢.PROVINCIA SNURSV _Y|NLASPA PR TT 10 #4 ; § e C.... f sR DDM ~ ~ ~ ~ ~ ~ ~~~~- , =TSTA T. ime, 000 |~~~~~ ~ ~~~~~~~~ 12 M