Armenia - Power Maintenance Project

Document of The World Bank Report No. 13347-AM STAFF APPRAISAL REPORT ARHENIA POWER MAINTENANCE PROJECT NOVEMBER 11, 1994 Infrastructure Operations Division Country Department IV Europe and Central Asia Region  CURRENCY EQUIVALENT Currency unit = Russian Ruble (RR)/Armenian Dram EXCHANGE RATES: RUBLES/DRAMS PER US$ (End of Period) Ruble:* 1990 (Avg.) 19 Dram: Jan 1994 80 (official) 1991 (Avg.) 62 Apr 1994 262 (official) Jan 1992 169 Apr 1994 400 (market) Jul 1992 144 Aug 1994 320 (official) Jan 1993 415 Oct 1994 362 (official) Jul 1993 1061 Oct 1994 370 (market) Jan 1994 1247 Apr 1994 1736 * Moscow Inter-Bank Foreign Currency Exchange/Foreign Exchange Auction Market (VEB) rate US$1 = 14.3 Dram (At introduction in November 1993) UNilTS OF MEASURE bcm = billion cubic meters mcm = million cubic meters BTU = British Thermal units m3 = cubic meter GJ = giga joules mm = millimeter GWh = gigawatt hour (= 1 million kWh) MW = megawatts kgoe = kilograms oil equivalent t = metric tons KTOE = thousand (kilo) TOE tcm = thousand cubic meters kWh = kilowatt hour TOE = metric tons oil equivalent GROSS HEAT VALUES OF FUEL 1 Unit of Fuel = X tons = Y tons (tons or 1000 m3) conventional (coal) oil equivalent fuel (TCF) (TOE) Gcal Fuel X= Y= Conventional (coal) fuel 1.000 0.700 7.00 Coal (low quality) 0.814 0.570 5.70 Wood 0.266 0.186 1.86 Natural gas (000m3) 1.182 0.827 8.27 Mazut (residual fuel oil) 1.370 0.959 9.59 Light fuel oil 1.290 0.903 9.03 Diesel/stove oil 1.450 1.015 1.02 Gasoline 1.490 1.043 1.04 Jet fuel 1.490 1.043 1.04 Kerosene 1.470 1.029 1.03 Liquified Petroleum Gas (LPG) 1.570 1.099 1.10 Bitumen 1.420 0.994 9.94 Crude oil 1.429 1.000 10.00 1 Gcal = 4.187 GJ = 3.968 million BTU = 1163 kWh Hydro and Nuclear energy output converted to primary thermal equivalent at 250 gms OE/kWh  FISCAL YEAR January 1 - December 31 ABBREVIATIONS AND ACRONYMS ARMENERGO = Armenia Electricity Company (electricity/district heating) ARMGAZ = Natural Gas Distribution Company ARMGAZPROM = Natural Gas Transmission Company ARMOIL = Armenia Oil Products Company CHP = Combined Heat and Power c.i.f. = Cost, Insurance and Freight CPAR = Country Procurement Assessment Report EBRD = European Bank for Reconstruction and Development ESR = Energy Sector Review (June 1993) f.o.b = Free on board GDP = Gross Domestic Product GoA = Government of Armenia GPN = General Procurement Notice IAEA = International Atomic Energy Agency ICB = International Competitive Bidding ICR = Implementation Completion Report IEA = International Energy Agency IFI = International Financial Institutions IS = International Shopping LCB = Local Competitive Bidding MEF = Ministry of Energy and Fuel NIF = Not IDA Financed NMP = Net Material Product NPP = Nuclear Power Plant O&M = Operating and Maintenance PIU = Project implementation Unit SCADA = System Control and Data Acquisition SDR = Special Drawing Rights SOE = Statement of Expenditure TA = Technical Assistance tcm = thousand cubic meters TORs = Terms of Reference TPS = Thermal Power Station   ARMENIA POWER MAINTENANCE PROJECT TABLE OF CONTENTS Page No. CREDIT AND PROJECT SUMMARY ................................. i I. ECONOMIC OVERVIEW AND THE ENERGY SECTOR. . 1 A. Economic Overview .1 B. The Energy Sector. 2 II. THE ELECTRIC POWER SUBSECTOR .. 5 A. Electricity Demand and Supply. 5 B. Electric Power Infrastructure. 5 C. Present Condition of Power Facilities. 6 D. Priority Subsector Issues. 7 E. Medzamor Nuclear Power Plant. 8 F. Institutional Arrangements. 9 G. Electricity Tariffs. 9 H. Government's Power Subsector Strategy. 10 M. THE BANK'S EXPERIENCE AND STRATEGY . .13 A. Bank Lending to Armenia .13 B. World Bank Assistance Strategy .13 C. Lessons Learned from Previous Bank Projects in the Power sub-sector .13 D. Power Sub-sector Strategy for Armenia .14 IV. THE PROJECT ..16 A. Project Objectives .16 B. Rationale for Bank Involvement .16 C. Project Description .17 D. Detailed Project Description .17 E. Project Costs and Financing Arrangements .19 F. Procurement ............................................ 21 This report is based on the findings of a World Bank pre-appraisal mission in October 1993 and a desk appraisal in March 1994. The mission consisted of Mmes/Messrs S. Zaheer (Energy Financial Economist, Task Manager), J. Jicha (Power Engineer, Consultant), J. Masterson (Operations Analyst). The peer reviewers were J. Gilling (Energy Economist) and W. Hay (Power Engineer). Ms. C. Cooper provided secretarial support. Mr. B. Kavalsky and Ms. D. Lallement are the Department Director and the Managing Division Chief respectively for the operation.  G. Disbursement ........................................... 23 H. Project Preparation and Implementation ........................... 25 I. Reporting and Monitoring ................................... 26 J. Accounting and Auditing .................................... 26 K. Project Supervision ....................................... 27 L. International Waterways .................................... 27 M. Environmental Aspects ...................................... 27 V. FINANCIAL ASPECTS ...... ............ .................... 28 A. Main Financial Issues ...................................... 28 B. Consumption Patterns ...................................... 28 C. Accounts Receivable ...................................... 30 D. Cost Recovery and Electricity Tariffs ............................ 30 VI. BENEFITS AND RISKS ...... ............. ................... 32 A. Benefits .............................................. 32 B. Economic Justification ..................................... 32 C. Project Risks ........................................... 34 VII. AGREEMENTS REACHED AND RECOMMENDATIONS .............. 35 ANNEXES 1.1 The Energy Sector Structure and Policies 2..1A Charter of ARMENERGO State Concern 2.1B Corporate and Management Structure of ARMENERGO 4.1 Detailed Project Costs 4.2 Project Procurement Summary and Packages 4.3 Project Implementation Plan, Schedule and Monitoring 4.4 Detailed Disbursement Schedule 4.5 Supervision Plan 5.1 Electricity Supply Costs 5.2 Interim Methodology for Determining Electricity Tariffs CONTENTS OF PROJECT IMPLEMENTATION VOLUME Annex A: Detailed Equipment Lists and Procurement Method Annex B: Terms of Reference for Project Implementation Technical Assistance Annex C: Project Implementation Schedule and Monitoring Map: IBRD Map No. 24491R  ARMENIA POWER MAINTENANCE PROJECT Credit and Project Summary Borrower: Republic of Armenia Beneficiary: Armenia State Electricity Company (ARMENERGO) Amount: SDR 9.4 million (US$13.7 million equivalent) Terms: Standard IDA terms with a maturity of 35 years, including a grace period of 10 years On-lending Terms: Prevailing IBRD interest rate with a maturity of 20 years, including a grace period of 5 years Objectives: The objectives of the project are to: (i) arrest and reverse the deterioration of three thermal generation units and three hydro power generation plants, and improve their availability (reduce unscheduled down-time); and (ii) strengthen the electricity load management and dispatch capability of the national dispatch center and arrest the further deterioration of the electricity distribution system. Description: The proposed project consists of: (i) maintenance of two existing 200- MW thermal units at the Hrazdan power plant, one 150-MW thermal unit at the Yerevan power plant, one 100-MW and one 44-MW plant on the Sevan-Hrazdan hydro-power cascade, and one 170-MW plant on the Vorotan hydro-power cascade; (ii) strengthening and maintenance of the electricity dispatch communications and distribution systems; and (iii) technical assistance for project implementation and upgrading the electricity dispatch system. The components were selected based on expected fuel availability, the potential for deeper rehabilitation under future investment operations, the critical electricity demand of the economy, and available financing. Proiect Benefits: The project would arrest the continuing deterioration and costly damage to the selected facilities and alleviate high human and economic costs by improving the reliability of electricity supply to critical facilities. In particular, the project would: (i) reduce forced outages (down-time) of about 550 MW of thermal power capacity and about 315 MW of hydro capacity and prevent premature and costly replacement; (ii) restore the fuel efficiency of the thermal plants closer to design levels; (iii) reduce safety risks by mitigating the chance of catastrophic equipment failures; and (iv) reduce damage due to the overloading of power generation and distribution facilities.  - ii - Risks: The main source of project risk relates to the sustainability of project benefits. Delays in mobilizing international financing to support Armenia's economic recovery (following the lifting of the blockade) would prolong the poor financial condition of ARMENERGO and its customers. This would make it difficult to pass the full costs of electricity supply through to consumers and would hamper ARMENERGO's ability to function according to commercial principles. It would also make it difficult for the government to mobilize fiscal resources to offset the shortfall in revenues, risking the continued deterioration of infrastructure. With the lifting of the blockade, the physical constraints to fuel and goods transport (including goods financed by the proposed credit) are expected to be alleviated and the main risks would be financial in nature. The project would allow ARMENERGO to strengthen its ability to control electricity distribution and reduce damage to power systems. Technical assistance under the project will mitigate risks arising from the limited experience with Bank procedures and competitive procurement. On-going studies, conditions agreed to under the EBRD loan for the Hrazdan 5 Power Plant, and agreements under the proposed project on the methodology of electricity pricing and reduction in electricity system losses, would provide the basis for strengthening ARMENERGO's commercial performance and its financial viability. Environmental Aspects. The maintenance of the power facilities will reduce the danger of equipment failure and improve worker safety. Although neglected due to lack of financial resources, the electricity distribution and dispatch system is basically sound in design from environmental, public health, and safety viewpoints, and the equipment financed will be installed at existing sites without additional trenching. With the exception of transformer oil, the materials financed are not expected to contain hazardous chemicals such as PCBs. Bid documents for transformer oil will specify that the material not contain PCBs. A more thorough review of the environmental and safety practices of the electric power subsector, particularly the environmental impact of the draw-down of lake Sevan for power generation, will be conducted prior to appraisal of the follow-on Power Rehabilitation Project and after a greater level of normalcy, particularly with regard to fuel supply, has been restored in the country. In any case, the improvements in plant availability and efficiency as a result of the proposed project are not expected to add measurably to noxious emissions or to water usage. The proposed project has been assigned an environmental category C.  Estimated Project Cost: Million US$ Component Local Foreign Total A. Power Generation Plants 0.4 5.7 6.1 B. Electricity Dispatch & Distribution 0.2 3.1 3.3 C. Technical Assistance 0.3 1.0 1.3 D. PPF Re-financing 0.0 1.2 1.2 Project Base Costs 0.9 11.0 11.9 Total Physical Contingencies 0.1 1.0 1.1 Total Price Contingencies 0.1 1.4 1.5 Total Project Cost 1.1 13.4 14.5 Financing Plan: Million US$ % of Local Foreign Total Total IDA 0.3 13.4 13.7 94% ARMENERGO 0.8 0 0.8 6% Total 1.1 13.4 14.5 100% Estimated Bank Disbursement:' IDA Fiscal Year -> 19952 1996 1997 198 Annual (%) 22 40 33 5 (USS) 3.0 5.5 4.5 0.7 Cumulative (%) 22 62 95 100 (US$) 3.0 8.5 13.0 13.7 Economic Rate of Return: Project is the least-cost means of preserving installed capacity, providing reliable power, and restoring system efficiency. Calculation of ERR was not possible because erratic fuel supply over the last few years has made it difficult to determine baseline operating characteristics and quantify expected improvements under the proposed project. Disbursement profile reflects the project's urgent maintenance nature. 2 Assuming credit effectiveness by March 31, 1995 and including US$1.2 million for PPF refinancing.   Economic Overview and the Energy Sector 1 I. ECONOMIC OVERVIEW AND THE ENERGY SECTOR A. Economic Overview 1.1 Armnia is a small, landlocked country with a land area of 29,800 square kilometers. Turkey lies to the west, Georgia to the north, Iran and Nakhichevan (part of Azerbaijan) to the south, and Azerbaijan to the east. The population numbered 3.65 million in January 1992 and GNP per capita was estimated at US$867 for 1992, and US$662 for 1993, making Armenia eligible for IDA terms. Armenia formally declared independence on September 23, 1991. 1.2 Like other countries in the region, Armenia is experiencing the economic difficulties arising from the breakdown in monetary and trade relationships within the former Soviet Union (FSU), particularly the rapid escalation in fossil fuel prices towards world market levels. These difficulties have been compounded by the regional conflict over Nagorno-Karabakh, and the resulting trade and transport blockade by Azerbaijan, and by civil strife in Georgia, blocking Armenia's second major trade route. The effects of the blockade, imposed in 1991, has overshadowed all other economic problems. The main economic effects include: 3 a drop of 52 percent in GDP in 1992, to almost a third of the 1989 level, and a further decline of about 15 percent in 1993; 3 a growing fiscal deficit which reached 48.9 percent of GDP in 1993, financed largely through payment arrears and credit emission (from the banking sector); 3 inflation reaching 3750 percent for 1993 contributed to by loose monetary policy and an influx of old rubles from other FSU countries; and 3 a growing trade deficit financed mainly through trade credits, loans (from Russia) and arrears. 1.3 The authorities introduced their new currency, the dram, in November 1993; however, conditions were not propitious, and the currency, initially set at 14.3 dram to the US dollar, depreciated to around 400 drams/US$ by May 1994. There are, however, signs of stabilization, and the exchange rate in August 1994 was around 320-340 drams/US$ and inflation declined from an average of more than 50 percent per month in January-May to 4 percent in August. 1.4 Reform Program. The primary objectives of the Govermnent's reform program are to: (a) achieve macroeconomic stability; (b) create a strong private sector within the framework of a market- oriented economy; (c) develop an efficient public sector that provides public goods and services and implements policies that promote sustainable growth; and (d) protect vulnerable groups in society. The Government's immediate priority is to arrest the fall in output and assure social assistance to those most in need while at the same time narrowing the fiscal deficit and reasserting control over money and credit. 1.5 Progress with the Reform Program. Armenia undertook strong structural reforms in 1991. Ninety percent of agricultural land was privatized, followed by the privatization of over 300 small enterprises in 1992. Since that time, however, implementation of the reform program has been slow because decision makers have focussed largely on crisis management in a siege economy. Nevertheless, producer prices have been fully liberalized and consumer prices, liberalized in successive stages, are now deregulated in all spheres except bread, public utilities, and transport. Administered prices have been raised substantially. In recent months the pace of reforms has picked up, in conjunction with the  2 Economic Overview and the Energy Sector commencement of a stabilization program which has led to a decline in monthly inflation to 9% in June, and a stabilization of the dram/US dollar exchange rate. Parliament has approved the privatization program, implementation of which is set to begin with the privatization of medium and large enterprises. In addition, more prudent credit policies in the financial sector are being introduced. 1.6 Medium Term Outlook. The restoration of economic performance depends crucially on improving the external political situation and establishing lasting peace in the region. Armenia continues to have a level of export orders from both inside and outside the FSU which is high relative to current output. Once the blockade is lifted, exports, particularly to the FSU, but also to new markets, are projected to recover rapidly. Once conditions stabilize, the Armenian diaspora could help to finance the large direct foreign investment flows needed to stimulate export-led growth. Armenia currently has IDA status. B. The Energy Sector 1.7 Sector Overview. Within the political and economic framework of the FSU, Armenia, although almost completely dependent on primary energy "imports" from other Soviet states, had the infrastructure to comfortably meet its energy demands and supply surplus electricity to neighboring states and to Turkey. Electricity exports were stopped when the 815 MW Medzamor nuclear power plant was shut down in February 1989 after concerns over its safety following the December 1988 earthquake. The breakup of the FSU, the virtual collapse of traditional monetary and trading relationships and, in the energy sector, the rapid escalation of fossil fuel prices towards world market levels since 1991, has required Armenia to respond with a suitable strategy, the formulation and implementation of which has been complicated by the desperate conditions arising from the blockade during which crucial energy resources have either not been available in sufficient quantities or available only at premium prices. With the lifting of the blockade, predominantly physical constraints to the import and export of goods (including fuels) are expected to be replaced by financial constraints. 1.8 A detailed description of the structure and priority issues of Armenia's energy sector is presented in the Energy Sector Review (ESR) prepared by the Bank in collaboration with Armenian institutions and the International Atomic Energy Agency (Report No. 11412-AM, June 30, 1993). A summary of key sector issues are discussed below and the power sub-sector is discussed in Chapter II. 1.9 Key Sector Constraints. Structural constraints which limit Armenia's ability to adjust to a market basis and adequately respond to the energy price 'shock" include: (i) the high energy intensity of the economy, arising from artificially depressed energy prices in the past, energy inefficient technologies and consumption practices, and limited attention to commercial principles in enterprise operation; (ii) excessive import dependence compounded by Armenia's landlocked geographical position and the resulting vulnerability to supply disruptions; (iii) a limited fuel mix with about 95 percent dependence on oil and gas (all of which is imported); and (iv) market disruptions resulting from the contraction in the economies of Armenia's traditional trading partners. 1.10 In addition, the sector is financially constrained because the increased fuel and other operating costs have been exacerbated by the depressed "siege" economy, within which (i) the Government has not been able or willing to raise energy tariffs to their full cost recovery levels; (ii) severe energy shortages and rationing have resulted in increasing theft and illegal connections; (iii) the  Economic Overview and the Energy Sector 3 GoA and sector enterprises have been unwilling or unable to enforce collection of overdue arrears and reduce system losses; and (iv) consumers would be unable to afford full cost based energy prices. The country is receiving foreign humanitarian assistance and some foreign capital from the Armenian diaspora. Additional support is required, possibly from the international financial institutions (IFIs) to help finance the working capital and investments needed to arrest the deterioration of physical assets, purchase fuel and other raw materials needed to 'jump-start' industrial production, and facilitate market- oriented policy reforms and institutional restructuring of the economy to sustain the supply response. 1.11 Sectoral Importance. The high energy intensity of the economy, high percentage of industrial production in the GDP, and its climatic conditions, make it essential for Armenia to have an efficient and reliable energy sector, and secure energy supply arrangements. In 1990, the last year preceding the disruption in energy supply and regional trading relationships, Armenia's energy intensity was 1.04 kgoelUS$ of GDP and industrial production made up about 45% of the national material product3. This energy intensity was 4-5 times higher than Sweden and Austria, but was comparable with that of other east European/FSU countries such as Hungary and Belarus. 1.12 The move to world prices for energy and the decline in the country's GDP are having a profound effect on balance of payments and energy intensity. Although these impacts are difficult to quantify because of inflation and the rapid depreciation in the value of the local currency, energy imports were already two-thirds of total imports in the first half of 1993. At present contract prices, 1993 levels of heavy fuel oil (mazut) and gas imports would have cost about US$100 million. Armenia's GDP for 1994 has been estimated by the IMF at 191.9 billion drams, or about US$600 million at the (August) market exchange rate of 320 dramslUS$4. The actual quantity of Armenia's future energy imports would depend on its ability to pay for these imports which, in turn, would depend on the level of external financial support forthcoming and the extent of the supply response. 1.13 Recent Energy Supply. Compared with about 3.0 million tons (Mt) of mazut and 3.5 billion cubic meters (bcm) of natural gas imported annually prior to 1991, only 0.225 Mt of mazut and 0.9 bcm of gas were received in 1993. Electricity generation was 6,295 gigawatt-hours (GWh) compared with about 10,362 GWh in 1990, of which 4,292 GWh was from hydro (about 1,555 GWh in 1990) and 2,003 GWh from thermal (about 8,807 GWh in 1990). A daily average of 800 MW of generation capacity was operated (compared with about 2700 MW of installed and 1970 MW of available capacity) and households received electricity for 2-4 hours/day. 1.14 Sector Organization. The institutional relationships within the energy sector are still being defined. The Ministry of Energy and Fuel (MEF) is responsible for formulating the sector's development strategy, determining the investment program, and advising the Ministry of Economy and the Council of Ministers on price and tariff adjustments and on future institutional framework and sector policies. Sector entities involved in commercial activities are a part of the MEF although their charters 3 GDP estimated at US$2,380/capita and Energy Consumption at 2,477 kgoe/capita. 4 At prevailing border prices, the 1990 consumption/import of gas (3,551 thousand toe) and oil products (4,433 thousand toe) would have cost about US$798 million. Weighted average cost of petroleum products estimated at US$175/ton and gas at US$100/toe equivalent (US$80/thousand cubic meters). GDP estimated using Atlas methodology; estimates for economies of the FSU are subject to more than the usau rnua of uncertainty and should be regarded as preliminary.  4 Economic Overview and the Energy Sector allow them managerial control over day-to-day activities and over the use of operating revenues and profits (within guidelines established by the Government). These entities are ARMENERGO (for electricity and heat generation and transmission, and electricity distribution in all areas except Yerevan), the Yerevan Electricity Distribution Authority, ARMPETROL and ARMGAZPROM (for the transportation, storage and distribution of oil and gas respectively), and ARMENERGOATOM (for the nuclear power plant). The Ministry of Economy establishes pricing and taxation policy and must approve all tariff adjustments. The organizational structure of the MEF is presented in Annex 1.1. 1.15 Energy Pricing. With the exception of fuels procured under the state order system, prices of all other fuels are market based. The prices of state procured fuels, electricity and heat are based on the recovery of narrowly defined operating costs which include fuel and non-fuel direct operating costs, depreciation (based on assets grossly undervalued at historical costs) and interest charges, overhead costs, and a profit margin. The GoA has apparently ended concessional lending to enterprises from the budget and central capital expenditures in the energy sector have virtually disappeared. However, subsidies and support are provided to enterprises in the form of bank credit (this is rapidly disappearing), the passing-through of profits from the inter-republic clearing arrangements to state enterprises, and shelter against termination of services for non-clearance of arrears. Pricing mechanisms for natural gas, oil products and heat are discussed in Annex 1.1; electricity pricing is discussed in Chapter nI.  The Electric Power Subsector 5 II. THE ELECTRIC POWER SUBSECTOR A. Electricity Demand and Supply 2.1 Demand. Electricity demand projections are closely linked to the rate of economic recovery following the lifting of the blockade and the establishment of new monetary, trade and payment systems. Based on these factors, three scenarios of low, medium and high economic growth were prepared by the Bank (Country Economic Memorandum, Report No. 11274-AM, March 24, 1993). Although total energy demand is not expected to reach 1990 levels until after the year 2000 under any of the scenarios, electricity demand by itself would be strongly influenced by the energy supply strategy followed by the GoA. Under the assumption that the blockade would be lifted by mid-1993 and district heat services would be restored, the Energy Sector Review (ESR) projected that electricity demand would reach the 1990 level around 2003. With the delays in the lifting of the blockade, demand is not expected to reach the 1990 level (see Chapter V) until 2005. Also, owing to the initial drop in GDP and the need for a minimum level of energy for essential human and economic needs, the energy intensity of the economy is projected to rise sharply before declining to its 1990 level. Details of the three scenarios and the forecasts for electricity demand are presented in the ESR. 2.2 Supply. Armenia's electricity generation capacity is sufficient to meet the country's immediate needs; however, reserve and replacement capacity, and a cost-effective reduction in import dependence, are needed to ensure reliable supply. Generation planning options are discussed in detail in the ESR. Although a thorough least cost planning study is required (and is presently underway), new capacity addition is not expected to be a high short term priority. Initial estimates made by the ESR indicate that by 2010, a total of 1900 MW of capacity would need to be added to cover demand growth and plant retirements. 2.3 Under all scenarios, existing units at the Hrazdan thermal power station are assumed to be rehabilitated extending their life beyond 2010. Yerevan thermal units 1-5 (5x50 MW) are assumed to be retired by 1996 and the life of the remaining units 7 and 8 (2x150 MW) extended to around 2010. All of the Vanadzor plant would be retired by the year 2000. It is assumed that one nuclear reactor (415 MW) would be recommissioned in 1995 and retired by 2002 (paras. 2.8-10). While the hydro plants could provide peaking capacity, the arnount of pondage and firm power is limited. Further investigation is needed to assess the optimum plant mix. Small hydro plants totalling 300 MW of firm capacity could be developed in the period 1996-2000. 2.4 More immediate investments are required in system maintenance, and in the electricity dispatch, transmission and distribution systems in order to reduce technical and commercial losses, and strengthen the overall commercial performance of the sub-sector. The present condition of the infrastructure and key issues are discussed below. B. Electric Power Infrastructure 2.5 The subsector consists of three mazut and gas based thermal power plants (1746 MW), two main hydro power cascades (929 MW), the Medzamor nuclear power plant (815 MW) shut-down since early 1989, several mini-hydro stations which had been shut-down but are being rehabilitated, a transmission network, with links to Georgia, Azerbaijan and Turkey, and urban and rural distribution networks. Of the approximately 3,515 MW of installed capacity, about 1,970 MW is available after  6 The Electric Power Subsector derating on account of age, the low water level of Lake Sevan, and the shutdown of the NPP. The present condition of the system and the key constraints are presented below. The system is described in detail in the ESR and a summary of the power generating facilities is presented in Table 2. 1. TABLE 2.1: INSTALLED GENERATING CAPACITY Type of Plant No.of Units (Period Nominal Installed Effective of Commissioning) Capacity (MW) Capacity (MW) Thermal Hrazdan 4 (1971-74) 1100 1070 Yerevan 6 (1963-67) 550 460 Vanadzor 2 (1964-76) 94 40 Sub total 1744 1570 Hydro Sevan-Hrazdan Cascade 5 stns (1949-61) 554 60 Vorotan Cascade 4 stns (1970-84) 404 340 Other Hydro 2-3 stns (1932-36) 35 0 Sub total 993 400 Nuclear (shut down) Medzamor 2 (1971-76) 815 0 Total 3552 1970 C. Present Condition of Power Facilities 2.6 Armenia's high level of dependence on fossil fuel imports to meet its energy needs, the logistical constraints in importing these fuels, the high energy intensity of the economy, and the inability to raise sufficient revenues by passing fuel and other operating cost increases through to final energy consumers, has accelerated the deterioration of the country's electric power infrastructure, particularly during the last three winters. The condition of the power sub-sector can be characterized as follows: * The sub-sector has been operated in a crisis mode geared towards human survival, with only limited attention to commercial principles. Fuel shortages and power system deterioration in Armenia over the last three winters have resulted in extremely high economic and human costs. * ARMENERGO (the electricity and heat company) is virtually bankrupt but is kept afloat by: (i) periodic adjustments in its costs through ex-ante adjustments in fuel prices charged by local supply enterprises; and (ii) supplier credits, which are in reality growing arrears to fuel suppliers. * Electricity generation is constrained by fuel availability and affordability, and by the low water level in Lake Sevan, the main source of hydro power. Hydro power generation in 1993 was three times higher than in 1990 (Chapter V), comprising 70 percent of total electricity supply (typically only 15 percent), and is presently the most reliable (though environmentally unsustainable) source of energy. Disruptions in gas and mazut supply make thermal power generation unreliable even when fuels have been procured. This has resulted in the operation of only 150 to 500 MW of thermal power (10-30 percent of available capacity).  The Electric Power Subsector 7 * Electricity has become the dominant source of energy for human needs as residential gas supply and district heating have been discontinued for lack of reliable fuel supplies. The use of electric space and water heaters, and cooking stoves has increased substantially resulting in high (peak) load demand at all times in the winter. Electricity is being rationed through rotating blackouts and an elaborate system of supply regimes linked to fuel availability and the requirements of the population and strategic industries (para. 2.16-18). * Designed in an era of abundant electricity and with scant regard for commercial viability, the existing electricity transmission and distribution infrastructure was not designed to adequately protect the system from overload during periods of scarcity. Consequently, there has been extensive damage to the distribution system (destruction of over 300 transformers and several hundred kilometers of cable), particularly during the winter months. The situation has been exacerbated by rampant illegal connections and by-passing of circuit breakers at the residential buildings and sub-station levels. System overload has resulted in generator turbines continuously running at lower than acceptable frequencies (45-47 Hz), damaging not only expensive turbines, but also all motor-driven electric gadgets (such as refrigerators). D. Priority Subsector Issues 2.7 The immediate challenge of the subsector is to meet the survival needs of the economy and population, while minimizing the damage to the electricity supply systems and improving cost recovery. In the short term this will require: * Restoration of suDDly routes and the rebuilding of fuel stocks: The GoA needs substantial financial support to rebuild its fuel stocks and supply enough energy to restore industrial production. At present contract prices, monthly fuel costs to generate a minimum required amount of 12 GWh/day are estimated at US$10 million for gas (or US$15 million for mazut) . * Rehabilitation and replacement of facilities: There is an immediate need to perform critical maintenance to arrest and reverse system deterioration, and to upgrade system controls in order to better manage the imbalance between energy supply and demand which is expected to persist for several years. This maintenance would be followed by the rehabilitation of selected facilities to improve efficiency and reliability, and extend the remaining life. * Restoration of the financial viability of ARMENERGO: Electricity tariffs should be aimed at rationalizing energy consumption, protecting vulnerable groups, and restoring the financial viability of ARMENERGO while also providing incentives for the efficient use of its assets and energy resources (Chapter V). * Strengthening of metering and billing: The high costs of electricity supply and the mounting losses and arrears require serious reforms in metering and billing practices. Although all connections are metered for electricity consumed OkWh), maximum demand MW) meters should be installed, particularly at large industrial consumers, as part of tariff reforms. The practice of residential consumers reading their own meters and making monthly payments to the local bank should be complemented with better inspection by the utility. Investment support would be required for ARMENERGO to strengthen its commercial practices.  8 The Electric Power Subsector * Envirotmental iMprovements: Air pollution (from high sulfur fuels and improper combustion) and the draw-down of Lake Sevan (for both power generation and irrigation) are the principal environmental concerns of the energy sector requiring immediate attention. The safety of the nuclear power plant is also of considerable concern, both if it is recommissioned without adequate safety upgrades or if it remains shut-down without sufficient resources to ensure its safety. E. Medzamor Nuclear Power Plant 2.8 Given the energy scarcity arising from the blockade and the high cost of conventional fuels, the GoA has decided to re-start the NPP. Although the security of power supply expected from the NPP is considered an issue of economic survival, the GoA is committed to the plant's safe operation. This is a Soviet-built model WER 440-270 plant (an upgraded version of the Model 230) consisting of two reactors rated at 408 MW each. The first unit was commissioned in 1976 and the second in 1979. The plant was shut down in early 1989 after the earthquake in 1988, as a precautionary measure since the plant is located within 16 km of a seismic fault. No damage was sustained by the plant during the earthquake. Technical assessments of the plant have been performed by Framatome (France), the International Atomic Energy Agency (IAEA), as part of the World Bank's ESR, an earlier structural seismic analysis by Bechtel Power Corporation (USA), and a current effort sponsored by the GoA and assisted by the Armenian diaspora and Russia. 2.9 In order to take into account the G-7 concerns on safety, the GoA strategy is to leave Unit I closed and re-start unit 2 in early 1995 for an operation of 5-7 years by which time alternate resources are expected to be developed. Work needed to restart the unit was begun in late 1993. Costs for restoring the unit to original design levels (about 20 year old design) and restarting it are estimated at US$70 million of which about US$40 million is for fresh nuclear fuel. The GoA has secured this financing from its own resources (US$15 million), the Armenian diaspora represented by the Medzamor Foundation, and Russia (fresh fuel, disposal of spent fuel and technical assistance). Russian financing is to be provided as credit with a lien on a portion of assets of the nuclear plant and other industries. The GoA is also seeking an additional US$25 million for safety enhancements beyond the original design, including the installation of advanced instrumentation, leak detection reactor controls, and modern software from western suppliers. In this effort, the GoA is trying to get the G-7 countries to allow EBRD and/or western suppliers to provide the necessary credit and equipment. 2.10 As agreed under the EBRD Power Project loan, a Power Facilities Planning Study, to be completed by end 1994, is investigating power supply options with and without re-starting the NPP, and with its retirement after 5-7 years of operation. In addition, an EBRD-appointed panel of independent experts is scheduled to visit the NPP in early 1995 to assess whether the targeted safety standards are acceptable to the panel. In order to ensure the long-term environmental safety of the power subsector, during negotiations, the GoA agreed to submit to IDA. by June 30, 1995. a power subsector investment plan which takes into account the retirement of the Medzamor nuclear power plant (para. 7.1(i)). This plan would also take into account the findings of the EBRD-financed power facilities planning study. For its part, IDA would assist the GoA to mobilize financing to implement this investment plan.  The Electric Power Subsector 9 F. Institutional Arrangements 2.11 The main credit beneficiary, the Armenia State Electricity Company (ARMENERGO), within the MEF's organizational structure, was established as a State "Concern" in February 1994 and is an amalgamation of electric power enterprises in Armenia. ARMENERGO is responsible for all non- nuclear electricity and heat generation and transmission, and electricity distribution in all areas except Yerevan. The Yerevan Electricity Distribution Authority, also under the MEF, is responsible for electricity distribution in Yerevan. ARMENERGO also supplies steam and hot water generated from its combined heat and power (CHP) plants to urban district heating companies (under city and town administration) and to large industries, and is responsible for heat distribution in rural areas. ARMENERGO's corporate charter and management structure are presented in Annex 2. 1A and 2. 1B. The recent establishment of ARMENERGO as a state "Concern" is a step towards its separation from the Government with the view of it becoming an asset holding company for the electric power subsector. G. Electricity Tariffs 2.12 Although the GoA is committed to establishing full-cost based tariffs, its intentions to do so have been complicated by: (i) the lack of clear evidence as to whether inappropriate tariff policy, or inadequate management mechanisms and will to reduce system losses, is the primary cause of the financial difficulties of the sector; (ii) the inability of a "siege" economy to bear the burden of full economic costs of supply, either by the final consumers or by the Government budget; (iii) high inflation (average 3750 percent in 1993) making it difficult to raise electricity prices in real terms; and (iv) insufficient energy supply to serve both minimum human needs and adequately supply the industrial sector. Whereas industry, particularly export industry, could afford higher tariffs for reliable supply, full cost recovery from households is unlikely in the short term without some form of subsidy. 2.13 Electricity tariffs are determined by ARMENERGO, cleared by the MEF, approved by the Ministry of Economy and ratified by the Council of Ministers. Average tariffs are based on: (i) narrowly defined fuel and non-fuel direct operating costs plus depreciation (based on undervalued historical asset values) and interest charges; (ii) an allowance for technical and commercial losses of 20 percent of generation (increased in April 1994 from 15 percent); and (iii) a profit margin of 9 percent on assessed costs (increased from 7 percent) which must, after a 30 percent profit tax, contribute to an employee fund and to capital expenditures. 2.14 A significant achievement in tariff setting was the recent (April 1, 1994) indexation of electricity tariffs to the US dollar as a protection from inflation. Average tariff established in July 1994 was US cents 1.5/kWh and is expected to be raised every three months. Tariff trends are shown in Table 2.2. Tariffs for households and for irrigation purposes are only 1.3 drams/kWh (US cents 0.40/kWh) and are cross subsidized by non-households. Supply costs are strongly influenced by the proportion of electricity generated from low fuel cost hydropower, while ARMENERGO's revenues are complicated by problems of theft, non-payment for services, and an insufficient provision for maintenance and depreciation in tariff determination. Recognizing this, and the limitations of raising tariffs for household consumers, the authorities are investigating the possibility and mechanisms for supplying commercial entities through monthly electricity auctions. The first stage of this process (to be tested in early 1995) is for ARMENERGO to auction 10 percent of electricity generated, with this proportion to be increased over time (until full cost recovery tariffs are established).  10 The Electric Power Subsector Table 2.2: Electricity Prices by Sector Jan June June April July Sector 1990 1991 1992 1992 1993 1994 1994 Residential Rbs/kWh 0.027 0.032 0.16 0.20 1.50 1.0 dram 1.3 dram USc/kWh 0.14 0.05 0.09 0.14 0.14 0.25 0.40 Industrial Rbs/kWh 0.026 0.060 1.7 4.80 12.00 513 dram - USc/kWh 0.14 0.10 1.00 3.33 1.13 1.74 2.43 Agriculture* Rbs/kWh 0.008 0.010 1.7 0.40 12.00 513 dram - USc/kWh 0.04 0.02 1.00 0.28 1.13 1.74 2.43 Transport Rbs/kWh 0.019 0.053 1.2 2.00 12.00 513 dram - USc/kWh 0.10 0.09 0.71 1.39 1.13 1.74 2.43 Comm/Off Rbs/kWh 0.029 0.071 1.7 2.00 12.00 513 dram - USc/klWh 0.15 0.11 1.00 1.39 1.13 1.74 2.43 Tariff for irrigation purposes same as household tariffs since April 1994. Exch. Rates (RbslUS$). 1990: 19; 1991: 62; Jan 1992: 169; June 1992: 144; June 1993: 1061; April 1994: 1736 rubles/295 dram (official) and 400 dram (market); July 1994: 320 dram (market) 2.15 Although the present methodology for tariff determination provides allowances for operating and maintenance (O&M) costs, budgetary estimates of O&M costs used for tariff determination need further investigation to determine the actual needs of Armenia's electricity supply system for the next few years. O&M costs are expected to increase over the near term as a result of the accelerated deterioration in electricity supply infrastructure. A program that combines tariff adjustments (to reflect the increased maintenance and capital requirements of the system), cash flow improvements (through reduced system losses and improved billing and collections), and critical investments and organizational reforms (to strengthen the commercial performance of the electric power sub-sector), is needed to arrest and reverse the deterioration in supply infrastructure. Measures included under the project are discussed in Chapter V (section D). H. Government's Power Subsector Strategy 2.16 Short-Term Strategy. Recognizing that an imbalance between the relatively inelastic, survival-level demand, and price and transportation-constrained supply is likely to continue for some time, the GoA has embarked upon a short-term (1993-96) allocation strategy (called 'Decision 61") aimed at: (i) providing on a continuous basis at least a minimum level of electricity to critical facilities (such as hospitals, bakeries, public transport, schools, and certain export industries); and (ii) increasing the reliability, and if possible the quantity, of at least a minimum level of supply to other users (industries, households, etc.) through rotating blackouts.  The Electric Power Subsector 11 2.17 The strategy identifies types of consumers by priority and allocates electricity supply depending upon fuel availability. In addition to this allocation strategy, the GoA intends to recommission one nuclear power unit by early 1995 (taking into account the findings of the EBRD appointed panel of experts (para. 2.10)), commission the 300 MW Hrazdan 5 thermal power unit by end 1995; and rehabilitate and upgrade existing power facilities. 2.18 In order to implement the electricity allocation strategy, dedicated electricity feeders to critical facilities are being installed (financed by the facilities), and system protection and control is being strengthened. Even though the strategy is driven primarily by considerations of energy security, and is being implemented by central allocation, the increased system control introduced would allow electricity to be distributed according to commercial principles in the future as the crisis situation eases. 2.19 The GoA's longer-term strategy responds to the key energy sector constraints of severe fuel shortage, limited fuel mix (excessive dependence on imported fossil fuels), and insufficient useful and reliable power generation capacity to meet medium and longer term requirements. The strategy includes the development of Armenia's oil, gas, and coal resources, the building of an Iran-Armenia gas pipeline to alleviate present dependencies, the development of about 300 MW of new hydropower capacity, the conversion of a petrochemical plant into a 1 Mt/year oil refinery, and an intensive investment and public information campaign to promote energy conservation and efficiency. 2.20 Energy Law and Private Sector Development. A draft Energy Law is expected to be finalized by the end of 1994. Investment legislation is also being formulated. In the power sub-sector, the GoA announced that plants of less than 25-MW capacity would be privatized and six mini-hydro units, ranging in capacity from 0.4 MW to 5 MW, were "transferred" to plant employees in the latter part of 1993, however, ownership and pricing details are still being worked out. The MEF expects that private ownership, or joint ventures with the Government, would also be allowed for larger-capacity plants, and is actively encouraging foreign partners to invest in Armenia on the basis of attractive electricity sales contracts. Pending the adoption of enabling legislation and pricing policies, foreign investors interested in investing in power generation (mainly hydro and alternative energy) are negotiating contracts and government guarantees on a case-by-case basis. However, country risks remain high and it may be some time before these projects are realized. 2.21 Technical Assistance. A number of donor-funded studies and technical assistance (TA) programs have recently begun or are planned to begin in 1994 which will assist the GoA to better assess its institutional and policy reform options. Specific studies which have a bearing on power subsector reforms and sustainability of the benefits of the proposed project are described below (the Bank's ESR contributed to the preparation of terms of reference for these studies). * Financial Strengthening of ARMENERGO: The scope of work includes: (i) modification of the existing accounting system to better suit commercially-oriented operations; (ii) re-valuation of ARMENERGO's assets and preparation of pro-forma corporate financial statements for the most recent year based on internationally accepted principles; and (iii) an identification of the level and structure of electricity tariffs required to reflect the cost of service to each consumer category, and a brief analysis of billing methods and consumers' ability to pay. This study is included under the EBRD-funded Hrazdan 5 Power Project. It began in September 1994 and is expected to be completed in six months.  12 The Electric Power Subsector * Advice to Government on Institutional and Policy Reform: This TA (under the EU-TACIS program) comprises a study and a resident adviser to the GoA to define and implement energy policy reforms, sector restructuring and the legal framework. The TA began in May 1994 and is expected to last 12-18 months. * Power Subsector Restructuring: The MEF and USAID are considering a study (similar to one done in Russia) to provide the GoA with options and recommendations for the corporatization, restructuring and regulation of the electric power sub-sector. These institutional reforms would facilitate the country's access to investment capital from the World Bank, other international financial institutions, and private investors. TORs would be made available to the Bank prior to commencement of the study (expected to be completed by September 1995). * Medium-term Power Facilities Planning Study: This study, also under the Hrazdan 5 Power Project, is assessing the condition of Armenia's power facilities and projected demands, and investigating power supply options with and without the re-starting the NPP, and with its retirement after 5-7 years of operation. The study would also help determine the medium-term marginal costs of electricity supply in Armenia. The study began in April 1994 and is expected to be completed by the end of the year. - Determnination of System Operating and Maintenance Costs: Under the proposed project, TA to be provided for project implementation would also assess the operating and maintenance costs of the electricity supply system in its present condition. This determination would be completed by June 30, 1995 and the full O&M costs incorporated into the methodology for electricity tariff determination by December 31, 1995.  The Bank's Experience and Strategy 13 m. THE BANK'S EXPERIENCE AND STRATEGY A. IBRD/IDA Lending to Armenia 3.1 Armenia has received one Bank loan and one IDA credit since it became a member of the Bank in September 1992. A US$12 million IBRD loan to Armenia was approved in March 1993 to provide technical assistance to the Armenian government in strengthening the institutional basis for economic reform through programs in four functional areas (a) economic management; (b) resource mobilization; (c) enterprise reform; and (d) financial sector reform. This loan became effective on June 15, 1993. Its implementation is moving slowly due to the difficult circumstances in the country. In January 1994 an IDA credit for Earthquake Reconstruction of US$28 million was approved to support reconstruction of housing and factory shells in the zone hit by the 1988 earthquake. B. World Bank Assistance Strategy 3.2 Assistance from the IMF and the World Bank has been contingent upon substantial progress towards a resolution of the conflict over Nagorno-Karabakh and the lifting of the trade blockade. With constructive steps towards peace, the Bank's lending strategy would focus on investment operations to finance emergency infrastructure rehabilitation, improvement in irrigation systems in support of privatized agriculture, and promotion of employment in small business and infrastructure repair. An IMF transition facility is expected to be put in place in support of a macroeconomic stabilization program, and the Bank is assisting in the preparation of a quick disbursing rehabilitation operation to support the Government's structural reform efforts. This could be followed by subsequent loans to support financial sector reform and private sector development as well as additional investment operations such as rehabilitation of roads and a larger power rehabilitation project. C. Lessons Learned from Previous Bank Projects in the Power Sub-sector 3.3 The proposed project will be the Bank's first energy sector credit to Armenia. However, past Bank experience in Armenia's energy sector has been developed through the ESR and on-going project preparation activities, including the establishment in November 1993 of a Project Preparation Facility (PPF) of US$1.2 million for preparation of the Power Rehabilitation Project. Although the PPF advance was initially slow to disburse, it is giving ARMENERGO valuable experience in Bank procurement and accounting procedures and guidelines. To date US$0.5 million have been disbursed.5 3.4 The Bank also has considerable experience in financing power projects in other parts of the world, including Eastern Europe and the FSU. An assessment of the lending practices to the subsector was presented in the Bank paper titled "The Bank's Role in the Electric Power Sector: Policies for Effective Institutional, Regulatory and Financial Reform," approved by the Bank's Board in November 1992. The key principles and recommendations of this paper, aimed at guiding future Bank lending to the subsector, include the need for: (a) transparent regulation; (b) better demand management; (c) financing for the importation of services needed to ensure efficient implementation and operations; (d) commercialization and corporatization; and (e) promotion of private investment. 5 The EBRD loan for Hrazdan 5 (approved in April 1993) was also slow to start but has recently gathered momentum. Plant start-up is now expected by end 1995, about a six-month delay.  14 The Bank's Experience and Strategy 3.5 While primarily aimed at arresting the costly deterioration of power facilities, the proposed project would also provide for the importation of implementation assistance and introduce modem project management techniques and competitive procurement practices. In addition, on-going technical assistance (para. 2.21) is being provided to assist with policy and institutional reform, and commercialization and corporatization. D. Power Sub-Sector Strategy for Armenia 3.6 The proposed project, aimed at arresting the deterioration in energy infrastructure, is an integral part of the Bank's interim country assistance strategy (para. 3.2) and is consistent with the main findings of the ESR. In the power subsector, the key elements of the strategy for the next 3-5 years involve assisting Armenia with its transition to a market economy through a combination of investments and technical assistance. Strategy objectives are to promote the efficiency and competitiveness of the subsector, by adopting institutional structures and policy reforms which permit the financial viability and operational independence of the subsector's commercial entities, and to ensure that the GoA's pursuit of its broader economic and social goals do not jeopardize the financial health of commercial entities. External assistance would be directed towards: (i) Supporting the recommendations of the Power Facilities Planning Study (para. 2.21) which takes into account the retirement of the NPP. Preliminary conclusions include support for the rehabilitation of selected thermal and hydro power generation units, and the electricity transmission and distribution system. Significant economic gains are expected through improvements in fuel conversion efficiency, reduction in noxious emissions, life extension, and reduction in transmission and distribution losses; and (ii) Strengthening the commercial performance of operating entities through investment support, separation of the ownership, policy making, and regulatory functions of the Government, and the corporatization and restructuring of the electric power subsector so that it is more responsive to the demands of a market economy. Substantial returns on investment and reduction in the costs of electricity supply are expected through improvements in metering and billing, and upgrading of the System Control and Data Acquisition (SCADA) system. 3.7 The proposed project was identified in the context of the preparation of a Power Rehabilitation Project (pre-appraised in October 1993 and tentatively scheduled for Board presentation in FY96), the processing of which has been hampered by the crisis conditions which have delayed policy and institutional reforms, accelerated system deterioration, and made it difficult to fully define the project's scope. Given this situation, and the lack of financing available for urgently needed spare parts, the GoA requested that the Bank proceed in two steps: the proposed Power Maintenance Project, aimed mainly at arresting and reversing system damage, followed by the Power Rehabilitation Project, aimed at deeper efficiency improvements and life extension. The power facilities targeted for maintenance under the first project were identified by the ESR as being eligible for rehabilitation and are expected to be candidates for rehabilitation under the follow-on Power Rehabilitation Project. The first project could be implemented soon after the country enters into the regional peace process and is expected to be complemented by balance of payments support under a Bank supported Rehabilitation project. The second project would follow about one year later. Early implementation of the first project is justified  The Bank's Experience and Strategy 15 as benefits from efficiency and reliability improvement, and prevention of equipment failures, far outweigh the benefits of delaying the first project by one year and integrating the two projects (para. 6.8). 3.8 Credit Conditionality. The credit would include standard IDA conditions for procurement, disbursement and auditing. Project specific conditions include agreement on an electricity pricing methodology, system loss reduction targets, a reduction in the average revenue collections period, and submission to IDA, of a power subsector investment plan which takes into account the retirement of the NPP (Chapter VII). Policy and institutional reforms needed to sustain project benefits are being addressed through on-going and planned TA (para. 2.21) and through conditions agreed upon between the GoA and EBRD, which is presently the largest single lender to the power subsector and to Armenia. The EBRD loan of US$57.4 million equivalent was approved in April 1993 for the completion of the 300- MW Hrazdan 5 Thermal Power Plant. 3.9 EBRD Conditionality. The status of conditionality which is relevant to the proposed project is as follows: - ARMENERGO was to revalue its assets and introduce financial reporting and accounting procedures acceptable to EBRD, before April 1, 1994. Sta: Work is under way and is expected to be completed by March 1995. - Average electricity tariffs were to be increased to at least US cents 3.0/kWh before end 1993, US cents 3.5/kWh before end 1994, and US cents 4.0/kWh before end 1995. Additional tariff reforms upon completion of TA included in project. Status: This condition has been renegotiated and modified to establish an average tariff of US cents 2.0/kWh by end 1994 and 4.0/kWh by end 1996. - ARMENERGO's receivables were to be maintained at less than 2 months of average monthly billing. Sau: ARMENERGO is presently in default of this covenant; (its receivables for 1993 alone amounted to 129 days of sales) (para 5.7). - JGoA was to consult with EBRD before deciding to reopen the Medzamor nuclear plant. In addition, EBRD has the right to suspend, cancel or accelerate the loan if the plant is reopened without approval by a group of qualified and independent experts selected by EBRD. St: A panel of EBRD appointed experts is to inspect the plant prior to its reopening scheduled for early 1995. 3.10 Up-front pricing policy reforms, a time-bound schedule for restructuring the electric power subsector according to recommendations of on-going studies, the safety of the NPP (if it is re- opened), and agreement on a power subsector investment plan, which takes into account the retirement of the Medzamor nuclear plant, are expected to be conditions of the follow-on Power Rehabilitation project. 3.11 Program Objective Category. The project meets the environmentally sustainable development objective by providing urgent maintenance for critical power facilities. The project would arrest the deterioration and costly damnage to selected facilities, improve the reliability of electricity supply to critical facilities such as hospitals, schools and universities, public transportation, bread factories, telecommunications stations and export industries and reduce worker safety risks in the power plants.  16 The Project IV. THE PROJECT A. Project Objectives 4.1 The proposed Power Maintenance Project has the following objectives: * To arrest and reverse the deterioration of three thermal generation units and three hydro power generation plants, and improve their availability (reduce unscheduled down-time); and * To strengthen the electricity load management and dispatch capability of the national dispatch center and arrest the further deterioration of the electricity distribution system. 4.2 The achievement of these objectives would permit the continued operation of the power facilities and defer expensive replacement costs arising from equipment failures, some of which could be catastrophic. An improvement of 3-4 percent in generation efficiency (closer to the design level of 33-35 percent) is also expected from the general overhaul of boilers, turbines and generators. Project benefits are expected to be realized within the first three years. Electricity tariff-setting methodology and system loss reduction targets agreed to with IDA, and tariff increases agreed to with the EBRD, would strengthen the financial condition of ARMENERGO, the credit beneficiary. Other technical assistance (para. 2.21) would provide the basis for future tariff reforms and the restructuring of the electric power subsector. B. Rationale for IDA Involvement 4.3 An efficient and reliable energy sector is crucial for restoring macroeconomic stability and growth in Armenia. World Bank financing and technical assistance over the short to medium term would permit implementation of policy and institutional reforms needed to reduce the financial and managerial dependence of sector entities on the Government. The GoA has expressed its commitment to introducing market-based reforms; however, Armenia's transition to a market economy has been complicated by regional conflicts and civil disorder. 4.4 The Bank's assistance strategy in the power subsector is discussed in Chapter III-D. The strategy to proceed in two steps would permit a quick response by the Bank to arrest the continued deterioration in ARMENERGO's physical assets and in its financial position under the first project, and give the Government time, following the lifting of the blockade, to implement reforms needed to create an economically efficient and commercially sustainable power subsector. 4.5 The expenditures proposed under this, the first project, are necessary in any case, are focussed on selected, urgently needed facilities, and will be complemented on a broader scale, including deeper efficiency and life extension investments, under the Power Rehabilitation Project. The Bank is expected to support this latter project as the investments being considered are the least-cost means of reliably meeting electricity demand, and because the GoA has agreed in principle to establish ARMENERGO as an independent public utility, continue to raise electricity tariffs to their economic levels and, if recommissioned, retire the Medzamor nuclear plant within 5-7 years of operation. Schedules for implementing these initial institutional and policy reforms, and agreement on an investment plan which takes into account the retirement of the NPP, are expected to be conditions of the Power Rehabilitation Project.  The Project 17 C. Project Description 4.6 In support of project objectives and the priorities of ARMENERGO (the credit beneficiary), the project consists of the following components. (a) Maintenance of selected existing generation units and ancillary facilities at: (i) the Hrazdan power plant, mainly focussed on two thermal units (2x200 MW); (ii) the Yerevan power plant, mainly focussed on one thermal unit (lx15O MW) and the water treatment facilities; (iii) the Sevan-Hrazdan hydro power cascade, mainly focussed on the Kanaker (100 MW) and Yerevan (44 MW) plants; and (iv) the maintenance of about 170 MW capacity on the Vorotan hydro-power cascade (US$7.7 million); (b) Strengthening and maintenance of the electricity dispatch communications and distribution systems (US$4.1 million); and (c) Technical assistance for project implementation, and upgrading the electricity dispatch system (US$1.5 million). Project preparation activities, supported by a Project Preparation Facility (PPF) advance of US$1.2 million equivalent, approved in November 1993, are described in para 4.27. The PPF advance would be refinanced under this project. 4.7 Selection of facilities to be maintained. The facilities to be maintained were selected based on the critical need for maintenance and system protection, projected fuel availability, the potential for life extension of the selected generation facilities under future investment operations, and the level of financing available (para. 6.4). Compared with annual electricity demand projected at 7252 GWh for 1995, increasing to 8366 GWh by 2000 (Energy Sector Review - base case), the generation capacity to be maintained under the proposed project would be able to supply 4340 GWh (3375 GWh from thermal and 965 GWh from hydro). Another 1840 GWh would be supplied from Hrazdan 5 (300 MW) upon its completion in 1995. If recommissioned, 2500 GWh could be supplied from one unit of the Medzamor NPP. Peak load demand would be supplied from the hydro units. D. Detailed Project Description 4.8 Project investments and activities for each component are explained below. A detailed list of spares and materials, with cost estimates and procurement method is presented in the project implementation volume. Cost summaries of individual components are shown in Annex 4.1. Maintenance of Power Generation Plants (a) Hrazdan Thermal Power Plant. The project would cover installation of spare parts and materials for the maintenance of two (Units 2 and 3) thermal power-only units of 200 MW each. Equipment and materials included are essential for undertaking deferred normal maintenance to keep the plants in a reliable operating condition. Activities to be performed include the chemical treatment and replacement of boiler heating surfaces and insulation, air heaters and flue gas ducts, steam piping and valves, water heaters and pumps, and storage batteries. General maintenance  18 The Project on generators and turbines includes the replacement of worn out parts, including high pressure rotors and damaged blades. Transformers will be repaired and transformer and turbine oil replaced. Replacement of many smaller equipment parts is also included as these have exceeded their useful life and continued operation could result in equipment failure which, in some cases, might be catastrophic. In addition to normal wear and tear, substantial degradation of equipment has been caused by corrosion (because of excessive burning of high sulfur mazut instead of gas) and system overloading over the last three years causing generators and turbines to operate substantially below design frequency. (b) Yerevan Thermal Power Plant. The project would cover spare parts and materials concentrated mainly on the maintenance of one 150 MW unit (Unit 7). As with the Hrazdan units, the objective of the maintenance is to keep the Yerevan unit operating and prevent further deterioration. The activities to be performed and rationale are essentially the same as for Hrazdan and include the overhaul of the boiler, air heater, repair of corroded combustion gas ducts, general repair of the turbine (replacing parts of the high pressure stage and blades in the middle and low pressure stages), replacement of feed water and condensate pumps, and the replacement of steam and water valves, which have exceeded their useful life. Electrical repairs include replacement of generator transformer parts, electric motors and circuit breakers. (c) Hydropower Plants on the Sevan-Hrazdan Cascade. The project would cover spare parts and materials for the critical maintenance of selected hydro power plants on the Sevan- Hrazdan. This component would focus mainly on increasing the availability of the Kanaker plant (6 units, 100 MW total) and the Yerevan plant (2 units, 44 MW total) by replacing stator windings, and performing maintenance on hydro-pistons, pumps and governors. The component includes the replacement of electrical parts such as electromotors, circuit breakers, speed controls, storage batteries, power and control cables, and transformer and turbine oil. Materials for the repair of some diversion channels is also included. (d) Hydropower Plants on the Vorotan Cascade. This component includes activities similar to the work to be done on the Sevan-Hrazdan cascade. The main focus would be the maintenance of the Shamb plant (2 units, 170 MW total) and would include the repair of the turbine discharge pipes, a new oil cooling unit, and the replacement of different types of energizers, circuit breakers, pumps, electromotors, cables, and transformer and compressor oil. Electricity Dispatch and Distribution (a) Electricity Dispatch. The project would introduce a limited amount of modern telecommunication equipment to strengthen ARMENERGO's load management and system control capacity, and improve operating flexibility. The activities would aim to stabilize the deterioration in Armenia's distribution system and prepare a base for a SCADA system to be introduced within the next few years, possibly under the Power Rehabilitation Project. Modern equipment includes radio relays to connect the dispatch center with power stations and sub- stations, such as base stations, hand-held radios for back-up in cases of emergency, and the replacement of obsolete telephone switchboards and telephones. (b) Electricity Distribution. The aim of this component is to arrest further deterioration of the distribution system and begin transforming it into a modern, well protected and automated  The Project 19 system. Investments will be specifically aimed at restoring the reliability of electricity supply to facilities critical for humanitarian services and the restoration of economic growth. Selected facilities include hospitals, schools, public transportation, bread factories and telecommunication stations. Maintenance activities include the replacement and upgrading of circuit breakers, sub- stations, transformers, cables and overhead conductors. Better system protection would improve system reliability, reduce damage to cables and transformers (many of which have been damaged by severe overloading in past few winters). The new compact substations would replace damaged substations and would be available to serve as back-ups in a case of an emergency. System protection introduced under the project would also facilitate the introduction of a modern Load Distribution Management System, a prototype of which is being installed under the PPF for the Power Rehabilitation Project. Technical Assistance. Technical assistance (TA) would be provided to ARMENERGO for: (a) Project Implementation (US$0.8 million): The project would complement grant funds which might be available to finance consultant services in such areas as project management, procurement, and general office and logistical support services (paras. 4.28-30). This TA would be provided to the Project Implementation Unit (PIU) established within ARMENERGO with funding from the PPF established for preparing the Power Rehabilitation Project. TOR's of this assistance are presented in the implementation volume of the SAR. (b) SCADA Design Study (US$0.5 million): The main objective of this study would be to design a system management information system that allows the quick collection and dissemination of data regarding electricity supply, demand, and load flows throughout the network. This system could isolate parts of the network with high transmission and distribution losses, and would allow better system control and load management, and the introduction of automatic metering and billing in the future. TOR's of this study would be prepared by ARMENERGO by February 28, 1995. E. Project Costs and Financing Arrangements 4.9 Project Costs. Total project costs, including physical and price contingencies, are estimated at US$14.5 million equivalent of which US$13.4 million is the estimated foreign exchange cost. Cost estimates are based on supply from CIS countries (May 1994 estimates provided by ARMENERGO converted at Russian ruble 1800/US$). Foreign equipment costs include transportation to the border and supplier assistance for installation. Due to regional instability, costs for reliable transportation to Armenia are estimated to be higher than for other republics. Local investment costs are mainly for maintenance and installation by force account using ARMENERGO personnel. 4.10 Because of difficulties in precisely defining maintenance-type activities, physical contingencies were estimated at 10 percent, except for PPF refinancing. Because of high real price inflation for CIS-manufactured goods as these countries integrate into the international economy, price contingencies were estimated using a constant 10 percent per year for all investment-related and local costs, and the Bank's standard 2.2 percent for all other costs (not included for PPF refinancing). Average price contingencies are 11.6 percent of total base costs. Based on information from the Ministry of Energy and Fuel, imports under the proposed project would be exempt from duties and value-added taxes.  20 The Project A summary of project costs is presented in Table 4.1 and cost summaries for each component are presented in Annex 4.1. TABLE 4.1: PROJECT COSTS (based on May 1994 Estimates) Million US$ % Foreign % of Base Component Local Foreign Total Exchange Costs A. Power Generation Plants 0.4 5.7 6.1 94% 51% B. Electricity Dispatch & Distribution 0.2 3.1 3.3 93% 28% C. Technical Assistance 0.3 1.0 1.3 81% 11% D. PPF Re-financing 0.0 1.2 1.2 100% 10% Project Base Costs 0.9 11.0 11.9 93% 100% Total Physical Contingencies 0.1 1.0 1.1 92% 9% Total Price Contingencies 0.1 1.4 1.5 91% 13% Total Project Cost 1.1 13.4 14.5 92% 122% 4.11 Project Financing. The IDA Credit of US$13.7 million would finance 94 percent of total project costs, including 100 percent of all foreign costs estimated at US$13.4 million and the refinancing of the PPF. The credit would also finance US$0.3 million of non-staff related operating expenses for the PIU over the project period. The high level of IDA financing is justified because of the poor financial condition of the Government and ARMENERGO. The Credit would be lent to the Government of Armenia on standard IDA terms for an IBRD/IDA blend country, that is, a maturity of 35 years, including a grace period of 10 years. 4.12 Owing to ARMENERGO's weak financial position and its present inability to service additional debt (Chapter V), during negotiations. the GoA agreed to on-lend Credit proceeds to ARMENERGO. pursuant to a subsidiary loan agreement between the GoA and ARMENERGO. for a period of 20 years. including a grace period of 5 years and at the prevailing IBRD annual variable interest rate (presently 7.1 percent). ARMENERGO would assume the foreign exchange risk (para 7.1 (ii)). Interest on the disbursed credit amount would be capitalized during the grace period. Execution of the subsidiary loan agreement, agreeable to IDA. would be the only project-sDecific condition of effectiveness (para. 7.2). Local costs not financed by the IDA credit (US$0.8 million equivalent) would be covered by ARMENERGO and are mainly associated with installation to be carried out by its staff. 4.13 Donor grant funds have been used (about US$0.5 million) for preparation of the Power Rehabilitation Project and a PPF of US$1.2 million has been established for the completion of preparation work. PPF funds used will be refinanced from the IDA credit for the proposed project. If the GoA is able to secure grant financing for the technical assistance components, the amount secured would be reduced from the credit or reallocated. Financing arrangements are shown in Table 4.2.  The Project 21 TABLE 4.2: FINANCING PLAN Million US$ % of Local Foreign Total Total IDA 0.3 13.4 13.7 94% ARMENERGO 0.8 0 0.8 6% Total 1.1 13.4 14.5 100% F. Procurement 4.14 The IDA credit will finance Goods and Technical Assistance. A summary of procurement arrangements is given in Table 4.3 below. The list of procurement packages and the procurement schedule are presented in Annex 4.2 and the project implementation schedule is presented in Annex 4.3. 4.15 Goods and Equipment. Equipment to be financed by IDA will consist of spare parts and materials for replacement of damaged and worn out equipment, telecommunications and instrumentation for the upgrade of the electricity dispatching and control system, and office and logistical support for the Project Implementation Unit. Expediency, compatibility with existing equipment, and the need to introduce competitive bidding practices into ARMENERGO, were taken into account in proposing methods of procurement. Since most of this equipment is not manufactured in Armenia, local suppliers are not expected to bid for equipment procurement. For ICB contracts, domestic manufacturers would be eligible to 15% domestic preference in bid evaluation according to paras 1 to 4 of Appendix 2 of the Bank Guidelines. Also, it is the Bank's understanding that the specified imports are exempt from domestic taxes and duties. Taxes and duties, if any, will be financed by the GoA. The goods to be financed are urgently needed, and could be procured soon after credit effectiveness. 4.16 Procurement of goods, totalling about 13 packages, ranging in value from US$0.25 million to US$0.75 million, would follow ICB procedures using the Bank's standard bidding documents according to Bank Guidelines. Most of these materials could be packaged into bid packages in excess of US$250,000. International shopping would be used for smaller contracts for goods (primarily items such as welding electrodes, boiler insulation and tubing, aluminum, steel screens, etc.) under US$250,000 for a total of about US$1.7 million. Contracts awarded under IS procedures would be based on comparing price quotations obtained from at least three suppliers from three eligible countries in accordance with Bank Guidelines. Direct contracting would be used for replacement parts for generation and distribution systems consisting of about 31 packages for a total of about US$3.2 million. Items procured under direct contracting consist mainly of replacement piping and parts for boilers, turbines, transformers, electrical equipment, high frequency communication equipment, and splices for cable repair. Procurement would be from the original manufacturer in order to ensure compatibility with existing equipment. A combination of direct contracting and local shopping would be used for incremental operating costs (US$0.3 million) of the PIU for items such as office rent and maintenance, minor office equipment and consumable supplies, printing, translation, interpretation, communications, transportation and servicing and repairs of office equipment. Items such as minor office equipment and consumable supplies would be procured by local shopping on the basis of three quotations from eligible suppliers, while services for logistical support, such as translation, interpretation, communications, etc. would be contracted directly.  22 The Project 4.17 Consulting Services and Technical Assistance. Consultants are to be hired under two contracts for project implementation assistance ($650,000) and the SCADA design study ($550,000). There may be one or two short-term consulting assignments of a specialized nature, the value of which will not exceed US$50,000. All such arrangements will be contracted through individual consultants. Consultant selection would follow the Bank's Guidelines for the Use of Consultants, dated August 1981, and consultants would be hired on terms and conditions acceptable to IDA. TABLE 4.3: PROCUREMENT ARRANGEMENTS' (in US$ millions) Procurement Method Project Element ICB LCB Other N.I.F.b/ Total Cost 1. Goods: Eguipment & materials A. Generation 3.7 3.5c/ 7.2 (3.7) (3.5) (7.2) B. Distribution and Dispatch System 2.4 1.4dl 3.8 (2.4) (1.4) (3.8) 2. Works: Installation A. Generation 0.5*' 0.5 B. Distribution & Dispatch System 0.30/ 0.3 3. Consulting Services: Project 1.21' 1.2 Implementation and SCADA Study (1.2) (1.2) 4. Miscellaneous A. Incremental Operating Costs of PIU 0.3'- 0.3 (0.3) (0.3) B. Refinancing of PPF 1.2 1.2 (1.2) (1.2) TOTAL 6.1 7.6 0.8 14.5 (6.1) (7.6) (-) (13.7) a/ Figures in parentheses are the amounts to be financed by the IDA credit. b/ N.l.F = Not IDA financed. c/ Of which US$0.8 million by international shopping (IS) and US$2.7 million for replacement parts by direct contracting. d/ Of which US$0.9 million by IS and US$0.5 million for replacement parts via direct contracting. c/ Force account. f/ Two contracts to be procured according to Bank guidelines for the use of consultants. g/ Office supplies and logistical support over project period. 4.18 Prior Review. Prior review of draft tender documents, bid evaluation reports and recommendations for awards of contracts, would be carried out for all ICB procurement (US$250,000 and above). The Bank would also pre-review documentation relating to all contracts under direct contracting. The list of goods to be procured using international shopping procedures (contracts of less than US$250,000) would be submitted for prior review by the Bank. For consultants, prior review would be required for contracts over US$100,000 with firms, contracts over US$50,000 with individual consultants, and for all single source contracts regardless of value. Terms of reference for all consulting contracts would be subject to IDA's prior review. It is estimated that about 85 percent of all IDA financed procurement would be subject to prior review.  The Project 23 4.19 The General Procurement Notice (GPN) will be published in Development Business following negotiations. It is expected that this would give the required 60 days notice prior to the issuance of the bidding documents. The GPN will be updated and published annually. At least 45 days prior to the issuance of bidding documents, individual bidding opportunities will be advertized in a major local newspaper and embassies of World Bank member countries located in the country will be notified. ARMENERGO will also be expected to advise known eligible and qualified traditional suppliers. 4.20 Like many other Eastern European and FSU countries, Armenia does not have a tradition of competitive bidding for the procurement of public goods and services. Therefore, a Country Procurement Assessment Report (CPAR) is not planned at this stage. Under a recently approved Institutional Development Fund grant, TA to develop and strengthen competitive procurement practices for the procurement of public goods and services is expected to begin in September 1994. 4.21 ARMENERGO, the project executing agency, has limited experience with the Bank's procurement practices. However, a Consultant has been hired under PPF funding to set up the project implementation unit, introduce PIU staff to the Bank's procurement guidelines, and handle the procurement of equipment for a prototype Load Distribution Management System using international shopping procedures. It is expected that by the time the proposed project becomes effective, ARMENERGO will have also gained experience with preparing bidding documentation for ICB. The project implementation technical assistance contract provides for procurement training for ARMENERGO staff as well as the services of a procurement expert during bid preparation, evaluation and contract negotiations during the key procurement phases of the project. G. Disbursement 4.22 The proceeds of the IDA credit would be disbursed on the following basis: IDA Category Allocation % of Expenditures to he financed (million US$) 1. Equipment and Materials 8.8 100% of foreign expenditure 100% of local expenditure (ex-factory cost) 85 % of local exp. for other items procured locally 2. Technical Assistance 1.0 100% 3. Operating Costs 0.3 100% 4. PPF Refinancing 1.2 5. Unallocated 2.4 TOTAL 13.7 4.23 Table 4.4 shows the estimated Bank disbursement schedule for the project; a more detailed disbursement schedule is presented in Annex 4.4. Based on the urgent need for the equipment and materials to be financed, ARMENERGO intends to complete procurement of goods over a 24-month period. However, considering the limited local experience with ICB, a three calendar-year disbursement period has been estimated. This schedule is about three years shorter than the standard disbursement profile for energy projects in Europe and Central Asia, but is reasonable in view of the relatively simple nature of the project compared to the majority of Bank energy projects. Based upon credit effectiveness  24 The Project by March 15, 1995, the project is expected to be completed by January 31, 1998. The Closing Date for the proposed credit would be July 31, 1998. Approval of the follow-on Power Rehabilitation Project in FY96 would permit complementary life-extension and efficiency-enhancing investments to be programmed into the implementation schedule of the proposed project. This would allow the maintenance and rehabilitation of some units and facilities to be done simultaneously. Disbursement requests will be prepared and submitted to the Bank by the PIU which has acquired some experience in disbursement with on-going PPF activities. TABLE 4.4: DISBURSEMENT SCHEDULE (in million US$) IDA Fscal Year -> 1995S' 1996 1997 1998 Annual (%) 22 40 33 5 (US$) 3.0 5.5 4.5 0.7 Cumulative (%) 22 62 95 100 (US$) 3.0 8.5 13.0 13.7 Assuming credit effectiveness by March 15, 1995 and including US$1.2 million for PPF refinancing. 4.24 Special Account. To facilitate project implementation, ARMENERGO would establish a special account (SA) in a major foreign commercial bank on terms and conditions satisfactory to IDA to cover IDA's share of expenditures6. The maximum allocation authorized would be US$500,000 representing about four months of average expenditures effected through the SA. At the request of ARMENERGO, and based on project needs, IDA would make an initial deposit or deposits into the SA up to the amount of the authorized allocation. Applications for the replenishment of the SA would be submitted monthly, or when one-third of the amount has been withdrawn, whichever occurs earlier. Documentation requirements for replenishment would follow usual IDA procedures. In addition, monthly bank statements of the SA, which have been reconciled by ARMENERGO, would accompany all replenishment applications. 4.25 IDA would also permit the use of statements of expenditure (SOE) on contracts for materials and equipment, consultant services, and operating costs valued at US$100,000 or less to assist ARMENERGO in making timely payments on the contracts. The PIU would retain the supporting documents and make them available for inspection by IDA supervision missions and by external auditors. Full documentation would be required for expenditures on contracts over US$100,000. IDA will not accept applications for reimbursement or direct payments for amounts less than US$100,000. Audit requirements of the special account are discussed in para. 4.33. During negotiations. the GoA and ARMENERGO agreed with IDA on the arrangements for establishing and operating the Special Account (para 7.1 (iii)). 6 The SA eady established at the Bank of New York for the PPF could be continued.  The Project 25 H. Project Preparation and Implementation 4.26 Project Preparation. The project was identified and prepared by ARMENERGO as a part of the larger Power Rehabilitation Project. ARMENERGO was assisted through a cooperative effort between USAID and European Union-funded consultants, the EBRD, and IDA. Preparation work is complete and includes the specification of all equipment and materials. Preparation of bid packages and tender documents for 1995 procurement would be completed by credit effectiveness. Terms of Reference for project implementation assistance were agreed upon during negotiations. 4.27 Project Preparation Facility. A Project Preparation Facility (PPF) of US$1.2 million was established for the Power Rehabilitation Project on November 2, 1993 mainly to: (i) set up and provide operations and management assistance to a Project Implementation Unit (PIU) within ARMENERGO (US$250,000); (ii) build ARMENERGO's initial capacity in modern power system design and management (US$150,000); and (iii) introduce a prototype (including equipment) of a new electricity distribution and load management system (upgrading one substation and its data and communication links to the central dispatch center - US$800,000). This prototype would test means of strengthening system management and commercial performance, and complete the design of the Electricity Distribution component of the proposed Power Rehabilitation Project. 4.28 Project Implementation. ARMENERGO will be responsible for project implementation and a Project Implementation Unit (PIU), partly funded by the PPF, has been established for this purpose. A Project Manager, already appointed by ARMENERGO, will head the PIU and be responsible for ensuring that the project is implemented efficiently and on schedule. The Project Manager would be assisted by internationally qualified experts (consultants), to supplement expertise presently not available within ARMENERGO, particularly in the areas of project management, procurement, and project accounting and reporting. It is estimated that there will be a requirement for one full-time resident external consultant for overall project management (procurement, processing withdrawal applications and project accounting) for the first year. Additional expertise for the specific functions would be provided on an intermittent basis and will include bid preparation and evaluation (including for the follow-on Power Rehabilitation Project), operations training (particularly in maintenance and inventory management), and accounts auditing. During negotiations. ARMENERGO agreed to maintain an adequately staffed PIU for the duration of the project (para. 7.1 (vii)). 4.29 Consultant services for project implementation are to be provided by a single company (except for accounts auditing). In order to permit a smooth transition from project preparation to implementation, fees for initiai assistance (bid document preparation, evaluation, etc.) would be covered by the PPF while actual implementation assistance would be covered from the IDA credit. During negotiations. ARMENERGO agreed to contract. no later than March 31. 1995 and for the entire project period. proiect implementation assistance according to TORs agreed with IDA (para. 7.1(viii)). Cooperation between the PIUs for the proposed project, and the Institutional Building Loan and the Earthquake Reconstruction Project has been encouraged and is expected to facilitate project implementation. In addition, ARMENERGO/PIU staff would attend Bank-sponsored procurement and disbursement seminars which will be scheduled between November 15, 1994 and March 15, 1995. 4.30 The PIU will work with ARMENERGO's central procurement office and procure goods for each of the power plants and the electricity distribution and dispatch department. ARMENERGO operations and maintenance staff will be directly responsible for carrying out actual maintenance. The  26 The Project staff are technically competent, are trained in quick and efficient maintenance, and are expected to be able to meet the project implementation plan and schedule presented in Annex 4.3. The maintenance work to be financed would be performed mainly during routine maintenance shut-downs and other shut-downs of shorter duration. Key indicators to monitor the project's progress are presented in Annex 4.3. During negotiations. ARMENERGO and IDA agreed on the project implementation plan. project performance indicators, and targets to be achieved by September 1996 (mid-term review) and by proiect completion. This was reflected in the minutes of negotiations. I. Reporting and Monitoring 4.31 The project will be monitored in accordance with the milestones shown in the implementation schedule. Semi-annual and mid-term progress reports, covering all components of the project, would be submitted to IDA by the PIU. The mid-term report, based on the comprehensive mid- term review (para. 4.30), would be submitted to IDA not la:er than August 15, 1996. The detailed reporting formats would be agreed upon prior to the date of submission. In general, the quarterly reports would include: (i) progress achieved against agreed implementation and disbursement schedules; (ii) projected procurement and maintenance schedule for the next quarter; and (iii) progress in achieving technical and financial performance indicators. The main purpose of the reports will be to provide ARMENERGO, the Government, and IDA with timely and updated information on the status of project implementation, highlighting issues and problem areas, recommending actions, and commenting on progress in resolving previous recommendations. 4.32 ARMENERGO will also prepare an Implementation Completion Report (ICR) and a future plan of operations in accordance with IDA guidelines and submit it to IDA promdtly after the completion of the project but in any event not later than six months after the Credit Closing Date (para. 7.1(ix)). A timely and well prepared ICR would assist both the borrower and IDA in future projects in Armenia. Included in the ICR would be an assessment of the execution and initial operation of the project, costs and benefits (derived or to be derived), the performance (relative to their respective obligations) and accomplishments of the Borrower, ARMENERGO, IDA and other agencies involved, and the lessons learned. J. Accounting and Auditing 4.33 Accounting for all Special Account transactions and for all other project-related accounts will be maintained in accordance with international accounting standards. ARMENERGO's annual financial statements will be prepared and audited in accordance with international auditing guidelines by suitably qualified independent auditors acceptable to IDA, and submitted to IDA within six months of the close of the company's fiscal year. Audits will also be carried out in accordance with IDA guidelines, at the same time and for corresponding periods, for SOEs against which disbursements have been made or are due to be made out of the credit proceeds. Specific reference to the SA and SOEs will be made in the audit reports accompanying the company's financial statements. During negotiations. ARMENERGO agreed to submit to IDA. not later than six months after the close of each fiscal year. the auditors report and audited financial statements for the SA. project accounts and SOEs for the fiscal year (para. 7.1(x)). Assistance is presently being provided to convert ARMENERGO's annual financial reports into an internationally acceptable format. ARMENERGO intends to adopt this international format for future reporting.  The Project 27 K. Project Supervision 4.34 In addition to the review of procurement actions during project implementation, semi- annual reports, and other documentation, supervision missions will be planned as required. Owing to the limited experience of the borrower with Bank project implementation and procurement rules, the project is expected to require an above average supervision effort by the Bank in the first year (about 30 staff-weeks), and about 17 staff-weeks/year thereafter. The Supervision Plan, discussed and agreed during negotiations, is shown in Annex 4.5. During negotiations. the GoA and ARMENERGO agreed that a mid-term review of project implementation would take place no later than September 30. 1996 (para. 7.1(xi)). L. International Waterways 4.35 Notification to riparians is not required because the maintenance of the hydropower facilities will not adversely change the quality or quantity of water flows to other riparians. Also, project activities will not be affected by the use other riparians might make of the water. M. Environmental Aspects 4.36 The maintenance of the power facilities will reduce the danger of equipment failure and improve worker safety in the power plants. Although neglected due to lack of financial resources, the electricity distribution and dispatch system is basically sound in design from environmental, public health, and safety viewpoints, and the equipment financed will be installed at existing sites without additional trenching. With the exception of transformer oil, the materials financed are not expected to contain hazardous chemicals such as PCBs. Bid documents for transformer oil will specify that the material not contain PCBs. Over the last few years, most (about 90 percent) thermal generation has been gas-based because of the difficulty in transporting mazut to Armenia. This factor, and the general decline in power generation and all industrial activity, has resulted in a significant improvement in air quality. However, the level of hydropower generation, mainly based on the draw-down of Lake Sevan, is not expected to be sustainable. 4.37 A more thorough review of the environmental and safety practices of the power plants will be conducted prior to appraisal of the follow-on Power Rehabilitation Project. This would allow for an estimation of baseline conditions and a meaningful assessment of the environmental impact of future interventions. Environmental aspects to be addressed during the preparation of this larger project are expected to include: (i) emissions and effluent testing and monitoring; (ii) level of hydropower generation which is sustainable based on the water level of Lake Sevan and run-of-river generation; (iii) waste disposal practices, particularly with regard to disposal of spent transformer oil which often contain PCBs; and (iv) impact on forests and wood resources as a consequence of unreliable energy supply. In any case, the improvements in plant availability as a result of the proposed project are not expected to add measurably to noxious emissions, and would be offset by improvements in plant efficiency. Broader subsector environmental issues which may require attention in the future include the safety of the Medzamor nuclear power plant, either in its present shut-down condition or if it is reconumissioned. The proposed Power Maintenance Project has been assigned an environmental category C.  28 Financial Aspects V. FINANCIAL ASPECTS A. Main Flnancial Issues 5.1 The main credit beneficiary, ARMENERGO, is in a financial crisis. This is not surprising considering the difficult economic conditions in which the company has been operating over the last few years and the unprecedented demands placed on its resources and assets. ARMENERGO generates revenues from the production and sale of electricity and heat from thermal and hydro sources. The constraints on its ability to carry out its responsibilities, its present operating conditions, and the policy environment are discussed in Chapter II. All of these issues effect ARMENERGO's present financial condition and its future prospects, particularly since the unsound operating practices being forced on the company today will require higher investment and operating costs in the future. 5.2 A complete financial assessment of ARMENERGO was not performed because of the volatility in fuel supplies resulting in an inability to forecast electricity supply, distortions in costs, revenues and asset values resulting from high inflation rates (3750 percent in 1993), the practice of ex ante adjustments in the fuel prices charged to ARMENERGO in order to ensure nominal book profits at the end of each quarter, the high level of unaccounted system losses, and mounting arrears which are not written off as losses. Main causes for the deterioration in ARMENERGO's finances are discussed below; a detailed financial analysis of the company is being performed under the EBRD-funded Hrazdan 5 Power Project by an international consultant (para. 2.21) and is expected to be completed by March 1995. A full financial appraisal would be conducted for the follow-on Power Rehabilitation Project. 5.3 Developments which have had a direct impact on ARMENERGO's finances and require an appropriate response from ARMENERGO and the Government include: (i) shifts in electricity consumption patterns and increased system losses due to electricity theft; (ii) mounting accounts receivable; and (iii) electricity tariffs below full-cost recovery levels. These issues and their financial implications are discussed below. B. Consumption Patterns 5.4 The most pronounced shift in electricity consumption between 1990 and 1993 has been a five-fold decline in industrial consumption (traditionally the mainstay of the power subsector) and a more than doubling in consumption by the heavily subsidized household sector. This increase in household consumption is contributed to by the discontinuation of central district heating services and has occurred largely through illegal connections in order to circumvent electricity rationing norms. Non- household tariffs, presently US cents 2.43/kWh, subsidize a low household rate of 1.3 dram (US cents 0.40) per kWh (Table 2.2). The average tariff estimated by ARMENERGO as of July 1, 1994 was US cents 1.50/kWh. Electricity supply costs are discussed in Section D. A comparison of the 1990 and 1993 electricity generation and consumption profiles is presented in Table 5.1.  Financial Aspects 29 TABLE 5.1: ELECTRICITY GENERATION AND CONSUMPTION PROFILE GWh Percent GWh Percent . ~~~ ~ ~~~~~~~~~~~~ ~~~~~~~~. . .... . ,... ......... . . Tota Electricty Gertd - 1036 10% - 6-9 100 Thermal 8807 85 % 2003 32% Hydro - Total 1555 15% 4292 68% (From Sevan-Hrazdan Cascade) (445) (4%) (2838) (45%) Net Imports (Exports) 920 114 Total National Consumption 1182 100% 6409 _100 Self-Use (within Power Plants) 798 7% 199 3% Technical 'unavoidable' losses 1354 12% 769 12% Tota Avaiable for Sale 9130 81% 5441 SS System 'commercial' losses 278 2% 1618 25% Net System self-use and losses 2430 22% 2586 40% Amount sold and accounted for 8852 78% 3823 60% Consumption by sector Industry and Construction 4125 45% 773 14% Agriculture 2122 23% 447 8% Communal (Government, Admin, etc.) 1363 15% 1060 19% Population/Households - Totl 11 13% 297S S. Population/Households - Accounted 914 10% 1357 25% Population/Households - UAcounted 278 3% - 1615 30% Transport 328 4% 186 3% Total Consumption 9130 100% 5441 100% 5.5 System losses have increased from around 15 percent in 1990 (technical and commercial, excluding own-use) to 37 percent in 1993. These losses are largely attributed to the, increase in electricity "theft" through illegal connections which are themselves a result of the Governments recourse to the strict rationing of electricity to residential consumers. ARMENERGO estimates that due to the low residential tariffs, these losses would have contributed to only 4 percent of additional sales revenues. As tariffs are raised to reflect their full supply costs, it will be necessary to revise the current practice of having residential consumers pay according to their own reading of electricity meters. Better inspection and policing against illegal connections will also be required. Strengthening of the electricity distribution system under the proposed project would allow for improved isolation of areas where "losses" are occurring and permit the disconnection of non-paying customers. During negotiations. the GoA and ARMENERGO agreed to: (i) take all measures necessary to reduce. by December 31. 1995. and again by December 31. 1996. total electricity system losses and ARMENERGO's system losses by at least 30 percent of the losses (as a percentage of total production) assessed for the preceding year: and (ii! submit to IDA. not later than July 15. 1995. an action plan. including priority metering and control investments, billing and accounting methods. incentive programs. and other organizational arrangements to meet the electricity loss reduction targets agreed to with IDA (paras. 7.1(xii) and (xiii)). System losses were defined as the difference between total generation and total collections for ARMENERGO and for the entire power supply system.  30 Financial Aspects C. Accounts Receivable 5.6 ARMENERGO's arrears are growing and are losing their value due to the high rate of inflation. In 1993, of total sales of RR 34 billion, realized sales amounted to only RR 22 billion, and the company had a net book profit of RR 1.5 billion (realized sales revenues less costs), or 7 percent of realized sales. Accounts receivable were RR 15 billion, up from RR 4.8 billion at the end of 1992. Accounts receivable for 1993 alone amounted to about 129 days of sales. ARMENERGO now requires customers to pre-pay for electricity service, however this is not systematically enforced because of the inability of customers to pay, the critical nature of certain customers to the economy, and Government intervention. 5.7 Unless an enforceable collections policy is implemented, reforms in tariff policy are likely to only result in increased arrears. During negotiations the GoA and ARMENERGO agreed to ensure that the average revenue collection period for electricity sold not exceed 60 days by December 31. 1995. 45 days by December 31. 1996. and 30 days thereafter (para. 7.1(xiv)). Appropriate treatment of accumulated arrears and company debt would be addressed by the financial strengthening study. D. Cost Recovery and Electricity Tariffs 5.8 Although the present tariff setting methodology provides allowances for operating and maintenance (O&M) costs, budgetary estimates of O&M costs used for tariff determination need further investigation to determine the needs of Armenia's electricity supply system for the next few years. O&M costs are expected to increase over the near term as a result of the accelerated deterioration in electricity supply infrastructure. In addition, electricity generation costs in Armenia are strongly influenced by the proportion of low-fuel cost hydropower. Taking these factors into account, IDA estimates that the present average electricity tariff of US cents 1 .50/kWh is sufficient to cover only direct O&M costs of electricity generation. Additional allowances are required for self-use, transmission and distribution losses, depreciation, interest charges, and overhead costs. This assessment is based on: - Generation: 50 percent from no-fuel-cost hydropower and balance from thermal; - Natural gas contract price (for ARMENERGO) of US$55/tcm; - Annual non-fuel O&M costs estimated at the low end of typical industry standards (1.5% of replacement capital costs for hydropower and 2.5% for thermal generation facilities7; - Average fuel conversion efficiency (for thermal units) of 30 percent; - Transmission and distribution (T&D) losses of 20 percent of generation; and - Depreciation (based on replacement capital costs) valued on a straight line basis of 40 years for hydro and 25 years for thermal. 5.9 An estimation of direct operating costs and depreciation per unit of electricity supply is presented in Annex 5.1. The comparisons are done at two different prices for natural gas, USS55/tcm 7 For estimation of annual O&M costs, replacement capital costs were estimated at US$2000/kW for hydropower generation facilities (plant and ancillary facilities), US$750/kW for thermal generation facilities, and US$525/kW for the associated T&D network. O&M costs could be twice as high as those estimated because of the age and condition of existing equipment. Capacity factors: 60% for hydro (based on 1993 production) and 70% for thermal.  Financial Aspects 31 (price actually paid by ARMENERGO as of October 1994) and US$80/tcm (contract price between Armenia and Turkmenistan), and varying proportions of hydro and thermal power generation. A summary of the results is presented in Table 5.2. TABLE 5.2: ELECTRICITY SUPPLY COSTS (in US cents/kWh) Fuel Direct Direct Costs + Costs O&M Direct Costs + 20% Losses + Only Costs 20% Losses Depreciation Gas @ US$55/tcm: 75% Hydro 0.48 1.15 1.38 2.38 50% Hydro 0.95 1.57 1.89 2.75 25% Hydro 1.43 2.00 2.40 3.13 Gas @ US$80/tcm: 75% Hydro 0.69 1.36 1.64 2.64 50% Hydro 1.39 2.01 2.41 3.27 25% Hydro 2.08 2.65 3.18 3.91 Expenses such as interest charges & overheads, and revenues from heat supply are not included. 5.10 Over the last year, recourse to excessive hydro power generation, with virtually no financial costs for fuel, inadequate maintenance of facilities, low salaries, and subsidies in the form of concessional fuel prices have helped to keep average operating costs down. However, electricity "losses" have been substantially higher than in the past (Table 5.1) and fuel conversion efficiencies are likely to be lower than 30 percent, particularly for units urgently in need of deferred maintenance. The inability of operating revenues to cover operating costs is also reflected in the deteriorated condition of the country's electricity supply infrastructure. Although heat sales would contribute to the revenue stream, the amount is unlikely to be more than 10-15 percent of electricity sales. 5.11 During credit negotiations, the GoA agreed to adopt, by December 31. 1995. an interim electricity tariff setting methodologv which at least covers the full operating and maintenance costs of electricity supply, (para. 7. 1(vi)). On-going and planned studies (para. 2.21) would determine the full O&M costs by June 30, 1995, and, upon agreement by the GoA and IDA, these costs would be fully reflected in the average electricity tariff by December 31, 1995. The interim methodology agreed upon, and the principles for establishing future electricity tariffs (to be phased in after December 31, 1995), are presented in Annex 5.2. These agreements are aimed at restoring ARMENERGO's financial viability and credit worthiness (while providing it with incentives to improve operating efficiency), rationalizing energy consumption, and protecting vulnerable segments of the population.  32 Benefits and Risks VI. BENEFITS AND RISKS A. Benefits 6.1 The project would arrest the deterioration and costly damage to the selected facilities to be maintained, and alleviate high human and economic costs by improving the reliability of electricity supply to critical facilities such as selected hospitals, schools and universities, public transportation, bread factories, telecommunication stations and export industries. 6.2 In particular, the project would: * Improve the availability (reduce unscheduled downtime) of 550 MW of thermal power capacity and about 315 MW of hydro capacity and prevent its premature replacement. * Restore the fuel efficiency of the thermal plants closer to design levels (after boiler and turbine maintenance). * Reduce safety risks by mitigating the chance of catastrophic equipment failures. * Improve the reliability of electricity supply to consumers while reducing damage to power systems due to overloading of the distribution network. 6.3 Quantification of benefits has been difficult because the lack of fuel, and not lack of capacity, has been the main constraint to continuous operation, particularly of the thermal units. Consequently, the current performance (baseline) characteristics of the plants and their potential improvement under the project could not be quantified. However, economic justification based on indicative measures is presented below. B. Economic Justification 6.4 Selection of facilities to be maintained. The facilities to be maintained were selected based on the following factors: (i) the critical need for maintenance in order to keep the generating units operating; (ii) the amount of fuel which could be reliably available (for selection of thermal units); (iii) the potential for life extension rehabilitation of the generation units under the follow-on Power Rehabilitation Project and other rehabilitation operations; (iv) the need for improvement in the communications, control and protection of the electricity distribution system; and (v) the level of financing available under the proposed project and from other sources. 6.5 Demand and Supply. Compared with annual electricity demand projected at 7252 GWh for 1995 increasing to 8366 GWh by 2000 (Energy Sector Review - base case), the generation capacity maintained under the proposed project would be able to supply 4340 GWh (3375 GWh from thermal and 965 GWh from hydro)'. Another 1840 GWh would be supplied from Hrazdan 5 (300 MW) upon completion in 1995. If recommissioned, 2500 GWh could be supplied from the Medzamor NPP. Peak load demand would be supplied from the hydro units. 8 Assuming capacity factors of 70% for thermal and 35% (under stable fuel supply conditions) for hydro.  Benefits and Risks 33 6.6 Fuel Supply. Armenia's 1993 supply of 800 million m3 of gas and 232,000 tons of mazut would have been able to generate about 2775 GWh of electricity from about 450 MW of capacity9. Assuming a reserve margin of 25 percent, the maintenance of 550 MW of thermal capacity is justified from the view point of fuel availability. Additional fuel would be required in order to fully utilize the thermal capacity maintained under the proposed project and the Hrazdan 5 unit. Because of its higher fuel efficiency, about 325 million m3 of gas would be required annually for Hrazdan 5 (assuming a 70 percent capacity utilization factor). 6.7 Least-Cost Analysis. As is typical for maintenance activities, project investments are both a least-cost means of preserving installed capacity and extending plant life. Cost comparisons between plant maintenance under the project and capacity replacement and rehabilitation are presented in Table 6.1. The highlights of this comparison are: * Maintenance costs under the project are estimated to be US$9.8/kW for the targeted thermal units and US$4.3/kW for the hydropower units. These costs are considerably below typical capital costs for rehabilitation or capacity replacement. * Maintenance costs per unit of installed capacity are substantially below the annual maintenance costs estimated for new conventional oil and gas fired plants (the type in operation in Armenia) and new hydro units. Typical annual maintenance costs are US$22.5/kW (at 2.5 percent of capital costs) for conventional oil and gas fired thermal plants and US$30/kW for hydro plants (at 1.5 percent of capital costs). * The present value of deferring the investment in replacement capacity by one year is about US$37.5 million'". * A fuel efficiency improvement of 1 percent for 550 MW of thermal capacity would reduce annual fuel costs by US$3 million"1. Considering the poor condition of the boilers and turbines, an improvement in fuel efficiency of 3 to 4 percent could be expected. 6.8 Project Timing. The assistance strategy adopted is to proceed in two steps: first, with the proposed Power Maintenance Project, second, to follow with the Power Rehabilitation Project a year later (para. 3.7). This is justified as the benefits of quick implementation (prevention of premature failures and improved system reliability) far outweigh the benefits of delaying the first project by one year and integrating it with the larger Power Rehabilitation Project. Fuel savings alone (US$3 million) would be more than twice the company's first year interest on the loan amount"2. 9 Actually only 648 million m3 gas was supplied to ARMENERGO and 2003 GWh of electricity were generated from thermal units. '