Document of The World Bank Report No: 22589-GE PROJECT APPRAISAL DOCUMENT ONA PROPOSED CREDIT IN THE AMOUNT OF SDR 21.1 MILLION (US$27.4 MILLION) TO GEORGIA FOR AN ELECTRICITY MARKET SUPPORT PROJECT April 9, 2001 Energy Sector Unit Armenia, Azerbaijan and Georgia Country Unit Europe and Central Asia Region CURRENCY EQUIVALENTS (Exchange Rate Effective January 2001) Currency Unit = Lari Lari 2.0 = US$1 US$0.5 = Lari 1 FISCAL YEAR January 1 to December 31 ABBREVIATIONS AND ACRONYMS BD Bidding Documents MoFE Ministry of Fuel and Energy CAS Country Assistance Strategy NPV Net Present Value EBRD European Bank for Reconstruction and Development NCB National Competitive Bidding ED Electrodispatcherizatsia - Dispatch Company NS National Shopping EG Electrogadatsema - Transmission Company OECF Overseas Economic Cooperation Fund EMS Energy Management System PIP Project Implementation Plan ESAC Energy Sector Adjustment Loan PCB Polychlorinated Biphenyls EIRR Economic Internal Rate of Return PIU Project Implementation Unit EU European Union PLC Power Line Carrier FARAH Financial Accounting, Reporting and Auditing Handbook PPF Project Preparation Facility FIRR Financial Internal Rate of Return PMR Project Management Reports GEL Goorgian Lari QBS Quality Based Selection GNERC Georgian National Energy Regulatory Commission QCBS Qualify and Cost Based Selection GoG Government of Georgia RFP Request for Proposal GPN General Procurement Notice RTU Remote Terminal Unit GWh Gigawatt hour (million kilowatt hours) SAC Structural Adjustment Credit ICB International Competitive Bidding SATAC Structural Adjustment Technical Assistance Credit ICR Implementation Completion Report SCADA System Control and Data Acquisition IDA International Development Association SE Sakenergo, Dispatch company IMF International Monetary Fund SOE Statement of Expenditures IS International Shopping SPN Special Procurement Notice KV Kilovolt TACIS Technical Assistance for the KfW Kreditanstalt fur Wiederaufbau (Reconstruction Loan Commonwealth of Independent States Corporation) KWh Kilowatt hour T&D Transmission and Dispatch LACI Loan Administration Change Initiative USAID United States Agency for International LESP Letter of Electricity Sector Policy Development MC Management Contract VAT Value-added Tax WEM Wholesale Electricity Market Vice President: Johannes Linn, ECA Country Director: Judy O'Connor, ECCO3 Sector Director: Hossein Razavi, ECSEG Task Team Leader: Vladislav Vucetic CONTENTS A. PROJECT DEVELOPMENT OBJECTIVE ............................................................................. 3 1. PROJECT DEVELOPMENT OBJECTIVE: (SEE ANNEX 1) ...................................................................... 3 2. KEY PERFORMANCE INDICATORS: (SEE ANNEX 1) ........................................................................... 3 B. STRATEGIC CONTEXT ............................................................................. 3 1. SECTOR-RELATED COUNTRY ASSISTANCE STRATEGY (CAS) GOAL SUPPORTED BY THE PROJECT:.. 3 2. MAIN SECTOR ISSUES AND GOVERNMENT STRATEGY: ..................................................................... 3 3. SECTOR ISSUES TO BE ADDRESSED BY THE PROJECT AND STRATEGIC CHOICES: ................................6 C. PROJECT DESCRIPTION SUMMARY ............................................................................. 7 1. PROJECT COMPONENTS ............................................................................. 7 2. KEY POLICY AND INSTITUTIONAL REFORMS SUPPORTED BY THE PROJECT: ............ ...........................9 3. BENEFITS AND TARGET POPULATION: ............................. ................................................ 9 4. INSTITUTIONAL AND IMPLEMENTATION ARRANGEMENTS: ............................. .................................. 9 D. PROJECT RATIONALE ............................................................................. 12 1. PROJECT ALTERNATIVES CONSIDERED AND REASONS FOR REJECTION: ............. .............................. 12 2. MAJOR RELATED PROJECTS FINANCED BY THE BANK AND/OR OTHER DEVELOPMENT AGENCIES (COMPLETED, ONGOING AND PLANNED) .............................................................................. 14 3. LESSONS LEARNED AND REFLECTED IN THE PROJECT DESIGN: ..................... ................................... 1 5 4. INDICATIONS OF BORROWER COMMITMENT AND OWNERSHIP: .................... ................................... 15 5. VALUE ADDED OF BANK SUPPORT IN THIS PROJECT: ...................................................................... 15 E. SUMMARY PROJECT ANALYSIS ............................................................................. 16 1 . ECONOMIC (SEE ANNEX 4): .16 2. FINANCIAL (SEE ANNEX 4 AND ANNEX 5):. 1 6 3. TECHNICAL: .23 4. INSTITUTIONAL: .24 5. ENVIRONMENTAL .26 6. SOCIAL: .26 7. SAFEGUARD POLICIES: .28 F. SUSTAINABILITY AND RISKS ................................... 28 1. SUSTAINABILITY: ................................... 28 2. CRITICAL RISKS ................................... 29 G. MAIN CREDITCONDITIONS ................................... 30 1. EFFECTIVENESS CONDITION ................................... 30 2. OTHER ................................... 30 H. READINESS FOR IMPLEMENTATION ................................... 31 I. COMPLIANCE WITH BANK POLICIES ................................... 32 ANNEX 1: PROJECT DESIGN SUMMARY ANNEX 2: DETAILED PROJECT DESCRIPTION ANNEX 3: ESTIMATED PROJECT COSTS ANNEX 4: COST BENEFIT ANALYSIS ANNEX 5: FINNSIL SUMMARY ANNEX 6: PROCUREMENT AND DISBURSEMENT ARRANGEMENTS ANNEX 7: PROJECT PROCESSING SCHEDULE ANNEX 8: DOCUMENTS IN THE PROJECT FILE ANNEX 9: STATEMENT OF LOANS AND CREDITS ANNEX 10: COUNTRY AT A GLANCE ANNEX 11: LETTER OF ELECTRICITY SETOR POLICY MAP GEORGIA Electricity Market Support Project Project Appraisal Document Europe and Central Asia Region ECSEG Date: April 9, 2001 Team Leader: Vladislav Vucetic Country Manager/Director: Sector Manager/Director: Project ID: P054886 Sector(s): PP - Electric Power & Other Energy Adjustment Lending Instrument: Specific Investment Loan (SIL) Theme(s): Poverty Targeted Intervention: N Program Financing Data [ ] Loan [X] Credit [] Grant [ ] Guarantee [ ] Other: For Loans/Credits/Others: Amount (US$m): 27.37 Proposed Terms : Standard Credit Grace period (years): 10 Years to maturity: 40 Commitment fee: 0.5% Service charge: 0.75% Financing Plan: Source Local Foreign Total BORROWER 7.57 9.36 16.93 IDA 0.52 26.85 27.37 EUROPEAN BANK FOR RECONSTRUCTION AND 0.00 0.92 0.92 DEVELOPMENT KREDITANSTALT FUR WIEDERAUFBAU 0.00 11.36 11.36 Financing Gap 0.00 0.00 0.00 Total: 8.09 48.49 56.57 Borrower: GEORGIA Responsible agency: ELECTROGADATSEMA, ELECTRODISPETCHERIZATSIA, WEM, MOF&E Electrodispetcherizatsia Contact Person: Mr. Boris Kozhoridze, General Director Tel: 995-32-93-63-17 or 98-98-21 Fax: 995-32-92-37-48 Email: Other Agency(ies): JSC Elektrogadatsema Address: 2 Baratashvili St., Tbilisi 380005, Georgia Contact Person: Mr. Guram Javakhadze, Director Tel: 995-32-98-98-21 Fax: 995-32-98-98-21 Email: Ministry of Fuel and Energy Address: 10, Lermontov Str., Tbilisi, Georgia Tel: 995-32-93-13-84 Fax: 995-32-93-63-91 Email: Estimated disbursements ( Bank FYIUS$M): FY 2002 2003 2004 9 2005 7 2006 Annual 2 6.02 9.58 7.39 1.10 Cumulative 3.28 9.30 18.88 26.27 27.37 Project implementation period: 4.5 years Expected effectiveness date: 06/30/2001 Expected closing date: 12/31/2005 2 A. PROJECT DEVELOPMENT OBJECTIVE 1. PROJECT DEVELOPMENT OBJECTIVE: (SEE ANNEX 1) The project aims to improve reliability and efficiency of electricity supply, and improve financial and corporate management in the wholesale electricity market. 2. KEY PERFORMANCE INDICATORS: (SEE ANNEX 1) By the end of the project: * Reduce outage rates of the 500-kV lines and substations (see Annex 1) * Reduce system-wide outages from 20 hrs/yr to 15 hrs/yr (expressed in equivalent total system blackout hours); * Improve collections at the wholesale level from 55% to 95%; * Reduce losses in the subtransmission and transmission network from 15% to 12.5%. B. STRATEGIC CONTEXT 1. SECTOR-RELATED COUNTRY ASSISTANCE STRATEGY (CAS) GOAL SUPPORTED BY THE PROJECT: (see Annex 1) Document number: Report No. 17000-GE Date of latest CAS discussion: 10/21/97 The last CAS is dated Sept. 22, 1997 and is Report No. 17000-GE finance by restructuring the debt stock of the state enterprises in the sector, and stemming the accumulation The project will support all four objectives of the CAS. It will strengthen public of new debt through improved management of the beneficiary enterprises and the wholesale electricity market. The project will deepen and diversify sources of growth by improving the reliability of electricity supply to the economy and by enhancing the climate for private investment in the sector. It will protect the environment through reducing reliance on environmentally-harmful energy sources (kerosene, firewood etc.), and through improved environmental management practices in the beneficiary enterprises. The project will reduce poverty through its effect on overall economic growth and by supporting implementation of the social protection mechanisms agreed under the Energy Sector Adjustment Credit. 2. MAIN SECTOR ISSUES AND GOVERNMENT STRATEGY: The principal sector issues include: * high level of non-payments and accumulated debt; * high level of corruption; * high degree of politicization; * weak regional integration in Georgia and the Caucasus; * weak management at the sector ministry and enterprise level; * uncertain implementation of regulatory framework; and 3 * very unreliable electricity supply due to insufficient generation capacity (especially in winter), deteriorated network, and inadequate control and communications systems. The Government strategy to address these issues includes: * opening all parts of the sector to private participation to improve management and payment discipline, attract investment, reduce corruption and depoliticize the sector; * enhancing regulatory capacity; * improving management of physical and financial flows at the wholesale level; * restructuring debt stock; and * improved targeting of social protection and transfer from sector to Government budget. The Government, starting in 1996, launched a major reform in the power sector, aimed at its demonopolization, commercialization and privatization. The first two years were used to develop a market-oriented legal and regulatory framework, establish an independent energy regulatory commission, unbundle the sector and corporatize the sector enterprises. Starting in 1998, the Government offered all electricity distribution companies and thermal power plants for sale and hydropower for long-term concessions. The high-voltage transmission network and system dispatch assets were considered of strategic importance for national security and were not offered for privatization, but the Government is inviting international bids to put these assets under management contracts. Progress to date includes: * Electricity distribution in the capital Tbilisi, whose share in the national consumption ranges between 40- 50%, depending on the season and the year, was sold to AES, a US strategic investor, at the end of 1998. Distribution companies outside Tbilisi have not been sold (some are still under negotiations with investors), and will be offered for privatization again after being consolidated into larger companies in 2001. Those which could not be sold due to the lack of interested qualified investors, will be put under management contract with international manager through a competitive process; e Two 300-MW units at the Tbilsresi thermal power plant (also known under the name of Gardabani) -- i.e. all thermal generation capacity in the country which is operational and economic -- was sold also to AES on April 10, 2000. One of the units was rehabilitated under the IDA-financed Power Rehabilitation Project prior to privatization. The remaining old eight 150-MW units, six of which are not operational at all, should be either privatized or decommissioned. The plant, as the only major thermal plant in Georgia, plays a vital role in country's electricity supply, particularly in winter. For variety of reasons -- corruption, sector and corporate mismanagement, non-payments in the sector and consequent lack of funds for fuel, maintenance, etc. -- the plant had incurred an estimated US$230 million debt before privatization, a sizable portion of the sector's total debt estimated at about US$675 million. * Georgia has 17 hydropower plants larger than 10 MW outside disputed territories, most of which are in the range of 40-120 MW. At the end of 1999, AES bought 25-year concessions for two hydropower plants with total capacity of 220 MW. Four hydropower plants, with total capacity of about 180 MW, are under negotiations for management contract with a Greek contractor. The remaining plants will be offered for long-term concessions again; * There are three entities operating Georgia's wholesale electricity market: Electrogadatsema (EG), which owns and operates high voltage transmission network; Electrodispatcherizatsia (ED), in charge of physical dispatch of electricity flows; and the Wholesale Electricity Market (WEM), in charge of 4 financial settlements, established in July 1999. EG and ED, both 100% state-owned companies, were created in 1999 and 2000 respectively, by separation from Sakenergo. The remainder of Sakenergo, since 2000, became a company holding historic debts, with no role in operation of the power system. Tendering process is underway for selection of private management for EG, ED, and WEM; * Georgia National Energy Regulatory Commission (GNERC) was established under 1997 Electricity Law, and by now has developed a significant technical capacity and track record of independence and good performance (tariffs now approach full-cost recovery level); * Discounts for non-vulnerable groups were abolished, while discounts for others were capped and budgetized. Poverty benefit for groups most vulnerable to sector reforms were established. A donor- funded Winter Heat Program was also established. The Bank has been supporting the Government strategy through investments, adjustment, and technical assistance operations. The Energy Sector Adjustment Credit (ESAC), approved in June 1999, has been particularly instrumental for privatization of electricity distribution and generation companies, improving the regulatory framework, introducing greater transparency in financial management, and ensuring that compensatory social protection measures are in place and poverty benefits paid. It is expected that the final, second, tranche of ESAC would be disbursed by June 30, 2001. In spite of the major progress in the institutional, structural and regulatory reforms and privatization, the power sector is still in deep crisis. Power supply in the capital, provided by the AES-Telasi company, is better than in the rest of the country, but is still not satisfactory in winter times. Although AES-Telasi pays fully for electricity it buys directly from generation plants and imports (although there are some problems with the payments to the WEM for the difference between the average WEM price and the prices in direct contracts), the company is not able to provide 24-hrs supply due to a combination of reasons beyond its control: it is physically impossible to isolate the Tbilisi network from the rest of the country and have it connected to the generation plant and electricity import lines; electricity dispatch is affected by political considerations, not just by payment records; transmission lines are subject to outages; etc. Power supply in other areas, where distribution companies are still public, is worse and their financial performance extremely poor due to corruption, theft, mismanagement, poor metering, disrepair, and high losses. During the July 1999-June 2000 period non-privatized distribution companies paid only about 20% for electricity received though the wholesale electricity market, half of which was in cash and the other half in offsets. AES- Telasi reportedly paid 38% for electricity received through the wholesale market in the second half of 1999, and 60% in the first half of 2000, 80% of which was in cash. (AES-Telasi buys most of its electricity -- about 80% in 2000 -- through bilateral contracts, rather than the wholesale market.) This situation -- an increasingly better performing distribution company in the capital and non-performing distribution elsewhere -- is unsustainable. The Wholesale Electricity Market and the dispatch and transmission companies do not strictly enforce payments through disconnection of non-paying distributions for a variety of reasons: political pressure to maintain some supply to all regions irrespective of the payment records, technical difficulties to execute selective disconlections through the transmission network, etc. This, on one hand, creates enormous problems for the better performing distribution companies (such as AES-Telasi) who cannot maintain regular supply to their customers as electricity gets diverted elsewhere. On the other hand, it also creates increasing differences in the amount of supply of electricity between the capital and other regions, creating political problems. Clearly, without major improvement in financial performance of distribution companies outside the capital, and without better management of the Wholesale Electricity Market and the dispatch and transmission companies to impose market discipline on electricity trading, there is a major risk that the reform achievements in the sector could be lost quickly. The Bank agreed with the Government on a Letter of Electricity Sector Policy (LESP), which includes principal policies during the nextfewyears to further advance the reforms in the electricity sector (Annex 11). The policies include privatization of all segments of the power system through sale, lease, and management contracts, 5 restructuring of the sector historic debts, maintaining GNERC's independence, and maintaining prudent fiscal policies related to the energy sector (including well-targeted social policies and payments for energy consumption of budget agencies and institutions) 3. SECTOR ISSUES TO BE ADDRESSED BY THE PROJECT AND STRATEGIC CHOICES: The project is to address all the issues mentioned in the previous section. There are no credible alternatives to improving performance of either the distribution sector or the wholesale market servicing organizations without involvement of competent strategic investors and/or international managers. The only question is what are feasible options for doing so in the Georgian political context and legal framework, and response of international investment markets. These options differ for the distribution sector from the wholesale market servicing organizations. In the distribution sector, privatization of distribution companies to international strategic investors is Government's preferred strategy. However, it appears that the interest of investors is limited at this stage and Georgia may be unable to privatize most of its distribution (outside Tbilisi) for some time. In such case, the fallback strategy would be to hire international contractors to manage non-privatized distribution (with investment assistance provided by international financing institutions), improve their performance and prepare them for privatization at a more opportune moment later. Donors (US AID and KfW) have made grant funds available to allow the Government to hire transactions advisors to assist them in transferring the remaining nonprivatized distribution companies to private ownership/management. The Government, in its Letter of Electricity Sector Policy, has committed to a time-bound action plan to complete this process by June 30, 2002. Given the key importance of thefinancialperformance of the distribution sectorJfor the performance of the wholesale market organizations and, therefore, for the success of the project, it has been agreed that the Government willprivatize all distribution companies to qualified strategic investors for which there is interest in the market, and place all non-privatized distribution companies under management contract with a credible international manager, through a competitive, transparent process satisfactory to IDA, before any funds from the IDA Credit are disbursed against the investment contracts financed by the Credit. The Government already hired a qualified privatization advisor to assist with this process. Options for involving private sector in high-voltage transmission and dispatch, servicing the wholesale electricity market, are more limited. There are both legal and political obstacles to privatizing these assets, leaving management contracts as practically the only instrument. The contracts have to be supported by investments in the physical infrastructure underpinning the operation of the market: transmission network, metering, and dispatch. The only source of funds for such investment is public borrowing from international financing institutions. The proposed project would provide such funds. The project will address a range of interconnected sector issues. The introduction of private management for transmission, dispatch and the WEM, in conjunction with the planned investments, is intended to reduce corruption and politicization, increase financial flows and transparency, decrease technical losses, increase the reliability of transmission and dispatch services, and improve implementation of non-discriminatory market rules and transmission access. It will thus improve the climate for private investment in generation and distribution (both for further privatization and for investment in already-privatized facilities) and enhance competition. Through increased transparency of financial flows, it will allow improved regulation. The project will provide the physical infrastructure and institutional and managerial strengthening to enable better functioning of the existing system and its transition toward a more efficient electricity market, both domestically and regionally. Through restructuring the debt overhang, the project will remove a major threat to fiscal stability and to the sustainability of sector reforms. More efficient operation of transmission, greater involvement of the 6 private sector, and improved financial capacity should facilitate regional integration in the Caucasus, through electricity trade. Improved electricity supply may enhance integration within Georgia. C. PROJECT DESCRIPTION SUMMARY 1. PROJECT COMPONENTS (see Annex 2 for a detailed description and Annex 3 for a detailed cost breakdown): The project includes the following components: * Rehabilitation and upgrade of metering of electricity flows in the transmission network; * Rehabilitation and upgrade of system control; * Rehabilitation and upgrade of telecommunications; * Rehabilitation of a 500-kV transmission substation; * Improvements in management information systems for the wholesale electricity market organizations; * Management Contracts for the Wholesale Electricity Market and the transmission and dispatch companies; and * Technical services for project implementation. Rehabilitation and upgrade of metering. This component includes installation of energy meters in the 110- to 500-kV transmission network, which would enable metering and recording of active and reactive electricity flows in the wholesale electricity market. The meters would record the 15-minutes energy flows, be able to transmit information to the National Dispatch Center and the Wholesale Electricity Market Settlement Center, and have remote and on-site data downloading and reading capabilities. The metering system should be able to support a variety of market arrangements, from bilateral contracts to short-term spot markets based on competitive bidding. Rehabilitation and upgrade of system dispatch. This component includes installation of the necessary hardware and software to enable real time acquisition of operational information from the main facilities (power stations and transmission system substations), analysis and monitoring of the system status at the National Dispatch Center, and control and dispatch of the power plants, load centers, and the transmission system, to maintain a reliable, secure and economic operation, and facilitate financial settlements in the wholesale electricity market. The main elements of the system include Remote Terminal Units (RTU) and the corresponding local data acquisition equipment at the power plants and transmission substations (110- to 500-kV network), System Control And Data Acquisition (SCADA), and the Energy Management System (EMS) at the National Dispatch Center. Rehabilitation and upgrade of telecommunications. This component includes installation of the necessary communications equipment (fiber optics, power line carrier systems, and radio systems), which would serve the communication needs of the metering and dispatch. Rehabilitation of a 500-kV transmission substation. This component includes rehabilitation of selected equipment at the 500-kV Zestafoni substation, including mitigation of environmental shortcomings. The substation controls two key transmission lines -- Zestafoni-Inguri and Zestafoni-Ksani -- which are part of the 500-kV transmission link Russia-Inguri-Zestafoni-Ksani-Gardabani-Azerbaijan (and future planned link to Turkey). The substation also controls 1 10-kV lines to major industrial centers and 220-kV lines supplying major cities (Kutaisi, Gori). As such, the substation is critical for reliable operation of the entire transmission network in the country. 7 Management information systems for the wholesale electricity market organizations. This component includes supply and installation of computerized management information systems at Electrogadatsema, Electrodispatcherizatsia and the Wholesale electricity market (through leasing arrangements with Electrodispatcherizatsia). Management Contracts. In order to bring the necessary market and management expertise and improve the commercial and technical performance of the system, the Government intends to sign two 5-year management contracts (MC) with international firms to manage (1) the Wholesale Electricity Market (WEMMC), and (2) the dispatch and transmission companies (T&DMC). The MCs will be awarded through international competitive bidding, and will have a retainer and a performance based fee. A portion of the retainer fees will be financed from donors funds. The management contractors will have the authority and responsibility to effectively manage the companies and the WEM, including implementation of internal organizational restructuring; reassignment of staff, hiring and layoffs; business planning; entering into contracts with third parties; financial management; etc. The responsibilities will also include implementation of the project. Technical Services include: * Engineering, Procurement and Project Management: services of international consultants for engineering design, procurement and project implementation. - Electricity Sector Debt Restructuring: consulting services of legal and financial advisors to help the Government prepare and implement a plan for restructuring of electricity debt. - Transmission System Environmental Action Plan: consulting services for preparation of a transmission system environmental action plan. - Audit: services of a qualified independent auditor for auditing the companies' and project financial statements. Incremental operating costs. This component includes the incremental costs associated with the establishment and operation of a Project Service Organization, to be created by the project beneficiaries specifically for implementation of this project. Component Sector SCADA/EMS Electric Power & Other Energy Adjustment Telecommunications Electric Power & Other Energy Adjustment Metering Electric Power & Other Energy Adjustment Transmission Electric Power & Other Energy Adjustment Management Information Systems Electric Power & Other Energy Adjustment Management Contract - Wholesale Electricity Market (WEM) Electric Power & Other Energy Adjustment Management Contract - Dispatch Company (DC) and Electric Power & Other Energy Adjustment Electrogadatsema (EG) Transmission Company Engineering, Procurement, and Project Management Electric Power & Other Energy Adjustment Debt restructuring Electric Power & Other Energy Adjustment Environmental Action Plan Electric Power & Other Energy Adjustment Audit Electric Power & Other Energy Adjustment Incremental Operating Costs 8 2. KEY POLICY AND INSTITUTIONAL REFORMS SUPPORTED BY THE PROJECT: The project will contribute to: * improved climate for economic growth; * improved financial management in the electricity sector; * improved fiscal management and macroeconomic stability; * enhanced climate for private participation in infrastructure; * increased competition in electricity supply; * greater regional integration in Georgia and in the Caucasus; and * enhanced regulatory capacity. 3. BENEFITS AND TARGET POPULATION: Quantifiable benefits of the project include: (i) increased reliability of the transmission system and reductions in failures and forced outages as a result of equipment upgrades and better system control; (ii) reduced transmission losses; (iii) avoided operations and maintenance costs for the telecommunications system; (iv) increased output from hydroelectric plants, with consequent reductions in load shedding and/or savings in high cost thermal generation; and (v) reduced system maintenance costs and avoided future capital replacement through rehabilitation of the existing networks. Other benefits which have not been quantified include consumer surplus associated with customer willingness-to-pay in excess of the tariff, reduced maintenance costs associated with better scheduling and inventory management, savings in system expansion costs through better utilization of capacity. savings in operational manpower, improved operator training, and improved reliability through better operating procedures. It is also anticipated that the management contracts for the operation of the wholesale electricity market and the transmission and dispatch facilities will improve the financial viability of all power sector entities, both through improved collections and more efficient operating practices. The target beneficiaries of the project are the Georgian consumers of electricity, including residential, industrial and commercial sectors. 4. INSTITUTIONAL AND IMPLEMENTATION ARRANGEMENTS: Implementation period: Four and a half years. Executing agencies: Electrodispatcherizatsia and Electrogadatsema Lending and On-Lending Arrangements: The Borrower for the IDA credit will be Georgia, represented by the Ministry of Finance. The amount of credit would be approximately US$ 27.4 million equivalent, on standard IDA terms of 40 years, including 10 years grace. An annual service charge of 0.75 percent would be applied on balances outstanding. Commitment fees would'be charged on undisbursed balances in accordance with the terms set annually by the Association, but would not exceed 0.5 percent. The Government would onlend an amount equivalent to US$ 15 million to Electrodispatcherizatsia and US$ 12.4 million to Electrogadatsema for a period of 20 years, including 5 years grace. Interest on outstanding balances would be calculated at a rate equivalent to the semi-annual IBRD Variable Rate on currency pool loans. The Association would advise the Government of the applicable rate for each period. Commitment fees incurred by the Government on undisbursed balances would be passed on to the subsidiary borrowers. The signing of the Subsidiary Loan Agreements, satisfactory to IDA, would be a condition of Credit effectiveness. Electrogadatsema and Electrodispatcherizatsia would enter into Project Agreements with the Association, which would detail their obligations under the project. 9 KFW would provide a loan to the Government of DM 25 million (approximately US$ 11.4 million equivalent). Terms for the KFW loan would match those for the IDA credit (0.75 percent interest, 10 years grace, 40 years repayment). Proceeds of the KFW loan would be on-lent to Electrogadatsema for 20 years, including 5 years grace, at an interest rate of 4.0%. Project Management. Electrogadatsema and Electrodispatcherizatsia will be responsible for implementation of the of the project, except that the Ministry of Fuel and Energy will be responsible for the Management Contract. A Project Service Organization (PSO) was established as an agency under public law by the Ministry of Finance and the Ministry of Fuel and Energy. The PSO will have overall responsibility for coordinating and managing all project preparation and implementation activities on a day-to-day basis. Electrogadatsema and Electrodispatcherizatsia will be members of the Supervisory Council of the PSO, and will participate in the selection of its General Director. Management and oversight of the PSO will be established in a manner adequate to allow the Borrower, the project entities, and the Management Contractor to carry out their responsibilities under the project agreements in a timely and efficient manner. The PSO will be assisted by a qualified international procurement and project management consultant, who will be either part of the management Contractor's team or hired by them. A Project Implementation Plan (PIP), satisfactory to the Association, has been prepared and submitted by the PSO. The operating costs of the PSO will be co-financed by the IDA Credit, excluding any taxes and social charges. Procurement (see Annex 6). The general strategy for project implementation is to procure the equipment, goods and services in larger packages, making contractors responsible for supply and installation of equipment. This would minimize coordination needs on part of the implementing agencies and simplify project implementation, mitigating the risk of project delays. Equipment financed by the IDA Credit will be organized into four supply&install contracts -- metering, dispatch (SCADA/EMS), telecommunications, and management information systems -- and procured through the ICB procedures. The dispatch/telecommunications contracts will require pre- qualification of bidders. The Management Contract for Electrogadatsema and Electrodispatcherizatsia, also co- financed by the IDA Credit, will be procured internationally also through the ICB procedure. The consultants for engineering, procurement and project management, and for preparation of transmission system environmental action plan, will be selected through the QCBS process, except for a small consulting contract for preparation of PSO's Operating Manual and project accounting software upgrade which will be sole-sourced from the consultant who installed the previous version of the software (see Annex 6). Firm to perform audit will be selected through the least-cost selection process. Advisors for debt restructuring will be contracted through the procedure for selection of individual consultants. Financial Management System. Overall Status and Accountability: The financial management system satisfies Bank's minimum financial management requirements. Even though the existing project accounting software meets the Bank's minimum requirements, additional actions are needed to improve the cost-effectiveness of the system and make it better suited for producing Project Management Reports (PMRs). It was, therefore, agreed at negotiations that a new accounting software will be installed by July 1, 2001, and that the PSO should be able to prepare quarterly PMRs by September 30, 2001 (see the time-based Action Plan in Annex 6). The necessary improvements in the financial management systems of project beneficiaries -- Electrogadatsema and Electrodispatcherizatsia -- is included in the project. Reporting: Quarterly PMRs from the PSO are a part of the progress report, and are to be submitted to the Bank within 45 days after the end of each quarter. The PMRs will follow the accrual model format (See Annex 6). Audited annual Entity Financial Statements (Income Statement, Fund Flow Statement, and Balance Sheet) of EG, ED, and WEM, and the Project Financial Statements with accompanying audit reports, shall be submitted to the Bank within six months of the end of the fiscal year. Audit Arrangements: Audits will be carried out annually by independent external auditors acceptable to the Bank and in accordance with international standards of auditing (ISA). The intention is for the beneficiary companies to 10 pay for annual audits, but the audit for the first two years cannot be self-financed and funds have been allocated for this from the Credit. The auditor should be selected by October 2001 and the selection will follow Bank procurement guidelines. The scope of the annual audits will include the project financial statements (including SA and SOE), and the company financial statements for the two beneficiaries, EG and ED. Audited financial statements shall be submitted to the Bank within six months after the end of the fiscal year. The auditors should be engaged for at least three years. If in the future the auditor is to be changed, the new auditor shall be in place by October of the year to be audited. Disbursement. Disbursements will follow traditional Bank disbursement procedures and will be made against eligible expenditures. The Bank will make disbursements on the basis of Statement of Expenditures for (a) contracts for goods and equipment below US$100,000, (b) consulting services contracts with firms below US$100,000 and with individuals below US$50,000, and for (c) incremental operating costs. Supporting SOE documentation will be maintained by the PSO and made available for review by auditors and Bank missions. Other disbursement details are given in Annex 6. Special Accounts for IDA Credit. To facilitate the Credit disbursenment, the PSO will open two Special Accounts at a bank acceptable to IDA. It was agreed that the financial institution holding the Special Accounts would be acceptable to the Association provided that adequate arrangements were in place to ensure that the Project Service Organization could (a) execute both foreign exchange and local currency transactions; (b) arrange to open letters of credit; (c) handle a large number of transactions promptly; and (d) receive prompt and detailed monthly statements of transactions and balances. According to the Association's standard requirements, it would be necessary for the Association to receive assurances that amounts deposited in the Special Accounts would not be set off or otherwise seized or attached to satisfy amounts due to creditors of the Borrower or the subsidiary Borrowers. The Special Accounts will be drawn upon to meet payments to contractors, suppliers and consultants under the project. The PSO will maintain and operate these accounts under terms and conditions acceptable to the Bank. The Bank, upon request, will make an authorized allocation of US$0.4 million equivalent for each Special Account. Initially and until total disbursements reach US$2.6 million equivalent for each company, the allocation will be limited to US$0.2 million for both accounts. Replenishment applications will be submitted on a monthly basis, or when about 20 percent of the initial deposit has been utilized, whichever comes first. Replenishment applications will be supported by appropriate documentation, e.g., bank statements for the Special Accounts and a reconciliation of the bank statements against Bank records. Escrow Accounts for Local Financing (Project Accounts). To ensure that adequate funds are available to meet the project's needs for counterpart financing, Electrogadatsemia and Electrodispatcherizatsia will open special escrow accounts (Project Accounts), with an initial deposits of S150, 000 and $50,000 by Electrogadatsema and Electrodispatcherizatsia respectively, as a condition of Credit effectiveness.The enterprises will be required to maintain deposits in the escrow accounts sufficient to meet local cost financing for the coming three months. Project Preparation Facility. The Govemment of Georgia has financed preparatory activities: consulting services for the PSO, debt restructuring, and incremental operating costs for project management, through the Project Preparation Facility (PPF). Supervision, Monitoring and Reporting. The Bank's supervision will concern (i) physical implementation of the investment components of the project and associated project management issues (including procurement and financial management); and (ii) performance of the management contracts and associated sectoral issues. Project supervision will require intensive interaction with the beneficiary organizations, the Government, and the donors. The supervision effort will need to be especially intensive during the first two years of project implementation, which will be procurement-intensive and are therefore critical for successful implementation. This period will also be most important for the success of the management contracts. It is estimated that about 30 staff-weeks of Bank's supervision effort will be needed during the first two years, and 15 staff-weeks thereafter. 11 The PSO will monitor progress against agreed performance indicators specified in Annex 1. The PSO will provide, on a quarterly basis, consolidated reports on project implementation progress in the PMR format. Draft annual action programs for the upcoming year will be included with the December reports for the Bank's review and comment. The GoG and IDA will conduct joint reviews annually during supervision missions. The PSO will prepare a detailed mid-term report to serve as the basis for a project mid-term review, to be undertaken not later than June 30, 2003. The timing of the review will be agreed at negotiations. In addition to the topics covered under the quarterly reports, the mid-term review will include a review of the economic viability of the project based on actual costs and benefits achieved to-date, as well as an in-depth review of the management contracts and their performance. Based on the outcome of the mid-term review, measures will be taken to ensure efficient completion of the project. The PSO, with guidance from the Bank, will also prepare and submit an Implementation Completion Report (ICR) to the IDA within six months of the closing date of the IDA Credit. Included in the ICR will be an assessment of the execution of the project, its costs and benefits, the performance of the Borrower, SE, EG, the Bank and other agencies involved in the project regarding their respective obligations and accomplishments, and lessons learned. After completion of the project, Electrogadatsema and Electrodispatcherizatsia will submit to IDA a plan for operating the project. D. PROJECT RATIONALE 1. PROJECT ALTERNATIVES CONSIDERED AND REASONS FOR REJECTION: There are no technical altematives to the installation of meters, dispatch and communication systems to support trading of electricity and reliable and efficient operation of the power system. The proposed technical solutions are based on well established and proven standard technical concepts and technologies, which are being applied worldwide. There is also no alternative to a reliable transmission network which integrates power plants and consumers into a unified national power system and interconnects it with neighboring systems. Georgian transmission network, built during the Soviet times and over-designed for the current level of consumption in the country, has some structural deficiencies, particularly when operated in isolation from neighboring networks, as has been the case during the last decade. An outage of the 500-kV line, which runs from Russia through Georgia to Azerbaijan, leads to a disintegration of the system into several isolated parts and likely country-wide blackouts under some load conditions. International interconnections are inadequate, particularly with Turkey and, to a lesser degree, Armenia. The 220-kV interconnection with Russia, passing through Abkhazia, is inoperable, and the 500-kV line, crossing the Caucasus mountains, is subject to frequent outages during the winter time. Deterioration of the existing equipment -- the result of maintenance backlogs, theft, and substandard operating conditions (overloads, low voltages, low frequency) over the last ten or more years - is wide-spread and affected even the most critical equipment, such as 500-kV and 220-kV lines and substations. Full rehabilitation of the network would need a budget several times larger than available for the project. The project includes rehabilitation of a single most important 500-kV substation at Zestafoni, which is critical for overall system reliability and integrity. Transmission system is owned and operated by Electrogadatsema, a state-owned company. System dispatch is performed by another state-owned company, Electrodispatcherizatsia. The wholesale electricity market is administered by organization with the same name -- the Wholesale Electricity Market (WEM). The WEM is governed by the Management Board which includes members from distribution, generation, transmission and dispatch companies, a representative of direct consumers, and non-voting members from the Ministries of Fuel and Energy, Economy, and Finance. The WEM is at this stage entrusted with financial settlements and management of funds in the wholesale market, but is expected to assume responsibilities involving administration 12 of trading arrangements, as the market evolves toward more liberalized competitive structure. At this time, the Board is still dominated by publicly owned companies. Improving financial performance of the sector is the overriding objective of the ongoing market reforms and privatization, and is driving the design of this project as well. The completed and ongoing privatization of distribution and generation companies should lead to significant financial improvements, but need to be complemented by better management and improved efficiency of the transmission, dispatch and market administration segments, which are critical for stemming the financial leakages in the system, for it efficient operation and a player in the regional markets. Involvement of private sector in these segments is the most credible way of achieving this goal. Privatization of transmission and dispatch, as well as of market operations, could be conceptually done in several ways, ranging from privatization of assets, through long-term concession to privatization of management only. Privatization or even long term concession of transmission and dispatch is, however, neither legally nor politically feasible at this time in Georgia. There are very few countries in which transmission systems are sold or concessioned to foreigners (as the case would likely be in Georgia), making it difficult to argue that such practice is common and free of supply security and system development concerns. There are also constitutional limits on foreign ownership of the transmission system in Georgia. Furthermore, the optimal point of privatizing the transmission system would be after most of distribution and generation assets are privatized (the process which is still under way), financial performance of the sector improved, and regional electricity systems operationally interconnected. Therefore, the only feasible option at this stage to involve private sector in operation of transmission and dispatch systems and administration of the market is through management contracts. The Government endorsed this strategy by a Presidential Decree issued in November 1999. Tendering process has already started and preparation of Requests for Proposals (RfP) for both contracts is under way. Technical proposals have been evaluated, and signing the contracts will be a condition of Credit effectiveness. The management contracts will be maintained throughout project implementation. 13 2. MAJOR RELATED PROJECTS FINANCED BY THE BANK AND/OR OTHER DEVELOPMENT AGENCIES (COMPLETED, ONGOING AND PLANNED). Sector Issues Project Latest Supervision (PSR Ratings) (Bank-financed projects only) Implementati Development Bank-financed on Progress Objective w) (DO) Unreliable electricity supply due to Power Rehabilitation Project: S S insufficient generation capacity (especially in rehabilitation of three power winter); poor corporate governance and plants -- one thermal financial performance (Tbilsresi) and two hydro (Khrami II and Lajanuri) (cofinanced with KfW, OECF) (1997-2000) Poor financial performance; strengthening SAC 1, II and III, SATAC I S S institutional organization and regulatory and II, SRS (1996-2000) framework; initiation of privatization of electricity companies Poor financial performance and lack of funds ESAC S S to operate, maintain and invest in assets; corruption; weak management at sector and enterprise level; implementation of regulatory framework; privatization of electricity distribution and generation companies Other development agencies Unreliable electricity supply due to insufficient Rehabilitation of Tbilsresi generation capacity (especially in winter) and thermal plant (KfW, EBRD) deteriorated network (1996-1997) Rehabilitation of transmission network (KfW) (1996-1997) Rehabilitation of the Vartsikhe hydro plant (KfW) (1998 -) Rehabilitation of the Inguri plant (EBRD) (1998 -) Strengthening institutional organization and USAID (1996-) regulatory framework IP/DO Ratings: HS (Highly Satisfactory), S (Satisfactory), U (Unsatisfactory), HU (Highly Unsatisfactory) 14 3. LESSONS LEARNED AND REFLECTED IN THE PROJECT DESIGN: The Bank by now has accumulated considerable experience in implementation of projects and understanding of the problems in the power sector in Georgia and in other countries in the region. The most important lesson, shared by the Government of Georgia, is that improving the governance and financial performance of the power companies and the sector requires involvement of strategic private investors and establishment of independent de- politicized regulation. The first IDA financed project in the sector (the Power Rehabilitation Project) helped restructure and de-monopolize the sector, develop basic legal framework for regulation, and establish an independent regulatory commission. It succeeded in initiating the structural and regulatory reforms needed for privatization, as well as in physical rehabilitation of important generation assets. The project was accompanied by adjustment operations (the Second Structural Adjustment Credit and the Energy Sector Adjustment Credit (ESAC)), which aimed at further strengthening institutional and regulatory framework and financial position of the sector, leading to privatization of significant parts of generation and distribution segments of the sector, improved regulation, greater transparency in financial management, and (to a lesser extent) ensuring better compensatory social protection measures. The adjustment operations also proved to be a successful vehicle for coordination with donors and with the IMF. These and other lessons learned have been incorporated in the design of this project through decisions to: * contract management of beneficiary enterprises to the private sector; * ask for up-front actions on policy and institutional issues, including continuing progress in privatization of distribution companies; * escrow local financing funds; e leverage funds and coordinate policies with other donors; * leverage project conditionalities through other Bank operations; and * get all important stakeholders on board. 4. INDICATIONS OF BORROWER COMMITMENT AND OWNERSHIP: Borrower's commitment has been demonstrated by the following actions: - conducting a competitive selection of international firms to manage transmission and dispatch companies and the Wholesale Electricity Market; * successful privatization of some major distribution and generation companies, and continuing active effort to privatize the remaining distribution and generation assets; * continued commitment to sector reforms, demonstrated through establishment of the Wholesale Electricity Market in charge of settlement and management of funds in the wholesale market, noninterference in the work of the energy regulatory commission; * separation of historic debts and preparation of sector debt restructuring plan; * completion of project preparation (feasibility studies, establishment of PSO); and * increasing transmission and dispatch tariffs. 5. VALUE ADDED OF BANK SUPPORT IN THIS PROJECT: The project is critical to the success of the ongoing reform program, which the Bank has been supporting since mid-1990s. Without the Bank, the project is very unlikely to be implemented given the role played by the Bank in coordination of donors (and the IMF) in the sector, the influence of the Bank over difficult sector reforms (particularly those which touch vested interests), and the lack of alternative external financing available for public sector projects. 15 E. SUMMARY PROJECT ANALYSIS (Detailed assessments are in the project file, see Annex 8) 1. ECONOMIC (SEE ANNEX 4): *Cost benefit NPV=US$27.8 million; ERR = 23.4 % (see Annex 4) O Cost effectiveness O Other (specify) Quantifiable benefits of the project include: (i) increased reliability of the transmission system and reductions in failures and forced outages as a result of equipment upgrades and better system control; (ii) reduced transmission losses; (iii) avoided operations and maintenance costs for the telecommunications system; (iv) increased value of output from hydroelectric plants, with consequent reductions in load shedding and/or savings in high cost thermal generation; and (v) reduced system maintenance costs and avoided future capital replacement through rehabilitation of the existing networks. The present value of total benefits, at a discount rate of 12 percent, is US$60.3 million, while present value costs total US$32.5 million, yielding a Net Present Value of US$27.8 million. The project EIRR is a 23.4 percent, when reliability, loss reduction and output benefits are valued at the current tariff. A more optimistic valuation of these benefits (i.e. at a weighted average of tariff and cost of self-generation) would yield a significantly higher EIRR of 55.3 percent and a Net Present Value of US$124 million. The switching value analysis indicates that the project can maintain a 12 percent EIRR with an 85 percent increase in capital costs or a 46 percent reduction in benefits. Details of the cost-benefit calculations and sensitivity analyses are given in Annex 4. Apart from the benefits noted above, there are other potentially significant benefits that are more difficult to measure, and as such have not been quantified. These include: (i) reduced maintenance costs associated with better scheduling and inventory management, (ii) savings in system expansion costs through better utilization of capacity, (iii) savings in operational manpower, (iv) improved operator training, and (v) improved reliability through better operating procedures. It is also anticipated that the management contracts for the operation of the wholesale electricity market and the transmission and dispatch facilities will improve the financial viability of all power sector entities, both through improved collections and more efficient operating practices, yielding to potentially major economic benefits. 2. FINANCIAL (SEE ANNEX 4 AND ANNEX 5): NPV=US$ million; FRR = % (see Annex 4) Under the Georgian Electricity Law, the tariffs of the beneficiary companies are fixed to allow recovery of prudently incurred operating costs, including interest expenses and a return on investment. Hence, the FIRR of the project to the implementing agencies will be limited to the allowable return on investment. Residual financial benefits, such as O&M savings, reduced losses, etc., will flow to customers in the form of lower electricity tariffs. (a) Current Financial Status and Performance of Electrogadatsema and Electrodispatcherizatsia: Both Electrogadatsema (EG) and Electrodispatcherizatsia (ED) are newly formed enterprises. The former was established by separating the HV transmission assets from Sakenergo in mid-1998. The latter was established in February of 2001 as a separate enterprise to own and operate the dispatch assets of Sakenergo. Most historic data for the two companies is merged with the historic accounts of Sakenergo, which, in addition to transmission and dispatch, served as the wholesale buyer and re-seller of electricity. It is impossible to extract from these accounts a reliable picture of the past performnance of the transmission and dispatch functions. Hence, the analysis of 16 current financial performance is based on the very short operating history of EG, and on estimates (based on a detailed analysis of Sakenergo's asset and operating accounts) of the financial status and performance of ED. Electrogadatsema: The balance sheet position of EG as of December 31, 1999 indicates a relatively strong financial base. The current ratio was 2.4, and net working capital was GEL 121 million. Net cash generation during the year was GEL 1.4 million, and the debt service ratio (taking into account planned borrowings) was 3.1. Electrogadatsema Balance Sheet as of December 31, 1999 (million GEL) Assets Equity and Liabilities Fixed Assets (net) 412.0 Equity 531.3 Other Long-Term Assets 0.5 Long-term Liabilities 1.8 Current Assets 207.3 Current Liabilities 86.7 Total Assets 619.8 Total Equity & Liabilities 619.8 The income statement, however, when restated to IAS, showed a loss of GEL 19.4 million. While the company's operating margin was a positive 33 percent at current tariffs, the high level of uncollectible accounts (from Abkhazia and nonpaying distribution companies) resulted in the net loss on operations. Electrogadatsema - Income Statement Period ending December 31, 1999 (million GEL) Gross Revenues 81.3 Less Nonpayments (43.5) Net Operating Revenues 37.9 Cost of Sales (54.1) Net Profit from Operations (16.3) Profit after Tax (19.4) Net Cash Flow 1.4 Since transmission tariffs are calculated by dividing total revenue requirements by total sales, uncollectible accounts will continue to adversely affect the company's profitability. There are three mechanisms for addressing the problem: (i) the regulator can reflect the losses due to nonpayments in calculating the transmission tariff; (ii) the government can compensate the transmission company (and other sector enterprises) for the cost of supply to Abkhazia; (iii) the market can enforce rigid payment discipline so that sales figures more accurately reflect the number of kWh for which payment is received. At present, the first option contravenes the Electricity Law. The second and third options are being tested as a means of improving the profitability of power sector enterprises, and should be reinforced by the proposed management contracts for operation of the WEM and operation of the transmission and dispatch facilities (see (b) below). Notwithstanding the poor profits performance, however, the company generates significant positive cash flow as a result of its large asset base and consequent high depreciation charges, and its relatively small debt service obligations. Since its costs are largely fixed, profit performance is expected in improve in direct relation to load 17 growth. Thus, while tariffs have declined slightly in 2000 (from an average of 1.32 tetri/kWh to 1.19 tetri including VAT), current tariff levels appear to be adequate to provide for financial viability. Electrodispatcherizatsia: As noted above, formal establishment of ED as an enterprise separate from Sakenergo took place in February, 2000. The Government transferred approximately GEL 4.895 million of net fixed assets to the new company, as well as 0.2 million of inventories. Most of the remaining assets and liabilities of Sakenergo were transferred to a shell company (Sakenergo 2000) for later liquidation, although some were transferred to EG. The initial balance sheet of the new dispatch company is shown below. Electrodispatcherizatsia Estimated Balance Sheet as of February 1, 2000 (million GEL) Assets Equity and Liabilities Fixed Assets (net) 4.895 Equity 5.095 Other Long-Term Assets 0 Long-term Liabilities 0 Current Assets 0.200 Current Liabilities 0 Total Assets 5.095 Total Equity & Liabilities 5.095 Income and expenditures of the new company have been projected based on prior years' expenses of Sakenergo related to dispatch operations. Approximately 600 employees were to be transferred to the new company, including selected staff in the regional departments. In addition, to reflect the change in assets and scope of operations, GNERC proposed to reduce the dispatch tariff from 0.35 tetrilkWh (including VAT) to 0.2 tetri. This figure was later adjusted to 0.28 tetri/kWh. The projected income statement for the dispatch company for the year 2000, based on these assumptions, is shown below. Electrodispatcherizatsia - Projected Income Statement Period ending December 31, 2000 (million GEL) Gross Revenues 18.1 Less Nonpayments (8.0) Net Operating Revenues 10.1 Cost of Sales (12.1) Net Profit from Operations (2.0) Profit after Tax (2.5) Net Cash Flow (1.0) As with EG, nonpayments represent a major part of dispatch company's losses. However, because EG incurs substantial depreciation charges on its large asset base, the nonpayments have less impact on cash flow. At the revised 0.28 tetri tariff, the dispatch company would be able to achieve financial viability over the medium term, and meet its financial obligations under the project. The main concern is the negative cash flow, which can only be met by increasing the indebtedness - and hence the debt service costs - of the company. However, given that the operating costs of the new enterprise are only estimated based on poor historic data, the current tariff is considered to be satisfactory until such time as the actual costs of operations are known. (b) Projected Financial Performance of Electrogadatsema and Electrodispatcherizatsia: 18 Electrogadatsema: The financial outlook for EG at the existing tariff (adjusted for inflation) is satisfactory from the perspective of cash flow and debt service. Profitability and return on assets, however, remain negative until 2005. This is largely attributable to relatively conservative assumptions regarding future improvements in collections. If collections increase more rapidly, or if nonpayments are compensated in the tariff, profitability would be restored more quickly. With this in mind, the Association has proposed, and the government has agreed to appoint a qualified internationalfirm under a management contract to manage the operations of the transmission company. Part of the associated cost would be financed under the proposed project. The issue of long-term required return on fixed assets is complicated by the fact that the capacity of the transmission system considerably exceeds current and projected requirements. GNERC has taken the position that EG should earn an adequate rate of return only on that portion of revalued assets that are in service. The Association has concurred with this position, on the grounds that allowing a return on unutilized assets would merely inflate the cash position of the company, at the cost of high transmission tariffs. However, this issue will continue to be a part of the dialogue with the government, and will be reviewed as demand increases. The table below summarizes the highlights of financial projections through the project implementation period and the first two years of debt service. The financial projections also show that the company is able to finance all local costs of the project, as well as a significant amount of capitalized maintenance or normal asset replacement out of cash flow. Detailed pro forma financial statements are included in Annex 5, Tables 5.1 - 5.3 Electrogadatsema - Highlights of Financial Projections _ 2000 2001 2002 2003 2004 2005 2006 2007 Tariff (tetri/kWh) 0.99 1.07 1.11 1.15 1.20 1.25 1.30 1.35 Collections Rate 55.8% 58.6% 62.1% 69.3% 76.7% 84.2% 88.0% 88.1% Net Profits (19.9) (19.3) (17.6) (12.0) (4.0) 4.0 8.5 9.8 Cash Flow 54.8 45.1 51.3 59.6 66.8 62.3 67.0 71.2 Net Fixed Assets 408.1 417.8 4189 425.4 420.5 403.2 383.6 361.4 Long Term Debt 5.1 16.1 31.2 52.3 62.6 61.1 57.0 53.7 Incremental Financing Requirements (2.0) - - - - - - - Gross Capital Investment 24.6 31.0 37.6 46.1 37.6 28.5 30.1 31.7 Debt Service Ratio 3.66 4.44 5.27 6.79 8.61 10.32 11.52 12.23 Retum on NRFA -4.9% 4.6% -4.2% -2.8% -0.9% 1.0% 2.2% 2.7% It should be noted that in negotiating the privatization of selected generation and distribution assets, the government is discussing the possible inclusion of part or all of EG's 35 kV network (including some dedicated 1 10 kV lines) in the assets transferred to the new owners. The total gross value of EG's 35 kV network is approximately 306 million GEL, and accumulated depreciation is approximately 196 million. A sensitivity analysis, however, indicated that the loss of these assets would not have a material effect on the conclusions regarding the financial viability of EG at current tariffs. Electrodispatcherizatsia: The financial prognosis for ED at the current tariff is also satisfactory, both in terms of profitability and cash flow, with the proviso that upward adjustments may be needed to counter the projected negative cash flows over the first three years of operation. If operating costs equal or exceed projections, shortfalls in cash will lead to the accumulation of additional debts, which will in turn lead to ongoing losses and cash flow deficits. The table below presents the highlights of the dispatch company's projected financial 19 performance, assuming an increase in tariffs to 0.28 tetri/kWh (.23 tetri net of VAT) in the latter half of 2000, and increases with inflation thereafter. Detailed financial projections are given in Annex 5, Tables 5.4 - 5.6. Electrodispatcherizatsia - Highlights of Financial Projections 2000 2001 2002 2003 2004 2005 2006 2007 Tariff (tetri/kWh) 0.20 0.25 0.26 0.27 0.28 0.29 0.30 0.31 Collections Rate 50.4% 55.8% 58.2% 61.5% 69.0% 76.6% 84.2% 88.0% Net Profits (2.5) (0.4) (0.1) 0.7 1.8 3.6 4.9 5.4 Cash Flow (1.0) (1.5) (0.5) 0.4 1.9 4.3 5.0 5.7 Net Fixed Assets 4.9 7.1 12.8 24.6 35.1 39.2 40.5 42.0 Long Term Debt - 1.7 6.7 18.1 27.5 30.2 26.7 25.1 Incremental Financing Requirements 1.8 0.9 0.1 (1.1) (1.7) - - Gross Capital Investment 2.3 6.1 12.5 11.4 4.9 2.2 2.4 Debt Service Ratio (0.55) 0.02 0.24 0.77 1.35 1.91 2.28 2.48 Retum on NRFA -541% -86% -1% 3% 5% 9% 12% 13% The required tariffs for the two enterprises reflect in part the possible inefficiencies associated with maintaining separate regional facilities and staff for the transmission and dispatch companies, as well as the expected lag in achieving acceptable levels of collections, and the limited cash flow of the company. However, if the operations of the transmission and dispatch companies were merged, it might be possible to reduce overall operating costs, particularly in the regional departments. In addition, the surplus cash flow of the transmission company would be available to help finance some of the investment requirements of the dispatch operations. Financial projections indicate that a merged company would be able to avoid cash flow problems, and achieve positive returns by 2005 even in the absence of any efficiency gains. (see Annex 5, Table 5.7 for highlights of the consolidated operations). GNERC adopted tariffs satisfactory to IDA which should ensure the financial viability of ED and EG. It was further agreed that the Government would examine ways to increase efficiency of system operation, including, inter alia, merging EG and ED into a single company, to minimize the impact on tariffs caused by dispatch and transmission being operated by separate companies. In support of internal restructuring and enhancing the efficiency of the dispatch operations, the Government has also agreed to appoint a qualified utility under a management contract to manage the operations of the dispatch company. Part of the associated cost would be financed under the proposed project. (c) Wholesale Electricity Market (WE) During the first year of the wholesale electricity market (WEM) operations (July 1999-June 2000), 7009 GWh electricity was supplied to domestic customers. 63% of this power was supplied through WEM; the rest was delivered under direct contracts between generators and wholesale customers -- distribution companies and some larger consumers (Direct Customers). The amount of electricity contracted directly increased in 2000 in comparison with 1999. AES-Telasi is a major customer for direct contracts. In 1999, 67% of the power consumed by AES-Telasi was procured through direct contracts, while in 2000 the amount reached 80%. AES-Telasi was 20 also the largest consumer of electricity, with 44% of market share. Other distribution companies consume 35%, while the remaining 21% is consumed by Direct Customers, mainly industrial enterprises. According to the Market Rules, WEM should be reimbursed for the price difference between the weighted average generation tariff and the price obtained through direct contracts. Generation companies are paid 100% for electricity delivered under the direct contracts. To illustrate, in the first 6 months of 2000 AES-Telasi paid about Lari 42 million under the direct contracts, while payments to market amounted to 15 million laris. AES-Telasi is the largest supplier of cash to the wholesale market: 65-70% of the cash available to the market for generation companies come from AES-Telasi. About 25% is covered by other distribution companies and just 5% by the direct customers. The collections rate in WEM has been very poor. Collections from households were only 19% of billings in the second half of 1999, and 27% in the first half of 2000. Collections by WEM from AES-Telasi reached 60% in 2000 (of which almost 80% in cash), a significant increase from 38% in 1999. Collection from other distribution companies are only about 20%, and only half of it in cash, the rest are offsets. Direct customers pay on average, 22% but most of the payment is also done through offsets. Only 3-5% of the payments of direct customers are in cash. For political reasons, substantial amount of power is being supplied virtually for free to Abkhazia and South Osetia (12% of the billable electricity). During the July 1999-June 2000 period, about Lari 44 million worth of electricity was delivered to these regions, of which only about Lari 4 million was reimbursed to the WEM by the state trough offsets. To improve payment discipline and performance of the WEM, the Government agreed to appoint a qualifiedfirm to nmanage the operations of the WEM EBRD has agreed to contribute a grant of Euros 1,000,000 to assist in financing this contract. The balance will be paid by the WEM itself. As a non-profit association of market members, the WEM's only source of revenues to finance its share of the contract is the fees paid by the members. Because the expenses of the market operator have been relatively low to date, the fees imposed on members have represented only a tiny fraction of sales revenues (between 0.1 and 0.2 percent). Assuming that the cost of the management contract is allocated pro-rata among members based on total sales value, the average incremental fees would be 0.35 percent of revenues. While this represents a substantial percentage increase in fees, it remains an insignificant amount on a per kWh basis. At a maximum, the cost of the management contract would be 0.02 cents per kWh (0.04 tetri) and over the 5 year period would average 0.015 cents per kWh (0.035 tetri). In a best case scenario, this cost could be passed on to final customers in the form of tariff increases. In the worst case, where it must be absorbed by market members, it is expected that the appointment of a management contractor will lead to significant improvement in collections, and hence to improvements in the revenues transferred to market members. The avoided cost of nonpayments and payment delays should more than compensate the members for the cost of the contract. (d) Historic Sector Debts The power sector as a whole has amassed substantial debts over recent years, both in the form of inter-enterprises debts, and debts to suppliers, workers, the government, local and international financial institutions, and neighboring countries. As part of the restructuring and privatization process, the government has been reallocating this debt on a piecemeal basis. As part of the agreement to sell Telasi, for example, the government agreed to defer approximately GEL 130 million in payables to Sakenergo for 99-years. It is anticipated that additional write-offs/write-downs will have to be negotiated as other enterprises are privatized. At some point, many of these inter-enterprise debts will have to be written off. In addition, if buyers refuse to accept obligations 21 to other creditors, the government will have to find a mechanism for settling legitimate obligations, through direct budgetary interventions and/or through a surcharge on existing tariffs. Apart from these debts, there are substantial sector debts which were incurred on behalf of the power sector but do not appear on the balance sheets of any of the enterprises. Most of these debts relate to imports of electricity or to procurement of fuel for Tbilsresi. Annex 5, Table 5.8 lists the known outstanding debts of the sector - both allocated and unallocated - and their potential impact on tariffs. In consultation with the Association, the Government has adopted a Debt Restructuring Plan to provide for the orderly rescheduling and settlement of the outstanding obligations. A copy of the Plan, together with target dates and responsibilities, is attached in Annex 5, Table 5.9. The Plan incorporates the following major principles: the Government would prepare a strategy for addressing each of the debts, including renegotiation of repayment terms, and enter into negotiations with creditors in an attempt to bring annual repayment requirements to a manageable level; an initial surcharge would be added to the tariff at the time of the next tariff increase (June 2001), and earmarked for the settlement of sector debts. Once the initial outcome of negotiations with creditors became known, the surcharge would be adjusted to ensure that debt service requirements could be met; the surcharge would be collected by the Wholesale Electricity Market, sequestered in a separate account, and disbursed by the an independent settlements agent to creditors in accordance with the repayment schedule agreed between the creditors and the government. The Debt Restructuring Plan, including the specific targets agreed at negotiations, is a part of the Letter of Electricity Sector Policy (LESP). Satisfactory implementation of the LESP is a condition of effectiveness of the IDA Credit. (e) Financial Performance Criteria: The government and implementing agencies agreed to adhere to the following financial performance criteria: Pre-financing of local costs: To ensure that adequate funds are available to meet the project's needs for counterpart financing, the enterprises will be required to maintain on deposit in a commercial bank sufficient funds to meet local cost financing for the coming three months. Short-term Liquidity: To ensure that there is sufficient liquidity to meet current obligations, the enterprises will be required to maintain a ratio of current assets to current liabilities of not less than 1. 1. Debt Service Coverage: To ensure that the enterprises maintain creditworthiness, particularly in view of the substantial capital expenditures which will be required to rehabilitate and replace existing assets, EG and ED will be required to maintain a debt service coverage ratio of not less that 1.5 (projected net operating income divided by projected annual debt service requirements). 69 Financial Management and Auditing Both Electrogadatsema and Electrodispetcherizatsia are completing the conversion of their accounting systems to international standards. The companies have qualified accounting staff in place, all of whom have received training in international accounting practices. At present, understanding of management accounting is limited. However, training in this will be addressed as part of the management contracts. In addition, technical assistance will be provided under the credit to assist the companies in establishing and maintaining separate project accounts. 22 Under the Credit Agreement, the companies will be required to appoint qualified auditors to carry out audits of the companies' financial statements and project accounts to international standards, and submit to the Association audited financial statements not later than June 30 of the following year. Fiscal Impact: No Government funds will be required for the project, since local financing will be provided by the project beneficiaries. The Government will on-lend proceeds of the IDA Credit on terms much less concessionary than the terms of the Credit to the Government, which will have a positive fiscal impact. Similarly, the onlending terms for the KfW loan will have either neutral or a positive fiscal impact. Restructuring of the large power sector debt may have a major fiscal impact, which will be assessed as part of the debt restructuring exercise. 3. TECHNICAL: Unimpeded, reliable, and efficient transmission of electricity from power plants to the consumers is essential. This requires both the existence of adequate transmission lines and substations, and means to continuously plan, control, and monitor the complex system operation. It also requires metering of electricity flows with sufficient frequency and accuracy to settle numerous commercial transactions among trading parties, which become quite complex in a liberalized, competitive market. Given the nature of the physical processes involved, the system operation has to be centrally monitored and controlled in real time. This needs continuous collecting of information from geographically dispersed facilities (power plants, substations and lines) and transmission of this information to the central dispatch center, and vice versa -- communication of dispatch control actions (either automated or executed by personnel manning the facilities) to locations where the actions are to be taken. Therefore, a modern power network includes an elaborate system of data acquisition and metering devices, data transmission and communication lines, computers and software, physically and functionally integrated to ensure continuously secure and reliable operation of the system. The transmission network in Georgia, with its associated metering, dispatch and communications facilities, suffers from years of neglect, maintenance backlogs, and lack of investment in upgrades and new equipment. No transmission lines and substations were constructed after 1990. Only 7 out of 25 220-, 330-, and 500-kV substations have been in operation for less than 20 years, and 8 of them exceeded 30 years. The existing dispatch system, with it SCADA equipment, was installed in the 1980s. However, it is based on old Soviet technology, which is practically impossible to maintain and expand due to a number of reasons -- functional and technical limitations, lack of spare parts, technological obsolescence and incompatibility with modern equipment. The SCADA included 34 facilities -- power plants and substations -- from which information was collected. The system as designed is deficient: not all information is acquired (e.g., equipment alarms, transformer tap-changer positions, energy counter values), transmission speed is low, there is no capability for remote control. Furthermore, a number of the 34 remote terminal units (RTUs) are not operational and dispatchers rely on telephones -- also not very reliable -- to update themselves on the status of the system. The telecommunications network is based on power line carriers (PLCs), radio links, some communication cables, and leased telephone lines. About 50% of the PLCs and about 60% of the radio network is out of operation. Metering of electricity is done by electromechanical meters, with no remote reading capabilities, nor the capability to support time-of-day tariffs required for a pool-based trading arrangements. Furthermore, the metering has been designed for a vertically integrated system operated by a single company and is ill-suited for settling transactions in a restructured system with many market participants. The proposed project aims at repairing, rehabilitating, and upgrading the metering, dispatch and communications infrastructure and selected transmission facilities, which would improve system reliability and efficiency and enable better integration with the neighboring systems. The proposed technical solutions for the metering, control and communications are based on standard concepts and proven technologies, accepted and applied worldwide. 23 The solutions should satisfy current and short-to-medium term future requirements, and is open to functional and physical expansion to meet the needs further in the future. Transmission substations are selected for rehabilitation on the basis of their importance for system operation and the level of disrepair. The new transmission equipment to be installed will also be based on standard and well proven technologies. Cost estimates are based on the technical feasibility study conducted by an international consultants with broad experience in this type of projects. The estimates are consistent with similar projects in Georgia (earlier transmission rehabilitation projects financed by KfW) and the region. Physical contingencies are at 10%. Price contingencies for locally procured goods and works are based on the IMF/World Bank projections for Georgia, and for imported equipment on World Bank projections for the international manufacturers unit values indices. 4. INSTITUTIONAL: 4.1 Executing agencies: The executive agencies for the investment part of the project will be Electrodispatcherizatsia and Electrogadatsema, two state-owned enterprises responsible for dispatch and transmission, respectively. Ministry of Fuel and Energy will be responsible for administering the management contracts for these two companies. Electrodispatcherizatsia was created recently by separating dispatch functions from Sakenergo, former dispatch- and-trading enterprise. Electrogadatsema is in charge of the transmission system, and is responsible for investment, maintenance and operation of the network, with a large and excessive labor force exceeding 3600. In daily operation of the network, its personnel is subordinated to system dispatchers in Electrodispatcherizatsia, from whom it receives orders to perform switching operations in the network, and whom it informs on any outages of equipment affecting operation of the system. Planned network outages, due to maintenance requirements, are also coordinated with Electrodispatcherizatsia. It is important that both Electrodispatcherizatsia and Electrogadatsema acquire the necessary managerial and technical skills and adopt appropriate internal organization and level of staffing, to be effective in their new roles focused on technical operation of the system (as opposed to having trading functions), providing open access to trading parties, and facilitating market operation. It is also important that both of them become resistant to pressures to ration electricity or impose trading barriers according to the political and other special interest of the various groups and individuals. Although these two companies do not have a formal role in deciding to whom to supply electricity or whom to disconnect (these decisions should be made by the WEM, based on payment records), in practice their role is vital in facilitating implementation of such decisions. Both organizations are essential for reducing commercial and technical losses: Electrogadatsema by preventing theft through metering and illegal lines and properly maintaining equipment, and Electrodispatcherizatsia by optimizing network's operating configuration. Therefore, operating behavior and performance of Electrodispatcherizatsia and Electrogadatsema are crucial to improving collection and financial flows in the wholesale electricity market. There is a lot to be done to optimize internal organizations and work force of the two companies and improve their operational and financial management. Putting Electrodispatcherizatsia and Electrogadatsema under a management contract with a competent and internationally experienced firm, and with appropriate contractual incentives, aims to achieve these objectives. 4.2 Project management: Neither Electrodispatcherizatsia nor Electrogadatsema themselves have experience with IDA-financed projects, and experience with international projects in general is rather limited. Therefore, they set up a joint Project Service Organization (PSO) to manage preparation and implementation of the project on a day-to-day basis, staffed with Georgian professionals with experience in implementing other internationally financed projects in Georgia, including IDA-financed power sector projects. In addition, the management contract will include 24 implementation of the project as an area of responsibility for the international management contractor. This will include supervision of project implementation (including procurement, financial management, ensuring proper quality controls) and provision of adequate project financing. During project implementation, the PSO will report to the international management contractor, who will have full authority over the PSO (its staffing, terms of reference, etc.). The management contractor will be responsible to ensure that the PSO is properly assisted by additional international specialists, experienced in engineering design, international procurement and contract management. Project accounting procedures will be designed to serve the requirements for both traditional and PMR-based disbursement, although it is envisaged that the project will use only the Bank's traditional disbursement procedures. The accounting systems of the two credit beneficiaries will be reviewed during project appraisal, when formal financial assessment will be conducted, to ensure that the beneficiaries and the PSO fulfill the necessary fiduciary requirements. The Ministry of Fuel and Energy will handle the approval of disbursement withdrawal applications and the administration of invoices from the management contractors against the management contract. The PSO will handle all the bookkeeping of the payments for management contracts. This would allow project accounting to encompass the whole project. 4.3 Procurement issues: Procurement of goods and equipment will be organized into few larger supply-and-install procurement packages. This is a demanding strategy in terms of preparation of bidding documents, but should simplify implementation of the project, once procurement is completed. An international consultant will be hired through international competitive selection to help with engineering design, procurement and project management. Management contracts will also be awarded through international competition. Some spare parts and replacement materials for the existing SCADA and telecommunications equipment will have to be procured from the original suppliers through direct contracting. 4.4 Financial management issues: The Financial Management Review: The financial management review for the Electricity Market Support Project in Georgia was carried out in February 10 - 20, 2000, and updated in early April 2001 to reflect the actions taken since the initial review. These actions included establishing the PSO, adopting terms of reference for its staff, hiring competent personnel (including project accountant), and documented its accounting and internal control procedures in an Operating Manual. As result, the Bank's minimum financial management requirements have been fulfilled. Financial Management Risk: Financial management risks in Georgia are considered high in general. To bring the financial management risk of the project to acceptable level, implementation of the following measures have been agreed upon: a competent, international management contractor will be hired at the start of the project to manage project beneficiary companies during implementation of the project; experienced and qualified staff at the Project Service Organization have been hired -- and will be maintained throughout project implementation -- with significant experience in managing international projects, including IDA-financed ones; an international financial consultant will be hired to review and strengthen -- if necessary -- accounting and internal control procedures and routines to be documented in an operating manual, and to upgrade the project accounting software; and an international auditor will be hired to audit project accounts and financial statements of the beneficiary organizations. 25 5. ENVIRONMENTAL Environmental Category: B (Partial Assessment) 5.1 In accordance with OP/BP/GP 4.01 (Environmental Assessment) the project has been rated Environmental Category B. The reason for this rating was the inclusion of the transmission network components and associated potential environmental issues. The scope of this component, however, is rather limited, as it includes rehabilitation of only one transmission substations out of about 400 transmission substations in the country in the network comprising the 35-kV and higher voltages. The work involves repairs and replacement of the existing equipment; there will be no expansion of the substations or construction of new facilities. Therefore, there will be no resettlement or property rights issues as all work will be executed within the premises of the existing facilities. Under bidding document clauses, contractors will be responsible for keeping work sites pollution-free, minimizing work-related nuisance, and returning the sites to their original conditions. An environmental impact analysis, with proposed mitigation measures, was carried out as part of the technical feasibility study, and is available in project files. The analysis found that project will have no appreciable adverse environmental impacts, and will have environmental benefits associated with better performance of the new and repaired equipment. The analysis found no PCB (polychlorinated biphenyls) presence in the substation. Bidding documents for the repair, replacement, or rehabilitation of any existing equipment will specify that PCBs are not to be used. The main environmental issues associated with the old equipment are leaking of transformer oils and malfunctioning fire fighting equipment in the substations. The project will bring environmental benefits, as the new switchgears will be of SF6 type, replacing the old oil-based equipment, and the new transformers will have oil pits and working sprinkler systems, remedying the existing problems. On the basis of the analysis and proposed mitigating measures, the Borrower has prepared an Environmental Management Plan (EMP), containing specific actions to be implemented during project design and implementation to ensure that main problems associated with the old equipment at the facilities included in the project are alleviated. The necessary funds are included in the substation rehabilitation financing. 5.2 The environmental impact assessment established the level of pollution (oil, electromagnetic fields) at the substation included in the project and found that the impact was confined to the substation site. The Environmental Management Plan identify measures to improve environmental performance of the facilities at the substation, which include improved fire protection, continuing monitoring of electromagnetic fields and water pollution, and soil cleaning -- if needed -- to mitigate the contamination of soil from earlier oil leaks. 5.3 For Category A and B projects, timeline and status of EA: Date of receipt of final draft: February 5, 2000 5.4 Consultant discussed environmental issues with the relevant Government agencies and the staff manning the affected sites. The Government made available the environmental assessment report to the general public, who was informed through advertisement in local press. 5.5 Environment Management Plan has been developed as part of project preparation and will be implemented as part of the project. The Plan includes measures to continuously monitor environmental impact of the substation and mitigate the consequences of oil pollution, if needed. 6. SOCIAL: 6.1 The principal social issues are (i) effect of increased cost recovery for electricity on vulnerable groups; and (ii) social impact of labor restructuring in beneficiary enterprises. 26 Implementation of the targeted social protection scheme agreed under the Energy Sector Adjustment Credit (in 1999) to compensate for increased cost recovery improved significantly since mid-2000, in spite of the significant fiscal constraints. The Letter of Electricity Sector Policy, submitted by the government to IDA states that there will be no arrears in disbursement of benefits agreed under the ESAC. As of March 2001, The Government was current on payment of the benefits for 2000 and 2001, but there were arrears carried over from the 1999 budget. The Government agreed to repay these arrears in 2001 as a condition under Bank's structural adjustment lending. The project conditionality supported improved implementation of the social protection scheme prior to credit effectiveness, but further implementation improvements can only realistically be expected through policy dialogue at the macroeconomic level. The new management contractors in the beneficiary enterprises are likely to reduce overstaffing. The law provides for the payment of wage arrears and for severance pay at the time of layoff. The management contractors will be required to ensure respect of the law (and are more likely to do so than existing management), and to develop supplementary social mitigation schemes where appropriate. It should be noted, however, that employees of the electricity sector in Georgia are not generally poor (as evidenced by Household Survey). They are also widely-perceived (according to corruption survey evidence) to have a high level of illegal income; special social mitigation programs for such employees may therefore not be well-supported by the population. The management contractors, in conjunction with the Government, will develop a public education campaign to consult stakeholders and explain the benefits of reform to the population. The Government, with Bank's assistance, will also request the extension of USAID's Winter Heat program, which has been in place already for several years and which has been designed to subsidize electricity bills of the poorest segments of population. The Government will also seek participation of other donors and private sector in the program. 6.2 Participatory Approach: How are key stakeholders participating in the project? Primary beneficiaries of the project are transmission and dispatch companies -- Electrogadatsema and Electrodispatcherizatsia -- who prepared the project and will implement it. Other key stakeholders -- participants in the Georgian electricity market -- have been consulted through the Wholesale Electricity Market. The Ministries of Environment and Telecommunications have also been included in discussions. Georgian National Electricity Regulatory Commission have been consulted as well. 6.3 How does the project involve consultations or collaboration with NGOs or other civil society organizations? N.A 6.4 What institutional arrangements have been provided to ensure the project achieves its social development outcomes? N.A. 6.5 How will the project monitor performance in terms of social development outcomes? N.A. 27 7. SAFEGUARD POLICIES: 7.1 Do any of the following safeguard policies apply to the project? Policy Applicability Environmental Assessment (OP 4.01, BP 4.01, GP 4.01) Yes Natural habitats (OP 4.04, BP 4.04, GP 4.04) No Forestry (OP 4.36, GP 4.36) No Pest Management (OP 4.09) No Cultural Property (OPN 11.03) No Indigenous Peoples (OD 4.20) No Involuntary Resettlement (OD 4.30) No Safety of Dams (OP 4.37, BP 4.37) No Projects in International Waters (OP 7.50, BP 7.50, GP 7.50) No Projects in Disputed Areas (OP 7.60, BP 7.60, GP 7.60) No 7.2 Environmental impact assessment and an Environmental Management Plan have been completed. A broader transmission system environmental action plan will be developed as part of the project. F. SUSTAINABILITY AND RISKS 1. SUSTAINABILITY: The sustainability of the project depends largely on the degree of success in: * completion of privatization of distribution and generation companies (including management contracts for non-privatized distribution) and improved financial performance of the sector; * successful negotiation and implementation of the management contracts for the transmission and dispatch companies and the wholesale electricity market; and * resolution of sector's debt overhang. A successful completion of these activities should lead to significantly better financial performance of the sector through improved collections and reduced costs, stemming the accumulation of debt and reducing its stock. It should also lead to better integration of the Georgian power system into regional network, creating conditions for a competitive and more liberalized electricity market in the country, bringing further efficiency gains both in operation and in investments. 28 2. CRITICAL RISKS (reflecting the failure of critical assumptions found in the fourth column of Annex 1): Risk Risk Rating Risk Mitigation Measure From Outputs to Objective Improved performance of distribution and H Privatization of distribution and generation, generation companies (improved collections and and management contracts for transmission reduced losses) and dispatch, and the WEM; consolidation of non-privatized distribution companies under a single management contractor; better enforcement of payment through disconnections; debt restructuring; however, the risk of continued poor performance of non- privatized assets not completely mitigated, especially during the initial few years Reliable electricity supply from domestic H Rehabilitation of several major power plants generation and unimpeded regional energy trade either completed or under way, financed by (electricity and gas) international donors; the main thermal power plant privatized; the risk of disruptions in the regional trade not mitigated Maintaining cost-covering tariffs S Assistance to strengthen GNERC provided through other IDA operations and by bilateral donors (USAID) From Components to Outputs System dispatch and meter reading procedures S Included in the scope of management established and followed contracts; additional assistance provided by bilateral donors outside the project (USAID) Adequate maintenance and operation of the S Included in the scope of management transmission, dispatch and communications contracts systems The Government to facilitate performance of the H Coordinated effort by all major international management contracts; actively pursue anti- financing institutions to help fight corruption corruption measures; and honor its financial and improve management of the public sector; obligations to the energy sector the risk, however, remains high Successful completion of management contracts H Privatization of distribution and generation; coordinated assistance of donors to address major problems in the sector 29 Government and the sector enterprises to carry H Assistance by international financing out debt restructuring plan institutions to improve management of the public sector and public sector debt Availability of local counterpart funds for the H Improved financial management of the project investment and technical services components beneficiaries through management contracts; establishment of escrow accounts for local financing Overall Risk Rating H Overall project risk is high: privatization of distribution areas outside Tbilisi may not succeed and the ability of management contractor to improve the performance of these companies is not tested; the management contracts may not succeed due to pressure from vested interests; corruption will be hard to eradicate and the effort will take time; domestic and regional political tensions are still present and are likely to persist Risk Rating - H (High Risk), S (Substantial Risk), M (Modest Risk), N(Negligible or Low Risk) 3. Possible Controversial Aspects: Georgian Constitution imposes some limits on foreign ownership and control of the power transmission network. The management contracts for transmission and dispatch will involve foreign firms. High level of political commitment to the management contracts, expressed through a Presidential Decree, indicates that the Constitutional stipulation should not be prohibitive, but it cannot be excluded that some elements of the contract may be challenged by vested interests on Constitutional grounds. G. MAIN CREDITCONDITIONS 1. EFFECTIVENESS CONDITION 1. Sign management contracts (satisfactory to IDA) for Wholesale Electricity Market, Electrogadatsema, and Electrodispatcherizatsia [D. 1] 2. Satisfactory progress in implementation of actions in Letter of Electricity Sector Policy [B.2] 3. Sign subsidiary loan agreements, satisfactory to IDA [C.4] 4. Electrodispatcherizatsia and Electrogadatsema to establish escrow account for local financing of the project and make initial deposits [C.4] 2. OTHER [classify according to covenant types used in the Legal Agreements.] 1. The Borrower to maintain Management Contracts for Electrogadatsema, Electrodispatcherizatsia, and the Wholesale Electricity Market, satisfactory to IDA, throughout the project implementation [D, 1] 2. The Borrower, Electrogadatsema and Electrodispatcherizatsia to establish and maintain a Project Service Organization (PSO) [C.4, E.4] 30 3. The Borrower, Electrogadatsema and Electrodispatcherizatsia to implement the action plan to strengthen financial management system of the project [C.4, E.4] 4. Arrangement for opening and operating Special Accounts for IDA Credit [C.4] 5. Electrogadatsema and Electrodispatcherizatsia to open project escrow accounts and maintain sufficient deposits for local financing of the project [C.4] 6. PSO to implement project management reporting requirements (including quarterly and annual reports, and project mid-term review by June 30, 2003) [C.4] 7. Electrogadatsema and Electrodispatcherizatsia to prepare a plan for the future operation of the project and discuss it with IDA [C.4] 8. Principal terms and conditions of the subsidiary loan agreements to be maintained [C.4] 9. Electrogadatsema and Electrodispatcherizatsia to submit audit reports to IDA no later than six months after the close of fiscal year [C.4] 10. Electrogadatsema and Electrodispatcherizatsia to maintain debt coverage ratio at 1.5 and the ratio of current asset vs. current liabilities at 1.1 [E.2] Disbursement Conditions 11. Privatize all distribution companies to strategic investors for which there is interest in the market, and place all non-privatized distribution companies and management contract with a credible international manager, through a transparent, competitive process satisfactory to IDA, before any funds from the IDA Credit are disbursed against the investment contracts financed by the Credit [B.3] H. READINESS FOR IMPLEMENTATION 1. a) The engineering design documents for the first year's activities are complete and ready for the start of project implementation. 1. b) Not applicable. 2. The procurement documents for the first year's activities are complete and ready for the start of project implementation. 3. The Project Implementation Plan has been appraised and found to be realistic and of satisfactory quality. 4. The following items are lacking and are discussed under loan conditions (Section G): N.A. 31 I. COMPLIANCE WITH BANK POLICIES 1. This project complies with all applicable Bank policies. Vladislav Vucetic Hossein Razavi Judy M. O'Connor Team Leader Sector Manager Country Director 32 Annex 1: Project Design Summary GEORGIA: Electricity Market Support Project Hierarchy of Objectives Key Performance Monitoring & Evaluation Critical Assumptions Indicators Sector-related CAS Goal: Sector Indicators: Sector/ country reports: (from Goal to Bank Mission) Reduce barriers to private Privatize additional Government's statistics Continued implementation sector development and generation and distribution of the economic reform deepen and diversify sources assets to strategic investors Project Implementation program of growth through Reports from the PSO rehabilitation of basic Improved collections at the Government's social policies infrastructure and improved wholesale level from 55% to to deal with energy supply to environment for private 95% vulnerable groups investment in the sector Project Development Objective Outcome / Impact Indicators: Project reports: (from Objective to Goal) To improve reliability and Reduce system-wide outages Project Implementation More efficient public efficiency of electricity from 20 hrs/yr to 15 hrs/yr Reports from the PSO governance; stronger law supply, and improve (expressed in equivalent enforcement (including financial and corporate total system blackout hours) bankruptcies and anti- management in the wholesale corruption measures) electricity market. Reduce losses in the Project Supervision Reports subtransmission and from IDA and co-financiers Incentives for private transmission network from investment; transparent, 15% to 12.5%. competitive privatization of enterprises and public Improved collections at the procurement wholesale level from 55% to Reports from Management 95% Contractors Political stability in the country and the region Outages of the Zestafoni- Ksani line to decrease by 25% (from 10.5 hrs/yr to 7.9 hrs/yr average) Outages of the Zestafoni- Inguri line to decrease by 10% (from 16 hrs/yr to 14.4 hrs/yr average) Outages of the Zestafoni 500-kV substation to decrease from 13.3 hrs/yr to 4 hrs/yr average 33 Hierarchy of Objectives Key Performance Indicators Monitoring & Evaluation Critical Assumptions Output from each Component: Output Indicators: Project reports: (from Outputs to Objective) Improved system metering Reduced commercial losses Project Implementation Reliable electricity supply in the system from 1.8% to Reports from the PSO from domestic generation 1% and unimpeded regional energy trade (electricity and Number of meters installed gas) in the transmission network: 480 Improved power system Reduce system-wide outages Project Supervision Reports dispatch and control from 20 hrs/yr to 15 hrs/yr from IDA and co-financiers (expressed in equivalent total system blackout hours) Reduced Reduce losses in the subtransmission and transmss* t rrom Reports from Management transmission network from Contractors 15% to 12.5%. A computerized control center in Tbilisi processing 4700 controls, 5000 status indications, 4900 alarrns, and 450 measurements from 30 remote terminal units 2 telephone exchanges with 230 telephone sets Fiber optics telecommunication network (580 km) 34 Improved efficiency and Outages of the Zestafoni- Maintaining cost-covering reliability of the Zestafoni Ksani line to decrease by tariffs transmission substation 25% (from 10.5 hrs/yr to 7.9 hrs/yr average) Outages of the Zestafoni- Inguri line to decrease by 10% (from 16 hrs/yr to 14.4 hrs/yr average) Outages of the Zestafoni 500-kV substation to decrease from 13.3 hrs/yr to 4 hrs/yr average Improved financial Debt service cover ratio of Improved performance of performance of EG and ED: 1.5 distribution and generation Electrogadatsema (EG), companies (improved Electrodispatcherizatsia Current ratio of EG and ED: collections and reduced (ED), and the wholesale 1.1 costs) electricity market Local counterpart funds for the project provided timely Improved collections at the wholesale level from 55% to 95% Successful implementation of Procurement completed per the project and improved schedule (see Annex 6) capability of the beneficiaries to implement investment Project completed by June projects 30, 2005 35 Hierarchy of Objectives Key Performance Indicators Critical Assumptions Project Components /Sub- Inputs: (budget for each component) (from Components to components: Outputs) Outputs) Rehabilitation and Upgrade of System Project Implementation Reports from Metering the PSO Meter reading procedures established Rehabilitation and Upgrade of System Project Supervision Reports from IDA and followed Dispatch, Control and Communications and co-financiers System dispatch rules and procedures Rehabilitation of Transmission Audit Reports followed; Adequate maintenance and Network operation of the dispatch and communications systems Adequate maintenance and operation of Management Information Systems Reports from Management Contractors the transmission systems Improved performance of distribution Management Contract for the Availability of local counterpart funds and generation companies (improved Wholesale Electricity Market for the investment and technical collections and reduced costs); The services components Government to facilitate performance of the management contracts, including allowing disconnection of non-paying customers, prosecution of electricity theft and financial misuses; to pursue actively anti-corruption measures; and to honor its financial obligations to the energy sector; Government and the sector enterprises to carry out debt restructuring plan Management Contract the Transmission and Dispatch Companies Technical Assistance -Procurement and Project Management - Environmental Action Plan - Debt Restructuring - Audit Incremental Operating Costs 36 Annex 2: Detailed Project Description GEORGIA: Electricity Market Support Project Description of the system. The nameplate capacity of the Georgian power plants exceeded 4400 MW, of which about 60% were hydropower and 40% thermal plants. However, the available capacity is much lower, as most of thermal capacity is either out of operation or de-rated due to poor condition. Currently, only two 300-MW units at the Tbilsresi (Gardabani) thermal plant are available and economic. Similarly, the capacity of hydropower plants, which varies with water availability, is much lower than nominal due to disrepair and aging. The total capacity varies between 1200 MW and 1800 MW. The transmission system includes 572 km of 500-kV lines, 21 km of 330-kV lines, 1173 km of 220-kV lines, 2991 km of 1 1O-kV lines, and 2661 km of 35-kV lines. There are 4 500/220-kV substations, 16 220/1 10-kV substations, 141 110/35-kV substations, and 227 35/10-kV substations. Interconnections with neighboring countries include two lines to Russia (one 500-kV and the other 220-kV through Abkhazia, which is not operational as an interconnection at this time), two lines to Azerbaijan (one 500-kV and the other 330-kV; the 500-kV line is not operational), one 220-kV line to Armenia, and one 220-kV line to Turkey. The 500-kV line stretches from Russia to the Inguri hydropower plant, then to the Gardabani thermal plant via the Zestafoni and Ksani substations, with a branch from Ksani to Azerbaijan. This line is the backbone of the transmission network, and its outage often causes a collapse of the system, as the transfer capacity of the 220-kV network does not provide sufficient reserve. The distribution network includes the 10- and 0.4-kV lines, and some 35- and 1 IO-kV lines around Tbilisi. The system dispatch is organized into a three-level hierarchical system. National Dispatch Center (NDC) in Tbilisi is at the top of the hierarchy with the authority to supervise and control dispatch of power plants above 10 MW, tie lines with neighboring countries, and the transmission network above 11 0-kV (including some 11 0-kV lines). At the second level are 12 Area Control Centers (ACCs) whose responsibilities include the portion of 110- kv network which is not supervised by the NDC, the 35-KV network and power plants below 10 MW. The Kutaisi ACC has some enhanced responsibilities for the western part of the system. At the third level are distribution control centers (DCC), responsible for local distribution network of 10-kV and lower voltage. In the FSU, there was a regional dispatch center Pontoel in Tbilisi. It still exist as an organization, with Russia, Armenia, Georgia and Azerbaijan as the founders, nominally in charge of coordinating joint operation of the regional power systems. Since the systems, however, operate largely in isolation, Pontoel is de facto defunct. There is little automation in the control systems, except some in the NDC, which was established in 1974 (before that the Georgian power system was controlled from elsewhere as part of the FSU-wide system), and was expanded in parallel with the expansion of the transmission network. The existing control and communications system was completed in the late eighties. It is based on the old Soviet technology. It is practically impossible to maintain and expand the system due to a number of reasons: functional and technical limitations, lack of spare parts, and technological obsolescence and incompatibility with modern equipment. The SCADA system included 34 facilities - power plants and substations - from which information was collected in real time. The system as designed is obsolete: not all information is acquired (e.g., equipment alarms, transformer tap-changer positions, energy counter values), transmission speed is low, there is no capability for remote control. Furthermore, a number of the 34 remote terminal units (RTUs) are not operational and dispatchers rely on telephones - which are also not very reliable -- to update themselves on the status of equipment. The telecommunications system is based on power line carriers (PLCs), radio links, some communication cables, and leased telephone lines. About 50% of the PLCs and about 60% of the radio network is out of operation. Metering of electricity is done by electromechanical meters, with no remote reading capabilities, nor the capability to support time-of-day tariffs required for a pool-based trading arrangements. 37 System demand had decreased substantially during the last decade, from about 17 TWh in late 1980s (at the generation level) to about 7-8 TWh during the last 5 years, mainly due to decrease in industrial demand, which fell from about 8 TWh to about 1 TWh during the same period. The demand could be met from domestic plants if sufficient fuel is procured for the Gardabani (Tbilsresi) plant, and if both thermal and hydropower plants are maintained and operated properly. There could be some seasonal imbalances due to seasonal character of water inflows, which could be mitigated by exchanges with neighboring systems. It is expected that demand will remain flat or slightly higher during the next several years. Structurally, the Georgia power system is organized into distribution, generation, transmission, and dispatch segments. The distribution and generation segments are operated by a number of companies, whose structure is changing with privatization. At this time, about 50% of distribution (measured by share in demand) is privatized, almost entirely to strategic investors, with another 10% under negotiations. The remaining distribution assets are being consolidated into few companies, and continue to look for private investors. The generation assets are undergoing privatization. It is expected that most plants outside Abkhazia, with few exceptions, will be sold or leased through 25-year concession to strategic investors by mid-2000. The transmission and dispatch assets and functions belong to Electrogadatsema and Electrodispatcherizatsia, respectively, which are publicly owned. Ministry of Fuel and Energy is Government's agency in charge of sector policies, whereas the Ministry of State Property exercises the ownership functions over the public companies and Government's shares in the privatized ones. An independent energy regulatory agency (GNERC) regulates the sector. The bulk of trading goes through the Wholesale Electricity Market (WEM), which acts as a central purchasing agency, settles the transactions and administers the funds. Some trading is also organized through bilateral contracts, which are regulated. Electrodispatcherizatsia dispatches the system according to the availability of power plants and schedule of export/import contracts. All prices are regulated by GNERC, and therefore there is no electricity market in the customary sense of the word. This is a transitional arrangement, designed to last until the bulk of distribution and generation assets are privatized and financial discipline established. Once this is achieved, it is expected that a more competitive arrangement in generation and imports will be possible and that the market could be liberalized. Project concept. Unimpeded, reliable, and efficient transmission of electricity from power plants to the consumers is essential. This requires both the existence of adequate transmission lines and substations, and means to continuously plan, monitor, and control the complex system operation. It also requires metering of electricity flows with sufficient frequency and accuracy to settle numerous commercial transactions among trading parties. Given the nature of the physical processes involved, the system operation has to be centrally monitored and controlled in real time. This needs continuous collecting of information from geographically dispersed facilities (power plants, substations and lines) and transmission of this information to the central dispatch center, and vice versa -- communication of dispatch control actions (either automated or executed by personnel manning the facilities) to locations where the actions are to be taken. Therefore, a modem power network includes an elaborate system of data acquisition and metering devices, data transmission and communication lines, computers and software, physically and functionally integrated to ensure continuous reliable operation of the system. The transmission network in Georgia, with its associated metering, dispatch and communications facilities, suffers from years of neglect, maintenance backlogs, and lack of investment in upgrades and new equipment. No transmission lines and substations were constructed after 1990. Only 7 out of 25 220-, 330-, and 500-kV substations have been in operation for less than 20 years, and 8 of them exceeded 30 years. The existing dispatch system, with it SCADA equipment, was installed in the 1980s. However, it is based on old Soviet technology, which is practically impossible to maintain and expand due to a number of reasons -- functional and technical limitations, lack of spare parts, technological obsolescence and incompatibility with modem equipment. The SCADA included 34 facilities -- power plants and substations -- from which information was collected. The system as designed is deficient: not all information is acquired (e.g., equipment alarms, transformer tap-changer positions, energy counter values), transmission speed is low, there is no capability for remote control. Furthermore, a number of the 34 remote terminal units (RTUs) are not operational and dispatchers rely on 38 telephones -- also not very reliable -- to update themselves on the status of the system. The telecommunications network is based on power line carriers (PLCs), radio links, some communication cables, and leased telephone lines. About 50% of the PLCs and about 60% of the radio network is out of operation. Metering of electricity is done by electromechanical meters, with no remote reading capabilities, nor the capability to support time-of-day tariffs required for a pool-based trading arrangements. Furthermore, the metering has been designed for a vertically integrated system operated by a single company and is ill-suited for settling transactions in a restructured system with many market participants. The proposed project aims at repairing, rehabilitating, and upgrading the metering, control and communications infrastructure, and selected transmission facilities, which would enable a secure, reliable, and efficient operation of the power system and its integration with the neighboring systems. The proposed technical solutions for the metering, control and communications are based on standard concepts and proven technologies, accepted and