World Bank Document - Documents & Reportsdocuments.worldbank.org/curated/en/873371468767980151/pdf/multi0page.pdf · LACI Loan Accounting Change Initiative USTDA United States Trade

Document of

The World Bank

Report No: 20167-BIH

PROJECT APPRAISAL DOCUMENT

ONA

PROPOSED CREDIT

IN THE AMOUNT OF SDR 26.4 MILLION

(US$35 MILLION EQUIVALENT)

TO

BOSNIA AND HERZEGOVINA

FOR THE

THIRD ELECTRIC POWER RECONSTRUCTION PROJECT

MAY 24, 2001

Energy Sector UnitSouth East Europe Country UnitEurope and Central Asia Region

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CURRENCY EQUIVALENTS

(Exchange Rate Effective December 31, 2000)

Currency Unit = Konvertible Marka (KM)1 KM = US$0.47US$1 = 2.14KM

FISCAL YEARJanuary 1 -- December 31

ABBREVIATIONS AND ACRONYMS

BiH Bosnia and Herzegovina N.B.F. Not Bank FinancedCAS Country Assistance Strategy NCB National Competitive BiddingDFID Department for International Development (UK) NGOs Non-Government OrganizationsDM Deutsche Mark NORAD Norwegian Agency for DevelopmentEBRD European Bank for Reconstruction and Cooperation

Development OECD Organization for Econornic Cooperation andEC European Commission DevelopmentEIB European Investment Bank OECF Overseas Economic Cooperation Fund (Japan)EPBiH Elektroprivreda Bosnia and Herzegovina PCBs Polychlorinated ByphenylsEPHZHB Elektroprivreda of the Croatian Community of PIU Project Implementation Unit

Herzeg-Bosnia PMRs Project Management ReportsEPRS Elektroprivreda Republika Srpska PIP Project Implementation PlanEMP Environmental Management Plan RRTF Refugee Return Task ForceEU European Union RS Republika SrpskaFBiH Federation of Bosnia and Herzegovina RSMEI Republika Srpska Ministry of Energy andFMERI Federation Ministry of Energy, Mining and Industry

Industry SCADA Supervisory Control and Data AcquisitionGDP Gross Domestic Product SDR Special Drawing RightsHPP Hydropower Plant SECO State Secretariat for Economic AffairsIC International Community (Switzerland)ICB International Competitive Bidding SIL Specific Investment LoanICR Implementation Comnpletion Report SOE Statement of ExpenditureJICA Japanese International Cooperation Agency TPP Thermal Power PlantIDA International Developmnent Association UCTE European Union for Coordination ofIS International Shopping Transmnission of ElectricityISO Independent System Operator USAID United States Agency for InternationalJUGEL Yugoslav Electric Power Industry DevelopmnentLACI Loan Accounting Change Initiative USTDA United States Trade and Development Ageac),

LIB Limnited International Bidding ZEKC Joint Power Coordinating CenterLIBOR London Inter-Bank Offered RateLRMC Long-run marginal cost

Vice President: Johannes F. LinnCountry Director: Christiaan J. Poortman

Sector Manager: Henk BuszTask Team Leader: Iftikhar Khalil

BOSNIA AND HERZEGOVINATHIRD ELECTRIC POWER RECONSTRUCTION PROJECT

CONTENTS

A. Project Development Objective Page

1. Project development objective 32. Key performance indicators 3

B. Strategic Context

1. Sector-related Country Assistance Strategy (CAS) goal supported by the 3project

2. Main sector issues and Government strategy 33. Sector issues to be addressed by the project and strategic choices 6

C. Project Description Summary

1. Project components 72. Key policy and institutional reforrns supported by the project 93. Benefits and target population 104. Institutional and implementation arrangements 12

D. Project Rationale

1. Project alternatives considered and reasons for rejection 162. Major related projects financed by the Bank and other development 18

agencies3. Lessons learned and reflected in proposed project design 194. Indications of borrower commitment and ownership 195. Value added of Bank support in this project 1 9

E. Summary Project Analysis

1. Economic 202. Financial 213. Technical 264. Institutional 265. Environmental 296. Social 307. Safeguard Policies 32

F. Sustainability and Risks

1. Sustainability 322. Critical risks 333. Possible controversial aspects 35

G. Main Credit Conditions

1. Effectiveness Condition 362. Other 36

H. Readiness for Implementation 38

I. Compliance with Bank Policies 38

Annexes

Annex 1: Project Design Summary 39Annex 2: Detailed Project Description 42Annex 3: Estimated Project Costs 51Annex 4: Cost Benefit Analysis Summary 56Annex 5: Financial Summary 66Annex 6: Procurement and Disbursement Arrangements 75Annex 7: Project Processing Schedule 82Annex 8: Documents in the Project File 83Annex 9: Statement of Loans and Credits 84Annex 10: Country at a Glance 86Annex 1 1: Review of Financial Management Arrangements 88

MAP(S)IBRD 30803 Bosnia and Herzegovina: Third Electric Power Reconstruction Project


Third Electric Power Reconstruction Project

Project Appraisal Document

Europe and Central Asia RegionECSEG

Date: May 24, 2001 Team Leader: Mian Iftikhar KhalilCountry Manager/Director: Christiaan J. Poortman Sector Manager/Director: Henk BuszProject ID: P058521 Sector(s): PD - Distribution & TransmissionLending Instrument: Specific Investment Loan (SIL) Theme(s):

Poverty Targeted Intervention: N

Program Financing Data[ ] Loan [X] Credit []Grant [ Guarantee 1 Other:

For Loans/Credits/Others:Amount (US$m): $35.0 (equivalent of SDR 26.4 Million)

Proposed Terms (IDA): Standard CreditGrace period (years): 10 Years to maturity: 35Commitment fee: 0.50% Service charge: 0.75%Financing Plan (US$m): Source Local Foreign TotalBORROWER 0.00 0.00 0.00IDA 0.00 35.00 35.00AGENCY FOR INTERNATIONAL DEVELOPMENT 0.60 19.20 19.80BRITISH DEPARTMENT FOR INTERNATIONAL 0.00 1.00 1.00DEVELOPMENTEUROPEAN BANK FOR RECONSTRUCTION AND 7.00 37.20 44.20DEVELOPMENTEC ASSISTANCE FOR SOUTH EAST EUROPE 0.00 1.80 1.80EUROPEAN INVESTMENT BANK 8.10 45.50 53.60GOVERNMENT OF SPAIN 0.00 18.00 18.00KREDITANSTALT FUR WIEDERAUFBAU 0.00 2.90 2.90NORWEGIAN AGENCY FOR DEV. COOP. (NORAD) 0.00 6.20 6.20OTHER SOURCES OF BORROWING COUNTRY 21.00 0.00 21.00OTHER FOREIGN SOURCES (UNIDENTIFIED) 0.00 13.60 13.60SWISS AGENCY FOR DEV. & COOP. (SDC) 0.00 14.00 14.00

Total: 36.70 194.40 231.10Borrower: BOSNIA AND HERZEGOVINAResponsible agency: EPBIH, EPHZHB, AND EPRS

Address: See below.

Other Agency(ies):

Elektroprivreda Bosnia and HerzegovinaAddress: Vilsonovo Setaliste 15, 71000 Sarajevo, Elosnia and HerzegovinaContact Person: Mr. Ognjen Markovic, Acting General ManagerTel: 387 33 47 24 81 Fax: 387 33 65 42 66

Elektroprivreda of the Croatian Community of Herzeg-Bosnia (EPHZHB)Address: Mile Budaka 106A, Mostar, Bosnia and HerzegovinaContact Person: Mr. Matan Zaric, General ManagerTel: 387 36 31 08 47 Fax: 387 36 31 71 57

Elektroprivreda Republika Srpska (EPRS)Address: Luke Vukalovica 3, Trebinje, Bosnia and ]HerzegovinaContact Person: Mr. Svetozar Acimovic, General ManagerTel: 387 59 26 00 91 Fax: 387 59 26 00 70

Estimated disbursements ( Bank FY/US$m):FY ~ 2002 2003 2004 2005

Annual 5.75 13.50 13.75 2.00lCumulative 5.75 19.25 33.00 35.00 l

Project implementation period: October 1, 2001 - September 30, 2004

Expected effectiveness date: 09/30/2001 Expected closing date: 03/31/2005OCS PAD Fd, R

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A. Project Development Objective

1. Project development objective: (see Annex 1)

The project development objective is to continue the post-conflict reconstruction program in the powersector and to ensure access to reliable, lower cost electricity, to be supplied with reduced environmental andsafety risks, and improved cost recovery by suppliers.

The component outputs contributing to this objective include:

(i) increased transmission capacity;(ii) increased distribution capacity;(iii) improved operation of the BiH power system on an integrated basis;(iv) establishment of a legislative and regulatory framework conducive to competition and eventual

privatization;(v) adoption and implementation of detailed power sector restructuring and privatization action plans;(vi) improved availability and safety at hydropower plants;(vii) reduced pollution at thermal power plants; and(viii) institution building through establishment of new management information systems.

2. Key performance indicators: (see Annex 1)

Increased power generation and sales; avoided increase in transmission losses; reduced distribution losses;increased gross power flows between the power companies; passage of electricity laws consistent with EUDirectives and the adopted sector policy statements; establishment of independent regulatory agencies;adoption and implementation of action plans for sector restructuring and privatization; reduced particulateemissions at thermal power stations; improved self-financing of investments; and improved revenuecollection relative to amounts billed.

B. Strategic Context1. Sector-related Country Assistance Strategy (CAS) goal supported by the project: (see Annex 1)Document number: IDA/R2000-60 Date of latest CAS discussion: 05/18/2000

The sector-related CAS goals are to:

(i) strengthen institutions and governance, and(ii) foster private sector-led growth and employment.

2. Main sector issues and Government strategy:

Reconstructing the power system. In 1990, BiH produced 12,613 Gigawatt hours (GWh) of electricityfrom generating plants located on its territory. Electricity consumption was 11,535 GWh. The systemcomprised 13 hydropower plants with a total capacity of 2,034 megawatts (MW) and an average output of6,922 GWh/year, and 12 thermal power plants with a total capacity of 1,957 MW and an output of 9,252GWh in 1990. The thermal power plants were brown coal and lignite fired, with the fuel coming frommines within BiH. BiH was responsible for operating its own system and meeting local demand. However,being part of the former Yugoslav network, the 400 kV power grid in BiH as well as power exchanges werecontrolled by the Yugoslav Electric Power Industry's (JUGEL) dispatching center in Belgrade.

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At the beginning of 1996, more than half of the generating capacity had been put out of operation becauseof direct damages, destroyed transmission lines or lack of coal. Most plants had also suffered from lack ofmaintenance during the war. About 60% of the transmission network and control system in the Federationwas seriously damaged, including transmission facilities and interconnection lines to neighboring countries.The transmission network and control system in RS were also heavily darnaged, particularly in those areaslocated close to confrontation lines. The 400 kV system in BiH was almost completely out of operation(the main exception was the Trebinje-Podgorica 400 kV transmission line). Many distribution networkswere badly damaged in both the Federation and RS as a result of fighting and lack of maintenance. Manytransformer stations, buildings, telecommunications and maintenance facilities and equipment were alsoeither seriously damaged or destroyed.

Rehabilitation enabled total generation to reach 10,429 GWh in 2000 (83% of the 1990 level) andconsumption within BiH to reach 9,365 GWh in 1999 (81% of the 1990 level). However, despite theseachievements, the remaining rehabilitation needs are still very large and many facilities remain to bereconstructed. Investments are also needed to improve reliability, safety and environmental protection.

The Federation and RS governments place high priority on continued reconstruction of the power system asone of the primary means to relaunch economic activity. IDA and other international donors have beensupporting this reconstruction, mainly through the Emergency Electric Power Reconstruction Project (Cr.No. 2903) (Power 1) and the Second Electric Power Reconstruction Project (Cr. No. 3071) (Power 2).Further investments are needed to continue the post-war reconstruction program.

Improving cost recovery. All three power enterprises were severely affected during the war by revenueconstraints arising from the inability of households as well as commercial and industrial enterprises to payfor their electricity consumption. Revenue collection during the war dropped to as low as 25% of invoicedamounts, leading to severe cash deficits. Since the Dayton peace accord, the revenue situation of the threeenterprises, both in terms of tariff levels as well as collection performance, has improved, particularly forEPBiH. In 2000, revenue collection by EPBiH, EPHZHB and EPRS reached 97%, 89% and 87%respectively of the amounts billed. The collected revenue is estimated to have covered 132%, 127% and123% respectively of cash expenses. In 2000, total distribution losses were reduced to 11% of electricityentering the distribution network for EPBiH, 25% for EPHZHB and 27% for EPRS. Of these amountstechnical losses were estimated at between 10% and 12%. The rest consisted of non-technical losses, thatis unbilled consumption due to such factors as lack of meters, meter tampering or bypassing. An adversefactor is that operating costs appear to be excessively high because of overstaffing and possibleoverestimation of depreciation. The Elektroprivredas need to make further progress to reach full costrecovery, including coverage of appropriate depreciation charges. This will require progress in increasingbilling and collection, improving cost efficiency, reducing distribution losses and increasing tariff levels, ifnecessary. There is also a need for asset revaluation in order to ensure realistic depreciation chargesnecessary for asset replacement. All three Elektroprivredas have been implementing recommendations forimproving billing and collection and reducing distribution losses made by a recently completed electricitytariff study.

Improving tariff structures. In 1999, the average industrial electricity tariff rate of about US$ 0.06/kWh(kilowatt hour) in BiH was close to the average in OECD Europe of US$ 0.07/kWh. By contrast, thehousehold rates of about USS 0.05/kWh was much lower than the OECD Europe average of US$0.13/kWh. The tariff study recommended large rate increases, mainly for households, phased in over theperiod 1999-2003. It also recommended the establishment of a three-block tariff structure for households,under which the high-priced third block would compensate for the low-priced "lifeline" first block, and asystem of vouchers to allow targeted low income consumers to pay for their lifeline consumption of

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electricity. On October 1, 1999, the RS Government raised tariff rates to about the level recommended bythe study, and gave each municipality the authority to designate 6.7% of collected electricity revenue forthe reduction of arrears on previous electricity bills of specified consumer groups. The FederationGovernment raised and harmonised tariff rates for EPBiH and EPHZHB in April 2001, with the increasesbeing concentrated on household consumers. The strategy each of the Federation and RS Governments setout in their Electricity Policy Statement is to gradually remove the distortion between household and othertariff rates, and provide compensation to help offset the costs to the poorest groups.

Improving power coordination between EPBiH, EPHZHB and EPRS. Since the war, coordination ofthe power sector in BiH, both in terms of system control and technical regulation, and in terms of exchangeof electricity, has been restricted because of the breakdown of many transmission lines and the existence ofthree separate vertically-integrated power enterprises.

With regard to electricity exchanges between the Elektroprivredas, these were initially in kind andconstrained so that net trade between any pair of Elektroprivredas was always zero or close to it (e.g.,exports from one company to a service area with a power deficit of another company were offset byimports of the same amount from a power surplus area of the other company). The development ofcommercial trade was also hindered by difficulties in making payments because of a poorly functioningbanking system. More recently, commercial exchanges have been initiated on a limited scale.

Enhancement of power exchanges would:

(i) permit surplus power of one company to be used to alleviate shortages of another company (causedby inadequate generation capacity or by outages of large generating units or surges in powerdemand);

(ii) reduce transmission costs by allowing the most direct routes to be used, regardless of whether theseroutes cross the territories of the other companies; and

(iii) reduce generating costs by permitting the lowest cost generating units in the country to be used ateach time of day and year. Further progress towards improved power exchanges would bedemonstrated by the establishment of more commercial trade contracts between the threecompanies, and a readiness by the companies to help each other out in emergencies.

With regard to system control and technical regulation, there was before the war a single control center forthe BiH system, which coordinated plant dispatch and technical regulation. Since the war, however, a morecomplex system has operated. Each Elektroprivreda has been dispatching its own power stations for thebenefit of its own consumers. For purposes of frequency control, EPRS is synchronized with the powersystem of Federal Republic of Yugoslavia, while EPBiH and EPHZHB are synchronized with the powersystem of Croatia. However, EPBiH provides some ancillary services free-of-charge to both EPHZHB andEPRS. For instance, both frequency regulation and reserve for the EPHZHB service areas in CentralBosnia are provided by EPBiH by means of the Jablanica hydropower station. Similarly Jablanicaprovides frequency regulation for the EPRS service areas around Prijedor, Modrica and Derventa, as wellas power supply when EPRS cannot supply itself. In order to improve the management of the BiH system,the three Elektroprivredas established a Joint Power Coordinating Center (ZEKC) in March 1999 tocoordinate the operation of the BiH power system in a safe, effective and efficient manner. Under theproposed project, the Entity governments will establish an Independent System Operator (ISO) for theentire BiH system, and the three Elektroprivredas will develop ZEKC to fulfil this role. The ISO will beresponsible for ensuring the safety, stability, and efficiency of the BiH system, and, in this context, forensuring the availability of all necessary ancillary services. All three Elektroprivredas have declared theirsupport for BiH to rejoin the European Union for the Coordination of Transmission of Electricity (UCTE),

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and to this end have agreed that the ISO will operate the BiH system as a single control area according toUCTE rules, within the UCTE Control Block covering Slovenia, Croatia and Bosnia and Herzegovina.

Power sector reform. Prior to the war, BiH had a single vertically-integrated socially-owned powercompany. There are currently three vertically-integrated companies (two in the Federation and one in RS),largely serving three separate groups of consumers (Bosniaks, Croats and Serbs). The current arrangementlacks the economies of scale and coordination that existed before the war, whilst at the same time lackingthe potential benefits of competition (lower costs and prices and greater supply quality and reliability).Private involvement in the sector, particularly if it comes from abroad, could bring valuable expertise aswell as new resources for investment. However, privatization may require significant third partyguarantees in order to reduce perceived risks.

The challenge for the future is to incorporate clear policies for power sector reform in the Federation andRepublika Srpska into new electricity legislation which is in tune with developments in the EuropeanUnion, to establish an independent regulatory framework, and to introduce a power sector structure whichis conducive to the emergence of both beneficial competition and privatization. To this end, the Federationand RS Governments have, with assistance from international consultants, jointly prepared ElectricityPolicy Statements that set out a coordinated program of power sector reform for BiH, and have adoptedthese Statements. The Statements provide for the establishment of an Independent System Operator for theBiH system, the early establishment of independent regulatory agencies for the electricity industry in BiH,and the preparation of a detailed program of restructuring and privatization for the Elektroprivredas in bothEntities. The Statements aim to reform the BiH power sector in accordance with Directive 96/92 of theEuropean Parliament and of the Council of December 19, 1996, which establishes the conditions for aliberalized electricity market in which power distribution companies and at least the largest final consumershave the right to choose their electricity suppliers. The Entity Governments have presented to theirParliaments new electricity laws, also prepared with international assistance, that incorporate thesereforms.

Restructuring the coal mine sector in the Federation. Investments have been carried out to enable theFederation coal mines to meet the needs of the thermal power stations of Tuzla and Kakanj over the nextseveral years. In the medium term, the forecast needs of the power stations could be met from a smallnumber of low-cost mines. The other mines appear to be financially and economically unviable. A coalsector restructuring study was completed under Power 2. The study reports identify those mines which canbe made economically viable, list investments needed to make these mines economic, and proposeappropriate measures to protect redundant coal miners and help them find alternative employment.

3. Sector issues to be addressed by the project and strategic choices:

Providing credits to government-owned power companies is still necessary in order to restore full electricitysupply as soon as possible and enable economic recovery. Private lending or investments in the sector arestill not possible for the time being because of perceived country risks and the fact that economic recoveryis still in the early stages so that many consumers, especially in RS, cannot pay fully for their electricity.While priority under the proposed project would continue to be given to power sector reconstruction,improving cost recovery and tariff structures, major emphasis would also be given to improving powercoordination and power sector reform. Coal mine sector restructuring would be best handled under aseparate new project since the actions required would be quite different in nature from the investmentsincluded under the proposed project. These actions would consist largely of social measures to helpredundant miners and their families.

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C. Project Description Summary

1. Project components (see Annex 2 for a detailed description and Annex 3 for a detailed costbreakdown):

The project would focus on restoration of the 400 kV and other high voltage transmission systems,especially reconstruction of damaged substations. This would help BiH to restore the pre-warinterconnections with the other parts of formner Yugoslavia and eventually to re-join the Union for theCoordination of Transmission in Europe (UCTE). The project would also include a Supervisory Controland Data Acquisition (SCADA) System component to improve power dispatching and facilitate theoperation of the high voltage network within BiH on an integrated basis. It would include investments inpower distribution to provide electricity to returning refugees and to reconstruct damaged facilities, therebyrelieving serious overloading in some areas and enabling reduction in the high levels of technicaldistribution losses. It would provide investments at selected hydropower stations to improve safety andplant availability. Investments at thermal power stations would be limited to reducing pollution.

Technical assistance would be provided:

(i) for procurement and implementation of the physical components;(ii) to enable ZEKC to function as the Independent System Operator;(iii) for a survey of socially vulnerable electricity consumers;(iv) for corporatization and commercialization of the power sector enterprises; and(v) for the establishment of regulatory agencies.

Training would be included for (i), (ii), (iv) and (v).

As the investment needs for full rehabilitation of the power system are still very significant, a feasibilitystudy was carried out by AGRA Monenco-Teshmont to evaluate priority components and the sequence ofreconstruction implementation covering the high voltage transmission components of the BiH powertransmission system, the distribution systems of the respective Elektroprivredas, and the safety- andavailability-related rehabilitation requirements of the Trebinje, Rama and Jablanica hydropower plants.Priorities were established for reconstruction and rehabilitation of the respective transmission facilities ineach of the areas in accordance with specific criteria. The distribution components included in theproposed scope of the Power 3 project represent only a part of the total rehabilitation requirements of thedistribution facilities. Similarly, significant rehabilitation of the 110 kV system is required for furtherstrengthening and improvement of the power system of BiH.

Costs were estimated for reconstruction and rehabilitation of each component, and contract packagesestablished in a manner that would permit co-financier contributions to be obtained on a packaged orindividual component basis. The economic viability of the proposed transmission, distribution and hydroplant components was established. The Final Report was submitted by the Consultants in January 2000.The costs and the financial and economic analyses were updated in April 2001.

The components proposed by the AGRA Monenco-Teshmont feasibility study have a total cost, includingphysical and price contingencies, of about US$ 156.6 million (Variant IA). Other principal components ofthe project, which were not included in the scope of the AGRA Monenco-Teshmont feasibility study,include a SCADA and associated telecommunication system, investments at thermal power plants aimed atreducing pollution and technical assistance.

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A Supervisory Control and Data Acquisition (SCADA) system, comprising three regional control centersand an overall central dispatch center, together with an associated telecommunication system will beincluded under the Power 3 project to permnit nmodem integrated operation of the BiH system. The scope otthe system and detailed technical specifications are being defined through a separate feasibility studxfunded by USTDA. The cost of the system has been estimated at US$ 44.2 million (including physical andprice contingencies). The SCADA and telecommunication facilities required at the substations to berehabilitated under the Power 3 project have been included in the scope defined by the AGRAMonenco-Teshmont study.

Based on discussions with the Elektroprivredas, a review of their proposals for investments in pollutionicontrol measures, and site visits to examine the present environmental conditions which the proposedmeasures would mitigate, a pollution control investment program has been prepared for each of fourthermal power stations. In general, the proposed investments follow the Environmental Management Plans(EMPs) prepared under the previous two power projects in Bosnia (Power 1 and Power 2).

The components to be financed under the project are shown below. A description is given in Annex 2.

Iii4icative Bank Bank-Componnt Sctor Costs %X of;0 Kinankc 'fin anc!n-i

1. Transmission lines Distribution & 29.70 12.9 24.50 70 0Transmission

2. Transmission substations Distribution & 61.40 26.6 0.00 0.Transmission

3. SCADA Electric Power & 44.20 19.1 0.00 00Other EnergyAdjustment

4. Distribution Distribution & 42.90 18.6 0.00 ()Transmission

5. Hydropower stations PH 22.60 9.8 2.90 8 t

6. Environmental investments at Other 16.90 7.3 0.00 0.)thermal power plants Environment

7. Technical assistance Electric Power & 13.40 5.8 7.60 2 l7Other EnergyAdjustment

Total Project Costs 231.10 100.0 35.00 100.

Front-end fee 0.00 0.0 .00 0.0Total Financing Required 231.10 100.0 35.00 100 0(

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The specific components to be financed under the IDA Credit are:

Transmission Lines (IDA Financing US$ 24.5 million)

Reconstruction of war damage, including right-of-way clearing, replacement of damaged parts of existingtowers, construction of new towers to replace destroyed ones, dismantling of damaged insulators, hardwareand conductors and ground wires, and stringing, along the following lines:

1. Sarajevo 10 - Mostar 4 400 kV (US$ 5.0 million)2. Sarajevo 10 - Sarajevo 20 400 kV (US$ 1.6 million)3. Mostar 4 - Gacko 400 kV (US$ 3.5 million)4. Visegrad - Tuzla 400 kV (US$ 3.7 million)5. Ugljevik - Ernestinovo 400 kV (US$ 3.7 million)6. Jajce - Mraclin 220 kV (US$ 0.7 million)7. Jajce - Prijedor 220 kV (US$ 0.6 million)8. Kakanj - Prijedor 220 kV (US$ 1.0 million)9. Prijedor - Sisak 220 kV (US$ 0.7 million)10. Tuzla - Gradacac - Djakovo 220 kV (US$ 1.1 million)11. Dubrovnik - Trebinje 220 kV (US$ 0.2 million)12. Mostar - Nevesinje 110 kV (US$ 2.7 million)

Hydropower Station Component (IDA Financing US$ 2.9 million)

1. Rehabilitation of the tunnel and surge shaft at HPP Rama.

Technical Assistance Component (IDA Financing US$ 7.6 million)

I. An international consultant to assist in procurement and supervision of the IDA-financedcomponents, and provide procurement training.

2. A social assessment of socially vulnerable electricity consumers.3. Part of the assistance for the corporatization and commercialization of the power sector

enterprises.

2. Key policy and institutional reforms supported by the project:

As part of their preparation of the proposed project, the Governments of the two Entities have engaged in atwo phase process to establish a coordinated power sector reform program in Bosnia and Herzegovina.Under the first phase, the Entity Governments secured technical assistance in the formulation of powersector reform policy for Bosnia and Herzegovina. As a result, Electricity Policy Statements were draftedand approved by the Entity governments. In the second phase, the Entity Governments completed draftingnew electricity laws that reflect the approved policy statements, and have submitted the draft laws to theirParliaments.

The project would support this coordinated power sector reform program through measures at both theenterprise and the sectoral level, as follows:

At the enterprise level, the project would support the corporatization, commercialization, and privatizationof the three Elektroprivredas in a consistent manner, by sponsoring the following specific initiatives:

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the commissioning by the Governments of the Federation and the RS of comprehensive studies ofthe sequence, extent and timing of restructuring and privatization of the Elektroprivredas inaccordance with terms of reference acceptable to the Association and by consultants acceptable tothe Association, which would be completed by December 31, 2001;

on completion of the restructuring and privatization studies, the development and implementationof detailed restructuring and privatization action plans, including implementation schedules, whichwould be finalized and agreed withi the Association by February 28, 2002, with no priorrestructuring or privatization of the Elektroprivredas having taken place; in the case of EPRS, noprior privatization of EPRS will take place other than the purchase with vouchers of warrantsunder conditions acceptable to the Association, with the warrants entitling the bearer to purchasecomrnon shares upon the conversion of the constituent enterprises of EPRS into joint stockcompanies, with this conversion only taking place after the action plan has been agreed upon and instrict accordance with that plan; and

the establishment of new financial imanagement systems, based on intemational accountingstandards, in each of the Elektroprivredas by December 31, 2003.

At the sector level, the project would support the establishment of an independent regulatory framework forthe electricity industry, and the transition to integrated operation of the BiH system and to a morecompetitive industry structure in accordance with EC requirements. In this respect, the project wouldprovide technical assistance for:

the establishment of independent Entity and State Regulatory Commissions by December 31, 2001 .the preparation of methodologies for electricity industry regulations and licenses, and training forthe staff of the new regulatory agencies; and

the establishment by March 31, 2002 of an Independent System Operator (ISO) to operate the Biflsystem as a single control area, according to UCTE rules, and within the UCTE Control Blockcovering the territories of the Republic of Slovenia, the Republic of Croatia, and Bosnia andHerzegovina; in the event that the system of the Federal Republic of Yugoslavia remainsdisconnected from the UCTE system, selected EPRS generating units could be isolated, if desiredby EPRS, from the rest of the system in order to sell power to the Federal Republic of Yugoslavianetwork. The Joint Power Coordinating Center (ZEKC) would be developed in order to becomethe ISO for the BiH system, and the three Elektroprivredas would provide to the Association, byDecember 31, 2001, a plan and schedule covering the additional resources to be provided to ZEKCto enable it to function as the ISO and would implement this plan according to the said schedule.

3. Benefits and target population:

The domestic benefits from rehabilitation of transmission lines and substations would comprise:

(i) increased transmission capacity;(ii) improved access to market of power supply from the relatively low-cost Visegrad, Trebinje.

Dubrovnik and Gacko power plants;(iii) recommencement of operation of Capljina as a pumped storage plant which would provide power

to meet peak loads;(iv) fewer outages and other supply quality irnprovements;

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(v) avoided increases in power transmission losses; and(vi) revenue from transmitting power to foreign markets.

The potential international benefits of restoration of the 400 kV Mostar 4 substation and the BiH 400 kVtransmission system are very large and include the following:

(i) reconnecting the entire BiH system to the UCTE transmission system with the associatedopportunities for sale and purchase of power within the UCTE network;

(ii) providing Croatia access to thermal power generation in BiH;(iii) permitting wheeling of power for Croatia through BiH between the south-west and north-east

sectors of Croatia;(iv) providing security for the loads in north-east Croatia;(v) facilitating supply of power to Serbia and Kosovo during their network reconstruction;(vi) facilitating connection of other countries of south-eastem Europe to the UCTE network;(vii) facilitating implementation of the proposed 400 kV ring network around the Mediterranean; and(viii) comprising a part of the infrastructure required for realization of the main political and economic

targets of the Stability Pact for South Eastern Europe.

Several of these international benefits will require the restoration of the 400 kV Emestinovo substation inCroatia.

The benefits from the distribution investments would consist of:

(i) increased distribution system capacity;(ii) improved access to electricity for larger numbers of consumers;(iii) fewer outages; and(iv) reduced technical distribution losses.

The benefits from the hydropower station investments would consist of:

(i) reduced risk of unscheduled hydropower plant outages;(ii) increased assurance that Jablanica, Rama and Trebinje can contribute to secondary regulation,

which is needed to meet UCTE requirements; and(iii) improved safety at dams.

The benefits from the environmental investments at thermal power stations would consist of:

(i) reduced particulate emissions at Tuzla and Kakanj;(ii) reduced risk of polluted water discharges, contamination of ground water, and fugitive dust

emissions related to ash disposal at Gacko and Ugljevik; and(iii) avoidance of thermal pollution from heated water discharges at Kakanj, thereby improving the

ecological balance.

The benefits from the SCADA system and associated communications facilities would consist of:

(i) helping to enable BiH to rejoin the UCTE as a separate, single control area;(ii) fuel savings due to improved generation scheduling;(iii) reduced outages;(iv) reduced O&M costs at substations; and

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(v) revenue from the sale of surplus communications system capacity.

Institutional benefits would include:

(i) improved cost recovery by the power companies;(ii) improved financial management;(iii) improved procurement capacity;(iv) substantial progress towards operation of the BiH high voltage power network on an integrated

basis and conversion of ZEKC to an Independent System Operator (ISO);(v) formulation and implementation of a power sector restructuring and privatization policy; and(vi) establishment of a legislative and regulatory framework that would facilitate the introduction of

competition and privatization.

The target population would be household and non-household consumers of electricity throughout BiH,particularly returning refugees and those in small towns and rural areas who did not benefit from theprevious stages of the rehabilitation of the power system. Many of these potential beneficiaries are livingin poverty, and availability of electricity will significantly improve the quality of their lives.

4. Institutional and implementation arrangements:

Financing Plan

Of a total project cost of US$ 231.1 million, IDA would provide a Credit in the amount of US$ 35 million.An additional US$ 21 million would be provided by the three Elektroprivredas out of their owninternally-generated funds. The remaining financing required (US$ 175.1 million) would be provided byco-financiers through parallel financing arrangements, with each donor responsible for separatecomponents. As a result, possible delays in implementation of one donor's component would generallycause little or no delay in implementation of other donors' components. At the time of appraisal,reasonably firm commitments had been made for about US$ 161.5 million by: the European InvestmentBank (EIB), the European Bank for Reconstruction and Development (EBRD), the European Commission,and the Governments of Germany, Norway, Spain, Switzerland, the United Kingdom and the United States.The EIB has indicated its willingness to cover most or all of the financing gap of US$ 13.6 million. Italyhas also expressed interest in co-financing the project. The financing plan is given hereunder.

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Estimated Cost and Financing PlanUS$ Millions EPBIH

Total Financing EPHZHBCost Gap IDA EIB EBRD SECO USAID NORAD Spain DFID EC KfW EPRS

Component

TransmissionTransMission Lines 29.7 24.5 5.2Substations 61.4 53.6 7.8Subtotal 91.1 24.5 53.6 1 3

SCADA 44.2 44.2 0

Hydropower StationsHPP Jablanica 15.5 14 1.5HPP Rama 3.5 2.9 0.6HPP Trebinje 3.6 2.9 0.7Subtotal 22.6 2.9 1 4 0 0 0 0 0 2.9 2.8

Thermal Power StationsTPP Kakanj and TPP Tuzla 9.1 8 1.1TPP Gacko and TPP Ugljevik 7.8 5.6 2.2Subtotal 16.9 13.6 3.3

Distribution 42.9 16.8 6.2 18 1.9

Technical Assistance 13.4 7.6 3 1 1.8 0

Total 231.1 13.6 35 53.6 44.2 14 19.8 6.2 18 t 1.8 2.9 21

Note: Donors have indicated interest in financing most or all of the remaining investments.

Lending Arrangements

The IDA Credit would be lent to Bosnia and Herzegovina for 35 years with a 10 year grace period and atthe standard IDA service charge. The funds would be onlent to the Federation and RS Governments on thesame terms. The Federation Government would provide the funds to EPBiH and EPHZHB for 20 yearswith a 5 year grace period and at an interest rate of Libor plus 0.75%. The RS Government would providethe funds to EPRS for 20 years with a 5 year grace period and at an interest rate of Libor plus 0.75%.Bosnia and Herzegovina would enter into Subsidiary Credit Agreements with the FederationGovemment/EPBiH, the Federation GovernmentJEPHZHB, and the Govemment of RepublikaSrpska/EPRS as a condition for effectiveness of the IDA Credit.

Implementation

The proposed project would be expected to be completed within the three-year period October 1, 2001through September 30, 2004. Management of all aspects of project implementation, except those to becarried out by the Federation and RS Governments (i.e., sector reform), would be carried out by EPBiH,EPHZHB and EPRS, who would be responsible for execution of their respective parts. The PIUsresponsible for implementation of the Second Electric Power Reconstruction Project (Power 2) wouldcontinue for the proposed project. The Financial Management Review and Procurement CapacityAssessment have identified the need for strengthening each of the Elektroprivreda PIUs with qualifiedfinancial and procurement staff (see sections on Financial Management and Disbursement andProcurement). In addition, an intemational consultant would work with the PIUs during projectimplementation. The consultant would assist with procurement of the transmission line equipment andRama hydropower station works to be financed by IDA, monitor delivery and installation, and providein-house training to the Elektroprivredas' procurement staff.

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Procurement

A detailed procurement plan, along with project procurement elements, their estimated costs, biddingmethods, packaging and estimated schedules has been developed (Annex 6).

Financial Management and Disbursement

Each Elektroprivreda, through its PIU, would be responsible for its own financial management of theproject (see Annex 11 for the detailed financial management arrangements). In accordance with the LoanAccounting Change Initiative (LACI) requirement, a Bank accredited financial management specialistreviewed the proposed financial management systems between December 1999 and March 2001 to:

(i) assess the project's capacity and readiness for implementation of LACI;(ii) review whether the necessary elements are present for a sound project financial management

system such as adequate internal controls, project accounting, project staffing and auditarrangements; and

(iii) prepare a time-bound action plan for strengthening the financial management system to achievePMR-based disbursements in accordance with LACI.

The review found that the PlUs' financial management systems satisfy the Bank's minimum financialmanagement requirements. However, the PlUs do not have in place an adequate project financialmanagement system that would allow for the preparation of the accurate and timely Project ManagementReports (PMRs) required by IDA. A report on the review of the Financial Management System is in thePIP

The PIUs comply with the audit covenants under Power 2 and there were no significant accounting issuesreported by the auditors in the most recent audit, for the year ended 31 December 1999. However the 1999enterprise audits for the three Elektroprivredas were all qualified by the independent auditors. For EPBiHand EPHZHB, the auditors were unable to satisfy themselves as to the appropriate valuation of property,plant and equipment in accordance with International Accounting Standards. In the case of EPRS, theauditors were unable to confirm that the financial statements fairly represented the financial position ofEPRS as of December 31, 1999. They were unable to offer an opinion on several other important matters,including the value of fixed assets, receivables, internal balances, capital and reserves, and transactions inrespect of which they were unable to confirm fair value. The auditors also noted numerous internal andaccounting control weaknesses. The three Elektroprivredas are currently implementing detailed actionplans (acceptable to IDA) to address these issues. Under the project, the Elektroprivredas have agreed tohave their assets revalued by independent professional evaluators, by June 30, 2002.

An agreed action plan (see Annex 11) has been accepted by the three Elektroprivredas, with the followingprovisions:

(i) Each Elektroprivreda would appoint, by effectiveness, an independent auditing firm, acceptable tothe Association, to perform the audits of the company and project financial statements for 2001. Inaddition, a management letter on internal controls from the auditors would be provided four monthsafter project effectiveness.

(ii) Each Elektroprivreda would finalize its 2002 budget by December 31, 2001, including recordingand allocation of total budget in the accounting system - by month, and by year, by activities, bycategories, by sources and by account codes, and by effective date.

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(iii) Each Elektroprivreda would provide PMRs satisfactory to the Association by August 15, 2002.(iv) Each Elektroprivreda would prepare a reliable budget and budget revisions when compared against

the actuals, by August 15, 2002.(v) The PIUs would achieve the capability of preparing satisfactory supervision reports, satisfactory

withdrawal applications, receiving satisfactory audits, especially of internal controls, by August15, 2002.

(vi) The financial management arrangements would be reviewed by an IDA financial managementspecialist by August 31, 2002 to assess their readiness for PMR based disbursements.

Each Elektroprivreda's financial statements (income statement, balance sheet and cash flow statement)would be prepared in accordance with International Accounting Standards, while the Project FinancialStatements would be prepared in accordance with the format provided by IDA. Both the company andproject financial statements would be audited by an independent auditor acceptable to IDA, and the auditreports would be submitted to IDA within six months of the end of the fiscal year. The audit of the ProjectFinancial Statements would also include a separate opinion on the operation of the Special Accounts(disbursements made against PMRs). PricewaterhouseCoopers Canada audited the 1998 financialstatements of each Elektroprivreda and PricewaterhouseCoopers Macedonia audited the 1999 financialstatements for each Elektroprivreda. The three Elektroprivredas have signed contracts withPricewaterhouseCoopers Macedonia for the 2000 audits.

Disbursements from the IDA Credit would be made initially on the basis of the traditional system withreimbursements against direct payments, and there would be no Special Accounts initially. Once asatisfactory financial management system has been installed and is operating satisfactorily, the method fordisbursement may be changed to the new procedure whereby proceeds from the Credit would be disbursedagainst quarterly PMRs. The target date for such a conversion would be one year from effectiveness and aSpecial Account would be established in the name of each Elektroprivreda. In view of weaknesses of thecommercial banks within BiH, the Special Accounts would be established in banks outside BiH. Proceedsof the IDA Credit would be allocated in accordance with Table C, Annex 6.

Each PIU would prepare a quarterly PMR and furnish it to the Bank within 45 days of the end of thequarter. The first such PMR would be provided by August 15, 2002 for the quarter ending June 30, 2002.The reports would be used to track project progress, procurement and disbursement and would comprise:

(i) financial reports including project sources and uses of funds, uses of funds by project activity,project balance sheet, project cash withdrawals, Special Account statement and project cashforecast;

(ii) project progress reports including monitoring of contracts and output by project activity; and(iii) procurement management reports including process monitoring of goods, works and consultants'

services and contract expenditures for goods and consultant services. The PMRs would employ theformats set out in the Project Implementation Plan (PIP), which follow examples given in theBank's LACI Implementation Handbook.

The draft accounting and financial flows for the project are described in Annex 11. The PIUs wouldgenerate and maintain vouchers and supporting documentation for expenditures on all activities of theproject. The financial flows for all activities in Power 3 will involve direct payment from the creditaccounts to suppliers and there will be no special account initially.

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The risks related to the financial management aspects of the project include:

(i) possible delays in preparation of PMRs;(ii) poor handling of financial management due to a poor accounting environment and few qualified

accountants in BiH;(iii) possible continued lack of control of operating costs and large operating losses; and(iv) possible misuse of the IDA Credit.

These risks are considered manageable due to the, various risk-mitigation measures identified in Annex 11.

Supervision and Monitoring

The assessments carried out by IDA show that the Elektroprivredas are capable of implementing theproposed project. As this is a complex project with a major reform component, three responsibleimplementing agencies and several co-financiers, a significant supervision effort would be required.

IDA would carry out a mid-term review of the project by June 30, 2003. In addition to the topics coveredunder the PMRs, the mid-term review would include a review of the economic viability of the projectcomponents, based on actual costs and benefits achieved to-date, and of the overall institutional andfinancial performance of the Elektroprivredas This review could identify additional measures to be taken toensure the efficient completion of the project.

An Implementation Completion Report (ICR) would be prepared by the Association with inputs from theElektroprivredas not later than six months after project closing. The ICR would evaluate how well theobjectives of the project have been met, the overall performance of the project, the performance of theElektroprivredas and lessons learned.

D. Project Rationale

1. Project alternatives considered and reasons for rejection:

The following sets of project alternatives were considered:

(i) project versus no project;(ii) choices between project components; and(iii) choices of sub-components within each project component.

Project versus no project. The main justification of the investments that would be financed under theproject is that there is still much economically attractive post-war reconstruction to be carried out. Thebenefits of the project versus no project are listed in Section C.3 and evaluated in the economic rate ofreturn analysis. An economic rate of return of 61% was estimated for the project as a whole. An equallyimportant justification of the project is the support which can be given under it for power sectorcoordination, institutional strengthening, restructuring and reform. A third important justification is theproject's regional contribution in the form of restoring the high-voltage interconnections with othercountries of former Yugoslavia. This contribution would be a big step towards re-integration of the powernetworks of the Balkan countries with the West European grid.

A related question is what would happen in the absence of intemnational assistance for the project. Itsimplementation would then depend on the ability of the Elektroprivredas to finance the investments from netintemal cash generation and commercial borrowings. Although it has been projected that theElektroprivredas' capacity to finance investments will improve in future years, internally-generated funds

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remain insufficient to cover the financing needs of the proposed project and there are no conmmercial lendersavailable within BiH to provide financing of the magnitude required or on terms that would be reasonable.Another option would be for private companies to acquire equity in the power sector companies andprovide financing for the project investments. This option is not considered to be realistic at the presenttime because of substantial country risk, the lack of a suitable regulatory framework, and the maintenanceof prices below cost covering levels. Under the project actions would be taken to establish the necessarylegal and regulatory framework suitable for a largely privatized power sector, raise prices towardscost-covering levels and reduce the large distortion between household and other prices. However, theseactions will take several years to complete.

Choices between project components. Since the total reconstruction requirements identified by theElektroprivredas and the feasibility studies considerably exceeded available financing, some trade-offs hadto be made between project components. With the full agreement of the Elektroprivredas and the EntityGovermments it was decided to give first priority under Power 3 to rehabilitation of the high-voltagenetwork and system control in order to facilitate integrated operation of the BiH power system and enableBiH to rejoin the UCTE, both of which would greatly enhance the security of the power system andimprove other aspects of quality of supply. Financing constraints meant excluding investments in 110 kVtransmission and having relatively small distribution and generation components.

It was decided to concentrate on reconstruction of existing facilities rather than construction of new onessince the forecast demand over the next several years can be met from existing facilities, and availableanalyses have confirmed that the reconstruction options are less costly than completely new facilities.

Choices of sub-components. The choice of sub-components within the categories of transmission linesand substations was made on the basis of sets of criteria set out in the AGRA Monenco-Teshmontfeasibility study. The first step was to identify a list of essential components based on technicalconsiderations for restoration of the high-voltage grid and interconnection with UCTE. These include:

(i) reconstruction of all sections of 400 kV and 220 kV transmission line damaged during the war;(ii) reconstruction of the 400 kV substation at Mostar 4;(iii) reconstruction of the I 10 kV transmission line Mostar 2 - Nevesinje; and(iv) construction of a Mostar switchgear bay for the 110 kV line to Nevesinje.

The choice to reconstruct the 400 kV and 220/110 kV substations was based on an evaluation schemeusing the following criteria: public safety, Elektroprivreda personnel safety, transmission security risk,obsolete equipment, war neglect and lack of supplier support, UCTE performance, Balkans andMediterranean system interconnections, modernization of protection schemes, modernization for SCADAcontrol, and modernization of control systems in substations.

The AGRA Monenco-Teshmont study prioritized the distribution investments proposed by theElektroprivredas using the following criteria;

(i) the supply of power to locations that are currently without power where people are currentlyresiding;

(ii) the supply of power to locations where work is currently on-going to provide for the return ofrefugees;

(iii) the repair of facilities where failure could affect the safety of personnel nearby;(iv) the repair of facilities where failure could cause a widespread outage for a significant time (such as

power transformers or switchgears);

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(v) the repair of facilities which have a high rate of failure and affect a large number of people for lon gperiods of time (such as a radial 35 kV line where access is poor);

(vi) the supply of power to locations where vvork is planned to provide for the return of refugees;(vii) the improvement of facilities to reduce technical power distribution losses; and(viii) the repair of facilities which result in poor power quality, voltage and frequency of outages.

Hydropower investments have been confined to the plants at Jablanica, Rama and Trebinje as muchrehabilitation has already been carried out at the other hydropower plants and the needs at these threeplants were considered to be greater. Jablanica, Rama and Trebinje have added importance for purposes ofjoining UCTE since they provide secondary frequency regulation. The rehabilitation works were selectedusing the following priorities. Priority 1 was given to safety of the plant and operating personnel, andability to maintain the generator units in operation. Priority 2 was given to the ability to ensure reliableoperation at the rated output of the units. Priority 3 was given to increasing the generation outputcapability of the units through increasing the efficiency of the turbines and rewinding of the generator statorand possibly rotor.

The investments chosen for the four thermal power stations were confined to pollution control since furthercapacity rehabilitation was deemed to be of lower priority given the current surplus generating capacity inBiH. The choice of investments was based on the priorities set out in the environmental management plansprepared by EPBiH and EPRS for Power I and lPower 2.

Alternative options within the SCADA systemn and associated communications component are beingevaluated in the SCADA system feasibility study.

2. Major related projects financed by the Bank and/or other development agencies (completed,ongoing and planned).

Latest Supervision 2Sector lssue04 Pr0Ject j (PS) Rtins

I _ _ __ _ __ _ __ _ __ _ __ _ _ i__________ ___:::::___ :( aavk4nancei! pro je¢ts only) Implementation Development

Bank-financed Progress (IP) Objective (DO)

Repair damages for specific sectors Emergency Recovery Project S SEmergency reconstruction of power Emergency Electric Power S Sfacilities; cost recovery Reconstruction ProjectReconstruction in Republika Srpska Reconstruction Assistance S S

ProjectContinued reconstruction; cost Second Electric Power S Srecovery; improved power sector Reconstruction Projectcoordination; start of sector reform

Other development agenciesMany donors, including EBRD, EU, N/ACanada, Japan (JICA + OECF = nowJBIC); Norway, Spain, Switzerland, theUK, and US (USAID and USTDA) arecofinancing the above projects andparallel power sector investments.

IP/DO Ratings: HS (Highly Satisfactory), S (Satisfactory), U (Unsatisfactory), HU (Highly Unsatisfactory)

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3. Lessons learned and reflected in the project design:

The project would build on the successful performance of Power I and Power 2. One point alreadyrealized and taken into account is that, since the expected international financing would cover only part ofthe large remaining reconstruction needs, it is essential to obtain the agreement of all the projectimplementing agencies on the investments to be included under the project and the allocation of the projectbetween the three Elektroprivredas. An important contribution of the main feasibility study was to providethe basis for this agreement, which was reached during the preappraisal mission. A second lesson is theimportance of ensuring the timely availability of cofinancing. Reasonably firm financing commitments hadbeen secured to cover all costs except US$ 13.6 million. Prospects are good for securing the remainingfinancing. A third lesson is the importance of securing financing early for technical assistance in order toavoid delays in project components that depend on prior completion of that technical assistance. IDAwould finance the critical procurement technical assistance. A fourth lesson is the importance of havingstrong, well-staffed PIUs. The PIUs being used for Power 2 would be expected to continue under Power 3and technical assistance would be provided where necessary. Special emphasis is being given toestablishing sound project procurement and financial management systems within the PIUs. A fifth lessonis that progress towards power sector coordination and reform requires patience and an active role by theBank because of the need to gain the agreement of the implementing agencies and the Entity Governmentsunder the existing political climate. The project would benefit from activities under previous projects in anadditional way. The environmental components included under the project were based partly on theEnvironmental Management Plans prepared under Power 1 and Power 2. A lesson leamed from experiencein other countries in the Europe and Central Asia region is the desirability of minimizing barter tradearrangements. The project would contribute to this goal by emphasizing measures to strengthen thefinancial viability of the Elektroprivredas and encouraging actions towards corporatization and operationon a commercial basis. In this respect, agreement was reached to increase the proportion of bills to be paidin cash for coal purchases by EPBiH.

4. Indications of borrower commitment and ownership:

The following are indications of borrower commitment and ownership:

(i) the commitment shown by the Elektroprivredas in the implementation of the Power 2 Project;(ii) the Elektroprivredas and the Governments have been consistently prompt in providing requested

information to the Bank and its consultants and have made considerable efforts to meet Bank staffunder difficult conditions; and

(iii) working groups involving the State, Federal and RS Governments and the three Elektroprivredaswere established and worked under tight time schedules to prepare power sector reform policiesand new electricity laws. The power sector reform policies have been adopted by the Federal andRS Governments, and draft electricity laws have been submitted to the Federal and RSParliaments.

5. Value added of Bank support in this project:

The value added of Bank support in this project has been the following:

(i) The Bank was mandated to take the lead role among donors in establishing overall sectorrehabilitation and reconstruction investment priorities from the point of view of the whole country.The effectiveness of this arrangement has been confirmed by its leadership in the two largestpost-war electric power projects, Power I and Power 2.

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(ii) Bank involvement in the proposed project has served as a catalyst for securing other donorfinancing.

(iii) Because of its broad sector involvement, the Bank is able to take the lead role among donors inencouraging institutional reform and strengthening as well as general sector restructuring andreform.

(iv) The Bank is contributing to improved coordination between the Elektroprivredas and the EnergyMinistries of the two Entities by designing the project to include coordinated investments by allthree Elektropnrvredas and by strongly encouraging improved power system coordination.

(v) Procurement in accordance with World Bank procurement guidelines would help to minimize costsof equipment purchase and installation.

E. Summary Project Analysis (Detailed assessments are in the project file, see Annex 8)

1. Economic (see Annex 4):* Cost benefit NPV=US$1166 million; ERR = 61 % (see Annex 4)

O Cost effectivenessO Other (specify)

A cost-benefit analysis was carried out for 85% of the total project investments. The excluded investments,for which the benefits could not be measured accurately, comprise the environmental investments at thermalpower stations, the investments to improve safety at hydropower stations, and the technical assistance.Separate benefits were identified and measured for the different project components.

For transmission, the measured benefits include:

(i) avoidance of increases in transmission losses;(ii) reductions in unserved energy caused by power outages in the transmission system;(iii) increased electricity sales from the Gacko and Visegrad power stations made possible by the

removal of transmission constraints;(iv) resumption of pumped storage at the Capljina hydropower station made possible by an increase in

fault levels due to transmission system rehabilitation;(v) revenue from transmission within BiH of power intended for foreign markets; and(vi) the benefit (measured by willingness to pay determined on the basis of the cost of alternative

energy) of transmission of additional electricity to markets within BiH.

For distribution the measured benefits include:

(i) reductions in unserved energy caused by power outages in the distribution system; and(ii) increased sales made possible by distribution system restoration (measured by willingness to pay

determined on the basis of the cost of altemative energy).

For the SCADA system the measured benefits include:

(i) salary savings due to staff reductions at hydropower plants, substations and in record keepingunits;

(ii) reductions in unserved energy attributable to improved dispatching; and(iii) revenue from sale of spare communications capacity. For hydropower investments, the measured

benefits consist of improved availability of generating capacity at the Jablanica and Trebinjehydropower stations.

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The costs consist of 85% of the project investments, plus operating and maintenance expenditures. Importduties and other indirect taxes have been excluded. A shadow exchange rate 7.5% higher in local currencythan the actual rate was used, on the assumption that the current rate is distorted by import dutiesaveraging about 7.5% of import prices. A shadow wage rate was not used because a satisfactory estimatewas not available, and its use would increase an already higher than adequate rate of return. The estimateswere made in constant prices as of January 1, 2001.

Every project component was found to have a positive net present value when discounted at the opportunitycost of capital, taken to be 12%.

2. Financial (see Annex 4 and Annex 5):NPV=US$ 299 million; FRR = 32 % (see Annex 4)

A project financial analysis was carried out for the same 85% of the project investments. The benefits usedfor the economic analysis were also used for the financial analysis. However, two types of benefits weremeasured differently. Reductions in unserved energy were measured in the financial analysis using theactual average year 2000 retail tariff rate of US$ 0.056/ kWh whereas a higher estimate of US$ 0.25/kWhwas used in the economic analysis based on estimates in other countries of willingness to pay to protectagainst unplanned outages. Increased electricity sales were measured in the financial analysis using theactual tariff rate whereas a willingness to pay estimate of US$ 0.14/kWh was used in the economicanalysis. These two adjustments largely explain why the financial rate of return is lower than the economicrate of return for the project. The financial analysis is in nominal prices. Local taxes of 10% on the localcost project expenditures are included in the costs. Shadow prices were not used.

Every project component was found to have a positive net present value when discounted at the opportunitycost of capital of 12% plus average local inflation of 3%. The project net present values are positive for allthree Elektroprivredas. They are US$ 118 million for EPBiH, US$ 50 million for EPHZHB and US$ 130million for EPRS. The financial internal rates of return for EPBiH, EPHZHB and EPRS are 32%, 28%and 35% respectively.

Assessment of the Financial Performance of Elektroprivredas

EPBiH

Past Financial Performance

Since the war ended, EPBiH's financial performance has improved significantly. Domestic sales haveincreased from 1,700 GWh in 1996 to 2,950 GWh in 2000. Gradual tariff increases have resulted inimproved revenues and the overall collection rate as a percentage of billings has increased from 60% in1996 to 97% in 2000. Distribution losses have been reduced from 25% in 1996 to about 11% in 2000.

Based on the audited 1999 financial statements, EPBiH incurred a net loss of KM 60.9 million (US$ 33.5million). Operating income before depreciation, interest and extraordinary items was KM 90.7 million,resulting in a working ratio (cash operating expenses as a percentage of revenues) of 78% and an operatingratio (cash operating expenses and depreciation as a percentage of revenues) of 112%, illustrating thatdepreciation expenses remain relatively high. 42% of EPBiH's cash operating expenses were for coal forthermal power production. As a result of a strong overall collection performance, EPBiH generatedpositive cash flow.

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Based on unaudited financial statements, FPI3iH improved its financial perfonnance in 2000. Overalldomestic demand increased by 3.1%. The average domestic distribution tariff in 2000 was 11.90 Pf/kWhand the export tariff was 5.0 Pf/kWh. The result was a net loss of KM 32.2 million, a 47% reduction from1999 losses. The working ratio was 73%/o and the operating ratio was I 12%. EPBiH continued to generatepositive cash flow in 2000.

Future Financial Performance

Continued improvement in EPBiH's financial perfonrance relies on continued growth in the demand forelectricity by the industrial'commercial and residential consumers, continued strong collection performanceand the ability to keep distribution losses under control. As stated above, a major expense is thedepreciation charge, which accounted for nearly 38% of the revenues generated in 2000. Since fixed assetshave not been revalued according to international accounting standards, it may not be appropriate toimpose tariff increase conditions based on full cost-recovery until a proper revaluation of the company'sassets has been undertaken and an associated depreciation policy established. Given the importance ofappropriately valued assets and associated depreciation charges to accurately assess the financialperformance of EPBiH and the requirements for tariff increases that cover cost, EPBiH agreed to have itsfixed assets revalued and its depreciation policies reviewed by qualified independent organizations,satisfactory to the Association, by June 30, 2002.

Projections of the financial performance of EPBiH over the period January 1, 2001 through December 31,2007 are presented in Annex 5 and elaborated in the Project Implementation Plan. The projections havebeen prepared to assess EPBiH's capacity to meet debt servicing requirements and the required counterpartfunding of the project while, at the same time., remaining financially viable. The projections assume that:

(i) Domestic demand for electricity continues to increase, albeit at a slower pace after year 2001.(ii) Distribution losses do not exceed 1 1%.(iii) Tariffs increase at the rate of domestic intlation.(iv) The costs for salaries and wages are kept constant in real terms after the year 2001 reflecting

improvements in overall productivity and a reduction in staffing.(v) Pre-war debt is allocated and servicing of this debt takes place.(vi) The overall collection rate remains at the current level of close to 100%.(vii) External financing would finance 85%/0 of the total project costs of the proposed project and the

loan funds would be made to EPBill with a 20-year matLrity, a 5-year grace period on repaymentof principal, and an interest rate of Libor plus 0.75%. The remaining 15% of project costs wouldbe the responsibility of EPBiH.

(viii) Other investments, based on EPBii-l's proposed investment plan, have been assumed to be financedby EPBiH's internally-generated funds and borrowings at similar termns as those proposed for theproject.

Based on the above key assumptions, the financial projections show that EPBiH would be able to maintaina satisfactory self-financing ratio, including contributing the required USS 7.7 million out of its own fundsto the cost of the project, a debt service coverage ratio of at least 1.5, and overall positive cash flow.EPBiH agreed to maintain a self-financing ratio of at least 40% and a debt service coverage ratio of at least1.5 during the project implementation period.

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EPHZHB


Demand for electricity in the region served by EPIIZHB fell sharply during the war. In 1996, distributiondemand was 605 GWh whereas the two large industrial consumers' production had come to a halt and thushad no demand for electricity. In addition, revenue collection as a percentage of annual billings reachedonly 65% in 1996. At the end of 2000, demand had increased to 1,630 GWh and the overall collection ratehad improved to about 89%.

According to the audited 1999 financial statements, EPHZIIB incurred a net loss of KM 3.2 million.Operating income before depreciation, interest and extraordinary items was KM 36 million, resulting in aworking ratio (cash operating expenses as a percentage of revenues) of 72%. A key reason for the relativelygood working ratio is EPHZHB's availability of hydropower. EPHZHB relies entirely on hydropower forits own production and resorts to imports to mneet demand in excess of its own capacity. EPHZHB cashflow was negative in 1999 due to an overall low collection rate of about 81% and distribution losses of24%, due to continued theft of electricity. The average tariff was Pf 10.38/kWh and Pf 4.87/kWh fordistribution and bulk consumers, respectively.

Based on unaudited financial information, perfonnance improved in 2000 and EPHZHB generated apositive cash flow. The improved performance is primarily due to a 11% increase in electricity sales (fromKM126 million to KM140 million) and a lower increase in operating costs (8%). In addition, the overallcollection rate as a percentage of 2000 billings improved to about 89%/o. Although the annual depreciationcharge is relatively high, EPHZHB managed to keep the operating ratio (cash operating and depreciationexpenses as a percentage of revenues) to about 100%. Distribution losses remained high at about 25%.


The future financial performance of EPHZHB is dependent on the continued availability of adequatehydropower which allows the company to keep its operating expenses down. In addition, continued growthin sales as a result of electrification of new areas, reductions in distribution losses and an overallimprovement in revenue collection will be required to maintain a profit on operations and positive cashflow. As with EPBiH, annual charges for depreciation are high. Given the importance of appropriatelyvalued assets and associated depreciation charges to accurately assess the financial performance ofEPHZHB and the requirements for tariff increases that cover cost, EPHZHB agreed to have its fixedassets revalued and its depreciation policies reviewed by qualified independent organizations, satisfactoryto the Association, by June 30, 2002.

Projections of the financial performance of EPHZHB over the period January 1, 2001 through December31, 2007 are presented in Annex 5 and elaborated in the Project Implementation Plan. The projectionshave been prepared to assess EPHZHB's capacity to meet debt servicing requirements and the requiredcounterpart funding of the project while, at the same time, remaining financially viable. The projectionsassume that:

(i) Distribution demand for electricity continues to increase, al a consistent pace from 2001 to 2007.(ii) Hydropower continues to be available to EPIIZIIB at the 1999 level.(iii) Distribution losses are reduced to 12% by 2004 and remain at that level thereafter.(iv) Tariffs increase at the rate of domestic inflation.(v) The costs for salaries and wages are kept constant in real tenns reflecting improvements in overall

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productivity and a reduction in staffing.(vi) Pre-war debt is allocated and debt-servicing of this debt takes place.(vii) The overall collection rate improves to 99% by 2002 and remains at that level thereafter.(viii) Extemal financing would finance 83% of the total project costs of the proposed project and the

loan funds would be made to EPHZHB with a 20-year maturity, a 5-year grace period onrepayment of principal, and an interest rate of Libor plus 0.75%. The remaining 17% of projectcosts would be the responsibility of EPHZHB.

(ix) Other investments, based on EPHZHB's proposed investment plan, would be financed byEPHZHB's intemally-generated funds and borrowings at similar terms as those proposed for theproject.

Based on the above key assumptions, the financial projections show that EPHZHB would be able tomaintain a satisfactory self-financing ratio, including contributing the required US$ 5.1 million out of itsown funds to the cost of the project, a debt service coverage ratio of at least 1.5, and overall positive cashflow. EPHZHB agreed to maintain a self-financing ratio of at least 40% and a debt service coverage ratioof at least 1.5 during the project implementation period.

EPRS


The post-war period has been difficult for EPRS as demand for electricity has been slow to resume,revenue collection has only improved slowly and the Dinar exchange rate suffered a significantdeterioration between 1997 and 1998. Sales from distribution have increased from 1,851 GWh in 1996 to2,183 GWh in 2000, but are still below the pre-war levels of 2,714 GWh. Revenue collection as apercentage of annual billings was only 52% in 1996 and improved to about 87% in 2000.

According to the audited 1999 financial statements, EPRS incurred a net loss of KM 191 million largelydue to the higher depreciation charge for the year. Operating income before depreciation, interest andextraordinary items was KM 95 million, resulting in a working ratio (cash operating expenses as apercentage of revenues) of 71%. One reason for the poor working ratio was high distribution losses. In1999, the average domestic tariff was Pf 10.14/kWh and distribution losses exceeded 26%. Revenuecollection as a percentage of yearly billings was 76%.

Based on unaudited financial information, 2000 continued to be difficult for EPRS. Despite an increase inthe average domestic tariff to Pf 11.90/kWh, revenue only increased by 4% due to the reduction inelectricity sold (including exports) from 4,080 GWh to 3,430 GWh. However, by limiting the increase inoverall operating expenses to under 8%, it is estimated that the net loss was reduced to KM 170 million.The working ratio remained constant at 71% in 2000, and the operating ratio (cash operating anddepreciation expenses as a percentage of revenues) improved slightly from 133% in 1999 to 131% in 2000.Distribution losses remained high at about 27%.


The future financial performance of EPRS is dependent on, inter alia, continued growth in sales as a resultof electrification of new areas, increased use by industrial and commercial users and return of refugees,reductions in distribution losses, and improvements in revenue collection. In addition, the annual charge fordepreciation of EPRS's assets will have a significant impact on the future financial performance. Given theimportance of appropriately valued assets and associated depreciation charges to accurately assess the

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financial performance of EPRS and the requirements for tariff increases that cover cost, EPRS agreed tohave its fixed assets revalued and its depreciation policies reviewed by qualified independent organizations,satisfactory to the Association, by June 30, 2002.

Projections of the financial performance of EPRS over the period January 1, 2001 through December 31,2007 are presented in Annex 5 and elaborated in the Project Implementation Plan. The projections havebeen prepared to assess EPRS's capacity to meet debt servicing requirements and the required counterpartfunding of the project while, at the same time, remaining financially viable. The projections assume that:

(i) Distribution demand for electricity continues to increase and excess capacity is exported.(ii) Distribution losses are reduced to 12% by 2004 and remain at that level thereafter.(iii) Tariffs increase at the rate of domestic inflation.(iv) The salaries and wages are kept constant in real terms after 2001 reflecting improvements in

overall productivity and a reduction in staffing.(v) The Govemment of the Republic of Srpska has taken over responsibility for all pre-war debt,

whereby the amount has been transferred to state capital. Therefore EPRS does not have anypre-war debt obligations.

(vi) The overall collection rate improves gradually to 96% in 2004, and remains at that level thereafter.(vii) External financing would finance 82% of the total project costs of the proposed project and the

loan funds would be made to EPRS with a 20-year maturity, a 5-year grace period on repayment ofprincipal, and an interest rate of Libor plus 0.75%. The remaining 18% of project costs would bethe responsibility of EPRS.

(viii) Other investments, based on EPRS's proposed investment plan, would be financed by EPRS'sinternally-generated funds and borrowings at similar terms as those proposed for the project.

Based on the above key assumptions, the financial projections show that EPRS would be able to maintain asatisfactory self-financing ratio, including contributing the required US$ 8.2 million out of its own funds tothe cost of the project, a debt service coverage ratio of at least 1.5, and overall positive cash flow. EPRSagreed to maintain a self-financing ratio of at least 40% and a debt service coverage ratio of at least 1.5during the project implementation period.

Fiscal Impact:

The Federal and RS Governments would enjoy a financial benefit since the onlending terms (20 yearmaturity with five years of grace at an interest rate of Libor plus 0.75%) of the IDA Credit are moreonerous to the Elektroprivredas than the terms these Governments enjoy (35 year maturity with 10 years ofgrace, IDA service charge of 0.75%). The net present value of this benefit at a discount rate of 12% isUS$ 18.1 million. The Entity Governments would not be required to make any contributions to cover costsrelated to the project since the main Implementing Agencies (the Elektroprivredas) are revenue eamingenterprises who would be expected to cover all local investment costs as well as subsequent O&M costs,and take full responsibility for debt service. There would be no import duties on goods and servicesimported for the project since projects to repair war damages are exempt from such duties. However, thereis a 10% local tax on local cost investments under the project. The total tax revenue to municipalgovernments from this tax is estimated at US$ 4.3 million equivalent. The indirect fiscal impact of theproject would be positive to the extent that the project improves the financial performance of the companiessufficiently to enable them to pay corporate taxes. Current forecasts indicate that only EPHZHB would besubject to corporate tax and the amounts it would pay would be small. There would be a further positiveimpact to the extent that the project contributes to overall economic expansion thereby allowing furtherincreases in tax revenue.

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3. Technical:

A feasibility study has been prepared by AGRA Monenco-Teshmont for the transmission, distribution andhydropower components, with financing from the Canadian Consultants Trust Fund. A separate feasibilitystudy is being prepared for the SCADA component, with financing by USTDA. The analyses of theenvironmental investments at thermal power sta.tions are presented in the Environmental Management Plansprepared by the Elektroprivredas.

4. Institutional:

4.1 Executing agencies:

The executing agencies for the project would be the three Elektroprivredas that own and operate the powersystem of Bosnia and Herzegovina (BiH). In addition, ZEKC and the new regulatory agencies wouldreceive technical assistance and part of the SCADA investments under the project.

Elektroprivreda Bosnia and Herzegovina (EPBiH) is a vertically integrated power utility, owned by theGovernment of the Federation of Bosnia and Herzegovina (FBiH). As the successor to the pre-war.Republic-wide Elektroprivreda Bosne i Hercegovine, EPBiH was established by a Decree-Law on theElectricity Industry issued in September 1993 (Bulletin 1), and was registered by a Decision of the HighCourt in Sarajevo dated July 21, 1993.

EPBiH is supervised by a Management Board, two-thirds of whose members are appointed by theGovernment of FBiH, and the remaining third by the company. The Chairman of the Management Board isthe FBiH Assistant Minister of Energy, Mining, and Industry responsible for Electricity.

The Directorate of EPBiH in Sarajevo is divided between six departments: Generation, Transmission andSystem Control, Distribution, Research and Development, Economic and Financial Affairs, and HumanResources. The heads of these departments report to the General Manager, who in turn reports to theManagement Board. Including the Directorate, there are 13 business operating units within EPBiH: Ihydropower unit (managing three power plants on the Neretva River); 2 thermal power units (eachmanaging one of EPBiH's thermal power plants); 1 transmission unit; 7 distribution units; a Research andDevelopment Institute; and the Directorate.

Elektroprivreda of the Croatian Community of Herzeg-Bosnia (EPHZHB) is a vertically integratedpower utility established under the FBiH Law on Enterprises (Official Gazette of FBiH No. 2/95). Thecompany's capital is divided between 35 municipalities in 6 Cantons which constitute the company's serviceterritory.

The senior management of EPHZHB is undertaken by the Company Assembly, a Supervisory Board, aManagement Board, and the Directorate. The Company Assembly comprises representatives of themunicipalities that own shares in the capital of the company. The Company Assembly appoints anddismisses the Management Board and the Supervisory Board. The Supervisory Board has three members.and acts as a secretariat to the Company Assembly. The Management Board has seven members, and isresponsible for appointing and dismissing the General Director of the company. Of the remaining fourmembers, one is appointed by EPHZHB, and thwe others from the municipalities that own the company.

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The Directorate of EPHZHB in Mostar is divided into seven departments: Generation; Transmission;Distribution; Research and Development; System Control and Operation; Finance; and Legal, Personnel,and Administrative. The heads of these departments report to the General Manager, who in turn reports tothe Management Board. EPHZHB treats each of its non-operational departments as a separate cost center,so that there are 44 business operating units within EPHZHB: 4 hydropower units (one for each of thecompany's four hydropower plants); I transmission unit; 34 distribution units (managed by fiveDistribution Sub-departments, one for each Canton in which EPHZHB has service territory); the Researchand Development department; the System Control and Operation department; the Finance department; theLegal, Personnel, and Administrative department; and the Directorate.

Elektroprivreda Republika Srpska (EPRS) is a public enterprise established by the Republika Srpska(RS) Law on State Enterprises (Official Gazette of the RS No. 3/95), and the RS law on the ElectricityIndustry (No. 01-203/97, adopted on April 23 1997), and wholly owned by the RS Government.

EPRS is supervised by a Management Board, which is overseen by a Supervisory Board appointed by theRS Government. The Management Board has seven members, of which three are internal appointments bythe Elektroprivreda, and four are appointed from outside the Elektroprivreda by the RS Government. TheSupervisory Board has five members, of which one is appointed by the Elektroprivreda, and four areappointed from outside the Elektroprivreda by the RS Government.

The public enterprise EPRS consists of 11 legally independent operating companies and a Directorate inTrebinje. Although not a legally constituted holding company, since ownership of the operating units is notvested in the Directorate, EPRS acts as such in practice. Each of the 11 operating companies has its ownManagement Board, responsible for that operating company, and accountable to the EPRS ManagementBoard.

The Directorate of EPRS in Trebinje is divided between four departments: Technical, Development,Economic and Financial, and Organizational and Legal. Including the Directorate, there are 12 operatingcompanies within EPRS: 2 thermal power generation companies (one for each of the thermal power plantsin the RS, and each including the associated coal mines); 3 hydro power generation companies (one foreach of the hydropower plants in the RS); 5 distribution companies (one for each region of EPRS' serviceterritory); I transmission company; and the Directorate.

The technical and managerial capacity of the Elektroprivredas to implement the project has beendemonstrated and enhanced by their satisfactory preparation and implementation of Power 1 and Power 2.The design of the major part of the project investments has been undertaken by the Elektroprivredas inconjunction with intemational consultants (for EPHZHB and EPRS), and internationally accepted technicalcriteria and standards have been applied.

However, the organization of all three Elektroprivredas is in both operational and financial terms complexand inefficient. Hence, technical assistance would be provided under the project to improve theElektroprivredas' financial and management inforrnation systems, and to implement restructuring(primarily vertical disintegration) in accordance with the 1996 EU Electricity Directive. Experience fromsimilar projects within the Europe and Central Asia Region has demonstrated that the second of theseinitiatives would not affect the EPs' capacity to implement the project, and that the first would probablyimprove it.

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The Joint Power Coordinating Center (ZEKC) was established by the three Elektroprivredas in March1999 as a business association registered in FBiH and headquartered in Sarajevo. It has a three-personmanaging board, with one member appointed by each Elektroprivreda, and a three-person managementteam, with one manager appointed by each Elektroprivreda. The ZEKC assets are jointly owned by theElektroprivredas.

ZEKC currently acts as an information exchange for the BiH system, collating hourly data and relaying itto the control centers of the three Elektroprivredas. It also prepares the annual electricity balance for BiH.The Articles of Agreement of ZEKC include an agreed schedule for the development of the Center'sresponsibilities for the operation of the BiH power system. A complementary plan, detailing the plannedexpansion of the Elektroprivredas' contributions of human and financial resources to ZEKC in order toenable it to meet these responsibilities, was submitted to the Association in January 2000. Technicalassistance would be provided under the project to assist with the implementation of the development plan,and with the achievement of the schedule of responsibilities set out in the Articles of Agreement of ZEKC.

4.2 Project management:

The project management arrangements used under Power 2 would be continued. In the RS, all aspects ofproject management would be dealt with by a single Project Implementation Unit (PIU), located in andstaffed by EPRS. In the FBiH, a Federal PIU located in and staffed by the Federation Ministry of Energy,Mining, and Industry (FMERI), would undertake the coordination of the two EP PIUs located in andstaffed by EPBiH and EPHZHB respectively, which would undertake the day-to-day management of theproject.

The staff of the four PIUs are experienced in the management of IDA-financed projects through theirmanagement of Power 1 (EPBiH) and Power 2. The staffing of the Elektroprivreda PIUs is beingstrengthened in accordance with needs identified by the Procurement Capacity Assessment and theFinancial Management Review. In addition, the PIUs' project management capacities would be supportedand improved by continued technical assistance from an international consultant who would assist in theprocurement process, oversee the implementation of the contracts, and provide training to the PIUprocurement staff.

See also Section C.4.

4.3 Procurement issues:

The project implementation would require procurement of goods and works, and selection and employmentof consulting firms to carry out consulting services. The PIUs responsible for implementation of Power 2(the Federal PIU, the branch PIUs in EPBiH and EPHZHB, and the PIU in EPRS) would continue for theproposed project. The Procurement Capacity Assessment has identified the need for strengthening each ofthe Elektroprivreda PIUs with qualified procurement staff. The Federal PIU would not require anystrengthening since it would not be handling procurement matters under the project. In addition,international consultants would work together with the PIUs of the three EPs during projectimplementation. The foreign consultants would be employed to assist in procurement activities for therehabilitation of the transmission lines included in the project and for the Rama Hydro Power project. Theywould also provide in-house training to the Elektropriovredas' procurement staff. A procurement workshopwould be organized by the Association immediately after Credit effectiveness to ensure that the agreedprocurement procedures are well understood by PIU staff.

See also Annex 6.

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4.4 Financial management issues:

Financial Management arrangements and issues are discussed in Section C.4 above and in Annex 11.

5. Environmental: Environmental Category: B (Partial Assessment)5.1 Summarize the steps undertaken for environmental assessment and EMP preparation (includingconsultation and disclosure) and the significant issues and their treatment emerging from this analysis.

Consistent with the requirements for a Category "B" project, Environmental Management Plans (EMPs)were prepared by the three Elektroprivredas, who have also agreed to implement the associated mitigationactions (Section G.2(n)). The EMPs are in the Project Implementation Plan.

5.2 What are the main features of the EMP and are they adequate?

The EMPs, which are considered adequate, have identified the following issues:

Transmission lines

The major issue associated with the restoration of the transmission system is to assure that thesystem being restored is safe with respect to exposure of local residents to electromagnetic radiationby establishing that the levels are within acceptable limits (BiH, EU standards, etc.) duringoperation. Other issues are associated with movement of men, materials, and equipment duringconstruction (noise, dust) and noise and communication interferences during operation.

Transmission substations

The major issue is the possible presence of polychlorinated biphenyls (PCBs) in the transformers orother equipment in the substations (e.g. condensers) and, if found, the manner in which the PCBs willbe disposed of. Minor issues include establishing that exposure of local residents to electromagneticradiation and noise from restored substations is within acceptable limits (BiH, EU standards, etc.).Additionally, if any of the existing transformers have experienced leaks, the possibility of existingsoil and/or groundwater contamination will be investigated.

Distribution

A minor issue is associated with disruption to transport, communications, etc. during theconstruction phase.

Thermal Power Stations

Since the objective is to reduce pollution, there should be no major negative environmental issues.

Hydropower Stations

Since the objective is to rehabilitate existing plants in order to improve safety and availability, thereshould be no negative environmental issues.

Associated mitigation actions are identified in the EMPs.

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5.3 For Category A and B projects, timeline and status of EA:Date of receipt of final draft: March 2000.

5.4 How have stakeholders been consulted at the stage of (a) environmental screening and (b) draft EAreport on the environmental impacts and proposed environment management plan? Describe mechanismsof consultation that were used and which groups were consulted?

See Section E.6.2 below.

5.5 What mechanisms have been established to monitor and evaluate the impact of the project on theenvironment? Do the indicators reflect the objectives and results of the EMP?

The particulate emissions at Tuzla (Unit 5) and at Kakanj (Unit 7) will be monitored to evaluate the impactof the rehabilitation of the electrostatic precipitators.

6. Social:6.1 Summarize key social issues relevant to the project objectives, and specify the project's socialdevelopment outcomes.

Substantial direct benefits would accrue to consumers who rely on electricity for cooking and space heatingand at present have to endure limited or irregular supply, as well as to returning refugees for whom new orreconstructed connections will be installed. The improvement of system-wide efficiency and the increase inelectricity trade would over the medium to long term reduce the unit cost of electricity supply and hencerepresent a major benefit to the economy as a whole. However, since household tariff rates are below cost,there may not be any price reduction even in the long term. Over the short to medium term, improvedcollection of bills and the removal of distortions between household and other tariff rates under the projectcould impose additional costs on household consumers.

Since poverty is widespread, and especially so amongst the refugee population, measures to target both theincidence of project-related benefits and the mitigation of project-related costs to the poor would besupported under the project.

In order to facilitate the targeting of project-related benefits, those donors planning to fund investments inthe low-voltage distribution network are undertaking case-by-case feasibility studies in close coordinationwith the inter-agency Refugee Return Task Force (RRTF) to ensure that returning refugees and the poorwill benefit.

With regard to the mitigation of the social impact of improved collections and tariff reforms, a socialassessment would be carried out under the project. The principal aim of this social assessment would be toinform the design of tariff reform programs in both Entities in conjunction with the tariff study carried outunder the European Bank for Reconstruction and Development's Emergency Power Reconstruction Project,and to ensure that refugees, the poor, and the socially vulnerable are not disadvantaged by them. Asupplementary aim of the social assessment would be to inform the design of future investment projects ofthe Elektroprivredas by establishing the priority areas of concem to consumers in terms of servicecoverage, quality, and reliability.

The social assessment would incorporate both a quantitative study of household expenditure on electricityservices and substitutes and the impact of possible tariff increases, and a qualitative consumer satisfactionsurvey. The quantitative study would assess household consumption of and expenditure on electricityservices. In combination with the household survey for Bosnia and Herzegovina due to be completed in

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2001, this study would enable a comparative analysis of the impact of tariff increases during 2000-2001 onhousehold welfare, and particularly on refugees, the poor, and the socially vulnerable.

The consumer satisfaction survey would focus on the following topics:

(i) Priority areas for rehabilitation and reconstruction of distribution networks;(ii) Service quality and reliability;(iii) Payment and collection mechanisms;(iv) Formal and informal mechanisms to cope with service cut-off; and(v) Patterns of electricity and substitute service consumption.

6.2 Participatory Approach: How are key stakeholders participating in the project?

The primary beneficiaries of the project are residential, commercial and industrial consumers, includingreturning refugees and other, vulnerable, low income users. The vulnerable users are participating in theproject through the social assessment to be carried out under the project.

Key stakeholders in the project are the three Elektroprivredas, the Joint Power Coordinating Center, theFederation Ministry of Energy, Mining, and Industry (FMERI), and the Republika Srpska Ministry ofEnergy and Industry (RSMEI). Other key stakeholders in the project include the International Communityin Bosnia and Herzegovina involved in the reconstruction and economic reform efforts. Key stakeholderswithin the International Community in Bosnia and Herzegovina have been involved in project design, andwould be further involved in the project's implementation. Participation has been ensured by continuingconsultation with the Energy Sector Core Task Force, the Office of the High Representative, and bilateraldonor agencies with programs in refugee return, poverty alleviation, and the power sector itself.

The Elektroprivredas' environmental management plans, which involve new environmental investments,have been prepared in consultation with consumer groups and local non-governmental organizations(NGOs). In the preparation of the reconstruction components, on the other hand, there has not been directparticipation of final electricity consumers or NGOs, since the project aims to rehabilitate (and wherepossible improve) existing facilities. Wider participation in the planning of these reconstructioncomponents was not invited for the following reasons:

(i) As far as is known, there is no significant disagreement within BiH on the need to rehabilitate theelectric power system. Since the project would rehabilitate existing facilities rather than constructnew ones, its justification and implementation would be relatively straightforward, and it wouldhave minimal adverse environmental impacts;

(ii) There is broad agreement on the need for rapid action in order to improve electricity service assoon as possible to households, services and industry; and

(iii) The project's components would affect large numbers of persons spread throughout BiH so itwould be impractical to involve all affected final consumers directly.

6.3 How does the project involve consultations or collaboration with NGOs or other civil societyorganizations?

See Section E.6.2 above.

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6.4 What institutional arrangements have been provided to ensure the project achieves its socialdevelopment outcomes?

See Section E.6.2 above.

6.5 How will the project monitor perfonnance in terms of social development outcomes?

Follow-up on consultations with the stakeholders will be carried out at the mid-term and project completionreviews.

7. Safeguard Policies:7.1 Do any of the following safeguard policies apply to the project?

L~v _ _ _ _ _ _ __':

Environmental Assessment (OP 4.01, BP 4.01, GP 4.01) * Yes 0 NoNatural habitats (OP 4.04, BP 4.04, GP 4.04) 0 Yes * NoForestry (OP 4.36, GP 4.36) 0 Yes * NoPest Management (OP 4.09) 0 Yes * NoCultural Property (OPN 11.03) 0 Yes * NoIndigenous Peoples (OD 4.20) 0 Yes * NoInvoluntary Resettlement (OD 4.30) 0 Yes 0 NoSafety of Dams (OP 4.37, BP 4.37) 0 Yes 0 NoProjects in International Waters (OP 7.50, BP 7.50, GP 7.50) 0 Yes * NoProjects in Disputed Areas (OP 7.60, BP 7.60, GP 7.60) 0 Yes * No

7.2 Describe provisions made by the project to ensure compliance with applicable safeguard policies.

Environmental Mitigation Plans have been prepared in accordance with the requirements for a Category"B" project, and implementation of the mitigation actions is covenanted.

F. Sustainability and Risks

1. Sustainability:

Factors critical for sustainability include: (i) continued political stability; (ii) continued macroeconomicprogress in both Entities, which is needed to restore consumers' ability to pay for electricity; (iii)satisfactory financial performance of the three Elektroprivredas; (iv) satisfactory coordination between theenterprises to operate the BiH power system as a whole; and (v) steady progress towards establishing astrong regulatory framework, a competitive power market, and an environment that encourages privateinvestment in the power sector. A further contributor to sustainability would be restoration of 400 kVtransmission facilities in neighboring countries (especially reconstruction of the Emestinovo substation andassociated transmission lines). At this time, the prospects for sustainability of Power 3 are likely.

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2. Critical Risks (reflecting the failure of critical assumptions found in the fourth column of Annex 1):

Risk Risk Ratin_ Risk Mitigation MeasureFrom Outputs to ObjectiveInsufficient equipment maintenance N Ensure satisfactory financial performance of the

Elektroprivredas.

Failure to operate the BiH 400 kV and S The Elektroprivredas have made written220 kV power networks on an integrated commitments to operate the BiH system as abasis single control area in accordance with UCTE

requirements. A covenant is included.

Inadequate regulatory arrangements S Entity governments have adopted satisfactorypolicy statements and presented satisfactorydraft electricity laws to Parliaments. Datedcovenants for implementation and technicalassistance are included.

Failure to commission a restructuring and S Dated covenants are included, and donorprivatization study and agree on an action financing for the study is available.plan for implementation.

Delay in reconstruction of Croatia's M Delay reconstruction of theEmestinovo 400 kV substation Ugljevik-Emestinovo transmission line until

implementation of Emestinovo reconstructionbegins.

From Components to OutputsFailure to secure full financing M Reasonably firm cofinancing commitments have

been obtained for all except US$ 13.6 million.EIB has indicated an interest in financing thisgap. Failure to close the gap would notjeopardize the rest of the project, since thecomponents without financing are separate.

Failure by Implementing Agencies to N Ensure satisfactory financial performance by thecover all local costs Implementing Agencies. No problems have been

experienced in the financing of the local costsunder Power I and Power 2.

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Delayed project completion M Delays for technical reasons are unlikely sincethe project is for rehabilitation only. EachElektroprivreda has an effective PIU andtechnical assistance will be provided to thePlus.

Cost overrun M Adequate physical and price contingencyallowances have been provided in the costestimates.

Overall Risk Rating M Power 1 was completed on time and within cost.Power 2 has more ambitious institutionalreforms; its effectiveness was delayed by theAssociation's decision to first ensure theestablishment of ZEKC. While Power 3 haseven more ambitious objectives than Power 2,risks have been reduced by choosing realisticgoals and deadlines and by deepening theAssociation's relationship with theElektroprivredas.

Risk Rating - H (High Risk), S (Substantial Risk), M (Modest Risk), N(Negligible or Low Risk)

Special attention was paid to two risks. The first is that the Ernestinovo substation in Croatia andassociated transmission lines will not be reconstructed within the next few years. Before the war, thissubstation was an important node in the 400 kV grid which linked together the power transmission systemof former Yugoslavia. Until it or a substitute is put into operation, an important part of the internationalbenefits of the project, through improved power interchanges in the Balkans, will not be realized. Inaddition BiH would not earn any revenue from wheeling power between north-eastern Croatia and westernCroatia. The wheeling benefit has a present value of US$ 8.9 million. Reconstruction of theUgljevik-Emestinovo transmission line, for which the BiH portion is estimated to cost US$ 4.05 million,will not be started until work begins on reconstructing Ernestinovo and the associated transmission lines.Once the 400 kV system is completely restored there is still a risk that the wheeling revenue will be smallerthan US$ 8.9 million. Since the total net present value for the project is US$ 1,166 million, the impact ofthis risk on the overall project benefits is negligible.

The second risk receiving special attention is that the BiH power system will not be operated as anintegrated system after the transmission systeim is rehabilitated and the SCADA system is completed. Thepossible consequences would be the following:

- The SCADA investment of about US$ 7.8 million made for ZEKC would be wasted sincenon-integrated operation implies that ZEKC would be ineffectual. The SCADA investments in theregional dispatch centers and the associated communications networks would still be useful.

- BiH would be unable to rejoin the UCTE as a separate control area. Its membership might befurther delayed as a result. A possible scenario involving UCTE membership is that the Federationwould become part of the Croatia control area and RS would become part of a future FRY controlarea. In such a scenario-additional metering investments would be needed at the interface between

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the Federation and RS power systems that would not be required if BiH is accepted as a singlecontrol area. Additional investments might be needed within the Federation to permit it to meet theprimary and secondary regulation and other requirements of UCTE members that would not beneeded if BiH were a single control area.

Non-integrated operation would likely result in more frequent and longer power outages thanintegrated operation. Both EPRS and EPHZHB have experienced system outages related tobreakdowns in their interconnections with the FRY and Croatian power grids respectively.

When the BiH system is operated under non-integrated mode, with the EPRS and Federationnetworks not synchronized with each other, it would not be possible for EPRS to supply the fullpower demand in northem RS. This problem is due to the fact that most of the power generatingcapacity belonging to EPRS is in eastern and southern RS, whereas the main demand centers are inthe north and it is not possible to transmit additional power between the two parts of RS withoutgoing through transmission lines belonging to EPBiH and/or EPHZHB. It is estimated that therewas a shortfall of 345 MW in northern RS out of a total load of 680 MW in the year 2000. Thisparticular problem is being resolved through a specific arrangement under which EPBiH issupplying the power to northern RS. Integrated operation would allow more efficient transmissionof this power.

Non-integrated operation would not allow the Elektroprivredas to enjoy the benefits of wheelingpower to foreign markets evaluated in the cost-benefit analysis since in each case the power wouldneed to be transmitted through the transmission lines of more than one Elektroprivreda. Withnon-integrated operation, these problems would likely be resolved through specific transitagreements, but less efficiently.

- Non-integrated operation would not allow fault levels at Capljina to be raised sufficiently to allowthis power station to be used for pumped storage.

- Transmission system losses would be larger under non-integrated operation.

An economic cost-benefit analysis of the transmission and SCADA systems for the scenario ofnon-integrated operation reduced the combined rate of return for these project components from 55% to24%. This result is still satisfactory, but the difference between the two measures confirms that thebenefits of integrated operation are substantial.

3. Possible Controversial Aspects:

None.

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G. Main Credit Conditions

1. Effectiveness Conditions

(a) Execution of subsidiary credit agreements between the Borrower and the Federation/EPBiH, theFederation/EPHZHB and RS/EPRS.

(b) Assignment of a skilled and experienced procurement officer in each of the PIUs of EPBiH.EPHZHB and EPRS.

(c) Appointment of an independent auditor acceptable to the Association by each of EPBiH, EPHZHBand EPRS.

2. Other [classify according to covenant types used in the Legal Agreements.]

The Borrower has agreed to:

(a) onlend the IDA credit:

to the Federation Government for 35 years with a 10 year grace period and at the standardIDA service charge;

* through the Federation Government to EPBiH and EPHZHB at Libor plus 0.75% with 20years of repayment including five years of grace;

* through the RS Government to EPRS at Libor plus 0.75% with 20 years of repaymentincluding five years of grace; and

(b) prepare and furnish by April 30, 2003 a report integrating the results of monitoring and evaluationactivities, on the progress achieved in the carrying out of the project preceding this date, and settingout the measures recommended to ensure the efficient carrying out of the project and theachievement of the objectives thereof during the period following this date.

The Federation and Republika Srpska have agreed to:

(a) start implementation of power sector restructuring and regulatory reform actions contained in thepolicy statements approved by the Governments, including:

commissioning of a comprehensive study of the sequence, extent and timing ofrestructuring and privatization of the Elektroprivredas in accordance with terms ofreference acceptable to the Association and by consultants acceptable to the Association,with the study to be completed by December 31, 2001;

on completion of the restructuring and privatization study, developing and agreeing withthe Association by February 28, 2002, detailed restructuring and privatization action plansincluding an implementation schedule, followed by implementation of the agreed actionplans, with no prior restructuring or privatization of the Elektroprivredas taking place; inthe case of EPRS, no prior privatization will take place other than the purchase withvouchers of warrants under conditions acceptable to the Association, with the warrants

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entitling the bearer to purchase common shares upon the conversion of the constituententerprises of EPRS into joint stock companies, with this conversion only taking placeafter the action plan has been agreed upon and in strict accordance with that plan;

appointment of independent Entity and State Regulatory Commissions by December 31,2001; and

- establishment of an Independent System Operator by March 31, 2002.

EPBiH, EPHZHB and EPRS have agreed to:

(a) produce for each fiscal year after the fiscal year ending on December 31, 2001, funds from internalsources equivalent to not less than 40% of their respective capital expenditures estimated inadvance at a level satisfactory to the Association;

(b) review with the Association, by October 15 of each year commnencing in 2001, their respectiveproposed capital expenditures for the following five years, and take the Association's views intoconsideration in finalizing the programs;

(c) before October 15 in each fiscal year, commencing in 2001, on the basis of forecasts prepared bythem and satisfactory to the Association, review jointly with the Association whether they will meetthe requirements set forth in Para (a) above in respect of such year and the next following fiscalyear. If such a review shows that the requirements will not be met, the respective Elektroprivredashall take all necessary measures to meet such requirements;

(d) not incur new debt unless the debt service requirements are covered at least 1.5 times by netinternal cash generation;

(e) have their assets revalued and depreciation policies reviewed by qualified independentorganizations by June 30, 2002;

(f) develop and agree with the Association, by September 30, 2002, a plan to carry out adjustments inthe structure and levels of electricity tariffs to ensure satisfactory financial performance and toreflect cost of supply, taking into account both the results of the social assessment study to mitigatethe impact on the vulnerable segments of society and the revised depreciation charges, andimplement the agreed plan;

(g) submit within 6 months after the closure of each fiscal year project accounts and financialstatements audited by an independent auditor acceptable to the Association;

(h) make cash payments to the coal mines of at least 75% of the value of coal consumed each month,starting January 2002, and attaining 100% cash payment by December 31, 2002 (EPBiH);

(i) reduce and maintain total distribution losses below 12% for EPBiH, and below 19% by 2002, 16%by 2003 and 12% by 2004 for EPHZHB and EPRS.

(j) on completion of the rehabilitation of the high-voltage transmission network under Power 3,operate the power system in Bosnia and Herzegovina as a single control area according to UCTErules, within the UCTE Control Block covering Slovenia, Croatia and Bosnia and Herzegovina; in

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the event that the system of the Federal Republic of Yugoslavia remains disconnected from theUCTE system, selected EPRS generating units could be isolated, if desired by EPRS, from the restof the system in order to sell power to the Federal Republic of Yugoslavia network;

(k) revise the ZEKC Book of Rules and Grid Code by December 31, 2001 to bring them intoconformity with the Electricity Policy Statements and to remove discrepancies and overlapsbetween these two documents;

(1) reach agreement by December 31, 2001 with the Association on a plan and schedule covering theadditional resources to be provided by the Elektroprivredas to ZEKC to enable it to perform thefunctions assigned to it under the November 1998 agreement and to enable it to function as theIndependent System Operator, and implement the plan in accordance with the agreed schedule;

(m) establish a satisfactory company imanagement information system (including a financialmanagement system based on international accounting standards) in each of the Elektroprivredasby December 31, 2003; and

(n) furnish and agree with the Association by December 31, 2001 revised implementation schedulesfor the Environmental Management Plans (EMPs) and thereafter implement the EMPs inaccordance with these schedules.

H. Readiness for Implementation

L1 1. a) The engineering design documents for the first year's activities are complete and ready for the startof project implementation.

El 1. b) Not applicable.

I] 2. The procurement documents for the first year's activities are complete and ready for the start ofproject implementation.

1 3. The Project Implementation Plan has been appraised and found to be realistic and of satisfactoryquality.

01 4. The following items are lacking and are discussed under loan conditions (Section G):

1. Compliance with Bank Policies

O 1. This project complies with all applicable Bank policies.El 2. The following exceptions to Bank policies are recommended for approval. The project complies with

all other applicable Bank policies.

Mian Iftikhar Khalil Henk Busz staan J. PoortmanTeam Leader Sector Manager/Director Country ManagerlDirector

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Annex 1: Project Design Summary

BOSNIA AND HERZEGOVINA: Third Electric Power Reconstruction Project

HIrarO f Ob & Indclc- s Mon4lorl" & Evaluatbn Cultial AsumpmionsSector-related CAS Goal: Sector Indicators: Sector! country reports: (from Goal to Bank Mission)

Strengthen institutions and 1. Improved revenue 1. Continued politicalgovernance. collection relative to amounts stability.

billed. 2. Satisfactory economic2. Convert ZEKC to ISO. growth.

Foster private sector-led Energy laws and regulatory Same.growth and employment. agencies.

Project Development Outcome I Impact Project reports: (from Objective to Goal)Objective: Indicators:

Ensure access to reliable, 1. Increased restored and new 1. Project progress reports. 1. Continued progress inlower cost electricity, to be connections. 2. Supervision reports. cooperation between thesupplied with reduced 2. Reduced distribution losses 3. Mid-term review. Elektroprivredas.environmental and safety and avoidance of increase in 2. Continued efforts byrisks, and improved cost transmission losses. suppliers to improve billrecovery by the suppliers. 3. Reduced particulate collection and reduce

emissions at rehabilitated non-technical distributionthermal power stations. losses.4. Improved self-financing of 3. Government willingness toinvestments. raise electricity prices when5. Improved revenue needed to ensure the suppliers'collection relative to amounts financial viability.billed.6. Satisfactory debt servicecoverage ratio.

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* Mon¢ . . v iion ~r.i iTtiUNilons|

Output from each Output Indicators: Project reports: (from Outputs to Objective)Component:Increase transmission Length of transmission lines 1. Project progress reports. Satisfactory maintenance ofcapacity. and number of substations 2. Supervision reports. restored facilities.

restored. 3. Mid-term review.

Increase distribution capacity. Completion of planned Same. Successful coordination withexpenditures. refugee return.

Improve coordinated Increased gross power flows Same. Increased role of ZEKC inoperation of the BiH power between the EPs. economic dispatch of powersystem. throughout BiH.

Establish a legislative and Passage of laws and physical Same. Willingness by Governmentsregulatory framework establishment of regulatory to establish and carry out anconducive to privatization and agencies. effective reform policy.competition.

Prepare restructuring and 1. Completion of study. Same. Prompt and fullprivatization. 2. Adoption of satisfactory implementation of the adopted

plans. plans.

Improve availability and Completion of planned Same.safety at hydropower plants. expenditures.

Reduce pollution at thermal Reduced particulate emissions Same. Satisfactory maintenance ofpower plants. at specified plants. pollution control

arrangements.

Establish new management Beginning of operation of the Same. Adjustment of the plannedinformation systems. new systems. systems to fit the restructured

sector.

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. . ~~~Key PentormamHI2,rphy .s, ~ctlv.. __________A O ,, Mrai A#w"ImpU.

Project Components / Inputs: (budget for each Project reports: (from Components toSub-components: component) Outputs)Transmission. US$ 91.1 million 1. Project progress reports. 1. Avoided delay.

2. Supervision missions. 2. Avoided cost overruns.3. Mid-term review.

Distribution. US$ 42.9 million Same. Same.

SCADA and communications US$ 44.2 million Same. Same.facilities.

Availability and safety US$ 22.6 million Same. 1. Securing of full financing.investments at hydropower 2. Avoided delay.stations. 3. Avoided cost overruns,

Environmental investments at US$ 16.9 million Same. Same.thermal power stations.

Technical assistance for US$ 13.4 million Same. 1. Securing of full financing.procurement, social 2. Avoided delay.assessment, power sectorregulation, and managementinformation systems.

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Annex 2: Detailed Project DescriptionBOSNIA AND HERZEGOVINA: Third Electric Power Reconstruction Project

The proposed project would combine the continuation of the post-war reconstruction of the BiH powersector with support for restructuring and reform. A major objective would be to rehabilitate the damaged400 kV network in order to enable BiH to operate its power system on an integrated basis and to rejoin theUnion for the Coordination of Transmission in Europe (UCTE).

There would be seven principal project components:

I . Rehabilitation of the high voltage transmission network lines started under Power 2.

2. Reconstruction of key 400/220/110 kV substations.

3.. Establishment of a Supervisory Control and Data Acquisition (SCADA) System and associatedtelecommunications facilities.

4. Investrnents at the Jablanica, Rama ancl Trebinje hydropower stations to improve safety andavailability.

5. Investments at the Tuzla, Kakanj, Gacko and Ugljevik thermal power stations to control pollution.

6. Distribution investments focussing on:

(i) areas identified for refugee return;(ii) heavily damaged and cut-off areas, which have little or no electricity supply;(iii) areas with seriously overloaded networks, due to resettlement of refugees; and(iv) areas with war damage where rnany connections are of a temporary nature and power

supply is unreliable and unsafe.

7. Technical assistance and training in support of:

(i) procurement and implementation of the physical components;(ii) the development of the Joint Power Coordinating Center (ZEKC) into an Independent

System Operator for the BiH system;(iii) a survey of socially vulnerable electricity consumers;(iv) corporatization and commercialization of the power sector enterprises; and(v) establishment of independent power sector regulatory agencies for BiM.


The various project sub-components (with costs excluding physical and price contingencies in brackets) aredescribed below.

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By Component:

Project Component 1 - US$26.54 million

Transmission Lines

Transmission Lines (EPBiH) (Total US$ 11.56)


1) TL 400 kV Sarajevo 10 - Mostar 4 (US$ 4.49 million).

2) TL 400 kV Sarajevo 10 - Sarajevo 20 (US$ 0.87 million).

3) TL 400 kV Mostar 4 - Gacko (US$ 1.20 million).

4) TL 400 kV Visegrad - Tuzla (US$ 1.58 million).

5) TL 400 kV Ugljevik - Emestinovo (US$ 1.30 million).

6) TL 220 kV Jajce - Mraclin (US$ 0.67 million).

7) TL 220 kV Tuzla - Gradacac - Djakovo (US$ 0.12 million).

8) TL 110 kV Mostar - Nevesinje (US$ 1.34 million).

Transmission Lines (EPHZHB) (Total US$ 4.15 million)


1) TL 400 kV Sarajevo 10 - Mostar 4 (US$ 0.83 million).



4) TL 220 kV Jajce - Mraclin (US$ 0.10 million).

5) TL 220 kV Kakanj - Prijedor (US$1.08 million).

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Transmission Lines (EPRS) (Total US$ 10.83 million)

Reconstruction of war damage, including right-of-way clearing, replacement of damaged parts of existingtowers, construction of new towers to replace destroyed ones, dismantling of damaged insulators, hardwareand conductors and ground wires, and stringin,g, along the following lines:

1) TL 400 kV Visegrad - Tuzla (US$ 2.52 million).


3) TL 400 kV Sarajevo 10 - Sarajevo 20 (US$ 0.84 million).


5) TL 220 kV Jajce - Prijedor (US$ 0.66 million).

6) TL 220 kV Prijedor - Sisak (US$ 0.74 million).

7) TL 220 kV Tuzla - Gradacac - Djakovo (US$ 1.05 million).

8) TL 110 kV Mostar - Nevesinje (US$ 1.60 million).

9) TL 220 kV Dubrovnik- Trebinje (US$ 0.16 million).


Transmission Substations

Substations (EPBiH) (Total US$ 15.40 million)

1) TS 400/220/110 kV Tuzla (US$ 5.21 million): Rehabilitation of primary electrical equipmentincluding replacement of 420 kV, 220 kV and 110 kV circuit breakers, 420 kV, 220 kV and 110 kV busbardisconnectors, 400 kV line disconnectors, instrument transformers, arresters, post insulators and secondaryequipment comprising protection and remote control equipment, owner consumption (rectifier and inverter)

2) TS 400/110 kV Sarajevo 10 (US$ 3.44 million): Rehabilitation of primary electrical equipmentincluding replacement of 420 kV and 110 kV circuit breakers, 420 kV and 110 kV busbar disconnectors,420 kV and 110 kV line disconnectors, instrument transformers, arresters, post insulators and secondaryequipment comprising protection and remote control equipment, owner consumption (rectifier).

3) SG 220 kV Kakanj (US$ 1.21 million): Rehabilitation of primary electrical equipment includingreplacement of instrument transformers and secondary equipment comprising protection and remote controlequipment and owner consumption (battery, rectifier and inverter).

4) SG 220 kV Jablanica (US$ 1.24 million): Rehabilitation of primary electrical equipment includingreplacement of 220 kV circuit breakers, 220 kV busbar disconnectors, 220 kV line disconnectors.instrument transformers and secondary equipment comprising protection and remote control equipment andowner consumption (battery, rectifier, inverter, AC and DC cabinets).

- 44 -

5) TS 220/110 kV Zenica 2 (US$ 2.33 million): Rehabilitation of primary electrical equipmentincluding replacement of 220 kV and 110 kV circuit breakers, instrument transformers and secondaryequipment comprising protection and remote control equipment and owner consumption (battery, rectifierand inverter).

6) TS 220/110 kV Bihac 1 (US$ 1.14 million): Rehabilitation of primary electrical equipmentincluding replacement of 220 kV and 110 kV circuit breakers and secondary equipment comprisingprotection and remote control equipment.

7) TS 220/110/35/10(20) kV Gradacac (US$ 0.74 million): Rehabilitation of secondary equipmentcomprising protection, remote control equipment and communications equipment.

8) TS 110/35/10 kV Mostar 2 (US$ 0.09 million): Rehabilitation of primary electrical equipmentincluding replacement of 110 kV circuit breakers, 110 kV busbar disconnectors, 110 kV line disconnectorsand instrument transformers.

Substations (EPHZHB) (Total US$ 16.66 million)

1) TS 400/220/110/35 kV Mostar 4 (US$ 12.41 million): Reconstruction of 400 kV substation andprovision of new primary electrical equipment comprising 420 kV breakers, 420 kV busbar disconnectors,420 kV disconnects, instrument transformers, arresters, line traps, post insulators, support structures,busbars and connections and secondary equipment comprising protective relays, control, metering, faultrecording equipment (including breaker fail protection) and communication equipment. Rehabilitation of220 kV and 110 kV substation including circuit breakers, instrument transformers, and powertransformers, line traps and surge arresters together with secondary equipment comprising protectiverelays, control, metering fault recording equipment, (including breaker fail protection), and communicationequipment.

2) TS 220/110/35 kV Jajce 2 (US$ 2.22 million): Rehabilitation of primary electrical equipmentincluding replacement of 220 kV and 110 kV circuit breakers, 220 kV and 110 kV busbar disconnectors,220 kV and 110 kV line disconnectors, 110 kV instrument transformers, arresters, line traps and secondaryequipment comprising protective relays, control, metering, fault recording equipment (including breaker failprotection) and communication equipment.

3) TS 220 kV Mostar 3 (US$ 2.03 million): Rehabilitation of primary electrical equipment includingreplacement of 220 kV circuit breakers, 220 kV busbar disconnectors, 220 kV line disconnectors, line trapsand secondary equipment comprising protective relays, control, metering, fault recording equipment(including breaker fail protection) and communication equipment.

Substations (EPRS) (Total US$ 23.17 million)

1) TS 400/220/110 kV Visegrad 370 (US$ 2.50 million): Rehabilitation of primary electricalequipment including replacement of 420 kV and 110 kV circuit breakers, 420 kV and 110 kV busbardisconnectors, 420 kV line disconnectors, instrument transformers, arresters and secondary equipmentcomprising protective relays, control, metering, communication equipment and owner consumption(battery, rectifier and inverter).

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2) TS 380/110/x kV Ugljevik (US$ 1.77 million): Rehabilitation of primary electrical equipmentincluding replacement of 420 kV circuit breakers, 420 kV line disconnectors, instrument transformers,arresters and secondary equipment comprising protective relays, control, metering, communicationequipment and owner consumption (battery, rectifier and inverter).

3) TS 400/220/110 kV Trebinje (US$ 4.52 million): Rehabilitation of primary electrical equipmentincluding replacement of 420 kV, 220 kV and 110 kV circuit breakers, 420 kV, 220 kV and 110 kV busbardisconnectors, 420 kV, 220 kV and 110 kV line disconnectors, instrument transformers, arresters andsecondary equipment comprising protective relays, control, metering, communication equipment and ownerconsumption (battery, rectifier and inverter).

4) TS 400/110 kV Banja Luka 6 (US$ 2.44 million): Rehabilitation of primary electrical equipmentincluding replacement of 420 kV and 110 kV circuit breakers, 420 kV and 110 kV busbar disconnectors,420 kV and 110 kV line disconnectors, instrument transformers, arresters and secondary equipmentcomprising protective relays, control, metering and communication equipment.

5) TS 380/110/x kV Gacko (Switchgear in Gacko TPP) (US$ 2.00 million): Rehabilitation ofprimary electrical equipment including replacement of 420 kV and 110 kV circuit breakers, 420 kV busbardisconnectors and supporting insulators, 420 kV line disconnectors, instrument transforners, arresters andsecondary equipment comprising protective relays, control, metering, communication equipment and ownerconsumption (battery, rectifier and inverter).

6) TS 400/220/110 kV Sarajevo 20 (Lukavica) (US$ 7.12 million): Rehabilitation of primaryelectrical equipment including replacement of 420 kV and 110 kV circuit breakers, 420 kV and 110 kVbusbar disconnectors, 420 kV and 110 kV line disconnectors, instrument transformers, arresters andsecondary equipment comprising protective relays, control, metering, communication equipment and ownerconsumption (battery, rectifier and inverter). 420/220/110 kV power transformer is also required.

7) TS 220/110 kV Prijedor 2 (329) (USS 2.82 million): Rehabilitation of primary electrical equipmentincluding replacement of 220 kV and 110 kV circuit breakers, 220 kV and 110 kV busbar disconnectors,220 kV and 110 kV line disconnectors, instrument transformers, arresters and secondary equipmentcomprising protective relays, control, metering and communication equipment.

Project Component 3 - US$ 39.06 million

Supervisory Control and Data Acquisition System (SCADA) (US$ 39.06 million)

A supervisory control and data acquisition system, comprising three regional control centers and an overallcentral dispatch center, together with a telecommunications system to interconnect the regional centers withtheir 400 kV, 220 kV and selected 110 kV substations and hydro/thermal generating plant, as well asbetween the regional and central dispatch center's supervisory control and data acquisition system

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Hydropower Stations

EPBiH: HPP Jablanica Unit 5 (US$ 4.54 million)

I) Rehabilitation of Unit 5: turbine, generator, and switchgear.

2) Rehabilitation of the dam monitoring and control equipment.

EPBiH: HPP Jablanica Unit 6 and Common Services (US$ 9.51 million)

1) Rehabilitation of Unit 6: turbine, generator, exciter, and overhaul of generator transformer.

2) Replacement of unit control and protection.

3) Rehabilitation of cooling water.

4) Repair of drainage and de-watering systems plus spillway gates.

5) Upgrading and replacement of dam instrumentation.

6) Rehabilitation of 1lOkV substation comprising supply and installation of circuit breakers,disconnectors, instrument transformers, arresters, conductor, insulators, equipment and busbar structures,together with all secondary equipment comprising protection control and communications apparatus.

EPHZHB: HPP Rama (US$ 3.14 million)

1) Rehabilitation of power tunnel, inspection and repair of surge shaft.

EPRS: HPP Trebinje (US$ 3.20 million)

1) Rehabilitation of Unit 1: turbine, generator, excitation system and overhaul of generatortransfonner.

2) Replacement of unit control and protection.

3) Rehabilitation of draft tube gates and replacement of Inlet Servo Valve for unit 1.

4) A new third set of draft tube gates.

5) Rehabilitation of cooling water and drainage dewatering schemes.

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Environmental Investments at Thermal Power Stations

EPBiH: TPP Tuzia (US$ 3.09 million)

1) Rehabilitation of the Unit 5 electrostatic precipitator.

EPBiH: TPP Kakanj (US$ 5.03 million)

1) Completion of the cooling water re-circulation system and rehabilitation of the Unit 7 electrostaticprecipitator.

EPRS: TPP Gacko (US$ 1.46 million)

1) Reclamation of the Granica ash disposal site.

EPRS: TPP Ugljevik (US$ 5.41 million)

1) Introduction of a new system of ash transport and disposal.


Distribution

EPBiH (Total US$ 14.95 million)

Rehabilitation of distribution substations, comprising SF6 insulated switchgears, power transformers,arresters, insulators, switches, rehabilitation of distribution lines comprising conductors, splices andterminations, poles and towers, in the following areas:

1) Distribution Division Mostar (US$ 1.80 million).

2) Distribution Division Tuzla (US$ 3.54 million).

3) Distribution Division Bihac (US$ 0.82 million).

4) Distribution Division Gorazde (US$ 0.54 million).

5) Distribution Division Sarajevo (US$ 1.66 million).

6) Distribution Division Travnik (USS 4.41 million).

7) Distribution Division Mostar 1 (US$ 0.65 million).

8) Distribution Division Tuzla I (US$ 0.60 miallion).

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9) Distribution Division Zenica (US$ 0.93 million).

EPHZHB (Total US$ 10.67 million)

Rehabilitation of distribution substations, comprising switchgears, pole mounted transformer stations,power transformers, arresters, insulators, switches, rehabilitation of distribution lines comprisingconductors and cables, splices and terninations, poles and towers, in the following areas:

1) Canton No.6: Jajce, Vitez, Novi Travnik, Zepce, Usora, Novi Seher (US$ 2.53 million).

2) Canton No.7: Citluk, Doljani, Ravno, Capljina, Stolac, Mostar, Neum, Rama (US$ 4.59 million).

3) Canton No.8: Siroki Brijeg, Posusje, Grude (US$ 2.04 million).

4) Canton No.10: Drvar, Tomislavgrad, Glamoc, Kupres (US$ 1.50 million).

EPRS (Total US$ 13.36 million)

Rehabilitation of distribution substations, comprising metal clad switchgears, AC/DC auxiliary supplies,protection, power transformers, instrument transformers, disconnect switches, pole mounted transformerstations, circuit breakers, insulators, arresters, busbars, rehabilitation of distribution lines comprisingconductors and cables, poles and crossarms, structures and hardware, in the following areas:

1 ) Distribution Division Banja Luka (US$ 2.89 million).

2) Distribution Division Doboj (US$ 2.11 million).

3) Distribution Division Bijeljina (US$ 2.19 million).

4) Distribution Division Pale (USS 1.52 million).

5) Distribution Division Herzegovina (US$ 1.01 million).

6) Vehicles and Special Tools (US$ 3.65 million).


Technical Assistance

The project would include the following technical assistance components totaling about US$ 13.38 million:

1 ) Assistance to the Elektroprivreda PIUs in the procurement and implementation supervision of theIDA-financed components, including procurement capacity and other training.

2) A social survey of consumers to identify those who would need assistance to pay for electricity.

3) Assistance for corporatization (including the creation of opening balance sheets) and

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commercialization (including the establishment of financial management and management informationsystems) of the Elektroprivredas.

4) Assistance in the establishment of the Independent System Operator, and assistance to ZEKC toenable it to fulfil that role.

5) Assistance in establishing the independent power sector regulatory agencies and training for theirstaff.

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Annex 3: Estimated Project Costs



PROPOSED THIRD ELECTRIC POWER RECONSTRUCTION PROJECT

ESTIMATED PROJECT COSTS (excluding contingencies)

ITEM COSTS (US$)Local Foreign Total

A. 1. Transmission Lines

A. 1. 1. EPBiH1. Sarajevo 10 - Mostar 400 kV 825,000 3,662,000 4,487,0002. Sarajevo 10 - Sarajevo 20 400 kV 148,000 726,000 874,0003. Mostar 4 - Gacko 400 kV 197,000 1,000,000 1,197,0004. Visegrad - Tuzla 400 kV 329,000 1,246,000 1,575,0005. Ugljevik - Ernestinovo 400 kV 222,000 1,074,000 1,296,0006. Jajce - Mraclin 220 kV 316,000 356,000 672,0007. Tuzla-Gradacac-Djakovo220kV 0 121,000 121,0008. Mostar - Nevesinje 110 kV 104,000 1,237,000 1,341,000Total 2,141,000 9,422,000 11,563,000

A. 1. 2. EPHZHB1. Mostar 4 - Sarajevo 400 kV 185,000 640,000 825,0002. Mostar 4 - Gacko 400 kV 176,000 986,000 1,162,0003. Ugljevik - Emestinovo 400 kV 235,000 748,000 983,0004. Jajce - Mraclin 220 kV 44,000 59,000 103,0005. Kakanj - Prijedor 220 kV 125,000 952,000 1,077,000Total 765,000 3,385,000 4,150,000

A. 1. 3. EPRS1. Visegrad - Zvornik - Tuzia 400 kV 559,000 1,957,000 2,516,0002. Mostar 4 - Gacko 400 kV 211,000 1,275,000 1,486,0003. Sarajevo 10 - Sarajevo 20 400 kV 105,000 737,000 842,0004. Ugljevik- Emestinovo 400 kV 174,000 1,595,000 1,769,0005. Jajce-Prijedor220kV 150,000 511,000 661,0006. Prijedor - Sisak 220 kV 158,000 586,000 744,0007. Gradacac- Djakovo 220 kV 141,000 905,000 1,046,0008. Mostar- Nevesinje 110 kV 161,000 1,441,000 1,602,0009. Dubrovnik - Trebinje 220 kV 56,000 103,000 159,000Total 1,715,000 9,110,000 10,825,000

Transmission Lines Total 4,621,000 21,917,000 26,538,000

All totals rounded off to nearest 1,000.

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A. 2. Substations - 400 kV and 220 kV

A. 2. 1. EPBiH1. TS 400/220/110 kV Tuzla 894,000 4,312,000 5,206,0002. TS 400/110 kV Sarajevo 10 591,000 2,849,000 3,440,0003. SG 220 kV Kakani 209,000 1,004,000 1,213,0004. SG 220 kV Jablanica 213,000 1,031,000 1,244,0005. TS 220/110 kV Zenica 2 400,000 1,925,000 2,325,0006. TS 220/110 kV Bihac 1 195,000 943,000 1,138,0007. TS 220/110/35/10(20) kV Gradacac 126,000 609,000 735,0008. TS 110/35/10 kV Mostar 2 16,000 78,000 94,000Total 2,644,000 12,751,000 15,395,000

A. 2.2. EPHZHB1. 400/x kV Mostar 4 2,126,000 10,285,000 12,411,0002. 220/x kV Jajce 2 379,000 1,836,000 2,215,0003. 220 kV Mostar 3 348,000 1,684,000 2,032,000

Total 2,853,000 13,805,000 16,658,000

A. 2.3. EPRS1. SS 400/220/110 kV Visegrad 455,000 2,042,000 2,497,0002. SS 400/11 0/x kV Ugljevik 324,000 1,450,000 1,774,0003. SS 400/220/110 kVTrebinje 824,000 3,694,000 4,518,0004. SS 400/11 0/x kV Banja Luka 6 444,000 1,995,000 2,439,0005. SS 400/100/x kV Gacko 365,000 1,636,000 2,001,0006. SS 400/220/110 kV Sarajevo 20 (Lukavica) 1,298,000 5,819,000 7,117,0007. SS 220/110 kV Prijedor 2 515,000 2,308,000 2,823,000Total 4,225,000 18,944,000 23,169,000

Substations Total 9,722,000 45,500,000 55,222,000

Transmission Component Total 14,343,000 67,417,000 81,760,000


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B. SCADA 6,180,000 32,880,000 39,060,000

C. Hydropower Station Component

C. 1. EPBiH1. HPP Jablanica 1,374,000 12,675,000 14,049,000

C. 2. EPHZHB1. HPP Rama 505,000 2,639,000 3,144,000

C. 3. EPRS1. HPP Trebinje 666,000 2,537,000 3,203,000

Hydropower Station Component Total 2,545,000 17,851,000 20,396,000

D. Thermal Power Station Component

D. 1. EPBiH1. TPP Tuzla 364,000 2,727,000 3,091,0002. TPP Kakanj 540,000 4,487,000 5,027,000Total 904,000 7,214,000 8,118,000

D. 2. EPRS1. M&TPP Gacko 491,000 968,000 1,459,0002. M&TPP Ugljevik 1,275,000 4,135,000 5,410,000Total 1,766,000 5,103,000 6,869,000

Thermal Power Station Component Total 2,670,000 12,317,000 14,987,000


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E. Distribution Component

E. 1. EPBiH1. Mostar-NORAD 0 1,793,000 1,793,0002. Tuzla-NORAD 0 3,542,000 3,542,0003. Bihac 294,000 529,000 823,0004. Gorazde 150,000 387,000 537,0005. Sarajevo 393,000 1,269,000 1,662,0006. Travnik 1,042,000 3,363,000 4,405,0007. Mostar 1 154,000 497,000 651,0008. Tuzla 1 162,000 440,000 602,0009. Zenica 221,000 712,000 933,000Total 2,416,000 12,532,000 14,948,000

E. 2. EPHZHB

CANTON 61. Jajce 95,000 524,000 619,0002. Vitez 128,000 702,000 830,0003. Novi Travnik 107,000 590,000 697,0004. Zepce 27,000 150,000 177,0005. Usora 19,000 103,000 122,0006. Novi Seher 13,000 70,000 83,000Total Canton 6 389,000 2,139,000 2,528,000

CANTON 71. Citluk 45,000 248,000 293,0002. Doljani 13,000 70,000 83,0003. Ravno 26,000 140,000 166,0004. Capljina 55,000 304,000 359,0005. Stolac 51,000 281,000 332,0006. Mostar 347,000 1,907,000 2,254,0007. Neum 56,000 303,000 359,0008. Rama 115,000 632,000 747,000Total Canton 7 708,000 3,885,000 4,593,000

CANTON 81. Siroki Brijeg 94,000 515,000 609,0002. Posusje 71,000 388,000 459,0003. Grude 150,000 825,000 975,000Total Canton 8 315,000 1,728,000 2,043,000


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CANTON 101. Drvar 42,000 233,000 275,0002. Tomislavgrad 53,000 288,000 341,0003. Glamoc 73,000 403,000 476,0004. Kupres 63,000 346,000 409,000Total Canton 10 231,000 1,270,000 1,501,000

Total EPHZHB 1,643,000 9,022,000 10,665,000

E. 3. EPRS1. Banja Luka 715,000 2,176,000 2,891,0002. Doboj 534,000 1,574,000 2,108,0003. Bijelina 545,000 1,642,000 2,187,0004. Pale 491,000 1,026,000 1,517,0005. Herzegovina 327,000 684,000 1,011,0006. Vehicles & Special Tools 0 3,650,000 3,650,000Total 2,612,000 10,752,000 13,364,000

Distribution Component Total 6,671,000 32,251,000 38,977,000

F. Technical Assistance o 13,380,000 13,380,000

Total A+B+C+D+E+F 32,409,000 176,096,000 208,505,000

Physical Contingencies 2,000,000 11,540,000 13,540,000

Price Contingencies 2,354,000 6,734,000 9,088,000

TOTAL INCLUDING CONTINGENCIES 36,763,000 194,370,000 231,133,000


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Annex 4: Cost Benefit Analysis SummaryBOSNIA AND HERZEGOVINA: Third Electric Power Reconstruction Project

[For projects with benefits that are measured in monetary terms]

Prsn 3 au -e :f Flowsjiiii j00 FiRca Impact0000003i t:;: Economic i1 Financial s1

______________fF An ly i _ __ __ _ __ _ tu::Q:Q:;;;AL:uX:a: ,. ,Taxes ; ubSidlpsBenefits: $1,442 million $ 581 million $4.3 million

Costs: $ 276 million $ 282 million

Net Benefits: $ 1,166 million $ 299 million

IRR: 61% 32%

Summary of Benefits and Costs:

Economic analysis. Separate benefits were identified and measured for the different project components.

For transmission, the measured benefits include:

(i) reductions in transmission losses;(ii) reductions in unserved energy caused by power outages in the transmission system;(iii) increased electricity sales from the Gacko and Visegrad power stations made possible by the

removal of transmission constraints;(iv) resumption of pumped storage at the Capljina hydropower station made possible by an increase in

fault levels due to transmission system rehabilitation;(v) revenue from transmission within BiH of power intended for foreign markets; and(vi) the benefit (measured by willingness to pay determined on the basis of the cost of alternative

energy) of transmission of additional electricity to markets within BiH.

For distribution, the measured benefits include:

(i) reductions in unserved energy caused by power outages in the distribution system; and(ii) increased sales made possible by distribution system restoration (measured by willingness to pay

determined on the basis of the cost of alternative energy).

For the SCADA/EMS the measured benefits include:

(i) salary savings due to staff reductions at hydropower plants, substations and in record keepingunits;

(ii) reductions in unserved energy attributable to improved dispatching; and(iii) revenue from sale of spare communications capacity. For hydropower investments, the measured

benefits consist of improved availability of generating capacity at the Jablanica and Trebinjehydropower stations.

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The costs consist of 85% of the project investments plus operating and maintenance expenses. The omittedinvestments, for which it was not possible to reliably calculate the benefits, included the safety-relatedinvestments at the Rama hydropower station, the environmental investments at the thermal power plants,and the technical assistance. Import duties and other indirect taxes were excluded. A shadow exchangerate 7.5% higher in local currency than the actual rate was used, on the assumption that the current rate isdistorted by import duties averaging about 7.5% of import prices. A shadow wage rate was not usedbecause a reliable estimate was not available, and its use would increase an already higher than adequaterate of return. The estimates were made in constant prices as of January 1, 2001.

Financial Analysis. The benefits used for the economic analysis were also used for the financial analysis.However, two types of benefits were measured differently. Reductions in unserved energy were measuredin the financial analysis using the actual average retail tariff rate of US$ 0.056/ kWh whereas a higherestimate of US$ 0.25/kWh was used in the economic analysis based on estimates in other countries ofwillingness to pay to protect against unplanned outages. Increased electricity sales were measured in thefinancial analysis using the actual tariff rate whereas a willingness to pay estimate of US$ 0.14/kWh wasused in the economic analysis. These two adjustments largely explain why the financial rate of return isless than the economic rate of return for the project. The financial analysis is in nominal prices. Localtaxes are included in the costs. Shadow prices were not used.

Main Assumptions:

Economic Analysis

The benefit and cost estimates, except for the SCADA system, were prepared by Agra Monenco Inc. andgiven in full detail in "Electric Power III Reconstruction, Bosnia and Herzegovina, Final Report", January2000, Section 8, as updated in April 2001. The assumptions for these estimates as well as for the rate ofreturn estimates for the SCADA system are summarized below.

Net Present Value Calculations: All costs and benefits were converted to US dollars at the averageexchange rate for the year 2000 of US$ 1.00 = KM 2.10. All discounting was done to January 1, 2001. Areal discount rate of 12% was used.

Equipment Lifetimes: Equipment lifetimes were assumed to be the following: transmission (25 years),distribution (25 years), hydro (20 years), SCADA system (20 years).

Investment costs: The estimates are in constant US dollars as of January 1, 2001, and exclude importduties and local taxes. A conversion factor of 1.075 was used to multiply the actual exchange rate in orderto estimate the shadow price of foreign exchange in local currency terms. The factor was estimated on thebasis that the main distorting factor are import duties assumed to average about 7.5% of import values.The estimates include physical contingencies of: 5% for transmission and hydro investments; 10% fordistribution investments and 9.3% for the SCADA system.

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PROJECT ECONOMIC ANALYSIS(US$ million)

NPV EIRR2001 2002 2003 2004 2005 2006 2007 2008 2028 (at 12%)

TransmIssIon CostsInvestment 0 66.4 23.8 0 0 0 0 0 ---- 0 $69.9O&M 0 0 0 1.8 1.8 1.8 1.8 1.8 ---- 1.8 $10.0Subtotal 0 66.4 23.8 1.8 1.8 1.8 1.8 1.8 ---. 1.8 $79.9Transmlion BenefitsGacko-Mostar 0 0 0 1.4 3.3 3.3 3.3 3.3 ---- 0.3 $16.9Visegrad-Tuzla 0 0 0 3.8 3.8 3.8 3.8 3.8 ---- 3.8 $21.2Inernate onal connections 0 0 0 18.4 23.5 29.1 31.3 33.5 ---- 33 $180.4Loss Reduc. & Capljina 0 0 0 7 7.1 7.1 7.2 7.2 ---- 7.4 $40.5Additional Sales 0 0 0 0 51.4 71.6 72.7 84.5 ---- 185.1 $588.7Subtotal 0 0 0 30.6 89.1 114.9 118.3 132.3 ---- 229.6 $847.7NetBenefits 0 -66.4 -23.8 28.8 87.3 113.1 116.5 130.5 ---- 227.8 $767.8 62%

Dlstributlon CostsInvestment 45.4 0 0 0 0 0 0 0 ---- 0 $40.5Other 0 12.3 12.3 12.3 12.3 12.3 15.7 15.7 ---- 15.7 $100.4Subtotal 45.4 12.3 12.3 12.3 12.3 12.3 15.7 15.7 ---- 15.7 $140.9Distribution BenefitsReduc. unserved energy 0 6.3 6.3 6.3 6.3 6.3 31.4 31.4 ---- 31.4 $141.9AddtiSonal sales 0 43.9 43.9 43.9 43.9 43.9 43.9 43.9 ---- 43.9 $311.3Subtotal 0 50.2 50.2 50.2 50.2 50.2 75.3 75.3 ---- 75.3 $453.2Net Benefts -45.4 37.9 37.9 37.9 37.9 37.9 59.6 59.6 ---- 59.6 $312.3 86%

Hydro - Jablsnica 15Costs 6 0.1 0.1 0.1 0.1 0.1 0.1 0.1 ---- 0 $6.0Benefits 0 0 0 3.3 3.3 3.3 3.3 3.3 ---- 0 $17.5Net Benefits -6 -0.1 -0.1 3.2 3.2 3.2 3.2 3.2 ---- 0 $11.5 30%

Hydro - Jablsnica #6Costs 0 7.8 2 0,2 0.2 0.2 0.2 0.2 ---- 0 $8.7Benefits 0 0 0 0 0 0 3.3 3.3 ---- 0 $11.9Not Benefits 0 -7.8 -2 -0.2 -0.2 -0.2 3.1 3.1 ---- 0 $3.2 16%

Hydro - Trebinje #1Costs 0 2.9 0.7 0.1 0.1 0.1 0.1 0.1 ---- 0 $3.3Senefits 0 0 0 2.8 2.8 2.8 2.8 2.8 ---- 0 $23.0Net Benefits 0 -2.9 -0.7 2.7 2.7 2.7 2.7 2.7 ---- 0 $19.7 56%

SCADAIEMS CostsInvestrnent 0 15 16 15 0 0 0 0 ---- 0 $32.9O&M 0 0 0 0 0.8 0.8 0.8 0.8 ---- 0 $3.8Subtotal 0 15 16 15 0.8 0.8 0.8 0.8 ---- 0 $36.7SCADAIEMS BanefitsSalary savings 0 0 0 0 0.8 0.8 0.8 0.9 ---- 0 $5.1Reduc. unserved energy 0 0 0 0 6.3 6.3 6.3 6.3 ---- 0 $29.9Spare communications rev. 0 0 0 0 11.2 11.2 11.2 11.2 ---- 0 $53.2Subtotal 0 0 0 0 18.3 18.3 18.3 18.4 ---- 0 $88.1Net Benefits 0 -15 -18 -15 17.5 17.5 17.5 17.6 ---- 0 $51.5 29%

Total Costs 51.4 104.5 54.9 29.5 15,3 15.3 18.7 18.7 ---- 17.5 $275.6Total Benefits 0 50.2 50.2 86.9 163.7 189.5 221.3 235.4 ---- 304.9 $1,441.5Net Benefits -51.4 -54.3 -4.7 57.4 148.4 174.2 202.6 216.7 ---- 287.4 $1,165.9 61%

Transmission O&M: The O&M costs associated with the incremental output of the transmission systemresulting from the transmission investments under the project were assumed to be 10% of the estimatedtotal O&M cost for the 400 kV and 220 kV transmission system of US$ 7.5 per kW. The annual O&M isequal to 2% of the transmission investments under the project.

Benefits of Restoration of the Gacko-Mostar Transmission Line: Three benefits were measured. Firstis a reduction in transmission losses of 18 GWh per year, valued at the long-run marginal cost (LRMC) ofgeneration for EPRS estimated at US$ 0.04/kWh by the Fichtner/ESBI electricity tariff study. Second isan additional 55 GWh of power generation frorn Gacko and 2 GWh from hydropower plants that could besent to market. This benefit is valued at the difference between the average LRMC for generation of EPRSof US$0.04/kWh less the energy cost at Gacko of US$0.03/kWh and a transmission charge of US$0.7/kW/year. Third is revenue from wheeling 92 MW of power from Gacko to Hrvatska Elektroprivreda

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(HEP), which is entitled to this power by virtue of its pre-war investments in the Gacko power plant. Thewheeling charge was assumed to be US$ 20/kW.

Restoration of the Visegrad-Tuzia Transmission Line: Two benefits were measured. First is areduction in losses of 33 GWh per year, valued at the LRMC of generation for EPRS of US$ 0.04/kWh.Second is the benefit of diverting 62 GWh of electricity produced at Visegrad from the export market to thedomestic market, valued at the difference between the LRMC for EPRS of US$ 0.04/ kWh and the exportprice of US$ 0.0246/kWh.

Restoration of International Connections: Three benefits were measured. First is a reduction in outages.In the absence of the interconnections, transmission system outages were assumed to increase by oneoutage per year to a maximum of 14, and each outage was assumed to last 6 hours. The benefit wasmeasured as the reduction in unserved energy valued at US$ 0.25/kWh less the cost of supply of thiselectricity calculated as the average electricity export price for BiH of US$ 0.021/kWh (assuming someexports would be diverted to supply this energy) plus transmission and distribution costs valued at US$44.81kW/year, with an adjustment for transmission and distribution losses estimated at 14% of net powergeneration. The second benefit is revenue from wheeling of electricity owed to Croatia and Slovenia(excluding the amount already covered as a benefit for restoration of the Gacko-Tuzla line) valued at US$20/kW/year. The third benefit is revenue from wheeling an estimated 1,400 GWh per year of electricitywith an assumed value of US$ 0.03/kWh from western Croatia to eastern Croatia over 470 km of theBosnian transmission system, assuming a wheeling charge of 1.5% of the value of the electricity per 100km of transmission.

Loss Reduction and Resumption of Pumped Storage at Capljina: Two benefits are included here. Thefirst is a reduction in transmission losses not already included in the benefits of the Gacko-Tuzla line andthe Visegrad-Tuzla line. The reductions rise from 56 GWH in 2003 to 65 GWh by 2011. They are valuedat the avoided generation cost of US$ 0.04/kWh. Second, the transmission system rehabilitation wouldincrease the fault levels at Capljina, thus allowing the on-line start of the pumps to pernit the resumption ofpumped storage at that plant. It is assumed that the additional generation would be 225 GWh per year,which would require an additional 304 GWh of generation. The pumping cost was valued at US$0.0134/kWh (an energy cost only since the pumping would be done at night) and the additional energy wasvalued at US$ 0.04/kWh.

Additional System Sales: Restoration of the 220 KV and 400 KV transmission lines would allow a peakdemand of 2,700 MW to be supplied reliably, compared with a peak of 2,200 MW under existingconditions. This increase in capacity would make it possible to accommodate forecast additional electricitygeneration of 774 GWh in 2003 rising to 2,700 GWh by 2014. This is the same forecast as is used for theforecast financial statements of EPBiH, EPHZHB and EPRS, but the figures were adjusted downwards bythe increased generation taken account of in the other transmission benefit estimates described above. Theadditional sales corresponding to this generation were valued at the estimated willingness to pay of US$0. 14/kWh. This estimate was derived by calculating the cost of alternatives to electricity consisting ofkerosene for household consumers and diesel generation for commercial consumers and, in order to beconservative, taking the average between this price and the actual average price of electricity. The costs ofthe additional electricity include the average export price of electricity of US$ 0.021/kWh, transmissionand distribution valued at US$ 50.3fkW per year, and adjustments were made for transmission anddistribution losses of 14%.

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Distribution - Other Costs: Other costs relating to distribution benefits consisting of additional sales andreduction in unserved energy include: the associated cost of generation valued at the export price,transmission and distribution costs (excluding the distribution investments) and transmission anddistribution losses. Annual distribution O&M was assumed to be 1.5% of the distribution investments.The estimates of the various costs differ between the three EPs.

Distribution Benefits - Reducing Unserved Energy: It was assumed that in the absence of thosedistribution investments made in order to improve supply reliability the corresponding electricity would besubject to a probability of supply failure of 20% per year from 2003-2007 and 100% thereafter. Thereduction in unserved energy was valued at US$ 0.25/kWh.

Distribution Benefits - Additional Sales: The additional sales made possible by the distributioninvestments were valued at the estimated willingness to pay of US$ 0.14/kWh.

Hydropower Benefits: Benefits of improved availability were estimated for Jablanica 5 and 6 andTrebinje 1. It was estimated that in the absence of rehabilitation, generator output would decrease by 1.5%per year for five years after which the units would be incapable of producing any output. The value ofcapacity was estimated to be US$ 133.6/kW/year at Jablanica and US$ 110.2/kW/year at Trebinje. Thebenefits were measured as the avoided reduction in available capacity. A cost-benefit analysis was notcarried out for the safety investments at Rama, Jablanica and Trebinje because of the difficulty ofestimating the reduction in probability of dam failure attributable to the investments and the value ofdamages resulting from a dam failure.

Hydropower Costs: The hydropower costs include the investments for availability increase and annualoperation and maintenance costs equal to 2% of the investments.

SCADA/EMS O&M: O&M costs are assumed to be 2% of the total investment.

SCADAJEMS Benefits - Salary Savings: The salary savings are due to an estimated reduction of 42persons at hydropower plants and substations, and 42 persons in record keeping staff, having an averagesalary of DM 14,800 per year.

SCADA/EMS Benefits - Reduction in Unserved Energy: The reduction in unserved energy wasassumed to be 0.25% of gross electricity consumption of 10,000 GWh, valued at a cost of US$ 0.25/kWh.

SCADA/EMS Benefits - Spare Communications Revenue: The revenue from sale of sparecommunications capacity was estimated on the basis of installation of 1,052 km of fiber cable, each cablehaving 16 spare fibers, that would be sold for US$ 1,200/fiber/mile/year.

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BOSNIA AND HEFRZEGOVINATHIRD ELECTRIC POWER RECONSTRUCTION PROJECT

ELECTRICITY DEMAND AND SUPPLY(GWh)

-. - - f,_,;:. < ...... - : .:......Forecast201 2002 2003 2004 2005 2006 2007 2008

EPBiH Demand % s' ,.6Ei 6 ,w 6A, i--':7TDistribution demand ~~~~~~~~~~3,0C4 3,154 3,311 3,444 3,582 3,689 3,800 3,914

Distribution losses ^ k S l S S3410 390 368 341 354 365 376 387Energy to meet distribution demand ,. r 3,413 3,544 3,679 3,784 3.936 4,054 4,176 4,301

Direct demand i(ia~~~~~~~~~~~t6 176 185 192 20C0 206 212 219Oiretexprt demanrJ d;t , W 6M M 1611 1,716 1,821 1,967 2 074 2,180 2,185 2,191

Transmission losses 'e'4% l 6' ; 1 0 157 164 171 179 186 189 193Total electricity demand *---A-,,,4' sesesiwgayS! . i ! i ................... i ik 5,3'.1 5,592 5,849 6.115 6,389 6,625 6,762 6,904

Tuzta thermaltpower plant 4 6 2,247 2,385 2,526 2,672 2,823 2,953 3,028 2,106Kakanjthermal power plant . 1,838 1,951 2.067 2,187 2310 2,416 2,478 2,542

Jablanica hydropower plant 600 ~~~~~~~600 800 600 600 600 600 600Grabovica hydropoJwer plant 2-0 j g l 6t)250 250 250 250 250 250 250Satakovac hydropower plant 350 350 350 350 35(0 350 350 350

Small hydros 5~~~~~~~~~~~~ 6 56 56 56 56 56 56 56

Net purchases within BiH . ' 56 30 30 3; 5 5 5Total electricity supply ~~~~~~~~5,34 1 5,592 5,849 6,115 6,389 6.625 6,762 E'r904

Distributione dstribuboemand d 28i10 914 960 1,008 1,058 1,111 1,166 -.225

*D*str __ution losses 2,0 214 183 137 144 151 159 167Energy tpomeet distribution demand 1; 1,131 1,128 1,142 1.145 1,202 1,262 1,326 692

Direct deman*d ndem1,89 1,679 12679 1,679 1 679 12679 1R679 1 679

Transmission losses 40 40 41 42 43 44 46 47

Total electricity demand ' .; 2,850 2,847 2 862 2,866 2,924 2,985 3,051 3,118

EPHZH Supply 1,71,71,71271271,7121121

Trebmaehydropower plant1 h t0628 628 628 628 628 628 628 628

Mostar hydropower plant ~~~~~~~~~218 218 218 218 218 2118 218 218

Capserad hydropower plant . g _ 159 159 159 159 159 159 159 159

Joca)c hydropower plant O wp233 233 233 233 233 233 233 233

Jmajce 2hydropower plant r M-<t't2Ft>-162 162 162 162 162 1627 162 162Net imports ~~~~~~~~~~~~~~~1,480 1,447 1,462 1,466 1,524 1,585 1,651 1,718

Total electricity supply 2+'"S 'S pf'- '' ,,-t S 1; 5,(2880 2,847 2,862 2,866 2,924 2,985 3,051 3,118

EPRS~ri Demand g s lv

Distribution demand ~~~~~~~~~~~2,347 2.523 2,649 2,781 2,920 3,066 3,220 3,381

Distribution losses ~~~~~~~~~~~662 592 505 379 398 4113 439 461

Energyotal meetBi istributionHdemand3 DC9 3,114 3,153 3,161 3.319 3,485 3.659 3,842

Net Exporls - >. S .t-~ tX 2,1)870 1,777 1,751 1,743 1.585 1,411 1,245 1,062Transmission losses 125 113 100 100 100 1 03 100 100

Total electricity demand 5,C04 5 004 5,004 5,004 53004 5,004 5,004 5,004

EPRS SuppylUg1tevik thernal poWer plant 109 '71 19Y7Gacko thermal power plant ~ n 1,102 1,102 1,102 1,102 1 102 1,102 1,102 1,102Trebinje hydropower plancl 584 584 584 584 584 584 584 584Visegrad hydropower plant 1,085 1.085 1,085 1.085 1.085 1,085 1,085 1,085tDubrovni hydropower plant 77 577 577 577 57r77 577 577

Bocac hydropower plant 126 328 328 328 328 :328 328 328

Small hydros 57 5 7 5 7 5 7 5Total electricity supply 4t',S. 51004 5 004 5,004 5,004 5,004 5,004 5 004 5.004

Total Bin Demand Ln a 9 44 9.951 10,144 10.275 10,658 11,015 11,386 '1,772Net Exports '. 21~)01 2,045 2,109 2,244 2 135 2,014 1,780 1 536Total Electricity Supply fir~ ~$ ~ ~ t$l 1 1,745 11,996 12.253 12,519 1 2,793 13,029 13.16P, 3,30-8

Sources Actual Data from EPBiIH EPM and EPIR2 tDA Iorncastn-1/ Includes Dubrovnik for 1990, 1996 and 1937

Financial Analysis

The financial rate of return estilmates, except tir tile enviroinnental investments at thermal power plants andthe SCADAIEMS, were prepared by Agra MonLcOit Inc. and givern in full detail in "Electric Power IIlReconistruction, Bosnia and [Icr:'eg~ovina, Final Report., Janluary, 2000. Section 8, and updated to April2001. The assumptions fior these estimates as well a.s tor the SCADA system are summarized below.

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FINANCIAL PROJECT ANALYSIS(US$ million)

NPV FIRR2001 2002 2003 2004 2005 2006 2007 2008 2028 (at 15%)

Transmission CostsInvestment 0 68.4 25.6 0 0 0 0 0 ---- 0 $68.6O&M 0 0 0 2 2 2.1 2.2 2.2 ---- 4.7 $10.4Subtotal 0 68.4 25.6 2 2 2.1 2.2 2.2 ---- 4.7 $78.9Transmission BenefitsGacko-Mostar 0 0 0 1.6 3.7 3.8 3.9 4 ---- 0.8 $16.8Visegrad-Tuzla 0 0 0 4.2 4.3 4.5 4.6 4.8 ---- 10 $22.1Internat. Connections 0 0 0 5 8.7 13.1 13.7 14.3 ---- 13.6 $56.0Loss reduc. & Capljina 0 0 0 7.8 8.1 8.4 8.8 9.1 ---- 19.6 $42.5Additional Sales 0 0 0 0 12.3 17.7 18.5 22.2 ---- 102.2 $131.9Subtotal 0 0 0 18.6 37.1 47.5 49.5 54.4 ---- 146.2 $269.3Net Benefits 0 -68.4 -25.6 16.6 35.1 45.4 47.3 52.2 ---- 141.5 $190.4 36%

Distribution CostsInvestment 44.9 0 0 0 0 0 0 0 ---- 0 $39.0Other 0 13.2 13.6 14.1 14.6 15.2 20.4 21.2 51.7 $113.5Subtotal 44.9 13.2 13.6 14.1 14.6 15.2 20.4 21.2 --- 51.7 $152.5Distribution BenefitsReduc. Unserved energy 0 1.5 1.6 1.6 1.7 2.8 9.8 10.2 ---- 27 $41.5Additional sales 0 19.3 20 20.6 21.5 22.2 23.1 23.9 ---- 56.3 $141.1Subtotal 0 20.8 21.6 22.2 23.2 25 32.9 34.1 ---- 83.3 $182.5Net Benefits -44.9 7.6 8 8.1 8.6 9.8 12.5 12.9 ---- 31.6 $30.0 24%

Hydro - Jablanica #5Costs 5.8 0.1 0.1 0.1 0.1 0.1 0.1 0.1 ---- 0 $5.6Benefits 0 0 0 3.5 3.5 3.5 3.6 3.6 ---- 0 $15.1Net Benefits -5.8 -0.1 -0.1 3.4 3.4 3.4 3.5 3.5 ---- 0 $9.5 33%

Hydro - Jablanica #6Costs 0 7.8 2 0.2 0.2 0.2 0.2 0.2 ---- 0 $8.0Benefits 0 0 0 3.5 3.5 3.5 3.5 3.6 ---- 0 $15.1Net Benefits 0 -7.8 -2 3.3 3.3 3.3 3.3 3.4 ---- 0 $7.0 28%

Hydro - Trebinje #1Costs 0 2.9 0.8 0.1 0.1 0.1 0.1 0.1 ---- 0 $3.1Benefits 0 0 0 3.1 3.2 3.3 3.4 3.5 ---- 0 $24.1Net Benefits 0 -2.9 -0.8 3 3.1 3.2 3.3 3.4 ---- 0 $21.0 62%

SCADAIEMS CostsInvestment 0 13.5 17.9 12.8 0 0 0 0 ---- 0 $29.3O&M 0 0 0 0 0.9 1 1 1 ---- 0 $3.9Subtotal 0 13.5 17.9 12.8 0.9 1 1 1 ---- 0 $33.2SCADAIEMS BenefitsSalary savings 0 0 0 0 0.9 1 1.1 1.2 ---- 0 $5.4Reduc. Unserved energy 0 0 0 0 1.6 1.7 1.7 1.8 ---- 0 $6.9Spare communications rev. 0 0 0 0 14.6 15.1 15.5 16 ---- 0 $62.1Subtotal 0 0 0 0 17.1 17.8 18.3 19 ---- 0 $74.4Net Benefits 0 -13.5 -17.9 -12.8 16.2 16.8 17.3 18 ---- 0 $41.1 31%

Total Costs 50.7 105.9 60 29.3 17.9 18.7 24 24.8 ---- 56.4 $281.5Total Benefits 0 20.8 21.6 50.9 87.6 100.6 111.2 118.2 ---- 229.5 $580.5Net Benefits -50.7 -85.1 -38.4 21.6 69.7 81.9 87.2 93.4 ---- 173.1 $299.0 32%

Cost Escalation: The financial analysis was carried out in nominal terms. All costs were converted to USdollars at the average year 2000 exchange rate of US$ 1.00 = KM 2.10. Exchange rate fluctuations werenot taken into account since forecasts indicate that these would be small. For local costs, a 1% per annumincrease in prices was used for the Federation and 6% for RS. For foreign costs the inflation rate usedwere 2.4% per year.

Net Present Value Calculations: All discounting was done to January 1, 2000. A nominal discount rateof 15% was used (12 percentage points for the real opportunity cost of capital and 3 points for inflation).

Investment costs: The estimates are in US dollars. They exclude import duties on the understanding thatthese will be waived for the project. They include local taxes of 12%. Shadow prices were not used. Theestimates include physical contingencies of: 5% for transmission and hydro investments, and 10% fordistribution investments and the SCADA system.

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Transmission O&M: The O&M costs associated with the incremental output of the transmission systemresulting from the transmission investments under the project were assumed to be 10% of the estimatedtotal O&M cost for the 400 kV and 220 kV transmission system of US$ 7.5 per kW. The annual O&M isequal to 2% of the transmission investments under the project in real terms.

Benefits of Restoration of the Gacko-Mostar Transmission Line: Three benefits were measured. Firstis a reduction in transmission losses of 18 GWh per year, valued at the long-run marginal cost (LRMC) ofgeneration for EPRS estimated at US$ 0.04/kWh by the Fichtner/ESBI electricity tariff study. Second isan additional 55 GWh of power generation from Gacko and 2 GWh from hydropower plants that could besent to market. This benefit is valued at the difference between the average LRMC for generation of EPRSof US$0.04/kWh less the energy cost at Gacko of US$ 0.03/kWh and a transmission charge of US$0.7/kW/year. Third is revenue from wheeling 92 MW of power from Gacko to Hrvatska Elektroprivreda(HEP), which is entitled to this power by virtue of its pre-war investments in the Gacko power plant. Thewheeling charge was assumed to be US$ 20/kW. The dollar amounts mentioned here were adjusted forlocal inflation.

Restoration of the Visegrad-Tuzla Transmission Line: Two benefits were measured. First is areduction in losses of 33 GWh per year, valued at the LRMC of generation for EPRS of US$ 0.04/kWh.Second is the benefit of diverting 62 GWh of electricity produced at Visegrad from the export market to thedomestic market, valued at the difference between the LRMC for EPRS of US$ 0.04/ kWh and the exportprice of US$ 0.021/kWh. The dollar amounts were adjusted for local inflation, except the export price,which was adjusted for foreign inflation.

Restoration of International Connections: Three benefits were measured. First is a reduction in outages.In the absence of the interconnections transmission system outages were assumed to increase by one outageper year to a maximum of 14, and each outage was assumed to last 6 hours. The benefit was measured asthe reduction in unserved energy valued at the average actual electricity price of US$ 0.056/kWh less thecost of supply of this electricity calculated as the average electricity export price for BiH of US$0.021/kWh (assuming some exports would be diverted to supply this energy) plus transmission anddistribution costs valued at US$ 45/kW/year, with an adjustment for transmission and distribution lossesestimated at 14% of net power generation. The second benefit is revenue from wheeling of electricity owedto Croatia and Slovenia (excluding the amount already covered as a benefit for restoration of theGacko-Tuzla line) valued at US$ 20/kW/year. The third benefit is revenue from wheeling an estimated1,400 GWh per year of electricity with an assumed value of US$ 0.03/kWh from western Croatia toeastern Croatia over 470 km of the Bosnian transmission system, assuming a wheeling charge of 1.5% ofthe value of the electricity per 100 km of transmission. The dollar estimates were adjusted for localinflation, except for the export price, which was adjusted for foreign inflation.

Loss Reduction and Resumption of Pumped Storage at Capljina: Two benefits are included here. Thefirst is a reduction in transmission losses not already included in the benefits of the Gacko-Tuzla line andthe Visegrad-Tuzla line. The reductions rise from 54 GWH in 2004 to 65 GWh by 2012. They are valuedat the avoided generation cost of US$0.04/kWh. Second, the transmission system rehabilitation wouldincrease the fault levels at Capljina, thus allowing the on-line start of the pumps to permit the resumption ofpumped storage at that plant. It is assumed that the additional generation would be 225 GWh per year,which would require an additional 290 GWh of generation. The pumping cost was valued at US$0.0134/kWh (an energy cost only since the pumping would be done at night) and the additional electricitywas valued at US$ 0.04/kWh. The dollar estimates were adjusted for local inflation.

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Additional System Sales: Restoration of the 220 KV and 400 KV transmission lines would allow a peakdemand of 2,700 MW to be supplied reliably, compared with a peak of 2,155 MW under existingconditions. This increase in capacity would rmake it possible to accommnodate forecast additional electricitygeneration of 774 GWh in 2004 rising to 2,700 GWh by 2011. This is the same forecast as is used for theforecast financial statements of EPBiH, EPI-ZHB and EPRS, but the figures were adjusted downwards bythe increased generation taken account of in the other transmission benefit estimates described above. Theadditional sales corresponding to this generation were valued at the actual average electricity price of US50.056/kWh.. The costs of the additional electricity include the average export price of electricity ofUS$0.021/kWh, transmission and distribution valued at US$ 0.04481kW per year, and adjustments weremade for transmission and distribution losses of 14%. The dollar estimates were adjusted for localinflation, except the export price, which was adjusted for foreign inflation.

Distribution - Other Costs: Other costs relating to distribution benefits consisting of additional sales andreduction in unserved energy include: the associated cost of generation valued at the export price,transmission and distribution costs (excluding the distribution investments) and transmission anddistribution losses. Annual distribution O&M was assumed to be 1.5% of the distribution investrnent. Theactual estimates differ between the three EPs.

Distribution Benefits - Reducing Unserved Energy: It was assumed that in the absence of thosedistribution investments made in order to improve supply reliability the corresponding electricity would besubject to a probability of supply failure of 20% per year from 2003-2007 and 100% thereafter. Thereduction in unserved energy was valued at the existing electricity prices of the three EPs. The dollarestimates were adjusted for local inflation.

Distribution Benefits - Additional Sales: The additional sales made possible by the distributioninvestments were valued at the existing electricity prices of the three EPs. The dollar estimates wereadjusted for local inflation.

Hydropower Benefits: Benefits of improved availability were estimated for Jablanica 5 and 6 andTrebinje 1. It was estimated that in the absence of rehabilitation, generator output would decrease by 1.5%per year for five years after which the units would be incapable of producing. The value of capacity wasestimated to be US$ 133.6/kW/year for Jablanica and US$ 110.2/kW/year for Trebinje. The benefits weremeasured as the avoided reduction in available capacity. A cost-benefit analysis was not carried out forthe safety investments at Rama, Jablanica and Trebinje because of the difficulty of estimating the reductionin probability of dam failure attributable to the investments and the value of damages resulting from a damfailure. The dollar estimates were increased by local inflation.

Hydropower Costs: The hydropower costs include the investments for availability increase and annualoperation and maintenance costs equal to 2% of the investments.

SCADA System O&M: O&M costs are assumed to be 2% of the total investment in real terms. They areescalated by 3% per year for local inflation (the average of Federation and RS inflation).

SCADA System Benefits - Salary Savings: The salary savings are due to an estimated reduction of 42persons at hydropower plants and substations, and 42 persons in record keeping staff, having an averagesalary of DM 14,800 per year in 1999. The salaries are escalated by local inflation.

SCADA System Benefits - Reduction in Unserved Energy: The reduction in unserved energy was

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assumed to be 0.25% of gross electricity consumption of 10,000 GWh, valued at a the average tariff rate ofUS$ 0.056/kWh. The estimate is escalated by local inflation.

SCADA System Benefits - Spare Communications Revenue: The revenue from sale of sparecommunications capacity was estimated on the basis of installation of 1,052 km of fiber cable, each cablehaving 16 spare fibers, that would be sold for US$ 1,200/fiber/mile/year. The estimate is escalated bylocal inflation.

Sensitivity analysis / Switching values of critical items:

Estimates were made of switching values for both the economic analysis and the financial analysis. Theswitching values are those values of the selected critical items which cause the internal rate of return to beequal to the opportunity cost of capital (12% for the economic analysis and 15% for the financial analysis).

The critical items and corresponding switching values for the economic analysis are:

1. Project cost: US$ 1,850 million (670% increase).2. Delay between investment and output: 27 years.

Elimination of the increased sales benefit would not reduce the intemal rate of return to 12%.

The critical items and corresponding switching values for the financial analysis are:

1. Project cost: US$ 640 million (160% increase).2. Delay between investment and output: 9 years.

Elimination of the increased sales benefit would not reduce the intemal rate of return to 15%.

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Annex 5: Financial Summary


Actual and forecast financial statements for EPBiH, EPHZHB and EPRS are shown in the following pages.


Elektropnvreda of Bosnia and Herzegovina

Actual and Forecast Income Statements For Years Ending December 31(KM thousands)

Version date:

10-May-01

fInteret in post-rdeb 5,482001 2002 2003 200 4 200 5 2006 2007

DontestcElectricityo p les (GWh) 4,171 ,20 3,94 3,6 3,783 3,894 42071

Average Domnesbc Electricity Price (KM/kWh) 0.1215 0.1252 0.1289 0.1328 0.1368 0.1409 0,1451

Average Export Price (KMefWe) T 0.05(63 0(0526 0.0539 0.0552 0,0566 0.0540 0,0595

Foperaign Mnargin (%) -13% 215% -25% 211% -85% 2-6% 24%

Doe_ Inlto _%) 3.0% 3.0%M 3.20% 3.20% 3.0% 3.0%/ 3.0%

Electricity SalesFtevenue 467,965 506,96.7 5483a55 591,465 64,630 675,173 712072

Other Revenue 7,009 7,219 7,436 7,659 7,889 8,126 8,369

Oexraorinar Expenses

Coal (including transportabrnrost) 5ig 195,450 213,752 233,282 256,520 279,115 300,707 317,632

Salaries and Wages g g84,478 87,012 89,622 9231s41 95,80 97,933 100871

NeMaIenanome ad ar Pan re E48, 6944 804,)02 93,834 (01,35) ( 180,531 (3154 (,26

Worting T axio (r/6) 7 3; 71% 7&6 70% 30% 300% 0%Net Ope rabngIncSomneBeforeFna s 140(38521 15696)4 (19763)0 (t5080)4 32059 2168463 230 150

Depreciatincm an Fiaca Cot

Operabng Margin (%) 27%(86B (44804 (930 301% 30% 30% 30/

Net Oeain g Inoome TxBeforeFneancdinalCotes (38,768) (26,280) (19,7839) (50,37) (740,36) (1,47) (Z,2664

Adjusted Net Pnrfit i B T (48,688) (44,804) (49,839) (50,375) (40,531) (31,547) (22,262)

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Elektroprivreda of Bosnia and HerzegovinaActual and Forecast Sources and Applications of Funds For Years Ending Decernber 31

(KM thousand)

_ 7___L2_ ~~~~~~~~~~~Forecast~~~~~~2001 2002 2003 2004 200 i 2006 2007

SOURCESIntemal Sources

Net Operating Income Before Financial Costs 3 (38 756) (26,298) (19,763) (15,080) (7,036) 148 7,664

Depreciation 179,277 186,042 196,664 205,203 211632 216,846 222,486

Other Adjustments

Total Internal Sources 140,521 159744 176.902 190,124 204,597 216,993 230.150

External SourcesGrants 150 2,067 2,133 - - 1Borrowings 65,000 190,848 150,642 10,000 10,000 10.000 10,000

Total Extemal Sources 65150 192.915 152,775 10.000 10.000 10,000 10,000

TOTAL SOURCES 205 671 352.659 329,677 200,124 214,517 22609,3 240.150

APPUCATIONSCapital Investment Requirements 202,939 318.676 256,169 192,871 156.400 169.200 163,800

Total Capital Investment Requirements , . 202,939 318.676 256,169 192,871 156,400 169.200 163.500

Import Duty on Equipment for Investment Projects i

Profit Tax __-- _

Total Tax and Duties

Debt Service Post-War Debt

Interest 5,461 14,298 26.132 31.613 30,134 28.653 27,195Pincipal 4 873 8,798 9,433 8,328 38,097 38,128 37,432

Total Post-War Debt Service 10,334 23,096 35,565 39,941 68,231 63.782 64,627

Debt Service Pre-War DebtInterest 4 471 4,208 3,945 3,682 3,362 3,041 2,731

Pnncipal 1,729 6,034 6,034 6,034 7,946 7,946 7,79i

Total Pre-War Debt Service 6200 10,242 9,979 9,716 11.308 10,968 10.522

Increase (Decrease) in Working Capital (12,329) (10,669) (7,598) (6,120) (38.635) (6,686) (5,067)

TOTAL APPUCATIONS 267 144 341,34 294,114 236,408 197,304 240,284 233.861

Sw&gtps Funfs (1,473) 11,.13 35,%S3 r^ ) 17.29t (8329i) 6Op.rdrn Coset 8etatrou 46235 44,762 5#O076 01.69 56.3m4 7247 *367C)Oelng Ct1n 44 762 56,076 91,639 M5ae 72.4t7 50s397 MOO

Self-Financing Ratio 6 vt 61% 53% 54% 73% 95% 89% 96%Debt Service Coverage Ratio - -. 2S* 8 50 4.79 3.88 3.83 2.57 2.79 3.06

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Elektroprivreda of Bosnia and Herzegovina

Actual and Forecast Balance Sheet For Years Ending December 31

(KM thousand)

\ W W " ; E X ~~~~~~~Fomcast. g i | g i g E ~~~2001 2002 2003 2004 2005 2D06 2007

Fixed Assets

Gross Fixed Assets 8,388,980 8,591,919 8,910.595 9,166,764 9,359,635 9,516,035 9,685,235Less: Accumulated Deprecation 5,336,622 5,522,664 5,719,328 5,924,531 6,136,164 6,353,009 6,575,495

Net Fixed Assets 3,052,358 3,069,255 3,191,267 3,242,233 3223,471 3,163,026 3,1098740Otwe Non-Curfent Assets 5,8568 5,858 5,858 5,858 5,858 5,858 5,856

Work-ln-Progress 202,93 318676 256,169 192,871 156,400 169,2D0 163,800

Total Fixed Assets 3,261,155 3,393,789 3,453,294 3,440,962 3,385,729 3,338,084 3,279,398

Current Assets

cash 44,763 58,076 91,639 55,355 72,648 59,357 65,646

Gross Accounts ReceNvable i50,393 155,463 155,483 155,463 155,463 155,48.3 155,463

Less: A_ umuated Provisio For Doubtful Revenue 73,324 77,971 81,845 85,526 89,023 92,345 95,501

Net ArrDurts Recewable 77,069 T7,492 73,818 69,937 66,440 63,118 59,962

Inventories 113,062 113,962 113,962 113,962 113,962 113,962 113,962Other Current Assets 31,719 31,719 31,719 31,719 31,719 31,719 31,719

Total Current Assets 267,513 279,249 310,938 270,972 284,768 268,156 271,289

TOTAL ASSETS 3,528,668 3,673,038 3,764,231 3,711,934 3,670,498 3,606,239 3,550,687

EQUMtES AND LIABILrTIES

EQUIrY

State Capital 4,223,240 4,223,240 4,223,240 4223,240 4,223,240 4,223,240 4,223,240Legal and Statutory Reserves 14,588 14,588 14,588 14,588 14,588 14,588 14,588

Revakiaton Reserve (672,036) (672,036) (672,038) (672,036) (672,036) (672,036) (672,036)Retained Eamings/Losses (475,275) (520,079) (569,918) (620,293) (660,824) (692,372) (714,633)

Total Equity 3,090,517 3,045,713 2,995,874 2,945,499 2,904,968 2,873,420 2,851,159

Donation 148,660 150,747 152,880 152,880 152,880 152,880 152,860

Long-Term Debt 234,176 418,422 554,232 548,765 544,403 508,360 472,285Less Current PorAion (post-war debt) 4,873 8,798 9,433 8,328 38,097 38,128 37,432Less Current Portion (pre-war debt) 1,729 6.034 6,034 6,034 7,946 7,946 7,791

Net Long-Tern Debt 227,574 403,590 536,765 534,403 496,360 462,285 427,063

Accounts Payables 34,333 37,195 40,2833 43,828 47284 50,617 53,401Current Pourion ot Longp-Term Debt .. 6,602 14,632 15,467 14,362 46,044 48,075 45.223

Other Current LUabitties 20,962 20,962 20,962 20,962 26,962 20,962 20,962

Total Current Liabilities 61,897 72,988 76,712 79,152 114290 117,654 119,585

TOTAL EQUMnES AND LUABLMIES 3,528,666 3,673,038 3,764,231 3,711,934 3,670,498 3,606,239 3,550,687

kw* Aecwn MISe% (over axrerr yewrs WiP,ings) , W062% 999 100.0% 10040% 1000% 1*00% 100,0%

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Elektropriveda Hrvatske Zajedrsc,e Herceg-Bosne (EPHZHB)

Actual and Forerast Income Statements For Years Ending December 31

(KM thousands)

Version date:

10-May-01

E v ; ' ' ~~~~~~~~~~~~Forecast- 48,1 46280i 2 002 2003 2004 2005 2006 2007

DistObutionE icitycSales GWh) -F Cts . 12870 914 9,04 1,0508 1,8 2 ,111 1,166

Derine Elecricity Sales (GWh) 5 85 84% 91% 90% 835 835

Average Distnrbubon Eecrbicity Price (KM7KWh) 6 1227 071234 0.1302 0.1341 0.1382 0.1423 0.1467

Average Direct Electnricty Price (KMJKW\h) 0 0511 0 0524 0.0537 0.0551 0.0564 0.0579 0.0593

Noetg Operaton agn (%) 2% 5% -35% -25% 21% 3.% 25% 28%

DrontTti ( ) 30 30% 3.0% 3.0% 3.-0 3.0% 360%

Revenue frorn Serlvie and other incorne ,, 1575 1,654 1,736 1,823 193130 20S,39 220111

Tota Revenue 151,119 160,973 171,568 182,961 195,217 208,404 222,597

peradng Expense (

Aurasted net ProfitparePat 6,714 7,397 8,353 9,359 5,937 11,18 15,096

Pmvision for doubtffu receivatJf s 2,960 1,577 560 2,531 2,531 2,531 2,531

Other Operating Expenses ,,_28,456 29,309 30.189 31,094 32,027 32,988 33,978

Total Operating Expenses 10166 104,227 107,624 110,857 117,694 124,965 132,700

Workirng Ratio () ,67% 65% 63% 61% 60% 60% 60%

Ctiange in Operatng Expense (%) 2 1 °J4 2 5% 3.3% 3.0% 62% 6.2% 8 .2%

Net Operabing Income Before 49.451 56,746 63,943 72,104 77,523 83,439 B9,897

Operain Margin l%) _ 33% 35% 37% 39% 40% 40% 40%Depreciation 1 483171 49.680 52,896 56,054 57,629 59,204 60,779

Net Opegratinglnoorre Beore Financial Costs ffll, . * 1,290 7,066 11,047 16.050 19,894 24,235 29,118Operatig F'atio (%) 99% t , gg/ 960a 94% 91% 90% 88% 87%

Interest onpre-war debt 7 f " 7625 7,313 7,001 6,689 6,352 6,014 5,677

Finanaal Incorne , i ii - - _ _ _ _

Net OperatbnglIncoffe BeforeTax (8.016) (4,839) (3,275) 1.186 5,937 11,18 18,663Net Operabin MargBin(%) ' -S% -3% -2% 1% 3% 5% 8%/

Profit Tax (30%) .t6 - - 3.644

Extraordlinary Incorrle (Expense) .

Adjusted NetPrmiit . ' , 199 (8,016) (4,839) (3,275) 1,186 5,937 11,185 15,019

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Elektroprivreda Hrvatske Zajednice Herceg-Bosne (EPHZHB)

Actual and Forecast Sources aiid Applications of Funds for Years ending December 31(KM thousand)

1 1 l E I ~~~~~~~~~Forecast. | t ~~~~~2001 2002 2003 2D04 2005 2006 2007

Net Operating Income Before Financial Costs 1,280 7,066 11,047 16,050 19,1894 24,235 29,118

Depreciafion .48,171 49,680 52,B96 56,054 57,629 59,204 60,779

Extraordinary expense

Total Intemal Sources 49,451 56,746 63,943 72,104 77,523 83,439 89,897

External SourcesGrants 600 4,733 5.667 - - -

Borrowings __15,000 48,602 47,190

Total Extemal Sources 15,600 53,335 52,857

TOTAL SOURCES 65,051 110,081 116,800 72,i04 77,523 83,439 89,897

APPLICATIONSCapital Investment Requirements 45,273 96.484 94,731 47,250 47,250 47.250 47,250

Total Capital Investment Requirements 45.273 96.484 94,731 47,250 47,250 47,250 47,250

TaxesProfit Tax - - - - 3,644

Total Tax and Duties - - - 3.644

Debt Service

Interest 9.296 11,904 14,322 14,864 13,957 13,051 10,454Principal - 930 6,025 8,191 14,259 14,259 12,093

Total Debt Service 9,296 12,835 20,347 23,055 28,216 27,310 22,547

Increase (Decrease) in Working Capital 4,630 1,839 (373) (2,476) (2,473) (2,287) (3,302J

TOTAL APPUCATtONS 59,199 111,158 114,705 67,8291 72,993 72,273 70,139

_vpk Fud 5 5852 (1 fJ77 2.005 4,275 4*53$W 11,:66 19,753

CongC atiSh Babnce 19.t771 18,094 20,189 2444655 21139t :40,t61 59,919

Self Financing Ratio 49% 76% 54% 53% 55% 82% 110% 124% 1425cDebt Servire Coverage Ratio (20.4) 26.9 5.3 4.4 3.1 3.1 2.7 3.1 4 0

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Elektropuivreda Hrvatske Zajednice Herceg-Bosne (EPHZHB)

Actual and Forecast Balance Sheet for years ending December 31

(KM thousand)

5 l ll l l , ~~~~~~~~Forecast. 0 S e i 8E ~~~~2001 2002 2003 2004 2005 2006 2D07

GrossFixed Assets 1,598,514 1,643,787 1,740,271 1,835,003 1,882,253 1,929,503 1,976,753

Less: Accumulated Depreaation 832,627 882,307 935,204 991,258 1,048,887 1,108,091 1,188,870

Net Fixed Assets 765,888 761,480 805,068 843,745 833,366 821,412 807,883

Work-in-Progress 45,273 96,484 94,731 47,250 47,250 47,250 47.250

Total Fixed Assets 811,160 857,964 899,799 890,995 880,616 868,862 855,133

Long-Teffe Investments and Intangible Assets 1,265 1,265 1,265 1,265 1,265 1,265 1,265

Current AssetsCashr 19,171 18,094 20,189 24,464 28,994 40,161 59,918

Gross Acmunts Recewvable 246,602 251,382 253,080 253,080 253,080 253,080 253,080

Less Accujmulated Provisio For Doubtful Receivable 173,058 174,635 175,195 177,726 180,257 182,787 165,318

Net Accounts Receivables 73,544 76,747 77,885 75,354 72,823 70,293 67.762

Inventories 21,122 21,122 21,122 21,122 21,122 21,122 21.122

Other Current Assets 5,451 5,451 5A51 5,451 5,451 5,451 5,451Total Cuent Assets 119,288 121,414 124,647 126,392 128,391 137,026 154,253

TOTAL ASSS 931.713 980,643 1,025,711 1,018,651 1,010,272 1,006,953 1,010,651

EQ=UES AND LiABILrIES

EQUITYState Capital 269,93 269,936 269,936 269,936 269,936 269,936 269,936Legal and Statutory Reserves

Revaluation Reserve 397,720 397,720 397,720 397,720 397,720 397,720 397,720

Retained EamingsfLosses (25.746) (30,585) (33,860) (32,674) (26,737) (15,553) (533)

Total Equity 641,910 637,071 633,796 634,982 640,919 652,103 667,123

Deferred Reverue (donations) 49,801 54,5-34 60,201 80,201 60,201 80,201 80,201

LIABILMES

Long-Term Debt 208,392 256,063 297,229 289,038 274,778 260,519 248,427

Less Current Portion 930 6,025 8,191 14,259 14,259 12,093 -

Net Long-Term Debt 207481 250,039 289,038 274.778 260,519 248,427 248,427

Accounts Payable 180279 13,879 14567 15632 138625 124359 112031

ASual~esTax1 12,7146 126,947 13294 102,917 151217 106,149 722,9

Current corlecon oatf Log-ermorDebt yQr rr8% 941% 96,025 89191 14025% 14,259 1209.0 t00

Othe Curen Libilfies6,62 6622 6,62 6,22 ,62 6,221,62

BOSNIA AND HERZEGOGtVNA

Elektroprivreda Republika Srpska (EPRS)

Artual and Forecast Income Statemnents for Years Ending December 31

(KM thousands)Version date:

10-May-01

0 g 3 ~~~~~~~~~~~~~~~Forr.casta | | | | | | g~~~~~2001 2002 2003 2004 2005 2006 2007

Doanesic Elecbiriny Sales (GWh) 2,347 2.523 2.649 2.541 2.46% 3.44% 3,223

AewaedaDomsRatd EWincMCty 141P, (KM3512 16,011 188,082 212,689 229,133239 5093420 563,

Waintenarc a 32.5% 2 23% 4% 4,4% 4,5% 24% 24,%

Diredation _ 215,650 219,373 225,527 231,660 236,935 242210 247,485

t eatina nse c i alsCoss (74,499 (52,362) (372959) (108,71) (7,81) 72 19.1

Woraing Rato (%) 11% 611% 10598% 510% 102% 5% 53%

Intres on Oposr.we dxebts 1% 892,5 ,723 .9 .2 9,339 8,585 7,872 7,271

Not iOperesgtnmi So

TD t p lre stbadFnaca ot 84135 3,6 47,7118268 2269, 29,339 8586 7,0872 76,271

Net Operatng _n one BE#ore ya a l74,45 391) (52,36) (44,989) (28,311) (16,8) (3,00) 11,910

NtOperating Rarn (%) 119% 13%1 -10%. -04% -32% -91- 9 7%NettnoineterTaest efrExrornyte 7391 (55,16 (4,962) (2,311) (8,386) (3,000) 11.910

Notue Npetan Incrrot foe a (75,391) (55,816) (44,982) (28,311) (16,386) (3,000) 11,910

72


Elektroprivreda Republika Srpska (EPRS)Actual and Forecast Sources and Applications of Funds for Years Ending December 31

(KM thousand)

* , , .- ~~~~~~~~~~~~ForecastS i | L ~~~~~2001 2002 2003 2004 2005 2006 2007

TtlInterna Sources

Net Operabng lnoDme Beore Financial Costs -74,499 -52,362 -37,259 -18,971 -7,801 4,872 19,1 B1

Deprecration 215,850 219,373 225,527 231,660 236,935 242,210 247,486

Total Intemal Source 141,351 167,011 188,268 212,689 229,133 247,082 266,666

External Sources

Grants644 236 283 EB-MtOernS9rf 12,342 74,773 50,183 - - -

Total External Sources 18,782 77,140 53,016

TOTAL SOURCES 160,33 244,151 241284 2,6B9 229,i33 247,0B2 266,666

APPLICATIOSCapital nvestnent ReireqruetsY 105,693 184,629 183,9 158,250 158,250 158,250 158,250Total Capital lnvestment Requirements 105,693 164,629 183,985 158,250 158,250 158,250 158,250

Taxes

Prt Tax

Debt Service Pout-War Debt

Interest 893 3,454 7,723 9,339 8,585 7,872 7,271

PrnciPal 598 2,322 3,328 3,328 11,699 11,100 9.377

Debt Service Pre-War Debt

kirerest

Principal :

Total Debt Service 1,491 5,776 11,051 12,668 20,283 18,973 16,648

Interest on short-erm borowings . 0 O 0 0 0 O

Increase (Decrease) in Woring Capital 29,238 26,854 22,695 26,057 16,868 29,300 13,558

TOTAL APPLCATIONS 136,422 217,259 217,731 196,974 195,402 206,522 188,456

C9*VC_itlh8 _ililr 531,393 80,265 103,833 119>552 1S34284 193,S43 27Z,053

Self Financing Rato 89% 85% 88% 104% 121% 126% 149%DebtSeviceCoverageRatio 94481 28.92 1704 16.79 11.30 13.02 16.02

- 73 -


Elektoprivreda Republika Srpksa (EPRS)

Actual and Forecast B3alance Sheet for Years Ending December 31

(KM biousand)

; | l | 1|1 t2G~~~~201 200 2003 2004 2005 2006 2007

GossFhed Ass8s 7,122,841 7,228,534 7,413,164 7,597,149 7,755,39g 7,913,649 8,071,899

Low A qxmilvl n Dew 4,972,245 5,191.617 5,417,144 5,648,04 5,835,739 6,127,949 6,375,434

Not Food Assft ~~~~~~~~~2,150,596 2,036,917 1,996,019 1,948,345 1,869,660 1,785,700 1,696,465

Work4ln-PtOiSS 105,693 184,629 183,965 158,250 156,250 158,250 158,250

ToW F'ad Asset 2,256296 2.221,546 2,180,005 2,106,595 2,027,910 1,943,950 1,854.715

IriubleI Assts 3,947 3,947 3,947 3,947 3,947 3,947 3,947

cuzver ASSeSU

Cash 53,393 80,285 103,83 119,552 153,284 193,843 272,053

Grow Trade Receivables 354 891 387,056 412,785 431,131 450,456 470,829 492.325

PrvmWon for DauWrtA Debt 161 101 171.147 179.192 184,934 196,984 197,363 2041,096

NoTrade PAceIvbll 193,790 215,909 233,594 246,197 259,472 273,466 288,229

05w Receiablie 30900 3030 30.000 30,000 30.00 000D 30,000 30,600

Inventories 41,454 41,454 41,454 41,454 41,454 41,454 41.454

Total Cuient Asses 318,637 367,849 40,8 437,204 484,210 538,763 631,736

N*y-O"rshi Assets 9,012 9,012 9,012 9,012 9,012 9,012 9,012

2,587 886 2,602,153 2,601,850 2,556,758 2,525,079 2,495.673 2.499,410

EQAJTTES AND MABILITIES

Sbtat CapIta 3,685956 3,685,956 .,685,958 3,685,958 3,685,958 3,685,958 3,685,956

Revd&.MWn Peser7e 021 72.021 72,021 72,021 72,021 72,021 72,021

ReFned E Eaingose -1,481,921 -1,537,736 -1,582,718 -1,611,028 -1,627,415 -1,630,415 -1,618,505

TOW Eqaty 2,276,058 2.220,243 2.175.261 2,146,951 2,130.564 2.127.584 2,139,474

DOrPra 130,370 132,737 135,570 138,570 135.570 135,570 135,570

Post-war DX 36039 108,490 155,345 152,017 140,318 129,218 119.841

La Cuifernt PU17or6 222 3,328 3.328 11,699 11,100 9,377

Not Post-War Debt 33717 105,162 152,017 140,318 129,218 119,841 119,841

Pre-War Long-Teefn Dead 0 0 0 0 0 0 0

Lee CasrerIt Pordo

Net Pro-War Lonlg-Term Debt t

Cumn Liabilites

AcCurit Paybl 76T225 71,490 66,480 53,026 49,433 34,127 35,332

CtMATt P4ud f Aye Long-Term Deb 2,322 3,328 3,328 11,699 11,100 9,377 0

CiarrI PorImtof Prol'-War Long-Term Debt 00

Olfie CisAftIo LMebowe 69,154 69.194 69,194 69,194 69,194 69,194 69.194

Toal CuTer Uabl 147,741 144,012 139,002 133,919 129,728 112,698 104,526

- 74 -

Annex 6: Procurement and Disbursement Arrangements


Procurement

1. Responsibility. The project implementation would require procurement of goods and works,and selection and employment of consulting firms to carry out consulting services. The PIUs responsiblefor implementation of Power 2 (the Federal PIU, the branch PIUs in EPBiH and EPHZHB, and the PIU inEPRS) would continue for the proposed project. The Procurement Capacity Assessment has identified theneed for strengthening each of the Elektroprivreda PlUs with qualified procurement staff. The Federal PIUwould not require any strengthening since it would not be handling procurement matters under the project.In addition, intemational consultants would work together with the PlUs of the three EPs during projectimplementation. The foreign consultants would be employed to assist in procurement activities for therehabilitation of the transmission lines included in the project and for the Rama flydro Power project. Theywould also provide in-house training to the Elektropriovredas' procurement staff. A World Bankprocurement workshop would be organized immediately after loan effectiveness to ensure that the agreedprocurement procedures are well understood by PIU staff.

2. Methods for Bank-Financed Procurement. Bank-financed goods, works and technicalservices would be procured in accordance with the "Guidelines for Procurement under IBRD Loans andIDA Credits" published by the Bank in January 1995, revised January 1996, August 1996, September1997 and January 1999. The Bank's Standard Bidding Documents would be used for Bank-financedprocurement. The selection of Consultants to be financed by the Bank would be carried out in accordancewith the "Guidelines on Selection and Employment of Consultants by World Bank Borrowers" published bythe Bank in January 1997, revised September 1997 and January 1999. The project procurement plan isgiven in Para 10. A General Procurement Notice would be published in the Development Business of theUnited Nations in May 2001.

3. Methods for Non-Bank-Financed Procurement. Project procurement not financed by theBank would be carried out in accordance with Bosnian and the co-financiers' procurement rules andregulations. Procurement arrangements under parallel financing would be the responsibility of theborrower and the co-lenders.

4. Project Goods and Works. The project would finance restoration of the 400 kV and other highvoltage transmission systems, especially reconstruction of damaged substations (US$ 85.9 million). Theproject would also include a Supervisory Control and Data Acquisition (SCADA) System component toimprove power dispatching and facilitate the operation of the high voltage network within BiH on anintegrated basis (US$ 44.2 million). It would include investments in power distribution to provideelectricity to returning refugees and to reconstruct damaged facilities, thereby relieving serious overloadingin some areas and enabling reduction in the high levels of technical distribution losses (US$ 41.0 million).It would provide investments at selected hydropower stations to improve safety and plant availability (US$22.6 million). Investments at thermal power stations would be limited to reducing pollution (US$ 16.9million).

- 75 -

5. Project Technical and Consultant Services. The project would finance technical assistancefor:

(i) procurement and implementation of the physical components (US$ 2.8 million);(ii) the Joint Power Coordination Center ZEKC (US$ 1.0 million);(iii) a survey of socially vulnerable electricity consumers (US$ 0.1 million);(iv) corporatization and commercialization of the power sector enterprises (US$ 6.5 million); and(v) establishment of regulatory agencies (US$ 3.0 million).


6. Procedures for Bank-Financed Goods and Supply and Installation Contracts. InternationalCompetitive Bidding (ICB) would be used for works and supply and installation contracts estimated to costthe equivalent of US$ 100,000 or more. ICB procedures would cover 100% of Bank-financed works andsupply and installation contracts.

7. Supply and Installation Arrangements. Transmission line reconstruction is best realizedthrough supply and install arrangements, which would be applied for a large part of the projectprocurement using the Bank's Standard Bidding Documents for the Supply and Installation of Plant andEquipment. This approach would be appropriate because the cost of works would represent a substantialpart of the estimated contract value (up to about 50% of the total contract value); and (b) installationseparate from equipment supply is generally a lengthier process and could delay project implementation.

Procurement Review

8. Prior Review. Procurement documents for Bank-financed components would be subject to theBank's review. The prior review would cover 100% of Bank-financed procurement value.

9. Procurement Audit. In addition to prior reviews, the Bank may carry out an audit of theprocurement it finances. Whereas the prior reviews are regular tasks under the project, procurement auditwould be a spot check of the quality and consistency of Bank-financed procurement work.

10. Procurement Plan. The project procurement plan is given in the following table. It does notinclude US$ 7.1 million for services to be provided in-house by the EPs.

- 76 -

BOSNIA AND HERZEGOVINATHRID ELECTRiC POWER RECONSTRUCTION PROJECT

Project Procurement Plan

Main Procurement Actity

EstImated AwardlCost Procurement InviatIon Submission SIgning of

Project Beneficiary USS M Financier Method of Bids of Bids Contract Compldion

TRANSMISSION COMPONENT

T-01 400 kV Transmission Lines EPBiH / EPHZHB I EPRS 17.5 IDA ICB Feb-02 Apr-02 Jun-02 Apr-04T-02 220/110 kV Transmission Lines EPBiH I EPHZHB I EPRS 7.0 IDA ICB Mar-02 Jun-02 Aug-02 Aug-03

5-01- EPBiH Substations EPBiH 15.0 EIB Donor's method Apr-02 Jun-02 Mar-03S-02 Works EPBiH 2.1 EPBiH Sep-03S-03- EPHZHB Substations EPHZHB 16.3 EIB Donors method Apr-02 Jun-02 Mar-03S-04 Works EPHZHB 2.3 EPHZHB Sep-03S-05- EPRS Substations EPRS 22.3 EIB Donors method Apr-02 Jun-02 Mar-03S-06 Works EPRS 3.4 EPRS Sep-03

SCADA COMPONENT

Z-01- SCADA - ZEKC ZEKC 7.6 EBRD Donors method Feb-02 Apr-02 Jan-04Z-02' SCADA - EPBiH EPB)H 12.2 EBRO Donor's method Feb-02 Apr-02 Jan-04Z-03' SCADA - EPHZHB EPHZHB 12.2 EBRD Donors method Feb-02 Apr-02 Jan-04Z-04- SCADA - EPRS EPRS 12.2 EBRD Donor's method Feb-02 Apr-2 Jan-04

HYDROPOWER STATION COMPONENT

H-01- HPP Jablanica Unit 5 EPBiH 5.1 SECO Donors method Nov-99 Dec-99 May-01H-02 Works EPBiH 0.4 EPBiH Nov-01H-03' HPP Jablanica Unit 6 EPBiH 4.9 SECO Donors method Apr-01 Jul-01 May-02H-04' HPP Jablanica Common Services EPBiH 4.0 SECO Donors method Apr-01 Jul-01 May-02H-04 Works EPBiH 1.1 EPBiH Nov-02H-05 HPP Rama EPHZHB 2.9 IDA [CB Apr-02 Jul-02 Sep-02 Jul-04H-06 Works EPHZHB 0.6 EPHZHB Sep-04H-074 HPP Trebtnje EPRS 2.9 KtW Donors method Jun-01 Aug-01 Jun-03H-08 Works EPRS 0.7 EPRS Sep-03

THERMAL POWER STATION COMPONENT

C-01' TPP Tuzta EPBiH 3.0 NW Donors method Jul-02 Oct-02 Jun-04C-02 Works EPBiH 0.4 EPBiH Sep-04C-03' TPP Kakanj EPBiH 5.0 NYI Donors method Jul-02 Oct-02 Jun-04C-04 Works EPBiH 0.7 EPBiH Sep-04c-OS' TPP Gacko EPRS 1.1 NYt Donors method Jul-02 Oct-02 Jun-04C-06 Works EPRS 0.6 EPRS Sep-04C-07' TPP Ugljevik EPRS 4.5 NYI Donors method Jul-02 Oct-02 Jun-04C-S08 Works EPRS 1.6 EPRS Sep-04

DISTRIBUTION COMPONENT

D-XX- To be determnined by donors EPBiH / EPHZHB I EPRS 41.0 USAID f Donors' methodsNORAD/

Spain

TECHNICAL ASSISTANCE COMPONENT

q-01 Procurement EPBiH I EPHZHB I EPRS 2.8 IDA QCBS Jul-01 Aug-01 Oct-01 Apr-04Q-02 Financial management of Eps EPBiH / EPHZHB / EPRS 4.7 IDA QCBS Sep-01 Oct-01 Dec-01 Sep-04Q-03 Social assessment of electricity consumers EPBiH/ EPHZHB / EPRS 0.1 IDA aCBS Sep-01 Oct-01 Dec-01 Apr-040-04 Corporatizaton and commercializaton of EPs EPBiH EPHZHB / EPRS 1.8 EC Donors method Mar-O Jun-01 Aug-01 Aug-03Q-05' Establishment of ISO ZEKC 1.0 DFID Donors method Nov-01 Dec-01 Dec-030-06' Establishment of regulatory agencies FBiH & RS Govemments; 3.0 USAID Donor's method Nov-01 Dc0 Dec-03

NERC, ERC FBiH, andERC RS

These packages may contain multiple contracts / lotsNYI Financer not yet identified

- 77 -

Procurement methods (Table A)

Table A: Project Costs by Procurement Arrangements(US$ million equivalent)

Procurementetd

Expenditure Category IcB NC d: N.B.F. ToI cost

1. Works 2.90 0.00 0.00 13.90 16.80

(2.90) (0.00) (0.00) (0.00) (2.90)

2. Goods 0.00 0.00 0.00 125.10 125.10

(0.00) (0.00) (0.00) (0.00) (0.00)

3. Services 0.00 0.00 7.60 12.90 20.50

(0.00) (0.00) (7.60) (0.00) (7.60)4. Supply and Install 24.50 0.00 0.00 44.20 68.70

(24.50) (0.00) (0.00) (0.00) (24.50)

Total 27.40 0.00 7.60 196.10 231.10

(27.40) (0.00) (7.60) (0.00) (35.00)

Figures in parenthesis are the amounts to be financed by the IDA Credit. All costs include contingencies.

2! ilcludes three consulting services to be financed by IDA with selection being based on QCBS.

Prior review thresholds (Table B)

Table B is not required as all IDA-financed components would be subject to prior review.

- 78 -

Disbursement

Allocation of credit proceeds (Table C)

11. The Credit proceeds would be disbursed over the three-year period October 2001 to September2004. The Project Completion Date would be September 30, 2004, and the Credit Closing Date would beMarch 31, 2005, when full disbursement of the Credit is anticipated. The Elektroprivredas would maintainall required supporting documentation for at least one year beyond the year in which the last withdrawalfrom the Credit Account has taken place and make it available for review by the Bank staff andindependent auditors upon request.

12. Disbursements from the IDA credit would initially be made on the traditional system withreimbursements against direct payments. Once a satisfactory financial management system has beeninstalled and is operating satisfactory, the method for disbursement may be changed to the new procedurewhereby proceeds from the Credit are disbursed against quarterly Project Management Reports (PMRs).The target date for such a conversion would be August 15, 2002.

Table C: Allocation of Credit Proceeds

Expenditure Category Amount in Mmillion Financin Percentage(1) Goods (including associated works 100% of foreign expenditures, 100 % ofand services) local expenditures (ex-factory cost) and

85% of local expenditures for other itemsprocured locally.

(a) EPBiH Transmission Lines 10.50(b) EPHZHB Transmission Lines 3.80(c) EPRS Transmission Lines 10.20

(2) Works 85%(a) HPP Rama 2.90

(3) Consultants' services 100%(a) Technical assistance to EPBiH 2.54(b) Technical assistance to EPHZHB 2.53(c) Technical assistance to EPRS 2.53

Total Project Costs 35.00 _

Total 35.00

Special account:

There would be no Special Accounts prior to expenditures being made on the basis of PMRs.

Statements of Expenditure:

As all procurement packages are subject to prior review, disbursements would be made against fulldocumentation.

- 79 -

Section 2: Capacity of the Implementing Agency in Procurement and Technical AssistanceRequirement Review

The procurement capacity assistance has shown that there are significant shortcomings in the procurementlegislation, policies and procedures currently in place in the country. A Country Procurement AssessmentReport has not yet been prepared. However, experience on procurement for previous IDA-financed projectsin the power sector has been satisfactory, and it is proposed to strengthen the existing system forprocurement work under the project.

Based on an assessment of the capacity of the E]lektroprivreda PIUs to conduct procurement, the followingaction plan would be implemented:

One procurement specialist (PS) should be appointed in each PIU to assist in implementingprocurement activities for the project. The PS should have familiarity with World bankprocurement procedures and practices. The PS shall be appointed prior to the Project LaunchWorkshop.

- As soon as possible after project effectiveness, consultants should be appointed to assist the EPPIUs in procurement-related activities for IDA financed goods and works.

- In addition to the Project Launch Workshop, a procurement seminar will be held within six monthsof credit effectiveness to familiarize the PIU staff with World Bank procurement procedures andpractices.

- The PS for each PIU should attend Bank-sponsored training courses in Turin.

- The PlUs should develop computerized procurement monitoring system to track procurementactions and produce periodic progress reports.

Section 3: Training, Information and Developiment on Procurement

Estimated date of Project Launch Workshop: October 2001

Estimated date of publication of General Procurement Notice: May 2001

Is procurement subject to mandatory SPN in Development Business: No

Domestic Preference for Goods: No

Domestic Preference for Works, if applicable: NIA

Retroactive financing: No

Advance procurement: No

- 80 -

Procurement Monitoring System: A computerized procurementmonitoring system will beestablished within the PIUswhich will collect and keepup to-date all procurementdata and use this inprogress reports to the Bank.

Procurement arrangements under co-financing: Components financed by otherco-financiers will be procuredin accordance with theirprocedures.

Section 4: Procurement Staffing

Procurement Staff responsible for the procurement in the Project: Iftikhar Khalil, PTL & PAS.Explain briefly the expected role of the Field Office in procurement: Limited liaison role only.

- 81 -

Annex 7: Project Processing Schedule


ct0 0040 0h.PAW M, nnd At:ku alTime taken to prepare the project (months) 11

First Bank mission (identification) 05/24/99 05/24/99Appraisal mission departure 03/26/2000 03/26/2000

Negotiations 05/08/2000 05/08/2000Planned Date of Effectiveness 09/01/2001

Prepared by:

The three Elektroprivredas (EPBiH, EPHZHB} and EPRS) with the support of the Ministries of Energy.and the Joint Coordinating Center (ZEKC).

Preparation assistance:

Consultancy assistance provided by AGRA Monenco-Teshmont of Canada with financing from th,Canadian Consultant Trust Fund managed by the World Bank, Electrotek Concepts (SCADA component)with financing by USTDA, NERA (electricity policy statements) with financing by DFID, and Norwegianconsultants (electricity laws) with financing by the Government of Norway.

Bank staff who worked on the project included:

Name S0peialityIftikhar Khalil Program Team Leader/Engineer/Procurement Accredited Staff

Richard Hamilton Energy Economist

Anna Bjerde Financial Analyst

Felix Martin Economist

Angelica Fernandes Procurement Analyst

Bemard Baratz Envircinmental Specialist

Chai Ting Financial Management Specialist

Laszlo Jamniczky Consultant

Peter Kelly Consultant

Yolanda Gedse Team Assistant

Migara Jayawardena Financial Analyst

- 82 -

Annex 8: Documents in the Project File*


A. Project Implementation Plan

Project Implementation Plan for the three Elektroprivredas

B. Bank Staff Assessments

Financial Analyses of EPBiH, EPHZHB and EPRSProject Economic and Financial Analyses

C. Other

Electric Power III Reconstruction Project, Final Report, AGRA Monenco-Teshmont, January 2000, withupdated economic and financial analysis in April 2001.SCADA Feasibility Report (in progress)Environmental Management Plans of EPBiH, EPHZHB and EPRSElectricity Policy Statement of the RS, approved on April 20, 2000Electricity Policy Statement of the FBiH, approved on May 5, 2000Draft Electricity Law of the RS, submitted to the FBiH House of Representatives on April 12, 2001Draft Electricity Law of the FBiH, submitted to the FBiH House of Representatives on May 30, 2000

*lncluding electronic files

- 83 -

Annex 9: Statement of Loans and Credits


Difference between expectedand actLal

Original Amount in US$ Millions disbursements

Project ID FY Purpose IBRD IDA SF GEF Cancel. Undisb. Orig Frm RevdP044523 1999 BASIC HEALTH 0.00 10.15 0.00 9.56 0.22 0 00

P059763 1999 CULT. HERITAGE PILOT 0.00 4.13 0.00 4.13 2.26 0 00

P045313 1998 EDUCATION RECONSTR. 0.00 10.60 0.00 1.53 1.90 C0

P045483 1998 ELEC. POWER II 0.00 25.43 0.00 23.87 22.56 . 00

P050892 1998 EM PILOT CREDIT (RS) 0.00 5.06 0.00 0.53 0.47 ' 00

P045310 1997 EMG PUB WORKS & EMPL 0.00 9.63 0.00 0.62 0.79 C 00

P062936 1999 ENT EXP FACIL (BEEF) 0.00 12.10 0.00 12.10 4.96 ' 00

P048461 1999 ENTER & BANKING PRIV 0.00 51.59 0.00 41.27 14.72 . 00

P044522 1997 ESSEN. HOSPITAL SERV 0.00 14.28 0.00 1.56 2.38 C00

P045134 1998 FORESTRY 0.00 6.72 0.00 6.33 2.34 0 00

P056192 1999 LOCAL DEVELOPMENT 0.00 15.24 0.00 14.56 -0.15 Li D0

P045311 1997 LOCAL INITIATIVES 0.00 6.72 0.00 0.13 0.40 10 0

P055432 1999 PFSAC II 0.00 72.81 0.00 44.44 68.76 °00

P048462 1998 RECON ASST-REPUBLIKA 0.00 16.78 0.00 2.48 1.40 0 00

P045484 1998 TRANSPORT RECON. II 0.00 38.77 0.00 3.99 4.40 C 00

Total: 0.00 300.01 0.00 167.10 127.41 C 00

- 84 -

BOSNIA AND HERZEGOVINASTATEMENT OF IFC's

Held and Disbursed Portfolio

In Millions US Dollars

Committed Disbursed

IFC IFC

FY Approval Company Loan Equity Quasi Partic Loan Equity Quasi Partic1997/99 Bosnia Micro 0.00 0.27 0.00 0.00 0.00 0.27 0.00 0.00

1985 Energoinvest 8.10 0.00 0.00 0.00 8.10 0.00 0.00 0.001997 Enterprise Fund 0.00 1.84 0.00 0.00 0.00 0.39 0.00 0.001998 SEF Akova 1.96 0.00 0.00 0.00 1.96 0.00 0.00 0.001999 SEF Bosnalijek 0.00 0.00 2.30 0.00 0.00 0.00 2.30 0.001999 SEF Kopex 2.16 0.00 0.00 0.00 2.16 0.00 0.00 0.001998 SEF Lignosper 2.14 0.00 0.00 0.00 1.86 0.00 0.00 0.001999 SEF Lijanovici 2.32 0.00 0.00 0.00 2.32 0.00 0.00 0.001997 Sarajevska 3.33 0.00 0.00 0.00 3.33 0.00 0.00 0.001977 TKA Cazin 3.44 0.00 0.00 0.00 3.44 0.00 0.00 0.001998 Wood Agency-AL 4.61 0.00 0.00 0.00 0.00 0.00 0.00 0.001998 Wood Inga 1.63 0.00 0.00 0.00 0.33 0.00 0.00 0.00

0 Wood Konjuh 2.32 0.00 0.00 0.00 2.06 0.00 0.00 0.000 Wood Kozara 1.63 0.00 0.00 0.00 1.37 0.00 0.00 0.000 Wood Podgradci 1.16 0.00 0.00 0.00 0.95 0.00 0.00 0.00

1998 Wood Vrbas 1.63 0.00 0.00 0.00 0.33 0.00 0.00 0.00

Total Portfolio: 36.43 2.11 2.30 0.00 28.21 0.66 2.30 0.00

Approvals Pending Commitment

FY Approval Company Loan Equity Quasi Panic

Total Pending Commitment: 0.00 0.00 0.00 0.00

- 85 -

Annex 10: Country at a GlanceBOSNIA AND HERZEGOVINA: Third Electric Power Reconstruction Project

Sasania Eurooe & Lower-POVERTY and SOCIAL and Central middle-

Hlrzregost>ne Asia income Development diamond*1999Population, mid-year (millions) .. 475 2.094 Life expectancyGNP Per caDita (Atlas method. US$) . 2,150 1t200GNP (Atlias method, U$ bllions) 4.5 1,022 2,513 TAverase annual growth. 1993-99

Pooulation f%f 0,1 1t1Labor force G%N 1.2 P Gross

per I . . primaryMost recent estimate (latest year vavila4ble 1993-99) capita . . enrollment

Poverty 1% of population below national poveriy lifnel -Urban population (% of total ooPulation) 43 87 43Life expectancv at birth (rears) 73 69 69infant mortalilY(port 1000 livo births) 13 22 33ChGlr rnalnutrition i% of children under 5J .. 1s Access to safe waterAccess to improved water source (% of copulation) .. .. S6Illiteracy f% of population aoe t56+ .. 3 16Gross primary enroltmenet (% of school-are Dootul8WiOn - 0oo 114 - osnia and Herzegovina

Male - 101 114 Lower-middle-income groupFemale .. 99 116

KEY ECONOMIC RATIOS and LONG-TERM TRENDS

1979 1989 199t 1999 - ------ - -----Economic ratios

GDP (US$ itWiovns) ,, .- 4.1 4.6Gross dornestc irlvestmentlGDP 38.0 33.3 TradeExports of goods and servicesiGDP 33,7 34.0Gross domestic savinoslGDP -1,1 9.4Gross national savings/GOP . 10.9 16.7

Current accounl balarucefGDP - -27.1 -&6 Domes-icinterest aymrents/GDP . 1,4 1.4 Dmsic > InvestmentTotat debt/GOP 74.0 67.5 .v.Total debt servce/exoorts . .. 9.6 7.9Present value of debtGDP 25.7 ..

Present value of debtlexports . 76.3Indebtedness

1979-89 1989-99 1998 1999 1999-03(averaqe arnual orowth)GOP .. 12.8 10.0 11.0 Bosnia and HerzegovinaGNIP per capita .. .. 12.8 10.0 11.1 *Lower-middle-income groupExports of qoods aPd services .. 33.7 11.0 12, f

STRUCTURE of the ECONOMY1979 19119 1998 1999 Growth of investment and GDP(%)

(% of GDP) 75

Aqriculture . 15.8 15.8 TIndustry . 27.8 27.8

50T

Manufacturinq . . .. 25Services . 56.4 56.4

Private consumption . 25 9General qovernment consumption .GDI O GDPImports of qoods and services 70.6 57.9

1979-89 1989-99 1998 1999 Growth of exports and imports (%)(average annual qrowthJAgriculture l.. .Industry . 120,-

Manuifacturinq.. . ... Services ... 6u-

Private consumptionGeneral government consumption . . .. . . 94 95 96 97 98 99

Gross domestic investment . 3.7 -3.5 -60Imoorts of goods and services . . 7.8 -9.8 - aponts Itmp0rtGross national product .. .. 17.3 11.1

Note: 1999 data are preliminary estimates.

The diamonds show four kev indicators in the countrv (in bold) compared with its income-grouc average. If data are missing. the diamond willbe incomplete.

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Bosnia and Herzegovina

PRICES and GOVERNMENT FINANCE1979 1989 1998 1999 Inflation (%)

Domestic prices 20

(% change)Consumer prices (In KM. the Federation) 5.0 0.0 -Implicit GDP deflator o . . --

-10 , 94 N 9fi / 97 9 99Government finance(% of GDP, includes current qrants) -20

Current revenue 32.6 29.4 -30Current budaet balance -0.6 -3.7 GOP deflator CPI

Overall surplus/deficit , -7.2 -3.0

TRADE

(US$ motionS) 1979 1989 1998 1999 Export and Import levels (USS mill.)

Total exports (fob) 817 970 3OO0 Tn.e.n.a. 2,000

ManufacturesTotal imports (cif) 2573 2.399

F ood 1 000Fuel and enerqv

93 94 95 9S 97 98 99Export Price index (1995=100)Import price index (1995=100) .. E Exports * ImportsTerms of trade (1995=100)

BALANCE of PAYMENTS1979 1989 1998 1999 Current account balance to GDP )%),

(US$ millions) incl current official transfersExports of toods and services 1.367 1,560Imports of qoods and services 2,864 2,661 oResource balance -1,498 -1,101 93

Net income -111 -79 10Net current transfers , 510 417

Current account balance -1.098 -763 I I j 3_Financinq items (net) 1,014 1 347Chanqes in net reserves 85 -583

Memo:Reserves includina cold (USS millions) 175 380Conversion rate (DEC. locallUSS) .. .. 1.8 1.8

EXTERNAL DEBT and RESOURCE FLOWS1979 1989 1998 1999 -' ''

(US$ millions) Composition of 1998 debt (US$ minll.)Total debt outstandinq and disbursed | .

IBRD 596 596 G 278

IDA 437 373 A 596

Total debt service .. .. -FIBRD . 35 34 F 400/IDA .. 2 3

Composition of net resource flows B 437

Official prants 469 735Official creditors 181 255Private creditors -75 -74 C:77Foreign direct investment 0 60 | 70Portfolio eauitv -- 0 0 E 1,124

World Bank proqramCommitments -- - 100 163 EA - BRD - Bilateral

Disbursements 135 68 B - DA D - Other mulblateral F - Private

Principal repavments 0 0 LC - IMF G-Short-term

Netflows 135 68

Interest pavments 38 36Net transfers 97 32

Development Economics

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AdditionalAnnex 1 1

Review of Financial Management Arrangements

General

A review of the Financial Management System was undertaken between December 1999 and March 2001to:

(i) assess the project's capacity and readiness for the implementation of LACI;(ii) review the presence of the necessary elements for sound project financial management system such

as internal controls, project accounting, project staffing and audit arrangements; and(iii) prepare a time-bound action plan for strengthening the financial management system to achieve

Project Management Report (PMR)-based disbursement that would assist the project to movetowards LACI (a report on the Review of Financial Management System is included in the ProjectImplementation Plan).

Project Management and Coordination

The PlUs created within the three power companies for Power 2 would be the implementing agencies forthe project. The PIUs would manage contracting and expenditure under the project and coordinate projectactivities. They would receive no financing from the IDA Credit.

The Federal PIU was established in March 1998 to support the implementation of Power 2, partly financedby IDA. It currently handles the Special Account for EPBiH and EPHZHB. Under the proposed project,the Federal PIU would not have financial management responsibilities. The Federal PIU's main role underthat project would be to coordinate project implementation in EPBiH and EPHZHB.

Staffing

Each Elektroprivreda PIU would have at least one full-time accountant with sound credentials andexperience in accounting (acceptable to the Association) to make sound judgments on the maintenance ofthe books of accounts and on the production of financial information. In EPBiH, the alternativearrangement proposed by management under which EPBiH would nominate several staff members from theaccounting department to be responsible for financial management of the project is acceptable to the Bank.The nomination of suitable accountants in the tlhree PIUs is acceptable to the Bank.

Accounting and Internal Controls

The project accounting would comply with International Accounting Standards. The local accountingstandards, which are closely based on International Accounting Standards, were adopted by FBiH witheffect from January 1, 1999 and by RS with effect from January 1, 2000. Donor agencies are currentlyproviding training to local accountants to familiarize them with the new standards.

During the recent audits of the three PIUs, thie auditors did not identify any weaknesses in the internalcontrols. IDA also did not identify any major internal control weaknesses during the recent financialmanagement supervision of Power 2.

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Adequate intemal controls, including financial policies and procedures, segregation of duties, financialauthorities, are included in the financial manuals of the three PIUs.

Project Accounting System

The three Elektroprivreda PIUs would be responsible for overall project financial management andaccounting. Each PIU would maintain books of accounts for the project, prepare and disseminate financialstatements and financial management reports, and ensure timely audit of the financial statements. Theoverall principles for project accounting are outlined below:

(i) Books of accounts for the project would be maintained by the Elektroprivreda PIUs ondouble-entry bookkeeping principles. Project accounts would be maintained using a computerizedaccounting system.

(ii) Project accounting would cover all sources of project funds (including donors contributions), andall utilization of project funds. All project-related transactions (whether involving cash or not)would be accounted in the books of accounts. This would include contributions made by donors.Disbursements made by IDA and the Special Account maintained by BiH would also be includedin the project accounting system. Funds received from different sources would be identifiedseparately and reflected in the project accounts and financial statements

(iii) Project-related transactions and activities would be distinguished from other activities of theenterprise. This distinction would be effected at the data-capture stage. An identifiable TrialBalance for the project capturing all project receipts, expenditures, and other payments under theproject would be prepared. A Chart of Accounts for the project would be prepared. The Chart ofAccounts would conform to the classification of expenditures and sources of funds indicated in theproject documents (Project Implementation Plan, Project Appraisal Document). The Chart ofAccounts would enable data to be captured in a manner as to facilitate financial reporting ofproject expenditures by: project components; expenditure categories; disbursement categories; andfunding donors.

(iv) Project Financial Statements and financial reports would be filly based on the project books ofaccounts, and substantially generated from the financial accounting system.

(v) Physical information on key performance indicators which can be readily linked to financial costswould be maintained as part of the project financial management system. Initially this would bemaintained for some high cost items which account for a significant portion of project cost, and foritems for which data on physical activities can be easily captured. These items have been identifiedand indicated in the Financial Manual. This list would be gradually expanded duringimplementation.

The three Elektroprivreda PIUs have acquired and implemented the Scala accounting system (computerisedaccounting software) which is capable of producing PMRs in accordance with LACI requirements. Thissystem has been designed keeping in mind, inter alia, an accounting and intemal control system with thecapacity to record and retrieve in a timely manner all financial transactions under the project.

The accounting system conforms with intemationally accepted standards and would:

(i) reliably record and report all assets, liabilities, and financial transactions of the project;(ii) provide reliable financial information for managing and monitoring project activities, and(iii) provide quarterly PMRs on a timely basis.,

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The accounting system is classified by component; reflects the sources of funds and is broken down intodifferent types of expenditures for the project. Further, it provides information on the receipt and use offunds and is able to produce financial reports comparing budget with actual expenditures at any given time.The system is capable of providing financial data to measure performance when linked to the outputs of theproject. It is an important element of the financial management system. The Scala system is consideredacceptable to IDA.

Planning and Budgeting

The three PIUs should prepare quarterly budgets for the new project, although they do not prepare detailedplanning and budgeting for Power 2. The PIUs would need to improve their financial management skills inthe preparation of budgets in accordance with the PMR format (disbursement categories, components andactivities, financiers, account codes, and by mcnth).

Accounting Flows

The PIUs would generate and maintain vouchers and supporting documentation for expenditures on allactivities of the project and send these to the Bank for payments. Because of the small number of contractsand large value items, the financial flows for all activities in Power 3 would initially involve direct paymentfrom the credit accounts to suppliers, and there would be no Special Account initially.

Financial Reporting

Each Elektroprivreda PIU would maintain its own accounts for its part of the project and would ensureappropriate accounting of the funds provided. Each Elektroprivreda PIU would be responsible fordesigning appropriate PMRs and preparing PMRs on a quarterly basis, and would furnish the PMR foreach quarter to the Association not later than 45 days after the end of each calendar quarter, commencingfor the quarter ending June 30, 2002. The PMR would:

(i) (a) set forth actual sources and applications of funds for the project, both cumulatively and for theperiod covered by said report, and projected sources and applications of funds for the project forthe six-month period following the period covered by said report; and (b) show separatelyexpenditures financed out of the proceeds of the Credit during the period covered by said reportand expenditures proposed to be fmarLced out of the proceeds of the Credit during the six-monthperiod following the period covered by said report;

(ii) (a) describe physical progress in project implementation, both cumulatively and for the periodcovered by said report; and (b) explain variances between the actual and previously forecastimplementation targets; and

(iii) set forth the status of procurement under the project and expenditures under contracts financed outof the proceeds of the Credit, as at the end of the period covered by said report.

Financial Manual

Each Elektroprivreda PIU has completed a project financial manual which covers:

(i) the financial management system proposed under the project, with special emphasis on accountingand auditing policies, standards and internal controls;

(ii) the role of the financial management systems in project management and implementation;

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(iii) the accounting arrangements required for project management, the format for and content ofproject financial reporting;

(iv) the auditing arrangements that would be used during project implementation, and(v) budgeting and planning.

The financial manuals have been reviewed by the financial management specialist and are acceptable toIDA.

Financial Management Risks

The risks related to the financial management aspects of the project include:

(i) possible delays in preparation of PMRs;(ii) poor handling of financial management due to a poor accounting environment and few qualified

accountants in BiH;(iii) possible continued lack of control of operating costs and large operating losses; and(iv) possible misuse of the IDA Credit.

These risks are considered to be manageable due to the various risk-mitigation measures identified.Nonetheless, they are highlighted here in view of their potential to adversely affect project performance.These aspects would be monitored closely as part of project supervision.

The risk that preparation of the project management reports would be delayed and that the quality of thereports may be of variable or unsatisfactory quality is due to the fact that the PlUs have not previouslyprepared PMRs. Timely preparation, use of the project management reports and satisfactory quality ofthese reports are essential to facilitate effective project management. The risk-mitigation factors are thesubstantial upfront actions which are being taken including: (a) design of a comprehensive financialmanagement system; (b) implementation of a computerized financial management system; (c) recruitmentof key financial staff to augment financial management capabilities. The three PIUs have been using theScala accounting system, which is capable of producing reliable PMRs. Disbursements from the IDACredit would not be made on the basis of Project Management Reports (PMRs) in the first year, but ratherbe made on the traditional reimbursement basis. Disbursements could be converted to the PMR-basedmethod when the financial management system is operating satisfactorily.

The risk relating to the limited number of qualified accountants in BiH is being mitigated by stipulating theprofile of the desired accountant and ensuring that the Association has a say in the recruited accountant.With respect to the poor accounting environment in BiH, it has been decided to build up sufficientaccounting capacity within the project by specifying in detail what is required and by creating a projectcoordination unit, i.e., by ring-fencing the project.

All three Elektroprivredas have inadequate control of operating costs, operating losses and poor financialmanagement systems. The three Elektroprivredas need to improve their financial positions and also theirfinancial management systems urgently. The three Elektroprivredas are currently implementing detailedaction plans (acceptable to IDA) to address these issues. IDA would monitor the implementation of theseaction plans regularly.

The risk of misuse of the Bank's fund needs to be taken into account because of perceived corruption asreported in the press. The three Elektroprivredas operate in a business environment with a high rate ofperceived corruption, even though implementation of the two earlier power projects is considered to havebeen satisfactory. The risk that the project funds would not be used as intended for financing the definedinvestment program would be minimized by "ring-fencing" the project via the Elektroprivreda PIUs,

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segregating duties within the PIUs, recruiting appropriate staff in financial management and procurement,and requiring independent audits of project funds by an independent accounting firm. Furthermore, allprocurement activities would be subject to prior review by the Bank and disbursements from the IDACredit would be made initially on the traditional system with direct payments and no Special Accounts.

Cost and Financial Performance

The project's financing plan and the project's planned expenditures have been realistically estimated andthe project is considered financially sustainable.

The cost tables are based on realistic assumptions including appropriate physical and price contingencies.The project documentation adequately shows the relationship between the disbursement categories inSchedule I of the Development Credit Agreement and the project components.

One of the biggest financial risks at the company level is the ability of the Elektroprivredas to service theirterm borrowings, both the pre-war and post-war debts, including those for Power 1, 2 and 3. The analysesof the future financial performance are included in Section E2 of the PAD. They indicate that the three EPsare capable of maintaining a satisfactory self-financing ratio, a debt service coverage ratio of at least 1.5and overall positive cash flow.

Auditing

The Elektroprivreda PIUs would be responsible for ensuring that the companies' financial statements andthe project financial statements (including special accounts and Project Management Reports (PMRs)) areaudited by an independent auditor acceptable to the Association, in accordance with standards on auditingthat are acceptable to the Association.

The audited financial statements of the preceding fiscal year, including a separate opinion by the auditor ondisbursements made against PMRs, would be sent to the Association within six months of the end of thefiscal year.

The annual audit would be carried out in accordance with the Guidelines for Financial Reporting andAuditing of Projects Financed by the World Bank (March 1982). The audit report should be in a formatin accordance with the International Standards on Auditing promulgated by the Intemational Federation ofAccountants (IFAC). The audit report would include a separate opinion for PMRs against whichdisbursements have been made or are due to be made from the Credit and PMRs which will be included inthe audit report accompanying the financial statements.

The audit of the financial statement would include:

(i) an assessment of the adequacy of accounting and internal control systems to monitor expendituresand other financial transactions and ensure safe custody of project-financed assets;

(ii) a determination as to whether the project implementing entities have maintained adequatedocumentation on all relevant transactions; and

(iii) verification that expenditures submitted to the Association are eligible for financing, andidentification of any ineligible expenditures.

The four PIUs comply with the audit covenants under Power 2 and there were no significant accountingissues reported by in the most recent project audit, for the year ending December 31, 1999. However the1999 enterprise audits for the three Elektroprivredas were all qualified by the independent auditors.

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(i) In EPBiH and EPHZHBZ, the auditors were unable to satisfy themselves as to the appropriatevaluation of property, plant and equipment in accordance with the International AccountingStandards.

(ii) In EPRS, the auditors issued a qualified (disclaimer - the financial statements were not fairlystated) opinion on EPRS's financial statement because of the following matters/issues: (a) seriousinternal and accounting control weaknesses and numerous inconsistencies in accounting policieswithin the entity, (b) inability to verify the existence of the inventory and fixed assets as theauditors were appointed after the year end, (c) inability to satisfy themselves as to the appropriateverification & valuation of fixed assets in accordance with the International Accounting Standards,(d) inability to obtain verification of trade debtors/receivables of KM 154 million, (e) inability toverify the fair value of 'barter" arrangements with suppliers, (f) inability to fully reconcile internalbalances of KM 2.6 million, and (g) inability to verify the accuracy and fairness of the openingbalances of the capital and reserves. EPRS's financial statements indicated major deficiencies inthe enterprise requiring urgent actions.

Under Power 3, all three Elektroprivredas would have their assets revalued by independent professionalevaluators, by June 30, 2002. The three Elektroprivredas are currently implementing detailed action plans(acceptable to IDA) to address these issues.

PricewaterhouseCoopers Canada audited the 1998 financial statements of each Elektroprivreda andPricewaterhouseCoopers Macedonia audited the 1999 financial statements for each Elektroprivreda. Thethree Elektroprivredas and the Federal PIU have signed contracts with PricewaterhouseCoopers Macedoniafor the 2000 audits. Each Elektroprivreda would appoint, by effectiveness, an independent auditing firm,acceptable to the Association, to perform the audits of the company and project financial statements for2001. In addition, a management letter on intemal controls from the auditors would need to be providedfour months after project effectiveness.

Disbursements

It is expected that the proceeds of the Credit would be disbursed over a period of 3.5 years, which includessix months for completion of accounts and submission of withdrawal applications. As there is no standarddisbursement profile for Bosnia and Herzegovina, the disbursement forecast is based on the Bank'sexperience in financing similar projects in other ECA countries, and other projects in Bosnia andHerzegovina. The Project's Closing Date would be March 31, 2005.

Disbursements from the IDA Credit would be made initially on the traditional system with reimbursementsagainst direct payments. However, there would be no Special Accounts initially. Once a satisfactoryfinancial management system has been installed and is operating satisfactorily, the method for disbursementmay be changed to the new procedure whereby proceeds from the Credit are disbursed against quarterlyProject Management Reports (PMRs). The target date for such a conversion would be one year fromeffectiveness.

Special Account

As disbursements from the IDA Credit would be made initially on the traditional system withreimbursements against direct payments, there would be no Special Accounts initially. To facilitate timelyproject implementation, Special Accounts, denominated in US. Dollars, in the name of each of theElektroprivredas would be established when they are converted to the new PMR-based method. Because ofweaknesses of the commercial banks within BiH, banks outside BiH would be used for the purposes of theSpecial Accounts.

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The Government would be responsible for the appropriate accounting of the funds provided by IDA underthe Credit, for reporting on the use of these funds, and for ensuring that audits of the financial statements orreports are submitted to the Bank. A computerized accounting system is envisaged to be established by allthe three Elektroprivreda PIUs. Independently, the accountants at the Elektroprivreda PIUs would maintainaccounts (for their part of the project) each preparing quarterly financial reports as part of ProjectManagement Reports.

Conclusion

It is concluded that the Elektroprivreda PIUs currently satisfy the Bank's minimum financial managementrequirements. However, the three PIUs do not have in place an adequate project financial managementsystem that can provide the accurate and timely PMRs required by IDA under LACI. An Action Plan wasdiscussed and agreed with the PIUs. It requires the PIUs to design and implement satisfactory financialmanagement systems to address the above issues. Once this Action Plan is carried out successfully, it isbelieved that the project will have developed an accounting system that will be able to produce the requiredlevel of financial management reports in a timely fashion.

Action Plan

In order to ensure that the project would have a sound financial management system in place which canprovide, with reasonable assurance, accurate and timely information on the status of the project (PMRs)required by the Bank/IDA, the following time-bound Action Plan has been agreed with the threeElektroprivredas:

Action Deadline

1. Submission of the 2001 acceptable financial management action Doneplan by each Elektroprivreda

2. Submission of the acceptable annual financial management action January 31 afterplan by each Elektroprivreda each year end

3. Submission of the quarterly progress reports on the financial 30 days after eachmanagement action plans by each Elektroprivreda calendar quarter

4. Confirmation by each Elektroprivreda that an independent auditing By effectivenessfirm, acceptable to the Association, to perform the audits of the companyand project financial statements for 2001.

5. Finalization of 2002 Budget, including recording and allocation of December 31, 2001total budget in the accounting system - by month, and by year, byactivities, by categories, by sources and by account codes.

6. Reliable PMRs and satisfactory to the World Bank for the quarter August 15, 2002ending June 30, 2002

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7. Budgets are reasonable and accurate when compared against the August 15, 2002actual

8. Satisfactory supervision report, including FM implementation August 15, 2002

9. Satisfactory withdrawal applications August 15, 2002

10. Satisfactory audit, especially internal controls August 15, 2002

11. Review of the financial management arrangements by the FMS to August 31, 2002assess readiness for PMR based disbursement

- 95 -

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