Document of The World Bank Report No. 13887-RO STAFF APPRAISAL REPORT ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT AUGUST 9, 1995 Infrastructure Operations Division Country Department I Europe and Central Asia Region Currency Equivalents Currency Unit Leu Lei (plural) Value of US$1.00 in Lei (average) 1993 (January) Lei 480 1993 (December) = Lei 1276 1994 (April) Lei 1650 1994 (December) = Lei 1774 1995 (July) Lei 2020 Measures and Equivalents 1 Kilovolt (kV) = 1,000 volts (V) 1 Megawatt (MW) = 1,000 kilowatts (kW) = 1 million watts 1 Kilowatt-hour (kWh) 1,000 watt-hours 1 Megawatt-hour (MWh) 1,000 kilowatt-hours I Gigawatt-hour (GWh) 1,000,000 kilowatt-hours 1 Terawatt-hour (TWh) 1,000,000,000 kilowatt-hours I Ton of Oil Equivalent (TOE) 10 million kilocalories I Teracalorie (TCal) = 1,000 million kilocalories Principal Abbreviations and Acronyms used CC - Commercial Companies CCSER - Council for Coordination, Strategy and Economic Reform CHP - Combined Heat and Power CRP - Corporate Restructuring Program DSCR - Debt Service Coverage Ratio EBRD - European Bank for Reconstruction and Development EDC - Export Development Corporation of Canada EIB - European Investment Bank EU-PHARE - European Union Phare Program GOR - Government of Romania IAEA - International Atomic Energy Agency ICG - Internal Cash Generation J-EXIM - Japan Export-Import Bank MAPPM - Ministry of Water Resources, Forestry and Environment Protection MEDIO - Medio Credito Centrale - Italian Bank of Export Credits MoF - Ministry of Finance Mol - Ministry of Industries MMPS - Ministry of Labor and Social Protection MT - Ministry of Tourism MVA - Million Volt-Amperes NOX Nitrogen Oxide PID - Project Implementation Department RA - Regie Autonome RAL - Regia Autonoma de Lignite RENEL - Regia Autonoma de Electricitate (Romanian Electricity Authority) ROMAG - Nuclear Fuel Processing Company S02 Sulphur Dioxide USAID - United States Agency for International Development RENEL -- Fiscal Year January 1- December 31 POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT STAFF APPRAISAL REPORT Table of Contents Page No. LOAN AND PROJECT SUMMARY ....................................... i I. MACROECONOMIC SETTING AND THE ENERGY SECTOR .................. 1 A. Macroeconomic Setting ....................................... 1 B. The Energy Sector ........................................... 1 Introduction ............................................ 1 Energy Resources ......................................... 2 Institutional Setting ........................................ 2 Energy Pricing ........................................... 3 II. THE POWER SECTOR ........................ 7 A. Institutional Setting .......................................... 7 RENEL Organization and Management ........................... 7 RENEL Personnel and Staffing ................................ 8 Institutional Reform Measures ................................. 8 B. Power System Operations and Performance ........................... 9 Existing Facilities ......................................... 9 Generation ............................................. 9 Transmission and Distribution Networks ......................... 10 Technical and Operational Efficiency Improvement Measures ... ......... 10 C. Electricity and Thermal Energy Pricing ............................. 11 Electricity Pricing ........................................ 11 Thermal Energy Pricing .................................... 13 D. Demand for Electricity and Heat ................................. 13 Past Electricity Consumption and its Characteristics .................. 13 Forecast Electricity Demand ................................. 14 Past Supply and Consumption of Thermal Energy .................... 15 E. Power Sector Investment ...................................... 16 Mol's Investment Program .................................. 16 F. Private Sector Development .................................... 17 G. The Bank's Role and Strategy ................................... 17 The Bank's Role ........................................ 17 III. THE PROJECT .. 20 A. Project Objectives .......................................... 20 B. Project Description ......................................... 20 Thermal Plant Rehabilitation Program ........................... 20 C. Project Costs ............................................. 21 D. Project Financing .......................................... 23 E. Procurement .............................................. 24 F. Disbursements ............................................ 26 G. Enviromnental Aspects ....................................... 27 H. Project Implementation ....................................... 28 I. Project Monitoring and Bank Supervision ........................... 29 IV. FINANCIAL ASPECTS ....................................... ... 30 A. Background .............................................. 30 B. Financial Management ....................................... 30 Financial Organization ..................................... 30 Billing and Collections ..................................... 31 Insurance ............................................. 32 C. Past Performance .......................................... 32 RENEL Receivables and Payables ............................. 33 Targets for RENEL Accounts Receivable and Payable ................. 35 Actions to Resolve RENEL Arrears Situation ...................... 35 D. RENEL Investment Program and Financing .......................... 36 E. Financial Forecasts ......................................... 37 Financial Impact of Nuclear Power Generation on RENEL .............. 38 V. PROJECT JUSTIFICATION ...... ........... ....................... 39 A. Rationale for Bank Involvement ................................. 39 B. Generation Capacity ......................................... 39 C. Least-Cost Analysis ......................................... 39 D. Lignite to Imported Hard Coal Conversion .......................... 41 E. Rate of Return Analysis ...................................... 42 F. Other Benefits ............................................. 42 G. Sensitivity Analysis ......................................... 42 H. Sustainability ............................................. 43 I. Risks .................................................. 44 VI. AGREEMENTS REACHED AND RECOMMENDATIONS .................. 45 Agreements reached with GoR ................................ 45 Agreements reached with RENEL .............................. 46 Condition of Loan Effectiveness ............................... 47 Recommendation ........................................ 47 ANNEXES Annex 1.1 Proven Reserves of Commercial Energy . .48 Annex 1.2 Energy Price Movements and Comparison with Import Parity Prices ... . 49 Annex 2.1 RENEL's Organization Structure in 1995 ....... .. ............ 50 Annex 2.2 Power Generation Facilities ...... ...... .. ................ 51 Annex 2.3 The Cernavoda Nuclear Power Project ........ .. ............. 53 Annex 2.4 Structure of Electricity and Heat Prices ....... .. ............. 55 Annex 2.5 Daily Load Curves and Annual Load Duration Curve ..... ........ 58 Annex 2.6 Electric Energy and Power Balance (1989-2000) ..... .. .......... 60 Annex 2.7 Proposed RENEL Investment Program ....... .. ............. 62 Annex 2.8 Statement of Policies for the Power Sector ...... .. ............ 63 Annex 3.1 Detailed Description of Rehabilitation Candidates ..... .. ......... 69 Annex 3.2 Project Cost Estimates ....... ...... .. .................. 78 Annex 3.3 Project Implementation Plan ........... .. ................ 84 Annex 4.1 RENEL's Historical and Projected Cash Flows .... ..19.......... l Annex 5.1 Analysis of Project Justification .......... .. .............. 118 Annex 6.1 Documents in Project Files ............ .. ................ 132 MAP IBRD - 24989 This document is based on the findings of an appraisal mission which visited Romnania in October 1994, consisting of Messrs./Mmes. Sam O'Brien-Kumi (Task Manager), Arabela Aprahamian (Project Officer), Bernard Baratz (Principal Environmental Specialist), Hernan Garcia (Principal Power Engineer), Luiz Gazoni (Senior Power Engineer), Raghuveer Sharma (Senior Financial Analyst), and John Gunning (Thermal Plant Specialist-Consultant). Peer reviewers were Messrs. Roy Pepper (Principal Industrial Economist), Charles Woodruff (Senior Financial Analyst), Winston Hay (Senior Power Engineer), and Kashinath Sheorey (Senior Power Engineer). The division chief is Ricardo Halperin and the department director is Rachel Lomax. I ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT Loan and Project Summary Borrower and Beneficiary: Regia Autonoma de Electricitate (RENEL-Romanian Electricity Authority) Guarantor: Romania Loan Amount: US$110 million Lending Terms. Twenty years, including five years grace period at the Bank's standard variable rate of interest. Project Objectives and Description: The objectives of the proposed Project are to: (a) support the government's program to reform the power sector in accordance with its overall economic reform objectives; (b) meet the demand for electricity and thermal energy in an economic manner by rehabilitating thermal generation capacity; and (c) lay the foundation for the future development of the sector in an institutionally, economically, and environmentally sustainable manner. The proposed Project would comprise. (a) Power Sector Reform Program (about US$4.3 million). Under this component, technical assistance will be provided to the Government of Romania (GoR) through the Ministry of Industries (Mol) to: (i) carry out and implement a Study of Options of Long-Term Structure for the Power Sector; (ii) develop and implement an appropriate legal and regulatory framework for the sector to attract private investments; and (iii) establish a long-term least-cost power sector investment program, and carry out an electricity and thermal energy pricing study and implement its recommendations; (b) Thermal Plant Rehabilitation Program (about US$344.8 million). This component includes equipment, services and technical assistance to be provided to RENEL to: (i) rehabilitate about 1,445 MW of its existing thermal generation capacity; (ii) convert about 200 MW of its existing lignite-based thermal capacity to coal use; and (iii) reduce the pollution impact of thermal plants; and ii (c) Corporate Restructuring Program (about US$14.8 million). This component will provide technical assistance to RENEL to: (i) streamline the utility to focus on electricity and thermal energy generation, transmission, and distribution; (ii) create cost/profit centers for the generation plants and distribution subsidiaries; (iii) design and implement management systems (for operation and maintenance management, financial and cost accounting, human resources, materials management, and corporate planning system); (iv) improve metering, billing and collection system; (v) design hydropower plant, and transmission and distribution network rehabilitation programs; (vi) retire old and inefficient thermal units; and (vii) improve environmental management and occupational health and safety. Benefits and Risks: The quantifiable benefits arise from: (a) avoided cost of replacing about 1,445 MW of thermal capacity to be rehabilitated (which otherwise would have to be retired before year 2000); (b) lignite to hard coal conversion to curtail uneconomic transportation of lignite; (c) improvement in fuel use efficiency, and increased unit availability and production of electricity and thermal energy. The economic rate of return on the physical components is about 21 %. Cost savings through managerial and operational efficiency improvements are also expected. In addition, the Project will lead to improvement in the environment through reduction in air pollution. The main risk associated with the proposed Project relates to possible failure to move forward in the implementation of the sector reform and the corporate restructuring program . To address this, some important upfront actions have been taken. They include: (a) the appointment by GoR of a high level Inter- Ministerial Committee to oversee the Study of Options of Long- term Power Sector Structure, and the initiation of the Study; and (b) issuance of a Statement of Power Sector Policy which includes the Government's declaration to separate the nuclear power activities from RENEL into an independent public entity. In addition, a review would be conducted each year to assess progress in achieving the development objectives of the project and to consider need for further policy actions and/or project restructuring. A second concern is the possible inability of RENEL to mobilize the funding required for the project in a timely manner. As regards counterpart funding, this risk is mitigated by the upfront tariff increases already implemented and the measures already in place and to be instituted to eliminate arrears, as well as the measures to be implemented under the Project to improve billing and collection. Close monitoring of performance is planned. iii As regards cofinancing, GoR and RENEL have committed to secure co-financing by December 31, 1995 and there has been satisfactory progress in this regard. Project Cost and Financing: Project Cost (U$ Million) Local Foreign Total Sector Reforms 0.5 3.8 4.3 Thermal Plant Rehabilitation 120.8 224.0 344.8 Corporate Restructuring 1.6 13.2 14.8 Total 122.9 241.0 363.9 Financing Sources (US$ Million) Foreign Local US$ million Total RENEL 122.9 2.1 125.0 IBRD - 110.0 110.0 EIB - 23.1 23.1 EBRD - 54.4 54.4 EU-PHARE - 3.6 3.6 USAID - 2.9 2.9 OTHER - 44.9 44.9 TOTAL 122.9 241.0 363.9 Estimated Disbursements of Bank Loan (US$ Million) Bank FY 1996 1997 1998 1999 2000 Annual 20.0 40.0 30.0 18.0 2.0 Cumulative 20.0 60.0 90.0 108.0 110.0 Rate of Return: about 21% ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT I. MACROECONOMIC SETTING AND THE ENERGY SECTOR A. Macroeconomic Setting 1.1 Following the overthrow of the communist regime in December 1989, the new Government of Romania (GoR) initiated a reform program aimed at transforming Romania into a market economy. The reform program included price liberalization, redefinition of the role of the Government to give public enterprises more autonomy, the promotion of a commercial orientation in public enterprises by reclassifying them into "regies autonomes" (RAs) and "commercial companies" (CCs), with the intent that the latter be privatized; and an ongoing program of enterprise privatization. 1.2 This reform program was supported by the IMF with a Standby Arrangement (SA) in early 1991 and by the Bank with a Structural Adjustment Loan (SAL Loan No. 3481-RO), following the adoption of a stabilization program. Much of the reform agenda initiated to establish laws, institutions, and policies of the market economy is now complete, including the establishment of a two-tier system of banking, reform of the role of the Government and introduction of a modem tax system, the freeing of most prices and progress towards the elimination of subsidies, the adoption of a tariff-based trade regime with low tariffs, and the development of a framework for privatization of state-owned enterprises. There has been considerable expansion of private sector activity, including in agriculture. Presently the Bank is preparing a Financial and Enterprise Sector Adjustment Loan (FESAL), which is designed to assist the Government in its plans to reform the banking system, deepen the privatization process, accelerate the restructuring of government-owned enterprises and promote financial discipline. 1.3 A major turnaround of the economy occurred in 1993 with a positive 1 % growth in GDP, the first time since 1988. This was followed by about 3.4% growth in GDP in 1994. The main contributors to the growth in 1994 have been agriculture and the services sectors; industry also registered a modest growth. The share of industry has declined to 40% in 1994 from 54% in 1989, and that of agriculture has risen to about 24% from 19.6% in the 1980s, while trading activities have almost doubled since 1989. In 1996-2000, GDP is projected to grow at a trend rate of about 5% per year. Agriculture and services are expected to be the leading growth sectors. Industry is expected to expand in the light manufacturing and export oriented branches, and to contract in the uncompetitive metallurgical and chemical branches. As a result of the structural changes, the intensity of energy use in the economy is expected to decline. B. The Energy Sector Introduction 1.4 The energy sector has been shaped by the past industrialization policies. It is a vital sector of the economy. It accounted for 46% of total industrial sector investment in 1990, and for nearly 100% in 1992-1994 due to the nuclear power development program (see Annex 2.3). As a result of 2 the high energy intensity of the economy and the continued declines in known reserves of oil and gas, energy imports absorbed about 26% of export revenues in 1993 despite a depressed level of demand. Energy Resources 1.5 Romania has considerable reserves of primary energy (natural gas, lignite and coal, oil and hydropower potential). Reserves of natural gas are about 510 million tons of oil equivalent (TOE). Proven reserves of lignite are about 600 million TOE; hard coal about 330 million TOE; and oil about 200 million TOE. The total hydropower potential is about 40 terawatt-hours (TWh) per year, of which 12 TWh per year is already developed. Uranium deposits exist but the level of reserves is not published. However, the government's nuclear power development program is based on using it as the main source of fuel. Oil shale and geothermal reserves are known to exist, but their extent is unknown. Renewable energy resources in bio-mass and fuel wood are abundant, while geothermal, wind and solar energy are of relatively less significance. Levels of reserves of commercial energy resources are provided in Annex 1. 1. Institutional Setting 1.6 As part of the economic reform measures introduced in 1990, the energy sector was reorganized by establishing separate autonomous state enterprises, Regies Autonomes (RAs), for the production and supply of energy products and commercial companies (CCs) for support services and activities. This enabled the Government to separate policy and regulation from operational functions, and to bring about accountability and commercial orientation to the energy sector. The RAs and CCs have been formed out of the departments of the former ministries. RAs are state holding companies for enterprises considered strategic by the Government of Romania such as electric power, oil, natural gas, lignite, coal, etc. The CCs are joint stock companies which have been established under the commercial law. 1.7 Sector Organization: The sector is still predominantly state-owned under the supervisory responsibility of the Ministry of Industries (Mol), which formulates policy and strategy. Operational responsibility rests with the RAs and the CCs. The main RAs and CCs are: (a) Romanian Electricity Authority (RENEL), which is responsible for production, transmission and distribution of electricity, as well as production and bulk transmission of heat; (b) Regie Autonome for Natural Gas (ROMGAZ), which is responsible for the exploration, production, transmission, and distribution of natural gas; (c) Regie Autonome for Petroleum (PETROM), which is responsible for exploration, production, and supply of crude oil, transmission of associated natural gas to ROMGAZ; (d) Regie Autonome for Lignite (RAL), which is responsible for the production and marketing of lignite; (e) Regie Autonome for Hard Coal (RAH), which is responsible for the production and marketing of hard coal; 3 (f) Romanian Refinery Company (RAFIROM) is a holding company of the oil refineries; it is responsible for the allocation of crude oil to the refineries, management and coordination of refinery activities; and (g) Romanian Petroleum Distribution Company (PECO), which is responsible for the distribution and retail sale of petroleum products. Energy Pricing 1.8 Policy and Price Adjustments: After the 1989 revolution, in line with its policy of price liberalization under the macroeconomic reform program, the Government initiated actions to raise energy prices to import parity levels. As a result, within a period of about two years, significant real increases of the order of 10-15 fold were made to most energy prices, except natural gas and household fuels. The traditional non-tradeables, lignite and low grade local coal, were priced at parity with tradeable hard coal on a heat equivalent basis. Under the SAL that was approved in June 1992, the GoR agreed that: (a) crude oil, and petroleum product prices will be maintained at international levels through periodic adjustments for exchange rate and international price changes; (b) lignite, local coal, electricity and thermal energy prices will be maintained in real terms through periodic adjustments for exchange rate changes; (c) the price of natural gas to non-household consumers will be raised monthly by $4/thousand cubic meters (103m3) from about US$60/103m3 until parity with the FOB Mediterranean price of fuel oil (1 % sulphur content) on heat equivalent basis is achieved; and (d) the gradual elimination of the subsidies to households for energy. Despite the persistent high inflation, the conditionalities were substantially met by the Government, first in February 1993 when all subsidies to households on energy, with the exception of thermal energy and natural gas, were eliminated and later in April 1994, which enabled the release of the second tranche of the SAL. Prices were adjusted to import parity levels in June 1995 in fulfillment of the requirement under the SAL. Table 1.1 compares prevailing prices with import parity. Annex 1.2 shows the movements in energy prices since November 1990. A separate discussion of electricity and thermal energy prices is provided in paragraphs 2.20-2.25. 4 Table 1.1: Comparison of Domestic Energy Prices with Import Parity* (June 1995) As % Of: S:; ENERGY PRODUCTS US$"' Imonrt Parivy PriCe Crude Oil (Price to Refineries) Domestic 93.0 95 Imported 130.0 100 Petroleum Products (Retail price/ton) Premium Gasoline 410.0 203 Regular Gasoline 381.0 191 Diesel 263.0 156 Fuel Oil (i) from domestic crude price/ton (1% sulphur) 144.0 121 (ii) from imported crude price /ton (3.5% sulphur) 117.0 105 LPG (Households) 273.0 145 Natural Gas (OOOm3) (i) Industry 71.6 95 (ii) Households 20.0 26 Coal and Lignite Ex-mine (i) Lignite pricelton ** 19.0 166 (ii) Thermal Coal price/ton** 26.0 121 Coke 120.0 100 Electricity Price (kWh) IX Average 0.050 100 High Voltage 0.047 93 Medium Voltage 0.055 105 Low Voltage i. Households 0.024 48 ii. Others 0.066 133 Thermal Energy (Gigacalories) *** Industry 23.0 160 Household 7.3 52 * Using an exchange rate of 1,900 Lei/$. All prices (except household prices) include 18% value added tax (VAT). ** Based on FOB prices in Western Europe of internationally traded hard coal,adjusted for heating value. *** As % of marginal fuel cost. Electricity price is compared to US cents 5/kWh, representing the import price during the winter season. Sector Issues, Government Policy and Strategy 1.9 Issues: The main issues in the energy sector are. (a) high inefficiency of energy use due to old and inefficient technologies, and to the dilapidated state of assets, compounded by poor operations and maintenance; 5 (b) excessive vertical integration of enterprises, absence of a competitive environment, and inadequate regulatory systems; (c) lack of economic criteria in planning and investment selection; (d) over-employment, and operational inefficiencies; (e) weak financial position of sector entities, and the accumulation of inter-enterprise arrears; and (f) environmental pollution. 1.10 Government Strategy: The government strategy to address these issues has been to: (i) introduce a sector reorganization to separate policy and strategy from operational functions, followed by present plans to allow for the participation of public and private independent operators in a competitive environment; (ii) implement energy price reforms to align prices with economic costs; (iii) critically screen the energy sector investment program to limit it to the highest priority investments; and (iv) develop a program for the rehabilitation of the existing energy supply infrastructure. The Governrent should now develop long-term programs for fundamental restructuring of the sector. This would involve the implementation of further policy and institutional reforms. 1.11 The short and medium term measures are aimed at conservation in primary energy use, reduction in losses, improvement in the quantity and reliability of energy supplies to final consumers, and reducing the sector's pollution impact on the environment. The long-term measures would bring about the break-up of sector monopolies, downsize enterprises and operations, and introduce competition with the appropriate legal and regulatory systems to enhance the participation of independent operators, both public and private, in the sector. In addition, they are expected to bring about improvements in corporate governance, and institute modern management, accounting and financial systems. Finally, ongoing privatization programs in the industrial sector and production shifts away from heavy industry, in response to market forces, should result in progressive reduction in the energy intensity of the economy and increased end-use efficiency. 1.12 The implementation of the strategy by the Government has been hampered by lack of consensus on the proposed policy changes, and limited local expertise, especially regarding management and financial systems. 1.13 Bank Assistance Strategy: The Bank's Country Assistance Strategy (CAS) for Romania is presented in the Memorandum of the President (MOP) dated March 14, 1994 on the Petroleum Sector Rehabilitation Project. It is aimed at supporting the GoR to achieve macroeconomic stability and implement systemic reforms, particularly in creating the institutions fundamental to the operation of the market economy. This includes establishing property rights, privatization, tax and tariff reforms, establishing a modern financial system, strengthening the social safety net, developing legal institutions, and improving public administration, continuing the process of sectoral restructuring and adjustment in the industrial, agricultural and energy sectors; and enhancing long-term growth and development prospects through projects in education, social welfare, and infrastructure. 6 1.14 Within the framework of the CAS, the Bank's assistance to the energy sector is geared to promote fundamental reforms designed to support its rehabilitation, improve its efficiency, and eventually attract private investments to the sector. Loan 3723-RO approved by the Bank in 1994 is aimed at providing such support in the upstream petroleum sector. The proposed Power Sector Rehabilitation and Modernization Project will be directed to the power sector, to assist the Government to develop and implement a sound policy and strategy to achieve these objectives. Future lending to the power sector is planned, and would be contingent upon satisfactory progress in implementing the policy reforms to be initiated under the proposed Project. 7 II. THE POWER SECTOR A. Institutional Setting 2.1 The Ministry of Industries (Mol), created in 1990, has overall responsibility for the power sector. Mol is divided into 4 departments each headed by a Secretary of State, reporting to the Minister of Industries. The Secretary of State for Energy has the principal role in setting the policies for the power sector, (in addition to petroleum and other primary energy) while the Secretaries of State for Restructuring, Strategy and Reform make sporadic interventions. The Secretary of State for Energy has under him a director general for electric power, oil and gas, who is responsible for policy and strategy formulation, and for regulation of the sector. 2.2 Other GoR Ministries involved in the power sector are: (a) the Ministry of Finance (MoF) which, through its Pricing Office, sets electricity prices, and is represented on the Administrative Councils of each of the RAs; (b) the Ministry of Water Resources, Forestry and Environment Protection (MAPPM), which has a role in controlling environmental pollution in the country; and (c) the Ministry of Labor and Social Protection (MMPS), which is concerned with worker health and safety issues, and with the social impact of any significant staff reductions resulting from reorganizations; and (d) GoR's Council for Coordination, Strategy and Economic Reform, (CCSER) which is responsible for economic restructuring. 2.3 Responsibility for public electricity and thermal energy generation, transmission, and distribution is with RENEL. RENEL was created in 1990 from the former Ministry of Electrical Energy in accordance with Law 15/90. RENEL inherited the traditional role of production and supply of electricity and thermal energy, as well as detailed engineering design and construction, foreign trade, research and development (R&D), and nuclear power development functions. By now, some of the construction and foreign trade departments have been spun off into independent commercial companies. At the same time, the nuclear fuel processing enterprise, ROMAG, and the enterprise producing heavy water for the Cernavoda nuclear power plant were fully integrated into RENEL. In addition to RENEL, some large state-owned industrial plants also own co-generation plants and sell electricity and thermal energy directly to other industries, and to municipalities. RENEL Organization and Management 2.4 In line with the recommendations of a corporate restructuring study carried out with the help of foreign consultants (financed by EU-PHARE), RENEL was reorganized in late 1992 to give it a corporate form. Corporate policy-making is vested in a eleven member Board of Administration (Board of Directors), of which the President of RENEL is the Chairman. In addition, the Board of Administration comprises representatives of the Government, the financial institutions, the fuel suppliers, and consumers. Day-to-day affairs are the responsibility of RENEL Management, comprising the President (designated as Director General) and five Deputy-Director Generals - one each for: generation, transmission and distribution, nuclear power group, strategy and development, finance, and human resources. Structurally, RENEL comprises the headquarters, thirty-six branches, (each managing a power station), the Cernavoda nuclear power subsidiary, the fuel and heavy water processing subsidiaries, and forty-two electricity transmission and distribution subsidiaries divided along the lines of the forty-two administrative Judets (Counties). The organization structure of RENEL is shown in Annex 2.1. 8 2.5 The reorganization of RENEL separates, in theory, the corporate policy-making from company management and also from operations. However, in practice, there is little separation between corporate policy-making and management, because a number of vice-presidents are also members of the Board of Administration. In addition, the present policy attempts to centralize decision making. This is not desirable since RENEL is too large to be run efficiently in a centralized way. Moreover, in a number of important policy matters RENEL still depends on decisions taken at the government level. However, the operational units (the thirty-six generation plants and forty-two transmission and distribution units), which are called subsidiaries, are profit centers and are required to maintain records accordingly and this provides a basis to promote decentralization. RENEL Personnel and Staffing 2.6 Since 1990, RENEL has been implementing a program of gradual reduction in its labor force. By end-1994, a total reduction of about 48% (from about 200,000 to about 105,000) in the labor force had been achieved, mainly through the separation of some of the construction and repair subsidiaries into independent public commercial entities (para. 2.4), but also through reductions in unskilled labor. By end-1995 the labor force is expected to be further reduced to about 99,700. 2.7 Compared to international norms, RENEL is still overstaffed. The ratio of installed power capacity (MW) per thousand employees in RENEL is 198 (compared, for example, to 308 in Turkey, 603 in Poland or 770 in EdF-France). The overstaffing is mainly in the labor category (skilled and unskilled) which account for 75 % of the staff. Many of these staff (more than 50%) are engaged in support activities, such as detailed engineering and design, research and development, repairs and construction works and manufacturing which are normally not part of a power utility. Institutional Reform Measures 2.8 GoR and RENEL have decided to address the above structural and overstaffing problems in RENEL by implementing a corporate restructuring program. The program, to be implemented under the proposed Project, would involve: (a) separating nuclear activities into a different entity, reporting directly to Mol; (b) retiring old and inefficient units to reduce operating costs and working capital; (c) spinning off of construction, repair, and manufacturing subsidiaries and the engineering and technical institutes into independent commercial companies; (d) creating cost/profit centers based on viability and to correspond to the various operations (generation, transmission and distribution) in each of the generation plants (or a group of plants to ensure viability), a separate cost/profit center for the transmission network, and several cost/profit centers for the distribution activities; (e) designing and implementing a long-term Human Resources plan, including programs to reduce excess staff; (f) implementing management tools, such as financial accounting, cost accounting, materials management, corporate budgeting planning systems; and 9 (g) adopting financial performance criteria, first at the headouarters level and gradually at the cost/profit center level. B. Power System Operations and Performance Existing Facilities 2.9 Romania's installed power generating capacity is 21,808 MW, of which RENEL's total installed power generating capacity is 20,281 MW (93%). The remaining generating capacity is owned by industries, municipalities and independent rural cooperatives. In the RENEL system, hydropower capacity accounts for about 28%; lignite and coal-fired for about 42%; and oil and gas- fired for about 30%. Approximately 38% of RENEL installed thermal capacity (5,080 MW out of 14,829 MW) is in cogeneration, i.e. combined heat and power (CHP) plants. The structure of installed power generating facilities in the country is provided in Annex 2.2. 2.10 Romania has extensive interconnected power transmission and distribution networks of total length of about 592,000 kin, and total transformer capacity of about 172,000 MVA. The networks encompass the entire country such that accessibility to electricity is nearly 100%. RENEL operates about 74% of the network, comprising the following transmission voltages - 750 kV, 400 kV, 220 kV, and 110 kV; and the subtransmission voltage of 60 kV; and about 50% of the distribution network in the 20 kV, 10 kV, 6 kV, 1 kV, and 400 kV volts. The rest of the distribution network is operated by industrial plants and rural cooperatives in their designated supply areas. 2.11 RENEL operates five regional load dispatching centers, including the national center in Bucharest for management of the system load, and for international electricity exchanges. The Romania transmission network is linked by tie-lines with Ukraine at 750 kV and 400 kV; two lines at 1 10 kV with Moldova; one 220 kV line with Hungary; one 750 kV, two 400 kV, and one 220 kV lines with Bulgaria; and one 400 kV, and four 110 kV lines with the former Yugoslavia. 2.12 A significant characteristic of Romania's power system is its high base-load requirements, primarily due to the large industrial consumption. In 1994, the base load requirement (in winter) amounted to 78% of the system gross peak demand of 8,600 MW. The co-generation and the other thermal units are operated to meet base load requirements, and the hydropower units, complemented by imports are used to meet peaking requirements. Although the installed capacity is more than twice the peak demand, RENEL is unable to meet its peak and has had to resort to imports of electricity (Table 2.1). The constraints in meeting demand are primarily due to operational problems, which are discussed below. Generation 2.13 Thermal Plants: RENEL is barely able to obtain about 6,000 MW of dependable continuous electric power output during the winter season from its installed thermal capacity of 14,602 MW due to the poor operating state of the thermal plants, which is mainly attributable to: (a) plant design and construction deficiencies, including use of poor grade construction materials; (b) inadequate maintenance; (c) use of low grade fuels, which often do not meet plant design specifications; and (d) improper operations and management practices. 10 2.14 As a consequence of the above, most thermal plants, especially the lignite fired units, suffer from: (a) frequent and prolonged outages resulting in low availability rates (of about 30% on the average); (b) low fuel use efficiencies ranging between 18% and 24%, compared to design levels of 28%-34% (about 46% for the co-generating units); (c) lower power output than rated design capacity, with capacity factors (utilization of available capacity) of about 32%, which is very low; and (d) degraded and poor performing pollution control equipment. If the current operation and maintenance practices continue, estimates indicate that the dependable firm thermal capacity would decline to about 3,500 MW by the year 2000. 2.15 Hydropower Plants: RENEL's hydropower power plants are in a slightly better operating condition than the thermal plants. However, the hydropower plants are not operated in accordance with an optimal regime, because thermal generation is cut back in autumn (to conserve fuel for the winter) and the storage reservoirs are discharged during these times (prior to the winter season) to also meet the base load. This renders the hydroplants incapable of meeting the peaking requirements during winter. A number of the main plants/units, some of which have been in operation for the past 20 years, need urgent rehabilitation. 2.16 Nuclear Power: The first unit of a 5x700 MW nuclear power station at Cernavoda is planned for commissioning towards the end of 1995, after many delays. The continuation of investments in additional units, for which some of the infrastructure has been constructed, is subject to economic justification. The technology is based on CANDU-6 nuclear reactor of Canadian design, using natural uranium as fuel and heavy water as a coolant and moderator (which would be supplied locally), and a General Electric Turbogenerator. Engineering services and project management are being provided by a consortium of Atomic Energy of Canada (AECL), and Ansaldo-Impianti of Italy, which will also continue with operational management services for 18 months after commissioning to train Romanian staff in the operation of the station. The International Atomic Energy Agency (IAEA) has conducted separate inspections of the construction of Unit 1, and has found the works satisfactory. A post-commissioning inspection by IAEA is expected in 1996. Further discussion is provided in Annex 2.3. Transmission and Distribution Netivorks 2.17 The power networks also suffer from inadequate maintenance due to lack of spares and aged equipment, especially, at the medium and low voltage levels. RENEL transmission system has adequate carrying capacity for the foreseeable future, but several areas need upgrading and reinforcement. The load dispatching system equipment is old (1970 vintage) and would cease to be functional in the next five years. RENEL distribution network suffers from high technical losses (about 15%) due to overloading of substations and lines, as they were not designed to meet recent increases in consumption at the low voltage level. In addition, inadequate metering, billing and collection practices are causing additional (non-technical) losses. Technical and Operational Efficiency Improvement Measures 2.18 RENEL's and GoR's immediate priority should be the improvement of the technical and operational efficiency of the existing power system. In this regard, RENEL should: (a) undertake economic rehabilitation of the existing thermal power plants, reduce their pollution impact and implement measures to improve technical operations and maintenance; 11 (b) accelerate the mothballing and retirement of inefficient generation units (of about 3,000 MW by year 2000), thereby reducing operating costs (including personnel) and working capital (fuel inventories and spares); (c) undertake measures to ensure the adequacy and quality of its fuel supplies, which would require building the necessary handling and storage infrastructure and develop arrangements for advance procurement of fuels to build up stocks for the winter season; (d) design and implement a rehabilitation program for the hydro electric power plants; and (e) design and implement rehabilitation and reinforcement programs for the transmission and distribution networks, and modernize the load dispatching system. In the medium term, it is expected that the GoR will implement a competitive environment with private sector participation in generation, which would provide the incentives for further efficiency improvements. 2.19 The physical components of the proposed Project are aimed at financing the rehabilitation of RENEL's thermal plants; and at helping the design of rehabilitation programs for hydropower plants, and transmission and distribution networks. GoR has already agreed with the Bank to undertake a Fuel Options Policy Study under the Petroleum Sector Rehabilitation Project (Loan 3723-RO), which would provide the inputs to develop an optimal strategy for meeting RENEL's fuel needs. C. Electricity and Thermal Energy Pricing Electricity Pricing 2.20 As part of the price liberalization program, and in accordance with the agreement with the Bank under the SAL (para 1.8), since 1990 electricity prices have been set and maintained in dollar terms to reflect the cost of imported electricity, as a proxy for the opportunity cost of supply from the RENEL system. However, there have been long periods of decline in real electricity price levels, which necessitated periodic large increases to bring the tariffs back up to the targeted levels. RENEL's tariff structure does distinguish between various voltage levels, and provides for time-of- day and for seasonal tariffs. RENEL also applies a demand charge and a separate energy charge for customers (mainly industries) where a specific power level is contracted by the customers. The tariff structure is provided in Annex 2.4. 2.21 RENEL tariff regime has the following drawbacks: (a) residential customers pay only 32% of the price of other low voltage customers, and about 46% of the price to industrial customers, even though the cost of supply to the residential customers is the highest; (b) RENEL's cost-of-supply information, either in financial or economic terms, is very weak and unreliable. Consequently, it is not possible to: (i) allocate costs between heat supply and electricity supply; (ii) distinguish between generation, transmission and distribution costs; or (iii) provide for the right categorization by customer characteristics, especially at the medium and low voltage levels; 12 (c) RENEL lacks adequate metering equipment to ensure the accurate application of demand and energy charges in accordance with the tariff structure; and (e) as a consequence of economic restructuring, RENEL's load curve is assuming a double hump shape - some industries are no longer running multiple shifts and as a result the morning peaks have become high relative to the high evenings peaks, which have also become sharper. However, RENEL is applying its peak tariffs (as in the old days) only in the evening times. To address the issue under (a), at negotiations, it was agreed that GoR will progressively reduce the level of cross-subsidization of electricity price paid by households over a period of four years from the date of this Agreement, so as to ensure that by December 31, 1999, all such subsidies shall have been eliminated (para 6.2 p9). 2.22 In March 1994, GoR reviewed its electricity pricing policy with the Bank, in the context of the release of SAL's second tranche. As a result of the review, agreement was reached with the Bank to set the prices to reflect an average of US$50/MWh equivalent (including 18% VAT). In addition, GoR agreed to: (a) prevent deterioration in the average level, by automatically adjusting the prices to an average of US$50/MWh when, on the basis of the average exchange rate prevailing in the preceding month, the average price had fallen to or below US$46.25/MWh equivalent; and (b) review and make adjustments, as necessary to the electricity prices of US$50/MWh, whenever the international prices of fuels used by to RENEL are changed. Over time, the agreement under SAL has been found to cause some problems. On the one hand, it has some times required price adjustments during the winter season, which caused a negative social reaction. In addition, since the formula required maintaining the price in dollar terms, from time to time concerns were raised about the management of the exchange rate during the winter season, during which the resistance to price adjustments was perceived to be stronger. The Bank consulted the Fund on these issues and to overcome them, at negotiation the Government agreed to maintain electricity prices corresponding on average to not less than the equivalent of US$50/MWh (including VAT), through periodic adjustments to the consumer electricity prices in accordance with a timetable acceptable to the Bank (para.6.2 (g)). It was further agreed that the first such increase, after the one already implemented in June 1995, will take place in April 1996 followed by another one in November 1996. Thereafter the Government will adjust tariffs as required twice a year, in April and in August. These dates have been selected to facilitate the timing of the increases. Furthermore, in order to ensure that RENEL's finances will not be negatively affected, RENEL and the Govermnent have also agreed to the financial covenants which are discussed in para. 4.22, which provide for further tariff increases if needed. At present, the Government is in compliance with its commitments. Furthermore, the Goverment has agreed to adjust pursuant to guidelines acceptable to the Bank the consumer electricity prices if changes to the level prevailing on the date immediately preceding the adjustment of consumer electricity prices shall have occurred in the international market prices of the main fuels (coal, natural gas, and fuel oil) used by RENEL for power generation (para 6.2 (g)). Presently the tariff covenants are in compliance; the latest increase of 15% took place in June 1995. 13 2.23 In addition to maintaining the levels of electricity prices as above, GoR will carry out an Electricity and Thermal Energy Pricing Study with the help of experienced consultants, and implement the study's recommendations to provide a sound economic basis for setting electricity and thernal energy prices that would promote efficiency, ensure sector viability, provide incentives for the participation of private operators in the sector and take account of social and equity concerns. At negotiations, the GoR agreed that (i) by September 30, 1995, or such later date as the Bank may agree, it will appoint consultants, whose qualifications and terms of reference shall be satisfactory to the Bank, to carry out an electricity and thermal energy pricing study; (ii) promptly upon its completion, discuss with the Bank the findings and the recommendations of the study; and (iii) according to a timetable acceptable to the Bank provide to the Bank a satisfactory program for the implementation of the actions agreed as a result of said study and discussions with the Bank (para 6.2 (h)). This study should be completed by September 1998, since it must draw upon the findings of the least-cost power generation development study that is also to be carried out under the project (para. 2.37 (b)). These covenants are to be complemented by a financial covenant that requires adjustment of the average tariff level beyond the level set under SAL if needed to achieve a self-financing ratio of not less than 30% of RENEL's capital investments (para 4.22). At present, the average tariff level required under SAL is adequate to achieve the degree of self-financing proposed above, and the analysis of RENEL financial prospects indicates that it would allow for an acceptable financial evolution (paras. 4.19 - 4.22). Thernal Energy Pricing 2.24 RENEL sells thermal energy at bulk prices to the various municipalities and large industrial consumers. Retail prices are set by the Government in collaboration with the municipalities. Since 1990, thermal energy prices have been increased by about 20 fold to non-residential consumers, and about 8 fold to residential consumers. Although, the actual cost of service is unknown, the price to industrial consumers does cover variable operating costs, including fuel. Price to residential customers is significantly below cost of service, necessitating Government budget subsidies which are paid to the municipal heat distribution entities. The current price to industrial and commercial customers is about US$19/gigacalorie, including VAT, compared to US$7.3/gigacalorie to residential customers, who are exempted from VAT. 2.25 The structure of bulk heat supply prices is relatively simple (see Annex 2.4). It comprises a maximum demand charge based on the delivered pressure, and energy charges. However, due to lack of appropriate metering, sales are billed on energy. A major issue affecting heat pricing is the allocation of production cost between electricity and heat from co-generating sources. In addition, the cost structure of transmission and distribution is not known. Furthermore, there is no distinction in prices to reflect cost of supply by season, even though there are significant differences in seasonal supply costs. D. Demand for Electricity and Heat Past Electricity Consumption and its Characteristics 2.26 Intensity of electricity use is very high compared to other countries, both because of the high proportion of industrial consumption, and the inefficient use by industry. Consumption peaked in 1989 at 71.4 TWh following about 2.3% average annual growth rate since the early 1980s, but has since declined to about 43 TWh in 1994. Until 1989, industry accounted for 75-78% of total 14 consumption due to the priority given to industry in the allocation of electricity, households accounted for 6-8%, and the remainder went to other sectors, i.e agriculture, transport and communications, and services. However, by 1994, due to the structural changes in the economy that resulted in a decline in industrial output, the lifting of restrictions on household use, and the steep price increases to industry, industry's share in consumption declined to about 64%, and household consumption rose to about 15% of total consumption. 2.27 Annual maximum power demand ranged between 10 TW and 11.3 TW in the 1980s, but declined to about 7.9 TW in 1994, for the reasons given above. The demand profile shows a high load factor (ratio of average to peak energy), with annual load factor of about 75%, and daily load factors on winter work days of nearly 90%, indicative of the dominance of industry in consumption. Table 2.1 summarizes past supply and consumption trends. The characteristics of the demand are illustrated by the daily load curves and the annual load duration curve in Annex 2.5. Table 2.1: Electricity Supply and Consumption, 1975-94 (TWh) 1975 1980 1985 1989 1990 199 1993 1994 2 Gross Generation 53.7 67.5 71.8 75.8 60.9 53.7 55.4 53.8 Imports 0.5 0.5 3.3 7.8 9.5 4.4 1.9 1.2 Exports (-) 3.0 0.05 - - - - - - Total Available 51.2 67.9 75.1 83.6 70.4 58.1 57.3 55.0 Losses 8.4 10.0 10.4 12.3 13.5 11.4 11.8 11.7 Net Consumption 42.8 57.9 64.6 71.4 56.9 46.7 45.5 43.3 Industry 32.7 43.7 49.3 55.6 41.3 30.1 29.3 29.4 Residential 3.7 4.9 4.8 4.3 5.3 7.6 6.9 6.6 Others 6.4 9.3 10.5 11.5 10.3 9.0 9.3 7.3 Max. Demand-Net (TW) 8.1 10.0 10.7 11.3 10.7 9.5 8.0 7.9 System Annual Load Factor (%) 72.0 77.5 80.0 88.0 79.0 75.0 74.0 3.0 Forecast Electricity Demand 2.28 The Bank has prepared forecasts of demand for electricity up to 2005, which are based on the assumption of declining electricity use intensity in the productive sectors due to the changing structure of the economy. For households, the forecasts take into account the effects of the lifting of the limits on use of electricity by households, the increasing use of electricity for space heating due to the failures of the district heating system, and the effects of expected increases in personal incomes with return to steady economic growth as from 1996 onwards, as well as the expected increases in household tariffs. The demand forecasts are tentative, since the economy is still in the midst of a transformation process, and the structure that will emerge is only starting to take shape. 15 2.29 The net effect of the above is that future electricity demand is unlikely to exceed the 1990 levels until 2003-2005. Table 2.2 shows the electricity demand forecasts. Annex 2.6 provides past and forecast electric energy and power balances. Table 2.2: Summary Results of Electricity Demand Forecasts Estimated Forecast 1990 1995 2000 Industry 41.3 29.4 29.0 Residential 5.3 7.0 8.7 Others 10.3 8.1 12.3 Total Net Consumption (TWh) 56.9 44.5 50.0 Gross Generation + Net Imports (TWh) 70.4 58.1 61.9 Maximum Demand (TW) 10.7 8.2 9.1 System Annual Load Factor (%) 79.0 73.0 71.0 Past Supply and Consumption of Thermal Energy 2.30 In 1980-90, total heat production from thermal plants ranged between 150-170 thousand teracalories p.a. depending on the severity of the winter season. RENEL accounted for about 40% of total supply from its CHP and hot water boiler plants. The rest was provided by industrial self- generation, and by peaking hot water boilers operated by the municipalities. RENEL sells process steam and thermal energy at bulk transmission to large industries, and to the municipal distributing companies, who operate distribution network in their respective municipalities. 2.31 Forecast Demand for Thermal Energy: Similar assumptions as for electricity demand are made in forecasting the future demand for heat by the productive sectors. Demand by households takes into account the combined effects of increased urbanization and new housing developments. Similarly, projected demand is not expected to reach the 1990 level until after 2005. Forecasts, summarized in Table 2.3, include losses in the primary and secondary distribution systems. Table 2.3. Summary Forecast Thermal Energy Demand in Thousand Tera-Calories (TCal) Actual Estimated Forecast Total Production 1989 1990 1995 2000 2005 of which: 168 155 124 134 149 RENEL 65 62 48 55 67 Municipalities and Autoproducers 103 93 76 79 82 16 E. Power Sector Investment Mol's Investment Program 2.32 The sector investment program for the period 1995-2000 originally prepared by Mol and RENEL envisaged a total expenditure over the period of about US$7.9 billion (January 1994 prices), including about US$2.2 billion for the nuclear power development program, which is not realistic. Since the above amount is not economically justified, and furthermore cannot be funded, the GoR has: (a) scaled down the proposed sector investment program in conventional power facilities drastically (to about US$2.32 billion (Annex 2.7)), and agreed at negotiations to establish priorities on the basis of a least-cost investment program to be prepared with the help of consultants (para 2.37 (b)); (b) decided that RENEL's medium term investments will be limited to rehabilitation investments (generation, thermal and hydro; transmission and distribution networks; load dispatching); and environmental improvement (new ash disposal systems and deposits, land reclamation, and monitoring), and the completion of high priority unfinished hydro and the thermal power projects at advanced stages of completion, since at the current tariff levels RENEL can only invest about US$300 million per year on average and still maintain a reasonably satisfactory financial position (para 4.22); (c) agreed to meet the remaining local cost to complete Unit 1 of Cernavoda, the Nuclear Power Station, as well as moderate expenditures needed to preserve the works already completed on Units 2-5, from the state budget; (d) agreed not to undertake new investments for Units 2-5 of the Cernavoda Nuclear Power Station until their justification is established on the basis of a system-wide least-cost analysis mentioned in (a) above; (e) agreed to continue to implement measures underway for the future interconnection with the Western European Power Interconnection System (UCPTE), and to improve the ties with neighboring countries to enhance Romania's participation in a wider regional power market, which would provide for greater security and reliability of supply to meet the demand in the most economic manner; and (f) agreed to implement measures to reduce the environmental impact of the power sector. Agreement on the power sector's medium-term investment program has been reached, and an annual consultation with the Bank on the program will ensure that future changes are justified and financially viable (para 4.18). For the longer term, the proposed least-cost development program will serve as a basis for investment decision making (para 2.37 (b)). 17 F. Private Sector Development 2.33 The Government recognizes that in order to implement the medium term investment program, and for the longer term needs of the sector, substantial investments will be necessary. Hence, given the constraints on public finances, there is no option but to attract private investments, including foreign investments, to the sector. This approach should also spur efficiency improvements through competitive pressure. Therefore, the GoR plans to implement reforms to the sector organization and its legal and regulatory framework to create conditions for competition, and the participation of private operators. In this regard, GoR has agreed to: (a) carry out a study of options of the long-term structure for the power sector (the Options Study) with the assistance of consultants (para. 2.37 (c)). The Options Study, which is being funded by the United States Agency for International Development (USAID), has already been launched, it would be completed by September 1996 and its implementation would begin immediately thereafter. Terms of reference for the Options Study were agreed at negotiations; and (b) reform the legal and regulatory framework for the sector; for this purpose, the GoR has been preparing a draft electricity law, which it will complete following its decision on the long-term structure of the power sector, and thereafter submit to Parliament for its consideration no later than December 31, 1996. The law is expected to provide for competition in the sector, demonopolization, transparent regulations, and conditions for private sector participation in power activities. In addition, the law is expected to: (i) provide for creation of an independent national transmission company that would deal evenhandedly with publicly-owned, as well as private generators and distributors; (ii) permit a wide range of schemes for private sector participation, both local and foreign in power generation (self producers, cogenerators, and independent producers) and eventually in distribution; (iii) permit partial or total privatization of government-owned power generation and distribution facilities; (iv) provide for the creation of an independent regulatory body, and the principles of its operation; and (v) define principles and procedures for setting electricity prices and for transmission wheeling charges, when these would be applicable, and for the development of power purchasing agreements. G. The Bank's Role and Strategy The Bank's Role 2.34 The role of the Bank in the Romania power sector dates from July 1974 when the first loan of US$60 million equivalent (Loan 1028-RO) was made to the Government for the First Turceni Power Project for the construction 4x330 MW lignite-fired power station and associated transmission facilities. This was followed by three additional loans for the construction of the Mare-Retezat Hydropower Stations, the Second Turceni Power Project of 4x330 MW, and a mix of thermal and hydropower plants in the Government's 1980-83 power development investment program. By 1985 when the Government decided to repay all Bank loans, Bank financial assistance to the sector had reached US$300 million equivalent. 18 2.35 The Bank has been working closely with the Romanian authorities in the identification of issues, delineation of the strategy and in the analytical work to identify the policy choices that the Government needs to adopt. The Bank has also assisted in the preparation of the terms of reference for the various studies (for example: for electricity and thermal energy pricing, least-cost investment program and the Options Study), as well as in the preparation of a draft electricity law. 2.36 The strategic and policy choices discussed in the previous paragraphs represent, in the Bank's view, a comprehensive set of actions to address the critical issues faced in the power sector. However, the approval of the set of actions and, even more importantly, their implementation requires the involvement of other GoR agencies, such as the Ministries of Finance, Industries, Justice, Environment, and Social Protection. The Government has confirmed its long-term policy objectives for the power sector in a Statement of Power Sector Policy (Annex 2.8). A strategy document to implement the Government's policies for the sector has also been furnished to the Bank. 2.37 Furthermore, in order to ensure that the development objectives of the proposed Project are achieved in a timely manner, the GoR has agreed to: (a) i) promptly after the commissioning of the first unit of the Cernavoda nuclear power station, inform the Bank of the commission of said unit; (ii) over a period of 18 months after the commissioning of said unit, take all necessary measures, agreeable to the Bank, to separate all nuclear power activities from the power activities of the Borrower; and (iii) no later than 20 months after the commissioning of said unit, establish an independent public entity to carry out such nuclear power activities) (para. 6.2 (e)); (b) i) by September 30, 1995, or such later date as the Bank may agree, appoint consultants whose qualifications and terms of reference shall be acceptable to the Bank to carry out a long-term least-cost power generation development study; and (ii) promptly upon its comnpletion, discuss with the Batik the findings and recommendations of said study (para. 6.2 (i)); (c) i) appoint consultants, whose qualifications and terms of reference shall be satisfactory to the Bank to carry out a study of options of long-term structure for the power sector, and ensure its completion by September 30, 1996, or such later date as the Bank may agree; ii) no later than three months after the conclusion of the assessment of the options of the long-term sector structure (Phase I of the study), or such later date as the Bank may agree, inform the Bank of its decision on the selected long-term structure for the power sector in Romania; (iii) complete a draft electricity law for submission to the Romanian Parliament no later than December 31, 1996; iv) no later than three months after the submission to the Government of the consultants' final report on the study, provide to the Bank an action program satisfactory to the Bank for the implementation of the long-term sector structure; and v) implement the action program (para. 6.2 (b)); and (d) review annually with the Bank, no later than October 31 of each year, the progress in the implementation of the Power Sector Strategy and the policy framework, and take corrective actions and policy measures to ensure the achievement of the strategic objectives stated in the Power Sector Strategy (para 6.2 (d)). 19 The Bank's Strategy 2.38 The proposed Project is in line with the Bank's power sector policy. The strategy of the Bank is to promote and support fundamental reforms to bring about effective competition and participation of private operators in the sector, while bringing about efficiency improvements in the development and operations of the power sector as quickly as possible. The proposed Project will also serve to prepare the ground through studies for continuing the restructuring in a second phase, which is expected to be supported by a follow-up project. 2.39 The Bank will adhere to two main principles in assisting Romania's power sector. First, because of the large financing requirements, the Bank will work with other multilateral and bilateral cofinanciers to prepare, finance, and implement projects in the sector. Second, the institutional reforms will be deepened under each operation. Experience has shown that due to difference in the way in which country stakeholders view sectoral and institutional reforms, even agreed actions are sometimes not implemented as expected or are delayed. Therefore, there is a need not only to agree on a long-term strategy for the power sector, but also to spellout the progress in the reforms expected for the Bank's continued involvement in the sector. Accordingly, a follow-up project in the power sector would be contingent upon satisfactory implementation of the policy reforms and in the corporate restructuring of RENEL supported under the proposed Project. 20 III. THE PROJECT A. Project Objectives 3.1 The objectives of the proposed project are to: (a) support the government's program to reform the power sector in accordance with its overall economic reform objectives; (b) meet the demand for electricity and thermal energy in an economic manner by rehabilitating thermal generation capacity; and (c) lay the foundation for the future development of the sector in an institutionally, economically, and environmentally sustainable manner. B. Project Description 3.2 The proposed Project would comprise: (a) Power Sector Reform Program (about US$4.3 million), under which technical assistance will be provided to Mol to: (i) carry out and implement a Study of Options of Long-Term Structure for the Power Sector; (ii) develop and implement an appropriate legal and regulatory framework for the sector to attract private investments to the sector; and (iii) establish a long-term least-cost power sector investment program, and carry out and implement an electricity and thermal energy pricing study; (b) Thermal Plant Rehabilitation Program (about US$344.8 million), which includes equipment, services and technical assistance to RENEL to: (i) rehabilitate about 1,445 MW of its existing thermal generation capacity; (ii) convert about 200 MW of its existing lignite-based thermal capacity to coal use; and (iii) reduce the pollution impact of thermal plants; and (c) Corporate Restructuring Program (about US$14.8 million), under which technical assistance will be provided to RENEL to: (i) streamline the utility to focus on electricity and thermal energy generation, transmission, and distribution; (ii) create cost/profit centers for the generation plants and distribution subsidiaries; (iii) design and implement management systems (for operation and maintenance management, financial and cost accounting, human resources, materials management, and corporate planning systems); (iv) improve metering, billing and collection system; (v) design hydropower plant, and transmission and distribution network rehabilitation programs; (vi) retire old and inefficient thermal units; and (vii) improve environmental management and occupational safety and health. The Power Sector Reform Program was discussed in paragraph 2.33, and RENEL Corporate Restructuring Program is outlined in paragraphs 2.8 and 4.4. The Thermal Plant Rehabilitation Program is briefly discussed below. Detailed description of the units that are to be rehabilitated is provided in Annex 3.1. Thermal Plant Rehabilitation Program 3.3 The Rehabilitation Program was prepared on the basis of a detailed technical inspection and feasibility study of rehabilitation of eleven representative thermal generating units in RENEL system. 21 The inspections and the feasibility study were carried out by a consortium of international consultants. The criteria for selection of the representative unit candidates were based on age, unit size, type of technology and operational condition. The methodological approach called for the determination of the level of rehabilitation that was economically justified as part of the least-cost solution to meeting demand. 3.4 The inspection enabled the determination of costs and benefits associated with three levels of rehabilitation: Level 1 for 7 years life extension; Level 2 for 15 years life extension; and Level 3 for 25 years life extension. To determine the appropriate level of rehabilitation for each representative unit candidate, a lifetime cost analysis was undertaken. The analysis was based on comparison of alternatives over a reasonably long period (25 years), to bring the alternatives to a commnon basis. The alternatives considered were: (a) no rehabilitation or replacement; (b) rehabilitation to level 1; (c) rehabilitation to level 2; and (d) rehabilitation to level 3. As a result of the analysis, an optimum medium term (1994 - 2000) thermal plant rehabilitation program was developed. The program is to be implemented in two phases, Phase I and Phase II. A select number of units of total installed capacity of about 1,445 MW at six power stations would be rehabilitated in the Phase 1. In addition, about 200 MW of lignite based capacity at two power stations will be converted to coal usage. 3.5 The equipment and systems to be rehabilitated under the program will include: boiler plant and combustion system, turbine-generator plant, electrostatic precipitators, fuel feed system, water treatment system, controls and instrumentation. The program will also include the improvement of operation and maintenance practices and environmental management, and development of safety procedures for the power plants personnel. The Rehabilitation Program will result in increased availability of plant; improved fuel use efficiency; increase in output: extension of the useful life of the plant; pollution reduction; and increased worker health and safety. 3.6 The Rehabilitation Program is a complex undertaking and will require technical know-how and project management skills that are currently unavailable in RENEL. Therefore, RENEL will hire an experienced consulting firm as the "Engineer" for the Rehabilitation Program. The Engineer's responsibility will be to provide RENEL with engineering, procurement, and project management services. The Engineer's services will be financed by the proposed Bank loan and the process of selection of the "Engineer" from a shortlist of firms/consortia, from whom proposals were invited, is currently in progress by RENEL. The appointment of the Engineer in a timely manner is critical to the success and timely implementation of the Rehabilitation Program. C. Project Costs 3.7 The detailed estimate of the total cost of the proposed Project is provided in Annex 3.2, and is sunmmarized in Table 3.1. It will amount to about US$363.9 million, including physical and price contingencies of US$65 million (about 18% of total costs), and taxes and duties of about US$24 million (7% of total costs). Direct and indirect foreign exchange costs amount to US$241 million (about 66% of total costs) and local costs amount to about US$122.9 million equivalent (about 34% of total cost). The estimates of base costs for the technical assistance components were developed by the mission, based on similar projects in Romania and in other eastern European countries. The costs of the Rehabilitation Program are consultants' estimates. A physical contingency level of 15% has been included in the physical components of the proposed Project. 22 Table 3.1: Project Cost Summary al US$ million Cost Item. Local Foreign b/ Total A. Thermal Plant Rehabilitation: Bucharest South 11.2 19.0 30.2 Isalnita 35.1 50.6 85.7 Deva 24.6 42.0 66.6 Palas 3.8 9.0 12.8 Braila 9.8 17.5 27.3 Brazi 8.2 12.3 20.5 Conversion to hard coal 4.0 16.0 20.0 Environrmental 0.4 3.9 4.3 Monitoring Prog. 1.5 13.5 15.0 Engineering & Proj. Man. Subtotal 98.6 183.8 282.4 B. Technical Assistance Sector & Corporate Restructuring 1.0 6.6 7.6 Metering, Billing & Collection 0.3 2.3 2.6 Other Studies and Training 0.5 5.3 5.8 Subtotal 1.8 14.2 16.0 Total Base Cost c/ (Jan. 1995) 100.4 197.9 298.4 Physical Contingencies 14.9 29.8 44.8 Price Contingencies 7.5 13.4 20.7 Total Project Cost 122.9 241.0 363.9 a/ Figures may not add due to rounding. b/ Direct and indirect foreign exchange cost. c/ Includes taxes and duties. The price contingencies are computed based on the following MUV11 indices: 1995=2.0%; 1996=2.5%; 1997=2.7%; 1998=2.5%; 1999=2.6%; and 2000=2.7%. Interest during construction (IDC) is not included, because RENEL's accounting policies do not allow for capitalization of interest charges. Therefore, total project costs are the total financing requirements. Unit Value index of manufactured exports from 5 industrial market economies to developing countries on CIF basis: Source: The World Bank 23 D. Project Financing 3.8 The financing plan for the proposed Project, summarized in Table 3.2, calls for financing the local costs of the Rehabilitation Program from RENEL's internal cash generation. The foreign costs of the Rehabilitation Program, and costs of the Reform Program and RENEL Corporate Restructuring Program will be financed by a combination of loans and grants from multilateral and bilateral agencies. The foreign financing is expected to be provided by EIB for US$23.1 million equivalent (about 7% of total financing requirements) for the Bucharest South Units 3 & 4 (2x 100 MW); EBRD for US$ 54.4 million equivalent (about 15% of total financing requirements) for the Palas Units 1 and 2 (2x5OMW), Braila Unit 1 (210 MW), Brazi Unit 8 (200MW), and part of the associated Engineering and Project Management Services, and the Metering and Billing and Collection Program; and the proposed Bank loan of US$110 million (30% of total financing requirements) for Isalnita Unit 7 (330 MW); Deva Unit 1 (210 MW), part of the Project Management and Engineering Services, the RENEL Corporate Restructuring Program, the Power Plant Maintenance System Overhaul and the Environmental Monitoring System. The grant portion of the financing package, which will finance part of the technical assistance, will be from EU-PHARE for US$3.6 million equivalent, and from USAID for US$2.9 million. Contacts are under way with the Export-Import Bank of Japan (JEXIM) for US$44.9 million equivalent (about 12% of total financing requirements) for financing for the Deva Unit 2 (210 MW) and for the lignite to coal conversion of lasi and Suceava. Table 3.2 Project Financing Plan (US$ Million) RENEL EBRD EIB EU-PHARE USAID IBRD OTHER TOTAL Power Sector 1.4 - - 2.9 - - 4.3 Reform Thermal Plant 122.3 51.8 23.1 - - 102.7 44.9 344.8 Rehabilitation Corporate Restructuring Program 1.3 2.6 - 3.6 - 7.3 - 14.8 TOTAL 125.0 54.4 23.1 3.6 2.9 110.0 44.9 363.9 3.9 RENEL ought to be able to finance the requisite local costs from its internal cash generation provided that it improves its collection record and limits its investments to the agreed levels (Chapter IV). As regards foreign cost, USAID and EU-PHARE have confirmed their willingness to finance the identified technical assistance components. EIB and EBRD confirmed their participation in the project financing in 1995, while JEXIM has been approached by RENEL, and is evaluating the information received from the Government as well as other financing requests by the Government. JEXIM participation, if and when confirmed, is likely to be under parallel financing to be administered by the Bank. EIB and EBRD's participation will be under parallel financing arrangements, as they will be financing separate units for rehabilitation under their own procurement guidelines. A consequence of these financing arrangements is that it is not necessary that the entire financing package for the project be in place now. At negotiations, GoR and RENEL undertook to secure all the cofinancing needed by December 31, 1995 or such later date as the Bank may agree (para 6.2 (a)). 24 E. Procurement 3.10 RENEL has had limited exposure to international procurement in general, and to Bank- financed procurement in particular, though it has purchased spare parts funded by Loan 3363-RO (Technical Assistance and Critical Imports Project). The close working collaboration between RENEL and the Consultant to be selected to provide engineering and project management services (para 3.6) and active Bank supervision would seek to strengthen RENEL capabilities in international and Bank procurement. The procurement arrangements are designed to take into account the participation of multiple financiers with their respective procurement guidelines (para. 3.9) as well as RENEL project management capabilities. The Rehabilitation Program (comprising equipment, materials, services and technical assistance), for which most of the procurement activity will take place, will be procured under a turnkey approach. One general contractor will be selected for each of the thermal power plants/units to be rehabilitated to provide the supply, erection and commissioning services and guarantees/warranties for performance. This approach will save time and effort (that would otherwise need to be sper.t by RENEL and its Engineer on the tendering process and on coordination between suppliers of different equipment, materials and services). For the turn-key contracts to be financed by the Bank, contractors will be selected through pre-qualification procedures and ICB in accordance with Bank guidelines. 3.11 The project elements, estimated costs and the procurement arrangements for those elements financed by the Bank are summarized in Table 3.3. Goods and services to be financed through cofinancing are shown under the non-Bank Financed (NBF) column. Four packages (Annex 3.3) in total value of about US$321.7 million will be procured under the ICB procedures of the Bank and those of the other cofinanciers. All goods, equipment, and services to be financed from the Bank loan proceeds would be procured in accordance with the Bank's Guidelines for Procurement, dated january 1995. Romanian goods for supply under ICB procedures of the Bank would receive a preference in bid evaluation of 15% of the CIF price or the prevailing customs duty applicable to non-exempt importers, whichever is less, in accordance with World Bank Guidelines. For procurement of Bank-financed goods, equipment, and services, country-specific standard bidding documents will be used. For supply, erect, and turnkey contracts, the Bank's Standard Bidding Documents, including amendments as of loan signing date would be used. Engineering consulting and technical assistance services financed by the Bank will be selected in accordance with the "Guidelines for the Use of Consultants by the World Bank Borrowers and by the World Bank as Executing Agency" (August 1981), and by using the Bank's Standard Contract Form for Employment of Consultants. The process of selecting the Engineering Consultant is currently in progress. 3.12 All bidding packages for goods and associated services financed by the Bank would be subject to the Bank's prior review of procurement documentation. All documents relating to procurement of consulting services to be financed from proceeds of the loans of the Bank and JEXIM (assuming RENEL's loan request is favorably considered, see para. 3.9) would be subject to the Bank's prior review and approval, including the qualifications, experience, terms of reference and selection criteria of the proposed consultant(s). ,A 25 Table 3.3 Summary of Procurement Arrangements a! ICB OTHERS c/ NBF bi TOTAL Turn-key Contracts for Power Plant Rehabilitation 146.7 175.0 321.7 (86.0) 235.7 (86.0) Goods 2.1 Environmental Monitoring 4.0 1.1 5.1 (4.0) (4.0) 2.2 Metering, Billing & Collection 3.0 3.0 2.3 Plant Power Maintenance System 3.0 0.6 3.6 Overhaul (3.0) (3.0) Consultancies 3.1 Engineering & Project Management 18.0 18.0 (12.0) (12.0) 3.2 Technical Assistance d/ 5.4 7.1 12.5 (5.0) (5.0) TOTAL 153.7 23.4 186.8 363.9 (93.0) (17.0) (110,0) Note: Figures in parenthesis are the respective amounts financed by IBRD. af Figures may not add to totals due to rounding. b/ Non-Bank Financed, include equipment and materials to be financed through cofinancing (EIB and EBRD) using their respective procurement guidelines, and possibly JEXIM using World Bank guidelines. c/ Consultants - Procured using Bank's Standard Guidelines for Consultants. dl For studies and training 3.13 As a consequence of the above procurement approach, contracts with an estimated value of about US$153.7 million (about 42% of the total project cost) would be financed under the Bank's ICB procedures and this amount would increase to US$218.5 million if JEXIM funding is obtained. For the turn-key contracts, the Bank will have packages/sub-packages with a total value of US$146.7 million. In addition, there will be one package for the power plant maintenance system overhaul for US$3.0 million and one other package for environmental monitoring system for US$4.0 million. Consultancies for engineering and project management services, and for technical assistance for the sector reform, corporate restructuring of RENEL, studies and training will total about US$30.5 million, of which the Bank-financed portion would be about US$17 million. The engineering and project management consultant selected in accordance with Bank Guidelines will be financed by the Bank and the EBRD. In addition, two technical assistance services for the implementation of the corporate restructuring program and for the audit of RENEL's financial statements in total value of about US$5.4 million would be financed by the Bank, for which consultants will be selected on the 26 basis of shortlists of firms (para. 3.6). The non-bank-financed portion is expected to follow the procurement procedures established by cofinanciers (EIB, EBRD, EU-PHARE and USAID). Procurement under JEXIM financing is expected to follow Bank procedures (para 3.9). Procurement packages and schedules for monitoring of procurement activities are provided in Annex 3.3. Procurement will be closely monitored by the Bank as part of Bank supervision of the project implementation. Within the framework of the project reporting (para 3.21), RENEL will be sending to the Bank, periodically, the updated status of procurement, packages and costs. F. Disbursements 3.14 The Bank funds would be disbursed against: (a) 85% of the cost of goods and associated works and services with respect to turn-key contracts and (b) 100% of the cost for consulting services. Expenditures amounting to a maximum of $5 million (5 % of the loan amount), incurred within the 12-month period prior to loan signature and referring to consultant services, equipment and materials contracted under Bank procurement guidelines, would be eligible for retroactive financing. The schedule of disbursements for the proposed Bank Loan is summarized in Table 3.4. It indicates a disbursement period of five years from the approval date of the loan. This schedule is based on the Bank's "all sectors" standard disbursement profiles for loans to Romania which is judged to be the best fit for this project for which disbursement will be for rehabilitation, instead of new power plants. The physical completion of the project is expected by June 30, 1999, the guarantee period of the last unit to be rehabilitated will run to the beginning of FY 2000. The closing date for the proposed Loan should then be set as June 30, 2000, about six months after the estimated completion of the guarantee period of the last unit to be commissioned under the Project. The detailed disbursement profile is provided in Annex 3.3 Table 3.4: Estimated Disbursement Schedule FY96 FY97 FY98 FY99 FY00 Annual 20.0 40.0 30.0 18.0 2.0 Cumulative 20.0 60.0 90.0 108.00 110.0 3.15 Disbursements for all contracts for goods and consulting service contracts above US$250,000 would be fully documented. All other contracts would be disbursed against Statements of Expenditures (SOEs). The supporting documentation will be retained by RENEL and be made available for review by Bank supervision mission and auditors. To facilitate the implementation of the project, RENEL agreed at negotiations to open and maintain a Special Account with the National Bank of Romania or anothler acceptable commercial bank in Romania on terms and conditions satisfactory to the Bank (para. 6.3 (a)). The authorized allocation for the special account would be US$5 million, representing the estimated average expenditures for a four-month period for items financed by the Bank. The initial deposit will be limited to US$1 million and the remaining portion of the authorized allocation will be released when disbursements reach a level of US$18 million. Applications for replenishment of the Special Account would be submitted on a quarterly basis or when one-third (1/3) of the amount deposited has been withdrawn, whichever occurs earlier. All applications for direct payments or special commitments must be for an amount not less than 20% of 27 the special account deposit. In addition to documentation requirement stated above, each replenishment application will be supported by monthly bank statements of the special account which have been reconciled by RENEL. During negotiations, RENEL agreed to have the Special Account and the project accounts audited and to submit to the Bank, six months after the end of each year, the audit report for the past year. (para 6.3(a)). G. Environmental Aspects 3.16 Environmental Category. In accordance with OD 4.01 (Environmental Assessment), the proposed Project has been assigned to Category B, since the project will improve the environmental performance of thermal power generation operations at a number of specific power stations. An environrnental analysis (EA) has been completed by foreign consultants for the Government and RENEL which analyzed the magnitude of potential impacts of the proposed Project (Annex 3.3; paras. 11-16). 3.17 Mitigating Measures. The measures included in the Project to mitigate any serious pollution impacts from the future operations of RENEL after the rehabilitation are as follows: (a) introduction of low NOx burners and improvements in combustion systems will lead to reductions of NOx emissions in addition to the elimination of the problem of severe corrosion and damage to steam boilers; (b) improvements in fuel use efficiency through the rehabilitation of major unit components - boilers, turbines and generators - will lead to decreases in fuel consumption and associated pollutant emissions; (c) conversion to use of imported (low sulfur) hard coal at eleven lignite-fired units (for economic reasons) will lead to reductions in all pollutant emissions from these units; (d) conversion to use of low sulphur fuel oil (< 1% sulfur) instead of high sulphur fuel oil (3-5% sulfur) also containing high levels of corrosive impurities (notably vanadium) will lead to significant reductions in SO2 and will also improve operational life and performance of boilers, and save on maintenance costs. As soon as practicable, RENEL should substitute low sulphur for the high sulphur fuel oil in the oil -fired steam boilers to be rehabilitated; and (e) rehabilitation and upgrade electrostatic precipitators will reduce dust and particulate emissions. In addition, a number of old and inefficient thermal units will be retired (Annex 3.3), which will result in further overall emission reductions. All these measures will lead to reductions in emissions of nitrogen oxides by about 46%, sulphur dioxide by about 47%, dust particulates by about 61 %, and carbon dioxide by about 28% from the rehabilitated units (Annex 3.3). It is estimated that the costs of equipment specifically designed to improve environmental conditions amount to about US$18 million. 28 3.18 Agreement has been reached with the Government and RENEL on a comprehensive program of pollution monitoring by RENEL to complement the monitoring by the other government agencies (Ministry of Health, and the Ministry of Waters, Forestry and the Protection of the Environment). Under the Project, RENEL will procure the necessary monitoring equipment and the requisite training for implementation of the program (Annex 3.3). In addition, technical assistance will be provided under the Project for institutional strengthening in environmental management and for occupational health and safety improvements (Annex 3.3). 3.19 RENEL will adopt all the necessary measures to improve occupational health and safety, which is currently a major issue within the power stations. At negotiations, RENEL agreed to provide to the Bank a program for improvements in environmental management in RENEL, including the establishment of a department devoted to environmental concerns, the definition of its main functions and of its relations with the other departments. A training program for staff members of this office was agreed upon at negotiations. By December 1, 1995, RENEL should appoint consultants, under terms of reference satisfactory to the Bank, to assist in implementing the systems, including training of RENEL staff, and assistance in implementing occupational health and safety programs at headquarters and all thermal power generating facilities, including training of RENEL staff. These commitments have been included in the Project Implementation Plan (Annex 3.3). H. Project Implementation 3.20 Implementation responsibility for the Power Sector Reform Program will be with GoR, through CCSER and Mol, while the Thermal Plant Rehabilitation Program and Corporate Restructuring Program will be with RENEL. RENEL has set up a Project Implementation Department (PID) to oversee the implementation of its components of the Project. The organizational chart and the functions of the PID are provided in Annex 3.3, pages 24-25. Both Mol and RENEL will need considerable amounts of technical and consulting assistance for implementing the various components of the proposed Project. The technical assistance program is provided in Annex 3.3. The qualifications and the timetable for appointment of the consulting engineer and the terms of reference for the services, and those of the other consultants to be engaged under the technical assistance program, have been decided during appraisal of the Project. At negotiations, RENEL agreed to take all necessary measures to ensure that the Project Implementation Department will continue to be adequately staffed andfunded in a manner satisfactory to the Bank (para 6.3 (g)). As discussed earlier, there is a need for transfer of know-how, mainly from the consultants to be hired to help in implementation, to the staff of Mol and RENEL so that they can take greater preparatory and implementation responsibilities in the future. It would, therefore, be essential that Mol and RENEL ensure active participation of the local counterpart teams in the activities of the consultants. In addition, the Project components are sufficiently complex that they warrant special and focused attention on a day-to-day basis. Finally, each of the project's components have different stakeholders in the country and there is a need to build consensus at various steps to ensure successful implementation. Therefore, the following actions have been taken to help ensure successful project implementation: (a) GoR has established an Inter-Ministerial Steering Committee to oversee the implementation of the Study of Options of Long-Term Structure for the Power Sector Structure, for which the MoF's Directorate General for Energy will serve as the 29 Secretariat and has also appointed the local counterpart team for the Study (para 2.37(c)); and (b) RENEL has appointed a Corporate Restructuring Committee under the President- Director General to oversee the design and implementation of RENEL Corporate Restructuring Program. In addition, at negotiations the GoR and RENEL agreed to carry out the proposed Project with due diligence and efficiency and in confornity with appropriate practices, and shall provide promptly as needed, the funds, facilities, services and other resources required for the purpose. In this regard, GoR and RENEL agreed to secure all financing for the project by December 31, 1995 or such later date as the Bank may agree (para 6.2 (a)). Project Implementation arrangements are discussed in detail in Annex 3.3. 1. Project Monitoring and Bank Supervision 3.21 The proposed Project will need to be monitored closely to ensure successful implementation. The requirement to engage qualified engineering consultants for the rehabilitation of the thermal plants should help with physical implementation. However, there is a need for the top management of Mol and of RENEL to also focus on the respective project components, because there are a number of interim decisions that will be required to be taken to ensure progress of implementation in accordance with the planned schedule. For example, Mol will need to decide, once the relevant studies are completed, as to how the sector will be structured over the long term, and how the restructuring would be accomplished. Also, RENEL will have to make decisions during the procurement process and during the corporate restructuring process. In view of their limited experience in the implementation of complex projects, and lack of experience dealing with international financial institutions, close monitoring of their compliance with the agreed commitments is necessary. In addition, the financing agencies, including the Bank, will require periodic reporting by the beneficiary on the project's progress. A format for reporting to the Bank was discussed and agreed with RENEL at appraisal. At negotiations, the reporting requirements were confirmed. An outline of the Format is provided in Annex 3.3. To enable such monitoring, RENEL agreed at negotiations to furnish to the Bank: (i) by October 31 each year beginning with 1995, for the Bank's review, the draft of a rolling five-year corporate plan setting forth for each year (a) the agreed medium-term investment program, the sources of financing of said investment program including borrowing needs, and tariff levels and structures; (b) the financial targets, supported by financial projections showing compliance with agreed financial performance criteria; (c) the progress in the implementation of the Corporate Restructuring Program; and (ii) by December 31 of each year, beginning with 1995, the final rolling five-year corporate plan, incorporating the Bank's comments on the previous draft, and approved by GoR (para 6.3(e)). 3.22 Staff inputs required for supervision are estimated at about 30 staff weeks for the first year and an average of 25 staff weeks for each of the subsequent years. Details of both the Borrower and Bank staff inputs required were discussed at appraisal. All major contracts are on a turnkey basis, (para. 3.10), and the project can be implemented successfully once these contracts are awarded. Therefore, a measure of success of the project implementation will be that all major contracts for rehabilitation of power plants are awarded by March 1997. Project implementation arrangements are discussed in greater detail in Annex 3.3. 30 IV. FINANCIAL ASPECTS A. Background 4.1 RENEL's financial affairs are largely governed by Law 15/1990, which governs all RAs. As regards RENEL, Law 15/1990 stipulates, among other things that: * RENEL should meet from its revenues all costs, including those required to be paid under the Tax on Profit law; * in addition to 38% tax on taxable income, 90% of the net profit after taxes, should be paid into the state budget; * the revenue and expenditures of RENEL are a part of the State's budget and will have to be approved by the Government; and * new investments and disposal of old assets requires the Government's approval;. In addition to Law 15/1990, Law 776 of November 1991 stipulates that electricity and thermal energy prices will be approved by the Ministry of Finance; Law 66/1993 requires RENEL management to enter into a management contract with the GoR on an annual basis; and special ordinances have been enacted to address the issue of the systemic inter-enterprise arrears which affects RENEL (paras. 4.12-4.17). Accordingly, although RENEL Board of Administration has the power to set corporate policy, critical decisions such as electricity and thermal energy pricing, investment levels, borrowing levels, disposal of profits and senior staff appointments are actually taken by the Government itself. The proposed project seeks to expand the capacity of RENEL to act autonomously within a legal framework that promotes accountability. B. Financial Management Financial Organization 4.2 RENEL's financial management function is the responsibility of the Deputy Director General. The 36 generation subsidiaries and the 42 transmission and distribution subsidiaries maintain separate accounts, as required by law. In addition, there are four accounting units for the Research Institutes, and 4 more for the nuclear construction group. The individual subsidiary's accounts are prepared at the local level and consolidated at headquarters. Only the Income Statement and Balance sheet are prepared for the utility. 4.3 The problems encountered in RENEL's accounting and financial management function are: (a) RENEL's present financial accounting system is primarily cash-based and owing to bad record keeping prevalent throughout the company, the financial information RENEL generates is unreliable; (b) even though RENEL is required by Law 82 (the Accounting Law) to maintain its accounts in accordance with generally accepted accounting principles, RENEL has not developed a modern electric utility accounting system appropriate for its size and functions; and (c) RENEL does not have an appropriate cost-accounting system, which is necessary to: (i) assess the appropriateness of tariff levels and structure; (ii) assess the cost-of-supply of electricity separately from thermal energy; and 31 (iii) distinguish between costs of generation, transmission and distribution; (d) basic accounting practices, such as depreciation of assets, are manipulated to show minimal profits, in order to avoid tax payments (para. 4.1) to the GoR; (e) the aggregate value of RENEL's plant, equipment and other fixed assets is questionable, since no reliable records are maintained for the most part and the values do not reflect the operational capability of these assets, many of which should be scrapped; and (f) there is no long-term operational and financial planning, except the annual budget, whose periodic review involves mainly physical targets. 4.4 To overcome the above critical deficiencies, as well as to address the structural problems in RENEL (para 2.6) and overstaffing (para 2.8), the utility needs to implement a comprehensive Corporate Restructuring Program, which will comprise the following phases: (a) restructuring RENEL to spin-off non-core and non-conventional electricity utility activities and establishment of cost/profit centers; (b) modernization of financial accounting system to a standard appropriate for the size and function of RENEL; (c) development and implementation of a cost accounting system; (d) physical verification of fixed and current assets, establishment of asset registers and preparation of financial statements; (e) assessment of human resources availability and requirement, and implementation of programs to reduce staff while filling the skills gaps; and (f) implementation of a corporate budgeting and planning system. RENEL would require consultant assistance for designing and implementing the requisite management systems, for which financing is included under the proposed Project. Terms of reference for the Corporate Restructuring Program have been agreed with RENEL. RENEL has agreed to completely implementt, before December 31, 1997, or such later date as the Bank may agree, the Corporate Restructuring Program described above, with the assistance of consultants whose terms of reference and qualifications are satisfactory to the Bank (para 6.3(h)). It was also agreed that RENEL shall: (i) have its records, accounts andfinancial statements, for each fiscal year beginning with 1995, audited, in accordance with appropriate auditing principles consistenitly applied, by inidependent auditors acceptable to the Bank; (ii) furnish to the Bank as soon as available, but in any case not later than six months after the end of each year: (A) certified copies of its financial statements for such year as so audited; (B) the report of such audit by said auditors, of such scope and in sulch detail as the Banik shall have requested; and (iii) furnish to the Bank such other information concerning said records, accounts and financial statements as well as the audit thereof as the Bank shall request (para 6.3 (a)). Billing and Collections 4.5 RENEL has approximately 250,000 industrial and commercial customers who account for roughly 80% of its electricity sales. These customers are billed monthly on the basis of meter readings. Collection is made through the local banking system. RENEL also has about seven million residential customers who are dealt with by about 100 offices around the country. Billing is done once every two months. Collections are made in cash at each of the respective offices, and by meter readers during meter reading. 4.6 Billing and collection by RENEL is hampered by: (a) very old metering equipment, in need of urgent replacement; and (b) by law, the penalties for late payment cannot exceed the original bill amount, which may not be enough incentive for payment when the delays are very long due to inflation. Therefore, there is often no strong incentive to make payments on time, resulting in loss of real revenues to RENEL. To address these issues, RENEL will implement a Billing and Collection Modernization Program under the proposed project. This Billing and Collection Modernization Program, which will include both equipment installation and technical assistance, will be : (i) based 32 on a recently completed study carried out by foreign consultants under Swiss Government funding and Bank supervision; (ii) funded by EBRD; (iii) focused firstly on the Bucharest distribution system; and (iv) later expanded to the entire RENEL system. At negotiations, RENEL agreed to implement the Billing and Collection Modernization Program for its Bucharest distribution system by December 31, 1997, in a manner satisfactory to the Bank with the help of Consultants recruited by September 30, 1995. This is provided in the Project Implementation Plan (para.6.3 ()). Insurance 4.7 The current practice in Romania (and in RENEL) is for the companies to bear the risks of any damages to assets and personnel as and when they occur. However, the Government of Romania intends to issue decisions and/or decrees to require the companies to establish insurance arrangements as per standard industry practice internationally. Accordingly, RENEL plans to establish a self- insurance scheme to cover the risks to its assets, as is the standard practice for many electricity utilities around the world. Such self insurance scheme will be established soon after: (i) RENEL has completed the physical verification and valuation of its assets (which is part of the Corporate Restructuring Program under the Project); and (ii) the Government of Romania has issued the measures referred to above. For these reasons, the current practice of RENEL is considered acceptable until the two events mentioned above have occurred. C. Past Performance 4.8 RENEL's operational performance during 1992 - 1994 is summarized in Table 4.1 and provided in more detail in Annex 4.1. In view of the unreliability of the financial statements, particularly asset accounting (including depreciation); and in view of the high inflation levels that prevailed during the period, RENEL's past performance is analyzed in US$ cash flows terms. Table 4.1: RENEL Operational Performance in 1992 - 1994 (US$ Million) 1992 1993 1994 Electricity Sales (GWh) 47,178 45,597 43,300 Thermal Energy Sales ('000 GCal) 42,466 42,539 45,105 Ave. Electricity Tariff (US$/MWh) 2/ 33.75 34.89 40.34 Ave. Thermal Energy Tariff (US$ GCal) 9.75 9.39 11.21 Operating Revenue 2,090 2,060 2,293 Cash Operating Costs 1/ 1,915 1,854 2,090 Operating Income 174 206 203 Working Ratio (%) 91.7 90.0 91.2 Debt Service Coverage (times) 14.9 8.1 2.1 Internal Cash Generation (% of 31.0 36.9 10.5 1/ excluding depreciation. 2/ Net of VAT 33 4.9 During 1991-94, RENEL's electricity sales declined by about 16% (from 51,531 GWh in 1991 to 47,178 GWh in 1992 and to 43,300 GWh in 1994) as the economy and, in particular, the industrial sector (which accounts for nearly 80% of RENEL's electricity sales), continued to decline. In addition, RENEL realized a lower than targeted average revenue (US$33.7/MWh in 1992, US$34.9/MWh in 1993 and US$40.3/MWh in 1994, against targeted level of US$42.4 net of VAT), due to some delays in adjustments in electricity tariffs in an environment of high inflation. Moreover, as a consequence of the large proportion of thermal plant generation, higher than normal fuel consumption, and other operational inefficiencies, including overstaffing, RENEL's cash operating costs could not be reduced, even though sales declined. As a result, RENEL's operating margins were slim as indicated by the working ratio, (i.e. the ratio of its cash operating costs to its operating revenue), which averaged just over 90% during the three years. In addition, RENEL experienced significant cash flow constraints, caused primarily by the systemic inter-enterprise arrears problem prevailing in Romania. To compound the problems, RENEL continued with high investment levels of US$523 million in 1992 and US$444 million in 1993, mainly for the construction of the Cernavoda nuclear power station. 4.10 As a consequence of cash flow constraints, RENEL has had to resort to short-term borrowing (less than one year) to meet local costs of investments. As a result, RENEL's debt service coverage ratio (DSCR) declined from 14.9 in 1992 to 2.1 in 1994. RENEL's internal cash generation (ICG) ratio (the ratio of its internal sources of funds to annual investments) was satisfactory at 31 % in 1992 and 37% in 1993 primarily because: (a) RENEL had a very low overall debt burden resulting in low levels of debt service (US$12 million in 1992, and US$26 million in 1993); and (b) RENEL, kept its working capital increases to a minimum by not maintaining sufficient operating inventories and by not settling its accounts payable (particularly to fuel suppliers and transporters) on time. However, the ICG was about 10% in 1994 owing to a three-fold increase in debt service, which in turn is a consequence of RENEL having to start repaying the loans on the Cernavoda nuclear power plant. RENEL Receivables and Payables 4.11 Given electricity's critical role in the economy and the fact that RENEL system is dominated by thermal power generation capacity, it is not surprising that RENEL suffers from, and contributes to, the systemic inter-enterprise arrears problem in Romania. RENEL's main consumers are heavy industry (metallurgical, chemical) for electricity and local governments for thermal energy. The heavy industrial sector is in a very weak financial situation owing to high levels of inefficiencies, lack of market(s) for their products, and the downturn in the economy. Local governments face difficult budgetary problems and are unable to meet their payments for energy supplies to municipal and social services. Therefore, as RENEL customers delay paying their electricity and thermal energy bills, RENEL responds by delaying payments to its suppliers, mainly for fuels, - coal/lignite, fuel oil and natural gas. To address the inter-enterprise problem, in particular, and to improve financial viability of critical RAs in general, the Government in September 1994 issued Decree 499/1994, placing five RAs, including RENEL, under a special surveillance program. 4.12 RENEL's Accounts Receivable: Table 4.2 provides a breakdown of RENEL's accounts receivable as of March 16, 1995, by age; type of service; and type of debtor. 34 Table 4.2: RENEL Accounts Receivable as of March 16, 1995 (Lei billion) 1. Receivables by Age < 30 days 30 - 60 days 60 - 180 180 - 360 days 1 > year Total 267 190 271 173 35 936 29% 20% 29% 18% 4 % 100% 2. Receivables by Type of Service Electricity Thermal Energy Other Services Total 620 310 6 936 66% 33% 1% 100% 3. Receivables b- Type of Debtors l_l Industrv Agriculture Local Government Others Total 509 106 260 61 936 54% 11% 28% 7.1% 100% RENEL's receivables amount to lei 936 billion (2.5 months of 1995 projected sales) of which Lei 669 billion (1.75 months of 1995 sales are in arrears (i.e. outstanding for more than 30 days). RENEL's thermal energy receivables, which account for 33 % of overall receivables, are a larger problem because the thermal energy is sold mainly to the district lieating companies of the municipalities, who in turn supply to households. The district heating companies are unable to fully collect the bills on time from their consumers and in turn fail to pay RENEL. RENEL's largest debtors are the government owned industrial plants, all of them under Mol, which amount for 66% of RENEL receivables. Among the industries, metallurgical are the biggest debtors accounting for 39% of industry receivables (17% of overall), followed by petrochemical industries accounting for 30% (15% of overall). The second largest set of debtors is the local governments, who account for 28% of overall debts. The Bucharest municipality alone accounts for 90% of receivables from local governments, or 25 % of overall debts. 4.13 RENEL's Accounts Payable: Table 4.3 provides RENEL's accounts payable breakdown by creditor and levels of payable owed by RENEL, as of March 16, 1995. Table 4.3 RENEL Accounts Payable as of March 16, 1995 (Lei billion) Accounts Payable from Accounts RENEL in Monthly Average 1/ Payable months of Fuel Sales to RENEL from Fuel Sales Creditor (1994) RENEL (1994) ROMGAZ (Gas) 36 277 7.7 RA (Lignite) 60 146 2.4 RAH (Hard Coal) 20 30 1.5 RAFIROM (Fuel Oil) 19 96 5.0 SNCFR (Coal Transport) NA 22 N.A. I/ These figures are somewhat misleading as there is a strong element of seasonality in fuel purchases, which are higher during winter months. 35 The above five fuel suppliers to RENEL account for 77% of the utility's accounts payable. It should be noted that normally RENEL will become, cyclically, either a net creditor or a net debtor. At the end of summer, RENEL will be a net debtor, since during summer, RENEL's electricity and thermal energy sales are low (resulting in lower billing and lower collection); and towards the end of summer (August/September), RENEL will start incurring higher fuel costs to build up stocks for the winter; and at the end of winter (March/April), RENEL will be a net creditor, as electricity and thermal energy sales will peak during winter and fuel expenses start declining. Targets for RENEL Accounts Receivable and Payable 4.14 From a utility point of view, RENEL's accounts receivable level of about 2.5 months' average sales is high but within acceptable boundaries. However, given the size of RENEL within the Romanian economy (RENEL revenues of about US$2.3 billion in 1994 are equivalent to over 10% of GNP), a 3-month accounts receivable level would imply an amount equivalent to over 2% of GNP. Therefore, RENEL's accounts receivable level has a considerable macroeconomic significance and should be reduced to the minimum level possible. In this regard, there is a level below which the utility's accounts receivable cannot be reduced, due to the logistics of billing and collections - RENEL bills its major industrial customers every month, and allows them a month to pay. For its low voltage consumers, particularly households, RENEL bills them once every two months and allows a month for payment. Given the 80:20 ratio of high/medium voltage to low voltage consumers, the minimum level of accounts receivable below which RENEL probably cannot go at present is about 60 days' sales. Therefore, in a first stage RENEL should aim at reducing and maintaining its accounts receivable level at 2 months' sales. In terms of accounts payable, it is normal for a utility to maintain its dues to suppliers at one month's supply. RENEL should target to maintain its accounts payable to fuel suppliers at one month's average fuel bill or as per agreed terms in the supply contracts. Actions to Resolve RENEL Arrears Situation 4.15 Most of RENEL's high/medium voltage industrial customers, who are the worst offenders, are state-owned. Prior attempts at resolving the problem of unpaid bills by such customers have not succeeded because of political interference, arising from social considerations (since cutting electricity supply to industrial customers in arrears results in production stoppages, which reflects, in turn, on employment); and lack of sufficient financial discipline. At present, RENEL is implementing a very aggressive program to improve collections. However, additional arrangements must be implemented to promote discipline, both by RENEL customers and by RENEL itself. Also, separate arrangements must be devised for commercial businesses (commercial companies and other regie autonomies) who must face market discipline and local governments, who cannot be shut down. This means that GoR will have to play a critical role in the resolution of the inter-enterprise arrears problem, including the institution of measures to prevent recurrent build-up of arrears. 4.16 To address the problem of RENEL arrears, a set of actions, collectively called the Financial Recovery Plan (FRP) is being developed by RENEL and the GoR, under the proposed Financial and Enterprise Sector Adjustment Loan (para 1.2). RENEL's FRP would be the front-end portion -- i.e. the first year -- of the Corporate Restructuring Program concentrating on the financial improvements in 1995 only; and focuses on short-term measures that would achieve reduction in expenditures, increase in cash revenues and reduction in arrears on both accounts receivable and payable. In its dialogue on financial discipline issues, the Bank has emphasized the distinction between the stock of arrears and new bills. 36 4.17 To ensure RENEL's financial solvency, GoR agreed to take all necessary actions to ensure that GoR's departments, agencies and enterprises as well as local governments settle RENEL's electricity and thermal energy bills within 60 days of the date of such bills. In addition, REAEL agreed to ensure that (i) the receivables on its electricity and thermal energy sales to the private sector, including households will not exceed two months' sales to such customers; and (ii) it will settle its bills to its fuel suppliers as per contractual terms (para. 6.2 (c)). This is an ambitious objective, given the financial problems faced by RENEL's largest customers. To achieve it, the Goverrnent has provided assurances to the Bank that it will take all necessary measures to ensure that customers in significant arrears that do not pay their current bills on time will be disconnected or will be subject to progressively increasing electricity supply cuts. Also, the Treasury will change its administrative regulations to enable it to pay RENEL directly from the budget allocations of agencies that are not paying on time. Finally, it is expected that under the FESAL a financial relief fund will be established to provide some limited assistance to selected firms that meet stringent criteria to help them pay their current electricity bills. The issue of old arrears needs to be resolved through direct negotiations between RENEL and its customers, leading to partial cancellation or extended repayment periods based on a realistic assessment of their capacity to pay. It was agreed that RENEL shall have provided to the Bank satisfactory evidence that it has concluded enforceable arrangements for debt repayment with each of its customers listed in an Annex to the Power Sector Strategy (para 6.4) as a condition of loan effectiveness. D. RENEL Investment Program and Financing 4.18 At negotiations, the GoR and RENEL confirmed the medium-term (1995-2000) power sector investment program. It is estimated to amount to about US$2,323 million in nominal terms, comprising US$1,607 million in foreign exchange costs (72%). In accordance with the Government's strategy for the Power Sector (para 2.33), RENEL's investment priority will be: (i) rehabilitation of existing supply facilities in generation, transmission and distribution; (ii) the completion of high priority unfinished hydro and thermal plants at advanced stages of completion; (iii) expansion and reinforcement of the power transmission and distribution network and modernization of the load dispatching system for energy management applications; and (iv) heat transmission system, environmental pollution control and land reclamation. It is crucial for RENEL to focus on thermal plant rehabilitation investments in the next 3-4 years, and on other rehabilitation investments during the subsequent years. GoR and RENEL agreed to review with the Bank, by October 31 of each year, the medium-term investment program, including the sources of financing, and to take the views of the Bank into account in modifying the investment program (paras 6.3 (e)). RENEL Investment Program for the period 1995-2000 is provided in Table 4.4. Table 4.4 RENEL Investment Program (1994-2000) (US$ Million) Local Foreign Total %:_ i Thennal Plant Rehabilitation 248.7 471.3 720.0 31.0 Hydropower Plant Rehabilitation 1.2 1.6 2.8 0.1 T & D* Rehabilitation 18.4 78.9 97.3 4.2 EMS & SCADA 14.3 28.1 42.4 1.8 New Projects 433.0 1027.4 1460.4 62.9 Total Investments 715.6 1,607.3 2.322.9 1 * T & D = Transmission and Distribution Systems. 37 E. Financial Forecasts 4.19 RENEL's investments should only comprise the proposed investments discussed above. To finance the local costs of these levels of investments, RENEL may not be able to borrow domestically since the domestic financial markets are shallow relative to RENEL's needs. Therefore, RENEL aims to finance all of its local costs of investments from its internal cash generation (ICG). Also, in view of the separation of nuclear activities, the nuclear power investments, and the associated debt service obligations will be the responsibility of the GoR and the new nuclear power entity (para 2.38 (a)). 4.20 Under the above-mentioned planning environment, the forecasts of operational and financial performance of RENEL during 1995 - 2000 are summarized in Table 4.5, and provided in detail in Annex 4.1. RENEL's sales of electricity are expected to grow by about 2.4% each year until 1998; and then increase at about 2.2% per year, to reach a level of 50,000 GWh in the year 2000. These rates are lower than the expected economic growth of about 5%, as energy intensity is expected to fall. Thermal energy sales are assumed (conservatively) to remain constant at 45,105 Gcal/year throughout the forecast period. As a consequence, growth in operating revenue, from US$2.37 billion in 1995 to US$2.7 billion in the year 2000, will come primarily from growth in electricity sales, since average electricity tariffs are expected to be maintained at about US$50/MWh, inclusive of VAT. However, the cash operating costs (i.e., other than depreciation), are expected to increase at a slower rate than revenues, as an outcome of implementing the FRP and of reductions in fuel cost due to efficiency improvements under the Project. Therefore, RENEL's working ratio is expected to improve somewhat to 88.8% in the year 2000. 4.21 In 1995, the utility's ICG will be about 23%, as a result of slightly higher sales, and removal of Cernavoda nuclear power development expenditures from RENEL's investment program. RENEL's ICG in 1995 would have been higher if the tariff increases, which were due at the beginning of 1995, had been effected on time (tariffs were adjusted to US$50/Mwh in June 1995). RENEL's ICG will range between 30% and 45% in the remaining part of the forecast period, for an average of about 38%, which is sufficient to cover the local cost of its investments. As RENEL incurs significant levels of debt to finance its investment program, its debt service coverage ratio (DSCR) will decline. However, RENEL will still be able to achieve DSCR levels of above 1.5, which is satisfactory. 38 Table 4.S: RENEL Operational Performance in 1994 - 2000 (US$ Million) 1995 1996 1997 1998 1999 2000 Electricity Sales (GWh) 44,500 45,600 46,300 47,800 48,600 50,000 Thermal Energy Sales ('000 GCal) 45,105 45,105 45,105 45,105 45,105 45,105 Ave. Electricity Tariff (US$/MWh; net of VAT 40.80 42.37 42.37 42.37 42.37 42.37 Ave. Thermal Energy Tariff (US$ GCal) 11.40 11.40 11.40 11.40 11.40 11.40 Operating Revenue 2,374 2,495 2,530 2,599 2,639 2,705 Cash Operating Costs 2,192 2,220 2,252 2,307 2,351 2,401 Operating Income 182 276 278 292 288 304 Working Ratio (%) 92.3 89.0 89.0 88.8 89.1 88.8 Debt Service Coverage (times) 2.1 3.7 2.9 2.4 2.1 1.8 Intemal Cash Generation (%) of investments 22.7 31.8 45.4 37.8 34.1 33.3 4.22 Given that RENEL will have to operate under a "de-facto" price cap regimne during the forecast period, the utility will have to take steps to improve and maintain its financial viability (e.g. meet all of its operating costs and finance a reasonable portion of its investments) and creditworthiness (e.g. be able to comfortably service its debt after meeting all operating costs). RENEL agreed to: (a) produce, for each of its fiscal years after its fiscal year 1994, funds from internal sources equivalent to no less than 30% of the average of RENEL capital expenditures incurred, or expected to be incurred, for that year, the previous fiscal year and the next following year; (para 6.3 (b); and (ii) take such measures as may be necessary to ensure that the estimated net revenues shall be at least 1.5 times, in 1995 and each succeeding fiscal year, the estimated maximum debt service requirements of RENEL for any such fiscal year on all debt of RENEL (para 6.3 (c)). Financial Impact of Nuclear Power Generation on RENEL 4.23 The separation of nuclear power activities into an independent public entity (para 2.37 (a)), and the establishment of a Power Purchase Agreement (PPA) between this new entity and RENEL will have an impact on RENEL finances and, therefore, on its tariffs, if RENEL is to achieve the financial performance criteria stated earlier. Since the price of purchased power from the new nuclear entity has yet to be set, several levels of nuclear power prices to RENEL were examined for their impact on RENEL's retail electricity tariffs. 4.24 Such analyses show that if the nuclear power purchase price is US cents 3/kWh (which is just below RENEL's average cost of US cents 3.09/kWh of hydro and thermal electricity generated), RENEL can achieve its planned financial performance targets with an average price of about US$42.4/MWh equivalent. However, if the nuclear power purchase cost is higher, for example in the US cents 4-6/kWh range, then RENEL tariffs need to be increased beyond planned levels, since the power purchase cost will exceed RENEL's own generation costs by higher and higher amounts. Since the PPA between RENEL and the nuclear entity needs to be satisfactory to the Bank, the Bank's review of the proposed power purchase agreement (PPA) between RENEL and the new nuclear power entity, will focus, among other things, on ensuring appropriate level of the power transfer price (an artificially low price would require a government budget subsidy to the nuclear power entity, and a transfer price above RENEL's cost of generation will require increases in RENEL tariffs to its customers). 39 V. PROJECT JUSTIFICATION A. Rationale for Bank Involvement 5.1 The CAS submitted to the Board with the Petroleum Sector Rehabilitation Project on March 14, 1994, mentions the support of reforms in the power sector as one of the priorities in the Bank lending program for 1994 - 1997. The Bank's involvement would be critical to steer the development and implementation of market oriented sectoral policies and institutional reforms. The proposed Project is in line with the agreed strategy of promoting efficiency of energy use as a way of conserving scare resources, while reducing environmental pollution. The Bank's experience in power sector reforms worldwide will contribute to the development of a sound legal and regulatory framework. The Bank will be instrumental in mobilizing cofinancing. Furthermore, the Bank's involvement will contribute to meeting the structural reform objectives under the SAL, specifically in reducing the budget deficit through rationalization of the power sector investment program; and maintaining the momentum of liberalization of energy prices. Future Bank lending to the sector is envisioned, contingent upon satisfactory progress in the implementation of policy reforms. 5.2 The physical component of the Project is the least-cost solution to meet the demand for electricity in comparison with all the alternative feasible options considered, including imports of electricity. Sensitivity analysis carried out to establish the robustness of the economic solution on the basis of the technical and economic risks that could arise with the implementation of the Project, confirmed the robustness of the economic solution. The following sections explain, in summary, the justification. Further details are provided in Annex 5.1. B. Generation Capacity 5.3 The future electricity demand profile indicates that for the foreseeable future the system's priority requirement will continue to be base load, as opposed to peaking capacity requirements. However, the dependable output of the thermal plants, which provide base load, is rapidly declining. The Bank estimates that dependable thermal capacity would decline from the current level of about 5,500 MW to about 3,500 MW by year 2000, if no rehabilitation takes place, and if current poor operations and management practices continue. The thermal capacity that will be reinstated through the rehabilitation program will restore firm base load capability to meet demand through year 2000. C. Least-Cost Analysis 5.4 The results of a preliminary study of Least-cost Power Generation Development, carried out by consultants for RENEL in 1992, assigned priority to the rehabilitation of existing generating facilities. The follow-up technical inspection and feasibility study of rehabilitation (para. 3.3 - 3.6) to complement that finding showed that the plants are in much more degraded and unsafe operating condition than assumed in the least-cost study, and urgent rehabilitation is needed to prevent further rapid decline in output and availability of base load capacity, and to improve operational safety. 5.5 To establish that the proposed rehabilitation program is the least- cost solution, it was compared to other options of providing base load capacity. The comparison shows that the rehabilitation of the 40 thermal units is economically more favorable than alternatives which include: (a) completion of Units 2 and 3 of the Cernavoda nuclear power plant and of unfinished hydropower plants, with storage reservoirs, on firm energy capability basis; and (b) gas fired combined-cycle alternative. The time constraint in making capacity available is an added advantage of rehabilitation over new units. The possibility of imports of electricity from Ukraine was examined, but was disregarded because it would be more expensive than the production from the rehabilitated units, and in addition, it could not be relied upon as a source of firm continuous supply to meet base-load requirements. However, during critical periods of demand, when some of the large units would be under rehabilitation, imports may be needed to supplement local supply. Table 5.1 provides the comparison. Table 5.1.' Comparison of Highest Cost Rehabilitation Candidate with Other Options US Cents/kWh (Life-time Costs at 10% Discount Rate) Isalnita a/ 4.4 Cernavoda Unit 2 6.8 Cernavoda Unit 3 6.9 Dimbovita Hydropower Plant b/ 6.2 Bistra Hydropower Station b/ 9.4 Combined Cycle 5.5 Electricity Imports 5.2 a/ Highest cost rehabilitation candidate. b/ On the basis of estimated firm energy production capability. 5.6 There are uncertainties concerning the additional cost of completion of the Cernavoda nuclear power units, which should be established by a detailed engineering assessment. In addition, the costs do not include de-commissioning and spent fuel disposal costs, which are considered to be high. Finally, no account has been taken of the longer time required to complete Cernavoda Unit 2 compared with the time needed to rehabilitate Isalnita, but this consideration also favors rehabilitation. Considering the urgent need for firm based-load capacity in the system the lowest cost of rehabilitation, and the above considerations, rehabilitation of Isalnita is the preferred option. 5.7 Even with the reinstatement of capacity that the rehabilitation provides, the power system may be barely able to meet the expected demand. Table 5.2 compares available dependable continuous power output with demand on the system by year 2000. 41 Table 5.2: Dependable Continuous Power Output and Demand (MW) Actual Estimated 1992 2000 Maximum Thermal Plant Power Output Pre-rehabilitation (MW) 5,500 3,500 Reinstatement of Capacity through rehabilitation - 2,320a/ Other RENEL Rehabilitation - 600 New Plant Additions (i) Cernavoda Unit 1 - 660 (ii) Turceni 8 - 270 (iii) Other Thermal - 180 Total Thermal 5,500 7,530 Firm Hydropower Output 2,000 2,000 Total Firm Dependable Capacity 7,500 9,530 Maximum Demand 9,500 9,100 Imports/(Reserve margin) 2,000 (430) -/ Capacity to be reinstated by entire rehabilitation program of RENEL including the proposed project D. Lignite to Imported Hard Coal Conversion 5.8 The technical inspection and feasibility study conducted on the lasi cogeneration lignite fired unit was to establish the technical and economic merits of conversion of 11 similar units (1 lx50 MW cogeneration) to use of imported hard coal as the primary fuel. The results confirmed the technical and economic justification for such conversion. An additional important benefit is the reduction in air pollution and lower volume of ash disposal that the conversion would bring about. 5.9 The economic merit is the curtailment of the uneconomic transportation of lignite over long distances (300-600 km). At the lasi power station the economic cost of lignite delivered is about US$25/ton compared to the delivered cost of imported hard coal through Constanza port of about US$50/ton. To establish the economic merit of the conversion, the present value of economic cost of lignite at the power station over the life of the unit was compared with the present value of the incremental capital and fuel costs for the conversion over the same life of the unit on heat equivalent basis. The former was estimated at US$140 million compared with US$60 million for the latter. In addition, operation and maintenance costs will be lower in the case of the conversion. 5.10 Similar analysis has been extended to the other 10 units at the different locations in the North Eastern part of the country. The conversion of the units, apart from the environmental benefits, provides a least-cost means of serving the same quantity of thermal energy and electricity demand. 42 E. Rate of Return Analysis 5.11 The rate of return on the investments in the rehabilitation component is estimated to be about 21% compared to the estimated long-term opportunity cost of capital to Romania of about 10%. The analysis follows the traditional approach of comparing quantifiable incremental costs and benefits to the power system of the rehabilitation program. The estimates of investment costs and of fixed operation and maintenance costs are based on the estimates of the consultants that conducted the feasibility study. Fuel costs are estimated at improved unit efficiencies resulting from rehabilitation, and fuel was valued at border prices. Allowance was made for the incremental cost to the power system as result of a unit being on outage for rehabilitation by increasing the output of less efficient power units to replace the output of the units under rehabilitation. The incremental cost (outage cost) was based on the additional fuel and other variable operating costs to the power system. All costs were expressed in economic terms and in prices of January 1994. 5.12 The quantifiable benefits comprise: (a) fuel savings from improved unit efficiency; (b) increase in electricity production resulting from increase in power output, and improved availability of the rehabilitated units; (c) savings in consumption of support fuel, natural gas and fuel oil, in the lignite and coal fired units through improved loading of units, and reduction in stops and starts of the units; (d) improvement in quantity and reliability of heat supply, which is captured through credit of the efficiency of cogeneration to electricity production. 5.13 Incremental electricity sales were valued at an average electricity price of US cents 5/kWh, the agreed annual average price which the Government has committed to maintain in real terms over the year. Since price is a poor proxy for benefits, as it fails to capture the consumer surplus, this method of calculation underestimates the economic rate of return on the project. Details are presented in Annex 5.1. 5.14 For the conversion, incremental costs consist of the capital cost of the conversion and the associated fixed operation and maintenance costs. The benefit is the savings in cost of fuel delivered, and operation and maintenance costs. F. Other Benefits 5.15 Other benefits, which are not readily quantifiable, are associated with the improvements in the quality of the environment, mainly the reduction in air pollution that the rehabilitation will bring about. Additional benefits will arise from improvements in management and associated operational cost reductions arising from the corporate restructuring program. G. Sensitivity Analysis 5.16 The Base Case analysis already takes account of possible delays in project implementation by considering implementation over five years instead of three years in which the proposed rehabilitation program would normally be implemented and completed. Sensitivity analyses were carried out to test the robustness of the economics of the project as follows: (i) a 20% increase in capital costs could arise in rehabilitation work of this nature due to greater than expected plant deterioration that might be uncovered during implementation; and (ii) considerations that the rehabilitation might not achieve the expected improvements in fuel use efficiency and availability, thus leading to higher fuel consumption and that the targeted level of output and reliability may not be achieved. Reduction of 10% in fuel use efficiency and 43 in expected availability improvements are assumed. Additional sensitivity tests were conducted to assess the impacts of extreme conditions on project economics. For the economic rate of return to fall to about 10% (switching value analysis) a combination of the following changes would have to occur simultaneously, which is unlikely: (i) a two-year delay in project completion; (ii) a 20% increase in capital costs; (iii) a 10% reduction in the expected improvements in fuel use efficiencies (already conservatively assumed); and (iv) a reduction of about 10% in the expected power output and availability of the rehabilitated units. 5.17 The results of the analysis shown in Table 5.3 indicate the robustness of the rate of return in the face of increased capital costs and reductions in fuel use efficiency, and electricity production. The rate of return is most sensitive to the reduction in expected output and unit availability. Table 5.3: Results of Sensitivity Analysis RoR Base Case 21 (a) 20% increase in capital cost 18 (b) 10% reduction in fuel efficiency 17 (c) 10% reduction in availability 15 (d) Reduced Project Scope 18 (e) Combination of (a) (b) and (c) 10 5.18 A further sensitivity analysis was carried out on the base case to show the effect of a reduced project scope arising from unavailability of the cofinancing now being sought from JEXIM. In this case, the rehabilitation program will exclude the second thermal unit at Deva (210 MW) and the conversion of 200 MW of lignite based capacity to imported coal use proposed for JEXIM financing (para 3.8). This would penalize the power system through a net incremental benefit foregone due to the reduced rehabilitation scope, and the non-conversion of the isolated power stations from lignite to imported coal use. The economic rate of return in this case is estimated to be about 18%. H. Sustainability 5.19 Training in management and in modern corporate and financial systems will be provided; this, in addition to the initiation of the long-term reform measures is expected to help the benefits of the corporate restructuring of RENEL. Achievement and sustainability of the benefits from the physical components of the Project will be highly dependent on three main factors. These are: (a) the quality of materials used and quality of construction (b) the effectiveness of the project implementation; and (c) improvements in post rehabilitation operation and maintenance. The poor practices in these areas in the past have been the principal causes of the rapid and premature deterioration, and the poor performance of thermal power plants, which have necessitated the proposed rehabilitation project. 44 5.20 The lessons learnt by the Bank and the Romanians from the past have been taken into account. The establishment of a well structured project implementation department with experienced foreign technical advisors and consultants will ensure quality of both materials used and construction, and would ensure efficient project management and execution through new methods and technologies that would be introduced. Factory acceptance tests and other measures have been incorporated in the project implementation to assure quality of materials. Through the contractual arrangements, construction and erection will be undertaken by experienced contractors with proven track record. The computerized plant maintenance program, complemented by three years supply of essential spare parts with the associated training of RENEL staff is aimed at enhancing plant maintenance, which would be sustained by the improvements in the financial position of RENEL. The program for improved environmental management will contribute to sustaining the environmental benefits of the project. All these measures are to be complemented by active Bank supervision of the project implementation. With these measures, the benefits of the Project would be achieved and sustained. In the long run, sustaining the institutional and policy achievements will be contingent upon the govermment's continued commitment to a market economy. 1. Risks 5.21 The main risk associated with the proposed Project relates to the implementation of the sector reform and restructuring program. To address this, some important upfront actions have been taken. The actions include: (a) the appointment by the GoR of a high level Inter-Ministerial Committee to oversee the Study of Options of Long-term Power Sector Structure and the initiation of the Study; (b) the issuance of the Statement of Power Sector Policy by the Govermnent stating the government's medium to long-term reform policy objectives for the power sector, and the Strategy Document that outlines how the policy framework will be implemented. A review would be conducted each year to assess progress in achieving the development objectives of the project and to consider need for further policy actions or project restructuring (para 2.37 (d)). 5.22 A second concern is possible financial risk due to the inability of RENEL to mobilize the counterpart funds adequately and timely. This risk is mitigated by rate increases already implemented, and the measures to be implemented under the Project to improve billing and collection, and reduction of arrears. Close monitoring of performance is planned. A third concern relates to the availability of cofinancing. However, progress in this regard has been satisfactory and both EBRD and EIB are at an advanced stage of project preparation. Even if confinancing is not fully secured, such as if JEXIM confinancing does not materialize, the restructured project would still be economically and technically viable, as shown by the sensitivity analysis (para. 5.18). 5.23 Another concern is project implementation risk pertaining to the capacity of RENEL to implement a complex and demanding project. This is being addressed through a well staffed Project Implementation Department that has already been set-up (para 6.3(h)), and by using the turnkey contract modality to procure the rehabilitation of each of the power plants, which will reduce the need for detailed involvement of RENEL in the works. In addition, the process of selecting a reputable engineering consultant (the Engineer) by RENEL for the engineering and project management services is nearly completed. Hence, the risk has been mitigated as much as possible. 45 VI. AGREEMENTS REACHED AND RECOMMENDATIONS 6.1 During negotiations agreements were reached with the GoR (the Guarantor), and RENEL (the Borrower) on the conditionalities of the Guarantee and Loan Agreements. These are listed below. Agreements reached with GoR 6.2 The GoR agreed to: (a) carry out or cause to be carried out the proposed Project with due diligence and efficiency and in conformity with appropriate practices, and shall provide promptly as needed, the funds, facilities, services and other resources required for the purpose. In this regard, GoR has agreed to secure all the financing for the project by December 31, 1995, or such later date as the Bank may agree (para 3.20). (b) (i) appoint consultants, whose qualifications and terms of reference shall be satisfactory to the Bank, to carry out a study of options of long-term structure for the power sector, and ensure its completion by September 30, 1996, or such later date as the Bank may agree; (ii) no later than three months after the conclusion of the assessment of the options of the long-term sector structure (Phase I of the study), or such later date as the Bank may agree, inform the Bank of its decision on the selected long-term structure for the power sector in Romania; (iii) complete a draft electricity law for submission to the Romania Parliament no later than December 31, 1996; (iv) no later than three months after the submission to the Government of the consultants' final report on the study, provide to the Bank an action program, satisfactory to the Bank, for the implementation of the long-term sector structure; and (v) implement said action program (para 2.37 (c)); (c) take all necessary measures to ensure that its departments, agencies and enterprises, as well as local authorities, settle RENEL electricity and thermal energy bills within no more than 60 days from the date of such bills (para 4.17); (d) review annually with the Bank, no later than October 31 of each year, the progress in the implementation of the Power Sector Strategy and policy framework, and shall take corrective and other policy measures to ensure the achievement of the strategic objectives set in said Power Sector Strategy (para 2.37 (d) and 4.18); (e) (i) promptly after the commissioning of the first unit of the Cernavoda nuclear power station , inform the Bank of the commissioning of the said unit; (ii) over a period of 18 months after the commissioning of said unit, take all necessary measures, agreeable to the Bank , to separate all nuclear power activities from the power activities of RENEL; and (iii) no later than 20 months after the commissioning of said unit, establish an independent public entity to carry out such power activities (para 2.37 (a)); (f) will progressively reduce the level of subsidization of electricity price paid by households over a period of four years from the date of this Agreement, so as to ensure that by December 31, 1999, all such subsidies shall have been eliminated (para 2.21); 46 (g) maintain consumer electricity prices corresponding on average, to not less than the equivalent of US$50 (including VAT) per megawatt-hour through periodic adjustments to the consumer electricity prices in accordance with a timetable acceptable to the Bank; and also to adjust pursuant to guidelines acceptable to the Bank the consumer electricity prices if changes to the level prevailing on the date immediately preceding the adjustment of consumer electricity prices shall have occurred in the international market prices of the main fuels (coal, natural gas, and fuel oil) used by RENEL for power generation (para 2.22); (h) (i) by September 30,1995, or such later date as the Bank may agree, appoint consultants, whose qualifications and terms of reference shall be satisfactory to the Bank, to carry out an electricity and thermal energy pricing study; (ii) promptly upon its completion, discuss with the Bank the findings and recommendations of said study and (iii) according to a timetable acceptable to the Bank, provide a satisfactory program for the implementation of the actions agreed as a result of the study and the discussions with the Bank (para 2.23); and (i) (i) by September 30, 1995, or such later date as the Bank may agree, appoint consultants, whose qualifications and terms of reference shall be satisfactory to the Bank, to carry out a long-term least-cost power generation development study; and (ii) promptly upon its completion, discuss with the Bank the findings and the recommendations of said study (para 2.37 (b)). Agreements reached with RENEL 6.3 During negotiations, RENEL agreed to. (a) open and maintain a Special Account with the National Bank of Romania or another acceptable commercial Bank in Romania on terms and conditions satisfactory to the Bank and, appoint auditors whose qualifications and terms of reference are acceptable to the Bank to audit its annual accounts and the records and accounts of the Special Account, and furnish to the Bank within six months after the end of the year a copy of the audit report on the annual accounts, and of the audit report on the Special Account (paras 3.15 and 4.4); (b) produce for each of its fiscal years, after its fiscal year 1994, funds from internal sources equivalent to no less than 30% of the annual average of the Borrower's capital expenditures incurred, or expected to be incurred, for that year, the previous fiscal year and the next following year (para 4.22); (c) take such measures as may be necessary to ensure that the estimated net revenues shall be at least 1.5 times (in 1995 and each succeeding fiscal year) its estimated maximum debt service requirements for any such fiscal year (para 4.22); (d) ensure that (i) receivables on its electricity and thermal energy sales to private sector, including households, will not exceed the average of two months' sales to such customers; and (ii) payables to its suppliers will be made according to the respective supplier contract (para 4.17); 47 (e) furnish to the Bank (i) by October 31 of each year beginning with 1995, for the Bank's review the draft of a rolling five-year corporate plan setting forth for each year, the agreed medium term investment program and the sources of financing, financial targets with supporting financial forecasts showing compliance with the agreed financial performance criteria, and the progress in implementation of the Corporate Restructuring Program; (ii) by December 31 of each year beginning with 1995, the final rolling five-year corporate plan, incorporating Bank comments on the previous draft, and approved by the GoR (para 3.21); (f) carry out the proposed Project with due diligence and efficiency and in conformity with appropriate administrative, financial, engineering, environmental and public utility practices, and promptly provide, as needed, the funds, facilities, and other resources required for the purpose; and in accordance with the agreed Project Implementation Plan (para 3.20); (g) RENEL shall take all necessary measures to ensure that the Project Implementation Department will continue to be adequately staffed and funded in a manner satisfactory to the Bank (para 3.20); and (h) RENEL shall: (i) by September 30, 1995, or such later date as the Bank may agree, appoint consultants, whose qualifications and terms of reference shall be satisfactory factory to the Bank, to undertake the operations listed in paragraphs (i) to (iv) of the Corporate Restructuring Program, and have operations completed by December 31, 1997, or such later date as the Bank may agree (para 4.4); (ii) by January 31, 1996, or such later date as the Bank may agree, appoint consultants whose qualifications and terms of reference shall be satisfactory to the Bank, to undertake operations listed in paragraph (v) of the Corporate Restructuring Program (para 4.4); (iii) according to a timetable acceptable to the Bank, undertake the operation listed in paragraph (vi) of the Corporate Restructuring Program (para 2.19); and (iv) by December 1, 1995, or such later date as the Bank may agree, appoint consultants, whose qualifications and terms of reference shall be satisfactory to the Bank, to undertake the operations listed in paragraph (vii) of the Corporate Restructuring Program (para 4.4); Condition of Loan Effectiveness 6.4 A condition of loan effectiveness is that RENEL shall have provided to the Bank satisfactory evidence that it has concluded enforceable arrangements for debt repayment with each of its customers listed in an Annex to the Power Sector Strategy (para 4.17). Recommendation 6.5 Based upon the agreements reached, the proposed Project is suitable for a Bank loan of US$110 million equivalent to the Regia Autonoma de Electricitate (RENEL-Romanian Electricity Authority) for a twenty-year term, including a five year grace period at the Bank's standard variable rate of interest. 48 Annex 1.1 Page 1 of 1 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT PROVEN RESERVES OF COMMERCIAL ENERGY PR~~MA1IY SOURCES I 00 PHYSICAL UNITSt0 TONS OF t0 0 *OIL EQ IVALE T a) Natural Gas -proven -517 billion cubic meters 443 -probable -200 billion cubic meters (24-71) Ib) Crude Oil -proven -200 million tons 200 -probable -100 million tons 100 c) Lignite -billion tons 600 Id) Hard Coal -500 million tons 330 e) Hydropower potential 49 Annex 1.2 Page 1 of 1 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT ENERGY PRICES MOVEMENTS AND COMPARISON WTH IMPORT PARITY PRICES : : Nov. - Nov May May Aug Nov -June:::: I9 - 09 I 2 1993 1994 i M Crude Oil (Price to Refiners) Rer ton Domestic 117.0 134.0 80.3 105.3 87.0 76.0 93 95.0 Imported 117.0 143.0 85.3 130.4 122.0 129.0 130 100.0 Premium Gasoline 342.5 508.4 270.0 384.9 344.0 334.0 410 203.0 Regular 337.8 441.5 238.0 368.4 320.7 316.0 381 191.0 Diesel 263.2 342.3 186.0 269.4 232.6 212.0 263 156.0 Fuel Oil i) from domestic crude/ton 66.7 91.4 54.8 107.2 103.5 114.0 144 121.0 (ii) from imported 66.7 91.4 54.8 87.6 73.6 96.0 117 105.0 LGP (Households)/ton 56.7 15.6 9.3 169.1 126.3 183.0 273 145.0 Natural Gas (OOOm') (i) industry 46.7 59.2 39.0 39.0 45.4 67.0 71.6 95.0 (ii) Households 16.7 5.6 12.3 39.0 25.3 19.0 20.0 26.0 Coal and Ligrnite Ex-mine Lignite (ton) 7.1 13.3 7.9 12.6 10.5 13.6 19 166.0 (ii) Thermal Coal (ton) 7.1 30-40 25.0 29.0 24.4 26.0 26 121.0 (iii) Coke (ton)*** 7.1 55.0 117.0 146.3 07.4 120.0 120 100.0 Electricity (kWh) Average 0.024 0.052 0.032 0.04 0.04 0.047 0.05 100 Industry 0.025 0.050 0.03 0.04 0.04 0.049 0.052 Households 0.011 0.0036 0.012 0.05 0.03 0.023 0.024 Thernal Enrg Industry 7.8 4.2 8.0 12.0 15.0 18.0 19.0 138.0 Households 3.7 1.2 3.0 14.0 9.4 7.0 7.3 52.0 Exchange Rates (Lei/US$) 60 180 300 615 950 1750 1900 * As % of price of Imported Electricity during the winter season. ** As % of marginal fuel cost Used by metallurgical plants ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT RENEL'S OR GA NIZ4 TION STR UCTURE IN 1995 Electric and Thermal GeneralSecret eand Energy Generation _ Electric Power Station Legilsl sion Department Subsidiaries |_ General Inspection National Energy Territorial Energy _____________ _ _Dispatcher Dispatchers Human Resources Corporate Board Management Division of Administration Electricity Transmission I _ and Distribution Departen Elcti Newrk Synthesis Division President-Director Subsidiaries General Finance, Trade, Assets I FCNE Cernavoda Division | Counsellors m l l~~~~~~~~~~~ ROMAG DrobetaI International Affairs _Nuclear and Engineering _ o Division Department FCN Pitesti ICN Pitesti l CITON Bucuresti | ISPE ISPH GEOTEC Research and Engineering Department ICEMENERG Project Implementation Department Information and Telecommunication Center | CFP l 51 Annex 2.2 Page 1 of 2 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT EXISTING POWER GENERATION CAPACITIES JULY - 1995 Installed Capacity Plant/Fuel Type (MW) % of Total Total Thermal of which: 16,114 73.9 (a) Lignite 7.258 33.3 (i) Condensing 5,820 26.7 (ii) Co-generation 1,438 6.6 (b) Coa 1.260 5.8 (i) Condensing 1,260 5.8 (c) Oil and Gas 7J96 34.8 (i) Condensing 2.770 12.7 (ii) Co-generation 4,826 22.1 Total Hydropwer Plants 5.694 26.1 TOTAL 100.0 52 Annex 2.2 Page 2 of 2 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT MAIN THERMAL AAD HYDRO POWER PLANTS IN RENEL SYSTEM .. .. .. .. .. .. ... COMMISSIONING INSTALLED FUEL PLANT NAME ;;: PERIOD . TE- UCAPACITY .: UNTS. .MW. .TY THERMAL 1. Turceni 1978-87 2310 7 (330) lignite 2. Rovinari 1972-79 1720 4 (330) + 2 (220) lignite 3. Mintia 1969-80 1260 6 (210) brown coal 4. Craiova 1965-76 1035 2 (315) + 2 (100) lignite 1 (100) + 3 (50) 5. Braila 1973-79 960 1 (330) + 3 (210) oil/gas 6. Brazi 1961-86 910 2 (200) + 2 (105) oil/gas 6 (50) 7. Ludus 1963-67 800 2 (200) + 4 (100) gas 8. Borzesti 1955-69 655 2 (210) + 1 (60) oil/gas 2 (50) + 3 (25) 9. Bucuresti Sud 1965-75 550 2 (125) + 2 (100) oil/gas 535 2 (50) 10. Galati 1969-84 3 (105) + 1 (100) gas(coke/ 2 (60) furnace) 11. Doicesti 1952-67 520 2 (200) + 6 (20) lignite 12. Paroseni 1956-64 300 1 (150) + 3 (50) brown coal 13. Fintinele 1954-66 250 1 (100) + 1 (50) gas 4 (25) 14. Deva 1260 coal HYDRO 1. Portile de Fier 1970 1050 6 (175) 2. Portile de Fier II 1985 510 8 (27) 3. Retezat 1986 335 2 (167.5) 4. Mariselu 1977 220.5 3 (73.5) 5. Arges 1966 220 4 (55) 6. Loru 1972 216 3 (170) 7. Bicaz 1960 210 6 (35) 53 Annex 2.3 Page I of 2 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT THE CERNAVODA NUCLEAR POWER PROJECT 1. The Cernavoda nuclear power project was started in the mid-1970's by the Government of Romania, with Canadian and Italian financial assistance of about US$400 million in suppliers credits for the initial phase of construction of a 5x700 MW power station. The technology is based on CANDU-6 nuclear reactor of Canadian design, using natural uranium as fuel and heavy water as coolant and moderator, and a General Electric Turbogenerator. Engineering services and project management were to be provided by a Consortium (AAC) of Atomic Energy of Canada Limited (AECL), and Ansaldo-Impianti of Italy. Equipment and materials were to be mainly of foreign origin. 2. Construction commenced on all 5 units in 1980, but attention was focused on Unit I after 1985, by which time the civil works construction on all the units had reached various stages of completion. Following the decision of the Govermnent to prepay its foreign debts, it was decided to complete the project using primarily local inputs. As such, all foreign contracts on the project were terminated. From hence, construction proceeded slowly due to shortages in funding and lack of experience. 3. In 1990, the new Government, in the face of difficulties in continuing with project construction, sought Canadian and Italian Governments' financial assistance in a loan of US$415 million - US$315 million from Canada, and about US$100 million from Italy - mainly to finance engineering management services by AECL and Ansaldo-Implianti and for 18 months operational and management services by the consortium after commissioning of the unit. At that time, construction of Unit I was about 55-60% complete, Unit 2 about 31%, and the rest were at much lower levels of completion. At that time, about US$1.2 billion was needed to complete Unit 1. Following initial review to ensure that previous construction works met required engineering and safety standards, work has proceeded relatively smoothly on Unit 1 with temporary suspension of work on the other units. Orders for equipment that had been placed with local firms for Unit 2 proceeded. According to RENEL, nearly 70% of the equipment for Unit 2 ordered before 1991 have been completed and delivered to site. By September 1994, construction of Unit 1 had reached about 95% completion and was expected to be commissioned by April 1995. At present, all works are expected to be completed with the first delivery of power to the national power transmission grid in November 1995, and commissioning is scheduled for March 1996, when commercial operation could start. RENEL is now seeking joint ventures with foreign investors for build-operate-and-transfer (BOT) arrangements or other types of non-recourse financing, in which payment would be made to the foreign partners in electricity supplies, to complete Unit 2. 4. The construction of Unit 1 has been accorded a national priority status, and initially, it was the intention of the Government to finance the entire development, including the debt service obligations, from the state budget. However, since 1992, the Government has not been able to meet the obligations in view of the budgetary constraints. As such, RENEL and other state agencies have been called upon by the Government to fill in the local financing gap. Factories commissioned to provide equipment and materials for the project are granted preferential access to credits and foreign exchange. 54 Annex 2.3 Page 2 of 2 5. The Atomic Energy Agency (IAEA) has conducted separate inspections of the construction of Unit land has found the works satisfactory. Most of the recommendations of the IAEA have been fully complied with. The rest are gradually being implemented. A post-commissioning inspection is expected in 1996. ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT ELECTRICITY TARIFF STRUCTURE (Effective June 6, 1995) Voltage Level Prices for the active electric power Prices for the reactive electric power delivered l_____________________________________ ._________________ ____________ to the consum ers A. Differentiated binomial rate B. Differentiated C. Simple binomial D. with a monthly monomial rate rate Common medium power monomial factor less than rate 0.92 For demand For energy lei/kW/year lei/kWh lei/kWh lei/kWh lei/kWh lei/kVarh v Peak Off- Peak Off- Peak Off- For For Hours Peak Hours Peak Hours Peak subscribed Energy hours hours Hours demand 1. Low voltage 354000 152292 175.7 63.7 264.8 94.7 154.686 90.0 120.4 12.0 (0.1-lkv including) 2. Medium 222504 93372 159.3 58.0 214.4 79.3 128.844 75.0 99.0 9.9 voltage (1-110 kv) 3. High voltage 142560 61404 149.6 54.8 183.1 68.2 107.388 65.3 84.1 8.4 (110 kv and higher) J _ P o R ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT STRUCTURE OF HEAT PRICES (Effective June 6, 1995) Thermal Energy on Consumers and resellers connected to the output of the Consumers and resellers connected at the transport networks* pressure levels cogeneration plant or thermal plant* Rate for maximum thermal Rate for Energy Rate for maximum thermal Rate For Energy demand contracted per year power contracted per year Lei/year lei/Gcal For 1 Gcal/h lei/year lei/Gcal -industrial consumers x 22260 x 24860 -domestic consumers x 10050 x 11230 2. steam, according to the pressure: 18818844 28996 27094500 30603 2.2 Pressures greater than 19 ata: 2.2.1 from turbines 18818844 33163 27094500 35063 2.2.2 from boilers 18818844 38573 27094500 40165 3. Unreturned condensed and demineralized water 2890 lei/cubic m. 4. Unreturned hot water and demineralized water 1350 lei/cubic m. * The development levy is included in the price of heat X a " N) W1 > ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT A VERA GE ELECTRICITY AND THERMAL ENERGY PRICES (Effective June 6, 1995) A. ELECTRICITY PRICES CONSUMER CATEGORY Lei/KWh US Cents/KWh Average Consumers 95.11 5.0 High Voltage 88.50 4.6 Medium Voltage 104.98 5.5 Low Voltage 126.51 6.7 Households 46.0 2.4 B. THERMAL ENERGY PRICES U1 Lei/Gcal US$ Gcal Steam (pressure up to 19 Atmopheres) for Industry 19.0 (i) Consumers connected at plant gate (Industry) 39,714 20.94 (ii) Consumers connected to transmission 44,480 network 23.4 Hot Water (Household) 13800 7.3 Footnote: 1. Exchange rate Lei 1900/US$ 2. Prices to all consumers other than households includes 18% VAT. 0Q 1-h N) Annex 2.5 58 Page 1 of 2 RONM AMA POWER SECTOR REHABITATION AND MODERNTZATION PROJECT ROMANIA - RENEL DAILY LOAD CURVE - (SUMMER) _ _ _ _ _ _L_ t X I I 1_ _ _1 7c,: 7.2 _ _ [ 5.4 _ _ _ __ _ _ _ o 0 c 12 16 20 2- .TI.E (HOURS) O SUMMER c-1) SUMMER c-2) 0 SULA.JER b-1) A SUU.JER b-2) ROMANIA - RENEL DAILY LOAD CURVE - (WINTER) 7 O 4 e 12 17 20 24 TIME (HOURS) ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT ANNUAL LOAD DURATION CURVE 10 7 VIN. 5 a M 00 3 2 1 1 2 3 4 5 6 7 8 9 10 1 1 12 MiLi Months OQ~ Non RENEL Plants Cod'i Hydrocarbon r Hydro Imports 0 60 Annex 2.6 Page 1 of 2 Romania Power Sector Rehabilitation and Modernization Project ELECIRIC ENERGY BALANCE 1989-2000 < --- -Actual ---> Estimate <-----Forecast---> A. Demand (TWH) 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 1. Industry 55.6 41.3 35.1 30.1 29.3 29.4 29.4 29.3 29.1 29.0 29.1 29.0 Mining 6.5 6.0 7.1 5.5 5.7 5.0 4.9 5.0 5.0 5.1 5.2 5.2 Mettallurgy 15.3 11.2 9.1 6.9 6.1 6.0 6.0 6.0 6.0 6.0 6.2 6.2 Chemical 12.3 9.3 6.4 5.6 5.3 4.9 5.0 5.0 5.0 4.8 4.5 4.5 Machine Building 8.8 6.7 4.7 4.2 4.4 4.3 4.3 4.4 4.4 4.4 4.4 4.3 Light Industry 4.0 3.8 3.6 2.4 2.5 3.3 3.3 2.9 2.9 2.9 3.0 3.0 Construction Materials 2.7 2.5 1.3 1.6 1.7 1.8 1.8 1.8 1.8 1.8 1.8 1.8 Wood Processing 1.1 0.4 0.5 0.4 0.5 0.6 0.6 0.6 0.5 0.5 0.5 0.5 Other* 4.9 1.4 2.4 3.5 3.1 3.5 3.5 3.6 3.5 3.5 3.5 3.5 2. Agriculture & Construction 5.7 4.5 5.1 2.8 3.1 2.7 2.8 2.8 3.0 3.1 3.2 3.5 3. Trans. & Telecom. 2.9 2.6 1.8 2.8 2.0 2.0 2.2 2.2 2.5 2.7 2.7 3.0 4. Commerce & Services 2.9 3.2 2.8 3.4 4.2 2.6 3.1 4.0 4.0 5.0 5.3 5.8 5. Residential 4.3 5.3 6.7 7.6 6.9 6.6 7.0 7.3 7.7 8.0 8.4 8.7 6. Total Demand 71.4 56.9 51.5 46.7 45.5 43.3 44.5 45.6 46.3 47.8 48.8 50.0 B. SUPPLY 7. Gross Generation (TWH) - - - - - - - - - - - - a. RENEL Hydro Plants 12.5 10.9 14.2 11.6 12.7 13.0 12.3 12.5 12.6 12.7 12.8 12.6 Thermal - - - - - - - - - - - - (i) Lignite and Coal 29.9 21.1 17.2 22.1 22.7 23.3 26.6 26.6 26.1 25.1 26.2 26.5 (ii) Oil and Gas 30.1 26.1 22.7 18.2 18.5 17.2 18.0 17.4 16.7 16.9 16.2 16.4 (iii) Nuclear - - - - - - - 1.6 3.1 4.9 4.9 4.9 (iv) Subtotal Thermal 60.0 47.7 39.9 40.3 41.2 40.5 44.6 45.6 45.9 46.9 47.3 47.8 (v) Total RENEL 72.5 58.2 54.1 51.9 53.9 53.5 56.9 58.1 58.5 59.6 60.1 60.4 b. Auto Producers 3.3 2.7 2.2 1.8 1.5 1.5 1.2 1.2 1.2 1.2 1.5 1.5 (vi) Total Gross Generation 75.8 60.7 56.3 53.7 55.4 55.0 58.1 59.3 59.7 60.8 61.6 61.9 Less: (vii) Station use 7.6 7.6 6.1 6.1 5.8 6.2 6.9 7.0 6.6 6.6 6.1 6.0 Add: (viii) Net Imports 7.8 9.5 7.0 4.4 1.9 1.2 (ix) Net Available 76.0 62.8 57.2 52.0 51.5 49.7 51.2 52.3 53.1 54.2 55.5 55.9 Less: (x) Network Losses 4.6 5.9 5.7 5.3 5.9 6.1 6.6 6.7 6.8 6.4 6.7 5.9 (xi) Net Consumption 71.4 56.9 51.5 46.7 45.5 43.3 44.5 45.6 46.3 47.8 48.8 50.0 ** Other Compromise: Cellulose and paper; glass and porcelaine and food processing. 61 Annex 2.6 Page 2 of 2 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT ELEC7RTC POWER BALANCE 1989-2000 < ---------------------Actual---------------------------- > Estirate < -------Forecast---------> RENEL SYSTEM 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 C. Installed Capacity (GW) Hydro Plants 5.5 5.6 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 Thermal Plants (i) Conventional 15.4 15.0 14.9 14.9 14.9 14.8 14.6 14.4 14.2 14.0 12.4 12.2 (ii) Nuclear 0.7 0.7 0.7 0.7 0.7 0.7 (iii) Sub-total Thermal 15.4 15.0 14.9 14.9 14.9 14.8 15.3 15.1 14.9 14.7 13.1 12.9 (iv) Total Installed 20.4 20.6 20.6 20.6 20.6 20.5 21.0 20.8 20.6 20.4 18.8 18.6 D. Maximum Power Generated Hydro Plants 2.0 2.0 2.0 2.0 2.0 1.8 1.8 1.8 1.9 1.9 2.0 2.0 Thermal Coal and Lignite 4.3 3.9 3.5 3.3 3.2 3.2 4.0 4.0 4.0 3.9 3.8 3.7 Oil and Gas 4.5 4.4 3.7 3.6 3.3 3.4 3.4 3.1 3.2 3.5 3.6 3.6 Nuclear - - - - - - - 0.7 0.7 0.7 0.7 0.7 Total Thermal 8.8 8.3 7.0 6.9 6.5 6.6 7.4 7.7 7.9 8.1 8.1 8.0 Total (Hydro & Thermal) 10.8 10.3 9.0 8.9 8.5 8.4 9.2 9.5 9.8 10.0 10.1 10.0 E. Auto Producers 0.3 0.3 0.3 0.2 0.1 0.1 0.1 0.2 0.3 0.3 0.4 0.5 F. Total Power Generated 11.1 10.6 9.3 9.1 8.6 8.5 9.3 9.7 10.1 10.3 10.5 10.5 Net Power Sent Out 9.8 9.3 8.2 8.0 7.6 7.6 8.2 8.3 8.6 9.2 9.4 9.4 Imports 1.3 1.4 1.5 1.5 0.4 0.3 - - - - - - Reserve Margin - - - - - - - - - 0.5 0.4 0.3 System's Maximum - - - - - - - - - - Demand (GW) 11.3 10.7 9.7 9.5 8.0 7.9 8.2 8.3 8.6 8.7 9.0 9.1 System Load Factor (%) 88.0 79.0 75.0 75.0 74.0 73.0 73.0 73.0 72.0 72.0 71.0 71.0 ** Estimatc of net power capacity at time of system's peak. Rehabilitation provides reserve margin to improve reliability. ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT PROPOSED RENEL INVESTMENT PROGRAM (1994-2000) (US$ MILLION - JANUARY 1994 PRICES) 199 19k 1919999 12 TOTAL t; DD f t:: D ; 0 00: 0; y :0000~~~~~~~~~~~1995-20W0;0 TOTAL 250.3 338.5 466.9 509.3 407.9 350.0 2,322.9 NEW CAPACITY 191.2 211.9 293.0 319.5 255.0 219.1 1489.7 REHABILITATION 59.1 126.6 173.9 189.8 152.9 130.9 833.2 A.:. THERMAL - SubtotaI 140.0 188.7 155.0 186.0 149.0 105.0 923.7 NEW CAPACITY 108.5 95.2 - - - - 203.7 REHABILITATION 31.5 93.5 155.0 186.0 149.0 105.0 720.0 B. HYDRO ELECTRIC - Subtotal 29.7 49.7 43.8 175.7 136.0 73.5 508.4 NEW CAPACITY 28.3 48.3 43.8 175.7 136.0 73.5 505.6 REHABILITATION 1.4 1.4 - - - - 2.8 C .. ELECTRIC NETWORK Sub-total 75.0 80.9 181.6 81.9 40.0 66.5 525.9 NEW CAPACITY 48.5 51.8 139.9 81.9 40.0 66.5 428.6 REHABILITATION 26.5 29.1 41. 7 - - - 97.3 D.M MISCELLANEOUS. DISTRICT HEATING* - 6.5 2.6 2.2 1.0 3.1 15.4 ENVIRONMENT** 5.6 9.7 80.7 60.3 78.5 72.3 307.1 E. EMS/SCADA - 3.0 3.2 3.2 3.4 29.6 42.4 * Rehabilitation and improvement for heating transmission systems. ** Includes ash-handling and disposal systems, land reclamation, and other pollution abatement measures. Includes cost of environmental measures under proposed Project (See Annex 3.2). ox 0l 63 Annex 2.8 Page I of 6 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT STATEMENT OF POLICIES FOR THE POWER SECTOR February 23, 1995 Mr. Michael Wiehen Director Europe and Central Asia Department I The World Bank 1818 H St., N.W. Washington, D.C. 20433 Re: Statement of Policies for the Romanian Power Sector Dear Mr. Wiehen, The Government of Romania (GoR), through its Ministry of Industries (Mol) and the Romania Electricity Authority (RENEL) with the assistance of Bank staff, has completed preparation of the propose Power Sector Rehabilitation and Modernization Project (the proposed Project), for which we have request Bank assistance in its financing and implementation. This project is designed to support a comprehensive reform of the power sector to bring about efficiency improvements, and to provide for reliable electricity supply at least-cost, while addressing environmental concerns. In support of the above request, I hereby outline the GoR's policies and objectives for the electricity sector and the program of actions (Attachment A) the GoR is committed to take to achieve its objectives. Power Sector Policy and Strategy The main objectives of the GoR's policy are to meet electricity demand in the most economic manner, to improve the efficiency of the sector, and to improve reliability of supply. The strategy to achieve these policy objectives calls for the: * implementation of radical, comprehensive and stepped reforms to the sector organization and its legal framework which will create conditions for effective competition; * adaptation of the sector institutions to a market-oriented economy through corporate restructuring to ensure autonomy and accountability; * adoption of least-cost development program which considers all feasible alternatives, including resources available to the country, including rehabilitation and modernization of existing g facilities and demand side management; * implementation of pricing policies that would ensure sector economic viability and provide private sector participation; 64 Annex 2.8 Page 2 of 6 * establishing conditions for Romania's greater participation in a larger regional power market in Europe; and * taking of actions to minimize environmental impact and promote conservation. Sector Reforms The GoR is committed to fundamental, comprehensive and stepped reforms in the power sector. In 1990, in order to separate policy and strategy functions from entity operations and management, the GoR created RENEL, as an autonomous public electric power utility. Additionally, a number of actions to restructure RENEL are to be continued as an integral part of the proposed Project. A further step to bring about the desired improvement in efficiency is to create conditions for the participation of independent operators, both public and private, in a competitive environment. This will require the implementation of fundamental reforms to the sector structure and regulatory framework. TO develop a sound basis for carrying out the reforms, the GoR has decided to engage the services of International Consultants to undertake a "Study of Options for the Long-Term Structure of the Power Sector" (the Study). The Study will evaluate, starting from the existing strategy for the energy sector, alternative forms of sector structure presenting advantages and opportunity of the proposed alternatives, and their associated legal and regulatory aspects. The GoR has established a High Level Interministerial Committee to oversee the Study on its behalf. The GoR will review progress periodically, as well as discuss the results of the Study with the Bank following its completion. The GoR will analyze the final report, and will decide on the solution for restructuring the sector. The solution will be implemented in agreement with a stepped action plan,, which will be established in consultation with the Bank. The GoR has agreed the terms of reference for the Study with the Bank, and secure funding from the United States Agency for International Development (USAID). Electricity Law To provide the legal basis of the reform, and to create the enabling conditions for the participation of publicly-owned and private independent operators in a competitive environment, the GoR is preparing an Electricity Law (the Law). In the process of preparing the Law, the GoR is ensuring that its policy objectives are duly reflected in the draft, and the rules of the Study can be properly implemented. To this end, the Law will: * define the roles of the Government as policy maker, as the owner of the public utilities, and as regulator; * assure the introduction of competition in the generation sector for increasing efficiency and will permit the participation of both public and private producers; * define the segments of the industry that would be subject to the law, and define principles of granting concessions and setting electricity prices; * provide for the establishment of an independent regulatory body. Annex 2.8 65 Page 3 of 6 Since the preparation of the law will be furnished after the final decision regarding the structure adopted by the Government in legal terminology and will permit a wide rage of schemes for the participation of the private sector. Following approval of the Law by our Parliament, the GoR intends to seek Bank assistance to help develop detailed regulations for the power sector and to establish the Regulatory Body. Corporate Restructuring of RENEL Based on its own strategy for the energy sector, the GoR endorsed the program of corporate restructuring proposed by RENEL into a modern, commercially viable public utility. As a first step, to focus RENEL's activities on the primary activities of electricity and heat production and supply, part of the non-core activities of its engineering and technical institutes and of construction, repairs and manufacturing subsidiaries will be separated into independent commercial companies. In addition, all nuclear power activities will also be separated into an independent public entity. This Government Decision and the logistical and legal actions to effect separation will be formally issued by the Government in accordance with the timetable agreed with the Bank. In the medium term, the program will include the improvement of RENEL's management, mainly the accounting and financial systems, and will be implemented with the assistance of foreign consultants. In the transition period to corporation, management contracts have been introduced as a means of improving performance, profit and responsibility within the RENEL. Pricing In order to promote the efficiency of the sector, as well as to provide incentives for private sector participation, the policy of GoR is to set electricity prices to all consumers to reflect the economic costs of supply. However, for social reasons the Government wishes to protect low income households from large price increases, and pricing policies would be designed with this consideration in mind. To establish the basis for future pricing setting, the GoR has decided to undertake an Electricity and Heat Pricing Study with the assistance of consultants. In the interim period, prices will be set in accordance with the agreement with the Bank under the Structural Adjustment Loan (SAL) to maintain their levels in real terms at an average of US$50/MWh, including VAT. Inter-enterprise arrears The Gor has taken measures that will lead to the graDual reduction of inter-enterprise arrears and to the prevention of any re-emergence of them. RENEL has prepared a Financial Recovery Plan that includes the necessary measures to achieve this objective. The GoR will strictly enforce compliance with those measures. Under the FRP, RENEL will reduce operating costs and minimize arrears from its customers. Sector Investments and Development Plans The GoR has established that rehabilitation of the existing power supply facilities provides the most cost effective means of restoring capacity and improving and simultaneously reducing the power plants' impact on the environment. The GoR, therefore, gives a high priority to the economic rehabilitation, and has prepared a medium-term (1994-2000) rehabilitation and modernization program with a total cost of US$2.1 billion. The first phase of this program, which will also include retirement of old and inefficient units, is to be implemented under the proposed Project with financial assistance from the Bank and the other multilateral agencies. Meanwhile, the GoR will 66 Annex 2.8 Page 4 of 6 undertake a Least-Cost Power System Development Study, with the assistance of consultants, to establish the basis for the long-term development of the sector t meet future demand in the most economic manner. The study will examine the economic merits of all feasible alternatives, including further rehabilitation of existing plants, completion of the suspended thermal and hydropower projects, and also units 2-5 of the Cernavoda Nuclear Power Plant, and new feasible alternative plant candidates The GoR will discuss the results of the study with the Bank, and will adopt the optimal investment program as a basis of the future development of the sector. Under the proposed Project the GoR together with the Bank will carry out annual review on ongoing an planned investments in the sector, including the sources of financing. Energy Conservation Because of our past industrialization strategy, which was based on the development of energy- intensive industries, and the lack of incentives to use energy efficiently, our intensity of energy intensity is one of the highest in Europe. The GoR recognizes the high economic and environmental dividends to the country of reducing energy intensity. Our strategy to reduce energy intensity focuses both on the supply and demand sides. On the supply side, the rehabilitation and modernization program for existing facilities will lead to substantial reduction of losses. On the demand side, we believe that correct pricing policies, and the on-going macroeconomic reform measures, will play an important role in conserving energy. Additionally, our pursuit of industrial restructuring and privatization will lead to significant energy savings. In addition, it is the intention of GoR to promote aggressive public awareness of the benefits of conservation, for which the Romanian Agency for Energy Conservation was established, in 1991. Environment Protection The GoR strongly believes that sustainable development requires environmental protection. The Government has developed an environmental strategy with the assistance of the World Bank, and other international agencies. The Government intends to implement the measures stated in strategy document in the most economic manner, in order to minimize the environmental impact of the production and use of electricity. The ecological aspect of the proposed Project is in conformity with this strategy. Conclusion The GoR is confident that the program outlined above will have a very positive impact on the country's macroeconomic prospects. The Government is convinced that the implementation of the Project is absolutely necessary for future efficient operation and development of electricity sector and undertake the support of the World Bank for the program, through this and future projects, and looks forward to a continued cooperative and successful dialogue which will assist in placing Romania on a path to stable and sustained economic growth. Your sincerely, Mircea Cosea Minister of State Chairman of the Council for Coordination, Strategy and Economic Reform Attachment A STATEMENT OF POWER SECTOR POLICY Action Program Matrix MEASURE OBJECTIVE SHORT-TERM ACTIONS MEDIUM-TERM ACTIONS 1. SECTOR REFORMS To provide the necessary elements for a. TOR agreed with the Bank in April, 1995. Continue implementation of taking decisions to support fundamental reform. (a) Study of options for the reform of the sector aimed for b. A High-Level Interministerial Commnittee to oversee the Study long-term power sector introducing competition and the on behalf of the GoR; established a local Interministerial structure. participation of Counterpart Working Group. independent operations. c. Concluded arrangements for funding with USAID in March 1995. d. Initiate study in July 1995. e. Decide future sector structure, and initiate actions on development of regulatory framework by January 1997 establish, including creation of the regulatory agency. f. Complete study by September 1996, and initiate discussion of results with World Bank, USAID by November 1996. (b) Electricity Law To define the legal framework for Submit Draft Law satisfactory to the Bank to the Romania Passage of Law by operation, management and Parliament by Parliament and its adoption. development of the power sector, the December 31, 1996. role of the Government and of the economic agents involved, to establish the mechanism of price setting and concessions, to create conditions for the participation of both public and private and private independent producers, to provide the establishing of an independent regulatory body in order to increase the efficiency. _Ix °l MEASURE OBJECTIVE SHORT-TERM ACTIONS MEDIUM-TERM ACTIONS 2. RENEL CORPORATE To improve institutional, management, a. Agree TOR with Bank Continue corporate RESTRUCTURING financial and technical operational restructuring in line with the efficiency. b. Separate nuclear power activities into an independent public approved strategy. utility no later than 20 months after the completion of the first nuclear unit; and c. Appoint consultants by September 1995, to assist RENEL in implementation of corporate restructuring program. 3. PRICING Adopt price structures and levels that a. Continue with SAL agreement to adjust prices periodically in a. Complete pricing study ensure economic efficiency and sector accordance with exchange rate and changes in put fuel prices; by June 1996 financial viability. b. Agree with the BANK on TOR for electricity and thermal b. Adopt new tariff system energy pricing study by September 1995; and by December 1996. c. Appoint consultants by December 1995 for lead research component of study and complete by September 1996. 4. LEAST COST POWER To provide sound economic basis of a. Agree TOR with Bank by July 1995. Adopt least cost power GENERATION investment selection. generation expansion DEVELOPMENT b. Appoint consultants by September 1995. program by end-1996. co STUDY c. Complete Study by September 1996. d. In interim, conduct annual reviews on October 31 of each year of medium-term investments with the Bank. a. x 0 Annex 3.1 69 Page 1 of 9 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT DETAILED DESCRIPTION OF REHABILITATION CANDIDATES Braila 1. The power station is located on a 21 hectare site within the Chiscani agriculture area, approximately 13 km south of the town of Braila. Considerations in the siting of the station were the proximity of the River Danube for supplies of cooling water, access to the rail network for delivery of fuel oil and easy access to the gas supply system. 2. Commissioning of Units 1 and 2, each of 210 MW capacity, took place during 1973. Unit 3 also of 210 MW capacity was commissioned in 1974 and the final phase to date, Unit 4, of 330 MW capacity, was commissioned in 1979. The total station capacity is therefore 960 MW. There is space to extend the generating capacity further by adding on to the turbine room and boiler house adjacent to Unit 4 and there exists a spare flue gas duct entry point to further utilize No. 2 chimney. 3. Unit 1 consists of two Ramzin type once through boilers each with an output of 325 tons per hour at 540°C, 137 bar supplying steam to a three cylinder reheat turbine. The boilers are designed for firing oil and gas. The turbine systems include eight stages of feedwater heating and three off-takes for district heating. The rated output of the turbine generators is 210 MW without any extraction for district heating. Cooling water and raw water for the water treatment plant is taken from the River Danube and no cooling towers are installed. Power is generated at 15.75 kV and 50 Hz and supplied to the switchyard at 220 kV via the generator transformer. The generator cooling system utilizes hydrogen and water. 4. The first three units were of Russian design; two half-duty boilers are provided for each turbine-generator. Unit 4 is of Romanian manufacture based on a Deutsche Babcock boiler design and a Rateau Schneider turbine design. All the boilers are of once-through type, and are designed to burn both oil and gas. 5. Commissioning of Unit 1 was completed during 1973 and full design output was achieved during the manufacturer's performance tests. The boilers were not fired on oil in the first two years and since then the ratio of gas/oil firing has been in the ratio of about 77/23 percent heat input for Unit 1. 6. In the period 1985-1992 (inclusive), the unit operated for an average of 80 percent of each year at an average capacity factor of 64 percent. The highest availability occurred in 1983 when the unit operated for 98 percent of the year at an average capacity factor of 86 percent. The unit has operated for 134,467 hours until being shut down for maintenance on 16 March 1993. 7. The majority of operational problems on units 1-3 have been on the boiler plant and most of these boiler problems are associated with oil firing. 8. Unit 1 at Braila (and by extrapolation Units 2 and 3) are generally fit for continued service. They require new burner systems, increased surveillance and some replacement of high temperature piping and for oil firing the fitting of sootblowers and improved steam air heaters. The turbine needs some repairs to each of the cylinders, and the generator needs a new exciter and some attention to the hydrogen sealing systems. The condensate system requires replacement of many valves and some improvements to the design and control of the feed water heaters. The control systems should be totally replaced and a major upgrade of the chemical services is required. Brazi 9. Brazi Power Station is located approximately 12 km south of the city of Ploiesti and forms part of an industrial complex of oil refineries and chemical plant. A prime consideration of the siting of the power station 70 Annex 3.1 Page 2 of 9 was the availability of refinery crude and a natural gas supply from the adjacent oilfields. Water supply to the site is provided from two sources. Boreholes supply 1/3 of station needs while the nearby river Prohova supplies the remaining 2/3 of requirements. The industrial complex is situated on the main rail link between Ploiesti and Bucharest. 10. The Brazi installation consists of two power stations. Brazi 1, the older site, consists of nine boiler/turbine units, the first of which was commissioned in 1961 (Unit 1) and the last (Unit 9) in 1972. 11. Units 1-4 at Brazi 1 are 50 MW back-pressure units supplying process steam to the local refinery and hot water (via steam/water heat exchangers) for district heating in Ploiesti. Units 5 and 6 are 100 MW generating units while Unit 7 is a further 50 MW back-pressure unit supplying process steam. Units 8 and 9 are identical 200 MW generating units of a prototype design. 12. Brazi 2 Power Station consists of one 50 MW back-pressure turbine supplied by two boilers of 420 t/h capacity. In addition, there are four boilers of 100 t/h capacity and three boilers of 105 t/h capacity supplying steam at 16 bar for the district heating scheme. 13. Two smaller boilers of 50 t/h supply process steam at 35 bar, and one auxiliary boiler of unknown capacity is available for site services. 14. Brazi Unit No 9 comprises of a single boiler of 675 tfh capacity supplying steam to power a 200 MW turbine-generator set. 15. The boiler is of a La Mont design and includes an economizer, superheater, reheater and regenerative air heater. Although designed to be fired on Romanian fuel, supply problems have led to the use of lower grade imported fuel with a consequential deterioration in combustion parameters. 16. The steam turbine consists of single high pressure, intermediate pressure and low pressure cylinders with the steam being exhausted to an underslung dual flow condenser. Bled steam is extracted from various points for use in the unit's five low pressure heaters, deaerator and two high pressure heaters which raise the temperature of the feedwater prior to feeding it into the boiler. 17. Electricity is generated at 15.75 kV/50 Hz and supplied to the switchyard via the generator transformer. The generator cooling system uses hydrogen circulated within the stator casing. 18. Unit No. 9 at Brazi I power station has only operated for the equivalent of eight years in its 20 year history. Since being commissioned in 1972, the unit has experienced a number of problems which have restricted operational times to those listed below. 1972 - 1974 6,400 hours 1974 - 1987 52,100 hours 1987 - 1992 14,000 hours Total 73,300 hours 19. Although it has been reported that the majority of problems experienced on the plant have been associated with the boiler and fuel systems, aspects relating to unresolved design features, the use of unsuitable fuel oils and the unavailability of fuel oil have also contributed to the low service factor. Deva 20. The power station is located on a 231 hectare site 7 km from the town of Deva in the South Eastem part of Transylvania. Considerations in the siting of the station were access to the rail network for delivery of 7 1 Annex 3.1 Page 3 of 9 coal from the mining areas of the Valea Jiuliu basins and proximity to the Mures River for supplies of cooling water. 21. Construction of the station commenced in 1964 with the commissioning of the first stage of four Units in the period 1969-1971. Unit 5 was commissioned in 1977 while the final development was the commnissioning of Unit 6 in 1980. The total design and supply of the first stage was from the USSR, while stages 2 and 3 include equipment of Romanian manufacture. 22. The six units are each of 210 MW output and are arranged for independent operation with a combined output of 1,260 MW. All Units are virtually identical and consist of two boilers each supplying steam to a single 210 MW turbine generator. 23. The boilers are of the once-through type and include an economizer, superheater, reheater and tubular air heater and precipitators. 24. The boilers are designed for firing coal having a heating value of about 3500 kCal/kg (15.4 MJ/kg) with natural gas or fuel oil as a supplementary fuel for start up and flame stabilization. 25. Each turbine consists of one high pressure cylinder, one intermediate pressure cylinder and one double flow low pressure cylinder. Steam is exhausted to a split condenser with bled steam extracted to four low pressure heaters, a deaerator and three high pressure heaters. Bled steam from the intermediate pressure cylinder also passes to heat exchangers that heat the circulating district heating water. 26. Condenser cooling water is provided from the river or from forced draught evaporative cooling. Make- up water is supplied from the river via a common water treatment plant and each Unit is fitted with a condensate polishing plant. 27. Power is generated at 15.75 kV, 50 Hz and supplied to the switchyard at 220 kV via generator transformers. The generator cooling system utilizes demineralized water for stator cooling and hydrogen for rotor cooling. The generator is directly driven from the turbine at 3000 rev/min. Power is exported to the grid at 110 kV and 220 kV. 28. Development of Mintia power station at Deva, in Transylvania commenced with the construction of the first four 210 MW brown coal fired units in the late 1960s. Design, manufacture and construction supervision was almost entirely by manufacturers from the former USSR, and in common with much Russian equipment was generally extremely robust. Although automatic control systems were included, the Russian technology is of a type that was outmoded by Western European standards even when new. Each Unit consists of two once-through Benson type boilers supplying steam to a single reheat turbine. 29. Unit 1 started operation in 1969 closely followed by Units 2-4. Subsequent development saw commissioning of two further 210 MW Units (5 and 6) in 1977 and 1980 basically to the same design, but with a much higher Romanian content. The station therefore now consists of six similar units with a combined capacity of 1260 MW. 30. Unit 1 turbine has generally operated whenever available since commissioning and has run for 171, 000 hours to date. The boilers have run for 164,000 and 161,000 hours to date having on occasions being shut down for repairs or to reduce generation while the turbine remains on load. 31. Overall availability has averaged about 85 per cent with an average capacity factor of about 60 per cent. The station claim the Unit is still able to generate 210 MW when required although average output when operating is considerably below this and full load was not observed during the inspection period. 32. Operating data have not shown discernible trends in the last few years. Major renovations occurred in 1988 followed by continuous operation at low load in 1989. In 1990 and 1991, there were periods of standby 72 Annex 3.1 Page 4 of 9 and plant outages. Performance in 1992 to the time of the outage was better than the immediately preceding years. Over the life of the station the availability has remained high whereas there has been some decline in capacity factor. This would seem to indicate that the output of the Unit has in fact deteriorated. 33. Fuel supply quality has varied over the years, often due to non technical decisions. However, the station now seem to be obtaining fuel of a quality suitable for the Units. Gas consumption has averaged about 25 per cent of total fuel usage and is judged to be higher than necessary to sustain the coal flame. 34. The record of runmning hours indicates that most outages were planned. However, the durations and frequency are erratic and indicate that regular schedules of planned maintenance have not necessarily been adhered to. There are several maintenance activities such as the frequent replacement of pump impellers that, while not considered a problem by the power station staff, cause excessive maintenance activities. Many of these types of problem would be overcome by the use of good quality replacement parts or by eliminating the cause of the problem. 35. The site is well placed in regard to the rail system, river water supplies and the local load demands for metal ore mining and general industry. The long established mining industry and what was perceived to be a high level of education and generally well organized local infrastructure in the district should ensure a suitable source of personnel for the plant. The general impression was of a keen and interested staff endeavoring to operate as well as possible in difficult circumstances. However, the future will require enhanced personnel training and a more reasoned financial approach to preventative maintenance and plant item replacement. Bucharest South 36. The Bucharest South combined heat and power station is located on a 60 hectare site on the southeast side of the city of Bucharest, approximately 15 km from the city center. The station is located close to the rail network for delivery of fuel oil, and to the electrical power and district heating loads in the city of Bucharest. Construction of the station commenced in 1965, with the installation of two 50 MW combined heat and power (CHP) sets. The second phase of construction, in 1967 added two further CHP sets of 100 MW capacity. The final phase of construction in 1978, increased the capacity of the station to a total of 550 MW, with the installation of two 125 MW CHP sets. Unit 3 and 4 are of similar design and layout. 37. Bucharest-Sud Unit 4 comprises a 420 tonne per hour boiler supplying steam to a common range and a 100 MW turbo-generator. 38. The boilers are of the conventional steam drum type with double gas pass, and include an economizer, furnace, superheater, and rotary regenerative air heater. 39. The boilers are designed for the firing natural gas and fuel oil. The original design allowed for 100 per cent capacity on gas. Full production on natural gas only has not been achieved since the time of the performance tests, as there has not been sufficient gas available. This is a result of rapidly escalating gas demnand, mainly for fertilizer production, without a corresponding development of the gas supply system. 40. The turbine consists of a single high pressure cylinder, a single intermediate pressure cylinder and a single double flow. Low pressure cylinder. Steam is exhausted to a split condenser and bled steam is extracted to four low pressure heaters, a deaerator, three high pressure heaters and a district heating system. Condenser cooling water is provided from evaporative cooling towers. 41. Make-up water is extracted from the industrial network of the district heating system which takes its supply from the nearby Cernica Lake and the Arges river. Additionally, the facility exists to extract make up supplies from the town drinking water system. The make up water requirement is supplied from a common water treatment plant comprising pre-treatment, coagulation, softening and demineralization facilities. 73 Annex 3.1 Page 5 of 9 42. Power is generated at 10.5 kV and 50 Hz and supplied to the switchyard at 110 kV via the generator transformer. The generator cooling system utilizes hydrogen and water. 43. Construction of Unit 4 commenced in 1965 with commissioning completed during 1967. Design of the boilers was by CKO and that of the turbine generator by Turbomotorii Zavod (TMZ), both of Russia. Full design output was achieved during the manufacturers' performance tests and after some initial problems average annual output of around 90 MW, or 90 per cent of design, was achieved in the late 1960s with the turbine operating some 8085 and the boiler operating some 7966 hours per year. Since that time the average annual output has slowly declined, although the annual running hours have remained fairly constant. At present, near design output is occasionally achieved but is not usually sustained for more than about one hour. 44. The RENEL electrical system was operated between 47.5 Hz and 48.5 from 1983 to 1989, and this has had an effect on the condition of some equipment. 45. The Unit first generated significant power in November, 1967. Full design output was achieved during the manufacturers performance tests, and following some initial problems an average annual output of 90 percent was achieved in the late 1960s and early 1970s. 46. Since that time, the boiler has operated for around 81 percent of every year and the turbo-generator for around 76 percent of every year at an in service average load of 61 MW. The boiler and turbo-generator have accumulated some 182,000 and 176,000 hours of operation, respectively to date. 47. Since the exhaustion of plant spares from the original suppliers, more reliance has, by necessity, had to be placed on locally produced equipment of less than adequate quality. This has led to ever increasing maintenance problems which often have a knock on effect, resulting in problems elsewhere on the plant. 48. Over the years, various parts of the plant have been modified or taken out of commnission. This has had an effect on operational flexibility and plant efficiency to varying degrees. However, to reinstate the plant as new may not be necessary or cost effective. A review of the heat cycle and mass balance in relation to the anticipated operating regime and fuel quality is required before committing to major expenditure. 49. The quality of fuel oil supplied to the station varies from day to day, but is invariably worse than design, with a significantly higher sulphur content. The low quality of the fuel represent a major impediment to the achievement of full power, while the high sulphur content results in increased levels of corrosion and environmental pollution. 50. The original design allowed for 100 percent firing of natural gas and fuel oil. However, full production on gas in isolation is seldom achieved, as gas is no longer regularly available in sufficient quantities. 51. The turbine has operated for an average of 76 percent of the time in the twenty-four years of operation, and as it is believed that it has always been run when available this equates to the overall availability. The overall capacity factor for the unit has averaged 61 percent over the operating period. 52. The boiler has slightly higher operating hours at 81 percent over the twenty-four years of operation. Again, this is assumed to equate to the actual availability. The capacity factor for the boilers is not known. 53. Overall, the site is well placed in regard to the rail system, river water supplies and district heating and electrical load center of Bucharest. The level of industry in the district, and the universities should ensure a suitable source of personnel for the plant, where the general feeling was one of a keen and interested staff endeavoring to operate the plant as efficiently as possible in difficult circumstances. If plant is enhanced, however, personnel training and a more disciplined approach to preventative maintenance will be required in the future. 74 Annex 3.1 Page 6 of 9 54. The conclusion of the investigations and detailed discussions with the station staff is that Bucharest-Sud Unit 4, (and by extrapolation Unit 3), could be subject to major plant failures in the next five years with the potential to put future viability of the unit in question. However, a moderate level of rehabilitation work in the next few years could allow for many years of continued operation. 55. From the technical evaluation, it is concluded that medium-term rehabilitation, giving 5-15 years of life, would require almost as much investment as a full life extension of 15-25 years. 56. It is also important to note that several items of plant may require redesign or modification from the original. This could necessitate the recalculation of the unit heat balance and the establishment of a substantial level of confidence in the quality and availability of the fuels to be utilized for future operation. In view of the age of the plant, a return to the as-built condition is not necessarily a practical or sensible solution. 57. The specification and procurement procedures for high quality materials, spares and replacement equipment needs to be established together with appropriate quality control and assurance. The current philosophy of repair needs to change from the frequent and repetitive on-site repair with inferior materials and facilities to one of infrequent replacements with high quality reliable equipment. Personnel training needs to be increased to reflect modern best work practices and operating methods. Isalnita 58. The power station is located on a 52 hectare site within the Isalnita industrial complex, approximately 10 km north west of the city of Craiova. The station is located close to the rail network for delivery of lignite from the mining areas of the Oltenia basin; to the River Jiu for supplies of cooling water; and to the electrical power and district heating loads in the Craiova district. 59. Construction of the station commenced in 1964, with the installation of two 100 MW condensing sets and three 50 MW combined heat and power (CHP) sets. The second phase of construction, in 1967-1968, increased the capacity of the station to a total of 1030 MW, with the installation of two 315 MW condensing sets and an additional 50 MW CHP set. 60. Isalnita Unit 7 (and, similarly Unit 8) comprises two boilers each supplying steam to a single 315 MW turbine generator. 61. The boilers are of the Benson, or once-through, type and each includes an econornizer, superheater, reheater and rotary regenerative air heater. 62. The boilers are designed for firing lignite and/or natural gas. The design allowed for 100 per cent gas firing but this has not been achieved since the time of the performance tests (1969), as there has not been sufficient gas available. This is a result of rapidly escalating gas demand mainly for fertilizer production without a corresponding development of the gas supply system. 63. The turbine consists of a single high pressure stage, a single intermediate pressure stage and two low pressure stages. Steam is exhausted to a split condenser and bled steam is extracted to three low pressure heaters, a deaerator and six high pressure heaters. Condenser cooling water is provided from the river and evaporative cooling towers. 64. Make-up water is supplied from the River Jiu via a common water treatment plant. Units 7 and 8 are each fitted with a condensate polishing plant. 65. Power is generated at 24 kV and 50 Hz and supplied to the switchyard at 220 kV via the generator transformer. The generator cooling system utilizes hydrogen and water. 75 Annex 3.1 Page 7 of 9 66. Construction of Unit 7 commenced in 1967 with commissioning completed during 1969. Design of the boilers was by MAN of West Germany and that of the turbine generator by Rateu-Schneider of France. Full design output was achieved during the manufacturers' perfornance tests and after some initial problems average annual output of around 250 MW or 80 per cent of design was achieved in the early 1970s with the unit operating some 8000 hours per year. Since that time the average annual output has slowly declined although the annual running hours have remained fairly constant. At present near design output is occasionally achieved, but is not usually sustained for more than about one hour. 67. Coal quality varies from day to day and is usually less than that on which the design was based. The station staff attribute this as the major impediment to achieving full power. Although the availability appears good there are numerous short duration shut downs of one half of the boiler pairs which considerably reduces overall output. 68. The main plant, that is the boilers and turbine generator set, were designed and manufactured in Western Germany and France respectively, the boilers being of the once-through design. The plant represents an advanced design with high steam conditions and having accumulated some 186,000 operating hours, the materials in the areas designed to time dependent criteria, eg creep or fatigue, will have consumed a high proportion of their design lives. Thus, while it will be possible to maintain the unit in operation with normal overhauls, and piecemeal replacements, as and when failures of different sections occur, if the plant is to have a sustained extension to its operating life, fairly substantial replacements of essential components will be necessary. 69. The fuel used in the boiler plant is predominantly lignite with high moisture and ash contents which has resulted in the milling and burner systems becoming dilapidated and requiring urgent attention leading to renewal, preferably with re-designed equipment. The abrasive character of the ash in the fuel has also resulted in severe erosion of furnace, superheater, reheater and economizer tubes and extensive renewal of these sections is recommended. 70. Similarly, the abrasive fuel has resulted in extensive wear in the airheaters and the induced draft fans, the erosion of the latter being accelerated because of the inadequate electrostatic precipitator plant. Renewal of the precipitators and of the draft plant is recommended for extended service and it is essential that early attention be given to the precipitators with a view to providing plant of adequate size and performnance. 71. In general, the turbine is in good condition but in accordance with the previous remarks, attention will have to be given to the time dependent areas in order to give a substantial extension to the service life. The main areas involved would be the high temperature bolts, steam chests, journal and thrust bearings but detailed examination should also be made periodically of the rotors and cylinders, to ascertain the stage at which renewal might be desirable to give extended life and better thermal performance. 72. The condenser and feed systems are in reasonable condition subject to their having complete routine overhauls and replacement of some detailed sections such as the air extraction system, and the cooling water screening system should be re-instated in order to improve condenser performance. 73. Both the stator and the rotor require rewinding. The auxiliary electrical systems within the boiler and turbine house were found to be generally in poor repair and in need of major refurbishment, the protection equipment is obsolete and in need of replacement and the standby generator requires a full overhaul. 74. The quality of coal delivered to site has resulted in the coal handling plant requiring extensive refurbishment and in many cases some new equipment. Extensive belt renewal will be necessary, and we also think that the hydraulic couplings in the motor drives should be renewed with advantage to the operators. 75. The control systems are out of date, in very poor condition and the majority of the control loops are no longer capable of automatic operation. With such an advanced design of main plant it is essential that urgent attention be given to the control system and indeed that the entire system requires replacement by equipment of 76 Annex 3.1 Page 8 of 9 modem reliable design. The availability of a satisfactory control system would have very valuable influences on the efficiency of operation of the plant and of the safety of the installation. 76. With advanced steam cycle conditions, it is essential that adequate water treatment plant and chemical dosing facilities are available. The make up water and the cooling water for this site are both extracted from the River Jiul with high suspended solids. This together with the inadequate water treatment plant results in unsatisfactory operation and therefore we recommend that an extensive renewal and rehabilitation exercise be adopted for the water treatment plant and chemical services. 77. Apart from the boiler unit where there is a severe deterioration evident arising from the quality of the fuel with highly abrasive properties, and which will necessitate extensive replacement, and some re-design of the firing equipment, the remainder of the plant is basically in an operable condition. However, because of the extended number of hours of operation, it is evident that attention will be needed to all of the plant if operational reliability is to be sustained and a satisfactory life extension achieved; an example is the recommended rewinding of the generator stator and rotor. 78. Furthermore, in order to achieve reliability attention needs to be given on an urgent basis to some of the ancillary equipment, in particular the controls and water treatment plant. Palas 79. Palas Power Station is located in the industrial area situated to the south of the city of Constanta. Fuel oil is supplied by twin 219 mm OD x 2.5 km long pipelines from Oil Terminal SA who are located within the same industrial area. ° 80. Construction of the station commenced on 1 March 1966 with the installation of two 50 MW combined heat and power sets. The second phase of the construction in 1974 to 1979 increased the capacity of the station to a total of 250 MW (215 MW power) with the installation of a 115 MW/150 MW combined heat and power set. 81. The Unit 3 boiler is a 115 MW/150 MW once through design with reheat by Mannesmann Rohrbau AG of Dusseldorf, West Germany and built under license by Vulcan, Bucharest. 82. The boiler is designed to fire on fuel oil and rated at 525 tonne/hour of steam at 192 bar at a temperature of 5400C. It is a pressurized fumace design and does not have induced draught flue gas fans. The turbine was the first of three of this particular design manufactured by IMGB Romania and is rated at 150 MW or 115 MW plus 165 GCal/hour thermal output for district heating. Unit 3 is a three cylinder tandem compound machine with reheat, seven stages of feed heating and two bleed points for district heating supply. 83. Power is generated at 15.75 kV and 50 Hz supplied to the indoor substation at 124 kV via the generator transformer. The generator cooling system utilizes hydrogen and water. 84. Commissioning of Unit 3 took place in 1979 and we understand from the station that the boiler has never achieved its rated output of 525 tonne/hour of steam. 85. The unit has operated for a total of 29,927 hours which is only about 12 percent of its design life. It was last operated in May 1992 for 6 hours. 86. The machine has been subjected to some 200 starts and the total number of forced outages of the unit is 182. Most of the outages have ben attributed to the boiler with approximately 80 to the turbine and associated plant. However, the majority of the latter outages originate from boiler problems. 87. Shut-downs have been mainly attributed to high vibration levels on the turbine and boiler tube failures mainly in the vaporizer (furnace) and superheater areas. From the first run-up, bearing vibration levels were 7 7 Annex 3.1 Page 9 of 9 very high, particularly at the low pressure bearing pedestal No. 6. The vibration levels recorded were in the range 70 jtm pk/pk - 160 um pk/pk and although several strip-downs have taken place in the last ten years, no significant improvement has been achieved. 88. Unit No 3 has never operated satisfactorily and it has only run for approximately 12.5 percent of the design life. 89. The boiler requires significant rehabilitation work in order to provide an improved performance. 90. The turbine also requires rehabilitation in order to provide a critical speed well removed from the running speed. This may entail provision of a complete new high pressure rotor. 91. Most of the balance of plant is in a satisfactory condition for continued service, as would be expected after only 29,000 hours operation. However, close attention should be given to the water treatment plant in order to provide the high purity make-up water required for a once-through boiler. Conversion to coal 92. The boiler plant of four units in two power stations (Iasi II and Suceava ) will be redesigned to allow for coal firing instead of the present local lignite. This conversion will comprise, among other things, modifications/redesign of the coal mills, bunkers, thermal loads, burning system, evaporation sections, airflow, electrofilters, ash handling and the replacement of the control of the units. The summary description of the power plants is given below. ISl 11 93. Iasi II is a CHP plant located in a 49 hectare site within the city of Iasi in the north-east of Rormania. It provides electricity at 110 kV to national grid and hot water to the Iasi city district heating system. 94. The power station comprises of two boilers designed by ICPET ( Design Institute for Thermal Plant) to produce up to 420 tonne/hour of steam at 137 bar, 540 degrees C. The boilers were manufactured by Vulcan. The two turbines were manufactured by IMGB; both are rated at 50 MW. The generators are hydrogen cooled, 75 MVA, .8 power factor allowing for 60 MW of output. The first boiler was commissioned in 1986 and has operated for 37700 hours; the second 1988 and 27600 hours respectively. They were designed to fire lignite of 1550 kcal/kg (net) with fuel oil support. The fuel oil capability is 50% of the boiler load, but the plant normally operates with 10% oil and 90% lignite. Oil support is required all times. There are six beater type coal mills in each boiler. Suceava 95. The power station is located on a 45 hecatre site near the city of Suceava in the north of Romania. The units have similar design and same manufacturers as lasi II. The first unit was commissioned in 1987 and has 34700 hours of operation; the second 1989 and 27100 respectively. 78 Annex 3.2 Page 1 of 6 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT PROJECT COST ESTIMATES Capital cost estimates were made by the Consultants who inspected the sample units to provide for extension of the life of the units by 50,000, 100,000 and 150,000 hours. The original estimates reflect early 1993 price levels (updadated to January 1995), and they presuppose procurement by ICB with the contractors improving their competitive positions by making use of the low cost local industry and labor whenever quality can be assured. The basic estimate comprise the capital expenditure on the dismantling and removal of equipment to be replaced, on the renovation, where appropriate, of existing equipment and on the provision and installation of replacement equipment. The details of the repair and renewal work to be done, as identified by the Consultants during inspection work, are set out in the Consultant's report in the Project file. The estimates of basic cost have been arrived at in a two-stage process. First, costs were estimated by reference to the Consultants' own database and by inquiry of Western manufacturers. It is noted, however, that virtually all the inspected plant was designed and manufactured in Romania or elsewhere in Eastern Europe. Costs in Eastern Europe in general and in Romania in particular, are lower than in Western Europe. The Consultants have attempted to quantify the likely effect on prices of the above indicated local participation. Budget prices received from Romanian enterprises, and other information indicate a discount relative to Western prices of up to 30 percent. From the Consultant inspection work in the power stations, however, it was verified that quality control in the power engineering sector in Romania is, or was, poor. On the other hand, based on brief visits made to Romanian factories, it is believe that they are capable of matching the standards of their Western counterparts; but in doing so, the Consultant expect some diminution in the current price advantage. Therefore, it is reasonable to allow for a discount of 20 percent relative to Western prices for power plant equipment, except for such equipment as controls and instrumentation, which should be specified to be of Western origin. For life extensions of 100,000 and 150,000 hours cost estimates include the installation of low NOx burners and, for lignite/coal burning plant, complete rehabilitation of the precipitator plant. For life extent of 50,000 hours, the provision made depend on the efficiency of the existing burners and precipitators. There was no allowance for the retrofitting of FGD equipment. Engineering, project management and site supervision was estimated at about 6 percent of base cost. Discussions with Romania equipment manufacturers and local quality assurance groups revealed that the foreign contents of locally manufactured equipment in order to meet international standards of quality, would be high, as much as 40-50% of the original estimates of the local costs. The foreign exchange cost component takes account of the indirect foreign exchange cost due to the foreign inputs for local manufacture. As a result, the foreign exchange costs account for about 65 % of the total base cost for the various units to be rehabilitated. Physical contingencies of 15 percent were used all through the rehabilitation works. This high value is due to the uncertainty inherent to these type of estimation. For example, the Consultants did not have the opportunity to see all plant dismantled, or to carry out non-destructive tests (NDT) and other evaluations on all the potentially critical high temperature or high stress areas. This high contingencies is intended to cover costs of additional work that might come to light by the time the specifications are being prepared or during the actual execution of the work, in addition to covering the uncertainties in the basic cost estimates. Price contingencies are calculated by applying the Index of Unit Value of Manufactured Exports (from the G-5 countries) to the base cost plus the physical contingencies in accordance with Bank methodology. ROMANIA Power Sector Rehabilitation and Modernization Project Project Cost Estimates (IJSS rnillions) FY95 FY96 FY97 FY98 FY99 FYOO TOd Cod Itemi Local Fordgn Tu local Foreign Total Loca Foreign Tdael Lo1 Foreign Totld Ial Foreign Toa Local Foreign Todl LAoal Foreign Tod Annual Inflation (*) 49.1% 0.0 36.1% 2.3% 26.5% 0.0 21.0% 2.6% 18.8% 2.6% 18.8% 2.7% Inftion Factor 0.2 1.00% 0.8 2.14% 1.3 4.62% 1.8 7.34% 2.4 10.10% 3.0 12.96% ' Ned to Update Local inflalin figures for Romanim. PLANT REHABILITATION FY95 FY96 FY97 FY98 FYss FY00 Total Cod Item Local Foreign Total Locd Foreign Total Local Foreign Total Lo Foreign Total LoA Foreign Total Local Foreign Total Local Foreign Total Buchared South-3 (IlzOOMW) 0.0 0.0 0.0 1.7 2.9 4.5 3.4 5.7 9.1 0.3 0.5 0.8 0.3 0.5 0.8 0.0 0.0 0.0 5.6 9.5 15.1 Physical Contingencies 0.0 0.0 0.0 0.3 0.4 0.7 0.5 0.9 1.4 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.0 0.0 0.8 1.4 2.3 Price Contingencies 0.0 0.0 0.0 0.0 0.1 0.1 0.2 0.3 0.5 0.0 0.0 0.1 0.0 0.1 0.1 0.0 0.0 0.0 0.3 0.5 0.7 Subtotal Buchareo South-3 0.0 0.0 0.0 2.0 3.4 5.3 4.0 6.9 10.9 0.3 0.6 0.9 0.4 0.6 1.0 0.0 0.0 0.0 6.7 11.4 18.1 Buchare-d Sotdh-4 (IxlOOMW) 0.0 0.0 0.0 0.6 1.0 1.5 1.7 2.9 4.5 2.2 3.8 6.1 0.8 1.4 2.3 0.3 0.5 0.8 5.6 9.5 15.1 Pbysical Contingencies 0.0 0.0 0.0 0.1 0.1 0.2 0.3 0.4 0.7 0.3 0.6 0.9 0.1 0.2 0.3 0.0 0.1 0.1 0.8 1.4 2.3 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.2 0.2 0.2 0.3 0.5 0.1 0.2 0.3 0.0 0.1 0.1 0.4 0.7 1.2 Subtotal Bucharet Soutb.4 0.0 0.0 0.0 0.7 1.1 1.8 2.0 3.4 5.5 2.8 4.7 7.5 1.1 1.8 2.9 0.4 0.6 1.0 6.9 11.7 18.6 kD Palas-I (50MW) 0.0 0.0 0.0 0.6 1.3 1.9 1.2 2.7 3.8 0.2 0.4 0.6 0.0 0.0 0.0 0.0 0.0 0.0 1.9 4.5 6.4 Phy icContingenes o0.0 0.0 0.0 0.1 0.2 0.3 0.2 0.4 0.6 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.7 1.0 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.2 0.0 0.0 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.2 0.3 Subtotal Palaal 0.0 0.0 0.0 0.7 1.6 2.3 1.4 3.2 4.6 0.2 0.6 0.8 0.0 0.0 0.0 0.0 0.0 0.0 2.3 5.4 7.7 ParLa-2 (50MW) 0.0 0.0 0.0 0.6 1.3 1.9 1.2 2.7 3.8 0.2 0.4 0.6 0.0 0.0 0.0 0.0 0.0 0.0 1.9 4.5 6.4 Physical Contingencies 0.0 o.o o.o 0.1 0.2 0.3 0.2 0.4 0.6 o.o o.l o.l o.o 0.0 o.o e.e e.e e.e 0.3 0.7 I.o Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.2 0.0 0.0 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.2 0.3 Subtotal Palaa-2 0.0 0.0 0.0 0.7 1.6 2.3 1.4 3.2 4.6 0.2 0.6 0.8 0.0 0.0 0.0 0.0 0.0 0.0 2.3 5.4 7.7 Braila-1 (lx2lOMW) 0.0 0.0 0.0 0.0 0.0 0.0 3.0 5.2 8.2 6.9 12.2 19.1 0.0 0.0 0.0 0.0 0.0 0.0 9.8 17.5 27.3 Physical Continge e 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.8 1.2 1.0 1.8 2.9 0.0 0.0 0.0 0.0 0.0 0.0 1.5 2.6 4.1 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.3 0.4 0.6 1.0 1.6 0.0 0.0 0.0 0.0 0.0 0.0 0.7 1.3 2.0 Subtotal Braila-I 0.0 0.0 0.0 0.0 0.0 0.0 3.6 6.4 10.0 8.4 15.0 23.4 0.0 0.0 0.0 0.0 0.0 0.0 12.1 21.4 33.5 I (D 0 o~t -h W a, ;, ROMANIA Power Sectm Rehabilitation and Modemization Project Projec Cost Estimates (USS millions) FYT5 FT%6 FM 7 FY9S FYN6 Tet Cos ks Locea Fmi Tot L1a For*u TOtaloca Por*u TOt Local Foa*u TOta Local Forign Total LJocal Fari, Total cal Forig TOtal ssod (1z200MW) 0.0 6.0 6.0 1. 2.5 4.1 6.6 9.8 16.4 0.0 0.6 0.0 0.0 0.0 0.0 0.0 0. 0.0 .2 123 20.5 F1Y1A C tmaeks 0.0 0.0 0.0 *.2 0.4 0.6 1.0 1.5 2.5 0.0 0.0 0.0 0.0 0.0 0.S 0.0 0.0 0.0 1.2 l.S 3.1 Prim COtUMcim 0.0 g._ *.o *- 0.1 0.1 0.3 0.5 0.9 0.0 0.0 .0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.6 1.0 Subtotal 3r.-S 0.0 0.0 0.0 1.0 2.9 4.8 7.9 11.8 19.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.8 14.7 245 IainMa-7 (Ix31sMW) 0.0 0.0 0.0 0.0 0.0 0.0 10.5 15.2 25.7 17.6 25.3 42.9 3.5 5.1 8.4 3.5 5.1 8.6 35.1 50.6 85.7 Fhyucl Co eh"Pmalo 0.0 0.0 0.0 0.0 0.0 0.0 1.6 2.3 3.9 2.6 3.8 6.4 0.5 0.8 1.3 0.5 0.8 1.3 5.3 7.6 12.9 Pric Cootge cift 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.8 1.4 1.5 2.1 3.6 0.4 0.6 1.0 0.5 0.8 1.3 3.0 4.3 7.3 Subtota IaLnka-7 0.0 0.0 0.0 0.0 0.0 0.0 13.0 18.7 31.7 30.4 43.7 74.1 0.0 0.0 0.0 0.0 O.0 0.0 43.4 62.4 105.8 Dewa-1 (lx2lOMW) 0.0 0.0 0.0 0.0 0.0 0.0 3.7 6.3 10.0 7.4 12.6 20.0 0.6 1.0 1.7 0.6 1.0 1.7 12.3 21.0 33.3 Physcal Co.tl- gat 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.9 1.s 1.1 1.9 3.0 0.1 0.2 0.2 0.1 0.2 0.2 1.8 3.1 5.0 Price Co abrisa 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.3 0.5 0.6 1.1 1.7 0.1 0.1 0.2 0.1 0.2 0.2 1.0 1.7 2.7 Subttal Deva-I 0.0 0.0 0.0 0.0 0.0 0.0 4.4 7.6 12.0 9.1 15.5 24.7 0.8 1.3 2.1 0.8 1.4 2.2 15.1 25.8 40.9 Deya-2 (lx2lOMW) 0.0 0.0 0.0 0.0 0.0 0.0 3.7 6.3 10.0 7.4 12.6 20.0 0.6 1.0 1.7 0.6 1.0 1.7 12.3 21.0 33.3 Thyuca Cougainried 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.9 1.5 1.1 1.9 3.0 0.1 0.2 0.2 0.1 0.2 0.2 1.8 3.1 5.0 0 Price Coati'ga 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.3 0.5 0.6 1.1 1.7 0.1 0.1 0.2 0.1 o.2 0.2 1.0 1.7 2.7 Subtota] Dey*a2 0.0 0.0 0.0 0.0 0.0 0.0 4.4 7.6 12.0 9.1 MS. 24.7 0.8 1.3 2.1 0.8 1.4 2.2 15.1 25.8 40.9 1Ai CoUnVdM to Coe (I uoa 0.0 0.0 0.0 0.6 2.4 3.0 1.4 5.6 7.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0 8.0 10.0 Physcal Ceoting 0.0 0.0 0.0 0.1 0.4 0.5 e.2 0.8 1.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 1.2 1.5 Price Co _tnes 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.4 0.4 Subttal la CeDvoiioo 0.0 0.0 0.0 0.7 2.8 3.5 1.7 6.7 8.4 0.0 0.0 0.0 0.0 0.0 0.0 o.0 0.0 0.0 2.4 9.6 11. Succa CeDyeruo. to Coal a unka) 0.0 0.0 0.0 0.4 1.6 2.0 1.6 6.4 8.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0 8.O 10.0 Pbydcl Cooing_c. 0.0 0.0 0.0 0.1 0.2 0.3 0.2 1.0 1.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 1.2 1.5 Prie Cootinaic 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.3 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.4 0.5 Subttal Soe.s Coversica 0.0 0.0 0.0 0.5 1.9 2.3 1.9 7.7 9.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.4 9.6 12.0 Fayircmml Moekorn Prog. 0.0 0.0 0.0 0.2 1.4 1.5 0.3 2.5 2.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 3.9 4.3 Fhydcl C euthdi 0.0 0.0 0.0 0.0 0.2 0.2 0.0 0.4 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.6 0.6 riea Coejnaide 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.2 S5oka P,ir _ ooa Momi. Prog 0.0 0.0 0.0 0.2 1.6 1.8 0.3 3.0 3.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.5 4.6 S.1 ID 0 1-h LW Or, ;) ROMANIA Power Sector Rehabilitation and Modernization Project Project Cost Estirmtes (USS millions) FY95 FY96 FY9V7 FY98 FY99 FY00 TOta cant 1t4 LoAW Foreign Toald Local Foralga Tota Local Foreign Total Lcal Foruga Tota l Lcal Foreig Tota Lcalg Fordog Tota Local Foraga Tota Engineering & Project ?4anagmmm 0.3 2.7 3.0 0.3 2.7 3.6 0.5 4.1 4.5 0.3 2.7 3.0 6.1 6.7 e.g CA1 0.7 0.8 1.5 13.5 15.0 Phyacal C.otnmsedi 0.0 0.4 0.5 0.0 0.4 0.5 0.1 0.6 0.7 0.0 0.4 6.5 0.0 6.1 0.1 0.0 0.1 0.1 0.2 2.6 2.3 Prle. Cootlmgemdg. 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.2 0.2 0.0 0.2 0.3 0.0 0.1 0.1 0.0 0.1 0.1 0.1 0.7 0.8 Subota E1ff& POj MMt.0.3 3.1 3.5 0.4 3.2 3.5 0.5 4.9 5.4 0.4 3.3 3.7 0.1 0.9 0.9 0.1 0.9 1.0 1.8 16.2 18.0 TOTAL PLANT REHABlILITATION BASE COST 0.3 2.7 3.0 6.5 17.0 23.5 38.5 75.4 113.9 42.4 70.6 113.0 5.9 9.7 15.7 5.1 8.3 13.4 98.8 183.7 282.5 PEHYSICAL CONTINGENICIES 0.0 0.4 0.5 1.0 2.6 3.5 5.8 11.3 17.1 6.4 10.6 17.0 0.9 1.5 2.4 0.8 1.2 2.0 14.8 27.6 42.4 PhCE CONTINGENJCIES 0.0 0.0 0.0 0.2 0.4 0.6 2.0 4.0 6.0 3.6 6.0 9.5 0.7 1.1 1.8 0.8 1.2 2.0 7.2 12.8 20.6 TOTAL 0.3 3.1 3.5 7.6 20.0 27.6 46.3 90.7 137.0 52.4 17.1 139.5 7.5 12.3 19.8 6.6 10.8 17.4 120.8 224.0 344.8 TECENICAL ASSISTANCE-RENiEL World Bank -Corporate Rectruduring 0.0 0.0 0.0 0.3 1.5 1.8 0.2 1.2 1.4 0.1 0.7 0.8 0.0 0.0 0.0 0.0 0.0 0.0 0.6 3.4 4.0 Phiysical Cootiogeadets 0.0 0.0 0.0 0.0 0.2 0.3 0.0 0.2 0.2 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.6 Price Coatlngameic. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.2 Subtota 0.0 0.0 0.0 0.3 1.8 2.1 0.3 1.4 1.7 0.1 0.8 1.0 0.0 0.0 0.0 0.0 0.0 0.0 0.7 4.1 4.8 -maioteaiaacysetad Overhaul 0.0 0.0 0.0 0.1 1.2 1.4 0.1 0.9 1.1 0.1 0.5 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.3 2.7 3.0 Physical Cootingeades 0.0 0.0 0.0 0.0 0.2 0.2 0.0 0.1 0.2 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.5 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.0 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Subtotal 0.0 0.0 0.0 0.2 1.4 1.6 0.1 1.1 1.3 0.1 0.7 0.7 0.0 0.0 0.0 0.0 0.0 0.0 0.4 3.2 3.6 -External Audit 0.0 0.5 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.5 0.5 Phyical Ceutlgearica 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Prime Coutiagaiciss 0.0 0.0 0.0 0.0 .0. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Sahtotaj 0.0 0.6 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.6 -matrlg, Uuga & Caused.. (Ilardware) 0.0 0.0 0.0 0.1 0.5 0.5 0.2 1.8 2.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 2.3 2.5 i Phiaca Ceubgamdaa 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.3 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.4 CD '4 0 ROMANIA Power Sector Rehabilitation and Modernization Project Project Cost Estimates (USS millions) FY95 FY96 FY97 FY8 FY9 FYOO Total COd hem Local Foreign Total 1ocal Foreign Taal Local Foreign Total Loca Foreign Total lcal Fore4n Total Local Foreign Total Lal Foreign Tot Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Subtotidal . 0.0 0.0 0.1 0.5 0.6 0.2 2.2 2.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 2.7 3.0 EU-Phare - Mtering, Biling & Collection Coneuhing Service 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.4 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.5 Physical Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Price Contingenie 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtoal 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.4 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.6 - Hydra &Thernal Amueent 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.2 Phyal Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtotal 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.3 -Training in Environment O Ilesith & Sarety 0.0 0.2 0.3 0.0 0.2 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.5 Phyucal Contingencim 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 SubtotAl 0.0 0.3 0.3 0.0 0.3 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.6 - Trainin for Plant Operators 0.0 0.2 0.3 0.0 0.2 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.5 Phymicl Conlingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Price Coningencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtoa 0.0 0.3 0.3 0.0 0.3 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.6 -Distribotion Mnaer Plan 0.0 0.0 0.0 0.0 0.4 0.4 0.0 0.3 0.3 0.0 0.2 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.8 0.9 Pbysical Cootigendcis 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtotd 0.0 0.0 0.0 0.0 0.4 0.5 0.0 0.3 0.4 0.0 0.2 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.1 1.0 1.1 -Tranuniion Studies 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.3 PhysicalCoingmcies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Price Contingeies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtal 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.4 o (W 0 ' ROMANIA Power Sector Rehabilitation and Modernization Project Project Cost Estimates (USS millions) FY95 FYg6 FY97 FY98 FY99 FY00 Total Cos hIem Local Foreign Totdl LIcal Foreign Total lcal Forign Total Loal Foreign Total Local Foreign Total Local Foreign Total Local Foreign Total TECIINICAL ASSISTANCEGOVERNMENT USAID Optiona Study 0.0 0.4 0.5 0.1 0.5 0.6 0.1 0.8 0.8 0.0 0.4 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.2 2.2 2.4 Physical Contingencies 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.4 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Subtot o.l 0.5 0.6 0.1 0.6 0.7 0.1 0.9 1.0 0.1 0.5 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.3 2.6 2.9 Other -L est Cost laning 0.0 0.1 0.1 0.0 0.1 0.2 0.0 0.2 0.2 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.6 Phy ica Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Price Contingencis 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtotal 0.0 0.1 0.1 0.0 0.2 0.2 0.0 0.2 0.3 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.6 0.7 m - Eneuricity & Hleating Pricing 0.0 0.1 0.1 0.0 0.1 0.2 0.0 0.2 0.2 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.6 Pbysical Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 Price Contingencies 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtotal 0.0 0.1 0.1 0.0 0.2 0.2 0.0 0.2 0.3 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.6 0.7 TOTAL TECINICAL ASSISTANCE BASECOST 0.1 1.6 1.8 0.6 4.5 5.1 0.5 3.8 4.4 0.3 2.0 2.3 0.0 0.0 0.0 0.0 0.0 0.0 1.5 11.9 13.4 PHYSICAL CONTINC6ENCIES 0.0 0.2 0.3 0.1 0.7 0.8 0.1 0.6 0.7 0.0 0.3 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.2 1.9 2.1 PRICE CONTINCENCIES 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.2 0.2 0.0 0.2 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.6 TOTAL 0.2 1.9 2.1 0.7 5.3 6.0 0.7 4.6 5.2 0.4 2.4 2.8 0.0 0.0 0.0 0.0 0.0 0.0 1.8 14.3 16.1 TOTAL PROJECT 0.5 5.0 5.5 8.4 25.8 34.1 47.2 97.4 144.6 52.7 89.6 142.3 7.5 12.3 19.8 6.6 10.8 17.4 122.9 241.0 363.9 x 0e LQ Fh W a3 fD 84 Annex 3.3 Page 1 of 25 ROMANIA POWER SECTOR REHABILITATION & MODERNIZATION PROJECT PROJECT IMPLEMENTATION PLAN Project Objectives 1. The objectives of the proposed project are to: (a) support the government's program to reform the power sector in accordance with its overall economic policy objectives; (b) meet the demand for electricity and thermal energy in an economical manner by rehabilitating thermal generation capacity; and (c) lay the foundation for the future development of the sector in an institutionally, economically, and environmentally sustainable manner. Project Description 2. The proposed Project would comprise: (a) Power Sector Reform Program to: (i) carry out and implement a Study of Options of Long-Term Structure for the Power Sector; (ii) develop and implement an appropriate legal and regulatory framework for the sector; (iii) establish a long-term least-cost power sector investment program, and (iv) carry out and implement an electricity and thermal energy pricing study; (b) Thermal Plant Rehabilitation Program where equipment, services and technical assistance will be provided to RENEL to: (i) rehabilitate about 1,445 MW of its existing thermal generation capacity; (ii) convert about 200 MW of its existing lignite-based thermal capacity to coal use; and (iii) reduce pollution impact of thermal plants; and (c) Corporate Restructuring Program where technical assistance will be provided to RENEL to: (i) streamline the utility to focus on electricity and generation plants and distribution subsidiaries; (ii) create cost/profit centers for the generation plants and distribution subsidiaries; (iii) design and implement management systems (for operation and maintenance management, financial and cost accounting, human resources, materials management, corporate planning systems); (iv) improve metering, billing and collection system; (v) design transmission and distribution network rehabilitation programs; and (vi) retire old and inefficient thermal units; and vii) improve environmental management and occupational health and safety. Project Financing 3. The financing plan for the Project is summarized in the table below Table 3.2 Project Financing Plan (US$ Million) R:ENEL EBRD EIB EU- USAID IBRD OTHER: Total PHARE Power Sector 1.4 - - 2.9 - - 4.3 Reform Thermal Plant 122.3 51.8 23.1 - - 102.7 44.9 344.8 Rehabilitation Corporate 1.3 2.6 - 3.6 - 7.2 - 14.8 Restructuring program TOTAL 125.7 54.4 23.1 3.6 2.9 110.0 44.9 363.9 85 Annex 3.3 Page 2 of 25 Implementing Arrangements 4. Implementation responsibility for the Power Sector Reform Program will be with Mol while the Thermal Plant Rehabilitation Program and Corporate Restructuring Program will be the responsibility of RENEL. RENEL has established a Project Implementation Department to carry out all rehabilitation and renovation works at its plants and transmission systems. The following actions have also been taken to ensure successful project implementation: (a) GoR has established an Intenninisterial Steering Committee to oversee the design and implementation of the Power Sector Reform Program, for which the MoI's Directorate General for Electricity and Thermal Energy will serve as the secretariat,; (b) RENEL will ensure that the Project Implementation Department in RENEL will continue to be adequately staffed and funded in a manner satisfactory to the Bank; (c) RENEL has established a Corporate Restructuring Committee under the President to oversee the design and implementation of RENEL Corporate Restructuring Program; (d) RENEL has prepared a program for improvements in environmental management in RENEL, including eventually, the establishment of a department devoted to environmental concerns, the definition of its main functions and of its relations with the other departments. By December 1995, RENEL will appoint consultants, under terms of reference satisfactory to the Bank, to assist in implementing the systems, including training of RENEL staff, and assistance in implementing occupational health and safety programs at headquarters and all thermal power generating facilities, including training of RENEL staff 5. The role of the Bank during project implementation is in section H of Chapter 3 of the SAR. A first measure of success of project implementation will be that all major contracts for the rehabilitation of power plants are awarded by March 1997. Implementation Plan 6. The time-bound detailed implementation plan for each project component, including technical assistance and training is provided in the tables attached to this Annex showing the Schedule of procurement actions, including targets dates for each package under the project; 7. Detailed project cost estimated are provided in Annex 3.2, and forecast disbursement for each item financed under the project are provided on page 10; 8. Provisions for setting up project accounting and financial management are found in Chapter 4 of the SAR. The establishment of the Special Accounts are in Chapter 3 of the SAR. Project Monitoring and Bank Supervision 9. To enable monitoring GoR and RENEL will prepare quarterly progress reports on the respective components. In addition, RENEL will be asked to: a) prepare beginning with financial year 1996, a rolling 5-year corporate plan each year; and b) recruit internationally reputable private auditors to audit the utility's financial accounts and corporate performance. The form, content and timetable for the submission of these reports to the Bank will be confirmed with Mol and RENEL respectively at negotiations. 86 Annex 3.3 Page 3 of 25 10. Implementation Plan-Main Schedule: These are provided on pages 4-9. Engineering Services CONSULTANT CONTRACTING - SCHEDULE LOI/TOR finalized * 09.30.94 (a) LOI sent out * 11.14.94 (a) Clarifications Conference 2 12.16.94 (a) Visits to Sites 15 12.30.94 (a) Submission of Offers * 02.20.95 (a) Evaluation 95 06.16.95 (a) Bank Review 30 08.15.95 (a) Invitation to Negotiate * 08.17.95 Negotiations 11 08.28.95 Review of Draft Contract by the Bank 10 09.07.95 Contract Signature * 09.11.95 Mobilization of the Consultant 10 09.21.95 Start * 09.22.95 (a) - actual * - milestone PREQUALIFICATION OF GENERAL CONTRACTORS - SCHEDULE ...... . Actity Drto Compl etion Plannied . ..... ........ i(onth) Preparation of the Pre-Qualification Documents 2 mn 10.01.95 Review by the Bank 0.5 mn 10.15.95 Publication of the Invitation for Prequalification * 10.26.95 Deadline for Receipt of Applications * 11.26.95 Analysis and Report on Applicants Qualifications 2 mn 01.26.96 Proposed List of Qualified Contractors 0.5 in 02.10.96 Review by the Bank 0.5 m 02.26.96 Issuance of Bid Invitations * 03.0 1.96 87 Arnnex 3.3 Page 4 of 25 PROCUREMENT AND IMPLEMENTATION SCHEDULE - PACKAGE I (BUCHAREST SOUTH 3&4) Start: 11.21.95 Activity Duration Finish Planned (Month) Engineering and Design 3 m 02.21.96 Preparation and Review of Bidding Documents 1 m 03.21.96 Invitation to Bid * * 03.26.96 Bid Preparation 2 m 05.26.96 Bid Opening * 06.01.96 Bid Evaluation Im 07.01.96 Award Recommendations and Review 0.5 m 07.16.96 Contract Signature * * 07.20.96 Contract Execution (Physical) 25 m 08.20.98 Test and Commissioning 2 m 10.20.98 Guarantee Period 12 m 10.20.99 * milestones PROCUREMENT AND IMPLEMENTATION SCHEDULE - PACKAGE II (PALAS 1,2) Start 11.21.95 Activity Duration Finish Planned (Month) Engineering and Design 3 m 02.21.96 Preparation and Review of Bidding Documents 1 m 03.21.96 Invitation to Bid * * 03.26.96 Bid Preparation 1 m 04.26.96 Bid Opening * 05.01.96 Bid Evaluation 1 m 06.01.96 Award Recommendations and Review 0.5 m 06.15.96 Contract Signature * * 06.20.96 Contract Execution (Physical) 12 m 06.20.97 Test and Commissioning 1 m 07.20.97 Guarantee Period 12 m 07.20.98 *milestones 88 Annex 3.3 Page 5 of 25 PROCUREMENT AND IMPLEMENTATION SCHEDULE - PACKAGE III (BRAZI 8, BRAILA) Start 04.01.96 Activity Duration Finih aPlnn (Month) Engineering and Design 3.5 m 07.15.96 Preparation and Review of Bidding Documents 1.5 m 09.01.96 Invitation to Bid * * 09.06.96 Bid Preparation 1 m 10.06.96 Bid Opening * 10.11.96 Bid Evaluation I m 11.11.96 Award Recommendations and Review 1 m 12.11.96 Contract Signature * * 12.16.96 Contract Execution (Physical) 20 m 08.16.98 Test and Commissioning 2 m 10.16.98 Guarantee Period 12 m 10. 16.99 * - milestones PROCUREMENT AND IMPLEMENTATION SCHEDULE - PACKAGE IV (ISALNITA & DEVA 1) Start 04.01.96 Activi y Duration 1 EFiish Planned Engineering and Design 4 m 08.01.96 Preparation and Review of Bidding Documents 1.5 m 09.15.96 Invitation to Bid * * 09.20.96 Bid Preparation 2 m 11.20.96 Bid Opening * 11.25.96 Bid Evaluation 1.5 m 01.15.97 Award Recommendations and Review 1 m 02.15.97 Contract Signature * 02.20.97 Contract Execution 20 m 10.20.98 Test and Commissioning 2 m 12.20.98 Guarantee Period 12 m 12.20.99 * milestones 89 Annex 3.3 Page 6 of 25 PROCUREMENT AND IMPLEMENTATION SCHEDULE - PACKAGE V (IASI I & 2 Vl SECAVA 1 & 2) Start 04.01.96 Activity Duration Finish Planned (Month) Engineering and Design 3 m 07.01.96 Preparation and Review of Bidding Documents 1 m 08.01.96 Invitation to Bid * * 08.06.96 Bid Preparation 2 m 10.06.96 Bid Opening * 10.11.96 Bid Evaluation 1 m 11.11.96 Award Recommendations and Review 1 m 12.11.96 Contract Signature * * 12.16.96 Contract Execution 16 m 04.16.98 Test and Commissioning 1 m 05.16.98 Guarantee Period 12 m 05.16.99 * milestones PROCUREMENT AND IMPLEMENTATION SCHEDULE - PACKAGE VII (DEVA 2) Start 05.01.96 Activity Duration Finish Planned (Month) Engineering and Design 4 m 09.01.96 Preparation and Review of Bidding Documents 1.5 m 10.15.96 Invitation to Bid * * 10.20.96 Bid Preparation 2 m 12.20.96 Bid Opening * 12.25.96 Bid Evaluation 1.5 m 02.10.97 Award Recommendations and Review I m 03.10.97 Contract Signature * 03.15.97 Contract Execution 1.5 m 06.15.98 Test and Commissioning 1 m 07.15.98 Guarantee Period 12 m 07.15.99 90 Annex 3.3 Page / ot 25 8mC 0Y 0 L Ct) ma 0 0~~~~~ Li 0~~~~~~~~~~~~ o~~~~~~~~~~~~~~~~~~~~~~~~~~~c 0.~~~~~~~~~~~~ l I5c C-~~~~~~~~~~~~~ 0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~. 0- Cl~~~~~~~~~~~~~~~~~- C 0? i 0 0~~~~~~~~~~~~~~c CO ~ ~ ~ ~ ~ =O - N~~~~~~~~~~~~~~~~~~~x( Romania: Power Sector Rehabilitation and Modernization Project Procurement and Implementation Schedule 1995 1996 1997 1998 1999 ID Task Name Qtr Q tr 2 Otr 3 Otr 4 Otr 1 Otr 2 O Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 QtrS3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 26 Bid Preparation 27 Bid Opening * 51 28 Bid Evaluation 29 Award Recommendations and Review i 30 Contract Signature 6/20 31 Contract Execution (Physical) 32 Test and Commissioning 33 Guarantee Period 34 Package IlIl (Brazi 8 & Braila) 35 Engineering and Design 36 Preparation and Review of Bidding Documents 37 Invitation to Bid * 9/6 38 Bid Preparation 39 Bid Opening * 10/11 40 Bid Evaluation 41 Award Recommendations and Review 42 Contract Signature 12/16 43 Contract Execution (Physical) 44 Test and Commissioning 45 Guarantee Period 46 Package IV (Isalnita & Deva 1) 47 Engineering and Design - 48 Preparation and Review of Bidding Documents cO O x 49 Invitation to Bid * o 609Bid1Preparation2.0__ ._ W _ en ' 60 Bid Preparation Romania: Power Sector Rehabilitation and Modernization Project Procurement and Implementation Schedule 1996 1996 1997 ::-:~1998 1999 ID Task Narne Qtr 1 Otr 2 Qtr 3 Otr 4 Qtr 1 |Qtr2 D Qtr 3 Qtr 4 Qtr tr2 tr3 4 Qtr 1 DQtr 2 Dtr3 Dtr4 Qt Dtr2 Dtr Dtr4 61 Bid Opening * 11/25 62 Bid Evaluation 53 Award Recommendations and Review 64 Contract Signature * 2/20 55 Contract Execution (Physical) - 56 Test and Commissioning .jj 57 Guarantee Period ._ 59 Packages V (lasi 1 & 2) & VI (Secave 1 & 2) 59 Engineering and Design 60 Preparation and Review of Bidding Documents 61 Invitation to Bid ** 6 62 Bid Preparation 63 Bid Opening * 10/11 64 Bid Evaluation 65 Award Recommendations and Review 66 Contract Signature * 12/16 67 Contract Execution (Physical) 68 Test and Commissioning 69 Guarantee Period 70 Package VIt (Deva 2) 71 Engineering and Design 72 Preparation and Review of Bidding Documents 73 Invitation to Bid * 2 IO1020 C 74 Bid Preparation .HIi 76 Bid:Opening 12/26 '-~ t 75 Bid Opening * _/5 ui Romania: Power Sector Rehabilitation and Modernization Project Procurement and Implementation Scheduie 1995 | 1996 | 1997 1998 1999 ID Task Name Otr I Qtr 2 Otr 3 Qtr 4 Qtr Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr I Qtr 2 Qtr 3 Otr 4 Otr 1 Qtr 2 Qtr3 Qtr4 76 Bid Evaluation 77 Award Recommendations and Review 78 Contract Signature 79 Contract Execution (Physical) 80 Test and Commissioning 81 Guarantee Period (D d:) (D o D o x (DW 94 Annex 3.3 Page 11 of 25 TECHNICAL ASSISTANCE - KEYIMPLEMENTATIONDATES 1. Study of Options of the Long-Term Power Sector Structure Completion of Terms of Reference (TOR) November 30, 1994 Appointment of Inter-Ministerial Committee and Local Counterpart Team November 30, 1994 Issue of TOR & appointment of Consultant by USAID March 20, 1995 Initiation of Study July 27, 1995 Commence field work September 1995 Completion of Phase ( Diagnostic Analysis) March 31, 1996 Government Decision on Sector structure June 30, 1996 Action Report August 30, 1996 Final Report September 30, 1996 2. Long-Term Least Cost Power Generation Development Study Completion of TOR August 31, 1995 Issue Invitation for Proposals September 15, 1995 Receipt of Proposals October 30, 1995 Consultant Mobilization/ Start of Work November 29, 1995 Completion of Phase I ( Data Book) January 20, 1996 Submission of Draft Report April 30, 1996 Final Report June 30, 1996 3. Electricity and Heat Pricing Study Completion of TOR August 30, 1995 Issue Invitation for Proposals September 15, 1995 Receipt of Proposals October 30, 1995 Evaluation of Proposals and Approval November 20, 1995 Mobilization/Start of Work December 14, 1995 Phase I ( Load Research) Report June 30, 1996 Start Phase 11 (Determination of Cost of Supply) September 4, 1996 Phase 11 Report December 20, 1996 Start Phase III ( Tariff Design) February, 1997 Phase III & Draft Final Report May 1997 Final Report August 30, 1997 4. Power Transmission System Reinforcement and Expansion Feasibility Study Completion of TOR August 30, 1994 Issue Invitation for Proposals September 15, 1994 Receipt of Proposals October 30, 1994 Evaluation and Approval January 30, 1994 Negotiations & Contract Award November 30, 1994 Mobilization/ Start of Work March 10, 1995 Draft Final Report September 1995 Final Report November 15, 1995 5. Feasibility Study of Power Distribution System Rehabilitation, and Preparation of Distribution Master-Plan 9 5 Annex 3.3 Page 12 of 25 Completion of TOR September 29, 1995 Issue Invitation for Proposals October 30, 1995 Receipt of Proposals December 30, 1995 Evaluation and Approval March 30, 1996 Negotiations & Contract Award February 15, 1996 Mobilization/Start of Work March 30, 1996 Phase I Report (Feasibility Study) September 30, 1996 Phase II Completion ( Master-Plan) December 20, 1996 Draft Final Report January 30, 1997 Final Report April 15, 1997 6. Environmental Management Completion of TOR March 30, 1995 Issue of Invitation for Proposals September 30,1995 Receipt of Proposals October 30, 1995 Evaluation and Approval November 15, 1995 Negotiations & Contract Award December 10, 1995 Mobilization/Start of Work January 1, 1996 Completion of Assignment July 30, 1996 7. Training in Occupational Health and Safety Complete TOR March 30,1995 Issue of Invitation for Proposals September 30, 1995 Receipt of Proposals October 30, 1995 Evaluation and Approval November 15, 1995 Negotiations & Contract Award December 10, 1995 Mobilization/Start of Work January 1, 1996 Completion of Assignment July 30, 1996 8. Training for Power Plant Operators Complete TOR June 30, 1995 Issue Invitation for Proposals July 24, 1995 Receipt of Proposals September 25, 1995 Evaluation and Approval October 22, 1995 Negotiations and Contract Award December 9, 1995 Mobilization/Start of Work Jan 2, 1996 Complete Phase 1 ( On-site training) June 20, 1996 Complete Study Tours August 20, 1996 10. Assessment of Hydroplant Rehabilitation Completion of Unfinished Hydro & Thermal Projects Complete TOR August 30, 1995 Issue Invitation for Proposals September 30, 1995 Receipt of Proposals November 15, 1995 Evaluation of Proposals and Approval December 15, 1995 Negotiations and Contract Award January 15, 1996 Draft Report July 10, 1996 Final Report September 10, 1996 TECHNICAL ASSISTANCE COMPONENT ITEM OBJECTIVE DURATION STATUS ESTIMATED COST IMPLEMENTING AND FINANCING AGENCY AGENCY. Study of Options of To assist the Government of September 1 1995 - Study to be launched in July US$2.7 million Interministerial Long-Term Power Romania in defining a September 1996. 1995. Committee of the Sector Structure, structure of the power sector United States Agency Government, including the legal and that will create conditions for for International assisted by the regulatory aspects. the eventual participation of Development Local Counterpart independent public and private (USAID). Team operators in a competitive environment. Long-Term Least-Cost To provide economic basis of September 1995- TOR agreed at negotiations. US$600,000. Ministry of Power Generation future investments in September 1996 Industries, and Development Study. development of power EU-PHARE/OTHER RENEL. generating capacity. Electricity and Heat To provide basis of setting September 1995 - June TOR agreed at negotiations. US$600,000/OTHER Ministry of Pricing Study. prices for economic efficiency 1996 for the load research Finance, Ministry and sector viability. and study of consumer USAID. of Industries, and characteristics; from RENEL. September 1996 - June 1997 for the study and development of tariff structure, and pricing system. (D o x Ih Corporate Restructuring To bring about efficiency Start of implementation Corporate Restructuring US$5 million, to be RENEL/ Program of RENEL improvements and commercial with assistance of foreign Program and Terms of financed under the PID/Corporate orientation and accountability consultants by October Reference for Consultant Bank loan; and $1 Restructuring of RENEL, through 1995, and complete already developed and rnillion by RENEL Committee. organizational and mnanagerial implementation by June agreed upon. Selection of (Total US$6 million). improvements, modernization 1998. Consultant by September of accounting and financial 1995. systems, revaluation of assets, down -sizing operation by spinning off of non-core activities into independent commercial companies, separation of nuclear power activities into an independent public entity. Auditing of 1995 To establish RENEL's To be completed in six Draft TOR pi-,pared and US$600,000. To be Project Financial Statement financial position on the basis months, starting June agreed with tie Bank. financed under the Implementation of internationally accepted 1996. Bank loan for the Department (PID), accounting practices, and to Technical Assistance and RENEL train RENEL staff in the and the Critical Accounting preparation of financial Imports Loan; Department. statements in accordance with (TACI); international accounting practices. Power Transmission To establish economic basis of To be completed in 9 Evaluation of consultants US$500,000, financed PID. system reinforcement rehabilitation improvements in months, starting March, proposals completed in late by EU-PHARE. and expansion the power transmission 1995. October 1994, Contract feasibility study network. award expected by January 1994. Feasibility study of To establish technical and To be completed in one TOR for Consultants US$2 million, to be PID. power distribution economic basis of rehabilitation year starting March 1996. prepared and agreed with the financed by EU- system rehabilitation, and improvements in the power Bank. PHARE in two and preparation of a distribution network stages. First stage to Master-Plan for power cost $US 1I.1 million distribution system. for feasibility study. (D o w Envirornmental To strengthen capability in To be completed in six TORs prepared and agreed US$250,000 to be PID. Management RENEL for Environmental months, starting with the Bank. financed by EU- Impact Assessment studies, air November 1995. PHARE. pollution modelling, data collection analysis, formulation of R&D programs, capacity building and organizational improvements for effective environmental management Occupational Health and To reduce occupational health Indefinite in Romania. TORF prepared and agreed US$500,000 to cover PID. Safety Training and safety risks in RENEL's Services of external with bank. services of operations through training. Occupational health and advisor/trainer, and safety advisor/trainer will study tour by RENEL be for 5 months. staff. To be funded by EU-PHARE. Fuel Sourcing and To provide RENEL with the Six months duration, Draft TOR prepared and US$300,000 to be PID. Supply Study, including basis for developing a starting July 1995. agreed with the Bank. funded by EU- assessment of storage comprehensive strategy on fuel PHARE. c infrastructure, and procurement and supply alternative means of fuel transportation Assessment of To establish their economic Nine months from TOR agreed at negotiations. US$500,000. EU- PID Hydroplant merit in sector development January 1996 to PHARE. Rehabilitation & program. September 1996. Completion of Unfinished Hydro and Thermal Plants. Training for Plant To enhance operation and About seven months (4 TOR completed. US$500,000. EU- PID Operators maintenance of power plants. on-site in Romania, 3 for PHARE study tours). Footnote: (D on o x 99 Annex 3.3 Page 16 of 25 LOAN DISBURSEMENT SCHEDULE Bank Fiscal Year Cumulative Disbursements and Disbursements Semester Ending SJS M) $ M) (9% of Total) FY 1996 December 31, 1995 2.0 2.0 2.0 June 30, 1996 18.0 20.0 18.0 FY 1997 December 31, 1996 22.0 42.0 38.0 June 30, 1997 18.0 60.0 54.0 FY 1998 December 31, 1997 17.0 77.0 70.0 June 30, 1998 13.0 90.0 82.0 FY 1999 December 31, 1998 13.0 103.0 94.0 June 30, 1999 5.0 108.0 98.0 FY 2000 December 3 1, 1999 2.0 110.0 100.0 ENVIRONMENT 11. A comprehensive Environmental Strategy Paper (ESP)' was prepared by the Bank and the Govemment, with the participation of other intemational bilateral and multilateral agencies in 1992, to define an environmental strategy for Romania that will (i) in the short term, reduce, in the most economic manner, current and likely severe impacts of environmental degradation on human health; and (b) build up a framework which will foster a long term economically sustainable environment. The environmental aspects of the proposed Project are designed to meet these objectives. An environmental analysis (EA) was prepared by foreign consultants for the Government to assess the magnitude of potential environmental impacts of the proposed project and to recommend measures to include in the Project to mitigate any serious pollution impact from future operations. 12. Against the above background, the EA has analyzed the extent of the pollution impact due to the rehabilitation and life extension, and actions on fuel switching, and unit retirement program. At some of the individual power plants, the combined effects of higher availability, increased power output at will lead to slight increases in emissions even at improved fuel use efficiencies, whereas at most others the incremental pollution will be less. The net effect is dramatic reductions in the emissions of all pollutants. Table I compares emissions levels pre- and post-rehabilitation. The EA proposed mitigating measures that are to be implemented under the proposed Project are identified below. 1/ Romania Environmental Strategy Paper - Report No. 10613-RO dated July 31, 1992. 100 Annex 3.3 Page 17 of 25 Recommended Mitigation Measures and Monitoring Mitigating Measures 13 The technical and economic solutions that will be implemented as part of the rehabilitation activities will lead to reduction of pollution. These encompass: (a) introduction of low NOx bumers and improvements in combustion systems will lead to reductions of NOx emissions in addition to the elimination of the problem of severe corrosion and damage to steam boilers; (b) improvements in fuel use efficiency through the rehabilitation of major unit components - boilers, turbines and generators- will lead to decreases in fuel consumption and pollutant emissions; (c) conversion to use of imported (low sulfur) hard coal at 11 lignite fired units primarily for economic reasons will lead to reductions in all pollutants from these units. (d) conversion to use of light fuel oil (about 1 % sulphur content) instead of heavy fuel oil containing sulphur of 3-4% and high content of corrosive impurities (notably vanadium), to improve operational life and performance of boilers, and save on maintenance costs will lead to significant reductions in NOx and S02. Recognizing the cost savings and the environmental benefits, RENEL had agreed to switch to use of light, fuel oil presently used in its oil-fired boilers. 14. As a specific environmental improvement measure, rehabilitation and modemization of ESPs at Isalnita, Deva, and at the stations to be converted from lignite to hard coal to raise operational efficiency levels to 98-99%, will reduce fly-ash and particulate emissions. 15. In addition, the above measures will lead to reductions in CO2 emissions, and Romania's contribution to global warming. Since Romania is net importer of transboundary S02 emissions, these actions will lead to Romania improving its transboundary pollution impact relative to the other countries. Estimates of Annual Potential Pollutant Emission Reductions are provided in Table 1. Table 1. Summary Estimates of Annual Potential Emission Reduction (thousand of tons) No% CO2 SQ .. ...D..... ....t. Initial Level 125067 38344075 777288 250097 Plant Retirement 16773 6932611 179040 37268 Fuel Switching 6988 405711 145695 6507 Boiler Rehabilitation 11769 3274241 39130 71403 Low NO, Bumer 35771 0 0 0 ESP Rehabilitation 0 0 0 36632 Total Reduction 5.......i 0 0 . 37325 : 10612563 . ..... .... - ......36 I 101 Annex 3.3 Page 18 of 25 Environmental Category 16. In accordance with OD 4.01 (Environmental Assessment), this project has been assigned to Category B. Since the project seeks to improve environmental performance of thermal power generation operations at a number of specific stations, this rating is deemed justified. Results presented in Table 1 support this view. The environmental analysis discussed earlier was designed to establish how these improvements were to be accomplished in the most cost-effective manner. UNIT RET77REMENT AND MOTHBALLING (PRESERVAT70N) PROGRAM 1993 1994 1995 1996 1997 1998 - 199 2000 Tucemi MB (2 x 330) Rovinari MB Unit 1, 2, 3 (2 x 200) (1 x 330) Insalnita R R R R (1 x 50) (1 x 50) (I x 100) (1 x 100) Doicesti R (3 x 30) Ovidiu R R (3 x 12) Paroseni R (3 x 50) Oradea R R (1 x 25) (1 x 25) Comanesti R (2 x12) Fintinele R R R (4 x 25) (I x 50) R (1 x 100) Brazi R R R R (1 x 50) (1 x 50) (1 x 50) (1 x 50) Galati R R (1 x 60) (1 x 100) Borzesti R (3 x 25) Iasi R R (1 x 25) (1 x 25) Arad R (1 x 25) MB = Mothballed (out of operation and placed in preservation). R = Retired (out of operation). 102 Annex 3.3 Page 19 of 25 TECHNICAL ASSISTANCE FOR TRAINING IN ENVIRONMENT MANAGEMENT A. Institutional Strengthening The following program of training and institutional strengthening for the Environment Department has been agreed upon: C lArea of training Number of staff Duration(weeks)/ Cost (000 US$) .....-....... V enue E Environment' Assessment 20 3/Romania 20.0 Monitoring Equipment Selection and Use (to be included in equipment purchase) Air Pollution Modelling 4 2/Overseas 44.0 Pollution Control 8 3/Overseas 70.0 Equipment Technology Ash Disposal Technology 4 2/Overseas 22.0 and Impacts Environment Data Indefinite 4/Romania 31.0 Collection and Analysis Environment Regulations 2 2/Overseas 22.0 and Strategy Occupational Health and 300.0 Safety Training 2/Overseas Computers, software, literature, professional journals 41.0 GRAND TOTAL 550.0 B. I Environmental Monitoring Monitoring equipment for air quality and water quality will consist of four vans. Two additional vans for emission monitoring will be provided under the current EIB loan with RENEL. As part of the TA program in Environment Management, staff of RENEL will receive training in the preparation of environmental monitoring plans in accordance with international practice. Subsequent to the training, RENEL will submit a satisfactory environmental monitoring plan to the Bank. A description of equipment and associated costs are presented below. 103 Annex 3.3 Page 20 of 25 Ambient Air Quality Monitoring Mobile Vans Item Quantity Cost (US$) Total (000 US$) So, 2 12,500 24.00 NOx 2 15,000 30.00 CO 2 14,000 28.00 Ozone 2 14,000 28.00 TSP* 2 6,100 12.20 THC** 2 16,100 32.20 Met*** 2 15,000 30.00 Calibrator 2 16,100 32.20 Zero Air 2 5,520 11.04 Data System 2 8,500 17.00 Manifold 2 2,500 5.00 Cables 2 1,500 3.00 Miscellaneous 2 29,325 58.65 Consumables 2 9,775 19.55 Recorders 2 7,820 15.64 Truck 2 31,625 63.25 TOTAL 470.91 Total suspended part ** Total Hydrocarbons *** Meteorology 104 Annex 3.3 Page 21 of 25 Water Quality Monitoring Mobile Vans Item Quantity Cost (US$) Total (000 $US) Shelter 2 30,590 61.18 ICAP 2 85,000 170.00 Spectrophotometer 2 25,000 50.00 Organics GC* 2 100,000 200.00 **AA w/ Graphite 2 85,000 170.00 Furnaces 2 10,000 20.00 Distiller 2 21,900 43.80 Meters (pH, etc.) 2 12,500 25.00 Digestion Unit 2 22,500 45.00 Glassware 2 75,000 150.00 Data System 2 15,000 30.00 Hoods/Benches 2 29,400 58.80 Cold Storage 2 25,000 50.00 Lab Support Equipment 2 21,275 42.55 Miscellaneous 2 10,000 20.00 Truck 2 31,625 63.25 TOTAL 1,199.58 Training and Installation 368.70 Spare Parts 553.60 GRAND TOTAL 2592.80 * Gas chramatograph. ** Atomic Absorption. B.2. Occupational Safety and Health Item Quantity T Cost (000 US$) Hydrogen Detector 20 12.50 Hydrogen Sulfide Detector 50 50.00 Methane Detector 50 50.00 Mobile van (dust, noise, asbestos etc.) 541.00 TOTAL 653.50 GRAND TOTAL 3246.30 105 Annex 3.3 Page 22 of 25 PROJECT IMPLEMENTATION DEPARTMENT (PID) The PID is managed by a Director under the Director General for Engineering and Research. The Director will be responsible for all matters related to the implementation of the project including overall project management, engineering, procurement, overseeing site construction, testing, commissioning and handing over to operations. The Director will be assisted at Headquarters in Bucharest by four Divisional Deputy Directors. - Deputy Director for Power Generation Engineering responsible, with the Engineering Consultant, for the technical specifications of the project, for providing engineering overall supervision, inspect the works at factories and site, interpret drawings, establish test procedures, give opinion on claims by the contractors, care for the application of the environmental, health and safety regulations; - Deputy Directors for Transmission and Distribution Engineering, the same as above regarding Transmission and Distribution; - Deputy Director for Procurement and Contracts responsible for the supervision of all the procurement activities putting together the complete bidding documents for each package, advertisement of tenders, prequalification procedures, bid appraisal, award recommendations, contract discussions, contract monitoring and closing. The Procurement and Contracts Deputy Director will be represented in all planning activities of the Department proving inputs in this area of expertise. This Manager will also monitor closely all the activities of the project that have a bearing on the procurement and on the contracts' economy. D Deputy Director for Budget and Finance will be responsible for the overall and detailed planning activities of the Department together with the Engineering and Project Management Consultant. He will be responsible for the timely provision of resources (staff and financial ) to the project, budget and cost control as well as the monitoring of the project activities. The Head office staff will be assisted at the sites by Site Managers who, together with the Consultant, will supervise the Contractors. The Site team under the Site Manager may vary from site to site but will always include a planning engineer in charge of closely monitor the project site activities. The team may include, as needed, mechanical and electrical engineers as well as support from accountants and secretarial staff. A Quality Assurance group will work directly under the Department Head so that its recommendations are necessarily considered in the development of project. For specific and difficult problems the Department Head may convene "ad hoc" technical advisory groups to recommend solutions. Organizational chart of the PID is attached. ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT ORGANIZATION CHART PROPOSED PROJECT IMPLEMENTA TION DEPARTMENT DEPIJTY DIRECTOR GENERAL i:t :| 7:::: :FOR::::: : :ii: DEPARTMENT FOR RESEARC}I AND ENGINEERING AD IIOC LOCAL DIRECTOR ENGINEERING TECHNICAL ADVISORY _ _______:___|| CONSULTANTS GROUP 7 ::QUALITY ASSURANCE : 0:0GROUF::7 I~~~~~~~~~ ________________________________________ Manager for Manager for Power Manager for Transmission Procurement Manager for Generation Engineering I | Distribution Engineering I and Contracts Budget & Finances Mechanical Engineering Electric Lines & Inside & Outside Planning ______________I_ Station Engineering Procurement Construction & Installation I I A Programming & Monitoring I ~~~Engineering IPower SystemsCntuto I ~~~~~~~~~Engineering Monitoring Electrical Engineering I s Budget & Control Costs Electrical Engineering l Technical Assistance Automations & Adjustment Programs Renumerstion Site Manager Contractor |D o x Site Manager Consultant Power Plant Operations | & Maintenance Liason " Site Manager RENEL & Functional Personnel 107 Annex 3.3 Page 24 of 25 OUTLINE OF THE QUARTERLY PROGRESS REPORT RENEL is required to submit Quarterly Progress Reports (QPR) the Bank on the implementation of the Project. The QPRs will be based on the consultants reports on the various project components. The QPRs will cover the following: Thermal Plant Rehabilitation and Conversion I1. Summary of Project Contracts and activities during the quarter. 2. Statement on planned and actual project physical implementation, including procurement, manufacturing, and construction at site. Explanation of deviations. 3. For each unit to be rehabilitated/boiler to be converted: 3.1 Contractor's progress to date: Design Dismantling Off-site manufacturing and refurbishment On-site refurbishment Re-erection Commissioning and performance testing. 3.2 Consultant's activities, progress on: definition of scope of work preparation of tender documents prequalification of tenders review of tenders received award of contract review of contractor's design, refurbishment proposals site activities. 3.3 Key events - comparison of actual with planned progress. 3.4 Identification and discussion of areas of concern 3.5 Technical Matters 3.6 Variations to Contract: Agreed to dates Possible future dates 3.7 Project Cost Report Cost estimates, including comparison to last estimate. 108 Annex 3.3 Page 25 of 25 Monthly disbursement by contract and by cofinancier. Outstanding amounts to be disbursed Appendices Contractor's Report . Photographs . Cash Flow forecast . Staffing -contractor and consultant . register of documents . programs . inspection report and release notes. Corporate Restructuring and Sector Reforms 1 . Summary of Decisions and Activities under RENEL's Restructuring Program. 2. Performance Indicators for RENEL administrative units, including financial indicators. 3. Reporting on Sector developments. 109 Annex 4.1 POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT Page 1 of 9 RENEL'S HISTORICAL AND PROJECTED CA SH FLOW (In US$ Million) -------- - ----- Budget ----------------------------Projected----------------------------- 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 Sales - - - - -- -- -- -- - - Electuicity(GWh) 52103 47178 45597 43300 44500 45600 46300 47800 48600 50000 ThennalEnergy OOOGca1) 42466 42539 45105 45105 45105 45105 45105 45105 45105 Operating Revenues ElectricitySales 1592 1591 1747 1816 1932 1962 2025 2059 2119 Thenml EnergySales 414 400 506 514 514 514 514 514 514 therOperatingRevenuea 83 69 41 45 49 54 59 65 72 TotalOperatingRevenues 2090 2060 2293 2374 2495 2530 2599 2639 2705 49.20 49.76 51.67 51.67 51.67 51.67 51.67 Average Electricity TarifflMWh 37.46 37.40 40.34 40.80 42.37 42.37 42.37 42.37 42.37 AverageThernalEnergyTariff 9.75 9.39 11.21 11.40 11.40 11.40 11.40 11.40 11.40 Cash Operating Costs r Purchase (Incl. Imports) 32 4 0 0 48 93 147 147 147 FuelCosts 1120 1117 1448 1591 1593 1602 1622 1678 1737 Salaries&Wages 429 447 359 312 289 268 248 230 213 Operation& Maintensnce 209 179 173 178 176 173 172 175 180 OtherOperatingCosts 125 107 109 112 114 116 118 121 123 TotalCashOperatingCosts 1915 1854 2090 2192 2220 2252 2307 2351 2401 Operating Income 174 206 203 182 276 278 292 288 304 Non-Operating ncomne 0 0 0 0 0 0 0 0 0 Total Interal Surplus 174 206 203 182 276 278 292 288 304 Income Taxes 1 2 0 0 0 0 0 0 0 Dekt Sea-vice Interest 7 2 53 70 59 80 109 126 140 Repaymnent 5 23 43 16 16 16 13 13 31 TotalDebtService 12 26 97 86 75 96 121 139 171 ChlngeinWorkingCapital 0 15 102 78 133 -15 0 9 10 Net Available For Investments 162 164 4 18 68 197 170 141 123 Investments Local Costs 4 18 68 197 170 141 123 Foreign Costs 256 232 271 270 339 267 227 Total Investments 523 444 260 250 339 467 509 408 350 New Debt New Local Debt 0 0 0 0 0 0 0 New Foriegn Debt 256 232 271 270 339 267 227 Total New Debt 361 280 256 232 271 270 339 267 227 Perfoniance Indicators Working Ratio 91.7 90.0 91.2 92.3 89.0 89.0 88.8 89.1 88.8 CurrentRatio 1.4 1.3 1.6 1.9 2.1 2.1 2.0 2.0 2.0 Debt Service CoverRatio 14.9 8.1 2.1 2.1 3.7 2.9 2.4 2.1 1.8 IntemalCashGeneration 31.0 36.9 10.5 22.7 31.8 45.4 37.8 34.1 33.3 110 Annex 4.1 Page 2 of 9 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT ASSUMPTIONS FOR FINANCIAL PROJECTIONS Macro-economic variables: 1995 1996 1997 1998 1: 999 2000 International Inflation (%) 2.0 2.5 2.7 2.5 2.6 2.7 Domestic Inflation (%) 35 20 15 10 10 10 Ex. Rate (Lei/US$) - EOP 2871 3032 3292 3397 3652 3919 Ex. Rate (Lei/US$) - Ave. 2280 2656 2974 3186 3419 3669 2. Electricity Sales Forecast: Derived from the Electricity Balances provided in Attachment I to this Annex. 3. Thermal Energy Sales: To remain constant at the 1994 level, as it is a by-product of electricity generation and no new thermal energy or CHP plants are to be installed. 4. Electricity Revenue: Derived from the Electricity sales and the net electricity tariffs of US$42.37 MWh, kept constant through 2000. 5. Thermal Energy Tariffs: Derived from the thermal energy sales and thermal energy tariffs of US$11.40/GCal on average, kept constant throughout the forecast period. 6. Other Operating Revenue: Includes income from contractual services provided by RENEL for auto-producers, rental income, etc. Expected to increase by 10% from 1994. 7. Fuel Costs: Derived from (i) the consumption of fuel in each plant, taking into account the efficiency improvements; and (ii) the prevailing prices of fuels in Romania, which are provided below: Annex 4.1 Page 3 of 9 Local Hard Coal 31,241 18.5 Average Transport Cost - Local 7,786 4.6 Imported Hard Coal 35,379 21.0 Average Transport Cost - Imported 11,364 6.7 Lignite (per ton) Local 19,857 11.8 Average Transport Cost - Local 4,988 3.0 Imported Lignite 36,644 21.7 Average Transport Cost - Imported 9,214 5.5 Fuel Oil (per ton) Local Fuel Oil 130,198 77.1 Average Transport Cost - Local 0 0 Imported Fuel Oil 140,499 83.2 Average Transport Cost - Imported 0 0 Natural Gas (per 1000 cu.M) Local Natural Gas 102,673 60.8 Average Transport Cost - Local 0 0 Imported Natural Gas 118,209 70.0 Average Transport Cost - Imported 0 0 The above fuel prices are expected to remain stable in US$ terms. The details of fuel consumption by type of fuel and the resulting Fuel Costs, are provided in Attachment 2 to this Annex. 8. Power Purchase Cost: No imports are envisaged during the forecast period, and RENEL will buy electricity from the (to be separated) nuclear entity form 1996 onwards. For the base case, a US cents 3/kWh power purchase cost is assumed. 9. Salaries and Wages: For 1995, salaries and wages would account for 0.75 US cents/kWh sold (i.e. 10% lower than 1994 to take into account a 10% reduction in personnel in 1994), and would remain at these levels in constant US$ terms thereafter, which means a reduction in salaries and wages equal to the annual international inflation. From 1996 on, the salaries and wages of nuclear personnel is excluded. 10. Operations & Maintenance: In 1994, 0 & M expenses amounted to 0.40 US cents/kWh and this level is expected to remain stable. 112 Annex 4.1 Page 4 of 9 11. Other Operating Costs: Includes management overheads, travel, training and miscellaneous operating expenses; expected to increase by 2% each year. 12. Debt Service: Service of existing debt projected on the basis of contractual terms and the debt service on future loans are on the basis of prevailing terms which are provided in Attachment 3 to this Annex. From 1996 the debt service on Cermavoda loans is excluded. 13. Income Taxes: RENEL is liable for taxes at 38% of taxable income, plus 90% of net profits have to be paid to the Government. RENEL and Mol have avoided payment of these high levels of taxes by artificially increasing the operating costs by a "Development Tax" through specific legislation. The Development Tax, which in effect is additional depreciation, was 8% of revenues in 1993 and was increased in 1994 to 12%, to avoid taxes and to leave resources for investments. MoF tacitly approves the idea of a development levy, since the present Romanian income tax laws do not allow for an investment allowance. Therefore, it is assumed that RENEL will not be liable for income taxes throughout the forecast period. 14. Working Capital: Current Assets 1995 1996 ~1997 14998 199-9 2.00 Cash (in weeks of operating cost) 3 4 4 4 4 4 Maint. Invent. (US cents/kWh 0.1 0.1 0.1 0.1 0.1 0.1 Fuel Inventories (months of fuel) 1.5 2 2 2 2 2 Accounts Receivable 60 60 60 60 60 60 Otier Current Assets (ann. 1% 1% 1% 1% 1% 1% Current Liabilities Fuel A/C Payable (months of 1.5 1.5 1.5 1.5 1.5 1.5 Cont. A/CPayable 2 1 1 1 1 1 Other Current liabilities (ann. inc) 5% 5% 5% 5% 5% 5% 15. Investment Program: RENEL's Investment Program is provided in Attachment 4 to this Annex. 16 Performance Criteria: RENEL's financial performance criteria, to be covenanted under the project are discussed in Chapter 4. 113 Annex 4.1 ROMANIA Page 5 of 9 POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT ROMANIAN ELECTRICITY BALANCES (GWh) -Historical- Budget ---- Projected- 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 Hydroelectric 14174 11622 12683 13000 12300 12500 12600 12700 12800 12600 Thermnal - Coal 17829 22141 22737 23300 26600 26600 26100 25100 26200 26500 Thermall-Hydrocarbo 22700 18615 18477 17200 18000 17400 17200 16900 16200 16400 Total Thermnal 40529 40756 41214 40500 44600 44000 43300 42000 42400 42900 Nuclear 0 0 0 0 0 1600 3100 4900 4900 4900 Total RENEL 54703 52378 53897 53500 56900 58100 59000 59600 60100 60400 Auto Producers 2200 1800 1500 1500 1200 1200 1200 1200 1500 1500 Total Gross Generatio 56903 54178 55397 55000 58100 59300 60200 60800 61600 61900 Net Inports 7000 4400 1900 1200 0 0 0 0 0 0 Less: Station Consum 6100 6100 5800 6200 6900 7000 6600 6600 6100 6000 NetAvailable at Busb 57803 52478 51497 50000 51200 52300 53600 54200 55500 55900 Less: Trans. & Dist. 5700 5300 5900 6100 6600 6700 6800 6400 6700 5900 Net Electricity Consu 52103 47178 45597 43900 44600 45600 46800 47800 48800 50000 Structure of Consumption Industry M;ining 7072 5525 5700 5000 4900 5000 5000 5100 5100 5200 Metullurgy 9148 6866 6100 6000 6000 6000 6000 6000 6200 6200 Chemical 6423 5667 5300 4900 5000 5000 5000 4800 4500 4500 Mechanical Engg. 4732 4249 4400 4300 4300 4400 4400 4400 4400 4300 Light Industry 3580 2379 2500 3300 3300 2900 2900 2900 3000 3000 Building Industry 1303 1613 1700 1800 1800 1800 1800 1800 1800 1800 Wood Processing 454 394 500 600 600 600 500 500 500 500 Others 2376 3454 3100 3500 3500 3600 3500 3500 3500 3500 Subtotal Industry 35088 30147 29300 29400 29400 29300 29100 29000 29000 29000 Agriculture & Constr 5144 2846 3150 2700 2800 2800 3000 3100 3200 3500 Transport 1786 2827 2000 2000 2200 2200 2500 2700 2700 3000 Conmnercial & Servic 2792 3320 4200 2600 3100 4000 4000 5000 5300 5800 Residential 6721 7596 6900 6600 7000 7300 7700 8000 8400 8700 Total Consumption 51531 46736 45550 43300 44500 45600 46300 47800 48600 50000 114 Annex 4.1 POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT Page 6 of 9 RENEL'S FUEL CONSUAMPTION & COSTS ----Historical---- - ------ Budget ------------Projected----- - Fuel Consumption 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 Hard Coal (000 tons) Local 3779.0 3937.2 4020.6 4269.9 3720.0 3720.0 3835.0 3935.0 4060.0 4225.0 Imported 0.0 131.6 500.6 1000.0 1200.0 1200.0 1250.0 1400.0 1450.0 1500.0 SubtotalHardCoal 3779.0 4068.8 4521.2 5269.9 4920.0 4920.0 5085.0 5335.0 5510.0 5725.0 Lignite COOO tons) Local 24450.9 33145.2 35306.6 35083.4 40250.0 40450.0 41650.0 44500.0 48300.0 52000.0 Imported 2744.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtotal Lignite 35306.6 35083.4 40250.0 40450.0 41650.0 44500.0 48300.0 52000.0 Fuel Oil ('000 tons) Local 3349.2 3909.2 2903.3 2283.1 2230.0 2250.0 2290.0 2300.0 2300.0 2300.0 Imported 2430.0 1475.5 1870.0 1835.0 1650.0 1298.0 1251.0 1243.0 Subtotal Fuel Oil 5333.3 3758.6 4100.0 4085.0 3940.0 3598.0 3551.0 3543.0 Natural Gas (Million Cu. M) Local 9893.0 8476.9 7759.9 5769.9 5400.0 5400.0 5400.0 5400.0 5400.0 5400.0 Imported 0.0 2230.1 3200.0 3200.0 3200.0 3200.0 3200.0 3200.0 Subtotal Natural Gas 7759.9 8000.0 8600.0 8600.0 8600.0 8600.0 8600.0 8600.0 Total Fuel Consumption (MTOE) Fuel Coats (USS Million) Hard Coal Local 98.7 86.0 86.0 88.6 90.9 93.8 97.6 Imported 27.7 33.2 33.2 34.6 38.8 40.1 41.5 Subtotal Hard Coal 126.4 119.2 119.2 123.2 129.7 134.0 139.2 Lignite L.ocal 516.2 592.2 595.1 612.8 654.7 710.6 765.1 Imported 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Subtotal Lignite 516.2 592.2 595.1 612.8 654.7 710.6 765.1 Fuel Oil Local 176.0 171.9 173.5 176.6 177.3 177.3 177.3 Imported 122.8 155.6 152.7 137.3 108.0 104.1 103.4 Subtotal Fuel Oil 298.8 327.5 326.1 313.8 285.3 281.4 280.7 Natural Gas Local 350.8 328.3 328.3 328.3 328.3 328.3 328.3 Imported 156.1 224.0 224.0 224.0 224.0 224.0 224.0 Subtotal Natural Gas 506.9 552.3 552.3 552.3 552.3 552.3 552.3 Total Fuel Costs 1448.2 1591.2 1592.8 1602.2 1622.0 1678.3 1737.3 115 Annex 4.1 Page 7 of 9 Existing Foreign Loans: Loan Amount (millions) 25.0 32.0 115.0 22.8 149,200 319.4 Currency of Loan ECU DM DM US$ Italian Lira C$ Repayment period (years) 13.0 6.0 10.0 8.0 12.0 14.0 Grace Period (years, Inclusive) 3.0 0.0 0 2.0 4.0 4.0 Interest Rate (%) 8.0 8.5 8.5 8.0 10.6 8.2 Commitment fee, etc. (%) 0.0 0.25 0.25 0.25 0.38 0.5 Proposed Loans IBRD EIB EBRD OTHER Loan Amount (million) Currency of Loan US$ ECU EC US $ Repayment period (years) 20 12 12 12 Grace Period (years, Inclusive) 5 4 4 4 Interest Rate (%) 8 8 8 8 Commitment fee, etc. (%) 0.25 0.0 1.00 0.25 116 Annex 4.1 ROMANIA Page 8 of 9 POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT RENEL 'S INVESTAENT PROGR4Af Total Budget - ----------Projected------------------ --- 1994- Investments 1994 1995 1996 1997 1998 1999 2000 2000 Thermal Plant Rehabilitation Local 0.9 2.8 26.0 49.9 64.3 50.6 34.8 211.6 Foreign 242.3 28.4 64.5 96.4 106.8 83.1 57.0 401.0 Total 243.2 31.2 90.5 146.3 171.1 133.6 91.7 612.6 Hlydro Plant Rehabilitation Local 0.0 0.6 0.6 0.0 0.0 0.0 0.0 1.0 Foreign 0.0 0.8 0.8 0.0 0.0 0.0 0.0 1.4 Total 0.0 1.4 1.4 0.0 0.0 0.0 0.0 2.4 Trans. & Dist. Rehabilitation Local 3.2 5.0 5.3 7.5 0.0 0.0 0.0 15.7 Foreign 13.8 21.3 22.9 31.9 0.0 0.0 0.0 67.1 Total 17.( 26.2 28.2 39.4 0.0 0.0 0.0 82.8 EMS/SCADA Modernization Local 0.0 0.0 0.9 0.9 0.9 0.9 9.1 12.2 Foreign 0.0 0.0 2.0 2.1 2.0 2.2 16.8 23.9 Total 0.0 0.0 2.9 3.0 2.9 3.0 25.9 36.1 New Projects L.ocal 0.0 9.5 32.6 127.2 91.4 74.6 63.2 368.4 Foreign 0.0 179.5 172.2 124.8 203.0 154.5 125.0 874.1 Total 0.0 189.0 204.8 252.0 294.4 229.2 188.2 1242.5 lTotal Investrnents Local 4.1 17.8 65.5 185.5 156.6 126.1 107.1 608.9 Foreign 256.1 230.0 262.3 255.1 311.8 239.7 198.8 1367.5 Total 260.2 247.8 327.8 440.6 468.5 365.9 305.8 1976.4 Total Budget -------------- 1994- lnvestrnents(CurrentUS$) 1994 1995 1996 1997 1998 1999 2000 2000 Thermal Plant Rehabilitation lIocal 0.9 2.8 26.9 52.9 69.9 56.4 39.8 248.7 Foreign 242.3 28.7 66.6 102.1 115 1 92.6 65.2 471.3 Total 243.2 31.5 93.5 155.0 186.0 149.0 105.0 720.0 Ilydro Plant Rehabilitation Local 0.0 0.6 0.6 0.0 0.0 0.0 0.0 1.2 Foreign 0.0 0.8 0.8 0.0 0.0 0.0 0.0 1.6 Total 0.0 1.4 1.4 0.0 0.0 0.0 0.0 2.8 Trans. & Dist. Rehabilitation 0 Local 3.2 5.0 5.5 7.9 0.0 0.0 0.0 18.4 Foreign 13.8 21.5 23.6 33.8 0.0 0.0 0.0 78.9 Total 17.0 26.5 29.1 41.7 0.0 0.0 0.0 97.3 EMS/SCADA Modernization Local 0.0 0.0 0.9 1.0 1.0 1.0 10.4 14.3 Foreign 0.0 0.0 2.1 2.2 2.2 2.4 19.2 28.1 Total 0.0 0.0 3.0 3.2 3.2 3.4 29.6 42.4 New Projects Local 0.0 9.6 33.7 134.8 99.4 83.2 72.3 433.0 Foreign 0.0 181.3 177.8 132.2 220.7 172.3 143.1 1027.4 Total 0.0 190.9 211.5 267.0 320.1 255.5 215.4 1460.4 Total Investments Local 4.1 18.0 67.6 196.6 170.3 140.6 122.5 715.6 Foreign 256.1 232.3 270.9 270.3 339.0 267.3 227.5 1607.3 Total 260.2 250.3 338.5 466.9 509.3 407.9 350.0 2322.9 117 Annex 4.1 Page 9 of 9 RENEL's Financial Performance Criteria and Definition of Terms used RENEL will be required to: (a) meet, each year beginning 1995, from its internal sources, at least 30% of its average annual capital expenditures (averaged over the previous, current and the immediate next years), and (b) ensure that RENEL's DSCR is not less than 1.5. The definitions of terms used are: (a) capital expenditures include all investments related to RENEL's electricity and thermal energy operations. Interest and other charges to construction shall be excluded. (b) Local costs of its capital expenditures are the expenditures incurred by RENEL in local currency (Lei) for local materials, goods, services, environmental abatement, rehabilitation, new capacity development, etc. (d) internal sources of funds means the difference between: the sum of net revenues of RENEL and reductions in working capital other than cash; and the sum of debt- service and increases in working capital other than cash. (e) Net revenues are the difference between: the sum of revenues from all sources related to operations and net non-operating income; and the sum of all expenses related to operations including administration, adequate maintenance, taxes and payments in lieu of taxes, but excluding provision for depreciation, other non-cash operating charges and interest and other charges on debt. (f) Net non-operating income is the difference between: revenues from all sources other than those related to operation; and expenses; including taxes and payments in lieu of taxes, incurred in the generation of revenues from all sources other than those related to operations. (g) Total operating expenses include all expenses related to operations, including administration, adequate maintenance, taxes and payments in lieu of taxes, and provision for depreciation, but excluding interest and charges on debt; (h) Working capital other than cash means the difference between all current assets excluding cash and current liabilities. (i) Current assets excluding cash means all assets other than cash which could in the ordinary course of business be converted into cash within twelve months, including accounts receivable, marketable securities, inventories and prepaid expenses properly chargeable to operating expenses within the next fiscal year. (j) Current liabilities means all liabilities which will become due and payable or could under circumstances than existing be called for payment within twelve months, including accounts payable, customer advances, debt-service requirements, taxes and payments in lieu of taxes and dividends. (k) Debt service requirements is the aggregate amount of repayments (including sinking- fund payments if any) of, and other charges on, long-term debt. (I) Long-term debt is the indebtedness of RENEL, with the foreign portion appropriately revalued, which has a maturity of more than one year. 118 Annex 5.1 Page I of 14 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT ANALYSIS OF PROJECTJUSTIFICATION Introduction 1. The analysis of economic justification is carried out in two stages. The first stage establishes that the proposed Project is the least-cost means of meeting the demand for electricity and thermal energy, and of restoring dependable base-load capacity in the power supply system, compared to other alternatives feasible options considered, including electricity imports. The second stage establishes that the investment in rehabilitation of the selected thermal units is economically profitable, in that the rate of return is in excess of the long-term opportunity cost of capital to Romania. 2. Analysis of future demand for electricity and thermal energy is based on the assumption that in view of the economic transformation that is still going on, which will reduce the energy intensity of the economy, demand will remain depressed below the 1990 levels until about year 2005. The projected demand has been used to evaluate the economic merits of the Project in terms of need and its timing. Least- Cost Analysis 3. The results of the preliminary Least-cost Power Generation Expansion study carried out by consultants for RENEL assigned priority to the rehabilitation of existing power generating facilities. To complement this finding, and to properly establish the merits of rehabilitation among the alternatives considered in the least cost analysis, the detailed technical inspection and feasibility study of thermal units/plants rehabilitation (discussed in Chapter III) was undertaken by consultants for RENEL. The study was focused on thermal plants because of their critical importance in providing based-load capacity, and the rapid deterioration in their operational performance. 4. The study concluded that the thermal plants are in a more degraded and unsafe operating condition than assumed in the least-cost study, and as such unless urgent rehabilitation is undertaken, a number of them would cease to be operational within the next five years, and the generating system would begin to experience serious deficiencies in base-load capacity as early as 1995. The future electricity demand profile indicates that for the foreseeable future, the system's priority need will continue to be base load capacity, as opposed to peaking capacity, because of the continuing relatively high proportion of industrial demand. 5. The methodological approach of the feasibility study called for detailed inspection,including non-destructive testing (NDT) of materials, assessment of creep damage, remnant life analyses of parts of unit components and auxiliary plant items. This was to determine the level of economic rehabilitation necessary to achieve life extension levels compatible with the current status of the plants/units. The inspections enabled the determination of costs and benefits associated with three levels of rehabilitation as follows: * level 1 - rehabilitation for 7 years life extension (50,000 hours of operating duty); * level 2 - rehabilitation for 15 years life extension (100,000 hours of operating duty); and 119 Annex 5.1 Page 2 of 14 * level 3 - rehabilitation for 25 years life extension (150,000 hours of operating duty). 6. The feasibility study was conducted on eleven representative thermal units selected on the basis of type of technology, unit size, fuel type, age, and operating history. The criteria and selection was based on an initial field survey carried out by the Bank and consultants. The representative unit candidates were: Unit size Fuel type Operational In-service Station Name (MW) (Primary) Type Year Isalnita 315 Lignite condensing 1967 Rovinari 330 Lignite condensing 1979 Braila 330 gas co-gen (CHP) 1979 Braila 210 gas co-gen Brazi 200 HFO condensing 1972 Palas 50 gas co-gen Palas 150 gas co-gen 1979 Deva 210 hard coal condensing 1969 Braila 210 HFO/gas co-gen 1973 Palas 50 gas co-gen 1970 Bucuresti Sud 100 HFO/gas co-gen 1967 7. In determining the appropriate level of rehabilitation for each representative unit candidate, a lifetime cost analysis was first undertaken. The lifetime cost analysis was considered appropriate since the preliminary least-cost analysis had already enabled comparison between the plants/units. The analysis follows a conventional approach, based on comparison of alternatives over a reasonably long period, to bring the alternatives to a common basis in terms of power and energy capability for comparison. The alternatives considered comprised: (a) no rehabilitation or replacement with an alternative new plant; (b) rehabilitation to level 1; (c) rehabilitation to level 2; (d) rehabilitation to level 3, using the associated incremental capital, operating and maintenance costs. 8. The evaluation considered: * a lifetime of 25 years. If the unit' without or with rehabilitation, is expected to have a shorter life, then a notional replacement plant is allowed for in the cost stream; * capital costs include the cost of notional replacement plant at the expiry of the life of the existing plant. Any such new plant is assumed to have the same net output as the plant it replaces, and is costed accordingly; * a capital credit is allowed in respect of the unexpired life of any plant at the end of the 25 year life; * in some cases, rehabilitation is expected to lead to an increase in the sent out capability of the unit, i.e a recovery of lost output. Some credit is due on this account. This credit is calculated as a debit to the un-rehabilitated unit: a notional capital cost is debited to the relevant lifetime costs, the cost being proportional to the shortfall; 120 Annex 5.1 Page 3 of 14 * if the un-rehabilitated unit is incapable of matching the energy output of the rehabilitated unit (because it is de-rated) then the energy shortfall is calculated at the energy cost of the unrehabilitated unit. The reasoning behind this approach is that, in a well run system, there should be no other unloaded unit of lower operating cost. Therefore, the shortfall must be made up by a unit of equal higher operating cost; * fuel costs are calculated on an annual capacity factor of 60 percent, i.e on the basis that the plant will be operating as base load plant; * the cost of operation and maintenance is calculated according to normal planning procedures, taking into account the type of plant and the fuel; and * the total costs are present valued to a common date employing a range of discount rates and the lifetime cost of energy is deduced. 9. Capital Costs: The capital cost estimates comprise expenditure on dismantling and removal of equipment to be replaced, provision of equipment, materials, engineering services and on-site supervision and installation of replacement equipment. The estimates of cost of replacement equipment take into account that some manufacturing of equipment will be done in Romania, but allow for imports of necessary foreign inputs, application of Western standards of design, quality control of materials and workmanship for the construction as well. The cost estimates include physical contingency of about 15% compared to 5-10% for new plants. For rehabilitation to levels 2 and 3 life extension, the costs include installation of low NoX burners, and for the lignite/coal fired units complete rehabilitation of electrostatic precipitators. No allowance is made for installation of flue gas desulphurization (FGD) equipment. 11. Annual Fixed Operation and Maintenance Cost: This is calculated as percent of total capital cost of a new plant alternative of the relevant fuel type and capacity. The estimates used are: for gas fired unit (1.9%), and about 2% for oil and lignite/coal. 12. Fuel Costs: Local lignite and coal costs to RENEL comprise the marginal cost, ex-mine plus rail transport cost to the plant. Imported hard coal is priced at CIF Constanza plus local transport cost. Fuel oil is priced at import parity plus local transport cost. To minimize the corrosive effects, and reduce operating costs, the oil fired units would switch to fuel oil of 1 % sulphur content. Natural gas is priced at import parity plus local transmission costs. Table 1 summarizes fuel prices and fuel data. 121 Annex 5.1 Page 4 of 14 Table 1- Fuel Prices and Fuel Data Heavy Fuel Oil Lignite Hard Coal 1% 3.5% s. l%s Gas Price Ex-mine $/t 15.0 - - - - Border Price $/t - 40 85 110 - Border Price $/1000 Nm3 - - - - 90 Calorific Values HHV kjlkg 8800 - - - - HHV kJ/Nm3 - - - - 37150 LHV kj/kg 7300 24000 42600 42600 - LHV kj/Nm3 - - - - 33500 Specific Price (LHV) USc/MJ 0.20 0.167 0.2 0.258 0.27 12. Unit Efficiency: Due to lack of metering, reported unit efficiency had been treated with caution. Consultants estimates of efficiency to be expected after rehabilitation are in accordance with values to be expected from plant in good condition, properly operated, having regard to the type of plant and expected mode of operation as a base load plant. The efficiency rates are based on annual averages. For the co-generation units, the higher efficiency is allowed for by transferring the benefit as heat producers to their role as electricity producers. 13. Availability: As with efficiency, consultants estimates of the future availability of the units without rehabilitation are based on statistical evidence. For post-rehabilitation, is based on intended degree of reliability, with adjustment for regular scheduled maintenance and forced outages of about 8 weeks and 2 weeks respectively leaving 41 week (7,000 hours) availability, 80%, per year. 14. Remaining life: The list of items to be replaced, repaired and overhauled commensurate with each level of rehabilitation was identified for each unit candidate. For the oil and gas fired units rehabilitation to level 3, is possible because most major components of the unit have been previously replaced. 15. Annual capacity factor: This is based on the assumption that the units will be operated as base-load units at an annual capacity factor of 80% - equivalent to annual operation over 7000 hours at an average output of 75% of rated capacity. 16. Benefits: The potential quantifiable benefits of rehabilitation are: * increased availability; * increased efficiency; 122 Annex 5.1 Page 5 of 14 * longer life; and * increased power output. These are estimated for each level of rehabilitation. 17. Utilizing the above information, the following alternatives were evaluated on the basis of life cycle costs to determine whether to proceed with rehabilitation or not: * no rehabilitation; * rehabilitation to level 1; * rehabilitation to level 2; and * rehabilitation to level 3. The results are: * rehabilitation is the preferred option compared to new plant alternative; * co-generation units yield lower costs than electricity only units; * for oil and gas fired units, level 3 yields the lowest life cycle costs; and * the difference in capital costs between levels 2 and 3 is relatively small except for lignite and coal-fired units for which the greater life extension of level 3 implies the need to install flue-gas desulphurization units. Capital costs of level I rehabilitation is markedly less than level 2 or 3, but economic benefits are more than proportionally lower. 18. The general conclusion from the above is that a significant number of thermal units could be candidates for rehabilitation. To arrive at the optimum number of candidates, the following factors were considered: (a) pollution impact, necessitating that coal fired units be limited to level 2 rehabilitation; (b) risk of under-performance of units with design problems. Units with history of reliable performance were given priority in the selection; and (c) social issues such as the need to service district heating systems, and the care of the environment. Gas fired cogeneration units were accorded highest priority. 19. The results showed that the gas-fired units are the highest in ranking, followed by oil-fired cogeneration units, and the condensing solid fuel-fired units as lowest in ranking. These are shown in Table 2. 123 Annex 5.1 Page 6 of 14 Table 2 - Rehabilitation Program Life Cycle Cost Rehabilitation Station USc/kWh Level Bucuresti Sud (2x100 MW) 2.85 3 Palas (IX 50 MW) 2.54 3 Palas (lx15O MW) 2.68 3 Braila (2x 210 MW) 3.50 3 Deva (2x210 MW) 3.52 2 Isalnita (2x315 MW) 4.40 2 Brazi (2x200 MW) 3.80 3 20. The above program will reinstate about 2,320 MW of firm dependable base load capacity that would otherwise be lost without rehabilitation. To establish that the proposed rehabilitation program is the least- cost solution, it was compared to other options of providing base load capacity. The comparison shows that the rehabilitation of the thermal units is economically more favorable than alternatives which include: (a) completion of Units 2 and 3 of the Cernavoda nuclear power plant and of unfinished hydropower plants, with storage reservoirs, on firm energy capability basis; and (b) gas fired combined-cycle alternative. The time constraint in making capacity available is an added advantage of rehabilitation over new units. The possibility of imports of electricity from Ukraine was examined, but was disregarded because it would be more expensive than the production from the rehabilitated units, and in addition, it could not be relied upon as a source of firm continuous supply to meet base-load requirements. However, during critical periods of demand, when some of the large units would be under rehabilitation, imports may be needed to supplement local supply. Table 3 provides the comparison. Table 3. Comparison of Highest Cost Rehabilitation Candidate with Other Options USCents/kWVh (Life-time Costs at 10% Discount Rate) Isalnita a/ 4.4 Cemavoda Unit 2 6.8 Cemavoda Unit 3 6.9 Dimbovita Hydropower Plant b/ 6.2 Bistra Hydropower Station b/ 9.4 Combined Cycle 5.5 Electricity Imports 5.2 a/ Highest cost rehabilitation candidate. b/ On the basis of estimated firm energy production capability. 21. There are uncertainties concerning the additional cost to completion of the Cernavoda nuclear power units, which should be established by a detailed engineering assessment. In addition, the costs do not include de-commissioning and spent fuel disposal costs. It is highly improbable that imported nuclear fuel will be used in Cernavoda since the local mining and fuel processing infrastructure has not been established. Annex 5. 1 124 Page 7 of 14 22. Even with the reinstatement of capacity that the rehabilitation provides, the power system may be barely able to meet the demand. Table 4 compares available dependable continuous power output with demand on the system by year 2000. Table 4 - Dependable Continuous Power Output and Demand (MW) i i i Q ~~~Actual E sti0mate; 1992 2000 Maximum Thermal Plant Power Output Pre-rehabilitation (MW) 5,500 3,500 Reinstatement of Capacity through rehabilitation - 2,320 Other RENEL Rehabilitation - 600 New Plant Additions (i) Cernavoda Unit 1 - 630 (ii) Turceni 8 - 270 (iii) Other Thermal - 180 Total Thermal 5,500 7,530 Firm Hydropower Output 2,000 2,000 Total Firm Dependable Capacity 7,500 9,530 Maximum Demand 9,500 9,100 Imports 2,000 430 Lignite to Imported Hard Coal Conversion 23. The technical inspection and feasibility study conducted on the lasi cogeneration lignite fired unit was to establish the technical and economic merits of conversion of 11 similar units (1 lx50 MW cogeneration) to use of imported hard coal as the primary fuel. The results confirmed the technical and economic justification for such conversion. An additional important benefit is the reduction in air pollution and lower volume of ash disposal that the conversion would bring about. 24. The economic merit is the curtailment of the uneconomic transportation of lignite over long distances (300-600 km). At the lasi power station the economic cost of lignite delivered is about US$25/ton compared to the delivered cost of imported hard coal through Constanza port of about US$50/ton. To establish the economic merit of the conversion, the present value of economic cost of lignite at the power station over the life of the unit was compared with the present value of the incremental capital and fuel cost for the conversion over the same life of the unit. The former was estimated at US$140 million compared with US$60 million for the latter. In addition, operation and maintenance costs will be lower in the case of the conversion. 25. Similar analysis has been extended to the other 10 units at the different locations in the North Eastern part of the country. The conversion of the units, apart from the environmental benefits, provides a least-cost means of serving the same quantity of heat and electricity demand. 125 Annex S.1 Page 8 of 14 Rate of Return Analysis 26. The rate of return on the investments in the rehabilitation component is estimated to be about 21 %. Computations are provided in Table 6. The analysis follows the traditional approach of comparing quantifiable incremental costs and benefits to the power system of the rehabilitation program. The estimates of investment costs and of fixed operation and maintenance costs are based on the estimates of the consultants that conducted the feasibility study. Fuel costs are estimated at improved unit efficiencies resulting from rehabilitation, and fuel prices reflect border prices. Allowance is made for outage cost, which represents the incremental cost to the power system of units being taken out of service for rehabilitation, and their outputs replaced by increasing the output of less efficient thermal power units in the system. The estimate of the outage cost is based on the additional fuel and other variable operating costs of the less efficient units. The outage costs are estimated as follows: 1997 = US$7million 1998 = US$40million 1999 = US$45million 2000 = US$10million All costs are expressed in economic terms and in prices of January 1994. 26. The quantifiable benefits comprise: (a) fuel savings from improved unit efficiency; (b) increase in electricity production resulting from increase in power output, and improved availability; (c) savings in consumption of support fuel- natural gas and fuel oil- in the lignite and coal fired units through improved loading of units, and reduction in stops and starts of the units; (d) improvement in quantity and reliability of heat supply, which is captured through credit of the efficiency of cogeneration to electricity production. 27. Incremental electricity sales is valued at the average electricity price of US cents 5/kWh, the agreed average price under the SAL, which the Government is committed to maintain in real terms through periodic adjustments for exchange rate changes, as a proxy for the benefits of electricity consumption. Other Benefits 28. For the conversion, incremental costs consist of the capital cost of the conversion and the associated fixed operation and maintenance costs. The benefit is the savings in cost of fuel delivered, and operation and maintenance costs. An added benefit (not quantified) is the reduction in pollution that the conversion will bring about. 29. Other benefits, which are not readily quantifiable, are associated with the improvements in the quality of the environment discussed earlier, mainly the reduction in air pollution that the rehabilitation will bring about. Additional benefits will arise from improvements in management and associated operational cost reductions arising from the corporate restructuring program. Sensitivity Analysis 30. Sensitivity analysis was carried out to test the robustness of the economics of the project. A 20% increase in capital costs could arise in rehabilitation work of this nature due to greater than expected plant deterioration that might be uncovered during implementation. Other considerations are that the rehabilitation might not achieve the expected improvements in fuel use efficiency and availability, thus leading to higher fuel consumption, and that the targeted level of reliability may not be achieved. Reduction of 10% in fuel use efficiency and expected availability improvements are 126 Annex 5.1 Page 9 of 14 assumed. The robustness of the project economics was examined under the extreme condition of all those effects occurring simultaneously, which is considered to be highly unlikely. Even under such highly unlikely conditions, the rate of return would still be about 10%, and this figure does not include benefits that cannot quantified, including consumer surplus and environmental benefits. Hence the economic justification of the project is considered to be robust. 32. The results of the analysis shown in Table 5 indicates the robustness of the economic rate of return in the face of increased capital costs and reductions in fuel use efficiency and electricity Production, as well as at the lower electricity price. Detailed calculations are presented in Tables 6- 10. Table 5 - Results of Sensitivity Analysis NPV (US$000) RoR (%) Base Case 272 21 (a) 20% increase in capital cost 229 18 (b) 10% reduction in fuel efficiency 185 17 (c) 10% reduction in availability 126 15 (d) Reduced Project Scope 187 18 (e) Combination of (a), (b) and (c) 0 10 Calculations are provided in Table 6-10. 127 Annex 5.1 Page 10 of 14 Table 6 - Economic Rate of Return Analysis - Base Case (US$ Million - January 1994 Price) Fuel and Other Variable Capital fixed Outage Operating Total Total Net Year. Cost O & M Cost Costs Cost Benefits Benefits 1995 3.50 3.50 -3.50 1996 22.80 22.80 -22.80 1997 115.00 7.00 122.00 -122.00 1998 130.70 0.40 40.00 32.70 203.80 45.40 -158.40 1999 18.10 1.30 45.00 67.20 131.60 115.90 -15.70 2000 15.40 1.70 10.00 77.30 104.40 138.60 34.20 2001 5.60 173.20 178.80 285.20 106.40 2002 5.60 173.20 178.80 285.20 106.40 2003 5.60 173.20 178.80 285.20 106.40 2004 5.60 173.20 178.80 285.20 106.40 2005 5.60 173.20 178.80 285.20 106.40 2006 5.60 173.20 178.80 285.20 106.40 2007 5.60 173.20 178.80 285.20 106.40 2008 5.60 173.20 178.80 285.20 106.40 2009 5.60 173.20 178.80 285.20 106.40 2010 5.60 173.20 178.80 285.20 106.40 2011 5.60 173.20 178.80 285.20 106.40 2012 5.60 173.20 178.80 285.20 106.40 2013 5.60 173.20 178.80 285.20 106.40 2014 5.60 173.20 178.80 285.20 106.40 2015 2.00 87.40 89.40 161.30 71.90 2016 2.00 87.40 89.40 161.30 71.90 2017 2.00 87.40 89.40 161.30 71.90 2018 2.00 87.40 89.40 161.30 71.90 2019 1.60 54.70 56.30 115.90 59.60 2020 0.70 20.20 20.90 45.40 24.50 2021 0.35 10.10 10.45 22.70 12.25 NPV 217.63 35.27 80.06 1,166.76 1,186.90 1,942.46 272.49 IRUR 20.87% 128 Annex 5.1 Page 11 of 14 Table 7- Economic Rate of Return Analysis - Increase Capital Cost by 20% (US$ Million - January 1994 Price) ... ... . .a r..b.e. .... . . .. .. 199 4.2 4.2 - SLb4.20 1996 27.36 27.36 -27.36 1997 138.00 7.00 145.00 -145.00 1998 156.84 0.40 40.00 32.70 229.94 45.40 -184.54 1999 21.72 1.30 45.00 67.20 135.22 115.90 -19.32 -2000 18.48 1.70 10.00 77.30 107.48 138.60 31.12 2001 5.60 173.20 178.80 285.20 106.40 2002 5.60 173.20 178.80 285.20 106.40 2003 5.60 173.20 178.80 285.20 106.40 2004 5.60 173.20 178.80 285.20 106.40 2005 5.60 173.20 178.80 285.20 106.40 -2006 5.60 173.20 178.80 285.20 106.40 2007 5.60 173.20 178.80 285.20 106.40 2008 5.60 173.20 178.80 285.20 106.40 2009 5.60 173.20 178.80 285.20 106.40 2010 5.60 173.20 178.80 285.20 106.40 2011 5.60 173.20 178.80 285.20 106.40 2z012 5.60 173.20 178.80 285.20 106.40 2013 5.60 173.20 178.80 285.20 106.40 2014 5.60 173.20 178.80 285.20 106.40 2015 2.00 87.40 89.40 161.30 71.90 2016 2.00 87.40 89.40 161.30 71.90 2017 2.00 87.40 89.40 161.30 71.90 2018 2.00 87.40 89.40 161.30 71.90 2019 1.60 54.70 56.30 115.90 59.60 2020 0.70 20.20 20.90 45.40 24.50 2021 0.35 10.10 10.45 22.70 12.25 ,,N.?,V,- 261-t.,,0 . 1535 .27 80... .0........... 1 .....3:194 .46 ...... IRI~~~~~~~~~~ 18.16%...... .... .. 129 Annex 5.1 Page 12 of 14 Table 8 - Economic Rate of Return Analysis - Increase Fuel Cost by 10% (US$ Million - January 1994 Price) - Fuel and Other . . .. Variable ...... ap..aP Fixed Outage Operating Total Total Net Ct. . & M - Cost Costs Cost Benefits Bnemrs 1995 3.50 3.50 -3.50 1996 22.80 22.80 -22.80 1997 115.00 7.00 122.00 -122.00 1998 130.70 0.40 40.00 35.97 207.07 45.40 -161.67 1999 18.10 1.30 45.00 73.92 138.32 115.90 -22.42 2000 15.40 1.70 10.00 85.03 112.13 138.60 26.47 2001 5.60 190.52 196.12 285.20 89.08 2002 5.60 190.52 196.12 285.20 89.08 2003 5.60 190.52 196.12 285.20 89.08 2004 5.60 190.52 196.12 285.20 89.08 2005 5.60 190.52 196.12 285.20 89.08 2006 5.60 190.52 196.12 285.20 89.08 2007 5.60 190.52 196.12 285.20 89.08 2008 5.60 190.52 196.12 285.20 89.08 2009 5.60 190.52 196.12 285.20 89.08 2010 5.60 190.52 196.12 285.20 89.08 2011 5.60 190.52 196.12 285.20 89.08 2012 5.60 190.52 196.12 285.20 89.08 2013 5.60 190.52 196.12 285.20 89.08 2014 5.60 190.52 196.12 285.20 89.08 2015 2.00 96.14 98.14 161.30 63.16 2016 2.00 96.14 98.14 161.30 63.16 2017 2.00 96.14 98.14 161.30 63.16 2018 2.00 96.14 98.14 161.30 63.16 2019 1.60 60.17 61.77 115.90 54.13 2020 0.70 22.22 22.92 45.40 22.48 2021 0.35 11.11 11.46 22.70 11.24 NPV - 217.63 35.27 80.06 1,283.44 1,274.56 1,942.46 184.83 -Rk 17.66% 130 Annex 5.1 Page 13 of 14 Table 9 - Economic Rate of Return Analysis - Reduce Benefits by 10% (US$ Million - January 1994 Price) ..... ..... . . . ~~~ ~ a d Other ....... Capital Fxed O .utage. Orn o Tot.l Ne. Year: Cost O& M Cost Cost0 Cos tt -ene eit 1995 3.50 3.50 -3.50 1996 22.80 22.80 -22.80 1997 115.00 7.00 122.00 -122.00 1998 130.70 0.40 40.00 32.70 203.80 40.86 -162.94 1999 18.10 1.30 45.00 67.20 131.60 104.31 -27.29 2000 15.40 1.70 10.00 77.30 104.40 124.74 20.34 2001 5.60 173.20 178.80 256.68 77.88 2002 5.60 173.20 178.80 256.68 77.88 2003 5.60 173.20 178.80 256.68 77.88 2004 5.60 173.20 178.80 256.68 77.88 2005 5.60 173.20 178.80 256.68 77.88 2006 5.60 173.20 178.80 256.68 77.88 2007 5.60 173.20 178.80 256.68 77.88 2008 5.60 173.20 178.80 256.68 77.88 2009 5.60 173.20 178.80 256.68 77.88 2010 5.60 173.20 178.80 256.68 77.88 2011 5.60 173.20 178.80 256.68 77.88 2012 5.60 173.20 178.80 256.68 77.88 2013 5.60 173.20 178.80 256.68 77.88 2014 5.60 173.20 178.80 256.68 77.88 2015 2.00 87.40 89.40 145.17 55.77 2016 2.00 87.40 89.40 145.17 55.77 2017 2.00 87.40 89.40 145.17 55.77 2018 2.00 87.40 89.40 145.17 55.77 2019 1.60 54.70 56.30 104.31 48.01 2020 0.70 20.20 20.90 40.86 19.96 2021 0.35 10.10 10.45 20.43 9.98 NPV 217.63 35.27 80.06 1,166.760 1,186.90 :1,748.21 l 126.55 LRR ~~~~~~~~~~~~~~~~~~~~~~1541% 131 Annex 5.1 Page 14 of 14 Table 10 Economic Rate of Return Analysis - Reduced Project Scope (Without JEXIM Component) (US$ Million - January 1994 Price) Fuel and Other Variable Capital Fixed Outage Operating Add Sys Total Total Net Cost 0 & M Cost Costs Cost Cost Benefits B3enefits 1995 3.50 3.50 -3.50 1996 22.80 22.80 -22.80 1997 103.50 7.00 110.50 -110.50 1998 107.70 0.40 40.00 32.70 17.00 197.80 45.4 -152.40 1999 16.20 1.30 45.00 67.20 17.00 146.70 115.9 -30.80 2000 13.50 1.70 10.00 77.30 17.00 119.50 138.6 19.10 2001 4.85 150.30 17.00 172.15 259.3 87.15 2002 4.85 150.30 17.00 172.15 259.3 87.15 2003 4.85 150.30 17.00 172.15 259.3 87.15 2004 4.85 150.30 17.00 172.15 259.3 87.15 2005 4.85 150.30 17.00 172.15 259.3 87.15 2006 4.85 150.30 17.00 172.15 259.3 87.15 2007 4.85 150.30 17.00 172.15 259.3 87.15 -2008 4.85 150.30 17.00 172.15 259.3 87.15 2009 4.85 150.30 17.00 172.15 259.3 87.15 2010 4.85 150.30 17.00 172.15 259.3 87.15 2011 4.85 150.30 17.00 172.15 259.3 87.15 2012 4.85 150.30 17.00 172.15 259.3 87.15 2013 4.85 150.30 17.00 172.15 259.3 87.15 2014 4.85 150.30 17.00 172.15 259.3 87.15 2015 2.00 87.40 89.40 161.3 71.90 2016 2.00 87.40 89.40 161.3 71.90 2017 2.00 87.40 89.40 161.3 71.90 2018 2.00 87.40 89.40 161.3 71.90 2019 1.60 54.70 56.30 115.9 59.60 2020 0.70 20.20 20.90 45.4 24.50 2021 0.35 10.10 10.45 22.7 12.25 NPV 191.03 31.12 80.06 41,040.02 136.37 1,164.41 1,799.11 187.29 IRR - 17.88% 132 Annex 6.1 Page 1 of 2 ROMANIA POWER SECTOR REHABILITATION AND MODERNIZATION PROJECT DOCUMENTS IN PROJECT FILES 1. Rehabilitation Survey of Thermal Power Plants by Merz & McLellan Consulting Engineers in Association with Power Gen PLC -Dated August 1993. Volume 1 - Main Report - Parts 1 and 2; and Part 3 Volume 2 - Isalnita Power Station: Unit 7 Volume 3 - Isalnita Power Station: Unit 2 Volume 4 - Rovinari Power Station: Unit 6 Volume 5 - Braila Power Station Unit: 4 Volume 6 - Brazi Power Station: Unit 9 Volume 7 - Palas Power Station: Unit 3 Volume 8 - Deva Power Station: Unit 1 Volume 9 - Braila Power Station: Unit 1 Volume 10 - Palas Power Station: Unit 1 Volume 11 - Bucuresti Sud Power Station: Unit 4 Volume 12 - Iasi II Power Station: Study on Boiler Fuel Conversion. 2. Terms of Reference for Corporate for Implementation of RENEL Corporate Restructuring Program. 3. Terms of Reference for External Auditor for RENEL. 4. Terms of Reference for Technical Assistance for Training in Environment Management. 5. Terms of Reference for Engineering and Project Management Consulting Services 6. Terms of Reference for a Study of Options of the Long-Term Structure for the Power Sector. 133 Annex 6.1 Page 2 of 2 7. Terms of Reference for Long- Term Least-Cost Generation Development Study. 8. Terms of Reference for Electricity and Thermal Energy Pricing Study. 9 Terms of Reference for Power Transmission System Reinforcement and Expansion Study. 10. Terms of Reference for Feasibility Study of Power Distribution. 11. Terms of Reference for Technical Assistance for Training in Occupational Health and Safety. 12. Terms of Reference for Assessment of Hydropower Plant Rehabilitation and Completion of Unfinished Hydro and Thermal Projects. 13. Terms of Reference for Training of Power Plant Operators. 14. Environmental Impact Assessment Study for the Power and Lignite Sectors Rehabilitation Project . 15. Computations of Pollutant Emissions from the proposed Thermal Plant Rehabilitation Program. 16. Medium-term (1995-2000) Power Sector Investment Program 17. 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