Ukraine - Hydropower Rehabilitation and System Control Project

Document of The World Bank Report No. 13663-UA STAFF APPRAISAL REPORT UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT MARCH 20, 1995 Infrastructure Division Country Department IV Europe and Central Asia Region  CURRENCY EQUIVALENTS Currency unit = karbovanets, abbrev. Krb US$1 = 130,000 karbovanets (as of March 1995) WEIGHTS AND MEASURES atm atmosphere MJ Megajoule (101J) bcm billion cubic meter mt million metric tons Gcal Gigacalorie (109 cal) MW Megawatt (106W) GW Gigawatt MVA Megavolt Ampere kg kilogram Pi Petajoule (105J) km2 square kilometer psi pounds per square inch koe kilograms of oil equivalent t metric ton kV kilovolt tce tons of coal equivalent kW kilowatt toe tons of oil equivalent kWh kilowatt hour TWh Terawatt hour (10'2Wh) m3 cubic meter CALORIFIC VALUES I Unit of Fuel Gcal Coal (ton) 5.0 Wood (ton) 2.0 Natural gas (000m3) 8.5 Mazut (ton) 9.7 Diesel (ton) 10.2 Gasoline (ton) 10.5 Kerosene (ton) 10.3 Liquified Petroleum Gas (ton) 10.8 Crude oil (ton) 10.0 CONVERSION FACTORS I Gcal = 4.187 GJ 3.968 million Btu = 1,163 kWh I tce = 7 Gcal, and I toe = 10 Gcal I kWh of hydro and nuclear energy output converted to primary thermal equivalent at 250 grams of oil equivalent. ABBREVIATIONS DHE Dniprohydroenergo EBRD European Bank for Reconstruction and Development EU European Union GDP Gross Domestic Product GEF Global Environment Facility HPS Hydropower Station LAEA Intemational Atomic Energy Agency IDC Interest During Construction [MF International Monetary Fund LPG Liquid Petroleum Gas NDC National Dispatch Center NERC National Electricity Regulatory Commission PIU Project Implementation Unit PMU Project Management Unit PSP Pump Storage Plant TACIS Technical Assistance for the Community of Independent States UCP'TE Union for the Coordination of Production and Transport of Electricity (West European Grid) UPS Ukrainian Power System USAID United States Agency for Intemational Development VAT Value-Added Tax FISCAL YEAR January I - December 31  UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT CONTENTS PaMe No. LOAN AND PROJECT SUMMARY .... i SECTOR BACKGROUND A. Country Context ......................................... 1 B. Overview of the Energy Sector ............................... 2 C. Power Industry Conditions and Priority Needs ..................... 4 D. Government Policy and Strategy in the Power Industry ................ 8 E. Bank Strategy and Experience ................................ 10 11. THE PROJECT A. Project Concept and Objectives ............................... 12 B. Project Description ....................................... 12 C. Project Context .. ....................................... 15 D. Environmental Aspects .................................... 16 E Cost Estimates and Financing ................................ 16 IllI. FINANCIAL AND ECONOMIC ANALYSIS A. Electricity Prices ........................................ 19 B. Past Financial Performance of the Implementing Agencies .............. 20 C. Future Financial Performance of the Implementing Agencies ............. 22 D. Financial Analysis of the Project .............................. 26 E. Economic Costs and Benefits ................................. 27 F. Sensitivity Analysis ....................................... 28 IV. IMPLEMENTATION A. Institutional Arrangements .................................. 30 B. Implementation Schedule ................................... 33 C. Procurement . ........................................... 33 D. Disbursement . .......................................... 36 E. Accounts and Audits ...................................... 37 F. Monitoring and Evaluation .................................. 37 G. Operation . ............................................. 38 V. PROJECT RISKS AND BENEFITS ................................. 39 VI. SUMMARY OF RECOMMENDATIONS AND LOAN CONDITIONS .... ....... 40  ANNEXES 1. Electricity Demand Forecast 2. Nuclear Safety Issues 3. Least Cost Power Investment Program 4. Presidential Decree 244/94 and the Government's Action Plan 5. Detailed Cost Estimates 6. Financial Statements and Projections 7. Financial Rate of Return Calculation for the Hydropower Component 8. Economic Analysis 9. Project Implementation Schedule 10. List of Procurement Packages 11. Estimated Schedule of Disbursements 12. Performance Indicators 13. Supervision Plan MAP IBRD Map No. 26469 Main Power Stations and Transmission Lines  UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT Loan and Project Summary Borrower: Ukraine. Beneficiaries: Dniprohydroenergo and National Dispatch Center. Poverty: Not applicable. Loan Amount: US$114.0 million equivalent. Loan Terms: Standard variable interest rate with a maturity of 17 years, including five years grace period. Commitment Fee: 0.75% on undisbursed loan balances, beginning 60 days after signing, less any waiver. Onlending Terms: IBRD interest rate plus a mark-up of 1.5% for loan administration. Financing Plan: See paragraphs 2.17 and 2.18. Net Present Value: US$101.9 million (18.1 percent economic rate of return). Staff Appraisal Report: Report No. 13663-UA Map: IBRD Map No. 26469   UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT I. SECTOR BACKGROUND A. Country Context 1.1 Ukraine declared its independence from the Soviet Union in August 1991. It has a land mass that is the largest in Europe (with the exception of European Russia) and a population of 52 million that ranks fifth in Europe. GNP per capita was estimated at US$ 1,910 in 1993. The economy rests on industry and agriculture, which together accounted for more than 70 percent of GDP in 1991. Ukraine, despite its size, is also heavily dependent on trade, notably with the rest of the former Soviet Union (FSU). 1.2 The economic decline in Ukraine has been dramatic. Real GDP contracted by 14 percent in 1993, bringing the cumulative fall in output since 1990 to 38 percent. This trend accelerated in the 1994 as GDP declined by about 23 percent. Due to loose fiscal and monetary policies, the rate of inflation rose to an average of 4,735 percent in 1993 (up from 1,210 percent in 1992), and, in addition, varied significantly from month to month. In the first half of 1994, the inflation rate came down to single digit levels, primarily on account of flagging demand, itself the result of a large drop in real wages and a stringent credit policy. A freeze in the adjustment of administered prices (particularly energy) after December 1993 also contributed to the slowdown in inflation. 1.3 The external situation has become increasingly tenuous, reflecting a significant trade deficit with the FSU -- about US$ 3 billion in 1993 -- which was only partially offset by a trade surplus with the rest of the world. Developments in external trade have been marked by a sharp contraction in trade volumes, a considerable decrease in the terms of trade as import prices of energy moved towards world levels, and a modest shift in the direction of trade away from the FSU towards the rest of the world. The foreign trade deficit led to the increasing accumulation of arrears on payments for energy imports. 1.4 While external shocks, mostly brought on by the collapse of the FSU, have contributed to the economic decline, so too have the policies of the Government. Through 1993 and the first half of 1994, these policies have been marked by the absence of a coherent macroeconomic stabilization and structural reform program. A few disparate and uncoordinated attempts at stabilization have been undertaken instead. The Government resorted to a number of administrative measures to manage the economy. Price controls (including fixed administrative prices, advance notification of price adjustments, and an array of controls on profit margins) were expanded; the state order system dominated the domestic trade of key commodities; and export quotas and licenses remained widespread. Very little progress was achieved in privatization, and, due to frequent changes in regulations and high taxes, the growth of the emerging private sector took place outside the formal economy. 1.5 In July 1994, Ukraine elected a new President who called for a radical break from the past in economic policies. A comprehensive program of macroeconomic stabilization and structural reforms was developed with the assistance of the IMF and the World Bank. A series of difficult and far- reaching measures were implemented in October 1994 to demonstrate the Government's commitment, and the IMF approved a first purchase of US$ 365 million under the Systemic Transformation Facility in support of the stabilization program. A Rehabilitation Loan (Ln. 3831-UA) of US$ 500 million was approved by the Bank in December 1994 to support the implementation of structural reform measures necessary to create the conditions for future economic growth led by a vibrant private sector.  2 Sector Background 1.6 The Government's program calls for accelerating the transition to a market-oriented economy. Within this framework, the economic package that the Government has adopted aims to break inflationary expectations and promote a sustained recovery in economic growth. To this end, the program focuses on four key interdependent elements. First, a stable environment is required so that producers and consumers can make sound decisions without fear of macroeconomic disruptions. The stabilization of the economy will rest upon tight fiscal and monetary policies. Second, competition in markets is essential to an efficient allocation of resources. In an effort to promote free and open markets, the Government will rely upon the liberalization of prices and domestic and foreign trade; the dismantling of the state order system; demonopolization; and promotion of the private sector. Third, the hardening of enterprise budget constraints through corporatization, privatization and the enforcement of bankruptcy laws will encourage enterprises to respond to the new market forces. The elimination of directed credits and credits to settle inter-enterprise arrears and financial sector reform are expected to support behavioral changes at the enterprise level. Finally, the social safety net is to be strengthened through improved targeting in order to protect the segments of the population most vulnerable to the adjustments associated with the structural transformation of the economy. B. Overview of the Energy Sector 1.7 Energy Demand. Energy demand in Ukraine is characterized by high energy intensity in relation to industrial output and the high share of industry in final energy consumption. This is due to the high share of heavy industry (iron and steel, basic chemicals) and the low thermal efficiency of energy consumption technologies. Energy consumption per capita was about 3,500 kilogram oil equivalent (koe) in 1993, which is quite high even by Western European standards. Following a decline of 11 % between 1985 and 1990, the energy intensity of GDP increased by 40% in the 1990-1993 period reaching 2.5 koe/US$, a ratio that is several times higher than in the most developed countries. 1.8 Primary Energy Resources. Ukraine has large, practically unlimited coal resources. Donbass, the main mining basin, contains metallurgical coal, anthracite and high grade thermal coals, as well as coalbed gas. The unusually difficult geological conditions (thin, steeply inclined coal seams at great depth) in the central Donbass make the mining of coal costly and labor intensive. Natural gas and crude oil resources are declining, but are still significant. Remaining proven and probable reserves are 190 million tons of oil and 1,400 bcm of natural gas. The shallower and larger oil and gas pools in the Dnieper-Donetsk and Carpathian regions are rapidly being depleted. These deposits are replaced by reserves in smaller, deeper and less productive reservoirs, which are more expensive to find, to drill-up and to produce, to the point that a large part of the reserves appear to be uneconomic. 1.9 Energy Supply. Domestic energy production, consisting of fossil fuels and primary electricity (hydro- and nuclear power), represented 48 % of consumption in 1993-94 (see Table 1.1). The main import items were crude oil and oil products, originating almost exclusively in Russia, and natural gas, originating in Russia and Turkmenistan. The cost of fossil fuel imports reached US$ 5 billion in 1993 creating a demand for foreign exchange that the economy was only partly able to meet. In mid- 1993, Russia agreed to convert Rb 1.05 trillion of accumulated arrears to state debt of US$ 2.5 billion repayable over a six-year period. In 1994, arrears for gas delivered in 1993 by Turkmenistan were converted to a state debt of US$ 0.7 billion repayable over a seven-year period (including two years of grace). In late 1993, Russia introduced advance payment for crude oil deliveries that contributed to an almost 40 percent drop in Ukraine's crude oil imports in the following year. Gas deliveries, despite Ukraine's continued inability to pay, were maintained in 1994 at levels comparable to the previous year, leading once again to the accumulation of arrears.  Sector Background 3 Table 1.1 Primary Energy Supply and Consumption [ Year 1990 1991 1992 1993 1994 ] PRODUCTION washed coal (mt) 130.7 108.7 105.4 91.0 75.9 crude oil & condensate (mt) 5.3 4.9 4.5 4.2 4.2 natural gas (bcm) 27.8 24.0 22.0 19.2 18.3 peat & wood (mt) 4.3 4.0 3.7 4.1 4.0 nuclear (TWh) 76.2 75.1 73.7 75.2 68.9 hydro (TWh) 10.3 11.5 7.8 11.2 12.3 Total Production (mtoe) 116.77 102.10 97.02 88.44 78.81 IMPORT coal (mt) 21.1 12.7 11.7 8.7 7.5 crude oil (mt) 54.3 49.6 35.3 19.7 15.8 natural gas, net (born) 87.3 89.5 89.1 79.8 69.1 petroleum products (mt) 11.5 13.1 5.0 6.2 6.5 Total Import (mto.) 150.56 145.13 121.88 98.06 84.79 EXPORT coal (mt) 20.0 13.7 7.8 3.5 4.6 petroleum products (mt) 11.3 8.4 6.4 1.1 1.7 electricity, net (TWh) 28.0 14.3 4.6 1.2 1.1 Total Export (mtoe) 28.30 18.83 11.45 3.15 4.28 Primary Energy Consumptlon(mtoe) 239.02 228.40 207.45 183.35 159.32 l Annual Percentage Change -4.44% -9.17% -11.62% -13.11% Notes: *A ton of oil equivalent is defined as 10 million kcal. The applied conversion factors are: coal - 0.5, crude oil - 1.0, peat & wood - 0.2, hydro & electricity - 0.25, natural gas - 0.85, petroleum products - 1.0. 1.10 By October 1994, arrears for gas imported from Russia and Turkmenistan reached US$ 1.5 billion and US$0.7 billion, respectively. While Russia continued to deliver, Turkmenistan decided to suspend the deliveries of gas. An agreement between Ukraine and Turknenistan signed in November 1994 stipulated that payments of US$300 million would be made to Turkmenistan to resolve part of the arrears, and Ukraine would also compensate Turkmenistan for the cost of gas delivered in the fourth quarter of 1994 (the rest of the arrears would be rescheduled to be paid over seven years, with 2 years of grace). Negotiations with Russia are planned to be concluded in early 1995, and there are indications that Russia will agree to convert a large part of the already accumulated arrears to debt. 1.11 Energy Prices. Gasoline, diesel oil and fuel oil prices are liberalized. Electricity, gas, and coal prices are set by the central government. Local governments set the price of district heating, LPG, heating oil, peat and wood. With the exception of electricity, household energy prices cover only  4 Sector Background a fraction of costs. The difference is covered by central and local government budgets, and also by a non-transparent surcharge on industrial consumers (for gas and district heat). Even for electricity, there are several categories of households who are entitled to discounts, and the cost of these discounts is borne by the industrial consumers. During most of 1994, additional price distortions were caused by: (i) a subsidy to non-household consumers of coal; (ii) an artificial exchange rate that did not allow the passing of the full cost of imported gas to consumers; and (iii) price adjustments for electricity and heat that lagged behind fuel cost increases. Non-payment by customers became a major problem for electricity, gas and heat suppliers, further weakening the financial position of the utilities. In October 1994, the Government started the implementation of a program of price adjustments that: (i) drastically reduces household energy price subsidies; (ii) eliminates the explicit and implicit (through the exchange rate) subsidy to non-household consumers of coal and gas; and (iii) ensures the full recovery of increased fuel and other basic input costs in the price of electricity and heat. 1. 12 Sector Institutions. The sector is dominated by vertically integrated state owned monopolies, controlled by the State Coal Committee, the Ministry of Power and Electrification (Minenergo), the State Nuclear Energy Committee (Goskomatom) and the State Oil and Gas Committee. In 1994, the Government started a corporatization prograrn in the oil, gas and power subsectors, with the long term objective of privatizing those activities that are not natural monopolies (for more details on the Government's program in the power industry, see Section D below). There are eight vertically integrated state-owned regional utilities (Energos) under Minenergo. The regional utilities operate the regional dispatch centers, portions of the transmission network, the thermal power plants, and the distribution system. Two hydropower companies and the National Dispatch Center are directly under Minenergo. Minenergo performs policy making and ownership, and also acts as a day-to-day utility business manager. The concentration of the various, and in many ways conflicting, aspects of economic management in one entity is a major obstacle to improving the efficiency and quality of electricity supply. Institutional separation of the above functions, correction of fuel and electricity prices, commercialization of enterprises, and promotion of competition are needed to establish the foundation for a modern, profitable and efficient power industry. 1 .13 Employment. The energy sector employs almost 1 million people, or about 4.5 % of the labor force. About 630 thousand are employed in coal mining, 140 thousand in the power industry, and 200 thousand in oil and gas production, refining, transport and distribution. C. Power Industry Conditions and Priority Needs 1.14 Installed electricity generation capacity of the Ukrainian Power System (UPS) was 52,122 MW in 1993. It consisted of 12,818 MW of nuclear capacity, located in 5 plants with a total of 14 units in operation. There were more than 40 thermal (fossil fuel) power plants with conventional steam cycle technology, with over 110 generating units and a total capacity of 32,364 MW, of which 3,824 MW are combined heat-and-power units. Hydro capacity was 4,700 MW, stationed mostly in 9 plants with a total of 100 generating units. The capacity of industrial power plants was about 2,240 MW. The total effective generating capacity of the system was about 50,000 MW, due to the derating of older plants. Most older fossil fuel plants (about 23,000 MW) used coal as their primary fuel, but needed gas or mazut for co-firing. About 5,520 MW of power generation as well as most of the combined heat-and-power plants run on gas or mazut as main fuels. 1.15 Electricity generation was 228,316 GWh in 1993, of which thermal plants produced 135,875 GWh, nuclear plants 75,242 GWh, hydropower plants 11,214 GWh (including 200 GWh by a pump storage plant), and industrial plants 5,985 GWh (see Table 1.2). Net export was 1,145 GWh (2708  Sector Background 5 GWh exports, 1,563 GWh imports). Self-consumption of thermal and hydro plants was 10,648 GWh (or about 7.2% of their total generation), and of nuclear plants 5,228 GWh (6.9% of total nuclear generation). After accounting for other production needs (615 GWh), consumption of the pump storage plant (302 GWh), and transmission and distribution losses (22,473 GWh, or 9.8 % of total generation in the system), net electricity consumption came to 187,905 GWh. The peak demand in 1993 occurred in January, and was about 37,000 MW; the minimum demand, in June, was about 17,000 MW. Heat production was about 48 million Gcal. Total fuel consumption for electricity and heat production was 53 million tons of reference coal equivalent (tce, defined as 7000 kcal/kg), consisting of 19.4 million tce of natural gas, 7.3 million tce of mazut, and 26.3 million tce of coal. Table 1.2 Electricity Balance (GWh) . 1990 1991 1992 1993 1994 Generation 296258 276775 250945 228316 201598 Thermal 201682 182500 162390 135870 115848 Nuclear 76179 75131 73732 75240 68848 Hydro 10704 11904 8069 11210 12299 Small Industrial 7693 7240 6754 5996 4604 |hports* 7078 9231 5862 6449 5253 FSU 7078 9231 5862 6449 5253 Non-FSU Exports* 35048 23538 10511 7595 6277 FSU 6917 8094 4739 4885 4686 Non-FSU 28131 15444 5772 2710 1591 Net Exports 27970 14307 4649 1146 1024 Consumption 268288 262468 246296 227170 200575 Industry 146150 137725 126344 108022 88554 Agriculture 20453 20719 19061 18406 16758 Transport 14449 13611 12482 12111 10834 Communal 17582 17828 17219 16705 15722 Services Households 21142 24208 24909 26898 26764 Other 7460 7456 6049 5764 4876 Self Consumption 41054 40891 40231 39265 37066 and Losses including electricity exchange 1.16 Electricity generation, domestic consumption and exports have all declined significantly in recent years. Between 1990 and 1994, generation decreased by 32 %, domestic consumption by 25 %, and net exports by 96%. The decline in generation and consumption is likely to continue for some time (see Annex 1). GDP, however, declined even more (by about 50% in the same period), and, as a result, the electricity intensity of GDP increased from about 1.95 kWh/US$ in 1990 (that was already about 3.4 times the OECD average in that year) to 2.52 kWh/US$ in 1994.  6 Sector Background 1.17 The Ukrainian power industry was developed and operated as a part of the integrated power system of the FSU. During the last 15-20 years, investment policy favored the use of natural gas and nuclear power at the expense of coal-fired plants. The aging coal plants, whose performance was further affected by declining coal quality, have to use mazut or gas as supplementary fuels despite sharp increases in the price of imported oil and gas after the break-up of the Soviet Union. The total fossil fuel consumption of the thermal power plants consisted of 43.1 mt of coal, 20.2 bcm of gas, and 4.9 mt of fuel oil in 1993, representing, respectively, 45%, 20% and 50% of the domestic consumption of these fuels. 1.18 Nuclear power plants account for 26% of installed generating capacity. The 14 Soviet- designed operating units include two RBMK graphite moderated reactors at Chernobyl of 2 x 1000 MW nameplate capacity. The recommissioning of a third fire-damaged unit at Chernobyl is being contemplated. Construction of three new nuclear units in Zaporozhye, Rovno and Khmelnitsky, each 1000 MW of capacity, is in progress at varying degrees of completion. Sunk investments costs and the increasing costs of non-nuclear electricity generation are powerful incentives to complete these units. The April 1986 Chernobyl accident brought to the forefront the issue of the safety of nuclear plants (see Annex 2). The G-7 Summit Meeting held at Naples in July 1994 called for the phased closure of the Chernobyl plant and outlined a broad Action Plan to this effect, including the completion of three new nuclear reactor units to adequate safety standards, the rehabilitation of non-nuclear power plants, energy policy reform, and energy efficiency measures. The Ukrainian Government agreed to work with the G-7 to develop the details of the Action Plan (see Section D below). 1.19 The forced separation of the UPS, in November 1993, from the hydro plants on the Volga river that controlled system frequency, revealed some serious structural and functional weaknesses with negative consequences on overall system operation, security, reliability and quality of power supply. Most of the plants in the UPS are base-loaded, with limited load-following capabilities, and the system lacks peaking and spinning reserve capacity. Inability of the UPS to maintain the balance of supply and demand in real time, as measured by the system frequency and power flows through the interconnections with the neighboring systems, led to the separation of all neighboring systems, causing further deterioration of system performance and reduction in export capacity. The existing peaking capacity is provided by the hydro plants that are old and in need of rehabilitation. A decrease in hydropower capacity would lead to further deterioration in the reliability and quality of electricity supply. In view of unmet load-following requirements and the high share of base-load plants, it is also necessary to enhance the regulating capacity. 1.20 There are nine major hydropower plants in Ukraine, located on the two largest rivers, Dnieper and Dniester, with more than 25 km3 of total active volume of the reservoirs. The total average annual runoff of the rivers is 63.4 km3, the power capacity of the associated power plants is 4535 MW, and the total electricity production is about 10,750 GWh. The reservoirs are mainly low-head structures, with maximum heads ranging from 12 to 38.7 m. A cascade of eight plants is located on the Dnieper river, and one plant is on the Dniester (with two new plants under construction). The reservoirs were developed for multiple purposes. Operation of the reservoirs is, therefore, subject to many and often competing requirements, but is, to a large extent, determined by the electricity generation needs. The following summarizes the most important data:  Sector Background 7 Plant Storage Level Maximum Storage Active Turbine Avg. Max. Nane (above sea) Head Volume Storage Discharge Prod. Capacity m m mill. m3 mill. m3 m3/s GWh MW Kiev HPS 103 12 3730 1175 20x289 635 361 Kiev PSP 174.5 73.1 3.7 112 235 Kanev HPS 91.5 15.7 2620 290 24x320 850 444 Kremenchug HPS 81 17 13500 8970 12x490 1506 625 Dnieprodzerzhinsk HPS 64 15.5 2460 500 8x552 1250 352 Dnieper I & 11 HPSs 51.4 38.7 3330 865 4600 4140 1516 Kakhovka HPS 16 16.5 18200 6780 6x485 1420 300 Dniester HPS 125 40 6800 6x327 800 702 1.21 The severely inadequate capacity to regulate frequency in Ukraine has led to frequency levels that are not only unacceptable by international standards but also damaging to rotating electric equipment both in the consumption and generation side. Sometimes frequency drops below 49.0 Hz, while most well-operated systems would not allow frequency fluctuations of more than +/- 0.01 Hz. Owing to the damage done to electric equipment by substandard frequency, nuclear plants are normally taken out of service when frequency drops below a certain level (this is set at 49.0 Hz in Ukraine). Yet, these plants are kept on-line, even when frequency falls below the set point, because the authorities are loath to substitute lost nuclear plant with fossil fuel (more expensive) generation. Thus the safety of the nuclear plants is compromised. Therefore, enhancing the system's ability to better balance supply and demand, and improve frequency regulation, would have significant nuclear safety benefits. 1.22 The current control system consists of a hierarchical, four level dispatch and supervision system, and local automatic control subsystems at various facilities. At the top level of the dispatch system is the National Dispatch Center in Kiev, linked to the eight regional dispatch centers, to some hydro plants, and to 750 kV and 330 kV substations. The regional dispatch centers are connected to power plants located within their respective regions, and to the local distribution centers (27 in total). They also control the local 330 kV network and 330/110 kV substations. At the lowest, fourth level, are single generating units at the plants, and district distribution centers, connected with the local distribution centers. The system operation planning procedures are generally adequate, although there is space for improvements. Computer models are used for the analysis of system performance and optimization of regimes. The software, most of which is not portable, has been developed mainly in the central institutes of the FSU and delivered without the source codes and, therefore, cannot be maintained and upgraded locally. The real-time operation of the system is controlled manually, using telephone connections between dispatchers in central and regional dispatch centers, and plant and substations operators. The existing data acquisition and communication system is incomplete, and largely obsolete. No automatic generation control or automatic load control is used. Although these weaknesses are somewhat counterbalanced by the high technical competence of the staff, the weaknesses inevitably contribute to the low quality of electricity supply and operation inefficiencies. 1.23 The power transmission and distribution networks in Ukraine operate at levels of 0.4, 6, 10, 20, 35, 110, 150, 220, 330, 400, 500, 750 kV AC; there is also an 800 kV DC link with Russia. Transmission levels are defined as 330 kV and above, while 220 kV and lower voltage networks belong to distribution. Ukraine has interconnections with Central Europe (capacity 2000 MW), Russia (3900 MW AC, 200/250 MW DC), Romania/Bulgaria (3500 MW), Belarus (1000 MW), with a total effective power transfer capacity that exceeds 20% of the domestic generating capacity. In general, capacity of the transmission network is sufficient, particularly under the current conditions of lower consumption and reduced electricity trade. The 750 kV network was designed to become the main transmission network, to serve Ukraine and to export electricity from Ukraine and Russia to Central Europe. Power flows through Ukraine used to go from East to West, but now go in the opposite direction. Load on the 750  8 Sector Background kV lines is often light, and there is a problem of compensating the reactive power the lines generate. Other than for some local interventions (building a new substation instead of the one at Chernobyl, connecting the Dniester Pump Storage Plant, still under construction, to the 750 kV lines), there does not seem to be a need for major new additions to the network in the short-to-medium term. 1.24 Electricity demand is expected to drop even further before it starts growing again, due to a number of factors such as the general economic downturn, electricity price increases and economic restructuring (see Annex 1). An analysis of least-cost investment options was conducted for the 1995- 2010 period (see Annex 3). The analysis assumed that the Chernobyl units will be decommissioned in the 1997-2001 period, and thermal power units of 1525 MW capacity are retired in the 1996-2002 period. The safety upgrade of all nuclear units was also assumed (the upgrade requires each unit be taken off line for one year). The simulation of system operation showed that the marginal cost of generation in the peak period was about 60% higher than the marginal cost of generation at the minimal load. The completion of a pump storage plant on the Dniester river was consistently part of the least cost solution, suggesting that the system needs the peaking capacity provided by hydropower plants. This preliminary analysis also indicated that completing the nuclear units that are in an advanced stage of construction is justified, and that, after these units are commissioned, there is no need for additional capacity until 2008 (i.e., there will be a period of several years with significant capacity surplus in the system). Given that some of the plants are quite old, it may be more cost-effective to retire them earlier than indicated in Minenergo's current retirement plan. Those old coal-fired plants that are not retired and the hydropower plants will need to be rehabilitated. More details are provided in Annex 3. 1.25 Total power generation investment requirements are preliminarily estimated at US$3.5 billion in the 1995-2005 period. Of this total, US$1.9 billion is needed for nuclear power, including US$ 0.6 billion for safety upgrades, US$ 0.6 billion for decommissioning and other works at Chernobyl, and US$ 0.7 billion for the completion of three new nuclear units. The rehabilitation of thermal and hydropower plants and the partial completion of the Dniester PSP requires about US$ 1.6 billion. About half of total investment costs would be incurred in foreign exchange. 1.26 Ukraine has a significant power engineering and manufacturing base. The "Turboatom" and "Electrotyazhmash" factories in Kharkov, for example, were among the largest producers of turbines and generators in the FSU, with exports to many countries. However, domestic production capability for some categories, notably high-voltage equipment, advanced power generating technology (gas turbines, modern coal-burning technology, environmental protection equipment), and instrumentation, control, commnunications and computing equipment, is limited or non-existent. Also, there seems to be limited expertise available in modern computer-based software and methodology for system control, as well as for least-cost investment planning and economic dispatch. D. Governnent Policy and Strategy in the Power Industry 1.27 In 1992-93, the Government's reaction to the increase in the price of energy imports and cost of energy supply was to rely on the methods of central planning such as price controls, cross- subsidization among consumer classes, and the rationing of energy, rather than allowing market mechanisms to regulate and balance supply and demand. The principal reason, presumably, was concern about the political risk of increased unemployment inherent in market based solutions. Another prominent concern is dependency on one supplier, Russia, for half of Ukraine's primary energy needs. 1.28 In late 1993, the Government prepared a "Concept for the Development of the Energy Sector of Ukraine for the Period up to 2010". The "Concept" was subsequently approved by the  Sector Background 9 Parliament. It spelled out the following main directions for Ukraine's long-term energy strategy: (i) the development and implementation of a policy that promotes energy savings; (ii) economically and environmentally justified utilization of domestic energy sources; (iii) restructuring of the economy that reduces the energy intensity of production; and (iv) increasing reliance on alternative (renewable) energy sources. The investment program outlined in the "Concept" recognized the priority of rehabilitating capacities in the power, coal, gas and oil subsectors, however, it also included a number of ambitious expansion schemes in coal mining, oil and gas production, and nuclear power generation. 1.29 In early 1994, the Parliament passed a Law on Energy Conservation. The Law provided economic incentives for investments in energy conservation, including subsidies and earmarked loans. Specifically, it called for the establishment of national and local extra-budgetary energy conservation funds to support energy saving initiatives (however, it failed to specify the revenue sources of the funds). The Law also contained a number of command-and-control type provisions such as penalties for "above the norm" energy use. 1.30 "The Complex Program for the Modernization and Development of Fuel and Power Industry of Ukraine for the Period up to 2010" prepared by Minenergo in 1992 (and revised in 1994) focussed on the rehabilitation of thermal and hydropower plants in the 1995-2000 period. In addition to extending the life of these plants, rehabilitation would be aimed at maximizing the use of domestic coal, and improving plant reliability and environmental performance. Planned investments in new capacity in the same period would include the completion of pump storage and nuclear plants currently under construction. In order to meet the assumed increase in demand for electricity after 2000 (see Annex 1), the "Complex Program" recommended the construction of additional nuclear and thermal power units while continuing the rehabilitation and modernization of existing thermal and hydropower plants. 1.31 Both the "Concept" and the "Complex Program" included extensive measures to upgrade the safety of nuclear power plants. The "Complex Program" assumed that the two remaining units of the Chernobyl Nuclear Power Plant would be closed when their reactor channels reach the end of their life in 1998-2003. During discussions with the G-7 Nuclear Safety Working Group, the Government agreed to consider the possibility of the early closure of the Chernobyl plant provided that a solution was found for a set of related issues, such as the financing of replacement nuclear capacity, closure costs, and the mitigation of social consequences. It was agreed that an international Task Force would be formed from Ukrainian and foreign experts with the task of developing a detailed, comprehensive Action Plan for nuclear safety in the context of a power sector development strategy (see Annex 2). The joint international Task Force was set up in December 1994, and its work is underway. 1.32 On May 21, 1994, the President of Ukraine signed Decree 244/94 on Market Transformation Measures in the Electricity Sector of Ukraine (see Annex 4/A). The Decree ordered a broad restructuring of the power industry based on the United Kingdom's model of separating generation, transmission, and distribution functions, corporatizing and privatizing the generating and distribution companies, setting up a competitive wholesale market for electricity, and establishing an independent agency to regulate the industry (i.e., independent from the enterprises and not subordinated to any Ministry). After some initial delay, the Government adopted an Action Plan to implement the Decree on November 2, 1994 (see Annex 4/B). As a first step, a National Electricity Regulatory Commission was established in December 1994. The Commission is expected to take over the regulation of electricity prices from the Ministry of Economy in May 1995. Full implementation of the Decree is expected to increase the efficiency and reliability of electricity supply, restore the financial health of the industry, and create a favorable framework for private investment (including equity participation) in power generation.  10 Sector Background 1.33 In response to the growing problem of interenterprise arrears, the President of Ukraine signed a Decree on October 12, 1994 ordering electricity and gas suppliers to agree on a schedule for the reduction of arrears with their customers. The Decree created an Interministerial Operative Commnission to supervise the fulfillment of these agreements, and to ensure that supplies are maintained to the highest priority customers in the critical winter period. The electricity and gas suppliers are required to report non-payments to the Operative Commission, and the Commission's task is to take appropriate steps to remedy the situation, including ordering the utilities to reduce or discontinue service to delinquent customers. E. Bank Strategy and Experience 1.34 The Bank's overall objective is to support Ukraine's efforts to accelerate structural reforms, and to promote efficient investments in high priority sectors in order to complete the transition of the country to a market economy, accelerate the rate of economic growth, and increase efficiency. This will require strengthening key financial institutions; accelerating privatization; extending the openness of the policy environment; rehabilitating and re-orienting its physical infrastructure; and extending the social safety net and the efficient delivery of social services. This cannot and need not be done at the expense of the stabilization effort; in fact, many efficiency measures such as infrastructure cost recovery are likely to be revenue enhancing. 1.35 The Bank approved the first loan for US$27 million equivalent to Ukraine in June 1993 (Ln. 3614-UA) to finance an Institution Building Project aimed at supporting enterprise reform, financial sector reform, and public economic and financial management. Initially, the implementation of the project suffered from the unstable policy environment in Ukraine. Major bottlenecks have been: (i) Ukraine's inexperience with Bank policies and procurement procedures; (ii) the project structure (three components and eight implementing agencies, many different Bank staff involved); (iii) lack of guidance from an understaffed and demotivated Implementation Unit; and (iv) an adverse attitude toward interagency collaboration within the Ukrainian government. Institutional rearrangements and the improved policy environment significantly improved the performance of the project in late 1994. 1.36 The second Bank operation is a Rehabilitation Loan (Ln. 3831-UA) of US$500 million equivalent approved in December 1994. The Loan provides financing for critical imports needed to stem the decline in production and to cushion the deterioration of living standards of the population. 1.37 The Bank has been involved in the Ukrainian energy sector since early 1992. An Energy Sector Review (Report No. 11646-UA) was issued in 1993, leading to an Energy Strategy Conference held in Kiev in June 1993. During the Conference, an understanding was reached that the Bank would focus on power generation, gas transmission, and gas distribution, since these were the subsectors where the the Bank's contribution to policy development and financing of priority investments could make a significant difference. It was also determined that lending operations should aim at the rehabilitation of existing assets rather than capacity expansion, while supporting initiatives that increase the financial and operational autonomy of enterprises and foster competition. Immediately after the Conference, the Government, assisted by the Bank and other multi- and bilateral agencies, started the preparation of a number of projects to rehabilitate hydropower plants, thermal power plants, gas transmission lines, and gas distribution and metering facilities. In 1993-94, the Bank also assisted the Government to prepare projects for coalbed methane utilization and district heating end-user efficiency improvements for possible financing under the greenhouse gas reduction initiative of the Global Environment Fund. The Bank recognizes that it will not be able to provide all the required foreign exchange to the power industry. Additional funding will be needed from other sources such as EBRD, suppliers' credit and private investors.  Sector Background 11 1.38 Utilizing trust funds, the Bank provided technical assistance in the areas of industrial energy audits, rehabilitation of thermal and hydropower plants, gas distribution and metering, legislation for oil and gas production, and power industry institutional reform. Decree 244/94 (see above) is one of the regulatory and legislative acts that benefitted from these technical assistance activities. Following the approval of the Decree, the Bank, jointly with Minenergo, organized a donor meeting in Kiev in July 1994. The purpose of the meeting was to ensure the availability of adequate technical assistance for the implementation of this important reform initiative in the power subsector. The donors offered technical assistance of about US$4 million equivalent for the first year of the reform (including US$450,000 from the Bank's Institutional Development Fund), and asked the Bank to assist the Government to coordinate the implementation of the technical assistance program. The proposed project would both capitalize on the reforms undertaken under the Decree, and provide leverage for its further implementation. 1.39 The Bank has been actively supporting the dialogue between the G-7 and the Government of Ukraine in the area of nuclear safety. In collaboration with EBRD, the Bank assisted the G-7 Nuclear Safety Working Group to develop an Action Plan that includes the phased closure of capacity at Chernobyl, the completion of replacement nuclear capacity, the safety upgrade of the remaining nuclear units, the rehabilitation of non-nuclear power plants and energy efficiency improvements. The Bank is also actively participating in the work of a joint Ukraine/G-7 Task Force (para. 1.31) that is entrusted with the technical preparation of the details of the Action Plan. Although the Bank will not finance nuclear power investments, the Bank's support for pricing and institutional reforms is an important contribution to the establishment of a framework that will facilitate the implementation of the Action Plan. Furthermore, such projects as the proposed Hydropower and System Control Project, which will also positively affect the safety of the operation of the nuclear plants (para. 3.24), and the planned Thermal Power Rehabilitation Project, are key elements of the Action Plan. 1.40 A review of several decades of the Bank's worldwide lending for the power industry found a declining trend in the industry's pricing, financial, technical and institutional performance, mainly due to governmental failure to address the industry's fundamental structural problems ("The World Bank's Role in the Electric Power Sector", World Bank Policy Paper, Washington DC, 1993). Conflicts between the government's role as owner and its role as operator of utilities have led to poorly defined objectives, government interference in daily affairs, and a lack of financial autonomy. The review recommended that Bank lending for electric power should focus on countries with a clear commitment to improving the performance of the power industry by commercialization, corporatization and the establishment of a transparent regulatory framework. The Bank's experience in power rehabilitation is limited since there were very few purely rehabilitation projects. To the extent that rehabilitation components can be evaluated separately, performance has been satisfactory.  12 The Project II. THE PROJECT A. Project Concept and Objectives 2.1 The Bank's Power Demand and Supply Options study issued in 1993 (Report No. 11561- UA) examined a number of supply scenarios to meet projected electricity demand in the 1994-2010 period. The study found that, apart from the completion of the nuclear power and pump storage units already under construction, no new generation capacity is needed, and the rehabilitation of thermal and hydropower plants was likely to result in the most significant net benefits. Based on this finding, feasibility studies were initiated to prioritize Minenergo's thermal and hydropower rehabilitation programs and to prepare projects that could be financed by development banks. The hydropower study also included assessments of the Dniester Pump Storage Plant (PSP) and system-wide control and dispatch facilities. The studies were carried out by consultants whose activities were facilitated and supervised by counterpart teams appointed by Minenergo. The services of the consultants were financed from trust funds provided by the Government of Netherlands and the Government of Switzerland. 2.2 The draft final reports for the two studies were submitted to Minenergo and the Bank- in early September 1994. The hydropower study (prepared by SGI Engineering Ltd) identified high priority investments to rehabilitate the hydropower plants and to upgrade system control facilities. In addition, it also recommended the completion of the Dniester PSP. However, the preparation of the Dniester PSP lacked a proper environmental impact assessment and there was a need to revise the implementation schedule to take into account the expected availability of funds. 2.3 The results of the feasibility studies were reviewed in detail by Minenergo and the Baik. It was agreed that the Government would: (i) request a loan for a Hydropower Rehabilitation and Systeril Control Project; and (ii) continue the preparatory work on thermal power rehabilitation and thi completion of the Dniester PSP for eventual consideration for financing by the Bank. The appraisal ot the project took place in September/October 1994. 2.4 The objectives of the project are to: (i) improve the efficiency, reliability, safety and environmental performance of hydropower plants; (ii) increase hydropower generation capacity; (iii) improve the quality of electricity supply by upgrading load and frequency control, which would also improve the safety of nuclear plants; and (iv) reduce fuel costs by facilitating the economic dispatch of generating units. B. Project Description 2.5 The project includes the following four components: (a) The initial 5 years of the hydropower rehabilitation program outlined in the feasibility study, including the implementation of the complete rehabilitation program for the Dnieper I and Dnieper II hydropower plants and the Kiev PSP; near-complete implementation of the rehabilitation program for the Kakhovka HPS; and partial implementation of the rehabilitation program for the Kiev, Kanev, Kremenchug and Dniprodzerzhinsk hydropower plants; (b) Installation of dam safety monitoring systems at the main water reservoirs on the Dnieper river (Kiev, Kanev, Kremenchug, Dnieper, Dniprodzerzhinsk, Kakhovka);  The Project 13 (c) Upgrade of communications, dispatch, system control and protection, and generating unit control; and (d) Technical assistance for project implementation, and optimization of the use of the reservoirs on the Dnieper river. 2.6 Rehabilitation of Hydropower Plants. Hydropower plants play a critical role in regulating peak load and system frequency. Most of the existing plants are old and in need of rehabilitation (eight of the nine main hydro plants are older than 20 years; five are older than 30 years; the oldest plant, Dnieper I, was built in 1932 and then reconstructed in 1947). Many units have problems with turbine runners and governors, generator windings and auxiliaries, oil leakage, substations circuit breakers, load control, and instrumentation and control systems. This has lead to increased operating and maintenance costs, derating of the units, and lower efficiency and availability. Allowing further deterioration would increase costs, worsen the capacity mix, and further reduce the already insufficient regulating capability of the system. 2.7 The work involves: Replacement of turbine runners, turbine governors, and replacement, rehabilitation or upgrade of other related equipment (guide vanes, runner chambers, shafts, servomotors measuring and control devices) at the Kiev, Dnieper I and Kakhovka plants. Only eight out of twenty turbines at the Kiev plant will be rehabilitated due to the limited capaciiv of the turbine manufacturer (the Kharkhov turbine factory, which produced most of tc original turbines for the plants); the other twelve will be included in the second phase of the rehabilitationprogram. Four out of six turbines will be rehabilitated at the Kaklrovl.d HPS, where only one tubine at a time can be taken out. At the Dnieper I HPS. all turbines will be included in the project. Rehabilitation of one turbine both at Kremenchug and Dniprodzerzhinsk plants will also be included. * Rehabilitation of generators including replacement, rehabilitation or upgrade of stator and rotor windings, magnetic static core, generator circuit breakers, excitations and cooling systems, voltage transformers and electrical protection. All the generators that are associated with rehabilitated turbines will be rehabilitated too; in addition, generators at the Kiev PSP and Dnieper II, where no turbines are planned for rehabilitation, will also be included in the project. All generator circuit breakers will be replaced in all plants. * Rehabilitation of switchyards and related equipment (step-up transformers, circuit breakers, isolators and earthing switches, HV instruments and protection, current and voltage transformers) at the Dnieper I, Dnieper II, Kakhovka, Kremenchug, Dniprodzerzhinsk and Kiev plants, and the Kiev PSP. * Upgrading of control and monitoring equipment at the Dnieper I, Dnieper II, Kakhovka and Kiev plants, and the Kiev PSP. The work consists of rehabilitating, replacing or upgrading instruments for monitoring temperature, vibrations, generator air gap, water discharge, and equipment for local, unit and plant-level control. 2.8 Installation of Dam Safety Monitoring Systems. Reservoirs on the Dnieper river were developed with multiple uses in mind. In addition to hydropower generation, the reservoirs are used for  14 The Project flood control, irrigation, industrial and drinking water supply, shipping, fisheries, tourism. Because of the configuration of the terrain, the reservoirs are low head structures with long embankments. Some of them have long dykes protecting the surrounding land from being flooded. The project includes measures to rehabilitate and upgrade the existing dam monitoring systems for about 100 km of dams and dykes for the reservoirs on the Dnieper river. The work will include dam safety investigation, and rehabilitation and upgrade of the existing, as well as installation of new instrumentation (primarily pressure, motion and moisture sensors, water levels, etc.), drainage structures and alarm systems. Data collection, analysis and storage, automation and centralization of the readings where justified, will also be considered. Procedures for dam safety monitoring and emergencies will be reviewed and, if necessary, improved, including emergency response, evacuation and training programs. 2.9 Upgrade of Communications, Dispatch and System Control. Low level of automation across the entire UPS, outdated and inadequate protection, control, metering, communication and computing equipment compromise system operation. At present, the frequency is regulated manually, but deviations below 49.3 occur during the peak hours, and above 50.2 Hz during the low load hours (for comparison, the UCPTE standard requires the system frequency to be maintained at 50.0 Hz within the band of + or - 0.01 Hz). The response time of primary regulation is slow. The governors have large dead bands, and were made using old technology with hydraulic amplifiers and vacuum tubes. Load following scheduling is also done manually, rather than by computer-based economic dispatch, resulting in extra fuel costs. Production scheduling of hydro generators, which are all peaking units, is controled manualy. The control of power flows across interconnections with the neighboring systems is subject to similar problems as the control of frequency (manual control, unstable voltage conditions), creating major obstacles to reintegrating the UPS with its neighbors. Isolated operation, in addition to preventing the trade of electricity, also reduces reliability, security and quality of supply, and is more expensive as it requires a larger reserve capacity. The operation of the planned power pool (the spot market for electricity) will require the improved metering of interconnections, generating plants, power supply companies and wholesale customers. Bids and availability forecasts from the generators will have to be collected and evaluated. The data acquisition and communication system must be able to support the real- time operations of the pool by providing accurate and timely information for production scheduling, billing and compensation of the pool members. 2.10 The following measures are designed to answer the above problems: * Upgrading of generating unit governors: in addition to the new governors installed at the hydro plants (included as a component in the hydropower rehabilitation program), new governors will be installed at a number of thermal generating units. The governors will be equipped for manual, local automatic and remote control allowing the implementation of real-time economic dispatch by the National Dispatch Center. * Upgrade of plant protection, plant dispatch and generation control equipment at the Dniester hydropower plant. * Upgrade of protection systems for the high-voltage transmission lines. * Installation of the necessary computing equipment to support automatic generation control and economic dispatch at the National Dispatch Center. * Upgrading the data acquisition and transmission systems at the National Dispatch Center, the Regional Dispatch Centers, and at a number of generating plants and important  The Project 15 substations by installing modem remote terminal units and more powerful computer systems. The upgrade will increase volume and frequency of data available to the dispatchers enabling better monitoring of the system and more timely reactions, and allow the implementation of automatic generation control and economic dispatch functions, as well as effective functioning of pool operations. The system will be implemented as a modular, open architecture system, which can be expanded in stages. Upgrading the communication system by replacing the existing links representing the most serious bottlenecks. The communication system is essential for the real-time control and operation of the power network. The existing analog system has serious limitations. The communication lines (cables, power line carriers and radio) are old, unreliable, susceptable to noise corruption, and increasingly difficult to maintain. The bandwidth of the communications links is not adequate. Given the size of the Ukrainian power system and the corresponding communication requirements, this component will be designed to enable functioning of the new SCADA and automatic frequency control systems, laying down elements of the new communication system which will be gradually expanded over time. Detailed proposals for the location and type of the new communication lines will be determined in the detailed engineering design stage in conjunction with engineering specifications of the SCADA and automatic frequency control systems. 2.11 International Waterways. The Dniester hydropower plant is about 15 km upstream from the point where the river forms the borderline between Moldova and Ukraine. There is no dispute between the two countries concerning the operation of this plant. Upgrading of the dispatch and generation control equipment for this plant will not affect the reservoir nor any other water retaining structure, and will have no effect on the flow of the river. 2.12 Technical Assistance. Project implementation support will compensate for the limited experience of the beneficiaries in international procurement and the management of foreign contractors. It will include support for preliminary detailed engineering design, technical specifications, bidding document preparation, bids evaluation, contract negotiations, contract administration, cost control, schedule monitoring and coordination, establishment of communication and documentation procedures, supervision of detailed design development, construction inspections, inspections in manufacturers' facilities, quality control, system checkout and integration in factory and on site, factory and field acceptance tests, and other project implementation services. The technical assistance will also include review of the existing procedures in managing the river basin reservoirs for the Dnieper river, and proposals for the improvements, if necessary. Training will be included in the tender documents for the supply of equipment. In addition, training will be provided in project management and procurement. It is estimated that 160 man-months of internationally recruited, and 526 man-months of local consulting services will be needed. C. Project Context 2.13 The components of the project were chosen to address some of the most pressing problems in the Ukrainian power system, and to maximize the impact of the Bank's contributions. The least cost power investment plan includes the rehabilitation of a number of existing thermal and hydropower plants, and the completion of three nuclear units and the pumped storage plant that are already in an advanced stage of construction (see Annex 3). The proposed project is in accordance with the Bank's energy strategy which aims at promoting energy efficiency improvements and adaptation of  16 The Project energy utilities to the requirements of a market economy (see Energy Sector Review, Report No. 11646- UA). Increased efficiency in electricity generation will reduce fuel costs and improve the balance of payments. The improved quality of electricity supply, a basic input for production, will facilitate the modernization of Ukraine's industry. By increasing the efficiency of electricity generation, this project is consistent with the Country Assistance Strategy. Together with the planned Thermal Power Rehabilitation Project, the proposed project demonstrates that the Bank is willing to step up assistance to those sectors of the economy that are committed to reform. This is particularly important at this time when the power industry is making the first bold reform steps. The Bank's involvement is regarded as important in supporting the implementation of high priority investments under the present conditions of severe resource constraints. By rehabilitating and upgrading facilities that utilize a renewable resource, the project is consistent with the objective of environmentally sustainable development. Finally, the project is also consistent with the nuclear safety initiative of the G-7 since it supports the continued utilization of a low-cost alternative source of power, and improves the safety of existing nuclear units by reducing fluctuations in frequency. D. Environmental Aspects 2.14 The impact of the hydropower rehabilitation component (environmental category "B") was reviewed during the preparation of the feasibility study. Other project components were placed in category "C", not requiring specific environmental analysis. The main environmental problem detected by the enviromnental analysis carried out for the feasibility study was excessive leakage of lubricating oil from turbine runner blade seals. The study recommended the control of water pollution through the rehabilitation of turbines, and also identified the need for improved water management, and improved instrumentation and procedures related to dam safety. The conceptual design and structural stability of water retaining structures were found to be satisfactory. 2.15 During implementation, the project is not expected to impose any costs on the environment. Reservoir structures will not be subject to any work. There will be no activities that would result in a significant impact on the existing patterns of water flows and water usage. Environmental benefits will come from three sources: (i) the rehabilitation of turbines; (ii) the rehabilitation and upgrade of dam safety systems; and (iii) economic dispatch. The turbines of which the runners will be replaced were built between 1947 and 1964. The rehabilitated turbines are expected to have improved and longer- lasting sealing, which should significantly reduce or eliminate the leakage. In addition, improved turbine efficiency will lead to more hydro energy produced. Since the marginal source of power in Ukraine is fossil fuel, this will translate to reduced fossil fuel use with corresponding environmental benefits. Improved dam safety monitoring will reduce the risks of accidents and allow for improved water management and control, which will also take environmental aspects into account. Introduction of automatic generation control and economic dispatch will lead to a more efficient use of fossil fuel plants, resulting in commensurate reduction in fossil fuel use and the corresponding emission of pollutants. E. Cost Estimates and Financing 2.16 Project Costs. The total cost of the project is estimated at US$190.2 million equivalent, of which US$106.7 million is in foreign exchange. Cost estimates are based on September 1994 prices. Physical contingencies were estimated at 15% of base costs. Price contingencies for foreign costs were estimated using a constant price increase of 2.2% per year. Price contingencies for local costs were estimated assuming that the currently low domestic prices would increase in real terms in the future. Assumptions on domestic inflation and exchange rate are given in para. 3.11. Based on information from the Ministry of Finance that imports under the proposed project would be exempt from import duties and  The Project 17 value added taxes, these have not been included in the cost estimates. A summary of the cost estimates is presented in Table 2. 1. Table 2.1 Cost Estimates Bill. Krb | Mill. US$ | Foreign L2l | ~~~~~~Local | Foreign| Total | Local |Foreign| Total as| Tofa| 1. Hydropower 2460.6 2131.2 4591.9 45.1 39.1 84.2 46% Rehabilitation 2. Dam Safety 48.5 88.3 136.9 0.9 1.6 2.5 65% 3. System Control and 730.4 2277.1 3007.5 13.4 41.8 55.2 76% Communication 4. Technical Assistance 44.2 230.1 274.3 0.8 4.2 5.0 84% Project Base Costs 3283.7 4726.8 8010.6 60.2 86.7 146.9 59% Physical Contingencies 485.9 674.5 1160.4 8.9 12.4 21.2 58% Price Contingencies 2757.1 1439.7 4196.8 14.4 7.6 22.1 35% Total Project Costs 6526.7 6841.0 13367.8 83.5 106.7 190.2 56% Interest During 819.0 3990.5 4809.5 4.2 20.7 24.9 83% Construction* Total Financing 7345.7 10831.5 18177.3 87.7 127.4 215.1 59% Required * including commitment fee 2.17 Project Financing. The proposed World Bank loan of US$114.0 million would cover 50% of project costs, plus US$18.3 million of interest during construction (the foreign exchange component of total interest during construction estimated at US$ 24.1 million equivalent). Following a five year grace period, repayment of the principal and interest payments would commence and continue for 12 years. The Borrower would be Ukraine, whose Government would enter into subloan agreements with the beneficiaries. The beneficiaries would be the National Dispatch Center and the Dniprohydroenergo (DHE), a joint stock company that includes the hydropower plants on the Dnieper river. During negotiations, the delegation confirmed that the loan proceeds would be on-lent to the beneficiaries. The subloans would have a maturity of 1 7years includingfive years of grace. The interest rate in the subloan agreements would be equal to the World Bank's standard variable interest rate plus a margin of 1. 5 % to cover the cost of loan administration. The foreign exchange risk will be borne by the beneficiaries. The beneficiaries would also reimburse the Government for the commitment fee (para. 6.1.a). The signing of the subloan agreements would be a condition of loan effectiveness (para. 6.2.a). 2.18 The Government of Switzerland will provide a grant of US$10.5 million to finance part of the cost of the hydropower rehabilitation component and related technical assistance services. The proceeds of the Swiss grant (except the technical assistance component) will be on-lent to DHE at terms that are similar to the terms in the above subloan agreements. The Government of Canada will provide grant financing for technical assistance for project preparation, procurement and project implementation for the first year (1995), in the amount of US$ 1.8 million. The Government of Norway will finance the water management component of technical assistance in the amount of US$0.6 million, also on a grant basis. DHE and NDC will finance the remaining costs, part of interest during construction, and the commnitment fee, estimated at US$88.3 million equivalent, from internally generated revenues. Financing arrangements are shown in Table 2.2.  18 The Project Table 2.2 Financing Plan 7 V 0 00 T | Islmlion US$l milllon _________ % of Totall _____ _ Local Foreign Total IBRD 0.0 114.0 114.0 53.0% Government of Switzerland 0.0 10.5 10.5 4.9% Government of Canada 0.2 1.6 1.8 0.8% Government of Norway 0.1 0.5 0.6 0.3% Hydropower Company 66.5 0.4 66.9 31.1% National Dispatch Center 20.9 0.4 21.3 9.9% Total Financing Required 87.7 127.4 215.1 100.0%  Financial and Economic Analysis 19 III. FINANCIAL AND ECONOMIC ANALYSIS A. Electricity Prices 3.1 Electricity prices for residential consumers and the average price of electricity are set by the Ministry of Economy. Electricity prices for non-residential consumers (within the prescribed average) are set by Minenergo following the approval of the Ministry of Economy. Although the average nominal price of electricity increased almost 50 times (on average) in 1993, when expressed in a convertible currency, the price remained very low (see Table 3.1). Significant real increases occured in 1994 and early 1995, almost fully eliminating the gap between the average price (UScent 2.5/kWh equivalent in March 1995) and the economic cost of electricity (estimated at UScent 3.0/kWh)'. The prices cover the operating cost of the industry, and the difference between the average price and the economic cost is mostly due to the relatively low cost electricity produced by hydropower plants. Table 3.1 Average Electricity Prices, 1990-1994 1990 1991 1992 1993 1994 1995 _________ _________ ~M arch Price Krb/kWh 0.02 0.37 1.5 67 650 3,105 Exch. rate Krb/US$ 18.8 59 221 7,625 52,000 125,000 Price UScent/kWh 0.1 0.6 0.7 0.5 1.3 2.5 3.2 Hydropower companies sell their output to the National Dispatch Center (NDC) under a two-part, cost-based rate structure designed to recover operating costs and capital expenditures, including a pre-determined profit margin. Hydropower costs are generally low, although tariffs vary significantly from one hydropower company to the next, reflecting differences in capital costs and social/community infrastructure. Minenergo adjusts rates for the sale of hydropower to NDC on a monthly basis. The cost of hydropower constitutes a small item (less than 1 %) in the overall retail electricity tariff. In March 1995, NDC's average cost of purchasing power from the hydropower companies was Krb 542/kWh (UScent 0.5/kWh equivalent). NDC paid Krb 1,860/kWh for the output of nuclear plants, and sold the electricity purchased from the nuclear and hydropower plants to the eight regional associations at a price of Krb 1,900/kWh. The regional associations combined this with the electricity produced in their own thermal power plants, added the cost of transmission and distribution, and sold the electricity to the public at an average price of Krb 3,105/kWh. 3.3 After an eight-fold increase that was implemented on March 1, 1995, retail electricity prices were set at Krb 3,500/kWh for urban, Krb 3,000/kWh for rural households, and Krb 2,300/kWh for households who rely on electrical stoves and space heaters (see Table 3.2). Several categories of households (e.g., veterans, Chernobyl victims) are entitled to substantial discounts. The tariff for rural households and electric stoves/heaters inverted the cost structure, since the supply of electricity to households is generally more expensive due to a number of factors (e.g., household consumption coincides with peak demand, higher distribution losses, etc). Additional distortions are caused by the lack of time-of-day, seasonal and regional differences in electricity prices (only the capacity charge for large industrial consumers differed regionally). 1 The low economic cost (in international comparison) is explained by (i) decreasing electricity demand resulting in surplus capacity; (ii) access to relatively low cost imported fuels; and (iii) low labor costs.  20 Financial and Economic Analysis Table 3.2 Estimated Economic Cost and Actual Electricity Prices, March 1995 [UScent/kWh J Economic Cost Actual Price Rural households* 3.8 2.4 Urban households* 3.5 2.8 Electric stoves and heaters 3.3 1.8 Agriculture 3.0 2.2 Industry (750 kva or above) 2.5 2.4 plus US$2-3/kW/month capacity charge Other industry 2.7 2.7 All other consumers 3.0 2.7 Weighted average (including 3.0 2.5 discounts) * Several households (e.g., veterans, Chernobyl victims) are entitled to discounts up to 50% of the stipulated price. 3.4 The Government of Ukraine indicated in its Memorandum of Economic Reform Policies, supported by the Rehabilitation Loan (Ln. 3831-UA), that wholesale electricity prices would be set by the market by the end of 1995. Building on the existing national dispatch operation, the wholesale electricity market (Energomarket) will allow thermal generators to submit bids for the sale of electricity to the "pool" in each hour of the day. Those bids will be accepted which allow demand to be served at minimum cost. A national wholesale price for the electricity generated by thermal plants, equal to the highest accepted bid plus a margin ("uplift") to finance the operating cost of NDC, and certain other costs, will be formed each hour, and charged to the local electricity companies and to those large industrial consumers, who participate in demand side bidding and purchase electricity directly from the pool. All entities who purchase from the "pool" will pay an additional transmission fee based on the cost of delivering electricity to their respective locations. 3.5 Nuclear and hydropower plants will not participate in supply side bidding. NDC (Energomarket) will continue to buy electricity from the nuclear and hydropower plants on the basis of contracts that will ensure the optimal dispatch of their capacity and full recovery of their costs. Local electricity companies will be allocated a share of this low cost electricity. The operation of the wholesale market, the prices paid to the nuclear and hydropower companies, and the formulation of retail electricity prices will be regulated by the National Electricity Regulatory Commission (NERC) that was established in December 1994. B. Past Financial Performance of the Implementing Agencies 3.6 National Dispatch Center. NDC is the sole purchaser of output from Ukraine's hydropower and nuclear plants. This output is resold to Ukraine's eight regional power companies, who currently engage in both distribution and thermal power generation, and to a few large industrial concerns that purchase power directly from NDC. NDC's resale tariffs are determined by Minenergo and reflect certain cross-subsidies that cause tariffs to vary from one regional company to the next. Overall, NDC's average resale tariff is designed to cover its cost of service -- a goal that has not been fully achieved during the recent years of high inflation and accumulating payment arrears. Had NDC been collecting its accounts receivable in a timely manner, its resale tariffs would have been adequate and it would be in a stable financial position today.  Financial and Economic Analysis 21 3.7 NDC's revenue stream depends almost entirely upon payments by the regional power companies (Energos). These companies are in serious financial difficulty and have amnassed substantial arrears to their suppliers, including NDC. Accounts receivable at the end of the third quarter of 1994 were approximately US$49.5 million at the then-applicable exchange rate of 68,000 Krb/US$. The average age of NDC's receivables is about 60 days, down from 96 days in 1993. This improvement was entirely attributable to inflationary devaluation of receivables. Many of NDC's outstanding 1994 receivables were recorded when the exchange rate was around 45,000/US$, and the company had, as of September 30, 1994, suffered an economic loss of over US$25 million from the devaluation of its uncollected receivables. Accounts receivable make up more than 99% of NDC's current assets; cash balances in bank accounts are only about US$ 0.2 million equivalent. 3.8 Delays in collection left NDC unable to pay its own suppliers in a timely manner. Devaluation of these payables created an inflationary gain of US$ 13 million as of September 30, 1994, partially compensating for NDC's inflationary losses on receivables. NDC's gains from inflation were substantially less than its losses because its payable balances were approximately 52% of its receivables, and NDC's delay in making payments was less than its delay in collecting customer accounts (36 days versus 60 days in 1994). Roughly 2.5% of NDC's current liabilities reflect amounts owed to hydropower stations; 97.5% reflects debt for purchases of nuclear power. NDC is not encumbered with any short- term borrowing. 3.9 NDC's situation reflects the broader problems in Ukraine's power industry: * In most of 1993 and in the first nine months of 1994, retail electricity tariffs lagged behind fuel price increases, remaining too low even to fully reimburse operating costs, let alone capital items and a profit margin; and * On average, 22% of the regional companies' billings to retail customers have not been paid in a prompt manner since 1992. Because of high inflation, deferred payments effectively spelled non-payment, given a legal framework that prevented the application of interest charges and penalties to unpaid customer balances. 3.10 Hydropower plants. The hydropower plants had a relatively modest cash-flow problem almost entirely attributable to delayed payments by NDC. The cumulative US$0.5 million receivable owed by the NDC as of September 30, 1994 represented about 13 % (or 45 days) of the annual revenue stream of the hydropower companies, constraining their ability to finance essential maintenance and investment. Accounts payable, the only current liabilities of the hydropower companies, were below the amount that the NDC owed to them. Hydropower output is seasonal, with revenue collection concentrated in the first half of the year, whereas costs are incurred more evenly over time. Thus there is a risk of a revenue shortfall when costs continue to experience inflation that has not been adequately reflected in prior months' rate-setting process. Minenergo was able to counter this problem in 1994 through monthly tariff adjustments that recovered the actual costs over whatever volume was produced in a given month. For this reason, hydropower tariffs were subject to significant monthly fluctuations. Compared to other sources of electricity, however, hydropower remained a low-cost source of power.  22 Financial and Economic Analysis C. Future Financial Performance of the Implementing Agencies 3.11 Financial projections for Dniprohydroenergo and NDC for the period 1995-2001 have been prepared and are presented in summary form in Tables 3.3-3.8, and in detail in Annex 6. The key assumptions include: * the general rate of inflation in Ukraine will be 90% in 1995, 34.5% in 1996, 19.6% in 1997, 12.7% in 1998, 6.2% in 1999, and 5% in 2000-2001; * the Krb/US$ exchange rate will be 140,000 in 1995, 165,000 in 1996, 180,142 in 1997, 191,253 in 1998, 199,766 in 1999, 205,842 in 2000 and 212,103 in 2001; * electricity demand will follow the medium scenario (see Annex 1) and electricity generation will be according to the least cost plan (see Annex 3); * electricity produced by nuclear plants will be sold at a price of US$ 0.015/kWh (this is expected to ensure the full recovery of operating costs, safety improvements, the completion of ongoing investments, and financing of the decomissioning of the Chernobyl plant); * following the completion of the proposed project, the hydropower plants will need to generate local funds of US$ 8 million equivalent annually in the year 2000 and beyond, in order to finance other investments; * in contrast to its current practice of purchasing only surplus thermal power supplies from the regional companies, NDC (Energomarket) will purchase all output from the new generating companies applying market-based (marginal-cost) pricing after mid-1995. The average price of thermal power will be US$0.020/kWh in 1995, gradually increasing to US$ 0.025 in 2000; and * NDC increases its working capital in 1995 through a modest increase in tariffs. Table 3.3 Dniprohydroenergo Summary of Income Statement (Billion Krb) 1993 1994 1995 1996 1997 1998 1999 2000 2001 Electricity Sales (TWh) 10.7 10.7 10.1 10.1 10.1 10.1 10.2 10.2 10.2 Revenues 35.7 278.6 4,860.4 4,999.9 5,158.1 5,725.1 6,199.4 9,542.5 10,657.8 Operating Expenses 25.5 176.3 1,006.0 1,136.0 1,243.4 1,779.9 2,043.2 5,348.7 6,431.5 Net Operating Income 10.2 102.3 3,854.4 3,863.9 3,914.7 3,945.2 4,156.1 4,193.8 4,226.3 Net Income After Tax 7.2 71.5 2,698.1 2,704.8 2,740.3 2,761.6 2,909.3 2,935.7 2,958.4 Operating Income as % of Rev. 29% 37% 79% 77% 76% 69% 67% 44% 40% Net Income as % of Revenues 20% 26% 56% 54% 53% 48% 47% 31% 28% Electricity Tariff (Ukr/kWh) 3 26 480 495 510 565 610 935 1040  Financial and Economic Analysis 23 3.12 Based on these assumptions, in order to generate enough funds to cover the local costs of the project, the projected price of hydroelectricity (approximately Krb 480/kWh in 1995) would have to increase to Krb 935/kWh in 2000, equivalent to less than UScent 0. 1/kWh throughout the project period, based on the forecast exchange rate for those years. The price of electricity sold by NDC has already been increased from UScent 0.4/kWh in 1994 to UScent 1.52/kWh; for the year as a whole the average price would have to be increased to UScent 1.91/kWh (most of this increase represents increases in the costs of power, as well as a provision for bad debt, an increase in working capital, and the financing needed for the local cost of investments). The average price of electricity sold by NDC is projected to increase only 8% in dollar terms between 1995 and 2000. The project would lower the cost of electricity production following its completion in the year 2000, thereby reducing retail electricity prices in the long run. Table 3.4 NDC Summary Income Statement (Billion Krb) 1993 1994 199S 1996 1997 199f 1999 2000 20I1 Electricity Sales (TWh) 84.6 84.2 135.2 177.0 175.0 176.6 179.6 185.7 192.0 Revenues 2,914 18,958 361,688 557,420 605,249 656,565 709,563 786,427 846,549 Operating Expenses 2,395 17,362 342,570 551,361 589,977 646,297 692,995 769,851 829,227 Net Operating Income 520 1.596 19,118 6,059 15,272 10,268 16,568 16,576 17,322 Other Income (Losses) 0 0 2,199 1,393 680 452 234 259 279 Net Income After Tax 422 1,243 14,922 5,217 11,166 7,504 11,761 11,784 12,320 Operating Income as % of Rev. 17.8% 8.4% 5.3% 1.1% 2.5% 1.6% 2.3% 2.1% 2.0% Net Income as % of Revenues 14.5% 6.6% 4.1% 0.9% 1.8% 1.X% 1.7% 1.5% 1.5% Electncity Tariff (Urk/kWh) 34 225 2676 3148 3458 3718 3950 4235 4409 Table 3.5 Dniprohydroenergo Cash Flow Statemnent (Billion Krb) 1994 1995 1996 1997 1998 1999 2000 2001 Net Income 72 2,698 2,705 2,740 2,762 2,909 2,936 2,958 Depreciation 5 597 597 597 1,039 1,235 3,897 4,368 Subtotal 76 3,295 3,302 3,338 3,800 4,145 6,833 7,326 Changes in non-Cash C/A (23) (2,170) (1,204) 192 (924) (1,080) (839) (744) Debt Principal Repayments 0 0 0 0 0 0 (314) (690) Cash Flow from Operations 53 1,125 2,098 3,530 2,877 3,065 5,679 5,892 World Bank Project (1,271) (2,632) (3,788) (5,879) (6,625) (3,892) 0 Other Fixed Asset Purchases (15) (66) (13) (20) (30) (35) (1,676) (4,706) Financing Gap 38 (211) (548) (278) (3,033) (3,595) 111 1,185 Borrowings 0 256 1,107 2,022 3,565 3,677 1,081 0 Changes in Reserves (15) 0 0 0 0 0 0 0 Cash Increase/(Decrease) 23 45 560 1,744 532 82 1,192 1,185 Debt Service Coverage NDS NDS NDS NDS NDS NDS 7.9 4.1 Interest Covetage NDS NDS NDS NDS NDS NDS 8.6 4.9 ADS: no debt service due to capitalzation of interest during construction  24 Financial and Economic Analysis Table 3.6 NDC Cash Flow Statement (Billion Krb) 1994 195 1996 1997 1998 1999 2000 2001 NetIncome 1,243 14,922 5,217 11,166 7,504 11,761 11,784 12,320 Depreciation 1 92 147 259 390 434 1,841 1,895 Subtotal 1,244 15,014 5,363 11,425 7,894 12,195 13,625 14,215 Changes in non-Cash C/A (1,138) (14,716) 1,010 (10,229) 5,110 (1,721) (2,390) (1,742) Debt Pnncipal Repayments (11) 0 0 0 0 0 (335) (796) Cash Flow From Operations 95 298 6,373 1,196 13,005 10,474 10,900 11,797 World Bank Project 0 (1,055) (2,098) (4,391) (5,277) (2,315) (670) 0 Other Fixed Asset Purchases 0 0 0 0 0 0 0 0 Financing Gap 95 (757) 4,275 (3,195) (1,835) (1,829) (473) 72 Borrowings 0 780 1,566 3,277 3,965 1,877 564 0 Changes in Reserves 0 0 0 0 0 0 0 0 Cash Increase/(Decrease) 95 22 5,841 83 2,130 47 90 72 Debt Service Coverage 8.5 NDS NDS NDS NDS NDS 11.8 6.2 Interest Coverage NDS NDS NDS NDS NDS NDS 18.6 10.1 NDS: no debt service due to capitalization of interest during construction 3.13 Apart from water inflows, the financial performance of the Dniprohydroenergo is affected by (i) the price it receives for electricity; and (ii) its collection ratio. Even after the reform of the power industry is implemented, hydropower plants will be obliged to sell their output under long term contracts at cost-based (below-market) tariffs. There is no substitute for the essential services such as frequency control and peaking that these plants provide. In consideration of the service obligation that they bear, Dniprohydroenergo would, under standard regulatory practice, receive a guaranteed rate of return. Due to Ukraine's special problems with payment discipline, this guarantee should encompass provisions ensuring timely payment. During negotiations, it was agreed that the contract between NDC and Dniprohydroenergo would include the following (para. 6.1. b): * a cost-based tariff formula that (i) includes the regular adjustment of cost data to reflect inflation; (ii) compensates for seasonal and annual fluctuations in hydropower output due to external circumstances; (iii) ensures that sufficient funds are available to finance the cost of agreed investments (including the proposed project); and (iv) encourages efficient operation and maintenance of the hydropower plants; and * a guarantee of prompt payment within 20 days of billing, backed by an interest penalty if delay occurs. The interest penalty will be calculated applying the National Bank Refinancing Rate. The signing of a suitable contract would be a condition of loan effectiveness (para. 6.2.b). 3.14 NDC's arrears to hydropower plants make up only 2.5% of its current liabilities. Thus the hydropower plants' current problems could be fully resolved in the near term without substantially altering NDC's financial position. A one-time resolution of NDC's outstanding trade debt for hydropower would be a condition of loan effectiveness (para. 6.2. c).  Financial and Economic Analysis 25 3.15 In the medium term, a more fundamental solution that addresses the underlying problem of non-payments to NDC will be required, including appropriate provisions in NDC's resale contracts as well as improvement of the regulatory and institutional framework within which NDC will operate. An agreement was reached during negotiations that new contracts between NDC (Energomarket) and its downstream purchasers would include the following terms (para. 6.1. c): * NDC will be entitled to charge an interest penalty on accounts receivable that become past due (i.e., not paid within 20 calendar days of receiving the bill). This penalty will be based on the National Bank Refinancing Rate. These penalties shall be immediately due and payable at the time they are assessed, and shall be entitled to the same priority of collection as any other account receivable; and * NDC will be entitled to make proportional reductions in deliveries to customers who have not settled their accounts in full within 30 days of billing. Specifically, on the 20th day after billing, NDC (Energomarket) will notify such customer that (i) his account is past due and interest penalties have begun to accrue; and (ii) specify the portion of deliveries that are liable to termination unless full payment (including accrued interest penalties) is made. Proportional cutbacks will go into effect on the 10th day following the notice (i.e., the 30th day after the original billing), and remain in effect until the customer's past-due account, including interest penalties, is settled in full. Contracting parties will agree that NDC (Energomarket) shall be held harmless for any damages, of whatever type, resulting from a proportional cutback that has been carried out in accordance with these stated conditions. 3.16 These provisions are expected to make it feasible for NDC to reduce both its accounts receivable, and the delay when paying its suppliers. During negotiations, it was agreed that (i) ADC's delay in paying its suppliers would be reduced to 45 days in 1995, 30 days in 1996, and 20 days thereafter; and (ii) NDC's accounts receivable would not exceed 60 days in 1995, 40 days in 1996, 35 days in 1997, and 30 days thereafter (para. 6. 1.d). Table 3.7 NDC Summary Balance Sheet (Billion Krb) 1993 1994 1995 1996 1997 1998 1999 2000 2001 Total Assets 782 3,232 55,011 66,295 70,093 85,187 102,569 119,008 133,791 Fixed Assets 6 5 1,195 3,286 7,646 22,465 34,794 44,711 54,482 Current Assets 777 3,227 53,816 63,009 62,447 62,722 67,775 74,297 79,309 Long-Term Investments 0 0 0 0 0 0 0 0 0 Total Liabilities 782 3,232 55,011 66,295 70,093 85,187 102,569 119,008 133,791 Equity and Reserves 219 1,462 16,612 21,828 32,995 40,499 52,260 64,044 75,961 Long-Term Debt 0 0 780 2,485 5,990 10,324 12,661 13,274 12,942 Current Liabilities 564 1,770 37,620 41,982 31,108 34,364 37,649 41,690 44,888 Current Ratio 1.38 1.82 1.43 1.50 2.01 1.83 1.80 1.78 1.77 Days of Receivables 96 60 60 40 35 30 30 30 30 3.17 Ukraine's financial and regulatory accounting standards currently do not provide for explicit recognition of bad debt. During negotiations, the Bank and the delegation agreed that the price setting mechanism would allow the National Dispatch Center to recover an allowance for bad debt in its resale tariffs, currently estimated at 10% of revenue in 1995, 7.5% in 1996, 5% in 1997-98, and 2.5%  26 Financial and Economic Analysis thereafter (para. 6.1. e). A similar provision will not be needed in hydropower tariffs, as the contract between the NDC and Dniprohydroenergo will provide for prompt payment in full. 3.18 In order to ensure adequate levels of self-financing of capital investments and a feasible financing plan, an agreement was reached during negotiations that NDC and Dniprohydroenergo each would generate for every financial year beginning in 1996 sufficient internal funds to cover not less than 40% of the annual average capital expenditures expected (or actually incurred) for that financial year, the previous financial year, and the next financial year (para. 6.1 .ff In order to ensure that Dniprohydroenergo and NDC are capable of servicing their total borrowing requirements, it was agreed during negotiations that Dniprohydroenergo and NDC would maintain a debt service coverage ratio of at least 1.5 during the project period (para. 6.1.fl. 3.19 Profits for NDC are projected to be relatively uneven in the early years of project implementation even though tariffs stay fairly constant in dollar terms. This is in part a reflection of the forecast collection performance for 1995 (much of which will have transpired before loan effectiveness) requiring slightly higher tariffs in order to maintain adequate cash flow. Part of the delayed payments will become realized in 1996, significantly increasing the company's cash flow and allowing for a permanent increase in working capital. Faster than expected reduction of NDC's accounts receivable in 1995 would allow for smoother profits and cash flows. Table 3.8 Dniprohydroenergo Summary Balance Sheet (Billion Krb) 1993 1994 199S 1996 1997 1998 199f 2000 2001 Toal Asets 237 341 11,391 15,258 20,157 26,747 33,681 38,004 40,361 Fixed Assets 226 237 9,027 11,120 14,460 19,551 25,302 27,318 27,657 Current Assets 11 104 2,364 4,138 5,697 7,196 8,379 10,686 12,705 Long-Tern Investments 0 0 0 0 0 0 0 0 0 Total Labilities 237 341 11,391 15,258 20,157 26,747 33,681 38,004 40,361 Equity and Reserves 219 276 11,025 13,730 16,470 19,232 22,141 25,077 27,656 Long-TernDebt 5 31 287 1,441 3,592 7,376 11,380 12,492 12,180 Current Liabilities 13 34 79 88 95 139 160 435 525 Cufent Ratio 1 3 30 47 60 52 52 25 24 Days of Receivables 31 44 20 20 20 20 20 20 20 D. Financial Analysis of the Project 3.20 A financial analysis was carried out for the hydropower rehabilitation component in order to determine whether it was in Dniprohydroenergo's financial interest to undertake the proposed investments. The estimated after-tax Financial Intemal Rate of Return (FIRR) on incremental financial cash flows -- defined as the difference between the "with" and "without" project situations and expressed in current US dollars -- is 16 %. Details of the FIRR calculations, including the assumed electricity prices and taxes, are provided in Annex 7. There was no financial analysis carried out for the system control component, since the quantified benefits -- fuel savings derived from more efficient economic dispatch - - do not accrue to the National Dispatch Center. Nevertheless, as described in Section C above, the contracts between NDC and its downstream customers are expected to ensure the full recovery of the investment costs of this component.  Financial and Economic Analysis 27 E. Economic Costs and Benefits 3.21 An economic evaluation, based on incremental costs and benefits, was performed for each subcomponent and then aggregated for the two main components and the project as a whole. The summary results are shown in Table 3.9. Details of the economic analysis are presented in Annex 8, together with key assumptions. All costs are expressed in 1994 constant economic prices, net of taxes and subsidies. The discount rate assumed for the economic analysis is 10%. The evaluation period is 1995-2020. Table 3.9 Net Present Values and Economic Internal Rates of Return |Project/ComponentNPV EIRR(%) (million US$) Hydropower Plant Rehabilitation 54.8 17.0 System Control and Communications Upgrade 53.6 22.7 |Project Total 101.9' 18.1 a/ Project total is less than the sum of the two main components due to the safety monitoring and technical assistance components for which no benefits were quantified. 3.22 Hydropower Rehabilitation Component. The least cost investment analysis presented in Annex 3 suggests that there is a lack of peaking capacity in Ukraine, and preserving the existing peaking capacity is of high priority. In order to analyze the economic viability of hydropower rehabilitation in more detail, Net Present Values and Economic Internal Rates of Return (EIRR) were calculated by comparing the economic cost and benefit streams of a "with project" and a "without project" case. The "without project" case assumes continued operation of the units at a progressively deteriorating level of efficiency and availability. The plant operating parameters for the two cases and other assumptions are presented in Annex 8. The main quantified benefits are: (i) improvements in the efficiency of turbines and generators; (ii) reduction in operating and maintenance costs as a result of better instrumentation and plant control; and (iii) improvement in plant reliability and availability through the reduction of forced and planned outages. As a result of improved efficiency and availability, electricity production is estimated to increase (on average) by 567 GWh annually compared to the scenario where no rehabilitation is undertaken, equivalent to 5.5 % of the average production of the plants in 1991-93. Incremental electricity sales were valued at the estimated economic value of peak power (which is 35 % higher than the average economic value of electricity). The plant-by-plant EIRRs range from 11 % to 31 %, indicating that the proposed rehabilitation is economically viable for each plant (see Table 3.10 below). The detailed plant-by-plant economic analysis is presented in Annex 8. 3.23 System Control Component. The benefits of this component derive mainly from greater efficiency in the loading (automatic economic dispatch) of power units and improved power flow in the system. As a result of the upgrade of communications, dispatch and system control, about 11,000 MW of thermal capacity will become available for more efficient dispatching. These benefits were approximated by cost reduction resulting from fuel savings. Since the proposed upgrade measures represent a significant advance over the present system, fuel savings are expected to be substantial. For the purpose of this analysis, fossil fuel savings of 0.25 Mtoe/year were conservatively assumed (equivalent to 3% of the expected fuel consumption of these plants in 1994). The EIRR for this component was estimated at 22.7%.  28 Financial and Economic Analysis Table 3.10 Measures of Net Economic Benefits by Individual Plant Total Energy Increase in PLANT NPV ($M) EIRR (%) 1995-2020 (GWh) Kiev PSP 0.2 10.7 362 Kiev HPS 5.1 12.6 2,891 Kanev HPS 1.5 30.5 199 Kremenchug HPS 10.1 24.1 1,806 Dniprodzerzhinsk HPS 9.8 24.6 1,782 Dnieper I HPS 14.9 17.1 3,818 Dnieper 11 HPS 1.5 13.0 599 Kakhovka HPS 11.7 18.3 2,729 Total for 9 plants 54.8 17.0 14,186 3.24 Non-quantified Benefits. The above-quantified benefits are regarded as a minimum measure of the true economic benefits conferred by the project. Additional, non-quantified benefits of the hydropower component include: (i) life extension of the plants (thereby deferring replacement); (ii) improved environmental performance as a result of reduction in lubricating-oil leakage from old turbine blade seals and reduced risk of flooding as the monitoring of dams improves; (iii) plant safety improvements resulting from the upgraded instrumentation and control system; and (iv) consumer surplus associated with incremental electricity sales. Non-quantified benefits from the system control component include: (i) increased stability and security of the power system, which reduces unserved energy (due to fewer blackouts and faster restoration of service); (ii) improved frequency control, which extends the lifetime of rotary equipment connected to the network, and enhances the safety of nuclear plants (high trequency fluctuation causes structural damage to rotating equipment, including safety-related equipment, thus potentially compromising operational safety); and (iii) facilitation of Ukraine's future interconnection with the neighboring power pools, opening the possibility for electricity exports. F. Sensitivity Analysis 3.25 Calculations were carried out to analyse the sensitivity of the economic viability (proxied by the EIRR) of the two main components and the entire project to (i) a 10% investment cost overrun (for both components); (ii) a 10% decrease in the economic value of electricity produced (for the hydropower component); (iii) a 10% decrease in the amount of fossil fuels saved (for the system control component); and (iv) all of the above. Additionally, switching values (values at which the NPV is zero and the EIRR is 10%) were calculated for investment costs (for both components), electricity price (for the hydropower component), and fuel savings (for the system control component). The results are presented in Table 3.11. Project economic returns are very robust relative to the indicated variations in key project parameters. The switching value analysis suggests that project costs do not pose a significant risk because both components remain economic even in the face of considerable overruns in investment costs. The hydropower rehabilitation component remains economically viable even at 58% of the assumed economic value of electricity. Due to the high base-case level of economic returns, the system control component retains economic viability even when fuel savings amount to 41 % of the level assumed for the base case.  Financial and Economic Analysis 29 Table 3.11 Sensitivity Analysis Component/Project EIRR (%) l ~~~~Impact Assessedl Impact Assessed Hydropower System Project Total Rehabilitation Control Base Case EIRR 17.0 22.7 18.1 - 10% overrun in investment costs 15.6 20.6 16.6 - 10% of decrease in economic value of electricity 15.1 - 17.1 - 10% decrease in fuel saving - 20.4 17.2 - All of the above 14.2 18.5 15.0 Switching Values (at which NPV = 0 and EIRR = 10%) - Investment cost overrun (%) 76a Job 80' - Decrease in economic value of electricity (%) 42d - Decrease in fuel savings (%) )59 a/ From US$ 101.6 million to US$ 178.8 million b/ From US$ 64.7 million to US$ 135.9 million c/ From US$ 174.4 million to US$ 313.8 million d/ From UScent 3.6/kWh to UScent 1.9/kWh (annual weighted average of peak and off-peak economic value of electricity produced by the hydropower plants, averaged over 1995-2020) e/ From US$ 15.1 million per year to US$ 6.2 million per year, or 0.25 mtoe per year to 0.10 mtoe per year, averaged over 1995-2020 Note: Investment costs include base cost, 15% physical contingency, and 50% of the price contingency for local investment costs.  30 Implementation IV. IMPLEMENTATION A. Institutional Arrangements 4.1 Implementation of the project will be the responsibility of the beneficiaries, i.e., the recently formed joint stock company Dniprohydroenergo and the National Dispatch Center (NDC). The five hydropower plants under Dniprohydroenergo have maintained their role in day-to-day management, however, all commercial functions such as financial management, accounting, contract negotiations, etc. have been moved to the headquarters of the new corporation. In December 1994, Minenergo issued a resolution for the consolidation of the regional dispatch centers under NDC by mid-1995. During negotiations, it was agreed that the transfer of ownership of the regional dispatch centers to NDC would be a condition of loan effectiveness (para. 6.2.d). The consolidation is not expected to result in major changes (traditionally, NDC has been responsible for the operational control of the regional dispatch centers). Although it is expected to remain a 100% state owned enterprise, the role of NDC will change significantly when it becomes the commercial (as well as operational) center of the Ukrainian Power System. As Energomarket, it will purchase pratically all electricity from the generators, and sell it to the local electricity companies responsible for distribution and final sales to the consumers. 4.2 Dniprohydroenergo. In 1989, hydropower plants were taken out of the regional power utilities, organized into six enterprises, and placed under the direct supervision of Minenergo. The six enterprises formed a Hydropower Association. The Association was not a commercial entity, but a forum through which certain activities were coordinated among the hydropower plants. It did not have its own accounts, budget, nor (full time) employees. In early 1995, five out of the six enterprises were combined into Dniprohydroenergo, a joint stock company that is 100% owned by the state. The following five enterprises became part of Dniprohydroenergo (the number of employees in parenthesis): Mid-Dnieper Cascade (1,168), Kremenchug (204), Dniproderzhinsk (323), Dnieper (292) and Kakhovka (120). The Mid-Dnieper Cascade included the Kiev HPS, Kiev PSP and Kanev HPS, the Dnieper enterprise included Dnieper I and Dnieper 1I HPS (the other three enterprises were named after their plants). The sixth enterprise became a separate joint stock company by itself (Dnistrohydroenergo). 4.3 The hydropower plants have very similar organizational structures. The Chief Engineer, Deputy Director for Capital Investments (in some cases only a Senior Engineer for Capital Investments), Deputy Director for Support Services and Production, and the managers of the departments for economic analysis, accounting, and personnel report directly to the Director. The Chief Engineer is in charge of all technical activities related to the operation of the plant, and typically supervises production and dispatch, technical and operational divisions, and turbine, hydroelectrical, and electrical shops. "Support services and production" includes the procurement division, transport and security, and often involve some activities not directly related to the main business operation, but to the provision of social services (e.g., day-care centers) or other production activities (e.g., agricultural production). 4.4 Dniprohydroenergo not only centralized the commercial functions of the individual hydropower enterprises, but also assumed certain new functions. One of them that is of particular importance to the project, investment planning, has previously rested with Minenergo. Although the Ministry retained a strategic planning function, Dniprohydroenergo is in the process of establishing an independent planning capability. The individual hydro plants retained a significant part of their existing organizational structure, at least for some time. However, most of their staff performing functions that are to be carried out at the corporate level (financial management, accounting, procurement, investment planning, etc.) are expected to be moved to the corporate headquarters.  Implementation 31 4.5 Hydropower investment projects in the past have been managed by Minenergo through its Department for Capital Construction, and Ukrhydroproekt, an engineering organization which also belonged to Minenergo's structure. Ukrhydroproekt, with 700 employees, has been in charge of all engineering design work for the previous hydropower projects. It will have a similar role in this project as well, serving as the main local engineering and project management consultant to Dniprohydroenergo and its Project Implementation Unit, as well as to the Project Coordination Unit (see below). 4.6 The National Dispatch Center. NDC has about 430 employees, organized in 12 departments (number of employees in parenthesis): Dispatch (22), Optimization of Energy Regimes (15), Optimization of Network Regimes (20), Relay Protection and Automation (19), Long-Term Planning (8), SCADA and Communications (31), Computing Equipment (50), Economic Analysis (11), Billing and Collection, Government Audit, Maintenance, and Support Services. After the consolidation of the Regional Dispatch Centers under NDC, NDC will take over most of the employees from the existing eight regional power utilities who work at the Regional Dispatch Centers. It is expected that the number of people transferred will be under 100 per region. 4.7 The dispatch and system control component of the project includes the purchase and installation of several types of equipment (turbine governors, data acquisition, communications, computers, software). The existing engineering systems at the dispatch centers were developed and designed in the central institutions of the FSU. Some of them are no longer present in Ukraine, which has led to loss of information and engineering know-how. Although there are local engineering organizations with expertise in most of the equipment categories, there is no organization which could cover the entire range of issues, perform engineering work and provide counsel on integrated systems in power system control. This role will be performed by an international consultant under the technical assistance component of the project. 4.8 Project Coordination. A Project Coordination Unit (PCU), headed by a Project Coordinator appointed by Minenergo, will be in charge of overall project coordination. The PCU, located in Minenergo, will coordinate project preparation activities, technical assistance, scheduling (to the extent that it requires coordination between the hydropower rehabilitation and the system control components), reporting, training, and other aspects of project implementation requiring coordination between the two project implementation units (see para. 4.9). The Project Coordinator will report to Minenergo, and serve as a liaison to the Ministry of Finance and the Bank for project activities. He will establish project communication and documentation procedures, oversee preparation of bid documents, arrange appointment of bid evaluation committees, coordinate bidding and contracting, arrange for audits of project accounts, and organize training in project management, project financial operations and procurement. 4.9 Project Implementation. Two Project Implementation Units (PIU) will be set up with responsibilities to manage implementation of the hydropower rehabilitation (including dam safety) and the system control components. The PIUs will be responsible for managing the engineering aspects of project implementation (preparation of bid-level design specifications, supervision and approval of manufacturers' detailed design, inspection in manufacturers' facilities, construction supervision, quality control, system checkouts and integration in factory and on site, factory and field acceptance tests), as well as scheduling, procurement (including bidding and contracting, in coordination with the PCU), payments and disbursement operations related to the respective project components. The PIU of each company (Dniprohydroenergo and NDC) will manage the respective Special Account. The managers of the PIUs will have the authority to clear payments to suppliers and contractors, after authorization from site managers (see para. 4.10). The PIUs will be integral parts of the implementing agencies and will  32 Implementation consist of staff whose regular responsibilities include the implementation of investment projects. The managers of the PIUs will be appointed by the Dniprohydroenergo and NDC, and will also have the title of Deputy Project Coordinators of the PCU. The Deputy Project Coordinators will report to the Project Coordinator and to the Director of the company that appointed them. During negotiations, it was agreed that the Project Coordinator and the two Deputies would have qualifications acceptable to the Bank (para. 6. L.g). 7he establishment of the PCU and PIUs, and the appointment of the Project Coordinator and Deputy Project Coordinators would be a condition of loan effectiveness (para. 6.2. e). 4.10 Site managers will be appointed at each site where project subcomponents are to be implemented. The site managers, appointed by the managers of the respective facilities, will serve as liaisons between management of the facilities and the corresponding PIUs. They will participate in monthly review meetings with the PIUs, attended by concerned project staff, to review progress, address implementation issues and authorize payments to suppliers and contractors. Site implementation will be handled within the existing organizational structure of the concerned facilities. 4.11 Installation of equipment will be the responsibility of the respective facilities (hydro plants, dispatch centers, thermal plants and substations), which will use their force account and specialized local construction and installation companies, under the guidance of the supplier (to be included in the tender documents), with additional assistance from the international consultants providing TA for project implementation. The supplier will supervise the erection and provide the necessary training, and will assume responsibility for the performance of the equipment. There is sufficient local capability to perform the installation. Hydroelectromontazh, with 500 employees, which specializes in erection and installation of electrical equipment, has been the main contractor for this type of work to all Ukrainian hydroplants. Another company, Spetshydroenergomontazh, with 800 employees, specializes in installation of turbines and generators. Both companies have gained international experience through a number of projects in non-FSU countries. Equipment installed at the Dniester hydropower plant, the thermal power plants and substations will be owned by the National Dispatch Center and leased to the plants and the transmission company. The installation and maintenance of the equipment will be the responsibility of the thermal plants and the tramsmission company. 4.12 Technical assistance (TA) activities for the project have been subdivided into the following components: (i) engineering design; (ii) procurement; (iii) project management; and (iv) water management study. International consultants will be hired to assist local consultants and the Project Management and Implementation Units with all TA components. The TA activities will be coordinated by the PCU, which will sign and manage TA contracts both with intemational and local consultants. The first three TA activities (engineering design, procurement, and project management) have started in January 1995, and for the first year (1995) will be financed by the Canadian Government and performed by a Canadian consortium. During this year, emphasis will be on assisting Dniprohydroenergo and NDC in preparation of tender documents (including engineering design specifications), bid evaluation, contract negotiations, and with other procurement issues. The activities of the consultants during this stage will also include assistance in organizing the project management and implementation units, project administration, planning and scheduling. A substantial involvement of international consultants will be needed also during the second year of project implementation (1996), in advising the two companies, PCU and PlUs in various aspects of project management, administration and implementation (planning, scheduling, engineering, construction management, inspection, testing, commissioning, project documentation, reporting, cost accounting). International consultants will be needed throughout the entire project implementation period, although their involvement is expected to be much reduced after the second year. In case grant financing for TA activities after 1995 could not be secured, the foreign component of TA would be financed from the Bank loan, and consultants chosen according to the Bank's  Implementation 33 Guidelines for Use of Consultants by World Bank Borrowers and by the World Bank as Executing Agency (August 198 1). 4.13 The international consultants will work in conjunction with domestic consultants and the staff of the companies assigned to the project. The international consultant providing TA for project implementation will assign an Assistant Project Coordinator, reporting to the Project Coordinator, on a full-time basis. The international consultant providing TA for procurement activities will assign a Procurement Advisor, who is expected to be engaged full-time until the signing of the main contracts, and will work on demand thereafter (about one third of the time). TA in project management, supervision and quality control will be provided throughout the project. Training sessions in procurement, project management, financial management and quality control for project management and implementation staff at PCU, PIUs and elsewhere (as needed) will be organized by international consultants, in cooperation with the Project Coordinator, during the initial stages of project preparation and implementation. 4.14 The technical assistance related to the management of the reservoirs on the Dnieper river will be financed entirely by the Norwegian Government. This activity is expected to start by the end of 1995 and be completed in a two-year period. It will also involve both international and local consultants, in which the international consultant(s) will take the lead. The recepient of this assistance will be Dniprohydroenergo. 4.15 The technical assistance program (see Section I.E) supporting the implementation of Decree 244/94 includes a number of institution building activities targeted at the beneficiaries of the project. Dniprohydroenergo is receiving support for corporatization and development of organizational structure, internal reporting, financial management, budgeting and planning. The establishment of Energomarket on the basis of NDC is also supported, including the preparation of Energomarket Members Agreement, bidding procedures, price formation software, dispatcher's manual and software, and settlement procedures. Consultants are providing assistance for the preparation of contracts between Energomarket and the nuclear and hydropower plants. A detailed study is scheduled to start in April that will assess the metering and commnunications requirements for the operation of the "pool". These technical assistance activities are financed by grants provided by the United Kingdom, United States, Netherlands, Switzerland, and other donors. B. Implementation Schedule 4.16 According to the Implementation Plan (see Annexes 9-13), the project will be implemented over a period of 5 years and is expected to be completed by June 30, 2000. The rehabilitation of turbines is on the critical path of the implementation of the hydropower rehabilitation component. Installation of switchyard equipment, control and monitoring equipment and dam safety systems, as well as system control and monitoring components, is expected to proceed without difficulties since it involves work at existing sites. Consulting services under the technical assistance component have started in January 1995, so that project implementation can proceed expeditiously after the loan approval. A detailed implementation schedule is presented in Annex 9. C. Procurement 4.17 The procurement for the project will consist of 11 packages for equipment and goods, ranging from US$0.8 million to US$32.1 million with total aggregate value of US$91.4 million, and 2 packages for technical assistance activities, estimated at US$0.3 million and US$1.5 million, respectively.  34 Implementation A list of procurement packages is provided in Annex 10. All equipment and goods financed from the Bank Loan will be procured according to the Bank's Guidelines for Procurement under IBRD Loan and IDA Credits (1992). Contracts for equipment and goods estimated to cost more than US$300,000 will be procured through International Competitive Bidding (ICB) using Bank's Standard Bidding Documents. Domestic manufacturers competing under ICB will be eligible for a 15% preference, or the prevailing custom duty applicable to non-exempt importers (whichever is less) in bid evaluation, provided that they can prove that value added to the product in Ukraine equals to at least 20% of the ex-factory price of the bid. The preference shall be applied in accordance with the provisions contained in Appendix 2 of the Guidelines. Small contracts for goods, US$300,000 equivalent or below, with an aggregate limit of US$1.5 million, may be procured through international shopping, after obtaining a minimum of three price quotations from at least three eligible countries. Direct contracting up to an aggregate amount of US$1.0 million may also be allowed, if the procedure is justified (e.g., for items of proprietary nature or items required to ensure compatibility with the already installed equipment, for spare parts available only from the original supplier, etc.). Total amount of goods purchased through international shopping and direct contracting will not exceed US$2.5 million (less than 3% of the Bank Loan available for equipment and goods). List of goods to be purchased under these two procedures will be subject to prior review by the Bank. Consultants, to be employed under the technical assistance component of the loan if bilateral funds are not available, will be selected according to the Bank's Guidelines for Use of Consultants by World Bank Borrowers and by the World Bank as Executing Agency (August 1981). Project elements, their estimated cost, and proposed methods of procurement are summarized in Table 4.1. 4.18 Project implementing agencies in Ukraine have very limited knowledge of international commercial practices and the Bank's procurement procedures. Procurement teams will be established within the Project Implementation Units, and will receive training during the early stages of project implementation, both from the Bank and from the consultants engaged under the technical assistance component. To ensure compliance with the Bank guidelines, the following documents will be subject to prior review by the Bank: draft tender documents, bid evaluation reports and recommendations for awards of contracts, for all ICB procurement (US$300,000 and above) and all Bank-financed contracts awarded under direct contracting/negotiation (covering about 98% of the total value of Bank-financed equipment and goods); list of goods to be purchased through international shopping financed by the Bank; terms of reference for all consulting contracts; all consulting contracts financed by the Bank above US$100,000 for firms, and above US$50,000 for individual consultants. All other contracts will be subject to ex-post review. 4.19 The rehabilitation of turbines, stator and rotor windings and magnetic stator core for generators are expected to be financed from local sources and procured by direct contracting with domestic suppliers, Turboatom and Elektrotyazhmash. The Turboatom factory, producing turbines, has about 10,000 employees, of which 2,500 have university degree. It has delivered turbines to more than 160 plants in 26 countries. The generator factory, Elektrotyazhmash has about 8,600 employees, of which 2,140 are engineers. It has a long list of reference plants in more than 30 countries. The contracts will contain sufficient guarantees for timely delivery of the contracted equipment and services, performance, provisions for inspections and tests, pricing and warranties. The equipment under these contracts, although not financed by the Bank, is critical for the overall project implementation and operational performance. It was agreed during negotiations that Dniprohydroenergo would sign suitable contracts, satisfactory to the Bank, with the turbine and generator manufacturers by November 30, 1995 (para. 6.1.h).  Implementation 35 Table 4.1 Procurement Arrangements Procurement Method" | 1 Total Project Element ICB Other ||NBF t2 j Cost 1 Equipment and Goods 91.4 2.5 /3 64.2 158.1 (91.4) (2.5) (93.9) 2 Works /4 26.8 26.8 3 Consulting Services 1.8 '5 3.5 5.3 ___________________________ ______________ (1.8) ______ (1.8) Total 91.4 4.3 94.5 190.2 (91.4) (4.3) . (95.7) 1/ Figures in parentheses are the amounts to be financed by the Bank loan. In addition, the Bank loan would finance interest during construction of US$ 18.3 million equivalent. 2/ Not Bank Financed. 3/ To be procured through International Shopping (up to an aggregate amount of US$1.5 million) and Direct Contracting (up to an aggregate amount of US$1.0 million). 4/ Installation to be accomplished by Force Account and local companies, with training and supervision provided by the supplier, who would also assume responsibility for the performance of the equipment. 5/ Procurement under Bank's Guidelines for Use of Consultants by World Bank Borrowers and by the World Bank as Executing Agency (August 1981). 4.20 A General Procurement Notice was published in the Development Business Forum on Nov. 16, 1994, allowing for more than the required 60 days prior to the issue of the bidding documents. The General Procurement Notice will be updated and published annually. At least 45 days prior to the issuance of bidding documents, individual bidding opportunities will be advertised in a major local newspaper. The project agencies would also be expected to advise known eligible and qualified traditional suppliers. 4.21 Procurement information will be collected by the PCU and reported to the Bank as follows: (a) prompt reporting of contract award information; (b) semiannual and annual reports that include (see also para. 4.29): * revised cost estimates for individual contracts and the total project, including best estimates of allowances for physical and price contingency; * revised timing of procurement actions, including advertising, bidding, contract award, and completion time for individual contracts; and * compliance with aggregate limits on specified methods of procurement.  36 Implementation 4.22 The Government is expected to prepare legislation instituting public procurement rules and regulations as part of the program to transform the economy from a centrally planned to a narket- oriented system based on the development of a competitive private sector. The Country Procurement Assessment Report is expected to be prepared after legislation has been enacted and placed in effect. D. Disbursement 4.23 The proceeds of the loan will be disbursed over five and a half years (1995-2000) on the following basis: (a) 100% of the foreign costs of imported equipment and goods; (b) 100% of local ex-factory costs of supply of equipment and goods and 80% of local expenditures for other items procured locally; and (c) 100% of expenditures for consultancy services. 4.24 Table 4.2 shows the estimated disbursement profile for the project, as derived from the implementation plan of the project components (Annexes 5 and 9); a more detailed disbursement schedule is presented in Annlex I 1. The disbursement profile follows broadly the standard disbursement profile for energy projects in the Europe and Central Asia Region. The Closing Date for the proposed loan would be December 31, 2000. Table 4.2 Disbursement Schedule l_____________ 19961 IBRD Fiscal Year. __ 19961 19971 19981 19991 2 ____00 Annual (%) 12% 18% 27% 26% 13% 3% (US$ million) 14.2 20.6 30.8 29.7 15.4 3.3 Cumulative (%) 12% 31% 58% 84% 97% 100% (US$ million) 14.2 34.8 65.6 95.3 110.7 114 4.25 Disbursement for goods under contracts not exceeding US$300,000 equivalent, consulting firms under contracts not exceeding US$ 100,000 equivalent, and individual consultants not exceeding US$ 50,000 equivalent would be made against statement of expenditures (SOE) in order to assist the borrower in making timely payments. The supporting documentation for these contracts would not be sent to the Bank, but would be retained by the borrower for inspection by supervision missions and by external auditors. All other disbursements would be fully documented. The minimum size of applications for direct payments will be US$50,000. 4.26 To facilitate project implementation, the Borrower would establish two Special Accounts (one for the Dniprohydroenergo, the other for NDC) in commercial bank(s) on terms and conditions satisfactory to the Bank to cover the Bank's share of expenditures. The authorized allocation to the Dniprohydroenergo's Special Account would be US$2.0 million, and to the NDC's Special Account US$2.0 million, representing about four months of average expenditures effected through the Special Accounts. At the request of the Borrower and, based on project needs, the Bank would make initial deposits into the Special Accounts up to the amount of the authorized allocation. Applications for the  Implementation 37 replenishment of the Special Accounts would be submitted monthly or when one-third of the amount has been withdrawn, whichever occurs earlier. Documentation requirements for replenishment would follow the usual Bank procedures. In addition, monthly bank statements of the Special Accounts which have been reconciled by the Borrower would accompany all replenishment applications. During negotiations, agreement was reached on the arrangements for establishmett, operation and auditing of the Special Accounts (para. 6.1.i). E. Accounts and Audits 4.27 Ukraine's electricity enterprises follow standard Soviet accounting procedures, which have been augmented as required by the administrative reporting requirements of the many government bodies to which they report. The financial accounting standard now in use is not adequate for providing reliable management and regulatory reports. Revenues are reported on a cash basis, when received, and costs associated with producing revenue are not booked until such time as revenues arrive. When accounts receivable are not being collected, a substantial portion of costs are held off the books, misstating inconme. A related problem is that neither of the beneficiaries is equipped to track its receivables and payables on a dated basis, and thus there is no basis for calculating and recognizing inflationary losses. At present, there is no recognition of uncollectible debt. In addition to maintaining the statutory accounts required by Ukrainian law, the beneficiaries will maintain a parallel system of financial statements (income statements, sources and uses of funds, and balance sheets) that meet international accounting standards (IAS). The IAS accounts will supply data inputs suitable for use in tariff calculations and regulatory reporting that will be required by the National Energy Regulatory Commission. They also will serve as the basis for calculating interest penalties to be provided for under their new contracts, and for monitoring progress in improving the timeliness of payments and collections. Financial statemnents will be audited by an auditor acceptable to the Bank and the audit reports submitted to the Bank within six tmonths of the end of each financial year (para. 6.1.j). 4.28 The accounting for all Special Account transactions and for all other project-related accounts will be maintained in accordance with international accounting standards. Annual financial statements of IBRD-financed components will be prepared and audited in accordance with International Auditing Guidelines by suitably qualified independent auditors acceptable to IBRD, and submitted to IBRD within six months of the close of the GOU fiscal year. Audits will also be carried out, at the same time, and for corresponding periods in accordance with the Bank guidelines, for SOEs against which disbursements have been made or are due to be made out of the credit proceeds, and specific reference to the Special Account (SA) and SOEs will be made in the audit reports accompanying the financial statements. During negotiations, agreement was reached that the implementing agencies would submit to the Bank the audit reports and auditedfinancial statements for the Special Account, project accounts and SOEs for the every fiscal year, not later than six months after the close of such year. Agreement was also reached that auditors acceptable to the Bank would be retained to review the accounting systems and supporting internal procedures and practices for the Special and project Accounts and SOEs, and recommend any needed changes (para. 6.1. i). F. Monitoring and Evaluation 4.29 The Project Coordination Unit will prepare semiannual and annual project progress reports. The progress reports, following clearance by the Borrower, will be submitted to the Bank. The progress reports will include, but not necessarily be limited to, project physical progress, procurement, disbursements, project costs, schedule, plan for next reporting period, the work of consultants, and project administrative aspects. The progress reports will be sent to the Bank within four weeks after  38 Implementation conclusion of the reporting period. The first progress report will be sent three months after loan effectiveness. 4.30 The Borrower will submit a mid-term progress report, covering all components of the project, no later than June 30, 1997. In addition to the topics covered by the semiannual reports, the mid-term report will include an assessment of the status of loan covenants, overall institutional performance of the companies-beneficiaries, and evaluation of the project based on a set of performance indicators (Annex 12). This report will be reviewed with the Bank by no later than September 30, 1997, and, based on the recommendations of the report and the Bank's views on the matter, measures will be taken to ensure the efficient completion of the project. The timing of the mid-term review and the performance indicators were agreed at negotiations (paras. 6.1.k, 6.1.1). 4.31 A project implementation completion report (ICR) will be submitted to the Bank promptly after the completion of the project, but no later than 6 months after the Loan Closing Date. The ICR will discuss execution of the project, its costs and benefits, the performance of the borrower, the World Bank and other agencies involved, and lessons learned. The ICR will also contain evaluation of the project performance indicators. 4.32 In addition to the review of procurement actions, semi-annual reports and other documentation, a number of supervision missions is planned. The project is expected to require supervision from the Bank at an average of 25 staff-weeks per year during the first two years of implementation, and 15 staff-weeks per year thereafter (Annex 13). G. Operation 4.33 Following project completion, the life of the hydropower plants will be extended by about 20 years. The operation of the rehabilitated plants is not expected to pose a technical challenge for the well-educated, experienced staff working at the plants. The hydropower plants will continue to be the lowest cost electricity generators in Ukraine, ensuring the long term financial viability of Dniprohydroenergo. NDC, as the future Energomarket, will play a key role not only technically, but also financially in the reformed power industry. NDC will operate the wholesale (spot) market for (practically) all electricity generated in Ukraine, and recover its costs by adding a margin ("uplift") to the price of electricity it sells to local electricity distributors/suppliers. The facilities installed by the project will be essential for the successful functioning of the wholesale market, including daily bidding, dispatching, metering, verification, and settlements. Under the project, technical training will be provided to NDC staff in the operation and maintenance of the modernized communications, system control and dispatch facilities. A large donor funded institutional building effort that has been mobilized in support of the power industry reform will provide the necessary training for NDC's commercial functions. Suppliers will provide training the necessary training for the maintenance of the equipment they supply and guarantee delivery of spare parts, both for Dniprohydroenergo and NDC. The operation plans of Dniprohydroenergo and NDC were agreed at negotiations (para. 6.1. m).  Project Risks and Benefits 39 V. PROJECT RISKS AND BENEFITS 5.1 Project Risks. The main risks for the project is the possibility that the Government would be unwilling to (i) adhere to the agreed pricing formula for the electricity produced by the hydropower plants; and (ii) implement a strict regulatory policy to prevent the further accumulation of payment arrears. These could seriously undermine the financial position of the Dniprohydroenergo and NDC, and thereby endanger the implementation of the project. The reform of the power industry based on Decree 244/94 is expected to decrease these risks, but cannot eliminate them. The implementation of the reform itself is subject to political risks. Risks arising from the pricing of electricity have been addressed under the project by requiring the adoption of a tariff formula that includes all operating costs, recovers investment costs, and allows for regular adjustment to reflect inflation. Risks arising from non- payment by NDC's customers (i.e., local electricity companies and large industrial plants) have been addressed by requiring appropriate contractual arrangements, including the reduction/termination of service in the case of non-payment. The beneficiaries' inexperience in implementation of Bank projects poses additional risks. Inferior performance of domestic equipment and domestic supply constraints could also delay project execution and affect the quality of work. These risks have been addressed through the careful planning of activities that are on the critical path, and by providing technical assistance to the PIUs in procurement, supervision and quality control. Economic returns are very robust relative to variations in key project parameters. A switching value analysis suggests that project costs do not pose a significant risk because both major components remain economic even in the face of considerable overruns in investment costs. The hydropower rehabilitation component remains economically viable even at half of the assumed economic value of electricity. The system control component retains economic viability even when fuel savings amount to one-third of the level assumed for the base case. 5.2 Benefits. The main benefits are improvements in the efficiency and availability of hydropower plants, and the increased efficiency in the loading of hydro- and thermal power generation units. Additional benefits are: (i) the increased security of the power system that will lead to fewer blackouts; (ii) the improved stability of frequency that will enhance nuclear safety; (iii) the better environmental performance of the hydropower plants that will reduce the pollution of rivers; and (iv) the improved monitoring of dams and reservoirs that will reduce the risk of dam breaks.  40 Summary of Recommendations and Loan Conditions VI. SUMMARY OF RECOMMENDATIONS AND LOAN CONDITIONS 6.1 Agreements Reached During Negotiations. At negotiations, agreements were reached on the following: (a) On-lending arrangements between GoU and Dniprohydroenergo, and GoU and NDC, including on-lending interest rate and repayment method (para. 2.17); (b) Contract between NDC and Dniprohydroenergo, including the tariff formula ensuring the full recovery of investment and operating costs (para. 3.13); (c) Contract between NDC and its downstream customers, including the application of interest penalty and reductions in deliveries in the case of non-payment (para. 3.15); (d) Reduction of NDC's delay in paying its suppliers to 45 days in 1995, 30 days in 1996, and 20 days thereafter, and reduction of NDC's accounts receivable to 60 days in 1995, 40 days in 1996, 35 days in 1997, and 30 days thereafter (para. 3.16); (e) Price setting mechanism for NDC that allows it to recover an allowance for bad debt in its resale tariff (para. 3.17); (f) Commitment of Dniprohydroenergo and NDC to generate for every financial year (beginning in 1996) sufficient internal funds to cover not less than 40% of the annual average capital expenditures expected (or actually incurred) for that financial year, the previous financial year, and the next financial year; and to maintain a debt service coverage ratio of at least 1.5 during the project period (para. 3.18); (g) Qualifications for Project Coordinator and Deputy Project Coordinators (para. 4.9); (h) Signing of suitable contracts between Dniprohydroenergo and the turbine and generator manufacturers by November 30, 1995 (para. 4.19); (i) Arrangements for establishing, operating and auditing the Special Accounts for the project (paras. 4.26 and 4.28); (j) Auditing requirements of the accounts of Dniprohydroenergo and NDC (para. 4.27); (k) Set of Project Performance Indicators (para. 4.30); (l) Preparation and submission of mid-term report on project implementation no later than June 30, 1997, and a review with the Bank of this report by not later than September 30, 1997 (para. 4.30); and (m) Operation Plans of Dniprohydroenergo and NDC (para. 4.33).  Summary of Recommnendations and Loan Conditions 41 6.2 Conditions for Effectiveness. These would include: (a) Execution of the Subsidiary Loan Agreements between GoU and Dniprohydroenergo, and GoU and NDC (para. 2.17); (b) Signing of the power purchase contract between NDC and Dniprohydroenergo (para. 3.13); (c) Resolution of NDC's arrears for previous hydropower purchases (para. 3.14); (d) Transfer of ownership of the regional dispatch centers to NDC (para. 4.1); and (e) Establishment of PCU and PIUs, and appointment of Project Coordinator and Deputy Project Coordinators (para. 4.9). 6.3 Recommendation. Subject to the above, the Project is suitable for a Bank Loan of US$ 114.0 million equivalent at the standard variable interest rate with a maturity of 17 years including 5 years grace. The Borrower would be Ukraine and the implementation agencies would be Dniprohydroenergo and the National Dispatch Center.   ANNEX 1 Page 1 UKRAINE HYDROPOWER REHABILTIATION AND SYSTEM CONTROL PROJECT ELECTRICITY DEMAND FORECAST 1. Due to the large uncertainty surrounding the course of future economic changes in Ukraine, alternative electricity demand projections were prepared by the Bank. Scenario A assumes a comprehensive and radical reform process, including raising electricity tariffs to economic levels in the near future and the strict enforcement of hard budget constraints for enterprises. By contrast, Scenario B reflects very slow-paced reforms and restructuring, meaning that the completion of price adjustment is much deferred and enterprise budget constraints remain soft. Importantly, the pressure on enterprises to restructure towards a less electricity-intensive product mix and to use electricity more efficiently is much weaker in Scenario B than in Scenario A. Scenario C tracks a middle course between these two extreme outcomes by portraying a gradual, steady progress towards a market-based economy. 2. Macroeconomic performance. In Scenario A, GDP recovers from the current slump in 1996, and the economy is set to grow at relatively high rates (an average 5.5% per year over the 1996- 2010 period). In Scenario B, GDP continues to contract longer, the recovery is weak and the post- recovery (1998-2010) growth rate, at about 3.5%, is lower. Scenario C is an intermediate case, with an average growth rate of 4.5% per year in the post-recovery period of 1997-2010. 3. Structural shifts in total output. Ukrainian enterprises must make changes in their product mix under any reform scenario. These shifts are assumed to benefit the less electricity-intensive consumer industries, high technology manufacturing and services at the expense of the presently oversized heavy industries. The structural transformation proceeds at various speeds in the three scenarios, the fastest being in Scenario A and the slowest in Scenario B. 4. Electricity price adjustment. In Scenario A, industrial electricity tariffs rise to the economic level by the end of 1995, and the presently cross-subsidized tariffs (for households, communal services, agriculture, etc.) reach the industrial level by the end of 1997. The shift to economic cost levels happens more gradually in the other scenarios. 5. Price responsiveness. Consumer sensitivity to changes in electricity prices corresponds to that of a reformed semi-market economy proxied by Hungary. Under Scenario A, the assumed short- and long-run elasticities are -0.08 and -0.16, respectively. In Scenarios B and C, which reflect a weaker sensitivity to costs, price elasticity is set at half of the above values. 6. Methodology. For the purpose of the quantitative projection, a dynamic consumption model was used (described in detail in the Ukraine Energy Sector Review, Report No. 11646-UA) 7. Projections. The forecasts to the year 2010 are shown in Table 1 and Figure I (the figures refer to gross consumption, i.e., they include station use and network losses; in recent years gross consumption exceeded final, or net, consumption by about 20%). The recently experienced decline in  ANNEX 1 Page 2 gross consumption (27% in the past four years) is projected to continue in the near future in all cases. In Scenario A (High Case), the early economic recovery offsets a large part of the severe price shock imposed on the industrial users, resulting in a relatively small decrease in consumption until 1997. During the period 1998-2010, demand recovers at a rate of 3.4% per year, reaching the pre-crisis (1990) reference level only towards the end of the forecast period. In Scenario B (Low Case), demand levels out in 2000 at 64% of the reference level, followed by a slow recovery thereafter. Under Scenario C (Medium Case), after bottoming out in 1997-98, demand growth resumes at 3% per year, but the 1990 consumption level is not reached even in 2010. Projection of Electricity Consumption to 2010 (TWh) 300 __ 280- 260 L_ __ 240 . _. 220 __ e C 200 __T 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 High Demand IV Medium Demand *Low Demand Note: Gross consumption includes station use and network losses. Actual data for 1990-94.  ANNEX 1 Page 3 8. Official Ukrainian demand forecast. The latest (May 1994) forecast prepared by Minenergo and approved by the Government, predicts the future course of gross electricity consumption under two alternatives. The low forecast differs from the high one on the assumption of efficiency gains derived from the adoption of vigorous electricity conservation measures (in TWh): 1993 1995 2000 2005 2010 l _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ (A ct) Low forecast (enhanced 227.2 226.0 243.0 248.0 260.0 conservation) High forecast 227.2 228.1 256.0 278.0 295.0 The difference between the official and Bank forecasts is sizeable, although it narrows towards the end of the projection horizon. The discrepancy is especially large for the medium term, largely because the official forecast does not assume any drop in power usage for 1994 (the Bank projects a 14% decline) and for the subsequent years. For 2005 and 2010, the Bank's High and Medium forecasts are comparable with the conservation-centric official forecasts.  ANNEX 2 Page 1 UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT NUCLEAR SAFETY 1. Nuclear power in Ukraine currently provides almost 40% of electricity generation and represents 26% of installed capacity. The 14 Soviet-designed operating units include 10 pressurised water reactors of the VVER-1000 type, two older 440 MW units of the VVER 213 type, and two graphite water reactors of RBMK-1000 type at Chernobyl. Four more VVER-1000 reactors are in an advanced stage of construction at the Zaporozhye, Rovno, Khmelnitsky and South-Ukraine plants. 2. The safety of nuclear reactors in Ukraine has been a major concern for the international community. Especially serious doubts remain amongst international nuclear safety experts about the safety of the RBMK reactors at Chernobyl (which account for 5% of total electricity generation). Chernobyl Unit 4 was destroyed in April 1986 and is enclosed in a deteriorating concrete shelter (sarcophagus). Unit 2 has been shut down since the October 1991 fire in its turbine-generator block. A safety review conducted by the International Atomic Energy Agency in March 1994 found numerous safety deficiencies in the two units which remain operational. Of particular concern are specific problems in the design of the first generation Unit 1. These deficiencies include an insufficient emergency reactor cooling system and vulnerability to serious failures, particularly from fires, as a result of poor diversity and separation of electrical cables and equipment in the reactor control and protection systems. Unit 3 is a second generation RBMK reactor having significant safety improvements. However, it is in an increased radiation environment emanating from the neighboring destroyed Unit 4. Although planned, there is currently lack of safety-upgrading activities at Chernobyl. Only limited safety-enhancing measures were undertaken due to the original 1991 decision to terminate operations by the end of 1993. In addition to these shortcomings at Chernobyl, most of Ukraine's nuclear plants suffer from inadequate instrumentation and control and weaknesses in management and training. In 1994, the lack of financing severely constrained the ability of Goskomatom (the nuclear operator) to carry out maintenance and to undertake work to improve safety, including the procurement of up-to-date equipment and spare parts. The loss of highly skilled personnel who moved to Russia because of higher compensation also had a negative effect on safety. The price of electricity sold by the nuclear plants was substantially increased in early 1995, alleviating somewhat the financing constraints. 3. In response to mounting domestic and international safety concerns following the fire in Unit 2, Parliament mandated that the Chernobyl plant should be closed by the end of 1993 and imposed a moratorium on the completion of new nuclear units under construction. In November 1993, as a consequence of the deterioration in the country's energy supply, Parliament revoked the order and allowed continued operation as long as "technically feasible". Also, in February 1994 a presidential decree was issued approving the recommissioning of Unit 2 in 1995. According to current plans, Goskomatom will decommission Chernobyl Units 1-3 when their reactor channels are exhausted, i.e, in the 1997-2005 period. The Government's plan also includes the completion of Zaporozhye 6, Khmelnitsky 2 and Rovno 4 in 1995-1999 (the completion of South Ukraine 4 is hampered by the lack of cooling water). The implementation of a program of measures to upgrade the safety of all operating nuclear units is scheduled to start in 1995-96. And, as a matter of urgency, the construction of a new,  ANNEX 2 Page 2 structurally safe sarchophagus is planned for the destroyed Unit 4 at Chemobyl. 4. The Ukrainian authorities indicated that they were prepared to consider and discuss possible early closure of the Chernobyl plant, provided that a satisfactory solution was identified, in particular, for financing replacement nuclear capacity, closure costs, including the mitigation of the social costs of closure. In the dialogue with the G-7 Nuclear Safety Working Group, Ukraine suggested that an international task force be formed from Ukrainian and foreign experts, including representatives of the relevant international financial institutions, with the task of preparing a comprehensive nuclear safety Action Plan in the context of a power sector development strategy. 5. The G-7 Sunmmit Meeting, held at Naples in July 1994, called for the closure of the Chernobyl plant as an "urgent priority". The meeting outlined a broad sectoral Action Plan for the closure of Chernobyl, including the early completion of three nuclear reactors (Zaporozhye 6, Rovno 4 and Khmelnitsky 2) to adequate safety standards, comprehensive energy sector reformns, rehabilitation of conventional power plants, increased energy conservation, and the use of alternative energy sources. The G-7 offered to provide an "initial" amount of US$200 million in grants, in addition to the contribution offered by the European Union (US$120 million in TACIS grants and US$480 million in long-term loans from EURATOM). Support from the international financial institutions and other donors was also called for. 7. The dialogue between the Ukrainian authorities and the G-7 continues, notwithstanding initial Ukrainian reservations about the inadequacy of the financial package offered at Naples. The joint international task force was formed in December 1994 with a mandate to develop a detailed, comprehensive Action Plan for nuclear safety, and its work is underway.  ANNEX 3 Page 1 UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT LEAST COST POWER INVESTMENT PROGRAM A. Methodology 1. A least-cost analysis of the Ukrainian power system (UPS) expansion alternatives for the period 1995-2010 has been performed to assess future investment requirements of the system, and the type and timing of new capacity additions needed. The main objective of the analysis was to investigate the need for peaking units in the system, in order to assess the relative importance of the hydropower capacity as the only peaking capacity present in the existing capacity mix. The analysis was carried out using the WASP computer program'. The general methodology imbedded in WASP is focussed on finding the least cost power system expansion plan that matches projected electricity demand while maintaining the reliability of the system operation at a prescribed level. The model takes into account both maintenance requirements and the operational reliability of generating units. The system costs include investment costs, financing costs during construction, fuel costs, operation and maintenance costs, and costs of energy not served. B. Description of the Existing System 2. The installed electricity generation capacity of the UPS was 52,122 MW in 1993. It included 12,818 MW of nuclear capacity, located in 5 plants with a total Figure 1.1 Capacity Mix of 14 units in operation. There were more than 40 thermal (fossil fuel) power 4 > plants with conventional steam cycle technology, with over 110 generating X ch_ l units and a total capacity of 32,364 MW, FN of which 3,824 MW were combined heat- and-power units. Hydro capacity was . U3I.dbi 4,700 MW, stationed mostly in 9 plants a with a total of 100 generating units. The capacity of industrial power plants was about 2,240 MW. The total effective generating capacity of the system was about 50,000 MW, due to the derating of older plants. Most older fossil fuel plants (about 23,000 MW) used coal as their primary fuel, but needed gas or mazut for co- 1/ A PC version of WASP-III, implemented as the ELECTRIC module of the ENPEP package was used (ENPEP - ENergy and Power Evaluation Program, developed by Argonne National Laboratory, Argonne, Illinois; WASP - Wien Automatic System Planning Package of the International Atomic Energy Agency, Vienna, Austria).  ANNEX 3 Page 2 firing. About 5,520 MW of power generation as well as most of the combined heat-and-power plants run on gas or mazut as main fuels. Figure III.1 shows the capacity mix of the existing system. 3. Electricity generation in 1993 was 228,316 GWh, of which thermal plants produced 135,875 GWh, nuclear plants Figure m.2: Electricity Generathon (1993) 75,242 GWh, hydropower plants 11,214 3% 5s GWh (including 200 GWh by a pump storage plant), and industrial plants 5,985 -. l l El 5 Ndww GWh (Fig. 111.2). Net export was 1,145 GWh (2708 GWh exports, 1,563 GWh imports). Self-consumption of thermal lInduirtal and hydro plants was 10,648 GWh, and *0% Il3a H*of nuclear plants 5,228 GWh. After 60% accounting for other production needs (615 GWh), consumption of the pump storage plant (302 GWh), and transmission and distribution losses (22,473 GWh), final electricity consumption came to 187,905 GWh. The peak demand in 1993 occurred in January, at 37,000 MW: the minimum demand, in June, was about 17,000 MW. Heat production was about 48 million Gcal. Total fuel consumption for electricity and heat production was 53 million tons of coal equivalent (tce, defined as 7000 Kcal/kg), consisting of 19.4 million tce of natural gas, 7.3 million tce of mazut, and 26.3 million tce of coal (Figure III.3). 4. Electricity generation, domestic consumption and exports have declined significantly in recent years. Between 1990 and 1993, generation decreased by about 23 %, domestic consumption by 15 %, and net exports by 96% (the decline is likely to continue for some time -- see Annex 1). GDP, however, declined even more (37% in the same period), and the electricity intensity of GDP increased from about 1.95 kWh/US$ in 1990 (about 3.4 times the OECD) to 2.32 kWh/US$ in 1993. C. Main Assumptions 5. The main assumptions of the analysis concern system demand, unit retirement schedule, commitments to rehabilitation of existing and addition of new units, fuel mix, electricity imports, composition and characteristics of new generating units proposed for the system expansion, and various cost components and parameters. 6. Electricity Demand. Electricity demand scenarios were prepared by the World Bank (see Annex 1). To reflect the declining share of industrial consumption of electricity, the yearly load factors2 are assumed to decline gradually from the present level of about 0.73 to 0.65 by year 2010, remaining at that level through the rest of the planning period. The maximum yearly loads were derived from the energy projections (Annex 1) and the load factors assumption. In addition to satisfying the peak loads, the system has to have 15% reserve in capacity (the standard planning requirement for the UPS). Exports 2/ The load factor for a given period is defined as ratio of average load versus peak load in that period.  ANNEX 3 Page 3 were not considered in the simulations performed3. 7. The system load is modeled by four load duration curves4: winter, spring, summer and fall. For illustration, Figure 111.4 shows daily load profiles for winter and summer working days and Sundays for the period July 1, 1992 - June 30, 1993. Figure III.5 exhibits yearly maximum and minimum monthly loads for the same period. 8. Firm Commitments5. The only unit assumed to be firmly committed was a 225 MW unit at Dobrotvorsk, currently under construction, and the nuclear units, as described in para. 10 below. 9. Retirement Schedule. The following retirement schedule was provided by Minenergo. (Note: lxlOO in 1996 means that 1 unit of 100 MW is retired in year 1996.) Slaviansk lx720 in 1996, 1x80 in 1998 ng.,, 11. Fomul Fag Mix (193) Dobrotvorsk lx100 in 1996, 14Si lxlOO in 1997, lxlOO in 1998 :. Kharkhiv 1xS0 in 1996, . ..01 * a1 lxlWOO in 1997 Mironov lx 1O0 in 1998 Starobeshevo 1x 175 in 2002 Net exports of electricity declined dramatically in the last four years, from 27,970 GWh in 1990 (9.4% of total generation) to 1146 GWh in 1993 (0.5% of total generation). Demand is falling in most of the traditional Ukrainian electricity export markets. Also, most of the UPS now operates in an island mode. It is, therefore, difficult to project levels of electricity exports for future years. Given the relatively limited objectives of this exercise, exports were not included in the analysis. 4/ A load duration curve for a given time period represents duration of time for which the system load is greater than a given load level. 5f The WASP model handles units commnitted to future additions (these units, together with the existing units comprise what is in WASP terminology termed as "fixed" system) in a different manner than the candidate units, i.e., its investment costs are not part of the objective function being minimized in the optimization process, for obvious reasons (since they are committed, they are not part of the WASP's decision procedure). The term "candidate units" refers to units that are considered as candidates for system expansion.  ANNEX 3 Page 4 10. Nuclear program. For the nuclear program, the following scenario has been adopted: Zaporozhye 6, Khmelnitsky 2, and Rovno 4 completed in 1995-1999, and Chernobyl 3 recommissioned in 1996. It was also assumed that Chernobyl units 1, 2 and 3, with 1000 MW capacity each, would be retired in the 1997-2005 period. One thousand MW of nuclear capacity was assumed to be unavailable throughout the planning period due to safety upgrades of the nuclear plants. 11. Candidate Units. The following units were considered as candidates for the system expansion (the first number in parentheses represents construction costs, with interest during construction included, in US$ million; the second number represents duration of construction, in years): 120 MW single cycle gas turbine (357, 3), 450 MW combined cycle gas turbines (770, 4), 500 MW pulverized coal unit (1500, 5), and 500 MW mazut steam unit (1135, 4). Also, pump storage units of 324 MW in generating and 408 MW in pumping regime, with cycle efficiency of 0.7 and yearly generation of 492 GWh, were considered in order to model the Dniester pump storage plant (PSP) as a candidate. The remaining investment costs for the Dniester PSP, taking into account that about 70% of civil works and 20% of equipment was completed, were estimated at 227$/kW (of generating power), i.e., the cost of total completion was estimated at US$ 514.8 million (in 1994 US$). Figure 111.4: Daily Load Profiles AQ~~~~~~~~l 4000 35000 --_ _. 30000 =__ Thumday, Dec. 24 25000 -- - - -- - - -- --------- 20000_________________________.__________ ____________ Sunday, Dec. 27 MW _200D Thumday, July 23 1 _5_0 -_-_-_-_Sunday, July 2 10000 __ 5000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hours 12. Fuel Prices. The price of natural gas was assumed to escalate from $55/tcm in 1994 to $80/tcm in 2010, in real terms (in 1994 US$) with uniform growth rate over the period. The price of mazut was increased from $60/ton in 1994 to $75/ton in 2010, and the price of coal from $15/ton to $20/ton in year 2000, remaining at that level thereafter. Calorific values of the fuels were assumed at 8.1 Gcal/tcm (gas), 9.7 Gcal/ton (mazut), and 5 Gcal/ton (coal). The price of nuclear fuel was assumed at $ 5.2 per MWh electricity produced. 13. Other assumptions. Given the current low level of maintenance activities and the need to improve maintenance, the operating and maintenance costs were assumed to rise from their current levels  ANNEX 3 Page 5 by 10% annually in real terms until 2000, and at 5% thereafter. The discount rate, used both for levelizing all costs and for the calculation of interest during construction, was 10%. D. Results 14. Three cases were evaluated using the medium load forecast, with the four nuclear units firnly committed and commissioned according to the schedule described in para. 10. The base case (Case 1) assumed completion of seven units at the Dniester PSP in 1998, 1999, 2001, 2002, 2004, 2005 and 2006, respectively. In Case 2, the optimal timing of completing the Dniester PSP units was determined by the progran, rather than being pre-determined. Case 3, designed to test the contribution of the Dniester PSP, assumed that no units at the Dniester PSP would be completed during the planning period. 15. Total levelized system costs (for 1993 as the base year) for the medium demand cases (Cases 1, 2 and 3) are US$ 17,847 million, US$ 17,691 million and US$ 17,751 million, respectively. The associated total investment costs for the planning period, in constant 1994 US$ million (i.e., not levelized), assuming level 3 safety upgrades for the nuclear units6, were 4093, 4093 and 5311, respectively, of which costs of completing the four nuclear units were 1935.7 No new capacity additions (in addition to the firmly comnmitted 225 MW thermal capacity and 4000 MW nuclear capacity as described above are needed until 2008. The best solution (Case 2) is to commission all 7 units of the Dniester PSP; in addition, 6 gas turbine units (5 in 2009, 1 in 2010) and four combined-cycle units (all in 2010) are added. If the Dniester PSP is excluded (Case 3), the number of combined cycle units in the optimal solution increases to 9, while the number of gas turbine units remains 6. The presence of rather inefficient, but less capital intensive gas turbine units in the optimal solution shows that the system needs additional peaking capacity. 16. Although software constraints8 make the direct evaluation of the proposed project difficult, the results of the least-cost analysis suggest that rehabilitation of the existing hydro plants is consistent with the need to preserve and enhance regulating capacity. A similar conclusion should hold for the low-cost rehabilitation of thermal plants that would increase their load-following capabilities and efficiency. At the same time, the presence of the capacity surplus throughout an extended period (until 2008 for the medium demand forecast) merits a closer examination of the retirement program. The retirement of additional units that are inefficient, expensive to maintain and operate, and would require significant investments for rehabilitation, could be a cost effective solution. 17. Three additional cases, designed to shed some light on the cost-effectiveness of the assumed 6/ See footnote 9 below. 7/ The investment figures do not include the costs of completing the 225 MW Dobrotvorsk unit (para 8), and the cost of recomissioning Chernobyl 2. 8/ The constraints most relevant to this analysis are: (i) the modeling of hydro plants is fairly crude in the WASP; (ii) the modeling of a rehabilitation of a plant is not possible within a single run and is, therefore, awkward, time-consuming and heuristic; (iii) most of time-dependent constraints and time-dependent parameters can not be modeled. These constraints, among other things, may result in the later than optimal scheduling of the completion of pump storage units.  ANNEX 3 Page 6 Figure m.5: Minimal and Maximal Monthly Load 40000 30000 20000 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ M ax Load Low 7 8 9 10 11 12 1 2 3 4 5 a Months completion of the nuclear units under construction (Zaporozhye 6, Khmelnitsky 2, and Rovno 4) were also simulated, based on the cost figures proposed by the joint US DOE/Ukrainian Working Group (Report of June 23, 1994)9. In these cases, the timing of the completion of nuclear units was not fixed, i.e., it was left to the software to decide whether it was justified to complete the units, and to determine the optimal timing of the completion (other assumptions were the same as for Case 1). The US DOE/Ukrainian Working Group Report discussed three cases. In Case 4, which differ in the level of safety measures for the three units whose construction is most advanced, Z6 was completed as originally designed, and K2 and R4 were completed with level 1 safety measures. The costs of the completion were (in US$ per kW) 34, 257 and 267 for Z6, K2 and R4, respectively. In Case 5, Z6 was completed with level 1 and 2 safety upgrades, K2 and R4 were completed with level 2 safety upgrades, with corresponding costs of 110, 303 and 313 US$/kW. Case 6 assumed level "3" safety upgrades for all three units, with corresponding costs of 216, 439 and 449 US$/kW. It was further assumed that the Chernobyl 3 unit would not be recommissioned, and the remaining two units would be decommissioned in 1996-1999, respectively, in all three cases. The following are the least-cost results indicating optimal timing for completing the units: Case 4 Case 5 Case 6 Z6 1995 1996 1996 K2 1996 1998 2004 R4 1997 1999 2006 9/ The following completion cost figures were assumed by the US DOE/Ukrainian Working Group: Z6: 34, 76, 182; K2: 257, 46, 182; R4: 267, 46, 182. The above costs are in million of 1994 US$, the first figure includes completion costs and level 1 safety upgrades for K2 and R4, the second figure includes Li and L2 safety upgrades for Z6, and L2 safety upgrades for K2 and R4 (Ll upgrades for these two units were included in the completion costs); the third figure includes L3 safety upgrades.  ANNEX 3 Page 7 18. In all three cases it was optimal to complete all units under construction, with commissioning years depending on the level of safety upgrades, i.e., on the completion costs. Furthermore, in all three cases the least-cost plans contained installing 2 single-cycle gas turbines in 2009 and 3 in 2010, and one combined-cycle gas turbine in 2009 and another one in 2010 (in addition to completing the nuclear units, as given above).  UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT Table 111.1 Existing and Firmly Conmmitted Units Plant No. of Opetating Maint. Costs plant Code Units Heat Rate Maintenanrce Name I(end of Capacity of Total -.___Rte ___fFixe Name______ _ J (1993) 1Ist bl ok Capacity Ist block Avg. Fuel Price Fud Type Forced OuCage T Vabe Iracreas Rate Duration Capacity Vrble UScerits _ |USS/KcW- MW MWh KcaUKwh Kcal/Kwh /Gcal Days MW mUS/MWh Ladyzhinsk LD16 6 296 296 2433 2433 477.0 Coal 9.4 37 296 0.68 1.56 Pridnieprovsk PD14 4 145 145 2651 2651 377.1 Coal 9.4 29 145 0.83 1.89 Pridnieprovsk PD58 4 257 257 2704 2704 421.5 Coal 9.4 37 257 0.68 1.56 Kryvoi Rog KRIO 10 282 282 2612 2612 374.6 Coal 9.4 37 282 0.68 1.56 Zaporozhye ZP14 4 290 290 2413 2413 316.3 Coal 9.4 37 290 0.68 1.56 Zaporozhye ZP57 3 800 800 2388 2388 672.7 Gas 7.5 51 800 0.43 0.92 Ugliegorsk UG14 4 299 299 2458 2458 408.7 Coal 9.4 37 299 0.68 1.56 Ugliegorsk UG57 3 750 750 2327 2327 665.4 Gas 7.5 51 750 0.43 0.92 Zuev ZU14 4 290 290 2515 2515 472.6 Gas 9.4 37 290 0.68 1.56 Staro Beshevo SBI0 10 175 175 2825 2825 391.4 Coal 9.4 32 175 0.72 1.64 Lugansk LU18 8 163 163 3023 3023 453.7 Coal 9.4 32 163 0.72 1.64 Slaviansk SLA6 1 670 670 2510 2510 672.8 Gas 7.5 51 670 0.43 0.92 Staviansk SLA7 1 715 715 2490 2490 380.6 Coal 7.5 51 715 0.43 0.92 Kurakhovsk KUII 1 187 187 2598 2598 341.3 Coal 9.4 32 187 0.72 1.64 Kurakhovsk KU27 6 210 210 2598 2598 341.3 Coal 9.4 32 210 0.72 1.64 Tripolye TP14 4 293 293 2532 2632 443.9 Coal 9.4 37 293 0.68 1.56 Tripolye TP56 2 294 294 2384 2384 635.6 Mazut 9.4 37 294 0.68 1.56 Kiev TEC5 K512 2 60 100 1332 2850 665.8 Gas 9.4 29 100 0.83 1.89 Kiev Tec 5&6 K5A6 4 175 250 1514 2788 653.8 Gas 9.4 32 250 0.7 1.6 Bushtinsk BU12 12 191 191 2512 2512 455.3 Coal 9.4 32 191 0.72 1.64 Dobrotvorsk DT13 3 100 100 2837 2837 514.3 Gas 9.4 29 100 0.83 1.89 Dobrotvorsk DT45 2 150 150 2581 2581 625.3 Gas 9.4 29 150 0.83 1.89 x Zmiev ZM16 6 163 163 2741 2741 401.7 Coal 9.4 32 163 0.72 1.64 Zmiev ZM70 4 256 256 2594 2594 428.8 Coal 9.4 37 256 0.68 1.56  UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT Table III.1 Existing and Firmly Committed Units Plant No.of Operating & Maint. Costs Plant Code Units Heat Rate Maintenance 19a3me1st block Capacity I st block Avg. Fuel Price Fuel Type Forced Outage 1993) o Increase Rate | Duration Capacity Vafiable UScents |W US$/KW l l MW | MW KcallKwh I Kcal/Kwh I /Gcall mUSS/MWh || Harkov HV12 2 60 110 1691 2950 667.8 Gas 9.4 29 0.83 1.89 Harkov HV33 I 175 250 1426 2841 679.0 Gas 9.4 32 250 0.7 1.6 Lugansk LUNB I 120 200 1657 2950 494.9 Coal 9.4 32 200 0.72 1.64 Slaviansk SLNB 1 48 80 1657 2950 556.6 Gas 9.4 29 80 0.83 1.89 Mironov MRNV 2 60 100 1657 2950 393.8 Coal 9.4 29 100 0.83 1.89 Severodonetsk SVDK 1 162 270 1565 2950 677.6 Gas 9.4 32 270 0.68 1.56 Kramator KRAM 1 162 270 1889 2950 654.1 Gas 9.4 32 270 0.68 1.56 Darnitsk DARN 1 96 160 1317 2950 672.1 Gas 9.4 32 160 0.83 1.89 Chernigov CHGV 1 126 210 2023 2023 491.3 Coal 9.4 32 210 0.72 1.64 Cherkasov CHSK 1 120 200 1621 2950 614.3 Gas 9.4 32 200 0.72 1.64 Simferopol SIMF 1 167 278 2496 2950 667.2 Gas 9.4 32 278 0.68 1.56 Kaluga KLGA 1 120 200 1558 2950 572.0 Gas 9.4 32 200 0.72 1.64 Kremenchug KRCG 1 153 255 1626 2950 646.2 Mazut 9.4 32 255 0.7 1.6 Other, small SMLL 10 38 63 1657 2950 659.4 Gas 9.4 29 63 0.85 1.9 Industrial INDS 10 60 99.4 1657 2950 659.4 Gas 9.4 29 99.4 0.83 1.89 Nuclear, VVER NVVL 9 1000 1000 2606 2606 200.0 Nuclear 12 78 1000 1.37 0.6 Nuclear, VVER NVVS 2 409 409 3071 3071 200.0 Nuclear 12 41 284 1.53 0.6 Nuclear, RBMK NRBM 2 1000 1000 2606 2606 200.0 Nuclear 12 78 1000 1.37 0.6 Kiev 6 KV62 0 175 250 1514 2788 653.8 Gas 9.4 32| 250 0.7 1.6 Dobrotvorsk DT66 0 225 2251 2457 2457 375.8 Coal 9.4 32 225 0.721 1.64 ii  UKRAINE HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT Table III.2 Candidate Units Plant Plant No. of Capacity Name Code Units of Total Heat Rate Maintenance Operaing Cost (end of 1st block Capacity Ist block Av-rage Fuel Fuel Forced Outage Fixed 1993) lease Price Type Rate Duration Capacity Varable 11 MW ]fMw IKcaVKwh Kcal/Kwh ]Us centsDays IIMW I USSJKW- Ir _ _ _ __ _ _ _I _ _ _I ___ _ _ I_ J /Gcal ___ay___ -i_ _ _ _ _ Ii_ _ _ _ _ I _ _ _ _ _I m___ ____M W h_ Gas SCGT 120 120 2866 2866 679 Gas 4 21 120 0.2 2 Turbine Combined CCGT 450 450 1820 1820 679.3 Gas 6 25 450 0.3 1 Cycle Steam PVCL 500 500 2263 2263 300 Coal 9 30 500 0.6 1.44 Coal Steam MAZT 500 500 2263 2263 618.6 Mt 8 26 500 0.5 1 Mazut~~~~~~~~~~~~~~~~~~~~~  ANNEX 4/A Decree of the President of Ukraine On Market Transformation Measures in the Electricity Sector of Ukraine To ensure reliable energy supplies to the national economy and the Ukrainian population, to promote energy and fuel conservation, and to improve the efficiency of the energy sector in order to operate under market conditions and, taking into account the specific features of this branch, I decree: 1. To the Cabinet of Ministers: to develop and establish-within a month-an action plan for electricity sector restructuring and to implement in a definite order, a privatization process in the sector complete with the preparation of the appropriate draft regulations and normative acts; * to implement-within a year-a range of measures that will create a competitive electricity market in Ukraine; * to create-within two months-a regulatory body that will regulate electricity tariffs, promote competition within the sector, and protect consumers' rights. 2. To the Ministry of Power and Electrification (Minenergo) of Ukraine: * in a definite order, to reorganize the National Dispatch Center of the Ministry of Power and Electrification of Ukraine (i.e, the Center) and the regional power associations (i.e., the Associations) and establish on the basis thereof: * A state enterprise-the Energomarket-comprised of the Central and Regional Dispatch Centers of the above-mentioned Associations * Not less than four Joint-Stock State Electricity Generation Companies from the existing thermal power stations of 500MW (and higher) and from the hydropower stations of 300 MW (and higher) currently belonging to the Associations; * The National Electric Company (NEC) from the high voltage networks (220 KV and higher including substations and accompanying infrastructure) currently part of the Associations; * Regional (oblast) Joint-Stock State Electricity Distribution Companies from the remaining state property left in the Associations after the removal of the abovementioned assets. 3. This Decree is effective from the date of its signature. President of Ukraine L.Kravchuk Kiev May 21, 1994 Decree 244/94  ANNEX 4B Page 1 ACTION PLAN FOR TILE RESTRUCTURING OF THE ELECTRIC PONER SECTOR AND THE PREPARTION OF ITS OPERATION IN MARKET CONDITIONS CABINET OF MINISTERS' REGULATION 816 Ite ACTION AGESPNSIBL DEADLINE \.MAR_KET REFORM,f OF THE EXISTING POWER SECTOR STRUCTURE Creation of the interdepartmental Minenergo DEC 1994 Electricity Reform Commission MinEcon Anti-monopoly Committee State Property Fund Submit proposals to the Cabinet of M9inenergo DEC 1994 Ministers on the creation of an independent MinEcon National Electrictitv Regulatory Commission (,NERC) Determine the number and composition Minenergo DEC 1994 of the power generation companies to be set up Anti-monopoly Committee Create and confirm a list Minenergo DEC 1994 of energy facilities to be included in Anti-monopoly Comrnittee the National Electricity Company (NEC) Set up the "Energomarket" State energy Minenergo MAY 1995 enterprise Anti-monopoly Committee Set up the National Electricity Con-...any Minenergo MA-Y 1995 Anti-monopoly Cormmittee NlinEcon Determine composition of regional Minenergo JAN 1995 distribution companies (LECs) MinEcon Anti-monopoly Committee  ANNEX 4B Page 2 Item ACTION RESPONSIBLE DEADLINE AGENCY 2. CORPORATIZATION OF THE POWER SECTOR Organize thermal and hydro-power stations Minenergo APR 1995 into state power generation joint-stock Anti-monopoly Committee companies through corporatization NfinEcon Set up regional (oblast-level) power hfinenergo JUN 1995 distribution state joint-stock companies Anti-monopoly Committee through corporatization hfinEcon Corporatize auxiliary enterprises Minenergo MAY 1995 of regional assocations MinEcon 3. DEVELOPING THE LEGAL AND REGULATORY FOUNDATIONS Draft Regulations for NERC Minenergo DEC 1994 MinEcon NMinistry of Justice Anti-monopoly Committee Draft Regulations for the EnergoMarket Minenergo JAN 1995 MinEcon Ministry of Justice Anti-monopoly Comrmittee Draft Regulations for Electricity Minenergo Sector Licerses MinEcon JAN 1995 Ministry of Justice Anti-monopoly Committee Signed, V. Masol Prime Minister of Ukraine November 2, 1994  UKRAINr, HYDROPOWER RLHABILITATION AND SYSTFN COtZI'ROL PROJECT DETAILED COST ESTIMTES A. 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