_. po fht so Report No. 6Ol16-PH Philippines Rural Electrification Sector Study: An Integrated Program to Revitalize the Sector Noven*er 9, 1989 Coy Deparmnt 11 Asia Region FOR OFFICIAL USE ONLY i~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ DocuUmen of the Worl Bark This document has a restricted distribution aridnmay be used by recipients only,p if*th performance of their officdal duties. Its content may not otherwise be disclosed without Worl Bank authorization. W. " ,%~~~~~~~1 CURRENCY EQUWALENTS Currency Unit - Philippine Peso (P) US$1.00 - P 21.4 P 1,000 - US$46.73 P 1 = 100 Centavos (Ctvs.) WEIGHTS AND MEASURES Kw _ Kilowatt (1,000 watts) MW = Megawatt (1,000 kilowatts) GW Gigawatt (1 million kilowatts) kWh - Kilowatt-hours (1,000 watt-hours) NWh - Megawatt-hours (1,000 kilowatt-hours) GWh - Gigawatt-hours (1 million kilowatt-hours) kV = Kilovolt (1,000 volts) m - Meter (3.2808 feet) km = Kilometer (0.6214 miles) ABBREVIATIONS AND ACRONYMS ADB - Asian Development Bank APT - Asset Privatization Trust BAPA - Barangay Power Association BOT - Build-Operate-Transfer Program COA - Commission on Audits DBP - Development Bank of the Philippines DENR - Department of Environment and Natural Resources DOF Department of Finance ECC = Energy Coordinating Council ERB - Energy Regulatory Board ERR - Economic Rate of Ret-urn FECOPHIL - Feder. of Electric Cooperatives of the Philippines IRR - Internal Rate of Return LRMC = Long Run Marginal Cost MERALCO Manila Electric Company MIS = Management Information System NEA - National Electrification Administration NEDA - National Economic Development Authority NPC - National Power Corporation NPV - Net Present Value NRECA - National Rural Electric Cooperative Assn. (U.S.A.) OEA Office of Energy Affairs OECF = Overseas Economic Development Fund (Japan) PNOC = Philippine National Oil Company REA = Rural Electrification Administration (U.S.A.) REC - Rural Electric Cooperative REMP - Rural Electrification Master Plan SMCC - Synthesized Ma:ginal Cost of Capacity TOD - Time of Day USAID = United States Agency for International Development FOR OFFICIAL USE ONLI PHLIPPINES RURAL ELECTRICATION SECTOR STUDY: AN INTEGRATED PROGRAM TO REVITALIZE THE SECTOR Table of Contents EXECUTIVE SHMARY . . . . .......1. . . . . . . . . . . . . . . . . . . 1. RURAL ELECTRIFICATION SECTOR OVERVIEW . . . . . . . . . . . . . . .1 A. Introduction .1.................... . . . B. Energy Sector Institutions. 2 C. The Rural Eleci.rification Program . . . . . . . . . . . . . . 3 The Program's Origins . . . . . . . . . . . . . . . . . . . 3 Current State of the Sector. 4 D. Issues Facing the Sector ........ .. ... .. .. . 6 Operations, Investment and Priciag .... . . . . . . . . 6 The Rural Electric Cooperatives . . . . . . . . . . . . . . 8 The National Electrification Administration . . . . . . . . 9 E. A Revitalization Program ........ .. ... .. .. . 10 2. OPERATIONAL EFFICIENCY .... . . . . . . . ...... . . . . . 11 A. Introduction .... . . . . . . . . . . . . . . . . . . . . 11 B. The Rural Electric System .... . . . . . . . . . . . . . . 12 C. Operation and Maintenance . . . . . . . . . . . . . . . . . 15 D. Commercial Practices . . . . . . . . . . . . . . . . . . . . 17 E. Non-Technical Losses .20 F. Core Systems . . . . . . . . . . . . . . . . . . . . . . . . 22 G. Rural Electrification Master Plan . . . . . . . . . . . . . . 23 3. INVESTMENT STRATEGY .... . . . . . . . . ....... . . . . . 26 A. Current Planning Strategy .... . . . . . . . . . . . . . 26 B. Investment Priorities .... . . . . . . . . . . . . . . . . 27 C. Investment Scenarios .... . . . . . . . . . . . . . . . . 30 D. Coverage Targets . 33 E. Investment Criteria and Planning. 34 F. Planning Constraints .... . . . . . . . . . . . . . . . . 37 G. Summary of Recommendations .... . . . . . . . . . . . . . 39 This document has a restred distibution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. 4. PRICING POLICY . . . . . . . . . . . . . . . . . . . . . . . . . . 40 A. Introduction ....................... . 40 B. NPC Costs . . . . . . . . . . . . . . . . . . . . . . . . . . 41 C. LRMC-Based Wholesale Pricing ..... . . . . . . . . . . . 42 D. REC Cost of Supply . . . . . . . . . . . . I . . . . . . . . 43 E. A Possible Rate Formula .................. . 45 F. Operating and Customer-Related Costs . . . . . . . . . . . . 48 G. Other Pricing Issues .50 Affordability and Price Elasticity . . . . . . . . . . . . 50 Pilferage ........................ . 51 Regulation . . . . . . . . . . . . . . . . . . . . . . . . 51 H. Summary of Pricing Principles ... . . . . . . . . . . . . . 52 5. THE RURAL ELECTRIC COOPERATIVES . . ....... . 55 A. Introduction . . . . . . . . . . . . . . . . . . . . . . . . 55 B. Financial Condition .... . . . ...... . . . . . . . . 56 Aggregate Financial Results .... . ..... . . . . . . 56 Comparison of REP Performance by Area and Region . . . . . 58 Comparison of RECs with Investor-Owned Utilities . . . 59 C. Institutional Structure and Management .. ..... . . . . 60 Role of NEA .... . . . . . ....... . . . . . . . . 60 Role of REC Boards of Directors ... . ..... . . . . . 62 Role of REC Managers .... . . ...... . . . . . . . 63 D. Guidelines for Restructuring the RECs . . . . . . . . . . . . 63 Increase the RECs' Equity ................ . 64 Relief from Non-Performing Assets and Delinquent Loans . . 65 Improve the Manageability of the RECs .. ..... . . . . 66 Reorient the RECs' Investment Practices .. ..... . . . 67 6. THE NATIONAL ELECTRIFICATION ADMINISTRATION . . . . . . . . . . . . 69 A. Introduction ..69 B. NEA's Role . . . . . . . . . . . . . . . . . . . . . . . . . 69 C. Institutional and Financial Context . . . . . . . . . . . . . 71 D. Current Financial Performance ..74 E. Proposal for a Financial Restructuring of NU . . . . . . . . 78 F. Financing Strategy ..84 G. NEA's Financial Prospects ..87 H. Organizational Issues ..89 I. Summary of Recommendations ...... .......... 91 Annexes Armex 1.01 - Consumers Served by the RECs Annex 1.02 - Annual Formation of RECs Annex 1.03 - Current Status of Mini-Hydro and Dendro-Thermal Programs Annex 2.01 - Kilometers of Line per Region by Design Parameter Annex 2.02 - Consumers per km. of Line per Region Annex 2.03 - Distribution System Design Aspects of Technical Losses Annex 2.04 - Current Condition of the Rural Distribution System Annex 2.05 - Reeommendations for Improved Tree Clearing & Pole Treatment Annex 2.06 - Zonal Repair Facilities to Service the RECs Annex 2.07 - Transformer Circuit Metering - The'BAPA Model Annex 2.08 - Annual Energy Sold and Losses (By Geographic Region) Annex 2.09 - Program to Reduce Non Technical Losses Annex 2.10 - Pilot Program for Rehabilitating Substations and Feeders Annex 3.01 - NEA Investment Requirements Survey 1988 Annex 3.02 - Sample Feasibility Studies Annex 3.03 - Sample Feasibility Studies - Results Annex 3.04 - Potential Savings from Construction Efficiency Improvements Annex 3.05 - Rural Distribution Investment 1989-95 Annex 4.01 - Comparative Rate Levels for NPV's Luzon Grid Annex 4.02 - Marginal Cost Analysis Annex 4.03 - L.A - Based Wholesale Pricing Annex 4.04 - REC Cost of Supply: Four Case Studies 4nnex 4.05 - Hypothetical Cases: Marginal Cost Rates for REC Customers Annex 4.06 - Sample Cooperatives: Price and Cost Data Annex 4.07 - REC Performance Indicators Annex 4.08 - Price Elasticity of Demand Annex 5.01 - REC Energy Usage Annex 5.02 - 25 Largest/Smallest Rural Electric Cooperatives Annex 5.03 - REC - Summary Statement of Operations Amnnex 5.04 - REC - Net Operating Income (Losses) Annex 5.05 - REC - Summary Balance Sheet Annex 5.06 - Comparison of Loan Records - NEA vs RECs Annex 5.07 - Distribution of RECs Among Performance Categories Annex 5.08 - Cost Profile Summary Annex 5.09 - REC General Managers - Board vs NEA Appointments Annex 5.10 - Loan Releases to RECs (Per NEA Records)/ Annual Lending to the RECS Annex 6.01 - Foreign Lending to NEA - By Source Annex 6.02 - Foreign Lending to NEA - By Year Annex 6.03 - Summary of Overdrawn Loans to RECs Annex 6.04 - Status of NEA's Mini-Hydro Loans - By Region Status of NEA's Dendro-Thermal Loans - By Region Annex 6.05 - Summary of NEAL's Relending Terms Annex 6.06 - NEA's Fi.nancial Projections for 1989-93 Annex 6.07 - NEA Staff - By Department Annex 6.08 - Comparison of NEA & NPC Salary Structure Annex 6.09 - Relending Program - Status of Loan Repayments Appendix A - List of RECs and Their Acronyms Maps IBRD 216C8 - The Rural Electric System - Luzon Area IBRD 21763 - The Rural Electric System - Visayas Area IBRD 21762 - The Rural Electric System - Mindanao Area Acknowledgements This report was prepared by a rural electrification sector mis- sion that visited the Philippines during February 20-March 10, 1989. The mission included: (a) Jamil Sopher, Senior Financial Analyst/Mission Leader (b) Karl G. Jechoutek, Senior Economist (c) William H. Lawrence, Institutional Specialist (d) Gerald G. Dunnion, Rural Electrification Specialist (e) Ashley Lyman, Electricity Pricing Specialist (f) Myrna B. Villaralbo, Financial Analyst In addition, the mission wishes to express its sincere thanks to Raymond Schoff (Rural Electrification Specialist) and Eleanor Alcanites (Financial Analyst/Auditor) for the substantial assistance they provided, both during the mission and thereafter. We also wish to extend our thanks to Patricia Brereton-Miller, Merle Mendis, Lillian Samson and Anjali Villagran for the substantial help they priovided at headquarters. The mission wishes to express its gratitude for the excellent cooperation and gracious hospitality afforded by the host agency, the National Electrification Administration (NEA); the National Power Corpora- tion (NPC); the Department of Environment and Natural Resources (DENR); the Office of Energy Affairs (OEA); the National Economic Development Authority (NEDA); the Department of Finance (DOF); the Energy Regulatory Board (ERB); and the Development Bank of the Philippines (DBP). The mission also grate- fully acknowledges the management and staffs of the Cebu I, II and III Electric Cooperatives (CEBECO); Tarlac I Electric Cooperative (TARELCO I), Camarines Sur III Electric Cooperative (CASURECO III), Benguet Electric Cooperative (BENECO), La Union Electric Cooperative (LUELCO), and Tablas Island Electric Cooperative (TIELCO), who consulted with the team during field visits in the course of the main field mission and an earlier prepa- ratory mission (November 29-Docember 9, 1988). Finally, the mission wishes to offer sincere thanks to the staff of the Office of Capital Development of the United States Agency for International Development (USAID) mission in the Philippines, wb-, were ex- tremely generous about sharing their extensive knowledge of and experience in the rural electrification sector. EXECUTIVE SUMMARY A. Introduction 1. In early 1988, tbe Bank undertook a study of the Philippine energy sector; that study (Report No. 7269-PH; September 15, 1988) recom- mended a broad strategy for resource allocation and utilization. Since then, the Government indicated concern that some of the important benefits of that strategy might not be realized because of inefficiencies in the electricity distribution system, through which about 15% of total available energy is consumed. The Government was particularly concerned about the impact of rapidly increasing distribution losses, which reached 25% by the end of 1987, on the US$7 billion investment program that was launched for electricity generation and transmission in 1989-96. In June 1989, the Bank approved a US$65.5 million loan to finance distribution system improvements in Metro Manila and the surrounding area. In addition, it conducted a study of the rural electrification sector in February 1989. This report details the findings of that study. 2. The study confirmed that the rural electrification sector has major problems. Until about 1983, substantial investments were made for system expansion without due regard for cost or quality of service. Since 1983, with funding for further expansion becoming increasingly constrained, repayment of earlier loans coming due, and the physical deterioration of core systems scaadily increasing, the financial distress of the sector's institutions has become acute. The problems are so pervasive that they cannot be addressed by simple solutions; rather, the Government will need to implement an integrated program to revitalize the sector. That program should have three essential components: (i) a comprehensive restructuring of the sector's core institution, the National Electrification Administra- tion; (ii) a broad program of institutional reform, featuring some finan- cial restructuring, of the 117 Rural Electric Cooperatives that are respon- sible for distributing electricity to smaller urban centers, towns, vil- lages and rural areas nationwide; and (iii) a thorough refocussing cf oper- ational practices and investment priorities. B. Background The Economic Settng 3. The Philippine economy has undergone a dramatic turnaround since the mid-1980s. The economic reorientation since 1986 has stressed the primacy of efficiency, prudent macroeconomic management, a transition to market mechanisms, a reform of public enterprises, and a streamlining of public sector investment. The next steps in the transition to efficiency- oriented management will include (i) tailoring a public sector investment program to provide the prerequisites for sustained economic growth; (ii) upgrading the implementation capacity of public sector agencies; (iii) accelerating rural development investments; and (iv) removing infra- - ii - structure bottlenecks. In this context, a revitalization of the rural electrification sector is critically needed if issues of investment effi- ciency, rural development, and infrastructure improvement are to be ad- dressed vigorously. Energy Sector Instftutions 4. The main energy sector Government institutions include: (i) the National Power Corporation (NPC), which is responsible for power generation and transmission; (ii) the Philippine National Oil Company (PNOC), which is responsible for maintaining adequate oil supplies and developing indigenous energy resources; and (iii) the National Electrification Administration (NEA), which is responsible for formulating and implementing rural electri- fication policies. Following the change in Government in 1986, the Office of Energy Affairs (OEA) was given responsibility for planning and coordi- nating energy sector policies and programs. OEA, NPC and PNOC are under the formal control of the Office of the President while NEA reports to the Department of Environment and Natural Resources (DENR). Recently, to de- velop formal linkages between the energy sector participants, the Govern- ment formed an Energy Coordinating Council (ECC). 5. Within the power sector, NPC is responsible for all but very modest generation facilities nationwide and most transmission systems. The Manila Electric Company (MERALCO), an investor-owned company, is responsi- ble for electricity distribution in Metro Manila and surrounding areas. Six investor-owned power utilities provide distribution to urban centers outside Manila. Distribution for the smaller urban centers and the rural areas is provided by 117 Rural Electric Cooperatives (REC). NEA is respon- sible for coordinating the activities of the RECs. Historical Context 6. The rural electrification program began formally in June 1969, when Republic Act 5038 (i) declared total electrification of the country- side on an area coverage basis to be a national policy; (ii) provided for the creation of NEA as the primary agency responsible for executing the rural electrification policy; and (iii) provided for the organization of RECs to implement the electrification targets and operate the resultant networks. At that time, only 18X of the country's population was enjoying electric service. NEA was supposed to fulfill its statutory responsibility by (i) providing technical support to the RECs; and (ii) financing their expansion programs rith grants and long-term loans. Later, it acquired tne additional responsibilities of (i) supervising the RECs' technical and man- agerial activities; (ii) regulating their electricity rates; and (iii) pro- moting the development of alternative generating schemes and certain other special projects, which were concerned with integrated rural development programs but not per se with rural electrification. 7. In the program's early years, official and Government funding for rural electrification was so plentiful that the cooperative system ex- panded extremely rapidly. This expansion was realized through both the - iii - construction of new networks and the assumption of responsibility for existing systems following the failure of locally-based, investor-owned power companies. During this early period, RECs were formed following a thorough feasibility study, with service areas that afforded reasonable chances for technical and financial viability. But, as the pace of expan- sion accelerated, the feasibility studies became more superficial; and RECs were formed to meet political objectives, REC managements suffered from the same politicization, and the quality of operations suffered as a result. C State of the Sector 8. Currently, 117 RECs have franchises covering the entire country outside of the areas served by MERALCO and six smaller investor-owned dis- tribution companies. From an initial base of about 170,000 connections in 1971, they now provide electricity to about 2.8 million consumer members. A large proportion of RECs face serious operational and financial problems. Only 22 RECs are considered to be well managed and financially viable; for another 24, financial viability is within reach if they make some opera- tional and commercial adjustments. The remaining 71 either have a pro- nounced need for substantial remedial action or are considered beyond res- cue. REC distribution losses average 25%, but are in some cases as high as 45-50. Theft of electricity is common, and maintenance is inadequate throughout the REC system. Annual loan releases, which had averaged more that US$28 million in 1971-83, have dropped precipitously, reaching only US$3.3 million in 1988. With the decline in funding, the annual growth rate of new connections has slowed from 30% or more before 1980 to under 4% since 1983, and even declined in 1988. 9. The sector's operational and financial weaknesses are critical. The RECs' poor standards of maintenance have led to a widespread physical deterioration of their networks; as a result, with technical losses averag- ing 17% (non-technical losses are averaging 8%), most REC distribution sys- tems are operated at well below their design standards, leading to low re- liability of service. The Government's past emphasis on growth of coverage without sufficient regard for cost, combined with its use of the RECs to implement costly and economically unlustifiable alternative generation and rural development programs, has saddled most of the RECs with debts they cannot pay, despite the heavy concessional element built into the instru ments that were used to finance the sector's expansion. Generally, the RECs lack the skilled staff and equipment needed to improve their opcra- tional performance, and the burdens of past mistakes have weakened their prospects for improving their financial health. In many instances, the RECs' financial problems are directly related to managerial weaknesses that have resulted from the interference in their internal affairs by highly politicized Boards or individual Directors. Even if the RECs as a group would be provided with financial relief, some 25-30 among them face limited future prospects on account of franchise areas that are inherently too costly to serve. 10. NEA has performed poorly as both a lender and a provider of technical support to the RECs. Although it collects monthly data to docu- - iv - ment the RECs' performance. it has been unable to implement programs foi operational and financial improvement, largely because its already scanty technical staff is spread too thin to perform its functions well. NEA's financial condition is poor; and in 1987 and 1988, it realized a collection efficiency of only 36Z. This, in part, reflected the weakened financial condition of the RECs as a result of the recession of 1983-86, and, in oth- er part, the inherent inability of the RECs to repay loans for uneconomic investments that were promoted by the Government and NEA. Too often, the Government has used NEA to promote costly alternative generation schemes or rural development programs of dubious economic value; and, as a result, NEA has on its books some P 2.6 billion in loans for alternative generation and an undetermined amount of loans for social programs for which it has negli- gible prospects for repayment. Overall, NEA has questionable prospects for meeting some P 7 billion of loans raised from foreign lenders and from the Government. 11. NEA's weaknesses result largely from a lack of clarity regard- ing its role in the sector, and its consequent lack of direction. While its revenues accrue entirely from its lending operations, it has viewed itself primarily as an electrification company. In that regard, it has acted as the sector's policy maker, investment planner, regulator, and uti- lity manager of last resort; however, it has not developed the primary functions of a financial intermediary, namely loan programming and credit evaluation. Its lack of a clear focus has inhibited it from acting as an effective core agency for the sector. 12. Perhaps the sector's biggest problem is the participating in- stitutions' chronic lack of technical accountability. NEA has neither had (i) a mechanism to coordinate its activities with the rest of the energy sector, even though the RECs taken together form a substantial block of energy consumers, nor (ii) the outlook and accountability of a financial institution, even though lending and credit are essential elements of its own financial health. Instead, NEA h-as either been accountable to politi- cal agencies, as it was during 1979-86 to the former Ministry of Human Set- tlements, or to rural development agencies, as it is currently to DENR. In that context, its staff has dispensed substantial capital without regard for the technical or financial requirements for cost recovery. 13. The politicization of NEA created an environment that enabled the RECs to become politicized. Although NEA has sound rules governing the conduct and remuneratlon of REC Boards and individual directors, those rules are flaunted more often than not. Availabla data suggest a high cor- relation between interference by Poard members in the day-to-day activities of the RECs and poor management of those institutions. While the RECs are in principle accountable to their consumer members, most RECs whose weak performance may be attributed to poor management show little effort to de- velop member involvement. In effect, these Boards (and in turn their RECs) are accountable primarily to the political interests that sponsored their elections. . v . D. A Revitzation Pogram 14. Major reforms in the sector are urgently needed. To address problems that are so pervasive, an integrated nrogram should be developed that will simultaneously (i) introduce proper operational practices. Apgro- priate investment strategies. and sound pricing princigles and (ii) streng- then the sector's weak institutions. The first focus of the program should be on operations and investment, so as to determine the requirements for restoring the networks to their original design standards and the parame ters of an affordable investment program. Concurrently, appropriate pric- ing principles should be introduced to optimize the RECs' recovery of their costs from revenues. Programs to restructure and strengthen the RECs and NEA should follow after the requirements of operational and investment re- form have been established. Because neither the RECs nor NEA can concen- trate effectively on their future responsibilities as long as they are bur- dened with unmeetable obligations accruing from past uneconomic policies, the institutional strengthening components of the program should include measures for the financial restructuring of these organizations. To ensure that the benefits of restructuring remain effective in the long term, NEA will need to develop and implement a financing strategy that (i) encourages the RECs to invest in high-return projects and adopt proper operational practices and pricing principles, and (ii) discourages them from failing to meet obligations to their creditors and their consumers. Finally, any re- form of the RECs and NEA should include provisions for developing funcrion- al accountability within each of the organizations while also taking ac- count of the realistic constraints they face. 15. This report makes many recommendations for improved opera- tions, investment planning, and pricing for the rural electrification sec- tor. While the study addresses these issues in the aggregate, to ensure that these diverse activities are properly coordinated and to translate this extensive program into a management plan for each REC, an comprehen- sive Rural Electrification Master Plan (REMP) is needed to provide a de- tailed framework within whick (i) specific improvement measures can be for- mulated, taking into account realistic constraints on available financing, and (ii) operational performance can be measured against realistic techni- cal and financial targets. The REMP should be prepared by NEA in consulta- tion with the RECs, with the assistance of consultants. It should plan the integrated long-term development of rural electrification, with special emphasis on the next ten years. It should include as its main elements: (i) establishment of a methodology for investment planning and evaluation; (ii) preparation of indicative investment and lending programs; (iii) de- velopment of an appropriate pricing system; (iv) establishment of opera- tional performance criteria; and (v) formulation of a manpower development plan. - vi - E Operations, Investment and Pricing 16. The condition of the rural electric distribution system has gradually deteriorated so that supply standards and the quality of service have diminished markedly. Now, NEA and the RECs are facing the need for substantial investment in rehabilitation, system improveme.ts, and major maintenance as well as investments that may be justified ir system expan- sion. To ensure that capital is not wasted, proper operation and mainte- nance should take precedence over any investment in new systems. Funds that are allocated for new investmer.t should be used to support projects that are economically justifiable. Currently, because of the general.ly poor condition of many core systems, the relative priority of rehabilUta- tion within the context of all possible investments needs to be estab- lished. To the degree that investments in rehabilitation and system im- provements can be justified on economic grounds, NEA and the RECs should refocus away from extending area coverage and toward improving the quality of existing service. Finally, pricing of electricity should be reformu- lated so as to encourage efficien. operation and maintenaino2 bY the utili- ties as well as efficient utilization of electricity by the consumer, and not merely the recovery of average costs. Operational Effidency 17. Basic_Svstem Design. The basic design of the distribution net- works is sound and appropriate. Until the early 1980s, electricity service and supply continuity standards were generally good, and continue to be satisfactory in a majority of RECs. The system's main flaws result from (i) beginning construction prior to obtaining propsr rights-of-way; (ii) improper maintenance; and (iii) use of ad-hoc approaches for construction, operations and maintenance in the face of financial constraints. 18. Imiroved Operation and Maintenance. Network maintenance is currently performed by the RECs on an ad hoc basis, with poorly-trained staff using inadequate materials, tools and transport. Field inspections of more than half of the RECs, conducted by consultants in 1986-89, found that about 10 of the networks were well maintained, 25X satisfactorily maintained, 35X unsatisfactorily maintained, and the remainder showing no sign of maintenance. NEA should therefore develop a national program for planned and operational maintenance. Based on that program, NEA would help the RECs prepare their own budgets and work programs for major maintenance, and ensure through conditionality con future loans that each REC had formu- lated and would implement its own maintenance program. Programs for plan- ned maintenance should only cover core systems operating at or near design standards; otherwise, rehabilitation must be done first. At a minimum, maintenance activities should include the following three components: (i) clearance of trees; (ii) treatment of poles to prevent rotting; and (iii) repair of damaged equipment and tools that are now lying idle. 19. Rehabilitation of Core Systems. The rural distribution core system consists of about 250 69-kV substations and about 600 13.2-kV feed- ers that supply the distribution transformers, low-voltage networks and - vii - consumer service drops. About 20X of the rural network requires extensive rehabilitation or replacement to restore the system to the original design standards. A pilot program for rehabilitating core systems is included under the proposed Bank-Zinanced Energy Sector Loan; if successful, that program could form the basis for the design and implementation of future rehabilitationw projects. 20. Reduction of Nontechnical Losses. Nontechnical losses are un- acceptably high and should be reduced through a program that includes the following measures: (i) continuous surveillance of lines; (ii) replacement of all "Al base type meters; (iii) sealing of all socket-type meters; (iv) on-site meter testing, replacement and recalibration; (v) rewiring of all substandard major industrial and commercial meters, with regular checks of these meters; (vi) installation of check meters on distribution transform- ers; and (vii) replacement of low-grade service connections with concentric cable. These technical improvements should be complemented by (i) stronger laws to enable utilities and RECs to pursue pilferers and to impose stiffer penalties on those pilferers who are convicted (several proposed bills are currently pending before Congress); and (ii) increased consumer involvement through the promotion of group accounts, known as Barangay Power Associa- tions (BAPA), that would shift responsibility for losses in the secondary system to the BAPA and reduce billing costs. 21. Commercial Practices. Over the years, the RECs have become slack in implementing proper commercial procedures; now, only about 10 of the RECs run their commercial activities effectively. The causes of this deterioration include: (i) management's failure to accord priority to bill- ing, collection and related activities; (ii) insufficient funds to provide and maintain the equipment needed for commercial efficiency; (iii) short- ages of functioning mete.:s; ane (iv) local political and social pressures to forgive delinquent consumers. To restore the RECs to a sound commercial footing, NEA should update its commercial guidelines and encourage the RECs to implement them. Each REC should be provided with a mini-computer to manage its billings and collections, and training in the procedures as well as the hardware and software supplied. These improvements should be com- pl.'qmented with investments to rehabilitate service loops, metering instal- lations and meters. The experience in those RECs that have been performing well indicates a high correlation between effective collections and height- ened member involvement; therefore, the formation of BAPAs and implementa- tion of member outreach programs should be encouraged. Finally, NEA and NPC should develop technically-based policy guidelines concerning supplies to large industrial and commercial consumers; those guidelines would speci- fy conditions under which the RECs could enjoy exclusive franchises within their service areas. 22. Manpower Development. The most critical manpower development requirement facing the sector is to increase the effectiveness of managers, particularly the RECs' General Managers and NEA's senior functional manag- ers. The REMP could provide the framework for a management development program consisting of: (i) annual seminars for small groups of managers to discuss action planning, prioritization of operational and investment ac- tivities, and constraints on implementat.Ion of operational and investment plans; and (ii) training courses, including situational management, human resources management, investment planning and financial management, and - viii - distribution planning, to upgrade managerial skills. NE& will need to pro- vide the facilities and absorb the cost of managing this program; the en- sure that the related costs are recovered, NEA will need to charge appro- priate fees to participating RECs. Investment Strategy 23. In its early years, the rural electrification program was ori- ented towards expanding the distribution network outside the urban centers. The dominant issues in investment planning were the appropriate geographi- cal spread of network expansion and the pace for connectir.g villages and households. This approach, which was driven by (i) technical consider- ations, (ii) availability of finance, and (iii) implementation capacity, lent itself to quantitative planning methods primarily aimed at ensuring that the financial performance of the newly established RECs kept pace with investment. Over time, this planning approach gradually overlooked such increasingly important system requirements as maintenance and upgrading, intensification of connection density along existing lines, and service to non-residential consumers. 24. NEA changed its investment priorities in 1988 and embarked on a crash program of identifying the previously neglected rehabilitation and upgrading needs. However, this salutary effort can be sustained only if an investment evaluation and programming method based on economic criteria is put into place. Using such an approach confirms the intuitive view that rehabilitation is the highest investment priority, as indicated by rigorous analysis of alternative investment options which compete for scarce re- sources. As only marginal savings could be realized from changing design standards, the investment options are determined by the relative weight given to system improvement and expansion in the investment program. The results of sample feasibility studies conducted by NEU indicate that the highest priority should be accorded to rehabilitation/upgrading with simul- taneous addition of new connections in the rehabilitated parts of the net- work. Expansion is economically justified only when a large part of demand is provided by non-residential consumers such as medium and small industry. 25. These indicative priorities need to be translated into a con- sistent rural electrification investment plan and NEA lending program. Since establishing such a comprehensive planning and programming process in NEA and the RECs will take some time, indicative investment scenarios were developed to get this process started. Based on the priority for system improvement derived in the sample studies, two scenarios involving varia- tions in the pace of investment were examined: (i) a scenario based on a gradual increase in rehabilitation expenditure, and (ii) a second scenario based on a massive early rehabilitation effort. The first scenario even- tually rises to a higher level of annual expenditure as delayed rehabili- tation overlaps with increasing investment for expansion. Under both sce- narios, (i) system upgrading will take up most of the sector's funding and implementing capacity for the medium term, and (ii) considerable investment in expansion will have to be postponed to allow the distribution system to regain efficiency. In the early 1990s, when annual investment levels reach about P 1 billion, substantial new funds will have to be mobilized. In any - ix - case, the most important constraint affecting the level of future invest- ment appears to be the absorption capacity of NEA and the RECs. The most likely scenario, which involves aggregate investments of about 1 3.8 bil- lion during 1989-93, represents a best guess of NEAs absorption capacity. 26. During the early 1990s, assuming a redirection of NEA's invest- ment strategy, the proportion of rural population receiving electricity supply could rise from the present level of about 50X to about 651 by 1993/94. About half of the newly connected 700,000 to 800,000 consumers would be within easy reach of the existing grid, and would receive their connections through add-on investments; the remainder would receive elec- tricity as a result of judicious expansion into economically justifiable areas. From the mid-1990s onward, connecting the remaining 250,000 to 300,000 consumers that could be supplied economically through add-on in- vestments would increase coverage to about 701 of the rural population. However, given that the share of unconnected productive consumers must nec- essarily decline and the areas remaining to be electrified would become increasingly remote, the expansion investments that might increase penetra- tion significantly are likely to become more difficult to justify in eco- nomic terms. Even in the long term, penetration beyond about 75X of the rural population would appear difficult to justify economically, and would have to rely instead on social priorities (in which case, the economic cost would have to be absorbod). 27. The past preliferation of rural electrification in the Philip- pi.es occurred because of the emphasis that had been given to the social aspects of expanding the service. However, during the next five to ten years, the sector will be undergoing substantial restructuring (paras. 36 and 41-44). During this period, emphasis needs to be placed on addressing issues surrounding the needed restructuring while supporting investments that have prospects for an imminent favorable financial outcome and direct economic potential. Investments that are justified primarily on social grounds can be considered only sparingly before the late 1990s or early 2000s, and should be postponed until the current institutional problems have been remedied and the RECs have regained financial strength. Pricing Polic 28. NEA guides and monitors the RECs' rate setting activities. Rates are established according to a simple formula that includes the cost of power purchases (or own generation), REC operating costs, and debt ser- vice requirements. Current NPC bulk rates for REC purchases from the major grids are about P 0.5-1.0/kWh, resulting in an average retail rate for REC customers of about P 1-2/kWh. In isolated island RECs, where local genera- tion costs P 2.0-2.5/kWh, retail rates have averaged about P 4-5/kWh. Re- cently, NPC has agreed to take control of the generating facilities serv- ing those islands and charge those RECs a subsidized rate of P 1.30/kWh; in turn, the RECs would observe a retail rate ceiling of P 2.5/kWh. 29. In general, the existing formula does not encourage efficiency in consumption patterns, and does not provide for future investment. A move towards rates based on long-run marginal cost (LRMC) principles would - x - address both deficiencies. In 1987, the Government instructed NPC to de- velop LRMC-based bulk rates, and NPC is in the process of designing an ap- propriate pricing structuro. As the power purchase price forms a large element of the final REC retail price, the outcome of the NPC pricing anal- ysis will be an essential input into REC rate setting. The key issue in the structure of NPC rates is the differential in marginal cost between peak and off-peak periods of daily demand. To give clear signals to whole- sale consumers, NPC should introduce time-of-day pricing gradually, thus encouraging the shifting of price-elastic demand to off-peak periods. 30. The application of marginal-cosc principles to REC pricing is a logical extensicn of the improved NPC rate structure. During the evening hours, when NPC and REC peak periods overlap, the supply cost imposed by retail consumers is highest, amounting to about P 3/kWh in Luzon RECs with acceptable system loss levels; however, the corresponding off-peak costs would only be P 0.60-1.80/kWh. Large REC consumers such as industries could be billed on a time-of-day basis, according to this cost structure. Residential consumers, for whom average pricing is more suitable, would face a single rate, which would reflect the weighted costs imposed on the system by their pattern of consumption. On average, the RECs' revenue per kWh is likely to remaiui below the current ceiling of P 2.50 (assuming that they can keep their system losses at or below 20X), while the demand pat- tern would adjust to optimize the cost of supply. The report develops a rate formula which follows these principles. While the rate formula indi- cates substantial changes in the structure of rates to encourage more effi- cient utilization of electricity, efficient RECs would be realizing average revenues near their current rates. In many cases, industrial consumers would be paying less than or the same as current rates, while residential consumers might be paying as much as 10-15X more than they are currently. While the concept of time-of-day pr-cing is beneficial in the long run, it should be intreduced cautiously, observing consumer reactions at each grad- ual implementation step. If the concept yields efficiency benefits and is easy to administer, it should be implemented in full. 31. Electricity appears affordable to typical rural residential consumers. A simple cross-sectional analysis of price elasticity (ignoring income effects), as well as the responses to an NEA-conducted survey, indi- cate that consumer resistance to price increases only becomes strong at about P 2.50/kWh. The current share of expenditure for electricity amounts to about 10 of household income, while that for kerosene lighting is clos- er to 15X. Survey responses indicated that households would use electrici- ty to expand their lighting hours provided it cost no more than kerosene. In the minority of RECs that depend on high-cost isolated diesel genera- tion, any subsidization should be granted to the REC in a highly transpar- ent manner, showing the cost differential between retail rate ceilings and true supply costs. - xi - G. The Rural Electric Cooperatives 32. The RECs' problems do not result from their structure as coop- eratives. This conclusion is supported by (i) the mass failure in the ear- ly 1970s of investor owned utilities that served provincial cities and towns; (ii) the disinterest of investor-owned utilities or utility manage- ment companies in taking control of failing REC franchises; and (iii) the concentration of these failing REC franchises in areas where core systems are in severe disrepair and institutional problems are pervasive (as in central and southern Luzon), or where high self-generation and administra- tive costs undermine financial viability (as in the small, remote islar s of the Visayas). The RECs' operational and financial performance is more likely to be improved by launching programs to address the problems crip- pling the system rather than by creating a new organizational arrangement. 33. The major institutional problem shared by the most of the poor- ly performing RECs is the high degree of politicization of their Boards. Too often, tnose Boards and their members have become excessively involved in the REC's day-to-day affairs. This has resulted in abuse of perquisites and indications of corruption. While an elected Board representing the interests of consumer members is the fundamental characteristic of a coop- erative, the politicization of REC Boards and the resulting abuses indicate that, in those instances, the Board members are not accountable to their consumer members but rather to the political interests that supported their elections. To restore some accountability, existing legislation should be amended to provide that (i) a majority of REC Boards be composed of non- elected members, chosen either on an ex-officio basis or by appointment of ths NEA Administrator, and (ii) elected Board members serve a fixed term of two to four years, and thereafter be ineligible to serve the REC as a top officer. NEA's currently sound guidelines governing the conduct of REC Boards and their members need to be enforced through the use of condition- ality on future NEA loans to the RECs. 34. The subdivision of RECs, usually for reasons of political pa- tronage, has created clusters of RECs with franchise areas that cannot be served economically. Currently, some 25-30 RECs appear to have severely limited chances of ever becoming financially viable. Geography appears to be the most important constraint limiting their prospects for attaining viability. Virtually all of these RECs serve either remote, small islands, or sparsely populated mountainous areas with insurgency problems in Luzon, Mindanao, or Samar. The Government needs to consider adopting special pol- icies for supporting those R!SCs. Such policies could include excusing past loans that these RECs have virtually no chance of repaying, and using grants to finance economically-viable investments. 35. In conjunction with a program to restructure NPC, NEA received P 500 million in equity in August 1988; in turn, the funds were used to enable 21 RECs to refinance their significant arrearages to NPC. Under this Relending Program, 10 of the RECs retained their existing General Man- agers and Boards; for the other 11 RECs, NEA appointed new General Managers after the Boards agreed to be reduced to advisory bodies. Operations have improved significantly in the first group, but have continued to deterio- - xii - rate in the latter group. If NEA must exercise its authority to supplant a General Manager and/or disembody a Board, it should take that action as a receiver and not as a utility manager. In that capacity, NEA should ac- tively solicit proposals from all potentially interested parties - includ- ing adjacent RECs, investor owned utility management companies, and new groups from within the bankrupt REC's franchise area - for the future via- ble operation of that franchise. 36. While solutions to the RECs financial constraints can best be developed on a case-by-case basis, the following system-wide measures, which would have the effect of restructuring the RECs, would be generally beneficial and should be implemented as soon as practicable: (a) Even the most financially viable RECs are unable to generate sufficient revenues from operations to finance needed invest- ments. The RECs as a group are seriously undercapitalized and their scope for recapitalization is extremely limited. New consumers are required by law to pay only P 5 to join a REC, far below the cost to the REC of providing each consumer with service. As a result, membership-contributed capital in 198' represented just 0.2X of total REC assets. The Government needs to amend existing legislation to increase the membership fee to at least P 200 for all consumers. While this could in- crease the RECs' paid-in capital by an aggregate of about a 320 million by 1995, still other approaches to increasing the RECs' capital should be considered. Specifically, the Govern- ment should provide the RECs with relief from (i) loans for ex- tensions of service to uneconomic areas, alternative generation schemes, or social programs; and (ii) damage caused by natural disasters such as typhoons. (b) NEA should contain the proliferation of RECs by (i) curtailing the establishment of new RECs, (ii) reviewing the feasibility of consolidating adjacent RECs now participating in NEA's Re- lending Program, and (iii) developing incentives for well- functioning RECs to absorb adjacent REC franchises in receiver- ship. Such incentives could take the form of providing (i) special working capital loans, or (ii) grants to support needed economically justifiable investments aimed at revitaliz- ing the failing franchise. A broader consolidation program was considered and dropped for the time being out of concern that NEA could not enforce the dissolution of a REC that was not in receivership. A further factor now deterring consolidation is that the main criterion tor an effective consolidation is geo- graphical contiguity of service areas, and very few poor per- formers are contiguous to-good ones. (c) NEA should encourage needed institutional reforms through the use of conditionality in connection with future NEA loans to poorly performing RECs. NEA should consider supporting addi- tional investments for RECs that meet their targets for opera- tional and finarcial improvement, and might consider lending cash to RECs with a record of several years of good perform- ance. Alternatively, NEA should deny funding to poor perform- - xiii - ers that maIe insufficient effort to improve their operations, regardless of the priority of those RECs' planned investments. 37. An attempt by NEA to quantify the degree of managerial depth available to the cooperative system indicated that managerial ranks are thin, largely because of the low pay scales in effect at most RECs. These pay scales should be adjusted to enable the cooperatives to attract and retain sufficient numbers of qualified managers. HI The National Electriflcation Administration 38. Following the change of Government in 1986, many government agencies received special arsistance to restructure their operations, but no such assistance was extended to NEA. Despite this lack of Government support, in 1987-88, NEA's Board recruited an energetic new leadership team that appears capable and interested in providing the agency with an appro- priate focus. That team has already taken bold steps to streamline the staff and introduce efficiency measures. However, these measures by them- selves are not enough to make NEA function effectively as the sector's core agency. The organization needs a reorientation of its role and its vperat- ing perspectives, accompanied by a financial restructuring to put it on a "clean books' basis. NEA's Role 39. Given its weak performance during the last ten years, NEA's continued existence carmot be justified on the basis of its electrification activities alone. NPC can provide many, though not all, of the same ser- vices. However, NEA's lending activities are so specialized as to make compelling Jits continued functioning in that capacity. Its borrowers, the RECs, provide a service that is critical to the economic development of the areas within which they operate, yet few of them are financially viable and even fewer are credit worthy. Highly specialized technical support is needed to ensure that the formulated loans support feasible and appropriate projects, and the RECs develop into institutions that operate well enough to repay their loans. 'rhus, a core agency coordinating rural electrifica- tion through lending and technical support activities is essential to any institutional structure serving this sector. 40. NEA's difficulties have stemmed mainly from a lack of focus in its activities, and the previous Government's bent for asking NEA to exceed its institutional capabilities. Previously, however, when its direction was clear and its available resources were adequate, NEA performed effec- tively. Now, its Board and top management should reorient NEA to act pri- marily as an interested lender that provides support services aimed at as- sisting its borrowers on the path to credit worthiness. NEA currently has a staff of about 900 people who are providing many of those support ser- vices. These activities need to be supplemented with more focussed loan programming, credit analysis, and loan administration functions. Because NEA needs only to reorient its focus and supplement its existing staff, the e xiv - most effective approach to developing the needed core agency activities is to address NEA's weaknesses. 41. Over the years, NEA has acquired a number of side activities that were only peripherally related to rural electrification, or aimed at developing for the RECs supply alternatives to connection to the NPC grid. In its 1988 reorganization, NEA discontinued some of the more arcane of these activities; however, it continues to be involved in alternative gen- eration investments. NEA needs to restrict its business to providing fi- nance and technical support for the distribution utilities serving rural areas, and should divest itself of its other activities. 42. Despite its involvement in the energy sector, NEA is currently formally accountable to DENR, which cannot provide the technical support that NEA needs. To coordinate NEA's activities and investments with the rest of the energy sector, NEA has a seat on the ECC. Even so, a stronger interaction with the energy sector is needed. NEA should have the same reporting relationships as NPC, PNOC and OEA, the energy sector's main par- ticipants; this would mean bringing NEA directly under the Office of the President, and having it report to the Executive Secretary. 43. NEA also urgently needs to develop functional accountability over its activities. Although operating in both the electrification and the lending businesses with constrained resources, NEA has not previously had either formal ties to NPC or the outlook and accountability of a finan- cial institution. NPC can provide technical support for many of NEA's electrification planning and implementation functions. NEA should formal- ize its relationship with NPC by having the NPC president serve ex-officio as the NEA chairman, with the NEA Administrator assuming an ex-officio seat on NPC's Board. To ensure that NEA follows the policies of a financial intermediary, one seat on NEA's Board should be reserved for a senior bank- er, and a second for a senior official of the Department of Finance. Be- cause NEA currently lacks the staff needed to discharge its lending opera- tions and has only limited prospects for acquiring such expertise given its current pay scales, it should acqrire the expertise through a consulting arrangement with a major bank or financial institution. Financial Restructuring 44. NEA can hardly address the problems of the RECs while it is burdened with problems of its own that threaten to overwhelm the organiza- tion. Viewed as a commercial enterprise, NEA is insolvent. Accrued inter- est income, which is essentially NEA's only source of revenue, grew at an annual rate of about 151 during 1984-88; but interest expenses, which gen- erally account for about 75% of operating expenses, grew at an annual rate of 17% during the same period. Overall, NEA collects only about half of the amortization due from the RECs, and the default rate for its alterna- tive energy loans is nearly 100%. Since 1986, current liabilities (mainly advances from the Government) have exceeded current assets, and the gap is growing. A relevant restructuring program, which would put NEA on a "clean-books' basis, would include the major measures enumerated below. The progran to implement these measures will need to be framed in the con- - xv - text of when the Government, with its limited resources, can feasibly take responsibility for the liabilities from which NEA should be relieved. (a) Advances from the Gcvernment, aggregating P 3.3 billion, should be converted to equity. These obligations were accrued as the Government made debt service payments to foreign lenders that NEA could not otherwise have met during the past few years. (b) The Government should assume the impact of foreign exchange losses, aggregating about P 1.9 billion, on NEA's existing for- eign loan obligations. (c) Construction loans receivable due NRA from about 25 remote and/or self-generating RECs, amounting to about P 1.1 billion, should be written off; a corresponding amount of Government loans to NRA should be converted to equity. (d) NEA should divest itself of all assets and liabilities associ- ated with dendro thermal and mini-hydro generation. This in- cludes divestiture of substantial uninstalled inventory and removal of about P 791 million of dendro thermal loans and P 1.8 billion of mini-hydro loans from NEA's books. (e) NEA should divest itself of assets and liabilities associated with all social programs and other activities unrelated to electricity distribution (value to be determined). (f) NEA should reschedule all delinquent REC debts (principal and interest aggregating P 1 billion), based on feasible repayment terms. NEA should arrange a major loan monitoring and collec- tion effort. (g) P 150 million in deferred development costs, Government project costs and salaries and allowances of NEA staff posted to manage RECs should be expensed against current operations and the ac- counts used for their deferral should be closed. (h) NEA should turn its non-performing assets over to the Asset Privatization Trust, which should try to return to the Govern- ment whatever value can be realized from those assets. NEA's stronger balance sheet as a result of the proposed restructuring would enable it to be a magnet for increased official financial assistance; without restructuring, official sources of funds could only be attracted by the social appeal of rural electrification. Because many the loans from which NEA would be relieved under this restructuring program were raised in support of either (i) Government promoted system extensions into uneconomic areas, or (ii) Government sponsored social programs that were only margin- ally related to rural electrification, they should rightly be transferred to the Government for disposition. 45. This restructuring program involves a substantial outlay of public funds; in order that this be a one-time event that succeeds in revi- talizing the sector, the Government needs assurances that the RECs will - xvi - discontinue the practices that gave rise to their serious financial prob- lems. The effectiveness of the recommended meaaures presumes that the RECs will (i) curb their technical losses; (ii) take actions to identify and punish pilferers, and thereby reduce non-technical losses; (iii) imKrove their collection efficiency; (iv) revise their Drices to cover the full cost of providing service; and (v) gal on time for their power purchases and debt service. 46. The primary beneficiaries of the program will be the 25 poorly performing RECs with inherently poor financial prospects, which will bene- fit greatly by having past construction loans cancelled. The other major beneficiaries will be the 46 poorly performing RECs whose current distress results largely from mismanagement. Most of these latter RECs are cluster- ed in central and southern Luzon, and have franchise areas that provide favorable financial and economic prospects. To enable these prospects to be realized in the future, many of their delinquent loans will need to be rescheduled. All the poorly performing RECs should be required to earn their relief by formulating and agreeing to implement operational and fi- nancial improvement programs. Their progress in realizing agreed perform- ance targets should be monitored closely, and these RECs' eligibility for future loans from NEA should depend on their showing clear evidence of sus- tainable improvements in performance. Financing Strategy 47. The proposed restructuring is essentially a one-time measure with an immediate impact. To prevent a recurrence of its past problems, NEA will need to develop a financing strategy that, at once (i) provides finance on appropriate terms for economically justifiable projects, (ii) penalizes RECs that make insufficient effort to improve performance, and (iii) considers the special needs of RECs with structural constraints that limit their prospects for financial viability. 48. To keep its lending activities manageable, NEA should simplify its categories for lending and standardize its lending terms. In the fu- ture, it should limit its lending to support rehabilitation of rural net- works, add-on connections, economically justified system extensions, and working capital. While the bulk of its loans should be for the cash value of materials and equipment it provides to the RECs, it might consider lend- ing cash under special circumstances. 49. NEA should develop a basic interest rate pegged to its average cost of money plus a sufficient premium to cover its normal operations and the foreign exchange risk it expects to bear on future loans. A premium of about 2-3X should cover NEA's normal operations, while a premium of about 6-7% should cover the expected foreign exchange risk. The basic rate would guide NEA's pricing of all its loans. Also, the provisioning against the anticipated foreign exchange losses should be based on all NEA loans made under this financing strategy, not simply those with related foreign expo- sure, at least until an ample fund has been accumulated. Recently, in con- nection with a rural electrification project that it is financing, the United States Agency for International Development asked NEA to onlend at I - xvii - 12Z. In the current environment, that rate satisfies the criteria for the basic interest rate while being positive with respect to inflation and con- -s_tent with the opportunity cost of capital in the Philippines; therefore, it could serve as NEA's initial basic rate. The basic rate should be re- viewed annually, and the new rate fixed for all loans generated after com- pletion of the review. 50. NEA can provide incentives to the RECs through variations in the maturity and grace periods applied to individual loans. NEA's standard loans should carry grace periods of two years and maturities of ten years (these terms correspond to the construction period and depreciable lives of most distribution investments). However, maturities of more than ten years (perhaps as much as 20-25 years) could be applied to loans that suppc.t, directly or otherwise, (i) investments with higher than normal rates of return, (ii) agreed institutional improvement programs adopted by poor per- formers, or (iii) the sustained good perfonmance by the better RECs. 51. To accommodate the justifiable investment requirements of RECs without reasonable prospects for financial viability due to geographic con- straints, the Government should create a pool of grant funds that can be on-lent for 25-30 years at no interest but with a service charge of 1-2X (to cover NEA's costs). NEA could provide interest rate relief by blending loan and grant financings. Funding from this facility should be treated similarly to NEA's other loans. To qualify for financing from this pool, an REC would have to undertake a program to improve its operational and financial performance. To receive funds from this facility, the REC would need to agree to conditionality to (i) implement the performance enhance- ment program, and (ii) realize agreed periodic performance targets. 52. NEA should use its leverage as a lender to discourage chronic unsatisfactory performance in certain RECs. Performance targets could be included in loan conditionality. In the extreme, NEA could decide not to finance a particular poor performer, regardless of the priority of that REC's investment program. 53. Based on this financing strategy and financial projections de- veloped for NEA based on the alternative investment scenarios, NEA will need to finance some P 3.8 billion of investments between 1989-93. Of that amount, about P 1.6 billion will come from official financing that is ei- ther committed or at advanced stages of negotiations. Another P 1.7 bil- lion is expected to be provided through as yet unidentified official fin- ance. In addition, about P 0.5 billion will need to be provided by the Government as equity. This corresponds to the amount expected to be re- quired for (i) justifiable investments by RECs with limited prospects for commercial viability, and (ii) repair of networks damaged by typhoons. I - xviii - Organizational Improvements 54. Some of NEA's spotty performance can be attributed to organiza- tional weaknesses, including: (i) a lack of central coordination; (ii) in- adequate managerial compensation, making the retention of well-qualified managers very difficult; and (iii) a propensity to become involved in the day-to-day management of the RECs, thereby spreading thin its managerial and technical cadre. NEA should make three major organizational changes: (a) To coordinate the activities of its disparate units more effec- tively, it should establish a multi-disciplinary unit reporting directly to the Administrator that would be charged wtith apply- ing sound banking principles in the formulation and implementa- tion of a consistent medium-term lending program. While NEA has staff with some of the skills required by this unit, it lacks the requisite banking expertise; therefore, NEA will need to obtain this loan programming function on a consulting basis from a large bank or major financial institution. (b) Since NEA's pay scales follow directly from its classification as an infrastructure agency by the Department of Budget and Management, NEA should establish and fulfill the requirements for reclassification as a Government Financial Institution, a category with higher pay scales. (c) NEA should seek to minimize the time during which it must sec- ond its own staff to manage RECs by starting immediately after a takeover the process of identifying and transferring control of a REC to the group with the best long term plan for operat- ing it viably. 1. RURAL ELECTRIFICATION SECTOR OVERVIEW A. Introduction 1.1 In early 1988, the Bank undertook a study of the Philippine energy sector; that study (Report No. 7269-PH; September 15, 1988) recom- mended a broad strategy for resource allocation and utilization. Since then, the Government has indicated concern that some of the important bene- fits of that strategy might not be realized because of inefficiencies in the electricity distribution system, through which about 15X of total do- mestic available energy is consumed. The Government was particularly con- cerned about the impact of rapidly increasing distribution losses, which reached 251 by the end of 1987, on the US$7 billion investment program that was then being launched in electricity generation and transmission for 1989-96. The Bank has responded to the Government's concern by making a loan to finance a project to improve power distribution in and around Metro Manila (Loan 3084-PH, 1989). It also studied the condition of the rural electrification sector in February 1989. This report details the findings of that study. 1.2 In brief, the study confirmed that the rural electrification sector has major problems, including (i) poor operational performance, (ii) physical deterioration of core systems, and (iii) acute financial dis- tress among all the sector's institutions. The problems are so pervasive that they cannot be addressed by simple solutions. Rather, the Government will need to implement an integrated program to revitalize the sector, with the aim of (i) restructuring of the sector's core institution, the National Electrification Administration (NEA); (ii) considerably reorienting the organization, operations, and financial structure of the 117 Rural Electric Cooperatives (REC) that are responsible for distributing electricity to smaller urban centers, towns, villages and rural areas nationwide; and (iv) thoroughly refocussing the sector institutions' operational practices, investment priorities and pricing policy. 1.3 The recommended program for strengthening the rural electrifi- cation sector would provide an important stimulus for the continued econom- ic revitalization of the Philippines economy, which has undergone a dramat- ic turnaround since the mid-1980s. Following an economic decline during the early years of this decade, the reorientation since 1986 has stressed the primacy of efficiency, prudent macroeconomic management, a transition to market mechanisms, a reform of public enterprises, and a streamlining of public sector investment. While much already has been done to move forward in these areas, a large part of the reform agenda remains to be addressed. The next steps in the transition to efficiency-oriented management will in- clude (i) improving the level and composition of the public sector invest- ment program, focusing on appropriate priorities to sustain economic growth; (ii) upgrading the implementation capacity of public sector agen- cies; (iii) accelerating investment in rural development to encourage in- come growth outside of urban areas; and (iv) removing infrastructure bot- tlenecks to encourage productive investment and improve the delivery of services such as power supply. Such a reorientation is critically needed in the rural electrification sector, w'here strengthening the sector's weak institutions will enable issues of investment efficiency, rural develop- ment, and infrastructure improvement t.o be addressed vigorously. B. E^r- Swector Institutions 1.4 Before the change in Government in 1986, the Ministry of Energy coordinated all policies, plans and programs for the energy sector. The ministry served as the parent organization for two of the largest Govern- ment owned corporations: (i) the National Power Corporation (NPC), which had responsibility for power generation and transmission; and (ii) the Philippine National Oil Company (PNOC), which was responsible for assuring the adequacy of oil supplies and for development of indigenous energy re- sources. The National Electrification Administration (NE6), the organiza- tion responsible for formulating and implementing the Government's rural electrification policies, was under the control of the Ministry of Human Settlements, and not under the Ministry of Energy. 1.5 Following the change in Government in 1986, both the Ministry of Energy and the Ministry of Human Settlements were dissolved; all energy agencies as well as NEA were brought temporarily under the Office of the President. In mid-1987, the Office of Energy Affairs (OEA), which was giv- en responsibility for planning and coordinating policies and programs for the energy sector, was formally pla^ed under the Office of the President. At the same time, EPC and PNOC were brought under the formal control of the Office of the President while NEA was placed under the jurisdiction of the Department of Environ- e-nt and Natural Resources (DENR). Recently, to dev- elop formal linkages between the energy sector participants, the Government formed an Energy Coordinating Council (ECC) that would (i) be chaired by the Executive Secretary; (ii) have as members NPC, PNOC, and NEA; and (iii) have OEA acting as its Secretariat. 1.6 In its early stages, NPC was responsible only for hydropower development. The Manila Electric Company (MERALCO) generated most of the power for the Manila metropolitan area; power was supplied to provincial towns and rural areas by other privately-owned power companies and small municipal utilities. In 1971, NPC was given total responsibility for all power generation facilities nationwide as well as for the establishment of island power grids. This restructuring led to NPC's acquisition in 1979 of most of MERALCO's generating facilities. Electricity distribution in rural areas is handled by Rural Electric Cooperatives (REC). 1.7 Currently, NPC is responsible for all but very modest genera- tion facilities and most transmission systems nationwide. MERALCO is re- sponsible for distribution in Metro Manila and surrounding suburbs and ru- ral areas. Six privately-owned power companies provide distribution to the larger urban centers outside Manila. Distribution for the smaller urban centers and the rural areas is provided by 117 RECs. NUA is responsible for coordinating the activities of the RECs. -3- C. The Rural Electrfi0cation Program The Program's Origis 1.8 In June 1960, the Electrification Administration was created (Republic Act (RA] 2717) to carry out the Government's policy of providing cheap and dependable electric power for the country's agro-ir.dustrial de- velopment. Rural electrification of previously unenergized areas proceeded at a slow pace for the next seven years. In February 1967, using funds provided by the United States Agency for International Development (USAID) feasibility studies were conducted for two pilot rural electrification pro- grams: (i) to electrify eight towns in Misamis Oriental, and (ii) to elec- trify three towns in Negros Occidental. In June 1969 total electrification of the countryside on an area coverage basis was declared i national policy (RA 6038). At that time, only about 18X of the country's population was enjoying electric service. This Act also provided for the organization of Rural Electric Cooperatives to implement the electrification targets and operate the resultant networks, and converted the Electrification Adminis- tration into the National Electrification Administration. 1.9 NEA's charter gives it the twofold responsibilities of (i) co- ordinating implementation of the Government's total electrification policy, and (ii) supporting the RECs' efforts to achieve that total electrification objective. NEA is supposed to fulfill this latter responsibility by (i) providing technical support to the RECs; and (ii) financing their expansion programs with grants and long term loans. later Presidential Directives gave NEA the additional responsibilities of (i) supervising the RECs' tech- nical and managerial activities; (ii) regulating their electricity rates; and (iii) promoting implementation by the RECs of mini-hydro and dendro- thermal generating schemes. The Government also created within NEA various Special Project Offices that are responsible for integrated rural develop- ment programs unrelated to rural electrification. These programs included housing, water supply and livelihood projects. 1.10 In September 1971, the first REC, Misamis Oriental Electric Co- operative, Inc. (MORESCO) was energized. In August 1973, NEA became a cor- poration (Presidential Directive [PD] 269) and was provided initial capital stock of P 1 billion. Subsequent capital increases in 1978 (PD 1370) and 1979 (PD 1645) raised the authorized equity capital to P 5 billion. NEA orchestrated the growth of the system by functioning as a financial inter- mediary channeling the Government contributions or funds provided by donors to the RECs. Almost all the loan^ provided by NEA to any particular REC were for the peso value of materials procured by NEA on behalf of that REC. As such, the REC received goods and was credited with a loan liability; cash seldom flowed from NEA to an REC. Few, if any, sources of private sector finance were willing to lend to the RECs; as a result, they were re- quired to self generate the working capital needed for operations. As do- nor and Government funding for rural electrification appeared to be plenti- ful, the cooperative system expanded rapidly both through the construction of new distribution networks and the assumption of responsibility for - 4 existing facilities. The RECs acquired these existing core systems (mostly small, aging networks with 2400 volt primary distribution lines) from lo- cally-based, investor-owned power companies. 1.11 The cooperative system was cLosely modeled on the U.S. experi- ence. NEA itself was modeled, both in form and operation, on the Rural Electrification Administration. The RECs were organized and were supposed to be administered in much the same fashion as those in the United States. Also consistent with the U.S. model, the Philippine RECs established (in July 1979) the Federation of Electric Cooperatives of the Philippines (FECOPHIL) to serve as the umbrella organization representing their inter- ests. FECOPHIL's charter was closely based on that of the National Rural Electric Cooperative Association (NRECA), which had functioned as the lead consultant providing technical assistance under USAID financed projects. 1.12 The movement to use cooperarives to supply electricity to small urban centers and rural communities developed momentum in the early 1970s. During this early period, the RECs' service areas were defined to afford reasonable chances for technical and financial viability, and the decision to form an REC was generally prece' d by a thorough feasibility study. However, as the pace of expansion accelerated, the feasibility studies be- came more superficial. NEA did not focus significant attention on the day- to-day concerns of managing a rapidly expanding commercial organization; and, because of the long grace periods included in the terms of most NEA loans to the RECs, the financial implications of what was too ambitious an expansion program and the poor financial performance of the RECs were masked until the early 1980s. Annex 1.01 shows the number of consumers served by the RECs each year since 1974, and Annex 1.02 shows the year-by year formation of RECs. Current State of the Sector 1.13 Currently, 117 RECs are providing electricity throughout the entire country, except for franchise areas served by the investor-owned companies. About 22 of these RECs are considered to be well managed as well as financially viable; for another 24, financial viability is consid- ered within reach if they make some operational and commercial adjustments. The remaining 71 either have a pronounced need for substantial remedial action, or are considered beyond rescue. 1.14 The RECs' problems are both operational and financial. Chronic operational problems include excessive distribution losses, theft of elec- tricity, and inadequate maintenance. The RECs' poor standards of mainte- nance have led to a widespread physical deterioration of their networks; as a result, with technical losses averaging 17Z, most REC distribution sys- tems are operated at well be-low their design standards. The Government's past emphasis on growth of coverage without sufficient regard for cost, combined with its use of the RECs to implement costly and economically un- justifiable alternative generation and rural development programs, has sad- dled most of the RECs with debts they cannot pay, despite the heavy conces- sional element built into the instruments that were used to finance the sector's expansion. Generally, the RECs lack the skilled staff and equip- ment needed to improve their operational performance, and the burdens of past mistakes have weakened their prospects for improving their financial health. In many instances, the RECs' financial problems are directly re- lated to managerial weaknesses that have resulted from the interference in their internal affairs by highly politicized Boards of Directors. Even if the RECs as a group would be provided with financial relief, some 25-30 among them face limited future prospects owing to franchise areas that are inherently too costly to serve. 1.15 NEA has performed poorly as both a lender and a provider of rechnical support to the RECs. Although it has documented the RECs' opera- tional weaknesses, NEA has been unable to implement programs for improving their performance, partly because its already scanty technical staff has been spread too thin to perform its functions well. 1.16 The RECs are rural institutions that reflect the economic con- dition and financial health of their members; the economic constraints ex- perienced during last several years by the rural population has had an ad- verse impact on them. Given that its primary business is to act as finan- cier for the sector, NEA's financial condition must necessarily reflect the state of the RECs. The recession of 1983-86 weakened the RECs financially; in turn, that weakness resulted in NEA's realizing a collection efficiency of only 36X in both 1987 and 1988. In many instances, NEA promoted the measures that led to the RECs' uneconomic growth; therefore, not surpris- ingly, when the RECs are unable to meet their obligations on loans from NEA, NEA cannot meet its related obligations on the originating loans. In all, NEA has questionable prospects for meeting some P 7 billion of loans raised from foreign lenders and from the Government. Too often, NEA has lacked clear direction regarding the nature of its business. While its revenues accrue entirely from its lend'ng operations, it has viewed itself primarily as an electrification company. It has iulfilled a wide variety of roles, but it has not developed the primary functions of a financial intermediary, namely loati programming and credit evaluation. The or.-*.niza- tion's lack of a clear focus has inhibited it from acting as an effect.ve core agency for the sector. 1.17 Perhaps the sector's biggest problem is the participating in- stitutions' chronic lack of functional accountability. In the past, NEA has neither had (i) a mechanism to coordinate its activities with the rest of the energy sector, even though the RECs taken together form a substan- tial block of energy consumers, nor (ii) the outlook and accountability of a financial institution, even though lending and credit are essential ele- ments of its own financial health. Instead, NEA has either been account- able to political agencies, such as it was during 1979-86 to the former Ministry of Human Settlements, or to rural development agencies, such as it is currently to DENR. In that context, its staff has dispensed substantial capital without regard for the technical or financial requirements for cost recovery. The politicization of NEA created an environment that enabled the RECs to become politicized. Although NEA has sound rules governing the conduct and remuneration of REC Boards and individual directors, those rules are flaunted with equanimity. Available data suggest a high corre- lation between interference by Board members in the day-to-day activities of the RECs and poor management of those institutions. While the RECs are - 6 - in principle accountable to their consumer members, most RECs whose weak performance may be attributed to poor management show (i) little effort to develop member involvement and (ii) weak consumer relations. In effect, those Boards (and in turn their RECs) are accountable primarily to the po- litical interests that sponsored their elections. D. Issues Facing the Sector 1.18 To resolve the sector's problems, the issues enumerated In the following paragraphs must be addressed. The issues have been grouped ac- cording to whether their primary impact is on (i) sector operations, (ii) the RECs as irstitutions, or (iii) NEA's capacity to fulfill its responsibilities as the sector's core agency. Operations, Investment and Pricing 1.19 Poor ODerational Performance. As a result of the low priority accorded to operational matters, most RECs provide inefficient and unreli- able service; furthermore, they frequently provide electricity to rural consumers at excessive cost. Even the financially viable RECs have high rates of forced outages; however, operational problems are much more acute in the poorly performing RECs, where constrained cash flow for the proper maintenance of physical and human resources has resulted in the severe phy- sical deterioration of their networks. 1.20 Of the poorly performing RECs, some 25-30 have only marginal chances of ever attaining the financial viability needed to ensure imple- mentation of proper operational practices. Most of these RECs serve small remote islands in the Visayas; the remainder serve rugged mountainous areas with insurgency problems in Luzon, Mindanao, or Samar. Their inimical ge- ography and population sparsity, combined with their high cost of supply, limits their prospects. Another 41-46 RECs could become viable by taking substantial remedial action. Most of them are located in central and southern Luzon, and are characterized by (i) franchise areas with poten- tially favorable financial prospects, (ii) rapidly deteriorating core sys- tems, and (iii) politicized Boards and managements. 1.21 System Losses. With system losses averaging 25X nationwide, substantial amounts of expensive electricity are being wasted. System los- ses represent the second greatest 'use' of available energy. Specific Re- gions show different patterns of efficient operations and loss control. For example, the twelve RECs in Region 3 (Central Luzon) have system losses that averaged about 36X in 1987, making losses the predominant "use" of available electricity in those service areas. 1.22 Area Coverage Targets. The objective of the rural electrifica- tion program was to achieve total area coverage as rapidly as possible. Often, the RECs expanded their systems at the expense of major maintenance or the renewal of obsolescent core networks. Currently, the RECs serve somewhat more than 2.8 million consumers. Although the number of consumer - 7 - connections grew by more than 30X per year until 1980, this was not enough to meet the Government's original target of 901 area coverage by 1987. With the growth rate dropping since 1981, the target for achieving 901 electrification has had to be extended on several occasions. Currently. the Government's policy is to electrify 901 of rural areas by 1995. 1.23 This emphasis on area coverage has led NEA to support substan- tial investments in system expansion that were not economically justifi- able. The RECs met the cost of these investments either with cross-subsi- dies from productive loads in the same franchise areas, or by ignoring their related debt service payments to NUA. Despite the wide spread evi- dence of uneconomic investment and the resulting sector wide financial con- straints, NEA has still not developed appropriate criteria for investment decision-making. 1.24 Prioritization of Investments. NEA does not have a systematic strategy for programming investments by the REGs. Although a determined effort was made in 1988 to identify and prepare high-priority investments, this exercise was conducted in response to a perceived need to formulate a short-term investment strategy quickly. NEA still lacks a consistent stra- tegy and a sound methodology to establish national investment priorities. 1.25 Alternative Generation Programs. One striking example of the impact of inadequate investment screening is the substantial losses being incurred on account of uneconomic investments in alternative generation facilities. In October 1979, PD 1645 authorized NEA to develop indigenous and renewable energy sources, including specifically (i) mini-hydro gener- ating facilities of under 5 MW, and (ii) dendro thermal generation plants. Overall, 19 mini-hydro sites and 9 dendro thermal plants were either com- pleted or are still under construction. None of the completed dendro ther- mal plants are in operation todayV. Moreover, a large number of mini-hy- dro units, with an aggregate value of almost 0 1 billion, and nine dendro thermal units have not been installed and are in storage. Although, in 1988, NPC assumed responsibility for these facilities, the RECs are still obligated for the loans that financed these investments. At present, they are virtually in complete default to NEA in regard to these loan. In turn, NEA has been unable to service its debt related to these programs (para. 6.13). Annex 1.03 provides a brief summary of the operational aspects of the mini-hydro and dendro thermal programs. ' aie mini-hydro program's major problems included (i) inadequate technical planning, (ii) insufficient site investigation and (iii) unsatisfactory hy- drology. In addition, many of the sites chosen were aimed at serving areas already receiving electricity from the NPC grid. The dendro-thermal program envisaged growing trees on 1,000 acre sites over a five-year cycle. The ma- ture trees, when felled, were to be crushed into wood chips for burning in the boiler of a nearby power plant. The planting program did not produce the ex- pected number and quality of trees; the poor results were due to inadequate site preparation, lack of fertilizer, and generally careless farming. In ad- dition, the wood processing equipment was poorly operated and maintained, and the boilers were unable to burn the resultant output of chips. - 8 - 1.26 Pricing of Electricitv. Rural electric tariffs neither reflect the cost of supply nor influence consumers to optimize their utilization of electricity. NEA has developed and distributed a rate setting guideline that is based upon a simple average costing methodology. The resultant retail rates do not provide the RECs with sufficient cash for even routine maintenance and equipment overhauls, much less for the self financing of even minor amounts of system expansion. 1.27 Subsidies for Financially Weak RECs. RECs in remote areas, that must rely for their supplies on expensive self-generation, charge high rates (often in excess of P 4.00/kWh) that exceed the threshold of consumer affordability. Recently, the Government has decided to limit retail elec- tric tariffs to a maximum of P 2.50/kWh. To implement this policy, NPC is taking control of all generating facilities and lines energized at 69 kV and above, and will sell electricity to those RECs at a subsidized rate of P 1.30/kWh. In addition, a number of RECs will require direct subsidies to maintain their operations. NEA has computed the cost of this direct subsi- dy, which will be shared by NPC and NEA, at about P 50 million over the next five years. Fourteen self generating RECs are the beneficiaries of the direct subsidy program. The Rural Electric Cooperatives 1.28 Appropriateness of the Cooperative System. In 1988, as the outgrowth of a program to restructure NPC, NEA took control of the manage- ment of eleven RECs whose arrearages to NPC had reached intolerable levels so that the cutoff of electric service was imminent. In connection with the takeovers, the RECs' Boards of Directors were disembodied and the Gen- eral Managers were replaced. The failure of these cooperatives, the major- ity of which are located in some of the most prosperous rural areas of Cen- tral Luzon, raises questions about whether using cooperatives for providing electricity to rural areas of the Philippines is appropriate. If so, a major reorientation of the RECs appears urgently needed. 1.29 The RECs' Weak Financial Prospects. The RECs typically serve residential and small commercial consumers, most of whom take small amounts of electricity (often less than the amount covered by the minimum monthly charge) at low voltage. These consumers are expensive to serve and account for low revenues. Yet, even this modest revenue base has proven difficult to collect. At the same time, the RECs taken together account only for about 15X of NPC's sales. Thus, whether jointly or severally, the RECs have only limited leverage in their dealings with NPC, their principal sup- plier. In effect, the RECs are inherently weak institutions engaged in a business with weak financial prospects; and realizing even those weak pros- pects depends on the RECs (i) managing their operational, commercial, and financial affairs efficiently, and (ii) avoiding costly or non-optimal in- vestments that have only limited potential for acceptable economic returns. 1.30 The RECs Poor Financial Performance. The RECs financial per- formance has been extremely poor. In 1987, the cooperative system as a whole recorded a negative net margin of P 22 million. Certain REC account- ing policies are not consistent with generally accepted commercial prac- - 9 - tices; therefore, this figure most likely understates the RECs' financial losses. This poor performance has been recorded even though the RECs as a group are realizing very high mark-ups. In 1987, the average revenue for all the RECs was P 1.66/kWh, compared with an average cost of P 0.87/kWh for power purchases from NPC. 1.31 Proliferation and Politiclzation of the RECs. Following the first oil price shock in 1973, a spate of new RECs were formed to replace small private companies that had become non-viable because of their inabil- ity to recover the burgeoning cost of fuel. By 1976, the RECs became view- ed as organizations that provided political outreach to their leaders; and, the regime used REC directorships and management positions as patronage for political support. Until recently, RECs were repeatedly subdivided, there- by ballooning the number of these patronage opportunities. As the RECs became more politicized, financial viability and qtLality of service became less important. The National Electrification Administration 1.32 NEA's Role. NEA has a spotty record as the sector's core agen- cy. Since its nception, NEA has lacked clear direction regarding its role. The relevant statutes cast NEA in the diverse and occasionally mutu- ally exclusive roles of (i) policy maker, (ii) borrower of hard loans, (iii) lender to a marginal clientele, (iv) implementor of network expansion programs, (v) executor of alternative generation programs, (vi) promoter of rural development social programs, (vii) investment planner, (viii) pro- curement agency, (ix) electrification consultant, capable of providing ex- pertise regarding investment, construction, operations, maintenance, pric- ing, and finance, (x) regulator of a fragmented industry, and (xi) utility manager. Moreover, while NEA has always been accountable to political agencies, it has never been functionally accountable. 1.33 NSA's Financial Weakness. Although NEA is charged with earning a profit, the organization currently has an cumulative deficit and is proj- ecting to continue operating at a loss or at break even through 1991. NEA has experienced or is forecasting that its loan collection efficiency of only 36% for 1987 and 1988 will improve only to 52X in 1989. As a result, NEA's cash flow is not adequate to meet its operating requirements; unless NEA is restructured, it will need continuing Government financial commit- ments to enable repayment of outstanding foreign loans. 1.34 Financing Strategv for the Sector. During the period 1989-92, NEA plans to channel up to about US$200 million to the RECs for investment. Currently, the Government and NEA lack a clear financing strategy for the sector. That strategy needs to resolve the following existing gaps: (i) measures for restructuring the sector's institutions; (ii) criteria and instruments for lending; (iii) lending terms; (iv) use of conditionality; (v) measures for addressing foreign exchange risk; and (vi) special poli- cies to accommodate the investment needs of inherently weak RECs. 1.35 Loan Programming. NEA currently lacks an effective loan pro- gramming function; and, as a result, its management lacks the tools for - 10 - coordinating NEA's diverse activities. NEA's approach to loan programming has involved (i) using money that could be obtained from the Government to make sizeable purchases of materials and equipment, and then (ii) appor- tioning those purchases to the RECs, either to meet an agreed new connec- tion target or to reward Boards and managers for political support. Only rudimentary credit analyses were performed. NEA has neither placed empha- sis on developing and implementing a medium-term lending program, nor on applying sound banking principles in formulating loans. Even if NEA would wish to upgrade its loan programming activity, its staff lacks the needed banking and credit expertise; and it cannot attract the requisite number of suitably qualified people given its current pay scales. E. A Revitalization Program 1.36 Najor reforms in the sector are urgently needed. Addressing problems that are so pervasive requires an integrated program that will at once (i) introduce proper operational practices and appropriate investment strategies, and (ii) develop strong sector institutions. The development of such a program is the focus of the remainder of this report. 1.37 The first focus of the program must be on operations and in- vestment, so as to determine (i) the requiremer.ts for restoring the net- works to their original design standards and (ii) the parameters of an af- fordable investment program. These parts of the program must be comple- mented by the development and adoption of sound gricing principles, so that the RECs may optimize recovery of their costs from revenues. Programs to restructure and strenzthen the kECs and NEA must necessarily follow after the requirements of operational and investment reform have been estab- lished. Because neither the RECs nor NEA can concentrate effectively on their future responsibilities as long as they are burdened with unmeetable obligations accruing from past uneconomic policies, the institutional strengthening components of the program must necessarily include measures for the financial restructuring of these organizations. To ensure that the benefits of restructuring remain effective in the long term, NEA will need to develop and implement a financing strategy that (i) encourages the RECs to invest in high-return projects and adopt proper operational practices and pricing principles, and (ii) discourages them from failing to meet ob- ligations to their creditors and their consumers. Finally, any reform of the RECs and NEA must necessarily include provisions for developing functional accountability within each of the organizations while also tak- ing account of the realistic constraints they face. 1.38 The ensuing chapters of this report follow this sequence in developing the logical underpinnings for recommendations that, when taken together, provide the needed integrated program. The program is necessari- ly comprehensive, and the Government may have difficulties implementing its features simultaneously. For that reason, allovance was made in developing the recommendations for their gradual implementation. Even if implemented gradually, this program should provide substantial economic benefits and financial savings in the process of revitalizing a highly troubled sector. - 11 . 2. OPERATIONAL EFICIENCY A. Introduction 2.1 Originally, the Government intended that RECs would be formed to provide service in previously non-electrified areas; in those cases, which were mostly in the Visayas and Mindanao, core supply networks were usually technically sound and the operating systems were usually well de- signed and implemented. After the first oil price shock in the mid-1970s, however, a number of RECs were created to take over the franchises of nu- merous operators (mostly serving small urban centers in central and south- ern Luzon) that had failed, and extend their service to oatlying areas. These inherited networks were often old, with substandard core systems. NEA was responsible for financing the return of those core systems to de- sign standards and ensuring that these RECs had adequate qualified staff to operate and maintain properly the assets being absorbed. This mandate to rehabilitate decaying core systems was inconsistent with NEA's primary ob- jective of mobilizing all available resources to extend area coverage, and thus was largely ignored. As a result, many core systems, especially older ones that had belonged to failed franchisees, fell deeper into disrepair. 2.2 Beginning iu the early 1980s and becoming more pronounced after 1983, as funds for expansion became more scarce and the political pressure to add new connections remained strong, the rechnical standards were in- creasingly compromised in the construction of additions to networks. Con- temporaneously, as political pressure mounted to hold down tariffs in the face of mounting constituent costs for electricity, maintenance standards were also increasingly compromised. Major repairs, such as are often need- ed following typhoons, were usually flimsy patchworks that made best use of available materials and equipment; as newly received materials had to be channeled to expansion projects, the patchworks were seldom replaced by permanent installations. 2.3 Since 1983, the quality of rural electric service has declined sharply. Technical losses have iuscreased, as have instances of downed or obstructed lines and outages related to overloading of substations. With a few notable exceptions, the performance of the individual RECs has also declined sharply. This decline has affected all aspects of their opera- tions, including, inter alia, construction standards, supply continuity, network main_enance, control of operating costs, revenue collection, techn- ical losses, and pilferage of electricity. However, because the basic sys- tems and the extensions that were built in the 1970s were well designed and structurally sound, NEA and the RECs can still arrest this decline if as- sistance is made available and the problem is addressed urgently. - 12 - 2.4 This report makes many recommendations. This chapter develops recommendations aimed at improving operational performanceV; the next two chapters focus on resolving issues concerned with investment planning and pricing. Taken together, these recommendations provide the operational component of a revitalization program for the sector. While this study ad- dresses these issues in the aggregate, to ensure that these diverse activ- ities are properly coordinated and to translate this extensive program into a management plan for each REC, a comprehensive Rural Electrification Mas- ter Plan (REMP) is needed to provide a detailed framework within which (i) specific improvement measures can be formulated, taking into account realistic constraints on available financing, and (ii) operational perform- ance can be measured against realistic technical and financial targets. B. The Rural Electric System Technical Characteristics of the System 2.5 The rural distribution network follows a 60 cycle, 4-wire, mul- ti-grounded WYE design that is almost identical to the standard developed for the rural electrification system in the United States by the Rural Electrification Administration (REA); the major differences are that the Philippines uses 7,620/13,200-volt primary voltage levels (compared to 7,200/12,470 volts in the U.S.) and 240 volt/2-wire secondary systems (com- pared to the 120-240 volt/3-wire system in the U.S.). The basic design of the networks is sound and appropriate, with the major systemic flaw being an underestimation of the need for lightning arresters and voltage regula- tors. U.S. consultants provided good construction and operations manuals and supervised the correct implementation of the recommended techniques in the early years. Until the early 1980s, electricity service and supply continuity standards were generally good, and continue to be satisfactory in a majority of RECs. 2.6 Except for RECs in remote locations, the rural network is sup- plied by NPC at about 250 69-kV grid substations. NPC constructed the sub- stations, which are owned and operated by the RECs. Meters at the substa- tions are placed on the primary side of the transformers. The distribution I/ The measures being recommended fall into categories identified as (i) major maintenance, (ii) system improvement, and (iii) rehabilitation. Major mainte- nance involves activities to keep systems that are operating at design stan- dard in good repair. Expenditures for major maintenance should be budgeted and financed from on-going revenues. System improvement is performed on sys- tems currently operating at or near design standard, to enable them to meet expected increases in demand from existing consumers, or growth in the number of connections. Expenditures for system improvement require capital alloca- tions, but the cost should be quickly recoverable from the resultant incremen- tal revenues. Rehabilitation is needed to restore a system to design stand- ard. Those expenditures will need capital allocations and external financing, and the costs can only be recovered from the total consumer base over five to ten years. - 13 - networks consist of about 65,000 km of lines, including about 46,000 km of primary lines and about 19,000 km of secondary lines. The RECs also own and operate about 900 km of 69-kV lines (the standard NPC subtransmission voltage). A summary of line lengths is given in Table 2.1 and an analysis of line lengths by Region is provided in Annex 2.01. The RECs in central and southern Luzon that assumed control over the operations of failed pre- decessors acquired extensive non-standard networks. While some rewiring has taken place, the system still includes some 1,900 km of non-standard line. This remnant can and should be replaced. Table 2.1: LENGTH OF LINE BY DESIGN PARAMETER (000 km) 3 Phase 3 Phase 1 Phase 4-Wire 3-Wire 2-Wire Secondary Total Standard RE lines 19.1 5.9 19.8 18.4 63.2 Non-standard RE lines .6 .2 .4 .6 1.8 (2.4, 4.16 and 4.8 kV) TOTAL 19.7 6.1 20.2 19.0 65.0 2.7 Each of the RECs supplies an average of 24,000 consumer mem- bers, with an average of 40 consumers for each distribution transformer. Annex 2.02 summarizes Regional differences in consumer density. Each sub- station serves an average of two to three feeder lines. The design parame- ters for system protection are basic and inexpensive, and consist of re- closers on feeders and fuses on all branches. This low cost approach re- sults in some problems of coordination of rural network protection with protection measures used in the NPC transmission system. The design stan- dard provides for the use of self-protected, single-phase distribution transformers that range in size from 5 to 100 kVa. Wooden poles are used throughout the system and the standard for conductor is steel-reinforced aluminum. As the Philippines does not have any indigenous manufacturing or repair capacity, virtually all this material is imported. Technical Losses 2.8 The original rural electrification system in the Philippines was designed for a 12-13X range of technical losses based on a 5-year load forecast (Annex 2.03); this closely followed the REA design. The level of technical losses should decrease as the load increases, assuming implemen- tation of effective maintenance and planned system improvements. In the U.S., where the system is generally operated and maintained as designed, technical losses declined from 12X to 8X; however, in the Philippines they increased to an average of 171 - and, in some RECs, technical losses exceed 201. These high technical losses result from overloaded lines and. trans- formers, poor line connections, cracked insulators, poorly maintained elec- - 14 - trical and mechanical equipment and poor service connections. In addition, because necessary rights-of-way were not obtained during construction of lines, -che RECs cannot cut and prune trees to the degree required; as a result, inadequate clearance of trees is a major cause of technical losses. Recommendation 2.9 Considerable gains can be realized from a program to reduce technical losses, principally because much of the system was well con- ceived, designed, and constructed; years of neglect can therefore still be reversed. Reduction of technical losses will require a combination of mea- sures including, among other things, (i) system improvements, including upgrading power supply or increasing the capacity of line transformers where technical losses are high due to overloaded networks; (ii) improved maintenance that focusses on clearing trees (para. 2.16) from lines (alter- natively, poles might be reconfigured where existing rights of way do not permit adequate clearance of trees)V; and (iii) rehabilitation of non- standard core systems or poorly maintained networks (paras. 2.33-2.35). Technical losses due to design factors are discussed further in Annex 2.03. 2.10 With such measures, technical losses could be reduced by 4.5X. This would imply an annual cost saving of about P 1.4 million per REC, or about P 0.62 million per substation and feeder network. Reducing technical losses would also result in derivative benefits for the RECs, including: Mi) increased local system capacity, and (ii) improved supply continuity; both of these benefits would lead to improved quality of service. The fi- nancial impact of these derivative benefits cannot be computed directly; however, if the average REC manages to sell the increments of energy that are saved, it could realize additional revenues of about P 1 million per year (based on current rates), or about P 0.4 million per year per substa- tion and feeder network. Alternatively, it would save the cost of purchas- ing from NPC unsold amount of the energy that was saved. The cost of the system improvement measures (para. 2.9) is not likely to exceed about P 3 million per substation and feeder network (in most cases, the cost would be notably less). The cost of improved maintenance measures should not be incremental, but rather should be borne through improved efficiency. Where rehabilitation is required, the cost should be related to added reve- nues from incremental demand, and not to savings from reduced losses. Therefore the incremental cost of reducing technical losses should be cov- ered by savings in recurrent costs or enhanced revenues from existing de- mand within two years. & As necessary, tree clearing programs should take account of environmental considerations. - 15 - C. Operation and Maintenance 2.11 As with construction, operation and maintenance standards for rural networks were based on REA practices, and training courses were pro- vided during the 1970s to demonstrate correct procedures to REC staff. Over the years, these procedures gradually fell into disuse in the majority of RECs. Currently, network ^peration and maintenance is performed by the RECs on an ad hoc basis, with inadequately trained staff using inadequate materials, tools and transport. Less than 50X of the original staff who attended the early training courses on operation and maintenance till re- main with the RECs. The original supply of operation and maintenance tools has also been depleted. Test equipment was left unrepaired, safety equip- ment became unworkable, and when the original vehicles finally stopped working, they were never replaced. The RECs must now rely on public trans- port to move crews and materiais, which is expensive and inefficient. 2.12 The years of neglect and poor maintenance have left the network in poor working order. Field inspections conducted at over 50% of the RECs during a 1986-89 survey by USAID-financed consultants found that about 10l of the distribution system was well maintained, 25X was satisfactorily maintained, 35X was unsatisfactorily maintained, and the remaining 30% showed no sign of having received maintenance (Annex 2.04). The causes cited for poor maintenance included (i) lack of finance, (ii) shortages of materials, and (iii) managerial inattention to maintenance. The most com- mon problems ate rotting poles, broken crossarms, conductor sagging, bad connections, broken insulators, missing hardware, broken reclosers, fuses, lightning arresters, and other safety equipment, cut or missing ground wires, unsafe service drops, and defective meters. 2.13 In general, distribution systems require a combination of oper- ational and planned maintenance. Operational maintenance includes such ongoing activities as semi-annual line patrols and monthly inspection of all meter installations in the course of routine meter-reading and check- reading. Planned maintenance programs are normally developed from: (i) operation and maintenance reports, (ii) guidelines for priority plant maintenance, and for equipment such as reclosers, transformers, lightning arresters, and (iii) the physical condition of the network. 2.14 Table 2.2 compares the maintenance requirements of U.S. RECsV, which are generally well-managed and operate systems similar to those in the Philippines, with those of their Philippine counterparts. The perform- ance of the U.S. REGs indicates that the expected trend in well-managed distribution systems is for planned maintenance to increase gradually rela- tive to forced maintenance and the total cost of operations per unit sold to decrease gradually. In the Philippines, the trend is in the opposite ai As the U.S. RECs are generally efficient, well operated and profitable, this comparison may appear unfair to the Philippine RECs; however, since the Philippine rural electrification systems were designed according to the U.S. model, the comparison essentially relates the performance of the Philippine systems to their design standards. - 16 - direction and will contintue to worsen unless improved operation and mainte- nance procedures are adopted. Table 2.2: COMPARISON OF MAINTENANCE REQUIREMENTS (U.S. and Philippine RECs) U.S. RECs U.S. RECs Phil. RECs Phil. RECs After After After After 5 Years 10 Years 5 Years 10 Years (Percent of Operation and Maintenance Expenses) Operations 70% 50% - 30% Planned Maintenance 20% 35X - 20% Forced Maintenance 10% 15X - 50X O&M Cost as X of Kevenue 5.8X 4.41 5.2X 6.2% Recomeneldation 2.15 Three critical maintenance needs have been identified for the Philippines: (i) clearance of trees, (ii) treatment of poles, and (iii) re- pair of damaged equipment and tools. Remedies for these problems, which are common to many rural electrification systems, could account for about 501 to 701 of the cost of a planned maintenance program. 2.16 Tree clearing and pole treatment programs (Annex 2.05) are cen- tral to a sound annual maintenance plan. These programs are likely to cost. about US$7.5 million annually for the system as a whole (although only about US$5 million are incremental costs for the RECs), and should include specific work plans and budgets for each REC. A failure to implement these programs will lead to further serious deterioration of the network and con- tinuing unacceptably low supply continuity and service standards. 2.17 A recent survey indicates that equipment and tools with a re- placement value of over US$5 million are lying idle in REC stores, and that inoperable network equipment of even greater value is awaiting repair. NEA is acutely aware of this problem and is arranging to establish seven stra- tegically located zonal repair centers to serve the repair, major mainte- nance, and spare parts needs of the RECs (Annex 2.06). 2.18 As the sector's core agency, NEA urgently needs to develop and implement national policies, standards and planning systems for planned and operational maintenance. In that context, NEA will need to help the RECs prepare budgets and work programs for major maintenance. NEA would then need to ensure, possibly as a condition of lending to an REC, that it (i) has developed a sound program of major maintenance, (ii) has arranged to make available from revenues funds sufficient to implement the program (in the near term, when substantial major maintenance is needed to reverse years of neglect, NEA may wish to make some loans for this purpose to RECs - 17 - that cannot raise sufficient tariff revenues to cover these requirements), and (iii) is implementing properly and consistently the agreed major main- tenance program. Programs for planned maintenance should cover only core systems that are operating at or close to design standards; otherwise, re- habilitation must be done first. Since NEA may not have sufficient numbers of qualified staff to plan and supervise the RECs' implementation of such a comprehensive maintenance program, NPC, which has a direct interest in min- imizing the REC8' inefficiency, should assist NEA by seconding staff to supplement NEA's capabilities, and taking responsibility for the field mon- itoring of the RECs' maintenance efforts. D. Commercial Practices 2.19 In the early 1970s, with assistance from U.S. consultants, NEA provided all RECs with operational and training manuals outlining the com- mercial policies, guidelines and piocedures that were to be followed. Spe- cific guidelines were provided for meter reading and billing, collection, disconnection, penalties for reconnection, membership in a REC, and rights- of-way. The policy also specified the basis for pricing. Over the years, the RECs have become slack about implementing the commercial procedures so that, currently, only about 10 of the RECs run their commercial activities effectively. The causes of this deterioration in commercial performance include: 'i) weak REC management which failed to accord necessary priority to billing, collection and related activities; (ii) insufficient funds to provide and maintain the equipment needed for commercial efficiency; (iii) shortages of functioning meters, resulting in substandard metering, looping of services and unmetered supplies; (iv) local political and social pressures to forgive the delinquency of consumers capable of mustering ex- ternal support: and (v) seasonality of incomes, particularly among farmers, who fall into arrears during the lean months on the promise that they will repay after they sell their wares. At present, financial losses from inef- ficient commercial practices could be as high in value as 8X of energy sold. Arrearage Levels 2.20 The total annual revenue from rural consumers is P 4.0 billion, which averages about P 34 million per REC. The average percentage alloca- tion of revenues among consumer categories is shown in Table 2.3; these percentages vary significantly among RECs, especially for those in remote islands and in central and southern Luzon. - 18 Table 2.3, ALLOCATION OF REC REVENUES AMONG CONSUMER CATEGORIES (X) Consumer Niseellaneous Categories Residential Industrial Commercial Public Lighting, etc Contribution to Aggregate REC 40 30 18 12 Revenues (X) 2.21 The average level of accounts receivable is about 27X of total revenue (averaging about 3.2 months, or 100 days sales). While residential consumers are responsible for nearly 70% of outstanding bills, the monetary value of residential arrears is only about 35X of the total. Por the bal- ance: (i) local and national government bodies account for about 28X of the monetary value of arrears; (ii) large commercial ard industrial consumers account for about 301, and (iii) other consumers for the remaining 71. While this mix varies among the RECs, a relatively small number of govern- ment and business establishments account for the bulk of arrearages. Industrial Consumption 2.22 Currently, a number of large industrial consumers that take power at high voltage are supplied directly by NPC. These consumers prefer this arrangement because of (i) a desire to pay for electricity at the low- er rates charged by NPC, (ii) a concern that NPC's service is more reliable than that offered by the RECs; and (iii) a reluctance of some among them to face bills that they still have outstanding with the local REC, going back to the period prior to their direct connection with NPC. As indicated in Table 2.4, NPC now directly provides about 401 of the total energy supplied to industrial consumers. Tablg 24; SUPPLIERS OF ENERGY TO INDUSTRIAL CONSUMERS (MWh by Area) Private Area RECs Utilities NPC Luzon 80,312 15,703 78,023 Visayas 29,040 26,600 30,244 Mindanao 62.955 48.000 127.651 TOTALS 172,307 100,303 235,918 - 19 - 2.23 In most other countries, the usual practice is that all consum- ers are supplied by the distribution authorities except those requiring supplies at voltage levels higher than the highest distribution voltage. Some technical factors that would influence this choice are: (i) size of load; (ii) nature of load (e.g., continuous process manufacture); (iii) quality of supply requirements (e.g., the need for supplies to be free of harmonics); (iv) security considerations; and (v) the capital cost requirements of alternative arrangements. Recommendations 2.24 For large consumers, NEA and NPC should develop technically- based policy guidelines concerning the supply of large consumersV. Such guidelines would need to balance the critical importance of protecting the integrity of the RECs' franchise areas against the capability of the RECs to provide industrial consumers with reliable supply at reasonable cost. Where industrial consumers who are directly connected to NPG have arrears outstanding to their local RECs, NPC should arrange to collect a surcharge that would be used to settle those consumers' accounts with the RECs. 2.25 More generally, since the basic commercial systems that the RECs originally implemented are sound, NEA should now arrange to update these guidelines, particularly their coverage of procedures for revenue collection, including meter reading, billing, disconnection, penalties for reconnection, and electricity theft. Each REC should be provided with a mini-computer to process the data developed through the new systems, and with training in the procedures, hardware and software provided1. At the same time, the biases that undermine the ability and desire of REC managers to strengthen their commercia operations will also need to be addressed, presumably through conditionality to be attached to future NEA loans to the RECs. The experience of those RECs that have been performing well has in- dicated a close correlation between effective collections and heightened member involvement. In effect, the members police themselves and bring peer pressure to bear on the larger consumers. Therefore, special arrange- ments might be made to foster the growth of group accounts such as Barangay Power Associations (BAPA) (Annex 2.07). Moreover, mamber outreach programs are also needed to demonstrate the interrelationship between effective rev- enue collection and service standards, operating costs, electricity prices and employment conditions. In this regard, programs such as pre-paid stamps g The Government approved Policy Reforms in the Power Sector already provides that direct connections for industry shall continue until such time as "the appropriate regulatory board determines that the direct connection of industry to NPC is no longer necessary in the franchise area of the specific utility or cooperative." Therefore, the Government's inter-agency committee on technical and financial indicators and standards of performance, where both NEA and NPC are represented, can develop the needed policy guidelines. I/ In cases where an REC has a very small market, the benefits of computeriz- ing billing and collections should be weighed against the likely cost of the equipment, software and training. - 20 - and raffles with prizes could be used as part of a national communication effort to raise the level of public awareness of these issues. L Non-Technical Losses Levels of Non-Technical Losses 2.26 The average level of losses per REC is 25% (Annex 2.08), or about 700 GWh/year in the aggregate. For the average REC, technical losses are estimated at about 17% with non-technical losses accounting for the balance of 8%; however, non-technical losses of as much as 20% have been recorded in the worst cases, most of which are located in Luzon. 2.27 A detailed analysis of the causes of non-technical losses is provided in Annex 2.09, and can be summarized as: (i) utility staff collu- sion with consumers, (ii) consumer interference with meters, (iii) direct tapping of lines, (iv) faulty metering, and (v) unmetered supplies. Be- cause consumer meters are in short supply, a large number of consumers have unmetered supplies and others have been permitted to provide their own me- ters. Furthermore, the standard follo-ad for metering of large industrial and commercial consumers (those who use current-transformers) is not of sufficiently high. These practices all result in unrecorded consumption; although the resultant non-technical losses caused by these practices are difficult to estimate accurately, the magnitude is significant. Recommendation 2.28 Experience in other countries shows that the most effective strategy for reducing non-technical losses is a combination of management action, customer awareness and technical changes. The major elements of a non-technical loss-reduction program would include: (i) effective national legislation providing for the prosecution of pilferers based on circumstan- tial evidence and prescribing stiff penalties, judicial and financial, for offenders; (ii) continuous surveillance of lines by special monitoring units composed of full-time staff with their own transport; (iii) replace- ment of all "A" base type meters; (iv) sealing of all socket-type meters; (v) programs for on-site meter testing, replacement and recalibration to be implemented on an ongoing basis, (vi) rewiring of all sub-standard major industrial and commercial meters, with regular semi-annual and spot checks of all such installations, (vii) installing of check meters on distribution transformers, and (viii) replacing of low-grade service connections rith concentric cable. 2.29 Existing laws concerning pilferage of electricity are extremely weak. They place an excessive burden of proof on the utility or REC seek- ing redress; and, even when applied successfully, face the miscreant with only minor penalties. Currently, the Congrcss is considering several pro- posed bills to enhance the capability of utilities and RECs to pursue pil- ferers and to increase the penalties for those who are convicted. NEA should support strongly the rapid adoption of the strongest of these bills. - 21 - 2.30 Generally, the cooperative approach has been found to be the most effective institutional arrangement for reducing electricity theft; in some RECs in the Philippines, consumer involvement, resulting in a combina- tion of a group climate and peer pressure, has been effective in supporting afforts to minimize pilferage. The RECs should place a much higher priori- ty on consumer involvement to encourage their consumer-members to police themselves. Consumer awareness of the problem could be improved by greater REC outreach through the use of newsletters, newspaper articles and adver- tisements, radio programs, and local television appearances and advertise- ments. These measures cost very little and have the capacity to provide substantial savings. They also provide the basis for deeper accountability of the RECs to their corsumer-members. 2.31 Some RECs have made effective use of group accounts, with me- ters installed on individual transformers. Drives to form these group ac- counts, known as Barangay Power Associations (BAPA) (Annex 2.07), have been well received especially in the farming areas. Where the BAPA movement has been successful, non-technical losses have been more effectively con- trolled. The approach has a number of important advantages, including (i) providing single-point connections for many consumers, thereby reducing billing costs; (ii) shifting responsibility for all losses in the secondary system to the BAPA; (iii) monitoring the transformer load; (iv) providing a social grouping in the BAPA; and (v) providing the BAPA with a small income for use on community projects. The estimated cost of a more widesoread program of transformer metering is estimated at about US$100,000 per REC or US$40,000 per substation and feeder network; potential savings per fee costs of base-load equipment, which would meet off-peak demand. Using this method- ology, the calculations for Luzon indicate that a pure LRMC-based tariff would yield a range of rates between P 0.97-1.86/kWh (Annex 4.01), compared with a current average price range of P 0.96-1.08/kWh. The greater breadth of the range reflects the differences in cost of serving the varied con- sumption patterns of NPC's consumers. According to these calculations, the Luzon RECs would be subject to rates ranging from P 1.02/kwh to P 1.46 kWh. 4.7 An analysis of NPC's LRMC, taking into account peak and off- peak costs of supply, is presented in Annex 4.02. Based on using gas tur- bines to provide peaking capacity for the Luzon grid, this analysis results in the costs shown in Table 4.1: Table .1:. NPC's CALCULATION OF LRMC FOR THE LUZON GRID CaRacitX Cost Energy Cost (P/KW/year) (P/kWh) Peak Off-peak Average At generation 1,285 1.00 0.53 0.60 At extra-high voltage 1,570 1.00 0.53 0.60 At very high voltage 1,960 1.02 0.54 0.61 At high voltage 2,190 1.07 0.57 0.61 At medium voltage 2,440 1.14 0.60 0.68 4.8 Electricity demand in the Philippines does not appear to be subject to significant seasonal fluctuations, except for Luzon. In the Luzon Grid, seasonal peaking does occur during the hot season, and probably reflects the growing air-conditioning load. This seasonal peaking in Luzon would likely lead, with the calculation and use of loss-of-load probabil- ities, to a higher marginal cost for summer day peaks (7:00 to 23:00 hours) - 43 - than for the winter daily peak periods (same time range). However, for simplicity, this refinement was not considered and all peak periods are assessed as having the same marginal cost of supply. C. LRMC-Based Wholesae Pricing 4.9 Based on the LRMC structure derived for the Luzon grid, the theoretical bulk electricity price to the RECs is calculated in detail in Annex 4.03 and summarized in Table 4.2: Table 4.2. THEORETICAL ELECTRICITY COST TO THE RECs Peak Period Off-Peak Average (A/k1Wh) (0VkWh) (1/kWh) At 81 discount rate 1.56 0.52 1.05 At 12X discount rate 1.72 0.52 1.12 These estimates lie within the range of the cost-based rate previously cal- culated by NPC. The main difference results from the proposed introduction of differentiation by time of day. 4.10 NPC should move cautiously to introduce time-of-day (TOD) rates as soon as possible. In terms of hardware, such a move requires only that NPC introduce TOD metering for its major customers. However, since the principle of TOD pricing has not yet been accepted by Philippine consumers, NPC should move in this direction by introducing much smaller peak/off-peak price differentials than what would be justified purely on the basis of marginal cost considerations. After one to two years experience with this smaller differential, assessments and further adjustments could be made. 4.11 In addition to TOD differentials, electric rates should clearly reflect differential supply costs. This means that cost differences for supplying different voltage levels should be reflected in NPC's rate struc- ture. In the case of the RECs, their bulk rate would need to reflect the additional costs of (i) the downward steps from 230 kV (NPC's transmission voltage) to 69 kV (the level at which the RECs take their supplies); and (ii) transmission at 115 kV and 69 kV to the substations where the RECs take their power. 4.12 TOD rates that are based on daily peaking in demand and the cost of supplying the peak should encourage customers - especially indus- trial and commercial customers - to shift electricity usage to off-peak times where feasible. As a result, a firm peak that cannot be shifted through inducements will be established. Of equal importance, TOD rates could provide incentive for developing technology to enable consumers to shift their electricity usage for certain productive activities to off-peak periods. - 44 - 4.13 The application of marginal cost principles for rate setting in the grids outside Luzon is possible by using similar calculations. The sources of additional capacity needed to meet marginal requirements in the other grids are similar to those contemplated for the Luzon grid. At the margin, therefore, supply costs are likely to be similar nationwide, al- though average costs may differ. D. REC Cost of Supply 4.14 The average price paid in 1987 for REC-supplied electricity varied from as little as D 0.87/kWh to as much as P 5.31/kWh. Some of this variation was due to differences in the cost of electric generation. Most RECs purchased power from NPC at rates that varied from a low of about P 0.57/kWh in the Mindanao grid to somewhat over P 1.00 kWh in most other grids. Some RECs generated their own power at reported costs as high as P 2.30 to P 2.40/kWh. While some questions regarding whether the RECs op- erated their generating facilities efficiently have arisen, the issue be- came moot when NPC agreed to take responsibility for power generation na- tionwide. Under the new arrangement, if the inefficiencies in power supply cannot be reduced, they should at least be standardized. Once the average price paid for electricity by each REC has been rationalized through the application of LRMC-based NPC tariffs, the remaining spread to cover other costs still exhibits very large variations among different RECs. For some RECs, the current mark-up to cover distribution and customer costs is as low as P 0.49-P 0.51/kWh. For others, the current spread is as high as P 2.66-P 2.91/kWh. Admittedly, some RECs face costs that others do not; however, the breadth of the variations in these spreads is not justifiable within a system of efficiently operating RECs. 4.15 Case studies were conducted for the Tarlac II, Pelco I, Leyte V and Capiz I RECs to test inter alia the economic viability of their reha- bilitation and expansion investment programs. In all of these cases, load forecasts projected increased peak loads. Rehabilitation by itself does not stimulate increased peak demand, and so its costs are removed from in- vestment expenditures in computing an REC's cost of supply. Investments for expansion include some cost for actually connecting additional custom- ers and therefore these costs should also be excluded from investment ex- penditure when computing an REC's cost of supply. For each of the case studies, appropriate adjustments were made. 4.16 Table 4.3, which is based on the more detailed calculations shown in Annex 4.04, summarizes the marginal cost calculations applicable to the four case studies. Column 3 gives the off-peak marginal cost of electricity, which is basically the NPC rate adjusted for system losses in the range of 15X. Column 4 shows the synthesized marginal cost of new REC distribution capacity (SMCC) for the peak period and column 5 gives the total peak period marginal cost (derived by adding the energy cost from column 3 to the SMCC in column 4). Column 6 shows the average cost of ca- pacity per kWh sold. Finally in column 7, total average cost is the sum of the average capacity cost and the off-peak marginal cost (column 3). - 45 - Table 4.3: MARGINAL AND AVERAGE COSTS FOR CASE STUDY RECs (Based on NPC Using Average Cost Pricing) (1) (2) (3) (4) (5) (6) (7) NO. UTILITY CAPACITY ENEE;Y 8 TOTAL CAPACITY TOTAL (#/KW) COST (/RWNW) PEMK WV AVG. COSTA' AVG. COSTV (FA/) (U.KMh) (U/Wh) (0/Kh) 1. TARLAC II 2148.7 1.29 1.68 2.97 .8795 2.17 Excluding Rehabilitation .84 2.13 .4397 1.73 2. PELCO I 708.27 1.32 .55 1.87 .187 1.51 3. LEYTE VI 2503.6 1.29 1.96 3.25 .813 2.10 Excluding Rehabilitation .98 2.27 .406 1.70 4. CAPIZ I 496.07 1.25 .39 1.64 .161 1.42 11 SCC - Synthesized Marginal Capacity Cost 2/ Mc - Marginmal Cost 3/ AVG. COST - Average Cost Al For Tarlac II and Leyte V, the second line of figures represents the capacity costs after re- moval of costs unrelated to marginal capacity increases. 4.17 If NPC adopts full marginal cost pricing, the cost of energy to the REC will differ markedly from present rates. To illustrate the impli- cations for a REC, complete marginal costs were calculated for Tarlac II. Table 4.4 shows the results of this exercise. The actual rates charged by Tarlac II in March 1988 were in the range P 1.74-P 1.81/kWh. These actual rates are within the range of the average cost rates calculated in Table 4.3; however, they are well below marginal cost when the peak period for NPC and the REC coincide, and well above marginal cost when the off-peak periods of the two entities coincide. Table 4.4: MARGINAL COST PRICES FOR TARIAC II (P/kWh) (Based on NPC Charging Marginal Cost) Time Period Etirgy Price Adj. for SMCCI1 Total from NPC 15X Losses Tarlac II MC2G NPC Peak Period 7:00-17:00 Daily 1.56 1.83 0.0 1.83 NPC & REC Peak Period 17:00-23:00 Daily 1.56 1.83 1.68 3.51 to .84 to 2.67 Off-Peak 23:00-7:00 Daily .52 .61 0 .61 / SMCC - Synthesized Marginal Capacity Cost ~/ MNC - Marginal Cost NOTE: As of March 1988, tk-. electric rates charged by Tarlac II were: (i) Residential, P 1.78/kWh; (ii) Commercial, P 1.81/kWh; and In- dustrial, P 1.74/kWh - 46 - EL A Possible Rate Fonrula 4.18 The major weaknesses of the current pricing guidelines being followed by the RECs include: (a) The guidelines do not contain an explicit provision to enable the RECs to generate revenues sufficient to recover their in- vestment in distribution system assets. (b) Prices, particularly for large consumers, do not reflect the variations in marginal cost of supplying electricity at differ- ing voltage levels, times-of-day, and (in Luzon) seasons. (c) The guidelines do not address the administrative efficiency issues that have led to substantial differences in internal costs per kWh among the RECs. (d) The guidelines do not address problems of pilferage, politici- zation, and poor management that have fostered system losses in excess of 20X in about 70 RECs. 4.19 Efficient guidelines require that the following data be collec- ted and calculated for each REC: (a) All system investments need to be segregated into two categor- ies: (i) those that are sensitive to peak demand, and (ii) those that are unrelated to peak demand. The latter cate- gory clearly includes inter alia such distribution system com- ponents as (i) meters, (iij drop lines to consumer premises, and (iii) the smallest sized power lines and transformers. The remaining investment should be categorized as investments that are sensitive to peak demand. (b) System investments that are sensitive to peak demand should be valued on a replacement or current value basis. (c) A real cost of capital [r] needs to be identified for the REC. - 47 - (d) A carrying charge rate [CCR] must then be calculated based on the cost of capital and the life expectancy of the investments that are sensitive to peak demand. This carrying charge rate is then used to convert the investment [I1 to an annualized amount, which is then divided by the increased paak capacity made possible by the investment [MCm,J. Next, a coincident load factor [LFJ1 for the customer category under consideration needs to be determined, and the number of peak hours during the year [Hp.) is calculated. A synthesized marginal cost of ca- pacity [SMCC] can then be calculated. 1 CCR (r.-infl) (----------------------1 1 - ( (l+infl)/(l+r8) )T (rr) (-------------------) (approximation) 1 _ l/(l+r,)T MC,>,- CCR * I 8,760 hours - HPK + HpK SMCC - MCI/ (LFC * HPK) where infl - the rate of inflation r,- the nominal rate of interest or cost of capital rr the real cost of capital T - life of the investment (e) Then, the marginal prices for energy PE1] from NPC can be ad- justed to reflect REC system losses [L1 and a set of margir¶l energy prices developed for use in defining TOD marginal cost- based rates. MPI E PE/(l+L) MPPK MPE + SMCC Marginal Cost Electric Rates at Peak (PK) and Off-Peak (OPK) MPOPK - MPE - 48 - (f) For residential and other small consumers for whom metering costs do not justify TOD marginal cost rates, an average price for electric power needs to be developed. The easiest approach would be to complete the above steps and calculations, using the appropriate co:.ncident load factor for the new consumer group (e.g., residetntial consumers). The percentage of kWh consumption pertaiiing to the consumer group that falls in the various costing periods could then be computed and used to weight the different marginal prices in deriving a cost-based average price [AP]. MPPK * HPK + MPOPK HOPK AP - ----- __. 8,760 8,760 (g) The existing guidelines for pricing include a provision to re- cover the cost of interest on loans. The proposed approach makes this provision unnecessary as it focusses on the collec- tion of revenues sufficient to recover the REC's investment in its distribution system, thus providing for future investment including financing costs. A numerical example is provided in Annex 4.05. 4.20 The application of the proposed pricing formula in setting REC rates will involve rate changes that would be determined on a case-by-case basis. Some RECs may retain their rates at present levels, while others may need to make adjustments upwards or downwards. Whether NPC actually introduces marginal cost-based rates - and if so, at what pace - will have an important impact on the future level of retail rates. 4.21 The case of Tarlac II provides an example for the Luzon grid of the relationship between the approach NPC takes in applying marginal cost pricing and an REC's application of the proposed pricing formula to derive residential rates (para. 4.17). If NPC implements average-cost pricing with appropriate adjustments from the present price (to about P 1.30/kWh), and the REC applies the proposed pricing formula, then the average of the various REC charges would be roughly compatible with the current average calculated cost. However, the rate for a re3idential consumer with the bulk of consumption at system peak would be close to P 2.00/kWh, as compar- ed to the present rate of P 1.78/kWh. Assuming that NPC implements full marginal cost pricing with TOD differentiation immediately and also that the REC applies the proposed formula, the average of the various REC char- ges is still about equivalent to current average rates. However, in this scenario, the residential consumer would pay closer to P 2.50/kWh, as he would bear both the NPC and REC peak costs. A third scenario, which as- sumes that NPC does not change its bulk rate to the REC but that the REC applies the proposed formula, would result in a decrease in the average REC rate; but the residential consumer would continue to pay at th,e current rate level and bear the REC's peak cost. The smoothest transition to more efficient rate structures, therefore, would appear to be a gradual move of NPC to marginal cost-based rates, combined with an adoption of the proposed formula by the RECs. - 49 - F. Operating and Customer-Related Costs 4.22 Apart from consumption-related costs, the RECs incur costs at- tributable to the connection and administration of individual consumer ac- counts. Some of these costs are captured by the existing indicators for assessing the financial performance of the RECs, which are presented in Table 4.5: Table 4.5: PERFORMANCE INDICATORS FOR THE RECs Financial Indicator Standard Actual Calculation Method (a) Cost of Power 50% - 65% Average Power Cost Operating Revenue Average Price (b) Operatin& ExDense 5% - 7% Average Operating Cost Operating Revenue Average Price (c) Maintenance Expense 5% - 8% Average Maintenance Cost Operating Revenue Average Price (d) Cons. Acct. Expense 3% - 5% Average Customer Expense Operating Revenue Average Price (e) Adm. & Gen. Expense 10% - 15% Average Adm & Gen Expense Operating Revenue Average Price (f) Total Operating Exn 90% - 95% Average Ogerating Exp Operating Revenue Average Price (g) Net Margin 5% - 10% 1.0 - (f) 4.23 These indicators may yield somewhat misleading results because of the effect of scaling cost information by the average selling price of electricity. Whereas the average cost per kWh for an item would reveal any abnormal differences from a standard, the ratio of this cost to the selling price may not. For example, where the average price is high, the ratio of average administrative and general expenses per kWh to average price may not be large. Annex 4.06 presents comparisons indicating precisely this result. In the extreme case of Masbate, administrative expenses per kWh are P 0.90 kWh, well above the average; in contrast, scaled according to average price, the ratio is 0.19, or only somewhat higher than the desir- able range. This latter ratio is in fact lower than the corresponding fig- ure for Camarines Sur I; even though the administrative expenses per kWh for Camarines Sur I (P 0.375/kWh) is almost one third of that for Masbate. 4.24 Clearly, customer account expenses xiould be compared on a per customer basis, and operations and maintenance expenses should be consid- ered per km of line. At the same time, NEA should try to identify the pro- - 50 - portion of administrative and general expenses that varies with number of customers and the proportions that might vary with kWh sales and other characteristics of REC operations. Appropriate scaling of these costs would lead to an improved basis for cost comparison. Customer costs and administrative expenses that are related to the number of customers served by the system should not be included in pricing on a per kWh basis; rather, they should be covered as part of a fixed charge on customer's bills. 4.25 The following paragraphs attempt to evaluate cost components not directly attributable to sales volume. For purposes of analysis, and to eliminate the direct effect of system losses on efficIency, a sample of 47 RECs were identified based on the single criterion that energy losses were less than 20X in 1987 (Annex 4.07). 4.26 Comparison of administrative expenses on a per customer basis shows that a reasonable number of RECs are keeping these expenses within a narrow range. In a number of cases, administrative costs per customer are low when, at the same time, those same costs per kWh are high. In these cases, the RECs' price of electricity is also high, and the consequent kWh usage per customer is low; this leads to a high ratio of administrative costs per kWh, even though these expenses would be modest on a per customer basis. To avoid misleading judgments, performance indicators should mea- sure administrative costs on a per consumer basis. 4.27 The current variation in the difference between the price paid by consumers and the sum of (i) energy and (ii) operation and maintenance expenses per kWh appears unjustifiably large. Only in some cases does the difference reflect the extent of the customer and administrative costs; in many other cases, that difference is not related to identifiable overhead expenditures. Preliminary estimates indicate that, for an efficient REC with about 20,000 consumers, the spread over the cost of purchasing energy from NPC (adjusted for cooperative losses) needed by the REC should be about 9 0.50. A spread on that order should be sufficient to provide the REC with revenue to cover all of its expenses, including an allowance for recovering the cost of its investment in the distribution system. In a number of RECs, the members are already paying a price that approximates the cost of purchasing power from NPC plus P 0.50. Other RECs, however, show an unexplained spread that is much larger, and may be attributable to either special circumstances or Z. ...-ciency (Annex 4.07). 4.28 NEA has proposed (November 27, 1987) some standards for REC ex- penses, which are shown in Table 4.6: Table 4.6: STANDARDS FOR REC EXPENSES Category of Expense Proposed Standard Distribution Expenses: a 112 - P 168 per km. of line Customer Account Expenses P 4.80 to P 7.20 per customer Administrative and General Expenses P 0.089 kWh to P 0.276 per kWh, depending on sales range - 51 - 4.29 Annex 4.07 indicates that, in many cases, the RECs' costs are outside the standards shown in Table 4.6. In 30 of 47 cases, actual cus- tomer account expenses exceed 0 7.20 per customer; and, in 10 of the 47 RECs, those expenses are below the range given in the standards. In addi- tion, administrative and general expenses per kWh in 15 of the 47 RECs ex- ceed the upper end of the range given in the standards. NEA should (i) fo- cus carefully on a thorough evaluation of the RECs' customer-related and other administrative costs, and establish clearly monitorable benchmarks for costs per consumer and costs per km of line; and (ii) introduce a fixed charge per consumer to recover costs not directly attributable to sales volume. G. Other Prilcing Issues Affordability and Price Elasticity 4.30 A pricing pQlicy cannot be developed without considering the likely response of consumers to pricing decisions. When the pricing policy involves reflecting in the rate structure the higher cost of serving peak usage, the response of large consumers comprising the peak needs to be con- sidered. Peak-load pricing based on marginal costs could, if implemented at the projected prices, lead to a reduction in peak demand; in some cases, peak-load pricing could lead to some shifting of the peak. The same seiple of 47 RECs was used to investigate these issues. Annex 4:08 presents the information collected for these RECs on (i) number of customers, (ii) kWh consumption, (iii) per customer kWh consumption, and (iv) price paid. In addition, system peak data were also collected for the 40 RECs (out of the 47) for which such data were available. 4.31 The relationships between (i) price and per customer kWh con- sumption and (ii) price and peak demand, indicate that peak demand is more price elastic than average kWh usage. This result implies that cost-based TOD rates should initially be implemented only gradually. Customer respon- ses should be monitored and the marginal cost analysis repeated. Several iterations of this process might be needed before stabilization is reached. 4.32 The analysis here did not include data on income levels, which would explain some of the variation in electricity consumption. However, a rough estimate of price elasticity indicates that electricity demand appears to be related to price levels. The rate levels at which customer usage begins to increase significantly can be observed easily from the results of the analysis illustrated in Annex 4.08. This level appears to lie at around P 2.50/kWh. At prices below this range, consumption increases strongly. Therefore, at current REC rate levels, electricity appears to be affordable to the average rural consumer. 4.33 In a sample consumer survey conducted by NEA, households with- out electricity were found to spend typically about P 60 per month for ker- osene for lighting, and a further P 30 per month for purchases and repairs of kerosene lighting equipment. In comparison, the typical monthly elec- - 52 - tricity bill for a rural household is about 1 20-60. Only higher-income households with electric appliances incur bills of more than P 100 per month. If the annuitized cost of housewiring is added to the cost of elec- tricity, the total cost of power use amounts to about P 50-90, somewhat below the cost of kerosene lighting. Both forms of lighting cost a Luzon farmer about 9-14% of average annual income, with electricity at the cheap- er end of the range. Respondents in the survey indicated longer lighting hours with electricity as compared to kerosene, a reflection of the cost incurred. On the whole, affordability of electricity supply appears to be an issue only at the lower margin of the income range of current consumers, as long as the inefficiencies of poorly perfo-rming RECs do not push rates beyond levels where consumer resistance begins to be felt. Pilferage 4.34 Penalties that would induce consumers to help the REC police losses due to pilferage should be included in the tariff. Two alternative approaches to this problem might be considered. Both itnvolve installing meters at the transformer to record actual electricity supply to each sec- tion of the REC's service area. If metered electric supply, adjusted for expected line losses, were to exceed reported electric usage by all consum- ers down the line, the REC might introduce a fixed charge (identified as a temporary rate adjustment) to recover from all customers in that section the cost of lost power. The customers in the section would be advised that if they could police or otherwise identify the pilferers - thereby signifi- cantly reducing the pilferage - the fixed charge would disappear. Alterna- tively, rates (fixed charge or marginal price) could be adjusted automati- cally to recover expected pilferage; if pilferage were reduced below the recovered level, the consumers could receive a discount or rebste on sub- sequent bills. Regulation 4.35 The implementation, monitoring, and regulation of the proposed pricing principles for the RECs require, even more so than the current guidelines, specialized knowledge and administrative methods that are sub- stantially different from those used in the regulation of orthodox private sector rate setting. The non-profit nature of the RECs combined with the ma:-_nalist approach to pricing call for regulation by an authority which is intimately involved in rural electrification, such as NEA. This contra- venes the current proposal to transfer all regulatory responsibility for the RECs from NEA to ERM. A full transfer of the regulation over REC pric- ing would burden ERB with a large number of small and frequent rate ceses, and would require that ERB adopt a "two-track' approach to rate regulation; one methodology would be applicable to the private utilities, while a sec- ond different methodology would be applied to REC pricing. Instead, NEA should retain the responsibility for day-to-day REC regulation and ERB should audit and supervise NEA's regulatory activities. This combined ap- proach would ensure the consistent application of energy sector regulatory principles, while the detailed evaluation of REC rates would be performed by NEA, the authority with the comparative advantage. - 53 - 4.36 From NEA's perspective, intensive supervision of the principles and practice of REC rate setting is an essential element of its core func- tion as an "interested lender" for rural distribution systems. This func- tion implies that NEA should have an ongoing interaction regarding the full scope of REC activities, including operations, investment planning, cost recovery, and financing requirements. The monitoring of retail pricing and the guiding of REC price levels and structures are integral parts of NEA's role as the agency responsible for ensuring that scarce investment funds are channelled into economically viable rural electric investments. H. Summazy of Pricing Principles 4.37 Based on the cost and price analyses conducted, a number of pricing principles that would encourage efficiency can be developed. For wholesale pricing by NPC, the following principles should be considered: (a) Implement LRMC pricing on a TOD basis nationwide. (b) For Luzon, consider seasonal pricing using loss-of-load proba- bilities to associate marginal costs with pricing periods. (c) Move in stages to marginal cost prices. Evaluate a partial ad- justment to such prices after receiving the results of a year's experience. Rework the marginal cost analysis to project the target for marginal cost prices. If full marginal cost prices cannot be implemented fully, prices should at least reflect differences in marginal costs - such as differentiating between pricing periods and service voltage levels. (d) Avoid subsidized prices where possible. If subsidies are need- ed, they should be transparent transfers and not tied to pric- ing. If prices must be subsidized, the real price should be quoted and the subsidized price should be treated as a tempo- rary adjustment to the real price. In the case of currently subsidized island RECs, any temporary subsidy of this kind could involve a form of inverted bulk rate schedule (the life- line rate concept). Specifically, the price per kWh for a ba- sic block of consumption should be reduced. The price for all additional consumption should then be set at the marginal cost or full price. Optimally, however, the subsidy should be in the form of a lump sum transfer to the REC to cover the gap between the true cost of supply and the retail rate ceiling. - 54 - 4.38 The RECs should observe the following pricing principles: (a) Marginal cost-based pric6s should be developed for commercial and industrial consumers. A capacity charge (related to kg) and a consumption charge (related to kWh) should be developed to recover sales volume related costs, while customer related costs should be recovered through a fixed charge. The RECs appear to have a demand peak from around 5 p.m. until 11 p.m. each day. This demand peak establishes and drives each REC's distribution capacity. Since distribution capacity must be designed to meet the peak demand, investment costs should be associated with the peak period - leading to a capacity charge and a marginal price for the peak period that is higher than for other costing periods. At the same time, NPC's marginal cost pricing of electricity to the RECs should lead to prices that are different based on the time-of-day and, in Luzon, on the season. REC prices should reflect these rate differences where possible, especially for large commercial and industrial customers where the benefits of TOD metering justify the costs. In Luzon, seasonal rate differences could be reflected in rates for all customers, as no additional metering would be required. (b) Adjustment toward marginal cost pricing should take place in stages. A first step might involve the use of simple temporary formulae, introducing price differences of about 20-40X to re- flect the higher costs of providing supplies at lower service voltage levels or during peak periods. The extent to which customers would respond to rate changes and peak switching would occur needs to be ascertained before rate differentials become too substantial. The experience of each tariff ad- justment needs to be monitored and evaluated after a reasonable period of time. After the evaluation, marginal costs should be recalculated and pricing targets reviewed. Throughout this process, whatever formulae are used should be kept as simple as possible to enable the RECs to apply them effectively. (c) As LRMC prices are unlikely to be economically implemented for residential consumers, an appropriate strategy of average cost pricing should be designed. This involves (i) developing a fair value for the REC's investment in its distribution system, (ii) selecting an appropriate discount rate, (iii) calculating a carrying charge, (iv) annualizing distribution system invest- ment costs, and (v) spreading these costs together with other operating and power purchase costs over kWh usage. Selecting a discount rate and determining an appropriate, annualized dis- tribution system investment costs introduce a cost component for enabling the REC to recover the cost of its investments. - 55 - (d) Customer account costs and administrative and general expenses should be delinked from kWh sales. Customer account costs and some administrative and general expenses do not vary with kWh sales. These costs and any investment expenditures for consum- er connections, such as metering and drop lines to meters, should be recovered through a fixed monthly or bi-monthly con- sumer charge. (e) REC consumers should not be penalized because the REC is being run inefficiently. The available data for the sample of RECs that have low system losses indicates that their costs per kWh or per customer vary widely from one REC to the next. A seri- ous review is needed to determine acceptable ranges for these costs and remedial procedures to correct sizeable deviations from those acceptable ranges. (f) Pilferage should be discouraged by introducing group metering with penalties for exceeding reasonable loss levels. (g) The day-to-day activities of regulating the RECs should remain with NEA, and ERB could exercise general supervision over the process. - 57 - 5. THE RURAL ELECTRIC COOPERATIVES A. Itroduction 5.1 The RECs cannot be viewed as an electricity distribution mono- lith. The character and performance of the RECs differ greatly from region to region; even within a region, the individual RECs differ markedly from one another. In addition, the performance of RECs in the three major geo- graphic areas - Luzon, the Visayas, and Mindanao - show clear differences. 5.2 Many RECs face financial constraints that have given rise to or exacerbated a host of operational and institutional problems. On the oper- ational side, system losses currently account for 25% of power available for distribution in rural areas and are the second largest "consumer" of REC-supplied electricity (Annex 5.01). The institutional problems include: (i) politicization of REC Board members and general managers; (ii) a short- age of skilled, motivated REC gene-al and line managers; (iii) inadequate will to enforce collection of bills or to disconnect non-paying customers; and (iv) pressure to tolerate pilferage of electricity. Past studies con- ducted by NEA suggest that these institutional problems are most pervasive among the Luzon RECs; this conclusion was confirmed by field studies under- taken by consultants for USAID. RECs in certain areas also suffer some serious environmental problems, most notably periodic, devastating ty- phoons. The havoc they wreak is exacerbated by the lack of funds to re- build damaged systems. This is particularly true among the RECs in south- ern Luzon and in the Visayas. 5.3 Although efforts were made in the early years to provide the RECs with rational franchise areas that had similar prospects for growth, economic development favored certain locales; moreover, the subdivision of RECs for reasons of political patronage created clusters of irrationally defined RECs from what had previously been rational franchises. Thus, the RECs range in size from the Central Pangasinan Electric Cooperative in Luzon, with 77,000 consumers, to the Siargao Electric Cooperative in Ninda- nao, with just 414 consumers. Annex 5.02 ranks the 25 largest and smallest RECs, classified according to the number of customers. Where the RECs ei- ther serve customel bases that are too small or franchise areas that were not developed according to rational financial or economic criteria, pros- pects for profitable operations are poor. - 58 - B. Financial Condition Aggregate Financial Results 5.4 In the aggregate, the RECs are in a highly precarious financial condition. For the year ended December 31, 1987, the RECs recorded aggre- gate net financial losses totalling P 21.6 million (Annex 5.03) and cumu- lative deficits P 472 million. If the RECs had used certain accepted com- mercial accounting practicesl1, their performance would have been worse. When considered in the aggregate, the problem of financial losses appears pervasive; however, an analysis of data for individual RECs indicates that a minority of RE*s with excessively poor financial performance contribute disproportionately to the combined financial losses. Annex 5.04 provides a complete listing of the 1987 net results, shown in inverse order of per- formance for those 114 RECs that reported their 1987 operating results to NEA. As the annex shows, the instances of significantly poor performance are concentrated among (i) a few, relatively large RECs in Luzon and (ii) those smaller RECs operating in remote areas. 5._ Even the most viable RECs do not generate sufficient revenues from operations to enable self-financing of some investment for rehabili- tation of existin3 systems or for expansion. Because of the weak operating results of the RECs, planned maintenance has largely been deferred. In addition, the depressed economy of the early to mid 1980s constrained NEA from providing the RECs with financing needed to maintain, restore, or ex- pand their systems. Domestic private credit institutions have not been active participants in the sector, and their involvement has been limited to short term working capital advances to very few RECs. As a result, many REC systems are deteriorating for lack of funding. 5.6 An outline of the RECs' consolidated balance sheet for the years 1985-87 is presented in Annex 5.05, and summarized in Table 5.1. While a detailed analysis of the aggregate results must be qualified to take account of the important differences between the RECs, these high- lights indicate the fundamental weakness, common to all RECs, that limits their prospects of becomIng financially viable - namely, their nearly com- plete lack of equity capital. Membership-contributed capital, which in 1987 represented just 0.2% of aggregate REC assets, is limited by law to a token contribution of P 5 per member. Thus, the RECs are condemned by law to being capitalized entirely with borrowed funds. I/ Including: (i) making adequate provision for uncollectible consumer accounts; (i:) making timely close outs of completed construction work in pro- cess, thereby increasing the annual provision for depreciation, and (iii) tak- ing write offs for unusable generating equipment. - 59 - Zablea 5.i1* CONSOLIDATED BALANCE SHEET FOR THE RECs, 1985-87 (P Million) Years Ended December 31 1985 1986 1987 Assets: Net Utility Plant 3,094 3,229 3,650 Other Fixed Assets 49 52 69 Current Assets 1,573 1,647 1,760 Deferred Charges 954 966 1.004 Total Assets 5,669 5,894 6,483 Liabilities and Equity: M.mbership Contributions 13 14 15 Cum. Deficit & Other (308) (347) _ (449) Total Equity (295) (333) (434) Long Term Liabilities 4,493 4,550 4,873 Current Liabilities 1,362 1,530 1,863 Deferred Credits 109 147 181 Total Liabilities and Equity 5,669 5,894 6,483 5.7 The low paid-in capital combined in many instances with cumula- tive deficits leaves many RECs with negative equity. Even in those regions where the RECs have been able to amass modest retained earnings, the debt/equity ratios are much higher than normal distribution utility prac- tice; in Region 12, where the RECs collectively are the best financial per- formers, the recorded combined debt/equity ratio is 4.2, with all other Regions reporting significantly worse ratios. If the RECs were to recog- nize as debt payable the loan amounts carried on NEA's books, these capi- talization ratios would be significantly worse. Furthermore, the gap be- tween what NEA reports as having been lent to the RECs and what the RECs record as having been borrowed from NEA, which was P 2.2 billion as of De- cember 31, 1987, is large and growing year by year (Annex 5.06). 5.8 Cash represents just 5X of the RECs' total current assets for 1987. On an aggregate basis, the RECs current ratio has declined from 1.15 in 1985 to 0.94 in 1987. Their reported cumulative deficit is large, and growing. Asset values assigned to alternative generation equipment have questionable validity; and, based on past experience, the liabilities associated with them are not likely to be honored (para. 6.15). Many of the poorly performing RECs have displayed a notable reluctance to collect overdue consumer bills; and, in the absence of a comprehensive collection effort, substantial write-offs of consumer balances seem warranted. Given the extent of these problems, the RECs' generally dreary financial condi- - 60 - tion is not likely to be reversed by independent action; a comprehensive, Government-supported restructuring effort will be necessary. Comparison of REC Performance by Area and Region 5.9 NEA has developed a rating system for the RECs, which includes the assignment of weighted points for, inter alia, such factors as (i) prompt payment of NPC charges, (ii) prompt payment of amortization to NEA, (iii) collection efficiency, (iv) control of line losses, (v) number of consumer connections and (vi) cost control. The points are compiled an- nually, based on the REC's performance during the year just completed. The total of points awarded determines whether the REC is classified as A, B, C, or D, with A denoting the best category of performanceV. Of the 114 RECs that submitted results for 1987 to NEA, 27X were classed in the worst (D) category, while only 191 received 'A" ratings. Of the 31 "DI rated RECs, 25 (or 801) were from Luzon; in contrast, of the 46 RECs that were rated "A" or "B", 11 (or 24X) were from Luzon. While only two (3.71) of Luzon's 54 RECs were rated 'A", eight (261) of the 31 Visayas' RECs and 12 (411) of Mindanao's 29 RECs received the best ratings. Table 5.2 summa- rizes the classification of RECs by area; Annex 5.07 shows these regional differences in performance graphically. -Tlable 5.2: CLASSIFICATION OF RECs BY AREA (as of December 31, 1987) Area A B C D Total Luzon 2 9 18 25 54 Visayas 8 6 14 3 31 Mindanao 12 9 5 3 29 Total 22 24 37 31 114 5.10 The RECs' cost profiles also differ markedly from one geogra- phic region to the next. Annex 5.08 shows the aggregate cost profiles for the RECs operating in the three primary geographic areas; in addition, that Annex compares the cost structures of the RECs operating within a geograph- ic region with the other distribution utilities operating in the same area. This analysis indicates that the Mindanao RECs should have the best pros- pects for profitability given i:hat the rate they pay for their power pur- chases from NPC is only P 0.57/kWh and that their other constituent costs are at or below the costs recorded in the other regions. While the oost structures of the Luzon and Visayas RECs appear roughly comparable, the high self-generation and administrative costs faced by the small remote island RECs in the Visayas distorts the aggregate cost profile for the y Among other uses, NEA bases its guidelines for compensation of REC Board Members on this classification. - 61 - group. Adjusting for those two factors, the Luzon and Visayas RECs have similar cost constituents, with the difference in their cost structures being the price they pay for purchasing power from NPG. 5.11 From a Region perspective, the vast majority of RECs' in poor financial straits are in Regions 3, 4, 5, 8 and 9. Regions 3, 4, and 5, which take in large areas of central and southern Luzon, contain some of the most prosperous, densely populated rural areas in the Philippines. The financially troubled RECs that provide service to 'ihese areas generally show system losses that are higher than the average of 25X, and high inter- est expenses. These apparently inconsistent results denote high invest- ments in low-return projects combined with deteriorating core systems. In addition, the high level of administrative costs despite the sizeable num- bers of consumers indicates that their managements are not controlling costs effectively. In general, these RECs have managerial problems, and not inherently unecnnomic franchise areas. In contrast, some of the finan- cially troubled RECs in Regions 4 and 5, as well as most of the poor per- formers in Regions 8 and 9 serve small, remote islands with sparse popula- tions. In general, they are characterized by low losses and high power costs. This indicates that these RECs have franchise areas that are inher- ently expensive to serve; the high cost of service so overwhelms other cost data that no judgement can be made as to the effectiveness of these RECs' management. In general, about 25-30 RECs appear to be in financial diffi- culty because they have franchise areas that are too costly to serve; they appear to be serving small Visayan islands or mountainous, sparsely popu- lated areas in Luzon, Mindanao, and Samar. In turn, about 40-45 RECs ap- pear to be in financial diffictulty because of weak management; those RECs are concentrated mostly in central and southern Luzon. Comparison of RECs with Investor-Owned Utilities 5.12 Comparing the RECs' cost structures on a P/Kwh basis with those of other distribution utilities in their geographic regions, indicates that the RECs compare unfavorably with the investor-owned utilities. In gener- al, this is because the investor owned utilities enjoy service areas with a more lucrative economic base and greater population density than those served by the RECs; as a result, they have a greater sales volume over which to spread their fixed costs. In Luzon, MERALCO's distribution cost is about 67X, while its administrative costs are about 58X those of being realized by the RECs. In addition, the RECs' systems losses are propor- tionally much worse than MERALCO's. Distribution costs of the ot.her inves- tor-owned utilities in Luzon are only about 42X of those of the RECs. Com- parisons of the cost structures of the Visayas and Mindanao RECs with in- vestor owned utilities in those areas indicate results similar to those recorded for Luzon. Surprisingly, in the one area where a REC and an inves- tor-owned utility compete directly on similar footing (La Union Province in northern Luzon), the REC sells its energy at lower cost and provides more reliable service. 5.13 Despite the more favorable cost structures of the investor owned utilities and the statistical evidence that they are more efficient than the RECs in the aggregate, the cooperative system continuss to be an - 62 - appropriate medium for providing electricity distribution services in the rural areas of the Philippines. The only failing REC franchise that has been attractive to an investor-owned utility management company has been the Benguet Electric Cooperative (BENECO), which serves the important re- sort city of Baguio and some significant outlying industrial users (mining companies). Otherwise, investor-owned utility management companies have not been willing, even when invited to do so on a contractual basis, to assume control over the operations of more characteristically rural net- works. Despite their weak financial and operational performance as a group, many RECs have served successfully as engines for considerable eco- nomic development in rural areas, often in the face of daunting con- straints. The RECs have taken responsibility for and extended the service of investor-owned utilities -!-at virtually abandoned their franchises in the early 1970s, and RECs havw extended service to previously non-electri- fied large areas. In the process, the RECs have brought service to about 50% of rural households. C Institutional Structue and Management 5.14 While the cooperative system as a group has not performed well, nearly 40% of the RECs have been successful in developing and operating their systems. Moreover, the concentration of poor performers among the RECs of central and southern Luzon and the small remote islands of the Vis- ayas indicates that some of the problems are more institutional than sys- temic. Therefore, institutional improvement in the sector is more likely to flow from (i) generalizing the factors that have contributed to the suc- cess of the well managed RECs and (ii) replicating th_ae factors in the less effective RECs. In addition, special programs can be developed to address special conditions that contribute to the weak performance of blocks of RECs with unusual common characteristics. The NPC-NEA subsidy program that addresses substantially the structural weakness of remote island RECs is just such a program. Role of NEA 5.15 NEA's performance as the sector's core institution and its im- pact on the RECs is discussed at length in Chapter 6. Over the years, NEA's initial collegial relationship with the RECs has been severely strained. The RECs' poor financial performance has resulted in widespread defaults on their loans to NEA; in turn, NEA has at times taken over the management of some poorly-performing RECs, bur without producing salutary results. This latter concern has been highlighted in the course of a re- cent program to refinance the most substantial of REC arrears to NPC. 5.16 In August 1988, under a Relending Program imp', aented in con- junction with a larger program to restructure NPC, NEA received P 500 mil- lion in equity to provide 21 RECs with 7% medium-term loans to refinance their significant arrearages to NPC. While the transactions were struc- tured so that the cash would flow to NPC aid not to NEA or the RECs, the RECs' remittances of principal and interest associated with these loans - 63 - would ultimately provide NEA with a source of funds. NEA selected ten RECs to participate under Part 1 of the Program and 11 other RECs to participate under Part 2. The two Parts to the Program differed significantly in one respect: the General Nanagers and Boards of the ten Part 1 RECs retained their jobs and received only advisory assistance from an NRA appointee, but the General Mane;,ers and Boards of the Part 2 RECs were effectively disen- franchised -- the General Manager was discharged and replaced by an NEA appointee and the Boards were retained only in an advisory capacity. As regards both Parts of the Program, NEA committed that it would not partic- ipate in the day-to-day management of the RECs for more than two years. 5.17 Since the outset of the Relending Program, the operations of the 10 Part 1 cooperatives have improved significantly while those of the Part 2 participants have not improved and in some cases have even deterio- rated. As clear evidence of this anomaly, the Part 1 RECs currently are realizing a loan repayment rate of about 80X while the loan repayment rate of the Part 2 RECs is only 271. As of February 1989, the General Managers of 43 RECs (including those in Part 2 of the Relending Program) were NEA appointees (Annex 5.09). Too often, these appointees have had inadequate training or prior experience in managing troubled organizations and as a result they have largely not succeeded in bringing about the promised per- formance improvements. These experiences indicate that NEA's involvement in the RECs' day-to-day affairs will not automatically lead to improved performance. 5.18 NEA is not in the utility management business but rather in the lending business. Instead of assuming management responsibilities, NEA can and should regulate the practices that have contributed to the weakness of poorly performing RECs by tying the financing of their investments directly to the adoption of reforms. When a failing REC will not reform and contin- ually fails to meet its obligations either to NPC for wholesale power or to ilEA for debt service, NEA should assume control over the franchise in the manner of a receiver and seek proposals for the future operation of the system from all potentially interested parties - including adjacent RECs, investor-owned utility management companies, and new groups from within the bankrupt REC's franchise area - and not simply attempt to regenerate the same REC with potentially the same Board and management. This process should begin a.. soon as NEA takes control of a REC. The Board members and General Manager of any REC that submits to this form of receivership should be disqualified from future participation in the affairs of the franchise. 5.19 Political considerations have, in the past, had a distortionary effect on NEA's lending operations. Annex 5.10, which was prepared from NEA's records, shows annual loan releases to tl.i RECs from inception through 1988. If the B 500 million Relending Program is excluded from con- sideration, the graph shows a dramatic burst of loan releases in 1986. The politicization indicated by this pattern of lending remains a dominant fac- tor in investment decision-making. While the restructuring of some RECs' loans, particularly those that were advanced for politically motivated non- economic activities, would provide some financial relief, the impact would be immediate and non-continuous. The best approach to limiting the delete- rious impact of politicization on investment decision-making in the future would be for NEA to reorient its support only to economically justified investments. - 64 - Role of REC Boards of Directors 5.wS As provided ia PD 269, the business of a REC is managed by a Boarl of not less than five directors, each of whom is a member of the REC. Directors are elected by the consumer members and serve terms as specified in the REC's by-laws. The officers of a REC - its president, vice-presi- dent, secretary and treasurer - are elected annually from among the Board members; however, also according to PD 269, the officers and Board members serve as a policy making body while day-to-day operations and management is vested in the REC's General Manager and staff. This organization structure follows closely the U.S. model for RECs. 5.21 In certain of the poorer performing RECs, particularly those of central and southern Luzon, the boards and their members are heavily im- mersed in the day-to-day affairs of the cooperative. In some cases, this has served to undermine the authority of the General Manager; in other in- stances, it has led to open squabbling between the General Managers and the Board members. As a result of the confusion at the top of the organization structure and the multiple lines of authority implied by that confusion, necessary discipline within the REC's organization and among its members has broken down. In most cases, the excessive involvement of Board members in the REC's affairs has led to widespread abuse of perquisites and strong indications of corruption. All too frequently, Board seats have been used as opportunities to expand personal influence through patronage. As a re- sult, Board elections have been marked by excessively lavish campaigns and violence at the polls. In general, in the Philippines, the RECs that func- tion effectively have strong General Managers who enjoy the respect of their Boards. In c'ontrast, RECs with General Managers who are dominated by activist Boards often suffer from politicization, whicb creates major dis- tractions and drains scarce REC resources. 5.22 Two of the major problems confronting many RECs are past due consumer receivables and the proliferation of illegal connections. Each REC has established a policy of prompt disconnection for non-payment, as well as procedures for the detection, disconnection and pros-cution of pil- ferers of electricity. These two problems are not, in theory, difficult to address under the existing policy framework. However, the impact of these problems on the performance of financially-troubled RECs, where the abuses have become widespread and the perpetrators are influential in the communi- ty, has been highly deleterious. In certain RECs, tne Boards themselves have apparently succumbed to pressures to tolerate these abuses and have blocked the implementation of necessary remedial action. As the RECs oper- ate within narrow financial margins under even the best of circumstances, financial viability cannot be attained if basic commercial practices, such as collection of sales revenue for all power consumed, are not fully sup- ported by the RECs' Boards of Directors. 5.23 An elected Board representing the interests of consumer members is the fundamental characteristic that distinguishes cooperatives from oth- er types of enterprises. Therefore, any deviation from the primacy of the freely-elected Board would imply a disenfranchisement of the REC's members, - 65 - and must be approached carefully. Still, because of the host of instances where politicization at the Board level has led to blatant patterns of abuse that have been harmful to the operational effectiveness of the RECs, any program for their institutional rehabilitation must include careful consideration of the appropriate role for the Board and checks on the ac- tivities of its members. A proposed change to the NEA charter that would give the NEA Administrator the right to appoint all REC Board members has potential to address this issue of politicization at the local level; how- ever, it would effectively disenfranchise the cooperatives' members and thereby alter the fundamental character of the RECs. Instead, the Govern- ment should consider an amendment to PD 269 that restructures REC Boards so that a majority of members would be non-elected. These members, some of whom would acquire their seats either by appointment or by virtue of their positions in the community, could be expected to be responsive to the needs of the public. In addition, elected Board members would serve a fixed term of between two and four years (to be fixed ir the REC's by-laws) and there- after be ineligible to serve that REC either as a Board member or as Gener- al Manager. NEA has developed sound and adequate guidelines to govera the conduct of REC Boards and their members. These guidelines currently .are not being enforced; NEA should consequently attach conditionality on future loans to the RECs to enforce the guidelines. Role of REC Managers 5.24 The successful operation of an REC demands not only a compe- tent, experienced General Manager but often also a strong individual with character and courage. lntrusive Board members, consumers long accustomed to REC tolerance of non-payment and pilferage, and an uncertain peace and order situation in many areas present difficult challenges to even seasoned managers. While the General Managers have the pivotal jobs, each REC also needs adequately skilled line managers; however, an informal management inventory performed by NEA in connection with this study indicates that their ranks are spread thin. Compounding this perceived dearth of manage- ment talent is the low pay scales in effect at most RECs. Considering how little they can offer and their remoteness from the larger centers of eco- nomic activity, the RECs have difficulty in attracting capable managers and still greater difficulty in retaining them. Many managers and technical personnel who were attracted to the rural electrification program during the period of rapid expansion have left to pursue more rewarding opportuni- ties. The pay scales of the RECs should therefore be adjusted to enable them to attract and retain the necessary quantity and quality of managers. D. Guidelines for Restructuring the RECs 5.25 The RECs' problems are not intrinsic to their organization as cooperatives. This conclusion is supported by (i) the mass failure in the early 1970s of investor-owned utilities that served provincial cities and towns, directly accelerating the growth of the cooperative system; (ii) the disinterest of investor-owned utility management companies in taking over the operations of failing REC franchises; and (iii) the concentration of - 66 - financially-troubled RECs in areas where the core systems are in severe disrepair and institutional problems are perviasive (as in central and southern Luzon), or where high self-generation and administrative costs ur.dermine financial viability (as in the small, remote islands of the Vis- ayas). The RECs' operational and financial performance is therefore more likely to be improved by launching programs to address the problems crippl- ing the system rather than by developing new organizational arrangements. The action programs suggested under the REMP to correct operational con- straints and the revised pricing policy proposed in Chapter 4 should both contribute to improvements to the RECs' financial performance. These ini- tiatives should be complemented by institutional reforms. 5.26 As indicated above, the RECs are experiencing serious financial difficulties. They are (i) severely undercapitalized; (ii) lacking in prospects for good financial returns; (iii) over-burdened with responsibil- ities ancillary to their main function of providing electricity distribu- tion services; (iv) distracted by politicization of their Boards and top managements; and (v) critically short of capable managers and skilled staff. While specific solutions for these problems can only be developed on a case-by-case basis, the following restructuring guidelines focus on measures that would have a system-wide beneficial impact. Increase the RECs' Equity (a) Increase Members' Equity Contributions. The RECs are uniformly undercapitalized. New consumers are required by law to pay only P 5 to join the REC. This token payment is not only sub- stantially below the cost to the REC of providing the member with service, but it is also so insignificant that the member perceives himself merely as a "customer" and not as an "owner" of the REC. The law that stipulates the RECs' membership fee needs to be amended so that the RECs can recover an equity con- tribution from consumers that (i) gives the members a greater stake in the REC's success, and (ii) better reflects the cost they impose on the system. One way of infusing new equity into the RECs would be to increase the membership fee substantially for all consumers. For example, raising the membership fee to * 200 for all members (old as well as new) would provide the RECs with about P 320 million in additional paid-in capital by 1995 (still not be enough to bring all Luzon and Visayas RECs back to positive net worth). In the long run, legislation that would also permit RECs to impose annual dues on their members is needed. In return for the additional fees, the RECs should be obliged to circulate an annual report to their members. (b) Make Available Government Grants. As the RECs are not capable of raising the additional equity they need only through in- creasing membership fees, the Government needs to consider mak- ing available to the RECs some grants, especially to support (i) Government-sponsored extension of service to uneconomic areas, and (ii) relief from typhoon, earthquake, or other envi- ronmental damage. In effect, through widespread default on - 67 - amortization due to NEA, a number of RECs have de facto been helping themselves to 'grants." (c) Surnport for Non-Economic RECs. Certain remote and self-gener- ating RECa have no hope of becoming financially viable. The Government and NEA will need to develop a program for providing financial relief to marginal RECs by (i) converting existing construction loans to equity, (ii) providing grant-financing for justifiable system expansion (para. 6.39), and (iii) sup- porting the NPC-NEA subsidy program for the fourteen RECs that cannot contain their costs below the P 2.50/kWh retail price ceiling (para. 4.3). The debt to equity conversions imply the forgiveness bf loans valued at about P 1.1 billion. Relief from Non-Performig Assets and Delinquent Loans (d) Transfer of Alternative Generation Facilities. The RECs need relief from the burden of mini-hydro and dendro thermal genera- tion facilities that either do not work or are superfluous to their day to day operations. In general, the RECs are not ca- pable of bearing the cost for such facilities. The facilities that work, together with the corresponding liabilities, are slated to be transferred in the near future to NPC. As the Government spearheaded these alternative generation programs, it should absorb the responsibility for those liabilities that exceed the net asset value of facilities being transferred to NPC. This measure implies forgiving about P 1.8 billion in loans to the RECs (para 6.26 (d)). (e) Relief from Loans Pertaining to Soclal Programs. Similarly, the RECs need relief from the burden imposed by social programs that are not related to electricity distribution. In general, the RECs are not capable of supporting these programs. The extent of such loans to be forgiven has yet to be determined (para. 6.26 (e)). (f) Rescheduling of Delinquent Construction Loans. RECs with sub- stantial arrearages have clearly limited prospects of meeting their debt service obligations on time. NEA should develop and implement a program to reschedule previous, delinquent con- struction loans (para. 6.26 (f)). The arrears in principal and interest in question have an aggregate value of about P 1 bil- lion. NEA will need to determine, on a case-by-case basis, a schedule for each delinquent loan that takes account of each REC's financial prospects. - 68 - Improve the Manageability of the RECs (g) Amend PD 269 to Depoliticize the REC Boards. The amended law should provide that (i) a majority of Board members be non- elected, chosen either on an ex-officio basis or by appointment of the NEA Administrator, and (ii) elected Board members serve a fixed term of two to four years, and thereafter be ineligible to serve the REC as a Board member or top level officer. NEA's current guidelines governing the conduct of REC Boards and their members are sound and need to be enforced through the use of conditionality on future NEA loans to the RECs. (h) Consolidation of RECs. Shrinking the number of RECs can yield substantial savings in administrative and payroll costs. NEA should contain the proliferation of RECs by (i) curtailing the establishment of new RECs, (ii) reviewing the feasibility of consolidating adjacent RECs now participating in NEA's Relend- ing Program, and (iii) developing incentives for well-function- ing RECs to absorb adjacent REC fran^hises in receivership. Such incentives, which are meant to prevent the acquisition of a failing REC from becoming a resource drain on a successful REC's existing membership, could take the form of providing (i) special working capital loans, or (ii) grants to support needed economically-justifiable investments aimed at revitaliz- ing the failing franchise. A broader consolidation program was considered and dropped for the time being out of concern that NEA could not enforce the dissolution of a REC that was not in receivershipV. As importantly, the main criterion for an ef- fective consolidation is geographical contiguity of service areas, and very few poor performers are contiguous to good ones. (i) Encourage Regionalization. NEA has initiated a program to develop field offices and appoint managers to oversee the com- bined operations of the RECs in an administrative Region. Al- though this effort is currently modest, it has potential for realizing some of the benefits of consolidation. Regionaliza- tion can be used to centralize services so that some increases in efficiency or reductions in overhead can be realized. Re- gionalization should therefore be supported as a salutary in- termediate step toward a longer-term program of consolidations. (j) Raise REC Pay Scales. This action is critically necessary to enable the RECs to attract and retain sufficient numbers of qualified managers. / In one instance, NPC had cut the power to a REC for about two weeks and threatened a second cut in service for the next month before the REC reluc- tantly agreed to participate in Part 2 of the program. - 69 - Reorient the RECe' Investment Practices (k) Redirect the RECs' Investments. For most of their history, the RECs have been encouraged to invest in extending their networks to reach more residential loads. In general, these investments yield marginal to unsatisfactory returns. The RECs should re- focus their investments on projects that include (i) rehabili- tation with add-on connections, and (ii) system expansion de- signed to capture productive loads. Moreover, the RECs should be provided with clear and transparent subsidies when pressed to implement marginal investments that are justifiable only on social or law and order grounds. (1) Tighten NEA Supervision of Project Implementation. The RECs must accept that, as a financier concerned with the RECs' long- term financial welfare, NEA has a fiduciary responsibility to ensure that (i) the projects it finances are constructed effi- ciently, and (ii) the RECs are taking needed steps to improve their operating efficierncy and financial performance. NEA needs to tighten its supervision procedures, and the RECs will need to agree to those procedures as a condition of borrowing. Moreover, the RECs may need to agree to conditionality concern- ing their operating and financial performance. 5.27 This restructuring program involves a substantial outlay of public funds; in order that this be a one-time event that succeeds in revi- talizing the sector, the Government needs assurances that the RECs will discontinue the practices that gave rise to their serious financial prob- lems. In particular, the effectiveness of the recommended measures (as well as the financial and economic prospects of the investment program de- veloped in Chapter 3) presumes that the RECs will (i) curb their technical losses; (ii) take actions to identify and punish pilferers, and thereby reduce non-technical losses; (iii) improve their collection efficiency; (iv) revise their prices to cover the full cost of providing service; and (v) Eay on time for their power purchases and debt service. 5.28 The primary beneficiaries of the program will be the 25 poorly performing RECs with inherently poor financial prospects (paras. 5.26 (c) and 6.26 (c), and Table 6.5), which will benefit greatly by having past construction loans cancelled; before the Government cancels these loans, each of these RECs should formulate and agree to implement measures to op- timize their operational and financial performance. They should establish monitorable performance targets, and their eligibility for future borrow- ings from NEA should be predicated on meeting these targets. 5.29 The other major beneficiaries will be the 46 poorly performing RECs whose current distress results largely from mismanagement. Most of these RECs are clustered in central and southern Luzon (page 6 of Annex 5.03, and Annex 5.04), and have franchise areas that provide favorable fi- nancial and economic prospects. To enable these pros spto be realized in the future, many of their delinquent loans will n ed to be rescheduled (paras. 5.26 (f) and 6.26 (f)). They too must earnJheir relief by formu- lating and agreeing to implement operational and financial improvement pro- - 70 - grams. Their progress in realizing agreed performance targets should be monitored closely, and a chronic failure to realize those targets should result in the REC defaulting on its rescheduled loans. These RECs should be eligible for future loans from NEA only after showing clear evidence of sustainable improvements in performance. 5.30 Other RECs will benefit from the cancellation of loans for al- ternative generation (paras. 5.26 (d) and 6.26 (d)) and social programs (paras. 5.26 (e) and 6.26 (e)). However, since the related problems re- sults from faulty Government policy and not from poor management, these RECs should not need to earn their relief by adopting specific institution- al development programs. 5.31 The RECs that are performing poorly and will not agree to im- plement improvement measures should not be provided with relief under the restructuring program. They should be disconnected if they fail to make timely payments for power purchases; similarly, they should be declared in default if they fail to meet their debt service obligati,.ns to NEA on time. At that point, NEA's objective should be to transfer control of the failed REC's assets to the group proposing the best long-term plan for the future operation of the franchise. - 71 - 6. THE NATIONAL ELECTRIFICATION ADMINISTRATION A. Introduction 6.1 Following the change of Government in 1986, many Government agencies received special assistance to restructure their operations while NEA did not. Despite this lack of overt Government support, in 1987-88, NEA's Board recruited an energetic new leadership team that appears capable and interested in providing the agency with an appropriate focus. That team has already taken some bold steps to streamline the staff and intro- ducc. efficiency measures. However, these measures by themselves are not enough to make NEA function effectively as the sector's core agency. The organization needs a reorientation of its role and its operating perspec- tives, accompanied by a financial restructuring to put it on a 'clean books" basis and a new financing strategy designed to meet the sector's future needs. This chapter discusses NEA's role, its institutional rela- tionships, and its past and current financial position. Against this back- ground, recommendations are made for (i) a financial restructuring of NEA, and (ii) a financing strategy for the sector, and (iii) organizational ad- justments needed to enable NEA to refocus on its lending activities. B. NEA's Role 6.2 NEA's existence as the core agency to direct the rural electri- fication this sector cannot be justified solely on the basis of its provid- ing electrification support to the RECs. NPC, supplemented by the private sector, can provide many (though not all) of the required services. Howev- er, the uniquely specialized financial requirements of the RECs provide a compelling reason for NEA's continued existence as the sector's core agency, functioning primarily as an interested lender. 6.3 The RECs provide a service that is critical to the economic de- velopment of the areas within which they operate. By nature, their busi- nesses are characterized by a need for heavy capital investment and lengthy cost recovery periods. Yet, few of them are financially viable and even fewer are credit worthy. Because of the thin economic base of most of their franchise areas, many RECs need to borrow at concessional rates and hope that the resultant economic development will be sufficient to enable them to afford market rates for financing subsequent increments of expan- sion. In the early stages of the rural electrification program, demand for service overwhelmed the funds available for investment; as electrification has increased, so has the need to optimize investment expenditures, thereby creating a need to base investment decisions on load forecasting and cost/benefit analyses. Moreover, the RECs must now refocus their invest- ments away from system expansion and toward rehabilitation and add-ons, but they lack the expertise and orientation for developing and programming such investments. Although the technology of electricity distribution is rela- - 72 - tively prosaic, most RECs pay too little to afford an ample cadre of fully qualified managerial and technical staff; they therefore need to supplement their thin capabilities with external expertise. In short, the sector needs a core agency capable of financing weak borrowers with an extensive need for highly specialized technical support, to ensure that (i) the proj- ects being financed are feasible and appropriate, and (ii) the RECs develop into institutions that operate well enough to repay their loans. 6.4 Since the late 1970s, NEA has not performed effectively as the sector's core agency. However, its difficulties stemmed mainly from (i) a lack of focus in its activities, (ii) the absence of functional account- ability, and (iii) the previous Government's bent for requiring that NEA exceed its institutional capabilities. However, when NEA's direction was clear and available resources were adequate, it performed quite effective- ly. NEA has led a movement that succeeded in providing electricity, and therefore raising the standard of living, for about 2.7 million new consum- ers in less than 20 years; Government policy and not organizational weak- ness caused NEA to disregard the cost of that program. The organization itself has the structural units to perform most of the functions that would be needed of the core agency; if those functions were to be reassigned, most of NEA's staff of about 900 would still be needed by NEA's successor. NEA needs primarily to reorient its focus toward loan programming, credit analysis, and loan administration, and supplement its existing staff to perform these functions. Thus, the most effective approach to developing the needed core agency activities is to address NEA's weaknesses. 6.5 Over the years, NEA has acquired a number of side activities that were (i) only peripherally related to rural electrification, or (ii) aimed at developing for the RECs' supply alternatives to connection to the NPC grid. In its 1988 reorganization, NEA discontinued some of the more arcane of these activities; however, it continues to be involved in alternative generation. NEA needs to restrict its business to providing finance and technical support for the distribution utilities serving rural areas, and divest itself of its other activities. 6.6 In the past, NEA was shunted between a number of Government agencies before finally settling under the Ministry of 1uman Settlements. Currently, NEA reports to DENR, which can neither provide the technical support nor require the functional accountability that NEA needs. To coor- dinate NEA's activities and investments with the rest of the energy sector, NEA has a seat on the ECC. Even so, a stronger interaction with the energy sector is needed. NEA should have the same reporting relationships as NPC, PNOC and OEA, the energy sector's main participants; this would mean bring- ing NEA directly under the Office of the President and having it report to the Executive Secretary. 6.7 NEA needs urgently to develop functional accountability over its activities. Although operating in both the electrification and the lending businesses with constrained resources, NEA has not previously had either formal ties to NPC or the outlook and accountability of a financial institution. NPC can provide technical support for many of NEA's electri- fication planning and implementation functions. NEA should formalize its relationship with NPC by having the NPC President serve ex-officio as the NEA Chairman and the NEA Administrator assume an ex-officio seat on NPC's - 73 - Board. To ensure that NEA follows the policies of a financial intermedi- ary, one seat on NEA's Board should be reserved for a senior banker, and a second for a senior official of the Department of Finance. Because NEA currently lacks the staff needed to discharge its lending operations, and has only limited prospects for acquiring such expertise given its current pay scales, it should acquire this expertise through a consulting arrange- ment with a major bank or financial institution. C Institutional and Financial Context 6.8 In the rural electrification program's early days, NEA and the fledgling cooperative system received extensive financial support from USAID. Beginning with the formation of two cooperatives under a pilot pro- ject that began in 1970 (para. 1.7) and continuing for the rest of that decade, USAID provided concessional loans totalling nearly US$86 million for rural electrification, making it the leading financial supporter of the program. The Overseas Economic Cooperation Fund (OECF) of the Government of Japan, which has provided nearly US$84 million since the program's in- ception, also participated enthusiastically in the early days and is the sector's second largest financier. The Bank has lent US$60 million for rural electrification (Loans 1120-PH and 1547-PH), and is NEA's third larg- est creditor. These primary lenders, together with other multi- and bi- lateral agencies, have provided a total of US$419 million of loans for rural electrification through December 31, 1988 (Annex 6.01). 6.9 During 1971-83, loan releases to NEA from all sources averaged US$28.4 million per year. After 1983, however, the rate of borrowing drop- ped precipitously, reaching a low of US$3.3 million in 1988 (Annex 6.02). As financing for rural electrification slackened, so did the rapid growth of new consumer connections, dropping to under 41 during 1983-87, and actu- ally declining slightly in 1988 (Annex 1.02). 6.10 Rural electrification quickly became one of the most effective of the Government's rurai outreach programs, and NEA was increasingly per- ceived as one of the lea.ding rural development agencies. The early surge of electric service was hailed as evidence of the Government's eommitment to the rural commur.tiy, and NEA was asked to build upon these early suc- cesses by accelerating even more the pace of electrification. Increasing- ly, the Government's emphasis on adding new connections exceeded the ab- sorptive capacity of NEA and the newly formed RECs. Institution building was subordinated to the objectives of stringing lines and connecting new consumers. NEA's feasibility studies of investments in expansion became increasingly perfunctory, and actual investments under the program often differed markedly from the approved plan. As of December 31, 1988, 38 RECs had availed themselves of loan releases that exceeded approved amounts. The total of these overdrafts is about P 713 million, or 271 more than the total of approved loans for these RECs (Annex 6.03). 6.11 Increasingly, NEA was given responsibility for implementing ambitious social programs that were intended to improve the quality of life for rural dwellers. These programs, some not even remotely linked to elec- - 74 - trification, drained scarce financial and manpower resources from both N%A and the RECs. Most of these social programs were either sponsored or pro- moted by the Ministry of Human Settlements, which became NEA's parent orga- nization in 1978. These programs are summarized in Table 6.1: Table 6.1:. NEA's RURAL OUTREACH PROGRAMS PROJECTS DESCRIPTION Small Scale Industries (BLISS Small scale industry projects (em- Project) broidery, handicrafts, rice mills, ice plants, etc.) financed and supported by the RECs to provide economic development in rural communities. Water Impounding Water development through the con- struction of dams. BLISS - Level I Construction of dwelling units in rural areas. School Reforestation Tree plantation loans to schools and universities to develop natu- ral energy resources and support the Government's reforestation programs. Charcoal Livelihood Project Construction of charcoal kilns. Fower Use Promotional projects in support of the small-scale industry program. People's Forest Program Supporting the national tree planting program through the Fami- ly Tree Farms Association. Rural Water Systems Providing rural areas with potable water by drilling of deep wells. Schonl Lighting Electrification of school rooms throughout the country. 6.12 These programs received funding from a variety of sources, in- cluding foreign lenders and other Government agencies. As of December 31, 1988, NEA continued to hold a number of trust funds and recognize trust liabilities associated with these programs. Because of the strong emphasis on physical progress in attaining rural development targets, NEA paid scant attention to whether the programs being supported would provide the RECs with revenues sufficient to meet the related debt service requirements. In - 75 - turn, the Government did not provide NEA with adequate capital and operat- ing subsidies to support the cash flow requirements of these and other po- litically motivated programs. Foreign donor support, often featuring sub- stantial grant elements and long grace periods, provided sufficient finance to defer until the early 1980s the cash flow constraints that inevitably would result from supporting social programs with poor prospects for finan- cial returns. 6.13 NEA was also made responsible for implementing the Government's program to develop alternative forms of electricity generation. This in- volved supporting the RECs' developing mini-hydro and dendro thermal gener- ating plants of 5 MW or less. These ill-fated ventures were financed by foreign hard currency loans. Table 6.2 gives the status of these programs. Table 6.2: STATUS OF ALTERNATIVE GENERATION PROGRAMS (As of December 31, 1988) No. No. Mini-hydro in Dendro Thermal in # Sites # Units Op. # Sites # Units Op. Installed 13 35 N/A 7 7 0 Under Construction 6 17 - 0 0 - Constr. terminated 10 2S - 7 7 - In Storage: at NEA 29 78 - 3 3 - at Source Country 17 53 - 0 O - TOTAL 75 209 N/A 17 17 0 6.14 Less than 171 of the mini-hydro units acquired by NEA had been installed as of December 31, 1988. Of the 17 dendro thermal units procured by NEA, seven had been installed, although none are in operation. To pro- vide fuel supplies for the dendro thermal units, the program was linked to largely unsuccessful tree planting programs that were financed by NEA and sponsored by the RECs. NPC, which is taking control of the RECs' self-gen- erating facilities, will conduct a study to determine whether the dendro thermal units can be converted to diesel and restored to service; other- wise, the units will be scrapped. 6.15 Financially, the alternative generation program has been a ma- jor failure. As shown in Annex 6.04, the RECs have been unable to service the debts related to the program; as of December 31, 1988, they had repaid less than 8X and 0.2 respectively of the amortization due on their mini- hydro and dendro thermal loans. As NPC takes control of the units that have already been installed, it will only absorb liabilities corresponding to the depreciated value of units to be kept in operation. The alternative generation loans will provide cash flow to NEA only to that small extent; the RECs are not expected to remit to NEA debt service related to the re- mainder of loans raised to finance plants that they no longer own. - 76 - D. Current Finandal Perfornance 6.16 NEA's central business is lending to the rural electrification system. NEA obtains funding from foreign and domestic sources, procures goods and services for approved projects on behalf of the RECs, and col- lects the resulting loan principal and interest from the RECs as these be- come due. In short, it is a finaneial intermediary. As a Government cor- poration, NEA is responsible for generating funds from ongoing operations sufficient to (i) support its internal operations and (ii) service its own debts. To provide an adequate foundation in support of NEA's expected ac- tivities, the Government pledged to invest up to P 5 billion in NEA equity; about P 3 billion which was actually paid into NEA as of December 31, 1988. As a financial intermediary, NEA's financial viability is inextricably linked to that of the RECs, since NEA depended upon the cash flow from principal and interest payments from the RECs to meet its obligations. Therefore, from the outset, since the RECs were weak operationally and com- mercially, NEA was intended to act as an active lender, providing various outreach and technical support services to help the RECs evolve into via- ble, self-supporting organizations. 6.17 When viewed from the perspective of a commercial enterprise, NEA is insolvent. In the aggregate, NEA is collecting only about half of the amortization due from the RI.Cs; and for most of the alternative energy loans, the default rate is nearly 100%. Since 1986, current liabilities (composed primarily of advances from the Government) have exceeded current assets, and the gap is growing. NEA's debt obligations to its foreign and domestic creditors exceeds its total loans receivable from the RECs. These results suggest that NEA has done a poor job as a lender; and, without a restructuring, its future prospects as a lender are highly limited. NEA's current financial woes are primarily due to: (i) its lack of focus on its lending business; (ii) the Government's underestimation of the substantial capital and operating subsidies needed by the RECs, particularly tnose op- erating in remote and/or distressed areas, during their formative period; and (iii) the Government's overestimation of the RECs' and NEA's ability to manage non-commercial and social development projects unrelated to distri- bution of electricity. 6.18 Highlights of NEA's Balance Sheet for the period 1984-88 (Table 6.3) indicate a significant deterioration in NEA's financial position over that period. If NEA's accounts were adjusted to reflect commercial prac- tices (e.g., by establishing pro-sions for prospectively uncollectible debts and expensing arrears considered uncollectible), its financial per- formance would have been significantly worse than was reported. - 77 - Table 6.3: BALANCE SHEET HIGHLIGHTS (P millions) Years Ended December 31 1984 1985 1986 1987 1988 ASSETS Current Assets Inventories 817 959 1,242 1,263 1,247 Interest receivable-RECs 313 280 392 476 589 Loans receivable-RECs 198 265 369 472 609 Other 71 214 177 268 269 Subtotal 1,399 1,718 2,180 2,479 2,714 Long Term Assets Loans receivable-RECs 4,909 5,243 5,858 7,105 7,75a Other 2.758 170 161 1.999 374 Subtotal 7.667 5.413 6.019 9.104 8.130 TOTAL ASSETS 9,066 7,131 8,199 11,583 10,844 LIABILITIES & EQUITY Current Liabilities Advances from Govt. N/A 1,334 1,990 2,507 3,307 Other N/A 352 327 561 481 Subtotal 1,095 1,686 2,317 3,068 3,788 Long Term Liabilities Foreign Loans Payable 5.604 2.981 3.447 5.607 6.104 TOTAL LIABILITIES 6,699 4,667 5,764 8,675 9,892 Capital and Surplus Paid in capital 2,151 2,241 2,261 2,961 3,084 Cum. (Deficit)/Earning 44 51 2 (231)(2,310) Other 172 172 172 178 178 TOTAL CAPITAL 2.367 2.464 2.435 2.908 952 TOTAL LIAB. & EQUITY 9,066 7,131 8,199 11,583 10,844 - 78 - 6.19 NEA's current assets have questionable value. (a) Nearly 45X of NEA's inventory consists of uninstalled mini-hy- dro and dendro thermal units. A'.though NPC may acquire some of the units (para. 6.14), it is unlikely to relieve NEA of much of this inventory, since it refused to take responsibility for the program in its initial stages on economic grounds. More- over, the suppliers of these units have not indicated interest in retrieving them. Therefore, from a commercial perspective, these assets are worthless (despite NEA's continuing obligation for the related debt). (b) Interest receivable from the RECs includes both current amounts and arrears. Currently, this account shows that NEA has about two years of interest income due and still owing from the RECs; thus, an ample portion of that account represents arrears. (c) Loans receivable from the RECs shows a similar accumulation of arrearages in amortization payments. NEA currently makes no provision for uncollectible accounts, so these current assets are clearly overstated in light of actual remittances. Long- term assets as of December 31, 1988 consist almost entirely of loans due from the RECs. As with the current assets, no provi- sion for uncollectible accounts is made and the reported bal- ance is almost certainly overstated. 6.20 NEA's liabilities, on the other hand, represent bona fide claims arising from its borrowings. Advances from the Government, which are growing at an increasing rate, represent the value of principal and interest payments that NEA owed but was unable to pay to its foreign credi- tors. Foreign loans payable at December 31, 1988 include adjustment for foreign currency fluctuations. For the majority of these foreign loans, NEA bears the exchange risk between the peso and the original currency. In no instance has NEA passed this exchange risk to the RECs; and, when NEA has applied an interest rate spread, the extent of the spread was inade- quate to cover the related exchange rate losses. As of December 31, 1988, NEA's cumulative exchange Tate exposure amounted to about 0 2 billion. 6.21 NEA's paid in capital increased in 1987 primarily because of a Government equity infusion of about 9 500 million, the proceeds of which were to finance a Relending Program wherein NEA was to make loans to 21 troubled RECs so that they could pay down their NPC power acccint ar- rearages. The proceeds of this equity infusion was never disbursed to the RECs in question, but rather was paid immediately to NPC; and NEA opened new loan accounts, equal in amount to their NPC liability, for eaci, of the participating RECs. NEA will receive the benefit of this equity contribu- tion as these loans are repaid. 6.22 NEA's retained earnings have gone from a small positive balance to a significant accumulated deficit as a result of a change in the ac- counting treatment for foreign exchange losses. In the past, the impact of the devaluation of the peso on the foreign loan liability was not reflected in NEA's books; now, however, borrowings are adjusted at the end of the year according to the exchange rate prevailing at the time. - 79 - 6.23 Table 6.4 shows NEA's Income Statement highlights for the peri- od 1984-88. Although the reported figures, as audited by the Commission on Audit (COA), indicate a marginally profitable operation, income from opera- tions is overstated since interest income is recagnized when accrued and not when the cash payments are actually received. The recording of inter- est income on the accrual basis is an acceptable accounting procedure; how- ever, in light of NEA's poor collection experience, the absence of a re- serve for bad debts results in overstatement of the year's true income. Table 6.4: INCOME STATEMENT HIGHLIGHTS (P millions) Years Ended December 31 1984 1985 1986 1987 1988 Operating Ticome: Interest on loans 173 193 263 284 305 Operating Expenses: Interest expense 119 109 184 248 224 Personal services 28 32 33 38 47 Other 12 14 14 23 30 Subtotal 159 155 231 309 301 Income from Operations 14 38 32 (25) 4 Other Income 0 11 5 13 34 Foreign exchange losses O 0 0 (231) (234) NET INCOME (LOSS) 14 49 37 (243) (196) 6.24 Accrued interest income, which is essentially NEA's only source of revenue, grew at an annual compound rate of about 15X during the period. Interest expense, which generally accounts for about 751 of operating ex- penses, grew at a compound rate of 171. From NEA records, the extent to which interest income recognized in each of these years was actually col- lected cannot be deduced; however, the growth in the interest receivable balance suggests that the collection rate was about 501. Foreign exchange losses were only recognized in NEA's accounts as of 1987. Because the amount expensed relative to these losses was virtually equivalent to inter- est expense, this change in accounting procedure had the effect of trans- forming NEA from a break-even performer into a significant money loser. 6.25 The problems confronting NEA today are due partly to past man- agerial failings, and (i)partly to the heavy influence of politics in the rural electrification program. For the most part, NEA tried (perhaps too willingly) to do everything that was asked of it. Perceived political needs of the moment drove the organization, often to its detriment. The - 80 - recently installed NEA administration has approached the need for a new beginning with substantial energy; however, it is faced with inherited problems of such magnitude that "growing out" of the bad situation may not be feasible. When problems of similar magnitude confronted the Government Financial Institutions (GFI) during the past several years, the Covernment developed the Asset Privatization Trust (APT) to take over the GFIs' non- performing assets and thereby enable that sector to get a new start on a "clean books" basis. Similarly, NPC was relieved of the ponderous finan- cial burden posed by the politically motivated decision to build the Phil- ippine Nuclear Power Plant when the Government agreed to assume responsi- bility for those assets and the corresponding liabilities. So far, NEA has been denied access to similar mechanisms for relief from past mistakes. E. Proposal for a Flnancial Restructuring of NEA 6.26 NEA cannot address the RECs' problems while it is burdened with problems of its own that threaten to overwhelm the organization. The growing burden of unpayable advances from the Government, the poor payment history of RECs located in distressed or unsecured areas, and the debts overhanging the organization from past, ill advised, activities unrelated to electricity distribution must be addressed as the first stage of the recovery of the sector. Delays in implementing remedial actions will only compound the problems; however, any program to implement this restructuring will have to take account of when the Government, with its limited re- sources, can feasibly take responsibilities for the liabilities from which NEA should be relieved. The recommended remedial actions, the amounts of which are based on NEA's financial position as of December 31, 1988, are essentially short-term, one time measures that would alter materially NEA's financial situation. A restated Balance Sheet, shown in Table 6.6, indi- cates the effects of this restructuring program recommended below: (a) Advances from the Government. aggregating P 3.3 billion, should be converted to equity. This amount represents past payment by the Government of principal and interest related to NEA loan obligations. NEA has no reasonable prospect of repaying this obligation as its cash inflows are not even adequate to cover current operations and debt service. While the Government would absorb the impact of this measure, it represents a non- cash, "book" transaction for both the Government and NEA; how- ever, by substantially improving NEA's capital structure, it also improves NEA's prospects for credit worthinessV. (b) The Government should assume the imgact of foreign exchange losses on NEA's existing foreign loan obligations. This amount, aggregating P 1.9 billion, represents the difference between the original peso equivalent valued at the time of availment of the foreign obligations outstanding as of December gI The Government has already provided for conversion of some of these ad- vances to equity, and is weighing approaches for converting the remainder. - 81 - 31, 1988 ard their present peso equivalent value. NEA has made no provision for the RECs to assume all or part of the foreign exchange risk pertaining to these loans; moreover, it cannot expect to recover this cost element retroactively. Recent USAID loans require the Government to assume the foreign ex- change risk. Because NEA lacks cash inflows that correspond to these obligations, the Government will have to meet them; thus, while this measure implies no change from the status quo in terms of cash flow, it does substantially improve NEA's Balance Sheet and therefore its prospects for being effective in the future. For the future, the Government and NEA need to develop a system for managing the foreign exchange risk (para. 6.39)V. (c) Construction loans receivable due NRA from remote and/or self eenerating RECs should be written off: a corresponding amount of Government loans to NEA should be converted to eguity,. Twenty-five RECs have unpaid construction loans totalling P 1.1 billion (Table 6.5) that should be assumed by the Government in recognition that these loans were justified more on social than on economic grounds. The final amount to be converted to eq- uity would be computed after deducting from the outstanding balances the small amounts that correspond to the undepreciated value of the self generating facilities that NPC is acquiring. ./ NEA has already applied to have the Government absorb some of the foreign exchange losses applicable to existing loans. - 32 - Table 6.5; STATUS OF CONSTRUCTION LOANS TO REMOTE/SELF-GENERM:ING RECs (P million) Amortization Outstanding Region REC Releases Due Paid Balance 4 Marinduque 35.2 11.6 0.3 34.9 4 Occ. Mindoro 37.8 15.8 6.3 31.4 4 Lubang 10.4 4.2 0.0 10.4 4 Or. Mindoro 101.7 23.5 7.0 94.7 4 Palawan 61.5 3.9 0.6 60.9 4 Busuanga 39.5 0.4 0.0 39.5 4 Tablas Island 69.6 0.2 0.1 69.5 5 Catanduanes 32.9 9.5 0.7 32.2 5 Masbate 49.3 5.3 0.1 49.2 6 Guimaras Is. 47.2 0.4 0.2 47.0 7 Bantayan 49.1 0.0 0.0 49.1 7 Camotes Is. 15.6 0.0 0.0 15.6 7 Siquijor 54.8 0.1 0.0 54.8 A Samar I 26.1 6.6 1.4 24.7 8 Samar II 92.5 28.2 1.1 91.4 8 E. Samar 49.5 3.4 0.0 49.5 8 N. Samar 28.9 1.8 0.0 28.9 8 Biliran Is. 25.9 0.2 0.1 25.8 9 Sulu 16.7 3.6 0.1 16.6 9 Tavi Tawi 5.6 1.6 0.0 5.6 9 Basilan 18.7 5.9 0.1 18.6 9 Cag. de Sulu 2.5 0.9 0.0 2.5 10 Siargao 112.2 0.0 0.0 112.2 10 Camiguin 73.4 0.1 0.0 73.4 10 Surigao Sur 35.7 1.8 0.4 35.3 1,092.3 128.7 18.5 1,073.8 (d) Assets and liabilities associated with dendro thermal and mini- hydro. both installed and uninstalled, should be divested, To the extent that NPC acquires the deoreciated value of sonte of these assets. it should assume the corresponding liabilities. NEA's inventory as of December 31, 1988, includes P 565 million of mini-hydro and dendro thermal equipment. The RECs partici- pating in the alternative energy program owe an aggregate of about P 1.8 billion for the mini-hydro and dendro thermal fa- cilities provided to them. As of December 31, 1988, NEA's re- maining liability to foreign lenders was P 791 million (based on the exchange rate originally in effect at the time of loan availment). These obligations should be removed from the books of both the RECs and NEA. (e) Assets and liabilities of all social programs and other activi- ties unrelated to electricity distribution (value to be deter- - C3 - mined) should be disted. For the most part, these social projects were economically unsuccessful and have drained scarce resources. Funds h3ld in trust should be returned to the Gov- ernment. No NEA personnel should be assigned to the monitoring of these activities. (f) NMA should restructure all delinquent REC debts (RrinciRal and interest aggregating P I billion), based on feasible renavment terms. Much of thL arrearages may be collectible if NEA and its borrowers approach the issue on a crse-by-case basis. NEA should arrange a major loan monitoring and collection effort. (g) P 150 million in deferred dev,elooment costs. Government Rroiect costs and salaries and allowances of NEA staff gosted to REC management positions should be expensed against current onera- tions. and the accounts used for their -defrral should be closed. These amounts relate to past activities of NEA and no continuing benefits are being realized. The cost of NEA's in- terim management of the RECs can be borne by the RECs through fees that the RECs would pay as incurred. (h) NEA should turn its non-Rerformina assets over to the APT. ibhich should try to return to the Government whatever value can be realized from those assets. To ensure that this effort indeed serves as a one time measure to return NEA (and through it, the troubled RECs) to sustainable financial health, NEA will need to implement stricter credit and financial prudence practices (para. 6.32) and tighter loan administration procedures (para. 6.28). In addition, NEA will need to become more involved in supervising the activi- ties of the RECs. In that context, it will need to take a sterner view of the RECs' failure to comply with their loan agreement obligations. In ad- dition, the individual RECs will need to take steps to improve their opera- tional and financial performance in order to earn their eligibility for relief under this proposed restructuring (paras. 5.27-5.31). - S4 - Table 6.6: EFFECTS OF RESTRUCTURING ON NEA BALANCE SHEET !/ (P million) Actual Restated Year Ended Dec. 31 1988 debit credit (est) ASSETS Current Assets Inventories 1,247 (d) (565) 682 Interest rec.-RECs 589 589 Loans rec.-RECs 609 (c) (110) (d) (281) 218 Other 269 269 Subtotal 2,714 0 (956) 1,758 Long Term Loans rec.-RECs 7,756 (c) (964) 5,242 (d)(1,550) 5,242 Other 374 (g) (150) 224 subtotal 8.130 0 (2.664) 5.466 TOTAL ASSETS 10,844 0 (3,620) 7,224 LiABILITIES & EQUITY Current Liabilities Advances from Govt 3,307 (a) 3,307 0 Other 481 481 Subtotal 3,788 3,307 0 481 Long Term Foreign Borrowings 6,104 (b) 1,907 (c) 1,074 (d) 719 2.332 TOTAL LIABILITIES 9,892 7,079 0 2,813 Capital and Surplus Paid in capital 3,084 (a)(3,307) 6,391 Cum. Surplus/(Def.) (2,310) (g) 150 (b)(1,907) (d) 1,605 (2,158) Other 178 178 Subtotal 952 1.755 (5.214) 4.411 TOTAL LIAB & EQUITY 10,844 8,834 (5,214) 7,224 t./ The letter in parenthesis denotes the component cof the restructuring that accounts for the indicated account adjustment. - a)5 - 6.27 Because many loans from which NEA would be relieved under this restructuring program were raised in support of either (i) Government-pro- moted expansion of distribution systems into uneconomic areas, or (ii) Gov- ernment-sponsored programs that were only marginally related (if at all) to rural electrification, they should be transferred to the Government for disposition. The beneficiaries of the uneconomic expansion of the distri- bution systems as well as the secial programs were the rural poor, who can- not bear the true cost of those investments. The beneficiaries of the in- vestments in self-generation facilities were the foreign suppliers; since the Government pursued this program even after NPC rejected it on economic grounds, the Government should bear the cost of these mistakes. Since Gov- ernment policy proscribed NEA from (i) passing to the RECs the exchange risk on foreign borrowings, or (ii) charging the RECs an interest rate spread designed to cover that risk, the Government must bear responsibility for losses that resulted from the deep devaluation of the peso during the 1983-86 recession. While the Government is admittedly facing severe cash flow constraints, no other entity can reasonably be asked to bear the cost of the politically-motivated profligacy of the previous administration. 6.28 In many instances, the recommended adjustments to NEA's Balance Sheet (Table 6.6) were based on estimates, since NEA's accounts contained (i) internal discrepancies and (ii) loan amounts that could not be recon- ciled with corresponding accounts in the books of the RECs. For example, NEA's subsidiary loan records show the total of mini-hydro and dendro ther- mal loans receivable from the RECs was P 1.76 billion. These records, which are used for monitoring releases to, collections from, and arrearages -P the RECs, are maintained to support NEA's general ledger; however, the ge..eral ledger indicates that mini-hydro and dendro thermal loans receiv- able from the RECs total P 2.31 billion. Also, in none of the twenty cases, examined in depth by USAID's consultants during 1986-87, did the loan amounts carried in either NEA's general ledger or its subsidiary loan records reconcile with the corresponding loan amounts carried in the RECs' books of accounts. In effect, NEA's loan records are not maintained sat- isfactorily. A comprehensive effort aimed at (i) reconciling the amounts and terms of outstanding loans and (ii) adjusting the books of KEA and the RECs accordingly, is thus urgently needed. Once existing obligations to NEA are established definitively, releases of undisbursed amounts of future loans can be tied to the timely remittance of current payments. 6.29 NEA's accounting practices substantially overstate its commer- cial condition and, therefore, need to be revised. These practices in- cl. de: (i) not making provision for uncollectible interest and principal payments due from troubled RECs, although the collection history woulP sug- gest that a substantial allowance for uncollectibles is needed, and (ii) capitalizing development costs, Government project costs and salaries and allowances of NEA employees posted to REC management positions. These practices have been specified by the Commission on Audits (COA), which for accounting purposes considers NEA to be a social organization and not a "Government Financial Institution". To improve its ability to monitor its portfolio, NEA should obtain COA's permission to use accounting practices, including making provisions for uncollecttble interest and principal pay- ments and expensing many pericd expenditures that are currently capital- ized, that are normal to Government Financial Institutions. - 36 - F. Financing Strategy 6.30 The proposed restructuring is essentially a one time measure with an immediate impact. To prevent a recurrence of its past problems, NEA will need to develop a financing strategy that, at once (i) provides finance on appropriate terms for economically justifiable projects, (ii) penalizes RECs that make insufficient effort to improve performance, and (iii) considers the special needs of RECs with structural constraints that limit their prospects for financial viability. 6.31 In the past, NEA has not observed reasonable financial prudence practices in the course of its lending activities. Often, investment deci- sions were based on political pressures to energize specific areas and technical considerations related to service expansion, but without proper feasibility studies. As a result, some loans were made in support of proj- ects for which cost recovery was impossible. Had proper investment analy- sis and loan programming been performed, and if NEA's loan recording proce- dures were adequate, NEA might not have been susceptible to overdrafts to the extent indicated in Annex 6.03. Because ample funds with soft terms and long grace periods were available to the sector in the program's early years, problems resulting from NEA's failure to observe financial prudence were deferred until about 1983. 6.32 In the future, NEA must comply more closely with financial pru- dence practices. It must base its justification for making loans on proper credit analysis. When lending, NEA should apply conditionality aimed at improved financial performance and institutional development, and it should deny funding on the grounds of a borrower's poor past performance if an REC is unable to provide credible evidence that it would comply with reasonable conditionality. Where the Government wqnts NEA to support marginal proj- ects for either social or peace and order purposes, transparent subsidies need to be provided. Given the link between NEA's financial health and that of the RECs, NEA must improve the quality of its loan portfolio. 6.33 As shown in Annex 6.05, NEA currently administers at least 38 different types of loans. These include, inter alia, "regular' rural elec- trification loans, alternative energy loans, and a broad array of loans for social projects unrelated to rural electrification. To keep its lending activities manageable, NEA should simplify its categories for lending and its lending terms. In the future, it should limit its lending to support rehabilitation of rural networks, add-on connections, economically justi- fied system extensions, and working capital. While the bulk of its loans should be for the cash value of materials and equipment it provides to the RECs, it might consider lending cash under special circumstances. 6.34 Annex 6.05 summarizes the terms of both NEA's borrowings as well as its loans. Currently, NEA's charges for its loans are based on the cost of the underlying funds. This approach has proven unsatisfactory be- cause (i) NEA could not price its loans predictably, or even reflect in the interest rate its own underlying cost of operation; (ii) the donors' con- flicting onlending preferences were not necessarily consistent with overall - 87 - sector development; ard (iii) RECs vied with each other to participate in programs supported by the softest, least restrictive financing packages. 6.35 To enable NEA to solicit financial support from a broad range of donors, it should cnntinue to focus on its overall cost of funds in de- veloping its interest rate policy. "EA should develop a basic interest rate pegged to its average cost of capital plus a spread that allows for recovery of its administrative and operating costs and reflects adequately the foreign exchange risk. A premium of about 2-3X should cover NEA's overhead and loan generation costs, while a premium of about 6-71AI should cover the expected foreign exchange risk. The basic rate would guide NEA's pricing of all of its loans. Also, the provisioning against anticipated foreign exchange losses should be based on all NEA loans made this financ- ing strategy, not simply those with foreign exchange exposure, at least until an ample fund has been accumulated. The basic rate should be re- viewed annually, and the new rate fixed for the duration of all loans gen- erated after completion of the review. In conjunction with a rural elec- trification project approved in 1988, USAID asked that NEA apply an onlend- ing rate of 12X; that rate was justified because it was (i) positive rela- tive to inflation, (ii) approximately equal to the opportunity cost of cap- ital in the Philippines, and (ili) broadly reflective of the exchange rate risk that NEA would face on a portfolio composed in equal parts of soft loans from bilateral lenders, harder loans from multilaterals, and low-cost domestic funds. Because the 12X rate currently covers NEA's cost of capi- tal and provides the requisite spreads, it could become NEA's initial basic rate and be valid until the first annual review is conducted, presumably in August/September 1990. 6.36 Once the basic rate has been established, NEA can use preferen- tial pricing to encourage specific types of investment. For example, loans to support rehabilitation with add-on connections or system expansion de- signed to capture an unconnected productive load could be priced at 1X be- low the basic rate; loans to support system expansion aimed at only captur- ing residential loads could be priced at 2X over the basic rate. However, because variations in the repayment period have a greater impact on an REC's cash flow than interest rate variations, NEA should keep all its rates within a range defined by a floor that is 12 below and a ceiling that is 22 above the basic rate. 6.37 The best incentive NEA can use to encourage the RECs to (i) in- vest in justifiable projects, (ii) stay current in meeting their debt ser- vice obligations, and (iii) meet reasonable operational and financial per- formance targets, is to vary the maturity and grace periods applied to each loans. NEA should have a standard loan that carries a grace period of two years and a maturity of ten years (these terms correspond to the construc- tion period and depreciable lives of most distribution investments). How- ever, maturities of more than ten years (perhaps as much as 20-25 years) could be applied to loans that support, directly or otherwise, (i) invest- , For the Bank-financed Manila Power Distribution Project, an onlending rate, which was about 6.5X below the current market rate for similar local funds, was accepted on the basis that the differential w3s an adequate reflection of the foreign exchange risk being borne by NERALCO. - BB - ments with higher than normal rates of return, (ii) agreed institutional improvement programs adopted by poor performers, or (iii) the sustained good performance by the better RECs. NEA should adopt no more than three alternative combinations of maturities and grace periods (i.e., 15 years-30 months; 20 years-36 months; and 25 years-42 months), and develip a point system (i.e., that assigns points for the project's expected rate of re- turn; the REC's credit record; and the REC's operational and financial per- formance) to determine the specific terms of any particular loan. 6.38 As noted earlier (para. 6.26 (b)), for the future, the Govern- ment and NEA need to develop a system for managing the foreign exchange risk. Elsewhere in the Philippine power sector, the foreign exchange risk is borne by the borrowing utility (i.e., NPC or MERALCO) and automatically passed on to the consumer through the electricity tariff. However, NEA cannot realistically on-lend foreign exchange to the RECs; to do so would not only require an unwieldy exchange rate tariff adjustment provision that the RECs would have difficulty administering, but would also expose the fi- nancially fragile RECs to the unpredictable risk of devaluation. 6.39 Instead, the risk should be borne by NEA. In the future, NEA will continue to be responsible for (i) the RECs' investment planning and project development, as well as (Ji) the selection of investments to be financed by loans and (iii) the credit analysis of the borrowing RECs. In effect, by taking the foreign exchange risk, NEA would become accountable for its mistakes. However, NEA cannot assume the full future foreign ex- change burden without making provision for the possibility that the risk might materialize. It should, therefore, develop an Exchange Risk Fund that it would maintain with the Central Bank. Annually, NEA would deposit into the Fund a provision equal to about 6.5% of the principal value of its outstanding repayable foreign credit. 6.40 To accommodate the justifiable investment requirements of RECs without reasonable prospects for financial viability, the Government should create a pool of grant funds that can be onlent for 25-30 years at no in- terest, but with an annual service charge of 1-2% (to cover NEA's adminis- trative costs). NEA could use the pool either to provide soft finance for a small number of justifiable projects, or to provide interest rate relief for a larger number of projects through the blending of hard and soft loans. To be eligible to tap the soft loan facility, a REC would either have to be receiving power from NPC at the subsidized rate of P 1.30/kWh or participating in the NPC-NEA subsidy program for RECs unable to reduce their costs below the retail ceiling of P 2.50/kWh. The Government should provide NEA with an annual equity investment of P 125 million to fund this pool. As the weak RECs' investment needs are expected to be modest, and as most of them are located in the typhoon belt, the pool could also be used to provide them with relief from typhoon damage. Funding from this facili- ty should be treated similarly to NEA's other loans. To qualify for fin- ancing from this pool, a REC would have to undertake a program. to improve its operational and financial performance. In connection with a "soft" loan, the REC would need to agree to conditionality to (i) implement the performance enhancement program, and (ii) realize agread periodic perform- ance targets. - 89 - 6.41 To prevent the recurrence of past abuses, NEA must make better use of its leverage as a lender. To discourage chronic unsatisfactory per- formance in certain RECs, NEA could restrict the availability or delay the processing of loans. Performance targets, or even action plans to improve performance, could be covered by loan conditionality. In the extreme, NEA could decide not to finance a particular poor performer, regardless of the priority of that REC's investment program. 6.42 NEA vist also avoid a recurrence of its own past financial dis- tress. It is providing the RECs with a vast array of services and needs to develop the operating cash flow to cover the expenses related thereto. It should expect to cover the cost of its lending operations and its overhead from the spread on its loans; however, it needs to provide the bulk of its electrification services to the RECs on a fee basis. A fee schedule, which incorporates rates comparable to those of a consulting firm, needs to be devised to cover the costs of investment planning, project development, procurement, warehousing, and project supervision; the amounts involved should be estimated in advance and be withdrawn immediately from the prin- cipal amount of each loan, in the manner of a front end fee. The fee for maintenance services should be payable In cash according to credit terms normal to the Philippines. The cost of NEA staff seconded to the RECs should also be borne fully by the RECs as incurred. G. NEA's Financial Prospects 6.43 In connection with this study, five year financial projections for NEA were prepared on the basis of the following scenarios: Scenario I NEA would finance an investment program for the RECs consistent with Investment Scenario 1 (para. 3.34), without NEA being restructured. Scenario I-A NEA would finance an investment program for the RECs consistent with Investment Scenario 1 (para. 3.34), and would be restructured according to the recommended program (para. 6.26) . Scenario II NEA would finance an investment program for the RECs consistent with Investment Scenario 2 (para. 3.34), without NEA being restructured. Scenario II-A NEA would finance an investment program for the RECs consistent with Investment Scenario 2 (para. 3.34), and would be restructured according to the recommended program (para. 6,26). All scenarios assume that, (i) the collection rate will improve gradually to about 65X by 1993; (ii) external financing for investment that is shown as committed includes only the US$40 million USAID financing package, the US$22 million rural electrification component of the proposed Bank-financed Energy Sector Loan, and about US$15 million of loans or grants from other - 90 - sources-' that are either ongoing or strongly indicated; (iii) the Govern- ment provides an average of a 125 million annually to support justifiable investments in non-viable RECs and typhoon relief; and (iv) current ac- counting practices will continue to be used. The projections for Scenarios I-A and II-A are presented in Annex 6.06. 6.44 These projections indicate that the proposed restructuring is the critical financial factor facing NEA. Under all scenarios, the Govern- ment would be investing about P 280 million per year in NEA equity to cover the foreign exchange losses on its past loans. Under the restructuring proposal, this commitment would be acknowledged officially; without the restructuring, these investments would still be needed because NEA would lack the wherewithal to meet the corresponding obligations. However, with- out the restructuring, the Government would be providing NEA with addition- al advances of about P 500 million per year to meet debt service on loans that, under the restructuring proposal, would be converted to equity. With restructuring, NEA's debt/equity ratio moves from about 40:60 as of the end of 1989 to about 25:75 as of the end of 1993. In contrast, without re- structuring, the debt/equity ratio goes from 87:13 as of 1989 to 65:35 as of end 1993; and the improvement would be dire-tly attributable to the very same assumptions of Government support that would be acknowledged official- ly under the restructuring. With the expression of Government support and the improved capitalization resulting from the restructuring, NEA would be able to obtain credit from the financial markets, and could be held ac- countable for its financial management; without the restructuring, NEA would continue struggling while the Government would need to make the same cash commitments over a protracted period. In effect, the restructuring proposal recognizes the reality that NEA cannot meet many of the past obli- gations that the Government had guaranteed and needs to be put on a "clean books" basis to meet the challenges of the future effectively. 6.45 Even with the restructuring, NEA's operating results are ex- tremely sensitive to its collection rate. The projections assume that col- lections will improve from about 521 in 1989 to about 65X in 1993 (since NEA's collection rate was about 36X in 1987 and 1988, further improvement wol'd be difficult to justify). While NEA is expected to be comfortably profitable on an accrual basis in each of those years, its operating cash flow is projected to be somewhat constrained. Although the restructuring will afford NEA some capacity to borrow, it should be encouraged instead to improve its collection performance. In addition, NEA needs to pay particu- lar attention to ensuring the continued adequacy of its relending rate. Under the four scenarios considered, its profitability improves as existing lower-rate loans are retired and replaced in its portfolio by newer higher- interest loans. 6.46 After completing the restructuring, the pace of the investment in the sector is limited more by the availability of finance and NEA's or- ganizational capability to (i) plan and develop investments, (ii) formulate loans, (iii) procure the needed materials and equipment, and (iv) supervise i These include about US$9 million from the Asian Development Bank, US$5 mil- lion from the Government of Norway, and US$1 million from the Government of the United Kingdom. - 91 - the investment activity, than by issues related to its credit worthiness. Indeed, the more NEA can lend, the better become its financial prospects. 6.47 The financial projections for Scenario I-A, the one which best reflects the absorptive capabilities of the sector's institutions, indicate that NEA will need to finance some P 3.8 billion of investments during 1989-93. Of that amount, about P 1.6 billion will come from official fi- nancings that are either committed or at advanced stages of negotiations. Another P 1.7 billion is expected to be provided through as yet unidenti- fied official finance. In addition, about P 0.5 billion will need to be provided by the Government as equity. This latter figure correspotis to the amount expected to be required for (i) justifiable investments by RECs with limited prospects for commercial viability and (ii) a reasonable esti- mate for repairs of typhoon damage. H. Organizational Issues 6.48 The NEA organization consists of about 900 employees engaged in a variety of technical and supporting functions (Annex 6.07). Part of NEA's spotty performance can be traced to organizational weaknesses, in- cluding: (i) a pay scale that provides severe disincentives to managers who may otherwise desire to remain with the organization; (ii) a history of spreading thin its own managerial and technical cadre by frequently becom- ing heavily (and often ineffectually) involved in the day-to-day management of troubled RECs; and (iii) the lack of a multi-disciplinary central group to coordinate the activities of its disparate units. 6.49 For pay purposes, the Department of Budget and Management clas- sifies NEA as an infrastructure organization. When the NEA pay scales are compared with NPC's, rank and file workers appear to be receiving similar pay rates; however at supervisory and managerial levels the rates diverge quickly, with NPC paying twice as much to its mid and upper level managers (Annex 6.08). NEA's nearly "flat" pay scale is a disincentive to retaining manager; and most of NEA's capable managers and staff who have left in re- cent years have cited the opportunity for better pay elsewhere as a prime reason for their departure. The Government therefore needs to reclassify NEA as a financial institution and adjust its pay scales to evels tha* enable attracting and retaining capable managers and supervisors. 6.50 Under the Relending Program (paras. 5.16-5.17), NEA seconded its own staff to take responsibility for the day-to-day management of 11 RECs, on the assumption that the NEA manager would succeed in reversing the poor fortunes of those RECs. Under the same Program, 10 RECs retained their original management. While NEA has good technical staff, few of them have hands-on experience in managing troubled organizations. This became clear as the RECs being managed by NEA appointees recorded a repayment rate of 27X, while the RECs that retained their own managements recorded an 80% repayment rate (Annex 6.09). This suggests that NEA is not effective as a utility manager. Therefore, NEA should take control of a REC in the manner of a receiver; and, immediately after a takeover, it should start the pro- cess of identifying and transferring control of the REC to the group with - 92 - the best long-term plan for operating the REC viably in the future. NEA's activities in managing troubled RECs should serve as an adjunct to its core lending function and not an end in itself. 6.51 Finally, and most importantly, NEA needs to improve the coordi- nation of its various activities, so that it can fulfill its primary role as an "interested" lender for rural electric systems. This can be done most effectively by developing a loan programming capability which will allow NEA not only to develop and implement a consistent medium-term lend- ing program but also to use the program as a means of coordinating and in- tegrating its own banking, technical and institutional development activi- ties under one all-encompassing umbrella. 6.52 Currently, NEA's loan programming function is diffused through- out the organization, creating the image of a "hollow" institution where peripheral expertise sex%ices a non-existent core. The current collegial approach to reviewing project proposals, formulating a lending strategy, and managing lending is not conducive to establishing a strong lender's link to the REC borrowers. The lack of this central function is exacerbat- ed by a dearth of banking competence. 6.53 Final decision-making authority concerning the lending program is now vested in the Administrator and the Executive Committee. However, the decisions need to be driven by clear recommendations originating in a multi-disciplinary unit at the heart of NEA which reports directly to the Administrator and is charged with: (a) Development of an indicative rational strategy for rural elec- trification investment; (b) Formulation of an internali, consistent lending program based on thiz strategy; (c) Responsibility for assessing specific REC investment proposals; (d) Formulation of appropriate lending operations based on these proposals; and (e) Supervision of the implementation of REC investments financed by NEA. 6.54 To discharge this function, the central multi-disciplinary staff (consisting of planners, economists, engineers, financial and insti- tutional specialists) would draw on the specialized skills available in the supporting departments, including those concerned with th.e development and application of lending instruments. This unit's mandate should be defined to ensure that it functions a coordinative line body, and not as an addi- tional bureaucratic adjunct to NEA's top management. In fact, because of its lack of lending expertise, NEA will most likely have to contract with a large bank or major financial institution to provide this loan programming function on a consulting basis. Such an arrangement may last for as much as ten years while NEA develops the necessary in-house knowledge. Still, NEA's own staff assigned to loan programming would retain responsibility for managing the lending program. - 93 - 6.55 While NEA would need to hire some new staff for this function, its low pay scales preclude hiring more than a few senior level people. As a result, it will need to rely on bringing in a cadre of bright young peo- ple either fresh out of school or with minimal experience. NUA can expect that, over time, some of those people will develop the necessary expertise and will decide to stay and become lending officers and managers in their own right. I. Summary of Reconmendations 6.56 NEA's continued existence as the core agency serving the sector is justified primarily by the specialized requirements of lending to 117 financially weak enterprises that provide a service that is critical to the economic development of the rural areas. For this purpose, NEA needs the capacity to provide technical support to ensure that (i) the formulated loans support feasible and appropriate projects, and (ii) the RECs develop into institutions that operate well enough to repay their loans. Current- ly, NEA's staff of about 900 people are providing many of those support services. These activities need to be supplemented with more focussed loan programming, credit analysis, and loan administration functions. To per- form its core functions effectively, NEA needs to restrict its business to providing finance and technical support for the distribution utilities ser- ving rural areas, and should divest itself of those other activities that were only peripherally related to rural electric distribution. To coordi- nate its activities more closely with the energy sector, NEA should have the same reporting relationships as NPC, PNOC and OEA; it should be brought directly under the Office of the President, and report to the Executive Secretary. Finally, to begin the development of functional accountability that it urgently needs, (i) NEA should formalize its relationship with NPC by having the NPC president serve ex-officio as the NEA chairman, and the NEA Administrator assume an ex-officio seat on NPC's Board, and (ii) NEA should reserve one seat on its Board for a senior banker, and a second for a senior official of the Department of Finance. 6.57 Despite the strong impetus provided by its new management team, NEA is insolvent financially and unfocused in its lending function. NEA needs to (i) undergo a major financial restructuring in order to purge its balance sheet; (ii) adopt clearer lending policies; (iii) institute more precise loan administration procedures; and (iv) reorient its focus and its activities so that it serves primarily as an "interested" lender for rural electric systems. 6.58 Under the proposed financial restructuring, the Government would relieve NEA of responsibility for (i) 0 3.3 billion of advances that were provided to cover debt service obligations to foreign lenders that NEA could not meet from operations during the last few years; (ii) f 1.9 bil- lion of expected losses resulting from exchange rate variations related to NEA's foreign borrowings; (iii) f 1.1 billion in loans that financed expen- sive self-generation facilities for small remote-island RECs; and (iv) as- sets and liabilities related to Government-sponsored alternative generation - 94 - and social programs. These measures would be realized by converting corre- sponding loans to equity. To complete the restructuring, NEA would re- schedule its remaining delinquent loans to RECs. The stronger balance sheet ensuing from the proposed restructuring would enable NEA to be a mag- net for increased official financial assistance for rural electrification. 6.59 To clarify its lending policies, NEA should (i) select invest- ments according to economic criteria to ensure that projects that are fund- ed have the highest potential returns; (ii) lend only for rehabilitation projects, add-on projects, system extensions and working capital support; (iii) develop standard lending instruments, with a basic interest rate peg- ged to NEA's average cost of capital plus a spread of 2-3X to cover NEA's loan generation expenses and overhead, and a second spread of 6-7X to cover the expected foreign exchange risk; (iv) maintain an interest rate struc- ture, with rates kept within 1-2X of the basic rate; (v) develop a standard maturity of ten years and a standard grace period of two years, to be ap- plied to all categories of loans; (vi) provide incentive for the RECs to pursue good quality investments, pay their debt service on time, and im- prove their operational and financial performance, through variations in the maturity and grace periods of loans; (vii) develop an Exchange Risk Fund into which NEA would make annual provisions based on 6.51 of its out- standing portfolio of foreign loans; and (viii) develop a pool, that the Government would fund with equity contributions of about a 125 million per year, to support justifiable investments and provide typhoon relief to the financially non-viable RECs. In general, NEA should observe financial pru- dence practices, extending loans only after having conducted a proper cred- it analysis and applying to loans conditionality aimed at improving REC fi- nancial performance and institutional development. Transparent subsidies should be provided by the Government when NEA is required to support mar- ginal projects for social or peace-and-order purposes. 6.60 To tighten its loan administration practices, NEA should im- prove its procedures for supervising loans. In particular, it should (i) reach agreement with each REC regarding the amount and terms of each outstanding existing loan; (ii) develop procedures, which include provision for realistic penalties, to improve its collection rate to at least 65X by 1993; and (iii) for future loans, tie releases of undisbursed amounts to the timely payment of existing obligations. To improve its ability to mon- itor its portfolio, NEA should obtain COA's permission to use accounting practices, including making provisions for uncollectible interest and principal payments and expensing many period expenditures that are current- ly capitalized, that are normal to Government financial institutions. - 95 - 6.61 To reorient itself as an "interested' lender, NEA needs to es- tablish a multi-disciplinary unit reporting directly to the Administrator that would be charged with applying sound banking principles in the formu- lation and implementation of a consistent medium-term lending program. This unit would be charged with (i) development of an indicative rational investment strategy; (ii) based on that strategy, formulation of an inter- nally consistent lending program; (iii) assessment of specific REC invest- ment proposals; (iv) based on those proposals, formulation of appropriate lending operations; and (v) supervision of the implementation of invest- ments being financed by NEA. While NEA has staff with some of the skills required by this unit, it neither has currently in-house nor can attract during the medium term the requisite banking expertise; therefore, NEA will need to obtain this loan programming function on a consulting basis from a large Government bank. Such ati arrangement could last for as long as ten years while NEA develops the necessary in house body of knowledge. Still, NEA's own staff assigned to loan programming should retain the responsibil- ity for managing the lending program. - 97 - ANNEX l.Ql PHILIPPINES - RURAL ELECTRIFICATION SECTOR STUDY Consumers Served by the RECs No. of Year Consumers Increase 1974 176,000 -- 1975 299,000 70% 1976 465,000 56% 1977 653,000 29% 1978 845,000 29% 1979 1,118,000 32% 1980 1,441,000 29% 1981 1,700,000 18% 1982 2,034,000 20% 1983 2,284,000 12% 1984 2,492,000 9% 1985 2,648,000 6% 1986 2,752,000 4% 1987 2,857,000 4% 1988 2,825,000 -1% CONSUMER CONNECTIONS 2.9 2.13 2.4- 2.2- 2- 1.2 a. r . - lm:A:1 Ii '0~ isa ia jg j[ ir 197 94 9 in 1978 1979 W 4"0 11982 IM9X -S -97 I= M!AR - 98 - ANNEX 1.02 PHIL}PPINES RURAL ELECTRIFICATION SECTOR STUDY Annual Formation of RECs (1971-88) No. of RECs Year Established 1971 16 1972 20 1973 10 1974 6 1975 19 1976 3 1977 21 1978 9 1979 6 1980 2 1981 3 1982 0 1983 2 1984 1 1985 1 1986 1 1987 -2 1988 TOTAL 117 RECS ESTABLISHED BY YEAR b~~~~~~~o "70 meIs"LLa 21am3 15 9717 99031 20~~ - 99 - ANNEX 1.03 ZELRPPINES RURAL ELECTRIFICATION SECTOR STUDY Current Status of Mini-Hydro and Dendro-Thermal Programs 1. As of 1980, a development of a total of 75 mini-hydro sites were planned, including some 209 generating units with an aggregate capaci- ty of 99 MW. Of the planned sites, 13 have been completed, six are still under construction, ten have been suspended while under construction, 24 were suspended after the equipment was delivered to NEA's main warehouse in the Philippines, 17 were suspended after the equipment had been purchased but not yet delivered to the Philippines (the equipment is being stored in the source country), and five were suspended in the planning stage. Nearly 70% of the units were supplied by People's Republic of China, with the bal- ance being mainly of French and British origin. The program's major prob- lems included (i) inadequate technical planning, (ii) insufficient site investigation and (iii) unsatisfactory hydrology. Only four of the instal- lations are operating satisfactorily; the remaining nine are facing either insufficient water or site stability problems. NPC has now taken responsi- bility for this mini-hydro program and is investigating the feasibility of the implementing the remaining projects. 2. Beginning in 1980, a total of 12 Dendro-thermal projects were planned, including 13 of 3.2 NW each and four of 1 KW each. The total ca- pacity of the plants was to be nearly 46 MW. Of the 17 planned projects, six were completed, three were suspended while under construction, five were suspended after the equipment was delivered but before the start of construction, and three were suspended while still in the planning stage. Balfour Beatty Engineering Ltd. of the U.K. was to have supplied six of the plants; Alsthom Atlantique of France was to have supplied nine of the plants; Mintours Duvent Diesel of France was to have supplied the remaining two plants. Technical details of the plants are attached. 3. The Dendro-thermal program envisaged growing trees on 1,000 acre sites over a five-year cycle. The mature trees, when felled, were to be cut into logs and crushed into wood chips for burning in the wood fired boiler of a nearby power plant. The first phase of the planting program was not successful in producing the expected number and quality of trees. The results from second cycle of planting were even poorer than the first due inadequate site preparation, lack of fertilizer, and generally careless farming. The wood processing equipment was poorly operated and maintained, so that the quality of timber chips was uneven. In turn, the boilers were unable to burn the timber chips so that none of them ever produced the rated output of steam. The manufacturers/suppliers have now stopped sup- porting the equipment they provided (originally supplied under bilateral aid programs). Finally, NEA lacked the in-house capacity to provide the RECs with adequate technical support in designing, planning, implementing, and operating generation plants of this type. NPC has now assumed respon- sibility for the program, and is investigating the possible use of local coal in the boilers. - 101 - RURAL ELECTRIFICATION SECTOR STUDY Kilometers of Line per Region by Design Parameter (As of December 1987) 13.2/7.6 kv 240 V Region 69 KV DC 3-PHASE V-PHASE 1-PHASE SEC CKT.KM. Region I 0 24 1,998 662 3,498 5,753 16,713 Region II 44 35 1,676 377 1,444 1,819 9,387 Region III 27 7 1,412 700 1,178 1,770 8,707 Region IV 4 14 1,933 530 1,761 2,827 11,545 Region V 2 13 1,664 498 1,450 2,252 9,773 Region VI 261 35 2,021 371 3,086 3,144 14,030 Region VII 1 13 1,604 457 1,154 2,172 9,133 Region VIII 271 10 1,493 153 862 1,699 8,220 Region IX 10 14 846 504 686 1,103 5,449 Region X 104 14 1,675 794 1,897 2,573 11,477 Region XI 6 10 1,559 351 1,321 1,727 8,505 Region XII 154 40 1,131 502 1,332 1,052 7,484 SYSTEM TOTAL 884 229 19,012 5,900 19,669 27,891 120,423 - 102 - ANNEX 2.02 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Consumers per km. of Line ger Region Region HH/Consumers CKT Km. as of 1988 Consumers/km. Region I 395,939 15,965 24.8 Region II 177,857 9,455 18.8 Region III 390,892 8,173 47.8 Region IV 332,059 11,125 29.8 Region V 282,602 10,043 28.1 Region V} 275,396 14,457 19.0 Region VII 174,614 9,106 19.2 Region VI'I 153,145 8,529 18.0 Region IX 119,783 5,223 22.9 Region X 229,310 11,575 19.8 Region XI 185,957 8,075 23.0 Region XII 102,153 7,484 13.7 SYSTEM TOTAL 2,819,707 119,210 23.7 - 103 - ANNEX 2.03 Page 1 of 2 PHILIPPINES RURAL ELECTRIFICATION SECTOR SY Distribution System Design Asegcts of Technv4-jL_4o_s_e 1. Because of the direct relationship between voltage drop and sys- tem-losses in an electricity distribution system, this annex will discuse how design and system losses are related by distribution-line segments. 2. The electricity distribution systems are designed in relation to voltage drop: sub-station output is configured based on the number and loca- tion of consumers being served, and to the demand they place on the system. Generally, the system is designed so that the percent drop over peak load should not exceed 7%. The systems design are usually designed with a five year time horizon; at the conclusion of the period, expected demand for the next five year increment is recomputed and system-improvement requirements (e.g., voltage regulator additions, conversion of single-phase lines to 3- phase lines, etc.) are planned based on the new expectations for load growth. 3. The typical design standards for a 7620/13200 volt electricity distribution system in rural Philippines allowed for technical system losses of 12%-13% (not including substation transformer losses) for the five-year load-forecast cycle. This standard closely parallels the REA design standard for 7200/12470 volt rural lines in the U.S. Historically, the actual techni- cal losses recorded in early years of REC operations in the U.S. were in the ll%-14% range. In the instance of Philippine RECs that built their systems to provide service in previously unserved area, the actual losses recorded in the early years of operation was in the 12%-15% range, comparing favorably with their U.S. counterparts. 4. Currently, at RECs in the U.S., where load growth has been sub- stantial but distribution system improvements are keeping pace with that growth, total system losses have decreased to the 7%-10% range. In the Phil- ippines, the RECs have shown the opposite trend. 5. The original design work, as performed by local architecture and engineering firms, was in line with the standard. Unfortunately, the REC sys- tems have been operating for an average of 13 years, but the five year update of demand projections has not been developed and the corresponding distribu- tion system improvements required have neither been designed nor implemented at the vast majority of RECs. 6. Although technical losses cannot be pinpointed exactly, they are estimated at about 17% for a typical REC system. This assumes the REC oper- ates a 7620/13200 volt primary system and without any 2,400 volt primary lines remaining from predecessor operators. The range of technical losses for RECs without take-over lines could be as high as 20% in some of the high-loss Luzon RECs and as low as 14% in the best of the RECs. Losses attributable to prima- ry lines may be about 3.5%, resulting inter alia from undersized conductors, poor conductor connections, improper right-of-way clearing, and cracked or defective insulators. Losses attributable to line-transformers may also be about 3.5%, due - 114 - ANE L2.0 Page 2 of 2 mostly to improperly sized transformers and the use of poorly rewound trans- formers. Se^ondary line losses are estimated at about 4%, and result from (i) the excessive length of some of these lines, and (ii) factors similar to those causing primary line losses. Technical losses resulting from service drop lines, service entrances, and kWh metering could be as high as 6%, and result from (i) unmetered and undermetered consumer loads, and (ii) service-drop in- stallations and connections that do not meet standards. Table 1 shows how the results realized compare with the design standards. Table 1: Comparison of Realized Losses with Design Standards Design Probable Standard Actual Losses Primary Lines 3% 3.5% Line-Transformers 3% 3.5% Secondary Lines 3.5% 4% Service Lines 2% 2.5% Kwh Meters/Entrances 1% 3.5% Total 12.5% 17% 7. The system should be designed to keep losses within maximum allow- able tolerances; consequently, a realistic target for a rehabilitation project could be to reouce losses from an average of 17% to 12.5%, or a net reduction of 4.5%. The total energy sold to all the RECs is estimated at about 3,500 GWh; in turn, the RECs sell about 2,830 GWh to their consumers and the balance of about 700 GWh (about 25% of total REC sales) is estimated to be dissipated as losses. The energy supplied to the average REC is approximately 30 GWh. This could vary between about 10 to 100 GWh, depending on the size and load- density of the particular REC. A reduction in technical losses by about 4.5% would result in a saving of about 1.35 GWh per REC; valued at an average wholesale price of 1.05 pesos/kWh, the saving would be about P 1.4 million per year for the average REC. Each REC has an average of about 2-3 substations and associated feeder networks; therefore, the saving per feeder system would be about P 0.6 million, or US$30,000, per year. - 105 - ANNEX-2-04 Page 1 of 2 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Current Condition of the Rural Distribution System 1. Field inspections of segments of electricity distribution lines at nearly 50 RECs, conducted during 1986-89 by USAID financed consultants, assessed the condition of the distribution systems nationwide as follows: - 10% of the distribution systems are well maintained - 25% of the distribution systems are maint&ined satisfactorily - 35% of the distribution systems are maintained unsatisfactorily - 30% of the distribution systems show no sign of maintenance 2. A partial list of the distribution systems' problems includes: - uncleared rights-of-way - rotting poles, with decay at and just below groundline - leaning poles - twisted and broken crossarms - excessively sagging conductor - spliced conductor, connected with guy clamps and loop dead-end clamps - wrapped conductor connections, with no connectors - no hot line clamps on equipment connections - broken insulators - loose and missing hardware - pulled anchors, with guys that are slack or disconnected - broken pole ground wires - improper sized or no equipment fuse protection - lightning arresters broken, missing, or gap too wide - service-drops too low - hanging over roofs - loose service entrance cable - tilted kWh meters - troken service entrance ground-wires or with rods missing 3. The most impot.av-t alectrical problem of the distribution sys.- tems is improper sectionalizing and fault-current control. The original sectionalizing studies are, for the majority of the RECs, outdated. The reasons include: (i) distribution systems that have been expanded or al- tered significantly since the study; (ii) OCRs that are not available in the sizes required; (iii) OCRs that were removed from lines years ago the source of power was self-generation; and (iv) OCRs that no longer function because of inadequate maintenance. 4. While fused cutouts have been installed (15 kV, 100 amp rated) on about one-half of tap-lines on the primary distribution system, 80% of the RECs have no records of fuse sizes in the cutouts and co-ordination with OCRs (if any) is non-existent. - 106 - ANNEX 2.04 Page 2 of 2 5. About 35% of primary lines have serious drops in voltage during peak periods; and another 30% show drops that exceed design parameters. Line-type voltage regulators are used in about 20% of the RECs and would be used at another 20% if proper sizes of regulators were available. However, the preferred approach is to use capacitors because they offer the added benefit of voltage improvement. 6. Because so many capacitors have been installed, power-factor is not a serious problem at the majority of the RECs. Primary metering in- stallations normally include power factor meters, which only register total kVAR; thus, power-factor for peak and off-peak periods is not known. From field checks, 24-hour power factor changes in the 10%-15% range were com- monly observed in these low load-factor systems. Additional benefits could be realized by installing proper sized capacitors, to be located by actual load-study. Some of the larger-size banks should be switched in relation to load or time. 7. Sufficient numbers of lighting arresters are installed in 80% of the distribution systems. However, during the heavy construction period of the late 1970s, gaps were not set p- perly (on gap-type arresters); therefore about 15% of the arresters are improperly installed. 8. The voltage drop is excessive in about 40% of the secondary line due to: (i) absence of transformers for "splitting" the secondary; (ii) absence of larger-size conductors; (iii) high-resistance conductor- connections along the secondary; and, (iv) the addition of unmetered elec- tric loads at night at some RECs (hooking-on to open secondaries for ille- gal house service or to "kill-rats" in rice fields). 9. Substation operating conditions vary. At about 5% of the sub- stations, the original power transformers have failed. In most instances, they are still at the station, sitting idly on the side, with no prospect of being repaired. About 3% of the substations are missing one or more 69 kV lightning arresters. 40% of the substations have station-type volt- age regulators installed, but one-third of these are not functioning. In most instances, the problem is in the control circuit of one of the three single-phase regulators, and the REC has removed all three regulators from service to avoid phase voltage imbalance. 10. About 70% of the substations had three-phase OCRs installed for individual feeder protection at the time of construction. Now, about 30% of these three-phase OCRs have malfunctioned and are out of service. The reasons include: (i) lightning damage; (ii) flashover at the bushings; (iii) loose terminal connection overheating; (iv) mechanical failure; or (v) lack of maintenance. 11. Single-phase OCRs and fused cutouts have been used unsatisfac- torily to replace three-phase OCRs. Single-phasing on three-phase circuits results. Also, fault-current interruption capabilities are inadequate. 12. About 30% of RECs have made make-shift installations of meters, using unsuitable materials, on individual feeders. The safety and accuracy of these meters is doubtful. - 107 - ANNEX 2.05 PHILIPPINE RURAL ELECTRIFICATION SECTOR STUDY Recommendations for Jm=orvd Tree Clearing and Pole Treatment Tree Clearin8 1. Trees growing into and through rural electrification networks are a major problem in Philippines. Many of the trees are fruit-bearing. Because rights-of-way were not obtained during the construction phase and the trees are considered of value by their owners, the RECs nationwide have a problem of clearing branches from lines. The problem gets worse each year as the owners are increasingly resistive to attempts to cut or prune the trees. 2. The obstruction of distribution lines by trees causes many problems, including inter alia: (i) conductor breakages, (ii) technical losses, (iii) poor supply quality and continuity, (iv) flickering, and (v) posing a safety hazard to people and property. A regular annual program of tree-cutting to clear lines must be initiated and implemented on a continu- ous basis; this would only be possible if the RECs reach agreement with the landowners; such agreement could involve compensation. The costs of the program would primarily be for labor, with minimal additional expenditures on tools and equipment; based on average line lengths and unit prices and assuming a five year cycle for network configurations, this program is es- timated to cost about US$2.5 million per year. As existing REC staff would be redeployed to perform this work, most of the cost of the program would r.ot be incremental to the RECs but rather would be absorbed within existing cost structures. Pole Treatment 3. All wooden poles require regular maintenance and cyclical treatment to reduce or prevent rotting; due to the public safety consider- ations, the periodic treatment of wood poles is mandated by regulation in some countries. The 1974 REA Bulletin on Pole Inspection and Maintenance outlines procedures to be followed in the U.S. 4. The usual maintenance and treatment cycle for poles is from 8 to 12 years; for most of the rural network in the Philippines the elapsed time for most poles since they were last treated has now exceeded this range. The average number of poles per REC is exceeds 8,000 and total for the country is likely to exceed 1 million. Between 10-15% of these poles are estimated to need replacement; about 30-35% need special treatment for rot; and the remainder need standard treatment. To develop an accurate cost estimate for a pole maintenance program, each REC would need to devel- op detailed on-the-ground inspections; however, based on the number of poles involves and unit costs and using a ten year cycle for maintenance and treatment, the needed pole maintenance program is estimated to cost about US$5 million. As much of this money would be spent for goods and materials, the cost of the program would be incremental to the RECs. - 108 - ANEX 2.D6 Page 1 of 3 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Zonal Repair Facilities to Service the RECs 1. Millions of dollars worth of electrical equipment, operational and maintenance apparatus, and tools were purchased and distributed to the RECs during the 1970s and early 1980s; however, little consideration was given to the maintenance or upkeep of what was distributed. Little attention was paid to assessing the capabilities of the RECs to provide for their own maintenance or determining how to provide the RECs with those aspects of maintenance that exceeded their capacity. No system or plan was developed for the procurement and distribution of spare parts. Because of insufficient training of equip- ment operators with regard to maintenance procedures, assets became inopera- tive and were removed from service much sooner than expected. For the most part, many assets that could be repaired and restored to service remain idle and inoperative at REC storage. 2. The following are the major categories of idle equipment: (a) Distribution System Equinment Mi) Line-type transformers (ii) OCRs (3-phase and single-phase) (iii) Voltage regulators (iv) Sectionalizers and oil switches (v) Lighting control-equipment (vi) Metering transformers (including potential, and current transformers) (vii) Specialized kW/kWh/kVAR meters (viii) Mini-max indicating ampere meters (b) Test Eguipment (i) Recording volt-amp meters and watt meters (ii) IrAicating volt-amp meters and watt meters (iii) kWh meter rest sets (iv) Insulation testers and meggers (v) Rubber-glove test sets (vi) Communication equipment and test sets (vii) Oil test sets (c) Tools and Related Eguilmert (i) Hydraulic compression tools (ii) Hand operated compression tools (iii) Coffin hoists (wire pullers) (iv) Climbing equipment for linemen - 109 - ANNISX 2.06 Page 2 of 3 (d) Safety EquiRment (i) Hot-sticks (ii) Rubber gloves (Untested) 3. A review of the problem conducted during 1986 indicated that an estimated average of US$30,000-35,000 per REC of equipment, apparatus, and tools were laying idle. A second review, conducted during 1988-89 concluded that, on average, the estimate of machinery laying idle had risen to about US$45,000-50,000 per REC. The same review concluded that the replacement val- ue of idle equipment nationwide exceeded US$5 million, and the quantity of idle equipment is increasing steadily. 4. The RECs can do little by themselves to remedy this problem. They lack the skills and the resources to address most of their repairs require- ments. The only action that some have initiated was to attend to the rewind- ing of small-size transformers, in some cases at their own premises using their own staff, and in other cases by sending the transformers to local shops for rewinding. With few exceptions, the results of these efforts was not sat- isfactory; because the rewinding was done by hand without proper test instru- ments to insure quality control, rewinding costs were high and core-coil loss- es of rewound transformers were usually excessive. 5. Service Centers to serve the RECs are badly needed. Consultants for USAID had recommended that six to eight such centers should be strategi- cally located throughout the Philippines. All of the centers should be equip- ped to provide the "normal range of services" described in para. 6 below; two of the centers (possibly located in Manila and Cebu) should be fully equipped to provide not only "the normal services' but also to repair and rewind power transformers (the type used in substations). 6. Normal services to be provided by these centers could include: (a) Stocking Supplies to be made available for the RECs to purchase. These stores would include spare parts (A) and complete units (B): OA' Transformer bushings and other parts - OCR bushings and other parts - Voltage regulator bushings and other parts - Replacement parts for other line equipment and apparatus - Replacement parts for test equipment - Replacement parts for lighting equipment - Replacement parts for multi-phase kW/k'Wh metering equipment - Replacement parts for tools and related equipment - Replacement parts for communication equipment - Other replacement parts "B' - Complete units - transformers, OCRs, and regulators - Complete units - test equipment - Complete units - tools and related equipment - Complete units - safety equipment (hot sticks, gloves) - Complete units - lighting controls - 110 - ANNEX 2.06 Page 3 of 3 (b) Repairs and Other Services. These would include special services (A), regular services (B), and mapping (C): I"A" - Rewinding, repair and testing of line-type transformers. - Rewinding, repair and testing of OCR Equipment - Rewinding, repair and testing of voltage regulators - Repair and testing of other line type equipment - Repair and adjusting of electrical test equipment - Repair and testing of lighting control equipment - Repair and adjusting of tools Repair and testing of communication equipment "B, - Periodic frequency checks of communication equipment - Bi-monthly testing of rubber gloves - Semi-annual testing of hot-sticks "C" - Assistance in the preparation of system maps - Reproduction of key maps and detail maps 7. The RECs would arrange to leave equipment needing repair at the centers while, at the same time, collecting identical new or reconditioned replacements. Alternatively, when appropriate, center personnel would provide services to the RECs on location. 8. In all likelihood, the centers will be owned and managed by NEA. Under its current project, USAID is providing technical assistance to NEA; that consultancy will include a component to study (i) where the centers should be located, how they should be managed, the extent of service they should provide, and the cost of making them operational. In turn, under the proposed Energy Sector Loan, the Bank is providing NEA with nearly US$1 mil- lion to establish and equip the centers and train the centers' prospective staff. On this basis, the centers should be ready to provide service to the RECs by mid 1991. The Regional Associations of RECs that NEA is developing may be given a role in operating and managing these service centers. - 111 - ANNEX 2.07 PHIU PPINES RURAL ELECTRIFICATION ASETOR STUDY Transformer Circuit Metering - The BAPA Model 1. The average REC in the Philippines uses about 600 line-type trans- formers to serve about 23,000 consumer-coii.-ctions. Except in small-island RECs, a single-phase transformer serves an average of 35 to 45 consumers. 2. In the mid-1980s, NEA began promoting the formation of Barangay Power Associations (BAPA) to act on behalf of consumers served by particular transformers (one or more). The BAPA becomes a single consumer-connection for REC billing purposes; it then is responsible for billing and collecting from its membership. Three important objectives of BAPA formation include: (i) to reduce the RECs' expenses for meter reading and billing; (ii) to reduce non- technical losses on secondary and service linesJ/; and (iii) to provide a mod- est income to the BAPA through the differential between the energy rate billed by the REC to the BAPA and the regular retail rates applicable to the BAPA's eventual consumers. At RECs with a consumer base made up primarily of farmers and with only a small commercial load, the BAPA concept is working effective- ly. However, at RECs formed to take control of systems left by failed prede- cessors, the consumer members seem to have much less interest in the affairs of their REC. In these cases, the BAPA program has not been well received. 3. Installing kW/kWh meters on the transformer pole at all single- phase line-type transformer locations has benefits that transcend the BAPA program. These benefits include: (i) relating kV demand to the load on the transformer to determine whether the transformer is under or overloaded; and (ii) energy consumption recorded on this master-meter can be compared with the energy consumption billed to all the consumers served from that particular transformer, and thereby identify pockets of non-teehnical losses. Installing master-meters high on the transformer pole is an inexpensive way to minimize tampering. Self-contained kW/kWh meters can be used with 10 kVA and 15 kVA transformers, and transformer-rated meters can be used together with one cur- rent-transformer on larger size transformers. The cost of one typical kW/kWh meter installation is about US$150. Their benefits, including (i) detecting transformer overload and preventing burnout; (ii) detecting oversized trans- formers that contribute to technical losses; and (iii) pin-pointing non-tech- nical losses to a particular circuit, are much greater than the cost of in- stalling the master-meter. To achieve maximum benefits, transformer locations would need to be numbered. In turn, consumer account numbers would need to contain additional numbers to identify the transformer from which electric service is received. The master-meter would be read monthly on the same date that the consumer meters along that secondary are read. 4. Any program of distribution system rehabilitation should include a provision for "transformer-circuit metering". The cost of this provision is likely to average about US$100,000 average per REC. 1J Because the REC's meter is placed at the transformer, the BAPA would bear responsibility for losses beyond the transformer. - 112 - RURAL ELECTRIFICATION SECTOR STUDY Annual Energy Sold and Losses (By Geographic Region) ENERGY SALES BY YEAR i IC g MIc Mg t YW- ..ne w . VSM VA O SYSTEM LOSSES AS A % OF SALES -illeft u nt Owhc M9 gI@ * 9 l81 1 11BfB at i srs =VF - 113 - ARME 2.09 Page 1 of 3 PHILIPPI= RURAL ELECTRIFICATION SECTOR STUDY Program to Reduce Non-Technical Losses Causes of Losses 1. For this Annex, non-technical losses are categorized as follows: 'A" - Losses created by, or with assistance from, REC employee(s). "B' - Losses created by innovative consumer actions, with or without assistance from an REC employee or an outside electric energy "theft-artist.' nC" - Losses that are strictly pilferage by wire tapping. 2. In group "A" (REC-employee involvement), the activities which re- sult in energy losses are: (a) Falsifying billing records to show a consumer as having been dis- connected. (b) Recording lower than actual meter readings. (c) Tampering with meters to record less than actual consumption. (d) Place a wire jumper in the socket of socket-type meters; once re- set, the meter will record only about half of actual consumption. (e) Seal the meters improperly during installation to enable undetect- ed tampering by the consumer. 3. Group "B" (Consumer action) includes these various "tricks" that distort recorded consumption: (a) On 'A' Base, bottom-connected meters, tilt the meter so that the bearings controlling the disk bind and the disk slows or stops. (b) Place permanent magnets on the outside of the meter glass to in- fluence the rotational speed of the meter disk. (c) Drill a small hole in meter-glass and insert an object to stop or slow the disk's rotation. (d) Connect a reversing transformer on the internal wiring circuit and thereby slow dramatically the rotational speed of the disk. 4. Group "C' (direct pilferage of electric energy) methods of theft usually involve the following: - 114 - ANNEX 2.09 Page 2 of 3 (a) Directly connecting wires to open secondary lines. (b) Directly connecting wires from the service drop to the service en- trance connection at the consumer's premises. (c) Directly connecting wires to the conductors in the kWh-meter ser- vice entrance cable (usually by using pins or nails). (d) Reversing or altering the conductors at the bottom-terminals of 'A" Base, bottom connected meters. (e) Interchange connections at the service drop to service entrance cable connection at the consumer's premises, so that the ground is the conductor to which the 2-W kWh meter, single current coil, is connected in series. By using a makeshift ground at the load, the meter records much less than full consumption. 5. The foregoing presents the methods of pilfering electricity com- monly used by residential and small commercial consumers in rural areas of the Philippines. Pilferage at large commercial or industrial consumer premises (where the meter is transformer-rated using current transformers) are more likely to rely on the following methods: (a) In collusion with REC staff, compute the meter-reading multiplier incorrectly so that false information is provided to the REC bill- ing department and billed consumption is less than actual. (b) Shunt the current transformer output so that much of the current flow does not pass through the meter. (c) When consumers are required to supply their own three-phase me- ters, purchase a meter (either from a big-city market or a theft- expert) in which the gear chain has been replaced with one of a higher ratio. REC metermen have difficulty detecting the error since, even though the register was changed, the speed of the disk in relation to load is still correct. Loss Reduction 6. At many of the RECs, employee morale is low due largely to: (i) too frequent changes in REC management; (ii) inadequate opportunities for ad- vancement; (iii) relatively low salaries; and (iv) absence of a good wage and benefits plan. These factors provide an inducement for employees to collude with consumers to pilfer electricity. However, morale-building alone is not a sufficient remedy for this problem. REC management must become directly in- volved in curbing losses where REC staff is in collusion with consumers. 7. The RECs have an internal audit department charged with policing cash-flow. A unit within internal audit should be created for monitoring non- cash commercial activities, including the activities of meter readers, meter- men, and linemen. The main function of this proposed unit would be meter con- trol. The RECs have a clear weakness in controlling the handling of meters. Since meters are handled by meter-testing personnel, warehousemen, linemen, installers, and readers, too many o"portunities exist for manipulation. - 115 - ANE 2.09 Page 3 of 3 8. The collusion of consumers with professional electricity thieves who are not REC employees is more difficult for REC management to control. Tough enforcement of laws, which are stricter and carry greater penalties than those currently on the books, is needed to address this particular crime. 9. The following actions reduce significantly pilferage among resi- dencial and small commercial consumers: (a) In areas where tapping of secondary lines is a problem, change the secondary phase-conductor to insulated conductor. Tape or other- wise cover all connection points to this phase-conductor so that no open wire connector point exists. (b) Replace all service-entrance cable (average of three meters length per house) with concentric neutral cable to eliminate the possi- bility of direct nail-pin tapping. (c) Use compression connectors at all service-drop wire to service entrance cable connection points. Tape or cover these securely. (d) Replace large numbers of "A" Base, bottom connected meters, and install new meters so that they cannot be tilted. Test and adjust the meters taken from service. Repeat this process until all "A" Base, bottom connected meters have been changed. (e) Remove and inspect all socket type meters for jumpers. (f) Reseal all meters at the time of inspection or replacement. 10. A thorough inspection of meter circuitry should be conducted at all commercial and industrial consumer premises. Primary amp readings should be taken and compared with secondary amp readings to verify the current trans- former ratios. The RECs should provide locked compartments in which current transformers would be enclosed to prevent shunting. Meter multipliers should be verified. Three-phase meters should be tested, at least on site, to verify their accuracy. The ratio of meter registers should be checked to determine if it is correct for the particular meter. Three-phase metering installations should be checked semi-annually for commercial and industrial consumers. 11. The work programs outlined above can be undertaken in the context of a program to rehabilitate substations and associated feeders. The poten- tial benefits of a program to reduce non-technical losses is very high, as these losses represent more than 30% of the total distribution system losses. The average loss per REC is estimated at 25% of sales; of this, about 17% is the estimate for technical losses and the balance of 8% is the estimate for non-technical losses. The management actions described above, if effectively and consistently applied, could quickly reduce non-technical losses in the average REC from 8% to 2%. The elimination of non-technical lobses altogether would take longer to achieve. As outlined in Annex 4.03, a reduction of 6% for non-technical losses would represent an annual saving of 0 1.9 million per year for an average REC (and more than double that for many RECs in Luzon). The saving per substation and associated feeder network, calculated on a simi- lar basis, would be about 0 0.8 million, or approximately US$40,000, per year. - 116 - ANNEX 2.10 Page 1 of 5 PHIIPPINES RURAL ELECTRIFICITION SECTOR STUDY Pilot Program for Rehabilitating S§ubstations and Feeders Substation Component Obiectives: 1. (a) To provide all of the major electrical equipment for the in- stallation of additional 69/13.2 kV substation capacity at participating RECs; (b) to provide automatic voltage reguLating equipment at participating RECs where voltage levels on the 69 kV source dictate a need; (c) to supplement the RECs' existing steck of three-phase oil circuit reclosers to provide proper distribution-feeder fault-current protection and sectionalizing on substation feeders; (d) to provide 69 kV metering equipment to supplement the existing equipment at the RECs to provide high-side 69 kV metering installations for all the substations being provided; (e) to provide 13.2 kV metering to supple- ment the existing equipment at the RECs and thereby enable 13.2 kV primary metering on all substation feeders; and (f) to provide substation accessories, fuses, switches, lightning arresters. ScoRe of Work 2. New Substations. The RECs and NEA have selected the site for the new substations. These have been agreed with NPC. (a) Land acquisition for substations will be the responsibility of the REC. The material and labor for substation erection will be pro- vided by the REC, with NEA assistance. (b) The major equipment items for the substations include: power- transformers, voltage regulators, oil circuit reclosers, and sub- station auxiliary equipment. Installation of this equipment in the respective substations shall be the responsibility of the RECs, with NEA supervision. (c) NPC shall provide the 69 kV tap-lines to the substations, and will assist the REC in the installation of 69 kV metering equipment. 3. Individual Power Transformers. NEA shall be responsible for de- livery of these items to the RECs. Installation of the transformers at the existing substations shall be the responsibility of the RECs. 4. Voltage Regulators. OCRs. Other Auxiliary Substation Equipment. NEA shall be responsible for delivery of these goods to the RECs. The RECs shall install this equipment with NEA guidance. - 117 - AM L210 Page 2 of 5 Distribution System Cogponent Objectives: 5. (a) To restore to origir..l operating condition 69/13.2 kV substa- tions and all associated electrical distribution lines and apparatus, for com- mercial use in electricity distribution; (b) to provide a durable system, with increased distribution system capacity, proper voltage levels, adequate s8 stem protection, and a minimum of system energy losses. Scope ogf Work 6. Substations. Where required: (a) increase substation transformer capacity; (i) install automatic voltage regulators; (b) install three-phase OCRs on individual feeders; (c) install primary 13.2 kV/kWh/kVAR metering on individual feeders (d) add substation auxiliary equipment to supplement exist- ing equipment; and (e) completing installation of equipment-requirements in the affected substations. 7. Tighten all hardware: (a) ground-line treatment of wood poles in substation structure; (b) inspection of substation grounding network; and (c) general improvement of substation area. 8. Primary Distribution Lines. Rebuild all lines that are still op- erated at non-standard voltage to a 7,620/13,200 kV system. (a) Poles: (i) Groundline (1/2 meter below ground) and above ground inspection of all poles in the primary lines; (ii) groundline- treat all poles which still appear to be sound; (iii) replace all poles that show signs of uncontrollable decay; (iv) straighten or re-tamp poles as required. (b) Crossarms and Hardware: (i) Straighten or recant crossarms that are still sound and replace damaged, broken crossarms; (ii) re- place or add hardware items and tighten all hardware. (c) Insulators: (i) Replace all cracked or broken insulators; (ii) clean all insulators along coastal areas. (d) Guys and Anchors: (i) Add additional line-support as required; (ii) pull guys to proper tension and proper "Rake" on poles; (iii) add guy-guards as necessary: (iv) connect or reconnect grounds to guy wires as required. (e) Pole-grounds: (i) Reinstall pole-grounds where missing or broken; (ii) check ground rods and clamps; (iii) restaple ground wires; (iv) check connections, pole-ground to system neutral; (v) check for proper clearance, ground wire to pole hardware. (f) Rights-of-way: (i) Clear all trees, shrubs, branches to proper distance from conductors; (ii) remove or relocate antennas and other man-made hazards near conductors. - 113 - ANNE 2. 10 Page 3 of 5 (g) Conductors: (i) Reconductor sections of the primary line near substations where present or projected load would result in exces- sive voltage drop using existing conductors; (ii) re-sag, retie, and re-deadend existing conductor as required; (iii) replace tem- porary, incorree.t splices and sleeves with proper compression con- nectors. (h) Conductor Connections: (i) Replace temporary connectors in use at conductor deadends, tapping points with proper compression connec- tors; (ii) at points where electrical apparatus is connected to conductors, install proper hot-line clamps. (i) Line-Type Transformers: (i) Increase or decrease transformer sizes by replacement as necessary; (ii) add additional transform- ers where secondary-line loads are split; (iii) inspect and cor- rect as needed fuse protection on conventional transformers; (iv) and tighten all conductor-transformer connections. (j) Protective Devices: (i) Maintain existing OCRs; (ii) relocate OCRs as necessary; (iii) add additional OCRs as required; (iv) Relocate or add fused cutouts on all taplines, properly fused to coordinate with OCRs; (v) tighten all conductor-OCR connections. (k) Voltage Regulation: (i) Add line-type voltage regulators and ca- pacitors as required; (ii) tighten all conductor-regulator connec- tions. (1) Lightning Protection: (i) Connect all lightning arresters on new- ly installed combination fused-cutouts and arresters; (ii) inspect connections and gap settings on all existing arresters. 9. Secondarv Lines: (a) Poles: (same as for primary lines) (b) Hardvare/insulator2: (same as for primary lines) (c) Guys and Anchors and Pole-Grounds: (same as for primary lines) (d) Rights-of-Way: Clear all trees, shrubs, branches to proper dis- tance from conductors. (e) Conductors: (i) Replace bare open-secondary phase wire with insu- lated conductor along lines designated in illegal-connection ar- eas; (ii) "Split" secondaries to reduce load on individual trans- formers and to reduce energy losses; (iii) Re-sag, re-tie and re- deadend as required; (iv) Replace temporary, incorrect splices and sleeves with proper compression connectors. (f) Conductor Connections: Replace temporary, improper connectors in use at conductor deadends, junctions, tapping points, (including connections service drop wire to secondary conductor) with com- pression connectors. - 119 - ANNE 2. 10 Page 4 of 5 (g) Apparatus Connections: (i) Inspect and tighten all conductor con- nections at transformers and/or other apparatus; (ii) replace any aluminum-copper connections. 10. Service Lines. (a) Lift Poles: (i) Maintain in the same manner as primary and sec- ondary lines; (ii) install additional lift-poles to establish proper clearances above ground. (b) Pole-Deadend: Install proper bracket clevis or spool insulator at points where service-drop conductors are attached to poles. (c) Conductors: (i) Install larger-size duplex for large-residential and small commercial leads as warranted; (ii) Re-sag or rearrange duplex service drop wire in congested areas to eliminate wire con- tact with roofs or buildings and other obstructions; (iii) re-sag, re-deadend as required. (d) House-Deadend: (i) Install screw-type insulated wire holder (or clevis type insulated wire holder) where presently missing, and deadend properly; (ii) connect the duplex conductors to the ser- vice entrance conductors with compression connectors; (iii) in- stall insulated sleeve or tape protection over connectors (after the service entrance cable has been replaced). 11. Service Entrances. (a) Cables: (i) Replace all 2-J #10-CU NM entrance cable with conduc- tor of the concentric-neutral type; (ii) staple properly and con- nect to service-drop conductors with taped or covered compression connectors. (b) Grounds: (i) Inspect, reconnect, or replace grounds at consumers metering w.ocations to assure proper-solid grounding of neutral conductor, socket and meter. 12. kWh-Meter Installations. (a) Remove all socket type, IS" Base, meters from their sockets tempo- rarily. Check for jumpers in the meter sockets. Assure that sockets are properly attached to prevent turning. Assure that socket-hubs are sealed (or seal them) to prevent moisture and in- sects from entering. Tighten connections in sockets. Inspect kWh meters. Replace and reseal kWh meters. (b) Replace large quantities of 'A" Base, meters. Re-install new or newly tested kWh meters assuring that: (i) connections are cor- rect; (ii) terminal connectors are tight; (iii) double mounting- screws are installed to prevent meter turning; (iv) meter-cover tighten to prevent entrance of moisture; and (v) seal properly all kWh meters. Test kWh meters which were removed from service. Repeat the process until all "A" base meters have been tested. - 120 - ANNEX 2.10 Page 5 of 5 (c) Commercial and Industrial Metering Installations: (i) Test all three-phase kWh meters; (ii) determine applicability of meter to load; and (iii) check register-ratios on all meters. (d) Current transformer installation: (1) Verify size and ratio of current transformer; (ii) verify kWh-reading multiplier; (iii) protect current transformers and wiring by placing them in locked, properly installed REC-owned compartments. (Inspect and measure voltage output on power transformers if in use.) Technical Criteria for Assigning Priority to Rehabilitation Prosgects 13. Criteria for selecting among prospects for projects to rehabili- tate distribution systems would include: (a) Existence of non-standard voltage distribution lines on substation feeders (benefit to be realized by rebuilding to standard design is substantial). (b) Physical condition--exteat of typhoon damage. (c) Physical condition of distribution lines--extent of wood pole de- cay (a serious problem at most RECs). (d) Electrical condition--extent of overload, voltage drop, technical system-losses. (e) Extent of non-technical system-losses. (f) Importance of the substation service area by comparison to other REC-owned substations--presence of commercial or industrial loads. (g) Potential for additional consumer-connections. (h) Condition of distribution system electrical apparatus--trans- formers; OCRs, regulator.s, capacitors, lightning arresters, and - cutouts. (i) Electrical condition--phase imbalance, low power factor, section- alizing problems. (j) Physical condition--condition of guy-anchors; leaning poles; con- ductor sag. - 121 - ANNEX 3.01 Page 1 of 3 PHILIPP=E RURAL ELECTRIFICATION SECTOR STUDY NEA InvestMent Reguirements SuMvey 1988 Original Funding Reauirements 1988/89 (Pesos 000) Region Add-Ons Expansion Rehab Total I 9,890 19,251 47,771 76,912 II 16,480 12,359 53,559 82,398 III 10,671 79,446 96,459 186,576 IV 28,243 103,901 66,888 199,032 V 16,186 114,221 47,146 177,553 VI 40,000 30,000 130,000 200,000 VII 12,646 9.486 41,100 63,232 VIII 26,209 19,658 85,181 131,048 IX 12,449 54,065 14,851 81,865 x 24,506 18,380 79,645 122,531 xi 40,610 107,508 30,581 178,699 XII 3.126 8.376i -10.682- 22.184 TOTALS 241,016 576,651 703,863 1,521,530 - 122 - ANNME3.Q01 Page 2 of 3 PHILIPPINE RURAL ELECTRIFICATION SECTOR STUDY NEA Imestment ReqUirments Survey 1988 Revised Funding Requirements - 1989 (Pesos 000) Region Add-Ons Expansion Rehab Total I 3,501 2,502 27,665 33,668 II 4,455 8,487 17,758 30,700 III 5,900 7,001 31,099 44,000 IV 7,380 5,535 23,985 36,900 v 6,389 5,051 25,164 36,604 VI 12,446 5,000 18,440 35,886 VII 5,235 3,816 15,232 24,283 VIII 6,077 4,685 17,680 28,442 iX 4,856 17,336 15,302 37,494 X 8,477 5,205 16,220 29,902 xi 13,280 21,310 23,963 58,553 XII 3.490 2.2500J 10.700. 16.690 TOTALS 81,486 88,428 243,208 413,122 PUL1ITfNES- RID"L ELECIFIICATION SCIfiR STUDY 4 PHYSICAL TARGETS * - -~~4 t I a a a- a 1U aNtS. 20u 220 204, 21 215 2160 220 240, 25' Uoa 12. 2In 21 * . 4 . S. a S~~~~3 -X l a a Is m I*- In a a ft -lIj a, - . a-. ----- - --1 S .4 I a I~~onL' AMa I PI 2 a a a aII 2 U S S 1 16 a t, a 0 I & -.- - .a .4S~4 ~. - - - -&- 144 It~ -* .3045- I It 53 * , -1 I e-r, J- I 1 lE 2. 2, -? I . I0 ac II I? It I. I4 5? lY a a s a a a a , , , ,~~~~~~~~~#' , * - . -LIIISMUUUSa 4 C' .02 I'm * S,1 ox 04 .15 6 512 ft 150 ," . - 124 - ANNEX 3.02 Page 1 of 6 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Sample Feasibility Studies Benefit Calculation for Residential Consumers I. USE OF ALTERNATE ENERGY Kerosene: Initial Cost - P 800.00 Assumption: Fuel Cost - P 60.00/month Life - 10 years Repair = p 20.00/month i - 7% Annuity/month - P 9.287 Monthly Expenses P 9.287 + P 60 + P 20 3 P 89.29 Assumption: typical Cost per Kwh - e 89.29 kerosene use time about 24 two thirds of electric - P 3.72 lighting time. II. USE OF ELECTRICITY Cost of Housewiring - P 1,300 Assumption: Life 30 years Annuity/month - P 8.60 i 7% Cost per Kwh - P 8.60 - P 0.24 36 Adjusted cost/Kwh - P 1.98 + P 0.24 - P 2.22 III. INTEGRATION Adjusted cost of Assumption: - P 3.72 - P 2.22 + P 2.22 Linear sloping Electricity/Kwh 2 demand function _ P2.97 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUY Sample Feasibility St.udy- Expansion (Mainly Industrial) (Capiz) (P000) Year 1 2 3 4 S e 7 8 9 10 11-26 Incremental Sol a(Nwh.) - 1456 598 7499 7941 8894 8852 9121 9848 98 10611 Incrental purcae (15 los8) - 1718 5992 8822 6842 9876 10414 10731 10998 11680 12719 Incrental Benefit (tariff) - 2596 9055 15442 17694 20058 21128 21769 28241 25641 29620 Invest. Scot ('000) 8181 6842 8106 107 1s8 190 196 198 oo oo - Oi t5% 157 488 594 598 606 $18 888 888 648 648 Cone r Admin. Cost - 400 400 400 400 400 400 400 400 400 400 Coat; of purehase (0.72/Kw) - 1283 4814 852 6726 7110 7498 7726 7919 8a74 9169 UIIC of purchase (1.81/Kwh) - 2244 7860 11557 12288 12986 18642 14068 14407 152856 1882 Tot;alcost (fin.) 8181 7482 8258 7458 7908 8808 8711 89U2 9057 9562 10206 Tot. I coat (oeon.) 8181 8448 11794 12658 18420 14184 14856 15284 15545 16884 17710 N3 0 s wO 04 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Sample Feasibility Study - Rehabilitation & Add-on (P.lco I) (P '0O0) Year 1 2 a 4 5 6 7 8 9 10 11-26 Iner.. sales (MWh) - 2916 6804 6078 10780 10960 11172 11640 1188 12084 12896 Systemlsse(U) 24 22 22 21 20 19 18 17 18 1S 15 Inerem. pure (UWh) - 8837 8800 10228 13485 18640 13824 14024 14114 14218 14684 Inre.. revesue (P '000) - 6770 10588 16086 21891 21766 22149 23072 23631 28974 24589 leere. aeeon. benefit - 7828 14262 21889 29020 29525 80708 81960 81960 82669 a8382 Invest. cost (P'000) 7862 2880 2415 2825 86 44 37 38 39 46 - 0 M of 6 - 5688 61 1008 1284 lk. 1240 1248 1246 1249 1268 Consumer Admin. Cost - 160 160 1 160 160 180 160 160 160 60O System Lees Reduction Cost 498 493 498 498 493 498 493 493 498 498 498 0% Cost of purchas (P 1.146/Kwh) - 4898 7788 11705 16440 15508 16699 16057 18180 16277 18699 LRUC of purchase (1.81/Kwh) - 5026 8908 18892 17686 17787 17847 16871 18469 1628 19106 Total eost (fin.) 7846 684 11689 16191 17888 17487 17629 17991 18098 16225 18112 Tot I cost (econ.) 7846 9097 12791 17876 1968 19671 19777 20805 20427 20671 20518 01 0. Moo ts PHILIPPNES ___________ RURAL ELECTRIFICATION SECTOR STUDY Sample FeistbilIty Study - RwhabiIltation Only (Polcc I) (p.' 1000) Year 1 2 8 4 5 8 7 8 9 10-26 Volume (MWh) Sales without rehab. (HWh) 8166 8240 8a80 8482 8628 8824 8720 8828 89n8 4044 Sales wlth rehab. (1Wh) 8166 8872 8588 8804 4020 4238 4462 4O66 4884 6100 Inera. - Sales - 12 262 872 492 612 782 840 948 1058 Syet. lnoss w/o rehab. (%) 24 24 24 24 24 26 26 26 26 25 Syst. losses with rehb. (X) 24 28 22 20 18 16 15 14 18 12 Purcaseh /oJ rehab. (1Mb) 4158 4268 4889 4518 4642 4882 4960 6104 6248 6592 Purchae with rehab. (oMh) 4165 4879 4600 4766 4902 5043 5287 6478 6814 5796 Incrm. purchose - 116 116 211 289 288 211 277 874 e86 Capital cost a68 2482 1979 2816 14 14 14 14 14 - Non-tech. lose reduction cost 498 498 498 498 498 498 498 498 49B - O&i St SS of cap. costs 54W 745 904 1089 1090 1091 1092 1093 1094 Iners. cons. adtn. cost - 149 149 149 149 149 149 149 149 149 Cost ot inerem. purchse (P 1.146/Kwh) - l88 1l8 242 274 298 242 817 419 461 Total cost 7846 87s6 8785 8600 4185 2043 1968 2176 2163 1704 LRKC of Incrm. purchase (P1.8l/Kwh) - 152 276 813 846 276 686 490 479 628 Total cost 8416 8804 8642 4174 2090 2022 2110 2288 2228 1m Ebn.tit (P'000) Tariff bsd (P1.98/Kwh) - 261 499 787 9?4 1212 1449 1668 1877 2091 Econ. benefit (P.2.97/Kwh) - 392 778 1104 1461 1818 2174 2495 2816 8186 No sales growth: MWh purch. seved - 64 107 208 804 8s6 440 488 656 6es Cost saving bnewit - ?1 140 272 899 519 576 688 e88 ?42 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY --_______________________________ Sample Feasibility Study - Expansion (Mainly Residential) (Leyte V) (P000) Year. 1 2 8 4 6 6 7 8 9 10 11-26 Increm. sales (Sih) - 120 U41 615 1020 1506 1841 219 268 2953 U 80 Increm. purchase (165 loss) - 141 401 724 1200 1772 2166 2686 3042 8474 8988 Incrae. revenue (tariff) - 189 895 718 1186 1758 2149 2569 8024 8464 3966 Increm. econ. ben. (Res: 2.61/kWh) - 284 807 1485 2B10 3876 4041 4762 6621 6289 71t8 Invest. cost 2742 4758 4807 5014 5043 590 690 810 694 63 - 0oh of 5X - 187 376 605 85s 1103 1187 1167 1197 1227 1230 Corsumer Adamn. - 26 26 26 26 25 26 25 26 26 26 Cost of purchase (P 0.94) - 188 377 680 1128 1i66 2036 2431 2880 3266 3749 LRUC of purchase (P 1.12) - 158 449 811 1844 1965 2426 28sa 3407 8891 4487 Total cost (fin.) 2742 6048 5884 6824 7062 8383 8788 4233 4676 4681 5004 Tote cost (econ.) 2742 5073 5456 6455 72608 3703 4178 4e96 5223 6206 6722 09 Ph 0 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Sample FeasIbil7ty Study - Rehabilitation & Expansion (Tarlac II) (P'O000) Year 1 2 a 4 6 6 7 8 9 10 11-25 Incre. sa les (Nh) - 1452 6006 7403 8694 9127 9672 10221 10787 11411 12080 eM loss( t) 22 22 20 18 16 14 12 12 12 12 12 Increm. purchase (MIh) - 1862 7506 9028 10862 10812 10991 11815 12201 12987 18727 Inerem. f7n budget (tarirt) - 8365 11862 14490 17427 18202 19174 20105 21098 22292 23602 Inere. eeon. ben. (ros: 2.29/Kwh) - 4217 13237 16532 19699 20485 21684 22894 28754 26167 26559 Invest. cost (TP000) 9148 22048 9627 8966 278 808 822 304 879 46U - Ohm of S - 467 1660 2061 2501 2614 2580 2648 2561 2680 2603 Consumer Admin. Cost - - 190 too 190 190 190 190 190 190 190 190 Cost of purchase (fin) (0.97/Kwh) - 1806 8767 8757 10041 10294 10661 11287 11836 12678 13816 LRMC of purchase (1.81/Kwh) - 2489 11827 11627 13681 18902 14898 16216 15698 10967 17982 Total cost (fin.) 9148 24601 19986 1986 18008 18806 13708 14807 14965 15811 16108 Total cost (econ.) 9146 26134 23068 23068 16626 16914 17440 182568 19113 20220 20775 0. H,O - 130 - ANNEX 3.03 PHILIPPI=E RURAL ELECTRIFICATION SECTOR STUDY Sample Feasibility Studies - Results IRR NPV at 12% (%) (Pesos 000) Rehabilitation only (Pelco I) Financial -7.5 -16,080 Economic 1.8 -11,145 Rehabilitation with Add-ons (Pelco I) Financial 24.0 18,557 Economic 48.0 57,583 Extension based on residential (Leyte V) Financial 0.13 -13,634 Economic 3.7 -10,519 Extension based on industrial (Capiz) Financial 65 82,757 Economic 35 39,020 Rehabilitation with Extension (Tarlac II) Financial 11.0 -3,912 Economic 8.0 -12,987 Sample Financial Cost/Benefit Studies Financial IRR (%) Rehab Add-On Extension Albay I, II and III 12-15 - - Camarines II and IV 25 8 - Pelco I, II and III 95 - - - 131 - ANNEX 3.04 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Potential Savings from Construction Efficiency Improvements (a) The raising of distyibution voltage wherever possible will con- tribute to loss reduction; (b) A smaller size of conductor for distribution lines would lead to the following approximate savings, with little loss of reli- ability - Using ACSR No.2 instead of ACSR No.2/0 saves about P 5,200 per km., and using ACSR No.2/0 instead of ACSR No.4/0 saves P 3,400 per km. of line; (c) Increasing the normal pole span from 100 m. to 111 m. saves one pole per km. at about P 1,000 per pole; (d) Using a lower class wood pole provides a saving of about P 1,350 per km. of line; (e) A shift from horizontal to vertical alignment of conductor on the pole would address the prevalent problem of insufficient right-of- way to clear branches and foliage. Supply quality would improve while maintenance costs would not rise significantly; (f) The installation of unprotected transformers may lead to more out- ages, but perceived cost of an outage in rural areas is likely to be low; (g) A reduction in non-technical losses can be achieved by installing insulated wire on low-voltage lines, or by changing the current metering and billing system to prepaid card meters, or to an unmetered flat-rate charge where the risk of waste is low. On average, the cost of meters per km of line is about P 2,300; and (h) Significant efficiency gains could be achieved by introducing com- puter-assisted network design and planning. Appropriate and economical software and hardware is now readily available, and could be used by both NEA and the RECs in planning investments. - 132 - ANNEX 3.05 PHILIPPINES Page 1 of 2 RURAL ELECTRIFICATION SECTOR STUDY Rural Distribution Investment 1989-96 (Scenario 1) (P million) 1988 1989 1990 1991 1992 1993 1994 1995 Total Consumption (GWh) 2680 2796 3000 8239 3506 3803 4134 4608 Region 1: Rehab A Add-on 30.9 63.5 63.6 63.9 63.9 - - -------- Expansion - - 8.6 61.2 52.6 62.8 - Total 30.9 63.5 72.3 116.1 116.5 62.8 31.4 Region 2: Rehab & Add-on 21.7 47.4 47.4 47.4 47.4 - - Expansion - - 16.7 32.9 33.3 31.6 15.8 Total 21.7 47.4 64.1 80.8 80.7 31.6 16.8 Region 3: Rehab & Add-on 37.1 78.2 78.2 78.2 78.2 - - -------- Expansion - - 18.8 46.0 45.4 33.0 16.3 Total 87.1 78.2 92.0 124.2 12S.8 33.0 16.3 Region 4: Rehab A Add-on 80.0 23.4 28.4 23.4 23.4 - - _______- Expansion - - 18.8 46.0 45.4 33.0 26.9 Total 30.0 23.4 37.2 69.4 68.8 33.0 26.9 Region 5: Rehab & Add-on 31.5 121.8 121.8 121.8 121.8 - _ ---__-_- Expansion - - 13.0 110.4 112.4 18.1 9.1 Total 81.5 121.8 184.6 238.2 234.2 18.1 9.1 Region 6: Rehab & Add-on 24.4 48.1 48.1 48.1 48.1 - - -------- Expansion - - 13.8 46.0 46.4 83.1 16.6 Total 24.4 48.1 61.9 94.1 93.5 33.1 16.6 Region 7: Rehab & Add-on 20.4 24.6 24.6 24.6 24.6 - - -------- Expansion - - 4.4 40.6 86.1 34.8 26.1 Total 20.4 24.6 29.0 85.1 60.7 34.8 26.1 Region 8: Rehab & Add-on 29.3 55.7 56.7 56.7 55.7 - - -------- Expansion - - 9.5 82.1 29.8 24.1 12.0 Total 29.3 56.7 65.2 87.8 85.6 24.1 12.0 Region 9: Rehab A Add-on 19.8 11.1 11.1 11.1 11.1 - - -------- Expansion - - 27.9 26.4 28.3 22.6 12.1 Total 19.8 11.1 39.0 37.S 39.4 22.6 12.1 Region 10: Rehab A Add-on 22.2 36.7 36.7 85.7 35.7 - - -------- Expansion - - 13.8 46.0 45.4 62.9 18.5 Total 22.2 36.7 49.6 81.7 81.1 62.9 16.5 Region 11: Rehab A Add-on 84.1 22.2 22.2 22.2 22.2 - - …------- Expansion - - 15.7 28.7 21.9 24.6 12.3 Total 84.1 22.2 37.9 50.9 44.1 24.6 12.3 Region 12: Reheb A Add-on 18.1 6.8 5.8 6.8 6.8 - - --------- Expansion - - 3.3 17.7 48.0 44.4 22.2 Total 18.6 5.8 9.1 23.6 63.8 44.4 22.2 - 133 - ANNEX 3.05 Page 2- of~ 2 PHILIPPINES ___________ RURAL ELECTRIFICATION SECTOR STUDY Rural Distribution Investment 1899-94 (P milIton) 1988 1989 1990 1991 1932 1998 1994 Actual Projected Borrowing Ongoing projects (USS) 8.6 7.8 Committed or expected (USS) 24.4 24.7 21.1 1.8 1.9 Total (US$) 33.2 22 21.1 1.6 1.9 Total (P) E1] 710 471 452 84 41 Investment Scenario 1 E2] Rehabilitation & Add-on 81s 588 5s3 sa8 5as Expansion - - 1s4 630 sos Total 81s sa8 692 1068 1047 of which FX 265 448 564 860 648 Local SO 95 126 208 199 Investment Scenario 2 (8) Rehabilitation & Add-on 600 s60 700 ao0 - Expansion - - iso bSO soo Total 600 850 860 s50 soo of which FX SOO 700 700 700 400 Local - 19 250 68s 8s0 NEDA Plan (1988) Relending Program S0 Rehabilitation 65 824 228 Expansion 160 718 841 1102 les1 Total 705 1887 1089 1102 1668 Mini-hydro 815 a8 a886 814 168 Multi-fuel 684 84 59 44 4 FX funding 1158 808 829 915 NEA Plan (January 89) Rehabilitation & Add-on 667 408 s98 687 Expansion 88 855 740 1052 Alt. Energy 406 818 848 880 Total FX requirement 768 824 1172 1491 NEA Plan (draft Oct. 89) Rehabilitation/Upgrading 81 508 247 182 161 Ex pnsion 825 898 819 862 867 Other 82 128 126 e5 148 Totel 1268 1029 891 599 668 E USSI a P 21.4 Scenario 1: Rehabilitation and Add-on as per latest requets by coops, 90-98 estimated true requirements over 4 years. Expansion not before 91. (8] Scenario 2: Rehabilition i Add-on strongly concentrated In 89/90, reaInder 91/92. Expansion not before 91. - 135 - ANNEX 4.01 PHLIPPINES RMtAL ELECTIFlSTIP-N SECTOE STUDY Comarative Rate Levels for NPC's Luzon Grid Existing vs Revenue Neutral LRNC-Gas Turbine (#/kWh) Increase (Decrease) in Rates Theor. Adj. LRMC NPC Retail 43 LRMC Gas Turb. Theor LRMC Adj LRMC Extng L Cur Tar Rev Neut vs Extng vs Extng Utilities 0.98 1.01 0.96 0.03 (0.02) (0.03) Small 0.97 1.45 1.38 0.48 0.41 0.56 Private U 0.97 1.43 1.36 0.46 0.39 0.53 RECs 0.97 1.46 1.39 0.49 0.42 0.57 Medium 0.97 1.27 1.21 0.30 0.24 0.32 Private U 0.96 1.15 1.10 0.19 0.14 0.18 RECs 0.97 1.31 1.25 0.34 0.28 0.38 Large RECs LI 0.96 1.15 1.10 0.19 0.14 0.18 Angeles 0.96 1.02 0.97 0.06 0.01 0.02 Batelec II 0.97 1.35 1.29 0.38 0.32 0.43 Beneco 0.96 1.20 1.14 0.24 0.18 0.25 Olongapo 0.96 1.08 1.03 0.12 0.07 0.09 Pelco II 0.96 1.23 1 17 0.27 0.21 0.29 Meralco 0.98 0.97 (0.01) (0.06) (0.08) Non-Utilities 1.01 1.18 1.12 0.17 0.11 Industries 1.01 1.17 1.11 0.16 0.10 Miscellaneous 1.08 1.86 1.77 0.78 0.69 U.S. Gov't 1.01 1.10 1.05 0.09 0.04 Total Luzon 0.98 1.03 0.98 0.05 0.00 21. Effective November 8, 1988 billing month. ta Multiplier: Cooperatives: 1.35; Meralco: 1.4. Subject to changes in retail rate structures. /3 Above 20,000 KW Demand. - 136 - ANEX 4.02 Page 1 of 5 PHILIPPIB RURAL ELECTRIFICATION SECTOR STUDY Marginal Cost Analysis Costing Periods 1. While some of the grids show the beginnings of seasonal fluctuations involving a summer peak, the Luzon Grid is the only one with a pronounced summer peak. This is clearly apparent in both the plots of monthly generation and monthly sales. Based on these data, the peak season for the Luzon grid runs from April through November. 2. Based on preliminary estimates of load curves, Table 1 reports time periods and load variations for daily peaks. Table 2 then summarizes the lengths of these periods measured in hours. Capacity Costs 3. The generation and rransmission capacity considered is the same as that employed in the Energy Sector Study (Report 7269-PH; September 15, 1988), where the field work was conducted in February of 1988. Peaking capacity was identified as a proposed GT (gas turbine) unit and baseload capacity was represented by two proposed plants CAIACA 2 and BACMAN 1. While the basic data for (i) these plants, (ii) the transmission system and (iii) the associated transmission losses are used, the handling of plant outages is given alternative treatment. Plant Outagt 4. The generation capacity calculations are adjusted upwards to allow for planned and forced outages: for the GT peaking unit, the estimate for outages is 25.48% and for the, baseload units, the estimated outage rates are 13.59 % and 24.34%, respectively. The total of these outage rates is in the 25% range, which seem high. Also these adjustments as well as station energy use may more appropriately be handled by simply making a reserve margin adjustment. This approach has the effect of assuming a particular reserve margin in generating capacity as being needed to offset forced and unforced outages. This approach is used here; after the subtotal of capacity costs is computed, operation and maintenance expenses for the unit are added and then, arbitrarily, a reserve margin of 15% is added. In practice, the actual reserve margin available should be computed after some research to determine what the target should be. Marginal Capacity Costs 5. Tables 1 and 2 report the capacity cost results assuming a 12% and then an 8% real discount rate, and using the reserve margin adjustment. - 137 - Page 2 of 5 Table : IDENTIFICATION OF COSTING PERIODS 1, Power Grid Daily Peak Seasonal Peak Time/Days Months MW Variation 1. Luzon 7:00-23:00 Week Days April through November 2100MW-2650MW ETS Study I 6:00-23:00 All Days February through August 2. Cebu 7:00-23:00 All Days Not significant 754W-95MW ETS Study If No Seasonal or time-of-day structure 3. Negros 18:00-23:00 All Days Not significant 45MW-60MW ETS Study V 18:00-22:00 All Days Not significant 4. Panay 18:00-23:00 All Days Not significant 301W-50MW ETS Study V 18:00-22:00 All Days Not significant 5. Leyte-Samar 18:00-23:00 All Days Not significant 45MW-70MW ETS Study 21 18:00-22:00 All Days Not significant 6. Bohol 18:00-23:00 All Days Not significant 5MW-10MW ETS Study al 18:00-22:00 All Days Not significant 7. Mindanao 18:00-23:00 Wkday Only Not significant 450MW-560MW ETS Study 21 no time of day Jan through March & Aug. through Dec. .1/ 1988: 365 Days: 105 weekend days, 260 weekdays; holidays were ignored. ~/ ETS study was the Electricity Tariff Studf compiled for NPC by Electric de France in 1985-1986 - 133 - ANNEX 4.02 Page 3 of Table 2: LENGTH OF COSTING PERIODS IN 1988 V Seasonal Periods Power Grid Offpeak Peak Total 1. Luzon Months: Dec-March/4 mo April-Nov/8 mo Weekdays: Number (DaYs) 86 174 260 Hours: Peak (17) 1462 2958 4420 Off-Peak (7) 602 1218 1820 Total 2064 4176 6240 Weekends: Number (Days) 35 70 105 Hours: Peak 0 0 0 Off-Peak(24) 840 1680 2520 2. Cebu Months: No significant seasonal peak Weekdays: Number (Days) 260 Hours: Peak (17) 4420 Off-Peak (7) 1820 Total 6240 Weekends: Number (Days) 105 Hours: Peak (16) 1680 Off-Peak(8) 840 Total 2520 3. -N egros, Panay, Leyte-Samar, Bohol Months: No significant seasonal peak Weekdays:26 Number (Days) 260 Hours: Peak (6) 1560 Off-Peak(18)i 4680 Total 6240 Weekends: Number (Days) 105 Hours: Peak (6) 630 Off-Peak(18) 1890 Total 2520 4. Mindanao Months: No significant seasonal peak Weekdays: Nu b r (Da s) 260 Hours: Peak (6) 1560 Off-Peak(18) 4680 Total 6240 Weekends: Number (DaYs) 105 Hours: Peak ° Off-Peak(24) 2520 J/ No allowance is made for holidays and 1988 is treated as if there were only 365 days. Therefore there are 8,760 hrs in year, 105 weekends and 260 weekdays. - 139 - ANNE 4102 P-age 4 of S table-3: CAPACITY COSTS OF GENERATION No. Item Units Power Generating Station Loss (0) GT BACNAN 1 CALACA 2 1. Capital cost $/kW 350 690 900 2. Plant life yrs 15 25 25 3. Discount Rate % 12% 12% 12% Carrying Charge Rate % 14.68 12.75 12.75 4. Annual Cost $/kW/yr 51.39 87.97 114.75 5. Fixed O&M $/kW/yr .80 .63 .65 6. Subtotal $/kW/yr 52.19 88.60 115.40 7. Reserve Margin % 15% 15% 15% 8. Capacity Cost at Gen $/kW/yr 60.02 101.89 132.71 9. Capacity Cost at EHV " .5 60.32 102.40 133.38 10. Capacity Cost at VHV n 1.4 61.18 103.85 135.27 11. Capacity Cost at HV " 5.0 64.40 109.31 142.39 12. Capacity Cost at MV 6.0 68.51 116.30 151.48 Table 4: CAPACITY COSTS OF TRANSMISSION I No. Item Units _ Voltage Level ehv vhv hv mv 1. NPV of Investments $N 187.60 71.70 16.30 4.40 2. NPV of NW at Peak MW 1695.00 517.70 325.00 102.80 3. AIC $/kW 110.68 138.50 50.15 42.80 4. AIC/yr $/kW/yr 13.36 16.72 6.06 5.17 Including Losses: losses $/kW/yr 5. At EHV .5% 13.36 13.36 6. At VHV 1.4% 30.27 13.55 16.72 7. At HV 5.0% 37.92 14.27 17.60 6.06 8. At MV 6.0% 45.51 15.18 18.73 6.44 5.17 1/ Discount Rate: 12% Life: 45 years Period: 1987-1996 - 140 - ANNE 4.02 Page 5 of 5 Table 5: TOTAL CAPACITY COST (Real Cost of Capital at 128) No. Item Units GeQmratinz Station GT BACNAN 1 CAIACA 2 1. At generation $/kIW/yr 60.02 101.89 132.71 2. At EHV 73.38 115.25 146.07 3. At VHV 91.45 134.12 165.54 4. At HV 102.32 147.23 180.31 5. At NV 114.02 161.81 196.99 Marginal Energy Costs 6. Marginal energy cost calculations are taken directly from the earlier exercise attached. They are summarized in Table 9. Table 9: MARGINAL ENERGY COSTS Voltage at which Units Power Pricing Period Electricity Taken Losses Peak Offpeak Average At Generation UScts/KWH 4.67 2.46 2.80 At EHV UScts/KWH .5% 4.69 2.48 2.81 At VHV UScts/KWH 1.4% 4.75 2.51 2.85 At HV UScts/KWH 5.0% 5.00 2.64 2.85 At MV USctsl/KW 6.0% 5.32 2.81 3.19 - 141 - ANNEX 4.03 Page 1 of 3 PHILIPPINE RURAL ELECTRIFICATION SECTOR STUDY LRNC-Based pholesale Pricing 1. Since the billing period is one month, the annual capacity costs must be divided by 12 to convert them to monthly costs. These capacity costs have been calculated per kW of demand falling exactly at the system peak, or alternatively stated, per kW of coincident demand on the system. But, during the peak period for the Luzon Grid (7:00-23:00), not all customer groups or individual customers place their maximum loads on the system at the exact time of the system peak. Therefore the measured or metered maximum load that the REC places on the system during the peak period may not be that REC's total contribution to the system peak unless it occurs at the system peak itself. Thus capacity costs per kW are not appropriate for establishing, rates as they may not indicate the costs imposed on the system by the particular customer (REC, private utility, industrial customer, etc). Therefore a class coincidence factor (equal to 1/diversity factor) must be calculated for the customer in question. The formula for calculating demand charges is therefore: Demand Charge/KW - coincidence factor x monthly capacity cost/kW - (1/diversity factor) x monthly cap. cost/kW 2. An alternative approach might be to make the rate simpler by developing a single kilowatt hour charge that incorporates both capacity costs and energy costs while allowing for the issues raised above. One commonly used formula for calculating the per kWh marginal capacity charge component is: S14CC - MC=/(LFC x H) where SMCC the synthesized marginal capacity charge on a per kWh basis NC, - marginal cost of capacity in the billing period LFc the coincident load factor for the customer in the period H the number of hours in the period (Annex 3.03, Table 2) Data do not appear to exist for the coincident load factors for different NPC customers or customer groups. Therefore, the load factors given for the various customer groups are assumed to be approximately coincident. - 142 - ANNEX 4.03 Page 2 of 3 table 1: LOAD FACTORS Customer Group Load Factor Cooperatives .463 Industry .631 Private Utilities .668 Finally, completing the SHCC calculations and employing the information on marginal energy prices, Table 2 reports marginal cost TOD rates with syn- thesized marginal capacity costs for the RECs in the Luzon grid: Table 2: MARGINAL COST-BASED ELECTRIC RATES (per kWh) Customer Prices Group Peak Period Off Peak Averagell (7:00-13:00) (SIMCC + marginal (marginal energy price) energy price) Cooperatives: a. 8% real rate P .0276 + .0469 - P .0744 P .0248 P .05 of interest (P 1.56/kWh) (P .52/kWh) (P 1.05/kWh) b. 12% real rate P .035 + .0469 - P .0819 P .0248 P .053 of interest (P 1.72/kWh) (P .52/kWh) (P 1.12/kWh) 1/ Assumes constant consumption flow As a basis for comparison, if the Luzon Grid had no peaking pattern, then baseload capacity would be the marginal capacity; and in that case the marginal cost of supplying electricity on a per kwh basis would be as follows: -143- ANNEX 4.03 Page 3 of 3 Table 3: MARGINAL COST RATES WITHOUT SYSTEM PEAKS Capacity Energy Marginal Generating Cost Price Cost Plant mc/kWh - U 107.33/8760 + P .0281 - .04/kWh (CAIACA2) (P .84/kWh) mc/kWh - U 84.58/8760 + P .0248 - P .034/kWh (BACMANI) (i .714/kWh) - 144 - ANNEX 4.04 Page 1 of 5 PHILIPPINES RURAL ELEcTRIFICATION $ECTOR STUDY REC Cost of SUDYIV: Four Case Studies TARLAC II The case study for Tarlac II considers both rehabilitation and an investment program for expansion. Data from NEA's Project Appraisal Division regarding distribution costs show that in 1988, approximately one half of the investment was spent on expansion and one half on rehabilitation. In addition, of the investment going to expansion, 16% was for meters and street lights. Of the rehabilitation investment, 23% was spent for those same items; and, in 1989, as much as 34% of rehabilitation investment will be spent on meters and street lights. Table 1 summarizes the calculations in reaching marginal cost rates and an alternative average price for the Tarlac II Electric Cooperative. - 145 - ANNEX 4.0 Page 2 of 5 able 1.: MARGINAL COST CALCULATIONS AND RATES FOR TARLAC II 1. Present value of investment cost (a 000's) 9 85,627.4 (assume real discount rate of 8%) 2. Carrying charge rate 9.3679% 3. Annualized investment cost 9.3679*85627.4 a 8,021.49 4. Annual 0 & M expenses (9 000's) 9 2,603 5. Original Peak kW 590 kW 6. Peak KW after investments 4,249 kW 7. Increase in peak kW 3,659 kW 8. Annual Cost/kW (3+4/7) 9 2.9036 9. Cost attributable to expanding Peak kW (74%) 9 2.1487 (remove investment in meters & street lights) 10. Peak Period:(17:00 to 23:00 daily) Peak Hrs 2,555 hours Off-Peak Hrs 6,205 hours 11. Assumed coincident Load Factor: residential .5 commercial .6 industrial .7 12. Marginal Cost of Distribution Capacity: 9 2,148.7/(.5*2555) P 1.68/kWh 13. Energy Price/kWh sold with 15% power loss and 9 1.12/kWh wholesale price from NPC assumed: 9 1.29/kWh 14. Marginal Cost Rates: Peak 9 2.97/kWh Off-Peak 9 1.29/kWh 15. Adjustments for Rehab calculations: assume 1/2 of investment is for expansion then item 12 should be reduced by 1/2: SMCC - .5 * 1.68 - .84/kWh Marginal Cost Rates are then: Peak 92.13/kWh Off-Peak 9 1.29/kWh 16. Average Cost Rate calculation: (Investment Cost + O&M)/total kWh - 9 10,624,490/12,080,000 kWh - 9 .8795/kWh Reduce by 1/2 to eliminate #ehal): :R .43975/kWh Total Cost/kWh - 9 .43975/kWh + energy price - 1 .43975/kWh + P 1.29/kWh - } 1.73/kWh - 146 - Page 3 of 5 The case study for PELCO I considers only an investment program for expansion. Date from NEA's Project Appraisal Division regarding distribution costs, show that in 1989, that approximately 7% of the investment expense was spent on meters and street lights. In 1991 expenditures for these items was expected to drop to 4%. Table 2 summarizes the calculations in reaching marginal cost rates and an alternative average price for the Pampanga I Electric Cooperative. Table 2: MARGINAL COST CALCULATIONS AND RATES FOR PELCO I 1. Present value of investment cost (P 000's) P 14,479.9 (assume real discount rate of 8%) 2. Carrying charge rate 9.3679% 3. Annualized investment cost 9.3679*14479.9 P 1,356.46 4. Annual 0 & H expenses (P 000's) P 1,253 5. Original Peak kV 1,261 kW 6. Peak kW after investments 4,742 kW 7. Increase in peak kW 3,481 kW 8. Annual Cost/kW (3+4/7) P .749497/kW 9. Cost attributable to expanding Peak kW (74%) P .70827/kW (remove investment in meters & street lights) 10. Peak Period:(17:00 to 23:00 daily) Peak Hrs 2,555 hours Off-Peaic Hrs 6,205 hours 11. Assumed coincident Load Factor: residential .5 commercial .6 industrial .7 12. Marginal Cost of Distribution Capacity: 708.27(.5 * 2555) - P .554/kWh 13. Energy Price/kWh sold with 15% power loss and P 1.145/kWh wholesale price from NPC assumed: P 1.32/kWh 14. Marginal Cost Rates: Peak P 1.87/kWh Off-Peak P 1.32/kWh 15. Adjustments for Rehab calculations: (none) 16. Average Cost Rate calculation: (Investment Cost + 06M)/total kWh - P 2,609,460/13,931,496 kwh -P 0.187/kwh Total Cost/kWh P .187/kWh + energy price P .187/kWh t P 1.32/kWh P 1.51/kWh - 147 - M= 4.04 Page 4 of 5 LEYTE V The case study for Leyte V considers an investment program for both expansion and rehabilitation investment program. Table 3 summarizes the calculations in reaching marginal cost rates and an alternative average price for Leyte V Electric Cooperative. Table 3: MARGINAL COST CALCULATIONS AND RATES FOR LEYTE V 1. Present value of investment cost (P 000's) P 16,282.5 (assume real discount rate of 8%) 2. Carrying charge rate 9.3679% 3. Annualized investment cost 9.3679 * 14479.9 - P 1,525.33 4. Annual 0 & H expenses (P 000's) P 1,230 5. Original Peak kW 68 kW 6. Peak kW after investments 1,108 kW 7. Increase in peak kW 1,040 kW 8. Annual Cost/kW (3+4/7) P 2.64935/kW 9. Cost attributable to expanding Peak kW (94.5%) P 2.5036/kW (remove investment in meters & street lights) 10. Peak Period:(17:00 to 23:00 daily) Peak Hrs 2,555 hours Off-Peak Hrs 6,205 hours 11. Assumed coincident Load Factor residential .5 commercial .6 industrial .7 12. Marginal Cost of Distribution Ca,aeity: 2SW36 (.5 * 2555) 0 1.9598/kWh 13. Energ Price/kWh sold with 15% power loss and P 1.12/kWh wholesale price from NPC assumed: P 1.29/kWh 14. Marginal Cost Rates: Peak P 3.25/kWh Off-Peak P 1.29/k*h 15. Adjustments for Rehab calculations: (none) assume 1/2 of investment is for expansion then reduce item 12 by 1/2 to P .9799/kWh and the marginal cost rates are Peak P 2.27/kwh Off-Peak P 1.29/kWh 16. Average Cost Rate calculation: (Investment Cost + O&N)/total kWh - P 2 755 330/3,390,000 kWh Total Cost/kWh - P .81/kWh + ener price - P .81/kWh + P 1.29/kWh - P 2.10/kWh - 143 - ANNEt 4.04 Page 5 of5 CAPIZ I The case study for Capiz I considers only an investment program for expansion only. Table 4 summarizes the calculations in reaching marginal cost rates and an alternative average price. Table 4: MARGINAL COST CALCULATIONS AND RATES FOR CAPIZ I 1. Present value of investment cost (P 000's) P 11,712.19 (assume real discount rate of 8%) 2. Carrying charge rate 9.3679% 3. Annualized investment cost 9.3679 * 85627.4 - P 1,097.18 4. Annual 0 & M expenses (P 000's) P 648 5. Original Peak kW 570 kW 6. Peak kW after investments 4,088 kW 7. Increase in peak kW 3,518 kW 8. Annual Cost/kW (3+4/7) P .49607 9. Cost attributable to expanding Peak kW (remove investment in meters & street lights) 10. Peak Period:(17:00 to 23:00 daily) Peak Hrs 2,555 hours Off-Peak Hrs 6,205 hours 11. Assumed coincident Load Factor: residential .5 commercial .6 industrial .7 12. Marginal Cost of Distribution Capacity 496.07/(.5 * 2555) = P 0.388/kWh 13. Energy Price/kWh sold with 12% power loss and B 1.12/kWh wholesale price from NPC assumed: P 1.25/kWh 14. Marginal Cost Rates: Peak P 1.642/kWh Off-Peak P 1.25/kWh 15. Adjustments for Rehab calculations: 16. Average Cost Rate calculation: (Investment Cost + O&M)/total kWh P 0 1 745,180/10,811,448 kWh P p .i614/kWh Total Cost/kWh - P .1614/kWh + energy price - P .1614/kWh + P 1.25/kWh - P 1.41/kWh - 149 - AMEX 4.05 Pa-geIl of 2 PHILIPPS RURAL ELECTRIFICATION SCR SY Hypothetical Cases: Calculation of Mareinal Cost Rates for REC Customers A. Entire Plant Investment Considered 1. Current Cost of Investment in System: i 35,000,000 2. Investment attributed to Minimum System and Customer hook-up a 10,000,000 3. Investment Associated with capacity necessary for peak demand P 25,000,000 4. Calculation of CCR: Assume: r - 8% and T - life of investment - 25 years Then: CCR° 9.3679% 5. Annualized Investment cost: CCR * Item (3) -9 2,341,975 6. Annual 0&6 [10% of item (3)]: 9 2,500,000 7. Peak kW without item (3): 500 kW 8. Peak kW with item (3): 5600 kW 9. Increase in Peak kW: (8-7) 5000 kW 10. Annual Cost/kW: 1(5+6)/9] 9 968/kW 11. Costing periods and hours: Period Time Hours in Year i) Peak Daily: 1700 thru 2300 or 7 hours 2555 hrs ii) Off-peak Daily: all other hours or 17 hours 6205 hrs TOTAL 8760 hrs 12. Coincident load factor for Customer classes: i) Residential .5 ii Commercial .6 iii Industrial .7 - 150 - AM=E 4 Q5 13. Marginal Cost of Capacity Peof i) Residential: P 968/ .5*2555) W .758/kWh ii Commercial: P 968/ .6*2555) - .631/kWh iii Industrial: P 968/ .7*2555 - P .541/kWh 14. Energy P:ice/kWh sold with 158 power loss for all customer classes (it may be thatpower losses are different for the different classes--if so this needs to be taken into account) Assume flat wholesale rate: P 1.00/kWh Energy price/kWh sold: P 1.15/kWh 15. Marginal Cost Rates assuming flat rate pricirg by NPC at P 1.00/kWh. If NPC adopts Marginal Cost Prices, then all calculations below would have to be adjusted accordingly: i) Residential: Marginal Costs: Peak 1.15 + 7.58 - P 1.908/kWh Off-peak - P 1.15/kWh Since the benefits do not justify costs for time-of-day pricing for residential customers, a flat rate price should be set equal to a weighted average of Peak and Off-peak marginal costs. The weights could be the percentage of residential electricity consumption occurring in the periods or, without this information, the percentage of hours in each pariod could be used as a rough approximation. Assume 50% or Residential electricity usage occurs in peak period Residential price: 5*1.90P + .5*1.15 - P 1.529/kWh ii) Commercial: Marginal Costs: Peak 1.15 + .631 - P 1.781/kwh Off-peak - P 1.15/kWh If belefits do not justifv metering costs then a calculation similar to the one above wo;1d be made for these customers to obtain a flat rate. If the benefits do justify metering costs, then the marginal costs would be the prices in the costing periods. Hii) Industrial: Marginal Costs: Peak 1.15 + .541 - P 1.691/kWh 0ff-peak - P 1.15/kWh The analysis and rates for this case are determined along the same lines that were used for the Comercial case above. B. Incremental Investment in Plant The analysis for this case would proceed along the same lines as were used in the case above, except that items 1 and 2 would be interpreted as current value of all investment and current value of previous investment. - 151 - ANNE 4.06 Page I or PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY REC Performance Indicator8 Table 1: ALTERNATIVE FINANCIAL INDICATORS REC .P2}1 OP MAIDS CUSTI' ADNIN AVC 1. 11cOJ Norte 1.246 0.031 0.097 0.199 0.199 1.773 2. Ifugao 1.350 0.068 0.307 0.182 0.581 2.489 3. Quirino 1.157 0.034 0.123 0.225 0.429 1.968 4. Zambales I 1.190 0.023 0.028 0.076 0.090 1.408 5. Aurora 1.112 0.107 0.125 0.173 0.440 1.956 6. )Indoro Or. II 2.388 0.123 0.327 0.388 0.634 3.860 7. Quezon 1 1.096 0.043 0.072 0.096 0.135 1.442 8. CamarLnes Sur 1 1.212 0.083 0.058 0.115 C.375 1.843 9. Camarines Norte 1.327 0.031 0.105 0.115 0.159 1.739 10. Masbate 2.964 0.327 O.518 0.345 0.907 5.061 11. Sorsogon II 0.672 0.088 0.080 0.149 0.268 1.035 12. Capis 0.863 0.049 0.062 0.261 0.153 1.389 13. Central Negros 1.396 0.066 0.028 0.056 0.124 1.670 14. Guimaras 1.895 0.000 0.033 0.049 0.977 2.954 15. Iloilo I 0.922 0.032 0.072 0.180 0.167 1.373 16. Negros Occ. 1.280 0.050 0.058 0.128 0.151 1.667 17. Bantayan 2.699 0.043 0.119 0.273 0.371 3.505 18. Bohol I 0.824 0.055 0.102 0.128 0.175 1.285 19. Camotes 2.757 0.194 0.155 0.320 0.583 4.010 20. Cebu I 1.046 0.035 0.088 0.127 0.216 1.513 21. Cebu II 1.013 0.033 0.065 0.090 0.221 1.423 22. Cebu III 0.965 0.047 0.074 0.131 0.186 1.402 23. Negros Or. I 1.269 0.027 0.035 0.061 0.120 1.512 24. Negros Or. II 1.399 0.027 0.088 0.111 0.178 1.803 25. Biliran 1.263 0.220 0.182 0.239 0.591 2.495 26. Eastern Samar 2.749 0.182 0.143 0.273 0.580 4.028 27. Leyte IV 1.382 0.114 0.040 0.135 0.391 2.062 28. Leyte V 1.127 0.050 0.044 0.096 0.111 1.428 29. Northern Samar 2.519 0.089 1.504 0.775 2.581 7.469 30. Ssamr I 1.575 0.128 0.271 0.214 0.445 2.633 31. Zamboanga Norte 0.689 0.068 0.065 0.094 0.260 1.176 32. Zamboanga Sur II 0.637 0.066 0.134 0.138 0.220 1.195 33. Augusan Norte 0.715 0.038 0.056 0.099 0.114 1.022 34. Augusan Sur 0.699 0.037 0.055 0.135 0.259 1.184 35. Bukidnon II 0.700 0.049 0.055 O.G90 0.151 1.045 36. Mis:.mis Occ. XI 0.665 0.028 0.111 0.130 0.102 1.035 37. 4isamis Or. II 0.681 0.013 0.061 0.105 0.165 1.025 38. Siarga Is. 2.867 0.047 0.148 0.625 1.781 5.469 39. Surigao Norte 0.632 0.013 0.015 0.045 0.045 0.749 40. Davao Norte 0.685 0.021 0.119 0.092 0.173 1.089 41. Davao Sur 0.679 0.039 0.056 0.093 0.144 1.011 42. So. Cotobato 1 0.685 0.047 0.117 0.116 0.183 1.150 43. So. Cotobato II 0.707 0.009 0.058 0.068 0.076 0.918 44. Surigao I 0.627 0.047 0.055 0.122 0.186 1.038 45. Lanao Sur 0.682 0.012 0.111 0.044 0.063 0.913 46. Maguindanao 0.669 0.015 0.046 0.101 0.176 1.024 47. No. Cotabato 0.692 0.063 0.083 0.141 0.235 1.231 jI XF2 IPC price adjusted for losses V CUST Customer Account Expeaditures - 152 - AMUE 4. 06 Page 2 of 2 Table 2: NEA FINANCIAL INDICATORS R8C fP21P OPIP WAIXTIP CUSTIP AW4NP AVCIP 1. Ile.s Note 0.617 0.015 0.048 0.099 0.099 0.878 2. Ifug.o 0.582 0.029 0.132 0.079 0.251 1.073 3. Qulrn 0.480 0.014 0.051 0.094 0.178 0.817 4. Zembales t 0.696 0.014 0.017 0.045 0.053 0.823 5. Aurora 0.501 0.048 0.056 0.078 0.198 0.881 6. Klndoro Or. II 0.647 0.033 0.089 0.105 0.172 1.046 7. Queson I 0.672 0.027 0.044 0.059 0.083 0.884 8. CarLne ur X 0.635 0.044 0.031 0.060 0.196 0.ff5 9. Cmines Norte 0.710 0.017 0.056 0.061 0.085 0.930 10. Masbate 0.621 0.068 0.109 0.072 0.190 1.061 11. Sor"egon XI 0.328 0.043 0.039 0.073 0.131 0.505 12. Caplx 0.464 0.027 0.033 0.140 0.082 0.747 13. Central Negros 0.763 0.036 0.015 0.031 0.068 0.913 14. Gulmara 0.569 0.000 0.010 0.015 0.293 0.887 15. Iloilo I 0.555 0.020 0.043 0.109 0.101 0.827 16. Negros 0ce. 0.688 0.027 0.031 0.069 0.081 0.896 17. 1antayan 0.680 0.011 0.030 0.069 0.093 0.883 18. Bohal I 0.487 0.033 0.061 0.076 0.104 0.760 19. Cot.es 0.548 0.039 0.031 0.064 0.116 0.797 20. Cebu I 0.612 0.021 0.051 0.075 0.126 0.885 21. Cebu II 0.596 0.020 0.038 0.053 0.130 0.837 22. Cebu III 0.568 0.028 0.043 0.077 0.109 0.825 23. Negros Or. I 0.788 0.017 0.022 0.038 0.075 0.939 24. Negros Or. II 0.714 0.014 0.045 0.057 0.091 0.920 25. BIlIran 0.544 0.095 0.078 0.103 0.255 1.076 26. E"tern Samnx 0.770 0.051 0.040 0.077 0.162 1.128 27. Leyte IV 0.578 0.048 0.017 0.056 0.164 0.863 28. Leyte V 0.727 0.032 0.028 0.062 0.072 0.921 29. gorthorn Smar 0.648 0.023 0.387 0.199 0.664 1.920 30n game. I 0.553 0.045 0.095 0.075 0.156 0.924 31. Zmboauga Nortoe 0.482 0.048 0.046 0.066 0.182 0.822 32. Zamboanga Sur II 0.468 0.048 0.098 0.102 0.162 0.878 33. Augusan Norte 0.656 0.035 0.052 0.091 0.104 0.938 34. Ausuan Sur 0.310 0.027 0.040 0.099 0.189 0.864 35. Bukidno. IX 0.584 0.041 0.045 0.075 0.126 0.871 36. iantl.s Oce. II 0.593 0.025 0.099 0.116 0.091 0.924 37.N1-t1sm Or. XI 0.508 0.010 0.045 0.078 0.123 0.765 38. Strga Is. 0.540 0.009 0.028 0.118 0.335 1.030 39. Surgao Mortt 0.735 0.015 0.017 0.052 0.053 0.871 40. Davao Norte 0.561 0.017 0.097 0.075 0.142 0.892 41. Davao Sur 0.580 0.033 0.048 0.079 0.123 0.864 42. So. Cotobato 1 0.523 0.036 0.089 0.089 0.140 0.878 43. So. Cctobato II 0.693 0.009 0.057 0.067 0.074 0.900 44. Surngao I 0.575 0.043 0.051 0.112 0.171 0.952 45. Leona Sur 0.725 0.012 0.118 0.046 0.067 0.972 46. MaguLndanso 0.539 0.012 0.037 0.082 0.142 0.826 47. No. Cotabato 0.467 0.042 0.056 0.096 0.159 0.832 - 153 - ANX4.07 RURAL ELECTRIFICATION SECTOR STUDY SAmpe Cooperatives: Price and CO8t Comparisons among RECs (Pesos/kWh) REC Price/Cost Information (9Ikidh) (1) (2) (3) (4) (5) (6) (7) (8) MPhl' HP21 Ou4t CUSTIl' N?IPUMIA TOTCIQ PRICEZI CUST2a1 1. Ilos worte 0.98 1.25 0.13 0.40 1.37 1.77 2.02 16.99 2. Ifugao 1.07 1.35 0.38 0.76 1.73 2.49 2.32 17.68 3. QuirWIo 0.96 1.16 0.16 0.65 1.31 1.97 2.41 27.07 4, Eambales I 0.97 1.19 0.05 0.17 1.24 1.41 1.71 23.77 S Aurora 0.93 1.11 0.23 0.61 1.34 1.96 2.22 28.69 6. mindoro Or. II 1.52 2.39 0.45 1.02 2.84 3.86 3.69 7.91 7. Queson I 0.92 1.10 0.11 0.23 1.21 1.44 1.63 12.99 8. Cemerines Sur I 1.21 1.21 0.14 0.49 1.35 1.84 1.91 26.61 9. C=amrines Norte 1.12 1.33 0.14 0.27 1.47 1.74 1.87 32.83 10. Masbate 2.43 2.96 0.84 1.25 3.81 5.06 4.77 19.35 11. Sorsogon II 0.93 1.11 0.17 0.42 1.28 1.70 2.05 20.29 12. Capia 0.74 0.86 0.11 0.41 0.97 1.39 1.86 28.80 13. Central Negros 1.12 1.40 0.09 0.18 1.49 1.67 1.83 28.62 14. Gumaras 1.63 1.90 0.03 1.03 1.93 2.95 3.33 34.00 15. Iloilo 1 0.74 0.92 0.10 0.35 1.03 1.37 1.66 19.68 16. Negros Occ. 1.13 1.28 0.11 0.28 1.39 1.67 1.86 24.57 17. Bantayan 2.21 2.70 0.16 0.64 2.86 3.51 3.97 17.97 18. Bohol I 0.67 0.82 0.16 0.30 0.98 1.29 1.69 7.77 19 Cemotes 2.37 2.76 0.35 0.90 3.11 4.01 5.03 5.60 20. Cebue I 0.89 1.05 0.12 0.34 1.17 1.51 1.71 16.48 21. Cebu II 0.88 1.01 0.10 0.31 1.11 1.42 1.70 16.06 22. Cebu III 0.85 0.96 0.12 0.32 1.09 1.40 1.70 15.36 23. Negros Or. I 1.12 1.27 0.06 0.18 1.33 1.51 1.61 27.13 24. Negros Or. II 1.12 1.40 0.12 0.29 1.51 1.80 1.96 18.85 25. Biliran 1.02 1.26 0.40 0.83 1.66 2.50 2.32 15.81 26. Eastern Same? 2.16 2.75 0.43 0.85 3.18 4.03 3.57 8.33 27. Leyte IV 1.12 1.38 0.15 0.53 1.54 2.06 2.39 7.45 28. Leyte V 0.94 1.13 0.09 0.21 1.22 1.43 1.55 57.46 29. Itorthern Samar 2.30 2.52 1.59 3.36 4.11 7.47 3.89 13.13 30. Samr I 1.32 1.57 0.40 0.66 1.97 2.63 2.85 80.79 31. Zamboanga Norte 0.56 0.69 0.13 0.35 0.82 1.18 1.43 21.72 32. Zemboanga Sur II 0.56 0.64 0.20 0.36 0.84 1.19 1.36 21.39 33. Augusan Norte 0.58 0.72 0.09 0.21 0.81 1.02 1.09 22.94 34. Augusan Sur 0.58 0.70 0.09 0.39 0.79 1.18 1.37 27.11 35. Bukidnon II 0.63 0.70 0.10 0.24 0.80 1.05 1.20 23.35 36. Mlsamis Occ. II 0.56 0.66 0.14 0.23 0.80 1.04 1.12 18.92 37. lsadmis Or. 1 0.56 0.68 0.07 0.27 0.76 1.03 1.34 25.03 38. Siarga Is. 2.40 2.87 0.20 2.41 3.06 5.47 5.31 19.05 39. Surigao Norte 0.57 0.63 0.03 0.09 0.66 0.75 0.86 17.21 40. Davao Norte 0.57 0.68 0.14 0.26 0.82 1.09 1.22 29.10 41. Datao Sur 0.57 0.68 0.10 0.24 0.77 1.01 1.17 19.92 42. So. Cotobato I 0.57 0.68 0.17 0.30 0.85 1.15 1.31 21.97 43. So. Cotobato I1 0.57 0.71 0.07 0.14 0.77 0.92 1.02 25.11 44. Surigao I 0.57 0.63 0.10 0.31 0.73 1.04 1.09 24.94 45. Lanao Sur 0.56 0.68 0.12 0.11 0.81 0.91 0.94 20.34 46. Naguadmano 0.54 0.67 0.08 0.28 0.75 1.02 1.24 42.03 47. No. Cotabato 0.55 0.69 0.16 0.38 0.85 1.23 1.48 25.50 1IMP1 BPC price to REC at MP2 NPC price adjusted for losses I0 41M NEC O01 expenses per kWh I CUST1 Custosr and admdntstrative eaqpensoa Mi iPOet HPS-O- Item (2) * Item (3) 6I TOTC Total operating expenses (per kUh) I PR1CE Average price to consumers Ql CUST2 Customer and administrative expenses (per consumer) . . . .. ..* . .. . .. ....* . . . .. ..u *~~~~* * * *~~~~~~~~~~~. U'~t.04 K.~~~~~~~~~~~'o - 155- AN 4, 8 Page 2of 2 F 2 5.00 . . . ... . ... . PRICE IN PKWH* 4.50 .* . ........... 1. ** . ~ESTIMATED DEMAND FOR ELECTRICITY ** * LOGQ)=7.53751-1 74183*LOG(PRICE) 4.00 . . ... . . . . . ** 3.50 ** . . . . .j 3.00 . ** . . . . . . . . **. 2.50 . *.i . . . i 2.00 .* ] *. . . * . . . . . . . .i . . . .- 1.50 .. *. ........... ] 3.00 .... .°° 500] 1000! 1500. 2000. QUANTTY INkWh ANNEX 5.01 -157- PHILIPPINES RURAL ELECTRIFICATION SECTOR STUIDY REC Eaergy Usage TOTAL ENERGY USES- 1987 RATO5OL 5If OI2U sun (I 4*2)B(t1 " \\RRAL S R1=(20.1O sŽ\ '\*~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ - 153 - Page 1 of 2 PHILIZPPI RURAL ELECTRIFICATION SECTOR STUDY 25 Largest Rural Electric Cooperatives (by Number of Consunners) REC Location # Consumers Category 1 Central Pangasinan Electric Coop Luzon 77,192 C 2 Ilocos Norte Electric Coop Luzon 68,503 A 3 Pampanga II Electric Coop Luzon 64,067 D 4 Ilocos Sur Electric Coop Luzon 58,707 D 5 Batangas II Electric Coop Luzon 55,513 C 6 Batangas I Electric Coop Luzon 51,892 D 7 Central Negros Electric Coop Visayas 51,752 C 8 Quezon I Electric Coop Luzon 48,683 A 9 Bataan Electric Coop Luzon 48,446 D 10 La Union Electric Coop Luzon 46,780 C 11 Isabela I Electric Coop Luzon 41,185 C 12 Pangasinan III Electric Coop Luzon 40,601 D 13 Agusan del Norte Electric Coop Mindanao 38,743 B 14 Zamboanga City Electric Coop Mindanao 38,590 B 15 Benguet Electric Coop Luzon 36,503 D 16 South Cotabato II Electric Coop Nindanao 33,296 A 17 Davao del Norte Electric Coop Mindanao 31,713 B 18 Iloilo I Electric Coop Visayas 31,541 A 19 Nueva Ecija III Electric Coop Luzon 31,334 D 20 Nueva Ecija I Electrie Coop Luzon 30,845 D 21 Nueva Ecija II Electric Coop Luzon 30,766 D 22 Pampanga III Electric Coop Luzon 30,077 D 23 Bohol I Electric Coop Visayas 30,055 A 24 Negrcs Oriental II Electric Coop Visayas 29,751 B 25 Davao del Sur Electric Coop Mindanao 291.02 A 1,075,637 - 159 - ANN - 5.02 Page 2 of 2 25_Smallest Rural Electric Coogeratives (by Nunber of Consumers) REC Location # Consumers Category 89 Samar I Electric Coop Visayas 8,199 C 90 Occidental Mindoro Electric Coop Luzon 8,114 C 91 Marinduque Electric Coop Luzon 7,707 D 92 Iloilo III Electric Coop Visayas 7,282 C 93 Aurora Electric Coop Luzon 6,671 B 94 Quirino Electric Coop Luzon 6,147 B 95 Pampanga Rural Electric Coop Luzon 5,748 D 96 Kalinga Apayao Electric Coop Luzon 5,325 C 97 Basilan Electric Coop Mindanao 5,015 D 98 Quezon II Electric Coop Luzon 4,900 C 99 Eastern Samar Electric Coop Visayas 4,665 C 100 Mountain Province Electric coop Luzon 4,328 D 101 Sulu Electric Coop Nindanao 4,249 D 102 Ifugao Electric Coop Luzon 4,224 C 103 Tablas Island Electric Coop Luzon 3,551 C 104 Province of Siquijor Electric Coop Visayas 2,979 C 105 Masbate Electric Coop Luzon 2,976 C 106 Camiguin Electric Coop Mindanao 2,454 C 107 Northern Samar Electric Coop Visayas 2,162 D 108 Guimaras Island Electric Coop Visayas 2,066 B 109 Bantayan Island Electric Coop Visayas 2,000 C 110 Camotes Island Electric Coop Visayas 1,331 D 111 Biliran Island Electric Coop Visayas 997 B 112 Tawi-Tawi Electric Coop Mindanao 615 113 Siargao Electric Coop Mindanao 414 C 104,119 - 160 - 61ME 5.-03 Page 1 of 6 RURAL ELECTRIFICATION SECTOR STUDY Rural Electric CooDeratives National Summary Statement of Operations (9 Million) Year Ended December 31 1987 1986 1985 Operating R6.enues: 3,536.9 3,118.8 3,196.5 Operating Expenses: Power 2,467.4 2,170.4 2,423.7 Transmission 2.4 1.6 1.3 Distribution-Operation 90.5 79.8 74.8 Distribution-Maintenance 145.0 114.2 102.5 Consumers Account 244.9 211.2 198.4 Administrative and General 298.5 259.8 234.9 T o t a 1 3,248.7 2,836.8 3.035.6 Operating Margin 288.2 282.0 160.9 Depreciation Expenses 160.0 141.1 133.5 Interest on Long-Term Debt 132.2 129.1 115.9 Net Operating Margin (4.0) 11.8 (88.5) Non-Operating Revenue 56.0 59.2 60.3 Non-Operating Expenses (73.7) (60.2) (46.8) Net Margin (21.7) 10.7 (75.0) - 161 - Page 2 of 6 Rural Electric gooperatives Regional Summary Statement of Operations (P Million) Year Ended December 31, 1987 Luzon Visayas Mindanao Operating Revenues: 1,856.7 872.0 808.1 Operating Expenses: Power 1,354.3 604.4 508.7 Transmission .2 1.3 .9 Distribution-Operation 46.3 22.9 21.2 Distribution-Maintenance 68.8 29.5 46.7 Consumers Account 132.2 50.1 62.6 Administrative and General __138.2 73.7 86.7 T o t a 1 1.740.0 781.9 726.8 Operating Margin 116.7 90.1 81.3 Depreciation Expenses 66.9 43.4 49.6 Interest on Long-Term Debt 67.9 38.0 26.3 Net Operating Margin (18.1) 8.7 5.4 Non-Operating Revenue 26.8 16.8 12.4 Non-Operating Expenses (57.8) (8.3) (7.6) liet margin (49.1) 17.2 10.2 - 162 - ANN 5.03 Page 3 of 6 Luzon - Rural Electric Cooperatives Resuonal Suwmarv Statement of Operatfons (P M tion) Year Ended Oecdber 31. 1987 1 it III IV V Luzon Operating Revenues: 453.6 232.5 525.9 330.4 314.2 1t856.7 Operating Expenses: Power 323.2 143.3 436.4 233.3 218.1 1t354.3 Transmission - .1 - - .1 .2 Distribution-operation 11.5 6.1 10.4 7.6 10.7 46.3 Distribution-Maintenance 16.0 10.7 12.8 16.1 13.2 68.8 Consumers Account 33.7 16.6 30.1 26.9 24.9 132.2 Administrativ end General 34.9 17.6 27.9 25.2 32.6 138.2 T o t a t 419.3 194.4 517.6 309.1 299.6 1t740.0 Operating Margin 34.3 38.1 8.3 21.3 14.6 116.7 Deprecfatfon Expenses 15.6 11.7 12.5 15.9 11.3 66.9 Interest on Long-Term Debt 17.1 16.3 11.0 12.9 10.5 67.9 Net Operating Margin 1.6 10.1 (15.2) (7.5) (7.2) (18.1) Mon-Operating Revenue 8.4 5.6 S.0 5.0 2.8 26.8 Non-Operating Expenses (4.5) (1.7) £38.6) (2.5) (10.4) (57.8) Net Margin 5.6 14.1 (48.9) (5.1) (14.8) (49.1) OPERATING STATISTICS Mwuicfpalfties Served 143 107 91 125 108 Barangays Energized 3126 1425 1747 2062 1987 Houses Comnected 385724 174293 393635 267453 27M760 MMh Purchased/Generated 340196 149934 446786 213673 229297 MMb Sold 225871 101879 286875 157030 165148 Coop Consumption (NWA) 1282 566 970 2452 841 Systems Loss (In Percent) 33.22 31.67 35.57 25.36 27.61 Average Systems Rate (P) 2.01 2.28 1.84 2.10 1.90 Average Power Cost per kWh (P) 0.95 0.96 0.98 1.09 0.95 *Excludes non-operational electric cooperatives - 163 - ANNEX 5.03 Page 4 of 6 Visa'tas - Rural Electric Cooperatives Regional Summary Statement of oPperations (a Million) Year Ended Decenber 31, 1987 VI vII VIII Visayas Operating Revenues: 458.1 174.9 238.9 872.0 Operating Expenses: Power 303.9 112.9 187.6 604.4 Transmission .4 - .9 1.3 Distribution-Operation 14.2 3.6 5.1 22.9 Distribution-Maintenance 15.2 7.5 6.7 29.5 Consumers Account 28.3 10.4 11.4 50.1 Administrative and General 40.2 17.9 15.6 73.7 T o t a 1 402.2 152.3 227.3 781.9 Operating Margin 55.9 22.6 11.6 90.1 Depreciation Expenses 21.5 10.2 11.7 43.4 Interest on Long-Term Debt 14.2 7.6 16.3 38.0 Net Operating Margin 20.2 4.9 (16.4) 8.7 Non-Operating Revenue 9.3 3.9 3.5 16.8 Non-Operating Expenses (5.7) (.5) (2.1) (8.3) Net Margin 23.8 8.3 (15.0) 17.2 OPERATING STATISTICS Municipalities Served 128 120 112 Barangays Energized 1895 1605 1623 Houses Connected 265532 163604 150279 MWH Purchased/Generated 303367 115224 178939 MWH Sold 240865 96657 144601 Coop Consumption (MWH) 1757 773 1352 Systems Loss (In Percent) 20.02 15.44 18.43 Average Systems Rate (P) 1.90 1.81 1.65 Average Power Cost per KWH (P) 1.00 0.98 1.05 *Excludes non-operational electric cooperatives - 164 - ANNEX 5.03 Page 5 of 6 Mindanao - Rural Eltectl Coceratives Resional Suiary Statement of Ocerations (P milton) Year Ended Deceiber 31, 1987 IV X Xi XII Mindmnao Operating Revenus: 189.6 278.4 227.0 113.1 808.1 Operating Expenses: Pooer 127.6 .78.6 138.5 63.9 508.7 Transmission - .1 .1 .8 .9 Distribition-Operation 5.5 7.2 5.6 3.0 21.2 Datribution-Maintenence 9.0 14.2 16.4 7.1 46.7 Conwers Account 14.6 20.8 17.6 9.6 62.6 Administrative and General 16.5 28.8 28.0 13.2 86.7 T o t a t 173.2 249.7 206.2 97.6 726.8 Operating Margin 16.4 28.7 20.8 15.5 81.3 Depreciation Expenses 13.2 17.0 12.8 6.7 49.6 Interest on Long-Term Debt 5.5 8.9 5.6 6.3 26.3 Net Operating Nargin (2.4) 2.9 2.4 2.5 5.4 Non-Operating Reven 1.3 3.6 6.1 1.4 12.4 Non-Operating Expewses (.6) (4.8) (1.8) (.4) (7.6) fNet Margin (1.7) 1.6 6.7 3.6 10.2 OPERATING STATISTICS unicipalities Served 65* 112 76 94 Sarangays Energized 761* 1344 678 1332 Nouses Connected 122460* 217123 180184 99361 MWH PurchasedlGenerated 207437 310346 241538 113885 ON Sold 147391 269280 202582 90697 Coop Corsuptfion (MMn) 809 941 948 383 Systems Loss (In Percent) 28.55 12.93 15.74 20.02 Average Systems Rate (P) 1.29 1.03 1.12 1.25 Average Poter Cost per KWH (P) 0.62 0.58 0.57 0.56 *Excludes non-operational electric cooperatives - 165 - ANNEX 50 Page 6 of 6 Reoions With Acarecate REC Losses - 1987 Luzon Cooperatives: Net Incance/(Loss)-1987 Net Income/(Loss) - 197 Net Income/(Loss) - 1987 Region III Region IV Region V (Peso $000) (Peso '000) (Peso 000) Zambales 11 8,208 Palawan 3,328 Albay 11 2.141 Zambntes 1 3.611 Quezon 11 274 Albay 1 903 Tarlac 1 596 Quezon 1 (45) Cam. Sur 1 179 Pampanga Rural (160) Occ. Nindoro (100) Sorsogan 1 (331) Pampanga III (297) Aurora (159) Cam. Norte (626) Tarlac II (524) Batangas 1 (330) Masbate (936) Nueva Ecija 11 (5,641) Oriental Nin. 1 (381) Sorsogon II (1,397) Nueva Ecija III (8,355) Oriental Min. It (773) First Catan (1,590) Pampanga I1 (10,654) Narlnduque (833) Can. Sur II1 (1,964) Pampanga I (10,790) Dusuanga Island (907) Cam. Sur IV (3,288) Bataa (11,264) Batangas II (1,105) CaM. Sur II (3,474) Nueva Ecija I (13.591) Tpblas Islend (1,235) Albay III 4.432) First Laguna (2,637) Total (48,861) :bang _/A_ Totat (14,815) Total (5,103) Visavas Cooreratives: WIndanso Cooperatives: get Incomel(Loss)) - 1987 Net Income/(Loss) - 1987 Region VIII Region IX (Peso '000) (Peso c000) Leyte 1 2,332 Zasboange City 1.901 Leyte V 1,282 Zamroanga Sur 1 1,027 Leyte IV 779 Zanboanga Sur It 477 Leyte 11 (338) Zeiroanga Norte (108) Uortherm Samar C7&.. Basi tan (2,112) Siliran Island (805) Sultu (2,864) Easterm Samar (1,213) Tawf-Tawl N/A Leyte 11 (3,084) Samar 1 (3,749) Total (1,679) Samar I1 (4,538) Southern Leyte (4.831) Total (14,954) - 166 - ANNEX 5. 04 Page 1 of 3 P,HILIPPINZES RURAL ELECTRIFICATION SECTOR STUDY Rural Electric Cooneratlves Net C>eratins Income (Losses) Year Ended December 31, 1987 (p '00) Reaion Location REC Net Income (Loss) I III Luzon Nueva Eclja 1 (13,591) 2 III Luzon Bataan (11,264) 3 III Luzon Papanga I (10.790) 4 III Luzon PDan9gua it (10,654) S III Luzon Uueva EciJa III (8,355) 6 III Luzon Nueva Ecija II (5.641) 7 VIII Visayas Southern Leyte (4,831) -3 Vtil Visayas Sonar I1 (4,538) 9 V Luzon Albey III (4,432) 10 VIII Visayes Samar 1 (3,749) II V Luzon Cam. Sur 1I (3,474) 12 V Luzon Cam. Sur IV (3,288) 13 VIII Visayas Leyte it (3,084) 14 XII Nindanao Lanso Sur (2,965) 15 X Mindanao Nisamis Or. 1 (2,936) 16 IX Ninoanso Sulu (2,864) 17 IV Luzon First Lequnm (2,837) 18 IX Nindanao Basflan (2,112) 19 V Luzon Can. SW,r III (1,964) 20 V Luzon First Catanduenes (1,590) 21 1 Luzon Abra (1,508) 22 V Luzon Sorseon II (1,397) 23 IV Luzon Tablas Island (1,235) 24 VIII Visayas Eastern Samr (1,213) 25 11 Luzon Ifugao (1,116) 26 IV Luzon Bateangs 11 (1t105) 27 V Luzon Nasbate (936) 28 IV LuLon Susuanga Islan (907) 29 IV Luzon Narinduque (833) 30 VIII Visayes Bltlran Island (805) 31 VIII Visayas Morthern Samar (789) 32 X Mindanwo Nisonms Occ. 1 (77) 33 IV Luzon Or. Nindoro II (7M7) 34 11 Luzon Kalnga Apayso (656) 35 V Luzon Cam. Norte (626) 36 VI Vlsayes Central Negros (555) 37 Xi NfndEiso Surfgao Sur It (544) 38 tiI Luzon Tartac It (524) 39 X Nindanso Salrgao Istand (513) 40 IV Luzon Or. Nindoro 1 (381) 32 X Nindaneo Nisams Occ. 1 (7 33 IV Luzon Or. mIndoro II (773) 34 It Luzon Katinga Apeyao (656) 35 V Luzon CaM. Norte (626) 36 VI Vlsayas Central Negros (555) 37 XI NIndanso Surigao Sur 11 (544) 38 III Luzon Tarlae II (524) 39 X findanso Sairgeo Island (513) 40 IV Luzon Or. Nindoro I (381) - 167 - AN=I 5. 04 Page 2 of 3 Rural Electric Coomeratives Net Oaeratinm Incane (Losses) Year Ende December 31, 1987 (P '000) Resion Location REC Net Ircane (Losa) 41 VIII Visayas Leyte III (338) 42 V Luzon Sorsogon 1 (331) 43 IV Luzon Batangas 1 (330) 44 III Luzon Ppanga III (297) 45 XII Nindanao Lanao Norte (293) 46 X Nindanao Camiguin Island (254) 47 1 Luzon Sur (245) 48 VII Visayas Prv. of Siquijor (230) 49 III Luzon Papwanga Rural (160) 50 IV Luzon Aurora (159) 51 Xi Nindanao Surigao Sur I (129) 52 IX Nindanfo Zambo Norte (108) 53 IV Luzon Occ. Mindoro (100) 54 IV Luzon Ouezon I (45) 55 I Luzon Pangasinmn III (31) 56 1 Luzon Pangasinan 1 (15) 57 11 Luzon Cagayan 11 (9) 58 Vil Visayas Bantayan Island (6) 59 1 Luzon Nt. Province (2) 60 VII Visayas Camotes 65 61 I Luzon Pangasinan 1I 96 62 V LLmon Cam. Sur 1 179 63 X Nindanao Suriqao Norte 196 64 VI Visayas Guimaras Island 232 65 VII Visayas Negros Or. 1 237 66 IV Luzon Ouezon 274 67 VI Visayas Iloilo It 306 68 VII Visayms sBohol i 346 69 It Luzon Quirino 418 TO VII Visayas Cebu 1 438 71 X NIndanao First Bukidnon 462 72 1 Luzon Ilocos Sur 477 73 IX Nindanao Z'o Sur II 477 74 X Nindanao Agusan Norte 528 75 XI Nindanao Davao Oriental 568 76 III Luzon tarlac 1 596 77 VIII Visayas Leyte IV 779 78 X Nindanmo Nisamis Occ. II 873 79 V Luion Albay 1 903 80 VII Visayas Cebu 1111 907 - 168 - ANNEX% 5.04 Page 3 of 3 Rural Etltric Cootoratives Net Omratirn Ircon (Losses) Year Ended Decaber 31, 1987 (P '000) Relfon Location REC Net Incoew ELOssl 81 IX Nindanso Zanbo Sur 1 1,027 82 XI irndxano South Cota 1 1,032 83 VII Visayas Negros Or. II 1,089 84 X Nindanao Agusan Sur 1,234 85 XI Nindanac Davao Norte] 1,263 86 VIII Vissyas Leyte V 1,282 87 VI Visayss htoeto III 1,293 88 X Nfndac Nisasis 11 1,328 89 XI Nindwo South Cota 11 1,453 90 X Ntfndanao Sukidnon I1 1,460 91 XII NI ndmo North Cotabato 1,488 92 11 Luton Nueva Vizcea 1,557 93 IX Rindanao Zeabo City 1,901 94 VI Vsyas Vresco 1,958 95 1 Luzon Denguet 2,122 96 V Luzon Atbay I1 2,141 97 11 Luzon Cagyan 1 2,202 98 Vill V sayas Leyte 1 2,332 99 VII Visass Sdoot 1 2,393 100 Xii Nirdano Sultan Kudearat 2,509 101 It Luzon Isabeta II 2.798 102 XII indanao Naguindmnso 2,837 103 VI Vfsayes Capia 3,003 104 XI Nindwnee Oavao Sur 3,066 105 VII Viseys Cebu II 3,109 106 IV Luzon Palawan 3,328 107 III Luzon Zaidmates t 3,611 108 VI VWayas Itofto 1 3,644 109 1 Luzon Itocos Norte 4,673 110 VI V1sayas Nesros Occ 5,333 111 III Luzon Zalmbtes II 8,208 112 II Luzon Isabela 1 8,908 113 IV Luzon Lubang NhA 114 IX Mindanao Tawi-Tawl N/A - 169 - ANEX 5.05 Page 1 of 5 PHIIJPPINES RURAL ELECTRIFICATION SECTOR STUDY Rural Electric Cooperative National Summarv 8Elance Sheet (P Ml ttion) As of December 31 1987 1986 1985 ASSETS Gross Utility in Service 3,919.2 3,409.0 3,097.4 Accumulated Depreciation 1Z051.2) . (895.1) t761.7) get Utility Plant in Service 2,868.1 2,513.9 2,335.8 Construction Work in Progress 781.5 714.7 758.2 T o t a l 3,649.6 3,228.6 3,093.9 Other Property and Investment 69.1 52.1 48.8 Current and Accrued Assets: cash 107.8 105.4 63.5 Accounts Receivable: Energy Sates 725.2 696.4 726.7 Others 303.8 254.8 227.1 1,029.0 951.1 953.8 Materials and Supplies: Distribution Lines 502.4 469.8 454.8 Nousewiring 9.9 11.9 11.4 Others 57.7 53.6 48.1 570.0 535.2 514.4 Fuel Stock Inventory 8.2 10.0 8.1 Other Current and Accrued Assets 45.3 45.2 32.8 Total Current & Accrued Assets 1,760.4 1,647.0 1,572.6 Deferred Charges 1.003.9 966.2 954.1 Total Assets 6,483.0 5,893.9 5,669.4 LIABILITIES AND EQUITIES Equities and Margin Membership 14.5 13.8 13.4 Accumulated Margins (472.1) (366.0) (333.7) Other Equities and Margins 23.0 19.0 25.7 Total Equities and Margins (434.6) (333.2) (294.6) Long Term Liabilities: NEA Construction 4,378.3 4,286.1 4,232.6 Mini-Hydro 235.4 - - Dendro Thermal 105.8 -- Others 154.5 263.7 260.4 Total Long Term Liabilities 4,873.9 4,549.8 4,493.0 Current and Accrued Liabilities: Accounts Payable Power/Fuel and Oi 795.8 704.4 750.4 Others 233.1 208.5 183.0 Consuners Deposit 48.5 35.5 28.1 Other Current and Accrued Liabilities 7.1 581.5 400.1 Total Current and Accrued Liabilities 1,862.5 1,530.0 1,361.6 Deferred Credits Itj 1.2 147.3 109.4 Total Liabilities and Equities 6,48&.0 5,893.9 5,669.4 - 170 - E 5.05 Page 2 of 5 Rural Electrie Coooeratives Reoianat Ssmm( v Oaltane Sheet (P NilltIon) Totat As of December 31. 1987 Luzon Visavas indanso System A S S E T S Gross Utility in Service 1,767.3 1,076.3 1,075.6 3,919.2 Accumulated Depreciation (477.?) (298.9) (274.6) (1.051.2) Net Utitity Plant in Service 1,289.6 77.5 801.1 2,868.1 Constructfon Work In Progress 451.3 199.6 130.5 781.5 T a t a l 1,740.9 977.1 931.6 3,649.6 other Property and Investment 30.1 18.7 20.3 69.1 Current and Accrued Assets: Cash S7.8 35.6 14.4 107.8 Accounts Receivable: Energy Sales 436.0 155.1 134.1 725.2 Others 14.4 94.6 64.9 303.8 580.3 249.6 199.0 1,029.0 Materials and Supplies: Distribution Lines 269.8 133.5 99.2 502.4 Housewiring 5.0 2.3 2.7 9.9 Others 28.2 21.3 8.2 57.7 303.0 151.0 110.1 570.0 Fuel Stock Inventory 3.2 4.6 .4 8.2 other Current and Accrued Assets 22.4 12.4 10.5 45.3 Total Current & Accrued Assets 966.8 459.3 334.4 1,760.4 Deferred Charges 619.6 318.2 66.1 1.003.9 Total Assets 3,357.4 1M7.3 1,352.3 6,483.0 ___uUu auu m3u a__ #zz: LIABILITIES AND EQUITIES Equities and Margin Nembership 7.7 3.1 3.3 14.5 Accumulated Margins (455.) (93.2) 76.8 (472.1) Other Equities and Margins 10.3 17.7 (4.9) 23.0 Total Equities and Margins (437.8) (71.9) 75.1 (434.6) Long Term Liabilities: NEA Construction 2,128.2 1,276.9 973.1 4,378.3 Nini-Nydro 161.1 74.3 0 235.4 Dendro-Thermat 100.6 5.2 0 105.8 Others 82.5 4Q.1 31.9 154.5 Total Long Term Liabilities 2,472.S 1,396.5 1,005.0 4,873.9 Current and Accrued Liabilities: Accounts Payable Power/Fuel and Oil 613.1 112.7 69.9 795.8 Others 103.5 60.5 69.1 233.1 Consmners Deposit 18.2 20.0 10.3 48.5 other Current and Accrued Liabilities 472.4 207.2 105.4 785.1 Total Current and Accrued Liabilities 1,207.2 400.5 254.8 1,862.5 Deferred Credits 115.4 48.3 17.5 181.2 Total Liabilities and Equities 3,357.4 1, M .3 1,352.3 6,483.0 mmuu uuuuu inin - 171 - AM= S.OS Page 3 of 5 Luzon - Rural Electric Coomerative Realonal SummarY malance Sheet (P Nillion) As of December 31. 1987 I II tII IV V Luzon Gross Utility in Service 402.6 368.0 290.0 437.0 269.6 1,767.3 Accumulated Depreciation (107.6) (67.3) (97.9) (119.0) (85.9) (477.7) Net Utility Plant in Service 295.0 300.7 192.1 318.1 183.7 1,289.6 Construction Work in Progress 94.1 60.5 81.1 70.0 145.6 451.3 T o t a t 389.2 361.2 273.2 388.0 329.3 1,740.9 Other Property and Investment 17.5 2.6 2.0 4.7 3.3 30.1 Current and Accrued Assets: Cash 15.9 6.5 3.8 19.8 11.8 57.8 Accounts Receivabte: Energy Sales 106.9 48.0 130.4 45.5 105.2 436.0 Others 25.2 34.6 29.2 23.3 32.0 144.4 132.1 82.6 159.6 68.9 137.2 580.4 HateriaLs and Supplies: Distributien Lines 59.4 56.7 25.5 66.1 62.1 269.8 mouse*iring 2.3 .6 .4 .7 1.0 5.0 Others 3.4 4.6 4.0 12.7 3.6 28.2 65.1 61.9 29.8 79.5 66.7 303.0 Fuel Stock Inventory .9 - .1 1.7 .4 3.2 other Current and Accrued Assets 1.2 10.6 1.2 .7 8.6 22.4 Total Current & Accrued Assets 215.2 161.6 194.6 170.6 224.7 966.8 Deferred Charges 116.3 100.6 108.2 140.6 153.8 619.6 Total Assets 738.2 626.0 578.1 703.9 711.1 3.357.4 U=S==== 9 UU NU LIABILITIES AND EQUITIES Equities and Margin membership 1.9 1.0 2.1 1.4 1.4 7.7 Accumulated Margins (24.2) (27.0) (236.2) (99.4) (68.9) (455.7) Other Equities and Margins 2.2 .9 2.0 4.4 .7 10.3 Total Equities and Margins (20.1) (25.1) (232.1) (93.6) (66.8) (437.8) Long Term Liabilities: NEA Construction 459.6 446.4 353.6 501.1 367.5 2,128.2 Mini-Nydro 42.8 - 50.5 67.8 161.1 Dendro-Thermal 4.4 4.7 .5 91.1 100.6 Others 18.3 .9 8.5 40.7 14.1 82.5 Total Long Term Liabilities 525.1 452.0 362.1 592.8 540.4 2,472.5 Current and Accrued Liabilities: Accounts Payable Power/Fuel and Oil 82.8 11.3 336.6 60.2 122.2 613.1 Others 37.8 12.7 20.5 13.2 19.2 103.5 Consumers Deposit 6.0 3.2 4.2 3.2 1.6 18.2 Other Current end Accrued Liabilities 84.1 136.3 68.4 104.5 79.0 472.4 Total Current and Accrued Liabilities 210.7 163.5 429.6 181.2 222.1 1,207.2 Deferred Credits 22.5 35.6 18.5 23.5 15.4 115.4 Total Liabilities and Equfties 738.2 626.0 578.1 703.9 711.1 3,357.4 muUa_s #c u uu UW UUUU *=a=a - 172 - Page 4 of 5 visavas - Rural Electric Cooaeratives Reaional Sunarv Baelance Shoot (P Miltion) As of Decenber 31. 1987 VI Vil Vill Vimvas a s s E T S Gross Utility in Service 477.9 285.8 312.6 1,076.3 Accumutated Depreciation (144.3) (59.2) (95.3) (298.9) Met Utility Plant in Service 333.6 226.6 217.3 m.5 Construction Work in Progress 105.5 25.4 68.8 199.6 T o t a t 439.1 252.0 286.1 977.1 Other Property and Investment 10.6 3.7 4.4 18.7 Current and Accrued Assets: Cash 15.7 11.5 8.4 35.6 Accounts Receivable: Energy Sales 83.2 26.1 45.8 155.1 Others 57.8 16.8 20.0 94.6 141.0 42.9 65.8 249.6 Materials and Supplies: Distribution Lines 6.9 40.7 45.9 133.5 Housefiring 1.4 .3 .5 2.3 Others 12.5 1.7 7.0 21.3 60.8 42.8 53.4 157.0 Fuel Stock Inventory 3.5 .7 .4 4.6 Other Current and Accrued Assets 1.4 9.2 1.9 12.4 Total Current & Accrued Assets 222.3 107.0 129.9 459.3 Deferred Charges 139.7 77.1 101.4 318.2 Total Assets 811.7 439.9 521.8 1,7M7.3 = == = - LIABILITIES AND EQUITIES Equities and Nargin Neership 2.0 .8 .8 3.6 Accumulated Margins 11.5 7.0 (111.7) (93.2) Other Equities and Margins 6.6 7.0 4.0 17.7 Total Equities and Margins 20.1 14.9 (106.8) (71.9) Long Term Liabilities: NEA Construction 539.5 347.5 389.9 1,276.9 Nini-Hydro 21.0 17.1 36.2 74.3 Dendro-Thermal t 5.2 5.2 Others 15.4 2.8 21.9 40.1 Total Long Term Liabilities 575.8 372.6 448.0 1,396.5 Current and Accrued Liabilities: Accounts Payable Power/Fuel and Oil 60.7 16.4 35.7 112.7 others 33.0 12.7 14.8 60.5 Consumers Deposit 12.3 3.6 4.1 20.0 Other Current and Accrued Liabilities 89.3 7.5 110.4 207.2 Total Current and Accrued Liabilities 195.3 40.2 165.0 400.5 Deferred Credits 20.4 12.2 15.6 48.3 Total Liabilities and Equities 811.7 439.9 521.8 1,m.3 - 173 - ANNEX 5.05 °age 5 of 5 Nindanmo - Rural Electric Coooeratives Reaionat Sumuary Batance Steet CP MNi Won) As of December 31. 1987 IX X Xl Xil Mindanao A S S E T S Gross Utility in Service 286.8 355.8 262.1 171.0 1,075.6 Accumulated Depreciation M83.1) 86.5) (67.2) (37.8) (274.6) Net Utility Plant in Service 203.6 269.3 194.9 133.2 801.1 Construction Work in Progress 23.8 43.1 34.2 29.4 130.5 T o t a t 227.4 312.5 229.1 162.6 931.6 Other Property and Investment 6.1 6.7 6.6 1.0 20.3 Current and Accrued Assets: Cash (.8) 4.2 6.1 4.9 14.4 Accounts Receivable: Energy Sales 26.1 42.7 33.6 31.7 134.1 others 11.6 20.2 15.6 17.4 64.9 37.7 62.8 49.3 49.2 199.0 Materials and Sunplies: Distribution Lines 20.0 30.3 29.5 19.5 99.2 Nousewiring 1.0 .4 .8 .5 2.7 others 3.0 2.6 1.7 .9 8.2 23.9 33.3 32.0 20.9 110.1 Fuel Stock Inventory (.1) .2 .3 - .4 Other Current and Accrued Assets 1.0 2.8 6.0 .6 10.5 Total Current & Accrued Assets 61.7 103.4 93.6 75.6 334.4 Deferred Charges C5.3) 9.6 25.6 36.2 66.1 Total Assets 290.0 432.1 354.9 275.4 1,352.3 -u xmm m LIABILITIES AND EQUITIES Equities and Margin Nembership .6 1.1 1.0 .5 3.3 Accumulated Margins 6.6 (9.1) 31.8 47.4 76.9 Other Equities and Margins (10.4) 3.5 1.4 .5 (4.9) Total Equities and Margins (3.1) (4.4) 34.1 48.5 75.1 Long Term Liabilities: NEA Construction 215.2 317.4 240.7 199.8 973.1 Mini-Hydro O 0 Dendro-Thermal 0 . - 0 Others 6.0 18.2 4.1 3.6 31.9 Total Long Term Liabilities 221.2 335.5 244.8 203.4 1,005.0 Current and Accrued Liabilities: Accounts Payable Pouer/Fuel and oil 18.3 22.1 23.4 6.3 69.9 Others 12.5 28.4 20.4 7.9 69.1 ConsuIers Deposit .S 3.2 5.8 .7 10.3 Other Current and Accrued Liabilities 36.0 42.2 19.6 7.7 105.4 Total Current and Accrued Liabilities 67.2 95.8 69.2 22.5 254.8 Deferred Credits 4.6 5.2 6.7 .9 17.5 Total Liabilities and Equities 290.0 432.1 354.9 275.4 1,352.3 inuuUa inuaa upu pu == .ukut= - 174 - ANNEX 5.06 PHILIPPINES_ RURAL ELECTRIFICATION SECTOR STUDY Comparison of Loan Records NEA yeG RECs (o Million) 1985 1986 1987 NEA Long Term Loans Receivable 5,243 5,858 7,105 REC Long Term Loans Payable 4,493 4,550 4,874 Difference (NEA exceeds RECs) 750 1,308 2,231 COMPARISON OF LOAN PEORDS NEA yg E 0 7.2 - 7 - 6.9 6.6 4.4 4.L 4.6 a WEA I.-? L0N Am . MC L-T LOAN PAY ANNEX 5.07 -175- Page 1 of 4 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Distribution of RECs Among Performance Categories NATIONWIDE SUMMARY OF REC PERFORMANCE m of DMA 31. 1987 D~~~27.~~~ * ~A (1O.3M ~~~~~- I C ~3W 176 ANNEX 5.07 Page 2 of 4 46 A & B RATE-L REC. BY GEOGRAPHIC AREA AS OF OECEM 31. 1tV ( WZON (23.9 - (4.7X)i 31 D RATED REC9 BY GEOGRAPHIC AREA = of DECOD 31. t97 memo" (#9.,I V3AYvM (9.7%) * N\ -."\ -- f 2 x: .~. ..'. \ .. ' -..a . - 17/ - ANNE 5.07 54 LUZON RECV - SUMMARY OF PERFORMANCF - of DEWdMM 31, 1157 A (3.7%) Az: S .A D (41) 4 - / ~~~I J 3.1 31 V15AYAS REC8-SUMMdARY OF PERFORMACE - ot DIB6 .31. 105 ' A (2._ ) Av@~~~(10.1 ANNEX 5.07 - 178 - Page 4 of4 29 MINDANAO REC8-SUMMARY OF PERFORMANCE m of D _3 31. tOW C (17.2 A (41.4K \ X1 - 179 - ANNEX 5.0 Page 1 of 4 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Cost Profile Summary (f/kWh) Year Ended December 31, 1987 Luzon Visayas Mindanao Philippines Distribution Iurchased Power from NPC 0.9793 0.8671 0.5657 0.9038 Trans/Distribution 0.1564 0.1717 0.1755 0.1593 Other Prodn. Cost 0.0006 0.0733 0.0270 0.0068 Administration 0.0633 0.1199 0.1007 0.0706 System Losses 0.3339 0.2981 0.1608 0.3107 Total 1.5336 1.5301 1.0298 1.4512 Interest Expense 0.0787 0.0489 0.0214 0.0706 Total Cost 1.6123 1.5790 1.0511 1.5218 Profit 0.0642 0.0566 (0.0018) 0.0839 Selling Rate to End Users 1.6765 1.6356 1.0493 1.6058 GWh Sales 10,043 768 1,318 12,129 % of Total 82.8 6.3 10.9 100.0 % losses (kWh Sold vs. 21.8 18.9 15.7 21.0 Supplies) - 180 - ANNEX 5.08 Page 2 of 4 Cost Profile Summarv - Luzon (9P/k'Wh) Private RECs & Year Ended December 31, 1987 MERALCO RECs Utilities Utilities Total Distribution Purchased Power from NPC 0.9793 0.9793 0.9793 0.9793 0.9793 Trans/Distribution 0.1502 0.2228 0.0948 0.1966 0.1564 Other Prodn. Cost 0.0000 0.0000 0.0239 0.0048 0.0006 Administration 0.0567 0.0980 0.1381 0.1062 0.0633 System Losses 0.3184 0.6198 0.3042 0.5441 0.3339 Total 1.5046 1.9199 1.5403 1.8310 1.5336 Interest Expense 0.0818 0.0712 0.0070 0.0563 0.0787 Total Cost 1.5864 1.9911 1.5473 1.8873 1.6123 Profit 0.0618 (0.0191) 0.0404 (0.0047) 0.0642 Selling Rate to Eend User 1.6482 1.9720 1.5877 1.8826 1.6765 GWh Sales 8,828 932 283 1,215 10,043 % of Total 87.9 9.3 2.8 12.1 100.0 % losses (kWh sold vs. 20.6 32.1 19.9 29.6 21.8 Supplies) - 151 - ANNE 5.08 Page 3 of 4 Cost Profile - Visayas (0/k'Wh) Private Year Ended December 31, 1987 REC8 Utilities Total Distribution Purchased Power from NPC 0.8671 0.8671 0.8671 Trans/Distribution 0.2592 0.0931 0.1717 Other Prodn. Cost 0.0000 0.1492 0.0733 Administration 0.1317 0.1093 0.1199 System Losses 0.3265 0.2734 0.2981 Total 1.5845 1.4920 1.5301 Interest Expense 0.0639 0.0356 0.0489 Total Cost 1.6484 1.5276 1.5790 Profit 0.1884 (0.0714) 0.0566 Selling Rate to End Users 1.8368 1.4562 1.6356 GWh Sales 362 406 768 % of Total 47.1 52.9 100.0 % losses (kWh Sold vs. 19.2 18.6 18.9 Supplies) - 182 - Page 4 of 4 Coat Profile $mmary - Mindanao (0/kWh) Private Year Ended December 31,1987 RECs Utilties Total Distribution Purchased Power from NPC 0.5657 0.5657 0.5657 Trans/Distribution 0.2023 0.1421 0.1755 Other Prodn. Cost 0.0000 0.0612 0.0270 Administration 0.0976 0.1047 0.1007 System Losses 0.1999 0.1166 0.1608 Total 1.0656 0.9903 1.0298 Interest Expense 0.0339 0.0069 0.0214 Total Cost 1.0994 0.9973 1.0511 Profit 0.0273 (0.0372) (0.0018) Selling Rate to Had Users 1.1267 0.9600 1.0493 GlWh Sales 706 612 1,318 S of Total 53.6 46.4 i00.0 % losses (kWh Sold vs. 18.6 12.0 15.7 Supplies) - 183 - ZliLLUEIEU~~ANNX .0 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY REC General Managers - Board vs. NRA AnDointments (as of February 1989) Luzon Visayas Mindanao Total Board Appointments 32 19 23 74 NEA Appointments 23 12 8 43 Total 55 31 31 117 REC GENERAL MANAGERS flD vs ASOINTE0 40- 30 20 10- LUZON VIST1AS ml GRfl4IC MM I f r At I MppoO CM WA Appointea - 184 - ANNEX 5.10 Page 1 of 2 PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Loan Releases to RECs (Per NEA Records) (U Million) Region 1971-83 1984 1985 1986 1987 1988 Total 1 351.7 43.9 79.8 21.5 6.8 49.6 553.3 2 369.8 37.7 4.4 46.6 4.3 8.6 471.5 3 317.8 34.8 29.2 81.6 14.6 356.1 834.3 4 424.4 41.1 18.9 154.3 15.7 55.6 710.0 5 318.9 23.1 11.7 76.6 7.1 148.1 585.5 Luzon 1,782.8 180.5 144.1 380.8 48.4 618.1 3,154.6 6 424.5 28.9 5.2 55.3 56.9 23.8 594.7 7 201.7 16.9 25.2 124.5 32.4 17.9 418.7 8 331.0 24.0 9.0 64.4 24.1 ('.1) 450.5 Visayas 957.1 69.9 39.5 244.3 113.4 39.7 1,463.8 9 184.1 17.9 6.3 39.1 4.2 8.9 260.5 10 223.0 29.6 10.0 11.5 226.2 13.0 513.3 11 191.7 15.3 9.8 11.5 54.2 9.7 292.3 12 152.3 14.6 5.3 8.9 31.7 16.3 229.0. Mindanao 751.2 77.4 31.3 71.0 316.3 47.9 1,295.0 Total 3,491.1 327.7 214.9 696.0 478.1 705.7 11 5,913.5 Annual Releases 317.4 327.7 214.9 696.0 478.1 705.7 Excluding Relending Program 205.7 1L Peso 500 million was disbursed as part of the REC relending program - 185 - Page 2 of 2 Annual Leading to the RECs (P Million) LOAN RELEASES TO RECs aoo t - - - - - - - ___ '00- I X o' /~ XI 4 r AVG 71- 1t94 tm lo low 9 WR a t_ EsJ do d AN= 6.01 - 187 - PHILIPPINES RURAL ELECTRIFICATION SECTOR STUDY Foreign Lending to NEA - By Source LOAN RELEASES TO NEA ms Xm U mMm_ 10- X 0 P H I L I P P I N E S (UN BEGUEVA THE RURAL ELECTRIC COOPERATIVE SYSTEM /BENGLJET ~~~~~~~LUZON AREA RE N C NUEVAIO QIUIRINO -- EleOdrc Coopeortive, Inc. Boundaries /UIRtlECO @ o Nalionol Capitol PANEICI A GS PANI/Il 0 M11or-Towns -LNPLGASI I --- Provinea Boundarns cEwrio Region Boundares IRIC I NUEVO ECIJA \ ZAMLCO I f/ IT1 t-A ) IV~~~~~~~~~~~NLIC L lb - ARlooA II 0 0 0 j2oo 9 /TA>RLAC \MICOICTA KICO5 -t PAMPANGA I _ ANI I~~~~~~~~FUI Bolongo0 LA aATAAN tn NCR *7RWU /MCANIEA IASlNA \ ) \ CAMARINES T4'~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~4 BATA,NGAS QUEZON L [UBANG K 'AS'L' *I.t J CATANDIJANES tLL>e vO °0iur L~~L~~ /0 '~~~Batanga CAMARINES SUR MARINDMQUE \ I IV v A A / f AIBAY 0leggzpi c ct rr MI~~NDOROI *, MINDORO . I SORSOGON cW0a ou rraa-ia Iatldm F, t.. CapM,f qt " ,..au 0 _ t nt __. 120' 12Z ' \ 124' *ttRD21766 . < CooMpn \ M\A\R.IPHILIPPINES o \ M-MRANR THE RURAL ELECTRIC COOPERATIVE SYSTEM Lt4aW 2a- <,, ORIENrA \ VISAYAS AREA ORIENWAL MINDORO OR-[co OCCIDENTAL i 0 as / [ . . . \ \ ~~~~~~~~ ~ ~ ~~~~~~~ ~ ~~~~~~~~~Rmborcn 77CAO \/ \ Rom 1bbbl 11CAOsote NORTHERN SAMAR -- g ! ROMBLON MASBATE -12' _1 . SASsFCCOI g1~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1 AE( WESTER N \ DoIo 12: frb=a 9't0sM // BUSANq$AFL,o \ / __ |SAMAR \ EASTM BUeSAN6N C l1gan 0 SAMAR _t__S_ __ // / \ AA0tLACoN / z ., . _ . r _12. BICOtb60 \ aECI )EML BIIRIAN \ S NAICC )\ a X 1 1 \-----2vIlcoe 1 \ VA( |~~~~~~~~~~~~~~~~~AIQN [c / AAN71QUE< O / \ ELCo I~~~~~~~~~~~~~~~AKLC //11(8 /1 1CC ILECO/111 V v IV y lloiloO - ~~~~~~~~ ~ ~~~~~~~~~~~~VI vi-) CECIC EC*Co\\ // 124// |~I GUIMARAS¢/ CNC T/ 2/ PAlf(O 7g ~~~~~~~~~~ ~~ ~ ~~~~~~ ~ ~~~~ ~~~GWlAEtCO / CEEE /| /SCUlfN/ NEGROS \ /VE~~cCet2O / SQLECO //mans O Puerlo PrinaWc // OCCIDEN0A5/ o< J // '0~ >vITZIyX/// IROMETBM ~ ~~~~~~~~~~~~~~~~1P1C BNAVAN //~~ ~ ~~~ ~ ~~~~~~~~~~~~~~ p S/Eecric Copwaiw, Inc Boundedes /NORECOn IIbo O^jw // o~~~~~~~~~ Maijrlbo"s NOCcyn/ 5ECO4 B (gcHl cnC" 1 // ~~~~~--- Prrmince Boundcra A EE EO v - ~~~~~~~~~Re_'ionBondcries/ INA1/ \ ILECOO 11 I_/ O-O/ ANTIQUE \ d DunuetP SQUIOR ' 11 r0p0 IOLOMETE- MT C (IEQ cMOE IloIIo~~~~~~ VJ. - CEICO ~~~~~~~~~~Y1 ~ ~ ~ UGYOW . . . . .4, , , , IpRD: NEGROS J z | LEYpE f;/CEBU I OCCDENTAL / sWEco O C a D E N D A / / C E 8 U t l ~~~~~~~S U R I G A O /lw / / OEL NORE / / BOHW ) - - - - g BOHO S64RGAO I0*~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ P H I L I P P I N E S /NECGROS/Sno M THE RURAL ELECTRIC COOPERATIVE SYSTEM / / BOHOL / S MINDANAO AREA /CU \ /~~~~~~~~~~~~~CM f AGUSN E he ric C o rati v e, b x. E on d o nes D N R tE EC O t1 o MojorTowns , ~~~~~~~~--- Proirn>BoundonB e/ Butuon° / SURIGAO RegionBound6ies mORESCOI ANECO D SUR / apd¢9O MISAWS O)RIENT N O I / ZA~~~~LNEOO OCCIDENb4 MORESCO I- r AGUSAN \5RSECO I / \ _ _ o > 4~~~~MELI bUSECO DEH SUR ~ 8' IGO zk14io _ _ _ _ _ ZA M'V~URECO F C ANECO tL~Mor AwA ~~~1OI~~~~~~ETW ~ ~ ~ ~ ~ ~ ~~ ~ZAMBANGA DE Si ktESS~~ ~ ~~~~~~~~~~~~~~~~~~ /~ A/ D^8^N L SUR SJ( F;O / DANECO \ / // ZAMSURCO LANAO DEL SUR DAVAO DEL NORE / ZAMSEJEOA ARC E OT / / / DAVAO -otobot 0' /< t_ , ) 1 OTagum ORIENTAL / \ Z^M80ANGA IXB mColbot o NORTIH Davcio DORECO CITY MAGUINDANAO \ COTABATO /o / \o - XT I \ ~~~~~~~~~~~~~~~ ~ ~~~~~~~~~~COTELCO/ O W BllSmon \ MAGEL OI DASURECO C: // - 8~~~~~~~~ASILAN \~ '4 {{ c WELCO ~~~~~~SULT~AN orai DAVAO _ _ _ _ _ _ _ _ _ SUJKELCO SOCOTEC IUZON ' ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~I TAUtlAWV TAWELCO .\ .1MFDANAC A Ara12fM,op 12 T~~~~~~~~~~122 26' AUG