world bank document · i gcal = 4.187 gj 3.968 million btu = 1,163 kwh i tce = 7 gcal, and i toe =...

Document of

The World Bank

Report No. 13663-UA

STAFF APPRAISAL REPORT

UKRAINE

HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT

MARCH 20, 1995

Infrastructure DivisionCountry Department IVEurope and Central Asia Region

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

CURRENCY EQUIVALENTS

Currency unit = karbovanets, abbrev. KrbUS$1 = 130,000 karbovanets (as of March 1995)

WEIGHTS AND MEASURES

atm atmosphere MJ Megajoule (101J)bcm billion cubic meter mt million metric tonsGcal Gigacalorie (109 cal) MW Megawatt (106W)GW Gigawatt MVA Megavolt Amperekg kilogram Pi Petajoule (105J)km2 square kilometer psi pounds per square inchkoe kilograms of oil equivalent t metric tonkV kilovolt tce tons of coal equivalentkW kilowatt toe tons of oil equivalentkWh kilowatt hour TWh Terawatt hour (10'2 Wh)m3 cubic meter

CALORIFIC VALUES

I Unit of Fuel Gcal

Coal (ton) 5.0Wood (ton) 2.0Natural gas (000m3 ) 8.5Mazut (ton) 9.7Diesel (ton) 10.2Gasoline (ton) 10.5Kerosene (ton) 10.3Liquified Petroleum Gas (ton) 10.8Crude oil (ton) 10.0

CONVERSION FACTORS

I Gcal = 4.187 GJ 3.968 million Btu = 1,163 kWhI tce = 7 Gcal, and I toe = 10 GcalI kWh of hydro and nuclear energy output converted to primary thermal equivalent at 250 grams of oil equivalent.

ABBREVIATIONS

DHE DniprohydroenergoEBRD European Bank for Reconstruction and DevelopmentEU European UnionGDP Gross Domestic ProductGEF Global Environment FacilityHPS Hydropower StationLAEA Intemational Atomic Energy AgencyIDC Interest During Construction[MF International Monetary FundLPG Liquid Petroleum GasNDC National Dispatch CenterNERC National Electricity Regulatory CommissionPIU Project Implementation UnitPMU Project Management UnitPSP Pump Storage PlantTACIS Technical Assistance for the Community of Independent StatesUCP'TE Union for the Coordination of Production and Transport of Electricity (West European Grid)UPS Ukrainian Power SystemUSAID United States Agency for Intemational DevelopmentVAT Value-Added Tax

FISCAL YEARJanuary I - December 31

UKRAINE


CONTENTS

PaMe No.

LOAN AND PROJECT SUMMARY .... i

SECTOR BACKGROUNDA. Country Context ......................................... 1B. Overview of the Energy Sector ............................... 2C. Power Industry Conditions and Priority Needs ..................... 4D. Government Policy and Strategy in the Power Industry ................ 8E. Bank Strategy and Experience ................................ 10

11. THE PROJECTA. Project Concept and Objectives ............................... 12B. Project Description ....................................... 12C. Project Context .. ....................................... 15D. Environmental Aspects .................................... 16E Cost Estimates and Financing ................................ 16

IllI. FINANCIAL AND ECONOMIC ANALYSISA. Electricity Prices ........................................ 19B. Past Financial Performance of the Implementing Agencies .............. 20C. Future Financial Performance of the Implementing Agencies ............. 22D. Financial Analysis of the Project .............................. 26E. Economic Costs and Benefits ................................. 27F. Sensitivity Analysis ....................................... 28

IV. IMPLEMENTATIONA. Institutional Arrangements .................................. 30B. Implementation Schedule ................................... 33C. Procurement . ........................................... 33D. Disbursement . .......................................... 36E. Accounts and Audits ...................................... 37F. Monitoring and Evaluation .................................. 37G. Operation . ............................................. 38

V. PROJECT RISKS AND BENEFITS ................................. 39

VI. SUMMARY OF RECOMMENDATIONS AND LOAN CONDITIONS .... ....... 40

ANNEXES

1. Electricity Demand Forecast2. Nuclear Safety Issues3. Least Cost Power Investment Program4. Presidential Decree 244/94 and the Government's Action Plan5. Detailed Cost Estimates6. Financial Statements and Projections7. Financial Rate of Return Calculation for the Hydropower Component8. Economic Analysis9. Project Implementation Schedule10. List of Procurement Packages11. Estimated Schedule of Disbursements12. Performance Indicators13. Supervision Plan

MAPIBRD Map No. 26469 Main Power Stations and Transmission Lines

UKRAINE


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 yearsgrace period.

Commitment Fee: 0.75% on undisbursed loan balances, beginning 60 days after signing, less anywaiver.

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 AppraisalReport: Report No. 13663-UA

Map: IBRD Map No. 26469

UKRAINE


I. SECTOR BACKGROUND

A. Country Context

1.1 Ukraine declared its independence from the Soviet Union in August 1991. It has a landmass that is the largest in Europe (with the exception of European Russia) and a population of 52 millionthat ranks fifth in Europe. GNP per capita was estimated at US$ 1,910 in 1993. The economy rests onindustry 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 percentin 1993, bringing the cumulative fall in output since 1990 to 38 percent. This trend accelerated in the1994 as GDP declined by about 23 percent. Due to loose fiscal and monetary policies, the rate ofinflation 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 singledigit levels, primarily on account of flagging demand, itself the result of a large drop in real wages anda stringent credit policy. A freeze in the adjustment of administered prices (particularly energy) afterDecember 1993 also contributed to the slowdown in inflation.

1.3 The external situation has become increasingly tenuous, reflecting a significant tradedeficit with the FSU -- about US$ 3 billion in 1993 -- which was only partially offset by a trade surpluswith the rest of the world. Developments in external trade have been marked by a sharp contraction intrade volumes, a considerable decrease in the terms of trade as import prices of energy moved towardsworld levels, and a modest shift in the direction of trade away from the FSU towards the rest of theworld. The foreign trade deficit led to the increasing accumulation of arrears on payments for energyimports.

1.4 While external shocks, mostly brought on by the collapse of the FSU, have contributedto the economic decline, so too have the policies of the Government. Through 1993 and the first halfof 1994, these policies have been marked by the absence of a coherent macroeconomic stabilization andstructural reform program. A few disparate and uncoordinated attempts at stabilization have beenundertaken instead. The Government resorted to a number of administrative measures to manage theeconomy. 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 domestictrade of key commodities; and export quotas and licenses remained widespread. Very little progress wasachieved in privatization, and, due to frequent changes in regulations and high taxes, the growth of theemerging 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 thepast in economic policies. A comprehensive program of macroeconomic stabilization and structuralreforms 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 Facilityin support of the stabilization program. A Rehabilitation Loan (Ln. 3831-UA) of US$ 500 million wasapproved by the Bank in December 1994 to support the implementation of structural reform measuresnecessary 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-orientedeconomy. Within this framework, the economic package that the Government has adopted aims to breakinflationary expectations and promote a sustained recovery in economic growth. To this end, the programfocuses on four key interdependent elements. First, a stable environment is required so that producersand consumers can make sound decisions without fear of macroeconomic disruptions. The stabilizationof the economy will rest upon tight fiscal and monetary policies. Second, competition in markets isessential to an efficient allocation of resources. In an effort to promote free and open markets, theGovernment will rely upon the liberalization of prices and domestic and foreign trade; the dismantlingof the state order system; demonopolization; and promotion of the private sector. Third, the hardeningof enterprise budget constraints through corporatization, privatization and the enforcement of bankruptcylaws will encourage enterprises to respond to the new market forces. The elimination of directed creditsand credits to settle inter-enterprise arrears and financial sector reform are expected to support behavioralchanges at the enterprise level. Finally, the social safety net is to be strengthened through improvedtargeting in order to protect the segments of the population most vulnerable to the adjustments associatedwith 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 intensityin relation to industrial output and the high share of industry in final energy consumption. This is dueto the high share of heavy industry (iron and steel, basic chemicals) and the low thermal efficiency ofenergy consumption technologies. Energy consumption per capita was about 3,500 kilogram oilequivalent (koe) in 1993, which is quite high even by Western European standards. Following a declineof 11 % between 1985 and 1990, the energy intensity of GDP increased by 40% in the 1990-1993 periodreaching 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, aswell as coalbed gas. The unusually difficult geological conditions (thin, steeply inclined coal seams atgreat depth) in the central Donbass make the mining of coal costly and labor intensive. Natural gas andcrude oil resources are declining, but are still significant. Remaining proven and probable reserves are190 million tons of oil and 1,400 bcm of natural gas. The shallower and larger oil and gas pools in theDnieper-Donetsk and Carpathian regions are rapidly being depleted. These deposits are replaced byreserves in smaller, deeper and less productive reservoirs, which are more expensive to find, to drill-upand 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 primaryelectricity (hydro- and nuclear power), represented 48 % of consumption in 1993-94 (see Table 1.1). Themain import items were crude oil and oil products, originating almost exclusively in Russia, and naturalgas, originating in Russia and Turkmenistan. The cost of fossil fuel imports reached US$ 5 billion in1993 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 billionrepayable over a six-year period. In 1994, arrears for gas delivered in 1993 by Turkmenistan wereconverted to a state debt of US$ 0.7 billion repayable over a seven-year period (including two years ofgrace). In late 1993, Russia introduced advance payment for crude oil deliveries that contributed to analmost 40 percent drop in Ukraine's crude oil imports in the following year. Gas deliveries, despiteUkraine'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 decidedto suspend the deliveries of gas. An agreement between Ukraine and Turknenistan signed in November1994 stipulated that payments of US$300 million would be made to Turkmenistan to resolve part of thearrears, and Ukraine would also compensate Turkmenistan for the cost of gas delivered in the fourthquarter of 1994 (the rest of the arrears would be rescheduled to be paid over seven years, with 2 yearsof grace). Negotiations with Russia are planned to be concluded in early 1995, and there are indicationsthat 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 anon-transparent surcharge on industrial consumers (for gas and district heat). Even for electricity, thereare several categories of households who are entitled to discounts, and the cost of these discounts is borneby the industrial consumers. During most of 1994, additional price distortions were caused by: (i) asubsidy to non-household consumers of coal; (ii) an artificial exchange rate that did not allow the passingof the full cost of imported gas to consumers; and (iii) price adjustments for electricity and heat thatlagged 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, theGovernment started the implementation of a program of price adjustments that: (i) drastically reduceshousehold 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 fueland other basic input costs in the price of electricity and heat.

1. 12 Sector Institutions. The sector is dominated by vertically integrated state ownedmonopolies, 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 thelong term objective of privatizing those activities that are not natural monopolies (for more details on theGovernment's program in the power industry, see Section D below). There are eight vertically integratedstate-owned regional utilities (Energos) under Minenergo. The regional utilities operate the regionaldispatch centers, portions of the transmission network, the thermal power plants, and the distributionsystem. 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 oneentity is a major obstacle to improving the efficiency and quality of electricity supply. Institutionalseparation of the above functions, correction of fuel and electricity prices, commercialization ofenterprises, and promotion of competition are needed to establish the foundation for a modern, profitableand efficient power industry.

1 .13 Employment. The energy sector employs almost 1 million people, or about 4.5 % of thelabor force. About 630 thousand are employed in coal mining, 140 thousand in the power industry, and200 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 52,122MW in 1993. It consisted of 12,818 MW of nuclear capacity, located in 5 plants with a total of 14 unitsin operation. There were more than 40 thermal (fossil fuel) power plants with conventional steam cycletechnology, with over 110 generating units and a total capacity of 32,364 MW, of which 3,824 MW arecombined heat-and-power units. Hydro capacity was 4,700 MW, stationed mostly in 9 plants with a totalof 100 generating units. The capacity of industrial power plants was about 2,240 MW. The totaleffective 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 mazutfor co-firing. About 5,520 MW of power generation as well as most of the combined heat-and-powerplants run on gas or mazut as main fuels.

1.15 Electricity generation was 228,316 GWh in 1993, of which thermal plants produced135,875 GWh, nuclear plants 75,242 GWh, hydropower plants 11,214 GWh (including 200 GWh by apump 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 (orabout 7.2% of their total generation), and of nuclear plants 5,228 GWh (6.9% of total nucleargeneration). After accounting for other production needs (615 GWh), consumption of the pump storageplant (302 GWh), and transmission and distribution losses (22,473 GWh, or 9.8 % of total generation inthe system), net electricity consumption came to 187,905 GWh. The peak demand in 1993 occurred inJanuary, and was about 37,000 MW; the minimum demand, in June, was about 17,000 MW. Heatproduction was about 48 million Gcal. Total fuel consumption for electricity and heat production was53 million tons of reference coal equivalent (tce, defined as 7000 kcal/kg), consisting of 19.4 million tceof 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 201598Thermal 201682 182500 162390 135870 115848Nuclear 76179 75131 73732 75240 68848Hydro 10704 11904 8069 11210 12299

Small Industrial 7693 7240 6754 5996 4604|hports* 7078 9231 5862 6449 5253

FSU 7078 9231 5862 6449 5253Non-FSU

Exports* 35048 23538 10511 7595 6277FSU 6917 8094 4739 4885 4686Non-FSU 28131 15444 5772 2710 1591

Net Exports 27970 14307 4649 1146 1024Consumption 268288 262468 246296 227170 200575

Industry 146150 137725 126344 108022 88554Agriculture 20453 20719 19061 18406 16758Transport 14449 13611 12482 12111 10834Communal 17582 17828 17219 16705 15722ServicesHouseholds 21142 24208 24909 26898 26764Other 7460 7456 6049 5764 4876Self Consumption 41054 40891 40231 39265 37066and Losses

including electricity exchange

1.16 Electricity generation, domestic consumption and exports have all declined significantlyin 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 3.4times 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 integratedpower system of the FSU. During the last 15-20 years, investment policy favored the use of natural gasand nuclear power at the expense of coal-fired plants. The aging coal plants, whose performance wasfurther affected by declining coal quality, have to use mazut or gas as supplementary fuels despite sharpincreases in the price of imported oil and gas after the break-up of the Soviet Union. The total fossil fuelconsumption of the thermal power plants consisted of 43.1 mt of coal, 20.2 bcm of gas, and 4.9 mt offuel oil in 1993, representing, respectively, 45%, 20% and 50% of the domestic consumption of thesefuels.

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 MWnameplate capacity. The recommissioning of a third fire-damaged unit at Chernobyl is beingcontemplated. Construction of three new nuclear units in Zaporozhye, Rovno and Khmelnitsky, each1000 MW of capacity, is in progress at varying degrees of completion. Sunk investments costs and theincreasing costs of non-nuclear electricity generation are powerful incentives to complete these units. TheApril 1986 Chernobyl accident brought to the forefront the issue of the safety of nuclear plants (seeAnnex 2). The G-7 Summit Meeting held at Naples in July 1994 called for the phased closure of theChernobyl plant and outlined a broad Action Plan to this effect, including the completion of three newnuclear reactor units to adequate safety standards, the rehabilitation of non-nuclear power plants, energypolicy reform, and energy efficiency measures. The Ukrainian Government agreed to work with the G-7to 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 Volgariver that controlled system frequency, revealed some serious structural and functional weaknesses withnegative 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 systemlacks peaking and spinning reserve capacity. Inability of the UPS to maintain the balance of supply anddemand in real time, as measured by the system frequency and power flows through the interconnectionswith the neighboring systems, led to the separation of all neighboring systems, causing furtherdeterioration of system performance and reduction in export capacity. The existing peaking capacity isprovided by the hydro plants that are old and in need of rehabilitation. A decrease in hydropowercapacity would lead to further deterioration in the reliability and quality of electricity supply. In viewof unmet load-following requirements and the high share of base-load plants, it is also necessary toenhance 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 averageannual 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 Dnieperriver, and one plant is on the Dniester (with two new plants under construction). The reservoirs weredeveloped for multiple purposes. Operation of the reservoirs is, therefore, subject to many and oftencompeting requirements, but is, to a large extent, determined by the electricity generation needs. Thefollowing 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 361Kiev PSP 174.5 73.1 3.7 112 235Kanev HPS 91.5 15.7 2620 290 24x320 850 444Kremenchug HPS 81 17 13500 8970 12x490 1506 625Dnieprodzerzhinsk HPS 64 15.5 2460 500 8x552 1250 352Dnieper I & 11 HPSs 51.4 38.7 3330 865 4600 4140 1516Kakhovka HPS 16 16.5 18200 6780 6x485 1420 300Dniester HPS 125 40 6800 6x327 800 702

1.21 The severely inadequate capacity to regulate frequency in Ukraine has led to frequencylevels that are not only unacceptable by international standards but also damaging to rotating electricequipment 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 normallytaken 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 areloath to substitute lost nuclear plant with fossil fuel (more expensive) generation. Thus the safety of thenuclear plants is compromised. Therefore, enhancing the system's ability to better balance supply anddemand, and improve frequency regulation, would have significant nuclear safety benefits.

1.22 The current control system consists of a hierarchical, four level dispatch and supervisionsystem, and local automatic control subsystems at various facilities. At the top level of the dispatchsystem is the National Dispatch Center in Kiev, linked to the eight regional dispatch centers, to somehydro plants, and to 750 kV and 330 kV substations. The regional dispatch centers are connected topower 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, aresingle generating units at the plants, and district distribution centers, connected with the local distributioncenters. The system operation planning procedures are generally adequate, although there is space forimprovements. Computer models are used for the analysis of system performance and optimization ofregimes. The software, most of which is not portable, has been developed mainly in the central institutesof the FSU and delivered without the source codes and, therefore, cannot be maintained and upgradedlocally. The real-time operation of the system is controlled manually, using telephone connectionsbetween dispatchers in central and regional dispatch centers, and plant and substations operators. Theexisting data acquisition and communication system is incomplete, and largely obsolete. No automaticgeneration control or automatic load control is used. Although these weaknesses are somewhatcounterbalanced by the high technical competence of the staff, the weaknesses inevitably contribute tothe 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 belongto distribution. Ukraine has interconnections with Central Europe (capacity 2000 MW), Russia (3900MW AC, 200/250 MW DC), Romania/Bulgaria (3500 MW), Belarus (1000 MW), with a total effectivepower transfer capacity that exceeds 20% of the domestic generating capacity. In general, capacity ofthe transmission network is sufficient, particularly under the current conditions of lower consumption andreduced 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 flowsthrough 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 notseem 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, dueto a number of factors such as the general economic downturn, electricity price increases and economicrestructuring (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 inthe 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 linefor one year). The simulation of system operation showed that the marginal cost of generation in thepeak period was about 60% higher than the marginal cost of generation at the minimal load. Thecompletion 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 preliminaryanalysis also indicated that completing the nuclear units that are in an advanced stage of construction isjustified, 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 thatsome of the plants are quite old, it may be more cost-effective to retire them earlier than indicated inMinenergo's current retirement plan. Those old coal-fired plants that are not retired and the hydropowerplants will need to be rehabilitated. More details are provided in Annex 3.

1.25 Total power generation investment requirements are preliminarily estimated at US$3.5billion 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, andUS$ 0.7 billion for the completion of three new nuclear units. The rehabilitation of thermal andhydropower plants and the partial completion of the Dniester PSP requires about US$ 1.6 billion. Abouthalf 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 turbinesand generators in the FSU, with exports to many countries. However, domestic production capabilityfor some categories, notably high-voltage equipment, advanced power generating technology (gasturbines, modern coal-burning technology, environmental protection equipment), and instrumentation,control, commnunications and computing equipment, is limited or non-existent. Also, there seems to belimited expertise available in modern computer-based software and methodology for system control, aswell 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 andcost 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 marketmechanisms to regulate and balance supply and demand. The principal reason, presumably, was concernabout the political risk of increased unemployment inherent in market based solutions. Another prominentconcern 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 EnergySector 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) thedevelopment and implementation of a policy that promotes energy savings; (ii) economically andenvironmentally justified utilization of domestic energy sources; (iii) restructuring of the economy thatreduces the energy intensity of production; and (iv) increasing reliance on alternative (renewable) energysources. The investment program outlined in the "Concept" recognized the priority of rehabilitatingcapacities in the power, coal, gas and oil subsectors, however, it also included a number of ambitiousexpansion 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 providedeconomic incentives for investments in energy conservation, including subsidies and earmarked loans.Specifically, it called for the establishment of national and local extra-budgetary energy conservationfunds 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 "abovethe norm" energy use.

1.30 "The Complex Program for the Modernization and Development of Fuel and PowerIndustry 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 toextending 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 inthe same period would include the completion of pump storage and nuclear plants currently underconstruction. 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 unitswhile continuing the rehabilitation and modernization of existing thermal and hydropower plants.

1.31 Both the "Concept" and the "Complex Program" included extensive measures to upgradethe safety of nuclear power plants. The "Complex Program" assumed that the two remaining units ofthe Chernobyl Nuclear Power Plant would be closed when their reactor channels reach the end of theirlife in 1998-2003. During discussions with the G-7 Nuclear Safety Working Group, the Governmentagreed to consider the possibility of the early closure of the Chernobyl plant provided that a solution wasfound for a set of related issues, such as the financing of replacement nuclear capacity, closure costs, andthe mitigation of social consequences. It was agreed that an international Task Force would be formedfrom Ukrainian and foreign experts with the task of developing a detailed, comprehensive Action Planfor nuclear safety in the context of a power sector development strategy (see Annex 2). The jointinternational 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 MarketTransformation Measures in the Electricity Sector of Ukraine (see Annex 4/A). The Decree ordered abroad 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 distributioncompanies, setting up a competitive wholesale market for electricity, and establishing an independentagency to regulate the industry (i.e., independent from the enterprises and not subordinated to anyMinistry). After some initial delay, the Government adopted an Action Plan to implement the Decreeon November 2, 1994 (see Annex 4/B). As a first step, a National Electricity Regulatory Commissionwas established in December 1994. The Commission is expected to take over the regulation of electricityprices from the Ministry of Economy in May 1995. Full implementation of the Decree is expected toincrease the efficiency and reliability of electricity supply, restore the financial health of the industry, andcreate 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 Ukrainesigned a Decree on October 12, 1994 ordering electricity and gas suppliers to agree on a schedule forthe reduction of arrears with their customers. The Decree created an Interministerial OperativeCommnission to supervise the fulfillment of these agreements, and to ensure that supplies are maintainedto the highest priority customers in the critical winter period. The electricity and gas suppliers arerequired to report non-payments to the Operative Commission, and the Commission's task is to takeappropriate steps to remedy the situation, including ordering the utilities to reduce or discontinue serviceto delinquent customers.

E. Bank Strategy and Experience

1.34 The Bank's overall objective is to support Ukraine's efforts to accelerate structuralreforms, and to promote efficient investments in high priority sectors in order to complete the transitionof 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 theopenness of the policy environment; rehabilitating and re-orienting its physical infrastructure; andextending the social safety net and the efficient delivery of social services. This cannot and need not bedone at the expense of the stabilization effort; in fact, many efficiency measures such as infrastructurecost 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, financialsector reform, and public economic and financial management. Initially, the implementation of theproject 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 (threecomponents and eight implementing agencies, many different Bank staff involved); (iii) lack of guidancefrom an understaffed and demotivated Implementation Unit; and (iv) an adverse attitude towardinteragency collaboration within the Ukrainian government. Institutional rearrangements and theimproved 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 millionequivalent approved in December 1994. The Loan provides financing for critical imports needed to stemthe 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 EnergySector Review (Report No. 11646-UA) was issued in 1993, leading to an Energy Strategy Conferenceheld in Kiev in June 1993. During the Conference, an understanding was reached that the Bank wouldfocus on power generation, gas transmission, and gas distribution, since these were the subsectors wherethe the Bank's contribution to policy development and financing of priority investments could make asignificant difference. It was also determined that lending operations should aim at the rehabilitation ofexisting assets rather than capacity expansion, while supporting initiatives that increase the financial andoperational autonomy of enterprises and foster competition. Immediately after the Conference, theGovernment, assisted by the Bank and other multi- and bilateral agencies, started the preparation of anumber of projects to rehabilitate hydropower plants, thermal power plants, gas transmission lines, andgas distribution and metering facilities. In 1993-94, the Bank also assisted the Government to prepareprojects for coalbed methane utilization and district heating end-user efficiency improvements for possiblefinancing under the greenhouse gas reduction initiative of the Global Environment Fund. The Bankrecognizes 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 industrialenergy audits, rehabilitation of thermal and hydropower plants, gas distribution and metering, legislationfor oil and gas production, and power industry institutional reform. Decree 244/94 (see above) is oneof the regulatory and legislative acts that benefitted from these technical assistance activities. Followingthe approval of the Decree, the Bank, jointly with Minenergo, organized a donor meeting in Kiev in July1994. The purpose of the meeting was to ensure the availability of adequate technical assistance for theimplementation of this important reform initiative in the power subsector. The donors offered technicalassistance of about US$4 million equivalent for the first year of the reform (including US$450,000 fromthe Bank's Institutional Development Fund), and asked the Bank to assist the Government to coordinatethe implementation of the technical assistance program. The proposed project would both capitalize onthe 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 Governmentof Ukraine in the area of nuclear safety. In collaboration with EBRD, the Bank assisted the G-7 NuclearSafety Working Group to develop an Action Plan that includes the phased closure of capacity atChernobyl, the completion of replacement nuclear capacity, the safety upgrade of the remaining nuclearunits, the rehabilitation of non-nuclear power plants and energy efficiency improvements. The Bank isalso actively participating in the work of a joint Ukraine/G-7 Task Force (para. 1.31) that is entrustedwith the technical preparation of the details of the Action Plan. Although the Bank will not financenuclear power investments, the Bank's support for pricing and institutional reforms is an importantcontribution 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 alsopositively affect the safety of the operation of the nuclear plants (para. 3.24), and the planned ThermalPower 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 industryfound a declining trend in the industry's pricing, financial, technical and institutional performance, mainlydue to governmental failure to address the industry's fundamental structural problems ("The World Bank'sRole in the Electric Power Sector", World Bank Policy Paper, Washington DC, 1993). Conflicts betweenthe 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 recommendedthat Bank lending for electric power should focus on countries with a clear commitment to improving theperformance of the power industry by commercialization, corporatization and the establishment of atransparent regulatory framework. The Bank's experience in power rehabilitation is limited since therewere very few purely rehabilitation projects. To the extent that rehabilitation components can beevaluated 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 1994-2010period. The study found that, apart from the completion of the nuclear power and pump storage unitsalready under construction, no new generation capacity is needed, and the rehabilitation of thermal andhydropower 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 programsand to prepare projects that could be financed by development banks. The hydropower study alsoincluded assessments of the Dniester Pump Storage Plant (PSP) and system-wide control and dispatchfacilities. The studies were carried out by consultants whose activities were facilitated and supervisedby counterpart teams appointed by Minenergo. The services of the consultants were financed from trustfunds 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- inearly September 1994. The hydropower study (prepared by SGI Engineering Ltd) identified high priorityinvestments 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 PSPlacked a proper environmental impact assessment and there was a need to revise the implementationschedule 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 SysterilControl Project; and (ii) continue the preparatory work on thermal power rehabilitation and thicompletion of the Dniester PSP for eventual consideration for financing by the Bank. The appraisal otthe project took place in September/October 1994.

2.4 The objectives of the project are to: (i) improve the efficiency, reliability, safety andenvironmental performance of hydropower plants; (ii) increase hydropower generation capacity; (iii)improve the quality of electricity supply by upgrading load and frequency control, which would alsoimprove the safety of nuclear plants; and (iv) reduce fuel costs by facilitating the economic dispatch ofgenerating 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 feasibilitystudy, including the implementation of the complete rehabilitation program for theDnieper I and Dnieper II hydropower plants and the Kiev PSP; near-completeimplementation of the rehabilitation program for the Kakhovka HPS; and partialimplementation of the rehabilitation program for the Kiev, Kanev, Kremenchug andDniprodzerzhinsk hydropower plants;

(b) Installation of dam safety monitoring systems at the main water reservoirs on the Dnieperriver (Kiev, Kanev, Kremenchug, Dnieper, Dniprodzerzhinsk, Kakhovka);

The Project 13

(c) Upgrade of communications, dispatch, system control and protection, and generating unitcontrol; and

(d) Technical assistance for project implementation, and optimization of the use of thereservoirs on the Dnieper river.

2.6 Rehabilitation of Hydropower Plants. Hydropower plants play a critical role inregulating peak load and system frequency. Most of the existing plants are old and in need ofrehabilitation (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 problemswith turbine runners and governors, generator windings and auxiliaries, oil leakage, substations circuitbreakers, load control, and instrumentation and control systems. This has lead to increased operating andmaintenance costs, derating of the units, and lower efficiency and availability. Allowing furtherdeterioration would increase costs, worsen the capacity mix, and further reduce the already insufficientregulating capability of the system.

2.7 The work involves:

Replacement of turbine runners, turbine governors, and replacement, rehabilitation orupgrade of other related equipment (guide vanes, runner chambers, shafts, servomotorsmeasuring and control devices) at the Kiev, Dnieper I and Kakhovka plants. Only eightout of twenty turbines at the Kiev plant will be rehabilitated due to the limited capaciivof the turbine manufacturer (the Kharkhov turbine factory, which produced most of tcoriginal turbines for the plants); the other twelve will be included in the second phase ofthe rehabilitationprogram. Four out of six turbines will be rehabilitated at the Kaklrovl.dHPS, where only one tubine at a time can be taken out. At the Dnieper I HPS. allturbines will be included in the project. Rehabilitation of one turbine both atKremenchug and Dniprodzerzhinsk plants will also be included.

* Rehabilitation of generators including replacement, rehabilitation or upgrade of stator androtor windings, magnetic static core, generator circuit breakers, excitations and coolingsystems, voltage transformers and electrical protection. All the generators that areassociated with rehabilitated turbines will be rehabilitated too; in addition, generators atthe Kiev PSP and Dnieper II, where no turbines are planned for rehabilitation, will alsobe included in the project. All generator circuit breakers will be replaced in all plants.

* Rehabilitation of switchyards and related equipment (step-up transformers, circuitbreakers, isolators and earthing switches, HV instruments and protection, current andvoltage 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, Kakhovkaand Kiev plants, and the Kiev PSP. The work consists of rehabilitating, replacing orupgrading instruments for monitoring temperature, vibrations, generator air gap, waterdischarge, and equipment for local, unit and plant-level control.

2.8 Installation of Dam Safety Monitoring Systems. Reservoirs on the Dnieper river weredeveloped 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 ofthe configuration of the terrain, the reservoirs are low head structures with long embankments. Someof them have long dykes protecting the surrounding land from being flooded. The project includesmeasures to rehabilitate and upgrade the existing dam monitoring systems for about 100 km of dams anddykes for the reservoirs on the Dnieper river. The work will include dam safety investigation, andrehabilitation and upgrade of the existing, as well as installation of new instrumentation (primarilypressure, motion and moisture sensors, water levels, etc.), drainage structures and alarm systems. Datacollection, analysis and storage, automation and centralization of the readings where justified, will alsobe considered. Procedures for dam safety monitoring and emergencies will be reviewed and, ifnecessary, improved, including emergency response, evacuation and training programs.

2.9 Upgrade of Communications, Dispatch and System Control. Low level of automationacross the entire UPS, outdated and inadequate protection, control, metering, communication andcomputing 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 (forcomparison, the UCPTE standard requires the system frequency to be maintained at 50.0 Hz within theband of + or - 0.01 Hz). The response time of primary regulation is slow. The governors have largedead bands, and were made using old technology with hydraulic amplifiers and vacuum tubes. Loadfollowing scheduling is also done manually, rather than by computer-based economic dispatch, resultingin extra fuel costs. Production scheduling of hydro generators, which are all peaking units, is controledmanualy. The control of power flows across interconnections with the neighboring systems is subject tosimilar problems as the control of frequency (manual control, unstable voltage conditions), creating majorobstacles to reintegrating the UPS with its neighbors. Isolated operation, in addition to preventing thetrade of electricity, also reduces reliability, security and quality of supply, and is more expensive as itrequires a larger reserve capacity. The operation of the planned power pool (the spot market forelectricity) will require the improved metering of interconnections, generating plants, power supplycompanies and wholesale customers. Bids and availability forecasts from the generators will have to becollected 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 thehydro plants (included as a component in the hydropower rehabilitation program), newgovernors will be installed at a number of thermal generating units. The governors willbe equipped for manual, local automatic and remote control allowing the implementationof real-time economic dispatch by the National Dispatch Center.

* Upgrade of plant protection, plant dispatch and generation control equipment at theDniester hydropower plant.

* Upgrade of protection systems for the high-voltage transmission lines.

* Installation of the necessary computing equipment to support automatic generation controland 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 computersystems. The upgrade will increase volume and frequency of data available to thedispatchers enabling better monitoring of the system and more timely reactions, and allowthe implementation of automatic generation control and economic dispatch functions, aswell as effective functioning of pool operations. The system will be implemented as amodular, open architecture system, which can be expanded in stages.

Upgrading the communication system by replacing the existing links representing themost serious bottlenecks. The communication system is essential for the real-time controland 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 bandwidthof the communications links is not adequate. Given the size of the Ukrainian powersystem and the corresponding communication requirements, this component will bedesigned to enable functioning of the new SCADA and automatic frequency controlsystems, laying down elements of the new communication system which will be graduallyexpanded over time. Detailed proposals for the location and type of the newcommunication lines will be determined in the detailed engineering design stage inconjunction with engineering specifications of the SCADA and automatic frequencycontrol systems.

2.11 International Waterways. The Dniester hydropower plant is about 15 km upstream fromthe point where the river forms the borderline between Moldova and Ukraine. There is no disputebetween the two countries concerning the operation of this plant. Upgrading of the dispatch andgeneration control equipment for this plant will not affect the reservoir nor any other water retainingstructure, and will have no effect on the flow of the river.

2.12 Technical Assistance. Project implementation support will compensate for the limitedexperience of the beneficiaries in international procurement and the management of foreign contractors.It will include support for preliminary detailed engineering design, technical specifications, biddingdocument 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 fieldacceptance tests, and other project implementation services. The technical assistance will also includereview of the existing procedures in managing the river basin reservoirs for the Dnieper river, andproposals for the improvements, if necessary. Training will be included in the tender documents for thesupply 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 consultingservices will be needed.

C. Project Context

2.13 The components of the project were chosen to address some of the most pressingproblems in the Ukrainian power system, and to maximize the impact of the Bank's contributions. Theleast cost power investment plan includes the rehabilitation of a number of existing thermal andhydropower plants, and the completion of three nuclear units and the pumped storage plant that arealready in an advanced stage of construction (see Annex 3). The proposed project is in accordance withthe 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 ofpayments. The improved quality of electricity supply, a basic input for production, will facilitate themodernization of Ukraine's industry. By increasing the efficiency of electricity generation, this projectis consistent with the Country Assistance Strategy. Together with the planned Thermal PowerRehabilitation Project, the proposed project demonstrates that the Bank is willing to step up assistanceto those sectors of the economy that are committed to reform. This is particularly important at this timewhen the power industry is making the first bold reform steps. The Bank's involvement is regarded asimportant in supporting the implementation of high priority investments under the present conditions ofsevere resource constraints. By rehabilitating and upgrading facilities that utilize a renewable resource,the project is consistent with the objective of environmentally sustainable development. Finally, theproject is also consistent with the nuclear safety initiative of the G-7 since it supports the continuedutilization of a low-cost alternative source of power, and improves the safety of existing nuclear units byreducing fluctuations in frequency.

D. Environmental Aspects

2.14 The impact of the hydropower rehabilitation component (environmental category "B") wasreviewed during the preparation of the feasibility study. Other project components were placed incategory "C", not requiring specific environmental analysis. The main environmental problem detectedby the enviromnental analysis carried out for the feasibility study was excessive leakage of lubricatingoil from turbine runner blade seals. The study recommended the control of water pollution through therehabilitation of turbines, and also identified the need for improved water management, and improvedinstrumentation and procedures related to dam safety. The conceptual design and structural stability ofwater retaining structures were found to be satisfactory.

2.15 During implementation, the project is not expected to impose any costs on theenvironment. Reservoir structures will not be subject to any work. There will be no activities that wouldresult in a significant impact on the existing patterns of water flows and water usage. Environmentalbenefits will come from three sources: (i) the rehabilitation of turbines; (ii) the rehabilitation and upgradeof dam safety systems; and (iii) economic dispatch. The turbines of which the runners will be replacedwere 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 turbineefficiency will lead to more hydro energy produced. Since the marginal source of power in Ukraine isfossil 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 watermanagement and control, which will also take environmental aspects into account. Introduction ofautomatic 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 wereestimated using a constant price increase of 2.2% per year. Price contingencies for local costs wereestimated 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 fromthe 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 estimatesis 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%

Communication4. 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 cover50% of project costs, plus US$18.3 million of interest during construction (the foreign exchangecomponent of total interest during construction estimated at US$ 24.1 million equivalent). Following afive year grace period, repayment of the principal and interest payments would commence and continuefor 12 years. The Borrower would be Ukraine, whose Government would enter into subloan agreementswith the beneficiaries. The beneficiaries would be the National Dispatch Center and theDniprohydroenergo (DHE), a joint stock company that includes the hydropower plants on the Dnieperriver. During negotiations, the delegation confirmed that the loan proceeds would be on-lent to thebeneficiaries. The subloans would have a maturity of 1 7years includingfive years of grace. The interestrate in the subloan agreements would be equal to the World Bank's standard variable interest rate plusa margin of 1. 5 % to cover the cost of loan administration. The foreign exchange risk will be borne bythe 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$10.5 million to finance partof the cost of the hydropower rehabilitation component and related technical assistance services. Theproceeds of the Swiss grant (except the technical assistance component) will be on-lent to DHE at termsthat are similar to the terms in the above subloan agreements. The Government of Canada will providegrant financing for technical assistance for project preparation, procurement and project implementationfor the first year (1995), in the amount of US$ 1.8 million. The Government of Norway will financethe water management component of technical assistance in the amount of US$0.6 million, also on a grantbasis. DHE and NDC will finance the remaining costs, part of interest during construction, and thecommnitment fee, estimated at US$88.3 million equivalent, from internally generated revenues. Financingarrangements are shown in Table 2.2.

18 The Project

Table 2.2 Financing Plan

7 V 0 00 T | Islmlion US$lmilllon _________ % 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 theMinistry 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 nominalprice of electricity increased almost 50 times (on average) in 1993, when expressed in a convertiblecurrency, the price remained very low (see Table 3.1). Significant real increases occured in 1994 andearly 1995, almost fully eliminating the gap between the average price (UScent 2.5/kWh equivalent inMarch 1995) and the economic cost of electricity (estimated at UScent 3.0/kWh)'. The prices cover theoperating cost of the industry, and the difference between the average price and the economic cost ismostly 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 52,000 125,000Price 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) undera 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 varysignificantly from one hydropower company to the next, reflecting differences in capital costs andsocial/community infrastructure. Minenergo adjusts rates for the sale of hydropower to NDC on amonthly basis. The cost of hydropower constitutes a small item (less than 1 %) in the overall retailelectricity tariff. In March 1995, NDC's average cost of purchasing power from the hydropowercompanies was Krb 542/kWh (UScent 0.5/kWh equivalent). NDC paid Krb 1,860/kWh for the outputof nuclear plants, and sold the electricity purchased from the nuclear and hydropower plants to the eightregional associations at a price of Krb 1,900/kWh. The regional associations combined this with theelectricity 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 electricityprices were set at Krb 3,500/kWh for urban, Krb 3,000/kWh for rural households, and Krb 2,300/kWhfor households who rely on electrical stoves and space heaters (see Table 3.2). Several categories ofhouseholds (e.g., veterans, Chernobyl victims) are entitled to substantial discounts. The tariff for ruralhouseholds and electric stoves/heaters inverted the cost structure, since the supply of electricity tohouseholds is generally more expensive due to a number of factors (e.g., household consumptioncoincides with peak demand, higher distribution losses, etc). Additional distortions are caused by the lackof time-of-day, seasonal and regional differences in electricity prices (only the capacity charge for largeindustrial consumers differed regionally).

1 The low economic cost (in international comparison) is explained by (i) decreasing electricity demand resulting insurplus 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 2.8Electric stoves and heaters 3.3 1.8Agriculture 3.0 2.2Industry (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 2.5discounts)

* 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 bythe market by the end of 1995. Building on the existing national dispatch operation, the wholesaleelectricity market (Energomarket) will allow thermal generators to submit bids for the sale of electricityto the "pool" in each hour of the day. Those bids will be accepted which allow demand to be served atminimum cost. A national wholesale price for the electricity generated by thermal plants, equal to thehighest accepted bid plus a margin ("uplift") to finance the operating cost of NDC, and certain othercosts, will be formed each hour, and charged to the local electricity companies and to those largeindustrial consumers, who participate in demand side bidding and purchase electricity directly from thepool. All entities who purchase from the "pool" will pay an additional transmission fee based on the costof 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 ofcontracts that will ensure the optimal dispatch of their capacity and full recovery of their costs. Localelectricity companies will be allocated a share of this low cost electricity. The operation of the wholesalemarket, the prices paid to the nuclear and hydropower companies, and the formulation of retail electricityprices will be regulated by the National Electricity Regulatory Commission (NERC) that was establishedin December 1994.

B. Past Financial Performance of the Implementing Agencies

3.6 National Dispatch Center. NDC is the sole purchaser of output from Ukraine'shydropower and nuclear plants. This output is resold to Ukraine's eight regional power companies, whocurrently engage in both distribution and thermal power generation, and to a few large industrial concernsthat purchase power directly from NDC. NDC's resale tariffs are determined by Minenergo and reflectcertain cross-subsidies that cause tariffs to vary from one regional company to the next. Overall, NDC'saverage resale tariff is designed to cover its cost of service -- a goal that has not been fully achievedduring the recent years of high inflation and accumulating payment arrears. Had NDC been collectingits accounts receivable in a timely manner, its resale tariffs would have been adequate and it would bein a stable financial position today.


3.7 NDC's revenue stream depends almost entirely upon payments by the regional powercompanies (Energos). These companies are in serious financial difficulty and have amnassed substantialarrears to their suppliers, including NDC. Accounts receivable at the end of the third quarter of 1994were approximately US$49.5 million at the then-applicable exchange rate of 68,000 Krb/US$. Theaverage age of NDC's receivables is about 60 days, down from 96 days in 1993. This improvement wasentirely attributable to inflationary devaluation of receivables. Many of NDC's outstanding 1994receivables were recorded when the exchange rate was around 45,000/US$, and the company had, as ofSeptember 30, 1994, suffered an economic loss of over US$25 million from the devaluation of itsuncollected receivables. Accounts receivable make up more than 99% of NDC's current assets; cashbalances in bank accounts are only about US$ 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 weresubstantially 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 daysversus 60 days in 1994). Roughly 2.5% of NDC's current liabilities reflect amounts owed to hydropowerstations; 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 laggedbehind 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 beenpaid in a prompt manner since 1992. Because of high inflation, deferred paymentseffectively spelled non-payment, given a legal framework that prevented the applicationof interest charges and penalties to unpaid customer balances.

3.10 Hydropower plants. The hydropower plants had a relatively modest cash-flow problemalmost entirely attributable to delayed payments by NDC. The cumulative US$0.5 million receivableowed by the NDC as of September 30, 1994 represented about 13 % (or 45 days) of the annual revenuestream of the hydropower companies, constraining their ability to finance essential maintenance andinvestment. Accounts payable, the only current liabilities of the hydropower companies, were below theamount that the NDC owed to them. Hydropower output is seasonal, with revenue collectionconcentrated in the first half of the year, whereas costs are incurred more evenly over time. Thus thereis a risk of a revenue shortfall when costs continue to experience inflation that has not been adequatelyreflected in prior months' rate-setting process. Minenergo was able to counter this problem in 1994through monthly tariff adjustments that recovered the actual costs over whatever volume was producedin 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.


C. Future Financial Performance of the Implementing Agencies

3.11 Financial projections for Dniprohydroenergo and NDC for the period 1995-2001 havebeen prepared and are presented in summary form in Tables 3.3-3.8, and in detail in Annex 6. The keyassumptions include:

* the general rate of inflation in Ukraine will be 90% in 1995, 34.5% in 1996, 19.6% in1997, 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 electricitygeneration 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 isexpected to ensure the full recovery of operating costs, safety improvements, thecompletion of ongoing investments, and financing of the decomissioning of the Chernobylplant);

* following the completion of the proposed project, the hydropower plants will need togenerate 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 fromthe regional companies, NDC (Energomarket) will purchase all output from the newgenerating companies applying market-based (marginal-cost) pricing after mid-1995. Theaverage price of thermal power will be US$0.020/kWh in 1995, gradually increasing toUS$ 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


3.12 Based on these assumptions, in order to generate enough funds to cover the local costsof the project, the projected price of hydroelectricity (approximately Krb 480/kWh in 1995) would haveto increase to Krb 935/kWh in 2000, equivalent to less than UScent 0. 1/kWh throughout the projectperiod, based on the forecast exchange rate for those years. The price of electricity sold by NDC hasalready been increased from UScent 0.4/kWh in 1994 to UScent 1.52/kWh; for the year as a whole theaverage price would have to be increased to UScent 1.91/kWh (most of this increase represents increasesin the costs of power, as well as a provision for bad debt, an increase in working capital, and thefinancing needed for the local cost of investments). The average price of electricity sold by NDC isprojected to increase only 8% in dollar terms between 1995 and 2000. The project would lower the costof electricity production following its completion in the year 2000, thereby reducing retail electricityprices 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


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 affectedby (i) the price it receives for electricity; and (ii) its collection ratio. Even after the reform of the powerindustry is implemented, hydropower plants will be obliged to sell their output under long term contractsat cost-based (below-market) tariffs. There is no substitute for the essential services such as frequencycontrol 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. Dueto Ukraine's special problems with payment discipline, this guarantee should encompass provisionsensuring timely payment. During negotiations, it was agreed that the contract between NDC andDniprohydroenergo would include the following (para. 6.1. b):

* a cost-based tariff formula that (i) includes the regular adjustment of cost data to reflectinflation; (ii) compensates for seasonal and annual fluctuations in hydropower output dueto external circumstances; (iii) ensures that sufficient funds are available to finance thecost of agreed investments (including the proposed project); and (iv) encourages efficientoperation and maintenance of the hydropower plants; and

* a guarantee of prompt payment within 20 days of billing, backed by an interest penaltyif delay occurs. The interest penalty will be calculated applying the National BankRefinancing 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. Thusthe hydropower plants' current problems could be fully resolved in the near term without substantiallyaltering NDC's financial position. A one-time resolution of NDC's outstanding trade debt for hydropowerwould be a condition of loan effectiveness (para. 6.2. c).


3.15 In the medium term, a more fundamental solution that addresses the underlying problemof non-payments to NDC will be required, including appropriate provisions in NDC's resale contractsas 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 itsdownstream purchasers would include the following terms (para. 6.1. c):

* NDC will be entitled to charge an interest penalty on accounts receivable that becomepast due (i.e., not paid within 20 calendar days of receiving the bill). This penalty willbe based on the National Bank Refinancing Rate. These penalties shall be immediatelydue and payable at the time they are assessed, and shall be entitled to the same priorityof collection as any other account receivable; and

* NDC will be entitled to make proportional reductions in deliveries to customers who havenot settled their accounts in full within 30 days of billing. Specifically, on the 20th dayafter billing, NDC (Energomarket) will notify such customer that (i) his account is pastdue and interest penalties have begun to accrue; and (ii) specify the portion of deliveriesthat are liable to termination unless full payment (including accrued interest penalties) ismade. 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'spast-due account, including interest penalties, is settled in full. Contracting parties willagree that NDC (Energomarket) shall be held harmless for any damages, of whatevertype, resulting from a proportional cutback that has been carried out in accordance withthese stated conditions.

3.16 These provisions are expected to make it feasible for NDC to reduce both its accountsreceivable, and the delay when paying its suppliers. During negotiations, it was agreed that (i) ADC'sdelay in paying its suppliers would be reduced to 45 days in 1995, 30 days in 1996, and 20 daysthereafter; and (ii) NDC's accounts receivable would not exceed 60 days in 1995, 40 days in 1996, 35days 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 forexplicit recognition of bad debt. During negotiations, the Bank and the delegation agreed that the pricesetting mechanism would allow the National Dispatch Center to recover an allowance for bad debt in itsresale tariffs, currently estimated at 10% of revenue in 1995, 7.5% in 1996, 5% in 1997-98, and 2.5%


thereafter (para. 6.1. e). A similar provision will not be needed in hydropower tariffs, as the contractbetween 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 feasiblefinancing plan, an agreement was reached during negotiations that NDC and Dniprohydroenergo eachwould generate for every financial year beginning in 1996 sufficient internal funds to cover not less than40% 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 thatDniprohydroenergo and NDC are capable of servicing their total borrowing requirements, it was agreedduring negotiations that Dniprohydroenergo and NDC would maintain a debt service coverage ratio ofat 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 projectimplementation even though tariffs stay fairly constant in dollar terms. This is in part a reflection of theforecast 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 paymentswill become realized in 1996, significantly increasing the company's cash flow and allowing for apermanent increase in working capital. Faster than expected reduction of NDC's accounts receivable in1995 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 orderto determine whether it was in Dniprohydroenergo's financial interest to undertake the proposedinvestments. The estimated after-tax Financial Intemal Rate of Return (FIRR) on incremental financialcash flows -- defined as the difference between the "with" and "without" project situations and expressedin current US dollars -- is 16 %. Details of the FIRR calculations, including the assumed electricity pricesand taxes, are provided in Annex 7. There was no financial analysis carried out for the system controlcomponent, 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, thecontracts between NDC and its downstream customers are expected to ensure the full recovery of theinvestment costs of this component.


E. Economic Costs and Benefits

3.21 An economic evaluation, based on incremental costs and benefits, was performed for eachsubcomponent and then aggregated for the two main components and the project as a whole. Thesummary 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 taxesand subsidies. The discount rate assumed for the economic analysis is 10%. The evaluation period is1995-2020.

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 assistancecomponents for which no benefits were quantified.

3.22 Hydropower Rehabilitation Component. The least cost investment analysis presentedin Annex 3 suggests that there is a lack of peaking capacity in Ukraine, and preserving the existingpeaking capacity is of high priority. In order to analyze the economic viability of hydropowerrehabilitation in more detail, Net Present Values and Economic Internal Rates of Return (EIRR) werecalculated by comparing the economic cost and benefit streams of a "with project" and a "withoutproject" case. The "without project" case assumes continued operation of the units at a progressivelydeteriorating level of efficiency and availability. The plant operating parameters for the two cases andother assumptions are presented in Annex 8. The main quantified benefits are: (i) improvements in theefficiency of turbines and generators; (ii) reduction in operating and maintenance costs as a result ofbetter instrumentation and plant control; and (iii) improvement in plant reliability and availability throughthe 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 thescenario where no rehabilitation is undertaken, equivalent to 5.5 % of the average production of the plantsin 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 rangefrom 11 % to 31 %, indicating that the proposed rehabilitation is economically viable for each plant (seeTable 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 greaterefficiency in the loading (automatic economic dispatch) of power units and improved power flow in thesystem. As a result of the upgrade of communications, dispatch and system control, about 11,000 MWof thermal capacity will become available for more efficient dispatching. These benefits wereapproximated by cost reduction resulting from fuel savings. Since the proposed upgrade measuresrepresent a significant advance over the present system, fuel savings are expected to be substantial. Forthe 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 thiscomponent was estimated at 22.7%.


Table 3.10 Measures of Net Economic Benefits by Individual Plant

Total EnergyIncrease in

PLANT NPV ($M) EIRR (%) 1995-2020 (GWh)Kiev PSP 0.2 10.7 362Kiev HPS 5.1 12.6 2,891Kanev HPS 1.5 30.5 199Kremenchug HPS 10.1 24.1 1,806Dniprodzerzhinsk HPS 9.8 24.6 1,782Dnieper I HPS 14.9 17.1 3,818Dnieper 11 HPS 1.5 13.0 599Kakhovka HPS 11.7 18.3 2,729Total for 9 plants 54.8 17.0 14,186

3.24 Non-quantified Benefits. The above-quantified benefits are regarded as a minimummeasure of the true economic benefits conferred by the project. Additional, non-quantified benefits ofthe 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 turbineblade seals and reduced risk of flooding as the monitoring of dams improves; (iii) plant safetyimprovements resulting from the upgraded instrumentation and control system; and (iv) consumer surplusassociated with incremental electricity sales. Non-quantified benefits from the system control componentinclude: (i) increased stability and security of the power system, which reduces unserved energy (due tofewer blackouts and faster restoration of service); (ii) improved frequency control, which extends thelifetime of rotary equipment connected to the network, and enhances the safety of nuclear plants (hightrequency fluctuation causes structural damage to rotating equipment, including safety-related equipment,thus potentially compromising operational safety); and (iii) facilitation of Ukraine's future interconnectionwith 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 (proxiedby 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 thehydropower component); (iii) a 10% decrease in the amount of fossil fuels saved (for the system controlcomponent); and (iv) all of the above. Additionally, switching values (values at which the NPV is zeroand the EIRR is 10%) were calculated for investment costs (for both components), electricity price (forthe hydropower component), and fuel savings (for the system control component). The results arepresented in Table 3.11. Project economic returns are very robust relative to the indicated variations inkey project parameters. The switching value analysis suggests that project costs do not pose a significantrisk because both components remain economic even in the face of considerable overruns in investmentcosts. The hydropower rehabilitation component remains economically viable even at 58% of theassumed economic value of electricity. Due to the high base-case level of economic returns, the systemcontrol component retains economic viability even when fuel savings amount to 41 % of the level assumedfor the base case.


Table 3.11 Sensitivity Analysis

Component/Project EIRR (%)l ~~~~Impact Assessedl

Impact Assessed Hydropower System Project TotalRehabilitation 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 millionb/ From US$ 64.7 million to US$ 135.9 millionc/ From US$ 174.4 million to US$ 313.8 milliond/ 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 localinvestment costs.

30 Implementation

IV. IMPLEMENTATION

A. Institutional Arrangements

4.1 Implementation of the project will be the responsibility of the beneficiaries, i.e., therecently formed joint stock company Dniprohydroenergo and the National Dispatch Center (NDC). Thefive 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 aresolution for the consolidation of the regional dispatch centers under NDC by mid-1995. Duringnegotiations, it was agreed that the transfer of ownership of the regional dispatch centers to NDC wouldbe a condition of loan effectiveness (para. 6.2.d). The consolidation is not expected to result in majorchanges (traditionally, NDC has been responsible for the operational control of the regional dispatchcenters). Although it is expected to remain a 100% state owned enterprise, the role of NDC will changesignificantly when it becomes the commercial (as well as operational) center of the Ukrainian PowerSystem. As Energomarket, it will purchase pratically all electricity from the generators, and sell it tothe 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 powerutilities, organized into six enterprises, and placed under the direct supervision of Minenergo. The sixenterprises formed a Hydropower Association. The Association was not a commercial entity, but a forumthrough which certain activities were coordinated among the hydropower plants. It did not have its ownaccounts, budget, nor (full time) employees. In early 1995, five out of the six enterprises were combinedinto Dniprohydroenergo, a joint stock company that is 100% owned by the state. The following fiveenterprises became part of Dniprohydroenergo (the number of employees in parenthesis): Mid-DnieperCascade (1,168), Kremenchug (204), Dniproderzhinsk (323), Dnieper (292) and Kakhovka (120). TheMid-Dnieper Cascade included the Kiev HPS, Kiev PSP and Kanev HPS, the Dnieper enterprise includedDnieper I and Dnieper 1I HPS (the other three enterprises were named after their plants). The sixthenterprise 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 economicanalysis, accounting, and personnel report directly to the Director. The Chief Engineer is in charge ofall technical activities related to the operation of the plant, and typically supervises production anddispatch, technical and operational divisions, and turbine, hydroelectrical, and electrical shops. "Supportservices and production" includes the procurement division, transport and security, and often involvesome 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 individualhydropower enterprises, but also assumed certain new functions. One of them that is of particularimportance to the project, investment planning, has previously rested with Minenergo. Although theMinistry retained a strategic planning function, Dniprohydroenergo is in the process of establishing anindependent planning capability. The individual hydro plants retained a significant part of their existingorganizational structure, at least for some time. However, most of their staff performing functions thatare to be carried out at the corporate level (financial management, accounting, procurement, investmentplanning, 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 throughits Department for Capital Construction, and Ukrhydroproekt, an engineering organization which alsobelonged to Minenergo's structure. Ukrhydroproekt, with 700 employees, has been in charge of allengineering design work for the previous hydropower projects. It will have a similar role in this projectas well, serving as the main local engineering and project management consultant to Dniprohydroenergoand 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 12departments (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 andCollection, Government Audit, Maintenance, and Support Services. After the consolidation of theRegional Dispatch Centers under NDC, NDC will take over most of the employees from the existingeight regional power utilities who work at the Regional Dispatch Centers. It is expected that the numberof people transferred will be under 100 per region.

4.7 The dispatch and system control component of the project includes the purchase andinstallation of several types of equipment (turbine governors, data acquisition, communications,computers, software). The existing engineering systems at the dispatch centers were developed anddesigned in the central institutions of the FSU. Some of them are no longer present in Ukraine, whichhas led to loss of information and engineering know-how. Although there are local engineeringorganizations with expertise in most of the equipment categories, there is no organization which couldcover the entire range of issues, perform engineering work and provide counsel on integrated systemsin power system control. This role will be performed by an international consultant under the technicalassistance component of the project.

4.8 Project Coordination. A Project Coordination Unit (PCU), headed by a ProjectCoordinator appointed by Minenergo, will be in charge of overall project coordination. The PCU,located in Minenergo, will coordinate project preparation activities, technical assistance, scheduling (tothe extent that it requires coordination between the hydropower rehabilitation and the system controlcomponents), reporting, training, and other aspects of project implementation requiring coordinationbetween the two project implementation units (see para. 4.9). The Project Coordinator will report toMinenergo, and serve as a liaison to the Ministry of Finance and the Bank for project activities. He willestablish project communication and documentation procedures, oversee preparation of bid documents,arrange appointment of bid evaluation committees, coordinate bidding and contracting, arrange for auditsof project accounts, and organize training in project management, project financial operations andprocurement.

4.9 Project Implementation. Two Project Implementation Units (PIU) will be set up withresponsibilities to manage implementation of the hydropower rehabilitation (including dam safety) andthe system control components. The PIUs will be responsible for managing the engineering aspects ofproject implementation (preparation of bid-level design specifications, supervision and approval ofmanufacturers' detailed design, inspection in manufacturers' facilities, construction supervision, qualitycontrol, system checkouts and integration in factory and on site, factory and field acceptance tests), aswell 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 eachcompany (Dniprohydroenergo and NDC) will manage the respective Special Account. The managers ofthe PIUs will have the authority to clear payments to suppliers and contractors, after authorization fromsite 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. Themanagers of the PIUs will be appointed by the Dniprohydroenergo and NDC, and will also have the titleof Deputy Project Coordinators of the PCU. The Deputy Project Coordinators will report to the ProjectCoordinator and to the Director of the company that appointed them. During negotiations, it was agreedthat 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 andDeputy 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 beimplemented. The site managers, appointed by the managers of the respective facilities, will serve asliaisons between management of the facilities and the corresponding PIUs. They will participate inmonthly review meetings with the PIUs, attended by concerned project staff, to review progress, addressimplementation issues and authorize payments to suppliers and contractors. Site implementation will behandled within the existing organizational structure of the concerned facilities.

4.11 Installation of equipment will be the responsibility of the respective facilities (hydroplants, dispatch centers, thermal plants and substations), which will use their force account andspecialized local construction and installation companies, under the guidance of the supplier (to beincluded in the tender documents), with additional assistance from the international consultants providingTA for project implementation. The supplier will supervise the erection and provide the necessarytraining, and will assume responsibility for the performance of the equipment. There is sufficient localcapability to perform the installation. Hydroelectromontazh, with 500 employees, which specializes inerection and installation of electrical equipment, has been the main contractor for this type of work to allUkrainian hydroplants. Another company, Spetshydroenergomontazh, with 800 employees, specializesin installation of turbines and generators. Both companies have gained international experience througha number of projects in non-FSU countries. Equipment installed at the Dniester hydropower plant, thethermal power plants and substations will be owned by the National Dispatch Center and leased to theplants and the transmission company. The installation and maintenance of the equipment will be theresponsibility of the thermal plants and the tramsmission company.

4.12 Technical assistance (TA) activities for the project have been subdivided into the followingcomponents: (i) engineering design; (ii) procurement; (iii) project management; and (iv) watermanagement study. International consultants will be hired to assist local consultants and the ProjectManagement and Implementation Units with all TA components. The TA activities will be coordinatedby the PCU, which will sign and manage TA contracts both with intemational and local consultants. Thefirst three TA activities (engineering design, procurement, and project management) have started inJanuary 1995, and for the first year (1995) will be financed by the Canadian Government and performedby a Canadian consortium. During this year, emphasis will be on assisting Dniprohydroenergo and NDCin preparation of tender documents (including engineering design specifications), bid evaluation, contractnegotiations, and with other procurement issues. The activities of the consultants during this stage willalso include assistance in organizing the project management and implementation units, projectadministration, planning and scheduling. A substantial involvement of international consultants will beneeded 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, projectdocumentation, reporting, cost accounting). International consultants will be needed throughout the entireproject implementation period, although their involvement is expected to be much reduced after thesecond year. In case grant financing for TA activities after 1995 could not be secured, the foreigncomponent 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 thestaff of the companies assigned to the project. The international consultant providing TA for projectimplementation will assign an Assistant Project Coordinator, reporting to the Project Coordinator, on afull-time basis. The international consultant providing TA for procurement activities will assign aProcurement 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 inprocurement, project management, financial management and quality control for project management andimplementation staff at PCU, PIUs and elsewhere (as needed) will be organized by internationalconsultants, in cooperation with the Project Coordinator, during the initial stages of project preparationand implementation.

4.14 The technical assistance related to the management of the reservoirs on the Dnieper riverwill be financed entirely by the Norwegian Government. This activity is expected to start by the end of1995 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 beDniprohydroenergo.

4.15 The technical assistance program (see Section I.E) supporting the implementation ofDecree 244/94 includes a number of institution building activities targeted at the beneficiaries of theproject. Dniprohydroenergo is receiving support for corporatization and development of organizationalstructure, internal reporting, financial management, budgeting and planning. The establishment ofEnergomarket on the basis of NDC is also supported, including the preparation of EnergomarketMembers Agreement, bidding procedures, price formation software, dispatcher's manual and software,and settlement procedures. Consultants are providing assistance for the preparation of contracts betweenEnergomarket and the nuclear and hydropower plants. A detailed study is scheduled to start in April thatwill assess the metering and commnunications requirements for the operation of the "pool". Thesetechnical 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 beimplemented over a period of 5 years and is expected to be completed by June 30, 2000. Therehabilitation of turbines is on the critical path of the implementation of the hydropower rehabilitationcomponent. Installation of switchyard equipment, control and monitoring equipment and dam safetysystems, as well as system control and monitoring components, is expected to proceed without difficultiessince it involves work at existing sites. Consulting services under the technical assistance componenthave started in January 1995, so that project implementation can proceed expeditiously after the loanapproval. 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 2packages 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 theBank Loan will be procured according to the Bank's Guidelines for Procurement under IBRD Loan andIDA Credits (1992). Contracts for equipment and goods estimated to cost more than US$300,000 willbe 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 prevailingcustom duty applicable to non-exempt importers (whichever is less) in bid evaluation, provided that theycan prove that value added to the product in Ukraine equals to at least 20% of the ex-factory price of thebid. The preference shall be applied in accordance with the provisions contained in Appendix 2 of theGuidelines. Small contracts for goods, US$300,000 equivalent or below, with an aggregate limit ofUS$1.5 million, may be procured through international shopping, after obtaining a minimum of threeprice quotations from at least three eligible countries. Direct contracting up to an aggregate amount ofUS$1.0 million may also be allowed, if the procedure is justified (e.g., for items of proprietary natureor items required to ensure compatibility with the already installed equipment, for spare parts availableonly from the original supplier, etc.). Total amount of goods purchased through international shoppingand direct contracting will not exceed US$2.5 million (less than 3% of the Bank Loan available forequipment and goods). List of goods to be purchased under these two procedures will be subject to priorreview by the Bank. Consultants, to be employed under the technical assistance component of the loanif bilateral funds are not available, will be selected according to the Bank's Guidelines for Use ofConsultants 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 Table4.1.

4.18 Project implementing agencies in Ukraine have very limited knowledge of internationalcommercial practices and the Bank's procurement procedures. Procurement teams will be establishedwithin the Project Implementation Units, and will receive training during the early stages of projectimplementation, both from the Bank and from the consultants engaged under the technical assistancecomponent. To ensure compliance with the Bank guidelines, the following documents will be subject toprior review by the Bank: draft tender documents, bid evaluation reports and recommendations for awardsof contracts, for all ICB procurement (US$300,000 and above) and all Bank-financed contracts awardedunder direct contracting/negotiation (covering about 98% of the total value of Bank-financed equipmentand goods); list of goods to be purchased through international shopping financed by the Bank; terms ofreference for all consulting contracts; all consulting contracts financed by the Bank above US$100,000for firms, and above US$50,000 for individual consultants. All other contracts will be subject to ex-postreview.

4.19 The rehabilitation of turbines, stator and rotor windings and magnetic stator core forgenerators are expected to be financed from local sources and procured by direct contracting withdomestic suppliers, Turboatom and Elektrotyazhmash. The Turboatom factory, producing turbines, hasabout 10,000 employees, of which 2,500 have university degree. It has delivered turbines to more than160 plants in 26 countries. The generator factory, Elektrotyazhmash has about 8,600 employees, ofwhich 2,140 are engineers. It has a long list of reference plants in more than 30 countries. The contractswill contain sufficient guarantees for timely delivery of the contracted equipment and services,performance, provisions for inspections and tests, pricing and warranties. The equipment under thesecontracts, although not financed by the Bank, is critical for the overall project implementation andoperational performance. It was agreed during negotiations that Dniprohydroenergo would sign suitablecontracts, 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 TotalProject 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 wouldfinance 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 onNov. 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 theissuance of bidding documents, individual bidding opportunities will be advertised in a major localnewspaper. The project agencies would also be expected to advise known eligible and qualifiedtraditional suppliers.

4.21 Procurement information will be collected by the PCU and reported to the Bank asfollows:

(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 bestestimates of allowances for physical and price contingency;

* revised timing of procurement actions, including advertising, bidding, contractaward, 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 rulesand 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 ProcurementAssessment 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 thefollowing 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 localexpenditures 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 theimplementation plan of the project components (Annexes 5 and 9); a more detailed disbursement scheduleis presented in Annlex I 1. The disbursement profile follows broadly the standard disbursement profilefor energy projects in the Europe and Central Asia Region. The Closing Date for the proposed loanwould 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 3.3Cumulative (%) 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$300,000 equivalent, consultingfirms under contracts not exceeding US$ 100,000 equivalent, and individual consultants not exceedingUS$ 50,000 equivalent would be made against statement of expenditures (SOE) in order to assist theborrower in making timely payments. The supporting documentation for these contracts would not besent to the Bank, but would be retained by the borrower for inspection by supervision missions and byexternal auditors. All other disbursements would be fully documented. The minimum size ofapplications 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 conditionssatisfactory to the Bank to cover the Bank's share of expenditures. The authorized allocation to theDniprohydroenergo's Special Account would be US$2.0 million, and to the NDC's Special AccountUS$2.0 million, representing about four months of average expenditures effected through the SpecialAccounts. At the request of the Borrower and, based on project needs, the Bank would make initialdeposits 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 hasbeen withdrawn, whichever occurs earlier. Documentation requirements for replenishment would followthe usual Bank procedures. In addition, monthly bank statements of the Special Accounts which havebeen reconciled by the Borrower would accompany all replenishment applications. During negotiations,agreement was reached on the arrangements for establishmett, operation and auditing of the SpecialAccounts (para. 6.1.i).

E. Accounts and Audits

4.27 Ukraine's electricity enterprises follow standard Soviet accounting procedures, which havebeen augmented as required by the administrative reporting requirements of the many government bodiesto which they report. The financial accounting standard now in use is not adequate for providing reliablemanagement and regulatory reports. Revenues are reported on a cash basis, when received, and costsassociated with producing revenue are not booked until such time as revenues arrive. When accountsreceivable 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 ona 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 requiredby Ukrainian law, the beneficiaries will maintain a parallel system of financial statements (incomestatements, 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 regulatoryreporting that will be required by the National Energy Regulatory Commission. They also will serve asthe basis for calculating interest penalties to be provided for under their new contracts, and for monitoringprogress in improving the timeliness of payments and collections. Financial statemnents will be auditedby an auditor acceptable to the Bank and the audit reports submitted to the Bank within six tmonths of theend of each financial year (para. 6.1.j).

4.28 The accounting for all Special Account transactions and for all other project-relatedaccounts will be maintained in accordance with international accounting standards. Annual financialstatements of IBRD-financed components will be prepared and audited in accordance with InternationalAuditing Guidelines by suitably qualified independent auditors acceptable to IBRD, and submitted toIBRD within six months of the close of the GOU fiscal year. Audits will also be carried out, at the sametime, and for corresponding periods in accordance with the Bank guidelines, for SOEs against whichdisbursements have been made or are due to be made out of the credit proceeds, and specific referenceto the Special Account (SA) and SOEs will be made in the audit reports accompanying the financialstatements. During negotiations, agreement was reached that the implementing agencies would submitto the Bank the audit reports and auditedfinancial statements for the Special Account, project accountsand SOEs for the every fiscal year, not later than six months after the close of such year. Agreement wasalso reached that auditors acceptable to the Bank would be retained to review the accounting systems andsupporting internal procedures and practices for the Special and project Accounts and SOEs, andrecommend any needed changes (para. 6.1. i).

F. Monitoring and Evaluation

4.29 The Project Coordination Unit will prepare semiannual and annual project progressreports. The progress reports, following clearance by the Borrower, will be submitted to the Bank. Theprogress 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, andproject 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 loaneffectiveness.

4.30 The Borrower will submit a mid-term progress report, covering all components of theproject, no later than June 30, 1997. In addition to the topics covered by the semiannual reports, themid-term report will include an assessment of the status of loan covenants, overall institutionalperformance of the companies-beneficiaries, and evaluation of the project based on a set of performanceindicators (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 betaken to ensure the efficient completion of the project. The timing of the mid-term review and theperformance 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 promptlyafter the completion of the project, but no later than 6 months after the Loan Closing Date. The ICR willdiscuss execution of the project, its costs and benefits, the performance of the borrower, the World Bankand other agencies involved, and lessons learned. The ICR will also contain evaluation of the projectperformance indicators.

4.32 In addition to the review of procurement actions, semi-annual reports and otherdocumentation, a number of supervision missions is planned. The project is expected to requiresupervision from the Bank at an average of 25 staff-weeks per year during the first two years ofimplementation, 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 about20 years. The operation of the rehabilitated plants is not expected to pose a technical challenge for thewell-educated, experienced staff working at the plants. The hydropower plants will continue to be thelowest cost electricity generators in Ukraine, ensuring the long term financial viability ofDniprohydroenergo. NDC, as the future Energomarket, will play a key role not only technically, butalso 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") tothe price of electricity it sells to local electricity distributors/suppliers. The facilities installed by theproject 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 beprovided to NDC staff in the operation and maintenance of the modernized communications, systemcontrol and dispatch facilities. A large donor funded institutional building effort that has been mobilizedin support of the power industry reform will provide the necessary training for NDC's commercialfunctions. Suppliers will provide training the necessary training for the maintenance of the equipmentthey supply and guarantee delivery of spare parts, both for Dniprohydroenergo and NDC. The operationplans 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 Governmentwould be unwilling to (i) adhere to the agreed pricing formula for the electricity produced by thehydropower plants; and (ii) implement a strict regulatory policy to prevent the further accumulation ofpayment arrears. These could seriously undermine the financial position of the Dniprohydroenergo andNDC, and thereby endanger the implementation of the project. The reform of the power industry basedon Decree 244/94 is expected to decrease these risks, but cannot eliminate them. The implementationof the reform itself is subject to political risks. Risks arising from the pricing of electricity have beenaddressed 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 beenaddressed by requiring appropriate contractual arrangements, including the reduction/termination ofservice in the case of non-payment. The beneficiaries' inexperience in implementation of Bank projectsposes additional risks. Inferior performance of domestic equipment and domestic supply constraints couldalso delay project execution and affect the quality of work. These risks have been addressed through thecareful planning of activities that are on the critical path, and by providing technical assistance to thePIUs in procurement, supervision and quality control. Economic returns are very robust relative tovariations in key project parameters. A switching value analysis suggests that project costs do not posea significant risk because both major components remain economic even in the face of considerableoverruns in investment costs. The hydropower rehabilitation component remains economically viableeven at half of the assumed economic value of electricity. The system control component retainseconomic 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 ofhydropower plants, and the increased efficiency in the loading of hydro- and thermal power generationunits. Additional benefits are: (i) the increased security of the power system that will lead to fewerblackouts; (ii) the improved stability of frequency that will enhance nuclear safety; (iii) the betterenvironmental performance of the hydropower plants that will reduce the pollution of rivers; and (iv) theimproved 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 reachedon 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 thefull recovery of investment and operating costs (para. 3.13);

(c) Contract between NDC and its downstream customers, including the application ofinterest 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 inits 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 annualaverage capital expenditures expected (or actually incurred) for that financial year, theprevious financial year, and the next financial year; and to maintain a debt servicecoverage 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 generatormanufacturers by November 30, 1995 (para. 4.19);

(i) Arrangements for establishing, operating and auditing the Special Accounts for theproject (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 thanJune 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, andGoU 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 DeputyProject 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 5years grace. The Borrower would be Ukraine and the implementation agencies would beDniprohydroenergo and the National Dispatch Center.

ANNEX 1Page 1

UKRAINE

HYDROPOWER REHABILTIATION AND SYSTEM CONTROL PROJECT

ELECTRICITY DEMAND FORECAST

1. Due to the large uncertainty surrounding the course of future economic changes inUkraine, alternative electricity demand projections were prepared by the Bank. Scenario A assumes acomprehensive and radical reform process, including raising electricity tariffs to economic levels in thenear future and the strict enforcement of hard budget constraints for enterprises. By contrast, ScenarioB reflects very slow-paced reforms and restructuring, meaning that the completion of price adjustmentis much deferred and enterprise budget constraints remain soft. Importantly, the pressure on enterprisesto restructure towards a less electricity-intensive product mix and to use electricity more efficiently ismuch weaker in Scenario B than in Scenario A. Scenario C tracks a middle course between these twoextreme outcomes by portraying a gradual, steady progress towards a market-based economy.

2. Macroeconomic performance. In Scenario A, GDP recovers from the current slumpin 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, withan 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 theirproduct mix under any reform scenario. These shifts are assumed to benefit the less electricity-intensiveconsumer industries, high technology manufacturing and services at the expense of the presently oversizedheavy industries. The structural transformation proceeds at various speeds in the three scenarios, thefastest being in Scenario A and the slowest in Scenario B.

4. Electricity price adjustment. In Scenario A, industrial electricity tariffs rise to theeconomic level by the end of 1995, and the presently cross-subsidized tariffs (for households, communalservices, agriculture, etc.) reach the industrial level by the end of 1997. The shift to economic costlevels happens more gradually in the other scenarios.

5. Price responsiveness. Consumer sensitivity to changes in electricity prices correspondsto 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 weakersensitivity to costs, price elasticity is set at half of the above values.

6. Methodology. For the purpose of the quantitative projection, a dynamic consumptionmodel 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 (thefigures refer to gross consumption, i.e., they include station use and network losses; in recent years grossconsumption exceeded final, or net, consumption by about 20%). The recently experienced decline in

ANNEX 1Page 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 shockimposed 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 levelsout 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 1990consumption level is not reached even in 2010.

Projection of Electricity Consumptionto 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 1Page 3

8. Official Ukrainian demand forecast. The latest (May 1994) forecast prepared byMinenergo and approved by the Government, predicts the future course of gross electricity consumptionunder two alternatives. The low forecast differs from the high one on the assumption of efficiency gainsderived from the adoption of vigorous electricity conservation measures (in TWh):

1993 1995 2000 2005 2010l _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ (A ct)

Low forecast (enhanced 227.2 226.0 243.0 248.0 260.0conservation)

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 endof the projection horizon. The discrepancy is especially large for the medium term, largely because theofficial 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 arecomparable with the conservation-centric official forecasts.

ANNEX 2Page 1

UKRAINE


NUCLEAR SAFETY

1. Nuclear power in Ukraine currently provides almost 40% of electricity generation andrepresents 26% of installed capacity. The 14 Soviet-designed operating units include 10 pressurisedwater reactors of the VVER-1000 type, two older 440 MW units of the VVER 213 type, and two graphitewater reactors of RBMK-1000 type at Chernobyl. Four more VVER-1000 reactors are in an advancedstage 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 internationalcommunity. Especially serious doubts remain amongst international nuclear safety experts about thesafety 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 numeroussafety deficiencies in the two units which remain operational. Of particular concern are specific problemsin the design of the first generation Unit 1. These deficiencies include an insufficient emergency reactorcooling system and vulnerability to serious failures, particularly from fires, as a result of poor diversityand separation of electrical cables and equipment in the reactor control and protection systems. Unit 3is a second generation RBMK reactor having significant safety improvements. However, it is in anincreased radiation environment emanating from the neighboring destroyed Unit 4. Although planned,there is currently lack of safety-upgrading activities at Chernobyl. Only limited safety-enhancingmeasures 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 inadequateinstrumentation and control and weaknesses in management and training. In 1994, the lack of financingseverely constrained the ability of Goskomatom (the nuclear operator) to carry out maintenance and toundertake 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 anegative effect on safety. The price of electricity sold by the nuclear plants was substantially increasedin early 1995, alleviating somewhat the financing constraints.

3. In response to mounting domestic and international safety concerns following the fire inUnit 2, Parliament mandated that the Chernobyl plant should be closed by the end of 1993 and imposeda moratorium on the completion of new nuclear units under construction. In November 1993, as aconsequence of the deterioration in the country's energy supply, Parliament revoked the order andallowed continued operation as long as "technically feasible". Also, in February 1994 a presidentialdecree 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, inthe 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 lackof cooling water). The implementation of a program of measures to upgrade the safety of all operatingnuclear units is scheduled to start in 1995-96. And, as a matter of urgency, the construction of a new,

ANNEX 2Page 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 discusspossible early closure of the Chernobyl plant, provided that a satisfactory solution was identified, inparticular, for financing replacement nuclear capacity, closure costs, including the mitigation of the socialcosts of closure. In the dialogue with the G-7 Nuclear Safety Working Group, Ukraine suggested thatan international task force be formed from Ukrainian and foreign experts, including representatives ofthe relevant international financial institutions, with the task of preparing a comprehensive nuclear safetyAction 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 theChernobyl plant as an "urgent priority". The meeting outlined a broad sectoral Action Plan for theclosure of Chernobyl, including the early completion of three nuclear reactors (Zaporozhye 6, Rovno 4and Khmelnitsky 2) to adequate safety standards, comprehensive energy sector reformns, rehabilitation ofconventional power plants, increased energy conservation, and the use of alternative energy sources. TheG-7 offered to provide an "initial" amount of US$200 million in grants, in addition to the contributionoffered by the European Union (US$120 million in TACIS grants and US$480 million in long-term loansfrom EURATOM). Support from the international financial institutions and other donors was also calledfor.

7. The dialogue between the Ukrainian authorities and the G-7 continues, notwithstandinginitial Ukrainian reservations about the inadequacy of the financial package offered at Naples. The jointinternational 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 3Page 1

UKRAINE


LEAST COST POWER INVESTMENT PROGRAM

A. Methodology

1. A least-cost analysis of the Ukrainian power system (UPS) expansion alternatives for the period1995-2010 has been performed to assess future investment requirements of the system, and the type andtiming of new capacity additions needed. The main objective of the analysis was to investigate the needfor peaking units in the system, in order to assess the relative importance of the hydropower capacity asthe only peaking capacity present in the existing capacity mix. The analysis was carried out using theWASP computer program'. The general methodology imbedded in WASP is focussed on finding theleast cost power system expansion plan that matches projected electricity demand while maintaining thereliability of the system operation at a prescribed level. The model takes into account both maintenancerequirements and the operational reliability of generating units. The system costs include investmentcosts, financing costs during construction, fuel costs, operation and maintenance costs, and costs ofenergy not served.

B. Description of the Existing System

2. The installed electricity generationcapacity of the UPS was 52,122 MW in1993. It included 12,818 MW of nuclearcapacity, located in 5 plants with a total Figure 1.1 Capacity Mixof 14 units in operation. There weremore than 40 thermal (fossil fuel) power 4 >

plants with conventional steam cycletechnology, with over 110 generating X ch_ lunits and a total capacity of 32,364 MW, FNof which 3,824 MW were combined heat-and-power units. Hydro capacity was . U3I.dbi4,700 MW, stationed mostly in 9 plants awith a total of 100 generating units. Thecapacity of industrial power plants wasabout 2,240 MW. The total effectivegenerating capacity of the system was about 50,000 MW, due to the derating of older plants. Most olderfossil 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 3Page 2

firing. About 5,520 MW of power generation as well as most of the combined heat-and-power plantsrun on gas or mazut as main fuels. Figure III.1 shows the capacity mix of the existing system.

3. Electricity generation in 1993 was228,316 GWh, of which thermal plantsproduced 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 pumpstorage plant), and industrial plants 5,985

-. l l El 5 Ndww GWh (Fig. 111.2). Net export was 1,145GWh (2708 GWh exports, 1,563 GWhimports). 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 pumpstorage plant (302 GWh), andtransmission 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 26.3million tce of coal (Figure III.3).

4. Electricity generation, domestic consumption and exports have declined significantly in recentyears. Between 1990 and 1993, generation decreased by about 23 %, domestic consumption by 15 %, andnet 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 about1.95 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 variouscost components and parameters.

6. Electricity Demand. Electricity demand scenarios were prepared by the World Bank (see Annex1). To reflect the declining share of industrial consumption of electricity, the yearly load factors2 areassumed to decline gradually from the present level of about 0.73 to 0.65 by year 2010, remaining at thatlevel through the rest of the planning period. The maximum yearly loads were derived from the energyprojections (Annex 1) and the load factors assumption. In addition to satisfying the peak loads, thesystem 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 3Page 3

were not considered in the simulations performed3.

7. The system load is modeled by four load duration curves4: winter, spring, summer and fall. Forillustration, Figure 111.4 shows daily load profiles for winter and summer working days and Sundays forthe period July 1, 1992 - June 30, 1993. Figure III.5 exhibits yearly maximum and minimum monthlyloads for the same period.

8. Firm Commitments5 . The only unit assumed to be firmly committed was a 225 MW unit atDobrotvorsk, 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 thetraditional 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 limitedobjectives 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 isgreater than a given load level.

5f The WASP model handles units commnitted to future additions (these units, together with the existing unitscomprise what is in WASP terminology termed as "fixed" system) in a different manner than the candidateunits, i.e., its investment costs are not part of the objective function being minimized in the optimizationprocess, for obvious reasons (since they are committed, they are not part of the WASP's decisionprocedure). The term "candidate units" refers to units that are considered as candidates for systemexpansion.

ANNEX 3Page 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 recommissionedin 1996. It was also assumed that Chernobyl units 1, 2 and 3, with 1000 MW capacity each, would beretired in the 1997-2005 period. One thousand MW of nuclear capacity was assumed to be unavailablethroughout 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 cyclegas 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 and408 MW in pumping regime, with cycle efficiency of 0.7 and yearly generation of 492 GWh, wereconsidered in order to model the Dniester pump storage plant (PSP) as a candidate. The remaininginvestment costs for the Dniester PSP, taking into account that about 70% of civil works and 20% ofequipment was completed, were estimated at 227$/kW (of generating power), i.e., the cost of totalcompletion was estimated at US$ 514.8 million (in 1994 US$).

Figure 111.4: Daily Load ProfilesAQ~~~~~~~~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 $80/tcmin 2010, in real terms (in 1994 US$) with uniform growth rate over the period. The price of mazut wasincreased from $60/ton in 1994 to $75/ton in 2010, and the price of coal from $15/ton to $20/ton in year2000, 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 MWhelectricity produced.

13. Other assumptions. Given the current low level of maintenance activities and the need toimprove maintenance, the operating and maintenance costs were assumed to rise from their current levels

ANNEX 3Page 5

by 10% annually in real terms until 2000, and at 5% thereafter. The discount rate, used both forlevelizing 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 firnlycommitted 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 theprogran, 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. Theassociated total investment costs for the planning period, in constant 1994 US$ million (i.e., notlevelized), 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 asdescribed above are needed until 2008. The best solution (Case 2) is to commission all 7 units of theDniester PSP; in addition, 6 gas turbine units (5 in 2009, 1 in 2010) and four combined-cycle units (allin 2010) are added. If the Dniester PSP is excluded (Case 3), the number of combined cycle units in theoptimal solution increases to 9, while the number of gas turbine units remains 6. The presence of ratherinefficient, but less capital intensive gas turbine units in the optimal solution shows that the system needsadditional peaking capacity.

16. Although software constraints8 make the direct evaluation of the proposed project difficult, theresults of the least-cost analysis suggest that rehabilitation of the existing hydro plants is consistent withthe need to preserve and enhance regulating capacity. A similar conclusion should hold for the low-costrehabilitation of thermal plants that would increase their load-following capabilities and efficiency. Atthe same time, the presence of the capacity surplus throughout an extended period (until 2008 for themedium demand forecast) merits a closer examination of the retirement program. The retirement ofadditional units that are inefficient, expensive to maintain and operate, and would require significantinvestments 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), andthe cost of recomissioning Chernobyl 2.

8/ The constraints most relevant to this analysis are: (i) the modeling of hydro plants is fairly crude in theWASP; (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-dependentparameters can not be modeled. These constraints, among other things, may result in the later than optimalscheduling of the completion of pump storage units.

ANNEX 3Page 6

Figure m.5: Minimal and Maximal MonthlyLoad

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) werealso 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 determinethe optimal timing of the completion (other assumptions were the same as for Case 1). The USDOE/Ukrainian Working Group Report discussed three cases. In Case 4, which differ in the level ofsafety measures for the three units whose construction is most advanced, Z6 was completed as originallydesigned, 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 withlevel 1 and 2 safety upgrades, K2 and R4 were completed with level 2 safety upgrades, withcorresponding costs of 110, 303 and 313 US$/kW. Case 6 assumed level "3" safety upgrades for allthree units, with corresponding costs of 216, 439 and 449 US$/kW. It was further assumed that theChernobyl 3 unit would not be recommissioned, and the remaining two units would be decommissionedin 1996-1999, respectively, in all three cases. The following are the least-cost results indicating optimaltiming for completing the units:

Case 4 Case 5 Case 6

Z6 1995 1996 1996K2 1996 1998 2004R4 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 firstfigure includes completion costs and level 1 safety upgrades for K2 and R4, the second figure includes Liand L2 safety upgrades for Z6, and L2 safety upgrades for K2 and R4 (Ll upgrades for these two unitswere included in the completion costs); the third figure includes L3 safety upgrades.

ANNEX 3Page 7

18. In all three cases it was optimal to complete all units under construction, with commissioningyears depending on the level of safety upgrades, i.e., on the completion costs. Furthermore, in all threecases the least-cost plans contained installing 2 single-cycle gas turbines in 2009 and 3 in 2010, and onecombined-cycle gas turbine in 2009 and another one in 2010 (in addition to completing the nuclear units,as given above).

UKRAINE


Table 111.1 Existing and Firmly Conmmitted Units

Plant No. of Opetating Maint. Costsplant Code Units Heat Rate MaintenanrceName 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 VabeIracreas 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 1.56Pridnieprovsk PD14 4 145 145 2651 2651 377.1 Coal 9.4 29 145 0.83 1.89Pridnieprovsk PD58 4 257 257 2704 2704 421.5 Coal 9.4 37 257 0.68 1.56Kryvoi Rog KRIO 10 282 282 2612 2612 374.6 Coal 9.4 37 282 0.68 1.56Zaporozhye ZP14 4 290 290 2413 2413 316.3 Coal 9.4 37 290 0.68 1.56Zaporozhye ZP57 3 800 800 2388 2388 672.7 Gas 7.5 51 800 0.43 0.92Ugliegorsk UG14 4 299 299 2458 2458 408.7 Coal 9.4 37 299 0.68 1.56Ugliegorsk UG57 3 750 750 2327 2327 665.4 Gas 7.5 51 750 0.43 0.92Zuev ZU14 4 290 290 2515 2515 472.6 Gas 9.4 37 290 0.68 1.56Staro Beshevo SBI0 10 175 175 2825 2825 391.4 Coal 9.4 32 175 0.72 1.64Lugansk LU18 8 163 163 3023 3023 453.7 Coal 9.4 32 163 0.72 1.64Slaviansk SLA6 1 670 670 2510 2510 672.8 Gas 7.5 51 670 0.43 0.92Staviansk SLA7 1 715 715 2490 2490 380.6 Coal 7.5 51 715 0.43 0.92Kurakhovsk KUII 1 187 187 2598 2598 341.3 Coal 9.4 32 187 0.72 1.64Kurakhovsk KU27 6 210 210 2598 2598 341.3 Coal 9.4 32 210 0.72 1.64Tripolye TP14 4 293 293 2532 2632 443.9 Coal 9.4 37 293 0.68 1.56Tripolye TP56 2 294 294 2384 2384 635.6 Mazut 9.4 37 294 0.68 1.56Kiev TEC5 K512 2 60 100 1332 2850 665.8 Gas 9.4 29 100 0.83 1.89Kiev Tec 5&6 K5A6 4 175 250 1514 2788 653.8 Gas 9.4 32 250 0.7 1.6Bushtinsk BU12 12 191 191 2512 2512 455.3 Coal 9.4 32 191 0.72 1.64Dobrotvorsk DT13 3 100 100 2837 2837 514.3 Gas 9.4 29 100 0.83 1.89Dobrotvorsk DT45 2 150 150 2581 2581 625.3 Gas 9.4 29 150 0.83 1.89 xZmiev ZM16 6 163 163 2741 2741 401.7 Coal 9.4 32 163 0.72 1.64Zmiev ZM70 4 256 256 2594 2594 428.8 Coal 9.4 37 256 0.68 1.56

UKRAINE


Table III.1 Existing and Firmly Committed Units

Plant No.of Operating & Maint. CostsPlant Code Units Heat Rate Maintenance

19a3me1st block Capacity I st block Avg. Fuel Price Fuel Type Forced Outage1993) o Increase Rate | Duration Capacity Vafiable

UScents |W US$/KWl 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


Table III.2 Candidate Units

Plant Plant No. of CapacityName Code Units of Total Heat Rate Maintenance Operaing Cost

(end of 1st block Capacity Ist block Av-rage Fuel Fuel Forced Outage Fixed1993) 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 2Turbine

Combined CCGT 450 450 1820 1820 679.3 Gas 6 25 450 0.3 1Cycle

Steam PVCL 500 500 2263 2263 300 Coal 9 30 500 0.6 1.44Coal

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 Measuresin the Electricity Sector of Ukraine

To ensure reliable energy supplies to the national economy and the Ukrainian population, to promoteenergy and fuel conservation, and to improve the efficiency of the energy sector in order to operate undermarket 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 toimplement in a definite order, a privatization process in the sector complete with the preparation of theappropriate draft regulations and normative acts;

* to implement-within a year-a range of measures that will create a competitive electricity marketin Ukraine;

* to create-within two months-a regulatory body that will regulate electricity tariffs, promotecompetition 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 andElectrification of Ukraine (i.e, the Center) and the regional power associations (i.e., theAssociations) and establish on the basis thereof:

* A state enterprise-the Energomarket-comprised of the Central and Regional Dispatch Centersof the above-mentioned Associations

* Not less than four Joint-Stock State Electricity Generation Companies from the existing thermalpower stations of 500MW (and higher) and from the hydropower stations of 300 MW (andhigher) currently belonging to the Associations;

* The National Electric Company (NEC) from the high voltage networks (220 KV and higherincluding substations and accompanying infrastructure) currently part of the Associations;

* Regional (oblast) Joint-Stock State Electricity Distribution Companies from the remaining stateproperty 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

KievMay 21, 1994Decree 244/94

ANNEX 4BPage 1

ACTION PLANFOR TILE RESTRUCTURING OF THE ELECTRIC PONER SECTOR AND THE

PREPARTION OF ITS OPERATION IN MARKET CONDITIONSCABINET OF MINISTERS' REGULATION 816

Ite ACTION AGESPNSIBL DEADLINE

\.MAR_KET REFORM,f OF THE EXISTINGPOWER SECTOR STRUCTURE

Creation of the interdepartmental Minenergo DEC 1994Electricity Reform Commission MinEcon

Anti-monopoly CommitteeState Property Fund

Submit proposals to the Cabinet of M9inenergo DEC 1994Ministers on the creation of an independent MinEconNational Electrictitv Regulatory Commission(,NERC)

Determine the number and composition Minenergo DEC 1994of the power generation companies to be set up Anti-monopoly Committee

Create and confirm a list Minenergo DEC 1994of energy facilities to be included in Anti-monopoly Comrnitteethe National Electricity Company (NEC)

Set up the "Energomarket" State energy Minenergo MAY 1995enterprise Anti-monopoly Committee

Set up the National Electricity Con-...any Minenergo MA-Y 1995Anti-monopoly CormmitteeNlinEcon

Determine composition of regional Minenergo JAN 1995distribution companies (LECs) MinEcon

Anti-monopoly Committee

ANNEX 4BPage 2

Item ACTION RESPONSIBLE DEADLINEAGENCY

2. CORPORATIZATION OF THE POWER SECTOR

Organize thermal and hydro-power stations Minenergo APR 1995into state power generation joint-stock Anti-monopoly Committeecompanies through corporatization NfinEcon

Set up regional (oblast-level) power hfinenergo JUN 1995distribution state joint-stock companies Anti-monopoly Committeethrough corporatization hfinEcon

Corporatize auxiliary enterprises Minenergo MAY 1995of regional assocations MinEcon

3. DEVELOPING THE LEGAL AND REGULATORY FOUNDATIONS

Draft Regulations for NERC Minenergo DEC 1994MinEconNMinistry of JusticeAnti-monopoly Committee

Draft Regulations for the EnergoMarket Minenergo JAN 1995MinEconMinistry of JusticeAnti-monopoly Comrmittee

Draft Regulations for Electricity MinenergoSector Licerses MinEcon JAN 1995

Ministry of JusticeAnti-monopoly Committee

Signed, V. MasolPrime Minister of UkraineNovember 2, 1994

UKRAINr,

HYDROPOWER RLHABILITATION AND SYSTFN COtZI'ROL PROJECT

DETAILED COST ESTIMTESA. HYDROPOViER REHABILITATION

h.b Nos- 1"'15 111% 19W 1 19% 2000 -1J.. USS d.dw '. P'.1-t -. 1 T�.I L".1 F.-g. IwA I -1 I .. g" F�ul I -. 1 I "g. I A I -. 1 F.-g. T,,.J I-I T-I -I f-.g. T..I

DO 0 00 ............. 2.(0 0 00 .......... 3� 1.00 I 0 3................ .. ........Twb-� NAG---t C-pI.t' P,og,- 0 0.0 0 00 0 00 0 00 0 00 0 (K) 0 02 0 27 0 29 0 02 0 27 0 29 0 (O 0 00 0 00 0 0( 0 00 0 ou 0 04 054 0 58S.-hy.& C..plete P,og,- 0 (U 0 00 o 00 0 00 0 00 1) (( 0 05 0 10 0 11 0 01 o 03 0 04 0 00 0 00 u ou 0 00 0 00 0 N 0 06 013 0 19C-. & Nim., opitte P,,g,- 0 L-0 0 00 0 0( 0 00 0 ou oli 0 00 u (X) 0 00 0 14 1 72 1 86 0 09 I uu I ag 0 Oi t) 14 0 0 23 2 87 3 102s 2 ill 2 99- 1 67 4 5 5 2 99 4 37 7 36 2 40 0 3 2 1 15 04

�7 766 �3 190 13 1 1 49 4-9 . .. ...... O' 'I'i I - I 1 49 0 1 I. . ....... a 90T-b-, 1 49 o Ii 1 63 1 49 0 13 1 63 1 49 6 o3 0 96 9 75G- .- 420, CB all 0 76 0 12 0 98 0 76 0 12 0 88 0 76 0 12 0 88 0 76 0 12 0 as 0 76 0 12 0 88 0 76 0 12 0 88 4 56 072 528S-.,hy.d, coo�pj.t. P,.g,m 0 00 0 01) o 0. (X) 0 uu 0"� 0 00 U w (I 0( 0 55 0 3 I 0 85 0 44 02� ( 68 0 11 0 Ob 0 1 7 1 09 0 62 1 7iC_ & Ni-" Cotople, Nos- 0 00 (00 0 00 0 DO 0 0( �00 0 00 u 00 0 0( 0 09 1I 0 1 I9 0 31 3 86 4 17 0 04 0 5s 0 6( 044 552 5 9(,..... .. ........... . ......... ...... . ................ ............. �.�9 . .. .......... 3 . ....... � 31f 0 w9�9� 0 42 0 46T.,b,.,t Not,.cl.dedG--." CB -ly 0 00 0 (O 0 00 0 Du 0 (X) 0 00 0 03 U 34 0 i6 0 01 0 09 0 09 0 00 0 (O 0 0( 0 ou 0 00 0 0(1 0 03 0 42 0 46S- hy.d, Nm..cl.ded

M-t Nm includ�d

. ........ . .. 9.99 0.99 III 0 00 I 11 2.?� 74 6 65T.t,.ts I of 12 0 (O 0 00 0 Du 0 00 0 (O 0 00 0 00 0 00 0 00 0 (a 0 0( 0 (JO I 11 0 00 I f 'Ii I'i'i 5 22 0 00 2 22G-m- CB -ly 0 00 0 00 0 00 0 00 0 (o 0 00 0 05 0 57 0 62 0 05 0 57 0 62 0 00 0 00 0 00 0 00 0 00 0 00 0 09 1 14 1 235-.hy.d. cmpi- 0 00 0 ou 0 00 0 00 0 00 0 00 0 36 1 56 1 92 U 24 1 04 1 29 o 00 0 00 0 00 0 DO 0 00 o 00 0 60 2 61) 3 20C-u & M-4 Not .d.dd

2.�2 0 00 o 00 00 0 00 0 0 62 0 7� 0 90 1 4 5 F34 1 49 0 32 1 80 1 48 0 16 1 b4 3 92................... !?�� . . . ..... ................. ....... . ...... . ............. .... ....... ...... .. . . ..................... . .................. .............................................. I. ........ .......- 2T-b-, I of 9, J] 8--.. 0 0 00 0 00 0 ou 0 00 0 00 0 (K) 0 74 o 32 1 06 1 49 0 3 2 1 80 1 48 0 i6 1 64 1 69 6 90 4 49C�e'.- B. --. u- 0 00 0 (U 0 00 0 00 0 00 u 00 0 02 011) 0 41 0 03 0 58 0 61 0 DU 0 00 1) (X) 0 (( 0 (O 0 00 u 05 0 116 1 cliS- hy.& pi.t. P,.g,- 0 00 0 00 0 00 0 00 0 00 0 06 0 00 0 224 0 2" 0 13 0 55 u bs O 00 0 (O 0 0 w 0 ou 0 0 18 V 78 97C.- & M-" -I.d�d

Pip 2 65 4 97 2 3 1 2.42 4 72..... . ....... ............. ... .1,!T 2,84 2 3�'. 52 3 8" 2 lo 0 57 2 73 13 79 9 60 2 3 39.......... . ....... ... ....... ... .. .. ......... .... .. ..... . .... - ..- ..... . ..... ... -.. - - -- -- ............T.,b,.,, oplete P,(,g,- 1 99 0 13 2 6� ------- I'i� .................. � 13 2 02 89 u 13 . ....... 2 O5 1 89 0 13 2 02 I 89 0 13 2 02 1 89 0 13 2 O' It 34 0 78 12 12G- .1- -plem P,.V- 0 2 5 0 21 0 46 0 25 0�1 0 46 0 25 0 21 0 46 0 2 5 o 21 0 46 o 25 0 21 0 46 0 2 5 0 21 0 4't 1 53 1 26 2 78S- hy.d p1m P,.g,- 0 C-6 0 29 o 35 0 29 1 47 1 7 5 0 22 1 18 I 40 0 co o 00 0 (O ( 0( 0 ou 0 00 0 0( 0 00 0 oc 0 St, 2 95 3 SC..� & Nfm,t pl�' P-".. 0 00 0 ou 0 00 0 00 0 00 0 00 0 (o 0 ou 0 ou 0 18 2 3 1 2 49 0 16 2 09 7 24 0 02 U-23- - -02! G 36 4 61 4 9Tffl.� �rmv� 0 ol 0 02 o 03 0 17 0 71 ( 8 0 2 5 1 77 2 02 072' 0 78 0 00 0 OD 0 00 0 63. .. ............ ..... ............. ........ ... . ... ..... ............... . ....... . . ... ..... ... .. . ................ ... . . . . .. ........ ....... ....- ............. - ...................... ..............T. AC�-.' pe�p' 0 00 0 DO 0 00 0 14 0 0 74 0 14 0 61 0 74 u 00 o 00 0 00 0 00 0 0 00 0 00 0 00 0 oc 0 28 1 21 1 49S- hy.�d, -P�.. 0 01 0 02 0 03 0 03 u I I 0 14 0 03 0 09 0 1 1 0 W 0 (O 0 00 (I 00 0 Jo 0 ou 0 Ou 0 00 0 00 0 07 0 22 0 29Cmu & Moon pl�t� P'"'- o oo 0 O.) O 00 0 (0 0 00 0 (( 0 (9 t 08 I !7 _ o 14 1 B() 1 94 u 06 0 72 U 78 0 00 0 00 u 00 0 28 3 bO 1 1920 I so 0 78 2 28 1 28 1 21 2 50 1 38 2 44 3 82 1 21 0 34 155 9 47 6 55.... ... ............ .... _._ .. .. ....... - ---- ----- .. ..... ....... ... .. ........... __ . .. .......T-b- oot .1`6 1 19 0 07 1 25 1 19 0 07 1 2 1 19 0 07 1 2 1 19 0 07 1 25 1 19 0 07 1 25 1 19 0 07 125 7 12 0 40 7 52G .... m- -1 .1-6 0 01 0 10 0 It 001 0 10 0 II 001 0 10 0 11 0 01 0 10 0 11 0 01 u 10 0 11 0 01 0 10 0 1 t 0 08 O 59 0 6)S-whyvds -plm P.8- 0 10 0 21 o 31 0 60 1 24 1 84 0 30 0 62 0 92 0 00 0 00 0 001 0 00 0 O0 0 00 0 00 0 110 0 1 00 2 07 3 06C..u & Moon -plm P,.g,- 0 (O 0 00 0 00 0 Du 0 00 0 00 0 00 0 uo 0 00 u 08 1 05 1 13 0 la 2 27 2 4 5 0 01 0 0 0 1 0 28 3 50 3 77

p--t Bw Cmt 5 76 1 28 7 04 6 64 4 19 1 0 83 6 95 1 79 14 74 7 99 12 48 20 49 9 40 II 26 20 66 9 38 2 08 10 4 45 H 39 09 84 2 1% of Tmal 13% 3% 8% 15% 11% I It, 15% 20% 1 7','. 19111. 32% 24% 21% 291,,. 25% 19% 5-11. 12', 1 DO,/. 1001/. I 00%Phy.c.] C-u.g-cy [St 0 86 0 19 1 ob I 00 0 63 1 62 1 04 1 17 2 21 1 20 1 87 3 07 1 4 1 1 6� 3 10 1 26 0 31 1 5 6 77 5 96 12 63P- Coob.getwy 0 35 0 03 0 39 0 84 0 21 1 05 1 35 0 60 1 96 2 13 I 31 3 44 3 22 1 49 4 71 3 54 0 33 3 9 11 44 3 98 1' '

Cog 6 98 1 51 9 49 8 49 5 03 13 51 9 34 9 56 Is 90 II 33 15 66 26 99 14 04 14 44 28 47 13 Is 2 73 15 63 33 49 93 112 21

(D

Ln

ANNEX5PAGE 2

_~~~~~~~~~~~~~~~~~~~~ . . . -. . . 3 d- - -8o - - _^i -

3 s o og__~ ;t 8 29 A x o . 3 t 8- S^ 8

_ ! o s s s i _ 7 o s3 o s s s 02 s o i 18 - e8 G

t x o SO$SSS M3 s o s s o s 3 -te o°= ^ ° .

g~ ~ ~ ~ ~ ~ ~~~~~~ ~- - -08 - -Sw - "~ - -o -80 - F" 2_ ao

8 g U 8 SSSS8 g 1 s s -e ogoo' _ 3 SoS85S80°. .. - .----- l-

?H~~~~~~~~ . . . . .. .. .. .. . .. ._ . . _ SS_°SO _ _!*'o. . .:_ m"

ffi ~ ~ ~ ~~~~~~~~~ . . . . . . . . . . . . . . .g .s .<8S ~ >SO tt

e I U v S S _ g3 s s .- s - t 3 s o s - o s " g o < _ ~ oa_

ANNEX 6Page 1

UKRAINEHYDROPOVER REHABILITATION AND SYSTEMS CONTROL PROJECT

Notes to the Financial Statements and Projections

1993 and 1994 Statements

1. Ukrainian statutory accounting employs a cash system with elements of accrualsaccounting. Revenue is recorded in the income statement only after payment is received, and only at thispoint are the associated costs recorded. During periods when there is poor performance in collectingrevenues, the statutory accounts can seriously misstate financial performance, because the costs associatedwith uncollected revenues are held off the books, even when they have been incurred in fact.

2. In order to provide a more meaningful presentation of the financial performance ofDniprohydroenergo and National Dispatch Center (NDC), their historical financial statements have beenmodified to approximate International Accounting Standards (IAS) using accruals accounting. Revenuesrepresent the imputed sales value of energy and services supplied during each year, irrespective of thetiming of receipt of those revenues. Costs reflect the costs of supplying those services and energy.

3. Both Dniprohydroenergo and NDC are experiencing difficulty in collecting customeraccounts and meeting their own payments to suppliers, so that there is a difference between their accruedincome and the income they are actually realizing on a timely basis. Under IAS, such delays in collectingconsumer accounts are not reflected on the income statement until the point when accounts are recognizedas being uncollectible and written off, or when inflationary losses on the outstanding receivables arerecognized. Because Ukrainian statutory accounting rules do not recognize either of these concepts (baddebt or inflationary losses), there has historically been no recognition of the impact that payment delayshave upon a company's income. The contracts, covenants, and tariff rules to be agreed duringnegotiation of this project will address these omissions, as discussed below. Projections of income foryears 1995 and beyond contain new line items ("provision for bad debt," and "interest penalty income")that reflect the measures that were agreed during negotiations to address the problem of delayed revenuecollection. These measures, in effect, will require the companies to begin recognizing bad debt andinflationary losses, but the resulting losses to the companies will be compensated through tariff-recoverymechanisms.

4. The companies' problems in collecting accounts, during 1993 and 1994, can be seen inthe accounts receivable recorded on their balance sheets, and in the changes to accounts receivablerecorded on their cash-flow statements. The NDC's accounts receivable amounted to 96 days of annualrevenue during 1993, and fell to 60 days in 1994. This did not reflect an improvement in collectionperformance; rather, it reflected inflation of the revenue stream that serves as a denominator in the ratio.Dniprohydroenergo had 36 days of receivables in 1993, rising to 45 days in 1994.

5. The fixed assets of both companies were originally recorded on a cost basis. Costsrecorded during the Soviet era traditionally were below comparable costs in the West. The statutorydepreciation lives for fixed assets are generally far longer than the useful lives applicable under IAS.Ukraine has experienced severe inflation since 1991, and the book values of the companies' fixed assets

ANNEX 6Page 2

remain seriously undervalued, despite indexations that have occurred under national law in May 1992 andAugust 1993 as well as the most recent revaluation in January 1995. These indices are very broad andmay not accurately reflect the actual worth of the fixed assets.

Assumptions for the Financial Projections

6. Power Production. Hydropower production in 1995 and beyond is expected to besomewhat below recent historical levels. Local personnel report that power has been produced abovesustainable levels by drawing down the water reservoirs, and it is assumed that this cannot continue.Production of nuclear and thermal power and import/export levels are detailed in the table which follows,entitled "National Dispatch Center: Assumptions for Electricity Purchases," which follows from Annexes1 and 3. Cost and tariff assumptions have been discussed in Section C of Chapter III of the main text.

7. General Financial Assumptions. Assumptions for Ukrainian inflation and US$/Krbexchange rates are as outlined in Section C of Chapter III of the main text. The US dollar inflation ratehas been assumed at 2.2%.

8. Tariffs for hydropower are set at a level that covers the costs of existing facilities,including depreciation and allowed profit margin. In addition, the tariff cost-recovery mechanismdescribed in Section C of Chapter III of the main text (see also Annex 7, paras. 7 - 9) is included at alevel sufficient to cover costs associated with the World Bank project and to generate additional US$ 8million equivalent per year of funds for other rehabilitation and investment projects that are expected tobe necessary after the year 2000.

9. The resale tariff of the National Dispatch Center is set at a level that permits it to recoverits costs of purchased power from all sources, plus an uplift to cover its small costs of operation,including a profit margin. The actual resale mechanism, which will involve allocation of a portion ofits low cost supplies to the Local Electricity Companies who are its customers, and sale of thermal powerat a wholesale rate reflective of marginal costs, is discussed in paras. 3.4 - 3.5 of the main text.

10. Both companies were subject to a 22% profits tax prior to 1995 which was based onrevenues minus material costs (operating costs net of costs associated with labor). Ukraine's previoustax law did not recognize interest on long-term debt or labor costs as deductible items. At the beginningof 1995, Ukraine introduced a new corporate profit tax of 30% which allows for the deduction of laborcosts before tax. At the time of publication, it was still unclear whether interest on long-term debt wouldalso be deductible, although it is highly likely that this provision will also be approved. For the purposesof the financial projections, the new tax law and rate are applied beginning in 1995 assuming that intereston long-term debt can be expensed.

11. The hydropower stations pay a 0.8 % - 1.2% road maintenance charge, on the same taxbase that is used for the profits tax. Proceeds go to a local government entity or are retained by thehydropower station, depending on where the plant is located and the division of responsibility for roadmaintenance. Contributions to the Chernobyl fund are paid by both organizations, under national law,and are treated here as a labor-related cost in operating expenses. Similar treatment is accorded topayments to the unemployment fund, assessed at 1 % of the profits tax base, and statutory worker benefitssuch as the insurance fund.

ANNEX 6Page 3

12. Company-Specific Assumptions. The projected balance sheets take into account theindexation announced as of January 1995 according to an approximation of the age of assets. The actualindexation will inevitably be slightly different because it is impossible to guess the exact acquisition dateof the assets. A more thorough revaluation, aimed at determining the proper value of existing assets, hasnot been performed in the context of this analysis. Thus, the assets to be added under the World Bankloan, because they will be properly valued when booked, appear on the balance sheets to make up adisproportionate share of the total fixed assets of the two companies.

13. For the companies' statutory accounting and reporting requirements, the new assetscreated under this project will be treated according to the usual rules prescribed by Ukrainian law. Suchrules involve useful lives that are in some cases much longer than would be called for under IAS. Forthis reason, an attempt has been made to apply IAS standard useful lives and depreciation methods indeveloping the income projections included in this Annex.

14. Both companies make a number of statutory fund contributions, which are tied to theirprofitability after tax. These are currently paid to Minenergo, which uses them as retained earnings tobe distributed among the organizations within its structure. It is assumed that, after the restructuring ofthe power industry, such fund contributions would cease and the resulting funds would remain at thedisposal of the corporatized Dniprohydroenergo and NDC/Energomarket. Such funds are thus treatedas part of equity on the balance sheets of the companies.

15. Standard ratios such as the current ratio and quick ratio appear highly distorted,particularly for Dniprohydroenergo, during some of the forecast years. This is simply an artifact of thetariff cost-recovery mechanism that is being adopted to ensure recovery of project-related costs. Thismechanism will cause large capital costs of the project to be passed through tariffs on a current basis, ascash is spent on local investment costs and on the subsequent repayment of the World Bank loan. Thetariff cost-recovery mechanism increases billed tariffs, and hence increases the companies' accountsreceivable. At the same time, the associated project costs, being capital in nature, are not reflected inthe companies' routine, course-of-business accounts payable. This is particularly true forDniprohydroenergo, which is very capital-intensive but has very low current liabilities. For this reason,standard ratios (such as current assets over current liabilities) achieve very high values during the peakyears of tariff cost-recovery. Under the circumstances, such ratios have limited information value.

16. The projections embody the tariff, contract, and covenant provisions that were agreedduring loan negotiations. Specifically, resale tariffs for the NDC include an allowance for bad debt asdescribed in Section C of Chapter III. Such an allowance is not included for the Dniprohydroenergo,because it is assumed that NDC (its only customer) will settle its accounts in full within 20 days ofbilling, as will be required in the contract between NDC and Dniprohydroenergo. Both companies willbe entitled to collect interest penalties on outstanding receivables not paid within 20 days. It is assumedthat Dniprohydroenergo will be paid promptly and hence no interest-penalty income is shown on itsstatements. However, it is assumed that NDC will have income from interest penalties during the projectperiod, because the average age of its receivables will be reduced to 60 days in 1995, 40 days in 1996,35 days in 1997, and 30 days thereafter (para. 3.16). This interest-penalty income has been calculatedbased on the average number of days receivables during each of the years; the penalty would apply afterthe 20th day, and would accrue at a rate calculated to compensate NDC for its implicit loss fromextending trade credit and provide an incentive for prompt payment.

UKRAINEHYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT

Dniprohydroenergo - Financial Assumptions (Krb'000)

1993 1994 1995 1996 1997 1995 1999 2000 2001ExdhngeRate-AAA 7.629 54.529 140.00D 165,000 180.142 191,253 199.766 205,842 212.103perceincraease 000# 614.76% 156,74% 17.86% 9.18% 6.17% 4.45% 3.04% 3.04%

In8abon Rate 1.9 1.345 1.196 1 127 1.062 1.05 1.05Resl Gwth Ra te o iSoie 1.00 1.10 1.10 1.10 1 10 1.05 1.05

A nowfs Receivable (000) 3,054,000 34.343.677 266,320.818 273.966.989 282,633.677 313.703.059 339,691.648 522,878,148 583,989,914Days Revenue n AR 31 45 20 20 20 20 20 20 20Provision fbr Bad Debts 0.00% 0.00% 0 00% 0.00% 0.00% 0 00% 0 00% 0.00% 0.00%

Accounts Payable (000) 9.972.995 13,185.478 15,651,018 17.641.279 18.773.197 20.261.705 21.416,345Days Phubases h AP 20 20 20 20 20 20 20

Sales of power to NDC

Dhyo

Total K44(000) 10.746.831 10.698,520 10,125,739 10.100.803 10,113.852 10.132.886 10,162,906 10.205.910 10.247.900TanfUtM(wH 3.32 2804 480.00 49500 510.00 565.00 610.00 93500 104000TotW Value 35.669.86 278.565,380 4.860,354.933 4.999.897.555 5.158,064,600 5,725.080,826 6.199,372,568 9.542.526.204 10.657,815.928Tariff in US dollarsfl-wH 0.0004 0.0005 0.0034 0.0030 0 0028 0.0030 0.0031 0 0045 0.0049


Dniprohydroenergo - Statement of Cash Flows (Krb 000)1994 1995 1998s 1997 1996 1999 2000 2001

Cash Flows From Operations

Not sncont (loss) 71,514,107 2.98,056,029 2.704.750,011 2,740.268,620 2,761.619.538 2.909.293.192 2.935.690.917 2,958.398.345Adjustneu bt r concle not inconr

(loss) to nft ras flows from opermanss

Add Depreciation 4.522.000 597.365,395 597.385.395 597.385,395 1,038,691,583 1.235,246.185 3.896.986,191 4.367.612,330Subtotal 76,036.107 3.295.442,224 3,302,135,405 3.337,674,015 3.800,311.121 4.144.539.377 6.832.677,108 7,326.010.675

Debt Prncipal Payments 0 0 0 0 0 0 (314.472.456) (690,474,948)

Changes In Non-cash current assets and

Non-debt current liabilities:

Accounts receivable (31.289,677) (231.977.141) (7.646.171) (8.666.688) (31,069,382) (25,968.589) (183.196,500) (61.111,766)Inventory & production stocs (3,491.000) (1.976.467.495) (1,196,431,797) 207,231,220 (914.838,922) (1,042.798.254) (582,521,321) (699.939.207)Prepyiyments andoth1erreivabfles (9,232,000) (6,354,500) (9.531,750) (14,297.625) (21,446.438) (32.169,656) (48.254,484) (72,381.727)Accountspayable 14,907,000 (14,624.005) 3.212,483 2.465.640 1,990,261 1.131.918 1.488.508 1.154.640A.untd iatabiaes 6.197.000 59,333,074 5,946.092 5.200,125 41.685,102 20.222.657 273.189.776 88.481.530

Cash Available for Investments 53.127.430 1.125,352,156 2,097,684,263 3,529.606.5686 2.876.631.743 3.064,940.453 5,678.920.632 5.891,739,29a

Cash Flows From Investing ActivitiesPurdads of fixed assets (14,707,000) (1.336,247,323) (2,645,198.002) (3,807.386.167) (5.909.828.353) (6,659,796,244) (5,567,720.550) (4,706,261.382)

FmKag Gap 38,420.430 (210.895.167) (547,513,739) (277,779,581) (3,033,196,610) (3.594.855.791) 111,200.082 1.185.477.916

Cash Flows From Financing ActivitiesProceeds rmm vB debt 0 256.122,842 1.107,361.408 2,021,770,805 3.564.838,732 3.876.717.376 1.081.159.271 0Prwocds km tOer debt 26,246,000 0 0 0 0 0 0 0Chanes bi Funds (15.126.000) 0 0 0 0 0 0 0

NotChangeinCasht 49,540,430 45,227.675 559,847,669 1.743.991.224 531,842,122 81,86t.585 1.192,359.353 1,185.477,918Cash at begnnwt of yeo 1,384,000 50.924.430 96,152.105 655.999,774 2,399,980,998 2,931,633,120 3,013.494.705 4,205,854,058

Cash at End of Year 50,924,430 96.152.105 655,999.774 2.399.990.998 2,931,633,120 3,013,494,705 4.205,854.058 5.391.331.974

a.3


Dniprohydroenergo - Balance Sheet (Krb '000)1993 1994 1995 1996 1997 1999 1999 2000 2001

ASSETS

Cash i 384.000 50.924.430 96.152 105 655990774 2399990.99e 2931.633.120 3,013,494,705 4.205 854.058 5.391,331.974

Aooo11. l-o -blv.6e 3054000 34.343677 266320818 273.966989 282.633677 313.703,659 339,691,648 522 078 148 583,989,914

1nvenl0y & pndubon10 k6 2.809000 6300,000 1.982,767 495 3179 199292 2971 968072 386.06,994 4929 602.248 5812123.569 6512 062 776

Pre9.Y-eN0. nd othl. ,eteibl0s 3.477 000 12.709 000 19.063,500 28.595.250 42.892,875 64.339.313 86.508.969 144 763.453 217.145 180

Total Current Assets 10724000 104.277,107 2.34 303 918 4,137.761304 5697 485.622 7,196.482 485 8379,297.570 10685619228 12704,529844

Fixed Assets:VVH e9o.Po71 0 0 256122.042 7,409.220.472 3%560.314.752 7.344.745.906 1,348.395.244 12.774.726.816 12 774.726,816

L09 eq90pnen11 365.272.000 357.906 000 12.9G2.327,124 14.486.775,986 16,252.805.728 18.567.3002.716 21.515.619.743 25 972.763.645 30 839.025.027

O8h. " eqo.pmenll 311.000 587000 66092.250 79.479,982 99.065602 129.560,233 164.320.075 222.37A,452 262.371.452

CoekocWo.n b poogrese 6.837.000 28,634,002 28 634 OMo 28.634,000 28.634,000 280634.000 28,634.000 0 0

Arn.Wal.d depOecdaln (148,058.000) 150,580,000) (4.206,268.957) (4,883.654.352) (5.4817039.747) (6.519,731.330) (7.754,977,514) (11,651.963.706) )16,019.576,035)

NelbooLvuee 226.362,000 236,547,000 9,026,07.259 11.120,456.089 14,459780,336 19.550.W09.529 25,301.991.548 27.317.896.208 27.656.547.260

Long-leni .-nn09 ino6sUmenl 1000 1 000 17000 1.000 1.000 1.000 7. 1.00o 1.000

Total Assets 237,067 000 340.825.107 11.391 212,177 15.258.218,393 20.157.266,958 26 746 993.015 33.681,290.119 38.003.578.436 40.381.078,104

LIABILITIES & FUNDSShod-lem bwv".

Aun. payable 690,000 24.597.000 9,972.995 13,785.478 15,651.018 17.641.279 18.773,197 20.261 705 21.416.345

A-00,.dh N6."0" 3.135,000 9,332,000 68656074 74.611,166 79.811,291 121 496393 141.71.9050 4149038.826 503.390,357

Curen pp,on d bnte9m0 V4 debt 0 0 0 0 0 0 0 0 0

Total Current Liabilities 12825,000 33829,000 78638069 87,796.644 95.462,309 139,1378672 150.492,247 435,170.531 524.806.702

Long.te08 debl 5,051.000 31,297,000 31.297,000 31 297.000 31.297.000 31,297,ODO 31.2000 31,297.000 31R297.000

Log-.760w66debt 0 0 256.122.842 1.409.220.472 3.560.314,752 7.344745908 11,348,395.244 12.460,254,360 12,148.770,072

St7bndy kd 219,026.000 203.023,000 203.023.000 203.023.000 203,023.000 203,023,000 203.023.D0O 203,023.000 203.023.000

Rees6 bmd 2,000 0 0 0 a 0 0 0 8

Sp.o*918mds I63,000 1,062,000 1,062,000 1.062,000 1.062,000 1.062.000 1,062,000 1,062,000 1.062000

R ... o,n Rw 6.0051.498,330 8.051.498,330 8,001,498.330 8.051.498,330 8.051.496.330 8.051.498.330 8.051,498,330

PFsi Sor Fo..gn E hrge Los0s" O (376.980,560)

U,9diibt74.ed prot 71.514.107 2.769.570,936 5.474.320.947 8.214.609.568 10.976.229.105 13,685,522,297 16,821,213.2i4 19.779,6117559

Total Funds 219.2i1,000 275.599,107 11.025,154.266 13,729.904.277 16,470,192,897 19.231.812,435 22,141.105.627 25,076.798,545 27.656.204.330

Total Liabilities and Funds 237.067.000 340,825.107 1i.391,212.177 15.258,218.393 20,157.266.958 28.746.993.015 33.501.290.119 38.003.518.436 40.361.078.104

(Lw a,


Dniprohydroenergo - Income Statements (Krb '000)1993 1994 199S 1996 1997 199S 199 2000 2001

Income (excluding VAT)Sales to NDC 35.669.846 278.565,380 4,860.354.933 4,999,897.555 5.158,064.600 5.725,080,826 6,199,372,568 9,542,526,204 10.657.815.928

Total saies 35.669.846 278,565.380 4,860.354,933 4.999,897,555 5.158,064,600 5.725,080.826 6.199.372.568 9,542.526.204 10,657,815,928

Operating ExpensesCosto,porodurcon 3.907.500 26.338.034 50.042,265 67,306,846 80.498.968 90.722.359 96,347,145 101.164,503 106.222.728Materials 46.089 51.8466.56 98,509,026 132.494.641 158.463.590 178,588,466 189 660,951 199.143 998 209.101.198

Purchased power 293,264 755,591 14.207.739 14,944.765 15.705.589 17.747,316 19,544.035 30.555.978 34.667.146Salary ad wages 2.421,295 8.408.431 15.976.019 23.636.520 31,096.206 38.549.966 45.034.070 49.650.063 54.739.194Bonuses 2,665,977 29,219,206 55.516.491 82.136,649 108,058.975 133.960.712 156.492.904 172,533 426 190,218,102Payrollrelatedcharges 2,770.455 15,611,641 37,176,105 55.002,048 72,360.694 69,705.553 104.794.027 115.535.414 127.377,7941nnovabontund 290.560 3.722.861 48,603,549 49.998,976 51,580.646 57.250.80d 61,993.726 95A425262 106.578.159

Land aM. 491.989 2,748.549 5,222.243 7,023 917 8.400.605 9.467,481 10.054.465 10,557,189 11.085.048Depreaabon 2.350.907 4,522,000 597.385.395 597,385.395 597.385.395 1 038.691,583 1.235,246.185 3,896.986.191 4.367.612.330Interest(andfees) 0 0 20.389.725 21.291,965 18.370,361 10,787.843 2,411.627 549.313,253 1,089.642,308Socal osts 3,411.372 22.744.777 43,215.076 58.124.278 69,516.636 78.345.249 83,202.654 87.362.787 91.730.926Other 7.500.758 10.130.590 19,248,121 25.888.723 30,962,912 34.895.202 37,058.705 38.911.640 40.857,222Specsal wage tl 0 261.200 496.280 734.246 965.974 1.197.518 1.398941 1.542.332 1.700,422Tl. benefits (1.492.143) (42,032) 0 o 0 0 0 0 0

Operating Expenses 25,458.023 176.267704 1.005,988.034 1,135,968,968 1,243 366.571 1.779,910,057 2,043.239.436 5.348,682,036 6,431.532,577

Income fron operations 10.211,823 102,297,676 3,854,366.899 3,863929.587 3.914.698,028 3.945 170,769 4.156,133,132 4,193.844.167 4.226.283.350Incorne t"(22%. 30% rom 1995) 3,026,000 30,783,569 1,156.310.070 1 159,1789576 1,174409.409 1.183.551.231 1.246.839,940 1,258,153,250 1,267885005

Net Profit 7,185,823 71,514.107 2,698.056,829 2.704.750.011 2.740,268,620 2.761,619,538 2,909.293.192 2.935,690.917 2.958.398.345

v r

UKRAINEPROPOSED HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT

National Dispatch Center - Financial Assumptions (Krb '000)1993 1994 1995 1996 1997 1998 1999 2000 2001

E.change Rate 7,629 54.529 140.000 165,000 180.142 191,253 199.766 205.842 212.103Percent increase 614.76% 156.74% 17.86% 9.18% 6.17% 4.45% 3.04% 3.04%

Intla.tin Rate 90% 35% 20% 13% 6% 5% 5%

Acconts Recevable 0001 763,460,264 3.110.668,970 53.510.036.153 56,505,546.171 55,135,723.949 52.377,580,308 56,862.218,399 63.021.862,696 67,839.869,656Days Revenue in A/R 96 60 60 40 35 30 30 30 30Pronision fot Bad Debts 0.00% 0.00% 10.00% 7.50% 5.00% 4.50% 2 50% 2 50% 2.50%Grace period 20 20 20 20 20 20 20Pnalty days 40 20 15 10 10 10 10Interest rate monthly 25.00% 7.50% 5.00% 5.00% 2.50% 2.50% 2.50%Penalty revenue net of provision 2.199.042.582 1,393,287.440 679,755,501 451,595,193 233.680,350 258,993.957 278.793,985

Accounts Payable (0001 377.382,622 1,688,321,345 37.221,391,792 41.350,507.780 30,283,965.117 33,377,288.367 36.554.797,854 40,506,231.362 43.607.336,800Days Purchases in A/P 59 36 45 30 20 20 20 20 20

c_n O


National Dispatch Center - Statement of Cash Flows (Krb '000)1994 1995 1996 1997 1998 1999 2000 2001

Cash Flows Fron Operation.

Net income (loss) 1,243,488.332 14,922,012.152 5.216,506,527 11,166,386,757 7,503,781,961 11,760,983,058 11,784,369,740 12,320,416,462

Adiustments to reconciie net income

Oosst to net cath flows fIom operations:

Add: Depreciation 890,600 92,423,108 146,781,190 258,947,934 390,454,127 434.398.885 1,840,797.143 1.894.851,861

Subtotal 1,244.378.932 15,014,435,261 5,363,287,717 11,425.334,691 7,894,236,089 12.195.381,943 13,625,166,883 14,215.268.323

Debt Principal Repayments tll,193.0001 0 0 0 0 0 (335,012,414) (735,573,629)

Changes In Nn-cash current ssets wnd

Non-debt current laibitire:

Accounts receivable (2,350,338,9701 (50,399,367,1831 (2,995,510.018) 1,369,822,222 2.758,143,641 (4,484,638.091) (6,159,644,2971 (4,818,006,9601

Inventory & production stocks 1,813,000 (155,905,412) (341,045,500) (701,062,348) (8666,38.148) (467,252,125) 1189.719.629) 0

Prepayments nd other recesables (7,164,500) (10.746,750) (16,120,125) (24.180,188) (36,270,2811 (54,405,422) (81,608.133) (122.412,199i

Accounts payable 1,159,088.345 35,533,070,447 4,129,115,988 (11,066,522,663) 3,093.303,250 3.177.509.487 3,951,433,508 3,101,105,438

Accrued kabrties 23,229,000 120,111,274 88,416,501 73,237.307 61.464,064 40.884,843 34.003,844 36,789,439

lntercompanv payables 35,230,560 196.550.009 144,684,702 119,845,480 100,579,753 66,903.930 55.643,868 60,202.213

Net cash flows from operating activities 95,043,367 298.147.645 6,372.829,285 1,196,474,500 13,004,618,366 10.474.384.565 10.900.263.630 11.737.372.625

Cash Flows From Investing Activrties

Purchases of hfed assets 0 (1,055,463,6941 (2,098,073,460) (4,391.209.262) (5,277.056,590i (2.315,432,465) (669,618.090) 0

Financing Gap 95,043,367 (757,316,049) 4,274,755,806 (3,194.734,761) (1.835,074.8261 (1.829,340.007) (473.133,852) 71,719,170

Cash Flows From Financing Activities

Proceeds from Wodd 8ank Debt 0 779,527,062 1,566,026,237 3,277,287,025 3,964.736.560 1.876,703,596 563,516.384 0

Net Change in Cash 95.043.367 22.211.014 5.840,782.043 82,552,264 2.129.661.734 47,363.589 90,382,532 71.719.170

Cash at begnming o) Veor 194.000 95.237.367 117.448.380 5,958,230,423 6,040,782,687 8,170,444,421 8,217,808,010 8.308,190.542

Cash at end of year 95.237.367 117,448,380 5,958.230.423 6.040.782.687 8.170,444.421 8.217,08.010 8,308,190,842 8.379.909.712

Cashin US doNiws 1,746,541 838.917 36,110,487 33.533,455 42,720.668 41,137,203 40,361.997 39,508,720

Neot pofit US Dorm quivalent 22,804.103 106,585,801 31,615,191 61,986,592 39.234.901 58,873,844 57,249,613 58,087,008

ON _


National Dispatch Center - Assumptions for Electricity Purchases (Krb '000)1613 1"4 18S6 1SS 1917 1990 19SS 2000 2001PNod o. EolldY t0001

- wolvirogo

% o1 pucb. 13.08% 12.64% 7.45% 5.67% S.75S 6.71% 5.63% 5.47% 5.31%Told K., H OO0 10,746.831 10.698,520 10,125.739 10,100.803 10.113.052 10.132.U86 10,162,906 10,205.910 10,247,900Iodll Uk/KwH 3 26 400 495 510 565 610 935 1040Tolal Vj.. 35.669.846 278.565.380 4.860.354,933 4.999.897,555 5.168.064,600 5.725.060.826 6.199,372.561 9.542.526.204 10.657.,15.928ta,if in US dolws/KwlH 0.0004 0.0006 0.0034 0.0030 0.0028 00030 0.0031 0.0045 0.0049

Dr"o_-11

% of Puladsrd 0.73% 0.43% 0.33% 0.34% 0.34% 0.33% 0.32% 0.31%ToldwHf (000) 620.480 567.261 590.197 593,148 596.114 599,094 602,090 605.100WIN UhKwH 78 1440 1485 1530 1695 1830 2805 3120Told Vah- 48.467.70W 845.655.201 876,442.335 907,516,201 1.010.412,523 1.096.342,296 1,698,861,388 1.887.912.217laInUSd downa(w1 0.0014 0.0103 0.0090 0.005 0.0089 0.0092 0.0136 0.0147

Nod- P Sow t e

% .1 Pwdo.-a,s 84.45% 85.30% 55.53% 45.A0% 47.91% 47.49% 46.69% 45.16% 43.68%Tolal KwH 00 69.392,977 72.221,000 75.481.000 81,538.000 84,335.000 64.335.000 84,335.000 84,335.000 84.335,000tilf U.lSKwH 31 230 2100 2475 2702 2869 2996 3088 3182Total Vokw 2,167.089,073 16.639.718.400 158,510,100.000 201,806,550.000 227.884.095,021 241.939.487.360 252,706.784,459 260.395,163,959 268,315.332.046ia.iffwUSdo"m/KwH 0.0041 0.0042 OO015 0.0150 0.0150 0.0150 0.0150 0.0150 0.0150

Th,.-W Pow.- 51.60

% ol P-Ih"as 0o25% 0.24% 3585%S 47 63% 45 43% 45S91% 46.80% 48 51% 50.18%Tol;l KwH i0001 202.178 202,000 48.727.282 84,795.497 79.971.884 81.522.485 84,519.675 90,596,400 96.873.635l.,.ll U,k/KwH 250 264 2800 3465 3963 4399 4794 5146 5303Total Vkm 50,544,500 53.328.000 136,436,389.600 293,16.397.105 316.938.439.220 358,602.153.533 405,220.416.176 466.213,403.531 513,679.206.766loilw US do8../XwH 0.0328 0.004B 0.0200 0.0210 0.0220 0.0230 0.0240 0.0250 . 0.0250

hops.d E.t,ddlty% .1 Poldhlog 2 22% 1109% 0 74% 0.56% 0.57% 0.56% 0.55% 0.54% 0.52%Totl KwH 10001 1.828,201 925.135 1,000.000 1,000,000 1000.000 1,000,000 1.000,000 1,000.000 1.000.000lill Uk/KwH 53 179 2100 2475 2702 2869 2996 3088 3182Total Vkm 97.631.758 165,922.902 2,100,000.000 2.475.000.000 2,702.129.543 2.868.790,981 2.996,487,632 3.087,628.671 3.181.541.852twill In US doll l/KwKH 0,0070 0.0033 0.0150 0.0150 0 .050 0.0150 00150 0 0150 0 01 50

Told Pwd,*s*.

% ol PwChm... 100.00% 100,00% S Oo 00% 99.99% 100.00% 100 01% 10000% 100 00% 1000%Toli KwH 10001 82.170.187 84.667.135 135.921.282 178,024.497 1/G.013,884 177.586,4H5 180.616.875 186.739.400 193.061.635I-dl UUk/KwH 29 202 2221 2826 3140 3430 3694 3959 4122Told V.h. 2,350.935.176 17,137,534,602 301,906,844,533 503.097.844,660 552.682.728.383 609,135.512.699 667,125,060,835 739.238.722,365 795.833.896.591W0ill iUS doMll-AwH 0.0038 0.0037 00159 0.0171 001/4 0.0179 0.0185 0.0192 00194

-. >


National Dispatch Center - Assumptions for Sale of Electricity(Krb '000)1993 1994 1995 1996 1997 1998 1999 2000 2001

Internal usage KwH 0.55% 455.659 747,567 979.135 968,076 976,726 993.393 1.027.067 1,061,839

Regional Distribution Center% of Safes 96.46% 97.40% 98.50% 98.85% 98.83% 98.84% 98.86% 98.90% 98.93%Total KwH 10001 S1,577,633 82,012,227 133,141.822 175,003,442 173,004.36) 174,567,943 177,580.944 183,668,337 189.954,295twitf UrkJKwH 33 226 2674 3145 3452 3710 3941 4225 4400Total Vahe 2,726.090,700 18,514.260.245 356.021,232.028 550,385,825,090 597,211.074.884 647.647,068.530 699,846,500,304 775.998.723.825 835,798.898,000

tariff in US dollars1K.H 0.0044 0.0041 0.0191 0.0191 00192 0.0194 0.0197 00205 0.0207

Exports

% of Saafs 3.52% 2.60% 1.48% 1.13% 1.14% 1.13% 1.11% 1 08% 1.04%Total KwH t0001 2,978,331 2,189,238 2.000.000 2.000.000 2,000,000 2.000.000 2,000,000 2,000,000 2,000,000tanfi Urk/KwH 63 203 2800 3465 3963 4399 4794 5146 5303

Total Vauo 186,967.346 443,736.650 5,600,000.000 6.930.000.000 7.926,246,660 8,797.625,674 9.588,760.423 10,292,095,570 10,605,139,505tiwiff in US doflmrs/KwH 0.0082 0.0037 0.0200 0.0210 0.0220 0.0230 0.0240 0.0250 0.0250

Nuclear Power Stations

S of Sales 0.02% 0% 0.02% 0.02% 0.02% 0.02% 0.02% 0.02% 0.02%Total KwH i000) 19,541 0 31,93 41,920 41.441 41,816 42.538 43,996 45,501iatill Urk/Kwfl 66 235 2100 2475 2702 2869 2996 3088 3182

Tolo Vlue 1.298.727 0 66,975,300 103,752,000 111,978,950 119.961,364 127,464.591 135.843.311 144.763.336tanffinUSdolNrs/KwH 0.0087 0.0043 0.0lSO 00150 0.0150 0.0150 O.O1S0 0.0150 0.0150

Total Sales

% of Safes 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%Tolal KwH 1000) 84.575,505 84,201,485 135,173.715 177,045.362 175,045,808 176,609,759 179.623.482 185.712,333 191,999,796anif UrklKwH 34 225 2676 3148 3458 3718 3950 4235 4409Totl Vafu 2,914,356,773 18,957,996,895 361.688.207.328 557,419,577,090 605.249,300,494 656.564.655.568 709.562,725,318 786,426,662,706 846,548.800.841triff inUSdolas/KwH 0.0045 0.0041 0.0191 0.0191 0.0192 0.0194 0.0198 0.0206 0.0208

Twitf tor:

Purchass of enrgy 27.797 203.530 2233.473 2841.632 3157.361 3449.048 3714.019 3980.558 4144.973Caotal-d precieliononaeeinslgasoets 0.004 0.011 0.471 0.359 0.363 0360 0.354 0.343 0.331Local mwestrnenl 0.000 0.000 2.131 3.070 6.408 7.446 2.446 0.571 0.000Debt sarvc 0.000 0.000 0.000 0.000 0000 0.000 0.000 0.492 1.110Pro.*ion for wicollctible accounts 0.000 0.000 267.573 236.134 172.883 167.292 98.757 105.866 110.228Interest 0.000 0.000 0.151 0 114 0.080 0.029 0.006 3.151 6.046Oth*f opertaing expenses 0.511 2.660 32.566 35.638 38692 40.910 42.848 49.058 53.826hIcoli. tanes 1.155 4.182 47.311 12.628 27 339 18.209 28061 27.195 27.501Protit 4.991 14.768 110.391 29.464 63 791 4? 488 65.476 63.455 64.169

00 aO


National Dispatch Center - Balance Sheet (Krb '000)1993 1994 1995 1996 1997 1998 1999 2000 2001ASSETS

Cash 194,000 95.237,367 117,448.380 5.958,230.423 6.040.782,687 8,170,444.421 8,217.808.010 8,308.190.542 8.379.909,712Accwunts rec,oable 760.330,000 3.110.668,970 53,510,036.153 56,505,546.171 55,135,723.949 52,377,580.308 56.862.218,399 63.021,862,696 67,839,869,656In-entoy & production stocks 1,813,000 0 155,905,412 496.950,912 1,198,013,260 2,064.851,409 2.532.103,533 2.721.823,162 2.721,823.162Prepayrents and other recevables 14,329.000 21,493.500 32,240,250 48.360,375 72,540,563 108.810.844 163.216,266 244.824,398 367.236.598

Total Current Assets 776.668.000 3,227,399,837 53.815,30.196 63,009.087,881 82,447.060.469 62,721,686,981 67,775,346,208 74,296.700.799 79.308.839.128Fixertd asets:

WB .ompnrnt 0 0 779.527,062 2.484,754.561 5.930,066.301 10,324,257.043 12,660.517.666 13,609,115.810 13,809.115,810Local eqtirmpn1 8.906,000 8,906,0D0 721,236.632 1,253,283.854 2,367.206.091 3.679,526.121 4,118.254.969 4.224.356,696 4,224.356.696Accurmdualed depreciation 0 0 0 0 0 9,562,636,602 19.550,928,710 30,254,708,102 41,920,361,558Net book vaku 0 0 0 0 0 0 0 0 0Long-tnrm financial intestntenl 49,D00 49,000 49,000 49,000 49,000 49,000 49,000 49,000 49.000

Total Assets 782.254.000 3,232,097,237 55,011,139.781 66,295.090.998 70,093.349.618 85,186,669.388 102,569,211.328 119.006,248.018 133,791,187,42

LLA8tLITIES & FUNDS

Shon-tern borrow.ings 11.193,000 0 0 0 0 0 0 0 0Accounts payable 529,233,000 1,688,321,345 37,221,391,792 41,350,507.780 30.283,985.117 33,377,288,367 36,554,797,854 40,506,231,362 43,607,336,800Accru.d liabilites 7,743,000 30,972,000 151,083,274 239.499,775 312.737,082 374,201,145 415,085,988 449.089,833 485.879,272Intercompwny PaYsbile 15,452.000 50,682,560 247.232,569 391,917.271 511,762,750 612.342,503 679,246,433 734.90.300 795.092.514

Total Current Liabilities 563,621,000 1,769,975,905 37,619,707,635 41,981,924,826 31,108,484,949 34,363.832.015 37,649.130,275 41,690,211,495 44,688.308.585Lo,g-term WB debt 0 0 779.527.062 2,484,754.561 5,990,066.301 10.324,257,043 12,660,517,666 13,274.103.395 12,942,274,323

Statutory fund 101,477,000 210,402,000 210,402,000 210,402,000 210,402,000 210,402,000 210.402,000 210.402,000 210.402,000Reser-e fund 5.432,000 0 0 0 0 0 0 0 0Specrial funds 111,724,000 166,590,000 166,590,000 166,590.000 166,590,000 166.590.000 166,590,000 166,590,000 166,590.000Revaluabon Reswe 0 0 227,771.600 227,771,600 227,771,600 227.771,600 227.771.600 227,771,600 227.771,600Prouisonfbr Forgn Exchange Lous 0 0 0 0 0 0 0 0 (403,744,557)Undistributed profi 0 1,085,129.332 16,007,141,484 21,223.648,011 32,390,034,768 39,893.816,729 51,654,799,788 63,439,169.528 75,759.585,990

Total Funds 218,633.000 1,462,121.332 16,611,905,084 21,828,411.611 32,994,798,368 40,498,580,329 52,259.563.388 64,043,933,128 75,960.605,033

Total Liabilities and Funds 782.254,000 3,232,097.237 55.011,139,781 66,295,090,998 70,093.349,618 85,186,669.388 102,569,211,328 119,008,248.018 133,791,187,942

*1993 - AcfuS

-1994 - Esh,natb

1995-200l1 - Forsfst


National Dispatch Center - Income Statements (Krb '000)1993 1994 1995 1996 1997 1998 1999 2000 2001

Income (excJud,ng VAT)

SalestoRDC 2.726.090,700 18,514,260.245 356.021.232.028 550.385.825,090 597,211.074,884 647,647.068.530 699,846.500.304 775,998.723,825 835,798,898.000

E.port sales 186.967.346 443.736.650 5,600.000.000 6,930,000,000 7.926.246,660 8.797.625.674 9.588.760.423 10,292.095.570 10,605.139,505

N.clearsales 1.298.727 0 66,975,300 103,752.000 111.978,950 119,961,364 127,464.591 135,843.311 144.763.336

Total Sales 2,914,356,773 19,957,996,895 361,688,207,328 557,419.577,090 605,249,300,494 656,564.655,568 709,562,725,318 786,426,662,706 846,54,,800,141

Operabing Eopenses

Purchases frm HPS 35,669,846 278,565,380 4,860,354,933 4,999,897,555 5,158.064.600 5,725,080,826 6.199,372.568 9 542,526,204 10,657,815.928

Purchases from NPS 2.167.069.073 16.639.718,400 158,510.100.000 201.806,550,000 227,894.095.021 241.939.487,360 252,708.794.459 260,395.163.959 268.315.332,046

Purchases fromr REA 50.544.500 53.328.000 136,436.389.600 293.816.397,105 316.938.439,220 358.602.153.533 405.220.416,176 466.213.403.531 513,679,206.766

Imported 97.631.758 165.922.902 2.100.000.000 2,475.000.000 2.702.129.543 2.868.790.981 2.996,487,632 3.007,628.671 3.181.541.852

Total Purchases 2,350,935,178 17,137,534,652 301,906,844,533 503,097,84,660 552,682,728,383 609,135,812,899 U67,125,060,525 739,226,722,325 795,833,898.591

Grossmargin 563.421.597 1.820.462,213 59.781.362.795 54.321.732.430 52,566.572.111 47,429,142.869 42.437.664.482 47.187,940.341 50.714.904.250

Innovation fund 28.611.671 189.579,969 3.816.882.073 5.574.195.771 8.052,493.005 6,565.646.556 7,095.627.253 7,864,266.627 8.465.488.008

Road taa 3.288.000 9.630.000 717.378,354 651.860.789 630.798.865 569,149,714 509.251,974 566.255,284 608.578.851

Land tax 56.000 518.000 1,329.913 1.567,435 1,711,326 1.816.915 1.897.768 1,955,460 2,014,906

Deprecraoion 335.000 890.600 92.423.108 146.781,190 258.947.934 390,454,127 434,398,885 1,840,797,143 1.894.851.861

Pro.s,on forbaddebts 0 0 36.168.820.733 41.806,468,282 30,262,465025 29.545,409501 17.739,068 133 19660666.568 21.163,720.021

Inlerest 0 0 20.415.657 20.127.824 13,938,165 5.183.511 1,137.097 585.191.980 1,160,812,953

Salary 386.000 5,030,000 9,557,000 12,854,165 15,373.581 17,326,026 18,400,240 19.320,252 20,286.265

Payrollrelatedrosts 595,000 4,218,000 8.014.200 10.779,099 12,891.602 14.529.061 15.429.863 16201,356 17.011.424

Otherowss 10.301.116 14.961.116 28,426,121 38.233.133 45,726,827 51,534,134 54.729.250 57,465,713 60,338,999

Total Operating Expenses 43,572,767 224,827,685 40,663,245,159 48,262,667,688 37,294,346,530 37,161,049,545 25,869.940,463 30,612,120,383 33,393,103,288

Inroflsefrornopefabons 519.848.810 1,595.634,528 19,118.117,636 6.058,864,742 15,272,225,581 10,268,093,324 16,567,724,020 16,575,819.957 17,321.800.961

Interest penaly income (net) 0 0 2,199,042.582 1.393.287,440 679.755,501 451,595,193 233.680,350 258.993,957 278.793,985

519,848,810 1,595,634,528 21,317,150.218 7.452.152,182 15.951,981.081 10,719,688,516 16.801.404,369 16,834.813.914 17.600.594,946

Incomeltax (22%) 97,700.726 352,146,196 6,395,148,065 2.235.645,655 4,785,594,324 3.215,906,555 5.040,421,311 5.050.444,174 5.280.178.484

Net Profit 422,146,0U 1,243,488,332 14,922,012,152 5.216,506,527 11,166,386,757 7,503,781,961 11,760,983,058 11,7U4,369,740 12,320,416,412

tC D

ANNEX 7Page 1


Financial Rate of Return Calculation forDniprohydroenergo

1. Revenues. The project will produce incremental revenue through two mechanisms.First, it will result in incremental output (i.e., positive difference between the electricity output under the"with" and "without the project" scenarios). Second, the tariff structure to be adopted in connection withthe project will result in an incremental cost-recovery mechanism that will be charged on all output (pre-existing and incremental output associated with the project), beginning in 1995. In standard regulatorypractice, this conforms to "rolled-in" rate treatment, whereunder all ratepayers bear a ratable share ofthe cost of making improvements to their system. Such treatment is appropriate in instances, such as this,where benefits of the project (e.g., enhanced reliability, prevention of losses in capacity over time) accrueto all parties who currently consume hydropower.

2. Taxation. It is assumed that revenues associated with the cost-recovery mechanism willbe subjected to the same taxation regime as other revenues of Dniprohydroenergo. This includes a 30%"'profits" tax, a 1 % road-maintenance assessment, and a 1 % unemployment fund contribution, all ofwhich operate off the same tax base. The base for such taxes and assessments is revenue minus "materialcosts." These material costs include operating costs with the exception of labor costs. During the yearsof construction when the tariff cost-recovery mechanism will be generating funds to pay for localconstruction costs, the new facilities will not result in any addition to Dniprohydroenergo's operatingcosts, and incremental revenues are not offset by an incremental deduction. Thus, it is assumed that100% of the incremental revenue stream will be subjected to these three taxes, totalling 32%.

3. As discussed in Annex 6, Ukraine's tax law is subject to change, including the possibleintroduction of a deduction for interest on long-term debt. The rate of return is not sensitive to thisuncertainty, since it is assumed that any resulting reductions in tax would be flowed through to consumersvia reductions in the tariff.

4. Operating Costs. The operating cost reduction is the same that is assumed for purposesof calculating the economic rate of return, however, it has been converted to current dollars assuminga US dollar inflation rate of 2.2%.

5. Project Costs. The project costs are in current dollars and reflect the local and foreigninvestment costs and the commitment fee on a "cash-flow" basis as spent.

6. Rate of Return and Sensitivities. The financial internal rate of return is 13.5% on areal basis, and 16.0% on a current basis. This compares favorably to Dniprohydroenergo's estimated

ANNEX 7Page 2

cost of capital, 8.5%, reflecting the estimated cost of borrowing under this project' (1.5% on-lendinginterest rate, plus 7.0% estimated World Bank rate). It is assumed that any reductions in project costs,or reasonable cost increases within the allowed contingencies, would be flowed through to consumers viaa reduction/increase in the tariff. For this reason, the rate of return is not sensitive to changes in projectcosts. It is sensitive to the extent to which the forecast operating cost reductions and incrementalelectricity output are achieved. Risks associated with those factors have been discussed in the section oneconomic rate of return.

7. Because of Ukraine's high inflation rate and due to volatility in the Karbovanets/hardcurrency exchange rates, the beneficiaries would be at risk unless their tariff formulas provide a closematch between actual cash outlays under the project, and the recovery of such costs. The cost-recoverymechanism has been designed to minimize this risk, thus reducing the sensitivity of the financial rate ofreturn to inflation and exchange-rate movements. An alternative, more standard, recovery mechanismwould have been recovery of investment costs through customary depreciation of the new assets.Customary depreciation typically results in over-recovery of investment outlays in early years, and under-recovery in later years. The beneficiaries would be required to invest over-recovered funds in a way thatkeeps pace with inflation and exchange-rate movements, for use in years when there is an under-recovery,placing them at considerable risk. Because of these risks, a more direct tariff cost-recovery mechanismwill be used in place of customary depreciation. The cost recovery mechanism will fully recover localinvestment costs and the small commitment fee on an annual basis as spent, during the years 1995-2000.Obligations for the commitment fee would be converted to Krb at the then-applicable exchange rate.Interest on the loan incurred during construction will be capitalized and included in the loan balance;therefore, tariff recovery of accrued interest costs during these years will be deferred until such time asloan repayment commences. At the end of the 5-year grace period, loan repayment will commence andcontinue for 12 years. At that time, amounts equal to the beneficiaries' actual loan-service obligationswill be recovered through prices, with conversion to hard currency at the then-applicable exchange rates.

8.. During the early years of loan repayment, the cost-recovery mechanism will result inslightly lower prices than would be the case if customary asset depreciation had been used. In later years,there will be correspondingly higher recovery of investment principal through rates. Thus, the cost-recovery mechanism tends to defer revenue, and hence reduces the financial rate of return somewhat.However, as noted above, it significantly reduces the risk surrounding the estimated rate of return.

Dniprohydroenergo has no other long-term debt upon which to base its average cost of borrowing, and itscost of equity is unclear as its assets remain under state ownership.


IIYDROPOWER REHABILITATION FINANCIAL RATE OF RETURN IALL FIGURES IN CURRENT DOLLARS UNLESS OliEnlWISE NOIEOI

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

REVENUE WITHOUT PROJECT

ElecIricityOOulput GWh/yt 10713 10G53 10594 105J4 1041G 10417 10359 10302 10245 10188 10131 10075 10019 9964 9909

Tarill Kbv/kwh 173 233 279' 114 314 476 49G 534 574 617 663 713 766 824 S85

Tawill S/kwh 0.00140 0.00145 0 0015Si 00011P 0.00167 0 00231 000234 0.00240 0.00245 0.00251 0.00257 0.00263 0.00270 0 00276 000283

Revenje Smillon 14 98 15 44 16.40 17 31 17 50 24 07 24 25 24 69 25.14 25.59 26.06 26.53 27.01 27.50 28 00

WITH PROJECT

Elect,icily Outpul GWhlyr 10713 10659 10652 10661 10692 10763 10820 10808 10797 10785 10774 10762 10750 10739 10727

Tafill Kbv/kwh 281 407 481 601 679 922 736 791 851 915 983 1057 1136 1221 1313

Tailil S/kwh 000227 0.00253 0.00267 0.00314 0.00340 0.00448 0.00347 0.00355 0.00364 0.00373 0.003l1 0.00390 0.00400 0.00409 0.00419

Revenue Smilfion 24.27 26 96 28.44 33 48 36.36 48 19 37.56 38.41 39 28 40.18 41.09 42.02 42.97 43 95 44.95

Incemental Tao Smllion 2.23 2.77 2 89 3.88 4.53 5 79 3.19 3.29 3.40 3.50 3.61 3.72 3.83 3 95 4 07

REVENUE INCREASE (Aliet Ta.) 7.06 8.76 9 15 12 29 14.33 18 32 10.12 10.43 10.75 11 08 11.43 11 77 12.13 12.50 12 88

O&M COST REDUCTION Sm/rlon 0 0.00 0.00 0.1 0.11 0 11 0.12 0.12 0 24 0.25 0 25 0 39 0.40 0.54 0 55

PROJECT COSTS

Local Im,est-ent Cost 6.83 8.75 9 45 11.59 13 7 12 7

WB Loan Disb.rsemenls 1.71 6.53 11.65 18.91 16 07 2.80

Commitment Fee 0.16 0.14 0 11 0 06 0 01 0.00

TOTAL PROJECT COSTS 8.70 15.42 21 21 30 56 29 78 I5550

INCREMENTAL CASH FLOW lCwr'emi 5S -1.64 6.66 1206 18.16 1b 34 2 94 1023 1055 11.00 11 33 11.68 12.16 12.53 13.05 13.44

FINANCIAL IRR 0.1599

INCREMENTAL CASI FLOW $S1994) 1.60 6.38 -11.30 -16.65 13.76 2 58 ./'J 8 86 9.04 9.12 9.19 9.37 9.44 9.62 9 69

FINANCIAL IRR tREALI 0.1349

-3


HYDROPOWER REHABILITATION - FINANCIAL RATE OF RETURN (ALL FIGURES IN CURRENT DOLLARS UNLESS OTHERWISE NOTED)

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

REVENUE WITHOUT PROJECT

Electricity Output GWh/yr 9854 9800 9746 9692 9639 9586 9533 9481 9429 9378 9326

Tariff Kbv/kwh 952 1023 1100 1183 1271 1367 1469 1579 1698 1825 1962

Tariff S/kwh 0.00289 0.00296 0.00303 0.00310 0.00318 0.00325 0.00333 0.00341 0.00349 0.00358 0.00366

Revenue Smillion 28 51 29.03 29.55 30 09 30.64 31.19 31.76 32.34 32.93 33.53 34.14

WITH PROJECT

Electricity Output GWh/yr 10716 10704 10693 10681 10670 10658 10647 10635 10624 10612 10601

Tariff Kbv/kwh 1412 1517 1631 1754 1885 2026 2178 2342 2518 2706 2909

Tariff S/kwh 0.00429 0.00439 0.00450 0.00460 0.00471 0.00483 0.00494 0.00506 0.00518 0.00530 0.00543

Revenue Smillion 45.97 47.01 48.08 49.17 50.29 51.43 52.60 53.79 55.02 56.26 57.54

Incremental Tax Smillion 4.19 4.32 4.45 4.58 4.72 4.86 5.00 5.15 5.30 5.46 5.62

REVENUE INCREASE (After Tax) 13.27 13.67 14.08 14.50 14.94 15.38 15.84 16.31 16.79 17.28 17.79

O&M COST REDUCTION $million 0.71 0.72 0.89 0.91 1.08 1.26 1 45 1.65 1.85 2.07 2.47

PROJECT COSTS

Local Investment Cost

WB Loan Disbursements

Commitment Fee

TOTAL PROJECT COSTS

INCREMENTAL CASH FLOW (Current Sl 13.98 14.39 14.97 15.41 16.02 16.64 17.29 17 95 18.64 19.35 20.25

FINANCIAL IRR

INCREMENTAL CASH FLOW ($19941 9.87 9.94 10.12 10.19 10.37 10.54 10.71 10.88 11.06 11.23 11.50

FINANCIAL IRR (REAL)

ANNEX 8Page 1

UKRAINEHYDROPOWER REHABILITATION AND SYSTEMS CONTROL PROJECT

Economic Analysis

1. An economic analysis, based on incremental costs and benefits derived from thewith/without project approach, was conducted on the two main components separately and then integratedfor the project as whole. Project total indicators of economic benefits also reflect the investment costsassociated with the dam safety monitoring and technical assistance components, for which no benefitswere quantified. All figures are expressed in constant 1994 U.S. dollars. A summary discussion ofthe methodology of the economic analysis and main findings are provided in Chapter III.E. This Annexoutlines the basic assumptions used and presents the detailed results for the project as a whole and itsmain components, including plant-by-plant results for the hydropower rehabilitation component (Tables1-10).

Basic Assumptions

A. Hydropower Rehabilitation

2. Electricity Prices. The average economic price of electricity is forecast to increase fromthe equivalent of UScent 2/kWh in 1995 to UScent 3/kWh in 2005 and remain at that level thereafter.The economic price approximates the estimated long-run marginal cost. The average economic price wasused for the valuation of off-peak sales (one-fifth of the total). For the balance of sales, the peakeconomic price was used, which is 35% higher than the average price.

3. Availability. Under the "without" rehabilitation scenario, it is assumed that (i)electricity production falls by 0.5% per year due to reduced availability caused by growing plantdeterioration; and (ii) a lower percentage (79% instead of 80%) of electricity can be sold at peak timedue to the reduced availability of the generating units. Under the "with" project case, (i) electricityoutput declines at a rate of 0. 1% after completion of the rehabilitation; and (ii) 80% of the energy is soldat the peak price to reflect higher availability.

4. Efficiency Increase. Based on actual equipment testing, the rehabilitated units, inaddition to regaining original name-plate efficiency, are expected to achieve on average an incrementalefficiency gain of about 4% (expressed as increased energy production per year) due to the more modemdesign of new equipment (turbines, generators, transformers) and materials. Over half of the full-loadefficiency increase results from the more efficient turbines. The efficiency increase is reflected in theanalysis beginning in the third year of the implementation period, with the full efficiency benefit realizedone year after the completion of the investment.

5. Operation and Maintenance. For 1994, real values for the O&M costs were obtainedfrom local sources and converted to U.S. dollars at the exchange rate of 50,000 Krb per US$. To reflect

ANNEX 8Page 2

the current undervaluation in U.S. dollar terms of labor, materials and other items, O&M costs wereassumed to rise by 10% per year from 1995 to 2000, and by 5% per year thereafter under both the"with" and "without" project cases. The rehabilitation is expected to generate savings in O&M costsrelative to the "without" project situation. To reflect this, O&M costs increase at a lower rate under therehabilitation scenario, following the slope of an empirically determined curve that relates the rate ofchange in O&M costs to the age of the plants. Rehabilitation is essentially taken as the equivalent ofa "reduction" in the assumed age of the plant, with the reduction depending on the scope of therehabilitation.

B. System Control Rehabilitation

6 The main benefits associated with this component were quantified in terms of fuels savedas a result of improved (lower cost) allocation of total generation requirement among the generatingunits and improved power flow in the system. The achievable fuel savings were conservatively assumedat 2.5% of the annual fuel requirements (1.25% from 1997 to 1999 to reflect partial implementation).The underlying generation forecast for the period 1995-2020 was based on the electricity demandprojection presented in Annex 1. As a result of the upgrade of communications, dispatch and systemcontrol under the proposed project, about one-third of the thermal capacity would become available forautomatic economic dispatch. Fuel savings were valued at the projected economic price of heavy fueloil, natural gas and coal (see Annex 3 for the fuel price forecast).

7. Investment Costs. For each project component, investment costs used in the economicanalysis are based on detailed cost estimates in Annex 5. They include a 15 % physical contingencyallowance for all components. Because of the current undervaluation in U.S. dollars of locally procuredinvestment items, local investment costs also include 50% of the price contingency to reflect anticipatedrelative increases in unit prices of such inputs.


ECONOMIC ANALYSIS

HYDROPOWER REHABILITATION TOTAL FOR EIGHT PLANTS

1995 199 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007Economic price ol elecuicnv

Averege pric */MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak pric (.35%) $/MWh 27.0 2B.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 40.5 40.5 40.5

WITHOUT PROJECTElectricity output GWhIyr 9913 9857 9802 9746 9692 9637 9583 9529 9476 9423 9370 9318 9266Total revenue mion 1 256 267 278 289 300 311 322 332 343 353 363 361 359O & M coat milloon4 -3.6 -4.0 -4.5 -5.0 -5.5 -6.1 -6.5 -6.9 -7.3 -7.7 -8.2 -8.7 -9.2Net revenue midlion S 252 263 274 284 295 305 315 325 335 345 355 352 350Not Prsent Vn @ 10% mifion $ 2817

WITH PROJECTElectricity output GWhiyr 9913 9863 9860 9858 9875 9922 9954 9933 9913 9892 9871 9851 9830Total revenue millon $ 256 267 280 293 307 321 335 347 359 371 383 383 3820 & M coat million $ -3.6 -4.0 -4.5 -4.9 -5.5 -6.0 -6.4 -6.8 -7.1 -7.6 -8.0 -8.4 -8.9Total investment miNion $ -7.1 -12.8 -18.0 -25.5 -24.0 -14.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0Net revenue milion $ 245 251 258 263 277 301 329 340 352 364 375 374 373Net Preent Vaku @ 10% million t 2872

INCREM. NET REVENUE miNion $ -7.1 -12.6 -15.8 -21.6 -17.5 -4.0 13.5 15.2 16.9 18.8 20.7 21.9 23.2NPV 0incremental) @10% million $ 54.8EIRR (increwental) % 17.0%

Energyincrease/yr GWIVyr 0 6 58 112 186 289 376 410 443 475 508 540 572Ave. enrgy incieasafyf GWhiyr 567

Total nergy increase GWh 14186


ECONOMIC ANALYSIS

HYDROPOWER REHABILITATION TOTAL FOR EIGHT PLANTS

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Economic price of electricity

Average price $/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak price t + 35%) $/MWh 40.5 40.5 40.5 40.5 40.5 40 5 40.5 40.5 40.5 40.5 40.5 40.5 40 5

WITHOUT PROJECTElectricity output GWh/yr 9214 9163 9112 9062 9011 8961 8912 8862 8813 8765 8716 8668 8620Total revenue million S 357 355 353 351 349 347 345 343 341 340 338 336 3340 & M cost million $ -9.7 -10.3 *10,9 -11 6 -12.3 -13.0 -13.8 -14.6 -15.5 -16.4 -17 4 -18.4 -19.5Net revenue million $ 347 345 342 339 337 334 331 329 326 323 320 317 314Net Present Value @ 10% million $

WITH PROJECTElectricity output GWh/yr 9810 9790 9769 9749 9729 9709 9689 9669 9649 9629 9609 9589 9569Total revenue million $ 381 380 379 379 378 377 376 376 375 374 373 373 372O & M cost million S -9.4 -10.0 -10.5 -11.1 -11.8 -12.5 -13 2 -13.9 -14.7 -15.6 -16.4 -17.4 -18.4Total investment million $ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Net revenue million S 372 370 369 368 366 365 363 362 360 359 357 355 353Net Present Value @ 10% million S

INCREM. NET REVENUE million $ 24.4 25.7 26.9 28.1 29.4 30.6 31.8 33.0 34 2 35.4 36 6 37.8 38.9NPV (incremental) @10°/. million $EIRR (incrementall %

Energy increase/yr GWh/yr 603 635 666 697 727 757 787 817 846 876 905 933 962Aver. energy ncrease/yr GWh/yrTotal energy increase GWh

00to

UKRAINEHYDROPOWER REHABLITATION AND SYSTEM CONTROL PROJECT

ECONOMIC ANALYSIS

DAM SAFETY MONITORING

1995 1996 1997 1911 1999 2000 2001 2002 2003 2004 2006 2006 2007

Total invsmnt mAion * 0.43 1.32 0.44 0.75Donstic million 4 0.15 0.49 0.16 0.28Foreign million S 0.28 0.84 0.28 0.47

SYSTEM COKTROL ANDCOLMAUNCATIONS

Elecuicity consumnption TWIh 187.6 180.5 178.4 179.8 182.7 189 195.3 201.8 208.4 215.1 222 228.6 235.6Not eaports TWh 1 1 1 1.5 3 5 6 7 8 9 10 11 12Gross elet,. production TWh 188.6 181.5 179.4 181.3 185.7 194 201.3 208.8 216.4 224.1 232 239.6 247.6Thermal power genration TWh 105.6 101.6 100.5 101.5 104.0 108.6 112.7 116.9 121.2 125.5 129.9 134.2 138.7Fuelcostsolpow rgener. milionil 1363 1312 1297 1311 1342 1402 1431 1484 1538 1593 1649 1703 1760Fuel saving benefit milion $ 0.0 3.9 5.8 7.9 10.1 12.6 12.9 13.4 13.8 14.3 14 8 15.3 15.8

Total investment costs miHion $ -7.2 -10.8 -20.3 -21.2 -5.2 0.0Domestic milion $ -1.8 -2.8 -5.3 -5.6 -1.2 0.0Foreign milion S -5.3 -8.0 -15.0 -15.6 -4.0 0.0

Net baeft million $ -7.2 -6.9 -14.5 -13.4 4.9 12.6 12.9 13.4 13.8 14.3 14.8 15.3 15.8NPV @10% miHion S S53.6EIRR % 22.7%

TECHNICAL ASSISTANCE million S 2.26 1.36 0.55 0.31 0.31 0.32

PROJECT TOTALTOTAL NET BENEFITS million S -17.0 -22.2 -31.3 -36.0 -12.9 8.3 26.4 28.5 30.8 33.1 35.5 37.3 39.0NPV @ 10% million $ 101.9EIR % 18.1%


ECONOMIC ANALYSIS

DAM SAFETY MONITORING

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Total investment mniiion *Domestic milion SForeign million S

SYSTEM CONTROL ANDCOMMUNICATIONS

Electricity consmwtion TWh 242.9 250.3 257.7 261.6 265.5 269.5 273.5 277.6 281.8 286.0 290.3 294.7 299.1Nat expors TWh 13 14 15 15 15 15 15 15 15 15 15 15 15Gross elect,. production TWh 255.9 264.3 272.7 276.6 280.5 284.5 288.5 292.6 296.8 301.0 305.3 309.7 314.1Thwrmalpowargewration TWh 143.3 148.0 152.7 154.9 157.1 159.3 161.6 163.9 166.2 168.6 171.0 173.4 175.9Fuel costs ofpowertgew. mill $ 1819 1879 1939 1941 1968 1996 2025 2054 2083 2112 2143 2173 2204Fuel saving beweit miionS 16.4 16.9 17.4 17.5 17.7 18.0 18.2 18.5 18.7 19.0 19.3 19.6 19.8

Total investment cons milon $Domestic nmiion Foreign nion S

Net befths million 16.4 16.9 17.4 17.6 17.7 18.0 18.2 18.5 18.7 19.0 19.3 19.6 19.8NPV 10% rilon $EIRR %

TECHWICAL ASSOSTANCE niinS $

PROECT TOTALTOTAL NET 8ENFFITS rmibln * 40.8 42.6 44.4 45.6 47.1 48.6 60.0 51.5 52.9 54.4 55.9 57.3 58.8NPV @ 10% rniion $EIRR %


ECONOMIC ANALYSIS

DNIEPRODZERZSINSK HPS

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007WITHOUT PROJECT

Aver. economic price $/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price S/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 40.5 40.5 40.5Electricityoutput GWh/yr 1250 1244 1238 1231 1225 1219 1213 1207 1201 1195 1189 1183 117721% at average price GWh/yr 263 261 260 259 257 256 255 253 252 251 250 248 247Corresponding revenue thousand $ 5250 5485 5717 5947 6175 6400 6623 6843 7061 7277 7490 7453 741579% at peak price GWhiyr 988 983 978 973 968 963 958 953 949 944 939 935 930Corresponding revenue thousand $ 26663 27856 29036 30204 31360 32503 33634 34753 35860 36955 38038 37848 37659Total revenue thousand $ 31913 33341 34754 36152 37535 38903 40257 41596 42921 44232 45528 45301 45074O&M cost thousand $ -921 -1023 -1136 -1261 -1399 -1553 -1646 -1744 -1848 -1959 -2076 -2199 -2331Netrevenue thousand 4 30991 32318 33618 34891 36135 37350 38611 39852 41073 42273 43453 43101 42744NPV @10% thousand $ 344,283

WITH PROJECT

Aver. economic price $/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price S/MWh 27 28.35 29.7 31.05 32.4 33.75 35.1 36.45 37.8 39.15 40.5 40.5 40.5Electricity output GWh/yr 1250 1244 1238 1231 1225 1249 1257 1255 1254 1253 1251 1250 124920% at average price GWh/yr 263 261 260 246 245 250 251 251 251 251 250 250 250Corresponding revenue thousand $ 5250 5485 5717 5664 5881 6244 6534 6778 7022 7266 7509 7501 749480% at peak price GWh/yr 988 983 978 985 980 999 1005 1004 1003 1002 1001 1000 999Corresponding revenue thousand S 26663 27856 29036 30587 31757 33716 35283 36603 37921 39236 40548 40507 40467Total revenue thousand t 31913 33341 34754 36251 37638 39960 41816 43381 44943 46501 48057 48009 47961Total O&M cost thousand $ -921 -1023 -1136 -1261 -1399 -1549 -1636 -1729 -1827 -1930 -2039 -2154 -2276

O&M cost unrelated to rehab thousand 8 -921 -1023 -1136 -1261 -1399 -777 -823 -872 -924 -979 -1038 -1100 -1165O&M cost related to rehab thousand $ 0 0 0 0 0 -772 -813 -857 -902 -951 -1001 -1055 -1111

Investment, total thousand $ 0 0 -813 -2822 -2323 -2199Domestic thousand $ 0 0 -100 -1155 -1955 -2015Foreign thousand $ 0 0 -713 -1668 -368 -184

Netrevenue thousand $ 30992 32318 32805 32167 33915 36213 40180 41652 43116 44572 46018 45854 45685NPV @10% thousandi $ 354,074INCREM. NET REVENUE thousand $ 0 0 -813 -2724 -2220 -1137 1569 1800 2043 2298 2565 2753 2941

.m -. p. ,. ... :j S :. -... - .. 'Energy increase/yr GWhIyr 0 0 0 0 0 30 44 48 53 58 63 67 72Aver. enrgy increase/yr GWh/yr 85Total energy increase GWh 1782


ECONOMIC ANALYSIS

DNIEPRODZERZSINSK HPS2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

WITHOUT PHOJECT

Aver economic price fMWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak econoff.c price */MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Etectrcityoutput GWhjyr 1171 1165 1159 1154 1148 1142 1136 1131 1125 1119 1114 1108 110321%*atavergeprice GWhJyr 246 245 243 242 241 240 239 237 236 235 234 233 232Corfesponding revenue thouswnd $ 7378 7341 7305 7268 7232 7196 7160 7124 7088 7053 7017 6982 694779% at peak prsce Gwtvyr 925 921 916 911 907 902 898 893 889 884 880 876 871Corresponding revenue thous nd$ 37471 37283 37097 36911 36727 36543 36361 36179 35998 35818 35639 35461 35283Total revenue thousand 4 44849 44625 44402 44180 43959 43739 43520 43303 43086 42871 42656 42443 42231O&M cost thousand $ -2470 -2617 -2773 -2939 -3114 -3300 -3496 -3705 -3926 -4160 -4409 -4672 -4950Net revenue thousnd 42379 42008 41628 41241 40845 40439 40024 39598 39160 38710 38248 37771 37281NPV @10% thousand $

WITH PROJECT

Aver. economic price */MW`h 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price S/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electficityoutput GWh/yr 1248 1246 1245 1244 1243 1242 1240 1239 1238 1237 1235 1234 123320% *t average price GWhIyr 250 249 249 249 249 248 248 248 248 247 247 247 247Corresponding revenue thousand 1 7486 7479 7471 7464 7456 7449 7442 7434 7427 7419 7412 7404 739780% at peak price GWhyr 998 997 996 995 994 993 992 991 990 989 988 987 986Corresponding revenue thousand 4 40426 40386 40346 40305 40265 40225 40185 40144 40104 40064 40024 39984 39944Total revenue thousand $ 47913 47865 47817 47769 47722 47674 47626 47578 47531 47483 47436 47388 47341Total O&M cost thousand S -2405 -2541 -2685 -2837 -2998 -3167 -3347 -3536 -3737 -3949 -4172 -4409 -4659O&M cost unrelted to rehab thouand -1235 -1308 -1387 -1469 -1557 -1650 -1748 -1853 -1963 -2080 -2204 -2336 -2475O&Mcost reltedtoreheb thousandS -1170 -1233 -1299 -1368 -1441 -1518 -1599 -1684 -1774 -1868 -1968 -2073 -2184

Invesatent, total thousand SOomstic thousand SForeign thousand 1

Net revenue thousand $ 45508 45324 45132 44932 44724 44506 44279 44042 43794 43535 43263 42979 42682NPV @10% thousand *INCREM NET REVENUE thousand $ 3128 3316 3504 3691 3879 4067 4256 4444 4634 4824 5016 5208 5402

Ermgy incrve yr GWwyr 77 81 86 90 95 99 104 108 113 117 121 126 130Aver. energy iaaeyr GWhVrFTotal energy cres GWh

twi CO


ECONOMIC ANALYSIS

DNIEPER I HPS1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

WITHOUT PROJECT

Aver. economic price S/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30

Peak economic price $/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 40 5 40.5 40.5

Electricity output GWh/yr 1800 1791 1782 1773 1764 1755 1747 1738 1729 1721 1712 1703 1695

21% at average price GW/yrf 378 376 374 372 370 369 367 365 363 361 360 358 356

Corresponding revenue thousand S 7560 7898 8233 8564 8892 9216 9537 9854 10168 10478 10786 10732 10678

79% at peak price GWh/yr 1422 1415 1408 1401 1394 1387 1380 1373 1366 1359 1352 1346 1339

Corresponding revenue thousand $ 38394 40112 41812 43494 45158 46805 48433 50045 51639 53216 54775 54502 54229

Total revenue thousand $ 45954 48010 50045 52058 54050 56021 57970 59899 61807 63694 65561 65233 64907

O&M cost thousand $ -255 -283 -315 -349 -388 -430 -456 -483 -512 543 -575 -609 -646

Netrevenue thousand S 45699 47727 49731 51709 53662 55590 57514 59416 61295 63151 64986 64624 64261

NPV @10% thousand 8 515,847

WITH PROJECT


Peak economic price S/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 40.5 40.5 40.5


20% at average price GWhIyr 378 376 361 364 367 370 373 372 372 371 371 371 370




Total revenue thousand 8 45954 48010 50840 53575 56347 59155 62001 64321 66636 68947 71253 71182 71111

O&M cost thousand $ -255 -283 -307 -332 -359 -388 -410 -433 -457 -482 -509 -537 -567

Investment, total thousand S -2597 -5004 -5024 -5971 -5527 -3897

Domestic thousand $ -2597 -2936 -2956 -2990 -3052 -2940

Foreign thousand $ 0 -2068 -2068 -2981 -2475 -957

Net revenue thousand $ 43102 42723 45510 47272 50460 54870 61591 63888 66180 68465 70745 70645 70544

NPV @10% thousand J 530,757INCREM. NET REVENUE thousand $ -2597 -5004 -4221 -4437 -3202 -721 4077 4473 4885 5314 5759 6022 6283

N$9 CwtO% '-.',', -,ltt -. -.

Energy increase/yr GWh/yr 0 0 23 47 70 93 116 123 130 137 144 150 157

Aver. energy increase/yr GWh/yr 159

Total energy increase GWh 3818

> r


ECONOMIC ANALYSIS

DNIEPER I HPS2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

WITHOUT PROJECT

Aver. economic price S/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak sconornic price $/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electrisctyoutput GWh/yr 1686 1678 1670 1661 1653 1645 1636 1628 1620 1612 1604 1596 158821% at average proce GWh/yr 354 352 351 349 347 345 344 342 340 339 337 335 333Corresponding revenue thousand $ 10625 10571 10519 10466 10414 10362 10310 10258 10207 10156 10105 10055 1000479% at peak price GWh/yr 1332 1326 1319 1312 1306 1299 1293 1286 1280 1274 1267 1261 1255Correspondcng revenue thousand $ 53958 53688 53420 53153 52887 52622 52359 52097 51837 51578 51320 51063 50808Total revenue thousand 64582 64260 63938 63619 63300 62984 62669 62356 62044 61734 61425 61118 60812O&M cost thousand S -684 -725 -768 -814 -863 -914 -969 -1027 -1088 -1153 -1222 -1295 -1372Net revenue thousand S 63898 63534 63170 62804 62438 62070 61700 61329 60956 60581 60203 59823 59441NPV @10% thousand S

WITH PROJECT

Aver. economic price I/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price S/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electricity output GWh/yr 1850 1848 1846 1844 1843 1841 1839 1837 1835 1833 1832 1830 182820% at average price GWh/yr 370 370 369 369 369 368 368 367 367 367 366 366 366Corresponding revenue thousand $ 11100 11089 11078 11067 11056 11045 11034 11023 11011 11000 10989 10978 1096880% at peak price GWh/yr 1480 1479 1477 1476 1474 1473 1471 1470 1468 1467 1465 1464 1462Corresponding revenue thousand S 59940 59880 59820 59760 59701 59641 59581 59522 59462 59403 59343 59284 59225Total revenue thousand $ 71040 70969 70898 70827 70756 70685 70615 70544 70474 70403 70333 70262 70192O&M cost thousand $ -598 -631 -666 -703 -742 -784 -827 -873 -921 -972 -1026 -1083 -1143Investment, total thousand $

Domestic thousand SForeign thousand S

Net revenue thousand S 70442 70338 70232 70124 70014 69902 69788 69671 69552 69431 69306 69179 69049NPV @1o% thousand *INCREM. NET REVENUE thousand S 6544 6803 7062 7319 7576 7832 8088 8342 8596 8850 9103 9356 9608

{ -w16--- .. ~~~...... ....

Energy increase/yr GWh/yr 164 170 177 183 190 196 202 209 215 221 228 234 240Avr nrgy increase/yr GWh/yrTotal energy increase GWh

w a

UKRAINEHYDROPOWER REHABIUTATION AND SYSTEM CONTROL PROJECT

ECONOMIC ANALYSIS

DNIEPR H HPS1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

WITHOUT PROJECT

Avr. econonii price */MWih 20 21 22 23 24 25 26 27 28 29 30 30 30Peak ecorwonic price S/MW\h 27 28.35 29.7 31.05 32.4 33.75 35.1 36.45 37.8 39.15 40.5 40.5 40.5Electricity output GWh/yr 2340 2328 2317 2305 2294 2282 2271 2259 2248 2237 2226 2214 220321% at averge price GWhIyr 491 489 486 484 482 479 477 474 472 470 467 465 463Correspondingrevenue thousandS 9828 10268 10703 11134 11559 11981 12398 12810 13218 13622 14021 13951 1388179% atpeekprice GWhiyr 1849 1839 1830 1821 1812 1803 1794 1785 1776 1767 1758 1749 1741Correspordig revenue thousand $ 49912 52146 54356 56542 58706 60846 62963 65068 67130 69180 71208 70852 70498Total revenue thousand S 59740 62414 65059 67676 70265 72827 75361 77869 80349 82802 85229 84803 84379O&M cost thousand S -314 -348 -387 -429 -476 -529 -560 -594 629 -667 -707 -749 -794Net revenue thousandS 59426 62065 64672 67247 69789 72298 74801 77275 79719 82135 84523 84054 83586NPV @10% thousand $ 670.942

WITH PROJECT

Aver. economic price $/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price S/MWh 27 28.35 29.7 31.05 32.4 33.75 35.1 36.45 37.8 39.15 40.5 40.5 40.5Electricity output GWh/yr 2340 2328 2317 2307 2298 2289 2280 2271 2262 2253 2244 2235 222620% at avrage price GWh/yr 491 489 463 461 460 458 456 454 452 451 449 447 445Correspondin revenue thousand S 9828 10268 10193 10614 11031 11445 11855 12262 12665 13065 13461 13407 1335480% at peak prce GWh/yr 1849 1839 1853 1846 1839 1831 1824 1817 1809 1802 1795 1788 1781Corfesponding revenue thousand S 49912 52146 55044 57316 59568 61802 64017 66213 68391 70550 72691 72400 72111Tote revenue thousand S 59740 62414 65237 67930 70600 73247 75872 78475 81056 83615 86153 85808 85465

OhM cost thousand S -314 -348 -387 -427 -473 -523 -552 -582 -615 -649 -685 -723 -763Investment, total thousnd $ -35 -1023 -2347 -2250 -907

Dorestic thousand S -12 -206 -312 -180 -79Foreign thousand S -23 -817 -2036 -2070 -828

Net revenue thousand S 59392 61043 62503 65252 69220 72724 75321 77893 80442 82967 85468 85085 84702

NPV @10% thousIndS 672,415INCREM.NETREVENUE thousandS -36 -1023 -2169 -1994 -569 426 520 618 722 831 945 1031 1116

X i S -;j~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~. .g .... .8:

Enrgyincrease/yr GWhnyr 0 0 0 2 5 7 9 11 14 16 18 20 22Aver. enrgy ncfesee/yr GWh/yr 24Total energy hrges GWh 599

U10


ECONOMIC ANALYSIS

DNIEPR II HPS2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

WITHOUT PROJECT

Aver, economic price S/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price S/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40 5 40.5 40.5Electricity output GWh/yr 2192 2181 2171 2160 2149 2138 2127 2117 2106 2096 2085 2075 206421% at average price GWh/yr 460 458 456 454 451 449 447 445 442 440 438 436 434Corresponding revenue thousand S 13812 13743 13674 13606 13538 13470 13403 13336 13269 13203 13137 13071 1300679%atpeakprice GWh/yr 1732 1723 1715 1706 1698 1689 1681 1672 1664 1656 1647 1639 1631Correspondrig revenue thousand $ 70145 69794 69446 69098 68753 68409 68067 67727 67388 67051 66716 66382 66050Total revenue thousand $ 83957 83537 83120 82704 82291 81879 81470 81062 80657 80254 79853 79453 79056O&M cost thousand S -841 -891 -944 1001 -1060 -1123 -1190 -1262 -1337 1417 -1501 -1591 -1685Net revenue thousand 5 83116 82646 82176 81704 81230 80756 80279 79801 79320 78837 78352 77863 77371NPV @10% thousand $

WITH PROJECT

Aver, economic price S/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price S/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electricityoutput GWh/yr 2217 2208 2199 2190 2181 2173 2164 2155 2147 2138 2130 2121 211320% at average price GWh/yr 443 442 440 438 436 435 433 431 429 428 426 424 423Corresponding revenue thousand $ 13300 13247 13194 13141 13089 13037 12984 12932 12881 12829 12778 12727 1267680% at peak price GWh/yr 1773 1766 1/59 1752 1745 1738 1731 1724 1717 1711 1704 1697 1690Corresponding revenue thousand $ 71822 71535 71249 70964 70680 70397 70116 69835 69556 69278 69001 68725 68450Total revenue thousand $ 85123 84782 84443 84105 83769 83434 83100 82768 82437 82107 81779 81451 81126O&M cost thousand S -805 -850 -897 -946 -999 .1054 -1113 -1174 -1240 -1308 -1381 -1458 -1538Investment, total thousand ,

Domestic thousand SForeign thousand $

Net revenue thousand $ 84318 83933 83547 83159 82770 82380 81987 81593 81197 80799 80398 79994 79587NPV @10% thousand $INCREM NET REVENUE thousand S 1202 1286 1371 1455 1540 1624 1708 1792 1877 1961 2046 2131 2217

Energy increase/yr GWh/yr 24 26 29 31 33 35 37 39 41 43 44 46 48Aver energy increase/yr GWh/yrTotal energy increase GWh

>2


ECONOMIC ANALYSIS

KIEV HPS1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

WITHOUT PROJECT


Peak economic price $/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37 8 39.2 40 5 40 5 40.5


21% at average price GWh/yr 133 131 129 127 126 124 122 120 118 116 115 113 111


79% at peak price GWhiyr 502 494 487 479 472 465 458 451 445 438 431 425 418


Total revenue thousand 5 16212 16767 17302 17817 18313 18790 19248 19688 20111 20517 20906 20593 20284

O&M cost thousand $ -366 -407 -451 -501 -556 -618 -654 -694 -735 -779 -825 -874 -927

Net revenue thousand $ 15845 16360 16850 17316 17756 18172 18593 18995 19376 19738 20081 19718 19357

NPV @10% thousand $ 162.489

WITH PROJECT

Aver, economic price S/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30

Peak economic price $/MWh 27 28.35 29.7 31.05 32.4 33.75 35.1 36.45 37.8 39.15 40.5 40 5 40.5


20% at average price GWh/yr 133 133 127 128 128 129 129 129 129 129 129 129 129




Total revenue thousand * 16212 16937 17879 18782 19694 20613 21540 22346 23150 23953 24754 24729 24705

Total O&M cost thousand 5 -366 -407 -451 -500 -554 -614 -649 -687 -727 -769 -814 -861 -911

O&M cost unrelated to rehab thousand S -366 -407 -271 -301 -334 -371 -393 -416 -441 -467 -495 -525 -556

O&M cost related to rehab thousand S 0 0 -180 -199 -220 -243 -257 -271 -286 -302 -318 -336 -355

Investment, total thousand 8 -2943 -3017 -3094 -5616 -8976 -4278

Domestic thousand $ -2656 -2730 -2806 -3696 -3951 -3267

Foreign thousand $ -288 -288 -288 -1921 -5026 -1011

Net revenue thousand S 12902 13513 14335 12666 10164 15721 20890 21659 22423 23184 23941 23869 23794

NPV @10% thousand S 167.567

INCREM NET REVENUE thousand $ -2943 -2847 -2516 -4649 -7593 -2451 2297 2664 3047 3446 3859 4150 4437... it~sEs *O. .h41 , -. ,- ,,,, O............. . ..

X,.#~ - -~ - - ....% - - -....... ...Energy increase/yr GWh/yr 0 6 19 31 43 55 67 75 83 91 99 106 114

Aver energy increase/yr GwhIyr 116

Total energy increase GWh 2891

O'rO02


ECONOMIC ANALYSIS

KIEV HPS

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020WITHOUT PROJECT

Aver. economic price $/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price $/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electricity output GWh/yr 522 514 506 499 491 484 476 469 462 455 449 442 43521 % at average price GWh/yr 110 108 106 105 103 102 100 99 97 96 94 93 91Corresponding ievenue thousand $ 3287 3238 3189 3141 3094 3048 3002 2957 2913 2869 2826 2783 274279% at peak price GWh/yr 412 406 400 394 388 382 376 371 365 360 354 349 344Corresponding revenue thousand $ 16693 16442 16196 15953 15713 15478 15246 15017 14792 14570 14351 14136 13924Total reverue thousand $ 19980 19680 19385 19094 18808 18525 18248 17974 17704 17439 17177 16919 16666O&M cost thousand S -982 -1040 -1103 -1168 -1238 -1312 -1390 -1473 -1561 -1654 -1753 -1857 -1968Net revenue thousand $ 18998 18639 18282 17926 17569 17214 16857 16501 16143 15785 15424 15062 14697NPV @10% thousand $

WITH PROJECT

Aver. economic price $/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price $1MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electricity output GWh/yr 643 642 641 641 640 640 639 638 638 637 636 636 63520% at average proce GWh/yr 129 128 128 128 128 128 128 128 128 127 127 127 127Corresponding rerenue thousand $ 3856 3852 3849 3845 3841 3837 3833 3829 3826 3822 3818 3814 381080% at peak price GWh/yr 514 514 513 513 512 512 511 511 510 510 509 609 508Corresponding revenue thousand $ 20824 20803 20782 20761 20741 20720 20699 20678 20658 20637 20616 20596 20575Total revenue thousand 8 24680 24655 24631 24606 24581 24557 24532 24508 24483 24459 24434 24410 24385Total 0&M i-ost thousand S -964 -1020 -1079 -1141 -1208 -1278 -1352 -1430 -1513 -1601 -1694 -1793 -1897

O&M cost unrelated to rehab thousand S -589 -624 -662 -701 -743 -787 -834 -884 -937 -992 -1052 -1114 -1181O&M cost related to rehab thousand S -374 -395 -417 -440 -465 -490 -518 -546 -577 -609 -642 -678 -716

Investment, total thousand $Domestic thousand SForeign thousand 8

Net revenue thousand S 23716 23636 23552 23465 23374 23279 23180 23077 22970 22858 22740 22617 22489NPV @10% thousand $INCREM. NET REVENUE thousand $ 4719 4996 5270 5539 5804 6066 6323 6577 6827 7073 7316 7555 7791NPV On ttMntail) @10% -. th;sn4114^lf iint,ementfii , d.J: ... : :: ::.Energy increase/yr GWh/yf 121 128 135 142 149 156 162 169 175 182 188 194 200Aver. energy increase/yr GWh/yrTotal energy increase GWh

_ \~~~~~~~~~~~~~~~~~~~~~~~~~


ECONOMIC ANALYSIS

KAKHOVKA HPS____________________________________ 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007WITHOUT PROJECT

Aver, economic price S/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price S/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 40.5 40.5 40.5Electricity output GWh/yr 1420 1413 1406 1399 1392 1385 1378 1371 1364 1357 1351 1344 133721% at average price GWh/yr 298 297. 295 294 292 291 289 288 286 285 284 282 281Corresponding revenue thousand $ 5964 6231 6495 6756 7015 7270 7523 7774 8021 8266 8509 8466 842479%atpeak price GWh/yr 1122 1116 1111 1105 1100 1094 1089 1083 1078 1072 1067 1062 1056Corresponding revenue thousand S 30289 31644 32985 34312 35625 36924 38209 39480 40737 41981 43212 42996 42781Total revenue thousand 9 36253 37875 39480 41068 42640 44194 45732 47254 48759 50248 51720 61462 51204O&M cost thousand S -422 -468 -520 -577 -641 -711 -754 -799 -846 -897 -950 -1007 -1067Net revenue thousand S 35831 37407 38960 40491 41999 43483 44978 46455 47912 49351 50770 50455 50137NPV @10% thousand $ 402,815

WITH PROJECT

Aver, economic price $/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price S/MWh 27 28.35 29.7 31.05 32.4 33.75 35.1 36.45 37.8 39.15 40.5 40.5 40.5Electricity output GWh/yr 1420 1413 1422 1431 1439 1448 1457 1455 1454 1452 1451 1449 144820% at average price GWh/yr 298 297 284 286 288 290 291 291 291 290 290 290 290Corresponding revenue thousand S 5964 6231 6255 6580 6909 7241 7575 7858 8141 8423 8705 8696 868880%atpeakprice GWh/yr 1122 1116 1137 1144 1151 1158 1165 1164 1163 1162 1161 1160 1158Corresponding revenue thousand $ 30289 31644 33780 35534 37307 39099 40903 42434 43962 45486 47007 46960 46914Total revenue thousand $ 36253 37875 40035 42114 44215 46339 48478 50292 52103 53909 55713 55657 55601Total O&M cost thousand S -422 -468 -518 -538 -636 -704 -744 -786 -831 -878 -928 -981 -1037

O&M cost unrelated to rehab thousand $ -422 -468 -173 -192 -214 -237 -251 -266 -282 -299 -317 -336 -356O&M cost related to rehab thousand S 0 0 -345 -382 -422 -467 -493 -520 -549 -579 -611 -645 -681

Investment total thousand S -1534 -3768 -2773 -4008 -3583 -2252Domestic thousand S -1534 -2184 -1871 -1643 -1823 -1647Foreign thousand S 0 -1584 -902 -2365 -1760 -605

Net revenue thousand $ 34296 33639 36744 37569 39996 43383 47734 49506 51272 53031 54785 54676 54565NPV @10% thousand $ 414,548INCREM NET REVENUE thousand S -1535 -3768 -2216 -2922 -2003 -100 2756 3051 3359 3681 4015 4221 4427

^R.. -- 1*3;Energy increaseayr G/yrYr 0 0 16 32 47 63 79 84 90 95 100 106 111Aver energy increase/yr GWh/yr 114Total energy increase GWh 2729

7)~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~>


ECONOMIC ANALYSIS

KAKI4OVKA HPS

2008 2009 2010 2011 2012 2013 2014 2016 2016 2017 2018 2019 2020WITHOUT PROJECT

Aver. economic price $/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price $/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40 5 40.5Electricityoutput GWhlyr 1330 1324 1317 1311 1304 1297 1291 1285 1278 1272 1265 1259 125321% at average price GWh/yr 279 278 277 275 274 272 271 270 268 267 266 264 263Corresponding revenue thousand 8382 8340 8298 8257 8215 8174 8133 8093 8052 8012 7972 7932 789279%h t peak price GvhWyr 1051 1046 1041 1035 1030 1025 1020 1015 1010 1005 1000 995 990Corresponding revenue thousand* 42567 42354 42142 41931 41722 41513 41306 41099 40894 40689 40486 40283 40082Total cevenue thousand 8 50948 50694 50440 50188 49937 49687 49439 49192 48946 48701 48458 48215 47974O&Mcost thousand* -1131 -1198 -1270 -1345 -1426 -1511 -1601 -1696 -1797 -1905 -2018 -2139 -2266Net revenue thousand 1 49818 49496 49171 48843 48511 48177 47838 47495 47148 46796 46439 46076 45708NPV @10% thousnd 8

WITH PROJECT

Aver. econonic price /MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peek economic price *IMWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electriity output GWhJyr 1447 1445 1444 1442 1441 1439 1438 1436 1435 1434 1432 1431 142920% at average price GWhIr 289 289 289 288 288 288 288 287 287 287 286 286 286Corresponding revenru thousand 1 8679 8670 8662 8653 8644 8636 8627 8618 8610 8601 8593 8584 eI57580%atpeakprice GWh/yr 1157 1156 1155 1154 1153 1151 1150 1149 1148 1147 1146 1145 1143Corresponding revenue thousand , 46867 46820 46773 46726 46679 46633 46586 46540 46493 46447 46400 46354 46307Total revenue thousand 8 55546 55490 55435 55379 55324 55268 55213 55158 55103 55048 54993 54938 54883Total O&M cost thousand -1096 -1158 -1224 -1293 -1367 -1445 -1527 -1614 -1706 -1803 -1906 -2014 -2129

O&M cost unrelated to rehab thousand $ -377 -399 -423 -448 -475 -504 -534 -565 -599 -635 -673 -713 -755O&M coat related to rehab thousand 8 -719 -759 -801 -845 -892 -941 -994 -1049 -1107 -1168 -1233 -1301 -1374

Investment, total thousand 1Domestic thousand 8Foreign thousand $

Net revenue thousand $ 54450 54332 54211 54086 53957 53824 53686 53544 53397 53245 53087 52923 52754NPV@1% thousand $INCREM NET REVENUE thousand 1 4632 4837 5040 5243 5446 5647 5848 6048 6249 6448 6648 6847 7046

Energyincrease/yr GWhJyr 116 121 126 132 137 142 147 152 157 162 167 172 176Aver. enrgy increas/yr GWhJytTotal energy increase GWh

to7\~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~0


ECONOMIC ANALYSIS

KANEV HPS1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

WITHOUT PROJECT

Aver. economic price S/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price S/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 . 40.5 40.5 40 5Electricity output GWh/yr 850 846 842 837 833 829 825 821 817 813 808 804 80021%ataverageprice GWh/yr 179 178 177 176 175 174 173 172 171 171 170 169 168Corresponding revenue thousand $ 3570 3730 3888 4044 4199 4352 4503 4653 4902 4948 5093 5068 504279% at peak price GWh/yr 672 668 665 661 658 655 652 648 645 642 639 635 632Corresponding revenue thousand $ 18131 18942 19745 20539 21325 22102 22871 23632 24385 25130 25866 25737 25608Total revenue thousand S 21701 22672 23632 24583 26524 26454 27375 28286 29187 30078 30959 30805 30651O&M cost thousarnd -444 -493 -547 -607 -674 -749 -793 -841 -891 -944 -1000 -1060 1123Netrevenue thousand S 21256 22179 23085 23976 24849 25706 26582 27445 28296 29134 29959 29745 29527NPV @10% thousand $ 237,532

WITH PROJECT

Aver, economic price $/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price $/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 40.5 40 5 40 5Electricityoutput GWh/yr 850 846 842 837 834 831 827 824 821 817 814 8el 8C320% at average price GWh/yr 179 178 177 176 167 166 165 165 164 163 163 162 1fiCorresponding revenur thousand $ 3570 3730 3888 4044 4003 4153 4302 4450 4596 4741 4885 4865 4c.4680% at peak price GWh/yr 672 668 665 661 667 665 662 659 657 654 651 649 646Corresponding revenue thousand $ 18131 18942 19745 20539 21616 22427 23231 24028 24818 25602 26378 26273 26168Total revenue thousand 8 21701 22672 23632 24583 25619 26580 27533 28477 29414 30343 3,263 31138 3101e0&M cost thousand $ -444 -493 -547 -607 -672 -746 -791 -838 -888 -941 -997 -1057 -1120Investment, total thousand $ 0 0 -428 -105

Domestic thousand $ 0 0 -37 -13Foreign thousand $ 0 0 -391 -92

Net revenue thousand 8 21256 22179 22657 23871 24947 25834 26742 27639 28526 29401 30266 30081 29894NPV @10% thousand S 239,055INCREM. NET REVENUE thousand $ 0 0 -428 -105 98 128 160 194 230 268 307 337 367

0R........... . ::

Energy increase/yr GWh/yr 0 0 0 0 1 2 2 3 4 5 6 6 7Aver.energy increase/yr GWhlyr 8Total energy ircrease GWh 199


ECONOMIC ANALYSIS

KANEV HPS

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020WITHOUT PROJECT

Aver, economic price S/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price $/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40 5 40 5 40.5Electricity output GWh/yr 796 792 788 784 781 777 773 769 765 761 757 754 75021%ataveregeprice GWh/yr 167 166 166 165 164 163 162 161 161 160 159 158 157Corresponding revenue thousand s 5017 4992 4967 4942 4918 4893 4869 4844 4820 4796 4772 4748 472479% at peak price GWh/yr 629 626 623 620 617 614 610 607 604 601 598 595 592Corresponding revenue thousand $ 25480 25353 25226 25100 24974 24849 24725 24602 24479 24356 24234 24113 23993Total revenue thousand S 30497 30345 30193 30042 29892 29742 29594 29446 29299 29152 29006 28861 28717O&M cost thousand S -1190 -1261 1336 -1416 -1501 -1590 -1685 -1786 -1892 -2005 -2125 -2251 -2386Net revenue thousand $ 29307 29084 28857 28626 28391 28152 27909 27660 27406 27147 26882 26610 26331NPV @10% thousand 8

WITH PROJECT

Aver, economic price S/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price $/MWh 40.5 40.6 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40 5 40.5Electricity output GWh/yr 804 801 798 795 792 788 785 782 779 776 773 770 76720%ataverageprice GWh/yr 161 160 160 159 158 158 157 156 156 155 155 154 153Corresponding revenue thousand 8 4827 4807 4788 4769 4750 4731 4712 4693 4674 4656 4637 4618 46h080%atpeakprice GWh/yr 644 641 638 636 633 631 628 626 623 621 618 616 613Corresponding revenue thousand $ 26063 25959 25855 25752 25649 25546 25444 25342 25241 25140 25039 24939 24833Total revenue thousand 8 30890 30766 30643 30520 30398 30277 30156 30035 29915 29795 29676 29557 29439O&M cost thousand $ -1187 -1257 -1332 -1412 -1496 -1585 -1680 -1780 -1886 -1999 -2118 -2245 -2379Investment, total thousand S

Domestic thousand S

Foreign thousand 8Net revenue thousand 8 29703 29509 29311 29109 28902 28691 28476 28255 28028 27796 27558 27313 27061NPV @10% thousand 8INCREM. NET REVENUE thousand 8 396 425 454 483 511 539 567 595 622 649 676 703 729

Energy increase/yr GWh/yr 8 9 10 10 11 12 13 13 14 15 15 16 17Aver energy increase/yr GWhtyrTotal energy increase GWh

. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~00


ECONOMIC ANALYSIS

KIEV PUMP STOfRAGE1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

WITHOUT PROJECT

Aver. econonuc price */MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peek econormic price $/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 40.5 40.5 40.5

Electrycu outp t(turbinel GWhiyr 112 111 111 110 110 109 109 108 108 107 107 106 1050% at average price GWhlyr 0 0 0 0 0 0 0 0 0 0 0 0 0

Corresponding revenue thousand S 0 0 0 0 0 0 0 0 0 0 0 0 0100% tpspkprice GWhlyr 112 111 111 110 110 109 109 108 108 107 107 106 105

Correuponding revenue thousand S 3024 3159 3293 3426 3557 3686 3815 3942 4067 4191 4314 4293 4271

Elecriciy output (pumping) GWh/yr 108 107 107 106 106 105 105 104 104 103 103 102 102

Adjusted coiresp. revenue thousand $ 2712 2833 2953 3072 3190 3306 3421 3535 3647 3759 3869 3850 3830Toteirevenue thousandw 5736 5993 6247 6498 6746 6992 7236 7476 7715 7950 8183 8142 8102O&M cost thousand * -233 -259 -287 -319 -354 -393 -416 -441 -468 -496 -525 -556 -590Net revenue thousarnd * 5503 5734 5959 6179 6392 6599 6819 7035 7247 7455 7658 7586 7512NPV @10% thousand S 60,615

WITH PROJECT

Aver. economic prkc $/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economnic prke S/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 40.5 40.5 40.5Electricityoutput(turbine) GWh/yr 112 111 111 110 111 112 113 113 113 113 113 113 1130% at aveage prce GWhlyr 0 0 0 0 0 0 0 0 0 0 0 0 0


100% atpeakprce GWh/yr 112 111 111 110 111 112 113 113 113 113 113 113 113Couresponding revenue thousand * 3024 3159 3293 3426 3607 3791 3978 4127 4275 4424 4571 4567 456?Elecuicitycoutput(purnping) GWhlyr 108 107 107 106 108 109 110 110 110 110 110 109 1:9Adjusted corresp. revenue thousand * 2712 2833 2953 3072 3254 3421 3591 3725 3859 3993 4127 4122 4118Total revenue thousand S 5736 5993 6247 6498 6861 7212 7569 7852 8134 8417 8698 8689 8681O&M cost thousand $ -233 -259 -287 -318 -351 -388 -410 -433 -457 -482 -509 -537 -567Investment, total thousand 1 0 0 -524 -2541 -1256 -25

Domestc thousand * 0 0 -99 -218 -106 -14Foreign thousand * 0 0 -425.5 -2323 -1150 -11.5

Net revenue thousand $ 5503 5734 5435 3639 5254 6799 7159 7419 7678 7935 8189 8152 8114NPV @10% thousand $ 60817

INCREM. NET REVENUE thousand S 0 0 -524 -2540 -1138 199 339 384 431 480 531 567 602

Energy mcnresaeyr GWhlyr 0 0 0 0 4 7 10 11 12 12 13 14 15

Aver. energy Increase/yr GWh/yr 16Total energy icreese GWh 362

~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~.00


ECONOMIC ANALYSIS

KIEV PUMP STORAGE2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

WITHOUT PROJECT

Aver. economic price S/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price $/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electricity output (turbine) GWh/yr 105 104 104 103 103 102 102 101 101 100 . 100 99 990% at average price GWh/yr 0 0 0 0 0 0 0 0 0 0 0 0 0Corresponding revenue thousand $ 0 0 0 0 0 0 0 0 0 0 0 0 0100% at peak price GWhiyr 105 104 104 103 103 102 102 101 101 100 100 99 99Corresponding revenue thousand * 4250 4229 4207 4186 4165 4145 4124 4103 4083 4062 4042 4022 4002Electricity output (pumping! GWh/yr 101 101 100 100 99 99 98 98 97 97 96 96 95Adjusted coriesp. revenue thousand S 3811 3792 3773 3754 3736 3717 3698 3680 3661 3643 3625 3607 3589Total revenue thousand 4 5061 8021 7981 7941 7901 7862 7822 7783 7744 7705 7667 7629 7590O&M cost thousand $ -625 -662 -702 -743 -788 -835 -885 -937 -993 -1053 -1115 -1182 -1252Net revenue thousand $ 7436 7359 7279 7197 7113 7027 6938 6846 6751 6653 6552 6447 6338NPV @10% thousand $

WITH PROJECT

Aver. economic price $/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price S/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electricity output turbine) GWh/yr 113 112 112 112 112 112 112 112 112 112 111 111 1110% at average price GWh/yr 0 0 0 0 0 0 0 0 0 0 0 0 0Corresponding revenue thousand $ 0 0 0 0 0 0 0 0 0 0 0 0 0100% at peak price GWhiyr 113 112 112 112 112 112 112 112 112 112 111 111 110Corresponding revenue thousand S 4558 4553 4549 4544 4540 4535 4530 4526 4521 4517 4512 4508 4455Electricity output (pumping) GWh/yr 109 109 109 109 109 109 109 108 108 108 108 108 108Adjusted corresp. revenue thousand S 4114 4110 4106 4102 4098 4094 4090 4086 4081 4077 4073 4069 4065Total revenue thousand $ 8672 8663 8655 8646 8637 8629 8620 8611 8603 8594 8586 8577 8520O&M cost thousand $ -598 -631 -666 -703 -742 -783 -827 -873 -921 -972 -1026 -1083 -1143Investment, total thousand $

Domestic thousand $Foreign thousand $

Net revenue thousand S 8074 8032 7988 7943 7895 7845 7793 7739 7682 7622 7560 7494 7377NPV @10% thousand S

INCREM. NET REVENUE thousand S 638 673 709 745 782 819 856 893 931 969 1008 1047 1039

Energy rncreaselyr GWhiyr 16 16 17 18 19 20 20 21 22 23 24 24 25Aver. energy increase/yr GWh/yrTotal energy increase GWh

hO 00w


ECONOMIC ANALYSIS

KREMENCHUG HPS1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

WITHOUT PROJECT

Aver. economic pf,ce S/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price S/MWh 27.0 28.4 29.7 31.1 32.4 33.8 35.1 36.5 37.8 39.2 . 40.5 40.5 40.5Electricity output GWhIyr 1506 1498 1491 1484 1476 1469 1461 1454 1447 1440 1432 1425 141821% at average price GWhiyr 316 315 313 312 310 308 307 305 304 302 301 299 298Corresponding revenue thousand $ 6325 6608 6888 7165 7440 7711 7979 8245 8507 8767 9024 8979 893479% at peak price GWh/yr 1190 1184 1178 1172 1186 1160 1154 1149 1143 1137 1132 1126 1120Corresponding revenue thousand S 32123 33560 34983 36390 37782 39160 40523 41871 43204 44524 45829 45600 45372Total revenue thousand S 38448 40169 41871 43555 45222 46871 48502 50115 51712 53291 54853 54578 54306O&M cost thousand S -677 -752 -835 -926 -1028 -1142 -1210 -1282 -1358 -1440 -1525 -1616 -1713Net revenue thousand $ 37771 39417 41037 42629 44194 45729 47292 48833 50353 51851 53327 52962 52593NPV @10% thousand $ 422,905

WITH PROJECT

Aver. economic price $/MWh 20 21 22 23 24 25 26 27 28 29 30 30 30Peak economic price $SMWh 27 28.35 29.7 31.05 32.4 33.75 35.1 36.45 37.8 39.15 40.5 40.5 40.5Electricity output GWh/yr 1506 1498 1491 1484 1492 1501 1510 1507 1504 1501 1498 1495 149220% at average price GWhlyr 316 315 313 312 298 300 302 301 301 300 300 299 298Corresponding aevenue thousand $ 6325 6608 6888 7165 7163 7504 7853 8139 8424 8707 8989 8971 895380% at peak price GWh/yr 1190 1184 1178 1172 1194 1201 1208 1206 1203 1201 1199 1196 1194Corresponding revenue thousand S 32123 33560 34983 36390 38678 40523 42408 43951 45487 47018 48542 48445 48348Total revenue thousand S 38448 40169 41871 43555 45840 48027 50261 52090 53911 55725 57531 57416 57301Total O&M cost thousand S -677 -752 -835 -926 -1026 -1137 -1203 -1272 -1345 -1423 -1504 -1591 -1683

O&M cost unrelated 1o rehab thousand $ -677 -752 -835 -926 -514 -571 -605 -641 -679 -720 -763 -808 -856O&M cost related to rehab thousand S 0 0 0 0 -512 -566 -598 -631 -666 -703 -742 -783 -826

Investment, total thousand $ 0 0 -2961 -2224 -1467 -1511Domestic thousand S 0 0 -511 -372 -1467 -1511Foreign thousand S 0 0 -2450 -1852 0 0

Net revenue thousand S 37771 39417 38075 40406 43347 45379 49058 50818 52566 54302 56027 55825 55618NPV @10% thousand S 432,997INCREM. NET REVENUE thousand S 0 0 -2961 -2223 -846 -350 1767 1985 2213 2451 2699 2863 3026NWV llti¢ftstttIhtd @X10%. ;0:Th pishd# -i:: 1;0092

Energy rncrease/yr GWh/yr 0 0 0 0 16 32 49 53 57 62 66 70 74Average energy increase/yr GWh/yr 82Total energy increase GWh 1806

iC 0DC


ECONOMIC ANALYSIS

KREMENCHUG HPS2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

WITHOUT PROJECT

Aver. economic price S/MWh 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economic price $/MWh 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electncay output GWh/yr 1411 1404 1397 1390 1383 1376 1369 1362 1356 1349 1342 1335 132921% at average price GWh/yr 296 295 293 292 290 289 288 286 285 283 282 280 279Correspondmng revenue thousand $ 8889 8845 8801 8757 8713 8669 8626 8583 8540 8497 8455 8412 837079% at peak price GWhiyr 1115 1109 1104 1098 1093 1087 1082 1076 1071 1066 1060 1055 1050Correspondny reven.ue thousand $ 45145 44919 44694 44471 44249 44027 43807 43588 43370 43153 42938 42723 42509Total revenue thousand $ 54034 53764 53495 53228 52961 52697 52433 52171 51910 51651 51392 51135 50880O&M cost thousand S -1815 -1923 -2038 -2160 -2288 -2425 -2570 -2723 -2885 -3058 -3240 -3433 -3638Net revenue thousand $ 52219 51841 51457 51068 50673 50272 49863 49448 49025 48593 48152 47702 47241NPV @10% thousand S

WITH PROJECT

Aver. eronomic price $/MWih 30 30 30 30 30 30 30 30 30 30 30 30 30Peak economrc price $/MWh 40.5 40 5 40 5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5 40.5Electricity uutput OW/hyr 1489 1486 1483 1480 1477 1474 1471 1469 1466 1463 1460 1457 145420% at average price GWh/yr 298 297 297 296 295 295 294 294 293 293 292 291 291Corresponding reveiue thousand $ 8935 8918 8900 8882 8864 8846 8829 8811 8793 8776 8758 8741 872380% at peak price GWh/yr 1191 1189 1187 1184 1182 1180 1177 1175 1172 1170 1168 1165 1163Corresponding revenue thousand $ 48251 48155 48058 47962 47866 47771 47675 47580 47485 47390 47295 47200 47106Total revenue thousand $ 57187 57072 56958 56844 56730 56617 56504 56391 56278 56165 56053 55941 55829Total O&M cost thousand S -1780 -1882 -1991 -2105 -2227 -2355 -2491 -2634 -2786 -2946 -3116 -3296 -3486

O&M cost unrelated to rehab thousand S -908 -962 -1019 -1080 -1144 -1213 -1285 -1361 -1443 -1529 -1620 -1717 -1819O&M cost related to rehab thousand S -872 -921 -972 -1025 -1082 -1142 -1206 -1273 -1343 -1418 -1496 -1579 -1667

Investment, total thousand $Domestic thousand $Foreign thousand $

Net revenue thousand $ 55407 55190 54967 54739 54504 54262 54013 53757 53492 53219 52937 52645 52343NPV @10% thousand SINCREM. NET REVENUE thousand S 3188 3349 3510 3671 3831 3990 4150 4309 4467 4626 4784 4943 5102ONPV OnRemnAtita @10$ .o % thorijand StIAfll tintsrenentrt.8 -. -Energy increase/yr GWh/yr 78 82 86 90 94 98 102 106 110 114 118 121 125Average energy increase/yr GWh/yrTotal energy increase GWh

t- cX0

Annex 9Page 1 of 3

UKRAINE


Project Implementation Schedule

1. Main procurement activities are planned as follows:

Start Date End Date

Preparation of Bid Documents Jan. 1, 1995 May 31, 1995

World Bank Review of Bid Documents June 1, 1995 June 20, 1995

Final Project Schedule Plan Revision June 21, 1995 June 30, 1995

Contract Signing with Domestic Suppliers June 30, 1995 June 30, 1995(turbines, generators)

Bid Advertisement July 1, 1995 July 1, 1995

Preparation of Bids July 1, 1995 Sep 15, 1995

Bid Evaluation Sep. 16, 1995 Oct. 15, 1995

World Bank Review of Bid Evaluation Oct. 16, 1995 Nov. 5, 1995

Contract Negotiations Nov. 6, 1995 Nov. 20, 1995

Contract Signing Nov. 21, 1995 Nov. 21,1995

2. The project closing date is December 31, 2000.

3. Details of project implementation plan are given in Tables I and II.

UKRAINE

HYDROPOWER REHABILITATION AND SYSTEM5 CONTROL PROJECT

PROJECT IMPLEMENTATION SCHEDULE

A HyAwo R.9.0I6.o

97, ,996 91"7 1999 230It 0 , , . , 6 7 . I, 0 1, 12 , 2 3 4 5 6 7 i 9 10 ,1 12 7 2 , 4 5 6 7 S 9 30 12 II 2 3 4 5 6 7 6 9 0 2 2 , I 2 3 S

i,6. NA

C.- - _ __ _

-,- a - m _

T. A

G C__,. .v.. _____.._____

\~~~.~ .tOCB - _ ______ _ ___ ____ .__ ._____

. 7 S X - -_ __

_w ____ __Ia.& -- -

G. wH .* ^ ._~~~~~~~~~~2~ _ _ ___ _ _^5.9..6)& 4 6 d 9 - __ _

c-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-

TZ. .- - _

s-zb"& v .&}

cT Co.. .6l ________ __ ___DSm- - --

C- - _ _ _ _

-- W.65 , .94.-

Ta -

S....b,.,4 _~4. S _ __ _ ___ ._ _ _-- --

C & *4 FT.e .6 _|._ ___-_

G.., 4.66 -T _ _._ _ __ _ _ __0.o... .. p. W-______ _ _ _ S_ C m* * 66W_ _ _ _ _ __ _ _ _ ___ ___ _ _ _ _ _ _ _ _ _ _ _ 5 -. __ _ _ __ _ _____ ___ __ _ _ __ _ _ __ _ _

CH C... 114._ _

1 1 IH ; ~~~~~~~~Page 3

.~~~ _, -

a g j0 ; - F0

j - _ -.. |<

I L , __ j __ ! -,

ANNEX 10

UKRAINE


List of Procurement Packages

Cost Procurement Contract(US$mil) Method Date

A. Hydropower Rehabilitation

(i) Equipment for Turbines 3.4 ICB November '95

(ii) Generators and Related Equipment 4.2 ICB November '95

(iii) Switchyard Equipment 7.4 ICB November '95

(iv) Plant Control & Monitoring 24.5 ICB November '95

B. Dam Safety Monitoring

(i) Dam Safety Monitoring Equipment 1.9 ICB November '95

C. System Control & Communuications

(i) Thermal Unit Governors 2.4 ICB November '95

(ii) Generation Control Equiupment 7.3 ICB November '95

(iii) Transmission Lines Protection 2.4 ICB November '95

(iv) Automatic Generation Control andEconomic Dispatch 0.8 ICB November '95

(v) SCADA 5.0 ICB November '95

(vi) Communications 32.1 ICB November '95

D. Technical Assistance '

(i) Project Management and 1.5 Short List November '95Implementation

(ii) Procurement 0.3 Short List November '95

1/ Technical assistance will be provided from grant agencies for water management, and for the engineering,procurement and project management and implementation for the first year of project implementation(1995). Continuation of the grant financing will be sought for other years as well. In the case that grantfinancing can not be found, the rest of the technical assistance including project management andimplementation, and procurement, will be financed from the Bank loan, as given in this Annex, accordingto the World Bank's Guidelines for Use of Consultants by World Bank Borrowers and by the World Bankas Executing Agency (August 1981)

ANNEX 11

UKRAINE


Estimated Schedule of Disbursements

Bank Fiscal Year Disbursement Cumulative Cumulative Incrementaland Semester in Semester Disbursement % %

FY 1996Dec. 31, 1995 5.0 5.0 4 4June 30, 1996 9.2 14.2 12 8

FY 1997Dec. 31, 1996 10.3 24.5 21 9June 30, 1997 10.3 34.8 31 10

FY 1998Dec. 31, 1997 15.4 50.2 44 13

June 30, 1998 15.4 65.6 58 14

FY 1999Dec. 31, 1998 14.7 80.3 70 12

June 30, 1999 15.0 95.3 84 14

FY 2000

Dec. 31, 1999 8.0 103.3 91 7

June 30, 2000 7.4 110.7 97 6

FY 2001Dec. 31, 2000 3.3 114.0 100 3June 30, 2001 0.0 114.0 100 0

ANNEX 12Page 1

UKRAINE


Performance Indicators

1. The following indicators will be used to measure the effectiveness of project implementationand operation:

A. Technical Indicators

For hydropower plants:

(i) Nominal and maximum operating capacity (MW) for each unit. The following areestimates of the nominal capacities (in MW) of the individual generating units in theplants after rehabilitation:

Kiev: 19.9Kremenchug: 56.6Dniproderzhinsk: 52.2Dnieper I: 79.8Kakhovka: 52.2

It is expected that total increase in system capacity after the rehabilitation will be 130MW;

(ii) Total energy produced and energy sales (GWh/year). Total energy sales are expectedto reach an average of 10,800 GWh/year over the next five years after rehabilitation(assuming normal water inflows, i.e., equal to the historical average);

(iii) Total inflows into reservoir, total water turbined, total water spilled (thousand cubicmeters/year);

(iv) Target turbine efficiency, for each unit (%), to be achieved after rehabilitation

Kiev: 4.3 %Kremenchug: 3.4 %Dniproderzhinsk: 4.2 %Dnieper I: 3.5 %Kakhovka: 3.9 %

For National Dispatch Center:

(v) Compared to 1994/95, reduction in ihe deviation of maximunm and minimumfrequency from the 50 liz target, and reduction of the monthly maximum accumulated

ANNEX 12Page 2

time error (sec);

(vi) Compared to 1994/95, reduction in the number, amount (MW) and duration of loadcurtailments per year;

(vii) Real time economic dispatch software installed, tested, and operating by June 30,1999.

B. Financial Indicators

(viii) NDC's account receivables should not exceed 60 days in 1995, 40 days in 1996, 35days in 1997, and 30 days thereafter;

(ix) Maintaining the required debt service ratio (1.5) and self financing ratio (40%) byDniprohydroenergo and NDC during the project period.

C. Proiect Implementation

(x) Actual timing of procurement actions by bid package (bid specifications, invitation forbidding, opening of bids, evaluation reports, award of contract, contract signing)against the schedule;

(xi) Actual installation of equipment against the project schedule;

(xii) Actual disbursements against the disbursement schedule.

ANNEX 13Page 1

UKRAINE


Supervision Plan

1. The supervision is expected to require about 25 staff weeks per fiscal year during the first twoyears of implementation, and 15 staff weeks per year thereafter. The schedule below is in addition tothe regular review requirements for procurement actions, progress reports and correspondence,estimated to be about 9 staff weeks per year in the first two years, and 7 staff weeks per yearthereafter.

Approximate Activity Expected Skill StaffDate Requirement Weeks

9/95 Supervision Engineer, Procurement 8Mission Specialist, Disbursement(Project Startup) Specialist, Financial Analyst,

Economist, Lawyer

3/96 Supervision Engineer, Procurement 8Mission Specialist, Disbursement

Specialist, Financial Analyst,Economist, Lawyer


Specialist, Financial Analyst,Economist, Environmental Specialist


Specialist, Financial Analyst

9/97 Supervision Engineer, Procurement 8Mission Specialist, Disbursement(Mid-Term Review) Specialist, Financial Analyst,

Economist, Environmental Specialist

3/98 Supervision Engineer, Financial 4Mission Analyst

9/98 Supervision Engineer, Financial 4Mission Analyst

ANNEX 13Page 2

3/99 Supervision Engineer, Procurement 4Mission Specialist, Economist

9/99 Supervision Engineer, Procurement 4Mission Specialist, Financial Analyst

2/00 Supervision Engineer, Financial 4Mission Financial Analyst

7/00 ICR Preparation Engineer, Procurement 8Specialist, DisbursementSpecialist, Financial Analyst,Economist, Environmental SpecialistLawyer

MAP SECTION

I-RD 26469

20, 25 30 O5°

B, E E L A R * > S2 R U S S I A N F E D E R A T I O AN

-50,

ROAI 25 t5c .ro Ai

HYDROPOWER REHABILITATION AND SYSTEM CONTROL PROJECT \h)/J H

MAIN POWER STATIONS AND Qtr~KSik TRANSMISSION LINES

TRiAN$AC OSION LINES 0 #/ /> ) 4 AAzov , RUS5IAN- REHABILITATION FEDERATION D-

SYSTEM CONTRO PRLOJECTNT

* THERMAL POWES PTNTS A

9 NACILER POWER PLANTS // )

IEGIONAL ELECTiC ASsOCIATIONS N OUNARIES

NATIONAL L FDITA_

-. INTERNATIONAL B3.LNAARITS os{0 50 l00 120\

ilVARS / , B LA CK S EA t I I\

330 500 kV ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~~~~~50 0 5

NUCLEAR 'ER NSBULGARIA - 3 os M51ES

LOECOMTEB AC SE