CENTRAL ASIA

REGIONAL ELECTRICITY EXPORT POTENTIAL STUDY

EUROPE AND CENTRAL ASIA REGION

WORLD BANK, WASHINGTON, D.C.

DECEMBER 2004

The views expressed in this paper are the views of the authors and do not necessarily reflect the views or policies of the Asian Development Bank (ADB), or its Board of Governors, or the governments they represent. ADB does not guarantee the accuracy of the data included in this paper and accepts no responsibility for any consequence of their use. Terminology used may not necessarily be consistent with ADB official terms.

CENTRAL ASIA

REGIONAL ELECTRICITY EXPORTS POTENTIAL STUDY

December 2004

________________________________________ Europe and Central Asia Region The World Bank Washington, D.C.

ACRONYMS AND ABBREVIATIONS

ADB Asian Development Bank BCM billion cubic meters CACO Central Asian Cooperation Organization CAPS Central Asian Power System CARs Central Asian Republics CHP Combined Heat and Power GDP Gross Domestic Product GWh Gigawatt-hour HV High Voltage IGIAs Inter-Governmental Irrigation Agreements JBIC Japan Bank for International Cooperation KEA Kazakhstan Electricity Association kV Kilovolt kWh kilo Watt hour LV Low Voltage MW Megawatt RAO UES Russian Joint-Stock Company Unified Energy System REC Regional Electricity Companies REEPS Regional Electricity Export Potential Study RESW Regional Economic and Sector Work T&D Transmission and Distribution TWh Terawatt-hour UNDP United Nations Development Program USAID United State Agency for International Development WEC Water Energy Consortium

CENTRAL ASIA REGIONAL ELECTRICITY EXPORTS POTENTIAL STUDY

Table of Contents

ACKNOWLEDGEMENT ............................................................................................................... i EXECUTIVE SUMMARY ............................................................................................................ ii CHAPTER I: INTRODUCTION................................................................................................... 1 CHAPTER II: THE WATER ENERGY NEXUS IN THE SYR DARYA BASIN....................... 4

B. The Regional Electricity Export Potential Study................................................................ 7 CHAPTER III: CURRENT STATUS OF THE POWER SECTOR IN THE CENTRAL ASIAN REPUBLICS................................................................................................................................... 8

A. Power System Characteristics............................................................................................. 8 B. Policy Reforms in the Power Sectors of CARs ................................................................ 10 Policies to be Pursued Going Forward...................................................................................... 14

CHAPTER IV: DEMAND SUPPLY BALANCEAND POTENTIAL FOR ELECTRICITY EXPORTS..................................................................................................................................... 15

A. Demand Forecast.................................................................................................................. 15 B. Supply Options.................................................................................................................... 19 C. Demand and Supply Balance and Export Potential ............................................................. 25

CHAPTER V: ASSESSMENT OF NEW GENERATION OPTIONS....................................... 28 A. Technical Assessment .......................................................................................................... 28 B. Economic Assessment.......................................................................................................... 29 C. Financial Assessment ........................................................................................................... 31 D. Sensitivity Analysis.............................................................................................................. 32 Financial Sensitivity Analyses.................................................................................................. 33 E. Competitiveness Assessment................................................................................................ 34 Transmission Needs for Electricity Trade ................................................................................ 34 Competitiveness of Central Asian Electricity........................................................................... 36 Key Conclusions ....................................................................................................................... 36

CHAPTER VI: PROFILE OF THE POTENTIAL EXPORT MARKETS ................................. 38 A. Afghanistan .......................................................................................................................... 38 B. China .................................................................................................................................... 41 C. Iran ....................................................................................................................................... 43 D. Pakistan ................................................................................................................................ 46 E. Russia ................................................................................................................................... 49

CHAPTER VII: INSTITUTIONAL ISSUES.............................................................................. 52 A. Water and Energy Nexus Related Issues ............................................................................ 52 B. Power System Operation Related Issues............................................................................. 52 C. Investment and Related Institutional Issues ........................................................................ 54

CHAPTER VIII: BENEFITS, RISKS AND THE WAY FORWARD ....................................... 62 A. Benefits ............................................................................................................................. 62 B. Risks.................................................................................................................................. 62 C. The Way Forward ............................................................................................................. 65

TABLES

Table ES 1: Gross Electricity Demand Projections ....................................................................... vi Table ES 2: Projected Electricity Supply Increments (TWh)........................................................ vi Table ES 3: Supply Costs from Generation Options ..................................................................... x Table ES 4: Marginal Costs of Generation in Target Markets versus Import Costs ..................... x

Table 1. 1: Primary Energy Resources in Central Asia ................................................................. 1 Table 3. 1: Installed Capacities and Supply/Demand Balances of CARs in 2002 ........................ 8 Table 3. 2: Seasonality of the Electricity Consumption of the CARs in 2002 ............................... 9 Table 3. 3: Losses, Billing and Collections in the CARs in 2002 ............................................... 10 Table 3. 4: Electricity Tariffs in the CARs in 2003..................................................................... 12 Table 3. 5: Shifts in Electricity Trade in Central Asian Power System 1990-2000 .................... 13 Table 4. 1: Gross Electricity Demand Projections: Base Case .................................................... 17 Table 4. 2: Results of Sensitivity Analyses on Demand Forecast ............................................... 18 Table 4. 3: Current and Targeted Electricity Loss Levels in CARs ............................................ 19 Table 4. 4: Composition of the Annual Incremental Supplies..................................................... 25 Table 4. 5: Surplus Electricity Available for Trade (GWh)......................................................... 26 Table 4. 6: Investment in Loss Reduction and Generation Rehabilitation in CARs ................... 27

Table 5. 1: Physical and Technical Details of New Generation Projects .................................... 28 Table 5. 2: Comparison of Economic Cost of Supply with Marginal Costs in Exporting/Importing Countries and Status of Cost Competitiveness ........................................... 30 Table 5. 3: Levelized Tariffs for Generation Options................................................................... 31 Table 5. 4: Results of Sensitivity Analyses on Levelized Tariffs of Generation Projects........... 34 Table 5. 5: Economic and Financial Analysis of Transmission Options...................................... 36 Table 5. 6: Marginal Costs of Generation in Target Markets versus Import Costs ..................... 36

Table 6. 1: Current Electricity Imports by Afghanistan .............................................................. 39 Table 6. 2: Afghanistan – Summary of Energy Demand (GWh) and Peak Load (MW) Forecast....................................................................................................................................................... 40 Table 6. 3: Current Electricity Tariffs in Afghanistan................................................................. 40 Table 6.4: Pakistan Electricity and Peak Demand Projections .................................................... 48

Table 7. 1: Summary of the Central Asia Countries Investment Plans ....................................... 54

FIGURES Figure ES 1: Central Asia Republics Power Development and Trade Strategy ............................ v

Figure 4. 1: Gross Electricity Demand in CARs, Monthly Totals, 2005 - 2025 ......................... 18 Figure 4. 2: Kyrgyz Power System and Location of Kambarata schemes................................... 22 Figure 4. 3: Planned and Existing Hydro Schemes on Vaksh River in Tajikistan ...................... 23

Figure 4.4: Central Asia Export Surpluses .................................................................................. 26

Figure 5. 1: Economic Output Costs of New Projects at different Plant Factors Vs. Average Incremental Costs of National Systems of CARs ......................................................................... 32 Figure 5. 2: Economic Output Cost of New Projects at Different Plant Factors Vs. Generation costs in Target Markets (Excluding Transmission Cost).............................................................. 33 Figure 5. 3: New Transmission Lines Needed For Exports......................................................... 35

Figure 6. 1: Afghanistan’s Cross-Border Electricity Interconnections........................................ 38 Figure 6. 2: Seasonal Load Curve in Iran in 2001 ....................................................................... 44 Figure 6. 3: Power Exports and Imports of Iran .......................................................................... 45

Figure 7. 1: Suggestions for an Institutional Framework for Water Energy Consortium............ 57 Figure 7. 2: Financial Scheme for Development of New Regional Infrastructure ...................... 60

Figure 8. 1 ..................................................................................................................................... 66

BOXES

Box 2. 1: A Brief Summary of the Findings of the CAWENS Report.......................................... 4

Box 7. 1: Two Examples of Jointly owned Hydropower Projects............................................... 59 Box 7. 2: Power links Transmission Project in India................................................................... 61

APPENDIXES (In separate Volume)

Appendix 3.1: Current Status of Power Sectors in Central Asian Republics Appendix 4.1: Electricity Demand Forecasts Appendix 4.2: Incremental and Total Supplies from Supply Options Appendix 4.3: Electricity Demand Supply Balances Appendix 5.1: Economic Analysis of Supply Options Appendix 5.2: Economic Analysis of Transmission Line Options for Exports Appendix 5.3: Financial Analysis of Generation and Transmission Options Appendix 7.1: Establishment of Water Energy Consortium-Conceptual Approaches Appendix 7.2: Laos Theun-Hinboun Hydropower Project Appendix 8.1: Options for De-congesting Southern Central Asian Power System

i

ACKNOWLEDGEMENT

This report was prepared by a team led by Raghuveer Sharma and comprised Anil Markandya, Aman Sachdeva, Marat Iskakov, Venkataraman Krishnaswamy, Nikolay Nikolov and Ms. Suzette Pedroso. The work is part of the wider effort by the World Bank, together with its Development Partners, aimed at improved regional cooperation in Central Asia. The team is grateful to: Mamta Murthi, Mangesh Hoskote and Barry Trembath, who peer reviewed the work; to Martin Raiser and Peter Thomson for providing extensive managerial inputs and quality oversight; and to Dennis de Tray (Director, Central Asia Regional Office) and Hossein Razavi (Director, Infrastructure and Energy Services, ECA Region & Director, Infrastructure Economics and Finance), for providing strategic direction to the work. The team is also grateful to Shigeo Katsu, Vice President, Europe and Central Asia (ECA) Region, for the encouragement and engagement at higher levels of client governments on this high profile topic. The team would like to gratefully recognize the contributions of Matthew Buresch, Natalia Charkova, Yukari Tsuchiya, for helping shape the report to its current form.

ii

Central Asia Regional Electricity Exports Potential Study

EXECUTIVE SUMMARY

Introduction and Key Conclusions 1. The Central Asian Republics1 are endowed with significant energy related natural resources. However, the distribution of these resources is highly skewed. The Kyrgyz Republic and Tajikistan have abundant hydropower potential but negligible amounts of commercially exploitable fossil fuels. In contrast, Kazakhstan has significant reserves of oil, gas and coal; Uzbekistan has substantial gas reserves as well as some oil and coal and Turkmenistan also has substantial gas reserves together with some oil. 2. During the Soviet Union era these resources were managed on a regional basis. The hydropower resources in the Kyrgyz Republic and Tajikistan were operated primarily as an irrigation system with power generation being secondary. Energy systems were then designed to take account of the location of various energy sources. The result was a system in which energy was exchanged regionally among the various republics. Following the break-up of the Soviet Union, however, the scope of regional exchanges, which were turned into trade in energy, has declined as the individual republics have focused on achieving a greater level of energy self sufficiency. 3. The fossil fuel rich countries, especially Kazakhstan, have been able to leverage their energy resources into a significant volume of energy exports, accessing markets outside Central Asia. In contrast, the Kyrgyz Republic and Tajikistan face energy shortages in the winter and attempts to secure major export markets for their summer hydropower surpluses have not succeeded. The political changes in Afghanistan and sustained economic growth in other neighboring countries such as China, Iran, Pakistan and Russia, however, have raised expectations in the region that opportunities may materialize to export significant amounts of hydropower outside the region. Such an expectation has further raised hopes that support can be obtained for investment in major new generation facilities. 4. The Central Asian republics have asked the World Bank to help identify the potential for electricity exports outside the region and also the impediments that need to be addressed to realize such potential. However, these countries also need to assess how best to meet their own future requirements for electricity. This study, therefore, addresses (i) options for meeting future electricity demand within the region; (ii) the potential scope and location of export markets outside the region and (iii) the prospects for accessing these markets.

1 Kazakhstan, the Kyrgyz Republic, Tajikistan, Turkmenistan and Uzbekistan.

iii

Key Conclusions 5. The key conclusions of the study may briefly be summarized as follows: Meeting Regional Demand

i. Annual domestic demand in the Central Asian Republics can be met until about 2020 through the implementation of loss reduction measures, the rehabilitation of existing generation capacity and regional trade at the margin.

ii. Seasonal supply shortages in the winter will persist. While the most cost effective option

to meet this shortfall will be to trade at the margin, some new generation will be needed to meet winter demand requirements.

iii. The most attractive new generation options to meet the winter demand requirements are

the Talimardjan Thermal Power I Project in Uzbekistan that is largely complete, and the Bishkek II Thermal Power Project in the Kyrgyz Republic, which is partially constructed. The Bishkek II Thermal Power project represents a more cost effective and quicker option to meet the Kyrgyz Republic’s future requirements than the Kambarata hydropower projects in the Kyrgyz Republic. These two thermal power plant projects, however, are both dependent upon the availability of gas in Uzbekistan.

iv. In addition, some upgrading of the transmission facilities will be required to facilitate

intra-regional trade, including the construction of the North South Line in Kazakhstan, and the reduction of transmission bottlenecks in the southern part of the Central Asian grid.

v. Increased intra-regional trade will provide significant benefits. In order to take full

advantage of this, appropriate agreements are required among the countries in the region. In all likelihood these will have to be negotiated on a bi-lateral basis, in which case efforts should be made to ensure that the agreements among the various parties are based on consistent principles. A consistent approach to electricity trade by the various countries would facilitate the development of intra-regional trade. Once agreements are in place they will then have to be carefully managed to ensure the benefits from intra-regional trade are optimized.

Export Markets Outside the Region

i. Afghanistan, Pakistan, Iran, China and Russia are all potential markets for electricity produced in Central Asia. Pakistan and Iran have the added attraction of experiencing their peak demand in the summer when the largest potential electricity surpluses exist in Central Asia.

ii. Access to these markets will particularly benefit the Kyrgyz Republic and Tajikistan

since they are the countries with the potential to export significant quantities of

iv

electricity. Uzbekistan (and to some extent Kazakhstan), have the potential to export thermal power in the winter and also benefit in their role as prospective transit countries and as potential power traders2.

iii. Accessing these markets, however, will face a number of constraints. Afghanistan has

potential demand but is constrained in its ability to pay for imports. Access to the Pakistan market would involve transit and the associated construction of transmission facilities through Afghanistan. The demand growth in China is centered on the population centers of the East Coast, a considerable distance from Central Asia. Access to the Russian market will require access to the North-South transmission line across Kazakhstan that is under construction and would likely be dependent on RAO UES’ interest and willingness to purchase supplies. Supplies to Iran from the Kyrgyz Republic and/or Tajikistan will likely have to compete with supplies from Turkmenistan and will have to transit Afghanistan or Turkmenistan as well as, potentially, Uzbekistan. Moreover, access to export markets would, in many instances, require agreement on power transit among the Central Asian countries themselves.

Potential Access to the Export Markets

i. Major new generation projects in Central Asia will likely only be feasible if there is assured access to export markets outside the region.

ii. Electricity from Central Asia has the potential to compete in cost terms with marginal

generation costs in each of the targeted markets outside the region. The cost advantage, however, is not overwhelming and, in several cases, may not be sufficient to overcome security of supply concerns.

iii. The development of export markets for electricity from Central Asia will be very much

demand driven. Initially such trade will be limited to seasonally based activity. The more extensive level of trade that would justify the construction of major facilities focused on the export markets will be predicated on the alleviation of supply security concerns on the part of the importing countries, the existence of transmission infrastructure to access the markets and a politically stable environment.

iv. Perceptions of risk among potential investors and importers vary. Western investors

currently view the new generation projects as high risk ventures. RAO UES of Russia, on the other hand believes that it can mitigate many of the risks and has expressed particular interest in some of the proposed hydropower projects. RAO UES represents the best opportunity for at least one of the proposed hydropower projects to be implemented in the medium term.

2 The power trader role could, for example, take the form of importing hydropower and exporting thermal power taking advantage of relative logistics and relative peaking times.

v

Summary Conclusions

i. Extensive investment in new capacity, for example the proposed Rogun and Talimardjan II projects, will be predicated on the ability to access markets beyond the immediate region and will, therefore, likely be a longer term proposition. A possible scenario for development of Central Asia’s electricity generation and trading activity is shown schematically in Figure ES 1 below. This contemplates the phased introduction of measures to make capacity available beginning with the introduction of loss reduction programs to be followed by construction of new capacity needed to meet winter demand within the region (Talimardjan and Bishkek II) and the completion of the transmission link to Russia through Kazakhstan. These activities should be completed in a medium term time frame (up to 10 years). These phases have a relatively high probability of going ahead.

ii. The outlook for implementation of new projects focused on the export markets that could

occur in a subsequent phase is too uncertain at this time to justify the commitment of significant resources to the large generation projects3. Instead efforts should be focused on (a) developing intra-regional trade; and (b) promoting the introduction of a business climate that will support future investments in generation.

INTERIMCG MEETING

CopenhagenApril 29, 2002

Central Asian RepublicsPower Development and Trade Strategy

Loss Reduction &Rehab. Programs

Transmission Links:North-South Project

Power Trading Capacity: Sangtuda

Le v

el o

f Ris

k

Low

High

Time Frame

Near-Term1- 5 yrs

Medium -Term3 - 10 yrs

Long -Term8 - 15 yrs

Domestic & RegionalCapacity Balance:

Bishkek II & Talimardjan I

Export MarketNegotiation

South TransmissionLinks Development

Export Capacity PPP:Rogun & Talimardjan II

Russia

Afghanistan

Pakistan

IranChina?

Figure ES 1: Central Asia Republics Power Development and Trade Strategy

3 The one possible exception to this is Russian involvement in Sangtuda I hydropower project in Tajikistan.

vi

Meeting Regional Demand 6. Table ES1 summarizes the base case4 gross electricity demand projections for Kazakhstan, the Kyrgyz Republic, Tajikistan and Uzbekistan through 2025.

Table ES 1: Gross Electricity Demand Projections

Country Forecast Demand (GWh) 2003 2010 2015 2020 2025 Kazakhstan 58,944 72,056 84,034 98,367 115,146 The Kyrgyz Republic 12,145 9,222 10,033 11,296 12,719 Tajikistan 16,348 11,267 12,410 13,972 15,731 Uzbekistan 48,691 46,597 51,255 56,589 62,479 All four countries 136,128 139,142 157,731 180,225 206,075

Source: World Bank analysis 7. The projections show that demand will grow during the 2005-2010 timeframe only in Kazakhstan where economic growth is likely to be high, and needed electricity pricing adjustments are minimal. In contrast, demand is projected to decline in the 2005 to 2010 timeframe in the other three countries, a reflection of lower GDP growth forecasts, the impact on demand of substantial increases in real effective tariffs and, in Uzbekistan, the effect of the gasification program of the past few years. 8. Demand growth can be met through a combination of loss reduction measures, rehabilitation of existing generation facilities and the addition of new capacity from projects that have already been identified. Table ES2 summarizes the potential supply increases from these sources.

Table ES 2: Projected Electricity Supply Increments (TWh)

Available Supply 2003* 138.7 Loss Reduction 14.4 Rehabilitation of Existing Facilities 26.9 New Facilities 49.3

Potential Supply Level in 2025 229.3

*Based on 5-year average hydro generation Source: World Bank analysis

9. Table ES2 indicates that regional demand can be covered until about 2020 without the addition of new generating capacity. Investments would be needed in transmission and distribution facilities in the Kyrgyz Republic and in Tajikistan to reduce technical losses. Investments in Kazakhstan and in Uzbekistan can be justified for generation rehabilitation and to reduce technical losses in transmission and distribution. These investments to upgrade existing facilities generally offer the most cost effective increments of electricity supply in the various

4 The report considered alternative demand projections and these are addressed in the main body of the text. The selected base case projection is shown in the Executive Summary. The main conclusions of the report, however, will not be significantly affected by the different demand scenarios. What will change is the timing of the requirement for the various increments of new generation capacity, not the overall thrust of the conclusions.

vii

countries. However, seasonal shortages during the winter will remain an issue, while a significant level of net exports would require the addition of new capacity. 10. The region, and more specifically the Kyrgyz Republic and Tajikistan, have several options for dealing with the winter shortages:

i. The Kyrgyz Republic, and, to some extent Tajikistan can potentially operate their hydropower facilities in a power generation mode to increase the availability of electricity in the winter. Such operation, however, carries the risk of downstream flooding during the winter and shortfalls in the availability of water for irrigation in the summer. The 1998 Framework Agreement deals with the issue of the water/energy nexus and sets out terms for operating the hydropower facilities in an irrigation mode (to the benefit of the downstream riparian countries) in exchange for the provision of energy in the winter by the downstream riparian countries. The agreement, however, is not optimal. Even if the agreement were optimized, the region overall would still face a potential shortage in the winter.

ii. The Kyrgyz Republic and Tajikistan both have the potential to generate surplus power in

the summer. Iran experiences peak power demand in the summer and may have some surplus generating capacity in the winter, creating the potential to enter into seasonal trading arrangements. In order to enter into such arrangements, however, transit arrangements would have to be negotiated and such arrangements would involve transit of either Afghanistan or Turkmenistan and potentially Uzbekistan.

iii. The construction of some new capacity would also allow the region to meet its winter

shortfall. The two projects that would most logically be able to serve this function are the 800 MW Talimardjan Thermal Power Project I in Uzbekistan and the 400 MW Bishkek II Thermal Power Project in the Kyrgyz Republic. The 670 MW Sangtuda I hydropower project in Tajikistan also has the potential to contribute to meeting winter demand.

11. Enhanced intra-regional trade in electricity would also yield benefits:

i. It would allow individual countries to meet future demand at a lower cost than if they were to rely solely on their indigenous resources.

ii. The countries could optimize their cost of supply on a seasonal basis by taking advantage

of intra-regional trade opportunities. For example, Kazakhstan and Uzbekistan could both benefit from importing hydro electricity from existing hydropower stations in the summer rather than generate power in their own thermal power stations. This would have the benefits of providing electricity at a lower cost while saving fossil fuel resources and reducing emissions, thereby, creating the potential to benefit from carbon trading.

12. Enhanced intra-regional trade would, however, require some investment in transmission facilities such as the Kazakhstan North-South line (which would also support exports to Russia). This would also require the introduction of a number of institutional reforms including:

viii

i. Negotiation of updated agreements to govern electricity trading between countries. These are likely to be bi-lateral arrangements. However, if these arrangements are all based on a consistent set of principles, they will facilitate increased intra-regional trade. Among the items these agreements need to address are the legal and policy framework for third party access to transmission systems and transmission pricing arrangements.

ii. Introduction of a much greater level of transparency associated with the electricity sectors

in the various countries is an important pre-requisite to making informed decisions about electricity trading opportunities.

iii. Careful coordination between the management of electricity resources and the

management of water resources will be an important adjunct to effective intra-regional trade in electricity.

The CARs have decided to establish the Water Energy Consortium (WEC) under the Central Asian Cooperation Organization (CACO) umbrella to provide the institutional framework and eventually the legal framework to address these issues. A key first step is that CACO members should reconcile the differing views each of them currently has on the role of WEC. Export Markets Outside the Region 13. Afghanistan, Pakistan, Iran, China and Russia are all potential markets for electricity produced in Central Asia. There are, however, certain constraints that will have to be overcome to access any of these markets. 14. Afghanistan currently experiences severe power shortages. It has a small supply base and it lacks resources to build new capacity. Imports represent a near term option to meet its demand requirements. However, its lack of resources also translates into difficulty in paying for electricity imports. Consequently, while some trading activity between Central Asia and Afghanistan can be expected, it is unlikely to represent a significant market outlet for Central Asian exports. 15. Pakistan is projected to face power supply shortages. Imports may well represent the least cost option to meet future demand. Of particular note is the fact that Pakistan experiences its peak demand in the summer when Central Asia has substantial surplus generating capacity. However, in order to access the Pakistan market a 500 kV transmission line will have to be constructed. Pakistan has expressed considerable interest in securing access to electricity supplies from Central Asia and this may ultimately help mobilize the funding needed to construct the transmission line across Afghanistan, but construction of such a line is a key hurdle that will have to be overcome. 16. Iran experiences supply shortages during the summer. It purchases some electricity from Turkmenistan but could also have an interest in supplies from other Central Asian countries. In order to access the Iranian market, however, such supplies will have to transit either Afghanistan or Turkmenistan and Uzbekistan.

ix

17. China is experiencing a severe power shortage currently and Central Asian electricity has the potential to be an inexpensive import option to meet demand in the Urumqui area of the Xingjian province. The major growth in demand, however, will be in the population centers on the east coast of China where transmission distances for supplies from Central Asia become an issue. 18. Russia has an interest in balancing its system at the border with Central Asia (i.e. the border with Kazakhstan). It also views Central Asia as a potential source of inexpensive electricity supply that could support its ambitions to expand electricity exports to Europe. A 500 kV north-south transmission line is under construction in Kazakhstan. In addition to facilitating intra-regional trade this line could be used to transmit electricity from the Kyrgyz Republic, Tajikistan and Kazakhstan to Russia. RAO UES of Russia has expressed particular interest in securing access to electricity supplies in the future from Central Asia and has made specific commitments to Tajikistan concerning the Sangtuda I hydropower project. Potential Access to These Markets 19. A number of new generation projects have been identified in Central Asia and developed to the point where they could be constructed. Indeed, several of these projects have been partially completed. For example: construction of hydropower projects at Kambarata in the Kyrgyz Republic and at Sangtuda I and Rogun in Tajikistan were under construction during the Soviet era. Following the break-up of the Soviet Union, however, construction on these projects ceased. 20. While projects such as the Talimardjan Thermal Power Project I in Uzbekistan and the Bishkek II Thermal Power project in the Kyrgyz Republic may be able to proceed on the basis of demand requirements within Central Asia, the economic viability of the majority of the identified projects is predicated on securing assured access for a substantial portion of their electricity production to markets outside the immediate Central Asia region. Accessing these markets is likely to be very much a demand driven process. 21. Table ES3 summarizes the economic and financial costs of the electricity generated from these projects5:

5 These calculations are made on a base case set of assumptions. Sensitivities are discussed in the main body of the report

x

Table ES 3: Supply Costs from Generation Options

No. Country Supply Option Capacity in MW

Economic cost/kWh in

Cents

Financial cost/kWh in

Cents Rank

1 Talimardjan Thermal Power Project I 800 1.68 1.75 1

2 Uzbekistan

Talimardjan Thermal Power Project II 2,400 2.76 2.92 5

3 Bishkek II Thermal Power Project 400 2.55 2.67 4

4 Kambarata Hydropower Project I 1,900 7.17 8.54 9

5

The Kyrgyz Republic

Kambarata Hydropower Project II 360 3.72 3.95 7

6 Sangtuda I Hydropower Project 670 1.97 2.44 2

7 Rogun Hydropower Project Phase I 1,200 2.46 2.91 3

8

Tajikistan

Rogun Hydropower Project Phases I and II 3,600 2.83 3.24 6

9 Kazakhstan New Ekibastuz Thermal Power Project 1,000 4.54 5.05 8

Source: World Bank analysis 22. All of these projects except Kambarata I and the new Ekibastuz project are partially constructed – Talimardjan is the furthest along and Kambarata II the least progressed. These projects have the advantage that only incremental costs needed to effect completion must be recovered and there are no liabilities associated with the projects. 23. After the addition of transmission costs, most of these projects would be competitive in the identified export markets. The clear exception is Kambarata I. A comparison of marginal costs of generation and projected import costs (based on the financial costs of the projects and transmission lines) in the various markets is shown in Table ES4.

Table ES 4: Marginal Costs of Generation in Target Markets versus Import Costs

(cents/kWh)

Target Market Marginal

Generation Cost in Target Market

Supply Options Transmission Cost

Total Landed Cost of Imports

Afghanistan 3.7 Sangtuda I, Rogun I, Talimardjan I and II 0.51 2.26 – 3.43 Iran 3.6 Sangtuda I, Rogun I, Talimardjan I and II 0.54 2.29 – 3.46

Pakistan 5.6 Sangtuda I, Rogun, Talimardjan I and II, Kambarata II 0.51 2.26 – 3.75

China 3.6 Sangtuda I, Talimardjan I 0.72 2.47 – 3.16 Russia 3.0 Sangtuda I, Talimardjan I 0.55 2.30 – 2.99

Source: World Bank analysis 24. While Central Asian supplies should be cost competitive in these markets, the cost advantage is not overwhelming. Electricity trade is more politically sensitive than general trade since electricity supply is often viewed as a national security issue. Also, trade of significant amounts of electricity requires long-term commitments and a clear perception, in the importing countries, that the supplier can be relied upon to fulfill its commitments. The level of trade that will justify the construction of major facilities to service the export markets and the associated commitment of capital will be predicated on the alleviation of supply security concerns on the part of the importing countries and an associated perception that the political climate and the business environment in the exporting countries are stable.

xi

25. It appears likely, therefore, that trade with the markets outside the immediate Central Asia region will initially be limited to seasonally based activity at the margin. However, as trade in electricity establishes a positive track record, the potential for expanded activity will increase. Consequently, the Central Asian suppliers of electricity should approach the issue of expanded export activities with the recognition that a significant expansion in export levels will take some time to develop, and they should, therefore, focus on the objective of building towards this longer term goal in a phased fashion.

1

CHAPTER I: INTRODUCTION 1.01 The Central Asian Republics (CARs) consisting of Kazakhstan, the Kyrgyz Republic, Tajikistan, Turkmenistan and Uzbekistan are endowed with significant energy resources. However, as Table 1.1 indicates there is considerable disparity in the specific endowments. While Kazakhstan, Uzbekistan and Turkmenistan enjoy world class endowments of fossil fuel resources, the Kyrgyz Republic and Tajikistan enjoy very limited access to these resources but do have significant endowments of water resources.

Table 1. 1: Primary Energy Resources in Central Asia Fossil Fuel Reserves Unit Kazakhstan Kyrgyz

Republic Tajikistan Turkmenistan Uzbekistan Total

Crude Oil MTOE 1,100 5.5 1.7 75 82 1,264.20 Natural Gas MTOE 1,500 5 5 2,252 1,476 5,238 Coal MTOE 24,300 580 500 Insignificant 2,851 28,231 Total MTOE 26,900 591 507 2,327 4,409 34,734 % of Total 77.4 1.7 1.5 6.7 12.7 100

GWh/year 27,000 163,000 317,000 2,000 15,000 524,000 Hydro Potential

MTOE/year 2.3 14 27.3 0.2 1.3 45.1 % of Total 5.2 31.1 60.5 0.4 2.9 100

1.02 The energy and water infrastructure assets that these countries inherited reflect the regional approach employed by the central planners of the Soviet Union. This infrastructure implicitly contemplated energy and water transfers across administrative boundaries that have since become national borders and the design reflected perceived needs within the region. 1.03 The water management system was designed primarily as an irrigation system, with power generation being incorporated as a by-product. Energy systems were then designed to take account of the location of various energy sources and resulted in the following key elements:

• The Central Asia Transmission System was designed as a regional power grid, utilizing hydropower exports from the Kyrgyz Republic and Tajikistan as well as allowing interchange of power among all the countries. The dispatch center for this system was and is located in Uzbekistan.

• The gas pipeline network was designed to allow delivery of gas to the southern portion of Kazakhstan, to the Kyrgyz Republic and to Tajikistan from Turkmenistan and Uzbekistan.

• Oil refineries were located in the more significant oil producers – Kazakhstan, Uzbekistan and Turkmenistan with refined products being transported into the Kyrgyz Republic and Tajikistan.

• Coal consumption was largely tied to the local availability of coal and to the ability to use the rail network for coal transportation.

1.04 At the time of the break-up of the Soviet Union a number of power generation projects were under construction in the Central Asian republics. These included large hydro-projects such as Rogun and Sangtuda I in Tajikistan and, to a lesser extent, Kambarata in the Kyrgyz

2

Republic. Investments had also been made in a number of large thermal power projects such as Talimardjan in Uzbekistan, Ekibastuz in Kazakhstan and a second combined heat and power (CHP) plant at Bishkek in the Kyrgyz Republic. 1.05 With the break-up of the Soviet Union, these countries inherited extensive energy networks that had been designed to function on a regional basis, but they also inherited a substantial amount of partially constructed infrastructure that had also been predicated on the continuation of a regional approach to managing energy and water issues. At that point, each of the countries was faced with the need to establish formal relations with the other countries in the region covering energy trade and water resource transfers. In addition, they had to take over responsibility for the operation and maintenance of the infrastructure facilities within their own countries and are faced with having to define the optimum means of financing and constructing the new infrastructure facilities that will be required to sustain the energy and water sectors in the region over the longer term (i.e. beyond 2020). 1.06 A key consequence of the new environment that emerged after the break up of the Soviet Union has been a move towards increasing energy self-sufficiency at the expense of regional synergies. 1.07 All the countries, with the possible exception Kazakhstan (which has been able to attract significant private sector participation in the sector), have been keen that the World Bank and other multilateral/bilateral financiers help them finance expansion of generation facilities, including some of the projects that had been under construction at the time of the break-up of the Soviet Union. However, these requests have made within the context of the policies of national self-sufficiency being pursued by the CARs. The World Bank’s view is that all these large projects would be feasible only in the context of: (a) significantly enhanced electricity trade, both within the CARs and with external electricity markets; (b) a significantly increased level of regional cooperation among the riparian states relating to the rivers on which such projects would be located; (c) adoption of innovative measures to structure the entities to construct, own and operate these assets; and (d) serious efforts to attract foreign private investments, especially in the context of most of these countries being already highly indebted. 1.08 Of late, there has been an increasing recognition of the need for regional cooperation among the countries in various sectors such as energy, water, transport and food security. The formation of the Central Asian Cooperation Organization (CACO) in 2002, overseen by a Council of the Heads of States of four of these countries6, for this purpose is a clear indication of the importance they attach to the promotion of such cooperation. In his letter dated September 8, 2003, the President of Kazakhstan, writing on behalf of all four Heads of State, confirmed their intention to enhance regional cooperation in the above areas and invited the World Bank to take the lead in assisting to set up the Water and Energy Consortium, the twin objectives of which are enabling cooperative water usage and enhancement of internal trade and export of electricity.

6 Turkmenistan is not a member of CACO. Since May 2003, it is not a part of the Central Asian Power System and operates in an island mode. This Study therefore does not cover Turkmenistan and deals largely only with the remaining four countries.

3

1.09 The World Bank, working closely with other multilateral and bilateral financiers (a.k.a. Development Partners) has followed a two-track approach. The first track had been directed at the near term objective of solving the problems caused by the water-energy nexus, by securing multi-lateral agreement to a series of measures to improve the 1998 Framework Agreement. Key recommendations were contained in the World Bank’s report on the Water and Energy Nexus in Central Asia that was distributed to governments of the four countries prior to the consultations that took place earlier this year. Details of the findings arising from this work are presented in Chapter III. 1.10 The second track addressed longer term measures including preparation of this Regional Electricity Export Potential Study, continuation of efforts, in coordination with Development Partners, to promote energy and water sector reforms, estimation of investment requirements for major projects, and exploration of ways to include Russia in the regional cooperation process. 1.11 The CARs have asked the World Bank to help identify the potential for electricity exports outside the region and also the impediments that need to be addressed to realize such potential. However, these countries also need to assess how best to meet their own future requirements for electricity. This study, therefore, addresses (a) options for meeting future electricity demand within the region; (b) the potential scope and location of export markets outside the region and (c) the prospects for accessing these markets. 1.12 The remainder of this Study: reviews the current state of the electricity systems in each of the CARs (Chapter III); assesses the long-term (20-year) domestic demand for electricity and available supply options within each republic and therefore of the region (Chapter IV); undertakes an in depth assessment of the large projects that form a significant part of supply options and identifies broadly the costs of transmission required to reach the target markets (Chapter V); reviews the possible export markets for Central Asian electricity (Chapter VI); identifies an institutional framework for the countries to have a more coordinated and integrated development of their energy resources and water use (Chapter VII); and clarifies the benefits and more importantly the risks, that the countries need to overcome, as well as the way forward to realize the potential (Chapter VIII).

4

CHAPTER II: THE WATER ENERGY NEXUS IN THE SYR DARYA BASIN

2.01 The Bank’s report, Water Energy Nexus in Central Asia, focusing on the Syr Darya Basin, complements the significant amount of work done earlier on water resources earlier under the Aral Sea – Water and Environmental Management Project. Its key findings and recommendations are summarized in Box 2.1.

Box 2. 1: A Brief Summary of the Findings of the CAWENS Report

Toktogul reservoir in the Kyrgyz Republic was designed during the Soviet rule as a multi-year storage facility to enable the storage of water inflows in wet years, for irrigation use in downstream countries during the normal and dry years. The irrigation oriented operating regime called for the release of 75% of the annual releases of water from the reservoir in summer months and for restricting the releases during the winter season to 25% of the annual release. Power generation followed the irrigation regime and the excess power produced in summer was fed into the Central Asian Power System for use by Kazakhstan and Uzbekistan and winter deficits in energy in the Kyrgyz Republic was met by allocation of fossil fuels needed for heat and electricity from Uzbekistan and Kazakhstan. Once the Soviet Union was dissolved and these countries became independent, these arrangements came under great strain. Toktogul reservoir came to be increasingly used to meet the power needs of the Kyrgyz Republic, reducing summer releases and increasing winter releases of water causing irrigation problems in summer and flooding problems in winter in the downstream countries. To mitigate this problem, a 1998 Framework Agreement among the upstream and downstream riparian countries sought to compensate the former by the latter for the annual and multi-year water storage services through the purchase of surplus summer electricity from the Kyrgyz Republic and supply of fossil fuels needed for Kyrgyz winter needs. In actual practice the annual agreements concluded under this arrangement proved unsatisfactory and difficult to enforce. The Bank’s CAWENS report carried out an economic analysis which demonstrated that net Syr Darya basin benefits are substantially higher under the irrigation regime of reservoir operation (i.e., a minimum of 6 BCM of water releases in summer and a maximum of 3 BCM of water releases in winter) than under the power regime (i.e., reduced summer releases and increased winter releases). While it duly recognized the major contribution made by the Framework Agreement in an attempt to restore the sensible reservoir operating regime, it pointed out the key areas in which the Framework Agreement should be improved to ensure better implementation. These relate to: (a) the need to pay explicitly for the water storage services in cash; (b) the need to use a multi-year rather than annual perspective to take into account unusually wet and dry years as well as normal years; (c) the need to divide the compensation package for water storage services into a fixed and a variable component; (d) the need to link the fixed portion of the compensation to the value of the Kyrgyz fossil fuel needs for the winter months; and (e) the need to have a monitoring and guarantee mechanism to ensure compliance with agreed obligations. Further, the Study highlighted the areas for institutional improvement to ensure more effective water and energy coordination, regulation, monitoring and enforcement. 2.02 This report was discussed in a conference of Development Partners held in February 2004. Following this conference, the Bank carried out consultations with the CARs in March 2004 to identify key areas where additional work is needed to build consensus among the parties involved. 2.03 The country consultations revealed that each riparian country has a somewhat differing position regarding operation of the Naryn Cascade and Syr Darya:

• The Kyrgyz Republic is of the view that water should be sold to the downstream countries and has adopted national legislation for the sale of water to other countries.

5

• Tajikistan, while acknowledging that its role is small, views its role as crucial nevertheless, for a balanced operation of the entire basin facilities.

• Uzbekistan believes that solutions should be based on an “international legal framework of trans-boundary waters” such as the Helsinki Agreement, essentially implying that monetizing the compensation mechanisms in the 1998 Framework Agreement, them are not acceptable.

• Uzbekistan also favors the construction of re-regulating structures downstream on its own territories to ensure irrigation supplies, to lessen the dependence on other countries, especially the Kyrgyz Republic with respect to Toktogul operations.

• While Kazakhstan does not currently have any firm plans to build re-regulating structures on its territory, it has not ruled this option out.

• The downstream riparian states (Uzbekistan and Kazakhstan) highlighted the structural deficits in winter energy supply that would be likely to compel the Kyrgyz Republic to be non-compliant with the 1998 Agreement even if the downstream countries were fully compliant.

2.04 In addition, more recently, downstream countries have initiated the following efforts, which have changed the parameters for Toktogul reservoir operations:

• Kazakhstan has promoted works towards increasing the conveyance capacity of the Syr Darya River to pass flows to Northern Aral Sea in winter.

• Uzbekistan, meanwhile, has intensified efforts to increase its downstream water-regulating reservoir capacity in the Fergana valley.7 The completion of these reservoirs could provide additional storage of about 2.5 BCM downstream, which could absorb the equivalent additional discharge from Toktogul in winter and subsequently release the same quantity of water again in summer for downstream irrigation.

• Furthermore, the dam safety of Kairakum and Shardara dams is being enhanced allowing better re-regulation of water in these facilities, while current usage of available winter water downstream for leaching and growing winter wheat also helps absorb greater winter releases from upstream.

• Large reserves of underground water in Fergana valley also offer possibilities to increase irrigation supply in summer through groundwater development on a sustainable basis.

2.05 At the same time, the latest hydrologic analysis prepared by USAID suggests that the average annual inflows to the Toktogul reservoir are about 12 billion cubic meters (BCM). The implication of the efforts by the downstream countries is that, with the benefit of improved downstream storage and carrying capacity, Toktogul can be operated under a modified irrigation regime making higher releases during winter for energy generation for the Kyrgyz Republic, without endangering the irrigation water supplies during summer. Taking account of seasonal variation and optimum reservoir levels for power generation, winter releases of around 4.5 BCM are considered sustainable. 7 Uzbekistan is proceeding with the design of new water storage capacity {Karamansay reservoir of 0.690 billion cubic meters (BCM)}, and is also continuing the construction of Razaksay (0.650-0.750 BCM) and Kangkulsay (0.3 BCM) reservoirs in addition to the existing storage reservoir of 0.8 BCM in the Arnasai depression.

6

2.06 Meeting the Kyrgyz Republic’s energy deficits in the winter is a key to overcome the current problems induced by the water-energy nexus. The additional 1.5 BCM released would cover around half of the current energy deficit in the winter, while energy efficiency gains in transmission and distribution could feasibly absorb another 20% of the winter deficit. To meet the remaining winter energy shortage, one of the most economic and a relatively quick option would be to invest in an additional 400 MW of thermal generation capacity in Bishkek by finishing the partly constructed Bishkek II power plant (discussed in Chapters IV and V). This would enable the Kyrgyz power system to produce both summer and winter surplus by 2010; and, together with loss reduction efforts and modified irrigation operation of Toktogul, would be able to meet the Kyrgyz Republic’s electricity year round until 2020. 2.07 The revised cooperation basis on the Syr Darya basin does imply enhanced electricity trade in the short term. Electricity trade would occur on a commercial basis (i.e., not linked to water releases) and at prices determined by market principles. In addition to possibilities of intra-CAR trade, Russia has indeed become a serious importer of Central Asian electricity, especially the cheaper hydropower from the Kyrgyz Republic and Tajikistan (and it has been exchanging power with northern Kazakhstan for a few years now). To enable this trade with Russia in particular, there is a need to complete the North South transmission line in Kazakhstan, and equally important, access to transmission grids in Uzbekistan and Kazakhstan by the Kyrgyz Republic and Tajikistan are necessary.

A. Revised Approach by the Bank and its Development Partners 2.08 Considering the above changes and developments, the approach for the Bank and its Development Partners should remain the same in regard to the long-term track, i.e. mobilizing donor support and resources to help Central Asian countries develop their energy resources in a sustainable manner. However, the strategy with regard to the short-term track should change. Instead of the previously planned efforts to encourage multi-country consensus and contractual agreements in all areas, the focus should be on working to address the institutional, managerial and financial constraints related to power and water at the national level and promote intra-state cooperation on water sharing and energy exchange between the Syr Darya riparian states. Such an approach will have three components:

a) Work with individual countries on solving power and water management issues. This is already a component of the World Bank’s Country Assistance Strategies. The particular aspects related to energy-water cooperation are: (i) reduction of electricity losses in all four countries by reinforcement and rehabilitation of transmission and particularly distribution networks; and (ii) increasing ground water development in the Ferghana Valley in Uzbekistan and in Tajikistan, along with improving the safety of the Kairakum reservoir and improving its re-regulation capacity. Also, continued support in improving the conveyance capacity of the Syr Darya River, improvements to the Shardara dam, delta lakes, and Northern Aral Sea, and irrigation and drainage system improvements in each country will improve the water use efficiency.

7

b) Work with Kazakhstan, the Kyrgyz Republic and Tajikistan to improve the energy cooperation among the three countries. In addition to providing analytical support, financing options for eliminating the winter energy deficit in the Kyrgyz Republic and strengthening the electricity transmission network in Kazakhstan should be pursued. In particular, consideration should be given to: (i) the completion of the partly constructed Bishkek II power plant, which could potentially export surplus electricity to Russia during Kyrgyz off-peak seasons; and (ii) the construction of the second phase of the 500 kV North-South transmission line in Kazakhstan that is necessary from the point of view of load flow, system stability and ease of transmission for electricity exports to Russia.

c) Work with all countries to analyze the long-term energy potentials, provide

international experience in water-energy cooperation, and to improve the operational plans at the Toktogul reservoir. The World Bank has already proposed an institutional set up for the Water-Energy Consortium (WEC) to the working group dealing with this matter within the Central Asia Cooperation Organization (CACO). Once approved by the CACO Heads of Sate, further support should be mobilized in setting up the WEC, including technical assistance and funding for consensus building. The technical assistance could include provision of further advice on the institutional and legal framework of the Consortium, training and provision of venues for continuing the Consortium dialogue, redesign of the operating rules of the Toktogul reservoir as well as further extension of the analysis of regional power demand, options for expanding the regional power grid, and consequently enhancing the regional exports potential through specific investment projects.

2.09 The Bank and the development partners should give full consideration to the views of all the riparian states and should also incorporate Russia in the dialogue to ensure synergy between the above activity and the ongoing relevant initiatives supported by Russia.

B. The Regional Electricity Export Potential Study 2.10 This Regional Electricity Export Potential Study (REEPS) is a part of the Bank’s short- and long-term assistance approaches discussed above. As such, this study is a second (after the Water Energy Nexus Study) in a series of Regional Economic and Sector Work (RESW) initiatives being undertaken by the Bank to assist the CARs in developing a regional approach to meeting their development objectives.

8

CHAPTER III: CURRENT STATUS OF THE POWER SECTOR IN THE CENTRAL ASIAN REPUBLICS

A. Power System Characteristics

3.01 The power systems in the Kyrgyz Republic, Tajikistan, Turkmenistan, Uzbekistan and south Kazakhstan were developed and optimized as an integrated grid during the Soviet era as the Central Asian Power System (CAPS) which even now operates as a synchronized grid.8 Details of the power sector in each of the four countries9 in CAPS are provided in Appendix 3.1.

3.02 Capacities and Output. The capacities and output of the electricity sectors of the Central Asian Republics are summarized in Table 3.1. Two issues merit specific comment. First, the region was a net exporter of about 150 GWh. Second, while gross supply to the domestic market totaled 134,445 GWh, total sales in CAPS to domestic consumers only amounted to 97,984 GWh implying an overall average total system loss level of 27%.

Table 3. 2: Installed Capacities and Supply/Demand Balances of CARs in 2002 Item Kyrgyz Rep. Tajikistan Uzbekistan Kazakhstan Total

Installed Capacity Hydro (MW) 2,950 4,059 1,710 2,000 10,719

Installed Capacity Thermal (MW) 763 346 9,870 16,240 27,219

Installed Capacity Total (MW) 3,713 4,405 11,580 18,240 37,938

Available Capacity (MW) About 3,100 3,428 7,800 13,840 25,068

Peak Demand (MW) 2,687 2,901 7,925 9,432

Generation Hydro (GWh) 10,778 15,086 7,278 8,861 42,003

Generation Thermal (GWh) 1,115 138 42,021 49,317 92,591

Generation Total (GWh) 11,893 15,224 49,299 58,178 134,594

Exports (GWh) 1,216 266 634 595 2,711

Imports (GWh) 430 1,058 609 464 2,561

Gross supply to domestic Market (GWh) 11,107 16,016 49,274 58,048 134,445

Domestic Billed Consumption Annual (GWh) 6,836 12,988 38,112 40,053 97,989

3.03 The arithmetical sum of their peak demand amounted to 22,945 MW in 2002. Even though the total installed capacity is 40% higher than the system peak, the supply in all countries and especially in the Kyrgyz Republic and Tajikistan remains unreliable on account of the low availability of thermal plants, seasonal variations in water flows in the rivers, restrictions on reservoir operations arising from irrigation demand as well as seasonal variations in electricity demand. Supply shortages are acute in winter (October to March) especially in Tajikistan. 3.04 Seasonality of the Electricity Demand. As shown in Table 3.2, CAPS as a whole is a winter peaking system, where 56% of the total consumption occurs in the winter. Kazakhstan

8Turkmenistan’s power system was also a part of CAPS from the days of the Soviet era. Since May 2003, however, Turkmenistan is operating in an island mode in relation to CAPS, and is operating in parallel with the Iranian power system and exports electricity to Iran. The reason for Turkmenistan’s action is not clear since export to Iran can take place even without such isolation from CAPS. 9 Hereafter, CARs and CAPS do not include Turkmenistan

9

and the Kyrgyz Republic have their annual peak in winter, which are substantially higher than their summer peaks. The electricity consumed in winter in the Kyrgyz Republic and Kazakhstan amounts to approximately 67% and 60% of their annual electricity consumption. In the Kyrgyz Republic this is caused by the high share of residential consumers in total electricity consumption and the use of electricity for space heating by households, most of which do not have access to any gas network or any reliable gas supply. South Kazakhstan’s winter shortages are caused by limitations of power flow from North Kazakhstan and non availability of export surplus from Tajikistan and the Kyrgyz Republic in winter.

Table 3. 3: Seasonality of the Electricity Consumption of the CARs in 2002 Item The Kyrgyz

Republic Tajikistan Uzbekistan Kazakhstan Total

Share of Consumption in Summer (%) 33 57 47 40 44

Share of Consumption in Winter (%) 67 43 53 60 56

3.05 The annual load curves of Uzbekistan and Tajikistan are relatively flat, since irrigation pumping loads of summer in these two countries balance the heat loads of winter. In Uzbekistan, availability of gas supply to most areas ensures that winter demand for electricity does not rise unduly. Additionally, in Tajikistan, the aluminum production accounts for the summer consumption being larger than winter consumption. 3.06 Power Market Trends and Structure of Demand. Due to the collapse of the Soviet Union and the resulting economic turmoil, electricity demand and generation in the CAPS fell dramatically during 1990-1998 and has still not been able to climb back to the level prevailing in 1990. Even more importantly, industrial demand dropped and the share of the residential consumers in total consumption rose dramatically, especially in Tajikistan and the Kyrgyz Republic. This resulted in inadequate loading of some High Voltage (HV) lines and overloading of the Low Voltage (LV) lines and the distribution system, contributing to high levels of technical losses and unreliability of supply. In the Kyrgyz Republic the residential consumption accounted for 58% of total in 2003. In Tajikistan, a state owned Aluminum smelter TADAZ consumes about a third of the total electricity and out of the remaining, nearly half goes to the residential consumers. The share of Tajikistan’s residential consumption in the total has risen from 8% in 1990 to 34% by 2001. 3.07 System Losses, Billing and Collection. These consist of technical losses (undelivered electricity) and commercial losses (delivered but unbilled consumption and uncollected bills). Technical losses have increased well beyond normative values, because of the changes in structure of demand, inadequate maintenance and lack of needed reinforcements of the transmission and distribution system. Unbilled losses arise from theft of electricity, defective metering, meter reading and billing and un-metered supplies billed on the basis of normative consumption. The separation of these components is difficult. It is broadly estimated that the technical loss level is about 18% in Kazakhstan and is 22 to 23% in the other three countries. The unbilled consumption is estimated to range from 5% to 18% in these countries. Nonpayment problem are pervasive and on average only about 70% to 85% of the bills are collected. However, these collection figures include payment through non-cash mechanisms such as barter and offsets, which are still widely prevalent, and cash collection is generally believed to be in the

10

range of 40% to 55% of the billings. Thus, out of the total electricity available, only about 50% is converted into revenues and only about 35% to 40% is converted into cash revenues . Within this overall framework, operational inefficiency varies a great deal among the countries and even among the many distribution companies in Kazakhstan. Data on System Losses, Billing and Collections are summarized in Table 3.3.

Table 3. 4: Losses, Billing and Collections in the CARs in 2002 Item The Kyrgyz Republic Tajikistan Uzbekistan Kazakhstan

System Losses (GWh) 4,271 3,028 11,162 17,995

System Losses (as a % of net supply) 38 19* 23 31

Total number of consumers (million) 1.1 About 1.0 4.1 About 4.3

Billing (as a % of sales) 80 70 85 N/A

Collection (as a % of billings) 80 70 75 85

Non Cash payment 55% 60% 60% 45%

* Including TADAZ 3.08 Regional System Operation. The backbone of the CAPS is the 500kV grid which totals 1400 kilometers in length, and almost all major power stations in the CARs are connected to the grid at this voltage. The grid includes a closed central loop connecting the major facilities, with nodal substations located in eastern Uzbekistan, Kazakhstan and the Kyrgyz Republic. Turkmenistan is connected to the CAPS by a 500 kV tie-line (Mari TPP-Karakul), as is southern Tajikistan (Regar-Guzar). In addition, all power systems are interconnected to various degrees through a 220 kV network. Tajikistan could supply electricity to its northern part from the southern part only through power exchanges with Uzbekistan on account of the highly inter twined geographic location of Tajikistan and Uzbekistan and on account of a lack of a north-south transmission link within Tajikistan. Similarly inadequate transmission capacity and stability problems in the North-South 500 kV transmission line restrict the flow of power from the north Kazakhstan grid to the South Kazakhstan grid, which is a part of CAPS. 3.09 The Unified Dispatch Center, Energia, in Tashkent is responsible for maintaining the balanced and synchronized operation of the power transmission and distribution system. Energia also takes into account the irrigation and hydro power related obligations of the member countries (incorporated in the annual Inter-Governmental Irrigation Agreements or IGIAs), balances the real time demand and supply of the integrated grid and ensures system security by arranging for ancillary services such as system reserves, frequency and voltage regulation and reactive power compensation. Energia’s Dispatch Service performs the task of translating the quarterly power exchange plans prepared by Central Asian Power Council (CAPC) into daily schedules for generation unit commitment. Energia’s Energy Regime Service attempts to balance irrigation and hydropower requirements, which is a controversial issue in the region. Another of Energia’s core functions is ensuring overall system security.

B. Policy Reforms in the Power Sectors of CARs

3.10 The CARs have in general adopted policy reforms that are moving the electricity sectors towards a market economy. However, the progress has been uneven among the countries. The

11

current status of policy reforms in each of the CARs is discussed below. Further details of the status of the reform effort in the four countries along with charts of the sector structure are provided in Appendix 3.1.

3.11 Legal/Regulatory Framework and Industry Structure. In all countries a new set of Energy Laws (actually a set of Presidential Decrees in Uzbekistan) have been enacted enabling sector restructuring, corporatization, separate regulation, competitive trading and private sector participation. The policy function has been assigned to the Government Ministries and electricity entities have been corporatized. However, progress beyond legislation and corporatization is very uneven among the four countries:

• Kazakhstan is the most advanced in this regard. More than 85% of the large generation assets (called national level generation) have been separated as independent power producers. The independent transmission company KEGOC is state owned and provides regulated third party access on the basis of regulated transmission tariffs. Distribution is handled by 21 Regional Electricity Companies (RECs), which have smaller embedded generation assets (called regional level generation), transmission at or below 110kV and distribution networks. These RECs are also being unbundled as appropriate and thus nine of the distribution networks have been separated. Price regulation is done by the Anti-Monopoly State Committee. Trading and dispatch is on the basis of bilateral contracts. RECs, distribution companies and large industrial consumers can enter into contracts with generators. Recent innovations include adoption of a Grid Code and introduction of a day-ahead market and spot market.

• There has been progress in the Kyrgyz Republic but less than in Kazakhstan. The sector has been unbundled into one generation company, one transmission company and four distribution companies. There is an independent regulator. The transmission company acts as a common carrier with third party access based on regulated transmission tariffs. Distribution companies directly contract with the generation company. The latter handles exports.

• Progress in Uzbekistan is limited. The state owned joint stock company Uzbek Energo has fully owned subsidiaries for generation units, transmission and 15 distribution areas. The transmission subsidiary acts as a single buyer. Large consumers at 110 kV and above can buy directly from the generators on the basis of regulated tariffs. There is a regulatory body, the independence of which is quite limited.

• The progress is least in Tajikistan where only the modest power sector assets in the Gorno Badakshan region have been given on a 25 year concession to the privately owned Pamir Power Company, which will function as a vertically integrated utility. The power sector assets in the rest of the country remain with Barki Tajik, a state owned joint stock company functioning as a vertically integrated utility, with wholly owned subsidiaries for generation units, transmission and distribution, which for all practical purposes function as divisions of Barki Tajik. There is no independent regulation. The distinction between the government and Barki Tajik is somewhat fragile. A separate Joint stock company has been formed for the construction of the Sangtuda I Hydropower project with the objective of attracting equity from outside the government.

3.12 Electricity Tariffs. Posted electricity tariffs range from a low of 0.5 cents/kWh in Tajikistan to a high of 2.64 cents/kWh in Kazakhstan, but are below the cost recovery level in all

12

countries, as shown in Table 3.4. There are considerable subsidies in favor of residential consumption in all countries, especially in the Kyrgyz Republic and Tajikistan. Uzbekistan is the most serious in terms of pricing reforms, as it adopted a multi-year tariff adjustment policy that has been in effect since August 2001 (prices are increased by roughly 10% once every 2 months) and aims to reach full cost recovery levels by end 2005. Kazakh tariffs vary widely among the distribution companies and may have reached cost recovery levels in the case of a number of distribution companies.

Table 3. 5: Electricity Tariffs in the CARs in 2003 Item The Kyrgyz Republic Tajikistan Uzbekistan Kazakhstan

Average tariff (Cents/kWh) 1.40 0.50 2.15* 2.64

Cost recovery level of Tariff (Cents/kWh)** 2.30 2.10 3.50 2.80

Current Tariff as % of Cost Recovery Tariff 61% 24% 61% 94%

*Aug. 2004; ** See Chapter IV and Appendix 5.1 for details 3.13 Private Sector Participation. Kazakhstan has the most private sector participation. 85% of large generation plants (called national generators) are in private hands, as well as 9 distribution networks are privately operated. The policy objective is to privatize all distribution operations. Tajikistan has given out the investment, operations and management responsibility for the electricity operations in Gorno Badakshan Autonomous Oblast to a private operator under a 25-year concession. In the Kyrgyz Republic, all electricity distribution companies are to be privatized and one of the four distribution companies is planned to be awarded under a concession arrangement in the near future. Uzbekistan has put up four power plants (50% of installed capacity) and 4 distribution companies (30% of consumers) for privatization, and plans to offer 49% of the equity to private investors in generation and distribution companies 3.14 Electricity Trade. There has been a considerable reduction in the amount of electricity exchanged between the CARs since 1990, as shown in Table 3.5. The total export/import flow in 2000 was only 30% of the 1990 level, even though the consumption levels in each country has recovered to about 80% of the 1990 level. Until 1992 the electricity flows followed Soviet era commodity exchanges based on planned allocation of electricity, irrigation water, and fossil fuels to the regions, but from 1993 onwards the newly independent countries introduced a system of barter payments for the exchange of fossil fuels and electricity based on cash prices. As traded fossil fuel prices went up sharply and electricity prices remained low, the exchange became difficult and electricity trade suffered large declines. Pursuit of national energy self-sufficiency policies by the CARs is also a key reason for the decline in trade. Significant trade of electricity occurs only in the Syr Darya basin, with the Kyrgyz Republic being a net exporter to Uzbekistan and to southern Kazakhstan10. The Kyrgyz Republic and Tajikistan, due to their large hydro systems, provide frequency regulation to the wholes CAPS, and they earn fees for providing such services. In 2000, the total frequency regulation services amounted to about 5,000 MW over the 12 months period, which earned them about US$7 million. 10 However, given that there are many links at the medium and low voltage levels (at 35kV especially) across borders, there are transfers of energy between some countries (e.g., the Kyrgyz Republic and Almaty area) that are unrecorded.

13

Table 3. 6: Shifts in Electricity Trade in Central Asian Power System 1990-2000 Electricity Trade in 1990 (GWh)

Imports

Exports Kazakhstan The Kyrgyz Republic Tajikistan Turkmenistan Uzbekistan Outside CAPS* Total Exports

Kazakhstan -- 277 0 0 310 0 587

The Kyrgyz Republic 697 -- 0 0 2383 0 3080

Tajikistan 0 324 -- 0 2344 0 2668

Turkmenistan 0 0 0 -- 6066 0 6066

Uzbekistan 8139 0 3927 946 -- 0 13012

Outside CAPS* 0 0 0 0 0 -- 0

Total Imports 8836 601 3927 946 11103.2 0

Electricity Trade in 2000 (GWh)

Imports

Exports Kazakhstan The Kyrgyz Republic Tajikistan Turkmenistan Uzbekistan Outside CAPS* Total Exports

Kazakhstan -- 0 0 0 0 0 0

The Kyrgyz Republic 1253 -- 154 0 1926 0 3333

Tajikistan 0 126 -- 0 244 0 370

Turkmenistan 35 0 819 -- 68 0 921

Uzbekistan 0 195 729 32 -- 0 956

Outside CAPS* 2224 0 0 0 0 -- 2224

Total Imports 3512 320 1702 32 2237 0

*Mainly northern Kazakhstan.

Over the 1990-2000 period, the changes in the electricity trade were as follows:

• Within CAPS, in Kazakhstan imports dropped by 85% from 8.8 TWh in 1990 to1.3 TWh in 2000.

• Although the Kyrgyz Republic, a traditional electricity exporter, registered an increase of exports of 6% in 2000 over 1990, the year 2000 was an exceptional year in terms of water needs of the downstream countries and therefore the electricity exports were high. In reality the exports average around 2 TWh per year, which implies a drop of about 35% in its exports. The Kyrgyz Republic’s imports dropped 50% from 0.6 TWh in 1990 to 0.3 TWh in 2000.

• In Tajikistan imports dropped by 56% from 3.9 TWh in 1990 to 1.7 TWh in 2000. In the same period the export went down by 85% from 2.7 TWh to 0.4 TWh.

• In Turkmenistan imports dropped by 97% from 0.9 TWh to 0.03 TWh and export dropped by 85% from 6.1 TWh to 0.9 TWh.

• In Uzbekistan from 1990 to 2000 the import dropped by 80% from 11.1 TWh in 1990 to 2.2 TWh in 2000. The exports dropped by 92% from 13.0 TWh in 1990 to 1.0 TWh in 2000.

3.15 The electricity trade that occurred in 2000 was actually a proxy for water exchanges and, therefore, is an unreliable source of revenue to the electricity exporting countries. Despite the pursuit of national energy self-sufficiency policies, the Kyrgyz Republic and Tajikistan are unable to meet their winter peaks demands for energy.

14

Policies to be Pursued Going Forward 3.16 The current policy frameworks are generally pointed in the right direction in all countries, except that policy implementation needs to be accelerated to assist sector development. Specifically:

• As regards industry structure, third party access to transmission is an absolute necessity if electricity trade is to be enhanced;

• While independent regulation is a final objective (which may take many years to realize), nearer-term measures that should be pursued are: (a) bringing transparency to regulation; (b) providing multi-year regulatory certainty (e.g., adopting a tariff policy that covers several years); and (c) where private operators already exist, even handed treatment of public and private operators, is necessary.

• As regards pricing, especially for the Kyrgyz Republic and Tajikistan, it is useful to follow Uzbekistan’s example and implement a multi-year tariff path to reach cost recovery levels as soon as possible, after taking into account affordability consideration including the provision of a social safety net. In addition to providing the urgently needed resources for investments, proper pricing will also have a beneficial effect on demand, and will give the right signals for intra-CAR trade.

• Private Sector Participation will be important over time, in view of the huge investment need and the weak management capacity.

• There is a need to enhance electricity trade as an integral part of overall energy trade, since such trade would meet demand at the lowest possible cost, given the resource complementarities. However, it should be ensured that energy/electricity trade occurs based on market principles.

3.17 Trade within the region could increase if payments for electricity, water services, and fuels are fully monetized and if the annual IGIAs are based on least cost solutions for the river basins as a whole. Further increases in trade would arise when the transmission systems in all four countries provide non-discriminatory third party access on the basis of transparent transmission tariffs. Metering, payment discipline and settlement mechanisms have to be improved. Further, in order to arrive at rational trade decisions, prices of electricity in all four countries need to reflect the cost of supply.

15

CHAPTER IV: DEMAND SUPPLY BALANCEAND POTENTIAL FOR ELECTRICITY EXPORTS

4.01 This chapter attempts to answer the following set of questions: what is the current and projected demand for electricity in each of the CARs; what are the supply options to meet such demand, and in turn what is the potential exportable surplus from the CARs.

A. Demand Forecast

(i) Issues in Demand Forecasting in CARs. 4.02 Trending, end-use analysis and macroeconomic modeling are the common approaches to electricity demand forecasting. Given the economic collapse following the dissolution of the Soviet Union and the continued decline in GDP and electricity consumption in the former Soviet Union countries, trending would be inappropriate in the CARs. End-use analysis is really what the countries need to do, but is currently difficult on account of paucity of data and is distorted by the excessively inefficient use of electricity. Demand projections made during the Soviet era and even in years immediately thereafter, were more in the nature of targets to be achieved than in the nature of forecasts. Given the central planning background and practices, price as a determinant of demand was largely ignored and concepts of price elasticity and income elasticity were not much in use. Kazakhstan Electricity Association – a national industry association—has recently commenced the practice of making long-term forecasts. There have also been recent forecasts made by consulting firms financed by International Financial Institutions such as ADB and UNDP, and some bilateral aid agencies in the context of their operations, which use macroeconomic modeling and also incorporate considerations of income elasticity and price elasticity. However they do not appear to have considered seasonal variations in demand adequately. Given the high degree of such seasonal variations, it is necessary to incorporate them in the demand projections to determine export surpluses. Also other key assumptions relating to GDP growth rates, electricity prices and possible efficiency improvements need to be updated. The forecast made in this report on the basis of macroeconomic modeling incorporates these elements. The model is based on a simple iso-elastic demand function of the type often used in such aggregate demand analysis. (ii) Key Determinants of Demand Growth 4.03 Demand forecasts have been made for the four countries at the aggregate level, by estimating the total sales in GWh for the sector as a whole (without going into the demand at the level of different classes of consumers) and adding to it the estimated transmission and distribution losses to arrive at the demand at the generation level.11 The details of the model, methodology and assumptions used are presented in Appendix 4.1. Some of the key determinants used are described below.

11 It is worth noting that this demand does not include auxiliary consumption or station use by the generating stations. This consumption could amount to 0.5% to 1% for hydro stations, 4% to 6% for gas fired thermal plants and 6% to 8% for coal fired thermal plants.

16

• Income Elasticity or GDP elasticity of electricity demand: A range of available literature indicates that for most developing countries the GDP elasticity of electricity demand ranges between 1.2 and 1.4 (i.e., for every percentage increase in GDP, the electricity demand increases by 1.2 to 1.4 percent). However, most former Soviet Union states (and more so in the case of CARs) do not fit into this category as their electricity consumption is already very high relative to their GDP level. Therefore, it is expected that the relationship between GDP and electricity demand in CARs would be more akin to those prevailing in developed countries, which have exhibited a GDP elasticity of demand of 0.8. This value had been used in relation to CARs in this study.

• Price Elasticity: The estimates for price elasticity of demand for electricity in lower income countries generally are in the range of –0.1 to –0.2, implying that for every percentage increase in electricity price, the demand decreases by 0.1 to 0.2 percent. The elasticity levels for electricity are generally lower than those for other energy forms (e.g., petroleum products), reflecting:

consumers’ inflexibility to switch from electricity to other forms of energy. This is particularly true of all types of consumers in the short term, and for industries, such as metallurgical and chemical, even in the long term;

non-availability of other energy forms (e.g., gas), as is the case in the Kyrgyz Republic and Tajikistan; and

the share of industrial consumption in overall consumption – the higher the industrial consumption share as is the case with Kazakhstan and Uzbekistan, the lower the price elasticity of demand.

It is also important to note that there is an inverse relationship between price elasticity of demand and a country’s income (GDP) level. At higher income levels, electricity demand becomes less and less elastic to electricity price changes as GDP increases. This is the case with Kazakhstan, where its higher level of GDP would tend to lower the price elasticity values. Considering all of the above, price elasticity values of –0.1 have been assumed in Kazakhstan and Uzbekistan and –0.3 in the Kyrgyz Republic and Tajikistan (where the needed price increases to reach financial viability are 80% and 300% respectively).

• Effective Tariffs: It was also recognized that the effective tariffs paid by the consumers were actually lower than the posted tariffs, due to the poor metering, billing and collection efficiencies. Therefore the applied prices to estimate demand were adjusted by the collection rate to arrive at the effective prices.

(iii) Results of the Base Case 4.04 The results of the base case demand forecast exercise are summarized in Table 4.1 for each country and for Central Asia as a whole. In the short term (up to 2010) the total demand in all four CARs combined is expected to increase at a modest annual rate of 0.31%. Demand is actually projected to decline in Tajikistan, Uzbekistan and the Kyrgyz Republic, whereas in Kazakhstan, there would be a growth of about 2.94% per year. Over the longer term (up to 2025), all countries except Tajikistan would register an increase in demand, resulting in an annual compound growth rate of about 1.9% for the region. Kazakhstan would experience the highest annual rate of growth (3.09%), and demand in Tajikistan would actually decline at 0.17% p.a. compared to the 2003 level.

17

Table 4. 1: Gross Electricity Demand Projections: Base Case

Actual Forecast Demand (GWh) Annual Growth rates Country

2003 2010 2015 2020 2025 2003-2010 2003-2015 2003-2020 2003-2025 Kazakhstan 58,944 72,056 84,034 98,367 115,146 2.91% 3.00% 3.06% 3.09% The Kyrgyz Republic 12,145 9,222 10,033 11,296 12,719 -3.86% -1.58% -0.43% 0.21% Tajikistan 16,348 11,267 12,410 13,972 15,731 -5.18% -2.27% -0.92% -0.17% Uzbekistan 48,691 46,597 51,255 56,589 62,479 -0.63% 0.43% 0.89% 1.14% All Four Countries 136,128 139,142 157,731 180,225 206,075 0.31% 1.24% 1.66% 1.90%

4.05 Kazakhstan’s high growth rate in electricity demand among the four countries is on account of (i) the high sustained GDP growth projected over the period; and (ii) the fact that since its tariffs are already at 94% of cost recovery levels (Chapter III, Table 3.4), the effect of price increases on demand growth would be minimal. The Kyrgyz Republic would actually experience a contraction in demand during 2005-2020 as a result of significant increases in metering, billing and collection leading to a real effective tariff increase of 103% over the period, when collection rates are factored in. There would be modest demand growth thereafter. Tajikistan’s demand would also decline through 2025 for a similar reason - on account of its very low tariff base, tariff increases and improvement in collections would lead to real effective tariff increases of five times the level in 2003. Uzbekistan’s demand would also decline through 2010 but would experience a modest growth rate thereafter. The key reasons for a relatively flat demand curve in Uzbekistan are: (a) extensive gasification of the country in the 1990s, resulting in over 87% of the population having access to gas supplies; (b) relatively lower GDP growth rates, and (c) an assumed increase in real effective tariff of 37% over that period.

(iv) Seasonal Variations in Demand 4.06 As discussed in Chapter III, seasonal variations in electricity demand are significant in the CARs. The CAR region’s annual peak occurs in winter, and consumption during winter (October-March) is substantially higher than in summer (April-September) generally as a result of using electricity for space heating. The variation is highest in the Kyrgyz Republic followed by Kazakhstan, Tajikistan and Uzbekistan in that order. In the Kyrgyz Republic (and to a large extent in Kazakhstan also) gas distribution is limited and electricity is used for space heating. In Tajikistan the increased heat load in winter is somewhat balanced by the irrigation pumping load in summer. In Uzbekistan the seasonal variation is not pronounced on account of extensive gas distribution. For the region as a whole, 58% of the annual consumption takes place in winter (Fig 4.1). This need to be factored in and the supply demand balances need to be worked out on a monthly basis to plan for system expansion and for determining the exportable surplus.

18

0

5,000

10,000

15,000

20,000

25,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

GW

h

2005 2010 2015 2020 2025

Figure 4. 1: Gross Electricity Demand in CARs, Monthly Totals, 2005 - 2025

(v) Sensitivity Analysis 4.07 In view of the fact that the key determinants of demand, price and income elasticity levels chosen were based on experience elsewhere and not in the CARs, the demand projections were subjected to extensive sensitivity analyses by varying the key determinants of demand – price and income elasticity – in both directions. In addition, the projections were tested for delay or acceleration in reaching cost recovery tariffs. The results are summarized in Table 4.2 and elaborated in Appendix 4.1.

Table 4. 2: Results of Sensitivity Analyses on Demand Forecast Percentage Change in End-of-Period Demand for every

Country 1% Change in Income Elasticity

1% Change in Price Elasticity

Kazakhstan 0.74 0.08 The Kyrgyz Republic 0.53 0.52 Tajikistan 0.64 0.74 Uzbekistan 0.45 0.22 All four Countries 0.63 0.20

4.08 Sensitivity analyses showed that demand growth in the region overall is more sensitive to income elasticity values compared to price elasticity. Over the 2005 – 2025 period, every 1% decrease in income elasticity projected demand would decrease by 0.63% compared to 0.2% change in demand for every 1% change in price elasticity. However, projected demand in individual countries behaves differently. Projected demand in Kazakhstan is more sensitive to changes in income elasticity and least sensitive to changes in price elasticity, confirming the international experience that as incomes grow, electricity demand becomes less and less elastic

19

to price changes. Tajikistan, the poorest of the CARs, is more sensitive to price changes. Given the dominant size of the Kazakhstan and Uzbekistan systems within CARs, the regional demand growth patterns will reflect the growth patterns in these two systems. The changes in the timing of projected tariff increases had only a minor impact on projected demand.

B. Supply Options

4.09 The supply options to meet the projected demand include (a) projects for rehabilitation of the transmission and distribution system to reduce the high level of Transmission and Distribution (T&D) losses; (b) projects for rehabilitating the existing generating units; and (c) construction of new generating plants. (i) Loss Reduction 4.10 Reduction of technical losses in the T&D system is the most economical method of meeting the incremental demand when the loss levels are high compared to industry standards. Table 4.3 below indicates the existing and targeted loss levels in the four countries and the volume of incremental demand such reduction would help to meet. Much of the losses are occurring in the low voltage distribution systems, since the consumption structure has shifted more towards residential consumption in all countries. This shift is most pronounced in the electricity dependant Kyrgyz Republic and Tajikistan. Though losses in the transmission systems, as reported at about 8%, are higher than the industry standard of 4% to 5%, most of the system is still carrying loads lower than their design capacity (the overall power transmitted in 2003 was still only 90% of the level it carried in 1990); and considerable investments have already been made in the transmission system12.

Table 4. 3: Current and Targeted Electricity Loss Levels in CARs Country Current Losses* (%)

(2004) Target Loss Levels (%) Time Period of the Projects

Additional Annual Electricity (GWh) in 2010

Kazakhstan 24 15 2004-2010 5,843

The Kyrgyz Republic 34 13 2004-2010 1,39213

Tajikistan 28 13 2004-2010 1,988

Uzbekistan 25 15 2004-2010 4,064

*Includes technical losses mainly, but also some commercial (unbilled consumption) losses. 4.11 The focus of future investment thus would be more on distribution rehabilitation, reinforcements and expansion. The projects for the reduction of losses in all four countries implemented during 2005-2010 would make available an annual incremental supply of 13,287 GWh of electricity by 2010. The total value of investments on such transmission and distribution loss reduction projects in all four countries is estimated at $3,009 million in 2004 prices.

12 Roughly US$80 million of a foreign funding of power sector investments in Kyrgyz Republic has been spent on transmission, and ADB and EBRD are assisting Uzbekistan with its transmission system improvement, ADB is assisting Tajikistan to invest in rehabilitation of its transmission system; and World Bank is assisting Kazakhstan. 13 An additional 220 GWh would be realized in 2011.

20

(ii) Rehabilitation of Generation

4.12 Major hydropower stations in the region are generally in reasonably good condition. Rehabilitation of Nurek hydropower station in Tajikistan has already been funded. In the Kyrgyz Republic the main thermal plant (Bishkek CHP-I) has already undergone feasible rehabilitation. The rehabilitation of the CHP units in Tajikistan would add relatively small amounts of electricity. On the other hand there is considerable scope for rehabilitation of thermal power stations in Uzbekistan and Kazakhstan to secure increased power generation from them.

• In Uzbekistan UzbekEnergo estimates that out of the total installed thermal generating capacity of 9,870 MW (consisting of 11 thermal plants) only about 8,200 MW is actually available. If units well beyond the age of 35 years and or 200,000 hours of operation are also excluded the available capacity would be even lower at 7,800 MW. UzbekEnergo, with considerable support from the Government, is undertaking rehabilitation of the country’s electric generation capacity through several projects, including an US$81 million loan from EBRD for the renovation of the Syrdarya plant and a US$200 million loan from Japan Bank for International Cooperation (JBIC) for the rehabilitation of Tashkent coal fired station. Further rehabilitation of two units at Syrdarya as well as the rehabilitation of the Angren, Navoi Angren units are planned. When all the planned rehabilitation of power plants is implemented over the 2004-2023 period at a cost of US$1.15 billion, the operational life of all major power plants would have been extended avoiding the loss of generation of about 32,000 GWh (during 2005-2025) due to retirements.

• In Kazakhstan, large thermal power plants (called “National level” power plants) provide

considerable generation volumes of electric power. These are the Ekibastuz I and II, Aksu and Karaganda coal fired thermal power plants, There is a need for rehabilitation of the thermal power plants since all of them are operating at low plant use factors (29% at Ekibastuz I compared to a design value of 77%; 51% at Ekibastuz II; 52.5% at Aksu; and 54% at Karaganda); and 58% of the total installed thermal capacity or about 10,600 MW, will reach the end of its operational life before 2015. The rehabilitation of Ekibastuz I plant is expected to cost $440 million and result in the annual incremental generation of 11,283 GWh. The Kazakhstan Electricity Association (KEA) estimates that roughly US$1,070 million is needed to rehabilitate the thermal power plant (US$770 million for all other national power plants and $300 million for the regional plants owned by the Regional Electricity Companies) to extend the operational lives of the units and improve the plant factor to 60%. With such rehabilitation, the incremental annual generation from those plants would amount to 17,118 GWh.

(iii) New Generation Projects

4.13 Large new power plant projects are contemplated in all four countries and they are briefly discussed below14. 14 It is important to note that the information on costs, time to completion of construction etc, are obtained from country authorities, and have not been independently verified. Such verification would come when investment commitments would be contemplated.

21

• New Ekibastuz Thermal Power Station in Kazakhstan15: The existing Ekibastuz II power

station consists of two coal fired units of 500 MW each located in a site which has all the infrastructure and site facilities to accommodate easily two more units of 500 MW each. The original project planning was done during the Soviet era on this basis. A recent study has estimated the cost of construction of these additional units at $1,085 million.16 The implied cost per kW of about $1000 is lower than the international reference cost of $1300 per kW reflecting the availability of basic infrastructure.17 This project is expected to be implemented during 2008-2011 and is expected to result in an incremental annual generation of 7,446 GWh.

• Bishkek II Thermal Power Plant in the Kyrgyz Republic: This plant, referred to

sometimes as Bishkek CHP II, is a plant that is partly constructed Its construction began in 1985, but has been put on hold since 1992. The original scheme was to develop a combined heat and power plant of 800 MW, including seven heat-only-boilers as Phase 1 of the plant. Two of the seven planned heat-only-boiler units, as well as the building housing the boilers, water treatment facilities, natural gas and fuel oil supply/storage installations, flue disposal structure (chimney) and a railway line within the land allocated to the plant of about 47 hectares have been installed. The plant is designed to use mainly natural gas from the Tashkent-Almaty gas pipeline. In addition, a newly equipped 220-kV substation is located just next to the plant site, which will facilitate the evacuation of power. Constructing a new gas fired 400 MW thermal plant using the combined cycle technology making the best use of the existing site facilities is perhaps the most cost-effective and rational solution to meet the winter power shortages of the Kyrgyz system. Allowing one year for engineering and raising finances, and two years for construction this plant could be commissioned in 2007, enabling an annual incremental generation of 2,453 GWh from 2007 or 2008. Taking into account the site facilities already available the capital cost is not expected to exceed $200 million.18

• Kambarata I and Kambarata II Hydroelectric Projects in the Kyrgyz Republic are being

actively pursued by the government. Kambarata I is a 1,900 MW storage hydroelectric facility, identified and designed during the Soviet era, located in the middle part of the Naryn river upstream of the Toktogul reservoir (see Figure 4.2). As proposed, it would be a 275 meter high dam built by controlled blasting and would include the associated power/spillway tunnels, penstocks and power generation facilities. The reservoir would have a live storage of about 3.4 BCM and would provide seasonal storage. The maximum net head of the dam would be 180 meters and annual energy generation would be about 5,000 GWh with a plant use factor of about 30%. Since it is located upstream of Toktogul reservoir (which has a much larger live storage of 14 BCM), water could be released from Kambarata I to generate almost all of its annual power output in the winter, thus

15 This is a state owned power plant in which 50% of the equity is believed to have been transferred to RAO UES of Russia in lieu of the electricity arrears, which Kazakhstan had owed to RAO UES for power imports from Russia. 16 RWE Solutions/Lahmeyer International: Feasibility Study for the Kazakhstan North-South Line 2002 17 However, it needs to be verified if this costs include environmental impact mitigation equipment. 18 Compared to the international reference price of $600 to $700 per kW for a green-field Combined Cycle plant, the plant proposed in Bishkek is likely to cost less than $500/kW.

22

avoiding the release of water from Toktogul in the winter. Enabling additional generation of electricity during winter without releasing water from Toktogul would be the most significant contribution of this project. The estimated capital cost of Kambarata I is about US$1.67 billion, and together with transmission line costs needed to evacuate power (of about $265 million), the total costs would amount to $1.94 billion (or $1,000/kW). It is anticipated that it would take 8 years to prepare the project and 9 years to construct it and that power would be available starting in 2017, though the full output could be realized only in 2020.

KYRGYZST AN ELECT RICIT Y SYST EM

110 kV

Osh TET

Glavnaya

Almaty

Toktogul

October

Lochin

Alai

Kemin

Tamga

Ak Kiya

Ala ArchaTokmak

Bishkek TET

Kara Balta

Frunzenskaya

Ala Bel

Uzlovaya

Semetey

Jalalabad

Naryn

Talas

Tashkent

Balykchy

KrystalUch Kurgan

KurpsaiTash Kumyr

Shamaldi Sai

At BashiHydro

Toktogul Cascade

Kambarata 2

Datka

Upper Naryn Hydro

500 kV 220 kV

Substations and Lines

Power Stations and Lines

Existing

Existing Existing

Existing

Proposed

Proposed

Proposed

ProposedBakten

Jambal

Chui

Shymkent

Stepnaya

Kara BulakAigul Tash

KYRGYZSTAN ELECTRICITY SYSTEM

110 kV

Figure 4. 2: Kyrgyz Power System and Location of Kambarata schemes

• Kambarata II would be a run-of-the river hydro project downstream of Kambarata I but

upstream of Toktogul (see Figure 4.2). The installed capacity would be 360 MW if Kambarata I is developed, or 240 MW if it is a stand-alone scheme. As proposed, it would be a 62 meter high dam built by controlled blasting, and would include the associated power/spillway tunnels, penstocks and power generation facilities. The average energy production would amount to about 1,100 GWh at 240 MW and 1260 GWh at 360 MW. Almost all the generation, when built as a stand alone project, would be in the summer. About 20% of the project had already been completed and the incremental costs for completing this project are estimated at about $280 million for a 240 MW plant, including the necessary transmission lines. On this basis, the cost per kW of Kambarata II would be about US$1,167. It is important to note that in the absence of Kambarata I, the Kambarata II project should be considered with caution as it would merely add to the summer surplus and would not help to remedy the winter shortage of electricity. However construction is proceeding, albeit slowly, and RAO UES of Russia has reportedly agreed to fund the effort to update the feasibility report and if construction is to begin in say 2008/09 it may be possible to commission it by 2012.

Kambarata II Kambarata I

Source: Kyrgyz Republic-UK DfID Tariff Policy Project, 2003

23

Figure 4. 3: Planned and Existing Hydro Schemes on Vaksh River in Tajikistan

• Rogun Hydropower Project of Tajikistan is located upstream of the existing Nurek hydropower cascade on the Vaksh river (see Figure 4.3). The project was planned to be constructed in two phases with an ultimate installed capacity of 3,600 MW. The dam to be built will be one of the highest in the world with a height of 335 meters. The construction of the project commenced during the Soviet era when all the construction machinery was assembled, construction colony was established, and diversion tunnels and most of the excavation needed for the project were completed at a cost of $800 million (as estimated by Tajik authorities). Since 1992 no further progress had been made for want of funds. The incremental costs required to complete this project are about $2.1 billion19. In Phase I the remaining works would involve the construction of the dam to two-thirds of its final height, repairing two existing tunnels; building a third new tunnel; creating the regulating reservoir and installing two generation units which would operate

19 The full costs are estimated by Tajik authorities at about $2.9 billion, of which they claim that $800 million has already been spent.

Legend: Prospective HPPs Operating HPPs 1 - Rogun HPP (3600 MW) 2 – Shurob HPP (750 MW) 3 – Nurek HPP (3000 MW) 4 – Baipaza HPP (600 MW) 5 – Sangtuda I HPP (670 MW) 6 – Sangtuda II HPP (220 MW) 7 – Golovnaya HPP (240 MW) 8 – Perepadnaya HPP (29.9 MW) 9 – Central HPP (15.1 MW)

24

with a capacity of 800 MW. The electricity output of this Phase I would be about 4,300 GWh, and it would also enable the generation of an additional 400 GWh at Nurek. The funds needed to complete this Phase I are estimated at $785 million.

• Phase II involving completion of the dam to its full height of 335 meters and installation of additional power capacities of 2,800 MW is expected to cost $ 1.67 billion. After completion of Phase II, the whole Rogun scheme would generate roughly 13,000 GWh and the additional generation at Nurek would increase to 1,300 GWh.

• Sangtuda I Hydropower Project in Tajikistan is a proposed to be located downstream of

the existing Nurek hydropower cascade (see # 4 and 5 on Figure 4.3) on the Vaksh river. The construction of this project also commenced during the Soviet era and was suspended in 1992 for want of funds after completing a sizeable amount of work. The planned installed capacity on this run-of-the-river scheme is 670 MW and expected annual electricity generation would be about 2,700 GWh. About 60% of the generation would be in the summer months (April to September) and the remainder would be during the winter months. The total cost of the project is estimated to be about $482 million, and it is estimated that about $114 million has already been spent. Therefore, a further $368 million would need to be mobilized to complete the project.

• Talimardjan Thermal Power Project in Uzbekistan is a gas fired steam turbine plant with

4 units of 800 MW each. It is located in the Mubarek gas field, one of the larger producing gas fields in Uzbekistan. This project was also started during the Soviet times, and the basic infrastructure has been built for the four units. Since independence, Uzbekistan has been attempting to install and commission the first unit, which is expected to come on stream in 2005. It is estimated that about $100 million would be needed to commission this unit, which at a plant factor of 60% would annually produce about 4,537 GWh. This would complete the first phase. The amount of sunk cost already incurred is not readily available. The second phase would involve construction and commissioning of the three remaining units of 800 MW each and would likely to take place during 2009-2013 after firming up possible export sales agreements. The capital cost for this phase is estimated at $ 1.2 billion ($500/kW) taking into account the infrastructure which is already in place. These three units would provide an annual incremental generation of about 13,613 GWh.

(iv) Overall supply increases

4.14 As a result of the implementation of the above mentioned projects the overall gross supply in all four countries would rise from 139 TWh in 2003 to 228 TWh in 2025. About 54% of this incremental supply would come from new generating units, about 16% from loss reduction programs and the balance 30% from the rehabilitation of old generating units (see Table 4.4). Kazakhstan would contribute 45% of the incremental supply, followed by Uzbekistan and Tajikistan (22% each) and the Kyrgyz Republic (9%). Appendix 4.2 contains a more detailed set of information for each country and for the different years.

25

4.15 In addition to these supply increases, the Kyrgyz Republic and Tajikistan have some additional options to increase availability of electricity in winter from existing sources:

• In the Kyrgyz Republic, it is now possible to operate Toktogul cascade in a modified

irrigation mode (see Chapter II) which will enable the release of an additional 1.5 BCM of water and thus generate an additional 1.5 billion kWh in the winter;

• In Tajikistan it is possible to shift the heat demand away from electricity to other resources (coal, gas, biomass), which is expected to make available roughly 860 GWh to meet electricity demand.

Table 4. 4: Composition of the Annual Incremental Supplies

Incremental Supply (GWh) resulting from Projects Relating to: Country

Loss reduction Generation Rehabilitation New Generation Total

41,094 Kazakhstan 5843 28401 6850

45%

10,121 The Kyrgyz Republic 1612 - 8509

11%

19,678 Tajikistan 1,988 +860 - 16830

22%

19,637 Uzbekistan 4064 -1489 17062

22%

14,367 26,912 49,251 90,530 Total

16% 30% 54% 100%

Note: The negative number in column 3 above indicates reduction in generation due to retirements in Uzbekistan. Also 860 GWh is gained in Tajikistan due to replacement of electricity for heating in winter by other energy sources.

C. Demand and Supply Balance and Export Potential

4.16 The supplies for each country for each year during the period 2005-2025 (from existing level of supply, the incremental generation coming on stream and retirement of old generating units) are compared to the projected demand in Table 4.5 The results indicate that in 2005 there would an annual surplus 7.4 TWh. Once the new investments start yielding, the regional surplus would rise to 43.4 TWh in 2020. Towards 2025, surpluses would drop back to 16.5 TWh, as demand growth outstrips supply growth. All countries except Uzbekistan have a deficit in winter currently. With the new projects, the largest surpluses come from Uzbekistan (2015) and Tajikistan (2020). 4.17 The picture is different when variations between summer and winter conditions are considered. In the winter of 2005 the region as a whole has a shortage of 1.6 TWh (2% of winter demand), but these deficits would be turned around as new investments start yielding output. The winter surplus in 2010 amounts to 6.9 TWh and it rises to 15.5 TWh by 2020. New capacity may be needed to meet winter demand towards 2025. The Kyrgyz Republic would be able to meet its winter demand (and therefore annual demand) through 2020, without Kambarata I and II, but with Bishkek II. Kazakhstan faces winter shortages but these shortages can be met through trade. Tajikistan would experience sizeable winter surpluses from 2010. Uzbekistan, however, has winter surpluses right through (see Table 4.5 and Figure 4.3).

26

Table 4. 5: Surplus Electricity Available for Trade (GWh) Country Season 2005 2010 2015 2020 2025

Summer 3198 3623 6876 3745 -234

Winter -2504 -2969 -130 -5563 -12318 Kazakhstan

Annual 694 654 6746 -1818 -12552

Summer 4737 6283 6863 6406 5991

Winter -2092 1584 1517 5761 4753 The Kyrgyz Republic

Annual 2645 7866 8381 12167 10744

Summer 1511 4587 6767 12579 11697

Winter 96 2841 4287 8308 7431 Tajikistan

Annual 1607 7429 11055 20887 19128

Summer 1620 3904 7635 5088 2091

Winter 2862 5485 9846 7058 3767 Uzbekistan

Annual 4482 9389 17481 12147 5858

Summer 11066 18396 28142 27819 19545

Winter -1637 6942 15521 15564 3633 All Four Countries

Annual 9429 25338 43663 43383 23178

4.18 It should be borne in mind that this is an indicative analysis intended only to provide a broad understanding of the potential for exports. Further meaningful analysis would be possible when the simulation of the systems are done both in energy and capacity terms (taking into account the daily and seasonal variations in demand both in the producing and importing markets). This is likely to be undertaken during the second phase of this study.

-10000

0

10000

20000

30000

2005 2010 2015 2020 2025

GWh

Summer Winter

Figure 4.4: Central Asia Export Surpluses

27

Economic Assessment of Loss Reduction and Generation Rehabilitation Investments 4.19 A major portion of the projected demand in the CARs can be met with loss reduction and generation rehabilitation. The investments needed in transmission and distribution for loss reduction and in generation rehabilitation in the CARs is summarized in Table 4.6. Investment needs in the Kyrgyz Republic and Tajikistan are in transmission and distribution for technical loss reduction projects, whereas in Kazakhstan and Uzbekistan investment in generation rehabilitation are also needed in addition to those in transmission and distribution. Accordingly, these two countries account for 90% of the investments needs in the region.

Table 4. 6: Investment in Loss Reduction and Generation Rehabilitation in CARs (US$ million)

Investment Project 2004-2005 2006-2010 2011-2015 2016-2020 2021-2025 2004-2025 AIC (c/kWh)Kazakhstan Transmission and Distribution 324.0 972.0 0.0 0.0 0.0 1296.0 2.8 Ekibastuz GRES-1 Rehabilitation 0.0 308.0 132.0 0.0 0.0 440.0 2.65 Other Large and Medium Units Rehabilitation 0.0 395.9 460.1 214.0 0.0 1070.0 2.75 Kazakhstan Total 324.0 1675.9 592.1 214.0 0.0 2806.0 2.8 The Kyrgyz Republic Transmission and Distribution 50.0 200.0 0.0 0.0 0.0 250.0 2.3 The Kyrgyz Republic Total 50.0 200.0 0.0 0.0 0.0 250.0 2.3 Tajikistan Transmission and Distribution 25.0 285.0 0.0 0.0 0.0 310.0 2.1 Tajikistan Total 25.0 285.0 0.0 0.0 0.0 310.0 2.1 Uzbekistan Transmission and Distribution 172.9 691.8 288.2 0.0 0.0 1153.0 3.5 Rehabilitation of Existing Generation 87.0 522.0 246.8 80.7 213.5 1150.0 3.6

Uzbekistan Total 259.9 1213.8 535.0 80.7 213.5 2303.0 3.5 CARs Grand Total 658.9 3374.7 1127.1 294.7 213.5 5669.0

4.20 Table 4.6 also summarizes the impact of the investments in loss reduction and generation rehabilitation on the cost/kWh of electricity for individual investment schemes as well as for the respective systems. As shown, these investments would result in a system average incremental costs/kWh (in 2004 prices) of 2.1 cents in Tajikistan; 2.3 cents in the Kyrgyz Republic; 2.8 cents in Kazakhstan and 3.5 cents in Uzbekistan. Details are provided in Appendix 4.1.

28

CHAPTER V: ASSESSMENT OF NEW GENERATION OPTIONS

5.01 This chapter would try to answer the following set of questions: what are the economic and financial costs of the electricity generated from the new generation projects? What would be the transmission costs for the power to understand the landed cost of power in the target markets? How competitive would the landed power from CARs be in these target markets?

A. Technical Assessment 5.02 A summary of physical and technical parameters of the new projects under consideration in Central Asia20 is provided in Table 5.1. All projects, except Kambarata I and the New Ekibastuz Thermal Plant, are partly constructed. Of these, Talimardjan is the most advanced (requires only one year to complete) and Kambarata II is the least advanced.

Table 5. 1: Physical and Technical Details of New Generation Projects

Project Country Type

Capital Costs

($ million)

First Year

of Output

Capacity MW

Steady State

Generation (GWh)

Steady State Sales

(GWh)

Sangtuda I Tajikistan Hydro (Run-of-River) 370 2009 670 2,700 2,673 Rogun I Tajikistan Hydro (Storage) 785 2014 1,200 4,690 4,643 Rogun I&II Tajikistan Hydro(Storage) $2,455 2014 3,600 14,300 14,157 Kambarata I The Kyrgyz Republic Hydro (Storage) 1,940 2017 1,900 5,100 5,049 Kambarata II The Kyrgyz Republic Hydro (Run-of-Rover) 280 2012 240 1,116 1,105 Bishkek II The Kyrgyz Republic Thermal Gas CCGT 196 2007 400 2,453 2,355 Talimardjan I Uzbekistan Thermal Gas fired Steam 100 2005 800 4,537 4,265 Talimardjan II Uzbekistan Thermal Gas fired Steam 1,200 2011 2,400 13,613 12,796 Ekibastuz Rehabilitation Kazakhstan Thermal Coal Fired Steam 440 2010 2,000 12,264 11,283 New Ekibastuz Plant Kazakhstan Thermal Coal Fired Steam 1,085 2020 1,000 7,446 6,850

5.03 In terms of planned installed capacity Rogun I and II together would be the largest, at 3,600 MW, followed closely by both phases of Talimardjan in Uzbekistan, which would have a capacity of 3,200 MW. Partly due to its advanced state of construction, and partly due to the fact that the capital costs of thermal projects would be lower than for hydro projects, Talimardjan I has the lowest capital cost per kW of installed capacity, followed by Ekibastuz rehabilitation. In terms of electricity output, the Talimardjan scheme would have the highest output of 18,150 GWh, which represents a plant factor of about 65%. This plant factor could be higher (e.g. 85%), but there are technology issues21 and gas reserves issues22, which are likely to keep the plant

20 The list also includes rehabilitation of the 4 x 500 MW units at Ekibastuz I plant owned by US based AES, as this company has plans to rehabilitate and add substantial capacity at this location, assuming markets exists 21 Though each unit will have a nameplate capacity of 800 MW, the maximum plant factor is expected to be 65% only based on technical/operational experience in a few similar operating units in the former Soviet Union. Further, cooling water availability is a limiting factor for the first unit. Before proceeding with the three new units arrangements for additional water supply must be firmed up. 22 The plant is located at the Mubarek gas field, which is a reasonably large field. However, the field has been producing for more than 15 years now, there has not been an independent audit of the reserves to know what is the remaining recoverable reserves from this field.

29

factor low. Rogun would have the next highest output of 14,300 GWh23, representing a plant factor of about 45%. This is rather high for hydro projects (which are typically in the 20 to 30% range) and reflects the assumed nature of the glacier-melt and snow-melt fed water flows in the Vaksh River, which currently average 20 BCM annually. The rehabilitated Ekibastuz I plant would be the third largest producer, with an annual output of 12,300 GWh, i.e., at a plant factor of 70%, typical for a coal-fired steam power plant. 5.04 Time needed to complete the remaining works and commission the plant would be the lowest for Talimardjan I followed by Bishkek II, which would require a year to prepare and two years to construct. The smaller hydro scheme at Sangtuda I, which is essentially a run-of-the-river scheme, could be completed in 4 years and could come online in 2009. The larger storage hydro schemes, Rogun and Kambarata I, would require a longer preparation time, typically 4-5 years, and a long construction time, typically 7 years. These large storage hydropower schemes on international rivers would need time to sort out environmental and riparian issues. Accordingly, it is estimated that the first units from Rogun could be put into operation in 2014, and those from Kambarata I in 2017. Kambarata II could come on stream in 2012, though its construction ahead of Kambarata I has to recognize certain risks 24. The new thermal power plants, Talimardjan II and the New Ekibastuz Plant, could come on stream after the rehabilitation of existing thermal plants. Accordingly, Talimardjan II construction could start in 2009 and the new units would commence generation in early 2011. The New Ekibastuz Plant construction could start in 2016 and units would be put into operation from 2019 onwards.

B. Economic Assessment (i) Economic Cost of Generation 5.05 Based on the above technical parameters, the economic costs of output from each of the new projects are derived, as summarized in Table 5.2. The details of the computations are given in Appendix 5.1, including annual phasing of capital expenditures, fuel costs (where applicable), operation and maintenance (O&M) costs, as well as the energy sent out from the generating station (i.e., gross energy generated minus station use or auxiliary consumption). For projects partly constructed, capital costs shown are for completing the remaining works needed to commission the unit (i.e., sunk costs are not taken into account). For Kambarata I and the New Ekibastuz Thermal plant for which no cost has so far been incurred, full construction costs have been taken into account. All costs are stated in constant 2003 dollars.

5.06 Talimardjan I would have the lowest economic output costs, reflecting minimal incremental capital costs and a short construction timeframe. Sangtuda I has the next lowest output cost, followed by Bishkek II, reflecting the smaller capital outlays (compared to new projects of similar size), shorter construction period. From a Central Asian perspective, much of Sangtuda I’s generation (60%) is in the summer, when there are already surpluses in Tajikistan

23 When combined with the additional generation of 1,300 GWh at Nurek. 24 It is essentially a run-of-the river plant with very little storage and generates only in the summer, when there is already surplus electricity. Also, without Kambarata I, the sedimentation problems could become severe calling for expensive solutions.

30

as well as elsewhere in the region, but the thermal projects can generate electricity throughout the year, especially in winter, when there are shortages.

5.07 Among the large hydro schemes, Kambarata I would have the highest economic output price of 7.17 cents/kWh and is therefore the least attractive. Compared to Rogun, Kambarata’s cost/kW installed is about 50% higher (US$1,021 compared to US$682) and its plant factor is much lower (31% compared to 41%). Rogun I would be able to generate power after five years of construction while Kambarata I will take eight years of construction before it could generate power. Further, Rogun also benefits from the fact that when it is built, the generation at the downstream Nurek reservoir would also increase.

Table 5. 2: Comparison of Economic Cost of Supply with Marginal Costs in Exporting/Importing Countries and Status of Cost Competitiveness

Marginal Generation Costs in the Target Export Markets (cents/kWh) Afghanistan Iran Pakistan Russia China New Project

Economic Cost/kWh from the

New Project

National system Marginal Cost

/kWh without the New Project 3.7 3.56 5.6 3.0 3.6 to 4.0

Sangtuda I 1.97 2.1 yes yes yes yes yes Rogun I 2.46 2.1 yes yes yes yes yes Rogun I&II 2.83 2.1 yes yes yes yes yes Kambarata I 7.17 2.3 no no no no no Kambarata II 3.72 2.3 no no yes no no Bishkek II 2.55 2.3 yes yes yes yes yes Talimardjan I 1.68 3.5 yes yes yes yes yes Talimardjan II 2.76 3.5 yes yes yes yes yes Ekibastuz I Rehabilitation 2.65 2.8 yes yes yes yes yes New Ekibastuz Plant 4.54 2.8 no no yes no no

5.08 The economic analysis determined the economic cost/kWh for each generation option at a discount rate of 10%. What this also implies is that if the output could be sold in the domestic or export markets at higher prices the internal Rate of Return would be higher than 10%. A comparison is also made in Table 5.2 between the economic output costs from the new projects and: (a) the average prices needed to recover the incremental costs of the relevant national power system without the new projects25; and (b) the estimated marginal generation costs in the target export markets. 5.09 The above table helps to judge, broadly whether the projects are reasonable economic choices in the national, regional and export electricity markets. Electricity from projects like Sangtuda I, and Talimardjan I and II have economic costs actually lower than the average incremental costs of their national systems26, and therefore these projects make sense as good capacity additions to the national grids if the incremental demand warrants such capacity addition. Actually, most of the projects except Kamabarata I and the New Ekibastuz Plant seem to be economic choices, purely based on generation cost consideration. Later in this chapter,

25 The incremental cost referred to here consists of investment costs, fuel, O&M costs of rehabilitation of generation, transmission and distribution, including loss reduction. 26 That is, average incremental costs of national system before the construction of these projects.

31

competitiveness analysis is carried out which considers costs of transmitting central Asian power to target market.

C. Financial Assessment 5.10 The financial analysis is carried out to understand the financial cost of supply of electricity from each of the new supply options. A corporate finance approach is taken where it is assumed that each of these options would be developed as an independent power producer with private sector participation. Also, to enable comparability, a consistent set of assumptions is applied as regards financing structure, cost of capital etc. 5.11 The estimated costs used for the economic analyses (Table 5.1) are converted to nominal values and interest during construction (IDC) is considered to arrive at the financing needed for each project. The financing of each of these projects is based on a structure that would result in a post IDC financing structure of roughly 25% equity and 75% debt. This structure brings a balance between the lenders’ views (assurance that the debt service is adequately covered from annual net revenues) and investors’ views (minimize equity, also because equity is often costlier than debt which would drive up the output costs). The terms of debt assumed are an interest rate of 10%, a repayment period of 15 years including a five year grace period. The equity is expected to earn an internal rate of return (IRR) of 15% over the life of the investment, which translates to an annual rate of return on equity in the range of 17% to 24% in respect of these projects27. On this basis, the tariff/kWh required to service the debt and provide the return on equity for each year is computed for a 20-year period. These annual tariffs are then levelized28 to enable comparison among different financing options (for a given project) or among different projects. Such levelized tariff/kWh for the projects are summarized in Table 5.3.

Table 5. 3: Levelized Tariffs for Generation Options

Project Electricity output GWh

Levelized Tariff Cents/kWh

Sangtuda I 2,673 2.44

Rogun I 4,643 2.91

Rogun I &II 14,157 3.24

Kambarata I 5,049 8.54

Kambarata II 1,105 3.95

Bishkek-II 2,355 2.67

Talimardjan I 4,265 1.75

Talimardjan II 12,796 2.92

Ekibastuz Rehabilitation 11,283 2.66

Ekibastuz New 6,850 5.05

27 The level of annual Return on Equity varies among the projects, largely, as a function of the construction period. Longer construction periods make the investors wait for longer periods for cash inflows and thus raise the annual equity returns to achieve a 15% IRR on equity over the life of the investment. 28 Levelized tariffs are the smoothened tariffs for the whole period under consideration. It is a single tariff figure and it implies that the present value of the cash flow generated from the application of levelized tariff will be the same as the present value of the cash flow generated through the application of the actual tariff, which usually varies, sometimes significantly, from year to year.

32

0

1

2

3

4

5

6

7

8

9

10

10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 Plant Factor %

AIC USc/kWh

Sangtuda HPP Rogun HPP I Rogun HPP I and IIKambarata 1 HPP Kambarata 2 HPP Talimatjan TPP Unit #1Talimatjan TPP Units #2-4 Bishkek 2 Ekibastuz 1Kazakh New

5.12 As can be seen, the financial output costs are consistent with the economic costs analyses, in that Talimardjan I remains the most attractive, and Kambarata I the least.

D. Sensitivity Analysis 5.13 Sensitivity analyses are carried out on from both economic and financial perspectives, to understand how the changes in key variables impact output costs. Economic Sensitivity Analyses 5.14 The above economic output costs assume that all the production from these new projects would be sold (either in the domestic market or in the export markets). However, it is possible that sometimes, not all of the power generated would be consumed. Therefore, a sensitivity analysis has been performed on each of the projects to understand the extent of impact on output costs, under different plant factors, and the results, in what are known as Screening curves, are shown in Figures 5.1 and 5.2.

Figure 5. 1: Economic Output Costs of New Projects at different Plant Factors Vs. Average Incremental Costs of National Systems of CARs

5.15 The curves in Figure 5.1 compare the economic output costs of power from the new projects at different plant factors with the average incremental costs of each system before the construction of the new projects. This indicates the limits of plant factors at which the marginal costs from the new projects remain conducive to internal trade within the CARs. As the plant factor is lowered, the volume of generation declines and the economic cost of output/kWh rises. Rates of such rise are notably lower in the case of thermal projects than in the case of hydro projects. A combination of these graphs and the marginal cost data of export markets give us an

Uzbek AIC 3.5 ¢/kWhKazakh AIC 2.8 ¢/kWh

Tajik AIC 2.1 ¢/kWh Kyrgyz AIC 2.3 ¢/kWh

33

0

1

2

3

4

5

6

7

8

9

10

10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 Plant Factor %

AIC USc/kWh

Sangtuda HPP Rogun HPP I Rogun HPP I and IIKambarata 1 HPP Kambarata 2 HPP Talimatjan TPP Unit #1Talimatjan TPP Units #2-4 Bishkek 2 Ekibastuz 1Kazakh New

0

1

2

3

4

5

6

7

8

9

10

10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 Plant Factor %

AIC USc/kWh

Sangtuda HPP Rogun HPP I Rogun HPP I and IIKambarata 1 HPP Kambarata 2 HPP Talimatjan TPP Unit #1Talimatjan TPP Units #2-4 Bishkek 2 Ekibastuz 1Kazakh New

indication of the range of demand within which these projects remain economic in the export markets (See Figure 5.2). Figure 5. 2: Economic Output Cost of New Projects at Different Plant Factors Vs. Generation costs

in Target Markets (Excluding Transmission Cost)

Financial Sensitivity Analyses

5.16 Sensitivity analysis on the financial assessments has been carried out for decreases in generation, for increases in capital expenditures, fuel cost, interest rate and rates of return on equity. The results are summarized in Table 5.4. Given the high cost per kW, long preparation and construction times and low load factors, the hydropower projects are much more sensitive to changes in respect of most parameters, than thermal power projects. Accordingly, unless firm export contracts are in place it would not make sense to invest in these projects. Thermal power projects would be able to deal with possible reductions in export demand much better than the hydro projects. However, thermal projects are also quite sensitive to fuel price increases. The high sensitivity value for fuel price changes for Talimardjan I is due to the fact that the considered capital costs is very small, since a large portion of it is sunk cost.

Generation costs in Pakistan 5.6 c/kWh

Generation costs in Afghanistan Iran and China 3.6 cents/kWh

Generation costs in Russia 3.0 c/kWh

34

Table 5. 4: Results of Sensitivity Analyses on Levelized Tariffs of Generation Projects Percentage change in levelized tariff when there is

Project Base Case

Levelized Tariff Cent/kWh

1.0% decrease in Generation

1.0% increase in Capital

Expenditure

1.0% increase in Interest Rate*

1.0% increase in Return on Equity**

1.0% increase in Fuel Cost

Sangtuda I Hydro 2.44 1.25% 0.97% 0.70% 0.42% ..

Rogun I Hydro 2.91 1.25% 0.99% 0.71% 0.45% ..

Rogun I &II Hydro 3.24 1.25% 0.89% 0.79% 0.49% ..

Kambarata I Hydro 8.54 1.25% 1.00% 0.82% 0.52% ..

Kambarata II Hydro 3.95 1.25% 0.99% 0.38% 0.46% ..

Bishkek-II 2.67 0.83% 0.46% 0.30% 0.21% 0.34%

Talimardjan I 1.75 0.37% 0.17% 0.09% 0.04% 0.71%

Talimardjan II 2.92 0.81% 0.59% 0.47% 0.31% 0.17%

Ekibastuz Rehab 2.66 0.63% 0.23% 0.18% 0.12% 0.50%

Ekibastuz New 5.05 0.60% 0.59% 0.46% 0.50% 0.29%

*1% of 10% or 10 basis points; **1% of assumed rate of return (17 basis points if the RoE is 17%).

E. Competitiveness Assessment

5.17 From the previous sections it appears that Central Asian power, including several of the new projects, could be competitive in the target export markets. However, to gain a better understanding of competitiveness, it is necessary to consider the landed costs of Central Asian power in the target markets and therefore the costs of transmission from Central Asian grid (CAPS) to each of these target markets should also be considered.

Transmission Needs for Electricity Trade 5.18 On the face of it, it would appear that no major expansion of the grid is needed to accommodate power transfers from one part of the CAPS to the other since the electricity currently handled by the CAPS is currently 136 TWh (2003) compared to 184 TWh in 1990. However, this needs to be confirmed with studies of the present and projected load flows, and also an assessment of the condition of the network29. Nevertheless, one link that is considered strategic is the expansion of the North South transmission link in Kazakhstan to facilitate enhanced flows of power from north Kazakhstan to south Kazakhstan, and removal of bottlenecks for enabling exports to Russia. Part of this strategic link has already been funded by a recent EBRD loan. The funding and completion of the remaining sections of the this second link is of great importance to facilitate trade within CAPS and with its external market in Russia making full use of the large thermal plants in northern Kazakhstan for trade. 5.19 To supply power to markets other than Russia, new lines will be needed as shown in Figure 5.3 to complement the existing ones (which themselves need strengthening).

29 This is planned to be carried out in Phase II of the Study.

35

Figure 5. 3: New Transmission Lines Needed For Exports

5.20 Mazar-e-Sharif in Afghanistan, which is linked from Tajikistan and Uzbekistan (as well as Turkmenistan), has the potential to become a key node in northern Afghanistan to enable power transfers between Central Asia and Afghanistan, Iran and Pakistan. The line between Central Asia and Iran via Afghanistan would follow the Central Asia – Mazar-e-Sharif - Herat (in western Afghanistan) route to where Iran is already constructing a 220 kV line from its network. Central Asia to Pakistan lines could follow the Central Asia – Mazar-e-Sharif – Kabul routing and then possibly to Tarbela in Pakistan. Alternatively, it could pass through Khandahar in southern Afghanistan and reach Karachi (via Quetta in western Pakistan). For exports to China, the optimal routing appears to be Almaty to Urumqui in the Xinxiang province. All the proposed new lines are considered to be double circuit 500 kV AC transmission lines with associated substations, with the exception of the Almaty –Urumqui line which would be built as a 500 KV DC line with back to back converters. 5.21 Following a methodology similar to that adopted for generation projects, the economic and financial analyses of the transmission links are undertaken and the transmission cost/kWh in respect of these lines have been arrived at (see Appendix 5.2 for details). The results are summarized in Table 5.5.

36

Table 5. 5: Economic and Financial Analysis of Transmission Options

Line Distance km

Voltage kV

Line type

Annual transm. GWh

Number of new

substations

Number of substations expansion

Investment US$

million

Economic cost of transm. Cents/ kWh

Financial cost of transm.

Cent/kWh

Almaty (Kazakhstan) - Urumqui (China) 1,050 500 DC 10,000 1 1 390.0 0.66 0.72

Surhan (Uzbekistan) - Kabul (Afghanistan) 515 500 AC 5,000 2 1 153.0 0.43 0.51

Kabul (Afghanistan) - Tarbela (Pakistan) 360 500 AC 3,000 1 1 90.5 0.44 0.49

Surhan (Uzbekistan) - Mashad (Iran) 1,150 500 AC 10,000 4 1 320.0 0.53 0.59

Optional Lines

Kabul (Afghanistan) - Kandahar (Afghanistan) 490 500 AC 5,000 2 1 138.2 0.40 0.46

Kandahar (Afghanistan) - Karachi (Pakistan) 900 500 AC 4,000 3 1 226.6 0.84 0.99

Competitiveness of Central Asian Electricity

5.22 The marginal generation costs in the target markets have been compared to the landed costs (generation costs of each envisaged projects in the CARs plus associated transmission costs) and the results are summarized Table 5.6. Sangtuda I in Tajikistan and Talimardjan I in Uzbekistan are likely to be competitive in all markets, where as Rogun I and Talimardjan II would be competitive in Afghanistan, Iran and Pakistan. In Pakistan, Rogun phase II as well as Kambarata II could also be competitive.

Table 5. 6: Marginal Costs of Generation in Target Markets versus Import Costs (cents/kWh)

Target Market Marginal

Generation Cost in Target Market

Supply Options Transmission Cost

Total Landed Cost of Imports

Afghanistan 3.7 Sangtuda I, Rogun I, Talimardjan I and II 0.51 2.26 – 3.43 Iran 3.6 Sangtuda I, Rogun I, Talimardjan I and II 0.54 2.29 – 3.46

Pakistan 5.6 Sangtuda I, Rogun, Talimardjan I and II, Kambarata II 0.51 2.26 – 3.75

China 3.6 Sangtuda I, Talimardjan I 0.72 2.47 – 3.16 Russia 3.0 Sangtuda I, Talimardjan I 0.55 2.30 – 2.99

Key Conclusions

5.23 It would perhaps be useful to recapture the key points from the discussions on demand/supply from the previous chapter, as well as the in-depth analysis of the supply options from this chapter:

i. Annual domestic demand in the Central Asian Republics can be met roughly until about 2020 through the implementation of loss reduction measures, the rehabilitation of existing generation capacity; and complementary measures such as modified irrigation operation of Toktogul reservoir in the Kyrgyz Republic and shifting the demand for space heating in Tajikistan away from electricity.

37

ii. Seasonal supply shortages in the winter will persist. The most cost effective option to meet this shortfall will be to trade at the margin. However, since there is a shortage of capacity in winter, some new generation will be needed to meet winter demand requirements.

iii. The most attractive new generation options to meet the winter demand requirements are

the Talimardjan Thermal Power I Project in Uzbekistan that is largely complete, and the Bishkek II Thermal Power Project in the Kyrgyz Republic, which is partially constructed. The Bishkek II Thermal Power project represents a more cost effective and quicker option to meet the Kyrgyz Republic’s future requirements than the Kambarata hydropower projects in the Kyrgyz Republic. These two thermal power plant projects, however, are both dependent upon the availability of gas in Uzbekistan.

iv. In addition, some upgrading of the transmission facilities will be required to facilitate

intra-regional trade, including the construction of the North South Line in Kazakhstan, and addressing any transmission bottlenecks in the southern part of the Central Asian grid.

v. These additional transmission investments and generation capacity also make sense from

an extra-regional perspective. In addition, the Sangtuda I hydroelectric scheme, which is quite competitive and makes some contribution to meeting winter demand, should also be considered a strategic investment with regional implications.

vi. Increased intra-regional trade will provide significant benefits. In addition to enabling the

CARs to meet their respective demand at least costs. Uzbekistan, for example, can optimize seasonal fuel mix, conserve gas, benefit the environment, and perhaps even qualify for carbon emission credits.

vii. Major new generation projects in Central Asia, such as Rogun and Talimardjan II, will be

feasible only if there is assured access to export markets outside the region. In this regard, electricity from Central Asia has the potential to compete in cost terms with marginal generation costs in each of the targeted markets outside the region. However, the cost advantage is not overwhelming, and may not be sufficient to overcome security of supply concerns.

38

CHAPTER VI: PROFILE OF THE POTENTIAL EXPORT MARKETS

A. Afghanistan

6.01 Infrastructure: Afghanistan has considerable energy resource endowments but uncertainty exists about the extent of the resources. Its fossil fuel resources are thought to comprise: some 30 billion cubic meters of gas reserves, 95 million barrels of oil and condensate reserves; and coal reserves in excess of 100 million tons based on historical geological reserves estimates. However, engineering, costs and market analysis work is needed to improve upon these reserves estimates and evaluate how much of these can be commercially exploited. Afghanistan also has considerable amount of hydroelectric potential. On account of the series of prolonged conflicts, the energy infrastructure of Afghanistan could not grow beyond the level at which it was in the mid 1970s and had in fact considerably deteriorated on account of war damages. As of 2003, its installed electricity generation capacity is reported to be 454 MW, while its operable capacity is believed to be only 285 MW30. There is no national electricity grid, and the system is made up of three isolated systems centered around the cities Kabul, Kandahar and Mazar-e-Sharif. The largest system is the one in Kabul, with installed capacity of 245 MW (200 MW Hydro and 45 MW diesel fired gas turbine). The hydroelectric units have a firm power output of only 65 MW, thus making electricity shortages more acute in winter. 6.02 The Afghan power system is connected to those of its northern neighbors, the Central Asian Republics of Tajikistan, Turkmenistan, and Uzbekistan, as shown in Figure 6.1. There is also a relatively small link (20 kV single current, between Zabol in Iran and Zaranji in Afghanistan) with Iran in the Herat area. In addition, 132 kV double circuit line from Tobat-e-Jam in Iran to Herat (a 150 km distance) is in operation.

Source: Asian Development Bank - Study for Power Interconnection for Regional Trade, March, 2003. Figure 6. 1: Afghanistan’s Cross-Border Electricity Interconnections

30 Electricity Sector Policy, Ministry of Water and Power, Afghanistan, August 2003.

39

6.03 Efforts are underway to strengthen and increase the interconnections, and some of these efforts are more concrete than others. The line between Turkmenistan and Herat was completed with Afghan government funds in May 2004. This line is built at 220 kV, but is currently operated at 110 kV. In addition, ADB will be financing the repair and reconstruction of the Termez (Uzbekistan) to Phul-e-Khumri and this will be a 241 km long two parallel single circuit lines. 6.04 Current Demand : The recently completed Power Sector Master Plan for Afghanistan estimates that the current demand is about 750 GWh and the present peak load is assumed to be 215 MW for all of Afghanistan. There may also be a suppressed demand, which is assumed to be 470 GWh in energy terms and 121 MW peak power needs. 6.05 Consumers and Consumption: A very low level of access to electricity is the most urgent energy issue in Afghanistan. Only 234,000 consumers in the country are connected to the electricity network. More than 202,000 of them were residential consumers. The grid around Kabul caters to about 76,000 consumers. On the whole only about 6% of the population have access to the electricity network. With the lack of generation capacity, even those connected to the grids do not enjoy reliable power, results in a per capita power consumption of only 16 kWh/year31, perhaps the lowest figure in the world. 6.06 System Loss and Collection: Given the damaged state of the transmission and distribution facilities, the transmission and distribution losses were estimated at 25% in 2002. In addition the non-technical losses in the distribution system were estimated at 20%. Thus 45% of the electricity generated is lost and does not get billed. Only about 54% of the value of the bills issued are actually collected. 6.07 Costs of Supply: Different parts of the Afghan power supply system incur varying levels of costs based on sources of power supply (hydro, thermal, imports etc), the density of the population and the extent of coverage of this population. As such, the Kabul area has the lowest costs of supply, (since it has the highest proportion of hydro-based supply, and more than 50% of the customer base is located here) followed by the Balkh, Kunduz and Herat areas. 6.08 Present Imports of Electricity: Afghanistan imports electricity from Iran, Uzbekistan, Tajikistan and Turkmenistan. . The information on current electricity imports is summarized in Table 6.1.

Table 6. 1: Current Electricity Imports by Afghanistan Iran Tajikistan Turkmenistan Uzbekistan

Duration of Contract (years) 4 1 10 1

Maximum Capacity (MW) 2 MW (Nimroz);2MW (Herat)

Winter - 5 MW; Summer - Unlimited

2 MW (Herat); 6 MW (Andkhoy)_ 150

Maximum Energy (million kWh) NA NA 15 million kWh NA

Price (US cents/kWh) 2.25 2 2 2

Source: Afghanistan Ministry of Water and Power .

31 ADB Appraisal Report (No. AFG 36673) on Emergency Infrastructure Rehabilitation and Reconstruction Project, May 2003.

40

6.09 The Protocol of Intentions between Afghanistan and Uzbekistan says that Uzbekistan will provide up to 150 MW for a 10-year period at a cost of 2.0 US cents/kWh for the first year. There are issues of payment by Afghanistan for its power imports – Uzbekistan is owed funds for past supplies. 6.10 Projected Electricity Demand: The recently completed Power Sector Master Plan for Afghanistan also projects the demand for the 2020 period, which is summarized in Table 6.2.

Table 6. 2: Afghanistan – Summary of Energy Demand (GWh) and Peak Load (MW) Forecast

Region Present Load Suppressed Demand Forecast Basis Basic Low High

Demand Peak Load Demand Peak

Load Demand Peak Load Demand Peak

Load Demand Peak Load Demand Peak

Load Kabul 359 111 212 55 571 166 1522 347 1047 239 2133 487 Nangarhar 49 8 9 5 58 13 260 54 176 36 374 78 Parwan 1 2 30 6 31 8 166 38 105 24 248 57 Ghori 28 14 75 12 103 26 358 80 248 55 604 129 Balkh 149 38 52 13 201 51 680 155 432 99 969 221 Herat 1 2 36 8 37 10 325 74 196 45 509 111 Kandahar 141 30 43 12 184 42 431 90 292 61 625 130 Other 22 10 13 10 35 20 126 67 175 92 Total 750 215 470 121 1220 336 3868 905 5637 1305

Source: Power Sector Master Plan for Afghanistan, 2004 6.11 In the Basic Forecast the energy demand is assumed to reach 3,868 GWh in the year 2020. This gives an average annual growth rate of 6.6% from the forecast basis (including suppressed demand) and 9.5% from the present (2002) load. In the High Forecast the energy demand is assumed to reach 5,636 GWh in the year 2020. This is 46% higher than the Basic Forecast and implies an average annual growth rate of 8.9% from the forecast basis (including suppressed demand) and 11.9% from the present (2002) load. 6.12 Institutional and Financial Aspects. Da Afghanistan Brishna Moassesa (DABM) is a state-owned vertically integrated utility that operates all the power facilities in Afghanistan. It is subject to supervision by the Ministry of Water and Power.

Table 6. 3: Current Electricity Tariffs in Afghanistan Kabul Balkh Kunduz Herat

Category Afs/kWh USc/kWh Afs/kWh USc/kWh Afs/kWh USc/kWh Afs/kWh USc/kWh Residential 2.0 4.1 2.5 5.1 4.0 8.2

0-600 kWh/month 0.5 1.0 600-1200 kWh/month 1.6 3.3 Above 1200 kWh/month 2.5 5.1

Government 5.0 10.2 5.5 11.3 5.0 10.2 7.0 14.3 Other Consumers 5.0 10.2 5.5 11.3 5.0 10.2 7.0 14.3 Foreign NGOs etc. 5.0 10.2 6.0 12.3 10.0 20.5 10.0 20.5

Source: Securing Afghanistan’s Future Power Sector Technical Annex, December, 2003

41

6.13 The present tariff structure in Afghanistan is summarized in Table 6.3. Although the posted tariffs appear high compared to the affordability level in Afghanistan, the average bills incurred by the residential consumers tend to be much lower, since most consumers do not get anything more than 600 kWh a month, due to supply shortages. 6.14 Afghanistan’s Emerging Power Supply Strategy: Subsequent to the finalization of ‘Securing Afghanistan’s Future’, the strategic document presented to the Donors in Berlin earlier this year, key elements of a strategy to meet electricity supply needs are beginning to emerge. These elements include, recognition that electricity imports are key to close the supply gap in the short term and imports would continue to play an important role in meeting power demand over time. The focus therefore in the short term is to address the problems of sub-optimal power purchase arrangements with Central Asian neighbors. In the medium to long term, Afghanistan would develop its own generation sources for strategic/developmental reasons, as well as one of energy security; and whether or not imports would constitute a serious option would depend on the availability of long term power priced competitively. 6.15 To sustain imports at least in the short term, Afghanistan has to ensure payments for the imported power, which is a challenge. In this regard, the Afghan authorities are willing to provide the exporting entities additional comfort regarding the payment obligations for power, most likely with support from international financial institutions (IFIs). This could possibly come from the Afghanistan Reconstruction Trust Fund (a multi-donor trust fund administered by the World Bank) although sufficient funds are not currently available. The ARTF is expected to be in place until 2010. Another alternative to consider could be a line of credit and/or guarantee from an IFI backstopping payment obligations. 6.16 Afghanistan as a Transit Country: Afghanistan has the potential to wheel power from the Central Asian Republics to Pakistan and to Iran via Herat, which is an important load center in Afghanistan. However, to be able to realize this potential, significantly more information and indications of serious interest on the part of all concerned would need to be available, and this may take some time

B. China 6.17 Infrastructure: Xingjian province of China has a common border with the Central Asian Republics and could be a potential market for electricity exports. With a population of about 1.3 billion China has the second largest electricity industry in the world. Its total installed generation capacity at the end of 2002 was about 353 GW and total electricity generation in 2002 amounted to 1620 TWh. About 74% of the electricity generation is based mostly on coal and partly on gas. 24% is from hydroelectric stations. About 2% from nuclear power plants. 6.18 Market: More than 95% of the settlements in China are believed to have access to electricity. Industries consume 72% of total electricity, followed by households (12%), Agriculture (5%) and others (11%). 6.19 Demand Growth and Outlook: Though electricity demand growth decelerated during 1994-1998 and the country had excess capacity, the demand growth has accelerated considerably since then and 19 out of the 31 provinces are currently experiencing serious shortages of power

42

supply which is affecting industrial production. Given its rate of GDP growth projections, and its relatively low level of present per capita annual electricity consumption (1,062 kWh), the forecast long term electricity consumption growth rate of 4.5% p.a. through 2020 may yet prove conservative. 6.20 Tariffs: Tariffs differ from province to province and even within a province. Till recently a policy of “new price for new plant” was followed, resulting in a multiplicity of tariffs even within a province. Since 2000, China is moving on to unified tariffs based on average costs of generation, transmission and distribution. After the sector reforms of 2002, the generation tariff is expected to be on the basis of competition and retail tariffs would be a sum of competitive generation costs and regulated network tariffs. This is still in the process of evolution. Overall the level of average tariff at the level of SPC was around 4.5 cents/kWh in 2000. It is believed that tariffs had gone up notably since that time. 6.21 Sector Reform: Since the end of 2002, the Chinese power sector has undergone structural changes. The State Power Corporation has been unbundled into five large generation companies and several transmission and distribution companies to introduce competition in the power sector. A State Electricity Regulatory commission has been set up to regulate network tariffs. 6.22 Export Possibility to Xingjian Province: Xingjian Uyghur Autonomous Region has an area equal to one sixth of the total Chinese territory and has a population of 17.5 million growing at the rate of 1.28% per year. The interconnections among the eight regions of the Chinese power grid are not adequate to transfer fully the surplus of one region to another. Xingjian province is presently in the list of provinces with no special shortages or surplus of power. 6.23 Its installed generation capacity at the end of 2001 was 4,744 MW and its annual power generation is about 19.6 TWh. It experienced recently an annual electricity demand growth at the rate of about 8% compared to its annual GDP growth rate of 7.6%. Since 1993, it is reported to be receiving an annual supply of about 5GWh from the Kyrgyz Republic through a 10 kV line. 6.24 The well known Tarim Basin with significant oil32 and gas reserves lies in this province. A gas pipeline going from this province all the way to the east with a length of 2,600 miles and an estimated cost of $5.2 billion had been committed and the work is ongoing. When finished in 2007, it is expected to carry 12 million cubic meters of natural gas every year to the eastern provinces. The region is also believed to have notable coal reserves too. 6.25 It is reasonable to assume that on account of the oil and gas related activity the electricity demand in the province would continue to grow at about 7 to 8% per year. In that context, the Kyrgyz Republic and Tajikistan could hope to capture a part of this demand for the export of their hydroelectric power. 6.26 In the context of electricity prices in China rising as a result of the tightening of coal supplies and increasing oil and gas costs and in the context of electricity shortages, capture of a part of the Xingjian electricity market by the CARs is a possibility. However, the major growth in demand, and current deficits will be in the population centers on the East coast of China where 32 Potential oil reserve estimates vary from a low of a few billion barrels to 80 billion barrels.

43

transmission distances for supplies from Central Asia become an issue. The Xingjian province at the moment can meet its demand with supplies within the province.

C. Iran33 6.27 With a population of about 66 million (2003) and a per capita GDP of about $1,000, Iran is endowed with an abundance of energy resources. It is believed to have over 8.6% of the world’s oil reserves and 15% of the world’s gas reserves, besides substantial reserves of coal and about 42,000 MW of hydroelectric potential. Nonetheless, it is a potential market for exports of electricity from the Central Asian Power System on account of its summer electricity shortages as well as the isolated nature of the grid adjoining Turkmenistan. 6.28 Sector Structure: The Ministry of Energy is responsible for the energy policy. The operational responsibilities have recently been vested with Tavanir, which appears to be a holding company responsible for generation and transmission with 27 generation subsidiaries, transmission and dispatch subsidiaries. In addition there are 16 Regional Power companies and 39 Distribution companies reporting to the Ministry. There are also 27 companies for support services, 18 subsidiaries for engineering and management consulting services, 6 subsidiaries for training and research, 8 subsidiaries for financing and 27 subsidiaries for contracting for construction etc. reporting either to Tavanir or to the Ministry. 6.29 Infrastructure: The total installed power generation capacity in Iran in 2001 amounted to 34,222 MW, of which 1,998 MW was hydroelectric, and the rest was fossil fuel fired. The thermal plant capacity consisted of oil or gas fired steam turbines (14,402 MW), gas fired combined cycle plants (4,060 MW), open cycle gas turbines (7,038 MW) and diesel fueled generation sets (540 MW). It also included a capacity of 6,190 MW not owned by government electricity agencies. About 70% of the thermal capacity was gas fired. The peak demand of the system was 21,790 MW in 2001 and annual electricity generation amounted to 130,083 GWh of which only 5,077 GWh was from hydroelectric units. A nuclear power plant with a capacity of 1000 MW had been under construction at Bushehr for a long number of years with Russian assistance and was expected to be completed in the first half of 2004. 6.30 The power system consists of three major networks: (a) the Interconnected Network, which serves all of Iran except for remote eastern and southern areas, using 440-kV and 230-kV transmission lines; (b) the Khorassan Network, which serves the eastern Khorossan province; and (c) the Sistan and Baluchistan Network, which serves the remote southeastern provinces of Sistan and Baluchistan. The government goal is to join these three networks into one national grid. Currently, these three grids cover 43,000 villages and around 94% of Iranians are connected to the power grids. The transmission system consisted of 10,079 km of 400 kV lines, 20,444 km of 220 kV lines, 13,210 km of 132 kV lines and 30,264 km of 66kV lines. Iran also has power links to neighboring countries, including Azerbaijan, Turkmenistan (started August 2002), and Turkey.

33 Most of the information in this section is taken from the Iran Energy Environment Review Report prepared for the Bank in 2003. An exchange rate of 8000 Rials to a dollar had been adopted.

44

6.31 System Loss: The overall electricity system losses in 2001 amounted to 21.3% consisting of auxiliary consumption of generating units (4.7%), transmission losses (3.7%) and distribution losses (12.9%). The distribution losses include an undetermined share of non-technical losses. 6.32 Power Market: There were over 16 million consumers in the country and the total sales of electricity to them amounted to 97,171 GWh in 2001. The residential consumers had a share of 33.8% of the total sales, followed by industrial consumers (31.4%), commercial consumers (18.9%), agricultural consumers (11.4%) and others (4.5%). The seasonal variations in the Iranian power system is characterized by high demands during June-October driven by air-conditioning loads and relatively lower demands during November-May. The demand is highest in August and lowest in April as can be seen from the following Figure 6.2.

Total Needs for 2001 126,902 GWh

Figure 6. 2: Seasonal Load Curve in Iran in 2001

6.33 Recent estimates are that the annual shortage in the Iranian system is about 6 billion kWh and most of this shortage arises during summer. 6.34 Demand Outlook: Electricity consumption during 1990-2000 grew at the average annual rate of 7.7%. A peak demand of 40,000 MW and an energy generation of 239 TWh are forecast for 2010. The installed capacity is planned to be tripled by 2020 to about 96,000. While the underlying demand projections appear somewhat optimistic and may need to be moderated on the basis of gradual reduction of price subsidies, the population growth and the scope for increases in specific consumption in the context of anticipated economic growth would prove to be a significant driver of the demand. The planned addition of 12,800 MW capacity during the Third Five Year Plan period (1999-2004) is reported to be lagging behind the target. The overall strategy is to add as much economic hydro generation capacity as possible and meet the remaining demand by gas fired combined cycle units and open cycle gas turbines. While fuel sources are available, financing for the new capacity is proving to be a major constraint. Invitations to private investors on a build, operate, and own (BOO) basis did not elicit much

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

GWh

45

response. In November 2003 the first agreement for a 2000 MW open cycle gas turbine plant near Tehran on a build, operate and transfer (BOT) basis was signed. 6.35 Electricity Trade: Electricity trade with adjoining systems would be used to even out seasonal capacity and energy shortages. It will also come in handy in the context of financing constraints to add new capacity. Iran exchanges power with Armenia and Azerbaijan and also exports power to Turkey. It may be seen from the following Figure 6.3 that its imports are rising during 1998-2001.

Figure 6. 3: Power Exports and Imports of Iran 6.36 Electricity from the Central Asian Power System could reach Iran in the Mashad area in the eastern province of Khorassan via Turkmenistan or via Afghanistan. Iran has entered into a 10-year power import contract with Tajikistan since mid-2002. Tajikistan’s exports would be during the summer months, and the purchaser on the Iranian side is a corporate entity (as opposed to the national utility). The electricity transmission would occur via the existing lines from Tajikistan (Regar) through Uzbekistan (Guzar and Karakul) and Turkmenistan (Mari). 6.37 Electricity Prices: Electricity prices in Iran lag behind supply costs. In 2000, the overall average electricity tariff was 88.5 Rials per kWh or 1.11 cents compared to an estimated supply cost of 195 Rials or 2.4 cents. The industrial tariff, at 121 Rials (1.51 cents) was subsidizing the residential tariff at 65.1 Rials (0.81 cents). Tariffs vary from province to province. The tariff prevailing in the Tehran area was as follows: Residential tariffs per kWh ranged from Rials 64 or 0.8 cents (for consumption below 300 kWh) to 559 Rials or 7.0 cents (for monthly consumption above 600 kWh). Industrial consumers paid a capacity cost of 108,000 Rials or $13.5 per kW per year and an energy cost of 102 Rials or 1.3 cents per kWh. Commercial consumers paid the same level of capacity cost, but an energy cost of 183 Rials or 2.3 Cents per kWh.

82

195 196

157

384

526

630

1104

1023

1116

153

321

802

306

0

200

400

600

800

1000

1200

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Export Import

46

6.38 Marginal Electricity Costs in the Iranian System: The least cost method of meeting incremental demand in the Iranian system is to add combined cycle gas turbines fuelled by natural gas. Based on a natural gas price of $ 1.5 /million BTU, and a capital cost of $700/kW for the combined cycle plant, the avoided cost/kWh at the generation level amounts to 3.56 cents.34 6.39 Iran appears to be considering electricity imports from Central Asia for several reasons. First, high rates of growth in electricity demand and the continued financing constraints to build the needed capacity in time to meet the demand is more than likely to result in the demand/supply gap widening if Iran remains solely dependant on indigenous supply. Second, the lack of a unified grid in the country will also hamper the ability to generate power where the necessary resources (e.g., gas and hydro) are available, and importing from neighbors (e.g., as is happening in the Mashad province) is often more economic. Third, entering into electricity trade relationships serves Iran’s foreign policy agenda (as is happening in Armenia, Azerbaijan and Turkey) and would serve commercial interests as well – Iran has offered to help Tajikistan build the Sangtuda I hydro-power scheme, and given that Iran would have spare capacity (in the medium term) in the winter, can even export to its neighbors.

D. Pakistan

6.40 Pakistan has an area of nearly 800,000 square kilometers, a population of 148 million (35% of them living below poverty line) and a per capita GNP of $470 (2003). It has oil reserves of 310 million barrels, gas reserves of 750 BCM, coal reserves of 2.5 billion tons and 27,000 MW of hydroelectric potential. It has a large and extensive power sector with reasonable economies of scale. Despite its large generating capacity (19.5 GW) and consumer base (14.5 million consumers), nearly 40% of the population has no access to electricity. The annual per capita electricity consumption remains low at around 320 kWh. 6.41 Infrastructure: Pakistan’s installed power generation capacity at the end of 2003 was 19,478 MW of which 65% was thermal, 33% hydroelectric and 2.4% nuclear. The thermal plants were fueled mostly by oil and natural gas. A large hydropower project (Ghazi Barotha) with 1,450 MW was commissioned in 2002-2003. The electricity generated in the fiscal year 2002-2003 (the fiscal year ends on 30 June in Pakistan) amounted to 73,961 GWh. 6.42 Market: The total number of consumers exceeded 14.5 million. Over 11 million of them were residential consumers. The share of the residential consumption in total sales was the largest at 46.7%, followed by industrial consumers (29.5%), agricultural consumers (10%), commercial consumers (5.8%) and others (8%). The system experienced some excess generation capacity during the last few years. Still power outages could not be avoided owing to transmission and distribution bottlenecks. 6.43 System Loss and Collection Efficiency: Auxiliary consumption of generation units and transmission and distribution losses were estimated at around 30%. A significant part of this is

34 The underlying assumptions for this computation are: (a) plant capacity of 300 MW; (b) Capital cost financed by 30% equity and 70% debt; (c) Return on equity of 15% and debt with a maturity of 20 years and an interest rate of 6% p.a; (d) Plant load factor of 70%; and (e) O&M Expenses of 1 c/kWh. The resulting per kWh avoided cost consists of: (a) 1.35 cents of fuel cost, (b) 1.21 cents of capacity cost, and (c) 1.0 cent of O&M cost.

47

attributed to power theft. Collection problems are also severe and the two major utilities have accounts receivables valued in excess of several months sales. 6.44 Sector Structure and Institutions: The power wing of the Water and Power Development Authority (WAPDA) of Pakistan owns and operates 5009 MW of hydroelectric capacity and 5040 MW of thermal capacity. It also handles transmission and distribution in the entire country except the area around Karachi, which is handled by Karachi Electric supply Corporation (KESC). This corporation handles 1948 MW of thermal generation capacity as well as transmission and distribution in the Karachi area. Pakistan Atomic Energy Authority owns and operates two nuclear power plants with a total capacity of 462 MW. A large number of private independent power producers owned and operated 5,959 MW of thermal capacity and supplied power to WAPDA on the basis of government guaranteed and take or pay based power sales contracts. Distribution is organized in the form 8 Area Boards. 6.45 Sector Reform: Since 1997 the government has set up an autonomous regulatory body, the National Electric Power Regulatory Authority, to regulate sector tariffs. WAPDA’s power wing has been separated and corporatized as the Pakistan Electric Power Corporation. The hydro assets would continue to be in the public sector. It has been further unbundled into 3 generation companies, one transmission and load dispatch company and 8 distribution companies. The generation and distribution companies are to be privatized and competition is to be introduced in stages on the basis of regulated transmission access to all generators, distributors and perhaps the large industrial consumers. The 1,600 MW thermal power plant of WAPDA at Kot Addu was privatized to a strategic investor, who purchased 36% of the shares and secured management control. KESC is being privatized as a vertically integrated utility through the sale of government shares.

6.46 Tariffs: The average retail electricity tariff in Pakistan in FY 2001-2002 was Rs 3.22/kWh or around 6 cents/kWh, compared to long run marginal cost estimates of about 7.3 to 7.4 cents/kWh. The price at which WAPDA buys power from IPPs, presently around 5.6 cents/kWh is a good proxy for marginal supply cost at the generation level. 6.47 Demand Outlook: During the 10 year period FY 1992-93 to FY 2002-03, demand grew at an average annual rate of 3.7%. The growth level was relatively modest as a result of the economic downturn and periodic political unrests experienced during a good part of the period. For the period 2000-2010, forecasts based on moderate GDP growth rates and peaceful conditions seem to indicate an average annual electricity demand growth rate of about 6%. These forecasts further indicate that notable capacity and energy shortages would appear in 2005-06 and that capacity shortages could grow from 411 MW in that year to about 5,500 MW by 2009-2010.

48

Table 6.4: Pakistan Electricity and Peak Demand Projections Year Demand TWh T&D Losses

% Auxiliary % Generation TWh Peak Demand MW

2002 51 28.1% 4.0% 72 12334

2003 54 25.3% 4.0% 77 13096

2004 58 24.6% 4.0% 82 13895

2005 63 23.9% 4.0% 87 14741

2006 67 23.3% 4.0% 93 15640

2007 72 22.6% 4.0% 99 16593

2008 78 22.0% 4.0% 105 17604

Growth Rate during 2002-08 7.4% 6.4% 6.1%

2009 83 21.1% 4.0% 111 18682

2010 89 20.3% 4.0% 118 19826

2011 96 19.5% 4.0% 125 21039

2012 103 18.7% 4.0% 133 22327

2013 110 18.0% 4.0% 141 23694

Growth Rate during 2008-13 7.2% 6.1% 6.1%

2014 118 18.0% 4.0% 152 25446

2015 127 18.0% 4.0% 163 27328

2016 136 18.0% 4.0% 175 29349

2017 146 18.0% 4.0% 188 31520

2018 157 18.0% 4.0% 202 33851

Growth Rate during 2013-18 7.4% 7.4% 7.4%

2019 168 18.0% 4.0% 216 35184

2020 180 18.0% 4.0% 230 38679

2021 192 18.0% 4.0% 246 41345

2022 205 18.0% 4.0% 263 44195

2023 220 18.0% 4.0% 281 47242

Growth Rate during 2018-23 6.9% 6.9% 6.9%

Source: Government of Pakistan – Pakistan Atomic Energy Commission 6.48 Longer terms forecasts to the year 2023 have also been prepared for the Private Power Implementation Board (PPIB) of the Government of Pakistan, the results of which are summarized in Table 6.4. These forecasts show that demand for Grid based electricity will grow from 51 TWh to 220 TWh, i.e., at an annual average rate of 7.2%; and peak demand will increase from 12,344 MW in 2002 to 47,242 MW, amounting to an annual average growth rate of 6.6%. 6.49 The policy makers in Pakistan are fully aware that the indigenous energy resource base is insufficient to meet such demand over the medium and long term. Accordingly, they recognize that imports of energy would have to increase, and they are considering import of electricity from the Central Asian republics via Afghanistan as an option to meet their demand. The Government of Pakistan has requested the Bank to play a lead role to help them to analyze such options (among others) as the regional electricity trade with Central Asia.

49

E. Russia 6.50 Russian power system, one of the largest in the world, adjoins the Central Asian Power System and represents a market with significant potential. The recently funded and ongoing construction of the second 500 kV north-south line in Kazakhstan would greatly enhance the power transfer capability between the Russian system and CAPS. 6.51 Infrastructure: Russia is endowed with enormous energy resources such as oil reserves exceeding 60 billion barrels, gas reserves exceeding 47,000 BCM, coal reserves exceeding 157 billion tons and vast hydroelectric potential. Its installed power generating capacity at the end of 2002 was about 215 GW comprising 147 GW of thermal power plants fired by gas, oil or coal, 45 GW of hydroelectric capacity and 23 GW of nuclear power capacity. The total electricity generated in 2002 was about 890 TWh of which 584 TWh or about 65.5% was from thermal plants, 164 TWh or 18.5% was from hydroelectric units, and 142 TWh or 16% was from nuclear power plants. The power system had about 2.6 million km of high voltage and extra high voltage lines. Electricity demand, which declined from 1990 to 1998, resumed growth in 1999. The system is believed to have an excess capacity over demand of about 20% to 25%, but because of transmission bottlenecks in the vast system spread over several time zones, the actual system reserves tended to be around 10% to 15%. 6.52 Present Sector Structure: The Russian government owns 52.6% of the shares of RAO UES. About 35% of the shares are held by foreign and domestic institutional investors and the rest by individual shareholders. RAO UES owns the national power grid and national load dispatch facilities, as well as most of the large thermal and hydro plants. It also owns varying percentages of shares (on average 49%) in the 72 Regional Power companies called Energos, which are vertically integrated power utilities serving the regions with their own generation, transmission and distribution facilities. Though the remaining shares in the 72 Energos are held by other institutional and individual investors, RAO UES (as the holder of the largest block of shares) has full management control over the Energos. RAO UES, its generation, transmission and load dispatch subsidiaries as well as the 72 Energos are collectively referred to as RAO UES Holding. This holding company has 72.5% of generation capacity and 96.1% of the transmission facilities and accounts for 70% of the electricity generation in Russia. Nine of the 11 nuclear plants are owned by Rosenergatom, a 100% state-owned nuclear power company and the two remaining units are directly owned by the Ministry of Nuclear Energy. 6.53 Market: RAO UES operates the wholesale electricity market called FOREM, in which the sellers are the large hydro and thermal power plants owned by RAO UES and others, the nuclear plants owned by Rosenergatom and the Ministry, as well as four regional Energos which have surplus electricity to sell. Eight other Energos use the FOREM for energy exchanges through sales and purchases. The other buyers in the FOREM are 59 regional Energos which have demands in excess of their own capacities and large industrial consumers. Regional Energos handle retail sales to end consumers within their region. In 2002, the volume of electricity passing through the wholesale market amounted to about 299 TWh or about 38% of the total electricity supply in the country of 790 TWh.

50

6.54 In the total retail sales (of 580 TWh) by the regional Energos, industries had a share of 48.9% followed by households, housing and communal services (22%), transport and telecommunications (11.5%), agriculture (3.4%), and others (14.2%). 6.55 Tariffs: Generation tariffs for the power plants owned by RAO UES or by the state supplying to the FOREM, as well as the transmission tariff for the national grid are regulated by the Federal Tariff Service (FTS). Retail tariffs for end consumers in the regions are regulated by Regional Energy Commissions which are administratively controlled by regional governments, but are guided by the relevant federal laws and guidelines issued by the FTS. 6.56 Electricity tariffs in Russia vary from region to region and had been rising in the last few years at a rate faster than the rise in the prices of industrial goods. Nonetheless the level of tariff is not adequate to cover full supply costs and subsidies to households, agriculture and state financed organizations persist. The average tariff for households after taking into account the price discounts mandated to different privileged classes of consumers amounted in 2002 to 48.77 kopecks/kWh or 1.63 cents/kWh. The tariff for large industrial consumers averaged at 64.85 kopecks/kWh or 2.16 cents/kWh. The overall average tariff/kWh for the 13 major Energos ranged from 34.5 kopecks to 80.2 kopecks. 6.57 Information from Energy Regulators’ Regional Association (ERRA) indicates that in Russia the electricity tariff per kWh at the producer level in the first quarter of 2003 was 1.45 cents. In the same quarter the clearing price in the wholesale market (FOREM) was 1.67 cents and the average end user price amounted to 2.78 cents. In terms of the Energy Strategy adopted by the government, the average end user price is expected to rise to 4.0 to 4.5 cents per kWh by 2020 corresponding to a generation level tariff of about 2.0 cents. Considering the marginal cost of generation in Russia estimated at 3.0, the question remains whether the projected end-user tariffs need to be increased more than envisaged. 6.58 Losses and Collection: Collection problems in the Russian power sector have largely been overcome. Collections ran at around 102% of bills for current consumption implying that some of the arrears are also being collected. Most of the collections are in the form of cash and the problem of barter and offset payments has been largely eliminated. RAO UES is implementing a comprehensive and result oriented Cost Management Program in which reduction of network losses and theft of power and improved metering and billing figure prominently. 15% of the total cost saving in 2002 of RUR 14.5 billion ($483 million) is attributed to network loss reduction efforts. 6.59 Sector Reforms: Russian power sector is in the process of being restructured to enable competition in the “generation” and “supply”35 segments and continuation of regulation of network services. This process is expected to be implemented first in the “European” part of Russia, and with suitable time lags in the Siberian and Far East regions. This process would also involve the eventual disappearance of RAO UES, as the separate Federal Grid Company, Energos, and generation companies become independent companies as part of Russia’s emerging competitive power market. 35 Distribution function would be unbundled into network services and supply services. The latter will be driven by competition and the former will function on the basis of regulated prices.

51

6.60 Power Sector Outlook: Till now the demand growth in Russia had been moderate and a situation of excess capacity prevailed. However many large units (including many nuclear units) are reaching retirement age and demand growth has resumed and is expected to grow at an average annual rate of 2.54% through 2020. The present tariffs do not leave adequate internally generated cash to finance the new investments in generation and transmission, which are expected to become necessary in the relatively near future. RAO UES is revaluing its assets in order to have a realistic depreciation expense component in the tariff. It also promoting the concept of tariffs being driven by investment needs. Based on these considerations the average sale price in the wholesale market could go up significantly in the next five to six years.

6.61 Electricity Trade: Export of electricity is viewed as a priority by RAO UES as providing one of the sources of funds for investment. In 2002, RAO UES exported a total of 16.7 TWh of which 7.4 TWh went to former Soviet Union countries such as Azerbaijan, Belarus, Georgia, Kazakhstan, Moldova, and Ukraine. The remaining 9.3 TWh went to China, Latvia, Mongolia, Norway, Poland, Estonia, Turkey and Finland. The largest volume of export went to Finland (7.5 TWh). In terms of export receipts the first group of countries provided $117.46 million while the second group provided $175.30 million. The company aims to maximize its exports to west European destinations with higher electricity prices, and also get involved in retail sales in the importing markets to maximize export receipts. A recent forecast estimates that exports might grow to the level of 40 TWh by 2020. A new subsidiary “RAO UES Inter” had been formed to look after and manage exports. This company in turn sets up local subsidiaries in export markets to handle retail sales. 6.62 Strategies and Prospects: Russia seeks the Nordic markets through Baltic ring arrangements (known as Baltrel) and markets in Turkey through Georgia, and markets in Moldova, Romania and the Balkans (constituting the so called second UCTE systems) through Ukraine. It also has long term interests in supplying profitable markets in China, South Korea and Japan making use of the large hydro resources in the Far East Russian regions. It also aspires to synchronize its grid with West European systems in the not too distant future. In pursuit of its aims RAO UES has been acquiring generation and distribution assets in Georgia, Ukraine, and Kazakhstan. RAO UES Inter is also eyeing the possibility of importing inexpensive hydropower from CAPS, partly to balance the regional systems like Omsk and partly to augment its pool of exportable surplus. Acquisition of the generation assets at Ekibastuz in Kazakhstan, offers to buy summer power from the Kyrgyz Republic and Tajikistan, and offers of help to construct Kambarata and Rogun hydro power projects may all be part of this strategy. Operation of CAPS in synchronism with the Russian system and the new 500 kV line in Kazakhstan should greatly enhance the export possibilities of power from CAPS to Russia. It will however be driven by the competitive nature of the cost of power from CAPS. If Russia succeeds in exporting its electricity to the UCTE countries at prices around 4.0 cents/kWh then it would provide a rationale for import of power from CAPS at prices higher than its own cost of generation. Russia’s recent ratification of the Kyoto Protocol may also be a reason for Russia to be looking at importing hydroelectricity from the CARs.

52

CHAPTER VII: INSTITUTIONAL ISSUES

7.01 Realization of the export potential of the CARs calls for tackling at least three groups of significant institutional issues. The first group of issues (the Water and Energy Nexus Issues) relate to the institutional arrangements necessary to operate the existing and proposed large multipurpose reservoirs and the associated hydropower facilities in a manner acceptable to all riparian states and for the optimal benefits of entire river basins. The second group of issues (Power System Operation Issues) relate to the need to reform and operate the power systems of the CARs to maximize electricity trade within CARs and with external electricity markets. The third group of issues (Investment Issues) relate to the organization and financing of the legal corporate entities to raise financial resources, construct, own and operate the new large hydro and thermal projects and market the electricity generated. Given the existing and anticipated dominant role for hydroelectric power in these systems, these three groups of issues are inseparably intertwined and call for a coherent resolution. Since a coherent resolution of these issues is indeed the objective of the proposed Water Energy Consortium under CACO, the last section discusses proposals for WEC’s structure, roles and functions.

A. Water and Energy Nexus Related Issues

7.02 The large hydropower projects are to be built on international rivers and the construction of these projects would have significant and profound implications to the riparian states downstream. The need for securing agreements for water sharing and the regime of reservoir operation among all relevant riparian states is paramount, since without such agreements, security of the assets and projected revenues would be seriously compromised and it would not be possible to raise the resources needed for the investments. 7.03 Meaningful regional cooperation in the energy and water sectors is a major issue in the CARs. Under Soviet rule, they could operate multi-purpose reservoirs such as Toktogul in the irrigation mode for the benefit of irrigation in the downstream regions. The consequent electricity deficits in the upstream regions during winter were met by the synchronized integrated operation of the Central Asian Power System (CAPS) and by internal reallocation of fossil fuel supplies among the regions. Once CARs became independent states, these arrangements broke down and the subsequent efforts to restore some order encountered difficulties36. Solutions lie in operating the reservoirs for the maximum net benefit of the transboundary river basin, and would require a combination of updated agreements and key investments, as discussed in Chapter II (paragraphs 2.05 to 2.07).

B. Power System Operation Related Issues

7.04 During the Soviet era CAPS was optimized and operated as an integrated system. After independence, though the constituent power systems operate synchronously, they function more like inter-connected systems, rather than as integrated systems. The analyses in this Report has

36 Discussions of these efforts, the difficulties encountered and proposed solutions have been dealt with extensively in the Water Energy Nexus in Central Asia Report of the World Bank.

53

shown that it would be necessary to engage in seasonal trade to make full use of the existing generation capacities; and that the proposed large thermal and hydro capacity additions can only be justified for trade with external electricity systems. Institutional reforms are necessary for facilitating such expanded trade in order to realize the export potential. The necessary and desirable elements of such reform are presented below.

• It would be necessary:

To ensure non-discriminatory third party access to the transmission system on the basis of transparently regulated and fair transmission tariffs.

To operate the transmission systems to meet both national and regional needs. To form a regional association composed of the national transmission and dispatch

operators (which are expected to remain in the public sector) underpinned by the necessary agreements, to achieve the above two steps. Such association would enable, without having to change ownership structures, the smooth regional operation37 of the transmission grids; and identification of the needed reinforcements and new transmission links (to relieve congestion and enable smooth regional and extra regional trade). Europe’s Union of Coordination of Transmission of Electricity (UCTE) provides a good model on which such an association can be based.

• While the above are necessary steps, it would also be desirable to:

Separate the transmission and load dispatch functions from the rest of the utility

operations (such as generation and distribution) into independent corporate entity for transmission and dispatch, since these transmission system operators (TSOs) would support trade more naturally than vertically integrated utilities.

Implement the 1999 decision to create an integrated electricity market in the CARs and a power pool mechanism to facilitate the operation of the pool38 and convert Energia into the Pool operator. This would eventually enable the creation of a competitive electricity market at the regional level39.

Create competent and independent regulatory bodies in each country whose mandate would include ensuring that electricity is being sourced from the cheapest source in the region. In addition, these national regulatory bodies could form a Regional Council of Regulatory Bodies and this Regional Council could encourage agreement upon regional matters such as the regional grid code, transmission tariffs for trade etc.

Some of the desirable actions (separation of TSOs, separate regulatory bodies) have been realized in Kazakhstan and the Kyrgyz Republic.

37 Transparency is the key need for smooth operation 38 Initially, dispatch would follow mostly bilateral contracts and the pool would essentially be a balancing pool. 39 This is the level at which competition would make sense, since some of the markets, for example the Kyrgyz Republic and Tajikistan, are (i) too small and (ii) have single dimension large assets to enable national level competitive electricity markets.

54

C. Investment and Related Institutional Issues

7.05 The investment needs being considered in all the countries for rehabilitation of existing plants and networks are summarized in Table 7.1. As can be seen, the size of the proposed investments are large - the realization of all the projects identified, including rehabilitation of transmission and distribution and new projects need about US$13 billion in real terms over the next 20 years.

Table 7. 1: Summary of the Central Asia Countries Investment Plans

(in constant US$ million) Investment Project 2004-2005 2006-2010 2011-2015 2016-2020 2021-2025 2004-2025

Kazakhstan Transmission and Distribution 324.0 972.1 0.0 0.0 0.0 1296.1 Generation - Ekibastuz GRES-1 Rehabilitation 0.0 308.0 132.0 0.0 0.0 440.0 Generation - Other Kazakh Large and Medium Units Rehabilitation 0.0 395.9 460.1 214.0 0.0 1070.0 New Generation Units 0.0 0.0 0.0 922.3 162.8 1085.0

Kazakhstan Total 324.0 1676.0 592.1 1136.3 162.8 3891.1 The Kyrgyz Republic Transmission and Distribution 50.0 200.0 0.0 0.0 0.0 250.0 Generation - Bishkek CHP 2 0.0 196.0 0.0 0.0 0.0 196.0 Generation - Kambarata 1 HPP 0.0 0.0 1067.0 873.0 0.0 1940.0 Generation Kambarata 2 HPP 0.0 140.0 140.0 0.0 0.0 280.0

The Kyrgyz Republic Total 50.0 536.0 1207.0 873.0 0.0 2666.0 Tajikistan Transmission and Distribution 25.0 285.0 0.0 0.0 0.0 310.0 Generation - Sangtuda I HPP 0.0 296.0 74.0 0.0 0.0 370.0

Generation - Rogun HPP, Phase I and II 0.0 0.0 1453.0 1002.0 0.0 2455.0

Tajikistan Total 25.0 581.0 1527.0 1002.0 0.0 3135.0 Uzbekistan Transmission and Distribution 172.9 691.8 288.2 0.0 0.0 1153.0 Generation - Talimardjan TPP 100.0 480.0 720.0 0.0 0.0 1300.0

Generation - Rehabilitation of the existing TPPs. 87.0 522.0 246.8 80.7 213.5 1150.0

Uzbekistan Total 359.9 1693.8 1255.0 80.7 213.5 3603.0 Total Central Asia 759.0 4486.8 4581.1 3091.9 376.3 13295.1

The prioritization of the investments needs for the countries should be:

• Focus on loss reduction first, followed by generation rehabilitation. • Undertake, in parallel, electricity trade using existing surpluses both within and

outside Central Asia. In this regard, Russia becoming a serious importer of hydro electricity from Kyrgyz and Tajikistan will require the completion of the North-South line in Kazakhstan.

• Then consider implementing the new projects, beginning with the smaller ones and those that do not need riparian agreement. This would include Talimardjan in Uzbekistan, Bishkek II in the Kyrgyz Republic, and Sangtuda I in Tajikistan. Uzbekistan is likely to complete Talimardjan I on its own, and the recent commitments of Iran (US$150 million) and Russia (US$50 million) towards

55

constructing Sangtuda I have significantly enhanced the chances of realization of this project.

D. Proposals for the Formation of a Water and Energy Consortium

7.06 The recent formation of the high-level CACO and its focus on regional cooperation in the water and energy sectors through the establishment of a Water and Energy Consortium (WEC) seems to be an auspicious start to enable the operation of existing reservoirs to derive optimal benefit for all riparian states, and facilitate the construction and operation new multipurpose reservoirs. Kazakhstan, which has been nominated by CACO to take the lead in the energy and water sectors, has set up a technical experts working group with representation from all member countries, and this working group has prepared a Protocol on the ‘Conceptual Approaches to the Formation of a Water Energy Consortium’ (Appendix 7.1). This Protocol envisages the organization of the WEC as a corporate entity. Further, all four member countries would have equal voting rights and decisions would be made only on the basis of full consensus. The main objectives of the WEC would be to: (a) ensure optimal operation of reservoirs in accordance with the Water Sharing and Reservoir Operation Agreements; (b) enable the mobilization of investments for rehabilitation of existing assets and for new construction of both water and hydropower facilities; and (c) create the conditions for coordination of hydro and thermal power generation and for expanding electricity export. It also envisages the establishment of regional task forces to develop these concepts further and to seek the help of international financial institutions to obtain advisory, technical and financial assistance for establishment of the WEC and for the preparation of feasibility reports for the new investment projects. Criteria for Evolving the Institutional Structure of WEC 7.07 However considering the complexity of the tasks (with political, economic and commercial dimensions) to be handled by WEC a more nuanced and a specialized set of institutional arrangements would appear to be called for. While corporate entities would be appropriate for the commercial tasks of raising financial resources, rehabilitating the existing assets, constructing, owning and operating new assets, and domestic and export sales, other forms of organization have to be considered. The political economy dimension needs to be addressed by concluding Water Sharing Agreements and Reservoir Operation and Water Release Agreements among the riparian member states, and effective multilateral monitoring and enforcement of these agreements needs to be arranged. Institutions with equal voting rights and consensus based decisions would be appropriate for the latter set of tasks, while they would be impractical and ineffective for commercial tasks. Further, the envisaged arrangements should look at the possibility of avoiding the creation of ‘yet another new’ institution and make the best use of existing institutions by absorbing them where possible, or reshaping them to serve the desire objectives. The institutional political and economic framework needs to incorporate flexibility, such as allowing for changing basin priorities, incorporating public input, and applying new information and monitoring techniques and technologies. Examples of changing basin priorities would include recognition of secular increases in the level of annual water inflows in the basin and tailoring sustainable and reliable solutions to meet the power requirements of upstream countries in the region (especially during the winter) and addressing the environmental priorities (of Kazakhstan) that more and more of Syr Darya water should

56

reach the Aral Sea. Finally the institutional framework should enable national structures to participate effectively in international/regional efforts and serve the regional objectives. Existing Institutions and Their Limitations 7.08 In the water sector, the need for a mechanism for regional water resource management was recognized very early after independence and an Interstate Commission for Water Coordination (ICWC), was established through an agreement reached in February 1992. The main functions of ICWC, as defined in its founding charter, are to: (a) determine water management policy for the region, as well as the limits on water consumption annually in the Basin for each republic and for the region as a whole; (b) allocate available water resources for various purposes, including the need for water to reach the Aral Sea and schedule water reservoir operations accordingly; (c) determine the future program for water supply and measures to implement the program; and (d) coordinate construction of major works. 7.09 The ICWC comprises officials (generally Ministers or Deputy Ministers) from the Ministries of Water and Water Resources Agencies of all the member countries. ICWC’s decision making is based on the proposals formulated and analyzed by its secretariat located in Khodjent. Allocation of water and monitoring water flows are the responsibilities of the basin water management organizations, called BVOs, one each for the Syr Darya and Amu Darya basins. Scientific and information support at the interstate level is provided by the Scientific Information Center (SIC) of the ICWC. 7.10 In the electricity sector, the Central Asian Power Council (CAPC), comprising representatives from the electricity or grid companies of the CARs, has been established and this Council formulates quarterly power exchange schedules. There are also a number of multilateral and trilateral agreements between the upstream states (the Kyrgyz Republic and Tajikistan) and downstream states (Kazakhstan and Uzbekistan), which regulate the water and energy flows and set out a framework for mutual obligations and benefits. The Unified Dispatch Center, Energia, in Tashkent is responsible for maintaining the balanced and synchronized operation of the power transmission and distribution system. Energia’s Dispatch Service performs the task of translating the quarterly power exchange schedules into daily schedules for generation unit commitment. Energia’s Energy Regime Service attempts to balance irrigation and hydropower requirements, which is the most controversial issue in the region. Energia also has the responsibility for ensuring overall system security and for frequency regulation. 7.11 Limitations. ICWC is purely a water-focused body with no representation from the energy or environment sectors; this narrow focus has proven to be a major handicap in a system in which water and energy interests are intertwined. The BVOs and the Energia lack an international character, consist almost exclusively of staff and officers of the host nation and do not give the impression of functioning impartially among the constituent member countries. Their expenses as well as the expenses of the Secretariat of ICWC are met by the host nation only. Neither ICWC nor the BVOs and Energia have any power or mechanism to enforce the implementation of the Agreements.

57

A Five-Tiered Structure for WEC 7.12 Under these circumstances it would perhaps be appropriate to consider a five- tiered institutional framework for the water and energy related issues. As shown in Figure 7.1, at the apex, there would be the Council of the Heads of State (of CACO) to provide the overall vision of regional cooperation, identify the specific areas of cooperation, the extent of such cooperation and lay down the basic governing principles. At the second level there would be the Council on Water and Energy Consortium consisting of Prime Ministers or Deputy Prime Ministers to decide on policy issues. At the third level there would be Supervisory Board for the WEC, comprising the Ministers of Water and Energy. At the fourth level would be the Executive Directorate of the WEC with departments for Water and Energy. At the fifth level there would be the corporate legal entities carrying out generation (including reservoir operation), transmission, and load dispatch. New hydro projects would be constructed and operated by similar corporate legal entities in accordance with the Agreements among the riparian states concerning water sharing and reservoir operation regimes.

INTERIMCG MEETING

CopenhagenApril 29, 2002

INTERIMCG MEETING

CopenhagenApril 29, 2002

IFAS

ICWC, ICSD, & CAEC

EXECUTIVE DIRECTOR

WATER WING DIRECTOR AND 2 PROFESSIONALS

ENERGY AND ENVIRONMENT WING

DIRECTOR

CACO

PRIME MINISTERS / DEPUTY PMs

GENERAL SERVICES WING DIRECTOR

National Dispatch National Transmission Companies

Association of CA Transmission Systems Reservoirs

ASSOCIATION OF ENERGY REGULATORY AUTHORITIES

Individual Power Plants (jointly developed or on Transboundary rivers)

HEADS OF STATE

CENTRAL ASIAN WATER ENERGY ENVIRONMENT CONSORTIUM (CAWEC) COUNCIL

CAWEC - SUPERVISORY BOARD

MINISTERS OF ENERGY, WATER

(Operator of the "pool" at the regional level)

UDC Energia

OPERATION OF FACILITIES

Figure 7. 1: Suggestions for an Institutional Framework for Water Energy Consortium

7.13 Somewhat on the lines on which G-8 functions, the Council of Heads of States would meet once a year. Prior to this meeting the WEC would have resolved most of the issues faced during the previous year and place before the Council only those issues that could not be resolved at the level of the WEC. The WEC is envisaged to meet once in six months, while the task forces of the Secretariat would meet as often as needed. There is no need to adopt a

58

corporate structure at these three tiers. They could function as inter-governmental committees with equal representation for all member countries. Relationship with Existing Organizations and Other Institutional Issues 7.14 Consideration should be given to subsume ICWC into the WEC in the long term. In the short term, given its extant nature and links to national water organizations, the proposal is to have an association agreement on cooperation between ICWC and the WEC. Similar association arrangements are appropriate for CAPC in the short term. The WEC Executive Directorate needs to be staffed by competent professionals drawn equitably from all member countries and supported by international experts to the extent needed. The expenses of the WEC and its Executive Directorate, have to be met jointly by all governments40. It may also be appropriate for these agencies to be governed by a special charter approved by the parliaments of all member countries. Evolving a Legal Framework for WEC 7.15 A legal framework should be developed to underpin the work of the WEC and the associated bodies. For trans-boundary waters such as the Syr Darya and the Amu Darya, it is desired at the highest levels of the governments in the CARs that the sharing of trans-boundary waters should be done according to international law. It is useful to note that there is no ‘international law’ governing transboundary waters, but the following is available: (i) the convention of the Protection and Use of Transboundary Watercourses and International Lakes signed in Helsinki in 1992 (commonly known as the Helsinki Convention) and (ii) the UN Convention on the Law of the Non-Navigational Uses on International Watercourses (commonly known as the UN Convention). As such, these are not laws by themselves, but only provide principles based on which the appropriate legal framework for specific situations can be developed. Therefore, while ratification of these conventions is desirable, what is really needed is incorporation of the principles of these Conventions into a specific Agreement to govern the WEC and the related water use agreements etc. It would, therefore, be useful to develop an overall Framework Agreement appropriate to the circumstances of CARs. WEC could develop specific agreements for water release regimes and reservoir operations for the proposed new hydro projects and transmission access agreements under the overall Framework Agreement. Institutional Aspects for Investments

7.16 The institutional structure most suitable for constructing and operating new generation and transmission projects is clearly that of a corporate entity. Each of the projects analyzed in this report are discussed from their institutional structure point of view.

• Large projects such as Rogun and Talimardjan II may need to be regional. The size of investments needed for them are beyond the financing capabilities of the countries themselves. Securing the large amounts of debt and equity financing needed from outside sources is contingent upon firm arrangements being in place to export the power

40 Part of the expenses of institutions like BVOs and Energia could be met from user fees. However depending on funds from IFIs or Donors for this purpose is not considered sustainable or desirable.

59

to the power systems both within and outside the CAPS. Such large generation projects may therefore have to be conceived of as export oriented regional projects to be jointly owned by: (a) all the relevant riparian states (in the case of Rogun); (b) the importing countries; and, (c) where possible, private sector investors. Such joint ownership by several states would help the projects overcome the problems associated with level of external indebtedness and credit limits of individual countries such as Tajikistan. Joint ownership by riparian states would tend to minimize water related disputes and create greater understanding of, and confidence in, the adherence to the agreed operating regimes. It would also provide all states a measure of control over the reservoir operation. Joint ownership by the importing states could greatly improve their commitment to long-term imports, as has been demonstrated by other regional power projects in the developing world. Box 7.1 gives two examples of such projects in South America and Africa jointly developed by two or more riparian states. Another good example of inviting importers of power to be shareholders is provided by the Theun Hinboun Hydropower Project in Laos (see Appendix 7.2). It also highlights the efficacy of public private partnership and the useful role that an IFI (such as the ADB in the Laos case) can play in a project like this.

Box 7. 1: Two Examples of Jointly owned Hydropower Projects

The Itaipu Hydroelectric project on the Parana River, with an installed generation capacity of 12,600 MW is the world’s largest hydroelectric project. It has been jointly developed by a joint stock company “Itaipu Binacional” owned by the Brazil and Paraguay and established under the Itaipu Treaty of 1973. The first unit was commissioned in 1983. In 2000 it generated 93.4 TWh of electricity and met 95% of the demand of Paraguay and 24% of the demand of Brazil. The agreement to develop the project needed to be reached among all three riparian countries, Brazil, Paraguay and Argentina. The company pays royalties to the governments of Brazil and Paraguay and sells the electricity to utilities in Brazil and Paraguay. Manatali Hydroelectric Project on the Senegal River is a joint development by three countries – Mauritania, Mali and Senegal in West Africa. They have established a joint stock company proportionally owned by the three countries. This company has constructed the 200 MW facility and the related transmission lines.

• Kambarata I hydro project in the Kyrgyz Republic appears to be highly capital intensive

and uneconomic; and proceeding with Kambarata II hydro projects without first constructing Kambarata I should be very carefully examined as it entails many risks. Nonetheless, if it were to be pursued on the basis of the new feasibility studies recently commissioned with help from RAO UES International of Russia, it may have to be jointly owned by the governments of the Kyrgyz Republic, Uzbekistan, Kazakhstan and likely importing states such as Russia. Since the operating regimes of Kambarata I and II have to be strictly coordinated with that of Toktogul, the joint owners of the new project would have some measure of oversight and control over the operation of all these facilities, including Toktogul reservoir, though it is expected that it would continue to be fully owned by the Kyrgyz government.

• Bishkek II thermal power project which appears to be the best option to meet the winter

electricity shortages in the Kyrgyz Republic calls for an investment of the order of $200 million and could conceivably be implemented on the basis of a Public Private Partnership approach. Since Uzbekistan and Kazakhstan perceive the augmentation of

60

winter electricity supply in the Kyrgyz Republic is the best insurance for the adherence by the Kyrgyz authorities to agreed water release regimes of Toktogul reservoir, they could conceivably be invited to make equity investments41 in this project. This might induce them to provide uninterrupted fossil fuel supplies to the project.

• Sangtuda I hydropower project, prima facie, appears to be economic. Given the

significant commitment made to develop this project by Russia (US$50 million) and Iran (US$150 million) it would likely be multi-country endeavor.

• The large thermal projects Talimardjan I in Uzbekistan and Ekibastuz Rehabilitation

could be constructed and operated by the existing power companies which own them as the investments needed to complete them are modest.

INTERIMCG MEETING

CopenhagenApril 29, 2002

WATER-ENERGY CONSORTIUMPOSSIBLE FINANCING SCHEME FOR DEVELOPMENT OF NEW REGIONAL

INFRASTRUCTURE

International PrivateInfrastructure

Development andOperating Company

SHAREHOLDERS

GOVERNMENTS

Kazakhstan KyrgyzRepublic Tajikistan Uzbekistan

PRIVATE INVESTORS

from CentralAsia

OtherInternational

from neighbouringcountries (Russia ?)

PURCHASERS OFPOWER

GENERATEDFROM THEFACILITY INTERNATIONALINSTITUTIONS

IFC EBRD Others

NATIONALDEVELOPMENT

BANKS

CORPORATEFINANCE

PRIVATE BANKS(national & international)

INTERNATIONAL FINANCIALINSTITUTIONS

IFC EBRD Others

MULTILATERAL FINANCIALINSTITUTIONS

WorldBankGroup

AsianDevelopment

BankOthers

CounterGuarantees

DEBTand / or

GUARANTEES

EQUITY

Figure 7. 2: Financial Scheme for Development of New Regional Infrastructure 7.17 Private sector participation is quite necessary to realize these projects, and to enable this a proper investment climate needs to be created and sustained through the adoption of sound policy, legal, and regulatory framework. Private investors, supported by financiers such as EBRD and IFC, could be mobilized to complement public funding for financing the electricity

41 The equity could possibly come from the gas supply company of Uzbekistan and coal supply companies of Kazakhstan.

61

distribution in all four countries, and for electricity generation in Uzbekistan and Kazakhstan, which can happen through concessions and/or outright privatizations. For the large projects, however, assuming that the regional/multi-investor approach is adopted, an international corporate entity needs to be formed with equity participation by several states as well as the private investor. IFIs like EBRD and IFC could mobilize non-sovereign guaranteed finance along with private investors. IFIs like World Bank and ADB could provide long term debt to the international company against the joint guarantees to be provided by the member governments holding equity stakes in the company. A schematic representation of the above three-element institutional structure for attracting the financing for large projects is shown in Figure 7.2. Transmission Investments 7.18 For transmission investments within the CARs, the state owned national corporate entities responsible for the transmission function would be the appropriate entities to undertake the construction of the new transmission projects to facilitate electricity exports. The equity financing needed for such transmission projects may have to be raised through internal generation of cash from the electricity sector through tariff adjustments and through efficiency improvements relating to loss reduction. The loans could then be raised from the world markets with the help of, and participation by, the IFIs and bilateral donors. 7.19 With respect to specific and radial transmission extension lines, dedicated to supply power to a export market such as the Almaty - Urumchi line or even the Surhan- Mashad line, an independent transmission project (ITP) approach, one in which equity participation by the exporting and importing states and by the private sector is possible, may be more appropriate. A good example of Public-Private participation in a transmission project is the Powerlinks Transmission Project in India (see Box 7.2).

Box 7. 2: Power links Transmission Project in India

Tata Power Company (a private power company) and the Power Grid Corporation of India (a state owned transmission company) have invested 51% and 49% of the equity of $79.5 million and have raised long term loans from IFC ($75 million), ADB ($66.3 million) and local banks and financing institutions ($44.2 million) to finance the construction of five 400 kV and one 220 kV lines of about 1200 km length and 3000 MW of power transfer capacity between Siliguri of West Bengal and Mandaula of Uttar Pradesh near Delhi at a total cost of $265 million. The project is on the basis of a BOOT contract to build, own and operate the project for 30 years and transfer it thereafter to the Power Grid Corporation. The lines are under construction and are expected to be completed by July 2006. The entire transmission capacity will be placed at the disposal of the Power Grid Corporation under a Transmission Service Agreement.

62

CHAPTER VIII: BENEFITS, RISKS AND THE WAY FORWARD

A. Benefits 8.01 The expected benefits are at least threefold. First, electricity trade within the region would enable the CARs to meet their demand at a lower cost than if they were to rely solely on their indigenous resources. For example, the Kyrgyz Republic plans to develop Kambarata I hydro scheme to meet its long term demand. However, this study demonstrates that electricity from Kambarata I would cost more than 7 cents/kWh, compared to the much less expensive electricity from Uzbekistan or Kazakhstan. Second, Kazakhstan and Uzbekistan would benefit from importing hydro electricity (from the existing hydroelectric stations) in summer from the Kyrgyz Republic and Tajikistan, as the economic costs of such hydroelectricity are lower than those of their own thermal power plants. By doing so, and by reducing fossil fuel based electricity generation on a seasonal basis, these countries can conserve their fossil fuel resources, and also might gain from carbon trading. Third, electricity exports beyond the region would indeed contribute significant economic benefits to the region as a whole. Not only the countries that generate and export electricity benefit, but also the transit countries e.g, Kazakhstan and Uzbekistan, would reap the benefits of transit income. Also, the building of large reservoirs like Rogun would help provide multi-year regulation of the Vaksh River, and therefore contribute to further developing irrigated agriculture, with its own attendant benefits.

B. Risks 8.02 The development of the energy sectors of the CARs, both individually and collectively, is as important to be realized as part of realizing the export potential. In this regard, the CARs face several major risks, many of which belong to the realm of political economy. These risks can be categorized as Reform Risks, which essentially affect the development of the national energy sectors; Cooperation Risks that affect the development of national as well as regional trade; and Market Risks, which affect the realization of export potential beyond the region. These risks are discussed below. 8.03 Reform Risks. Although all countries have adopted some level of policy and institutional reforms of their energy sectors to transition to a market economy, the implementation of these reforms is very uneven. Kazakhstan has made most progress in reforming the industry structure, private sector participation, and pricing. Uzbekistan has become quite aggressive in pricing reforms, and has made progress in industry structure reform by creating a holding company structure with separate companies for generation, distribution and transmission. However, the Kyrgyz Republic and Tajikistan, where reforms are needed urgently, are lagging the most. Pricing reforms and private sector participation have become highly politicized in the Kyrgyz Republic in recent years, and the country is facing both Parliamentary and Presidential elections in 2005. In Tajikistan, a firm plan for reform of pricing, industry structure and private sector participation is yet to be adopted. 8.04 In addition, all countries need to put in place effective social protection schemes to accompany energy reforms. Equally important, the countries need to improve their investment climate to increase the chances of attracting private investments that are surely needed to realize

63

the investments. Moreover, in view of the fact that trade at the margin would be needed to meet the demand at least cost, the countries should move away from the energy self-sufficiency policies. 8.05 Implementation of these reforms is within the control of the individual countries themselves, and are actually fundamental for national sectoral development as well as for electricity trade within Central Asia and with neighboring countries. Pricing reforms in the two hydro countries for example, would give them urgently needed resources for rehabilitating their power networks and reducing losses, which could lead to reduced demand and therefore have more surpluses for exports on a seasonal basis. 8.06 Cooperation Risks. This set of risks affect development of the national energy sectors as well as the possibility of enhanced electricity and water trade within the region.

• Water Energy Nexus Risk. This problem, in the Syr Darya basin, still exists, despite attempts to resolve it since 1998, and despite the many possible solutions that have been put forward. Resolution of this problem would have significant impact on meeting domestic electricity demand in the Kyrgyz Republic, and would involve expanded energy trade on commercial terms. However, each of the countries involved have different solutions to the problem (see Chapter II, paragraph 2.03) and reconciling these and implementing a solution satisfactory to all will be a challenge in the current environment. A solution to this problem is seen as a litmus test for regional cooperation.

• Riparian Risk. This is an extension of the Water Energy Nexus Risk as far as the Syr

Darya basin is concerned, and will affect the building of the Kambarata schemes. Uzbekistan and Kazakhstan are unlikely to agree to Kambarata since building this scheme would increase the Kyrgyz Republic’s capability to regulate the Naryn river close to 100% (which means that the Kyrgyz Republic can in theory hold all the waters in Naryn in the Toktogul and Kambarata reservoirs), unless of course the downstream countries are given the operational rights to Toktogul. This, understandably, is not agreeable to the Kyrgyz Republic, thus diminishing the chances of Kambarata coming to fruition.

Building the Rogun scheme would face a similar riparian risk as both Uzbekistan and

Turkmenistan are downstream riparians on the Amu Darya. Turkmenistan is not a member of CACO (for example) and its views regarding the building of Rogun are not known. The solution lies in developing Rogun as a regional project, with the involvement of the riparians, who would have a say in the operation of the reservoir, but all of this needs to be worked out.

• Transmission Access Risk. The integrated nature of the CAPS grid and the landlocked

status of the CARs makes these countries dependent on each other for transmission of power to reach parts of their own market (e.g., Tajikistan is dependent on the Uzbek grid to transmit power from its generation sources in the south of the country to the more industrialized north) and export markets. In order to supply Russia, the Kyrgyz Republic needs the access to the Kazakh grid). Such interdependence creates risks of capacity –

64

Uzbekistan claims that there is no spare capacity in its part of the grid adjoining Tajikistan to transmit Tajik power (either for Tajik’s own use or for export to Russia via the Kyrgyz Republic and Kazakhstan). This risk is manifest in Uzbekistan’s reluctance so far to sign the Power Trade Relations Agreement with Tajikistan enabling power trade between the two countries, despite its having initialed the draft contract in the context of negotiating a loan of $120 million from ADB and EBRD for the construction of transmission lines and substations. Also this gives rise to hold up risks – Kazakhstan and Uzbekistan can indirectly dictate when and how much water can be released in the reservoirs in the Kyrgyz Republic and Tajikistan by refusing access to their electricity grids. When this is juxtaposed with the Kyrgyz Republic’s tendency to ensure that every drop of water released from the Toktogul reservoir produces electricity (i.e., if it cannot use or sell electricity it would tend not to release water), the risk is all too real and serious.

Here too, the solutions lie in a combination of agreements and investments. Agreements are needed so that Kazakhstan and Uzbekistan give Third Party Access to their transmission grid; and by the Kyrgyz Republic and Tajikistan to observe optimally beneficial water release regimes. Investments are needed to complete the construction of the North South Line in Kazakhstan, which is needed to enable supply from the larger generation capacities to the CAPS in winter, and to enable exports to Russia in summer. Financing, in part by EBRD, for a section of this high priority line is in place, and the Kazakhstan government is planning to complete this line by 2008. Investments would also be needed to overcome the capacity problems that may exist in the southern part of CAPS (southern Uzbekistan, southern Kyrgyz Republic and Tajikistan), especially when Talimardjan I begins to dispatch. Recognizing this possibility and to create alternative transmission routes for their own power, the Kyrgyz Republic and Tajikistan are building a 54-km 220 kV transmission line between Kanibodom (in Tajikistan) and Batken (in the Kyrgyz Republic). It may be worthwhile to think of extending this line to link the Nurek cascade in Tajikistan and the Toktogul cascade in the Kyrgyz Republic, thus creating alternative transmission routing which would essentially link Kazakhstan (and therefore the Russian grid) via the Kyrgyz Republic with Tajikistan (and therefore Afghanistan) without going through Uzbekistan. Details of this scheme are discussed in Appendix 8.1.

• Resource Risk. Currently the supply of gas from Uzbekistan to the Kyrgyz Republic and to Tajikistan is not reliable for several reasons, the most important of which is the inability of the Kyrgyz/Tajik authorities to pay for the gas in cash and the need to rely on barter arrangements. In this context, the proposal that Bishkek II be based on Uzbek gas may be perceived from the Kyrgyz perspective as a gas supply risk. However, the Kyrgyz perspective may be driven by their efforts to try to promote the construction of the Kambarata schemes, which are seen as projects of national importance, and therefore adoption of Bishkek II to solve Kyrgyz’s winter deficit problem (as opposed to Kambarata) is likely to be a politically tough decision.

65

Perceptions apart, in view of the fact that there has not been an independent evaluation of Uzbek gas reserves, the perception of this risk is likely to persist also for Talimardjan I and especially for Talimardjan II. Solutions lie in the Uzbek authorities quickly conducting an independent evaluation of their reserves, and continuing to attract private/foreign investment in order to increase the reserves. In addition, the Bishkek II plant needs to be structured as a commercially viable entity privately owned and managed and capable of contracting for gas and paying for it in cash. The gas supply entity, Uzbekneftegaz in Uzbekistan, is commercializing rapidly and is slated for privatization; it naturally prefers to export to cash paying customers. There may be other approaches for fuel supplies for Bishkek II – it could be designed as a coal fired plant instead of gas, for example.

8.07 Market Risks. It is clear that the CARs do have the potential to provide electricity to markets outside the region. While Central Asian supplies should be cost competitive in these markets, the cost advantage is not overwhelming. Also, realization of electricity export potential is not just about economics. Electricity trade is politically more sensitive than general trade since electricity supply is often viewed as a national security issue. Also, trade of significant amounts of electricity requires long-term commitments and a clear perception, in the importing countries, that the supplier can be relied upon to fulfill its commitments. The level of trade that will justify the construction of major facilities to service the export markets and the associated commitment of capital will be predicated on the alleviation of supply security concerns on the part of the importing countries and an associated perception that the political climate and the business environment in the exporting countries are stable. 8.08 In addition to the above general risks that apply to long-term electricity trade, there are specific risks with each of the target markets. Afghanistan has potential demand but is constrained in its ability to pay for imports, and in any case is a small market in the immediate future for the larger new projects in the CARs. Access to the Pakistan market would involve transit and the associated construction of transmission facilities through Afghanistan and there would be questions of who will bear the responsibility for such transmission links, and also perceptions of security risks. The demand growth in China is centered on the population centers of the East Coast, a considerable distance from Central Asia. Access to the Russian market will require access to the North-South transmission line across Kazakhstan that is under construction and would be dependent on the interest and willingness to purchase power by RAO UES and later by whatever power companies that emerge from Russia’s power sector restructuring. CARs would also face the risk that supplies to Iran from the Kyrgyz Republic and/or Tajikistan will likely have to compete with supplies from Turkmenistan and will have to transit Afghanistan or Turkmenistan as well as Uzbekistan.

C. The Way Forward 8.09 Addressing the risks and impediments to realize the full regional trading and export potential will require time and strong political will both within the CARs and in the target markets. While the international financial community is prepared to work with and support all the countries, such support cannot replace the political will needed to make the necessary

66

compromises for regional cooperation. The World Bank, in concert with other development partners is providing advice and technical assistance (including this report) to aid the formation of the Water-Energy Consortium, to help put in place the requisite legal, institutional, and financial framework. 8.10 The Central Asian suppliers of electricity should approach the issue of expanded export activities with the recognition that a significant expansion in export levels will take some time to develop, and they should, therefore, focus on the objective of building towards this longer term goal in a phased fashion. A possible scenario for development of Central Asia’s electricity generation and trading activity is shown schematically in Figure 8.1 below. This contemplates the phased introduction of measures to make capacity available beginning with the introduction of loss reduction programs to be followed by construction of new capacity needed to meet winter demand within the region (Talimardjan I and Bishkek II) and the completion of the transmission link to Russia through Kazakhstan. These activities should be completed in a medium term time frame (up to 10 years). These phases have a relatively high probability of going ahead.

INTERIMCG MEETING

CopenhagenApril 29, 2002

Central Asian RepublicsPower Development and Trade Strategy

Loss Reduction &Rehab. Programs

Transmission Links:North-South Project

Power Trading Capacity: Sangtuda

Lev

el o

f Ri s

k

Low

High

Time Frame

Near-Term1- 5 yrs

Medium -Term3 - 10 yrs

Long -Term8 - 15 yrs

Domestic & RegionalCapacity Balance:

Bishkek II & Talimardjan I

Export MarketNegotiation

South TransmissionLinks Development

Export Capacity PPP:Rogun & Talimardjan II

Russia

Afghanistan

Pakistan

IranChina?

Figure 8. 1

8.11 Integral to this process, the CARs will need to address the risks discussed earlier. The policy reforms will need to be accelerated in parallel with the loss reduction programs – in fact the two are intertwined closely that one would not happen without the other. Bishkek II and Talimardjan I will contribute to the solution of the Cooperation Risks, which would require overcoming the political resistance to adopting Bishkek II (instead of Kambarata); and ensuring the necessary agreements on water releases and transmission access are in place. 8.12 The chances of realizing updated agreements to govern electricity trading between countries within the region would be higher if these were attempted on a bilateral basis in the initial phase, as is being done with the Batken Kanibodom line between the Kyrgyz Republic and Tajikistan, and between the Kyrgyz Republic and Kazakhstan on Kyrgyz exports to Russia. If

67

these arrangements are all based on a consistent set of principles they will facilitate increased intra-regional trade, and will reinforce the multilateral agreements that is now being explored (with little success to date). 8.13 As regards trade with the markets outside the immediate Central Asia region, it appears likely that such trade will initially be limited to seasonally based activity at the margin. The more extensive level of trade that would justify the construction of major facilities would be ‘demand driven’ by the importing countries. Accordingly, the outlook for implementation of new projects focused on the export markets, e.g., Rogun and Talimardjan II that could occur in a subsequent phase is too uncertain at this time to justify the commitment of significant resources to these large generation projects. What is needed to realize these projects is the alleviation of supply security concerns on the part of the importing countries, the existence of transmission infrastructure to access the markets and a politically stable environment. 8.14 The one exception is the Sangtuda I hydro project in Tajikistan, where both Iran and Russia are making financial commitments to help develop this project. Russia’s role in the development of the large projects of the CARs needs to be better understood. At the moment, it is playing multiple roles – as an importer of Central Asian electricity, as an investor, and as a strategic partner in construction and metals (aluminum) industry. It also became a member of CACO in 2004. Russia’s expanding role in the CIS energy sectors in general and Central Asia in particular may be due to the following reasons:

• Energy supply security - its own gas reserves and electricity generation capacities are declining and Russia may be aiming to shore up its now growing demand for energy, with (still) cheap electricity from CIS, especially Central Asia.

• With ratification of the Kyoto Protocol in early 2005, incentives will exist to shut down highly polluting coal capacity;

• Russia needs to fulfill its energy supply obligations to Western Europe. At present these are limited to gas but in future may include electricity; and

• While western investors currently view the new generation projects as high risk ventures, RAO UES of Russia, believes that it can mitigate many of the risks and has expressed particular interest in some of the proposed hydropower projects.

RAO UES, in combination with Iran (and perhaps Kazakhstan) represents the best opportunity for the Sangtuda I project to be implemented in the medium term. Next Steps 8.15 Further analytical and technical assistance work is needed to continue to build consensus for the power sector development and trade strategy identified in this report. Future phases of this work should focus on: (a) helping to prepare more detailed demand projections (using an end-user approach) and help prepare Least Cost Investment Programs for each of the CARs; (b) undertaking a transmission system assessment including the load flows on a projected basis to understand the bottlenecks, investment needs and costs of service; (c) through country visits to the target markets, confirming the willingness and modus operandi of importing Central Asian electricity in the short, medium and long term; (d) developing commercially oriented contractual

68

documents (e.g., power purchase agreements and transmission service agreements) for intra-Central Asian trade and for extra-Central Asian trade; (e) developing viable PPP financing structures for chosen projects; and (f) developing institutional options for this regional approach to energy development.

CENTRAL ASIA

REGIONAL ELECTRICITY EXPORT POTENTIAL STUDY

Appendix Volume

EUROPE AND CENTRAL ASIA REGION WORLD BANK, WASHINGTON, D.C.

DECEMBER 2004

The views expressed in this paper are the views of the authors and do not necessarily reflect the views or policies of the Asian Development Bank (ADB), or its Board of Governors, or the governments they represent. ADB does not guarantee the accuracy of the data included in this paper and accepts no responsibility for any consequence of their use. Terminology used may not necessarily be consistent with ADB official terms.

2

List of Appendixes

Appendix 3.1: Current Status of Power Sectors in Central Asian Republics Appendix 4.1: Electricity Demand Forecasts Appendix 4.2: Incremental and Total Supplies from Supply Options Appendix 4.3: Electricity Demand Supply Balances Appendix 5.1: Economic Analysis of Supply Options Appendix 5.2: Economic Analysis of Transmission Line Options for Exports Appendix 5.3: Financial Analysis of Generation and Transmission Options Appendix 7.1: Establishment of Water Energy Consortium–Conceptual Approaches Appendix 7.2: Laos Theun-Hinboun Hydropower Project Appendix 8.1: Options for De-congesting Southern Central Asian Power System

3

Appendix 3.1 Central Asia

Regional Electricity Export Potential Study Current Status of Power Sectors in Central Asian Republics

Kazakhstan Infrastructure: Kazakhstan is endowed with enormous fossil fuel resources. Its oil reserves are estimated in the range of 0.8 to 2.5 billion tons. Its gas reserves exceed 1,950 BCM and its coal reserves exceed 185 billion tons. Its hydroelectric potential is about 20,000 MW of which only 10% had been developed. The installed electricity generation capacity is estimated at 18,240 MW consisting of 4 large thermal power plants (8,630 MW), 12 hydroelectric plants (2000 MW), and 38 combined heat and power (CHP) plants (7,610 MW). Due to their age and lack of maintenance the available capacity is estimated available capacity is around 13,840 MW. The rehabilitation of the two large Ekibastuz thermal power stations would add considerably to the available capacity. Kazakhstan’s power system consists of the northern grid (which is well integrated with the Russian grid) and the southern grid (which is an integral part of the CAPS). A single circuit 500 kV line interconnects these two grids, but because of stability problems the line is sometimes kept open. Plans to reinforce the interconnection by another 500 kV line are being actively pursued, and a part of it is already funded with help from an EBRD loan.

Table A3.1: Kazakhstan: Generation, Trade, and Consumption of Electricity Indicators Units 1998 1999 2000 2001 1) 2002 1) 2003 2)

Peak Demand MW 9,318 9,432 Domestic Generation

Hydropower Pants GWh 6,100 3) 6,100 3) 7,500 3) 8,057 8,861 Thermal Power Plants GWh 40,400 3) 38,900 3) 41,400 3) 47,174 49,317

Total Domestic Generation GWh 46,600 3) 45,000 3) 48,900 3) 55,231 58,178 63,700 Exports to

Russia GWh 595 Uzbekistan GWh The Kyrgyz Republic GWh

Exports total GWh 130 3) 90 3) 90 3) - 595 4,119 Imports from

Russia GWh 322 Uzbekistan GWh The Kyrgyz Republic GWh 970 4) 1,2534) 1,095 433 1,389 Tajikistan GWh 2 4) 31 360 Turkmenistan GWh 321 4) 35 4) 9

Imports total GWh 4,000 3) 3,070 3) 3,100 3) 1,426 464 2,448 Net Supply to Domestic Market GWh 50,470 47,980 51,910 56,657 58,048 62,029 Domestic Consumption GWh 33,815 32,626 35,299 39,094 40,053 43,420 System Losses GWh 16,655 15,354 16,611 17,564 17,995 18,609 Losses as a % of Net Supply 5) % 33% 32% 32% 31% 31% 30% 1) Energy sector and Fuel Resources of Kazakhstan, March 2003. 2) Kazakhstan Electricity Association, Energy Industry Bulletin 3-2004. 3) Fossil Energy International, An Energy Overview of the Republic of Kazakhstan, October 2003. 4) UDC "Energiya", Annual Reports. 5) WB’s estimate based on Environmental Performance Review of Kazakhstan, UN, Economic Commission for Europe, Committee on Environmental Policy, September 2000 and Regional Review of Social Safety Net Approaches, USAID, October 2003 (see Appendix 5: Energy Reform and Social Protection in Kazakhstan)

4

Generation, Trade and Consumption. Table A3.1 shows the historical data for electricity generation, trade and consumption from the year 1998 to 2002 in Kazakhstan. Generation from thermal plants accounted for 85% of overall generation, while hydro plants accounted for the remainder. The northern system was a net exporter of electricity in 2002, where as the southern system is a net importer. Imports in the south are from the Kyrgyz Republic mainly as a result of obligations under the annual IGIAs relating to the operation of the Toktogul reservoir in the Kyrgyz Republic. Domestic consumption, which was declining from 1990 to 1999, resumed growth in the subsequent years reflecting the economic growth experienced by the country and the region. A growth of 23% in domestic consumption of electricity occurred during 1999-2002. The annual peak demand is in the month of January and the summer peak in July is generally around 60% of the winter peak.

System Loss, Billing and Collections: Overall system loss is reported at 30% for the country as a whole. However, there is considerable variation in the loss levels among the distribution entities. In many distribution companies, the loss levels are as high as 35% of the electricity supply received by them. Similar variations in billing and collection efficiencies are reported to exist among these agencies. While overall collection levels are reported to be around 85% of billings, overall cash collection levels appear to be around 55% of billings.

Public DistributionCompanies

Final Consumers

KEGOC

Policy

Ministry of Energy,Industry and Trade

State Property andPrivatizationCommittee

Committee onNatural

Monopolies

Private Power Plants85 percent capacity

State Power Plants

Public DistributionCompanies

Public DistributionCompanies

Private DistributionCompanies

Source: ADB Report on Regional Power Transmission Modernization Project

Figure A3.1: Structure of the Kazakhstan Electricity Supply Industry

Sector Structure: Kazakhstan is one of the earliest former Soviet Union countries that pursued structural reforms to enable privatization of sector assets. The sector has been unbundled into generation, transmission and distribution since 1996 (See Figure A3.1). Transmission at 220 kV and above and dispatch are being handled by the state owned joint stock company KEGOC. There are 21 Regional Energy Companies, which own smaller sized generation units1 (mostly combined heat and power plants), transmission at 110 kV level and 1 The total capacity of such regional level units in Kazakhstan as a whole amounts to 8,860 MW or 48.6% of the total installed capacity in the country.

5

electricity distribution networks and heat distribution networks. Not all of them have been unbundled and some continue to retain the status of vertically integrated utilities. These RECs are owned by different levels of government. Eleven of them have state ownership, six have communal ownership, and four have trust management ownership. Regulation of the industry is carried out by the State Committee for Regulation of Natural Monopolies and Protection of Competition. The regulatory bodies at the oblast level have also a major role to play in regulation of tariffs. Private Sector Participation: Significant portion of the large sized generation assets (referred to as national level power plants) have been privatized to foreign and local strategic investors. The large hydroelectric generation units have been given on concession basis to private investors. Nine of the electricity distribution networks from the unbundled RECs have been privatized adopting a concessions approach. Regulatory problems have resulted in notable cases of disinvestment by international private investors from distribution business. Market Operations: Distributors and generators are linked by a system of bilateral contracts. Major industries, connected to the HV transmission grid, as well as RECs and privatized distribution companies are free to contract directly with generators, as third party access to the national grid is legally ensured. A contract trading market has been introduced and determines wholesale prices. Contracts for basic capacity, peak and off peak capacity, standby capacity and reactive capacity are provided. The final consumer pays a tariff which is a sum of the cost of energy, national, regional and distribution network charges, technical losses and maintenance charge. An experimental market trading organization, KOREM, has been set up, and a trial electricity market trading is already taking place. With assistance form a World Bank/EBRD financed US$190 million loan a Grid Code was prepared during 2001 and has since been approved by the Ministry of Justice; market rules are being finalized; measures for the operation of “a day ahead” and “spot” markets for the real time balancing of supply and demand in a largely bilateral contract driven market are being pursued. Further privatization of distribution is also being pursued. Electricity Pricing: Since the Kazakhstan power system has multiple generators and multiple distributors, it has a complex tariff system, featuring different generation tariffs, as well as a three-part transmission tariff. Wholesale tariffs presently range from 0.5 US¢/kWh to just below 1 US¢/kWh. Transmission tariffs applied by KEGOC and subject to quarterly review by the regulator are currently at about to 0.7 Tenge/kWh (0.4 US¢/kWh). Retail tariffs are charged by RECs, and tariff levels are generally higher for privatized RECs than for those still remaining in government ownership. Energy Regulators Regional Association (ERRA) reports that the unweighted overall average of all RECs is 2.64 US¢/kWh. In general residential consumers pay more than the industrial consumers, indicating some decline in the cross subsidy. The Kyrgyz Republic

Infrastructure: Though only 10% of its hydroelectric potential has so far been developed, the Kyrgyz power system is predominantly hydroelectric. It has an installed power generation capacity of 3,713 MW, of which 2,950 MW (79.5) is hydroelectric and 763 MW (20.5%) is thermal. The hydropower units of the Toktogul storage reservoir and those in the downstream

6

Naryn2 cascade account for 97% of the hydro capacity and 78% of the total installed power generation capacity in the country. They account for 90% (or 11 to 12 TWh) of the total electricity generation. The thermal capacity consisting of two combined heat and power plants (CHP) fueled by gas, fuel oil or coal generate only about 1.1 to 1.2 TWh though their design outputs were rated at around 4.1 TWh, as a result of lack of fuel and their poor condition. Transmission voltages include 500 kV, 220 kV and 110 kV. Distribution is at 35 kV, 10 kV, 6 kV, and 0.4 kV. Generation, Sales and Trade: Data relating to generation, exports, imports, domestic consumption and sales in the Kyrgyz Republic are summarized in Table A3.2.

Table A3.2: The Kyrgyz Republic: Generation, Trade, and Consumption of

Electricity. Indicators Units 1998 1999 2000 2001 2002 5 year Average

Peak Demand MW 2633 2554 2622 2775 2687 2,661 Domestic Generation

Hydropower Pants GWh 9,939 12,137 13,024 12,391 10,778 11,654 Thermal Power Plants GWh 1,631 982 1,222 1,215 1,115 1,233

Total Domestic Generation GWh 11,570 13,119 14,246 13,606 11,893 12,887 Exports to

Uzbekistan GWh 970 1,926 1,038 523 1,114 Kazakhstan GWh 970 1,253 1,264 575 1,016 Tajikistan GWh 149 154 78 118 125

Exports total GWh 1,043 2,089 3,333 2,380 1,216 2,012 Imports from

Uzbekistan GWh 2 195 287 267 188 Kazakhstan GWh 0 0 0 0 0 Tajikistan GWh 137 126 35 163 115 Turkmenistan GWh 49 0 0 0 12

Imports total GWh 320 188 321 322 430 316 Net Supply to Domestic Market GWh 10,847 11,218 11,234 11,548 11,107 11,191 Domestic Sales GWh 6,624 7,251 7,779 6,641 6,836 7,026 Losses GWh 4,223 3,967 3,455 4,907 4,271 4,165 Losses (as a % of Net supply) % 39 35 31 42 38 37

On the basis of five-year (1998-2002) averages total generation was about 12.9 TWh of which more than 90% was hydroelectric. About 15.6% of the total generation was exported mainly to Uzbekistan and south Kazakhstan in terms of the annual IGIAs relating to Toktogul reservoir operation; and partly to Tajikistan. Imports are modest and are mainly for technical exchanges needed for system stability and balancing purposes. Net supply to the domestic market amounted to about 11.2 TWh, but domestic sales amounted to only 7.0 TWh implying a system loss level of about 37% of the net supply. Since Toktogul reservoir provides multi year storage facility for irrigation and agriculture in the downstream countries, water releases from it are subject to annual IGIA. This leads to substantial release of water and export of electricity in summer and limited release of water and import of fuels in winter. Thus to a large extent, trade in electricity is a byproduct of water release agreements.

2 Naryn is the major tributary of Syr Darya River

7

Power Market: The country is fully electrified and the total number of consumers is about

1.08 million, more than 95% of which are residential consumers. Though the level of electricity consumption by the year 2000 reached the level prevailing in 1990 (before the dissolution of the Soviet Union), the structure of consumption has changed dramatically. Industrial consumption declined sharply and the share of the residential consumers rose from 15% to about 60% of the total consumption.3 The main reasons for the surge in the residential consumption were the lack of indigenous fossil fuels, the quick rise in the price of imported fossil fuels to internationally traded levels, the scarcity of imported fuels for want of cash to pay for imports, and consequent behavior of residential consumers in switching from fossil fuels to electricity for space heating, cooking and hot water, encouraged by the continued low and highly subsidized price of electricity. Thus seasonal variations in demand became pronounced. The system peak demand occurs in the height of winter and the summer peak demand is only about 55% of the winter peak demand. About 2/3 of the annual electricity consumption takes place in the first and the fourth quarters of the year (winter and fall), as a result of the increased heat demand. System Loss, Billing and Collection: The total system loss level averages to about 37%. The technical losses in the transmission and distribution network have increased on account of the dramatic change in the structure of demand. The network also needs extensive rehabilitation. A substantial portion of the losses (more than 50%) is attributable to unmetered supplies, defective meters and theft of power. Billing and Collection efficiencies are poor at around 80% each, and the sector is still beset with problems of nonpayment and payment in barter. Sector Structure: The Kyrgyz Republic electricity system was unbundled in 2001 creating the Electricity Supply Industry (ESI) comprising: one generation company; one transmission company and four distribution companies (See Figure A3.2). The State Energy Agency is the regulatory body for the whole energy sector, while the policy formulation is in the hands of the Department of Fuel and Energy Complex under the Prime Minister. Market Operations: According to the Electricity Market Rules adopted by the Government in 2000, the transmission company is a ‘common carrier’ with no responsibility for buying and selling electricity4 (other than very small quantities for maintaining system stability and to follow the instructions of the Unified Dispatch Center in Tashkent). The distribution companies trade directly with the generation company for their electricity purchases and pay a transmission service fee to the transmission company. The generation company is responsible for the exports of electricity.

3 Average annual consumption of the residential consumer in 2003 was about 4,560 kWh 4 However, the Government later made a decision that, on an exceptional basis and during a transitional period only, the transmission company would be allowed to sell directly to the Kumtor Gold Mining Company.

8

Serva (North) Electra(Bishkek, Chuj and

Talas oblasts)Jalal-Abadelectro

(Jalal-Abad Oblast)

Vastock (East)Electro (Issyk-Kul

and Naryn Oblasts)

Oshelectro (OshOblast)

Final Consumers

JSC National Grid

JSC ElectricPower Plants

PolicyPM Department of Fuel-Energy, Infrastructureand Communications

State Commission onProperty, Investment

owner of all electricitysupply facilities

State EnergyAgency

Source: ADB Report on Regional Power Transmission Modernization Project

Figure A3.2: The Kyrgyz Republic Electricity Supply Industry Structure

Private Sector Participation: The Government has committed itself to seek private sector participation in electricity distribution and in small hydro schemes. Two small hydro schemes, Chakan and Kalinin, have been handed over to private investors. The implementation of the decision to offer Severelectro, one of the four distribution companies, to the private sector on the basis of concessions is still in the preparatory stage.

Electricity Pricing: Though tariffs have been revised several times since 1999 and the overall average tariff in the Kyrgyz Republic power sector in 2003 amounted to 1.42 US cents/kWh5, it still lagged behind the cost recovery tariff level of about 2.3 US cents. In addition, there is a significant cross subsidization of the residential consumers by industrial consumers. SEA regulates the generation, transmission and distribution tariffs. Tajikistan

Infrastructure: Tajik power system is also predominantly hydroelectric. The hydroelectric potential of the country is estimated at 40,000 MW with an annual energy content of 527 TWh, and of this only 10% has so far been developed. The total nominal installed power generation capacity is about 4,405 MW consisting of seven large and several small hydroelectric stations (4,059MW) and two fossil fuel fired CHP units (346 MW). The available capacity, 5 The generation company realizes a tariff of 23 to 26 tyins /kWh from the distribution companies and 71.3 tyins/kWh from the 14 large Industrial consumers to whom it supplies power at 110 kV. Industrial consumers receiving supplies at 35 kV and 10 kV pay to the distribution company a tariff of 80 tyins/kWh. The transmission charge amounted to an average of 8.7 tyins/kWh. Residential consumers pay to the distribution company 43 tyins/kWh for the first 150 kWh per month (lifeline rate) and 80 tyins/kWh for consumption above that limit. The government is examining the possibility of removing the lifeline rate and charging a unified tariff for all residential consumers.

9

however, is much lower at about 3,428 MW (comprising 3,218 MW of hydro and 220 MW of CHP capacity). The Nurek hydropower cascade, comprising the Nurek reservoir and power houses at Nurek and Baipaza with combined capacity of 3,600 MW and an annual energy capability of 15 TWh is the most important generation asset. Tajik power system comprises essentially three separate grids. The grid in the northern part (Sogd region) and that in the southern part, (Khatlon region) are not directly interconnected within the country because of the high mountain range that divides them. The grid in the eastern part (Gorno Badakhshan Autonomous Region) is connected to the southern grid by a long 35 kV line with a very limited transfer capacity. Most of the generation is concentrated in the southern grid and major load centers are in the northern grid. The southern and northern grids are however interconnected with the power grid of Uzbekistan at several voltage levels and there is thus a continuous exchange of power between Tajikistan and Uzbekistan. Tajik power system meets its domestic demand mostly by domestic generation and partly by net imports. Its transmission system consists of 226 km of 500 kV lines, 1,203 km of 220 kV lines, 2,839 km of 110 kV lines. Distribution is by 35 kV, 10 kV, 6 kV, and 0.4 kV lines. Electrification of the country is nearly complete and almost every household has access to the electricity grid. Its annual per capita electricity consumption in 2000 amounted to 2473 kWh.

Table A3.3: Tajikistan Electricity Generation, Trade, Consumption and Losses Indicators Units 1990 1998 1999 2000 2001 2002 5-year Average

Peak Demand MW 2,352 2,605 2,723 2,750 2,901 2,666

Domestic Generation

Hydropower Plants GWh 17,459 14,147 15,426 14,025 14,206 15,086 14,578

Thermal Power Plants GWh 633 271 369 222 130 138 226

Total Domestic Generation GWh 18,092 14,418 15,795 14,247 14,336 15,224 14,804

Exports to

Uzbekistan GWh 2,344 3,600 3,691 244 299 72 1,581

The Kyrgyz Republic GWh 324 124 137 126 35 163 117

Turkmenistan GWh - - 2 - - 31 7

Exports total GWh 2,668 3,724 3,830 370 334 266 1,705

Imports from

Uzbekistan GWh 3,927 3,619 3,493 729 569 360 1,754

The Kyrgyz Republic GWh - - 149 154 78 118 100

Turkmenistan GWh - 350 - 819 1,037 580 557

Imports total GWh 3,927 3,969 3,642 1,702 1,684 1,058 2,411

Net Supply to Domestic Market GWh 19,351 14,663 15,607 15,579 15,686 16,016 15,510

Domestic electricity sales GWh 18,109 12,495 13,310 12,040 12,165 12,988 12,600

System Losses % 6% 15% 15% 23% 22% 19% 19%

Source: Barki Tajik Generation, Sales and Trade: Data relating to generation, sales, trade and losses are summarized in Table A3.3. Domestic generation declined from about 18 TWh in 1990 to about 14 TWh during 1995-1998 on account of: (a) the mothballing of the CHP plant at Yavan caused by the shortage of fuels, non-operation for prolonged periods and lack of funds for maintenance; (b) reduction of the Nurek Hydro reservoir capacity caused by silting; and (c) the need to shut down some of the hydro units for lack of spare parts and funds for maintenance. Rehabilitation of some of the hydro units has resulted in some improved hydro output in the later years. Trade

10

is the result of the annual Inter Governmental Irrigation Agreements (IGIA) made under the Framework Agreement of 1998 among the riparian states of Syr Darya River basin.6 Tajikistan is obliged under these agreements to store a minimum of 3.4 BCM of water in the Kairakkum reservoir7 on Syr Darya River during the winter season to enable the flow of adequate water for irrigation in the summer season in Uzbekistan. For this storage service, Uzbekistan is obliged to receive 250 GWh of electricity from Tajikistan in summer and transfer 200 GWh in winter to Tajikistan. Trade above the levels mentioned in the IGIAs has to be paid for in cash. Exports from Tajikistan declined over the decade on account of the energy self sufficiency policy followed by Uzbekistan and imports by Tajikistan declined as a function of its inability to pay in cash for such imports. Power Market: The decline in domestic sales by 33% during 1990-2001 was on account of the economic turmoil following the dissolution of Soviet Union and the ensuing internal conflicts within Tajikistan. TADAZ one of the largest Aluminum smelters in the world is located in Tajikistan and it accounts for about 32% of total domestic sales of electricity. Residential consumers account for 34% of the sales, followed by agriculture and irrigation pumping (21%) other industries (7%) and government consumers (6%). During the decade the share of industry (including TADAZ) fell from 68% to 39%, while the share of the residential consumers rose from 8% to 34%. As in the Kyrgyz Republic, and for the same reasons, residential consumers switched from fossil fuels to electricity for heating and cooking during winter. However, the seasonal variations in the demand for electricity in Tajikistan are not as pronounced as in the Kyrgyz Republic due to aluminum production and demand for irrigation water pumping balances. The share of the winter consumption in the total annual consumption is actually only 43% and shortages are acute, mainly owing to lack of supply, as flows in the rivers are reduced significantly, and the storage capacity in the reservoirs is limited. Regional consumption pattern is such that about 40% of the energy is consumed in the northern region followed by southern region (25%), capital region (18%) and others (17%). System Loss, Billing and Collection: The overall loss for 2001 is reported at 22% in Table A3.4. However, nearly 32% of the total sales (3,916 GWh) was to the Aluminum smelter TADAZ at 220 kV. The loss here can not be any higher than 1.0 % thus the losses on the remaining sales of 8,249 GWh amounts to nearly 30%. It is estimated that out of the 30% of losses about one half is attributable to technical losses in the transmission and distribution system and the rest is attributable to non-technical losses arising from theft, defective metering, use of norms based billing for consumers without meters, non-billing or inadequate billing. Billing inefficiencies are so high that only about 70% of the consumption gets billed. Collections are at around 70% of the amounts billed. Only 40% of the collections are in cash, the rest being in barter and offsets. Sector Structure, Market Operation and Private Sector Participation: Barki Tajik (BT), the state owned vertically integrated utility was responsible for generation, transmission and distribution in the whole of Tajikistan till recently (See Figure A3.3). After the privately owned Pamir Energy Company was given a 25-year concession in the end of 2002 for the operation of all power facilities in the Gorno Badakshan Autonomous Region (GBAO), BT’s responsibilities cover the remaining areas of the country. BT is registered as a state owned Joint Holding

6 Kyrgyz Republic, Uzbekistan, Kazakhstan and Tajikistan 7 It is a 126 MW storage hydro power station in the northern Grid of Tajikistan.

11

Company (SJHC) and has 28 subsidiary companies within its holding. There are several generation subsidiaries, one transmission and dispatch subsidiary and 11 distribution subsidiaries, in addition to subsidiary companies for maintenance, design, research etc. Though from a legal point of view the generation, transmission and distribution entities are separate companies, BT functions for all practical purposes as a vertically integrated utility and these units function mostly as divisions of BT, especially in terms of system operations and finance. In addition to these, a new Sangtuda I Joint Stock Company (JSC) has been formed for completing the construction of the large run-of river Sangtuda I hydroelectric project downstream of Nurek-Baipaza cascade and later its operation.

Generation andDistribution Company

Northern,Southern and Eastern

10 repair, construction, material-technical provision enterprises

Final Consumers

State Joint HoldingCompany (SJHC)

Barki Tajik

Inter-AgencyCommitee

Policy and RegulationMinistry of Energy

Electricity Department

State Commission onProperty, Investment

owner of all electricitysupply facilities

Source: ADB Report on Regional Power Transmission Modernization Project

Figure A3.3: Electricity Industry Structure in Tajikistan (2002)

Tariffs: The weighted average tariff in 2003 was of the order of 0.49 US cent/kWh compared to the cost recovery level of 2.1 US cents/kWh. Seasonal tariffs with higher rates for winter than in summer have been introduced in 2003. Lifeline rates for residential consumers is at 0.41 cents Industries and Residential consumption above the lifeline rate limits are charged at around 0.68 and 0.69 cents /kWh. However the limit for the lifeline rate has recently been raised from 150 kWh to 250 kWh per month. Uzbekistan Infrastructure: Uzbekistan has oil reserves of 82 million tons, gas reserves of 1,875 BCM and coal reserves of 4 billion tons and a modest hydroelectric potential of 15,000 GWh/year. Its nominal installed power generation capacity at 11,580 MW is nearly 50% of the total generating capacity in CAPS. It consists of 11 thermal plants totaling 9,870 MW and 31 hydroelectric units totaling 1, 700 MW. The large natural gas fueled power plants include Syrdarya (3,000 MW), Tashkent (1,860 MW), and Navoi (1,250 MW). The large coal fired plants include Angren (600

12

MW) and Novo-Angren (2,100 MW). The largest hydroelectric plant is Charvak (620 MW). Large 800 MW gas fired units are under construction at Talimardjan. It has an extensive transmission system with 500 kV (1,700km) and 220 kV lines (5,100km) and has also a 220 kV line connecting it to Afghanistan.8

Generation, Trade, and Consumption. Data relating to generation, trade, sales, consumption and losses are summarized in Table A3.4.

Table A3.4: Uzbekistan: Generation, Trade, and Consumption of Electricity. Indicators Units 1998 1999 2000 2001 2002 5-year Average

Peak Demand MW 7,603 7,494 7,571 7,674 7925 7653 Domestic Generation

Hydropower Pants GWh 7,269 6,585 4,909 5,354 7,278 6,279 Thermal Power Plants GWh 38,645 38,734 41,932 42,574 42,021 40,781

Total Domestic Generation GWh 45,914 45,319 46,841 47,928 49,299 47,060 Exports to

The Kyrgyz Republic GWh 2 195 287 267 188 Kazakhstan GWh 0 0 0 0 0 Tajikistan GWh 361 729 569 360 505 Turkmenistan GWh 77 33 0 7 29 Outside CA (Afghanistan) GWh 0 0 0 63 16

Exports total GWh 482 440 957 856 634 674 Imports from

The Kyrgyz Republic GWh 970 1,926 1,038 523 1,114 Kazakhstan GWh 0 0 0 0 0 Tajikistan GWh 558 244 299 72 293 Turkmenistan GWh 126 68 13 14 55

Imports total GWh 658 1,654 2,238 1,350 609 1,302 Net Supply to Domestic Market GWh 46,090 46,533 48,122 48,422 49,274 47,688 Domestic Consumption GWh 38,311 37,927 39,465 37,935 38,112 38,350 System Losses GWh 7,779 8,606 8,657 10,487 11,162 9,338 System Losses as a % of Net Supply % 17 18 18 22 23 20

About 77% of the total electricity generated is from gas fired thermal plants, 7% from fuel oil fired thermal plants, 3.5% from coal fired thermal plants, and 12.5% from hydroelectric plants. Its electricity trade with the Kyrgyz Republic and Tajikistan is a result of the obligations under the annual IGIAs relating to the irrigation flows in Syr Darya River regulated by Toktogul and Kairakum reservoirs in those countries. Unlike in the Kyrgyz Republic, the difference between the summer and winter peak demands in Uzbekistan is insignificant. In the year 2000, for example, the summer peak at 6882 MW was about 91% of the winter peak demand of 7,571 MW. Irrigation pumping loads in spring and summer compensate for the heating loads in fall and winter. Despite the large nominal installed capacity of 11.6 GW, Uzbekistan has difficulties in meeting its peak demand ranging from 6.9 GW to 7.7 GW, because of the poor availability of its generation units (which significantly reduces the effective reserve margin) and the relatively low percentage of the peaking plants in the generation mix. The poor plant availability is attributable to the old age of many large plants (most are 30 years old and many are over 40

8 Presently this line can operate only at 110 kV on account of transformer limitations at the Substation located in Mazar-i-Sharif.

13

years old), the need for extensive rehabilitation, and poor electricity tariffs inadequate to generate internal cash to carry out rehabilitation. Capacity shortages of the order of 1000 MW are being met by rolling power outages or by imports from neighboring countries. Power Market: Like the Kyrgyz Republic and Tajikistan, Uzbekistan is also fully electrified and all areas and households have access to electricity. The total number of consumers as of 2001 was about 4 million. Based on 2002 data, unlike in the other two countries, the share of the residential consumers in total electricity consumption in Uzbekistan is low at 15.3%. Since most households have natural gas supply, residential households do not depend on electricity for cooking and heating. Industrial consumers have a share of 47.5%, followed by agricultural and irrigation pumping loads (30.6%) and others such as government entities, commercial consumers and transport (6.6%). System Loss, Billing and Collection: System loss as a difference of gross domestic available supply and billed sales was about 23% in 2002. Approximately half of this is attributable to the transmission and distribution network losses and the rest attributable to defective metering, unmetered supplies and theft of power. No recent data on collection efficiency is available. Based on partial data of 2000, it is estimated that only about 75% of the bills are collected. Payment in barter and offsets is also a major problem as only 40% of the collection is in cash

Sector Structure: Uzbekistan is one of the last former Soviet Union countries to transfer the responsibility for the operational aspects of the electricity system from the government to a legal entity organized on a commercial basis. In 2001, the Uzbekistan Electricity Supply Industry (UESI) was created by abolishing the Ministry of Energy and Electrification and creating a state owned joint stock company UzbekEnergo JSC (See Figure A3.4). UzbekEnergo has three affiliated companies Ugol, in charge of coal mining; UzEnergoSet, for the transmission of energy and one UzEnergoSbyt, as the single buyer and single seller of electricity. In addition, there are subsidiaries for, among others, 7 thermal power plants, 6 hydropower plants, 3 combined heat-and-power plants, and 15 distribution companies. Four of the thermal generation plants (Syrdarya, Fergana, Tashkent, Mubarek) and all the 15 Distribution companies have been registered as independent Joint Stock Companies. UzbekEnergo JSC holds all the shares in them as a holding company. Large industrial consumers receiving supply at 110 kV and above are allowed to buy directly from the generating companies, though at regulated tariffs. A state agency for the technical regulation of the operations of the energy sector, UzGosEnergoNadzor, has also been established. This regulatory agency has authority over electricity, coal and heat energy. It reports to the Cabinet of Ministers, but the economic regulation remains with the Ministry of Finance. Market Operations: UzEnergoSbyt acts as the single buyer for all generated electricity and a single seller to the distribution companies. In effect it is a clearing house accounting for all electricity flows from generators to the distribution companies and large industrial consumers through the national transmission grid. It is also responsible for electricity trade (both imports and exports). Further, the distribution companies remit to the account of UzEnergoSbyt, the difference between their purchase and sale price of electricity. UzEnergoSbyt then allocates the total revenues among the generating companies and transmission company on the basis of power flows. It is a non profit organization and therefore any surplus left with it is remitted to UzbekEnergo. In the context of low rates of collection and extensive use of barter, the system of

14

settlement does not always work logically and available cash is distributed among the participants of the market using ad hoc formulae.

Final Consumers

JSC UzbekenergoPolicy

Cabinet of Ministersdetermines

CoalJSC

Design,construction-

erection, repair andother enterprises

Affiliated Companies16Generation,

15 Distribution etc

Affiliated CompaniesUzelectroSet

(transmission system)

Affiliated CompaniesGeneration;

UzEnergoSbyt(single buyer / seller)

RegulatoryUzgosenergonadzor

Source: ADB Report on Regional Power Transmission Modernization Project

Figure 3.4: Structure of the Uzbekistan Electricity Supply Industry

Private Sector Participation: The Government plans to offer up to 49% of the shares in four generation plants and four distribution companies for private investors. However management control by private investor is not envisaged. While there is a possibility for further private sector involvement in generation and distribution, the Government’s current plans call for the continued state-ownership of all hydropower plants, transmission network, communications system, UzElectroSet as well as UzEnergoSbyt. Electricity Pricing: The weighted average tariff in 2001 was 0.5 US¢/kWh at curb market exchange rates. However, since then, the government has been implementing an aggressive tariff adjustment policy for all energy commodities, as a part of which electricity prices have been increased roughly once every two months. As a result, as of August 2004 the posted average tariff was 2.15 US cents /kWh compared to an estimated cost recovery tariff level of 3.5 US cents. The posted tariff structure also appeared to have reduced cross subsidies to some extent. The Ministry of Finance reviews and approves unbundled tariff proposals for generation, transmission and distribution. The retail tariffs for end consumers are uniform all over the country. Each generating unit /company has a separate regulated tariff. Transmission service has a regulated transmission tariff. The retail tariff is the sum of generation and transmission tariffs, and the purchase price of each distribution company from UzEnergoSbyt is derived on the basis of consumer mix, density of load and a desired level of profit.

15

Appendix 4.1

Central Asia Regional Electricity Export Potential Study

Electricity Demand Forecasts I. Background and Methodology

Trending, end-use analysis and macroeconomic modeling are the common approaches to electricity demand forecasting. Given the economic collapse following the dissolution of the Soviet Union and the continued decline in GDP and electricity consumption in the former Soviet Union countries, trending would be inappropriate in CARs. End-use analysis is difficult on account of paucity of data and is distorted by the excessively inefficient use of electricity. Demand projections made during the Soviet rule and even in years immediately thereafter, were more in the nature of targets to be achieved than in the nature of forecasts. Given the central planning background and practices, price as a determinant of demand was largely ignored and concepts of price elasticity and income elasticity were not much in use. Kazakhstan Electricity Association – a national industry association—has recently commenced the practice of making long-term forecasts. There have also been recent forecasts made by consulting firms financed by International Financial Institutions such as ADB and UNDP, and some bilateral aid agencies in the context of their operations, which use macroeconomic modeling and also incorporate considerations of income elasticity and price elasticity. However they do not appear to have considered seasonal variations in demand adequately. Given the high degree of such seasonal variations, it is necessary to incorporate them in the demand projections to determine export surpluses. Also other key assumptions relating to GDP growth rates, electricity prices and possible efficiency improvements need to be updated. The forecast made in this report on the basis of macroeconomic modeling incorporates these elements. The model is based on a simple iso-elastic demand function of the type often used in such aggregate demand analysis. II. Key Determinants of Demand Growth and Assumptions Income and price elasticity of electricity demand are the key determinants to demand growth in such aggregated demand analysis. An attempt was made to derive the elasticities from the historical data of the four countries, but this did not prove possible – the statistical series are too short, have too many gaps and reflect a period that is not typical in terms of economic activity. Hence, the above elasticities of demand were adopted after a review of a number of studies in the region and elsewhere.

o Income Elasticity or GDP elasticity of electricity demand: The range of available literature indicates that for most developing countries the GDP elasticity of electricity demand ranges between 1.2 and 1.4 (i.e., for every percentage increase in GDP, the electricity demand increases by 1.2 to 1.4 percent). However, most former Soviet Union states (and more so in the case of CARs) do not fit into this category as their electricity consumption is already very high relative to their GDP level. Therefore, it is expected that the relationship between GDP and electricity demand in CARs would be more akin to those prevailing in developed countries, which have exhibited a GDP elasticity of demand of 0.8. This value had been used in relation to CARs in this study.

16

o Price Elasticity: The estimates for price elasticity of demand for electricity in lower income countries generally are in the range of –0.1 to –0.2, implying that for every percentage increase in electricity price, the demand decreases by 0.1 to 0.2 percent. The price elasticity levels for electricity are generally lower than those for other energy forms (e.g., petroleum products), reflecting:

• consumers’ inflexibility to switch from electricity to other forms of energy. This is particularly true of all types of consumers in the short term, and for industries, such as metallurgical and chemical, even in the long term;

• non-availability of other energy forms (e.g., gas), as is the case in the Kyrgyz Republic and Tajikistan; and

• the share of industrial consumption in overall consumption - higher the industrial consumption share as is the case with Kazakhstan and Uzbekistan, lower the price elasticity of demand.

It is also important to note that there is an inverse relationship between price elasticity of demand and a country’s income (GDP) level. At higher income levels, electricity demand becomes less and less elastic to electricity price changes as GDP increases. This is the case with Kazakhstan, where its higher level of GDP would tend to lower the price elasticity values. Considering all of the above, a price elasticity values of –0.1 has been assumed in Kazakhstan and Uzbekistan and –0.3 for the Kyrgyz Republic and Tajikistan (where the needed price increases to reach financial viability are 80% and 300% respectively) are used.

Other Assumptions

A. Table A4.1 shows the periods where the GDP data are available and where the values were estimated. Also shown are the GDP growth rates used in the electricity demand projections. GDP growth rates from 2007 to 2025 were estimated by the Team based on previous experience in the four countries and assessments of acceptable growth rates for these 19 years.

Table A4.1: Gross domestic product, 4 CARs, data source and growth rates GDP growth rates

Country Data Source 2004 2005 2006 2007-2025

KAZ 2004-2006: SIMA, IMF 2007-2025: Estimate 0.072 0.07 0.075 0.04

KYR 2004-2006: SIMA, IMF 2007-2025: Estimate 0.041 0.045 0.051 0.03

TAJ 2004-2006: SIMA, IMF 2007-2025: Estimate 0.153 0.066 0.067 0.03

UZB 2004-2025: Estimate 0.04 0.04 0.04 0.025

B. The electricity tariffs were determined in two stages. The first was to reach the average

incremental cost by a certain date and the second was to maintain that tariff in US dollar terms thereafter. In the first stage, the tariffs and dates were taken as in Table A4.2. The tariffs for each year, from 2003 to the date given in Table A4.2, are determined by interpolating linearly between the years.

17

Table A4.2: Long Run Average Incremental Cost

Country Long Run Average Incremental Tariff (US¢/kWh)

Average Tariff in 2003 (US¢/kWh) Date to Reach Long Run Tariff

Kazakhstan 2.9 2.64 2006

The Kyrgyz Republic 2.45 1.42 2009

Tajikistan 2.1 0.47 2009

Uzbekistan 3.5 1.29 2006

C. It was also recognized that the effective tariffs paid by the consumers were actually lower

than the posted tariffs, due to the poor metering, billing and collection efficiencies. Therefore the applied prices to estimate demand were adjusted by the collection rate to arrive at the effective prices. From the posted average tariff, an effective tariff was determined based on the amount actually collected. More precisely, the effective or adjusted electricity tariff for a given country and year was taken as:

Adjusted electricity tariff = Electricity tariff x Collection rate

The following assumptions are used to derive the rates for the remaining years:9All countries except the Kyrgyz Republic would achieve 98% collection rate by 2010; and the Kyrgyz Republic would reach this level by 2011; and 2011 thru 2025: 98% for all countries. Table A4.3 presents each country’s yearly collection rates from 2003 thru 2025.

Table A4.3: Collection rates per year, 4 CARs, 2003 to 2025 Country 2003 2004 2005 2006 2007 2008 2009 2010 2011-2025

Kazakhstan 50% 57% 64% 71% 77% 84% 91% 98% 98%

The Kyrgyz Republic 40% 48% 56% 64% 71% 79% 87% 95% 98%

Tajikistan 70% 70% 74% 78% 82% 86% 90% 98% 98%

Uzbekistan 50% 57% 64% 71% 77% 84% 91% 98% 98%

D. The monthly electricity demand of the 4 countries for five years (2005, 2010, 2015, 2020 and

2025) were estimated using the average monthly rates of power consumption by the Central Asian Power Systems and Kazakhstan in 1999-2003 (Tables A4.4 and A4.5)10, which were obtained from the Unified Load Dispatch Center in Tashkent.

Table A4.4: Monthly Power Consumption by Central Asian Power Systems and

Kazakhstan, Average in 1999-2003 Power System Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year

Kazakhstan 6,320 5,877 5,404 3,940 3,602 3,639 3,747 3,561 3,786 4,923 5,285 6,061 56,144

The Kyrgyz Republic 1,636 1,445 1,284 854 623 528 542 535 528 809 1,178 1,610 11,572

Tajikistan 1,417 1,256 1,191 1,171 1,389 1,363 1,434 1,445 1,287 1,185 1,287 1,424 15,850

Uzbekistan 4,462 3,995 4,250 3,791 3,891 3,789 4,084 4,055 3,546 3,762 4,048 4,518 48,192

9 Note that the collection rate refers to cash collections only. 10 The assumption of the monthly demand structure remaining constant over 25 years should be treated with caution, as it is unlikely to remain constant for such as long timeframe.

18

Table A4.5: CAPS Monthly Consumption, Average in 1999-2003 (%) Power System Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year

Kazakhstan 11 10 10 7 6 6 7 6 7 9 9 11 100

The Kyrgyz Republic 14 12 11 7 5 5 5 5 5 7 10 14 100

Tajikistan 9 8 8 7 9 9 9 9 8 7 8 9 100

Uzbekistan 9 8 9 8 8 8 8 8 7 8 8 9 100

III. Resulting Estimates of Demand The resulting forecast electricity demands are given in annual terms (see Table A4.6) for each country separately and for the region as a whole, as well as in monthly values (see Table A4.7 through A4.9). The tables show:

a. A decrease in demand to 2010 everywhere, except Kazakhstan. This is due to the tariff increases that take effect while the economies demonstrate modest growth. During the first five-year period, the electricity demand in Kazakhstan increases by 2.91 percent p.a., while the demand in the Kyrgyz, Tajikistan and Uzbekistan decreases by 3.86 percent, 5.18 percent and 0.63 percent p.a., respectively;

b. From 2005 to 2025, the annual growth rate of demand compared to 2003 at the aggregate level is about 1.90 percent, with Kazakhstan showing the highest growth (3.09%), and Tajikistan showing a decline compared to 2003 (-0.17%);

Table A4.6: Gross Electricity Demand Projections, in GWh, 2005-2025 Actual Demand forecast (GWh) Annual Growth rates

Country 2003 2010 2015 2020 2025 2003-2010 2003-2015 2003-2020 2003-2025

Kazakhstan 58,944 72,056 84,034 98,367 115,146 2.91% 3.00% 3.06% 3.09% Kyrgyz Republic 12,145 9,222 10,033 11,296 12,719 -3.86% -1.58% -0.43% 0.21% Tajikistan 16,348 11,267 12,410 13,972 15,731 -5.18% -2.27% -0.92% -0.17% Uzbekistan 48,691 46,597 51,255 56,589 62,479 -0.63% 0.43% 0.89% 1.14% All Four Countries 136,128 139,142 157,731 180,225 206,075 0.31% 1.24% 1.66% 1.90%

c. The monthly demands for all countries except Uzbekistan show winter peaking, with

Kazakhstan showing the greatest winter peak while the Kyrgyz Republic and Tajikistan showing the least peaking demand. In Uzbekistan there is virtually no seasonal variation in demand. (Tables A4.7 through A4.9)

19

Table A4.7: Seasonal electricity demand (gross) in Kazakhstan and the Kyrgyz Republic,

in GWh, 2005-2025 Kazakhstan The Kyrgyz Republic

Monthly Cons. (%)*

2005 2010 2015 2020 2025 Monthly

Cons. (%)*

2005 2010 2015 2020 2025

Jan 11% 7,033 8,111 9,460 11,073 12,962 14% 1,502 1,251 1,361 1,533 1,726 Feb 10% 6,540 7,543 8,797 10,297 12,053 13% 1,450 1,208 1,314 1,479 1,665 Mar 10% 6,013 6,935 8,088 9,467 11,082 11% 1,236 1,030 1,121 1,262 1,421 Apr 7% 4,384 5,056 5,896 6,902 8,080 6% 675 563 612 689 776 May 6% 4,008 4,623 5,392 6,311 7,388 5% 538 448 488 549 618 Jun 6% 4,049 4,670 5,446 6,375 7,463 5% 511 426 463 521 587 Jul 7% 4,169 4,809 5,608 6,565 7,684 5% 513 428 465 524 590 Aug 6% 3,963 4,571 5,331 6,240 7,304 5% 501 417 454 511 575 Sep 7% 4,213 4,859 5,666 6,633 7,764 4% 486 405 441 496 558 Oct 9% 5,479 6,319 7,369 8,626 10,098 8% 918 765 832 937 1,055 Nov 9% 5,880 6,782 7,910 9,259 10,838 11% 1,217 1,014 1,104 1,242 1,399 Dec 11% 6,744 7,778 9,071 10,619 12,430 14% 1,521 1,268 1,379 1,553 1,748 Total 100% 62,475 72,056 84,034 98,367 115,146 100% 11,069 9,222 10,033 11,296 12,719

Table A4.8: Seasonal electricity demand (gross) in Tajikistan and Uzbekistan,

in GWh, 2005-2025 Tajikistan Uzbekistan Monthly

Cons. (%)*

2005 2010 2015 2020 2025 Monthly

Cons. (%)*

2005 2010 2015 2020 2025

Jan 10% 1,351 1,071 1,180 1,328 1,495 9% 4,275 4,350 4,784 5,282 5,832 Feb 9% 1,253 993 1,094 1,232 1,387 9% 3,916 3,985 4,383 4,839 5,343 Mar 7% 1,000 792 873 982 1,106 9% 4,132 4,204 4,625 5,106 5,638 Apr 7% 987 783 862 970 1,093 8% 3,585 3,648 4,013 4,431 4,892 May 9% 1,283 1,017 1,120 1,261 1,420 8% 3,773 3,839 4,223 4,662 5,148 Jun 9% 1,247 988 1,088 1,226 1,380 8% 3,621 3,685 4,053 4,475 4,941 Jul 9% 1,267 1,004 1,106 1,245 1,402 8% 3,814 3,881 4,269 4,713 5,203 Aug 9% 1,274 1,009 1,112 1,252 1,409 8% 3,742 3,808 4,188 4,624 5,106 Sep 8% 1,071 849 935 1,053 1,185 7% 3,326 3,384 3,722 4,110 4,537 Oct 7% 1,048 830 914 1,030 1,159 8% 3,626 3,690 4,059 4,481 4,948 Nov 8% 1,135 900 991 1,115 1,256 8% 3,849 3,916 4,308 4,756 5,251 Dec 9% 1,300 1,030 1,135 1,278 1,438 9% 4,135 4,208 4,628 5,110 5,642 Total 100% 14,216 11,267 12,410 13,972 15,731 100% 45,794 46,597 51,255 56,589 62,479

20

Table A4.9: Seasonal electricity demand (gross) in Central Asian Republics, in GWh, 2005-

2025 2005 2010 2015 2020 2025

Jan 14,161 14,783 16,785 19,216 22,015 Feb 13,158 13,728 15,587 17,847 20,448 Mar 12,381 12,962 14,706 16,818 19,247 Apr 9,632 10,050 11,384 12,993 14,840 May 9,603 9,928 11,222 12,784 14,574 Jun 9,428 9,768 11,051 12,597 14,370 Jul 9,764 10,121 11,448 13,047 14,880

Aug 9,480 9,805 11,085 12,627 14,395 Sep 9,095 9,496 10,764 12,291 14,045 Oct 11,071 11,604 13,175 15,074 17,260 Nov 12,082 12,612 14,312 16,373 18,744 Dec 13,700 14,284 16,213 18,559 21,258

Total 133,554 139,142 157,731 180,225 206,075

IV. Results by Country Kazakhstan Demand increases from about 60,100 GWh in 2005 to 104,255 GWh in 2025, representing an annual growth rate over the period of 3.09% (compared to 2003). This is the highest rate of all the four countries and is the result of: (a) the highest sustained growth in GDP over the period, (b) the fact that there are no large tariff increases expected with respect to the 2004 levels, to cause a reduction in demand. The forecasts can be compared with those derived from other sources (Table A4.10).

Table A4.10: Alternative Forecasts for Kazakhstan (Terawatt hours) Source 2005 2010 2015 2020

This Study 62.5 72.1 84.0 98.4

ADB 62.6-66.1 66.0-75.4 72.0-86.7 77.6-98.1

Kazakh Energy Association 62.5-67.0 75.0-82.0 86.0-95.0 n.a.

This study has forecasts that are somewhat lower than KEA’s forecasts for 2005-2015; and are towards the higher range of ADB forecast (Study for the Regional Power Transmission Modernization Project) figures. The differences with the national forecasts cannot be analyzed as the basis for them was not available, but the reasons for the differences with the ADB forecasts are as follows:

• There are no further price increases beyond 2.9 c/kWh after 2006 assumed in this study, whereas in the ADB study tariffs go up to 6 c/kWh.

• The ADB study assumed GDP growth falls to 3% p.a. after 2015, in their ‘basic scenario’ (i.e. the mean of the range given) while this study assumes continuing growth at 4% p.a. to 2025.

21

The Kyrgyz Republic Demand decreases from around 12,145 GWh in 2003 to 10,000 GWh in 2015, after which it grows slowly, reaching 11,300 GWh in 2020 and 12,700 in 2025. The reasons for the negative growth to 2010 are: (a) substantial increases in tariffs and collections, which cause the effective tariff rate to rise by 103 percent between 2005 and 2010. Table A4.11 shows a comparison of this study’s forecasts with those from other sources.

Table A4.11: Alternative Forecasts for the Kyrgyz Republic (Terawatt hours) Source 2005 2010 2015 2020

This Study 11.1 9.2 10.0 11.3

ADB 12.3-13.2 13.3-15.6 14.6-18.2 15.7-20.5

The forecasts in this study are lower than the mean of the ADB forecasts by about 13 percent for 2005, 36 percent for 2010, 39 percent for 2015 and 38 percent for 2020. The reasons for the differences with the ADB forecasts are due to higher income elasticity in the ADB Study (1.1 versus 0.8 in this study) and higher GDP growth rates in the ADB Study (4.0% through 2015 compared to 3% in this study); and higher price elasticity in this Study (-0.3), which have a substantial impact on generation 2010. Tajikistan Demand would decline from 14,348 GWh in 2003 and even in 2025 will be lower than 2003 level indicating a declining level of demand of 0.17% through the period. The main reason for the decline of demand is the substantial increase in tariffs, which, combined with a large increase in collections, causes the effective tariff rate to rise by almost 4 times more than the 2003 levels.

Table A4.12: Alternative Forecasts for Tajikistan (Terawatt hours) Source 2005 2010 2015 2020

This Study 14.2 11.3 12.4 14.0

ADB Study 15.7-17.0 16.8-19.8 18.3-22.8 19.7-25.7

Forecasts from this study are compared with those estimated in other sources (see Table A4.12). The forecasts calculated here are lower than the mean of the ADB forecasts in 2005 by 13 percent, thru 2010 by 38 percent, thru 2015 by 40 percent, thru 2020 by 38 percent. The reason for the lower growth rate of demand in this study is the lower assumed growth in GDP after 2006 (3% versus 4% in the ADB study); and higher price elasticity (-0.3). Uzbekistan Demand increases from about 44,700 GWh in 2003 to about 62,500 GWh in 2025, representing an annual growth rate over the period of about 1.14 percent. In the first 5 years, the annual growth is a negative 0.63 percent due to increase in collection rate and therefore effective tariff between 2005 and 2010.

22

Table A4.13: Alternative Forecasts for Uzbekistan (Terawatt hours) Source 2005 2010 2015 2020

This Study 45.8 46.6 51.3 56.6

ADB Study 47.8-51.7 52.8-62.6 59.6-75.0 65.2-86.1

JBIC's Forecast 50.7 55.9 61.8

Table A4.13 presents this study’s demand forecasts as well as those from other sources. This study has forecasts that are considerably lower than the mean ADB estimates11: 8 percent lower in 2005, 14 percent lower in 2010, 24 percent lower in 2015 and 24 percent lower in 2020. The very substantial differences can be attributed to the higher income elasticity in the ADB study (1.1 versus 0.8 in this Study) and higher GDP growth rates in ADB Study (4% p.a. up to 2015 and 3 % thereafter compared to 2.5% in this study for 2007-2025).

0.0

50.0

100.0

150.0

200.0

250.0

2005 2010 2015 2020

TWh

World Bank estimates ADB estimates

Figure A4.1: Comparison of ADB estimates and WB estimates,

Gross Electricity Demand of CARs, 2005-2020

Overall Forecasts Comparison. Overall, therefore, compared with the ADB estimates, this study predicts a lower growth in demand for the region from 2005 to 2020. This can be seen in Figure A4.1. V. Sensitivity Analysis In view of the fact that the key determinants of demand, price and income elasticity levels chosen were based on experience elsewhere and not in the CARs, the demand projections were subjected to extensive sensitivity analyses by varying the key determinants of demand – price and income elasticity – in both directions. In addition, the projections were tested for delay or acceleration in reaching cost recovery tariffs. The primary objective of the sensitivity analyses is to ensure that unnecessary investments in new generation would need to be avoided in the CARs, and secondarily to understand the impact of the changes in demand on the exportable surpluses. The following cases were examined and with each case, the demand was matched with supplies from the existing and future supply sources. 11 as well as the Japan Bank for International Cooperation estimates, and the mean figures of ADB forecasts and those of JBIC are close to each other.

23

(i) High case 1: The proposed tariff adjustments were delayed to 2015 (instead of 2010) for

the Kyrgyz Republic and Tajikistan, where the tariff adjustments needed are the highest. The impacts are: the 2003-2025 compounded annual average growth rate (CAGR) of demand is higher by 0.04%; the 2025 demand is higher by about 0.8%; and the exportable surplus is lower by 0.7%. The winter deficits are slightly larger in the 2005-2010 period, confirming the need for new thermal generation sources.

(ii) High case 2: Price elasticity values were reduced in the Kyrgyz Republic and Tajikistan, where the poverty levels as well as tariff adjustments needed are the highest. The impacts are: the 2003-2025 CAGR of demand is higher by 8% (2.05% versus 1.9%); the 2025 demand is higher by about 3.25%; and the 2025 exportable surplus is lower by 29%. The winter deficits continue in the 2005-2010 period.

(iii) High Case 3: Income elasticity values were increased in all countries. The impacts are: the 2003-2025 CAGR of demand is higher by 20% (2.26% versus 1.9%); the 2025 demand is higher by about 8.23%; and the 2025 exportable surplus is lower by 73%. However, the peak surpluses during the 2010 through 2020 are in the 21.2 TWh to 36.3 TWh range and seasonal surpluses will continue.

(iv) Low Case 1: The proposed tariff adjustments were brought forward to 2006 for the Kyrgyz Republic and Tajikistan, where the tariff adjustments needed are the highest. The impacts are: the 2003-2025 compounded annual average growth rate (CAGR) of demand is lower by 2.5% (1.85% versus 1.0); the 2025 demand is lower by about 1.1%; and the exportable surplus is higher by 10%. The winter deficits continue to persist despite reduced demand in the Kyrgyz Republic.

(v) Low Case 2: Income elasticity values were reduced in all countries. The impacts are: the 2003-2025 CAGR of demand is lower by 19% (1.54% versus 1.9%); the 2025 demand is lower by about 7%; and the 2025 exportable surplus is higher by 32%. The winter deficits continue to persist in the Kyrgyz Republic and Kazakhstan in the 2005-2010 period, confirming the need for new thermal generation.

(vi) Low Case 3: Price elasticity values were increased in all countries. The impacts are: the 2003-2025 CAGR of demand is lower by 34%% (1.25% versus 1.9%); the 2025 demand is lower by about 13%; and the 2025 exportable surplus is higher by 120%. However, despite the significantly lowered demand, winter deficits continue to persist in the Kyrgyz Republic and Kazakhstan in the 2005-2010 period, confirming the need for new thermal generation.

Table 4.14: Results of Sensitivity Analyses on Demand Forecast

Percentage Change in End-of-Period Demand for every Country 1% Change in

Income Elasticity 1% Change in Price Elasticity

Kazakhstan 0.74 0.08 The Kyrgyz Republic 0.53 0.52 Tajikistan 0.64 0.74 Uzbekistan 0.45 0.22 All four Countries 0.63 0.20

The result of the sensitivity analyses, summarized in Table A4.14 shows that demand growth in the region overall is more sensitive to income elasticity values compared to price elasticity. Over

24

the 2005 – 2025 period, every 1% decrease in income elasticity projected demand would decrease by 0.63% compared to 0.2% change in demand for every 1% change in price elasticity. However, projected demand in individual countries behaves differently. Projected demand in Kazakhstan is more sensitive to changes in income elasticity and least sensitive to changes in price elasticity, confirming the international experience that as incomes grow, electricity demand becomes less and less elastic to price changes. Tajikistan, the poorest of the CARs, is more sensitive to price changes. The changes in the timing of projected tariff increases had only a minor impact on projected demand. The analyses also confirmed that even if demand were to be lower than projected, the new thermal capacity, especially Bishkek II, will still be needed. What would change is the timing of the requirement for the various increments of new generation capacity.

25

Demand Forecasts: Sensitivity Analysis Key Parameters: Base Case

Cost Recovery Tariff Country Price Elasticity Income Elasticity

Level USc/kWh Year Tariffs reach Cost Recovery Level

GDP Growth in 2007-2025 p.a.

Kazakhstan -0.1 0.8 2.90 2006 1.040 The Kyrgyz Republic -0.3 0.8 2.45 2010 1.030 Tajikistan -0.3 0.8 2.10 2010 1.030 Uzbekistan -0.1 0.8 3.50 2006 1.025

Table A4.15: Gross Electricity Demand Projections, Base Case

Actual Demand forecast (GWh) Annual Growth rates Country

2003 2005 2010 2015 2020 2025 2003-2010 2003-2015 2003-2020 2003-2025

Kazakhstan 58,944 62,475 72,056 84,034 98,367 115,146 2.91% 3.00% 3.06% 3.09% The Kyrgyz Republic 12,145 11,069 9,222 10,033 11,296 12,719 -3.86% -1.58% -0.43% 0.21%

Tajikistan 16,348 14,216 11,267 12,410 13,972 15,731 -5.18% -2.27% -0.92% -0.17% Uzbekistan 48,691 45,794 46,597 51,255 56,589 62,479 -0.63% 0.43% 0.89% 1.14% All Four Countries 136,128 133,554 139,142 157,731 180,225 206,075 0.31% 1.24% 1.66% 1.90%

2005 2010 2015 2020 2025Supply 27984 32211 40215 42771 45449Demand 24786 28588 33340 39026 45683Surplus (+) / Deficit (-) 3198 3623 6876 3745 -234Supply 35185 40500 50564 53778 57145Demand 37689 43468 50694 59341 69463Surplus (+) / Deficit (-) -2504 -2969 -130 -5563 -12318Supply 63169 72710 90780 96550 102594Demand 62475 72056 84034 98367 115146Surplus (+) / Deficit (-) 694 654 6746 -1818 -12552

Table A4.16: Kazakhstan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 23482 26149 32104 32104 31918Demand 21862 22245 24469 27016 29827Surplus (+) / Deficit (-) 1620 3904 7635 5088 2091Supply 26794 29837 36632 36632 36419Demand 23932 24352 26786 29574 32652Surplus (+) / Deficit (-) 2862 5485 9846 7058 3767Supply 50277 55986 68736 68736 68337Demand 45794 46597 51255 56589 62479Surplus (+) / Deficit (-) 4483 9389 17481 12147 5858

Table A4.19: Uzbekistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 9158 10821 13581 20176 20176Demand 7648 6233 6814 7597 8479Surplus (+) / Deficit (-) 1511 4587 6767 12579 11697Supply 6665 7875 9883 14683 14683Demand 6569 5033 5596 6375 7252Surplus (+) / Deficit (-) 96 2841 4287 8308 7431Supply 15823 18695 23464 34859 34859Demand 14216 11267 12410 13972 15731Surplus (+) / Deficit (-) 1607 7429 11055 20887 19128

Table A4.18: Tajikistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 7961 8969 9786 9696 9696Demand 3224 2686 2922 3290 3705Surplus (+) / Deficit (-) 4737 6283 6863 6406 5991Supply 5754 8120 8628 13767 13767Demand 7845 6536 7111 8006 9014Surplus (+) / Deficit (-) -2092 1584 1517 5761 4753Supply 13714 17089 18414 23463 23463Demand 11069 9222 10033 11296 12719Surplus (+) / Deficit (-) 2645 7866 8381 12167 10744

Table A4.17: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 68585 78149 95686 104748 107239Demand 57520 59753 67544 76929 87694Surplus (+) / Deficit (-) 11066 18396 28142 27819 19545Supply 74398 86331 105708 118860 122014Demand 76035 79390 90187 103296 118381Surplus (+) / Deficit (-) -1637 6942 15521 15564 3633Supply 142984 164480 201394 223608 229253Demand 133554 139142 157731 180225 206075Surplus (+) / Deficit (-) 9430 25338 43663 43383 23178

Annual

Table A4.20: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025

Year

Summer

Winter

26

Demand Forecast: Sensitivity Analysis Key Parameters: High Case 1

Cost Recovery Tariff Country Price Elasticity Income Elasticity

Level USc/kWh Year Tariffs reach Cost Recovery Level

GDP Growth in 2007-2025 p.a.

Kazakhstan -0.1 0.8 2.90 2006 1.040 The Kyrgyz Republic -0.3 0.8 2.45 2015 1.030 Tajikistan -0.3 0.8 2.10 2015 1.030 Uzbekistan -0.1 0.8 3.50 2006 1.025

Table A4.21: Gross Electricity Demand Projections, High Case 1 Actual Demand forecast (GWh) Annual Growth rates

Country 2003 2005 2010 2015 2020 2025 2003-

2010 2003-2015

2003-2020

2003-2025

Kazakhstan 58,944 62,475 72,056 84,034 98,367 115,146 2.91% 3.00% 3.06% 3.09% The Kyrgyz Republic 12,145 11,409 10,067 10,305 11,528 12,980 -2.65% -1.36% -0.31% 0.30%

Tajikistan 16,348 17,532 15,238 13,771 15,199 17,113 -1.00% -1.42% -0.43% 0.21% Uzbekistan 48,691 45,794 46,597 51,255 56,589 62,479 -0.63% 0.43% 0.89% 1.14% All Four Countries 136,128 137,209 143,958 159,364 181,684 207,718 0.80% 1.32% 1.71% 1.94%

2005 2010 2015 2020 2025Supply 27984 32211 40215 42771 45449Demand 24786 28588 33340 39026 45683Surplus (+) / Deficit (-) 3198 3623 6876 3745 -234Supply 35185 40500 50564 53778 57145Demand 37689 43468 50694 59341 69463Surplus (+) / Deficit (-) -2504 -2969 -130 -5563 -12318Supply 63169 72710 90780 96550 102594Demand 62475 72056 84034 98367 115146Surplus (+) / Deficit (-) 694 654 6746 -1818 -12552

Table A4.22: Kazakhstan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 7961 8969 9786 9696 9696Demand 3323 2932 3001 3358 3781Surplus (+) / Deficit (-) 4638 6037 6784 6338 5915Supply 5754 8120 8628 13767 13767Demand 8086 7135 7303 8171 9199Surplus (+) / Deficit (-) -2332 985 1325 5596 4568Supply 13714 17089 18414 23463 23463Demand 11409 10067 10305 11528 12980Surplus (+) / Deficit (-) 2305 7022 8109 11935 10483

Table A4.23: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 9158 10821 13581 20176 20176Demand 9431 8431 7561 8264 9224Surplus (+) / Deficit (-) -273 2390 6020 11912 10952Supply 6665 7875 9883 14683 14683Demand 8101 6807 6210 6935 7889Surplus (+) / Deficit (-) -1436 1067 3674 7748 6794Supply 15823 18695 23464 34859 34859Demand 17532 15238 13771 15199 17113Surplus (+) / Deficit (-) -1709 3457 9694 19660 17747

Table A4.24: Tajikistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 23482 26149 32104 32104 31918Demand 21862 22245 24469 27016 29827Surplus (+) / Deficit (-) 1620 3904 7635 5088 2091Supply 26794 29837 36632 36632 36419Demand 23932 24352 26786 29574 32652Surplus (+) / Deficit (-) 2862 5485 9846 7058 3767Supply 50277 55986 68736 68736 68337Demand 45794 46597 51255 56589 62479Surplus (+) / Deficit (-) 4483 9389 17481 12147 5858

Table A4.25: Uzbekistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 68585 78149 95686 104748 107239Demand 59402 62196 68371 77664 88515Surplus (+) / Deficit (-) 9183 15953 27315 27084 18725Supply 74398 86331 105708 118860 122014Demand 77807 81762 90993 104020 119203Surplus (+) / Deficit (-) -3409 4569 14715 14840 2811Supply 142983 164480 201394 223608 229253Demand 137209 143958 159364 181684 207718Surplus (+) / Deficit (-) 5774 20522 42030 41924 21536

Winter

Annual

Table A4.26: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025

Year

Summer

27

Demand Forecast: Sensitivity Analysis Key Parameters: High Case 2

Cost Recovery Tariff Country Price Elasticity Income Elasticity

Level USc/kWh Year Tariffs reach Cost Recovery Level

GDP Growth in 2007-2025 p.a.

Kazakhstan -0.1 0.8 2.90 2006 1.040 The Kyrgyz Republic -0.2 0.8 2.45 2010 1.030 Tajikistan -0.2 0.8 2.10 2010 1.030 Uzbekistan -0.1 0.8 3.50 2006 1.025

Table A4.27: Gross Electricity Demand Projections, High Case 2 Actual Demand forecast (GWh) Annual Growth rates

Country 2003 2005 2010 2015 2020 2025 2003-

2010 2003-2015

2003-2020

2003-2025

Kazakhstan 58,944 62,475 72,056 84,034 98,367 115,146 2.91% 3.00% 3.06% 3.09% The Kyrgyz Republic 12,145 11,625 10,815 11,904 13,403 15,090 -1.64% -0.17% 0.58% 0.99%

Tajikistan 16,348 15,699 14,254 15,818 17,809 20,051 -1.94% -0.27% 0.50% 0.93% Uzbekistan 48,691 45,794 46,597 51,255 56,589 62,479 -0.63% 0.43% 0.89% 1.14% All Four Countries 136,128 135,593 143,722 163,010 186,169 212,767 0.78% 1.51% 1.86% 2.05%

2005 2010 2015 2020 2025Supply 27984 32211 40215 42771 45449Demand 24786 28588 33340 39026 45683Surplus (+) / Deficit (-) 3198 3623 6876 3745 -234Supply 35185 40500 50564 53778 57145Demand 37689 43468 50694 59341 69463Surplus (+) / Deficit (-) -2504 -2969 -130 -5563 -12318Supply 63169 72710 90780 96550 102594Demand 62475 72056 84034 98367 115146Surplus (+) / Deficit (-) 694 654 6746 -1818 -12552

Table A4.28: Kazakhstan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 7961 8969 9786 9696 9696Demand 3386 3150 3467 3904 4396Surplus (+) / Deficit (-) 4575 5819 6319 5792 5300Supply 5754 8120 8628 13767 13767Demand 8239 7665 8437 9499 10695Surplus (+) / Deficit (-) -2485 455 191 4268 3072Supply 13714 17089 18414 23463 23463Demand 11625 10815 11904 13403 15090Surplus (+) / Deficit (-) 2090 6273 6510 10060 8373

Table A4.29: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 9158 10821 13581 20176 20176Demand 8446 7886 8685 9683 10808Surplus (+) / Deficit (-) 713 2934 4896 10493 9368Supply 6665 7875 9883 14683 14683Demand 7254 6368 7133 8126 9244Surplus (+) / Deficit (-) -589 1507 2751 6557 5439Supply 15823 18695 23464 34859 34859Demand 15699 14254 15818 17809 20051Surplus (+) / Deficit (-) 124 4441 7647 17050 14808

Table A4.30: Tajikistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 23482 26149 32104 32104 31918Demand 21862 22245 24469 27016 29827Surplus (+) / Deficit (-) 1620 3904 7635 5088 2091Supply 26794 29837 36632 36632 36419Demand 23932 24352 26786 29574 32652Surplus (+) / Deficit (-) 2862 5485 9846 7058 3767Supply 50277 55986 68736 68736 68337Demand 45794 46597 51255 56589 62479Surplus (+) / Deficit (-) 4483 9389 17481 12147 5858

Table A4.31: Uzbekistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 68585 78149 95686 104748 107239Demand 58479 61869 69960 79629 90714Surplus (+) / Deficit (-) 10106 16279 25726 25119 16526Supply 74398 86331 105708 118860 122014Demand 77113 81853 93050 106540 122053Surplus (+) / Deficit (-) -2716 4478 12658 12320 -40Supply 142983 164480 201394 223608 229253Demand 135593 143722 163010 186169 212767Surplus (+) / Deficit (-) 7390 20758 38384 37439 16486

Winter

Annual

Table A4.32: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025

Year

Summer

28

Demand Forecast: Sensitivity Analysis Key Parameters: High Case 3

Cost Recovery Tariff Country Price Elasticity Income Elasticity

Level USc/kWh Year Tariffs reach Cost Recovery Level

GDP Growth in 2007-2025 p.a.

Kazakhstan -0.1 0.9 2.90 2006 1.040 The Kyrgyz Republic -0.3 0.9 2.45 2010 1.030 Tajikistan -0.3 0.9 2.10 2010 1.030 Uzbekistan -0.1 0.9 3.50 2006 1.025

Table A4.33: Gross Electricity Demand Projections, High Case 3 Actual Demand forecast (GWh) Annual Growth rates Country 2003 2005 2010 2015 2020 2025 2003-

2010 2003-2015

2003-2020

2003-2025

Kazakhstan 58,944 63,113 74,549 88,639 105,785 126,248 3.41% 3.46% 3.50% 3.52% The Kyrgyz Republic

12,145 11,137 9,441 10,422 11,908 13,604 -3.53% -1.27% -0.12% 0.52%

Tajikistan 16,348 14,453 11,684 13,059 14,920 17,046 -4.69% -1.85% -0.54% 0.19% Uzbekistan 48,691 46,059 47,547 52,944 59,174 66,138 -0.34% 0.70% 1.15% 1.40% All Four Countries

136,128 134,762 143,220 165,064 191,787 223,035 0.73% 1.62% 2.04% 2.27%

2005 2010 2015 2020 2025Supply 27984 32211 40215 42771 45449Demand 25039 29577 35167 41969 50087Surplus (+) / Deficit (-) 2945 2634 5049 802 -4638Supply 35185 40500 50564 53778 57145Demand 38074 44972 53472 63816 76160Surplus (+) / Deficit (-) -2888 -4472 -2908 -10038 -19015Supply 63169 72710 90780 96550 102594Demand 63113 74549 88639 105785 126248Surplus (+) / Deficit (-) 57 -1839 2140 -9235 -23653

Table A4.34: Kazakhstan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 7961 8969 9786 9696 9696Demand 3244 2750 3036 3468 3963Surplus (+) / Deficit (-) 4717 6219 6750 6228 5733Supply 5754 8120 8628 13767 13767Demand 7893 6691 7387 8439 9642Surplus (+) / Deficit (-) -2139 1429 1241 5327 4125Supply 13714 17089 18414 23463 23463Demand 11137 9441 10422 11908 13604Surplus (+) / Deficit (-) 2577 7648 7991 11555 9859

Table A4.35: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 9158 10821 13581 20176 20176Demand 7775 6464 7170 8112 9188Surplus (+) / Deficit (-) 1383 4356 6411 12064 10989Supply 6665 7875 9883 14683 14683Demand 6678 5219 5889 6807 7858Surplus (+) / Deficit (-) -13 2655 3995 7876 6825Supply 15823 18695 23464 34859 34859Demand 14453 11684 13059 14920 17046Surplus (+) / Deficit (-) 1370 7011 10405 19939 17814

Table A4.36: Tajikistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 23482 26149 32104 32104 31918Demand 21988 22699 25275 28250 31574Surplus (+) / Deficit (-) 1494 3450 6829 3854 344Supply 26794 29837 36632 36632 36419Demand 24071 24848 27669 30925 34564Surplus (+) / Deficit (-) 2723 4989 8963 5707 1855Supply 50277 55986 68736 68736 68337Demand 46059 47547 52944 59174 66138Surplus (+) / Deficit (-) 4218 8439 15792 9562 2199

Table A4.37: Uzbekistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 68585 78149 95686 104748 107239Demand 58047 61490 70648 81799 94812Surplus (+) / Deficit (-) 10539 16659 25038 22948 12428Supply 74398 86331 105708 118860 122014Demand 76715 81731 94417 109987 128224Surplus (+) / Deficit (-) -2318 4600 11291 8873 -6210Supply 142983 164480 201394 223608 229253Demand 134762 143220 165064 191787 223035Surplus (+) / Deficit (-) 8221 21260 36329 31821 6218

Winter

Annual

Table A4.38: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025

Year

Summer

29

Demand Forecast: Sensitivity Analysis Key Parameters: Low Case 1

Cost Recovery Tariff Country Price Elasticity Income Elasticity

Level USc/kWh Year Tariffs reach Cost Recovery Level

GDP Growth in 2007-2025 p.a.

Kazakhstan -0.1 0.8 2.90 2006 1.040 The Kyrgyz Republic -0.3 0.8 2.45 2006 1.030 Tajikistan -0.3 0.8 2.10 2006 1.030 Uzbekistan -0.1 0.8 3.50 2006 1.025

Table A4.39: Gross Electricity Demand Projections, Low Case 1 Actual Demand forecast (GWh) Annual Growth rates

Country 2003 2005 2010 2015 2020 2025 2003-

2010 2003-2015

2003-2020

2003-2025

Kazakhstan 58,944 62,475 72,056 84,034 98,367 115,146 2.91% 3.00% 3.06% 3.09% The Kyrgyz Republic 12,145 11,069 8,813 9,695 10,915 12,290 -4.48% -1.86% -0.63% 0.05%

Tajikistan 16,348 14,216 9,809 10,896 12,268 13,812 -7.04% -3.32% -1.67% -0.76% Uzbekistan 48,691 45,794 46,597 51,255 56,589 62,479 -0.63% 0.43% 0.89% 1.14% All Four Countries 136,128 133,554 137,275 155,879 178,140 203,728 0.12% 1.14% 1.59% 1.85%

2005 2010 2015 2020 2025Supply 27984 32211 40215 42771 45449Demand 24786 28588 33340 39026 45683Surplus (+) / Deficit (-) 3198 3623 6876 3745 -234Supply 35185 40500 50564 53778 57145Demand 37689 43468 50694 59341 69463Surplus (+) / Deficit (-) -2504 -2969 -130 -5563 -12318Supply 63169 72710 90780 96550 102594Demand 62475 72056 84034 98367 115146Surplus (+) / Deficit (-) 694 654 6746 -1818 -12552

Table A4.40: Kazakhstan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 7961 8969 9786 9696 9696Demand 3224 2567 2824 3179 3580Surplus (+) / Deficit (-) 4737 6402 6962 6517 6116Supply 5754 8120 8628 13767 13767Demand 7845 6246 6871 7736 8710Surplus (+) / Deficit (-) -2092 1874 1757 6031 5057Supply 13714 17089 18414 23463 23463Demand 11069 8813 9695 10915 12290Surplus (+) / Deficit (-) 2645 8276 8719 12547 11173

Table A4.41: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 9158 10821 13581 20176 20176Demand 7648 5427 5983 6670 7445Surplus (+) / Deficit (-) 1511 5394 7598 13506 12731Supply 6665 7875 9883 14683 14683Demand 6569 4382 4913 5597 6368Surplus (+) / Deficit (-) 96 3493 4970 9086 8315Supply 15823 18695 23464 34859 34859Demand 14216 9809 10896 12268 13812Surplus (+) / Deficit (-) 1607 8886 12568 22591 21047

Table A4.42: Tajikistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 23482 26149 32104 32104 31918Demand 21862 22245 24469 27016 29827Surplus (+) / Deficit (-) 1620 3904 7635 5088 2091Supply 26794 29837 36632 36632 36419Demand 23932 24352 26786 29574 32652Surplus (+) / Deficit (-) 2862 5485 9846 7058 3767Supply 50277 55986 68736 68736 68337Demand 45794 46597 51255 56589 62479Surplus (+) / Deficit (-) 4483 9389 17481 12147 5858

Table A4.43: Uzbekistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 68585 78149 95686 104748 107239Demand 57520 58827 66615 75892 86535Surplus (+) / Deficit (-) 11066 19322 29071 28856 20704Supply 74398 86331 105708 118860 122014Demand 76035 78448 89265 102249 117193Surplus (+) / Deficit (-) -1637 7883 16443 16611 4821Supply 142983 164480 201394 223608 229253Demand 133554 137275 155879 178140 203728Surplus (+) / Deficit (-) 9429 27205 45515 45468 25526

Winter

Annual

Table A4.44: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025

Year

Summer

30

Demand Forecast: Sensitivity Analysis Key Parameters: Low case 2

Cost Recovery Tariff Country Price Elasticity Income Elasticity

Level USc/kWh Year Tariffs reach Cost Recovery Level

GDP Growth in 2007-2025 p.a.

Kazakhstan -0.1 0.7 2.90 2006 1.040 The Kyrgyz Republic -0.3 0.7 2.45 2010 1.030 Tajikistan -0.3 0.7 2.10 2010 1.030 Uzbekistan -0.1 0.7 3.50 2006 1.025

Table A4.45: Gross Electricity Demand Projections, Low Case 2 Actual Demand forecast (GWh) Annual Growth rates

Country 2003 2005 2010 2015 2020 2025 2003-

2010 2003-2015

2003-2020

2003-2025

Kazakhstan 58,944 61,840 69,634 79,646 91,439 104,978 2.41% 2.54% 2.62% 2.66% The Kyrgyz Republic 12,145 11,002 9,008 9,657 10,715 11,888 -4.18% -1.89% -0.73% -0.10%

Tajikistan 16,348 13,981 10,861 11,788 13,079 14,512 -5.67% -2.69% -1.30% -0.54% Uzbekistan 48,691 45,529 45,663 49,615 54,111 59,014 -0.91% 0.16% 0.62% 0.88% All Four Countries 136,128 132,352 135,167 150,706 169,343 190,391 -0.10% 0.85% 1.29% 1.54%

2005 2010 2015 2020 2025Supply 27984 32211 40215 42771 45449Demand 24534 27627 31599 36278 41649Surplus (+) / Deficit (-) 3450 4584 8616 6494 3800Supply 35185 40500 50564 53778 57145Demand 37306 42007 48047 55161 63329Surplus (+) / Deficit (-) -2120 -1507 2517 -1383 -6184Supply 63169 72710 90780 96550 102594Demand 61840 69634 79646 91439 104978Surplus (+) / Deficit (-) 1329 3076 11133 5111 -2384

Table A4.46: Kazakhstan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 7961 8969 9786 9696 9696Demand 3205 2624 2813 3121 3463Surplus (+) / Deficit (-) 4756 6345 6973 6575 6233Supply 5754 8120 8628 13767 13767Demand 7798 6385 6844 7594 8425Surplus (+) / Deficit (-) -2044 1736 1784 6173 5342Supply 13714 17089 18414 23463 23463Demand 11002 9008 9657 10715 11888Surplus (+) / Deficit (-) 2712 8080 8757 12748 11575

Table A4.47: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 9158 10821 13581 20176 20176Demand 7521 6009 6473 7112 7822Surplus (+) / Deficit (-) 1637 4811 7108 13065 12354Supply 6665 7875 9883 14683 14683Demand 6460 4852 5316 5968 6690Surplus (+) / Deficit (-) 205 3023 4568 8715 7993Supply 15823 18695 23464 34859 34859Demand 13981 10861 11788 13079 14512Surplus (+) / Deficit (-) 1843 7834 11676 21780 20348

Table A4.48 Tajikistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 23482 26149 32104 32104 31918Demand 21735 21799 23686 25832 28173Surplus (+) / Deficit (-) 1747 4350 8418 6272 3745Supply 26794 29837 36632 36632 36419Demand 23793 23864 25929 28278 30841Surplus (+) / Deficit (-) 3001 5973 10703 8354 5578Supply 50277 55986 68736 68736 68337Demand 45529 45663 49615 54111 59014Surplus (+) / Deficit (-) 4748 10323 19121 14625 9323

Table A4.49: Uzbekistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 68585 78149 95686 104748 107239Demand 56995 58059 64570 72342 81106Surplus (+) / Deficit (-) 11590 20090 31116 32406 26133Supply 74398 86331 105708 118860 122014Demand 75357 77107 86136 97001 109285Surplus (+) / Deficit (-) -959 9224 19571 21859 12729Supply 142983 164480 201394 223608 229253Demand 132352 135167 150706 169343 190391Surplus (+) / Deficit (-) 10631 29314 50687 54264 38862

Winter

Annual

Table A4.50: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025

Year

Summer

31

Demand Forecast: Sensitivity Analysis Key Parameters: Low case 3

Cost Recovery Tariff Country Price Elasticity Income Elasticity

Level USc/kWh Year Tariffs reach Cost Recovery Level

GDP Growth in 2007-2025 p.a.

Kazakhstan -0.2 0.8 2.90 2006 1.040 The Kyrgyz Republic -0.4 0.8 2.45 2010 1.030 Tajikistan -0.4 0.8 2.10 2010 1.030 Uzbekistan -0.2 0.8 3.50 2006 1.025

Table A4.51: Gross Electricity Demand Projections, Low Case 3 Actual Demand forecast (GWh) Annual Growth rates

Country 2003 2005 2010 2015 2020 2025 2003-

2010 2003-2015

2003-2020

2003-2025

Kazakhstan 58,944 60,883 66,563 77,335 90,526 105,968 1.75% 2.29% 2.56% 2.70% The Kyrgyz Republic 12,145 10,526 7,830 8,418 9,478 10,671 -6.08% -3.01% -1.45% -0.59%

Tajikistan 16,348 12,789 8,799 9,618 10,829 12,192 -8.47% -4.32% -2.39% -1.32% Uzbekistan 48,691 40,750 37,388 40,969 45,233 49,941 -3.70% -1.43% -0.43% 0.12% All Four Countries 136,128 124,948 120,580 136,340 156,066 178,772 -1.72% 0.01% 0.81% 1.25%

2005 2010 2015 2020 2025Supply 27984 32211 40215 42771 45449Demand 24155 26408 30682 35916 42041Surplus (+) / Deficit (-) 3830 5802 9533 6856 3408Supply 35185 40500 50564 53778 57145Demand 36729 40154 46653 54611 63926Surplus (+) / Deficit (-) -1543 345 3911 -833 -6781Supply 63169 72710 90780 96550 102594Demand 60883 66563 77335 90526 105968Surplus (+) / Deficit (-) 2286 6148 13445 6023 -3374

Table A4.52: Kazakhstan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 7961 8969 9786 9696 9696Demand 3066 2281 2452 2760 3108Surplus (+) / Deficit (-) 4895 6688 7334 6936 6588Supply 5754 8120 8628 13767 13767Demand 7460 5550 5966 6717 7563Surplus (+) / Deficit (-) -1706 2570 2662 7049 6204Supply 13714 17089 18414 23463 23463Demand 10526 7830 8418 9478 10671Surplus (+) / Deficit (-) 3189 9258 9996 13985 12792

Table A4.53: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 9158 10821 13581 20176 20176Demand 6880 4868 5281 5888 6572Surplus (+) / Deficit (-) 2279 5952 8300 14288 13605Supply 6665 7875 9883 14683 14683Demand 5909 3931 4337 4941 5620Surplus (+) / Deficit (-) 756 3944 5546 9742 9063Supply 15823 18695 23464 34859 34859Demand 12789 8799 9618 10829 12192Surplus (+) / Deficit (-) 3034 9896 13847 24031 22667

Table A4.54 Tajikistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 23482 26149 32104 32104 31918Demand 19454 17849 19558 21594 23842Surplus (+) / Deficit (-) 4028 8300 12546 10510 8076Supply 26794 29837 36632 36632 36419Demand 21296 19539 21411 23639 26099Surplus (+) / Deficit (-) 5498 10298 15221 12993 10320Supply 50277 55986 68736 68736 68337Demand 40750 37388 40969 45233 49941Surplus (+) / Deficit (-) 9527 18598 27767 23503 18396

Table A4.55: Uzbekistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 68585 78149 95686 104748 107239Demand 53554 51406 57973 66158 75563Surplus (+) / Deficit (-) 15031 26743 37713 38590 31676Supply 74398 86331 105708 118860 122014Demand 71394 69174 78367 89908 103209Surplus (+) / Deficit (-) 3004 17158 27341 28952 18805Supply 142983 164480 201394 223608 229253Demand 124948 120580 136340 156066 178772Surplus (+) / Deficit (-) 18036 43901 65054 67542 50481

Winter

Annual

Table A4.56: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025

Year

Summer

32

Demand Forecast: Sensitivity Analysis Key Parameters: Alternative Demand case

Changes in Electricity Intensity p.a. in % Country 2005-2009 2010-2014 2015-2025

Kazakhstan -2.0 -1.5 -1.0 The Kyrgyz Republic -2.0 -1.5 -1.0 Tajikistan -2.0 -1.5 -1.0 Uzbekistan -2.0 -1.5 -1.0

Table A4.57: Gross Electricity Demand Projections, Alternative Scenario

Actual Demand forecast (GWh) Annual Growth rates Country

2003 2010 2015 2020 2025 2003-2010

2003-2015

2003-2020 2003-2025

Kazakhstan 58,994 75,706 85,837 99,316 114,911 3.63% 3.17% 3.11% 3.08% The Kyrgyz Republic 12,145 13,915 15,033 16,573 18,271 1.96% 1.79% 1.85% 1.87% Tajikistan 16,348 21,485 23,211 25,589 28,211 3.98% 2.96% 2.67% 2.51% Uzbekistan 48,691 53,828 56,756 61,067 65,705 1.44% 1.29% 1.34% 1.37% All Four Countries 136,178 164,934 180,837 202,545 227,099 2.77% 2.39% 2.36% 2.35%

2005 2010 2015 2020 2025Supply 7961 8969 9786 9696 9696Demand 3538 4053 4378 4827 5322Surplus (+) / Deficit (-) 4423 4916 5407 4869 4374Supply 5754 8120 8628 13767 13767Demand 9410 9862 10655 11746 12949Surplus (+) / Deficit (-) -3657 -1742 -2026 2021 818Supply 13714 17089 18414 23463 23463Demand 12948 13915 15033 16573 18271Surplus (+) / Deficit (-) 766 3174 3381 6890 5191

Table A4.59: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 9158 10821 13581 20176 20176Demand 8794 11887 12744 13914 15206Surplus (+) / Deficit (-) 364 -1066 837 6263 4970Supply 6665 7875 9883 14683 14683Demand 10897 9598 10467 11676 13005Surplus (+) / Deficit (-) -4232 -1723 -583 3007 1678Supply 15823 18695 23464 34859 34859Demand 19691 21485 23211 25589 28211Surplus (+) / Deficit (-) -3868 -2790 253 9270 6648

Table A4.60 Tajikistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 23482 26149 32104 32104 31918Demand 23245 25697 27095 29153 31368Surplus (+) / Deficit (-) 237 452 5009 2951 550Supply 26794 29837 36632 36632 36419Demand 28366 28131 29661 31914 34338Surplus (+) / Deficit (-) -1572 1706 6971 4718 2081Supply 50276 55986 68736 68736 68337Demand 51611 53828 56756 61067 65705Surplus (+) / Deficit (-) -1335 2158 11980 7669 2632

Table A4.61: Uzbekistan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 27984 32211 40215 42771 45449Demand 23405 30036 34055 39403 45589Surplus (+) / Deficit (-) 4579 2175 6160 3369 -140Supply 35185 40500 50564 53778 57145Demand 42854 45670 51782 59913 69321Surplus (+) / Deficit (-) -7669 -5170 -1218 -6135 -12176Supply 63169 72710 90780 96550 102594Demand 66259 75706 85837 99316 114911Surplus (+) / Deficit (-) -3090 -2995 4943 -2766 -12317

Table A4.58: Kazakhstan. Electricity Demand Supply Balance in 2005-2025

Year

Summer

Winter

Annual

2005 2010 2015 2020 2025Supply 68585 78149 95686 104748 107239Demand 58982 71673 78273 87296 97485Surplus (+) / Deficit (-) 9603 6476 17413 17451 9754Supply 74398 86331 105708 118860 122014Demand 91527 93261 102564 115249 129614Surplus (+) / Deficit (-) -17129 -6930 3144 3611 -7600Supply 142983 164480 201394 223608 229253Demand 150509 164934 180837 202545 227099Surplus (+) / Deficit (-) -7526 -454 20557 21063 2155

Winter

Annual

Table A4.62: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025

Year

Summer

33

Appendix 4.2 Central Asia

Regional Electricity Export Potential Study Incremental and Total Supplies from Supply Options

The incremental and total power supplies available from the supply options in each of the countries are presented in this Annex. The supply options to meet the projected demand include (a) projects for rehabilitation of the transmission and distribution system to reduce the high level of T&D losses; (b) projects for rehabilitating the existing generating units; and (c) construction of new generating plants.

Table A4.63: Kazakhstan. Incremental Power Supply and Total Supply (GWh)

Incremental Supply from Investment Projects in:

Year Transmission

and Distribution

Ekibastuz GRES-1

Rehabilitation

Other TPPs' Units

Rehabilitation

New Generation

Units

Total Kazakhstan

Supply

Current Generation 61,500

2004 835 - - - 62,335 2005 1,669 - - - 63,169 2006 2,504 - - - 64,004 2007 3,339 - 856 - 65,695 2008 4,174 - 2,225 - 67,899 2009 5,008 - 3,595 - 70,103 2010 5,843 403 4,964 72,710 2011 5,843 3,224 6,334 76,901 2012 5,843 6,447 7,703 81,493 2013 5,843 11,283 9,072 87,698 2014 5,843 11,283 10,613 89,239 2015 5,843 11,283 12,154 90,780 2016 5,843 11,283 13,694 92,320 2017 5,843 11,283 15,406 94,032 2018 5,843 11,283 17,118 95,744 2019 5,843 11,283 17,118 95,744 2020 5,843 11,283 17,118 806 96,550 2021 5,843 11,283 17,118 4,231 99,975 2022 5,843 11,283 17,118 6,850 102,594 2023 5,843 11,283 17,118 6,850 102,594 2024 5,843 11,283 17,118 6,850 102,594 2025 5,843 11,283 17,118 6,850 102,594

34

Table A4.64: The Kyrgyz Republic. Incremental Power Supply and Total Supply (GWh)

Incremental Supply from Investment Projects in: Year Transmission and

Distribution Bishkek CHP-

2 Kambarata 2

HPP Kambarata 1

HPP

Total Kyrgyzstan Gross Supply

Current Generation 13,342

2004 184 - - - 13,526 2005 372 - - - 13,714 2006 566 - - - 13,908 2007 764 353 - - 14,459 2008 968 1,531 - - 15,841 2009 1,177 2,355 - - 16,874 2010 1,392 2,355 - - 17,089 2011 1,612 2,355 - - 17,309 2012 1,612 2,355 221 - 17,530 2013 1,612 2,355 1,105 - 18,414 2014 1,612 2,355 1,105 - 18,414 2015 1,612 2,355 1,105 - 18,414 2016 1,612 2,355 1,105 - 18,414 2017 1,612 2,355 1,105 252 18,666 2018 1,612 2,355 1,105 1,515 19,929 2019 1,612 2,355 1,105 3,029 21,443 2020 1,612 2,355 1,105 5,049 23,463 2021 1,612 2,355 1,105 5,049 23,463 2022 1,612 2,355 1,105 5,049 23,463 2023 1,612 1,183 1,105 5,049 22,291 2024 1,612 1,183 1,105 5,049 22,291 2025 1,612 2,355 1,105 5,049 23,463

Notes: The current generation shown (13,342 GWh) is the average generation over the 1999-2003 period, which included a good combination of normal, wet and dry hydrological years. Also it encompasses the modified irrigation mode (recommended for Toktogul operation) since modified mode is a split in seasonal generation and there would not be a change in annual generation.

35

Table A4.65: Tajikistan. Incremental Power Supply and Total Supply (GWh)

Incremental supply from Investment Projects in: Year Transmission &

Distribution DSM Sangtuda I HPP Rogun HPP, Phase I and II Total Tajikistan Supply

Current Generation 15,181

2004 266 - - - 15,447 2005 537 105 - - 15,823 2006 815 225 - - 16,221 2007 1,099 523 - - 16,803 2008 1,389 572 - - 17,142 2009 1,685 631 134 - 17,631 2010 1,988 724 802 - 18,695 2011 1,988 751 1,470 - 19,390 2012 1,988 778 2,138 - 20,085 2013 1,988 806 2,673 - 20,648 2014 1,988 833 2,673 515 21,190 2015 1,988 860 2,673 2,762 23,464 2016 1,988 860 2,673 4,643 25,345 2017 1,988 860 2,673 5,282 25,984 2018 1,988 860 2,673 7,712 28,414 2019 1,988 860 2,673 10,712 31,414 2020 1,988 860 2,673 14,157 34,859 2021 1,988 860 2,673 14,157 34,859 2022 1,988 860 2,673 14,157 34,859 2023 1,988 860 2,673 14,157 34,859 2024 1,988 860 2,673 14,157 34,859 2025 1,988 860 2,673 14,157 34,859

Notes: • The current generation shown (15,181 GWh) is the average generation over the 1999-2003 period, which included a good combination

of different hydrological years. • DSM involves shifting space heating load away from electricity.

36

Table A4.66: Uzbekistan. Incremental Power Supply and Total Supply (GWh)

Incremental supply from Investment Projects in: Retirement Year Transmission and

Distribution Talimarjan TPP

Unit #1 Talimarjan TPP Units

#2-4 Loss of Capacity

MW Loss of Generation

GWh

Total Uzbekistan Supply

2003 48,700 2004 555 - 49,255 2005 1,118 609 250 (151) 50,277 2006 1,690 1,828 110 (435) 51,783 2007 2,270 4,265 100 (849) 54,387 2008 2,860 4,265 160 (1,044) 54,781 2009 3,457 4,265 - (1,044) 55,379 2010 4,064 4,265 - (1,044) 55,986 2011 4,064 4,265 609 - (1,044) 56,595 2012 4,064 4,265 2,437 - (1,044) 58,423 2013 4,064 4,265 6,703 55 (1,067) 62,665 2014 4,064 4,265 10,359 - (1,067) 66,322 2015 4,064 4,265 12,796 55 (1,090) 68,736 2016 4,064 4,265 12,796 - (1,090) 68,736 2017 4,064 4,265 12,796 - (1,090) 68,736 2018 4,064 4,265 12,796 - (1,090) 68,736 2019 4,064 4,265 12,796 - (1,090) 68,736 2020 4,064 4,265 12,796 - (1,090) 68,736 2021 4,064 4,265 12,796 110 (1,489) 68,337 2022 4,064 4,265 12,796 - (1,489) 68,337 2023 4,064 4,265 12,796 - (1,489) 68,337 2024 4,064 4,265 12,796 - (1,489) 68,337 2025 4,064 4,265 12,796 - (1,489) 68,337

37

Table A4.67: All Four CA Republics. Incremental Power Supply and Total Supply (GWh)

From Power Investment Program Year Kazakhstan The Kyrgyz

Republic Tajikistan Uzbekistan Total CA Supply

Current Generation 61,500 13,342 15,181 48,700 138,723

2004 62,335 13,526 15,447 49,255 140,563 2005 63,169 13,714 15,823 50,277 142,983 2006 64,004 13,908 16,221 51,783 145,916 2007 65,695 14,459 16,803 54,386 151,343 2008 67,899 15,841 17,142 54,781 155,663 2009 70,103 16,874 17,631 55,378 159,986 2010 72,710 17,089 18,695 55,986 164,480 2011 76,901 17,309 19,390 56,595 170,195 2012 81,493 17,530 20,085 58,423 177,531 2013 87,698 18,414 20,648 62,666 189,426 2014 89,239 18,414 21,190 66,322 195,165 2015 90,780 18,414 23,464 68,736 201,394 2016 92,320 18,414 25,345 68,736 204,815 2017 94,032 18,666 25,984 68,736 207,418 2018 95,744 19,929 28,414 68,736 212,823 2019 95,744 21,443 31,414 68,736 217,337 2020 96,550 23,463 34,859 68,736 223,608 2021 99,975 23,463 34,859 68,337 226,634 2022 102,594 23,463 34,859 68,337 229,253 2023 102,594 22,291 34,859 68,337 228,081 2024 102,594 22,291 34,859 68,337 228,081 2025 102,594 23,463 34,859 68,337 229,253

38

Appendix 4.3

Central Asia Regional Electricity Export Potential Study

Electricity Demand Supply Balances The supplies from the supply options are matched with the projected demand (Base Case) for each of the CARs to arrive at the demand supply balances both on a seasonal (summer and winter) and annual basis in this Annex. Kazakhstan Supply Demand Balances

Table A4.68: Kazakhstan. Electricity Demand Supply Balance in 2003-2025 Year 2003 2005 2010 2015 2020 2025

Supply 27245 27984 32211 40215 42771 45449 Demand 23385 24786 28588 33340 39026 45683 Summer

Surplus (+) / Deficit (-) 3859 3198 3623 6876 3745 -234 Supply 34256 35185 40500 50564 53778 57145 Demand 35559 37689 43468 50694 59341 69463 Winter

Surplus (+) / Deficit (-) -1303 -2504 -2969 -130 -5563 -12318 Supply 61500 63169 72710 90780 96550 102594 Demand 58944 62475 72056 84034 98367 115146 Annual

Surplus (+) / Deficit (-) 2556 694 654 6746 -1818 -12552

Figure A4.2: Summer

0 20000 40000 60000

2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.3: Winter

020000400006000080000

2005 2010 2015 2020 2025

GWh

Supply Demand Figure A4.4: Annual

0

50000

100000

150000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.5: Export Surplus

-16000-12000-8000-4000

040008000

2005 2010 2015 2020 2025

GWh

Summer Winter

39

The Kyrgyz Republic Supply Demand Balances

Table A4.69: The Kyrgyz Republic Electricity Demand Supply Balance in 2003-2025 Year 2003 2005 2010 2015 2020 2025

Supply 4430 7961 8969 9786 9696 9696 Demand 3538 3224 2686 2922 3290 3705 Summer

Surplus (+) / Deficit (-) 892 4737 6282 6863 6406 5991 Supply 8912 5754 8120 8628 13767 13767 Demand 8607 7845 6536 7111 8006 9014 Winter

Surplus (+) / Deficit (-) 305 -2092 1584 1517 5761 4753 Supply 13342 13714 17089 18414 23463 23463 Demand 12145 11069 9222 10033 11296 12719 Annual

Surplus (+) / Deficit (-) 1197 2645 7866 8381 12167 10744

Figure A4.6: Summer

0 5000

10000 15000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.7: Winter

05000

1000015000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.8: Annual

0 10000 20000 30000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.9: Export Surplus

-4000

0

4000

8000

2003 2005 2010 2015 2020 2025

GWh

Summer Winter

40

Tajikistan Supply Demand Balances

Table A4.70: Tajikistan Electricity Demand Supply Balance in 2003-2025 Year 2003 2005 2010 2015 2020 2025

Supply 8835 9158 10821 13581 20176 20176 Demand 8794 7648 6233 6814 7597 8479 Summer

Surplus (+) / Deficit (-) 41 1511 4587 6767 12579 11697 Supply 6346 6665 7875 9883 14683 14683 Demand 7554 6569 5033 5596 6375 7252 Winter

Surplus (+) / Deficit (-) -1208 96 2841 4287 8308 7431 Supply 15181 15823 18695 23464 34859 34859 Demand 16348 14216 11267 12410 13972 15731 Annual

Surplus (+) / Deficit (-) -1167 1607 7429 11055 20887 19128

Figure A4.10: Summer

0 10000 20000 30000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.11: Winter

05000

100001500020000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.12: Annual

0 20000 40000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.13: Export Surplus

-40000

40008000

1200016000

2003 2005 2010 2015 2020 2025

GWh

Summer Winter

41

Uzbekistan Supply Demand Balances

Table A4.71: Uzbekistan Electricity Demand Supply Balance in 2003-2025 Year 2003 2005 2010 2015 2020 2025

Supply 22746 23482 26149 32104 32104 31918 Demand 23245 21862 22245 24468 27015 29827 Summer

Surplus (+) / Deficit (-) -499 1620 3904 7636 5089 2091 Supply 25,954 26,795 29,837 36,632 36,632 36,419 Demand 25,446 23,932 24,352 26,786 29,574 32,652 Winter

Surplus (+) / Deficit (-) 508 2863 5484 9846 7058 3767 Supply 48,700 50,277 55,986 68,736 68,736 68,337 Demand 48,691 45,794 46,597 51,255 56,589 62,479 Annual

Surplus (+) / Deficit (-) 9 4483 9388 17481 12147 5858

Figure A4.14: Summer

0 10000 20000 30000 40000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.15: Winter

0

10000

20000

30000

40000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand Figure A4.16: Annual

0 20000 40000 60000 80000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.17: Export Surplus

-4000

0

4000

8000

12000

2003 2005 2010 2015 2020 2025

GWh

Summer Winter

42

All Four CA Countries Supply Demand Balances

Table A4.72: All Four CA Countries Electricity Demand Supply Balance in 2003-2025 Year 2003 2005 2010 2015 2020 2025

Supply 63255 68585 78149 95686 104748 107239 Demand 58962 57519 59752 67544 76929 87694 Summer

Surplus (+) / Deficit (-) 4293 11066 18396 28142 27819 19546 Supply 75468 74399 86331 105708 118860 122014 Demand 77166 76035 79390 90187 103296 118381 Winter

Surplus (+) / Deficit (-) -1698 -1636 6941 15521 15564 3633 Supply 138723 142984 164480 201394 223608 229253 Demand 136128 133554 139142 157731 180225 206075 Annual

Surplus (+) / Deficit (-) 2595 9429 25338 43663 43383 23178

Figure A4.18: Summer

0 50000

100000 150000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.19: Winter

0

50000

100000

150000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.20: Annual

0 50000

100000 150000 200000 250000

2003 2005 2010 2015 2020 2025

GWh

Supply Demand

Figure A4.21: Export Surplus

-80000

8000160002400032000

2003 2005 2010 2015 2020 2025

GWh

Summer Winter

43

Appendix 5.1

Central Asia Regional Electricity Export Potential Study

Economic Analysis of Supply Options Economic costs of output from each of the supply options are derived in this Appendix. The key determinants are annual phasing of capital expenditures, fuel costs (where applicable), operation and maintenance (O&M) costs, as well as incremental sales (as losses are reduced) in the case of transmission and distribution investments and the energy sent out from the generating station (i.e., gross energy generated minus station use or auxiliary consumption) in the case of generation plants.12 Fuel costs are computed on the basis of gas prices at $35/KCM (the current traded price of Uzbek gas to Kazakhstan)13; and coal prices at $20/ton (the current border price for Kazakh coal to Kyrgyz). To arrive at the economic output cost per kWh, the capital, fuel and O&M costs incurred and energy sent out by the plant each year (GWh) are discounted over a 20-year period to the present using a discount rate of 10% (which is considered the opportunity cost of capital in CARs) and discounted costs are divided by the discounted electricity units sent out.

12 It is important to note that in respect of all the partially completed projects, all costs incurred so far in the past are treated as sunk costs and are ignored for the purposes of this analysis, which essentially compares incremental costs to be incurred with the benefits that will accrue. 13 These prices indeed are low compared to the international prices of $80-120/KCM (e.g., long-term contract price of Gazprom to Western Europe), and the difference reflects the penalty that Uzbekistan pays for being land-locked, and for being far away from creditworthy markets.

44

A. Loss Reduction in Transmission and Distribution Systems

1. Kazakhstan During 2004-2010, Kazakhstan plans to invest $258 million in transmission rehabilitation to reduce losses and to improve the reliability of its electricity supply.14 Its distribution rehabilitation investment needs are estimated at $1,038 million at the rate of $250 per low

Table A5.1: Kazakhstan. AIC for T&D Rehabilitation

Calendar Year Capital Investment ($ million)

Incremental O&M Costs ($ million)

Total Incremental Costs ($ million) Incremental Sales GWh

2003 2004 129.6 2.6 132.2 835 2005 194.4 6.5 200.9 1669 2006 194.4 10.4 204.8 2504 2007 194.4 14.3 208.7 3339 2008 194.4 16.2 210.6 4174 2009 194.4 18.1 212.6 5008 2010 194.4 20.1 214.5 5843 2011 20.1 20.1 5843 2012 20.1 20.1 5843 2013 20.1 20.1 5843 2014 20.1 20.1 5843 2015 20.1 20.1 5843 2016 20.1 20.1 5843 2017 20.1 20.1 5843 2018 20.1 20.1 5843 2019 20.1 20.1 5843 2020 20.1 20.1 5843 2021 20.1 20.1 5843 2022 20.1 20.1 5843 2023 20.1 20.1 5843

Present Values Incremental Costs ($ million) discounted at 10% 1016.7Incremental Sales (million kWh) discounted at 10% 36016

Average Incremental Costs (¢/kWh) 2.8

voltage consumer connection for 4,152,470 households.15 Incremental O&M expenditures are assumed at 2% of Capital Expenditure in year 1 through 4, but declining to 1% in year 5 through 716. The system losses are expected to come down from the present levels of 24% to 15% by 2010. The economic cost of additional supply resulting from the loss reduction project is estimated at 2.8 cents/kWh as shown in Table A5.1 by discounting incremental costs and incremental supplies at 10%.

14 This is the on-going World Bank and EBRD funded project 15 DFID, IPA Energy Consulting, the Kyrgyz Republic, Azerbaijan, Georgia, Investigations on Electricity Distribution Capital Expenditures Requirements. See also USAID, Regional Review of Social Safety Net Approaches, Annex 5, Energy Reform and Social Protection in Kazakhstan 16 WB’s estimate

45

2. The Kyrgyz Republic During 2004-2010, the Kyrgyz Republic would spend $250 million in transmission and distribution rehabilitation to reduce technical losses from the present level of 34% to 13% by 2010. Almost the whole of this investment would be in the distribution system. Incremental O&M expenditures are assumed at 4% of Capital Expenditures in year 1, declining to 3% in year 2, and stabilizing at 2% year 3 onwards. The economic cost of additional supply arising from this project is estimated at 2.3 cents/kWh as shown in Table A5.2.

Table A5.2: The Kyrgyz Republic. AIC for T&D Rehabilitation

Calendar Year Capital Investment ($ million)

Incremental O&M Costs ($ million)

Total Incremental Costs ($ million) Incremental Sales GWh

2003 2004 20.0 0.8 20.8 184 2005 30.0 1.7 31.7 372 2006 50.0 2.7 52.7 566 2007 60.0 3.9 63.9 764 2008 50.0 4.9 54.9 968 2009 30.0 5.5 35.5 1177 2010 10.0 5.7 15.7 1392 2011 5.7 5.7 1612 2012 5.7 5.7 1612 2013 5.7 5.7 1612 2014 5.7 5.7 1612 2015 5.7 5.7 1612 2016 5.7 5.7 1612 2017 5.7 5.7 1612 2018 5.7 5.7 1612 2019 5.7 5.7 1612 2020 5.7 5.7 1612 2021 5.7 5.7 1612 2022 5.7 5.7 1612 2023 5.7 5.7 1612

Present Values Incremental Costs (US$ million) 211.3Incremental Sales (million kWh) 9280

Average Incremental Costs (cents/kWh) 2.3

46

3. Tajikistan During 2004-2010, total investment in transmission and distribution rehabilitation in Tajikistan for reducing technical losses from the present level of 28% to 13% by 2010 is estimated at US$310 million. Incremental O&M expenditures are estimated at 4% of capital expenditures in year 1 through 5, declining to 3% in year 6, and to 2% in year 7. On this basis the economic cost of the additional supply is estimated at 2.1 cents/kWh as shown in Table A5.3.

Table A5.3: Tajikistan. AIC for T&D Rehabilitation

Calendar Year Capital Investment ($ million)

Incremental O&M Costs ($ million)

Total Incremental Costs ($ million) Incremental Sales GWh

2003 2004 8.0 0.3 8.3 266 2005 17.0 1.0 18.0 537 2006 38.0 2.5 40.5 815 2007 55.0 4.7 59.7 1099 2008 59.0 7.1 66.1 1389 2009 65.0 9.0 74.0 1685 2010 68.0 10.4 78.4 1988 2011 10.4 10.4 1988 2012 10.4 10.4 1988 2013 10.4 10.4 1988 2014 10.4 10.4 1988 2015 10.4 10.4 1988 2016 10.4 10.4 1988 2017 10.4 10.4 1988 2018 10.4 10.4 1988 2019 10.4 10.4 1988 2020 10.4 10.4 1988 2021 10.4 10.4 1988 2022 10.4 10.4 1988 2023 10.4 10.4 1988

Present Values Incremental Costs (US$ million) 254.6Incremental Sales (million kWh) 12129

Average Incremental Costs (cents/kWh) 2.1

47

4. Uzbekistan

Transmission rehabilitation investments are estimated at $125 million, based on a loan from ADB for this purpose. The distribution rehabilitation needs are estimated at $ 1,028 on the basis of an investment at the rate of $250 per consumer connection for 4,111,860 households to reduce system losses from the present level of losses of 22% to 15% by 2010. Incremental O&M expenditure is assumed at 4% of the capital expenditures in year 1 through 2, declining to 3% in year 3 through 5, and to 2% in year 6 through 10. The economic cost of additional supplies are estimated at 3.5 cents/kWh.

Table A5.4: Uzbekistan. AIC for T&D Rehabilitation

Calendar Year Capital Investment ( $ million)

Incremental O&M Costs ($ million)

Total Incremental Costs ($ million) Incremental Sales (GWh)

2003 2004 57.6 2.3 60.0 555 2005 115.3 6.9 122.2 1118 2006 115.3 10.4 125.7 1690 2007 115.3 13.8 129.1 2270 2008 172.9 19.0 192.0 2860 2009 172.9 22.5 195.4 3457 2010 115.3 24.8 140.1 4064 2011 115.3 27.1 142.4 4064 2012 115.3 29.4 144.7 4064 2013 57.6 30.6 88.2 4064 2014 30.6 30.6 4064 2015 30.6 30.6 4064 2016 30.6 30.6 4064 2017 30.6 30.6 4064 2018 30.6 30.6 4064 2019 30.6 30.6 4064 2020 30.6 30.6 4064 2021 30.6 30.6 4064 2022 30.6 30.6 4064 2023 30.6 30.6 4064

Present Values Incremental Costs (US$ million) 873.7Incremental Sales (million kWh) 24877

Average Incremental Costs (cents/kWh) 3.5

48

B. Rehabilitation of Generating Units

1. Kazakhstan

(a) Investment in Ekibastuz TPP-1 Rehabilitation The coal fired Ekibastuz I thermal power plant is located at the mine mouth on the northern side of Kazakhstan, is currently owned by private investor AES, and has eight units of 500 MW each, of which only four are believed to be operational. The remaining four units need rehabilitation. The cost of such rehabilitation to restore the full 4,000 MW capacity of the plant is estimated at $440 million.17 The rehabilitation project would need three years to prepare (2005-2007), and four years to implement (2008-2011). The first year of generation from the rehabilitated units would be 2010.

Table A5.5: Kazakhstan. AIC for Ekibastuz I Plant Rehabilitation Calendar Year Capital Investment Fuel Cost Incremental O&M

Costs Excluding FuelTotal Incremental

Costs Incremental Sales

US$ million US$ million US$ million US$ million GWh 2007 2008 44.0 44.0 2009 132.0 132.0 2010 132.0 5.3 17.6 154.8 403 2011 132.0 42.0 37.6 211.7 3224 2012 84.1 75.2 159.3 6447 2013 147.2 80.2 227.3 11283 2014 147.2 80.2 227.3 11283 2015 147.2 80.2 227.3 11283 2016 147.2 80.2 227.3 11283 2017 147.2 80.2 227.3 11283 2018 147.2 80.2 227.3 11283 2019 147.2 80.2 227.3 11283 2020 147.2 80.2 227.3 11283 2021 147.2 80.2 227.3 11283 2022 147.2 80.2 227.3 11283 2023 147.2 80.2 227.3 11283 2024 147.2 80.2 227.3 11283 2025 147.2 80.2 227.3 11283 2026 147.2 80.2 227.3 11283 2027 147.2 80.2 227.3 11283

Present Values Incremental Costs (US$ million) 1582.6Incremental Sales (million kWh) 59794

Average Incremental Costs (cents/kWh) 2.65

The net Heat Rate of the units is 9,600 kJ/kWh. The main fuel of the plant would be Ekibastuz coal with a calorific value of 16 GJ/ton with a price of $20/Ton, which is also the export price of coal from Kazakhstan. The fixed and variable O&M costs are based on calculations for similar

17 WB’s estimate and RWE Solution, KEGOK, Kazakhstan North-South 500 kV Power Transmission Line Investment Pre-Feasibility Study

49

plants in the region.18 The plant factor for each unit is assumed to be 10% during the first year of operation and 70% in the following years. Plant’s self-consumption or auxiliary consumption is estimated at 8% of gross generation. The average incremental cost of supply from rehabilitated units is determined to be 2.65 cents/kWh., as can be seen from the Table A5.5. (b) Rehabilitation of Other National and Regional Level Generating Units. Project preparation: 2005 Construction: 2006-2017 The first year of output: 2007 Table A5.6: Kazakhstan. AIC for Rehabilitation of the Other Large and Medium Units at

the National and Local Level Calendar Year Capital Investment Fuel Cost Incremental O&M

Costs Excluding FuelTotal Incremental

Costs Incremental Sales

$ million $ million $ million US$ million GWh 2005 2006 53.5 3.6 57.1 2007 85.6 11.2 10.4 107.1 856 2008 85.6 29.0 17.6 132.2 2225 2009 85.6 46.9 24.8 157.3 3595 2010 85.6 64.7 32.0 182.4 4964 2011 85.6 82.6 39.3 207.5 6334 2012 85.6 100.5 46.5 232.6 7703 2013 96.3 118.3 54.5 269.1 9072 2014 96.3 138.4 62.6 297.3 10613 2015 96.3 158.5 70.7 325.6 12154 2016 107.0 178.6 79.6 365.2 13694 2017 107.0 200.9 88.6 396.6 15406 2018 223.3 90.4 313.7 17118 2019 223.3 90.4 313.7 17118 2020 223.3 90.4 313.7 17118 2021 223.3 90.4 313.7 17118 2022 223.3 90.4 313.7 17118 2023 223.3 90.4 313.7 17118 2024 223.3 90.4 313.7 17118 2025 223.3 90.4 313.7 17118

Present Values Incremental Costs (US$ million) 1861.7Incremental Sales (million kWh) 67670

Average Incremental Costs (cents/kWh) 2.75

From the total installed capacity of about 18,000 MW in Kazakhstan, about 9,870 MW of thermal plants would be retired by 2015 (including 2,700 MW by 2005, 2,500 MW by 2010, and 4,670 by 2015), reducing substantially the system reserve margin. The Kazakh authorities plan to invest $1,070 million in rehabilitation of these units to prolong their operating lives.19 The schedule of investment in rehabilitation of the TPPs’ large and medium units in general reflects the present retirement schedule. It is assumed that the involved units will consume coal from the Ekibastuz mine. The Heat Rate, coal calorific value, and coal price are thus the same as those 18 WB estimate and TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan 19 Kazakhstan, Plans on implementation of national policy of further power sector development

50

adopted for Ekibastuz I TPP. Fixed and Variable incremental O&M expenditures20 adopted are also similar to those adopted in Ekibastuz I plant. It is assumed that the Unit’s Capacity Factor would increase by about 20% after rehabilitation21; Plants’ Own Needs (auxiliary consumption) is assumed at 8% of gross output. The details of AIC calculations are shown in Table A5.6.

2. Uzbekistan Project Implementation period for the rehabilitation of existing thermal plants is 2004-2023. The installed capacity of the existing thermal power plants is about 10,000 MW.

Table A5.7: Uzbekistan. AIC for Rehabilitation of the existent TPPs. Calendar Year Investment in TPPs Rehabilitation Avoided Decrease of Generation

US$ million GWh 2003 2004 47.5 0 2005 39.5 414 2006 118.6 1338 2007 166.1 4597 2008 94.9 6415 2009 94.9 3750 2010 47.5 2200 2011 23.7 1350 2012 47.5 425 2013 47.5 1350 2014 47.5 1350 2015 80.7 1350 2016 0.0 2375 2017 33.2 0 2018 0.0 1025 2019 0.0 0 2020 47.5 0 2021 94.9 940 2022 71.2 1880 2023 47.5 1365

Present Values Incremental Costs (US$ million) 561.0Incremental Sales (million kWh) 15562

Average Incremental Costs (cents/kWh) 3.60

But according to the most recent consultant’s estimate22 the total available net capacity is about 7,800 MW. Majority of the plants were commissioned during 1960-1970 and some even earlier. They have all suffered for want of spare parts and regular maintenance since 1990.

20 WB estimate and TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan 21 WB’s estimate 22 TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan, draft Final Report

51

The objective of the rehabilitation is to increase the lifetime, availability and the efficiency of TPPs and to upgrade the units so that they reach/approach the capacity they were originally designed for. The rehabilitation program will implement those measures, which should have been implemented within the maintenance schedules of the past years but were not. It will concentrate on mitigating the weak points and bottlenecks at the principal power plant components, mainly at the boilers, turbines, condensers, pre-heaters, piping, as well as instrumentation and control. At the damaged sections, the insulation has to be renewed and leakages have to be repaired.23 It was also assumed that units with installed capacity less than 60 MW would be retired as investments in rehabilitation of such units would not be economic and rational.

23 TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan, draft Final Report

52

C. Construction of New Generation Units

1. Uzbekistan

(a) Talimardjan Thermal Power Project I: Unit 1

This gas fired 800 MW steam turbine unit had been under construction since the late 1980s and it is now anticipated that it would be commissioned in 2005. Ignoring the sunk costs incurred so far, the cost for completing the project is estimated at $100 million. There are cooling water limitations and other problems based on the experience of similar units operating in Russia, which limit the plant factor to be around 60%- 65%. The unit will have a heat rate of 10,500 kJ/kWh. The calorific value of gas is 34.3 GJ/KCM. The gas price is assumed at $35/KCM which is the cash export price for Uzbek gas. Plant auxiliary consumption is assumed at 6% of the gross output. Fixed and variable O&M costs are based on consultant reports.24

Table A5.8: Uzbekistan. AIC of Electricity from Talimardjan Unit 1 Calendar Year Capital Investment Fuel Cost Incremental O&M Costs

Excluding Fuel Total Incremental Costs Incremental net generation

$ million $ million $ million $ million GWh 2004 90.0 0.0 1.6 91.6 0 2005 10.0 6.9 6.7 23.6 609 2006 20.8 7.1 27.9 1828 2007 48.4 7.9 56.3 4265 2008 48.4 7.9 56.3 4265 2009 48.4 7.9 56.3 4265 2010 48.4 7.9 56.3 4265 2011 48.4 7.9 56.3 4265 2012 48.4 7.9 56.3 4265 2013 48.4 7.9 56.3 4265 2014 48.4 7.9 56.3 4265 2015 48.4 7.9 56.3 4265 2016 48.4 7.9 56.3 4265 2017 48.4 7.9 56.3 4265 2018 48.4 7.9 56.3 4265 2019 48.4 7.9 56.3 4265 2020 48.4 7.9 56.3 4265 2021 48.4 7.9 56.3 4265 2022 48.4 7.9 56.3 4265

2023 48.4 7.9 56.3 4265 Present Values

Incremental Costs (US$ million) 463.1Incremental Sales (million kWh) 27583

Average Incremental Costs (cents/kWh) 1.68

24 WB estimate and TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan

53

(b) Talimardjan Thermal Plant II: Units 2 to 4

All the site facilities at Talimardjan have been designed and constructed for locating four units of 800 MW each. It is assumed that the preparation for the construction of units 2 to 4 would be during 2005-2008 and that the construction would take place during 2009-2013, while Power will start flowing from 2011.Since all site facilities exist the additional investment needed is estimated at $ 1,200 million25. All other assumptions such as heat rate, calorific value of gas, gas price, level of auxiliary consumption, plant factor etc are the same as those for Unit 1.

Table A5.9: Uzbekistan. AIC of Electricity from Talimardjan Units #2-4 Calendar

Year Capital Investment Fuel Cost Incremental O&M Costs Excluding Fuel Total Incremental Costs Incremental net

generation $ million $ million $ million $ million GWh

2008 2009 120.0 120.0 2010 360.0 360.0 2011 400.0 6.9 6.7 413.6 609 2012 280.0 27.7 13.8 321.5 2437 2013 40.0 76.1 21.7 137.8 6703 2014 117.6 22.9 140.5 10359 2015 145.3 23.7 168.9 12796 2016 145.3 23.7 168.9 12796 2017 145.3 23.7 168.9 12796 2018 145.3 23.7 168.9 12796 2019 145.3 23.7 168.9 12796 2020 145.3 23.7 168.9 12796 2021 145.3 23.7 168.9 12796 2022 145.3 23.7 168.9 12796 2023 145.3 23.7 168.9 12796 2024 145.3 23.7 168.9 12796 2025 145.3 23.7 168.9 12796 2026 145.3 23.7 168.9 12796 2027 145.3 23.7 168.9 12796 2028 145.3 23.7 168.9 12796

Present Values Incremental Costs (US$ million) 1804.3Incremental Sales (million kWh) 65343

Average Incremental Costs (cents/kWh) 2.76

2. The Kyrgyz Republic

(a) Bishkek II Thermal Power Plant The construction of two units of gas fired combined cycle power plant each with a capacity of about 200 MW in the same site as that of Bishkek CHP 2 plant would be an option to meet the chronic winter power deficit of Kyrgyz system. The project would be prepared and funding secured in 2005 and construction would proceed during 2006-2008. Initial output of power

25 TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan

54

would be in 2007. The international cost/ kW of installed capacity of such units is around $700. The Bishkek plant site already has all infrastructure – natural gas connection, 110 kV electric power substation, drinking water and sewerage connections, access road, railway access, erection site, etc. It is assumed that existence of infrastructure would decrease cost per 1 kW of installed capacity by 30%. Total investment needed to complete this project is estimated, thus, at US$196 million. Combined cycle unit's efficiency is assumed as 50%; natural gas price for cash including transportation cost is estimated at $40/KCM; and the natural gas calorific value is 34.3 GJ/KCM26. Incremental O&M expenditures (excluding fuel cost) are assumed at 1% of capital expenditures in year 2, 8% of capital expenditures in year 3, and 10% of capital expenditures in year 4 and further. Capacity factor is assumed to be 70%; and annual electricity generation by plant is estimated at 2,450 GWh. Auxiliary consumption is estimated at 4% of the gross output.

Table A5.10: The Kyrgyz Republic. AIC of Electricity from Bishkek II Calendar

Year Capital Investment Fuel Cost Incremental O&M Costs Excluding Fuel Total Incremental Costs Incremental net

generation $ million $ million $ million $ million GWh

2005 2006 78.4 0.8 79.2 2007 58.8 3.1 1.3 63.1 353 2008 58.8 13.4 7.1 79.3 1531 2009 20.6 12.4 33.0 2355 2010 20.6 12.4 33.0 2355 2011 20.6 12.4 33.0 2355 2012 20.6 12.4 33.0 2355 2013 20.6 12.4 33.0 2355 2014 20.6 12.4 33.0 2355 2015 20.6 12.4 33.0 2355 2016 20.6 12.4 33.0 2355 2017 20.6 12.4 33.0 2355 2018 20.6 12.4 33.0 2355 2019 20.6 12.4 33.0 2355 2020 20.6 12.4 33.0 2355 2021 20.6 12.4 33.0 2355 2022 20.6 12.4 33.0 2355 2023 10.4 12.4 22.8 1183 2024 10.4 12.4 22.8 1183 2025 20.6 12.4 33.0 2355

Present Values Incremental Costs (US$ million) 388.9Incremental Sales (million kWh) 15231

Average Incremental Costs (cents/kWh) 2.55

(b) Kambarata I Hydropower Plant.

The site of Kambarata 1 plant is upstream of the Toktogul reservoir. The total installed capacity of this new hydro station would be 1900 MW (four units of 475 MW each). Total investment needed is estimated at $1,940 million, including $265million for 500 kV line that connects Kambarata-1 and substation Kemin in the North of Kyrgyzstan. The annual output from

26 Information from the Kyrgyz Authorities

55

Kambarata 1 is estimated at 5,100 GWh and auxiliary consumption is assumed at 1% of gross output. The plant factor of this station is 31%, but the large capacity enables it to meet efficiently the daily system peaks in the Kyrgyz and CAR systems. O&M cost are assumed at 0.1% of capital investment for each power unit after one year of guaranty operation; plus 0.1% of capital investment for dam after completion of the dam construction and one year of guaranty operation. Since agreements among riparian states have to be reached and financing secured, it will take six to seven years (2005-2011) to prepare the project, and it will need seven years of construction time (2012-2019). Initial flow of power could commence from 2017.

Table A5.11: The Kyrgyz Republic. AIC of Electricity from Kambarata 1 Calendar Year Capital Investment Incremental O&M Costs Total Incremental Costs Incremental net generation

$ million $ million $ million GWh 2011 2012 194.0 194.0 2013 291.0 291.0 2014 291.0 291.0 2015 291.0 291.0 2016 291.0 291.0 2017 194.0 194.0 252 2018 194.0 0.1 194.1 1515 2019 194.0 0.2 194.2 3029 2020 0.9 0.9 5049 2021 0.9 0.9 5049 2022 0.9 0.9 5049 2023 0.9 0.9 5049 2024 0.9 0.9 5049 2025 0.9 0.9 5049 2026 0.9 0.9 5049 2027 0.9 0.9 5049 2028 0.9 0.9 5049 2029 0.9 0.9 5049 2030 0.9 0.9 5049 2031 0.9 0.9 5049

Present Values Incremental Costs (US$ million) 1317.4Incremental Sales (million kWh) 18382

Average Incremental Costs (cents/kWh) 7.17

The incremental cost of power generation by Kambarata-1 at US¢7.17/kWh (see Table A5.11) is the highest among those from all the generation options available or contemplated in Central Asia.27. However, Kambarata 1 is a large storage hydro plant which enables electricity generation in winter, since the water released would be stored in downstream Toktogul reservoir. Thus it will enable Toktogul hydro units and the Naryn cascade hydro units operate following the irrigation regime as per international agreements. 27 JSC “Electric Power Plants”, Investment Projects, Bishkek, the Kyrgyz Republic

56

(c) Kamabarata II Hydropower Plant The site of Kambarata 2 project is also upstream of the Toktogul HPP and is situated between Toktogul and Kambarata-1 HPPs. Construction of Kambarata-2 was started in 1986 and about 30% of civil and erection works have been completed so far. According to estimates of the local experts it is necessary to invest US$280 million to complete this project, including US$18 million for construction of 500 kV connection line28. The project will be prepared for lining up funds etc during 2005-2008, and construction would be during 2009-2012. Annual generation of the Kambarata 2 is estimated at 1116 GWh based on the designed Plant Factor of 35%29.

Table A5.12: The Kyrgyz Republic. AIC of Electricity from Kambarata 2 Calendar Year Capital Investment Incremental O&M Costs Total Incremental Costs Incremental Sales

$ million $ million $ million GWh 2008 2009 56.0 56.0 2010 84.0 0.1 84.1 2011 84.0 0.1 84.1 2012 56.0 0.4 56.4 221 2013 0.6 0.6 1105 2014 0.6 0.6 1105 2015 0.6 0.6 1105 2016 0.6 0.6 1105 2017 0.6 0.6 1105 2018 0.6 0.6 1105 2019 0.6 0.6 1105 2020 0.6 0.6 1105 2021 0.6 0.6 1105 2022 0.6 0.6 1105 2023 0.6 0.6 1105 2024 0.6 0.6 1105 2025 0.6 0.6 1105 2026 0.6 0.6 1105 2027 0.6 0.6 1105 2028 0.6 0.6 1105

Present Values Incremental Costs (US$ million) 225.4Incremental Sales (million kWh) 6055

Average Incremental Costs (cents/kWh) 3.72

Though the marginal cost of generation is ¢3.72/kWh (see Table A5.12), its construction ahead of Kambarata 1 should be weighted carefully, as it does not have seasonal storage and would merely aggravates the problem of the Kyrgyz system with summer surplus and winter deficits.

28 JSC “Electric Power Plants”, Investment Projects, Bishkek, the Kyrgyz Republic 29 JSC “Electric Power Plants”, Investment Projects, Bishkek, the Kyrgyz Republic

57

3. Tajikistan (a) Sangtuda I Hydropower Plant The site of the project is downstream of the Nurek Cascade of hydropower plants on the Vaksh River. The installed capacity of this run-of the river project would be 670 MW and the annual electricity generation is estimated at 2,700 GWh at a plant factor 46%. The total cost of the project is estimated at about US$482 million, and, of this, about US$110 million already have been spent30. Project preparation would be during 2005-2007 and construction would be during 2007-2012. Power would start flowing from 2009. Incremental investment needed to complete construction would thus be about $368-$370 million. O&M expenses are assumed at 0.1% of capital investment for each power unit after the first year of guaranty operation; plus 0.1% of capital investment for dam after completion of the dam construction and one year of guaranty operation. The average incremental cost of electricity of this project at 1.97 cents/kWh is the lowest of all generation options available to the CARs.

Table A5.13: Tajikistan. AIC of Electricity from Sangtuda I Calendar Year Capital Investment Incremental O&M Costs Total Incremental Costs Incremental Sales

$ million $ million $ million GWh 2006 2007 37.0 37.0 2008 55.5 55.5 2009 111.0 0.0 111.0 134 2010 92.5 0.1 92.6 802 2011 55.5 0.1 55.6 1470 2012 18.5 0.2 18.7 2138 2013 0.4 0.4 2673 2014 0.4 0.4 2673 2015 0.4 0.4 2673 2016 0.4 0.4 2673 2017 0.4 0.4 2673 2018 0.4 0.4 2673 2019 0.4 0.4 2673 2020 0.4 0.4 2673 2021 0.4 0.4 2673 2022 0.4 0.4 2673 2023 0.4 0.4 2673 2024 0.4 0.4 2673 2025 0.4 0.4 2673 2026 0.4 0.4 2673

Present Values Incremental Costs (US$ million) 273.0Incremental Sales (million kWh) 13883

Average Incremental Costs (cents/kWh) 1.97

30 Information from the Tajik Authorities

58

(b) Rogun Hydropower Project, Phase I

The site of this project is upstream of the existing Nurek reservoir on Vaksh River. Phase I of the project includes installation of two generation units of 600 MW each, construction of the dam up to a certain height, repairing the previously constructed, but damaged two tunnels; building a third new tunnel; creation of the regulating reservoir. According to Tajik authorities, a sum of $800 million had already been spent during Soviet era, before the construction was stalled for want of funds upon dissolution of the Soviet Union. There has been no progress in construction since 1991 and it is estimated that an additional US$785 million would be needed to complete Phase I. This is a major storage reservoir and it would also facilitate additional generation from the existing downstream hydropower stations. Reaching a fresh agreement among the riparian states would be necessary. Thus project preparation would be during 2005-2010 and construction would be during 2011-2015. Power could flow from 2014.

Table A5.14: Tajikistan. AIC of Electricity from Rogun HPP Phase I Calendar Year Capital Investment Incremental O&M Costs Total Incremental Costs Incremental Sales

$ million $ million $ million GWh

2010 2011 78.5 78.5 2012 196.3 196.3 2013 196.3 196.3 2014 157.0 0.2 157.2 515 2015 157.0 0.7 157.7 2762 2016 0.9 0.9 4643 2017 0.9 0.9 4643 2018 0.9 0.9 4643 2019 0.9 0.9 4643 2020 0.9 0.9 4643 2021 0.9 0.9 4643 2022 0.9 0.9 4643 2023 0.9 0.9 4643 2024 0.9 0.9 4643 2025 0.9 0.9 4643 2026 0.9 0.9 4643 2027 0.9 0.9 4643 2028 0.9 0.9 4643 2029 0.9 0.9 4643 2030 0.9 0.9 4643

Present Values Incremental Costs (US$ million) 590.4Incremental Sales (million kWh) 23995

Average Incremental Costs (cents/kWh) 2.46

The electricity output of Phase I is about 4,300 GWh; and it would also enable to generate of an additional 400 GWh of electricity at the existing downstream Nurek cascade. O&M cost are assumed at the same level as for Sangtuda I HPP: 0.1% of capital investment for each power unit after one year of guaranty operation; plus 0.1% of capital investment for dam after completion of the dam construction and one year of guaranty operation. The designed Plant Factor of the Phase I Rogun HPP is 41%. The AIC of power generation of this project is ¢2.46/kWh.

59

(c) Rogun Hydropower Project, Phase I and II In the second phase, the dam height will be raised to the full level of 335 meters, making it one of the tallest dams in the world, four more generating units (600 MW each) would be installed, raising the total capacity to 3,600 MW. In addition to $800 million believed to have been spent in the Soviet days, the total additional funds needed to complete both Phases I and II would be $2,450 million. The construction of phase II would go on till 2019 and full power output realized in 2020.

Table A5.15: Tajikistan. AIC of Electricity from Rogun HPP Phase I and II Calendar Year Capital Investment Incremental O&M Costs Total Incremental Costs Incremental Sales

$ million $ million $ million GWh 2010 2011 78.5 78.5 2012 196.3 196.3 2013 196.3 196.3 2014 491.0 0.2 491.2 515 2015 491.0 0.7 491.7 2762 2016 417.5 0.9 418.4 4643 2017 250.5 0.9 251.4 5282 2018 167.0 1.4 168.4 7712 2019 167.0 1.5 168.5 10712 2020 2.6 2.6 14157 2021 2.6 2.6 14157 2022 2.6 2.6 14157 2023 2.6 2.6 14157 2024 2.6 2.6 14157 2025 2.6 2.6 14157 2026 2.6 2.6 14157 2027 2.6 2.6 14157 2028 2.6 2.6 14157 2029 2.6 2.6 14157 2030 2.6 2.6 14157

Present Values Incremental Costs (US$ million) 1544.1Incremental Sales (million kWh) 54535

Average Incremental Costs (cents/kWh) 2.83

The completed project would produce roughly 13,000 GWh of electricity annually. It will totally eliminate spilling of water through the existent Nurek cascade of HPPs and enable them to produce an additional 1300 GWh of power. O&M cost are assumed at 0.1% of capital investment for each power unit after one year of guaranty operation; plus 0.1% of capital investment for dam after completion of the dam construction and one year of guaranty operation. The designed Plant Factor of the Phase I and II Rogun HPP is 41%. The AIC of power generation of this investment project is US¢2.83/kWh.

4. Kazakhstan

60

A New Coal Fired Generation Plant The supply/demand balance for Kazakhstan shows that in 2020s Kazakhstan will experience a notable shortage in power generation, unless action is taken to add at least about1000 MW of

Table A5.16: Kazakhstan. AIC of Electricity from the New TPP Calendar

Year Capital Investment Fuel Cost Incremental O&M Costs Total Incremental Costs Incremental Sales

$ million $ million $ million $ million GWh 2015 2016 162.8 162.8 2017 162.8 162.8 2018 217.0 217.0 2019 217.0 217.0 2020 162.8 11.1 18.0 191.8 806 2021 162.8 58.4 38.6 259.8 4231 2022 94.5 41.3 135.8 6850 2023 94.5 41.3 135.8 6850 2024 94.5 41.3 135.8 6850 2025 94.5 41.3 135.8 6850 2026 94.5 41.3 135.8 6850 2027 94.5 41.3 135.8 6850 2028 94.5 41.3 135.8 6850 2029 94.5 41.3 135.8 6850 2030 94.5 41.3 135.8 6850 2031 94.5 41.3 135.8 6850 2032 94.5 41.3 135.8 6850 2033 94.5 41.3 135.8 6850 2034 94.5 41.3 135.8 6850 2035 94.5 41.3 135.8 6850

Present Values Incremental Costs (US$ million) 1424.2Incremental Sales (million kWh) 31374

Average Incremental Costs (cents/kWh) 4.54

capacity by about 2020. These would be coal fired steam turbine units. One reasonable option would be to locate them in the site of the existing Ekibastuz II thermal plant31 which already has two units of 500 MW each. It will use Ekibastuz coal. The heat rate, fuel calorific value, fuel prices, and O&M costs and auxiliary consumption would be the same as those used for the rehabilitation of Ekibastuz I plant. The capital costs are estimated at $1,085 million32. Construction would be during 2016-2020 and the first year of output would be 2020. The Capacity Factor for each unit assumed at 20% during the first year of operation of each unit and at 85% in the follow up years. On the basis of the above-mentioned assumptions, the AIC of generation by the new units is expected to be ¢4.54/kWh (see Table A5.16).

31 50% of the equity in this existing Ekibastuz II power station is believed to have been transferred to RAO UES of Russia. 32 RWE Solution, KEGOK, Kazakhstan North-South 500 kV Power Transmission Line Investment Pre-Feasibility Study

61

Appendix 5.2

Central Asia Regional Export Potential Study

Economic Analysis of Transmission Line Options for Exports The economic analysis calculates the economic cost of transmission in respect of the proposed six export transmission line options using an 10% discount rate and using constant 2004 dollar price levels. The Basic Data on the proposed transmission lines are shown in the Table A5.17.

Table A5.17. Basic Data on Transmission Lines

Export Transmission Line Distance kilometers

Voltage kV

Line type

Annual trans-mission (GWh)

Number of new SS

Number of expanded

SS

Investment in US$ million

Almaty (Kazakhstan) - Urumqui (China) 1,050 500 DC 10,000 1 1 390.0

Surhan (Uzbekistan) - Kabul (Afghanistan) 515 500 AC 5,000 2 1 153.0

Kabul (Afghanistan) - Tarbela (Pakistan) 360 500 AC 3,000 1 1 90.5

Kabul (Afghanistan) - Kandaghar (Afghanistan) 490 500 AC 5,000 2 1 138.2

Kandaghar (Afghanistan) - Karachi (Pakistan) 900 500 AC 4,000 3 1 226.6

Surhan (Uzbekistan) - Mashad (Iran) 1,150 500 AC 10,000 4 1 320.0

The following assumptions were assumed during AIC calculations for all Transmission Lines:

The unit cost of the double circuit 500kV overhead transmission line is US$0.2 million per kilometer;

Maximum load in the lines is estimated at about 2000 MVA, and average load at about 1000 MVA;

Construction time is estimated at 24 to 30 months; An intermediate 500 kV substation is placed at intervals of 200 to 300 kilometers in the

AC lines, inter alia, for reactive compensation purposes; Cost of each 500 kV substation is estimated at $20 million; Cost of expansion of each existing substation is estimated at $10 million; The designed power technical losses is at 1% of electricity transmitted for every 250 km; O&M expenses of transmission lines is estimated at 0.1% of the capital cost; The amount of power transferred is 10,000 GWh a year in each direction in respect of

Almati-Urumqi and Surhan-Mashhad; and 5,000 in respect of Surhan-Kabul. Back-to-back DC conversion cost for DC lines is estimated at $150 million but no

intermediate substations would be needed. The details of AIC calculations summarized in Table A5.18.

62

Table A5.18: Transmission Lines’ AIC Calculations

Almaty - Urumqui

Surhan – Mashad Surhan – Kabul Kabul – Tarbela Kabul –

Kandaghar Kandaghar – Karachi

Calendar Year

Invest. US$ mil

Sales GWh

Invest. US$ mil

Sales GWh

Invest. US$ mil

Sales GWh

Invest. US$ mil

Sales GWh

Invest. US$ mil

Sales GWh

Invest. US$ mil

Sales GWh

Year 0 Year 1 97.5 80 Year 2 156 128 Year 3 136.5 112 Year 4 477 2832 Year 5 2862 6136 Year 6 5724 9440 45.9 Year 7 9540 9440 107.1 Year 8 9540 9440 1460 27.1 Year 9 9540 9440 3164 63.3

Year 10 9540 9440 4867 883 41.5 Year 11 9540 9440 4867 1914 96.7 Year 12 9540 9440 4867 2945 1462 68 Year 13 9540 9440 4867 2945 3167 158.6 Year 14 9540 9440 4867 2945 4872 1147 Year 15 9540 9440 4867 2945 4872 2486 Year 16 9540 9440 4867 2945 4872 3824 Year 17 9540 9440 4867 2945 4872 3824 Year 18 9540 9440 4867 2945 4872 3824 Year 19 9540 9440 4867 2945 4872 3824 Year 20 9540 9440 4867 2945 4872 3824 Year 21 9540 9440 4867 2945 4872 3824 Year 22 9540 9440 4867 2945 4872 3824 Year 23 9540 9440 4867 2945 4872 3824 Year 24 4867 2945 4872 3824 Year 25 4867 2945 4872 3824 Year 26 4867 2945 4872 3824 Year 27 4867 2945 4872 3824 Year 28 2945 4872 3824 Year 29 2945 4872 3824 Year 30 4872 3824 Year 31 4872 3824 Year 32 3824 Year 33 3824 Incremental Costs (US$ mil.) 322.3 264.5 131.2 77.6 118.5 194.3

Incremental Sales (GWh) 48531 53817 30521 18467 30552 23980

Economic Cost of Transmission (cents/kWh)

0.66 0.49 0.43 0.42 0.39 0.81

63

Appendix 5.3 Central Asia

Regional Export Potential Study Financial Analysis of Generation and Transmission Options

The financial analysis of the major supply options seeks to estimate the financial cost of

supply of electricity to determine the competitiveness of these options, and to help the judge the attractiveness of these investment options in relation to both export and domestic markets. The analysis is limited to major hydroelectric supply options (Kambarata I and II, Sangtuda I, Rogun I and II) major thermal plant options (Talimardjan I and II, Bishkek II, Ekibastuz I rehabilitation and the New Ekibastuz units).

Financing is based on a structure that will roughly result in 25% equity and 75% long term debt ratio after financing cost. The terms of debt are assumed to include a risk adjusted interest at 10%, a repayment period of 15 years including a five year grace period. The equity is expected to earn an internal rate of return (IRR) of 15% over the life of investment, which translates to an annual rate of return on equity in the range of 17% to 24% in respect of these projects. The level of annual Return on Equity varies among the projects, largely, as a function of the construction period. Longer construction periods make the investors wait for longer periods for cash inflows and thus raises the annual equity returns to achieve a 15% IRR on equity over the life of investment. On this basis, the tariff/kWh required to service the debt and provide the return on equity for each year is computed for a 20 year production period. These annual tariffs are then discounted to 2004 at 10% to arrive at the levelized tariff/kWh for the project. The capital costs used for economic analysis which are in constant 2004 dollars, are converted into nominal dollars using a MUV inflation index of 1.52% per year. O&M and Fuel expenses are also similarly inflated at 1.52 % per year for the financial analysis. Preparatory period is the estimate of the time needed for firming up markets and financing sources. The steady state sales in GWh are derived from the steady state generation by reducing from the gross generation, the volume of electricity consumed for the generation station use at the rate 8% for coal fired steam units, 6% for gas fired steam units, 4% for gas fired combined cycle plant and 1% for the hydro plants as per the industry practice. The levelized tariffs derived for the generation options enable comparison among the among the options and for a given scheme for different financing and output assumptions. Sensitivity analysis has been carried out for decrease in generation, for increases in capital expenditure, fuel cost, interest rate and rates of return on equity. Given their construction schedules and structure of financing they are most sensitive to increases in interest rates and significantly sensitive to increases in rate of return on equity. They are also markedly sensitive to decreases in output and increases in fuel (especially natural gas) prices. Given the high cost per kW, long preparation and construction times and low load factors the hydropower projects are much more sensitive to changes in respect of most parameters, than thermal power projects. Thermal power projects would thus be able to deal with possible reductions in export demand much better than the hydro projects. However thermal projects are also quite sensitive to fuel price increases.

64

Table A5.19: Financial Analysis of Sangtuda I Hydropower Project

Construction Period Operating Period

Year Capital Expenditures without IDC

IDC Capital

Expenditureswith IDC

Debt Funded

Equity Funded

O&M Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

OutflowGeneration Annual

Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2007 $19 $1 $20 $17 $3 2008 $39 $4 $43 $37 $6 2009 $79 $9 $88 $76 $12 2010 $80 $17 $97 $72 $25 2011 $122 $26 $149 $122 $27 2012 $62 $35 $97 $55 $42 2013 $0.41 $38 $22 $61 2,538 2.40 2014 $0.41 $38 $22 $61 2,538 2.40 2015 $0.42 $38 $22 $61 2,538 2.40 2016 $0.42 $38 $22 $61 2,538 2.40 2017 $0.43 $38 $22 $61 2,538 2.40 2018 $0.44 $69 $22 $92 2,538 3.64 2019 $0.44 $66 $22 $89 2,538 3.52 2020 $0.45 $63 $22 $86 2,538 3.39 2021 $0.46 $60 $22 $83 2,538 3.27 2022 $0.46 $57 $22 $80 2,538 3.14 2023 $0.47 $54 $22 $77 2,538 3.02 2024 $0.48 $51 $22 $73 2,538 2.90 2025 $0.49 $47 $22 $70 2,538 2.77 2026 $0.49 $44 $22 $67 2,538 2.65 2027 $0.50 $41 $22 $64 2,538 2.52 2028 $0.51 $13 $22 $36 2,538 1.40 2029 $0.52 $12 $22 $35 2,538 1.38 2030 $0.52 $11 $22 $34 2,538 1.35 2031 $0.53 $11 $22 $34 2,538 1.33 2032 $0.54 $10 $22 $33 2,538 1.31 Total $402 $91 $493 $379 $114 Levelized Tariff (c/kWh): 2.44 (in 2004 prices)

Table A5.20: Sangtuda I Sensitivity Analysis Percentage

Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change

Lev Tariff (%)

Sensitivity Index a

Base Case 2.4350 Sensitivities (1) Change in Generation -20% 3.0438 25.0% (1.25) (2) Change in Interest Rates 1% 2.4521 0.7% 0.70 (3) Change in Return on Equity 1% 2.4453 0.4% 0.42 (4) Change in CapEx 1% 2.4587 1.0% 0.97 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

65

Table A5.21: Financial Analysis of Rogun Hydropower Project Phase I

Construction Period Operating Period

Year Capital Expenditures without IDC

IDC Capital

Expenditures with IDC

Debt Funded

Equity Funded

O&M Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow Generation Annual

Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh

2011 $88 $4 $92 $75 $16 2012 $223 $18 $241 $214 $27 2013 $226 $39 $265 $194 $71 2014 $184 $59 $243 $165 $78 2015 $187 $76 $263 $191 $72 2016 $0.9 $84 $52 $137 4,643 2.94 2017 $0.9 $84 $52 $137 4,643 2.94 2018 $0.9 $84 $52 $137 4,643 2.94 2019 $1.0 $84 $52 $137 4,643 2.94 2020 $1.0 $84 $52 $137 4,643 2.94 2021 $1.0 $154 $52 $207 4,643 4.45 2022 $1.0 $147 $52 $200 4,643 4.30 2023 $1.0 $140 $52 $193 4,643 4.15 2024 $1.0 $133 $52 $186 4,643 4.00 2025 $1.0 $126 $52 $179 4,643 3.85 2026 $1.1 $119 $52 $172 4,643 3.70 2027 $1.1 $112 $52 $165 4,643 3.55 2028 $1.1 $105 $52 $158 4,643 3.40 2029 $1.1 $98 $52 $151 4,643 3.25 2030 $1.1 $91 $52 $144 4,643 3.10 2031 $1.1 $28 $52 $81 4,643 1.74 2032 $1.2 $27 $52 $79 4,643 1.71 2033 $1.2 $25 $52 $78 4,643 1.68 2034 $1.2 $24 $52 $77 4,643 1.65 2035 $1.2 $22 $52 $75 4,643 1.62 2036 Total $908 $196 $1,104 $839 $264 Levelized Tariff (c/kWh): 2.91 (2004 prices)

Table A5.22: Rogun Phase I Sensitivity Analysis

Percentage Change in

Parameter (%)

Levelized Tariff c/kWh

Percentage Change Lev Tariff (%)

Sensitivity Index a

Base Case 2.9104 Sensitivities (1) Change in Generation -20% 3.6380 25.0% (1.25) (2) Change in Interest Rates 1% 2.9310 0.7% 0.71 (3) Change in Return on Equity 1% 2.9235 0.5% 0.45 (4) Change in CapEx 1% 2.9392 1.0% 0.99 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

66

Table A5.23: Financial Analysis of Rogun Hydropower Project Phases I&II

Construction Period Operating Period

Year Capital Expenditures without IDC

IDC Capital

Expenditures with IDC

Debt Funded

Equity Funded

O&M Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow Generation Annual

Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2011 $88 $4 $92 $75 $16 2012 $223 $18 $241 $214 $27 2013 $226 $39 $265 $194 $71 2014 $575 $76 $651 $506 $145 2015 $584 $127 $711 $527 $184 2016 $504 $91 $596 $473 $123 $0.9 $84 $52 $137 4,643 2.94 2017 $307 $129 $436 $273 $163 $0.9 $84 $52 $137 4,643 2.94 2018 $208 $154 $362 $243 $119 $0.9 $84 $52 $137 4,643 2.94 2019 $211 $178 $389 $290 $99 $1.0 $84 $52 $137 4,643 2.94 2020 $2.7 $279 $209 $491 14,157 3.47 2021 $2.7 $349 $209 $561 14,157 3.96 2022 $2.8 $342 $209 $554 14,157 3.91 2023 $2.8 $335 $209 $547 14,157 3.86 2024 $2.8 $328 $209 $540 14,157 3.82 2025 $2.9 $321 $209 $533 14,157 3.77 2026 $2.9 $477 $209 $689 14,157 4.87 2027 $3.0 $454 $209 $666 14,157 4.70 2028 $3.0 $431 $209 $643 14,157 4.54 2029 $3.1 $408 $209 $620 14,157 4.38 2030 $3.1 $384 $209 $596 14,157 4.21 2031 $3.2 $305 $209 $517 14,157 3.65 2032 $3.2 $287 $209 $499 14,157 3.53 2033 $3.3 $270 $209 $482 14,157 3.40 2034 $3.3 $252 $209 $464 14,157 3.28 2035 $3.4 $234 $209 $446 14,157 3.15 Total $2,927 $816 $3,743 $2,795 $948 Levelized Tariff (c/kWh): 3.24 (in 2004 prices)

Table A5.24: Rogun Phases I & II Sensitivity Analysis

Percentage Change in

Parameter(%)

Levelized Tariff c/kWh

Percentage Change Lev

Tariff(%) Sensitivity Index a

Base Case 3.2388 Sensitivities (1) Change in Generation -20% 4.0485 25.0% (1.25) (2) Change in Interest Rates 1% 3.2644 0.8% 0.79 (3) Change in Return on Equity 1% 3.2547 0.5% 0.49 (4) Change in CapEx 1% 3.2676 0.9% 0.89 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

67

Table A5.25: Financial Analysis of Kambarata I Hydropower Project

Construction Period Operating Period

Year Capital Expenditures without IDC

IDC Capital

Expenditures with IDC

Debt Funded

Equity Funded

O&M Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

OutflowGeneration Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2012 $221 $10 $230 $193 $38 2013 $336 $35 $370 $308 $63 2014 $341 $65 $406 $305 $101 2015 $346 $97 $443 $333 $111 2016 $351 $132 $483 $363 $121 2017 $238 $161 $398 $267 $131 2018 $241 $174 $415 $307 $108 2019 $245 $190 $435 $322 $113 2020 $0.9 $240 $196 $437 5,049 8.65 2021 $0.9 $240 $196 $437 5,049 8.65 2022 $0.9 $240 $196 $437 5,049 8.65 2023 $1.0 $240 $196 $437 5,049 8.65 2024 $1.0 $240 $196 $437 5,049 8.65 2025 $1.0 $440 $196 $637 5,049 12.61 2026 $1.0 $420 $196 $617 5,049 12.22 2027 $1.0 $400 $196 $597 5,049 11.82 2028 $1.0 $380 $196 $577 5,049 11.43 2029 $1.0 $360 $196 $557 5,049 11.03 2030 $1.1 $340 $196 $537 5,049 10.64 2031 $1.1 $320 $196 $517 5,049 10.24 2032 $1.1 $300 $196 $497 5,049 9.84 2033 $1.1 $280 $196 $477 5,049 9.45 2034 $1.1 $260 $196 $457 5,049 9.05 2035 $1.1 $80 $196 $277 5,049 5.49 2036 $1.2 $76 $196 $273 5,049 5.41 2037 $1.2 $72 $196 $269 5,049 5.33

$1.2 $68 $196 $265 5,049 5.26 $1.2 $64 $196 $261 5,049 5.18

Total $2,319 $864 $3,183 $2,398 $785 Levelized Tariff (c/kWh): 8.54 (in 2004 prices)

Table A5.26: Kamabarata I Sensitivity Analysis Percentage Change in

Parameter (%) Levelized Tariff

c/kWh Percentage Change

Lev Tariff (%) Sensitivity Index a

Base Case 8.5445 Sensitivities (1) Change in Generation -20% 10.6806 25.0% (1.25) (2) Change in Interest Rates 1% 8.6143 0.8% 0.82 (3) Change in Return on Equity 1% 8.5894 0.5% 0.52 (4) Change in CapEx 1% 8.6298 1.0% 1.00 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

68

Table A5.27: Financial Analysis of Kambarata II Hydropower Project

Construction Period Operating Period

Year Capital Expenditures without IDC

IDC Capital

Expenditures with IDC

Debt Funded

Equity Funded

O&M Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow Generation Annual Tariff

($ M) $ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2009 $61 $3 $63 $52 $11 2010 $93 $9 $102 $83 $19 2011 $94 $18 $112 $82 $30 2012 $64 $24 $88 $55 $33 2013 $0.6 $27 $17 $45 1,105 4.10 2014 $0.6 $27 $17 $45 1,105 4.10 2015 $0.6 $27 $17 $45 1,105 4.10 2016 $0.7 $27 $17 $45 1,105 4.10 2017 $0.7 $27 $17 $45 1,105 4.10 2018 $0.7 $50 $17 $68 1,105 6.16 2019 $0.7 $48 $17 $66 1,105 5.95 2020 $0.7 $45 $17 $64 1,105 5.75 2021 $0.7 $43 $17 $61 1,105 5.54 2022 $0.7 $41 $17 $59 1,105 5.34 2023 $0.7 $39 $17 $57 1,105 5.14 2024 $0.7 $36 $17 $54 1,105 4.93 2025 $0.7 $34 $17 $52 1,105 4.73 2026 $0.8 $32 $17 $50 1,105 4.52 2027 $0.8 $30 $17 $48 1,105 4.32 2028 $0.8 $9 $17 $27 1,105 2.47 2029 $0.8 $9 $17 $27 1,105 2.43 2030 $0.8 $8 $17 $26 1,105 2.39 2031 $0.8 $8 $17 $26 1,105 2.35 2032 $0.8 $7 $17 $26 1,105 2.31

Total $311 $54 $365 $272 $93 Levelized Tariff (c/kWh): 3.95 (in 2004 prices)

Table A5.28: Kambarata II Sensitivity Analysis Percentage Change in

Parameter (%)

Levelized Tariff c/kWh

Percentage Change Lev Tariff

(%) Sensitivity Index a

Base Case 3.9534 Sensitivities (1) Change in Generation -20% 4.9418 25.0% (1.25) (2) Change in Interest Rates 1% 3.9684 0.4% 0.38 (3) Change in Return on Equity 1% 3.9716 0.5% 0.46 (4) Change in CapEx 1% 3.9926 1.0% 0.99 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

69

Table A5.29: Financial Analysis of Bishkek II Thermal Power Project

Construction Period Operating Period

Year Capital Expend. without

IDC

IDC

Capital Expend.

with IDC

Debt Funded

Equity Funded

O&M Expenses

Fuel Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow Generation Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2006 $81 $3 $85 $69 $16 2007 $62 $9 $71 $45 $26 2008 $63 $14 $77 $55 $22 2009 $12.6 $21 $17 $12 $62 2,355 2.62 2010 $12.8 $21 $17 $12 $62 2,355 2.64 2011 $13.0 $21 $17 $12 $63 2,355 2.66 2012 $13.2 $22 $17 $12 $63 2,355 2.68 2013 $13.4 $22 $17 $12 $64 2,355 2.71 2014 $13.6 $22 $31 $12 $78 2,355 3.33 2015 $13.8 $23 $30 $12 $77 2,355 3.29 2016 $14.0 $23 $28 $12 $77 2,355 3.25 2017 $14.2 $23 $27 $12 $76 2,355 3.22 2018 $14.4 $24 $25 $12 $75 2,355 3.18 2019 $14.6 $24 $24 $12 $74 2,355 3.15 2020 $14.9 $24 $23 $12 $73 2,355 3.11 2021 $15.1 $25 $21 $12 $72 2,355 3.08 2022 $15.3 $25 $20 $12 $72 2,355 3.04 2023 $15.6 $25 $18 $12 $71 2,355 3.01 2024 $15.8 $26 $6 $12 $59 2,355 2.50 2025 $16.0 $26 $5 $12 $59 2,355 2.51 2026 $16.3 $27 $5 $12 $60 2,355 2.53 2027 $16.5 $27 $5 $12 $60 2,355 2.55 2028 $16.8 $27 $5 $12 $60 2,355 2.56 2029 2030 Total $206 $27 $233 $169 $64 Levelized Tariff (c/kWh): 2.67 (in 2004 prices)

Table A5.30: Bishkek II Sensitivity Analysis Percentage Change

in Parameter (%) Levelized Tariff

c/kWh

Percentage Change Lev

Tariff(%) Sensitivity Index a

Base Case 2.6743 Sensitivities (1) Change in Generation -20% 3.1178 16.6% (0.83) (2) Change in Interest Rates 1% 2.6822 0.3% 0.30 (3) Change in Return on Equity 1% 2.6800 0.2% 0.21 (4) Change in CapEx 1% 2.6866 0.5% 0.46 (5) Change in Fuel Price 1% 2.6833 0.3% 0.34 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

70

Table A5.31: Financial Analysis of Talimarjan - Phase I Power Project

Construction Period Operating Period

Year Capital Expenditures without IDC

IDC Capital Expenditures

with IDC

Debt Funded

Equity Funded

O&M Expenses

Fuel Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow

Generation Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2005 $102 $6 $108 $85 $23 2006 $8.1 $48 $9 $3 $68 4,266 1.60 2007 $8.2 $49 $9 $3 $69 4,266 1.62 2008 $8.3 $50 $9 $3 $70 4,266 1.64 2009 $8.4 $51 $9 $3 $71 4,266 1.66 2010 $8.6 $51 $9 $3 $72 4,266 1.68 2011 $8.7 $52 $16 $3 $80 4,266 1.88 2012 $8.8 $53 $15 $3 $80 4,266 1.88 2013 $9.0 $54 $15 $3 $80 4,266 1.89 2014 $9.1 $55 $14 $3 $81 4,266 1.89 2015 $9.2 $55 $13 $3 $81 4,266 1.90 2016 $9.4 $56 $12 $3 $81 4,266 1.90 2017 $9.5 $57 $12 $3 $81 4,266 1.91 2018 $9.7 $58 $11 $3 $82 4,266 1.92 2019 $9.8 $59 $10 $3 $82 4,266 1.92 2020 $10.0 $60 $10 $3 $82 4,266 1.93 2021 $10.1 $61 $3 $3 $77 4,266 1.80 2022 $10.3 $62 $3 $3 $78 4,266 1.82 2023 $10.4 $63 $3 $3 $79 4,266 1.84 2024 $10.6 $63 $2 $3 $80 4,266 1.87 2025 $10.7 $64 $2 $3 $81 4,266 1.89 2026 $10.1 $61 $3 $3 $77 4,266 1.80 2027 $10.3 $62 $3 $3 $78 4,266 1.82 2028 $10.4 $63 $3 $3 $79 4,266 1.84 2029 $10.6 $63 $2 $3 $80 4,266 1.87 2030 $10.7 $64 $2 $3 $81 4,266 1.89 Total $102 $6 $108 $85 $23 Levelized Tariff (c/kWh) : 1.75 (in 2004 prices)

Table A5.32: Talimardjan Phase I Sensitivity Analysis Percentage

Change in Parameter(%)

Levelized Tariff c/kWh

Percentage Change

Lev Tariff (%) Sensitivity Index a

Base Case 1.7490 Sensitivities (1) Change in Generation -20% 1.8770 7.3% (0.37) (2) Change in Interest Rates 1% 1.7506 0.1% 0.09 (3) Change in Return on Equity 1% 1.7497 0.0% 0.04 (4) Change in CapEx 1% 1.7520 0.2% 0.17 (5) Change in Fuel Price 1% 1.7614 0.7% 0.71 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

71

Table A5.33: Financial Analysis of Talimarjan - Phase II Power Project Construction Period Operating Period

Year Capital Expend. without

IDC

IDC

Capital Expend.

with IDC

Debt Funded

Equity Funded

O&M Expenses

Fuel Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow Generation Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2009 $130 $6 $136 $113 $23 2010 $397 $31 $428 $390 $38 2011 $448 $70 $518 $398 $120 2012 $318 $104 $422 $277 $145 2013 $46 $124 $170 $124 $46 2014 $130 $6 $136 $113 $23 2015 $24.2 $145 $130 $75 $375 12,796 2.93 2016 $24.6 $147 $130 $75 $377 12,796 2.95 2017 $24.9 $150 $130 $75 $380 12,796 2.97 2018 $25.3 $152 $130 $75 $383 12,796 2.99 2019 $25.7 $154 $130 $75 $385 12,796 3.01 2020 $26.1 $156 $239 $75 $497 12,796 3.88 2021 $26.5 $159 $228 $75 $488 12,796 3.82 2022 $26.9 $161 $217 $75 $480 12,796 3.75 2023 $27.3 $164 $206 $75 $472 12,796 3.69 2024 $27.7 $166 $195 $75 $464 12,796 3.63 2025 $28.1 $169 $185 $75 $457 12,796 3.57 2026 $28.6 $171 $174 $75 $449 12,796 3.51 2027 $29.0 $174 $163 $75 $441 12,796 3.45 2028 $29.4 $177 $152 $75 $433 12,796 3.38 2029 $29.9 $179 $141 $75 $425 12,796 3.32 2030 $30.3 $182 $43 $75 $331 12,796 2.59 2031 $30.8 $185 $41 $75 $332 12,796 2.59 2032 $31.3 $188 $39 $75 $333 12,796 2.60 2033 $31.7 $190 $37 $75 $334 12,796 2.61 2034 $32.2 $193 $35 $75 $335 12,796 2.62 2035 $30.3 $182 $43 $75 $331 12,796 2.59 2036 $30.8 $185 $41 $75 $332 12,796 2.59 2037 $31.3 $188 $39 $75 $333 12,796 2.60 2038 $31.7 $190 $37 $75 $334 12,796 2.61 Total $1,340 $335 $1,675 $1,303 $372 Levelized Tariff (c/kWh): 2.92 (in 2004 prices)

Table A5.34: Talimardjan Phase II Sensitivity Analysis Percentage

Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change

Lev Tariff (%)

Sensitivity Index a

Base Case 2.9168 Sensitivities (1) Change in Generation -20% 3.3893 16.2% (0.81) (2) Change in Interest Rates 1% 2.9305 0.5% 0.47 (3) Change in Return on Equity 1% 2.9258 0.3% 0.31 (4) Change in CapEx 1% 2.9340 0.6% 0.59 (5) Change in Fuel Price 1% 2.9217 0.2% 0.17 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

72

Table A5.35: Financial Analysis of Ekibastuz I Rehabilitation Project

Construction Period Operating Period

Year Capital Expend. without

IDC

IDC

Capital Expend.

with IDC

Debt Funded

Equity Funded

O&M Expenses

Fuel Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

OutflowGeneration Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2008 $47 $2 $49 $39 $10 2009 $143 $11 $154 $137 $17 2010 $146 $23 $169 $115 $54 2011 $148 $35 $183 $124 $59 2012 $81.4 $147 $42 $25 $295 11,283 2.62 2013 $82.7 $149 $42 $25 $299 11,283 2.65 2014 $83.9 $151 $42 $25 $302 11,283 2.68 2015 $85.2 $154 $42 $25 $306 11,283 2.71 2016 $86.5 $156 $42 $25 $310 11,283 2.74 2017 $87.8 $158 $76 $25 $348 11,283 3.08 2018 $89.1 $161 $73 $25 $348 11,283 3.09 2019 $90.5 $163 $69 $25 $349 11,283 3.09 2020 $91.9 $166 $66 $25 $349 11,283 3.09 2021 $93.3 $168 $62 $25 $349 11,283 3.10 2022 $94.7 $171 $59 $25 $350 11,283 3.10 2023 $96.1 $173 $55 $25 $350 11,283 3.11 2024 $97.6 $176 $52 $25 $351 11,283 3.11 2025 $99.1 $179 $49 $25 $352 11,283 3.12 2026 $100.6 $181 $45 $25 $353 11,283 3.12 2027 $102.1 $184 $14 $25 $326 11,283 2.89 2028 $103.7 $187 $13 $25 $329 11,283 2.92 2029 $105.2 $190 $12 $25 $333 11,283 2.95 2030 $106.8 $193 $12 $25 $337 11,283 2.99 2031 $108.5 $196 $11 $25 $341 11,283 3.02 2032 2033 Total $484 $71 $555 $416 $140 Levelized Tariff (c/kWh) : 2.66 (in 2004 prices)

Table A5.36: Ekibastuz I Rehabilitation Project Sensitivity Analysis Percentage

Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change

Lev Tariff (%)

Sensitivity Index a

Base Case 2.6617 Sensitivities (1) Change in Generation -20% 2.9956 12.5% (0.63) (2) Change in Interest Rates 1% 2.6665 0.2% 0.18 (3) Change in Return on Equity 1% 2.6649 0.1% 0.12 (4) Change in CapEx 1% 2.6677 0.2% 0.23 (5) Change in Fuel Price 1% 2.6750 0.5% 0.50 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

73

Table A5.37: Financial Analysis of Kazakhstan New Ekibastuz Project

Construction Period Operating Period

Year Capital Expend. without

IDC

IDC Capital Expend.

with IDC

Debt Funded

Equity Funded

O&M Expenses

Fuel Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow

Generation

Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh 2006 $197 $8 $205 $169 $36 2007 $200 $25 $225 $164 $60 2008 $270 $46 $316 $250 $66 2009 $274 $71 $345 $252 $93 2010 $209 $93 $302 $200 $102 2011 $212 $112 $324 $235 $89 2012 $42 $99 $127 $88 $356 6,850 5.20 2013 $42 $101 $127 $88 $358 6,850 5.23 2014 $43 $102 $127 $88 $360 6,850 5.26 2015 $44 $104 $127 $88 $363 6,850 5.29 2016 $44 $105 $127 $88 $365 6,850 5.33 2017 $45 $107 $233 $88 $473 6,850 6.90 2018 $46 $109 $222 $88 $465 6,850 6.78 2019 $46 $110 $212 $88 $456 6,850 6.66 2020 $47 $112 $201 $88 $448 6,850 6.54 2021 $48 $114 $190 $88 $440 6,850 6.42 2022 $48 $115 $180 $88 $432 6,850 6.31 2023 $49 $117 $169 $88 $424 6,850 6.19 2024 $50 $119 $159 $88 $416 6,850 6.07 2025 $51 $121 $148 $88 $408 6,850 5.95 2026 $51 $123 $138 $88 $400 6,850 5.84 2027 $52 $124 $42 $88 $307 6,850 4.48 2028 $53 $126 $40 $88 $308 6,850 4.49 2029 $54 $128 $38 $88 $308 6,850 4.50 2030 $55 $130 $36 $88 $309 6,850 4.51 2031 $55 $132 $34 $88 $310 6,850 4.52 Total $1,361 $356 $1,717 $1,270 $447 Levelized Tariff (c/kWh): 5.05 (in 2004 prices)

Table A5.38: Kazakhstan New Ekibastuz Sensitivity Analysis Percentage

Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change

Lev Tariff (%) Sensitivity Index a

Base Case 5.0468 Sensitivities (1) Change in Generation -20% 5.6524 12.0% (0.60) (2) Change in Interest Rates 1% 5.0700 0.5% 0.46 (3) Change in Return on Equity 1% 5.0720 0.5% 0.50 (4) Change in CapEx 1% 5.0766 0.6% 0.59 (5) Change in Fuel Price 1% 5.0614 0.3% 0.29 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

74

Table A5.39: Financial Analysis of Surhan - Mashad Transmission Line Project

Construction Period Operating Period

Capital Expend. Without

IDC

IDC

Capital Expend.

With IDC

Debt Funded

Equity Funded

O&M Expenses

Debt Service

Expenses

ReturnOn

Equity

Total Cash

OutflowTransm Annual

Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh

Year 1 $86 $4 $89 $72 $17

Year 2 $139 $13 $152 $123 $29

Year 3 $124 $24 $148 $98 $50

Year 4 $0.3 $29 $17 $47 9,440 0.49

Year 5 $0.3 $29 $17 $47 9,440 0.49

Year 6 $0.3 $29 $17 $47 9,440 0.49

Year 7 $0.3 $29 $17 $47 9,440 0.49

Year 8 $0.3 $29 $17 $47 9,440 0.49

Year 9 $0.3 $54 $17 $71 9,440 0.75

Year 10 $0.3 $51 $17 $69 9,440 0.73

Year 11 $0.3 $49 $17 $66 9,440 0.70

Year 12 $0.3 $47 $17 $64 9,440 0.68

Year 13 $0.3 $44 $17 $61 9,440 0.65

Year 14 $0.4 $42 $17 $59 9,440 0.62

Year 15 $0.4 $39 $17 $56 9,440 0.60

Year 16 $0.4 $37 $17 $54 9,440 0.57

Year 17 $0.4 $34 $17 $52 9,440 0.55

Year 18 $0.4 $32 $17 $49 9,440 0.52

Year 19 $0.4 $10 $17 $27 9,440 0.29

Year 20 $0.4 $9 $17 $27 9,440 0.28

Year 21 $0.4 $9 $17 $26 9,440 0.28

Year 22 $0.4 $8 $17 $26 9,440 0.27

Year 23 $0.4 $8 $17 $25 9,440 0.27

Total $225 $41 $266 $170 $96

Levelized Tariff (c/kWh) 0.54

Table A5.40: Surhan - Mashad Transmission Line Sensitivity Analysis

Percentage Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change Lev Tariff (%) Sensitivity Index a

Base Case 0.5075 Sensitivities (1) Change in Generation -20% 0.6344 25.0% (1.25) (2) Change in Interest Rates 1% 0.5106 0.6% 0.61 (3) Change in Return on Equity 1% 0.5094 0.4% 0.38 (4) Change in CapEx 1% 0.5125 1.0% 0.99 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

75

Table A5.41: Financial Analysis of Kandahar - Karachi Transmission Line Project

Construction Period Operating Period

Year Capital Expend. without

IDC

IDC

Capital Expend.

with IDC

Debt Funded Equity Funded O&M

Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

OutflowTransm Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh Year 1 $85 $3 $88 $59 $29

Year 2 $200 $14 $215 $166 $48 Year 3 $0.2 $23 $13 $36 3,824 0.94 Year 4 $0.2 $23 $13 $36 3,824 0.94 Year 5 $0.2 $23 $13 $36 3,824 0.94 Year 6 $0.2 $23 $13 $36 3,824 0.94 Year 7 $0.2 $23 $13 $36 3,824 0.94 Year 8 $0.2 $41 $13 $55 3,824 1.43 Year 9 $0.2 $39 $13 $53 3,824 1.38 Year 10 $0.2 $38 $13 $51 3,824 1.33 Year 11 $0.2 $36 $13 $49 3,824 1.28 Year 12 $0.2 $34 $13 $47 3,824 1.23 Year 13 $0.2 $32 $13 $45 3,824 1.18 Year 14 $0.2 $30 $13 $43 3,824 1.13 Year 15 $0.2 $28 $13 $41 3,824 1.08 Year 16 $0.2 $26 $13 $40 3,824 1.04 Year 17 $0.3 $24 $13 $38 3,824 0.99 Year 18 $0.3 $15 $13 $28 3,824 0.74 Year 19 $0.3 $6 $13 $20 3,824 0.52 Year 20 $0.3 $6 $13 $19 3,824 0.51 Year 21 $0.3 $6 $13 $19 3,824 0.50 Year 22 $0.3 $5 $13 $19 3,824 0.49

Total $285 $17 $302 $225 $77 Levelized Tariff (c/kWh): 1.03

Table A5.42: Kandahar - Karachi Transmission Line Sensitivity Analysis

Percentage Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change Lev Tariff (%) Sensitivity Index a

Base Case 0.9839 Sensitivities (1) Change in Generation -20% 1.2299 25.0% (1.25) (2) Change in Interest Rates 1% 0.9892 0.5% 0.54 (3) Change in Return on Equity 1% 0.9876 0.4% 0.37 (4) Change in CapEx 1% 0.9937 1.0% 0.99 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

76

Table A5.43: Financial Analysis of Kabul - Kandahar Transmission Line Project Construction Period Operating Period

Year Capital Expend. without

IDC

IDC

Capital Expend.

with IDC

Debt Funded Equity Funded O&M

Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

OutflowTransm Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh Year 1 $51 $2 $53 $35 $17

Year 2 $120 $9 $129 $100 $29 Year 3 $0.1 $14 $8 $21 4,872 0.44 Year 4 $0.1 $14 $8 $21 4,872 0.44 Year 5 $0.1 $14 $8 $21 4,872 0.44 Year 6 $0.1 $14 $8 $21 4,872 0.44 Year 7 $0.1 $14 $8 $21 4,872 0.44 Year 8 $0.1 $25 $8 $33 4,872 0.67 Year 9 $0.1 $24 $8 $32 4,872 0.65 Year 10 $0.1 $23 $8 $31 4,872 0.63 Year 11 $0.1 $21 $8 $29 4,872 0.60 Year 12 $0.1 $20 $8 $28 4,872 0.58 Year 13 $0.1 $19 $8 $27 4,872 0.56 Year 14 $0.1 $18 $8 $26 4,872 0.53 Year 15 $0.1 $17 $8 $25 4,872 0.51 Year 16 $0.1 $16 $8 $24 4,872 0.49 Year 17 $0.1 $15 $8 $23 4,872 0.46 Year 18 $0.1 $5 $8 $12 4,872 0.26 Year 19 $0.1 $4 $8 $12 4,872 0.25 Year 20 $0.1 $4 $8 $12 4,872 0.25 Year 21 $0.1 $4 $8 $12 4,872 0.24 Year 22 $0.1 $4 $8 $12 4,872 0.24

Total $171 $10 $182 $135 $46 Levelized Tariff (c/kWh): 049

Table A5.44: Kabul - Kandahar Transmission Line Sensitivity Analysis

Percentage Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change Lev Tariff (%) Sensitivity Index a

Base Case 0.4636 Sensitivities (1) Change in Generation -20% 0.5795 25.0% (1.25) (2) Change in Interest Rates 1% 0.4661 0.5% 0.54 (3) Change in Return on Equity 1% 0.4653 0.4% 0.37 (4) Change in CapEx 1% 0.4698 1.3% 1.34 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

77

Table A5.45: Financial Analysis of Almaty - Urumqui Transmission Line Project

Construction Period Operating Period

Year

Capital Expend. without

IDC

IDC

Capital Expend

with IDC

Debt Funded Equity Funded O&M

Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow Trans Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh Year 1 $104 $4 $108 $86 $22

Year 2 $169 $16 $185 $148 $37 Year 3 $150 $29 $179 $116 $63 Year 4 $0.4 $35 $22 $57 9,540 0.60 Year 5 $0.4 $35 $22 $57 9,540 0.60 Year 6 $0.4 $35 $22 $57 9,540 0.60 Year 7 $0.4 $35 $22 $57 9,540 0.60 Year 8 $0.4 $35 $22 $57 9,540 0.60 Year 9 $0.4 $64 $22 $87 9,540 0.91 Year 10 $0.4 $61 $22 $84 9,540 0.88 Year 11 $0.5 $58 $22 $81 9,540 0.85 Year 12 $0.5 $55 $22 $78 9,540 0.82 Year 13 $0.5 $53 $22 $75 9,540 0.78 Year 14 $0.5 $50 $22 $72 9,540 0.75 Year 15 $0.5 $47 $22 $69 9,540 0.72 Year 16 $0.5 $44 $22 $66 9,540 0.69 Year 17 $0.5 $41 $22 $63 9,540 0.66 Year 18 $0.5 $38 $22 $60 9,540 0.63 Year 19 $0.5 $12 $22 $34 9,540 0.36 Year 20 $0.5 $11 $22 $33 9,540 0.35 Year 21 $0.5 $11 $22 $33 9,540 0.34 Year 22 $0.5 $10 $22 $32 9,540 0.34 Year 23 $0.5 $9 $22 $32 9,540 0.33

Total $422 $50 $472 $350 $122 Levelized Tariff (c/kWh): 0.72

Table A5.46: Almaty - Urumqui Transmission Line Sensitivity Analysis

Percentage Change in

Parameter(%)

Levelized Tariff c/kWh

Percentage Change Lev Tariff (%) Sensitivity Index a

Base Case 0.6176 Sensitivities (1) Change in Generation -20% 0.7720 25.0% (1.25) (2) Change in Interest Rates 1% 0.6212 0.6% 0.59 (3) Change in Return on Equity 1% 0.6200 0.4% 0.39 (4) Change in CapEx 1% 0.6237 1.0% 0.99 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

78

Table A5.47: Financial Analysis of Kabul - Tarbela Transmission Line Project

Construction Period Operating Period

Year Capital Expend. without

IDC

IDC

Capital Expend.

with IDC

Debt Funded Equity Funded O&M

Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

OutflowTransm Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh Year 1 $32 $1 $33 $22 $11

Year 2 $76 $5 $82 $64 $18 Year 3 $0.10 $9 $5 $14 2,946 0.46 Year 4 $0.11 $9 $5 $14 2,946 0.46 Year 5 $0.11 $9 $5 $14 2,946 0.46 Year 6 $0.11 $9 $5 $14 2,946 0.46 Year 7 $0.11 $9 $5 $14 2,946 0.46 Year 8 $0.11 $16 $5 $21 2,946 0.71 Year 9 $0.11 $15 $5 $20 2,946 0.68 Year 10 $0.12 $14 $5 $19 2,946 0.66 Year 11 $0.12 $14 $5 $19 2,946 0.63 Year 12 $0.12 $13 $5 $18 2,946 0.61 Year 13 $0.12 $12 $5 $17 2,946 0.59 Year 14 $0.12 $11 $5 $17 2,946 0.56 Year 15 $0.12 $11 $5 $16 2,946 0.54 Year 16 $0.13 $10 $5 $15 2,946 0.51 Year 17 $0.13 $9 $5 $14 2,946 0.49 Year 18 $0.13 $3 $5 $8 2,946 0.27 Year 19 $0.13 $3 $5 $8 2,946 0.27 Year 20 $0.13 $3 $5 $8 2,946 0.26 Year 21 $0.14 $2 $5 $8 2,946 0.26 Year 22 $0.14 $2 $5 $7 2,946 0.25

Total $109 $7 $115 $86 $29 Levelized Tariff (c/kWh) 0.51

Table A5.48: Kabul - Tarbela Transmission Line Sensitivity Analysis

Percentage Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change Lev Tariff (%) Sensitivity Index a

Base Case 0.4878 Sensitivities (1) Change in Generation -20% 0.6098 25.0% (1.25) (2) Change in Interest Rates 1% 0.4905 0.5% 0.54 (3) Change in Return on Equity 1% 0.4896 0.4% 0.37 (4) Change in CapEx 1% 0.4927 1.0% 0.99 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

79

Table A5.49: Financial Analysis of Surhan - Kabul Transmission Line Project

Construction Period Operating Period

Year Capital Expenditures without IDC

IDC Capital

Expenditures with IDC

Debt Funded Equity Funded O&M

Expenses

Debt Service

Expenses

Return on

Equity

Total Cash

Outflow Trans Annual Tariff

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh c/kWh

Year 1 $46 $2 $48 $30 $18 Year 2 $125 $9 $134 $104 $30 Year 3 $0.20 $14 $8 $22 4,865 0.46 Year 4 $0.21 $14 $8 $22 4,865 0.46 Year 5 $0.21 $14 $8 $22 4,865 0.46 Year 6 $0.21 $14 $8 $23 4,865 0.46 Year 7 $0.22 $14 $8 $23 4,865 0.46 Year 8 $0.22 $26 $8 $34 4,865 0.70 Year 9 $0.22 $25 $8 $33 4,865 0.68 Year 10 $0.23 $24 $8 $32 4,865 0.65 Year 11 $0.23 $22 $8 $31 4,865 0.63 Year 12 $0.23 $21 $8 $30 4,865 0.61 Year 13 $0.24 $20 $8 $28 4,865 0.58 Year 14 $0.24 $19 $8 $27 4,865 0.56 Year 15 $0.24 $18 $8 $26 4,865 0.53 Year 16 $0.25 $16 $8 $25 4,865 0.51 Year 17 $0.25 $15 $8 $24 4,865 0.48 Year 18 $0.25 $5 $8 $13 4,865 0.27 Year 19 $0.26 $4 $8 $13 4,865 0.26 Year 20 $0.26 $4 $8 $13 4,865 0.26 Year 21 $0.27 $4 $8 $12 4,865 0.25 Year 22 $0.27 $4 $8 $12 4,865 0.25

Total $171 $11 $182 $134 $48 Levelized Tariff (c/kWh) 0.51

Table A5.50: Surhan - Kabul Transmission Line Sensitivity Analysis

Percentage Change in Parameter (%)

Levelized Tariff c/kWh

Percentage Change Lev Tariff (%) Sensitivity Index a

Base Case 0.5061 Sensitivities (1) Change in Generation -20% 0.6320 25.0% (1.25) (2) Change in Interest Rates 1% 0.5087 0.5% 0.54 (3) Change in Return on Equity 1% 0.5078 0.4% 0.37 (4) Change in CapEx 1% 0.5111 1.0% 0.99 a) Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff.

80

Appendix 7.1 Central Asia

Regional Electricity Export Potential Study Establishment of Water Energy Consortium-Conceptual Approaches

Conceptual Approaches of the Experts of the Republic of Kazakhstan, the Kyrgyz Republic, Tajikistan and Uzbekistan

Towards Creation of Water and Energy Consortium

To implement the instructions of the heads of the Republic of Kazakhstan, Kyrgyzstan, Tajikistan and Uzbekistan as of July 5-6, 2003, on the issues of creation of an International Water and Energy Consortium (hereinafter – the IWEC) the following basic conceptual approaches are proposed:

1. Conditions of Creation

IWEC shall be created based on the intergovernmental agreement where each of the member countries determines the IWEC founders. It is important for the parties’ Governments to create necessary conditions of their founders for parity participation in the Consortium of the latter; IWEC shall be a legal entity with the charter, address, settlement and currency accounts, and other attributes of an interstate organization. Its activity shall be guided by the laws of the country of destination; It shall be generally managed by the Council (or Board) of the authorized Consortium representatives formed by equal representation of the parties. In the process of decision making each party shall have equal votes. The decisions shall be made on the assumption of full parties’ agreement; Within the framework of International Water and Energy Consortium distribution of water resources will be performed in the economic interests of the CACO member countries;

All countries shall fulfill the common requirement on trans-border rivers;

Legal status, start-up conditions, establishment conditions and the authorized fund size along with the other conditions of Consortium creation shall be defined by the intergovernmental agreement; The member countries of the Consortium when using trans-border waterways on all territory shall apply all appropriate measures to prevent damage to other countries in compliance with the principles and norms of International Law.

2. Goals and Objectives

(a) Ensuring optimum proportion between the energy and irrigation regimes for operation of cascades of water reservoirs in annual and perennial cycles breakdown with consideration of balances of fuel-energy resources of the IWEC member countries;

(b) Ensuring implementation of international agreement of CACO member countries on the issues of cross-supply of water, energy and power sources;

81

(c) Attracting investments for reconstruction of the existing and construction of new water and water-energy facilities for development and effective use of water and energy potential of the region;

(d) Creating conditions for production and technological cooperation of water and fuel-energy sectors, expanding their export potential, and introduction of innovation technologies;

(e) The other functions determined by the inter-state and inter-governmental agreements can be committed to the Consortium.

3. Main Activity Directions Coordination of joint activity of water and fuel-energy entities of the member countries in the area of rational and effective use of water and energy resources within the competence provided by the founders;

Creating conditions for ensuring economical and effective operation of energy systems, taking advantages of parallel operation, established regime of reservoirs operation, and interstate supplies of fuel-energy resources and flows of electric energy in volumes determined by the agreements and treaties;

Preparing proposals on rapprochement of legislations, improvement of legal frameworks enabling the entities to implement their activities based on a single legislative framework in the area of rational use of water and energy resources with consideration of international law;

Pursuing investment policy oriented on construction of new (Rogun hydropower station in Tajikistan, Kambarata hydropower stations in Kyrgyzstan, and other facilities) and rehabilitation, modernization of the existing capacities;

Interacting with interstate and intergovernmental bodies, and state organizations, economic entities of the member-countries of the Consortium;

Ensuring functioning of the coordinated mechanism of cross-payments and payment for interstate electric power flows and fuel-energy resources supplies;

Participating in preparation of interstate and intergovernmental agreements on developing cooperation in the area of electric power and water; The other functions determined by the inter-state and inter-governmental agreements can be committed to the Consortium.

From Experts' Group of the Republic of Kazakhstan From Experts' Group of the Kyrgyz Republic From Experts' Group of the Republic of Tajikistan From Experts' Group of the Republic of Uzbekistan

82

Opinions and Proposals of the Republic of Uzbekistan (in hand writing)

Amu Darya and Naryn – Syr Darya are the trans-border rivers. Any changes in their regimes enabled by previously approved documents on distribution of water resources are the breach of regime of water reservoirs cascade. Coordination with other countries is required.

At time of creation of IWEC the charge for water resources has not been considered, and distribution of water resources cannot be performed for commercial purposes.

<signature>

1.04.2004

Proposals of the national experts: there is a need for establishing a regional working group to elaborate in details the

Feasibility Study and the funding mechanisms considering the issues of related sectors’ cooperation, study of the legal framework, and determination of the share of each CACO’ Parties in this Consortium;

during the preparation of the Feasibility Study it is also necessary to envisage the principle of financing the authorized fund being established, economic benefits from the activities of the consortium, and the principle of distribution of the benefits gained;

it is necessary to address international financial institution with the request for practical and technical assistance, and financial assistance, if needed, for the preparation of the Feasibility Study for the establishment of the consortium.

83

Appendix 7.2

Central Asia Regional Electricity Export Potential Study

Theun-Hinboun Hydropower Project - Lao Theun Hinboun hydropower project, is an inter-basin transfer scheme in the Lao People’s Republic (Lao PDR) designed to export power to neighboring Thailand. The main objective of this project was to support economic growth in the Lao PDR by enhancing foreign exchange earnings through the export of power to Thailand. It diverts 110m3/sec of river flow from the Nam Theun basin into the Nam Hinboun basin (this combination gives the project its name) through a 5.2km headrace tunnel into a power station lying some 240m below the level of the reservoir created by the dam on the Nam Theun. The capacity of the plant is 210 MW and the average annual generation potential is 1,645 GWh.

The Project is very good example of public private partnership, as well as of importers of power having equity stake in the generation company. The total estimated project cost of $240 M was funded by 46% equity and 54% debt. 60% of the equity was provided by the Lao PDR Government through its state owned power utility, Electricity du Laos (EdL). The other investors that make up the consortium are: MDX Lao Company Ltd. of Thailand (20%); and Nordic Hydropower AB of Sweden (20%), itself a consortium of the two largest Nordic hydro utilities, Norway's Statkraft and Sweden's Vattenfall each with equal shares in Nordic Hydropower. The debt funds were provided by the Government, Commercial Loans and Export Credit. Further Asian Development Bank partially financed the Lao PDR Government’s equity through a $60 M loan from its soft loan window.

The power is sold to Electricity Generating Authority of Thailand (EGAT) through a 25 year Power Purchase Agreement based on a take-or-pay principle by which EGAT undertook to purchase 95% of the Project’s available energy output.

Figure A7.1: Ownership Structure of Theun-Hinboun Power Company

84

Figure A7.2: Financial Structure of Theun-Hinboun Power Company

85

Appendix 8.1 Central Asia

Regional Electricity Export Potential Study Options For De-Congesting the Southern Central Asian Power System

At present Tajikistan supplies power from its southern part to its northern part and further to Kazakhstan through Uzbekistan, the latter often claims transmission capacity limitations. These capacity constraints are likely to be exacerbated once the Talimardjan I plant starts dispatching. Therefore Tajikistan is examining options to transmit its power generated in the south of the country to its north and beyond The construction of a north-south 500 kV transmission line from SS Regar to northern Tajikistan is one such option. At the same time, the Kyrgyz Republic and Tajikistan have decided to interconnect themselves in the Fergana valley and are building a 54 km 220 kV transmission line between Batken (the Kyrgyz Republic) and Kanibodom (Tajikistan). In view of the expected growth in demand in the region, new generation sources coming on stream (e.g., Sangtuda I) and new markets (e.g., Russia and Afghanistan) on a seasonal basis, it would make sense to examine the option of linking the Toktogul cascade in the Kyrgyz Republic with the Nurek cascade in Tajikistan. This would have the dual advantage of de-congesting southern CAPS and enhance exports on a seasonal basis. In order to complete this Naryn Nurek link, the key element is the South North Line in Tajikistan linking Nurek with Khodjand. In addition, some improvements to the associated 220 kV system in Tajikistan and the Kyrgyz Republic need to be done as follows: (see Figure A8.1 showing the locations): • A 220 kV line (a) between SS Aigul-Tash (Batken, Kyrgyzstan) – SS Kanibodom

(Tajikistan). SS Kanibodon has developed connections to the Southern Tajikistan power grid by 220 kV and 110 kV lines (b);

• A new 500/220 kV SS Dakta in Kyrgyzstan (c). As a Phase I, SS Datka could be constructed as a 220 kV switch yard;

• An 80 km length 220 kV line tap (d) from SS Datka to 220 kV line Kurpsay-Crystal; • A 6 km length 220 kV line tap (e) from SS Datka to 220 kV line Kurpsay – Oktiabrskaya; • A new 120 km length 220 kV line(f) Osh – Datka; and • A 30 km length line tap (g) from SS Alay to 220 kV line Osh – Lochin (Uzbekistan). The first of these is already under construction by Kyrgyz and Tajik governments using their own resources. The other elements need to be funded and construction started. Some alternative configurations are also under study for these elements. These aspects will have to be studied further in detail.

86

Figure A8.1: Tajikistan North South 500 kV Line and De-conjunction of the Power Transmission in the Southern CAPS

Assessment of the North South Line in Tajikistan This would be the key (and highest cost) element of the Toktogul-Nurek Link. The capital cost of constructing this 350 km line, a new substation and rehabilitating one existing substation is estimated at $ 145.6 million. The construction can be completed in three years. Conservatively it is assumed that the line will carry 3000 GWh annually even though, according to Fichtner International the maximum annual carrying capacity of the line is actually 8300 GWh. The line losses are assumed at 1.4% and substation losses are assumed at 0.4%. Incremental O&M expenses are assumed at 0.05% of the capital costs. On this basis, the average incremental cost (the economic cost) of transmission is estimated at 0.63 cents/kWh (see Table A8.1). At the initial likely levels of loading at about 3600 GWh/year the AIC will come down to 0.53 cents.

87

Table A8.1: Tajikistan South North Transmission Line AIC (Economic) of Transmission

Year Capital

Investments (% of total)

Incremental Transmission

(GWh)

Capital Investments

(US$ Million)

IncrementalO&M Exp.

(US$ Million)

Cumulative O&M Exp.

(US$ Million)

Total Incremental

Costs (US$M)

Incremental Sales

(GWh)

Year 1 0 Year 2 30 43.67 0.02 0.02 43.69 0 Year 3 40 58.22 0.03 0.05 58.27 0 Year 4 30 900 43.67 0.02 0.07 43.74 884 Year 5 2100 0.07 0.07 2946 Year 6 0.07 0.07 2946 Year 7 0.07 0.07 2946 Year 8 0.07 0.07 2946 Year 9 0.07 0.07 2946 Year 10 0.07 0.07 2946 Year 11 0.07 0.07 2946 Year 12 0.07 0.07 2946 Year 13 0.07 0.07 2946 Year 14 0.07 0.07 2946 Year 15 0.07 0.07 2946 Year 16 0.07 0.07 2946 Year 17 0.07 0.07 2946 Year 18 0.07 0.07 2946 Year 19 0.07 0.07 2946 Year 20 0.07 0.07 2946 Year 21 0.07 0.07 2946 Year 22 0.07 0.07 2946 Year 23 0.07 0.07 2946

Present Values (23 years) Incremental Costs (US$ million) 121.2Incremental Sales (million kWh) 191790Average Incremental Costs of Transmission (cents/kWh) 0.63

Data Source: Barki Tajik Report

88

On the basis of financing assumptions similar to those employed for the financial analysis of all other export transmission lines elsewhere in this report, the levelized transmission tariff needed for the service by this line would be 0.92 cents/kWh (see Table A8.2).

Table A8.2: Tajikistan South North Transmission Line Levelized Tariff Calculations Construction Period Operating Period

Year Capital Expend. Without

IDC

IDC Capital Expend.

With IDC

Debt Equity O&M Expense

Debt Service Expense

Return on

Equity

Total Cash

Outflow

Net Electricity

Transmitted

Annual Tariff c/kWh

($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) ($ M) GWh Year 1 50 2 52 35 17 Year 2 68 6 74 45 29 Year 3 52 9 61 20 41 Year 4 0.02 10 15 26 2,946 0.87 Year 5 0.02 10 15 26 2,946 0.87 Year 6 0.02 10 15 26 2,946 0.87 Year 7 0.02 10 15 26 2,946 0.87 Year 8 0.02 18 15 34 2,946 1.15 Year 9 0.02 18 15 33 2,946 1.12 Year 10 0.02 17 15 32 2,946 1.10 Year 11 0.02 16 15 31 2,946 1.07 Year 12 0.02 15 15 31 2,946 1.04 Year 13 0.02 14 15 30 2,946 1.01 Year 14 0.02 13 15 29 2,946 0.98 Year 15 0.02 13 15 28 2,946 0.95 Year 16 0.02 12 15 27 2,946 0.92 Year 17 0.02 11 15 26 2,946 0.90 Year 18 0.03 3 15 19 2,946 0.64 Year 19 0.03 3 15 19 2,946 0.63 Year 20 0.03 3 15 19 2,946 0.63 Year 21 0.03 3 15 18 2,946 0.62 Year 22 0.03 3 15 18 2,946 0.62 Year 23 0.03 3 15 18 2,946 0.62 Total 171 17 187 101 86 Levelized Tariff (c/kWh): 0.92

saecatj001 E:\Tajik 05\Backup of REEPS Appendix Volume 050115.wbk January 16, 2005 7:27 PM