ASIAN DEVELOPMENT BANK RRP: TAJ/UZB 35096
REPORT AND RECOMMENDATION
OF THE
PRESIDENT
TO THE
BOARD OF DIRECTORS
ON
PROPOSED LOANS
TO THE
REPUBLIC OF TAJIKISTAN
AND TO THE
REPUBLIC OF UZBEKISTAN
FOR THE
REGIONAL POWER TRANSMISSION MODERNIZATION PROJECT
November 2002 CURRENCY EQUIVALENTS (as of 15 November 2002) Tajikistan Currency Unit – somoni (TJS) TJS1.00 = $0.3390 $1.00 = TJS2.95
Uzbekistan Currency Unit – sum (SUM) SUM1.00 = $0.0012 $1.00 = SUM856
ABBREVIATIONS
ADC – area dispatch center DMC – developing member country EA – executing agency EIRR – economic internal rate of return FIRR – financial internal rate of return GDP – gross domestic product IAS – International Accounting Standards LRMC – long-run marginal cost MOE – Ministry of Energy NDC – National dispatch center O&M – operation and maintenance PIU – project implementation unit PSC – project steering committee SCF – standard conversion factor TA – technical assistance UDC – unified dispatch center USAID – United States Agency for International Development
WEIGHTS AND MEASURES
kV (kilovolt) - 1,000 volts kW (kilowatt) - 1,000 watts MW (megawatt) - 1,000,000 watts GW (gigawatt) - 1,000,000,000 watts kWh (kilowatt-hour) - 1,000 watt-hours GWh (gigawatt-hour) - 1,000,000 kWh TWh (terawatt-hour) - 1,000,000,000 kWh t (metric ton) - 1,000 kilograms toe (ton of oil equivalent) - 10,000,000 kilocalories mtoe (million tons of oil equivalent) - 1,000,000 toe
NOTES
(i) The fiscal year (FY) of the governments and their agencies ends on 31 December. (ii) In this report, "$" refers to US dollars.
This Report was prepared by a team consisting of: S. O'Sullivan (Team Leader), R. Clendon, S.Hasnie, X. Humbert, and H.Y. Hong.
CONTENTS Page LOAN AND PROJECT SUMMARY ii MAP vii I. THE PROPOSAL 1 II. RATIONALE: SECTOR PERFORMANCE, PROBLEMS, AND OPPORTUNITIES 1 A. Performance Indicators and Analysis 1 B. Analysis of Key Problems and Opportunities 2 III. THE PROPOSED PROJECT 6 A. Objectives 6 B. Components and Outputs 6 C. Special Features 6 D. Cost Estimates 10 E. Financing Plan 10 F. Implementation Arrangements 11 G. The Executing Agencies 14 IV. PROJECT BENEFITS, IMPACTS, AND RISKS 16 A. Financial and Economic Benefits 16 B. Regional Benefits of Trade 17 C. Social and Poverty Impact 18 D. Environmental Impacts 20 E. Project Risks 20 V. ASSURANCES 21 A. Specific Assurances 21 B. Conditions of Loan Effectiveness 22 VI. RECOMMENDATION 23 APPENDIXES 1. Project Framework 24 2. Central Asian Power System 26 3. Problem Analysis 28 4. External Assistance 29 5. Detailed Technical Scope 30 6. Regional Power Trade 32 7. Regional Power Trade Action Plan 33 8. Detailed Cost Estimates 35 9. Project Implementation Schedules 37 10. Procurement Lists 39 11. Terms of Reference for Project Implementation Consulting Services 41 12. Power Sector Reform 45 13. Financial Performance and Projections 46 14. Power Sector Management Information System Terms of Reference 51 15. Financial and Economic Analysis 53 16. Summary Poverty Reduction and Social Strategy 59 17. Summary Initial Environmental Examination 60
LOAN AND PROJECT SUMMARY
Borrowers The Republic of Tajikistan and the Republic of Uzbekistan
Classification Thematic: Economic growth, regional cooperation Poverty classification: Other
Environment Category B. An initial environmental examination was undertaken; Assessment the summary is a core appendix.
Project Description The Project will improve the reliability and the operation of the Central Asian power transmission system, enhance intercountry power trading, and establish the foundation for a future wholesale regional power market.
Rationale Regional cooperation among the countries of Central Asia is required to develop their economies. An adequate and reliable power supply is essential to support economic growth. The Central Asian power system comprises interconnected high- voltage links encompassing southern Kazakhstan, Kyrgyz Republic, Tajikistan, Turkmenistan, and Uzbekistan. The main transmission lines link the power systems of the five countries for parallel operation. The system shares common operational and service management, planning, information channels and control, and connects 83 power plants, including 29 thermal and 48 hydropower plants, with a total installed capacity of about 25,000 megawatts. The unified dispatch center (UDC) in Tashkent is responsible for maintaining the balanced and synchronized operation of the power transmission and distribution systems of the five countries. Following the dissolution of the Soviet Union in 1991, the countries maintained balanced and synchronized operation to allow import and export of electricity among them. Market-oriented issues increasingly play a major role in power system management. However, the regional technical operation protocols are less respected and funds for maintenance and rehabilitation have been limited. Each country has been focusing more on power self-sufficiency rather than establishing a competitive regional market that would achieve economically efficient patterns of trade. It is, however, increasingly accepted in Central Asia that there are mutual benefits in exploiting complementary energy resources on a regional basis.
Objective, Outputs, and The Project will improve the operation and efficiency of the Components regional power transmission system and enhance economic regional power trade and cooperation among the Central Asian republics. Under the Project, the focus will be on modernizing the transmission systems of Tajikistan and Uzbekistan and enhancing the power trade relations between them. The Project will be the first stage of an assistance program to promote regional energy cooperation. The project outputs will be as follows:
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(i) Rehabilitated 500-kilovolt (kV) substations and switchgear. Replace circuit breakers (500 and 220 kV), current and voltage transformers, protection and control systems, and the direct current system. (ii) Upgraded dispatch and communications facilities. Upgrade facilities at UDC, national dispatch centers and area dispatch centers, and telecommunications links. Install new remote terminal units in 500 kV substations and in major power plants. (iii) New meters. Install new transborder metering together with meter management systems at all dispatch centers. (iv) Improved policy, institutional, and regulatory environment. Implement a Regional Power Trade Action Plan and a bilateral Power Trade Relations Agreement.
Cost Estimates The total project cost is estimated at $175.5 million. The Tajik component is estimated to cost $27.0 million equivalent (foreign exchange cost $22.4 million, local currency cost $4.6 million equivalent), and the Uzbek component $148.0 million equivalent (foreign exchange cost $137.6 million, local currency cost $10.4 million equivalent) and regional TA $0.5 million.
Financing Plan ($ million) Source Foreign Local Total % Exchange Currency Cost
Tajik Component ADB 20.0 0 20.0 74 OPEC Fund 2.4 0 2.4 9 Barki Tajik 0 4.6 4.6 17 Total 22.4 4.6 27.0 100
Uzbek Component ADB 70.0 0 70.0 47 Cofinancing 49.0 0 49.0 33 Uzbekenergo 18.6 10.4 29.0 20 Total 137.6 10.4 148.0 100
Regional USAID 0.5 0 0.5
Total Project 160.5 15.0 175.5
ADB = Asian Development Bank, EBRD = European Bank for Reconstruction and Development, USAID = United States Agency for International Development.
Tajik Component. The Asian Development Bank (ADB) will finance $20 million equivalent of the foreign exchange cost, representing 74% of the cost of the component. Parallel cofinancing totaling $2.4 million (9%) will be provided from the OPEC Fund to meet the remaining foreign exchange requirements. Barki Tajik will finance the entire local currency cost of $4.6 million (17%).
Uzbek Component. ADB will finance $70 million of the foreign exchange cost, representing 47% of the cost of the component. Cofinancing totaling $49.0 million (33%) will be provided from the iv
Cofinancing totaling $49.0 million (33%) will be provided from the European Bank for Reconstruction and Development to meet the foreign exchange requirements. Uzbekenergo will finance the balance of the component cost in the amount of $29.0 million (20%).
Regional. United States Agency for International Development will provide technical assistance support for regional institutional activities in the indicative amount of $0.5 million.
Loan Amount and Terms Tajik Component. A loan in various currencies equivalent to 15.133 million Special Drawing Rights from ADB’s Special Funds resources will be provided at 1% interest per annum during the grace period and 1.5% per annum during the amortization period, and with an amortization period of 32 years, including a grace period of 8 years.
Uzbek Component. A loan of $70 million from ADB’s ordinary capital resources will be provided under ADB’s LIBOR-based lending facility. The loan will have a 25-year term including a grace period of 5 years, an interest rate determined in accordance with ADB’s LIBOR-based lending facility, a commitment charge of 0.75% per annum, a front-end fee of 1.0%, and such other terms and conditions set forth in the draft loan and project agreements.
Relending Terms Tajik Component. The Government will relend the proceeds of the ADB loan to Barki Tajik denominated in local currency, at ADB’s ordinary capital resources interest rate applicable to the LIBOR-based lending facility with a repayment period of 25 years, including a grace period of 5 years. The foreign exchange risk will be borne by the Government.
Uzbek Component. The Government will relend the proceeds of the ADB loan to Uzbekenergo in the same currency and on the same terms and conditions as the ADB loan to the Government.
Period of Utilization Until 31 December 2006 for Tajikistan and 30 June 2008 for Uzbekistan.
Estimated Project 30 June 2006 for Tajikistan and 31 December 2007 for Completion Date Uzbekistan.
Executing Agency Barki Tajik will be the executing agency for the Tajik component and Uzbekenergo for the Uzbek component.
Implementation Barki Tajik will be responsible for supervising and implementing the Arrangements Tajik component through a project implementation unit (PIU) established for the Project. The PIU will be supported by project implementation consultants financed under the loan. A project steering committee (PSC) will be established to coordinate the Project implementation at the Government level.
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Uzbekenergo will be responsible for supervising and implementing the Uzbek component through a PIU established for the Project. The PIU will be supported by project implementation consultants financed under the loan. A PSC will be established to coordinate the Project implementation at the Government level.
Procurement All procurement to be financed under the ADB loans, including contracts for the design, supply, installation, and commissioning of the project facilities, will be carried out in accordance with ADB's Guidelines for Procurement through international competitive bidding.
Consulting Services Consulting services will be required for design and construction supervision. All consultants financed from the ADB loans will be selected and engaged in accordance with ADB's Guidelines on the Use of Consultants. Uzbekistan: 155 person-months of foreign and 180 person-months of local consulting services. Tajikistan: 38 person-months of foreign and 50 person-months of local consulting services. The implementation of a management information system in Uzbekenergo will involve 15 person-months of foreign and 30 person-months of local consulting services. Retroactive financing was approved for the Uzbek component implementation consulting services expenditures from 15 November 2002, up to a ceiling of $500,000.
Project Benefits and The primary beneficiaries of the Project will be business Beneficiaries enterprises and the population who will benefit from improved quality of electricity services and long-term cost reductions resulting from economic dispatch of power plants and the overall efficiency gains from enhanced power trade. Since effectively all the population of both Tajikistan and Uzbekistan have access to electricity, the project benefits will be universal. The financial internal rates of return for the Tajikistan and Uzbekistan components of the Project are estimated to be 7.0% and 11.3%, respectively. The economic internal rates of return are estimated to be 30.0% and 24.2%, respectively. In terms of poverty impact, the net economic benefits accruing to the poor over the life of the Project are estimated at about $46 million–$17 million for Tajikistan and $29 million for Uzbekistan. The poverty impact ratio is estimated at 41%–57% for Tajikistan and 35% for Uzbekistan. Hence, the Project can be said to be pro-poor as a substantial portion of the project benefits will go to the poor.
Risks and Assumptions The Project has been formulated to minimize potential technical and economic risks. The main risks and assumptions are (i) continued political commitment to power sector reform and regional power trade, (ii) utility financial sustainability, (iii) project delay, (iv) cost overruns, and (v) inadequate plant maintenance following commissioning.
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I. THE PROPOSAL
1. I submit for your approval the following report and recommendation on proposed loans to the Republic of Tajikistan and the Republic of Uzbekistan for the Regional Power Transmission Modernization Project. I further summit for administration by the Asian Development Bank (ADB) a loan for the Project to be provided by the OPEC Fund for International Development (OPEC Fund).
2. The Project was identified and prepared under ADB’s regional technical assistance (RETA) program.1 Regional consensus building has been accomplished through two regional meetings held in July 2001 and April 2002. The Project was included in the regional project pipeline and endorsed at the Central Asian Ministerial Conference on Economic Cooperation in April 2002. Fact-finding for the Project was undertaken from 19 April to 6 May 2002 and appraisal from 6 August to 2 September 2002. The Project was formulated based on the findings of the technical assistance (TA) consultants and the ADB missions. A project framework summarizing the Project's goal, purpose, outputs, activities, and inputs is presented in Appendix 1. The Project is the first stage of a regional assistance program to promote regional energy cooperation and will focus on rehabilitating power transmission equipment and enhancing the power trade relationship between Tajikistan and Uzbekistan.
I. RATIONALE: SECTOR PERFORMANCE, PROBLEMS, AND OPPORTUNITIES A. Performance Indicators and Analysis 3. The Central Asian power system comprises interconnected high-voltage links encompassing southern Kazakhstan, Kyrgyz Republic, Tajikistan, Turkmenistan, and Uzbekistan (see map). The main transmission lines link the power systems of the five countries for parallel operation. The system shares common operational and service management, planning, information channels and control, and connects 83 power plants, including 29 thermal and 48 hydropower plants, with a total installed capacity of about 25,000 megawatts (MW). The unified dispatch center (UDC) in Tashkent is responsible for maintaining the balanced and synchronized operation of the power transmission and distribution systems of the five countries. Following the dissolution of the Soviet Union in 1991, the countries have maintained synchronized operation, which permits the exchange of electricity among them. Further details of the Central Asian power system are provided in Appendix 2. The main operating features are summarized below. (i) Regional electricity demand declined sharply in response to the fall in industrial output following independence. In 1991, peak demand was 19,754 MW, in 1995 it was 16,364 MW. Since 1998, demand has been increasing and in 2001 it was 16,682 MW. Demand is expected to grow at about 2.5% a year to reach 20,150 MW in 2010. (ii) Electricity production has fallen in line with demand, from 116.1 terawatt-hour (TWh) in 1991 to 91.8 TWh in 2001, or by 21%. (iii) Available generating capacity has declined by 16% over the same period to about 21,000 MW due to lack of adequate maintenance. (iv) No new generating capacity has been commissioned since 1991.
1 RETA 5960: Regional Power Transmission Modernization Project in Central Asian Republics, for $900,000, approved on 12 December 2000. 2
(v) System reliability has declined as a result of inadequate transmission system maintenance and changes in the regional operating regime. Recorded transmission system related outages were 178 gigawatt-hours (GWh) in 1998, 138 GWh in 1999, and 309 GWh in 2000. (vi) Power trade has fallen by 80% from 28.7 TWh in 1990 to 4.6 TWh in 2001. The trade levels represented 25% and 5% of generation, respectively. Due to complementarity of energy resources, there is significant potential for economic trading of power among the countries. With reforms in pricing, and power sector restructuring combined with open trading policies, it is expected that power trade could increase to 12% of power generation by 2011.
B. Analysis of Key Problems and Opportunities
1. Problem Analysis
4. Adequate and reliable power supplies are required for economic development in Central Asia. The complementarity of energy resources and the existing high-voltage regional transmission network means that power trade offers the least-cost economic solution to meeting the region’s power needs. However, there are substantial barriers and challenges to power trade in Central Asia. The core problem that the Project seeks to address is the suboptimal operation of the regional power system and intercountry power trade. The causal factors are described below and a problem tree is presented in Appendix 3.
5. Political and Structural Constraints. A prime obstacle to energy trade is that governments in the region have had self-sufficiency as a policy goal. The effect is that some republics are generating electricity using high-value fossil fuels rather than importing electricity from neighboring countries with surplus electricity generated from renewable, lower-cost resources. There has also been a tendency in some countries to limit access to their transmission lines to countries wishing to trade with third countries.
6. The energy-water nexus also negatively impacts optimal power system operation and trade. Water from the two large rivers, Syr Darya and Amu Darya, is used not only for hydropower generation in the upriver countries of Tajikistan and the Kyrgyz Republic, but also for irrigation purposes in these countries and in the downriver countries of Turkmenistan, Uzbekistan, and Kazakhstan. The differing times of year for hydropower requirements (mainly in winter) and for irrigation (mainly in summer) pose serious conflicts for reservoir operation, the replacement of winter hydropower by supplies of fossil power and fuel, and the exchange conditions between water and energy. To cope with these interrelationships in regional trade, the Central Asian governments have resorted to bilateral and multilateral agreements that determine the quantities of water and energy (coal, electricity, and gas) that are exchanged between the countries and the values at which they are exchanged.
7. Power sector restructuring and reform are key to providing the incentives for trade, since independent transmission and distribution companies that are separate from generation, more actively seek to trade power compared to integrated utilities that have a conflict of interest to sell and maximize their own generation. Apart from Kazakhstan, the reform process of the power sectors toward a competitive power market system has made only limited progress to date and reform efforts vary from one country to another. Ultimately a regulator that could guarantee free and nondiscriminatory access of all parties that meet certain technical and commercial requirements will also be required to facilitate open trade.
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8. Management and Institutional Problems. The institutional framework for cooperation at the regional level requires strengthening. The UDC in Tashkent is responsible for maintaining the balanced and synchronized operation of the power transmission and distribution system. Because of its close association with Uzbekenergo, the UDC is considered, fairly or unfairly, by other countries not to be a truly independent regional organization. Moreover, the UDC presently plays only a minor role in promoting regional cooperation in the power sector. Funding of UDC operation is supposed to be on an equal basis from all the countries; however, a number of countries are in arrears in their contributions. A power council consisting of the heads of each regional power utility is the executive body that overseas the operation of the UDC.
9. Transmission System Technical Problems. System reliability is closely linked to the quality and adequacy of maintenance. Many components of the transmission system have reached the end of their economic life and are technically obsolete, and resources for maintenance and development of the power system have been limited. Tariffs are below cost recovery and consequently power utilities cannot operate and maintain the system to international standards. Since even maintenance needs cannot be met there is also no provision for asset replacement and system expansion. The other technical problem is that the power system dis patch (or control) at the country and regional levels is suboptimal. The system is presently controlled manually at the station level with coordination from the UDC, the national dispatch centers (NDCs), and the area dispatch centers (ADCs). Coordination is performed via a deteriorated telephone network on the basis of fragmented information and without application of appropriate supervisory control and data acquisition systems or energy management system functions. The existing level of automation of network control at the control centers as well as at the substation level does not allow for efficient and optimized dispatch of generated power and ancillary services2 including an operating reserve as required to maintain frequency regulation and load following in the power system.
10. Pricing Problems. Pricing is the key to providing incentives for trade. Presently, a distorted system of energy prices exists. Primary energy sources for thermal power generation are frequently and grossly undervalued (e.g., in Uzbekistan the gas price for power generation is one fifth of the export or border price). Also, there is no value attributed to water regulation for irrigation. For power trade to work it is necessary for both buyer and seller to receive an economic advantage. This is possible only in an environment of undistorted prices of electricity and primary fuels for power generation. A further pricing issue is that there is no adequate mechanism in place for the provision of and compensation for ancillary services. In short, the large hydropower plants in the Kyrgyz Republic and Tajikistan provide these services and are required to maintain spinning reserves for regulating the interconnected system to the predominantly thermal generating systems of Uzbekistan, Turkmenistan, and Kazakhstan, without being paid a price for these services that would allow them to recover their costs. Hydropower plants are able to quickly increase or decrease output compared to thermal plants, which allows them to be used to follow changes in demand. Hydropower plants are also able to restart or blackstart the whole power system in the event of a system-wide collapse. Finally, as power tariffs are below long-run marginal costs, power utilities cannot create the revenues that are required to sustain power system operation, let alone trade.
11. Payment Problems. Currently, exchange of power is governed by agreements under which government officials of the various countries decide in regular meetings on the quantities to be imported and exported within a given time period. This exchange of power is often linked
2 Ancillary services include spinning reserve (capacity which is instantaneously available if required), system control, frequency regulation, black-start capacity, and reactive power. 4 to the exchange of fossil fuels and water allocations for irrigation. For an electricity market to work it will be essential to decouple the electricity trade from water and the trade in fuels. Barter and political allocation of commodities need to be transformed into traded energy and traded feedstocks (such as coal and gas) with separate markets for each. Water allocation must be on a fair and equitable basis and costs of water storage and regulation must be adequately compensated. Also, the financial framework does not yet exist that would allow an efficient settlement of transactions in those cases where they are not barter-based and are dollarized. There are problems of currency convertibility and there are no bank guarantees easily available, if at all, for such transactions. Nonpayment across borders is a common problem. Finally, energy trade is technically distorted by the lack of adequate metering of electric energy and load at the borders. The present metering installations do not provide the required accuracy for billing purposes nor the capability for real-time and multi-tariff metering that would be necessary for trade.
2. Project Rationale
12. The Central Asian power system was designed as a single integrated system out of which the national systems have been partitioned following the dissolution of the former Soviet Union. As a result, some of the national power systems are divided and joined only through other countries; others have inadequate generation or water storage capacity for their own needs and must import electricity seasonally or over the year; in other countries there is conflict between the electricity generation by hydropower stations and the needs of their neighbors for water for irrigation. The fundamental rationale for cooperation is the energy resource complementarity combined with remoteness from world markets that makes it essential for the Central Asian countries to share water and energy. Thus, parallel operation of the regional power system and enhancement of energy trade are indispensable for the partner countries in addition to the economic advantages that the interconnected operation provides. To facilitate power exchange and to maintain reliable operation, the 500 kV transmission system must be upgraded and reliability secured, the dispatch and control systems need to be modernized, and metering needs to be installed. Together with these key investments, policy, institutional, and pricing reforms need to be implemented at both the domestic and regional levels.
13. The Project involving Tajikistan and Uzbekistan is a beginning towards the long-term goal of a wholesale regional power market. The other republics are expected to join in subsequent projects and activities. At this stage the other republics have not been included in the Project since Kazakhstan is already undertaking transmission rehabilitation and control investments with the assistance of the World Bank and the European Bank for Reconstruction and Development (EBRD); Turkmenistan is yet to commence lending operations with ADB; and the Kyrgyz Republic has borrowing constraints. To support expanding the participation of these countries in the regional cooperation, undertaking further necessary investment requirements and making further progress on regional reforms, ADB's regional assistance program includes a Phase II project in 2004. In this way the condition of the transmission network and power trading in the Central Asian grid can be progressively improved.
14. Tajikistan and Uzbekistan together represent about 65% of the generation capacity in the Central Asian grid. Tajikistan has huge hydropower export potential and Uzbekistan is the key centrally located country through which most Central Asian power trade must flow. In addition, its thermal-based power system would benefit significantly from the availability of hydropower energy. The focus of the Project will be on enhancing the bilateral power trading relationship between the two countries while encouraging broader regional cooperation. It is expected that Tajikistan and Uzbekistan will become the champions to move the cooperation forward (particularly in terms of the Regional Power Trade Action Plan). 5
15. Government Strategy. The Central Asian governments recognize the need to provide reliable, efficient, and affordable energy to support economic development. To this end, each government has been taking steps to reform its respective power sector and improve cost recovery. The governments also recognize the importance of regional cooperation to address energy and water issues to the benefit of all parties. In this regard they executed in 1999 an agreement on the parallel operation of the regional electricity grid that forms the basis for trade and cooperation and the ultimate development of a regional power pool. The Project was endorsed at the Central Asian Ministerial Conference on Economic Cooperation in Manila in April 2002 as part of the 3-year regional program and was reconfirmed as top priority by Tajikistan and Uzbekistan representatives at the ADB annual meeting in May 2002.
16. ADB Strategy. ADB’s regional program, which complements and supplements the individual country programs, has focused on identifying infrastructure needs and improving the policy environment for promoting cross-border trade in the areas of energy, trade, and transportation. In the energy sector the focus is on maximizing benefits from resource complementarity by rationalizing and encouraging regional energy trade, based on market principles, and rehabilitating existing infrastructure.
17. External Assistance. In Central Asia, since 1994 ADB has lent $84 million for power rehabilitation projects in Tajikistan and the Kyrgyz Republic and an infrastructure program loan in Tajikistan. A total of $6.1 million of TA complemented the loan program. Other major funding agencies active in the sector include EBRD, World Bank, and the governments of Japan and the United States. A list of funding agency activities is included in Appendix 4. The focus of all of them has been on rehabilitation and power sector reform. In 1999, the World Bank and EBRD financed the Electricity Transmission Rehabilitation Project in Kazakhstan that aims to improve the reliability of the 500 kV transmission system, modernize the dispatch facilities, and support the establishment of a national power pool. The United States Agency for International Development (USAID) has provided TA and supported a regional electricity working group that resulted in the execution of the parallel operating agreement and a body of work on the development of a regional power pool. Over the last couple of years the focus has been on regional cooperation in water resources that are integral to power sector operations. The Project will build on these initiatives and further encourage regional power trade and cooperation. EBRD and the OPEC Fund will provide cofinancing and USAID will provide TA for the Project
18. Lessons Learned. ADB has modest experience in the energy sector in Central Asia. The proposed Project is the first regional lending operation in the power sector, but its design draws on ADB's experience in providing power rehabilitation assistance to countries in transition, including the Kyrgyz Republic, Tajikistan, and Mongolia. ADB projects have had front- end delays in implementation due to the governments' unfamiliarity with ADB procedures. This was the case with Loan 1817-TAJ: Power Rehabilitation Project. This should not be a problem for the implementation of the proposed Project since Tajikistan has gained experience with ADB procedures and Uzbekistan has had experience with an EBRD project. Also, the implementation schedules in each case allow a reasonable period for procurement activities.
19. ADB experience has also shown that it takes considerable time and effort to restructure, corporatize, and commercialize utilities, and to achieve full cost recovery, especially in an economy that is undergoing transition. The Tajikistan Government had difficulty in meeting the conditionalities under Loan 1651-TAJ: Postconflict Infrastructure Program, and had to obtain waivers for second tranche release. The reform agenda in the Kyrgyz Republic was also difficult and took considerable time. The lesson that conditionalities have to be realistic and reasonable has been taken into account in the project agreements. Finally, the experience with the first 6 regional project in Central Asia, Loan 1774/1775 REG: Almaty-Bishkek Regional Road Rehabilitation, found that regional agreements take time to ratify and this has been factored into the design of the Project.
II. THE PROPOSED PROJECT
A. Objectives
20. The strategic objective of the proposed Project is to efficiently meet the energy requirements of the Central Asian counties to support economic development. The specific project objective is to improve the operation and efficiency of the regional power transmission system and enhance economic power trade among the Central Asian republics. Under the Project, the focus will be on modernizing the interconnected transmission systems of Tajikistan and Uzbekistan and enhancing the power trade relations between them.
B. Components and Outputs
21. The outputs of the Project are as follows (the technical scope is detailed in Appendix 5):
(i) Rehabilitated 500 kV substations and switchgear. Replace circuit breakers (500 and 220 kV), current and voltage transformers, protection and control systems, and the direct current system. In Tajikistan, the rehabilitation work will cover the Regar 500/220 kV substation. In Uzbekistan, the rehabilitation work will cover the 500/220 kV substations of Tashkent, Surkhan, Lochin, Guzar, and Karakul, and the switchgear at the power stations of Tashkent, Novo Angren and Syr Darya.
(ii) Upgraded dispatch and communications facilities. Upgrade facilities at UDC, NDCs, ADCs, and telecommunications links. Install new remote terminal units in 500 kV substations and in major power plants. In Tajikistan, the NDC and the ADCs of Hojent and South regions will be upgraded. In Uzbekistan, the NDC and the ADCs of Fergana, Takhitash, and Samarkand will be upgraded.
(iii) New transborder metering. Install new meters together with meter management systems at all control centers. In Tajikistan, the installation will involve replacement of 40 energy meters, provision of 12 sets of meter reading equipment, and a metering management system in the NDC. In Uzbekistan, the installation will involve replacement of 220 energy meters, provision of 40 sets of meter reading equipment, and a metering management system in the NDC.
(iv) Improved policy, institutional, and regulatory environment. Implement the Regional Power Trade Action Plan and the bilateral Power Trade Relations Agreement with consulting services support.
C. Special Features
1. Foundation for a Future Regional Competitive Power Market
22. The measures to be implemented and the equipment to be installed under the Regional Power Transmission Modernization Project constitute an important prerequisite for the enhancement of regional trade and the development of a future regional competitive power system. The steps required to reach the ultimate long-term goal can best be illustrated through 7 the comparison with a no trade scenario and different stages of trade, ranging from pre- independence times to the long-term objective of a regional power pool system.
23. Soviet-Era Trade Scenario. The Soviet, pre-independence situation represented complete integration and the level of trade was much higher than at present. The whole region was operated as a single power exchange zone and, even though dispatch was not according to economic and market principles, it was a rational system in terms of energy resource utilization.
24. No Trade Scenario. Given that peak electricity usage is time sensitive and the major population centers of the region are spread over different time zones, economizing on peak generation capacity alone would provide a strong rationale for energy trade. Trading also allows substantial economizing on reserve capacity. If no trade were to take place, each country would have to provide its own reserve capacity, the sum of which is much higher than the reserve capacity of an integrated system. While self-sufficiency in the newly independent republics has been a policy objective, it is now recognized that the no trade option can only be attained at a very high cost and would confer few, if any, benefits on the country adopting the policy.
25. Present Trade Scenario. The present power trade situation is characterized by barter deals and technical dispatch. It is not based on economic considerations. The trade in 2001 is shown in Appendix 6. Southern Kazakhstan imports power from Turkmenistan (wheeled through Uzbekistan) and the Kyrgyz Republic and receives power from north Kazakhstan as well. The Kyrgyz Republic imports power from Uzbekistan and Tajikistan and exports power to Kazakhstan, Uzbekistan, and Tajikistan (at different times of the year). Tajikistan imports power from the Kyrgyz Republic, Turkmenistan, and Uzbekistan and exports power to the Kyrgyz Republic and Uzbekistan. Turkmenistan exports power mainly to Tajikistan but also small amounts to Kazakhstan and Uzbekistan. The energy trade picture is further complicated by exports and imports of gas for power production and by the inclusion of water for irrigation in the present exchange agreements.
26. With-Project Trade Scenario. Enhanced power trade development is the objective of the Project. This intermediate stage can be described as voluntary cross-border trade on the basis of genuinely independent electricity utilities that are managed according to economic principles, with no political interference. Barter trade would decline over the transition period. The Project provides three key building blocks: rehabilitation of substations, augmentation of the control systems, and enhanced metering. It will allow better optimization of the control systems and monitoring of power flows. The other key building blocks that are key elements of the Regional Power Trade Action Plan include legal/regulatory compatibility, transmission ownership, open access transmission, more comprehensive sales contracts, transmis sion pricing, voluntary trading, a grid code, a metering code, ancillary services pricing, and hard currency contracts and settlement. The trading envisaged would be a mixture of long- and short- term contracts between the respective utilities on the basis of mutual economic advantage.
27. Regional Wholesale Market Scenario. Once voluntary economic trade has been well established and a substantially enhanced level of regional power trade has been achieved, it will be appropriate to move to the establishment of a regional wholesale power trading pool. In the medium term, it is anticipated that the power sector in each country of the region will be fully restructured to achieve independent and commercial operation. In addition, each country will have fully unbundled its electricity sector with independent generation, transmission, and distribution. Transmission, distribution, and energy companies will be operationally separate but may still have the same owner. Private sector participation will be a feature providing funding, management, and expertise. Indicative levels of trade for 2011 are shown in Appendix 6. 8
2. Regional Consensus and Power Trade Action Plan
28. Government and utility representatives from Kazakhstan, Kyrgyz Republic, Tajikistan, and Uzbekistan attended a Regional Power Transmission Meeting on 22–23 April 2002 to (i) discuss the findings of TA 5960-RETA; (ii) consider the recommendations for pursuing enhanced power trade relations among the Central Asian republics; and (iii) reach a consensus on the way forward. The meeting agreed on a number of time-bound actions that would enhance the present power trading relations and establish the foundation for the ultimate wholesale regional power market. The agreed action plan explicitly addresses the problem areas identified in paras. 4 to 11 and is presented in Appendix 7. It covers the key areas of policy reform necessary for trade, regional institutional arrangements, technical investment requirements and operating protocols, commercial and financial arrangements, and individual country reforms. The governments of Tajikistan and Uzbekistan have formally endorsed the action plan and have committed, as a condition of the loan, to implement the actions within their direct control and to take an active role in the implementation of the necessary cooperative actions involving other countries.
29. The governments of Tajikistan and Uzbekistan have further committed, as a condition of the loan, to implement a Power Trade Relations Agreement that will enhance their bilateral trade relations. The agreement was negotiated in November 2002 and is to be implemented by 31 December 2003. It involves the following:
(i) establishment of a policy of open access to the transmission networks in each country; (ii) development and use of a transparent methodology for transmission tariff calculation including procedures for asset valuation and fair return on capital; (iii) introduction of a compatible standard metering protocol that will provide the framework for the collection, analysis, and management of power exchanges; (iv) development and use of a pro-forma contract to be used for bilateral power trading (v) development and agreement on pricing arrangements for ancillary services (reserve capacity, voltage control, etc.); (vi) resolution of all outstanding issues relating to the use, management, and maintenance of cross-border transmission facilities; (vii) agreement on an annual contract for power trade that will, among other things, consider the mutually beneficial utilization of and payment for excess hydropower energy; and (viii) initiation and leadership of a working group with the nonparticipating countries to develop the institutional framework for regional power trade and support the implementation of the Regional Power Trade Action Plan.
30. Cooperation with USAID will be important for the implementation of the institutional aspects of the Project. USAID provided expert support in the area of power trade during the processing of the Project, and during the negotiation of the Power Trade Relations Agreement. A 5-year program of assistance was prepared and covers the institutional support required to (i) implement the Regional Power Trade Action Plan including support for intercountry institutional and technical working groups to prepare necessary protocols to enhance trade and ultimately establish a wholesale power market, and (ii) establish UDC as an independent 9 commercial enterprise. Under the program USAID has committed initially to provide the technical support for the implementation of the Power Trade Relations Agreement and to undertake a needs assessment of UDC to incorporate the monitoring and control of water dispatch as well as electric power dispatch.3
3. Technical Features
31. The reliability of the 500 kV network is a prerequisite to the development of regional power trade—trade cannot effectively take place as long as the system does not have an acceptable level of reliability. The existing grid is old and the reliability is very low due to frequent failures of equipment. The rehabilitation of the major substation equipment within the main power corridors will reduce the number of forced outages and increase the amount of delivered energy. This will benefit both the national and regional power systems.
32. Upgrading the NDC and ADCs and associated telecommunications is essential to ensure safe and reliable operation of the national systems and improve the reliability of the interconnected transmission system with the aim of enhancing regional electricity trade. Closer supervision of the national network operation and loading as well as monitoring and initiation of corrective measures to comply with steady state and dynamic stability will allow optimal utilization of the grid networks and power plants. This will result in a reduction of transmission losses and in fuel cost savings for thermal power plants. Planning software will allow the national utilities to adjust the existing automatic schemes, within the stability limits and will better enable prevention of the collapse of the whole system in case of major failure. This will benefit both the national and regional power systems.
33. Accurate and real-time metering at the borders of the national grid and at the interface with large customers (connected to the transmission system) is essential for measuring and billing purposes and is essential for any development of trade. Improved metering systems will allow the introduction of a market for ancillary services, which will enhance regional cooperation among the Central Asian republics. It will further resolve disputes over the payment of electricity transfer and, in the long run, introduce savings through improved energy efficiency.
34. The rehabilitation of UDC is necessary to ultimately achieve the full benefit of the Project in terms of optimization of regional network operation and reduction of losses. The upgrade of UDC will allow real-time, overall control of the regional network. This will permit a better utilization of the installed generation capacity, reduction of fuel consumption, as well as reduction of transmission losses through improved operation of the regional grid network.
4. Support for the Reconstruction of Afghanistan
35. The Project will facilitate power exchange between the Central Asian power system and Afghanistan. There exists a 60 km double circuit 110 kV transmission line linking Kunduz in Afghanistan to Tajikistan, and a 71 km double circuit 220 kV transmission line linking Khulm substation in Afghanistan to Surkhan substation in Uzbekistan. Electricity exports stopped in the 1990s due to payment arrears. Limited exports to Afghanistan have recently resumed. There is also long-term potential to export power across Afghanistan to Pakistan.
3 Depending on the success of the initial work and provided there is continued government commitment, USAID may consider continuing support for the program. 10
D. Cost Estimates
36. The total project cost is estimated at $175.5 million equivalent. The Tajik component is estimated to cost $27.0 million equivalent (foreign exchange cost $22.4 million and local currency cost $4.6 million equivalent), and the Uzbek component $148.0 million equivalent (foreign exchange cost $137.6 million and local currency cost $10.4 million equivalent). A regional technical assistance component will cost $0.5 million. The estimates are summarized in Table 1, and presented in detail in Appendix 8.
Table 1: Project Cost Summary ($ million)
Item Tajikistan Uzbekistan Total Foreign Local Total Foreign Local Total Project Exchange Currency Cost Exchange Currency Cost
I. Base Costs Transmission Rehabilitation 3.4 0.2 3.6 76.3 3.9 80.2 83.8 Dispatch Upgrading and Metering 14.3 2.2 16.5 25.2 3.9 29.1 45.6 UDC Rehabilitation 0.9 0.1 1.0 2.9 0.4 3.3 4.3 Consulting Services 1.2 0.2 1.4 5.5 1.0 6.5 8.4 a Total 19.8 2.7 22.5 109.9 9.2 119.1 142.1
II. Contingencies a. Physical contingencies 1.0 0.1 1.1 5.5 0.5 6.0 7.1 b. Price contingencies 1.0 0.2 1.2 9.0 0.7 9.7 10.9 III. Interest During 0.6 1.6 2.2 13.2 0.0 13.2 15.4 Construction Total Project Cost 22.4 4.6 27.0 137.6 10.4 148.0 175.5 % 83 17 100 93 7 100 UDC = unified dispatch center. a Including regional technical assistance of $0.5 million.
E. Financing Plan
37. The financing plan for the Project is summarized in Table 2 and detailed in Appendix 8.
Table 2: Financing Plan ($ million) Source Foreign Local Total % Exchange Currency Cost
Tajik Component ADB 20.0 0 20.0 74 OPEC Fund 2.4 0 2.4 9 Barki Tajik 0 4.6 4.6 17 Total 22.4 4.6 27.0 100
Uzbek Component ADB 70.0 0 70.0 47 Cofinancing 49.0 0 49.0 33 Uzbekenergo 18.6 10.4 29.0 20 Total 137.6 10.4 148.0 100
Regional USAID 0.5 0 0.5
Total Project 160.5 15.0 175.5
ADB = Asian Development Bank, EBRD = European Bank for Reconstruction and Development, USAID = United States Agency for International Development. 11
38. For the Tajik component, the Borrower will be the Republic of Tajikistan for an ADB loan in various currencies equivalent to 15.133 million Special Drawing Rights [$20 million equivalent] from ADB’s Special Funds resources with 1% interest during the grace period and 1.5% during the amortization period and with an amortization period of 32 years, including a grace period of 8 years. The Government will relend the proceeds of the ADB loan to Barki Tajik, denominated in local currency, at ADB’s ordinary capital resources interest rate applicable to the LIBOR-based lending facility with a repayment period of 25 years, including a grace period of 5 years. The foreign exchange risk will be borne by the Government. Barki Tajik will finance the $4.6 million equivalent local currency cost of the Tajik component. Parallel cofinancing of $2.4 million for transmission rehabilitation under the Tajik component will be provided by the OPEC Fund and is expected to be approved in December 2002.
39. For the Uzbek component, the Borrower will be the Republic of Uzbekistan for an ADB loan of $70 million from ADB’s ordinary capital resources. The loan will have a 25-year term, including a grace period of 5 years, an interest rate determined in accordance with ADB’s LIBOR-based lending facility, a commitment charge of 0.75% per annum, a front-end fee of 1.0%, and such other terms and conditions set forth in the draft loan and project agreements. The Government will relend the proceeds of the ADB loan to Uzbekenergo in the same currency and on the same terms and conditions as the ADB loan to the Government. Uzbekenergo will finance $18.6 million of the foreign cost and all the $10.4 million equivalent local currency cost of the Uzbek component. Cofinancing of $49.0 million for transmission rehabilitation under the Uzbek component will be provided by EBRD and is expected to be approved in April 2003.
40. ADB financing of 47% is higher than the current 40% limit for Uzbekistan as a Group C country under the graduation policy and is justified on the following grounds: (i) the Project is almost entirely foreign exchange cost, (ii) the ADB loan will finance only one half of the total project foreign exchange requirement, and (iii) Uzbekistan is facing a shortage of foreign exchange.
41. In the cost estimates, both Tajikistan and Uzbekistan have agreed to allocations of funding for the upgrading of the UDC. However, the use of the allocated funds will be subject to UDC being reestablished within a new institutional framework acceptable to the other Central Asian countries, and with the agreed participation of these countries.
F. Implementation Arrangements
1. Project Management
42. Barki Tajik will be the executing agency (EA) responsible for overall supervision and coordination of the Tajikistan component of the Project. A project implementation unit (PIU) has been established under Loan 1817-TAJ: Power Rehabilitation Project and will be expanded to cover the Project. The PIU will be responsible for day-to-day implementation, including review of tender documents, bid evaluation, and supervision of installation, as well as the necessary liaison among Barki Tajik, contractors, and ADB. The PIU, which will be supported by implementation consultants financed under the loan, will be staffed with suitably qualified personnel. A project steering committee (PSC) will also be established to provide guidance to the Project. The PSC will coordinate activities at the government level and serve as a forum for discussions on important issues. The PSC will be chaired by the Minister of Energy and its members will include representatives from the Ministry of Energy, Barki Tajik, and the PIU Manager. The PSC will meet when required, but in any event, at least twice a year.
12
43. Uzbekenergo will be the EA responsible for overall supervision and coordination of the Uzbek component of the Project. A PIU has been established. The PIU, which will be supported by implementation consultants financed under the loan, will be staffed with suitably qualified personnel. A PSC will also be established to provide guidance to the Project. The PSC will coordinate activities at the government level and serve as a forum for discussions on important issues. The PSC will be chaired by the Head, Energy Department, Cabinet of Ministers, and its members will include representatives from the Energy Department, Uzbekenergo, Ministry of Finance and Ministry of Macroeconomics, and the PIU Manager. PSC will meet when required, but in any event, at least twice a year.
44. For the implementation of the UDC component, a special PIU will act as EA and consist of representatives from each of the regional utilities. It will also act as a standardization coordinator for functional requirements and the data to be acquired as well as ensuring compatibility of interfaces between dispatching, communications, and metering the systems installed in the individual countries.
2. Implementation Period
45. It is envisaged that project implementation will start in 2003 and be completed by June 2006 for Tajikistan and December 2007 for Uzbekistan. Loan closing will be in December 2006 and June 2008, respectively. The project implementation schedules are shown in Appendix 9.
3. Procurement
46. Procurement of ADB-financed goods and services under the proposed Project, including contracts for the design, supply, installation, and commissioning of the project facilities, will be carried out in accordance with ADB's Guidelines for Procurement through international competitive bidding (ICB). A list of the proposed procurement packages, the financer of the package, and their mode of procurement is attached as Appendix 10. Barki Tajik and Uzbekenergo have agreed to take steps so that bidders, suppliers, contractors, and consultants under contracts financed through the loan observe the highest standards of transparency during the procurement and execution of such contracts.
4. Consulting Services
47. The services of internationally recruited consulting firms, to be financed by ADB, will be required to provide project management services and assistance to Barki Tajik and Uzbekenergo in such matters as detailed design, tendering, supervision of installation, testing, and commissioning of equipment and training for operation and maintenance (O&M). In each country, consultants will support the PIU and will be required to transfer project management skills to PIU staff. Outline terms of reference and cost estimates are presented in Appendix 11. For the Uzbek component the services of an internationally-recruited consulting firm, to be financed by ADB, will be required to develop a computerized management information system for effective management of Uzbekenergo and its subsidiary companies. Outline terms of reference and cost estimates are presented in Appendix 14. All consulting services under the Project will be recruited in accordance with ADB's Guidelines on the Use of Consultants, using quality and cost-based selection methods on the basis of a full technical proposal. Other arrangements satisfactory to ADB will be used for the engagement of domestic consultants. There will be four contracts in total: (i) 38 person-months of international and 50 person-months of local consulting services will be engaged in Tajikistan for transmission rehabilitation, dispatch upgrading, and UDC; (ii) 110 person-months of international and 130 person-months of local consulting services will be engaged in Uzbekistan for transmission rehabilitation; (iii) 45 person- 13 months of international and 50 person-months of local consulting services will be engaged in Uzbekistan for dispatch upgrading, including UDC; and (iv) 15 person-months of international and 30 person-months of local consulting services will be engaged for the development of the power sector management information system in Uzbekistan.
5. Retroactive Financing
48. Retroactive financing of reasonable expenditures incurred after 15 November 2002 for consulting services was approved for the Uzbek component up to a maximum of $500,000. Such financing will facilitate Project implementation prior to the effectiveness of the ADB and EBRD loans. The Government was advised that approval of retroactive financing does not commit ADB to financing of the Project.
6. Disbursement Arrangements
49. All disbursements under the ADB loan will be carried out in accordance with the ADB’s Loan Disbursement Handbook. Direct payment procedures will be utilized for the procurement and consulting services contracts.
7. Accounting, Auditing, and Reporting
50. There will be continued monitoring and evaluation of project implementation, with timely reporting. The EAs will prepare quarterly reports on progress of project implementation and furnish ADB and cofinancers with copies of these reports. ADB will review implementation of the Project on a regular basis, at least once a year, and will monitor overall performance of the EAs. Within 3 months of project completion, the EAs will furnish ADB with a project completion report covering details of implementation and other information required by ADB. The EAs will maintain separate records and accounts for the Project and will have the accounts audited annually by independent auditors acceptable to ADB. Copies of audited project accounts will be provided to ADB within 6 months of the end of each relevant fiscal year. The EAs will also provide ADB with copies of its audited corporate accounts within 6 months of the end of its fiscal year. The EAs will adopt international accounting standards for their financial reporting. ADB disbursements will be suspended if delays of 6 months in submis sion of audited financial statements occur.
8. Project Performance Monitoring and Evaluation
51. The EAs will carry out all benefit monitoring and evaluation activities of the Project. These will be undertaken in accordance with the relevant provisions of ADB’s Benefit Monitoring and Evaluation: A Handbook for Bank Staff, Staff of Executing Agencies and Consultants. At the beginning of project implementation, the EAs will submit to ADB a report on the benchmark information, to be followed by annual performance reports during project implementation. Upon project completion, a comprehensive report will be submitted. In addition, 3 years after completion, the EAs will finance out of their own funds benefit monitoring and evaluation studies to assess the overall benefits of the Project.
52. An integral component of the project monitoring and evaluation will be to assess over time the poverty reduction impacts of the Project. With support from the implementation consultants, benchmark surveys will be undertaken, and various indicators will be formulated and then monitored throughout and following project implementation. Trends in electricity use by domestic consumers by income level, changes in electrical appliance ownership, rural versus 14 urban consumption patterns, small enterprise electricity use, and other indicators will be monitored.
9. Project Review
53. In 2004, ADB will, together with the EAs, carry out a midterm review of the Project, focusing on all regional policy, institutional, administrative, organizational, technical, environmental, social, economic, financial, and other relevant aspects that may have an impact on the performance of the Project and its continuing viability. The review will cover the implementation of the Regional Power Trade Action Plan and the Power Trade Relations Agreement.
G. The Executing Agencies
54. The EAs for the Project will be Barki Tajik in Tajikistan and Uzbekenergo in Uzbekistan. Each country is implementing reforms in its power sector and details of the reforms are included in Appendix 12. An overview of the EAs is provided below.
1. Barki Tajik
55. Barki Tajik is the state-owned utility responsible for generation, transmission, and distribution of electricity in Tajikistan. Prior to the country’s independence, the entity was administratively a government agency. In 1992, it became a state joint stock holding company. Although it is fully owned by the Government, Barki Tajik enjoys autonomous status according to its charter.
56. Under the present institutional arrangements, Barki Tajik consists of a network of 10 subsidiary power generation companies, 11 subsidiary distribution companies, and 8 supporting companies including a research institute and construction companies (Appendix 13). The chairperson of Barki Tajik, who has overall responsibility for operations, reports directly to the Prime Minister, and is appointed by the Government with no fixed term. The chairperson is assisted by the first deputy chairperson (chief engineer), who manages Barki Tajik’s day-to-day operations, and six deputy chairpersons who are in charge of the technical departments, supporting services, and subsidiary power generation and distribution companies. Since 1999, the Government has created business units for some of these subsidiaries, with ownership rights vested directly in the State Property Committee on behalf of the Government but with business management responsibilities assigned to Barki Tajik.
57. In 2000, Barki Tajik was incorporated as a commercial entity, and a separation of operations has taken place along its business unit lines for generation, transmission, and distribution, but within the same management control. As agreed under Loan 1817-TAJ, the Energy Law was passed setting up the Ministry of Energy as the policy unit of the Government. Tariffs are regulated by Ministry of Finance (MOF). Supported by ADB TA, Barki Tajik is currently implementing international accounting practices4 and modernized consumer accounting systems and meter reading systems.5
4 TA 3601-TAJ: Introducing International Accounting Standards at Barki Tajik , for $500,000, approved on 20 December 2000. 5 TA 3600-TAJ: Improving Barki Tajik’s Billing and Collection Systems, for $500,000, approved on 20 December 2000. 15
a. Past Financial Performance
58. Barki Tajik's past financial performance has been improving but revenues are still only sufficient to cover cash operating expenses. Electricity sales remained almost unchanged in 2001 after a sharp decline of 9.5% in 2000, mostly as a result of lack of hydropower generation (dry summer) and declining growth in industrial demand. Accounts receivable remain a major problem despite a 40% reduction between 1999 and 2001. At the end of 2001, they stood at $23.3 million or equivalent to 7.5 months of gross billings, which exceeds the agreed target under the previous loan of 6 months by December 2001.
b. Financial Projections
59. Cost recovery has been considered in two ways. Under the project preparatory TA, the average incremental cost of supply was estimated in economic terms to be 2.5 cents/kilowatt- hour (c/kWh) on the basis of rehabilitation of existing assets and completion of an unfinished hydropower station to meet new demand. By contrast, the financial projections, with assets revalued indicatively, indicate that a reasonable level of financial cost recovery based on a 6% return would require a tariff level of about 2.2 c/kWh at 2002 prices. Therefore, the target level for tariffs over the medium term should be 2.2–2.5 c/kWh.
60. The current average tariff is 0.95 c/kWh. Under Loan 1817-TAJ: Power Rehabilitation Project, by December 2001 industrial tariffs were to be increased to 1.03 c/kWh to achieve 100% cost recovery; this was achieved in April 2002. Domestic tariffs were to be increased to $0.75/kWh to achieve 50% cost recovery by December 2002. This will entail an 83% increase over present levels and the Government has notified ADB that it will implement the same by end-December 2002. The first 150 kWh block of consumption will, however, maintained at 0.18 c/kWh to protect low-income consumers.
61. In addition to the 2002 tariff adjustments, the financial projections assume tariff increases for 2003 onward to maintain the covenanted 90% operating ratio and to achieve a 6% rate of return by 2006. Given the large tariff increases in 2002 and the expected negative impact on accounts receivable, the current loan covenant for accounts receivable of 3 months by December 2002 is now targeted for achievement by December 2004. Due to lower sales than previously projected, the rate of return covenant of 6% on revalued net fixed assets in service will become applicable a year later, i.e., from 2006.
2. Uzbekenergo
62. Uzbekenergo is the state-owned joint-stock company responsible for generation, transmission, and distribution of electricity and heat in Uzbekistan. In 2001, it was created out of the former power ministry. Under the present institutional arrangement, Uzbekenergo consists of a network of subsidiary power companies, including all power stations, the distribution and transmission network, and other energy-related companies (the organizational chart is in Appendix 13). The Government’s reform program envisages that all distribution entities will be made shareholding companies by 2003, followed by generation entities by 2005. The transmission network will remain in government hands for the foreseeable future. Only minority shareholdings will be offered to the private sector in the thermal generating companies, with the majority shareholding remaining with the Government. Currently, each power station is operating as a separate legal entity. By the end of 2002, each distribution entity will operate independently and accounting separation for the transmission company is expected to be finalized. Under the Project, support will be provided to develop a computerized management information system for effective management of the 38 subsidiary companies. The terms of 16 reference, cost, and equipment requirements are presented in Appendix 14. Support is also being provided by EBRD in the form of a tariff study and the World Bank is to undertake a study to consider future power sector restructuring and reform.
a. Past Financial Performance
63. Uzbekenergo has incurred losses for the last 2 years. Electricity sales grew at an annual average rate of only 2% between 1999 and 2001. Accounts receivable, which are one of the key concerns of Uzbekenergo’s operation, increased from 4.4 months to 5.2 months between 1999 and 2001. In an operating environment of high foreign cost expenditures and local currency revenues the large depreciation of the currency has severely impacted Uzbekenergo’s finances. Despite tariff increases of 40% between 1999 and 2001, currency depreciation of 70% resulted in the tariff falling in dollar terms during the period. In this environment, despite subsidized fuel prices at only 20% of economic cost, Uzbekenergo’s finances have worsened.
b. Financial Projections
64. Under the project preparatory TA, the average incremental cost of supply was estimated in economic terms to be 3.0 c/kWh on the basis of rehabilitation of existing assets to meet increasing demand. This should be the target level for Uzbekenergo's tariffs over the medium term. This is consistent with the financial projections that show that a tariff level of 3.3 c/kWh (in 2002 prices) is required for Uzbekenergo to achieve a 6% return on indicatively revalued net fixed assets.
65. The Government is committed to increasing tariffs to cost-recovery levels over the medium term even as Uzbekenergo faces further cost side pressure as a result of expected gas price liberalization. During 2002, in quarterly steps, the tariff has been increased by 56% to achieve an average tariff level of 1.1 c/kWh. Further tariff increases are planned for 2003. Uzbekenergo is expected to breakeven in 2003 and show profits from 2004 onward. The financial analysis shows that with the proposed increases, the working ratio can be gradually reduced to 70% by 2006 from 111% in 2002. This means that 30% of the annual revenue will be available over and above cash operating costs for investment and debt service. Uzbekenergo has agreed to achieve a working ratio of at least 90% in 2003, 85% in 2004, 75% in 2005 and 70% in 2004 and onward. It has also agreed to reduce accounts receivable to an acceptable level of 3 months by 31 December 2004.
III. PROJECT BENEFITS, IM PACTS, AND RISKS
66. The project benefits and impacts have been assessed along with the potential risks associated with the Project. The integrated benefits and impacts are expected to outweigh the costs.
A. Financial and Economic Benefits
67. From a least-cost perspective, there is no technical alternative to the rehabilitation of the high-voltage transmission substations because the further deterioration of substation equipment would increasingly make the transmission system unreliable to deliver electricity from the major generating plants to regional and domestic customers. The automation of dispatch control and metering are also essential for the optimal operation of the regional and the domestic power systems and for economic regional trade. To assess the financial and economic benefits of the 17
Project, a viability analysis was undertaken. The analysis and the assumptions are in Appendix 15 and the results are summarized below.
68. Financial analysis from the perspective of Barki Tajik and Uzbekenergo has been based on a capital cost (base cost plus physical contingencies) of $23.6 million and $125.1 million, respectively, over the life of the equipment. As a result of the rehabilitation of the 500 kV substations, forced outages are expected to be reduced by an estimated 45%, which will provide additional amounts of electricity to consumers and reduced interruption to economic activities. The rehabilitation works will also reduce the high cost emergency and unscheduled maintenance and serious collateral damages (i.e., in case of exploding old equipment damaging adjacent equipment) that is presently experienced.
69. Load dispatch upgrading will result in optimization of power generation and an improved dispatch regime that will increase the output from hydropower stations and will lead to lower spinning reserve requirements. As a consequence, fuel and other variable costs for thermal power stations will be reduced. A 1% reduction for fuels and a 0.5% reduction in variable operating costs are expected. As a result of improved power system control, it is estimated that outages can be further reduced by 25%. More equal loading of the entire system leads to reduced losses in the transmission system. A 6% reduction has been assumed. Finally, new fiber optic communications lines will reduce telephone costs and even provide revenues from the rent of communications links to telephone companies.
70. Reduced outages and transmission losses were valued at the average financial electricity tariff projected to increase in real terms in line with the financial projections. On this basis, and after allowance for adequate O&M costs and income tax, the financial internal rate of return for the Tajikistan and Uzbekistan components of the Project is estimated to be 7.0% and 11.3%, respectively, which, when compared with an estimated weighted average cost of project capital of about 4%, indicates that the Project should be financially viable for both the participating utilities. Financial viability depends mainly on tariff reform and will be able to withstand variations in capital cost and the level of benefits.
71. The viability of the Project was analyzed from a broader national perspective in terms of its economic internal rate of return (EIRR). The financial costs were adjusted to reflect the economic opportunities forgone and realized on account of the Project. The capital cost for the Tajikistan and Uzbekistan components of $23.2 million and $118.7 million, respectively, were used. Reduced outages were valued at a conservative value of energy not served of 20.0 c/kWh and transmission loss reduction on the basis of willingness to pay (estimated for Tajikistan and Uzbekistan to be 5.0 c/kWh and 4.5 c/kWh, respectively). On this basis, the EIRRs for the Tajikistan and Uzbekistan components of the Project are estimated to be 30.0% and 24.2%, respectively.
72. The results of a sensitivity analysis show that even with adverse changes in the key assumptions, the Project remains financially and economically viable. The analysis shows that for Tajikistan and Uzbekistan the benefits (in terms of value or quantity) would have to be 66% and 53% less, respectively, or the capital cost would have to be 147% and 104% more, respectively, before the EIRR would fall to the ADB’s minimum cutoff value of 12%.
B. Regional Benefits of Trade
73. The foregoing viability analysis considered the Project benefits for Tajikistan and Uzbekistan, excluding the benefits of increased trade. Increased power trade facilitated by the Project would yield substantial additional benefits. Benefits result from a number of factors that 18 can be grouped into two categories: (i) reduced operating costs and (ii) lower generation capacity and expansion requirements.
74. Lower overall generation costs will result from increased trade. This is of particular importance in Central Asian countries where there are huge hydropower resources available in certain countries (the Kyrgyz Republic and Tajikistan), while other countries (Kazakhstan, Turkmenistan, and Uzbekistan) have immense reserves of fossil fuels. The two complement each other to achieve least-cost generation. Also, by working as one large integrated system, operating costs can be reduced as a consequence of reduced individual spinning reserve requirements, the joint provision of and exchange of ancillary services, the possibility to support and better supply loads at the periphery of an individual system, and generally an increased service quality and reliability standards of power supply. The feasibility study consultants estimated that these benefits would be in the order of $25–30 million per year by 2011, assuming that power would be supplied from the low-cost generation (hydropower) countries to the other countries.
75. Reduced capacity requirements result, since reserve capacities can be used jointly and thus the total installed reserve capacity can be lower. Pooling of reserve capacities makes it possible to reduce future expansion of power system generation and reduce total capital required for new power stations. Moreover, for future expansion planning it will also be possible to coordinate power system expansion planning and take advantage of economies of scale through the installation of large generation units that would not be viable in the individual systems. Finally, lower capacity requirements can also result from the fact that peak load hours slightly differ amongst the Central Asian countries. It is thus possible to improve the overall system load factor and equalize the daily load curve. The feasibility consultants estimated that with trade, by 2011, 900 MW of additional capacity could be avoided, the fixed cost savings of which would be about $40 million per year.
76. Both Tajikistan and Uzbekistan would enjoy a share of the above benefits. In the short term the benefits of enhanced trade were estimated on the basis that agreement is reached for Uzbekistan to import the surplus summer energy available from the Nurek power station in Tajikistan, on average 1,000 GWh per year as envisaged in the bilateral Power Trade Relations Agreement. Instead of spilling and wasting this water, as at present, the net economic benefit that could be shared by both countries is estimated at $12 million based on 1.2 c/kWh. The benefit is calculated as avoided generation costs (fuel and variable cost) to Uzbekistan of 1.9 c/kWh less transmission cost of 0.5 c/kWh and the negligible Tajik generation cost of 0.2 c/kWh. The share of the benefit will be based on the price agreed. The upper bound price that Uzbekistan could pay is 1.65 c/kWh and the lower bound price that Tajikistan could accept is 0.45 c/kWh, assuming transmission costs are equally shared. This gives a clear demonstration of the potential benefits of trade and would, if included in the foregoing viability analysis, significantly enhance returns.
C. Social and Poverty Impact
77. The primary beneficiaries of the Project will be business enterprises and the population who will benefit from improved quality of electricity services and the long-term cost reductions resulting from the economic dispatch of power plants and the overall efficiency gains from enhanced power trade. Since effectively all the population of both Tajikistan and Uzbekistan have access to electricity, the project benefits will be universal.
78. Electricity supply is a prerequisite for improving the economic situation and quality of life, as it is required for agriculture (irrigation and drainage), drinking water supply, health, education, 19 industry, and small-scale enterprises. Adequate and reliable power supply will remove an important obstacle to investment and facilitate operation of private enterprises. Agriculture will benefit due to improved irrigation and drainage. Direct and indirect health benefits include (i) improved drainage that will reduce the risks from malaria, and saline water in farmland and water tables; (ii) improved water supply through use of electric pumps; and (iii) ability to boil water efficiently thus reducing risks from unsafe water. Provision of lighting and heating in schools will improve the education facilities and increase school enrollment.
79. In terms of poverty impact, the difference between the financial and economic net present values, and consequent gains and losses for different stakeholders, provide the basis for considering the impact of the Project on the poor. For the poverty impact assessment, the project beneficiaries are divided into three groups: utility, consumers, and government economy. The net economic benefits of the latter two groups are distributed between poor and nonpoor. The increased, more efficient, and reliable electricity supply resulting from the Project will benefit the poor directly and indirectly. Net economic benefits accruing to the poor over the life of the Project are estimated at about $46 million–$17 million for Tajikistan and $29 million for Uzbekistan (Appendix 15). These estimates are conservative as the benefits of trade and some indirect economic and social benefits are not considered. The poverty impact ratio, which expresses the proportion of net economic benefits of the Project accruing to the poor, is estimated at 41%–57% for Tajikistan and 35% for Uzbekistan. Hence, a substantial portion of the project benefits will go to the poor.
80. Under the project preparatory TA, a social assessment was carried out and a summary of the assessment is in Appendix 16. The assessment found that the risk of negative socioeconomic impacts is small or nonexistent. The main conclusions are as follows:
(i) In terms of output-using employment, it is expected that the improved adequacy and reliability of electricity supply will support the creation of new employment opportunities in terms of higher productivity for all sectors of the economy. In Uzbekistan, 6,000 output-using jobs are expected to be created, and in Tajikistan the number is expected to be 2,200.
(ii) There will only be a small direct input-supplying employment impact since the Project involves relatively few civil works and the expertise required for the installation of the new equipment is unavailable in either country.
(iii) Gender inequality was identified in terms of poverty incidence and wage levels. It is expected that the Project’s poverty impact will be greater for men than for women since men are expected to be in a better position to take advantage of employment opportunities as a result of a more reliable power supply.
(iv) Affordability of electricity tariffs is a potential issue that needs to be considered as increases are implemented to cover the cost and ensure sustainable supply of electricity. Tajikistan maintains a lifeline tariff and the EBRD tariff study will consider the tariff levels for each consumer category in Uzbekistan.
(v) There will be no issues of resettlement or indigenous peoples since the rehabilitation and upgrading activities will be undertaken in existing facilities.
20
D. Environmental Impacts
81. The Project will have considerable environmental benefits as a result of more optimal system operation, transmission loss reduction, and substitution of thermal generation with renewable hydropower as a result of enhanced power trading. It is estimated that the energy savings as a result of efficiency improvements alone in 2011 will be 330 GWh and the direct fuel savings 274,000 tons of coal equivalent.
82. The Project is not expected to have any major adverse impact on the environment. It consists entirely of rehabilitation of existing structures and facilities. The rehabilitation includes replacing switchgear and transformers at existing substations and retrofitting new components to existing equipment. The Project has been classified as Category B in ADB’s environmental classification system. An initial environmental examination was undertaken according to ADB’s guidelines at the feasibility study stage (Appendix 17).
83. The adverse impacts of the Project will be very small, and will be limited to the construction period. During the stringing of the new optical ground wire, trucks and equipment need access over the whole route of the transmission line, i.e., over 1,000 km in Uzbekistan and about 300 km in Tajikistan. Special arrangements have to be made in order to minimize the impacts on agriculture, such as seasonal implementation schedule, crops compensation mechanisms, stringing under tension, etc. The following waste volumes are estimated to be generated: (i) 26 tons of aluminum, (ii) 601 tons of steel, (iii) 625 tons of ceramic insulators, (iv) 94 tons of insulation oil, and (v) 125 tons of copper. Additional chemical products such as lead, acid, and electrochemical condensers will be disposed from the rehabilitation of control and protection system as well as from the direct current system, especially from the batteries. The ceramic wastes will be disposed in landfills. The insulation oil will be cleaned and filtered, and partly reused or sold as fuel oil. Lead, steel, aluminum, and copper will be sold. Acid and other chemical components will be conditioned and sent to specialized laboratories. Adverse impacts can be readily mitigated through good engineering and construction practices. No negative impact will persist during the operation phase. The governments and EAs have agreed to undertake necessary mitigative measures during optical ground wire stringing and to remove and dispose of all waste materials associated with the Project, in a safe and environmentally responsible manner. An environmental monitoring program will be prepared and implemented.
E. Project Risks
84. The Project has been formulated to minimize potential technical and economic risks. The main risks are identified and discussed below.
85. Political Commitment. Active involvement of participating countries and continued commitment to improve energy supply services, energy trade and to resolve the energy-water nexus will be key to maximizing the benefits of the Project. ADB’s continued engagement with the cooperating countries and active role in regional cooperation as an honest broker will help facilitate improved regional relations for the benefit of all the countries. In the event that regional trade does not achieve expectations, the Project investments will remain viable, as they have been shown to be fully justified on the basis of the domestic benefits alone.
86. Financial Sustainability. For the utilities to be able to provide counterpart contributions and meet ongoing O&M costs requires financial viability. This implies that tariffs need to be adjusted to allow the utilities to (i) fully recover operating costs and earn a reasonable return on capital, and (ii) generate sufficient revenue to cover the contribution to the Project and to meet 21 debt service requirements. In addition, the utilities have to improve collection performance. Financial covenants have been agreed to mitigate this risk.
87. Project Delay. There is risk of project delays due to (i) the nature of rehabilitation projects and since they will be implemented at several locations in parallel, and (ii) lack of experience with ADB procurement under ICB and ADB’s procurement procedures. The risk of project delays would be actively managed through close monitoring of implementation progress by the PIU, which will be assisted by experienced international consultants, training in ADB’s procurement and disbursement procedures, and regular ADB review missions.
88. Cost Overruns. The risk of cost overruns due to (i) uncertainties in the precise scope of rehabilitation and upgrading work, and (ii) possible increases in inflation, is modest. The use of ICB for procurement under all contracts funded by the ADB will minimize the risk of cost overruns, as will the use of turnkey contracts. Finally, the physical and price contingencies are designed to allow for uncertainties in project scope and in inflation.
89. Inadequate Plant Maintenance. Several measures have been included in the design of the Project to reduce the potential risks of inadequate plant care and maintenance, which has been a problem in the past. An on-the-job training component has been included in each contract package to provide exposure to the proper O&M procedures for the new and rehabilitated equipment. International consultants will also provide training and O&M support during implementation of the Project so that the rehabilitated and modernized facilities will be managed properly after commissioning.
IV. ASSURANCES
A. Specific Assurances
90. In addition to the standard assurances, the governments and EAs have given the following assurances, which are incorporated in the legal documents:
91. Trade Enhancement. The governments will:
(i) implement the bilateral Power Trade Relations Agreement with provisions listed in para. 29; (ii) take all necessary steps to implement the actions in the Regional Power Trade Action Plan within their direct control, and take an active role in the implementation of the necessary cooperative actions involving other countries; and (iii) provide ADB with annual reports on the progress of implementation of the bilateral Power Trade Relations Agreement and their individual initiatives in furthering the purposes of the Regional Power Trade Action Plan.
92. Financial Matters. The EAs will take all necessary measures including tariff adjustment to comply with the following financial covenants:
(i) achieve a working ratio of no more than 90% in 2003, 85% in 2004, 75% in 2005 and 70% from 2006 onward for Uzbekenergo; (ii) achieve a rate of return on net fixed assets in service of at least 6% from 2006 onward for Barki Tajik; 22
(iii) maintain accounts receivable at no more than 3 months of billings by 31 December 2004 onward for both Barki Tajik and Uzbekenergo; and (iv) maintain net revenues at a level that will produce internally generated funds equal to at least 1.3 times the maximum debt service requirement – this is to apply to both Barki Tajik and Uzbekenergo.
93. Governance. The governments will ensure that:
(i) the EAs will provide adequate funds for independent annual audits, acceptable to ADB, for project accounts and corporate accounts; and (ii) if the EAs undergo any major reorganization or privatization during the term of the loan, the concerned government, the EA and ADB will review the terms of the ADB loan agreement with a view to making any amendments that may be deemed necessary.
94. Environment and Safety Measures. The governments will ensure that:
(i) the Project is carried out, and all Project facilities are operated and maintained, in accordance with the existing laws, regulations, and standards of the relevant government concerning environmental protection and ADB's environmental guidelines, in particular, ADB's Environmental Guidelines for Selected Infrastructure Projects; (ii) each EA takes all necessary measures to handle and dispose of, in a safe and environmentally responsible manner, all discarded materials and all hazardous waste materials associated with the Project; (iii) either they or the EAs will provide for adequate funds annually for O&M and will operate and maintain the project facilities in accordance with all national safety and O&M guidelines and also those identified by the project implementation consultants, including safe storage of construction, rehabilitation, and maintenance materials to prevent contamination of soil and water with fuel and lubricants; and (iv) project activities will not include any land acquisition or resettlement.
95. Benefit Monitoring and Evaluation. The EAs will carry out benefit monitoring and evaluation of the Project in accordance with ADB’s guidelines.
B. Conditions of Loan Effectiveness
96. In addition to the standard conditions, the following further conditions for effectiveness of the Loan Agreements, have been incorporated in the legal documents:
(i) the bilateral Power Trade Relations Agreement with the provisions listed in para. 29 must have been signed; (ii) subsidiary loan agreements, satisfactory to ADB, will have been delivered on behalf of the governments and the respective EAs, and will be fully binding, subject only to the effectiveness of the ADB Loan Agreement; (iii) in the case of the Uzbek component, the funds required under the EBRD loan must have been obtained; and 23
(iv) a cross effectivity provision is included under both components, so that for one loan to become effective, the other must as well.
V. RECOMMENDATION
97. I am satisfied that the proposed loans would comply with the Articles of Agreement of ADB and recommend that the Board approve
(i) the loan of $70,000,000 to the Republic of Uzbekistan for the Regional Power Transmission Modernization Project from ADB’s ordinary capital resources with interest to be determined in accordance with ADB’s LIBOR-based lending facility; a term of 25 years, including a grace period of 5 years; and such other terms and conditions as are substantially in accordance with those set forth in the draft Loan and Project Agreements presented to the Board; and
(ii) the loan in various currencies equivalent to 15,133,000 Special Drawing Rights to the Republic of Tajikistan for the Project, from ADB’s Special Funds resources with an interest charge at the rate of 1% per annum during the grace period and 1.5% per annum thereafter; a term of 32 years, including a grace period of 8 years; and such other terms and conditions as are substantially in accordance with those set forth in the draft Loan and Project Agreements presented to the Board; and
(iii) the administration by ADB of the loan in an amount of $2,400,000 to the Republic of Tajikistan for the Project to be provided by the OPEC Fund.
TADAO CHINO President 22 November 2002 24 Appendix 1
PROJECT FRAMEWORK
Design Summary Performance Targets Monitoring Mechanism Assumptions and Risks 1. Goal · Efficiently meet energy · Economic internal rate of · National statistics · Stable domestic and requirements of each return >20% regional political Central Asian country to Poverty impact ratio >40% · Country and sector review environment support economic missions · Active involvement of development and poverty · Project review missions reduction participating countries and · Policy dialogue with continued commitment to improve energy supply government agencies services and energy trade, and to resolve the energy - water nexus
2. Objective/Purpose · To improve the operation · Reduction of unserved · Unified dispatch center and · Political commitment on free and efficiency of the energy due to forced national dispatch centers exchange of power between regional power transmission outages. Saving 135 statistics participating countries system and enhance gigawatt-hours (GWh) in economic power trade 2011 · Statistics from ministries, · Simultaneous phased among the Central Asian utilities, energy market development in the republics. Under the · Reduction of technical management organizations, countries toward an energy Project, the focus will be on transmission network and regulatory commissions market environment modernizing the losses. Saving 185 GWh in in the individual countries 2011 · Tariff reform and improved transmission systems of · Project review missions cost recovery and Tajikistan and Uzbekistan · Optimization of generation. collections and enhancing the power Reduce fuel for power trade relations between generation by 1%. · Low institutional capacity them. · Increased exchange of · Adequate plant energy between the maintenance countries and between energy companies. At least 500 GWh for Tajikistan and Uzbekistan by 2006 3. Outputs · Rehabilitated and · Regar in Tajikistan; · Quarterly progress reports · Cost sharing for refurbished 500 kilovolt (kV) Tashkent, Surkhan, Lochin, prepared by the consultants investments and operation substations and switchgear Guzar, Karakul, Tashkent and maintenance (O&M) of TPS, Novo Angren TPS, · Project review missions unified dispatch center
Syr Darya TPS in · Taking over certificates agreed Uzbekistan prepared by the consultant · Funds covering local project for respective contract · Rehabilitated and upgraded · Unified dispatch center and costs made available national dispatch centers packages dispatch and · Funds for O&M of project communication facilities new computer hardware · Project completion report and software. Associated components made available SCADA and tele- · No delay in project communications for the implementation regional transmission networks · Adequate project management · New metering · Cross-border metering systems for the regional · Procurement of high-quality transmission networks equipment and material · Improved policy, institutional · Bilateral Power Trade · Cooperation of concerned and regulatory environment Relationship Agreement government agencies in for the Central Asian grid implemented by Tajikistan providing required and Uzbekistan by end information and data 2003. Progress on the Power Trade Action Plan
Appendix 1 25
Design Summary Performance Targets Monitoring Mechanism Assumptions and Risks
4. Inputs · Procurement of consulting · $83.8 million: rehabilitation · Review by implementation · Timely recruitment of services for design, and refurbishment of the consultants: monthly consultant tendering, and 500 kV substations and progress reports, quarterly implementation of all project switchyards progress review report · Timely issuance of supply components and erection contracts and · $49.9 million: unified and · Contract site meetings efficient performance of · Procurement of supply and national dispatch centers, contractors construction contracts for communication systems, · Review of tender implementation of the and metering documents for the project · Beneficiary’s project team project pac kages packages nominated · $8.4 million: consulting · Procurement of consulting services · Payment certificates for · Timely availability of local services for elaboration of respective contracts for all funds policy and institution-related · $18.0 million: physical and implementation packages price contingencies · Cofinancing availability studies and documents · Review missions · $15.4 million: interest during · Training activities to ensure · Project accounts sustainability of all project construction components · Total project cost: $175.5 · Training evaluation report and training certificates million issued
26 Appendix 2
CENTRAL ASIA POWER SYSTEM
A. Overview
1. The high-voltage (HV) transmission networks of South Kazakhstan, Kyrgyz Republic, Tajikistan, Turkmenistan and Uzbekistan are interconnected and form the Central Asia Power System. This transmission system was built up starting in the 1960s up to the dissolution of the Soviet Union in 1991, without any consideration of the borders of the five states and based purely on output maximization. The system consists of 3,770 kilometers (km) of 500 kilovolt (kV) lines, 16,200 km of 220 kV and 41,820 km of 110 kV lines. The installed capacity of transformers in the substations of 110 kV voltage level and above amounts to more than 62,000 megavolt-amperes (MVA), including 17,170 MVA at 500 kV substations and 22,300 MVA at 220 kV substations.
2. The majority of the transmission lines are single circuit lines. For reliability reasons various 500 kV and 220 kV ring configurations have been formed to avoid interruption of power supply in case of an outage of a single section. There were plans for more 500 kV and 220 kV lines to complete further ring schemes but since the dissolution of the Soviet Union none have been built. Although to some extent the 220 kV system can take over load from the 500 kV system in the event of its outage, there are still various sections which do not have sufficient capacity to cope with these situations. During such events, partial or total black-outs of the electrical system have been recorded. The present condition of the electrical equipment in the substations in all countries, except for Kazakhstan, requires rehabilitation and substantial replacement at all voltage levels. Most of the equipment has already reached the end of its technical service life.
3. Total installed generation capacity amounts to close to 25,000 megawatt (MW), of which 9,000 MW is hydro power plants (37%) and around 16,000 MW thermal power plants (63%). The major hydro power plants are located in Kyrgyz Republic (2,950 MW hydro capacity) and in Tajikistan (4,021 MW hydro capacity) whereas the major thermal power plants are located in Uzbekistan, Kazakhstan and Turkmenistan. Many of the power plants were constructed as long ago as in the 1950s and 1960s, with no major overhaul since then, and so have reached the end of their technical service lives.
B. Kazakhstan
4. The electrical network of Kazakhstan consists of two parts. The northern grid is part of the Russian Federation, and the southern grid is part of the Central Asia Power System. A 500 kV single circuit line connects the northern and southern grids, which frequently shows stability problems. The entire system comprises around 23,500 km of 1,150 kV, 500 kV, 330 kV and 220 kV transmission lines as well as three 1,150 kV and fifteen 500 kV substations. Moreover, it includes around 440,000 km of power lines below the 220 kV level. In South Kazakhstan, the grid consists of four 500/220 kV substations and about 1,080 km of 500 kV and 1,300 km of 220 kV transmission lines. The southern grid in Kazakhstan has an installed generation capacity of 2,422 MW, of which 2,058 MW is thermal and 364 MW hydro plants. Total installed generation capacity in Kazakhstan is around 16,000 MW (2,057 MW hydro, 8,100 MW conventional thermal and 5,622 MW combined heat and power (CHP) plants). 75% of the thermal power plants are coal fired plants, the rest uses oil and gas.
Appendix 2 27
C. Kyrgyz Republic
5. The electrical network in Kyrgyz Republic is connected by 500 kV and 220 kV lines with the grids of Kazakhstan and Uzbekistan. The system in the country includes about 540 km of 500 kV and 1,250 km of 220 kV transmission lines. Apart from two CHP stations in Bishkek (742 MW) and Osh (50 MW), the electricity supply system of Kyrgyz Republic depends on hydropower as its primary energy source. Total installed generation capacity is about 3,742 MW, of which almost 3,100 MW is presently available.
D. Tajikistan
6. The HV transmission system in Tajikistan consists of a northern and a southern part which are connected only indirectly through the Uzbekistan system. Tajikistan is also connected with Afghanistan via a 110 kV transmission line operated at 35 kV. Total lengths of the transmission lines are 300 km and 1,200 km for the 500 kV and 220 kV systems respectively. In addition, about 2,800 km of 110 kV transmission lines is in operation. Tajikistan’s generation capacity currently consists of 4,021 MW of hydro capacity and a 300 MW CHP plant in Dushanbe. The output of the CHP plant is currently severely limited because of fuel shortages.
E. Uzbekistan
7. The network of Uzbekistan is the main part of the Central Asia network supply linking the systems of Kazakhstan, Kyrgyz Republic, Tajikistan and Turkmenistan. The HV transmission system consists primarily of some 1,700 km of 500 kV and 5,100 km of 220 kV lines. Uzbekistan has a 220 kV transmission connection to Afghanistan. Uzbekistan also represents close to 50% of the generation capacity of the joint Central Asian system (11,600 MW of 25,000 MW). It includes 9,873 MW of thermal and 1,705 MW of hydro plants. Of this installed capacity, around 8,400 MW of thermal power and 1,400 MW of hydropower are actually available for generation.
F. Turkmenistan
8. The electrical network of Turkmenistan is connected with the network of Uzbekistan by two transmission lines, one of 500 kV and the other 220 kV. Turkmenistan uses only thermal power plants with an installed capacity of 2,600 MW, of which presently only around 1,500 MW is available for operation.
28 Appendix 3
PROBLEM ANALYSIS
Limited Economic Development and Poverty Reduction Effects
Lost Economic Negative Energy Losses & Power Outages & Trading Environmental High Operation Cost Unserved Energy Oppurtunities Impact
Suboptimal Regional Power Core Problem System Operation & Trade Causes
Policy, Legal and Regional Transmission Payment/ Regulatory Coordination and System Technical Pricing Problems Settlement Institutional Constraints Problems Problems Problems
Self Sufficiency Lack of Independence Obsolete and Old Noneconomic Currency Exchange
Policies of UDC Equipment Pricing of Fuels Problems
Energy Water Nexus Financial Mgt. Suboptimal Operation Low End-User Tariffs Arrears
Problems of Grid in Each Country
Lack of Enforcement Inappropriate Inadequate Water Energy Barter Trade
of Contracts Operating Regime Maintenance Problem
Varying Stages of Human Resource Valuing of Ancilliary Inadequate Metering
Sector Restructuring Constraints Services
Lack of Free Access Setting of Wheeling
to Transmission Lines Charges
Lack of Regulatory
Entities
UDC=Unified Dispatch Center
Appendix 4 29
EXTERNAL ASSISTANCE
Country Asian Development Bank External Funding Agencies No. Project/TA Name Amount Approval ($ m) Date
Kazakhstan TA 2262 Almaty Air Quality Study 0.10 Dec-94 World Bank provided financing for an electricity TA 2366 Rehabilitation and Environmental Improvement 0.56 Jul-95 transmission rehabilitation project with cofinancing of the Almaty No. 1 Heat and Power Station by EBRD.
TA3674 Energy Sector Study 0.25 Jun-01 0.90
Kyrgyz Republic TA 2542 Revaluation and Tariff Study for Kyrgyz National 0.31 Mar-96 World Bank cofinanced the Power and District Energy Holding Company (KNEHC) Heating Rehabilitation Project with ADB. 0.31 LN 1443 Power and District Heating Rehabilitation 30.00 Jun-96 30.00 Tajikistan TA 3207 Power Sector Development 0.85 Jun-99 IDB and Switzerland provided cofinancing for the Power Rehabilitation Project. The Kuwait Fund TA 3600 Improving Barki Tajik's Billing and Collection 0.50 Dec-00 supported the rehabilitation of power distribution System facilities in Dushanbe. World Bank, IFC and the TA 3601 Introducing International Accounting Standards 0.50 Dec-00 Aga Khan Foundation financed a private sector at Barki Tajik power project in the Eastern region. 1.85 LN 1651 Postconflict Infrastructure Program 20.00 Dec-98 LN 1817 Power Rehabilitation 34.00 Dec-99 54.00 Turkmenistan
Uzbekistan TA Energy Needs Assessment 0.85 Dec-02 EBRD provided financing for the Syrdarya power 0.85 station rehabilitation. The Government of Japan is financing power station rehabilitation and new facilities.
Regional TA 5663 Kyrgyz Republic and Xinjiang Uygur 0.36 Dec-95 USAID provided support for a regional working Autonomous Region Power Development Study group to develop a regional power pool. Various legal documents were developed and the most TA 5960 Regional Power Transmission Modernization 0.90 Dec-00 important achievement was the execution of the Project in Central Asian Republics “Parallel Operations Agreement” between TA 6023 Regional Gas Transmission Improvement 0.90 Mar-02 Kazakhstan, Kyrgyz Republic, Tajikistan and Project Uzbekistan in 1999. 2.16
ADB = Asian Development Bank, EBRD = European Bank for Reconstruction and Development, TA = technical assistance IDB = Islamic Development Bank, IFC = International Finance Corporation, USAID = United States Agency for International Development 30 Appendix 5
DETAILED TECHNICAL SCOPE
Tajikistan
Table A5.1: Substations
Substation Regar Item 500 kV voltage transformer (set) 3 500 kV surge arresters 6 220 kV voltage transformer (set) 2 220 kV control system/diameter 12 220 kV protection sets/diameter 13 220 kV coupling capacitor 4 220 kV surge arresters 16 35 kV 1600 kVA auxiliary transformer 1 35 kV circuit breaker and support 1 35 kV shunt reactor 1 Mobile transformer oil treatment trailer 1
kV=kilovolt, kVA=kilovolt ampere
Table A5.2: Dispatch, Communications, and Metering
Item Quantities NDC hardware-software 1 ADCs hardware-software 2 RTUs and interfaces 17 Optical ground wire (km) 316 Fiber optic communication equipment 8 Power line carrier terminals 5 Main telephone exchanges 2 Subtelephone exchanges 2 Remote subscribers 5 Metering management system 1 Energy meters 40 Meter reading equipment 12
ADC=area dispatch center, km=kilometer, NDC=national dispatch center, RTU=remote terminal unit
Appendix 5 31
Uzbekistan
Table A5.3: Substations
Substation Tashkent Surkan Lochin Guzar Karakul Novo Tashkent Syr Item Angren TPS Darya 500 kV circuit 6 3 5 8 6 8 3 17 breaker 500 kV current 6 3 4 8 6 8 3 17 transformer (set) 500 kV voltage 2 2 2 2 2 2 2 2 transformer (set) 500/220 kV grid 0 0 0 0 0 0 2 1 transformers 500 kV control 3 2 3 3 4 3 2 6 system/diameter 500 kV Protection 3 2 3 3 4 3 2 6 sets/ diameter 220 kV circuit 0 9 11 8 13 14 17 23 breaker 220 kV current 11 9 11 8 13 14 17 23 transformer (set) 220 kV voltage 3 3 3 3 3 5 3 5 Transformer (set) 220 kV control 11 9 11 8 13 14 17 23 system/diameter 220 kV protection 11 9 11 8 13 14 17 23 sets/ diameter DC batteries and 0 3 4 4 3 10 5 8 equipment Compressors 0 0 0 0 0 3 4 4
DC=direct current, kV=kilovolt, kVA=kilovolt ampere
Table A5.4: Dispatch, Communications, and Metering
Item Quantities NDC hardware-software 1 ADCs hardware-software 3 RTUs and interfaces 46 Optical ground wire (km) 1,107 Fiber Optic communication equipment 24 Power line carrier terminals 8 Main telephone exchanges 4 Subtelephone exchanges 8 Remote subscribers 23 Metering management system 1 Energy meters 220 Meter reading equipment 40
ADC=area dispatch center, km=kilometer, NDC=national dispatch center, RTU=remote terminal unit
32 Appendix 6
REGIONAL POWER TRADE
2001
All values in million kWh Northern Kazakhstan Total Generation 91,824 million kWh 3,102.9
Turkmenista n South Kazakhstan Generation 10,510.5 Generation 5,449.5 9.0 Export 1,060.5 Export 3,102,9 Import 0 Import 1,269.3 12.5 Uzbekistan
Generation 47,926.5 1039.1 1,260.3 Export 848.7 Import 1,349.8 564 1,038.1 299.2 248.1 Tajikistan Kyrgyz Republic 34.6 Generation 14,320.5 Generation 13,617.1 Export 333.8 Export 2,376.0 77.6 Import 1,681.2 Import 318.7
2011
All values in million kWh Northern Kazakhstan
Total Generation 117,400 million kWh
3,000
South Kazakhstan Turkmenistan
Generation 5,500 Generation 12,400
Supply from North Import 600 Kazakhstan 3,000
Import from CARs 4,100
Uzbekistan
Generation 51,700 600 4,100
Import 8,900
3,400
5,500
Tajikistan Kyrgyz Republic
Generation 25,100 Generation 22,700
Export 6,100 Export 7,500
KWh=kilowatt hour CARs=Central Asian Republics
Source: RETA 5960: Regional Power Transmission Modernization Project in Central Asian Republics Appendix 7 33
REGIONAL POWER TRADE ACTION PLAN (Agreed in Tashkent on 23 April 2002 by government and utility representatives from Kazakhstan, Kyrgyz Republic, Tajikistan and Uzbekistan)
Objective To improve the operation and efficiency of the regional power transmission system and enhance economic regional power trade and cooperation among the Central Asian Republics. The action plan will encourage inter-country power trading and establish the foundation for a future wholesale regional power market.
OBJECTIVE ACTION TIMEFRAME AND STATUS
1. Policy National Priority Each country to recognize and endorse international 1999 trading of electricity to be an integral component of its Agreement on parallel operation policies to strengthen its electricity sector. signed between all countries except Turkmenistan. Legal and Each country to examine the compatibility of legislation 2003 Regulatory and regulations to ensure the development of the regional Compatibility market. Transmission Each country to establish a clear policy on which entity is Ongoing activity. Kazakhstan and Ownership to own and operate the transmission assets within its Kyrgyz Republic complete. Uzbekistan boundaries and independent management. ongoing expected completion 2003. Tajikistan completion envisaged 2004. Open Access Each country to establish a policy of open access to their 2003 Transmission transmission network. Ongoing activity. Kazakhstan and Kyrgyz Republic complete. Interim transmission access arrangements to be explored.
2. Institutional Ruling Body To propose to the governments of Central Asia to give the 2002/3 Central Asian Electric Power Council the status of inter-
governmental coordinating body for regional power transmission and trade. Executive Body To give the United Dispatch Center (UDC) the status of 2002/3 executive body of the Central Asian Electric Power Efforts to be made to commercialize Council. UDC within an agreed time frame. Regional Establish an expert working group to undertake The Energy System Steering Group Coordination necessary activities to implement the regional power will undertake these activities under trade action plan. direction of the Central Asia Electric Power Council and within the framework of the Parallel Operations Agreement. To be strengthened.
3. Technical Transmission Rehabilitate the 500kV substations and switchyards. Kazakhstan and Tajikistan ongoing. Facilities Replace in each substation all circuit breakers (500 and Priority investment program outlined 220kV), current transformers, protection and control and supported by the meeting. To be systems and the DC system. implemented in phases subject to the availability of resources.
34 Appendix 7
OBJECTIVE ACTION TIMEFRAME AND STATUS
Dispatch and Upgrading of facilities at UDC, national and area dispatch Kazakhstan ongoing. Investment Control Facilities centers and interconnecting telecommunication links. program outlined and supported by Install new remote terminal units in 500kV substations the meeting. To be implemented in and in major power plants parallel to the extent possible subject to the availability of resources. Agreed that UDC has an important future role. The equitable sharing of UDC costs needs to be resolved. Metering Install new trans-border metering together with meter Kazakhstan and Kyrgyz Republic management systems at control centers complete. Investment program in Tajikistan and Uzbekistan outlined and supported by the meeting. To be implemented in phases subject to the availability of resources. Regional Develop and implement an operations protocol that 2007 Operations Protocol establishes procedures and processes as necessary to Agreed that new operations code maintain reliable grid operation and to facilitate trading. essential for improved trading regimes. TA support may be required. Develop further USAID work and use Kazakhstan grid code as model. Unified licensing framework. Metering Protocol Introduce compatible standard metering protocol that will 2003 Agreed that standardized provide the framework for the collection, analysis and metering protocol essential for fair management of power exchanges. trading and settlement.
4. Commercial and Financial Power Trade Develop pro-forma contracts for power trading 2002/3 Agreements Transmission Develop and implement a transparent methodology for 2003 Pricing transmission tariff calculation including procedures for Agree on pricing methodology for asset valuation and fair return on capital. interregional wheeling. Ancilliary Services Develop and implement pricing arrangements for 2003 Pricing ancilliary services (reserve capacity, voltage control etc.) Agree on pricing methodology. Monetize Trade Gradual reduction in barter trade towards cash payment. 2007 Power Pool Ultimately institute a power pool which allows direct 2007 trading between buyers and sellers. The long term goal.
5. Country Reforms
Power Sector Continue the restructuring of the power sector by 2005 Reform liberalization into generation, transmission and distribution for market oriented operation. Electricity Tariffs Implement a program to achieve full cost recovery in end 2007 user power tariffs. The key to financial sustainability of power sectors. Independent Each country to establish an independent regulator and a 2005 Regulation system of regulations. Kazakhstan and Kyrgyz Republic complete. Meeting recognized importance of independent regulation. Operating Each country to develop and implement its own grid 2005 Protocols operational protocol that should be consistent with the Kazakhstan complete. regional protocol.
Appendix 8 35
DETAILED COST ESTIMATES
Table A8.1: Tajikistan Cost Estimate and Financing Plan ($ million)
Item Costs Financing Foreign Local Total ADB OPEC Barki Total Exchange Currency Cost Fund Tajik I. Base Costs a/ Part A: Transmission Substation Rehabilitation Rehabilitation of Regar Substation 3.43 0.16 3.59 1.27 2.16 0.16 3.59 Total Part A 3.43 0.16 3.59 1.27 2.16 0.16 3.59
Part B: Load Dispatch System Upgrading Dispatch and SCADA systems 8.03 8.03 8.03 8.03 Telecommunication Equipment 2.43 2.43 2.43 2.43 Metering 0.21 0.21 0.21 0.21 Installation and Commissioning 2.70 1.95 4.65 2.70 1.95 4.65 Training, Spare Parts, Tools 1.16 1.16 1.16 1.16 Total Part B 14.31 2.16 16.48 14.31 2.16 16.48
Part C: UDC Rehabilitation Share in UDC rehabilitation 0.72 0.72 0.72 0.72 Installation and Commissioning 0.20 0.11 0.31 0.20 0.11 0.31 Total Part C 0.92 0.11 1.03 0.92 0.11 1.03
Part D: Consultancy Services Implementation Consultants 1.18 0.23 1.41 1.18 0.23 1.41 Total Part D 1.18 0.23 1.41 1.18 0.23 1.41 Total 19.84 2.66 22.51 17.68 2.16 2.66 22.51 II. Contingencies
a. Physical contingencies b/ 0.99 0.13 1.12 0.88 0.11 0.13 1.12 b. Price contingencies c/ 1.00 0.23 1.23 0.87 0.13 0.23 1.23
Base Cost + Contingencies 21.83 3.02 24.86 19.43 2.40 3.03 24.86 III. Interest During Construction d/ 0.57 1.57 2.14 0.57 1.57 2.14
TOTAL PROJECT COST 22.40 4.59 27.00 20.00 2.40 4.60 27.00 83% 17% 100% 74% 9% 17% 100% ADB = Asian Development Bank, UDC = unified dispatch center a/ 2002 prices. b/ 5% physical contingencies. c/ Based on 2.45% escalation (annual disbursement 3%, 22%, 65%, and 10%). d/ Assuming 5% used for relending. 36 Appendix 8
Table A8.2: Uzbekistan Cost Estimate and Financing Plan ($ million)
Item Costs Financing Foreign Local Total ADB EBRD Uzbek- Total Exchange Currency Cost energo I. Base Costs a/ Part A: Transmission Substation Rehabilitation 500 kV Circuit Breaker 15.39 15.39 15.39 15.39 500 kV Protection System per diameter 3.25 3.25 3.25 3.25 500 kV Control System per diameter 1.39 1.39 1.39 1.39 500 kV Current Transformers 4.62 4.62 4.62 4.62 500 kV Voltage Transformers 1.26 1.26 1.26 1.26 500/220 kV Grid Transformer 11.21 11.21 6.30 4.91 11.21 220 kV Circuit Breaker 9.28 9.28 9.28 9.28 220 kV Protection System 11.90 11.90 11.90 11.90 220 kV Control System 4.43 4.43 4.43 4.43 220 kV Current Transformers 3.34 3.34 3.34 3.34 220 kV Voltage Transformers 0.88 0.88 0.88 0.88 DC-Supply system (charger and battery) 2.72 2.72 2.72 2.72 Compressors 0.49 0.49 0.49 0.49 Design, Installation & Commissioning 6.11 3.92 10.03 6.11 3.92 10.03 Total Part A 76.28 3.92 80.19 27.08 43.79 9.32 80.19
Part B: Load Dispatch System Upgrading Dispatch and SCADA systems 10.84 10.84 10.84 10.84 Telecommunication Equipment 7.07 7.07 7.07 7.07 PLC and Telephone exchanges 0.65 0.65 0.65 0.65 Metering 0.35 0.35 0.35 0.35 Installation and Commissioning 4.18 3.93 8.10 4.18 3.93 8.10 Training, Spare Parts, Tools 2.12 2.12 2.12 2.12 Total Part B 25.21 3.93 29.14 25.21 3.93 29.14
Part C: UDC Rehabilitation Share in UDC rehabilitation 2.30 2.30 2.30 2.30 Installation and Commissioning 0.64 0.35 0.99 0.64 0.35 0.99 Total Part C 2.94 0.35 3.28 2.94 0.35 3.28
Part D: Consultancy Services Implementation Consultants Part A 3.41 0.60 4.01 3.41 0.60 4.01 Implementation Consultants Part B 1.41 0.21 1.62 1.41 0.21 1.62 TA for Institutional Strengthening 0.70 0.20 0.90 0.70 0.20 0.90 Total Part D 5.51 1.02 6.53 5.51 1.02 6.53 Total 109.94 9.20 119.14 60.74 43.79 14.60 119.14 II. Contingencies a. Physical contingencies b/ 5.50 0.46 5.96 3.04 2.19 0.73 5.96 b. Price contingencies c/ 8.99 0.78 9.77 5.51 3.02 1.24 9.77 III. Interest During Construction d/ Front End Fee 0.70 0.7 0.70 0.70 Interest During Construction 12.43 12.43 12.43 12.43 TOTAL PROJECT COST 137.56 10.44 148.00 70.00 49.00 29.00 148.00 93% 7% 100% 47% 33% 20% 100% ADB = Asian Development Bank, EBRD = European Bank for Reconstruction and Development, PLC = power line carrier, UDC = unified dispatch center a/ 2002 prices. b/ 5% physical contingencies. c/ Based on 2.45% escalation (annual disbursement 1%, 9%, 27%, 45%, and 18%). d/ Assuming ADB LIBOR rate at 6% and capitalized up-front fee.
Figure A9.1: Tajikistan Project Implementation Schedule
Activity 2002 2003 2004 2005 2006 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 Loan Appoval Rehabilitation of substations Recruitment of the consultant Design and preparation of tender documents Bidding period Award of the contracts Manufacturing of equipment Erection Commissioning
Rehabilitation of Dispatch Facilities Recruitment of the consultant Design and preparation of tender documents Bidding period Award of the contracts Manufacturing of equipment Erection Commissioning Appendix 9 37 38
Figure A9.2: Uzbekistan Project Implementation Schedule Appendix 9
Activity 2002 2003 2004 2005 2006 2007 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 Loan Appoval Rehabilitation of Substations Phase I Recruitment of the consultant Design and preparation of tender documents Bidding period Award of the contracts Manufacturing of equipment Erection Commissioning
Phase II Design and preparation of tender documents Bidding period Award of the contracts Manufacturing of equipment Erection Commissioning
Rehabilitation of Dispatch Facilities Recruitment of the consultant Design and preparation of tender documents Bidding period Award of the contracts Manufacturing of equipment Erection Commissioning Appendix 10 39
PROCUREMENT LIST S
Table A10.1: Tajikistan Procurement Packages
Packages Procurement Mode ICB Financing Estimated Tender Source Value No. ($ million)
A. Rehabilitation of 500/220 kV Substations 220 kV Protection and Control Systems ICB 1 OPEC Fund 2.4 500/220 kV Substation Equipment ICB 2 ADB/BT 1.6
B. Rehabilitation of NDC, ADCs, ICB 3 ADB/BT 18.2 Telecommunications, and Metering NDC Hardware and Software ADCs Hardware and Software RTU and Interfaces Optical Ground Wire and Accessories Power Line Carrier, Telephone Exchanges and Accessories Energy Meters and Energy Management System Spare Parts Installation and Commissioning
C. UDC Rehabilitation ICB 4 ADB/BT 1.1 (Tajikistan's Share)
ADB = As ian Development Bank, ADC = area dispatch center, BT = Barki Tajik, ICB = international competitive bidding, kV = kilovolt, NDC = national dispatch center, RTU = remote terminal unit, UDC = unified dispatch center.
40 Appendix 10
Table A10.2: Uzbekistan Procurement Packages
Packages Procurement Mode ICB Financing Estimated Tender Source Value No. ($ million)
A. Rehabilitation of 500/220 kV Substations 500 kV and 220 kV Circuit Breakers ICB 1 EBRD 27.9 500 kV and 220 kV Protection and ICB 2 ADB 23.7 Control Systems 500 kV and 220 kV Current and Voltage ICB 3 EBRD 11.4 Transformers 500/220 kV Grid Transformers ICB 4 EBRD 7.1 500/220 kV Grid Transformers ICB 5 Uzbekenergo 5.6 DC Supply Systems ICB 6 EBRD 3.1 Compressors ICB 7 Uzbekenergo 0.6 Design, Installation and Commissioning ICB 8 ADB and 11.4 Services Uzbekenergo
B. Rehabilitation of NCC, ACCs, ICB 9 ADB and 33.0 Telecommunications, and metering Uzbekenergo NDC Hardware and Software ADCs Hardware and Software RTU and Interfaces Optical Ground Wire and Accessories Power Line Carrier, Telephone Exchanges and Accessories Energy Meters and Energy Management System Spare Parts Installation and Commissioning
C. UDC Rehabilitation ICB 10 ADB and 3.7 (Uzbekistan's Share) Uzbekenergo
ADB = Asian Development Bank, ADC = area dispatch center, BT = Barki Tajik, ICB = international competitive bidding, kV = kilovolt, NDC = national dispatch center, RTU = remote terminal unit, UDC = unified dispatch center.
Appendix 11 41
TERMS OF REFERENCE FOR PROJECT IMPLEMENTATION CONSULTING SERVICES
A. Preconstruction Phase 1. The consultant will be responsible for (i) conducting field visits, (ii) preparation of the conceptual design report, (iii) preparation of tender documents, (iv) assistance during the tendering period, (v) assistance during pre-bid meetings, (vi) assistance during bid evaluation and preparation of bid evaluation report, and (vii) assistance in contract negotiation and preparation of contract documents. The consultant will: (i) Conduct field visits on the project sites and will collect all necessary data for carrying out the conceptual design. Special care will be taken during data collection as well as during conceptual design to the interfaces between existing and new equipment. (ii) Review existing soil tests and foundations calculations to ensure that they can be reused with new equipment. (iii) Prepare a conceptual design study report, including main characteristics of new equipment, drawings (general layout, cross-section drawings, single line diagrams, foundations and steel structure calculations, detailed cost estimate with bill of quantities, implementation schedule, list of recommendations and conclusion, which enable the project implementation unit (PIU) and the Asian Development Bank (ADB) to reach decisions on the technical options available. The report shall provide sufficient details as to be used as a basis for the preparation of technical specifications and tender documents. (iv) Prepare, upon approval of the conceptual design report, the tender document in accordance with ADB and other cofinanciers’ standards and procedures. The tender documents to be prepared will be suitable for a one stage, two envelope turnkey contract and shall include instruction to the bidders, general terms and conditions, particular terms and conditions, technical specifications, price schedules, bill of quantities, and drawings. (v) Seek approval from the PIU, ADB, and other cofinanciers on the tender documents. (vi) Assist the PIU during the tendering period, including but not limited to clarification of tender documents, organization of site visits, attendance during pre-bid meeting if any, bid opening, and bid evaluation. (vii) Participate in the contract negotiations. (viii) Assist during preparation of contract documents.
B. Construction Phase 2. The consultant will be responsible for: (i) engineering design review and approval; (ii) in- factory inspection of main equipment; (iii) supervision of installation, testing, and commissioning; checking; and approval of disbursement; (iv) checking and approval of as-built drawing and operation manuals; and (v) preparation and issuance of provisional taking-over certificates. The consultant will: (i) Prepare a project implementation manual covering project organization, payment procedures, project time schedule, and quality insurance program. The consultant will also establish a computerized project monitoring program using appropriate off-the-shelf software packages. 42 Appendix 11
(ii) Prepare the overall disbursement plan, monitor costs, and maintain project accounts. (iii) Review and approve the engineering design drawings, calculations, delivery program, and documents submitted by the contractor. (iv) Monitor the execution of the Project in line with the project time schedule and with the work program provided by the contractor. (v) Advise the PIU and seek approval from ABD and other cofinancier any variation orders to be issued to the contractor. (vi) Identify any problem areas during project implementation, propose remedial actions, and promptly report any outstanding issues to PIU management. (vii) Conduct field visits at appropriate times during contraction, testing, and commissioning phases of the Project. (viii) Conduct regular meeting with the PIU and the contractor during all the implementation phase. (ix) Advise the PIU on any contractual or technical disputes that may arise between the contractor and the PIU during the implementation phase. (x) Provide support to the PIU for the settlement of contractor claims. (xi) In line with the work program of the contractor, prepare and advise the PIU on the outage planning of existing facilities during implementation. The consultant will pay attention to minimize as much as possible the impact of outages in the supply of power at the national as well as international levels. Considerations, such as seasonal or weekly constraints, will have to be taken into account. (xii) Coordinate with other consultants, contractors, and other parties, which may be involved in the same sites under the same or other project(s). This point is of the utmost importance, especially for the interface works to be carried out in the national control center and in relation with the UDC. (xiii) Coordinate safety measures between live components in operation and components in rehabilitation. (xiv) Witness in-factory inspection and performance tests within the framework of the engineering contract. (xv) Review and approve the settings calculation for protection submitted by the contractor. (xvi) Review and approve the commissioning tests program submitted by the contractor. (xvii) Review and approve the commissioning tests report submitted by the contractor, and attend the commissioning phase. Establish the list of reserves after commissioning and prepare a time frame for the contractor to remove the deficiencies and draw up a monitoring program for the use of the PIU. (xviii) Review and approve the operation and maintenance manuals submitted by the contractor. (xix) Review and approve the as-built drawings submitted by the contractor. (xx) Prepare and issue the provisional acceptance certificate for the works as well as for the spare parts. Appendix 11 43
(xxi) Prepare the final taking-over certificate, along with the final payment to be issued by the PIU after the end of the warranty period and the removal of all deficiencies.
C. Project Administration 3. The consultant will: (i) Keep records of all correspondence between the PIU, the contractor, and the consultant. (ii) Keep records of any disbursement under the Project. (iii) Develop and implement applicable procedures required to ensure adequate control of the manufacturing, factory tests, delivery, and acceptance of the materials and equipment. (iv) Periodically update the overall project disbursement schedule and physical target accomplishment. (v) Prepare the quarterly progress reports to be submitted to the financing institutions. (vi) Prepare and implement an environment monitoring plan on the basis of the environmental impact assessment report (vii) Undertake project performance monitoring and evaluation during the Project and upon completion; prepare the project completion report.
Table A11.1: Uzbekistan Transmission Rehabilitation Consultant Cost Estimate ($'000)
Item FX LC Total ADB Financing Consultants Remuneration and Per Diem i. International 2,673 0 2,673 ii. Domestic 130 0 130 International Travel 300 300 Local Transport 150 0 150 Office Equipment 77 0 77 Administrative Support 40 0 40 Reports and Communications 40 0 40 Contingencies 0 Subtotal (I) 3,410 0 3,410
Government Contribution Counterpart Staff 0 200 200 Office Space 0 200 200 Logistics 0 200 200 Contingencies 0 0 0 Subtotal (II) 0 600 600
TOTAL (I+II) 3,410 600 4,010
44 Appendix 11
Table A11.2: Uzbekistan Dispatch Upgrading Consultant Cost Estimate ($'000)
Item FX LC Total ADB Financing Consultants Remuneration and Per Diem i. International 1,080 0 1,080 ii. Domestic 50 0 50 International Travel 130 130 Local Transport 80 0 80 Office Equipment 30 0 30 Administrative Support 20 0 20 Reports and Communications 20 0 20 Contingencies 0 Subtotal (I) 1,410 0 1,410
Government Contribution Counterpart Staff 0 80 80 Office Space 0 80 80 Logistics 0 50 50 Contingencies 0 0 0 Subtotal (II) 0 210 210
TOTAL (I+II) 1,410 210 1,620
Table A11.3: Tajikistan Implementation Consultant Cost Estimate ($'000)
Item FX LC Total ADB Financing Consultants Remuneration and Per Diem i. International 922 0 922 ii. Domestic 35 0 35 International Travel 75 75 Local Transport 80 0 80 Office Equipment 30 0 30 Administrative Support 18 0 18 Reports and Communications 20 0 20 Contingencies 0 Subtotal (I) 1,180 0 1,180
Government Contribution Counterpart Staff 0 80 80 Office Space 0 80 80 Logistics 0 70 70 Contingencies 0 0 0 Subtotal (II) 0 230 230
TOTAL (I+II) 1,180 230 1,410
Appendix 12 45
POWER SECTOR REFORM
A. Tajikistan
1. In 1998 the Government of Tajikistan issued an energy sector policy statement that envisaged energy sector reform in terms of increasing private sector participation, improving corporate governance of energy enterprises, and allowing cost-based tariffs. Subsequently, an energy sector action plan was formulated with assistance from ADB and is presently under implementation. It provided for an Energy Law and the establishment of a Ministry of Energy. The Law on Energy Sector was passed in October 2000, and the Ministry of Energy was established in December of the same year. Implementing regulations for the Energy Law are presently being prepared. The setting up of an Anti-Monopoly Committee with powers for tariff setting and licensing, is envisaged. Tariff reform to achieve cost recovery levels is being implemented. Barki Tajik, a state-owned enterprise, is responsible for running the power sector operations and the Ministry of Energy is responsible for policy. Plans to unbundle and commercialize Barki Tajik provide that the 12 regional electricity joint-stock companies are to be aggregated into two to four enterprises. The current organization makes no distinction between transmission and distribution. There are no plans to privatize existing generation stations, which will remain bundled with transmission.
B. Uzbekistan
2. In Uzbekistan, Decree No. UP-2812, of 22 February, 2001, creates a Uzbekenergo subsidiary enterprise, UzelectroSet for high-voltage transmission. There are also provisions for future unbundling of combined heat and power companies and regional electricity distribution companies. The Decree also provides for Uzbekenergo to retain controlling blocks of shares in all power generation, transmission, and distribution joint-stock companies that may be set up in the future. Plans for future industry structure call for the gradual corporatization of the thermal power plants and regional distribution networks. Up to 49% of the capital of the corporate entities will be offered to investors; 75% of the shares of enterprises involved in design, civil works, and maintenance formerly under the Ministry will be sold, the assets and operating responsibility of the heat-only plants will be transferred to local governments, and the social infrastructure facilities of Uzbekenergo to be privatized will be listed. Components of the electricity system that will remain state owned include all the hydropower plants, the energy network communications system, the transmission grid (UzelectroSet) and UzEnergoSbyt, an affiliated company of Uzbekenergo that will handle commercial transactions between generation and distribution as well as export sales on a nonprofit basis. Implementation began on 1 July 2001 with the objective of achieving partial privatization by 2005 for generation and 2003 for distribution. The aim is to develop a market for electricity along the lines of that in Kazakhstan.
46 Appendix 13
FINANCIAL PERFORMANCE AND PROJECTIONS
A. Barki Tajik
1. The financial statements of Barki Tajik are presented in Table A13.1 to A13.3. Figures for 1999–2001 are based on actual operations while those for 2002–2010 are projections based on notes and assumptions described below.
Prices, Inflation, and Exchange Rate
2. Prices in dollar terms are assumed to increase in accordance with international inflation at 2.4% per annum. Prices in local currency are expected to increase by 15% (2002 to 2006), by 10% (2007 to 2009), and 7.5% in 2010. The forecast foreign exchange rates are shown below.
2002 2003 2004 2005 2006 2007 2008 2009 2010 Year 2.98 3.35 3.76 4.22 4.74 5.32 5.72 6.14 6.60 Income Statement
3. Sales. Energy sales are estimated to grow at a rate of 1.5% between 2002 and 2007 and at 2.5% from 2008.
4. Tariffs. Tariffs are adjusted to meet the covenants of at least 6% rate of return on net fixed assets from 2006 onward. Real tariff levels are shown below.
Year 2002 2003 2004 2005 2006 2007 2008 2009 2010 cents/kWh 0.81 1.00 1.30 1.70 2.22 2.18 2.23 2.29 2.29
5. Operating Expenses and Taxation. Cost of fuel and cost of purchase power is assumed to grow with increased sales, adjusted for exchange rates and local inflation. Wages, administration expenses, and other local expenses are also adjusted by inflation. Bad debt is calculated at 10% of the accounts receivable each year starting from 2003 and 5% from 2006 onward, while income tax is calculated as 30% of taxable income.
Balance Sheet
6. Fixed assets. The gross fixed assets are indicatively revalued in 2003 at $3.75 billion.
7. Accounts Receivable, Accounts Payable, and Cash. Accounts Receivable and Accounts Payable are modelled as 3 months of revenue and 3 months of operating expenses, respectively, by 2004; minimum cash reserve at 1 month’s operating expenses beginning in 2003.
8. Long-Term Debt. In the forecast are incorporated loans for the ADB Power Rehabilitation Project and the Project.
Cash Flow
9. Capital Expenditure. Average annual capital expenditure is expected to total $933 million from 2003 to 2010 including the Project.
10. Loan Repayments. The principal payments and interest expenses include the Project and other existing and expected lending. Appendix 13 47
Figure A13.1: Barki Tajik Organization Chart
Chairperson
Director General
Generating & Distribution Company Repair, construction, material, technical service enterprises
Tajikpower supply
Northern Region Southern Region Gorno Badahshan Tajik power repair Generation Generation Generation Tajik PS Nurek HPS Pamir HPS Kairakum HPS Baipazi nski HPS Tajik Power Design Vahsh Cascade Small HPS Varzob Cascade Tajik Power Install ation Distribution Yavan CHP Diezel HPS Leninabad PS Dushanbe CHP Tajik Power Research Institute Distribution Distribution Khujand PS Kafarnihon repair factory Central Gorno -Badahshan Electric network Board of Rogun HPS under Uratybe PS Dushanbe construction Yujini Penjiken PS Tajik Power Supervision Kulyab Kulyab Town Tursunzada District Norak State Farm Garm
CHP = Combined Heat and Power Plant HPS = Hydropower Station PS = Power Station
Figure A13.2: Uzbekenergo and its Affiliated Companies
Board of Company
Management
Affiliated Companies Other Enterprises Thermal power Uzelectronetwork Distribution & Other Sectoral Stations Retail Functions Design Thermal electrodesign research institute Angren Tashkent region Tashkent Rural power design research institute Tashkent T ashkent city. Tashkent city Uzenergosale Hydroproject Sredaz energy network design Navoi Andijan Andijan Uzenergorepair Takhiatash Fergana - Fergana Uzenergocommunication Novo -angren Samarkand Samarkand Construction, Erection, Repair Syr-darya Surhandarya Surhandarya ADC enterprises Talimarjan Namangan Namangan Bukhara Bukhara Hydropower Karakalpak Karakalpak stations Kashkadarya Kashkadarya Shahrisabz Shahrisabz Urta-chirchik Jizzak Jizzak Kadarya Navoi Navoi Tashkent Syrdarya Syrdarya N-Bozsu Khorezm Khorezm Coal Joint Stock Chirchik Companies Farhad
Combined Heat & Power
Mubarek Fergana Tashkent 48
Appendix 13 Table A13.1: Income Statements Barki Tajik (somoni '000)
Item Actual Projected 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Operating Data Energy Sales (GWh) 13,310 12,040 12,165 12,352 12,542 12,735 12,932 13,131 13,333 13,666 14,008 14,358 Increase in Energy Sales (%) -9.5 1.0 1.5 1.5 1.5 1.5 1.5 1.5 2.5 2.5 2.5 Average Tariff (c/kWh), incl-vat 0.73 0.68 0.65 0.81 1.02 1.37 1.83 2.44 2.45 2.57 2.70 2.77 Average Tariff (diram/kWh), incl-vat 1.05 1.49 1.63 2.41 3.42 5.14 7.71 11.57 13.05 14.71 16.58 18.28 Increase in Tariff (%), US$ -7.6 -3.3 23.4 26.7 33.6 33.6 33.6 0.4 5.0 5.0 2.6 Increase in Tariff (%), somoni 41.2 9.9 47.1 42.3 50.1 50.1 50.1 12.8 12.8 12.8 10.2 Revenues Energy sales 140,178 179,090 198,885 297,143 429,415 654,329 997,047 1,519,268 1,739,342 2,010,136 2,323,089 2,624,046 VAT 20,360 12,443 8,990 51,131 75,688 116,676 175,916 268,915 311,194 362,992 423,191 486,906 Other Revenue 533 401 3,479 3,630 15,808 31,997 37,751 62,585 91,210 125,112 166,271 240,108 Discounts and Nonpayments (59,876) (91,253) (99,709) (112,041) (80,000) (60,000) (30,000) - - - - - Total Revenue 60,475 75,795 93,666 137,601 289,535 509,651 828,882 1,312,938 1,519,358 1,772,256 2,066,169 2,377,248 Operating Expenses Cost of Power 19,443 60,704 49,713 44,590 58,385 69,468 81,071 96,349 109,436 128,286 150,233 174,443 Wages 4,274 7,207 11,840 15,527 20,629 34,772 45,134 59,334 76,951 86,763 97,825 107,791 Administration 3,787 3,177 7,123 13,241 20,275 33,759 34,889 32,474 34,386 38,771 43,714 48,167 Other expenses 7,677 8,261 15,203 22,590 29,246 41,923 53,446 67,681 84,895 89,040 100,393 110,621 Depreciation/Major Repairs 3,305 3,868 4,284 6,281 104,751 145,082 167,893 194,128 220,244 244,326 275,984 306,649 Total Operating Expenses 38,486 83,217 88,163 102,229 233,285 325,004 382,433 449,967 525,912 587,186 668,148 747,671 Operating Income 21,989 (7,422) 5,503 35,372 56,250 184,647 446,448 862,971 993,446 1,185,070 1,398,021 1,629,577 Financial Expense 73 145 175 300 1,012 1,658 2,421 2,636 2,881 2,881 29,813 30,997 Nonoperating Income 304 (216) 1,206 1,842 2,637 3,360 3,498 3,674 3,104 3,182 3,261 3,343 Exchange rate (loss/gain) 531 (944) (27) ------Bad debt 6,234 4,103 2,341 11,027 9,651 12,741 20,722 16,412 18,992 22,153 25,827 29,716 Taxable Income 16,517 (12,830) 4,166 25,887 48,223 173,608 426,803 847,597 974,677 1,163,217 1,345,642 1,572,206 Income Tax 12,392 (3,546) 2,413 8,284 15,432 55,554 136,577 271,231 311,897 372,230 430,605 503,106 Net Income 4,125 (9,283) 1,753 17,603 32,792 118,053 290,226 576,366 662,780 790,988 915,036 1,069,100
Ratios a Rate Base 138,228 140,920 179,111 211,470 6,912,332 7,380,176 8,386,385 9,527,477 10,728,292 11,860,086 13,221,666 14,824,046 b Operating Ratio (%) 64 110 94 74 81 64 46 34 35 33 32 31 c Working Ratio (%) 58 105 90 70 44 35 26 19 20 19 19 19 d Return on Revalued Net Fixed Assets (%) - - - - 0 2 3 6 6 7 7 7 a Average of beginning and end of year net fixed assets. b Total operating expenses as a percentage of total revenues. c Total cash operating expenses as a percentage of total revenues. d Net income before financial expenses as a percentage of rate base. Source: Staff estimates.
Table A13.2: Balance Sheets Barki Tajik As of 31 December (somoni '000) Item Actual Projected 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Assets Fixed Assets Gross Fixed Assets 181,227 190,479 265,762 265,762 12,550,049 14,508,190 16,789,301 19,412,803 22,024,358 24,432,639 27,598,352 30,664,939 Accumulated Depreciation 43,000 46,868 51,152 57,432 5,637,717 6,660,169 7,864,551 9,282,599 10,697,978 12,038,847 13,548,812 15,066,387 Net Fixed Assets in Service 138,228 143,612 214,610 208,330 6,912,332 7,848,021 8,924,750 10,130,203 11,326,380 12,393,793 14,049,540 15,598,553 Work in Progress Other Constructions 5,119 7,031 145,225 123,168 137,131 153,359 467,862 849,855 1,668,779 2,472,272 3,027,302 3,588,666 ADB Power Rehabilitation - - - - 42,034 101,042 207,073 251,726 - - - - ADB-Regional Power Rehabilitation - - - - 18,407 44,246 90,677 110,231 - - - - Net Fixed Assets 143,347 150,642 359,835 331,498 7,109,904 8,146,668 9,690,362 11,342,015 12,995,159 14,866,065 17,076,841 19,187,218 Long-Term Investment 54,790 46,838 40,678 40,678 94,502 233,523 146,594 250,747 335,578 528,099 747,226 1,023,389 Current Assets Cash 784 3,138 3,200 500 18,304 22,954 41,490 56,334 93,656 122,654 168,594 230,407 Accounts Receivable 48,543 62,043 58,325 98,588 96,512 127,413 207,220 328,234 379,840 443,064 516,542 594,312 Inventories 9,892 14,561 22,301 24,275 19,462 23,156 27,024 32,116 36,479 42,762 50,078 58,148 Total Current Assets 59,219 79,743 83,826 123,363 134,277 173,523 275,734 416,684 509,975 608,480 735,214 882,866 Total Assets 257,356 277,224 484,339 495,539 7,338,683 8,553,714 10,112,690 12,009,446 13,840,711 16,002,644 18,559,282 21,093,474 Equity and Liabilities Equity Capital 167,442 175,634 175,634 175,634 175,634 175,634 175,634 175,634 175,634 175,634 175,634 175,634 Revaluation Surplus - - 193,128 193,128 6,704,002 6,704,002 6,704,002 6,704,002 6,704,002 6,704,002 6,704,002 6,704,002 Reserves 625 766 6,271 6,301 6,301 6,301 6,301 6,301 6,301 6,301 6,301 6,301 Retained Earnings 28,066 18,783 20,326 8,951 324,191 1,456,044 2,834,449 4,526,625 5,911,681 7,617,071 9,696,901 11,723,027 Total Equity 196,133 195,184 395,360 384,015 7,210,128 8,341,981 9,720,386 11,412,563 12,797,618 14,503,008 16,582,838 18,608,964 Long Term Liabilities ADB Loans - - - - 49,463 128,368 277,710 383,421 430,599 462,558 480,929 498,451 Other Loans - - 28,586 28,586 - - 43,080 149,503 536,077 951,363 1,397,473 1,875,804 Deferred Tax Liabilities 11,521 7,689 8,304 8,304 8,304 8,304 8,304 8,304 8,304 8,304 8,304 8,304 Total Long Term Liabilities 11,521 7,689 36,890 36,890 57,766 136,672 329,094 541,228 974,980 1,422,225 1,886,706 2,382,558 Current Liabilities Accounts Payable 49,702 74,328 52,086 63,455 74,978 74,967 71,513 63,960 76,417 85,715 98,041 110,255 Short-Term Loan 1 23 3 19,483 4,114 8,398 ------
Total Current Liabilities 49,703 74,351 52,089 82,939 79,092 83,366 71,513 63,960 76,417 85,715 98,041 110,255 Appendix 13 Total Equity and Liabilities 257,356 277,224 484,339 495,539 7,338,683 8,553,714 10,112,690 12,009,446 13,840,711 16,002,644 18,559,282 21,093,474 Ratios a Current Ratio 1.2 1.1 1.6 1.5 1.7 2.1 3.9 6.5 6.7 7.1 7.5 8.0 Accounts Receivable (months) 9.6 9.8 7.5 8.6 4.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 b Debt/(Debt + Equity) (%) - - - 7 1 2 3 4 7 9 10 11 a Ratio of current assets to current liabilities. b Ratio of long-term debt to long-term debt plus equity. 49
- not available Source: Staff estimates.
Table A13.3: Cash Flow Statements 50 Barki Tajik Appendix 13 (somoni '000)
Item Actual Projected 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Sources Net Income before Interest (11,741) 4,369 17,903 33,804 119,711 292,647 579,003 665,661 793,869 944,850 1,100,098 Depreciation 3,868 4,284 6,281 104,751 145,082 167,893 194,128 220,244 244,326 275,984 306,649
Change in Working Capital 6,479 (26,283) (11,387) 3,043 (37,965) (100,313) (139,288) (49,839) (65,316) (75,214) (80,252) Net Internal Cash Generation (1,394) (17,630) 12,796 141,598 226,828 360,227 633,842 836,066 972,879 1,145,619 1,326,495 Long-Term Loans (3,832) 28,586 (0) 20,877 78,905 192,422 212,134 433,752 447,245 464,481 495,853 Proceeds from Long-Term Investments 7,952 6,160 - - - 86,929 - - - - - Total Sources 2,726 17,116 12,796 162,475 305,733 639,578 845,976 1,269,818 1,420,125 1,610,099 1,822,348
Applications Other Capital Expenditure 3,774 15,081 6,912 13,963 20,001 329,584 388,904 832,886 823,495 884,614 950,269 ADB Power Rehabilitation - - - 42,034 59,008 106,030 44,654 - - - - ADB Regional Power Rehabilitation - - - 18,407 25,840 46,430 19,554 - - - - Debt Service Principal ------Interest 145 175 300 1,012 1,658 2,421 2,636 2,881 2,881 29,813 30,997 Long-Term Investments - - - 53,823 139,021 - 104,153 84,831 192,522 219,127 276,163 Income Tax (3,546) 1,798 8,284 15,432 55,554 136,577 271,231 311,897 372,230 430,605 503,106 Total Applications 373 17,054 15,496 144,671 301,083 621,043 831,132 1,232,495 1,391,128 1,564,159 1,760,535 Net Cash Flow 2,353 62 (2,700) 17,804 4,650 18,535 14,844 37,323 28,997 45,940 61,813 Cash, Beginning 784 3,138 3,200 500 18,304 22,954 41,490 56,334 93,656 122,654 168,594 Cash, End 3,138 3,200 500 18,304 22,954 41,490 56,334 93,656 122,654 168,594 230,407
Ratios Debt Service Ratioa (times) 42.7 139.9 136.8 148.8 240.4 290.2 337.6 38.4 42.8 Self Financing Ratiob (%) 185 190 216 77 144 106 127 142 157 a Ratio of net internal cash generation to debt service requirement. b Ratio of self financing fund to average capital expenditure. - not available Source: Staff estimates.
Appendix 14 51
POWER SECTOR MANAGEMENT INFORMATION SYSTEM: TERMS OF REFERENCE
A. Objective/Purpose
The objective of this technical assistance (TA) is to develop a management information system (MIS) for the purposes of power sector management and tariff regulation. The TA would develop a computerized MIS that would provide a monthly consolidation of all key physical and financial information for Uzbekenergo and its affiliates. It would enable improved control over productivity, costs, and collections and provide key inputs for tariff regulation.
B. Activities
1. Diagnostic (i) Interviews with Ministry of Finance to determine requirements as a regulator (ii) Interviews at Uzbekenergo holding company to determine requirements as shareholder (iii) Inception report (iv) Interviews with management of principle operating entities of Uzbekenergo to determine requirements as operating companies (v) Review of existing reports at various levels in Ministry and Uzbekenergo (vi) Review state of computerization in both Ministry and Uzbekenergo (vii) Development of requirements for tariff regulation, billing, collections management, customer data 2. Stakeholder Consultation on System Requirements (i) Organize workshop (ii) Hold workshop to discuss results of diagnostic and requirements (iii) Prepare diagnostic report 3. High-Level Design Specification (i) Develop specification and bill of quantities for hardware (ii) Develop specification for software 4. Selection of Components (i) Determine available suppliers in Uzbekistan (ii) Develop hardware specifications using available and supported components (iii) Prepare high-level design report 5. Approval of Design (i) Prepare presentation on high-level design (ii) Deliver presentation in a workshop with stakeholders (iii) Await client approval of design 6. Procurement and Delivery of Basic Components (i) Procure workstations (ii) Procure basic PC software (iii) Procure servers and local area networks (iv) Procure MIS system software 7. Preliminary Customization of Software (i) Customize MIS software to meet Uzbekistan requirements (ii) Develop Russian language version
52 Appendix 14
8. Training and Consultation (i) Develop training manual, in Russian (ii) Provide training on preliminary software (iii) Receive feedback on MIS software customization 9. Completion and Commissioning (i) Adapt customization based on feedback received (ii) Edit training manual for final software version (iii) Develop user’s manual, in Russian (iv) Provide final training (v) Design commissioning test (vi) Participate in commissioning and handover test (vii) Supervise “go live” of MIS 10. Follow-up support (i) Provide follow-up support to clients for 6 months.
C. Outputs (ii) Inception report, in Russian and English (iii) Diagnostic report, in Russian and English (iv) High-level design specification, in Russian and English (v) Computer workstations (vi) Local area networks and servers at Uzbekenergo and Ministry of Finance (vii) Customized MIS software, in Russian and English (viii) Training manual, in Russian (ix) MIS user’s manual, in Russian
D. Schedule Estimate
Eight months for all deliverables, with 6 months follow-up thereafter.
E. Executing Agency
Uzbekenergo in close consultation with the Ministry of Finance.
F. Cost Estimates
Table A14.1: Power Sector MIS Cost Estimate ($'000)
Item FX LC Total ADB Financing Consultants Remuneration and Per Diem Table A14.2: Equipment i. International 380 0 380 ii. Domestic 60 0 60 International Travel 30 30 Equipment: Quantity Local Transport 5 0 5 Workstations, with modem 50 Office Equipment 200 0 200 PC software 50 Translation/Interpretation 15 0 15 Server at Uzbekenergo 1 Reports and Communications 10 0 10 Server at Min Finance 1 Contingencies 0 LAN at Uzbekenergo 1 Subtotal (I) 700 0 700 LAN at Min Finance 1 MIS software package 1 Government Contribution Miscellaneous 1 Counterpart Staff 0 100 100 Office Space 0 100 100 Total estimate Logistics 0 0 0 Contingencies 0 0 0 Subtotal (II) 0 200 200
TOTAL (I+II) 700 200 900 Appendix 15 53 FINANCIAL AND ECONOMIC ANALYSIS
A. Least-Cost Analysis
1. There is no technical alternative to the rehabilitation of the high-voltage transmission substations because the further deterioration of substation equipment would increasingly make the transmission system unreliable to deliver electricity from the major generating plants to regional and domestic customers. The automation of dispatch control and metering is also a mandatory requirement for the optimal operation of the regional and the domestic power systems and for economic regional trade.
B. Project Viability Analysis
2. The viability analysis has been undertaken on a conservative basis in terms of improvements in system reliability and optimized operation. The analysis does not include the benefits of power trade.
1. Financial Internal Rate of Return
3. The financial internal rate of return (FIRR) has been estimated for the project components from the perspective of the electric utilities in each country on the basis of the following assumptions. Table A15.1: Assumptions
Assumption Tajikistan Uzbekistan Average life 15 years for dispatch and 25 years 15 years for dispatch and 25 years for substations for substations Estimated total cost (2002 base price $23.6 million $125.1 million plus physical contingencies) Savings in communication expenses $0.17 million/year $0.50 million/year Operation and maintenance cost 0.5% saving. 0.5% saving. savings due to optimal dispatch Fuel cost savings due to optimal 1% saving assumed increasing by 1% saving assumed increasing by dispatch and use of thermal and 2.5% per year with generation 2.5% per year with generation hydropower plants and lower growth. Valued at import price. growth. Valued at financial cost. spinning reserve Transmission loss reduction due to 6% of transmission losses increasing 6% of transmission losses increasing optimal dispatch and more equal by 2.5% per year with generation by 2.5% per year with generation loading of the entire power system growth. Savings valued at the growth. Savings valued at the present average electricity tariff present average electricity tariff adjusted for real tariff movements in adjusted for real tariff movements in future years as per the financial future years as per the financial projections. projections. Improved transmission system Energy not served savings valued at Energy not served savings valued at reliability: 70 % reduction in forced average tariff. In the without-project average tariff. In the without-project outages (45% due to substation situation the outages are assumed to situation the outages are assumed to rehabilitation and 25% due to become progressively worse. become progressively worse. dispatch upgrading) Financial variable generation cost is Financial variable generation cost is added. added. Collateral damage from explosions $1.5 million per incident once every 3 $1.5 million per incident once every 3 savings due to more reliable years for one substation years for 8 substations equipment in substations Income tax. 30% applied to the net positive cash 30% applied to the net positive cash flows after allowance of 5% flows after allowance of 5% depreciation on the capital cost. depreciation on the capital cost.
54 Appendix 15
4. The analysis is presented in Tables A15.2b and A15.3b. Based on the above assumptions, the FIRR for the Project for Tajikistan and Uzbekistan is estimated at 7.0% and 11.3%, respectively. The Project’s weighted average cost of capital (WACC) is difficult to estimate, given the current variable economic conditions prevailing in both countries and the lack of an indicative set of interest rates and rates of return at present. However, using the expected US dollar interest rate for ADB's LIBOR-based loans of 3.9% as a proxy for the WACC,1 the Project components should be financially viable.
2. Economic Internal Rate of Return
5. The viability of the Project was analyzed from a broader national perspective in terms of its economic internal rate of return (EIRR). The financial costs were adjusted to reflect the true economic opportunities forgone and realized on account of the Project. The economic analysis was based on the following additional assumptions:
(i) a standard conversion factor (SCF) of 0.90 for Tajikistan and 0.70 for Uzbekistan; (ii) fuel cost savings due to optimal dispatch valued at gas border price of $43 per 1000m3; (iii) transmission loss reduction valued on the basis of estimated weighted average willingness to pay for electricity of $0.050 per kWh and $0.045 per kWh for Tajikistan and Uzbekistan, respectively;2 and (iv) energy not served savings valued at $0.20 per kWh3; the long run marginal cost of generation added. 6. The analysis is presented in Tables A15.2c and A15.3c. From the above assumptions, the EIRR for the Project for Tajikistan and Uzbekistan is estimated at 30.0% and 24.2%, respectively. These figures are higher than the ADB’s generally accepted cutoff point of 12%.
3. Regional Benefits
7. The foregoing viability analysis considered the project benefits for each country excluding the benefits of increased trade. The additional benefits of enhanced trade were estimated on the basis that agreement is reached for Uzbekistan to import all the surplus summer energy available from the Nurek power station in Tajikistan, on average 1,000 GWh per year. Instead of spilling and wasting this water, as is the case at present, the net economic benefit that could be shared by both countries is $12 million estimated at 1.2 cents/kWh. The benefit is calculated as avoided generation costs (fuel and variable cost) to Uzbekistan of 1.9 cents/kWh less transmission cost of 0.5 cents/kWh and the negligible Tajik generation cost of 0.2 cents/kWh. The share of the benefit will be based on the price agreed. If these expected regional benefits are realized the financial and economic viability of both the Tajik and Uzbek components of the Project will be substantially enhanced.
1 This interest rate is applicable for the relending to Barki Tajik and Uzbekenergo and would also be a proxy for the equity cost of capital on an opportunity cost basis (i.e., the saving if the utilities repaid the current debt). 2 Based on (i) an upper bound of $0.13 per kWh for diesel generation and $0.24 per kWh for kerosene lighting; (ii) a lower bound of present average tariffs, for Tajikistan of $0.005 per kWh and $0.012 per kWh for residential and industry, respectively, and for Uzbekistan of $0.01 per kWh and $0.01 per kWh for residential and industry, respectively; (iii) present demand for Tajikistan of 35% and 65% for residential and industry, respectively, and for Uzbekistan of 16% and 84% for residential and industry, respectively; and (iv) a 0.25 curvature correction factor. 3 The feasibility report quotes a range of $0.40 to $5.0 per kWh of energy not served in other countries; $0.20 per kWh was considered reasonable for Central Asia and would roughly equate with the cost of autogeneration based on a 10% utilization factor. Appendix 15 55
Table A15.2 : Tajikistan Component
Table A15.2a : Assumptions
Item Unit 2003 2004 2005 2006 2007 2008 2009 2010 2015 2020 2025 2030
Fuel Cost Savings mtce .002 .002 .002 .002 .002 .003 .003 System Loss Reduction GWh 49 50 51 52 54 61 69 Outage Reduction GWh 21 22 23 24 25 34 50 47 69 Substation Rehabilitation GWh 13 14 15 15 16 22 32 47 69 Dispatch Upgrade GWh 7 8 8 9 9 12 18
Benefit Values Outage Cost c/kWh 20.0 Fuel Saving - Economic $/tce 43.0 Fuel Saving - Financial $/tce 43.0 WTP Estimate c/kWh 5.0 Expected Real Tariff c/kWh 1.0 1.3 1.7 2.2 2.2 2.2 2.3 2.3 2.5 2.5 2.5 2.5 Variable Gen. Costs c/kWh 0.20
Table A15.2b : Financial Internal Rate of Return ($million)
Item NPV 2003 2004 2005 2006 2007 2008 2009 2010 2015 2020 2025 2030
Incremental Inflow Communication Savings 0.9 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 O&M Cost Savings 0.1 0.01 0.01 0.01 0.01 0.01 0.01 0.02 Fuel Savings 0.5 0.09 0.10 0.10 0.10 0.10 0.12 0.13 Energy Loss Reduction 6.3 1.08 1.09 1.14 1.20 1.23 1.52 1.72 Outage Reduce -Dispatch 1.2 0.17 0.17 0.18 0.20 0.21 0.30 0.44 Outage Reduce -Substation 3.0 0.30 0.31 0.33 0.35 0.37 0.54 0.80 1.18 1.73 Collateral Damage Savings 2.8 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50
Total 14.8 2.32 2.34 2.43 2.53 2.59 3.16 3.78 1.85 2.40
Incremental Outflow Capital Cost 17.2 0.71 5.20 15.36 2.36 O&M 0.8 0.16 0.16 0.16 0.16 0.16 0.16 0.16 0.06 0.06 Outage Energy Cost 0.3 0.04 0.04 0.05 0.05 0.05 0.07 0.10 0.09 0.14 Tax 2.1 0.28 0.29 0.31 0.34 0.36 0.53 0.70 0.16 0.31 Total 20.5 0.71 5.20 15.36 2.84 0.49 0.52 0.55 0.57 0.75 0.96 0.30 0.50
Net Cash Flow (5.7) -0.71 -5.20 -15.36 -0.53 1.85 1.91 1.98 2.02 2.41 2.82 1.54 1.90
FIRR 7.0%
Table A15.2c : Economic Internal Rate of Return ($ million)
Item NPV 2002 2003 2004 2005 2006 2007 2008 2009 2010 2015 2020 2025 2030
Incremental Benefits Communication Savings 0.9 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 O&M Cost Savings 0.1 0.01 0.01 0.01 0.01 0.01 0.01 0.02 Fuel Savings 0.5 0.09 0.10 0.10 0.10 0.10 0.12 0.13 Energy Loss Reduction 12.1 2.19 2.24 2.30 2.36 2.41 2.73 3.09 Outage Reduce -Dispatch 8.8 1.34 1.41 1.48 1.55 1.63 2.18 3.20 Outage Reduce -Substation 22.0 2.41 2.54 2.66 2.79 2.93 3.92 5.76 8.48 12.44 Collateral Damage Savings 2.8 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 Total 47.1 6.71 6.96 7.21 7.47 7.75 9.63 12.87 9.14 13.11
Incremental Costs Capital Cost 16.9 0.70 5.11 15.10 2.32 O&M 0.8 0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.05 0.05 Outage Energy Cost 0.3 0.04 0.04 0.05 0.05 0.05 0.07 0.10 0.09 0.14
Total 18.0 0.70 5.11 15.10 2.52 0.20 0.20 0.20 0.20 0.22 0.25 0.15 0.19
Net Benefit 29.1 -0.70 -5.11 -15.10 4.19 6.76 7.01 7.27 7.54 9.40 12.61 8.99 12.92
EIRR 30.0%
56 Appendix 15
Table A15.2d : Sensitivity Analysis - Internal Rates of Return
Financial Analysis Economic Analysis Case Change in FIRR Sensitivity EIRR Sensitivity Variable (%) Indicator (%) Indicator
(i) Base Case 7.0% 30.0% (ii) Capital Costs +10.0 % 6.0% 1.47 27.7% 0.78 147% (iii) Benefits -10.0 % 5.6% 0.72 28.0% -0.10 66% (iv) Combination of (ii) and (iii) 4.6% 25.7%
Table A15.2e: Distribution Analysis (NPV $m at 12%)
Item Econ. Fin. Difference Govt. Consumers Total
Incremental Benefits Communication Savings 0.9 0.9 0.9 O&M Cost Savings 0.1 0.1 0.1 Fuel Savings 0.5 0.5 0.5 Energy Loss Reduction 12.1 6.3 5.7 5.7 12.1 Outage Reduce -Dispatch 8.8 1.2 7.6 7.6 8.8 Outage Reduce -Substation 22.0 3.0 19.1 19.1 22.0 Collateral Damage Savings 2.8 2.8 2.8 Total 47.1 14.8 32.4 32.4 47.1
Incremental Costs Capital Cost 16.9 17.2 (0.3) (0.3) 16.9 O&M 0.8 0.8 0.8 Outage Energy Cost 0.3 0.3 0.3 Tax 2.1 (2.1) (2.1) Total 18.0 20.5 (2.4) (2.4) 18.0
Net Benefit 29.1 (5.7) 34.8 2.4 32.4 29.1 Adjustment 5.7 (5.7) (5.7) Adjusted Net Benefit 29.1 29.1 (3.3) 32.4 29.1
Poverty Impact Ratio Adjusted Net Benefit (3.3) 32.4 29.1 % of Poor 76% 59% Benefits to the Poor (2. 5) 19.1 16.6 Poverty Impact Ratio 57%
c/kWh = cents per kilowatt hour, EIRR = economic internal rate of return, FIRR = financial internal rate of return, mtce = million ton of coal equivalent, $/tce = $ per ton of coal equivalent, O&M = operation and maintenance, WTP = willingness to pay
Appendix 15 57
Table A15.3 : Uzbekistan Component
Table A15.3a : Assumptions
Item Unit 2003 2004 2005 2006 2007 2008 2009 2010 2015 2020 2025 2030
Fuel Cost Savings mtce 0.24 0.24 0.25 0.25 0.29 0.32 System Loss Reduction GWh 119 122 125 128 145 164 Outage Reduction GWh 70 89 94 99 132 194 118 173 Substation Rehabilitation GWh 40 57 60 63 85 125 118 173 Dispatch Upgrade GWh 30 32 34 35 47 69
Benefit Values Outage Cost c/kWh 20.0 Fuel Saving - Economic $/tce 43.0 Fuel Saving - Financial $/tce 43.0 9 17 26 34 43.0 43.0 43.0 43.0 43.0 43.0 43.0 43.0 WTP Estimate c/kWh 4.5 Expected Real Tariff c/kWh 1.2 1.6 2.1 3.2 3.3 3.4 3.4 3.4 3.4 3.4 3.4 3.4 Financial Generation Costs c/kWh 2.00
Table A15.3b : Financial Internal Rate of Return ($million)
Item NPV 2003 2004 2005 2006 2007 2008 2009 2010 2015 2020 2025 2030
Incremental Inflow Communication Savings 2.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 O&M Cost Savings 3.2 0.6 0.6 0.6 0.6 0.7 0.8 Fuel Savings 49.8 10.1 10.4 10.6 10.9 12.3 14.0 Energy Loss Reduction 19.9 3.9 4.2 4.3 4.4 4.9 5.6 Outage Reduce -Dispatch 6.1 1.0 1.1 1.1 1.2 1.6 2.4 Outage Reduce -Substation 13.1 1.3 2.0 2.1 2.2 2.9 4.2 4.0 5.9 Collateral Damage Savings 22.2 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0
Total 114.0 21.5 22.7 23.2 23.7 27.0 31.4 8.5 10.4
Incremental Outflow Capital Cost 82.8 1.5 11.3 33.4 56.7 22.1 O&M 3.2 0.6 0.6 0.6 0.6 0.6 0.6 0.5 0.5 Outage Energy Cost 11.3 1.4 1.8 1.9 2.0 2.6 3.9 2.4 3.5 Tax 23.1 4.0 4.2 4.3 4.5 5.2 6.2 (0.2) 0.1 Total 117.6 1.5 11.3 33.4 56.7 28.1 6.6 6.8 7.0 8.5 10.7 2.6 4.0
Net Cash Flow (3.6) (1.5) (11.3) (33.4) (56.7) (6.6) 16.1 16.4 16.7 18.5 20.7 5.9 6.4
FIRR 11.3%
Table A15.3c : Economic Internal Rate of Return ($ million)
Item NPV 2002 2003 2004 2005 2006 2007 2008 2009 2010 2015 2020 2025 2030
Incremental Benefits Communication Savings 2.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 O&M Cost Savings 2.7 0.6 0.6 0.6 0.6 0.7 0.8 Fuel Savings 49.8 10.1 10.4 10.6 10.9 12.3 14.0 Energy Loss Reduction 18.5 3.8 3.8 3.9 4.0 4.6 5.2 Outage Reduce -Dispatch 25.7 4.3 4.5 4.7 4.9 6.6 9.7 Outage Reduce -Substation 54.1 5.6 8.0 8.4 8.9 11.9 17.4 16.5 24.2 Collateral Damage Savings 21.5 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 Total 172.4 28.7 31.7 32.7 33.7 40.4 51.4 20.8 28.6
Incremental Costs Capital Cost 78.5 1.5 10.7 31.7 53.9 21.0 O&M 3.1 0.6 0.6 0.6 0.6 0.6 0.6 0.4 0.4 Outage Energy Cost 11.0 1.4 1.7 1.8 1.9 2.6 3.8 2.3 3.4
Total 92.3 1.5 10.7 31.7 53.9 22.9 2.3 2.4 2.5 3.1 4.3 2.7 3.8
Net Benefit 80.1 (1.5) (10.7) (31.7) (53.9) 5.7 29.4 30.3 31.2 37.3 47.1 18.1 24.8
EIRR 24.2%
58 Appendix 15
Table A15.3d: Sensitivity Analysis - Internal Rates of Return
Financial Analysis Economic Analysis Case Change in FIRR Sensitivity EIRR Sensitivity Variable (%) Indicator (%) Indicator
(i) Base Case 11.3% 24.2% (ii) Capital Costs +10.0 % 9.9% 1.22 22.2% 0.82 104% (iii) Benefits -10.0 % 9.1% 0.85 22.3% -0.03 53% (iv) Combination of (ii) and (iii) 7.8% 20.4%
Table A15.3e: Distribution Analysis (NPV $m at 12%)
Item Econ. Fin. Difference Govt. Consumers Total
Incremental Benefits Communication Savings 2.4 2.8 (0.4) (0.4) 2.4 O&M Cost Savings 2.7 3.2 (0.4) (0.4) 2.7 Fuel Savings 49.8 49.8 49.8 Energy Loss Reduction 18.5 19.9 (1.4) (1.4) 18.5 Outage Reduce -Dispatch 25.7 6.1 19.6 19.6 25.7 Outage Reduce -Substation 54.1 13.1 41.0 41.0 54.1 Collateral Damage Savings 21.5 22.2 (0.7) (0.7) 21.5 Total 174.8 117.0 57.7 (1.5) 59.2 174.8
Incremental Costs Capital Cost 78.5 82.8 (4.2) (4.2) 78.5 O&M 3.1 3.2 (0.1) (0.1) 3.1 Outage Energy Cost 11.0 11.3 (0.3) (0.3) 11.0 Tax 23.1 (23.1) (23.1) Total 92.6 120.4 (27.8) (27.8) 92.6
Net Benefit 82.1 (3.4) 85.5 26.3 59.2 82.1 Adjustment 3.4 (3.4) (3.4) Adjusted Net Benefit 82.1 82.1 22.9 59.2 82.1
Poverty Impact Ratio Adjusted Net Benefit 22.9 59.2 82.1 % of Poor 60% 25% Benefits to the Poor 13.8 14.8 28.6 Poverty Impact Ratio 35%
c/kWh = cents per kilowatt hour, EIRR = economic internal rate of return, FIRR = financial internal rate of return, mtce = million ton of coal equivalent, $/tce = $ per ton of coal equivalent, O&M = operation and maintenance, WTP = willingness to pay
Appendix 16 59
SUMMARY POVERTY REDUCTION AND SOCIAL STRATEGY
A. Linkages to the Country Poverty Analysis
Sector identified as a National Priority in TAJ: Yes Sector identified as a National Priority in TAJ: Not yet Country Poverty Analysis? UZB: No Country Poverty Partnership Agreement? agreed UZB: Not yet agreed Contribution of the sector/subsector to reduce poverty: Electricity supply is a prerequisite for improving the economic situation and quality of life, as it is required for agriculture (irrigation and drainage), drinking water supply, health, education, industry, and small-scale enterprises. Adequate and reliable power supply will remove an important obstacle to investments, and facilitate operation of private enterprises. Agriculture will benefit due to improved irrigation and drainage. Direct and indirect health benefits include (i) improved drainage that will reduce the risks from malaria, and saline water in farmland and the water table, (ii) improved water supply through use of electric pumps, and (iii) ability to boil water efficiently thus reducing risks from unsafe water. Provision of lighting and heating in schools will improve the education facilities and increase school enrollment.
B. Poverty Analysis Proposed Classification : Other The Project area covers the countries of Tajikistan and Uzbekistan and out of a total population of 31.2 million, 65% are below the poverty line (83% Tajikistan, 60% Uzbekistan). Greater reliability of electricity supply at lower long-term cost will increase investment and private and public sector productivity. Output using employment generated by the Project is estimated to be 8,800 (2,200 Tajikistan, 6,000 Uzbekistan). Improved power supply will improve the economic situation and quality of life of the poor, as it is required for agriculture (irrigation and drainage), drinking water supply, health, education, industry, and small-scale enterprises. In terms of poverty impact the net economic benefits accruing to the poor are estimated at about $46 million—$17 million for Tajikistan and $29 million for Uzbekistan. The poverty impact ratio is estimated at 41%—57% for Tajikistan and 35% for Uzbekistan. Hence, a substantial portion of the project benefits will go to the poor.
C. Participation Process Stakeholder analysis prepared? No. No specific stakeholder analysis was prepared due to the regional nature of the Project. Participation Strategy No. No specific participation strategy could be undertaken due to the nature of the regional project.
D. Potential Issues
Significant/ Nonsignificant/ Strategy to Address Issues Output Uncertain/ Prepared None No Resettlement None No Gender None No Affordability Not significant Affordability of electricity tariffs is a potential issue that needs to be considered. TAJ maintains a lifeline tariff and an EBRD tariff study will consider tariff levels for each consumer category in UZB. No Labor None No Indigenous None Peoples No Other Risks/ None Vulnerabilities
EBRD = European Bank for Reconstruction and Development, TAJ = Tajikistan, UZB = Uzbekistan. 60 Appendix 17
SUMMARY INITIAL ENVIRONMENTAL EXAMINATION
A. Introduction
1. The Project covers Tajikistan and Uzbekistan and is classified as environmental category B. The summary initial environmental examination (SIEE) has been prepared based on the findings of the feasibility study consultants.
B. Background and Description of the Project
2. The Central Asia power system comprises interconnected high-voltage links encompassing southern Kazakhstan, Kyrgyz Republic, Tajikistan, Turkmenistan, and Uzbekistan. The main transmission lines link the power systems of the five countries for parallel operation. The system shares common operational and service management, planning, information channels and control, and connects 83 power plants, including 29 thermal and 48 hydropower plants, with a total installed capacity of about 25,000 megawatts. The unified dispatch center in Tashkent is responsible for maintaining the balanced and synchronized operation of the power transmission and distribution systems of the five countries. Following the dissolution of the Soviet Union in 1991, the countries maintained their balanced and synchronized operation to allow import and export of electricity among them. Market-oriented issues increasingly play a major role in power system management. However, the regional technical operation protocols are less respected and funds for maintenance and rehabilitation are scarce. Each country has been focusing more on power self-sufficiency rather than establishing a competitive regional market that would achieve economically efficient patterns of trade.
3. The objective is to improve the operation and efficiency of the regional power transmission system and enhance economic power trade among the Central Asian republics. The Project will rehabilitate the 500-kilovolt (kV) substations to improve system reliability, upgrade dispatch and communications facilities to optimize system operation, and install new transborder metering to better measure traded power. Under the Project the focus will be on modernizing the transmission systems of Tajikistan and Uzbekistan.
4. In Tajikistan, the components are: (i) the rehabilitation of the high-voltage Regar substation, and (ii) the rehabilitation of the national dispatch center including the installation of new communications links between the main substations. In Uzbekistan, the components are: (i) the rehabilitation of high voltage substations of Tashkent, Tashkent TPS, Lochin, Novo Angren, Karakul, Syr Darya, Guzar and Sukhan; (ii) the rehabilitation of the national and area dispatch centers including the installation of new communications links between the main substations; and (iii) the rehabilitation of the unified dispatch center in Tashkent.
C. Description of the Environment
5. Tajikistan is characterized by a strongly continental climate with hot, dry summers and cold winters, especially in mountainous areas. Daily temperature fluctuations are usually quite large. The cold winters make heating a necessary for winter months in the whole country. Approximately 97% of the country is mountainous, and almost half of it peaks at altitudes of more than 3,000 meters above sea level. The few flat areas available are intensively used for agriculture, which is carried out almost exclusively under irrigation. For this reason, the considerable water resources of the country, stemming from the high mountain areas, are important for power generation as well as for irrigation. Appendix 17 61
6. Uzbekistan is characterized by a strongly continental climate with hot, dry summers and cold winters, mostly flat-to-rolling sandy desert with dunes; broad, flat intensely irrigated river valleys along the course of the Amu Darya, Syr Darya, and Zarafshon; the Fergana Valley in the east surrounded by mountainous Tajikistan and Kyrgyzstan; and the shrinking Aral Sea in the west. About 40,000 square kilometers (sq km) of flat areas are intensively used for agriculture, which is undertaken almost exclusively under irrigation.
D. Environmental Problems due to the Project Location
7. The Project will be conducted at the existing switchyards/substation sites and at dispatch centers. All substations and switchgears in which rehabilitation measures are foreseen are in the ownership of the power utilities in each country, namely Barki Tajik and Uzbekenergo. There will be no new installations and no need for land acquisition.
8. In Tajikistan optic fiber cables will be installed on the Regar-Novaya-Djangal-Yavan- Bapazin-Lolazor-Sebiston-Nurek 220 kV transmission line, in substitution of the existing earthwire. The transmission line partly crosses mountainous areas, mainly near Nurek and the Varkhsh valley, where crops and households are scarce. The transmission line near Regar crosses a flat area where intensive agriculture is undertaken.
9. In Uzbekistan optic fiber cables will be installed on the Lochin-Uzbekistanskaya-Angren - Tashkent 220 kV transmission line and on the Karakul-Navoiy-Syrdarinskaya-Taskent 220 kV transmission lines in substitution of the existing earthwires. A total of 1,107 km of cable have to be installed under the project. The transmission lines partly cross desert areas, where crops and households are scarce. The transmission lines near the Fergana Valley and around Tashkent cross intensive agriculture areas. Some archeological sites are located in the vicinity of the transmission lines, namely near Bukhara and Samarkand.
E. Potential Environmental Impacts
1. Construction
10. Impacts during construction will be limited apart from normal environmental impacts associated with construction activities such as noise, dust, and waste disposal. During the stringing of the new optical ground wire, access of trucks, equipments have to be allowed all over the route of the transmission line, i.e., over 1,000 km in Uzbekistan and about 300 km in Tajikistan. Special arrangements have to be made in order to minimize the impacts on agriculture, such as seasonal implementation schedule, crops compensation mechanisms, and stringing under tension. Some impacts cannot, however, be fully avoided such as temporary access roads and trimming. Special care will be taken into consideration at the end of the works to mitigate the environmental impacts, such as land slide and land erosion that can appear after these temporary works. The following generated waste volumes are estimated for Tajikistan: (i) 6 tons of aluminum and (ii) 130 tons of steel. Estimated waste volumes in Uzbekistan are: (i) 20 tons of aluminum and (ii) 450 tons of steel. These wastes can be readily sold for recycling.
11. For substation works in Tajikistan, the following waste volumes will likely be generated: (i) 25 tons of ceramic insulators, (ii) 4 tons of insulation oil, (iii) 5 tons of copper, and (iv) 1 ton of steel. In Uzbekistan the waste volumes are expected to be: (i) 600 tons of ceramic insulators, (ii) 90 tons of insulation oil, (iii) 120 tons of copper, and (iv) 20 tons of steel. Additional chemical products such as lead, acid, and electrochemical condensers will be disposed from the rehabilitation of control and protection system as well as from the direct current system, 62 Appendix 17 especially from the batteries. The ceramic wastes will be disposed of in landfills. The insulation oil will be cleaned and filtered, and partly reused or sold as fuel oil. Lead will be sold. Acid and other chemical components (bakelite, electrochemical condensers) will be properly conditioned and sent to specialized laboratories.
2. Operation
12. From an operational point of view, there will be no change from the present operation in terms of electric or magnetic fields due to the proposed rehabilitation works at the substations sites and in their vicinity, as the substations already exist.
13. It will be the same for the transmission lines, as they already exist and the operation of optical ground wires for telecommunications will not present any problem for the environment, as this kind of technology does not create any kind of emissions. Moreover, the optic ground wires will reinforce the grounding of the tower and will then, as a positive impact, reduce the step voltage during storms and lightning.
14. The new power line carrier at substations will not create any radio interference as long as the same frequency band as now is reused. Attention must be paid to this point during the detail design study. The installation of hardware and software in the dispatching will not create any adverse impact on the environment.
F. Mitigation Measures
15. The most important environmental mitigation measure in relation to the Project will be proper disposal of discarded material, especially transformer oil and lead-acid batteries. Contractors and executing agencies (EAs) will be required to filter, sell, or reuse the remaining transformer oil as fuel oil. For other products, the EAs will take appropriate measures for the recycling of the discarded materials. Other material, which cannot be recycled, will be deposited in controlled deposit sites. The EAs will, with the help of the consultants, prepare and implement an environmental monitoring plan.
16. During construction at any site, care will have to be taken to prevent contamination of soil and water with fuel and lubricants. Proper storage in plastic tanks and other preventive measures will have to be included in the contractor bid document and contract document. The EA will assure periodic site monitoring and supervision to ensure compliance.
17. During the transmission line works, the damage to the crops much be reduced as much as possible. This can be achieved through a seasonal implementation schedule, i.e., during a low period of agricultural activities, after the harvest. Where it will not be avoidable, the EA will set up and implement crops compensation mechanisms.
18. Temporary access roads will have to be limited to a minimum, and special techniques such as tensioning stringing will be implemented to the maximum extent. This particular technique will have to be implemented near any archeological sites and other sensitive areas.
19. At the end of the construction period, the contractor will be asked to remove all wastes and to recondition the parts that have deteriorated during the construction phase. Appendix 17 63
G. Findings and Recommendations
20. The Project will improve power supply in the region and will enhance the exchange of energy. Adverse impacts of the project will be very small, and will be limited to the construction period. The most important measures to be taken consist of proper disposal of discarded materials. Adverse impacts can be easily mitigated through good engineering and construction practices. No negative impact will persist during the operation phase. The Project will not involve resettlement or land acquisition. Since all identified adverse environmental impacts are minor and can be mitigated, a detailed environmental impact assessment is not required for the Project.