Dscument of

The World Bank

FOR OFFICIAL USE ONLY

Report No. 8523-BD

STAFF APPRAISAL REPORT

BANGTADESH

THIRD RURAL ELECTRIFICATION PROJECT

APRIL 9, 1990

Industry and Energy DivisionCountry Department IAsia Region

This document bas a restricted distribution and may be used by recipient only in the performanee oftbeir offiWial duties. Its contents may not otherwise be disclosed without World Bank authorization.

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BANGLADESH

THIRD RURAL ELECTRIFItVTION PROJECT

CURRENCY EQUIVALENTS

Currency Unit - Taka (Tk)Taka 1.00 - US$0.0295Taka 33.9 - US$1.00Taka 1.00 - Paisa 100

WEIGHTS AND MEASURES

kV - Kilowatt (- 1.341 horsepower)mW Megawatt (thousand kilowatts)MVA - Megavolt-Ampere (thousand kilovolt amperes)kWh - Kilowatt hour (- 860.42 kcals)GWh . Gigswatt hour (million kilowatt hours)kV - Kilovolt (thousand volts)TOE - Ton of oil equivalent (thousand kilograms oil equivalent)kcal = Kilocalorie (- 3.968 British thermal units (Btu))km = Kilometer (0.6214 mile)MCFD - Thousand cubic feet per dayMMCFD - Million cubic feet per dayTCF = Trillion cubic feet

ABBREVIATIONS AND ACRONYMS

ADB - Asian Development BankACRE - Area Coverage Rural ElectrificationBPC - Bangladesh Petroleum CorporationBPDB = Bangladesh Power Development BoardCIDA - Canadian International Development AgencyDCA = Development Credit AgreementlIRR - Economic Internal Rate of ReturnERL - Eastern Refinery LimitedESAC = Energy Sector Adjustment CreditpY - Fiscal YearGOB - Government of BangladeshICB - International Competitive BiddingKFAED - Kuwait Fund for Arab Economic DevelopmentKfW - Kreditanstalt fuer ViederaufbauLCB - Local Competitive BiddingLIB = Limited International BiddingLPG - Liquified Petroleum GasLRMC v Long Run Marginal CostKMEM - Ministry of Energy and Mineral ResourcesNRECAIGC - National Rural Electric Cooperatives Association/Gilbert CommonwealthODA - Overseas Development Administation (UK)OECF - Overseas Economic Cooperation Fund (Japan)OPEC = Organization of Petroleum Exporting CountriesPBS - Palli Bidyut Samity (Rural Electrification Cooperative)REB - Rural Electrification BoardSFD = Saudi Fund for DevelopmentTOR - Terms of ReferenceTFYP = Third Five Year PlanUNDP - United Nations Development ProgrammeUSAID = United States Agency for International Development

REB's Fiscal Year X July 1 to June 30

FOR OFFICIAL USE ONLY

BANGLADESH

THIRD RURAL ELECTRIFICATION PROJECT

CREDIT AND PROJECT SUMMARY

Borrower s People's Rep.blic of Bangladesh

Beneficiary s Rural Electrification Board (REB)

Amount t SDR 79.6 million (US$105 million)

Terms s Standard, with 40 years maturity

Cofinancing s USAID, under an existing commitment until July 199:,and thereafter under an extension to be confirmed byDecember 31, 1990, of the ongoing technical assistancegrant.

Onlendins Terms : The Government of Bangladesh (GOB) would relend theproceeds of the credit to REB for a period of 33 yearsincluding a grace period of 8 years, at a rate of0.752 per annum (capitalized) during the grace periodand 22 during the repayment period. The assets of thecompleted schemes would be transferred by REB to therespective Rural Electrification Cooperatives (PalliBidyut Samities--PBSs) on the basis of sub loans. Thesub loans would be for a period of 30 years. includinga grace period of 5 years, at a rate of 0.75? perannum (capitalized) during the grace period and 32 perannum during the repayment period. GOB would bear theforeign exchange risk.

Project Description t The project would include: (a) installation ofdistribution networks in four new PBSs (Comilla,Dinaipur, Manikganj and Cox's Bazar), all of whichshow good prospects for financial viability;(b) expansion of five existing PBS networks andintensification of existing PBS networks financed byIDA under the First Rural Electrification Project(Cr.1262-BD); (c) rehabilitation of distribution linesand substations to be taken over from BPDB; (d) tech-nical assistance to strengthen REB and PBSs;managerial, financial and institutional performance,and training; and (e) construction of REB centralfacilities (offices, training center and workshop/warehouse).

Risks s No major technical risks are foreseen. The majorimplementation risk concerns possible constraints onGOB's local funds to support the program. This riskhas been mitigated by reducing the program's overallsize, by improved planning and construction super-vision by REB and by extending the implementationperiod from five to seven years.

This document has a restricted distribution and may be used by recipients only in the performanceof their official duties. Its contents may not otherwise be disclosed without World BakQauthorization.

Local Foreign Total

-------(US$ Million)------Estimated Costs

New PBSs 20.2 42.8 63.0PBS Extension/Intensification 11.3 25.8 37.1RiB Central Facilities 8.8 0.5 9.3Technical Assistance and Training 2.0 10.1 12.1

Base Cost 42.4 79.1 121.5

Physical Contingencies 2.1 4.0 6.1Price Contingencies 14.5 18.1 32.6

Total Project Cost al 59.0 101.2 160.2

Interest during Construction 3.3 - 3.3

Total Financing Required 62.3 101.2 163.5

Financing Plans

IDA 19.1 85.9 105.0Cofinancing 2.4 15.3 17.7GOB 40.8 - 40.8

Total 62.3 101.2 163.5

a/ The total project cost net of taxes and duties (US$15.4 million) isUS$144.8 million.

Estimated Disbursements

IDA FY 91 92 93 94 95 96 97 9s

Annual 2.3 10.9 18.8 22.6 22.3 16.1 9.0 3.0

Cumulative 2.3 13.2 32.0 54.6 76.9 93.0 102.0 105.0

Economic Rate of Returns 172

Maps IBRD 22134

BANGLADESH

THIRD RURAL ELECTRIFICATION PROJECT

STAFF APPRAISAL REPORT

Table of Contents

Pase No.1 ENERGY SECTOR

A. Sectoral Importance . ... . . . . . .......... . 1B. Energy Resources and Supply . 1.... . ..... 1C. nergy Consumption ... . * ... .............. 2D. Organization of the Energy Sector .3...... . 3S. Energy Pricing . . . . . . . . . . . . . . . . . . .4F. GOB's Energy Sector Strategy .S........ 5G. Bank Group Involvement in the Energy Sector SH Cofinancing and Donor Coordination ......... 7

II. THE BENEFICIARIESA. Rural Electrification 7

Baclkground . . . . . . . . . . . . . . . .. 7

Future Developments .... . . . . . .... . 8B Rural Electrification Board g...4.. .9

Organisation of RlB .... . . . . . . . . . . . 9Lending Operations to PBSs 9Subsidies . .4. . . . . . .4.4 44 * . . . *.* . *.. 10Scheme Selection and Implementation . . . . . . . 10RIB Supervision and Honitoring of the PBSs . . . 11Impact Evaluation of the RE Program .. 11Coordination between BPDB and REB. 12Transfer of BPDB Lines to PBSs 12Training.. 1* . ... .*. . *. . . * . . .. . **... 13

C. Palli Bidyut Samlties-PBSs (Rural ElectrificationCooperatives) ..*. . .*. . . . . . . . . . .. . . 13Organization Structure .. 13PBS Responsibilities ...... 4... 13Losses in PBSa System. 14Advisory Consulting Services 14

III. THE PROJECTProject Setting .... . . . . . . . . . . 14Project Objectives ........ .... . ..... 15Project Description .... . . .... . . . . . . . 15System Design . .. . . . . . . . . . . . . . . . 16Project Cost . . . . . . . *. . .... .16Project Financing .... . ............. . 18Project Implementation and Consulting Services . . 16Procurement . . . . . *. .. .. . . . . . . . .. . . 19Disbursement ; . * . . . . . . . . . . . . . . . . . 20Developmental Impact . .............. . 21Project Monitoring ... 22Risks . . . . . . . .............. ... . * * .4..... 22

This report is based on the findings of an IDA appraisal mission In December1989 comprising Messrs./Mnes. S. Oushes (Senior Power Engineer), MG. Webb(Principal Energy Economist), S. Mukherji (Financial Analyst), L. Haistre(Consultant, Power Economist) and B. Wu (Consultant, Financial Analyst).Mrs. A. Thornton supervised the production of the report.

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IV. FINANCESA. Rural Electrification Board . . . . . . . . . . . . . 22

Financial Objectives .e................ . 22Past Results and Present Position . . . . . . . . . 22Future Performance ......................... ... 25Accounting Systems and Organization . . . . . . . . 26External Auditing .... . . . ............... . 26Insurance Arrangement . . . . . . . . .. . . . . . 26

B. PBSs . . ........ ;t......................... 27Past Operation lesults ........ .... .. 27Auditing . . . . . . . . . . . . . . ..... . . 28

V. PROJECT JUSTIFICATIONA. Electricity Demand Forecast . . . . . . . . . . . . . 29

Demand Forecast for Rural Electrification Program . 29Demand Forecast for the Project PB$s . . . . . . . 30

B. Least Cost Analysis . ............... . 30C. Economic Internal Rate of Return . . . . . .. ... 31D. Sensitivity and Risk Analysis . . . . . . . . . . . . 32E. Justification of Bank Group Involvement . . . . . . . 33

VI. SUMMARY OF AGREEMENTS REACHED AND RECOMMENDATIONS . . . . 34

ANNEXES

2.1 Bangladesh Historical Growth in Demand Energy Generation and Sales.2.2 Bangladesh Generating Capacity and Energy Forecast.2.3 Bangladesh Maximum Demand and Generation Forecast.2.4 RED Organization Chart.2.5 REB Staffing.2.6 Timing, Cost and Financing of the RE Program.2.7 Selection Criteria for Areas to be Electrified.2.8 Status of Transfer of BPDB Lines to PBSs in Operation.2.9 REB Training Program.2.10 PBS9 Organization Charts.2.11 PBSs Characteristics.

3.1 Project Details.3.2 Project Cost Estimate.3.3 Project Implementation Sc.edule.3.4 Disbursement Profile.

4.1 Past Financial Performance and Financial Projections for REB.4.2 Assumptions used for REB Financial Projections.4.3 Financial Projections for the Project PBSs.4.4 Assumptions used for the PBS Financial Projections.4.5 Key Performance Indicators for Selected PBSs.

5.1 Detailed Analysis of PBS Past Demand.5.2 Economic Internal Rate of Return.

6.1 Data and Documents available in Project File

TABLES

3.1 Project Cost S"uiary.3.2 Project Financing Plan.3.3 Procurement Arrangements.

4.1 REB Operating Performance: FY85-894.2 REB's Projected Operating Performance FY90-954.3 Key Performance Indicators for Selected PBSs--19881894.4 Project PBSs--Projected Operating Performance FY94-2003

5.1 FY82-89 Development of PBSs' Electricity Sales5.2 Demand Forecasts for PY90-2000

TD RURAL IICTRIFiCAMION PROJEOT

STAFF APPRAISAL RIIPOR

1. ENERGY SECTOR

A. Sectoral Importance

1.01 The energy sector plays a key role In Bangladesh's development.Given its severe resource limitations and persistent balance of paymentsconstraints, the country needs an efficient energy sector to promoteeconomic growth, mobilize resources for sector entities and the Governmentbudget, and reduce foreign exchange outlays on energy Imports. However,shortages of local resources, caused lrimarily by the under-pricing ofenergy and inadequate cost recovery actions, and the absence of a coordin-ated plan for channeling foreign assistance to priority investments, haveimpeded the achievement of energy targets. Further, in the past, unreli-able power supply has constrained overall economic growth, and only 82 ofthe population has access to electricity. The Government's Third Five-YearPlan (TFYP) (FY86-90) recognized the need for the energy sector'saccelerated development and earmarked about 162 of total public allocationsfor the sector (para. 1.13).

B. Energy Resources and SUDplY

1.0, Bangladesh's principal commercially exploitable energy resourcesconsist of substant'al reserves of relatively low-cost natural gas andlimited hydropower potential. There are also potential oil, coal and peatresources for which the economic feasibility has yet to be determined,although this is the subject of ongoing studies for coal and oil. Atpresent, substantial quantities of oil are still imported. About 402 oftotal energy supply is from commercial resources, and the remainder is fromtraditional fuels in the form of crop residues, animal dung and wood. InFY87, domestic sources (natural gas and hydropower) accounted for about 602and imported sources (oil and coal) for about 402 of commercial energysupplies.

1.03 Natural Gas and Oil. Natural gas output increased from 45 billioncubic feet (bcf) in FY80 to about 147 bcf in FY89 (14Z annual growth rate).It is now the main source of commercial energy, accounting for about 592 ofsupply compared to 36Z in FY80. Estimated recoverable reserves, all locatedin the east zone, are about 10 trillion cubic feet (tcf), sufficient to meetincremental demand for another 15 years and to supply all existing gas-using projects and those to be commissioned in the 19909 throughout theirdesigned lives. Further, prospects are good for increasing the reserves toat least 15 tcf. The Government of Bangladesh (GOB) has accorded highpriority to these reserves' development: the gas exploration and developmentprogram is reviewed annually with IDA in accord with an agreement under theEnergy Sector Adjustment Credit (ESAC) (Cr.1999-BD). Oil was discovered inthe Sylhet gas field area in 1989; however, it is too early to estimate thefind's full significance. Under the Petroleum Exploration Promotion Project(Cr.1402-BD) GOB prepared promotional packages aimed at attracting

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international oil companies to undertake petroleum exploration. Tnepromotions, which were carried out in London, Houston and Dhaka in June/July1989, were well attended and more than 20 companies purchased explorationdata packages. By January 15, 1990, the closing date for submission of theoffers, however, GOB has received only one offer and is consideringextending the closing date. With these efforts petroleum imports are beingreduced. In FY88 they claimed about 13Z of the country's limited foreignexchange earnings, compared to 242 in FY86.

1.04 Coal and Peat. Several thick coal seams at depths of less than 200meters have recently been located in the Barapukaria area of DinajpurDistrict in the vest zone. With the assistance of consultants funded by theOverseas Development Administration (ODA), UK, GOB is assessing the tech-nical and economic feasibility of mining this coal. The consultants' mid-1988 report estimated total potentially mineable resources of 265 milliontons, with an average he-t value of 11,400 British Thermal Unitsllb.Following the report's review by GOB, ODA and IDA, a full feasibility study,to be completed by December 1990, was initiated. Good peat deposits areknown to exist in the Faridpur and Khulna districts in the vest zone. TheBangladesh Power Development Board(BPDB) is assessing the potential formining and processing peat and installing a small experimental generationplant.

1.05 HYdropower. Bangladesh's hydropower potential is estimated to beabout 1,500 GVh/year, of which 1,050 GWh/year has been developed with theinstallation of 330 MS capacity on the Karnafuli river at Kaptai (nearChittagong). Two other prospective hydro sites have been investigated inthe same area; however, since their development would require the relocationof about 30,000 people, no detailed engineering studies have beenundertaken.

1.06 Traditional Fuels. Per capita biomass supplies are continuouslydiminishing, and Increases in forest-based fuelwood or a major shift tocovmercial fuels are not viable options to meet the supply gap due to thehigh population density and low income levels. However, the substitution ofcommercial fuels for traditional fuels is occurring slowly. It is thereforeimportant for GOB to improve biomass recovery and conversion efficiency,e.g., in cooking stoves, charcoal kilns and other wood-burning equipment.GOB has agreed, under the joint World Bank/UNDP Energy Sector ManagementAssistance Programme, to undertake an inter-fuel substitution study toassess the micro and macroeconomic impacts of substitution and formulate aleast-cost strategy for meeting commercial energy needs. Funding for thestudy is presently bei<>g sought.

C. Energy Consumption

1.07 Bangladesh's per capita commercial energy consumption of about 42kilograms of oil equivalent per annum is among the lowest in the world(about one-ninth of the average for low-income countries). In FY87, grosscommercial energy consumption was about 4.6 million tons of oil equivalent,of which natural gas accounted for 54?, petroleum 38S, hydropower 52, andcoal 3S. However, with the accelerated development of gas supplies, theconsumption of coamercial energy increased rapidly at 10.8? a year duringFY83-87, compared with annual real GDP growth rate of about 4.1?. The GDP/

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commercial energy elasticity was thus rather high at about 2.6, compared tothe average of about 1.1 for all developing countries. The bulk of gasconsumption in FY88 was in power generation (442) and fertilizer production(362); however, other industrial, commercial and domestic uses are expandingsteadily. There is considerable inefficiency in commercial energy use andhence substantial scope for improvement, particularly in industry, petroleumrefining and electric power transmission and distribution. This issue isbeing addressed through the Industrial Energy Efficiency Project(Cr.2942-BD), the Pover Distribution (16 Towns) Project (Cr.2016-BD), andthe proposed Power Distribution and Rehabilitation Project (FY9lS). Totalconsumption of traditional fuels (biomass etc.) declined by 52 during FY83-87, principally because of a sharp fall in the use of rice hulls.Consequently, total energy consumption increased by only 2.4Z a year duringFY83-87, aru t.he overall GDP/energy elasticity was about 0.6, comparable tothat for all developing countries.

1.08 With increased gas availability and GO8's policy of substituting gasfor imported petroleum products, the country's dependence on imported energywas significantly reduced during FY8O-87 from about 60? to 402 of the totalcommercial energy needs. Further, the share of crude oil and petroleumproducts in commercial energy supply declined from 552 in FY80 to 38Z inFY87. However, petroleum products are still a dominant source of energy inthe transportation sector. Despite this decline in the relative importanceof petroleum products and the global decline in petroleum prices, petroleumimports continue to be substantial and claimed about 132 of the country'sforeign exchange earnings in FY88 (para. 1.03).

D. Organization of the Energy Sector

1.09 The principal institutions responsible for energy sector policy are:(a) the Planning Commission, which is responsible for macroeconomicplanning, including the Five-Year Plans and the Annual Development Plans(ADPs), and for approving all capital investments costing more than Tk 5.0million (US$152,000); and (b) the Ministry of Energy and *U;neral Resources(MEMR), which is responsible for overseeing the operations of the fourprincipal publicly-owned energy sector entities which produce, transport anddeliver most of Bangladesh's commercial energy. The entities are BPDB, theRural Electrification Board (REB), Petrobangla, and the Bangladesh PetroleumCorporation (BPC). BPDB is responsible for electricity generation, trans-mission and distribution, except in areas served by REB. REB is responsiblefor the construction of rural electrification schemes and organizing pros-pective consumers into semi-autonomous cooperatives called Palli BidyutSamities (PBSs) which buy electricity from BPDB and distribute it to theirconsumers. Petrobangla is responsible for the exploration, production anddelivery of natural gas and the exploration and development of oil and solidminerals, including coal. Under the ESAC, GOB reorganized Petrobangla as aholding company, holding equi.y in a new set of operationally independentoperating companies established along functional lines for exploration anddrilling, production, transmission and distribution of gas. BPC is respon-sible for purchasing and refining crude oil and marketing petroleumproducts. The refining operation is carried out at Bangladesh's onlyrefinery by Eastern Refinery Limited (ERL), a BPC subsidiary. Liquefiedpetroleum gas (LPG) is bottled and sold to private marketing companies byLPG Limited, another BPC subsidiary. Three other BPC subsidiaries marketpetroleum products and LPG.

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1.10 The exceptions to public sector domination of the energy sector arein traditional energy and in the distribution of petroleum products handledby BPC subsidiaries, which rely primarily on privately-owned road and rivertankers for transport and on private dealers for local retailing. Althoughthe petroleum distribution system is operating satisfactorily, the expectedfuture growth in demand for cometc±al energy may stretch the system'scapability to meet demand efficiently. Consequently, there may be scope forincreasing private sector participation. Private sector participation isalso being encouraged in other areas of the energy sector. Private sectorinvolvement in the distribution of LPG in Ehulna is being promoted under theRefinery Modification and LPG Recovery and Distribution Project (Cr.1749-BD);this private asector role will be enhanced under the proposed Bakhrabad LPGRecovery and Distribution Project (PY91). Further, GOB is seeking toincrease private oil exploration through promotional packages under thePetroleum Exploration Promotion Project (Cr.1402-BD) (para. 1.03).

E. Energy Pricing

1.11 GOB's key energy pricing policy objectives include economicefficiency, resource mobilization and equity. Accordingly, it has beenIncreasing energy prices to reflect the costs to Bangladesh of meetingconsumers' energy requirements, while minimizing the adverse effects on low-income consumers. In accordance with this policy, gas prices were increasedby an average of 18? annually during FY86-90. In FY90, the average gasprice is about Tk 43.5/MCF, which is slightly abov- the estimat.. long-runmarginal cost (LRMC) of supply (Tk 40.0/MCI). In accordance with itsefficiency and resource mobilization objectives, GOB agreed under the ESACto ensure that the weighted average domestic price (net of distribution,marketing and other handling costs) is always at least 115? of the borderprice. In December i989 this ratio was 111, marginally below the agreedlevel.

1.12 Turning to electricity prices, BPDB's tariff rates for each consumerclass are unifom throughout Bangladesh, while each PBS sets its own tariffrates with the approval of REB. Electricity tariffs have been raisedfrequently in recent years. During FY80-90, BPDB's average tariff rateswere increased at an annual average rate of about 12.52 in nominal terms andabout 2.52 in real terms, with a total increase of about 28? in real terms,while rates for energized PlSs were increased at average annual rates of 13?in nominal terms (4? in real terms) during FY84-90. BPDB's average tariffis now Tk 2.16/kWh and that for PBSs is Tk 2.60/kWh.

1.13 Under the Second Rural Electrification Project (Cr.1633-BD) and thePower Transmission and Distribution Project (Cr.1648-BD), GOB, BPDB, and REBagreed to carry out a tariff study based on LRMC and to Implement agreedrecommaendations. Coopers and Lybrand Associates Ltd. (UK), completed thestudy In August 1986 and highlighted various deficiencies, including anexcessive number of tariff categories, tariff rates lower than the economiccosts of supply, significant cross-subsidization, an-d little incentive toreduce consumption during the system's peak period. Based on the tariffstudy, GOB reformed power tariffs in early FY88. For BPDB, a new simplifiedtariff was introduced In August 1987. The number of tariff categories wasreduced from 19 to 10; new two-rate time-of-day tariffs for 33 kV and 11 kVconsumers and an optional time-of-day tariff for large low-voltage consumers

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were i 'tced; and the sizes of the subsidized blocks of energy forresidenti. consumers were greatly reduced. In the PBSs, tariffs forresidential consumers were changed from a constant rate to three blockIncreasing rates to limit electricity consumption at heavily subsidizedrates. The new tariff structures greatly improved the signals whichelectricity prices give to consumers &bout the costs to Bangladesh ofmeeting their consumption requirements. In addition to the restructuring,PBSs' average tariff rates were increased by about 251 on July 1, 1987, andon August 1, 1987 BPDB's tariffs were increased by about 17X. Subsequently,electricity tariffs for all consumers were increased by about 32 on July 1,1988 as a result of the FY89 gas price increase. Further, effective July 1,1989, PBS tariffs were increased by about 11?, and BPDB's tariffs wereincreased by about 7.51. The FY90 tariff increase was accompanied by adoubling of the kWh excise tax rate to Tk 0.10 to mobilize resources for theBudget. Following these tariff Increases, BPDB's overall average tariffrate is about 70? of LRHC, and that for PBSs is about 562 of LRMC. BPDB'stariff rates for supplies to industrial, commercial and large (above 200kVhlmonth) residential consumers esceed LRNC while the tariff rates forsmall residential consumers and bulk rates to PBSs are below LRMC. Despitethe series of tariff increases, neither BPDB nor most PBSs have been able tomeet their financial covenants (paras. 4.01 and 4.11).

F. GOB's Energv Sector Strategy

1.14 Recognizing the importance of improving energy supplies to meetforecast demand, GOB accorded high priority to the energy sector in the TFYP(para. 1.01). The TPYP's principal energy objectives are to: (a) acceleratethe development of domestic natural gas resources to reduce the country'sdependence on imported oil; (b) improve the reliability and quality of powersupply and reduce power system losses; (c) improve energy use and efficiencythrough conservation measures and appropriate pricing policies; (d) meetenergy demands at least cost to the economy; (e) improve the energy sectorentities' performance; and (f) encourage the private sector's participationIn the energy sector, particularly in gas and oil exploration. Followingdonor-funded studies, GOB has implemented, with some measure of success,agreed recommendations regarding policy changes, capital investments,pricing decisions and resource mobilization (paras. 1.09 to 1.12). However,due to over ambitious and uncoordinated investment plans and local currencyconstraints, implementation of capital investment programs have notproceeded as planned. To underscore its commitment to the sector's develop-ment, GOB allocated Tk 61 billion (US$2.0 billion equivalent) at FY85 pricesfor energy investments under the TFYP. Energy accounts for 162 of the totalplan allocation, compared with about 12? under the Second Five-Year Plan,and is exceeded only by the allocation to the agricultural sector.

G. Bank Group Involvement in the Energy Sector

1.15 Lending in the power and gap subsectors has been designed to:(a) strengthen investment planning to meet forecast demand for gas andelectricity at least cost, (b) improve sectoral institutions' performanceand provide training, (c) optimize the use of available energy resourcesthrough appropriate energy pricing and conservation measures, (d) appraisediscovered gas fields and optimize their development, and (e) attractprivate capital to intensify oil exploration.

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1.16 Since 1973 IDA has supported GOB's energy strategy through 13credits, amounting to US$858 million equivalent, representing about 152 ofIDA resources committed to Bangladesh. Seven of the credits were for powerprojects aggregating to US$390 million, while the remaining six credits,totalling US$305 million, were for other energy projects. The credit forthe Greater Khulna Power Distribution Project (Cr.934-BD) was closed onJune 30, 1986. The project completion report, which will be issued in mid1990, shows that changes in design and procurement delays occurred due toinadequate system studies and detailed design. Based on that experience.BPDB has strengthened its planning and design organizations to ensure thatall major system studies and bid documents are prepared in a timely manner.Except for the procurement problems in the Project's initial stages, BPDB'sproject implementation was satisfactory. Implementation of the AshuganjPower Project (Cr.1254-BD) was very good; the project was completed ahead ofschedule and below the estimated cost. Both projects generated the expectedbenefits and contributed to the power subsector's more efficient develop-ment. Implementation of the Rural Electrification Project (Cr.1262-BD) isnearly complete and all the seven rural electrification cooperatives (PBSs)financed under the project are in operation. The Second RuralElectrification Project (Cr.1633-BD) is under implementation with ascheduled completion by 1991/92. Both projects are about 12 to 18 monthsbehind the schedule envisaged at appraisal. REB and PBSs' financialperformance have been unsatisfactory mainly because of improper financialpolicies, non transfer of BPDB lines and customers to PBSs in rural areas,and lack of coordination between BPDB and REB. These issues will beaddressed under the proposed Project (paras. 2.14, 2.15 and 4.03).

1.17 Although considerable progress was achieved through the aboveprojects, they did not provide an effective means to rationalize the entireenergy investment program and address issues affecting the overall organiza-tion of Bangladesh's power and petroleum subsectors. Thus during FY87, GOBand IDA developed a comprehensive energy sector program, including invest-ment planning, institutional development, and energy pricing and resourcemobilization, to be implemented under the ESAC. The ESAC was made effectivein June 1989 and all of the first tranche was released by December 31, 1989.A second tranche review mission visited Bangladesh in that month. AlthoughGOB had made substantial progress in meeting the release conditions,especially concerning energy pricing and the reduction of power systemlosses, IDA decided to delay the second tranche release pending satisfactionof other agreements. Based on recent progress, the release could occur byJune 30, 1990. Since the ESAC provides a policy framework for investmentprojects, they need relatively few, mainly project-specific, conditions toensure their effective implementation.

1.18 Under the ESAC, it has been agreed that new capital investmentswould be focused on priority projects under an agreed three-year rollingPriority Investment Program (PIP). GOB has included this Project in the PIPfor FY90-92 since GOB accords high priority to improving the econouicconditions of the rural population and to furthering the substitution ofindigenous energy (basically electricity generated using natural gas) forImported petroleum products.

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H. Cofinancing and Donor Coordination

1.19 Under Cr.934-BD, Cr.1254-BD, and Cr.1586-BD, there has been sig-nicant cofinancing between IDA and the Asian Development Bank (ADB),Ireditanstanlt fuer Wiederaufbau WKfV), Canadian International DevelopmentAgency (CIDA), Kuwait Fund for Arab Economic Development (KFAED),Organization of Petroleum Exporting Countries (OPEC), and the United NationsDevelopment Programme (UNDP). Furthermore, during the preparation of theESAC, donors representing twelve major bilateral and multilateral agenciesattended several coordination meetings. This coordination resulted in KfWcofinancing the ESAC. There was no cofinancing under Cr.1262-BD andCr.1633-BD since the various donors involved in the RE program providedfinancing under parallel operations (para. 2.03). However, despite the factthat the schemes were carried out in parallel, coordination among the donorswas good and led to adopting uniform onlending terms and consistentfinancial covenants for all the RE projects.

II. THE BENEFICIARIES

A. Rural Electrification

Background

2.01 Although in 1976 over 902 of Bangladesh's population lived in ruralareas, and agriculture accounted for nearly 601 of its gross domesticproduct and employed over 751 of the labor force, less than 31 of the ruralpopulation had access to electricity. At that time, GOB decided to extendthe public supply ef electricity to rural areas to improve the quality oflife of the rural population and stimulate economic growth through thedevelopment of agriculture and small-scale agro-industries. Following thatdecision, GOB created REB in 1977 to carry out a national program of ruralelectrification (para. 2.06). In 1978, a comprehensive rural electrifi-cation master plan was developed by RED, with assistance of USAID-financedconsultants, National Rural Electrification Cooperative Association andGilbert Commonwealth (NRECAIGC). The plan envisaged the country-wide ruralelectrification in five phases by year 2000. Because of resourceconstraints the target date for program completion is now 2005 and may bedelayed further.

2.02 Rural electrification under the plan is based on the concept of'Area Coverage Rural Electrification' (ACRE), involving the design of abasic distribution system to provide a backbone system that can cater forrapid increases in the number of consumer connections. The ACRE conceptinvolves the development of autonomous member-owned rural electric coopera-tives (PBSs), each of which covers an area of 900-1,300 square km. and hasbetween 20,000 and 30,000 members. Each PBS includes three to fiveupazilas, which are administrative districts. The formation of PBSs hasbeen progressing smoothly under REB guidance and its consultants, althoughit involves a lengthy and laborious process at the local level in insti-tution building and training. The PBSs are subject to supervision andcontrol by REB, which is the lending and construction institution.

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2.03 The rural electrification master plan envisages the creation of 62PBSs by FY200S. Phase I was completed in 1986, Phase II is expected to becompleted in 1989, and Phase III is now underway with scheduled completionin 1992193. These three phases cover about 402 of the geographical ruralarea with a population of 31 million. Phase I was financed by USAID(US$69.3 million for 13 PBSs), IFARD (US$30.0 million for 8 PBSs), and ADB(US$7.2 million for the expansion of 2 PBSs). Phase II is being financed byIDA (US$48.0 million for 7 PBSs under Cr.1262-BD and Cr.l504-3-BD), USAID(US$50.0 million for 4 PBSs), and Finland (US$5.7 million for 1 PBS).Phase III, comprising the formation of 7 new PBSs and the extension andintensification of the Phase I and 1I PBSs, is under construction withfinancial assistance from IDA (US$79.0 million for 7 new PBSs and extensionof 5 existing PISs under Cr.1633-BD), USAID (US$60.0 million for theintensification of the 17 PBSs financed under their previous projects), CIDAand Saudi Fund for Development (SFD) (US$28.0 million and US$15.0 millionrespectively, for the extension of 8 Phase I PBSs financed by KFAED), andFinland (US$4.4 million for the augmentation of 22 existing substations).

2.04 By June 1989, 33 PBSs under Phases I and II had been connected tothe grid and were supplying over 396,000 consumers, of which 315,000 weredomestic, 56,000 commercial, 14,400 irrigation, 7,600 industrial and 3,000others (including public lighting). In FY89, total electricity sales were372 GWh (about 10 of BPDB sales) and were divided as follows: domestic/others 25S, industrial/commercial 502, and irrigation 252. Annex 2.1 giveshistorical growth in demand, energy generation and sales for Bangladesh, andshows the relative contribution of PBSs' consumption. While the sales havebeen significantly lower than that projected under the Second RuralElectrification Project, the average annual growth rate was 43Z during FY83-89. A major reason for the lower than forecast sales has been BPDB's delaysin providing power supply to newly constructed PBSs substations and inhanding over BPDB lines with associated customers to PBSs (para. 2.15). Theseven new PBS6 under Phase III have been organized and most of them areexpected to commence operation in 1990/91.

Future Developments

2.05 GOB is now considering the implementation of Phase IV of theprogram. In June 1988, REB completed the prefeasibility study for thisphase to cover an area of about 60,000 sq km. in 206 upazilas, includingabout 800,000 new connections. It identified 19 areas for the formation ofnew PBSs and 22 areas for annexation to existing PBSs. However, consideringthe economy's absorptive capacity and the ongoing program's scale, inFebruary 1989 MEHR reduced the program to 110 upazilas with 11 areas wherenew PBSs would be formed and 19 areas which would be annexed to existingPBSs. The Phase IV program is now planned to cover about 32.000 sq km. ofrural areas and provide service to about 435,000 consumers. Its estimatedcost is about US$350 million, including about US$250 million in foreigncurrency. It is planned to start in FY91 and to be completed by 2000. Inaddition to IDA financing for Phase IV-A, GOB is seeking additionalfinancing for Phase IV-B from ADB, IFAED, Japan, SFD and Finland. Annexes2.2 and 2.3 show forecast to year 2000 of BPDB generation capacity as wellas the impact of future sales to REB.

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B. Rural Electrification Board

Organization of REB

2.06 REB and PBSo are the proposed Project's prospective beneficiaries.RED is a government entity which was formed in 1977 with dual respon-sibilities as the implementing agency for constructing RE schemes and thefinancial intermediary and supervising agency after completed scheues arehanded over to the P8Ss (para. 2.11). It is responsible for the initiation,planning and implementation of rural electrification schemes within theframework of the rural electrification master plan. Its specific responsi-bilities include: (a) arranging finance for rural electrification schemes;(b) constructing new distribution systems and rehabilitating existingschemes; (c) organizing prospective consumers into PBSs and prescribingtheir by-laws; (d) establishing PBSs' technical and administrativestandards; and (e) approving their tariffs. Although RED's Ordinance alsoallows it to generate electricity to supply rural areas, it has not done soand has no firm plans to construct power stations. RnE's managementconsists of a chairman, three full-time members and four part-time members.GOB determines the chairman and members' period, terms and conditions ofappointment. REB's organization and staffing charts are shown inAnnexes 2.4 and 2.5. IDA considers its structure appropriate for REB'sactivities and objectives. Since the rural electrification program'sinception, NRECA, under financial assistance from USAID, has been supportingREB's development as a viable and effective organization. MRECA's contractwill expire on July 31, 1991; however, GOB has requested USAID to finance afive-year extension of NRECA's contract (para. 2.21).

2.07 The fragmentation of REB's headquarters in Dhaka in 16 rentalbuildings impedes effective management coordination and high productivity.Further, REB is considering computerizing some of its activities andrationalizing its working environment. The availability of suitable centraloffice facilities would greatly improve REB's productivity and effective-ness. Also, PBSs' increasing demands for maintenance repair services couldbe met at least cost by establishing a central, fully equipped REB workshop.To address these issues the proposed Project includes new headquartersoffices for REB, together with a new training center and workshop/warehousefacilities (para. 3.04(g)).

Lending Operations to PBSs

2.08 As of June 30, 1989, REB's investment in the rural electrificationschemes was Tk 7.8 billion (Annex 2.6). About 72S ox the financing require-ments were provided by external sources (para. 2.03), with the balance of28X covered by GOB contributions. To mobilize resources within thesubsector for the RE program's future phases, REB acted as a financialintermediary, administering funds allocated to the RE program. Uponcompletion and transfer of a scheme to a PBS, REB onlends the constructioncost of the scheme to the PBS. In the early years, onlending terms weredifferent for the various sources of financing. However, since 1983 allonlending arrangements have followed onlending terms first introduced underIDA Cr.1262-BD. Under these terms, Government contributions to the REprogram are passed on to REB as equity, while external financing obtained bythe Government is ='Aent to REB with a maturity of 30 years, including a

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grace period of 5 years, at an interest rate of 0.752 p.a. during the graceperiod and 21 p.a. thereafter. When a completed RE scheme is transferred toa particular PBS, the entire construction costs of the scheme are passed tothe PBS as a loan with a maturity of 30 years, Including a grace period of 5years starting from the date of PBS registration, at an interest rate of0.75Z p.a. during the grace period and 32 p.a. during the repayment period.In both cases, interest during the grace period is capitalized and added tothe loan principal. As of June 1989, REB had made loans of Tk 7.2 billionto PBSs.

Subsidies

2.09 The rural electrification program is subsidized in three ways:(a) through an operating subsidy during the first five years of a PBS'slife; (b) through the bulk supply tariff (BST) since the rate is below LRHC;and (c) through grants and soft onlending terms on loans to financeinvestment. Two of these subsidies, (a) and (b), are of limited duration.The operating subsidy only supports PBSs during their infancy, and the BSTsubsidy is being eliminated gradually through the phased increase of the BSTrate to LRMC. The subsidy inherent in the onlending terms is justified bythe fact that rural electrification program is of national interest and hasa high economic internal rate of return, although it requires a subsidizedinterest rate to be financiallv viable. However, in future such subsidieswould be limited and the PBSs Lhould be able to generate part of the fundsneeded for the RE program's expansion. GOB/REB agreed under the proposedProject that the individual performance agreements (para. 2.11) wouldinclude shorter repayment periods for those P8Ss whose cash position, aftermeeting operating expenses, debt service liability and payments into thereplacement reserve fund, would enable advance payments to be made againstthe debt service liability.

Scheme Selection and Implementation

2.10 To determine priorities under Phase IV-A, BEB selected 11 areasaccording to a rating system that -mphasiz-s existing infrastructure,availability of power supply and roads, ?Ad potential number of customers.The ranking approach, which was also us.,d in Phases I-III, is discussed inAnnex 2.7. For the proposed Project, GOB agreed to carry out ten-yearfinancial projections of the 11 candidate PBSs and to select only thoseshowing good prospects for financial viability. Following IDA appraisal ofthe proposed Project, a Project Proforma containing details or projecttargets, physical facilities, proposed financing and cost benefit analysisis prepared by REB. GOB's procedures require the Project Proforma to bereviewed by the Project Evaluation Committee (PEC) of the PlanningComuission and to be approved by the Executive Committee of the NationalEconomic Council (ECNEC). To ensure that project implementation would notbe delayed while obtaining necessary GOB approval and clearances, draftProject Proforma for the proposed Project were prepared by REB and approvedby PEC as a condition of negotiations. A condition of Credit effectivenesswould be GOB's approval of the final Project Proforma.

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REB Supervision and Monitoring of the PBSs

2.11 REB is responsible for the initial promotion of PBSs and exercisesstatutory control over them. This includes the supervision of their opera-tions, assiating with the implementation of technical and administrativecontrol systems which RUB has developed for the PBSs, and training PBSs'staff. Pollowing REB's implementation of a project, schemes are handed overto the newly created PBSs. REB lends the initial cost of the scheme,secured by a mortgage, to the PBS, provides loans to cover their workingcapital requirements, and arranges finance for PBSs' expansion. During thefirst five years of operation, an operating subsidy is provided by GOB.Under the uniform onlending agreement, all the PBSs, after the first fiveyears, are expected to earn sufficient revenue to cover operating expenses,including depreciation, and generate, after debt service and provision ofincrease in working capital, a surplus equivalent to at least 202 of annualcapital expenditure after the sixth year of operation. PBSs' actualfinancial results as well as projections made by Coopers and LybrandAssociates (C&LA) (para. 2.12) indicate that PBSs' financial performancewill vary widely, and that it would be more appropriate to set specifictargets in the form of Performance Agreements. During negotiations it wasagreed that REB will introduce procedures for the annual determination ofPerformance Agreements with individual PBSs, that it vould satisfactorilyenforce such Agreements and would each year monitor, to the Association'ssatisfaction, PBSs' performance against the targets. The financial targetswould include the year in which revenue should cover operating costs, debtservice, the level of self-financing to be achieved each year, accountsreceivable, accounts payable and system losses. It is anticipated that sometargets, such as those for operations and maintenance costs would be set atcommon levls for all PBSs. REB has established a Financial Planning Cellto prepare financial projections for existing and proposed PBSs using amodel developed by C&LA. For REB, the Financial Planning Cell would be incharge of preparing, negotiating and monitoring the Performance Agreementswith the PBSs. The Performance Agreements would include a target onaccounts pavable for power purchases, namely that such purchases would notexceed the total billed consumption of the preceding two months. Further,the agreement would include a target for accounts receivable which shouldnot exceed 3 months' average billing of the twelve preceding months (theseasonal effect of irrigation being taken into account). The introductionof Performance Agreements for all energized PBSs would be a condition ofeffectiveness of the proposed credit.

Impact Evaluation of the RE Program

2.12 REB has set up an Evaluation Cell in its Program PlanningDirectorate to assess the impact of completed rural electrification schemeson rural communities. A study of the 12 Phase I PBSs financed by USAID wascarried out in 1983 by REB's Evaluation Cell, USAID and Dhaka University'sInstitute of Statistical Research and Training. Further, an exploratorystudy of small scale industrial and commercial development in four PBSs wascarried out by the Bangladesh Center for Advanced Studies in 1988. Thestudy assessed the socio-economic changes which have occurred in ruralcommunities as a result of electrification. A comprehensive assessment ofthe RE program's overall developmental impact, including the strengtheningof REB's evaluation cell, is being carried out with USAID assistance. The

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results of the various studies indicate that ACRE program's major objectivesare being realized. However, many erergized PBSs are not financiallyviable. To address this issus, in 1988 USAID appointed consultants (C&LA),to study i.3s' financial policies and performance. The study concluded thatalthough the RE program as a whole could be financially viable, individualPBSs' financial performance would vary widely depending on consumer mix anddensity. The study made several recommendations to improve REB/PBSs'financial viability, which are being implemented by GOB/REB under thisProject.

2.13 NRECA prepares annual evaluation reports on the RE program'simplementation. The most recent report, covering 1988, identified a numberof problems* including the need to improve power supplies to PBSs, delays inhanding over BPDB's lines to PBSs, shortage of local currency for projectimplementation, and the need for a new headquarters complex for REB toimprove staff productivity and efficiency. These problems are beingaddressed under the proposed Project (paras. 2.07 and 2.15).

Coordination between BPDB and REB

2.14 Although BPDB's member (Distribution) is a part-time ex-officiomember of REB's Board, coordination between REB and BPDB has been ineffec-tive. Because BPDB has not supplied power to some substations constructedby REB under Phase II and III for long periods of time, newly constructedPBSs' distribution networks could not be energized. Although these problemswere anticipated under the Second Rural Electrification Project, BPDB failedto expand its transmission and distribution capacity in a timely manner toprovide reliable power supply to PBSs. Coordination between REB and BPDB atthe operation level needs to be improved to ensure that REB's expansionprogram ic consistent with BPDB's plans,and that PBSs participating in theproposed Project receive adequate power on time. As a condition ofnegotiations for the proposed Proiect. a joint MEMRtREB/BPDB engineering andplanning group has been created and is operational. A list of BkDBsubstations which need to be upgraded to provide timely supply to the PBSshas been prepared jointly by BPDB and REB.

Transfer of BPDB Lines to PBSs

2.15 In the planning of PBS distribution networks, REB assumes, inaccordance with the 1977 RED Ordinance, that existing BPDB 11 kV lines andcustomers within the PBSs areas would be handed over to the PBSs. AlthoughBPDB has handed over about 3,750 km of lines, there is a backlog of about1,700 km to be handed over (Annex 2.9). Further, several PBS villagesalready equipped with distribution networks cannot be energized because theBPDB lines, which are part of the supply system, have not been transferred.During negotiations a dated action plan for the transfer of BPDB lines toPBSs was agreed with GOB and about 500 km of BPDB lines have already beentransferred to PBSs. The actual handing over of the remaining 1,200 km ofthe backlog would be a condition of Credit effectiveness. To avoid thisproblem in the project PBSs, during negotiations it was agreed that theproiect areas would be surveyed and a dated program prepared for BPDBhandover of lines and customers before the start of project implementation.

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Training

2.16 REB's training program is designed to meet its own requirements.together with those of PBSs and local construction and consulting firmswhich are implementing the rural electrification program. Between July 1980and June 1989 it trained about 14,700 persons in courses designed andsupervised by NRECA (Annex 2.10). Its training programs have enabled REB toovercome a shortage of linesmen in PBSs which had earlier hindered consumerconnections. By June 1989, about 725 PBS employees had participated intraining courses for linesmen. REB, with assistance by NRECA, has alsoinitiated training in Rot Line Maintenance. A comprehensive trainingprogram and the teaching of working procedures has enabled the PBSs tomanage their technical operations efficiently. Wbile REB's training programis challenging when judged in terms of the number of persons to be trainedand skills to be developed, to date it has been successful in meeting itsobjectives. However, the lack of a centrally located training center withadequate physical facilities for conducting technical training programs,continues to hamper the Training Directorate efficient functioning. Thisissue vould be addressed through the construction of training facilitiesunder the proposed Project (para. 2.07).

C. Palli Bidyut Samities (PB88 (Rural Electrification Cooperatives)

Organization Structure

2.17 The PBS system consists of member-owned autonomous cooperatives forelectricity distribution in rural areas. A PBS's initial Board of Directorsis selected from local citizens, subject to the approval of REB's Board ofDirectors. After their appointment the directors register the PBS with REB,which then proceeds to promote PBS membership among potential consumers.The Board of Directors consists of 10-15 members elected by an annualmembers' meeting. Eligibility to become or remain a director includes beinga bona fide member of a PBS and a resident of its area. Any person ororganization in a PBS area may become a member of the PBS followingacceptance by the Board of Directors and payment of the membershipapplication fee of Tk 10.

2.18 The typical organizational structure for PBSs was developed by REB,with NRECA's assistance. Two sample organizational charts have beenprepared as flexible models to meet different levels of activity(Annex 2.11). The chief executive, the General Manager, is accountable tothe Board of Directors. Four main departments, each headed by an AssistantGeneral Manager, are responsible for extension and member services, finance,construction and maintenance, and general services. In each PBS fivepositions are reserved for female advisors to the PBS Board, who serve aschannels for expression of women's development needs in PBS areas. Theorganization structure has been reviewed by IDA and found satisfactory.

PBS Responsibilities

2.19 A PBS's responsibilities begin when a scheme is handed over afterconstruction and energisation. A PBS's principal objective is to supply itsmembers and other consumers with electricity. Its functions includes(a) distribution of electricity and making consumer connections; (b) meterreading, billing and collection; (c) purchase of electricity from BPDB;(d) planning and implementing the expansion of local distribution systems

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with REB's financial and technical assistance; and (e) technical andfinancial aosistance to consumers for wiring their premises, acquiring andinstalling electrical appliances, and improving their power factors throughthe installation of capacitors.

Losses in PBSs Systems

2.20 System losses are a problem for most PBSs. In June 1989, systemlosses in 5 out of the 17 PBSs which had been energized for at least fouryears were about ten percentage points higher than the anticipated levels,namely that losses would not exceed 252 in a PBS's first year of operations,202 in the second year, 152 in the third year, and lOZ in subsequent years(Annex 2.12). To identify the causes of losses and introduce appropriateremedial measures, in 1988189 R8B with NRECA's assistance, carried out astudy to determine the causes of high PBS losses. The study determined thatfrom year five, a typical PBSs' technical losses should generally be about71 to 10X. The remaining losses are non-technical in nature, resulting fromillegal connections, improper meter reading or outright corruption. Duringnegotiations, dated loss reduction targets to be incorporated in thePerformance Agreements were agreed with GOB/R8B (para. 2.11).

Advisory Consulting Services

2.21 The first agreement with NRECA, financed by USAID, to providegeneral institution building and technical consulting services to REB andPBSs, was signed in February 1978. Among other things, NRECA assisted insetting up PBSs' accounting and operating systems, which IDA considersappropriate. The initial const?lting services agreement with NRECA expiredIn July 1984 but was extended initially to July 1987 and subsequently toJuly 1991 under USAID financing. However, in 1991 RIB and PBSs will stillrequire institutional strengthening and technical consulting services(para. 3.08). During negotiations REB agreed to continue to employ, underterms and conditions acceptable to IDA. consultants to review technicalspecifications, supervise construction, and assist REB and PBSs indeveloping their technical and institutional capabilities (para. 3.08).

III. THE PROJECT

Project Setting

3.01 GOB attaches great importance to the scheduled completion of theongoing rural electrification program by FY2005 (para. 2.01). However,because of resource constraints, GOB is focusing on the intensification ofservice connections within existing PBS areas to improve existing PBSs'financial viability, and expansion of the backbone system to new areas. Theproposed Project consists of the first part of Phase IV (Phase IV-A), whichwould start in 1991, when major works under Phase III have been completed.It comprises the installation of new electricity distribution networks infour proposed PBS areas; rehabilitation of existing distribution networks inthose areas; expansion of five PBSs and intensification of the networks inseven existing PBSs; and technical assistance to strengthen REB and PBSs'financial and institutional performance. GOB is approaching other donors tofinance Phase IV-B of the program (para. 2.05).

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Proiect Objectives

3.02 The Project's main objectives would be to substitute power at leastcost for imported petroleum products and to strengthen REB and PBSs'performance byt (a) expanding existing distribution networks to unservedareas; (b) rehabilitating systems which REB would take over from BPDB;(c) reducing system losses; and (d) improving PBSs' financial viability andinstitutional performance by increasing the density of connections andmodifying accounting practices. It is anticipated that the Project, by itscompletion date, vill extend the public electricity supply to about 122,000domestic consumers, 20,000 commercial consumers, 2,900 industrial consumers,and 5,600 irrigation pumps.

Project Description

3.03 The proposed Project would consist of the supply and installation ofthe necessary equipment and material and the associated engineering servicesfor the implementation of Phase IV-A of the Rural Electrification program.It would include: (a) the installation of new distribution networks in fournew PBSs (Manikganj, Comilla, Dinajpur and Cox's Bazar); (b) expansion offive existing PESs' networks to include seven new upaxilas (Rangpur PBS-1,Rangpur PBS-2, Pabna PBS-1, Meherpur PES and Kushtia PBS); (c) intensifica-tion of seven PBSs financed by IDA under the First RE Project (Cr.1262-BD);(d) rehabilitation of existing BPDB lines and substations to be taken overby PBSs; (e) construction of central facilities for REB (offices, trainingcenter and workshop/warehouse); (f) consultant services to assist REB inproject engineering and construction supervision; and (g) technical assis-tance and training to strengthen the managerial, financial and institutionalaspects of both REB and the PBSs.

3.04 The proposed Project (details of which are given in Annex 3.1) wouldconsist of the following components:

(a) construction of about 6,035 km of 33 kV and 11 kV three phase andsingle phase primary lines, and about 3,015 km of 4001230 voltssecondary lines;

(b) construction of 18 substations 33111 kV of 10 MVA each and upgradingof 6 substations;

(c) service materials for consumer connections including serviceconnections, meters and LT capacitors;

(d) support commodities consisting of vehicles, motor cycles, tools,communications equipment, boats, etc.;

(e) rehabilitation of about 850 km of existing 33 kV, 11 kV and lowvoltage lines and distribution substations now operated by BPDB butto be taken over by PBSs in the areas included in the proposedProject;

(f) general plant for the PBSs consisting of local transport, office andresidential buildings, including cost of land and office equipment;

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(g) infrastructure and support faciliti.. for REB consisting ofheadquarter offices (10,000 square me-ers), training center,workshop and warehouse facilities (12,700 square meters); and

(h) consulting services to assist REB and the PBSs in project executionand management, including upgrading of technical and financialskills.

System Design

3.05 The system design was selected in 1978 for the program as a wholeafter evaluating alternatives for the primary voltage (11 kV vs. 33 kV),types of poles, types of conductors, and three phase vs. single phaseexpansion. It was found that 11 kV was the least cost primary voltage forboth three phase and single phase lines, together with both three phase andsingle phase transformers. ACSR conductors mounted on wooden poles wereselected as the least cost design for the lines. The basic design willcontinue to be used for the proposed Project following its successful use todate. Although some modifications have been introdsiced to take account ofexperience learned from specific site conditions in Bangladesh, Includingthe need for further actions to be taken--both through design and operation--to reduce system losses. A priority action is to raise the system powerfactor to the level of 0.90 and the proposed Project includes procurement ofLV capacitors of various size and pole-mounted 11 kV capacitors. Duringnegotiations REB agreed to submit no later than December 31, 1990 a datedprogram, satisfactory to IDA, to install capacitors on both the 11 kV and LVsystems to ensure that the power factor does not fall below 0.90.

Pro]ect Cost

3.06 The Project's estimated cost, including physical and pricecontingencies, duties and taxes, is US$160.2 million based on mid-1989prices. It comprises US$101.2 million on foreign exchange, and US$59.0million in loca)l costs, including US$15.4 million in taxes and duties.Physical contingencies of 5S are assumed for equipment, materials andservices on the basis of previous experience with rural electrificationprojects. Price contingencies for foreign costs are assumed at 4.9S eachyear from 1990 to 1995 and 3.7S each year thereafter. Price contingenciesfor local costs are assumed at 10 for FY90, 91 for PY91, 8S for FY92 and 72each year thereafter. The cost estimates are summarized below and presentedin detail in Annex 3.2.

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Table 3.1: PROJECT COST SUIOARY

Local Forelgn Total LocaI Foreign Total Foreign Exchange Cost(r*io htillon)(USS Million) (U)

A. Now PBSn

Line Material ^/ 296.1 1202.? 1497.3 6.7 1C.4 44.1 s0Substation Matorial & a4.5 140.4 174.9 1.0 4.1 5.1 s0Support Comoditie 10.2 05.9 02.1 0.5 1.9 2.4 s0Line Construction 100.0 100.0 2.9 2.9Substation Construction 10.5 10.6 0.8 0.8Consulting services 58.4 41.7 97.1 1.6 1.8 2.9 45General Plant 68.7 56.7 1.7 1.7REB Overheads and 119.2 119.2 8.5 8.5other *xpeem / - - - - - -

Sub-Total A 087.6 1462.8 2140.8 20.2 42.6 08.0 66

B. P65 extens./intenaif.

Line Material I/ 186.9 757.2 "44.1 5.5 22.8 27.6 80Substation Material 2 18.5 74.6 98.8 0.5 2.2 2.7 s0Support Comrodities 4.6 16.7 28.8 0.1 0.6 0.7 s0Line Constructlon 68.0 68.0 1.9 1.9Substation Construction 7.5 7.5 0.2 0.2Consulting servics 29.9 24.5 54.4 0.9 0.7 1.0 45RIB Overhead and 76.1 75.1 2.2 2.2other expenses -

Sub-Total B 165.5 675.2 1260.7 11.8 26.6 87.1 69

C. REB central facilities

Subtotal C 288.5 16.4 816.9 6.0 0.5 9.8 6

0. TA and TraininA

SubtotaI 0 69.1 842.2 411.5 2.0 10.1 12.1 ea

Total aBse Costa 1440.6 2088.6 4129.4 42.4 79.1 121.5 65

Physical Contingencies 72.0 184.4 206.4 2.1 4.0 6.1 e6Price Continencies 492.1 615.0 1107.1 14.5 16.1 82.0 5s

Total Project Costs 2004.9 8488.0 5442.9 59.0 101.2 100.2 esInterest during Constr. 112.1 112.1 8.8 8.8

Total Finance Required 2117.0 8416.0 5655.0 02.8 101.1 168.5

/ The Ites lnclud the cost of materials required to construct new lim and torehabiIltato old Itnes, secure matrtal for consumer connections and LT capaectors.

V Thsese ita Include th cost of mterial to construct n substations and to rehabilItatethe old substations.

0 Thee it.o. lnclud costa lncurrd on REB adeinlotration, doevlopmnt, operation (fromdate of registration to date of mrgiMtion), and staff training costa of P*Ss; andcompensation charge to im for system taken over by PUS.

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Prolect Financing

3.07 The financing requirements, including interest during construction(IDC) at a rate of 0.752 p.a., are US$163.5 million, including US$62.3million in local costs and US$101.2 million in foreign exchange. A proposedIDA credit of US$lO million equivalent would finance 852 of the foreigncost and 442 of the local cost excluding taxes and duties and IDC, whichwould represent 732 of the total project cost (excluding lr.al taxes andduties and IDC). USAID has been requested to finance the technical assis-tance component, representing 152 of the foreign cost and 62 of the localcost. The remaining 502 of the local cost, together with local taxes andduties and IDC, would be covered by grants from GOB to RED. The proposedfinancing plan is summarized in Table 3.2. Cost overrun and foreignexchange risk would be covered by GOB. During negotiations GOB agreed tocontinue to provide to REB, as a grant contribution, all the local fundsthat may be required for the proposed Project.

Table 3.2s PROJECT FINANCING PLAN

Local Foreign Total(US$ Million Equivalent)

IDA 19.1 85.9 105.0Cofinancing 2.4 15.3 17.7GOB 40.8 a/ - 40.8Total 62.3 101.2 163.5

aI Of which US$15.4 million is taxes and duties.

Project Implementation and Consulting Services

3.08 The Project would be implemented during 1991-97 after major worksunder ACRE Phase III would have been completed. The implementation scheduleis shown in Annex 3.3. As the main implementing agency, REB would beresponsible for the overall project management, including% (a) projectengineering, design, construction and system operation; (b) procurement andlogistics; (c) financial system, record and accounts; (d) development of newPBSs; and (e) training. Engineering design and layout of the backbonedistribution systems would be done by REB, which also oversees design andconstruction. Detailed design and layouts of the village distributionsystems would be done by local consultants, and construction of the distri-bution systems, including substations, by local contractors under contractswith REB. Under Phases l-III of the rural electrification program, REB hasassisted in developing an adequate number of competent firms to meet theproposed Project's consultancy and construction requirements. REB wouldprocure project equipment using technical specifications prepared on thebasis of the design criteria adopted for the RE program. While involvementof REB staff and local consultants would be much greater than in previousprojects in engineering, design and construction supervision, the develop-ment and organization of Phase IV PBSs, together with the continuousmonitoring of the 40 PBSs under Phases I-I1l, would require further manage-ment and technical support from the expatriate consultants NRECA/GC. GOBhas requosted USAID to continue financing NRECAIGC beyond July 1991 for

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another five years. If USAID does not provide this financing GOB would findan alternative financing source. During negotiations agreement was reachedon the scope of the technical assistance and training to be provided byconsultants during project implementation. The financing of the additionaltechnical assistance component after July 1991 should be determined beforeDecember 31, 1990.

Procurement

3.09 The various components would be procured as follows:

Table 3.3: PROCUREMENT ARRANGEMENTS

Procurement arrangements(US$ Million)

ICB LCB Other NA Total

Line Material I/ 73.5 0.5 0.5 18.6 93.1(73.5) (0.5) (0.5) (74.5)

Substation Material 21 8.0 0.2 0.2 1.8 10.2(8.0) (0.2) (0.2) (8.4)

Support Commodities 2/ 2.9 0.- 0.2 0.5 3.8(2.9) (0.2) (0.2) (3.3)

Line Construction 7.4 7.4(6.0) (6.0)

Substation Construction 0 8 0.8(0.5) (0.5)

Consulting Services 4.2 4.2(4.2) (4.2)

General Plant 2.7 2.7

RED Overheads andother expenses 8<4 8.4

REB Buildings 8.7 0.9 2.5 12.1(7-4) (0.7) (8.9)

TA and Training 17.5 17.5

84.4 17.8 26.2 31.8 3/ 160.2(84.4) (14.8) (5.8) (105.0)

1/ Includes 1-phase and 3-phase meters and service drops.

2/ Material and equipment to be procured on LIB basis are included under'Other".

3/ Local duties and taxes relating to materials and construction costs areshown under column 'NAR.

Notes Figures in parenthesis are the amounts proposed to be financed byID.

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3.10 Procurement of most material and equipment needed for the projectwould be on the basis of ICB according to IDA guidelines. Local suppliersand manufacturers competing for the supply of goods under ICB would have apreference of 152 or the applicable customs duty, whichever is less.Contracts for minor quantities of materials, tools, spares and equipment notexceeding US$100,000 each and in aggregate not exceeding US$1,000,000 wouldbe procured according to LIB procedures. In addition, contracts for minorquantities of materials not exceeding US$50,000 each and in aggregate notexceeding US$1,000,000 would he procured using LCB procedures satisfactoryto IDA. All the construction work financed by IDA, including the civilworks related to lines and substations, would be carried out using localcontractors selected according to LCB procedures satisfactory to IDA. Civilworks related to buildings and REB'; central facilities to be financed inpart by IDA and in part through GCn s contribution to the project, would beconstructed by local contractors also selected through LCB procedures.Except for REB's Headquarter complex, all the buildings are scatteredgeographically and would cost less tha.. US$200,000 each. Since the localconstruction industry can provide competitive prices, IDA has agreed thatthese buildings, like the construction works, can be procured under LCBprocedures. However, as per Bank Group's Procurement Guidelines, para 3.3,any foreign firms wishing to participate will be allowed to do so.Consultants for project engineering and supervision would be selected andemployed in accordance with the Bank Group Guidelines for the use ofconsultants.

3.11 To suit the implementation schedule procurement of the equipment,materials and support commodities would be split in four tranches over 1991to 1995. Further each tranche would include separate packages to beprocured under ICB as shown in Annex 3.3. All bidding packages andcontracts over US$100,000 would be subject to IDA's prior review and willapply to about 90o of the estimated cost of IDA-financed items.

3.12 Under GOB's current policy, single phase meters cannot be importedand, further, all single LV customers are required to purchase their ownmeters in the local market. The application of this policy to rural areaswould cause a significant drop in new connections and it would be contraryto the RE program's objectives. Prior to negotiations, GOB waived theimport ban for all IDA-financed proiects including the proposed Project, andagreed that meters would be purchased by REB under ICB and not by individualconsumers.

Disbursement

3.13 Disbursements under the proposed credit would be in respect ofmaterials and equipment, erection and commissioning expenditure, andconsulting fees, as shown belows

(a) 1001 of the CIF expenditure of imported material for lines, sub-stations and support commodities; in the case of locallymanufactured goods, 10OZ of ex-factory expenditure, and in the caseof goods procured locally, 70? of the expenditure;

(b) 1001 of total expenditure of consulting services, includinginspection of equipment and materials; and

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(c) 852 of civil vorks related to the expenditure of erection andcommissioning, including civil works related to lines, substationsand infrastructure facilities.

These disbursements would be fully documented except for small civil workscosting less than US$20,000. In such cases, disbursement will be madeag'Rinst Statemeat of Expenses (SOE), the documentation of which will not besubmitted to IDA but retained for inspection by supervision missions. Thestandard procedures for auditing SOEs would apply. To facilitate disburse-ment, a Special Account would be established in the Bangladesh Bank (CentralBank) on terms and conditions satisfactory to IDA. The amount of theSpecial Account is proposed to be set at US$2.5 million. The disbursementschedule is indicated in Annex 3.4.

Developmental Impact

3.14 Environment. The Project's direct environmental impact would belimited to the construction of distribution lines and substations and PBSheadquarters facilities. There would also be an indirect, but very limited,impact caused by increased irrigation schemes and expansion of small scaleindustries. The Project would have a positive environmental impact byproviding a higher quality of life since lighting by electricity is cleanerand less of a fire hazard than kerosene lamps. The replacement of dieseland gasoline engines would reduce local air pollution and lead to a netimprovement in air quality since the grid generating plants are moreefficient and generally burn natural gas. Tree cutting requirements wouldbe minimal since much of the area requiring pole setting is on farmlandunder cultivation. With each PBS headquarters limited to 3 acres and eachpole requiring only about 2.25 square feet of clearance space, total lostagricultural land would be negligible. Overall, the Project would be inCategory B in terms of environmental impact, although many components wouldbe in Category C. The engineering and construction codes and practices usedare largely derived from those used by NRECA in the US which provide for themitigation of the minor environmental impacts. The scheduling of lineconstruction would be such as to minimize damage to agricultural crops.

3.15 Poverty Alleviation. Much of the labor force in rural areas iscomprised of poor and landless persons. Income distribution would beachieved through increased economic activity and creation of employmentopportunities mainly in agriculture and small scale industry. The REprogram would provide employment to the local labor force for erecting thedistribution works and through the economic activities set in motion as aresult of backward and forward linkages of the program. An assessment ofthe RE program's overall developmental impact will be carried out during1990 under USAID financing.

3.1E Women in Development. The extension of electricity supply to ruralhouseholds would have a positive impact on women but mainly in the higherincome groups. Female advisors have been officially made a part of the PBSBoards and serve as channels for the expression of demands by women in thePBS areas. Further, PBSs employ many women in their headquarter officesespecially for the revenue function. At the community level, electrifica-tion of public facilities such as dispensaries, schools, offices and placesof worship will result in better services to the residents and in particularto women attending these facilities.

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Project Monitoring

3.17 During implementation the proposed Project would be monitored byREB with the assistance of consultants. After completion (within six monthsafter the closing date or a later date agreed with IDA) REB would furnish toIDA a Project Completion Report on the Project's execution and initialoperation, its cost and benefits, REB's performance and the accomplishmentof the Credit's objectives.

Risks

3.18 The Project presents no major technical or environmental risks andinvolves no complexities as it is a continuation of the ongoing program ofrural electrification. The principal risk concerns possible delays inproject implementation because of shortage of local funds from GOB. Thisrisk has been mitigated by reducing the program's overall size, by Improvedplanning and construction supervision by REB, and by extending theimplementation period from five to seven years.

IV. FINANCES

A. Rural Electrification Board

Financial Obiectives

4.01 REB's financial objectives originate from the financial covenantsagreed under Cr.1262-BD and Cr.1633-BD which require REB to achieve anoperating ratio 1/ not exceeding 751 in any fiscal year beginning FY86 and aminimum long-term debt service coverage of 1.5. Other donors have adoptedthe same covenants. As explained in paras. 4.03 and 4.04, REB so far hasbeen unable to meet its financial objectives. To improve the financialposition of REBI/PBSs, the consultants, Coopers and Lybrand Associates (UK),recommended that the existing onlending terms should be modified. Thisissue will be addressed under the proposed credit (para. 4.03).

Past Results and Present Position

4.02 EEB's FY85-89 operating performance is summarized below and givenin greater detail in Annex 4.1

11 Operating ratio in context of this analysis has been defined as theratio between all operating expenses, excluding depreciation butincluding interest charges and operating revenues.

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Table 4.1: REB OPERATING PERPORMANCE--FY85-39(In Tk Million)

FY85 PY86 FY87 FY88 FY89

Revenues 4.1 6.4 63.5 72.9 99.7Expenses 23.1 29.2 32.4 37.2 43.9Repayment of Loans from PBS 0.0 0.0 0.0 0.0 50.1Internally Generated Funds (16.2) (20.0) 56.7 39.8 111.3

Debt ServicesInterest 29.4 38.8 34.1 61.4 93.5Amortization 0.0 0.0 0.0 0.0 77.3

Operating Ratio 12.0 10.2 1.0 1.3 1.3

Debt Service Coverage Ratio (0.6) (0.5) 1.7 0.6 0.7

4.03 Since the RE program's inception, REB has been acting both as theimplementing agency responsible for the construction of rural electrifi-cation schemes and as the financial intermediary and supervising agencyafter the completed schemes are handed over to PBSs. REB's performance asan implementing agency is impressive. As of June 1989, 33 PBSs withcombined assets of Tk 7.1 billion have been energized. This, together withconstruction work in progress of Tk 0.3 billion, represents an averageannual investment level of Tk 0.7 billion during the ten-year period ofFY80-89. However, a review of REB's past financial performance reveals adisturbing trend which, if not addressed, could undermine REB's long-termfinancial health as a financial intermediary. It relates to REB's seriousliquidity problem, as reflected by its continuing dependence on GOBbudgetary allocations to cover its operating expenses and REB's inability toservice its debt to GOB from internally generated funds. The basic causesof REB's insolvency are: (a) the tandem relationship between the graceperiod on GOB loans to REB and the grace period on corresponding REB loansto PBSs; (b) PBSs' default on debt service to REB; and (c) the inordinatedelays in the scheme closing process. These are discussed in more detailbelow.

4.04 Onlending Terms. Given the two to three year time lag between thesignature of REB loans with GOB and the date of a PBS's registration, the 5-year grace period on each GOB loan to REB expires before the end of the 5-year grace period on the corresponding REB loan to a PBS, which starts fromthe date of PBS registration. This tandem relationship has two adverseimplications for RIB's cash flow. First, during the grace period of REBloans to PBSs, REB cannot use interest revenues from PBSs to cover itsoperating expenses (administrative expenses and interest on GOB loans) sinceinterest charges on REB loans to PBSs are capitalized. Second, REB has toservice its debt to GOB before PBSs start repaying the onlent funds to REB.In recent years, GOB has been deducting REB's debt service obligations fromits annual allocation to REB. While this practice has allowed REB, unlikeother public institutions, to be current on its debt service obligationsunder the SLA, on the IDA credits, it has diminished local funds for newschemes. Similarly, the five-year grace period on REB's loans to PBS starts

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at the date of PBS registration instead of at the date of energization,which is typically one year later. Consequently, debt service for a PBSbecomes due before it has been operating for five years to build up itssales and generate an operating surplus for meeting debt service to REB. Toensure REB's and PBSs' solvency and to provide a rational basis formonitoring REB's future financial position, during negotiations GOB/REBaareed thats (a) the grace period on GOB loans to RB should be extended to8 years while keeping the repayment period of 25 years and other onlendingconditions similar to those already agreed under Cr.1633-BD: and (b) the 5-year grace period on REB loans to PBSs should start from the date ofcommercial energization, which is the end of the month when bills are firstsent to consumers. The conclusion for the proposed Credit of a SubsidiaryLoan Agreement between GOB and REB satisfactory to IDA is a condition forcredit effectiveness. Further, during nesotiations it was agreed that oncompletion of each scheme under the proposed Prolect REB will enter into aSubloan Agreement with the PBSs under terms and conditions satisfactory toIDA.

4.05 Depreciation Fund. By June 1986, debt service to REB from thefirst 4 PBSs became due, and by June 1989, 12 PBSs were liable for debtservicing. Although 7 of them had operating surpluses after interestcharges and depreciation, only a partial payment of Tk 50 million was madein FY89. One of the factors explaining the PBSs' poor debt serviceperformance was the depreciation fund policy prescribed by REB. Accordingto this policy, each PBS should maintain a depreciation fund in a bankaccount and deposit the full amount of its annual depreciation charge intothe said account. Compliance with this policy took precedence over debtservice payments to REB. This resulted in some PBSs accumulating largebalances in the depreciation fund account while, at the same time, owingsubstantial arrears to REB. In view of the serious shortages of local fundsand the crowding-out impact that GOB's contributions to the RE program wouldhave on other development programs in the country, the efficient use of theresources mobilized in the subsector is critical to the long termsustainability of the RE program. The recent report submitted by Coopersand Lybrand Associates (UK) (para. 2.12) noted that there is nojustification to continue the current practice. This conclusion has beenendorsed by the major donors of the RE program. In 1989 REB agreed tosuspend the depreciation fund and to introduce a replacement reserve fundlimited to a maximum of 5 of gross fixed assets. This policy was fullyimplemented effective July 1, 1989.

4.06 Scheme Closing Process. REB's liquidity problem is furthercompounded by the inordinate delays in the scheme closing process. In manycases, capital investments that have been completed and handed over to EBSshave remained in REB's accounts as current assets for several years. Thus,REB has been deprived of interest revenues which would have accrued. This,together with the inappropriate treatment of interest accrued during thegrace period on REB loans to PBSs in the income statement explains very highoperating ratio during FY85-89. To avoid the future reoccurrence of thissituation, during negotiations, REB agreed that the process of schemeclosing out would be completed within six months from the date of a PBS'scommercial energization (para. 4.09).

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Future Performance

4.07 REB proforma financial statements vere prepared for FY90-95(Annex 4.1) on the basis of the investment plan of the Phase IV ruralelectrification program and the revised onlending terms discussed Inparas. 2.05 and 4.04 and other assumptions set out in Annex 4.2. Due to thedeficiencies in the management of the accounting systems for capital work-in-progress, assets transfer and loan sales to PB8s, accurate Information ona PBS by PBS basis is not available at this stage (para. 4.09). Sincereconciliation between assets transfer and loan sales for the existing 33PBSs just began recently and will be completed only by end-1990 financialprojections were prepared on the ACRE basis (group of PBSs financed underthe same operation). REB's projected financial performance is consideredconservative in view of the assumption used. For instance, the finalcompletion date of Phase III RE program in 1992/93 ie taken as the assettransfer date for all the PBSs involved, and interest revenues are assumedto flow in thereafter. In reality, however, REB will collect interestrevenues and repayment of principal from some PBSs much earlier than that.Key financial indicators based on the proforms statements in Annex 4.1 areshown in Table 4.2.

Table 4.2: REB'S PROJECTED OPERATING PERFORMANCE FY90-95(In Tk Million)

FY90 FY91 FY92 93 FY94 FY95

Revenues 225.2 221.0 249.5 261.4 257.1 252.8Expenses 54.0 62.5 72.6 84.2 107.2 120.4Repayment of Loans from PBSs 297.0 297.0 297.0 297.0 297.0 297.0Internally Generated Fund 477.5 466.2 486.6 488.9 473.3 455.8

Debt Service:Interest 49.7 93.6 90.6 111.2 119.2 115.8Ammortization 102.2 194.0 194.0 194.0 194.0 194.0

Operating Ratio 0.4 0.7 0.6 0.7 0.8 0.8Debt Service Coverage Ratio 3.1 1.6 1.7 1.6 1.5 1.5

4.08 During the forecast period FY90-95, total investment on the REprogram is estimated at Tk 16 billion of which Tk 10.5 billion (652) is inforeign exchange. It is expected that external donors would providefinancing for the investment program's entire foreign cost (para. 2.05) andthe local cost would be covered by GOB equity contributions. Clearly, REB'sfinancial position as a financial intermediary depends on the PBS's futureperformance. Assuming an 8-year grace period on GOB loans to REB and thatthe system of annual performance agreements described in para. 4.10 issuccessfully implemented, REB's financial position would improve substan-tially. Its operating ratio would not exceed the covenanted level of 752and debt service coverage would be maintained at or above 1.5 throughout theperiod. To ensure resource mobilization within the limit of affordabilityand to enhance REB's long-term financial viability, it was agreed duringnegotiations that REB shall ensure that: (a) its administrative expenses and

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interest payments in any fiscal year beginning FY91 shall not exceed amaximun of 752 of the aggregate interest and other revenues received fromall sources during that fiscal year: and (b) its internal sources of funds,including PBS loan repayments in any fiscal year, shall cover at least 1.5times the debt service requirement.

Accounting Systems and Organization

4.09 REB's accounting systems were designed by NRECA based on soundaccounting principles. Subsequently, REB has implemented and operated thesystem under NRECA's supervision. REB's financial functions are managed bythe Board Member of Finance, who is assisted by four directors overseeingmatters relating to finance, accounts, PBS loans and auldit and procurement,and one deputy director for internal audit. In recent years, severalfinancial management deficiencies have been identified. These includeproblems associated with the operation of the material accounting system andin the management of accounting systems for capital work-in-progress, assetstransfer and loan sales to PBSs. As a result, information on asset transferand loan sales on a PBS by PBS basis is difficult to obtain. This hascaused inordinate delays in the scheme closing process and seriouslyaffected REB's capacity to generate revenue. REB is aware of this situationand reconciliation work is now under way. To ensure timely and long-lastingimprovements in the identified areas, during negotiations REB agreed that itwould prepare and furnish to IDA by December 31, 1990 an action plan toimplement the required reforms to its accountin8 systems and procedures andthereafter implement the said plan as agreed with IDA.

External Auditing

4.10 REB's accounts are audited by private auditing firms. Underprevious Credits (Cr.1262-BD and Cr.1633-BD) REB is required to furnish toIDA, not later than nine months after the end of each fiscal year, certifiedcopies of its financial statements accompanied by the auditor's report. Thequality of the audits for the recent years has shown some improvement,although some deficiencies remain to be addressed. To ensure accountabilityfor resources used by REB, during negotiations it was agreed that REB shouldhave its accounts audited by independent auditors acceptable to IDA andfurnish to IDA no later than nine months after the end of each fiscal yearcertified copies of its financial statements, accompanied by the auditor'sreport which would cover the Special Account and include a separate opinionas to whether 80E submitted can be relied upon to support the relatedwithdrawal applications.

Insurance Arrangement

4.11 All REB loans to PBSs are secured by mortgages on the assetstransferred to PBSs. To provide coverage for PBSs' assets, REB hasestablished an insurance pool fund, requiring each PBS to maintain areplacement reserve fund equal to 52 of its gross fixed assets. The fund isadministered by RIB. This arrangement is considered adequate.

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B. Palli Bidyut Samities (Rural Electrification Cooperatives)

Past Operation Results

4.12 As of June 1989, 33 PBSs were in operation, of which 12 have beenoperating for six years or more. Recognizing that newly formed PBSs wouldneed time to build up their memberships to self-sustaining levels, GOBagreed, under Cr.1262-BD and Cr.1633-BD, to provide PBSs with operatingsubsidies to cover operating losses, if any, during the first five years oftheir operations. It was also agreed that REB would cause each PBS to takemeasures, including tariff adjustments, to: (a) earn, starting from thesixth year, revenues sufficient to cover cost of electricity purchases,othe: operating expenses, depreciation and interest expenses, therebyeliminating the need for GOB subsidies; and (b) generate, starting from theseventh year, a cash surplus equivalent to 20Z of its capital expenditureafter meeting debt service and working capital requirements.

4.13 A review of the operations results of the 12 PBSs which have beenenergized for six years or longer indicates their performance has fallenshort of expectations. As shown in Table 4.3, although 11 out of 12 PBSshave earned operating surpluses, only three made principal repayments to REBin FY89. The poor performance of many PBSs is attributable to severalmutually reinforcing factors, including unfavorable consumer mix, lowconsumer density, high system losses and low load factor. The problem hasbeen compounded by delays in the transfer of designated BPDB lines andassociated consumers to PBSs (para. 2.15). While the transfer of the entirebacklog of BPDB lines to PBSs is a condition of effectiveness for theproposed Credit (para. 2.15), additional actions need to be takenimmediately to improve PBSs' operating efficiency and put them on a soundfinancial footing. To this end, a system of Annual Performance Agreementswould be established to set specific annual operating and financialperformance targets for existing operating PBS. The introduction of thesaid system would be a condition of Credit effectiveness (para.2.11).

Table 4.3: KEY PERPORMANCE INDICATORS FOR SELECTED PBSs--FY89

Date of Avers Operating Not Oper.KINM of PBS En.rgization Torifr Ratio Incoms Share of Revenue () / System Loss

Tk/kWh '000 Tk (1) (2) (a) m

Dhaka 08/02/80 2.48 0.80 26,057 17 S7 16 20Co.T I la 01/Ol/01 2.47 0.92 4,045 20 es 17 20Jwesre II 02/02/81 2.84 0.07 1,100 19 68 18 17Nator. I 08/15/81 2.88 0.0899 C 24 86 41 14Sirearni 04/14/01 2.40 0.92 3,6S5 20 40 84 19Moul vrn Xar 06/28/01 2.08 0.77 11,079 23 72 0 11Jessor I 06/29/51 2.50 0.95 2,128 28 89 88 14T ngail I 10/19/81 2.27 0.07 1,278 15 40 45 24Chandpur 12/18/01 2.51 1.27 (7,718) 89 48 18 21Metors I 08/08/82 2.48 0.90 1,078 29 54 17 19Hbpganj 10/12/82 2.58 0.85 5,986 25 69 6 15Pnbn. I 01/06/88 2.47 0.8 2,207 25 6o 15 14

1/ (1) D.z".ti. sales(2) Induetty(8) IrrigatTon

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4.14 Based on the investment costs, implementation schedule and demandforecast discussed in paras. 3.06, 3.08 and 5.04, financial projections for thefour new PBSs to be financed under the proposed Credit have been prepared.Table 4.4 presents a summary of perfozmance indicators for selected years. Theprojected financial statements and the assumptions are given in Annexes 4.3 and4.4.

Table 4.4s PROJECT PBSs--PROJECTED OPERATING PERFORMANCE PY94-2003(In Tk Killion)

FY94 FY95 FY9 Mn FY98 FY0 FY20ao FY2003

Electricity Purchase (U1h) 14.6 24.0 60 69.0 91.8 100.0 107.5 120.6Electrielty Sol"e (G) 10.9 19.2 81.5 60.2 79.4 89.7 96.7 108.4Syte Lo" ) 26 20 1? 15 18 18 18 13Average RetalI Tariff (Tk/kWh) 8.78 4.07 4.44 4.64 5.25 5.75 .18 7.44Not Inuos (8.9) (6.2) (0-0) (0.2) 48.0 87.0 08.7 176.2008 Subsidy 5.5 4.0 a.?operating Ratio 1.1 1.0 1.0 0.9 0.9 0.6 0.6 0.7Det Servica Coverage 1.1 1.8 1.9S.lt-Flnenclsg Ratio (S) 6.1 9.9 9.9Current Ratio 1.5 1.8 2.0 2.5 2.9 1.8 1.4 2.0

4.15 Table 4.4 shows that the four new PBSs would become financiallyviable beginning from the 5th year of operation and their financial positionwould strengthen during the next five years, with debt service coverage andcurrent ratio projected at 1.9 and 2.0 respectively at the end of the 10thoperating year. During negotiations GOB agreed to continue to provide anoperating subsidy to the PBS, if needed, during the first five years ofoperation in accordance with a formula acceptable to IDA.

Auditing

4.16 Under previous credits, REB agreed to cause PBSs to have theiraccounts audited by independent auditors acceptable to IDA and to submit toIDA, not later than nine months after the end of each fiscal year, certifiedcopies of their financial statements accompanied by the auditor's reports.In the past, accounts for those PBSs financed by InA were submitted withinthe covenanted period. However, the quality of audits were very poor. Thisproblem is particularly due to the restriction that an auditing firm is onlyallowed to audit a single PBS and for no more than three years. The system,designed to provide opportunities to all auditing firms in the privatesector, has so far failed to ensure the quality of the audits. REB hasagreed to revise its current procedure and allow auditing firm, acceptableto IDA, to audit more than one PBS. To ensure that REB continues to conformto the audit arrangements agreed under Cr.1262-BD and Cr.1633-BD duringnegotiations it was agreed that REB should cause the PBSs to have theiraccounts audited by independent auditors acceptable to IDA, and to furnishto IDA not later than nine months after the end of each fiscal year,certified copies of their audited financial statements, the audit report andtheir coaments or, if necessary, a plan for corrective actions.

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V. PROJECT JUSTIFICATION

A. Electricity Demand Forecast

5.01 The electricity demand forecast used to quantify the proposedProject's benefits is based on an analysis of historic sales data and growthrates. Average growth rates of PBSs' electricity sales by consumer categoryduring FY82-89 are shown in Table 5.1, together with the forecast pattern ofconsumption at appraisal of the Rural Electrification Project (Cr.1262-BD),and the actual patterns in FY84 and FY89. Actual consumption has beensubstantially different than projected; the percentage of sales toirrigation consumers is six times higher than the forecast level, and forindustrial consumers is nearly 502 higher, while that for residentialconsumers is less than half the projected level. The actual consumptionpattern will assist more PBSs in becoming financially viable and improvesthe economic viability of the rural electrification program. A detailedanalysis of the past demand is presented in Annex 5.1, Table 1.

Table 5.1: FY82-89 DEVELOPMENT OF PBSs' ELECTRICITY SALES

Average Yearly Pattern of Consumption as Per:Consumer Category Growth Rate RE I Appraisal FY84 FY89

Residential 55.3 58.0 24.9 25.1Commercial 113.6 6.0 5.6 6.9Irrigation 61.2 4.0 22.5 24.7Industry 63.1 32.0 46.7 43.0Other 34.1 - 0.4 0.3Total Sales 61.4 100.0 100.0 100.0

5.02 Two load forecasts have been prepared: a general one for the wholerural electrification program and a specific one for the project PBSs, bothof which are shown in Table 5.2.

Demand Forecast for the Rural Electrification Program

5.03 The MY90-2000 forecast was prepared using a multiple non-linearregression model which implicitly assumes that sales in new and extendedPBSs will replicate the performance of existing PBSs at the same stage ofdevelopment.21 That is, the first year sales by consumer category of a newPBS will be identical to the average sales recorded by existing PBSs intheir first year of operation, and similarly for subsequent years. Theforecast includes a major change in the relative sales shares of industrialand irrigation consumers, with a relative increase in the latter. Further,by FY2000, the impact of the development of residential sales causes thepeak demand to increase faster than energy sales, with a consequentreduction in the load factor from 0.38 in PY89 to 0.31 by FY2000. This

2/ The detailed forecast is given in Annex 5.1, page 2. Full details ofthe load forecast methodology are given in the project file.

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decline emphasizes the importance of the early introduction of effectiveload management measures, including time-of-day tariffs for irrigationconsumers and other consumers with contracted demands above 10 kVA.Table 5.2 shows that such measures could reduce estimated peak demand byabout 300 MW by FY2000, with an associated discounted cost saving of morethan Tk 8 billion (US$240 million). Consequently, during negotiations REBaareed to introduce time-of-day tariffs, or other suitable load managementmeasures, for large consumers before December 31, 1990.

Table 5.2: DEMANID FORECASTS FOR PY90-FY2000

Consmur Category P'rogr Forocast--- -Project Forecast-FM00 FY2000 Growth Rates FY05 PY2000

G X OW X FYs0-2000(X) GH X Il s

Residential 98.4 25.1 621.1 27.7 16.9 9.6 19.8 48.7 20.1Comercatl 25.6 6.9 106.7 5.8 14.1 2.9 5.6 13.5 8.4Irrigation 91.8 24.7 684.0 35.8 19.7 11.0 22.1 28.2 17.6Industry 160.1 48.0 574.6 80.5 12.8 26.8 52.0 72.1 44.9Other 1.8 0.8 14.4 0.6 24.6Total Soles 872.1 100.0 1,698.0 100.0 15.9 49.8 l00.0 160.6 100.0Purchses 468.0 124.4 2,164.4 114.0 18.2 60.7 121.0 184.6 115.0

Psk DOmand NW X w M X W X !" X

Non-CoincIdwotl 168.0 100.0 896.5 100.0 17.0 16.1 100.0 81.6 100.0Without Load Manaemant 140.0 69.1 780.0 80.1 17.0 16.1 69.1 55.1 89.1With Load Management 96.7 61.2 488.9 54.0 15.8 11.7 04.7 44.5 72.0

Demand Forecast for the Project PBSs

5.04 The proposed Project would start in FY91, and the first PBS would beenergized in FY93. Consequently, FY93 was taken as the base year for theProject PBSs' demand forecast. The forecast, which is presented inTable 5.2, and detailed in Annex 5.1, Table 3, was prepared using a fullydisaggregated approach based on 13 existing PBSs' past sales data. Thus,for residential and commercial consumers the forecast number of consumerconnections and consumption per consumer for the first five years of theforecast period was derived from an analysis of the relevant data fromexisting PBS. The forecast suggests that the Project PBSs' share of totalsales to residential consumers will be slightly higher than that for allPBSs in the RE program (29Z compared with 27.72); the share of sales toirrigation consumers will be considerably lower than that in the program asa whole, but this will be more than offset by the forecast high share ofsales to industrial consumers.

B. Least-Cost Analysis

5.05 Two types of least cost analysis have been undertaken. One, whichwas prepared by REB/NRECA, analyzed each component of the proposed Projectto determine its optimum design and capacity to ensure that the forecastelectricity demand in the project PBSs would be supplied at least cost. Themethodology, cost data and recommendations have been reviewed by IDA andfound to be satisfactory. The other considered alternative energy sources

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to electricity supply, such as kerosene or diesel fue:, to identify the typeof energy which would meet the forecast energy requirement for eachspecified end use, e.g., lighting, irrigation pumping, motive power, etc.,at least cost.3/ The analysis showed that electricity to be supplied by theproposed Project would meet forecast energy demands in the specified uses atleast cost.

C. Economic Internal Rate of Return

5.06 The economic internal rate of return (EIRR) has been estimated for:(a) the entire Project, including the TA costs and those of the plannedtraining center, workshop, etc.; (b) for the four new PBSs; and (c) for thefive PBSs which would be extended. In each case the analysis was undertakenover 30 years. All foreign costs were measured using border prices in termsof mid-1989 prices. Local costs were expressed in terms of equivalentborder prices using conversion factors of 0.8 for materials, equipment andservices, 0.8 for skilled labor and 0.8 for unskilled labor. A standardconversion factor (SCF) of 0.8 was applied to costs such as house wiring andelectric motors for irrigation pumps. Electricity supply costs wereestimated as the long run marginal cost (LRMC) of generation increased by10X to account for system losses prior to the 33 kV bulk supply points.Since it was ascertained, on the basis of with and without project analysis,that the incremental demand associated with the Project would not be largeenough to change the planned transmission investment program, costsassociated with the 220 kV and 132 kV lines were excluded from the analysis.Operation and maintenance (O&M) costs were estimated as 52 of cumulativeannual investment costs. The estimated investment, O&M and LRIC supplycosts are given in Annex 5.2, Table 1.

5.07 Based on the estimated economic costs, the EIRR was estimated usingtwo different measures of benefits. A minimum measure of the benefitsassociated vith the incremental electricity sales is given by incrementalsales revenue using Y90 tariffs. On this basis, the adjusted EIR for theentire project is estimated to be -2.8Z, and for the four new PBSs the fivePBSs to be extended to be about zero percent. Using this measure ofbenefits, tariff rates would need to be increased by about 80Z to give anEIRR of 12? for the total project. However, it should be noted that (a) therevenue-based measure of EIRR is more an evaluation of the adequacy oftariffs (which are about 562 of LRMC), than of the Project's true economicworth; and (b) the project cost includes US$17.0 million of technicalassistance for the entire rural electrification program.

5.08 A better measure of the EIRR is that based on estimates ofconsumers' willingness to pay (WTP) for the incremental electricity sales.A conservative estimate of WTP was made as follows: (a) for residential andcommercial consumers it was based on the cost of lighting using eitherkerosene wick lamps (yield equivalent to a 20 W electric bulb) orpressurized kerosene lamps (yield equivalent to 60 U bulb); and (b) forindustrial and irrigation consumers it was based on the cost of running a

13 These analyses formed the basis for the calculation of consumers'willingness to pay for electricity for particular uses. Details aregiven on the project file.

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diesel plant using imported high speed diesel oil. For each consumer groupthe WTP-based benefits estimates were prepared as followss first, toestimate benefits for those electricity sales which would represent asubstitution of electricity for an alternative fuel, WTP was measured asindicated in (a) and (b) above. Second, the incremental electricity saleswhich are forecast to occur as a response to the lower price of electricityvis-a-vis its substitutes and as a response to the availability ofelectricity supply, were valued assuming a linear demand curve with amaximum WTP as just described and a minimum equal to the FY90 tariff rate.The discounted weighted average WT? was estimated to be Tk 6,2/kWh, and the8IRR for the entire project, including the TA and costs of the trainingcenter and workshop/warehouse, was estimated to be 172. Similarly, the EIRRfor the four new PBSs was estimated to be 34Z and for the five PBSs whichare to be extended it was estimated to be 55?. It should be noted that allof the foregoing WTP-based measures of the EIRR are conservative since theyassume that consumers' WTP to pay for new product uses of electricity (e.g.,residential consumers' use of televisions, electric fans, etc.) is alwayslower than the WTP for lighting and, further, they all assume zero benefitsfor the proposed training center.

D. Sensitivity and Risk Analysis

5.09 Sensitivity analysis was carried out on the WTP measures of the EIRR(Annex 5.2, Tables 2, 4 and 6) to ascertain the likely risk that the projectwill be uneconomic. The analysis is presented in terms of the percentagechange in a particular item required to yield the specific EIRR. Forexample, for the total project's EIRR to fall from the estimated 17Z to 12?would require any one of the following to occur: (a) a 33Z increase in theproject's investment and O&M costs; (b) a 40S increase in the electricitysupply cost (LRMC); Ic) a 212 decrease in consumers' WTP; (d) a 43? decreasein forecast demand (in GWh); (e) a 25? decrease in the forecast number ofconsumer connections; or (f) a 43Z decrease in forecast consumption perconsumer. The results for (a)-(d) above are shown in Figure 1. Thesensitivity analysis indicates that the base case EIRR is robust since thebase case estimates for WTP (c above), number of consumer connections (dabove) and consumption per consumer (e above) are all derived from existingPBSs with similar characteristics to the project PBSs. Thus for each ofthese variables the probability of a decrease in the base case value isconsidered to be very low. The probability of a significant increase in theestimated LPMC is also assessed to be low since it is derived from BPDB'splanned investment program which is unlikely to be increased in size.Further, the project's base case cost estimates have been derived from 1989awarded contracts, and the probability of a further significant increase isconsidered to be small. Finally, in view of the foregoing, the probabilityof a set of changes in the variables (a)-(e) above sufficient to reduce theEIRR to 12? is also considered to be very low.

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Fiaure 1: ZCO=OtC INTUM, RAIT OF UTUR tSENSIT VITY ANALYSIS WOLE PROJECT

SENSSITIVITY ANALYSISVer Ist Ion of S I R vs paresers

140%S<

120%

640%-

I-0

4 2% 16 IX 2X 2420

OISCOUNT RATEOemanf A WtP q LRMC

E. Justification for Bank Group Involvement

5.10 In addition to meeting the forecast demand for energy in rural areasat least cost, the proposed Project would, through IDA's involvement:

(a) improve the power subsector's efficiency and sustainability bystrengthening existing PBSs and enhancing the institutionalperformance of both REB and PBSs;

(b) enhance energy conservation through the reduction of power systemlosses;

Cc) resolve BPDBIREB coordination and line transfer issues, which isnecessary for the efficient implementation of the ruralelectrification program;

(d) expand training facilities; and

(e) improve both REB and PBSs' operational and financial performance.

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VI. SUMMARY OF AGREEMENTS REACHED AND RECOMMENDATIONS

6.01 During negotiations the following agreements were reached with GOBt

(a) GOB will cause REB to introduce procedures for the annual4etermination of Performance Agreements and, each year, to theAssociation's satisfaction, monitor PBSs' performance against theagreed targets (para. 2.11).

(b) GOB will cause BPDB to expand in a timely manner its transmissionand grid capacity to provide reliable power supply to the PBSs to beestablished under the proposed Project (para. 2.14).

(c) GOB agreed on a dated action plan for the transfer of BPDB lines toPBSs and will cause BPDB and REB to implement this plan in a timelymanner (para. 2.15).

'd) GOB will provide REB, as Grant Contribution, all the local fundsthat may be required for the proposed Project; (para. 3.07).

(e) GOB will relend the proceeds of the proposed Credit to REB under aSubsidiary Loan Agreement under terms and conditions acceptable toIDA and which shall include: (i) repayment period of 25 years afteran 8-year grace period; (ii) an interest rate of three-fourth of onepercent (3/4 of 12) per annum during the grace period, and aninterest rate of two percent (2Z) thereafter, and (iii) the foreignexchange risk to be borne by GOB (paras. 2.08 and 4.04).

(f) GOB will provide PBSs with a subsidy during the first five years ofoperation in accordance with a formula acceptable to IDA(para. 4.15).

6.02 During negotiations the following agreements were reached with REB.

(a) REB, with the assistance of their existing consultants, will prepareeach year individual performance targets for the PBSs and willmonitor PBS performance against the agreed targets (para. 2.11).

(b) REB will cause PBSs to pay promptly for their electricity purchaseso that the unpaid consumption of any of them at any time - does notexceed the total billed consumption of the preceding two months(para. 2.11).

(c) REB will cause the PBS to reduce their accounts receivable to notmore than 3 months of average billing of the twelve preceding months(the seasonable effect of irrigation being taken into account)(para. 2.11).

-35-

(d) RBE will continue to employ under terms and conditions acceptable toIDA, consultants to provide REB and PBSs with technical assistancerequired for the implementation of the proposed Project, and for theentire on-going rural electrification program, after July 1991(paras. 2.21 and 3.08).

(e) REB will (i) propose not later than December 31, 1990 a datedprogram, satisfactory to IDA, for the installation of capacitors, toensure that the power factor does not fall below 0.90; and (ii)thereafter carry out such program (para. 3.05).

(f) fB will maintain and cause PBSs to maintain records to reflecttheir operation and financial condition in accordance withconsistently maintained and appropriate accounting practices(para. 4.09).

(g) On completion of each scheme under the proposed Project REB willenter into a Sub-Loan Agreement with the PBS under terms andconditions satisfactory to IDA, including (i) a repayment period forthe principal represenzing the cost of the scheme of 25 years afterfive-years grace period starting at the date of PBS comercialenergization; and (ii) an interest rate of three-fourth of onepercent (314 of 1X) during the grace period and three percent (3Z)per annum thereafter (paras. 2.08 and 4.04).

(h) REB will ensure thats (i) its administrative expenses and interestpayments in any fiscal year beginning FY91 shall not exceed amaximum of 752 of the aggregate interest and other revenues receivedfrom all sources during that fiscal year; and (ii) its internalsources of funds. including PBSs' loan repayments in any fiscalyear, shall cover at least 1.5 times the debt service requirement(para. 4.08).

ti) REB will prepare and submit to IDA by December 31, 1990 an actionplan to implement the required reforms to its accounting systems andprocedures and thereafter implement the said plan as agreed with IDA(para. 4.09).

(j) REB will have its accounts and PBS's accounts, audited byindependent auditors acceptable to IDA and furnish, and cause PBSsto furnish, to IDA no later than nine months after the end of eachfiscal year, certified copies of their audited financial statements,the audit report and their comments and, if necessary, a plan forcorrective actions (paras. 4.10 and 4.16).

(k) REB will introduce not later than December 31, 1990 appropriate loadmanagement measures and time-of-day tariffs, so as to ensure anadequate and higher load factor (para. 5.03).

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6.03 The following conditions should be met before Credit effectiveness:

(a) approval of the final Project Proforma (para. 2.10).

(b) introduction of Individual Performance Agreements for the 33operating PBSs (para. 2.11).

(c) actual transfer of 1200 km of BPDB's lines to PBSs (para. 2.15).

(d) conclusion of a Subsidiary Loan Agreement between GOB and REB(para. 4.04).

6.04 Subject to the above conditions, the proposed Project constitutes asuitable basis for an IDA credit of SDR 79.6 million (US$105 millionequivalent) at IDA standard terms with 40 years maturity to the People'sRepublic of Bangladesh.

SANCLAVESH

TSlRD RURAL ELECTRIFICATION PROJECT

BANGLADESH RISTORICAL CIWTH IN DEIWID, MMY MMEEATION AND SA

< --------------------------------------------------------- a¢tuol---------------------------------------------------------- >

nscAL IABM 1975 1974 1975 1976 1977 1978 1979 1980 1981 1962 1983 1984 1985 1986 1967 1968 199

GENEREA 31R GWh 1065.6 1265.4 1322.1 1459.8 1618.6 1912.9 2122.3 2353.3 2661.8 3036.5 3432.7 3560.5 4528.4 4800.3 5587.0 6541.4 7114.8

EASTE ZO2EB RBQUIRU GMh 656.8 982.4 1022.0 1115.7 1224.4 1444.4 1603.5 1744.5 1978.3 2292.1 2465.3 2847.6 5183.5 3365.0 3994.7 457S.0 5098.5

VESTl ZOnE R.EQUIMR3S CUb 228.6 283.0 300.1 344.1 394.2 468.5 519.0 608.8 685.5 744.4 947.4 1112.9 1344.9 1435.3 1592.3 1968.4 2016.3

IRAESPER EAST-VEST C 477.4 222.3 797.8 1179.5 1435.4

ASREII VWEST-ES C 20.6 106.4 10.9 - -

E-V SNTEROOHMM XWSUS GM 22.4 12.1 42.7 90.2 106.2

PEAK DW96D NW 221.6 250.1 266.1 301.3 342.3 395.6 436.5 461.9 545.2 603.7 709.0 761.0 687.0 683.0 1083.0 1316.8 1390.0

ESt ZONE MV 174.4 184.8 198.8 219.9 254.0 287.0 331.3 337.6 599.1 450.7 505.8 552.0 651.0 613.0 745.0 925.4 980.0

VEST ZONE mV 47.2 65.3 67.3 81.4 88.S 108.6 105.2 124.5 146.1 153.0 203.2 209.0 236.0 270.0 340.0 391.4 410.0

SYSTE LOAD FACTOR 2 55.92 37.86 56.72 55.33 34.0S 55.2X 55.52 58.22 55.71 57.41 55.32 59.42 5S8.3X 62.12 58.92 56.72 58.41

EAST ZONE SYST LOAD PACTOR 2 56.12 60.71 58.72 57.91 55.01 57.51 55.22 59.02 56.61 58.12 56.11 58.92 55.82 62.72 61.42 56.42 59.42

VEST ZONE SYSTE LOAD FACTOR 2 55.32 49.52 50.92 48.32 51.02 49.22 56.32 55.92 53.42 55.52 53.22 60.82 65.12 60.72 53.52 57.42 56.11

RE SALES GMN 13.0 44.6 87.8 142.6 162.9 232.9 294.6 372.0

REB LOSSES GOH 19.4 19.2 30.4 55.4 61.1 69.6 91.0

REB PURCHASES CHH 64.0 107.0 173.0 238.3 294.0 364.2 463.0

TOTAL SALES GO 623.9 828.2 855.2 932.0 1013.0 1204.5 1381.3 1406.3 1740.4 2029.1 2283.0 2608.4 2842.0 3306.8 3485.3 3772.7 4695.1 W

LOSSES 11. GON 461.7 437.2 486.9 527.8 605.6 708.4 741.0 947.0 921.4 1007.4 1149.7 1352.1 1686.4 1493.5 2101.7 2768.7 2419.7

S 42.52 34.6S 36.86 36.22 37.4X 37.02 34.92 40.22 34.62 33.22 33.52 34.12 37.21 31.12 37.62 42.32 54.02

CONSUMERS: BPDB '000 258.2 281.8 280.0 305.0 348.4 402.6 450.8 521.2 568.4 645.1 669.2 727.6 803.7 888.6 963.1 1,038.3 1,151.6

CONNECTIONS: RED '000 8.9 20.6 70.3 103.9 153.8 196.9 269.3 325.3 396.1

CONSUMPTION 21. KWHICOR2416.1 2939.1 2982.5 3055.8 2907.7 2991.5 3064.3 2698.4 3061.9 3145.5 3411.5 3585.1 3536.0 3721.5 3619.0 3633.4 4076.9

CONSUMPTION 21. KWHICONE 630.5 634.7 845.2 927.1 928.8 864.6 905.6 "99.

LES VOLTAGE WISELV: .231.4 kw GNE 136.2 187.8 183.5 266.6 381.3 517.5 611.0 614.6 762 4 825.1 944.0 1135.4 1379.0 1662.4 1811.9 1936.2 229".6

NV: 11 kV GOW 487.7 640.4 651.9 663.4 631.7 687.0 770.3 791.7 875.0 1025.0 1133.0 1208.0 1129.0 1244.9 1213.7 1295.1 1766.1

NV: 33 kV OGM 103.0 179.0 206.0 267.0 334.0 399.5 459.7 551.4 629.4

C CONSUMPTIONSDMILV(.4kv) KNEICON 527.4 666.5 654.6 880.7 1094.5 1285.3 1355.5 1179.3 1341.3 1279.1 1410.6 1557.8 1715.7 1870.9 1881.4 1864.7 1996.8

REB/LV(. 4kv) KWHICONE. 630.5 634.7 845.2 927.1 926.8 864.8 905.6 "99.1

DPD0/MV(llkv) NWHICONS. 865.5 675.7 740.0 745.7 686.7 697.8 633.5 676.0 882.6

8PDS1MV(33kv) G4HICONS. 7.2 7.3 7.8 7.3 7.7 7.4

GROWTH RATESTOTAL BFDM SALES <--------------------------- 12.32-----------------><--------- 16.711------------->------------- 13.42--------------->

TOTAL LV SALES <--------------------------- 24.0S-----------------><--------- 16.52-------------><------------- 13.62X---------------

(OUT OF WHICB RESIDERTIAL) <--------- 21.0S-31---------…><------------- 13.32--------------->

TOTAL llkV SALES <--------------------------- 7.2…-----------------1>…--------- l.t------------->2<------------- 11.8…--------------->

TOTAL 33kV SALES <--------- 37.42--31---------><------------- 17.2X---------------'

11. System losses do not include R.E.B. lossea.

21. CONS * Consumer(); COONN - Coranection(s). 31. Period FY1981 - FY1984 only, due to a change in tariff categories during FY1980.

2/. CONS- Consumr(s): COE - Connction(s)N

B A N C L A D e s 4

I71IR9 RURAL ELECTRIVICATION PROJSCT

BANlClADESH CERMTI0tl CAPACITY AND ENRYFORECASTAverage hvrere AverW

XAklfF rcto of rate of rte ofCASCORIES 1985 1986 1#87 1988 1999 1990 1991 1992 IM9 1994 1995 1996 1997 19# 1999 2000 growth growtth growtJhLV RV -------- actual -- l----- t----------------------------------foer cst ---------------------------------- l fy81-89 fy85-89 fy89-00

Residerts- A GM 63S.0 715.8 825.6 885.4 1044.0 1253 1467 1747 2062 2433 2848 3277 3772 *328 4937 5630 A 15.09X 13.49X 16.0XIrtgtlote;. B 3W1 56.0 51.1 36.2 62.9 9f.3 its 133 161 198 240 290 337 391 4$4 S27 607 8 16.211 18.66X '18.3XIndustrt*4 C GMil 317.0 117.4 349.7 370.9 398.1 442 477 529 587 651 722 765 oil 860 906 941 C 7. 96S 6.03S 8.1SIntictttetou D AM 27.0 45.1 76.7 64.5 5S.8 61 64 t0 77 84 92 98 103 108 113 its D 5.14X *.68X 7.0XComercil- E GW 250.0 278.1 S08.7 391.1 531.4 652 768 905 1075 1277 1518 1789 2108 2484 2918 3410 e 17.US2 24.705 18.4XNVGneCral F GMll 1129.0 1244.8 1213.7 1285.1 1766.1 2061 2311 2582 2860 3168 3519 3981 *434 U367 5294 5699 P 9.79S 13.391 11.21NV | OW011 161.0 161.2 IS! 7 I87.2 166.4 189 200 218 237 258 281 292 303 315 327 335 H 4.051 0.371 6.6Xuttters J GMiq 96.0 255.0 19f.0 161.4 175.0 ITS 181 185 189 193 199 201 205 209 213 217 J 2.0XU08 e S^LES to Olll C01SWMSS anl 2669.0 3068.5 3191.3 3408.5 4232.1 4951 5621 6397 7285 8304 9469 10740 12126 13625 15235 16957 12.19S 12.89S 13.45

1Un SALS RllblDEltTAL GWM 34.9 44.8 5B.7 78.9 93.4 116 140 164 193 224 259 Soo 343 392 452 521 27.90X 16.9SCOMMIECAL Clll 9.6 13.9 17.3 21.7 25.5 30 35 42 48 35 GS 70 79 se 98 109 27.66X 14.1ZISRlCATION Clll 26.3 29.5 37.9 51.6 91.8 11 144 179 218 263 312 370 *36 508 584 664 36.69X 19.71TWMt S.RES 111 71.2 93.7 118.0 141.1 160.0 Is? 216 247 278 313 351 390 431 475 523 575 22.441 12.3XO?IIEz Clll 0.6 0.9 1.1 1.3 1.3 2 2 2 2 3 4 5 6 a 11 14 IL4 NA

Rl8 ?OTA SALgS c 142.6 182.8 233.0 294.6 372.0 450 SS? 633 740 858 989 1134 1294 1471 1667 1883 26.721 15.91R158 LOSSS CiW 30.4 U3.5 61.0 69.6 91.0 106 126 139 152 163 175 192 211 230 249 281

X 17.6X 23.31 20.71 MI.X I9.7S 19.01 19.0X 18.0X 17.0X 16.0X 15.0X 14.51 14.01 13.5X 13.0S 13.0S NVG fALSS to RED I Clll 173.0 238.3 294.0 364.2 463.0 556 663 772 892 1021 1164 1326 1505 1701 1916 2166 X 20.21X 26.U5X 15.0X Co

OMD TOTAL SALSS CJII 2842.0 3306.8 3485.3 3772.7 4695.1 5507 6284 7169 8177 9325 10633 12066 13631 15326 1715 19121 13.571 14.08X 13.6XOROVIT R^lt x 9.0X 16.42 5.4X 8.2X 24.4X 17.3X 14.11 14.lX 14.1X 14.01 14.OX 13.51 13.X 12.42 11.9X 11.5X

BYD LOSSES OMB 1696.4 1493.5 2101.7 2768.3 2410.7 2360 2567 2788 S024 1277 3544 3810 *071 4323 43S9 4780X 37.21 3I.IX 37.6X 42.3X 33.9X 30.0X 29.OZ 28.OX 27.02 26.OX 25.0X 24.0X 23.0X 22.0S 21.0X 20.0X

CDMRBIOSNl REBrIIDN anll 4528.4 *800.3 5587.0 6541.0 7105.8 7867 8851 9957 11201 12602 14177 15877 17702 19648 21710 23902 12.58X 11.94X 11.71ORJT RATE 1 13.22 6.0X 16.4X 17.11 8.61 IO.7X 12.51 12.5X 12.5X 12.5X 12.5X 12.0X 11.52 11.0X 10.5X 10.1X

00ERSu BPDR 1000 803.7 888.6 958.8 0138.3 1151.6 1258 1374 1501 1640 1792 1958 2139 2337 2553 2790 3049 9.281 9.45X 9.31CONNCTIONS RED .000153.8 196.9 269.3 J36.6 407.2 471 554 645 745 85U 977 1112 1259 1422 1602 1800 27.01X 25.28X 14.51

8PCC .OSUP MsD 1W03320.8 3453.3 3328.6 A282.6 3674.9 3936 4091 4262 4442 4634 4936 5021 5189 5337 5461 5561 2.23X 2.55X 3.8XanB l>§ll 927.1 92S.S865.28 75.2 91S.6 9f5 1140 1144 99 1003 1012 1020 1027 1034 1041 1046 4.31X -0.47X 1.2X

XhIIBSBDthILSzomREQUIII EAST OM 3l194.7 3367.0 3959.9 4571.3 4994.0 3198 6021 6716 7490 8353 9314 I1033811423 12564 13756 15005 12.66X 12.68X1 0.5X

Wm OM 1302.0 1414.5 1577.8 1872.9^13S0.8 2469 2830 3241 3711 4249 4863 5539 6279 7084 7954 8897 11.49X 9.27X 13.918PD WA l*S28.4 4800.5587.0 6541.0 7114.8 7867 8851 9957 11201 12602 14177 15877 17702 19648 21710 23902

DO-D E45S gm 651.0 613.0 743.0 925.4 980.0 1095 1221 1350 1492 1650 1824 2017 2219 2431 2650 2878 11.691 10.921X10.31IIEST NW1236.0 270.03U0.0 391.4 413.0 509 583 662 751 852 967 1094 1235 1387 1551 1727 13.03X I3.00X 13.9XamD NW1887.0 883.0 1083.0 1316.8 1393.0 1604 1804 20.2 2243 2502 279O 3111 3454 3818 4201 4605 12.211 11.68X11.5X

LOO FACTOS EAST X 56.OX 62.7X 6O.8XS6.4XS8O.1X 56.3X 56.3XS56.8XS57.3S1 7.8X 50.3X 58.5X 58.8XS59.0XS39.3XS59.5XWm 63.OX 39.8X 53.01 54.6t S8.9X 55.4X 55.4X 35.9X 56.41 56.92 57.41 37.8X 58.0S 58.XS85.51 58.8XamD I 58.3X62.1XS89.9X56.7X 58.3X 56.0x 56.0X 56.5X 57.01X57.5XS38.01 5S.SX S8.5X %8.7X 59.01 $9.3X

BANGLADESH

THIRD RURAL ELECTRIFICATION PROJECT

BANGLADES8 MAXIMM DEK0ND AND GMMETATION FORECAST

MAXIMUM DEMAND 1988 1989 1990 1991 1992 1993 194 1995 19"6 1997 1998 19" 2000(2*)

( 1) TOTAL AVAILABILITY 7+16 MNW 1,972 1,935 2,184 2,232 2,506 2,735 2,930 3,440 3,722 3,894 4,644 5,194 5,174

( 2) TOTAL REQUIREMENT 9+21 MW 1,317 1,393 1,604 1,804 2,012 2,243 2,502 2,791 3,111 3,454 3,818 4,201 4,605

( 3) TOTAL AVAILABLE RESERVE 1-2 Mw 655 542 580 428 494 492 428 649 611 440 826 993 569

( 4) REQUIRED RESERVE 8+19+20 MNW 380 380 360 371 371 391 391 481 481 .81 621 660 660

( 5) FINAL SURPLUS I (SHORTAGES) 10A+22 MK (15) (175) 156 57 37 (16) (117) 168 79 (62) 146 193 (91)

( 6) EAST NON TRANSFERABLE SURPLUS 10-14-15 Mw 291 336 64 0 86 117 154 0 51 21 59 140 0

EAST ZONE( 7) AVAILABLE MN 1,592 1,692 1,825 1,814 2,102 2,275 2,470 2,980 3,280 3,452 3,702 4,002 4.002

( 8) LARCEST UNIT MW 210 210 210 210 210 210 210 300 300 300 300 300 300

t 9) ZONE DEMAND MN 925 980 1095 1221 1350 1492 1650 1824 2017 2219 2431 2650 2878

(10) AVAILABLE FOR TRANSFER 7-8-9 If >0 MN 457 502 520 383 542 573 610 856 963 933 971 1,052 824

(1A) EAST SHORTAGE 7-8-9 if <0 Mw 0 0 0 0 0 0 0 0 0 0 0 0 0INTERCONNECTOR

(11) VOLTAGE LEVEL kV 132 132 230 230 230 230 230 230 230 230 230 230 230

(12) CAPABILITY PER CIRCUIT mW 83 83 228 228 228 228 228 228 228 228 228 228 228

(13) NUMBER OF CIRCUITS 5 2 2 2 2 2 2 2 4 4 4 4 4 4

(14) ACTUAL TRANSFER TO WEST Min(12*13,10,21-10OMN) MNW 166 166 409 383 456 456 456 856 912 912 912 912 824 1

(15) EAST TRANSFERABLE SURPLUS Min(10-14,12*13-14) MW 0 0 47 0 0 0 0 0 0 0 0 0 0if >0

WEST ZON!(16) AVAILABLE MW 380 243 359 418 404 460 460 460 442 442 942 1,192 1,172

(17) RECEIVMD FROM EAST 14 Mw 166 166 409 383 456 456 456 856 912 912 912 912 824

(18) MAXIMUM AVAILABLE 16+17 MW 546 409 768 801 860 916 916 1,316 1,354 1,354 1,854 2,104 1,996

(19) IST LARGEST UNIT MW 110 110 90 90 90 110 110 110 110 110 250 250 250

(20) 2FD LARGEST UNIT MN 60 60 60 71 71 71 71 71 71 71 71 110 110

(21) ZONE DEMAND Mw 391 413 509 583 662 751 852 967 1094 1235 1387 1551 1727

(22) FINAL SURPLUSI(SHORTAGE) 18+15-19-20-21 MW (15) (175) 156 57 37 (16) (117) 168 79 (62) 146 193 (91)

GENERATION

EAST ZONE GENERATION GWh 5,751 6,533 7144 8128 9234 10478 11879 13716 15867 17660 19374 20906 22541

EAST ZONE DEKAND GWh 4,580 5,097 5398 6021 6716 7470 8353 9314 10338 11423 12564 13756 15005TRANSFER CAPABILITY GSW 1,454 1,454 395 3995 3995 3995 3995 7989 7989 7989 7989 7989 7989

ACTUAL TRANSFER TO WEST GWh 1,171 1,436 1746 2107 2518 2988 3526 4402 5529 6237 6810 7150 7536

WEST ZONE GENERATION GWh 784 573 723 723 723 723 723 461 10 42 274 804 1361

VEST ZONE AVAILABLE GWh 1,955 2,009 2469 2830 3241 3711 4249 4863 5539 6279 7084 7954 8897

NEST ZONE DEMAND GmW 1,955 2,009 2469 2830 3241 3711 4249 4863 5539 6279 7084 7954 8897

SURPLUS I (SHORTAGES) GNh 0 0 0 0 0 0 0 0 0 0 0 0 0

BANGLADESHTHIRn RURAL ELECTRIFICATION PROJECT

Organ!adtlon Chart of th Rural Elctrlflcatlon Board

_,,I1 I: rE _ F.mm ||It {3I.

[mm }X 11

-41- ANNEX 2.5

RUOIA ElSTRFIGTION IQR

INumbr of Sanctioned nd Actusl Staff ra at June 1989

Top Management-i t 1d881 Mandedtaent-2 Proflmonal-4 Support Staff Totl

Sanctioned Actual Sanctioned Act6.I Sanctiond ActuaI tunl| anctioned Actual

1. Chairman's Office I 1 1(1) 1 a a 4(*t) 4 9(2) 9

2. Secretary 1 1 2(2) 2 SOS) a S( 4) 8 14(.11) 14

3. Peronnel and AdminiatrativeDire.tort.e (.1) - 2 2 7C(S) 7 41(*14) 41 ZOOM1) sO

4. Directorate of Program 1 1 9 8 t 14() 9 14(-7) 7 82(-12) 20

S. Member Eneineering 1 1 - - 1(01) 1 3 8 S(.1) b

6. Chief Engineer (Project) 1 1 1() t 3(1) a S(*0 a S(*?) S7. Chief Engineering (System

Operation and Standard) (.1) - - - 1) . (4) - (.8) -

S. T;mber Products - - 1 1 2 2 8-1) 7 11(-1) 10

9. Superintending Engineer 4 4 4 4 4 4 24 24 86 36

10. Project Division - - 1S I6 48 48 ISO(+12) 1SO 244(*M2) 244

11. Directorate SrytemEngineering Desin 1 1 4 4 4 4 8 S 17 17

12. E A H 1 1 9(e2) 9 74(*17) 74 69(019) 59

13. Directorate of SyrtemOperation 1 1 5(*2) 6(.11) S 24(*9) 24 86(*22) S6

14. Material Planning Standardand Specification (.1) - 1(4) 1 4 4 1(4) 1 6(09) 6

iS. Member Finance 1 1 - 0 1(1) 1 8 8 S(,) S

16. Controller of Accounts andFinanee (01) - - - - (43) - (4) -

17. Directorate of Finance I 1 8 8 15 1 8(-S) o 27(-S) 24

1i. Internal Audit - - 1 1 2(*d) 2 9 9 12( 1) 12

19. Accounts Directorate (-1) - 6(+1) 8 810(19) 81 14(*4) 14 48(+25) 48

20. Procureaent Directorate 1 1 8 8 5(*1) a 6(1) 6 1S(d) 1S

21. PBS Lans and Audit 1 1 2 2 6(*4) 6 10(-1) 9 19(*3) 18

22. Member (P8S and Trainine) 1 1 - - l(*1) 1 a 8 a (41) 5

2. Executive Directors (QqDevelopment and Management) (01) - - - _ _ (.8) - (*4) -

24. Policy Development andReview P8S/RE - - (.1) _ (1) - (1) - (8) -

25, Training 1 1 8 8 7 7 17( 1) 17 28(+1) 28

26. Management Operation andDevelopment (North Zone) 1 1 8(+I) 8 G(O 6 S 8 18(06) 1S

27. PBS Development and HmnagementOperation (South Zone) 1 1 8(*1) 8 4(*7) 4 5(*3) a 13(*11) 18

20(.6) 20 66(41S) 68 186(+9) 181 478(*74) 468 747(+182) 730

* Denotes the proposed post.

- Denotes the posts which have been surrendered in spite of the apprvel given by the OSMAN CMOga,ES

-42-ANNEX 2.6

INMR "A"L ELEC1RIPICAUWI PROJECT

Timing. Cost and Financing of the RE Propram

-Cost (Tk Biliton)-- Financing ImplementationACRE No. PMS Local Foreign Total Source USI Mltlilon Period

Phase 1 18 0.8 1.t 2.1 USAID 79.2 1978-88

Phase 1 Ext. 8 0.6 0.7 1.8 KFAED 29.6 1981-872 PUS Ext. 0.06 0.1 0.2 AD 10.8

Phas 2-A 5 0.6 0.9 1.4 USAID 40.0 1982-89Finland 6.7

Phase 2-8 7 0.7 0.9 1.6 IDA 40.0 1982-89

Phase 8-A 7 1.6 1.7 8.2 IDA 79.0 1986-92(Ext. 5)

Phase 8-8 Int. PS 0.6 1.5 2.1 USAID 60.00 1987-98Phase 1/1 Ext.

Phase W- Subst. Ext. 0.06 0.1 0.1 Finland 4.4 1987-91

Pha8se 8-c It. P8S 0.5 1.4 1.9 Canada 28.0 1987-92Phas 1 Ext. Saudi Arabia 16.0

TOTAL ONGOING 40 5.2 8.9 14.1 891.2

Phase 4-A 4 2.1 8.2 5.8 IDA 105.0 1991-97(Ext. S/mnt. 7)

Phase 4-0 1992-2000

Phase 5 1997-2005

-43-

ANNEX 2.7Page 1 of 2

BANGDES

TRIRD RURAL ELECTRIFICATION PROJECT

Selection Criteria for Areas to be Electrified

1. For past operations the criteria employed by RED (developedjointly by REB and NRECA with USAID approval) to study, rank, and selectnew areas of the country for electrification, places emphasis onInfrastructure and numbers of potential consumers. The steps followed byREB in identifying priority areas are as follows:

(i) Selection of a large number of prospective upazillas for detailedstudy: these areas are distributed throughout the country toachieve regional balance in the initial stages of identification.

(ii) Collection of detailed data for each upazilla (or group ofupazillas) covering the following subjects:

- available power supplys this covers available MW capacity on132 (33 kV substations, after assessing total installedtransformer capacity and maximum demand at the substation, andcapacity of 33 kV lines);

- number of villages in the area;

- area population;

- number of households;

- area in square miles;

- miles of paved road in the area;

- percentage of land area likely to be flooded regularly;

- number of institutions (bank branches, extension offices, etc.)in the area;

- extent of irrigated land;

- numbers of tubewells and diesel-driven pumps, covering shallowand deep tubewells, and low-lift pumps;

- number of commercial establishments; and

- number of small, medium and large industries.

ANNEX 2.7Page 2 of 2

(iii) Each major infrastructure and consumer potential indicator isranked among areas, using a straight numeral ranking beginningwith 1 for the top area in the category, after eliminating thoseareas that do not have surplus substation and 33 kV line capacity.Weighting factors, developed in the Phase I feasibility study andranging from 0.3 to 1.0, are then applied to the rank of eachcategory. The sum of the adjusted ranks of categories for eacharea constitutes that area's final overall ranking; the lowestnumber represents the highest overall rank.

(iv) If an extreme regional imbalance emerges from the strict rankingprocedure, constraints representing regional equity considerationsare applied, i.e., a minimum number of areas per region isobserved.

2. For the proposed Project, in addition to the criteria indicatedabove, a financial simulation of the candidate PBSs was carried out usingthe PBS financial model developed by Coopers and Lybrand Associates. Thefour new PBSs selected to be developed under the project ranked among thebest and all of them showed good prospects for financial viability.

-45-

ANNEX 2.8

T?K IAL CTI BOA

Status of Transfer of BPDB Lines to the 33 PBSs in Operation(As of June 30, 1989)

Name of PBS Taken Over To Be Taken OverAs of June 30, 1989

(KR) (KH)

Dhaka PBS-I 225.30 64.9Tangail PBS-I 96.00 -Comilla PBS-I 248.54 16.0Chandpur PBS 217.45 77.6Moulavibazar PBS 95.30 -Habigoni PBS 133.67 6.9Pabna PBS-I 141.01 -Pabna PBS-II 52.00 -Sirajganj PBS 137.00 -Natore PBS-I 117.85 -Natore PBS-II 55.62 -Jessore PBS-I 254.39 68.8Jessore PBS-II 97.39Rangpur PBS-I 128.89Satkhira PBS 64.88Kushtia PBS 149.00 64.0Pirojpur PBS 68.50 151.2Mymensingh PBS 87.16 147.0Peni PBS 223.65 9.6Joypurhat PBS 23.70 24.8Dinajpur PBS 339.90 11.2Rangpur PBS-II 309.92 163.8Bogra PBS 15.90 68.8Thakurgaon PBS 177.00 153.6Jamalpur PBS - 22.4Chittagong PBS-I - 159.2Madaripur PBS 55.29 12.3Barisal PBS-II 45.59 111.8Bagerhat PBS 144.79 32.6Meherpur PBS 33.27 184.8Narsingdi PBS-I 8.10 32.0Chittagong PBS-1I - 172.8Noakhali PBS - 55.2

TOTAL 3,747.06 1,811.3

-46-

ANNEX 2.9Page 1 of 3

SANGLADES

UB RUn &CTRICATXO3 PROE

EBB Training Program

Total 'EB-conducted Training. Trainees by Recigient Category

iEB Personnelt 122 19SPBS Personnelt 496 78?Other Personnels 15 2S

REB-conducted First Year Level vs. Advanced Training

Trainees Periods Trainee-Days

First Year Levels 300 47Z 900 515 1,752 531Advanced Levels 333 53S 877 49? 1,571 472

Training Course Implementation: to Date and for April-June, 1989

-TRAINEES----NAME Of COURSE PARTICPANTS Class 4/S9O To

P-er lodl 8/SO OatsCOURSES FOR PBS BOARD DIRECTORS:Choi leong and Problems in the POS PBS Dirncter, Lay Advisors - - 79Establishing Good Member Relation PS Directors, Lady Advisors 17 11 174PBS Directores Orientation Cour PBS Directors, Lady Advisors - - 647Policy Devlopment PS Di eOters, Lady Advisors 24 81 308The PBS Director In the Board Roe PMS Directors, Lady Advisors 84 20 950Understanding Financial Reports P8S Directors, Lady Advisors 18 11 SOOUndorstanding Policy Instruction PBS Directors, Lady Advisors 88 20 18Workshop on P8S Policy Instructions PS Directors, Lady Advisors, WMe - - 189Board Meting *nd PMS MNnament Intro. PS Directors, Lady Advisors - - 19PBS Board Retrh r Course P8S Directors, Lody Advisors 42 81 81

FINANCE COURSES:Accounting REB/PIS Finance Personel - - 138Auditors Orientation Course Contract Auditors - - 263Billing Procedures Flance Personnel - - 206PBS Audit Manual Court PBS Finance Personnel - - 43Prparing Financial Reports PBS AM (Finance) and Accountant - - 193Procuremnt Proedurs RE, PBS OffIcors - - 31REB/PBS Geneanl Account RnB, PBS Finance Peronnel - - 277Retill Rat Constercion PBS AC (Member Service) - - 14Understanding Financil Reports RED/P8S Otopirs - - 87Work Ordr Procedur nd CPR RED Oficers/PBS Finanoe Personnel 42 87 278Workshop on Imprest Fund REB Personnel - - 81

MANAGEMENT COURSE$:Class for Departmental Exas RED Personnel - - 84Controlling and e souring Reslts PBS Directors, Lady Advisors - - 14Duplicating Machin Operation PBS Offloo Employ e - - 89Effectiwe Management of the PBS REB Dirctors - - 16Manaesemt: ItO mature nd Scope RE Off Icr, PBS Ose, AGVM 27 19 616Managments Understnding People MM Off icer, PBS On., AGMa - -

lgng the CO Depar PS Dpt. Nad (CO) - - 49Managing th OS D rtt PBS AM(4S) - - 8SMonaling the MaPoertes Dept. PBS ACN(GS) 21 10 124Managing tah P1S P8S rl Manager - - 14Managing thme OBSn Depart PBS AOM(FIN) - - 1

-47- ANNEX 2.9Page 2 of 3

----- TRAINEES-----NAME OF COURSE PARTCI-PAT Cilass 4/09- ToPAtTSCSPANTS Per!ods 8/ Date

New Connection Procedures PBS Flnnce , GS Personnel - - 27Office and Administrative Duties RU Line lspector - - 49OffIce Man 9agont Ra, PaS Manageont Personnel 21 t 145Office Procedure/Pcrsonn.l Policy RU Officers - - 29PBS Enforcement Course PBS Assistant Enforcement Offtler - - 16Planning and Organizing PBS GU., ACM. - - 176Reords Mnagemnt RED, PBS Offleer 21 5 160Training of Trainers Course Selocted REB Offic rs 67 a9 89The Nature of Supervision RES ADb and Class 1I Officers 42 a3 131Introductlon to POS Instruction RE/PBS Offi crs - - So

ORIENTATION COURSs:Orlentation Coure REB, BS Offic rs and Support Staff so as 1,449Refresher Course on REB Activities REB Officers and Supporting Staff - - S18

COS4RUCTICN COURSS:DistrTbution Line Construction Contractor Linemen and Supervisors - - 6O4Lin Construction Orientation Construction Contractor Principles - - 275POS System Construction/Inspection REB, POS, Consultant Engineers - - 764Substtiton Construction Workshop RIC Consultants and Sub Contractors - - 71Wrehoue Managemnt RE3, POS Stores, Personnel 42 21 339

CONSUMER WIRING AND POWER USE COURSES:Power Use In the PS Wiring Coordinators/Itnpectors - - 14Advaned Consumer Wiring P8S Power Use Personnel - - 525Housneiring Course MS Dept. Personnel 61 15 884

s System Introduction MS Dpt. Personnel - - 11

ENGINEERtNG COURSES:Distribution Line Staktng RES, PBS, Consultant Engineers - - a05POS Line Renovation RE8 Local Consultant Engineers - - 28PBS System Design RUS, Consultant Inspectors - - 49P-s SystmO Destgn and Construction REU, Local Consultant - - 227Timber Speciaists Orientation RES Timber Specialists - - 6

OPERATIONS AD0 MAINTNANCE COURSES:Capacitors and Power Factor Control RE8, CON and MS Dpt. Personnel - - 16SCON Accounting RE and CON Dept. PRrsonnel - - 47Distribution Syste Introduction POS nd AQM(FIN),(GS),(MS) 48 1S S1Driver Skills Training REB Drvers - - 64OCR/Regulator Maintenance, Repair Operations and maintenance Personnel - - S8PBS System Operation and Maintenance RED AE, PBS AGM(COM) and LB - - 141Single Phase Meter Maintenance, Repa r meter Specialists - - 81Single Phase o btsr Testing POS CO8M Personnel - - 161Substation Introduction COm Personnel - - 77Transport Maintnance REB I POS Personnel 10 5 204Tractor and Truck OAM Equipment Operators, Supervisors - - sWireloe Operation and Maintenance POS COUM Personnel - - 185

PBS LINESMN COURSES:PBS Lineman's Tra inng, Part I PBS Linemn 8S7 28 725PBS Linman's Training, P rt II PUS Linemen 147 16 468PBS Linesmn'o Training, P rt III PBS Lineman - - 122PBS Not Line Maint nance Cours 8S Lineen 876 8 8

TOTAL CENTRALLY ADMINISTE' - COUSE TRAINING 1,148 487 18,726

Conferenco, Workshop., Foru, etc. PBS General managers - - 18OAM(MS - - 67ACQ (F - - 89AGM(COM) 21 8T 87Contractor Flrms - - 114REB Engineers, Consultents 869 8 8SOPBS Staff for Accounting Manual - - 97

TOTAL RN C4UNERENCES, ETC. 6o 70 824

-48- ANN 2.9Page 3 of 3

-AmINEES---OKIE OF cOU=E ,H Crse Clel 4/89- To

Periodo f/9 f It

Fleld Training Proram ArranSg by RE Training 1lerstorat:PM Genr m re - -PMS Bard M or EU En wr an S AGCOM) - - 1am Staff - -

AOl (OS) - - 22A (s) - - 23AOMFDIN) and Finno Saf 81 2 150CoraOtr Lime - - 124El.ctrell and IS Staff 20 1S 76Polytschnic Stud - - 10S Linemen - - 18

TOTAL FIELD TRAN BY RENO 109 97 626

TOTAL RU-CUIICTBD IRAIN 1,815 604 16,176

PB5..t 7 T CONCUCTID MB ?R TRAININ DRECTOATEs

P-Condue Linemen S"el Part I: (Linemn *ho passed the RO eam) 89 517

PUS-Conducted Houewlring Courete (Eloctrieoins qualified by RM) 6 2,476

Sourmo: RED/NRECA

TI"R UAL mRVICATMN PiEC

Omnlztlon Chart of Patt l idyat SJlItee(L" than 30,000 C.enoetlonn)

I l_rs IPo of Dl truon|

I rol vn"O

AG wrnl S*rv"1 A S Conrctlon AC inw A0t Etonse *a nd Mal nnosm . Wr S1rla

_ l sotaticz Billingl VW

Col lactio_ SInot _ ~~~~~~Pewr Uz

*dJorw | q Stono Typing

_ Ibter l -| l 9 ~~~comsozpuln

HI. JML .iC1RPlCATMN PROJECT

Oraamlzatlon Chart of Pal II eldft Samitlee(8,0oo to 50,000 Connctions)

Dosrd of Diror

LW _

ConsInt I

Genera I Managr

Steno Typis

AM Gneral Servi ACM Construction AC lnnmn ACM EngInelring ACM Extenion *nd*nd Iint nrnom and Stores r Servics

_ tbin*n nco Right of Way _ lIerand Operalslon _ _Procurement and Education

_aA&lni tr t Bl l l Ing nd Cloerning

0 r ~~~~~~~~~~~Ptr sConCulr

Mbterlnl | -i amProcure t *nd SrLnnd Stores 1 Typin | ! tWehousing

-[ lSoeoe Pool g {Cl-ric l j { ~~~~~~ComplantsH

, , 4 lS~~~~~~~~~~~ouse Wirin g°

t lh*er Reading | ! Xx lR~~0

0,l

-51- ANNEX 2.11

------------------------------------------------------------------ ___-__

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_- ae a e a a e a e e e a a e I IV 8 e U * e e e V s U e I 91 I

,~j j4 e a w : fi~ a s s a a a : : a a 3 w a a a a a a a : # a a

& Vi, a a t ;2 a , aa in ,e, sS;l ausna 8l g :S ,a;-e8s5 a a * aimI - -----------------------

j1h jG S a u Z Sa | a S a at a 8a a a. mat gS| a a

i J a a a a a a a ae 2 S a a 8 il 3 aS 11t 1 tt

u X - --- -- - -- - -- -- - -- - -- - -- - -- - -------- _--__________

~~il g g 23; S 8s 3 1 s Si f S S t;eS e ReI S |1 _ __ -_____________________H____ ______H________________ - --- ----------

I> 16 8 8 8! 8 1 I 8888!91SI 8* 38. a3 | 98 U 88 S3f SW 1

£A! s as ! fa r a n a a _ e e * 4 4 a d a n a a ff _ a o a ff _ _ _ _ _ £ !n :8 8 I s: £ 3t ; w sa s 1 :8 q e 3 Sl 3 3 3 3 : 3 8 : 2 3 3; 8!a

Ji9- qs 0 4 6 0 0 0 0 0 U_ e H e0 HO >: e .4 H H H H E . ff00ff9#>$

i ai a 8 a t S U Z w S a aw | # a8 1n z U ,e aj 8 a 8 3 8, E 8 ; X e- U * ti H H H H H H. H. H. UtJ S 5 tf a U n. H H H a 84 H f H H U U 8 5n

$ ma 8 fn"nf a nu ul e aw n a ffa n ff n a ff ff

---------------------------------------------------------------------

| sil :I § A 8i ii I !8 i~ 8 *i i 0 I i -§ 8 Ii o 11181 i§

-§--!-1- t g I i v s sI ti A-.4-R iiA 4 6______6§j}2

PRI 4 i I n 4 1!!!§ § i Z .! . . .

.= "4.4 .. 6 - 4.-. .... .4 4 4aa a .i4 4.4 4.4. -

-52-

ANNEI 3.1Page 1 of 2

TuM Ruu.L CuIncUOu PROJUCT

IUBL LS CIOI BOARD

Proiect Details

The design of the proposed Project is based on a model PBS spreadover an area of 1,500 square km. Quantities of material designed for amodel PBS have been used for the Project. Vhen the Project starts, the newareas will be surveyed and actual bills of material will be prepared. Inorder to start the Project, 25Z of material included in Tranche One will beprocured without preparing the detailed survey and design. The subsequentprocurements will be based on detailed survey and design and will includeany adjustment in quantities of material required to be made out of firstprocurement.

Lines

1. It is estimated that the proposed Project would consist of about70 km of 33 kV and 5,965 km of 11 kV three phase and single phase primarylines. The 33 kV lines would be for taking supply from existing BPDBsystem. All lines would be on wooden poles. In addition there would beabout 4,590 km of low voltage secondary lines (including about 1,575 km ofunderbuilt LV lines).

2. The main physical features of the lines are summarized below.

3. Primary Lineskm

(a) 33 kV 4/o ACSR conductor 70(b) 1116.35 kV, 4/o ACSR conductor and 1lo ACSR neutral wire 1,530(c) 11/6.35 kV, 1/o ACSR conductor and t3 ACSR neutral wire 575(d) 11/6.35 kV, 13 ACSR conductor and 13 ACSR neutral wire 1,905(e) 6.35 kV, 110 ACSR conductor and #3 ACSR neutral wire 300(f) 6.35 kV, 1 ACSR conductor and 13 ACSR neutral wire 1,655

Sub Total 6,0354. Secondary Lines

(g) 3-phase, 4-wire 13 ACSR conductor and 13 ACSR neutral wire 165(h) 1-phase wire 13 ACSR conductor and t3 ACSR neutral wire 1,680(i) 1-phase insulated conductor 13 Duplex 930(j) 3-phase insulated conductor 13 quadruplex 240(k) underbuilt lines with 13 ACSR 1.575

(702 single phase 301 three phase)Sub Total 1/ 3,015

1/ Excluding the underbuilt lines.

-53-ANNEX 3.31Page 2 of 2

Substations

5. There will be 18 substations, each substation consisting of thefollowing equipments

Description Per Substation

(a) 33122 kW, single phase, 1,667 kVA powertransformer 4 Nos.

(b) automatic voltage regulator, 700 amperes at6.35 kV, 467 kVA capacity, single phase 3 Nos.

(c) automatic circuit recloser(i) three phase, 15 kV, 6000 A interrupting

capacity, 100 A continuous rating200 A minimum trip 2 Nos.

(ii) single phase recloser, 70 A load, 140 A trip,4000 A interrupting capacity 6 Nos.

(d) 34.5 kV class outdoor potential transformer33 kV/240 volt stepdown operation, 50 HZ 2 Nos.

Ce) wound type current transformer to be installedon 33 kV busbar for metering purpose ratio150-30015A 2 Nos.

(f) 6350/240 volt 5 kVA single phase conventionalstation service transformer 1 No.

(g) metering cabinet including all meters 1 No.

Consumer Connections

6. It is estimated that the infrastructure would enable the followingconnections to be given to the consumerst

Year 1993 1994 1995 1996 1997 1998 1999

Connectionss

Residential 12,220 21,946 39,413 70,784 127,098 128,369 129,653Commercial 3,016 4,919 8,023 13,085 21,341 21,661 21,986Irrigation 1,128 1,687 2,523 3,773 5,642 5,642 5,642Industrial 576 861 1,287 1,925 2,879 2,879 2,879

TOTALs Cumulative 16,940 29,413 51,246 89,567 156,960 158,551 160,160

-54- ANNEX 3.1Page 1 of 4

Third Rural Eletrlficalo ProjTable 801. II PDDetaileld Cost Table

Take

B.e. Coata

1381 1992 1908 1904 1095 1038 10t0 Totl

I. INVESTMT COSTS

A. Line Materiale1nsul.PItting Hardare 7.0 23.7 21.5 84.9 20.5 15.4 5.0 189.7Bare Condutor 1s.8 62.0 59.1 76.5 6U.1 38.0 12.2 306.9Insulated Conductor 5.6 19.1 21.$ 21.0 21.8 12.8 4.5 112.1Pin Insulator 0.4 1.4 1. 2g1 1.6 0.0 0.3 6.2Sueapenlon Insult.ro 0.0 2.1 2.8 8.1 2.3 1.4 0.5 12.3Spool Inulator. 0.1 0.4 0.4 0.6 0.4 0.2 0.1 2.2Conductor Accoorbes 0.9 3.2 3.5 4.7 8.5 2.1 0.7 18.?our & Oroundia Wire 1.2 8.9 4.4 5.0 4.4 2.6 0.9 28.2Connecter 1.2 4.2 4.7 6.1 4.7 2.7 1.0 24.6Oldetributton Transorer. 11.2 21.0 42.5 t5.9 42.5 24.6 6.9 223.5Sectioaslasn Devices 3.1 10.7 11.9 15.7 11.9 0.9 2.5 62.9Oil Cirit woelo..rs 1.2 4.2 4.7 8.2 4.7 2.7 1.0 24.0LT Capaectors 0.9 8.0 3.3 4.4 8.3 1.0 0.7 17.5:o:aing Cable 0.4 1.4 1.6 2.1 1.6 0.9 0.3 0.4Stret Light Equipment 0.5 1.3 2.0 2.0 2.0 1.2 0.4 10.5Single Phaa Metr. 3.0 10.3 11.5 15.1 11.5 6.0 2.4 00.4There Phase metre 1.9 6.5 7.8 7.4 7.8 4.2 1.5 16.3Spar.. 0.4 1.3 1.5 1.9 1.5 0.6 0.3 7.750 ft Treated Wood Poles 0.0 0.1 0.1 0.1 0.1 0.1 0.0 0.045 ft Treated Wood poloe 0.2 0.5 0.6 0.6 0.0 0.8 0.1 3.140 ft Trted Wood Poles 1.0 8.6 4.0 5.2 4.0 2.3 0.0 20.935 ft Treted Wood Poles 0.6 2.2 26.9 84.0 25.0 15.0 5.5 180.230 It Trted Wood Pole. 6.4 21.9 24.5 S2.2 24.5 14.2 5.2 121.925 *t Treted Wood Pole 2.8 7.6 3.7 11.5 8.7 5.0 1.0 45.8Tr"ted Wood X-Am 0.9 8.2 8.0 4.7 8.6 2.1 0.7 13.7Treated Aach.& Stab. Log 2.2 7.0 6.5 11.2 6.5 4.9 1.0 44.7

Sub-Total 75.0 255.0 215.0 372.8 285.0 165.0 60.0 1497.9B. Subtation Materials

88/11kV Poer Transformer 2.0 6.8 7.0 10.0 7.0 4.4 1.0 80.3Auto Voltg R"ulator. 0.9 2.9 8.8 4.8 8.3 1.9 0.7 17.23-ph Auo Circuit Recloe 1.6 5.8 5.0 7.6 5.9 8.4 1.8 81.384.6kV Potential Transeo 0.6 1.9 2.1 2.7 2.1 1.2 0.4 10.90.8/.24kV-5kVA Serv.Trteo 0.8 1.1 1.2 1.0 1.2 0.? 0.2 0.3Metering Cabinet u Meter 0.2 0.6 0.7 0.0 0.7 0.4 0.2 8.6Misc. Material 3.1 10.6 11.9 15.0 11.9 0.9 2.5 62.5Spare Per" 0.2 0.5 0.0 0.8 0.6 0.8 0.1 8.1

Sub-Toal 6.7 29.7 8.2 48.7 88.2 19.2 7.0 174.9C. Support C_omditie.

Line Toole 4.0 9.9 9.9 0.6 1.0 0.0 0.0 82.6Test Instrunt. 0.9 1.6 1.8 1.2 0.3 0.0 0.0 0.0Misc. Equip_mt 0.0 1.1 1.1 0.6 0.2 0.0 0.0 8.6Vehicle. p) 0.7 1.4 1.4 1.0 0.2 0.0 0.0 4.0Vohile. (ick-up) 0.6 1.1 1.1 0.0 0.2 0.0 0.0 8.6Hydraulic Crane 1.4 2.9 2.0 1.9 0.5 0.0 0.0 0.6PF Correction Equipmet 1.6 3.8 3.3 2.2 0.0 0.0 0.0 11.0Co_nnleation Equip_mt 1.5 8.1 3.1 2.1 0.5 0.0 0.0 10.8

Sub-Total 12.3 24.6 24.0 16.4 4.1 0.0 0.0 62.10. Lino Construction 0.0 10.0 15.0 20.0 20.0 20.0 15.0 100.0E. Substation Contruction 0.0 1.0 1.6 2.1. 2.1 9.1 1.0 10.5f. Conweltat Servie. 12.1 14.6 14.0 14.6 14.0 14.t 12.1 91.14. Genral Plant 0.0 5.9 8.3 11.7 11.7 11.7 0.6 59.?M. REB 0/11 A Other 0 pease.

REI Owerheede 1.4 4.3 5.7 5.7 4.8 4.3 2.0 21.0SE Office 0.7 2.1 2.9 2.0 2.1 2.1 1.4 14.8PBS Deelomet 0.2 0.7 0.7 0.7 0.0 0.0 0.0 2.4Training 0.0 0.5 0.0 0.0 0.5 0.4 0.0 2.5PBS Opratig Expenses 0.0 1.2 1.0 2.4 2.4 2.4 1.6 11.9Comp_n.tor B1 eyst.T/0 0.0 0.0 14.9 20.8 14.0 3.9 0.0 59.5

a - - - - -- - -~~ - - -

Sub-Totl 2.4 6.6 21. 88.1 24.2 16.1 0.1 119.2

Total INVESTWENT COSTS 110. 3409.7 400.4 14.5 804.9 250.7 110.5 2140.3

-55- ANNEX 3.1Page 2 of 4

SANOLAmSThird Rural Eletbrifluteon Project

Table 302. PBS EXTENS100/1NTESTIFICATIONDetailed Coat Tablo

Take

sees Ceot

1991 1992 19CJ 1994 19o 1996 1997 TotaI

I. INVESTMENT COSTS

A. Line MaterielsInsul.fittinga& Hardware 4.4 14.9 10.7 22.0 10.7 9.7 8.5 8?.9Bare Conductor 9.6 82.7 86.0 48.1 86.0 21.2 7.7 192.5Insulated Conductor 8.5 12.0 18.4 17.0 18.4 7.6 2.6 70.8PIn Insulator 0.8 0.9 1.0 1.8 1.0 0.6 0.2 6.2Suspenslon Insulators 0.4 1.8 1.5 1.9 1.5 0.9 0.8 7.6Spool Insulators 0.1 0.2 0.8 0.4 0.8 0.2 0.1 1.4Conductor Acceaeories 0.6 2.0 2.2 2.9 2.2 1.8 0.6 11.7Guy A Grounding WIre 0.7 2.5 2.8 8.7 2.8 1.0 0.6 14.6Conneatoer 0.8 2.6 2.9 8.9 2.9 1.7 0.6 15.5Distribution Transformrs 7.0 28.9 26.? 85.2 26.7 15.5 6.6 140.7Sectionaliiang Devics 2.0 6.7 7.5 9.9 7.5 4.3 1.6 89.6OlI Crecuit Recloes 0.8 2.7 8.0 8.9 8.0 1.7 0.0 16.6LT Capacitors 0.6 1.9 2.1 2.7 2.1 1.2 0.4 11.0Me4teing Cable 0.8 0.9 1.0 1.8 1.0 0.6 0.2 65.Street Light Equipment 0.8 1.1 1.8 1.6 1.8 0.7 0.8 6.eSingle Phase Metrs 1.9 6.5 7.2 9.5 7.2 4.2 1.5 38.0Three Phase eters 1.2 4.1 4.0 6.0 4.0 2.7 1.0 24.2Spares 0.2 0.8 0.9 1.2 0.9 0.5 0.2 4.660 ft Tretod Wood Poles 0.0 0.1 0.1 0.1 0.1 0.0 0.0 0.445 ft Treated Wood poles 0.1 0.8 0.4 0.5 0.4 0.2 0.1 2.040 ft Troated Wood Poles 0.? 2.2 2.5 8.8 2.5 1.4 0.5 18.285 ft Treted Wood Poles 4.S 14.6 10.8 21.4 16.8 9.4 8.4 85.780 ft Treated Wood Poles 4.1 1S 8 16.4 20.8 15.4 8.9 8.2 61.125 ft Treated Wood Poles 1.4 4.9 5.6 7.2 6.5 8.2 1.2 26.8Treated Wood X-Are 0.6 2.0 2.2 2.9 2.2 1.8 0.5 11.Treted Aneh.& Stab. Leg 1.4 4.6 5.8 7.0 5.8 8.1 1.1 28.1

Sub-Total 47.2 16O.S 179.4 286.0 179.4 108.0 87.8 944.1S. Substation Materials

88/llkV Poer Transformer 1.1 8.0 4.0 5.8 4.0 2.8 0.9 21.8Auto Voltage Regulators 0.5 1.6 1.7 2.8 1.7 1.0 0.4 9.28-ph Auto Circuit Reloe 0.0 2.6 8.2 4.2 8.2 1.6 0.7 16.784.5kV Potential Transfo 0.8 1.0 1.1 1.6 1.1 0.6 0.2 5.96.S/.24kV-SkVA Serv.Trafo 0.2 0. 0 0.6 0.6 0.0 0.4 0.1 8.8Metering Cabinet k Meter 0.1 0.8 0.4 0.5 0.4 0.2 0.1 2.0Misc. Material 1.7 6.7 6.8 .8 6.8 .7 1.8 38.4Spare Pert 0.1 0.8 0.8 0.4 0.8 0.2 0.1 1.6

Sub-Total 4.6 1.6. 17.7 28.8 17.7 10.8 8.7 98.3C. Support Ceoioditie

Line Tools 1.4 2.8 2.6 1.9 0.5 0.0 0.0 9.8Test Instrumente 0.8 0.5 0.5 0.8 0.1 0.0 0.0 1.7mistc. Equipment 0.2 0.8 0.8 0.2 0.1 0.0 0.0 1.1Vehicles p) 0.2 0.4 0.4 0.8 0.1 0.0 0.0 1.4Veh IceOs (tpc-up) 0.2 0.8 0.8 0.2 0.1 0.0 0.0 1.1Hydraulic Crone 0.4 0.6 0.6 0.5 0.1 0.0 0.0 2.7PF Correction Equipment 0.5 0.9 0.9 0.6 0.2 0.0 0.0 8.1Comunication Equipment 0.4 0.9 0.9 0.6 0.1 0.0 0.0 2.9

Sub-Total 8.5 7.0 7.0 4.7 1.2 0.0 0.0 28.8D. Lino Constructlon 0.0 6.S 9.4 12.6 12.6 12.0 9.4 68.0E. Substation Construction 0.0 0.7 1.1 1.5 1.5 1.6 1.1 7.5f. Consultant Servies 5.4 6.2 0.2 6.2 6.2 6.2 6.2 54.4G. RED O/H & Other Expenes

RED Ovorbade 1.2 8.6 4.8 4.8 8.6 8.6 2.4 24.1SE Office 0.6 1.9 2.6 2.6 1.9 1.9 1.8 12.6Training 0.0 0.6 0.9 0.9 0.3 0.4 0.0 8.6Compens.for GM eyet.T/O 0.0 8.7 12.1 6.7 5.2 0.0 0.0 84.6

Sub-Total 1.6 14.9 20.4 17.0 11.5 5.9 8.7 76.2

Total INVESTMENT COSTS 62.6 218. 248.2 808.2 282.0 142.8 68.9 1260.7

Total 62.6 218.5 248.2 808.2 282.0 142.8 68.0 1260.7

-56- ANNEX 3.1Page 3 of 4

BAIADESHThird Rural Electrifleatito Projec6Table 803. RNO Central Faecllt es

Detailed Coot TableTake

1991 102 1998 1904 195 90-97 Total

I. INVESTMENT COSTS

A. FuncClonel BuildingsH"A Complex (10000 sqi) 0.0 87.8 42.7 16.0 10.7 0.0 106.7Training Complex(lOOO qm) 0.6 1.8 1.6 0.0 0.0 0.0 4.1Main Workshop (1000 sq) 0.6 1.8 1.6 0.0 0.0 0.0 4.1Warehouse (0soq.) 0.9 2.7 2.4 0.0 0.0 0.0 6.1

Sub-Total 2.1 48.7 48.8 16.0 10.7 0.0 120.9S. Resdential Buildings

C-Typ 2 unite 140 uq ea 0.0 0.6 0.? 0.2 0.2 0.0 1.6d-Typ 6 unite 10eqm ea 0.0 1.3 1.5 0.6 0.4 0.0 8.7E-typ 12 unite 96 sq ea 0.0 2.8 2.6 1.0 0.? 0.0 6.5F-type 32 unite 67 sq so 0.0 4.2 4.? 1.8 1.2 0.0 11.9Training Hostel (400 sqm) 0.3 1.0 0.9 0.0 0.0 0.0 2.3

Sub-Tote I 0.8 0.3 10.4 8.6 2.4 0.0 26.0C. Other Constructlon Works

Opo St ck Yard (4000 q) 0.0 0.4 0.4 0.2 0.1 0.0 1.1S 1 Steak Yard (ISOOpsa) 0.0 0.2 0.2 0.1 0.1 0.0 0.5Utilities 0.0 4.5 5.2 1.9 1.8 0.0 12.9

Sub-Total 0.0 6.1 5.8 2.2 1.5 0.0 14.5D. Equipment 0.0 2.8 9.2 9.2 2.8 0.0 22.9E. hesign A Superviston 4.6 4.6 8.0 1.8 1.1 0.0 16.2F. Land(80 acrs)

Lend Acquisition 45.8 45.3 0.0 0.0 0.0 0.0 90.7Lend Rogistr. A Develop. 18.8 13.3 0.0 0.0 0.0 0.0 26.?

Sub-Total S8.? 58.7 0.0 0.0 0.0 0.0 117.4

Total INVESTMi ET COSTS 65.? 123.7 7B.7 82.8 17.0 0.0 816.9mu= mu mu mu _ u.. -

Total 65.? 123.7 MT.7 82.8 17.9 0.0 816.9

- Values scaled by 1000000.0 8,5,1000 18:68

-57 ARMEX 3.2

Page 4 of 4

THIRD MA EECTRCAT PECT

Technical A681stance Advisor SXtafin[Auu 1991 - 5seateer 136)

A. TECHIICAL ASSISTANCE

1991 1o 1998 194 19 19 Tol EstimatedAdvisor Position Months Mentim Moths Month Monhs Months Months Amount of

5 12 12 12 12 9 '000two8

Tom Lr <- d2

mangeIb t Advisor <-- > 2

REB Flnance Advisr 2

POS Finance Advisor at-- 62

P1l Finance Advisor C 42

Membr Sorvice Advisor <- 62

Member Services Advisor <_> 41

PMS Operation Maintenae Advisor S > t0

PS Operation Maintenance Advisor C -) 41

Institutlonal Training Advisor a-

Technical Training Advisor <> 41

Engineering Advisor <- -- > 02

Distribution Enginer < - >41

Substatlio Constructlon Advlsor <2

Construction Advloor - a

Constructlon Advisor < >8

Short Term Advisle 12 20 20 2 29 22 10

Total Man Months 92 221 221 221 162 94 1,011 12,640

D. IRU^NO

s0 TraInes (12/year) G00

TOTAL BASE COST

Short Tere Advlsors include:Rate Specialists: Meter Specialist:s Wood Produc Specialists: Public Relatios Advisor:Audido-isual Programs Specialists: ngement Consultant Specialists: Financial AuditSpecialists: Trane_ision Engin er: Distribution Engineer: System Analysis and Design EnginerProcurement Speciallsts: Automati Dat Processing SpeciallsO .

BANLD ESH

Third Rural Electrtflcatlon ProJect

Zaln.msrttion and Construction Schedul.

lo 199 1992 1998 1994 1995 19 1

1Il TR2 TR TR4In.r'natlonal Tenderin - -- -

131 1R2 12 TR4hliv.r7 of mterials

P3$ Lino Design - -

Lan Acqutsltlo and R_Headquarters Costructon - -

Line end SubstationC oest uetlon - ---------- -----------

Membership Drive-

Consumer Connecion

TR = Trncwhe corresponding to about 26X of equlpmt and material

-59- ANNEX 3.3Page 2 of 2

DM10 -PA aOIMIPiMATIVI MM

P,etmtptI1i *w a:

'IIAAS.1Ima is ilqqo. III IMsO IV MAL

LtS Am ts-4W 16 19 19/4 194/

LOT-A LD OTMATZL 9.00 S."0 7.60 8.00 11.70

pM a FXTTS me H

Dau emc,WATOW -.PIN DWA.LAI

SFi41 DLRBSW N D VDLS

LOT-I SpiT 50 6.70 8.10 4.90 22.20

DISTRiUJTI IW6ftSOYA

OIL CIW. .FlS#L

LT CAPAIT

-EOt CAKE

11 Pf SE-

5S

LOT-C WU UCT 4.30 8.00 4.e0 5.40 19.60

so Fr. 1TE WOM POLO

45 Ff. 1USTW WOW POLEB

40 Fr. 1R6TW WtOL 0

81 FT. 1TAT0 WOO POLO

10 Fr. WAYD Wm Pot

2 Fr. WOO WOW POL

TRATW WMO X-

WOOW AN0 NC STA9112M LOO

W. 6"-O*, 2-'

LtT-OU SMATI@M TAS S.70 2.70 2. 10 0.60 6.10

I/11I PO TWM6R4

AVU"ITIC VOLTA R1AlIAT

S-PHASE FuMnTc CtlXT fibS

14.5 KV OT OOi _OTWTIA 156

S="240 V-S WA STAtYi SIICE tROf.

ETWDvi SMUT UNuSDCA Wm

NIsc. NUJIM VATUIAL

SPCE PAlSE

LO-I SUPORET Ci?IOTm 1.00 1.30 0.60 2.90

LWZ TOOLS

UFIE S -

V540. (PIOC.4P)

HNIUALIC CRt

cS6iCATiS 2IRUtW

Total A.S.C.0 60.80 25.60 21.40 16.00 84-40

-60. ANNEX 3.4

THIRD RRAL sldCTRXP?CATIOM PROJECT

Disbursement Profile

Cumulative Disbursement Cumulative Disbursement(Project) (Project)

Fiscal Year (USS Mlllon) (1)

1990/91: December 31, 1990June 30, 1991 2.3 2

1991192: December 31, 1991 4.6June 30, 1991 13.2 13

1992/93: December 31. 1992 21.8June 30, 1993 32.0 30

1993/94: December 31, 1993 42.2June 30, 1994 54.6 52

1994/95: December 31. 1994 67.0June 30, 1995 76.9 73

1995196: December 31, 1995 86.8June 30, 1996 93.0 89

1996/97: December 31, 1996 99.2June 30. 1997 102.0 97

1997/98: December 31. 1997 103.5June 30, 1998 105.0 100

100.

so

40

20

SO 19 9 4 6 6

FY

- FM,, melee. * US dkeL_ POW

BANGLADESH..........

RURAL ELECTRIfICATION f(OARD...........................

ACTUAL AND FORECAST tNCOME STATEMENTS

(In Tk. aittion)Fiscal Year ending ,-..-....June 30 1978 1979 1960 1981 1982 1983 1984 1985 1966 1987 1968 1989 1990 1991 1992 1993 1994 1995.................. ------- ------------------- audited -- .--------------------------I (proa) test.) t--------- projections -----------t

Revenues

Interest from PaSs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.2 59.4 68.4 94.3 219.6 215.2 243.6 255.3 250.8 246.3Other Revenues 0.1 1.1 1.7 1.0 2.7 9.3 2.3 4.1 2.2 4.1 4.5 5.4 5.6 5.8 5.9 6.1 6.3 6.S

Total Revenues 0.1 1.4 2.2 2.3 2.7 9.3 2.3 4.1 6.4 63.5 72.9 99.7 225.2 221.0 249.S 261.4 257.1 2S2.8

Expenses

Pay & Attowance 0.0 0.0 0.0 0.0 6.3 5.5 5.9 7.4 12.8 14.6 17.4 18.5 22.1 26.6 31.9 38.3 4S.9 55.1Transportation 0.0 0.0 0.0 0.0 3.3 1.8 2.9 3.1 3.2 4.0 4.0 5.4 6.2 7.2 8.3 9.5 10.9 12.6 ON

Rent 0.0 0.0 0.0 0.0 3.1 2.6 2.8 3.9 3.3 3.1 3.5 5.0 5.5 6.1 6.7 7.4 8.1 8.9Depreciation 0.0 1.2 1.8 1.3 2.4 2.5 2.5 3.1 2.9 3.4 4.4 5.1 9.2 10.8 12.7 14.7 26.4 28.8Other Misc. Expenses 0.0 0.0 0.0 0.0 65.8 4.0 3.9 5.6 7.0 7.3 7.9 9.8 10.8 11.9 13.1 14.4 15.8 17.4

.... .... . .... .... . .... .... . .... .... . .... .... . .... .... . ---- .... . .... .... . .... ----..... ........ ..... ..... .. ........ ...

Total Expenses 7.3 36.5 122.0 105.1 80.9 ?6.3 17.9 23.1 29.2 32.4 37.2 43.9 54.0 62.5 72.6 84.2 107.2 122.9

operating Income -7.2 -35.2 -119.8 -102.9 -78.2 -7.0 -15.6 -19.0 -22.8 31.1 35.7 55.9 171.3 158.4 176.9 177.2 149.9 129.9

interest paid to G.O.S. 0.0 0.2 1.7 4.3 5.8 8.7 15.4 29.4 38.8 34.1 61.4 93.5 95.4 93.6 89.7 85.8 81.9 78.1Add: Interest during Grace Pd. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 13.7 28.1 44.7 63.2 76.8 83.6Less: Interest during Constr. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 59.4 28.1 43.8 37.9 39.6 45.9

Total tnterest Expenses 0.0 0.2 1.7 4.3 5.8 8.7 15.4 29.4 38.8 34.1 61.4 93.5 49.7 93.6 90.6 111.2 119.2 115.8

Prior Pd's Adjustment 0.0 0.0 0.9 2.0 3.3 312.7 -13.9 0.7 0.1 22.0 0.4 0.7 0.0 0.0 0.0 0.0 0.0 0.0... . .. .. . .. -- - -- .. .. . .. .. . .. .. . ... .. . ... .. .... ....

Net Income -7.2 -35.4 -120.6 -105.2 -80.8 297.0 -44.9 -47.8 -61.4 18.9 -25.3 -37.0 121.6 64.8 66.3 66.0 30.7 14.2

Administrative cost and interest t2.0 10.2 1.0 1.3 1.3 0.4 0.? 0.6 0.7 0.8 0.8as a X of revenues

...

BAtJGLADf S1

RURAL ELECTRIF:ICATION4 BOARD

ACIUAL MMO FORECAST SOURCES ANO APPLICATIONS 0Of FUNDS STATENENTS...... ..... ...... ..... ...... ..... ...... ..... ...... ..... (in Tk. miltion)

Fiscal Year ending -------jurwe 30 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 199 1994 199

......... -. I-----------------audited.-----------------I (prov) test.] C .----- projections .------Internat Sources

Operating Income -7.2 -35.2 -119.8 -102.9 -78.2 -7.0 -#5.6 -19.0 -22.8 31.1 35.7 55.9 171.3 158.4 176.9 177.2 149.9 129.9Depreciation 0.0 1.2 1.8 1.3 2.4 2.0 0.0 2.1 2.7 3.6 3.7 4.6 9.2 10.8 12.7 14.7 26.4 28.8

Tot'i Internal Sources -7.2 -34.0 -118.0 -101.5 -75.8 -5.0 -15.6 -16.9 -20.1 34.7 39.4 6k1. 5 180.5 169.2 189.6 191.9 176.3 158.8Pr...r Year's Adjustment 0.0 0.0 0.9 2.0 3.3 312.7 -13.9 0.7 0.1 22.0 0.4 0.7 0.0 0.0 0.0 0.0 0.0 0.0

External Sources

Foreign~ G-ants 0.0 0.0 24.7 306.5 86.9 126.8 0.0 2.8 0.0 0.0 27.3 -27.3 0.0 0.0 0.0 0.0 0.0 0.0GMS Contribution 26.0 75.9 167.3 155.0 170.0 189.3 233.6 214.9 385.1 417.9 331.6 391.9 635.Z 975.2 1042.5 1027.3 750.7 803.1Captiata Gains 0.0 0.0 0.0 0.0 0.0 0.0 31.6 20.3 23.1 143.0 46.9 41.1 30.6 33.6 37.0 40.7 44.8 49.3Foreign Borrowing 7.0 21.6 211.4 0.0 0.0 182.9 316.5 4028.6 791.0 996.0 805.2 713.3 2000.0 1946.3 2419.6 2432.4 1067.0 584.4

Sale of Assets 0.0 0.0 0.0 0.0 117.5 211.8 1236.2 65.0 109.7 546.7 1206.7 1275.4 510.9 1rZ.3 3941.5 2030.1 0.0 0.0

Repayment recd, from PSSs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 50.1 297.0 297.0 297.0 297.0 297.0 297.0

Def. & other tiabitiies 0.0 0.0 0.0 3.7 2.7 2.0 44.7 -45.2 56.4 8.1 65.3 *85.7 9.3 11.1 13.3 15.9 19.0 22.8... . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Totat Sources 25.8 63.5 286.2 365.5 304.6 100. 1833.1 1270.1 1345.4 2168.3 2522.8 2420.0 3677.3 3633.0 796.3 6098.5 2431.7 1999.0

Apptications

Pro-po*s,e-d p,roject 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 108.9 598.7 925.3 1197.4 1143.0Other Cap. investment 7.6 23.8 48.3 178.4 294.1 678.1 516.2 477.6 356.4 315.0 975.0 1289.1 2611.9 2936.2 3087.5 2619.9 674.3 278.1Transfer of Stores to PSS assets 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3003.7 0.0 0.0 0.0 0.0 0.0Capitatised interest 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 59.4 28.1 43.8 37.9 39.6 45.9

Total Investment Program 7.6 23.8 48.3 178.4 294.1 678.1 516.2 477.6 356.4 315.0 975.0 1289.1 5675.0 3073.1 3730.0 3583.1 1911.3 1467.0

Loans to Pess 0.0 0.0 0.0 0.0 137.7 '17.4 1241.9 76.7 126.2 565.2 1217.0 809.8 941.4 205.2 4011.9 2126.8 109.4 125.1SpeciaL fund & Deposit 8.8 2.7 1.0 -5.2 7.2 7.2 -4.5 41.2 16.8 0.1 18.5 30.4 18.6 21.4 24.6 28.3 32.6 37.4Loan to R.E.B. EspI. 0.0 0.0 0.0 0.0 0.1 0.0 0.0 1.1 0.5 1.8 1.3 2.0 0.3 0.4 0.4 0.4 0.4 0.4Change of Store In transit 0.0 0.0 0.0 1.8 -0.6 0.9 -2.1 233.1 4.5 -98.8 59.5 78.9 -227.2 0.0 0.0 0.0 0.0 0.0Insurance and other CLaimS 0.0 0.0 0.0 0.0 0.0 0.0 5.9 5.3 2.1 4.2 29.9 -18.9 1.4 1.5 1.6 1.6 1.7 1.8

Debt Service

Amwortization 0.0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 77.3 102.2 194.0 194.0 194.0 194.0 194.0Interest Payment 0.0 0.2 1.7 4.3 5.8 8.7 15.4 29.4 38.8 34.1 61.4 93.5 49.7 93.6 90.6 111.2 119.2 115.8

Total Debt Service 0.0 0.2 1.7 4.3 5.8 8.7 15.4 29.4 38.8 34.1 61.4 170.8 151.9 287.6 284.7 305.2 313.2 309.8

Change in Working Capital

Change in Cash 7.8 -0.9 -3.7 3.8 24.6 -2.8 55.0 -57.4 16.9 38.4 48.0 4.6 -123.1 1.8 2.0 2.4 2.8 3.3Chin Work. Cap. other than Cash 1.6 37.8 238.9 182.6 -164.2 M1.0 5.3 463.0 783.2 1308.3 112.3 53.3 -2761.2 42.0 -69.9 50.7 60.3 54.1

Net Change in Work. Cap. 9.5 36.8 235.2 186.4 -13Y.6 108.1 60.3 405.5 800.1 1346.7 160.3 57.9 -288.2 43.8 -67.8 53.1 63.1 57.4 0.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~.

Debt Service Coverage Ratio -0.6 -0.5 1.7 0.6 0.7 3.1 1.6 1.7 1.6 1.5 1.5 o(including repayment from PBSS-

AGADE SN

RURAL ELECTRIFICATION BOARD

ACTUAL AND FORECAST BALANCE SHEETS.................................. ~~(in Tk. millionl)

As an June 30 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1968 1969 1990 1991 1992 1993 1994 1995........ ------------------ audited ..---------------- I (provi test.] I------projections -....... )

Assets

Fixed Assets

Gross Fixed Assets 5.7 12.8 17.0 23.0 24.9 34.3 53.4 143P.3 191.7 90.5 94.5 113.6 132.2 155.8 181.7 210.3 618.8 653.3Less :Ace. Depreciation 0.0 1.2 3.0 4.3 6.7 8.8 8.8 10.9 13.6 17.2 20.9 25.6 34.8 45.6 58.3 73.0 99.3 128.2

Net Fixed Assets 5.7 11.6 14.0 18.7 18.1 25.5 44.6 138.4 178.1 73.3 73.6 88.0 97.4 i10.2 123.5 137.3 519.5 525.1Work-in-Progress 1.8 18.5 62.7 235.0 409.7 866.6 127.5 444.2 648.5 517.9 282.3 276.9 5422.4 8299.6 8062.2 9586.? 11089.4 '12522.0

Loans to PBS 0.0 0.0 0.0 0.0 137.7 355.1 1597.0 1673.6 1799.8 2365.0 3582.0 4341.7 4986.1 4894.3 8609.1 10438.9 10251.2 10079.3Special Fund & Other Deposits 8.8 11.5 12.4 7.2 14.4 21.6 17.1 58.3 75.1 7..2 93.7 124.1 142.7 164.1 188.7 217.0 249.6 287.0

Current Assets

Cash mncI. working fund 7.8 9.1 5.2 9.1 33.8 31.0 86.1 29.4 45.9 84.5 132.5 137.3 14.3 16.1 18.1 20.6 23.4 26.8Working Capital loans to PUSs 0.0 0.0 11.5 53.1 20.5 13.5 10.8 4.4 4.5 5.2 4.6 8.0 8.1 8.3 8.5 8.6 8.8 9.0Advance to Euptoyees 0.0 0.2 1.5 0.7 0.6 1.0 1.3 1.3 0.9 1.1 1.5 2.4 2.6 2.8 3.1 3.4 3.8 4.2Stores 0.0 15.0 238.7 395.8 251.9 339.4 293.4 806.0 1565.6 2894.0 2950.1 2994.6 218.1 243.1 154.5 184.3 221.6 250.3Receivables from P8Ss 1.7 22.9 35.1 23.4 46.4 78.5 129.3 101.3 134.6 115.0 155.5 180.9 199.0 218.9 240.7 264.8 291.3 320.4Misc. Current Assets 0.0 2.0 0.0 0.0 0.0 0.0 1.0 3.2 1.2 3.6 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

Total Current Assets 9.6 49.3 291.9 482.0 353.1 463.5 521.8 945.8 1752.7 3103.5 3244.6 3323.4 442.4 489.5 425.3 482.1 549.2 610.9

Loan to REB employees 0.0 0.0 0.0 0.0 0.1 0.1 0.1 1.2 1.7 3.5 4.8 6.9 7.2 7.6 7.9 8.3 8.8 9.2 ?Stores in transit 0.0 0.0 0.0 1.8 1.2 2.1 0.0 233.1 237.6 138.8 198.4 277.2 50.0 50.0 50.0 50.0 50.0 50.0Insurance and other Ctaims 0.0 0.0 0.0 0.0 0.0 0.0 5.9 11.2 13.3 17.6 47.4 28.5 29.9 31.4 33.0 34.6 36.3 38.2

TOTAL ASSETS 25.9 90.9 381.0 744.6 934.3 1734.5 2314.0 3505.9 4706.9 6294.9 7526.7 8466.6 11178.0 14046.7 17499.7 20955.0 22754.0 24121.6

Equity & Liabilities

Equity

Foreign Grant 0.0 0.0 24.7 331.1 418.1 544.9 544.9 18.6 18.6 0.0 27.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0GOB Contribution 26.0 101.9 269.2 424.2 594.2 783.5 1017.0 1231.9 1617.0 2035.0 2366.6 2758.5 3393.6 4368.8 5411.4 6438.7 7189.4 7992.5Capital Gain 0.0 0.0 0.0 0.0 0.0 0.0 31.6 51.8 74.9 217.9 264.8 305.9 336.5 370.1 407.2 447.9 492.7 541.9Retained Earnings -7.2 -42.6 -163.2 -268.4 -349.2 -52.2 -97.1 -1448 -206.3 -187.3 -212.6 -249.6 -128.0 -63.2 23.2 89.2 119.9 134.0

Totat Equity 18.8 59.3 130.6 486.9 663.0 1276.1 1496.4 1157.5 1504.3 2065.5 2446.1 2814.8 3602.1 4675.8 5841.7 6975.7 7801.9 866.4

Long Term Debt 7.0 28.6 240.0 240.0 240.0 422.9 739.4 2297.1 3088.1 4102.? 4907.8 5543.8 7455.3 9235.7 11506.0 13807.6 14757.4 15231.3Other long term liabilities 0.0 0.0 0.0 0.0 1.0 1.5 2.4 2.9 5.5 8.5 11.5 15.5 19.4 24.3 30.4 38.0 47.4 59.3

Current Liabilities

Accounts Payable 0.1 3.0 0.6 0.0 0.5 0.0 0.2 19.4 21.9 19.2 0.0 14.0 15.0 16.0 17.2 18.4 19.6 21.0Security Deposits 0.0 0.0 9.5 10.1 12.4 15.5 18.7 23.9 28.2 34.8 33.9 39.9 41.9 44.0 46.2 48.5 50.9 53.5Misc . current liabilities 0.0 0.1 0.2 4.0 11.9 11.6 6.3 0.2 0.3 0.4 1.3 2.2 2.4 2.7 2.9 3.2 3.5 3.9 ,0

Total Current Liab. 0.1 3.0 10.4 14.1 24.9 27.1 25.1 43.5 50.3 54.4 35.2 56.1 59.3 62.7 66.3 70.1 74.1 ? 4wDeferred Liabilities 0.0 0.0 0.0 3.7 5.3 6.8 50.6 4.9 58.7 63.8 126.1 36.4 41.9 48.1 55.4 63.7 73.2 84:2

Total Equity & Liabilities 25.9 90.9 381.0 744.6 934.3 1734.5 2314.0 3505.9 4706.9 6294.9 7526.7 8466.6 11178.0 14046.7 17499.7 2095.0 22754.0 24121.? 0

w

-64-ANNEX 4.2Page 1 of 2

BANGLADESH

THIRD RURAL ELECTRIFIC&TION PROJECT

Rural Electrification Board

Assumptions Used in the Financial Projections

1. Onlending Terms

GOB Loans to REBt

Maturity t 33 years including a 6 year grace period.Interest Rates s 0.75Z p.a. during the grace period and 21 p.a.

thereafter.

REB Loans to PBSs:

Maturity : 30 years including a grace period of 5 years.Interest Rates : 0.752 during the grace period and 32 p.a.

during the repayment period.

In both cases, interest during the grace period is capitalized andadded to the loan principal.

Income Statement

2. Interest from PBSs : As per onlending terms.

3. Other Revenues s Assumed to grow at 32 p.a.

Expenses

4. Pay and Allowances s Assumed to increase at 202 p.a.

5. Transportation : Assumed to grow at 15 p.a.

6. Rent s Assumed to grow at 102 p.a.

7. Depreciation : Straight line depreciation is followed. Thedepreciation rates ate 2.52 for the new officecomplex and 7.5Z for the other assets.

8. Other MiscellaneousExpenses : Assumed to grow at 10 p.a.

9. Interest ExDenses a As per onlending terms.

-65- ANNEX 4.2Page 2 of 2

Sources and A#Mlications of Fund

10. GOB Contribution s Following the current policy, all local costsof RE program as required are assumed to befunded by GOB equity contributions.

11. GOB Loans to REB s Following the current policy, financingprovided by external donors to cover theforeign exchange costs of the RE program willbe onlent to RIB as loans.

12. Investment Program s Includes the proposed IDA project and otherprojects under implementation or identifiedfor he Phase IV of the RE program.

Balance Sheet

13. Minimum Cash s Three months of cash operating expenses.

14. Workint Capital LoansTo PBSs s Assumed to increase at 22 p.a.

15. Stores s Assumed to reduce from a level equal to 5Z ofthe capital work-in-progress for the REprogram in FY89 to 21 in FY91 and maintain atthat level thereafter.

16. Receivables from PBSs s Assumed to grow at 1O0 p.a.

17. Security Deposits s Represent security deposits from contractorsand are assumed to increase at 51 p.a.

Project PBSs- Projected Incom Statements----------------- _-----------------_----

( in current Tk million)

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

lectriceity Purchase()ih) 14540 24054 37976 59054 91261 103137 111189 116678 120910 124610Electricity Salee(Muh) 10905 19243 31520 50196 79397 89729 96734 101510 105191 108411System Loss(%) 251 20X 171 152 131 132 13X 13S 13S 13SAversge Bulk Purchase Tarriff(TkKwth) 1.74 1.88 2.03 2.19 2.37 2.56 2.74 2.93 3.13 3.35Average Retail Tariff(Tk/Kvh) 3.73 4.07 4.44 4.84 5.25 5.75 6.13 6.54 6.97 7.44

Operating RevenuestElectrieLty Sales 40.67 78.41 140.10 242.74 416.93 516.06 593.45 664.05 733.62 806.45Other Operating Revenues 1.22 2.35 4.20 7.28 12.51 15.48 17.80 19.92 22.01 24.19Interest Earned 0.00 1.17 3.35 7.87 14.95 30.41 32.99 35.80 42.14 52.12

total Operating Revenues 41.89 81.93 147.65 257.89 444.39 561.94 644.25 719.77 797.77 882.77

Operating ExpensestElectriclty Purchase 25.32 45.24 77.14 129.55 216.21 263.90 304.42 341.81 379.00 417.94Distribution 3.18 5.09 8.13 13.02 21.82 23.58 25.49 27.54 29.77 32.17Customer Service 1.41 2.62 4.88 9.12 17.09 18.47 19.96 21.57 23.32 25.20Administration 3.53 6.55 12.19 22.79 42.72 46.17 49.90 53.94 58.30 63.01Depreciation 13.90 25.28 45.64 67.08 83.45 90.97 94.36 95.54 96.80 98.14

Total Operst=nb Expenses 47.34 84.77 147.98 241.55 381.29 443.09 494.12 540.40 587.18 636.46

Operating Income befoce iaterest -5.45 -2.84 -0.12 16.35 63.10 118.85 150.12 179.37 210.59 246.31

Long Term Debt Interest 3.13 5.71 10.33 15.24 19.03 81.81 81.45 77.99 74.53 71.07Interest on Short Term Borroving 0.75 1.65 2.025 1.275 0.15 0 0 0 0 0net Operating Income -9.33 -10.21 -12.68 -0.16 43.92 37.04 68.67 101.38 136.06 175.24

GM8 Subsidy 5.45 4.01 3.68 0.00 0.00 0.00 0.00 0.00 0.00 0.00

NET Inceme (3.88) (6.20) (9.01) (0.16) 43.92 37.04 68.67 101.38 136.06 175.24

Operating Ratio(%) * 113 103 100 94 86 79 77 75 74 72

Is8

Project PBSs- Projected Funds Flow Statements-----------------------.--.-- _------_---

(in Current Tk millon)

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Sotrces of Funds ------ ------ ------ ------ ------ ------ ------ ------ ------ ------

Net Income Before OOB Subsidy (9.33) (10.21) (12.68) (O.L6; 43.92 37.04 68.67 101.38 136.06 175.24Interest on LTD 3.13 5.71 10.33 15.24 19.03 81.81 81.45 77.99 74.53 71.07Deprecletion 11.90 25.28 45.64 67.08 83.45 90.97 94.36 95.54 96.80 98.14

Total Internal Cash Ceneration 7.70 20.79 43.29 82.15 146.40 209.82 244.48 274.91 307.39 344.45

Long-Texm Borrowing 344.50 616.34 653.56 506.38 244.68 101.58 0.00 0.00 0.00 0.00

Government Subsidy 5.45 4.01 3.68 0.00 0.00 0.00 0.00 0.00 0.00 0.00Membership Subscriptions 0.14 0.12 0.23 0.42 0.80 0.14 0.15 0.16 0.17 0.19

Total Sources 357.80 641.26 700.75 588.95 391.88 311.54 244.63 275.07 307.56 344.63

Applications of Fund-____________________

Purcheas of FLxed Assets 341.38 610.63 643.23 491.14 225.65 101.58 35.56 37.78 40.10 42.57

Debt Service:Interest 3.13 5.71 10.33 15.24 19.03 81.81 81.43 77.9" 74.53 71.07Repayment of Prlnclpal 0.00 0.00 0.00 0.00 0.00 111.30 115.36 115.36 115.16 115.36

Allocation to Replacement Reserve 4.17 11.00 25.90 39.42 44.68 11.28 5.08 1.78 1.89 2.01

lntrease in working Capital:Cash 5.40 5.38 6.30 11.70 87.52 8.93 20.45 80.80 906.95 136.93son-cash 3.72 8.54 14.98 31.46 14.99 -3.36 -13.27 -18.64 -21.27 -23.30Subtotal 9.12 13.92 21.29 43.15 102.52 5.57 7.17 *2.16 75.67 113.62

Total Applicatins 357.80 641.24 700.75 588.95 391.88 311.54 244.63 273.07 307.56 344.63

LTD Sertlce Coverage$Before Allocation to Replacement Fund 1.09 1.24 1.42 1.62 1.85After Allocation to Replemnmat Fund 1.03 1.22 1.41 1.61 1.84Self-li aening Ratio(X) -1.9 -2.4 -3.5 -7.3 -0.1 60.7 ".5 ".4 9.4

iNl

O0.

Project PBSs- Projected Balance Sheets

(in Current Tk million)

1994 1995 1996 1997 1998 19" 2000 2001 2002 2003

Assets

Gross Fixed Asets in Servlce 417.0 758.4 1,369.1 2,012.3 2,503.4 2,729.1 2,830.7 2,866.2 2,904.0 2,944.1Less Cui-dated Depreciation 13.9 39.2 84.8 151.9 235.3 326.3 420.7 516.2 613.0 711.1Net FL=ed Asaets In Servlce 403.1 719.2 1284.2 1860.4 2268.1 2402.8 2410.0 2350.0 2291.0 2233.0Capital Work-in Progress 341.4 610.6 643.2 491.1 225.7 101.6 35.6 37.8 40.1 42.6

Total Flied Assets ;4;.5 1,329.9 1,927.5 2,351.5 2,493.7 2,504.3 2,445.5 2,387.8 2,331.1 2,275.5Replacemset Reserve 4.2 15.2 41.1 80.5 125.2 136.5 141.5 143.3 145.2 147.2

Current AssetsCash S.4 10.8 17.1 28.8 116.3 125.2 145.7 206.5 303.4 440.3Accounts Recelvable 10.0 19.3 34.5 59.9 102.8 127.2 146.3 163.7 180.9 198.9Stores 10.4 19.0 34.2 50.3 62.6 68.2 70.8 71.7 72.6 73.6Other Current Assets 1.0 1.9 3.4 5.0 6.3 6.8 7.1 7.2 7.3 7.4

Tntal Current Assets 26.9 51.0 89.3 144.0 287.9 327.5 369.9 449.0 564.2 720.2

Total Assets 775.6 1,396.0 2,057.8 2,576.0 2,906.9 2,968.3 2,956.9 2,980.1 3,040.5 3,142.9

EquitySubscrLptions 0.1 0.3 0.5 0.9 1.7 1.8 2 0 2.2 2.3 2.5 tRetained Earnings -3.88 -10.07 -19.08 -19.24 24.67 61.72 130.39 231.76 367.82 543.06 0bTotal Equity -3.74 -9.81 -18.59 -18.33 26.38 63.56 132.38 233.92 370.15 545.58 t

Long-Term Debt 761.6 1,377.9 2,031.5 2,537.8 2,782.5 2,657.4 2,542.1 2,426.7 2,311.3 2,196.0

Current LiabilitiesAccounts payable 4.1 7.3 12.6 21.5 36.7 43.4 49.3 54.8 60.5 66.4Consumer Advance Deposits 3.7 8.6 17.3 33.0 61.2 88.6 117.8 149.3 183.1 219.6Short-Term Debt 10.0 12.0 15.0 2.0 0.0 0.0 0.0 0.0 0.0 0.0

Current Portlon of LTD 0.0 0.0 0.0 0.0 0.0 115.4 115.4 115.4 115.4 115.4

Total Current Liabilities 17.8 27.9 44.9 56.5 98.0 247.3 282.5 319.5 359.0 401.3

Total Equity and Liabilitieas 775.6 1,396.0 2,057.8 2,576.0 2,906.9 2,968.3 2,956.9 2,980.1 3,040.5 3,142.9

Current Ratio 1.5 1.8 2.0 2.5 2.9 1.3 1.3 1.4 1.6 1.8Debt 91 86 80

/EquLty 9 14 20

go

w

-69- ANNEX 4.4Page 1 of 2

BANGLADESH

THIRD RURAL ELECTRIFICATION PROJECT

New Prolect PBs9

Assumptions Used in the Financial Projections

1. Price Escalation

Domestic Inflation:FY90 81FY91 onwards 71

International InflationsFY90 O0FY91 2.32FY92-95 4.91FY96 4.3ZFY97-2003 3.71

2. BPDB's Bulk Supply Tariff. Assumed to increase at 11 above localinflation for FY90-99 and follow local inflation thereafter.

3. PBS,' Average Retail Tariffs Assumed to increase at 21 above theincrease in BPDB's bulk supply tariff for FY91-99 and follow localinflation thereafter.

4. Electricity Saless As per demand forecast given in Annex 5.1

5. System Loss:FY94 25SFY95 202PY96 171FY97 151FY98 onwards 131

6. Operating Expenses Other Than Power Purchases The following expensesare based on the statistical data of the existing PBSs for FY90 and areescalated as per local inflation:

Distribution Expenses Tk 2,000 per km of linesConsumer Service Tk 100/consumerAdministration Tk 250/consumer

-70- ANNEX 4.4

Page 2 of 2

7. Depreciations Equal to 3.3? of fixed assets in service.

8. Minimum Cashs Two months of cash operating expenses.

9. Storess 2.5 of fixed assets in service.

10. Accounts Receivable: 90 days of electricity sales.

11. Accounts Payable: 45 days of cash operating expenses

12. Membership Subscription: Tk 10 per consumer

13. Consumer Deposits: Tk 120 for each residential/commercial consumer andTk 5,000 for each irrigation consumer.

14. Replacement Reserves Is assumed to gradually build up and maintain alevel equal to 5 of fixed assets in use in FY98 and onwards.

-71- ANNEX 5.1Page 1 of 3

BANGLADESH

THIRD RURAL ELECTRIFICATION PROJECT

Table It DETAILED ANALYSIS OF THE PAST DEMAND

<----------------------------~~~* act Wl --. - - - - -- - - - - -- - - ---- >

FISCAL YEARS 1982 1983 1984 1985 1986 1987 I988 1989

NUMBER of CONNECTIONSRESIDENTIAL 1709? 56383 81973 119384 150167 210713 256223 314993COMOERCIAL 2531 9S57 15270 24279 33538 42190 48933 56173

IRIGATION 321 2454 3844 5780 6848 8177 10753 14337INDUSTRIES 402 1189 1971 2891 4432 5711 6629 7681

OT1ms 269 684 823 1487 1941 2517 2770 2937

TOTAL 20620 70267 103881 153821 196926 269308 325308 396121

YEARLY GROWTH RAse of CONNECTONS 131.13 240.82 47.82 48.12 28.02 36.82 20.8S 21.82

TOTAL REB SALES MUR mm A MWH WI mW Mb8 MWg W

RESIDENTIAL 4279 11363 21863 34874 44786 58650 78928 93403COMUORCIAL 126 1917 4885 9625 13939 17278 21751 25521

ItRIGATION 3243 10666 19707 26320 29492 37937 51577 91826

INDUSTRIES 5224 20417 40966 71211 93696 117956 141026 160054

OTHES 164 222 355 597 943 1081 1338 1281

GRAND TOTAL B 13036 44585 87776 142627 182856 232902 294620 372085

YEARLY C GROWT RATE 242.02 96.92 62.52 28.22 27.42 26.52 26.32

RED PURcHaSES GWU 64.0 107.0 173.0 238.3 309.0 364.2 463.0

RE3 SALES CW 44.6 87.8 142.6 182.9 232.9 294.6 372.1

RED LOSSES CW 19.4 19.2 30.4 55.4 76.1 69.6 90.9

LOSS RATIO vs PURCHASES 30.342 17.97X l7.5-Z 23.262 24.631 19.102 19.64X

LOSS RATIO vs SALES 43.552 21.902 21.302 30.31S 32.672 23.622 24.43X

REB PEZA DEMAND <--------------------------estimates -----------. -

Ps" 18 19983 1984 1983 1986 1987 1988 1989

RESIDENTIAL 20.02 IW 6.2 12.0 19.1 24.5 32.1 43.2 51.2

COIOURCIAL 10.02 lU 0.5 1.3 2.6 3.8 4.7 6.0 7.0

IcrATION 1.02 * 0.9 1.6 2.2 2.5 3.2 4.3 7.7

NDUSTES 4.02 Ml 2.2 4.5 7.8 10.3 12.9 15.5 17.5

OTHERS 10.02 lE 0.1 0.1 0.2 0.3 0.3 0.4 0,4

TOTAL DEIMAD 11 98.ox NV 1.05 10.2 20.1 32.8 42.5 54.8 71.3 86.1

LOSSES N 2.2 2.2 3.5 6.4 9.0 8.4 10.52 Vs sa1es 21.8X 11.0X 10.62 15.22 16.32 11.82 12.22X vs purcases 17.92 9.92 9.62 13.22 14.02 10.62 10.92

PEAK DEID ("a) NW 12.5 22.3 36.3 49.0 63.8 79.8 96.7Diversity factor ------ >>> 89.12

IRRIGATION IMPACT 5.02 NW 5.6 9.4 12.5 14.6 18.9 24.7 44.2

POSSIUg PEA DDtWJlD NW 18.0 31.7 48.8 63.6 82.7 104.5 140.88ISTORICAL MON CO-INCIDENTAL PEAK DE4AND ------- >>> 158.0

1/. Assumiag a cO-icidental factor Mlnim- loa4 factor (Vs non-coaincidetal peak) 33.52

of 0.n8 and a peak ratio of 1.05 Mlnimum 1oa factor (Vs estimated possible peak) 37.S5

SHARE of CONSUMPTION CATEGORY wI.iRESIDENTIAI. 32.SX 2S.52 24.92 24.52 24.52 25.22 26.82 25.12

COMERCIAL 1 02 4.32 5.62 6.72 7.62 7.42 7.42 6.92

IRRIGATOIO 24.9: 23.92 22.52 18.52 16.12 16.32 17.52 24.72

INDU3TRIES 40.12 45.8S 46.72 49.92 51.22 50.62 47.92 43.02

OTlilS 1.32 0.52 0.42 0.42 0.52 0.52 0.52 0.32

SAR of CONLSCTIONS CATEOY WISERESIDETvIAL 82.92 80.21 78.92 77.62 76.32 78.22 78.82 79.52

COIORIA 12.32 13.62 14.72 15.8S 17.02 15.72 15.02 14.22tRRICATION 1.62 3.52 3.72 3.82 3.52 3.0X 3.32 3.62

nwsutES 1.92 1.72 1.92 1.9X 2.32 2.12 2.02 1.92

OERS 1.32 1.02 0.82 1.02 1.02 0.92 0.92 0.72

-72-ANNEX 5.1Page 2 of 3

Table 2: CONSUMPTION FORECAST FOR RE PROGRAM

CONSUIPTIOU FORECAST FOR RE PROGRAM<3rd FYP>|<. 4th FYP … > -- t--------------5th FYP------

F:SCAL YEAAS 1990 |l1991 1992 1993 1994 1995 1996 1997 1998 1999 200o

NL"43ER of CONNECTIONSRESIDENTIAL 377800 447500 324700 610200 704800 809400 925000 1052700 1193700 1349300 1520900O0MMERCIAL 6i900 71900 80300 89100 98300 108000 118300 129100 140600 152800 165700IRRIGTIOr 17400 20800 24700 29100 34100 39800 46200 53400 61500 70700 81000INDUSTRIES 8800 10000 11300 12700 14200 15900 17700 19700 21900 24300 26900OTHERS 3100 3300 3500 3700 3900 4100 4300 4500 4700 4900 5100

.- - -.- - -- -- - - -*-- -- -- - -- -- -- - -- -- -- - -- -- -- - -- -- -- - -- -- -- - -- ----- ---- ----

TOTAL 471000 553500 644500 744800 855300 971200 1111500 1259400 1422400 1602000 1799600YEARLY GROWTE RATE of CONNECTIONS 18.92 17.52 16.42 15.62 14.82 14.3X 13.72 13.32 12.9X 12.62 12.32

TOTAL REB SALES Gw0 GM5 G0H GW1 G01 0mm on 0m G3 GWH 0cm1RESIDENTIAL 116.0 139.9 164.3 193.0 224.3 259.2 299.5 342.6 392.3 451.5 521.1COMKERCIAL 30.1 35.4 41.6 48.4 55.1 62.6 70.3 78.7 87.8 97.8 108.7IRRIGATION 115.0 144.3 178.5 217.9 262.5 312.1 369.5 435.7 507.5 584.0 664.0INDUSTRIES 187.3 215.6 246.6 278.4 313.2 351.4 389.9 430.8 475.3 522.9 574.8OTERS 1.6 1.8 2.0 2.3 2.9 3.7 4.8 6.2 8.1 10.8 14.4

,- - - -- -- -- - -- -- ----- -- -- --- -- - - --- -- ----- -- -- --- -- -- --- -- -- --- -- -- --- -- -*- --

GRAND TOTAL RED 450.0 537.0 633.0 740.0 858.0 989.0 1134.0 1294.0 1471.0 1667.0 1885.0YEAiLY GROYT8 RATE 20.92 19.32 17.92 16.92 15.92 15.32 24.72 14.12 13.72 13.32 13.02

RU PURCHASES C1H 555.6 663.0 772.0 891.6 1021.4 1163.5 1326.3 1304.7 1700.6 1916.1 2164.4RUB SALES GWH 450.0 537.0 633.0 740.0 858.0 989.0 1134.0 1294.0 1471.0 1667.0 1883.0

. -- -- - - -- -- - -- -- -- --- -- ----- -- -- --- -- -- --- -- -- --- -- -- --- -- -- --- -- -- --- -- -- ---

RU LOSSES 011 105.6 126.0 139.0 151.6 163.4 174.5 192.3 210.7 229.6 249.1 281.4

LOSS RATIO vs PURCHASES 19.00X 19.oo0 18.002 17.002 16.00X 15.002 14.50X 14.00X 13.502 13.002 13.002LOSS RATIO vs SALES 23.462 23.462 21.9S2 20.4sx 19.052 17.652 16.96, 16.28* 1S.612 14.942 l4.v42

REs PEAK DEMAND <3rd FYP> <----------------4th m ---------------- <----------------4th TP----------------PEAK 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000

CONJtRBUTIONRESIDENTIAL 20.02 MW 65.6 76.7 90.0 105.8 122.9 142.0 164.1 187.7 215.0 247.4 285.5COMMERCIAL 10.02 m4 8.2 9.7 11.4 13.3 15.1 17.2 19.3 21.6 24.1 26.8 29.8IRRIGATION 1.02 KW 9.6 12.0 14.9 18.2 21.9 26.0 30.8 36.3 42.3 48.7 55.3INDUSTRIES 4.02 38 20.5 23.6 27.0 30.5 34.3 38.5 42.7 47.2 52.1 57.S 63.0OTHERs lO.OX 3Y 0.4 0.5 0.5 0.6 0.8 1.0 1.3 1.7 2.2 5.0 3.9

- -- - -- -; - - ---- ;; - - - - -- - -- -- -- --- -- -- --- -- -- --- -- -- --- -- -- --- -- -- ---

TOTAL DEMAND 11 98.02 2W 105.3 126.1 148.0 173.2 200.6 231.2 265.7 303.0 345.3 394.2 450.3LOSSES MI 12.4 14.8 16.2 17.7 19.1 20.4 22.5 24.7 26.9 29.5 33.6

2 vs sales 11.72 11.7X 11.02 10.22 9.52 8.82 S.52 8.12 7.82 7.x 7.522 vs putcbss 10.52 10.52 9.92 9.32 8.72 S.1X 7.sx 7.52 7.22 7-02 7.02

PEAK DEMAND (POD) 1w t1'17.7 140.8 164.3 190.9 219.8 251.6 288.2 327.7 372.3 423.7 483.953.922. 53.72 53.6% 53.32 53.12 52.82 52.52 52.42 52.12 51.62 S1.12

IRRICATiON IMPACT 5.02 41 55.1 | 69.1 84.9 103.0 123.3 145.6 171.9 202.0 234.6 269.1 306.0POSSIBLE PEAK DEKAND M2 172.8 | 210.0 249.2 293.9 343.0 397.2 460.1 529.7 606.9 692.8 789.9

36.7tL, 36.02 35.42 34.61 34.02 33.42 32.92 32.42 32.0X 31.6X 31.3211. Assing a co-Incldantal foator |

of 0.98 and a pCk ratLo of 1.05

SHARE of CONS2ISTIOI CATEGORY VISERESIDENTIL 25.82 26.1 26.02 26.12 26.12 26.22 26.42 26.52 26.7X 27.12 27.72CIClIAL 6.72 6.62 6.62 6.52 6.42 6.32 6.22 6.12 6.02 5.92 5.82IRRICATION 25.62 26.92 28.22 29.42 30.62 31.62 32.62 33.2X 34.52 35.02 55.32INDUStRIES 41.62 40.1X 39.0X 37.62 38.5X 35.52 34.42 33.32 32.32 31.42 30.52OTHERS O.42% 0.32 0.3x 0.32 0.32 0.4X 0.4X 0.52 0.62 0.62 0.82

SHARE of CONNECTIONS CATEGO WISERESIDENTIAL 80.22 80.82 81.42 81.92 82.42 82.82 83.2X 83.62 8. 92 84.2X 84.: tOOORCMIL 13.62 13.02 12.52 12.07 1 .52 1.X12 10.62 10.32 9.92 9.52 9.22I RRICATION 3.2 3.82 3.82 3.92 4.02 4.1X 4.22 4.22 4.32 4.42 4.52INDUSTRZR 1.92 1.82 1.82 1.72 1.7X 1.62 1.62 1.62 1.52 1.52 1.52OThERS 0.72 0.62 0.52 0.52 o.5S 0.4X 0.4X 0.42 0.32 0.32 0.32

Table 3: CONSUMPTION FORECAST FOR PROJECT PBSs

1993 1994 1995 1996 1997 198 19 2000 2001 2002 2003 2004 2005 2006 2007C0ONECTIONSRESIOEWsTAL 12214 21937 39400 70765 127098 128669 129653 130950 132260 131SS3 134919 136268 137631 119007 140397COERCIAL 3016 4919 *023 13085 1 .341 21661 21986 22316 22651 22991 23336 23686 24041 24602 24768IRRIGATION 1128 1687 2523 3773 5642 5642 5642 5642 5642 5642 5642 S642 5642 5642 5642INDUSTRy 576 861 1287 1925 2879 2879 2879 2879 2879 2879 2879 2679 2879 2879 2879OTHER 6 9 13 19 28 28 28 28 28 28 28 28 28 28 28

TOtAL 16940 29413 51246 89s67 156988 158579 160188 161815 163460 165123 166804 168503 170221 171958 173714coelsuliprtopRESIDEXIIAL mmN 2320.7 5023.0 9571.2 17556.9 31838.6 38421.7 43073.0 46681.1 49867.1 52762.0 55805.6 59005.4 62369.3 65905.5 69622.6CO 4ERCIU. WA 603.2 1526.7 2851.9 4832.4 8002.0 10548.6 12305.3 13526.9 14640.5 IS828.2 17101.4 18466.2 19928.9 21496.6 23176.7IRRIGATION HMO 4512.0 7199.2 11048.8 16748.6 25214.6 26582.1 27509.7 28199.3 28670.2 28956.9 29246.5 29539.0 29834.3 10132.7 30434.0INDUSTRY WU 9792.0 16653.0 26132.5 40188.4 60449.0 66294.4 70044.9 72088.6 73149.2 73880.6 74619.5 75365.6 76119.3 76680.5 77649.3OTHER m11 2.0 3.7 5.8 8.6 12.7 14.3 15.2 15.5 15.7 15.8 16.0 16.1 16.3 16.5 16.6

TOTAL mu 17230 30406 49810 7933S5 125517 141861 152948 160511 166343 17144 176789 182392 18S268 194432 200889

PURCRAUStS 2ts3? 37538 60744 9384 149425 166095 177846 184493 191198 197062 203206 209646 226400 2#*345 230919LOSS P1 4307 7132 10934 16249 23908 25034 2489 23984 24856 2561S 26417 27254 28132 29053 30019

LOSS RATIO ws PURCRASES 20.02 19.01 18.0t 17.02 16.01 15.02 14.0 13.02 13.02 13.02 13.02 13.02 13.02 13.02 13.02LOSS RATIO vs SALES 25.01 23.52 22 20.52 19.02 17.62 16.32 14.92 14.92 14.92 14.92 14.92 14.92 14.92 14.92

PM DEDAWN 193 1"9 199 19"6 197 198 I 2000 200t 2002 2003 2004 2005 2006 2007

RESIDENTIAL 20.02 P0 1.27 2.75 5.24 9.62 17.45 21.0s 2s.60 2s.58 27.32 28.91 S3.so 32.33 34.17 3U.11 36.15CO9IERCIAL 10.02 MM 0.17 0.42 0.78 1.32 2.19 2.89 3.37 3.71 4.01 4.34 4.69 S.06 5.46 S.8 6.35IRRtGATIO 1.02 111 0.38 0.60 0.92 1.40 2.10 2.22 2.29 2.33 2.39 2.41 2.44 2.46 2.49 2.51 2.54IUNUSTRY 4.02 O 1.07 1.82 2.89 4.40 6.62 7.27 7.68 7.90 8.02 8.10 8.10 6.26 8.34 9.43 8.51OTHE 10.02 OS 0.00 0.00 0.00 0.00 0.00 0.08 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 o.00

---- - ---- ----- --- -- - -- -- - - -- - - - --- - ------ ------ -- --- ...... - -- --- - -- --- - -- --- - -- --- - -- ---TOTAL 98.01 P 2.83 5.48 9.64 16.41 27.80 32.76 36.21 38.75 40.91 42.89 44.97 47.15 69.46 52.88 54.64

LOSS RATIO vs SALES * 25.02 23.52 22.02 20.35 19.0X 17.6S 26.31 14.92 14.92 14.92 14.92 14.9 1n4.92 1I.9 14-92LOSS P0 0.71 1.29 2.12 3.36 5.30 5.78 5.69 5.79 6.11 6.41 6.72 7.05 7.39 7.75 6.13

PEAK DOIAJD. PDs LEVEL W 3.54 6.77 11.75 19.77 33.10 38.54 42.10 4.4 47.02 49.29 51.68 54.20 54.65 59.64 2.57LOSS RATIO 20.02 19.01 18.02 17.02 16.02 15.02 14.02 13.02 13.O2 13-02 13.02 13.02 13.02 13.02 13.02

LOAD rACTOR 69.52 63.32 59.02 55.22 51.52 49.42 48.21 47.32 46.42 45.62 44.92 64.21 63.52 42.82 *2.121RR. IMPACT 4.02 P0 1.84 2.90 4.40 6.59 9.81 10.22 10.45 10.59 10.7? 10.87 10.98 11.09 11.20 11.31 11.43POSSIBLE PWA OFSMAND P0 5.34 9.67 16.15 26.36 42.90 48.76 52.55 55.13 57.79 60.17 62.67 65.29 66.05 70.95 74.00POSSISLE LOAD FACTOR 45.72 44.32 42.92 41.42 39.82 39.12 38.62 38.22 37.82 37.42 37.02 36.72 36.32 36.02 35.62

0*

-74- ANNEX 5.2

Page 1 of 9

BANGLADESH

THIRD RURAL ELECTRIFICATION PROJECT

Economic Internal Rate of Return

1. As described in Chapter III, the proposed project would comprisethe establishment of four new PBSs, the extensionlintensification ofexisting PBSs, plus technical assistance, construction of new headquarteroffices, central training and workshop facilities. It is thus necessary todemonstrate that not only will the EIRR for the entire project exceed 12?,the estimated opportunity cost of capital, but in addition that the EIRRfor each separate part of the project, i.e.s (i) the four new PBSs; and(ii) by the extension of existing PBSs, exceed 12?.

Costs

2. All financial costs were converted to economic costs by:(i) expressing the import content at c.i.f. prices in terms of mid-1989prices; (ii) valuing skilled labor at 0.89 and unskilled labor at 0.7 ofthe market wage rates; (iii) using a conversion factor of 0.9 to expresslocal costs for materials, equipment and services in terms of equivalentborder prices; and (iv) using a standard conversion factor (scf) of 0.89for local costs such as house wiring and electric motors for irrigationpumps. The economic cost of electricity supply at the 33 kV bulk supplypoints was estimated as the long run marginal cost (LRMC) of generationincreased by 10? to allow for power plants' self-consumption and losses inthe high voltage transmission system. The LXMC excluded costs of extendingthe high voltage transmission system since studies showed that theincremental demand by the proposed project would not change the proposedtransmission investment program. Transmission costs at 33 kV and belowwere estimated separately and are included in the investment cost column ofTable 1 of this Annex. The costs referred to as private costs in Table 1relate particularly to the costs of house wiring and the acquisition oflocally procured electric motors. Operations and maintenance (O&M) costswere estimated as 5? of cumulative annual investment costs.

Benefits

3. Benefits in the economic rate of return calculations wereestimated on two bases. First, simply in terms of what consumers actuallypay for electricity (Tk 2.6/kVh) under the PBSs' FY90 tariffs. This isreferred to as the adjusted EIRR since benefits are measured in financialterms rather than in economic terms. On this basis, the EIRR for theentire project is 0o, for the four new PBSs it is 3.0?, and for the PBSs tobe extendedlintensified it is 2.2X. These measures of the EIRR say moreabout the adequacy of tariffs and their relationship to LRMC than about thetrue economic worth of the proposed project. The latter requires benefitsto be measured in economic terms, that is in terms of consumers'willingness to pay (VTP) for the incremental electricity sales. WTP wasmeasured, on a conservative basis, as follows: (i) for residential andcommercial

-75-ANNEX 5.2Page 2 of 9

consumers it was based on the cost of lighting using either kerosene wicklamps (yield equivalent of 20 W electric bulb) or pressurized kerosenelamps (yield equivalent of 60 W electric bulb); and (ii) for industrial andirrigation consumers it was based on the costs of running diesel plantsusing imported high speed diesel oil. Table 1 shows the estimated annualbenefits for the entire project, both in terms of the benefits based onFY90 tariff rates and the measures of incremental consumer surplus for thelighting and other loads, while Tables 3 and 5 show the equivalentestimated benefits for the four new PBSs and the PBSs to be extended,respectively. The methodology used in the computation of the WTP basedbenefit measure is illustrated in Figure 1, and was as follows. First, toestimate the benefits for those electricity sales which would represent asubstitution of electricity for an alternative fuel, WTP was measured asindicated in (i) and (ii) above (area OPOAQO in Figure 1). Second, theincremental electricity sales which are forecast to occur, either as aresponse to the availability of electricity (for such uses as televisions,electric fans and electric cooking), or as a response to the lower price ofelectricity vis-a-vis its substitutes, were estimated assuming a lineardemand curve (AC in Figure 1) with a maximum WTP as just described, and aminimum equal to the FY90 tariff rate. The WTP for these type of benefits,which relate to a shift in the demand curve from Do to Dn in Figure 1, wasequal to area QOACQn in that figure. For the entire project the discounted(sales) weighted average WTP was equal to Tk 6.21kWh. Table 1 shows thaton this basis the EIRR for the entire project is 19Z, while Table 3 showsthat the EIRR for the new PBSs is 36.5X and Table 5 shows that the EIRR forthe seven PBSs to be extended is 582. As mentioned in para. 1 above, theforegoing WTP based measures of EIRR are lower bound measures since, forexample, they assume that consumers' maximum WTP for new product uses ofelectricity (e.g., for televisions) is equal to the WTP for electricity tosubstitute for kerosene in lighting. Further, the foregoing measuresassume zero benefits for the technical assistance component of the project,and for the training, warehouse, etc., components.

Sensitivity Analysis

4. Sensitivity analysis of both the adjusted and VTP based measuresof EIRR are presented in Tables 2 (for the entire project), 4 (for the newPBSs) and 6 (for the extended PBSs). In each case, the analysis ispresented in terms of the percentage change of a particular parameterrequired to yield a specified value of the EIRR. Thus, consideringTable 2, the investment costs for the entire project would have to increaseby 68.52 to make the EIRR fall to 12Z; or, alternatively, total benefitswould have to fall by 222 to bring about the same result. The sensitivityanalysis shows that all base case EIRRs are robust.

ANNEX 5.2Page 3 of 9

BA ECLADI 83

t?HRD RURAL ELECTRIFICATION PRCJECT

Table 1: EIM FOR TUB PROPOSED PROJECT

Olsbura. Invest. Supply OU PrIvate BeotIts Fuel saing Luba oll Totsl Total Balance BalanceProflIo Cost Cost Cost Costs from sales zero. USD0 Savuams Cost Benefits (WtP) (Tartff)

M.Tk 1.Tk K.Tk K.Tk .Tk X.2k 1.?k 1X.?k N.Tk 1.Tk H.5k M.2k

F1992 4.02 133.8 133.8 0.0 (133.8) (133.8)FY1993 13.02 434.8 6.7 441.5 0.0 (441.5) (441.5)FY1994 13.01 434.8 54.0 28.4 17.4 122.8 15.8 28.2 10.0 534.7 176.9 (382.4) (435.5)FY1995 22.02 735.8 94.1 50.2 12.3 218.4 27.9 42.2 14.9 890.5 303.4 (630.8) (726.4)Fn1996 22.02 735.8 152.3 87.0 16.8 359.5 49.2 63.1 22.3 991.9 494.2 (569.7) (729.1)FY1997 16.02 535.2 239.7 123.8 27.4 578.4 86.9 94.4 33.4 926.0 793.0 (248.6) (509.6)FY1998 7.02 234.1 374.6 150.5 45.2 926.9 153.8 141.1 49.9 804.5 1,271.8 281.9 (144.8)FY1999 3.01 100.3 418.4 162.2 0.7 1,028.9 155.4 141.1 49.9 681.7 1,375.4 488.0 18.7FY2000 445.9 167.2 0.7 1,094.7 157.1 141.1 49.9 613.8 1,442.9 610.2 114.4FY2001 462.5 167.2 0.7 1,139.5 158.8 141.1 49.9 630.4 1,489.4 631.0 116.7FY2002 479.3 167.2 0.7 1,196.1 160.5 141.1 49.9 647.2 1,547.7 661.2 114.4FY2003 494.0 167.2 0.7 1,205.2 162.2 141.1 49.9 661.9 1,558.5 655.5 112.5Ff2004 509.4 167.2 0.7 1,237.9 164.0 141.1 49.9 677.3 1,593.0 668.1 110.5FY2005 525.5 167.2 0.7 1,272.0 165.7 141.1 49.9 6"9.4 1,628.8 680.9 108.3Ff2006 542.4 167.2 0.7 1,307.4 167.5 141.1 49.9 710.4 1,666.0 694.2 105.9FY2007 560.1 167.2 0.7 1,344.3 169.3 141.1 49.9 728.1 1.704.7 707.7 103.4FY2008 578.8 167.2 0.7 1,382.8 171.1 141.1 49.9 746.7 1,745.0 721.7 100.6Ff2009 598.0 167.2 0.7 1,422.4 173.0 141.1 49.9 766.0 1,786.4 736.0 97.7Ff2010 617.9 167.2 0.7 1,463.1 174.9 141.1 49.9 785.8 1,829.0 750.5 94.5FY2011 638.4 167.2 0.8 1,504.9 176.7 141.1 49.9 806.4 1,872.7 765.4 91.2FY2012 659.6 167.2 0.8 1,548.0 178.6 141.1 49.9 827.6 1,917.7 780.5 87.7FY2013 681.5 167.2 0.8 1,592.3 180.S 141.1 49.9 849.5 1,963.9 796.0 83.9FY2014 704.2 167.2 0.8 1,657.8 182.5 141.1 49.9 872.2 2,011.4 811.7 79.9Ff2015 727.6 167.2 0.8 1,684.7 184.5 141.1 49.9 895.6 2,060.3 827.8 75.7Ff2016 751.7 167.2 0.8 1,732.9 186.5 141.1 49.9 919.8 2,110.5 844.1 71.3FY2017 776.7 167.2 0.8 1,782.5 188.5 141.1 49.9 944.8 2,162.1 860.8 66.6FY2018 802.5 167.2 0.8 1,833.5 190.5 141.1 49.9 970.6 2,215.1 877.8 61.6Ff2019 829.2 167.2 0.8 1,886.0 192.6 141.1 49.9 997.2 2,269.6 895.2 56.3FY2020 856.7 167.2 0.8 1,940.0 194.6 141.1 49.9 1,024.8 2,325.7 912.9 50.8FY2021 885.2 167.2 0.8 1,995.5 196.7 141.1 49.9 1,053.3 2,383.3 930.9 45.0FY2022 914.6 167.2 0.9 2,052.6 198.9 141.1 49.9 1,082.7 2,442.5 949.3 38.8PY2023 9'5.0 167.2 0.9 2,111.3 201.0 141.1 49.9 1,113.1 2,503.4 968.0 32.3

ECOWONIC INTERNAL RATE of RETURN: 16.92 -2.82

-77- ANNEX 5.2Page 4 of 9

BANGLADESH

THIRD RURAL ELECTRIFICATION PROJECT

Table 2: 9B1M AID SESSIT1VITY AMNLYSIS OF RE-I11 PROJECT

Not Present Values

lanvest. Supply OSM Private Beneflts Fuel savins Lube otl Total Total Balance BalanceDiscunt Cost Cost Cost Costs frm sales xero. USD0 SavIAIs Cost Benefits (MtP) (Tariff)

Rate H.Tk K.Tk M.Tk M.Tk M.Tk H.Tk M.Tk M.Tk K.Tk H.Tk M.Tk H.Tk

0.0X (3,345) (17.320) (4,622) (136) 32,482 4,765 3,897 1,379 (25,423) 42,324 17,101 (1,082)2.02 (3,070) (11,600) (3,237) (118) 21,855 3,276 2,728 965 (18,024) 28,825 10,800 (1,447)4.01 (2,825) (8,017) (2,340) (103) 15,173 2,323 1,970 697 (13,285) 20,164 6,879 (1,633)6.02 (2,607) (5,711) (1,741) (91) 10,853 1,696 1,465 518 (10,149) 14,532 4,383 (1,712)8.0X (2,412) (4,184) (1,329) (81) 7,982 1,271 1,117 395 (8,006) 10,766 2,760 (1,726)

10.02 (2,236) (3,146) (1,039) (73) 6,022 975 872 309 (6,494) 8,178 1,684 (1,703)12.02 (2,078) (2,422) (829) (65) 4,689 765 695 246 (5,395) 6,354 960 (1,657)14.0S (1,936) (1,904) (673) (59) 3,663 611 564 200 (4,572) 5,037 465 (1,398)16.02 (1,807) (1,525) (556) (54) 2,939 496 465 164 (3,941) 4,064 123 (1,533)18.02 (1,690) (1,242) (465) (49) 2,396 4v8 3S8 137 (3,445) 3,330 (115) (1,465)20.01 (1,584) (1,026) (393) (45) 1,981 340 328 116 (3,047) 2,766 (282) (1,398)22.02 (1,487) (858) (337) (41) 1,658 287 280 99 (2,722) 2,325 (397) (1,332)24.0X (1,398) (726) (291) (37) 1,403 244 241 85 (2,452) 1,974 (477) (1,268)26.02 (1.317) (620) (253) (34) 1,199 210 210 74 (2,224) 1,693 (532) (1,207)28.0 (1,243) (534) (222) (32) 1,033 182 183 65 (2,030) 1,463 (567) (1,149)30.02 (1,174) (464) (196) (29) 897 158 162 57 (1,863) 1,274 (589) (1,095)

RIME 16.91 -2.82

Sensitivity Analysis

Discount Invest. OSM Inv.+01M Supply Connaec- CGM Total WtP Savings Total Discount TariffRate Cost Cost Costs Cost tions Consumption Cost Benefits Benefits Benefits Rate

0.0X 511.32 370.0X 214.62 98.72 -68.22 67.32 -52.62 -40.22 0.0X 7.622.02 351.82 333.6X 171.2Z 93.12 -63.1X 59.92 -49.42 -37.5X 2.0X 15.124.02 243.52 294.02 133.22 85.82 -57.12 -96.12 51.82 -45.32 -34.12 4.02 24.326.02 168.12 251.82 100.8S 76.72 -50.22 -85.22 43.22 -40.42 -30.22 6.02 36.028.02 114.42 207.62 73.8S 66.02 -42.52 -72.72 34.52 -34.62 -9".12 -25.62 8.01 49.4210.02 75.32 162.12 51.42 53.52 -34.02 -58.62 25.92 -28.02 -78.12 -20.62 10.0S 64.6212.02 46.22 115.82 33.02 39.62 -24.8X -43.12 17.8X -20.62 -56.32 -15.12 12.02 81.5214.0X 24.02 69.02 17.82 24.42 -15.12 -26.42 10.22 -12.72 -33.8S -9.2X 14.0X 99.8216.02 6.8X 22.12 5.2X 8.02 -4.92 -8.72 3.12 -4.22 -10.92 -3.02 16.02 119.4218.02 -6.8X -24.8X -5.42 -9.32 5.72 10.02 -3.32 4.82 12.42 3.52 18.02 140.1220.02 -17.82 -71.62 -14.22 -27.42 16.62 29.52 -9.22 14.22 35.92 10.22 20.02 161.7222.02 -26.72 -21.82 -46.32 27.92 49.6X -14.62 24.02 59.62 17.12 22.02 184.0224.02 -34.1X -28.32 -65.8X 39.42 70.42 -19.52 34.02 83.62 24.22 24.02 207.0226.02 -40.42 -33.92 -85.82 51.22 91.82 -23.92 44.32 107.72 31.42 26.02 230.7X28.02 -45.72 -38.72 63.2X 113.72 -27.92 54.92 132.0X 38.82 28.02 254.8230.02 -50.22 -43.02 75.52 136.12 -31.62 65.72 156.42 46.3X 30.02 279.52

-78- ANNEX 5.2Page 5 of 9

RANOLADBSR

THSRD RURAL ELSCTRIFICATION PROJECT

Table 3: tIRR FOR TOB NW PBSS OF THE PR3P01SD PROJEcT

Disburs. Ihaest. Supply O4 Private Recfits Puel sav1ns Lube i11 Total Total Blance SalanceProfile Cost Coat Cost Costs from sales Kero. HSD0 Savings Cost Benefits (WtP) (Tariff)

M.Tk M.T.c M.Tk M.Tk K.Tk ).Tk M.Tk M.Tk M.Tk M.Tk M.Tk M.Tk

FY1992 4.01 70.0 70.0 0.0 (70.0) (70.0)FY1993 13.01 227.5 3.5 231.0 0.0 (231.0) (231.0)FY1994 13.01 227.5 34.1 14.9 11.0 122.8 10.0 17.8 6.3 287.5 157.0 (155.1) (224.9)FY1995 22.01 385.0 59.5 26.3 6.5 218.4 17.6 26.7 9.4 477.3 272.1 (248.9) (373.7)FY1996 22.0X 385.0 96.2 45.5 10.6 359.5 31.0 39.9 14.1 537.3 444.5 (164.7) (371.4)FY1997 16.01 280.0 151.3 64.8 17.3 578.4 54.9 59.6 21.1 513.5 713.9 84.8 (250.5)n11998 7.01 122.5 236.5 78.8 28.6 926.9 97.1 89.1 31.5 466.4 1,144.6 492.9 (49.9)FY1999 3.01 52.5 240.0 84.9 0.4 1,028.9 98.1 89.1 31.5 377.8 1,247.7 664.1 64.3FY2000 281.5 87.5 0.4 1,094.7 99.2 89.1 31.5 369.4 1,314.5 726.2 90.3FY2001 292.0 87.5 0.4 1,139.5 100.2 89.1 31.5 379.9 1,360.4 752.6 91.7;Y2002 302.6 87.5 0.4 1,196.1 101.3 89.1 31.5 390.5 1,418.0 788.3 90.3FY2003 311.8 87.5 0.4 1,205.2 102.4 89.1 31.5 399.8 1,428.2 787.4 89.1FY2004 321.5 87.5 0.4 1,237.9 103.5 89.1 31.5 409.5 1,462.1 05.0 87.8FY2005 331.7 87.5 0.4 1,272.0 104.6 89.1 31.5 419.7 1,497.2 823.2 86.41Y2006 342.4 87.5 0.5 1,307.4 105.7 89.1 31.5 430.3 1,533.8 842.0 84.9FY2007 353.6 87.5 0.5 1,344.3 106.9 89.1 31.5 441.5 1,571.8 861.5 83.3?Y2008 365.3 87.5 0.5 1,382.8 108.0 89.1 31.5 453.3 1,611.5 881.6 81.51Y2009 377.4 87.5 0.5 1,422.4 109.2 89.1 31.5 465.4 1,652.2 902.3 79.7FY2010 390.0 87.5 0.5 1,463.1 110.4 89.1 31.5 477.9 1,694.1 923.5 77.7TY2011 402.9 87.5 0.5 1,504.9 111.6 89.1 31.5 490.9 1,737.1 945.3 75.6MM2012 416.3 87.5 0.5 1,548.0 112.8 89.1 31.5 504.3 1,781.4 967.5 73.3FY2013 430.1 87.5 0.5 1,592.3 114.0 89.1 31.5 518.1 1,826.9 990.4 71.01Y2014 444.4 87.5 0.5 1,637.8 115.2 89.1 31.5 532.4 ;,873.7 1,013.8 68.51Y2015 459.1 87.5 0.5 1,684.7 116.4 89.1 31.5 547.1 1,921.8 1,037.7 65.8?Y2016 474.4 87.5 0.5 1,732.9 117.7 89.1 31.5 562.4 1,971.3 1,062.3 63.01Y2017 490.1 87.5 0.5 1,782.5 119.0 89.1 31.5 578.1 2,022.1 1,087.5 60.01Y2018 506.4 87.5 0.5 1,833.5 120.3 89.1 31.5 594.4 2,074.4 1,113.3 56.91Y2019 523.2 87.5 0.5 1,886.0 121.5 89.1 31.3 611.2 2,128.2 1,139.8 53.5FY2020 540.6 87.5 0.5 1,940.0 122.9 89.1 31.5 628.6 2,183.5 1,166.9 50.01Y2021 558.5 87.5 0.5 1,995.5 124.2 89.1 31.5 646.5 2,240.3 1,194.7 46.47Y2022 577.0 87.5 0.5 2,052.6 125.5 89.1 31.5 665.1 2,298.7 1,223.2 42.51Y2023 596.2 87.5 0.5 2,111.3 126.9 89.1 31.5 684.2 2,358.8 1,252.3 38.4

ECOOICC ISTERNAL RATE of RETURN: 34.21 0.81

_79_ ANNEX 5.2Page 6 of 9

BANGLADESH

TSIRD RURAL ELECTRIFICATION PROJECT

table 4: EIRR AND SENSSTIVITY ANALYSISt NEN PBSs

net Present Values

Invest. Supply 04M Private Benefits Fuel savings Lube oil Total Total Balance BalanceDiscount Cost Cost Cost Costs from sales Kero. 8SD0 Savings Cost Benefits (NtO) (Tariff)

Rate M.Tk H.Tk M.Tk 3.Tk m.Tk 3.Tk M.Tk W.7k H.Tk M.Tk H.Tk M.Tk

10.01 (1,170) (1,975) (544) (46) 6,022 616 551 195 (3,734) 7,383 3,649 (710)12.02 (1,088) (1,519) (434) (41) 4,649 483 439 155 (3,082) 5,726 2,644 (722)15.01 (978) (1,066) (319) (36) 3,274 347 323 114 (2,399) 4,058 1,659 (713)20.02 (829) (642) (206) (28) 1,981 215 207 73 (1,705) 2,477 772 (663)25.02 (710) (419) (142) (23) 1,296 143 142 50 (1,293) 1,631 337 (601)30.02 (615) (290) (102) (19) 897 100 102 36 (1,025) 1,135 109 (540)35.0X (537) (210) (77) (15) 648 73 76 27 (838) 823 (15) (484)40.01 (473) (157) (59) (13) 484 54 58 21 (702) 617 (85) (435)45.01 (420) (120) (47) (11) 371 42 46 16 (598) 475 (123) (392)50.02 (376) (95) (38) (9) 291 33 37 13 (517) 373 (144) (354)55.02 (338) (76) (31) (8) 232 26 30 11 (453) 299 (154) (322)60.02 (306) (62) (26) (7) 188 21 25 9 (400) 243 (157) (293)

ErRR 34.22 0.82

Sensitivity Analysis

Discount Invest. OH lnv.+O&M Supply Connec- GW Total wtP Savings Total Discount TariffRate Cost Cost Costs Cost tlons Consumption Cost Beneflts Benefits Benefits Rate

10.01 311.81 671.22 212.92 184.82 -68.01 -90.22 97.71 -60.61 -49.42 10.01 42.7212.02 243.11 609.62 173.82 174.0X -63.5X -84.52 85.8X -56.9X -46.22 12.01 56.3215.02 169.52 519.22 127.82 155.72 -56.11 -75.1X 69.12 -50.71 -40.92 15.02 79.0X20.01 93.22 375.02 74.62 120.32 -42.71 -57.62 45.32 -39.01 -31.22 20.02 121.5225.02 47.51 238.12 39.62 80.51 -28.42 -38.5X 26.12 -26.02 -20.7X 25.02 168.4230.0X 17.82 107.02 15.31 37.82 -13.22 -18.02 10.7X -12.21 -46.01 -9.61 30.01 218.4235.01 -2.81 -19.81 -2.52 -7.22 2.52 3.51 -1.82 2.32 8.62 1.82 35.02 270.8240.02 -17.92 -15.92 -54.12 18.9X 25.91 -12.12 17.51 63.51 13.7X 40.02 325.3245.02 -29.32 -26.41 35.92 49.22 -20.61 33.21 118.71 26.02 45.01 381.5250.02 -38.32 -34.82 53.42 73.31 -27.82 49.42 174.52 38.51 50.02 439.4X55.02 -45.4X -41.7X 71.41 98.11 -34.02 66.22 231.02 51.42 55.02 498.8260.02 -51.32 -47.41 89.92 123.72 -39.32 83.32 288.12 64.62 60.02 559.62

-80- ANE 5.2Sage 7 of 9

3ANLAVDESH

T8IRD 204L .:SCTRITICANTICN P1WS0

Table 5, EM IOR TH1 PAS' 1MISSIO0 OF TSM PROPOSD ECS0

DLsbUra. Invst. Supply 041 Private Benefits Puel sawngs Lube *. Total Teotl Balance &alancProfile Cost Coat Cost Costs from "1se ero. 380 SaIVnS cost Benefits (VtP) (Tariff)

It.Tk H.Tk t.Tk H.Tk It.Tk 4.1k t.Tk It.Tk It.Tk H.Tk It.Tk 3.Tk

FY1992 4.02 41.2 41.2 0.0 (41.2) (41.2)n199" 13.02 134.0 2.1 136.0 0.0 (136.0) (136.0)

Y11994 13.02 134.0 19.9 8.8 6.4 122.8 5.8 10.4 3.7 169.0 142.7 (50.8) (132.5)FY1995 22.02 226.7 34.7 15.5 3.8 218.4 10.3 15.5 5.5 280.6 249.7 (74.6) (220.2)FY1996 22.02 226.7 56.1 26.8 6.2 359.5 18.1 23.2 8.2 315.8 409.2 21.5 (218.9)FY1997 16.OX 164.9 88.3 38.1 10.1 578.4 32.1 34.8 12.3 301.4 657.5 240.4 (147.9)2119" 9 7.0 72.1 138.0 46.4 16.7 926.9 56.7 52.0 18.4 273.2 1,054.0 595.4 (30.1)11999 3.01 30.9 240.0 50.0 0.2 1,028.9 57.3 52.0 18.4 S21.1 1,156.6 629.7 (63.0)

nY2000 164.3 51.5 0.2 1,094.7 57.9 52.0 18.4 216.1 1,223.0 788.0 52.SF2001 170.5 51.5 0.2 1,139.5 58.6 52.0 18.4 222.2 1,268.5 818.3 53.1112002 176.7 51.5 0.3 1,196.1 59.2 52.0 18.4 228.4 1,325.6 858.0 52.3112003 182.1 51.5 0.3 1,205.2 59.8 52.0 18.4 233.9 1,335.4 660.5 51.61Y2004 187.8 51.5 0.3 1,237.9 60.5 52.0 18.4 239.5 1,368.8 881.6 50.91Y2005 193.7 51.5 0.3 1,272.0 61.1 52.0 18.4 245.5 1,403.5 903.6 50.11Y2006 200.0 51.5 0.3 1,307.4 61.8 52.0 18.4 251.7 1,439.6 926.3 49.21Y2007 206.5 51.5 0.3 1,344.3 62.4 52.0 18.4 258.3 1,477.1 950.0 48.31Y2008 213.4 51.5 0.3 1,382.8 63.1 52.0 18.4 265.2 1,516.3 974.6 47.22Y2009 220.5 51.5 0.3 1,422.4 63.8 52.0 18.4 272.3 1,556.5 999.8 46.2112010 227.8 51.5 0.3 1,463.1 64.5 52.0 18.4 279.6 1,597.9 1,025.7 45.01Y2011 235.4 51.5 0.3 1,504.9 65.2 52.0 18.4 287.2 1,640.5 1,052.3 43.81Y2012 243.3 51.5 0.3 1,548.0 65.9 52.0 18.4 295.1 1,684.3 1,079.6 42.5.f2013 251.3 51.5 0.3 1,592.3 66.6 52.0 18.4 303.2 1,729.3 1,107.7 41.1112014 259.7 51.5 0.3 1,637.8 67.3 52.0 18.4 311.5 1,775.5 1,136.5 39.61Y2015 268.4 51.5 0.3 1,684.7 68.0 52.0 18.4 320.2 1,823.1 1,16.0 38.11Y2016 277.3 51.5 0.3 1,732.9 68.8 52.0 18.4 329.1 1,872.1 1,196.4 36.4112017 286.5 51.5 0.3 1,782.5 69.5 52.0 18.4 338.3 1,922.4 1,227.6 34.7TY2018 296.1 51.5 0.3 1,833.5 70.S 52.0 18.4 347.9 1,974.2 1,259.6 32.9fY2019 305.9 51.5 0.3 1,886.0 71.0 52.0 18.4 357.7 2,027.4 1,292.5 31.0

1Y2020 316.1 51.5 0.3 1,940.0 71.8 52.0 18.4 367.9 2,082.1 1,326.2 28.91Y2021 326.6 51.5 0.3 1,995.3 72.6 52.0 18.4 378.5 2,118.4 1,360.9 26.8112022 337.5 51.5 0.3 2,052.6 73.5 52.0 18.4 389.3 2,196.3 1,396.5 24.51Y2023 348.7 51.5 0.3 2,111.3 74.1 52.0 18.4 400.6 2,235.8 1,433.0 22.1

E0UmOC SIITE31L RATE of RSt= I 55.52 0.02

-81- ANNEX 5.2Page 8 of 9

BANCLADESH

T3z RURAL ElCTRIFICATION PROJE

Table 6: EIR AND SENSIUIVM ANALYSIS% PBS8' flmnsI0Net Preseat Values

Invest. Supply O0t Private Renefits Fuel savias Lube oil Total Total Balance BalanceDiscount Cost Cost Cost Costs frnm sales Xero. S Swvins Cost Beneflts MPt?) (Tariff)

Rate 1t.k I.tk M.Tk M.Tk V.Tk )tSk M.Tk I.tk M.Tk M.Tk 1.Tk M.Tk

20.02 (488) (398) (121) (16) 1,981 126 121 43 (1l023) 2,270 1,247 (416)24.02 (431) (283) (90) (14) 1.403 90 89 31 (817) 1.614 797 (381)28.0S (383) (209) (68) (12) 1,033 67 68 24 (672) 12191 520 (347)32.02 (342) (159) (53) (10) 784 51 5S 19 (565) 906 342 (316)36.02 (308) (124) (43) (9) 610 40 42 15 (483) 706 223 (288)40.02 (279) (98) (35) (7) 484 32 34 12 (419) 562 143 (263)44.02 (253) (79) (29) (7) 391 26 28 10 (368) 454 86 (241)48.02 (231) (65) (24) (6) 320 21 23 8 (326) 372 47 (222)52.02 (212) (54) (20) (5) 265 17 20 7 (291) 309 18 (204)56.02 (195) (45) (17) (4) 223 15 17 6 (262) 260 (2) (189)60.02 (180) (38) (15) (4) 188 12 14 5 (237) 220 (17) (175)64.02 (167) (33) (13) (4) 161 11 12 4 (216) 18e (28) (163)68.02 (155) (28) (11) (3) 139 9 11 4 (198) 162 (36) (152)72.02 (145) (24) (10) (3) 120 8 9 3 (182) 141 (41) (142)76.02 (136) (21) (9) (3) 105 7 8 3 (168) 123 (45) (133)80.02 (127) (19) (8) (2) 92 6 7 3 (156) 108 (48) (125)

BlM 55.52 0.0O

SensitLvity Analysis

Dlscount Invest. Ott Iav.0&K Supply Con4es- amE Total U?? Sayings Total Discomt TariffRate Cost Cost Costs Coat tins Consumption Cost bnefits Benefits Benfits Rate

20.02 255.62 1028.72 204.72 313.3X -67.2X -78.82 121.8S -62.9Z -54.92 20.02 130.3224.02 185.02 890.42 S53.2 281.82 -60.52 -71.1X 97.62 -56.82 -49.42 24.02 168.5228.02 135.82 761.12 115.22 249.02 -53.5X -63.12 77.42 -50.32 -43.62 28.02 208.7232.02 99.8X 638.9X 86.32 215.32 -46.32 -54.7X 60.52 -43.62 -37.72 32.02 250.3236.02 72.52 $22.02 63.62 180.62 -38.92 -45.92 46.2X -36.6X -31.62 36.02 293.2240.02 51.2X 409.32 45.52 145.12 -31.31 -37.02 34.02 -29.52 -25.41 40.02 337.3244.02 34.12 300.02 30.6X 108.8X -23.42 -27.72 23.52 -22.1X -19.0X 44.02 382.5148.02 10.12 193.3X 18 22 71.62 -15.42 -18.32 14.32 -14.62 -88.42 -12.52 48.02 428.6252.02 8.62 89.0X 7.81 33.6X -7.22 -8.62 6.22 -6.82 -41.12 -5.92 52.0X 475.7156.02 -1.22 -13.52 -l.12 -5.22 1.12 1.32 -0.92 1.12 6.3X 0.92 56.02X523.8260.02 -9.5X -8.8X -44.92 9.62 11.42 -7.22 9.12 54.02 7.8x 60.02 572.7164.02 -16.72 -15.52 -85.42 18.3X 21.72 -12.92 17.32 101.92 14.81 64.02 622.5268.0X -22.92 -21.42 27.22 32.22 -18.02 25.2150.22 21.92 68.02 673.2272.02 -28.42 -26.62 M6.22 42.92 -22.62 34.22 198.92 29.22 72.02 724.6276.02 -33.32 -31.22 45.42 5.8S -26.82 42.92 247.9X 36.62 76.02 776.9180.02 -S7.62 -35.32 54.7 64.82 -30.62 51.7X 297.42 44.12 80.02 830.11

-82- ANNEX 5.2Page 9 of 9

Figure ls ESTIZTION OF WILLINGNESS TO PAY

WILLINGNESS TO PAYVariation of WtP with tme consumption

oe\nd curve

Oemarw curve

A

Con)~~a

YEARLY OLIANr ITY CONSLMEO

-83-a . , *~~~~~~~~~~ANNEX 6.1

BANGLADESH

THIRD RURAL ELECTRIFICATION PROJECT

Selected Documents Available in the Project File

1. Feasibility Study Report on Area Coverage Rural ElectrificationPhase IV.

REBINRECA: June 1988

2. Financial Policies and Performance of the PBSs prepared byCoopers and Lybrand Associates for USAID

Volume l: Executive SummaryVolume 2s Main ReportVolume 3: AppendicesVolume 4: Manual for Financial Model, March 1989

3. Bangladesh Rural Electrification Preliminary Assessment: Draft finalreport prepared for USAID by de Lucia and Associates Inc.September 1989.

4, REB Annual Reports for 1986187, 1987188, .988189

5. Background data used for the economic analysis: October 1989.

6. Project ProformaACRE Phase IV-ACentral Facilities, REB: January 1990

89^2!* t 900 9V BANGLADESH 9?,OS'g\ ~ (\y. -I>>9NDIA THIRD RURAL ELECTRIFICATION PROJECT

;<Jt,4. 't vv . Area Coverage -Rural Electrification ProgramI CFfmi ;)* > 's - | ffi ELECTRIFICATION AREAS:

J.4 t/Phae IV -A New PBS Areas(Project) UpozilaBoundaries

,,/S ,tjjjf > , |||||||||iPhase IV A PBS Extension Areas(Project) Zilla8 otries

260 -- '__ Kue1A (rfDA) Division Boundlaries-26° * . Under Constrcton -- 26°

Phase If B (IDA) PBS IntensikfitionlProjed) nerfoa" s

C~~~~~~~~~~~~~~~~~~~~~~~~ 'Al II CDASMan;FNIND

2. , g < 4.^ ' X S ~~~~~~~~~~~~~~~~Division Headquarters

%~~%

X INDIA < r Bay of Be~~~~~~~~~~~~~~~~~Ntingal C,pf3

206

,~~~~~~~~~~~~~~~~~~~~~~~~~~~L~ 'D QoaY.'A

Arebint: 0 Bengol Q lp 2 Bay SOfiE Benga

| sea -.< -21° O 20 40 60 OD KaUOM.TETS 21

K~~~~~~~~~~~~~~~

X ~~~~~~~~~~~~~~~900 9,1 92°_?%