Document of

The World Bank

FOR OFFICIAL USE ONLY

M l crtEl N (CHE 0 4I X

Re-port No. 1(41W PU ru 'I'ype: I A1Ku(IC, A. , X3229b / H. 1 ECKE

STAFF APPRAISAL REPORT

TURKEY

BERKE HYDROPOWER PROJECT

MAY 5, 1992

Industry and Energy Operations DivisionCountry Department IEurope and Central Asia Region

This document has a restricted distribution and may be used by recipients only in the performance oftheir official duties. Its contents may not otherwise be disclosed without World Bank authorization.

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 Turkish Lira (TL)TL 1.00 100 Kurus (KRS)US$1.00 e TL 6585 (April 24, 1992)TL 1.00 US$0.0002

MEASURES AND EQUIVALENTS

k (kilo) - lo0 Ws (Watt second) - Joule (J)M (mega) _ 106 J - 0.239 calG (giga) - lo0 kcal = 3.968BTUT (tera) - 1012 kWh - 3.8 MJA - ampere TOE - 10.2 GcalV - volt TCE - 7.1 GcalW -watt Meter (m) - 3.28 feetJ = Joule Kilometer (km) - 0.6214 milescal - calorie Kilogram (kg) - 2.2 poundsTOE = ton of oil equivalent Metric ton (t) - 2,205 poundsTCE - ton of coal equivalentBTU - British thermal unit

PRINCIPAL ABBREVIATIONS AND ACRONYMS

CEAS - Gukurova Elektrik A.S. (Cukurova Electric Company)C&B - Coyna et Bellier (engineering consultants)DSI - Devlet Su Isleri (State Hydraulic Works)ICB - International Competitive 3iddingKEPEZ A.S. - Kepez ve Antalya Havalisi Electrik Santrallari

(Kepez Electric Co.)LCB - Local Competitive BiddingLRMC - Long-Run Marginal CostMENR - Ministry ef Energy and Natural ResourcesPEE - Public Economic EstablishmentPPAR - Project Performance Audit ReportSEE - State Economic EnterpriseSPO - State Planning OrganizationSPK - Sermaye Piyasi Kurulu (Capital Markets Board)TEK - Turkey Electrik Kurumu (Turkish Electricity Authority)TKI - Turkey Komur Isletmeleri Kurumu (Turkish Brown Coal Ent.)TPAO - Turkey Petrollerei Anonim Ortakligi (Turkish

Petroleum Corp)VAT - Value Added Tax

Turkey - Fiscal YearJanuary 1 to December 31

FOR OFFICIAL USE ONLY

TURKEYBERKE lYDROPOWER PROJECT

STAFF APPRAISAL REPORT

Table of Contents

page Ng.Loan and Project Summary ............. ...................... i

I. THE ENERGY SECTOR AND POWER SUBSECTOR ........................ 1A. Energy Sector. 1

Overview. 1Energy Resources. 1Ene-gy Sector Prices. 3Institutions of the Energy Sector. 5Investment Financing ....................r.......... 6Input-Substitution Strategy/Environmental Constraint 7

B. Power Subsector. 8Overview. 8Power Subsector Strategy. 8Power System Expansion. 9Plan and the Role of Private Sector Investment .... ..... 10Bank Role in the Power Subsector ....................... 12

II. THE PROJECT ENTITY - CUKUROVA ELECTRIC A.S.... .............. 13A. Corporate Background ..................................... 13

Introduction ........................................... 13Existing Power Facilities .............................. 14

B. Rezulatory Environment ................................... 14C. Organization and Management .............................. 15

Personnel and Staffing ................................. 15Long-Term Planning and Investment Program .... ........... 16Project Implementation Capacity ........................ 17Operation and Maintenance .............................. 17Load Dispatch and Management ........................... 17

D. Commercial and Financial Management ...................... 18Electricity Demand and Supply .......................... 18Tariffs ................................................ 19Sales, Billing and Collections ......... . .............. 19Taxes ................................ 20Insurance ................................ 20Financial Organization ................................. 20Accounting Systems and Practices .......... ............. 20Audit ................................ 21

This report is based upon the findings of an appraisal mission thatvisited Turkey in January 1992. The mission comprised Messrs. AntanasijeKocic (Mission Leader), Franco Batzella (Division Chief), Varada-ajan Atur(Financial Analyst), C. Tufarelli (Economist), P.N. Gupta (Principal DamSpecialist), E. Crousillat (Energy Economis:) and R. Zwolak (EnvironmentalSpecialist Consultant). Secretarial Assistance was provided by Mmes.Hannah Thomas and Young Ok Hong.

This document has a restricted distribution and may be used by recipients only in the performanceof their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

III. THE PROJECT .................................................. 21A. Prolect Setting ................ .......................... 21

Overview ....... 21Rationale for BankIvolvement ............ .................... 22Project Objectives ........... .......................... 22Project Description .......... .......................... 22Project Origin . ........................................ 23

B. JTechiJca Evaluation ........... .......................... 24The Dam and the Powerhouse ....... ...................... 24Transmission . .......................................... 24Technical Assistance ......... .......................... 24Status of Project Preparation .......................... 25

C. Proiect Costs and Financing .............................. 26Project Costs . ......................................... 26Project Financing Plan ......... ........................ 26Retroactive Financing .................................. 27

D. Procurement and Disbursement ........... .................. 27Procurement Aspects .................................... 27Bank-Financed Procurement ............ .................. 27Non-Bank Einanced Procurement ......... ................. 28Disbursement Aspects ................................... 29Special Account ....................................... 30

E. Proiect Implementation Aspects .......... ................. 30Engineering Consultants . ................................ 30Organization and Management .......... .................. 30Implementation Schedules and Project Completion Date.... 31Progress Reports .................................. 31Development of Ceyhan River Basin and Water Management.. 31Land Acquisition and Resettlement ....... ............... 32

F. Environmental Aspects .................................... 34Physical Environment .................................... 34Biological Environment .................... ....... .... 34Socio-economic Environment ........ ..................... 35Mitigation and Monitoring Plans ....... ................. 35Transmission Lines Environmental Review ..... ........... 35

G. Dam Safety AsRects ........................................ 35Engineering ............................................ 35International Panel of Experts .................. 36Instrumentation . ....................................... 36Dam Safety Inspections during Operation ..... ........... 36

H. Benefits and Risks . ....................................... 36

IV. FINANCIAL ASPECTS ..................... 37A. Introduction ..................... 37B. Past Performance and Present Condition ................... 37C. Tariff Agreements ........................................ 40D. Proposed Tariff Policy and Implications for CEAS .. . ..... 41

Energy Exchange Price with TEK ... 41Implications for CEAS ... 42

E. Investments and Financing ... 42Cofinancing ... 43Proposed Bank Loan ... 43Dividend Policy and Equity Financing ... 43

F. Financial Forecasts ...................................... 44Financial Results .......... ............................ 45VEAS' Creditworthiness ........ ......................... 46

G. Prospective Take-Over of Distribution Operations .... ..... 47

V. ECONOMIC JUSTIFICATION .......... ............................. 47The Project as a Least-Cost Generation Alternative .... ..... 48Benefits of the Berke Project ....... ....................... 49

VI. AGREEMENTS REACHED AND RECOMMENDATION ...... .................. 50

ANNEXES:

1.1 Energy Balance 19901.2 Installed Capacity, Electricity Generation and Sales in the Power Sector1.3 Transmission and Distribution System CharacterJ.stics1.4 Status of Distribution Facilities and Substation Composition1.5 Least-Cost Generation Expansion Program2.1 List of Shareholders as of December 19912.2 Organization Chart of Vukurova Elektrik A.S.2.3 Actual Demand-Supply Balance, 1977-1990 and

Forecast Demand-Supply Balance, 1991-20002.4 Average Revenue Computation, CEAS Submissio to MENR, 19912.5 VEAS Electricity Sales by Customer Groups, 1986 and 19903.1 Technical Assessment of the Dam and the Powerhouse3.2 Transmission Lines and Substations3.3 Technical Assistance3.4 Project Cost3.5 Disbursement Schedule3.6 Construction Schedule3.7 List of Mitigation Activities3.8 Project Monitoring Guidelines4.1 Notes to Financial Forecasts4.2 Demand, Supply, Average Costs and Revenues4.3 Investment Phasing and Financing Plan 1992-964.4 Simulation of Hydrology and Hydro Generation4.5 Investments and Financing Plan5.1 Comparison of the Least-Cost Expansion Plans With and Without Berke5.2 Comparative Analysis of System Costs5.3 Estimation of the Internal Economic Rate of Return for the

Berke Hydropower Project5.4 Economic Analysis of Transmission Expansion5.5 Economic Analysis of Transmission Expansion Sensitivity Analysis

Map No. IBRD-23671IBRD-23672

TRE

DERKE HYDROPOWER PRQJECT

Loan and Project Summary

Borrower: The Republic of Turkey

Beneficiary: Qukurova Elektrik A.S. (CEAS)

Amount: US$270 Million Equivalent

Term: Seventeen years, including a five-year grace period, atthe Bank's standard variable interest rate.

Onlending Terms: The Government would charge VEAS an onlending feeequivalent to 35 basis points p.a. on the outstandingbalance of the Loan. gEAS would bear the foreignexchange risk, as well as the interest risk on the BankLoan.

Project Description: The proposed Project would provide for the installationof 510 MW hydroelectric generating capacity comprisingthree units of 170 MW located betwe.t the Sir andAslantas Hydropower Plants and expansion, transmissionsystem. The hydro plant would comprise tv-. onstructionof a double curvature thin arch dam with & height of 201m, an energy tunnel of 2.05 km length and an insidediameter of 9.30 m, and an undezground power plant. Thereservoir active volume would be about 300 million m3.When completed the complex will provide 1,600 GWh p.a.of electric energy. The transmission component wouldcomprise construction of 737 km 154 kV transmissionlines and 12 substations with installed transformercapacity of 1,350 MVA and a modern load dispatch center.

Benefit and Risks: The measurable benefits attributable to the proposedProject include incremental generation of electricity bythe private sector with no claims on GOT's budget forthe domestic financing of the project, and for the shareof the financing plan to be covered by IFC. Anadditional important benefit is the demonstration effectexpected to derive from the success of the expansion ofQEAS's scope of activities as an integrated, privatelyowned, regional power utility, effectively cooperatingwith TEK in Turkey's power subsector. The main risksenvisaged are the possibility of construction delaysderived from construction site conditions as well as thesize of the project, which is large in relation to theimplementation capacity of CEAS. This risk issubstantially reduced since CEAS has appointedconsultants of proven competence, to assist in designand engineering as well as implementation.

- ii -

..- US$ Million------Prolect Coste: Local Eagegn Total

A. BERKE HYDRO POWER PROJECT1. Land Acquisation 0.5 0.0 0.52. Preliminary Works 40.5 0.0 40.53. Civil Works 122.2 159.2 281.34. Electro-Mechanical Eq. 4.2 38.0 42.25. Eleatrical Equipment 3.4 14.0 17.46: Engineering/Supervision 7.4 0.1 7.57. General Expenditures 26.2 0.0 26.2

Sub-Total 204.3 211.2 415.5

B. TRANSMISSION NETWORK1. Transmission Lines 22.4 10.0 32.42. Substations 13.5 7.9 21.43. Dispatch Center 2.5 12.5 15.0

,,,- -- - .....

Sub-Total 38.4 30.4 68.8

C. TECHNICAL ASSISTANCE1. Staff Training 0.1 0.3 0.42. Load Dispatch Center St. 0.1 0.4 0.53. Special Equipment 0.0 0.3 0.3

.... ..... ----

Sub-Total 0.2 1.0 1.2

Total Base-Line Costs 242.9 242.6 485.5

Physical Contingencies 24.8 26.1 50.9Price Contingencies 25.4 30.3 55.7

Total Project Costs 293.0 299.0 592.1

IDC - Bank Loan 0.0 48.0 48.0- Other 0.0 23.2 23.2

Less Expenditures 1989-91 -39.6 0.0 -39.6Total Financing Required 253.5 370.2 623.7

Financing PlanM

Proposed Bank Loan - 270.0 270.0Cofinancing - 100.2 100.2CEAS 253.5 - 253.5

253.5 370.2 623.7

Estimated Disbursements:

Bank El 1993 1994 1995 1996 1997

Annual 46.9 66.4 82.4 56.5 17.8Cumulative 46.9 113.3 195.7 252.2 270.0

Economic Rate of Return: 15.2X

TURgKEY

BERKE HYDROPOWER PROJECT

STAFF APEPlISAL REPORT

I. THE ENERGY SEO D THE POWER SUBSECTOR

A. Energ SLector

Overvie

1.01 Turkey has made remarkable progress in developing its commercialenergy base over the last two decades. Net primary energy supply increasedthreefold since 1970, reaching 58.8 million TOE in 1990. Lignite is the mostimportant commercial source of domestic energy (with an output of 11.4 millionTOE, representing 19 percent of the totel energy supplied) followed by about 7.1million TOE of hydroelectric generation (providing 12 percent of total primaryenergy supply). The volume of non-commercial energy consumed in Turkey hashalved since 1980, but it still represents the second largest domestic source ofenergy supply, with 131 of total net primary energy. The importance of naturalgas (of which 89 percent is imported) is slowly increasing (from 11 in 1987 to71 in 1990) w.inly as a result of its increased competitiveness as an industrialfuel and iti. ¶vironmental benefits relative to lignite fuels for electricitygeneraticn residential heating (natural gas is virtually sulfur-free andburns with -nw particulate emissions). The balance is accounted for by oil(22.8 million 2, 891 of which is imported) and coal (57 million TOE, 56Ximported). The ener7- sector balances for 1990 are illustrated in Annex 1.1.

1.02 Turkey's final co.-umption of commercial energy is estimated to beat about 44.9 million TO'( TVa two largest consumers of commercial energy arethe industrial sector (ab; rt.'x 35Z of total energy), and the residential sector(391). Fossil fuels meet 611 of the energy requirements of the manufacturingsector but they will be partially substituted by electricity (whose relativeshare will increase from 17X in 1990 to 221 in 2010) and they will provideapproximately 51.5X of the sector's requirements by the year 2010.Transportation is almost entirely fueled by imported oil, the consumption ofwhich amounts to 8.3 million TOE in 1990 and will reach 10.7 million TOE in 1995(more than doubling by the year 2010). Turkey is expanding its renewable energybase: solar energy finds some application in the household sector but it stillprovides a negligible portion of total energy consumed (estimated at 0.11 in1991). Per capita consumption of commercial energy was 0.687 TOE/cap in 1990 andis estimated to steadily increase to more than double by 2010 (reaching 1.647TOE/cap).

Energy Reoum

1.03 Hydroelectric Poteniial. Development of hydroelectric resources, anindigenous source of energ;. has been steadily increasing since the 1970s.Development should be accelerated even further in the next 20 years in order tomatch the subsector's required investment expansion. Approximately 241 ofTurkey's hydroelectric potential (estimated at about 31 GW) has been developed,and an additional 4 oW is expected to come on-stream by 1994.

1.04 Lignite. Lignite is an entirely domestic energy resource and it ismainly utilized for residential heating (where it is being gradually replaced bynatural gas in the major cities for environmental reasons) and for firing thermalpower plants. Lignite fuels are mainly produced in western Turkey and in the

-2-

Afsin-Elbistan region; deposits (50 percent of which have low calorific value andhigh sulfur content) are estimated at 8.2 billion tons (about 1 billion TOE).Consumption of lignite grew by an average of 14X since 1980; this escalation wasmainly caused by the expansion of lignite-based power generation, which rose to5.58 million TOE in 1990, increasing by 29.6X since 1970 and absorbing 492 ofTurkey's total net supply of lignite. Lignite is currently the basis for 292 ofpower generation. The largest end-user of lignite is the residential sector,which accounts for 572 of total consumption. The industrial sector is the secondlargest final consumer, absorbing the remaining 2.484 million TOE (432 of thetotal).

1.05 Non-Commercial Energy. Non-commercial energy mainly consists ofbiomass, which supplies 7.7 million TOE to the household sector (the mainconsumer). Approximately 33.72 of the energy used for cooking in Turkey is non-commercial. This proportion will drop to 26.32 in 1995 (when non-commercialenergy is expected to be partially replaced by fossil energy), and it willfurther decrease to 152 in 2010. Fuelwood ls mainly utilized for heatin&purposes; it provided 50.92 of total energy required by the household sector in1983. Households still depend on fuelwood for 322 of their heating requirements;the importance of fuelwood ls expected to gradually decline but remainsignlficant at 152 in 2010.

1.06 Coal. The domestic production of coal decllned during the past twodecades because of rising production costs, due to increasingly difficultextraction. The industrial sector's demand was met by raising imports to 53.52of total coal consumed in 1987. Total primary coal supply amounts to about 5.7million TOE, of which 43 percent (equivalent to 2.4 million TOE) is produceddomestically and the remaining 572 imported. Final consumption consists of 2.8million TOE and is mainly absorbed by the residential sector (692) and by theindustrial sector (302).

1.07 Natural Gas. Natural gas represents 62 of total primary energysupply. Domestic production consists of 12 million cubic meters per year (410thousand TOE) extracted from the Hamitabat field in Thrace and represents 112 oftotal supply. Imports amount to 3.1 million TOE and are increasing very rapidly,as demand is expected to rise more than threefold by the late 1990s. Natural gasis mainly utilized in power generation and industry, and its importance isincreasing as a response to environmental concerns. Approximately 152 ofelectricity is in fact produced by ccmbined-cycle plants and this proportion isexpected to increase to 202 by the year 2000, representing 262 of total powersubsector's installed capacity by the year 2010. Natural gas is also beingincreasingly uxilized for residential heating in major cities.

1.08 Since 1987 a gas supply contract with the USSR has been ln place,whereby imports via Bulgaria are to reach 5.6 bcm/y by 1992 (4.6 million TOE).Under this fifteen year contract at least 702 of the cost of the imported gas iscovered by counter-trade, thus enabling Turkey to expand its exports to the USSR.In addition, liquefied natural gas (LNG) to be imported from Algeria to theterminal facility now under construction in Thrace, is expected to reach, aftera four year buildup, 2 bcm/y by 1997 (1.6 million TOE). More recently, theGovernment has reportedly signed a protocol with Libya to import 1.5 bcm/y of LNG(0.8 million TOE), and negotiations on price are underway. A substantial shareof imported gas is currently allocated to bulk users, i.e., the power andindustrial sectors.

1.09 Under the Sixth Five-Year Plan, the gas distribution and transmissionnetwork was extended, so as to inerease efficiency of imported gas utilization.

-3

In particular, expansion of the gas distribution network in the cities of Bursaand Eskischir began and storage facilities of imported gas were developed inorder to allow for a more efficient management of supplies during the peak demandperiod.

1.10 Crude Qil and Petroleum Product. Total crude oil supply in 1990amounted to 21.8 million TOE. Of these, 19.2 million TOE (88X) were imported.Proven hydrocarbon reserves consist of 250 million barrels (about 35 million TOE)of oil and 0.5 billion cubic feet (about 12.5 thousand TOE) of natural gas.Domestic production has slightly increased during 1980-90, accounting forapproximately 12X of domestic demand in 1989. This proportion is not expectedto increase substantially because of the limited prospectivity of Turkey'sgeology. Losses in the refinery process averaged 5.4X of total crude oil supplyduring the 1980s.

Energy Sector Prices

1.11 Turkey'5 energy pricing policy has experienced wide fluctuatioiassince the early 1980s. While the first half of the past decade was characterizedby an ini;r4asing trend in most energy prices, this policy was relaxed during thesecond half following the decline of oil prices worldwide, but also reflectinga loosening of Turkey's demand management policies at a macro level. After 1988,important corrective measures on the level and structure of energy prices havebeen introduced with the support of the Bank. Table 1.1 shows the evolution ofrelative prices of key energy products since 1980. Important features ofTurkey's energy pricing policies are:

(a) After a period of relative increases in all energy prices during1980-1985, except for lignite and residential electricity tariffs,most prices declined sharply until 1988. Since then, most energyprices have been increased. Energy sources that have notexperienced a real price increase compared to 1988 price levels areheavy fuel oil, natural gas and lignite for power generation.

(b) The early 1980s policy of encouraging the substitution of importedfuel oil by lignite (a domestic resource), through relative priceincentives for all consumption categories (i.e., industrial,household and power generation), has been gradually reversed duringthe last few years. This shift is partially attributed to GOT'sconcerns on the environmental impact of an increasing consumption oflignite as well as to the declining real prices of petroleumproducts worldwide.

(c) Domestic lignite is the cheapest energy resource for thermal powergeneration, on an equivalent heat basis. Lignite prices for powergeneration are currently 411 of those for natural gas and only 29Xof heavy fuel oil. Conversely, lignite prices for industrial useare competitive with natural gas, which costs only 21 more on acomparative heat basis, while fuel oil remains as the most expensivesource of energy (421 higher). This policy of promoting natural gasuse in industry has caused an annual average increase of 901 inconsumption since 1988.

(d) In spite of the increase in lignite prices and the significant fallof gas prices for household consumption which took place during thelast two years, lignite remains the cheapest source of energy at the

-4-

household level. Currently, lignite prices are only 60% and 18X ofnatural gas and electricity prices, respectively, on an equivalentheat basis.

(e) Generally speaking, the relative price of electricity has graduallyimproved with respect to its main thermal generation inputs (heavyfuel oil, lignite and natural gas). Electricity tariffs toresidential consumers declined dramatically until 1989, whereastariffs to industrial and commercial consumers inereased. Sincethen, the cross-subsidy from industrial/commercial consumers toresidential has been substantially reduced.

(f) Domestic prices for petroleum products increased con- 3Urably during1980-85. These prices fell significantly durinp : . remainder ofthe decade, ranging from a fall of 382 to 302 a.. p! talleling thedecline of world market crude oil prices. Gasoline and diesel oilprices have been increased during the last year thus reaching realvalues similar to those of 1980.

Table 1.1: Relative Prices of Key Energy Productsl'

Price Indices Prices as Z of that1980 1955 1988 I9 2/ of Lianits C1991)3/

A. EletriatTariffs

Residential 162.8 127.2 100.0 87.3 151.2Industry 80.4 84.4 100.0 72.1 65.9

I InputsHeavy fuel oil 133.7 164.0 100.0 84.4 73.1 339.0Lignite 141.0 124.6 100.0 59.7 U1.6 100.0Natural as 100.0 52.5 50.7 244.0

D. IovueboldsLight fuel oil 115.4 142.8 100.0 117.5 145.5 436.0Electr.icty 162.8 127.2 100.0 87.3 151.2 558.0LignLte 107.9 123.9 100.0 117.0 148.1 100.0Natural gas 100.0 58.5 75.9 168.0

C. lnduztrvHeavy fuel oil 133.7 164.0 100.0 84.4 73.1 142.0Lignite 144.7 113.1 100.0 88.4 115.6 100.0Natural gas 100.0 56.2 61.0 102.0

D. Petroleun ProductsGasoline 134.6 149.6 100.0 92.5 122.6Diesel oil 11 142.8 100.0 114.8 141.6

HIso Itsn4

Base yew: loSe

Consumer Price Index 6.1 30.5 100.0 302.2 483.4US$ Inter'l Frice 75S. 72.1 100.0 104.8 113.5

Index (MUV)OECD Oil Price 268. 8 258.2 100.0 145.1 110.1(US$ Real Term)

OCD Coal Price 155.3 150.3 100.0 109.6 100.1(US$ Real Terms)

1/ Yearly averages. except 1991, based on conAtant domestic prices; including taxes.2/ Fourth quarter 1991.3/ Fourth quarter 1991, for an equivalent beet basis.

Source: FEWR, IEA, mission estimates.

-5-

Institutions of the Energy Sectgr

1.12 The Mivistry of Energy and Natural Resources (MENR) is responsiblefor managing, regulating and planning the development of the energy sector. MENRhas also been given primary responsibility for establishing policies andregulations for accelerating private sector involvement in energy development.At the operating level, the energy sector is dominated by State EconomicEnterprises (SEEs). The Turkish Hard Coal Enterprise (TTK), the Turkish LigniteEnterprise (TKI), the Turkish Petroleum Corporation (TPAO) and the MineralResearch Institute (MTA) have responsibility for the extractionl of fossil fuelsand radioactive materials. The production, transport and marketing of petroleumproducts are undertaken respectively by Turkish Petroleun, Refineries Corporation(TUPRAS), Petroleum Pipelines Corporation (BOTAS) and Petrol Ofisi (marketing anddistribution). Design and construction of hydroelectric schemes is entrusted tothe State Hydraulics Akuthority (DSI). The Turkish Electricity Authority (TEK)is responsible for the generation, transmission and distribution of almost allthe electricity sold in Turkey, including the operation of the DSI-builthydropower plants. TEK is also responsible for the implementation of theGovernment's rural electrification program and the construction of all publiclyowned thermal power plants and transmission and distribution facilities. TheElectricity Survey Administration (EIE) is responsible for renewable onergy,hydropower surveys and for the formulation and implementation of the nationalenergy conservation program. Table 1.2 lists the main energy institutionsclassified by subsector and the Ministry to which each institution refers.

1.13 The Public Participation Administration (PPA) is an extra-budgetarynational fund for investments in infrastructure. Although not formally part ofthe energy sector, it plays a significant role in mobilizing financing for thepower subsector. In particular, hydropower facilities constructed by DSI arefinanced by the PPA, the national budget and foreign credits and loans. PPA'ssources of funds comprise market instruments such as revenue sharing bonds, andsince 1985, a levy on TEK's generation from certain large hydropower plants whoseconstruction was financed by PPA. The private sector indirectly contributes tothe funding of PPA, since a portion of the taxes levied on revenues from energysales is earmarked for the fund.

Table 1.2: Enerzv Sector: state Economio EnterDrises CSEEs)

Ministry ofMinistry of Energy and Natural Resources PubUo Works

Sector Coal Lignite Petroleum Electricity Electrioity

State Turkish Turkish Turkish Turkish StatelEconomLe Hard Coal Lignite Petroleum Electricity HydraulicEnterprises Enterprise Enterprise Corporation Authority Authority(SEEs) (TTK) (TKI) (TPAO) (TEX) (DSI)

EloctricitySurvey

Mlneral Research Institute (MTA) Administration(lIE)

TurkishPetroleumRefinerie3

PetraolemPipelinesCorporation(BOTAS)

-6

1.14 Direct private investment is largest in the power subsector(paras 1.25-1.28) with two regional utilities (QEAS and KEPEZ) totalling 690 MWof installed capacity and two small BOT hydro projects (Hasanlar and AksU-Caykoy)which have come on-strea.m in 1991 with a cumulative installed capacity of 24.35MW. The operation of two energy distribution networks located in the Kayseri andAktas (eastern Istanbul regions) respectively, has been turned over to twoprivate companies. The power subsector also counts on a few industrialautoproducers, which generate approximately 6X of total electricity. Privateparticipation in the other subsectors consists of small coal mines, one refineryand joint ventures with TPAO for petroleum exploration and petroleum productmarketing. The stcps being taken by the Government in prioritizing privateinvestment mobilization and in exploring different investment funding options forenergy indicate that the private sector will play an increasingly important role,as it is expected to provide the additional investment to supplement constrainedpublic funds which is indispensable to meet the future energy requirements ofTurkey.

Investmetnt Financing

1.15 The evolution ofenergy investment is explainedby the dynamics of the broadermacroeconomic context. Duringthe late 1980s, the Government Energy Sector: Fixed Capital Investmentfinanced the capital account Eo e .F C

deficit and covered the 4

requirements of the consolidatedpublic sector by placingfinancial claims on the doriestic 'bond market. As a result, ! u.

public expenditure shifted frominvestment financing to debtservicing, no longer sustaining ..

the large energy investments Iwith long gestation periodswhich had been financed in theprevious years. Private savingswere, to some extent, channelledto fuel the requirements of an o " . _ '

inefficient public sector.Figure 1.1 illustrates themovements of total energy fixedcapital investment (classifiedby source of financing) in the Figure 1.1: Fixed Capital Investment insecond half of the 1980s. Public the Energy Sector (1985-1990)investment in fixed capitalpeaked at TL 3,448 billion in1986 (growing by 141 from the previous year). This level of public investmentwas however eroded by almost 111 during 1987-88, dropping by approximately 22Xin 1990 after a slight recovery in 1989.

1.16 The share of private fixed capital investment has been increasing(with fluctuations in 1985 and 1986) at a decreasing rate during the same period.The largest expansion of private investment in energy was recorded in 1988, whenit was raised by 65.81 from the previous year. The actual estimated volume ofenergy investment from private sources amounted to TL 264 billion in 1990 (inconstant 1988 prices). The wider presence of private capital did not compensate

-7-

for the cut-backs in public financing sources. Total volume of energyinvestment, which had declined to TL 3,255 billion in 1987, slowly recoveredduring the two subsequent years, dropping again in 1990 to TL 2,769 bn (thelowest value since 1985).

InRut-Substitution Strategy vis-a-vis the Environmental Constraint

1.17 The policies and investments launched during 1980-1990 in responseto the two major oil shocks were largely successful not only in overcoming theserious energy shortages of the 1970s - early 1980s, but also in changingsignificantly the structure of the energy sector toward less dependence onimported oil. The evolution of the country's overall energy balance during thepast decade, discussed in paras 1.1 - 1.10 illustrates such progress. By 1990Turkey's overall energy intensity had increased considerably, since net primaryenergy consumption grew by about 72% during the 1980s, as compared to a 49%increase of real GDP. With the supply of electricity having grown faster (grosssupply more than doubling in 1980-89), the country's dependence on petroleumproducts had fallen by as much as 5 percentage points to 55% of total commercialconsumption. Consequently, in 1990, electricity (of which less than 1% of netsupply was imported), accounted for a somewhat larger proportion (27.5%) of allcommercial energy supplied than in 1980 (23%), with industry's share havingdeclined over the past decade to the benefit of residential consumption. Inparallel, the use of domestic lignite expanded significantly during the 1980s (byas much as 6 percentage points) representing in 1990 about 19% of commercialenergy consumed.

1.18 Oil-based power generation was partly substituted by a greater useof domestic lignite during 1980-1990; only 12% of total generation was oil-basedin 1990 (compared to 25% in 1980), while lignite-based generation has increasedmore than threefold (by 371%) during the same period. However, as a response tothe Government's commitment to contain the volume and level of emissions fromthermal power plants within EEC-comparable pollution control standards, and asa result of lower than projected demand growth, the new lignite-fired generationhas been underutilized in the past few years; full capacity utilization is notexpected to be achieved before 1995. Consequently, Turkey's plan for furtherexpansion of electricity generation to meet demand growth projected to the endof the century, is less reliant on domestic lignite and consistent with the needto balance the trade-off between substituting for imported fuels and confiningthe implementation of lignite-based generation to those investments which proveeconomically justifiable within the environmental constraint. The generationexpansion plan, therefore, calls for a greater share of hydro-generation and fora further expansion of imported but cleaner natural gas combined-cycle basedcapacity.

1.19 Notwithstanding the vigorous policy of indigenous resourcedevelopment undertaken by the Government since the 1970s, Turkey's dependence onimported energy was exacerbated over the last decade. The share of energyimports in the country's overall net supply of primary energy increased from 44%in 1980 to 46% in 1990. Due to greater reliance on imported natural gas andcoal with lower sulphur content, the energy import bill absorbed approximately4% of the GDP in 1990. This trend reveals clearly the conflict faced by Turkey'senergy policy between its trade balance and environmental objectives.

- 8 -

B. The Power Subsector

OveMrvl

1.20 Turkey has a total installed capacity of 18 oW, of whichapproximately 431 based on hydro power, 301 based on lignite, and 151 based onnatural gas. Fuel oil-fired plants represent 121 of total capacity installed(the composition of installed capacity in 1990 i8 illustrated in Figure 1.2).The system generatea 56 TWh ofelectricity in 1990, of which 26 TWh(471) was from hydropower. Annex 1.2illustrates the configuration of the -4woneton of Inut-lI.a clpaitygeneration system's installed capacity W'v em"s_ c_iIand the expected trend of electricity .e C

generation and electricity sales during(1991-2010). According to the currentleast-cost development plan for the csubsector, the relative importance ofnatural gas will increase to 26 percentby end-1991, when 50 percent of totalinstalled capacity will be hydro-based.Total generation and distribution lossesamount to approximately 17.21, havingdecreased by an average of 1X per yearsince 1984.

FLS=ue 1.2: Comositionm of X:ostallsd1.21 Power is transmitted through C.J.k1u An! as I"o 190

8,660 km of high voltage transmissionlines at 380 kV and 20,700 km lower-voltage transmission network at 220, 154 and 66 kV. The distribution system'sgrid consists of 309,815 km of distribution lines with a cumulative distributiontransformer capacity of 14,611 tVA. The system encompasses 593 transformers (541of which at 154 kV level). Annex 1.3 contains a detailed descriptions of thetransmission system across different kV levels and of the distribution systemduring 1981-1990. A tabulation of the status of distribution facilities and ofsubstations composition is in Annex 1.4.

Power Subsector Strategy

1.22 The Government's basic strategy for the power subsector is to ensurea balanced, least-cost expansion of the system at a rate adequate to meet thecountry's economic growth requirements and is articulated along the followingmain policies: (a) improving the operational and financial efficiency ofsubsector; (b) reforming the pricing policies on the basis of the LRHC of supply;(c) reallocating public investment to correct those systemic imbalances in thepower sector which have led to inadequate investments in transmission anddistribution vis-a-vis investment in power generation; (d) maximizing prlvateinvestment in power generation; (e) developing an institutional framework suitedto attract private investors and facilitate their co-existence with the publicsector utility; (f) reducing the environmental impact of the existing thermalplants, where feasible, and limiting new investment in lignite-based generation.

1.23 Pursuing the above policies, GOT's objectives for the sector include:(i) providing an adequate basis for tariff setting and maximizing investmentfunding; (ii) modernizing and improving the efficiency of the public powersector; (iii) turning around the market's perception of the uncertaintiesassociated with power generation investments by developing clear regulatory

- 9 -

policies; (iv) adapting the regulatory framework to the needs of a mixed system;and (v) mitigating and monitoring the adverse environmental impact of domesticlignite-fueled power generation.

Power System Expansion

1.24 Due to the severe energy shortages in the 1970s and early 1980s,domestic lignite-based power generation was expanded at a fast pace in order toalleviate the sector's dependence on imported energy. The establishment of thePPA fund supported DSI's large investments in hydro-generation during the 1980s.Overall power system expansion during 1986-90 was characterized by contingencydecision-making dependent on budgetary constraints. With the commitment offunding mainly concentrated on the ongoing generation expansion, investment intransmission and distribution was in fact not commensurate to Saintain a balancedpower system. The lack of adequate investment planning and the authorities'overestimation of economic expansion and of power demand growth resulted in over-investment in generation, reflected by an excessive reserve margin of thegeneration system's installed capacity (82.1X in 1990). The generation capacityreserve margin which can ensure adequate contingency-responsiveness andreliability of the system is estimated at 35-40Z of total generation capacity(corresponding to a loss of load probability of 2-3X).

1.25 A detailed reviewof the power subsector Reserve Margin and LOLP (1989-2010)expansion plan with regard to | ww 9_w

the volume, composition and sphasing of an investmentprogram has been carried out K0

by the Turkish authorities incooperation with the Bank inthe context of preparing theTEK Restructuring Project so(Ln. 3345-TU) and the 4

proposed Berke Project (theleast-cost expansion plan and 30

its underlying assumptionsare described ir, Annex 1.5).Agreement on the Core X

Investment Program to be a"g

undertaken under the Sixth l 2

Five-Year Plan (1990-94) was O X"r Urgin + OWU

reached under the TEKRestructuring Project which Figure 1.3at the same time aims atimproving operational efficiency of TEK. The generation system expansion programplanned from 1991 to 2010 and reviewed by the Bank is sequenced so as to ensurethat system's reserve margins will fall within the optimal range and that thesystem's expansion will adequately meet increasing demand for electricity. Theobserved and expected trends in the level of reserve margins and in thecorresponding loss of load probability (LOLP) are illustrated in Figure 1.3 (ahigher reserve margin corresponding to a higher level of reliability of thesystem). Reserve margins reduced to 69.11 in 1991, and will steadily decreaseto a desired level of about 371 by 1996.

1.26 The current Government target of increasing GDP by an average ofabout 6X a year during 1991-2010 would result in an average yearly growth ofelectricity demand of around 91 during the same period. On this basis, the long-

- 10 -

term least-cost expansion plan for the power subsector (1991-2010) calls for anincrease in generation capacity of about 47 GW (15.5 GW for hydropower).Conversely, the critical value of average GDP growth which would require noadditional investment in power generation (given a reserve margin of 35-40X)corresponds to approximately 2 percent annual growth during 1996-2010. Annex 1.6contains a synoptic table of the simulations obtained with a demand forecastmodell/, showing that, other assumptions being held constant, an average levelof GDP growth above 2 percent during 1996-2010 requires new investment in powergeneration during 1991-2010 (the average construction period of generation plantsbeing approximately five years).

Plan and the Role of Private Sector Investment

1.27 The fluctuations in the fixed capital investment observed during thesecond half of the 1980s (paras 1.15-1.16) were reflected in the imbalances inthe expansion of the power subsector. The significant investments in generationexpansion (66X of total power investment) were not matched by an adequateupgrading of the transmission and distribution networks, which together accountedfor only 16X of total power investment during the Fifth Plan (1984-88)(para 1.22). Agreement on the least cost-expansion plan corresponding to thaSixth Plan (1990-94) including its financing, was reached under the TEKRestructuring Project (Ln. 3455-TU), subject to annual reviews. Investment inthe subsector under the Sixth Plan calls for a rationalization of investmentallocation, with a 62X reduction of incremental investment in generation and agreater emphasis on transmission and distribution (to reach 521 of totalinvestment in the subsector). Moreover, the plan foresees the increasedparticipation of private investments as a portion of total incrementalinvestment, expected to total US$ 2.7 billion by 1994 (about 27X of totaladditional investment).

1.28 Private investment in the subsector is planned to reach approximately251 of total investment in generation by 1999 (of which 221 are expected to bemet by BOT consortia). Table 1.3 describes the actual status of privateinvestment in generation. Results in Implementing the private participationstrategy have been mixed; QEAS is at the moment the private utility with thelargest generation capacity (598 MW), 821 of which is hydro-based. With theproposed Berke Project, SEAS would add 510 MW to its existing generationcapacity, doubling it size and becoming the largest private entity operating inthe subsector. Only two small BOT hydroplants (Hasanlar and Aksd-Cayk6y) havecome on-stream in 1991, with a total installed capacity of 24.35 MW. In thecontext of the rationalization/privatization strategy undertaken by TEK, themanagement of the operation of the distribution networks in the regions ofKayseri and eastern Istanbul (Aktas) has been transferred to private companieson the basis of arrangements under which the local distribution utilities operateon a cost-plus basis with a certain guaranteed margin of profit regardless oftheir efficiency. A new performance-based management contract is being developedby TEK for transferring in the future the operating rights of distributionnetworks to qualified ,rivate companies/utilities.

1 The Model for the Analysis of Energy Demand (MAED-1).

- 11 -

Table 1.3: Power Subsector: Status of Private Investment (1991)

INSTALLED CAPACITY (/W)

UTILITY HY ''' THERMAL DISTRIBUTION

Regional Qukurova El.ktrik Sir (283) Mersin (106) Qukurova 'Utilities hnonim Sirketi (VEAS) Kadlneik I (70)

Seyban 9/ (60)Kadincik II (56)Yur.gir (6)

KEPEZ Karaceoren II (47.2)Other (33.20)

DOT Alerko Eansalar (9.35 MR)Consortia Akaf-Caykoy Ak*O-Cayk8y (15 NW) b/

KameribAkt,a b/

Kayseri b/.k. i b/

a/ Operation of DSI's assets.b/ Turn-over of management end operations (assets are still ownmd by TEK).a/ Under negotiation: turn-over of management end operations, as In bI above.

1.29 A total investment of TL 546 billion (corresponding to a totalinstalled capacity of 401 MW) is planned to be commissioned by 1994 forhydropower projects, 37X of which by BOTs. The Government projects that, ofthese planned investments, TL 145 billion would be realized by the private sector(26 percent of the total). The status of investment preparation however signalsthat significant delays are inevitable. There have in fact been many proposalsto undertake BOT projects in the power sector, for which letters of intent havebeen issued. However, the contract for the BOT projects have not been finalizedand their financing plans have not yet been defined. BOT projects which were toprovide 128 KW additional installed hydro-based capacity by 1994 have not beeninitiated, with the exception of the two small hydro plants commissioned in 1991(para 1.28). Hydro-generation capacity assumed to be implemented by BOTs beyond1994 &mounts to 1.5 GW. The investment plan foresees an additional 1.6 GW ofthermal capacity by 1995 consisting in one BOT project (Aliaga-1000 MW) and anatural gas combined-cycle plant (600 MW). The financing plan for theseinvestments, as well as for the remaining 5.5 GW of new hydro-based installedcapacity to be built by DSI and expected to come on-stream during 1998-2003 havenot yet been defined, with the exception of the Kayraktepe Hydropower Project(Ln. 2655-TU) (431 MW), to be commissioned in 1999.

1.30 Government expectations as to private investments' contribution tothe current expansion plan appear to be unrealistic as evidenced by the delaysin finalizing the BOT agreements. With the public investment in generationconstrained by finances, unless private investment is escalated in the short-runthe economy might experience a severe bottleneck in the energy sector. Domesticprivate investment may be partly mobilized through the assignment of entrustedregions to regional utilities, as in the case of 5ukurova and Antalya. Signalsin this direction are promising, as several companies have applled to theGovernment to become regional utilities. Accordingly, IENR intends to gear theinstitutional framework at hedging the utilities against the risk associated withthe uncertainty of investing in a mixed system. In particular, clear rules need

- 12 -

to be laid out with respect to competition for investment, determination of theutilities' costing bases, formulation and ratification of power purchaseagreements between the utilities and TEK, handling of disputes, and allocationof water rights among different users of the waters of the same river for hydroprojects. Moreover, MENR needs to rapidly step-up its expertise in evaluatingproposals for new investments. The revived institution-building component of theESAL (Ln. 2856-TU) and the sector reforms launched under the TER RestructuringProject (Ln. 3455-TU) will contribute to these efforts.

Bank Role in the Power Subsector

1.31 The Bank's lending strategy in the energy sector has been consistentwith the Government's demand management objectives and macro stabilizationpolicies. The composition of the Bank portfolio consists of five loans,including a loan approved in 1991 (the TEK Restructuring Project, Ln. 3345-TU).

1.32 The Bank has helped to introduce state-of-the-art system planningmethodoLogies and has interacted with the sector agencies toward the formulationof an adequate investment program. The recently completed TEK Transmission IV(Ln. 2586-TU) and the ongoing Power Operations Assistance Project (Ln. 2602-TU)supported the construction and rehabilitation of high-voltage transmissionfacilities.

1.33 The Kayraktepe Hydro Project (Ln. 2655-TU) and the Sir HydropowerProject (Ln. 2750-TU) supported hydro development and private sector involvement(the loan beneficiary of the Sir project, as in the case of the proposed Project,is 5EAS, a regional utility). The ESAL (Ln. 2856-TU) addressed the potentialbottlenecks in the energy sector, leading to less dependence on imported oil,deregulation of the domestic markets for petroleum products, the preparation ofan institutional framework conducive to greater involvement of private ventures,emphasis on the use of domestic resources for generation capacity expansion inthe power subsector and increased use of natural gas. Under the ESAL, themanagement system of TEK was reviewed and representatives from the Treasury, SPOand MENR were included in TEK's Board of Directors with the aim of introducingexternal accountability and improving coordination among the agencies involvedin the power industry. Furthermore, under the ESAL agreements TEK began to haveits accounts audited by private auditors of international repute (PriceWaterhouse), in addition to the Government's statutory auditors.

1.34 PCRs on three Bank financed projects in the power subsectors (Loan1023-TU, 1844-TU and 2650-TU) noted major problems with regard to TEK'sperformance, including, in particular, weak financial management, absence ofstrategic corporate planning, lack of autonomy and inadequate tariff levels. TEKemerged as a major contributor to GOT's PSBR. The Bank was requested to assistGOT iir restructuring TEK. Subsequent Bank lending pursued a sectoral approachensuing from the ESAL experience. The TEK Restructuring Project addresses thoseweaknesses of TEK which have led to the utility's insolvency and those sectoralissues which have caused misallocation of chronically scarce public funds forpower investments. In the context of that project, agreement was reached withGOT/TEK on: (a) indexing electricity tariffs and linking them to the LRKC ofsupply; (b) establishing cost centers to monitor the efficiency of plantsoperations; and (c) monitoring TEK's financial performance and investmentsthrough the adoption of cor"orate planning. Moreover, by bringing andmaintaining real electricity tariffs to UtKC level, the project will expand theutilities' revenue basis throughout the sector, supporting their financialviability and improving their potential for sustaining and expanding investment.

- 13 -

1.35 The Bank is also contributing to a UNDP-cofinanced technicalassistance program in envirormental planning, monitoring and institutionalstrengthening through the Global Environmental Fund (GEF). The Bank has beenrequested to assist in financing the cost of reducing pollution from selectedlignite-fired generation plants through flue gas desulphurization systems, andthrough the establishment of monitorable guidelines for SO2 emissions.

1.36 The Bank is actively involved in upgrading the sector's regulatorycapabilities necessary to support expansion of private investment. MENR will inthis context carry out a study (agreed upon under the ESAL Loan) which is gearedto exploring the option of establishing an independent regulatory agency for thesubsector. The study will focus on the institutional framework needed to supportand increase regional utilities' participation in the subsector and will bedeveloped using the Cukurova region (entrusted region of VEAS), as a case study.The study will define the criteria and guidelines for evaluating new investmentprojects with regard to cost estimates and efficiency of the projects and willidentify issues in the process of investment allocations and investment selectionin the power subsector which will have to be addressed by the regulatory body.Most importantly, the study will draw-up the principles for setting the exchangetariffs between the utilities operating in the region, consistently with thetariff reform agreed under the TEK Restructuring Project (Ln. 3345-TU) (para4.11).

II. THE PROJECT ENTITY: GOMKUROV ELECTRIC AS.(CEAS\

A. CoXRorate Background

Introductio

2.01 QEAS is a limited liability company subject to the provisions of theTurkish Commercial Code. Initially formed to operate the power portion of themultipurpose Seyhan project, QEAS was granted a concession in 1953 for supplyingelectricity in the Cukurova region in Southern Turkey. With the enactment of Law30962/ in 1985, CEAS subsequently became a regional utility in 1988. Thecompany's present operating decree, which expires in the year 2058, provides forit to invest in electricity generation, transmission and distributioninstallations as well as distribute electricity to consumers in its entrustmentregion comprising the provinces of Adana, Mersin, Hatay as well as the Sir andBerke Project areas in the Kahramanmaras province. The present decree alsostipulates that a major part of the company's assets would revert free to theGovernment at the end of the year 2058. gEAS operates six generating plants,including a thermal power plant, and a regional network of subtransmission(154 kV and under) and associated substations.

2.02 QEAS presently has an authorlzed share capital of TL 300 billionwhich is fully paid in. While the Government, through PPA, is the single largestshareholder, PPA's shares account for only 11.81 of the total capital.Individual investors, trade associations, banks and insurance companies, andother private firms own the majority of the stock. Shareholders, by type, arelisted in Annex 2.1 and shown in Fig.2.1. In addition, VEAS has investmentinterests in three subsidiaries - KEPEZ Electric A.S.(26.68Z), CESTAS (45.89X)and ELTEM-TEK (11X). KEPEZ is an electric utility - much like CEAS - in theAntalya region and CESTAS is a manufacturer of electrical equipments, including

2 Law 3096 established a legal right for private companies to generateand distribute electricity.

- 14 -

surge protectors and circuit breakers.ELTEH-TEK is an engineering contractorproviding services in installation andmaintenance of power plants. All of rew-udalithese subsidiaries ave managed by theirown Board of Directors elected by the /shareholders with no interference fromQEAS t.

Existing Power FaciltiLes

2.03 At present, QEAS' installedcapacity is 581 MW, of which 475 NW (82X) 64

is hydro including the recently completedSir hydroelectric power plant. Thegenerating facilities consist of: (i) the Figure 2.1 Sh:arholding In I as of 1991.

60 NW Seyhan hydro-electric power plant;(ii) the 70 MW Kadincik I hydroelectric plant; (iii) the 56 MW Kadincik IIhydroelectric plant; (iv) a 106 MW oil-fired steam plant at Hersin; and (v) the283 NW Sir hydroelectric power plant. In addition, SEAS also operates a 6 HWhydropower station at Yuregir for which it pays an annual rental fee to DSI. In1990, total net generation by VEAS amounted to 1058 GWh compared to the regionalelectricity consumption of 3959 GWh (representing about 8X of nationalelectricity consumption) and a peak demand of 737 NW.

2.04 Primarily a wholesaler of electricity in the region, QEAS operatesthe regional network from 154 kV down to 6 kV in the region. Altogether, as ofend 1990, CEAS owns and operates about 2500 km of subtransmission lines at 154kV (1012 km), 66 kV (114 km), 30 kV (1290 km), 15 kV (98 km) and 6 kV (63 km).The transformer capacity amounts to 1672 HVA spread over 27 substations.Subtrant aission losses on §EAS' network are reasonable, amounting to about 6X ofthe electricity supplied. The operation of the VEAS power system is controlledfrom the dispatch center at Seyhan (para 2.16).

2.05 The 380 kV lines and substations in the Qukurova region are part ofthe national power grid owned and operated by TEK. VEAS interconnects with the380 kV grid at TEK's 380/154 kV substation at Erzin. A second inter-connectionat Adana, financed under the TEK Transmission IV Project (Ln. 2586-TU), isexpected to be commissioned in June 1992. Also, at the 154 kV level, thesubstations at Toroslar and Osmaniye provide the inter-connection between TEK andEAS networks. As regards distribution, QEAS supplies directly village,industrial and commercial users, as well as the three Distribution Enterprises(DEs) responsible for retail sales of electricity3/ to households in thegukurova region which are owned and operated by TEK.

B. R2gMlatoXX Environmnt

2.06 VEAS' operations and key long-term policies are dictated to a largedegree by several public agencies in the energy sector which are mandated toimplement the various policies of the Government. The electricity tariffs to becharged by VEAS are determined by MENR and TEK in accordance with the Governmentpolicy to maintain electricity tariff structure and levels uniform throughout the

3 The responsibility for retail distribution of electricity wastransferred from municipalities to TEK in 1982. At present, there are 72distribution enterprises under TEK, one for each province.

- 15 -

country. The water releases for power generation are to be coordinated wlth DSIto optimize the use of water resources. CEAS lnvestments, like all investmentsin the subsector, must be approved by the SPO and MENR to ensure lntegratedplanning for least-cost expansLon of the country's power system; thelrenvironmental associated aspects are regulated by the Ministry of Environment.The financial affairs of VEAS are governed by the Turklsh Commercial Code, theCapital Markets Law and the Capital Markets Board. Under the Capital Market Law,passed in 1981, the Capltal Markets Board (Sermaye Piyasasi Kurulu -SPK) wasestablished to carry out the Government's policy of strengthening the regulationof capital markets and protecting tha rights of investors. The SPK carries outits mandate through regulation and supervision of public offering of securities,stipulation of financial reporting and auditing requirements and related matters.QEAS is thus, a regulated monopoly utility engaged in generation, transmissionand bulk distribution of electricity including trading with TEK. However, yEAS'management is not controlled by these agencies.

2.07 In order to ensure consistent and transparent application of theGovernment's policy of enhancing private sector participation in the powersubsector, MENR intends to set up an independent regulatory body. MENR is nowin the process of recruiting consultants to assist in developLng the scope ofregulations, defining the mandate of the regulatory body, determining itsstaffing needs and the related aspects4/ (para 1.25). Pending the creation ofa regulatory body, the proposed Project would address the issues of electricitypricing and water management in so far as they bear on the viability of theProject and yEAS.

C. Organization and Management

2.08 The present organization of QEAS is presented in Annex 2.2. TheBoard of Directors includes: a chairman; five directors representing privatestockholders have two-year terms; and three directors representing PPA have one-year term. QEAS' Board of Directors is an elected body under the provisions ofthe Turkish Commercial Code. QEAS' management, which comprises a General Managerand six Assistant General Managers (AGM), is distinct from the Board of Directorsthus separating the policy making and policy implementing bodies of gEAS. Fourof the AGNs are for technical functions - Operations, Projects and Design, PowerPlants Installation and Planning and Coordination - and one each for Finance andAdministration. The six AGMs are supported by 21 managers and their staff.

Personnel and Staffing

2.09 gEAS' personnel policies are governed by the general Labor Law 1475,applicable to both public and private enterprises in Turkey. Under this law, alllabor contracts are subject to collective bargaining without governmentintervention. gEAS' labor force is unionized like TEK and other utilities in thecountry and the relationship between management and unior. is satisfactory.

2.10. QEAS is able to pay higher salaries and provide better benefits thanthose permitted for SEEs such as TEK and has experienced low turnover of staff

4 The consultlng services would be financed from the ESAL (Ln. 2856-TU)as agreed with the Bank. In 1991, the Government also sought the Bank'sasslstance to study and propose optlons for reforming and restructuring thepublic sector (the State Owned Enterprise Sector Review). The reviewrecommends regulation of key sectors including the power subsector eitherthrough one regulatory body or one for each key sector.

- 16 -

(less than 1.5X annually), mostly due to retirement. The total number ofemployees at the end of year 1991 was 1,490 and the classification by educationallevel and technical area is shown in Table 2.1.

Table 2.1 Staff Profile of CEAS - 1991

By Education Level Humber X Bv Activitvy Number

Higher Education 324 22 Generation 373 25High School 678 46 T & D 297 20Secondary School 131 9 Construction 324 22Primary School 357 23 Administration 496 33

Total 1490 100 1490 100

2.11. QEAS has adequate training facilities for training its staff in mostareas of technical operations. In addition to in-house training, QEAS providesexternal training to its staff in various functions. Technical Assistance wasprovided under the ongoing Sir Hydropower Project (Ln.2750-TU) for training gEAS'staff in load management and dispatch, project management, financial management,manpower planning, computer systems applications, as well as for studies coveringMersin thermal power plant rehabilitation, Kadincik II hydropower stationmaintenance, power transmission and wheeling. The studies have been completedand the recommendations implemented except for the power wheeling aspects whichare not considered practical by both TEK and QEAS.

Long-Term Planning and Investment Program

2.12. QEAS' long-term plan is based on SPO's and TEK's detailed powersystem expansion plan for the country5/. Although QEAS does not do its owngeneration planning, it prepares demand forecasts for the region, usingstatistical methods to facilitate its own corporate planning. QEAS intends toupgrade its software to adopt more sophisticated and modern tools of demandforecasting such as the MAED model used by sro and MENR. As regardstransmission, detailed system master plan was developed with technical assistancefrom Power Technologies Inc., USA. gEAS updates the master plan whenever majorchanges occur in generation investments or in the estimated growth of demand inthe region. gEAS has installed modern tools such as the Power Systems AnalysisPackage (PAP) on its computer for analyzing load flows, system stability (bothtransient and steady state), short circuits, etc.

2.13. gEAS is required to obtain approvals from the SP0 for all powerinvestments, except those with a rc ing of 1000 kVA or less, and from TEK ontransmission line designs. SP0 also determines and approves the investmentincentives for QEAS6/. These are reflected in gEAS' medium- and long-termfinancial plan and annual budgets. The annual budget is considerably detailedand is a combination of capital and operating budgets. The annual budgets aredisaggregated to monthly budgets including monthly financial statements and cashbudgets. Although, for purposes of approval by SP0 and MENR, the assumptionsdictated by the Treasury with regard to exchange rates, inflation levels andtariff increases are used, QEAS uses different assumptions for the purposes of

5 This is done using modern planning tools such as the WEIN AutomaticSystem Planning (WASP-III) model based on load forecasts prepared by MENR/SPO.

6 Under the Turkish Law, a portion of a company's investments can bededucted from income for tax purposes, as determined by SP0 for eachinlvestment. Such investment incentives are intended for promoting developmentin designated areas of the country and vary from region to region.

- 17 .

corporate and financial planning. Because of the consistently higher thanforecast inflation over the past few years, the budgets are continually revisedand monthly analys's of the budget covering three months - preceding, current andfollowing months - is presented to the Board.

Project ImDlementation Capacity

2.14. VEAS has limited in-house but well organized project implementationexpertise. The AGM - Power Plants Construction - oversees construction of newpower plants, while the AGH - Projects and Design - oversees construction of T& D projects as well as other projects. QEAS creates ad hoc Project Departmentsto coordinate the implementation activities by drawing appropriately skilledstaff from its various departments. For large and complicated projects,consultants of international repute are recruited to design and carry outconstruction. QEAS successfully implemented the Bank financed Sir dam andHydroelectric power plant with project assistance from Coyne et Bellier, France(C & B). VEAS has again recruited C & B as project consultants to provide thenecessary assistance to design, construct and commission the proposed Berke Damand Hydropower Plant (Chapter III). For all T & D projects, engineering servicesincluding implementation, are provided by ELTEM-TEK.

OReration and Maintenance

2.15. The AGM for operations is responsible for operation and maintenance(O&M). The operation and maintenance department carrys out O&M activities ingeneration (hydro and thermal power plants), transmission/lines and substations,154 kV to 6 kV). The operation of the hydro plants is under the jointresponsibility of DSI and VEAS. DSI is responsible for the operation of all damsexcept Sir. The operation of the powerhouses is the responsibility of QEAS. Forthe Sir dam, DSI is responsible for the water release program only. DSI cornductsregular inspections of all dams and follows the practices of the US Bureau ofReclamation in this respect. Annual inspections are conducted by DSI's regionaldivision in the territorv where the dam is located. The Mersin thermal plant isoperated by QEAS. However, the operational capacity level is determined as perthe agreement between TEK and QEAS. The maintenance programs of all power plantsare prepared by the Load Dispatch Department, while the maintenance programs ofall the substations, switching stations and transmission lines are prepared andcarried out by the Network Operation Department. The routine maintenanceactivities, which require expertise involving manufacturing and repair ofsophisticated parts, are carried out by contractors.

Load DisRatch and Management

2.16 QEAS load dispatch center at Ceyhan is old and has reached capacitylimit. In order to meet the needs of the utility in managing the expandedgeneration pool as well as transmission network in the decade, a modern loaddispatch center electronically connected with the national load dispatch centerwould need to be constructed. QEAS has agreed to carry out a study to determinethe location, type, size and other specifications for the proposed load dispatchcenter. VEAS has agreed to complete the load dispatch center study by December31, 1993, under terms-of-reference satisfactory to the Bank.

- 18 -

D. Commercial and Financial Management

Electricity Demand and SUDPlY

2.17. The region's actual and forecast electricity demand-supply balancefor the period 1977-2000 is included in Annex 2.3 and summarized in Table 2.2.

Table 2.2 : Cukurova Re*ion Electricity Demand and SupDly Balance. 1981-2000

-------------Actual ---- Forecast-- ------Growth Rate (X)------1977 1 9 1991 1989 2000 1977-87 1977-91 1991-2000

Demand (GWh) 1749 2166 3409 4047 5586 7361 6.9 6.2 6.9Peak Demand (MW) 261 372 577 793 1112 1457 6.3 8.3 7.0Installed Cap.(MW) 1/ 298 298 298 581 751 1091 na na naQEAS Generation (OWh)

- Existing Plants 1571 1362 1413 1154 1874 1796 -1.0 -2.2 5.0- Proposed Project - - - - 700 1543 - - -- Total Generation 1571 1362 1413 1154 2574 3339 -1.0 -2.2 12.5- as X of demand 90 63 41 29 46 45 - - -

Purchase from TEX (GMh) 2/ 244 697 2167 3178 3306 4410 24.4 20.1 3.7- as of Demand 14 41 64 79 59 60 - - -

1/ Assuming availability of one-third of proposed Project capacity in 1996.2/ Gross of transmission losses.

2.18 The regional demand for electricity grew at an annual rate of 6.2Xover the 1977-91 period, much in line with the overall growth of the same in thecountry, while QEAS' generation decreased at an annual rate of -2.2%. This wasbecause QEAS could not expand its generation capacity in line with the demand dueto the restrictions placed on it prior to 1985 as well as to the unfavorablehydrological conditions, especially towards the latter part of the period. Also,VEAS could not increase thermal generation at the fuel oil-fired Mersin plantsince it is old and required extensive maintenance. QEAS is fully responsiblefor ensuring supply of electricity to all customers in the region, includingTEK's DEs which account for over a third of the regional demand. In order tomeet the gap in the regional demand and its own generation, SEAS purchases powerfrom TEK. Such purchases increased gradually in the past but sharply over the1987-91 period. This is indicated by the proportion of power purchases todemand, which increased from 14% of demand in 1977 to 64% by 1987 and to 791 in1991. The demand forecasts for the region carried out by t;_AS estimate it togrow at an annual rate of 6.9% over the 1991-2000 period. The commissioning ofthe three units of the Sir Hydropower plant in 1991 as well as the proposed BerkeHydropower plant in 1996/97 would enable gEAS to increase its own generation atan annual rate of 12.5X during 1991-2000 and reduce its dependence on TEK from79% of demand in 1991 to about 59% by 1996.

2.19 Power Exchange Agreement. VEAS buys energy from TEK at variousinterconnections with the national grid owned and operated by TEK. The amount(s)of power/energy QEAS obtains from TEK is based on monthly load-forecasts whichare prepared by QEAS and reported to TEK, MENR and DSI detailing planned wateruse at its hydro plants and required power from TEK to meet demand in the regionas well as its sales to TEK's national grid. QEAS also supplies to the gridsmall amounts of power for system considerations. The two utilities exchangepower in accordance with the provisions of the Power Exchange Agreement (PEA)signed in 1983. The PEA, which has been revised twice since, establishes theprinciples of power exchange covering such aspects as measurement of energytransfer, operating conditions, exchange price, billing, payments, inspection,arbitration, etc. The PEA does not stipulate the amount(s) of energy to beexchanged between them. This is because QEAS remains subject to load-shedding

- 19 -

measures to the same extent as other regions of the country in the event of powershortages. Accordingly, the PEA establishes that the two utilities will applysimilar measures in the event of power shortages. QEAS has not experienced anydifficulties in obtaining power in the required amounts from TEK. Given therelatively high reserve margin in the system up to 1995 and the planned additionto the system including the proposed Project, no power shortages warranting loadshedding measures are expected.

Tar,if fs

2.20 CEAS' tariff structure is similar to that of TEK's which is based onthe broad classification of consumers into categories - Industry, DEs, Villages,Agriculture/Irrigation, Municipalities and Government Departments. Two-parttariffs are applicable to large a.id medium industries drawing power at the 66 kVand above level, and consists of peak (17:00-22:00 hrs), off-peak (22:00-6:00hrs) and day-time (6:00-17:00 hrs). In addition, demand charges and punitivedemand charges for consumption above the specified limits are applied. One-parttariffs are applicable to all other categories of consumers. Village customerspay at the lifeline rate regardless of consumption while the irrigation consumerspay at 46X of the applicable rate for villages. The tariffs for DEs are set byTEK and are linked to the average costs and revenues of TEK (paras 4.12 - 4.13).

2.21 QEAS is allowed to charge its customers in the region the sametariffs charged by TEK in other regions. This follows from the policy of GOT tomaintain electricity tariff structure and levels uniform throughout the countryand is expected to continue into the foreseeable future. However, CEAS has norole in setting such tariff structure or levels which are set by TEK inconjunction with MENR and Treasury. Following any changes or increases totariffs announced by TEK, VEAS applies to MENR for obtaining approval to adjustits own structure and/or levels in line with TEK's, along with a statementshowing the impact/effect of such tariff changes on its financial situation(Annex 2.4).

Sales. Billing and Collections

2.22 Sales and revenues by customer group for 1986 and 1990 is providedin Annex 2.5. The textiles industry is the largest consumer (131 of sales in1990) followed by iron and steel (11) and cement (9X). In 1990, about 901 ofsales by volume is accounted for by bulk consumers - industry (531) and TEKs a DEs(371) - who also account for over 901 of CEAS' revenue base, 60X and 331respectively. The annual rate of growth in consumption by industries over theperiod 1986-90 was 5.81 while the same for TEK's DEs was 10.51.

2.23 Industrial customers are billed once a month and bills are deliveredimmediately. Also, official departments, agriculture/irrigation andmunicipalities are billed once a month. The meters in villages are read once inthree months but are billed every mo.,th on a pro-rata basis. Segments ofcustomers are billed at different dates of the month to smoothen the billing andcollection process. CEAS prepares and delivers bills to retail customers underTEK's DEs but TEK collects the payments. Sales to TEK's DEs are netted out ofpayments to TEK for power purchased and settled every month. CEAS has acomputerized billing system. Customers can pay at any bank and a penalty of 71per month is levied on late payments. VEAS has a good ~ollection record and itsreceivables in 1990 was about one month of sales which is very satisfactory.

- 20

2.24 CEAS bills and collects from consumers, as does TEK, a number oftaxes including municipal tax (3.5X), VAT (12X), Television and Radlo Taxes (TRT1X) and Collective Housing Fund Levy (CHFP 1O). TRT and CHF are included in thebase tariffs and do not appear as separate items in energy bills. Afterdeducting the VAT paid on its own power purchases, QEAS transfers to theGovernment the VAT collected from its sales. Also, the VAT paid on purchases tobe incorporated in fixed assets is similarly recovered. Corporation tax andother levies on CEAS' profits are assessed at 461 of taxable income base.Investment incentives approved are deductible for tax purposes and are carriedforward for full recovery of allowed amounts. Contributions to various statutoryfunds such as Defence Fund and Social Solidarity Fund are payable at 51 and 1Xof corporate tax respectively.

InsurLce

2.25 CEAS maintains fire and machinery breakdown insurance policiescovering 50X of cost on plant and equipment and 801 on inventories. Work-in-progress is insured on all risk basis for its full value. QEAS also ensures thatcontractors provide adequate insurance on all major projects and procurement.

Financial Organization

2.26 The financial management function in CEAS is headed by the AGH forFinance who is supported by a manager and six assistant managers responsible forGeneral Accounting, Operations Accountsng, Investment Accounting, Tax Management,Finance and Shares & Shareholder Relations. The finance department is adequatelystaffed (36 members) with some staff having university degrees in commerce andbusiness management. The staff are also well trained in the use of computerapplications used by CEAS for its accounting and financial management.

Accounting Systems and Practices

2.27 CEAS' accounting systems and accounts are in accordance with theprovisions of the Turkish Commercial Code. Under the Turkish Law 2791 (1983),concessionary companies (like QEAS and KEPEZ) and foreign companies operating inTurkey are not allowed to revalue their fized assets. However, CEAS capitalizedup to 1984 the exchange losses on foreign loans outstanding by adding anequivalent amount to fixed assets as allowed by the commercial code7/. Thispractice was discontinued in 1984 on the recommendations of auditors (PriceWaterhouse), and only that part of the exchange losses attributable toconstruction in progress has been capitalized since then, in line withinternational accounting standards. QEAS now intends to revert to capitalizingall of the foreign exchange losses on outstanding foreign loans beginning with1991 as a means to de-facto revalue its assets, by presenting the foreign costportion of the asset base in revalued units. This is acceptable as long ascumulative capitalized exchange losses do not exceed the reasonable revaluationof fixed assets which the recent high inflation would call for, but would not beotherwise allowed with Turkish Law. The proforma revaluation of CEAS' asset baseprepared by VEAS and the mission indicates that its revalued net fixed assets inoperation at end 1990 was TL 152 billion (US$52 million equivalent) compared withunrevalued TL 70 billion (US$23 million). In order to compensate for the

7 The Turkish Commercial Code allows capitalizing or expensing theforeign exchange losses each year at the option of the company.

- 21 -

stipulation that a major part of the assets should be transferred to theGovernment at the end of the concession agreement, VEAS is granted an additionalannual amortization on its capital for tax purposes. Other legal reserves arealso appropriated from statutory profits which may be used to absorb losses.

Audit

2.28 In addition to a Board of Auditors required by the law, QEAS hasestablished an internal audit wing reporting directly to the General Manager.The audit wing is staffed with two professionals, one each for financial andtechnical audit, and headed by a manager. The technical audit covers alltechnical and related operational aspects; and the financial audit covers onlyprocedural compliance with organizational policies and practices for internalcontrol rather than compliance with accounting principles and policies. TheTurkish commercial code requires that the annual financial report be submittedby mid-March, two weeks prior to the annual shareholders meeting. The Board ofAuditors performs the financial audit regularly during the year. Also, theauditors representing the Treasury carry out audit of large investments todetermine compliance with regulations.

2.29 For companies whose shares are traded on the stock exchanges in thecountry, the Capital Market Law requires an independent financial audit by firmsregisterod with the Capital Market Board. Accordingly, CEAS recruited PriceWaterhouse of Turkey to conduct such audit. SEAS has submitted to the Banksatisfactory audit reports prepared by Price Waterhouse as agreed under theongoing Sir Hydropower Project (Lra.2750-TU). With the expiry of the six-yearterm of the audit contract with Price Waterhouse (last audit for 1991), VEASintends to recruit another firm, approved by the Capital Market Board andacceptable to the Bank, to conduct the audit of its accounts beginning with thefiscal year 1992. QEAS has agreed to carry out the financial audit of itsaccounts for each year beginning with 1992 accounts, including project accounts,by private auditors under terms-of-reference satisfactory to the Bank,and submitthe audit reports to the Bank within six months after the end of the fiscal year.

III. THE PROJECT

A. Proiect Setting

Overview

3.01 The Government's strategy in the power subsector during the Sixth-Five Year Plan as embedded in the power generation expansion plan calls forfurther exploitation of domestic resources, particularly hydro potential forpower generation in preference to lignite base generation (which is subject toenvironmental constraint). In addition, the strategy aims at expanding privatesector participation in the subsector. Given the constraints in public financingand the delays encountered in the fruition on the BOT proposals, the proposedProject needE to be completed as planned in order to reduce the risks of powershortages toward the end of the decade. QEAS, a private utility, is well placedto implement the proposed Project.

3.02 Turkey's main domestic sources of energy are hydro potential andlignite deposits. The exploitable hydro power potential is estimated at about31 GW with average annual generation about 122 TWh, of which 7.5 GW has beendeveloped. gukurova region's hydro potential has been estimated at about 3.9 GWwith average annual generation of about 12 TWh. The region's existing hydro

- 22 -

generation capacity is 721 KW of which 475 MW is owned and operated by QEAS.About 697 NW are under construction by DSI. The proposed Berke Hydro PowerProject would exploit a further 510 MW of hydro potential. This wouldsubstantially increase EAS' generation capacity and help CEAS cover more thanone-half its final sales by self generation.

RAtionale for Bank Involvement

3.03 The Bank's involvement would support GOT's strategy of mobilizingprivate funds for the power sector. The delays being experienced in establishingBOT schemes have escalated the pressure on GOT for ensuring that the proposedProject is implemented without delay. The proposed Loan would secure resourceson terms and conditions suited for long-gestation investment. Private resources,which would not otherwise be available without Government guarantee, are to bemobilized by IFC while the Bank would provide the additional funds needed to meetthe foreign costs. Further, the Bank"s involvement would ensure thatenvironmental and resettlement concerns are properly addressed.

Project Objectives

3.04 The proposed Project would assist the Government in: (a) acceleratingthe development of hydro potential; and (b) expanding the role of the privatesector in power generation, thereby alleviating the pressure on the public sectorfor mobilizing the financial resources.

Project Descriptio'

3.05 The Project consists of the following components:

(a) Construction of a thin concrete double curvature dam (201 m highabove the foundation and with a crest length of 270 m), includinggrout and drainage curtains at Berke on the Ceyhan River to form agross storage reservoir capacity of 427 million mi, tunnel andsurface spillways, bottom outlets, intake structures with a 2,050 mlong and 9.3 m in diameter headrace tunnel, a horizontal steel-linedtunnel (41 m long), a surge tank (20 i in diameter, 90 m high), anunderground power house (25 m long, 19.75 m wide and 33.5 m high)with three 187.5 NVA vertical Francis type turbine generators andtheir power step-up transformers, and a switchyard with an outdoordouble busbar type switchgear;

(b) subtransmission lines (737 km) and substation facilities (12substations with installed capacity of 1,350 MVA) in order totransmit the energy generated by Berke to load centers and expandthe 154 kV system to meet the forecasted demand in the QEAS servicearea and regional dispatch center;

(c) technical assistance for studies related to the regional dispatchcenter installation and operation, training and procurement of thespecial equipment; and

(d) The project includes a program to resettle or provision toindemnify, as required, 144 people affected by the project,including provision of alternative adequate housing and othercommunity and infrastructure facilities.

- 23 -

A full description of the project components is provided in Annexes 3.1, 3.2 and3.3 respectively.

Project Origin

3.06 The proposed Berke Dam and reservoir are situated along a 35 kmsegment of the Ceyhan River. The project area lies in the south Anatolia regionwithin the provinces of Kahramanmaras and Adana. The project site lies withina narrow, steep-sided canyon between two existing dam/reservoir systems: onelocated immediately upstream at Sir, and the other 2 km downstream at Aslantas.The Berke project is close to transmission lines associated with the Sir andAslantas power plants.

3.07 The Berke hydroelectric project has long been considered an importantpotential source of electricity to the region and has been the subject of aseries of feasibility studies (IECO, 1966; OTCA, 1969; Temelsu, 1978Energoproject, 1984; C&B/Aknil 1990). Of the 31 existing or proposedhydroelectric projects identified in the VEAS service area, the Berke projectprovides the highest installed capacity. Furthermore, many features of the sitemake it ideal for the generation of hydro-electricity: the steep hydraulicgradient, its location between two existing reservoirs, the proximity to existingtransmission lines, the relatively small area to be inundated for the reservoir,and the paucity of settlements and arable land within this area. A detailedwater resources development master plan (IECO, 1966) was prepared for the CeyhanRiver Basin in 1966 which proposed a series of dams and reservoirs along thelength of the Ceyhan River for water supply, irrigation and hydroelectricity.Eight out of a total of twenty-seven projects have been completed to date and theremainder are projected to be completed within the next 20 to 30 years. TheBerke hydroelectric project was one of the projects identified in the IECO masterplan. The design of the proposed Berke hydroelectric project has undergone anumber of transformations since its initial conception to accommodate physicalconstraints of the site.

3.08 The first Berke feasibility study, conducted for DSI by IECO in 1966,envisaged two alternative layouts: either a high dam (207 m) situated at theBerke site with a powerhouse located immediately downstream, or a run-of-riverdam located further upstream with a 9340 m power tunnel which would relay thewater to a power plant located slightly upstream of the Berke site. This secondalternative was designed in the event that a high dam in karstic limestone mightcause leakages (IECO, 1966). In 1969, the Japanese Overseas TechnicalCooperation Agency (OTCA) was commissioned by DSI to evaluate the project. Theirreport concluded that a 310 meter high dam could be constructed at the Berke sitewithout inducing leakage into adjacent valleys. No significant karstificationwas observed at the dam s'.te and the OTCA report indicated that any foreseeableproblems could be resolved by means of grout curtains (OTCA, 1969). The projectwas reevaluated again in 1979, this time at the request of the Electric WorkAdministration (EIE), by the firms Temeslu and Energoproject, who designed a run-of-the river dam at Duzkesme, a 13.8 km power tunnel and a power station at Berke(Temelsu, 1978; Energoproject, 1984). Although the Duzkesme-Berke scheme did notmake full use of the available head between Sir and Aslantas, this layout wasproposed because of concerns about leakage from a high dam located at the Berkesite.

3.09 As the project preparation progressed, however, it became evidentthat there were a number of problems associated with construction of the 13.8 kmtunnel. Unfavorable geologic conditions raised serious questions about the timeand cost required for tunnel construction. Furthermore, the tunnel diameter was

- 24 -

limited by economic considerations, which in turn, limited the installed capacityof the project. When further geological studies at the Berke site indicated thatrisks of leakage were limited, the Duzkesme-Berke design was abandoned in favorof the project described herein. The firm of Coyne et Bellier and Aknil werecommissioned in December 1988 by VEAS to draw up, under a grant from the FrenchGovernment, the feasibility study of this project. During the planning anddesign phase, a number of different alternatives were evaluated, including thetype of dam, height and design capacity, and the layout of the hydraulic conductsand power station.

B. Technical Evaluation

The Dam and the Powerhouse

3.10 Zhe Bank's experts reviewed the available information on: (a) geologyof the dam site; (b) the slope and stability around the reservoir area; (c) watertightness; (d) foundation treatment; (e) drainage and grout curtains;(f) seismicity; (g) hydrology; (h) geology of the headrace tunnel and undergroundpowerhouse sites; (i) availability of suitable construction materials; and(j) instrumentation and safety of the dam. The dam site is uniquely attractivefor an arch dam, and for the layout of the project permanent structures. Thelayout of structures including the main arch dam, the downstream lower arch dam,coffer dams, headrace tunnel, surge tank, spillway tunnels, diversion tunnel,penstocks, underground powerhouse, etc., have been carefully studied on the basisof: (i) geological conditions, (ii) rock bedding planes, (iii) comparativeadvantage, and (iv) suitability and ease of access and construction. The Bank'sexperts are in general agreement with proposed layout of structures, and inparticular: (a) all permanent structures (intake structures, headrace tunnel,surge tank, spillway tunnels, penstalks, and underground power house) beinglocated on right abutment, and (b) the powerhouse located downstream along witha long tunnel instead of adjacent to dam, for increased generation and avoidingthe technical concerns of the possibility of left bank slide, and blockage of thetail race. An independent international Panel of Experts (POE) has already beenassociated with the project and the layout of structures has duly been concurredby the POE. All the members of the POE are well known in their fields ofexpertise and they also worked for the Bank financed Sir arch dam (verysuccessfully completed upstream of Berke dam).

Transmission

3.11 The Berke Hydro Power Plant switchyard will be connected to the 154kV gukurova Regional Transmission System, which is connected to 380 kV NationalGrid System. The project includes about 750 km of transmission lines and about1,350 MVA of transformer capacities at VEAS' substations, as well as regionaldispatch center. The attachment to Annex 3.2 gives the breakdown of thesefacilities. This would adequately meet VEAS' requirement up to 2000.

Technical Assistance

3.12 Technical assistance proposed for the project includes:

(a) study of existing regional dispatch center and requirements for theperiod till 2010;

(b) training for VEAS staff in the area of local dispatch; and

(c) special equipment regarding training under (b).

- 25 -

QEAS would prepare and submit to the Bank for a reiLaw (a) terms of referencefor the load dispatch center study; (b) a proposal for t'ie training program andcurriculum vitae of the staff to be involved in training activities; and(c) technical specification and cost estimates for the speeial equipment.

Status of Project Preraration

3.13 Project preparation activities are at an advanced stage. Thefollowing summarizes the status of project preparation:

(a) Project Management: gEAS has already appointed the Project Managerand the essential support staff for the dam and powerhouse.

(b) Engineering and Supervision Consultants: In consultation with theBank, QEAS has appointed the engineering firm of Coyne at Bellier(C&B) on the sole source basis for detailed design of the projectand preparation of main civil works and E&M equipment biddingdocuments, and also to assist SEAS for construction supervision.VEAS has already established the independent international Panel ofExpert (POE) for the dam and powerhouse.

(c) Project Design: C&B has completed the detailed engineering anddesign for the dam and powerhouse. The transmission lines,substations and load dispatch center components of the Project willbe finalized in accordance to the Project implementation timetable.

(d) PreRaratory Works: In order to provide basic infrastructurefacilities at the dam and powerhouse sites, VEAS has already awardedcontracts for:

- access roads, tunnels and bridges- exploratory galleries- diversion tunnel_ camps

- communication system- supply of energy

Most of the access roads, appurtenances and structures and theproposed areas for screening and crushing plants have already beencompleted. The bridges on the upstream and downstream access roadsare also completed. Extensive progress has been made on thediversion tunnel construction on the left bank which is scheduled tobe completed before the award of the main civil works contract. Alltemporary and permanent camps for the engineers and VEAS have beencompleted and offices and other relevant buildings are scheduled tobe completed also before the award of the main civil works contract.In addition, QEAS, in consultation with the Bank, has prequalifiedto joint ventures which participated in pre-bid conference and willbe submitting bids for the main civil works contract.

(e) Land Acquisition: VEAS has agreed to a schedule for landacquisition and the land required for the start-up of the projecthas already been acquired.

(f) Environmental Assessment ReRort (EA) and Resettlement Plan: TheEnvironmental Assessment report and Resettlement Plan have alreadybeen completed and distributed.

- 26 -

C. Proiect Costs and Financing

,Pr2ject Cgst

3.14 A summary of the cost estimates for the Project is given below inTable 3.1 and is detailed In Annex 3.4.

Table 3.1: Project Cost Summary

------nTL BIlin----- ----- UUS$ Mllion------ X ForeignLocal Foreign Total Local Foreign Total Exchang.

A. DERxR HYDRO POWER PROJECT 805.2 613.5 1218.7 204.3 211.2 415.5 51

B. TRANSMISSION NETWORK 112.5 89.1 201.6 38.4 30.4 68.8 44

C. TECHNICAL ASSISTANCE 0.4 2.9 3.3 0.2 1.0 1.2 B9

TOTAL BASE-LInE COSTS 718.1 705.5 1423.6 242.9 242.6 485.5 50

PHYSICAL CONTINGENCIES 72.8 76.5 149.3 24.6 26.1 50.9 51PRICE CONTINGENCIES 3180.7 3818.7 6099.4 25.4 30.3 55.7 54

TOTAL PROJECT COSTS 3971.6 4600.7 8572.3 293.0 299.0 592.1 51

IDC - BANK LOAN 0.0 870.0 870.0 0.0 48.0 48.0 100- OTinR - 447.0 447.0 - 23.2 23.2 100

LESS EXPENDITURES 1989-91 -116.0 0.0 -118.0 -39.6 0.0 -39.6 0

TOTAL FINANCIG RECUIRED 3855.6 5917.7 9773.3 253.5 370.2 623.7 59

The base project cost is in January, 1991 prices as estimated by C&B and VEAS andreviewed by the Bank. The cost estimates do not include import duties and taxesas QEAS will be exempt from such duties and taxes on this project. Although VEASwill pay Value Added Tax (VAT) on the expenditures for the Project, the amountspaid would subsequently be recovered by VEAS and therefore, VAT is not includedin the project cost in Table 3.1. Overall physical contingencies of about 51have been added except for the civil works component for which 15X physicalcontingencies have been included. Similarly, specific allowances of 51 have beenincluded for the hydraulic and electromechanical equipment. The overallcontingencies and specific allowances are considered adequate. An exchange rateof US$1 - 2,933 TL (January 1991) has been used. The relatively lower pricecontingencies is due to the relatively shorter construction period of 41 years(para 3.29). Price escalation contingencies have been calculated on the basisof March 1992 forecasts (EClCO) for domestic and international inflation.

Project Financing PLan

3.15 The financing plan for the Project is summarized in Table 3.2. Thetotal foreign cost of the Project including interest during construction,US$370.2 million, is proposed to be financed by a Bank loan to the Republic ofTurkey on standard country lending terms and Cofinancing (para 4.18). The Bankfunds would be onlent to QEAS under a Subsidiary Loan Agreement on termssatisfactory to the Bank, with CEAS bearlng the foreign exchange and the interestrisk on the Bank loan, as well as an on-lending fee equivalent to 35 basis pointsp.a. to be charged by the Treasury. The Bank Loan would finance: (a) 601 of costof civil works; (b) 1001 of forelgn cost and 1001 local ex-factory cost of supplyof materlal and equipment and 201 of installation costs; and (c) 1001 ofconsultancy services. In view of the considerable foreign exchange cash flowneeds during the construction period of the Project, the loan amount would also

- 27 -

cover the interest during construction of the Bank Loan (para 4.19). The localcosts (US$253.5 million equivalent excluding the investment made during 1989-91),will be financed from internal cash generation and new share capital issues. Theexecution of a Subsidiary Loan Agreement between GOT and SEAS, on terms andconditions satisfactory to the Bank, is set as a condition of effectiveness ofthe proposed Loan.

Table 3.2: Proiect Financing Plan

-US MillionLocal Foreign Total X

Proposed Bank Loan - 270.0 270.0 43Cofinancing a/ - 100.2 100.2 16QEAS b/ 253.5 - 253.5 41

253.5 370.2 623.7 100

a/ IFC/Comercial banks/Supplier credits (see para 4.18).b/ Excludes 1989-91 expenditures of US$39.6 million equivalent: soe Table 4.2 for details.

Retroactive Financing

3.16 In order to maintain the time schedule of the Project, theprocurement process for the main civil works was carried out in conjunction withthe Bank's appraisal and the contract is planned to be awarded by end June 1992,when all preparatory works are expected to be completed. Therefore, retroactivefinancing of about US$20 million would be allowed to cover eligible expendituresand advance payment to the civil works contractor (the foreseen loan signing isJune 1992).

D. Procurement and Disbursement

Procurement Aspects

3.17 All Bank-financed procurement for civil works, and supply andinstallation of material and equipment would be accordir.n to the Bank'sProcurement Guidelines. Hiring of consultant's services would be done accordingto the Bank's Guidelines for the Use of Consultants.

Bank-Financed Procurement

3.18 International Competitive Bidding (ICB) according to the Bank'sprocurement guidelines would be followed for the following, except technicalassistance:

(a) civil works - dam, powerhouse and associated structures (excludingriver diversion tunnel and preparatory works);

(b) hydromechanical equipments;

(c) transmission lines - supply and erection of towers; supply ofconductors, accessories, insulators and hardware;

(d) substations - supply and installation of switchgear equipmentincluding cables and transformers;

- 28 -

(e) load dispatch center - supply of equipment and installation; and

(f) technical assistance - load dispatch center study, special equipmentand training.

It is likely that domestic manufacturers will submit bids against items (b)through (e). In case a contract is awarded to domestic manufacturers, the Bankwould finance the ex-factory amount of the contract. Qualifying domesticmanufacturers will receive preference in bid evaluation of 15X or the prevailingimport duty, whichever is lower. Consultancy services and staff training wouldbe procured according to the Bank guidelines. Details are provided in Annex 3.3.

3.19 International shopping according to the Bank's Guidelines would beused for procurement of certain auxiliary equipment, tools, etc. Procurementfollowing the international shopping method would involve obtaining offers fromat least three suppliers from three different countries - - such procurement beinglimited to US$50,000 per contract and US$300,000 in the aggregate. Directcontracting following the Bank's Procurement Guidelines would be used for specialequipment. Total foreign expenditure under this procedure would be limited toabout US$300,000.

3.20 A Country Procurement Assessment Report has not yet been completed.However, during negotiations, agreements have been reached that for the Bank-financed contracts SEAS will follow the Bank Procurement Guidelines. Bank loanproceeds will not be used for financing contracts procured through LCB.

Non-Bank Financed Procurement

3.21 The Bank would not finance the cost of the preparatory works andsupply and installation of material and equipment procured according to LocalCompetitive bidding procedures for the following: (a) river diversion tunnel;(b) the owners camp; and (c) materials and equipment for transmission lines andsubstations. Local shopping procedures would be used for: (a) miscellaneouscivil works; (b) temporary bridge and site access roads; (c) miscellaneous boringand drilling required for the site investigation; and (d) engineering consultantsfor the engineering and supervision during construction of civil works,transmission lines and substations. These would be financed by QEAS. Land forthe project would be acquired according to the laws of the country. Procurementfor the electromechanic equipment, electrical equipment, general expenditureswill be done according to IFC procedure. Also, it is expected that consultancyservices of C&B would be financed by IFC.

- 29 .

3.22 The procurement arrangements are summarized in Table 3.3.

Table 3.3: Summary of Procurement Arrangements

Use MillionProcurement Method

TotellCe LCB Other N A Coat

A. Berko Hvdro Power Plgnt1. Lend Acquisition 1.5 1.5

2. Preliminary Works 37.6 37.6

3. Civil Works 313.4 313.4(164.0) (164.0)

4. HydromeohanLeal Equipment 44 3 44.3(21.6) (21.6)

S. Electromeohanical Equipment 49.8 40.8

S. Electrical Equipments 20.5 20.5

7. Engineoring end Consulting 13.0 13.0

6. General ExpeandLture. 31.1 31.1

S. Rlated T 6 D 8 vtmn1. Tronmission Lines 11.6 25.9 37.5

(11.6) (11.6)

2. Substations 9.2 15.7 24.9(9.2) (9.2)

3. Load Dispatch Center 17.3 17.3(14.4) (14.4)

C. Technical As1istance1. Dispatch Center Study 0.5 0.5

(0.5) (0.5)

2. Special Equipment 0.3 0.3(0.3) (0.3)

3. staft Training 0.4 0.4(0.4) (0.4)

D. Interest during Construction 71.2 71.2(48.0) (48.0)

TOTML 466.1 79.2 14.2 103.8 663.3

Tbe Dank (220.8) (1.2 _(48.0) 270.0)1

Disbursement AsRects

3.23 The proceeds of the loan would be disbursed over six years (1992-1997) on the following basis:

(a) 60X of the total costs of the civil works;

(b) 10OZ of the foreign cost and 1001 of local ex-factory cost of supplyof electromechanical, powerhouse and switchyard equipment,hydromechanical equipment and supply of material and equipment forthe transmission lises and substations, and 20X of installationcosts;

(c) 100l of the foreign cost of training for QEAS staff; and

- 30

(d) lOOX of consultancy services.

SRecial Account

3.24 The disbursement schedule (Annex 3.5) follows the Bank's standarddisbursement profile for the region's power projects. A special account for QEASwith initial deposits of US$15 million will be established at a commercial bankor with the Central Bank on terms and conditions satisfactory to the Bank. TheBank would also permit the use of statements of expenditure on contracts valuedat US$200,000 or less to assist VEAS in making timely payments to thecontractors. QEAS would retain the supporting documents and make them availablefor inspection by Bank supervision missions and by external auditors. Except incases of direct payments, no reimbursement applications for less than US$200,000would be accepted. An audit of the special account would be carried out byindependent auditors and the audit report would be submitted to the Bank withinnine months after the end of the fiscal year. In addition to the audit of theSpecial Account by the Central Bank's audit department as required by TurkishLaw, the private auditors who would be contracted to audit VEAS' annual accounts(para 2.28), would prepare a special report to include a statement verifying theamounts disbursed against the SOEs. The Loan Closing Date would be December 31,1997.

E. Project Implementation Aspects

Engineering Consultants

3.25 Based on a contract with QEAS signed in July 1990, C&B is responsiblefor: (i) preparation of the bid documents; (ii) assisting QEAS in examination andevaluation of the bids received; and (iii) inspection of equipment duringmanufacture; and (iv) providing advice to QEAS' project team on engineering andteclnical supervision during construction and commissioning. C&B has completedthe detailed design of the project. Assurances would be obtained that CEAS wouldcontinue to employ C&B engineering consultants throughout the period ofconstruction and commissioning. This contract is proposed to be financed fromIFC or VEAS' own resources.

Organization and Management

3.26 CEAS has already appointed the Project Manager and the essentialsupport staff at its headquarters. In addition, VEAS would also have a siteorganization consisting of a chief site engineer assisted by civil, electrical,mechanical engineers and surveyors. The QEAS project team would be assisted bythe engineering consultants in inspection of the equipment during manufacture andin supervision of the dam and the powerhouse during construction andcommissioning. CEAS would establish a laboratory at site for testing of thecivil construction materials, an essential requirement for the quality controlduring construction of the thin arch concrete dams.

3.27 Implementation of transmission lines, substations and technicalassistance would be the responsibility of CEAS Project Planning and ConstructionDivisions. QEAS has ample experience in procuring materials and equipment forits subtransmission lines and substations. It also has adequate experience inengineering and supervlsion during construction and commissioning fortransmission facilities. However, considering the extent of the work involved,it proposes to appoint engineering consultants for the load dispatch center studyand transmission and subtransmission lines according to the Bank's Guidelines.

- 31

Implementation Schedules and Project CompIetion Date

3.28 The construction schedule for the Project (shown by major bidpackages in Annex 3.6) foresees project completion by the end of 1996. Theactivities connected with transmission lines and substations would be coordinatedto enable power generated at the Berke Dam to be effectively utilized by the loadcenters in the QEAS service area. QEAS, therefore, reasonably expects theproject to be commissioned in last quarter of 1996. However, on the basis of theexperience reflected in the Bank's disbursement profile of power projects, thedisbursement could be expected to complete about a year later. The loan closingdate, therefore, would be December 31, 1997. A 4h year construction scheduleappears quite realistic based on the following factors: (a) easy access to damsite from highway; (b) completion of the primary access road to dam site andother preparatory works (including the upstream and downstream bridges) inadvance; and (c) completion of the diversion tunnel before the award of the maincivil works contract.

Progress Reports

3.29 To monitor the progress of the Project and permit its evaluation oncompletion, QEAS would maintain records on the matters shown in the ProjectMonitoring Guidelines in Annex 3.8 and submit a quarterly progress report to theBank. On completion of the Project, VEAS would prepare a project completionreport.

DeveloRment of Ceyhan River Basin and Uater Manag:ement

3.30 The proposed Berke dam and power plant would be built on the Ceyhanriver on which other dams and power houses already exist. The upstream Menzeletand the downstream Aslantas dam are multi-purpose projects including floodcontrol, water supply, irrigation and power generation. The dams are operatedby DSI while the power plants are operated by TEK. The Sir dam and power house,situated midstream between Menzelet and Aslantas, are exclusively for powergeneration and operated by CEAS, as would be the proposed Berke dam and powerhouse (which would be downstream of Sir). The management and distribution ofwater resources in Turkey is administered by the General Directorate of StateHydraulic Works (DSI) under the Ministry of Public Works and Settlements.Prir.rities for water use have been established, in order of decreasing importanceas follows: flood control, potable water supplies, irrigation and hydropower.This ranking reflects the importance of irrigated agriculture in Turkey's long-term development plans. A water resources development master plan wascommissioned by DSI for the Ceyhan, Seyhan, Berdan, Develi and Amik Basins andwas completed in 1966 (IECO, 1966). This document proposed a series ofirrigation and hydropower projects in the Ceyhan River Basin, many of which havebeen completed or are in the process of construction. Although the timing andsome of the details of this original master plan have changed over the years, thebasic development plan has been followed to a large degree. The volume of waterdiverted from the river for agricultural purposes will increase by four times bythe year 2023, with the largest volume diverted to the Amik Plains irrigationproject. The project involves the irrigation of 105,434 ha and will require anannual water withdrawal of 658 Mm3 from the Menzelet reservoir, which is locatedupstream of the Sir Hydro Power Project.

3.31 The Berke dam and powerhouse has been designed based on confirmeddata by DSI on water flows and developmental plans for the Ceyhan river basin.Accordingly, the generation from the proposed Project is estimated to be anannual average of 1,660 GWh from 1997 decreasing gradually due to upstream

- 32

development, and stabilizing at 1,100 GWh/year after 2023, the year when theupstream development is planned to be completed. In order to ensure viabilityof the Project, confirmation from DSI of the assumptions on planned upstreamdevelopment for the Ceyhan river basin on which the design and feasibility of theproposed Project is based has been received. The Bank's review indicates thatsome of the upstream irrigation projects are substantially behind schedule andthat accelerated development of these projects would not be detrimental to theexpected generation from the proposed Project.

3.32 The current practices in water management are not codified, but arebased on bilateral interactions between the parties involved. Since the Ceyhanriver water system presents a rather unique pattern of water sharing acrossdifferent users and purposes, no existing arrangements can be replicated tooptimize the Ceyhan river's water uses. Accordingly, a detailed study examiningthe optimal utilization of water across all the parties involved (namely DSI,gEAS and MENR), with the active participation of DSI and gEAS would be carriedout. The study will also focus on rules and regulations to be adopted forsharing of water, especially under extreme circumstances and will be financed bya Japan Grant Facility (JGF) arranged by the Bank. It is expected that the studywill be completed by Tuly 1993.

Land Acguisition and Resettlement

3.33 The law and procedures relating to resettlement have been reviewedand are considered to contain adequate provisions to protect the rights of thepopulation to be resettled. Land needed for public purposes may be acquiredcompulsorily in Turkey in accordance with the Expropriation Law of 1983. Thisis a three-step procedure. Firstly, the Project agency offers to purchase theland from the landowner through normal negotiations for the sale and purchase ofland. In the event the landowner does not wish to sell, a notice is filed forcompulsory acquisition in the public interest pursuant to the 1983 ExpropriationLaw. Under the Law, a permanent committee in each province- -consisting of localrepresentatives, land experts and members of the administration--determines thevalue of land in such cases. Land valueq are determined at market value. In theevent there is disagreement, the third s:ep is to take the matter to the courts.There are, in addition, procedures for resettlement of displaced populations.Landowners are given the option either to be resettled or to take cashcompensation. Usually, it is the Resettlement Department of the Ministry ofAgriculture, Forestry and Rural Affairs (MAFRA) that makes available other landfor displaced populations. The cost of resettlement is borne by the projectagency. Current resettlement procedures specify that dam construction andresettlement should be carried out in a coordinated manner and that priorityshould be given to the resettlement of people whose land would be submerged dueto dam construction.

3.34 The Berke Dam reservoir covers about 7.8 km2 of surface area andwould affect four settlements having 144 inhabitants in 18 houses which aremostly built with sun-dried bricks, stones and briquettes, and 23 otherbuildings. The farms in the reservoir area consist of small scattered pieces ofland and their produce is mostly for their own consumption. About 60 hectaresof land that is cultivated will be submerged under the reservoir. gEAS wouldacquire the necessary land in accordance with the resettlement plan (paras 3.37and 3.40).

3.35 The above figures appear to be extremely low compared to those forcomparable schemes: Table 3.4 provides the results of the calculation of arating equal to the number of people displaced from a dam reservoir area in order

- 33

to produce one GWh per year. This shows a ratio 80 times lower at Berke than atSir, 1,500 times lower than for the Nangbeto scheme in Togo, which wascommissioned in 1989.

Table 3.4: Ratio of the Number of People Displaced/AnnualPower Production for a Few Purelv Hdrolectrc Dom

Date of Annual Ratio PeopleComission- Pow r Displacod/

in& Production People Annual Pow.r(GWh) Displaced Production

(OWh -1)

Berke 1996 1669 144 0.087

Vouglans 1968 230 150 0.65(France)

Lokka and 1970 412 56 01.4Porttipahta (1)(Finland)

Sir 1991 725 3010 (2) 4.2(Turkey)

Adjarala 1996 270 7301 27(Togo/Benin)(3)

Nangbeto 1989 150 12000 (4) 80(Toto)

(1) Source: CIGB, 1988.(2) Source: Yenicrioglu and Kaya, 1987, Table 1.(3) Source: Adjarala dam and BPP. Environmental Assessment, in progress. Coyne et Bellier(4) Source: Direction due Project Ranabeto, 1988.

3.36 After the Ministry of Energy and Natural Resources declared theproject of public interest in a letter of July 3, 1989, gukurova Elektrik A.S.asked the Kahramanmaras Regional Directorate for Rural Services, who are legallyin charge of resettlement, to ask the families living in the homes within thelimits of the future reservoir if they wished to be resettled or not. Allfamilies have opted for compensation. A resettlement plan prepared by gEAS hasbeen reviewed by the Bank.

3.37 The Kalender cemetery is located within the limits of the futurereservoir. The Department of Religious Affairs of the Governorate ofKahramanmaras, consulted in 1986 with respect to the cemeteries that were todisappear under Sir reservoir, responded that the cemeteries could remain underwater, or could be relocated, but only as a whole. The Imam of Muratli issuedthe same opinion about the Kalender cemetery. VEAS will relocate the Kalendercemetery, and/or build a new one, if so desired by the populations.

3.38 An important thermal source, the Ilica hot spring, is located 1.8 kmdownstream of the site. The Ilica thermal installations have already been closedfor a season to allow for the preparatory work for the construction of the damto be carried out. SEAS therefore rented the installations for the season inorder to close them. The municipality of Duzici received complaints from Ilica'spatrons. The thermal baths will have to be closed again during the period ofexcavation of the outlet structures (4-15 months or. the construction schedule)and'during the period of construction of these structures (25-39 months on theconstruction schedule).

3.39 According to the municipality of Duzici, the economic impact of atemporary shut-down of the thermal baths is limited. Patrons will be redirected

- 34 -

towards the hot springs of Ciftehan, which is located 110 km to the northwest ofAdana. Appropriate agreements have been obtained from GOT and QEAS to ensurethat resettlement is carried out in a manner satisfactory to the Bank.

F. Environmental AsRects

3.40 Coyne and Bellier, Paris, conducted a study of the environmentalimpact of the Berke dam. The draft report has been submitted to the Bank andreviewed by the Environment Department. The comments have been incorporated intothe final report. The report elaborates the following impact:

Physical Environment

3.41 The possibility of leakage from the reservoir to the low-lying SabunSuyu and Andirin River valleys was discounted due to the presence of geologic andhydrologic barriers between the reservoir and these valleys. Leakage within theCeyhan River valley itself is precluded by the presence of impermeable geologicstrata complemented by grout curtains. In evaluating the ability of the dam towithstand earthquakes, two alternative methodologies were used: a probalisticapproach (Cornell-McGuire) and a deterministic approach (ICOLD). The results ofthe two analyses were in close agreement, and led to a peak soil acceleration of190 cm/s2 for the Basic Design Earthquake, and 300 cm/s2 for the Maximum probableEarthquake. An independent review of dam safety was provided by the members ofQEAS' Panel of International Experts. Impacts of a catastrophic failure of theBerke dam were evaluated on the Aslantas dam, Kayraktepe Aslantas National Parkand on dwellings located near the reservoir. Temporary overtopping is theprimary risk for the Aslantas dam. The likelihood of overtopping depends on thewater level in the Aslantas reservoir at the time of rupture and the speed withwhich the spillway gates at Aslantas can be opened. Reactivation of the landslidelocated immediately downstream of the dam would have no serious consequences onthe Project. The sedimentation rate for the Berke reservoir was calculated atthe low figure of 180,000 m* per year. Because of the relatively small size andgreat depth of the Berke reservoir, the volume of water lost from the riversystem due to evaporation is relatively low (0.21 of the total annual flow).Impounding should have no impact on the Ilica thermal springs, since it is notconnected to the ground-water system in the vicinity of the proposed reservoir.The project is included as a component of the Ceyhan River Master Plan.

Biological Environment

3.42 Construction of the dam will result in the inundation of a 7.8 km2

area, which include pine and oak forest, mediterranean macchia formation, andlittle agricultural land. Additional areas of vegetation will be disturbed atthe construction sites for the dam, access roads, power house, etc. As none ofthe endemic species identified in the area are restricted to elevation of lessthan the 345 m maximum rese,voir elevation, none of them will undergo the totalloss of their habitat. A Land Cover Management Plan will be developed andimplemented for the intermediate watershed. Objectives of the Plan include themaintenance of existing vegetation communities for the purpose of Biologicaldiversification. Microclimatic changes in the immediate vicinity of thereservoir will enhance plant growth. The inundation and disturbance of thevegetative commun..ties described above will result in the displacement ofassociated fauna. If reservoir filling takes place in the winter, dormantspecies may be drowned. Although the creation of the reservoir may disturb themigration routes of some mammals, it may create new habitat types for waterdependent species.

- 35 -

Socio-economic Envlironment

3.43 Only 144 persons live within the limits of the future reservoir. Ifthey so desire, they will be resettled by the Ministry of Agriculture and RuralAffairs. The reservoir location and the fast regression of malaria in theprovince of Adana make it likely that the impoundment will not favor water-bornediseases. The implementation of actions identified in the EnvironmentalAssessment will prevent the region from becoming a new malaria focus. The Ilicathermal springs which are located near the site will have to be closed duringpart of the construction period, and will be renovated by the Province of Adanaand QEAS. Some footpaths and mule passages across the Ceyhan River will be cutby the creation of the reservoir. Communication will be reestablished by meansof a boat service. CEAS has already rehabilitated the road which leads to theCeyhan from the future Adana-Gaziantep freeway, and has built a permanent bridgeover the river. This construction will provide a new way to travel betweenDuzici and Andirin when the link is completed north of the river to Andirin.This will bring the latter closer to markets and will have a considerablepositive impact on the economy of the region. The provision of additionalcommunity facilities and services is not necessary to accommodate constructionand operation employees or relocatees becas e constructionl employees will behoused in self-contained camps, total operation employment is small (150employees) and relocation impacts a total of 144 people, who will take up nowresidence in six different locations.

Mitigation and Monitoring Plans

3.44 CEAS will accomplish the activities summarized in the tables givenas Annex 3 and coordinate the activities of the other implementing groups. Thereport states that the overall long-term environmental impact is positive.Appropriate agreements have been obtained from GOT and gEAS to ensure that themitigation and monitoring measures are carried out in a manner satisfactory tothe Bank.

Transmission Lines Environmental Review

3.45 A transmission line environmental review (ER) (Category 'B') wouldbe carried out by consultants under TOR satisfactory to the Bank. The ER wouldbe financed from the Japan Grant Facility arranged by the Bank for that purpose.gEAS has agreed to complete the ER for transmission lines by December 31, 1992,and implement the recommended measures to mitigate environmental impact in amanner satisfactory to the Bank.

G. Dam Safety Aspects

3.46 In accordance with the Bank guidelines for safety of dams (OMS 3.80,1977), the project provides for the following specific safety measures to ensuresafety of the proposed Berke dam:

ZngLnugX1u

3.47 Coyne et Bellier (C&B), a well known engineering firm with extensiveexperience in arch dAms, has been engaged by gEAS for detailed designs of theproject and preparation of contract documents and also to assist QEAS forconstruction supervision.

- 36 -

International Panel of Experts

3.48 An independent Panel of International Experts has already beenestablished to carry out a comprehensive review of the designs and/or completedworks of the dam and related structures with the objective of advising andascertaining on the safety of the dam and the appurtenant structures, withdetailed consideration of the structural, geologic, hydraulic, soil mechanics andthe seismic aspects. The Panel comprises of four well known experts (acceptableto the Bank) with relevant expertise in dam engineering (including engineeringgeology, rock mechanics, dam design, tunnelling and dam construction). The Panelwould meet often enough for it to guide and advise in time on the designs,construction and the safety aspects of the dam. QEAS will keep the Bank informedabout the schedule of the Panel meetings and submit copy of each panel report tothe Bank. Bank will participate in the panel meetings as and when convenient.

Instrumentation

3.49 Extensive instrumentation (including pendulums, extensometers, jointmeasurement devices and seismographs) is proposed to be installed at Berke damfor dam safety monitoring. The same will be further reviewed by the panel andthe Bank experts for its adequacy when instrumentation design are finalizedduring construction and additional instrumentation will be incorporated (ifconsidered essential). The proposed instrumentation would provide handy toolsfor studying the behavior of the dam and foundations after construction and fortimely requisite protective measures to control undesirable developments oremergency conditions.

Dam Safety Insgections during Operation

3.50 DSI conducts regular inspections of all dams in the country andgenerally follows the practices of the US Bureau of Reclamation in this respect.Annual dam safety inspections are conducted by the DSI's Regional Division inwhose territory the dam is located. VEAS has confirmed the details of thearrangement with DSI for inspection of the dam during operation. The dam safetyinspections by DSI as an independent agency would be acceptable to the Bank.

3.51 All works completed under the project including the dam, powerhouse,allied structures, mechanical and electrical equipment, residential quarters, andaccess roads and bridges would be maintained by VEAS. Assurances have beenobtained from QEAS that all the structures and other works constructed under theproject would be maintained by QEAS in accordance with sound engineeringpractices.

H. Benefits and Risks

3.52 The measurable benefits attributable to the proposed Project includeincremental generation of electricity along the least-cost path with no claimson GOT's budget for the domestic financing of the project. An additionalimportant benefit is the demonstration effect expected to derive from the successof the expansion of VEAS's scope of activities, effectively cooperating with TEKand DSI in Turkey's power subsector. The main risks envisaged are thepossibility of construction delays derived from construction site conditions aswell as the size of the project. This risk is substantially reduced since QEAShas appointed consultants of proven competence, to assist in design andengineering as well as implementation,

- 37 -

IV. FINANCIAL ASPECTS

A. Introduction

4.01 The financial affairs of VEAS are governed by the Turkish CommercialCode, the Capital Markets Law and the Capital Markets Board (SPK). Theaccounting system and the related policies are stipulated by the TurkishCommercial Code, while the financial market operations are regulated by the SPK.Further, QEAS' dividend policy is geared to the statutory stipulation set by SPK.Despite constrained autonomy (para 2.06;, QEAS is an efficiently managed utilitythat has a long history of consistent profitability. This is well demonstratedby the wide holding of SEAS' shares and its market standing. An analysis ofQEAS' past performance is presented in the context of its limited autonomy. Theactions and measures proposed to address the issues of pricing and watermanagement, dividend policy and financing plan, as well as proposal formonitoring VEAS' financial performance are discussed in this chapter. Further,aspects related to the possible transfer of TEK's distribution operations in theregion to QEAS and proposal to address possible implications of theimplementation of the proposed Project are also discussed.

4.02 VEAS has received five loans/credits from the Bank Group since 1963.The last loan (Ln.2750-TU) was made in 1985 for the recently completed SirHydropower Project. Because of the restrictions placed on VEAS' investments, duein part to the creation of TEK in 1970, there was no new lending to CEAS from1972 to 1985. Among other things, VEAS agreed under the Sir Hydropower Projectto maintain a minimum debt service coverage ratio of 1.5. QEAS has complied withall the covenants under the loan and its performance has been satisfactory.

B. Past Performance and Present Condition

4.03 Detailed historical financial statements are presented in Annex4.1 and a summary of its operational and financial performance for the period1986-91 is provided in Table 4.1. The financial data and the analyses arepresented in current US Dollar equivalent in order to remove the effects of highinflation in Turkey, which averaged 56X per year during the 1986-91 period basedon the wholesale price index. Further, the income from financial investments isexcluded from the analysis in order to assess the profitability of the utilityoperations of the company.

4.04 The installed generation capacity of QEAS remained at 298 MW through1990 when it almost doubled to 581 MW in 1991 on account of the completion of theSir dam and power plants. The generation from QEAS owned power plants increasedup to 1988, but decreased sharply over the 1989-91 period due to the poorhydrological condition during the latter period as well as the shut-down of threeunits of the old thermal plant at Mersin. Further, the additional capacity fromthe Sir plants has not been entirely available to QEAS in 1991 because of theprogressive commissioning of the three units (3 x 100 NW). The demand forelectricity in the region was met from energy purchased from TEK, which increasedfrom 2148 GWh in 1986 to 3179 GWh in 1991 and is estimated to be 2740 GWh for1992. The generation from QEAS' hydro plants is expected to improve further inthe current year.

- 38 -

Table 4.1: CEAS' Past Performance Indicators. 1986-91

Prov.1986 ,mi87 im 19 9

Installed Capacity (NW) 298 298 298 298 298 S81Generation (GWh) 1274 1413 1454 1034 1058 1154

Total Sales (GWh) 3247 3409 3421 3673 3959 4047Bulk Purchase from TEK (GWh) 2148 2167 2158 2872 3136 3179of which sold to TEK DE (Glh) 989 1100 1222 1328 1472 1781

Total System Loases (1) 5.1 4.8 5.3 6.1 5.6 6.5Average Revenue (Cents/kWh) 5.23 5.38 5.07 5.07 6.01 5.91

Not Sales Revenue (USS M) 170 183 173 186 238 239Operating Costa (USS M) 114 118 114 148 194 183of which : Purchased Power (US$M) 74 84 87 108 143 137EBIT (USS M) 1/ 2/ 52 48 46 32 37 53

Non-Operating Income (US$ M) 27 28 34 40 17 5Not Income CUS8 M) 2/ 23 24 29 31 35 51

Ave.1et Fized Assets in Opn.(USS 3) 13 12 9 11 18 101

Total Assets (USS M) *37 170 179 242 297 286Total Equity CUSS M) 3/ 69 88 91 128 122 121Total Capital Employed (USS M) 80 109 133 175 230 250

Operating Ratio (C) 67 65 S6 79 82 77Not Income/Not Sales tS) 13 13 17 17 15 21Net Income/Average Equity (Z) 38 30 33 28 28 42Net Income/Capital Employed (X) 4/ 29 28 26 21 18 22Current Ratio 2.3 2.7 2.9 3.0 1.9 2.0Debt-Service Cover Ratio (DSCR) (times) 11.4 11.0 9.3 10.6 7.8 3.7DScR net of Dividends 11.0 10.6 7.1 7.1 2.4 2.6

Accounts Receivable (days) 49 49 51 46 43 50LT Debt to Total Capitalization (1) 24 30 35 39 51 52

Exch.Rate (TL/) - Average 5/ 675 857 1422 2120 2609 4166- End of Year 5/ 758 1021 1815 2314 2930 5080

I/ : arnings Before interest and lazes net of foreign exchange losses.2/ : Ezcluding income from non-utility operations.3/ : Excluding Reserve for Employee Trmination Benefits (ETB).4/ : Adjusted for Interest Charges.5/ : Rounded (Source : IFS - actual ;IBR - 1991 eatLmate).

4.05 The overalloperating and financial CEAS- OPERATIONS, 1986 - 1991performance of QEAS over the so1986 - 91 period is satisfactory. However, itsperformance varied 70 considerably year-to-year asindicated by the trend of net s

income to sales ratio, return 9oon equity and return oncapital employed shown inFigure 4.1. This is because 00-,the utility's profitabilityis, in large part, not under a.0

its control. While the use Iof water for generation from . X .u, *; .. ,its predominantly hydroplants (82X of installed .W , N * m £

capacity) is dependent on Figure 4.1prevailing hydrologicalconditions, the electricityprices are set by TEK/MENR, including the prices at which TEK sells in bulk toVEAS. As such, VEAS has little control, if any, on its power purchase cost,

- 39 -

which is the single largest operating cost for the utility. Although the powerpurchase cost is a pass-through (para 4.14), the linkage of such prices withTEK's own tariffs which eroded substantially in real terms during the 1987-89period has resulted in considerable variations in CEAS' earnings. The investmentincentives received on the Sir project for tax purposes and the tariff increases- particularly the monthly adjustments since April 19908/ - helped CEAS maintainthe level of net income in Dollar terms.

4.06 CEAS' average AVERAGE COSTS AND REVENUES t 1086 - 1991

costs of generation andpurchased power compared with 7 _E_ _ _ _ _ Pon _ _

its average revenues over the1986-91 period are shown in . .....e. .*.................................... ...................

Figure 4.2, and the detailsare included in Annex 4.2. o ._ == __ .-. _ .The costs are adjusted fortransmission losses allocated . ................ ...

proportionally to the .generation and purchasedenergy. The generation cost ..... .sharply increased from thelow of about US. ¢ 2 per kWh . ... .......................

in 1988 to over US Cents 5per kWh in 1989 due to a 29X . am a. a am

decrease in generation from1454 GWh in 1988 to 1034 GWh -nw + 40-PImouCin 1989. The production from Figure 4.2the Sir power plants, whichreached 503 GWh compared to392 GWh expected in 1991, contributed to reversing the adverse trend ingeneration costs and would help reduce the generation costs beginning 1992. Itspredominantly hydro capacity has thus contributed to significant variations inCEAS' cash flows and profitability. As regards power purchase cost, the stablemargins providod incentive to QEAS to reduce transmission losses and reducecosts.

4.07 Recognizing its limited role in controlling profitability throughtariffs and power purchases, VEAS has managed efficiently all areas of operationsthat are under its control. QEAS completed the construction of the Sir dam andpower plants on originally planned schedule in spite of delays of about a yearin the initial phase of the project due to changes in the final design warrantedby safety aspects related to spill ways. This provided VEAS the needed self-generation capacity without delay. Further, QEAS adopted good operations andmaintenance practices (para 2.15) ensuring plant availability and reasonabletransmission losses, thereby keeping its costs of operation competitive.

4.08 QEAS managed its surplus cash prudently by investing in marketablesecurities, including Government securities, and realized attractive returns,more than compensating for the high inflation. The substantial cash and cashbased assets helped finance a part of the peaking investments of the Sir project

8 Monthly adjustment of electricity tariffs was instituted for the firsttime in Turkey in April 1990 to prevent further erosion of electricity tariffsin real terms in the context of the financial restructuring of TEK as well asof the launching of reforms for the subsector. The monthly adjustment ofelectricity tariffs has since remained in effect.

40 -

and the requirements in 1990-91 of the initial expenditures in local currency forthe proposed Project. The current ratio, therefore, fell from 3.0 in 1989 to astill very satisfactory 1.9 in 1990 and slightly improved to 2.0 in 1991.

4.09 QEAS has exercised cautious cash management practices and ensuredtimely collections from customers. gEAS has no major customers in arrears. Theoverall accounts receivable is less than seven weeks of sales and receivablesover three months old amount to less than 2X of total sales in 1990. This hasbeen facilitated by the fact that QEAS sells energy in bulk to its customers inthe region and that its payments to TEK for energy purchases are offset againstreceipts from it for energy sold to TEK's DEs, the largest customer.

4.10 As regards financing of its power infrastructure, VEAS has been ableto obtain equity capital from the market and long-term loans in foreign currencyfrom the Bank Group (para 4.02). gEAS is conservatively capitalized and its debtto equity ratio at end 1990 was 49/51 on unrevalued assets and 42/58 when equityis restated to reflect asset revaluatioi. (para 2.27). The issuing of new equityof TL 150 billion (US$36 million equivalent) in 1991 has helped gEAS meetinvestment requirements and maintain a balanced capital structure. The debtservice cover has been more than adequate given that QEAS did not contract anynew debt in the late 1970s and early 1980s and that all of its long-term debtoutstanding since 1985 are the Bank loans.

4.11 With the regional demand for electricity projected to grow at anannual rate of 6.9% during the decade, the Sir project has provided SEAS thescope to increase its own generation and correspondingly reduce its dependenceon TEK. The Sir project (about US$240 million equivalent) also increased itsdebt outstanding five times over the 1986-90 period and necessitated new equityissues to finance the Project. The proposed Project (which is estimated to costabout US$667 million including financing costs), while increasing SEAS' selfgeneration pool by adding another 510 MW, would also increase its indebtednessto about US$377 million equivalent by January 1997, the year of its expectedcommissioning. It would also necessitate new equity issues during projectconstruction. The utility is well placed to undertake the Project and in orderto ensure the predictability of QEAS' earnings and its financial viability,satisfactory agreements have been obtained from GOT regarding tariff policyapplicable to gEAS (para 4.15).

C. Tariff Agreements

4.12 The GOT and TEK agreed with the Bank in 1991 under the TEKRestructuring Project (Ln. 3345-TU) to implement, beginning January 1, 1993, arevised Tariff Policy acceptable to the Bank along with other reforms aimedtowards financial restructuring of TEK. The principles of the new tariff policyare to increase and sustain the self-financing capability of TEK in accordancewith certain financial performance criteria and to establish a tariff structuredictated by the economic costs of electricity supply. Specifically, theagreements reached are that the new tariffs would:

(a) reflect the power system's long run marginal costs of supply,9/which would in turn be based on the agreed least-cost investment

9 The system's LRMC, based on the mission's estimates using the agreedleast-cost investment program, is US.; 5.75/kWh in 1989 prices which isequivalent to US.0 6.40/kWh for 1992 in current prices.

- 41 -

program for expansion of the power subsector; and

(b) enable TEK (i) to achieve a minimum debt-service cover of 1.5 from1993 onwards ; and (ii) to generate from its operations, fundsequivalent to not less than 25X of its investments10 / in 1993, 30Zin 1994 and 35X each year thereafter.

Until the implementation of the revised tariff policy, the agreed interimarrangement for tariffs is for TEK to adjust electricity tariffs monthly orquarterly so as to maintain the average revenue for TEK at no less than US.06/kWh, measured on an annual average basis. This agreement with the Bank is nowin effect and TEK's tariffs are being adjusted monthly since April 1990. TEK'saverage revenue for 1991, the first year of the agreement, reached TL 251/kWh(US.¢ 6.02/kWh at TL 4166/US$ average for 1991). TEK's average revenue isexpected to reach TL 449/kWh in 1992, which is equivalent to US.0 6.33/kWh basedon projected average exchange rate of TL 7C90/US$.

D. Proposed Tariff Policy and Implications for CEAS

Energy Exchange Price with TEK

4.13 TEK and QEAS exchange (sell and buy) energy in bulk at the 380, 154and 33 kV levels depending on the system iznterconnection. QEAS buys from TEK atits interconnection with TEK at substations Erzin (380 kV) and Toroslar (154 kV).Due to system considerations, VEAS sells energy to TEK in small amounts at thesesubstations. For supply to the DEs, QEAS sells to TEK at the 33 kV substations.The price at which TEK buys from QEAS at the 33 kV level for supply to its DEsis set at 80X of applicable tariffs to industrial and other bulk customers atthat voltage level whereas the price at which TEK sells to or buys from VEAS atthe 380/154 kV level ("Exchange Price") 11/ is set according to the establishedbase-level of TL 32.35/kWh (February 1987 base) as per the Power ExchangeAgreement (para 2.19). Rate increases to electricity tariffs since the date ofthe Power Exchange Agreement have been applied to the respective bases.

4.14 The effective tariffs for January 1992 are TL 276/kWh for TEK's salesto QEAS and TL 318/kWh for QEAS' sales to TEK's DEs, which are equivalent toUS.0 5.11/kWh and 5.88/kWh respectively (current prices). Based on the monthlyincreases planned by TEK to reach the target level of TL 449/kWh for 1992(para 4.11), these tariffs are expected to reach TL 336.75/kWh and TL 381.65/kWhon annualized average basis, which are equivalent respectively to US.r 4.75/kWhand 5.39/kWh1 Z/ for 1992 using forecast average exchange rates for the year.Thus, although the prices provide a reasonable margin to QEAS, and are expectedto reach near parity with the system's LRMC, they are not set on any rationalbasis. The exchange price should: (i) be based on the economic costs of supply

10 The investments refer to the average of three-year investments,namely, the actual for the previous year, the budgeted for the current and theplanned for the next year in order co smoothen the typically large variationsin year to year investments of power subsector.

11 The "Exchange Price", on average, represents about 751 of TEK'saverage revenue.

12 These levels would represent about 931 and 951 respectively of thesystem's LRMC in current terms, based on the mission's estimates using theagreed least-cost investment program.

- 42 -

at the relevant voltage levels; (ii) be in line with the overall structure oftariffs; and (iii) allow both TEK and QEAS to achieve appropriate performancecriteria. The new tariff policy would be based on such principles.

Implications for CEAS

4.15 The new tariff policy to be implemented from January 1, 1993, settingtariffs on the basis of the LRMC of suppl.y at the relevant voltage levels would:(i) remove any arbitrariness in pricing; and (ii) enable the determination of theefficiency and/or inefficiency of the DEs. Since QEAS' generation pool ispredominantly hydrobased (83%, para 2.06) while TEK's is only 43% hydrobased itsoperating costs are lower than TEK's; therefore the revised tariff levels set toallow TEK to achieve the agreed financial performance criteria would allow QEASto exceed similar performance criteria. Financial projections for SEAS, basedon the agreed minimum of US. C. 6.0/kWh for TEK's average revenue (nominal terms),indicates that VEAS would be financially viable and able to generate sufficientfunds from its operations for the project (paras 4.24-4.26). Further, beforeimplementation, the new tariff policy would have to be reviewed and agreed by theBank under the TEK Restructuring Project. However, pending the implementationof a new tariff policy satisfactory to the Bank, in order to provide the neededcomfort to private cofinanciers (para 4.18), GOT agreed to: (a) maintain theprevailing tariff setting system and continue to establish electricity prices asagreed under the TEK Restructuring Loan; and (b) ensure that electricity pricesincluding the exchange prices between TEK and VEAS under the new tariff policywould not adversely affect the financial condition of QEAS.

E. Investments and Financing

4.16 The detailed investment program and financing of VEAS for the period1992-96 including the annual phasing of the same is provided in Annex 4.3 andsummarized in Table 4.2.

Table 4.2: CEAS Investments and Financing. 1992-96(In current prices) 1/

--------TL billon ------- -----US$ million-------Local Foreign TotaL Local Foreian Total 1

RegnirementsProposed Project 3,856 4,601 8,457 253.5 299.0 552.5 87

Other Investments 126 0 126 8.2 0 6.2 1Interest During Const. 0 1 317 1 317 0 71.2 .71 2 _I2

Total Requirements 3 U 5.918 9.900 261 7 3 631.9 100

SourcesGross Casb Generation 2/ 9,174 0 9,174 609.9 0 609.9

Less Debt Service 1 54 0 1 7 lL8 0 115 8Funds from Operations 7,420 0 7,420 494.1 0 494.1

Less Dividends 2.454 0 2,454 153.6 0 153.6Net Cash Generation (NCG) 4,966 0 4,966 340.5 0 340.5NCG Applied to Project 3,476 0 3,476 238.3 0 238.3 38Customer Contributions 367 0 367 27.1 0 27.1 4

Equity 1,200 0 1,200 83.5 0 83.5 13Proposed Bank Loan 3/ 0 4,290 4,290 0.0 270.0 270.0 43

Cofinancinng 4/ 0 1,628 1.628 0.0 100.2 100.2 16Financing Surplus 5/ (1.062) 0 (1t062) (87.1) 0 (87.1) (14)

Total Sources 3.982 5.918 9.900 261.7 370.2 631.9 10

1/ : Using forecast exchange rates; source - IBRD.2/ : Net of Working Capital Increase.3/ : See pars 4.19.4/ : IFC/Comercial Banks/Supplier Credits (see para 4.18).5/ : Towards contingent reserves (para 4.17).

4.17 The total requirements of VEAS amount to about TL 9.9 trillion(US$639 million equivalent) over the 1992-96 period including interest during

- 43 -

construction, about 80X of which (US$508 million) would be for the hardwarecovering the Berke Dam and power house, transmission lines and substations.Foreign exchange requirements amount to US$370 million equivalent representing58X of total costs, which would be met from the proposed Bank loan andcofinancing from other sources (para 4.18). As regards financing of local costs,CEAS proposes to apply 70X of the net cash generation (about US$238 millioneqitivalent representing 38X of total investments) towards the Project and meetthe balance requirements from customer deposits, new equity and borrowing. CEAS'approach to apply only a part of the internally generated funds is intended toprovide for contingencies and is Justified because: (i) the generation from itspredominantly hydro-based capacity is subject to hydrological conditions; and(ii) it has no control over electricity tariffs. Further, CEAS experienced ashortfall of about US$12 million (about 9X of foreign iosts) in the Bank loan(Ln.2750-TU) for the Sir Hydropower Project due to appreciation of the contractcurrencies vis-a-vis the US Dollar. New equity is proposed to be raised fromstock issues for an amount of US$84 million equivalent.

Cofinancing

4.18 The project would be cofinanced with loans from other sources. Fora hydropower project of its size, the proposed Project requires long-termfinancing. Based on the terms CEAS has received from private sources, theprojectinns (para 4.25) show that the financing plan would require a substantialamount a. .onger terms, such as those of the Bank's, to preserve the financialviability of CEAS. The IFC has proposed to lend US$50 million with a maturityof about 15 years including 4.5 years grace, as well as US$50 million insyndicated loans from commercial sources with a maturity of 8 years including 4years grace. The IFC has completed its appraisal and has confirmed that theproposed commercial loans are syndicatable. However, before finalizing the dealwith IFC, QEAS intends to evaluate several offers of financing arrangements whichit has received from manufacturers/suppliers of turbines, generators, electricaland electro-mechanical equipments as well as hydromechanical equipments forfinancing procurement of these equipments. The combined foreign cost of theseequipment packages is about US$80 million equivalent including contingencies.With the Bank's participation through the proposed loan (para 4.19), CEAS expectsto be able to negotiate better terms with suppliers. QEAS is inclined to acceptthe IFC's proposal since, inter alia, it would permit procurement undercompetitive bidding rather than tied-p;ocurement under other offers. Based onthe fact that VEAS has received financial offers, including from the IFC, andthat the procurement and financing arrangements for the electrical, electro-mechanical and hydromechanical equipments can be finalized as late as a yearafter those for the civil works according to the implementation schedule, VEAS'proposal is acceptable. In order to ensure availability of funds, gEAS hasagreed to finalize the agreements with cofinanciers before June 30, 1993.

Proposed Bank Loan

4.19 The proposed Bank loan of US$270 million would complete the financingplan. Considering that the proposed Project would more than double the assetbase of the utility (from US$297 million in 1991 to US$759 by end 1996) andnecessitate commitment of all available cash flows to the Project, the interestduring construction on the Bank loan would also be financed.

Dividend Policy_and Eauitv Einancing

4.20 gEAS' dividend policy is to declare such dividends as deemednecessary to maintain its market standing. Further, SPK's regulatLon requires

- 44 -

that dividends shall not be less than 50X of C istributable income or 20X of paid-in capital, whichever is larger, not exceeding 75X of distributable income13/.Based on such stipulation, the dividends to be distributed during theconstruction of the proposed Project would amount to TL 2,454 billion (US$154million equivalent). QEAS proposes to reinvest its profits by recovering mostof the distributed dividends through issue of new equity, thus ensuring stabilityin dividend payout from market perspective and compliance with statutoryrequirements. During 1988-91, QEAS issued new equity on a stock-rights basis upto US$95 million equivalent to reinvest from the distributed profits of US$121million equivalent during that period when Sir Hydropower Project (Ln. 2750-TU)was under construction.

4.21 QEAS must obtain clearance from the SPK for issuing new securitiesto the public. For any new issues of shares up to the authorized level, theapplication is accompanied by a three-year financial forecast which will allowSPK to determine whether VEAS will be in a strong enough financial position toensure adequate returns to investors. An increase in the authorized sharecapital requires a meeting of the shareholders representing at least 75X ofexisting capital, obtaining a two-thirds vote in favor of such an increase andapplying to SPK for such authorization. VEAS' authorized share capital hasincreased every year, from TL 15 billion in 1987 to TL 150 billion in 1990. Therecent increase of up to TL 300 billion in 1991 has been fully paid in. Thetotal amount of equity proposed to be issued during 1992-96 amounts to about TL1,200 billion (US$84 million equivalent) during the implementation of theproposed Project. VEAS has obtained SPK's approval for increasing its-authorizedcapital up to TL 1,500 billion. It is expected that new equity issues would beon stock rights basis and is intended to recover the dividends declared duringthe period (para 4.20). Based on the fact that VEAS has had no difficulty inobtaining clearance from the SPK or in selling new shares due to its good marketstanding, QEAS' proposal is satisfactory.

F. Financial Forecasts

4.22 The financial forecasts of QEAS were prepared under various scenariosto take into account its limited control on financial performance due tonaturally constrained hydrological conditions and its inability to setelectricity tariffs (paras 2.06, 4.05 & 4.06). Accordingly, reduction in hydrogeneration due to adverse hydrological conditions and/or more than estimatedwater diversion upstream of Sir dam, and reduction in tariff levels wereconsidered for such scenario analyses. The Bass Case assumes yearly hydrogeneration based on typical cycles in hydrological conditions and the prevailinglevel of US. 0 6/kWh for TEK's average revenue to be maintained using the Bank'sforecast of inflation and exchange rates. Alternative scenarios test thesensitiveness of VEAS' cash flows and financial performance to a decrease inhydro generation (Scenario A) and a decrease in tariff levels (Scenario B).

4.23 In order to estimate the reduction in hydro generation, the state ofpoor hydrological conditions (dry year conditions) was imposed on all hydroplants of VEAS. Based on statistical analysis using recorded data on riverstream flows spanning 44 years (1944-88), the probability of a dry year wasestimated to be about 151 (i.e. 15 years in a span of 100 years of water flow)which corresponds to three dry years during the 1992-2010 period. The generation

13 For companies in which the GOT or para-statal agencies havesubstantial shareholding, exception to the minimum dividends may be approvedby the Ministry of Finance on a yearly basis.

- 45 -

of the hydro plants was estimated using the computer model (VALORAGUA) whichsimulates mixed thermal-hydropower system and optimizes the generation of hydroplants taking into account the irrigation and other requirements for use of wateras constraints. Accordingly, accelerated development upstream of Sir dam wasassumed to account for more than currently estimated off-take of water forirrigation and drinking water projects. In addition, six dry years were imposedduring the period 1991 - 2000 (expected number of dry year is two) to simulateVEAS' finances under worst-case hydro scenarios. The dry years imposed are for1993, 1994 and 1996-98, corresponding to peaking investments for 1994 and peakingdebt-service in 1997-99. Details are provided in Annex 4.4. As regards tariffs,US. C 5.50 for TEK's average revenue was used for Scenario B.

Financial Results

4.24 Forecast financial statements for QEAS for the period 1992-2000 underthe base case scenario is provided in Annex 4.1. QEAS' key operational andfinancial performance indicators for the period 1992-2000, as well as projectfinancing plan under the three scenarios are provided in Annex 4.5. Thefinancial results under the three scenarios are summarized in Table 4.3 whichshow the changes in the financing surplus during 1992-2000.

Table 4.3: CgAS' Financial Results. 1992 - 2000(In US$ million except where stated)

1992 1993 1994 1995 1997 1998 1999 ;02Base CameSales (Gb) 4243 4545 4868 5214 5586 5985 6412 6870 7362Hydro Generation (GWb) 1694 1774 1774 1774 2474 3454 3446 3422 3246Ave.Revenue (Cents/kWh) 1/ 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91Gross Cash Generation 2/ 109 120 102 108 131 129 101 95 126Less: Dividends 21 26 32 38 38 48 39 33 38

Loan Repayments 15 14 12 10 23 26 48 48 38Not Cash Generation 73 80 58 60 70 55 14 14 50Financing Surplus 3/ 71 46 2 14 58 55 14 14 50Debt-Service-Cover (DSCR) 5.1 5.5 6.3 6.5 4.9 2.7 1.8 1.9 2.2DSCR After Dividends 4.2 4.4 4.7 4.5 3.7 1.9 1.4 1.4 1.6

Seonario A (Hydra)Hydrology Norm Dry Dry Norm. Dry Dry Dry Norm. WetHydro Generation (GWh) 1694 1132 1132 1685 1132 2076 2076 3347 4057Change from Base Case (Z) 0 -36 -36 -5 -54 -40 -40 -2 25Ave.Revenue (Cents/kWh) 1/ 5.91 5.91 5.91 5.el 5.91 5.91 5.91 5.91 5.91Gross Cash Generation 2/ 109 92 89 110 81 110 112 1S0 94Dividends 21 26 25 26 35 25 31 29 31Not Cash Generation 73 52 45 62 20 36 25 69 18Financing Surplus 3/ 71 17 -11 15 8 36 25 69 18Debt-Service-Cover (DSCR) 5.1 4.6 4.7 6.1 3.1 2.3 1.7 1.8 2.5D8CR After Dividends 4.2 3.5 3.5 4.7 1.9 1.9 1.3 1.4 2.0

Scenario B (Tariffs)Hydro Generation (GWh) 1694 1774 1774 1774 2474 3454 3446 3422 3246Ave.Revenue (Cents/kWh) 4/ 5.42 5.42 5.42 5.42 5.42 5.42 5.42 5.42 5.42Change from Base Case (t) -8.3 -8.3 -8.3 -8.3 -8.3 -8.3 -8.3 -8.3 -8.3Gross Cash Generation 2/ 96 102 100 99 119 116 121 83 113Dividends 21 26 29 31 32 41 43 25 33Net Cash Generation 60 62 56 51 58 42 34 2 37Financing Surplus 3/ 57 28 0 4 46 42 34 2 37Debt-Service-Cover (DSCR) 4.5 5.1 5.4 5.7 4.3 2.8 1.7 1.7 2.0DSCR After Dividends 3.7 4.0 4.0 4.0 3.3 2.1 1.3 1.4 1.5

1/ Corresponds to TEK's average revenue of US Cents 6.00/kWh.2/ Net of working capital change, interest charges and statutory payments.3/: Change in cash during the year.4/ Corresponds to TEK's average revenue of US Cents 5.50/kWh.

- 46 -

4.25 The forecasts show that QEAS' performance under all three scenariosare satisfactory, although the year-to-year variations are as significant as wasobserved in its past performance (paras 4.05 & 4.06). While the trend infinancing surplus and debt-service-cover-ratio (DSCR) is similar under all threescenarios, all other things being same, CEAS' financial performan'ce is moresensitive to reduction in hydro generation than in tariffs as shown by thefinancing surplus and DSCR under scenarios A and B. Specifically, the financingsurplus shows a negative US$ll million in 1994 (Scenario A), the year of peakinvestments, implying a drawdown of cash resources in that year. However, thenet cash generation would be positive under all scenarios, due in part to QEAS'proposal to build-up contingency reserves from internally generated funds(para 4.17). The hydrological cycle assumed implies hydro generation beingsubstantially lower than in the base-case in all the years during 1993-98,resulting in lower DSCR in the 1996-99 period when debt-service would behighestl4/. Such hydrological cycle assumed for Scenario A is highly unlikely,but nevertheless shows the sustainability of QEAS' cash flows under extremeconditions. The proposed actions regarding water management aspects (para 3.32)would ensure increased coordination among CEAS, DSI and TEK thereby minimizingthe hydro risk. As regards tariffs, the prevailing agreement with the Bank(para 4.12) as well as the proposed agreement on exchange prices affecting QEAS(para 4.15) would ensure revenue mobilization for QEAS. Furthermore, the USCents 6/kWh average level assumed for TEK is conservative and higher tariffswould be required for TEK's own cash flow needs and compliance with the agreedfinancial performance criteria (para 4.12). CEAS' performance shows improvementbeginning 1999 and could be expected to improve further as the commercial loanswould have been fully repaid by 2000.

CEAS' Creditworthiness

4.26 QEAS has maintained its creditworthiness satisfactorily in the 1980sas indicated by debt-service-cover - the ratio of cash operating income to debt-service - well above the agreed 1.5 (para 4.02), and intends to maintain itsatisfactorily in the future. However, the statutory stipulation for QEAS todistribute at least 50X of its distributable income (para 4.20) would placedividends above debt-service payments. Furthermore, since QEAS is not allowedto revalue assets (para 2.27), the depreciation provisions are less thandesirable, thereby increasing the distributable income and statutory dividends.Despite the financial projections showing a debt-service cover of 1.5 and higher,the stipulation on dividend distribution would likely reduce QEAS access toborrowings from private lenders. In order to ensure the needed comfort tolenders and enhance scope for mobilizing funds from private sources, the standingdebt-service-cover agreement with the Bank must be modified to account fordividend payments. The financial projections under the extreme case (ScenarioA) show this ratio after dividends to be in the range of 1.3-4.2 during1992-2000, with the lowest of 1.3 in 1998. However, considering that substantialpart of CEAS' own generation is subject to hydrological conditions and that thetariff agreements would ensure CEAS' financial viability (paras 4.12 and 4.15),the minimum DSCR (after dividends) to be set should ensure balance betweenproviding comfort to lenders and guaranteeing shareholders' returns.Accordingly, a debt-service-cover-ratio of a minimum of 1.2:1 on an afterdividends basis would be adequate. QEAS has agreed to maintain, beginning with1993, a minimum debt-service-cover ratio of 1.2 net of dividends paid.

14 The financial projections assume eight-year maturity including four-year grace for syndicated commercial loans based on IFC's proposed terms.

- 47 -

G. Prospegtive Take-Over of Distribution Operations

4.27 CEAS has been negotiating with TEK and MENR, since 1989, theprospects and terms of transfer of operating rights of TEX-operated powerfacilities in the Cukurova region. CEAS' concessionary agreement, revised in1988 under Law 3096 (para 2.01), accords it a regional atility status. Theconcession, in addition to providing rights for new investments in generation,transmission and distribution infrastructure, provides for the transfer to VEASof the operating rights of the existing infrastructure in the region, undermutual agreement between QEAS and the current operators.

4.28 DSI owns the Aslantas hydropower plant (138 MW), which is locateddown stream of Sir and the proposed Berke dam, and is operated by TEK. TEK ownsand operates the 380 L-V transmission lines and associated substations, as wellas the three DEs in the provinces of Adana, Icel and Hatay. Based on the long-term objective of converting TEK into a national transmission company for HV gridoperations and the legal complexities affecting the TEK-operated and DSI-builthydroplants, the 380 kV transmission lines and the Aslantas HPP have been removedfrom the purview of QEAS' concessionary agreement through a decree.Accordingly, only the three DEs are under consideration.

4.29 CEAS has not found any of TEK's various proposals attractive enough.The latest proposal (August 1991) involved CEAS taking over from TEK the completeoperations of the three DEs and hence their profits/losses. Because of the timeneeded to gradually address the problem of over-staffing and high distributionlosses in the DEs, TEK proposed to sell energy at prices that would provideincentive to QEAS to realize a profit. The governing contract for the operationof the DEs would reward/penalize performance. The proposed performance basedcontract is expected to reduce overall financial losses to TEK from these DEs andimprove the efficiency of the DEs. However, the privatization of TEK and/or itsoperations is under review by the new Government and no time table has been setby GOT for this purpose. CEAS is well placed to ensure that its financialviability is not adversely affected by any arrangement for transfer of DEs to itsscope of operations. However, in order to ensure that a change of such scale inits scope of operations does not affect the implementation of the proposedproject, VEAS has agreed to periodically exchange views with the Bank on theprogress of distribution takeover and review the details of such takeover,including the implications thereof, before finalizing the arrangements.

V. ECONOMIC JU-STIFICATION

5.01 The Berke hydroelectric project is part of the least-cost generationexpansion program for Turkey (1991-2010). Its size and timing are economicallyjustified. The expansion of the transmission network included in the scope of theproject is also justified on the basis of the economic benefits associated withthe incremental electricity which would be transmitted through the expanded gridstarting in 1995. The revenue from average tariffs used in the analysis is basedon the LRMC of supply calculated by the mission, which is US.0 4.9/kWh atgeneration level and US.0 5.4/kWh after transmission level (154 kV) and US.06/kWh at distribution level. In addition, the economic analysis was undertakenreflecting other benefits to the economy encompassed in the consumers' surplvz.All costs are expressed in 1991 constant economic prices, tet of taxes ndsubsidies - local costs are expressed in equivalent border prices.

5.02 The project's marginal benefits vls-a-vis the possible generationalternatives have been analyzed using a systems approach. Further, an estimateof the internal economic rate of return (IERR) for the Berke Project and for the

- 48 -

investment in transmission lines, substations and load dispatch center necessaryto connect the hydropower station to the 154 kV grid is provided. In addition,a separate economic analysis is provided for the investments in expansion andrehabilitation of the transmission network, including an estimate of the IERR forthis component.

The Proiect as a Least-Cost Generation Alternative

5.03 The candidacy of the proposed Project as part of the least-costgeneration expansion plan has been tested under a broad range of adverseassumptions: on increase in the discount rate used in the WASP optimization modelfrom ten percent to fifteen percent, twenty percent increase in the project cost,and load growth reduced from nine percent to seven percent a year. A base-casesequence is presented in Annex 1.5 and discussed in Chapter 1. In order tohighlight and analyze the project's comparative advantages in terms of costsavings an alternative least-cost expansion sequence was optimized without Berke.The characteristics of the alternative sequence are described in Annex 5.1 andcompared with the configuration of the least-cost plan. The alternative sequencepresents an overall lower installed capacity (164 MW lower than in the least-costsolution), and a different system configuration resulting in 190 MW additionalthermal installed capacity and 354 MW less hydro-capacity installed than theleast-cost plan.

5.04 Arnnex 5.1 describes the economic costs corresponding to both theoptimal generation expansion sequence (where Berke is singled out as a separateproject) and the alternative expansion plan. The system costs include:(i) investment cost, including investments to reduce environmental impact;(ii) operational costs, consisting of O&M and fuel costs; and (iii) cost ofenergy not served. The Net Present Value (NPV) of the cost savings associatedwith the expansion plan including the Berke Project a-mounts to US$33.5 million.The distribution and the NPV of the cost savings generated by the expansion planare summarized in Table 5.1, and presented in greater detail in Annex 5.2.

Table 5.1: ComRa:ative Systems' Costs Analysis

Savings in Net Savings Net Savingsavoided in Unserved in avoided Net Fuel Net

& Deferred Energy Operational Benefit SavingsYear Investment Cost Cost1989 0.00 0.00 0.00 0.00 0.001990 0.00 0.00 0.00 0.00 0.001991 0.00 0.00 0.00 0.00 0.001982 0.60 0.00 0.00 0.00 0.601993 2.20 0.00 0.00 0.00 2.201994 4.50 0.00 0.00 0.00 4.50199S 4.30 0.00 0.00 0.00 4.301996 -14.00 0.00 0.00 0.00 -14.001997 -31.30 -0.13 17.29 9.31 -14.151998 -66.40 -4.84 16.46 8.52 -54.781999 -96.20 -5.08 17.54 9.44 -83.752000 -2.80 -4.82 17.23 9.13 9.612001 10.50 -2.92 18.67 10.58 26.262002 172.80 0.01 41.56 34.52 214.372003 75.00 0.69 8.26 15.46 83.952004 -45.60 -0.13 19.40 11.44 -26.33200' -11.20 0.32 36.25 28.50 25.372006 -20.40 0.27 -39.60 -22.20 -59.732007 -21.00 0.12 21.04 13.03 0.162008 -0.00 0.54 18.88 16.72 19.422009 84.14 0.54 18.82 16.64 83.50

NP - -17.57 -5.66 56.71 40.31 33.48

- 49 -

The difference in systems' configuration given by the larger thermal (lesscapital intensive) component contained in the alternative sequence, entails lowercapital investments and higher operational costs for the sub-optimal plan. Thesavings in avoided and deferred investment resulting from the least-costexpansion are correspondingly negative and amount to a loss of US$17.57 million.The unserved energy cost will also slightly increase (by US$5.66 million). Thesavings brought about by the least-cost expansion plan consist in a US$56.71million reduction in operational costs, of which US$40.31 million correspond tofuel savings. This reduction in lignite-based generation capacity can also beexpected to have a positive environmental impact on the economy.

Benefits of the Berke Project

5.05 The IERR for the Berke Project and the transmission and distributioninvestment components necessary to connect the power station to the grid is 15.21(the benefit-cost analysis is described by Annex 5.3). This estimate isconservative since the net benefits do not capture the positive environmentalimpact associated with the optimal configuration. Table 5.2 illustrates theresults of a sensitivity analysis testing the economic feasibility of the projectagainst the following adverse assumptions: (a) investment cost increases by 101,(b) project implementation delayed by one year, and (c) load growth reducedsubstantially from 9.51 to 6.5X during the remainder of the decade. While thesehypotheses would not affect the feasibility of the project they would lower theIERR to about 14X to 12%. The sensitivity analyses are described in Annex 5.3.

Table 5.2: Berke Hydropower Proiect Sensitivity Analysis

Case IERR (X)

Investment cost increased by 101 14.1

One-year delay in investment 14.3Implementation

Lower demand growth 12.0

5.06 The economic analysis for the regional transmission expansioncomponent included in the project scope, though not part of the Berke hydropowerplant, is described in Annex 5.4. Investments are in constant 1991 economicprices, while the benefits are captured by the revenue associated with theincremental electricity transmitted through the grid in the Qukurova region asa result of the investment. The energy to be transmitted via the grid more thandoubles after full commissioning of the Berke Project; in the absence of therequired transmission expansion foreseen in the project scope, the incrementalgeneration provided by the proposed Berke Project and further generationexpansion would face serious transmission constraints. The base-case benefit-cost analysis corresponding to an incremental tariff equal to the LRMC ofelectricity transmission (US.C 0.52/kWh) results in a IERR of 20X. Thesensitivity analysis presented in Annex 5.5 tests the feasibility of theinvestment against progressively lower values of the incremental tariff, showingthat the bench-mark incremental tariff for ele.-tricity transmission justifyingthe investment corresponds to US.M 0.31/kWh.

X so -

VI. AGREEMENTS REACHED AND RECOMMENDATION

Agreements

6.01 The following are set as dated covenants:

(a) QEAS would complete the ER for transmission lines, in a mannersatisfactory to the Bank, by December 31, 1992 (para 3.45);

(b) VEAS would complete the load dispatch center study by December 31,1993 under TOR satisfactory to the Bank (para 2.16); and

(c) QEAS would submit to the Bank, beginning with 1992 accounts, itsaudit reports prepared by private auditors under terms-of-referencesatisfactory to the Bank, within six months after the end of thefiscal year (para 2.29).

6.02 The following covenants are set for monitoring the implementation ofthe Project:

(a) GOT to ensure that environmental and resettlement aspects arecarried out in a manner satisfactory to the Bank (paras 3.39 and3.44);

(b) GOT to: (i) maintain the prevailing tariff setting system andcontinue to establish electricity prices as agreed under the TEKRestructuring Loan; and (ii) ensure that electricity pricesincluding the exchange prices between TEK and QEAS under the newtariff policy would not adversely affect the financial condition ofSEAS (para 4.15);

(c) VEAS to carry out, in a manner satisfactory to the Bank, the agreedprograms related to the environmental aspects of the proposed damand the transmission lines as well as resettlement of the affectedpopulation (paras 3.39, 3.44 and 3.45);

(d) QEAS to finalize agreements with cofinanciers for funds up to US$100million equivalent before June 30, 1993 (para 4.18);

(e) QEAS to maintain a minimum debt-service-cover, net of dividends at1.2 (para 4.26); and

(f) QEAS to periodically exchange views with the Bank on the progress ofdistribution take-over and review the details of such take-over,including the implications thereof before finalizing thearrangements (para 4.29).

6.03 The execution of a subsidiary loan agreement between GOT and QEAS,on terms satisfactory to the Bank, is set as a condition of effectiveness of theproposed Loan (para 3.15).

Regommendation

6.04 On the basis of the above agreements, the proposed Project issuitable for a Bank loan of US$270 million.

TURKEYPROPOED BERKE NYOROPOSER PROJECT

ENERGY BALAMCE (1990)(Unit: 1000 IOE)

Coal Lignite Aspha- Raw Crude Ol Nydro Geoth- Other Fuetwocd Wastes Coke Briqu- Gas Petroteui E ectricity T 0 T A Lttite Mat. Gas ermat nonsp- ettes Proce- Proec ts

ecifid ssed1 2 3 4 5 6 7 8 9 10 11 12 13 14 1S 16

1.Domestic production 2,392.2 11,415.7 295.1 410.4 2,598.2 7,072.0 22.3 67.6 5,255.9 2,498.4 0.0 0.0 0.0 0.0 0.0 32,027.82.ilports 3,300.6 0.0 0.0 3,160.9 19,200.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1,010.6 134.9 26,807.93.Exports £ Bta*ers 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.04.Stock Changes 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

A NET PRINARY ENERGY 5,692.7 11,415.7 295.1 3,571.3 21,799.1 7,072.0 22.3 67.6 5,255.9 2,498.4 0.0 0.0 0.0 1,010.6 134.9 58,835.7

5.Reffneries 0.0 0.0 0.0 0.0 (21,799.1) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 21,799.1 0.0 0.06.Gas nawfactute (46.6) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 62.1 (15.4) 0.0 0.07.Electric Powe Stat (221.3) (S,358.9) 0.0 (2,178.6) 0.0 (7.072.0) (22.3) 0.0 0.0 0.0 0.0 0.0 0.0 (400.4) 15,453.6 0.08.Coke Ovens (2.528.5) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2,556.5 0.0 (27.9) 0.0 0.0 0.09.B.equetting Plant 0.0 (10.9) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (14.4) 31.5 0.0 (6.2) 0.0 0.010.Conv.Losses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (344.6) (3.5) (9.9) (1,419.6) (10,614.9) (12,392.0)

B TOTAL TRMSFORNATIO (2,796.4) (5,569.8) 0.0 (2,178.6) (21,799.1) (7,072.0) (22.3) 0.0 0.0 0.0 2,197.5 27.9 24.3 19,957.5 4,838.7 (12,392.4)

C T . ENERGY SUPPLY 2,896.3 S,845.9 295.1 1,392.7 0.0 0.0 0.0 67.6 5,255.9 2,498.4 2,197.5 27.9 24.3 20,9b8.1 4,973.6 6,43.3

11.Second.Exports 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.012.Trwas.6 Distribut

Losses and On Use 67.0 78.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 767.9 545.5 1,459.3 I

O FINAL ENtERGY USE 2,829.3 5,767.1 295.1 1,392.7 0.0 0.0 0.0 67.6 5,255.9 2,498.4 2,197.5 27.9 24.3 20,200.1 4,428.1 44,984.0

13.Residential 1,964.6 3,282.6 210.8 53.5 0.0 0.0 0.0 55.9 5,255.9 2,498.4 0.0 27.9 24.3 2,609.6 1,553.7 17,537.214.1ndustrial 864.8 2,484.4 84.3 1,339.1 0.0 0.0 0.0 11.8 0.0 0.0 2,161.8 0.0 0.0 5,842.9 2,795.5 15,584.6

- Iron an Steel 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2,161.8 0.0 0.0 0.0 0.0 2,161.8-Petrocuei.and Chm 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0-Ufrtilizer 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0- Cement 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Sugar 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0-Nonferreus Netals 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0-Other Industry 864.8 2,484.4 84.3 1,339.1 0.0 0.0 0.0 11.8 0.0 0.0 0.0 0.0 0.0 S,842.9 2,795.5 13,422.8

IS.Transport 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 8,334.1 43.2 8,377.316.0t8er Sectors 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 35.7 0.0 0.0 2,149.4 35.7 2,220.87T.Non Energry Use 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1,264.1 0.0 1,264.1

I I I_ _~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~E;

TURKEY

Installed Capacity, Electricity Generation cnd Sates in the Power Sector

Installed Capacity || Energy Generation |Energy|

Hydro | Thermt II Hydro I Thermal t Sales 1

ITears if Lignite I Coal IFuel Oil |Diesel OillIat. Gas I Total 11 ILignite I Coal IFuel Oi1 IDiesel OilImat. Gas I Total 11 II || (N) |(NW) I (NW) I (NW) I (NW) I (NW) I (NW) 0 (Gh) I (GWh) I (Gh) I (GWh) I (GWh) I (GUh) I (GUh) | h)11_1-_1

J _ 1 .... I 11 _ .___ I.._________ I I I I _ 1 11989 II 6904 4722 I 150 I 2106 I 429 I 2550 I 16861 II 25556.45 I 20371.04 I 0.01 I 0.05 I 0.00 I 9148.27 55075.8 1j 43909.31990 1j 7488 4872 | 300 j 2106 I 429 I 2550 1 17745 II 27136.55 I 24178.54 I 0.02 I 0.06 I 0.00 9906.49 61221.7 II 47570.31991 II 7381 5253 300 I 2106 429 j 2550 I 18019 1j 28819.25 28415.53 0.03 1 0.10 1 0.02 110382.20 167617.1 11 52470.6 1i1992 II 8176 5418 | 300 | 2106 I 429 2550 I 18979 1I 35865.20 I 28389.60 I 0.06 1 0.18 1 0.03 110378.35 1 74633.4 1 57876.9 |1993 5j 9708 I 6003 300 I 2106 I 429 I 2550 21096 JI 40965.30 I 29855.21 I 188.54 1 132.43 1 0.04 111252.35 1 82394.9 11 63823.9 1I II I I I I I I I I I I I I I II I "1994 0 10662 I 6213 I 780 2106 I 429 I 2550 I 22740 II 42297.30 j 32627.19 I 3644.53 I 969.52 1 0.12 112449.57 1 91988.2 11 70369.2 11995 II 11149 I 6213 | 1260 2106 I 429 I 2550 I 23707 II 49671.05 j 31877.70 I 6817.91 11013.61 | 61.26 111984.38 1101425.9 || 77570.5 |1996 11 6234 2090 2106 I 429 I 0 I 10859 1I 55186.53 I 30105.61 112053.97 987.38 1 104.46 111820.35 1110258.3 11 84194.3 11997 II 10879 8614 I 3530 I 2106 I 429 I 2550 28108 5I 57222.30 I 28619.48 I 21166.27 793.94 1 54.93 112412.38 1120269.3 1I 91368.3 I1998 Ij 13061 j 8614 I 4710 I 2106 I 429 I 2550 I 31470 II 61050.18 I 29231.20 28495.26 I 790.24 1 43.62 111542.92 1131153.4 11100351.4 I

I II I I I I I I II I I I ~ ~ ~ ~ ~ ~ ~~~ ~~~~~~~~~~~~~~~I I I II I1999 II 13787 8614 I 6150 I 2106 I 429 I 3900 I 34986 II 61050.05 j 31289.64 I 37860.18 I 624.29 I 46.23 112197.61 0143068.0 1111m991.8 I2000 1I 14987 8 8614 I 7110 I 2106 I 429 I 5250 I 38496 JI 65408.60 I 32344.04 44090.36 I 534.66 1 35.22 113629.21 1156042.1 11127684.9 I2005 II 18345 I 9213 11300 I 2106 I 429 10200 51593 1190495.73 146465.63 M 70502.42 239.66 1 37.60 117004.06 1224745.1 11175414.1 12010 II 22881 I 11244 I 16630 I 2106 I 429 1 16950 1 70240 11123150.50 1 69431.45 1105510.49 1 227.02 1 39.18 127887.32 1326246.0 11260901.8 II__________ ,_____ _ 1 1_1_1_ _1_1_11_I _ I ___________ I..................I...................I __________ _ 11..................II __________ i

eNDRO PW pNNTRAMISSIOU AMD DISTRIBUTIIO STSTE'S CUARAUTERISTICS

TrouuM1sa Systm Distributfonsvatm GrowdTOr 3kV 220 k 154k 66 kv Total Totat Total

llo. :tip.tilWAI~~~~~~~(vk Length| No. Cap.JIVI ;igtl No. Cop.(llA) Legth ho N4z)t|o. Ca. (NA) Lenth .g .tA o. Ca.(NA) Legh

i3iF T 3N0.0 | l - l ~~~~~- 6224. |- I 1571f.0 - -1W 13155.0 | -l3S2 f10.0- 1-39 3 2455.0O 0gigl2 2S 3810.0 sm 123 .5 0° 299 I.01585.0 629 13980.0 0 41589 13060.0 42218 27040.0 019M 29 4410.0 33 9219.0 299 1691.0 651 1532.0 0 461 1532.0 019t4 30 4SD0.0 354 10945.0 9 1731.0 682 17206.0 0 682 17206.0 0TEE 19C5 36 5710.0 3 11843.0 265 173.0 693 19326.0 0 693 19326.0 01986 49 7660.0 576? 13 42? 13702.0 14600 16T 1358.0 1tJ2 63 22740.0 24264 62636 14590.3 W642 63279 37330.3 33190619eJ 55 8610.0 6bD6 W 450 15093.0 1757 159 1320.0 lIMS 664 25H23.0 25543 342661 664 250.3.0 36520419S8 56 8b60.0 7202 57 478 16237.0 17906 150 1295.0 1646 684 26192.0 26839 379672 684 26192.0 4065111"a 0 0.0 0 0 0.0 01990 0 0.0 0 0 0.0 0

ygs-l -o 0.0 ~~~~~~~~~~~o -0.0 0*1182 0 0.6 0 0 0.0 01953 O 0.0 0 0 0.0 01984 0 0.0 0 0 0.0 0hAS 195 0 0.0 0 0 0.0 01986 26 792.5 762 20 231.5 112 46 1024.0 874 1 6.3 1444 47 1030.3 23181987 ZS 872.5 765 20 231.5 114 46 1104.0 89 2 5.0 1446 S0 1129.0 2251918 29 922.S 765 20 231.5 114 49 1154.0 879 2 25.0 1446 51 1179.01 2325190 0 0.0 0 0 0.0 0190 0 0.0 0 0 0.0 0 °

1t5 0 0.0 0 0 0.0 0WQ 19|5 0 0-.0 0 0 0.0 01984 0 0.0 0 0 0.0 0RM I 0 0.0 0 0 0.0 096 3 75.0 106 3 40.0 12 6 115.0 118 2 15.0 729 6 130.0 847198 4 100.0 163 3 40.0 12 7 140.0 175 2 15.0 732 9 15SM 907sum 4 100.0 163 3 40.0 122 140.0 175 2 15.0 72 9 155.0 907

I989 0 0.0 0 0 0.0 07ii 0 0.0 0 0 0.0 0

gm 3m. 00 0 -~. 0 294 -VS-71.0 -0 df0F 0-1-550 -0 AWF 11-402.0 -0 3941F 24557.0 0~1982 25 3810.0 0 0 0.0 0 307 15.0 0 297 15S.0 0 629. 139W.0 0 41589 13060.0 0 42218 2M4.0 019529 "10.0 0 0 0.0 0323 9219.0 0 299 1691.0 0 651 1530.0 0 0 0.0 0 6of 153.0 0tM 30 4530.0 0 0 0.0 0 354 1045.0 0 298 1731.0 0 682 17206.0 0 0 0.0 0 68 12 = 0 OM1 36 573.0 0 0 0.0 0 392 11843.0 0 265 1753.0 0 693 1926.0 0 0 0.0 0 69 10.0 O1 *9 76M0.0 5767 0 o.e 1 46 1469.5 17 190 1629.5 2006 695 23.0 256 62639 14611.6 3815 63334 340.6 335071911 55 3610.0 6606 0 0.0 7 482 1605.5 17t 18 1591.5 1919 79 26?.0 267 4 40.0 3449 72 26.0 31436195 56 060.0 72 0 0.0 7 511 172.5 183 173 156.5 1M 740 246.0 278 4 40.0 38150 744 272.0 493198 0 0.0 0 0 0.0 0 0 0.0 0 0 0.0 00 0.0 0 0 0.0 0 0 0.0 019 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 0.0 0

go. * _a of LineSourwee; Niggl Estfetes

- 54 - Annex 1.4

'TURKEY

BERKE HYDRO POWER PROJECTSTATUS OF DISTRIBUTION FACILITIES AND SUBSTATION COMPOSITION

Distribution Facilities

erpse Primry Feeders (km) Secondarieskm) D OIstribution Transformer.

35 kV 15 kV 6 kV 3 kV 220/380 V Number 1Capaity(MVA)

1 ogazici 753 1179 255 | 7683 1648 26662 G. Marmara 246 516 183 | 41371 189 |1563 Ego 1147 1050 193 .- 8259 785 3064 Porsuk 597 137 352 - 3645 290 475 Akdeniz 420 489 93 306211 325 726 Moran 569 288 1118 4067 388 79i7 Ic Anadolu 633 250 309 . 71931 582 621I8 Torostar 608 587 | 286 S - 5715 576| 152|9 Erciyes 443 570 58 31 3506 330 4710 Kahraman G. 323 292 76 19261 234 11611 Dicle 321 142 92 . 2386 185 4412 First 550 64 328 . 1592 240 7113 Vangolu 82 200D 01 1106 63 2314 0. Anadolu 385 238 270 1906 200 7915 Kizilirmak 388 86 59 I * 1117 264 6616 0. Mayis 632 281 2461 I 15831 502 9117 0. Karadeniz 340 345 134 1 3598 384 8918 Ilgaz 202 260 33 - 1494 I0 1319 Sakarya I .20 Malatya I .21 Erzincan _ I *-

TOTAL 8639 j 6721 I 4085 3 3 I 63975 || 6289 1 4738

1~~~~~~ 1-

Substation Composition

INOI Voltage i No. of No. of ITransformeri TotalLevel kV Substations Transformer Ratio kV Capaity MVAI

I l- 38*H | 14 - 29 380/154 I 43081 220/154 I 176

2 154 204 90 154/66 I 582229 154/34.5 I 9483

3 566 9 56 66/34.5 I 28156 66/15 400

4 34.5 91 103 34.5/15 36529 30/15 131

TOTAL | 59; 1526 |

** This table shows only the transmission powertransformers maintained by the eight regionaldivisions.

Source: Mission Estimates

- 55 - Annex L1Page 1 of 6

2muERKE HYDROPOWER PROJECT

Least-Cost Geneartlon Expansion Proram

1. The long-term investment program is prepared by the planningdepartment of TEX in cooperation with MENR and DSI. MENR provides theforecast for electrLclty demand and DSI formulates the ranklng for the hydrogeneratLon capacity. The Lnvestment program li then submitted to 8P0 forapproval. The corresponding Lnvestment plan is however formulated only for aflve-year perlod.

2. Under the Core Investment Program (CIP) TEX Restructuring Project(Ln. 3345-TU) agreement was reached on the power sector CIP for tho period1990-1994. During the preparatlon of the Staff Appraisal Report for theproposed Berke Hydropower Project, an lndependent least-cost analysis was alsocarrled out. Further generatlon system optlons were examLned uslng hydro,lignite, natural gas and lmported coal plants as acceptable candidates forexpanaLon. Special attentlon was paid to BOT projects. The analyaLs wasperformed uslng the WASP III and VALORAGOVA system plannLng models whichdetermine the optlmal pattern of system expansLon necessary to mest theelectrLcLty requLrements of Turkey over a given perlod. The assumptlons andconstraints utllized for the study are detalled below.

3. Demand Forecast: ElectrLcLty demand was forecasted by uslng twodLfferent approacheos (a) econometrlc estimates, and (b) the MAED model. Bothapproaches gave very sLmilar results, whlch were revlowed wlth INER, PO andTEX. The long-term demand forecast on the basLi of which the requirements forgeneratlon expanslon are established is shown in Table 1.1

Tabte 1.1: Iemnd Forecas= -. _ ., =_ . -_ - -

Year feakload GR.R Nfn.Load GR.R Energy GR.R LoadN X NW X Ch X Factor

1989 8522.0 . 2990.8 52513.8 . 70.341990 9342.0 9.6 3278.5 9.6 57566.8 9.6 70.341991 10225.0 9.5 3624.4 10.5 63351.0 10.0 70.731992 11255.0 10.1 3989.4 10.1 69732.6 10.1 70.731199 12388.0 10.1 4391.0 10.1 76752.3 10.1 70.731994 13635.0 10.1 4833.1 10.1 84478.3 10.1 70.731995 15007.0 10.1 5319.4 10.1 92978.7 10.1 70.871996 16236.0 8.2 5780.2 8.7 100797.3 8.4 70.87?1997 17600.0 8.4 6265.8 8.4 109265.4 8.4 70.871499 19080.0 8.4 6792.7 8.4 118453.7 8.4 70.871999 20685.0 8.4 7364.1 8.4 128417.9 8.4 70.872000 22434.0 8.5 7986.8 8.5 139276.2 8.2 70.872001 24767.0 10.4 8716.6 9.1 150717.9 8.3 69.472002 26814.0 8.3 9437.0 8.3 163174.9 8.3 69.472003 29030.0 8.3 10216.3 8.3 176660.2 8.3 69.472004 31428.0 8.3 11060.9 8.3 191253.1 8.3 69.472005 34025.0 8.3 11974.9 8.3 207056.9 8.3 69.472006 36840.0 8.3 12965.6 8.3 224187.5 8.3 69.472007 39880.0 8.3 14035.5 8.3 242687.2 8.3 69.472008 43176.0 8.3 15195.5 8.3 262744.8 8.3 69.472009 467U.0 8.3 16451.3 8.3 284457.6 8.3 69.472010 50607.0 8.3 17810.8 8.3 307965.6 8.3 69.47- _ - : - = _

- 56 -Annex 1.5

Page 2 of 6

4. Existina Power System: The breakdown of the existing generationcapacity of the Turkish power system by fuel type at the beginning of year1990 is shown in Table 2.1.

Table 1.2 - Breakdown of Generation Capacitv

Plant Type Capacity (NWS) % of Total

Hydro 6,081 40.9Lignite 4,955 31.3Coal 150 1.0Natural Gas 2,750 17.4Fuel Oil 1,440 9.1Diesel Oil 429 2.7

Total 15,805 100.0

Table 2.1 shows that the existing generation capacity is mainly based (69.8%)on domestic primary energy resources (hydro and lignLte), and that natural gasis emerging as the third important basis for power generation.

5. The historical development of the total generation capacity of theTurkish power system from 1970 to 1989 is presented in Table 1.3

Table 1.3 - Generation Cacacity Develooment

[1 TZK TURKEY

(ZN) (1) (II) (t) (S) (II) (NW) (NW) CZ) (2)

1970 905 534 1,439 1,509 725 2,234 13.61971 1.095 670 1,765 22.6 1,700 872 2,578 15.31972 1.188 690 1,878 5.5 1,819 893 2,712 5.21073 1,568 782 2,350 25.1 18.4 2,207 985 3,192 17.72874 1,643 1,190 2,833 20.6 2,283 1,449 3,732 16.9;.975 1,708 1,521 3,229 14.0 2,407 1,780 4,187 12.2 13.71976 1,771 1,814 3,385 4.8 2,492 1.973 4,365 4.21977 2,071 1,614 3,685 8.9 2,855 1,873 4,728 8.31978 2,179 1,622 3,801 3.1 7.4 2,988 1,881 4.869 3.01979 2,179 1,872 4,051 5.6 2.988 2.131 5,119 5.1 6.51980 2,179 1,872 4,051 0.0 2,988 2,131 5,119 0.01981 2,345 2,007 4,442 9.7 3,181 ..2.i.6 5,537 8.21082 2,720 2,823 5,543 24.8 3,556 3,082 6,638 19.91983 2,983 2,998 5,936 7.1 3,696 3,239 6,035 4.51984 3,543 3,644 7,167 21.1 4,584 3,875 8,459 22.0 10.51985 4,148 3,644 7,792 8.4 5,244 3,875 9,119 7.81986 5,142 3,644 8,786 12.8 12.1 6,235 3,877 10,112 10.91967 6,291 4,720 11,011 25.3 7,489 5,003 12,492 23.51986 7.046 5,935 12,981 17.9 8,300 8,218 14,518 16.219s8 7,939 6,208 14,237 9.7 14.6 9,208 6,597 15,805 8.9 13.3

6. Candidate Unito. The candldate units are defined as those units that are notcurrently flrmly committed and that could be added to the generation system beforethe end of the planning horizon. The generation system expansion path is optimized

- 57 -Annex l.5

Page 3 of 6

by selecting the least-cost solution obtained using the WASP model. The WASP modelLs constrained to the level of demand provided by the MAED model. As candidateunits for the WASP, the following were considered: lignite fired steam turbine unitsof 150 MW, 300 MW and 340 MW, 500 MW imported coal, 450 MW natural gas combinedcycle plant, and 1,000 MW nuclear unit. In addition, 75 hydro candidate have beenconsidered as candidates fr generation system expansion. The sezluencing ofhydroplant has been initially determined by DSI. However, this ranking has beenlater refined using the VALORAGUA computer program.

7. Discount Rate. The discount rate used for this analysis was 10%. The use ofthis assumption for the long-term planning purpose has been agreed with MENR andSPO.

8. Cost of Unerved Enerov. The expected unserved energy is theprobabilistically determined amount of yearly electricity demand that in notsupplied because of generating deficiencies and/or shortages in basic energysuppliers. The cost of unserved energy is included Ln the WASP objective functionas a way to consider explicitly cost/reliability trade-offs. Thus, if the unit costof unserved energy is assumed to be zero, the least-cost expansion plan will followthe minimum allowable reserve margin. Conversely, if the cost per unit of unservedenergy is assumed to be very high, the least-cost expansion plan tends to haverelatively high reserve margins. In this study, the basic cost per unit of unservedenergy is assumed to be represented as a function of the unserved energy. Thereserve margin and reliability of the power system were not set in advance, but theywere obtained as a result of the optimization anticipating the unserved energy costgiven as c - 0.1 + 2.* (E,/Et)2, where Et is total generated energy, and E, isunserved energy. The coefficients were determined so as to represent the cost ofenergy generated by a diesel generator (US$0.1/kWh) and loss of the GDP due tounserved electrical energy (US$2.0/kWh).

9. Fuel PRric. The prices of the fossil and nuclear fuel which was assumd inthe analysis are presented in Table 1.4.

Table 1.4: Fossil and Nuclear Fuel Prices

Fuel Tyne S/Gcal IMkg kcal/k

LigniteAfsin-Elbistan 10.35 11.8 1149Tuncbilek 5.50 16.5 2994Yatagan 6.80 13.2 1964Catalgazi 12.00 50.9 4245Soma A 3.80 13.0 3428Cayirham 5.20 13.0 2509Kangal 10.65 14.7 1380Bingol-Karliova 16.67 14.7 882Coal 7.22 13.2 1828Imported Coal 6.90 40.0 5797Natural Gas 11.76 100.0* 8503*Diesel Oil 30.30 312.1** 10300Fuel Oil 16.00 153.6** 9600Nuclear 3.17

*$/k*m3S kcal/m3 ** S/ton

-58 - Annex 1.5

Page 4 of 6

10. Reliability ISvstem LOLPI. The* ~~~~~PIo 1.1 - CPIW ReLIABILITY AS A PUQ X UMJW * PRIX

system reserve margin and reliability 7

are very often given as constraints ofthe system optimization. In ourapproach the price of unserved energy

were given at the outset so that systemreserve margin was obtained as a result I a4

of the optimization and is consistent l

with economically optimal levels of thereserve margin. A weak point of this

approach is that the price of the H4unserved energy cannot be preciselydetermined. In order to provide a ¶ a 43 . , a a l

better approximation, an additional AATIO OF UNSERVE ENE Y PR CIE TO LRMC

analysis has been done so as to obtain Figure 1.1functional relations between long runmarginal cost, unserved energy price andsystem reliability (reserve margin). The system was optimized with unserved energyprice equal to N*LRMC, N - 1, ... , 10, so as to obtain the system reliability level.

The results are presented in Figure 1.1. High price of unserved energy will request

very high additional investment and would have little incremental contribution to

reliability of the system. The economically optimal system reliability as shown by

the result presented on Fig. 1.1, is at around LOLP value of 3%. Corresponding

unserved energy price of 3*LRMC is consistent with the value used in the system

optimization.

11. Least-Cost Expansion Plan. The resulting least-cost solution is presented

in Table. 1.5.

Table 1.5: CG4ARATIVE ANALYSIS OF SY TEMS'COSTS(USe million)

SAVINGS IN NET SAVINGS NET SAVINGS 1AVOIDED & IN UNSERVEk IN AVOIDED NET FUEL NET IDEFERRED ENERGY OPERATIONAL BENEFIT SAVINGS

I YEAR INVESTMENT COST COST

1989 0.00 0.00 0.00 0.00 0.001990 0.00 0.00 0.00 0.00 0.001991 0.00 0.00 0.00 0.00 0.001992 0.60 0.00 0.00 0.00 0.601993 2.20 0.00 0.00 0.00 2.201994 4.50 0.00 0.00 0.00 4.501995 4.30 0.00 0.00 0.00 4.301998 -14.00 0.00 0.00 0.00 -14.001997 -31.30 -0.13 17.29 9.31 -14.151998 -66.40 -4.84 16.46 8.52 -54.781999 -96.20 -5.08 17.54 9.44 -83.752000 -2.80 -4.82 17.23 9.13 9.612001 10.50 -2.92 18.67 10.58 26.262002 172.80 0.01 41.55 34.52 214.372003 75.00 0.69 8.26 15.46 83.952004 -45.60 -0.13 19.40 11.44 -26.332005 -11.20 0.32 36.25 28.50 25.372006 -20.40 0.27 -39.60 -22.20 -59.732007 -21.00 0.12 21.04 13.03 0.162008 0.00 0.54 18.88 16.72 19.422009 64.14 0.54 18.82 16.64 83.50 1

NVY - -17.57 -5.66 56.71 40.31 33.48

- 59 - Annex 1.5

Paee 5 of 6

TABLE 1.6 - LEAST-COST EXPANSION PLAN

Year Unit Namn Size Type TEK D81 CEAS KEPEZ BOT NA TURKEY(MWo)

1990 Kangal 2 160.0 Lignite-Stearn TEK 160.0Amnbaril 618.1 N.Qas - CC TEK 618.1Tercan 16.0 Hydro DSI 16.0Karacaoron 32.0 Hydro DS9 32.0Killckaya 120.0 Hydro DSI 120.0Derbent 68.3 Hydro DSI 68.3Menselet 124.0 Hydro DSI 124.0

Sub-Total 68. 1 349.3 1017.41991 Y. Catalagazi 160.0 Lignite-Steam TEK 160.0

Orhanell 210.0 Lignite-Stoam TEK 210.0Soma B-6 166.0 Llgnite-Stearn TEK 188.0Ataturk 1,2 600.0 Hydro DSI 600.0Gozende 1 176.0 Hydro D01 176.0Kralklzi 1,2 93.8 Hydro 081 93.8Adiguzel 1,2 62.0 Hydro Del 62.0Yenice 1.2 26.2 Hydro 081 26.2Kockorpu 1.2,3.4 8.8 Hydro DSI 8.8Sir 273.0 Hydro CEAS 273.0

Sub-Total 625.0 966.8 273.0 1763.81992 Soma -8- 166.0 LignItetearn TEK 166.0

Kamorkoy 1.2 420.0 Llgnito-Steam TEK 420.0Ataturk 3,6 900.0 Hydro D81 900.0Catsian 1,2 112.6 Hydro DSI 112.6Gozende 2.3 106.2 Hydro DS0 106.2Yonice 3 12.6 Hydro DSI 12.6Kuzgun 1,4 22.6 Hydro D81 22.6Mercan 1,3 19.2 Hydro DS0 19.28eykoy 1,3 16.0 Hydro DSI 16.0Camulgczo 16.6 Hydro DSI 16.6

Sub-Toial 686.0 1204.7 1789.71993 Kemorkoy 3 210.0 Lignite-Steam TEK 210.0

Ataturk 6,8 900.0 Hydro D01 900.0Oziuce, Pore 170.0 Hydro D91 170.0Catalan 3 68.3 Hydro 081 68.3Dicle 110.0 Hydro DSI 110.0Suat Ugurlu 3 30.0 Hydro TEK 30.0

Sub-Total 240.0 1238.3 1476.31994 Kunun 86.0 Hydro DS1 66.0

Small Hydro 20.0 Hydro SOT 20.0Sub-Total 85.0 20.0 106.0

SIXTHFIVEYEARPLAN(1990-1994) 2018.1 3841.1 273.0 20.0 6162.2

1996Sub-Total

1996 Ellistan 340.0 Lignite-Steam TEK 340.0Sub-Total 340.0 340.0

1997 Elbiatan 2040.0 Lignite-Stoamn TEK 2040.0Berke 610.0 Hydro CEAS 610.0

Sub-Total 2040.0 610.0 2660.01S98 Birecik 672.0 Hydro SOT 872.0

SBabat 613.0 Hydra DSI 613.0Yedigoze 300.0 Hydro NA 300.0Allpasa 187.0 Hydro NA 187.0

Sub-Total 613.0 672.0 487.0 1872.01999 Kerkamis 180.0 Hydro DSI 180.0

Kayraktope 431.0 Hydro DSI 431.0Natural Gas 1360.0 N.6AS - CC TEK 1360.0Akkopru 116.0 Hydro DSI 116.0

Sub-Total 1360.0 726.0 2076.0SEVENTH FIVE YEAR PLAN (1996-1999) 3730.0 1239.0 610.0 672.0 487.0 86838.0

TOTAL (1990-1090) 6748.1 6080.1 783.0 6Z.0 487.0 12790.2

- 60 - Annex 1.5

Pae 6 of 6

TAE 1.S - LEAST-COST EXPANS1ON PLAN

Yer Unit Nam 612. Typ TEK OSI COAM KEPEZ SOT NA TURKEY

2000 llbu 1200.0 Hydro 061 1200.0Naturalee 1S50.0 N.Gae - CC CERA 13S0.0

Sub-Total 1200.0 1380.0 2660.02001 Oivhu 240.0 Hydro 061 240.0

Torul* 175.0 Hydro O6I 17.0ODeine 670.0 Hydro 081 670.0Natural Oa 1600.0 N.Gas - CC TEK 1800.0

Sub-Total 1800.0 1086.0 2886.02002 Soroka 3000 0Hydro DS1 300.0

Muratl 116.0 Hydro D01 1160Yu. s 640.0 Hydro OSI 640.0Of-8"kI 380.0 Hydro SOT 380.0Natural GCM 1360.0 N.Oas - CC TEK 1S30.0

Sub-Tota 1360.0 06S.0 380.0 2688.02003 Beakonak. 603.0 Hydro OSI 633.0

OlCIur 138.0 Hydro DSI 136.0,nported Coal 2000.0 Coal-Stmn SOT 2000.0

Sub-Total 6ee.0 2000.0 2666.02004 Natural Gee 900.0 NOm - CC TEK 900.0

Imported Coal 1000.0 Coal-Stem SOT 1000.0914CS 180.0 Ugnito-St em 'EK 180.0

Cnylrhan 300.0 L,gnite-Steam TEK 300.0Sub-Tota 1360.0 1000.0 2360.0

EIGTH FIVE YEAR PLAN (2000-204) 4500.0 3s08.0 3380.0 13138.0

2006 Golta 270.0 Hydro 061 270.0Natural an 9o.0 NOs - CC TEK 900.0Imported Coal 1600.0 Coal-stearn OT 1800.0Adlyaman 180.0 UgnIt-Steam TEK 180.0

Sub-Tota 10S0.0 270.0 1600.0 2820.02006 Konaktepe 210.0 Hydro 01 210.0

Uluoln + 160.0 Hydro 061 1Mo0Camlial 131.0 Hydro 081 131.0Ermune, 642.0 Hydro DSt 642.0Hydro 1 1372.0 Hydro 061 1372.0Natural Gm 900.0 N.Gae - CC TEK 9oo.oImported Coal 1000.0 Coal-Steam SOT 1000.0

Sub-Total 000.0 2616.0 1000.0 441h02007 Hydro2 411.0 Hydro 081 411.0

S-Urfs 60.0 Hydro 0S1 60.0Aelnolk 90.0 Hydro 081 90.0Natural a 460.0 N.Ga- CC TEK 460.0Importod Coal 2000.0 Coal-Stem BOT 2000.0Caylrhn SI 340.0 Ugnite-Stem TEK 340.0

Sub-Total 790.0 661.0 20O0.0 3341.0200 Natural 800.0 N.s -CC TEK 1800.0

Imported Coal 1000.0 Coal-Steam SOT 1000.0SBC8 300.0 LignIte-Steam TEK 300.0

Caylrhan 92 340.0 Lignle-Stearn TEK 340.0Sub-Totad 2440.0 1000.0 3440.0

2009 N tural O 1380.0 NOs - CC TEK 1380.0,mported Coal 1600.0 Coal-Steam SOT 1600.0GOC8. 300.0 Ugnits-Stsm TEK 300.0Amah_ 600.0 UgnIte_tm TEK 600.0

Sub-ToWl 2260.0 1600.0 3760.0NINT) FIVE YEAR PLAN 004-20 7430.0 33360 7000.0 17760

20Io Hydro 3 1470.0 Hydro D01 1470.0Natural Gm 2260.0 NlOm -00 TEK 2260.0Imported Coal 1000.0 Coal-Steam SOT 1000.0film. 180.0 LgnIt-Seam TEK 160.0

Sub-Total 2400.0 1470.0 1000.0 4870.0

TOTAL (190-2010) 20078.1 13794.1 12072.0 48884.2

Soma 1.St Solu-Ooynuk Can-Lap.kP, and Seyltomer 8 1,2

- 61 -

Annex 1.6

TURKEY

SUMMARY OF RESULTS OF MAED (for GDP 1990.2010 growth: 2X)

8asic Input Information: 1983 1990 1995 2000 2010.. .. ........ ............ ..... ......... . ............... .......... ................ .. .. ........ ............... .........

Population:Total (Mitlion people) 47.283 56.583 63.180 70.370 85.100Average annual growth rate

versus base yr (X) 0.000 2.598 2.44S 2.366 2.200

G.D.P.:Total (10'9 monetary units

of base yr) 11531.801 16544.500 18266.461 20093.109 25720.879Average annual growth rate

versus base yr (X) 0.000 5.292 3.907 3.320 3.016Per capita C1003 Nu/cap) 243.889 292.393 289.118 285.535 302.243

Final Energy Results:......................................

Commercial EnergyTotat (Cwyr) 32.216 52.620 60.426 73.516 101.185Average annual growth rate

versus base yr (X) 0.000 7.261 5.381 4.973 4.330Per capita (Kwyr/cap) 0.681 0.930 0.956 1.045 1.189

Electricity DemandTotal (CGwyr) 2.823 5.570 6.930 9.652 15.956

(Ttahr) 24.727 48.791 60.707 84.551 139.7mAverage annual growth rate

versus base yr (X) 0.000 10.196 7.7(2 7.500 6.626Per capita (KwyVrcap) 0.600 0.098 0.110 0.137 0.188

CKwhr/cap) 522.9f6 862.293 960.8S1 1201.526 1642.507Ratio of electricity to Energy (X) 0.088 0.106 0.115 0.131 0.158

For an annual C(DP growth of 2%, peak demand for the vear 2010 would

reach 22.8 GW (15.956/load factor 0.7), which compares to a maximumcapacity of 22.3 (.W to be reached in 1996 through already committedexpansion projects. Any GDP growth above 2% would therefore require Pewinvestment in power generation during 1991-2010. Furthermore, even for a

very unlikely (DP growth rate of 2X, there would be a need to install an

additional capacity of 6 to 8 V.T before 2010, in order to achieve an

acceptable reserve margin.

- 62 - Annex 2.1Page 1 of 2

TURKEY

BERKE HYDROPOWER PROJECT

CUKUROVA ELECTRIC A.S.

List of Shareholders as of December 1991

PERCENT

GOVERNMENTAL SHARES TL MILLION OF TOTAL................... ............ . .............. .............................

T.C. Public Participation Fund 35,509,540 11.84%

Municipality of Adana 922,870 0.31%

T.C. Tarim Orm.Koy.Isl.Bak. 200,000 0.07%

Municfpality of Ceyhan 230,620 0.08%

municipality of Kozan 5.000 0.00%

T.C. Zirast Bankasi Gen.Mud. 11.250 0.00%

Health Center of Karaisali 82 0.00%

Kozan Mal Mudur lugu 82 0.00%............ ..........

Subtotal 36,879,444 12.29%

BANKS

Turk Ticaret Bankasi 10,854,030 3.62%

Akbank 14,567,620 4.86%

T.Is Bankasi 9,807,750 3.27%

Pamukbank 2,168,318 0.72%

T.Garantf Bankasi 1,749,398 0.58%

T.OgretmenLer Bankasi 461,250 0.15%

EmLak Bankasi 275,000 0.09%............ -----. ...

Subtotal 39,883,366 13.29%

INSURANCE COMPANIES

Anadolu Anonim Turk Sigorta SIrketI 2,929,120 0.98%

Basak Sigorta 1 199 120 0.40%

Sark Sigorta 676,870 0.23%

Tam SIgorta 375.000 0.13%

T.Genel Sigorta 369.000 0.12%

Magdeburger 34,048 0.01%

Birlik SSgorta 59,200 0.02%............ ..........

Subtotal 5,642,358 1.88%

CHAMBERS OF TRADE & COMMERCE............................

The Chamber of Industry of Adana 750,000 0.25%

The Chamber of Commerce of Adana 738,000 0.25%

The Chamber of Commerce & Industry of Mersin 7F,000 0.03%

Commerce Exchange of Mersfn 170,620 0.06%............ ..... 58%

Subtotat 1,733 620 0.58X

- 63 - Annex 2.1Page 2 of 2

TURKEY

BERKE HYDROPOWER PROJECT

CUKUROVA ELECTRIC A.S.

List of Shareholders as a. December 1991........................................

PERCEMT

RETIREMENT FOUNDATIONS TL MILLION OF TOTAL.. . ................... ............ . .......... ;........

CEAS Emk.SandIgi Vakfi 12914,325 4.30%

Akbank Tekaut Sandigi 4,305,380 1.44%

Zerbank Mem.Emekli Sand.Vakfi 2,988,370 1.00%

T.K.Koop.Mem.Emekli Sand.Vakfi 2,134,500 0.71%

T.K.Kcoop.Per.Sosy.Yard.Vakfi 1,831,620 0.61%

T.Is Bank.Mem.Emekli Sandigi 1,067,250 0.36%

Z.D.M.Mem.Must.Yard.Vakfi 727,871 0.24%

Sin.Yat.Kr.Mem.Emekli Sandigi 597,370 0.20%

Seker Sigorta Pers.Sigortacilik Vakfi 454,120 0.15%

Milli Reasurans Mem.Emekli Sandigi 196,120 0.07%

Turk Bank Munzam Sosy.Guvenlik Vakfi 133,330 0.04%

Veb Ofset MatbacIlik Yardim Sandigi 6,000 0.00%

Koc dolding Emekii Sandigi 39,370 0.01%

T.S nai Kalkfnma Bankasi 2,000 0.00%

CEAS Sosyal Dayanism Vakfi 12,000 0.00%

SubtotaL 27,409.626 9.14%

OTHER COMPANIES....... .. ....

Cukobirtik 5,212,500 1.74%

Kepez Antalya Hav.Elektrik Sant. 1,292,250 0.43%

Tuncel Pamuk Iplik Yag Sanayl A.S. 2,952,380 0.98%

Berdan Tekstil San. 454.500 0.15%

Bosse A.S. 230.620 0.08%

Haci Omer Sabanci Holding 225.381 0.08%

Endustri Holding 150.000 0.05%

Cukurova Ithalat Ihracat 61,870 0.02%

Yaltir Inasoat A.S. 56.750 0.02%

Nasa Gida Sanayi A.S. 58,330 0.02%

Adana Sanayl ve Ticaret 9,000 0.00%

Seyhan Sanayi ve Ticare: 9,000 0.00%................. . ....... ..

Subtotal 10,712,581 3.57%

Total 122.260,995 40.75%................ . .....

Individuals 177,739,005 59.25%

Total Paid-up Capital 300,000,000 100.00%3u:uas-=uzm.m3 3=3U3

TURKEYBERKE HIYDROPOWER PROJECT

Organization Chart of Cukurova Elektrik, A.S.

Shareholder8s

Bo&rd of Directors]

&Design Construction &Coordination Administration

Pover~~~~~~~~~ Planta Genagerl

Operations Project Projet r Planlning and Accounting Lea| & Design* lDeConstructign l l& Coordination J

Transmission _ Operations Security& Substations T&D Projects Construction Training and Accounting

Construction Research. ~~~~~~~~~~~~~IPersonnel

Load Dispatch InvestmentsData Accounting

Processing _Administration|Relay ang Pla|Measurement .Shareholder

Accounts 1|

Operations & |rI|H at'ntenance Taxes 11

q Workshop l q ~~~~~~~~~~~~~Finance

*Excluding Pover Plants

TURKEYBERE HYDROPOVER PROWECTCWURMA ELEKTRIK A.S.

Actual Demand-Suply Balance, 1977-1990.......................................

(in Ut)

197 978 1979 1980 1981 1982 1983 1984 1935 1986 1987 1988 1969 1990.... .... .... ... .. .. .... .... .... .... .... --- ... .... . ...

Generation by Plant........ ............ ..

SeyhanOPP Grwation 411 413 376 410 a48 370 371 384 311 241 386 460 213 301Kadincik 1 301 336 289 335 420 294 326 315 316 285 288 347 235 243Kadincik 11 238 276 234 271 338 237 247 257 247 229 220 284 183 192Turmgir 16 12 10 12 16 18 11 11 9 7 13 19 0 10

..... ..... .... - ..... ..... .... ..... ..... ... .. . . ... --- . .... ....

Total Uydro Oeneration 965 1038 909 1058 1223 919 955 966 883 762 906 1110 630 746

Nwrin Thertl PP 652 677 477 394 544 483 492 550 551 551 550 382 440 346.... .... ..... .... ..... ..... ..... ... .. ..... ..... . .... .. ...

Total 6rts Butaltion 1617 1714 1386 1453 1767 1402 1447 1516 1435 1313 1456 1492 1071 1091

Less:Statlon Loss 46 43 42 40 4 40 42 44 40 40 43 38 37 33 0

Total Net Gaeratlon 1571 1671 1344 1413 1723 1362 1405 1472 1394 1273 1413 1454 1034 1058 1

Energy Purchased...............

from TEX 209 240 517 604 449 897 1174 1482 1853 2147 2166 2152 2867 3134Frr SEKA u IDC 36 0 0 0 1 0 0 1 0 1 1 6 5 2

Suppled to Network 1815 1911 1861 2016 2173 2259 2580 2955 3248 3421 3579 3613 3906 4195

Less: Tranmissin Losses 67 78 71 83 91 93 101 126 144 175 171 192 233 236

Total Slaes 1749 1833 1790 1933 2082 2166 2479 2829 3104 3246 3409 3421 3673 3959

Of IWhch:to TEK 258 202 51 79 73 74 225 267 304 379 350 187 156 90to Cukurava region 1491 1631 1739 1855 2009 2092 2253 2563 2800 2867 3059 3233 3517 3869 oQ X

Net Purchase frmo TEK as2 of lctasales 12X 13X 29X 31X 222 41% 472 52X 60X 66% 64X 63% 782 79 ow

TURKEYBERKE HYDROPOWER PROJECTOUKUROVA ELEKTRIK A.S.

Forecost Demend-Supply Batance, 1991-2000......................... .. ............................... .. .

(In MAh)

1991 1992 1993 1994 1995 1996 1997 1996 1999 2000... .... .... ... .... .... --- .... -- ....

Generation by Plants....... ............ .. ..

S$,an 249 315 340) 340 340 340 340 340 340 340Kadinclk 1 167 285 295 295 295 295 295 295 295 295Kedinmk II 125 200 235 235 235 235 235 235 235 235Tureolr 5 10 8 8 8 8 8 8 8 8Sir 503 876 876 876 876 876 876 873 865 805Birke 0 0 0 0 0 700 1680 1675 1659 1543Aslantaf NPP 0 0 0 0 0 0 0 0 0 0Yedfooze HPP 0 0 0 0 0 0 0 0 0 0Seyhan 2 0 8 20 20 20 20 20 20 20 20

---- .... ---- .... .... ---- ... ~~ ~~~. .... .... --

Total Hydro 1049 1694 1774 1774 1774 2474 3454 3446 3422 3246

Nersin Theral PP 131 50 130 130 130 130 130 130 130 130 0%............ .... .... . .... .... ..... .... ----. .... ..... .... ----. ...

Total Gross Generation 1180 1744 1904 1904 1904 2604 3584 3576 3552 3376

less: station toss 26 18 24 24 24 30 38 38 38 36

let Generation 1154 1726 1880 1880 1880 2574 3546 3539 3514 3339

Energy Purchased................

Butk Purchase from TEK 29 25 26 28 29 30 32 34 35 37Purchase from TEK 3149 2715 2878 3217 3580 3276 2722 317r' 3682 4373Purchase from GEZENDE 0 0 0 0 0 0 0 0 0 0

Total Suppty 4332 4466 4784 5124 5489 5880 6300 6749 7232 7749

less: Transmn.Losses 285 223 239 256 274 294 315 338 362 387 ,.

Total Sates by CEAS 4047 4243 4545 4868 5214 5586 5985 6412 6870 7362 9 ::5= __=33 ==: __Q ==: = =3= =3= ___ =3:: = :4

Of Which :to TEK 29 25 26 28 29 30 32 34 35 37 0.to Cukurova region 4018 4218 4518 4840 5185 5556 5953 6378 6835 7325

Met Purchase from TEK asX of Total Sales 78X 64X 63X 66X 69X 59K 45X 50X 54X 59X

- 67 - Annex 2.4

TURKEY

BERKE HYDROPOWER PROJECT

PIKUROVA ELECTRIC A.S..........................

Average Revenue ComputationCEAS Submission to NENR, 1991

CTL '000)

January-August September-December

Excess Items Actual Program Total

The price of energy bought from TEK 186The cost of energ} bought 358,714,034 245,669,854 604,383,888The cost of energy bought from ISDEMIR-SEKA 690,485 690,485Fuel Expenses 13,064.695 22,273,177 35.337,872Foreign Debt Capital and Interest Installment 6,526,784 Ce)Depreciation Expenses CTechnical) 69,511,300Capital Amortization 2,182,543Fxchange Rate DIfferential 29,237,071personal Expenses 43,734,870 46,265,130 90,000,000Naterial Expenses 1,573,353 903,191 2,476,544Matntenance and Repafrs Expenses 664,630 4,866,971 5,331,601Miscellaneous Expenses 9,274.182 5,187,752 14,461,934Insurance Expenses 977,334 451,154 1,428,488Taxes to be paid 484,99T 4,602 531,599

Water Cost 3,608 2,617 6 225Difference of invoice for Ekinciler 5,637,838Extension and Upgrading Expenditures 5,685.075Total Operational Expenses 911,282,475Cooperation Tax + Other Taxes 56,336,799The profit after tax for dfvidend payment 37,086,591

Total Expenses 1,004,705,866Necessary Returns 1.004.705,866

Energy to be sold (NWA) 4.041,500Average Sale Price CTLI/Kh) 249

C') Thfs figure Is the fraction of Repayment Expenditures

- 68 - Annex 2.5

TURKEY

BERKE HYDROPOWER PROJECT

CUKUROVA ELEC.RIC A.S.

CEAS Electricity Sates by Customer Groups, 1986 and 1990.................................. ......................................................... ............ .

........1986------- --------1990-------

Sales X of X of Sales X of X of

(CGA) Sales Revenue (GWh) Sales Revenue

INDUSTRY

Textiles 489 15 529 13

Iron & SteeL 249 8 427 11

Cement 270 8 343 9

Chemical 237 7 245 6

Food processin 113 3 138 3

Fertilizer 66 2 66 2

Glass, Paper &

Plastic 88 3 89 2

Others 165 5 270 7o ~~~~~~.... . .... ...... ........ ... ........

Total Industry 1677 52 60 2107 53 60

TEK's DEs 989 30 33 1472 37 33

GOVERNMENT DEPTS. 65 2 2 100 3 3

AGRICULTURE AND

IRRIGATION 23 1 1 42 1 1

VILLAGES 72 2 2 105 3 2

MISCELLANEOUS 1/ 419 13 2 133 3 1.... .... . .... .... . .... ........ ..... .....

TOTAL CEAS 3246 100 100 3959 100 100

1/ Includes sates to TEK's HV grid

- 69 -TJRKEY

BERKE HYDROPOWER PROJECT £tachnL1at liLU. e4 oed R lcArie Prots t 8 8c- Arc.

RIM KANE STATUS DSTALLED CAPACITY

Undcr (NM)Zxisting Construction Propozed

Oakeu Geseud. x ISO

_ K?yraktope X 431

TarS Kadinoik I X 70

Kadinak II X 56

8ah Yuregir X0Saybana _Uei X _______ _ ___ __ 6o

______ ______ Seyhan I 60

Syhan 1 I 8

Catalan X 1S6

Imoslu X 40

Y*disoze ______ X 300

__a"k X 120

Kopiu X 189

Topakt.s X 7

Tiblar X 60

CamUce 195

Gaktas X 262

_______ _____ Menge __ _ _ _ _ _ _ _ _ _ so

Yoke X 170

Yanu I X 23

Yeaen II x 35

Korkun X 36

KenieLt __ X 15Kapus X 25

Ceyh= Aelantas X 138

sic X 284

Bcrke X 511

KiIavu%Lu 54

MnzzeLet X 120

KanCl X 55

Kandl. I x 103

lurhak 36

Total InstaULed Capacity 3916

ItQ°

X v 16.o0~~4U60a 14.00

_ _ -~~~~~~~~~~~~~~ 14000

SILX ^ KSDIL HE5-l

bo~ ~ ~ ~ ~ o

14800

a~ 04 0 5,5m 6001

a~~~~~~~~~~~~~~

4200

.14002i .200

AGI K LA M A 0

M IEVCUT 8ARAJLAR

I7 115 "AL-DEIU B^RAJLZt2 YAPILMASI1 OtU~VAEN SlARAJIARDAS QO CAVSTR1Xfluc PLANED DAMS

KUHDAOELEtTR3~SANTRALIFt

CEYHAN NEHRI BOYKESiTi3CEYHA2N RIVER '

LONGI TUDINAL SECTION

- 71 -

Attachmmnn3

REM H;fYDROPWER PROJECT

Summary of Damg and Reservoirs in Cevhan River Watershed. Ugstream of Aglantas

Name Number Purpose Status Installed Total(I,E,F) Capacity Energy

(KW) (GWh)

Aslantas 1 I,EIF Operating 138 605Berke 2 E Proposed 511 1669Sir 3 E Operating 284 725Kilavuzlu 4 I,E Design 54 99|Menzelet 5 I'E Operating 120 334Kandil 6 E Proposed 55 178Kandil I B Proposed 103Kandil II E Proposed 103Gaben 7 I ProposedAdatepe 8 I DesignKarakuz 9 I DesignKavaktepe 10 I ProposedHasanali 11 I ProposedSogutlu 12 I ProposedAyvali 13 I,F DesignSinarli 14 I ProposedOzbek 15 I ProposedKartalkaya 16 I OperatingKisik 17 I ProposedSallikaya 18 I Design

E B EnergyF - Flood ControlI - Irrigation

- 72 -

Attachment 4

Summary of Existina and Pronosed Irriatigan/Diveruion Withdrawals(Sourc-s DS! Letter to CEAS of the Oct. 17, 1985)

PROPOSEDEXISTING (2023)

PROJECT NAME ORIGIN OF WATER & LOCATION OF THE IRRIGATED WITHDRAW WITHDRAWPROJECT AREA (ha) ALS ALS

(Mm3) (Mm

3)

Karakuz Karakuz 10800 26 50

Goksun Adatepe, upstream of the dam 6485 32 32

Adatepe Adatepe, downstream of the dam 36345 85 164

Elbistan Afain Plain Adatepe, downstream of the dam 13400 0 39

Cooling watsr for Elbistan TPP Adatepe, downstream of the dam 48 95

Sisne Geben Menzelet, downstream of the dam 3610 11 25

Adiyanman Gltbasi (from Kartalkaya, upstream of the dam 3669 10 21Abasiye Regulator)

Adiyaman G8tbasi (pumping) Kartatkaya, upstream of the dam 5111 0 10

Kartalkays (pumping) Kartatkaya, downstream of the dam 8586 0 8

Kartalkays Kartalkays, downstream of the dam 22180 158 158

KiSprUagzi Kartalkaya, downstream of the dam 4160 30 36

Gaziantep Water Supply Kartalkaya, downstream of the dam 48 96

Kahramarunaras Water Supply Menzelet, downstream of the dam 0 11

Kahramarmaras Plain Menzelet, downstream of the dam 12085 2 72

Seglik Plain Menzelet, downstream of the dam 8529 0 54

Gazfantep Menzelet, downstream of the dam 15000 0 85

Istahiye Plain Menzelet, downstream of the dam 29601 0 165

Amik Plain Menzelet, downstream of the dam 105434 0 6S8

TOTAL 284995 450 1779

- 73 -

Altachment SPage 1 of 3

I-I

BE= HYDROPOVER PROJECT

Prlncigal CharacteristiCs of the Project

HydroloavMean discharge 157.67 m315Maximum flood discharge 7510 m3/sDiversion discharge 1360 m3/1

*m-iervozMaximum supply level 345.00 m ASLMaxiomum flood level 345.00 m ASLMinimum water level 288.00 m ASLMaximum storage volume 427 million m3

Minimum storage voluem 119 million m3

Reservoir area at max. re. elev 7.8 million m3

Divergion TunnelTunnel type Horse-shoeTunnel diameter 11.00 mTunnel length 493.50 mUnstream Coffer damCrest elevation 191.50 mUpstream slope 1.4/1Downstream slope 2.5/1

Tunnel SoillwavLocation Right bankNumber 2Tunnel type Circular (U/S) & U shape (D/S)Tunnel diameter 12 m - 13 m

sill elevation 290 m ASLMax discharge 2 x 2755 m3/8Control gates 2 Noslope 3.1 %Length 529.20 m, 424.20 mType of energy dissipating device Flip buckets

surface SnillwavLocation On arch damNumber 4 baysMaximum discharge 4 x 500 m3/ssill elevation 337.5 m ASLSluice dimensions 7.5 m x 11.5 m

- 74 -

Attachment 5Page 2 of 3

BOttom OutletLocation In arch damNumber 2Pipe diameter 3.00 mControl valves 2 x 2.5 m sleeve valuesDischarge 2 x 214 m3/sSill elevation 207.80 m ASL

Arch DamType Double curvature thin archHeight 201 mCrest length 270 mCrest elevation 346.00 m ASLFoundation elevation 145.00 m ASLType of arcs 600 logarithmic spiral

Variable thickness

Arch DamWidth at toe of crown cantilever 29.9 mCrest width 4.60 mConcrete volume 745 500 m3Volume of excavation 700 000 m3

Tailwater DamCrest elevation 201.00 mType Cylindrical archHeight 47.50 m

Energv Structure.

Water Intake StructureLocation Right bankNumber IGates 2Gate dimensions 2 x 7.5 x 10 mSill elevation 274 m ASL

Headrace TunnelLocation Right bankType CircularDiameter 9.30 mLength 2057 m

Surae TankLocation Right bankType Cylindrical, with diaphragmDiameter 22 m

Pressure ShaftsNumber 3Diameter 4.60 m

- 75 -

Attachment Page 3 of 3

Power Plant BuildinaLocation Right bankType UndergroundDiamensions 1 x b x h 129 x 19.75 x 44 m

TurbinesType Vertlcal axis FrancisNumber 3Rated power 170.25 MNRated head (net) 186.31 mDischarge (at full load) 100 m3/sRotation speed 231 rpm

GeneratorsNumber of units 3Type Vertical shaft-3 phaseContinuous rating 186 MVAOutput voltage 15.75 kV (or 15 kV)Frequency 50 HzSynchronous speed 231 rpmInsulation Class F

Unit FransformerNumber 10 single phase (1 as spare)Type Indoor type, oil-immersedContinous rating 62 MVANominal voltage 15.75/154 kVFrenquency 50 Hz

lailrace TunnelLocation Right bankNumber 3 U-shapeDiameter 6.30 mLength 119 m, 114 m, 110 m

SwitchvardLocation Left bank - facing powerhouseType Outdoor double busbar typeNominal voltage 154 kVNumber of baysincoming bays 3outgoing line bays 6coupling bay 1local network transformer bay 1

Power and Energv GenerationFirm power (Initial 1996) 104 MWFirm energy 920.7 GWh/yearSecondary energy 748.15 CWh/yearTotal energy 1668.85 GWh/year

J~~~~~~~ *'~ ,' ,," _; _, UBAA.t2 |E

.4 LM~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

DAMA *uIDxKn IWIRN

Cross Section ~ ~ ~ ,,,&tagff. H.TA ~ ~ SLLAV1 Br uga.AfBM

un ~ ~~~~~0

"SlaKfURES ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~~~~~~.,t*.C

___ ___ ___ __ iatn 1 2 >

- 77 - Annex 3.1Page 1 of 12

TURKEY

BERKS HYDROPOWER PROJECT

Technical Assessment of the Dam and the Powerhouse

General

1. Origin of the Project Component: Four major rivers are locatedwithin the 9EAS service area: the Goksu and Tarsus rivers in Icel Province, andthe Seyhan and Ceyhan rivers in Adana Province. Of these, the Ceyhan River thelargest, in terms of both drainage area and discharge, and constitutes animportant regional source of irrigation water and hydroelectricity.

2. A summary of existing and proposed hydroelectric projects on thesefour rivers was provided in Attachment 1. Of the 31 projects listed, theproposed Berke project provides the highest installed capacity, and its 7.8 km2

reservoir is among the smallest. The project is located in a rocky, isolatedgorge, along stretch of the Ceyhan River: between the two existing dam/reservoirsystems: one located immediately upstream of the Berke reservoir at Sir, and theother 2 km downstream of the Berke dam at Aslantas. This segment of the CeyhanRiver has a steep gradient (190 m of available head over a distance of 25 km) andthe Berke project was designed to make use of this hydraulic potential.

3. A detailed water resources development master plan (IECO, 1966) wasprepared for the Ceyhan River Basin in 1966 which proposed a series of dams andreservoirs along the length of the Ceyhan River for water supply, irrigation andhydroelectricity. Eight out of a total of twenty-seven projects have be3ncompleted to date and the remainder are projected to be completed within the next20 to 30 years. The Berke hydroelectric project was one of the projectsidentified in the rECO master plan.

4. The Berke hydroelectric project has long been considered animportant potential source of electricity to the region and has been the subjectof series of feasibility studies (IECO, 1966; OTCA, 1969; Temelsu, 1978;Energoproject, 1984; C&B/Aknil, 1990).

5. Numerous alternatives to the proposed project were e aluated duringthe planning process. Alternatives considered included variations in the planttype, location, dam height and project layout.

6. Project History: The first Berke Feasibility Study, conducted forDSI by IECO in 1966, envisaged two alternative layouts; either a high dam (207m) situated at the Berke site with a power-house located immediately downstream,or a run-of-river dam located further upstream with a 9340 m power tunnel whichwould relay the water to a power plant located slightly upstream of the Berkesite. This second alternative was designed in the event of leakage problemsassociated with the construction of a high dam in karstic limestone (IECO, 1966).

7. In 1969, the Japanese Overseas Technical Corporation Agency (OCTA)was commissioned to evaluate the projecc by DSI. Their --eport concluded that a310 meter high dam could be constructed at the Berke site without inducingleakage into adjacent valleys. No significant karstification was observed at thedam site and u.he OCTA report indicated that any foreseeable problems could beresolved by means of grout curtains (OCTA, 1969).

- 78 -Anne 3._1

Page 2 of 12

8. The project was re-evaluated again in 1979, this time at therequest of the Electric Work Administration (CIE), by the firms Temeslu andEnergoproject, who designed a run-of-the river dam at Duzkesme, a 13.8 km powertunnel and a power station at Berke (Temelsu, 1978; Energoproject, 1984).Although the Duzkeeme-Berke scheme did not make full use of the available headbetween Sir and Aslantas, this layout was proposed because of concerns aboutleakage from a high dam located at the Berke mite.

9. Based on the conclusions of the feasibility study, EIE completedthe final design documents and technical specification for the bidding documentsin the year 1983. The final design divided the Ceyhan-Berke scheme in twophasest

(a) Phase 1 - the Sir dam and the powerhouse; and(b) Phase 2 - the Duzkesme dam and the powerhouse at Berke.

10. The final design proposed thin arch concrete dams at Sir andDuskesme (located about 7 km downstream of the Sir dam). The powerhouse for theSir dam was an outdoor type located near the toe of the dam, while that for theDuzkesme dam was an underground type located at Berke and connected to the damwith a seven-meter diameter tunnel about 11 km in length. The installedcapacities proposed at Sir and Duzkesme (Berke) were 273 KW (3x91 NW) and 168 MW(3x56 MW), respectively. The Bank's consultants of the preappraisal team of SirProject reviewed the final design prepared by EIE. The Bank's consultantscommented that the second phase of the scheme (the Duzkesme dam and the Berkepowerhouse) needed further investigations -- especially the areas of the tunneland the powerhouse -- for proper estimation of its costs.

11. As the project progressed, however, it became evident that therewere a number of problems associated with construction of the 13.8 km tunnel.Unfavorable geologic conditions raised serious questions about the time arad costrequired for tunnel construction. Furthermore, the tunnel diameter was limitedby economic coneiderations, which in turn, limited the installed capacity of theproject. When further geological studies at the Berke site indicated that risksof leakage were limited, the Duzkesme-Berke design was abandoned in favor of theproject described herein.

12. The Redesian of the Project Component: The firms of Coyne etBellier and Aknil were commissioned in December 1988 oy QEAS to draw up, undera grant from the French government, the feasibility study of this project.During the planning and design phase, a number of different alternatives wereevaluated, including the type of dam, height and design capacity, and the layoutof the hydraulic condults and power station. These design alternatives arediscussed below.

13. Two possible dam types were considereds a high rockfill dam witha clay central core and a concrete arch dam. The concrete arch dam was selectedover the rockfill dam for the following reasons

- the deep, narrow gorge and competent limestone walls thatcharacterLze the Berke sLte are ldeal for the constructlon ofan arch dam;

79- Annex 3.1

Page 3 of 12

the narrowness of the gorge makes access difficult in the case

of a rockf ill dam, with respect to material haulage, placement

and compaction;

the presence of the Kemerkaya fault requires considerable

excavation and/or prevents the design of a steep slope on the

upstream face of the rockfill dam;

- no core material was available in the immediate vicinity of

the site (i.e. over 30 km away); and

- due to the above constraints, a high rockf ill dam was 27% more

expensive than the concrete arch alternative.

14. An analysis of three alternative dam heights (176, 186 and 201 m)

was conducted to determine the most efficient project design. A 201 high dam

with a full supply level of El. 345 was determined to be the most economically

favorable for the project (see C&B/Aknil, 1990 for details). The reservoir area

does not change significantly with dam height, on account of the steepness of the

canyon walls.

15. The design and location of the hydraulic conduits and power station

was determined by the geologkc conditions immediately downstream of the dam. The

Kemerkaya fault crosses the reservoir upstream of the dam and parallels the left

bank for a distance of approximately 800 m. Consequently, several areas of the

left bank are characterized by heavily fractured and tectonified rock, which is

not suitable for the excavation of large caverns or tunnels. In addition, both

banks of the river are susceptible to landslides over a distance of approximately

700 m downstream of the dam. In 1981, a landslide on the right bank caused the

river water level to rise by approximately two meters in this area.

16. Three alternative conduit and power station configurations were

evaluated from the perspective of both physical and economic considerations. All

were located in the right bank to avoid problems associated with the Kemerkaya

fault zone.

- Alternative 1 consisted of a 2057 m long headrace tunnel, a

power-house located in a rock spur across from the Ilica

thermal spring buildings and three 120 m long tailrace

tunnels.

- Alternative 2 consisted of a power-house located immediately

downstream of the dam and a 1500 m long tailrace tunnel

discharging at Ilica. Access to the power-house q via a

1500 m long tunnel, running parallel to the tailraw tunnel.

- Alternative 3 consisted of a power-house located immediately

downstream of the dam with a short tailrace tunnel and a long

access tunnel, as in Alternative 2 above.

17. These alternative configurations were evaluated on the basis of

seven different rated discharges (159 to 415 m3/s) to determine the most

efficient design capacity of the system. It was found that the rates of return

were most favorable for Alternative 1, with the optimum obtained at a nominal

discharge of 300 m3/s (see Final Design Report, C&H/Aknil, 1991 for details).

- 80 -Annex 3.1

Page 4 of 1 2

This alternative is also the only one that avoids the right bank landslide areamentioned before.

18. RelationshiR with DSI Master Plan and Operational Alternatives:The management and distribution of water resources in Turkey is administered bythe General Directorate of State Hydraulic Works (DSI) under the Ministry ofEnergy and Natural Resources. Priorities for water use have been established,in order of decreasing importance as follows: potable water supplies, irrigation,flood control and hydropower. This ranking reflects the importance of irrigatedagriculture in Turkey's long-term development plans.

19. A water resources development master plan was commissioned by DSIfor the Ceyhan, Seyhan, Berdan, Develi and Amik Basins and was completed ia 1966(IECO, 1966). This document proposed a series of irrigation and hydropowerprojects in the Ceyhan River Basin, many of which have been completed or are inthe process of construction. Although the timing and some of the details of thisoriginal master plan have changed over the years, the basic development plan hasbeen followed to a large degree. Attachment 2 depicts the location of existingand proposed dams, reservoirs and irrigation projects in the Ceyhan River Basin,compiled from maps provided oy DSI's Adana and Ankara offices in July 1991.Further details on dams located upstream of Aslantas are provided in Attachment4. A summary of existing and proposed irrigation works are listed in Table 3.2,based on DSI correspondence to gEAS (Letter No.123.2004/5351, 17 October 1985).According to this table, the volume of water diverted from the river foragricultural purposes will increase by about three times by the year 2023, withthe largest volume diverted to the Amik Plains irrigation project. This projectinvolves the irrigation of 105434 ha and will require an annual water withdrawalof 658 Mm3 from the Menzelet reservoir.

20. Hydraulic inflows to the Berke reservoir, and consequentlyelectricity production, will be largely controlled by the operating conditionsof the upstream diversion works. Between the 1996, when the Berke project isscheduled for completion, and 2023, when the irrigation projects are scheduledfor completion annual river flows are projected to decrease by about 1100 Mm3

(24%), due to additional diversion from upstream structures for the increasedirrigation demand.

21. To evaluate the effects of these diversions on the Berke project,a reservoir operation simulation study was conducted using the SIM program. Thismodel simulates the monthly balance of water displacements in a system ofinterconnected reservoirs, while taking into account the operational 'nd physicalconstraints of the individual reservoirs, evaporation losses and the requirementsof irrigation projects. Hydraulic inflows to the Berke system were simulated forfour different years: 1996, 2001, 2010 and 2023. The following operatingconditions were predicted using this model.

1966: No shortages predicted for irrigation projects.The minimum operating level for the Berke reservoir (289 m)occurs during 2 months out of a total 528 months (0.4% of thetime).

2001: Slight shortages are predicted for irrigation projects locateddownstream of Kartalkaya dam.The minimum operating level for the Berke reservoir occursduring 24 months out of a total 528 months (4.5% of the time).

- 81 - Annex 3.1

Page 5 of 12

2010: Very slight shortages are predicted for Menzelet, in additionto Kartalkaya.

2023: Significant shortages are predicted for Menzelet (2 years outof 44 years), in addition to Kartalkaya.The minimum operating level for the Berke reservoir occursduring 106 months out of a total 528 months (20% of the time).

22. Currently (beginning of October 1991), a formal Protocol is beingnegotiated between DSI and gEAS, whereby it will be guaranteed that 9EAS beprovided with the quantities of water promised (personal communication, CEAS).The DSI letter confirming the upstream development has been already received bygEAS. The Protocol, which is going to address other aspect of the Ceyhan riverwater management is expected to be signed by about end of June 1992.

23. Proiect Layout of Structures: The proposed project layout of structuresincluding the main arch dam, the downstream lower arch dam (for energydissipation), dams, headrace tunnel, surge tank, spillway tunnels, diversiontunnel, penstocks, underground powerhouse, and tail race etc., appear to havebeen carefully studied on the basis of: (i) geological conditions; (ii) rockbedding planes; (iii) comparative advantage; and (iv) suitability and ease ofaccess and construction. Based on the relevant technical aspects, the POE andBank experts are in general agreement with proposed layout of structures, and inparticular:

(a) all permanent structures (intake structures, headrace tunnel,surge tank, spillway tunnels, penstocks, and underground powerhouse) being located on right abutment.

(b) the powerhouse located downstream alongwith a long tunnel insteadof adjacent to dam, for increased generation and avoiding thetechnical concerns of the possibility of left bank slides andblockage of the tail race.

Geologv

24. The Berke project site has been the subject of a series of geologicinvestigations since the 1960s, when it was initially identified as a potentialdam site (Caglayik, 1970, 1971; Ayaclioglu, 1972; Aknil-Sial Group, 1988;Demirtaeli, 1988; ozgul and Arpat, 1988, 1989; Knobel, 1989; Ozgul and Arpat,19901 ChB/Aknil, 1990).

25. Stratigraphic and structural interpretations of the regional geologyhave evolved as the geologic data base has grown, and many of the details willundoubtedly continue to evolve as more data becomes available In preparing thefeasibility report for the project, these previous investigations were reviewedand large quantities of new data were collected and analysed, including 6395 mof borehole data, 2203 m of adit data from exploratory galleries and a seismicsurvey. The paragraphs below summarize the lithologic, structural and seismicfeatures of the region.

26. LithQlo&X and Stratigraphv: The lithology in the vicinity of the Berkesite consists largely of stratified limestone and dolomite deposits, inassociation with a variety of other rock types, includiug schists, quartaites,ophiolites and volcanic and marine deposits.

- 82 - Annex 3.1Page 6 of 12

27. These various rock types are organized into two fundamental units: anolder, 'autochthonous' unit (deposited in situ), and a younger, 'allochtonous'unit (originating elsewhere) which was emplaced as an overthrust nappe(C&B/Aknil, 1990).

28 The autochthonous unit consists of a series of Paleozoic schists,dolomites, limestones and quartzites which are overlain by Mesozoic-agedcarbonates. The relatively impervious rocks of the Paleozoic series outcrop tothe east of the project site. The carbonate deposits of the Mesozoic seriesoutcrop at the project site and consist of five separate units: the Akcinar,Sulucadere, Colak, Berke and Ilica Formations. Two of these formations, theSulucadere and Colak, contain impervious layers which play an important role inthe watertightness of the reservoir (Ozgul and Arpat, 1988, 1989, 1990). Thesetwo formations are described in further detail below.

29. The Sulucadere Formation underlizs the reservoir itself, and consistsof a lower dolomitic section, a middle section of alternating dolomites andlimestones, and an upper limestone section. Two impervious clay layers have beenidentified in the upper part of the dolomitic section which play a fundamentalrole in the watertightness of the reservoir. These clay layers, identified asTRskl and TRsk2, are 50 m and 120 m thick, respectively (Demirtasli, 1988; Ozguland Arpat, 1988, 1989, 1990).

30. The Colak Formation consists of a thin layer of cherty limestoneoverlain by impervious bed of volcanic ash deposits (tuffites) approximately 60to 100 m thick. These tuffites are overlain by the calcareous Berke Formation,which is capped in turn by the Ilica Formation (Ozgul and Arpat, 1989; C&B/Aknil,1990).

31. The rocks of the allochtonous unit outcrop to the west of the projectsite and consist of a combination of ophiolites, volcanics and deep marinedeposits (Ozgul and Arpat, 1988). This relatively impermeable unit also playsan important role in the watertightness of the proposed reservoir.

32. The limestones and dolomites in the vicinity of the Berke dam site donot show widespread karstification, with the exception of an area located on theleft bank, near the Xemerkaya fault (Ozgul and Arpat, 1988). Karstification isthe process by which solution channels form in carbonate rocks. These channelsmay range in size from less than a centimeter to tens of meters in diameter andfrequently form above impervious layers or along fractures or faults. Wherepresent, karstic strata may constitute a severe source of leakage.

33. The lack of karstification at the Berke site may be attributed in partto the widespread occurrence of dolomite, which is theoretically less solublethan limestone, and to the recent regional uplift of the region which wasaccompanied by rapid lowering of the hydrographic system (C&B/Aknil, 1990). TheXemerkaya karst is located at an elevation well above the future water level ofthe reservoir, and appears to be a fossil karat system which formed when theriver flowed at a higher elevation (C&8/Aknil, 1990).

34. Structure: The stratigraphic sequence described above has been subjectto multiple periods of folding, faulting, uplift and erosion. Structuralinterpretations are complicated by difficulties of access and by the abundanceof rcck slides and talus. A gross simplification of the structural 1Matory ofthe region is provided in feasibility study. As indicated in this study, the

- 83 -

Annex 3.1Page 7 of 12

autochthonous unit was subject to extensive folding, prior to the emplacement ofthe allochtonous nappe from the west. The entire lithologic sequence was thenfractured by a series of NE/SW-trending thrust faults (N300E to N40°E), which dipto the west at angles of 55-80°.

35. The most important fault in the vicinity of the Berke dam site is theKemerkaya fault. This fault crosses the Ceyhan River just upstream of the damand runs northeast, paralleling the riverbed. This fault has displaced the upperunits of the Sulucadere Formation over the clay layer TRsk. Immediately upstreamof the dam axis, the fault splits into two major branches which bound a shearzone composed entirely of intensively folded and faulted TRsk (C&8, 1990). Noneof the faults present morphological evidence of recent seismic activity (C&B,1990).

36. Watertightness: The initial feasibility studies for the Berke dam sitewere discontinued because of concerns about the watertightness of the reservoirand dam abutments. A high rate of leakage could have serious consequences, bothwith respect to the viability of the hydroelectric project itself, and in termsof the regional hydrology. Therefore, subsequent studies focused on theidentification and tracing of potential sources of leaks (e.g. karstic limestoneand faults), as well as the identification of impervious layers in the region.

37. A review of topographic maps for the region indicates that only threeareas in the project vicinity have surface elevations of less than 350 m andcould thus potentially be affected by leakage from the reservoir. These are theAndirin Valley to the northeast, the Sabun Suyu Valley to the south and thedownstream portion of the Ceyhan River valley.

38. The risk of subsurface leakage to the Andirin valley is consideredunlikely, as the limestone strata which underlie this valley are separated fromthose underlying the Berke reservoir by the impervious ophiolitic deposits of theallochtonous series (Eroskay et al, 1978; Aknil-Sial, 1988; Ozgul and Arpat,1988). Similarly, it appears that the Sabun Suyu area is protected fromsubsurface leakage by the presence of a hydrologic barrier between the reservoirand valley (C&B/Aknil, 1990). Therefore, the Ceyhan River valley has been theprimary focus of studies on the watertightness of the dam.

39. Two impervious stcata have been identified in the vicinity of theproject site: the volcanic tuffites o' the Colak Formation and the clay layersof the Sulucadare Formation. These layers are of critical importance in ensuringthe watertightness of the dam and reservoir, and thus considerable energy hasbeen expended in tracing these strata both horizontally and vertically (Ozgul andArpat, 1988, 1989, 1990).

40. The tuffites of the Colak Formation outcrop along the right bank of theCeyhan River at an elevation of 170 m and roughly parallel the reservoir to apoint approximately two kilometers upstream of the 'am site. At this point, thetuffite bed descends to the level of the river, and thus no longer serves as aneffective barrier to potential seepage to the limestones of the Berke Formationwhich lie to the west (C&B/Aknil, 1990). The maximum seepage gradient from thisarea (5°/.-) would result in negligible water losses, unless continuous openkarstic solution channels were present. No surficial karstic features have beenobserved in this area at an elevation of less than 350 m. However, in the eventthat subsurface leakage paths do exist, the proposed grouting layout will ensurethat these can be detected and remedied (C&B/Aknil, 1990).

- 84 - Annex 3.1

Page 8 of 12

41. On the left bank, the clay-bearing strata TRsk2 of the SulucadereFormation acts a an impervious layer which generally parallels the Kemerkayafault. The impervious nature of TRsk2, as well as the fact that the ground waterdrainage basin is closed toward the south, is confirmed by observations ofgroundwater levels in drill holes. This data indicates that the groundwatertable rises to the east and south and that the direction of groundwater flow willalways be towards the reservoir in this area (Coyne et Bellier, 1990).

42. The proposed grouting scheme consists of a grout curtain constructed&sear the right shore of the reservoir which extends upstream from the dam for adistance of 800 m. From this point, the curtain turns to the northwest andcontinues for an additional 800 meters, passing through the tuff beds and up tothe Berke formation. The number of galleries and intensity of grouting will varyfrom place to place, as required by site specific hydrogeologic conditions(C&B/Aknil, 1990).

43. The Berke project has many similarities to a recently completed (1983)dam and hydroelectric project at the Oymapinar site, on the Manavgat River insouthern Turkey. This project was design by Coyne et Bellier and consists of a185 m arch dam and a 540 MW underground powerhouse situated in an area of karsticlimestones. A grout curtain of similar designed to that proposed at Berke wasconstructed and has been successful in preventing leakage from the reservoir anddam abutments (ozis and Yanar, 1984).

44. Seismicitv: The tectonic setting of western Turkey is controlled by theinteractions between the African, Arabian and Anatolian continental plates. Theseismic activity and crustal deformation observed in this area is the result ofthe convergence of the African and Arabian plates with the Anatolian plate.These plates and their component blocks are separated by major fault zonestncluding the Dead Sea Fault, North Anatolian Fault and East Anatolian Fault.

45. The closest of these, with respect to the Berke site, is the EastAnatolian Fault (EAF). This fault has been active since the Pliocene and has atotal observed displacement of 22-27 km, implying an average slip rate of5 mm/year (Arpat and Seroglu, 1972, 1975; Yalcin, 1978). The EAP consists of14 separate fault segments (Barka and Kadinsky-Cade, 1988), which can be groupedinto 5 segments which are capable of inducing strong earthquakes. Of these, the110 km-long Tetirlik-Turkoglu segment lies closest to the study area, 25 to 40 kmaway.

46. According to historic records, the EAF has been the site of severalearthquakes greater than magnitude 8.0 on the Richter scale. Most of theseoccurred before 1000 A.D., the most destructive occurring in 995 A.D. (Ambraseys,1970). The Tetirlik-Tr-koglu fault segment has not experienced a major shocksince the 12th century. During this century, several earthquakes of moderatemagnitude, but greater than 6.5 on 4- e Richter scale, have been recurded alongthe EAF, including the earthquakes of 1905, 1908 and 1971.

47. Recorded seismic data for the project area was obtained from the USGSOlobal Hypocenters Database (1939-1988) and from other sources. Seismic activityin the region is characterized by shallow earthquakes (less than 5C km in depth)of moderate to low magnitude. According to this figure, the strongest recordedearthquakes in the vicinity of the Berke site (1945, 1951) measured 6.0 on theRichter Scale and occurred at a point approximately 75 km to the west. Smallershocks (less than 6.0, Richter Scale) have occurred within 10 to 40 km of the

- 85 - Annex 3.1

Page 9 of 12

site (Coyne et Bellier, 1991). No surface breaks have been associated with any

of these earthquakes.

48. Seismic Risk: Two alternative methodologies were used: a probabilisticapproach, which assumes an equal probability that an earthquake will occur at any

point in the area, and a deterministic approach which takes the regional tectonic

setting into account.

49. The probabilistic analysis (Cornell-McGuire method) developed for the

Feasibility Report was based on the methodology and assumptions used for the Sir

Dam site, situated 20 kilometers to the north (Energoproject, 1982). Using this

methodology, a peak soil acceleration of 190 cm/s2 was adopted for the MaximumProbable Earthquake (1000 year return period) (Coyne et Bellier, 1990).

50. The deterministic approach was conducted in accordance with the latest

recommendations of the International Commiraion on Large Dams (ICOLD, 1989) and

requires the analysis of critical seismogenic sources and the assignment of

maximum earthquake magnitudes. Design criteria are then obtained by considering

the most severe combination of the maximum magnitude and minimum distance,independent of the return period. Two design criteria are determined using this

approach: the Maximum Design Earthquake (MDE) and the Operating Basis Earthquake

(ODE). The MDE will produce the maximum level of gr..und motion for which the dam

should be designed. When subjected to this seismic load, the impounding capacity

of the dam must be malntained. The ODE is the level of ground motion at which

only minor damage is acceptable. Following an earthquake of this magnitude, the

dam, appurtenant structures and equipment should remain operational and damagesshould be easily repairable.

51. For the Berke dam analysis, Tetirlik-Turkoglu segment of the WA,

located 25 to 40 km from the dam site was assumed to be the critical aeismogenic

source. Five alternative methods were used to determine the MDE based on

documented relationships between earthquake magnitudes and fault parameters such

as rupture length, rupture area, slip rat.e, total displacement and seismic moment

(Slemmons, 1982t Wyss, 1979; Woodward-Clyde, 1979; Hanks and Kanamori, 1979).

These methods yielded fairly consistent results, ranging from 7.3 to 8.1.

Therefore, a magnitude of 7.5 to 8.0 was recommended for the MDE. Peak soil

acceleration values derived from an earthquake of this magnitude ranged from 0.14

to 0.3 g (Coyne et Bellier, 1991). An OBE of 6.0 t'. 6.5 was selected based on

a review of the regional seismic data, which corresponds to Peak soil

acceleration values ranging from 0.04 to 0.14 (Coyne et Bellier, 1991).

52. The results of the two seismic risk studies are ln close agreement.

Therefore, the design parameters proposed for the Berke dam project seem both

appropriate and well documented.

53. Motion accelerographs shall be installed in the dam and its foundation

and will monitor any seismiclty.

54. Reservoir Induced Seismicity: The question of the potential of induced

seismity for Berke dam and the impacts of the project on geologic structures,

particularly wlth respect to the Kemerkaya fault was studied in detail. A fiold

survey of this fault revealed no morphological evidence of recent seismic

activity (C&B/Aknil, 1,90). The following discussion analyses the unlikely or

very limited extent of the reservoir induced seLimicity.

- 86 - Annex 3.1

Page 10 of 12

55. There have been several documented cases of seismic evants induced bythe filling of large reservoirs (e.g. Xoyna, Krematoa, Kariba), with maximumrecorded magnitudes of 6 to 6.5. The impoundment appears to act as a modifyingor triggering phenomenon, whereby elastic strain release is accelerated oradvanced. It le now accepted by the ucientific community that reservoirimpoundment could produce reservoir-induced seismicity only in those systemsalready near failure; i.e. the naturally accumulated elastic straln release istriggered by the impoundment of the reservoir. According to Vladut (1988),induced seismicity is of greater concern in areas with low levels of naturalseismicity. In areas with high levels of seismic activity, it may increase thefrequency of seismic events, but is unlikely to increase the magnitude.

56. The physical mechanism responsible for induced seismicity is not fullyunderstood, but appears to be related to higher fluid pressures resulting fromincreased head. Stress changes resulting from surface loading may increase thelikelihood of crustal failure in areas of normal and transcurrent faulting, butmay inhibit failure in areas of thrust faulting. Induced seismicity mainlyoccurs in areas that combine steeply dipping faults, relatively high strain ratesand either extersional or horizontal shear strair..

57. Tectonic forces in the Berke project area are primarily compressive, asindicated by regional thrusting and folding. The reservoir area appears to beseismically much less active than along the East Anatolian Fault zone and noactive faults have been identified close to the reservoir. This suggests thataccumulated elastic strain related to the convergence of the African, Arabian andAnatolian plates is mainly released along the East Anatolian Fault zone. Forthese reasons, it is unlikely that strong earthquakes will be triggered by theimpoundment of the Berke reservoir.

58. The proposed Berke reservoir lies over two crustal blocks separated bythe Kemerkaya fault. With this geometry, stress changes resulting from surfareloading will be roughly equivalent for each block and will not be a determinantfor crustal failure. Given the dimensions of the faults identified in vicinityof the reservoir (Hanks and Kanamori, 1979; Kanamori, 1977)), if an inducedearthquake occurs, its magnitude should not exceed 4.0. Under the worst casescenario (earthquake of magnitude 4.0, located in close proximity to the dam),horizontal peak accelerations will be less than those taken in account in damdesign.

59. The reservoirs associated with the Sir and Aslantas dams areconsiderably larger than the Berke dam reservoir and are located in tectonicallysimilar setting. No seismic events were recorded during the filling of thesereservolre (source: personal commurnications, 9EAS and DSI). In any case, theBerke dam has been designed to withstand earthquakes of up to a magnitude of 8.0on the Rlchter Scale, which is well above the world strongest recorded reservoirinduced seismicity event.

60. The strong motion accelerogaphs installed in the Aam and its foundationwlll monltor any induced seismicity.

61. RLvyer and watersheds: The Ceyhan River originates in the high plateauto the east of Mount Ercyias and flows southwest into the Gulf of Iskenderum,crossing the Amanos Y,untain. It is 365 km in length, from source to mouth, and

- 87 -Annex 31Page 11 of 12

is the most important source of water in the region. Numerous tributaries jointhe Ceyhan along its course. Within the future reservoir area, these include theCagirgan, Toprakhisar (which is the main one, and falls into the Ceyhan at KererBanisi), Kayaduldul, and Suluca, in order from north to south. The Ceyhan Riveris not navigable in its natural state, although small fishing boats may be ableto navigate on the various reservoirs constructed along the length of the river.

62. At the Berke dam site, the Ceyhan River has a catchment area of13,222 km2, 98% of which (12,950 W2) is located upstream of the Sir dam site.Land uses within the catchment area are characterized by agriculture, forests,villages and a few towns.

63. Hater Availability and Flooding: Thirty-five stream gauging stationsare maintained by DSI along the Ceyh3n River and its tributaries. 1935-1985records from ten of these gauging stations and from the Kartalkaya reservoir wasused in estimating the surface water potential for the Berke reservoir(C&B/Aknil, 1990). The average yearly run-off to the Ceyhan River was calculatedas 4817.75 x 106 m 3, equivalent to an average flow of 153 m3/s. Monthly averageflows range from 145 x 106 m3 in September to 894 x 106 m3in April. Annualflooding is caused by a combination of rainfall and snowmelt and occurs duringthe period December through May. A flood frequency analysis was conducted andflood hydrographs were developed for various return periods. (C&B/AknilFeasibility Report).

64. The proposed reservoir has a surface area of 7.8 Wm2 at a maximum waterelevation of 345 m and contains a maximum storage volume of 427 x 106 m3.Reservoir morphology is long and narrow, measuring approximately 25 km in lengthand 300 meters in width. With the full supply level (345 m), the reservoir willbe quite deep, with an average depth of 55 m and a maximum depth of 186 m. Anevaporation rate of 1209 mm/year was calculated in the C&B/Aknil 1990 Report,based on local climatic conditions at the site. The calculated retention time(reser,oir volume divided by average discharge) is approximately 32 days.

65. Impact of Dam Failure: The impacts of the dam failure have beenevaluated on dwellings located downstream of the reservoir, the Katalepe AslantasNational Park, and the Aslantas dam. The computations are based on theassumption that there would be a total and instant failure of the dam. For theregion of the valley located immediately downstream of the dam, computations ledto a peak discharge of 600,000 m3/s. Taking into account the shape of the Berkereservoir and the flow in the 2 km of valley preceding the Aelantas reservoir,the peak discharge will be reduced to 230,000 m3/s at the entrance of theAslantas reservoir. The relatively favorable shape of the reservoir results ingeneral, in damping the transient effects. The study casts a light upon theimportance of two parameters:

* the water level of the Aslantas reservoir at the time of failures

* the speed at which the spillway gates of the Aslantas dam areopened.

* The main resulting conclusion is the necessity to monitor and analyseon a regular basis the readings of the instrumentation (pendulum.,extensometers, joint measurement devices, etc.) scheduled forinstallation at Berke dam for dam safety monitoring.

- 88 - Annex 3.1

Page 12 of 12

* It appears necessary to severely apply the regulation whereby it isforbidden to settle within the drawdown zone of the Aslantas reservoir.This interdiction could be brought up to 160 m.a.s.l., unless in caseof an alert there is a stricter order to limit the water level of thereservoir.

66. Hydraulic Model Test: 93AS (under the contract with DSI) is carryingout all the required hydraulic model tests.

- 89 -

fnnex 3. 2Page 1 of 2

BERKE HYDROPOWER PROJECT

Transmission Lines and Substations

1. The project component includes:

(a) about 30 km of transmiusion lines to connect the Berkepowerhouse switchyard with existing 154 kV system;

(b) about 700 km of sub-transmission lines (154 kV and below) andabout 1,350 MVA of transformer capacities at its VEAS(existing and planned) substation required for meeting VWASregional system's demand up to the year 2000.

2. The list of the sub-transmission lines and substations included inthe project component are given in Table 3.2.1 and Table 3.2.2.

Table 3.2.1: List of Subtransmission Lines

am Characteristi-A Lenath km

lak 2 - Antk 2 154 kV 1 x 795 45Berke - Bahbc 154 kV 2 x 795 21Minsi - Barke 154 kV 2 z 795 88Bahoc - Iak 3 154 kV 2 x 795 62Kadirli - Berke 154 kV 1 x 795 33Isk 2 - Isk S 154 kV 2 x 795 4Cibadlye - Karahan 154 kV 1 x 795 55Nacart - Texmlk 154 kV 2 x 795 15Teriik - Toce 154 kV 2 x 795 55Karahan - Tece 154 kv 1 x 795 80Tasucu - Toee 154 kV 1 x 795 55Tasucu - Gesends 154 kV 1 x 795 38Gesende - Anemur 154 kV 1 x 795 60S. Adana - Sasa 154 kV 2 x 477 18Kosan - Kadirli 154 kV 1 x 477 35S. Adana - Incirlik 154 kV 2 x 477 18Zak 1 - Gubre Fab. 30 kV 2 x 477 15Ikizler-Frea Zone 30 kV 2 x 477 10Misis-T1am Enorji 30 kV 2 x 477 10Milsl - Incirlik 30 kV 2 s 477 20

Total 737

Zaulnment Reouired

Conductor 477, 795 KQW ACSR 5630 tConductor 154 kV 2 z 795 MM4Hardware 154 kV 2 z 477 MNWIvuulator U-60 BL, UF-60 BL

U-100 BL, U-120 BSUP-120 B8 204212 Ec

Insulator 154 kV 2 x 795 MNWHardware 154 kV 2 z 477 MCMShield Wire 70 2 at 870 t

- 90 -

Annex 3.2Page 2 of 2

Table 3.3.2: List of Substations

0. NAME EQUIPMENT ADDITIONALCAPACITY !N

WYJA

A SUBSTATIONS TO BE EXTEWDED

01 Nacarli Substation 154/30 kV, 2 x 50/63 MVA Power Transformers 1004 x 154 kV Feeders

02 Karahan Substation 154/30 Kv, 2 x 50/63 MVA Power Transformers 1001 x 154 kV Feeders

03 CihadLye Substation 154/30 kV, 1 x 50/63 MVA Power Transformers 501 x 1".4 kV Feeders

04 Ikizler Substation 154/30 kV. 2 x 50/63 MVA Power Transformers 100

05 Mntakya 2 Substation 154/30 kV, 3 x 50/63 MVA Power Transformers 1503 x 154 kV Feeders

06 Misis Substation 154/30 kV, 2 x 50/63 MVA Power Transformers 1003 x 154 kV Feeders

rsNEW SUBSTATIONS EQUIPMENTS

01 Toce Substation 154/30 kV, 3 x 50/63 MVA Power Transformers 15012 z 154 kV Feeders

02 S. Adana Substation 154/30 kV. 3 x 50/63 MVA Power Transformers 15012 x 154 kV Feeders

03 Bange Substation 154/30 kV, 2 x 50/63 MVA Power Transformers 5012 x 154 kV Feeders

04 Iskenderun 3 Substation 154/30 kV, 3 x 50/63 MVA Power Transformers 15012 x 154 kV Feeders

05 Kadirli Substation 154/30 kV, 2 x 25/31.25 MVA Power Transformers 506 x 154 kV Feeders; 12 x 30 kV Feeders

06 Sasa Substation 154/30 kV, 2 x 50/63 MVA Power Transformers 1006 x 154 kV Feeders

TOTAL 1250

C EQUIPMENT REQUIRED Amount

1 Power Transformers 154/30 kV, 50/63 HVA Onan/Onaf 27

2 Circuit Breakers 170 kV Gas Insulated, (3), (3+1) Phases 82

3 Voltage Transformers 170 kV 187

4 Current Transformers 170 kV Capacitive Voltage Transformers 229

5 Shunt Capacitor Banks 31.5/5 MVAR 42

6 Neutre Resistance 42

7 Circuit Breakers 36 kV 74

_ Secondary Equipments Misc, relays, measuring instruments *tc.. (sets) 66

- 91 - Annex 3.3

TURKEYBERKE HYDROPOWER PROJECT

Technical Assistance

I. Studies

1. 3EAS' load dispatch center is old and recent plants (Sir) were notincluded in the system due to capacity reasons in the control room. There isalso no automatic coordination with TEK regarding optimization of generationscheduling and the plant outages, but periodical plans are exchanged. AfterBerke hydropower plant is put into operation, it will be essential to estaalisha proper interface with TEK's system, to ensure efficient load dispatchoperations. A modern load dispatch center with adequate capacity to meet gEAS'needs through the decade would be constructed. In order to determine theoptional location, size, characteristics, etc., a study would be undertaken.

2. The proposed study (technical assistance) would consist of:

Phase-I: - A survey of the existing facilities.- Identification of necessary interface equipment,.- An evaluation of proposed schemes.

Phase-II: - The engineering design and specifications.- Preparation of bid documents.- Assistance during bid evaluation.

II. Trainina

The following training activities are planned:

Subiect of Training Estimated Man-monthl

Load Dispatch 6Load Management 3Computer System Applications 3Project Planning 4Financial Management 4Manpower Planning and Training 4Seminars and Workshop 6TOTAL 30

III. Snecial Eauioment

Snecial Trainina Ecuivment. 9EAS has its own training center whichincludes active training equipment. 9EAS plans to procure special trainingequipment and materials including audiovisual systems.

PC Hardware and Software. 9EAS has a mainframe computer of IBM AS 400/B60and about 80 PC/PS systems. It is planned to procure special hardware andsoftware needed for improving the operational efficiency as well as complementingthe training requirements.

Special Maintenance Eauioment. Special maintenance equipment would beprocured to meet 9EAS' operational needs.

- 92 -

Annex 3.4

TURKEY

BERKE HYDROPOWER PPOJECT

Proiect Cost Summary

----------TL-------- - ----USS Million ----- X ForeignLocal Foreign Total Local Foreign Total Exch-inge

A. BERKE HYDRO POWER PROJECT1. L&ND ACQUISATION 4.3 0.0 4.3 1.5 0.0 1.5 02. IAELIMINARY WORKS 95.0 0.0 95.0 32.6 0.0 32.6 03. CIVIL WORKS 364.9 460.9 825.2 123.2 159.2 281.3 564. ELECTRO-MECHANICAL EQ. 12.4 111.4 123.8 4.2 38.0 42.2 905. ELECTRICAL EQUIPMENT 9.9 41.0 51.0 3.4 14.0 17.4 816. ENGINEERING/SUPERVISION 37.2 0.2 37.4 12.7 0.1 12.8 17. GENERAL EXPENDITURES 81.5 0.0 81.5 27.8 0.0 27.8 0

SUB-TOTAL 605.2 613.5 1218.7 204.3 211.2 415.6 51

B. TRANSMISSION NETWORK1. TRANSMISSION LINES 65.6 29.5 94.8 22.4 10.0 32.4 312. SUBSTATIONS 39.6 23.2 62.8 13.5 7.9 21.4 373. DISPATCH CENTER 7.3 36.7 44.0 2.5 12.5 15.0 83

SUB-TOTAL 112.5 89.1 201.6 38.4 30.4 68.8 44

C. TECHNICAL ASSISTANCE1. STAFF TRAINING 0.2 0.9 1.1 0.1 0.3 0.4 882. LOAD DISPATCH CENTER ST. 0.1 1.2 1.3 0.1 0.4 0.5 893. SPECIAL EQUIPMENT 0.0 0.9 0.9 0.0 0.3 0.3 100

SUB-TOTAL 0.4 2.9 3.3 0.2 1.0 1.2 89

TOTAL BASE-LINE COSTS 718.1 705.5 1423.5 242.9 242.6 485.5 50

PHYSICAL CONTINGENCIES 72.8 76.5 149.3 24.8 26.1 50.9 51PRICE CONTINGENCIES 3180.7 3818.7 6999.4 25.4 30.3 55.7 54

TOTAL PROJECT COSTS 3971.6 4600.7 8572.8 293.0 299.0 592.1 50

IDC - BANK LOAN 0.0 870.0 870.0 .. 0 48.0 48.0 100- OTHER 442.0 442.0 0.0 23.2 23.2 100

LESS EXPENDITURES 1989-91 -116.0 0.0 -116.0 -39.6 0.0 -39.6 0

TOTAL FINANCING REQUIRED 3855.6 5917.7 9773.3 253.5 370.2 623.7 59

-93 - Annex 3.5

TurkeyBerks Hydropower Project

Disbursment ScheduleIBRD US$ MillionFiscal Year Quarter Cumulative

September 30,1992 0.2 0.2December 31,1992 21.3 21.5March 31,1993 11.2 32.7J'rne 30,1993 14.2 46.9

September 30,1993 13.7 60.6December 31,1993 13.9 74.5March 31,1994 16.5 91.0June 30,1994 22.3 113.3

4

September 30,1994 16.5 129.8December 31, 1994 28.4 158.2March 31, 1995 16.4 174.6June 30, 1995 21.1 195.7

September 30, 1995 13.7 209.4December 31,1995 20.8 230.2March 31, 1996 7.9 238.1June 30. 1996 14.1 252.2Mt

September 30,1996 4.0 256.2December 31,1996 13.8 270.0

Cumulative Disbursement Schedule300

210 - 270.0 270.0 270.0

2tE0 - 2Z

240 -

220 -

200 -1

160; 40

20

100

40 20

93 U 97 9

O aROI YeaS40 PROFIL + gmR rat. B ERKE

___________ _ a@2 il l -Io t -- sr- ~ --- |~ s

~~~~~~~~~~~~~~~~~~~~~~~~~~~~_ ____________

___J I F i A 11

1-i!

_~~~~~~MJJAs AJJA60N01J , r-S 0a k 61AOOIMMJSOD A t= 0

* - v# _I I -,

. _ >- T-- :-t--- -__._______________________..........................____ . ......-......... __.-:_..... .__ -- -

__L itp'''' '|',i''Oo .

2

coIM&sTWVN o CIscnzna Oil 2 3 4 6 6 ?1 B B 0IlI213I41IG6712i2O 2022222242 2S2722303l1323334353S373S304041424 *44114674449S5253b26 5145 766?SSI60616262649666

fb.dWbWVft i ~ ~ ~ ~ ~ ~ ~ ~ ~ -h -I~- I

CIVIL WOBKS' ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ .~ .

4~~~~~~~~~~~~4

_______ ____ L WOJ I

I w~~~~~~~~V______________~~~~~ M ,

14~~~~~~~~~~~~~~~~~~0

______________ -r~~~~~~~~~~~~L

j__,.,,xD mw,. 192 0193

1t~~~ ~~ i EL- X -- , .99 129 li og 09X~~~~~~~~~~~ , . I1 : , T -- =--t-i A Ji 0- i __ J F_ =E= | no --- m t--T i 2S 45 _7 ;_ .iii ~1111111222 2 A--. IJFAJA

U~~~~I M t A M * JAS0NeJF A M J J A S 0 h DIJ F M | F M A M J J a S 0 N o!J F N A U J J A 5 0 1

Camurcn HU -oil a * * sf * ?I$ *10a10 g3*4|5l6 17|||1 202l2223242 262720293031132333435363730394041424344464fis^748495061S 235455i657585f9*0061263s6451z

a, .. _T7 4 t a t Wi,>~~~~~I.. 1~~~~~~~~~~~~~~~~~~~~~~~~~~~~- -----T--I-r----_

,I9 *'f odtb ft_ L ,_ =u ;{ t WI .

I 114-0- Xl W A~~~~~~7.~~~~ _V - -

_ . j | +m I , ,-.----1 ___.!

i _7; *!-b 4- & X z F- v=

__,i ,!;,,._|i1- W

. _ X, ! i , ;, ';' $ : T i t :~~~~~--- ----i--- - t -4

3fl~~baNAEUEW 1993 I 1903 ~~~~1991 1904 1095 I l9SS 199.-

U 4 i A S 0 H Oti F #A A U .9 J A S 0 N Di J F M A M J i A S 0 N 0;J I? M iA U J i A $ 0 im at F M A M J J A S C N D!j F M A U j J A S O N

coqS13uc1Io9 $Cfl1II 0ff 2 3 4 5 5 7 5 0 1013 192l3435553 98Ul2021322232425 12E27t2I503IS323334353637383g404l424$.4 5445e 4S4 950I523S45Si56575559SO011563646566

AVKMMST owmwaa i

i 14 I i i i I I I i i I I~~~~~~~~~~~~~~_________________________________________________

I_ _ _ _ _ _X_X X XX_ _ _ _ _ I _I

_ _ _ i I--_

_ _ _ _

I .- I - - - - - - . 1

I I I Ih OI'

____________ ___________

_ _

_______f jii___________________L____________________

TABLE 3.7.1 - LIST OF MITIGAT;ON ACTIVMES

Est!qatedSubJect Activity !ementatfon Organization Ftiding Cost

Period In-Charge _(U.,. Vtelrs)

Study adbqate design features (location. GOpt ,4 CEMS EAS UfdetSrIinrddimenions aterials, foundation

structural and treatment) _watertightness of thereservoir Provide an independent review of design Completed cEAS GEAS 30,000

features

Instrument the den During construction cEAS CEAS 430.000

Develop a mre detalled study of potential Durlng construction CEAS CEAS 40.000Iaects of a catastrophic failure ftood

Catastrophic failureEstablish a pulic coordination plan Befure iqiouarding CE S CEAS 30.000

- DSt- Others

Coordinate land management activities with During construction CEAS -CES 272,000the ninistry of Forestry and develop and and operation - inistry of Ninistry ofimplement a specific pltn for nagement Forestry Fores'tryof vegetative cover and control of

Erosion and deforestation __sedimentation 'C

Restore cleared land at construction site Durlng and immediately - CEmS - CEAS 30,000and vicinity after construction - Ministry of - Ninistry of

Forestry Forestry

Erosion, sedimentation Coordinate with and if necessary assist to During construction Ninistry of CEmS 12.000water quality and inagmeent of the Sir-Berke Intermediate and operation Forestrywildlife watershed gme protection area

Water quality Remove trees and shrths from reservofr Before and during N-nistry of N No additiorml costarea impounding Forestry

Clsimtology Suppress dust in the vicinity of During construction Contractors Contractors Undeterminedconstruction uwokers, including Interiorareas and roads

Wltdlife Contiuue to Investigate fiwects to Brown As soon as possible CEmS CEAS 10t000Fish OulFurther Investigate fauna, emphaslzing 1992 CEAS CEAS 20'000bird populations, in Berke reservolr area 2000 _

Subject Activity laptementation Organization Fur.diry Estimated costPeriod in Charge (U.S. Dollars)

Pay coapensations Before impounding CEmS CEAS 40.000Resettloment Assist in resettlement of populations if Before inpoidinsg Ministry of Ninistry of Loans frm theso desired by the Agriculture and Agricutture and goverrment

___________________________ __________________ _ _Rurat Affairs Rural Affairs

Prepare a record of Kalender cemetary Prior to ipourdind_ CEgS gEAS 10 000

Prepare a new cemetary and/or relocate Prior to ipowiding -CtAS CEAS 20,000Kelender cometary, if requested -Department of

_eligious affair

Survey of resettled population one year after independent CEAS 10,000coMpletion Specialist

Develop a reconstruction plan for the Completed cEAS SEAS 12C000springs

Rent the springs for one season to close Completed WES CEAS 55,000facilities during preparatory constructionwork _

illica hot spring Ren the springs for three seasons to During construction CEAS CEAS 1650S00close facilities during construction work

Renovate the springs During construction Province of Adana Province of Adana 1.000.O00and CEAS

E.ployment Employ and train local residents for During construction Contractors No additonal cost 0construction

Employ and train local residents for During commissioning VEAS No additional costoperation _ _

Renovate the Yarbasi-llica access road; Coepleted CEAS CEWS 21500.000construct a road section by-passing Duzici _

Infrastructure Construct a permrnet bridge on the Ce)lan lmpleted WEAS CEmS ? tOO.000

Subsidy for a boat service across the DurinS operation CEAS CEAS 120,000reservior for Kargi and Kizilhartlap andacross the reservoir near Nuratil

Economy Prepare a fish management program for During construction DSI DSI No additional costeconomSc and possibly health reasons to CEmSProvide public access to reservoir for During and DSI DSI F. sdditional costrecreational and aesthetic opportunity. Immediately after to CEASLandscape area or areas of pAblic access construction

institutional improve CEAS enviromuental management and ammediate WEAS CEAS 30,000/yearDevelopment compliance capability _ X

Environaental Assure compliance of mitigation plan Imediate CEAS No additional cost wcoordination __ _ __ _

Report on compliance of mitigation and During construction (EAS No additional cost Wmonitoring plan and operation

TABLE 3.7.2 - LIST OF MONITORING ACTIVITIES

Estimated costSubject activity Frequency Organization Funding (U. S. Dollars)

in charge

Seismicity Monitor seismic activity by meas of Continous lEAS _ o additional coststrong-motion accelerographs

Implemeat construction quality control During construction VEAS gm Undetermined

Provide independent reviews of dan safety During construction cEAS cmgA 100.000Dam safety and integrity

Read dan mnitoring instruments Dapends on type of EAS No additional coatinstrument

Report on dam monitoringdau safety Annual gEAS m 20,000/year

Catastrophic failure Update public coordination plan Annual - MEAS- DSI N Eo additional cost- Others

Evaluate erosion and sedimentation in the Every two years - gmAIErosion and sedimentation Sir-Berke intermediate watershed and - Ministry of _ 20.000

reservoir Forestry every two years O

Ciordinate land ma*agunent activities with Annual - VEAMinistry of Forestry/Monitor the possible - Ministry of N ho additional costspecific plan for managemant and control Forestry

Erosion and sedlmentation Monitor the restoration of cleared land on Annual MEAs _ No additional costconstruction site and vicinity

Mater quality Monitor water quality Every two months SI WsA 6.000/year

Illca hot spring Monitor dischargea temparature, quality of Every two months MEAS gmA 6.000/yearllica thermal water

Econmw Monitor implementation of the fish Annual DSI DSI No additional costmanagement program to AS

Cultural resources Inform the Ministry of Culture of any During construction VEAS cEAS Un4dtcrminedarcheologlcal finding uncovered duringconstruction

Axsure compliance of mnitoring plan During operation MEAS cmAS 30,000/yearEnvironmental 00coordination Report on cinpliance of monitoring plan Annual cEA- No additional cost

0t1'h

- 102 -

Annex LI8Page 1 of 2

BE M RYDROPOWER PROJECT

Prolect Nonltoring Guidelines

1. The monltoring guidelines given below indicate the broadreqpirementc and supplement the Borrower's oblilgations according to the LoanAgreement. Theme requirements could be modified if circumstances so require.

2. Records will be maintained given planned against actualachievements, to be reviewed annually or at agreed intervals, for thefollowings

(a) Installed and derated generation capacity in NW for each of thepower stations and according to types (such as hydro, thermal);

(b) Energy capability in GWh by station;

(c) Units generated in OWh by station;

(d) Station use in GWh by station;

(e) Purchase in GWh from TEK and other sources;

(f) Sales in GWh to TEK and other utilities;

(g) Transmission and distribution losses;

(h) Planned and forced outages (by classification) in power stations,and in transmission and distribution networks;

(i) Sales in GWh to consumers (by categories);

(j) Number of consumers (by categories);

(k) .e'lty of supply to the consumers (number of interruptLons,durations classified according to causes and voltage conditions atthe consumer end);

(1) Annual system load duration curve;

(m) Plant and load factors and plant availability;

(n) Fuel consumption for each of the units in the power stations; and

(o) Average tariff for purchase from TEK and average sales tariff tocustomrs.

- 103 -

Amnex 3.8Page 2 of 2

Proieot imioleimentation

3. Records will be maintained, showing original schedule againstactual achievements and supplied to the Bank at agrec,d intervals on thefollowing aspectes

(a) Procurement action by bid packagee (bid specifications, bidinvitation, opening of blds, bid evaluation reports, award ofcontracts and ,igning of contract documents);

(b) Physi^:al progress according to project components and contracts(highliOhting critical activities);

(c) Actual project costs and expenditures (local and foreign) andestimated remaining expenditures (local and foreign); projected onan annual basis through project completion;

(d) Disbursement schedule (for Bank loan and any other loans);

(e) Information on problems encountered during implementation(including major mishaps), and expected impact on commissioningscheduleS

(f) Minutes of the meetings and reports of the International Board ofConsultants;

(g) Progress report on land acquisition and resettlement of thoseaffected by the project; and

(h) Progress report on the environmental issues connected with theproject.

-104 - Annex 4.1

-UBX 1 -Page 1 of 5BERUE HYDROPOWER PROJECTUKUROVA ELECTRIC A.S.

Notes to Financial Forecasts

I. All financial projections were prepared in current TL (functionalcurrency). The financial statements, supporting financial data andanalyses have been presented in current US$ equivalent in order to isolatethe effect of high inflation in Turkey (56X per year average over 1986-91on WPI). The Bank's projections for inflation and exchange rates wereused as shown below:

Inta1Lo Z [ Xl 1M2 1DM 199 4 1996 1211 18 19 9 20

- Domestic 73 66 40 24 18 13 it 12 13- Foreign 2.8 3.9 3.9 3.8 3.8 3.8 3.8 3.8 3.8

Exch.Rates 7090 11444 15518 18777 21612 23817 25675 28088 31065

Note: GOT's estimtes are 52Z and TL 8332/US9 tor inflaian and averae exchange rates for 1992.

II. Income Statement

1. Electricity Sales: Based on regional demand forecasts prepared byCEAS/SPO and the Bank.

2. Generation: Hydro generation based on forecast hydrologicalconditions and master plan of DSI for water use; thermal generationfrom Mersin plant at 50 GWh in 1992 and 130 GWh in subsequent years.Alternative hydro for Scenario A is based on simulation (see Annex4.4 arid para 4.23).

3. Electricity Tariffs: Linked to TEK's average revenue, assumed at UScents 6.0/kWh for base case, at 5.50/kwh for Scenario B.

4. Power Purchase Cost: Based on prevailing levels as per PowerExchange Agreement; approximately 751 of average revenue for TEK.

S. Salaries & wages: Pro-rata inflation based on 1991 actual andfuture staffing plan.

6. Operations and Maintenance: Based on generation and transmissionwith 1991 base adjusted pro-rata inflation.

7. Water chaxg : Fixed charge at TL 0.015/kWh generated at Seyhan HPPbased on existing law.

8. DeRrgeiati-on: At 3X for power plant and 41 for T&D assets.Accelerated depreciation for non-operating assets as per Turkishlaw.

9. Non-operating Income: Net of income from other investments,dividends received, employee termination benefits provisions, etc.

10. Foreign Exchange Losses: Losses on completed transactions(transaction losses) during the year is espensed.

11. Taxes: Corporate tax at 46X of taxable income. Investmentincentive at 601 of expenditures for the proposed Project aredeductible for corporate tax purposes, but income tax at 10.5X ofthe deductible amount is payable.

- 105 - Annex 4.1

Page 2 of 5III. Balanc Sheet

1. Other Long-term Assets: Investments in KEPEZ, ELTEM-TEK, CESTAS,etc.

2. £Aah: Based on cash-flow with minimum of one-month cash operatingexpense excluding power purchase cost.

3. Acounts Receivable: Assumed at 40 days sales.

4. InyentoriL : Based on gross assets and fuel requirements for MersinTPP adjusted pro-rata inflation on 1991 actual.

5. Other Current Assets: Includes advances paid, recoverable taxes,etc.

6. EmDloyee Termination Benefits: As per Turkish Labor Law - one monthsalary for each year of service for retirees and for thosecompleting 25 years of service.

7. Retained Earnings: Current year's net income which is fullyappropriated to statutory and other reserves after dividends in thefollowing year.

8. Long-Ter Debt: Foreign currency loans are translated at end-of-year exchange rates. All foreign cost requirements assumed to befinanLced from foreign loans including the proposed loan.

9. Customer DeRosits: Collected to maintain 81 of yearly bill fromCEAS' customers excluding DEs.

10. Customer Contributions: Advances for new connections, estimated at10 of substation investment.

IV. Qther

1. Foreign Exchange Losses: Losses on account of end of yeartranslation (translation losses) are capitalized in assets or WIP asappropriate in accordance with Turkish Commercial Code (see para2.26).

2. Interest During Construction: Interest During Construction iscapitalized.

3. New Eauitv: From proposed issues to recover distributed dividendsfor in-vestment needs.

4. Dividends: Fifty percent of distributable income as per Turkish Law(para 4.20).

5. Contingent Reserves: Thirty percent of yearly net cash generationafter debt-service and statutory payments. Reflected in cashresources (para 4.17).

TurkeyBerke Hydropower ProjectCuwkrova Electric A.S.

Actual and Forecast Inceme Statement(USS million current) 1/

--..-.........- Actut ..............- Prov. Budget .......-....... Foreeast-------------------------

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 l,JB 1999 2000.. . . . . . - -.. . - - --- -.- . . . . - - - - . . - - . .

Energy Sold CGWh) 3246 3409 3421 3673 3959 4047 4'43 4545 4868 5214 S586 59d4 6412 6870 7361Aruuat Increase (X) -- 5X OX 72 8X 2X 52 72 72 72 7 72 72 7X 7X

let Average Revenue (TL/kWh) 35.3 46.1 72.1 107.5 156.7 246.3 419.0 676 917 1110 1277 1408 1518 1660 1836Anuat lncrease () *- 312 562 49X 46X 572 702 61X 362 21X 152 102 82 9X 11X

Net Average Revenme (US Cents/kIAh) 5.23 5.38 5.07 5.07 6.01 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91

NET SALES REVENUE 170 183 173 186 238 239 251 269 288 308 330 354 379 406 435

Operating Expenses :Fuel Oil 30 22 15 20 21 7 3 8 a 8 8 8 9 9 9Purchased Energy 74 8K 87 108 143 136 121 128 143 159 146 122 142 164 195Persomet Cost 4 6 6 9 15 20 18 20 22 24 27 29 31 33 34 1Operations & Nainten no 2 3 4 4 6 3 4 5 5 5 7 9 9 10 10Insurance & other 0 0 0 0 0 0 0 1 1 1 2 3 3 3 4 0%

Depreciatfon 4 3 2 6 9 16 12 10 10 10 18 22 22 21 20

Totat Operating Expenses 114 118 114 148 194 185 159 172 188 207 208 193 215 240 272

OPERATING INCOE 56 65 60 38 44 54 92 97 99 101 122 160 184 166 164Nonoper.Revenue(Expenses) 27 28 34 40 17 5 24 35 26 19 21 24 24 27 31Foreign Exchange AdJustment (6) (18) (13) (4) (6) (5) (4) (3) (1) (1) (1) (1) C2) (2) (2)

.... ... ... .. - --- .... .... ... . ---- - -- . .. . . . -- - .- - .... - -

PROFIT UEFORE INTEREST AND TAX 76 75 80 75 54 55 112 129 124 119 142 183 186 191 193

Interest Charges 2 3 2 1 1 2 9 9 9 9 8 34 32 28 24..... ..... .... . ---- .... ___.. . __.... ___ __ __ _....... ..... ..... ---- ..... ..... --- ..... ....... __ __ ._ __

PROFIT BEFORE TAX 74 72 78 73 53 53 103 120 115 111 134 150 154 163 169 O 3m m

Taxes 26 22 15 8 6 6 11 22 12 11 14 49 74 78 80 w ,.. ----- ----- ----- ----- -- -- ----- ---- ----- ----- - --- ----- --- - ----- -- - 0 .

NET INCONE AFTER TAX 48 51 63 65 47 47 92 99 103 99 120 101 81 86 89 n==SuG .ula==a ==G= -5=G 85= =GG ===== === =2= =-= === _= ==G S=zGG

1/: Financial projections prepared In functional currency (Turkish Lira) and presented in USt equivalentusing average exchange rates (Source: IFS - actual 1986-90 ; IBRD - Forecast 1991-2000).

TurkeyBerke Hydropow.er ProjectCukurova Etectric A.S.

Actual and Forecast Balance sheet(USS million current) I/

......... Actual .-------- Proy. Budget---------------Forecast -------------ASSETS 1986 1987 1988 1989 199 1991 1992 1993 1994 1995 1996 1997 199 1999 2000

Fixed Assets in Operation 28 23 21 30 47 209 179 175 19 210 479 642 626 598 572Less: Accwumuated Depreciation 14 14 12 17 23 27 24 24 28 33 46 64 81 93 104

ket Fixed Assets In Operation 14 9 9 13 24 182 154 151 167 177 433 578 545 505 468Work in Progress 17 44 59 124 191 40 54 129 259 381 174 10 9 8 8Other Long Term Assets 9 9 9 34 12 13 10 19 30 28 16 2 2 2 1

TOTAL FIXED ASSETS 1.0 62 77, 170 227 235 218 300 456 586 623 589 555 515 477Current Assets Cash Resources 68 79 75 33 22 10 61 78 64 67 114 158 160 157 190Accounts ReceIvable 20 21 19 21 25 27 21 24 28 30 33 36 39 41 44Accounts Receivsble TEK 0 0 0 0 0 0 0 0 0 0 0 22 25 14 0Inventories 3 3 3 5 18 15 9 7 6 6 10 12 10 8 6Other 6 5 5 13 6 5 5 5 II II 11 11 34 61 69

TOTAL CJURRENT ASSETS 97 108 102 72 70 58 96 114 109 114 168 239 267 280 309

TOTAL ASSETS 137 170 179 242 297 293 314 414 565 700 791 82 822 794 786U33ZZ= 003 533 000 00 053 = 03= 235 55 33

EQUITY & LIABILITIES532320353353033003~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~C

Paid-in Capital 10 15 17 32 51 59 49 44 52 59 65 61 56 51 4Reserves 17 31 25 29 24 17 14 35 64 99 133 182 221 238 253Retained Earmings 42 43 s0 60 42 39 72 82 93 92 113 97 78 81 85Provision for ETS 4 4 4 a 9 9 7 8 10 12 13 15 16 18 20

Total Equity 73 92 95 129 126 123 142 168 220 261 325 354 371 388 403Long Term Debt Foreign 24 41 53 77 131 141 144 205 307 398 425 399 350 302 264Local 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0sabtotal 24 41 53 77 131 141 144 205 307 398 425 399 350 302 264

toss: current portion 3 4 S 5 9 15 14 11 10 23 26 48 48 38 48Subtotat 21 37 48 72 122 126 130 193 296 376 400 351 303 264 216Custmer Deposits 8 7 7 10 .12 11 12 13 15 17 18 20 22 23 24

Total Lang-term Debt 29 44 55 82 135 137 142 206 312 393 418 371 324 287 241Currrent Liabilities:Acco~mts Payabte 5 6 5 . 11 4 4 4 5 5 6 6 8 8 8 9Bank Overdraft 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Tax ProvsiIon 23 18 12 7 5 5 9 18 11 11 13 47 71 74 76Current payabte to TEK 4 4 6 8 16 8 3 4 5 7 2 0 0 0 9 (uCurrent Part ofLT Debt 3 4 5 5 9 15 14 11 10 23 26 48 48 38 48 X1Customer Contributions 1 1 I 1 1 0 1 1 2 1 0 0 0 0 0

... ... . ... .. .. .. . . .. .. .. .. .. .. . . .. .. .. ... . --- . ... -- -- 0 .Total Curr. LIabilities 35 35 29 31 .36 32 31 39 33 47 48 103 127 120 142 * '

TOTAL EQUJITY & LIABILITIES 137 170 179 242 297 293 314 414 565 700 791 828 822 794 786

11 : Financial projections prepared in functional currency (Turkish Lira) and presented in USS equivalentusing end-of-year eycbange rates (Source :IFS - actual 1986-91 ; IBRD) - Forecast 1992-2000).

TurkeyBerke Hydropower ProjectCukurovn Etectric A.S.

Forecast Sources and Use of Funds Statement(USS million Current) 1/

,.,. .. *-Forecast----------------

1992 1993 1994 1995 1996 1997 1998 1999 2000

Net Income 92.0 98.5 103.1 99.1 119.9 100.6 80.9 85.7 88.8Plus : Depeciation 12.2 10.1 9.7 9.8 17.9 22.4 21.9 21.3 20.3

Exchune Losses 4.1 2.8 1.3 0.8 1.4 1.0 1.8 2.5 1.8ETB Provision 2.4 4.7 4.1 3.4 3.2 2.9 2.9 3.3 3.8

Gross ICB 110.7 116.1 118.2 113.1 142.4 127.0 107.5 112.7 114.8Customer Deposits 7.2 6.7 5.3 4.1 3.7 3.2 3.0 3.5 3.9New Share Capital 21.2 13.1 19.3 16.0 13.9 0.0 0.0 0.0 0.0Local Loans 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Proposed IBRD Loan 20.4 51.3 80.6 83.3 34.4 0.0 0.0 0.0 0.0IFC Loan 0.0 26.1 34.8 20.9 18.3 0.0 0.0 0.0 0.0Other Foreign Loans 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Other Funds 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

..... ---- ..... .... .... . - ----- ..... ----- ..... --- -'Total Sources 159.5 213.3 258.2 237.4 212.7 130.2 110.4 116.2 118.7

an- - - - - -s" Ema= u

Proposed Project 48.6 123.7 180.8 146.8 52.5 0.0 0.0 0.0 0.0Other Investments 1.4 1.5 1.6 1.8 1.9 5.3 5.4 5.5 5.6

... .............................. ..... ....... ..... ....... ..... ....... ..... .........

Total Investments 50.0 125.2 182.4 148.6 54.3 5.3 5.4 5.5 5.6Interest During Construction 0.9 6.3 13.8 22.4 28.0 0.0 0.0 0.0 0.0

Principal RepaVuents 14.6 13.6 11.5 10.2 22.7 25.7 47.7 47.7 37.7Dividends 21.1 25.7 31.6 37.5 37.8 47.8 39.3 33.3 38.3ETB and Bonus Payeents 1.0 0.5 0.5 0.4 0.3 0.3 0.2 0.2 0.2Increase in other LT assets 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 e DNon-Cash Working Capitat 1.4 -3.7 16.5 4.9 12.1 -3.6 4.4 15.7 -13.1 go >Change In Cash 70.5 45.7 2.0 13.5 57.5 54.6 13.5 13.8 49.9

0.Total Applicatios 159.5 213.3 258.3 237.4 212.7 130.2 110.4 116.2 118.7 it .= c33= 33= z=3 3=333 -mM 33= 3=3= =3

1/: Financial projectlons prepared In functional currency (Turkish Lira) and presented in USS equivalentusing average exchage rates (Source: IBRD - Forecst 1992-2000).

- 109 - Annex 4.2

TurkeyBerke Hydropower ProjectCukurova Electric A.S.

Demand, Supply, Average Costs and Revenues..........................................

1986 1987 1988 1989 1990 1991

Demand (GWh)TEK DEs 1061 1183 1316 1431 1578 1781Industry 1678 1723 1748 1914 2107 2034Others 508 503 357 328 274 232Total 3247 3409 3421 3673 3959 4047

Supply (GWh)Own Generation 1274 1413 1454 1034 1058 1154Purchase from TEK 2148 2167 2159 2876 3137 3178Losses -175 -171 -192 -237 .236 -285Total 3247 3409 3421 3673 3959 4047

Unit Revenue (TL/kwh) 1/ 35.28 46.10 72.13 107.54 156.68 248.29

Unit Cost (TL/kWh) 1/ 2/Own Generation 22.65 22.15 28.02 87.30 134.84 178.83Purchase from TEK 24.49 34.75 60.41 84.78 125.69 194.29Combined 23.73 29.77 47.38 85.44 127.99 190.17

EBIT (TL/kWh)From Own Generation 12.83 23.95 44.11 20.24 21.84 69.46From Purchased Energy 10.79 11.35 1 .72 22.76 31.00 54.00Combined Sales 11.55 16.32 24.75 22.09 28.69 58.12

Unit Revemje (Cents/kWh) 2/ 5.23 5.38 5.07 5.07 6.01 5.91

Unit Cost (Cents/kWh) 2/Own Generation 3.33 2.58 1.97 4.12 5.17 4.26Purchase from TEK 3.63 4.05 4.25 4.00 4.82 4.63Combined 3.52 3.47 3.33 4.03 4.91 4.53

ESIT (Cents/kWh) 2/From Own Generation 1.90 2.79 3.10 0.95 0.84 1.65From Purchased Energy 1.60 1.32 0.82 1.07 1.19 1.29Combined Sales 1.71 1.90 1.74 1.04 1.10 1.38

EBIT/Ave.Revenue (X)Own Generation 36% 52K 61X 19X 14X 28XPurchase from TEK 31X 25X 16X 21X 20X 22XCombined 33X 35X 34X 21X 18X 23X

Contribution to Op.Income fromOwn Generation (X) 4/ 44X 61X 76X 26X 20 34K

Own Generation as I of Demand 39X 41X 43X 28X 27X 29°Annual change in generation (K) -9K 11K 3X -29K 2K 9K

Contribution to Op.Income fromPurchased Energy (K) 56K 39X 24X 74X 80X 66X

Gross Purchases as K of Demand 5/ 66K 64K 63K 78X 79K 79KAnnual change in Gross Purchases (K) 16X 1X OX 33X 9X 1X

Exch.Rate CTL/S) - Average 3/ 675 857 1422 2121 2609 4200

1/ : From Income statement.2/: Transmissfon losses allocated to generation and purchased energy propornately.3/: Source: 1986 to 1990 - IFS; 1991 - IBRD estimate.4/: Proportionate to the net generation.5/ : Including tranramssion losses.

TurkeyBerke Nydrpower ProjectCukurova Electric A.S.

Investe nt Phasing wnd Financing Plan 1992-96(In million USS current) 1/

............... ............................ ... ..........

----- 1992. -------- ------- 1993 -------- ------- 1994 -------- ------- 1995 -------- ----.-- 1996 --------Local foreign Total Local Foreign Total Local Foreign Total Local Foreign Total Local Foreign TotalInwestments - ----- ----- ---- ----

Berk Oem & Powerhouse 23.4 19.1 42.5 39.0 56.3 95.3 62.9 85.6 148.5 58.2 78.1 136.4 25.4 23.6 49.1Tranmission & Sub tatlons 5.6 0.0 5.6 13.5 14.3 27.9 16.2 15.9 32.1 6.8 3.7 10.5 2.3 1.1 3.4Technical Assistance 0.1 0.5 0.5 0.1 0.5 0.5 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0other lnvestents 1.4 0.0 1.4 1.5 0.0 1.5 1.6 0.0 1.6 1.8 0.0 1.8 1.9 0.0 1.9Interest During Conatructln 0.0 0.9 0.9 0.0 6.3 6.3 0.0 13.8 13.8 0.0 22.4 22.4 0.0 28.0 28.0

Total 30.5 20.4 50.9 54.1 77.4 131.5 80.7 115.4 196.2 66.8 104.2 171.0 29.6 52.7 82.3

Flinacing

Gross Cash Generation 2/ 118.7 0.0 118.7 124.4 0.0 124.4 126.5 0.0 126.5 121.2 0.0 121.2 150.2 0.0 150.2Less Woring Cmp.Change 1.4 0.0 1.4 (3.7) 0.0 (3.7) 16.5 0.0 16.5 4.9 0.0 6.9 12.1 0.0 12.1Lou Debt ServIce 3/ 23.6 0.0 23.6 22.5 0.0 22.5 20.3 0.0 20.3 18.7 0.0 18.7 30.7 0.0 30.7 0Les Dividends 21.1 0.0 21.1 25.7 0.0 25.7 31.6 0.0 31.6 37.5 0.0 37.5 37.8 0.0 37.8 Nat Cash Generation (NCO) 72.6 0.0 72.6 79.9 0.0 79.9 58.1 0.0 58.1 60.3 0.0 60.3 69.6 0.0 69.6MC Applied to Project 50.8 O.G 50.8 55.9 0.0 55.9 40.7 0.0 40.7 42.2 0.0 42.2 48.7 0.0 48.7

Customer Defosits 7.2 0.0 7.2 6.7 0.0 6.7 5.3 0.0 5.3 4.1 0.0 4.1 3.7 0.0 3.7

Equity 21.2 0.0 21.2 13.1 0.0 13.1 19.3 0.0 19.3 16.0 0.0 16.0 13.9 0.0 13.9

Foreign BorrofingIBD 0.0 20.4 20.4 0.0 51.3 51.3 0.0 80.6 80.6 0.0 83.3 83.3 0.0 34.4 34.4IFC/Comwerlel Banks 4/ 0.0 0.0 0.0 0.0 26.1 26.1 0.0 34.8 34.8 0.0 20.9 20.9 0.0 18.3 18.3Other 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0-° 0.0 0.0

Financino (Surplus)/Deficit (48.7) 0.0 (48.7) (21.7) 0.0 (21.7) 15.4 0.0 15.4 4.5 (0.0) 4.5 (36.7) (0.0) (36.7)..... . ..... ,. ...... .... ...... . ...... . ...... . ...... . ..... ...... . ...... . ...... . ...... . ...... . ...... Total 30.5 20.4 50.9 54.1 77.4 131.5 80.7 115.4 196.2 66.8 104.2 171.0 29.6 52.7 82.3

1/ : Using Forecast Averge Exchanoe Rates (source - IBRD).2/ : Net of all statutory paeyents but gross of interest charges.3/ : Loan repayment and interest charges.4/ : See pare 4.18.

Turkey

Berke Hydropower Project

Cukurova Electric A.S.Simulation of Hydrology and Hydro Generation for Financial Analysis

| Anmual I Annual Anmual I GENERATION (GWh)Year I|ydrology| Ftou at I Flow at I Irrigation |I|

I * )enzelet I Sir I Requirement ISeyhan I I I I I II I I Chm*-3) I Chm*3) I 1h1"3) I I & 11 IKadincik I iKadincik III Yuregir I Sir I Berke I TOTAL I

I_ _ __ _ I_ _ _ __ _ _ __ _ __ _ I I_ _ __ _ _ I I_ _ __ _ l....... ~ .I_ _ __ _ I - I_ ___I I1992 avg 2732) 4479 6101 3151 2851 2001 10.0 876) 01 1686.01|19953| dry I 16791 27001 6261 2451 2221 1561 7.8 5001 0 11130.81| 1994 dry | 1679 2700 628 245 2221 156 7.81 500) 0 1130.8|

1995 a avg w 2732 6479 641 315 285 200 10.0 876) 0) 1686.01 1996 dry | 1679| 27001 |m5 4 25 22 1561 7.81 5001 0 1130.81

"19971 dry 16791 27001 76! 245) 222! 156 7.8! 500 945 2075.8|11998 dry | 16791 2700) 727 245) 222| 156% 7.8 5001 945 2075.81

1999) awg ) 27321 4479 761 315) 2851 200 10.0 876 1660 3346.01120001 wet | 41281 6889° 835 398 360 252 12.6 1215 1822 4059.611--…---1---------1---------1----------I----- I---------I-----------…I-----------I---------I---------I--------- I--------1-20011 wet ) 41281 68891 916) 398) 3601 2521 12.6 962 1822 3806.6

2002 avg | 2732| 4479 932) 315 285 200) 10.0 714 1353) 2877.02003 aw 2732| 4479 995 315 285 200) 10.0) 714 1353 2877.020041 avg | 27321 4479 1002 315 285 200 10.0 714 1353 2877.02005) dry ) 1679 2700 1032 245) 222| 156) 7.8 354 670 1654.82006 avg | 2732) 4479| 1097 315) 285) 200 10.0 7141 1353) 2877.020071 wet ) 41281 6889 11121 3981 360 252 12.6 962 1822 3806.62008) avg ) 2732) 4479 1199 3151 285 2001 10.01 6671 1263 2740.02009) wet I 4128 6889 1209) 398 3601 252 12.6 962 1822 3806.62010| avg | 2732 4479 1219) 31!.1 2851 200) 10.0 667 1263 2740.0

* ProbabilityAvg 0.65Wet 0.20Dry 0.15Water flow unit Is Hecte-cubic meters

-112-Annex 4.5

Turkey Page 1 of 6Cukurova Electric A.S.

Berke Hydropower ProjectInvestments and Financing Plan(in US$ million current) 1/

BASE CASE.-.... ---------------------Forecast--------------------

1 m 1993 1994 1995 1996 TOTAL

Net Income 92.0 98.5 103.1 99.1 119.9 512.6

Deprecfation 12.2 10.1 9.7 9.8 17.9 59.7

ETB Pijvision 2.4 4.7 4.1 3.4 3.2 17.7

Foreign Exchange Adjustment 4.1 2.8 1.3 0.8 1.4 10.4

Gross Cash Generation 110.7 116.1 118.2 113.1 142.4 600.5

Less:Long Term Debt Payments 14.6 13.6 11.5 10.2 22.7 72.6

Dividend and Bonus Payments 21.9 26.0 32.0 37.7 38.0 155.6

ETS Paid in the Year 0.1 0.1 0.1 0.1 0.1 0.6

Change in Working Capital 2/ 1.4 -3.7 16.5 4.9 12.1 31.2

Sub Total 38.1 36.2 60.1 52.9 72.8 260.0

Net Cash Generation (NCG) 72.6 79.9 58.1 60.3 69.6 340.5

NCG to be applied to Project 50.8 55.9 40.7 42.2 48.7 238.3

Project Expenditures- Berke Dam & Powerhouse 42.5 95.3 148.5 136.4 49.1 471.7

-Transmission 3.7 12.1 14.3 5.3 2.0 37.4

- Substations a Load Dispatch 1.9 1S.8 17.8 5.2 1.3 42.1

- Technical Assistance 0.5 0.5 0.1 0.0 0.0 1.2

- Other Investments 1.4 1.5 1.6 1.8 1.9 8.2

- Interest During Construction 0.9 6.3 13.8 22.4 28.0 71.3

Total Project Expenditures 50.9 131.5 196.2 171.0 82.3 631.9

Financing Plan- NCG Applicable 50.8 55.9 40.7 42.2 48.7 238.3

- Customer Deposits 7.2 6.7 5.3 4.1 3.7 27.1

- Equity 21.2 13.1 19.3 16.0 13.9 83.5

- Local Loans 0.0 0.0 0.0 0.0 0.0 0.0

- Foreign Loans 20.4 77.4 115.4 104.2 52.7 370.2

- Balance -48.7 -21.7 15.4 4.5 -36.7 -87.1

Total Financing 50.9 131.5 196.2 171.0 82.3 631.9

Financing Surplus/(Deficit) 48.7 21.7 -15.4 -4.5 36.7 87.1

Plus: Reserve NCG 21.8 24.0 17.4 18.1 20.9 102.1

Total Financing Surplus/(Deficit) 70.5 45.7 2.0 13.5 57.5 189.3

Change In Cash per Balance Sheet 70.5 45.7 2.) 13.5 57.5 189.3

1/ : Using Forecast Average Exchange Rates (Source - IBRD).

2/ : Excluding Cash.

TurkeyBerke Hydropower ProjectCukurova Electric A.S.

Key Operational and Financial Indicators BASE CASE

-....---------------------------Forecast------------------------------------1992 1993 1994 1995 1996 1997 1998 1999 2000.... .... . .... .... . .... .... . ... .... .... . ----......... ............ ..... Sales OGWh) 4243 4545 4868 5214 5556 5985 6412 6870 736ZInstalled Capacity (NW) 598 598 598 598 598 1108 1108 1108 1108Generation (GUh) :

Hydro 1694 1774 1774 1774 2474 3454 3446 3422 3246Thernal 50 130 130 130 130 130 130 130 130Total 1744 1904 1904 1904 2604 3584 3576 3552 3376Bulk Purchase from TEK 2740 2904 3244 3609 3306 2754 3211 3717 4410Total System Losses (K) 5 5X 5% 5S 5% 6% 6X 5% 5XAverage Revenue (US Cents/kWh) 1/ 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91

Net Sales Revenue CUSS N) 251 269 288 308 330 354 379 406 435Operating Costs CUSS N) 159 172 188 207 208 193 215 240 272of shich Power Purchases (USS N) 121 128 143 159 146 122 142 164 195EBIT (US$ N) 2/ 92 97 103 107 128 168 172 175 173Non-Operating Income CUSS N) 24 35 26 19 21 24 24 27 31Net Income (USS # 3/ 72 67 82 87 107 86 67 69 69

Net Fixed Assets in Opn. (USS N) 4/ 168 153 159 172 305 505 561 525 486Total Assets CUSS N) 314 414 565 700 791 828 522 794 786Total Equity CUSS N) 5/ 142 168 220 261 325 354 371 388 403Total Capital Employed (USS N) 4/ 272 329 453 592 698 734 711 685 659Operating Ratio CX) 63 64 65 67 63 55 57 59 62Net Income/Net Sales CX) 29 25 29 28 32 24 18 17 16Net Income/Ave.Equity (K) 54 43 42 36 36 25 18 18 18Net Income/Capital Employed (K) 30 25 23 18 18 17 14 14 14Current Ratio 3.1 2.9 3.3 2.4 3.5 2.3 2.1 2.3 2.2Debt-Service-Cover (0SCR) (times) 5.1 5.5 6.3 6.5 4.9 2.7 1.8 1.9 2.2DSCR after dividends (times) 4.2 4.4 4.7 4.5 3.7 1.9 1.4 1.4 1.6Accoumts Receivable (days) 39 39 39 39 39 39 39 39 38LT Debt to Total Capitalization (K) 50 55 59 60 56 51 47 43 37

-----------------------------------------------------------------------........---.....

Average Excharge Rate (TL/USS) 6/ 7090 11444 15518 18777 21612 23817 25674 28088 31065

1/ : Corresponds to TEK's Average Revenue of US Cents 6.00/kWh2/ Earnings Before Interest are Taxes.3/ Excluding Incou from non-utility operations.4/ : Average of beginming and end of year.5/ : Excluding Employee Termination Benefits (ETB) Provisions.6/ : Source - IBRD.

1,h Ln

0.

- 114 -Annex 4.5

Turkey Page 3 of 6Cukurova Electric A.

Berke Hydropower ProjectImnestments and Financins Plan

(In US$ million current) I/SCENARIO - A

........ -.. ------ Forecast- ---------1992 1993 1994 1995 1996 TOTAL

Net Income 92.0 77.4 71.3 9i.0 63.4 395.0Depreciation 12.2 10.1 9.7 9.8 17.9 59.7ETS Provision 2.4 4.7 4.1 3.4 3.2 7

Foreign Exchange Adjustment 4.1 2.8 1.3 0.8 1.4 10.4

Gross Cash Goneration 110.7 94.9 86.4 105.0 8S.8 482.9

Less:Long Term Debt Payments 14.6 13.6 11.5 10.2 22.7 72.6Dividend and Bonus Payments 21.9 26.0 25.4 26.1 34.9 134.3ETB Paid in the Year 0.1 0.1 0.1 0.1 0.1 0.6

Change in Working Capital 2/ 1.4 3.6 4.6 6.8 8.0 24.4

SuW Total 38.1 43.4 41.6 43.1 65.6 231.8

Net Cash GeneratIon (NCO) 72.6 51.5 449 61.9 20.2 251.1

NCG to be applied to Project 50.8 36.0 31.4 43.3 14.1 175.7

Project Expenditures- Berke Dam & Powerhouse 42.5 95.3 148.5 136.4 49.1 471.7- Transmission 3.7 12.1 14.3 5.3 2.0 37.4- Substations & Load Dispatch 1.9 15.8 17.8 5.2 1.3 42.1- Technical Assistance 0.5 0.5 0.1 0.0 0.0 1.2- Other Investments 1.4 1.5 1.6 1.8 1.9 8.2- Interest During Construction 0.9 6.3 13.8 22.4 28.0 71.3Total Project Expenditures 50.9 131.5 196.2 171.0 82.3 631.9

Ffn,ncing Plan- NCG Applicable 50.8 36.0 31.4 43.3 14.1 175.7-Customer Deposits 7.2 6.7 5.3 4.1 3.7 27.1-Equity 21.2 13.1 19.3 16.0 13.9 83.5- Local Loans 0.0 0.0 0.0 0.0 0.0 0.0- Foreign Loans 20.4 7.4 115.4 104.2 52.7 370.2-Balance -48.7 -1.8 24.7 3.4 -2.1 -24.6

Total Ffnancing 50.9 131.5 196.2 171.0 82.3 631.9

Financing Surplus/(Deficit) 48.7 1.8 -24.7 -3.4 2.1 24.6Plus: Reserve NCG 21.8 15.4 13.5 18.6 6.1 75.3

Total Financing Surplus/(Deficit) 70.5 17.3 -11.2 15.2 8.2 99.9Change In Cash per Balance Sheet 70.S 17.3 -11.2 15.2 8.2 99.9

1/ : Using Forecast Average Exchange Rates (Source - IBRD).2/ : Excludfng Cash.

TurkeyBerke Hydropower ProjectCukurova Eltectric A.S.

Key operational and Financial Indicators SCENARIO - A

------------------------------Forecast-----------------------------------1992 1993 1994 1995 1996 1997 1998 1999 2000

Sales (GWh) 4243 4545 4868 5214 5586 5985 6412 6870 7362Installed Capacity (MU) 598 598 598 598 598 1108 1108 1108 1108Hydrology Normal Dry Dry Normal Dry Dry Dry Normal WetHydro Generation Change from

the Base Case (X) 0 -36 -36 -5 -54 -40 -40 -2 25Generation (U) :

Hydro 1694 1131 1132 1685 1131 2076 2076 3347 4057Thermal 50 130 130 130 130 130 130 130 130Total 1744 1261 1262 1815 1261 2206 2206 3477 4187

Bulk Purchase from TEK 2740 3549 3882 3697 4645 4120 4571 3792 3605Total System Losses (X) 5% 6% 5% 5X 5X 5% 5% 5% 6%Average Revenue (US Cents/kWh) 1/ 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91 5.91

Net Sales Revenue (USS N) 251 269 288 308 330 354 379 406 435Operating Costs (USS M) 159 199 215 211 264 251 273 243 238of which Power Purchases (USS h) 121 156 171 163 204 182 202 167 159

EBIT CUSS N) 2/ 92 70 76 103 72 111 114 172 207Non-Operating Income (USS M) 24 28 17 13 14 16 18 23 29Net Income (USS M) 3/ 72 52 59 84 57 69 66 70 88

Net Fixed Assets in Opn. (USS M) 4/ 168 153 159 172 305 505 561 525 486 1'Total Assets (USS N) 314 391 530 672 721 724 711 733 761Total Equity (USS M) 5/ 142 151 183 233 249 282 305 329 372Total Capital Employed (USS N) 4/ 272 320 426 560 647 660 642 623 614

Operating Ratio (X) 63 74 75 68 80 71 72 60 55Net Income/Net Sates (X) 29 19 20 27 17 19 17 17 20Net Income/Ave.Equity (%) 54 36 35 40 24 26 22 22 25Net Income/Capital Employed (X) 30 21 18 19 11 16 15 15 18Current Ratio 3.1 2.7 2.1 1.9 1.8 1.9 1.9 1.9 1.9Debt-Service-Cover (DSCR) (times) 5.1 4.6 4.7 6.1 3.1 2.3 1.7 1.8 2.5DSCR after dividends (times) 4.2 3.5 3.5 4.7 1.9 1.9 1.3 1.4 2.0Accounts Receivable (days) 39 39 39 39 39 39 39 39 38LT Debt to Total Capitalization (X) 50 58 63 63 63 57 51 47 39

Average Exchange Rate (TL/USS) 6/ 7090 11444 15518 18777 21612 23817 25674 28088 31065

1/ :Corresponds to TEK's Average Revenue of US Cents 6.00/kWh2/ :Earnings Before Interest ans Taxes. >3/ : Excluding Income from non-utility operations. :D4/ : Average of beginning and end of year. X X5/ : Excluding Employee Termination Benefits (ETB) Provisions. -r X6/ : Source - IBRD. O -P

0'k

-116 - Annex 4.5

Turkey Page 5 of 6Cukurova Electric A.S.

Berke Hydropower ProjectInvestments and Financing Plan(In US$ million current) 1/

SCENARIO - B............ .....................-Forecast --.-.---.-.--.---

1992 1993 1994 1995 1996 TOTAL.... .... . .... .... . ..... .....................

Net Income 79.8 89.6 86.5 84.0 102.2 442.1Depreciation 12.2 10.1 9.7 9.8 17.9 59.7ETB Provision 2.4 4.7 4.1 3.4 3.2 17.7Foreign Exchange Adjustment 4.1 2.8 1.3 0.8 1.4 10.4

Gross Cash Generation 98.5 107.2 101.6 98.0 124.6 529.9

Less:Long Term Debt Payments 14.6 13.6 11.5 10.2 22.7 72.6Dividend and Bonus Payments 21.9 26.0 29.4 31.6 32.1 141.2ETB Paid in the Year 0.1 0.1 0.1 0.1 0.1 0.6Change in Working Capital 2/ 1.9 4.9 4.2 4.7 11.8 27.5

Sub Total 38.5 44.8 45.2 46.6 66.8 241.9

Net Cash Generation (NCG) 59.9 62.4 56.4 51.4 57.9 288.0

NCG to be applied to Project 41.9 43.7 39.5 36.0 40.5 201.6

Project Expenditures- Berke Dam & Powerhouse 42.5 95.3 148.5 136.4 49.1 471.7Transmission 3.7 12.1 14.3 5.3 2.0 37.4Substations & Load Dispatch 1.9 15.8 17.8 5.2 1.3 42.1

- Technical Assistance 0.5 0.5 0.1 0.0 0.0 1.2- other Investments 1.4 1.5 1.6 1.8 1.9 8.2* Interest During Construction 0.9 6.3 13.8 22.4 28.0 71.3Total Project Expenditures 50.9 131.5 196.2 171.0 82.3 631.9

Financing Plan

- NCG Applicable 41.9 43. 39.5 36.0 40.5 201.6- Customer Deposits 6.0 6.2 4.9 3.8 3.4 24.2- Equity 21.2 13.1 19.3 16.0 13.9 83.5- Local Loans 0.0 0.0 0.0 0.0 0.0 0.0- Foreign Loans 20.4 77.4 115.4 104.2 52.7 370.2- Balance -38.6 -8.9 17.1 11.1 -28.2 -47.5

Total Financing 50.9 131.5 196.2 171.0 82.3 631.9

Financing Surplus/(Deficit) 38.6 8.9 -17.1 -11.1 28.2 47.5Plus: Reserve NCG 18.0 18.7 16.9 15.4 17.4 86.4

Total Financing Surplus/(Deficit) 56.6 27.6 -0.1 4.3 45.5 134.0Change In Cash per Balance Sheet 56.6 27.6 -0.1 4.3 45.5 134.0

1/ : Using Forecast Average Exchange Rates (Source - IBRD).2/ : Excluding Cash.

TurkeyBerke Hydropower ProjectCukurova Electric A.S.

Key Operational and Financial Indicators SCENARIO - -B

------------------- -F o r e c a stFrecast-----¶992 1993 1994 1995 1996 19"7 1998 1999 2000

Sales (GU) 4243 4545 4868 5214 5586 5985 6412 6870 7362Instatted Capacity (NW) 598 598 598 598 598 1108 1108 1108 1108Generation (Vh) :

Nydro 1694 1774 1774 1774 2474 3454 3446 3422 3246Thermal 50 130 130 130 130 130 130 130 130Total 1744 1904 1904 1904 2604 3584 3576 3552 3376

Butk Purchase from TEK 2740 2904 3244 3609 3306 2754 3211 3717 4410Total System Lcsses (X) 5X 5X 5X 5 5X 6X 6X 5X 5XAverage Revenue (US Cents/kWh) 1I 5.42 5.42 5.42 5.42 5.42 5.42 5.42 5.42 5.42

Net Sales Revenue (USS N) 230 246 264 283 303 324 347 372 399Operating Costs (USS N) 148 161 176 194 196 183 204 226 255

of which Power Purchases (USS N) 111 117 131 146 134 111 130 15J 179EBIT (USS N) 2/ 81 85 91 94 113 149 152 154 153Non-Operating Income (CUSS ) 21 27 19 14 17 19 21 24 27Net Income (USS O 3/ 63 66 72 76 93 96 58 60 61

Net Fixed Assets in Opn. (USS N) 4I 168 153 159 172 305 505 561 525 486 1Total Assets (USS N) 302 389 537 668 750 776 775 747 734Total Equity (USS N) 5/ 132 155 196 233 288 333 337 353 366 1'Totat Capital Employed (USS N) 4/ 267 316 433 565 664 704 681 649 621 _

Operating Ratio (K) 65 65 67 69 65 57 59 61 64Net Income/Met Sales (X) 27 27 27 27 31 30 17 16 15Net Income/Ave.Equity (X) 49 46 41 35 36 31 17 18 17Net Income/Capital Employed (X) 27 26 22 17 16 19 13 17 13Current Ratio 2.9 3.0 2.6 1.9 2.8 2.5 1.9 2.1 2.0Debt-Service-Cover (DSCR) (times) 4.5 5.1 5.4 5.7 4.3 2.8 1.7 1.7 2.0OSCR after dividerds (times) 3.7 4.0 4.0 4.0 3.3 2.1 1.3 1.4 1.5Accounts Receivable (days) 39 39 39 39 39 39 39 39 38LT Debt to Total Capitalization CX) 52 57 61 63 59 53 49 45 39

Average Exchange Rate (TL/USS) 6/ 7090 11444 15518 18777 21612 23617 25675 28088 31065

1/ : Corresponds to TEK's Average Revenue of US Cents 5.50/kWhand represents 8.3X decrease from the Base Case.

2/ : Earnings Before Interest ens Taxes. ,.3

3/ : Excluding Income from non-utility operations.4/ : Average of begimning and end of year.5/ : Excluding Employee Termination Benefits (ETS) Provisions. X6/ : Source - tBRD.

0.o0'> @

- 118 -

Ann2x 5.1Page 1 of 6

RIS HYDROPOWER PROJECT

CGMoarison of the Least-Co2t Exoansion Plans with Berke andwithout B2rk Hydra Plant as a Candidate for Exoansion

1. The least-cost expansion plan was described in Annex 1. 5. In orderto evaluato the contribution of the Berke Hydropower Plant to the syxtem, analternative least-cout expansion plan has been formulated. In this alternativesequence, all assumptions and constraints are the same, the same optimizationsoftware was used, and all candidates for expansion but Berke are taken intoaccount as in the base case. The resulting least-cost expansion plan (withoutBerke) is presented in Table 5.1. Table 5.2 allows for the differences betweenthe two solutions to be seen.

2. The alternative sequence introduces in 1997 a 340 NW lignite-firedplant in replacement of Berke. ThLi difference determines posterior, thoughminor modLfications during 2002-2008. The alternative sequence presents anoverall lower installed capacity (164 MW lower) and a different systemconfiguration resulting in 190 MW additional thermal capacity and 354 MW hydro-capacity less than the least-cost plan.

- 119 - AAnnex S.1

Page 2 of 6

TABL1.6.1 - LEAST-COSTEXANSON N HOUTSIn

Yvw Unit Nu sin T" To 091 OEM KEP GOT NA TUNCEY

1660 KanGal 2 130.0 Ugnlta-tm TM 160.0Abtaill 514.1 N.LG - Co 11K 616.1Tin 16.0 "to DBt 10Kwaaoiun 2L0o "tro ODM o0Kul*"& 120.0 myd"o Do 120.0Ob1 U.63 Hpro OS 66.3Mentalbt 1260 yd"e De1 124.0

Sub-Tota OK8. 349.3 @71201 Y. C _auJ 1860.0 Un i TEK t10.0

Or_11 210.0 UpIts-I1i_ TEK 210.0soma t84 1880 Ugnhslm TElK t6O0Auak 1t2 600.0 Htd,o Ot 600.0

K<lkIu 112 90.6 IYdo OSt 00.6AdIgus 1.2 .to Hydro 08t 82.0VYnie 12 26.2 HYo 091 26.2Keekorpu I.t3.4 A.6 *yd*o 016 6.6Sk 23.0 "ro OEM 270.0

Sub-ToW 6260 96. 2730 176081662 soma 8.4 6.0 Ugnii-amn TIK 166.0

Kam.kay 1.2 4aQ0 Ugnitnnm T0K 420.0Atelurk 3.6 pO.0 Nydro co t00.0Catatanl12 ttZ0 htdf 091 I112Gend. 2,.3 102 Hyd CS 106.2vYnionJ 12.6 tdro OSt la6Kutagun 1,4 2ZO Hydro OSt 22.6Meoen 1.3 19.2 Hydro ONt 10.2Bivo 1.3 160 Hydro Oc 160Cnn-_ 16.8 Hidro ON 16s

Sub-Toeul 665.0 1204.7 1.716 Kameikoy 3 210.0 U 9gnu-Stmn TEK 210.0

Ataurk 6.6 200.0 HMoto ON 000.0Owus,P.Pd 170.0 drO Do 170.0catln 66.0 Hydro ON 66SDObo 110.0 Hyiro D91 110.0Sue Ugurtu 3 30.0 Hydro TEIK 30.0

Sub-TOtl 240.0 12363 1476.3166 Kurun 65.0 Hydro ONI 6.0

Smta Hyro 20.0 b"tod 8OT 20.0Sub-TotW 6.0 20.0 1060

8iXTH FVE YEAR PLAN 2016.1 341.1 2730 20.0 6161*

Sub-Tota10 Elbltan 340.0 Upiteterm TEKl 340.0

Sub-Total 340.0 340low Elbitan 2560.0 Ugnte-Stm TEK 260.0

Sub-TOW 2560.0 30.0Swe 672O Hydro SOT s6OBay" 81.O Hydro 0OS 6130Vedgp 300.0 Hydro NA 00.0Alpae 167.0 Hydro NA 167.0

Sub-TOW 610.0 672.0 487.0 162.1W KakamW 160.0 HY"o ON 180.0

Kayrktp 431.0 Hydfo OS 431.0NaUal n 1360.0 N.OAS-OC TEK 1360.0Ataogru 116.0 Hydro on9 116.0

Sub-TOW 1360.0 726.0 2076.0W8-b*Te4f16Og ) 4070.0 1230.0 0.0 672.0 467.0 66660

TOTAL (100-1o6 606.1 06.1 273.0 SI2O 47.0 126.

- 120 - Annex 5.1Page 3 of 6

TAMBE A1 - LEAT-COST XPANSION PKAN CMTHO*T EIERK).

VYa Unit Name SIe Type TEK D0 CEAS KEPEZ SOT NA TUFKEY

2000 llUu 1200.0 Hydro 081 1200.0Natual an 1380.0 NA.Q -CC CEAS 1360.0

Sub-Total 1200.0 1380.0 2380.02001 Cikro 240.0 Hydro D81 240.0

Torul- 17.0 Hydro 081 1780Da" 60.0 Hydro 0t 6070.0Natural On 180.0 NMAS -0 TEK 160.0

Sub-Total 18W.0 1085i0 2865.02002 8orc&a 300.0 Hydro 08 1 300.0

Muratl 11AO Hydro 08t 11tAOVusufb 60.0 Hydra OSt 540.0Natural Oa 1380.0 N.a. -CC TEK1880.0

Sub-ToWa 1360.0 958O 2305.020003 konk 8 533.0 Hydro OSI 6330

DIlgur 1380 Hydro 081 1380Impor"d Coal 1800.0 CoasOten SOT 100.0Of-So" 380.0 Hydro SOT 380.0Sim. 180.0 ULnh4-ktarn TEK 180.0Caylthan 1 10.0 LIgnne-Starn TEK 150.0

Sub-Total 300.0 868.0 180.0 284.02004 Natural Ga 900.0 N.oe -00 TEK 900.0

Imported Coal 1800.0 Coa-Swtam OT 1600.0Cayirhan 8 180.0 Lgnite-Stean TEK 180.0

Sub-Total 10t0.0 1OW.0 02580.0E10TH FIVE YEAR PLAN i 200004) 4600.0 3908.0 3380.0 13130.0200S 8-Urta 80.0 Hydro 083 80.0

Aslanalk 90.0 Hydro 0S 90.0Imported CoL 1800.0 Coa-Steam SOT 1800.0Adlyaman 10.0 Ugnite-team TEK 180.0Natural Gi 900.0 NAe - CC TEK 900.0

Sub-Total 1080.0 140.0 1800.0 2690.021006 Gokts 270.0 Hydro 081 270.0

Konaktepe 210.0 Hydro 031 210.0Utcin * 160.0 Hydra G 180.0Camlica 131.0 Hydra 08i 131.0Emenr 6 40 Hydro 088 642.0Hydro 1,2 178.0 Hydro 08I 1783.0Natural GX 900.0 NOes -CC TEK 00.0Imported Coal 00.0 Co-Steam OT 6000

Sub-Total 900.0 31960 600.0 46X.02007 Natural G 450.0 Nas - CC TEK 480.0

nported ̂ a 2500.0 Coal-Steam SOT 260.0Cayirhan S1 340.0 Ugnitt-Starn TEK 340.0

Sub-Total 790.0 2600.0 3290.02000 Natural O 1600.0 N.Ga - CC TEK 1600.0

Imported Coal 1000.0 Coal-Stem SOT 1000.0S8CS. 180.0 Lgnite-Searn TEK 180.0Caytrhn 02 340.0 Ugnite-Steam TEK 340.0Ozkoy 1i66

Sub-Total 2290.0 1000.0 344602009 Natural a 1380.0 N.Ge - CC TEK 1380.0

miported Coa 18100.0 Col-tearn m OT 1800.098C* 300.0 Ugnite-tarn TEK 300D0

Amasra 600.0 e Ugnite-Ston TEK 600.0Sub-Total 2260.0 1600.0 3760.0

NiNTH FIVE YEAR PLAN (04-2009) 728.0 3336.0 7000.0 17772.0

2010 Hydra 3 1470.0 Hydro DSI 1470.0Natural en 2230.0 N Ou - CC TEK 2260.0Imported CoiL 1000.0 Coal-Sotn SOT 1000.0S8C8 180.0 Ugnite-Sten TEK 160.0

Sub-Total 2400.0 1470.0 1000.0 4870.0

TOTAL (190-2010) 202681 13704.1_ 12072.0 48400.2

Born 12 Bolu-Goynulm Can-Lamk and Seyltorr 0 1.2

-121 -Anz

Page 4 of 6

TAE ' 5- TEM'BCHAPtERSIIO ALTERN4'J/E OONFR6TSON COMPA VED IMTN THE LEAST COST OWLUTIOVdTH BOEM VITHOUT BERME

Y Unit Nu ane TV" Unit N" Sie Type0) __ k)

Im Kfingail 150.0 Uunlt.Sseam TEK KangeI2 160.0 Ugnft*4ean TEKAnd"bin 616.1 #4Gm- T K_U Ambfl 618.1 #4Gm-C c TTeMa I6O "ro DS T*M 160 Hy6o DuKwIMassn 010 #pdro D01 KItason 810 Hrdro ONKIM"ap, 120.0 Hpdtr DO Khlkap 120.0 #Idfo ONDest 58.3 Hpdro O8S Orbmnt 66.3 Hydto CUvenom" 124.0 Ibdfo DO Menmit 124.0 Hwdro ON

Sub-Told 1017.4 Sub-Tol 10174166 V. C "elda 160.0 Ugnhibeanm TEK V. Caiaal 160.0 LignWte4ftn TEK

O0hamil 210.0 UgnheS4sm TEKt Orhan 210.0 LU_t4am TKso. s-6 1660 Ugnt-Sfn TEK Sco.na6 166.0 UL1gn4tsin TE1KAatuek 1.2 600.0 Hpdro DSI Aurk 12 600.0 Hdto OCGeands 1 160 Mdro 0S Geende 1 176.0 lydto 081Kld 1.2 6 Hpdro osS Kiau 1.2 we NYdfo 0 9tAdipus 12* 6O Hydro OS1 ,dm 1.2 sa0 "v&* ONVYice 1.2 262 Hydro OS Yenic 1.2 26.2 HydroCUKoekoepu 1.A.4 8.i Hy" OSI Ko ekorpu 1.3.4 6.8 Hydro Sir 273.0 Hydro CEAS Sit 270 Hydro CUA

Sab-Told 1760. Sub-Toia 170&8low2 Sorm.-8 166.0 Ulnite-Stemn TK Soman'. 166L0 Lignite-Sean TEK

K:1 1,2 420.0 Lgnhle-Sam T0K Kwnesay 1.2 420.0 UienitSm TEKAtuik 3.6 600.0 Hydro 031 Aaturk 36 t00.0 HYd CU0 O1tul1n 1.2 11t6 Hydro OS CajaJn 1,2 112. HWd" CGn 2.3 I0C2 Hydro cU Gendn 2.3 100.2 Hydro Do,enloe 3 tZ0 Hyro OSI Yninb 3 116 Hydro OSIKu2gn 1.4 22.06 dfo r8 Kuagun 1,4 220 Hydro OSt

-. ' t91.2 Hydro OS Mercan 1.3 19.2 H"dro DalSekoy1.0 I6O Hydro OSI Seyky 1.3 16.0 Hydro DOOmUgeze 16.6 Hydro OSI Camllgo 16.5 Hydro CU

Sub-ToW 1760.7 Sub-Tota 1769.7162 Kmky 210.0 ULgnItStam TEtK KmCky 3 210.0 UignIteSm TEK

Atauk 6.6 9600.0 Hydro OSt Aktuek 6.8 000.0 Hydro CUlCu". PNd 170.0 NytSo OSJ Owuce. Ped 170.0 "Omo 081Ctdaln S 66.3 Hydro OSt Catal 3 66.3 Hydro OSIDieb 110.0 hydro OSI DIal 110.0 Hydro CUISuat Ueudu 3 30.0 Hdiro TEK Suat Ugudu 3 80.0 Hydo TK

Sub-TOW 1476.3 Sub-TOW 1476.3lo6 Kurtun 66.0 Hydro OSI Kurtun 6A Hydro OS

Sand Hydra 20.0 Hydra SOT SnaIHdr 20.0 H*dro GOTSub-Toul 100 Sub-Toul 106.O

GTHFIVEVEARPLAN(190-194) 616Z2 61612

Sub-TotW 0.0 Sub-ToW 0.0low ESsm 340.0 Ugnite-Stam TEK Elbiatan 34O.0 Usgnite4hon TEK

Sub-tOW 340.0 Sub-ToW 340.0_ Ebian 2040.0 Upnite-ftn TEK Elbatn 040.0 LUgniteim TEK

BP" 610.0 Hdro CEAS Elbian 340.0 LIg eam TEKSub-TOW 250.0 Sub-TOW 2380.0

1t lireBko 0 71O Hyeo SOT Bbrsol 672.0 Hydro SOTbabet 618.0 Hydto 091 BSabat 61.0 Hdfa OWYVdo 80o.0 Hydro NA Vedigo 300.0 Hdro NAAIloa 187.0 Hydro NA AIpae 167.0 Hy_o NA

Sub-ToW 167d.O sub-ToW 162.ltt Karkan* 160.0 Hydro co Kakami 16.0 Hyd"o Da

Kayratep 431.0 Hydro 01 Ksyateo 431.0 Hydro 00.N8ralm 1360.0 KA" - CC t K NaturuGo 1350.0 #,GM CC TEKAkew 116.0 Hydro Ds Akkopru 11hO Hy" OCU

Sub-Totl 2076.0 Sub-ToW 2076.0

TMFIVEYEARPLAN(1166-1610) 663.0 64O6O

TOTAL (t6-1 12760.2 TOTAL 12.2

Thu wtm peMe diffl t In te es hic Idd bythade aa

-122- - Annex S5l--Page 5 of 6

UMLE 1.- 3707EWCtA UTRIWIAC. M.tR4TIVCONPIURATOI COMPAU8 WW"THULEATO0a1O aLUT"WtJ - ip U I3T^t , 0 nsnu PU spD

IMefot~~~~~~~~~~~~~~MO2000 muu 1200.0 Hydro D81 Itu 1200.0 Hydro 0a1

Naturwal 1360.0 Item -C 064OE Natural Gan 188.0 N.Ga - CC CEASub-Total 2880.0 2660.0

2001 Cil 240.0 Hydro OSI Ck 240.0 Hydro D0ITOWl 17IM0 Hydro 081 Torul. 1711,0 Hydro DEWDown 070.0 Hydro 081 Taeru 070.0 Hydro 0alNaural an 1800.0 N.m -CC TEK Natural Gs 1600.0 N.GM -OC TK

------ Sub-Total 2805. Sub-Total 2886.8ub-Tou Hm3.o Hydro 081

Murad 116.o Ndro OSI Mura 116.0 Hydro 08OYu1ute 640.0 Hdfro 0S Vugu t 640.0 dro a01Nauturl GM 1860.0 N.O" - cO T NaturSa an 1350.0 N. - CC TEKOl-sola 60.0 ryd*o OT

Sub-ToWtl 2m.0 Sub-Total 23050_ 0onak + 6D8.0 Hydro 08t Bkonak 68.0 Hydro 001Olgur 138.0 Hydtro 05 Ogur 185.0 Hydro Delkhorted Oee 2000.0 Coa-Stem SOT Impor Cal 1600.0 Coa-Sm SOT

Oa-solk 380.0 Hydr* GOT

so"8 180.0 Ugnte-Stean TEK_Cayrhan S 160.0 Ugnite-Stmn TEK

Sub-Total 26M6.0 Sub-Toal 2684.02004 Natural a" 00.0 N.Ge - cc TEK Natural Gt 900.0 N.1- CC TEK

mpdOl 1000.0 Coal-Stam SOT Bmported cow ¶600.0 Col-Stnm B0Tsaw 160.0 Ugobe-Sam TEK Caybhan 150.0 Ugnlte-tem TE1KCItn 800.0 Ugnit-SteFmn TEK

Sub-Toal 2360.0 Sub-Totaw 2660.041TM FNe tEAR PLAN 2000- ) 1318.0 18136.0

-3006' Goktaa 270.0 Hydro O SI S-Ura 60.0 Hydro DS1Natural aS 00.0 NKe - CC TEK Ascick 00.0 Hydro DOSbIportd COal 160.0 Cold-Searn SOT Importnd Coal 1600.0 Coal-Stea 90TAdtynan 160.0 Ugnite-ftean TEK Adlyaman 160.0 Ugnit-Steam TEK_________________________________ Naturl an g 00.0 N.Gaa - CC TM

Sub-Towa 220.0 Sub-Total 2600.0_&TAWpol'S~Komattpe 210.0 Itdro ODl Goor 270.0 ydra DSe

lJtudn * 160. hydra 0el Konetitpe 310.0 Hydra OS1Camlloa 131.0 Hydro D91 Utuci * 160.0 Hydro DSI

E8m 642.0 Hydra DSt CamUca 131.0 Htydo 0OSHydro 1 1372. Hydro 0el Erene *04.Z0 Hydro OSNatural Ges 00.0 NOes - CC TEK Hydro 1372.0 Hydro 05 tImportedCoal 1000.0 Col-Steam GOT Hydro 2 411.0 Hydra uSt

Naturil Gan 900.0 NOs -CC TEK__nported Coal 600.0 Coal-emn SOT

Sub-Toutl 4415.0 Sub-Total 48.0* . .. Hydra 2 411.0 Hydr_ Dal Natural Gs 460.0 N.Ge - OC TM

S4br& 60D0 Hydro OSt bnported Coal 2600.0 Coaltasm SOTAelrtO 00.0 Hydro Dal OErhan n1 340.0 Ugnitn-Sm 1KNaitural 0 46 C N - co TEKItpoed Coal 2000.0 Coal-Stem SOTCalthtan el 040.0 Lignite-Steam TEK

Sub-Total 3341.0 Sub-Totwl 3200.0Natura GM 180.0 ".31.Oas - c K Natura an 160.0 tLGa -CC 1TEKhImpoted Coal 1000.0 Cold-St"m SOT Imported Coal 1000.0 Co6st"a SOTam, 00.0 ULgnl_eStem T1K 160.0 LgnIten-St TE1KCan B2 340.0 UgnIteo m TQK Cytrtan St 640 Ugnte-Stam TEK

___o* 166.0 Hydro De1

* Sub-Tolal 3640.0 Sub-Tot 3446.02006 Natural a 1360.0 N.a -CC TEK NMaturalG 1360.0 tJ.0 - CC TEK

tP.C coal 1600.0 Coal-Stem SOT hImptedal 6o00.0 Coal-Steam SOTSaC* 100.0 Ugnt-Stem TEK 8w 000.0 U egnI-Sm TElKAmsa 600.0 Usgnis-Steam TI1K Amar 600.0 Lignie-Stnm TEK

Sub-Total 3760.0 Sub-Total 3760.00TH FNVE YEAR PLAN (20062000 1716.0 17772.0

2010 Hydr3 1470.0 Hydro 0D1 Hydro3 1470.0 Hydro 081Natural m 2260.0 N.Os - CC TEK Naturl am 2260.0 tl. -CC TEKImor ted cow 1000.0 Caliteam VOT Imworted Coa 1000.0 Coal-Se OTSSCS 160.0 Ugnnte-Stem TEK sas 160.0 UgnIteStem TEK

Sub-Totl 4870.0 Sub-Toal 470.0

TOTAL*(10 10) 466.2 TOTAL 48400*Sun 1.2 SaluGoytulu Cwt-Lepak and SaytoMer a1.2

TURKEYBERKE HYDROPOWER PLANT

COMPARATIVE SYSTEMS' COST ANALYSIS(constant 1989 US$ million)

BERKE PROJECT LEAST - COST PLAN _ ALTERNATIVE SEQUENCE _Total Total Total Energy TOTAL Total Energy TOTAL NETYear Investm- O&M lnvestm- O&M not SYSTEM Investm- O&M not SYSTEM SAVINGS

ent Cost Cost Cost ent Cost Cost Served COST ent Cost Cost Served COST

1989 0.00 0.00 0.00 0.00 555.95 0.01 555.96 0.00 555.95 0.01 555.96 0.001990 0.00 0.00 0.00 0.00 618.44 0.00 618.44 0.00 618.44 0.00 618.44 0.001991 0.00 0.00 0.00 34.10 751.08 0.01 785.19 34.10 751.08 0.01 785.19 0.001992 18.26 0.00 18.26 290.60 823.62 0.02 1114.24 291.20 823.62 0.02 1114.84 0.601993 65.78 0.00 65.78 831.80 873.53 0.01 1705.34 834.00 873.53 0.01 1707.54 2.201994 135.63 0.00 135.63 1609.60 966.36 0.03 2575.99 1614.10 966.36 0.03 2580.49 4.501995 129.80 0.00 129.80 1849.50 1130.46 0.44 2980.40 1853.80 1130.46 0.44 2984.70 4.301996 38.39 0.00 38.39 1385.20 1325.62 13.78 2724.60 1371.20 1325.62 13.78 2710.60 -14.001997 0.00 5.40 5.40 1321.20 1473.83 3.27 2798.30 1289.90 1491.12 3.13 2784.15 -14.151998 0.00 5.40 5.40 1561.80 1560.82 27.36 3149.98 1495.40 1577.28 22.52 3095.20 -54.781999 0.00 5.40 5.40 1770.20 1751.46 24.13 3545.79 1674.00 1769.00 19.05 3462.04 -83.752000 0.00 5.40 5.40 2054.70 1937.83 26.57 4019.10 2051.90 1955.06 21.75 4028.71 9.612001 0.00 5.40 5.40 2416.80 2118.30 7.15 4542.25 2427.30 2136.97 4.23 4568.50 26.262002 0.00 5.40 5.40 2655.80 2306.34 5.70 4967.84 2828.60 2347.89 5.71 5182.21 214.372003 0.00 5.40 5.40 3032.10 2595.27 3.36 5630.73 3107.10 2603.53 4.05 5714.68 83.952004 0.00 5.40 5.40 2837.50 2960.22 5.30 5803.01 2791.90 2979.62 5.16 5776.68 -26.332005 0.00 5.40 5.40 2798.40 3336.31 7.13 6141.84 2787.20 3372.57 7.45 6167.22 25.372006 0.00 5.40 5.40 3111.30 3565.76 5.07 6682.13 3090.90 3526.16 5.34 6622.40 -59.732007 0.00 5.40 5.40 3234.00 3988.77 6.72 7229.49 3213.00 4009.81 6.84 7229.66 0.162008 0.00 5.40 5.40 2424.10 4495.98 9.60 6929.68 2424.10 4514.86 10.14 6949.10 19.42 > :2009 0.00 5.40 5.40 -27357.00 5055.20 12.74 -22289.06 -27292.86 5074.03 13.27 -22205.56 83.50 o

0.

TURKEY

BERKE HYDROPOWER PROJECTCOMPARATIVE ANALYSIS OF SYSTEMS' COSTS

(Constant 1989 US$ million)

Total Investment Cost O&M _ Fuel _ Energy Not ServedYear Least Alternative Net Least Alternative Net Least Alternative Net Least Alternative Net

Cost Plan Savings Cost Plan Savings Cost Plan Savings Cost Plan Savings

1989 0.00 0.00 0.00 234.74 234.74 0.00 321.21 321.21 0.00 0.01 0.01 0.001990 0.00 0.00 0.00 243.79 243.79 0.00 374.65 374.65 0.00 0.00 0.00 0.001991 34.10 34.10 0.00 263.82 263.82 0.00 487.26 487.26 0.00 0.01 0.01 0.001992 290.60 291.20 0.60 271.75 271.75 0.00 551.87 551.87 0.00 0.02 0.02 0.001993 831.80 834.00 2.20 298.74 298.74 0.00 574.79 574.79 0.00 0.01 0.01 0.001994 1609.60 1614.10 4.50 311.20 311.20 0.00 655.16 655.16 0.00 0.03 0.03 0.001995 1849.50 1853.80 4.30 313.93 313.93 0.00 816.53 816.53 0.00 0.44 .44 0.001996 1385.20 1371.20 -14.00 327.33 327.33 0.00 998.29 998.29 0.00 13.78 13.78 0.001997 1321.20 1289.90 -31.30 384.44 392.42 7.98 1089.39 1098.70 9.31 3.27 3.13 -0.131998 1561.80 1495.40 -66.40 389.52 397.46 7.94 1171.30 1179.82 8.52 27.36 22.52 -4.841999 1770.20 1674.00 -96.20 426.48 434.58 8.10 1324.98 1334.42 9.44 24.13 19.05 -5.082000 2054.70 2051.90 -2.80 464.58 472.68 &10 1473.25 1482.38 9.13 26.57 21.75 -4.822001 2416.80 2427.30 10.50 513.80 521.89 8.09 1604.50 1615.08 10.58 7.15 4.23 -2.922002 2655.80 2828.60 172.80 552.47 559.51 7.04 1753.87 178&38 34.52 5.70 5.71 0.012003 3032.10 3107.10 75.00 662.51 655.31 -7.20 1932.76 1948.22 15.46 3.36 4.05 0.692004 2837.50 2791.90 -45.60 757.15 765.11 7.96 2203.07 2214.51 11.44 5.30 5.16 -0.132005 2798.40 2787.20 -11.20 870.56 878.31 7.75 2465.75 2494.26 28.50 7.13 7.45 0.322006 3111.30 3090.90 -20.40 954.86 937.46 -17.40 2610.90 2588.70 -22.20 5.07 5.34 0.272007 3234.00 3213.00 -21.00 1086.82 1094.83 8.01 2901.95 2914.98 13.03 6.72 6.84 0.122008 2424.10 2424.10 0.00 1210.69 1212.85 2.16 3285.29 3302.01 16.72 9.60 10.14 0.542009 -27357.00 -27292.86 64.14 1354.79 1356.97 2.18 3700.41 3717.06 16.64 12.74 13.27 0.54

.=...~* =. =S ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~X

- 125 -

Annex 5.3Page 1 of 7

TURKEY

BERKE HYDROPOWER PROJECT

Estimation of the Internal Economic Rate of Return

1. All costs are expressed in 1991 constant economic values. Thefinancial flows were converted to economic costs by: (a) netting out taxes andother domestic transfer; (b) expressing the import component at CIF prices; and(c) applying conversion factors to local costs in order to express them inequivalent border prices. The following conversion factors were used: localmaterials at 0.8 of their domestic prices; skilled labor at 0.8 of the domesticskilled labor wage rate; and unskilled labor at 0.6 of the domestic unskilledlabor wage rate.

2. Benefits are measured as the consumers' willingness to pay (WTP) forthe additional electricity supplied by Berke. Consumers' WTP comprises therevenue of additional sales and the consumers' surplus. The additional energywas calculated based on the load demand projections constrained to Berke's wateravailability. Sales revenues were estimated using as a proxy for average tariffsthe LRMC of supply at generation level. LRMCs estimated by the mission coincidewith current and agreed tariff levels; these are 4.9 c/kWh at generation level,5.4 c/kWh after transmission and 6.0 c/kWh after distribution.

3. The consumers' surplus is measured by the price above the tarifflevel that consumers' are willing to pay. The valuation of this economic benefitrequires estimates of the price elasticities of demand. Consumers' surplus wascomputed considering a weighted price elasticity of -0.42 obtained from aneconometric demand study for Turkey. This value was adjusted in time as afunction of the consumers' income increase using an income elasticity of demandequal to 2 obtained from the same source.

4. The internal economic rate of return (IERR) for the Berke Project andassociated transmissicn and distribution components is 15.2%. Sensitivityanalyses, shown in the following tables, tested the economic viability of theproject to cost overruns, implementation delays and a lower demand growth. Theseresults are summarized as follows:

IERR

- Base Case 15.2%- Cost overrun of 10% 14.1%- one year implementation delay 14.3%- Cost overrun (10%) plus delay (1 yr.) 13.3%- Lower demand growth (down by 3 points) 12.0%

- 126 -

Annex 5.3Page 2 of 7

S. Additional sensitivity was undertaken to test the robustness ofresults to economic assumptions related to the conversion factors, consumers'surplus and sunk costs. Results of these tests are summarized below:

TERR

- Higher conversion factors 15.1%(local materials: 0.8, skilledlabor: 0.9, unskilled labor: 0.75)

- No conversion factors 13.9%(all factors equal to 1.0)

- No consumers, surplus 14.7%(economic benefits - sales revenue)

- No conversion factors nor consumers'surplus 13.4%

- Including sunk costs 13.6%(i.e. including investments of period1989-91 in preparatory works)

- 127 - Annex 5.3

Page 3 of 7

TURKEYBERKE HYDROPOWER PROJECT

Internal Economic Rate of Return/Base Case

Constant (1991) Prices (US S Miltion) 1 Border (1991) Prices (US S Million) a/

Year TotaL Local Material Skilled Unskilled Foreign Total Local Material SkiLLed Unskilled ForeignInvestment Cost Labor Labor Cost Investment Cost Labor Labor Cost

Cost Cost

1989 0.3 0.3 0.2 0.0 0.0 0.0 0.2 0.2 0.2 0.0 0.0 0.01990 11.7 11.7 9.3 0.6 1.7 0.0 9.0 9.0 7.5 0.5 1.0 0.01991 31.7 31.7 25.4 1.6 4.8 0.0 24.4 24.4 20.3 1.3 2.9 0.01992 58.6 20.8 16.6 1.0 3.1 37.8 53.8 16.0 13.3 0.8 1.9 37.81993 77.9 35.9 28.7 1.8 5.4 42.0 69.7 27.7 23.0 1.4 3.2 42.01994 114.8 53.3 42.6 2.7 8.0 61.5 102.5 41.0 34.1 2.1 4.8 61.51995 98.4 44.6 35.7 2.2 6.7 53.8 88.1 34.3 28.5 1.8 4.0 53.81996 33.5 18.5 14.8 0.9 2.8 15.0 29.2 14.2 11.8 0.7 1.7 15.0

Economic Cost (1991) Average Incremental Total(US S Million) Benefit Generation Economic Net

/kwh Benefits BenefitsYear Total O&M | Total (US cents) (GWh) (US S) (US S)

Investment Costs Costs b/ (Million) (Million)Cost

1992 53.8 0.0 53.8 0 00 -53.81993 69.7 0.0 69.7 I 0 I 0.0 I -69.71994 102.5 0.0 102.5 0 0.0 102 51995 88.1 0.0 88.1 0 O.O 88.11996 29.2 0.0 29.2 0 0.0 -29.21997 5.1 5.1 5.00 1669 83.5 78.41998 5.1 5.1 5.02 1627 81.6 76.51999 5.1 5.1 5.04 1584 79.8 74.72000 5.1 5.1 5.06 1542 78.0 72.92001 5.1 5.1 5.08 1500 76.2 71.12002 5.1 5.1 5.10 1457 74.4 69.32003 5.1 5.1 5.12 1455 74.5 69.42004 5.1 5.1 5.14 1452 74.7 69.62005 5.1 5.1 5.16 1449 74.8 69.72006 5.1 5.1 5.19 1446 75.0 69.92007 5.1 5.1 5.21 1444 75.2 70.12008 5.1 5.1 5.23 1441 75.3 70.22009 5.1 5.1 5.25 1438 75.5 70.42010 5.1 5.1 5.27 1435 75.6 70.52011 5.1 5.1 5.29 1433 75.8 70.72012 5.1 5.1 5.31 1408 74.8 69.72013 5.1 5.1 5.33 1383 73.8 68.72014 5.1 5.1 5.35 1359 72.7 67.62015 5.1 5.1 5.37 1334 71.7 66.62016 5.1 5.1 5.39 1309 70.6 65.52017 5.1 5.1 5.42 1285 69.6 64.52018 5.1 5.1 5.44 1260 68.5 63.42019 17.3 5.1 22.4 5.46 1235 67.4 45.02020 23.2 5.1 2w.3 5.48 1211 66.3 38.02021 17.3 5.1 22.4 5.50 1186 65.2 42.82022 5.1 5.1 5.52 1161 64.1 59.02023 5.1 5.1 5.54 1136 63.0 57.912024 5.1 5.1 5.56 1112 61.8 56.7 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

2025 5.1 5.1 5.58 1112 62.1 57.0 Internal Economic Rate of Return = 15.2X12026 5.1 5.1 5.60 1112 62.3 57.2

12027 5.1 5.1 5.62 1112 62.5 57.4 Net Present Value - 163.012028 5.1 5.1 5.65 1112 62.8 57.7 ___

2029 5.1 5.1 5.67 1112 63.0 57.92030 5.1 5.1 5.69 1112 63.2 58.12031 5.1 5.1 5.71 1112 63.5 58.42032 5.1 5.1 5.73 1112 63.7 58.6 a/ Conversion Factors2033 5.1 5.1 5.75 1112 63.9 58.8 Capital Goods: 0.802034 5.1 5.1 5.77 1112 64.2 59.1 Skilled Labour: 0.802035 5.1 5.1 5.79 1112 64.4 59.3 Unskilled Labour: 0.602036 5.1 5.1 5.81 1112 64.6 59.5 b/ Estimated for additional sales plus2037 -23.2 5.1 -18.1 5.83 1112 64.8 82.9 consumers' surplus. Elasticities:

l - ________ _____ l_ _ _____ _ |Price: -0.42Income: 2.00

- 128 - Ahnex 5. 3

Page 4 of 7

TURKEYBERKE HYDROPOWER PROJECT

Internal Economic Rate of Return/Sensitivity AnalysiaTen Percent Investment Cost Overrun

Economic Cost (1991) Average Incremental Total(US S Mfilion) Benefit Generation Economic Net

/kwh Benefits BenefitsYear Total O&S Total (US cents) (GWh) (US S) (US 5)

Investment Costs Costs b/ (MilLion) (Million)Cost

1992 59.2 0.0 59.2 0 0.0 -59.21993 76.7 0.0 76.7 0 0.0 -76.71994 112.8 0.0 112.8 0 0.0 *112.81995 96.9 0.0 96.9 0 0.0 -96.91996 32.1 0.0 32.1 0 0.0 -32.11997 5.1 5.1 5.00 1669 83.5 78.41998 5.1 5.1 5.02 1627 81.6 76.51999 5.1 5.1 5.04 1584 79.8 74.72000 5.1 5.1 5.06 1542 78.0 72.92001 5.1 5.1 5.08 1500 76.2 71.12002 5.1 5.1 5.10 1457 74.4 69.32003 5.1 5.1 5.12 1455 74.5 69.42004 5.1 5.1 5.14 1452 74.7 69.62005 5.1 5.1 5.16 1449 74.8 69.72006 5.1 5.1 5.19 1446 75.0 69.92007 5.1 5.1 5.21 1444 75.2 70.12008 5.1 5.1 5.23 1441 75.3 70.22009 5.1 5.1 5.25 1438 75.5 70.42010 5.1 5.1 5.27 1435 75.6 70.52011 5.1 5.1 5.29 1433 75.8 70.72012 5.1 5.1 5.31 1408 74.8 69.72013 5.1 5.1 5.33 1383 73.8 68.72014 5.1 5.1 5.35 1359 72.7 67.62015 5.1 5.1 5.37 1334 71.7 66.62016 5.1 5.1 5.39 1309 70.6 65.52017 5.1 5.1 5.42 1285 69.6 64.52018 5.1 5.1 5.44 1260 68.5 63.42019 19.0 5.1 24.1 5.46 1235 67.4 43.32020 25.5 5.1 30.6 5.48 1211 66.3 3W.72021 19.0 5.1 24.1 5.50 1186 65.2 41.12022 5.1 5.1 5.52 1161 64.1 59.02023 5.1 5.1 5.54 1136 63.0 57.92024 5.1 5.1 5.56 1112 61.8 56.72025 5.1 5.1 5.58 1112 62.1 57.0 Internal Economic Rate of Return * 14.112026 5.1 5.1 5.60 1112 62.3 57.22027 5.1 5.1 5.62 1112 62.5 57.4 Net Present Value X 136.62028 5.1 5.1 5.65 1112 62.8 57.72029 5.1 5.1 5.67 1112 63.0 57.92030 5.1 5.1 5.69 1112 63.2 58.12031 5.1 5.1 5.71 1112 63.5 58.42032 5.1 5.1 5.73 1112 63.7 58.6 ae Conversion Factors2033 5.1 5.1 5.75 1112 63.9 58.8 Capital Goods: 0.802034 5.1 5.1 5.77 1112 64.2 59.1 Skilled Labour: 0.802035 5.1 5.1 5.79 1112 64.4 59.3 Unskilled Labour: 0.602036 5.1 5.1 5.81 1112 64.6 59.5 b/ Estimated for additional saLes plus2037 -25.5 5.1 -20.4 5.83 1112 64.8 85.3 consuners' surplus. Elasticities:

Price: -0.42Income: 2.00

- 129 -Annex 5.3

TURKEY Page 5 of 7BERKE HYDROPOWER PROJECT

Internal Economic Rate of Return/Sensitivity AnalysisOne Year Delay in Project Inptementation

Economic Cost (1991) Average Incremental Total(US S Million) Benefit Generation Economic Net

-kwh Benefits BenefitsYear Total 081 Total (US cents) (GWh) (US S) (US S)

Investment Costs Costs b/ (Million) (Million)Cost

1 9 34.3 0.0 34.3 0 0.0 -34.31993 51.5 0.0 51.5 0 0.0 -51.51994 85.8 0.0 85.8 0 0.0 -85.81995 85.8 0.0 85.8 0 0.0 -85.81996 51.5 0.0 51.5 0 0.0 -51.51997 34.3 0.0 34.3 0 0.0 -34.31998 5.1 5.1 5.02 1627 81.6 76.51999 5.1 5.1 5.04 1584 79.8 74.72000 5.1 5.1 5.06 1542 78.0 72.92001 5.1 5.1 5.08 1500 76.2 71.12002 5.1 5.1 5.10 1457 74.4 69.32003 5.1 5.1 5.12 1455 74.5 69.42004 5.1 5.1 5.14 1452 74.7 69.62005 5.1 5.1 5.16 1449 74.8 69.72006 5.1 5.1 5.19 1446 75.0 69.92007 5.1 5.1 5.21 1444 75.2 70.12008 5.1 5.1 5.23 1441 75.3 70.22009 5.1 5.1 5.25 1438 75.5 70.42010 5.1 5.1 5.27 1435 75.6 70.52011 5.1 5.1 5.29 1433 75.8 70.72012 5.1 5.1 5.31 1408 74.8 69.72013 5.1 5.1 5.33 1383 ?3.8 68.72014 5.1 5.1 5.35 1359 72.7 67.62015 5.1 5.1 5.37 1334 71.7 66.62016 5.1 5.1 5.39 1309 70.6 65.52017 5.1 5.1 5.42 1285 69.6 64.52018 5.1 5.1 5.44 1260 68.5 63.42019 5.1 5.1 5.46 1235 67.4 62.32020 17.3 5.1 22.4 5.48 1211 66.3 43.92021 23.2 5.1 28.3 5.50 1186 65.2 36.92022 17.3 5.1 22.4 5.52 1161 64.1 41.72023 5.1 5.1 5.54 1136 63.0 57.92024 5.1 5.1 5.56 1112 61.8 56.72025 5.1 5.1 5.58 1112 62.1 57.0 Internal Economic Rate of Return = 14.3X2026 5.1 5.1 5.60 1112 62.3 57.22027 5.1 5.1 5.62 1112 62.5 57.4 Net Present Value a 132.82028 5.1 5.1 5.65 1112 62.8 57.72029 5.1 5.1 5.67 1112 63.0 57.92030 5.1 5.1 5.69 1112 63.2 58.12031 5.1 5.1 5.71 1112 63.5 58.42032 5.1 5.1 5.73 1112 63.7 58.6 a/ Conversion Factors2033 5.1 5.1 5.75 1112 63.9 58.8 Capital Goods: 0.802034 5.1 5.1 5.77 1112 64.2 59.1 Skilled Labour: 0.802035 5.1 5.1 5.79 1112 64.4 59.3 Unskilled Labour: 0.602036 5.1 5.1 5.81 1112 64.6 59.5 bI Estimated for additionat soles plus2037 -25.4 5.1 -20.3 5.83 1112 64.8 85.2 consumers, surplus. Elasticities:

_ ________ ________ ________ _________ ________ _________ Price: -0.42Income: 2.00

- 130 - Annex 5.3

Page 6.; of 7

TURKEYBERKE HYDROPOWER PROJECT

Internal Economic Rate of Return/Sensitivity AnalysisTen Percent Investment Cost Overrun and One Year Delay In Project Implem2ntation

Economic Cost (1991) Average Incremental Total(US S Million) Senefit Generation Economic Net

/kwh Benefits BenefitsYear Total O&M Total (US cents) (GWh) (US S) (US S)

Investment Costs Costs b/ (Million) (Million)Cost

1992 37.8 0.0 37.8 0 0.0 -37.81993 56.6 0.0 56.6 0 0.0 -56.61994 94.4 0.0 94.4 0 0.0 -94.41995 94.4 0.0 94.4 0 0.0 -94.41996 56.6 0.0 56.6 0 0.0 -56.61997 37.8 0.0 37.8 0 0.0 -37.81998 5.1 5.1 5.02 1627 81.6 76.51999 5.1 5.1 5.04 1584 79.8 74.72000 5.1 5.1 5.06 1542 78.0 72.92001 5.1 5.1 5.08 1500 76.2 71.12002 5.1 5.1 5.10 1457 74.4 69.32003 5.1 5.1 5.12 1455 74.5 69.42004 5.1 5.1 5.14 1452 74.7 69.62005 5.1 5.1 5.16 1449 74.8 69.72006 5.1 5.1 5.19 1446 75.0 69.92007 5.1 5.1 5.21 1444 75.2 70.12008 5.1 5.1 5.23 1441 75.3 70.22009 5.1 5.1 5.25 1438 75.5 70.42010 5.1 5.1 5.27 1435 75.6 70.52011 5.1 5.1 5.29 1433 75.8 70.72012 5.1 5.1 5.31 1408 74.8 69.72013 5.1 5.1 5.33 1383 73.8 68.72014 5.1 5.1 5.35 1359 72.7 67.62015 5.1 5.1 5.37 1334 71.7 66.62016 5.1 5.1 5.39 1309 70.6 65.52017 5.1 5.1 5.42 1285 69.6 64.52018 5.1 5.1 5.44 1260 68.5 63.42019 5.1 5.1 5.46 1235 67.4 62.32020 19.0 5.1 24.1 5.48 1211 66.3 42.22021 25.5 5.1 30.6 5.50 1186 65.2 34.62022 19.0 5.1 24.1 5.52 1161 64.1 40.02023 5.1 5.1 5.54 1136 63.0 57.92024 5.1 5.1 5.56 1112 61.8 56.7

|2025 5.1 5.1 5.58 1112 62.1 57.0 Internal Economic Rate of Return = 13.3%2026 5.1 5.1 5.60 1112 62.3 57.22027 5.1 5.1 5.62 1112 62.5 57.4 Net Present Value a 107.72028 5.1 5.1 5.65 1112 62.8 57.72029 5.1 5.1 5.67 1112 63.0 57.92030 5.1 5.1 5.69 1112 63.2 58.12031 5.1 5.1 5.71 1112 63.5 58.42032 5.1 5.1 5.73 1112 63.7 58.6 a/ Conversion Factors2033 5.1 5.1 5.75 1112 63.9 58.8 Capital Goods: 0.802034 5.1 5.1 5.77 1112 64.2 59.1 Skilled Labour: 0.802035 5.1 5.1 5.79 1112 64.4 59.3 Unskilled Labour: 0.602036 5.1 5.1 5.81 1112 64.6 59.5 b/ Estimated for additional saLes plus2037 -28.0 5.1 -22.9 5.83 1112 64.8 87.7 consumers' surplus. ELasticities:

_ _________ i_________ _________ Price: -0.42Income: 2.00

- 131 - Annex 5t3page 7 ot'f

TURKEYBERKE HYDROPOWER PROJECT

Internal Economie Rate of Return/Sensitivity AnaLysisLow Demand Growth (6.5X)

Economic Cost (1991) Averago Incremental Total(US $ NL Lion) Bonefit Goneration Economic Met

/kwh Benefits BenefftsYear Total OM TotaL (US cents) (GWh) (US I) (US 5)

Investment Costs Costs b/ (MilLfon) (MiLLion)Cost

0.0 53.8 0 0.0 -53.81993 69.7 0.0 69.7 0 0.0 -69.71994 102.5 0.0 102.5 0 0.0 -102.51995 88.1 0.0 88.1 0 0.0 -88.11996 29.2 0.0 29.2 0 0.0 -29.21997 5.1 5.1 1.39 1669 23.2 18.11998 5.1 5.1 1.39 1627 22.6 17.51999 5.1 5.1 1.39 1784 22.0 16.92000 5.1 5.1 5.06 1542 78.0 72.92001 5.1 5.1 5.08 1500 76.2 71.12002 5.1 5.1 5.10 1457 74.4 69.32003 5.1 5.1 5.12 1455 74.5 69.42004 5.1 5.1 5.14 1452 74.7 69.62005 5.1 5.1 5.16 1449 74.8 69.72006 5.1 5.1 5.19 1446 75.0 69.92007 S.1 5.1 5.21 1444 75.2 70.12008 5.1 5.1 5.23 1441 75.3 70.22009 5.1 5.1 5.25 1438 75.5 70.42010 5.1 5.1 5.27 1435 75.6 70.52011 5.1 5.1 5.29 1433 75.8 70.72012 5.1 5.1 5.31 1408 74.8 69.72013 5.1 5.1 5.33 1383 73.8 68.72014 5.1 5.1 5.35 1359 72.7 67.62015 5.1 5.1 5.37 1334 71.7 66.62016 5.1 5.1 5.39 1309 70.6 65.52017 5.1 5.1 5.42 1285 69.6 o4.52018 5.1 5.1 5.44 1260 68.5 63.42019 17.3 5.1 22.4 5.46 1235 67.4 45.02020 23.2 5.1 28.3 5.48 1211 66.3 38.02021 17.3 5.1 22.4 5.50 1186 65.2 42.82022 5.1 5.1 5.52 1161 64.1 59.02023 5.1 5.1 5.54 1136 63.0 57.92024 5.1 i.1 5.56 1112 61.8 56.72025 5.1 5.1 5.58 1112 62.1 57.0 Internal Economic Rate of Return * 12.0X2026 5.1 5.1 5.60 1112 62.3 57.22027 5.1 5.1 5.62 1112 62.5 57.4 Net Present value a 71.82028 5.1 5.1 5.65 1112 62.8 57.72029 5.1 5.1 5.67 1112 63.0 57.9 _2030 5.1 5.1 5.69 1112 63.2 58.12031 5.1 5.1 5.71 1112 63.5 58.42032 5.1 5.1 s.73 1112 63.7 58.6 a/ Conversion Factors t2033 5.1 5.1 s.75 1112 63.9 58.8 CapitaL Goodes: 0.802034 5.1 5.1 5.77 1112 64.2 59.1 SkiLled Labour: 0.802035 5.1 5.1 5.79 1112 64.4 59.3 UntskiLled Labour: 0.602036 5.1 5.1 5.81 1112 64.6 59.5 b/ Estimated for additional sles plus2037 -23.2 5.1 -18.1 5.83 1112 64.8 82.9 consun rs' surplus. Elasticities:

- - -. Price: -0.42Income: 2.00

- 132 -

Annex 5.4

CUKUROVA REGIONECONOMIC ANALYSIS OF

TRANSMISSION EXPANSION

NETYEAR INVESTMENT O&M TOTAL DEMAND REVENUES BENEFIT

(US$ M) a/ (US$ M) b/ (US$ M) (GWh) (USS M) c/ (US$ M)

1992 3.114 0.06 3.174 4324 0 -3.1741993 11.612 0.29 11.902 4627 0 -11.9021994 11.037 0.51 11.547 4951 0 -11.5471995 3.984 0.59 4.574 5298 1.8044 -2.76961996 1.459 0.62 2.079 5669 3.7336 1.65461997 0.62 0.62 6065 5.7928 5.17281998 0.62 0.62 6490 8.0028 7.38281999 0.62 0.62 6944 10.3636 9.74362000 0.62 0.62 7457 13.0312 12.41122001 0.62 0.62 7457 13.0312 12.41122002 0.62 0.62 7457 13.0312 12.41122003 0.62 0.62 7457 13.0312 12.41122004 0.62 0.62 7457 13.0312 12.41122005 0.62 0.62 7457 13.0312 12.41122006 0.62 0.62 7457 13.0312 12.41122007 0.62 0.62 7457 13.0312 12.41122008 0.62 0.62 7457 13.0312 12.41122009 0.62 0.62 7457 13.0312 12.41122010 0.62 0.62 7457 13.0312 12.41122011 0.62 0.62 7457 13.0312 12.4112

ERR . 247.

al Project Costs are in 1991 economic prices.b/ O&M costs-represent 2% of project cost.c/ Revenues from sale of the incremental electricity transmitted

through tho new network and sold at LRMC of transmission.

60

- 133 - Annex 5.5

Cukurova RegionEconomic Analysis of Transmission Expansion

Sensitivity Analysis

Incremental Internal RateTariff of Return

(US%:/Kwh)(%

6.0 23.06.5 21.45.2 20.55.0 19.84.5 18.14.0 16.23.5 14.23.1 12.03.0 11.9

BULGARIA __ '-\ 28' °2 Jo1

?& z ^E ,\- sno ~~~~~~~~~~~~~~~~~~~~~~~~GEORGIA

GRE ECt = 9 * f E _ -t g

.0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1

N)l ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~-

X / >i =~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~- ws ;PAN

4s¢1Ortk AJ @_ 9 \ \ / * y; * Et gJ g |~~~~~~~~~~~~~~~4%ARMN

RA

t-: ?.: ' -- i.s, 'i -. .>u -z-,,- -- ,,~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~---------

-36 , e_--<f. 7 TURKEY''i<w 'A-tsurU a J | BERKE HYDROPOWER PROJECT

to mi Foroel.. l38 23672 - MAIN GENERATION AND TRANSMISSION SYSTEMN ~~~~~~~~~AS OF JANUARY 1992

SYRIAN ARAB REPUBLIC AS OF JAU LANTS 19,,~~~~~ .- '- ' z; , In, operao'on . nopcrot

L* e Co Ucde (osrctoono Pd ite * o L oC4l0r 4'I-c4fluto

C Y P R U Prjec

.Xme4vi.e%forI. BtTRANSM SSION LINES

.eS8&e-ed 3 -de I41V0

porof2hehirsd-t,~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ - - - - -- jd -,eron-rcl- .,d ful-r

KIswe@~Faner lLOMITtAW3So 0 00 290 3C oLEBANON ) Proec,

L 4 * b .. e d o o .. 2 8 ' 8 1 4 8 8 6 R B 2 4 0 2 ' C ' - _ ___ _

OTHER POWER BERKE HYDROPOWER PROJECTCOMPANIES C.E.A,5, CUKUROVA REGION BOUNDARY' TRANSMISSION SYSTEM

ONDR PAINUNDER U ODR PLNNN PROVNCE SOUNDAR ES U ROA EG NIN OPERATION CONSTRUCTION IN OPERATION CONSTRUCTION PROVJNECT I ONAL BOUKUUROVA RfRGION

POWER PLANTS:* ~~~~~~ ~ ~~THERMAL |r Uoat2 n1 e; omj° s s rodonm

c C * U HYDRO

TRANSMISSION LINES: , i 380 kVV B.A Y S : Re;i //

SEE NOTE" 66 kV ( K A H R AM A N Mt A R A S SUBSTATIONS r K..dil 155 MW

A A * NEW /A* A A EXISTING/EXTENSION Ao8 K .( cRKndill 103 MW /

F.k. ,

ED K-diE H 103 MW X I#.A. wr nin f y on C f ,^ 5 Ohw ne hmn on hri c cK-m M .... I.M.n,.l.l 120 MW

- *Ia.MAU.IG E A D A N A T A n

F. 5ey#ihir ,.iT>rosr Ko,-nli , R . A D YA M A I

K.- ~ ~ ~ ~ ~ ~ -Kozon ONYALoren Koron >, A ( AYY

K.,.,.l c~~~~~~~~~~~~~~~~~~~~~~~~RMNA~. ~ US

70 MW ~~~~~~~~~~~~IA 3 n , ULAIA

.Ad.Ad, mw fh~~~~.oTbiA. K

g- C~~~~~~~~~~ E IL X:

fr~~~~~ |inone K y tR f / " ' amst h.R,. ~ ~ ~~~~~~~~~~~~~T.5I.TI * a Mediterranean Sea 1 °SYRIAN ARAB REPUBLIC

m________________________________ - Ulueino j/i~i A I A Y J bRO MANIA _A A AY _

X ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~H I-g>;u.EY §, So 4.0 Cl; ; t _ A oYoy ~~~~~~~~~~~~~~~~ ~~~~~~~~~~~All, AA...qDC-r A

lb lb, j; 4 Me di te rr an e an S ea t .o/t .- , SYRIAN IRA k! r +~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~IA