Turkey - Fourth TEK Transmission Project

Document of The World Bank FOR OFFICIAL USE ONLY 0&t/- SE-6 Tu Report Ne- 5571-TU TURKEY FOURTH TEK TRANSMISSION PROJECT STAFF APPRAISAL REPORT May 20, 1985 Projects Department Europe, Middle East and North Africa Regional Office This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization.  CURRENCY EQUIVALENTS Currency Unit Turkish Lira (TL) TL 1 100 Kurus (krs) US$1 TL 450 TL 1 US$.002 Currency equivalents are those effective January 1985, unless otherwise indicated. WEIGHTS AND MEASURES kVA = kilovolt ampere kW - kilowatt kWh - kilowatt hour GWh (Gigawatt hour) = 1,000,000 kWh HV = High Voltage kV (kilovolt) = 1,000 volts MW (Megawatt) = 1,000 kW MVA (Megavolt-ampere) 1 1,000 kVA MVAR (Megavolt-ampere reactive) - 1,000 kVAR One meter (m) = 3.28 feet One kilometer (km) - 0.624 miles One kilogram (kg) (1,000 grams) - 2.2 pounds Ore ton (metric ton) (1,000 kg) - 2,205 pounds One kilocalorie (kcal) (1,000 calories) = 3.968 BTU GLOSSARY AND ABBREVIATIONS AGMs - Assistant General Managers CEAS - Cukurova Elektrik A.S. (Cukurova Power Company) DSI - Devlet Su Isleri (State Hydraulic Works) DYB - Devlet Yatirim Bankasi (State Investment Bank) ELTEM-TEK - Elektrik Tesisleri Mishen Dislik Hizmetteri ve Ticaret Anonim Sirketi EdF - Electricite de France ICB - International Competitive Bidding IDA - International Development Association KEPEZ A.S. - Kepez Electric Company KfW - Kreditanstalt fur Wiederaufbau LRMC - Long-Run Marginal Cost MENR - Ministry of Energy and Natural Resources MTA - Mineral Research Institute PEE - Public Economic Establishment PIPMU - Project [mplementation and Performance Monitoring Unit PPAR - Project Performance Audit Report PPF - Public Participation Fund SAL - Structural Adjustment Loan SEE - State Economic Enterprise SEI - Southern Electric International SPO - State Planning Organization TEK - Turkiye Electrik Kuruxu (Turkish Electricity Authority) TKI - Turkiye Komur Isletmeleri Kurumu (Turkish Coal Enterprise) TPAO - Turkiye Petrollerei Anonini Ortakligi (Turkish Petroleum Corporation) Fiscal Year - January 1 to December 31  TURKEY FOR OFFICIL USE ONLY STAFF APPRAISAL REPORT FOURrH TEK TRANSMISSION PROJECT TABLE OF CONTENTS Page No. I. THE ENERGY SECTOR ........................ The Role of the Energy Sector in the Economy ................... I The Resource Base ........................... I Main Agencies ........................................ 2 Demand and Supply ........................................ 3 Energy Policy .................................. .. .... 4 Bank Strategy ........................................ 5 II. THE ELECTRIC POWER SUBSECTOR ................................... 7 Background ..................................................... 7 System Characteristics ...................................... 7 Sectoral Development 1971-1984 .............................. 9 Government's New Strategy ...................................... 9 Institutional Development ................................... 10 Pricing and Demand Management ............................... 12 Electricity Planning .................................... 13 Medium-Term Investment ..................................... 14 Bank"s Role in the Pswer Subsector ............................. 16 III. THE PROJECT ENTITY: TEK ....................................... 19 Legal Context .............. 19 Organization and Management of TEK ............................. 19 Manpower Development and Training .............................. 21 General Characteristics of the TEK Power System ........ o . ...... 21 TEK's Power System Operation Performance ....................... 22 IV. THE PROJECT .................................................... 24 Project Setting and Objectives .............. .. ................. 24 Project Description ........ .............. ...................... 24 Status on Engineering ....................... 25 Project Cost ......................... .......................... 26 Training ,........,.,,................................................ 26 Project Financing Plan ......................................... 28 Lending Arrangement ............................................ 28 Project Implementation ......................................... 28 Following a mission to Turkey in January/February 1985, this report was prepared by: Z. Ladhibi (Power Engineer), A. Posada (Power Engineer), I. Johnson (Economist), L. Meek Foote (Financial Analyst), and J. Chassard-Manibog (Consultant). This document has a resticted distibution ad may be used by recipints only in te perfoimnce of their ofrxic auties. Its contents may not otherwise be didosed without World Bank authorizaton.  - ii1 - TABLE OF CONTENTS (continued) Page No. IV. THE PROJECT (Cont'd) Procurement . . .................................................. 29 Disbursements ...32 Special Account .. . ............................................ 33 Retroactive Financing and Advanced Contracting .... 33 Environmental Impact . ............ 34 Project Risks . . . ............ 34 V. FINANCIAL ASPECTS .35 Introduction .35 Recent Financial Performance .35 Electricity Pricing ...................... 35 Working Capital .................... 36 Debt Service .................... 38 Recent Trends in Sector Financing and Internal Cash Generation .39 Public Participation Fund and Keban Revenue-Sharing Certificates .40 Financial Planning and Accounting Practices .41 Financial Planning ................... , . ....... 41 Audits ...... . ................................... 42 Asset Revaluation .................., , , . ... 42 Technical Assistance to Improve Accounting .43 Future Financial Prospects .43 Financing of Medium-Term Power Investment Program .......... 43 Future Financial Position of TEK .48 Agreed Revenue Covenant and Supporting Covenants .48 Potential for Private Investment in Power .49 VI. PROJECT JUSTIFICATION .50 Least-Cost Solution .50 Return on Investment .50 VII. AGREEMENTS REACHED AND RECOMMENDATION .52  - iii1 TABLE OF CONTENTS (continued) ANNEXES 1.1 Energy Balances 2.1 Demand Forecasts 2.2 Electric Power Investment Program (1985-1989) 2.3 Tariff Study 3.1 Legal Framework of TEK and Related Legislation 3.2 Organization Chart of the Turkish Electricity Authority 3.3 Personnel of TEK by Function and Level of Training 4.1 Detailed Project Description 4.2 Yearly Breakdown of the Total Project Cost 4.3 Cost Arranged by Nature of Goods and Services - Lines Component 4.4 Cost Arranged by Nature of Goods and Services - Substations Component 4.5 Estimated Implementation Schedule - Lines Component 4.6 Estimated Implementation Schedule - Substations Component 4.7 Estimated Procurement Schedule - Lines Component 4.8 Estimated Procurement Schedule - Substations Component 4.9 Estimated Disbursements Schedule 4.10 Comparison of Disbursement Profiles 5.1 Bulk (High Voltage) Electricity Tariffs: 1983-1985 5.2 Bulk (High Voltage) Tariffs Compared with TEK's Annual Revenue and Inflation: 1982-1985 5.3 Retail (Low Voltage) Electricity Tariffst 1983-1985 5.4 Income Statements for TEK (1981-1990) 5.5 Balance Sheets for TEK (1981-1990) 5.6 Statement of Sources and Uses of Funds for TEK (1981 - 1990) 5.7 Summary of Financial latios 5.8 Assumptions used in Financial Forecasts 6.1 Rate of Return Analysis 7.1 Selected Documents and Data Available in the Prcject File MAP IBRD 18845 May 14, 1985  1. THE ENERGY SECTOR The Role of the Energy Sector in the Economy 1.01 In 1977, four years after the first of the major oil price increases, Turkey's oil import bill was equivalent to 84Z of its merchandise export earnings. By 1980, the situation was even more precarious; oil imports stood at 1242 of total merchandise export earnings. Based on remedial actions in line with the Government's structural adjustment program the situation had, by 1984, improved and the above ratio had declined to 53%. The improvement was a result of both strong performance of merchandise exports as well as a policy of holding the growth in imports of crude oil and oil products to a more moderate level (oil imports grew by an average annual rate of 3.6Z between 1981 and 1984). However, despite this improvement the need to move away from an excessive reliance on oil imports remains crucial to Turkey's medium-term development strategy, as the latter is dependent on the economy's ability to mobilize foreign exchange. 1/ 1.02 High priority was assigned to the energy sector by Government during the 1980-83 period of structural adjustment. Energy policy was geared to increasing the domestic supply of energy, primarily through increased capital investment to about 35% of total public investment compared to about 20% during the 1970's. In parallel greater attention was given by Government to energy pricing policy as a means of restraining demand and mobilizing resources. In particular Government has ensured that petroleum products reflect economic costs as reflected by world prices, and electricity tariffs have increased in real terms over the period (para. 2.19). Although lignite prices declined slightly in real terms in 1981-83 a turnaround in lignite pricing policy during 1984 resulted in a 30% increase in April 1984 and a further 29.6% in January 1985 thus exceeding inflation over the 12-month period. The Resource base 1.03 Turkey has substantial untapped lignite and hydropower resources, as well as more limited, but still important, oil, gas and coal resources and geothermal potential. Hydropower with potential economic viability is estimated at about 29,500 KW under average hydrological conditions and corresponds to an annual production of about 100,000 GWh. Only 152 has been developed so far, but this is projected to rise to about 30% by 1990. Proven recoverable reserves of oil are about 16 million tons. However, potential reserves that may become economically recoverable using enhanced oil recovery 1/ See "Turkey-The Vth Five Year Plan in the Context of Structural Adjustment: A Review" (Green cover), February 27, 1985.  - 2 - techniques currently being tested could be as high as 30 million tons. Oil production has been declining over the last decade, as few discoveries have been made in recent years; in 1983 production was about 3 million tons. Proven recoverable gas reserves are about 400 billion standard cubic feet. Domestic gas will, however, be supplemented, beginning in 1987, by large scale imports of natural gas from the USSR. Total known reserves of hard coal are estimated at about 1 billion tons, all located in the north of Turkey (Zonguldak). Coal production has been declining as operations move to deeper, less accessible seams; in 1983 production was about 3.5 million tons, equivalent to 2.2 million tons of oil equivalent (toe). Proven and probable lignite reserves are about 8 billion tons, but about half of this is of extremely low quality (950-1,000 kcal/kg). Lignite production in 1983 was about 20 million tons, equivalent to about 4.6 million toe. The economic costs of domestic lignite appears to be very high, and, in some mines, not competitive with imported coal. There is potential for geothermal development, for both space heating and electricity generation. A foreign company with extensive experience in geothermal power has recently undertaken a technical review of a number of promising geothermal sites, and discussions with the Government on possible terms and conditions for developing one of these sites are currently in progress. Main Agencies 1.04 The energy sector in Turkey is characterized by the dominance of government-owned enterprises and agencies. The Ministry of Energy and Natural Resources (MEMR) is responsible for the development of energy resources in Turkey. Under MENR, the Turkish Coal Enterprise (TKI), the Turkish Petroleum Company (TPAO), and the Mineral Research Institute (MTA) have responsibility for the extraction of fossil fuels and radioactive minerals. Identification, design and construction of hydro projects is entrusted to the State Hydraulics Authority (DSI). The Turkish Electricity Authority (TEK) is responsible for the generation, transmission and, since November 1982, the distribution of almost all the electricity sold in Turkey. TEK is also responsible for the implementation of the Government's program for rural electrification and the construction of all generating and transmission facilities, with the exception of hydroelectric plants for which DSI has responsibility (see Chapter III). 1.05 Private sector participation in the supply of electricity was until 1983, confined to two small semi-private utilities (CEAS and KEPEZ) and industrial comparies which generated power for their own use, often in conjunction with the production of steam for process heat. However, recent shifts in government energy policy now give greater encouragement to private sector participation in the development and production of energy (para. 2.16).  3 Demand and Supply 1.06 Total gross energy consumption was about 38 million toe in 1983, of which co ercial energy consumption amounted to about 30 million toe. Petroleum made up the most significant share of primary commercial energy (60%) witn the balance made up of lignite (18%), hydropower (11%), coal (10%) and imported electricity (1X). About 24% of final commercial energy consumption was in the form of electricity. Non-commercial energy production (primarily fuelvood, but also other biomass) was an important energy source, accounting for 23% of total energy consumption. Imported energy (petroleum, hard coal and electricity) represents about 45% of total energy supply. Annex 1.1 presents energy balances for the period 1978-1983. 1.07 The most notable change in the pattern of energy consumption over the past two decades has been the decrease in the relative share of hard coal in total energy. This was accompanied by a rapid growth in consumption of petroleum until the mid-1970s, peaking at over 50% in 1977/78; and a rapid rise in the share of lignite (primarily for thermal power production) and hydroelectric power consumption starting in the second half of the 1970's. During this period, hard coal consumption stayed relatively constant in absolute terms, while traditional biomass energy sources increased slightly in absolute t3rms, but decreased steadily as a percentage of total energy consumed. 1.08 The most important factors in the growth of energy demand will be the growth rate of the economy as a whole, the growth rate of the energy-intensive industrial sector of the economy, and the extent to which Government implements an energy conservation and demand management program. Bank estimates indicate that the growth rate of the economy would average about 5.6% pe. annum during the 1980s and that the industrial sector would grow sl:-ghtly faster at about 7%. Under these projections and in the absence of a vigorous demand management program, electricity demand is expected to grow by over 200Z between 1980 and 1990 to about 60,000 GWh; lignite demand for thermal power plants would grow by almost tenfold to about 50 million tons; and petroleum products demand would grow by 110% to 30 million tons of oil equivalent. In total this -ould represent approximately 58 million toe, an increase of over 8% per annum from 1983 (38 million toe). However supply constraints, especially in the lignite sector (para. 2.30) and in the power sector (para. 2.03), will result in demard not being met, at least to 1990. The energy deficit is estimated by 1990 to be in the region of 7-8 million toe. 1.09 There is, however, considerable scope for conservation of energy particularly in the industrial sector which currently accounts for 40% of total energy consumption and this is expected to rise to 45% by 1990. The industrial sector also consumes 64% of total electricity supplied. Furthermore eight industries 1/ account for 40% of total industrial energy 1/ Iron and steel, cement, fertilizer, pulp and paper, glass, brick, aluminum, copper.  consumption, from which it has been estimated that almost 1 million toe could be saved through investment in conservation. The total estimated potential energy savings in the industrial sector, including a large number of energy-inefficient small industries, is about 2.4 million toe. There is therefore an urgent requirement for an energy conservation program in Turkey (para. 1.10). 1.10 The Gove-nment is in the process of developing a program for the conservation of energy by encouraging efficient use in existing and new industrial enterprises. Energy efficiency progrsms and legislation have been evaluated by both the MENR and the SPO, and legislation has already been passed which allows for tax credits for various types of investments in energy efficiency improvements. The Government has initiated programs to assist industrial firms to learn how to improve their energy efficiency in existing operations. The Bank included technical assistance for energy audits in selected manufacturing facilities as part of the assistance to the Government under Loan 1916-TU. These audits have now been completed and the Bank is currently reviewing their findings with a view to financing a conservation project. The findings of the energy audit on the Anbarli E'lectric Power Plant have been used as the basis for preparing a subcomponent of the proposed System Operations Assistance Project. TEK has also hired consultants to assist in the development of an energy conservation and load management program (para. 2.21). Energy Policy 1.11 To meet its energy requirements Turkey launched a massive program in the late 1970's to increase the domestic production of electricity and lignite. This program tended to stretch the implementation capabilities of the state energy agencies, and spread the resources available too thinly over too many projects, with resulting long delays in completion schedules. This has, in turn, resulted in an energy deficit which is likely to remain a feature of the Turkish economy at least through the 1980's (para. 1.08). MENR and TEK are currently in the process of improving their energy planning capabilities (para. 2.21) and MENR has produced Turkey's first energy policy paper. The recent Five-Year Development Plan!/ contains the following energy sector objectives: - priority is to be given to domestic sources of energy, especially, hydro and lignite, provided that they are economically justified; - imported energy including, but not limited to oil, will be considered; renewable and nonconventional resources such as geothermal, solar and biogas are to be supported; and 1/ V. Bes Yillik Kalkinma Plani 1985-1989, State Planning Organization, June 1984  - private sector financing, both local and foreign, will be sought for participation in energy development. 1.12 One feature of Government which represents a departure from previous energy policy concerns the expanded role of the private sector in the development and production of energy. Government policy is now quite clearly to encourage private sector participation in the energy sector. There are now no legal constraints to private sector generation, and private utilities (KEPEZ and CEAS) have plans to increase their capacities. In addition, the State Planning Organization (SPO) is currently undertaking, with assistance from consultants, preliminary studies to assess whether private financiers could be sought to construct and operate thermal plants based upon imported fuels (coal, nuclear) and geothermal. Over the long term this could have a fundamental bearing on the financing, staffing and planning of the subsector (para. 2.16). Bank Strategy 1.13 The Bank has prepared and discussed with Government an Energy Assessment Study as well as subsector studies on electricity and lignite_/. In addition, under SAL V Government agreed to develop and discuss with the Bank an energy action plan and MENR has instructed the individual energy institutions to prepare detailed medium term action programs (para. 2.11). As an ongoing part of our policy dialogue the Bank prepared an energy sector strategy paper on strategy and actions required in the energy sector. In discussions of this palper agreement was reached with the Government and related energy institutions on the content, analysis and scope of the issues facing the energy sectcr (para. 2.12). 1.14 The strategy for Bank lending and operational work in the energy sector is to focus on selected key issues in the medium term in order that projects may be brought on stream as rapidly as possible and the efficiency of existing energy producing facilities be maximized. The magnitude of the looming energy supply gap (para. 1.08) is such that priority should be accorded to projects aimed at reducing the deficit as soon as possible. Projects with relatively short gestation periods such as improvement of efficiency within existing facilities, industrial conservation, reduction of energy leakages, and utilization of energy resources which can be brought on stream rapidly, should have priority. Furthermore the private sector may well offer opportunities for developing energy resources more rapidly than the public sector, and emphasis will be given to investments which may increase private sector participation. 1/ See Turkey: Issues and Options in the Energy Sector (Blue Cover) 3877-TU, dated March 1983 Turkey: Electricity Planning and Investment (Green Cover) 5031-TU, dated June 22, 1984. (EPI) Turkey: Coal and Lignite Subsector: The Analysis of Sectoral Development Prospects and Main Issues (Green Cover) 5021-TU, dated September 18, 1984.  - 6 - 1.15 In conjunction with the strategy to address the key medium term issues the Bank will also emphasize the strengthening of the various energy institutions through technical assistance in training, manpower development, technical, economic and financial planning and project management. Finally, the open and constructive policy discussions between Government and the Bank undertaken in conjunction with SAL V (para. 1.13) will be continued on a regular and sustained basis and should provide a continuing policy framework within which both project lending and the development of a robust project pipeline can proceed.  - 7 - II. THE ELECTRIC POWER SUBSECTOR A. BACKGROUND System Characteristics 2.01 The present (1984) installed power capacity in Turkey is about 7,600 MW of which 3,500 MW (50%) is thermal and the balance hydro. The share of hydro power has increased over the past ten years from 33% in 1972 to about 50Z in 1984. On the thermal side lignite has made an increasing contribution to the production of electricity. Total gross generation in 1984 was about 30,000 GWh, of which TEK accounted for almost 90% and this was supplemented by 2,500 GWh imported electricity from Bulgaria and the USSR. This was less than the potential effective demand, estimated at 35,000 GWh. There is considerable evidence that power shortages have caused cutbacks in production in industries such as cement, textiles and paper. In addition to the capacity constraint, the high ievel of total system losses (technical losses plus unaccounted for energy), at about 20%! contributed to the supply shortages. 2.02 Demand Forecast. Growth in demand has averaged about 9Z per annum over the period 1965-1983. Between 1970 and 1983 the percentage of population with public electricity supply rose from 51% to 78Z. Per capita consumption of electricity is currently about 550 kWh. The current medium and long-term forecasts, prepared in connection with TEK's long-term generation plan (1987-2005) are based upon the relationship between electricity consumption and industrial output. They show total energy demand (GWh) growing at about 102 per annum to 1990 and peak demand (MW) increasing at about 8%. Beyond 1990 TEK project a growth in peak demand of about 9.5% per annum and about 9% per annum in energy. This implies a continuation of the high (1.6-1.8) elasticities with respect to GDP and sectoral (primarily industrial) growth rates. These are higher than in many other industrializing countries (e.g. Korea, Hungary, Singapore) which have been able to reduce electricity demand significantly by implementing a program of demand management. Given the difficulty Turkey has faced in expanding electricity supply (para. 2.09) it is critical that efforts be made to bring about lower demand elasticities. A program of demand management implemented in parallel with a program to improve efficiency and plant availabilitv within the electricity subsector could produce significant savings in investment over the medium to long term (para. 2.17). Annex 2.1 presents a summary of the long term demand forecasts. 2.03 Generation. Annex 2.2 gives details of the forecast electric energy and capacity balances. The forecast was prepared by the Bank on the basis of an updated implementation schedule, likely slippages in the commissioning of I/ This compares with losses of about 10% in a well designed and operated transmission and distribution network.  - 8 - some hydro or thermal pover plants and a review of potential fuel supply bottlenecks, especially in the lignite sector. The installed capacity is expected to grow from about 8,000 KW in 1985 to almost 15,000 MW by 1990, with the share of hydropower remaining constant at about 53%. Assuming average water flows, the share of hydropower in total generation is expected to be between 65% and 70% over the period. This estimate is, however, dependent on the extent to which lignite supply constrains the availability of thermal generation. The Bank assumed that it would take up to four years for major lignite mines to meet full power plant requirements. Any improvement in the lignite mines' abilities to supply lignite would have a major impact upon inereasing generation from the thermal plants (para. 2.30). However, it is unlikely that the projected generation expansion to 1990 will be able to meet the system's energy requirements (GWh), even under average hydrological conditions and with imports of up to 2,500 GWh per annunm from Bulgaria and USSR. 2.04 All new thermal power plants, under construction or proposed in the investment program, would use lignite for power generation, with the exception of a coal-fired plant to replace an old unit at Catalagzi, a small pilot (18 MW) geothermal plant, and a new 600 MW combined cycle plant located near Istanbul to utilize domestic gas (Hamitabat) and imported gas (USSR). 2.05 Given the shortfall in supply (para. 2.03) the forecast of electricity sales has been derived from the Bank's projections of available generation. Under this forecast, TEK's sales would increase at an annual average rate of about 12% to reach almost 50,000 GWh by 1990 (Annex 2.2, Attachment 1). It is estimated that by the early 1990s the electricity system would be in equilibrium and generation would be adequate to meet projected demand. 2.06 Trausmission. The salient feature of the Turkish transmission system is that the largest load centers are located at considerable distances from the existing and/or committed major power plants, most of which are to be located in the far east or south west of the country. For technical reasons of system stability and reliability, there is a need for a more geographically balanced system, especially in European Turkey (Thrace) where the system is particularly vulnerable. Greater flexibility could be afforded to the system by the installation of additional capacity in the Istanbul area. Government has recent'ly approved the construction of a combined cycle power plant (600 MW) located at Hamitabat, some 100 kms from Istanbul, to utilize indigenous natural gas. TEK is also to undertake a feasibility study, to be financed under the proposed Power System Operations Assistance Project, for an additional combined cycle power plant of 1,000 MW located in Thrace and fueled by natural gas. 2.07 Distribution and Village Electrification. Since 1982 TEK has been responsible for urban distribution (para. 3.02). Prior to the TEK takeover the municipalities were responsibLe for urban electrification. During the  1970s there was a sharp decline in the share of investment in urban distribution, from 14% of total subsector investment in 1975 to 6% in 1979 despite an urban population growth rate of almost twice the national average. Problems of underinvestment were compounded by the fact that many municipalities practiced cross subsidization of services, utilizing revenues from urban electricity sales to finance other services. This resulted in a deterioration in the physical condition of the urban networks and high losses. Recent estimates by TEK place losses at 1,500 GWh, of which pilferage and illegal connections account for about 500 GWh and technical losses the balance. Almost 1,000 GWh of total losses occur in the three largest urban areas, Istanbul, Ankara and Izmir. Rehabilitating the urban networks should be accorded greater priority than hitherto since it would provide a cost-effective and rapid way to increase the capacity of the system. TEK has hired consultants (EdF, France) to assist in identifying losses and to prepare an investment program for the urban networks. Izmir has been selected by TEK for the development of the first comprehensive investment masterplan. 2.08 The village electrification program forms part of Government's social policy of providing basic services to rural areas, especially to those provinces designated as least developed and most impoverished. As such, Covernment objectives are geared to regional development, equity considerations and poverty alleviation rather than either financial cost recovery or economic efficiency. By the end of 1984, about 70% of the villages had been connected to the national system, and the target is to electrify the balance by the end of 1990. SectorM. Development 1971-1984 2.09 The Turkish power sub-sector has been confronted with problems of major proportions. Electricity supply has been insufficient to meet demand in every year since 1971, resulting in high costs to the economy, as imports increased and supply interruptions became more frequent. The shortfalls in supply are attributed mainly to institutional problems, especially the shortage of qualified staff in the public sector agencies responsible for planning and implementing the development of the electricity sub-sector, and shortages of local funding resources. This has resulted in project delays, consequent substantial cost escalations, chronic power shortages, frequent and protracted power plant breakdowns due to inadequate maintenance, and high system losses. The shortages of qualified staff in TEK has resulted in resources, spread too thinly over too many projects in the investment program. Government has, however, now recognized many of these problems and is actively addressing them. B. GOVERNMENT'S NEW STRATEGY 2.10 Meeting electricity demand in Turkey will require a major coordinated effort on behalf of the major agencies in the subsector since it will require  - 10 - that the country bring on stream three times more capacity in the 1980s than in the 1970s and sustain that momentum throughout most of the l990s. Furthermore it will require that scarce resources be tied up in technologies new to the country (e.g. gas based generation, geothermal, nuclear) and in projects of a size unprecedented in the country. 2.11 The Government is however, committed to a program to deal with the issues faced by the electricity sector and plans to focus particularly on the medium term issues of expanding output, maximizing efficiency and, in line with the Government's structural adjustment program, curtailing the country's oil import bill. MENR has instructed all the individual energy institutions to prepare detailed medium term action programs to address the following priority issues: (a) managerial and institutional improvements, in particular the strengthening of planning, project selection and project management capabilities through increased training and technical assistance; (b) the completion of ongoing priority projects in the electricity subsector and in lignite mines to supply key thermal plants; (c) the upgrading of existing facilities with special reference to improving operational efficiency, retrofitting of plant and provision of adequate spare parts; (d) evaluation and implementation of a broader range of alternative energy supplies including natural gas, imported coal, and geothermal; (e) energy conservation, including the identification of investments and pricing policies to increase the efficiency with which energy is both produced and consumed; and (f) an increased role for the private sector, particularly in the construction and operation of power plants and operation of lignite mines. 2.12 In the electric power subsector both Government and TEK have recognized the nature and scope of the issues outlined in para. 2.09 and progress toward resolving many issues has been made. Paras. 2.13 to 2.31 below indicate actions taken or planned. Institutional Development 2.13 Maintenance and operation of the power system. The exigencies of maintaining supply at all costs has resulted in TEK abandoning a systematic maintenance plan for thermal power stations. This in turn has led to frequent and often protracted outages as well as major losses in plant efficiency and output. TEK has increased the allocation for equipment for operations,  - 11 - maintenance and spare parts, as well as specialized training in pover plant and network maintenance. The proposed Bank financed Power Systems Operations Assistance Project will result in improved operational efficiency and will develop manpower skills for operations and maintenance within TEK. 2.14 Project management. Inadequate project management has resulted in considerable delays in implementation and consequent high costs to the economy as project costs have escalated and supply shortages increased. Greater emphasis is being placed upon the development of strong project management teams utilizing both local and foreign expertise, increased autonomy at the project management level, especially on financial, procurement and personnel matters, and greater selectivity to ensure that high caliber teams are recruited. Initiatives taken by TEK have included a full project management contract for the construction of the Thrace Combined Cycle Plant and greater management autonomy at the Elbistan site. Furthermore, the establishment of ELTEM-TEK, a nublicly owned local consulting firm which remains outside civil service payscales, offers opportunities to recruit experienced engineering manpower, both local and foreign, for specific tasks including project management. 2.15 Manpower Development. Inadequate manpower planning, including the lack of a comprehensive training staff improvement program, has hindered both the recruitment and retention of qualified staff. In addition TEK's training centers are in poor condition and suffer from inadequate and outdated equipment. TEK has recently hired consultants (Ontario Hydro, Canada) under Bank Loan 2322-TU to assist in the development of a manpower and training plan focusing particularly on power plant operations and maintenance. Further details on manpower development and training including Bank assistance are given in paras. 3.08 to 3.11. 2.16 An Increased Role for the Private Sector. Government policy is now directed towards encouraging a greater role for the private sector in all aspects of the electricity subsector activities. The objectives are to ease the manpower and staffing problems in the public sector, improve project management, and mobilize private financing. TEK can now share ownership ir. electric power and mining projects through "participations", in which TEK would hold from 15% to 50% of shares. or in "affilitate partnerships', in which TEK would hold a majority of the astres. As of early 1985, TEX had received about twenty proposals from the private sector to enter into these types of joint ventures, mostly for construction of hydropower plants. Construction of an imported coal-fired station, for which the Government has requested proposals from three foreign companies, may also be financed through this mechanism, with TEK taking part as a minority shareholder. Decisions on these proposals are pending the Government establishing a policy for setting the electricity tariffs for sales from the public/private ventures to TEK. Furthermore a recent law (Law 3096) allows utilities and other companies, designated as entrusted companies, to construct and operate generating facilities and to have full responsibility for electricity distribution and  - 12 - sales within a concession area. The pilot case for the creation of an entrusted company is the application of CEAS to become a fully integrated utility. A decision on this matter is expected from Government in mid-1985. Pricing and Demand Management 2.17 Studies on the potential for demand management and load shedding, including the effect on peak demand and growth in connections by TEK, have just been started (para. 2.21). While load management policies would have relatively little impact upon energy demand, they could affect peak demand by up to 10%. This would represent a major investment saving and a load management program is an urgent requirement. Demand management can be achieved through both an appropriate pricing policy (para. 2.19-2.20) and by non-pricing mechanisms (e.g., ripple control, contracted interruptible supplies). 2.18 Pricing Policy. Bulk electricity tariffs are close to the long-run marginal costs of bulk supply (LRMC) but do not yet fully reflect the structure of LRMC. TEK has hired consultants (EdF, France) to assist them in preparing a tariff study on the long run marginal cost of supplying electricity at both the bulk and retail level. The Bank has monitored closely progress of the study and its preliminary findings were discussed with TEK in the course of project supervision. The consultants have prepared a draft report on bulk supply tariffs and are currently analyzing the retail tariff level and structure, although no preliminary report has yet been prepared. Annex 2.3 presents a simmary of the study's findings so far. The final results and recommendations on an appropriate level and structure of electricity tariffs (including those at the retail level) are expected in July 1985, and vill be implemented fully following discussion with the Bank, as already agreed under Loan 2322-TU. 2.19 However, in line with Government policy to price energy products closer to their respective economic costs, bulk tariffs were increased from 1982 to 1984 by about 13% in real terms. TEK's consultants (para. 2.18) estimated that average bulk supply tariff (TL 19/kWh as of January 1985) represented about 65%-70% of the LRMC of electricity supply at high voltage, estimated at about TL 26/kWh (adjusted to January 1985 prices). Following further tariff increases effective January, March and April 1, 1985, bulk tariffs (including all taxes and charges collected by TEK) were estimated at 85Z-90% of LRMC as of April 1, 1985 (Annexes 5.1 and 5.2). This represents a considerable improvement over the past two years; at the time of the previous Bank appraisal in May 1983 (TEK Transmission III, Loan 2232-TU), bulk tariffs were about 50Z of LRMC. Furthermore, the introduction in June, 1984 of a time-of-day differential in the tariff scnedule also brings tariffs closer to the structure of marginal costs and, once fully implemented, should help correct imbalances in the pattern of electricity consumption. The Bank will continue to discuss with Government required increases to mwintain and improve the structure and level of electricity tariffs.  -13 - 2.20 Load Research and Demand Management. A major constraint in identifying the costs and benefits of a load management program has been the inadequate data base upon which to prepare demand projections. Furthermore TEK staff has not been adequately trained in demand forecasting techniques nor in identifying and analyzing various demand management strategies. To address this problem TEK recently hired consultants (GOPA Consortium, Germany) under Bank Loan 2322-TU to assist them in developing a program of load research, demand management and conservation. The technical assistance includes the design of a system for the collection and storage of data, the development and testing of models to project energy and peak demand (short, medium and long term projections), the simulation of load management strategies including measurement of likely costs and benefits of alternative strategies, training of TEK staff and the preparation of recommended actions for a load management program. The work of the consultants is to be closely coordinated with the tariff study (para. 2.18) so that the impact of pricing policies on growth in demand may be estimated. The consultants started work in March 1985 and completion is expected by the end of 1987, although progress reports during the various phases of the work will provide recommendations for specific actions. The Bank will work closelv with TEK and the consultants to ensure that pricing policy, demand management and system planning (demand forecasting and supply analysis) are fully integrated. Electricity Planning 2.21 TEK is, and has been since its creation, overwhelmed by the immediate problems of coping with increasing demand, problems that have preoccupied senior management to the detriment of forward looking strategies. As a consequence little effort has, in the past, been made to upgrade TEK's planning skills. However, agreement has been reached with the Bank on a comprehensive system planning training pro-ram with MENR and TEK. Training is to be given in system planning using the WASP1/ model and in demand forecasting using the MAED/ model. Both models have been developed by the International Atomic Energy Agency (TAF4) and the training program is provided under their auspices. The latter will be fully coordinated by TEK's Planning and Coordination Department with the demand management study outlined in para. 2.20. 2.22 Results of the exercises are expected in early 1986 and the task force selected for training has completed its training using the WASP model. IAEA experts will visit TEK periodically throughout 1985 to assist in the implementation of the training program. Improved planning would ensure that significant opportunities to maximize supply over the medium term are realized (e.g., reduction of system losses, coordination of the investment program, 1/ WASP - Wien Automatic System Planning Model. 21 MAED - Model for Analysis of Energy Demand.  - 14 - demand management, rehabilitation of plant currently derated, etc.) as well as identifying a long-term least-cost expansion program for the subsector. TEK is to prepare a report by early 1986 of the proposed long term generation plan. 2.23 One area of system planning where technical and cost data could be significantly improved is in the hydro sub-sector. System planning is hampered by the lack of a systematic inventory of hydroelectric resources and a ranking of these resources based upon uniform technical criteria and comparable economic and cost criteria. A hydro inventory study will be included in a forthcoming Bank project (Kayraktepe, FY86) and once completed would allow the optimal design and development, scheduling and construction of hydro plants with consequent major savings in investment. The results of this study would provide additional information to a subsequent round of expansion planning exercises. C. MEDIUM-TERM Il1VESTMENT 2.24 There is considerable uncertainty surrounding likely resource availability for power investment in the period up to 1990. In view of this a set of investment scenarios was developed for the appraisal on the basis of information available to the Bank on physical progress and likely costs of ongoing projects as well as new projects likely to enter the investment program. The investment scenarios will also be used for discussion with the Turkish authorities, to assist them in formulating and understanding the financial implications of subsector requirements and to improve their investment planning. The financial implications of the investment scenarios are discussed fully in paras. 5.25 to 5.34. 2.25 Scenario "A"': As part of the short- to medium-term planning process both TEK and DSI prepare annual investment budgets for submission to SPO and Government. Currently there is no requirement for TEK and DS! to prepare a medium-term (e.g., three to five years) projection of expenditures. However, TEK and DSI were requested by the Bank to provide projections, in line with the timing of the 5th Five-Year Plan, of capital investment requirements to cover the period 1985-1989. (See Scenario "A" in Table 2.1). The projections were discussed in detail with the Bank and a summary and commentary on this Scenario "A', are given in Annex 2.2. On the basis of these discussions the Bank prepared alternative scenarios of projected investment. 2.26 Scenario "B" was based upon the national investment requirements for electric power during the 1985-1989 period and did not distinguish between public and private investment. This was prepared in view of the current uncertainty regarding the scope and likely role of public versus private investment in electric power development. While the projections of required investment in Scenario "B" are consistent with present demand estimates, it was not constrained by resource availability, nor by the implementation capacity of either the public or private sector.  - 15 - 2.27 Scenario 'C" was based upon the minimum requirements for completion of high priority projects and took into account likely completion dates of generation Drojects, a limited number of potential new generation projects entering the program and the requirements for the components of the program other than generation. 2.29 Scenario "D" was developed, based not upon a detailed project by project review of investment requirements but rather on the estimated availability of resources. It was assumed that the increases in both Government contributions to investment and foreign borrowing would be restrained to about 4% per annum in real terms and that, in line with Government's pricing policy (para. 2.18), tariffs would continue to increase in real terms to reach and maintain levels equivalent to LRMC. As shown in Table 2.1, on this basis TEK would be able to finance the completion of all ongoing projects (Scenario "C") and provide funds for expansion although not up to the full requirements of the sector (Scenario "B"). Scenario "D" was considered the base case for the financial projections (paras. 5.31-5.34). Table 2.1 Electric Power Investment Scenarios (TL billions).!i (In Mid-1984 Prices) 1985-89 Scenario 1985 1986 1987 1988 1989 Total A. TEK/DSI projection 600 973 936 987 1,195 4,691 B. National Investment to meet Demand 600 850 1,075 1,200 1,300 5,025 C. Adjusted to ensure, at minimum, completion of high priority projects 600 698 674 702 741 3,415 D. Public investment based upon estimated resource availability 589 684 810 974 1,054 4,111 a/ TL 350 = UStl  - 16 - 2.29 There is inadequate coordination of the investment programs of TEK and TKI. Further delays in the implementation of several lignite mining projects to supply fuel for thermal power plants remain a problem. Unless resolved this would result in substantial delays in electric power availability and consequent perpetuation of supply shortages continuing into the early 1990s and beyond. The Bank has prepared a subsector study on the lignite subsector (op cit) which identified the major problems faced by the subsector (poor planning, inadequate project management and inadequate financial management). The study has not yet been discussed with Government. The recent Technical Assistance Project for State Economic Enterprises (Loan 2400-TU) includes funds for two studies to improve TKI's project management and implementation capabilities, although consultants have not yet been hired. 2.30 To ensure the rational design of the medium term investment program, agreement was be reached during negotiations to undertake, as part of the ongoing energy policy dialogue, an annual joint Bank and Government review of the electric power investment program and related financing plans. This would include a review, by October 31 of each year, with Bank and representatives of MENR, TEK, SPO and Treasury of the proposed annual investment program for the power subsector and the required investments and related financing plans for the medium-term (five-year) period. The format and content of the information for such a review would be discussed between the Bank and MENR during supervision and would be undertaken with a view to identifying project priorities, realistic completion dates and adequacy of electric power investment levels and finance. D. BANK'S ROLE IN THE POWER SUBSECTOR 2.31 The two proposed Projects being processed in parallel1' would be the sixteenth and seventeenth Bank operations in the power subsector in Turkey. The Bank has made eleven loans and a technical assistance grant (total US$639.7 million), anc IDA has granted three credits (total USS55.7 million). These comprise loans/credits for four hydroelectric projects; two thermal power stations (oil- and lignite-fired); a lignite mine; and several for transmission and distribution networks. The technical assistance grant helped reorganize Turkey's power subsector. The first five loans/credits were for projects in the CEAS concession area. All these projects were completed successfully, although often with long delays. The Bank has made four previous loans to TEK, for the First, Second and Third Power Transmission Projects, and for the Elbistan Mine and Power Project. 2.32 A Project Performance Audit Report (PPAR), distributed to the Board in November 1981, on the Keban Transmission (Loan 568-TU) and the first TEK 1/ The Fourth TEK Transmission Project and the Power System Operations Assistance Project.  -17 - Power Transmission (Loan 763-TU) projects found that these projects had met their physical objectives despite implementation delays and cost overruns. A Project Completion Report on the Istanbul Power Distriburion Project (Loan 892-TU), distributed to the Board in December 1982, also reported physical completion of the Project after considerable delay. Major constraints to timely project completion were identified as shortage of local counterpart finance and, in the case of Loan 892-TU, late preparation of bidding documents. A major conclusion of the TEK II (Loan 1194-TU) Project Completion Report was the need for improvement in the monitoring and coordination of the Project. The Report recommended the establishment of a single unit within TEK to be accountable for project implementation. Such a monitoring unit has now become a feature of project design in Bank financed power projects in Turkey. For example, ELTEM-TEK was hired by TEK to assist in monitoring all aspects of the Third TEK Transmission Project (Loan 2232-TU). Procurement and physical implementation of this project, which includes about 1500 km of 380-kV lines, are proceeding on schedule. 2.33 The Bank played a major role in the consolidation of the power sector and in the creation of TEK. The Bank has since then continued to advocate needed institutional reforms and has met with some success in its endeavors to assist in strengthening the institutional capabilities of the subsector. Substantial progress has been made in some areas, e.g., improvements in TEK's accounting system, in system planning, and in procurement procedures. Furthermore, the Bank has assisted in attracting funds from other bilateral and international financing agencies (e.g., EIB, German Aid (RfW), US EXIMBANK). 2.34 The Bank has, through its sector work program, provided guidance and assistance in sector planning and pricing policy. The Energy Strategy Paper (op cit) and the Electricity Planning and Investment Report (op cit) discussed with the Government and energy sector agencies including TEK have provided a useful forum for a policy dialogue on the issues and constraints facing the subsector. Policy level discussions with MENR, TEK, DSI and SPO have continued to increase the awareness of those problems; and Bank guidance and advice has frequently been sought on a number of operational and policy questions. 2.35 Since it is not possible to address the full range of issues facing the subsector it was recommended in the Energy Strategy Paper that attention be given to a selected number of high priority issues where the Bank could have an appreciable impact. The strategy for assisting the power subsector is in line with the overall planned strategy for the energy sector as outlined ir para. 1.15 and includes focusing resources on investments which yield quick returns (e.g., completion of priority ongoing investments, upgrading of existing facilities, reduction in losses, improvements in efficiency etc.); ensuring a balanced electric power development program with respect to adequate investment in generation, transmission, distribution and general plant; strengthening, through technical assistance, capabilities in planning,  - 18 - financial management and manpower develonent; investment in new generation options such as those based upon imported coal and natural gas; and increasing the role of the private sector in the production of electricity. 2.36 The Bank has made a major effort at defining jointly with Government a series of pote..tial investments which would address the above mediumr-term issues. In particular the Bank proposes, in addition to the two proposed Projects, to finance, inter alia, a loan to ensure the completion of the Elbistan Project, an urban distribution component of the proposed Energy Policy Loan, a project with a private utility (CEAS), and a high priority hydro project (Kayraktepe). Project lending aimed at alleviating the medium-term problems faced by the subsector will be supported judiciously by technical assistance and sector work in a number of key areas such as planning and financial management.  - 19 - III. THE PROJECT ENTITY: TEK 3.01 The borrower, TEK, has primary responsibility in Turkey for design and construction of thermal generating plants, for operation of both thermal and hydroelectric generating plants, and for design, construction and operation of the national transmission system and distribution systems (para. 1.04). The organization and scope of responsibilities of TEK have been altered recently by a number of significant legal changes. TEK is now authorized to invest in and operate lignite mines and geothermal fields to supply its power plants; previously TKI was the only public enterprise authorized to own and operate lignite mines. In parallel, the opportunities for private sector investment in electric power have been expanded, removing TEK's previous near monopoly on electricity generation and sales. TEK will continue to require the Bank's assistance in institution-building. TEK is presently receiving technical assistance in four areas as part of Loan 2322-TU (TEK Transmission III), as follows: demand management and load analysis (para. 2.20); administration and standardization of distribution operations (para. 3.07); manpower planning and training (para. 3.10); and, improvements in accounting and management information systems (para. 5.23). Legal Context 3.02 TEK presently operates as a Public Economic Establishment (PEE) defined under Law 233 as a venture owned entirely by the Government which is "public service-oriented and founded to produce and market basic goods and services of a monopoly nature". As part of the reform in public enterprises, TEK's legal structure and organization were redefined effective January 1, 1985. The new legislation affecting TEK is listed in Annex 3.1. TEK was originally established in 1970 with its current mandate, but excluding urban electricity distribution, which had been the responsibility of the municipalities. Urban distribution was then legally traneferred to TEK in 1982, with actual operation and control of these distribution facilities being assumed in stages during 1983 and 1984. The objective of public enterprise reform in Turkey has been to permit greater autonomy and improved productivity, and in fact the Government has recently been taking significant steps toward increasing TEK's financial self-f.ufficiency (para. 5.01). However, TEK continues to be subject to the State Personnel Law (No. 657), which restricts management decisions on hiring, firing, salaries, and internal transfer of staff. Revised legislation for government employees is being drafted but the timing for implementation is uncertain. Organization and Management of TEK 3.03 Notwithstanding the recent reforms affecting public enterprises, important managerial and organizational decisions continue to require Government approval, and thus are not dealt with as quickly as would be the case in a more autonomous utility. Furthermore, there are no board members from the private sector who could represent the concerns of TEK's industrial  - 20 - and private consumers. In the past fifteen years, TEK has had seven general managers, normally appointed from within the company. The Board of Directors of TEK is chaired by the General Manager, and includes five members: two nominated by the NENR, one nominated by the Minister of Finance and two nominated from among the six Assistant General Managers (AGMs) of TEK by the Minister of Energy. The present organization of TEK is shown in Annex 3.2. The responsibilities of the six AGMs were shifted in early 1985, and are currently divided as follows: (a) Operations: Generation, Transmission and Distribution; (b) Design and Construction of Generating Plants; (c) Design and Installation of Transmission Lines and Substations; (d) General Administration and Distribution Studies; (e) Planning, Training and Data Processing; and (f) Finance. 3.04 Some of the activities reporting to the AGM for Operations have recently been classified as part of an "Operations Enterprise" within TEK, which is to include generation and transmission operations and responsibility for wholesale electricity sales to high voltage customers and to TEK's distribution enterprises. It is too soon to determine whether this recent change will have a visible impact on TEK's operations. 3.05 Having historically emphasized centralized operations and construction of new generating facilities in particular, the management of TEK is still adjusting to the new requirements of overseeing distribution where highly centralized decision-making is not desirable. Eighteen regional electricity distribution enterprises were created in 1983 as separate departments of TEK after the takeover of distribution from the municipalities (para. 3.02). While, officially, each enterprise manager reports directly to the General Manager, in practice they are required to report to two AGMs, to one with regard to operations and to the other with regard to distribution studies and project design. It would be advantageous to reallocate the responsibilities of the AGMs so that one would be fully responsible for coordinating distribution activities. 3.06 TER's central office provides continuous monitoring and inspection of the distribution enterprises, approves all personnel decisions, and determines the allocation of investment resources among the regions. The distribution enterprises are presently not authorized to seek outside financing. They are charged by the parent company for electricity purchased at wholesale tariff rates and for part of the overhead headquarters expenses associated with distribution. Each enterprise is responsible for preparation of its annual operating budget, drafting annual and long-term investment and plans, and preparation of annual financial statements. Full responsibility for the design, execution and control of urban distribution and rural electrification projects is only gradually being transferred from headquarters to the regional enterprises. 3.07 A number of distribution enterprises are presently receiving technical assistance on a pilot basis. A master plan for reduction of losses  - 21 - and network expansion is being developed for the Ege Enterprise (Izmir); improvement of the customer billing system is being introduced in one district of the Bosphorus Enterprise (Istanbul); and, improvements in stock control, general and customer accounting are being introduced to two enterprises, Ege and Central Anatolia (Ankara). Manpower Development and Training 3.08 The rapid expansion of electricity supply in Turkey has been accompanied by an almost equally rapid increase in the number of people employed by TEK. The total number of staff as of October 1984, was just over 55,000, of which 33,000 worked for TEK's Distribution Enterprises. This represents an increase in staff of 15,000 over a two-year period, of which 11,000 were new distribution staff and 4,000 were added to other departments of the utility. After distribution the next largest group, about 13,500, work in operations. A breakdown of TEK's staff by department and by level of training is shown in Annex 3.3. 3.09 Manpower planning for TEK as a whole is presently carried out only one year at a time, although staffing requirements for new generating plants are identified further in advance. The Personnel Department and the Training Department do not report to the same AGM, which complicates coordination. TEK has three technical training centers, the largest of which is located in Soma and has extensive laboratory capacity and models related to thermal electricity generation. However, much of the equipment is out of date and the training center is used at less than full capacity largely due to the shortage of instructors. Training materials dealing with transmission, distribution and overall system reliability are lacking. 3.10 Some of these weaknesses are being addressed under TEK Transmission III (Loan 2322-TU) which includes a thirtv-four man-month contract with Ontario Hydro. This technical assistance component is addressing; manpower planning for generation, overseas training of master instructors (in operation of generating plants, transmission and control), training on plant commissioning; and improvement of the equipment at the Soma training center. 3.11 The proposed Project includes a training component, addressing the specific requirements of staff in network engineering, planning and in transmision lines and substations design (para. 4.09). General Characteristics of the TEK Power System (see Map IBRD 18845) 3.12 The large magnitude of the TEK power system can be appreciated by considering the volume of the electric load supplied and the extension and size of its physical facilities. In 1984 the peak load in TEK power system reached 5,450 MW and gros_ generation was 26,000 GWh (net 23,600 GWh). In the same year TEK imported 2,500 GWh from Bulgaria and the USSR which gave a total electric energy delivered to the TEK power transmission grid of 26,100 GWh. Generation plus energy purchased, however, was not able to fully meet the system's unrestrained energy demand.  - 22 - 3.13 Total rated capacity of TEK power plants in commercial operation in 1984 amounted to 6,330 MW. Adding the peak supply from Bulgaria and the USSR - 285 KW - the total capacity available reached 6,615 MW, to meet a system constrained peak demand of 5,450 MW. This would give an apparent reserve margin of 1,165 MW or 21Z. In fact, TE1 had no actual reserve margin available in 1984 and could not meet the system's constrained peak demand, due to poor availability of its generating facilities. 3.14 TEK's bulk transport system consists of a 380-kV National Grid System that feeds into 1.54-kV grids. These 154-kV grids supply major power users and feed into 66-kV, 35-kV, and 15-kV subtransmission grids. In 1984 there was a total of 46,135 km of transmission and subtransmission lines. TEK's substation plant in the transmission grids consists in 1984 of 368 transformer substations with 593 transformers, having an aggregated capacity of 15,798 MVA. Besides power transformers, in these substations there were in 1984 a total of 34,569 major switchgear apparatus. 3.15 Low voltage distribution throughout Turkey is done at 50 Hz 220/380 V three-phase with neutral grounded. Primary distribution voltages are 35 kV, 15 kV, 6 kV and 3 kV. In the 18 regional distribution enterprises under TEX, the distribution systems consisted in 1984 ofi 19,500 km of primary distribution feeders at 35 kV, 15 kV and 6 kV; 64,000 km of secondaries at 220/380 V; and 6,289 distribution transformers with an aggregated capacity of 4,730 MVA (more than half of this distribution transformer capacity is installed in the Bogazici Distribution Enterprise, which includes the city of Istanbul with 1,600,000 consumers). 3.16 The level of technical losses in distribution is between 122 and 15Z, which is high by modern standards 1/. These losses can be reduced by increasing the capacity of the distribution facilities, particularly distributior transformer and feeders. (Master plans for reduction of losses and expansion of the distribution systems are underway; para. 3.07). It is considered economically feasible to reduce losses to about half of what they are now, but this will require considerable investment in the coming years. TEK is already programming substantial investments in this area in the next five years (para. 2.07). TEK's Power System Operation Performance 3.17 A parallel project "Power System Operations Assistance Project", describes in detail TEK's operational performance in the generation, transmission and distribution areas. The following paragraph gives a brief description of TEK's transmission system operation from the design point of view. 3.18 During the last ten years, TEK's transmission system proved stable in spite of the long transmission distance; voltage and reactive power were 1/ In most developed countries, the level of technical losses in the well operated distribution systems is about 6%.  - 23 - satisfactory. Operation experience with the substations equipment has been satisfactory, although maintenance problems have led to a considerable number of outages. The only major problem was in connection with the lightning arresters and TEK has taken measures to improve in3ulation coordination and lightning protection in the substations. With regard to the transmission lines, and during the first 5-year operation of the 380-kV system, TEK faced a more serious problem of mechanical failure iue to insufficient knowledge of the very severe weather conditions in certain areas where there was no prior experience of transmission line operation. Since then, TEK has introduced more adequate mechanical design for the lines, as well as the reinforcement of the existing lines exposed to heavy ice and wind loads in winter.  - 24 - Iv. THE PROJECT Project setting and Objectives 4.01 In view of the Gbvernment's policy objective to reduce dependence on imported hydrocarbons, and the location of the main indigenous energy resources vis-a-vis the load centers, TEK has had to develop, with the assistance of consultants, a least-cost and long-term construction program for an extensive transmission grid at the 380-kV level. Implementation of this grid started in 1974 and the related long-term construction program is being updated regularly to take account of changes in TEK's load growth and generation system. The latest update in January 1985, Which analysed the 380-kV transmission grid required to accommodate the load flows foreseen in the early l990s, has been reviewed by the Bank and found satisfactory. 1/ 4.02 The proposed Project, which is a continuation of the ongoing TEK Transmission III Project (Loan 2322-TU), constitutes the fourth phase of development of the 380-kV transmission network, and would provide major links and transformer substations needed to strengthen further TEK's power system and to ensure a continued supply of electricity to the growing demand on TEK's interconnected system. Project Description 4.03 The Project is part of TEK's current 1986-1990 development plan and involves: (a) the construction of about 800 km of 380-kV transmission lines to interconnect Altinkaya and Hamitabat power stations under construction to TEK's bulk supply system and to provide two additional links for Karakaya power station; (b) the construction and/or extension and placing into operation of 380/L54 kV transformer substations with total installed capacity of about 2,100 MVA; (c) the supply, installation and commissioning of equipment for the construction and/or extension of 154/35 kV substations with about 3,300 MVA of new installed capacity; (d) the construction of a tower testing station for testing towers for transmission lines up to 380 kV with possibility of extension for 800-kW range; 1/ TEK is currently evaluating, with the assistance of experts, the long-term planning (10-15 years ahead) of its transmission system, based on load flow, short-circuit studies and economic evaluation, and including the alternative of superimposing an 800-kV grid on the 380-kV system.  - 25 - (e) the supply of specialized line stringing equipment and vehicles to be used in the installation of transmission lines; (f) training and supply of devices, such as computer hardwarelsoftware to strengthen TEK's capabilities in network engineering, planning and in transmission lines aind substations design; and (g) consulting services to assist TEK in the implementation of the Project. Annex 4.1 gives a detailed description of the Project and IBRD Map No. 18845 indicates the location of the main Project components. Status of Engineering 4.04 TEK's transmission extension network has been planned and designed on the basis of: (a) traditional contingenc: criteria according to which the system should ride through disturbances at peak load without incurring instability, cascading or loss of load; Cb) studies carried out to ensure adequate operation of the projected system and correct design of each extension. These studies involve more specifically load flows, short-circuit study, transient and steady state stability, switching surges and dynaLic overvoltages; and (c) mechanical and electrical design and specifications of equipment and materials standardized in accordance with criteria established during previous construction and operation of TEK's transmission system. The adequacy of these criteria and the results of the studies carried out by TEK for its 1986-1990 transmission development program which includes the proposed Project, have been reviewed by the Bank and found satisfactory. 4.05 TEK's Engineering Department has prepared the detailed project design, which has been reviewed by the Bank and found satisfactory. Acquisition of rights-of-way for the lines is underway and bidding documents will be issued starting May 1985. 4.06 A study for the estaDlishment of a tower testing station in Turkey has been carried out by TEK's consultants, reviewed by the Bank and found satisfactory. Availability in Turkey of such a facility has become necessary as the 380-kV system expands and the export of locally manufactured steel towers develops. Tower testing is currently being done abroad and TEK and the local manufacturers are more and more faced with difficulties for getting the required tests in a timely manner. The tower testing station included in the proposed Project will be used for TEK's needs and also for the local manufacturers' requirements, and will permit the local firms to be more competitive by refining their design. During negotiations, TEX confirmed that these firms will be charged for the use of the facility, and that the basis  - 26 - for determining the level of fees will be reviewed with the Bank. The tower testing station will be used initially for testing towers for transmission lines up to 380-kV with the possibiiity of extension to the range 800kV. The facility will also provide for mechanical tests of steel structures, insulators, conductors and line fittings and for the analysis of concrete samples taken from tower foundations. With regard to the proposed line stringing equipment, TEK determined the list of the necesary equipment on the basis of the available equipment, the private sector construction capacity and the volume of works involved in TEK's investment program. This list has been reviewed by the Bank, and the type and quantities required have been found reasonable. Project Cost 4.07 The total cost of the proposed Project including physical and price contingencies but excluding interest during construction is about TL 180 billion (UStL95 million) of which TL 135 billion (US$146 million) is in foreign currency. Details of the project cost are given in the Annexes 4.2, 4.3 and 4.4 and sumnarized in Table 4.1 below. The project cost estimates are based on January 1985 prices derived from detailed data provided by TEK and discussed with the Bank and quotations received recently by the Borrower for equipment and material similar to those included in the Project. Total physical contingencies are about 10 of base cost, because of the advanced state of the design for the lines, and the repetitive and routine nature of the work for the substations. Price contingencies have been computed assuming an implementation period consistent with the relevant Bank standard profile and specific annual increases in domestic and international prices as follows; 1985 1986 1987 1988 1989 1990 1991 Local (Z) 35 30 25 20 15 10 10 International (v) 5 7.5 8 8 8 8 5 4.08 TEK is currently exempt from import taxes and customs duties for the projects under construction and plans to apply for an extension of that exemption for the proposed Project. Therefore, taxes and import duties are not included in the project cost. During negotiations, the Government gave assurances that tnis exemption will be extended to the proposed Project. Training 4.09 To further strengthen manpower development at TEK, and as a continuation of the training component included in the TEK Transmission Project III, the proposed Project would also include a training component which aims at improving TEK's capabilities in network engineering, planning and in transmission lines and substations design. This training will be provided to specialized and experienced personnel in certain specific areas. The Project provides training for about 90 trainees for the whole period of the project implementation. During negotiations, the Borrower agreed to submit to the Bank, not later than June 30, 1986 a detailed staff training program, and to implement the agreed program in accordance with an implementation schedule satisfactory to the Bank.  - 27 - Tible 4.1 amaoy of Project Cost --In TL Bilio - -In tD 1 Miim Equi3.- Fcreign Local Freign Local Cost Cost Tbtal Cost Cost Ibtal A. 380-kV Trasnissicn Line - Rar0smmiy 9.50 3.41 12.91 21.10 7.60 28.70 - Atirkaya-Camba 1.90 0.77 2.67 4.22 1.71 5.93 - Hauitabat-Alibe3coy 3.96 1.0 5.36 8.79 3.12 11.91 - KmardsaDikymb*ir 2.71 0.66 3.37 6.00 1.48 7.48 - Other Camnetios ii New 38).-W Sibstticns 0.90 0.31 1.21 2.00 0.71 2.71 - Tcver Testing Statim 1.13 0.90 2.03 2.52 2.00 4.5 - Line Str - z Equipiet 2.00 - 2.00 4.45 - 4.45 Sdbtta'L Base Line Cost A (Jar 185 pries) 2210) 7.45 29.55 49.08 16.62 65.70 B. Substatims Cozmpcnet - 38D/)14-W Sbstatics 9.22 1.85 11.07. 20.47 4.04 24.51 - 154/30G-k Sustatims 12.00 4.79 6.79 25.6B 1.66 37.34 StDtal Base Line Cost B (Jaiury 1985 prices) 21.22 6.64 27.86 47.15 1A.70 61.85 C. Others -C iHardeSoftware 1.00 0.02 1.02 2.20 0.06 2.26 -TUK Bg'g. Adin. forrA4B - 0.79 0.79 - 1.77 1.77 -Cmsa ting Sevices firA43 0.16 0.07 0.23 0.35 0.45 0.50 -Traming 0.29 0.14 0.43 0.65 0.31 0.96 SibtDtal BaseCost C (Ja-ary 1985 prices) 1.45 1.02 2.47 3.20 2.29 5.49 D. ibtal Project Cost (A + B + C) - Ibtal Base Lire Ccst (Jaiunry 'i:8 Prices) 44.77 15.11 59.88 99.43 33.61 133.04 - Physicl Cmtingacies 4.47 1.51 5.9B 9.96 3.36 13.37 - Price Ccatingecies 85.76 28.38 114.14 36.61 12.03 48.64 TOML lR)ECr ([ST 135.00 45.00 ]80 0 146.00 4900 195.00 Interst Dur* CCAStnsoti - Bark finad 110 - 11.00 13.00 - 13.00 -Other DIaL FE&{GIMG E;lpl) 166.00 45.00 191m 159.00 49.00 208.00  - 28 - Project Financing Plan 4.10 The proposed Bank loan of US$142 million would finance about 68Z of the total financing required for the Project of US$208 million, and 89Z of the foreign cost. It includes the US4L3.0 million required for the interest during construction. This is justified given the tight cash flow situation of TEK during a period of extension of its investment program. The remaining US$66 million would be covered by TEK's internal cash generation, materials fron stock, and government contributions (US$17.0 million of the foreign exchange cost represent the cost of material and equipment to be supplied by TEK and the indirect foreign exchange cost for installation and erection which would be undertaken by TEK or local contractors). A summary of the project financing plan is given in Table 4.2 below. Det; :led list of contracts to be financed by the Bank loan are given in the Tables 4.3 and 4.4. The foreign exchange risk would be borne by TEK. Table 4.2 Project Financing Plan (US$ Million) Local Currency Foreign Currency Total IBRD loan - 142.0 /a 142.0 TEK and Government 49.0 17.0 66.0 Total 49.0 159.0 208.0 /a Including US$13.0 million for interest during construction. Lending Arrangement 4.11 The proposed Bank loan will be made to TEK with the guarantee of the Republic of Turkey. Project Implementation 4.12 The Project will be implemented by TEK, in parallel with the extension and reinforcement of the existing system, and with assistance from consultants to ensure efficient implementation of the Project. As is currently being done for TEK Transmission Project III (Loan 2322-TU), TEK plans to retain for this project the services of ELTEM-TEK. ELTEM-TEK would provide assistance in engineering, project management and coordination and other technical and administrative services. ELTEM-TEK will hire foreign experts, whenever needed, to assist its own personnel. This arrangement is satisfactory to the Bank. It is estimated that TEK would require 60  - 29 - man-months of consulting services to implement the proposed Project. The engagement of project management consultants under terms and conditions satisfactory to the Bank shall be a condition of loan effectiveness. 4.13 The Project will be implemented over five years. The preparation of detailed design and tender documents for procurement of goods are underway and will be completed by March 30, 1986. Installation and erection of project facilities will start in mid-1986 and is expected to be completed by June 30, 1990. Annexes 4.5 and 4.6 show the related implementation schedule for the lines and substations, respectively. 4.14 Acquisition of rights-of-way for the lines is underway, and the implementation schedule has been estimated on the basis of current experience with TEK Transmision III. With regard to the substations, land acquisition for the new 380-kV and 154-kV substations has not yet started. During negotiations TEK agreed on a land acquisition timetable satisfactory to the Bank, which would permit completion of all necessary land acquisition by September 30, 1986 and for at least 50% of the substations by June 30, 1986.2! Procurement 4.15 The goods and services to be procured for the proposed Project have been grouped into 10 contracts for the transmission lines and 11 contracts for the substations to ensure effective international competition. Annexes 4.7 and 4.8 give the detailed list of these contracts and their estimated procurement schedule. The contracts with Bank financing are detailed in Tables 4.3 and 4.4 below. 1/ The detailed timetable for land acquisition appears in Supplemental No. 1 to the Loan Agreement.  - 30 - Table 4.3 Contract Packages with IBRD Financing Lines Component (In US$ Million) Foreign Local Total Cost Cost Bank Financing (a) Steel Towers /a 3.0 - 3.0 (b) Conductors and Shieldwires 36.6 - 36.6 (c) Insulators 4.0 - 4.0 (d) Hardware 3.3 - 3.3 (e) Tower Erection 2.2 8.8 2.2 (f) Tower Testing Station 3.7 3.0 3.7 (g) Line Stringing Eqpmt. and Vehicles 6.5 - 6.5 (h) Computer Hardware/Software 3.2 0.1 3.2 (i) Training 0.8 0.4 0.8 (j) Consulting Services 0.2 0.1 0.2 TOTAL 63.5 12.4 63.5 /a For the Karakaya-Diyarbakir line and for the connections of the new 380-kV substations included in the proposed Project. The steel towers for the remaining lines will be provided by TEK from stock. Table 4.4 Contract Packages with IBRD Financing Substations Component (In US$ Million) Foreign Local Total Cost Cost Bank Financing (a) Power Transformers 34.3 - 34.3 (b) Circuit Breakers 380kv & 154kV 13.5 - 13.5 (c) Circuit Breakers 35kV 1.2 - 1.2 (d) Disconnecting Switches & Earthing Blades 4.2 - 4.2 (e) Lightning Arresters 1.5 - 1.5 (f) Measurement Transformers 4.4 - 4.4 (g) Measuring, Protection & Auxiliary Eqpmt. 4.2 - 4.2 (h) Bus Bars and Hardware 1.0 - 1.0 (i) Insulators 0.7 - 0.7 (j) Training 0.3 0.1 0.3 (k) Consulting Services 0.2 0.1 0.2 TOTAL 65.5 0.2 65.5  - 31 - All items financed by the Bank will be procured in accordance with the Bank's procurement guidelines. Items (a) through (h) for the lines and (a) through (i) for the substations will be procured through international competitive bidding (ICB). For procurement through ICB, local firms will be allowed a margin of preference equal to the existing rate of customs duties applicable to nonexempt importers or 152 of the c.i.f. price of such goods, whichever is lower. 60 man-months of consulting services for both components will be procured in accordance with the provision of Part II of the Bank's Guidelines for Use of Consultants. Training manuals and other miscellaneous training aids and computer software/hardware packages will be purchased through limited international shopping for items of less than US$10,000 up to an aggregate limit of US$300,000; for such contracts the Borrower will obtain written price quotations from at least three reputable suppliers. To complete the Project, TEK will provide the following goods and services which will not be financed by the Bank; (i) towers (material and fabrication) for three lines: Karakaya-Osmaniye, Altinkaya-Carsamba and Hemitabat-Alibeykoy and all the remaining equipment for the substations (line traps, panels, steel structures, etc.); and (ii) lines stringing, and civil works and installation and erection of the substations which would be carried out by force account or local contractors. All the contracts for work, and equipment and materials to be financed by the Bank and costing over US$250,000 each will be subject to prior Bank review. Other Bank-financed contracts will be subject Lo post-award review. Table 4.5 below summarizes the procurement arrangements for the Project.  - 32 - Table 4.5 Summary of Procurement Arransements for the Project (US$ Million) "'rocurement Method Project Element ICB LCB Other Total Cost Transmission Lines - 8 Contract Packages 74.3 74.3 (see Annex 4.7) (62.5) (62.5) - Towers 16.6 /a 16.6 - Line Stringing 4.4 4.5 75 8.9 Substations - 9 Contract Packages 65.0 65.0 (see Annex 4.8) (65.0) (65.0) - Other Equipment 2.6 /a 2.6 - Civil Works 11.2 /b 11.2 - Installation & Erection 11.7 /b 11.7 Others - Training 1.6 1.6 (1.1) (1.1) - Consulting Services 0.6 0.6 (0.4) (0.4) - TEK Project Engineering Administration 2.5 /b 2.5 TOTAL PROJECT COST 139.3 4.4 51.3 195.0 (127.5) (1.5) (129.0) Note: Figures in parenthesis are the amounts to be financed by the Bank. The total does not include interest during construction. /a Equipment and material provided by TEK from its stock. /b Force account. Disbursements 4.16 The disbursements from the proceeds of the proposed Bank loan would be made for:  - 33 - (a) 100l of the foreign expenditures of directly imported equipment and materials or 100% of local ex-factory prices of equipment and materials manufactured in Turkey; (b) 20% of total expenditures for erection of steel towers for the lines; (c) 100% of foreign expenditures for overseas training; (d) 85% of total expenditures for services of consultants domiciled within Turkey and 100% of foreign expenditures for services of other consultants; and (e) interest during construction. 4.17 The estimated disbursements from the proposed loan are shown in Annex 4.9 and have been computed on the basis of the EMENA Region standard profile for similar power projects. Annex 4.10 gives a comparison with the actual disbursement of TEK Transmission Project II. Special Account 4.18 The establishment of a Special Account in the Central Bank will permit payment of Bank-financed expenditures with a minimum administrative delay. This Special Account would be replenished in the same currency, and would have a ceiling of US$8.0 million, which is equivalent to four-month average of the total expenditures to be financed out of the proceeds of the Bank loan. During negotiations the procedure for withdrawal of funds from the Special Account was explained. The following aspects concerning this Special Account will be reflected in the disbursement letter: (a) the unit within TEK responsible for aggregation and submission of withdrawal applications to the Bank; and (b) intervals at which bank statements and applications for replenishment will be submitted (in principle at quarterly intervals). Central Bank statements showing the transactions in the Special Account will be submitted to the Bank. Applications for replenishment will be accompanied by appropriate documentation or Statements of Expenditures. Replenishment will normally be made in the amount equal to payments made out of the Special Account for eligible expenditures, but only to the extent that the amount of any such deposit together with any amount remaining on the deposit in the Special Account as of the date of such request, does not exceed the equivalent of the agreed ceiling. Retroactive Financing and Advanced Contracting 4.19 No retroactive financing or advanced contracting is involved in the proposed Project.  - 34 - Environmental Impact 4.20 The Project has no major adverse effects on the environment. Aesthetic impacts on the landscape and, to a lesser extent, noise are the principal adverse effects, and both would be kept at acceptable levels. Project Risks 4.21 Most of the 380-kV lines are in mountainous areas difficult to reach. However, adequate construction technology is available to cope with the expected terrain and climatic conditions. 4.22 Land acquisition for the new 380-kV and 154-kV substations has not yet started and could be a critical factor in ensuring timely completion of the Project. Actions to carry out land acquisition on time have been agreed during negotiations (para. 4.14). Furthermore, the use of consultants to assist TEK in project implementation will provide improved coordination with construction of lines, substations and power plants affecting the Project and will assist TEK in preventing delays in project implementation. 4.23 Given the uncertainty surrounding likely investment levels for the medium term (para. 2.10 and Annex 2.3) there is some possibility of a shortfall in available funds to meet overall investment requirements. However, even at the suggested lowest range of investment, the components whicn will be served by the proposed Project represent a set of core high priority investments which would remain unaffected.  - 35 - V. FINANCIAL ASPECTS A. INTRODUCTION 5.01 The trend in the past year toward rapid improvement in TEK's financial position marks a reversal in the deteriorating situation which was presented two years ago.!/ While TEK suffered a net operating loss in 1983, due to insufficient tariff increases combined with very poor hydrological conditions, the financial situation improved dramatically in 1984. Tariffs increased significantly in real terms in 1984 (see para. 5.02), and internal cash generatLon in 1984 was adequate to finance about 16% of investments in the electric power subsector that year../ The changes in policy reflect the priorities of the new Government (elected in late 1983) for reducing public expenditures, pricing energy products closer to oconomic cost, and increasing the self-financing level of the electric power subsector. The financial analysis which follows assumes that this government commitment will be sustained during project implementation. However, financial constraints will continue to shape the level and timing of electric power investments. Foreign debt management, working capital stability and overall financial planning are other issues which will be dealt with through a Financial Action Plan in the proposed Project. B. RECENT FINANCIA PERFORMANCE Electricity Pricing 5.02 Wholesale Tariffs. Over the three-year period, 1982-1984, wholesale tariffs increased by about 13% in real terms. As shown in Table 5.1 (details in Annexes 5.1 and 5.2), wholesale tariffs were not adjusted sufficiently to keep up with inflation in 1982 and 1983, and consequentl lost 2% and 18% of their real value in those two years, respectively. Then in 1984, tariffs increased by 41% in real terms during the year, more thai making up for the ground lost in the two previous years. Although the wholesale price index climbed by just over 50% in 1984, the Government was apparently determined to increase tariffs even faster. In the first quarter of 1985, further 1/ TEK Transmission III (Loan 2322-TU, May 31, 1983). 2 N.B. All financial results for 1984 are based on estimated information which was available in January 1985; changes are likely to occur after the financial records are finalized and audited.  - 36 - significant tariff increases occurred (para. 5.26); however, the actual real increase resulting for 1985 will of course not be known until the end of the year.SY Table 5.1 Trends in Wholesale Electricity Tariffs 1982 1983 1984 Average Tariff (TL/kWh) - Jan. 01 5.70 6.99 8.05 - Dec. 31 6.99 8.05 17.15 Nominal Change During Year (Z) 23 15 113 Inflation (Z) 25 41 51 Real Incr. (Decr.) in Tariffs During Year (Z) (2) (18) 41 5.03 Retail Tariffs. During TEK's takeover of urban electricity distribution from the municipalities in 1983, retail tariffs were standardized for all regions of Turkey. Annex 5.3 shows changes in retail tariffs by customer group effective over 1983-1985. During the eighteen months following June 1983, retail tariffs increased by a range of 14Z to 25Z in real terms, depending on the customer type. Under Loan 2322-TU, TEK and the Government undertook to reflect fully in retail tariffs all increases in wholesale tariffs, including fuel cost adjustments, starting in 1984. In 1984, when the average wholesale tariff increased by TL 9.l0/kWh, the single-term retail tariff for small industries increased by TL 11.85/kWh during the same period. Other retail customer groups experienced larger tariff increases. Therefore, it appears that increases in wholesale tariffs, as measured in absolute terms CTL/kWh), were at least fully passed on through to the retail level in 1984. 5.04 Tariff Covenants. Existing agreements assuring automatic fuel cost adjustment of tariffs and passing increases in wholesale tariffs on to the retail level have been confirmed under the present loan_ Working Capital 5.05 Given TEK's new authority to collect sales revenues directly from retail customers (instead of the municipalities retaining these revenues), the deterioration in TEK's working capital situation should normally have been I/ The relationship between tariffs and the econocic cost of electricity supply (LRMC) is discussed in para 2.19. Bulk tariffs were estimated at 65Z-70Z of LRMC in January 1985, increasing to about 85Z-90Z of LRMC by April 1985.  - 37 - reversed in 1983. However, because of the significant real decrease in tariffs in 1983, serious cash flow problems continued in 1983. Foregoing payments to its fuel suppliers in 1983 (including other public enterprises such as TPAO, for fuel oil and TKI, for lignite), TEK used its available ftnds for the payment of capital expenditures, rather than operating expenses, in order to avoid delays in the implementation of its investment program. As a result of this, combined with past accumulated arrears, TEK's accounts payable had increased to TL 283 billion by the end of 1983, more than that year's gross operating revenues. 5.06 To put a halt to rising indebtedness among public enterprises, the Government took action in 1984 to consolidate these debts. TL 230 billion in TEK's net overdue accouats payable were consolidated and converted into equity. The Government made it clear, however, that it did not expect to repeat the role of a financial clearing house for debts between public enterprises. Furthermore, TEK was charged penalties of almost TL 50 billion in 1983 for late payments to its fuel suppliers. Since mid-1984, TEK has generally been paying its fuel suppliers on schedule. Table 5.2 TEK - Working Capital Position (As of December 31, 1982-1984) 1982 1983 1984 ---(Actual)-- (Estimated) Working Capital (Deficit) (in TL billion) -39 -106 +87 Current Ratio .8 .7 1.5 Days Receivables 272 267 186 5.07 Although TEK is reducing its accounts receivable, they are still very high, amounting to 267 and 186 days of sales at the end of 1983 and 1984, respectively. The estimated composition of TEK's accounts receivable by customer group as of 12/31/84 was as follows: 35% from municipalities, 28% from private industry and households, 22% from government agencies, 8Z from public agencies, and the remaining 7% from other customers. The largest category, municipalities, is composed of arrears due TEK for bulk purchases prior to the transfer of distribution from the municipalities to TEK. The law which transferred distribution assets and their operation from the municipalities to TEK made provision for outstanding arrears to be offset against net asset value. TEK's end-84 accounts receivable tould be equivalent instead to about 117 days of sales, if adjusted to exclude municipal arrears. The decision by the Ministry of Finance on how the municipalities' accounts  - 38 - would be repaid or consolidated is still pending, but is scheduled to be finalized by 1986 following the determination of the value of the distribution assets transferred to TEK. 5.08 Working Capital Covenants. It was agreed under Loan 2322-TU that TEK would maintain a current ratio (defined as current assets divided by current liabilities) of at least 0.7 at the end of 1983, increasing to 1.0 at the end of 1984 and future years, and this was confirmed under the present project. As indicated on Table 5.2, TEK has complied with this covenant (based on unaudited results)_ However, a satisfactory current ratio can still cover up other weaknesses in TEK's working capital situation; delays in collecting payments from some customers will also need to be reduced. As part of a Financial Action Plan, agreement was reached on a target for improving collection of customer payments. Measured in terms of days of average sales revenue, accounts receivable from all customers except municipalities should be reduced to 90 days by December 31, 1988, meeting that target in stages as follows: 1986 - 110 days; 1987 - 100 days. Debt Service 5.09 TEK has access to a limited amount of medium-te-rm TL borrowing from the State Investment Bank (DYB), and relies on foreign credits to finance most of the foreign cost of its investments. Due to TEK's past cash shortages, TEK and the Treasury have tacitly agreed that TEgC will defer from time to time reimbursement to the Government for installments on TEK's foreign debts paid by the Central Bank, without formally rescheduling them. In the last three years (1982-1984), it is estimated that TEK actually paid only about one half of foreign debt installments due out of its internal funds, with the remainder being postponed to the following year. The amount of foreign debt service payments deferred by TEK (including principal and interest) is estimated at US$16l million, US$232 million and USS74 million in 1982, 1983 and 1984, respectively. In 1984, the Government converted about US$115 million (TL 40 billion equivalent) of these arrears to equity. The accumulation of arrears to the Central Bank is the equivalent of giving an additional transfer to TEK from the Government, acting as an interest-free loan. In the future, it would be preferable either for TEK to receive adequate government equity to stay up to date on its debt service payments, or to make more internally generated funds available for TEK's debt service. 5.10 The Bank has discussed with TEK a method to maintain more accurate records of principal and interest payments due to foreign creditors and the date and amount of payments actually made by TEK, in foreign currency terms and converted to TL at the correct exchange rate. As part of the Financial Action Plan, TEK will update on a semi-annual basis records of foreign debt service payments paid and outstanding for the current and following two years for periodic review by the Bank.  - 39 - Recent Trends in Sector Financing and Internal Cash Generation 5.11 Among public enterprises, TEK has received in recent years the largest allocation from the national budget in the form of direct government equity. In 1983 and 1984, TEK received 23% and 35Z respectively of total government investments in public enterprises. With the objective of increasing sector self-financing, the Bank and the Government have agreed on targets for the share of public investments in electric power to be covered by internally generated funds. According to the agreed formula, TEK's internal cash generation is adjusted for TEK and DSI electric power-related debt service, and then compared to the subsector investment program, including TEK and DSI power investments.!! 5.12 Changes in working capital are included in the definition of internal cash generation (i.e., a decrease (increase) in working capital is regarded as a source (use) of funds). However, the covenant was not intended to consider failure to pay for annual operating costs as a "source of funds" for capital expenditures. As explained above (paras. 5.05-5.07), in the past four years, there have been abnormal variations in TEK's short-term accounts, distorting the picture of the degree of self-financing achieved. Therefore, in reviewing TEK's past levels of internal cash generation, it is more meaningful to exclude changes in working capital during this period. (Such unusual fluctuations in working capital are no longer expected after 1985.) 5.13 Table 5.3 compares the covenanted level of internal cash generation (column a) for the 1981-1984 period, with actual performance, both excluding changes in working capital (column b) and including these changes (column c). The level of sector internal cash generation for 1981-83 has been overstated since it was not possible to adjust correctly for DSI's debt service for power projects. However, estimated DSI debt service has been included for 1984 and afterwards. Borrowing for DSI projects is contracted by the Government; since many of DSI's projects are multi-purpose, it has been difficult to isolate the power-related debt service. This matter will be analyzed in the course of the appraisal for the next Bank-financed hydropower project with DSI, which is planned for FY86. 5.14 While estimated internal cash generation financed between 10% and 20% of power investments in 1981 and 1982, it did not quite reach covenanted levels. Then in 1983, when tariffs dropped in real terms, TEK internal cash generation was actually negative. Preliminary results for 1984 indicate a rebound, with internal cash generation at about 16% of power investment, compared to the covenanted level of 21Z. In view of the large real increase in tariffs achieved in 1984, however, the recent performance under the covenant can be regarded as acceptable. 1/ This covenant was originally included in the Karakaya Hydropower Project (Loan 1844-TU, 1980), and-later ammended in May, 1983. (The treatment of taxes in the internal cash generation formula is discussed in Annex 5.8, para. 16.)  - 40 - Table 5.3 TEK Internal Cash Generation (1981-1985) (As Z of Power Subsector Investment) Year Covenant Actual /a /b /c 1981 20 13 20 1982 22 19 21 1983 12 0 21 1984 (estimated) 21 16 (31) 1985 32 - - 1986 onwards 35 - /a Agreed under Loan 1844-TU (May 1980); subsequently targets for 1983 and 1984 were lowered during negotiations for Loan 2322-TU (May 1983). /b Excluding changes in working capital. More meaningful than /c for 1981-84 (as explained in para. 5.12). /c Including changes in working capital. Less meaningful than /b for 1981-84 (as explained in para. 5.12). Public Participation Fund and Keban Revenue-Sharing Certificates 5.15 As part of the Government's innovative resource mobilization policy, the recently created Public Participation Fund (PPF) issued in January, 1985, TL 40 billion (US$90 million equivalent) of revenue-sharing certificates associated with the Keban hydropower plant../ The certificates, underwritten by the Isbank, were sold within two days. TEK retains full ownership of the Keban power station but must transfer to the PPF a base rate of TL 11.3/kWh (60X of the bulk tariff) for electricity generated by the Keban station, with this rate increasing as bulk tariffs increase. The PPF will pay out as interest only 22Z of the money transferred to it from TEK, the remainder to be used for priority projects, especially in the energy sector. Holders of Keban certificates earn no guaranteed return, because the interest payments which they will receive are a function of TEK's sales tariffs and of the actual 1/ The PPF, established by Law 2983 (1984), can issue revenue-sharing certificates associated with existing public infrastructure facilities, and such certificates have also been issued for the Bosphorus Bridge. The first issue of Keban certificates included TL 20 billion of Series A with a three-year maturity and TL 20 billion of Series B with a five-year maturity. The Keban Hydropower Plant of 1330 MW was constructed in two stages during 1964-1983; the total cost in January 1985 prices is estimated at US$1.1 billion, or TL495 billion. Using a 50-year life, the annual depreciation would be about TL 9.5 billion.  - 41 - generation of Keban and, therefore, these investors could become a new constituency in favor of electricity tariff increases. 5.16 Most of the resources available to the PPF in conjunction with the Keban certificates come directly from TEK; out of TL 360 billion (in 1985 prices) projected to flow thr6ugh the PPF in 1985-1989, only the initial TL 40 billion invested by private individuals represent new resources being generated from outside the sector. In 1985 the PPF is directing these funds at priority hydroelectric projects under construction (e.g., Karakaya, Kapulkaya, Menzelet, Catalan, Genzende, Adiguzel) to assure a steady flow of Turkish Lira to contractors and, where possible, to advance the completion dates. Eventually some investments carried out by TEK may be selected for financing through grants from the PPF. Additional revenue-sharing certificates may be issued in the future, tied either to the Keban Dam or to other hydropower plants. 5.17 It is logical that cash generated by TEK should be used to finance DSI's investments in hydroelectric power, since DSI itself is not a revenue-earning entity, and because, under the present policy, TEK does not pay anything to the Government when completed hydroelectric facilities are transferred to TEK from DSI. TEK's payments to the PPF could now be regarded as a form of reimbursement for the Keban facility. On the basis of the January 1985 tariffs, TEK would have to pay TL 64 billion annually to the PPF. At this rate, TEK would have repaid the Government for the total cost of the Keban power station at the end of eight years. C. FINANCIAL PLANNING AND ACCOUNTING PRACTICES Financial Planning 5.18 Short-term financial planning is carried out by TEK in conjunction with the approved annual investment program, normally finalized in November/December preceding the given year. At this point, TEK receives an indication from the Ministry of Finance of the likely amounts of three sources: (a) government equity contribution from the budget, (b) foreign credits, and (c) local credits from the State Investment Bank (DYB). There is no implicit government approval of any tariff increases needed to permit financing the remainder of approved investment program. In its yearly finaa=ing plan, TEK therefore esti:a:es ,:s 4aterna` cash generation based only on tariff increases already authorized by the Government, showing a-y residual as a "gap". 5.19 Partly due to its lack of control over tariff setting, TEK management does not rely on medium- or long-term financial planning to determine the possible size of the investment program. Without giving full consideration to whether financing will be available, the formulation of the investment program is instead driven by technical criteria. Although a rolling five-year financial forecast is updated annually by TEK for submission to the World  - 42 - Bank, it is a very time-consuming exercise with inadequate flexibility to test the consequences of major changes. TEK prepares the forecast manually, making it nearly impossible to change parameters once the exercise is under -;ay. Furthermore, contingencies for price and exchange rate fluctuations over the forecast period are not incorporated. The necessity for closer coordination between financial and technical planning is now being recognized by TEK and the Government given that resource limits have directly affected the implementation of the investment program. This issue will cdntinue to be a focus of Bank sector and supervision missions. Audits 5.20 As with other public enterprises, TEK's financial statements follow the Ur.f'orm Chart of Accounts, and are audited by the High Control Board connected with the Prime Ministry. TEK is required by Law 233 to submit its balance sheets and final accounts to the Prime Ministry for auditing no later than the third month following the year they pertain to. TEK is then meant to submit its annual audited accounts to the Bank no later than five months after the close of the year. However, there are shortcomings with both the scope and the timing of the preser.t audit reports. The auditors rarely comnent on the reliability of the presentation of the accounts, or on significant events which occurred during the year. The audit reports concerning 1981 and 1982 were received more than a year after the close of the fiscal year. Similarly, the audit report for 1983 had not yet been received as of April 1985. 5.21 Most likely it will not be possible to meet the five month target for submission of the audit report, until the 1987 report. TEK's consultants, SEI/Mage (para. 5.23), are giving priority to helping TEK improve the timeliness and accuracy of the financial statements. Furthermore, an upgrading of TEK's computer center, presently being studied, should improve TEK's ability to prepare and correct the annual financial reports. During negotiations agreement was reached on a gradual schedule of improvement for submitting audit reports, with the 1985 and 1986 audit reports being expected within 10 and 8 months, respectively, after the end of the given fiscal year, and within 5 months for 1987 and afterwards. Asset Revaluation 5.22 The practice of revaluation of fixed assets in service was discontinued by TEK in 1979. Then, starting in January 1983, according to Law 2791, TEK and all other public enterprises were once again required to revalue their assets. However, the mission does not consider that the present revaluation regulation will result in a meaningful asset value.J' At such / The price index stipulated in the law does not appear to bear any relationship to historical trends, as this index would imply that inflation in Turkey has been 100% each year from 1972 to 1983, and then 37% in 1984, when the change in the wholesale price index was actually about 50%. In any year when inflation is less than 10%, no revaluation of assets need occur, according to this law.  - 43 - time when TEK's fixed assets have been revalued adequately reflecting their replacement value, the rate of return on assets will become a meaningful indicator of adequacy of tariffs. However, given higher priorities for improvement of TEK's accounting, including the accurate recording of the historical book value of assets, asset revaluation will not be dealt with under the proposed Project. Technical Assistance to Improve Accounting 5.23 A three-year technical assistance effort (1985-1987) to improve TEK's financial reporting and customer accounting, is being implemented under TEK Transmission III (Loan 2322-TU) by TEK with Southern Electric International (SEI) and Mage, their Turkish partner. The objectives are to: (a) eliminate double accounting and information flow bottlenecks between the accounting and related departments; (b) improve customer accounting systems for two pilot distribution enterprises -- Ege (Izmir) and Central Anatolia (Ankara); (c) improve the timeliness, accuracy and format of financial reports needed for management and external users (including IBRD); and (d) design the first stage of a management information system for TEK. This TA effort has made good progress to date and enjoys the close collaboration of the related TEK managers and staff. While the scope of the present contract is ambitious, it has still been limited to take account of constraints on TEK's absorptive capacity for change. 5.24 Follow-up will be needed to build on and extend the improvements made, but further consulting services in this area should be engaged only after the present TA contract has been implemented. The Power System Operations Assistance Project includes funds for an estimated 100 man-months of technical assistance which will cover the following: (a) development and implementation of improved cost accounting for maintenance, operations and materials; (b) introduction of a management information system for TEK; and (c) improvement in financial planning. D. FUTURE FINANCIAL PROSPECTS Financing of MediumrTerm Power Investment Program: 1985-1989 5.25 In order to meet expected national electricity demand after 1990, a considerable growth in investments in electricity generation, transmission and distribution would be required in the next five years. At the same time, TEK and DSI are expected to face substantial resource constraints in this period. The Bank's review of the public sector investment program and the potential for resource mobilization, which is presently being conducted in the context of SAL V, has ind-cated that it will be necessary to limit real growtn in overall public spending to lower levels than planned by the Governnent in the medium-term. However, since TEK is a revenue-earning entity, the power  - 44 - subsector will have increasing amounts of internally generated funds available and will not need to depend heavily on Government equity contributions. Furthermore, legal changes have increased the potential for private investment in power generating capacity (para. 5.36). 5.26 1985: As already mentioned, medium-term planning for the power subsector needs to be strengthened; only for 1985 is there some certainty regarding the power subsector investment program and related financing plan. TEK's 1985 investment program as approved in December 1984 amounts to TL 400 billion, and another TL 200 billion has been allocated for DSI's hydropower investments in 1985. DSI's power investments are to be financed in 1985 by government budget and borrowing (66%) and by transfers from TEK through the PPF (33Z). Financing for TEK was originally authorized as follows: 25% from government equity contribution; 30% from foreign borrowing; 5% in local borrowing from the State Investment Bank (DYB); and the remaining 40% from internal cash generation. Then in April 1985, the government contribution to TEK was reduced by half to TL 50 billion. To fill the resulting gap and to meet the remaining resource needs, the Government has already begun to implement a series of tariff increasu,. Bulk tariffs went up in nominal terms by 47% in the first quarter of 1985,- a period during which the wholesale price index increased 15% to 20%. It may be difficult for the Government to maintain the present level of tariffs in real terms throughout 1985, in the light of the sizeable tariff increases already implemented. One possible outcome is that no further tariff increases would occur other than fuel cost adjustments; in this case, the approved program would need to be slightly cut (by about 5%) and the resulting self-financing level would be about 36%. This is assumed to be a "base case". (Available internal cash generation could be lower if inflation surpasses the 35% forecast, or higher if significant further tariff increases are implemented during the rest of 1985.) 5.27 To determine what level of overall power subsector investment could realistically be financed through the public sector after 1985, the investment scenarios outlined in Chapter II were examined.2/ 5.28 Scenario "A": The desired investment program as proposed by TEK and DSI reflects a very large increase in investments in 1986, almost 60% higher than the 1985 level. This level of investment could be financed if: (i) tariffs in effect April 1, 1985 are sustained in real terms throughout 1985 and then increased a further 15% in 1986, and (ii) government equity doubles in real terms, compared with the approved 1985 level. Because this 1/ Bulk tariffs were increased by 10%, 11% and 20% effective January 1, March 1 and April 1, respectively. These are the nominal increases excluding the VAT and TRT charge collected by TEK, which do not affect TEK's net income. (See Annexes 5.1, 5.2 and 5.3.) 2/ Alternative scenarios for the TEK and DSI power investment programs are discussed in paras. 2.24-2.28 and Annex 2.2.  - 45 - combination of actions does not appear to be feasible, it is concluded that the program proposed by TEK and DSI for 1986, could not be financed. Overall the TEK/DSI program proposed for 1985-89 is about 15-20Z higher than the likely level of resource availability for the public sector. 5.29 Scenario "B": This represents the upper bound of national investment requirements needed to meet demand in the 1990s as estimated by the Bank. In order for TEK and DSI investments to reach this level, resources available to the public sector would need to be greater than can reasonably be envisaged. Government equity and foreign borrowing for power would need to increase by 10% and 20% p.a., respectively, over 1985-1989, and average tariff revenue in 1985 and 1986 would need to be 15% higher in real terms than the preceding years. The resulting internal cash generation levels would range from 50% to 60%. 5.30 Scenario "C": This scenario, considered by the Bank a lower bound of required investments, will still require significant tariff increases in 1985 and 1986. The average revenue per kWh sold would need to increase in real terms by 20% and 15Z in 1985 and 1986 respectively over the previous year's level in order to meet the sector's resource requirements. After 1986, as a result of these increases, and the expected increase in electricity sales made possible by completion of major plants, there would be more than adequate resources available within the sector to finance the minimum level described as Scenario "C". 5.31 Scenario "D": The Bank's financial projections thus indicate that resources could be available to the public sector (i.e., TEK and DSI) to finance an intermediate level of investment, which is between the higher levels (Scenarios "A" and "B") and lower bound (Scenario "C") discussed above. Scenario 'D", which was used as a base for the financial forecasts, indicates the level of investment which the public sector is likely to be able to support. The composition of the public power investment program and the timing of major projects which would be consistent with Scenario "D" will need to be examined through sector missions and project supervision. The relation of Scenario "Di to the other investment scenarios is shown graphically in Table 5.4. It is based on the assumptions listed below. (Related agreements are given in para. 5.35.) (a) Electricity tariffs. Following the major increases implemented in the first quarter of 1985 (para. 5.26), it is assumed conservatively that no further increases might occur in 1985 beyond the agreed fuel cost adjustment of tariffs. The real increase in the average bulk tariff for 1985 over the 1984 level would then be 10, assuming 35% inflation in 1985. Then, during 1986-1988, real increases of 5% p.a. are assumed in order to bring tariffs to at least reflect LRMC by 1989.  - 46 - (b) TEK's internally generated funds would stay within the sector, financing TEK's investment program directly, as well as being transferred in part to DSI via the PPF. (c) TEK's foreign borrowings and government contributions to TEK in the form of new equity would increase by at most 4% p.a. in real terms over the approved 1985 level. (d) DSI's power investment program could be funded by foreign borrowing and government contributions, together increasing at most 6% p.a. in real terms over the approved 1985 level, and by TEK's transfers to the PPF as already committed for the first Keban revenue-sharing certificates (para. 5.15). Under these assumptions, the level of self-financing (internal cash generation) for the power subsector could increase to 60-65% by the end of the decade.l/ 1/ The calculation of estimated internal cash generation is shown in Annex 5.6 and related assumptions are discussed in Annex 5.8, para. 16.  - 47 - Table 5.4 Scenarios for Investment in Electric Power (thousands of billion TL in mid-1984 prices) (TL 3501US$) 1.3 *B 1.2 A D 0.9 0.8 C 0.7 0.6 1 0.4 0.3- 0.2 0.1 1985 1986 1987 1988 1989 - Scenario "A" - TEK and DSI projection of required expenditures (TEK/DSI estimate). II = |Scenario "B" - Overall national level of investment required to meet growth in electricity demand in Turkey in the 1990s (Bank estimate). O~ Scenario "C" - Minimum level of investment required to complete ongoing and high priority projects (Bank estimate). A Scenario "D" - Level of investment by TEK and DSI which could be financed, taking into account expected tariff increases and growth in foreign borrowing and government equity (Bank estimate).  - 48 - Future Financial Position of TEK 5.32 Financial statements for TEK for 1981-1989, showing the implications of Scenario "D", appear in Annexes 5.4 to 5.6, and the resulting financial ratios for TEK and the subsector are shown in Annex 5.7. The assumptions used in the base forecasts are listed in Annex 5.8. 5.33 Summary. 1985-1989. The growth in TEK's access to government equity and foreign borrowing is expected to be constrained, and the base financial forecasts show TEK relying increasingly on self-financing towards the end of the 1980s. The Bank was informed by MENR during the appraisal mission that this was the Government's intention. The expected completion of major generating facilities (e.g., Elbistan, Karakaya) will enable TEK to increase its level of electricity sales at a faster rate (by up to 20% p.a.) at the end of the forecast period, and to start to close the gap of unmet energy demand. Debt service coverage could increase from a low level of 0.8 times in 1983 to 4.0 times at the end of the 1980s, assuming that sales tariffs at that time would reflect fully LRMC. TEK's liquidity situation is expected to improve, as a result of the technical assistance TEK is currently receiving in customer billing and monitoring of receivables. It is estimated that nearly half of TEK's investments in 1985-89 would be financed by internally-generated funds available to TEK after tax (43%), supplemented by foreign borrowings (44%) and local credits (3%). Government equity would still be relied on to finance the remaining 10% of TEK's program, but would be more than offset by TEK's expected income tax payments. 5.34 Sensitivity analysis shows that the base financial forecast would be materially affected by periods with higher than expected inflation, during which tariffs could easily slip downwards in real terms, while the cost of completing ongoing investment projects would increase and the Turkish Lira cost of foreign debt service obligations would also rise more than expected. Agreed Revenue Covenant and Supporting Covenants 5.35 If the progress made since January 1984 toward economic pricing of electricity (para. 2.19) is sustained, levels of sector self-financing could surpass 60%, especially when other sources (national budget, borrowing) are constrained. However, much uncertainty remains about future inflation rates in Turkey, as well as the possible levels of investment in electric power. The proposed Project therefore includes the present internal cash generation covenant (para. 5.11), supported by complementary covenants to strengthen investment and financial planning and to improve TEK's liquidity situation. The following agreements were reached during negotiations: -- to repeat the present internal cash generation covenant in the present loan, maintaining the same covenanted levels for subsector self-financing as minimum targets (32% in 1985, 35% thereafter).  - 49 - Indication of how the agreed level of internal cash generation would be met for the following year would be provided to the Bank by October 31 of each year. The definition of internal cash generation would be clarified as follows: TEK's payments to the PPF (para. 5.15), to the extent that these amounts are maintained within the subsector to finance electric power investments, would be treated as subsector internal cash generation. for TEK and the Government to review with the Bank by October 31 of each year the proposed annual investment program for the power subsector for the next year and the planned power subsector investments for the next five years and the related financing plans, (para. 2.30). These annual reviews would address present concerns that medium-term investment planning does not take financial constraints into account. for TEK to implement a Financial Action Plan achieving the following objectives; improvement of collection of customer bills (para. 5.08); improvement of foreign debt service recording and management (para. 5.10); and engagement of consultants to follow-up and extend improvements in accounting and MIS presently underway (para. 5.24). Potential for Private Investment in Power 5.36 A large gap remains between the total national requirements for investments in electric power (Scenario "B"), and the level of investment which can reasonably be financed and carried out by TEK and DSI (Scenario "D"). This gap is illustrated in Table 5.4. For the five-year period, 1985-1989, it is estimated that total national requirements will amount to uS$14 billion equivalent (TL 6,500 billion in early 1985 prices), of which TEK and DSI could feasibly carry out only about 802. The remaining gap, about US42.8 billion (TL 1,250 billion), would need to be financed through other sources which could include the following: (a) CEAS and KEPEZ; (b) foreign concessions; (c) local investors; and (d) issue of more revenue-sharing certificates associated with Keban or other hydro facilities. 5.37 The likely level of private investment in power in Turkey is still uncertain, other than for CEAS and KEPEZ, who plan to undertake investments of about US$0.5 billion in the next five years. The Government has begun discussions with local parties which could serve as "entrusted" companies operating as integrated utilities in designated regions, and with foreign companies which could invest in thermal power plants (e.g., nuclear, imported coal) on a concession basis without requiring TEK or the Government to take on additional foreign debt (para. 2.16). An expanded role for private investments in power could be advantageous, depending on the cost and the sales tariff agreed to for purchases from private suppliers. However, it is not likely that these prospects will result in the necessary scale and timing of investments in the next five years, and thus the shortage of electricity supply in Turkey is expected to continue into the 1990's, until financing constraints can be resolved.  - 50 - VI. PROJECT JUSTIFICATION Least-Cost Solution 6.01 The proposed Project is justified as being the least-cost means of interconnecting the new plants coming on line to meet the power requirements as reviewed by the Bank. The Project is part of TEK's long-term (10-15 years) transmission expansion plan which was updated in January 1985, on the basis of present worth comparison of investments and operating costs, including losses, for the following technically viable alternatives: (a) A 380-kv system throughout. (b) A combined 380-kV and 800-kV system. (c) A combined 380-kR and -, 500-kV (DC) system. 6.02 Alternative (a)-380 kV alone-was shown to be the least-cost solution at 12Z discount rate, equal to the estimated opportunity cost of capital in Turkey. 6.03 The evaluation of transmission expansion alternatives is updated regularly to reflect experience with the initial group of lines, as well as changes in the development of TEK's interconnected system. The latest technical and economic evaluation in January 1985 confirmed that the lines included in the Project are the least cost means of extending the 380-kv network to interconnect the new plants. The evaluation was reviewed by the Bank and found to be satisfactory. 6.04 In addition, given the uncertainty in the availability of investment resources (para. 2.24), the Bank reviewed the timing, priority and level of invest-mnts in transmission and concluded that the proposed Project is justified since it would finance lines and substations needed to meet the high priority generating plants identified as part of the core electric power investment program (para. 2.27 and Annex 2.2). Return on Investment 6.05 Since the Project forms an integral part of TEK/DSI's 1985-1990 expansion program the economic rate of return on the whole timeslice of TEK's investment program for 1985-1990 (covering the construction period of the proposed project) was calculated (Annex 6.1). 6.06 The measurable costs comprise: (a) the capital cost of the adjusted expansion program for 1985-1990; (b) operating costs; and (c) the fuel cost of incremental thermal generation excluding fuel savings. No fuel escalation was assumed since increases in the price of fuels are covered by the fuel adjustment clause incorporated in the tariff structure. Detailed assumptions as well as results of the analysis are presented in Annex 6.1. 6.07 Measurable benefits were limited to the incremental revenue attributable to the program (para. 6.06), computed on the basis of: (a) TEK's  - 51 - projected sales to industrial customers supplied directly at the high-voltage level and to low-voltage consumers supplied through TEK's distribution enterprises; (b) projected tariffs at the high- and low-voltage levels; and any net fuel savings resulting from investment in improved efficiency in the thermal plants. Tariff adjustments were projected in line with the financial projections given in Chapter V, as follows: the January 1 through April 1, 1985 increases would result in an average high-voltage sales revenue for 1985 of TL 26.87/kWh, and for low-voltage sales, of TL 34.90/kWh, assuming that all increases in bulk tariffs are passed on to retail tariffs as agreed under the Project (para. 5.04). Further increases would take place in 1986, 1987, 1988 and 1989 (6Z, 5Z, 2Z and 2Z in real terms, respectively), reflecting the Government's commitment to allow sufficient tariff increases to raise the level of self-financing in the power subsector. Tariffs would remain constant in real terms thereafter. Since the tariffs used in the calculation were estimated as a proxy for consumers' willingness to pay, all taxes were included. Given the large unmet demand (para. 2.02) the willingness to pay, for electricity is likely to be higher than the current average tariff; but it cannot be quantified. 6.08 Under the above assumptions, the return on the program is estimated at 11.2%, marginally below the estimated opportunity cost of capital of 12%. However, it understates the real economic return since it excl-des the consumer's surplus. In addition, given the difficulties of quantifying precisely all the benefits generated by investments in improved efficiency of system operations, these benefits were not fully taken into account in the analysis, thus understating further the rual return on the investment program.  - 52 - VII. AGREEMENTS REACHED AND RECOMMENDATION 7.01 During negotiations, the Government agreed to extend the customs duties exemption to the proposed Project (para. 4.08). 7.02 During negotiations, the Government and TEK agreed to: (a) review with the Bank, not later than October 31 of each year, (i) the proposed annual investment program for the power subsector for the next succeeding year and the related financing plan, and (ii) the required investments and related financing plans for the next succeeding five years (para. 2.30); (b) maintain a fuel adjustment clause in TEK's electricity supply contracts and enforce a provision that its charges will be increased automatically to take account of increases in its fuel costs (para. 5.04); (c) reflect all increases affecting bulk (high voltage) tariffs, including fuel cost adjustments, in retail (low voltage) tariffs (para. 5.04); and (d) take necessary actions to ensure that subsector internal cash generation is at least equal to the following shares of annual capital expenditures in electric power made by TEK and DSI; 1985 - 32%, 1986 and afterwards - 35%. TEK's payments to the PPF, to the extent that these amounts are maintained within the subsector to finance electric power investments, would be treated as subsector internal cash generation (para. 5.35). 7.03 During negotiations, TEK agreed: (a) to submit to the Bank not later than June 30, 1986 a detailed staff training program, and to implement this program in accordance with an implementation schedule satisfactory to the Bank (para. 4.09); (b) on an action plan for completion of land acquisition proceedings for the new 380-kV and 154-kV substations by September 30, 1986, and to complete the land acquisition for at least 50% of the new substations by June 30, 1986 (para. 4.14); (c) to maintain a current ratio (defined as current assets divided by current liabilities) of at least 1.0 (para. 5.08); (d) to implement a financial action plan including: (i) steps to improve collection of customer bills (para. 5.08);  - 53 - (ii) improvement of foreign debt service recording and management (para. 5.10); and (e) to subinit its annual audited financial statements to the Bank not later than ten months after the close of 1985, eigL- months after the close of 1986, and five months after the close of each following year starting with 1987 (para. 5.21). 7.04 As a condition of loan effectiveness, TEK shall engage a project management consultant under terms and conditinsC sevisfactory to the Bank (para. 4.12). 7.05 With the above agreements, the proposed Project is suitable for a Bank loan of US$142.0 million, for a term of 17 years at the standard variable interest rate, including a four-year grace period, to the Borrower, TEK, with the guarantee of the Republic of Turkey. May 14, 1985  - 54 - ANNE 1.1 TUFKE FOUR TEK TRANSMISSION PROJECT Turkey - Energy Balances (Million tons of oil equivalent, NTOE) 1978 1980 1982 1983 MTOE Z HTOE Z 2OE Z MTOE Z Consumption Petroleum 18.0 51.6 16.2 46.3 17.1 45.2 17.2 44.8 Ligaite 4.0 11.4 4.6 13.1 5.2 13.8 6.0 15.6 Hard coal 2.8 8.0 2.7 7.7 3.0 7.9 3.2 8.3 Asphaltite 0.1 0.3 0.2 0.6 0.3 0.8 0.3 0.8 Hydroelectric 2.3 6.6 2.8 8.0 3.5 9.3 2.8 7.3 Imported electricity 0.2 0.6 0.3 0.9 0.1 0.3 0.2 0.5 Wood 4.6 13.2 4.8 13.7 5.0 13.2 5.1 13.3 Wastes 2.9 8.3 3.4 9.7 3.6 9.5 3.6 9.4 Total Consumption 34.9 100.0 35.0 100.0 38.0 100.0 38.4 100.0 Domestic Production Petroleum 2.9 8.3 2.4 6.9 2.5 6.6 2.3 5.9 Lignite 4.6 13.2 4.3 12.3 5.3 14.0 6.1 15.9 Hard coal 2.6 7.4 2.2 6.3 2.5 6.6 2.2 5.7 Asphaltite 0.1 0.3 0.2 0.5 0.4 1.1 0.3 0.8 Hydroelectric 2.3 6.6 2.8 8.0 3.5 9.3 2.8 7.3 Wood 2.3 6.6 2.7 7.7 2.3 6.1 3.5 6.5 Wastes 2.9 8.3 3.4 9.7 3.6 9.5 3.6 9.4 Subtotal 17.7 50.7 18.0 51.4 20.1 53.2 19.8 54.5 Illicit deforestation 2.3 6.6 2.1 6.0 2.7 7.1 2.6 6.8 Stock changes, net (0.7) (2.0) 0.1 0.3 (0.2) (0.5 (0.2) (0.5) Total domestic supply 19.3 55.3 20.2 57.7 22.6 59.8 22.2 57.8 Imports Petroleum 15.2 43.5 14.3 40.9 16.0 42.3 16.2 42.2 Hard coal 0.3 0.9 0.5 1.4 0.6 1.6 0.9 2.3 Electricity 0.2 0.6 0.3 0.9 0.2 0.5 0.2 0.5 Total imports 15.7 45.0 15.1 43.2 16.8 44.4 17.3 45.0 Petroleum exports (0.1) (0.3) (0.3) (0.9) (1.6) (4.2) (1.1) (2.8) Total supply 34.9 100.0 -35.0 100.0 37.8 100.0 38.4 100.0 Source: Energy Sector Strategy Paper, IBRD Report No. 4973-TU, September 1984. Ministry of Energy and Natural Resources. April 1 1985  - 55 ANNEX 2.1 Page 1 of 4 TURXEY FOUIErR TEK TRANSMISSION PROJECT Demand Forecasts 1. TEK's latest long-term generation plan (1987-2005) is based upon the demand forecast shown in Table 2.1. Overall growth in energy demand is estimated at 11.2Z per annum with peak demand increasing at 9.OZ per annum. This represents a considerable sustained annual increase in demand, particularly as the base from which the demand is extrapolated (1987) appears to be high. Table 1 TEK's Demand Forecast (1987-2005) (Selected Years) Net Demand Required Generation Peak (MW) Energy (GMh) Capacity (mg) Energy (GWh) 1987 8,760 49,100 11,966 59,411 1990 12,180 68,300 16,199 82,960 1995 21,350 119,800 29,429 143,760 2000 28,900 162,200 38,437 192,640 2005 40,500 227,400 53,865 270,606 Source: TEK. 2. TEK's medium and long term demand forecasts are based upon the past relationships (1965-1983) between growth of (MP, industry and electricity consumption which may no longer be valid, and on over-optimistic assumptions about the future growth of the economy. Furthermore the forecast does not take into account the possibilities for modifying electricity consumption patterns through demand management, conservation and appropriate pricing policies. 3. In connection with Bank sector work as well as the subsector study - 'Turkey - Electricity Planning and Investment", Report No. 5031-TU, dated June 22, 1984 a set of demand projections were prepared for discussion with TEK. These were based upon the scenarios as presented below.  - 56 - ANNEX 2.1 Page 2 of 4 4. Scenario One assumes that the Government does not vigorously pursue a load management program nor increase prices in real terms. Projections of sales were made for five sectors: industry (large bulk supply consumers), manufacturing, agriculture, public buildings and households. Industry, manufacturing and agricuLture projections were based upon elasticity coefficients of 1.634, 1.663, and 1.0, respectively, from data for the 1965 to 1982 period. Estimated growth in the Government buildings and households sectors was, in the absence of adequate data on electricity usage in these sectors, assumed to be directly related to GDP growth. The economic growth projections used for this case are given in Table 2 and are below those used in TEK's forecast. Sales data for 1982 were adjusted by 12Z as estimated by TEK to represent effective demand for that year. Reliability standards (reserve margin of 36X) and system losses were maintained as in TEK's original demand forecast. Table 2 Economic Growth Projections (% per annpm) GDP Industry Manufacturing Agriculture 1985-1990 5.4 6.6 8.0 3.5 1991-2000 5.0 6.0 7 .0 3.0 2001-2005 4.5 5.5 6.5 3.0 Source: Bank estimates 5. The purpose of this forecast was to develop a scenario which was based upon the methodology employed by TEK but adjusted to take into account new projections of economic growth and available data on current sales and effective demand. While this scenario results in a very high demand forecast it was used to compare with scenarios 2 and 3 in order to illustrate the considerable potential for conservation and demand management as well as demonstrate the urgent need for an improved and more realistic demand forecast. Table 3 Scenario 1 Net Demand Required Generation (HW) (GWh) (Mw) (GWh) 1987 9,624 46,389 12,088 57,666 1990 12,340 59,480 16,056 71,376 1995 17,363 91,157 23,440 109,388 2000 26,758 140,480 36,123 168,576 2005 34,715 194,406 46,865 233,287  - 57 - ANNEX 2.1 Page 3 of 4 6. Scenario Two was developed to illustrate the possible impact a demand management program could have upon the level of demand. A direct load management program (excluding tariff adjustments) would have a greater impact upon peak demand than energy demand. In the absence of detailed price elasticities for Turkey a conservative estimate of -0.15 was used and this was based upon approximate price elasticities calculated in other countries.l/ The introduction of tariff increases was assumed to take place over a ten year period such that tariffs increased to their respective long run marginal costs. For three specific industries, iron and steel, copper and aluminum energy savings equivalent to about 600 GWh or approximately 100 MW of capacity were calculated. Required generation, excluding losses, was estimated on the same basis as the base case. The results indicate a long term growth in peak demand of about 7.5% per annum. Table 4 Scenario 2 Net Demand Required Generationa/ (MW) (Gih) (Mw) (GWh) 1987 9,624 46,389 12,088 57,666 1990 12,120 58,421 15,756 65,342 2000 15,787 88,847 20,523 97,731 2000 24,158 137,686 30,197 151,456 2005 31,243 180,867 39,054 195,894 a/ Assumes system losses reduce from 20% to 10X and a reserve margin equivalent to 25Z. 7. Scenario 3 assumed a more dramatic improvement in energy efficiency including a progressive decline in GDP-energy elasticity until unity is reached by 1995. This results in an overall growth from 1990 onwards of 6.12 per annum in peak demand and represents capacity additions of about 1000 MW per anntum. 1/ See for example, D. Julius 'Energy Pricing in Developing Countries: A Review of the Literature" World Bank Energy Department Paper No. 1, October 1, 1981.  - 58 - ANNEX 2.1 Page 4 of 4 Table 5 Scenario 3 Net Demand Required Generation (MW) (GWh) (KW) (GWh) 1987 9,624 46,389 12,088 57,666 1990 12,120 58,421 15,756 65,342 1995 15,190 85,064 18,988 90,421 2000 19,386 110,488 24,232 121,537 2005 24,742 143,232 30,927 155,129 8. The estimates in Scenario 1 are close to those estimated by TEK up to 1990 but thereafter show a marked difference, primarily as a result of the lower economic growth projections assumed by the Bank. This results in a required capacity by 2000 of about 2,300 MW less than in the TEK projection and 7,000 MW less in 2005. However, under Scenario 2, a further 3,000 MW by 2000 and almost 1,000 KW by 2005 could be saved. Scenario 3 shows an even greater savings in requited capacity by 2005, some 8,100 MW less than Scenario 2 and almost 23,000 MW less than TEK's projections. 9. While the above forecasts are very preliminary, they do illustrate the considerable potential for investment savings in generating plant. For example, Scenario 1 implies present worth (1983) capital investment savings of about $5.75 billion compared with the TEK forecast. Furthermore, a lower growth rate in demand would allow TEK to delay implementation of some of the more costly investment options in the plan such as the high capital cost nuclear and the more marginal lignite-fired plants. 10. The above projections underline the critical importance of preparing a realistic demand forecast. As discussed in para. 2.21 TEK has hired consultants to assist in the analysis of load data, preparation of detailed short-, medium- and long-term demand forecast and identify the costs and impact on demand of various load management (including pricing) actions. 11. The analysis of demand discussed here was, however, not used as a basis for the TEK sales forecast in the financial projections. In the period 1985-1989 electricity supply is expected to be less than demand, and sales will therefore be a residual of the supply forecast, i.e., gross available generation less losses (see Annex 2.2, Attachment 1). April 11, 1985  - 59 - ANNEX 2.2 Page 1 of 10 TURKEY FOURTH TEK TRANSMISSION PROJECT The Electric Power Investment Program 1985-1989 Introduction 1. TEK and DSI prepare annual investment budgets for submission to SPO and Government. There is no bureaucratic requirement for TEK and DSI to prepare a medium term (e.g. 3-5 year) projection of expenditures and, in the case of TEK a projection of revenues from sales. However, as part of the Bank appraisal and supervision process TEK and DSI were requested to provide projections of expenditures, sales and revenues for the period 1985-1989. The energy chapter of the Government approved 5th Five Year Plan was used as a guide to Government priorities and policies in the energy sector. .The 1985 Approved Program 2. Table 1 below summarizes the main features of TEK's proposed investment program submitted to SPO in July, 1984 for approval and the final Government approved investment program for 1985, including the DSI hydro program. Table 1 (a) The TEK 1985 Investment Program (millions of TI., June 1984 prices) TEK proposal sub- SPO-approved mitted to SPO program Generation Z Ongoing - to be completed in 1985 3,300 3,000 Ongoing - to be completed after 1985 281,756 185,300 New projects 39,270 12,750 Total generation 324,326 (53Z) 201,050 (50%) Transmission Transmission 100,378 63,250 Subtransmission 22,000 18,000 Total transmission 122,378 (20%) 81,250 (21%) a/ Exchange rate: US$1 - T1 350.  - 60 - ANNEX 2.2 Page 2 of 10 Table 1 (Con't) (a) The TEK 1985 Investment Program (millions of TL, June 1984 prices) TEK proposal sub- SPO-approved mitted to SPO program Distribution Urban distribution b/ 77,792 50,000 Village electrification 28,548 28,500 Total distribution 106,340 (17%) 78,500 (20%) Operations, Machinery & Equipment Operations 34,274 21,500 Machinery and Equipment 18,607 11,000 Vehicles 3,839 1,800 Total 35720 (9%) 23T;W (8%) Miscellaneous Studies 2,360 900 New TEX building 5563 4,000 Total miscellaneous 7,923 (lZ) 4,900 (1%) Total Investment 617,687 (1OOZ) 400,000 (100%) (b) TEK and DSI 1985 Investment Program (millions of TL at June 1984 prices) TL z Generating plant 401,050 65% Main transmission 63,250 11% Subtransmission 18,000 3% Urban distribution 50,000 9% Village distribution 28,500 5Z Other investment 39 200 7% Total 600,000 b/ Includes Illerbank. Source: TEK, MENR  - 61 - ANNEX 2.2 Page 3 of 10 3. The above table calls for the following comments: (a) The approved allocations for 1984 show a continuation of the trend for generating plant to take the major share of the program although the allocation shows some improvement compared with previous years. (b) The allocation to urban distribution shows considerable improvement (9Z compared with 5% in 1983) although still substantially below the investment requirements for renovating and expanding the urban distribution systems; and below the current absorptive capacity level of the distribution enterprises, estimated by TEK at 75-80 billion Turkish Lira. (c) The overall TEK investment program for 1985 shows a decline in real terms over the 1984 program. TEK had initially proposed a program for 1985 of about TL 618 billion althoug. this has been reduced to TL 400 billion. There are some encouraging signs that TEX has, in adjusting the program, paid attention to priority investments: (i) minimal adjustments have been made to the allocations for the high priority ongoing generation projects; (ii) the allocations for new projects (other than Thrace combined-cycle) have been substantially reduced or eliminated; (iii) potential uneconomic new projects such as Elbistan B and Saray have been excluded from the 1985 program and this should give time for TEK to re-evaluate these projects (in conjunction with the Bank's policy dialogue on the lignite sector); (iv) despite a trimming of investment for urban distribution to a level at which TEK agrees is undesirable, the allocation represents a real increase over the 1984 program; (v) the allocation for the nuclear program was cut from TL 45 billion to a negligible TL 10 million. (vi) allocation to operations and equipment (and hence presumably maintenance) shows an increase in real terms over 1984. 4. In economic and financial terms, the continuing high levels of investment in village electrification compared with other parts of the subsector investment program is unjustified. The investment requirements for the village electrification program show no reduction and are currently at a level of about 60% of the urban distribution program. For example, investment in the three major distribution enterprises (Bogazici, Ege, and Icanadolu) at about TL 20 billion is less than the village electrification program (TL 28.5 billion) despite the fact that those three enterprises account for 68% of total low-voltage consumption (1983 data). However, the village electrification program is considered an important social and political  - 62 - ANNEX 2.2 Page 4 of 10 objective of the Government, especially since the present program is focused primarily in the eastern provinces of the country which are considered impoverished and less developed than Western Turkey. Scenario "A": 1985-1989 TEK/DSI Projected Investment Program 5. Both TEK and DSI provided to the Bank an estimate of annual projected public sector expenditures between 1985 and 1989. These were given to the Bank as informal working documents and not as approved levels of investment for electric power. The principal assumption made by the agencies was that implementation capacity and not financial availability would be the main constraint to investment scheduling. The financing constraint is discussed in para 18. auble 4 summarizes the projected expenditures and greater detail is provided in the Project File. In addition balances of energy and capacity consistent with the projected investment program were prepared by TEK and are shown in Attachment 1. Table 2 Scenario "A" TEKIDSI Projected Investment 1985-1989 CTm billions, June 1984) at 1985 1986 1987 1988 1989 Thermal generation 201 368 200 159 135 Hydro generation 200 343 454 514 666 Transmission 63 88 69 69 89 Sub-transmission 18 24 33 45 60 Urban electrification 50 65 85 115 150 Rural electrification 29 40 50 60 70 Miscellaneous b/ 39 45 45 25 25 Total 600 973 936 987 1,195 of which TEK 400 630 482 473 529 a/ ~Figures rounded up, exchange rate US$l = TL 350. b/ Includes operations, buildings, machinery and equipment and studies. 6. Investment costs are based upon estimated costs to complete all ongoing projects; the introduction of a limited number of new thermal power plants, a rapid build up of new hydra plants, and the necessary investments in transmission, distribution, maintenance and general plant to complement the growth in new generation projects. 7. The Bank reviewed with the agencies and )ENR the proposed expenditure program and gave the following comments;  - 63 - ANNEX 2.2 Page 5 of 10 (a) The thermal generation program is basically sound although the Bank recommended that the Beysehir power plant be dropped from the 1985 investment program and revaluated, new geothermal projects be dropped from the program and Government should focus increasingly on providing a policy f.ramework for e;;couraging private sector development in the geothermal sector; the nuclear program be deferred from the 1985-1989 program until clarification is received on the "concession financing" model proposed, and a second combined cycle plant be introduced to utilize imported natural gas by the early 1990s. (b) The hydro generation program requires considerable revision: (i) it includes 26 ongoing projects which represents a heavy burden with respect to implementation schedules. However of these 26 ongoing projects 82! are either under 75 MW in size and/or have expenditures to date as a proportion of total cost of less than 5Z and would, therefore, be of lower priority than the larger and more developed projects. (ii) DSI has included start up of 84 new hydra projects in the 1986-1989 period which is totally unrealistic both from a financing viewpoint and from the implementation capacity of DSI to mount such a program. In essence, the list appears to be a 'shopping list" of potential projects, neither ranked technically nor economically and including projects ranging in size from 8 MW to 1,200 MW. A severe pruning of this project list is, therefore, required. (iii) Transmission and subtransmission line items appear to be consistent with the timing of the well advanced thermal and hydro generation projects although annual reviews and increased awareness of flexibility in planning the timing of transmission investments will be required, especially if delays are encountered in the generation program. (iv) Urban distribution is shown as increasing by about 30% per annum in real terms and this is a reasonable assumption given the growth in demand at the retail level as well as the poor condition of many existing urban networks. No breakdown by region was given, although it is recommended that the high density large urban areas, especially Istanbul, Izmir and Ankara, be given priority since together they account for almost 70% of total low voltage consumption. TEK has wisely hired consultants (EdF, France) to develop masterplans for these three urban areas which, once completed, would provide greater insight to required levels of investment for distribution. 1/ Lam2s 4, Mercan, Tohma, Derbent, Yenice, Ozluce, Kralkizi, Dicle (1100 MW but no expenditures yet incurred).  - 64 - ANMEX 2.2 Page o of 10 (v) Allccations for rural electrification are projected to rise by about TL 10 billion per annum on the basis of the targets for village electrification set by Government and the likelihood that new villages primarily located in the more remote provinces will cost more to connect as the program develops. This is a reasonable assumption at this point in time although TEK's consultants (EdF, France) have been requested to review the technical standards of the rural electrification program to assess whether investment costs could be reduced. (vi) The miscellaneous category includes general plant, vehicles, buildings, other machinery, studies and investment costs associated with the dispatch center but did not include the investment costs associated with the proposed Bank financed Operations Assistance Project. 8. The methodology adopted by SPO to estimate projected expenditures may result in a tendency to underestimate investment requirements. Both total project cost and past expenditures are adjusted to a constant price base and the difference represented as the balance of project cost. It is not clear whether real cost escalation as a result of delays is included in reestimating total costs nor whether costs are adjusted to reflect changes in project design. The Bank plans to investigate this issue further during the planned Public investment Review scheduled for end FY85. Scenario "B": Overall Power Subsector Investment Requirements - 1985-1989 9. Although TEK and MENR are currently working on the development of a long term least cost investment plan (para 2.09) for the power subsector no output from the WASP computer runs was available to the appraisal mission. However on the basis of sector work undertaken in Turkey (see Turkey - Long Term Investment Options for Power, Report nos. 5431-TU; and Turkey - Electricity Planning and Investment, Report nos. 5031-TU) the appraisal mission has constructed a likely level of investment in electric power to meet projected demand. 10. While the projections of required investment are consistent with present demand estimates they are assumed not to be constrained by resource availability nor by the implezentation capacity of the public sector. Indeed given the public sector's past record on implementation of key electric power investments it is clear that such an investment program could not be mounted solely in the public sector. It was assumed that ongoing projects currently in the investment program would be supplemented by the start up of new projects in order that demand between 1990 and 1995 would be met. Capacity requirements throughout the 1990-1995 period were taken from the base case of the draft subsector report on Long Term O7tions for Power (op cit) and are estimated as follows:  ANNEX 2.2 - 65 - Page 7 of 10 Table 3 Capacity A iEtons (NW) 1991 995 1992 1,095 1993 1,204 1994 1,191 1995 1,300 11. The table below gives the approximate levels of investment required during the 1985-1989 period to meet demand up to 1995. Table 4 Overall Investment Levels (T11 billion) W 1985 1986 1987 1988 1989 Thermal 201 250 250 300 325 Hydro 200 250 350 400 425 other 199 350 475 500 550 Total 600 850 1075 1200 1300 a/ TL 350 = US$1. Scenario "C": The Adjusted Public Investment Program 12. In view of the comments given in paras 6 and 7 the Bank carried out its own review of the different components of the program. This was based upon the assumption dhat, at a minimum, all ongoing high priority projects would be completed expeditiously and it included a review of current physical progress of ongoing hydro and thermal power plants, evaluation of size and type of new generation expansion candidates likely to be added to the program; and a review of the transmission, distribution and village electrification components of the program. The adjusted program, presented in sumary form in table 3 and in detail in the Project File, did not take into account macro-economic considerations of resource availability although a second scenario was constructed to reflect the serious resource mobilization issue facing the Goverment and this is presented in para 18 below. The adjusted program may be viewed as the minimum program required to ensure the completion  ANNEX 2.2 -66 - Page 8 of 10 of high priority ongoing generation projects. Balances of capacity and energy were also prepared reflecting the adjustments made to the investment program and these are available in the Project file. 13. The principal adjustments to TEK's projections of expenditures are sumxarized below: (a) Thermal Generation. High priority should be given to the following plants: Tuncbilek, Elbistan, Cayirham, Rangal, Chaneli, Soma, Yenikoy, Seyitomer, Yatagan 3, Yeni Catalagzi, Aliaga and Denizli 1, all of which are well advanced projects supported by foreign credits. Expenditures reflect TEK's estimates with the exception of Elbistan which was updated on the basis of recent cost data available within the Bank. Although physical progress to date is limited completion of the Trakya 1 combined cycle plant was accorded high priority since contracts have been awarded on a full project managament basis. The Kemerkoy plant scheduled for completion in 1987 is probably over ambitious and a rescheduling of that plant to 1989 has been assumed. Given the large scale imports of natural gas and TEK's decision to prepare a fesibility study for a second combined cycle plant located in Thrace it was assumed that construction of Trakya 2 (1000 MW) would start in 1987. Other than the first Denizli unit no new geothermal plants were included in the public investment program since it was assumed that no further investment would take place until the severe operating problems of the pilot project in Aydin were resolved and any future investments in geothermal would be undertaken by the private sector. The 1 x 340 MW Beysehir unit was assumed to be deferred, pending a reevaluation of its economic merit since preliminary analysis by the Bank indicates that, because of the high cost of lignite supplied to the power plant, the project is uneconomic. The first nuclear plant as well as any imported coal fired power plants were deferred from the adjusted program pending clarification on the "concession financing" model proposed by Government. However since it is likely that TEK will embark upon construction of an additional 2-3 large thermal power plants a line item for unidentified thermal plants was included in the adjusted program. (b) Hydro Generation. High priority large hydro projects were maintained in the program as scheduled by DSI with some adjustments to the Urfa Tunnel and Ataturk, both of which appear to have a rapid investment build up in the 1986-1989 period. The smaller hydro projects listed in pare 7 (b) (i) were either dropped or deferred. The unrealistic number of new projects included in the DSI proposal was reduced to six including Kayraktepe, Batman, Boyabat, Ilisu, Cizre and Karkamis. In the absence of a detailed hydro inventory and technico-economic ranking of the available hydro sites these six were selected on the basis of size, known characteristics, likely financing and stage of preparation. Furthermore, given the large DSI  -67- ANNEX 2.2 Page 9 of 10 portfolio of ongoing projects it was assumed that no more than two projects per annum would enter the investment program. (c) Transmission and Distribution. The transmission and distribution program was reviewed with respect to timing of lines and substations with power plants. Urban distribution was maintained as per the TEK schedule and no real growth in investment in the village electrification program was assumed. Finally the miscellaneous category was, in line with Government policy to ensure adequate resources for maintenance and rehabilitation, increased to include allocations for the proposed Bank financed Operations Assistance Project. 14. The adjusted investment program is shown in Table 5 below: Table 5 Scenario "C" The Adjusted 1985-1989 Program mTL billions, June 1984)