33877 v 2 CENTRAL ASIA REGIONAL ELECTRICITY EXPORT POTENTIAL STUDY Appendix Volume EUROPE AND CENTRAL ASIA REGION WORLD BANK, WASHINGTON, D.C. DECEMBER 2004 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 Consortium­Conceptual Approaches Appendix 7.2: Laos Theun-Hinboun Hydropower Project Appendix 8.1: Options for De-congesting Southern Central Asian Power System 2 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) 41,4003) 47,174 49,317 Total Domestic Generation GWh 46,600 3) 45,000 3) 48,9003) 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 Supply5) % 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) 3 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. Policy Private Power Plants State Property and Committee on Ministry of Energy, 85 percent capacity Privatization Natural Industry and Trade State Power Plants Committee Monopolies KEGOC Private Distribution Public Distribution Public Distribution Public Distribution Companies Companies Companies Companies Final Consumers 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 1The 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. 4 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 USĒ/kWh to just below 1 USĒ/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 USĒ/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 USĒ/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 5 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. 2Naryn is the major tributary of Syr Darya River 6 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. 7 Policy State Commission on JSC Electric State Energy PM Department of Fuel- Property, Investment Power Plants Agency Energy, Infrastructure owner of all electricity and Communications supply facilities JSC National Grid Serva (North) Electra Vastock (East) (Bishkek, Chuj and Oshelectro (Osh Jalal-Abadelectro Electro (Issyk-Kul Talas oblasts) Oblast) (Jalal-Abad Oblast) and Naryn Oblasts) Final Consumers 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. 8 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 9 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 6Kyrgyz Republic, Uzbekistan, Kazakhstan and Tajikistan 7It is a 126 MW storage hydro power station in the northern Grid of Tajikistan. 10 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. Policy and Regulation State Commission on Inter-Agency Ministry of Energy Property, Investment Commitee owner of all electricity Electricity Department supply facilities State Joint Holding Company (SJHC) Barki Tajik Generation and Distribution Company 10 repair, construction, material- Northern, technical provision enterprises Southern and Eastern Final Consumers 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 11 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. 12 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 13 settlement does not always work logically and available cash is distributed among the participants of the market using ad hoc formulae. Policy Cabinet of Ministers JSC Uzbekenergo determines Regulatory Uzgosenergonadzor Affiliated Companies Coal Design, Generation; JSC construction- UzEnergoSbyt erection, repair and (single buyer / seller) other enterprises Affiliated Companies UzelectroSet (transmission system) Affiliated Companies 16Generation, 15 Distribution etc Final Consumers 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 USĒ/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. 14 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. 15 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. 16 Table A4.2: Long Run Average Incremental Cost Country Long Run Average Incremental Average Tariff in 2003 Tariff (USĒ/kWh) (USĒ/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 9Note that the collection rate refers to cash collections only. 10The 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. 17 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) 18 Table A4.7: Seasonal electricity demand (gross) in Kazakhstan and the Kyrgyz Republic, in GWh, 2005-2025 Kazakhstan The Kyrgyz Republic Monthly Monthly Cons. 2005 2010 2015 2020 2025 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 Monthly Cons. 2005 2010 2015 2020 2025 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 19 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. 20 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. 21 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). TWh 250.0 200.0 150.0 100.0 50.0 0.0 2005 2010 2015 2020 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. 11as 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. 22 (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 1% Change in Income Elasticity 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 23 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. 24 Demand Forecasts: Sensitivity Analysis Key Parameters: Base Case Cost Recovery Tariff Country Price Elasticity Income Elasticity GDP Growth in Level USc/kWh Year Tariffs reach 2007-2025 p.a. Cost Recovery Level 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% Table A4.16: Kazakhstan. Electricity Demand Supply Balance in 2005-2025 Table A4.17: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 27984 32211 40215 42771 45449 Supply 7961 8969 9786 9696 9696 Summer Demand 24786 28588 33340 39026 45683 Summer Demand 3224 2686 2922 3290 3705 Surplus (+) / Deficit (-) 3198 3623 6876 3745 -234 Surplus (+) / Deficit (-) 4737 6283 6863 6406 5991 Supply 35185 40500 50564 53778 57145 Supply 5754 8120 8628 13767 13767 Winter Demand 37689 43468 50694 59341 69463 Winter Demand 7845 6536 7111 8006 9014 Surplus (+) / Deficit (-) -2504 -2969 -130 -5563 -12318 Surplus (+) / Deficit (-) -2092 1584 1517 5761 4753 Supply 63169 72710 90780 96550 102594 Supply 13714 17089 18414 23463 23463 Annual Demand 62475 72056 84034 98367 115146 Annual Demand 11069 9222 10033 11296 12719 Surplus (+) / Deficit (-) 694 654 6746 -1818 -12552 Surplus (+) / Deficit (-) 2645 7866 8381 12167 10744 Table A4.18: Tajikistan. Electricity Demand Supply Balance in 2005-2025 Table A4.19: Uzbekistan. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 9158 10821 13581 20176 20176 Supply 23482 26149 32104 32104 31918 Summer Demand 7648 6233 6814 7597 8479 Summer Demand 21862 22245 24469 27016 29827 Surplus (+) / Deficit (-) 1511 4587 6767 12579 11697 Surplus (+) / Deficit (-) 1620 3904 7635 5088 2091 Supply 6665 7875 9883 14683 14683 Supply 26794 29837 36632 36632 36419 Winter Demand 6569 5033 5596 6375 7252 Winter Demand 23932 24352 26786 29574 32652 Surplus (+) / Deficit (-) 96 2841 4287 8308 7431 Surplus (+) / Deficit (-) 2862 5485 9846 7058 3767 Supply 15823 18695 23464 34859 34859 Supply 50277 55986 68736 68736 68337 Annual Demand 14216 11267 12410 13972 15731 Annual Demand 45794 46597 51255 56589 62479 Surplus (+) / Deficit (-) 1607 7429 11055 20887 19128 Surplus (+) / Deficit (-) 4483 9389 17481 12147 5858 Table A4.20: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025 Year 2005 2010 2015 2020 2025 Supply 68585 78149 95686 104748 107239 Summer Demand 57520 59753 67544 76929 87694 Surplus (+) / Deficit (-) 11066 18396 28142 27819 19545 Supply 74398 86331 105708 118860 122014 Winter Demand 76035 79390 90187 103296 118381 Surplus (+) / Deficit (-) -1637 6942 15521 15564 3633 Supply 142984 164480 201394 223608 229253 Annual Demand 133554 139142 157731 180225 206075 Surplus (+) / Deficit (-) 9430 25338 43663 43383 23178 25 Demand Forecast: Sensitivity Analysis Key Parameters: High Case 1 Cost Recovery Tariff Country Price Elasticity Income Elasticity GDP Growth in Level USc/kWh Year Tariffs reach 2007-2025 p.a. Cost Recovery Level 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- 2003- 2003- 2003- 2010 2015 2020 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% Table A4.23: The Kyrgyz Republic. Electricity Demand Supply Balance in Table A4.22: Kazakhstan. Electricity Demand Supply Balance in 2005-2025 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 27984 32211 40215 42771 45449 Supply 7961 8969 9786 9696 9696 Summer Demand 24786 28588 33340 39026 45683 Summer Demand 3323 2932 3001 3358 3781 Surplus (+) / Deficit (-) 3198 3623 6876 3745 -234 Surplus (+) / Deficit (-) 4638 6037 6784 6338 5915 Supply 35185 40500 50564 53778 57145 Supply 5754 8120 8628 13767 13767 Winter Demand 37689 43468 50694 59341 69463 Winter Demand 8086 7135 7303 8171 9199 Surplus (+) / Deficit (-) -2504 -2969 -130 -5563 -12318 Surplus (+) / Deficit (-) -2332 985 1325 5596 4568 Supply 63169 72710 90780 96550 102594 Supply 13714 17089 18414 23463 23463 Annual Demand 62475 72056 84034 98367 115146 Annual Demand 11409 10067 10305 11528 12980 Surplus (+) / Deficit (-) 694 654 6746 -1818 -12552 Surplus (+) / Deficit (-) 2305 7022 8109 11935 10483 Table A4.24: Tajikistan. Electricity Demand Supply Balance in 2005-2025 Table A4.25: Uzbekistan. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 9158 10821 13581 20176 20176 Supply 23482 26149 32104 32104 31918 Summer Demand 9431 8431 7561 8264 9224 Summer Demand 21862 22245 24469 27016 29827 Surplus (+) / Deficit (-) -273 2390 6020 11912 10952 Surplus (+) / Deficit (-) 1620 3904 7635 5088 2091 Supply 6665 7875 9883 14683 14683 Supply 26794 29837 36632 36632 36419 Winter Demand 8101 6807 6210 6935 7889 Winter Demand 23932 24352 26786 29574 32652 Surplus (+) / Deficit (-) -1436 1067 3674 7748 6794 Surplus (+) / Deficit (-) 2862 5485 9846 7058 3767 Supply 15823 18695 23464 34859 34859 Supply 50277 55986 68736 68736 68337 Annual Demand 17532 15238 13771 15199 17113 Annual Demand 45794 46597 51255 56589 62479 Surplus (+) / Deficit (-) -1709 3457 9694 19660 17747 Surplus (+) / Deficit (-) 4483 9389 17481 12147 5858 Table A4.26: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025 Year 2005 2010 2015 2020 2025 Supply 68585 78149 95686 104748 107239 Summer Demand 59402 62196 68371 77664 88515 Surplus (+) / Deficit (-) 9183 15953 27315 27084 18725 Supply 74398 86331 105708 118860 122014 Winter Demand 77807 81762 90993 104020 119203 Surplus (+) / Deficit (-) -3409 4569 14715 14840 2811 Supply 142983 164480 201394 223608 229253 Annual Demand 137209 143958 159364 181684 207718 Surplus (+) / Deficit (-) 5774 20522 42030 41924 21536 26 Demand Forecast: Sensitivity Analysis Key Parameters: High Case 2 Cost Recovery Tariff Country Price Elasticity Income Elasticity GDP Growth in Level USc/kWh Year Tariffs reach 2007-2025 p.a. Cost Recovery Level 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- 2003- 2003- 2003- 2010 2015 2020 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% Table A4.29: The Kyrgyz Republic. Electricity Demand Supply Balance in Table A4.28: Kazakhstan. Electricity Demand Supply Balance in 2005-2025 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 27984 32211 40215 42771 45449 Supply 7961 8969 9786 9696 9696 Summer Demand 24786 28588 33340 39026 45683 Summer Demand 3386 3150 3467 3904 4396 Surplus (+) / Deficit (-) 3198 3623 6876 3745 -234 Surplus (+) / Deficit (-) 4575 5819 6319 5792 5300 Supply 35185 40500 50564 53778 57145 Supply 5754 8120 8628 13767 13767 Winter Demand 37689 43468 50694 59341 69463 Winter Demand 8239 7665 8437 9499 10695 Surplus (+) / Deficit (-) -2504 -2969 -130 -5563 -12318 Surplus (+) / Deficit (-) -2485 455 191 4268 3072 Supply 63169 72710 90780 96550 102594 Supply 13714 17089 18414 23463 23463 Annual Demand 62475 72056 84034 98367 115146 Annual Demand 11625 10815 11904 13403 15090 Surplus (+) / Deficit (-) 694 654 6746 -1818 -12552 Surplus (+) / Deficit (-) 2090 6273 6510 10060 8373 Table A4.30: Tajikistan. Electricity Demand Supply Balance in 2005-2025 Table A4.31: Uzbekistan. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 9158 10821 13581 20176 20176 Supply 23482 26149 32104 32104 31918 Summer Demand 8446 7886 8685 9683 10808 Summer Demand 21862 22245 24469 27016 29827 Surplus (+) / Deficit (-) 713 2934 4896 10493 9368 Surplus (+) / Deficit (-) 1620 3904 7635 5088 2091 Supply 6665 7875 9883 14683 14683 Supply 26794 29837 36632 36632 36419 Winter Demand 7254 6368 7133 8126 9244 Winter Demand 23932 24352 26786 29574 32652 Surplus (+) / Deficit (-) -589 1507 2751 6557 5439 Surplus (+) / Deficit (-) 2862 5485 9846 7058 3767 Supply 15823 18695 23464 34859 34859 Supply 50277 55986 68736 68736 68337 Annual Demand 15699 14254 15818 17809 20051 Annual Demand 45794 46597 51255 56589 62479 Surplus (+) / Deficit (-) 124 4441 7647 17050 14808 Surplus (+) / Deficit (-) 4483 9389 17481 12147 5858 Table A4.32: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025 Year 2005 2010 2015 2020 2025 Supply 68585 78149 95686 104748 107239 Summer Demand 58479 61869 69960 79629 90714 Surplus (+) / Deficit (-) 10106 16279 25726 25119 16526 Supply 74398 86331 105708 118860 122014 Winter Demand 77113 81853 93050 106540 122053 Surplus (+) / Deficit (-) -2716 4478 12658 12320 -40 Supply 142983 164480 201394 223608 229253 Annual Demand 135593 143722 163010 186169 212767 Surplus (+) / Deficit (-) 7390 20758 38384 37439 16486 27 Demand Forecast: Sensitivity Analysis Key Parameters: High Case 3 Cost Recovery Tariff Country Price Elasticity Income Elasticity GDP Growth in Level USc/kWh Year Tariffs reach 2007-2025 p.a. Cost Recovery Level 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 Country Actual Demand forecast (GWh) Annual Growth rates 2003 2005 2010 2015 2020 2025 2003- 2003- 2003- 2003- 2010 2015 2020 2025 Kazakhstan 58,944 63,113 74,549 88,639 105,785 126,248 3.41% 3.46% 3.50% 3.52% The Kyrgyz 12,145 11,137 9,441 10,422 11,908 13,604 -3.53% -1.27% -0.12% 0.52% Republic 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 136,128 134,762 143,220 165,064 191,787 223,035 0.73% 1.62% 2.04% 2.27% Countries Table A4.35: The Kyrgyz Republic. Electricity Demand Supply Balance in Table A4.34: Kazakhstan. Electricity Demand Supply Balance in 2005-2025 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 27984 32211 40215 42771 45449 Supply 7961 8969 9786 9696 9696 Summer Demand 25039 29577 35167 41969 50087 Summer Demand 3244 2750 3036 3468 3963 Surplus (+) / Deficit (-) 2945 2634 5049 802 -4638 Surplus (+) / Deficit (-) 4717 6219 6750 6228 5733 Supply 35185 40500 50564 53778 57145 Supply 5754 8120 8628 13767 13767 Winter Demand 38074 44972 53472 63816 76160 Winter Demand 7893 6691 7387 8439 9642 Surplus (+) / Deficit (-) -2888 -4472 -2908 -10038 -19015 Surplus (+) / Deficit (-) -2139 1429 1241 5327 4125 Supply 63169 72710 90780 96550 102594 Supply 13714 17089 18414 23463 23463 Annual Demand 63113 74549 88639 105785 126248 Annual Demand 11137 9441 10422 11908 13604 Surplus (+) / Deficit (-) 57 -1839 2140 -9235 -23653 Surplus (+) / Deficit (-) 2577 7648 7991 11555 9859 Table A4.36: Tajikistan. Electricity Demand Supply Balance in 2005-2025 Table A4.37: Uzbekistan. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 9158 10821 13581 20176 20176 Supply 23482 26149 32104 32104 31918 Summer Demand 7775 6464 7170 8112 9188 Summer Demand 21988 22699 25275 28250 31574 Surplus (+) / Deficit (-) 1383 4356 6411 12064 10989 Surplus (+) / Deficit (-) 1494 3450 6829 3854 344 Supply 6665 7875 9883 14683 14683 Supply 26794 29837 36632 36632 36419 Winter Demand 6678 5219 5889 6807 7858 Winter Demand 24071 24848 27669 30925 34564 Surplus (+) / Deficit (-) -13 2655 3995 7876 6825 Surplus (+) / Deficit (-) 2723 4989 8963 5707 1855 Supply 15823 18695 23464 34859 34859 Supply 50277 55986 68736 68736 68337 Annual Demand 14453 11684 13059 14920 17046 Annual Demand 46059 47547 52944 59174 66138 Surplus (+) / Deficit (-) 1370 7011 10405 19939 17814 Surplus (+) / Deficit (-) 4218 8439 15792 9562 2199 Table A4.38: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025 Year 2005 2010 2015 2020 2025 Supply 68585 78149 95686 104748 107239 Summer Demand 58047 61490 70648 81799 94812 Surplus (+) / Deficit (-) 10539 16659 25038 22948 12428 Supply 74398 86331 105708 118860 122014 Winter Demand 76715 81731 94417 109987 128224 Surplus (+) / Deficit (-) -2318 4600 11291 8873 -6210 Supply 142983 164480 201394 223608 229253 Annual Demand 134762 143220 165064 191787 223035 Surplus (+) / Deficit (-) 8221 21260 36329 31821 6218 28 Demand Forecast: Sensitivity Analysis Key Parameters: Low Case 1 Cost Recovery Tariff Country Price Elasticity Income Elasticity GDP Growth in Level USc/kWh Year Tariffs reach 2007-2025 p.a. Cost Recovery Level 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- 2003- 2003- 2003- 2010 2015 2020 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% Table A4.41: The Kyrgyz Republic. Electricity Demand Supply Balance in Table A4.40: Kazakhstan. Electricity Demand Supply Balance in 2005-2025 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 27984 32211 40215 42771 45449 Supply 7961 8969 9786 9696 9696 Summer Demand 24786 28588 33340 39026 45683 Summer Demand 3224 2567 2824 3179 3580 Surplus (+) / Deficit (-) 3198 3623 6876 3745 -234 Surplus (+) / Deficit (-) 4737 6402 6962 6517 6116 Supply 35185 40500 50564 53778 57145 Supply 5754 8120 8628 13767 13767 Winter Demand 37689 43468 50694 59341 69463 Winter Demand 7845 6246 6871 7736 8710 Surplus (+) / Deficit (-) -2504 -2969 -130 -5563 -12318 Surplus (+) / Deficit (-) -2092 1874 1757 6031 5057 Supply 63169 72710 90780 96550 102594 Supply 13714 17089 18414 23463 23463 Annual Demand 62475 72056 84034 98367 115146 Annual Demand 11069 8813 9695 10915 12290 Surplus (+) / Deficit (-) 694 654 6746 -1818 -12552 Surplus (+) / Deficit (-) 2645 8276 8719 12547 11173 Table A4.42: Tajikistan. Electricity Demand Supply Balance in 2005-2025 Table A4.43: Uzbekistan. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 9158 10821 13581 20176 20176 Supply 23482 26149 32104 32104 31918 Summer Demand 7648 5427 5983 6670 7445 Summer Demand 21862 22245 24469 27016 29827 Surplus (+) / Deficit (-) 1511 5394 7598 13506 12731 Surplus (+) / Deficit (-) 1620 3904 7635 5088 2091 Supply 6665 7875 9883 14683 14683 Supply 26794 29837 36632 36632 36419 Winter Demand 6569 4382 4913 5597 6368 Winter Demand 23932 24352 26786 29574 32652 Surplus (+) / Deficit (-) 96 3493 4970 9086 8315 Surplus (+) / Deficit (-) 2862 5485 9846 7058 3767 Supply 15823 18695 23464 34859 34859 Supply 50277 55986 68736 68736 68337 Annual Demand 14216 9809 10896 12268 13812 Annual Demand 45794 46597 51255 56589 62479 Surplus (+) / Deficit (-) 1607 8886 12568 22591 21047 Surplus (+) / Deficit (-) 4483 9389 17481 12147 5858 Table A4.44: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025 Year 2005 2010 2015 2020 2025 Supply 68585 78149 95686 104748 107239 Summer Demand 57520 58827 66615 75892 86535 Surplus (+) / Deficit (-) 11066 19322 29071 28856 20704 Supply 74398 86331 105708 118860 122014 Winter Demand 76035 78448 89265 102249 117193 Surplus (+) / Deficit (-) -1637 7883 16443 16611 4821 Supply 142983 164480 201394 223608 229253 Annual Demand 133554 137275 155879 178140 203728 Surplus (+) / Deficit (-) 9429 27205 45515 45468 25526 29 Demand Forecast: Sensitivity Analysis Key Parameters: Low case 2 Cost Recovery Tariff Country Price Elasticity Income Elasticity GDP Growth in Level USc/kWh Year Tariffs reach 2007-2025 p.a. Cost Recovery Level 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- 2003- 2003- 2003- 2010 2015 2020 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% Table A4.47: The Kyrgyz Republic. Electricity Demand Supply Balance in Table A4.46: Kazakhstan. Electricity Demand Supply Balance in 2005-2025 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 27984 32211 40215 42771 45449 Supply 7961 8969 9786 9696 9696 Summer Demand 24534 27627 31599 36278 41649 Summer Demand 3205 2624 2813 3121 3463 Surplus (+) / Deficit (-) 3450 4584 8616 6494 3800 Surplus (+) / Deficit (-) 4756 6345 6973 6575 6233 Supply 35185 40500 50564 53778 57145 Supply 5754 8120 8628 13767 13767 Winter Demand 37306 42007 48047 55161 63329 Winter Demand 7798 6385 6844 7594 8425 Surplus (+) / Deficit (-) -2120 -1507 2517 -1383 -6184 Surplus (+) / Deficit (-) -2044 1736 1784 6173 5342 Supply 63169 72710 90780 96550 102594 Supply 13714 17089 18414 23463 23463 Annual Demand 61840 69634 79646 91439 104978 Annual Demand 11002 9008 9657 10715 11888 Surplus (+) / Deficit (-) 1329 3076 11133 5111 -2384 Surplus (+) / Deficit (-) 2712 8080 8757 12748 11575 Table A4.48 Tajikistan. Electricity Demand Supply Balance in 2005-2025 Table A4.49: Uzbekistan. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 9158 10821 13581 20176 20176 Supply 23482 26149 32104 32104 31918 Summer Demand 7521 6009 6473 7112 7822 Summer Demand 21735 21799 23686 25832 28173 Surplus (+) / Deficit (-) 1637 4811 7108 13065 12354 Surplus (+) / Deficit (-) 1747 4350 8418 6272 3745 Supply 6665 7875 9883 14683 14683 Supply 26794 29837 36632 36632 36419 Winter Demand 6460 4852 5316 5968 6690 Winter Demand 23793 23864 25929 28278 30841 Surplus (+) / Deficit (-) 205 3023 4568 8715 7993 Surplus (+) / Deficit (-) 3001 5973 10703 8354 5578 Supply 15823 18695 23464 34859 34859 Supply 50277 55986 68736 68736 68337 Annual Demand 13981 10861 11788 13079 14512 Annual Demand 45529 45663 49615 54111 59014 Surplus (+) / Deficit (-) 1843 7834 11676 21780 20348 Surplus (+) / Deficit (-) 4748 10323 19121 14625 9323 Table A4.50: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025 Year 2005 2010 2015 2020 2025 Supply 68585 78149 95686 104748 107239 Summer Demand 56995 58059 64570 72342 81106 Surplus (+) / Deficit (-) 11590 20090 31116 32406 26133 Supply 74398 86331 105708 118860 122014 Winter Demand 75357 77107 86136 97001 109285 Surplus (+) / Deficit (-) -959 9224 19571 21859 12729 Supply 142983 164480 201394 223608 229253 Annual Demand 132352 135167 150706 169343 190391 Surplus (+) / Deficit (-) 10631 29314 50687 54264 38862 30 Demand Forecast: Sensitivity Analysis Key Parameters: Low case 3 Cost Recovery Tariff Country Price Elasticity Income Elasticity GDP Growth in Level USc/kWh Year Tariffs reach 2007-2025 p.a. Cost Recovery Level 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- 2003- 2003- 2003- 2010 2015 2020 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% Table A4.53: The Kyrgyz Republic. Electricity Demand Supply Balance in Table A4.52: Kazakhstan. Electricity Demand Supply Balance in 2005-2025 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 27984 32211 40215 42771 45449 Supply 7961 8969 9786 9696 9696 Summer Demand 24155 26408 30682 35916 42041 Summer Demand 3066 2281 2452 2760 3108 Surplus (+) / Deficit (-) 3830 5802 9533 6856 3408 Surplus (+) / Deficit (-) 4895 6688 7334 6936 6588 Supply 35185 40500 50564 53778 57145 Supply 5754 8120 8628 13767 13767 Winter Demand 36729 40154 46653 54611 63926 Winter Demand 7460 5550 5966 6717 7563 Surplus (+) / Deficit (-) -1543 345 3911 -833 -6781 Surplus (+) / Deficit (-) -1706 2570 2662 7049 6204 Supply 63169 72710 90780 96550 102594 Supply 13714 17089 18414 23463 23463 Annual Demand 60883 66563 77335 90526 105968 Annual Demand 10526 7830 8418 9478 10671 Surplus (+) / Deficit (-) 2286 6148 13445 6023 -3374 Surplus (+) / Deficit (-) 3189 9258 9996 13985 12792 Table A4.54 Tajikistan. Electricity Demand Supply Balance in 2005-2025 Table A4.55: Uzbekistan. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 9158 10821 13581 20176 20176 Supply 23482 26149 32104 32104 31918 Summer Demand 6880 4868 5281 5888 6572 Summer Demand 19454 17849 19558 21594 23842 Surplus (+) / Deficit (-) 2279 5952 8300 14288 13605 Surplus (+) / Deficit (-) 4028 8300 12546 10510 8076 Supply 6665 7875 9883 14683 14683 Supply 26794 29837 36632 36632 36419 Winter Demand 5909 3931 4337 4941 5620 Winter Demand 21296 19539 21411 23639 26099 Surplus (+) / Deficit (-) 756 3944 5546 9742 9063 Surplus (+) / Deficit (-) 5498 10298 15221 12993 10320 Supply 15823 18695 23464 34859 34859 Supply 50277 55986 68736 68736 68337 Annual Demand 12789 8799 9618 10829 12192 Annual Demand 40750 37388 40969 45233 49941 Surplus (+) / Deficit (-) 3034 9896 13847 24031 22667 Surplus (+) / Deficit (-) 9527 18598 27767 23503 18396 Table A4.56: All Four CA Countries. Electricity Demand Supply Balances in 2005-2025 Year 2005 2010 2015 2020 2025 Supply 68585 78149 95686 104748 107239 Summer Demand 53554 51406 57973 66158 75563 Surplus (+) / Deficit (-) 15031 26743 37713 38590 31676 Supply 74398 86331 105708 118860 122014 Winter Demand 71394 69174 78367 89908 103209 Surplus (+) / Deficit (-) 3004 17158 27341 28952 18805 Supply 142983 164480 201394 223608 229253 Annual Demand 124948 120580 136340 156066 178772 Surplus (+) / Deficit (-) 18036 43901 65054 67542 50481 31 Demand Forecast: Sensitivity Analysis Key Parameters: Alternative Demand case Country Changes in Electricity Intensity p.a. in % 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- 2003- 2003- 2010 2015 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% Table A4.58: Kazakhstan. Electricity Demand Supply Balance in 2005-2025 Table A4.59: The Kyrgyz Republic. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 27984 32211 40215 42771 45449 Supply 7961 8969 9786 9696 9696 Summer Demand 23405 30036 34055 39403 45589 Summer Demand 3538 4053 4378 4827 5322 Surplus (+) / Deficit (-) 4579 2175 6160 3369 -140 Surplus (+) / Deficit (-) 4423 4916 5407 4869 4374 Supply 35185 40500 50564 53778 57145 Supply 5754 8120 8628 13767 13767 Winter Demand 42854 45670 51782 59913 69321 Winter Demand 9410 9862 10655 11746 12949 Surplus (+) / Deficit (-) -7669 -5170 -1218 -6135 -12176 Surplus (+) / Deficit (-) -3657 -1742 -2026 2021 818 Supply 63169 72710 90780 96550 102594 Supply 13714 17089 18414 23463 23463 Annual Demand 66259 75706 85837 99316 114911 Annual Demand 12948 13915 15033 16573 18271 Surplus (+) / Deficit (-) -3090 -2995 4943 -2766 -12317 Surplus (+) / Deficit (-) 766 3174 3381 6890 5191 Table A4.60 Tajikistan. Electricity Demand Supply Balance in 2005-2025 Table A4.61: Uzbekistan. Electricity Demand Supply Balance in 2005-2025 Year 2005 2010 2015 2020 2025 Year 2005 2010 2015 2020 2025 Supply 9158 10821 13581 20176 20176 Supply 23482 26149 32104 32104 31918 Summer Demand 8794 11887 12744 13914 15206 Summer Demand 23245 25697 27095 29153 31368 Surplus (+) / Deficit (-) 364 -1066 837 6263 4970 Surplus (+) / Deficit (-) 237 452 5009 2951 550 Supply 6665 7875 9883 14683 14683 Supply 26794 29837 36632 36632 36419 Winter Demand 10897 9598 10467 11676 13005 Winter Demand 28366 28131 29661 31914 34338 Surplus (+) / Deficit (-) -4232 -1723 -583 3007 1678 Surplus (+) / Deficit (-) -1572 1706 6971 4718 2081 Supply 15823 18695 23464 34859 34859 Supply 50276 55986 68736 68736 68337 Annual Demand 19691 21485 23211 25589 28211 Annual Demand 51611 53828 56756 61067 65705 Surplus (+) / Deficit (-) -3868 -2790 253 9270 6648 Surplus (+) / Deficit (-) -1335 2158 11980 7669 2632 Table A4.62: All Four CA Countries. Electricity Demand Supply Balances in 2005- 2025 Year 2005 2010 2015 2020 2025 Supply 68585 78149 95686 104748 107239 Summer Demand 58982 71673 78273 87296 97485 Surplus (+) / Deficit (-) 9603 6476 17413 17451 9754 Supply 74398 86331 105708 118860 122014 Winter Demand 91527 93261 102564 115249 129614 Surplus (+) / Deficit (-) -17129 -6930 3144 3611 -7600 Supply 142983 164480 201394 223608 229253 Annual Demand 150509 164934 180837 202545 227099 Surplus (+) / Deficit (-) -7526 -454 20557 21063 2155 32 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: Total Transmission Ekibastuz Other TPPs' New Kazakhstan Year and GRES-1 Units Generation Supply Distribution Rehabilitation Rehabilitation Units 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 33 Table A4.64: The Kyrgyz Republic. Incremental Power Supply and Total Supply (GWh) Incremental Supply from Investment Projects in: Year Total Kyrgyzstan Gross Transmission and Bishkek CHP- Kambarata 2 Kambarata 1 Supply Distribution 2 HPP HPP 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. 34 Table A4.65: Tajikistan. Incremental Power Supply and Total Supply (GWh) Incremental supply from Investment Projects in: Year Transmission & Total Tajikistan Supply Distribution DSM Sangtuda I HPP Rogun HPP, Phase I and II 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. 35 Table A4.66: Uzbekistan. Incremental Power Supply and Total Supply (GWh) Incremental supply from Investment Projects in: Retirement Year Total Uzbekistan Transmission and Talimarjan TPP Talimarjan TPP Units Loss of Capacity Loss of Generation Supply Distribution Unit #1 #2-4 MW GWh 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 36 Table A4.67: All Four CA Republics. Incremental Power Supply and Total Supply (GWh) From Power Investment Program Year Kazakhstan The Kyrgyz Tajikistan Uzbekistan Total CA Supply Republic 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 37 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 Summer Demand 23385 24786 28588 33340 39026 45683 Surplus (+) / Deficit (-) 3859 3198 3623 6876 3745 -234 Supply 34256 35185 40500 50564 53778 57145 Winter Demand 35559 37689 43468 50694 59341 69463 Surplus (+) / Deficit (-) -1303 -2504 -2969 -130 -5563 -12318 Supply 61500 63169 72710 90780 96550 102594 Annual Demand 58944 62475 72056 84034 98367 115146 Surplus (+) / Deficit (-) 2556 694 654 6746 -1818 -12552 Figure A4.2: Summer Figure A4.3: Winter GWh 60000 GWh 80000 40000 60000 20000 40000 20000 0 0 2005 2010 2015 2020 2025 2005 2010 2015 2020 2025 Supply Demand Supply Demand Figure A4.4: Annual Figure A4.5: Export Surplus GWh 150000 GWh 8000 100000 4000 0 50000 -4000 2005 2010 2015 2020 2025 -8000 0 -12000 -16000 2003 2005 2010 2015 2020 2025 Summer Winter Supply Demand 38 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 Summer Demand 3538 3224 2686 2922 3290 3705 Surplus (+) / Deficit (-) 892 4737 6282 6863 6406 5991 Supply 8912 5754 8120 8628 13767 13767 Winter Demand 8607 7845 6536 7111 8006 9014 Surplus (+) / Deficit (-) 305 -2092 1584 1517 5761 4753 Supply 13342 13714 17089 18414 23463 23463 Annual Demand 12145 11069 9222 10033 11296 12719 Surplus (+) / Deficit (-) 1197 2645 7866 8381 12167 10744 Figure A4.6: Summer Figure A4.7: Winter GWh 15000 GWh 15000 10000 10000 5000 5000 0 0 2003 2005 2010 2015 2020 2025 2003 2005 2010 2015 2020 2025 Supply Demand Supply Demand Figure A4.8: Annual Figure A4.9: Export Surplus GWh GWh 30000 8000 20000 4000 10000 0 0 2003 2005 2010 2015 2020 2025 2003 2005 2010 2015 2020 2025 -4000 Supply Demand Summer Winter 39 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 Summer Demand 8794 7648 6233 6814 7597 8479 Surplus (+) / Deficit (-) 41 1511 4587 6767 12579 11697 Supply 6346 6665 7875 9883 14683 14683 Winter Demand 7554 6569 5033 5596 6375 7252 Surplus (+) / Deficit (-) -1208 96 2841 4287 8308 7431 Supply 15181 15823 18695 23464 34859 34859 Annual Demand 16348 14216 11267 12410 13972 15731 Surplus (+) / Deficit (-) -1167 1607 7429 11055 20887 19128 Figure A4.10: Summer Figure A4.11: Winter GWh GWh 30000 20000 15000 20000 10000 10000 5000 0 0 2003 2005 2010 2015 2020 2025 2003 2005 2010 2015 2020 2025 Supply Demand Supply Demand Figure A4.12: Annual Figure A4.13: Export Surplus GWh 40000 GWh 16000 20000 12000 8000 0 4000 2003 2005 2010 2015 2020 2025 0 Supply Demand -4000 2003 2005 2010 2015 2020 2025 Summer Winter 40 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 Summer Demand 23245 21862 22245 24468 27015 29827 Surplus (+) / Deficit (-) -499 1620 3904 7636 5089 2091 Supply 25,954 26,795 29,837 36,632 36,632 36,419 Winter Demand 25,446 23,932 24,352 26,786 29,574 32,652 Surplus (+) / Deficit (-) 508 2863 5484 9846 7058 3767 Supply 48,700 50,277 55,986 68,736 68,736 68,337 Annual Demand 48,691 45,794 46,597 51,255 56,589 62,479 Surplus (+) / Deficit (-) 9 4483 9388 17481 12147 5858 Figure A4.14: Summer GWh Figure A4.15: Winter GWh 40000 40000 30000 30000 20000 20000 10000 10000 0 0 2003 2005 2010 2015 2020 2025 2003 2005 2010 2015 2020 2025 Supply Demand Supply Demand Figure A4.16: Annual Figure A4.17: Export Surplus GWh GWh 80000 12000 60000 8000 40000 20000 4000 0 0 2003 2005 2010 2015 2020 2025 -4000 2003 2005 2010 2015 2020 2025 Supply Demand Summer Winter 41 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 Summer Demand 58962 57519 59752 67544 76929 87694 Surplus (+) / Deficit (-) 4293 11066 18396 28142 27819 19546 Supply 75468 74399 86331 105708 118860 122014 Winter Demand 77166 76035 79390 90187 103296 118381 Surplus (+) / Deficit (-) -1698 -1636 6941 15521 15564 3633 Supply 138723 142984 164480 201394 223608 229253 Annual Demand 136128 133554 139142 157731 180225 206075 Surplus (+) / Deficit (-) 2595 9429 25338 43663 43383 23178 Figure A4.18: Summer Figure A4.19: Winter GWh GWh 150000 150000 100000 100000 50000 50000 0 0 2003 2005 2010 2015 2020 2025 2003 2005 2010 2015 2020 2025 Supply Demand Supply Demand Figure A4.20: Annual Figure A4.21: Export Surplus GWh 250000 GWh 200000 32000 150000 24000 100000 16000 50000 8000 0 0 2003 2005 2010 2015 2020 2025 -8000 2003 2005 2010 2015 2020 2025 Supply Demand Summer Winter 42 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. 12It 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. 13These 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. 43 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 $250 per low Table A5.1: Kazakhstan. AIC for T&D Rehabilitation Calendar Year Capital Investment Incremental O&M Costs ($ Total Incremental Costs ($ ($ million) million) 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% 1016.7 Incremental Sales (million kWh) discounted at 10% 36016 Average Incremental Costs (Ē/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%. 14This 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 16WB's estimate 44 2. The Kyrgyz Republic During 2004-2010, the Kyrgyz Republic would spend $250 million in transmission and distribution rehabilitation to reduce technical losses from the present level of 34% to 13% by 2010. Almost the whole of this investment would be in the distribution system. Incremental O&M expenditures are assumed at 4% of Capital Expenditures in year 1, declining to 3% in year 2, and stabilizing at 2% year 3 onwards. The economic cost of additional supply arising from this project is estimated at 2.3 cents/kWh as shown in Table A5.2. Table A5.2: The Kyrgyz Republic. AIC for T&D Rehabilitation Calendar Year Capital Investment Incremental O&M Costs Total Incremental Costs ($ ($ million) ($ million) 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) 211.3 Incremental Sales (million kWh) 9280 Average Incremental Costs (cents/kWh) 2.3 45 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$310 million. Incremental O&M expenditures are estimated at 4% of capital expenditures in year 1 through 5, declining to 3% in year 6, and to 2% in year 7. On this basis the economic cost of the additional supply is estimated at 2.1 cents/kWh as shown in Table A5.3. Table A5.3: Tajikistan. AIC for T&D Rehabilitation Calendar Year Capital Investment Incremental O&M Costs Total Incremental Costs ($ ($ million) ($ million) 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) 254.6 Incremental Sales (million kWh) 12129 Average Incremental Costs (cents/kWh) 2.1 46 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 $250 per consumer connection for 4,111,860 households to reduce system losses from the present level of losses of 22% to 15% by 2010. Incremental O&M expenditure is assumed at 4% of the capital expenditures in year 1 through 2, declining to 3% in year 3 through 5, and to 2% in year 6 through 10. The economic cost of additional supplies are estimated at 3.5 cents/kWh. Table A5.4: Uzbekistan. AIC for T&D Rehabilitation Calendar Year Capital Investment Incremental O&M Costs Total Incremental Costs ($ ( $ million) ($ million) 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) 873.7 Incremental Sales (million kWh) 24877 Average Incremental Costs (cents/kWh) 3.5 47 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 $440 million.17 The rehabilitation project would need three years to prepare (2005-2007), and four years to implement (2008-2011). The first year of generation from the rehabilitated units would be 2010. Table A5.5: Kazakhstan. AIC for Ekibastuz I Plant Rehabilitation Calendar Year Capital Investment Fuel Cost Incremental O&M Total Incremental Costs Excluding Fuel Costs Incremental Sales US$ 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) 1582.6 Incremental 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 48 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 Total Incremental Costs Excluding Fuel 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) 1861.7 Incremental 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 $1,070 million in rehabilitation of these units to prolong their operating lives.19 The schedule of investment in rehabilitation of the TPPs' large and medium units in general reflects the present retirement schedule. It is assumed that the involved units will consume coal from the Ekibastuz mine. The Heat Rate, coal calorific value, and coal price are thus the same as those 18WB estimate and TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan 19Kazakhstan, Plans on implementation of national policy of further power sector development 49 adopted for Ekibastuz I TPP. Fixed and Variable incremental O&M expenditures20 adopted are also similar to those adopted in Ekibastuz I plant. It is assumed that the Unit's Capacity Factor would increase by about 20% after rehabilitation21; Plants' Own Needs (auxiliary consumption) is assumed at 8% of gross output. The details of AIC calculations are shown in Table A5.6. 2. Uzbekistan Project Implementation period for the rehabilitation of existing thermal plants is 2004-2023. The installed capacity of the existing thermal power plants is about 10,000 MW. Table A5.7: Uzbekistan. AIC for Rehabilitation of the existent TPPs. Calendar Year Investment in TPPs Rehabilitation Avoided Decrease of Generation US$ 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) 561.0 Incremental 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. 20WB estimate and TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan 21WB's estimate 22TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan, draft Final Report 50 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. 23TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan, draft Final Report 51 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 Incremental net Excluding Fuel Total Incremental Costs 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) 463.1 Incremental Sales (million kWh) 27583 Average Incremental Costs (cents/kWh) 1.68 24WB estimate and TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan 52 (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 Incremental O&M Costs Incremental net Year Capital Investment Fuel Cost Excluding Fuel Total Incremental Costs 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) 1804.3 Incremental 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 25TACIS, Verbundplan-ESBI-Fichtner, Assistance to the Electricity Sector of the Republic of Uzbekistan 53 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 Incremental O&M Costs Incremental net Year Capital Investment Fuel Cost Excluding Fuel Total Incremental Costs 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) 388.9 Incremental 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 26Information from the Kyrgyz Authorities 54 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) 1317.4 Incremental Sales (million kWh) 18382 Average Incremental Costs (cents/kWh) 7.17 The incremental cost of power generation by Kambarata-1 at USĒ7.17/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. 27JSC "Electric Power Plants", Investment Projects, Bishkek, the Kyrgyz Republic 55 (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) 225.4 Incremental Sales (million kWh) 6055 Average Incremental Costs (cents/kWh) 3.72 Though the marginal cost of generation is Ē3.72/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. 28JSC "Electric Power Plants", Investment Projects, Bishkek, the Kyrgyz Republic 29JSC "Electric Power Plants", Investment Projects, Bishkek, the Kyrgyz Republic 56 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) 273.0 Incremental Sales (million kWh) 13883 Average Incremental Costs (cents/kWh) 1.97 30Information from the Tajik Authorities 57 (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) 590.4 Incremental 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 Ē2.46/kWh. 58 (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) 1544.1 Incremental 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 USĒ2.83/kWh. 4. Kazakhstan 59 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 Incremental O&M Year Capital Investment Fuel Cost 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) 1424.2 Incremental 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 $1,085 million32. Construction would be during 2016-2020 and the first year of output would be 2020. The Capacity Factor for each unit assumed at 20% during the first year of operation of each unit and at 85% in the follow up years. On the basis of the above-mentioned assumptions, the AIC of generation by the new units is expected to be Ē4.54/kWh (see Table A5.16). 3150% of the equity in this existing Ekibastuz II power station is believed to have been transferred to RAO UES of Russia. 32RWE Solution, KEGOK, Kazakhstan North-South 500 kV Power Transmission Line Investment Pre-Feasibility Study 60 Appendix 5.2 Central Asia Regional Export Potential Study Economic Analysis of Transmission Line Options for Exports The economic analysis calculates the economic cost of transmission in respect of the proposed six export transmission line options using an 10% discount rate and using constant 2004 dollar price levels. The Basic Data on the proposed transmission lines are shown in the Table A5.17. Table A5.17. Basic Data on Transmission Lines Number of Export Transmission Line Distance Voltage Line Annual trans- Number of Investment in kilometers kV type mission (GWh) new SS expanded US$ million SS 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 $150 million but no intermediate substations would be needed. The details of AIC calculations summarized in Table A5.18. 61 Table A5.18: Transmission Lines' AIC Calculations Almaty - Surhan ­ Kabul ­ Urumqui Mashad Surhan ­ Kabul Kabul ­ Tarbela Kandaghar Kandaghar ­ Karachi Calendar Invest. Sales Invest. Sales Invest. Sales Invest. Sales Invest. Sales Invest. Year US$ US$ US$ US$ US$ US$ Sales GWh mil GWh mil GWh mil GWh mil GWh mil GWh mil 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 0.66 0.49 0.43 0.42 0.39 0.81 (cents/kWh) 62 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. 63 Table A5.19: Financial Analysis of Sangtuda I Hydropower Project Construction Period Operating Period Year Capital Capital Debt Return Total Expenditures IDC Expenditures Debt Equity O&M Service on Cash Generation Annual without IDC with IDC Funded Funded Expenses Expenses Equity Outflow 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 $114 Levelized Tariff (c/kWh): 2.44 (in 2004 prices) Table A5.20: Sangtuda I Sensitivity Analysis Percentage Levelized Percentage Change in Tariff Change Sensitivity a Parameter (%) c/kWh Lev Tariff (%) Index Base Case 2.4350 Sensitivities (1) Change in Generation -20% 3.0438 25.0% (1.25) (2) Change in Interest Rates 1% 2.4521 0.7% 0.70 (3) Change in Return on Equity 1% 2.4453 0.4% 0.42 (4) Change in CapEx 1% 2.4587 1.0% 0.97 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 64 Table A5.21: Financial Analysis of Rogun Hydropower Project Phase I Construction Period Operating Period Year Capital Capital Debt Return Total Expenditures IDC Expenditures Debt Equity O&M Service on Cash Generation Annual without IDC with IDC Funded Funded Expenses Expenses Equity Outflow Tariff ($ 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 $264 Levelized Tariff (c/kWh): 2.91 (2004 prices) Table A5.22: Rogun Phase I Sensitivity Analysis Percentage Percentage Change in Levelized Change Lev Sensitivity Indexa Parameter (%) Tariff c/kWh Tariff (%) Base Case 2.9104 Sensitivities (1) Change in Generation -20% 3.6380 25.0% (1.25) (2) Change in Interest Rates 1% 2.9310 0.7% 0.71 (3) Change in Return on Equity 1% 2.9235 0.5% 0.45 (4) Change in CapEx 1% 2.9392 1.0% 0.99 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 65 Table A5.23: Financial Analysis of Rogun Hydropower Project Phases I&II Construction Period Operating Period Year Capital Capital Debt Return Total Expenditures IDC Expenditures Debt Equity O&M Service on Cash Generation Annual without IDC with IDC Funded Funded Expenses Expenses Equity Outflow Tariff ($ 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 $948 Levelized Tariff (c/kWh): 3.24 (in 2004 prices) Table A5.24: Rogun Phases I & II Sensitivity Analysis Percentage Percentage Change in Levelized Tariff Change Lev Sensitivity Indexa Parameter(%) c/kWh Tariff(%) Base Case 3.2388 Sensitivities (1) Change in Generation -20% 4.0485 25.0% (1.25) (2) Change in Interest Rates 1% 3.2644 0.8% 0.79 (3) Change in Return on Equity 1% 3.2547 0.5% 0.49 (4) Change in CapEx 1% 3.2676 0.9% 0.89 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 66 Table A5.25: Financial Analysis of Kambarata I Hydropower Project Construction Period Operating Period Year Capital Capital Debt Return Total Expenditures IDC Expenditures Debt Equity O&M Service on Cash Generation Annual Tariff without IDC with IDC Funded Funded Expenses Expenses Equity Outflow ($ 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 $785 Levelized Tariff (c/kWh): 8.54 (in 2004 prices) Table A5.26: Kamabarata I Sensitivity Analysis Percentage Change in Levelized Tariff Percentage Change a Parameter (%) c/kWh Lev Tariff (%) Sensitivity Index Base Case 8.5445 Sensitivities (1) Change in Generation -20% 10.6806 25.0% (1.25) (2) Change in Interest Rates 1% 8.6143 0.8% 0.82 (3) Change in Return on Equity 1% 8.5894 0.5% 0.52 (4) Change in CapEx 1% 8.6298 1.0% 1.00 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 67 Table A5.27: Financial Analysis of Kambarata II Hydropower Project Construction Period Operating Period Year Capital Capital Debt Return Total Expenditures IDC Expenditures Debt Equity O&M Service on Cash Generation Annual Tariff without IDC with IDC Funded Funded Expenses Expenses Equity Outflow ($ 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 $93 Levelized Tariff (c/kWh): 3.95 (in 2004 prices) Table A5.28: Kambarata II Sensitivity Analysis Percentage Percentage Change in Levelized Tariff Change Lev Tariff Sensitivity Indexa Parameter (%) c/kWh (%) Base Case 3.9534 Sensitivities (1) Change in Generation -20% 4.9418 25.0% (1.25) (2) Change in Interest Rates 1% 3.9684 0.4% 0.38 (3) Change in Return on Equity 1% 3.9716 0.5% 0.46 (4) Change in CapEx 1% 3.9926 1.0% 0.99 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 68 Table A5.29: Financial Analysis of Bishkek II Thermal Power Project Construction Period Operating Period Capital Capital Year Expend. Expend. Debt Equity O&M Fuel Debt Return Total without IDC with Funded Funded Expenses Expenses Service on Cash Generation Annual Tariff IDC IDC Expenses Equity Outflow ($ 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 $64 Levelized Tariff (c/kWh): 2.67 (in 2004 prices) Table A5.30: Bishkek II Sensitivity Analysis Percentage Change Levelized Tariff Percentage a in Parameter (%) c/kWh Change Lev Sensitivity Index Tariff(%) Base Case 2.6743 Sensitivities (1) Change in Generation -20% 3.1178 16.6% (0.83) (2) Change in Interest Rates 1% 2.6822 0.3% 0.30 (3) Change in Return on Equity 1% 2.6800 0.2% 0.21 (4) Change in CapEx 1% 2.6866 0.5% 0.46 (5) Change in Fuel Price 1% 2.6833 0.3% 0.34 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 69 Table A5.31: Financial Analysis of Talimarjan - Phase I Power Project Construction Period Operating Period Year Capital IDC Capital Debt Equity O&M Fuel Debt Return Total Generation Annual Expenditures Expenditures Funded Funded Expenses Expenses Service on Cash Tariff without IDC with IDC Expenses Equity Outflow ($ 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 $23 Levelized Tariff (c/kWh) : 1.75 (in 2004 prices) Table A5.32: Talimardjan Phase I Sensitivity Analysis Percentage Levelized Percentage Change in Tariff Change Sensitivity Indexa Parameter(%) c/kWh Lev Tariff (%) Base Case 1.7490 Sensitivities (1) Change in Generation -20% 1.8770 7.3% (0.37) (2) Change in Interest Rates 1% 1.7506 0.1% 0.09 (3) Change in Return on Equity 1% 1.7497 0.0% 0.04 (4) Change in CapEx 1% 1.7520 0.2% 0.17 (5) Change in Fuel Price 1% 1.7614 0.7% 0.71 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 70 Table A5.33: Financial Analysis of Talimarjan - Phase II Power Project Construction Period Operating Period Capital Capital Year Expend. Expend. Debt Equity O&M Fuel Debt Return Total without IDC with Funded Funded Expenses Expenses Service on Cash Generation Annual Tariff IDC IDC Expenses Equity Outflow ($ 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 $372 Levelized Tariff (c/kWh): 2.92 (in 2004 prices) Table A5.34: Talimardjan Phase II Sensitivity Analysis Percentage Levelized Percentage Change in Tariff Change Sensitivity a Parameter (%) c/kWh Lev Tariff (%) Index Base Case 2.9168 Sensitivities (1) Change in Generation -20% 3.3893 16.2% (0.81) (2) Change in Interest Rates 1% 2.9305 0.5% 0.47 (3) Change in Return on Equity 1% 2.9258 0.3% 0.31 (4) Change in CapEx 1% 2.9340 0.6% 0.59 (5) Change in Fuel Price 1% 2.9217 0.2% 0.17 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 71 Table A5.35: Financial Analysis of Ekibastuz I Rehabilitation Project Construction Period Operating Period Capital Capital Year Expend. Expend. Debt Equity O&M Fuel Debt Return Total without IDC with Funded Funded Expenses Expenses Service on Cash Generation Annual Tariff IDC IDC Expenses Equity Outflow ($ 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 $140 Levelized Tariff (c/kWh) : 2.66 (in 2004 prices) Table A5.36: Ekibastuz I Rehabilitation Project Sensitivity Analysis Percentage Levelized Percentage Change in Tariff Change Sensitivity a Parameter (%) c/kWh Lev Tariff (%) Index Base Case 2.6617 Sensitivities (1) Change in Generation -20% 2.9956 12.5% (0.63) (2) Change in Interest Rates 1% 2.6665 0.2% 0.18 (3) Change in Return on Equity 1% 2.6649 0.1% 0.12 (4) Change in CapEx 1% 2.6677 0.2% 0.23 (5) Change in Fuel Price 1% 2.6750 0.5% 0.50 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 72 Table A5.37: Financial Analysis of Kazakhstan New Ekibastuz Project Construction Period Operating Period Capital IDC Capital Debt Equity O&M Fuel Debt Return Total Annual Tariff Year Expend. Expend. Funded Funded Expenses Expenses Service on Cash Generation without with Expenses Equity Outflow IDC IDC ($ 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 $447 Levelized Tariff (c/kWh): 5.05 (in 2004 prices) Table A5.38: Kazakhstan New Ekibastuz Sensitivity Analysis Percentage Levelized Percentage Change in Tariff Change Sensitivity Indexa Parameter (%) c/kWh Lev Tariff (%) Base Case 5.0468 Sensitivities (1) Change in Generation -20% 5.6524 12.0% (0.60) (2) Change in Interest Rates 1% 5.0700 0.5% 0.46 (3) Change in Return on Equity 1% 5.0720 0.5% 0.50 (4) Change in CapEx 1% 5.0766 0.6% 0.59 (5) Change in Fuel Price 1% 5.0614 0.3% 0.29 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 73 Table A5.39: Financial Analysis of Surhan - Mashad Transmission Line Project Construction Period Operating Period Capital Capital Expend. Expend. Debt Equity O&M Debt Return Total Annual Without IDC With Funded Funded Expenses Service On Cash Transm Tariff IDC IDC Expenses Equity Outflow ($ 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 $96 Levelized Tariff (c/kWh) 0.54 Table A5.40: Surhan - Mashad Transmission Line Sensitivity Analysis Percentage Change in Levelized Tariff Percentage Change a Parameter (%) c/kWh Lev Tariff (%) Sensitivity Index Base Case 0.5075 Sensitivities (1) Change in Generation -20% 0.6344 25.0% (1.25) (2) Change in Interest Rates 1% 0.5106 0.6% 0.61 (3) Change in Return on Equity 1% 0.5094 0.4% 0.38 (4) Change in CapEx 1% 0.5125 1.0% 0.99 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 74 Table A5.41: Financial Analysis of Kandahar - Karachi Transmission Line Project Construction Period Operating Period Capital Capital Year Expend. Expend. Debt O&M Debt Return Total without IDC with Funded Equity Funded Expenses Service on Cash Transm Annual Tariff IDC IDC Expenses Equity Outflow ($ 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 $77 Levelized Tariff (c/kWh): 1.03 Table A5.42: Kandahar - Karachi Transmission Line Sensitivity Analysis Percentage Change in Levelized Tariff Percentage Change a Parameter (%) c/kWh Lev Tariff (%) Sensitivity Index Base Case 0.9839 Sensitivities (1) Change in Generation -20% 1.2299 25.0% (1.25) (2) Change in Interest Rates 1% 0.9892 0.5% 0.54 (3) Change in Return on Equity 1% 0.9876 0.4% 0.37 (4) Change in CapEx 1% 0.9937 1.0% 0.99 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 75 Table A5.43: Financial Analysis of Kabul - Kandahar Transmission Line Project Construction Period Operating Period Capital Capital Year Expend. Expend. Debt O&M Debt Return Total without IDC with Funded Equity Funded Expenses Service on Cash Transm Annual Tariff IDC IDC Expenses Equity Outflow ($ 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 $46 Levelized Tariff (c/kWh): 049 Table A5.44: Kabul - Kandahar Transmission Line Sensitivity Analysis Percentage Change Levelized Tariff Percentage Change a in Parameter (%) c/kWh Lev Tariff (%) Sensitivity Index Base Case 0.4636 Sensitivities (1) Change in Generation -20% 0.5795 25.0% (1.25) (2) Change in Interest Rates 1% 0.4661 0.5% 0.54 (3) Change in Return on Equity 1% 0.4653 0.4% 0.37 (4) Change in CapEx 1% 0.4698 1.3% 1.34 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 76 Table A5.45: Financial Analysis of Almaty - Urumqui Transmission Line Project Construction Period Operating Period Year Capital Capital Expend. Expend Debt O&M Debt Return Total without IDC with Funded Equity Funded Expenses Service on Cash Trans Annual Tariff IDC IDC Expenses Equity Outflow ($ 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 $122 Levelized Tariff (c/kWh): 0.72 Table A5.46: Almaty - Urumqui Transmission Line Sensitivity Analysis Percentage Change in Levelized Percentage Change Lev Sensitivity Indexa Parameter(%) Tariff c/kWh Tariff (%) Base Case 0.6176 Sensitivities (1) Change in Generation -20% 0.7720 25.0% (1.25) (2) Change in Interest Rates 1% 0.6212 0.6% 0.59 (3) Change in Return on Equity 1% 0.6200 0.4% 0.39 (4) Change in CapEx 1% 0.6237 1.0% 0.99 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 77 Table A5.47: Financial Analysis of Kabul - Tarbela Transmission Line Project Construction Period Operating Period Capital Capital Year Expend. Expend. Debt O&M Debt Return Total without IDC with Funded Equity Funded Expenses Service on Cash Transm Annual Tariff IDC IDC Expenses Equity Outflow ($ 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 $29 Levelized Tariff (c/kWh) 0.51 Table A5.48: Kabul - Tarbela Transmission Line Sensitivity Analysis Percentage Change Levelized Tariff Percentage Change a in Parameter (%) c/kWh Lev Tariff (%) Sensitivity Index Base Case 0.4878 Sensitivities (1) Change in Generation -20% 0.6098 25.0% (1.25) (2) Change in Interest Rates 1% 0.4905 0.5% 0.54 (3) Change in Return on Equity 1% 0.4896 0.4% 0.37 (4) Change in CapEx 1% 0.4927 1.0% 0.99 a)Sensitivity index is the % change in parameter divided by % Change in Levelized Tariff. 78 Table A5.49: Financial Analysis of Surhan - Kabul Transmission Line Project Construction Period Operating Period Year Capital Capital Debt Return Total Expenditures IDC Expenditures Debt Equity Funded O&M Service on Cash Trans Annual Tariff without IDC with IDC Funded Expenses Expenses Equity Outflow ($ 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 Levelized Tariff Percentage Change a in Parameter (%) c/kWh Lev Tariff (%) Sensitivity Index 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. 79 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; 80 (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 81 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. 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. 82 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 83 Figure A7.2: Financial Structure of Theun-Hinboun Power Company 84 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. 85 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. 86 Table A8.1: Tajikistan South North Transmission Line AIC (Economic) of Transmission Capital Incremental Capital Incremental Cumulative Total Incremental Year Investments Transmission Investments O&M Exp. O&M Exp. Incremental Sales (% of total) (GWh) (US$ (US$ Costs Million) Million) (US$ Million) (US$M) (GWh) Year 1 0 Year 2 30 43.67 0.02 0.02 43.69 0 Year 3 40 58.22 0.03 0.05 58.27 0 Year 4 30 900 43.67 0.02 0.07 43.74 884 Year 5 2100 0.07 0.07 2946 Year 6 0.07 0.07 2946 Year 7 0.07 0.07 2946 Year 8 0.07 0.07 2946 Year 9 0.07 0.07 2946 Year 10 0.07 0.07 2946 Year 11 0.07 0.07 2946 Year 12 0.07 0.07 2946 Year 13 0.07 0.07 2946 Year 14 0.07 0.07 2946 Year 15 0.07 0.07 2946 Year 16 0.07 0.07 2946 Year 17 0.07 0.07 2946 Year 18 0.07 0.07 2946 Year 19 0.07 0.07 2946 Year 20 0.07 0.07 2946 Year 21 0.07 0.07 2946 Year 22 0.07 0.07 2946 Year 23 0.07 0.07 2946 Present Values (23 years) Incremental Costs (US$ million) 121.2 Incremental Sales (million kWh) 191790 Average Incremental Costs of Transmission (cents/kWh) 0.63 Data Source: Barki Tajik Report 87 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 Capital IDC Capital Debt Equity O&M Debt Return Total Net Annual Tariff c/kWh Year Expend. Expend. Expense Service on Cash Electricity Without With Expense Equity Outflow Transmitted IDC IDC ($ 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 88