Document of The World Bank

Public Disclosure Authorized Report No: ICR2613

IMPLEMENTATION COMPLETION AND RESULTS REPORT (IDA-40900)

ON A

Public Disclosure Authorized CREDIT

IN THE AMOUNT OF SDR 13.9 MILLION (US$ 21 MILLION EQUIVALENT)

TO THE

REPUBLIC OF SERBIA IN SUPPORT OF THE SECOND PHASE OF THE US$ 1,000 MILLION

ENERGY COMMUNITY OF SOUTH EAST EUROPE (APL) PROGRAM-SERBIA COMPONENT- SERBIA PROJECT Public Disclosure Authorized

December 28, 2012

Sustainable Development Department South East Europe Country Unit Europe and Central Asia Region

Public Disclosure Authorized

CURRENCY EQUIVALENTS (Exchange Rate Effective October 31, 2012) Currency Unit = Dinar (CSD) CSD 88.83 = US$ 1 US$ 1.53 = SDR 1 FISCAL YEAR January 1—December 31

ABBREVIATIONS AND ACRONYMS

AERS Energy Agency of the Republic of Serbia IDA International Development Agency APL Adaptable Program Lending ISA International Standards on Auditing CAS Country Assistance Strategy ISR Implementation Status and Results Report CMU Country Management Unit KfW Kreditanstalt für Wiederaufbau EAR European Agency for Reconstruction KPI Key Performance Indicators EBRD European Bank for Reconstruction and LAP Land Acquisition Plan Development ECSEE Energy Community of South East Europe ME Ministry of Energy EIB European Investment Bank NPV Net Present Value EC European Community PAD Project Appraisal Report EMP Environmental Management Plan PIU Project Implementation Unit EMS Elektro Mreza Sribje SDR Special Drawing Rights EPS Elektro Privreda Sribje SEE South East Europe EU European Union TSMO Transmission System and Market Operator ICB International Competitive Bidding WHO World Health Organization ICR Implementation Completion Report IDA International Development Agency

Vice President: Philippe H. Le Houerou Acting Country Director: Anthony A. Gaeta Sector Manager: Ranjit Lamech Project Team Leader: Salvador Rivera ICR Team Leader Enrique Crousillat

SERBIA ENERGY COMMUNITY OF SOUTH EAST EUROPE (APL) PROGRAM - SERBIA PROJECT

CONTENTS

Data Sheet A. Basic Information B. Key Dates C. Ratings Summary D. Sector and Theme Codes E. Bank Staff F. Results Framework Analysis G. Ratings of Project Performance in ISRs H. Restructuring I. Disbursement Graph

1. Project Context, Development Objectives and Design ...... 1 2. Key Factors Affecting Implementation and Outcomes ...... 4 3. Assessment of Outcomes ...... 9

4. Assessment of Risk to Development Outcome ...... 12 5. Assessment of Bank and Borrower Performance ...... 12 6. Lessons Learned ...... 14 7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners ...... 15 Annex 1. Project Costs and Financing ...... 16 Annex 2. Outputs by Component ...... 17 Annex 3. Economic and Financial Analysis ...... 20 Annex 4. Bank Lending and Implementation Support/Supervision Processes ...... 25 Annex 5. Beneficiary Survey Results ...... 27 Annex 6. Stakeholder Workshop Report and Results ...... 27 Annex 7. Summary of Borrower's ICR and/or Comments on Draft ICR ...... 27 Annex 8. Comments of Cofinanciers and Other Partners/Stakeholders ...... 31 Annex 9. List of Supporting Documents ...... 31 MAP

A. Basic Information

Energy Community of South East Europe (APL) Program - Serbia Country: Serbia Project Name: and Montenegro Component - Serbia Project Project ID: P088867 L/C/TF Number(s): IDA-40900 ICR Date: 12/28/2012 ICR Type: Core ICR SERBIA AND Lending Instrument: APL Borrower: MONTENEGRO Original Total XDR 13.90M Disbursed Amount: XDR 13.28M Commitment: Revised Amount: XDR 13.28M Environmental Category: B Implementing Agencies: Electric Power Company EPS Tranmission System and Market Operator - EMS Cofinanciers and Other External Partners:

B. Key Dates Revised / Actual Process Date Process Original Date Date(s) Concept Review: 11/17/2004 Effectiveness: 02/06/2006 02/06/2006 02/24/2010 Appraisal: 04/18/2005 Restructuring(s): 12/29/2011 Approval: 06/30/2005 Mid-term Review: 11/28/2008 12/09/2008 Closing: 02/28/2010 06/30/2012

C. Ratings Summary C.1 Performance Rating by ICR Outcomes: Moderately Satisfactory Risk to Development Outcome: Moderate Bank Performance: Moderately Satisfactory Borrower Performance: Moderately Satisfactory

i

C.2 Detailed Ratings of Bank and Borrower Performance (by ICR) Bank Ratings Borrower Ratings Quality at Entry: Moderately Satisfactory Government: Moderately Satisfactory Implementing Quality of Supervision: Moderately Satisfactory Satisfactory Agency/Agencies: Overall Bank Overall Borrower Moderately Satisfactory Moderately Satisfactory Performance: Performance:

C.3 Quality at Entry and Implementation Performance Indicators Implementation QAG Assessments Indicators Rating Performance (if any) Potential Problem Project Quality at Entry No None at any time (Yes/No): (QEA): Problem Project at any Quality of No None time (Yes/No): Supervision (QSA): DO rating before Satisfactory Closing/Inactive status:

D. Sector and Theme Codes Original Actual Sector Code (as % of total Bank financing) Transmission and Distribution of Electricity 100 100

Theme Code (as % of total Bank financing) Regional integration 50 50 Regulation and competition policy 50 50

E. Bank Staff Positions At ICR At Approval Vice President: Shigeo Katsu Philippe H. Le Houerou Country Director: Gerard A. Byam Orsalia Kalantzopoulos Sector Manager: Ranjit J. Lamech Hinderikus Busz Project Team Leader: Arturo S. Rivera Mohinder P. Gulati ICR Team Leader: Enrique O. Crousillat ICR Primary Author: Enrique O. Crousillat

F. Results Framework Analysis

Project Development Objectives (from Project Appraisal Document) Within the overall ECSEE APL objectives/context, the project (ECSEE APL2-Serbia) would provide investment support and technical assistance for Serbia, and complement ii the donor assistance for creation and institutional development of TSMO and the regulatory agency -- obligations Serbia has to fulfill under Athens Memorandum.

The objective of the project is to improve electricity market access for consumers and suppliers through increase in the quantity, quality, reliability, safety and efficiency of the bulk power transmission system, and strengthen capacity of the institutions to participate in the regional electricity market.

Revised Project Development Objectives (as approved by original approving authority) The Project Development Objectives remained unchanged throughout the implementation of the project. However, upon the recognition that the originally established PDOs lacked specificity and were considered overly ambitiously defined, the management (Sector Management and CMU) recommended updating the indicators and overall results framework. Subsequently, some target dates were specified , but the indicators remained essentially unchanged.

(a) PDO Indicator(s)

Original Target Formally Actual Value Values (from Revised Achieved at Indicator Baseline Value approval Target Completion or documents) Values Target Years Indicator 1 : Market liberalization in the regional market ECSEE Treaty-market access for non- The electricity residential Value Those to be agreed market is formally customers by quantitative or 0% in final version of open to all large January 2008; Qualitative) the ECSEE Treaty (non-residential) also, consumers. residential customers by January 2015. Date achieved 06/30/2005 07/01/2005 06/30/2010 12/01/2012 Comments Whereas the market is formally open to all large consumers, these have not (incl. % joined the market due to a significant price difference between the regulated achievement) price and the average market price.

(b) Intermediate Outcome Indicator(s)

Original Target Actual Value Formally Values (from Achieved at Indicator Baseline Value Revised approval Completion or Target Values documents) Target Years Indicator 1 : Quality of supply improvement Value One year after the Early results of four No baseline values were No formal (quantitative substations are completed defined at project design revision or Qualitative) fully substations indicate

iii

commissioned, in that the quality of their local service supply targets are area: (a) losses are being surpassed. In reduced by at least average, energy 15%; (b) voltages losses have been are within their reduced by 64%, operating limits; energy interruptions and (c) energy by 87% and voltage interruptions are drops by 62%. reduced by at least 40% Date achieved 06/30/2005 07/01/2005 06/30/2010 12/01/2012 Comments Impact of the project (quality of supply) is being monitored. EPS started to (incl. % collect quality of supply indicators of existing substations in mid 2011. These achievement) indicators include voltage drop, energy losses, hours of interruption. Indicator 2 : Satisfactory completion of substations and associated transmission lines. 5 substations fully completed. 4 All substations Value 2 substations by additional completed by (quantitative year 2 and by year substation are the project or Qualitative) 3 expected by the end closing date of 2012, and one during 2013 Date achieved 07/01/2005 06/30/2010 10/30/2012 Comments Target for the satisfactory completion of substations was increased to 8 (incl. % substations in 2009, and to 9 in 2010. achievement)

G. Ratings of Project Performance in ISRs

Actual Date ISR No. DO IP Disbursements Archived (USD millions) 1 06/13/2006 Satisfactory Moderately Satisfactory 0.00 2 11/20/2006 Satisfactory Moderately Satisfactory 0.00 3 11/08/2007 Satisfactory Moderately Satisfactory 0.06 4 03/31/2008 Satisfactory Moderately Satisfactory 0.47 5 03/20/2009 Satisfactory Moderately Satisfactory 5.32 6 11/07/2009 Satisfactory Moderately Satisfactory 6.10 7 06/30/2010 Satisfactory Moderately Satisfactory 8.09 8 05/19/2011 Satisfactory Satisfactory 13.35 9 02/17/2012 Satisfactory Satisfactory 15.37 10 06/26/2012 Satisfactory Satisfactory 18.07

H. Restructuring (if any)

iv

ISR Ratings at Amount Board Restructuring Disbursed at Restructuring Reason for Restructuring & Approved Restructuring Date(s) Key Changes Made PDO Change DO IP in USD millions (i) Extension of Closing date to December 30, 2011, (ii) reallocation of funds for further support to Component 1- 02/24/2010 S MS 6.82 substation and related activities; (iii) amendment of the project description to allow for more flexibility on the number of future substations. Extension of closking date to 12/29/2011 S S 15.20 June 30, 2012

I. Disbursement Profile

v

1. Project Context, Development Objectives and Design

Serbia is part of the South East Europe (SEE) group of countries, together with Albania, Bosnia & Herzegovina, Bulgaria, Croatia, Kosovo, Macedonia, Montenegro and Romania. The SEE countries acknowledge that the development of the energy sector is crucial to improve and sustain economic development in the region, and that efforts based on isolated national markets are neither desirable nor feasible as means to attempt closing energy sector investment gaps, demand growth and supply imbalances. Building upon their experience to cooperate in the power sector, in recognition of the potential gains from increased trade, and as part of a wider movement to strengthen regional cooperation, the Governments of the SEE countries and the European Commission signed in 2003 the “Athens Memorandum”, i.e. the Memorandum of Understanding on the Regional Energy Market in SEE and its Integration into the European Community Internal Energy Market, whereby they formally expressed their commitment to what is called the Energy Community of South East Europe (ECSEE). The key objectives of the ECSEE are: • Create a stable regulatory and market framework capable of attracting investment to the region in power systems and gas networks; • Establish integrated regional markets in SEE, closely linked to the European Union (EU) energy market and fully compliant with its rules; • Enhance the security of energy supply of SEE and the EU by providing incentives to connect the Balkans to Caspian and North African gas reserves; and • Improve the environmental situation in relation to energy in the region.

The Use of Adaptable Program Lending (APL) for ECSEE enables the World Bank to provide financial support to a regional program, yet financing is tailored to the needs of individual countries to help them meet their commitments to ECSEE. The SDR 13.9 million (US$ 21 million equivalent) IDA credit for Serbia was prepared and implemented within the context of the second phase of the APL.1

1.1 Context at Appraisal During the 1990s, a period characterized by arm conflicts, international sanctions and trade restrictions stemming from the break-up of the Socialist Republic of Yugoslavia, Serbia faced severely reduced output and foreign trade, high inflation, large fiscal deficits and large external obligations. Since the political changes in 2000, Serbia begun to implement reforms and made a remarkable progress in several areas, including a broad ranging market-oriented and regionally- focused energy sector restructuring and electricity tariff reforms. However, by the mid 2000s the power sector infrastructure remained old, inadequately maintained and requiring a major rehabilitation effort. Also, while sustained tariff adjustments had reduced the quasi-fiscal deficit and improved the sector’s financial performance, tariffs were still below the cost of supply. Successive years of economic growth brought a recovery in power demand and the urgent need of meeting future requirements. Major challenges faced by the power sector at the moment of appraisal were: • Implement a new legal and regulatory framework through the development of secondary legislation and the creation and institutional development of a regulatory agency;

1 ECSEE APL2-Serbia

1

• Restructure, corporatize and commercialize the industry by the creation of an independent Transmission System and Market Operator (TSMO), and functional separation of mining (lignite for power generation), generation and distribution; • Reform tariffs and improve the financial and operational efficiency of Elektro Privreda Sribje (EPS) and its successors to restore the creditworthiness of sector entities; • Rehabilitate the old and deteriorated assets of the network, and augment the network; • Upgrade and modernize transmission, distribution, dispatch and telecommunications systems to effectively participate in the regional electricity market; • Improve end-use efficiency and promote rational use of electricity; and • Encourage commercial development of renewable resources. Rationale for Bank assistance; The World Bank’s experience in supporting countries of the SEE in rehabilitating and restructuring their power sectors since the early 1990s, as well its active role in the development of the ECSEE, placed the Bank in a strong position to provide regional lending. The ECSEE APL2-Serbia, that finances the necessary infrastructure to improve market access to customers –through the rehabilitation and upgrading mentioned above– was aimed at complementing donors assistance in the creation and institutional development of a TSMO and the new Regulatory Agency (obligations Serbia had to fulfill under Athens Memorandum), and strengthening the transmission network to link Serbia to the regional electricity market. The project’s financing of necessary infrastructure complements other donors’ assistance in strengthening the power sector institutions, infrastructure and operating efficiency.2 The energy sector restructuring supported by the APL and its subcomponent APL2 relates to two of the three goals of the 2005 CAS for Serbia: creating smaller, more sustainable, more efficient public sector, and creating a larger, more dynamic, private sector.

1.2 Original Project Development Objectives (PDO) and Key Indicators (as approved) Within the overall ECSEE APL context, the project (ECSEE APL2-Serbia) was aimed at providing investment support for Serbia to improve electricity market access for consumers and suppliers through an increase in the quantity, quality, reliability, safety and efficiency of the bulk power transmission system. The ECSEE APL program is to be considered successful if the countries in the region achieve their commitments under the Athens process and are able to: (a) develop a functioning market including the agreed market liberalization targets; and (b) integrate it into the internal electricity market of the European Union. To accomplish this, the countries have to continue ongoing restructuring and reform measures, build institutions and improve their power systems including interconnections so that regional trade can increase. The key outcome indicator used to assess the APL2-Serbia, as approved at appraisal, was the following: • Satisfactory implementation of commercial agreements between the TSMO, distribution companies and the eligible customers.3

2 The EBRD, KfW, EIB and Government of Switzerland provided assistance in the rehabilitation and environmental improvement of mines (lignite for power generation) and generating stations. SIDA co-financed new financial management systems in EPS. EAR funded technical assistance for training of the transmission and system dispatch staff, as well as co-financed with KfW an energy efficiency program. 3 The umbrella ECSEE APL program’s outcome indicator is that electricity markets in SEE are liberalized according to the ECSEE Treaty and a regional electricity market is functioning. This would be measured by the freedom of an increasing number of electricity consumers to choose their electricity suppliers.

2

Intermediate results indicators were: • Satisfactory completion of substations and the associated transmission lines; and • One year after the substations are fully operational, in their local service area: (a) losses are reduced at by least 15%, (b) voltages are within their operating limits, and (c) energy interruptions are reduced by at least 40%. That is, the PDO as approved included one single DO that was associated to the sector reform and regional integration agenda, while project components (section 2.5) focused entirely on the strengthening of infrastructure and did not include any policy reform component.

1.3 Revised PDO (as approved by original approving authority) and Key Indicators, and reasons/justification The Project Development Objectives remained unchanged throughout the implementation of the project nor was there any re-allocation of resources. However, upon the recognition that the originally established PDOs lacked specificity and were considered overly ambitiously defined, the management (Sector Management and CMU) recommended updating the indicators and overall results framework. Subsequently, some target dates were specified4, but the indicators remained essentially unchanged.

1.4 Main Beneficiaries The PAD did not identify explicitly a primary target group as such. The project is aimed at benefiting a broad range of power sector players through its support to the sector’s restructuring and liberalization, providing access to an open and competitive electricity market to both consumers and suppliers. Also, the construction and rehabilitation of substations and associated transmission lines will benefit directly electricity users of the corresponding areas through an increase in the quantity, quality, reliability, safety and efficiency of the electricity service.

1.5 Original Components (as approved) Eligible ECSEE APL Project Components: Priority investments and technical assistance so that ECSEE Regional Members can effectively participate in the regional electricity market. The program proposed as a one billion US$ program in five phases (APL1 through APL5) for the original SEE countries plus Turkey and Kosovo. ECSEE APL-2 (Serbia) Project consisted of two components: Component 1: 110kV Substations and Related Activities Construction of five new 110kV substations in two phases:5 • Component 1-A: Two new 110kV substations through the financing of goods and consultancy services. • Component 1-B: In a second phase, three new 110kV substations plus additional related investments and/or services. Component 2: 110kV Interconnecting Transmission Lines and Related Activities

4 ISR #6 (Nov. 2009) incorporated target dates for the liberalization of the electricity market (a PDO indicator) as well as for the commissioning of substations (intermediate indicators). 5 A third phase was added during implementation as the number of substations was increased.

3

Construction of new 110kV interconnecting transmission lines for the substations selected under Component 1. The construction of these transmission lines will be carried also in two phases in coordination of the phases of Component 1. • Component 2-A: Financing of civil and installation works necessary for the construction of the two lines for the substations under Component 1-A, plus consultancy services. • Component 2-B: Financing of civil and installation works for the construction of the lines for the substations under Component 1-B, plus any additional related investments and/or services

1.6 Revised Components While the nature of the project components remained unchanged throughout its implementation and there was no re-allocation of resources, the components were modified in scale as the number of new 110kV substations was increased from five to ten –plus the rehabilitation of an eleventh substation– in three phases. Also, World Bank financing of Component 2 (110kV interconnecting transmission lines) was limited the civil and installation works of phase one only, as the responsible agency EMS opted to finance fully Phases II and III of Component 2.

1.7 Other significant changes The project’s closing date was adjusted twice. The original closing date was February 28, 2010. It was initially extended to December 31, 2011 and in December 29, 2011 it was extended to June 30, 2012. Both extensions were motivated mainly by delays associated to procurement problems, as there was need of re-bidding important contracts due to the forced withdrawal of a winning bidder (first extension) and the failure of a supplier to deliver transformers equipment (second extension).

2. Key Factors Affecting Implementation and Outcomes

2.1 Project Preparation, Design and Quality at Entry The project was prepared within the context of the ECSEE regional program using an adaptable program lending (APL) instrument. APLs in support of the regional program were provided in a horizontal manner –to support each of the member countries– and vertically, i.e. each member country could receive support from more than one APL installment over the program period. The APL instrument was chosen, as opposed to a free standing investment project, because it enables the Bank to provide support in a flexible manner, when individual countries and/or projects were ready to receive Bank support. 6 The approved size of the regional APL lending facility was US$1,000 million, of which US$ 21 million equivalent was allocated to Serbia under APL2. Project design was supported by a strategy for Bank assistance for regional energy trade that highlighted that achieving a well-functioning power market would require significant investments in power generation, transmission and distribution. Also, by project effectiveness it was confirmed that Serbia qualified for Bank support under the regional APL program, as it had met ECSEE’s basic entry conditions as defined in the Athens Memorandum: that an electricity sector regulator and a transmission system operator have been established and are operational.

6 Two sets of triggers apply under the APL. Policy triggers determine the eligibility of an individual country and project triggers determine when an individual investment is eligible to receive Bank funds.

4

The components of the Serbia APL2 were selected in a manner consistent with the regional program and the key objectives of the ECSEE, and in close consultation with other donors. Hence, the choice of supporting the construction of a set of new 110kV substations and associated 110kV transmission lines –a particularly weak segment of Serbia’s power system– was an adequate complement to other donors assistance that focused on the creation and institutional development of the TSMO and the new Regulatory Agency, and strengthening the transmission network to link Serbia to the regional electricity market. EPS performed a series of development and planning studies to determine the priority investments necessary to expand its power networks, improve their performance and meet the growing demand of electricity. Based on technical and economic analyses, EPS studies recommended a set of investments that were included in its Work and Development Plan for 2005-2010. Among others, it recommended the construction of new 110kV transformer substations in Arilje, Vranje 2, Jagodina 3, Macvanska Mitrovica, Nis 8 and Mosna substations and their associated interconnecting transmission lines. Two of these substations, Arilje and Macvanska Mitrovica, were selected for the project’s Phase I. Decisions on additional investments to be financed through the Credit in subsequent phases –which, in fact, included the other substations mentioned above– were based on an agreed criteria that considered the following: (a) confirmation that the proposed investments were technically and economically viable and part of EPS and EMS medium term investment plans; and (b) presentation of satisfactory Environmental Management and Land Acquisition Plans, if safeguard policies are triggered by the proposed investments. The project was designed taking into account lessons learned in Europe and other regions in power sector reform programs and the development of power markets. Key lessons incorporated into the project design were: (a) the need to establish an independent TSMO to operate and administer electricity markets; (b) confirmation of government’s political commitment and adequate financial support for a successful reform program; and (c) the convenience of proven and streamlined approaches emphasizing turnkey contracting. Project risks were assessed at appraisal and incorporated into its design. However, a shortcoming in the project’s design was its weak link and lack of balance between its sector policy objectives and its infrastructure components. Whereas the proposal to build a set of new 110 kV substations and associated transmission lines had the potential to contribute significantly towards the provision of a better electricity service and, hence, provide economic benefits inherent to a better service and, also, facilitate the access of suppliers and consumers to an electricity market, the reform objective of the project was not supported by a policy component. The project did not include any technical assistance to address sector reform challenges nor any policy agreements, to tackle these issues once the project had been declared effective. This implied that the Bank’s leverage in addressing reform issues was strongly weakened after the project was declared effective. This shortcoming was aggravated by a relatively weak design of PDO indicators that lacked specificity and did not establish a link between the project’s reform and infrastructure objectives (see section 2.3).

2.2 Implementation Component 1 of the Serbia APL2 was implemented by Elektro Privreda Srbije (EPS) and component 2 by Elektro Mreza Sribje (EMS), the transmission system operators established upon the unbundling of the power sector. In both cases, general management and support functions were assigned to their head office in Belgrade. Project Implementation Units (PIU) were designated for the implementation of the project. The main function of the PIUs was to coordinate with other corporate departments the effective implementation of procurement, contracting,

5

contract administration and disbursements, financial management and accounting reporting. PIUs were adequately staffed. Overall, the project was implemented in a satisfactory manner in most of its infrastructure components. Factors contributing to successful implementation included: • The strength of the two PIUs, supported by the different departments of their respective corporations; • The engagement of an Implementation Supervision Consultant (IDA financed) during Phase I, with the following objectives: (a) providing monitoring and support to EPS and EMS; (b) ensuring that the project’s activities are well coordinated between EPS and EMS; and (c) ensuring that the equipment and civil works are in compliance with the project design and schedule. • The use of proven designs and streamlined contracting approaches; • Continuous supervision of the World Bank, including the support of several team members in the field (particularly in safeguards and fiduciary issues); and • A flexible procurement process that incorporated the lessons learned throughout the implementation period and was able to react to the changing conditions of the suppliers market. However, the project had considerable implementation delays that motivated two extensions of the closing date and a 50% extension in the project’s implementation period (from 4 years and 8 months to 7 years). Main causes for delays were: • A slow start caused by the involvement of newly created institutions (EMS) and a weak coordination between the Ministry of Energy (ME) and the implementing agencies. Consequently, the Credit was declared effective seven months after Board approval; • Procurement problems, mostly out of the control of any of the players, required the need to re-bid two important contracts in Phases II and III of the project; and • An impasse in the environmental licensing for the Mosna substation, caused by gaps in the coordination of EMS and other public entities upon changes in forestry legislation. This problem has yet to be solved. On the reform area, considerable progress has been achieved in the unbundling of the sector structure, establishing a separate transmission company (EMS) as well as an independent sector regulator (Energy Agency of the Republic of Serbia-AERS), both conditions for project effectiveness. Subsequent legislation has opened the market to all customers, except residential, and regulated electricity tariffs have increased gradually (from an average tariff of 4.3 UScents/Kwh at appraisal to 7.6 UScents/Kwh) with view to move towards full cost recovery levels. However, the benefits of a competitive market have yet be realized. In spite of having the opportunity to access the competitive electricity market large consumers have opted to remain within the regulated component of the sector that still offers lower (below cost) prices.

2.3 Monitoring and Evaluation (M&E) Design, Implementation and Utilization A shortcoming of the project was its relatively weak design of PDO, and intermediate results indicators, that did not establish a clear link between the project’s reform and infrastructure objectives, nor acknowledged the development contribution of an improved electricity service.7

7 The Results Framework includes one single outcome indicator for the PDO: the satisfactory implementation of commercial agreements between the TSMO, distribution companies and the eligible customers. That is, a policy reform indicator, without acknowledging the development contribution that an improved electricity service can provide in terms of enhanced productivity and improved quality of life.

6

Also, the indicators lacked specificity and were defined indirectly (e.g. referred to the agreements of a treaty without providing any explicit guidance) or proposed for a period after project completion, thus undermining their practical value during implementation. Monitoring of the Serbia APL2 project was responsibility of the EPS and EMS PIUs. EPS provided on a quarterly basis consolidated (for both EPS and EMS components) reports on the implementation of the project in a format agreed with the Bank. These reports focused mostly on the status of works for each substation, including the identification of specific problems, updated schedules when required and commercial completion estimates. During the last phase EPS collected data on the initial impact of the project and produced physical indicators of such progress, including improvements in energy losses, voltage performance, reduction in energy interruptions and additional load supplied. EPS has proven to have the capacity to continue the evaluation of the project’s impact beyond the implementation period. The PIU’s did not monitor progress in the reform agenda nor was always informed of such progress. This was done at the ME level within the context of ECSEE’s coordination mechanisms.

2.4 Safeguard and Fiduciary Compliance

Safeguards Environment. The project triggered the Environmental Assessment safeguard. In accordance with OP 4.01, the project was assigned a “Category B” and Environmental Management Plans (EMPs) were prepared in advance for each of the substations and the associated transmission lines of Phase I. The eligibility criteria for the investments of Phases II and III included the submission of an EMP and a Land Acquisition Plan (LAP) satisfactory to the Bank. Appropriate design measures were taken to mitigate the environmental impact of equipment (e.g. no PCBs, ensuring that noise and electro magnetic field levels are below Serbian or WHO standards). Overall, all substations and transmission lines were implemented without facing any significant problems, with the exception of the interconnecting transmission line for the Mosna substation (Phase II), which is yet outstanding. The line, originally designed to cross a national park, was moved outside the park to a route that crosses an adjacent forest. However, a new Forestry Law that established the payment of high compensation fees (ten times the value of the affected timber) to obtain the construction license has become an obstacle for its completion. This problem remained unresolved at the moment of the ICR (October 2012) thus constituting a main and relatively costly delay in the completion of the project.

Social. The social aspects of the project were taken into account during the design phase. The project triggered the Involuntary Resettlement (OP/BP 4.12) safeguard because land acquisition was required for some substations and the foundations of transmission towers. EPS and EMS prepared LAPs that were reviewed and approved by the Bank. While the total land required was minimal and the transmission lines were placed usually at the edge of cultivated areas, the confirmation of right-of-ways caused delays in the commissioning of some substations. These delays were associated usually to problems with individual landowners. An outstanding case (by ICR mission, Oct. 2012) was the interconnecting transmission line for the Indjija 2 substation (Phase III) that, at the moment of the ICR mission, had all towers erected but the laying of cables was blocked by the complaint of a single landowner.

Fiduciary

7

Procurement. Procurement activities were carried out in accordance with the World Bank’s “Guidelines: Procurement under IBRD Loans and IDA Credits” of May 2004. In spite of the overall weakness of the country in conducting public procurement 8, an assessment of EPS’s capacity in implementing procurement actions found that the implementing agency had adequate staff, in skills and quantity, to conduct the required procurement. Nevertheless, training measures were agreed with the Bank, as well as the engagement of an experienced supervision consulting firm to support EPS and the newly created EMS, during Phase I of the project. A Procurement Plan was developed by the Borrower at appraisal and subsequently updated as the project entered into Phases II and III. The plan contemplated the following procurement methods: (a) International Competitive Bidding (ICB) for the supply of goods and the installation of equipment; (b) National Competitive Bidding for works; and (c) Fixed Budget Selection for the supervision consultant. Lessons learned during the initial phases were incorporated into the Procurement Plan of Phase III that included further breakdown in the bidding packages in order to achieve more competition9. While the procurement performance of the implementing agencies can be regarded as satisfactory, two unforeseen problems associated to this activity became important factors of delay. These were: • In July 2009, the winning bidder for the provision of equipment for the Phase II four substations (Mosna, Vranje 2, Jagodina 3 and Nis 8) withdrew its bids following a settlement with the World Bank related to past misconduct by the firm in other international activities. Consequently, EPS approached the second lowest bidder for Lot 2 (“other substation equipment”) and proceeded to re-bid Lot 1 (transformers) where Siemens had been the only bidder. While the ICB re-bidding of transformers provided an unexpected benefit –lower prices– it meant a delay of more than half a year that motivated the first extension of the project’s closing date; and • The failure of the supplier to deliver transformer equipment for Phase III also caused considerable delays. In this case EPS proceeded to apply the remedies contained in the contract and started a new ICB procurement process. In aggregate, it is estimated that these two unforeseen events caused a delay of more than one year. Financial management. FM arrangements were implemented in an adequate manner and maintained throughout the life of the project. EPS and EMS engaged specialists who had the appropriate skills to manage the project’s financial management and disbursement issues. The quarterly project financial reports were submitted in a timely manner and in compliance with World Bank’s accounting policies and internal control procedures. The audits of the entities EPS and EMS and project financial statements were submitted on a regular basis, albeit with some minor delays during the period 2009-2010. Project audits did not highlight any important irregularities. The auditor (issued qualified opinions on entity financial statements for both EPS and EMS. While these qualifications involved a set of issues vis-à-vis International Standards of Auditing (ISA), such as the valuation of fixed assets and inventories

8 A Country Procurement Assessment Report for the Federal Republic of Yugoslavia prepared by the Bank in June 2002 concluded that the environment for conducting public procurement in Yugoslavia was highly risky. At the moment of project appraisal a fiduciary update of that report was in progress. 9 During phase III the two lots ICB approach for the substations was replaced by three lots, subdividing Lot 2: Equipment, into two separate lots; Lot 2: Circuit Brakers, Switgears and Auxiliary Supplies, and Lot 3: Rely Protection Equipment. This breakdown resulted in greater competition and lower prices.

8

(e.g. obsolete inventories), the number of qualifications and weaknesses identified by the auditor decreased with time, an evidence that both entities gradually built capacity for the proper implementation of ISA over the years. Overall, the view of the auditor was that the deficiencies encountered in the entities’ accounting treatments did not represent significant inaccuracies. The audits on the project financial statements were satisfactory. While in some exceptional cases audits were qualified (due to lack of compliance with ISA), no weaknesses were found on internal controls. Counterpart financing from EPS and EMS was adequate in quantities and timing throughout the whole the project life. 2.5 Post-completion Operation/Next Phase Once in operation, the project is not expected to require any particular measures other than standard maintenance. The new substations and transmission assets belong to EPS and EMS, respectively, companies responsible for the operation and maintenance of the facilities that have the technical skills and financial capability to undertake these activities in a satisfactory manner. However, at the moment of the ICR mission (October 2012) some interconnecting transmission lines of phases II and III had yet to be completed.10 While these works and installations are not funded by IDA, they are an essential component of the project since, while they are not completed, the new substations will not able to operate or would operate in a technically suboptimal manner. EMS expects these transmission lines to be completed during the next calendar year (2013).

3. Assessment of Outcomes

3.1 Relevance of Objectives, Design and Implementation The project’s objectives focus on the need to improve electricity market access in Serbia through the provision of a better service –in terms of quality, quantity, reliability and safety– within a SEE regional context characterized by the countries’ commitment to liberalize and integrate their power markets. These are medium to long term objectives that require a sustained effort from all parts. Accordingly, the project is addressing concerns which remain valid in 2012, including the need to overcome important infrastructure bottlenecks, and hence, its PDO are still relevant at regional and country levels. In the particular case of Serbia, a World Bank power sector stock-taking mission concluded in 2010 that important power sector recovery issues remained unresolved and further policy reform and institutional strengthening was needed to create an attractive environment for public and private investment. The mission proposed, among other actions, to (a) improve the financial and commercial viability of the sector; and (b) deepen regional cooperation; two measures that are supported by the Serbia APL2 thus confirming the relevance of the projects objectives and components.

3.2 Achievement of Project Development Objectives Within the regional ECSEE APL program, the Development Objective of the Serbia project is to improve the electricity market access for consumers and suppliers through a substantial improvement in the electricity service and strengthen capacity of the institutions to participate n

10 As of October 2012, the transmission line interconnecting the Mosna substation had not been built; also, the laying of cables connecting the substation Indjija had not been completed.

9

the regional electricity market. The project has, therefore, two dimensions: (a) a reform agenda for regional integration and the liberalization of power markets; and (b) a physical component aimed at overcoming infrastructure bottlenecks that impeded a satisfactory service in terms of quantity, quality, reliability and safety. The Results Framework of the PAD established one single Outcome Indicator: the satisfactory implementation of commercial agreements between the transmission operator, distribution companies and the eligible customers. While considerable progress was achieved in the reform agenda through the unbundling of the sector structure, establishing an independent regulator, tariffs reform and establishing open access legislation (see section 2.2), the outcome has not been fully achieved because eligible consumers have not chosen to join the energy market as regulated tariffs still remain low. Accordingly, there are agreements between the transmission operator with the distributor, but not with eligible (large) customers. However, on the infrastructure side, the project has surpassed its original targets, which contemplated the construction of five 110kV substations in two phases. By the time of the ICR mission (Oct. 2012), five substations had been commissioned already and four more were expected to be completed by the first quarter of 2013. Quality of supply data being collected by EPS indicate important achievements in the reduction in energy losses and service interruptions, as well as an improvement in voltage levels. 11 Furthermore, there is evidence that the improvement in the electricity service has contributed towards the growth of important productive activities, such as local industrial parks and the production of raspberries for export.

3.3 Efficiency An ex-post economic evaluation of the project, using actual data on costs and early benefits –for the substations commissioned in Phase I and some of Phase II– as well as updated and better supported information for future benefits, yielded the following results (details in Annex 3): an economic internal rate of return of 42.6 % and a net present value (NPV, at 12% discount rate) of US$63.1 million. Total investment costs amounted US$ 34.9 million for ten substations and associated transmission lines. Three key benefits were considered: (a) reduction in energy losses; (b) reduction in energy interruptions; and (c) the supply of new loads. The results obtained compare favorably with the estimates at appraisal, which gave a rate of return of 29% and NPV of US$33 million. The main reason explaining this improvement is the fact that the project surpassed its physical objectives as ten new substations were completed instead of the five originally planned. Other factors are an increase in 50% in the average electricity tariff –which is used as a proxy for economic benefits per unit of energy consumed– and an increase in the (avoided) cost of alternative power supply associated to the prices of diesel. Using the appraisal assumptions for average tariffs and costs of alternative generation the ERR falls to 37% and the NPV to US$ 48.5 million. Overall, the results confirm the sound and robust economics of the project’s infrastructure component.

11 Early results of four of the five completed substations indicate that the quality of supply targets are being surpassed. In average, energy losses have been reduced by 64%, energy interruptions by 87% and voltage drops by 62%.

10

3.4 Justification of Overall Outcome Rating Rating: Moderately Satisfactory Taking into account the confirmed relevance of the project’s objectives, the progress made in the reform agenda, the remarkable success of the project’s physical component in surpassing its targets and the confirmation of a positive and robust economic impact, the overall outcome rating is considered Moderately Satisfactory. The rating is not Satisfactory because there are some shortcomings on the reform agenda that could have an impact on the degree to which the potential benefits of an energy market are fully achieved. These shortcomings relate to the viability of raising further the tariffs of electricity and weaknesses in the design of the project in addressing sector reform issues after it was declared effective. Nevertheless, a stable institutional environment characterized by the Government’s commitment to reform and regional integration within the ECSEE is likely to mitigate the impact of this shortcoming.

3.5 Overarching Themes, Other Outcomes and Impacts (a) Poverty Impacts, Gender Aspects, and Social Development The improvement in the quantity, quality and reliability of electricity services in rural areas offers the opportunity of developing productive activities that would not have been possible without the project. Several of the 110kV substations supported by the project offer such advantage and, thus, the potential of a major contribution towards economic growth in the respective regions. Two cases of particular interest in this respect are the substations of Indjija 2 and Arilje. • The 110/20kV substation of Indjija provides the power infrastructure (25MW) required for a new industrial park in the vicinities of a small but industrious town; • The 110/35/10 kV substation of Arilje has improved considerably the quality of electricity service in the said region, making possible (in only two years) the duplication of the refrigeration capacity needed for the production of raspberry. Consequently, the region of Arilje is producing about one fourth of the national raspberry production. 12

(b) Institutional Change/Strengthening It is recognized by all parties that the adoption of international standards in procurement and financial management, as well as the support of an experienced supervision engineer during Phase I of the project, have contributed considerably towards strengthening the capacity of the implementing agencies EPS and EMS in dealing with investment projects. (c) Other Unintended Outcomes and Impacts (positive or negative) None were detected

3.6 Summary of Findings of Beneficiary Survey and/or Stakeholder Workshops Not Applicable

12 One third of the world’s raspberries are grown in Serbia. About 98% of the Serbian production is exported at a value of €250 million per year.

11

4. Assessment of Risk to Development Outcome

Rating: Moderate. Project risks were assessed adequately at appraisal. These included: (a) the controversies that may arise upon the development of a regional energy market –such as a different degree of commitment of different countries, an uneven power trade; (b) the timely development of new generation capacity, implementation of environmental legislation and the impact of limited competition; (c) project investment risks typical of an infrastructure project in the power sector, i.e. possible delays, cost overruns, satisfactory operation; and (d) donor coordination issues. The project will operate within a stable institutional environment characterized by the Government’s commitment to the reform and recovery of the power sector, and the commitment towards regional integration and strong coordination of all countries of the ECSEE. In fact, a well functioning ECSEE is regarded as the best mitigation measure for regional and country/donor coordination risks. The risks of a faulty operation of power facilities supported by the project is considered minimal, given the use of proven designs and the technical and institutional capacity of the utilities (EPS and EMS) in charge. There are, however, risks associated to the benefits of the sector reform in Serbia. While the Government was successful in unbundling the sector, establishing a separate regulatory agency and increasing considerably electricity tariffs, the degree to which the benefits of the energy market will be achieved will rely on the political viability of maintaining regulated tariffs at a level that does not undermine the attractiveness of the market.

5. Assessment of Bank and Borrower Performance 5.1 Bank Performance (a) Bank Performance in Ensuring Quality at Entry Rating: Moderately Satisfactory The Bank selected a project consistent with the region’s and the country’s needs. The flexibility offered by an APL approach was consistent with the need to follow an incremental process using proven technologies. Useful sector work undertaken during an early stage (by the Bank and Borrower) led to the selection of much needed power infrastructure that addressed bottlenecks in areas were the project would provide significant benefits, thus ensuring its economic viability. Evaluations of the Borrower’s capacity were done objectively and the implementation measures were designed accordingly. Applicable safeguards were indentified correctly. Linking the initial steps of the reform (sector unbundling and establishing a separate regulator) to loan effectiveness conditions helped overcoming a main policy challenge and opened doors to the reform process. The disconnect between the project’s reform and physical components after effectiveness appears to have slowed down –or reduced pressure on– the pace of reform and, consequently, delayed the benefits of the energy market. The question is whether some technical assistant supporting specific steps of the sector reform would have helped. Furthermore, the Key Performance Indicators (KPI) were either overambitious, lack specificity or were proposed for a time frame that exceeded the implementation period, thus hindering their effectiveness in linking the two project agendas and supporting the monitoring progress (section 2.3).

(b) Quality of Supervision Rating: Moderately Satisfactory

12

The Bank followed closely the execution of the project and provided guidance at critical moments. Adequate resources were allocated –in quantity and quality– throughout the implementation period, including ten supervision missions and the continued provision of local support, particularly on fiduciary issues. Most of the practical implementation problems encountered during execution (e.g. delayed effectiveness and some procurement problems) were beyond its range of action, but the Bank team provided opportune advice. While delayed with respect to the original schedule, the MTR was undertaken a bit early and didn’t have much impact. The monitoring of KPI was not done always as rigorously as needed nor there was an effective attempt to improve them. In fact, restructuring the PDOs through the incorporation of the development benefits of the infrastructure component (e.g. including an indicator aimed at measuring the economic impact of a better electricity service) and revising the indicators for greater specificity could have improved greatly the monitoring and evaluation of results.

(c) Justification of Rating for Overall Bank Performance Rating: Moderately Satisfactory. This rating combines the ratings for project preparation and supervision.

5.2 Borrower Performance (a) Government Performance Rating: Moderately Satisfactory The Government supported the project throughout its entire execution. It revealed a strong commitment towards the reform of the power sector and the regional ECSEE objectives, and put in place the new energy regulatory agency and unbundled the sector structure. Counterpart funds were always made available in appropriate quantities and a timely fashion. Problems of coordination between agencies and the ME delayed the effectiveness of the project. The impasse of the Mosna substation –that has yet to be solved– exposes an important problem of coordination between ministries and sector agencies, the urgent need to streamline Construction Permits 13 , and an underlying conflict between the objectives of economic growth and environmental conservation that has yet to be addressed effectively. The Government’s inability to adjust electricity tariffs at a faster pace could undermine the potential benefits of the energy market. (b) Implementing Agency or Agencies Performance Rating: Satisfactory EPS and EMS put in place strong PIUs that received effective support from other corporate departments. The selection of additional investments (for Phases II and III) was based on sound planning. Lessons learned during the initial stages were incorporated into the design of procurement packages thus achieving greater efficiency. Most of the practical implementation problems encountered during execution (e.g. procurement problems during Phases II and III) were unexpected and beyond the control of the executing agencies. However, their reaction upon these problems was diligent and opportune.

13 Reportedly, the Construction Permits process –managed by the Ministry of the Environment, Mining and Spatial Planning– took between eight to twelve months; an excessively long period that contributed towards delaying many activities.

13

(c) Justification of Rating for Overall Borrower Performance Rating: Moderately Satisfactory Combines the ratings for Government and Implementing Agency.

6. Lessons Learned An APL instrument in conjunction with a sound planning/analytical effort are an appropriate approach to ensure the success of infrastructure projects characterized by the incremental implementation of proven technologies. The flexibility provided by the APL instrument, plus the sound planning of EPS were instrumental in incorporating the experience of initial stages into the project, ensuring a more effective implementation and enhancing the project’s economic benefits. The flexible APL approach facilitated also carrying on a procurement plan that adapted its design to market conditions and consequently achieved greater competition. Projects including both policy reform and infrastructure (physical) components pose additional challenges that require synchronized design and implementation. Complementary and policy and physical components require a fine-tuning so as to guarantee that they are well balanced and support each other. Failure to do so may undermine the fulfillment of both objectives. Two issues to consider in this respect are: • Providing a carefully designed technical assistance for specific parts of the reform agenda could be instrumental in ensuring an effective progress in this area and maximizing the projects benefits. In the particular case of the Serbia project, an explicit technical assistance aimed at supporting the Government in the design and implementation of a tariff policy could have proven highly beneficial. • The coordination of both policy reform and physical components could benefit from a more specific definition of performance indicators that should be fully consistent with the projects PDO and each of the project’s its components. The active role of the Government is paramount in addressing the conflict between economic growth and environmental protection objectives. In an economy challenged by high demand growth, the potential conflict between growth and environmental protection is often unavoidable. The Mosna substation experience illustrates the need for a more active role of the Government in coordinating the objectives, policies and programs of different ministries and public entities in order to minimize contradictions and resolve conflicts. Failure to do so may render executing agencies incapable in addressing such problems and could undermine the achievement of project objectives. The challenges faced by Executing Agencies during a reform process justify an additional support tailored to their specific needs. The support provided to EPS and EMS (a newly created entity) by an experienced supervision engineer during the first 18 months of implementation, as well as by the Bank’s local staff on fiduciary and safeguard issues, proved to be of great advantage and, therefore, a practice to be replicated in similar cases. The evaluation of long-term results requires a M&E effort beyond project closure and broad in scope. In projects aimed at improving the quality of the electricity service, provisions should be taken to ensure that the monitoring of results continues for a period of at least five years after project completion. Such information would be useful for a better evaluation of future projects of similar nature. Furthermore, in the case of projects –such as the APL2 Serbia– that are likely to provide significant socio-economic benefits to local economies, M&E systems should include a baseline and KPIs that are broad in scope and duration.

14

7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners (a) Borrower/implementing agencies

15

Annex 1. Project Costs and Financing

(a) Project Cost by Component (in USD Million equivalent)

Actual/Latest Appraisal Estimate Percentage of Estimate (USD millions) Appraisal (USD millions) Component 1 • 110kV Substations 19.00 25.53 134.4% • Supervision Consultants 0.25 0.25 100.0% • Unallocated 7.00 0.00 0.0 • Total Component Costs 26.25 25.78 88.2% Component 2 112.66 129.98 115% • 110kV Interconnecting 4.00 2.80 70.0% Transmission lines • Unallocated 0.25 0.00 0.00 • Total Component costs 4.25 2.80 65.9% Total Financing Required 30.75 28.58 92.9%

(b) Financing Actual/Latest Appraisal Estimate Percentage of Source of Funds Estimate (USD millions) Appraisal (USD millions) Borrowing Agency 9.75 8.02 82.3% • EPS 8.00 7.55 94.4% • EMS 1.75 0.47 26.9% International Development 21.00 20.56 97.9% Association (IDA) Total 30.75 28.58 92.9%

16

Annex 2. Outputs by Component

1. Component 1: 110kV Substations and Related Activities; Ten substations (as opposed to the five originally planned) have been completed or are expected to be completed n three phases by the end of 2012. Consultancy services for a supervision engineer were successfully delivered.

2. Component 2: 110kV Interconnecting Transmission Lines and Related Activities; All transmission lines have been completed except the line connecting the Mosna substation.

Performance Indicators Outcome Baseline Current (Oct. 2012) End Target Indicator Electricity market 0% of The energy law approved ECSEE Treaty – liberalization which consumers in July 2011 constitutes a market access for allows consumers to major step towards full non-residential choose their market opening: all customers by January electricity supplier customers, except 2008; also, residential residential, will become customers by January eligible no later than 2015 (end target as December 2012. presented in ISRs. Residential and small The Treaty’s consumers will be entitled agreements go to be supplied by public beyond this target).14 suppliers by December 2014. Comments The electricity market is formally open to all large consumers; however, these have not joined the market due to a significant price difference between the regulated price and the average market price. Under the amended Energy law, the Regulatory Agency (AERS) will assume tariffs setting responsibilities. This action is expected to facilitate conditions to

14 The PAD established that the indicators will be those in the final version of the ECSEE Treaty. Through the ECSEE Treaty (signed in October 2005), contracting parties committed to implementing European Community Directive 2003/54/EC by the above mentioned dates. The said directive enforces minimum requirements for the establishment of competitive electricity markets, including unbundling of network operation, tasks for transmission and distribution operators, third-party access to networks, eligibility and market opening, regulator powers, tendering of new capacity, monitoring of supply, etc. That is, the agreements of the Treaty go beyond the market access targets referred above, including tariffs that should allow investments to be viable.

17

Outcome Baseline Current (Oct. 2012) End Target Indicator achieve full market liberalization. Satisfactory No agreements EMS (transmission implementation of in place. company) and AERS commercial were established and agreements between strengthened during the EMS, distribution period of project companies and the implementation. eligible customers. Subsequently, agreements between EPS (transmission) and EMS (distribution) are in place; however, there are no agreements with eligible customers since these have decided not to join the energy market. Intermediate Results Indicators Quality of supply No baseline To be assessed one year One year after the improvement values were after completion of all substations are fully defined at substations. commissioned, in project design. their local service area: (a) losses are reduced at by least 15%; (b) voltages are within their operating limits; and (c) energy interruptions are reduced by at least 40%. Comments EPS started to collect Impact of the project quality of supply (quality of supply) to indicators of existing be monitored substations in mid 2011. continuously until These indicators include one year after the voltage drop, energy completion of the last losses, hours of substation. i.e. mid to interruption. Early results late 2014. of four completed substations indicate that the quality of supply targets are being surpassed. In average, energy losses have been reduced by 64%, energy interruptions by 87% and voltage drops by 62%. Satisfactory Nil Five substations have All five substations completion of been fully completed and (of phases 1 and 2) to substations and are in commercial be completed by associated operation. Four project closing date. transmission lines. additional are expected to

18

Outcome Baseline Current (Oct. 2012) End Target Indicator be completed by the first quarter of 2013. The Mosna substation has yet to overcome a license obstacle related to the transmission line right of way. Comments The project has surpassed its intermediate target of five 110kV substations.

19

Annex 3. Economic and Financial Analysis (a) Economic Analysis The economic internal rate of return for the project is 42.6 percent and the net present value (NPV) for the project is estimated to be US$ 63.1 million, based on a 12 percent discount rate which, as at appraisal, is considered to be the economic opportunity cost of capital in the Republic of Serbia. The analysis includes the investment costs of US$ 34.9 million for ten new substations (plus one reserve installation) and associated transmission lines. Taxes and duties are excluded from the analysis. The analysis compares with- and without-project cases. The with-project case considers actual investment costs for the period 2006-2011 and estimates for 2012-2013, and an economic life of 20 years until 2031. The figures presented are constant values for 2006 US$. The results obtained compare favorably with the estimates at appraisal, which gave a rate of return of 29% and NPV of US$33 million. The main reason explaining this improvement is the fact that the project surpassed its physical objectives as ten new substations were completed instead of the five originally planned. Other factors are an increase in 50% in the average electricity tariff –which is used as a proxy for economic benefits per energy unit– and an increase in the (avoided) cost of alternative power supply associated to the prices of diesel. Using the appraisal assumptions for average tariffs and costs of alternative generation the ERR falls to 37.0% and the NPV to US$ 48.5 million. The analysis takes into account the following: • The analysis uses performance data provided by EPS for with and without project scenarios, including actual improvements for some of the substations already completed and forecasts for those to be completed. • Investment figures include the costs of substations and interconnecting lines costs. Figures exclude VAT and adjusted for inflation (base year is 2006). • Annual average exchange rates are used to calculate current US$ values which are then adjusted for inflation (see above). • The estimates are based on constant prices. The analysis also uses a constant tariff of US$ 68.13/MWh assuming no real growth in the tariff. The US$ equivalent tariff is based on the average tariff of 5574 CSD/MWh resulting from total electricity sales by EPS of 28438 GWh in 2011 and EPS’ total income from the sale of electricity of 159,461 million CSD in 2011. • The operation and Maintenance costs are assumed to be 2.0 percent of the investment costs (provided by EPS).

1. Reduction in Energy Losses. A reduction in energy losses is the first estimated benefit of the project. The savings from this reduction is valued are the average Serbian electricity tariff as additional sales of electricity to consumers. In 2011, the average Serbian electricity tariff is estimated to be US$ 68.13/MWh. The savings estimate amounts to about US$ 1.2 million per year, or about US$ 23.6 million over the twenty year period. This is more than double the savings estimated at appraisal, mainly due to the increased number of substations constructed and/or rehabilitated by the project. 2. Reduction in Energy Interruptions. The reduction in energy interruptions caused by equipment failure and forced outages lead to the second benefit in this analysis. This reduction is valued at the cost of unserved energy, which is quantified with 533 US$/MWh, according to the

20

assumptions at appraisal. The reduction in energy interruptions due to the project is estimated to result in savings of about US$ 2.4 million per year, or about US$ 47.6 million over the twenty year period. This value exceeds the appraisal estimate by around 75 percent. 3. Supply of New Load. The installation of new substations leads to an increase in the transformers capacity, enabling the distribution company to serve additional loads. It is assumed that the substations will reach its full capacity in six years (by 2016). Based on EPS’s actual measures and assumptions, it is estimated that an additional load of about 62.5 MW will be served due to the project’s investments. Assuming a load factor of 60 percent, the eleven ten substations will serve an additional of 328,600 MWh of electricity per year by 2016. This surpasses the appraisal estimate by around 80 percent. The third benefit in this analysis results from the estimated savings to the consumers due to the avoided cost of alternative electricity supply. The estimated savings to consumers are valued at the cost of alternative power supply less the average electricity tariff of US$ 68.13/MWh. According to the PAD, the average capital costs and O&M of the alternative supply by the use of diesel generators are estimated to value 128.5 US$/MWh. The underlying assumptions are a capital cost of US$ 533/kW for diesel generators amortized over 10 years and a diesel fuel cost of US$ 12/GJ. The annual savings are estimated to reach US$ 19.8 million by 2016, resulting in a total of about US$ 386 million over the twenty year period. This is about 2.5 times larger than the appraisal estimate. (b) Financial Analysis Unbundling of EPS By decision of the Government of the Republic of Serbia, the activities of the former vertically integrated public enterprise EPS (Elektorpriveda Srbije) were unbundled on July 1 2005. As a result, the newly formed independent public enterprise EMS (Elektromreža Srbije) operates the electric energy transmission and transmission system control. Income Statements and Balance Sheets are presented below for the two unbundled companies. While transmission assets were unbundled, the core of the power sector has remained in EPS hands. Overall, at appraisal the financial situation of the power was challenged by the need to increase considerably average electricity tariffs, the high operating costs of a large component of lignite-fired power plants, an oversized staff and the burden of a pre-war debt. During the implementation of the project the financial situation of EPS and EMS was characterized by a rapid growth of the market and a gradual recovery of tariffs. The healthier financial situation of EMS indicates that transmission tariffs are closer to a full cost level than end-user tariffs, which in spite a considerable increase over the last six years still remain below cost recovery levels thus placing stress on EPS’s finances.

21

Income Statements EPS: Consolidated 2005 2006 2007 2008 2009 2010 2011 (non- Income Statement restated) million RSD million RSD million RSD million RSD million RSD million RSD million RSD Operating Income 91,254 104,844 120,657 146,578 154,186 172,432 190,325 Revenue (sales) 84,027 98,196 112,485 135,343 146,191 158,625 178,274 Own-work capitalized 2,899 2,191 2,665 4,309 4,861 6,466 7,516 Increase in the inventories 469 255 907 1,901 -1,739 850 -1,236 of work in progress, finished goods Other operating income 3,859 4,202 4,601 5,025 4,873 6,491 5,772

Operating costs & expenses -79,649 -95,094 -137,185 -155,828 -143,610 -157,800 -179,098 Cost of goods sold -217 -72 -21 -5 -3 -4 -2 Cost of materials, energy -17,794 -22,365 -28,878 -35,924 -31,467 -40,923 -46,838 and fuel Staff cost -24,261 -29,885 -31,621 -36,402 -39,148 -41,514 -46,982 Depreciation, amortization, -17,374 -18,607 -48,846 -50,786 -40,141 -39,169 -46,652 provisions Other operating expenses -20,002 -24,166 -27,819 -32,711 -32,851 -36,190 -38,624

Net operating income 11,605 9,749 -16,528 -9,250 10,576 14,632 11,227

Finance income 7,756 11,393 8,662 8,350 9,701 12,304 9,893 Finance expenses -16,192 -5,272 -3,206 -10,830 -6,740 -12,610 -4,020 Other income 18,714 17,504 4,711 2,736 2,431 6,227 53,941 Other expenses -20,862 -14,976 -102,872 -17,712 -25,481 -23,605 -41,437

Profit before taxation 1,021 18,399 -109,233 -26,705 -9,513 -3,051 29,605 Income taxes -2,249 -1,365 -592 -539 -670 172 -2,785 Deferred tax benefits/ 0 -249 10,211 3,094 1,659 0 0 expenses of the period

Profit/loss for the year -1,228 16,784 -99,614 -24,151 -8,523 -2,878 26,820

EMS: Consolidated 2005 2006 2007 2008 2009 2010 2011 Income Statement (non- restated) million RSD million RSD million RSD million RSD million RSD million RSD million RSD Operating Income 4,018 5,135 6,522 12,348 12,055 12,412 14,377 Revenue (sales) 3,732 4,766 6,017 11,454 10,903 12,050 14,070 Own-work capitalized 111 184 358 662 914 70 57 Other operating income 175 185 146 233 238 293 250

Operating costs & expenses -3,542 -4,337 -5,057 -11,369 -11,719 -11,103 -12,264 cost of goods sold -1 -4 -4 -4 -3 -4 -4 cost of materials -240 -338 -397 -3,586 -3,326 -3,344 -3,845 staff cost -1,133 -1,448 -1,601 -1,907 -2,028 -1,854 -2,109 Depreciation, amortization, -1,754 -1,850 -1,924 -3,037 -3,018 -2,930 -3,028 provisions Other operating expenses -413 -698 -1,132 -2,836 -3,344 -2,971 -3,278

Net operating income 476 798 1,465 979 336 1,310 2,112 Finance income 93 1,118 532 832 824 920 1,084 Finance expenses -790 -533 -503 -2,027 -982 -1,812 -547 Other income 77 108 133 734 256 787 139 Other expenses -709 -599 -1,112 -333 -24 -493 -251

Profit before taxation -853 893 515 186 410 711 2,538 Income taxes 0 -30 60 -61 -65 -63 -164 Deferred tax benefits of the 124 110 -47 91 72 72 69 period 16 Profit/loss for the year -729 972 543 216 417 720 2,443

22

Balance Sheets EPS: Consolidated 2005 2006 2007 2008 2009 2010 2011 (non- Balance Sheet restated) million RSD million RSD million RSD million RSD million RSD million RSD million RSD Assets Long-term assets 387,446 384,736 551,718 532,242 520,826 528,362 1,150,624 Intangible assets 2,031 2,245 2,373 2,428 2,426 2,482 2,558 Property, plant and 378,203 378,124 537,884 523,406 512,255 516,817 1,139,475 equipment Investment property 43 41 44 44 57 52 379 Advances intangible assets, 0 0 4,704 3,786 3,342 5,851 5,847 property, plant, equip. Equity investments 2,558 1,797 3,850 1,098 1,268 1,481 981 Long-term receivables and 4,610 2,529 2,863 1,479 1,478 1,679 1,383 placements

Current assets 53,159 62,406 68,649 76,759 85,869 98,556 102,950 Inventories 15,046 18,318 20,388 23,020 22,068 25,456 25,164 Advances for inventories 0 0 2,131 2,118 2,141 2,403 2,134 Accounts receivable 21,267 27,486 36,858 41,506 49,411 60,744 66,533 Receivables for prepaid 18 286 534 461 269 0 0 income taxes Short-term financial 5,497 6,333 2,069 2,073 2,031 1,898 2,873 placements Cash & cash equivalents 9,272 8,539 5,399 6,217 8,662 6,054 5,472 VAT and prepayments 2,058 1,445 1,271 1,363 1,288 2,001 774 Deferred tax assets

Total assets 440,605 447,142 620,367 609,001 606,695 626,918 1,253,574 Off-balance sheet items 0 39,380 0 0 0 140,500 186,823

Equity and Liabilities Equity 325,065 341,859 489,339 463,717 456,042 453,021 1,014,603 State-owned capital 358,324 358,656 358,656 358,656 358,718 358,718 358,718 Other capital funds 1,623 1,292 1,292 1,293 1,232 1,266 1,265 Revaluation reserves 24 0 248,637 248,089 246,539 245,681 781,743 Unrealized gains on 0 0 2,589 0 197 400 22 securities Unrealized losses on 0 0 0 -253 -477 -476 -664 securities Accumulated losses -34,906 -18,089 -121,836 -144,069 -150,168 -152,567 -126,481

Long-term provisions and 53,482 42,354 43,793 53,067 55,125 64,185 60,555 liabilities Long-term liabilities 756 1,704 3,622 7,515 9,088 10,848 12,341 Long-term interest-bearing 45,467 34,688 35,097 41,550 41,451 49,870 45,541 borrowings Other long-term liabilities 7,259 5,962 5,074 4,002 4,586 3,467 2,673

Short-term liabilities 50,613 51,255 59,983 67,106 71,793 86,864 96,119 Short-term interest- 14,239 9,469 9,387 9,582 12,845 16,224 17,682 bearing borrowings and other short-term financial liabilities Accounts payable 11,069 16,819 26,341 33,965 33,020 42,048 52,090 Other short-term liabilities 22,399 20,615 4,754 3,243 4,123 6,161 2,979 and accruals Value added tax and other 2,278 3,030 19,305 20,144 21,740 22,351 20,836 duties payable Income taxes payable 628 1,323 196 172 65 79 2,532

Deferred tax liabilities 11,445 11,674 27,253 25,110 23,724 22,848 82,297

Total equity and liabilities 440,605 447,142 620,367 609,001 606,684 626,918 1,253,574 Off-balance sheet items 0 39,380 42,456 77,974 76,990 140,500 186,823

23

EMS: Consolidated 2005 2006 2007 2008 2009 2010 2011 (non- Balance Sheet restated) million RSD million RSD million RSD million RSD million RSD million RSD million RSD Assets Long-term assets 40,558 41,470 42,419 56,774 55,550 54,647 55,525 Intangible assets 22 40 44 41 43 56 58 Property, plant and 39,508 39,793 40,935 54,165 54,152 53,170 54,114 equipment Equity investments 0 8 0 8 8 109 109 Advances for property and 0 0 0 672 152 602 606 plant investments Long-term investments 1,028 1,629 1,440 1,887 1,195 710 638

Short-term assets 2,425 3,180 4,243 6,586 8,578 10,940 12,460 Inventories 347 465 515 385 452 452 536 Trade & other receivables 1,343 955 1,886 1,961 1,230 1,717 2,658 Short-term investments 45 246 1,288 1,495 3,491 3,853 5,179 Cash and cash equivalents 606 1,428 372 2,052 2,462 3,876 3,074 Receivables for overpaid 0 0 2 0 income tax VAT and prepayments 83 86 182 692 943 1,043 1,012 Total short-term assets Deferred tax assets 0 0 0 0 0

Total assets 42,983 44,651 46,663 63,359 64,128 65,586 67,985 Off-balance sheet items 0 0 6,027 0 0 (2006) Equity and Liabilities Equity 29,879 30,971 31,144 45,183 45,191 45,342 47,280 State and other capital 30,420 30,540 30,540 30,540 30,540 30,540 30,540 Reserves 0 0 1 1 1 Revaluation reserves 0 0 0 12,207 12,192 12,058 12,055 Retained earnings 0 972 603 2,434 2,457 2,744 4,685 Accumulated losses -541 -541 0 0 0

Long-term liabilities and 6,822 7,937 9,661 11,240 12,555 14,305 14,188 provisions Long-term provisions 41 90 160 184 284 197 305 Long-term 4,526 6,605 7,859 10,788 12,007 13,840 13,631 loans/borrowings Other long-term liabilities 2,255 1,242 1,642 268 264 268 252

Short-term liabilities 4,145 3,716 3,847 5,506 5,024 4,665 5,310 Short-term financial 1,316 881 1,144 1,256 1,398 719 843 liabilities Operating liabilities , 457 683 0 1,828 1,097 1,478 1,877 (2008, 2009: accounts payables) Trade and other payables 0 0 630 0 0 265 254 Other short-term liabilities 2,292 82 384 517 884 2,196 2,238 and accruals Tax payables (2008, 2009: 80 2,040 1,689 1,873 1,637 6 98 VAT and other duties payable and accruals) Income tax payables 0 30 0 33 9

Deferred tax liabilities 2,136 2,027 2,011 1,430 1,358 1,275 1,206

Total equity and liabilities 42,983 44,651 46,663 63,359 64,128 65,586 67,985 Off-balance sheet items 6,273 6,078 6,027 14,371 15,868 19,133 19,391 (2006)

24

Annex 4. Bank Lending and Implementation Support/Supervision Processes

(a) Task Team members Responsibility/ Names Title Unit Specialty Lending Mohinder Gulati Lead Energy Specialist ECSIE TTL Michael Gascoyne Sr. Financial Management Specialist ECS-ECA Miroslav Frick Project Officer ECSIE Husam Mohamed Beides Sr. Power Engineer ECSIE Gailius Draugelis Operations Officer ECS-ECA

Supervision/ICR Salvador Rivera Lead Energy Specialist ECSEG TTL Varadarajan Atur Sr. Financial Analyst ECSSD former TTL Husam Mohamed Beides Sr. Power Engineer ECSSD Margaret Png Legal Counsel LEGLE Aleksandar Crnomarkvic Financial Management Specialist ECSO3 Enrique Crousillat Consultant ECSEG ICR author Miroslav Frick Operations Officer ECSSD Katsuyuki Fukui Sr. Power Engineer ECSEG Engineering Bjorn Hamso Senior Energy Economist ECSSD former TTL Lewis Hawke Sr. Financial Mgt. Specialist ECSC3 Charles A. Husband Consultant ECSEG Nicola Ille Sr. Environmental Specialist ECSS3 Bekim Imeri Social Scientist ECSS4 Plamen S. Kirov Sr. Procurement Specialist LCSPT José M. Martinez Sr. Procurement Specialist ECSO2 Chukwudi H. Okafor Sr. Social Development Specialist ECSS4 Milan Popovic Operations Officer ECCYU Desanka Stanic Program Assistant ECCYU Stratos Tavolaureas Consultant ETWES Claudia Vasquez Energy Economist ECSEG Richard Wong Consultant ECSIE Desanka Stanic Program Assistant ECCYU Rozena Serrano Program Assistant ECSEG

(b) Staff Time and Cost Staff Time and Cost (Bank Budget Only) Stage of Project Cycle USD Thousands (including No. of staff weeks travel and consultant costs) Lending FY05 34.76 175.829 Supervision/ICR

25

Staff Time and Cost (Bank Budget Only) Stage of Project Cycle USD Thousands (including No. of staff weeks travel and consultant costs) 1.034 FY05

FY06 11.85 49.236 FY07 14.62 83.992 FY08 15.20 71.243 FY09 25.02 87.972 FY10 29.63 103.125 FY11 21.62 99.539 FY12 8.18 72.951 FY13 .20 6.325

Total: 126.32 751.245

26

Annex 5. Beneficiary Survey Results Not Applicable

Annex 6. Stakeholder Workshop Report and Results Not Applicable

Annex 7. Summary of Borrower's ICR and/or Comments on Draft ICR The Borrower’s ICR was prepared by together with . It contains valuable information organized as follows:

A. Overall Impact of the Project is Positive:

The project has brought clear benefits in three fronts:

• Technical Improving reliability and quality of service in critical areas in need of rehabilitation. Actually, this is the first major investment on the rehabilitation of Sub-Transmission Substations, with voltage level of 110 kV, over the last 25 years. • Local Economic Development. As shown below in Description of 10 S/S, the modernization/expansion of the SSs has facilitated the development of the local industry and agriculture. These benefits, besides technical benefits such as loss reduction, etc, should be taken into account in the future in development of similar projects. • Improving of better household supply with electrical energy, as shown below in Description of 10 S/S. The lessons learned will serve as a model to further modernize and rehabilitate more than 150 Sub-Stations in EPS' assets, of which 54 will be transferred from EMS as part of the new Energy Law, to take effect on January 1, 2013.

Description of 10 S/S,

PHASE I

The 110/20 kV Mačvanska Mitrovica S / S, which has been in operation since 2009, has replaced the existing 35/10 kV S/S, which results in more reliable supply.

Interruptions were reduced by 98%, output increased by 33%, the number of customers increased by 32% and losses were reduced by 77%. Improved the supply of 35 kV surrounding network with the transformation of 20/35 kV. The total voltage conditions are vastly improved.

In addition to improving the supply of households is enabled and fabric development. A factory for battery production began.

27

110/35/10 kV substation Arilje S / S, which has been in operation since 2009 replaced the existing 35/10 kV, which results in more reliable supply. Interruptions were reduced by 96%, output increased by 20%, the number of customers increased by 8% and losses were reduced by 84%. Improved the supply of 35 kV network surrounding the transformation of 10/35 kV. The total voltage conditions are vastly improved.

Especially the improved conditions for economic growth: raspberry production and textile industry.

The substation of Arilje has improved considerably the quality of electricity service in the said region, making possible (in only two years) the duplication of the refrigeration capacity needed for the production of raspberry. Consequently, the region of Arilje is producing about one fourth of the national raspberry production.

PHASE II

110/35/10 kV substation Niš 8 S / S, which has been in operation since 2011 replaced the existing 35/10 kV, which results in more reliable supply. Interruptions were reduced by 82%, output increased 4 times, the number of customers increased by 4.8 times and the loss reduced by 60%.

The significant increase in load and the number of customers has been achieved by linkage of consumers from the downtown of Niš to this S / S.

The total voltage conditions are significantly improved by 16%.

110/35/10 kV Vranje 2 is a new S / S, which has been in operation since 2011 is substantively improve the reliability of electricity supply.

Interruptions were reduced by 73%, output increased by 50%, losses were reduced by 36%. Improved the supply of 35 kV surrounding network. The total voltage conditions are improved by 33%.Enabled the construction of new residential buildings, improved supply of existing households and enabled of industrial and fabric development.

The main reason for the construction of the 110/35 kV S/S MOSNA is a significant improvement of electricity supply in Iron Gate (Djerdap) region around Donji Milanovac which has so far had very long hours and often several daily interruptions in the supply of electricity especially in winter, when snow and ice tore the existing transmission line, over 40 years.

This S / S are completed in 2011.

Expected date of commissioning of S / S is the end of 2013, if EMS completes construction of transmission lines 100 kV Majdanpek 2-Mosna.

Expected improvements: interruptions are reduced by 73%, power increases by 98%, the number of customers by 1%, reduce losses by 82% and improve the voltage drop by 71%.

The 110/20 kV Jagodina 3 is a new S / S, which replaces the existing S / S 35/10 kV. The commissioning is expected in early 2013. This S/S will significantly improve the reliability of electricity supply. Expected improvements: interruptions are reduced by 42%, power increases by

28

56%, the number of customers by 74%, reduce losses by 54% and improve the voltage drop by 59%.

Improve the supply of existing households, Building of new and improve the quality of supply to industrial consumers.

PHASE III

110/35/10 kV substation lićevo Kragujevac, which has been in operation since July 2012, and has replaced the existing 35/10 kV, which results in more reliable supply. Interruptions were reduced by 95%, output increased by 20%, the number of customers increased by 1% and losses were reduced by 7%. Improved the supply of 35 kV network surrounding the transformation of 10/35 kV.

110/35 kV S/S Neresnica, with the commissioning is expected in early 2013-that will dramatically improve the supply of electricity to underdeveloped areas in eastern Serbia-Kučevo region. It will supply the existing 35/10 kV in the same location and in the vicinity of three new 35 kV transmission lines (Rabrovo.)

Expected improvements: interruptions are reduced by 85%, reduce losses by 82% and improve the voltage profile by 97%.

Create conditions for increasing the capacity of the water plant as the construction of new small producing facilities. Supply by electricity of this rural area to improve measurable.

The 110/20 kV Inđija 2 S / S, which is driven by the end of 2012-and, will supply new customers in the industrial zone (IT park, pumps factory, processing of animal waste-plant,). Interruptions will be reduced by 50%, increase power by 33%, the number of consumers increasing by 33% and reduce losses by 33%. Reduce the voltage drops to 20%.

Replacement of the existing substation 35/10 kV damaged by the earthquake in Kraljevo 2010, a new substation 110/10 kV RIBNICA.

Interruptions will be reduced by 95%, increase power by 72%, the number of consumers increasing by 60% and reduce losses by 92%. Reduce the voltage drops to 100%.

B. Project Design:

While separating funding sources for works (EPS) and goods (World Bank) may have initially slowed down construction, it had the added benefit of allowing the growth of the Serbian electricity service industry which is now providing competitive services to EPS and other utilities in the region. This has definitely been an added lasting benefit to EPS and to the energy service industry in Serbia.

Instead of 3-4 companies dealing with the construction of S/Ss in 2005 today, in Serbia exists dozen of them.

C. Implementation:

1. During implementation EPS have some suggestion according Delivery Parity (INCOTERMS), as follows:

29

Advantages of DDU (Delivery Duty Unpaid) over CIP (Carriage and Insurance Paid to)

Under the DDU terms the buyer takes the minimum possible risk. The goods in working conditions are delivered to the buyer in the place of destination, unloaded.

The seller is obliged to provide that the goods are accompanied with a relevant invoice, to obtain all export permits and licenses, to carry out export clearing, transport to the final destination, to notify the buyer of dispatch, and to send the buyer proof of delivery.

The buyer is obliged to pay for the goods, obtain all import permits and licenses, carry out import clearing, notify the seller of the exact time and point of delivery under the contract, and accept the seller’s advice of dispatch.

With regard to insurance neither the seller nor the buyer have any obligations.

RISK passes from the seller to the buyer at the place of final destination. The seller bears all risks of loss and damage to the goods up to the place of final destination. The buyer is obliged to provide the unloading of the goods, at his risk.

This term is used for any mode of transportation.

The CIP terms imply there is a greater risk for the buyer compared to DDU terms. The goods are delivered into the place of destination (site), unloaded, and only insured (not necessarily in working condition) i.e. the buyer gets an insurance policy.

The seller shall provide the goods with the accompanying invoice, all export permits and licences, export clearing, transport to the place of final destination, a minimal policy of insurance, and shall advise the buyer on despatch of the goods and send the buyer proof of delivery.

The buyer shall pay for the goods, obtain all import permits and licences, carry out import clearing, notify the seller of the exact time and point of delivery under the contract, and accept the seller’s advice of dispatch.

The seller shall obtain an insurance policy with minimum cargo coverage clauses for example, from the Institute of London Underwriters. If the buyer requires better insurance, the seller shall provide such insurance at the buyer’s expense.

RISK passes from the seller onto the buyer when the seller delivers the goods to the carrier.

The buyer shall bear all risks of loss and damage to the goods from the moment the seller has delivered the goods to the carrier.

This term is used for air or ocean containerized and roll-on roll-off shipments.

The advantages of DDU over CIP terms are obvious, and this is the reason why we insist on DDU.

Changes to STD regarding incorporation of DDU terms instead of CIP shall be made consistently and fully and they will also apply to ITB, BDS, Price Schedules and the Contract.

30

2. During implementation EPS have some comment on reason for delays

One of the main reasons for delays in the project (9 months), is delay of opinion (No objection) from the WB on Evaluation report in the second stage.

Annex 8. Comments of Cofinanciers and Other Partners/Stakeholders

Annex 9. List of Supporting Documents

Serbia – Project Appraisal Document, June 2005 Supervision Aide Memoires and Project/Implementation Status Reports EPS Status of Works and delivery Reports.

31 IBRD 34847R ° ° ° 19 E To 20 E 21 E Kiskoros To Szeged HUNGARY SERBIA

SELECTED CITIES AND TOWNS SuboticaSubotica KanjizaKanjizˇa To 46°N Arad OKRUG (DISTRICT) CAPITALS BajmokBajmok SentaSenta POKRAJINE (PROVINCE) CAPITALS BackaBaˇcka KikindaKikinda To Timisoara TopolaTopola AdaAda NATIONAL CAPITAL SomborSombor ApatinApatin RIVERS SivacSivac Ve liki BecejBeˇcej KulaKula ROMANIA MAIN ROADS VOJVODINAV O J V O D I N A RAILROADS T i sa ElemirElemir

TemerinTemerin To OKRUG (DISTRICT) BOUNDARIES CROATIA Timisoara BackaBackˇa ZrenjaninZrenjanin POKRAJNE (PROVINCE) BOUNDARIES To PalankaPalanka Vinkovci INTERNATIONAL BOUNDARIES NoviNovi SadSad To SidSˇid VrsacVrsaˇc Vinkovci Fruska Gora AlibunarAlibunar This map was produced by the Map Design Unit of The World Bank. IndijaIndija 45°N RumaRuma The boundaries, colors, denominations and any other information shown on this map do not imply, on the part of The World Bank Group, any judgment on the legal status of any territory, or any PancevoPancˇevo BelaBela CCrkvarkva endorsement or acceptance of such boundaries. SremskaSremska To MitrovicaMitrovica Carbunari ˇ To To SabacSabac S ˇ KovinKovin av ZeleznikZeleznik BELGRADEBELGRADE Gura Vail Bijeljina a ZminjakZminjak Danube PrnjavorPrnjavor PozarevacPozˇarevac KladovoKladovo V ObrenovacObrenovac SmederevoSmederevo GolubacGolubac las ic Ho Del LoznicaLoznica Pl m J i an ol ova ina MladenovacMladenovac js MajdanpekMajdanpek n V ke e P l PetrovacPetrovac i l D k a r a n in Velika-Velika- i

a n

M M

PlanaPlana M a NegotinNegotin

o o LjubovijaLjubovija ValjevoValjevo M o P r To o a a ZagubicaZˇagubica v v l lj SERBIAS E R B I A a Sarajevo e e n n Be BorBor To lja Vidin BOSNIA GornjiGornji nica ° KragujevacKragujevac 44°N 44 N RogacicaRogacica MilanovacMilanovac AND RavniRavni GajGaj CuprijaC´uprija To CacakCacaˇk Vidin UziceUzˇice JagodinaJagodina (Svetozarevo)(Svetozarevo) ZajecarZajecˇar HERZEGOVINA PozegaPozeˇga ParacinParac´in tan R Z or a To Zl uh SokoSoko g Gorazde at Z J l ib apa BanjaBanja a or KraljevoKraljevo dna M v orava KnjazevacKnjazˇevac a C k IvanjicaIvanjica e AleksinacAleksinac m KrusevacKruˇsevac J e UsceUˇsce B Midzor a r Veliki a (2168 m) v n in l PrijepoljePrijepolje o o lg strebac NisNiˇs k r Ze Ja a BelaBela n RaskaRaˇska ProkupljeProkuplje S PalankaPalanka SjenicaSjenica P u M lija BeloljinBeloljin la va t Go Ju n s z in PirotPirot n a . a NoviNovi PazarPazar a To Ra M n da o z Priština n ra o v 43° 43°N g PrepolakPrepolak a N o LeskovacLeskovac R To VlasotinceVlasotince To Podgorica Sofia To To MONTENEGRO Priština Sofia

PribojPriboj SurdulicaSurdulica BULGARIA KOSOVO VranjeVranje BosilegradBosilegrad To BujanovacBujanovac Pernik

PresevoPresˇevo

SERBIALakeLake ScutariScutari To Kumanovo FYR 0 25 50 75 Kilometers

ALBANIA MACEDONIA 0 25 50 Miles

19°E 20°E 21°E 22°E

JULY 2009