Document of The World Bank Report No: ICR2806 IMPLEMENTATION COMPLETION AND RESULTS REPORT (IBRD-77380) ON A LOAN IN THE AMOUNT OF US$ 48 MILLION TO THE KAZAKHSTAN ELECTRICITY GRID OPERATING COMPANY WITH THE GUARANTEE OF THE REPUBLIC OF KAZAKHSTAN FOR A MOINAK ELECTRICITY TRANSMISSION PROJECT October 30, 2013 Sustainable Development Unit Central Asia Country Unit Europe and Central Asia Region CURRENCY EQUIVALENTS (Exchange Rate Effective July 31, 2013) Currency Unit=Kazakhstani Tenge (KZT) 1 KZT = US$ 0.01 US$ 1.00 = KZT153.56 FISCAL YEAR January 1 – December 31 ABBREVIATIONS AND ACRONYMS ARNM Agency for Regulation of Natural Monopolies CPS Country Partnership Strategy EIRR Economic Internal Rate of Return EMP Environmental Management Plan FIRR Financial Internal Rate of Return FM Financial Management GHG Greenhouse Gases GOK Government of Kazakhstan GWh Gigawatt Hours KEGOC Kazakhstan Electricity Grid Operating Company kWh Kilowatt Hours LAP Land Acquisition Plan M&E Monitoring and Evaluation MHPP Moinak Hydroelectric Power Plant MW Megawatts NGO Non-government Organization OHTL Overhead Transmission Line OSY Outdoor Switchyard PAD Project Appraisal Document PDO Project Development Objective PMU Project Management Unit PP Procurement Plan REK Regional Energy Distribution Company SS Sub-Station Vice President: Laura Tuck Country Director: Saroj Kumar Jha Sector Manager: Ranjit J. Lamech Project Team Leader: Mirlan Aldayarov ICR TTL Joseph Melitauri ICR Author: Richard Berney KAZAKHSTAN Moinak Electricity Transmission 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 ........................................................... 5 3. Assessment of Outcomes ...................................................................................................... 10 4. Assessment of Risk to Development Outcome ..................................................................... 13 5. Assessment of Bank and Borrower Performance.................................................................. 14 6. Lessons Learned.................................................................................................................... 16 7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners ....................... 17 Annex 1. Project Costs and Financing ...................................................................................... 18 Annex 2. Outputs by Component .............................................................................................. 19 Annex 3. Economic and Financial Analysis ............................................................................. 21 Annex 4. Bank Lending and Implementation Support/Supervision Processes ......................... 25 Annex 5. Beneficiary Survey Results .................................................................................. 27 Annex 6. Stakeholder Workshop Report and Results ............................................................... 28 Annex 7. Summary of Borrower's ICR and/or Comments on Draft ICR ................................. 29 Annex 8. Comments of Cofinanciers and Other Partners/Stakeholders ................................... 33 Annex 9. List of Supporting Documents .................................................................................. 34 MAP A. Basic Information Kazakhstan Moinak Country: Kazakhstan Project Name: Electricity Transmission Project Project ID: P114766 L/C/TF Number(s): IBRD-77380 ICR Date: 10/30/2013 ICR Type: Core ICR KEGOC (KAZAKH Lending Instrument: SIL Borrower: ELETR.GRID OPERATING COMP) Original Total USD 48.00M Disbursed Amount: USD 44.73M Commitment: Revised Amount: USD 44.73M Environmental Category: B Implementing Agencies: Kazakhstan Electricity Grid Operating Company (KEGOC) Cofinanciers and Other External Partners: B. Key Dates Revised / Actual Process Date Process Original Date Date(s) Concept 11/10/2008 Effectiveness: 01/27/2010 Review: Appraisal: 05/13/2009 Restructuring(s): 12/11/2012 Mid-term Approval: 09/15/2009 06/30/2011 05/10/2011 Review: Closing: 12/31/2012 04/30/2013 C. Ratings Summary C.1 Performance Rating by ICR Outcomes: Satisfactory Risk to Development Outcome: Low or Negligible Bank Performance: Moderately Satisfactory Borrower Performance: Satisfactory C.2 Detailed Ratings of Bank and Borrower Performance (by ICR) Bank Ratings Borrower Ratings Quality at Entry: Satisfactory Government: Satisfactory Quality of Moderately Implementing Satisfactory Supervision: Satisfactory Agency/Agencies: Overall Bank Moderately Overall Borrower Satisfactory Performance: Satisfactory Performance: C.3 Quality at Entry and Implementation Performance Indicators Implementation Indicators QAG Assessments (if any) Rating Performance Potential Problem Project at No Quality at Entry (QEA): None any time (Yes/No): Problem Project at any time Quality of Supervision No None (Yes/No): (QSA): DO rating before Satisfactory Closing/Inactive status: D. Sector and Theme Codes Original Actual Sector Code (as % of total Bank financing) Public administration- Energy and mining 5 5 Transmission and Distribution of Electricity 95 95 Theme Code (as % of total Bank financing) Infrastructure services for private sector 100 100 development E. Bank Staff Positions At ICR At Approval Vice President: Laura Tuck Shigeo Katsu Country Director: Saroj Kumar Jha Motoo Konishi Sector Manager: Ranjit J. Lamech Ranjit J. Lamech Project Team Leader: Mirlan Aldayarov Istvan Dobozi ICR Team Leader: Joseph Melitauri ICR Primary Author: Richard L. Berney F. Results Framework Analysis Project Development Objectives (from Project Appraisal Document) The objective of the Project is to increase and improve the supply of electricity to business enterprises and households in southern Kazakhstan in an economically and environmentally sustainable manner. Revised Project Development Objectives (as approved by original approving authority) (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 : Partial reduction of power deficit in the southern region of Kazakhstan Additional Value average Target achieved. Winter power deficit quantitative or generation of Additional 300 was 865 MW Qualitative) 1,027 GWh/year MW is available. (or 300 MW) Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments (incl. % Achieved - 100% achievement) Indicator 2 : Reduction of load shedding in the Almaty power region Additional 300 MW of peak Target achieved. Value 230 MW (2008-2009 capacity No quantitative or winter season) available to load shedding in Qualitative) reduce load Almaty region. shedding to zero Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments Achieved - 100%, (Completion of the second North-South Interconnector (incl. % contributed to elimination of load shedding) achievement) Indicator 3 : Reduction in CO2 emissions (in mln. metric tons) Estimated 1.2 m Baseline scenario Estimated 1.2 m Value tons estimates emission of tons quantitative or of CO2 1.20 m tons of CO2 of CO2 emissions Qualitative) emissions without the project. avoided. avoided. Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments (incl. % Achieved - 100% achievement) Indicator 4 : Transmission lines constructed and commissioned Value 325.18 km of 325.18 km of quantitative or No line constructed. lines constructed lines constructed Qualitative) Date achieved 12/31/2007 12/07/2012 04/30/2013 Comments (incl. % Achieved - 100% achievement) Indicator 5 : Additional installed peak capacity in the southern region of Kazakhstan Moinak HPP is Moinak HPP Value commissioned Switchyard quantitative or No plant commissioned with complete and Qualitative) two 150MW commissioned units. Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments (incl. % Achieved - 100% achievement) Indicator 6 : Modernization of substations Value Substation Substation No substation quantitative or modernized and modernized and modernization Qualitative) commissioned commissioned Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments (incl. % Achieved - 100% achievement) Indicator 7 : Reduction in average wholesale price of electricity Value Moinak power Moinak power Maximum spot market quantitative or available at less available at less price 6.6 KZT/kWh Qualitative) than spot price than spot price Date achieved 12/31/2008 04/30/2013 04/30/2013 Indicator dropped, as introduction of administrative price caps on groups Comments of generators and the reduction of turnover on the spot market made the (incl. % indicator irrelevant. However, Moinak power was available at less than achievement) spot price. (b) Intermediate Outcome Indicator(s) Original Target Formally Actual Value Values (from Revised Achieved at Indicator Baseline Value approval Target Completion or documents) Values Target Years Turnkey contracts for transmission lines and substations awarded in Indicator 1 : accordance with procurement plan Target achieved. Value All Contracts (quantitative No contracts awarded contracts have implemented or Qualitative) been concluded and fully implemented Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments (incl. % Achieved - 100% achievement) Manufacturing and delivery of equipment in accordance with Procurement Indicator 2 : Plan (PP) Value No equipment Equipment Equipment (quantitative manufactured delivered on time delivered on time or Qualitative) Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments (incl. % Achieved - 100% achievement) Indicator 3 : Installation and commissioning proceeds according to PP schedule Value Installation and Installation has not Installation (quantitative commissioning commenced completed or Qualitative) completed Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments (incl. % Achieved - 100% achievement) Indicator 4 : Tender documents completed in accordance with PP Value Tender No tender documents (quantitative documents Tender completed exist or Qualitative) completed Date achieved 12/31/2007 04/30/2013 04/30/2013 Comments (incl. % Achieved - 100% achievement) G. Ratings of Project Performance in ISRs Actual Date ISR No. DO IP Disbursements Archived (USD millions) 1 06/11/2010 Satisfactory Satisfactory 0.00 2 12/17/2010 Satisfactory Satisfactory 0.30 3 06/27/2011 Satisfactory Satisfactory 14.86 4 03/30/2012 Satisfactory Satisfactory 31.37 5 02/03/2013 Satisfactory Satisfactory 43.15 6 04/28/2013 Satisfactory Satisfactory 43.15 H. Restructuring (if any) ISR Ratings Amount Board at Disbursed at Restructuring Reason for Restructuring Approved Restructuring Restructuring Date(s) & Key Changes Made PDO Change in USD DO IP millions To complete testing of MHPP the closing date was 12/11/2012 N S S 43.00 extended by 4 months from December 31, 2012 to August 31, 2013. I. Disbursement Profile 1. Project Context, Development Objectives and Design 1.1 Context at Appraisal At appraisal in 2008, Kazakhstan enjoyed strong economic performance as the real Gross Domestic Product grew at an average rate of 10 percent between 2000 and 2007. While the Government of Kazakhstan (GOK) had made diversification of the economy a development priority, economic output continued to be highly dependent on the exploitation of natural resources, with minerals and petroleum accounting for 39 percent of GDP and 73 percent of exports in 2007. The country’s vigorous economic growth and increasing diversification of the economic base had resulted in a 6 percent average growth in demand for electricity from 2000 to 2007. In the Southern regions of the country, where economic growth was particularly strong, electricity demand grew by 8 percent per year over the same period. At the time of project design in 2007, the Southern region’s supply-demand power deficit was 865 MW - about half of its consumption. The deficit was met largely by power transmitted from the North. In the winter period of maximum electricity loads, the deficit could not be fully met, even when the costly output of the Zhambyl plant, located in the South, was operational, so load shedding became necessary. Electricity demand in the South was projected to continue to increase by nearly 6 percent per year which, barring new generation and transmission investments, would have quadrupled the region’s projected supply-demand power deficit by 2020. One of the key pillars of the GOK’s strategy was the support of infrastructure investments needed to meet the needs of its rapidly expanding economy. To this end, the GOK had invested significant resources in modernizing and expanding the power sector. As part of this expansion program it planned to build a 300 MW hydropower plant in the South of Kazakhstan to reduce the constraints on power supply in this rapidly growing region. The Moinak transmission project supported evacuation of power from this hydropower plant. Three-fourths of Kazakhstan’s generation capacity was in the Northern part of the country where its low-cost coal-fired plants were located. Generation facilities in the South were limited to small hydro, combined heat and power plants, and one high-cost oil-fired plant at Zhambyl. The 300 MW Moinak Hydroelectric Power Plant (MHPP) was the only new significant generation investment planned for the South. Sector Institutions The GOK began reforming the power sector in 1996, with a view to introduce extensive private participation within a competitive power market. Most of the large thermal generation plants were sold to foreign strategic and local investors. The large hydropower plants were given on a concession basis to private investors. Most of the Regional Electricity Distribution Companies (REKs) were also privatized. The latter also owned a large number of smaller power plants and combined heat and power plants, most of which were largely outdated and highly inefficient. The Kazakhstan Electricity Grid Operating Company (KEGOC) was formed as a state-owned entity in 1997. It operated all transmission assets at the 220, 500 and 1,150 kV levels of national and interregional significance and was responsible for national dispatch control and international connections. Its system consisted of: (i) the Northern grid connected to the Russian power system; (ii) the Southern grid connected to the Northern grid and to the Central Asian power grid through single circuit 500 kV lines; and (iii) the Western grid comprised of two largely isolated subsystems that imported power from Russia to supplement local generation. 1 The wholesale electricity market was largely liberalized and operated mainly on the basis of bilateral direct sale contracts between generators and large consumers, including regional energy supply organizations. A liquid spot market accounted for about 20 percent of the total wholesale turnover in 2008. A real-time balancing market was scheduled to operate on a trial basis from January 2008. A lack of flexible load-following capacity and inadequate automated metering and communication devices has delayed its full implementation. Sector Regulation The transmission company, KEGOC, was regulated by the Agency for Regulation of Natural Monopolies (ARNM) under the Law on Natural Monopolies. This law ensured full recovery of justifiable costs, including the cost of new investments. KEGOC’s tariffs were approved by ARNM on a cost-plus basis and included a 10 percent regulated rate of return. There is a Grid Code in place with a set of rules governing non-discriminatory third-party access to the transmission and distribution networks. At the national level, KEGOC has implemented these rules on its high voltage transmission system. At the regional level, the largely vertically REKs have been more lax in the implementation of third-party access. Project Rationale The project financed the transmission lines as well as the modernization and extension of the two transmission substations required to evacuate electricity from the MHPP, and transmit it to the Southern regional network. The MHPP was a key element in the GOK’s strategy to address peak power shortages in the South. At the time of appraisal, the MHPP was under construction and scheduled to start operation by the end of 2012. By providing an additional power source within the Southern regional grid, MHPP would also strengthen the grid by taking pressure off the North-South interconnector at times of excessive load. The project was consistent with the objectives of the Country Partnership Strategy Paper of September 8, 2004, which was updated in the Country Partnership Strategy Paper Progress Report of May 1, 2008. Kazakhstan’s development agenda was focused on achieving international standards for public enterprises and increasing the competitiveness of the country’s tradable non-oil sectors. From the broader development perspective, the continued development of reliable and cost- effective electricity supply was fundamental to both social and economic development of Southern Kazakhstan. As an essential integrated component of the MHPP, this transmission operation contributes to these objectives by: (i) providing clean and low-cost peak energy; (ii) mitigating a binding energy supply constraint to continued economic growth in the region; and (iii) increasing the region’s competitiveness in terms of industrial and commercial development with related employment benefits. 1.2 Original Project Development Objectives (PDO) and Key Indicators (as approved) The primary project objective, as presented in both the Project Appraisal Document (PAD) and the Loan Agreement, was “to increase and improve the supply of electricity to business enterprises and households in Southern Kazakhstan in an economically and environmentally sustainable manner.” Completion of the integrated project (MHPP and transmission) was expected to have the following outcomes: 2  Increase in the amount of power available to customers in the Southern region with a consequent reduction in load shedding.  Improved quality and reliability of electricity supply.  Lower average cost of generation owing to the introduction of additional hydroelectric power into the system.  Reduced Greenhouse Gases (GHG) emissions as a result of displacement of coal/oil-based thermal generation. The specific baseline and target values of the monitoring indicators as in the PAD were as follows: Project Outcome Baseline Target (2013) Status at ICR Indicators Partial reduction of 865 MW Deficit Additional average Achieved, additional power deficit in the (2007) generation of 1,027 300 MW is available Southern region of GWh/year (or 300 MW) from Moinak HPP at Kazakhstan peak Reduction of load 230 MW (2008-09 Additional 300 MW of peak MHPP provided shedding in the Almaty winter season) capacity available to reduce additional 300 MW power region load shedding to zero capacity Reduction in average Maximum spot MHPP power available at Indicator dropped as wholesale price of market price 6.6 less than spot maximum price irrelevant. MHPP electricity KZT/kWh (2008) power is produced at a lower cost than the alternatives Construction and New lines operational Line is fully commissioning of lines operational Construction of MHPP Operational The MHPP switchyard switchyard is operational Modernization of Operational Substations are fully substations operational CO2 emissions Demand growth of Estimated 1.2m tons of CO2 Estimated 1.2m tons 900 GWh/yr by 2012 emissions avoided by 1.02 of CO2 emissions and 1,700 GWh/yr by TWh of hydroelectricity avoided after a full 2020 will be met by year of MHPP thermal generation operation 1.3 Revised PDO (as approved by original approving authority) and Key Indicators, and Reasons/Justification The Project Development Indicаtors were not formally revised. However, during project implementation the Outcome Indicator for reduction in average wholesale price was dropped as irrelevant, given the negligible share of the low-cost MHPP generation in the region’s overall generation mix and other factors like administrative price caps on groups of generation companies and the much-reduced turnover on the spot market. In addition, even if the average wholesale price was reduced, it would not have been attributable to the project. The detailed analysis of the M&E design is presented in the section 2.3 - Monitoring and Evaluation (M&E) Design, Implementation and Utilization. 3 1.4 Main Beneficiaries Electricity consumers in the Southern region are the main beneficiaries of the increased electricity production in the region. They will receive more reliable electricity supply made possible by the elimination of load shedding, and a reduction of periodic supply interruptions from the occasional overloading of the North-South transmission system. KEGOC also benefited, as it made an agreement with MHPP to purchase 350 GWh of electricity (which was needed to make up for transmission losses) for about 25 percent less than the wholesale price of electricity available from the Northern coal-fired power plants. 1.5 Original Components (as approved) The project was composed of the following three components: Component A – construction of transmission lines; Component B – construction of a switching station and modernization of two substations; and Component C – consulting and technical services for procurement and project management. An overall description of the components and their subcomponent are presented below. There is a more detailed technical description of each component in Annex 2. Component A – Construction of Transmission Lines • A1– Construction of a 97.73 km long 220 kV single-circuit overhead transmission line (OHTL) from MHPP to Shelek substation; Construction of two 220 kV transmission lines from 220 kV MHPP Switchyard to MHPP (circuit 1 – 0.484 km, circuit 2 - 0.553 km). • A2 – Construction of a 227.78 km long 220 kV single-circuit OHTL from MHPP to Robot substation. Component B – Modernization of Substations  B1 – Construction of 220/110 kV outdoor switchyard to transfer of power from MHPP to KEGOC transmission lines.  B2 – Modernization of 220 kV Robot substation;  B3 – Modernization of 220 kV Shelek substation. The Component C – Consulting and Technical Services  C1– Procurement and project management consulting services, including preparation of bidding documents, construction supervision and quality control.  C2 – Technical service, which include support for selection of transmission routes, engineering surveys and construction supervision of the turn-key contracts. 1.6 Revised Components No components were revised during the project implementation. 1.7 Other significant changes The IBRD loan Closing Date was extended by four months, from December 31, 2012 to April 30, 2013 to allow KEGOC to complete testing of the MHPP. At closing, US$3.27 million remained unspent and was cancelled. There were no significant changes in the scope of the project. 4 2. Key Factors Affecting Implementation and Outcomes Two main factors positively affected implementation of the project and contributed to achieving the stated outcomes; (i) KEGOC’s solid capacity to manage the project; and (ii) the Bank’s experience in the implementation of transmission projects in Kazakhstan. 2.1 Project Preparation, Design and Quality at Entry In overall, the project was well prepared and project design was sound, as it was based on a thorough assessment of the Borrower and implementing agency capacity and reflected lessons learned from past Bank operations. The project indicators fully allowed capturing the project benefits and achievement of the PDOs although some of the indicators required further refinement during the implementation. The detailed description and analysis of the design, implementation, and utilization of the project monitoring indicators are presented in section 2.3 Monitoring and Evaluation (M&E) Design, Implementation and Utilization. Preparation The project was well prepared with particular attention to the lessons learned and technical aspects of the proposed transmission line. The schedule of transmission line completion was closely coordinated with the MHPP completion. Lessons learned from prior Bank work in Kazakhstan were taken into account during design and preparation of the project. Prior experience in the implementation of transmission projects had demonstrated that special attention needed to be paid to the analysis of alternative possible transmission line routes to minimize the adverse environmental and social impact. Outcomes of public discussions of route location were incorporated into the final project design. A public consultation on the Environmental Management Plan was conducted with affected stakeholders and Non-Government Organization (NGOs) on November 14, 2008 in Astana. Its satisfactory implementation was verified by the Bank’s environmental specialist. The transmission project used standard technology for high-voltage transmission line construction and substation extension/modernization. Alternative transmission line routes were thoroughly evaluated. KEGOC’s analysis encompassed economic, technical, social, and environmental considerations. Two potential routes were modified because they would have crossed the Charyn and Altyn-Emel “Specially Protected Natural Areas.” Options using double circuit lines, which would have minimized the transmission line capital costs, were rejected because they would have required substantial increases in capacity of the receiving substations and would have been subject to the risk of both circuits being interrupted at the same time. This risk was considered undesirable from the standpoint of overall system reliability. All potential issues related to the construction of the associated MHPP dam were identified early in the preparation process. The dam design was reviewed in depth by an independent Bank-hired specialist. The application of the Bank Safeguards to the MHPP as a connected project is discussed in section 2.4. Assessment of Project Management KEGOC, the Borrower and implementing agency, was a competent grid operating company. It had already gained substantial experience in implementing two previous World Bank-financed projects: The Electricity Transmission Rehabilitation Project and The North-South Electricity Transmission Project. Its organization, staffing and reporting processes were well established and satisfactory and its procurement and financial management capacity had been shown to be satisfactory. 5 Design A simple three component design was selected. Turnkey contracts were agreed upon because previous projects with KEGOC demonstrated that turnkey contracts for the construction of transmission lines and rehabilitation of substations had provided an efficient way of implementing projects in a cost-effective manner without over-burdening the company’s project supervision capabilities. Timely implementation of the project was particularly important for the success of the project because any delay in start-up of the transmission line could have delayed the electricity production of the MHPP, which would have had significant repercussions on its economic and financial viability. The MHPP had a very tight implementation schedule which meant tight implementation for the transmission line as well. Because the project required local contracting for various aspects of project design and implementation, KEGOC believed that selecting a company with experience in similar turnkey projects in countries other than their home country would have reduced the risk of delay of the project implementation and ensured timely completion. KEGOC requested to prequalify companies with experience with similar turnkey projects in countries other than their home country. However, the Bank was not able to agree on the prequalification as requested by KEGOC. The Bank considered prequalification criteria too restrictive. This disagreement led to lengthy discussions between the Borrower and the Bank, as well as within the Bank. This issue has been also referred by the Borrower in the Summary of Borrower’s ICR, Annex 7. While KEGOC accepted the Bank’s decision not to restrict prequalification to companies that had experience in subcontracting outside their home country, KEGOC’s concerns proved to be justified. The winning bidder had great difficulty in organizing the necessary subcontracting activities, thus delayed start of the project. This delay caused late preparation of the detailed design for the transmission line and risked timely completion of the project. Detailed discussion on the causes of delay and remedial actions is presented in the section 2.2 Implementation below. The intermediate project indicators, which included the timing for critical activities, were adequate to monitor project progress. The key indicators were also well designed to capture the project outcomes. Section 2.3 presents a more detailed analysis of the project monitoring and evaluation. Adequacy of Government Commitment The project was critically needed for the evacuation of power from the MHPP. It enjoyed strong support from the GOK. The Bank team coordinated with key GOK agencies on the project’s design, processing schedule, and implementation plan. KEGOC obtained the approval of the “State Expertise” and the support of the relevant ministries in regard to the feasibility study, environmental impact assessment and project financing plan early on during project preparation. Assessment of Risks None of the risks identified at appraisal were rated as substantial, and the overall risk rating was assessed as Moderate, which proved to be the case. Financial risks were mitigated by the provisions of the Guarantee Agreement that ensured that the transmission tariff would be maintained at levels sufficient to cover KEGOC’s longer term cash flow requirements. Technical risks were mitigated by the strengthening of the Project Management Unit (PMU) of KEGOC 6 with an international consultant to assist in project management, while the turnkey procurement arrangement prevented major project implementation delays. Potential risks related to land acquisition practices and potential environmental concerns were mitigated with specific Loan Agreement safeguard covenants. Quality at Entry Based on the above and, specifically, the shortcoming in design of the prequalification criteria, an overall project quality at entry is moderately satisfactory. 2.2 Implementation The project had a tight implementation schedule, which needed to be closely coordinated with the completion of the MHPP, since the operation of the MHPP and construction of the transmission lines were mutually dependent. The evacuation of power from MHPP depended entirely on the completion of the related transmission facilities and testing and final acceptance of the lines depended on the availability of the full load from MHPP. MHPP’s first 150 MW generation unit was scheduled to be completed by December 2011, and the second by June 2012. KEGOC engaged consultants to assist with the preparation of bidding documents, quality control and monitoring of all executed work. The consultant also provided technical services associated with transmission line route selection. A single turnkey contractor was responsible for the design, supply and installation of the two transmission lines and the MHPP switchyard. KEGOC funded and implemented the upgrading of the project’s two substation components. The project had early implementation delays; the implementation got off to a slow start because the turnkey contractor had difficulties with fielding the requisite team needed to complete the detailed design of the project in a timely manner. There were also difficulties with completing contracts with local subcontractors, which compounded the problem. As a result the contractor was not able to prepare the detailed design package on time which risked timely completion of the project. The Bank’s early supervision missions flagged the seriousness of the risk of delayed project completion. These early implementation delays were overcome after KEGOC undertook the task of arranging for the completion of detailed design work. Under much pressure from KEGOC, the contractor sped up subsequent implementation activities. As a result of the constant attention to the implementation timeline by both the Bank and KEGOC, the works under the project were completed on time and below budget. The first of the two lines was completed in November 2011, in time for testing the first 150 MW power unit of the MHPP. The second line was completed in August 2012, in time for the commissioning of the second 150 MW power unit. While the works were completed on time, within the original IBRD loan Closing Date, a four month extension of the Closing Date was required to allow time for final testing and acceptance of the transmission facilities. The Closing Date was extended by four months, from December 31, 2012 to April 30, 2013. 7 2.3 Monitoring and Evaluation (M&E) Design, Implementation and Utilization Design of indicators Almost all of the outcome indicators were well designed to fully capture project outcomes. During the process of project supervision, one indicator – the reduction in average wholesale price of electricity – was reexamined and determined to have little relevance to the project outputs and was dropped. Project intermediate outcome indicators were adequate to follow implementation progress. They included: (i) tender documents completed in a timely manner; (ii) contracts awarded in accordance with the deadline of the project’s procurement plan (PP); and (iii) equipment delivered installed and commissioned in accordance with the PP. The Project Monitoring Annex of the PAD included a quantitative indicator for measuring the effect of the project’s impact on reducing the region’s power deficit: the amount of generated by MHPP (measured in GWh). The indicator target was at least 1,027 GWh, which was a reasonable measurable target for determining the deficit-reducing impact of the MHPP and associated transmission facilities. There was also a load shedding indicator, which was to be reduced to zero after project completion, from a baseline that was subsequently determined to be 80 MW. However, the level of system load shedding is affected by several factors in addition to the increase in the available generation capacity under the project. Other factors, including an increased electricity supply from the Northern region after the completion of the second North-South Interconnector, enabled load shedding to be eliminated, before MHPP power supply became available. Implementation Progress indicators were consistently used to keep track of, and identify problems in implementation progress. Slippage in implementation of procurement packages were identified on all supervision missions and agreement was reached on efforts needed to speed up the process and bring it in line with the PP, which was closely tied to the completion schedule of the MHPP. Utilization Intermediate outcome indicators were used to ensure that the project implementation remained on schedule. In order to have a full evidence of the annual generation of MHPP, the value of MHPP output continues to be collected. The quantitative indicators related to increased available capacity during peak demand periods have been achieved. The indictors requiring data from a full year of plant operation (power generated and saving in CO2 generation) give every indication that they will be achieved. KEGOC will continue providing operation data for the MHPP and electricity supply in the Southern region for the Bank’s monitoring of the project’s performance. A detailed discussion of project outputs is in section 3.2. 2.4 Safeguard and Fiduciary Compliance The project triggered OP 4.01 on environmental management, OP/BP4.12 on involuntary resettlement, and OP/BP 4.37 on dam safety. 8 Social and Environmental Safeguards Environmental Management (OP/BP 4.01): The transmission line will have a limited extent and duration of any potential environmental impacts during construction and operation phases, therefore the project was assigned Category B. Key environmental issues included the normal construction issues associated with the movement of men, machines and materials, dust, noise, engine exhaust, and disposal of solid (nonhazardous) wastes - mostly from packaging and land preparation. KEGOC prepared an Environmental Management Plan (EMP), held public consultations, and subsequently posted the EMP on its website and disclosed it in the Bank’s InfoShop. The project is in full compliance with environmental assessment regulations of the Borrower and World Bank safeguard policies for environmental assessment. Involuntary Resettlement (OP/BP 4.12): The project triggered OP 4.12 on Involuntary Resettlement due to land acquisition associated with project activities. KEGOC acquired about 14 hectares of land for permanent use and 555 hectares for temporary use. All land acquired was in rural areas and was agricultural and grazing land. In total, 316 persons (land users) have been affected. None had to be resettled, and all received reasonable cash compensation. A Land Acquisition Policy Framework was prepared during project preparation. However, construction of the line started prior to the Bank’s formal approval of a Land Acquisition Plan (LAP). The client was alerted to this and the Bank team worked with the client to approve a LAP acceptable to the Bank and which included relevant retroactive measures to ensure that all project-related compensation was in line with OP 4.12. All compensation has been completed prior to loan closure. Dam Safety (OP/BP 4.37): Although the MHPP was not formally part of the transmission project financed by the Bank, it was considered to be a “connected” project. OP/BP 4.37 was therefore triggered, and the Bank hired an independent dam safety expert to perform a due diligence assessment of its design, construction and envisaged operation. This assessment found that the dam was designed by qualified engineers and that the design drawings were of high quality, with sufficient details and quantitative assessments to confirm the safety of the dam. Given these findings, the Bank concluded that the dam was consistent with OP/BP 4.37. Financial Management KEGOC’s Financial Management (FM) procedures had been reviewed periodically as part the supervision of all ongoing Bank-financed transmission operations. The Bank considered the FM arrangements fully satisfactory. The major features were: (i) Sound project accounting system integrated with the corporate accounting system; (ii) Experienced and skilled project management team that includes qualified FM staff; (iii) Timely and regular submission of satisfactory interim financial reports to the Bank; (iv) Timely submission of satisfactorily audited project and entity financial statements; and (v) Effective internal control procedures that that have ensured completeness and accuracy of financial transactions. In addition, the project included: (i) regular reviews of compliance with the internal control framework; (ii) regular monitoring of activities of the Designated Accounts, including regular and timely reconciliation of the Designated Accounts with bank statements; (iii) quarterly submission of project Interim Financial Reports; (iv) audit of project financial statements by independent 9 auditors on terms acceptable to the Bank; and (v) regular FM supervision and procurement reviews. Project financial supervision missions were carried out in 2010, 2011 and 2012. All supervisions confirmed that adequate FM system, including sound internal controls had been established and KEGOC and the project were in full compliance with financial covenants under the Loan Agreement and that there were no issues with counterpart funds. KEGOC’s financial statements and the projects’ statements for 2010, 2011 and 2012 were audited by independent auditors acceptable to the Bank. The auditors issued an unmodified (clean) opinion on the consolidated entity and the project's financial statements. Procurement Procurement under the project was implemented in accordance with the Bank’s Procurement and Consultant Guidelines and in accordance with the provisions stipulated in the Loan Agreement. KEGOC ran a tight procurement process and a well-administered tender for the turnkey contract, which value was about US$2.7 million below the original cost estimate. The issue of procurement of the turnkey contractor for the line and the lengthy discussion between the Borrower and the Bank, as well as within the Bank with respect to prequalification criteria is discussed in the Section 2.1, Project Preparation, Design and Quality at Entry, subsection Design. 2.5 Post-completion Operation/Next Phase KEGOC will continue to collect information covering transmission of power from MHPP and the amount of load shedding in the Southern region of Kazakhstan as part of its normal data collection process. Recently, KEGOC has conducted discussions with the Bank on possible support for the proposed Third North-South Electricity Transmission Project. This project is included in the Bank’s FY12- FY17 Country Partnership Strategy (CPS). Such follow-up investment would strengthen the national power network and improve the reliability of electricity supply in Southern Kazakhstan. It would also provide the basis to sustain the dialogue with GOK on further sector reforms. 3. Assessment of Outcomes 3.1 Relevance of Objectives, Design and Implementation The project remains consistent with the objectives of the Bank’s CPS for FY12-17, which was designed to help the GOK implement its development priorities. As stated in the FY05-11 CPS Completion Report, relieving the infrastructure constraints to growth had been a key component of the GOK’s competitiveness agenda. The Bank has helped to finance strategic investments in the transmission sector through three consecutive loans to KEGOC. The PDOs of increasing and improving the supply of electricity to business enterprises and households in Southern Kazakhstan in an economically and environmentally sustainable manner were, and continue to be, highly relevant to the continued vigorous economic development of Kazakhstan’s rapidly growing Southern region. Kazakhstan has maintained an ongoing commitment to developing an infrastructure system to support its economic growth and social development objectives. This project was an integral part of the GOK’s electricity sector 10 development strategy for 2007-2015. Although the GOK has reduced its sovereign guaranteed borrowings in recent years, it continues to provide sovereign guarantees for KEGOC’s program of transmission system modernization and expansion, thereby demonstrating the strategic importance assigned to these initiatives. Project design and implementation were directly relevant to the above objectives. The transmission system financed under the project was indispensable for bringing the 300 MW of additional clean hydroelectricity to Kazakhstan’s Southern region. 3.2 Achievement of Project Development Objectives The development objectives of increasing and improving the supply of electricity to business enterprises and households in Southern Kazakhstan in an economically and environmentally sustainable manner were achieved. The supply of electricity to Kazakhstan’s Southern region was increased by providing the facilities required to evacuate the electricity generated by the MHPP. The first high voltage line went into operation in November 2011 and the second in August 2012 - within a couple of months of the original schedule. The project has achieved its development objective as measured by the set of monitoring indicators presented in the Data Sheet. The project has resulted in the following benefits in terms of achieving the development objectives:  MHPP’s additional 300 MW of generating capacity has contributed to the reduction of regional power deficit of the Southern Kazakhstan region.  The Southern region is expected to be provided with 1,000 GWh per year of hydroelectric power, much of which will be used to cover peak demand. MHPP has provided about 430 GWh of power in its first six months of full capacity operation.  There has been no load shedding in the Almaty power region since the project has gone on stream. While this result is attributable to the availability of MHPP, the expansion of the North-South transmission line which had been a limiting factor in the past, also contributed to the elimination of the load shedding.  It is not possible to evaluate the project’s contribution to the change in the average cost of power to the region, since it is difficult to fully access the MHPP cost data. However, a moderate downward pressure is plausible given the fact that the MHPP hydroelectricity is produced at a lower cost than the alternatives (including power supplied from the North over large distances. KEGOC has contracted with MHPP for 350 MWh of additional output (needed for making up for its transmission losses) at a price significantly lower than the cost would have been from power plants in the country’s Northern region.  MHPP’s annual output of about 1,000 GWh of electric power would replace this amount of electricity generated by coal-fired plants, thereby saving about 1.2 million tons of CO2. MHPP is expected to reach this level of output by the end of its first year of operation (i.e., end-2013). A detailed description of the benefits resulting from the implementation of the project is presented in the following sections. 11 Reduction of power deficit of the Southern region. As predicted during the appraisal of the project, the peak load in the Southern region grew from 2.8 GW to 3.5 GW over the project implementation period. As a result of this project and increase of North-South transmission line capacity the peak load of the Southern region was fully met; there were no outages or load shedding in the region. The project also led to reduced peak contribution of the inefficient heavy fuel oil Zhambyl plant. Zhambyl contributed to the peak of 817 MW in 2007. In 2012 the peak contribution reduced by about 300 MW. As a direct result of the project, commissioning of the transmission line allowed MHPP to provide 249 MW clean peak capacity to the Southern region during the peak demand in the winter of 2012.   The Southern region is expected to be provided with 1,000 GWh per year of hydroelectric power. In its first six months of operation the MHPP has provided about 430 GWh of hydroelectric power. There is a reasonable ground to expect that the Southern region will be provided with 1000 GWh annual hydroelectric generation from the MHPP. Unit 1 of the MHPP was completed and tested in November 2011, and Unit 2 - in August 2012. While monthly generation of the MHPP varied depending on the peak demand of the system and inflow of water, for six months of full availability of the MHPP from September 2012, to February 2013, the power generated by MHPP was about 429 GWh. This suggests that the Southern region will be provided with 1,000 GWh per year of clean hydroelectric power from MHPP. Saving about 1.2 million tons of CO2. The MHPP’s expected annual output of about 1,000 GWh of electric power will replace the same amount of electricity generated by coal-fired plants thereby emissions reduction of the MHPP is expiated to equal the Project appraisal target of 1.2 million tons. As there is no grid emission factor for the Kazakhstan grid approved by the United Nations Framework for Convention on Climate Change, a standard coal-fired plant emission factor was used. At the project appraisal the emission factor of a coal-fired plant was assumed at 1.2 kg CO2 /kWh, the MHPP’s expected annual is 1,000 GWh, thereby emissions reduction of the MHPP was estimated about 1.2 million tons of CO2. 3.3 Efficiency: Satisfactory The project was implemented on time and under budget. Based on current projections, the expected economic internal rate of return (EIRR) of the integrated project (MHPP and transmission) is 16 percent including the monetized economic value of the CO2 emission savings. If the CO2 savings are excluded, the EIRR is 13.6 percent. The financial internal rate of return (FIRR) to KEGOC from the transmission component alone is 20.8 percent. The FIRR is high because KEGOC receives the same price for a kWh transmitted no matter where the electricity is generated and consumed. The MHPP requires a substantially shorter transmission line than the national system’s average. Detailed assumptions of the financial analysis are in Annex 3. 3.4 Justification of Overall Outcome Rating The project is considered to have a satisfactory overall outcome rating. The project was implemented below estimated costs. The Development Objectives were achieved. The economic and financial benefits of the project have been substantial.   12 3.5 Overarching Themes, Other Outcomes and Impacts (a) Poverty Impacts, Gender Aspects, and Social Development The project is not associated with any extension of the grid that might affect the number of people receiving electricity services. Its impact is on the quality of the supply of electricity in Kazakhstan’s Southern region primarily in terms of avoiding brownouts and blackouts during periods of peak demand, as regional electricity demand, continues to grow. The avoided brownouts and blackouts in Southern region most likely will positively affect the region’s growth. While the indirect cost of brownouts and blackouts to businesses, and industries have not been assessed, unscheduled brownouts and sudden interruptions of power supply are known to cause substantial costs to all. Provision of stable supply of electricity almost inevitably will reduce of cost to power to businesses, thus it has a positive effect on the economy of the Southern region. It is also recognized that power interruptions disproportionally affect the poorest consumers which further signifies the impact of the Project on poverty. (b) Institutional Change/Strengthening: The project did not have any direct institutional strengthening component. However, the Bank’s engagement with KEGOC and the GOK in the electricity sector over many years, including the ongoing Alma Electricity Transmission project has contributed significantly to KEGOC’s operational and institutional strengthening. In this regard, Kazakhstan has become a model for other CIS countries, having created an efficient, profitable and commercially-oriented power system operator, a reasonably effective sector regulator, and a competitive power market, within the framework of an overall sound institutional and legal framework. (c) Other Unintended Outcomes and Impacts (positive or negative) None 3.6 Summary of Findings of Beneficiary Survey and/or Stakeholder Workshops Not Applicable 4. Assessment of Risk to Development Outcome: Low The overall risk to development outcome is rated as low for the following reasons:  Likelihood of not achieving development outcome due to technical risks is negligibly low. The technologies introduced under the project are well established, tested, and technically relatively simple. KEGOC’s staff is fully trained.  Likelihood of not achieving development outcome due to financial risks is low. The company’s overall financial position is solid, and there was no problem with KEGOC’s own financing of the project. The sector regulator has consistently granted tariff increases to cover KEGOC’s full operating and investment costs. While it cannot be totally excluded that future tariff increase requests might not be approved at the requested levels, transmission tariff increases of about 10 percent per year have already been approved for the next three years. 13  Likelihood of not achieving development outcome due to environmental risks is negligibly low. The EA rating of category B reflected appropriately the initial assessment that the environmental risks were of limited and manageable scope. KEGOC fully complied with the covenanted environmental protection requirements.  Likelihood of not achieving development outcome due to governance risks is low. KEGOC has benefited in the past from a strong and capable management team, which has enjoyed the support of the GOK agencies responsible for overall policy setting. As a result, the commercial focus of the company has been exemplary and political interference minimal. In February 2012, KEGOC informed the Bank that it has been included in the GOK’s “People’s IPO” program for selected major state-owned enterprises. Under this program the company shares (from 5 percent to 15 percent) will be floated on the stock market. The exact timing of the float has yet to be decided. While this development is expected to strengthen the corporate governance practice, the Initial Public Offering (IPO) may introduce a new element of uncertainty as to how KEGOC will be managed going forward.  The key factor contributing to achievement of development outcome is continued ability of the MHPP to generate at least 1,000 GWh of electricity per year, which implies an average capacity utilization of 39 percent. In the medium term, this level of utilization should not be a problem. However, in the longer term, climate change could have a possible impact on water availability for the hydropower plant. 5. Assessment of Bank and Borrower Performance 5.1 Bank Performance: Moderately Satisfactory (a) Bank Performance in Ensuring Quality at Entry: Satisfactory The project was prepared in a short time, with 10 months from the Concept Review to Board approval, and with minimal budget costs. The project was underpinned by sound technical, economic and financial analysis. It used well- tested technologies. The Bank mobilized a team with all the necessary skills including specialists in electricity markets, engineering, procurement, environment and financial management. KEGOC’s implementation, financial management and procurement capacity were judged to be adequate, as demonstrated by its performance under prior and ongoing Bank-funded transmission projects. The Bank team, recommended the hiring a project management consultant and the use of a turnkey approach for the major contract to minimize the additional work load of KEGOC’s implementation team. The Bank environmental specialist identified the limited environmental impacts and verified that the EMP had adequate arrangements for mitigation and monitoring the environmental impacts and that there was adequate public consultation during project preparation. The technical, environmental and social risk assessment was thorough and identified appropriate risk mitigation measures. While Bank considered the Borrower-suggested prequalification criteria to be restrictive as described in the section, 2.1 Design, the prequalification process failed to eliminate potentially inexperienced companies which had limited track record of implementing turnkey contracts with 14 tight schedule. As a result, the selected contractor was not able to rapidly mobilize the full team of specialized staff needed to meet this project’s critically tight implementation schedule. Borrower’s concerns with respect to inadequate prequalification proved justified; the contractor proved to be unprepared to mobilize a local team capable of implementing the Design and Supply subcontracts in an unfamiliar new country. To address the potential delay, the Borrower took over some tasks, including arrangements for detailed designs and identification of local subcontractors. (b) Quality of Supervision: Moderately Satisfactory Supervision missions were carried out at regular intervals over the three years of project implementation. Delays in the implementation schedule and the need to make up for the lost time were constant themes of supervision mission Aide-Memoirs. Most of the procurement issues were handled by the regional field office. Adherence to the EMP was monitored regularly. There were two fiduciary FM missions. The Bank maintained a collaborative relationship with the client and was regarded as a trusted partner, as indicated in the client’s assessment (Annex 7). While the Bank rigorously provided implementation support from fiduciary perspective, the Bank was not able to ensure timely preparation by the Borrower and approval of LAP. The construction of the transmission line started without approved LAP. On the other hand, the delay with the line construction would have been inadmissible. The retroactive measures implemented by the Bank and Borrower as described in the Section Social and Environmental Safeguards addressed the problem. In addition, the prequalification process failed to eliminate potentially inexperienced contractors. The Bank was fully aware of delay of preparation of the detailed design packages however, the delay was only overcome after KEGOC itself undertook the arrangements for completing the project’s detailed design packages. On December 14, 2012, the Bank agreed to extend the loan Closing Date from December 31, 2012 to April 30, 2013. This was the first and only extension requested by the Borrower. The reason for the request was that although the construction works were fully completed and the contract was to close before end-December 2012, KEGOC needed additional time to properly accept the works, carry guarantee tests, and, most importantly, obtain signed acceptance certificate from a number of competent GOK agencies. Only after the acceptance certificate was signed, could the final payment be processed. The extension met the needs of the implementing agency without compromising the project’s performance. (c) Justification of Rating for Overall Bank Performance: The overall Bank performance is rated Moderately Satisfactory due to Moderately Satisfactory rating for the Quality of Supervision. 5.2 Borrower Performance (a) Government Performance: Satisfactory The GOK considered MHPP to be of high regional and national economic importance. It was included in the 2010-2014 State Program of Accelerated Industrial and Innovative Development of Kazakhstan. The project was assessed and cleared by the Ministry of Energy and Mineral 15 Resources, the Ministry of Environmental Protection, the Ministry of Economy and Budget Planning, and the Ministry of Finance. The GOK monitored project implementation at the highest levels, including a site visit by the Prime Minister. The GOK ensured timely financing and supported the speedy construction of the MHPP.   (b) Implementing Agency or Agencies Performance: Satisfactory  KEGОС had a fully staffed, effective PMU that had extensive experience implementing Bank- financed transmission projects. To ensure that the project was implemented in the shortest time possible, KEGOC hired an international consultant to assist with writing and evaluating the bidding documents and used a turnkey contract to insure adequate coordination of all design and construction activities. It provided the financing for the Robot and Shelek substations and for the switchyard at MHPP, and ensured that they were completed on the agreed timetable. It continually pressed the turnkey contractor to meet the tight timetable for the transmission line construction and undertook key corrective tasks during the early stages of implementation to prevent a serious slippage. It developed an EMP in compliance with the IBRD requirements and the legislation of the GOK and implemented an effective environment monitoring system which included the appropriate mitigation actions at each stage of the project. The PMU supplied the Bank team with regular quarterly reports that identified problems as they arose, and worked closely with the contractors to ensure that the project was implemented on schedule. Two Bank’s FM missions found that accounting and auditing procedures were well designed and implemented, at both the project and corporate levels.   (c) Justification of Rating for Overall Borrower Performance: Satisfactory  The overall Borrower performance is rated as Satisfactory due to high proactivity, efficient and effective decision making, which led to the project implemented on schedule and at below original project cost estimates. The Borrower took necessary remedial measures to bring the project back on track following the turnkey contractor’s initial inadequate performance. The Borrower ensured that the project remained in full compliance with the Bank’s fiduciary requirements throughout project implementation and ensured that the project delivered the stated development objectives on time. All audit reports were clean, there were no environmental issues, and affected farmers were compensated for the short-term use of their land and for purchase of land permanently acquired for the project. The GOK requested, and the Bank agreed, to cancel US$2.7 of the loan proceeds because it was not needed to complete the project. 6. Lessons Learned The following three key lessons were learned from the project;  The Bank standard prequalification criteria are ill-suited for selecting a qualified contractor at a reasonable price for the turnkey design-supply-install contractor where tight delivery period is critical. For the selection of a turnkey design-supply-install contractor under a tight delivery period stricter prequalification criteria should be applied; while restricting competition, only those companies which have experience of similar turnkey contracts implemented within short period and outside of the country of their origin should be prequalified for such contracts. 16  Lack of consistent and close involvement of a qualified social scientist on the team experienced with land acquisition issues both during preparation and especially during implementation resulted in excessive delays in approving the LAP and risked the project becoming out of compliance with a safeguard covenant in the Loan Agreement. This shows that even projects that have limited land acquisition and no relocation of persons still require adequate attention and resources from the Bank’s team. It also highlights the importance of upfront technical assistance and capacity building to the client.  As with most Bank projects, the development of long relationships with the implementing agency helped to create mutual trust and understanding, which in turn facilitated resolution of problems that arose during the course of project implementation.  Early consultation with NGO community helps to avoid project implementation problems. During project preparation, it proved to be critically important to engage the NGO community, and to take into account in the final project design their justified concerns. In this project, NGOs expressed concerns about the initial routing of the two transmission lines. The result was a timely rerouting decision which ensured that the lines did not encroach upon the GOK-defined Specially Protected Natural Areas. 7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners (a) Borrower/implementing agencies No issues were raised by the Borrower   (b) Cofinanciers Not applicable   (c) Other partners and stakeholders Not Applicable 17 Annex 1. Project Costs and Financing (a) Project Cost by Components in US Dollars Equivalent Appraisal Percentage of Components Estimate Actual Appraisal A. Transmission lines 45.8 44.0 96 B. Substations 21.1 18.8 89 C. Consultancy and technical services 2.5 2.5 99 Total Baseline Cost 69.4 65.3 94 Physical Contingencies 0 0 Price Contingencies 0 0 Total Project Cost Front-end fee for IBRD 0.2 0.2 100 Total Financing Required 69.6 65.6 95 (b) Financing Source of Funds Appraisal Actual Percentage of Estimate Appraisal Borrower 23.6 20.8 88 IBRD 46.0 44.7 97 18 Annex 2. Outputs by Component The transmission line and associated substations and the outdoor switchyard (OSY) needed to evacuate power from the MHPP hydropower generating plant was completed on schedule at the end of 2012. The project components were: Component A – Construction of Transmission Lines with the following subcomponents: A1 – Construction of single-circuit Overhead Transmission Line (OHTL) from MHPP to Shelek SS: The OHTL exits the OSY at MHPP and heads North to the Shelek SS. It goes across the Yenbeksh- Kazakhsky territory in the region of Almaty. The 220 kV OHTL has a length of about 97 km. The design contemplates aluminum conductor steel reinforced, with cross-sectional areas of 394 mm2 of aluminum and 51.1 mm2 of steel. It is lightning protected by means of an overhead ground wire along the entire transmission line. A2 – Construction of single-circuit OHTL from MHPP to Robot SS: The OHTL exits the OSY at MHPP and heads North to the Shelek SS and from there to the Robot SS. It crosses the Yenbekshy-Kazakhsky, Ilisky and Talgarsky territory in the region of Almaty. The 220 kV OHTL has a length of about 225 km. Component B – Modernization of Substations with the following subcomponents: B1 – Construction of 220/110 kV OSY at MHPP: An OSY with a configuration consisting of double main busbars and transfer bus with single circuit breakers was built at the MHPP. B2 – Modernization of Robot SS Installation of new high voltage equipment in the reserve bay for the 220 kV OHTL MHPP – Robot SS and replacement of the high voltage equipment: circuit breakers, disconnect switches, surge arresters, and current and voltage transformers, as well as control and protection equipment. B3 – Modernization of Shelek SS Revamping of the existing 220 kV, 110 kV, and 35 kV switching arrangements, including replacement of main switching equipment including: circuit breakers, disconnect switches, busbars, current and voltage transformers, and control and protection equipment. Component C – Consulting and Technical Services with the following subcomponents: C1 – Procurement and project management Procurement and project management consulting services for the construction of the OHTLs, construction of the OSY at MHPP, modernization of the Robot SS and Shelek SS. Responsibilities of the consultant include: preparation of the bidding documents and technical 19 specifications, construction supervision, quality control and monitoring of all executed work, verification of contractor’s payments and reporting to KEGOC and the Bank. Component C – Consulting and Technical Services with the following subcomponents: C1 – Procurement and project management Procurement and project management consulting services for the construction of the OHTLs, construction of the OSY at MHPP, modernization of the Robot SS and Shelek SS. Responsibilities of the consultant include: preparation of the bidding documents and technical specifications, construction supervision, quality control and monitoring of all executed work, verification of contractor’s payments and reporting to KEGOC and the Bank. 20 Annex 3. Economic and Financial Analysis Economic and Financial Rate of Return General Approach. The project’s economic benefits have to be evaluated in the context of the overall scheme of delivering power from the MHPP to customers in the Southern region of Kazakhstan. The scope of costs therefore extends beyond those directly associated with the construction and operation of the new transmission facilities to include the other capital and operating expenditures that are required to provide this electricity service to the end user. Thus, although the Bank-financed investment covered only the transmission lines for the MHPP, the economic and financial analysis at the time of appraisal considered the two components as an integrated single entity and evaluated them as such. This same approach has been adopted for the ex-post evaluation. Benefits are also viewed from the perspective of the end-user. These benefits include the value which the customers attribute to incremental electricity supply which can be measured in terms of their willingness to pay for electricity. In Southern Kazakhstan, where virtually all households and businesses have access to grid-based electricity supply, the measurement of willingness to pay takes into account the basic tariff and the presumed willingness to pay for peak power. Both the PAD and this ICR has assumed that the peak power provided by MHPP has an added value to consumers beyond that indicated by the tariff. However, unlike the PAD, the ICR analysis does not consider the cost associated with load shedding, since there was no reported load shedding at the time of project completion. The sections below provide details of the major assumptions used with respect to the measurement of project costs and benefits. The analysis is based on the data KEGOC provided on the actual investment costs for their transmission project, the associated operating costs, and on KECOG’s projections for future MHPP output and peak power supply. The MHPP did not provide its actual cost data, because they consider this data to be proprietary. (The plant is partially privately owned.) The ICR therefore relied on the data about the MHPP that was used in the ex-ante analysis in the PAD. Project Costs. For the economic analysis, the project costs were assumed to include the following: (i) the financial capital cost of both project components (power plant and transmission), excluding all taxes; (ii) annual operating and maintenance costs for each project component, including wages, materials excluding property taxes; (iii) periodic major maintenance of lines and SSs; and (iv) the cost of technical losses on incremental volumes transmitted on the new transmission lines. Benefits from the reduction in CO2 emissions were included. Economic benefits from producing peak power were included but benefits from load shedding were excluded because of the actual lack of such curtailments due to the completion of the second North-South interconnector. The major differences between the PAD calculations and those of the ICR are: (i) the transmission project’s actual costs are used; (ii) unserved demand has been reduced to zero because the recent introduction of the second North-South transmission line has greatly reduced the likelihood of unserved energy demand; (iii) actual production figures were used to 2012 and projected for 2013; (iv) the percentage of MHPP output produced at peak times of the day was recalculated using KEGOC’s assumptions about the MW output they will need for each month. In months where their power utilization is assumed to be more than an average of 100 MW, the ICR 21 analysis has assumed that all the output is used to cover peak demand. This methodology leads to an estimate of total peak generation of 71 percent, up from the 48 percent estimated in the PAD. Based on the above assumptions and methodology, the estimated EIRR of the integrated project is 16.0 percent when the benefits attributed to CO2 reduction are included. This compares with an estimated EIRR of 17.2 percent in the PAD. If the CO2 reduction benefits are excluded, the EIRR is 13.6 percent. Financial Analysis. The major difference between the economic and financial analysis is that the latter focuses exclusively on KEGOC’s financial return from the transmission component. It is based on the same data set as that of the economic analysis, but only with KEGOC’s investment and operating costs for the transmission project component. All taxes are included. The ex-post FIRR is 20.8 percent. This compares with an estimated FIRR of 13.3 percent in the PAD. MHPP Generation in MWh Actual Generation 2012 Actual/Planned Generation 2013 Planned/ 1st Gen 2ed gen 1st Gen 2ed gen Total Planned Used for Unit Unit Total Gen Unit Unit Gen Generation Peaking January 4,477 4,477 39,820 22,949 62,769 70,000 61,000 February 1,522 5,671 7,193 35,572 27,029 62,601 67,000 61,000 March 0 16,123 16,123 29,519 30,601 60,120 66,000 61,000 April 22,074 951 23,025 93,000 61,000 May 52,884 13,422 66,306 102,000 61,000 June 11,462 35,910 47,372 168,000 61,000 July 12,224 13,175 25,399 117,000 61,000 August* 56,427 69,849 126,276 79,000 61,000 September 30,503 66,413 96,916 53,000 53,000 October 25,589 40,246 65,835 61,000 61,000 November 24,479 55,988 80,467 74,000 61,000 December 53,108 38,335 91,443 75,000 61,000 Yearly total 1,025,000 724,000 *Commissioning of the second transmission line 22 Ex-Post Financial Rate of Return Moinak Transmission Component EX POST Financial Rate of Return Calculations Assumptions 2008 2009 2010 2011 2012 2013 2014 2015‐35 Transmission losses (%) KEGOC 6.5% 6.5% 6.5% 6.5% End‐user tariff, Households, including VAT (a)   KZ/KWhPAD 9.37 9.37 9.37 9.37 1.12 1.29 1.49 1.66 End‐user tariff, Non‐residential, including VAT (a)  KZ/KPAD 7.08 7.08 7.08 7.08 1.12 1.29 1.49 1.66 Household share  of total  consumption PAD 0 Peak Premium (% of base tariff) PAD 210% **'Current Purchase price of losses (KZT/kWh) PAD 4.81 **'Moinak Price of Losses (KZT/kWh) PAD 3.49 Moinak Construction Period (months) & pecentage per year PAD 33 *Moinak HPP - Capital Cost (KZT milion) PAD 51,000 20% 40% 20% 14% **HPP Operating Cost (KZT/kWh) PAD 0.80 Distribution Costs (KZT/kWh) PAD 3.56 2.72 Avoided Carbon Emissions PAD 1.15 million tons/yr Peak power as a percentage  of output KEGOC* 71%   Output Generation (GWh) KEGOC 1012 actual  1013 projected 501 978 978 978 Transmission Losses (compensated by KEGOC) KEGOC 1012 actual  1013 projected 0 ‐33 ‐64 ‐ 64 ‐64 Transmission Volumes KEGOC 1012 actual  1013 projected 0 468 914 914 914 Sales End‐User Sales  GWh Derived 0 468 914 914 914 of which Peak GWh Derived 333 649 649 649    Base  load GWh Derived 136 329 329 329 Net Economic Cash Flow (million KZT) Costs   0 2058 4116 3087 1147 226 226 226 Benefits 0 0 0 0 3223 2057 2368 2682 Net Cash Flow 0 ‐2058 ‐4116 ‐3087 2076 1831 2142 2456 IRR 20.8% Capital  Cost of Transmission Interconnector (millions KKEGOC 10290 2058 4116 3087 1029 0 Operating Costs (million KZT) Transmission O&M ‐ New Line Wages (million KZT/yr) 3 3 3 3 Materials (million KZT/yr) 13 2 2 2 2 Line  Overhaul  (million KZT/yr) 0 Marginal  Cost of losses 114 222 222 222 Total  Operating 0 0 0 0 118 226 226 226 Benefits Household WTP, base  load  0 68 191 220 246 Commercial/industry WTP, base  load 0 84 234 269 301 WTP Premium for Peak Power ‐ households 0 352 793 911 1021 WTP Premium for Peak Power ‐ commercial  /industry 0 2720 839 969 1114 Avoided CO2 Emissions 0 0 0 0 Total  Benefits 3223 2057 2368 2682 23 Economic Internal Rate of Return (EIRR)  Kazakhstan Southern Transmission Project Moinak Transmission Component EIRR Assumptions 2008 2009 2010 2011 2012 2013 2014 2015 2016‐35 Transmission losses  (%) KEGOC 6.5% 6.5% 6.5% 6.5% 6.5% 6.5% 6.5% 6.5% 6.5% Distribution losses  (%) PAD 10% End‐user  tariff, Households, including VAT (a) PAD 9.37       9.37         9.37         9.37         9.37       9.37       9.37       9.37       9.37 9.37         End‐user  tariff, Non‐residential, including VAT (a PAD 7.08       7.08         7.08         7.08         7.08       7.08       7.08       7.08       7.08 7.08         Household share of total  consumption PAD 45% Peak Premium (% of base tariff) PAD 210% **'Current Purchase price of losses (KZT/kWh) PAD 4.81 **'Moinak Price of Losses (KZT/kWh) PAD 3.49 Moinak Transmission Construction Period KEGOC 10% 50% 40% *Moinak HPP - Capital Cost (KZT milion) KEGOC    51,000 20% 30% 40% 14% **HPP Operating Cost (KZT/kWh) KEGOC         0.80 Distribution Costs (KZT/kWh) PAD         3.56         ‐ Opportunity Cost of Capital PAD 8% *'Avoided Load Shedding ‐ Almaty Oblast (MW) KEGOC 0         ‐         ‐         ‐         ‐ ‐           Total  Unserved Energy ‐ GWH @  hrs/yr KLEGOC 0         ‐         ‐         ‐         ‐ ‐           Cost of Unserved Energy (KZT/kWh) PAD 43.25                ‐         ‐         ‐         ‐ ‐           Avoided Carbon Emissions  (Tons/GWh) PAD 1,200 Value of Avoided Emissions  US$/ton Assumption $10 Peak power  percentage of output KEGOC* 71%   Capital Costs (million KZT) HPP Construction (to completion) PAD 0 10200 15300 20400 7140 0 *Transmission system KEGOC 9296 930 3719 4648 0   of which VAT KEGOC 1184 0 ‐118 ‐592 ‐474 0 Total  Capital 0 10200 16111 23527 11315 0 0 0 0 Operating Costs (million KZT) Transmission O&M ‐ New Line Wages (million KZT/yr) 2.74      2.74      2.74      2.74      2.74        Materials (million KZT/yr) 12.73       1.66      1.66      1.66      1.66      1.66        Line  Overhaul  (million KZT/yr) 0.01302 Marginal  Cost of losses 114                 222         222         222        222 Distribution Costs          ‐    1,503    2,934    2,934    2,934    2,934 Total  Operating        ‐          ‐          ‐          ‐    1,621    3,160    3,160    3,160    3,160 Incremental Output Generation  GW.h   501.00 978.00     978.00   978.00  978.00 Transmission Losses (compensated by KEGOC) GW.h          ‐  (32.57)  (63.57)  (63.57)  (63.57) (63.57)    Transmission Volumes GW.h          ‐ 468.44   914.43     914.43   914.43  914.43 Distribution Losses  GW.h          ‐  (46.84)  (91.44)  (91.44)  (91.44) (91.44)    End‐User Sales GW.h          ‐   421.59   822.99   822.99 822.99    822.99 of which Peak GW.h 299.33   584.32     584.32   584.32  584.32    Base  load GW.h   122.26 393.68   393.68   393.68    393.68 Benefits Household WTP, base  load           ‐ 515            1,660    1,660    1,660    1,660 Commercial/industry WTP, base  load          ‐ 476            1,533    1,533    1,533    1,533 WTP Premium for Peak Power ‐ households          ‐    2,650    5,173    5,173    5,173    5,173 WTP Premium for Peak Power ‐ commercial  /industry          ‐    2,448    4,778    4,778    4,778    4,778 Avoided Outages             ‐             ‐             ‐             ‐             ‐ Avoided CO2 Emissions 908            1,772    1,772    1,772    1,772 Total  Benefits    6,997 14,916     14,916   14,916  14,916 Net Economic Cash Flow (million KZT) Costs          ‐ 10200   16,111     23,527   12,936    3,160    3,160    3,160    3,160 Benefits        ‐ 0                ‐               ‐    6,997   14,916 14,916     14,916  14,916 Net Cash Flow        ‐    (10,200) (16,111)  (23,527)  (5,939) 11,756      11,756 11,756  11,756 IRR 16.0% NPV   40,084 24 Annex 4. Bank Lending and Implementation Support/Supervision Processes (a) Lending Task Team Members Appraisal team Names Title UNIT Specialty Istvan Dobozi Task Team Leader ECSSD Energy Economist Sergio Gonzales Sr. Power Engineer ECSSD Power Engineer Imtiaz Hizkil Sr. Power Engineer ECSSD Power Engineer Margaret A. Wilson Financial Analyst Consultant Finance Yuling Zhou Sr. Procurement Specialist ECSPS Procurement Bernard Baratz Environmental Specialist Consultant Environment Hannah Koilpillai Sr. Finance Officer LOAFC Finance John Otieno Ogallo Sr. Financial Mgmt Specialist ECSPS Finance Danielle Malek Counsel LEGEM Legal Janna Ryssakova Social Development Specialist ECSSD Social Development Josephine Kida Program Assistant ECSSD Program Assistant Supervision/ICR task team members Arcadii Capcelea Sr Environmental Specialist ECSEN Environmental Safeguards Aliya Kim Finanical Management Analyst ECS03 Finance Sunil Kumar Khosla Lead Energy Specialist ECSEG Energy Economist Aliya Karakulova Operations Officer ECSTR Operations Anara Akhmetova Procurement Assistant ECCKZ Procurement Arcadii Capcelea Senior Environment Specialist ECSEN Environmental Safeguards Imtiaz Hizkil Sr Power Engineer ECSEG Power Engineer Istvan Dobozi Consultant MNSEG Energy Economist John Otieno Ogallo Sr Financial Mgmt Specialist ECSO3 Financial Management Joseph Melitauri Senior Operations Officer ECSEG Operations Joseph Paul Formoso Senior Finance Officer CTRLA Disbursement Mirlan Aldayarov Task Team Leader ECSEG Energy Economist Nurbek Kurmanaliev Procurement Specialist ECSO2 Procurement Ignacio Jauregui Counsel LEGLE Legal Regina Nesiama Senior Program Assistant ECSSD Program Assistant Richard Berney Consultant ECSEG Energy Economist Roxanne Hakim Sr Anthropologist ECSSO Social Safeguards Yelena Yakovleva Team Assistant ECCKZ Team Assistant Yolanda Litan Gedse Program Assistant ECSSD Program Assistant 25 (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) Appraisal FY 09 18.48 $ 77,104 FY 10 2.30 $ 17,611 Sub Total 20.78 $ 94,715 Supervision/ICR FY10 6.32 $ 53,009 FY11 10.90 $ 79,734 FY12 11.37 $ 113,099 FY13 14.21 $99,452 SubTotal: 42.80 $345,294 26 Annex 5. Beneficiary Survey Results Not Applicable 27 Annex 6. Stakeholder Workshop Report and Results Not Applicable 28 Annex 7. Summary of Borrower's ICR and/or Comments on Draft ICR Under the accelerated industrial and innovative development program of the Government of Kazakhstan (GOK), the Moinak Electricity Transmission Project was one of the important strategic investment projects for the electric power industry. The Project’s implementation was pursuant to the issue of GOK Decree No. 161 dated 22 February 2005 “On additional measures for development of hydroelectric industry in the Republic of Kazakhstan” and GOK Decree No. 1143 dated 21 November 2005 “On construction of Moinak hydroelectric power plant.” Relevant additional GOK measures included the Prime Minister Order No. 147 dated 31 May 2007 “On approval of Action Plan for the development of the electric power industry in the Republic of Kazakhstan for 2007-2015” and the “List of electric power facilities subject to upgrade, rehabilitation and extension,” as well as GOK No. 1129 dated 29 October 2010 “On approval of the programme for development of the electric power industry for 2010-2014 and Order of the President No. 958 dated 19 March 2010 “On State Programme of Accelerated Industrial and Innovative Development of Kazakhstan for 2010- 2014”. The Moinak Electricity Transmission Project was considered to be of great regional and national importance. The main objective of the Project was to ensure the transmission of the electric power from the 300 MW Moinak hydropower plant (MHPP) constructed on the Charyn River in the Raimbek district of the Almaty Oblast. The MHPP aimed to reduce capacity and electric energy deficit, cover peak loads, and secure reliable electricity supply to the Almaty Oblast and Southern Kazakhstan. Project implementation covered the period 2009-2012. All GOK-required expert assessments were performed and positive opinions were obtained for the Feasibility Study of the Project. The key assessments were as follows:  Sectoral expert assessment, Ministry of Energy and Mineral Resources;  State expert assessment, Republican State Enterprise GosExpertiza;  Environmental expert assessment, Ministry of Environmental Protection;  Bank expert assessment, Development Bank of Kazakhstan;  Economic expert assessment, Ministry of Economy and Budget Planning; and.  Financial expert assessment, Ministry of Finance. On 14 November 2008 and 2 October 2009, public hearings on environmental protection were held in the city of Almaty. The following measures were included in the Project: • Construction of 220 kV OHTL financed from borrowed funds including: - Construction of 220 kV OHTL from 220 kV outdoor switch yard (OSY) at MHPP to 220 kV Shelek substation [SS] (97.73 km); - Construction of 220 kV OHTL from 220 kV OSY at MHPP to 220 kV Robot SS (227.78 km); and 29 - Construction of two 220 kV transmission lines from 220 kV OSY at MHPP to MHPP (first circuit: 0.484 km, second circuit: 0.553 km). • Construction and provision of the following additional facilities and equipment from KEGOC's own: - Construction of 220 kV OSY at MHPP; - Rehabilitation and extension of 220 kV outdoor switchgear (OSG) at 220/110/10 kV Robot SS; - Rehabilitation and extension of 220 kV OSG at 220/110/10 kV Shelek SS; - Provision of required relay protection and automation devices as well as emergency automation; and - Provision of dispatch and process control devices. Under the Project, training courses were provided to KEGОС personnel. From 2011 to 2012, 18 employees of the company were trained in the course of the project implementation under the contract with the vendor. From 2011 to 2012, 28 employees participated in factory tests of transmission line equipment and FOCL. Pursuant to the terms and conditions under which loan proceeds were provided by IBRD, KEGОС developed an Environmental Management Plan (EMP). The plan was prepared in compliance with IBRD requirements and legislative provisions of the Republic of Kazakhstan relating to environment protection. As a result, the company implemented an effective environment monitoring system and carried out the required mitigation actions at each stage of the Project. The national importance of the Project was highlighted by the fact that on 31 October 2012 the Prime Minister of the Republic of Kazakhstan made a site visit to assess the progress for the construction of 220 kV high voltage transmission lines MHPP – Shelek SS. The total amount of loan proceeds (US$48 million) was obtained from IBRD to finance the Project, of which US$ 44.7 million was actually disbursed. To liaise with IBRD and the main companies involved in the Project, a team of highly qualified personnel specializing in technical, commercial, financial and communication issues was formed within KEGOC. One of the factors allowing successful Project implementation was the corporate and Project governance in place in accordance with the best international practice. KEGOC believes that to a large extent Project implementation was a success because of the IBRD Project team, which consisted of highly professional specialists in finance, economics, engineering and procurement. Thanks to the timely and professional assistance of the World Bank specialists at all Project stages, it was possible to solve the encountered problems effectively and in a timely manner. Selection of the consulting company for procurement and Project management under the “turn- key” contract (design, construction and commissioning of transmission lines) was carried out in compliance with the rules and procedures of IBRD. 30 The supply of high-voltage equipment and construction/assembly works at the SSs were financed from KEGOC’s own funds. In 2011, based on the audit results of the Integrated Management System of KEGOC, SO NDC, nine branches of the interregional electric networks (MES) and Energoinform JSC, the Integrated Management System of KEGOC were confirmed as complying with the requirements of ISO 9001-2008, ISO14001-2004 and OHSAS 18001-2007. The validity period of ISO 9001-2008 and ISO14001-2004 certificates was extended for the next three years. During implementation of the Project, KEGOC took into account and used the project management and monitoring experience acquired during implementation of the Electricity Transmission Rehabilitation Project and the second North-South Transmission Line Project funded from IBRD loans. Successful implementation of the Moinak and previous two projects as well as KEGОС’s reputation as a reliable and financially stable partner, enabled the company to mobilize financial resources from other international financial institutions to implement new investment projects. Finally, in terms of lessons learned under the Project, the main issues to be taken into consideration for future investment projects include the following: - In terms of time and cost efficiency, the best approach for large-scale and complex projects is turn-key contract. - During the prequalification of companies, the eligibility criterions should include the requirement of similar project experience outside the country of the potential contractor, as well as work experience in the given region and similar climatic conditions. - For the purpose of more effective procurement, it must be taken into account that achievement of the bidding stage deadlines (approval of prequalification evaluation reports [bid results], short-listing, etc.) is heavily affected by the bureaucratic procedures of IBRD. - Exchange rate fluctuations can result in an unplanned increase of expenses. - During preparation of tender documentation for the selection of contractors under the construction project, the corresponding standard IBRD documents are to be used. To bring the standard conditions of the tender document (the contract, in particular) into compliance with laws of the Republic of Kazakhstan, there is a possibility to correct the general conditions by means of the special conditions. However, IBRD does not always approve the amendments proposed by KEGOC based on the previous lesson learnt during the selection of the contractor and implementation of the signed contracts. Therefore, it is advised that IBRD take more seriously into account the KEGOC’s proposed amendments, realizing that KEGOC and IBRD are mutually interested in the selection of an experienced contractor and implementation of the contracts in a timely manner within the allocated budget. In the general conditions of the contract, the possibility to apply penalties for late submission of the documentation and violation of delivery time of equipment and materials by the contractor (which may adversely affect the final completion date of Project facilities) shall be taken into account. 31 - During Project preparation and implementation, the translation of materials (English/Russian) for KEGOC’s internal review and submission to the corresponding regulatory and oversight state bodies of the Republic of Kazakhstan is required. Therefore, in future the time for translation of documents during their preparation must be explicitly taken into account. The quality of translation is critical for effective interaction with the various Project partners and stakeholders, particularly with regard to the financial, legal and technical terminology. 32 Annex 8. Comments of Cofinanciers and Other Partners/Stakeholders Not Applicable 33 Annex 9. List of Supporting Documents  Project Appraisal Document  Loan Agreement between IBRD and Joint Stock Company “Kazakhstan  Electricity Grid Operating Company, dated November 12, 2009  Guarantee Agreement between Republic of Kazakhstan and IBRD, dated November 12, 2009  Project Implementation Plan  Implementation Status Reports  World Bank Mission Aide-Memoires  KEGOC Annual Reports, 2007-2012  Statistical Digest “Regions of Kazakhstan”, Statistical Agency of the Republic of  Kazakhstan, 2011  Integrated Safeguards Datasheet, August 2009  Project Information Document, November 2008  Environmental Management Plan, June 2009  Land Acquisition Policy Framework, June 2009  Kazakhstan Country Partnership Strategy for FY12-FY17  Kazakhstan Country Partnership Strategy, FY05-FY11 Completion Report 34 IBRD 36700 60° 70° 80° 90° KAZAKHSTAN RUSSIAN FEDERATION MOINAK ELECTRICITY TRANSMISSION PROJECT To TUMEN PROJECT COMPONENTS: FUTURE EXISTING SUBSTATIONS: 220 kV LINE NATIONAL CAPITALS To KURGAN TAVRICHESKAYA PETROPAVLOVSK KAZAKHSTAN 1150 kV SWITCHYARD INTERNATIONAL (PP TETS-2) To KARASUK BOUNDARIES TR.GRES IRTYSHSKAYA 500 kV 220 kV SUBSTATIONS AURORA ' FUTURE EXISTING To BARNAUL Ob 220 kV TRANSMISSION LINES: To MAGNITOGORSK THERMAL POWER PLANTS 1150 kV KUSTANAISKAYA KOKCHETAVSKAYA To BARNAUL 500 kV HYDRO POWER PLANTS 220 kV AKSU ES RUTSOVSK To MAGNITOGORSK PAVLODAR To GOLOVNAYA To KINEL SOKOL RUDNENSKAYA TETS MAKINSK KEZ To BAES EKIBASTUZSKAYA 50° Ir t LISAKOVSKAYA h ys EGRES-1,2 Ur a 50° l IR.GRES ZHITIKARA ALTYNSARINO AGPP OSKEMEN UZLOVAYA N.TROITSK ESSIL STEPNAYA GTES KPK ORSK BULAKSKAYA HPP ASTANA URALSKAYA TETS AKMTETS-1 PRAVOBEREZHNAYA ULKE SS-18 SHHPP GTS AKTURBO KIMPERSAI BATYS U-LHPP Zhaiy ATETS AKMTETS-3 CHERBAKOVSKAYA DOSTYK NURA SHYGYS k (Ural) GTES SNSP “AKTOBEMUNAIGAS” OSAKAROVKA ZPMK KANDYAGASHSKAYA GTES ZHARYK CHILISAI VOSTOCHNAYA KAR.GRES-2 KAR.TETS-4 Lake INDER ZHANAZHOLSKAYA GTES Zaisan MAKAT K A Z A K H S T A N AYAGUZ Vo lg AKTOGAI a ATETS GTES AGIP KCO BALKHASH AGADYR ATYRAU SS GTES KASHAGAN ZHEZKAZGAN KARAZHAL MOINTY BALKHASHSKAYA BALKHASHSKAYA TETS KULSARY ZHEZKAZGANSKAYA TETS TENGIZ ARALSKAYA Lake SARY-SHAGAN Balkash TALDYKORGANSKAYA TETS GTES TSHO KUMKOL (144,480,PVP) AITEKE-BI GTES KUMKOL (NOVOKAZALINSK) For detail, see inset below left GTES KALAMKAS BALKHASHSKAYA TETS KARAZHANBAS TALDYKORGANSKAYA SS BEINEU Aral YUKGRES ZSCHA SS Sea Altyn-Emel AKTAUSKAYA National Park KERBULAKSKAYA SARYOZEK SS AES KZYL-ORDINSKAYA HPP KAPCHAGAISKAYA HPP 220kV TRANSMISSION LINES AKTAU CHINA GPP-1 ROBOT SS SHELEK SS SHU-500 Charyn National Park KOTETS-6 ALMATY KOGTETS SWITCHYARD ATETS-3 SS ZAPADNAYA MOINAK HPP TALDYKORGANSKAYA SS KENTAU KENSAI SS UZEN Sy ZHAMBYL ZHAMBYLSKAYA GRES ZSCHA SS r- D BURNOYE ERMENSAI SS BISHKEK ar ya BISHKEK Lake Issyk-Kul CHINA SARYOZEK SS K-BALTY Caspian Altyn-Emel TULKUBAS To KURPSAISKAYA HPP TETS yn KERBULAKSKAYA National SHYMKENT Nar AZERBAIJAN Se a HPP Park SHTETS-1,2,3 KYRGYZ 40° 40° BAKU KAPCHAGAISKAYA HPP NO. 62 SS SHELEK Charyn National REPUBLIC 220kV TRANSMISSION SS Park TASHKENT TU RKME NISTAN ROBOT SS LINES SHARDARINSKAYA HPP TASH.GRES ATETs-3 SS PROJECT AREA UZBEKISTAN 0 100 200 300 SWITCHYARD FERUZ KENSAI SS KILOMETERS MOINAK HPP TASHKENT This map was produced by the Map Design Unit of The World Bank. The boundaries, colors, denominations and any other ERMENSAI SS information shown on this map do not imply, on the part of The World Bank Group, any judgment on the legal status of 50° KYRGYZ REP. TAJIKISTAN 70° any territory, or any endorsement or acceptance of such boundaries. JULY 2009