ASIAN DEVELOPMENT BANK RRP:BAN 31296

REPORT AND RECOMMENDATION

OF THE

PRESIDENT

TO THE

BOARD OF DIRECTORS

ON

PROPOSED LOANS

AND TECHNICAL ASSISTANCE GRANT

TO THE

PEOPLE’S REPUBLIC OF BANGLADESH

FOR THE

WEST ZONE POWER SYSTEM DEVELOPMENT PROJECT

November 2001

CURRENCY EQUIVALENTS (as of 22 November 2001)

Currency Unit – Taka (Tk)Tk1.00 = $0.0176

$1.00 = Tk56.70

ABBREVIATIONS

ADB Asian Development BankBOO build-own-operateBPDB Bangladesh Power Development BoardDESA Dhaka Electric Supply AuthorityDESCO Dhaka Electric Supply Company Ltd.DFID Department for International Development of U.K.DP development partnerEA executing agencyEIRR economic internal rate of returnFMU financial management upgradeFIRR financial internal rate of returnIPP independent power producerJBIC Japan Bank for International CooperationKfW Kreditanstalt für Wiederaufbau of GermanyLIBOR London interbank offered rateLRMC long-run marginal costNDF Nordic Development FundO&M operation and maintenanceOCR ordinary capital resourcePBS Palli Bidyut Samity (rural electric cooperative)PGCB Power Grid Company of Bangladesh Ltd.PSRB Power Sector Reforms in BangladeshREB Rural Electrification BoardRPC Rural Power CompanySDR Special Drawing RightsTA technical assistanceUSAID United States Agency for International DevelopmentWACC weighted average cost of capital

NOTES

(i) The fiscal year (FY) of the Government ends on 30 June. FY before a calendar yeardenotes the year in which the fiscal year ends, e.g., FY1998 ends on 30 June 1998.

(ii) In this report, “$” refers to US dollars.

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WEIGHTS AND MEASURES

V (volt) - Unit of voltagekV (kilovolt) - 1,000 voltsVA (volt-ampere) - Unit of powerMVA (mega volt-ampere) - 1,000,000 VAw (watt) - Unit of active powerkW (kilowatt) - 1,000 WmW (megawatt) - 1,000,000 WWh (watt-hour) - unit of energyKWh (kilowatt-hour) - 1,000 WhMWh (megawatt-hour) - 1,000,000 WhGWh (gigawatt-hour) - 1,000,000,000 Wh

CONTENTS

Page

LOAN AND PROJECT SUMMARY ii

MAP v

I. THE PROPOSAL 1

II. INTRODUCTION 1

III. BACKGROUND 2A. Sector Description 2B. Government Policies and Plans 4C. External Assistance to the Sector 5D. Lessons Learned 5E. ADB’s Sector Strategy 9F. Policy Dialogue 9G. Aid Coordination 10

IV. THE PROPOSED PROJECT 10A. Rationale 10B. Objectives and Scope 12C. Technical Justification 13D. Cost Estimates 13E. Financing Plan 14F. Implementation Arrangements 15G. Executing Agencies 16H. Environmental and Social Measures 22I. Technical Assistance 23

V. PROJECT JUSTIFICATION 24A. Project Basis 24B. Financial Analysis 24C. Economic Analysis 26D. Social Dimensions 28E. Impact on Poverty 28F. Risks 29

VI. ASSURANCES 30A. Specific Assurances 30B. Conditions for Loan Effectiveness 31

VII. RECOMMENDATION 32

APPENDIXES 33

LOAN AND PROJECT SUMMARY

Borrower The People’s Republic of Bangladesh.

Project Description The Project has three components:

Part A: Construction of 230-kilovolt (kV) transmission linesand substations in the west zone and the second 230 kVeast-west interconnector between Ashuganj and Serajganj;

Part B: Upgrade and expansion of the electricity distributionnetworks in Khulna, Barisal, Jessore, Kushtia, and Faridpurcities; and,

Part C: Upgrade and expansion of the electricity distributionnetworks of eight rural electric cooperatives (Palli BidyutSamities [PBS]).

Classification Thematic: Economic growthGovernance

EnvironmentalAssessment Category B. An initial environment examination was

undertaken and its summary is a core appendix.

Rationale The Project furthers the ongoing power sector reforms to(i) improve governance, (ii) build long-term institutionalcapacity, (iii) improve efficiencies and financial viability,and (iv) facilitate private sector participation.

Objectives and Scope The objectives of the Project are to (i) increaseelectrification in southwest Bangladesh; (ii) enableevacuation and economic utilization of the powergenerated from the projects being contracted at Baghabariand Bheramara; and (iii) reduce losses and improve thereliability of the existing transmission and distributionsystems in southwest Bangladesh.

Cost Estimates The Project is estimated to cost $402.1 million equivalent,comprising $259.0 million in foreign exchange costs and$143.1 million equivalent in local currency costs.

($ million)

Financing Plan Source ForeignExchange

LocalCurrenc y

TotalCost

Percentage

Asian Development Bank 198.9 0.0 198.9 49.5

Cofinancing 40.0 0.0 40.0 10.0

Government/ExecutingAgencies

20.1 143.1 163.2 40.5

Total 259.0 143.1 402.1 100.0

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Loan Amount and Terms (i) A loan in various currencies equivalent to SDR 47.581million ($60.2 million equivalent) from the AsianDevelopment Bank’s (ADB's) special funds resources witha term of 32 years, including a grace period of 8 years, andwith an interest charge at the rate of 1 percent per annumduring the grace period and 1.5 percent per annumthereafter; and (ii) a loan of $138.7 million from ADB'sordinary capital resources under ADB’s London interbankoffered rate (LIBOR)-based lending facility. The loan willhave a term of 20 years, including a grace period of5 years; an interest rate to be determined in accordancewith ADB's LIBOR-based lending facility; a commitmentcharge of 0.75 percent per annum; and a front-end fee of1.0 percent.

Relending Terms The Borrower will relend the proceeds as follows:

(i) to the Power Grid Company of Bangladesh Ltd.(PGCB) for Part A of the Project, with a repaymentperiod of 20 years including a grace period of5 years, with an interest rate of 5.5 percent perannum;

(ii) to Bangladesh Power Development Board (BPDB)for Part B of the Project, with a repayment period of20 years including a grace period of 5 years, with aninterest rate of 5.5 percent per annum; and

(iii) to the Rural Electrification Board (REB) for Part C ofthe Project, with a repayment period of 30 yearsincluding a grace period of 8 years, with an interestrate of 0.75 percent per annum during the graceperiod and 2 percent per annum thereafter.

Period of Utilization Until 30 September 2006

Executing Agencies Part A of the Project will be executed by PGCB; Part B,initially by BPDB and subsequently by a new company to beestablished; and Part C by REB.

Implementation Schedule 1 November 2001 to 31 March 2006

Procurement Goods and services financed by ADB will be procuredfollowing ADB's Guidelines for Procurement. To accelerateproject implementation, the Executing Agencies have beenallowed advance procurement action. Retroactive financinghas not been permitted.

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Consulting Services Consulting services for Parts A, B, and C will:

(i) review the current designs and engineering;

(ii) design a new training curriculum based on a needssurvey;

(iii) organize training for staff; and

(iv) help computerize management systems.

Project Benefitsand Beneficiaries

The Project will improve quality and reliability of powersupply in western Bangladesh by building institutionalcapacity and developing a market orientation. The Projectwill increase power supply to the west zone area by about450 megawatts. Beneficiaries will be the consumers ofelectricity in Bangladesh in general and specifically those inthe rural and urban areas in the west zone.

Technical Assistance The Project includes technical assistance for corporatizingBPDB’s distribution operations in the west zone. The totalcost of the TA is $1,250,000 equivalent, comprising$765,000 in foreign exchange and $485,000 in localcurrency. ADB will finance, on a grant basis, the full foreignexchange cost and $135,000 equivalent of the localcurrency cost for a total of $900,000. The funds will comefrom the ADB-funded TA Program. The TA will require 22person-months of input of an international consulting firmand 20 person-months from a domestic associate.

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I. THE PROPOSAL

1. I submit for your approval the following Report and Recommendation on two proposedloans to the People’s Republic of Bangladesh for the West Zone Power System DevelopmentProject. The Report also describes proposed technical assistance for the Corporatization of theWest Zone Distribution Operations of the Bangladesh Power Development Board, and if theproposed loans are approved by the Board, I, acting under the authority delegated to me by theBoard, shall approve the technical assistance.

II. INTRODUCTION

2. The power sector in Bangladesh performed poorly through the late 1980s and 1990s.The major constraints in the sector were (i) lack of institutional capability; (ii) unavailability oflong-term domestic capital for financing investments; (iii) limited foreign exchange debt servicecapability of the economy; (iv) poor management systems and procedures; (v) low employeecommitment; and (vi) institutional weaknesses in governance, banking, law enforcement, andjudicial processes, which are external to the sector but are essential for its proper functioning.

3. In 1994, the Government of Bangladesh adopted a paper titled Power Sector Reforms inBangladesh (PSRB), which was formulated in consultation with the major development partners(DPs)1 in the power sector. The PSRB outlined the reform process proposed to be followed bythe Government to gradually remove the constraints in the sector through improvements insector and corporate governance, introduction of competition, and public-private partnerships.Reform of the external environment was to be done through targeted interventions in the powersector.

4. In accordance with the PSRB, the power sector in Bangladesh has gradually beenundergoing structural changes. The DPs have been supporting these changes through technicalassistance for planning and institutional strengthening as well as capital for system expansion,in line with the principle of reforms-linked assistance. Prior to the West Zone Power SystemDevelopment Project (the Project), assistance by the Asian Development Bank (ADB) had focuson the greater Dhaka area, given its commercial and political importance to Bangladesh.However, while the greater Dhaka area has considerably improved both physically andfinancially (although by no means near financial viability and sustainability as yet), the otherregions of the country, which have not been able to attract aid or private sector capital, havebeen falling behind in physical infrastructure as well as progress of reforms. The Projectproposes to correct this imbalance by providing assistance to the western region of Bangladesh.

5. The Project, which will be the fourth assistance provided by ADB in support of the reformprocess, is part of ADB's 2001 Country Assistance Program for Bangladesh. The Project is anintegral part of the least-cost development plan for the power sector, and is accorded highpriority by the Government. Loan fact-finding was carried out during 7–17 May 2001 andappraisal during 26 September - 2 October 2001.2

1 The Asian Development Bank, the World Bank, the Department for International Development of the UK, the Japan

Bank for International Cooperation, Kreditanstalt für Wiederaufbau for the Government of Germany, and the UnitedStates Agency for International Development.

2 The Appraisal Mission comprised S. Chander, Senior Project Engineer/Mission Leader; S. Ahmed, Senior ProjectOfficer; M.Z. Hossain, Senior Economist; M. Elerud, Financial Analyst; and Dewi Utami, Environment Specialist.D. Gracyzk, Senior Energy Specialist, prepared the economics sections of the Report. ADB’s Bangladesh ResidentMission provided extensive assistance in the processing of the Project.

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III. BACKGROUND

A. Sector Description

6. The power sector in Bangladesh is organized under the Ministry of Energy and MineralResources. The Government, through the ministry, wholly owns and supervises the BangladeshPower Development Board (BPDB), the Dhaka Electricity Supply Authority (DESA), and the RuralElectrification Board (REB), which are its three executing agencies in the sector. Till fiscal yearFY1998, BPDB was responsible for all generation and most of the transmission in the country,and also for distribution in district towns, municipalities, and some rural areas, while DESA wasresponsible for distribution in the greater Dhaka area, including the capital city. The distribution ofelectricity in most of the rural areas of Bangladesh is the responsibility of the 67 rural electriccooperatives or Palli Bidyut Samities (PBSs), which are organized, initially funded, and monitoredby REB. As part of the sector reform process, new public sector entities such as the Power GridCompany of Bangladesh Ltd. (PGCB) and the Dhaka Electric Supply Company Ltd. (DESCO)as well as private sector independent power producers (IPPs) such as the Rural PowerCompany Ltd. (RPC),3 the Meghnaghat AES Power Company Ltd.,4 and the Haripur AES PowerCompany Ltd. have been constituted. Over the next few years, these companies will own andoperate a substantial part of the power sector’s assets. The distribution subsector has also seena major rationalization of distribution territory between DESA and the PBSs. The Government,BPDB, and REB have taken steps to involve the private sector by (i) adopting a private powergeneration policy in October 1996, (ii) adopting a small power generation policy in 1998 toencourage distributed generation, and (iii) awarding contracts for about 1,800 megawatts (MW)of generating capacity on a build-own-operate (BOO) basis.

7. Bangladesh’s annual per capita electricity consumption of 87 kilowatt-hours (kWh) inFY2001 was the third lowest among ADB's developing member countries, after Cambodia andNepal.5 Despite intensive efforts to increase coverage, only about 20 percent of the populationhas access to electricity.6 Consumption of electricity in Bangladesh has increased at an averageannual rate of 8.5 percent from FY1994 to FY2001, with major increases in industrial andresidential use. The ADB-financed Power System Master Plan Study7 estimated that the demandfor electricity will increase by about 8 percent per year for the next 10 years. The current installedcapacity is 4,035 MW. The peak demand met was 3,096 MW on 3 July 2001.

8. Inadequate supply of electricity is a major constraint to economic growth. During FY1999,load shedding in the range 16-774 MW was resorted to on 335 days for a total duration of 1,690hours. The situation improved in FY2000 and FY2001 with load shedding restricted to 15-663MW on 251 days for a total duration of 948 hours. The situation will improve further in FY2002with (i) elimination of gas supply constraints to power stations, (ii) full commissioning of the

3 The Rural Power Company Ltd. has 68 percent of its shares held by the private sector rural electric cooperative

and 32 percent by the public sector REB. It was established in 1994 as part of the policy dialogue for ADBLoan 1356-BAN(SF): Rural Electrification Project for SDR34.4 million, approved on 30 May 1995.

4 Supported by ADB through TA 2338-BAN: Solicitation for Private Sector Implementation of the Meghnaghat PowerProject, for $211,000, approved on 30 May 1995 and enhanced to $595,000 in March 1998; and Investment Loan7165/1793-BAN: AES Meghnaghat Power Project, for $50 million loan; 31909-BAN $70 million partial riskguarantee and complementary financing scheme no. 39, for $20 million, all approved on 5 December 2000.

5 In 2001, the annual per capita consumption was 55 kWh in Nepal and 30 kWh in Cambodia. Comparable figuresfor some other developing member countries (DMCs) were 340 kWh for India, and 950 kWh for Thailand.

6 Comparable figures for some other DMCs are less than 10 percent for Cambodia, 18 percent for Nepal, 82 percentfor India, 48 percent for Pakistan, and 98 percent for Thailand.

7 TA 1962-BAN: Preparation of a Power System Master Plan, for $600,000, approved on 11 October 1993.Completed in early 1995.

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Haripur IPP station, (iii) part commissioning of the Meghnaghat-I IPP station, and (iv)reinforcement of the Dhaka 230 kV ring and completion of the Rampura 230 kV substation.Some load shedding is expected to continue until substantial new generation capacity is addedto the system to (i) replace very old power stations, (ii) allow for routine preventive maintenancethrough creation of reserve margin, and (iii) meet the additional demand from new connectionsand suppressed load growth. Erratic power supply has tended to increase the unwillingness ofconsumers to pay their bills, which in turn has led to shortages of funds for maintenance and hasfurther aggravated the situation.

9. After DESCO became operational in 1998, and distribution territory between DESA andthe PBSs was rationalized, the sector’s financial situation improved (Table 1).

Table 1: Performance of the Power Sector, FY1998 and FY2000

DistributionFY1998

ShareFY2000

Distribution Losses(% of imports)

RevenueCollections

(% of billings)GWH % GWH % FY1998 FY2000 FY1998 FY2000

BPDB 3,485 42 5,888 38 29.1 24.9 81 86DESA 3239 39 4,745 31 30.1 36.6 80 88PBSs 1,435 17 4,114 27 16.5 17.7 96 94DESCO 224a 3 628 4 46.7a 29.9 88a 80

Total 8,383 100 15,375 100a As the Mirpur Division of DESA prior to its restructuring.BPDB = Bangladesh Power Development, DESA = Dhaka Electric Supply Authority, DESCO = Dhaka ElectricSupply Company, Ltd., GWh = Gigawatt-hours, PBSs = rural electric cooperatives.

10. Bangladesh has limited hydropower potential because the terrain is flat. The Jamuna-Padma-Meghna river system, which runs north to south, divides the country into two. Thecountry's entire proven recoverable reserves of oil (including condensate) estimated at 59 millionbarrels, and natural gas estimated at 12 trillion cubic feet are on the eastern side of the riversystem. The limited hydropower potential is also in the eastern part of the country. The westernpart has no developed commercial sources of energy. Coal reserves, which are in thenorthwestern part, are deep beneath the surface and difficult to develop, and only one potentialmine with a limited output of about one million tons per annum is being developed with externalassistance. Consequently, of the country's total installed generation capacity of 4,035 MW, about494 MW fueled by diesel oil and heavy fuel oil and 171 MW fueled by natural gas, are in thewestern part. Of the 3,370 MW in the eastern part, 3,135 MW is based on natural gas, thecountry's primary commercial fuel, and 235 MW on hydropower. In terms of energy generated,about 90 percent of the total in FY2000 was from gas-fired power plants.

11. In FY2001, BPDB's average retail tariff for its ultimate consumers was Tk3.13/kWh($0.055/kWh), DESA's was Tk2.83/kWh ($0.050/kWh), DESCO’s was Tk2.95/kWh ($0.052/kWh)and PBS's Tk3.19/kWh ($0.054/kWh), leading to a weighted average tariff of Tk3.06/kWh,($0.054/kWh), compared with the estimated long-run marginal cost (LRMC) of supply ofTk3.86/kWh ($0.068/kWh). The LRMC is, however, declining due to (i) the lower costs ofproduction from the larger private sector IPPs, and (ii) declining losses. Retail tariffs are beingadjusted every six months to reflect increased costs of inputs by way of (i) the increased debt-service burden on the utilities in local currency, caused by the devaluation of the taka; and(ii) increase in the price of natural gas.

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B. Government Policies and Plans

12. The PSRB envisions in the long-term a structure of the power sector based on(i) separation of sector regulation and operation; (ii) autonomy and commercial orientation of thesector entities; (iii) separation of generation, transmission, and distribution; and (iv) increasedprivate sector participation. Under such a structure, a new regulatory authority would beresponsible for (i) setting electricity tariffs and determining the corresponding performancenorms; (ii) collecting, verifying and disseminating sector statistics; (iii) reviewing and approvinglong-term power planning; (iv) creating and maintaining a nondiscriminatory and commercialbusiness environment in the sector; and (v) adjudicating disputes between sector entities. Whiletransmission will remain in the public sector, generation and distribution assets will have bothpublic and private ownership. The objective is to eliminate monopolies and foster competition.Commercial discipline and good customer service are expected to be achieved throughcompetition among entities in the power sector.

13. With the initiation of reforms in 1994, the organizational setup of the sector has changed.Whereas in 1994, all generation was with BPDB, today there are several public/ private andprivate sector entities that have been licensed to construct and operate power-generatingfacilities. The first private barge-mounted power station started operations in December 1998.The RPC’s (footnote 3) first gas turbine at its Mymensingh site started operation in April 2000.Three barge-mounted power stations totaling about 310 MW are under operation, as is theopen-cycle stage of the Haripur (360 MW) IPP station. IPPs under construction includeMeghnaghat-1 (450 MW) (footnote 4) and the 100 MW expansion at Baghabari.

14. Good governance, at both the sector and the corporate levels is emphasized in the PSRB.At the sector level, governance is to be improved through predictability (long-term planning,codification of rules and regulations, and independence of regulatory processes), transparency(systematic dissemination of relevant sector information, public hearings, and discussions onissues before they are decided), and accountability (cause-effect structure of incentives). At thecorporate level, governance is being enhanced through corporatization, independence of theboards of directors from the Government, defined delegation of powers to staff, computerizedmanagement information systems, and commercialization of activities.

15. The Government realizes that the investment requirements for the power sector during1995–2005, estimated at about $6.6 billion, exceed the resources available in the public sectorand could crowd out investment in other key sectors. Therefore, the Government has made apolicy decision to invite the private sector to participate in developing the sector. The Governmenthas made substantial efforts to streamline administrative and commercial procedures and theprivate sector has responded positively in its participation in the power sector. To streamline thelegislative basis for the sector’s restructuring and regulation, and to allow the establishment of anindependent regulatory authority, the Government has drafted a new electricity reform act and hasintroduced it for consideration of the Parliament. ADB has granted Technical Assistance (TA)8 tohelp draft the regulations for the power sector that will be administered by the new regulatoryauthority. This will permit depoliticization of tariff setting and licensing, making the sector’soperations more transparent.

8 TA 3129-BAN: Support for an Energy Regulatory Authority, for $900,000, approved on 16 December 1998.

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16. The Government's other priority in the power sector is to improve the operations andfinancial positions of BPDB and DESA until their successor organizations develop, and therebyreduce its losses in the sector. Over the past five years, as part of its drive to improve the financialposition of the sector, the Government has been monitoring and encouraging these two utilities toimprove their technical operations, as well as their billing and collection procedures. Although thecommercial operations of both utilities have improved, they have not reached a level of financialviability and sustainability. The improvement process has been slow because of discontinuities insenior management, the politicization of labor unions, and the day-to-day political interference inoperations. Extensive discussions between the Government and the DPs have focused on theneed to (i) improve the operations of BPDB and DESA; (ii) increase the participation of moreefficient agencies, such as REB; and (iii) create new sector agencies that will be commerciallyoriented. Many of these steps have been implemented.

C. External Assistance to the Sector

17. Investment in the power sector during the last decade totaled $3.5 billion (Appendix 1).The major sources of funding have been ADB, the World Bank, France, Kreditanstalt fürWiederaufbau of Germany (KfW), Japan Bank for International Cooperation (JBIC), Departmentfor International Development of UK (DFID), United States Agency for InternationalDevelopment (USAID), Organization of Petroleum Exporting Countries (OPEC), People’sRepublic of China, and Russia. Other sources include the Islamic Development Bank, theKuwait Fund for Arab Economic Development, Saudi Fund for Development, CanadianInternational Development Agency, United Nations’ Development Programme, SwedishInternational Development Agency, Belgium, Danish International Development Agency, FinnishInternational Development Agency, and the private sector.

18. While ADB has assisted generation, transmission, and distribution in urban and semi-urban areas, JBIC has concentrated its assistance on generation and rural electrification projects.DFID has financed transmission and distribution in the Dhaka area. USAID has been instrumentalin establishing and funding REB and the first PBSs, and continues to provide technical support toREB and the PBSs. KfW (for the Government of Germany) has assisted in augmenting generatingcapacity, and in reinforcing transmission projects. Other aid agencies have also financedgeneration projects, although France and OPEC have financed some transmission anddistribution projects as well. The World Bank had earlier supported distribution in smaller townsand rural areas. However, after the reforms were initiated, it has not provided any assistance tothe sector other than TA for soliciting private participation in power generation and establishing thePower Cell which is mandated to plan and execute reform related activities and act as aquasi-regulator until the statutory regulator is appointed.

D. Lessons Learned

1. Contextual Issues

19. ADB has been extensively supporting the power sector over the last 25 years. From beinga provider of funds for individual projects in the 1970s, it became a provider of funds as well astechnical advice in the 1980s. Since the adoption of the PSRB in 1994, ADB has been providingpolicy advice to the Government in implementing the PSRB, as well as funds to help achieve theleast cost expansion program. During this involvement, ADB has learned the following lessons.

20. Overall Macroeconomic/Political Issues . Macroeconomic/political issues of the countryhave a significant bearing on the sector's performance as well as its ability to reform. Political

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unrest, labor militancy, law and order enforcement, speed and quality of the judicial processes,and ability of the education system to provide the staff required for efficiently operating the sector,all affect the sector's performance. However, there is very little that the sector by itself can do tosystematically redress these problems. Thus at any point in time, power sector development canonly proceed up to a point and no more. Forcing actions beyond this point without removing theconstraints becomes dysfunctional and even jeopardizes the reform process.

21. Sector Entities . Delegation of powers from the Government to the management of thesector entities and from the management to the staff is crucial for speedy and efficient decisionmaking. Due to efforts by ADB, delegation of power has been significantly improved, resulting inspeedier decisions on procurement by the newly established companies. BPDB and DESA arealso restricted by the Government's personnel and wage policies; therefore, recruiting andretaining of competent staff and retrenching or dismissing of excess or nonperforming staff areinhibited. The situation is being addressed and a beginning has been made by PGCB andDESCO. The above factors clearly underscore the limited extent of the improvements that canbe made to the existing power sector entities in their present form. It is therefore essential to (i)create new sector entities that are not subject to the organizational limitations of BPDB andDESA, and (ii) establish an overall environment of commercialization in the sector.

22. Gradualism . Fundamental changes in infrastructure sectors take time to implement evenin developed countries. In developing countries, change is more difficult to implement and,therefore, requires a gradual approach. Speeding up reforms is functional only if the change iscomprehensive. For example, increasing tariffs too rapidly may help the finances of the sector butoften undermines the objectives of the reforms by penalizing the good consumer if the utilitiescollect only from a low percentage of consumers. Affordability is also a factor. Rapid rises in tariffscan drive up the costs of electricity so that it becomes unaffordable to the poorer consumers,whereas more gradual increases could have allowed time for managing the effects of theincrease.

2. Compliance with Reforms Actions Under Earlier ADB Loans

23. The ADB-financed Eighth Power Project9 closed on 23 February 2001 and the RuralElectrification Project (footnote 3) on 29 January 2001. All structural reform-relatedconditionalities stipulated in these loans have been met. While several of the restructuringconditionalities stipulated under the ongoing Ninth Power Project10 and Dhaka Power SystemUpgrade Project11 have been fulfilled, some are still to be met as indicated below.

24. Handing over Transmission Assets to PGCB . BPDB and PGCB have jointly proposedthe physical and legal transfer of all transmission assets of BPDB to PGCB by September 2002.The Government approved this plan in May 2001. The agreement needs to be followed by thephysical handover of assets, transfer of related personnel, finalization of the associated financialtransactions, and establishment of PGCB's partial tariffs. Considerable progress has been madein this area. PGCB’s partial tariffs have been notified and approval for payment of terminationbenefits and transfer of BPDB personnel to PGCB were approved on 6 September 2001.Forty-five percent of BPDB’s transmission assets have already been transferred to PGCB.

9 Loan No. 963-BAN(SF): Eight Power Project, for SDR 132.677 million approved on 11 July 1989.10 Loan No. 1505-BAN(SF): Ninth Power Project for SDR 92.931 million approved on 18 December 1996.11 Loan No. 1730/1731-BAN: Dhaka Power Systems Upgrade Project, for SDR 54.319 million plus $82.0 million,

approved on 21 December 1999.

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25. Corporatizing Ashuganj Power Station . Ashuganj Power Company was incorporatedin June 2000, and its first board of directors constituted in September 2001. The board hasinitiated the process for recruiting the company’s first management.

26. Handing over DESA's Gulshan Circle Assets to DESCO . Physical handover is to becompleted by December 2002. Legal and financial aspects need to be settled by early 2002 toallow the transfer. DESCO also needs to establish its own billing and financial accounting centerby early 2002 to accept the transfer of customer records from DESA.

27. Liquidating the Government’s dues to BPDB, REB, and DESA . It is imperative forthe Government to lead in commercializing the sector by liquidating the arrears owed by it andits agencies to BPDB and DESA. In September 2001, the Government made a special budgetallocation of Tk690 million (about 30 percent of total dues) to settle outstanding dues to BPDBand DESA. This process will be expanded to include DESCO and PBSs also.

28. The fulfillment of conditions related to restructuring has been delayed in some cases byover a year. Nevertheless, the Government must be complimented in its determination to followthrough with these politically difficult and sensitive actions. Some actions have led to law andorder problems that the Government had to tackle firmly. Since the reform program started in1994, the Government has always delivered on the conditionalities it has agreed to as part of theprocess of power sector reforms. The Government has also, on its own, started the process ofrationalizing retail electricity tariffs for residential consumers of BPDB and DESA, as also the baseretail tariffs for the sector. This gives DPs confidence that the Government will take necessaryactions to determinedly pursue reforms in the future.

3. Performance of Executing Agencies

29. The political unrest in the country over the last few years has significantly affected thecollection operations of both BPDB and DESA since many commercial establishments, includingbanks, were closed for prolonged periods and those that were open functioned with minimalservices. DESA was particularly hard hit since Dhaka, as the capital city, was the center of theunrest, and normal life in the city was disrupted for longer periods than in other towns. DuringFY2000, the collection-to-generation ratio of BPDB and the collection-to-import ratio of DESAwere 65.9 percent and 65.1 percent, respectively. These were way below the targets, whichwere 75 percent for BPDB and 70 percent for DESA. In FY2001, however, with theimplementation of the ADB-funded Financial Management Upgrade Project,12 the collectionperformance of both utilities has gone up dramatically, resulting in a collection-generation ratioof 70.8 percent for BPDB. DESA’s performance remained stagnant on account of the deferredpayments instituted with the PBSs that had just taken over DESA’s loss-incurring rural areas inFY1999. The performance of the seven PBSs supported by ADB in the Rural ElectrificationProject (footnote 3) has been very good, with an average collection-to-import ratio of over 85percent. REB’s (PBSs’) overall collection-import performance slightly deteriorated to 77.4 percentin FY2001 on account of the bad areas taken over from DESA. However, the trends are in theright direction and these PBSs should contribute positively to the sector’s financial viability inFY2002. The operational performance of BPDB, DESA, REB and DESCO over the last eightyears since the start of reforms is summarized in Table 2.

12 TA 2004-BAN: Financial Management Upgrade of BPDB and DESA, for $1,000,000, approved on 26 November

1993.

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Table 2: Operational Performance of the Power Sector, FY1994–FY2001

Item 1994 1995 1996 1997 1998 1999 2000 2001

Generation, MkWhBPDB (gross) 9,784 10,806 11,475 11,858 12,870 14,450 15,563 17,021IPP 578 824 2,248Net 9,221 10,166 10,845 11,243 12,182 13,634 14,739 16,309Energy Import and Sales, (MkWh)Gross BPDB Sales 7,441 8,372 8,996 9,447 10,177 11,351 12,469 14,002Import by BPDB Zones 5,082 5,586 5,825 5,810 6,238 7,045 7,515 8,324Sales by BPDB Zones 3,745 4,209 4,445 4,485 4,757 5,405 5,965 6,762Import by DESA 3,696 4,162 4,551 4,962 5,419 5,947 6,504 7,240Sales by DESA 2,538 2,914 3,209 3,589 3,908 4,469 4,831 5,392Import by DESCO 344 550 628Sales by DESCO 205 369 440Import by REB 906 1,247 1,372 1,472 1,718 2,442 3,172 4,114Sales by REB 765 1,052 1,172 1,220 1,435 1,989 2,546 3,386System Loss (Percent)BPDBa 23.95 22.53 21.60 20.33 20.93 21.45 19.88 17.73BPDB Zonesb 26.32 24.65 23.69 22.81 23.73 23.29 20.63 18.76BPDB Zones (Net of sales to REB) 30.26 29.42 28.44 27.59 29.09 29.69 26.72 24.93DESAb 31.34 30.00 29.49 27.67 27.89 24.84 25.72 25.53DESA (Net of Sales to REB andDESCO)

32.77 31.71 31.30 29.55 30.13 29.89 34.56 36.55

DESCOb 40.51 32.86 29.86REBb 15.61 15.67 14.60 17.15 16.46 18.55 19.74 17.68Overall Power Systema 37.23 35.90 35.04 34.04 34.87 35.77 35.82 33.65Billing and Collection (Tk million)BPDB Bills 14,067 15,684 16,791 18,487 21,014 23,622 27,359 31,903BPDB Collection 11,551 14,142 15,577 16,264 17,018 16,698 22,515 27,436DESA Bills 5,962 6,530 7,082 8,648 9,862 10,768 11,423 13,015DESA Collection 4,742 5,841 5,998 7,084 7,929 8,200 10,007 11,403DESCO Bills 569 1,067 1,297DESCO Collection 337 836 1,042REB Bills 2,101 2,710 3,180 3,518 4,448 6,139 7,837 10,810REB Collection 2,079 2,594 3,124 3,348 4,253 5,763 7,596 10,164Collection (as percent of Billing)BPDB 82.11 90.17 92.77 87.98 80.98 70.69 82.29 86.00DESA 79.54 89.45 84.69 81.91 80.40 76.15 87.60 87.61DESCO 59.23 78.35 80.31REB 98.95 95.72 98.24 95.17 95.62 93.88 96.92 94.02Collection-generation/Collection-Import ratio (Percent)BPDB Collection-Generation 62.45 69.85 72.73 70.09 64.03 55.53 65.93 70.75DESA Collection-Import 54.61 62.61 59.72 59.25 57.98 57.24 65.07 65.25DESCO Collection-Import - - - - - 35.23 52.60 56.33REB Collection-Import 83.51 80.72 83.90 78.85 79.88 76.46 77.79 77.40

BPDB = Bangladesh Power Development Board, IPP = independent power producer, DESA = Dhaka Electric SupplyAuthority, DESCO = Dhaka Electric Power Supply Authority, REB = Rural Electrification Board, MW = megawatts.Notes: 1. For comparison of distribution loss of BPDB , DESA, DESCO and REB , use BPDB and DESA's

distribution losses net of interorganization sales.2. Since October 1999, DESA has started reflecting real loss figures in some zones , which has increased

DESA's system loss. Latest REB figures include loss encountered but were not reported by PBSs.3. IPP generation includes small units (3x10 MW) selling directly to REB.

a As percent of gross generationb As percent of Import

9

E. ADB’s Sector Strategy

30. ADB recognizes that (i) the substantial external assistance to the sector in the past hasinduced a tendency in the sector agencies to depend on external assistance for their funding; (ii)recovery and development must come from within the sector; and (iii) the Government and allmajor aid agencies must realign their individual strategies to emphasize the objective in (ii). Inconsultation with the Government and the other DPs involved in the sector, ADB has developedits strategy to improve the power sector in Bangladesh. The strategy consists of (i) changes in thebusiness environment through corporatization, commercialization, and increasing private sectorparticipation; (ii) institutional improvements in BPDB and DESA; (iii) creation of new sectoragencies that could serve as role models for the sector; (iv) enlarging the scope of the PBSs; and(v) strengthening the long-term planning and regulatory processes in the sector. The proposedProject addresses items (i), (iii), and (iv) of this strategy. Item (ii) is an ongoing process and item(v) has partially been addressed through the PSMP, the creation of the Power Cell, and ADB’s TASupport for an Energy Regulatory Authority (footnote 8).

F. Policy Dialogue

31. ADB, the World Bank, JBIC, DFID, USAID, and KfW, have all been involved in policydialogue with the Government about issues in the power sector, with ADB playing the role of DPcoordinator. ADB has played a major role in drawing up the reform assistance strategy of theDPs. In addition, it has organized coordination meetings for the power sector in 1992, 1994,1995, and 1996, and for the power and natural gas sectors in 1997, 1998, 1999, and 2001.ADB-led aid coordination meetings in December 1992, December 1994, and September 1995contributed to the formulation of reforms and identification of reforms-linked projects in the sector.ADB also provided TAs to review electricity legislation,13 prepare a power system master plan(footnote 7), upgrade the financial management of BPDB and DESA (footnote 12), seek privatesector implementation of the Meghnaghat Project (footnote 4), and corporatize the AshuganjPower Station of BPDB.14 ADB has been instrumental in assisting the Government to draw up aplan for the planned transformation of the sector, as well as creation of new sector entities.

32. The medium-term goals of the policy dialogue with the Government up to 2005 and theresults achieved so far are summarized in Appendix 2. Generation is no longer a monopoly andhas sufficient private sector interest, and the public sector stations are starting to becorporatized and commercialized. A start has been made segregating the transmission functionand corporatizing it. Distribution is being corporatized in the Dhaka area, and the private sectorPBSs have increased their share of sales from 13 percent in FY1993 to 27 percent in FY2001and will increase this to over 30 percent by FY2005. Average retail power tariffs were increasedby about 15 percent (in September and December 1996) and an interim formula for semiannualadjustment of retail power tariffs to take into account fluctuations in fuel costs and foreignexchange rates has been successfully implemented.15 On the regulatory side, work hasprogressed through the creation of the Power Cell. Preparatory studies on new legislation,sector structure, and tariff framework have been completed. The Electricity Reform Bill 2001,16

which will form the legal basis for power sector reform, is being reviewed by parliament.

13 TA 1743-BAN: Review of Electricity Legislation and Regulations, for $90,000, approved on 18 August 1992.14 TA 3343-BAN: Corporatization of Ashuganj Power Station, for $1,000,000, approved on 17 December 1999.15 Agreed upon as part of the policy dialogue under ADB’s Loan 1505-BAN (SF): Ninth Power Project.16 Supported by ADB under TA 1743-BAN (footnote 10) as well as by a World Bank TA.

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G. Aid Coordination

33. Aid coordination in the sector has been intensive since the start of the reform process.The DPs hold a formal coordination meeting every year where sector policies and achievementsare reviewed by headquarters staff, and over the last year have introduced quarterly meetingsat the Resident Mission level to monitor progress. Informal views are also exchanged betweenADB missions that visit Dhaka and the resident missions/ offices of other DPs wheneverpossible. Regular visits by senior ADB staff to Washington, and World Bank staff to Manila havealso ensured that there is full exchange of views between the World Bank and ADB. Aide-memoires of ADB missions are shared with all DPs, and points of specific concern to any DPare discussed by email and telephone.

34. As is to be expected in such a complex sector, there are differences in views andperceptions among some of the DPs. However, these differences are not on the fundamentalsof the reform strategy being adopted, but on the pace and timing of specific reform actions,especially those related to (i) privatization of distribution; (ii) transfer of assets between BPDBand DESA and their successor entities; and (iii) rationalization of tariffs.

35. The Project has been extensively discussed between ADB and the other DPs and issupported by JBIC, KfW, Nordic Development Fund (NDF), and DFID. JBIC is seeking tocomplement the Project through a new loan that will strengthen and intensify rural electrificationin four PBSs, including one in the Khulna area. KfW and NDF are parallel cofinancing theProject. KfW has also been in constant dialogue with the Government in support of theliquidation of the Government's dues to BPDB and DESA. DFID is actively considering supportfor the West Zone Electricity Distribution Company that is being established as a successor toBPDB’s distribution operations in the west zone.

IV. THE PROPOSED PROJECT

A. Rationale

36. Poverty reduction is ADB’s overarching goal. Poverty reduction requires expansion inthe economy, increase in productivity, as well as equitable distribution of the gains of economicexpansion and increased productivity to the entire population. The power sector contributes tothis objective by (i) being an essential ingredient for increasing economic growth; and (ii)improving the quality of life of consumers, taking advantage of the information technologyrevolution and employment opportunities created, especially in the rural areas. In theBangladesh context, where only about 20 percent of the population has access to electricity,this means that the electrification program in the smaller towns and villages should beaccelerated to increase the population's access to electricity. However, increasing ruralconnections is not feasible until the entire supply chain comprising the generation andtransmission facilities is augmented. The Project, therefore, aims to facilitate generation throughthe private sector by establishing transmission and distribution lines to help evacuate and utilizethe power, at the same time, providing electricity to the district towns and villages in southwestBangladesh, a relatively poor area of the country.

37. The Project continues the long-term strategy of the Government and ADB for powersector reforms, which are presented in Appendix 2. The rationale for the choice of the Projectcomponents is given below.

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1. Generation

38. Potential has been created for the private sector to add 1,400 MW of capacity over thenext five years. This is 35 percent of the current installed capacity of 4,028 MW and 50 percentof the currently available capacity of about 2,800 MW. There is a need to slow down and takestock of the situation before further capacity is committed in the private sector. The Governmenthas guaranteed conversion of foreign exchange under the several implementation agreementsthat were signed or committed to be signed with private sector IPPs, and the amount underguarantee represents a significant portion of its total foreign exchange reserves. A “shelf” ofprojects for speedy implementation already exists. The expansion stages of the Meghnaghatproject offer the least-cost alternatives, since their infrastructure will already have beendeveloped during the first stage. Sites are being identified for 200 MW of peaking capacity in theDhaka area, and these sites could be prepared for future expansion through advance actions forenvironmental approvals, permits/licenses, and draft operating agreements. The total capacityof these projects would be adequate to fulfill the requirements of the east zone in the next fiveyears. In the west zone, the development of the Bheramara/Serajganj sites is being consideredalong the lines of development of the Meghnaghat site. ADB has already allocated funds underits Ninth Power Project for comprehensive studies and development of two peaking powerplants in the east zone and for a major site for base load generation in the west zone. Hence,there is no priority public sector investment requiring ADB support in this subsector.

2. Transmission

39. In the transmission area, priority investments include (i) the National Load DispatchCenter; (ii) the strengthening of the primary transmission system in the west zone; (iii)completion of the 230 kilovolt (kV) double-circuit ring around Dhaka; and (iv) the second east-west interconnector between Ashuganj and Serajganj, utilizing the Bangabandhu Bridge overthe Jamuna River.

40. With the ADB assistance to PGCB under the Ninth Power Project and the Dhaka PowerSystem Upgrade Project, funding for the 230 kV double circuit ring system around Dhaka hasbeen secured. The World Bank and JBIC have indicated their possible support for financing theNational Load Dispatch Center. Components for strengthening the west zone network and thesecond east-west interconnector are the only remaining works of priority since these areessential for delivering adequate quantities of secure power to the west zone and also forevacuation and economic utilization of power from all the BOO/build-operate-transfer (BOT)projects proposed to be contracted at Serajganj and Bheramara. Hence, these componentshave been identified for support by ADB, KfW, and NDF.

3. Distribution

41. Given the extensive participation of the private sector in generation projects, the financialviability of the power sector would be in jeopardy unless the distribution subsector isstrengthened to ensure offtake of power as well as generate adequate revenues for servicingthe investments in the generation and transmission subsectors. Otherwise, the Government’sguarantees to the IPPs could be called, placing an unacceptable burden on its budgets.Through its earlier operations, ADB has consolidated the reforms in the distribution subsector inthe Dhaka area. It would be prudent to wait for improvements to occur and the reforms toproduce the anticipated results before deciding on another round of assistance. Therefore, theonly priority would be to assist other major towns to restructure and upgrade their distributionnetworks. Given that the southwest is one of the poorer regions in Bangladesh, and upgrading

12

of infrastructure is urgently needed to stimulate economic growth for poverty reduction, it wouldbe appropriate if ADB’s next assistance support both urban and rural distribution in this region.This will also provide the opportunity for commencing the corporatization of BPDB's distribution,and rationalizing the boundaries between BPDB and REB in the area, leading to lower lossesand higher collections, and improving the self-sustainability of the sector.

42. In the Dhaka area, results of the Financial Management Upgrade Project (FMU)17

funded by ADB, combined with the Pilot Scheme for Loss Reduction supported by JBIC, havebeen encouraging. Such reduction in losses, if effected on a large scale, would considerablyease the financial pressure on the sector. Hence upgrading of distribution in the areas outsideDhaka and extension of FMU to them, is an ADB priority in the next phase of sector reforms.

4. Institutional Strengthening

43. The Bangladesh power sector will have to rapidly expand if the current low access rateof electricity is to speedily improve. Expansion will place a major burden on the humanresources of all agencies in the sector. The present structures of BPDB and DESA are notconducive to rapid decision making and commercial accountability. It is therefore proposed thatas part of the new operation, (i) the west distribution operations of BPDB be corporatized; and(ii) the remainder of DESA, which will service the southern part of metropolitan Dhaka after thehanding over of assets to DESCO, be corporatized. While the corporatization of DESA will beaddressed through ADB's proposed TA being considered separately, the corporatization ofBPDB's distribution in the west zone will be supported through TA and a loan component.18

44. Based on the above analysis, it is appropriate for ADB to support (i) completion of the230 kV "backbone" transmission system in the west zone and the second east-westinterconnector, (ii) upgrading of urban and rural distribution in the southwest; and (iii)corporatization of BPDB's southwest distribution.

B. Objectives and Scope

45. The objectives of the Project are to (i) increase electrification in southwest Bangladesh;(ii) enable evacuation and economic utilization of the power generated from the projects beingcontracted at Baghabari and Bheramara; and (iii) reduce losses, improve reliability, and expandthe capacity of the transmission and distribution systems in southwest Bangladesh. The logicalframework for the Project is at Appendix 3.

46. The Project comprises the following:

1. Constructing 230kV Transmission Lines and Substations (Part A)

(i) Ishurdi-Baghabari 230 kV double circuit transmission line (55 kilometers [km])19

(ii) Baghabari-Bogra (via Serajganj) 230 kV double-circuit transmission line(110 km)20

(iii) Ishurdi-Bheramara-Khulna 230 kV double-circuit transmission line (160 km)

17 Supported by ADB through TA 2004-BAN (footnote 9) and Loan 963-BAN (SF): Eighth Power Project for

$1.0 million each.18 DFID has indicated that it may be interested in funding a "twinning" arrangement with a reputed electric

power utility. DFID’s final decision will be known only in January 2002.19 Being considered under supplier’s credit.20 Being considered for financing by KfW.

13

(iv) Ashuganj-Jamuna-Bangabandhu Bridge-Serajganj 230 kV double circuittransmission line (162 km)

(v) Khulna (new) substation to Khulna 132 kV Central (old) substation – 132 kVdouble-circuit transmission line (7 km)

(vi) New 230 kV substations at Bogra (4 bays and 7X75 MVA 230/132 kVtransformers),21 and Khulna (4 bays and 7X75 MVA 230/132 kV transformers)22

(vii) New 230 kV switching station at Serajganj(viii) Extension of existing 230 kV substations at Ashuganj (2 bays), and Ishurdi

(2 bays).(ix) Extension of 132 kV substations at Bogra (2 bays), and Khulna Central (2 bays)(x) Purchase of equipment for operations including vehicles(xi) Consulting services for engineering and quality assurance(xii) Training

2. Distribution Upgrading in Major Towns (Part B)

(i) Upgrading of distribution in Khulna, Barisal, Kushtia, Jessore, and Faridpur towns(ii) Consulting services for engineering of distribution in these towns, preparation of

specifications, quality assurance, and inspection(iii) Extension of FMU program to cover all of east and west zones of BPDB(iv) Purchase of vehicles, operation and maintenance equipment, and office facilities.(v) Training

3. Distribution Upgrading in 8 PBSs (Part C)

(i) Upgrading and expanding distribution in Jessore-1, Jessore-2, Barisal-1, Barisal-2, Bagherhat, Faridpur, Kushtia, and Meherpur PBSs

(ii) Construction of 33 kV reinforcements in the southwest region(iii) Computerization and training of personnel, especially in these 8 PBSs and REB

C. Technical Justification

47. The Project is part of the least cost expansion plan for the power sector. In addition tothe evacuation of power from the current and planned generation capacity in the west zone, theProject will also add to the transfer capacity between the east and west zones thus optimizingthe generation resources in both regions. This will reduce the cost of power supply in the WestZone and will lead to better stability and reliability of the power system as a whole. Thedistribution components in reducing losses, improving the quality of supply, and in supplyingelectricity to over 500,000 additional consumers, a significant portion of whom live in the ruralareas. Computerization will result in significant improvements in billing and collections and willalso improve customer satisfaction.

D. Cost Estimates

48. The total cost of the Project is estimated $402.1 million equivalent, including foreignexchange cost of $259.0 million (64.4 percent) and local currency costs of $143.1 million(35.6 percent) A detailed breakdown of the Project's scope along with cost estimates is inAppendix 4. A summary is given in Table 3.

21 Being considered for financing by KfW.22 Being considered for financing by Nordic Development Fund.

14

Table 3: Summary Cost Estimates($ million)

Component Foreign Exchange Local Currency TotalPart A 140.5 28.8 169.3Part B 39.6 10.5 50.1Part C 36.0 5.6 41.6

Subtotal 216.1 44.9 261.0Taxes and Duties - 64.9 64.9

Subtotal Base Cost 216.1 109.8 325.9Contingencies Physical Price

10.816.0

5.511.1

16.327.1

Interest DuringConstruction

14.7 16.7 31.4

Front-end fee 1.4 - 1.4Total Cost 259.0 143.1 402.1

E. Financing Plan

49. The financing plan is summarized in Table 4. ADB and the other cofinancing agencieswill be financing only foreign exchange costs associated with the Project. The Government andthe sector agencies will finance all local currency costs.

Table 4: Summary Financing Plan a

($ million)Agency Foreign Exchange Local Currency Total Percentage

(%)ADB 198.9 0.0 198.9 49.5Cofinancing KfW 30.0 0.0 30.0 7.5 NDF 10.0 0.0 10.0 2.5Suppliers’ Credit 20.1 0.0 20.1 5.0Government, EAs 0.0 143.1 143.1 35.5

Total 259.0 143.1 402.1 100.0 ADB = Asian Development Bank, EA = executing agency, KfW = Kreditanstalt für Wideraufbau of Germany,NDF = Nordic Development Fund

a The financing plan may change after Department for International Development of UK finally decides on its participation in the Project.

50. It is proposed that ADB extend two loans to the People's Republic of Bangladesh insupport of this Project. The first loan will be for Special Drawing Rights (SDR) 47.581 million($60.2 million equivalent) from ADB's special funds resources and will fund parts B (iii)through(v), and C of the Project. The loan will have a repayment period of 32 years including agrace period of 8 years and an interest charge of 1.0 percent during the grace period and 1.5percent thereafter. The borrower will be the People’s Republic of Bangladesh and the proceedswill be re-lent to BPDB (and later transferred to its successor companies) and REB pursuant tosubsidiary loan agreements with terms and conditions acceptable to ADB. Relending terms toBPDB will include a repayment period of 20 years including a 5 year grace period, and interestat the rate of 5.5 percent per annum. The foreign exchange risk will be assumed by BPDBduring the life of the subsidiary loan, and by the borrower thereafter. For REB, the relendingterms will include an interest rate of 2 percent per annum, repayment over 30 years including a

15

grace period of 8 years during which the interest will be 0.75 percent per annum. The borrowerwill bear the foreign exchange risk.

51. The second loan23 will be for $138.7 million from ADB's ordinary capital resources (OCR)and will fund parts A, B (i), and B (ii) of the Project. The loan will have a 20-year term, includinga grace period of 5 years, an interest rate determined in accordance with ADB’s LIBOR-basedvariable lending facility, a commitment charge of 0.75 percent per annum, a front-end fee of 1.0percent (the front-end fee will be capitalized in the loan), conversion options that may beexercised in accordance with the terms of the draft Loan Agreement, the Loan Regulations,ADB’s Conversion Guidelines, and such other terms and conditions set forth in the draft LoanAgreement. The Government has provided ADB with (i) the reasons for the Government’sdecision to borrow under ADB’s LIBOR-based lending facility on the basis of these terms andconditions, and (ii) an undertaking that these choices were the Government’s own independentdecision and not made in reliance on any communication or advice by ADB. The borrower willbe the People’s Republic of Bangladesh. The loan proceeds will be re-lent to PGCB and BPDB(and later transferred to the new company) pursuant to subsidiary loan agreements with termsand conditions acceptable to ADB. Relending terms to PGCB and BPDB will include arepayment period of 20 years including a 5-year grace period, and interest at the rate of 5.5percent per annum. Foreign exchange risk will be assumed by PGCB and BPDB during the lifeof the respective subsidiary loan, and thereafter by the borrower.

52. While KfW and NDF have confirmed their participation in the Project, DFID hasexpressed interest in considering participation in part B and will be in a position to confirm suchparticipation only by January 2002. This may result in changes in scope and implementingarrangements as well as a reduction in ADB’s OCR loan. For the first time, ADB has alsoencouraged PGCB to obtain commercial cofinancing (suppliers’ credit) through internationalcompetitive bidding for $20.1 equivalent for the Ishurdi-Baghabari transmission line.

F. Implementation Arrangements

1. Implementation Schedule and Performance Review

53. The implementation schedule of the Project is in Appendix 5. Implementation will beginin November 2001 and be completed in March 2006. Direct supervision of subprojectimplementation and monitoring of subproject operation performance will be the responsibility ofthe Executing Agencies (EAs) and the Government. These agencies will provide quarterlyprogress reports to ADB covering their respective responsibilities within 30 days from the end ofeach quarter. ADB will review the implementation and operation of the Project based on thesereports and meet with the EAs and the Government semi-annually to discuss project progress.ADB will also monitor the overall performance of the EAs.

2. Procurement

54. Goods and services financed by ADB will be procured following ADB's Guidelines forProcurement. For such procurement, bid specifications will be prepared so as to ensure maximumcompetition under international competitive bidding. A list of the major contract packages underthe Project with their cost estimates is given in Appendix 6.

23 Refer to note under Table 4 and para. 52. Reduction in ADB financing as a result of bilateral cofinancing will affect

mainly parts B (i) and (ii) of the Project and hence the OCR loan.

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3. Consulting Services

55. Consultants will support PGCB, BPDB, and REB for their respective parts of the Projectand will be recruited in accordance with ADB's Guidelines on the Use of Consultants. Consultantswill essentially provide design review, quality assurance services and training.24

4. Advance Procurement Action

56. All the EAs have sufficient expertise in procuring materials for the works entrusted to themunder the Project and were allowed to initiate advance procurement action for the goods andservices to be financed by ADB. The Government has been advised that ADB's approval of suchadvance procurement action will not in any way commit it to subsequently approve the Project.Retroactive financing has not been permitted.

5. Disbursement Procedures

57. Since the disbursements under the Project will be mainly for supply of goods andconsulting services, ADB's commitment letter and direct payment procedures will be used forthe purpose.

6. Reports, Accounts, and Audits

58. The EAs will prepare separate progress reports for their respective components andsubmit them to ADB on a quarterly basis. The reports will provide a narrative description ofprogress made during the period, changes in the implementation schedule, problems or difficultiesencountered, the performance of the project implementation consultants, and the work to becarried out in the next period. The progress reports will also include a summary financial accountfor the Project, consisting of project expenditures during the period year to date, and totalexpenditure to date. ADB will review the implementation and operation of the Project based onthese reports and meet with the EAs and the Government semiannually to discuss projectprogress. Project completion reports will be submitted to ADB within three months of projectcompletion.

59. The EAs will have their annual financial statements and project accounts audited by aprofessional auditing firm acceptable to ADB. Unaudited statements will be submitted to ADBwithin six months of the close of the financial year and audited statements within three monthsthereafter.

G. Executing Agencies

60. Part A will be executed by PGCB. BPDB will transfer the Ishurdi 230 kV substation, theKhulna Central 132 kV substation, and the associated 230 kV and 132 kV transmission lines toPGCB before PGCB executes Part A. Part B will be executed by BPDB initially and by itscorporatized subsidiary ultimately. REB will implement Part C of the Project.

24 DFID stated that it may enlarge the scope of consulting services under part B (ii) and training under B (v) to provide a

comprehensive organization development intervention, spanning 3-5 years. If realized, this intervention by DFID willbe a major step for power sector reforms in Bangladesh. Selection of consultants will then follow DFID guidelines.

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1. The Power Grid Company of Bangladesh (PGCB)

a. Responsibilities

61. PGCB is a limited-liability company registered under the Companies’ Act, 1994. TheMemorandum of Association of PGCB gives it a wide-ranging mandate to be involved in amultitude of activities, not only in electricity but in any infrastructure project, both in Bangladeshand abroad. However, PGCB’s primary role is to act as the owner and operator of the country’stransmission network and the National Load Dispatch Center.

b. Organization Structure

62. PGCB is governed by a part-time board of directors elected by its shareholders, who inturn appoint a full-time managing director and two functional directors. The chairperson of BPDBis the chairperson of the board of directors of PGCB as long as BPDB holds shares in PGCB.PGCB has recruited about 550 staff from BPDB in September 2001 as well as received over1,200 km of 230 kV and 132 kV transmission lines and four major 230 kV substations. It alreadyhas an established project management team that is conversant with ADB’s guidelines, withexperience drawn from implementing the ADB-funded Ninth Power and Dhaka Power SystemUpgrade Projects.

c. Financial Performance

63. The financial performance of PGCB depends on the rate of transfer of assets fromBPDB to PGCB. Since the tariff structure applicable to PGCB is based on the net fixed assets inoperation, and takes into account a post-tax return of 15 percent per annum, the financialsituation of PGCB should be fairly robust provided it collects its dues on time. To alleviateconcerns in this regard, the Government has already issued two notifications for transmissiontariffs in 1998 and 2001, taking into account the assets held by PGCB at each time. PGCBaccounts receivable from BPDB, REB, and DESA have been brought down to the equivalent oftwo months billing and steps are being taken to maintain this level. A summary of the financialprojections and indicators for PGCB is in Table 5. The financial projections and the criticalassumptions used in developing the financial projections are in Appendix 7.

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Table 5: Summary of PGCB's Projected Financial Performance,FY 2000-2007

(Tk million)

Item 2000 2001 2002 2003 2004 2005 2006 2007

Total Revenue 172.6 575.8 994.2 1,650.4 2,549.2 4,020.7 5,667.2 7,389.9

Net Profit 23.8 84.7 317.1 579.3 654.9 706.6 1,218.0 1,897.2

Total Assets 3,489.6 6,954.4 19,576.8 30,971.8 43,193.0 55,469.2 64,855.1 70,658.6

Current Liabilities 522.7 263.9 562.0 1,043.6 1,387.9 2,749.1 4,344.7 6,344.9

Long-Term Liabilities 1,818.3 4,347.6 11,683.1 19,749.2 28,560,6 36,909.2 41,885.4 43,245.3

Equity 1,148.5 2,342.9 7,331.7 10,179.0 13,244.5 15,810.8 18,625.0 21,068.3

Rate of Return on Net

Fixed Assets (%)

22.9 2.59 5.3 6.5 4.7 3.5 3.9 4.8

Operating Margin (%) 62.2 63.5 58.5 55.9 53.1 61.7 63.7 66.3

Rate of Return on

Average Equity (%)

2.1 4.9 6.5 6.6 5.6 4.9 7.1 9.6

Current Ratio 1.1 5.4 12.4 5.4 4.6 2.7 1.9 1.35

Long-term

Debt-to-Equity Ratio

1.6:1 1.9:1 1.6:1 1.9:1 2.2:1 2.3:1 2.3:1 2.1:1

Debt-Service Coverage

Ratio (times)

0.8 neg. 1.4 0.7 0.9 0.9 0.9 0.9

neg. = negative, PGCB = Power Grid Company of Bangladesh, Ltd.

64. The financial projection for PGCB is based on the principles discussed in para. 63,transfer of transmission grid from BPDB, and investments derived from this Project. Theprojection indicates a sound financial performance over the term of the loan. The debt-to-debtplus equity ratio is well above 30 percent during the entire projected period, and the cash flowsare reasonably sufficient to meet all operating costs and debt and equity service requirements.

2. New Company for West Zone Distribution

a. Responsibilities

65. The new company will be a limited-liability company registered under the Companies’Act, 1994. It’s memorandum of association will give it a wide-ranging mandate to be involved ina multitude of activities, not only in electricity but in any infrastructure project, both inBangladesh and abroad. However, the company’s primary responsibility will be to distributeelectricity in the metropolitan areas of Khulna, Barisal, Kushtia, Jessore, and Faridpur, and othermajor towns in the west zone.

b. Organization Structure

66. The new company will be governed by a part-time board of directors elected by itsshareholders, who in turn will appoint a full-time managing director and two functional directors

19

(finance director and technical director). The chairperson of BPDB will be the chairperson of theboard of directors of the company as long as BPDB holds a majority interest. For theconstruction and supervision of part B of the Project, the new company is expected to recruitabout 20 engineers and about 100 other technical and nontechnical support staff. This will be inaddition to the 10 or 20 professional and support staff at the corporate office in Khulna to handleprocurement, and financial and administrative matters. While most of the staff will be recruitedfrom BPDB, DESA, and REB on a selection basis, some will be recruited from the open market.Operation and maintenance (O&M) staff will be transferred from BPDB’s staff in the distributionsubsector.

c. Financial Performance

67. The financial projections for the new distribution company are summarized in Table 6and detailed in Appendix 7. These projections are based on a phased transfer of assets fromBPDB to the new company over five years ending in FY2007. This transfer process could beaccelerated if DFID decides to provide assistance to the company for comprehensiveorganization development. The analysis also assumes that the new company starts off with aclean balance sheet and BPDB’s assets will be gradually transferred to it in parallel with the newexpansion investments under the Project. It is expected that system losses will be reduced fromthe current level of 26 percent to about 18 percent by FY2008, further increasing the profitabilityof the company.

Table 6: Summary of the New West Zone Company’s Projected Financial Performance,FY2001-FY2008

(Tk million)Item 2001 2002 2003 2004 2005 2006 2007 2008

No. of Customers 147,246 154,608 160,793 165,616 190,459 247,597 321,875 418,438

Sales (MWh) 823,850 827,527 907,522 977,432 1,044,328 1,247,994 1,651,625 2,185,875

Total Revenue 2,495.1 2,613.7 2,997.7 3,376.4 3,754.4 4,659.6 6,431.1 8,882.5

Net Profit (35.6) (6.2) (6.0) 45.2 185.4 283.8 330.1 700.0

Total Assets 2,879.0 2,990.5 4,212.1 5,572.3 6,803.6 7,867.0 8,558.9 9,612.0

Current Liabilities 750.2 583.8 680.2 759.3 865.1 1,261.3 1,835.1 2,400.6

Long-Term Liabilities 602.5 803.0 1,622.6 2,526.5 3,209.5 3,459.1 3,247.1 3,035.1

Equity 1,526.3 1,603.8 1,909.3 2,286.5 2,728.9 3,146.6 3,476.7 4,176.3

Operating Margin (%) (0.3) 0.2 0.4 2.9 8.6 10.0 12.1 15.5

Rate of Return on Total

Assets (%)

0.1 1.0 0.7 1.5 3.4 4.1% 6.1 9.4

Rate of Return on Average

Equity (%)

(4.7) (0.4) (0.3) 2.2 7.4 9.7 10.0 18.3

Current Ratio 0.9 0.8 0.7 0.6 0.8 1.1 1.1 1.4

Equity Ratio (%) 53.0 53.6 45.3 41.3 40.1 40.0 40.6 43.5

Debt-Service Coverage

Ratio (times)

(27.0) (4.5) (0.9) 10.2 10.5 33.2 2.9 3.8

MWh = megawatt-hours.

20

68. The financial projection for the new company is based on the handover of 147,000customers and a load of 824 gigawatt-hours (GWh) in five cities from BPDB, as well as theeffects of the investments derived from the Project. With the net value of the transferred assetsbeing financed as loans and equity in the ratio of 70:30, the expected improvements in losses,and the major increase in number of customer and load, the projections indicate a robustperformance. The expected increase in number of customers and energy sales during theproject implementation period are 271,000 customers and 1,362 GWh, (an increase of284 percent and 339 percent, respectively). The operating margin gradually increases from 0 toroughly 15 percent over seven years along with the decrease in losses and increased load. Thereturn on total assets also improves from 0 to 9 percent based on the same factors and thedeclining new investments later in the period. The financing of the transferred assets gives thecompany a very solid foundation, which is indicated by an equity ratio of around 40 percent.This solid foundation will give good opportunities for external financing of future expansions as aself-sustainable and independent company.

3. Rural Electrification Board/Palli Bidyut Samities

a. Responsibilities

69. REB is an infrastructure development agency of the Government. It was created as anautonomous entity under a presidential ordinance in 1977, to implement the electrificationprogram through consumer cooperatives, the PBSs. The creation of this autonomous body wasone of the recommendations of the consulting firms that conducted feasibility studies for theGovernment’s Rural Electrification Program in 1977, which was financed by USAID.

70. As stated in its charter, the major functions of REB are to (i) establish electricitygeneration, transmission, and distribution systems in the rural areas of Bangladesh; (ii) organizeprospective consumers of electricity into formal and informal groups such as societies andcompanies; (iii) formulate by-laws for the PBSs and other groups registered with REB, anddetermine the methods of their operations; (iv) advance funds for implementing approvedschemes, operating and managing works and services, and constructing lines for electricconnections for members; (v) hand over to the PBSs the completed projects for O&M andmanagement; (vi) train personnel in the management and operation of REB and PBSs; and (vii)develop standards for work, equipment, O&M, procurement and warehousing, personnel andfiscal administration, and other aspects of management to be followed by REB as well as by thePBSs and other groups registered with REB.

71. Currently, 67 PBSs serve about 1.5 million consumers and distribute about 26 percent ofthe electricity consumed in the country. The responsibilities of a PBS begins when a distributionscheme is handed over to it for O&M after construction and commissioning. Its principalobjective is to supply its members and other consumers with electricity. Its functions include (i)distributing electricity and providing consumer connections; (ii) meter reading, billing, andcollection; (iii) purchasing electricity from BPDB and DESA; and (iv) planning and implementingthe expansion of local distribution systems with REB’s financial and technical assistance toconsumers for wiring their premises, acquiring and installing electrical appliances, andimproving their power factors through the installation of capacitors.

b. Organizational Structure

72. REB is managed by a board consisting of a chairperson and four full-time boardmembers (finance, engineering, administration, and PBSs and training). To coordinate the rural

21

electrification program in their respective fields, four part-time board members, one each fromBPDB, Bangladesh Agricultural Development Corporation, Bangladesh Small and CottageIndustries Corporation, and Bangladesh Rural Development Board serve on the board.

73. Each PBS is a member-owned autonomous cooperative, distributing electricity in itsservice area. The initial board of directors of a PBS is selected from local citizens, subject to theapproval of REB’s board of directors. After their appointment, the directors register the PBS withREB, which then proceeds to encourage potential consumers to become members of the PBS.The PBS board consists of 10-15 members elected in an annual members’ meeting. Personsare to become or remain a director if they are bona fide members of a PBS and residents of itsservice area. Any person or organization in a PBSs area may become a member of the PBSfollowing acceptance by the board and payment of a membership application fee of Tk10. Theboard elects a president who functions as its chief representative officer.

c. Financial Performance

74. The ultimate owners and operator of the REB-implemented component of the Project willbe the eight PBSs which are receiving assistance from the Project: Jessore-1, Jessore-2,Barisal-1, Barisal-2, Kushtia, Bagherhat, Faridpur and Meherpur. In order to assess the financialposition and performance for part C, the financial statements for the eight PBSs wereconsolidated and projections based on the consolidated position. A summary of the financialprojection and indicators for the eight involved PBSs are presented in Table 7. The detailedprojected financial statements and major assumptions used for the financial projections are inAppendix 7.

Table 7: Summary of the Consolidated 8 PBS’s Projected Financial Performance,FY2001-FY2008

(Tk million)Item 2001 2002 2003 2004 2005 2006 2007 2008

No. of Customers 391,276 410,840 427,273 440,092 484,101 629,331 818,130 981,756

Sales (MWh) 256,064 282,311 305,347 323,943 367,027 486,678 645,335 782,146

Total Revenue 894.6 1,026.5 1,156.8 1,279.7 1,509.0 2,075.1 2,858.8 3,609.6

Net Profit (111.9) (146.8) (132.5) (97.7) (57.3) (96.6) 7.4 168.9

Total Assets 5,244.5 5,460.6 6,576.8 7,801.7 8,704.8 9,247.8 9,224.8 9,382.9

Current Liabilities 759.1 805.6 823.1 829.1 865.3 1,025.3 1,092.7 1,179.7

Long-Term Liabilities 4,344.3 4,561.1 5,472.8 6,452.9 7,138.9 7,489.4 7,391,7 7,293.9

Equity 14.8 (32.3) 154.6 393.4 574.3 606.7 614.0 782.9

Operating Margin (%) (1.8) (5.0) (3.3) (0.2) 2.5 (0.1) 4.7 8.3

Rate of Return on Total

Assets (%)

(0.4) (1.1) (0.7) (0.2) 0.3 (0.2) 1.2 2.9

Rate of Return on Average

Equity (%)

neg. neg. neg. neg. neg. neg. 1.2 24.2

Current Ratio 0.5 0.4 0.5 0.6 0.7 0.8 0.8 0.9

Equity Ratio (%) 0.3 (0.6) 2.4 5.0 6.6 6.6 6.7 8.3

Debt Service Coverage

Ratio (times)

0.7 0.7 0.5 0.6 0.8 1.0 1.3 1.9

MWh = megawatt-hours, neg. = negative.

22

75. The PBSs have the authority to set retail tariffs except agriculture tariffs, which areestablished by the Government. PBS tariffs tend to be sufficient to cover all operating costs,debt-service obligations with the expected increased energy load, an adequate return on equitycan be expected in the long run. The earnings of the PBSs are nontaxable and the PBSs do notbear foreign exchange risks. Surplus cash and reserves are invested in expansion and technicalimprovement projects. In general, the PBSs already perform better than BPDB. Their systemlosses, on the average, are about 18 percent, which will decrease to about 15 percent byFY2007. Considering the investments financed by the Project, the expected increase incustomers (590,000) and energy load (526 GWh) will be about 250 percent and 300 percent,respectively, during the implementation period. In general, due to the lower load per investedtaka, the PBSs have a weaker financial position than the more dense urban distributionnetworks. It will take 7-8 years until the PBSs reach reasonable return on equity and another 7years to reach an adequate equity ratio of roughly 30 percent to bring them to a self-sustainableand independent status.

H. Environmental and Social Measures

1. Environment

76. The Project has been classified in environment category B requiring a summary of theinitial environmental examination to be attached to this Report. From the information supplied byPGCB, there appears to be no deleterious environmental impact that cannot be mitigated.PGCB conducted an initial environmental examination of the 230 kV and 132 kV transmissionlines and substations in part A of the Project, including an initial social assessment,. Otherproject components have negligible impact on the environment. A summary of the Mission’senvironmental assessment is given in Appendix 8. The appendix also details the principles ofland acquisition and routing of transmission lines that will be followed to minimize environmentaland social impact, and the principles of compensation that will be applied to persons affected bythe Project.

77. PGCB will acquire about 23.6 hectares for the new 230 kV substations at Bogra,Baghabari, and Khulna, and the switching station at Serajganj. The identified sites, other thanthose at Bogra, are low-lying and get flooded every year. Hence they support few permanentpopulation or structures. At Baghabari and Khulna, it will be necessary to demolish onehomestead and resettle the occupant families. At Bogra, though the land is good for agricultureand supports three crops a year, there are no permanent settlements or structures. For theswitching station at Serajganj, land developed by the Jamuna Multipurpose Bridge Authority willbe used and land acquisition will not be necessary. Few trees need cutting at all the identifiedsites. In addition to land for the substations, PGCB will also need to acquire right-of-way for thetransmission lines that will be constructed. The Mission observed that the transmission lineswere proposed to be routed through paddy fields where tree cutting is not necessary. Thetemporary disruption of agriculture (during line construction only) can easily be mitigated.

2. Social Analysis

78. ADB missions have discussed project components in detail with the management as wellas the staff of BPDB and REB/PBSs who, in turn, have briefed their members. ADB missionshave also discussed the elements of the Project with potential beneficiaries, such as theFederation of Bangladesh Chambers of Commerce and Industry, several industrialists, as well asa few residential and commercial consumers at Khulna. The beneficiaries are aware of the Project

23

and support the power sector reforms now being implemented. The staff of the power sectororganizations support the project, but some have reservations regarding the restructuring andcorporatization activities.

79. The Project will not necessitate major relocation of persons. Only about 63 landownerswhose land will be acquired for the four substations may be permanently affected. A resettlementplan has been prepared based on ADB’s policy on involuntary resettlement (November 1995) andconsistent with laws, regulations, and practices of Bangladesh. Minor rerouting of the transmissionlines, to be considered during project implementation, will further reduce the number of affectedpersons. ADB’s review missions will closely monitor implementation of the plan for compensationand resettlement.

3. Project Performance Monitoring

80. Project performance monitoring will be done by BPDB, PGCB, and REB, and will bereviewed by ADB missions as part of the supervision work. This will include verifying of (i) thenumber of additional connections provided, (ii) the consumer categories of the new connections,and (iii) the improvements in service for the existing consumers in the project area. Institutionalparameters such as accounts receivable, accounts payable, and systems losses will also beevaluated.

I. Technical Assistance 25

81. The distribution operations of BPDB are organized into four zones: central zone, eastzone, west zone, and north zone. With a view to improving operating efficiencies of these zonesas well as their consumer orientation, BPDB intends to reorganize its distribution systems inthese zones and introduce modern management systems. As part of this effort, BPDB wishes toorganize each zone as a separate company, governed by its own board of directors, andmanaged independently. The first zone to be corporatized will be the west zone, with itsheadquarters at Khulna. In this context the Government has requested ADB to provide TA toBPDB and the new company for west zone distribution to conduct studies necessary to effectthe corporatization of BPDB’s western zone, as well as develop systems for efficient O&M.

1. Objectives and Scope

82. The TA will assist the Government and BPDB to (i) corporatize BPDB’s distribution in thewest zone, (ii) introduce modern management systems in the new company, (iii) advise thenew company on modernizing and upgrading the power network of Khulna City, and (iv)establish quality assurance practices in the new company for its efficient operation. Outlineterms of reference are in Appendix 9.

2. Cost Estimates and Financing Plan

83. The total cost of the TA is estimated at $1,250,000 equivalent, comprising $765,000 inforeign exchange costs and $485,000 equivalent in local currency costs. ADB will finance, on agrant basis from the ADB-funded TA Program, the full foreign exchange costs and $135,000equivalent of the local currency costs for a total of $900,000. The remaining $350,000 will beprovided by the Government and BPDB in kind, to cover costs of office accommodation,

25 This TA will be withdrawn if DFID provides support for a comprehensive organization development.

24

transport, salaries of counterpart staff, administrative support, and contingencies. A detailed costestimate is in Appendix 10.

3. Implementation Arrangements

84. The TA will require about 22 person-months of input of an international consulting firm orutility with expertise in management systems, engineering, O&M of distribution systems, legaldrafting of power purchase agreements, and cost accounting. The international consultingservices will be supported by 20 person-months of domestic consultants in the areas of assetvaluation, computerization of information systems, human resources management (especiallybeneficiary consultations), and legal aspects. The international consulting firm will be selected inaccordance with ADB’s Guidelines on the Use of Consultants, and will be responsible to ADB forthe total scope of the work. The consultant will be requested to submit a simplified technicalproposal. 85. BPDB and the new company for West Zone distribution will be the EAs for the TA. Forsmooth implementation of the study and to facilitate transfer of knowledge, a task force withsuitably qualified and experienced staff and facilities will be set up before the consultants arefielded. BPDB and the new company will provide, free of charge to the consultant’s team,(i) office accommodation and facilities,26 and (ii) transport within Bangladesh. BPDB and thenew company will assist the consultants in gathering data, preliminary analysis, and writing thereport. The entire work, including writing the report, will be done in Bangladesh, thus maximizingtransfer of knowledge to Bangladeshi managers, engineers, accountants, and other staff. Theconsulting firm will make its own arrangements for personal computers and other facilities forproducing its reports.

V. PROJECT JUSTIFICATION

A. Project Basis

86. As part of its private power generation policy adopted in October 1996, the Governmenthas invited private sector investment to increase generation capacity in Bangladesh. Proposalshave been solicited for about 1,400 MW of generating capacity on a BOO basis. This capacity isexpected to be available within the next five years. In addition, 320 MW generation capacity isunder construction or commissioning in the public sector.

87. Almost all incremental base load generation is thus expected to come from IPPs.Consequently, to allow evacuation of power from the new plants, complementary investments intransmission and distribution facilities are required. The Project provides for these matchingfacilities. The Project also provides one more interconnection to the east zone, improvingoptimization of generation sources. Appendix 11 presents the consumer connection summary,which was used as the basis for the financial and economic analyses of the Project.

B. Financial Analysis

88. The financial evaluation of the Project (Appendix 12) was undertaken as three separatebusiness cases and in real terms using constant 2001 prices. Project cost estimates andfinancial projections in nominal terms were converted to real terms by adjusting for the projected

26 Facilities, such as computer hardware, software and services for implementing financial management, billing and

consumer accounting systems will be purchased under the proposed ADB loan.

25

effects of foreign and domestic inflation and currency fluctuations. Incremental costs andbenefits were derived by evaluating the financial position of the EAs under with- and without-Project scenarios.

89. The weighted average financial internal rate of return (FIRR) for Part A (PGCB),computed on an after-tax basis, is 6.6 percent. This compares favorably with the weightedaverage cost of capital (WACC), also computed on an after-tax basis, of 4.0 percent. Part A ofthe Project is considered both financially viable and sustainable. Sensitivity analysis indicatesthat the weighted average FIRR is robust under adverse conditions.

90. For Part B (the new company) financial analysis is based on input data provided byBPDB regarding the expected transfer of assets, customers, and load for the involved five cities.The FIRR for part B, conservatively computed on an after-tax basis, is 10.0 percent, whichcompares favorably with the WACC of 2.8 percent, also computed on an after-tax basis.Decreased system losses beyond those assumed are expected to bring higher returns since theaverage improvement assumed is from the current 26 percent to the projected 18 percent byFY2008.

91. The weighted average FIRR for Part C (upgrade of eight PBSs), computed on an after-tax basis, is 5.9 percent. This slightly lower FIRR is, as earlier mentioned, caused by the lowerload and less dense consumer base per invested amount in fixed assets. Still, it comparesfavorably with the WACC, also computed on an after-tax basis, of less than 0 percent in realterms because of subsidized low interest rates from the Government to REB/PBSs. Theinvolved PBSs are expected to develop, financially as well as operationally, in a very positivedirection as a result of this Project and after some years become sustainable and viableindependent entities capable of financing their own expansion.

92. The FIRR analysis is summarized in Table 8, and the WACC analysis is summarized inTable 9.

Table 8: Summary of Financial Internal Rate of Return Analysis(percent)

Case Part A Part B Part C

Base Case 6.6 10.0 5.9

Revenues Decrease by 10% 4.8 neg. 0.2

Operating Expenses Increase by 10% 6.2 neg. 1.8

One-year Construction Delay with a 10% Cost Overrun 4.3 7.2 3.2

neg. = negative.

Table 9: Summary of Weighted Average Cost of Capital Analysis(percent)

Case Part A Part B Part C

Base Case 3.96 2.84 <0

One-year Construction Delay with a 10% Cost Overrun 4.27 3.26 <0

26

C. Economic Analysis

1. Economic Rationale for the Project

93. The greater Dhaka area has the highest commercial and political importance toBangladesh. Thus, infrastructure and other investments have tended to focus on it. As aconsequence, the area has shown considerable improvement in its physical infrastructure, whileother regions of the country, which have not been able to attract aid or private sector capital,have been falling behind. However, increasing the connections in predominantly rural areas isnot feasible until the entire supply chain comprising the generation and transmission facilities isaugmented. Bangladesh has made good progress in promoting private sector investment ingeneration facilities while the public sector has continued to establish transmission anddistribution lines to help evacuate and utilize the privately generated power. This successfulmodel will now be applied to west Bangladesh, a relatively poor area of the country, with a viewto the correct existing imbalance of physical infrastructure, electrification rate, and overall socialand economic development in the country.

94. Studies in Bangladesh have shown the crucial contribution of the power sector to socialand economic development and, ultimately, poverty reduction. Power is an essential ingredientfor increasing economic growth, for improving the quality of life of consumers, and for creatingemployment opportunities, especially in the rural areas. Given that only about 20 percent of thepopulation in Bangladesh has access to electricity, this means that the electrification program inthe smaller towns and villages should be accelerated to increase the population's access toelectricity and to reap the benefits offered by good quality power supply.

95. The multiplier effect that the use of electricity can have on the local economy wasemphasized by the findings of a USAID-funded comprehensive field study carried out in 1996 toinvestigate the economic and social impact of the rural electrification programs implementedthrough the PBS.27 A general finding of that study was that the creation of PBSs caused localmarkets to expand and gave rise to a new class of entrepreneurs. Since the launch of theprogram, 6,000 direct jobs have been created in PBSs and REB. Once the PBSs mature andthe industries became more established, use of local raw material also increased, therebyestablishing a support economy that helps local employment and increases cash income. Thishas resulted in the creation of about 20,000 indirect jobs at various industries and shops, whichhad opened in response to the demands created by the program. The establishment ofindustries as a result of electrification, their growth, and the creation of a support industry forindustrial inputs have another beneficial aspect on the local economy – the gradualdevelopment of local demand markets.

2. Project Costs in Economic Prices

96. The economic analysis was carried out at border price level using 2001 prices. Toconvert financial capital costs to economic costs, taxes and duties were deducted. No pricecontingencies are included in the base capital costs. However, the economic capital costsinclude 5 percent physical contingencies. The costs have been separated into foreignexchange, indirect foreign exchange, and local currency cost. Local costs were furtherseparated and specific conversion factors used for skilled and unskilled labor. The remaining

27 A Socio-economic Impact Estimation of the Rural Electrification Program in Bangladesh carried out by NRECA

International Ltd.

27

local costs were converted to border prices by applying a standard conversion factor. Annualmaintenance and operating costs were also calculated in economic prices as a percentage ofthe total investment costs for each component. The cost of energy is valued at the LRMCgeneration level for IPP plants, since the Project will evacuate and utilize the incremental powerproduced by the Baghabari and Bheramara IPP plants that are expected to become operationalin 2004. Transmission and distribution losses included in the total amount of energy to beimported into the transmission system separately for BPDB and REB distribution investments.Reduction in system losses is reflected progressively in the reduced need for energy import toserve the same level of consumption.

3. Project Benefits in Economic Prices

97. The economic benefits of electricity consumption for each major consumer categorywere calculated separately for BPDB and REB. Different proportions of consumer categories ineach PBS were taken into account for the REB benefit calculation. Customers suffer fromfluctuating voltage levels and general poor quality of supply. In addition to improving the qualityand quantity of supply, the Project will provide for new connections, in both the urban and therural areas. It is expected that when load shedding is completely eliminated and reliableelectricity supply is created, the purchase of more sensitive electrical appliances likerefrigerators for domestic consumers or production equipment for industries will increase. Theeconomic benefits were calculated separately for the new consumers and the incrementalconsumption of existing consumers due to reduced load shedding and improved quality ofsupply. Consumption of new consumers was valued at replacement cost, that is the alternativeeconomic costs of other energy sources such as captive power plants for industrial users orkerosene lamps for the domestic segment. Incremental, or induced, consumption was valued atthe estimated average willingness to pay for electricity based on the weighted average of thealternative cost of providing similar energy-related services and the current electricity tariff foreach consumer category. The evaluation is described in more detail in Appendix 13, which alsoprovides the results of the sensitivity analysis.

98. The base case economic internal rate of return (EIRR) for the Project was estimated at19.3 percent. The EIRR was calculated for a 20-year period including a 5-year constructionperiod, corresponding to the estimated useful life of the Project. No residual value wasconsidered.

4. Macroeconomic Effects

99. The creation of new sector entities should instill discipline and financial viability into thesector. Presently, because of failure to manage utilities properly, system losses and accountsreceivable are excessive and drain the sector of about $80 million per year. This has meant thatthe Government has been directly subsidizing the end users of electricity. In FY1995, Governmentloans of $345 million to BPDB were converted to equity. This meant that the Government hadforegone the domestic mobilization of funds inherent in the onlending of development loans andgrants to the sector. In DESA, the Government’s equity of $260 million has become almostworthless because of operational losses incurred since its creation in FY1992.

100. Electricity tariff did not increase during September 1991-September 1996 thus the price toconsumers was reduced in real terms and creating further strain on the sector, whereasdebt-service obligations, fuel prices, and operating costs had risen. ADB’s Ninth Power Projectaddressed this issue by increasing the average retail tariffs by 14.93 percent effective September-December 1996 and introducing of a formula for automatic adjustment for variations in key input

28

costs. The Dhaka Power Systems Upgrade Project and the Project will seek to further thefinancial consolidation of the sector by rationalizing the tariff regime to decrease subsidies toricher PBSs and reducing in the consumption slab for the “lifeline” tariff. Efforts to remove thedrain on the national exchequer and improve public financial management are essential to aid inmacroeconomic management, which is one of the objectives of ADB’s policy on goodgovernance.28

101. The Project is designed to bring electricity to west Bangladesh, especially the southwestregion. With the completion of the Rupsha and Paksey bridges now under construction with JBICfunding, extension of the natural gas network to the region as part of ADB’s next operation in thegas sector, and proximity to the Indian market, this region of Bangladesh could become the nextgrowth center of the country if appropriate infrastructure facilities exist.

D. Social Dimensions

102. The Project is designed to promote economic growth by increasing access to electricitysupply in urban and rural areas in southwestern Bangladesh. The Project will provide a reliablepower supply that will improve the chances for industrialization and thus provide employmentopportunities. A reliable electricity supply will also enhance education, health, and security facilitiesthat exist in the area.

103. Although the Project is essentially gender neutral, there are benefits that will be derived bywomen as a result of electricity supply; education, security, and more comfortable living. With theadvantage of better lighting, women can spend their spare time on education or other vocations.Community televisions in the villages can improve general knowledge on health, hygiene, andprevention of diseases. Street lighting will provide better security to women after dark.

104. The domestic tariff structure incorporates a lifeline tariff of Tk2.00/kWh ($0.04) for the first300 kWh per month. This amount of energy is much higher than the electricity consumed for lightingand by one or two fans, which is considered the basic minimum for electricity consumption.Therefore, ADB has requested that this level be brought down to 50 kWh per month, which is theconsumption of a poor household. While increasing tariffs in the past, it was ensured that this lifelinetariff is affordable to the lower income groups. The Government is considering a proposal submittedby the Power Cell on this issue.

105. No layoffs are envisaged as part of the Project, the overall reform process will, in the future,lead to surpluses in certain categories of staff in BPDB and DESA. Such staff can be retrained inother skills for redeployment in REB, DESCO, and BPDB's successor organizations. Staff who arenot employable in the sector will be given compensation packages for separation. The power sectoragencies, in association with ADB and other aid agencies, will conduct studies next year and evolvean appropriate scheme to mitigate the social impact of the reforms.

E. Impact on Poverty

106. The Project does not directly address poverty reduction because the primarybeneficiaries are largely the industrial, commercial, and domestic consumers, both rural andurban. This mix of consumers is important to safeguard the financial and economic viability ofthe Project. However, the Project yields very attractive economic returns and with increasingemployment opportunities as a result of electrification, there will be benefits for the poor. Power

28 R151-95: Governance: Sound Development Management.

29

outages affect the small businesses more than the larger ones - the small shopkeeper and theartisan, as well as the poorer residential consumers who cannot afford backup generators.

107. Over the past three years, agriculture output in Bangladesh has considerably increaseddue to one additional crop a year based on irrigation, using water from nearby rivers or shallowtube wells, drawn up using electric pumps. Without the spread of electricity, farmers would beforced to use diesel pumps, which are considerably more expensive to purchase and operate,and hence may not be an incentive for additional cropping. This increased agriculture activityhas provided more employment opportunities, both on and off the farm. With increasingelectrification, agroprocessing industries are also slowly developing, providing moreemployment.

108. A long-term research study on rural poverty,29 published in 1995, covered 62 villagesrepresenting 57 of 64 districts in Bangladesh. One article compiled in the book analyzes thedeterminants of poverty and their relative significance. One of the six major factors identified,physical infrastructure, was defined to comprise rural electrification, irrigation, and transportfacilities.

109. The methodology compared electrified with nonelectrified villages. Poverty incidencewas estimated for electrified villages and was then compared with that of villages without accessto electricity. Poverty was substantially reduced with the spread of electrification. Only 14percent of the residents in electrified villages are hard-core-poor – defined as persons whoseaggregate expenditure falls below the normative poverty line of 2,112 calories per day plus a 30percent allowance for nonfood basic needs – as compared with 31 percent for villages withoutelectricity. The matched figure for moderate poverty is 27 percent and 31 percent respectively.The researchers concluded that the extremely poor benefit more from rural electrification thanthe moderately poor.

F. Risks

110. The success of the Project depends on the maintenance of tariffs to ensure the financialviability of the sector and its entities. The FIRR and EIRR of the Project were tested forsensitivities and have been found robust. To further mitigate the risk, (i) covenants were proposedto ensure the financial viability of PGCB, Ashuganj Power Company, and the new west zonedistribution company, in the short term; and (ii) the legal framework for the sector is beingchanged and an independent regulatory authority is being established for the long term. ADBgranted TA to the new regulatory authority to support its operationalization (footnote 8).

29 Rahman, H.Z. and M. Hossain eds. 1995. Rethinking Rural Poverty – Bangladesh as a Case Study. The University

Press Limited, Chapter 15.5.

30

VI. ASSURANCES

111. The Government and the EAs have given the following assurances, in addition to thestandard assurances, which have been incorporated in the legal documents. These assuranceswill be in addition to those already agreed to between the Government and ADB in connectionwith the loans provided for the Ninth Power Project and the Dhaka Power System UpgradeProject.

A. Specific Assurances

112. The Government has agreed on the following specific actions.

(i) The first boards of directors of the new companies will be appointed by BPDB inaccordance with principles agreed upon with ADB.

(ii) At least 25 percent of the board members of the West Zone Electricity DistributionCompany will be persons who are not employees of the Government or publicsector enterprises, and who represent consumer or professional interests.

(iii) The Government will, at all times, emphasize, respect, and support the autonomyof PGCB, BPDB, and REB, including any of their successsor entities includingtheir organization structure, procurement, decisions or actions, in respect ofProject implementation and carrying out their administrative, financial andcommercial responsibilities.

(iv) To enable the proper functioning of the new company, the Government and itsagencies will expedite, and assist in expediting, issues of due permits andlicenses as may be required by law for the functionalization and operation of theWest Zone Electricity Distribution Company.

(v) Local currency funds required to be mobilized by the Government to BPDB,PGCB and REB will be committed in advance in the annual developmentprogram of the Government based on the anticipated expenditure of that yearand transferred to the EAs at least one quarter in advance.

(vi) In addition to the covenants under the ADB-funded Ninth Power Project andDhaka Power Systems Upgrade Project for PGCB and DESCO, the Governmenthas agreed to the following covenants on PGCB, the Ashuganj Power Companyand the new power distribution company from FY2005 onward, to secure theirfinancial health:

a. Debt-service coverage ratio of not less than 1.2.b. Rate of return on equity of not less than 15 percent.c. Rate of return on net fixed assets not less than 5 percent.d. Debt-equity ratio not exceeding 70:30.e. Accounts receivables not more than 2 months billing.

(vii) The Government will ensure that BPDB will transfer the Ishurdi 230 kVsubstation, Khulna Central 132 kV substation, and associated 260 kV and 132 kV

31

transmission lines to PGCB, and that PGCB will not award any contracts relatingto any assets that are owned by BPDB till such transfer.

(viii) The Government will ensure that PGCB implements land acquisition, routing oftransmission lines, and payment of compensation under the Project inaccordance with the agreed Resettlement Plan prepared as per ADB’sInvoluntary Resettlement Policy. The Government will also ensure that all EAscarry out the Project in accordance with ADB’s Environment Guidelines forSelected Infrastructure Projects.

(ix) The Government will ensure that PGCB shall complete, along each section of thefinal 230 kV transmission routes, prior to the commencement of each stage ofconstruction activities in that section (a) a census; (b) an estimation of the losses;(c) a socioeconomic survey of the affected persons. No construction work undera section shall commence till the compensation for the persons affected by thatwork has been assessed and paid to the affected persons.

(x) Government will ensure that the EAs will carry out performance monitoring andreviews of the Project in accordance with ADB’s Project PerformanceManagement Systems Handbook. The reviews shall include (a) numbers ofadditional connections provided; (b) consumer categories of new connections; (c)improvements in service for existing consumers; and (d) institutional parameterson accounts receivables and payables, and systems losses.

B. Conditions for Loan Effectiveness

(i) The Government shall have caused BPDB to operationalize the West ZoneElectricity Distribution Company by (a) incorporating it under the Companies’ Act,1994; (b) constituting its first board of directors in accordance with principlesagreed with ADB; and (c) advertising for recruitment of its first managing director,director (technical), and director (finance);

(ii) PGCB shall have completed a socioeconomic survey for the as yet unsurveyedareas pertaining to the 230kV substations under Part A to the satisfaction ofADB; and

(iii) The Government shall have (a) increased retail electricity tariffs by Taka0.15/kWh to cover fuel price increase and foreign exchange variations; (b)reduced the first (life line) slab of consumption for its residential consumers fromthe current 300 kWh/month to a level not exceeding 100 kWh/month; and (c)have increased retail electricity tariffs based on its tariff study to recover debtservice liabilities for new investments made in the sector from 1997 onwards.

32

VII. RECOMMENDATION

113. I am satisfied that the proposed loans would comply with the Articles of Agreement ofADB and, acting in the absence of the President under the provisions of Article 35.1 of theArticles of Agreement of ADB, I recommend that the Board approve:

(i) the loan in various currencies equivalent to Special Drawing Rights 47,581,000to the People’s Republic of Bangladesh for the West Zone Power SystemDevelopment Project, with a term of 32 years, including a grace period of8 years, and with an interest charge at the rate of 1 percent per annum during thegrace period and 1.5 percent per annum thereafter, and such other terms andconditions as are substantially in accordance with those set forth in the draftLoan and Project Agreements presented to the Board; and

(ii) the loan of $138,700,000 to the People’s Republic of Bangladesh for the WestZone Power System Development Project from ADB’s ordinary capital resources,with interest to be determined in accordance with ADB’s LIBOR-based loanfacility, an amortization period of 20 years, including a grace period of 5 years,and such other terms and conditions as are substantially in accordance withthose set forth in the draft Loan and Project Agreements presented to the Board.

MYOUNG-HO SHINVice-President

23 November 2001

33

APPENDIXES

Number Title Page Cited onPage, para.

1 External Assistance to the Sector 34 5, 17

2 Reform Road Map 37 9, 32

3 Logical Framework 38 12, 45

4 Cost Estimates 41 13, 48

5 Implementation Schedule 44 15, 53

6 Contract Package List 47 15, 54

7 Financial Performance and Projections 50 17, 63

8 Summary Initial Environment Examination 57 22, 76

9 Outline Terms of Reference for Technical Assistance 60 23, 82

10 TA Cost Estimates and Financing Plan 63 24, 83

11 Consumer Connection Summary 64 24, 87

12 Project Financial Analysis 65 24, 88

13 Economic Evaluation 69 27, 97

Supplementary Appendix

A Financial Projections of PGCB, New Company and PBSs

34 Appendix 1, page 1

Amount Date ofItem ($ million) Approval Name

141-BAN(SF) 9.25 17 Oct 1973 West Zone Power142-BAN 1.20 18 Oct 1973 West Zone Power212-BAN(SF) 4.55 19 Dec 1974 West Zone Power - Supplementary325-BAN(SF) 27.75 9 Dec 1977 Chittagong Power523-BAN(SF) 26.50 22 Sept 1981 Power System Rehabilitation and Expansion587-BAN(SF) 35.00 21 Oct 1982 Ashuganj Project636-BAN(SF) 82.00 13 Sept 1983 Power Transmission and Distribution683-BAN(SF) 120.00 14 Jun 1984 Sixth Power (Sector Loan)751-BAN(SF) 40.50 31 Oct 1985 Seventh Power963-BAN(SF) 165.00 11 Jul 1989 Eighth Power1356-BAN(SF) 50.00 30 May 1995 Rural Electrification1505-BAN(SF) 134.40 18 Dec 1996 Ninth Power1730-BAN(SF) 75.00 21 Dec 1999 Dhaka Power System Upgrade Project1731-BAN 82.00 21 Dec 1999 Dhaka Power System Upgrade Project

Total 853.15

095-BAN 250 17 Oct 1973 Management and Accounting Reforms Study111-BAN 50 09 May 1974 Energy Survey Inception Study130-BAN 1,250 31 Oct 1974 Bangladesh Energy Study218-BAN 250 09 Dec 1977 Power System Rehabilitation and

Expansion Study456-BAN 2,100 15 Apr 1982 Energy Planning460-BAN 50 07 Jun 1982 Power Transmission and Distribution487-BAN 650 21 Oct 1982 Power System Master Plan672-BAN 75 15 Feb 1985 Seventh Power714-BAN 1,355 31 Oct 1985 East Zone Thermal Power Project1743-BAN 90 18 Aug 1992 Review and Electricity Legislation and

Regulations1962-BAN 600 11 Oct 1993 Preparation of Power System Master Plan2004-BAN 1,000 26 Nov 1993 Financial Management Upgrade

of BPDB and DESA2338-BAN 211 30 May 1995 Solicitation for Private Sector

Implementation of the Meghnaghat Power2715-BAN 175 19 Dec 1996 Valuation of Assets of DESC3129-BAN 900 16 Dec 1998 Support to the Energy Regulatory

Authority3244-BAN 90 20 Aug 1999 Capacity Building - Dhaka Electricity

Supply Authority Co., Ltd.3343-BAN 1,000 17 Dec 1999 Corporatization of the Ashuganj Power Station

Total 10,096

ADB = Asian Development Bank, BPDB = Bangladesh Power Development Board, DESA = DhakaElectric Supply Authority, DESC = Dhaka Electric Supply Company, Ltd.

ADB LENDING AND TECHNICAL ASSISTANCE TO BANGLADESH'S POWER SECTOR

Donor/sProject Executing Loan/Credit Year of ADB WB JAPAN/ UK/ KFAED SFD OPEC IS.D.B. USA/ Germany France Russia China

Agency(ies) Number Approval OECF DFID USAID($) ($) (¥) STG KD SR ($) IDR ($) (DM) FF a ($) ($)

West Zone Power BPDB 141-Ban(sf) 1973 9.25West Zone Power Suppl.) BPDB 142-Ban(sf) 1973 1.20West Zone Power BPDB 212-Ban(sf) 1974 4.55Power Supply for Irrigation BPDB/BADC 56 1975 6.382nd Loan (Commercial) BPDB 1975 18.003rd Loan (Commercial) BPDB 1976 21.00Chittagong Power Distr. BPDB 325-Ban(sf) 1977 27.75Goalpara-Barisal Trans. Line BPDB BD-P1 1977 2,532.75 Kaptai Hydro BPDB 388-W-007 1976 2.50Rural Electrification REB 388-T-012 1977 16.00Kaptai Hydro BPDB 388-T-007A 1978 6.98East-Weat Interconnector BPDB 120/168 1978 10.06

186-P 1980 9.161980 7.89

6th Loan (Commercial) BPDB 1979 52.00Rural Electrification REB 388-T-013 1980 17.65Greater Khulna Power Distr. BPDB 943-BD 1979 28.00

139-P 1979 8.50Barge Power Generating BPDB BD-P5 1979 3,540.00 Bheramara-Faridpur-Barisal Trans BPDB BD-P7 1980 3,099.94 7th Loan (Treasury & Commercial) BPDB 1980 97.50Ghorasal Power Unit III BPDB 1981 70.558th Loan (Commercial) BPDB 1981 66.50Rural Electrification REB 181 1981 7.83Kaptai Hydro BPDB BD-P10 1981 249.16 Power System Rehab. & Expan. BPDB 523-Ban(sf) 1981 26.50Ashuganj 90 MW CC Plant BPDB 1981 12.8239th Loan (Treasury) BPDB 1982 69.10Ashuganj Thermal Power BPDB 1254-BD 1982 92.00

587-Ban(sf) 1982 35.00232 1982 7.91

295-P 1982 20.00Rehab./ Extension of Ashuganj Power BPDB 8265423 1982 125.00Rural Electrification Project REB 1262-BD 1982 40.0010th Loan (Treasury) BPDB 1983 56.25Ghorasal Power Unit IV BPDB 1983 73.45Power Trans. & Distr. BPDB 636-Ban(sf) 1983 82.00Suppl. Assistance to REB REB 1504.3-BD 1984 8.00Kaptai Power Plant BPDB BD-P15 1984 10,632.92 Barge Mounted Power plant BPDB BD-P16 1984 6,056.05 Sixth Power BPDB 683-Ban(sf) 1984 120.0011th Loan (Treasury) BPDB 1984 55.25Ghorasal Power Unit V BPDB 1985 75.75Seventh Power BPDB 751-Ban(sf) 1985 40.50Ashuganj Thermal Power (5th Unit) BPDB 373-P 1985 3.94Land Based Gas Turbine BPDB BD-P17 1985 7,461.99 2nd Rural Electrification REB 1633-BD 1985 79.0012th Loan (Treasury) BPDB 1985 79.9513th Loan (Treasury) BPDB 1986 30.80Power Distr. Project (East & West Zone) grant BPDB 1986 5.90Power Trans. & Distr. BPDB 1648-BD 1986 56.00Sylhet 90MW CC plant BPDB BD-P22 1987 8,170.00 14th Loan (Commercial) BPDB 1987 69.0315th Loan (Treasury) BPDB 1988 117.00Ashganj-Comilla Reactive Power Plant BPDB 8665630 1988 22.50Ashuganj-Comilla Trans. Line BPDB 8665853 1989 87.00Eighth Power BPDB/ 963-Ban(sf) 1989 165.00

DESA

35A

ppendix 1, page 2EXTERNAL ASSISTANCE TO THE POWER SECTOR

(SINCE 1972)Table A2.1

Donors

Donor/sProject Executing Loan/Credit Year of ADB WB JAPAN/ UK/ KFAED SFD OPEC IS.D.B. USA/ Germany France Russia China

Agency(ies) Number Approval OECF DFID USAID($) ($) (¥) STG KD SR ($) IDR ($) (DM) FF a ($) ($)

Donors

1987 58.9Rural Electrification Project REB 9/299 1989 50.00Power Distr. (16 Town) BPDB 2016-BD 1989 87.003rd Rural Electrification BPDB 2129-BD 1989 105.0017th Loan (Treasury) BPDB 1990 95.82Ghorasal Power Unit V ( 4 Suppl.) BPDB 1987-1990 6.70Energy Sector Adjust. Loan GOB BD-C18 1990 3,800.00 Rauzan 210MW unit I BPDB 1990 86.64Rehab. Of Ashuganj Power plant BPDB 4602552 1992 44.10Ghorasal Power Unit VI BPDB 1992 75.85Haripur Power Plant Rehab. BPDB BD-P30 1993 15,100.00 Rural Electrification Project REB 440 1993 10.00Rural Electrification Project REB 7.00RE Solar Project (grant) REB 1993 6.40Barge Mounted Power plant Rehab. BPDB BD-P31 1994 1,561.00 Sylhet 90MW CC plant II BPDB BD-P34 1994 5,943.00 Rural Electrification REB 610-P 1994 15.30Rauzan 210MW unit II BPDB 1994 79.50Reactive Power Compensation and BPDB 1995 7.50 System Loss Reduction ProgramSiddirganj TPS BPDB 1995 91.00Rural Electrification REB/RPC 1356-Ban(sf) 1995 50.00Rural Electrification-III REB 1995 2.90RE Project (Phase-IV C) REB BD-P37 1995 5,442.00 Rural Electrification Project REB 1997 2.15Comilla-Chittagong Transmission Line BPDB 1997 30.00Ninth Power BPDB/PGCB/ 1505-Ban(sf) 1997 134.40

DESA/DESCORural Electrification REB 1997 7.00Rural Electrification REB 1998 3.10

Total 696.15 495.00 73,588.80 71.72 44.32 50.00 56.89 21.89 46.03 316.10 840.49 393.29 166.13Dhaka Power System Upgrade Project PGCB/DESA/ 1730- Ban(sf)/ 1999 157.00

DESCO/REB 1731-BanACRE Phase V-A REB 1999 40.00 ACRE Phase V-A REB P-45 2000 3,465.00 Pilot scheme for SL Reduction BPDB/DESA P-45 2000 911.00 Greater Rajshahi Power Distribution BPDB 2000 5.50 Greater Chittagong Power Distribution BPDB 2000 12.30 Rehabilitation of Grid Substations BPDB S. Credit 2000 87.67Rehabilitation of Dhaka Distribution DESA S. Credit 2000 60.00Rehabilitation of Ghorasal Unit 1 & 2 BPDB S. Credit 2000 17.72ACRE Phase V-B REB P-49 2001 1,460.00 Barapukuria Coal fired 250 MW P. Plantlant BPDB S. Credit 2001 209.00

a 80 percent of this amount is for BPDB (details to be collected)Note: A. Belgium provided BF 150 million interest free loan in 1977 to GOB, a part of that had been used by BPDB. The Netherlands provided DFL 55 million grant in 1995 for RE project. Belgium provided grant for NKR 90.2 million in 1997 for RE project. UAE provided DIR 60 million loan for East-West Interconnector in 1978. India provided IRS 202 million state credit to BPDB for greater Rajshahi project in 1991. B. NORAD provided $7.80 million to REB for ACRE Phase V-B project in 2000

36A

ppendix 1, page 3

STATUS AS OF 19941 Monopoly on generation and transmission by BPDB2 No companies in the sector. All were autonomous organization under GOB3 Major Issues were (i) Financial insolvency; (ii) Circular debt;(iii) High losses

(iv) Poor technical and managerial capacity; (v) Overstaffing; (vi) Indisciplineand low morale of employees; and (vii) acute shortage of capacity

GOVERNMENT'S PAPER "POWER SECTOR REFORMS IN BANGLADESH"

1 Introduce competition in generation - both foreign and local IPPs2 "Unbundle" the sector into functionally separate businesses2 Corporatize sector entities3 Separate regulation from ownership of assets4 Separate distribution in major cities into five or six entities. REB to handle all rural and small towns

ADB'S ROAD MAP

AREA REQUIRED REFORMS STAGING1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005-10

1 Reform Planning Issue of policy statement XApproval by Government XReform legislation X X XMid-course corrections X XPower system master plan X X

2 Functional Segregation Establishment of Transmission Company XTakeover of first assets and manpower XTakeover of eastern grid XTakeover of entire grid X X

Establishment of Distribution Company(ies)Dhaka distribution XOther areas X X X X

Establishment of Generation Company (ies)Domestic IPPs X XForeign IPPs X XBPDB Successors X

Establishment of regulator X

3 Introduction of Competition Establish merit order dispatch XPrivate sector participation

a) IPPs X X X X Xb) Privatization X

Establish efficient benchmarks in distribution X X

4 Tariffs and Subsidies Depoliticize tariff setting X XMake variations transparent and routine XLink tariffs with efficiency XAchieve operational costs recovery X XAchieve total cost recovery X X XPhased elimination of unnecessary subsidies X

5 HRD Salaries and wages made competitive X X X XWork culture improved X X X X XTechnical and managerial training systems introduced X X X X X X

6 Management Strengthening Corporatization of entities X X X X X X XIndependence of the Board of Directors X X X X X X XDelegation of powers to the management X X X X X X X XCompetitive selection of management X X X X X X X XComputerized accounts and billing systems

Pilot - 20,000 consumers X X XExpand to 500,000 consumers X X XCover whole country X X X X

7 Market Development Grid code XAlternative investment mechanisms X X X X X

BPDB = Bangladesh Power Development Board, HRD = Human Resource Development, IPP = independent power producers, REB = Rural Electrification Board.

Appendix 2

37

REFORM ROAD MAP

Appendix 3, page 138

LOGICAL FRAMEWORK

Design Summary Indicators & Targets MonitoringMechanisms

Key Assumptions& Risks

Goal1 Effective electricalenergy supply insouthwest Bangladesh-- especially Khulna,Barisal, Faridpur andKushtia towns

1.01 No load shedding,by 2008

1.01 Utility interruptionreports by PGCB, BPDB,new company, REB/PBSs

1.02 Applications fornew electrical connectionspending for not more than2 months, by 2008

1.02 Monthly MIS reportof BPDB, newdistribution company,PBSs

Purpose End of Project 'Success'Status

Purpose to Goal

1 Sustainableeffective and efficientpower sectorinstitutions maintained

1.01 5,000 MW peakload network maintained

1.01 Power companysystems operationsreports

1 Load growthcontinues as per1995 power systemmaster plan

1.02 Power systemlosses decreased from 26percent in 2001 to 18% ofpower import by 2008

1.02 Power companysystems operationsreports

1.03 ROE>15% andSFR>30%, by 2008to ensure that adequaterevenues are collected forboth continued O&M andfuture expansion

1.03 Power companysystems annualoperations reports

1.03 Tariffs arerestructured inorder to encourageenergyconservation andimprove economicgrowth

1.04 Regulatory systemeffectively enforced, by2006 and sustained

1.04 Regulatorycommission systemreports and annualstatistics

1.04 National LoadDispatch Center inoperation by 2005

2 Customer outreachservice expanded

2.01 New customersconnected as follows:Residential: At least 229thousandCommercial: At least 34thousandIndustrial: At least 10thousandOthers: At least 4thousand all by 2008

2.01 MIS reports of newcompany, PBSs

Appendix 3, page 239

Design Summary Indicators & Targets MonitoringMechanisms

Key Assumptions& Risks

Outputs /Components

Output to Purpose

1 New power sectorinstitutions created

1.01 Southwestdistribution companyestablished and fullyoperational, by 2006

1.01 RegistrationCertificate and GOBnotification· Memorandum· Articles of Association· Board Nominations· Asset and staff

transfers1.02 New regulatoryauthority created andoperational, by 2002

1.02 RegistrationCertificate· GOB notification

1.02 Competentregulators areappointed

2 BPDB's territoryredistributed

2.01 Core metropolitanareas given to Southwestcompany, by 2005

2.01 Project progressreports

2.02 Semi-rural areasand non-contiguous areashanded over to REB /PBSs, by 2006

2.02 Project progressreports

3 New plant installed 3.01 Power linesestablished as follows:400 km 230/132kV1,000 km 33kV, 11kV200 km 0.415 kVby 2006

3.01 Project progressreports

3.02 230/132/33 kVsubstation capacityaugmented by 1,100MVA, by 2006

3.02 Project progressreports

Activities forOutputs / Comp

Schedule Start /Complete

Activity to Output

1 New power sectorinstitutions1.01 Incorporation ofnew distributioncompany

1.01 Start: 01.11.2001Complete: 01.01.2002Responsibility: BPDB

1.01 Memorandum andArticles of Association;Certificate of Registration

1. Government’sapproval

1.02 Appointment ofBoard of Directors

1.02 Start: 15.11.2001Complete:01.01.2001Responsibility: BPDB

1.02 Company Boardnotification

1.03 Appointment ofManagement

1.03 Start: 15.11.2001Complete: 28.02.2002Responsibility: BPDB

1.03 Appointmentletters

Appendix 3, page 340

Design Summary Indicators & Targets MonitoringMechanisms

Key Assumptions& Risks

2. BPDB territoryredistribution2.01 Handover ofareas to REB/ PBSs

2.01 Start: 01.01.2000Complete: 31.01.2003Responsibility: BPDB/REB

2.01 Project progressreports

2 Timely transfer ofassets from BPDBto PGCB• Timely transfer

of assets fromBPDB to REB,new company,PGCB

2.02 Handover ofassets and staff tonew company

2.02 Start: 01.01.2003Complete: 31.12.2005Responsibility: BPDB/new Co.

2.02 Project progressreports

2.03 Handover ofassets and staff toPGCB in west zone

2.03 Start: 01.01.2001Complete: 30.06.2002Responsibility: BPDB/PGCB

2.03 Project progressreports

3. New plantinstallation3.01 Preparation ofbid documents

3.01 Start: 01.11.2001Complete: 31.12.2002Responsibility: PGCB,BPDB, REB

3.01 Project progressreports

3 Availability of IPPpower atBheramara by 2005

3.02 Evaluation ofbids and award ofcontracts

3.02 Start: 31.03.2002Complete: 31.03.2003Responsibility: PGCB,BPDB, REB

3.02 Project progressreports

3.03 Completion ofwork

3.03 Start: 31.03.2005Complete: 31.03.2006Responsibility:Contractors

3.03 Project progressreports

Inputs Resources Costs and'LOE'

Input to Activities

1 Financing 1.01 FX $270.3 millionLC $210.9 million

1.01 Loan Agreement 1 Timely availabilityof adequate GOBcounterpart funding

2 ConsultingServices

2.01 International: 30person monthsDomestic: 30 person-months

2.01 PGCB, BPDB,REB contract documents

3. TechnicalAssistance

3.01 International: 22person-monthsDomestic: 20 person-months

3.01 ADB contractdocuments

41 Appendix 4, page 1

($ million)Serial No. Item Remarks

Foreign Local TotalA. Preconstruction Cost

1.1 Survey and Soil Test 0.10 0.19 0.29 1.2 Land Acquisition - 1.18 1.18 1.3 Land Requisition - 0.25 0.25 1.4 Land Development - 0.52 0.52 1.5 Civil Works 1.25 1.60 2.85 1.6 Environment and Social Study 0.08 0.06 0.14

Subtotal 1.43 3.80 5.23

B. Transmission Lines

1 Ishurdi-Baghabari-Bogra230 kV Transmission Line

1.1 Baghabari- Serajganj- Bogra (110 km) 20.00 2.82 22.82 Subtotal 20.00 2.82 22.82 Parallel Financing by KfW

2 Ishurdi-Bheramara- Khulna1.1 Ishurdi-Bheramara-Khulna 230 kV (170 km) 40.00 6.78 46.78 1.2 Khulna new SS to Khulna 132 kV (7 km) 0.80 0.13 0.93

Subtotal 40.80 6.91 47.71 3 Ashuganj-Baghabari 230 kV

(2nd East-West Interconnector)3.1 Ashuganj- Jamuna Bridge (140 km) 33.50 5.74 39.24 3.2 Jamuna Bridge- Serajganj (15 km) 3.60 0.61 4.21 3.3 Restringing of existing Jamuna Bridge 0.77 0.20 0.97

Section (7 km)Subtotal 37.87 6.55 44.42

C. Substations

1 New1.1 Bogra, 230/132 kV, 7x75 MVA 10.00 1.50 11.50 Parallel Financing by KfW1.2 Khulna, 230/132 kV, 7x75 MVA 12.00 1.13 13.13 Cofinancing by NDF1.3 Serajganj 230 kV Switching Yard 6.00 1.13 7.13

Subtotal 28.00 3.76 31.76 2 Extension/Upgradation

2.1 Extension of 2 230 kV bays at Ishwardi SS 3.00 0.28 3.28 (for connecting outgoing 230 kV line to Bheramara)

2.2 Extension of 2 132 kV bays at Bogra SS 1.50 0.09 1.59 (for connecting incoming 132 kV line from Bogra 230 kV SS)

2.3 Extension of 2 132 kV bays at Khulna SS 1.50 0.09 1.59 (for connecting incoming132 kV line from Khulna 230 kV SS)

2.4 Extension of 2 230 kV bays at Ashuganj SS 2.78 0.39 3.17 (for connecting outgoing 230 kV line to Baghabari including230 kV underground cable from substation to terminal tower)

Subtotal 8.78 0.85 9.63

D. Operational Equipment and vehicle a 0.76 0.24 1.00 (6 crane mounted truck, 4 fork lift, 10 pickups,10 jeeps, 23 motor cycles, 3 cars, computers, office equipment, etc.)

E. Internal Transportation cost - 3.25 3.25

F. Consulting Services 2.50 0.42 2.92

G. Training 0.47 0.09 0.56

H. Customs Duty and VAT - 42.18 42.18

Total Base Cost 140.61 70.87 211.48

I. Interest During Construction 7.03 3.54 10.57

J. Physical Contingency 10.39 7.29 17.68

K. Price Contingency 12.59 14.35 26.94

Total Cost 170.62 96.05 266.67 KfW = Kreditanstalt für Wiederaufbau of Germany, km = kilometer, kv = kilovolt, NDF = Nordic Development Fund, VAT = value-added tax.a Trucks, forklifts, jeeps, and pickups from loan fund.

Table A4.1: Part A: PGCB Component

Estimated Cost

COST ESTIMATES

42 Appendix 4, page 2

($ million)

Serial Item Quantity Foreign Local TotalNo. km/No.

1 Preconstruction Cost

1.1 Survey and Design 0.00 0.08 0.08

1.2 Land Acquisition 0.00 0.33 0.33

1.3 Land Requisition 0.00 0.00 0.00

1.4 Land Development 0.00 0.08 0.08

1.5 Civil Works 0.00 2.45 2.45

1.6 Environment and Social Study 0.00 0.11 0.11Subtotal 0.00 3.05 3.05

2 Transmission Line

2.1 132 kV Line 13 0.95 0.13 1.08Subtotal 0.95 0.13 1.08

3 Distribution Line

3.1 33 kV Cable (new) 10 1.82 0.27 2.09

3.2 33 kV Line (new) 74 2.02 0.30 2.32

3.3 33 kV Line (upgrading) 82 0.75 0.11 0.86

3.4 11 kV line (new) 148 2.42 0.36 2.79

3.5 11 kV Line (upgrading) 122 0.67 0.10 0.77

3.6 11/0.4 KV line (new) 225 4.09 0.61 4.71

3.7 11/0.4 kV Line (upgrading) 160 1.16 0.17 1.34

3.8 0.4 kV Line (new) 266 3.39 0.43 3.90

3.9 0.4 kV Line (upgrading) 225 1.23 0.18 1.41

Sub-total 17.54 2.53 20.174 Substations

4.1 132/33 kV (new) 1 2.18 0.32 2.50

4.2 132/33 kV (upgrading) 2 1.27 0.18 1.45

4.3 33/11 kV (new) 5 4.55 0.65 5.20

4.4 33/11 kV (upgrading) 10 4.28 0.62 4.90Subtotal 12.28 1.77 14.05

5 Transformers

5.1 11/0.4 kV 250 KVA 510 1.39 0.21 1.60

5.2 11/0.4 kV 100 KVA 515 0.94 0.14 1.08

Subtotal 2.33 0.35 2.686 Meters

6.1 Three-Phase meters (new) 1,950 0.53 0.08 0.61

6.2 Three-Phase meters (replacement) 4,000 0.73 0.10 0.83

6.3 Single-Phase Meters (new) 98,500 1.28 0.18 1.46

6.4 Single-Phase Meters (replacement) 87,500 1.13 0.16 1.29

6.5 Meter Seals 230,000 0.05 0.01 0.06

6.6 Service drops 120,000 0.60 0.09 0.69Subtotal 4.32 0.62 4.94

7 Capacitor Banks/Tools/Communication Equipment LS 0.85 0.13 0.98

8 Operational Vehicles 29 0.25 0.00 0.25

9 Internal Transportation 0 0.00 0.86 0.86

10 Consulting Services 0 0.00 0.91 0.91

11 Computerization of Billing and Accounting 1.00 0.24 1.24

12 Training 0 0.14 0.18 0.32

13 Customs Duty and VAT 0 0.00 11.90 11.90

Total Base Cost 39.65 22.67 62.32

Physical Contingency 1.98 1.13 3.11

Price Contingency 2.93 2.43 5.36

Interest During Construction 2.84 1.13 3.97

Total Cost 47.40 27.36 74.76kV = kilovolt, KVA = kilovolt ampere, sqm = square meter, VAT = value-added tax.

Table A4.2: Part B: BPDB Distribution Component

43 Appendix 4, page 3

($ million)

Serial Item Quantity Foreign Local Totalkm/No.

1 Preconstruction Cost

1.1 Survey and Design 0.00 0.07 0.07

1.2 Land Acquisition 0.00 0.15 0.15

1.3 Land Requisition 0.00 0.00 0.00

1.4 Land Development 0.00 0.06 0.06

1.5 Civil Works 0.00 0.00 0.00

1.6 Environment and Social Study 0.00 0.13 0.13

Subtotal 0.00 0.41 0.41

2 33 kV Backbone Line

2.1 New 200 2.88 0.30 3.18

Subtotal 2.88 0.30 3.183 Distribution Line

3.1 11/6.35 kV Line (new) 2580 16.25 1.70 18.06

3.2 11 kV Line (upgrading) 430 1.74 0.17 1.94

3.3 0.4/0.230 KV line (new) 1620 5.84 0.60 6.48

3.4 0.4/0.230 kV Line (upgrading) 230 0.52 0.08 0.58

Subtotal 24.35 2.55 27.054 Sub-stations

4.1 33/11 kV (new) 3 0.68 0.07 0.75

4.2 33/11 kV (upgrading) 1 0.09 0.01 0.10

Subtotal 0.77 0.08 0.855 Transformers

5.1 75/100 KVA 87 0.05 0.01 0.06

5.2 50 KVA 150 0.07 0.01 0.08

5.3 37.5 KVA 485 0.20 0.02 0.22

5.4 25 KVA 970 0.35 0.04 0.39

5.5 15 KVA 2190 0.74 0.07 0.81

5.6 10 KVA 7290 2.13 0.21 2.34

5.7 5 KVA 4860 1.31 0.15 1.46

Subtotal 4.85 0.51 5.366 Meters

6.1 Three-Phase Meters 2273 0.61 0.07 0.68

6.2 Single-Phase Meters 113613 1.54 0.16 1.70

Subtotal 2.15 0.23 2.38

7 Internal Transportation 0.00 1.15 1.15

8 Computerization 0.40 0.19 0.59

9 Training 0.60 0.19 0.79

8 Customs Duty and VAT 0.00 10.80 10.80

Total Base Cost 36.00 16.41 52.41

Physical Contingency 1.80 0.82 2.62

Price Contingency 2.66 1.62 4.28

Interest During Construction 0.69 0.35 1.04

Total Cost 41.15 19.20 60.35kV = kilovolt, kVA = kilovolt ampere, REB = Rural Electrification Board, VAT = value-added tax.

Table A4.3: Part C: REB Distribution Component

YearDescription Month 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52

T CA DA C

Ishurdi-Bheramara-Khulna 230 kV D/C Transmission Line (170 km)132 kV D/C Transmission Line (7 km), from Khulna SS to Khulna 132/33 kV SS

T CA DA C

Ashuganj-Jamuna Bangabandhu Bridge-Serajganj 230 kV D/C Transmission Line (187 km)(inclusive of 7 km restringing of bridge section)

T CA DA C

Baghabari-Serajganj-Bogra 1/230 kV D/C Transmission Line (110 km)

T CA DA C

Khulna Substation 2/230/132 kV, 7X75 MVA

T CA DA C

Bogra Substation 1/230/132 kV, 7X75 MVA

T CA DA CSerajganj 230 kV Switchyard

T CA DA C

Ishurdi,Bogra, Khulna, and Ashuganj Substations230 and 132 kV Bay Extension

T CA DA C

Ishurdi-Baghabari 3/230 kV D/C Transmission Line (55 km)

T CA DA C

Baghabari Substation 4/132/230 kV, 7X75 MVA

T CA DA C

Ishurdi Substation 4/230 kV Bay Extension

T CA C

Consultant ServicesT CA C

Training

CA= contract award, C= commissioning, DA= design approval, kV = kilovolt, kVA = kilovolt ampere, PGCB = Power Grid Company of Bangladesh, T =tender.

Note:1/- Parallel financing by KfW2/- Cofinanced by NDF3/- Construction through supplier's credit4/- Financing from loan savings from ADB's Ninth Power Project

SWRPP-IMP

Appendix 5, page 1

442005

PROJECT IMPLEMENTATION SCHEDULE

Part A: PGCB Component-230 and 132 KV Transmission Lines and Substations

2001 2002 2003 2004

YearDescription Month 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58

CKhulna Distribution

T CA DA132 kV D/C Transmission Line (13 km)

T CA DA C132/33 kV substation (New) and upgradationof 132/33 kV existing substation

Five City/Town DistributionT CA DA C

33 kV new overhead and under ground network (79 km)T CA DA C

33 kV overhead network upgradation (82 km)T CA DA S C

11 kV and 11/0.4 kV new overhead line (373 km)T CA DA S C

11 kV and 11/0.4 kV overhead line renovation (282 km)T CA DA S c

0.4 kV new overhead line (266 km)T CA DA S C

0.4 kV overhead line renovation (225 km)T CA DA S C

33/11 kV new substation (5 nos.) and upgradation of T CA C

Computerization of Billing and AccountingC

Customer connectionT CA DA C

Consultant ServicesT CA C

Training

CA= contract award, C= commissioning, DA= design approval, BPDB = Bangladesh Power Development Board, T =tender.

SWRPP-IMP

Appendix 5, page 2

45

2005 2006

Part B: BPDB Component-Reinforcement of Distribution System in Five Cities/Towns

2001 2002 2003 2004

YearDescription Month 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58

T CA S C33 KV Backbone System (200 km)

T CA S C11/6.35 kV Distribution Line ( 2580 km new)

T CA S C11/6.35 kV Distribution Line (430 km upgradation)

T CA S C0.4/0.230 kV Distribution Line (1620 km new)

T CA S C0.4/0.230 kV Distribution Line (230 km upgradation)

T CA S C33/11 kV Substations (3 new and 1 upgradation)

Customer Connection

T CA S CComputerization of biliing system

T CA CTraining

CA= Contract Award, C= Commissioning, kV = kilovolt, REB = Rural Electrification Board, S= Supply, T =tender. Appendix 5, page 3

46

Part C: REB Component-Reinforcement of Distribution System in Eight PBSs

2001 2002 2003 2004 2005 2006

47 Appendix 6, page 1

Contract Item Description Contract No. Type

A. Tower Packages (including erection and stringing)

1 Ishurdi-Bheramara- Khulna 230 kV D/C (inclusive of 132 kV D/C Turnkey7 km line from Khulna 230 kV substation to Khulna 132 kV existing substation)

2 Ashuganj-Serajganj 230 kV D/C (including restringing of TurnkeyJamuna Bangabandhu bridge section)

B: Substation Packages

3 Serajganj 230kV Switching Yard and 230 kV Bay extension at Ashuganj Turnkey

4 230kV and 132 kV Bay Extensions in Ishwardi, Bogra,and Khulna Turnkey

5 Operational Equipment and Vehicles Supply

6 Consultant Services

TotalkV = kilovolt, D/C = double circuit, S+C = supply and commissioning.

SWRPP-CP

CONTRACT PACKAGE LIST

0.75

Estimated Contract Value ($ million)

Table A6.1: Part A: 230 kV Transmission System

6.00

95.25

43.00

34.00

2.50

9.00

48 Appendix 6, page 2

Contract Item Description Contract No. Type

A. Line and Customer Connection Materials

1 Tower Materials Supplyi. 132 kV Tower Materialsii. Conductoriii. Optical Groundwire (OPGW) iii. Insulators and Hardware Fittings

2 Cables Supplyi. 33 kV Cables and Jointing Kits

3 Poles, Conductor Cables and Insulators Supplyi. 33 and 11 kV Poles and Accessoriesii. Conductors iii. 33 and 11 KV Insulators and accessoriesiv. 0.4 kV Insulated Cables and Service Drops

4 Transformers Supply11/0.4 kV Transformers and accessories

5 MetersThree-Phage and Single-Phase Meters, and Meter Seals

B. Substations

6 Substation Package Turnkey

i. Six nos. 33/11 kV new substation ii. Twelve nos. 33/11 kV substation upgradation

7 Computer and Computerization Services Turnkey

TotalBPDB = Bangladesh Power Development Board, kV = kilovolt

2.00

1.00

Table A6.2: Part B: BPDB Distribution System in 5 Cities/Towns

Estimated Contract

39.10

Value ($ million)

1.00

12.00

4.50

2.60

16.00

49 Appendix 6, page 3

Contract Item Description Contract No. Type

1 Poles, Conductor Cables and Insulators Supplyi. 33 and 11 kV Poles and Accessoriesii. Conductors iii. 33 and 11 KV Insulators and accessoriesiv. 0.4 kV Insulated Cables and Service Drops

2 Transformers Supply11/0.4 kV Transformers and accessories

3 Meters SupplyLT and HT Three-Phage Meters, Single-Phase Meters, and Meter Seals

4 Substation Materials Supply

5 Computers Supply

TotalkV = kilovolt, HT = high tension, LT = low tension, PBS = Palli Bidyut Samities (rural electric cooperatives).

SWRPP-CP

5.00

0.80

35.95

2.25

0.40

Value ($ million)

27.50

Table A6.3: Part C: Reinforcement of Distribution System in 8 PBSs

Estimated Contract

Appendix 7, page 150

FINANCIAL PERFORMANCE AND PROJECTIONS

A. General

1. The Power Grid Corporation of Bangladesh Ltd. (PGCB) in part A is a limited-liabilitycompany incorporated under the Companies Act 1994. PGCB’s primary role is to own andoperate the country’s transmission network and the National Load Dispatch Center. PGCB is inthe process of receiving assets and staff from the Bangladesh Power Development Board(BPDB), which is expected to be completed by September 2002.

2. In part B, the new company that will be created for the five district towns in the westernregion of Bangladesh, will start up with a “clean” balance sheet as an independent corporationunder the Companies Act, 1994. During the Project period, it will gradually take the over assets,customers database, and energy load from BPDB. Apart from this transfer, the Project will thenprovide financial resources for further investment in an expanded grid that will secure a majorincrease of new connected customers.

3. Part C involves eight rural electric cooperatives or Palli Bidyut Samities (PBSs) thatsurround the five district towns covered by Part B. These PBSs are operated locally as fullyindependent cooperatives, but with extensive support from the government institution, the RuralElectrification Board (REB), regarding technical and financial management, procurement, andgeneral business control. To avoid uneven development between the urban and the rural areas,the Project will provide similar resources to the eight PBSs, aiming for the same targets inachieving improved quality of supply and a major increase of new connected customers, aswell.

B. Past Financial Performance

4. PGCB was incorporated in 1996 as a public limited company with an authorized capitalof Tk10 billion and the paid up capital by the end of FY1999–2000 was Tk938.72 million. DuringFY1999–2000 the company became partially operational, taking over some grid substations andtransmission lines from BPDB and already from the start earning a return on its investments.From the start the company had operational success as a result of the Power Sector ReformProgram initiated by the Government of Bangladesh. PGCB aims to become an efficient gridmanager by acquiring the whole existing transmission system of the country, by establishing anew National Load Dispatch Center, and by constructing new transmission lines andsubstations commensurate with generation growth. For the first operational FY1999-2000,PGCB had a turnover of Tk172.6 million and a net profit before Tax of Tk39.7 million. (Furtherdetails are in the audited annual report for FY1999–2000 in a supplementary appendix.)

5. For part B, BPDB will initially act as the Executing Agency (EA) but as soon as the newcompany is incorporated, and its first executive management appointed according to the loancovenants, the newly created entity will be the actual EA for implementing the Project. The initialoperation of the company will be based on assets, customer database, and energy load thatgradually will be transferred from BPDB. As the available information regarding this specificportion of BPDB’s operation has been very limited, it was not possible to present any completehistorical financial performance reports. From the available basic information – number ofcustomers, energy load, and losses – the focus has been on the financial analysis of the futureprojection. The audited annual report of BPDB for FY1999-2000 is available as a supplementaryappendix.

Appendix 7, page 251

6. REB will be the formal EA for part C being the supporting umbrella institution to theoperational PBSs. As REB will be just administratively, and not financially affected by theproposed project, no further financial analysis have been carried out for this entity. The auditedannual reports for the last years are available as supplementary appendixes. The consolidatedfinancial historical data for the eight PBSs is presented in the projection for FY2000. Due to aless dense customer database and lower load, these rural PBSs show a weaker financialperformance. Despite a much more efficient operation in terms of general management andadministration and much lower losses than those of the urban distribution entities.

C. Financial Projections

1. General

7. The effects of the proposed Project on the financial position of PGCB, the new westzone distribution company, and the eight PBSs have been reflected in the projected financialstatements. Projections were prepared on a nominal basis, based on major assumptionsoutlined in the following paragraphs. The financial projections are in supplementary Appendix A.

8. Domestic inflation rates were assumed to be 4.5 percent and international inflation rates2.4 percent throughout the projections from FY2001.

2. Power Grid Company of Bangladesh (PGCB)

a. Income Statement

9. PGCB’s revenues are derived from transmission of electricity. Transfer of transmissionassets from BPDB has been effected gradually since October 1999 and till September 2002.For the purpose of the financial projections, it was assumed that the transmission tariff will becomputed following a full-cost-recovery methodology. An operation and maintenance provisionwas assumed at 1.5 percent on average fixed asset balance and increased in line with domesticinflation. In addition, depreciation, foreign exchange losses, and taxes were covered by thetariff. It was also assumed that a gross margin on average historical fixed assets of 10 percentconstitutes a reasonable return.

10. It is assumed that PGCB’s operating expenses will include repairs and maintenance,materials and equipment, salaries and wages, contract labor, and administrative charges.Financial projections are based on actual historical figures and a budget prepared by thecompany. Local costs are projected to increase in line with domestic inflation. An averagedepreciation rate of 3 percent per annum is charged, on a declining balance basis, against thehistorical value of fixed assets. The transferred assets from BPDB are computed to betransferred at historical net value after depreciation.

11. Together with the earlier transfer of assets from BPDB, PGCB’s current debt positionwas analyzed, and from available information, an amortization schedule was prepared to projectannual interest expenditure including existing as well as new loans. The company has assumeda debt and an equity portion associated with assets transferred from BPDB. In addition, it willfinance future capital expansion through a combination of equity, domestic and internationaldebt, including supplier’s credit. Interest expense for the project loan is computed on the basisof an ordinary capital resource (OCR) interest charge estimated at 4 percent per annum with alocal mark-up of 1.5 percent per annum. Cofinancing by Kreditanstalt für Wiederaufbau (KfW) of

Appendix 7, page 352

Germany and Nordic Development Fund (NDF) is computed at an interest rate of 0 percent anda local markup of 5.5 percent.

12. For PGCB, income tax is computed at 40 percent of gross profits.

b. Balance Sheet

13. It is assumed that PGCB will maintain its accounts receivables to within two months ofbilling.

14. It is assumed that PGCB will maintain an inventory balance of approximately threemonths use of materials and spare parts.

15. It is assumed that accounts payable will comprise one month’s repairs and maintenance,contract fees, procurement, and administrative charges.

16. Capital expenditures are based on the ongoing capital expenditure and expansionprograms to 2006. Financing for the planned expenditures will be from domestic debt andequity, bilateral assistance, and supplier credit. For purposes of the financial projections, it isassumed that no further investment in capital assets will be made after 2006.

17. PGCB’s existing debt position was analyzed (para. 11) and from available information,an amortization schedule was prepared to project annual interest expenditures, foreignexchange losses and debt-service obligations. It is assumed that the project loan will have a5-year grace period (to coincide with the construction timetable) and a 15-year repaymentperiod.

18. It is assumed that PGCB’s share capital will increase due to partial equity financing ofassets transferred from BPDB to assure an initial accurate equity ratio of roughly 30 percent forthe company.

19. It is assumed that if cash balance at the end of the year exceeds the coming year’sdebt-service requirements, then up to 50 percent of the balance can be distributed as dividends.

3. West Zone Electricity Distribution Company

a. Income Statement

20. It is assumed that the new company will gradually take over distribution assets andcustomer database from BPDB, starting with Khulna town by 2002. The remaining towns willfollow in 2003–2006 along with expansion investment from the Project that will be implementedduring the same period for all five towns. The current customer database is expected toincrease by 15 percent in 2004, and 30 percent annually in 2005–2007. The total increase willbe roughly 147,000-418,000 customers during the implementation period. The tariffs are basedon current tariffs increased by the Tk0.15 increase (approximately 5 percent) in line with thecovenant of this Project. The initial average tariff is computed at Tk3.106 per kilowatt-hour(kWh) and will increase with the local inflation rate. Aside from the increase in new connectedcustomers and in tariffs, the sales are conservatively computed with no expected increase inaverage consumption for all customer categories.

Appendix 7, page 453

21. It is assumed that the new company will continue to purchase its power supply fromBPDB at current price plus Tk0.08 as its share of the expected general increase inend-consumer tariffs. The purchase tariff will increase with local inflation as well. The initialpurchase tariff is computed to be Tk1.99 per KWh. The amount of power purchased will be afunction of consumer demand and system losses. According to BPDB’s records, the currenttechnical and nontechnical system losses, range from 25 percent to 35 percent for the involvedtowns. These losses are expected to conservatively slowly decrease to almost the same levelas for most of the PBSs, 18 percent compared with the PBSs 15 percent. These decreases insystem losses will raise the collection ratio from today’s extremely low 50 percent to theexpected 88 percent from 2010 onwards.

22. Operating costs are computed based on the current actual costs provided by BPDB andinclude operation supervision, engineering, overhead lines and meters, customer installations,and consumer accounts expenditures. Financial projections are based on actual historicalfigures from FY1999-2000 and are computed as a weighted average cost per kWh purchased,assuming these are fully variable costs. This weighted average cost will increase with thedomestic inflation rate.

23. Distribution maintenance costs are based on current actual costs. For the financialprojection, these costs were computed at 1.5 percent of the ending book value of gross assetsuntil the end of the construction period, and will increase with domestic inflation from 2007onward.

24. Based on actual figures, the administrative and general expenditures including salariesand wages are assumed to increase with domestic inflation.

25. The fixed assets are based on transfer of assets from BPDB at net book value afterdepreciation as well as additional investments related to the Project. It was assumed that allassets will be depreciated on a declining balance basis at 3 percent per annum.

26. The company has assumed a 30 percent debt and a 70 percent equity portionassociated with assets transferred from BPDB to ensure a healthy equity ratio from the start.Future capital expansion will be financed through a combination of equity, domestic andinternational debt, as well as supplier’s credit. The interest charges are estimated at 4 percentper annum with a local markup of 1.5 percent per annum on foreign exchange loans. Interest ondomestic loans are computed at the rate of 5.5 percent per annum.

27. For the new west zone distribution company, income tax is computed at 40 percent ofgross profits.

b. Balance Sheet

28. The current accounts receivable for the entire five regions of BPDB, which was the onlyinformation available as of June 2000, on average, represent roughly 14 months' sales. It isassumed that as the new company gain operational experience, it will be able to reduce this, onaverage, to 3 months by 2004-2005, and then to 2 months by 2006-2010, and to 1.5 months by2011 onward. It is assumed that a provision for doubtful accounts will be maintained at 5percent of the total accounts receivable balance.

Appendix 7, page 554

29. It is assumed that the new distribution company will maintain a stock of electricalmaterials of approximately 24 months of distribution expenses less supervision and rentcharges.

30. No specific information on accounts payable was available for the five towns. However,based on actual figures for the entire BPDB, it is assumed that ending accounts payable willreflect 2 months electricity purchase and 5 months of other operating expenses lessdepreciation.

31. Capital expenditures are based on the transfer of assets from BPDB and from theinvestments related to the Project. Financing for the planned expenditures will be from domesticdebt and equity, bilateral assistance, and supplier credit. The financial projections, assumed thatno further investment in capital assets will be made after 2006. A debt and amortizationschedule was prepared based on the terms for these specific loans to project annual interestexpenditures, foreign exchange losses, and debt-service obligations.

32. It is assumed that the new distribution company’s share capital due to partial equityfinancing of assets transferred from BPDB, will be created to assure an accurate initial equityratio of roughly 40-45 percent for the company.

33. It is assumed that future surplus cash generated from the operation of the company willbe invested in further transfer of the remaining towns in the western zone of Bangladesh. Nodividends were considered during the projection period for the company.

3. Rural Electricity Board/Palli Bidyut Samities

a. Income Statement

34. The projection is based on a consolidation of the eight involved PBSs. The currentcustomer database is expected to increase by 10 percent in 2004, 30 percent annually in 2005and 2006 and by 20 percent in 2007. The total increase will be roughly 410,000-980,000customers during the implementation period. The tariffs are computed, based on currentaverage tariffs depending on the customer category mix for the involved PBSs in the range ofTk3.08-Tk3.52 per kWh, and will increase with the local inflation rate. Aside from the increase innew connected customers and in tariffs, the sales are conservatively not computed with anyexpected increase in average consumption for any of the customer categories.

35. It is assumed that the PBSs will continue to purchase their power supply from BPDB andpartially from the new west zone distribution company at the current price, which will increasewith local inflation as well. The initial purchase tariff is computed to be Tk2.16 per kWh in 2002.The amount of power purchased will be a function of consumer demand and system losses.Current technical and nontechnical losses for the eight PBSs range from 9.4 percent to 17.7percent. On the average, these losses are expected to gradually decrease to 15 percent in2008, which is a marginal change to an already very good performance.

36. Operating costs are computed based on the current actual costs for the eight PBSs andinclude operation supervision, engineering, overhead lines and meters, and customerinstallations. Financial projections are based on actual historical figures from FY1999-2000 andare computed as a weighted average cost per kWh purchased (Tk0.092 per kWh in 2002),assuming these are fully variable costs. This weighted average cost will increase with domesticinflation.

Appendix 7, page 655

37. Distribution maintenance costs are based on the current actual costs (0.68 percent onfixed assets value in 2000). For the financial projection, these costs were computed to 0.75percent of the ending book value of gross assets until the end of the construction period and willincrease with domestic inflation from 2007 onward.

38. Consumer accounts expenditures comprising supervision, meter reading, customerrecords/collection, uncollectible accounts, and consumer assistance are based on actual costs.It is assumed that these average costs will be based on weighted average cost per customer(assuming these are fully variable costs) and that they will increase with domestic inflation. Theaverage cost is computed to be Tk166.00 per customer in 2002.

39. Based on actual figures, the administrative and general expenditures, including salariesand wages, are assumed to be approximately Tk60 million per annum in 2001 and will increasewith domestic inflation.

40. It is assumed that all assets will be depreciated on a declining balance basis at 3 percentper annum.

41. The current debt position of the eight PBSs was analyzed. From available information,an amortization schedule was prepared to project annual interest expenditure including existingas well as new loans. Interest expense for the Project is computed on the basis of ADB’sSpecial Funds resources and the interest charges are estimated at 0.75 percent per annumduring an 8-year grace period and at 2.0 percent per annum during the remaining years. Thedomestic loan is computed at the same interest rates as the international loan.

42. Given their cooperative status, the PBSs are exempt from paying the corporate incometax.

b. Balance Sheet

43. Accounts receivable for the eight PBSs, as of June 2000, ranged from 1.3 to 3.1 months.It is assumed that they will be gradually reduced, on average from 2.5 months in 2002 to 2months in 2003-2006, and to 1.5 months in 2007 onward. It is assumed that the provision fordoubtful accounts will be maintained at 5 percent of the total accounts receivable balance.

44. It is assumed that the PBSs on the average will maintain a stock of electrical materials ofapproximately 50 months of distribution expenses, less supervision and rent charges. This is avery high and conservative assumption for an efficiently managed operation even if it is basedon the actual situation, and reflects partially the current difficulties in rapidly accessing reliablesupply of goods.

45. Using historical data, the accounts payable are computed as 1 month of electricitypurchases and 3 months of other operating expenditures.

46. The PBSs existing debt position (para. 41) was analyzed and from available information,an amortization schedule was prepared to project annual interest expenditure and debt-serviceobligations. It is assumed that the loans will have an 8-year-grace period and a 24-yearrepayment period. For the purposes of the financial projections, it is assumed that no furtherinvestment in capital assets will be made after 2006.

Appendix 7, page 756

47. The PBSs have a cooperative ownership structure. Rather than share capital, amember’s equity is derived from the member’s subscriptions. The entire project cost will bepassed on from REB to the PBSs as a loan, denominated in taka, and with concessionaireterms; therefore, no increase in member equity is projected.

48. No dividends for the PBSs were considered in the computations during the projectionperiod.

Appendix 8, page 157

SUMMARY INITIAL ENVIRONMENTAL EXAMINATION

A. Description of the Environment

1. The proposed 230 kilovolt (kV) substation sites at Bogra, Khulna, Ishwardi, andBaghabari are paddy fields occupied by a 63 households, in houses, ranging from permanentbrick and cement structures to temporary corrugated sheet and mud structures. All sites exceptthose at Khulna and Bogra substations, get flooded during the monsoon and therefore do notsupport permanent settlements. At the Bogra site, there is no settlement on the land to beacquired. The routes leading to the substations are low-lying land and are flooded every yearduring the rains. During the dry season, the area is cultivated with paddy crops.

2. The 230 kV transmission lines that will be constructed as part of the Project passthrough typical rural Bangladesh countryside, for a total length of about 450 kilometers (km).While most of the proposed routes pass through open agricultural fields, the lines will traversesome river used for inland water navigation, and some clumps of trees beside some humansettlements. No forest areas are involved. It is estimated that about 35 households, will beaffected.

B. Screening of Potential Environmental Impacts and Mitigation Measures

3. Possible impacts include damage to crops, cutting of trees, demolition of buildings, anddisplacement of persons. These impacts were assessed as not significant and can be mitigatedby (i) minimizing such impact through careful routing of the transmission line, and (ii) payingadequate compensation. The number of persons affected will be reduced through a properdelineation of the sites and their transmission line approaches, as well as by modifying the routealignments. Compensation will be paid to all those to be affected.

4. The following guidelines for tower spotting will be observed:

(i) The alignment will avoid, without exception, known wildlife reserves, closed (orold growth) forests, archaeological sites, religious structures, and educationalinstitutions.

(ii) As far as practicable, the alignment will avoid orchards and houses (permanentor temporary). In particularl, special care will be taken to avoid human settlementclusters. Where orchards are unavoidable, the ground clearance will beincreased to at least 10 meters.

(iii) Where road or river crossing is unavoidable, prescribed vertical and horizontalclearance requirements will be strictly adhered to.

(iv) The proposed alignment will be submitted to at least the following authorities forreview: Archaeological Survey, Wildlife Conservation Agency, Inland WaterTransport Authority, and Highways Department. If no substantive reply isreceived from these authorities within 30 days, it will be presumed that they haveno objection.

Appendix 8, page 258

(v) Compensation in terms of country and Asian Development Bank (ADB) normswill be paid to owners of all property, including crops, orchard trees, homesteads,water sources, etc. following prescribed procedures.

5. Based on ADB’s guidelines for land acquisition and resettlement, the following principleswere identified as applicable to the Project:

(i) The principal objective of involuntary settlement policies is to ensure thatpopulations affected by the Project should be at least as well off, as they wouldbe without the Project, if not better off. Affected populations should be able tomaintain or preferably, improve their standard of living and quality of life.

(ii) People affected by the Project are defined as those who, as a consequence ofthe Project, stand to lose all or part of physical and nonphysical assets, includinghomes, homesteads, productive lands, commercial properties, tenancy, income-earning opportunities, social and cultural activities and relationships, and otherlosses that may be identified during resettlement planning. A socioeconomicsurvey to be carried out as part of the resettlement planning process, willrepresent the cutoff date for compensation eligibility for physical assets asidentified during the survey. Affected populations will be involved in the processof developing and implementing the resettlement plans through the process ofthe socioeconomic survey. Affected populations will receive fair (market-basedreplacement cost) compensation for all losses, including physical andnonphysical assets. Compensation will include not only immediate losses, butalso opportunities forgone. Affected populations that stand to lose only part oftheir physical assets will not be left with a proportion that will be inadequate tosustain their current standard of living, such a minimum size being identified andagreed upon during the resettlement planning process.

(iii) All affected populations will be eligible for compensation and mitigativemeasures, irrespective of tenurial status, social or economic standing, and anysuch factors that may discriminate against achieving the objectives mentionedabove.

(iv) Involuntary resettlement will be minimized by identifying possible alternativeproject designs; and appropriate social, economic, operational, and engineeringsolutions that have the least impact on populations in the project area. Aresettlement plan for the affected populations should identify among other things,those affected, all losses that might be incurred, and appropriate mitigativemeasures. The plan should include detailed implementation schedules that arealso consistent with available and projected budgetary outlays and constructionschedules.

(v) Adequate budgetary support will be fully committed and be made available tocover the cost of land acquisition within the agreed upon implementation period.

(vi) Construction activities will not commence until the required lands have been fullyacquired and populations appropriately relocated in accordance with theforegoing.

Appendix 8, page 359

(vii) Appropriate reporting, monitoring, and evaluation mechanisms will be identifiedand set in place as part of the resettlement management system. Theresettlement process and the final outcome will be evaluated independent of theExecuting Agency.

C. Institutional Requirement and Environmental Monitoring Program

6. Since the impact is small, the environment monitoring program will be limited to thecompensation to be paid to affected persons. This will be done by the Power Grid Company ofBangladesh, which will prepare summary reports every six months, to be verified by ADBmissions.

D. Resettlement Plan

7. A Resettlement Plan, in accordance with ADB Guidelines of Resettlement and the lawsof Bangladesh has been prepared and approved by the PGCB.

Appendix 9, page 160

OUTLINE TERMS OF REFERENCE FOR TECHNICAL ASSISTANCE

A. Scope of Work

1. The work is divided into two parts. The first covers the development of the overallapproach to corporatization, the legal and accounting formalities required for the transferof the assets and personnel of the west zone distribution system from the BangladeshPower Development Board (BPDB) to an independent company; and details theoperational and management information systems (MIS) required in the new companyand help in implementing this corporatization. The second part comprises engineeringassistance to the new company by way of developing expansion and modernizationprograms, preparing specifications and bid documents; assistance in bid evaluation; andimprovement of operation and maintenance standards by implementing a qualityassurance program, preparing manuals, and conducting training,

1. Management Assistance

2. The consultant’s first task involves three components to facilitate thecorporatization of the west zone distribution system.

(i) Suggest methodology and approach, activities, time schedule, duties andtasks of relevant agencies to implement the process of corporatization.

(ii) Prepare all necessary legal instruments and suggest organizationalrelationships with various agencies, accountability, and modus operandifor the new company (this will include drafting the power purchaseagreement between BPDB and the new company for sale of power fromBPDB to it, documents for transfer of staff from BPDB to the newcompany).

(iii) Identify the total investment in the new company, prepare a list of assetsand liabilities and other necessary accounting and financial statement toreflect its financial position (do not revalue the assets but do value theassets based on written down book values and expected residual lives ofstation components).

3. After the process of corporatization is initiated, the consultant’s next task will beto study, recommend, and help implement management systems for the new company.The specific tasks follows:

(i) Review and design an effective organizational structure.

(ii) Study the manpower needs and skills mix, and prepare work standards, aperformance appraisal system, and a computerized personnel MIS.

(iii) Design a financial management system including a budget, budgetarycontrol, incentive schemes; delegating administrative and financial

Appendix 9, page 261

powers; prepare a 10-year financial forecast, including suggestions forraising capital to fulfill the plan.

(iv) Prepare daily and monthly computerized MIS reporting formats andsystems to enable the management to focus on key issues and not onroutine operations.

(v) Assist the management to implement the recommended managementsystems.

(vi) Evaluate social impacts on stakeholders, particularly the staff; in case ofadverse impacts, advise management on the measures to mitigate theseimpacts.

2. Operational Assistance

4. The consultant will provide the following engineering assistance to the newcompany:

(i) Review designs for system modernization, upgrading and expansion inKhulna City.

(ii) Design and implement a quality assurance system for smooth andefficient operation of the system, including preparation of standards andmanuals for operation and maintenance.

(iii) Assess training needs for the technical personnel of the new company;design training courses, including development of curriculum andpreparation of training manuals.

5. The consultant will coordinate the engineering and managerial support to thenew company to establish optimum and compatible operations and managementprocedures.

B. Implementation Arrangements

6. The work will begin on 1 November 2001 and be completed by March 2003. Theconsultant will submit the following reports to the executing agencies (EAs) and theAsian Development Bank (ADB):

(i) An inception report, within one month after the technical assistance (TA)starts. The report will outline a detailed work program and briefly describethe work steps proposed to fulfill the terms of reference. The first tripartitemeeting will follow the submission of this report.

(ii) A midterm report within six months after the TA starts. To report the

progress achieved, person-months utilized, any problems encountered,

Appendix 9, page 362

and proposed work plan revision, if required. It will incorporate detailedreports on completion of activities in part A.

(iii) A draft final report, with details of the consultants’ findings and

recommendations, within 15 months after the TA starts. The secondtripartite meeting with the consultants, the EA, and ADB will be held todiscuss final revisions to this draft.

(iv) A final report, which will incorporate all revisions required by the

consultants following the receipt of comments on the draft final reportfrom the EA, ADB, and other agencies.

(v) Engineering design reports, specifications, training programs, and qualityassurance program manual.

7. The consultant will organize a workshop for stakeholders after the first tripartitemeeting in Khulna to brief them and to receive their feedback on (i) the program forcorporatization, and (ii) the MIS and procedures that will be implemented. The consultantwill organize a seminar in Dhaka at the conclusion of the TA to disseminate its findingsto senior officials of the Government.

Appendix 1063

TA COST ESTIMATES AND FINANCING PLAN($'000)

Item Foreign Local TotalExchange Currency Cost

A. Asian Development Bank Financing a

1. Consultantsa. Remuneration

i. International Consultant 550.0 � 550.0ii. Domestic Consultants � 100.0 100.0

b. Per Diemi. International Consultant 50.0 � 50.0ii. Domestic Consultants � 5.0 5.0

c. Travel 30.0 _ 30.0d. Reports and communications 10.0 5.0 15.0

2. Seminars/ Workshops/Training 20.0 5.0 25.03. Representatives for Contract Negotiations 5.0 _ 5.04. Contingencies 100.0 20.0 120.0

Subtotal (A) 765.0 135.0 900.0

B. Government Financing1. Office accommodation and Transport 50.0 50.02. Counterpart Staff - 200.0 200.03. Administrative Support - 50.0 50.04. Contingencies - 50.0 50.0

Subtotal (B) - 350.0 350.0

Total 765.0 485.0 1,250.0

� = magnitude zeroa From the ADB-funded TA Program.Source: ADB estimates.

64 Appendix 11

Item 2002 Increment 2008

Customer SummaryBPDB 154,608 263,830 418,438 REB/PBSs Jessore-1 77,619 107,862 185,481 Jessore-2 72,048 100,120 172,168 Barisal-1 36,588 50,845 87,433 Barisal-2 43,092 59,882 102,974 Bagerhat 44,162 61,369 105,531 Faridpur 28,308 39,368 67,676 Kushtia 55,066 76,522 131,588 Meherpur 53,956 74,980 128,936 Total REB/PBSs 410,839 570,948 981,787

Energy Sales (MWh)BPDB 827,211 1,768,429 2,595,640 REB/PBSs Jessore-1 67,538 119,577 187,115 Jessore-2 58,495 103,567 162,062 Barisal-1 15,315 27,115 42,430 Barisal-2 30,993 54,875 85,868 Bagerhat 27,278 48,296 75,574 Faridpur 17,459 30,912 48,371 Kushtia 33,825 59,887 93,712 Meherpur 31,407 55,606 87,013 Total REB/PBSs 282,310 499,835 782,145

BPDB = Bangladesh Power Development Board, PBS = Palli Bidyut

Samities (rural electricity cooperatives), REB = Rural Electricity Board)

CONSUMER CONNECTION SUMMARY

Appendix 12, page 165

PROJECT FINANCIAL ANALYSIS

1. The financial evaluation of the Project was carried out in real terms. The project costestimates and financial projections in nominal terms were converted to real terms by adjustingfor the effects of foreign and domestic inflation and currency fluctuations.

A. Financial Internal Rate of Return

2. The financial internal rates of return (FIRRs) for the project components are calculatedover a 20-year period (5-year construction period plus 15 years of operations) on an after-taxbasis. In determining the FIRR, no residual value was computed, given the nature of the projectinvestment. The FIRR calculations are in Tables A12.1, A12.2, and A12.3.

Capital TaxYear Investment Inflows Outflows Adjustment Net2002 1,323 (1,323)2003 3,763 (3,763)2004 3,593 (3,593)2005 2,434 547 137 (2,024)2006 1,199 957 137 (379)2007 1,943 137 1,8062008 1,921 465 1,4562009 1,898 465 1,4332010 1,875 465 1,4102011 1,853 465 1,3882012 1,830 465 1,3652013 1,807 465 1,3422014 1,785 465 1,3202015 1,762 465 1,2972016 1,739 465 1,2742017 1,717 465 1,2522018 1,694 465 1,2292019 1,671 465 1,2062020 1,649 465 1,1842021 1,626 465 1,161

FIRR 6.6%FIRR = financial internal rate of return.

Table A12.1: FIRR Calculation for PGCB (Tk million)

Appendix 12, page 266

Capital TaxYear Investment Inflows Outflows Adjustment Net2002 330,020 (330,020)2003 1,091,100 (1,091,100)2004 1,091,100 (1,091,100)2005 757,060 16,289 6,516 (747,286)2006 362,350 424,724 375,624 (313,250)2007 1,494,836 1,318,330 (49,091) 225,5972008 2,950,637 2,593,116 (44,694) 402,2152009 4,806,424 4,280,581 (43,752) 569,5952010 4,901,033 4,358,310 (44,752) 587,4752011 4,997,524 4,442,659 (48,132) 602,9962012 5,095,934 4,531,703 (52,690) 616,9212013 5,197,831 4,623,123 (56,614) 631,3222014 5,288,736 4,704,495 (61,030) 645,2712015 5,380,550 4,786,665 (65,939) 659,8242016 5,473,282 4,869,644 (71,352) 674,9902017 5,563,228 4,951,957 (77,262) 688,5332018 5,563,228 4,952,238 (83,611) 694,6012019 5,563,228 4,952,510 (90,370) 701,0882020 5,563,228 4,952,775 (97,534) 707,9872021 5,563,228 4,953,032 (105,077) 715,273

FIRR 10.0%FIRR = financial internal rate of return.

Table A12.2: FIRR Calculation for New Company(Tk'000)

Capital TaxYear Investment Inflows Outflows Adjustment Net2002 304,370 (304,370)2003 914,180 (914,180)2004 914,460 (914,460)2005 609,270 78,041 60,057 (591,286)2006 304,830 431,443 332,031 (205,418)2007 913,303 702,860 210,4432008 1,345,451 1,023,255 322,1962009 1,372,494 1,043,818 328,6762010 1,400,081 1,064,800 335,2812011 1,428,223 1,086,204 342,0192012 1,456,930 1,108,032 348,8982013 1,485,230 1,129,554 355,6762014 1,513,812 1,151,295 362,5172015 1,542,680 1,173,247 369,4332016 1,571,837 1,195,422 376,4152017 1,571,837 1,195,422 376,4152018 1,571,837 1,195,422 376,4152019 1,571,837 1,195,422 376,4152020 1,571,837 1,195,422 376,4152021 1,571,837 1,195,422 376,415

FIRR 5.9%FIRR = financial internal rate of return, PBS = Palli Bidyut Samities (rural electricity cooperatives).

Table A12.3: FIRR Calculation for Ei ght PBSs(Tk'000)

Appendix 12, page 367

B. Weighted Average Cost of Capital

3. The weighted average cost of capital (WACC) was calculated in real terms based on thecapital composition in Table A12.4.

4. The cost of ordinary capital resources debt was calculated based on an interest rate of4.0 percent per annum, a local markup of 1.5 percent per annum, and an income tax rate of 40percent per annum on part A and part B. Part C (PBSs) is computed with an income tax rate of0 percent per annum.

5. For part B, the cost of Special Funds resources was calculated based on an interest rateof 4.0 percent per annum, a local markup of 1.5 percent per annum during the grace period andthereafter. For Part C, the cost of Special Funds resources was calculated based on an interestof 1.0 percent per annum, and with no markup during the grace period and thereafter with 1.5percent and 0.5 percent, respectively.

6. On this basis, and using an average outstanding loan balance per annum over the life ofthe loan, the cost of total foreign debt in real terms was computed to be 2.17 percent for part A,0.07 percent for part B, and negative for part C.

7. The costs of the Government debt for parts A and B were calculated based on aninterest rate of 5.5 percent per annum, an income tax rate of 40 percent per annum, and anaverage domestic inflation rate of 4.5 percent per annum. On this basis, and using an averageoutstanding loan balance per annum over the life of the loan, the cost of the Government debt inreal terms was computed to be 0.11 percent for part A and 0 percent for part B.

8. The cost of the Government debt for part C was calculated based on an interest rate of0.75 percent per annum for the first 8 years and 2.0 percent for the remaining years, an averagedomestic inflation rate of 4.5 percent per annum. On this basis, and using an averageoutstanding loan balance per annum over the life of the loan, the cost of the Government debt,in real terms was computed to be even negative.

9. The opportunity of equity in Bangladesh, in real terms, was calculated on the basis ofcurrent long-term savings rates (13 percent) adjusted by adding a risk premium of 3 percent perannum and taking into account an average domestic inflation rate of 4.5 percent per annum.

Financing Source Part A Part B Part C TotalADB-OCR Loan 6,812.2 1,653.9 8,466.1ADB-ADF Loan 1,160.2 2,510.9 3,671.1KFW 1,830.9 1,830.9NDF 610.3 610.3Suppliers Credit 1,149.2 1,149.2Government Loan 1,917.1 548.0 1,123.9 3,589.0Equity 3,705.4 1,171.4 4,876.8

Total 16,025.1 4,533.5 3,634.8 24,193.4ADB = Asian Development Bank, ADF = Asian Development Fund,KfW = Kreditanstalt für Wiederaufbau of Germany, NDF = Nordic Development Fund, OCR = Ordinary Capital Resources.

Table A12.4: Weighted Average Cost of Capita(Tk million)

Appendix 12, page 468

This interest rate is the same as the demanded rate of return for risk investments in the privatesector.

10. Based on the above, the WACCs were estimated to be 3.96 percent for part A,2.84 percent for part B, and negative for part C.

C. Conclusion

11. The FIRR is expected to comfortably exceed the WACC for each project component(both computed on an after-tax basis). Given the overall objectives of the Project, the financialperformance is deemed acceptable.

Appendix 13, page 169

ECONOMIC EVALUATION

1. An economic evaluation of the Project’s transmission and distributioninvestments was undertaken. Details of the Economic Internal Rate of Return (EIRR)calculations are in Table A13.1 and the sensitivity analysis are given in Table A13.2.

2. The Project targets urban and particularly rural areas; therefore, the consumersegments and their proportions differ for the Bangladesh Power Development Board(BPDB) and Rural Electricity Board (REB) investment portions and are calculatedseparately. The major towns have only three major consumer segments: domestic,commercial, and industrial. For the REB areas, there is also a significantly largeagricultural consumer segment for which economic benefits were also calculated.

3. Customers suffer from not only load shedding but also fluctuating voltage levelsand generally poor quality of supply. In addition to improving the quality and quantity ofsupply, the Project will also provide for new connections, particularly under the REBinvestment component in predominantly rural areas. The vast majority of newconsumers will be added in the first three years after construction is completed; afterthat the growth rate of new connections will drop back to the normal level of about 1percent. Benefits for the new customers were valued at their economic replacementcost, that is the alternative economic costs of other energy source such as captivepower plants for industrial users or kerosene lamps for domestic consumers. It isexpected that when load shedding is completely eliminated and reliable electricity supplyis created, there will be increased purchase of more sensitive electrical appliances likerefrigerators for domestic consumers or production equipment for industries.

4. Induced consumption was valued by estimating the consumer’s willingness topay for incremental electricity supply and adding the related consumer surplus benefitsto the tariff-based revenues. For reasons of convenience, frequently, the relevantdemand curve segment is treated as linear to simplify the arithmetic calculations.However, to reflect the demand price elasticity for the various categories of consumers,in this evaluation only a portion of the maximum consumer’s surplus benefits is assumedfor the valuation of induced sales. This is arithmetically expressed by using differentcurvature factors for different consumer categories, all of which are smaller than 0.5.

5. Alternative sources of power used by the four major consumer segments weredetermined and their respective costs were estimated. The dominant sources ofalternative power in the domestic sector are kerosene lamps and in the urban areas alsoinverter batteries. Private ownership of small diesel generators is very low throughoutBangladesh and is found only among very high-income urban consumers and thuscannot be considered for estimating the willingness to pay. A large proportion of totalend-consumption in the domestic sector is for lighting purposes and to run smallappliances like TV sets, fan, and radio. During power cuts or in non-electrified areas,electricity is substituted almost exclusively for lighting purposes. Therefore, consumptionin the domestic sector was valued based on the use of kerosene lamps, using thewillingness-to-pay method plus the related consumer surplus with a curvature factor of0.3. Consumer surplus was estimated at Tk3.22/kilowatt-hour (kWh) for REB customersand at Tk2.82/kWh for BPDB consumers, reflecting the different tariffs levels of the twodistribution units.

Appendix 13, page 270

6. Inverter batteries are the alternative energy source in the commercial sectorsince it can be used to operate small appliances that are typically used in smallcommercial establishments, like fans, TV sets, and radios in addition to lighting purpose.Since the project area is generally less economically developed, use of small generatorsfor commercial establishments is unlikely, given the high up-front capital cost ofpurchase and installation. The financial cost of using inverter batteries was estimated atTk5.9 per kWh. A curvature factor of 0.4 was used in the calculations.

7. Inquiries made with BPDB and REB found that the industry sector in the projectarea consists mainly of smaller industrial establishments that have not investedsubstantially in captive power. According to the two utilities, the typical captive powerfacility is a small diesel generator set of approximately 40 kilowatts. Textile mills wouldbe the user of this type of generator. The financial cost of such a generator wasestimated to be Tk5.5/kWh and as for the commercial segment, a curvature factor of 0.4was used.

8. For the purposes of the economic analysis, the estimated capital costs of thetransmission and distribution components were broken down into direct foreignexchange items, indirect foreign exchange, and local goods and services. All costselements were valued in border prices, using a domestic currency numeraire, with alltaxes and duties excluded, a standard conversion factor of 0.855 being applied tonontraded items, and a labor conversion factor of 0.8 being used for unskilled labor and1.1 for skilled labor. Operating costs were calculated as a fixed percentage of economicinvestment cost, using 1 percent for the transmission component and 5 percent for thedistribution investments. Operating costs are building up gradually until the constructionperiod is completed.

9. The economic benefits of transmission and distribution facilities required toevacuate power from new generation projects, such as the proposed independent powerproducers (IPPs), are difficult to determine independently. Transmission and distributionare integral parts of the total power system development plan and not independentinvestments. The EIRR on the complete investment required in new generation projectsplus associated transmission and distribution are normally considered as representativeof the rate of return on transmission and distribution investments, as they are typicallyonly a part of the total investment.

10. Therefore, the economic evaluations of transmission and distributioncomponents include economic send-out costs of power. The Project aims specifically toconstruct transmission and distribution facilities needed to evacuate power from newlyproposed IPP projects for which no financial closure has been arrived at yet and thus, notakeoff prices are available. Power input costs are valued at the long-run marginal cost(LRMC) generation level for IPP plants that have already reached financial closure at$0.375/kWh.

11. On the basis of a comparison of economic costs and benefits over a 20-yearproject lifetime, including a five-year construction period, the EIRR was estimated at19.30 percent with a net present value (NPV) of Tk6,495 million. Extensive sensitivitytesting was carried out and found that the Project is robust for all of the tested variables.

12. Sensitivity testing found a comfortable switching value for increases in capitalcosts of 59 percent, and of 24 percent for increase in energy input prices. Testing for

Appendix 13, page 371

changes in curvature factors for the different consumer categories as well as forchanges of fuel input prices for selected captive generation did not lead to significantdeterioration in the EIRR.

72A

ppendix 13, page 4

Table A13.1: Economic Evaluation of the Bangladesh West Zone Power System Development Project(Tk million)

Capital Cost Operating Cost BenefitsYear Transmission Distribution Transmission Distribution

GenerationImport

Total CostBPDB REB

TotalBenefits

NetBenefits

PGCB BPDB REB PGCB BPDB REB

2002 1,051 255 238 1,544 -1,5442003 2,975 807 718 11 13 12 4,534 0 -4,5342004 2,827 807 718 40 53 48 4,492 0 -4,4922005 1,922 553 478 69 93 84 2,805 6,005 4,257 102 4,359 -1,6452006 943 269 238 97 121 108 3,704 5,481 5,296 566 5,862 3812007 97 134 120 4,638 4,989 6,574 1,199 7,773 2,7832008 97 134 120 5,770 6,121 8,151 1,766 9,916 3,7952009 97 134 120 5,826 6,178 8,309 1,801 10,110 3,9322010 97 134 120 5,940 6,291 8,470 1,837 10,307 4,0162011 97 134 120 6,056 6,407 8,634 1,874 10,508 4,1012012 97 134 120 6,174 6,526 8,801 1,912 10,713 4,1882013 97 134 120 6,296 6,648 8,976 1,949 10,925 4,2782014 97 134 120 6,421 6,772 9,164 1,987 11,150 4,3782015 97 134 120 6,547 6,899 9,336 2,025 11,360 4,4622016 97 134 120 6,676 7,027 9,521 2,063 11,584 4,5562017 97 134 120 6,887 7,238 9,700 2,063 11,763 4,5252018 97 134 120 6,887 7,238 9,700 2,063 11,763 4,5252019 97 134 120 6,887 7,238 9,700 2,063 11,763 4,5252020 97 134 120 6,887 7,238 9,700 2,063 11,763 4,5252021 97 134 120 6,887 7,238 9,700 2,063 11,763 4,525

EIRR: 19.30% NPV: 6,495

BPDB = Bangladesh Power Development Board, EIRR = economic internal rate of return, PGCB = Power Grid Company of Bangladesh, REB = Rural ElectricityBoard.

Appendix 13, page 573

Table A13.2: Sensitivity Analysis

Variable Change inVariable

EIRR%

SwitchingValue

NPV(Tk million)

Base Case 19.3 6,495

Capital Cost +10% 17.71 59% 5,419+20% 16.31 4,343

Benefit Side:Curvature Factor atDomestic 0.2 18.90 6,126

0.4 19.67 6,864Commercial 0.3 19.24 6,438Industry 0.3 18.40 5,622Agriculture 0.3 19.25 6,441

System Losses:No reduction 17.53 4,669

Energy Input Price+10% 16.43 24 % 3,770- 10% 21.98 9,220

Implementation 1 year 18.35 5,458Delay 2 years 16.44 4,120

Captive Fuel InputIndustry

+10% 21.25 8,464-10% 17.25 4,526

Domestic+10% 19.85 7,045-10% 18.75 5,945

EIRR = economic internal rate of return, NPV = net present value.

(Tk '000)SALES 2000 2001 2002 2003 2004 2005 2006 2007

Actual Actual Projected Projected Projected Projected Projected ProjectedTransmission Revenues 172,603 556,235 994,247 1,650,440 2,549,216 4,020,726 5,667,166 7,334,286Other Income 26 19,601 27 28 30 31 32 34

172,629 575,836 994,274 1,650,468 2,549,246 4,020,757 5,667,198 7,334,320OPERATING EXPENSESOperating and Maintenance Repairs and maintenance 8,095 24,814 62,198 92,165 143,330 211,537 320,233 408,081 Spare parts and materials 0 0 24,879 36,866 57,332 84,615 128,093 163,232

8,095 24,814 87,078 129,031 200,662 296,152 448,327 571,313Salaries and wages 8,628 10,639 25,059 194,577 424,970 454,517 474,970 496,343Contract employees 0 0 67,925 70,982 74,176 77,514 81,002 84,647Administrative charges 3,988 1,189 39,710 41,497 43,364 45,316 47,355 49,486Depreciation 44,577 172,196 197,177 291,449 451,720 666,336 1,007,537 1,290,437Amortization 0 1,387 154 154 154 154 154 154

65,288 210,225 417,103 727,690 1,195,047 1,539,988 2,059,344 2,492,381OPERATING INCOME 107,341 365,611 577,171 922,779 1,354,199 2,480,769 3,607,854 4,841,939Non-Operating Income/(Expense) 0 0 0 0 0 0 0 0Interest Revenue 2,500 0 147,346 269,992 270,669 303,486 325,198 321,493Foreign exchange gain(loss) 0 0 0 0 0 (264,503) (136,092) (153,629)Net inc, before int and taxes 109,841 365,611 724,517 1,192,771 1,624,868 2,519,751 3,796,960 5,009,804Interest Expense - Foreign 0 0 0 0 270,975 676,837 1,012,085 1,204,072Interest Expense - Local 70,129 224,443 287,919 373,424 378,578 801,961 1,061,920 1,047,111Income Tax Expense 15,885 56,467 115,701 219,742 281,858 294,987 559,103 974,851Net Income 23,827 84,701 320,897 599,605 693,457 745,966 1,163,852 1,783,770Retained earnings, beginning 0 23,827 108,528 429,425 1,029,030 1,722,487 2,468,454 3,632,306Dividends 0 0 0 0 0 0 0 200,000Undistributed Profit, ending 23,827 108,528 429,425 1,029,030 1,722,487 2,468,454 3,632,306 5,216,076

Operating Margin (%) 62.18 63.49 58.05 55.91 53.12 61.70 63.66 66.02Net Margin (%) 13.80 14.71 32.27 36.33 27.20 18.55 20.54 24.32Ave Fixed Assets to Sales 165.90 17.64 19.36 18.62 18.43 19.68 18.30 18.69Return on Ave Fixed Assets 22.90 2.59 6.25 6.76 5.01 3.65 3.76 4.55Return on Ave Equity 2.07 4.85 6.25 6.24 5.27 4.51 5.94 8.00

Operating Margin % Sales = operating profit / net salesAve fixed assets to sales = sales / ((opening fixed assets+closing fixed assets) /2)Return on Ave Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)Return on Ave Equity = net income / ((opening total equity + closing total equity) / 2)

Supplem

entary Appendix A

, page 1POWERGRID COMPANY OF BANGLADESH LTD.TABLE A1a: PROJECTED INCOME STATEMENT

For the Years Ending 30 June 2001-2021

(Tk '000)SALES 2008 2009 2010 2011 2012 2013 2014 2015

Projected Projected Projected Projected Projected Projected Projected ProjectedTransmission Revenues 10,675,755 12,539,775 10,933,312 14,359,128 14,805,953 15,166,308 15,499,729 15,822,779Other Income 35 37 39 40 42 44 46 48

10,675,790 12,539,812 10,933,351 14,359,168 14,805,995 15,166,352 15,499,775 15,822,827OPERATING EXPENSESOperating and Maintenance Repairs and maintenance 547,377 654,801 663,552 672,011 660,986 649,962 638,938 627,914 Spare parts and materials 218,951 261,920 265,421 268,804 264,395 259,985 255,575 251,166

766,328 916,721 928,972 940,815 925,381 909,947 894,513 879,080Salaries and wages 543,501 567,959 593,517 639,389 668,161 698,228 729,649 762,483Contract employees 88,456 92,437 96,596 100,943 105,485 110,232 115,193 120,376Administrative charges 51,713 54,040 56,472 59,013 61,668 64,443 67,343 70,374Depreciation 1,734,341 2,087,930 2,146,379 2,204,828 2,204,828 2,204,828 2,204,828 2,204,828Amortization 154 154 0 0 0 0 0 0

3,184,493 3,719,240 3,821,936 3,944,987 3,965,524 3,987,679 4,011,526 4,037,141OPERATING INCOME 7,491,297 8,820,572 7,111,415 10,414,181 10,840,471 11,178,673 11,488,249 11,785,686Non-Operating Income/(Expense) 0 0 0 0 0 0 0 0Interest Revenue 340,100 404,738 486,244 578,126 673,833 783,317 916,031 1,084,280Foreign exchange gain(loss) (637,988) (431,195) 2,264,626 (368,501) (350,870) (329,050) (306,036) (281,823)Net inc, before int and taxes 7,193,410 8,794,116 9,862,286 10,623,806 11,163,434 11,632,940 12,098,244 12,588,144Interest Expense - Foreign 1,756,844 1,590,406 1,427,579 1,235,200 1,040,383 843,081 653,751 498,950Interest Expense - Local 1,486,920 1,475,577 1,475,396 1,384,081 1,284,537 1,177,700 1,068,601 957,162Income Tax Expense 1,443,818 2,129,358 2,589,226 2,970,560 3,265,873 3,531,537 3,783,944 4,019,101Net Income 2,505,828 3,598,775 4,370,085 5,033,965 5,572,641 6,080,622 6,591,948 7,112,931Retained earnings, beginning 5,216,076 7,221,904 10,120,678 13,590,763 17,524,728 21,797,369 26,377,991 31,269,939Dividends 500,000 700,000 900,000 1,100,000 1,300,000 1,500,000 1,700,000 1,900,000Undistributed Profit, ending 7,221,904 10,120,678 13,590,763 17,524,728 21,797,369 26,377,991 31,269,939 36,482,870

Operating Margin (%) 70.17 70.34 65.04 72.53 73.22 73.71 74.12 74.49Net Margin (%) 23.47 28.70 39.97 35.06 37.64 40.09 42.53 44.95Ave Fixed Assets to Sales 20.32 20.09 17.57 23.16 24.76 26.33 27.98 29.75Return on Ave Fixed Assets 4.77 5.77 7.02 8.12 9.32 10.56 11.90 13.37Return on Ave Equity 10.20 13.17 14.24 14.64 14.48 14.17 13.83 13.49

Operating Margin % Sales = operating profit / net salesAve fixed assets to sales = sales / ((opening fixed assets+closing fixed assets) /2)Return on Ave Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)Return on Ave Equity = net income / ((opening total equity + closing total equity) / 2)

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, page 2TABLE A1a: PROJECTED INCOME STATEMENT (Cont'd.)

POWERGRID COMPANY OF BANGLADESH LTD.

For the Years Ending 30 June 2001-2021

(Tk '000)SALES 2016 2017 2018 2019 2020 2021 2022

Projected Projected Projected Projected Projected Projected ProjectedTransmission Revenues 16,131,658 16,421,280 16,687,253 16,936,824 17,183,350 17,429,943 17,683,187Other Income 50 52 55 57 60 63 65

16,131,708 16,421,332 16,687,308 16,936,881 17,183,410 17,430,006 17,683,252OPERATING EXPENSESOperating and Maintenance Repairs and maintenance 616,890 605,866 594,842 583,817 572,793 561,769 550,745 Spare parts and materials 246,756 242,346 237,937 233,527 229,117 224,708 220,298

863,646 848,212 832,778 817,344 801,911 786,477 771,043Salaries and wages 796,794 832,650 870,120 909,275 950,192 992,951 1,037,634Contract employees 125,793 131,454 137,369 143,551 150,011 156,761 163,816Administrative charges 73,541 76,850 80,308 83,922 87,699 91,645 95,769Depreciation 2,204,828 2,204,828 2,204,828 2,204,828 2,204,828 2,204,828 2,204,828Amortization 0 0 0 0 0 0 0

4,064,602 4,093,994 4,125,403 4,158,921 4,194,640 4,232,662 4,273,089OPERATING INCOME 12,067,106 12,327,338 12,561,904 12,777,961 12,988,770 13,197,343 13,410,163Non-Operating Income/(Expense) 0 0 0 0 0 0 0Interest Revenue 1,288,378 1,526,304 1,786,669 2,063,536 2,357,384 2,663,490 2,990,970Foreign exchange gain(loss) (256,421) (231,347) (203,348) (174,159) (144,712) (112,928) (80,923)Net inc, before int and taxes 13,099,064 13,622,295 14,145,226 14,667,338 15,201,442 15,747,906 16,320,210Interest Expense - Foreign 391,848 320,376 270,219 219,596 168,464 115,162 59,386Interest Expense - Local 843,307 735,771 634,385 535,839 440,102 343,351 258,925Income Tax Expense 4,230,212 4,415,938 4,581,581 4,739,347 4,894,197 5,050,361 5,204,372Net Income 7,633,697 8,150,210 8,659,041 9,172,556 9,698,679 10,239,032 10,797,527Retained earnings, beginning 36,482,870 42,016,567 47,866,777 54,025,818 60,498,374 67,297,053 74,436,085Dividends 2,100,000 2,300,000 2,500,000 2,700,000 2,900,000 3,100,000 3,300,000Undistributed Profit, ending 42,016,567 47,866,777 54,025,818 60,498,374 67,297,053 74,436,085 81,933,612

Operating Margin (%) 74.80 75.07 75.28 75.44 75.59 75.72 75.84Net Margin (%) 47.32 49.63 51.89 54.16 56.44 58.74 61.06Ave Fixed Assets to Sales 31.64 33.66 35.83 38.17 40.75 43.62 46.83Return on Ave Fixed Assets 14.97 16.71 18.59 20.67 23.00 25.62 28.60Return on Ave Equity 13.14 12.78 12.41 12.05 11.72 11.41 11.13

Operating Margin % Sales = operating profit / net salesAve fixed assets to sales = sales / ((opening fixed assets+closing fixed assets) /2)Return on Ave Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)Return on Ave Equity = net income / ((opening total equity + closing total equity) / 2)

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POWERGRID COMPANY OF BANGLADESH LTD.TABLE A1a: PROJECTED INCOME STATEMENT (Cont'd.)

For the Years Ending 30 June 2001-2021

(Tk '000)2000 2001 2002 2003 2004 2005 2006 2007

CASH INFLOWS: Actual Actual Projected Projected Projected Projected Projected ProjectedFrom operations 26,806 316,516 925,777 1,595,757 2,474,318 3,898,100 5,529,963 7,195,359Received from BPDB 0 0 0 0 0 0 0 0Loan Proceeds 336,071 3,581,900 6,918,720 8,949,190 10,008,990 10,229,890 7,986,070 5,415,380Equity infusions 186,000 1,696,340 4,672,226 2,765,678 3,044,556 2,309,261 1,878,189 746,160Other Income 26 26 27 28 30 31 32 34Interest revenue 2,500 0 10,561 147,346 269,992 270,669 303,486 325,198Total Cash Inflows 551,403 5,594,782 12,527,311 13,457,999 15,797,886 16,707,951 15,697,740 13,682,131

CASH OUTFLOWS:Operating Expenses (84,537) 414,163 194,030 434,946 741,721 871,779 1,049,044 1,200,016Purchase of fixed assets 563,605 5,278,240 5,094,120 13,168,246 12,798,208 13,083,146 10,516,851 7,517,249Repayment of debt 0 0 286,127 286,127 616,773 754,273 1,679,255 2,800,770Interest payments 8,431 90,922 224,488 330,672 511,488 1,064,176 1,776,401 2,162,594Taxes 0 15,885 0 115,701 219,742 281,858 294,987 559,103Total Cash Outflows 487,499 5,799,210 5,798,765 14,335,692 14,887,933 16,055,232 15,316,538 14,239,733

Cash flow from operation 63,904 (204,428) 6,728,546 (877,693) 909,953 652,719 381,202 (557,602)

Cash Balance Beginning 289,767 353,670 149,242 6,877,788 6,000,095 6,910,048 7,562,767 7,943,969Dividends 0 0 0 0 0 0 0 0

Cash balance ending 353,671 149,242 6,877,788 6,000,095 6,910,048 7,562,767 7,943,969 7,386,367

Debt Service Coverage Ratio 0.78 n/a 1.37 0.73 0.83 0.87 0.87 0.88Self financing ratio 3.00% -1.00% 9.00% 11.00% 13.00% 25.00% 43.00% 94.00%

Debt Service = net cash flow from operationsCoverage Ratio debt service repayments

= sales + other income - operating expenses interest payment + debt repayments

Self financing ratio = (Cash from operations + other income - operating expenses)(3 year average) average 3 year(capital expenditures )

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, page 4POWERGRID COMPANY OF BANGLADESH LTD.

TABLE A1b: PROJECTED CASH FLOW STATEMENTFor the Years Ending 30 June 2001-2021

(Tk '000)2008 2009 2010 2011 2012 2013 2014 2015

CASH INFLOWS: Projected Projected Projected Projected Projected Projected Projected ProjectedFrom operations 10,397,300 12,384,440 11,067,184 14,073,643 14,768,718 15,136,278 15,471,944 15,795,858Received from BPDB 0 0 0 0 0 0 0 0Loan Proceeds 945,360 1,572,850 2,649,690 0 0 0 0 0Equity infusions 224,640 373,750 0 0 0 0 0 0Other Income 35 37 39 40 42 44 46 48Interest revenue 321,493 340,100 404,738 486,244 578,126 673,833 783,317 916,031Total Cash Inflows 11,888,829 14,671,177 14,121,651 14,559,928 15,346,886 15,810,155 16,255,307 16,711,937

CASH OUTFLOWS:Operating Expenses 1,446,746 1,629,105 1,675,684 1,739,446 1,760,443 1,782,407 1,806,228 1,831,812Purchase of fixed assets 1,170,000 1,946,600 0 0 0 0 0 0Repayment of debt 4,106,118 4,462,437 4,485,215 4,541,747 4,714,678 4,604,592 4,110,699 3,430,373Interest payments 2,747,474 3,154,873 2,984,479 2,761,128 2,472,101 2,172,850 1,871,567 1,589,232Taxes 974,851 1,443,818 2,129,358 2,589,226 2,970,560 3,265,873 3,531,537 3,783,944Total Cash Outflows 10,445,189 12,636,833 11,274,736 11,631,547 11,917,782 11,825,722 11,320,031 10,635,361

Cash flow from operation 1,443,640 2,034,344 2,846,915 2,928,381 3,429,103 3,984,433 4,935,276 6,076,576

Cash Balance Beginning 7,386,367 8,630,007 10,164,351 12,311,266 14,339,647 16,668,750 19,353,183 22,788,459Dividends (200,000) (500,000) (700,000) (900,000) (1,100,000) (1,300,000) (1,500,000) (1,700,000)

Cash balance ending 8,630,007 10,164,351 12,311,266 14,339,647 16,668,750 19,353,183 22,788,459 27,165,035

Debt Service Coverage Ratio 1.10 1.12 1.25 1.25 1.28 1.33 1.44 1.59Self financing ratio >100% >100% >100% >100% >100% >100% >100% >100%

Debt Service = net cash flow from operationsCoverage Ratio debt service repayments

= sales + other income - operating expenses interest payment + debt repayments

Self financing ratio = (Cash from operations + other income - operating expenses)(3 year average) average 3 year(capital expenditures )

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, page 5TABLE A1b: PROJECTED CASH FLOW STATEMENT (Cont'd.)

POWERGRID COMPANY OF BANGLADESH LTD.

For the Years Ending 30 June 2001-2021

(Tk '000)2016 2017 2018 2019 2020 2021 2022

CASH INFLOWS: Projected Projected Projected Projected Projected Projected ProjectedFrom operations 16,105,918 16,397,145 16,665,089 16,916,026 17,162,806 17,409,394 17,662,083Received from BPDB 0 0 0 0 0 0 0Loan Proceeds 0 0 0 0 0 0 0Equity infusions 0 0 0 0 0 0 0Other Income 50 52 55 57 60 63 65Interest revenue 1,084,280 1,288,378 1,526,304 1,786,669 2,063,536 2,357,384 2,663,490Total Cash Inflows 17,190,248 17,685,576 18,191,447 18,702,752 19,226,402 19,766,841 20,325,638

CASH OUTFLOWS:Operating Expenses 1,859,243 1,888,601 1,919,980 1,953,458 1,989,144 2,027,127 2,067,514Purchase of fixed assets 0 0 0 0 0 0 0Repayment of debt 2,923,872 2,333,736 2,364,168 2,064,535 2,096,298 2,055,138 1,681,907Interest payments 1,345,633 1,145,651 980,376 830,019 682,001 533,539 388,412Taxes 4,019,101 4,230,212 4,415,938 4,581,581 4,739,347 4,894,197 5,050,361Total Cash Outflows 10,147,849 9,598,200 9,680,462 9,429,593 9,506,790 9,510,000 9,188,194

Cash flow from operation 7,042,399 8,087,376 8,510,985 9,273,160 9,719,612 10,256,841 11,137,445

Cash Balance Beginning 27,165,035 32,307,434 38,294,810 44,505,796 51,278,955 58,298,568 65,655,408Dividends (1,900,000) (2,100,000) (2,300,000) (2,500,000) (2,700,000) (2,900,000) (3,100,000)

Cash balance ending 32,307,434 38,294,810 44,505,796 51,278,955 58,298,568 65,655,408 73,692,853

Debt Service Coverage Ratio 1.72 1.88 1.90 2.00 2.02 2.06 2.19Self financing ratio >100% >100% >100% >100% >100% >100% >100%

Debt Service = net cash flow from operationsCoverage Ratio debt service repayments

= sales + other income - operating expenses interest payment + debt repayments

Self financing ratio = (Cash from operations + other income - operating expenses)(3 year average) average 3 year(capital expenditures )

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TABLE A1b: PROJECTED CASH FLOW STATEMENT (Cont'd.)For the Years Ending 30 June 2001-2021

POWERGRID COMPANY OF BANGLADESH LTD.

(Tk '000)2000 2001 2002 2003 2004 2005 2006 2007

Current Assets Actual Actual Projected Projected Projected Projected Projected ProjectedCash 353,671 504,765 6,877,788 6,000,095 6,910,048 7,562,767 7,943,969 7,386,367Accounts Receivable 158,297 173,298 82,854 137,537 212,435 335,061 472,264 611,191Inventory 0 676,151 6,220 9,216 14,333 21,154 32,023 40,808Due from BPDB 0 0 0 0 0 0 0 0Prepayments and Deposits 55,849 66,422 55,849 55,849 55,849 55,849 55,849 55,849Interest Receivable 0 0 147,346 269,992 270,669 303,486 325,198 321,493Total Current Assets 567,817 1,420,636 7,170,057 6,472,689 7,463,334 8,278,316 8,829,303 8,415,708

Preliminary Expenses 1,386 1,247 1,078 924 770 616 462 308Long-Term AssetsConstruction in Progress 793,464 1,129,892 6,721,403 13,604,860 22,003,068 25,178,484 22,856,335 24,352,584Fixed Assets (Net) 2,126,907 4,402,629 5,867,093 11,860,433 15,808,713 25,050,107 36,881,570 41,612,133Total Long-Term Assets 2,920,371 5,532,521 12,588,496 25,465,293 37,811,781 50,228,591 59,737,905 65,964,717

Total Assets 3,489,574 6,954,404 19,759,631 31,938,906 45,275,885 58,507,523 68,567,670 74,380,733Current LiabilitiesAccounts Payable 401,880 125,554 16,238 20,375 26,943 35,483 48,962 59,520Interest Payable 91,170 44,016 143,960 186,712 324,777 739,399 1,037,003 1,125,592Taxes Payable 19,276 72,352 115,701 219,742 281,858 294,987 559,103 974,851Dividends Payable 0 0 0 0 0 0 0 200,000Other Current Liabilities 10,394 21,967 0 0 0 0 0 0Current Portion of Long-term Debt 0 0 286,127 616,773 754,273 1,679,255 2,800,770 4,106,118

522,720 263,889 562,026 1,043,602 1,387,851 2,749,124 4,445,838 6,466,081Long-Term LiabilitiesLong term debt - foreign 227,075 1,000,860 4,084,185 8,510,885 16,421,515 24,389,870 29,483,726 31,435,161Long term debt - domestic 1,591,230 3,346,746 7,662,486 11,568,203 12,912,289 13,759,072 13,986,608 13,498,063

1,818,305 4,347,606 11,746,671 20,079,088 29,333,804 38,148,942 43,470,334 44,933,225Owner's EquityShare capital and deposits 1,124,721 2,234,381 7,493,287 10,258,965 13,303,521 15,612,782 17,490,971 18,237,131Retained earnings 23,827 108,528 429,425 1,029,030 1,722,487 2,468,454 3,632,306 5,216,076

1,148,548 2,342,909 7,922,712 11,287,995 15,026,008 18,081,236 21,123,277 23,453,207Total Liabilities and Owner's Equity 3,489,573 6,954,404 20,231,409 32,410,685 45,747,664 58,979,302 69,039,449 74,852,512Current Ratio 1.09 5.38 12.76 6.20 5.38 3.01 1.99 1.30Quick Ratio 0.98 2.57 12.38 5.88 5.13 2.87 1.89 1.24Long Term Debt 61.29 64.98 59.72 64.01 66.13 67.84 67.30 65.70 to Equity 38.71 35.02 40.28 35.99 33.87 32.16 32.70 34.30

Current ratio = current assets / current liabilitiesQuick ratio = (cash + bills receivable + accounts receivable) / current liabilitiesLong-term debt: Equity = total long term debt / total equity

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POWERGRID COMPANY OF BANGLADESH LTD.TABLE A1c: PROJECTED BALANCE SHEET

(Tk '000)2008 2009 2010 2011 2012 2013 2014 2015

Current Assets Projected Projected Projected Projected Projected Projected Projected ProjectedCash 8,630,007 10,164,351 12,311,266 14,339,647 16,668,750 19,353,183 22,788,459 27,165,035Accounts Receivable 889,646 1,044,981 911,109 1,196,594 1,233,829 1,263,859 1,291,644 1,318,565Inventory 54,738 65,480 66,355 67,201 66,099 64,996 63,894 62,791Due from BPDB 0 0 0 0 0 0 0 0Prepayments and Deposits 55,849 55,849 55,849 55,849 55,849 55,849 55,849 55,849Interest Receivable 340,100 404,738 486,244 578,126 673,833 783,317 916,031 1,084,280Total Current Assets 9,970,340 11,735,399 13,830,824 16,237,416 18,698,359 21,521,204 25,115,877 29,686,520

Preliminary Expenses 154 0 0 0 0 0 0 0Long-Term AssetsConstruction in Progress 1,950,000 3,896,600 0 0 0 0 0 0Fixed Assets (Net) 63,450,376 61,362,446 63,112,667 60,907,839 58,703,011 56,498,183 54,293,355 52,088,527Total Long-Term Assets 65,400,376 65,259,046 63,112,667 60,907,839 58,703,011 56,498,183 54,293,355 52,088,527

Total Assets 75,370,870 76,994,445 76,943,491 77,145,255 77,401,370 78,019,387 79,409,232 81,775,047Current LiabilitiesAccounts Payable 76,702 89,495 90,243 91,802 90,952 90,294 89,662 89,060Interest Payable 1,621,882 1,532,992 1,451,488 1,309,641 1,162,460 1,010,391 861,176 728,056Taxes Payable 1,443,818 2,129,358 2,589,226 2,970,560 3,265,873 3,531,537 3,783,944 4,019,101Dividends Payable 500,000 700,000 900,000 1,100,000 1,300,000 1,500,000 1,700,000 1,900,000Other Current Liabilities 0 0 0 0 0 0 0 0Current Portion of Long-term Debt 4,462,437 4,485,215 4,541,747 4,714,678 4,604,592 4,110,699 3,430,373 2,923,872

8,104,839 8,937,060 9,572,704 10,186,681 10,423,877 10,242,921 9,865,155 9,660,089Long-Term LiabilitiesLong term debt - foreign 29,392,296 27,647,950 24,510,502 21,183,560 17,949,073 15,186,659 13,081,557 11,458,751Long term debt - domestic 12,661,839 11,925,015 10,905,779 9,886,544 8,867,309 7,848,073 6,828,838 5,809,595

42,054,135 39,572,965 35,416,282 31,070,104 26,816,382 23,034,733 19,910,395 17,268,346Owner's EquityShare capital and deposits 18,461,771 18,835,521 18,835,521 18,835,521 18,835,521 18,835,521 18,835,521 18,835,521Retained earnings 7,221,904 10,120,678 13,590,763 17,524,728 21,797,369 26,377,991 31,269,939 36,482,870

25,683,675 28,956,199 32,426,284 36,360,249 40,632,890 45,213,512 50,105,460 55,318,391Total Liabilities and Owner's Equity 75,842,649 77,466,224 77,415,269 77,617,034 77,873,149 78,491,166 79,881,011 82,246,826Current Ratio 1.23 1.31 1.44 1.59 1.79 2.10 2.55 3.07Quick Ratio 1.17 1.25 1.38 1.53 1.72 2.01 2.44 2.95Long Term Debt 62.08 57.75 52.20 46.08 39.76 33.75 28.44 23.79 to Equity 37.92 42.25 47.80 53.92 60.24 66.25 71.56 76.21

Current ratio = current assets / current liabilitiesQuick ratio = (cash + bills receivable + accounts receivable) / current liabilitiesLong-term debt: Equity = total long term debt / total equity

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POWERGRID COMPANY OF BANGLADESH LTD.TABLE A1c: PROJECTED BALANCE SHEET (Cont'd.)

For the Years Ending 30 June 2001-2021

(Tk '000)2016 2017 2018 2019 2020 2021 2022

Current Assets Projected Projected Projected Projected Projected Projected ProjectedCash 32,307,434 38,294,810 44,505,796 51,278,955 58,298,568 65,655,408 73,692,853Accounts Receivable 1,344,305 1,368,440 1,390,604 1,411,402 1,431,946 1,452,495 1,473,599Inventory 61,689 60,587 59,484 58,382 57,279 56,177 55,074Due from BPDB 0 0 0 0 0 0 0Prepayments and Deposits 55,849 55,849 55,849 55,849 55,849 55,849 55,849Interest Receivable 1,288,378 1,526,304 1,786,669 2,063,536 2,357,384 2,663,490 2,990,970Total Current Assets 35,057,656 41,305,989 47,798,402 54,868,124 62,201,026 69,883,419 78,268,345

Preliminary Expenses 0 0 0 0 0 0 0Long-Term AssetsConstruction in Progress 0 0 0 0 0 0 0Fixed Assets (Net) 49,883,699 47,678,871 45,474,043 43,269,215 41,064,387 38,859,559 36,654,731Total Long-Term Assets 49,883,699 47,678,871 45,474,043 43,269,215 41,064,387 38,859,559 36,654,731

Total Assets 84,941,355 88,984,860 93,272,445 98,137,339 103,265,413 108,742,978 114,923,076Current LiabilitiesAccounts Payable 88,489 87,952 87,445 86,977 86,543 86,148 85,793Interest Payable 617,578 528,074 452,302 377,718 304,283 229,257 159,156Taxes Payable 4,230,212 4,415,938 4,581,581 4,739,347 4,894,197 5,050,361 5,204,372Dividends Payable 2,100,000 2,300,000 2,500,000 2,700,000 2,900,000 3,100,000 3,300,000Other Current Liabilities 0 0 0 0 0 0 0Current Portion of Long-term Debt 2,333,736 2,364,168 2,064,535 2,096,298 2,055,138 1,681,907 0

9,370,015 9,696,132 9,685,863 10,000,340 10,240,161 10,147,673 8,749,321Long-Term LiabilitiesLong term debt - foreign 10,114,544 8,714,826 7,366,101 5,956,424 4,484,971 2,949,243 3,030,166Long term debt - domestic 5,076,486 4,343,383 3,830,921 3,318,459 2,879,486 2,846,235 2,846,235

15,191,031 13,058,209 11,197,022 9,274,883 7,364,457 5,795,478 5,876,401Owner's EquityShare capital and deposits 18,835,521 18,835,521 18,835,521 18,835,521 18,835,521 18,835,521 18,835,521Retained earnings 42,016,567 47,866,777 54,025,818 60,498,374 67,297,053 74,436,085 81,933,612

60,852,088 66,702,298 72,861,339 79,333,895 86,132,574 93,271,606 100,769,133Total Liabilities and Owner's Equity 85,413,133 89,456,639 93,744,224 98,609,118 103,737,192 109,214,757 115,394,855Current Ratio 3.74 4.26 4.93 5.49 6.07 6.89 8.95Quick Ratio 3.59 4.09 4.74 5.27 5.83 6.61 8.59Long Term Debt 19.98 16.37 13.32 10.47 7.88 5.85 5.51 to Equity 80.02 83.63 86.68 89.53 92.12 94.15 94.49

Current ratio = current assets / current liabilitiesQuick ratio = (cash + bills receivable + accounts receivable) / current liabilitiesLong-term debt: Equity = total long term debt / total equity

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POWERGRID COMPANY OF BANGLADESH LTD.TABLE A1c: PROJECTED BALANCE SHEET (Cont'd.)

For the Years Ending 30 June 2001-2021

TABLE A2a: INCOME STATEMENTFor the Years Ending 30 June 2001 through 2022

(Tk '000)SALES 2001 2002 2003 2004 2005 2006 2007 2008

Projected Projected Projected Projected Projected Projected Projected Projected Electricity sales 2,451,135 2,567,742 2,949,678 3,326,178 3,701,959 4,604,764 6,373,811 8,822,665 Other operating income 44,000 45,980 48,049 50,211 52,471 54,831 57,298 59,876 Less purchases 2,192,375 2,291,528 2,635,721 2,908,462 3,050,771 3,750,338 4,899,130 6,603,191Net Sales 302,760 322,194 362,006 467,927 703,659 909,257 1,531,979 2,279,350

OPERATING COSTSDistribution Expense - Operating 210,424 220,339 253,855 279,315 293,492 359,911 470,997 633,517Distribution Expense - Maintenance 31,082 30,149 29,245 28,367 27,516 26,691 91,968 89,209Consumer Accounts Expense 0 0 0 0 0 0 0 0Consumer Service Expense 0 0 0 0 0 0 0 0Sales Expense 0 0 0 0 0 0 0 0Depreciation 64,086 62,163 60,298 58,489 56,735 55,032 189,625 183,936Administrative and General 5,000 5,225 5,460 5,706 5,963 6,231 6,511 6,804Operating Costs 310,592 317,876 348,858 371,877 383,706 447,865 759,101 913,466Operating income (7,832) 4,318 13,148 96,050 319,954 461,391 772,879 1,365,884Interest Revenue 22,125 39,928 33,089 32,713 36,851 51,222 66,394 80,774Non-operating expenses 826 863 902 943 985 1,029 1,075 1,123Bad debt expenses 12,256 12,839 14,748 16,631 18,510 23,024 31,869 44,113Net inc, before int and taxes 1,211 30,544 30,587 111,189 337,310 488,560 806,329 1,401,422Interest Expense 36,817 34,976 31,294 27,613 23,931 20,249 167,078 155,417Income Tax Expense 0 1,727 5,259 38,420 127,982 184,556 309,152 546,354Net Income (35,606) (6,159) (5,966) 45,156 185,397 283,755 330,099 699,651Opening accumulated margins 0 (35,606) (41,765) (47,731) (2,575) 182,822 466,577 796,676Ending accumulated margins (35,606) (41,765) (47,731) (2,575) 182,822 466,577 796,676 1,496,327

Operating Margin % Net Sales (0.30%) 0.20% 0.40% 2.90% 8.60% 10.00% 12.10% 15.50%Ave Fixed Assets to Sales 236.58% 123.86% 144.39% 165.18% 186.47% 235.20% 154.19% 139.77%Return on Total Assets 0.04% 0.98% 0.70% 1.49% 3.38% 4.14% 6.05% 9.41%Return on Equity (4.67%) (0.39%) (0.34%) 2.15% 7.39% 9.66% 9.97% 18.28%Collection to Import Ratio 49.9% 73.9% 71.4% 79.7% 79.0% 85.3% 83.2% 85.5%

NEW WESTZONE DISTRIBUTION COMPANY

Collection to Import Ratio = Monthly collections in Taka/(imported energy in kWh x average monthly billing rate in Taka)

Operating Margin % Sales = operating profit / salesAve fixed assets to sales = sales / ((opening fixed assets+closing fixed assets) /2) Net SalesReturn on Ave Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)Return on Ave Equity = net ncome / ((opening total equity + closing total equity) / 2)

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TABLE A2a: INCOME STATEMENT (Cont'd.)For the Years Ending 30 June 2001 through 2022

(Tk '000)SALES 2009 2010 2011 2012 2013 2014 2015 2016

Projected Projected Projected Projected Projected Projected Projected Projected Electricity sales 11,957,664 12,741,724 13,577,248 14,467,615 15,416,430 16,271,271 17,173,513 18,125,784 Other operating income 62,570 65,386 68,329 71,404 74,617 77,976 81,484 85,152 Less purchases 8,999,355 9,569,739 10,178,284 10,853,288 11,585,589 12,220,747 12,902,406 13,631,791Net Sales 3,020,879 3,237,371 3,467,293 3,685,731 3,905,458 4,128,500 4,352,591 4,579,145

OPERATING COSTSDistribution Expense - Operating 864,956 918,178 978,301 1,041,647 1,110,571 1,173,607 1,237,792 1,306,674Distribution Expense - Maintenance 86,533 83,937 81,419 78,976 76,607 74,309 72,079 69,917Consumer Accounts Expense 0 0 0 0 0 0 0 0Consumer Service Expense 0 0 0 0 0 0 0 0Sales Expense 0 0 0 0 0 0 0 0Depreciation 178,418 173,065 167,873 162,837 157,952 153,214 148,617 144,159Administrative and General 7,110 7,430 7,764 8,113 8,478 8,860 9,259 9,676Operating Costs 1,137,017 1,182,610 1,235,357 1,291,573 1,353,608 1,409,990 1,467,747 1,530,426Operating income 1,883,862 2,054,761 2,231,935 2,394,158 2,551,850 2,718,511 2,884,844 3,048,720Interest Revenue 110,998 152,125 210,328 278,481 346,459 420,739 501,668 589,453Non-operating expenses 1,174 1,227 1,282 1,340 1,400 1,463 1,529 1,598Bad debt expenses 59,788 63,709 67,886 72,338 77,082 81,356 85,868 90,629Net inc, before int and taxes 1,933,898 2,141,950 2,373,095 2,598,961 2,819,827 3,056,431 3,299,115 3,545,946Interest Expense 143,755 131,369 118,257 106,987 97,557 88,126 78,697 69,267Income Tax Expense 753,545 821,904 892,774 957,663 1,020,740 1,087,404 1,153,938 1,219,488Net Income 1,036,598 1,188,676 1,362,064 1,534,311 1,701,530 1,880,900 2,066,480 2,257,191Opening accumulated margins 1,496,327 2,532,925 3,721,602 5,083,666 6,617,977 8,319,507 10,200,407 12,266,887Ending accumulated margins 2,532,925 3,721,602 5,083,666 6,617,977 8,319,507 10,200,407 12,266,887 14,524,078

Operating Margin % Net Sales 15.80% 16.10% 16.40% 16.50% 16.60% 16.70% 16.80% 16.80%Ave Fixed Assets to Sales 192.15% 207.63% 224.31% 242.28% 261.63% 279.78% 299.11% 319.71%Return on Total Assets 11.34% 11.32% 11.58% 11.56% 11.36% 11.17% 10.94% 10.68%Return on Equity 22.08% 20.47% 19.23% 17.99% 16.77% 15.75% 14.85% 14.04%Collection to Import Ratio 84.4% 87.5% 91.2% 87.7% 87.7% 87.8% 87.8% 87.8%

NEW WESTZONE DISTRIBUTION COMPANY

Return on Ave Equity = net ncome / ((opening total equity + closing total equity) / 2)

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Collection to Import Ratio = Monthly collections in Taka/(imported energy in kWh x average monthly billing rate in Taka)

Operating Margin % Sales = operating profit / salesAve fixed assets to sales = sales / ((opening fixed assets+closing fixed assets) /2) Net SalesReturn on Ave Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)

NEW WESTZONE DISTRIBUTION COMPANYTABLE A2a: INCOME STATEMENT (Cont'd.)

For the Years Ending 30 June 2001 through 2022(Tk '000)

SALES 2017 2018 2019 2020 2021 2022Projected Projected Projected Projected Projected Projected

Electricity sales 19,123,348 19,983,899 20,883,175 21,822,917 22,804,949 22,895,200 Other operating income 88,983 92,987 97,170 101,544 106,114 110,890 Less purchases 14,374,478 15,016,514 15,694,219 16,407,593 17,156,635 17,941,346Net Sales 4,837,853 5,060,372 5,286,126 5,516,868 5,754,428 5,064,744

OPERATING COSTSDistribution Expense - Operating 1,380,378 1,441,015 1,505,218 1,572,989 1,644,326 1,719,230Distribution Expense - Maintenance 67,819 65,785 63,811 61,897 60,040 58,239Consumer Accounts Expense 0 0 0 0 0 0Consumer Service Expense 0 0 0 0 0 0Sales Expense 0 0 0 0 0 0Depreciation 139,834 135,639 131,570 127,623 123,794 120,080Administrative and General 10,111 10,566 11,041 11,538 12,057 12,600Operating Costs 1,598,142 1,653,005 1,711,640 1,774,047 1,840,217 1,910,149Operating income 3,239,712 3,407,367 3,574,486 3,742,822 3,914,211 3,154,595Interest Revenue 684,373 786,749 896,774 1,014,561 1,140,148 1,264,561Non-operating expenses 1,670 1,745 1,824 1,906 1,992 2,082Bad debt expenses 95,617 99,919 104,416 109,115 114,025 114,476Net inc, before int and taxes 3,826,798 4,092,452 4,365,020 4,646,362 4,938,342 4,302,598Interest Expense 59,837 50,407 40,977 31,547 22,118 16,678Income Tax Expense 1,295,885 1,362,947 1,429,794 1,497,129 1,565,684 1,261,838Net Income 2,471,076 2,679,098 2,894,249 3,117,686 3,350,540 3,024,082Opening accumulated margins 14,524,078 16,995,154 19,674,253 22,568,501 25,686,187 29,036,727Ending accumulated margins 16,995,154 19,674,253 22,568,501 25,686,187 29,036,727 32,060,809

Operating Margin % Net Sales 16.90% 17.10% 17.10% 17.20% 17.20% 13.80%Ave Fixed Assets to Sales 341.52% 361.27% 382.07% 403.98% 427.05% 433.61%Return on Total Assets 10.47% 10.20% 9.93% 9.67% 9.41% 7.81%Return on Equity 13.40% 12.75% 12.16% 11.63% 11.15% 9.10%Collection to Import Ratio 87.7% 87.8% 87.8% 87.8% 87.8% 81.9%

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Operating Margin % Sales = operating profit / salesAve fixed assets to sales = sales / ((opening fixed assets+closing fixed assets) /2) Net SalesReturn on Ave Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)Return on Ave Equity = net ncome / ((opening total equity + closing total equity) / 2)Collection to Import Ratio = Monthly collections in Taka/(imported energy in kWh x average monthly billing rate in Taka)

NEW WESTZONE DISTRIBUTION COMPANYTABLE A2b: PROJECTED CASH FLOW STATEMENT

For the Years Ending 30 June 2001 through 2022(Tk '000)

2001 2002 2003 2004 2005 2006 2007 2008Projected Projected Projected Projected Projected Projected Projected Projected

Cash In flows:From Sales 1,634,090 2,524,788 2,818,086 3,472,943 3,603,856 4,758,166 6,075,133 8,409,211From other income 37,076 45,650 47,704 49,850 52,095 54,437 56,887 59,447From customer deposits 0 0 0 0 0 0 0 0Loan Proceeds 669,400 267,470 886,580 970,780 750,000 461,620 0 0Interest receipts 0 22,125 39,928 33,089 32,713 36,851 51,222 66,394Equity 1,561,932 83,590 311,500 332,070 257,010 133,900 0 0

3,902,498 2,943,623 4,103,798 4,858,732 4,695,674 5,444,974 6,183,242 8,535,052

Cash Outflows:From operations 2,167,457 2,732,670 2,895,076 3,223,506 3,386,548 4,078,344 5,445,797 7,318,461Non-operating expenditures 757 860 899 939 982 1,025 1,071 1,119Construction in Progress 0 343,180 1,224,280 1,330,240 1,039,920 603,820 0 0Transfer of Assets 2,231,332 0 0 0 0 0 0 0Interest 18,408 35,897 33,135 29,453 25,772 22,090 93,664 161,247Taxes 0 0 1,727 5,259 38,420 127,982 184,556 309,152Repayment - project 0 0 0 0 0 0 145,085 145,085Repayment - transfers 0 66,940 66,940 66,940 66,940 66,940 66,940 66,940Repayment - domestic 0 0 0 0 0 0 0 0Funding of reserves 106,809 78,373 66,512 51,996 30,191 (227,072) 227,072 0

4,524,763 3,257,920 4,288,569 4,708,333 4,588,773 4,673,129 6,164,185 8,002,004

Cash flow surplus/(deficit) (622,265) (314,297) (184,771) 150,399 106,901 771,845 19,057 533,048

Cash Balance Beginning 0 (622,265) (936,563) (1,121,333) (970,934) (864,033) (92,188) (73,131)

Cash balance ending (622,265) (936,563) (1,121,333) (970,934) (864,033) (92,188) (73,131) 459,917

Debt Service Coverage Ratio (26.96) (4.52) (0.88) 10.16 10.45 33.24 2.87 3.75

Debt Service Coverage Ratio = net cash flow from operations / debt service repayments

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NEW WESTZONE DISTRIBUTION COMPANYTABLE A2b: PROJECTED CASH FLOW STATEMENT (Cont'd.)

For the Years Ending 30 June 2001 through 2022(Tk '000)

2009 2010 2011 2012 2013 2014 2015 2016Projected Projected Projected Projected Projected Projected Projected Projected

Cash In flows:From Sales 11,427,812 12,601,082 13,993,095 14,347,833 15,288,786 16,154,781 17,050,563 17,996,017From other income 62,121 64,916 67,839 70,891 74,082 77,416 80,899 84,541From customer deposits 0 0 0 0 0 0 0 0Loan Proceeds 0 0 0 0 0 0 0 0Interest receipts 80,774 110,998 152,125 210,328 278,481 346,459 420,739 501,668Equity 0 0 0 0 0 0 0 0

11,570,707 12,776,996 14,213,059 14,629,052 15,641,349 16,578,656 17,552,201 18,582,226

Cash Outflows:From operations 9,852,002 10,742,725 11,228,794 11,962,886 12,759,162 13,473,901 14,205,067 14,997,645Non-operating expenditures 1,170 1,223 1,277 1,335 1,395 1,458 1,524 1,592Construction in Progress 0 0 0 0 0 0 0 0Transfer of Assets 0 0 0 0 0 0 0 0Interest 149,586 137,562 124,813 112,622 102,272 92,842 83,411 73,982Taxes 546,354 753,545 821,904 892,774 957,663 1,020,740 1,087,404 1,153,938Repayment - project 145,085 193,426 193,426 193,426 193,426 193,426 193,426 193,426Repayment - transfers 66,940 66,940 66,940 2 0 0 0 0Repayment - domestic 0 0 0 0 0 0 0 0Funding of reserves 0 0 0 0 0 0 0 0

10,761,137 11,895,421 12,437,154 13,163,045 14,013,918 14,782,367 15,570,832 16,420,583

Cash flow surplus/(deficit) 809,570 881,575 1,775,904 1,466,007 1,627,431 1,796,289 1,981,369 2,161,644

Cash Balance Beginning 459,917 1,269,488 2,151,063 3,926,967 5,392,975 7,020,405 8,816,695 10,798,063

Cash balance ending 1,269,488 2,151,063 3,926,967 5,392,975 7,020,405 8,816,695 10,798,063 12,959,707

Debt Service Coverage Ratio 5.56 5.81 8.90 8.02 8.81 9.64 10.57 11.53

Debt Service Coverage Ratio = net cash flow from operations / debt service repayments

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NEW WESTZONE DISTRIBUTION COMPANYTABLE A2b: PROJECTED CASH FLOW STATEMENT (Cont'd.)

For the Years Ending 30 June 2001 through 2022(Tk '000)

2017 2018 2019 2020 2021 2022Projected Projected Projected Projected Projected Projected

Cash In flows:From Sales 18,987,323 19,864,379 20,758,275 21,692,397 22,668,556 22,869,666From other income 88,344 92,320 96,473 100,815 105,352 110,094From customer deposits 0 0 0 0 0 0Loan Proceeds 0 0 0 0 0 0Interest receipts 589,453 684,373 786,749 896,774 1,014,561 1,140,148Equity 0 0 0 0 0 0

19,665,120 20,641,072 21,641,497 22,689,986 23,788,469 24,119,908

Cash Outflows:From operations 15,817,782 16,532,965 17,256,554 18,036,095 18,854,948 19,713,111Non-operating expenditures 1,664 1,739 1,817 1,899 1,985 2,074Construction in Progress 0 0 0 0 0 0Transfer of Assets 0 0 0 0 0 0Interest 64,552 55,122 45,692 36,262 26,833 19,398Taxes 1,219,488 1,295,885 1,362,947 1,429,794 1,497,129 1,565,684Repayment - project 193,426 193,426 193,426 193,426 193,426 48,341Repayment - transfers 0 0 0 0 0 0Repayment - domestic 0 0 0 0 0 0Funding of reserves 0 0 0 0 0 0

17,296,912 18,079,137 18,860,436 19,697,476 20,574,321 21,348,608

Cash flow surplus/(deficit) 2,368,209 2,561,935 2,781,061 2,992,510 3,214,148 2,771,300

Cash Balance Beginning 12,959,707 15,327,916 17,889,851 20,670,912 23,663,422 26,877,570

Cash balance ending 15,327,916 17,889,851 20,670,912 23,663,422 26,877,570 29,648,870

Debt Service Coverage Ratio 12.63 13.77 15.05 16.36 17.79 48.22

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Debt Service Coverage Ratio = net cash flow from operations / debt service repayments

NEW WESTZONE DISTRIBUTION COMPANYTABLE A2c: PROJECTED BALANCE SHEET

For the Years Ending 30 June 2001 through 2022(Tk '000)

2001 2002 2003 2004 2005 2006 2007 2008Pro jected Pro jected Pro jected Pro jected Pro jected Pro jected Pro jected Pro jected

Curren t AssetsCash and equivalents (622,265) (936,563) (1,121,333) (970,934) (864,033) (92,188) (73,131) 459,917Accounts Receivable (Net) 811,713 842,158 959,347 796,312 876,281 700,249 967,469 1,337,239Materials - electric/merchandise 488,512 506,724 572,206 621,640 648,575 780,058 1,133,092 1,452,937Prepaid and other current assets 0 0 0 0 0 0 0 0Interest receivable 22,125 39,928 33,089 32,713 36,851 51,222 66,394 80,774Total Curren t Assets 700,085 452,247 443,309 479,731 697,674 1,439,341 2,093,824 3,330,867Inves tmentsReplace reserve fund 106,809 185,182 251,694 303,690 333,881 106,809 333,881 333,881Special deposits 0 0 0 0 0 0 0 0Total Inves tments 106,809 185,182 251,694 303,690 333,881 106,809 333,881 333,881Deferred Expenses 0 0 0 0 0 0 0 0Long- Term AssetsConstruction in Progress 0 343,180 1,567,460 2,897,700 3,937,620 4,541,440 0 0Fixed Assets (Net) 2,072,101 2,009,938 1,949,640 1,891,151 1,834,416 1,779,384 6,131,199 5,947,263Total Long- Term Assets 2,072,101 2,353,118 3,517,100 4,788,851 5,772,036 6,320,824 6,131,199 5,947,263Total Assets 2,878,995 2,990,548 4,212,103 5,572,272 6,803,591 7,866,974 8,558,904 9,612,012

Curren t Liabiliti esNotes and accounts payable 664,791 497,574 592,261 640,039 658,168 854,478 1,230,321 1,564,426Customer deposits 0 0 0 0 0 0 0 0Interest Payable 18,409 17,488 15,647 13,807 11,966 10,125 83,539 77,709Other current liabilities 0 0 0 0 0 0 0 0Accrued taxes 69 1,799 5,334 38,499 128,064 184,642 309,242 546,448Current Portion of Long-term Debt 66,940 66,940 66,940 66,940 66,940 212,025 212,025 212,025Total Curren t Liabiliti es 750,209 583,801 680,182 759,285 865,138 1,261,270 1,835,127 2,400,608Deferred Credit s 0 0 0 0 0 0 0 0Long- Term Liabiliti esLoan - Project 0 267,470 1,154,050 2,124,830 2,874,830 3,191,365 3,046,280 2,901,195Loan - Transfers 602,460 535,520 468,580 401,640 334,700 267,760 200,820 133,880Loan - Domestic 0 0 0 0 0 0 0 0

602,460 802,990 1,622,630 2,526,470 3,209,530 3,459,125 3,247,100 3,035,075Owner 's EquityMembership capital 0 0 0 0 0 0 0 0Subsidy, donations, capital gains 1,561,932 1,645,522 1,957,022 2,289,092 2,546,102 2,680,002 2,680,002 2,680,002Undistributed Income (35,606) (41,765) (47,731) (2,575) 182,822 466,577 796,676 1,496,327

1,526,326 1,603,757 1,909,291 2,286,517 2,728,924 3,146,579 3,476,678 4,176,330Total Liabiliti es and Owner 's Equity 2,878,995 2,990,548 4,212,103 5,572,272 6,803,591 7,866,974 8,558,904 9,612,012

Curren t Ratio 0.93 0.77 0.65 0.63 0.81 1.14 1.14 1.39Quick Ratio 0.28 (0.09) (0.19) (0.19) 0.06 0.52 0.52 0.78Long Term Debt to Equity 39.47 50.07 84.99 110.49 117.61 109.93 93.40 72.67Equity Ratio 53.02 53.63 45.33 41.03 40.11 40.00 40.62 43.45

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Equity Ratio = Total stockholder's Equity/Total Stockholder's Equity and Total Liabilities

Current ratio = current assets / current liabilitiesQuick ratio = (cash + bills receivable + accounts receivable) / current liabilitiesLong term debt: Equity = total long term debt / total equity

NEW WESTZONE DISTRIBUTION COMPANYTABLE A2c: PROJECTED BALANCE SHEET (Cont'd.)

For the Years Ending 30 June 2001 through 2022 (Tk '000)

2009 2010 2011 2012 2013 2014 2015 2016Pro jected Pro jected Pro jected Pro jected Pro jected Pro jected Pro jected Pro jected

Curren t AssetsCash and equivalents 1,269,488 2,151,063 3,926,967 5,392,975 7,020,405 8,816,695 10,798,063 12,959,707Accounts Receivable (Net) 1,807,752 1,885,155 1,401,912 1,449,869 1,500,966 1,536,660 1,574,327 1,614,076Materials - electric/merchandise 1,910,799 2,012,403 2,127,981 2,250,172 2,383,683 2,505,579 2,629,928 2,763,826Prepaid and other current assets 0 0 0 0 0 0 0 0Interest receivable 110,998 152,125 210,328 278,481 346,459 420,739 501,668 589,453Total Curren t Assets 5,099,037 6,200,746 7,667,188 9,371,497 11,251,513 13,279,673 15,503,986 17,927,062Inves tmentsReplace reserve fund 333,881 333,881 333,881 333,881 333,881 333,881 333,881 333,881Special deposits 0 0 0 0 0 0 0 0Total Inves tments 333,881 333,881 333,881 333,881 333,881 333,881 333,881 333,881Deferred Expenses 0 0 0 0 0 0 0 0Long- Term AssetsConstruction in Progress 0 0 0 0 0 0 0 0Fixed Assets (Net) 5,768,845 5,595,780 5,427,907 5,265,069 5,107,117 4,953,904 4,805,287 4,661,128Total Long- Term Assets 5,768,845 5,595,780 5,427,907 5,265,069 5,107,117 4,953,904 4,805,287 4,661,128Total Assets 11,201,763 12,130,407 13,428,976 14,970,447 16,692,512 18,567,457 20,643,154 22,922,071

Curren t Liabiliti esNotes and accounts payable 2,128,240 2,066,403 2,198,955 2,340,284 2,495,878 2,621,396 2,762,214 2,916,525Customer deposits 0 0 0 0 0 0 0 0Interest Payable 71,878 65,685 59,129 53,494 48,779 44,063 39,349 34,634Other current liabilities 0 0 0 0 0 0 0 0Accrued taxes 753,643 822,006 892,881 957,775 1,020,857 1,087,526 1,154,065 1,219,621Current Portion of Long-term Debt 260,366 260,366 193,428 193,426 193,426 193,426 193,426 193,426Total Curren t Liabiliti es 3,214,127 3,214,460 3,344,393 3,544,979 3,758,940 3,946,411 4,149,054 4,364,206Deferred Credit s 0 0 0 0 0 0 0 0Long- Term Liabiliti esLoan - Project 2,707,769 2,514,343 2,320,917 2,127,491 1,934,065 1,740,639 1,547,213 1,353,787Loan - Transfers 66,940 (0) (2) (2) (2) (2) (2) (2)Loan - Domestic 0 0 0 0 0 0 0 0

2,774,709 2,514,343 2,320,915 2,127,489 1,934,063 1,740,637 1,547,211 1,353,785Owner 's EquityMembership capital 0 0 0 0 0 0 0 0Subsidy, donations, capital gains 2,680,002 2,680,002 2,680,002 2,680,002 2,680,002 2,680,002 2,680,002 2,680,002Undistributed Income 2,532,925 3,721,602 5,083,666 6,617,977 8,319,507 10,200,407 12,266,887 14,524,078

5,212,928 6,401,604 7,763,668 9,297,979 10,999,509 12,880,409 14,946,890 17,204,081Total Liabiliti es and Owner 's Equity 11,201,763 12,130,407 13,428,976 14,970,447 16,692,512 18,567,457 20,643,154 22,922,071

Curren t Ratio 1.59 1.93 2.29 2.64 2.99 3.36 3.74 4.11Quick Ratio 0.99 1.30 1.66 2.01 2.36 2.73 3.10 3.47Long Term Debt to Equity 53.23 39.28 29.89 22.88 17.58 13.51 10.35 7.87Equity Ratio 46.54 52.77 57.81 62.11 65.89 69.37 72.41 75.05

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, page 17

Current ratio = current assets / current liabilitiesQuick ratio = (cash + bills receivable + accounts receivable) / current liabilitiesLong term debt: Equity = total long term debt / total equityEquity Ratio = Total stockholder's Equity/Total Stockholder's Equity and Total Liabilities

For the Years Ending 30 June 2001 through 2022 (Tk '000)

2017 2018 2019 2020 2021 2022Pro jected Pro jected Pro jected Pro jected Pro jected Pro jected

Curren t AssetsCash and equivalents 15,327,916 17,889,851 20,670,912 23,663,422 26,877,570 29,648,870Accounts Receivable (Net) 1,655,123 1,675,391 1,696,572 1,718,706 1,741,836 1,653,690Materials - electric/merchandise 2,907,517 3,025,223 3,150,204 3,282,465 3,421,996 3,568,799Prepaid and other current assets 0 0 0 0 0 0Interest receivable 684,373 786,749 896,774 1,014,561 1,140,148 1,264,561Total Curren t Assets 20,574,929 23,377,214 26,414,462 29,679,154 33,181,550 36,135,920Inves tmentsReplace reserve fund 333,881 333,881 333,881 333,881 333,881 333,881Special deposits 0 0 0 0 0 0Total Inves tments 333,881 333,881 333,881 333,881 333,881 333,881Deferred Expenses 0 0 0 0 0 0Long- Term AssetsConstruction in Progress 0 0 0 0 0 0Fixed Assets (Net) 4,521,294 4,385,655 4,254,086 4,126,463 4,002,669 3,882,589Total Long- Term Assets 4,521,294 4,385,655 4,254,086 4,126,463 4,002,669 3,882,589Total Assets 25,430,104 28,096,751 31,002,429 34,139,498 37,518,100 40,352,390

Curren t Liabiliti esNotes and accounts payable 3,075,220 3,193,841 3,336,557 3,486,740 3,644,381 3,809,488Customer deposits 0 0 0 0 0 0Interest Payable 29,919 25,204 20,489 15,774 11,059 8,339Other current liabilities 0 0 0 0 0 0Accrued taxes 1,296,024 1,363,092 1,429,946 1,497,288 1,565,850 1,262,012Current Portion of Long-term Debt 193,426 193,426 193,426 193,426 48,341 39,144Total Curren t Liabiliti es 4,594,589 4,775,563 4,980,418 5,193,228 5,269,631 5,118,983Deferred Credit s 0 0 0 0 0 0Long- Term Liabiliti esLoan - Project 1,160,361 966,935 773,509 580,083 531,742 492,598Loan - Transfers (2) (2) (2) (2) (2) (2)Loan - Domestic 0 0 0 0 0 0

1,160,359 966,933 773,507 580,081 531,740 492,596Owner 's EquityMembership capital 0 0 0 0 0 0Subsidy, donations, capital gains 2,680,002 2,680,002 2,680,002 2,680,002 2,680,002 2,680,002Undistributed Income 16,995,154 19,674,253 22,568,501 25,686,187 29,036,727 32,060,809

19,675,157 22,354,255 25,248,504 28,366,190 31,716,729 34,740,811Total Liabiliti es and Owner 's Equity 25,430,104 28,096,751 31,002,429 34,139,498 37,518,100 40,352,390

Curren t Ratio 4.48 4.90 5.30 5.71 6.30 7.06Quick Ratio 3.85 4.26 4.67 5.08 5.65 6.36Long Term Debt to Equity 5.90 4.33 3.06 2.04 1.68 1.42Equity Ratio 77.37 79.56 81.44 83.09 84.54 86.09

TABLE A2c: PROJECTED BALANCE SHEET (Cont'd.)NEW WESTZONE DISTRIBUTION COMPANY

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, page 18

Long term debt: Equity = total long term debt / total equityQuick ratio = (cash + bills receivable + accounts receivable) / current liabilities

Equity Ratio = Total stockholder's Equity/Total Stockholder's Equity and Total Liabilities

Current ratio = current assets / current liabilities

(Tk '000)2000 2001 2002 2003 2004 2005 2006 2007

SALES Actual Projected Projected Projected Projected Projected Projected Projected Electricity sales 815,586 855,596 985,743 1,114,157 1,235,200 1,462,458 2,026,485 2,808,039 Other operating income 38,206 39,000 40,757 42,593 44,510 46,513 48,606 50,793 Less purchases 532,692 580,003 734,689 831,427 910,127 1,079,234 1,494,798 2,074,289Net Sales 321,100 314,593 291,811 325,323 369,583 429,737 580,293 784,543

OPERATING COSTSDistribution Expense - Operating 25,806 27,149 31,292 35,317 38,565 45,878 63,732 88,349Distribution Expense - Maintenance 34,440 29,309 28,177 28,762 27,577 26,392 51,644 49,642Consumer Accounts Expense 61,939 62,345 68,408 74,346 80,022 91,985 124,962 169,760Consumer Service Expense 0 0 0 0 0 0 0 0Sales Expense 0 0 0 0 0 0 0 0Depreciation 166,749 150,873 150,873 157,950 157,950 157,950 266,966 266,966Administrative and General 56,085 60,000 62,700 65,522 68,470 71,551 74,771 78,136Operating Costs 345,019 329,676 341,450 361,897 372,584 393,756 582,075 652,853Operating income (23,919) (15,083) (49,639) (36,573) (3,001) 35,982 (1,783) 131,690Interest Revenue 47,880 1,554 0 0 0 700 162 0Non-operating expenses (4,145) 3,000 3,135 3,276 3,423 3,577 3,738 3,906Bad debt expenses 0 4,278 4,929 5,571 6,176 7,312 10,132 14,040Net inc, before int and taxes 28,106 (20,807) (57,703) (45,420) (12,600) 25,793 (15,491) 113,744Interest Expense - Local 89,591 91,110 89,115 87,119 85,123 83,127 81,131 106,390Income Tax Expense 2,646 0 0 0 0 0 0 0Net Operating Income (64,131) (111,917) (146,818) (132,539) (97,723) (57,334) (96,622) 7,354Opening accumulated margins (221,838) (285,967) (397,884) (544,702) (677,242) (774,964) (832,299) (928,921)Ending accumulated margins (285,969) (397,884) (544,702) (677,242) (774,964) (832,299) (928,921) (921,567)

Operating Margin % Net Sales (2.90%) (1.80%) (5.00%) (3.30%) (0.20%) 2.50% (0.10%) 4.70%Rate of Return on Total Assets (%) 0.49% (0.40%) (1.06%) (0.69%) (0.16%) 0.30% (0.17%) 1.23%Rate of Return on Net Fixed Assets (1.58%) (2.50%) (3.83%) (3.49%) (2.60%) (1.59%) (1.86%) 0.11%Return on Equity neg. neg. neg. neg. neg. neg. neg. 1.20%Collection to Import Ratio n/a 80.6% 80.6% 84.4% 82.6% 81.8% 80.1% 83.6%

Operating Margin % Sales = operating profit / sales

Return on Equity = net ncome / ((opening total equity + closing total equity) / 2)Collection to Import Ratio = Monthly collections in Taka/(imported energy in kWh x average monthly billing rate in Taka)

Rate of Return on Net Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)

PALLI BIDYUT SAMITIES

For the Years Ending 30 June 2000 through 2021TABLE A3a: INCOME STATEMENTS

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(Tk '000)2008 2009 2010 2011 2012 2013 2014 2015

SALES Projected Projected Projected Projected Projected Projected Projected Projected Electricity sales 3,556,494 3,791,238 4,041,477 4,308,233 4,592,595 4,847,255 5,116,035 5,399,719 Other operating income 53,080 55,467 57,962 60,570 63,296 66,144 69,121 72,231 Less purchases 2,594,888 2,769,068 2,949,205 3,145,235 3,347,951 3,532,387 3,730,346 3,942,167Net Sales 1,014,686 1,077,637 1,150,234 1,223,568 1,307,940 1,381,012 1,454,810 1,529,783

OPERATING COSTSDistribution Expense - Operating 110,421 117,333 125,437 133,819 142,487 149,950 158,565 167,337Distribution Expense - Maintenance 47,640 45,638 43,635 41,633 39,631 37,629 35,626 33,624Consumer Accounts Expense 212,879 224,684 237,143 250,293 264,171 278,820 294,280 310,598Consumer Service Expense 0 0 0 0 0 0 0 0Sales Expense 0 0 0 0 0 0 0 0Depreciation 266,966 266,966 266,966 266,966 266,966 266,966 266,966 266,966Administrative and General 81,652 85,326 89,166 93,178 97,371 101,753 106,332 111,117Operating Costs 719,558 739,947 762,347 785,889 810,626 835,118 861,769 889,642Operating income 295,127 337,690 387,887 437,678 497,314 545,894 593,041 640,141Interest Revenue 0 0 0 0 0 0 0 0Non-operating expenses 4,082 4,266 4,458 4,659 4,869 5,088 5,317 5,556Bad debt expenses 17,782 18,956 20,207 21,541 22,963 24,236 25,580 26,999Net inc, before int and taxes 273,263 314,468 363,222 411,478 469,482 516,570 562,144 607,586Interest Expense - Local 104,394 102,398 144,313 139,289 134,265 129,241 124,217 119,192Income Tax Expense 0 0 0 0 0 0 0 0Net Operating Income 168,869 212,070 218,909 272,189 335,217 387,329 437,927 488,394Opening accumulated margins (921,567) (752,697) (540,627) (321,719) (49,529) 285,688 673,017 1,110,944Ending accumulated margins (752,697) (540,627) (321,719) (49,529) 285,688 673,017 1,110,944 1,599,338

Operating Margin % Net Sales 8.30% 8.90% 9.60% 10.20% 10.80% 11.30% 11.60% 11.90%Rate of Return on Total Assets (%) 2.91% 3.31% 3.83% 4.31% 4.87% 5.27% 5.61% 5.91%Rate of Return on Net Fixed Assets 2.60% 3.41% 3.68% 4.79% 6.19% 7.52% 8.97% 10.58%Return on Equity 24.18% 23.86% 19.82% 20.16% 20.27% 19.22% 18.04% 16.90%Collection to Import Ratio 82.7% 84.3% 84.3% 84.3% 84.3% 84.4% 84.4% 84.4%

Operating Margin % Sales = operating profit / sales

Return on Equity = net ncome / ((opening total equity + closing total equity) / 2)Collection to Import Ratio = Monthly collections in Taka/(imported energy in kWh x average monthly billing rate in Taka)

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PALLI BIDYUT SAMITIESTABLE A3a: INCOME STATEMENTS (Cont'd.)For the Years Ending 30 June 2000 through 2021

Rate of Return on Net Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)

(Tk '000)2016 2017 2018 2019 2020 2021

SALES Projected Projected Projected Projected Projected Projected Electricity sales 5,699,134 5,955,595 6,223,596 6,503,658 6,796,323 7,102,157 Other operating income 75,480 78,876 82,426 86,135 90,010 94,062 Less purchases 4,157,857 4,344,494 4,541,499 4,748,874 4,966,617 5,194,729Net Sales 1,616,757 1,689,977 1,764,523 1,840,919 1,919,716 2,001,490

OPERATING COSTSDistribution Expense - Operating 176,268 184,563 192,858 201,153 210,485 219,817Distribution Expense - Maintenance 31,622 29,620 27,617 25,615 23,613 21,611Consumer Accounts Expense 327,821 342,573 357,989 374,098 390,932 408,524Consumer Service Expense 0 0 0 0 0 0Sales Expense 0 0 0 0 0 0Depreciation 266,966 266,966 266,966 266,966 266,966 266,966Administrative and General 116,117 121,342 126,802 132,508 138,471 144,702Operating Costs 918,794 945,064 972,232 1,000,340 1,030,467 1,061,620Operating income 697,962 744,912 792,291 840,579 889,249 939,870Interest Revenue 0 0 0 0 0 0Non-operating expenses 5,806 6,067 6,340 6,625 6,923 7,235Bad debt expenses 28,496 29,778 31,118 32,518 33,982 35,511Net inc, before int and taxes 663,660 709,067 754,833 801,436 848,344 897,124Interest Expense - Local 114,167 105,744 97,546 92,973 88,399 84,599Income Tax Expense 0 0 0 0 0 0Net Operating Income 549,493 603,323 657,287 708,463 759,945 812,525Opening accumulated margins 1,599,338 2,148,831 2,752,155 3,409,442 4,117,905 4,877,850Ending accumulated margins 2,148,831 2,752,155 3,409,442 4,117,905 4,877,850 5,690,375

Operating Margin % Net Sales 12.20% 12.50% 12.70% 12.90% 13.10% 13.20%Rate of Return on Total Assets (%) 6.25% 6.64% 6.78% 6.89% 6.96% 6.97%Rate of Return on Net Fixed Assets 12.63% 14.78% 17.23% 19.96% 23.16% 26.95%Return on Equity 16.12% 15.14% 14.24% 13.37% 12.60% 11.91%Collection to Import Ratio 84.4% 84.5% 84.5% 84.5% 84.5% 84.5%

Operating Margin % Sales = operating profit / sales

PALLI BIDYUT SAMITIESTABLE A3a: INCOME STATEMENTS (Cont'd.)For the Years Ending 30 June 2000 through 2021

Return on Equity = net ncome / ((opening total equity + closing total equity) / 2)Collection to Import Ratio = Monthly collections in Taka/(imported energy in kWh x average monthly billing rate in Taka)

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, page 21Rate of Return on Net Fixed Assets = net income / ((opening fixed assets + closing fixed assets) / 2)

(Tk '000)2001 2002 2003 2004 2005 2006 2007

Projected Projected Projected Projected Projected Projected ProjectedCash Inflows:From Sales 831,373 957,738 1,132,800 1,214,098 1,423,553 1,931,262 2,793,092From other income 134,574 40,464 42,287 44,191 46,179 48,257 50,428From customer deposits (155,515) 3,913 3,287 2,563 8,802 29,046 37,760Loan Proceeds 110 314,570 1,009,450 1,077,840 783,790 448,230 0Interest receipts 0 1,554 0 0 0 700 162Equity 0 99,710 319,480 336,530 238,160 129,060 0

810,542 1,417,949 2,507,304 2,675,222 2,500,484 2,586,555 2,881,442

Cash Outflows:From operations 733,415 894,934 1,039,995 1,129,590 1,312,883 1,858,192 2,531,289Non-operating expenditures 2,750 3,124 3,264 3,411 3,564 3,724 3,892Construction in Progress 0 314,570 1,009,450 1,077,840 783,790 448,230 0Interest 195,058 89,614 87,618 85,622 83,626 81,630 100,075Repayment - project 0 0 0 0 0 0 0Repayment - transfers 0 0 0 0 0 0 0Repayment - domestic 97,743 97,743 97,743 97,743 97,743 97,743 97,743Funding of reserves 85,364 114,239 168,988 187,292 172,589 182,492 192,096

1,114,330 1,514,224 2,407,058 2,581,498 2,454,195 2,672,011 2,925,095

Cash flow surplus/(deficit) (303,788) (96,275) 100,246 93,724 46,289 (85,456) (43,653)

Cash Balance Beginning 208,411 (95,377) (191,652) (91,406) 2,318 48,607 (36,849)

Cash balance ending (95,377) (191,652) (91,406) 2,318 48,607 (36,849) (80,502)

Debt Service Coverage Ratio 0.66 0.69 0.50 0.61 0.80 1.02 1.27

Debt Service Coverage Ratio = (Net Operating Income + Interest on Long-Term Debt + Depreciation) / Debt Service Repayments

PALLI BIDYUT SAMITIES

For the Years Ending 30 June 2000 through 2021TABLE A3b: PROJECTED CASH FLOW STATEMENT

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(Tk '000)2008 2009 2010 2011 2012 2013 2014 2015

Projected Projected Projected Projected Projected Projected Projected ProjectedCash Inflows:From Sales 3,461,182 3,759,672 4,007,827 4,272,363 4,554,357 4,812,552 5,079,408 5,361,060From other income 52,699 55,069 57,547 60,135 62,842 65,669 68,625 71,712From customer deposits 32,725 1,964 1,983 2,003 2,023 2,043 2,064 2,084Loan Proceeds 0 0 0 0 0 0 0 0Interest receipts 0 0 0 0 0 0 0 0Equity 0 0 0 0 0 0 0 0

3,546,606 3,816,705 4,067,357 4,334,501 4,619,222 4,880,264 5,150,097 5,434,856

Cash Outflows:From operations 3,076,533 3,274,673 3,447,118 3,668,151 3,895,936 4,104,542 4,327,385 4,568,356Non-operating expenditures 4,068 4,250 4,442 4,643 4,851 5,070 5,298 5,536Construction in Progress 0 0 0 0 0 0 0 0Interest 104,893 102,897 133,835 140,545 135,521 130,497 125,473 120,448Repayment - project 0 0 151,416 151,416 151,416 151,416 151,416 151,416Repayment - transfers 0 0 0 0 0 0 0 0Repayment - domestic 97,743 97,743 97,743 97,743 97,743 97,743 97,743 97,743Funding of reserves 230,515 276,618 331,942 398,330 477,996 573,596 688,315 825,978

3,513,752 3,756,181 4,166,496 4,460,828 4,763,463 5,062,864 5,395,630 5,769,477

Cash flow surplus/(deficit) 32,854 60,524 (99,139) (126,327) (144,241) (182,600) (245,533) (334,621)

Cash Balance Beginning (80,502) (47,648) 12,876 (86,263) (212,591) (356,831) (539,431) (784,964)

Cash balance ending (47,648) 12,876 (86,263) (212,591) (356,831) (539,431) (784,964) (1,119,585)

Debt Service Coverage Ratio 1.88 2.69 1.52 1.62 1.76 1.94 2.09 2.24

Debt Service Coverage Ratio = (Net Operating Income + Interest on Long-Term Debt + Depreciation) / Debt Service Repayments

PALLI BIDYUT SAMITIESTABLE A3b: PROJECTED CASH FLOW STATEMENT (Cont'd.)

For the Years Ending 30 June 2000 through 2021S

upplementary A

ppendix A, page 23

PALLI BIDYUT SAMITIESTABLE A3b: PROJECTED CASH FLOW STATEMENT (Cont'd.)

For the Years Ending 30 June 2000 through 2021(Tk '000)

2016 2017 2018 2019 2020 2021Projected Projected Projected Projected Projected Projected

Cash Inflows:From Sales 5,658,332 5,919,976 6,186,373 6,464,761 6,755,675 7,059,679From other income 74,939 78,310 81,834 85,517 89,364 93,387From customer deposits 2,105 0 0 0 0 0Loan Proceeds 0 0 0 0 0 0Interest receipts 0 0 0 0 0 0Equity 0 0 0 0 0 0

5,735,376 5,998,286 6,268,207 6,550,278 6,845,039 7,153,066

Cash Outflows:From operations 4,813,227 5,028,294 5,250,064 5,484,461 5,733,139 5,993,457Non-operating expenditures 5,785 6,045 6,318 6,601 6,898 7,209Construction in Progress 0 0 0 0 0 0Interest 115,423 107,850 99,595 94,117 89,542 85,549Repayment - project 151,416 151,416 151,416 151,416 151,416 151,416Repayment - transfers 1 0 0 0 0 0Repayment - domestic 97,743 406,810 77,230 77,230 77,230 0Funding of reserves 991,173 1,189,408 1,427,290 1,712,748 2,055,297 2,466,357

6,174,768 6,889,823 7,011,913 7,526,573 8,113,522 8,703,988

Cash flow surplus/(deficit) (439,392) (891,537) (743,706) (976,295) (1,268,483) (1,550,922)

Cash Balance Beginning (1,119,585) (1,558,978) (2,450,515) (3,194,220) (4,170,515) (5,438,998)

Cash balance ending (1,558,978) (2,450,515) (3,194,220) (4,170,515) (5,438,998) (6,989,920)

Debt Service Coverage Ratio 2.40 1.40 2.97 3.17 3.36 4.71

Debt Service Coverage Ratio = (Net Operating Income + Interest on Long-Term Debt + Depreciation) / Debt Service Repayments

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, page 24

PALLI BIDYUT SAMITIESTABLE A3c: PROJECTED BALANCE SHEET

For the Years Ending 30 June 2000 through 2021 (Tk '000)

2000 2001 2002 2003 2004 2005 2006 2007Current Assets Actual Projected Projected Projected Projected Projected Projected ProjectedCash and equivalents 208,411 (95,377) (191,652) (91,406) 2,318 48,607 (36,849) (80,502)Accounts Receivable (Net) 236,297 160,668 184,037 160,129 175,374 207,301 292,741 294,013Materials - electric/merchandise 280,182 238,492 251,184 270,545 279,301 305,001 484,784 579,196Prepaid and other current assets 71,569 71,569 71,569 71,569 71,569 71,569 71,569 71,569Interest receivable 1,554 0 0 0 700 162 0Total Current Assets 796,459 376,906 315,138 410,837 528,562 633,178 812,407 864,276InvestmentsReplace reserve fund 241,869 251,455 267,183 329,451 383,343 422,532 444,944 444,944Special deposits 252,592 328,370 426,881 533,601 667,001 800,401 960,481 1,152,577Total Investments 494,461 579,825 694,064 863,052 1,050,344 1,222,933 1,405,425 1,597,521Deferred Expenses 144,015 144,015 144,015 144,015 144,015 144,015 144,015 144,015Long-Term AssetsConstruction in Progress 235,895 235,894 550,464 1,324,020 2,401,860 3,185,650 0 0Fixed Assets (Net) 4,058,701 3,907,828 3,756,955 3,834,899 3,676,949 3,519,000 6,885,914 6,618,947Total Long-Term Assets 4,294,596 4,143,722 4,307,419 5,158,919 6,078,809 6,704,650 6,885,914 6,618,947Total Assets 5,729,531 5,244,468 5,460,636 6,576,823 7,801,731 8,704,776 9,247,760 9,224,759

Current LiabilitiesNotes and accounts payable 88,489 72,190 115,214 129,954 133,881 161,738 293,236 316,535Customer deposits 233,770 78,255 82,168 85,455 88,018 96,820 125,866 163,626Interest Payable 126,726 22,778 22,279 21,780 21,281 20,782 20,283 26,598Other current liabilities 487,899 487,899 487,899 487,899 487,899 487,899 487,899 487,899Accrued taxes 0 250 261 273 285 298 312 326Current Portion of Long-term Debt 0 97,743 97,743 97,743 97,743 97,743 97,743 97,743Total Current Liabilities 936,884 759,115 805,564 823,104 829,107 865,280 1,025,339 1,092,727Deferred Credits 126,303 126,303 126,303 126,303 126,303 126,303 126,303 126,303Long-Term LiabilitiesLoan - Project 0 110 314,680 1,324,130 2,401,970 3,185,760 3,633,990 3,633,990Loan - Transfers 0 0 0 0 0 0 0 0Loan - Domestic 4,539,642 4,344,157 4,246,414 4,148,671 4,050,928 3,953,185 3,855,442 3,757,699

4,539,642 4,344,267 4,561,094 5,472,801 6,452,898 7,138,945 7,489,432 7,391,689Owner's EquityMembership capital 10,825 10,825 10,825 10,825 10,825 10,825 10,825 10,825Subsidy, donations, capital gains 401,844 401,844 501,554 821,034 1,157,564 1,395,724 1,524,784 1,524,784Undistributed Income (285,967) (397,884) (544,702) (677,242) (774,964) (832,299) (928,921) (921,567)

126,702 14,785 (32,323) 154,617 393,425 574,250 606,688 614,042Total Liabilities and Owner's Equity 5,729,531 5,244,470 5,460,638 6,576,825 7,801,733 8,704,778 9,247,762 9,224,761

Current Ratio 0.85 0.50 0.39 0.50 0.64 0.73 0.79 0.79Quick Ratio 0.47 0.09 (0.01) 0.08 0.21 0.30 0.25 0.20Long Term Debt to Equity 35.83 293.83 0.00 35.40 16.40 12.43 12.34 12.04Equity Ratio 2.21% 0.28% -0.59% 2.35% 5.04% 6.60% 6.56% 6.66%

Current ratio = current assets / current liabilities

Long term debt: Equity = total long term debt / total equityQuick ratio = (cash + bills receivable + accounts receivable) / current liabilities

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PALLI BIDYUT SAMITIESTABLE A3c: PROJECTED BALANCE SHEET (Cont'd.)

For the Years Ending 30 June 2000 through 2021(Tk '000)

2008 2009 2010 2011 2012 2013 2014 2015Current Assets Projected Projected Projected Projected Projected Projected Projected ProjectedCash and equivalents (47,648) 12,876 (86,263) (212,591) (356,831) (539,431) (784,964) (1,119,585)Accounts Receivable (Net) 371,924 384,932 398,790 413,554 429,283 440,225 451,768 463,947Materials - electric/merchandise 663,011 683,668 709,297 736,098 764,100 787,091 814,889 843,357Prepaid and other current assets 71,569 71,569 71,569 71,569 71,569 71,569 71,569 71,569Interest receivable 0 0 0 0 0 0 0 0Total Current Assets 1,058,856 1,153,045 1,093,393 1,008,630 908,121 759,454 553,262 259,288InvestmentsReplace reserve fund 444,944 444,944 444,944 444,944 444,944 444,944 444,944 444,944Special deposits 1,383,092 1,659,710 1,991,652 2,389,982 2,867,978 3,441,574 4,129,889 4,955,867Total Investments 1,828,036 2,104,654 2,436,596 2,834,926 3,312,922 3,886,518 4,574,833 5,400,811Deferred Expenses 144,015 144,015 144,015 144,015 144,015 144,015 144,015 144,015Long-Term AssetsConstruction in Progress 0 0 0 0 0 0 0 0Fixed Assets (Net) 6,351,981 6,085,015 5,818,049 5,551,083 5,284,116 5,017,150 4,750,184 4,483,218Total Long-Term Assets 6,351,981 6,085,015 5,818,049 5,551,083 5,284,116 5,017,150 4,750,184 4,483,218Total Assets 9,382,888 9,486,729 9,492,052 9,538,654 9,649,174 9,807,137 10,022,294 10,287,332

Current LiabilitiesNotes and accounts payable 371,297 359,330 382,427 405,235 428,912 447,900 473,462 498,417Customer deposits 196,351 198,315 200,298 202,301 204,324 206,367 208,431 210,515Interest Payable 26,099 25,600 36,078 34,822 33,566 32,310 31,054 29,798Other current liabilities 487,899 487,899 487,899 487,899 487,899 487,899 487,899 487,899Accrued taxes 340 356 372 388 406 424 443 463Current Portion of Long-term Debt 97,743 249,159 249,159 249,159 249,159 249,159 249,159 249,160Total Current Liabilities 1,179,729 1,320,659 1,356,233 1,379,804 1,404,266 1,424,059 1,450,448 1,476,252Deferred Credits 126,303 126,303 126,303 126,303 126,303 126,303 126,303 126,303Long-Term LiabilitiesLoan - Project 3,633,990 3,482,574 3,331,158 3,179,742 3,028,326 2,876,910 2,725,494 2,574,078Loan - Transfers 0 0 0 0 0 0 0 (1)Loan - Domestic 3,659,956 3,562,213 3,464,470 3,366,727 3,268,984 3,171,241 3,073,498 2,975,755

7,293,946 7,044,787 6,795,628 6,546,469 6,297,310 6,048,151 5,798,992 5,549,832Owner's EquityMembership capital 10,825 10,825 10,825 10,825 10,825 10,825 10,825 10,825Subsidy, donations, capital gains 1,524,784 1,524,784 1,524,784 1,524,784 1,524,784 1,524,784 1,524,784 1,524,784Undistributed Income (752,697) (540,627) (321,719) (49,529) 285,688 673,017 1,110,944 1,599,338

782,912 994,982 1,213,890 1,486,080 1,821,297 2,208,626 2,646,553 3,134,947Total Liabilities and Owner's Equity 9,382,890 9,486,731 9,492,054 9,538,656 9,649,176 9,807,139 10,022,296 10,287,334

Current Ratio 0.90 0.87 0.81 0.73 0.65 0.53 0.38 0.18Quick Ratio 0.27 0.30 0.23 0.15 0.05 (0.07) (0.23) (0.44)Long Term Debt to Equity 9.32 7.08 5.60 4.41 3.46 2.74 2.19 1.77Equity Ratio 8.34% 10.49% 12.79% 15.58% 18.88% 22.52% 26.41% 30.47%

Current ratio = current assets / current liabilitiesQuick ratio = (cash + bills receivable + accounts receivable) / current liabilitiesLong term debt: Equity = total long term debt / total equity

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PALLI BIDYUT SAMITIESTABLE A3c: PROJECTED BALANCE SHEET (Cont'd.)

For the Years Ending 30 June 2000 through 2021(Tk '000)

2016 2017 2018 2019 2020 2021Current Assets Projected Projected Projected Projected Projected ProjectedCash and equivalents (1,558,978) (2,450,515) (3,194,220) (4,170,515) (5,438,998) (6,989,920)Accounts Receivable (Net) 476,794 483,201 489,898 496,895 504,207 511,849Materials - electric/merchandise 872,498 899,002 925,515 952,045 982,909 1,013,789Prepaid and other current assets 71,569 71,569 71,569 71,569 71,569 71,569Interest receivable 0 0 0 0 0 0Total Current Assets (138,117) (996,743) (1,707,238) (2,650,006) (3,880,313) (5,392,713)InvestmentsReplace reserve fund 444,944 444,944 444,944 444,944 444,944 444,944Special deposits 5,947,040 7,136,448 8,563,738 10,276,486 12,331,783 14,798,140Total Investments 6,391,984 7,581,392 9,008,682 10,721,430 12,776,727 15,243,084Deferred Expenses 144,015 144,015 144,015 144,015 144,015 144,015Long-Term AssetsConstruction in Progress 0 0 0 0 0 0Fixed Assets (Net) 4,216,252 3,949,285 3,682,319 3,415,353 3,148,387 2,881,421Total Long-Term Assets 4,216,252 3,949,285 3,682,319 3,415,353 3,148,387 2,881,421Total Assets 10,614,134 10,677,950 11,127,778 11,630,792 12,188,816 12,875,807

Current LiabilitiesNotes and accounts payable 524,016 544,818 568,032 592,349 620,192 646,998Customer deposits 212,620 212,620 212,620 212,620 212,620 212,620Interest Payable 28,542 26,436 24,387 23,243 22,100 21,150Other current liabilities 487,899 487,899 487,899 487,899 487,899 487,899Accrued taxes 484 506 528 552 577 603Current Portion of Long-term Debt 558,226 228,646 228,646 228,646 151,416 151,416Total Current Liabilities 1,811,787 1,500,925 1,522,112 1,545,309 1,494,804 1,520,686Deferred Credits 126,303 126,303 126,303 126,303 126,303 126,303Long-Term LiabilitiesLoan - Project 2,422,662 2,271,246 2,119,830 1,968,414 1,816,998 1,665,582Loan - Transfers (1) (1) (1) (1) (1) (1)Loan - Domestic 2,568,945 2,491,715 2,414,485 2,337,255 2,337,255 2,337,255

4,991,606 4,762,960 4,534,314 4,305,668 4,154,252 4,002,836Owner's EquityMembership capital 10,825 10,825 10,825 10,825 10,825 10,825Subsidy, donations, capital gains 1,524,784 1,524,784 1,524,784 1,524,784 1,524,784 1,524,784Undistributed Income 2,148,831 2,752,155 3,409,442 4,117,905 4,877,850 5,690,375

3,684,440 4,287,764 4,945,051 5,653,514 6,413,459 7,225,984Total Liabilities and Owner's Equity 10,614,136 10,677,952 11,127,780 11,630,794 12,188,818 12,875,809

Current Ratio (0.08) (0.66) (1.12) (1.71) (2.60) (3.55)Quick Ratio (0.60) (1.31) (1.78) (2.38) (3.30) (4.26)Long Term Debt to Equity 1.35 1.11 0.92 0.76 0.65 0.55Equity Ratio 34.71% 40.16% 44.44% 48.61% 52.62% 56.12%

Current ratio = current assets / current liabilitiesQuick ratio = (cash + bills receivable + accounts receivable) / current liabilitiesLong term debt: Equity = total long term debt / total equity

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