Nepal - Power subsector review

Report No. 6879a-NEP Nepal Power Subsector Review January 15, 1988 Industry and Energy Operations Division Country Department I Asia Region FOR OFFICIAL USE ONLY 6otumen~ of th Wol .B.nk ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~a Ths ocmet asa etrctd isriuto ,. may be .; b c only ; t .0 K~~~ ~ ~~~~ _ .:. ., ., _,~~~' K, 2 ,, 2 K, -K~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~. .~~~~~~~~~~~ E botument~~1 ofte oldDn 2~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ This dcumen has resticteddistrbutio-and ay beused y recpient only in) th pefanco thi fiildte.Iscnet a o tews be dicoe wIthu;ol akatoiain  CURRENCY EQUIVALENTS 1 Nepalese Rupee (NRe) 100 Nepalese Paise US$1 (November 1987) = NRs 22.0 (Official Rate) = NRs 22.0 (Free Market Rate) WEIGHTS AND MEASURES 1 Kilovolt (kV) = 1,000 volts (V) 1 Kilowatt (kW) 1,000 watts (W) 1 Megawatt (MW) = 1,000 kilowatts (kW) 1 Kilowatt - hour (kWh) = 1,000 watt - hours (Wh) 1 Megawatt - hour (Mwh) = 1,000 kilowatt - hours (kWh) 1 Gigawatt - hour (Gwh) = 1,000,000 kilowatt - hours (kWh) ABBREVIATIONS ADB - Asian Development Bank ADB/N - Agricultural Development Bank of Nepal BEI - British Electricity International CCD - Corporation Coordination Division (Ministry of Finance) CIDA - Canadian International Development Agency CIWEC - Canadian International Water and Energy Consultants DCS - Distribution and Consumer Services Directorate (Nepal Electricity Authority) ED Electricity Department FCN - Fuelwood Corporation FMIS - Financial Management Information System HMG/N - His Majesty's Government of Nepal JICA - Japanese International Cooperation Agency kgoe - Kilogram Oil Equivalent LCGEP - Least Cost Generation Expansion Plan LRMC - Long Run Marginal Cost MOF - Ministry of Finance MPPU - Multi-Purpose Power Unit MWR - Ministry of Water Resources NCL - Nepal Coal Limited NEA - Nepal Electricity Authority NEC - Nepal Electricity Corporation NPC - National Planning Commission OECF - Overseas Economic Cooperation Fund (Japan) O&M - Operations and Maintenance PSC - Public Service Commission RE - Rural Electrification RECAST - Research Center fGr Applied Science and Technology TMIS - Technical Management Information System toe - Tonnes of Oil Equivalent WEC - Water and Energy Commission WECS - Water and Energy Commission Secretariat WERDP - Water and Energy Resources Development Project HMG/N FISCAL YEAR July 16 to July 15  NEPAL F01 OMFCIAL USE ONLY POWER SUBSECTOR REVIEw Table of Contents Page No. EXECUTIVE SUMMARY A. Introduction and Principal Findings ................... ix Background ......................................... ix Principal Findings .................................. ix B. Major Issues .......................................... x Improving Institutional Performance ....*............. x Future Electricity Supply and Investments ........... xii Electricity Pricing * .............................. xiii Planning ........... xiv Bulk Exports to India xv Rural Electrification xvi I. THE ENERGY SECTOR ......................I1 A* Institutions 1 B. Energy Rtesources 3 Fuelwood .. 3 Hydropower eegeggeeeggegggggee.eeeggege.ggge.ege.eege 4 Other Renewable Energy Sources ...................... 5 Petroleum 5............................ ............ S C. Trends in Energy Consumption and Supply ............... 5 Energy Consumption ...............e.. .......... 5 Energy Supply 7.................. 7 D. Energy Pricing ... . .. . ..... 9 This report is based on contributions by D. T. O'Leary (Systems Planner), S. Mukherji (Financial Analyst), J. Vance (Firancial Analyst), R. Addison (Power Engineer, ADB), A. Adhikary (Consultant), R. Benson (Consultant), J. Irving (Consultant), L. Maistre (Consultant) and B. Russell (Consultant) on the basis of a joint IDA/ADB mission to Nepal in January/February 1987. The report was written by D. T. O'Leary. Production of the report was supervised by A. Thornton. This document has a restricted dWibution and may be usod by tecipients only in thd pefonnane of their offAcW duties Its contents may not otherse be disclosed whout World Bank authortion.  -iii- Page Mo. II. ORGANIZATIONAL STRUCTURE .........................,........ 11 A. Power Subsector Organization ...... .................... 11 Historical Development .............................. 11 B. The Nepal Electricity Authority ....................... 12 Background **t*****O********O.*O*gO*OO****4**O***@**4 12 Autonomy . ............0..................... 12 Developing Coherent Corporate Goals ................. 13 Organizational Cohesiveness *6 13 Conditions of Service ....... ............ 14 Manpower Planning is............. 15 Training 16 Corporate Planning in NRA ...... .17 Operating Systems and Procedures 18 Preparation of Job Descriptions 19 C. Role of the Private Sector in Rural Electrification ... 19 III. HISTORICAL TRENDS IN THE SALE AND SUPPLY OF ELECTRICITY .... 21 A. Past Trends in Electricity Sales 21 Electricity Sales Data 21 Growth of Sales .......o21 Electricity Sales by Sector 23 Load Characteristics ....24 B. Past Trends in Electricity Supply ...o......... 25 NEA Interconnected System 25 VRA Isolated Systems 28 System Losses 28 Privately Owned Generation 31 C. Power Exchange with India 31  -iv-. Page No. IV. FORECiST CONSUMPTION AND SUPPLY OF ELECTRICITY ............. 33 A. Institutional Responsibilities for Planning 33 g. Growth of the Economy ..... .34 C. Future Electricity Demand 35 NEA Load Forecast for the Interconnected Network 35 Load Forecast for Isolated Centers 9 36 Follow-up Work in Demand Forecasting 37 D. Future Electricity Supply for the Interconnected System 38 6eneration 38 Transmission 44 Distribution *..... ... * 45 S. System and Operational Planning ....................... 47 System Planning * .................................... 47 Operational Planning .......... ..... * ............... 49 P. Rural Electrification ................ ................. 49 RE Action Plan .........e ............................ 50 V. ELECTRICITY PRICING .......... .5................2............. 52 A* Current Situation 52..................... .... 52 Institutional and Legal Framework ................... 52 S. Historical Review * .................................... 53 C. Economic Costs of Supply .............................. 54 D. NEA's Present Tariff ....*e.s..ee.ee ....ee........e 55 NUA Tariff and LRMC ...*** .......................... 57 Short-Term Strategy to Increase NEA's Average Tariff Towards LRMC .......... .... ............ 59 S. Tariffs for Private Sector Schemes .................... 59  Page No. VI. INVESTMENT AND FINANCE *...*e*eooeeeoeoeo*eeeee...e*e..* 61 A. Past Investment * ...................................... 61 B. Financing Past Investment ............................. 62 Government Arrears .................................. 63 C. Future Investment . 64 Financing Future Investment ......................... 65 NEA's Financial Performance Objectives and Financing Plan ................................ ... 66 Income Tax . 68 Macroeconomic Perspective of NEA's Investment Program ...................................... 68 VII. ELECTRICITY TRADE WITH INDIA ............................... 72 A. Development of an Export Strategy ..................... 72  -vi- LIST OF TABLES IN TEXT Table Page No. 1 High Priority Actions for the Development of the Power Subsector xviii 1.1 Final Energy Consumption, 1971-1985 6 1.2 Energy Consumption by Consumer Category, 1981-1985 8 1.3 Energy Supplies, 1971-1985 8 3.1 Electricity Sales and Supply, 1976-1986 22 3.2 Electricity Sales by Sector, 1976-1985 24 3.3 Growth of Capacity of the Nepal Interconnected System, 1976-1986 ..................... 26 3.4 NEA Transmission Facilities (January 1987) .......0...... 27 3.5 NEA Distribution Facilities (33 kV and below) (January 1987) ..................... 27 3.6 Generation and Sales Statistics for NEA Operated Isolated Systems, 1976-1986 ....... ................... 28 3.7 IEA Loss Reduction Program s Targets and Performance ... 29 3.8 Summary of Exchange of Energy with India, 1976-1986 .... 32 4.1 Growth and Composition of GDP, 1975-1985 .........0...... 34 4.2 Salient Characteristics of Candidate Hydroelectric Projects 40 4.3 Provision of NEA Distribution Facilities under Committed Finance (1986/87-1989/90) ...--.-.......... 46 5.1 Average Revenue from Electricity Sales, 1975-1987 .... 53 5.2 Structure of NEA Costs of Supply, Allowing for Seasonality .........................c...ecec....**c 55 5.3 Comparison Between 1987 Tariff Levels and LRMC .c....... 58 6.1 Capital Expenditure, 1981/82-1985/86 .................... 61 6.2 Sources of Financing for NEC/NEA's Development, 1981/82-1985/86 ...................................... 62 6.3 NEA's Investment Program, 1986/87-1995/96 *.............. 65 6.4 NEA Financing Plans for 1986/87-1996/97 under Two Scenarios ...... ... 69 6.5 Summary of NEA's Forecast Operating Results for 1986/87-1995/96 .....e70 6.6 Comparison of the NEA Investment Program with the EMG Investment Program, 1986/87-1995/96 .................. 71 LIST OF FIGURES IN TEXT 4.1 Capacity Balance for the Least Cost Generation Expansion Plan 43  -vii- LIST OF ANNEXES Annex Page No. 1. Proposed Strategy for the Development of the Power S u b s e c t o r ~~~~~~~~~~~78 1.1 Energy Balance for 1984/85 .......88 1.2 Fuel Prices 1972-1985 .................... 89 2.1 Organization of Energy Sector 0.......................... 9 2.2 Organization of the Water and Energy Commission Secretariat ........................................... 91 2.3 Organization of Nepal Electricity Authority * ........... 92 2.4 NEA Performance Targets 1985/86 and 1986/87 ............ 93 2.5 NEA Authorized and Existing Manpower at December 31, 1986 * .................................... 94 2.6 NEA Salaries * .......................................... 95 3.1 Electricity Supply and Consumption, 1976-1985 .......... 97 3.2 Typical Daily Load Curves for the NEA Interconnected System oo..oo.otoo..................... 98 3.3 Existing Generating Plants on the Interconnected s8ystem .................................................. 9 3.4 Existing Grid Substations (132 and 66 kV) .............. 100 3.3 Existing Transmission Lines in Nepal (1987) - Interconnected System ................................. 101 3.6 Integrated Power System Diagram ........................ 102 3.7 List of Existing Isolated Power Facilities Operated by NEA o..oo..ooooooo.oooooo......................... 103 3.8 Captive Power Plants ..................0................ 103 4.1 NEA 1986 Load Forecast for the Nepal Interconnected System *....**.....*................................... 106 4.2 Load Forecast Scenarios for the Interconnected System ................................................ 107 4.3 Forecast Electricity Supply in Isolated Centers, 1985-2005 ... .......... .................................. 108 4.4 Capacity Balance - NEA Least Cost Generation Expansion Plan oo........................o......o......... 109 4.5 Energy Balance - NSA Least Cost Generation Expansion Plan ........................................ 110 4.6 Technical Review of the Arun-3 Hydroelectric Project ... 111 4.7 Transmission Projects under Construction and Planned, 1987/88-1995/96 .............000 .....0..0.0....00000..... 117 4.8 Growth in NEA Transmission Facilities, 1985/86-1995/96 ...................... ..............o.... 119 4.9 Small Hydropower Stations ....... ....................... 120 4.10 NEA Proposed Distribution Extensions without Funding *o*t*eo****o*e-*oo*-o**e*-****oo***o***oooooo* 122 4.11 Micro-Hydropower Stations - Small Rural Electrification Program, ADB/N 123  -viii- Annex Page No. 5.1 Past and Present NSA Tariffs ......................... 124 5.2 Normalized Load Duration Curve, NEA .................... 126 6.1 Historical Financial Statements, 1981/82-1985/86 ....... 127 Forecast Financial Statements, 1986/87-1996/97 ......... 127-130 - 62 Rate of Return .* ..oee...eos..*.e..eo.* oeo 128-130 - Series of Alternative Increases 131-133 Debt Service Schedule ................... 134-138 6.2 Notes and Assumptions for Financial Forecasts .......... 139 7.1 Reports Available in the PSR Files ....... .............. 144 MAP: IBBD 19917  -ix- NEPAL POWER SUBSECTOR REVIEW EXECUTIVE SUMKARY A. Introduction and Principal Findings Background i. Nepal's power system is still in the early stages of development. Through its estimated 200,000 customers it provides electricity to approximately 6% of the population, whose average consumption of 25 kWh/month is one of the lowest in the world. However, the country has a vast hydroelectric potential, which has been estimated at about 83,000 MW, of which 25,000 MW have been investigated at different levels of detail and only 160 MW developed thus far. His Majesty's Government of Nepal (HMG/N) views the efficient exploitation of this enormous resource as one of Nepal's most important economic priorities because of the need to reduce substantially the cost and improve the availability of power to the domestic market and the potential for export of competitively priced hydropower to India. The Nepal power subsector faces numerous impediments to its development, chief of which are the lack of a well-defined tariff policy and institutional weaknesses in the subsector, primarily in the Nepal Electricity Authority (NEA)--the national public power utility. The principal objective of this report is to help HMG/N strengthen its policies and institutions for the efficient development and operation of the power subsector. It does not cover all aspects of the subsector, Sut rather focuses on areas which merit prompt attention and with potential for rapid improvement or reform. Principal Findings ii. The report reviews a wide variety of issues and makes many detailed recommendations (see below and Table 1). The following recommendations merit particular emphasis: (a) Change power tariffs so that they allocate Nepal's scarce power resources in ways most beneficial to the Nepalese; in particular, (i) raise rates 61 annually, in real terms, to bring them in line with the :ctual social cost; (ii) charge higher rates to users during peak times, to reflect the higher cost of generating that electricity; and (iii) introduce meters that permit making these charges.  x - (b) Change planning and management procedures, so managers can effec- tively undertake the changes recommended in the report; in par- ticular, (i) "twin" NEA with another utility to facilitate management train- ing; (ii) issue letters of appointment to all NEA staff and base their promotion on performance; and (iii) hire consultants necessary to undertake the detailed design and preparation of tender documents of the Arun-3 Hydroelectric Project and a master plan for nationwide tranamis- sion/distribution development at least cost. (c) Engage in further research and negotiation on two major issues: (i) sale of hydroelectric power to India; and (ii) proper design of the plan for rural electrification. The report summarizes these issues in the balance of this section and discus- ses them in more detail in subsequent chapters. B. Major Issues Improving Institutional Performance iii. The Nepal Electricity Authority (NMA) was created in August 1985, by amalgamating a number of different public entities, primarily the Electricity Department (ED) and the Nepal Electricity Corporation (NEC). It reports to the Ministry of Water Resources (MWR). NEA faces an immense challenge: over the next 10 years, it expects to manage a US$1.06 billion (in current terms) development program, which would be the largest ever undertaken in Nepal in any sector. Also, as part of the execution of the program, it may need to prepare and negotiate a bulk electricity supply contract with India (para. xvii). To succeed in these tasks, NSA needs to address three key issues: (a) improvement of NSA managers' understanding and application of basic utility management concepts and tools; (b) preparation of a corporate development plan; and (c) improvement of cond .tions of service for its employees.  -xi- iv. Utility ManagLent. In order to function effectively, NEA neels to pay particular attention to ensuring that its day-to-day operations are managed effectively. However, its managers have not been able to apply modern concepts and techniques to NEA's management. To address this issue, NUA has decided to enter a "twinning" arrangement with a suitable utilityt preferably in a developing country, for the training of NEA staff. As a final step NEA needs to define the scope of the twinning arrangement, with management training as a first priority but not confined to management. The twinning arrangement could include the secondment to NEA of some senior staff from the "twinning" utility. v. Preparation of a Corporate Development Plan. NEA would benefit considerably if it could implement its expressed objective of institutionalizing an annual corporate planning cycle, which is mandated by the NEA Act as part of an overall process to enable NEA to set flexible, realistic targets for its integrated institutional development and HMG/N to monitor NEA's progress in achieving them. The corporate development plan (CDP) cycle would include the preparation or updating of the load forecast, the least cost expansion program (generation, transmission, and distribu- tion), a set of long-run marginal cost (LRMC) tariff proposals based on the program, a series of projected 10-year financial statements based on the present and proposed tariffs, and corporate-wide manpower and associated training plans. To date, NEA has been unable to undertake the preparation of the CDP~ primarily because of staffing constraints. Consequently, NEA should estimate and deploy the staff required to prepare the first CDP. NEA would benefit from technial assistance to assist in preparing the first CDP and provide training to NRA staff responsible for preaMring subsequent CDPs. vi. Conditions of Service. NUA's performance is being undermined by inadequate conditions of service which are contributing to poor staff dis- cipline, low morale and the exodus of qualified staff. A major contributory factor to unsatisfactory staff performance is the NEA compensation package, which is not competitive with the private sector. A related problem is the issue of promotion, which at present gives heavy weight to seniority. However, beginning in 1988, NRA will have more freedom to base promotions on job performance. To provide incentives for improved staff performance, NEA should review the present conditions of service to identify areas where they could be improved, focusing on (a) the compensation package, paying par- ticular attention to the structuring of allowances and fringe benefits, and (b) establishing criteria for measuring and improving/rewarding individual manager and staff job performance, as appropriate.  -xii- Future Electricity Supply and Investments vii. NEA, in collaboration with CIDA and IDA-financed Canadian consultants has developed a least cost generation expansion plan (LCGEP) to identify the priority investments. A 20-year load forecast (1986-2006) was developed and a power system simulation model was used to identify the combination of existing and new projects that would satisfy the load forecast at least cost. Although NEA has taken Iajor steps in identifying the priority investments in the power sector, particularly in generation, there is a need for follow-up work to identify complementary investments in transmission and distribution and to ensure that the generation investments are commissioned on schedule. viii. NEA forecasts that the total demand for electricity within Nepal on the interconnected system would increase at an average annual rate of approximately 10% during 1986-2006. Because of the needle load shape during the peak period, it is considered feasible to reshape the peak load growth (without any change in energy demand) by restructuring NEA's tariffs in 1988 (para. xiv). This could lead to a progressive increase in the load factor from 50% to 54% in the near term. ix. From a portfolio of eight candidate hydroelectric projects (each of which had been studied to ei;her the prefeasibility or the feasibility level) plus a thermal peaking option (gas turbine), the LCGEP identified the 402 MW Arun-3 hydroelectric project (to be commissioned during 1995-2003) to be the most appropriate next investment in new generation capacity. Alternatively, the project commissioning could be accelerated to accommodate any commer- cially attractive bulk export sales agreement (para. xvii). This project is a run-of-river hydroelectric plant, located in eastern Nepal. For the project headworks (dam, penstock, power house, etc.) the preparation of final design and bid documents will require investigation in hydrology, geology and desanding facilities and an evaluation of alternative tunnel/powerhouse layouts. In addition, further studies are needed to define the size and commissioning date of each generating unit. In order to keep the project on schedule, it is essential that HM6/N expedite the hiring of consultants to undertake these headworks tasks. x. In conjunction with the LCGEP exercise, NEA also identified priority investments in transmission and distribution (T & D). However, although the analysis was generally satisfactory for determining a time-slice of NEA's T & D investment program, it was insufficient for detailed project justification work and minimizing system losses. Before particular future T & D projects tre committed, a master plan for nationwide transmission/distribution development should be prepared.  -xiii- xi. Although the LCGEP supports HMG/N's policy of minimizing thermal generation and therefore dependence on fossil fuels, there is a risk of load shedding, particularly 1993/94 and 1994/95, unless HMG/N and NEA develop a vigorous load management (LM) strategy and a series of supporting measures. The LM strategy would encompass tariff restructuring to include time-of-day metering, two-part tariffs for All consumers connected above the low voltage (LV) level (para. xiv) and possibly postponement of new connections. NEA should seek funding to implement a time-of-day metering system starting with all consumers connected at any level above LV. To support the LM strategy, NEA should also (a) implement its planned system loss reduction program, to reduce both technical and non-technical losses; (b) institute an operations and maintenance program with appropriate technical assistance aimed at optimizing system operation and reliability (para. xvi), and (c) develop an action plan for monitoring and utilizing autogeneration capacity when needed. Electricity Pricing xii. Electricity pricing should reflect the economic cost of supply to consumers while satisfying HMG/N's social objectives and taking into account NEA's financial viability and financing requirements. The last point is particularly important in view of the size of NEA's investment program. A review was made of NEA's present tariff schedule for thre' major consumer categories (industrial, commercial and residential) in terms of the long-run marginal cost (LRMC) of supply calculated on the basis of NEA's investment program (paras. vii and x). Principal determinants of LRMC of supply vary by voltage level, increasing as the voltage level drops and by the time of consumption. The review showed that the existing tariff rates for all con- sumer classes are substantially less than LRMC. As regards the tariff struc- ture, although in general rates for industrial consumers increase as the voltage level drops, the rates for commerical consumers do not reflect the higher costs of supply at the lower voltage level. Further, the rates for residential consumers, all of whom are supplied at the LV level, are only marginally above those for high voltage, for load factors up to 27%. Also, the tariffs do not signal the varying costs of supply in peak and off-peak periods or during wet and dry seasons. Thus the tariffs fail to signal the economic costs of supply. xiii. The impact of tariffs on NEA's financial viability and its ability to self-finance at least all local costs of its investment program was also examined. This is considered necessary because there is a financing gap of approximately US$119 million in foreign exchange funds for 1986/7-1995/6 and thus it is unlikely that foreign exchange funds will be available to cover any of the local costs of the investment program. Also, given HMG/N's own budget constraints, it is considered prudent that NEA not depend on HMG/N  -xiv- funding of local costs to support its investment program. The review showed that: (a) NEA's financial performance target of a 6% rate of return on historically valued assets (which is a covenant of an ongoing IDA-financed project) would not enable NEA to self-finance an adequate proportion of its funding requirements, and (b) a series of annual tariff adjustments of approximately 5.7% in real terms (11.7% in nominal terms) would allow NEA to meet all its projected operating and debt service requirements and self-finance nearly all local funding requirements of its investment program. xiv. Consequently, it is recommended that HMG/N and NEA increase the tariff levels periodically to cover the local funds component of NSA's investment program (and a modest amount of foreign costs) while ensuring that the tariff structure reflects the economic costs of supply. The tariff schedule would be revised following the completion of a full tariff study which should be conducted after the transmission/disttibution master plan is completed (para. x). These actions would result in an increase in the average revenue per kWh from 35X to 60% of LRMC. The study should pay special attention to ensuring that the resulting tariff serves as a tool for load management (paras. viii and xi). However, since the results of this study would not be available for 1-2 years, HMG/N should undertake a series of short-term adjustments to increase the average tariff rate annually by approximately 5.7% in real terms. This would require making the following adjustments to residential tariffs: (a) eliminating the fixed charge for the first block (0-25 kWh/month), and setting the unit price at NRs 0.80/kWh; (b) reducing the second block to 25-75 kWh/month and retaining the unit price at NRs 1.10/kWh, and (c) the third block would consist of all consumption above 75 kWh/month at a unit rate of NIs 1.35 kWh/month. Industrial tariffs should also be adjusted to allow use of a two-part time-of-day tariff, including seasonal rates. This would be achieved by introducing a metering system for all industrial consumers connected at any level above LV and rede3igning their tariffs to take into account the results of the report's analysis. Short-term technical assistance (approximately 1 man-month) could be provided by NUA's consultants to assist it in this activity. Planning xv. While load forecasting and generation planning are of a high standard at NEA, more attention needs to be paid to transmission/distribution and operational planning. Two areas merit special attention. First, the unclear division of responsibility between headquarters and regional units hampers the preparation and updating of distribution plans. This is aggravated by the lack of design criteria, standard costing data and an up-to-date registry of distribution system plant and configurations. Because NUA does not have  - xv - the capability to resolve these issues promptly, it is recommended that NUA engage technical assistance to help upgrade its capabilities in divtribution system planning by preparing the first annual rolling five-year distribution plan, using inputs from headquarters and regional umits, and training NEA staff responsible for distribution planning. This activity should be closely coordinated with the preparation of the transmission and distribution master plan (para. x). xvi. Operational planning has been carried out on a somewhat ad hoc basis, as evidenced by the lack of detailed procedures and guidelines for system operation. It is also hampered by the lack of a system control facility that could fully monitor and control NEA's interconnected network. Given the system expansion envisaged in the early 1990's that may include enhanced interconnection with the Indian system, and the need to minimize the pos- sibilities of load shedding, NEA should: (a) review its present system control facilities and determine its medium- and long-term requirements for such facilities; and (b) develop policies and guidelines for system opera- tions, including short-term (daily/weekly/seasonal) load forecasting, spin- ning reserve requirements, reservoir operation and planned maintenance out- ages. Technical assistance may be needed to enable NEA to complete this activity in a reasonable time frame. Bulk Exports to India xvii. Although bulk export of competitively priced hydropower to India represents Nepal's most attractive medium- and long-term foreign-exchange earning option, HMG/N does not yet have a detailed strategy to achieve this goal. The prospects for a hydropower-led export strategy are particularly good in view of the Government of India's (GOI) estimates of load growth (more than 5,000 MW per annum in the foreseeable future) and its stated desire "to import any available quantities of power imports (from Nepal) over the medium term." Power exports to India are currently limited to 25 MS (with a similar arrangement for power imports into Nepal) at a price of approximately US$0.01/kWh that has remained unchanged since 1971. The Arun-3 project could provide an opportunity for much larger bulk exports to India, and because of the complexity of the issues involved, Nepal should move from the informal, ad hoc approach used at present to develop a more coherent strategy to develop this export market. xviii. The framework of HMG/N's electricity export strategy would depend largely on engendering a climate of trust and cooperation between all the interested parties, including the central governments and the affected utilities. This would be achieved by joint preparation of the bulk export program.  -xvi-* xix. An action program could consist of the following elements: (1) NEA would establish a Task Force with a time-bound mandate to (a) review all the ramifications of bulk electricity export agreements, and (b) negotiate a bulk export agreement with Indian utility representatives. (2) NEA would imple- ment a number of studies to help define a negotiating position for Catinet concurrence. These include: (i) a review of existing international and/or inter-utility power contract agreements; (ii) estimation of a possible range of export prices; (iii) an interconnection study for power trade between Nepal and India; (iv) development of strategies for mobilizing financial resources, including possible commercial sources; and (v) evaluation of the macroeconomic and budgetary impacts of the NEA investment program (including the export-oriented Arun-3 project). (3) The bulk power export agreement would be negotiated by a joint technical committee (TC), consisting of utility representative of Nepal and India, under agreed guidelines. (4) Through the existing binational Committee on Water Resources Development, HMG/N and GOI could provide overall guidance to the TC. In view of the very tight schedule for the preparation of the Arun-3 Project, the Government of Nepal and India need to begin discussions on developing a bulk power agree- ment as soon as possible. Rural Electrification xx. Ninety-four percent of Nepal's population lives in rural areas and therefore rural development is a keystone of the Government's development strategy. Only two percent of the rural population has access to elec- tricity; however, HMG/N does not have a master plan for rural electrification (RE) that should form part of a wider strategy of meeting rural energy needs at least cost. This has been compounded by poor coordination among the parties involved in RE and various impediments to private sector participa- tion in RE schemes. Furthert there is an inaccurate perception that RE schemes, especially for isolated sites, cannot match supply and demand, and are inherently uneconomic because of their high costs and low returns. Analysi.s indicates that carefully designed schemes can be cost effective, financially viable and competitive with alternative fu-ls. xxi. To address these issues, HMG/N should undertake a seven-point RE action program. (1) A monitorable action plan should be prepared to address the impediments to private RE schemes. (2) A least cost rural energy supply/demand strategy should be developed that balances the objectives of minimizing dependence on imported fuels, promoting forest conservation and optimizing the use of hydro and other renewable resources. This should draw on the rural energy planning studies currently being implemented by the Water and Energy Commission Secretariat. It should also be supported by a fuel pricing policy geared to mobilizing resources to support the above strategy,  -xvii- while reflecting the cost to the economy of satisfying demand and meeting HMG/N's social objectives. (3) An RE Master Plan (REMP) (consistent with the least cost rural energy supply/demand strategy) should then be prepared to cover areas not yet electrified that lie within the periphery of existing and planned transmission lines and would be served by isolated systems. (4) Guidelines should be drawn up for tariff setting, which allow for meeting economic efficiency and social objectives while taking into account variability in local conditions, especially at isolated sites. (5) An institutional review of all the organizations currently involved in RE should be carried out to determine what roles they could play in implementing the REMP. (6) A load promotion program should be designed to develop commercial markets for the productive uses of electricity and thereby increase the system load factors and operating efficiency. (7) HMG/N should review the REMP and the associated institutional and tariff studies and specify its future RE policy in terms of yearly objectives, annual budgetary support, future institutional arrangements for implementing the REMP and tariff policy.  Table ItS HIGH PRIORITY ACTIONS FOR THE DEVELOPNENT OF THE POWER SUSSECTOR Stud4es/Techn4cat Assistance Issues Objective Recommendations NHeded (a) NIA has not resolved some To complete the integration NEA should review its present TA could be provided to fundamental problems of ED and NEC staff and organization and staffing levels conduct the revier and (related primarily to the establish a separate with particular reference to advise on its implement- amalgamation of NEC and corporate identity for NEA. consolidating all Rh activities ation. ED). which are undermining in a single directorate nd corporate performance eliminating surplus staff (para. 2.08). (parse. 2.08 and 2.12). (b) Tnadequate conditions of To provide Incentives for NEA should review the present yes service are contributing improved staff performance, conditions of s6rvice to identify to poor staff discipline areas where they could be improved and morale at NEA focusing on (a) the compensation (para. 2.10). packages and (b) establishing criteria for measuring and rewarding/improving individual management and staff performance. as appropriate. (c) NEA lacks well-defined. To enable NEA to formulate a NEA should prepare and update an TA could be provided to objectively determined dated monitorable plan to meet annual corporate development plan help NEA prepare the CDP. performance targets its corporate goals. (CDP) that defines short-. mediunm- (para. 2.17). and long-term objectiv6s. and includes a set of indicators for monitoring progress (para. 2.11). (d) NEA management, at alt ro facilitate the incorpora- KEA should enter Into a Ves levels, lacks an effective tion of modern utility manage- twinning arrangement with a understanding of modern ment into KEA's corporate suitable foreign utility utility management culture (pars. 2.14). techniques (paras 2.13). (e) The present residential To meet the equity require- HMG/N and NEA should eliminate No tariff structure is ments of NEA's tariffs while the flat charge for the first block inappropriately designed minimizing distortion of the n ncr--se the unit price towards to mee* social objectives tariff's signalling function, marginal cost; the range of the as well as load management second block should be reduced to requt.rements (para. 5.09). 25 kWhtmonth - 75 kwh/month (para. 5.09) (f) The levels of NEA's To ensure that the correct (1) As contemplated in its The TOR of this and its tariffs for the Nepal price signals are trans- FY87 work program. NEA findings could be discussed interconnected system mitted to consumers and that should finalize as soon as with ADS and IDA. are generally below the NEA meets fts financial possible a study to change its economic costs of supply targets. tariff levels and redesign the and hav- not beon designed tariff structure to satisfy to masximize resource economic criteria. meet HMG/N's mobilization for its social objectives and ensure investment program that NEA meats its financial (paras. 5.12 and 5.13). targets. The tariff study  Studies/Technical Assist Issues bcv Ra 10Andtions Ieeded stould pay attention to reflect- Ing the time of day/ossonal differences In marginal costs in supplyi1og consumers. (11) In the d tr a full T.A. Is needed. tariff study shouldunder- taken by NEA as soon *a the transission and distribution mster plan hat been completed (para. 5.12). (9) NEA has not yet developed To develop the NEA trans- NSA should implement a teast V s a least cost solution for mission system at least cost expansion plan study to the expansion of Its cost, identify s master plan for the transmission system development of the transmission/ (pars. 4.21). distribution system. (h) The least cost generation To modify the pattern of NEA should develop a strat%y to No expansion plan indicates consumption without reducing implemnt a vigorous load manage- that no now senerati the quality of service. ment program encompassing tariff will be nod td beorhe restructuring that includes time planned commissioning of of day/seasonal metering and post- the Arun-3 project (Phase poning now connections. This I). In 1995/96 provided should be accompanied by other that a load na nt meaturs including a system lose er*aramT 1s 11ex:tid reduction program. and the use of (para. 4.17). available Industrial autogenration capacity (para. 4.18). (1) Although the 402 MW Arun-3 To expedite the preparation NEA ahould develop a monito- Preparation of final design and project has been identi- and implementation of the rable action olan outlining the bid documents for the Arun-3 fied by the Least Cost Arun-3 project. steps that should be taken headworks to be preceded by Generation Expansion Plan by HUGN. tSEA their advisors. further inv-stigation In (LCGEP) as the next major potential donors. the project hydrology, generator unit size, hydroelectric project that consultants and the project geology and desanding facilities should be undertaken by contractors to prepare. imple- and an evaluation of an alternative HUG/N and the feasibility mont and commission the Arun-3 underground powerhouse layout. study has been completed. project (pars. 4.19). The definitive project trans- NEA does not have a detailed mission requirements should be plan for implementing the compatible with the proposed project (para. 4.16). transmission/distribution master plan.  Studies/Technical Assistance Issues Objective Recommendations Needed (j) The current high levels To expedite the reduction N4EA should give high priority to Ves, as indfcated in the previous system losses are in system losses. implementating its System Loss column. weakening the financial Reduction Program (SLRP) (including structore of NEA the prompt hiring of the SLRP (para. 3.16) Consultants). An Important feature of the program should be the devel- opment of a comprehensive data base on electricity consumption in order to monitor the levels of electri- city losses and thereby the effec- tiveness of the SLRP. This date base should includo the metering of presently unmetered supplies. (k) In general. rural electri- To develop and implement a HUG/N should develop a clear HUG/N should commission promptly ficetion (RE). particu- RE program targeted to meet policy on the scope and pace a study on the development of a larly for areas isolated rural energy requirements of development of RE resulting Rural Electrification Master Plan from the national grid has at least cost. from a review of the REMP study (REMP). The REMP should be con- not been planned system- (see next column) and ensure sistent with the least cost atically. nor Is there any that adequate financing is strategy for meeting rural energy substantive coordination or available for RE implementation needs. The study should also integration of activities (para. 4.32). examine the future role of NEA. amongst the various parties AD6/N and the private sector In RE. involved in RE (paras. 4.30-4.31). (1) Existence of impediments To further increase private HUG/N action/assistance needed No to further growth of sector participation in RE. to inter a*ia (t) facilitate private sector involve- particularly for the develop- prow sion ofTworking capital. ment in RE (para 2.21). ment of isolated sites, at competitive terms, to private equipment suppliers, to stock spare parts. especially for foreign equipments (ii) minimize Government administrative pro- cedures in obtaining spore parts; (iii) minimize approval process for installation of units up to 100 kWM (iv) facilitate research and development work in micro-hydro; (v) assist local manufacturers establish uniform standards to provide for interchangeable parts, and (vi) facilitate provision of T/A to undertake site investigation and design stvSi.s for micro- electrification schemes (para. 2.23).  Studies/Technical Assistance Issues Objective Recomiendations Needed (m) In spite of recognizing To develop medium-term A four-pronged action program Yes. TA will be needed to implement that the bulk export of strategy for exporting should be implemented: the following studies. competltively-priced electricity. () Establishment of a Task (a) review of existing hydropower represents Force within NEA with a time- international/inter- Nepal's most attractive bound mandateot t (a) conduct utility power contracts/ foreign exchange-earning a review of the contractual. agreements; option. HUG/N has yet financial, budgetary. technical, (b) estimation of ranges of to develop a detailed institutional, economic and economically and finan- medium-term strategy for political ramifications of bulk cially acceptable export electricity exports electricity export agreements; prices5 (para. 7.02). (b) negotiate the bulk export (c) interconnection for power sareonent with the GOI for the exports between NEA and Arun-3 project; (ii) implementation Indian utilities; of a series of study activities (d) strategies for mobilizing geared to developing a viable financial resources; and negotiating position (see next Ce) macroeconomic and bud- column); (111) Negotiation of a. getary impacts of the REA Bulk Power Export Agreement and investment program. (iv) consultation between HUG/N (para. 7.05). and GOI. using the existing binational Committee on Water Resources Development (para. 7.04).  NEPAL POWER SUBSECTOR REVIEW I. THE ENERGY SECTOR 1.01 The performance of the power subsector is affected by the development of various facets of the energy sector including institutions, resources, patterns of supply and consumption and pricing. This chapter introduces these issues and stresses the need to improve agency coordination to prevent duplication and avoid waste of resources and time delays. Emphasis is also put on the importance of developing an integrated supply/demand strategy for meeting Nepal's rural energy requirements that minimizes dependence on imported fuels, promotes forest conservation and optimizes hydro resource utilization. A. Institutions 1.02 Institutional responsibility for the energy sector is spread over many entities including overseeing ministries, line ministries, sector entities and subsector entities. The present organization of the energy sector is shown in the organization chart in Annex 2.1. The Ministry of Finance (MOF) is responsible for coordinating and securing external sources of finance for development assistance in the energy and other sectors; it also has an interest in the financial implications of energy investments and the financial operations of energy agencies. The National Planning Commis- sion (NPC), which is responsible for national economic planning, reviews the energy sector programs and projects, particularly in connection with the preparation of the national five-year development plans. The Public Service Commission (PSC) provides the guidelines governing conditions of service (recruitment, promotion, discipline, etc.) in government departments and public enterprises. 1.03 The line ministries with specific energy responsibilities are the Ministry of Water Resources (MWR) (electricity supply); the Ministry of Forestry (fuelwood); the Ministry of Agriculture (through its jurisdiction over the Agricultural Development Bank of Nepal (ADB/N), whose activities include the provision of finance for mini-hydro schemes and biogas plants in rural areas); the Ministry of Industry (which has jurisdiction over Nepal Coal Limited (NCL) and whose Department of Mines and Geology is responsible for oil and gas exploration); and the Ministry of Supply, which has jurisdic- tion over the Nepal Oil Corporation (NOC). Apart from the Nepal Electricity Authority (N&A), the other public enterprises in the energy sector are the Fuelwood Corporation (PCN) (fuelwcod supply); the NOC (import and distribu- tion of petroleum products); and the recently formed NCL (import and dis- tribution of coal). The Research Center for Applied Science and Technology (RECAST) at Tribhuvan University, under the aegis of the Ministry of Forestry, carries out research related to renewable energy sources (improved household stoves, micro-hydropower, solar and wind energy, biogas, wood gasification and briquetting).  -2- 1.04 Within the electricity subsector, MIWR has general responsibility for all public sector activities related to electricity supply, with jurisdiction over NEA. The Minister of MWR is also Chairman of NEA and Chairman of the Water and Energy Commission (WEC), which includes representatives of all the main ministries. WEC's responsibilities include investigation of national water and energy resources, studies of national water and energy require- ments, conservation, development and utilization of water and energy resources, and the preparation and coordination of short- and long-term plans for water and energy development. 1.05 Since 1978, WEC has been supported by technical assistance provided by the Canadian International Development Agency (CIDA) through the Water and Energy Resource Development Project (WERDP), staffed by Canadian Interna- tional Water and Energy Consultants (CIWEC). Since 1982, when the Water and Energy Commission Secretariat (WECS) was established as the technical arm of WEC, assistance under WERDP has been channeled through WECS, increasingly in the form of advice and training for WECS staff. The organization of WECS is shown in Annex 2.2. It liaises with NEA, which also benefits from the assis- tance of WERDP staff in load forecasting, system planning, tariff design, hydroelectric project preparation and engineering of distribution systems. 1.06 The major institutional problem is the lack of sustained work- ing-level coordination between the various ministries and line agencies involved in the energy sector. This is particularly noticeable in the power subsector which is undergoing a major system expansion in generation, trans- mission and distribution (Chapter IV) with attendant requirements for a wide range of supporting institutional and policy measures (Chapters II, V-VII). There is a need to improve agency coordination to prevent duplication and avoid waste of resources and time delays. Consequently, it would be useful for the Government to institute a Power Subsector Task Force, consisting primarily of staff of the MOF, NEA, WECS under the chairmanship of the MWR. 1T This Task Force would meet on a monthly basis. Its primary objectives would be to formulate a dynamic power subsector strategy consonant with national objectives, monitor strategy implementation and advise on corrective actions as appropriate. 1/ A good model for the functioning of such i Task Force is the Steering Committee (consisting of representatives of MOF, NEA, WECS and MWR) that has been established to coordinate HMG/N's inputs for the planned Techni- cal Meeting on the Development of the Nepal Power Subsector.  -3- B. Energy Resources 1.07 Nepal's main energy resources are fuelwood and hydropower. Agricul- tural residues are widely used for cooking and heating. Biogas potential is high because of the large livestock population. The solar energy potential also seems technically promising, and there may be some scope for utilizing wind energy, although data are lacking. There are no oil or coal commercial deposits. Fuelwood 1.08 Fuelwood accounts for 802 of total energy supplies. It is the basic source of energy for cooking and heating in rural areas, where the vast majority of the population lives. Forests cover some 382 of the total land area and are fairly evenly distributed. Fuelwood consumption, currently over three million tons of oil equivalent (toe) a year, exceeds the sustainable annual yield of the forests. If present trends continue, the forests will be largely exhausted by the year 2000. 1.09 Government fuelwood policy is to reverse deforestation by taking action on both supply and demand sides, including energy conservation. This is to be achieved through an afforestation program, improved watershed management, and utilization of alternative energy technologies (biogas (para. 1.12), mini/micro hydro schemes (para. 1.11), solar energy devices (para. 1.12) and more efficient woodstoves), coupled with strengthening beneficiary participation in these activities. The program is being assisted by various donors, including IDA and ADS. The Seventh Five Year Plan (1985/86-1989/90) includes an ambitious afforestation target of 175,000 ha. (35,000 ha./yr.), or nearly five times that achieved in the Sixth Plan. Concurrently, HMG/N is developing a Master Plan for Forestry Development, under the sponsorship of ADB and the P.nnish Government. Once the master plan is available, it should be reviewed jointly by HMG/N and other interested donors to evaluate whether: (a) the afforestation targets will achieve a sustainable balance in fuelwood supply and demand; (b) actions needed to ensure plan implementation can be carried out including land ownership and planned use of land and institu- tional cooperation and strengthening, and (c) technical assistance and other financing needs will be met. This should be linked with an overall strategy for balancing the supply and demand for rural energy, which accounts for approximately 90X of energy use in Nepal, including nearly all the firewood consumption (Table 1.2). To address this issue, WECS should undertake a study to develop/update a fuel pricing policy geared to mobilizing resources to support the above stratMgy, while reflecting the cost to the economy of satisfying demand and meeting HMG/N's social objectives. This work could draw on WECS's experience in rural (including household) energy and in developing least cost supply/demand strategies for meeting rural energy needs. It could also utilize, where pertinent, the proposals made by the  -4- Joint UNDP/World Bank Energy Sector Assessment mission 1/ in the areas of investment programming and institutional and policy reforms. This activity should also be coordinated with the proposed preparation of the Rural Elec- trification Master Plan (REMP) (para. 4.32). Hydropower 1.10 Nepal's theoretical hydropower potential 2/ is 83,000 MW, which is fairly widely distributed. The MWR (1985) has estimated the economically exploitable potential 3/ to be around 25,000 MW, of which about 20,000 MW have been investigated since 1966. Only 160 MW of the potential have been developed (158 MW in the interconnected network and 2 MW at isolated cen- ters), and a further 78 MW are under construction. Hydropower development is hindered by relatively low levels of domestic demand which do not justify projects that could take full advantage of economies of scale. An added problem is the relatively weak hydrological data base, which increases the level of uncertainty in project analysis. There are technical impediments: lack of access roads, difficult geological conditions, extreme variation in river flows 4/ and heavy silt loads 5/. Some potential projects are also very big (3,000 MS or above) and would depend on developing large export markets in India (para. 7.02). 1.11 The large number (about 30,000) of traditional water mills for grinding corn indicates that there is considerable scope for developing micro-hydropower schemes through individual or community effort. If all these mills were replaced by dual-purpose mills (grinding corn and generating electricity), they could be used to operate small power generators with an average capacity of about 10 kW, giving a total potential of 300 MW. Analysis indicates that dual-purpose micro hydro units could form part of the least cost solution for meeting rural energy needs and also provide high returns for relatively modest investments by private sector entrepreneurs (paras. 2.21 and 5.15). 1/ NEPAL: Issues and Options in the Energy Sector, Report No. 4474-zSEP, August 1983. A follow-up report was issued in January 1985 entitled NEPAL: Energy Assessment Etatus Report, Activity Completion Report No. 028/84. 2/ The theoretical hydro potential assumes full use for power of all runoff under average available head. 3/ The economically exploitable hydropower potential is limited to the ideal potential of sites that can be developed at costs competitive with other sources and that have no unacceptable social or environmental impacts. 4/ The Tamur River, for example, has an average flow of 324 m3/s, a sinimum flow of 41.4 m /s, and an estimated 10,000 year flood of 10,600 m /s. 5/ The Tamur River is estimated to carry down 29 million m3 of silt annually.  -5- Other Renewable Energy Soutces 1.12 Dung production by livestock (cattle, oxen and buffaloes) is estimated at 24.5 million tons per year, of which approximately 1Z is used directly as a fuel by rural households. If converted into methane in biogas digesters, it has been estimated that dung could provide for the cooking and lighting needs of an estimated 401 of the population. However, the projected number of units in 1990 is only 3,400, which would generate a methane yield equivalent to less than 0.01X of national fuelwood consumption. Agricultural waste (straw, husks, etc.) is widely used in rural and urban households and accounts for approximately 91 of total energy consumption. Solar energy applications, so far, have been limited primarily to demonstration7pilot projects (solar water heaters, solar driers, and photovoltaic and wind-power generating units), even though 781 of the land mass has an average daily incidence of 200 watts/mr. The economic viability of solar energy applica- tions still has to be justified. Petroleum 1.13 Although no oil or nak.ural gas reserves have been discovered, the prospects for oil discoveries are considered to be quite good. Following completion of the seismic program under an IDA-financed petroleum exploration project (Credit 1260-NEP), in May 1986 Shell Exploration BV in conjunction with Triton (a Houston company) signed an agreement on one of ten blocks offered by the Government. The Government plans to open the remaining nine blocks to competitive bidding after more seismic data have been obtained. C. Trends in Energy Consumption and Supply Energy Consumption 1.14 Data on energy consumption in Nepal suffer from gaps and inconsisten- cies, especially for traditional fuels. However they do point to some very definite trends. As shown in Table 1.1, total energy consumption rose from about 2.3 million toe in 1970/71 to about 2.9 million toe in 1980/81 and about 3.8 million toe in 1984/85. The 1970/71-1980/81 annual growth rate of 2.61 is very close to the GDP growth rate of 2.71 over the same period. The 1980/81-1984/85 annual growth rate for energy consumption was estimated to be 4.11. Total energy elasticity 1/ rose from 0.96 during 1970/71-1980/81 to 1.14 during the period 1980/81-4984/85, while that for commercial energy 1/ Total energy elasticity is defined as the ratio of X change in total' energy consumption to the X change in CDP, in constant terms. A similar definition hold for commercial energy elasticity and electricity elas- ticity.  -6- increased from 2.92 to 3.32. The relative share of commercial energy increased by 75Z to nearly 81 by 1984/85. This probably mirrors the accelerating economic growth in Nepal, which has been concentrated in the industrial and comme-rit! sectors. Over the whole 14-year period, consump- tion of traditional energy grew more slowly than commercial energy consump- tion, but it still accounts for 92' of total energy consumption. Hydroelec- tricity accounts for only about 21 of energy consumption, but this represents a significant increase from its 1970/71 level of 0.1Z. Table 1.1: FINAL ENERGY CONSUMPTION, 1971-1985 a 1971 1981 1985 Annual Growth Rate Z '000 toe '000 toe '000 toe 1971 1981 1971 X X X -1981 -1985 -1985 Traditional Fuelwood ) 2,665 (90.9) 3,068 (81.2) .. 3.6 .. Agricultural Residues) 2,165 (95.6) 47 (1.6) 330 (8.7) .. 62.7 Dung } 28 (0.9) 91 (2.6) .. 26.6 .. Total 2,165 (95.6) 2,740 (93.4) 3,489 (92.3) 2.4 6.2 b/ 3.7 Commercial Petroleum 62 (2.7) 110 (3.8) 146 (3.9) 5.9 7.3 6.3 Coal 37 (1.6) 36 (1.2) 61 (1.6) - 14.1 3.6 Hydroelectricity 3 (0.1) 47 (1.6) 84 (2.2) 31.7 15.6 26.9 Total 102 (4.4) 193 (6.6) 291 (7.7) 6.6 10.8 7.7 Grand Total 2,267 (100.0) 2,933 (100.0) 3,780 (100.0) 2.6 6.6 b/ 3.7 a/ Cited years are fiscal years. b/ The dramatic increase in the reported consumption of agricultural residues and dung over the period 1980/81 to 1984/85 are primarily due to the fact that the 1984/5 estimate included consumption of these fuels in the Hills, whereas the 1980/81 data did not. Assuming that the annual growth rate of consumption of these fuels was the same as that reported for fuelwood, reduced the overall annual growth rate of energy consumed to 4.1Z for the period 1981/2-1984/85. Source: WECS.  1.15 Although total energy consumption per capita was roughly constant during 1970/71-1980/81 (increasing from 196 to 198 kgoe), it increased rapidly from 1980/81 to 1984/85 when it reached 227 kgoe. Per capita consumption of commercial energy rose much more rapidly over the entire 14-year period, from 9 kgoe in 1971 to 17 kgoe in 1985, but Nepal still has the lowest commercial energy consumption per capita of any develtping country for which data are available. This trend of a gradual increase in per capita energy consumption is likely to continue in the future. However, while traditional fuels are expected to continue their predominance, commercial fuels are expected to increase their share of the market. 1.16 The pattern of consumption by consumer category is shown in Table 1.2 for 1981 and 1985 (1971 data are not available). In terms of total energy consumption, the industrial sector was the only sector that showed an increasing share of traditional fuel consumptiong increasing from 13X in 1981 to 33X in 1985. The principal changes in commercial energy consumption are the rise in the shares of the industrial sector (291 to 35) and the commer- cial sector (51 to 8.51) and the corresponding decline in the transport sector's share (from 34.51 to 251). The relatively sharp rise in the agricultaral sector's share of commercial energy (from 2.91 to 4.61) reflects increased use of diesel oil for irrigation pumping. Overall, the trend points to the household sector being predominant in future total energy consumption with the industrial sector playing an increasingly important role. Industry is likely to maintain its role as the most important consumer of commercial energy. Energy Supply 1.17 As shown in Table 1.3, energy imports (electricity from India (para. 3.21), petroleum products and coal) have been rising faster than internal energy production (of traditional fuels and electricity). The result has been that net energy imports increased from 4.61 of net energy supplies in 1970/71 to 6.11 in 1984/85. The rise in petroleum imports has been the main factor, but net electricity imports also increased greatly from 12,000 toe in 1980/81 to 21,000 toe in 1984/85. 1/ Overall, imports of petroleum products, coal and electricity were equivalent to about 16-21X of export earnings during 1980/81-1984/85. 1/ However, it seems that the trend for electricity imports is now in the opposite direc- tion; net electricity exchange with India dropped by approximately 54Z in 1985/86, compared with 1984/85 (Table 4.8).  -8- Table 1.2s ENERGY CONSUMPTION BY COUSUNER CATEGORY, 1981-1985 a/ ('000 toe and percentage distributions) Growth Rate 1981 1985 (1981-1985)s S Total Co_mercial Total Commercial Total Commercial Consumer Category Energy energy Energy Energy Energy Energy Residential 2,764.8 (94.2) 52.1 (27.0) 3,502.7 (92.7) 74.7 (25.7) 6.1 9.4 Industrial 63.9 (2.2) 55.9 (28.9) 149.9 (3.9) 100.9 (34.8) 23.8 15.9 Commercial 28.2 (1.0) 9.6 (5.0) 36.9 (1.0) 24.7 (8.5) 7.0 26.7 Transport 66.7 (2.3) 66.7 (34.5) 72.4 (1.9) 72.4 (25.0) 2.1 2.1 Agricultural 5.7 (0.2) 5.7 (2.9) 13.4 (0.4) 13.4 (4.6) 23.8 23.8 Other 3.3 (0.1) 3.3 (1.7) 4.0 (0.1) 4.0 (1.4) 4.9 4.9 2,932.6 (100.0) 193.3 (100.0) 3779.3 (100.0) 290.1 (100.0) a/ Cited years are fiscal years. Source: VECS. Table 1.3s ENERGY SUPPLIES, 1971-1985 a/ ('000 toe) 1971 1981 1985 Primary Production - Traditional Fuels 2,165 2,740 3,489 - Hydroelectricity 3 51 97 Total 2,168 2,791 3,586 Electricity Imports .. 13 24 Petroleum Imports 62 115 152 Coal Imports 37 36 61 Gross Energy Supply 2,267 2,955 3,823 Electricity Exports .. 1 3 Net Imports as Z Yet Supply 4.4 5.5 6.1 a/ Cited years are fiscal years. Source: WECS.  -9- 1.18 All imported energy supplies are purchased from India (coal and electricity) or have to be routed via India (petroleum products). Until 1973, all of Nepal's petroleum product imports were from India, but since then Nepal has bought on the international market, currently under two-year contracts with Kuwait and the Soviet Union at international prices. Petroleum imports are delivered to India, which supplies Nepal's required mix of products from the most convenient Indian refineries under a product exchange agreement because Nepal does not have a refinery. Nepal Oil Cor- poration (NOC) maintains stocks equivalent to 65 days' supply. 1.19 Until recently, coal was imported from India by licensed private sector importers. Most of it was brought in under a quota system at prices below world market levels, which could still be above the price charged customers in India. Supply patterns have been erratic partly because of the unavailability of rail wagons in India for private sector importers. This situation is likely to improve with the recent formation of NCL (para. 1.03), which is expected to negotiate supply contracts with the Indian authorities including timely provision of rail wagons for transporting the coal to Nepal's border. 1.20 Future patterns of energy imports are likely to be different even though the absolute and relative prices of petroleum products and coal (para. 1.22) are not expected to change appreciably in the medium term. First, with the continued expansion of the Nepal interconnected power system to isolated areas previously served from India, net power imports from India are likely to fall (para. 7.02). Second, if NCL succeeds in improving the coal supply, coal could capture a larger share of the commercial energy market. Finally, the trend points to continued increases in petroleum fuel imports but at a slower rate because coal may replace some petroleum fuels. D. Energy Pricing 1.21 Most energy in Nepal is not traded, and hence market clearing is not via the price mechanism. Pricing of commercial energy is generally administered by HMG/N; however, for a proportion of commercial fuelwood sales, which account for only a small proportion of fuelwood consumption, prices are -et in the market place. Pricing schedules of the principal commercial energy sources (petroleum products and electricity) are prepared by NOC and NEA, respectively; these must then be approved by the Cabinet. Coal prices are set by the Government of India. 1/ The pricing of commercial fuelwood sold by FCN is based on proposals prepared by FCN and approved by the Cabinet. 1/ The procedures used by HMG/N for pricing petroleum products will also apply to the coal subsector, once the recently formed public enterprise, Nepal Coal Limited, begins to play a more active part in the management of the subsector.  -10- 1.22 Prices of all forms of energy have risen substantially in real terms since 1973 (Annex 1.2), but much more so for imported energy (petroleum and coal) than for indigenous sources (fuelwood and electricity), reflecting different Government policy approaches. For petroleum products, the policy has been to adjust domestic prices to reflect the trend of international prices. In addition, taxes on petroleum products are a major source of Government revenue. Coal is priced at its border price of supply, but is exempt from any taxes or duties. 1/ Electricity prices have always been below the long-run marginal costs of supply; the present estimated average price of about NRs 1.16/kWh on total NEA sales is well below the estimated LRMC of NRs 3.27/kWh (para. 5.07). Since 1973, the fuelwood prices charged by the FCN have risen much more rapidly than electricity prices, but rather more slowly than kerosene prices. Despite these increases, FCN's prices remain well below the free market level set by private suppliers, which much more closely reflect the economic cost of supply. FCN's prices involve a significant subsidy to consumers in urban areas. 1/ To this should be added the cost of distribution and storage.  -11- II. ORGANIZATIONAL STRUCTURE 2.01 This chapter examines the institutional framework for electricity supply in Nepal, focusing primarily on the NEA. NEA is a young organization, having been formed only in 1985 through the amalgamation of existing organizations. The integration of these organizations is still incomplete, and NEA must confront several institutional issues--including insufficient autonomy, inadequate conditions of service for its staff and the development of effective planning processes--if it is to manage a large expansion program while providing reliable power supply effectively. After examining these issues, the chapter concludes with a review of the private sector's role in rural electrification. A. Power Subsector Organization Historical Development 2.02 In the early part of the century electricity was supplied from small privately-ow,ned generating plants, with expatriate management. The Govern- ment did not assume control of public electricity supply until the 1950's, when the Electricity Department (ED) was made responsible for electric power development throughout the country and for the regulation of privately-owned utilities. In 1962 the Nepal Electricity Corporation (NEC) was created in accord with a Government policy to transfer functions previously carried out by Government departments to public enterprises. In practice, ED retained control over the planning, preparation and implementation of generation and transmission projects, handing over completed projects to NEC for operation. In 1974 a separate Eastern Electricity Corporation (EEC) was created for the Eastern Region. Another new departure in the 1970s was the creation of separate development boards for major new power projects, such as Kulekhani I and Narsyangdi, and of the Small Hydro Development Board (SHDB) for hydropower projects up to 5 MW. 2.03 By the late 1970's the fragmentation of responsibility and lack of coordination in the power subsector were seriously affecting its efficiency. NEC had little contact with or influence over ED or the development boards in the planning and construction of new generation and transmission facilities. The diffusion of responsibility also led to inefficient staff deployment, confusion in decision-making and poor financial performance. Following studies financed by the Asian Development Bank (ADB), the Government agreed in November 1982 to establish a single public enterprise, the Nepal Elec- tricity Authority (NUA), with responsibility for the planning, construction and operation o' all public power facilities in Nepal. NEC took over EEC in the same year but NEA itself did not finally come into existence until August 1985. There is still private sector involvement in the power subsector in the areas of autogeneration (para. 3.02) and in the construction and commer- cial operation of micro-hydro plants of up to 100 kW capacity, which are not subject to government licensing (para. 2.21).  -12- B. The Nepal Electricity Authority (NEA) Background 2.04 NEA's establishment and consolidation has provided an appropriate institutional framework for the substantial development program and expansion of service envisaged for the power subsector. Over the next ten years, it expects to manage, in current terms, a US$1.06 billion development program (para. 6.08) which would be the largest ever undertaken in Nepal. Also, as part of the execution of the program, it may need to prepare and negotiate a bulk electricity supply contract with India (para. 7.07). However, NEA suffers from five major problems: (a) insufficient autonomy; (b) lack of coherent corporate goals; (c) lack of organizational cohesiveness; (d) inade- quate conditions of service for its employees; and (e) lack of a corporate development plan. Autonomy 2.05 Complete autonomy for NEA is neither practicable nor desirable. The Government must remain responsible for the critical policy decisions in the power subsector and for monitoring NEA's performance against financial and other targets. At the same time, NEA should be free of Government control and interference in the day-to-day management and operation of the elec- tricity supply system. The present NEA Act clearly spells out the Govern- ment's powers over the subsector, including requirements for NEA to submit regular reports and obtain Government approval for foreign loans, 1/ exports of power and changes in electricity prices. However, although the Act states that NUA is to be autonomous, it does not embody enough safeguards to protect NEA's independence. This is because it: (i) does not spell out clearly those areas where NEA can take decisions, without the need to consult with HMG/N, and (ii) requires that NEA's Board membership consist of Government employees or nominees, and the only NEA staff member is the Managing Direc- tor. To facilitate improving NEA's independence, it is recommended that HMG/N review the NEA Act with respect to defining those areas where NEA can take decisions without consulting the Government 2/ and changing Board com- position to increase the representation of NEA management and the private sector and reduce the number of Government representatives. 1/ The Act is ambiguous on the subject of local loans, one clause implying that these do not require Government approval, and another that they do. 2/ These areas could include hiring and firing of staff, procurement and operation of the thermal generation plants of the interconnected system.  -13- 2.06 In some respects, NEA professional staff enjoy less autonomy than they did prior to the creation of NEA. Thus, former ED staff at the equiv- alent of NUA salary level 7 or above (see Annex 2.6) could, as Government employees, deal directly with other Government departments or agencies, e.g., with the Customs Departmer.t to secure the clearance of urgently needed equip- ment. In NEA, these same staff must route such inquiries or requests via the NUA Managing Director to the MWR for transmission to the Government depart- ment concerned. In view of the likely adverse impact on corporate perfor- mance, including delays in project procurement and implementation, resulting from the present laborious communication process between HMG/N departments and NUA, HMG/N should authorize NUA staff at level 7 and above to deal directly with all Government departments and agencies in day-to-day business. Developing Coherent Corporate Goals 2.07 NUA's lack of coherent corporate goals also stems from incornisten- cies in the NEA Act. NUA is required to supply electricity to all, regard- less of ability to pay, while at the same time, to operate on commercial principles. Also, the Act does not specifically empowir the NRA Board, as the ADB studies had recommended, to publish details in its annual report of any costs incurred in complying with Government directives. 1/ To clarify NUA's corporate goals and thereby make it a more efficient power utility, HMG/N should review the NEA Act with respect to emphasizing unambiguously NEA's commercial character and the concomitant requirement that consumers should bear the costs of supply, except in cases of supplies for sccial purposes made at specific Government request, for which HMG/N would compen- sate NUA. Organizational Cohesiveness 2.08 NEA has not yet succeeded in molding the former NEC and ED organiza- tions into a well-coordinated entity. Their respective staffs, especially at the professional level, are largely segregated into.separate directorates (NEC staff in Operation & Maintenance (O&H) and Distribution/Consumer Serv- ices (DCS), and ED staff in Engineering and Construction) doing much the same work as in their previous organizations. This, coupled with the failure to resolve fundamental personnel problems (para. 2.11) and the absence of a corporate development plan (CDP) (para. 2.15), has impeded coordination within NEA and the development of a real corporate identity and strong staff commitment to NEA as an institution. To facilitate improved internal com- munications and the establishment of its own corporate identity, NEA should introduce a policy that professional staff career advancement would be 1/ Although NEA could presumably publish such information, under a clause of the Act empowering NEA to publish "other particulars as (it] deems necessary."  -14- generally dependent on gaining wide experience in the organization including, as a minimum, both upstream (planning, engineering, construction) and down- stream (O&M) activities. As a first step, NEA could arrange the interchange of some carefully selected middle-level staff between the Construction and Operations and Maintenance (O&W) Directorates and/or the Planning and Dis- tribution and Consumer Services (DCS) Directorates. 2.09 A particular example of the lack of organizational cohesiveness is in the preparation, implementation and management of rural electrification (RE) projects in NEA. This stems largely from poor coordination as a result of dividing responsibility for RE among four Directorates. RE involving supply from the interconnected network is carried out by the Regional Managers of DCS. RE projects for isolated centers too remote for grid supply (with a normal upper size limit of 5 Mi) are prepared under the Engineering Directorate (including site investigation and design), constructe$ by the Small Hydro Department (SHD) of the Construction Directorate, operated by the DCS Directorate and maintained by the 0 & M Directorate. Further, this division of responsibility makes it difficult for NEA to present a clear picture of the cost of its RE activities, especially if it wants to be reim- bursed for them by the Government. To improve the management of RE activities, including their cost control, NEA should place all RE, whether by grid or local supply, under a separate RE Directorate. Conditions of Service 2.10 Inadequate, ill-defined conditions of service during its first two years of existence contributed to poor staff discipline and morale at NEA and to the exodus of some of its best qualified staff. The most serious problem was that, with the exception of the Managing Director and non-official staff at levels 1-3, NEA staff had not been formally confirmed in posts they had been occupying for nearly two years. This situation arose from the problems of merging the professional staffs (salary levels 6-12) of the ED, a Govern- ment department, and NEC, a public corporation. The origin of the problem appears to have been that promotion for ED staff, as civil servants, was generally much slower than for NEC staff, so that they faced the prospect of being junior in salary and rank to former NEC employees with similar or fewer years of service. An aggravating factor was that many ED staff were already aggrieved at being transferred from Government service, with its higher prestige. Significant recent progress has been made in the regularization of staff contracts. Letters of appointment have been issued to all non-official levels up to level 6 and to higher level and management staff (levels 7 to 12). 2.11 However, the NEA compensation package, including salaries (Annex 2.6), allowances, pensions and other benefits, still contributes to unsatis- factory staff performance. Because their salaries are low, many NEA staff cannot manage without additional sources of income, sometimes from a second job. Undue staff time tends to be spent on activities unrelated to job  -15- assignments. Although the salary scales for professional staff are somewhat higher than those in Government service, they are well below those recom- mended in the ADB studies, which were designed to be competitive with the private sector. Government policy does not allow salaries in public enterprises to be too different from those in Government service, which are low. However, in setting allowances, which amount to lOX or more of staff salaries, and fringe benefits generally, NEA has more freedom from Government regulation, provided they are financed from its own resources and not out of the Government budget. A related issue concerns promotion, the criteria for which are governed by PSC procedures. These give heavy importance to seniority and relatively little importance to merit and performance on the job. However, beginning in 1988, PSC guidelines will give NEA more freedom to base promotions on job performance. To provide incentives for improved staff performance, NEA needs to review the present conditions of service to identify areas where they could be improved, focusing on: (a) the compensa- tion package, paying particular attention to the structuring of allowances and fringe benefits, and (b) establishing criteria for measuring and reward- inglimproving individual management and staff Job performance as appropriate. These criteria should also spell out the conditions under which unsatisfac- tory job performance would lead to the firing of a staff member from NEA. Manpower Planning 2.12 Although NEA is seriously overstaffed, it is deficient in key person- nel in virtually every key functional area. With total staff of around 7,000, NEA has easily the lowest annual sales and generation per employee of any Asian country for which data are available (43 and 61 staff per MWh respectively, compared to 93 and 153 for Bangladesh, the next lowest). Large numbers of NUA staff seem to be paid to do little or nothing, particularly at the non-technical levels. As a result, staff discipline and morale are poor. Despite the overall excess of manpower, there are serious staff shortages in certain departments, especially Finance, O&M, and Planning. 1/ The staffing issue will become even more crucial in the future because of the planned major increase in NEA's installed capacity (para. 4.17). At present, there is no effective manpower planning in NEA, since the detailed short-term manpower planning system proposed by their consultants, Coopers & Lybrand Associates Ltd., has not yet been implemented. 2/ To help ensure its cor- porate staffing needs are identified and provide for the continued profes- sional growth of its staff, the Director of Administration should implement 1/ For example, in the Finance Department, which also has the corporate accounting responsibility, there is not one accredited chartered account- ant. 2/ This system for short-term manpower planning, covering the needs of the coming year, is set out in NEA's Personnel and Administration Manual.  -16- the existing short-term maneower planning system that specifies a strategy for (1) hiring and/or retraining staff to fill identified gaps and (ii) deploying surplus staff, possibly by loaning some on a "pay back" basis to other Government entities. NeA should also expedite the preparation and implementation of a medium-term (10-year) manpower planning and training program with the assistance of consultants hired under the IDA-funded Mar- syangdi Hydroelectric Project. This activity should be targeted to help NEA implement its Corporate Development Plan (CDP) (paras. 2.14-2.16) including its 10-year investment program (Table 6.3). Training 2.13 The only training program under implementation is for financial and accounting staff, with the assistance of Coopers & Lybrand Associates Ltd. Since NEA has no train.ng facilities of its own, internal training is * "on-the-job." Training outside NEA is essentially ad hoc, dependent on offers of training in connection with specific projects or technical assis- tance packages, and is largely confined to engineers. However, NEA agrees that its most urgent needs relate to training for management staff, O&M personnel (particularly in generation and transmission), and technicians and skilled workers throughout the organization. The specific deficiencies that need to be addressed include: (a) unfamiliarity amongst NEA managers with the application of modern management techniques to a power utility. Middle managers (just below the Director level) do not seem to seek responsibility, nor senior managers to delegate it; (b) the lack of a well-planned set of instructions, programs, schedules, or manuals to guide O&M staff. This is especially evident in areas such as (i) the development of recording, monitoring, and evaluation systems geared to effective maintenance, and (ii) operational plan- ning procedures (para. 4.28); and F (c) unsatisfactcry standards of workmanship among technical workers (this should be rectified by the NEA training center to be financed by IDA under the Marsyangdi project).  -17- 2.14 One particularly promising method of strengthening NSA's management and training its staff would be for NEA to enter a "twinning" arrangement with a suitable utility, preferably in a developing country. This arrange- ment, which encompasses a direct long-term technical assistance linkage between the two institutions, would permit a flexible, responsive approach to addressing NEA's operating and planning needs. It would not necessarily be confined to management, although management training should be a first priority. The twinning arrangement could include the full-time secondment to NEA of some senior staff from the twinning utility for extended periods. Corporate Planning in NEA 2.15 The requirement for a corporate plan in NEA arises from the need for good management. The NEA Act stipulates that NEA should submit, along with its audited accounts, an annual report to the Government providing: (a) details of NEA's plans for future electricity suppiy; (b) a detailed progress report on NEA projects; (c) projected financial statements for the next five years; (d) details of actions taken to implement Government directives; and (e) any other information NEA deems necessary. This is apparently the first time such requirements have been embodied in a public enterprise statute in Nepal. However, the Act omits some additional requirements suggested in the ADB studies, such as annual performance statistics, a report on manpower and training initiatives, a least-cost development program for 15-20 years and the corresponding tariff proposals based on this program. 2.16 Responsibility for preparing a corporate plan and monitoring its progress rests with the Director of Corporate Planning in the Planning Direc- torate. NEA has not been able to submit to the Government the required annual report on its activities and plans, pending completion of NEA's long-term expansion plan and also because of the lack of qualified staff in the Corporate Planning Department. It has, however, submitted to the Cor- poration Coordination Division (CCD) of the Ministry of Pinance the annual performance targets required for all public enterprises. CCD monitors progress against the targets and rates each enterprise at the end of the fiscal year on its overall performance. The NEA targets have to be agreed with the NPC and MWR. They relate to both physical performance indicators (electricity generation, sales, losses* capacity utilization, number of personnel, number of customers) and financial indicators (income, expendi- ture, profits, fixed assets, current assets and liabilities, investment and net worth). Performance under loan covenants is also taken into account. NEA's 1986 and 1987 targets and its actual performance in 1986 are shown in Annex 2.4. According to the CCD, NEA's performance put it into the top four or five out of the 45 public corporations evaluated in 1986. However, there does not seem to be any mechanism for an independent evaluation of NuA's targets, which are largely self-determined.  -18- 2.17 Institutionalization of an annual corporate planning cycle within NRA, as called for by the N8A Act, and the establishment of a monitoring function by CCD would help NEA set flexible and realistic targets for its corporate development and monitor progress in achieving them. However, in order to make the process as effective as possible, NEA needs to develop a dated program and staffing requirements for implementingan annual planning cycle leading to the preparation of a Corporate Development Plan (CDP) defin- ing short-, medium-, and long-term objectives and indicators for monitoring progress. 1/ The planning process should include a least cost expansion program (generation, transmission, and distribution), a set of long-run marginal cost (LRMC) tariff proposals based on the program, a series of projected financial statements based on the present and proposed tariffs, and corporate-wide manpower and associated training plans. To allow adequate time for review, the draft plan should be submitted to the Government four months before the beginning of each fiscal year. 2/ NEt could benefit from technical assistance to assist in the preparation of the first CDP and train NEA staff who would be responsible for preparing the CDP subsequently (para. 2.15). Operating Systems and Procedures 2.18 NEA's consultants, Coopers & Lybrand, have designed detailed finan- cial, administrative and personnel systems and a comprehensive financial management information system (FMIS), based on modern power utility practice. NEA's implementation of these sy3tems is seriously behind schedule because of the lack of appropriate personnel and computer hardware. NEA has not fully implemented the proposals submitted by the consultants in November 1986 for a technical management information system (TMIS). Given its internal manage- ment and staff constraints and the importance of a regular and systematic flow of iiiformation to the management of a modern utility, NEA should seek technical assistance to assist in the implementation of the TMIS, the FMIS, and other financial, administratative, and personnel systems as soon as possible. 1/ In setting its performance targets, NEA could review the existing levels of performance of other Asian utilities, at a comparable state of develop- ment. 2/ Thereby, the CDP could serve as a framework for regular discussions between the various subsector agencies--MOWR, NEA, WECS, MOF and NPC--and facilitate improvements in subsectoral management particularly in the planning and policy areas.  -19- Preparation of Job Descriptions 2.19 Job descriptions exist for the Directors-in-Chief and their depart- mental directors and are preparation for the managerial staff in the Finance and Administration Directorate. These are useful in helping both staff to perform their jobs satisfactorily and top management to set and monitor performance targets for each directorate. In order to strengthen further its corporate performance, NEA should now begin to focus on defining the respon- sibilities of all its other staff (levels 1 to 10 inclusive). As a first step, NEA should have its consultants prepare job descriptions for all of its managerial staff, i.e. at the next level below director. This activity would begin once the initial manpower planning exercise had been completed. C. Role of the Private Sector in Rural Electrification 2.20 A number of non-governmental organizations (NGOs) are engaged in RE, as are various private firms. The most important of the NCOs is the United Mission to Nepal (UMN), together with its associated companies. Their cur- rent activities include the construction of small hydropower stations (up to 5 MW), manufacture and installation of micro-hydro turbines (up to 100 kW) and consultancy services. 2.21 The most promising area for private sector participation is the installation of isolated micro-hydro turbines (up to 100 kW) combined with small generators. These could supply mechanical energy for grinding grain and pumping water during the day and electricity to neighboring households at night. The existence of some 30,000 traditional water mills attests to the wide scope for generating electricity from small rivers and streams. The public Agricultural Development Bank of Nepal (ADB/N) has financed some 450 privately-owned water turbines (5-20 kW), mostly of the cross-flow type. ADB/N provides up to 901 of the capital cost, with repayment over 7 years at 151 interest. For those schemes where the turbine owner also wishes to supply electricity, the Government has proposed a program to subsidize 50% of the cost of the generator plus distribution lines, with the balance to be financed by ADB/N on the same terms as for the turbines. ADB/N has financed 26 sach isolated electrification schemes (Annex 4.11) without subsidies and has set a target of 650 by 2000. The schemes have an average installed capacity of about 6 kW and average cost of NRs 10.675 (US$ 544) per kW, 1/ which is low compared to similar schemes (para. 4.31). ADB/N is also provid- ing finance for the local manufacture of generators, and for training trips abroad. 1/ These costs include the associated low voltage lines but are exclusive of the costs of turbines and associated civil works; if the costs of the excluded items are included, the average cost per kW is $1,000.  -20- 2.22 Despite their promise, including high returns (para. 5.14), private RE schemes face a number of problems. Private equipment suppliers lack working capital to stock spare parts and also experience difficulties and delays in obtaining foreign spare parts. They are also expected to carry the burden of research and development, which tends to be neglected in conse- quence. Local equipment suppliers have not established uniform standards. The manufacturers of micro-hydro equipment also lack the resources for effec- tive sales promotion networks and for local repair and maintenance services. Finally the equipment supplier is expected to undertake the site investiga- tion and design studies for proposed schemes at his own risk. 2.23 Government help is needed to overcome most of these problems. However, NEA involvemenit would be undesirable--as in the proposal to set up a special NEA section to assist with site investigation and design work, for which NEA is unlikely to be compensated. It would be more appropriate for ADB/N, the agency mainly involved in financing these private schemes, to undertake this responsibility. It is recommended that ADB/N prepare a monitorable action plan to address the problems discussed above, specifying a monitorable action plan identifying the inputs required of Government, local research and development organizations, ADB/N itself, and the private sector. 2.24 Finally, the rationale for subsidizing private schemes needs to be reviewed since they have potential financial returns (para. 5.14). Undoub- tedly, these schemes support the government's policy of reversing deforesta- tion (para. 1.08). However, there is scope for better targeting of subsidies because private RE schemes have not been subject to a rigorous economic/ financial review at the time of appraisal. Consequently, economic and finan- cial appraisals should be required for all private schemes to be financed by ADB/N; for schemes with high estimated financial returns, government funds should be made available under comparable terms to those offered by ADB/N. Subsidies should only be considered for schemes that show satisfactory economic rates of return but low or marginal financial rates of return.  -21- III. HISTORICAL TRENDS IN THE SALE AND SUPPLY OF ELECTRICITY 3.01 This chapter analyzes recent trends in the sale and supply of elec- tricity for the Nepal interconnected system and for isolated systems. A major issue is the need to strengthen the sales data base by undertaking regua4r and systematic consumers surveys to ascertain the patterns of elec- tricity consumption by household, industrial and commercial consumers. On the supply side, the major issue is to implement the system loss reduction plan, which NEA has prepared (with the assistance of consultants) to reduce the unacceptable high current levels of system losses. Power exchange with India is also covered especially the need to develop bulk sales contracts encompassing technical, financial, economic and institutional aspects. A. Past Trends in Electricity Sales Electricity Sales Data 3.02 The available data on electricity sales by public utilities in Nepal suffer from gaps and inconsistencies. 1/ In particular, no reliable data are available for 1983/84 and 1984/85 because of the then impending reorganiza- tion of the power subsector. Available data are insufficiently disag- gregated; for example, there are no separate figures for high-, medium- and low-voltage industrial consumers. There are no recent data available on electricity generation/consumption by the private sector, by autoproducers from their own generating plant or by privately-owned micro hydroelectric plants having less than 100 kW capacity (para. 2.21). Growth of Sales 3.03 As shown in Table 3.1, electricity sales in the public sector increased at an average annual rate of 11.62 from about 107 GWh in 1975/76 to about 288 GWh in 1984/85. The growth rate in the second half of the.period (1980/81-1984/85) averaged 15.2Z, compared with 8.8X in 1975/76-1980/81. The relatively slow growth in sales in the former period was caused by supply constraints principally resulting from delays in the commissioning of the Kulekhani hydropower project, technical problems with other hydro stations and restrictions on new connections because of the supply constraint (para. 3.06). Since 1975/76, electricity prices have been increased several times, most noticeably in 1983 and 1985 (para. 5.05). These increases have not had any appreciable effect on the growth of demand for electricity. Electricity sales in 1975/76-1984/83 increased at a slightly slower rate than electricity supply partly because system losses increased from about 29Z to 30% (para. 3.16). 1/ This discussion is confined to electricity sales rather than consumption because of the high system non-technical losses (para. 3.16). Sales may be considered as a lower bound on consumption.  -22- Table 3.1: ELECTRICITY SALES AND SUPPLY, 1976-1986 Sales Supply System Losses kWh Per Capita Maximum Demand Fiscal I Z a/lbi- - Year GWh Increase GWh Increase GWh X Net Gross MW Increase 1976 107.3 - 150.2 - 42.9 28.6 8 12 40.2 - 1977 119.6 11.5 165.4 10.1 45.8 27.7 - - 45.6 13.4 1978 131.7 10.1 186.4 12.7 54.7 29.3 - - 50.6 11.0 1979 148.9 13.1 211.9 13.7 63.0 29.7 - - 52.4 3.6 1980 162.0 8.8 228.6 7.9 66.6 29.1 - - 36.9 8.6 1981 163.2 0.7 231.4 1.2 68.2 29.5 11 15 58,.9 3.5 1982 183.9 12.1 267.8 15.7 83.9 31.3 - - 75j.1 27.5 1983 230.6 25.4 345.0 28.8 114.4 33.2 - - 83.7 11.5 1984 246.5 6.9 372.1 7.9 125.6 33.8 - - 96.8 15.7 1985 287.8 16.8 413.0 11.0 125.2 30.3 17 25 104.5 8.0 1986 336.3 c/ 16.9 491.2 18.9 154.9 31.5 - - N/A - ai Sales per capita. b/ Supply per capita. C5 Data for 1986 are estimates; N/A not available. Source: NEA and mission estimates. 3.04 The GDP elasticity of demand for electricity (GDPEDE) 1/ remained stable at 3.1 in the periods 1975/76-1980/81 and 1980/81-1984/85. This relatively high value reflects the pattern of economic development in Nepal, where growth has been concentrated in the industrial and service sectors compared to agricalture (Table 4.1). Although the GDPEDE seems large, it is consistent with a country at Nepal's present low level of economic develop- ment. It reflects the increase in electricity intensity (kWh per US$1,000 GDP) from 104 kWh in 1975/76 to 175 kWh in 1984/85 at an average annual rate of about 6%. Per capita electricity consumption (measured as total supply divided by population) rose from 12 kWh in 1975/76 to 25 kWh in 1984/85, which is the lowest of any Asian country for which data are available (com- parable 1983 figures for Burma and Bangladesh, the next lowest, were 34 and 37 kWh, respectively). Access to public electricity supply increased from 3% to 6% of the population. 1/ The GDP elasticity of demand for electricity is defined as the ratio of % change in electricity consumption and the Z change in GDP, in real terms.  -23- Electricity Sales by Sector 3.05 Table 3.2 summarizes sales trends by sector in 1975/76-1984/85 (details in Annex 3.1). For consistency, the figures are all based on the tariff classification existing before April 1983, in which the "residential" category included schools, hospitals, offices, etc. (now included in the "commercial" category), and the ~'commercial" category included irrigation and water supply and transportation (now reported separately). The fastest growing category was "industrial" (13.5Z p.a.), followed by "others" (12%), "residential" (10.7%) and "commercial" (9.8%). The result was an increase in the share of "industrial" (from 30% to 35%) and a decline in the "residen- tial" share (54% to 50%). The increasing share of the "industrial" consump- tion improved the interconnected system's load factor from 45% to 50%. 3.06 The numbers of "industrial" and "commercial" consumers also grew more rapidly than the "residential" category, but "residential" consumers still account for 97% of NEA's customers. Over the whole period, the total number of consumers rose from about 79,000 to 168,000, representing an average of about 10,000 new connections a year (9% p.a.), but there was a marked acceleration in the rate to over 13,000 annually during 1980/81-1984/85, compared to 7,000 p.a. during 1975/76-1980/81. This rela- tively rapid rate of new connections probably was the driving force behind the observed increase in electricity consumption in the Nepal power system. However, the NEA data base does not contain enough detail, particularly for the non-household sectors, to make this conclusion definitive. Consequently, NEA should undertake regular, systematic consumer surveys to ascertain the electricity consumption patterns of household, industrial and commercial consumers. The surveys should include the collection of data on such con- sumer characteristics as the shapes of their daily load curves and daily, weekly and annual load factors. This information would also be useful for load forecasting and for load management. 3.07 Average consumption per consumer rose from 1,35e kWh in 1975/76 to 1,716 kWh in 1984/85, representing an average annual growth rate of 2.6%. Average residential consumption rose from 805 kWh to 956 kWh (80 kWh/month). Electricity is used almost exclusively for lighting by a large proportion of residential consumers (50% according to a sample survey by NEC in 1981) who do not consume more than the monthly minimum of 25 kWh. Average industrial consumption showed relatively little change over the period. It reached 22 GWh/consumer in 1984/85. "Commercial" consumers have the highest average consumption, but this fluctuated wildly, with a jump from 89 GWh in 1975/76 to 276 GWh in 1980/81, followed by a decline to 66 GWh in 1984/85.  -24- Table 3.2: ELECTRICITY SALES BY SECTOR , 1976-1985 a/ 1976 1981 1985 Growth Rate, X p.a. 1976 1981 1976 MWh Z MWh Z MWh Z -81 -85 -85 Residential 61,787 (58) 78,570 (48) 154,928 (54) 4.9 18.5 10.7 Industrial 32,128 (30) 50,202 (31) 100,137 (35) 9.3 18.8 13.5 Commercial 9,173 (8) 23,203 (14) 21,204 (7) 20.4 - 2.3 9.8 Others 4,173 (4) 11,239 (7) 11,559 (4) 21.9 0.7 12.0 Total 107,261(100) 163,214(100) 287,828(100) 8.8 15.2 11.6 a/ Fiscal years. Source: NSA and mission estimates. Load Characteristics 3.08 Daily maximum demand occurs in the evening between about 6:00 and 7:00 p.m. (see typical daily load curves in Annex 3.2). There is also a morning peak between 7:00 a.m. and 9:00 a.m. The minimum load during night hours is typically 35-401 of the maximum load. The pronounced evening peak reflects the heavy domestic load, which is mainly for lighting, and accounts for the present (1986/87) system load factor of around 501. The annual peak load occurs in the dry winter months of December/January, when the combina- tion of electric lighting, cooking and heating results in evening peak loads about 20X higher than during the wet summer months. Because of this charac- teristic, during the wet season the run-of-river hydropower plants operate at full capacity, while the output of Kulekhani I is reduced so that its reser- voir can be filled for the peak demands of the dry season. The daily and seasonal load characteristics of the Nepal interconnected system indicate there is scope for exploring the possible export of secondary energy to India equivalent to 40-100 MW, depending on the times of day and year. Given the high priority that HMG/N has placed on developing a large-scale export market for electricity in the medium term (1987-2005) (para. 7.02), the proposed interconnection study to be undertaken to prepare the export-oriented Arun-3 project (para. 7.05) should include a review of the factors impeding the development of an export market for secondary energy and recommend an action plan to address these factors.  -25- B. Past Trends in Electricity Supply NEA Interconnected System 3.09 NEA is Nepal's principal power supplier; electricity is also supplied by some industrial sector captive generation plants and a number of privately-owned micro-hydroelectric plants, each of less than 100 kW capacity. NEA is also involved in power exchanges with India at 15 different border points. Power supply statistics are confined to the NEA system. 3.10 Generation Capacity. Table 3.3 summarizes the growth of installed capacity in the interconnected system during 1975/76-1985/86. In early 1987, total installed capacity was 183 MW, of which 158 MW (861) were hydro plant and 25 MW (141) were diesel plant. Since 58% (107 MW) of the total hydro capacity was installed during 1982-1987, there has been a significant change in the plant mix, with the hydro proportion increasing from 72% in 1981 to 87% in 1987. The two main hydro projects commissioned were Kulekhani I (60 MW) in 1982 and Kulekhani II (32 MW) in 1987. Details of the installed plant are given in Annex 3.3. All hydro plants are run-of-riser type except for Kulekhni I, which has a live storage of 73.3 million m , a catchment area of 126 km and a rated head of 550 meters. 3.11 Annex 3.3 shows that the effective hydro capacity of 108 MW in 1985/86 was just sufficient to meet the peak demand. 1/ On the intercon- nected system, EMG/N prefers that NEA shed load rather than operate the diesel units to minimize expenditures on imported fuel. For example, in 1980/81 when there was major load shedding (para. 3.03), diesel units were used very infrequently; their capacity factor (i.e., the percentage of the time they were operating) was approximately 8.5X, and they accounted for approximately 8% of total generation. This policy implies that NEA, in the preparation of its least cost generation expansion plan (LCGEP) (para. 4.17), should link the explicit value of unserved energy with the cost of fuel for electricity generation (NRs 2.11/kWh). 1/ NEA's definition of effective hydro capacity takes into account design and operating restrictions of the different hydroelectric plants. Details are provided in Annex 3.3.  -26- Table 3.3: GROWTH OF CAPACITY OF THE NEPAL INTERCONNECTED SYSTEM, 1976-1986 a/ Annual Growth 1976 1981 1983 1986 Rate 1976-86 (X) Maximum Demand (MW) 31.9 44.5 66 107 12.9 Load Factor X 44.7 46.5 48.9 50.4 Installed Capacity (MW) 42 76 136 151 13.7 of which Hydro MW (X) 35(82) 51 (67) 111 (82) 126 (83) 13.7 Effective Capacity (KW) 50 110 125 of which Hydro MW (X) 33 (66) 93 (85) 108 (86) Plant Margin (Installed) MW (Z) 32 (42) 70 (51) 44 (29) Plant Margin (Effective) MW (X) 55 (11) 54 (49) 18 (14) ai Fiscal years. Source: NEA. 3.12 Transmission. The transmission system in Nepal (Map IBRD 19917) has developed through the gradual interconnection of isolated networks built to serve regional centers. In the Central Region, a 66-kV network was developed to bring power into the Kathmandu Valley from outlying hydrostations: Kulek- hani I (60 MW), Sunkosi (10 MW), Devighat (14 M) and Trishuli (21 MW). A 66-kV double circuit also extends to the south of Kulekhani I to supply Hetauda and Birganj. To allow electricity to be transmitted to the East and West Regions a 132-kV system is being superimposed on the 66-kV system, with 132-kV lines running west from Hetauda via Bharatpur to the Gandak power station, Pokhara and Butwal. To the east of Hetauda, a 283 km 132-kV single circuit transmission line has been constructed down to Biratnagar via Dhalkabar (Janakpur) and Dubi. 3.13 In January 1987, the transmission system comprised the facilities given in Annexes 3.4 and 3.5 and summarized below in Table 3.4. A single line diagram is shown in Annex 3.6. 3.14 Distribution. NBA does not have a central data base on its dis- tribution facilities and their development. However, the extent of the distribution facilities on NEA's interconected system was estimated based on information given in 1984 by NEC and the distribution expansion in the Eastern Region (See Table 3.5). Since there is no reliable information on NEA's distribution system and since this could have adverse impacts on the ongoing loss elimination program (para. 3.18), NEA should develop a central database on distribution system plant and train NBA staff on its maintenance. This activity could be added to the proposed technical assistance for preparation of an annual, rolling five-year distribution plan (para. 4.27).  -27- Table 3.4: NEA TRANSMISSION FACILITIES (January 1987) a/ TRANSMISSION LINES SUBSTATIONS Voltage Type km Type Voltage Number MVA 132 kV SC on DC towers 370 Generator 11/132 2 106.0 6.6/132 1 20.0 SC on SC towers 249 6.6/66 3 37.6 619 163.6 66 kV DC 158 Grid 132/66 2 70.0 SC on DC towers 4 132/33 3 25.0 132/11 3 46.0 SC on SC towers 57 66/11 10 115.6 219 256.6 a/ SC - Single Circuit; DC - Double Circuit. Source: NEA. Table 3.5: NEA DISTRIBUTION FACILITIES (33 kV and below) (January 1987) 11 kV 3.3 and LT Distribution Region 33 kV (km) 2.3 kV Lines Substations (km) DC SC a/ (km) (km) (MVA) Central 35 47.5 400 28 1500 98.3 Western 195 - 200 4 500 10.3 Eastern 188 - 166 - 286 62.0 Mid-Western 60 - 31 - 90 4.3 Far-Western 25 - 21 - 60 3.1 a/ SC - Single Circuit; DC - Double Circuit. Source: Nepal Electricity Corporation (NEC) and mission estimates.  -28- NEA Isolated Systems 3.15 NEA operates eleven isolated small hydro projects with total installed capacity of 1.92 MW and eight isolated diesel stations with nameplate capacity of 3.1 MW. Details of the plant are given in Annex 3.7, and supply statistics are given in Table 3.6. The data include imports from India to meet the electricity demands at eight border points in the Mid and Far West regions that are not connected to the national grid. From 1975/76 until 1985/86 the net supply grew at an average annual rate of 17.9%. However, losses grew at nearly twice that rate and reached the very high level of 34.1% in 1985/86 (para. 3.19). Table 3.6: GENERATION AND SALES STATISTICS FOR NEA OPERATED ISOLATED SYSTEMS, 1976-1986 a/ (CWh) Growth 1976 1981 1982 1983 1984 1985 1986 Rate % Hydro generation 0.000 0.336 0.416 0.512 0.764 0.832 0.954 22.23 Thermal generation 0.015 0.205 0.080 0.207 0.248 0.384 0.384 11.81 Total generation 0.015 0.541 0.496 0.719 1.012 1.216 1.338 23.61 Imports from India 3.153 7.697 9.529 11.956 12.701 15.511 15.870 17.28 Exports to India Net exchange 3.153 7.697 9.529 11.956 12.701 15.511 15.870 17.28 Net Supply 3.168 8.238 10.025 12.675 13.713 16.727 17.208 17.93 Lossoa 0.514 1.612 1.673 2.782 2.924 4.920 5.868 34.06 Sales 2.654 6.626 8.352 9.893 10.789 11.807 11.340 13.79 a/ Fiscal years. Source: NEA. System Losses 1/ 3.16 Table 3.1 shows that system losses in Nepal were unacceptablv high during 1975/76-1985/86. There seems to be substantial regional variation in losses. The highest levels of losses were recorded in the Bagmati Zone (Kathmandu Valley), which accounts for 56% of all electricity billings in Nepal and where losses were estimated to have reached 36% in 1984/85. Nationwide, technical and non-technical losses are about equal. The prin- cipal cause of the technical losses is the under-investment in medium- and 1/ Loss (Z) = (1 - Sales in Nepal and Exports to India ) X 100 Internal Generation in Nepal and Imports from India  -29- low-voltage distribution lines, resulting in overloading and poor voltage conditions; the non-technical losses are due to pilferage, meter reading errors and billing errors. HMG/N first addressed the problem of excessive system losses in the mid-1970s. Under the Second ADB Power Loan to Nepal in 1976, British Electricity International Ltd. (BEI) recommended a comprehen- sive set of administrative and engineering measures to reduce gross system losses. In 1978 NEC set up a Loss Elimination Division. HMG/N later agreed, under the IDA-financed Marsyangdi Hydroelectric Project, to implement a program to reduce losses from approximately 34% in 1983/84 to 18% in 1990/91 (Table 3.7). Although some minor steps have been taken, the loss reduction program has not met its targets for 1985/86, partly because of staffing instability due to the pending reorganization of the power subsector and financial constraints. Despite these problems, NEA could undertake a number of low cost measures in the near future to improve the effectiveness of its loss reduction program (para. 3.17). Chief among these would be ensuring the metering of all presently unmetered consumption, including the Royal Palace, some temples, and street lighting of some town panchayats. Given the impor- tance of developing a comprehensive data base on electricity consumption to monitor the levels of electricity losses and thereby the effectiveness of the loss reduction program, NEA needs to maintain an accurate up-to-date data base on electricity consumption, including the metering of presently unmetered supplies. Table 3.7: NEA LOSS REDUCTION PROGRAM : TARGETS AND PERFORMANCE Fiscal Year Targets a/ NEA Performance b/ Central Central Region Overall Region Overall Losses (Z) Losses (X) Losses (X) Losses (X) 1986 25 24 33 31.4 1991 N/A c/ 18 N/A 24.5 a/ As agreed under the IDA-financed Marsyangdi Hydroelectric Power Project. b/ Data for 1985/86 are estimates taken from Annex 3.1 (overall losses) and based on the report of the 1986 System Loss Study of BEI (Central Region Losses; data for 1990/91 are projections taken from the NEA load forecast (Annex 4.1). c/ N/A a Not available.  -30- 3.17 BEI conducted another system loss study in early 1986, under the IDA-financed Marsyangdi Hydroelectric Project. A five-year (US$16.3 million) system loss reduction program (SLRP) confined primarily to the Kathmandu Valley (Bagmati Zone) was recommended, together with a set of loss reduction targets covering technical and non-technical aspects. Technical measures would include phase balancing, followed by a program of transformer reloca- tion, reconductoring and distribution rehabilitation. Non-technical losses, sulch as pilferage, would be addressed through meter resealing, coupled with rehabilitation of inadequate service connections. Metering errors would be addressed through recalibration of three-phase meters (which in 1981 amounted to 130 consumers who accounted for 35% of electricity sales), to be followed by recalibration and testing of single phase meters. Billing errors would be handled through improved procedures for meter reading and accounting. Over- all, the BEI program envisages that about 75% of the reduction in losses would result from addressing non-technical factors and the remainder from dealing with technical factors. NEA intends to implement the first two years of the SLRP under savings from the Marsyangdi Hydroelectric Project. 3.18 NEA's load forecast projects that system losses will be reduced by approximately 1% p.a. over the next ten years (para. 4.04) through a progres- sive reduction in non-technical losses from their present level of 15% to 5%. The level of technical losses is predicted to remain unchanged at 15% because of continued stress on the subtransmission and distribution system resulting from the considerable planned rate of new connections (para. 4.05). NEA's thorough approach has resulted in realistic loss reduction targets, although they are less ambitious than those proposed by BEI. However, there is scope for increasing NEA's targets, especially for technical losses, by immediately instituting a phase balancing program (para. 3.17). Also, NEA has taken unnecessarily long (nearly eighteen months) to finalize the TOR and contract with BEI for implementing the agreed program. In view of the waste of resources and adverse financial effects of high system losses, NEA should review the projections of future system losses with the BEI team to agree on realistic monitorable targetsand accord very high priority to implementing the los reduction program. THIS should be combined with continued vigorous application of the penalties authorized under HMG/N's Electricity Rules against illegal connections. Since, at present, there is no loss reduction program specifically designed for the interconnected system outside of the Kathmandu Valley, NEA should also seek assistance to prepare an action plan to reduce losses in its interconnected system outside of the Kathmandu Valley. 3.19 Currently, NEA does not have a loss elimination program for its isolated systems. It is also recommended that NEA investigate the reasons for the large increase in losses in 1982/83-1985/86 and prepare a plan to reduce them to a level consistent with good operating practice.  -31- Privately Owned Generation 3.20 Privately-owned generation plants in Nepal include captive generation linked to industrial plants and micro hydroelectric plants. Available statistics indicate that the total installed capacity for captive generation is 17.1 MW (Annex 3.8); the capacity of known operating privately owned micro-hydro plants is approximately 250 kW. 1/ Given the possible capacity shortages in the NEA interconnected system, especially in 1993/94 and 1994/95 (para. 4.18) and the desirability of avoiding load shedding, NEA should monitor the status of privately owned generation (especially industrial autogeneration) regularly and develop a strategy for its use. C. Power Exchange with India 3.21 Nepal exchanges power with India at fifteen locations along their border. Table 3.8 summarizes the exchange of energy from 1975/76 to 1985/86. With the expansion of the 132-kV system to the Eastern Region and the availability of additional hydro energy resulting from the commissioning of the Kulekhani I, Devighat and Seti hydroelectric plants, there was a drastic reduction in net imports from India in 1985/86. The exchange of energy is arranged on an ad hoc basis with the Bihar and Uttar Pradesh State Elec- tricity Boards (SEBs). The price charged for each unit supplied is Indian Rs 0.14 (Nepal Rs 0.24), which has remained unchanged since 1971. Although an increase to Indian Rs 0.60 is under discussion, NEA will supply energy to India only when there is available hydro energy since it estimates the supply cost from diesel units to be NRs 2.11/kWh. Present contract arrangements for exchanging energy cover only tariffs and exchange limits (25 MW) (para. 7.02). Studies are required on the following areas usually covered in interconnection agreements between utilities: metering, communications and control; maintenance; control responsibility; operating procedures; and quality of supply (voltage, frequency, power factor). Furthermore, there is no formal contract agreement covering areas such as form of delivery, con- tinuity of power supply, force majeure, damages, billings, provisions for resolving disputes and modifying tariffs, etc. 3.22 Given the importance that HMG/N places on developing a bulk export market for electricity in India in the medium term (1987-2005), the present informal ad hoc arrangements for the relatively modest amounts of electricity exchange are not suitable for maximizing benefits from future bulk sales. Instead, it is proposed that HMG/N undertake an action program for developing bulk sales contracts with India, encompassing technical, financial, economic, institutional aspects and particularly the technical and contractual aspects of interconnection agreements mentioned above. Chapter VII, especially paras. 7.04-7.07, outlines the key steps of such a program. 1/ A listing of privately-owned micro hydro plants is available in the publication: Nepal Electricity Authority, Procedure Manual for Micro Hydro Evaluation, Kathmandu, May 1987, Report No. 4/2/120687/1/1Seq:2il.  -32- Table 3.8: SUMMARY OF EXCHANGE OF ENERGY WITH INDIA, 1976-1986 a/ (GWh) Growth Rate 1976 1981 1982 1983 1984 1985 1986 1976-1985 Imports from India 25.372 45.070 56.759 63.291 65.793 82.143 54.479 14.29% Exports to India 5.940 3.765 ?.432 8.922 10.313 10.575 21.457 6.512 Net exchange 19.432 41.305 49.327 54.369 55.480 71.568 33.022 15.05X a/ Fiscal years. Source: NEA.  -33- IV. FORECAST CONSUMPTION AND SUPPLY OF ELECTRICITY 4.01 NEA projects that the Nepal interconnected system will undergo a major expansion over the next twenty years, with total electricity demand increasing at an average annual rate of approximately 10X. This will require the implementation of a major integrated investment program in generation, transmission and distribution. This chapter reviews NEA's demand forecasts and expansion plans to satisfy the projected demand. Because of the need to ensure efficient resource allocation, Nepal needs to ensure that its power subsector investment program is least cost. The major issues examined in this chapter concern the implementation of the generation expansion plan (including the institution of a vigorous load management program) and the preparation of a nationwide master plan for transmission/distribution development. The chapter also suggests some ways in which NEA's institu- tional capabilities in system and operational planning could be strengthened. Finally, the impediments to the development of a comprehensive rural elec- trification program are examined. A. Institutional Responsibilities for Planning 4.02 NEA is responsible for the planning of generation, transmission and distribution development for its interconnected and isolated systems. The Director of System Planning, Planning Directorate, is responsible for load forecasting and conducting generation and transmission planning studies. Distribution planning is carried out in the Technical Services Department of the DCS Directorate (TS/DCS). After a project has been approved by NEA, a report is submitted to the MWR and ultimately to the Cabinet for approval. After Cabinet approval, NUA can proceed with the project and include it in its annual budget. Since NEA's formation, the planning functions have received considerable support from WERDP staff (para. 1.04). Within NEA, WERDP has set up generation planning programs and programs for carrying out load flow, fault, level analysis and stability studies. However, planning in generation and transmission is hampered by the lack of plann.ng criteria and standards and the inexperience of NEA staff in using the transmission plan- ning software to develop least cost technical solutions. Distribution plan- ning has not included a coordinated approach towards planning future exten- sions or formulating design standards. NEA's work is hampered by a lack of basic system data and geographic diagrams of existing 11 kV networks (para. 3.13).  -34- B. Growth of the Economy 4.03 Nepal is still one of the poorest countries in the world, with a per capita income of US$160 in 1985. Over the last decade, the GDP has grown at 3.21 annually in real terms, but with population growth averaging 2.71, per capita GDP has grown only 0.5% a year. As shown in Table 4.1, agriculture is still the economy's dominant sector, but its share of GDP fell from 701 to 591 during 1975-85. This reflects the fact that agricultural output grew only 1.51 annually from 1974/75 to 1984/85, compared with 6.41 a year for the non-agricultural sectors. As a result, food production has not kept pace with population growth, resulting in dwindling food exports with a consequent deterioration in the balance of trade. This has been accompanied by heavy Government budgetary reliance on domestic bank financing, which led to a serious drain on the country's foreign exchange reserves. To address these issues while facilitating continued economic growth, HMG/N has embarked on a program of financial stabilization measures (improving budgetary policy, controlling net credit expansion and non-concessional external borrowing and maintaining a realistic exchange rate) complemented by a package of broad macroeconomic and sectoral initiatives. 1/ The Nepalese authorities believe this program will enable Nepal to reach a real annual per capita growth of 2% by 1991. NEA's forecasts of electricity demand assume that economic growth will occur along the lines planned by the Government. Table 4.1: GROWTH AND COMPOSITION OF GDP, 1975-1985 a/ (NRs million) Annual Growth Rate 1975 1980 1975 1975 1980 1985 -1980 -1985 -1985 Gross Domestic Product 16,571 18,606 22,800 +2.3 +4.1 +3.2 Agricultural Sector 11,550 10,933 13,466 -1.1 +4.3 +1.5 Non-agricultural Sectors 5,021 7,673 9,334 +8.9 +4.0 +6.4 Non-agricultural Sector Share, 1 30.3 41.2 40.9 a/ In constant, 1975 prices. Cited years are fiscal years. Sources: Central Bureau of Statistics and the National Planning Commission. 1/ Further details are available in the World Bank report entitled NEPAL: Financial Stability with Economic Growth, March 1987, Report No. 6653-NEP.  -35- C. Future Electricity Demand NEA Load Forecast for the Interconnected Network 4.04 Base Case. NEA's current load forecast for the interconnected net- work was prepared with the assistance of the Canadian advisors of WERDP. 1/ It covers a 20-year period up to 2005/06. The methodology is a mixture of a disaggregated approach combined with econometric models, trend analysis and linkage with industrial output. It was developed based on a review of the effectiveness of different types of methodologies (extrapolation of previous experience, econometric models, Scheer model, 2/ energy input-outpit models and a disaggregated approach) in the Nepalese environment and their data requirements. This methodology is considered appropriate for the base case for the least cost generation expansion plan (LCGEP). 4.05 According to the base case load forecast (Annex 4.1), total sales within Nepal will increase at 12.4% a year during 1985/86-1995/96 and 5.7% a year during 1995/96-2005/06. The industrial and residential sectors would continue to be the driving forces in the expansion of the Nepal intercon- nected system, with 76% of sales in 2005/06. However, the industrial sector would surpass the residential sector as the leading source of electricity demand (42% of total sales). The decrease anticipated in the sales growth rate between the two periods reflects the projected major extension of serv- ice to new consumers (with a low initial demand for electricity) (para. 4.06) and a decrease in the industrial sector's expansion rate. This load forecast also assumed that system losses would be reduced progressively from approximately 30% now to 20% during 1985/86-1995/96 and remain at that level subsequently (para. 3.18). Bulk sales consist of the export to India of 1.5 MW at 50% capacity factor (para. 4.12). Units generated are projected to increase at an average annual rate of 10.4% during 1985/86-1995/96 and 5.7% p.a. during 1995/96-2005/06. Without considering the possible effects of a load management program, NUA estimated that the overall load factor would show little improvement, oscillating between 50.4% and 51.0%. This is because of the counteracting effects of projected increases in industrial sales (which improve the load factor) and rural residential connections 1/ Nepal Electricity Authority, Electricity Load Forecast 1986 (2 Volumes), Kathmandu, February 1987, Report No. PD/SP/430417/1-3. 2/ G. G. Scheer, "Prediction of Long-range Power Generation Requirements in Foreign Countries," AIEE CP 62-164 and Electrical Engineering, June 1962. The Scheer model links the annual growth rate of electricity consumption to the level of the per capita consumption of electricity in the long term. It also includes a price elasticity factor to account for real tariff increases.  -36- (which worsen the load factor because they have a load factor of about 25%). This pattern will increase peak demand 268% during 1985/86-1995/96 and 175% during 1995/96-2005/06. Per capita electricity consumption (measured as total supply divided by population) would increase to approximately 77 kWh in 2006, assuming average annual population growth of 2.7%. 4.06 NEA is projecting an annual increment of 20,000 household connec- tions through 1995/96 and then a progrensive increase in the number of annual connections to 60,000 by 2005/06. Although NEA has already achieved the target of 20,000 new connections per year for the last 2 years, this is a very challenging program since many of the future connections will be in dispersed areas (RE schemes) and the projections for 1995/96-2005/06 are much larger than previous levels. The capacity of NEA and local contractors to implement the complete program in the stipulated time is still unclear, although this would be a key factor in the program's success. Consequently, NEA should coordinate with local contractors to ensure that enough construc- tion capability will be available to implement the projected number of new connections. 4.07 Alternative Demand Forecast Scenarios. High and low medium- and long-term scenarios were developed to determine the extra costs resulting from the base case LCGEP if either the high or low scenarios become effective and to help formulate a plan to minimize these extra costs. To develop these scenarios, an econometric model relating energy generation to GDP was used. For the high scenario, NEA's forecast for the medium term (up to 1993) was acceptable; however, for the period beyond 1993, an extrapolation of the previous trend was used, but decreasing the annual growth rate progressively to 7%, then to 5.7% as NEA had done. This scenario resulted in a required supply by 2006 800 GWh higher than the NEA forecast and in a peak demand 125 MW higher. The low scenario resulted in a forecast energy demand in 2006 of 1,939 GWh (i.e., 87% of the base case demand); the corresponding capacity requirement is 64 NW lower than the base case scenario. Details of the base case and the high and low scenarios are presented in Annex 4.2. Load Forecast for Isolated Centers 4.08 NEA does not forecast electricity generation for those isolated centers not expected to be connected to the grid over the next 20 years. The level of consumption in these centers cannot be predicted in the absence of a rural electrification master plan. At present, the choice of villages for electrification appears to be largely political. Apart from this, they will be electrified mainly by run-of-river, mini-hydro schemes for which there are no reliable hydrological data. These are designed for a load factor of 0.35, and thus demand is supply constrained. Nevertheless, some estimates (based on judgement) have been made concerning the demand forecast for the isolated mini-hydro systems, taking account of generation from existing plants (2 MW) and plants under construction (6 MW by 1990 and possibly 20 MW by 1995), plus an estimated 5 GWh supplied from India. By 2005, the available supply for the isolated centers operated by NEA is projected to be 20 GWh or approximately 1% of the base case load forecast for the interconnected system for the same year. The resulting forecast is presented in Annex 4.3.  -37- Follow-up Work in Demand Forecasting 4.09 NEA plans to update its long-term load forecast (and LCGEP) as part of the preparation of its annual Corporate Development Plan (para. 2.16). The following approach would further strengthen NEA's long-term load forecasting: (a) enhance the present NEA load forecasting methodology by, (i) for the non-agricultural sectors, replacing the present linear model relating demand and non-agricultural gross domestic product by a log-log relationship 1/ to capture the impact of macro-income elasticity; (ii) for the residential sector, replacing the current approach, based on sample analysis, with one that estimates growth by utilizing existing data. This approach would extract from the data the average consumption of consumers who have been con- nected for one year, two years, three years, etc., and analyze the evolution of the rate of connection, taking account of existing local potential; and (iii) linking it with the proposed transmission/distribution master plan (para. 4.21) to develop a load forecast by voltage level; (b) introduce a technical management information system (THIS) to provide a reliable, current data base relevant to demand forecasting (para. 2.A7); (c) institute regular, systematic consumer surveys to ascertain elec- tricity consumption patterns by household, industrial and commercial consumers (para. 3.06); and (d) continue with a program of technical assistance to NEA, such as that provided by the WERDP team of advisors. 1/ LN(GVh(T)) - a + b LN (NAGDP(T)); where GWh(T) is the electricity demand in the non-agricultural sectors in the year T; NAGDP(T) is the non-agricultural GDP for year T; a and b are constants.  -38- D. Future Electricity Supply for the Interconnected System Generation 4.10 Exisqjn and Committed Cenerating Plants. Total installed capacity on the Nepal interconnected system in early 1987 was 183 MW, of which 158 MW (86%) was hydro and 25 MW (14%) diesel (see para. 4.08). Firm capacity is estimated at 162 MW, of which 145 MW is hydro (90%) and the remainder diesel. Available capacity should increase to 257 MW by 1990 with the commissioning of the Andi Khola (5 KW) and the Marsyangdi (69 MW) hydroelectric plants in 1989. During the Seventh Five Year Plan (1986-1990), the installed capacity of the interconnected system is planned to increase by 70%. 4.11 Generation Expansion Planning. A proposed power generation project is considered justified if it is shown to be part of the least cost gener- ation expansion plan required to meet demand at economically efficient price levels. This implies inter alia that (a) all practicable alternatives have been identified, (b) a standardized approach has been used to prepare cost estimates for each identified alternative, and (c) loss reduction, load management and other techniques for demand management and system improvement have been considered as an integral part of system planning. Under the joint sponsorship of CIDA and IDA, NHA, in conjunction with the advisors of the WERDP team, developed a rigorous four-step approach to identify priority generation projects in a Least Cost Generation Expansion Plan (LCGEP): 1/ (a) Standardized cost estimates were developed for eight candidate hydroelectric projects, each of which had been studied to either the prefeasibility or the feasibility level, 2/ plus for a thermal peak- ing option (gas turbines-GTs). The costs attributed to each project included transmission expenditures directly associated with the project and not common to all expansion sequences. All inputs were costed in economic terms; (b) Alternative expansion sequences that satisfied the base case load forecast were developed based on combinations of hydroelectric projects, supplemented by peaking thermal generation (GTs) as required; 1/ Further details are available in the report: Nepal Electricity Authority, Least Cost Generation Expansion Plan - 1987, Kathmandu, April 1987 (Draft), Report No. PD/SP/431124/3-2. 2/ Nepal Electricity Authority and Canadian International Water and Energy Consultants, Cost Evaluation of Hydropower Projects for the Generation Expansion Plan, Kathmandu, July 1987.  -39- (c) For each expansion sequence, the present value of the capital and operating costs was determined, and the least (economic) cost gener- ation expansion sequence was identified; (d, Sensitivaty analyses were conducted on the least cost sequence to variations in the load growth, opportunity cost of capital, fuel prices, and generation planning criteria. It should be noted that the base case load forecast explicitly takes into account the impact of loss reduction measures (para. 4.05); the potential results of a demand management program are discussed below (paras. 4.16-4.17). The candidate hydrolectric projects (Table 4,2) varied considerably in geographical location (see Map IBRD 19917) and size (60-660 MW); the smaller plants would only be suitable for domestic use while the larger projects could offer scope for power export. Five of the project sites offer potential for year-to-year storage, while the remainder, in common with most existing plants, are run-of-river, with little storage (see Table 4.2). 4.12 Some of the principal assumptions used in the LCGEP analysis included: (a) Fungibility of capital, i.e., capital was not tied to any particular project or subsector; rather it could be invested without restric- tions. The opportunity cost of capital was 10 in real terms; and (b) Generation sequences were identified within HMG/N's present elec- tricity export policy framework. Currently, NEA is only willing to make commitments to meet 1.5 MW of electricity load outside Nepal. However, once the next major hydroelectric project after Marsyangdi is added to the system, NEA would be able to meet cumulative export commitments of up to 25 MW load, as authorized by the present elec- tricity exchange agreement with India (para. 3.21). (NEA also plans to move towards arranging bulk export contracts of an incremental 100 MW or more at about a 501 capacity factor (para. 7.02).)  Table 4.2: SALIENT CHARACTERISTICS OF CANDIDATE HVDROELECTRIC PROJECTS /a I--Transmission--IAccesal I I I Road IIrricationl Project /a Region of ILength Voltage R Area i USt X 103 NW S/kW Nepal _ (Km) (kV) l(Km) (ha) AruA 3--Power Project Eastern ) 371.496 201 1.857 ) 386 220 105 - Arun 3--Power Pr^*ect Eastern ) 511.200 402 1,278 Bagmati Multi Ae Project Jb Central 132 N/A /c 120.000 612.481 140 4.375 Burhi Gandaki Power Project Central 65 220 31 - 709.841 600 1.183 /d Kali Gandaki A Power Project Western ) 123,868 60 2.064 ) 40 132 26 - Kali Gandaki A Power Project Western ) 149.652 90 1.663 Kali Gandaki 2 Power Project Western 30 220 N/A - 680.574 660 1.031 Kankai Multipurpose Project /. Eastern 99 132 N/A 67,450 194.907 60 3.248 Sapt Gandaki Power Project ) Intake Wall Scheme Central ) 372,199 225 1,654 ) t80 132 N/A - Sapt Gandaki Power Project ) Desanding Basin Scheme Central ) 439.147 225 1.952 West Seti Power Project Far Western 220 220 25 - 507.325 360 1.409 /a Costs in FY87 prices are exclusive of price contingencies and Interest during construction. /b Excludes 44,000 ha. of committed irrigation which is being financed separately. Ic N/A = not applicable. /d Earliest commissioning date 1997/98. /e Covers the cost of extending initial irrigation area from 8.000 ha. to 16,000 ha. Extending the irrigation component to 67,450 ha. would require a further USS153.1 million. Source: NEA/CIWEC. Cost Evaluation of Hydropower Projects for the Generation Expansion Plan.  -41- 4.13 Modeling techniques consisted of two programs, a reservoir operation routine called POWSIM and an economic analysis routine. The POWSIM model was used to simulate the operation of the power system when composed of any feasible combination of existing and new projects. The model developed certain rule curves geared to maximum use of hydro resources while minimizing thermal needs and complying with generation planning requirements. The models were reviewed and found to be satisfactory. 4.14 As a result of the LCGEP analysis, an initial sequence was selected consisting of: (a) 50 MW of peaking GT that would be commissioned over the period 1993/94-1994/95; and (b) the 402 MW Arun-3 hydroelectric project, that would be commissioned in 2 stages of 201 MW each, in 1995/96 and 2002/03, respectively. The Arun-3 project is a run-of-river hydroelectric plant, located in eastern Nepal, that is relatively isolated, requiring the con- struction of an access road of approximately 105 km. It is also situated close to the Chinese border, with 90% of its watershed located in Tibet. 4.15 The primary factor determining the least cost generation plan is capital because hydroelectric projects' operating costs are low. This gives a major advantage to the Arun-3 project because, unlike most other projects, its capital expenditures can be divided into two phases. The first phase would involve development of 201 MW, including the cost of facilities common to both phases (e.g., the dam, the access road, spillway, the power house and the transmission expenditures associated with the project). Almost 30% of the project cost including a second tunnel could be deferred to the second phase. This flexibility is albo advantageous in helping HMG/N execute its power export strategy (see Chapter VII). If Nepal negotiates a bulk export agreement with India (in the 100-200 MW range), commissioning of the second stage of the Arun-3 Project could be accelerated accordingly. 4.16 Least Cost Generation Expansion Plan. Analysis showed that if NEA's planting program were to proceed according to this initial generation expan- sion plan, there would be relatively large needs for hydrocarbon fuels in 1993/94 and 1994/95. In the latter year, approximately 10% of total gener- ation needs would be met by thermal generation utilizing approximately 34,600 toe of fuel (which would account for approximately 12% of hydrocarbon  -42- imports, if recent historical trends were to continue). 1/ Furthermore, analysis of the implicit cost of unserved energy 2/ (UE) associated with this expansion plan showed that it ranged from US$0.20 - 0.50, depending on the assumed capacity and fuel costs of the GTs. Since this range of values for UE is high compared to its explicit value, as determined by HMG/N (para. 3.11), and the proposed levels of fuel consumption for 1994 and 1995 would be contrary to the Government's policy of restricting thermal gener- ation, it was concluded that the initial sequence might not be optimal for Nepal. 4.17 The load duration curve for the NEA interconnected system (Annex 5.2) showed that there is considerable scope for reducing peak demand and eliminating the need for some or all GT generation at very little cost. During the peak period (the 202 of the time sf4en demand is above 75% of the maximum demand) only 2.5% of the total energy is consumed. Shifting some of this consumption to another period through load management, including time-of-day tariffs, could reduce the need for new thermal capacity. Thus, to demonstrate the least cost solution, it would be necessary to compare the initial sequence with a new sequence under different load conditions. The change in load conditions would be due to reshaping of peak load growth (without any changes in energy demand) by implementing a demand management program (para. 5.12). It was assumed that compared to the base case demand forecast (para. 4.05), this would cause at a minimum an attenuation of the growth in peak load during the first five years (and no further change there- after) and increase the load factor to 0.54. The first step in identifying the new sequence was to eliminate GTs from consideration. A revised planting sequence excluding thermal generation was developed. This sequence consisted of commissioning the first two units of the Arun-3 project in 1995/96, fol- lowed by individual units in 1997/98, 2002/03, 2004/05 and 2006/07 (see Figure 4.1). 1/ In 1980/81-1984/85, Nepal's petroleum imports grew at an average annual rate of 7.3%, respectively. 2/ This is defined as the value attributed "a posteriori" to the last kWh served, by HMG/N, within the framework of the LCGEP.  NEPAL CAPACITY BALANCE FOR THE LEAST COST GENERATION EXPANSION PLAN 700 - ARUN3#6 ARUN3#5 500 - ARUN3#4 --_ _ ARUN3#3 v 41130 U~~~RUN3#1h2 , 300 200 -SYUG1 AND 100 88 9 90 91 92 93 94 950 a 01 0 2 0 0 40 008 FSAL TA LOAD FORECAST INSTALLED CAPACIff  -.44- 4.18 The LCGEP program generated a solution for the revised sequence less costly than for the initial sequence, making it the least cost solution. Consequently, given the need to encourage the efficient allocation of resour- ces and meet forecast demand at least cost and bearing in mind the need to reduce Nepal's reliance on fossil fuel imports for meeting the generation needs of the power subsector, it is recommended that (a) the revised sequence involving Arun-3 without thermal generation be adopted as the least cost solution; (b) NEA develop a vigorous load management program encompassing tariff restructuring, time of day metering and seasonal two-part tariffs for all consumers connected at any level above LV (para. 5.13) and postpone, when appropriate, new connections (accompanied by implementation of a system loss reduction program (paras. 3.16-3.19) and use of available industrial autogeneration capacity (para. 3.20)); and (c) NEA should seek funding to finance and implement a time of day metering system starting with all con- sumers connected at any level above the low voltage level (para. 5.13). 4.19 Status and Follow-up Work for the Arun-3 project. Design of the headworks dams, waterways, powerhouse, switchyard and transmission) has been prepared to feasibility level status. An IDA-financed feasibility study has been completed for the access road; preparation of detailed design and bid- ding documents for the access road is expected to be finalized by June 1988. For the headworks the preparation of final design and bid documents will first require further investigation in hydrology, geology and desanding facilities and evaluation of alternative underground powerhouse/tunnel layouts. Additionally, further studies are needed to define the size and commissioning date of each generating unit. A detailed technical review of the Arun-3 project, including a proposed schedule for performing the inves- tigation work program and completing the final design, is provided in Annex 4.6. In order to keep the project on schedule, it is essential that HMG/N expedite the recruitment of consultants to undertake the above-mentioned tasks. Because of the size of both the Arun-3 project investments and the HMG/N power subsector investment program, the Government should review their macroeconomic impacts, especially with respect to the crowding-out implications for other sectors (see para. 6.15). Transmission 4.20 Excluding the 220 kV transmission associated with the Arun-3 project, NEA estimates that during 1986-1996 it will need to increase its transmission line route length by 89X by commissioning an additional 553 km of 132 KV transmission lines (of which 325 km would be strung on double circuit towers) and its total transformer capacity by 148% by constructing 7 new 132/33 kV substations and 4 new 66/11 kV stations with a total transformer capacity of 282 MVA and reinforcing existing 132 kV substations to a total transformer capacity of 356 MVA (details in Annexes 4.7 and 4.8). To date, financing has been secured only for projects due to be commissioned through 1989/90 (para. 6.09).  -45- 4.21 The proposed transmission projects are based on the results of load flow studies carried out by NEA that were linked to the load forecast for the interconnected network (para. 4.04) and the LCGEP recommendations (para. 4.18). The timing of substation reinforcement is linked to the criterion that reinforcement is necessary whenever the peak demand exceeds 75Z of the installed transformer capacity. The estimated peak demand at each substation has been based on an allocation of the system peak demand forecast, on a year-by-year basis, using the proportion pertaining at the time of the 1986 system peak. Although this approach is generally satisfac- tory for determining NEA's capital investment requirements over a time period, it is insufficient for detailed project justification and minimizing system losses. Before initiating funding for particular future reinforce- ments, a master plan should be prepared for longer-term nationwide transmis- sion/distribution development. Particular attention should be paid to reviewing the transmission reinforcement already identified by NEA and deter- mining the optimum linkage of the 220 kV supply from the proposed Arun-3 project with the 66 kV system in the Kathmandu Valley. Detailed studies will be required to determine whether there should be one infeed or two and the required phasing and operation consonant with meeting the longer term development of the 66 kV and 11 kV networks in the Kathmandu Valley and possible bulk exports to India. Distribution 4.22 Ongoing Projects. The major ongoing distribution project in the Kathmandu Valley is sponsored by JICA and consists of the reinforcement (Stage I) and extension (Stage II) of existing facilities. Stage I started in 1980, while Stage II began in 1982. Both stages are projected to be completed in 1987. The project's scope includes construction of 180 km of 11 kV lines and 270 km of 400/230 V lines, installation of distribution trans- formers with a combined rating of 53 MVA and associated switching facilities, and installation of 17,000 kWh-meters. As a follow-up to this project, NEA's transmission investment plan also includes a number of 66 kV transmission and step down 66 kV/11 kV transformer reinforcement for 1987/88 through 1995/96 (Annex 4.10). The scope of committed distribution projects sponsored by ADB and the Government of Finland (Finnida) outside the Kathmandu Valley is indicated in Table 4.3.  -46- Table 4.3s PROVISION OF NEA DISTRIBUTION FACILITIES UNDER COMMITTED FINANCEt 1986/87-1989/90 Overhead Lines Transformer Capacity Project 33 kV 11 kV LV MVA DC a/ SC a/ SC SC 33kV/llkV llkV/LV Fifth Power (ADB) 21 196 197 209 24 32.2 Sixth Power (ADB) 76 164 222 T.b.d. 32.5 T.b.d. b/ Finnida Phase II - 28 79 247 0.75 6.0 a/ SC = single circuit; DC - double circuit. b/ T.b.d. - to be decided. Source: NEA. 4.23 Future Projects. In addition to the six grid rural electrification (RE) schemes already being financed under the ADB Sixth Power LWan, HMG/N has proposed that the forthcoming ADB Seventh Power Project include an additional seven RE schemes, together with distribution and rehabilitation at a number of provincial towns. NEA has also identified five 33 kV reinforcement activities that need to be commissioned by the early 1990s for which no feasibility studies have been prepared nor funding committed (Annex 4.12). 4.24 Slow preparation and implementation of distribution projects are major factors in the present high levels of system technical losses (para. 3.15). The reasons for this include delays in hiring consultants for preparing the construction designs and tender documents, late availability of tender documents for procuring standard items and inadequate project manage- ment procedures. Since NEA is planning major increases in distribution investment (Table 6.3) compared to 1981/82-1985/86 (Table 6.1) and delays in distribution project implementation have adverse impacts on system losses and ultimately NEA's financial performance, consultant recruitment for new projects needs to be expedited to enable project design and bid documentation to be completed as soon as possible. Consultants should also assist NEA in project implementation, including the introduction of appropriate procedures for project monitoring and control.  -47- C. System and Operational Planning System Planning 4.25 While the techniques used by NEA in generation and transmission planning are generally adequate for the present, there is a need to focus on a number of points: (a) In generation planning, as the NEA interconnected system becomes more integrated with the planned commissioning of the Load Dispatch Center in 1987 (para. 4.28) and with the possible near-term establishment of interconnection links with the Indian power system, NEA should promptly develop probabilistic generation adequacy criteria. Also, since the nation-wide hydrological data base is being upgraded to provide approximately 20 coincident years of record at the major gauging stations and more storage hydroelectric projects are being considered for inclusion in the generating system, NEA should con- sider adapting and/or developing an optimization model that can handle stochastic rather than deterministic hydrological inputs and incorporate operating rules for multipurpose projects for both systeu generation and system operation planning (para. 4.28). (b) In transmission planning, since many areas are supplied via single circuit transmission lines, N8A should consider planning and operat- ing criteria related to the size of load being supplied and target restoration times. The selection and strategic siting of spares is influenced by the target restoration times. NEA should also seek the services of an advisor on transmission planning to help implement the above activity and develop a nationwide transmission/distribution master plan para. 4.12). (c) The interface between transmission and distribution planning has not been clearly defined. Therefore neither department was considering the reinforcement of transformers between the high-voltage and low-voltage networks that were not operating in parallel. In future the interface should be at the 33 kV busbar side of the 132 kV or 66 kV transformers' low-voltage circuit breakers. 4.26 To develop a stronger capability in distribution system planning, NEA needs to initiate a number of tasks promptly. These include the develop- ment of: (a) least-cost area load forecasts and distribution systems expan- sion plans; (b) distribution, design and equipment standards appropriate to Nepal and a costing data base for standard items of equipment; and (c) a central registry for system plant and configuration data. These tasks would be too large an undertaking for the six staff of the TS/DCS; decentralization  -48- of some activities could help to implement the tasks more efficiently. 1/ Zonal planning units could be made responsible for preparing short-term load forecasts three to five years ahead and then distribution expansion plans necessary to meet the load forecasts based on planning criteria, design standards and equipment cost data established by TS/DCS. 2/ The zonal plan- ning units would also establish and maintain an up-to-date data base of existing equipment. The TS/DCS would be responsible, on an annual basis, for reviewing and consolidating the zonal load forecast and development plans to ensure compatiblity with NEA's overall load forecast, prepared under the Director of System Planning (para. 4.04); preparing a consolidated distribu- tion capital investment plan; and establishing implementation priorities, based on available finance. It would also establish and maintain a central registry on distribution system plant and configurations. 4.27 At present NEA does not have the capability to implement the dis- tribution planning activities described above promptly. NSA should therefore seek technical assistance to help it: (a) prepare an annual rolling 5-year distribution plan; (b) train the engineers to be appointed to the zonal units to carrv out distribution planning on an economic as well as a technical basis; c organize a working committee to issue technical standards; and (d) develop a central registry on distribution system plant and configurations (para. 3.14). These activities should be coordinated with the proposed preparation of a nationwide transmission/distribution master plan (para. 4.21). A related issue is that NEA's systems planning capability has been severly weakened by the departure of key management and staff from the System Planning Department; as a matter of urgency, NEA needs to hire suitable staff for this department and arrange for them to participate in appropriate training programs. 1/ Distribution operations under DCS are grouped in three main regions (Eastern/Central, Western and Bagmati (Kathmandu)) which are further divided into zones, each with its own manager responsible for day-to-day operational activities. 2/ There are specific areas where immediate cost reductions can be achieved such as the use/expansion of (a) local manufacture of concrete poles; (b) simplified 33/11 kV substation designs for RE applications; and (c) the single wire earth return (SWER) system for single phase application.  -49- Operational Planning 4.28 The responsibilities of NEA's System Control Department of the Opera- tion and Maintenance Directorate include continuous coordination of gener- ation and load dispatch within the system to the level of 33 kV substations. This requires the formulation and implementation of daily, weekly and seasonal operation plans with procedures for system control, reservoir management and load dispatch. The system control facilities include a load dispatch center (LDC) built under the sponsorship of JICA at NEA headquarters in Kathmandu. The basic purpose of the LDC is to supervise limited com- munication facilities and a small status and telemetering system covering two major hydroelectric plants and three substations. Though the load dispatch centre will provide a useful introduction to central control, the facilities will not provide sufficient information to monitor and control NEA's total interconnected network effectively. For example, the upgrading and expansion of the communication network under the Japanese project does not include the integration of the new power-line carrier systems being installed on the 132 kV transmission lines presently being constructed nor the Marsyangdi hydroelectric project, when it comes on line in 1989. Also, training for the LDC staff will be limited to provision of operating manuals. There are difficulties in other areas because operational planning has been carried out on a somewhat ad hoc basis, as evidenced by the lack of detailed policies and guidelines for system operation. 4.29 Given the system expansion envisaged in the early 1990's (para. 4.7), possibly including interconnection with the Indian system, and the need to optimize system operation to minimize operating costs and the possibilities of load shedding, it is recommended that NEA seek technical as;istance to review the present LDC facilities and to determine, under a phased program, the medium- and long-term requirements in supervisory control and data acquisition facilities (SCADA) to include all power stations and 220 kV and 132 kV substations and reliable communication facilities with the relevant Indian load dispatch center(s). The consultants should also assist NEA in developing procedures for training NEA staff in preparation of daily, weeky and seasonal load forecasts and development of policies and guidelines for system operation, including spinning reserve, reservoir operation, and planned maintenance outages. F. Rural Electrification 4.30 Rural Electrification (RE) is an important component of a strategy to meet rural energy needs at least cost, which in turn should form part of a comprehensive rural development strategy (para. 1.07). This is because RE delivers high quality, potentially high productivity energy. At present, approximately 94% of Nepal's population live in rural areas, of which an estimated 2% has access to electricity. HMG/N policy in the Seventh Five Year Plan stresses the productivity aspects of RE such as facilitating the development and expansion of agriculture production and of cottage and  -50- small-scale industries. RE will be extended to areas that lie within the periphery of existing and planned transmission lines (para. 4.18); to a lesser extent it would also result from building and commissioning isolated hydroelectric projects. However, under the most optimistic scenarios, by 1995 only a marginal increase would occur in the percentage of the rural population with access to electricity. Most of those served would be con- nected to the national grid; only a small proportion would be served outside of the interconnected system because the capacity of isolated systems is not projected to exceed approximately 24 NW. 4.31 There are many reasons why RE programs, particularly for isolated sites, have not taken root in Nepal. First, there is no RE Master Plan to provide a framework for RE development. Second, activities of the various parties involved in RE are poorly coordinated. Even within NEA coordination is poor (para. 2.08). The situation is further complicated by the existence of a third party, the Agricultural Development Bank of Nepal (ADB/N), which finances private micro-hydropower rural schemes (para. 2.20). ADB/N operates quite independently of NEA, which it rarely consults. Third, poor project design, caused by data base weaknesses (hydrology) combined with errors in the estimation of the buildup of consumer demand, leads to mismatches of supply and demand. 1/ Fourth, inappropriate procedures have underestimated the consumers' willingness to pay for electricity and thereby tariff design for RE schemes has been distorted. Fifth, there exist misconceptions about the costs of RE schemes. For example, the costs of the hydropower schemes generally include the cost of transmission lines (mainly 11 kV), step-up and step-down transformers and the low-voltage grid, and consequently the average cost per kW is as much as US$5000. After deducting the transmission and distribution costs the average cost per kW installed declines to the more acceptable level of about US$1700 for the projects already in operation. Finally, despite ADB/N's support, private sector participation in RE schemes faces a number of financial, institutional, legal and technical impediments (para. 2.21). RE Action Plan 4.32 To address these RE issues, the following action plan is proposed: (a) ADB/N should prepare an action plan to address the impediments to private RE schemes, specifying the inputs required of Government, research and development organizations, ADB/N itself, NGOs and the private sector (para. 2.22); 1/ A review of the Dhankuta mini-hydro plant (240 kW) in Eastern Nepal shows that, contrary to earlier assumptions, the pattern of consumer consump- tion is the same for consumers of isolated centers and of tLe intercon- nected system provided the systems are not supply constrained.  -51- (b) Provide customized training for staff already working in RE. This could be done by sending some of the NEA staff working in the rural sector for training to countries such as Bangladesh, where rural electrification is much more developed than in Nepal and similar problems have already been experienced and solutions found. On their return, these staff could train other NEA staff. The cost of such training should be minimal; (c) Prepare a RE Master Plan (REMP) to define the scope and pace of RE development. Emphasis would be put on identifying a program of economically viable investments. It should cover areas not yet electrified that lie within the periphery of existing and planned transmission lines and would be served by isolated systems. The REMP should incorporate a RE load promotion program geared to developing markets for productive uses of electricity (in industry and commerce) and thereby increasing the system load factor and. operating efficiency. It should also include guidelines on tariff setting which allow for economic efficiency while taking into account variability in local conditions, especially at isolated sites (para. 5.11). In conjunction with the REMP activity, an institu- tional review should be carried out of all the organizations cur- rently involved in RE planning and implementation (including WECS, NEA, ADB/N, NGOs and private entrepreneurs) to determine what roles they could play in implementing the REMP and how coordination and integration of activities could be improved. The study to prepare the REMP should be carried out in Nepal under the management of a joint WECS/NEA working group. A private Nepalese consulting firm, or consultant, should be associated with the study to maximize the transfer of technology. (d) On its completion, HMG/N should review the REMP and the associated institutional and tariff studies and announce its future RE polic in terms of yearly objectives (e.g., the number of new connections per year at isolated sites), annual budgetary support, future institutional arrangements for implementing the REMP, and tariff policy. Given the social nature of many RE schemes, Government policy should also state explicitly that in cases of supplies for social purposes made at specific Government request, HMG/N would compensate the executing agency (para. 2.06).  -52- V. ELECTRICITY PRICING 5.01 Electricity tariff policy should be consistent with economic prin- ciples, as reflected in the long-run margin cost (LRMC) of supply for both the interconnected and isolated systems in the public sector. It should also ensure the financial viability of NEA and take into account HMG/N's social objectives. This chapter reviews the structure and level of the prevailing tariffs in the context of the economic pricing of power. A program is proposed to assist HMG/N in developing a tariff policy consistent with economic pricing principles for both the interconnected and isolated systems in the public sector. Overall pricing recommendations are made in Chapter VI. The tariffs for private sector schemes are also reviewed, leading to the conclusion that the present ad hoc procedures for tariff setting are satis- factory. A. Current Situation Institutional and Legal Framework 5.02 NEA is authorized by its Act to recommend electricity charges for Government approval charges for electricity. Within NEA, the Director Cor- porate Planning prepares recommendations on tariffs, in close consultation with the Director Systems Planning, the Distribution and Consumer Services Directorate and the Finance and Administration Directorate. After review by the NEA Board, the proposals are submitted to the Ministry of Water Resour- ces, whence they proceed to the Ministry of Finance, the Cabinet and, finally, His Majesty the King. This procedure (which is broadly similar to that of the NEC (paras. 2.02-2.03)) is not based on a detailed analytical review partly because NEA has not yet instituted the annual planning cycle provided for under Its Act (paras. 2.15-2.17). 5.03 As has been noted (para. 2.17), NEA should incorporate regular tariff reviews in any annual cycle for preparing the corporate development plans. This would also allow for timely signaling to consumers of short-term increases in electricity supply costs resulting from the impacts of unan- ticipated long dry periods, requiring heavy load shedding or thermal gener- ation using expensive oil to meet demand, and/or fuel price increases. The lack of tariff adjustments to compensate for unexpected short-term increases in electricity supply costs could also worsen NEA's financial performance. To address these issues, it is recommended that the NEA Act (1984) be modified to allow NEA to introduce a fuel adjustment charge (FAC) to the tariff energy rates when it incurs appreciable increased in fuel costs resulting from unanticipated low hudrological conditions and/or fuel price increases. The FAC should be used only to recoup fuel costs in excess of those incorporated in the published tariff rates linked to the forecast hydrological conditions and fuel costs in the reference year.  -53- 5.04 For private sector schemes, which are limited to isolated micro-hydro plants of up to 100 kW capacity (para. 2.21), there seems to be no regulation of tariffs. Rather, tariffs seem to be established by the private sector on an ad hoc basis and vary from scheme to scheme. B. Historical Review 5.05 Since 1978 NEA and its predecessor, NEC, increased tariffs on four occasions: in 1978/79 the average tariff rate was increased by about 351, about 56% in 1983, about 351 in March 1985, and about 22% in August 1985. During 1974/75-1984/85, although the average tariff rate increased by 16% a year in current terms, the increase in real terms was about 81 a year (Table 5.1). This was partly due to the Government's reluctance to make timely and adequate tariff increases. This situation, combined with high system losses (para. 3.16) and delays in commissioning of generation plant (which con- tributed to continuous shedding of peak load during 1978/79-1980/81), was also reflected in NEC's relatively poor financial performance (para. 6.04). However, with the introduction of the last three tariff increases, the rate of return improved to 5.41 in 1985/86, only marginally below NEA's financial objective of 5.51. No correlation could be established between electricity consumption and price, primarily because of load shedding. Now that the system is no longer supply-constrained, consumption and pricing should be linked as a load management tool (para. 5.13). The increases from 1983 onwards were accompanied by significant changes in the tariff structure. Table 5.1: AVERAGE REVENUE FROM ELECTRICITY SALES, 1975-1987 (NRs/kWh) Average Revenue Electricity Fiscal Constant Price Cost of Year Current Price 1975 Price Index Living Index a/ 1975 0.229 0.229 100 100 1976 0.262 0.250 109 105 1977 0.390 0.368 161 106 1978 0.387 0.331 145 117 1979 0.391 0.323 141 121 1980 0.435 0.320 140 136 1981 0.520 0.333 145 156 1982 0.522 0.293 128 178 1983 0.550 0.286 125 192 1984 0.795 0.390 170 204 1985 0.840 0.396 173 212 1986 1.170 b/ 0.476 208 246 1987 1.160 b/ - - N/A a/ Kathmandu cost of living index. b/ Estimate. N/A = Not available.  -54- C. Economic Costs of Supply 5.06 To provide a framework for analysis of tariff issues, the economic costs of supply of electricity were estimated. They were based on NEA's base case load forecast (para. 4.04), the least cost generation expansion program (LCGEP) (paras. 4.09-4.16), and the transmission/distribution program for 1986/87-1995/96 (paras. 6.07-6.08). Consequently the analysis was of com- parable reliability of NEA's work. It focused on the most likely export option--the 25 MW arrangement currently concluded between India and Nepal (para. 7.02)--and two alternative generation sequences, each incorporating the commissioning of the first phase of the Arun-3 Project in 1995/96, and different intermediate generation options. One generation option included a series of gas turbine units, while the other encompassed the introduction of a load management program through the implementation of the proposed tariff restructuring (para. 5.12) in 1988 (see also para. 4.16). 1/ 5.07 The analysis showed that the long-run marginal cost (LRMC) was lower for the generation sequence (1.39 Rs/kWh) without gas turbines (1.46 Rs/kWh) and therefore this sequence was used to estimate the LRMC for all components of the power system (generation, transmission and distribution). This was estimated for different voltage levels and for peak/off-peak and seasonal subperiods: (a) Peak hours, when demand is above 75X of peak demand (para. 4.17); (b) Off-Peak hours, when marginal energy costs are zero, this being the value of spilled water; and (c) Seasonality, since hydro-dominated generation systems incur different operating costs, depending on the season (wet or dry). Ir .'epal practically all generation is hydro during the wet season; most thermal generation occurs during the dry season. A seasonality analysis of the NEA system shows that the dry period (January-June) accounts for 842 of the average annual thermal generation. The resulting structure of the economic cost of supply is shown in Table 5.2. 1/ Simultaneously with the introduction of the "zero" option, HMG/N could also consider taking the following complementary actions: (a) implementing a system loss reduction program (paras. 3.14-3.16); (b) using available industrial autogeneration capacity (para. 3.20); and (c) postponing new connections.  -55- Table 5.2: STRUCTURE OF NEA COSTS OF SUPPLY, ALLOWING FOR SEASONALITY a/ (NRs/kWh) Net High Medium Low Generation Voltage Voltage Voltage LRMC 1.39 1.80 2.37 3.28 Medium term Capacity costs 1.35 1.76 2.33 3.23 Energy costs: Whole year: Peak 0.13 0.13 0.15 0.16 Off peak 0.00 0.00 0.00 0.00 Dry season: Peak 0.21 0.23 0.25 0.28 Off peak 0.00 0.00 0.00 0.00 Wet season: Peak 0.04 0.04 0.05 0.05 Off peak 0.00 0.00 0.00 0.00 a/ Generating sequence without gas turbines; 25-MW Exports; Arun-3 Stage 1 commissioned in 1995/96. Source: Mission estimates. D. NEA's Present Tariff 5.08 The present NEA tariff (see Annex 5.1), dating from August 1985, includes eight consumer categories. According to NEA, consumers in each tariff category pay the full costs of connection less an allowance of NRs 150; for domestic consumers, this is about NRs 350 in urban areas and URs 550 in rural areas. A major defect of the structure is that it does not signal the economic costs of supply to consumers; social and political con- siderations appear to weigh more heavily than economic principles in tariff formulation. Tariffs for the household and industrial sectors, which account for approximately 75% of electricity consumption in Nepal, are examined in this section. 5.09 The tariff for supply to residential consumers incorporates lifeline rates. It comprises three consumption blocks and a meter rent. The first block (up to 25 kWh/month) is charged a lump sum of NRs 11 plus URs 2 for the meter, giving a total cost to the consumer of URs 13 per month. The result- ing average price of NRs 0.52/kWh (for 25 kWh consumption) involves a large subsidy of 2.76 NRs/kWh (Table 5.3). The second block (26 kWh up to 300 kWh  -56- per month) has a unit rate of NRs 1.10/kWh. For the third block (all con- sumption above 300 kWh per month), the unit rate is NRs 1.35/kWh. Lifeline rates are justified in terms of an equity or income distribution objective. They enable low income consumers (who are equated to small consumers) to cover their basic needs, which are generally considered to include lighting and the use of a fan. Total monthly requirements for these uses would be approximately 25 kWh. Sometimes, a second subsidized block is defined in the 25-75 kWh range that would be sufficient to allow for the use of a small refrigerator, a black and -:hite television set and some additional lighting. Lifeline rates, which are applicable to all consumers in a tariff category, provide greater monetary oenefits to large consumers, since their consumption can take full advantage of all the units sold at the lifeline rate. If the sizes of the lifeline and subsidized blocks are too large and their unit rates are too small, then not only do large consumers enjoy greater monetary benefits, but also the smaller is the number of kWh sold at prices reflecting marginal costs. Further, in Nepal the lifeline rates could be increased without seriously undermining consumers' ability to pay because electricity represents a relatively small proportion of household expenditures for all residential consumers, particularly the middle income groups who constitute the bulk of consumers. 1/ In order to have the electricity tariff better reflect the economic cost of supply while meeting HMCIN' s social objectives, it is recommended that: (a) for the first block (0-25 kWh/month), the lump sum charge should be eliminated and the unit price be increased towards marginal cost (0.80 NRs/kWh); (b) the second block be reduced to 25-75 kW/month; and Tc) the third block would consist of all consumption above 75 kWh/month. 5.10 The present industrial tariff comprises three categories: small, medium, and large industries, defined by maximum permitted power demand (80 kW,, 5000 kW and over 5000 kW) and voltage of supply (400 V, 11 kV and 66 kV). They are two-part tariffs, with a demand charge and an energy rate. The tariff rates for small industries (on LV supply) are only marginally above those for industrial consumers on MV and HV supply, despite the higher costs of supply at LV. 1/ S. P. Sharma. Energy Pricing in Nepal (draft), The International Labour Organization, March 1986: Geneva. This study includes the results of a survey of urban households (that constitute approximately 70% of NEA's consumers). The survey showed that for all categories of consumers, expenditures on electricity averaged 3.3% of per capita annual income and for the poorest category, average electricity expenditures were 4.1% of per capita annual income. On average, electricity expenditures were approximately 30% of total household energy expenditures.  -57- NEA Tariff and LRMC 5.11 Table 5.3 shows the relationship between existing tariff rates and the long-run marginal cost of supply for the three major consumer categories: industrial, commercial and residential. Principal determinants of LRMC of supply vary by voltage level, increasing as the voltage level drops, and by the time of consumption. The table shows that existing tariff rates vary as a proportion of LRMC from a low of 161 for "lifeline" residential consumers to a high of 70% for hotels served at 11 kV and that all consumers are paying substantially less than LRMC. Considering the structure tariffs, Table 6.3 shows that although in general rates for industrial consumers increase as the voltage level drops, the rates for commercial consumers do not reflect the higher cost of supply at the lower voltage level. Rates for residential consumers, all of whom are supplied at the LV level, for load factors up to 271 are only marginally above that for HV. Also, existing tariffs do not signal the differing costs of supply in peak and off-peak periods or during wet and dry seasons. Thus, the tariffs fail to signal the economic cost of supply. 5.12 Since the current tariff does not (i) transmit the correct economic signals of supply to the various consumer categories; (ii) meet social or load management objectives; nor (iii) provide for an adequate level of self-financing by NEA of its investment program (para. 6.10), it is recom- mended that two detailed marginal cost based tariff studies be carried out covering the interconnected system and primarily isolated small/micro hydro systems. (a) For the interconnected system, a full tariff study should be con- ducted when both the LCGEP and the transmission/distribution master plans are completed (paras. 4.16, 4.19). In laying the groundwork for this study, NEA needs to expedite the implementation of the financial and technical management information systems (para. 2.17). Special attention should be paid to the issue of designing tariffs as a load management tool to support implementation of the recommended LCGEP; and (b) Because of the likely future importance of isolated small/micro hydro systems (paras. 4.28-4.29), a separate rural tariff study should be carried out after the preparation of the REMP (para. 4.29) as an input for the determination of a strategy for tariffs in rural areas.  -58- Table 5.3 COMPARISON BETWEEN 1987 TARIFF LEVELS AND LRMC a/ b/ TARIFF LRMC Average Cost per kWh CATEGORY per kWh/kW/month 200 400 600 kWh Load Factor Z (27) (55) (82) Industrial Large 1.80 HV c/ NRs 1.01 0.86 0.75 X of LRMC (56) (48) (42) Medium 2.37 11 kV NRs 0.98 0.91 0.89 % of LRMC (41) (39) (38) Small 3.28 LV NRs 1.03 0.96 0.94 X of LRMC (31) (29) (29) Commercial Hotels 2.37 11 kV NRs 1.66 1.46 1.39 I of LRMC (70) (62) (59) Hotels 3.28 LV NRs 1.66 1.46 1.39 I of LRMC (51) (45) (42) Others 2.38 11 kV MRs 1.43 1.27 1.21 I of LRMC (60) (53) (51) Others 3.28 LV NRs 1.43 1.27 1.21 % of LRMC (44) (39) (37) LRMC Average Cost per kWh per kWh/month 25 75 200 400 kWh Load Factor Z (3) (10) (27) (55) Residential 3.28 NRs 0.52 0.91 1.03 1.13 LV % of LRMC (16) (28) (31) (34) a/ Does not include categories, such as non-commercial, street lighting, drinking water, irrigation, transport, and temporary supply. b/ Numbers in parentheses indicate prevailing charges as a X of economic costs. c/ HV = high voltage (66 kV); LV - low voltage (400 V). Sources: NEA and mission estimates.  -59- Short-Term Strategy to Increase NEA's Average Tariff Towards LRMC 5.13 Since the results of the two master plan studies would not be available for some time (1-2 years), the NEA tariff should be redesigned now to reflect the economic costs of supply, meet the Government's social objec- tives, initiate load management measures to reduce the potential peak load demand and satisfy NEA's financial requirements. These will include self-financing of a major component of the very large investment program for 1986/87-1995/96 (paras. 6.07-6.08). The structure of the relevant tariffs to be applied could be designed on the basis of Table 5.2; however, there should be some modest off-peak energy charges to avoid a wholesale transfer of load to off-peak hours, thereby creating a shift in peak demand. The tariff increases should be geared at least to comply with the financial target agreed with IDA of a 6% rate of return on historically valued average net fixed assets in service over the next three years (para. 6.12). This task could be carried out by NEA with the help of a short-term tariff expert (approximately 1 month). Particular attention should be paid to the follow- ing aspects: (a) The residential tariff should consist of a three-block tariff, including a lifeline rate (para. 5.08); (b) For load management purposes, NEA should introduce a metering system for all HV and MV consumers which would allow the use of a two-part time-of-day tariff, including seasonality rates. The possibility of extending such tariffs and metering systems to industrial, commercial and noncommercial LV consumers should also be considered; and (c) Since the noncommercial tariff, which applies mainly to Government offices, does not include a demand charge, it should be modified by introducing a reference to the contracted load, if not to the metered load. Once the two tariff studies have been completed, the NEA tariff should be revised to reflect the studies' recommendations. E. Tariffs for Private Sector Schemes 5.14 Electricity tariffs for private sector schemes (micro-hydro plants of up to 100 kW capacity) usually take the form of a fixed charge per bulb, generally in the range of NRa 12-30 per month, but sometimes up to NRs 2 per night. Bulbs range from 40 to 60 Watts, giving an equivalent price per kWh of NRs 2.5-5. These values are well abovt the current NEA tariff (see Annex 4.1). Comparison of the estimated economic benefits of private iso- lated schemes and of RE supplies from the NEA network demonstrate that the high effective prices charged under private schemes are quite feasible, reflecting the capture of a large part of the consumer surplus in a quasi-monopoly situation (para. 2.20).  -60- 5.15 Based on a review of available data on household kerosene consump- tion patterns for lighting, the value of the willingness to pay ranged from NRs 3.24 to NRs 8.5 per kWh, which justifies the present tariffs of up to NRs 5.00 per kWh charged in some private sector schemes. However, once elec- tricity is used for other activities, such as cooking, willingness to pay becomes appreciably smaller, and the marginal benefits to the electricity suppliers are reduced. Consequently, because of the capacity limitation of the micro hydro plants, private owners are interested in their customers' limiting electricity use to low-consuming activities (such as lighting), where a large consumer surplus may be captured. In addition, this policy allows the owners to maximize benefits by maximizing the number of consumers. This also increases the social benefits by maximizing the number of people benefiting from electricity service under limited supply. 5.16 According to ADB/N, all the private sector micro-hydro schemes have been very successful; there have been no reported problems with accounts receivable and/or pilferage. Nor have there been reported complaints about reliability of service. In view of the above, the present ad hoc tariff setting procedure for private sector schemes appears appropriate and should not be changed.  -61- VI. INVESTMENT AND FINANCE 6.01 Nepal's electric power system began to expand significantly in 1977 (para. 3.10) as a result of HMG's decision to increase investment in the power subsector substantially. Its development has necessitated significant outside financial and technical assistance. The cost of building power infrastructure in Nepal has been high due to its rem teness, difficult ter- rain and geological conditions, poor communications, scattered load centers and lengthy high-voltage transmission lines relative to load sizes. In addition, plant unit sizes have been relatively small, 30 NW to 70 MW, and thus Nepal has been unable to achieve economies of scale. However, power consumption in Nepal is among the lowest in the world, and HMG/N has decided that the efficient development of power infrastructure in Nepal is essential to the nation's overall economic development. A. Past Investment 6.02 Annual public sector capital expenditure in the power subsector during 1981/82-1985/86 is shown in Table 6.1. Cumulative expenditure amounted to NRs 2,365 million (US$145 million) at current prices and accounted for 9Z of HMG's annual development expenditures during this period. In the early 1980s, investment resources were concentrated on building new hydropower stations to overcome the chronic power shortages (para. 3.10) and on high voltage transmission facilities. Investment in distribution facilities was badly neglected, causing them to be generally overloaded. This has been a major cause for the continuing unsatisfactory levels of system losses (paras. 3.16-3.19). Table 6.1: CAPITAL EXPENDITUREt 1981/82-1985/86 (millions of MRs in current prices) Fiscal Year Generation Transmission Distribution Total 1981/82 274 18 28 320 1982/83 214 56 92 362 1983/84 240 157 51 448 1984/85 287 199 34 520 1985/86 531 140 44 715 Total 1,546 570 249 2,365 X of Total 65 24 11 100 Source: NEA.  -62- B. Financing Past Investment 6.03 The development of Nepal's power subsector has been financed largely through concessional external aid. The funds have either been onlent to NEC/NEA at rates of interest ranging from 8.5X to 12Z or provided as grants in the form of government equity. Bilateral donors have included Canada, China, the Federal Republic of Germany, India, Japan, Kuwait and Saudi Arabia; multilateral sources were the Asian Development Bank, the UN Group and the World Bank Group (IDA). Table 6.2 summarizes NEC/NEA's sources of project financing during 1981/82-1985/86. The projects were prepared and implemented by the ED or one of the separate development boards, and trans- ferred upon completion to NEC/NEA for operation together with any debt serv- ice responsibilities. An analysis of NEC/NEA's sources of financing shows that long-term foreign exchange loans covered 49% of the capital require- ments, foreign exchange grants provided 34%, and Government equity contribu- tions 13%, while net internal cash generation only covered 4%. A financing pattern of large borrowings, substantial grant/equity contributions and low contributions from internal sources is not unusual at an early stage of power development, especially for systems based on the development of hydro projects. Table 6.2 SOURCES OF FINANCING FOR NEC/NEA'S DEVELOPMENT, 1981/82-1985/86 NRs Million US$ Million Sources of Funds (current prices) Equivalent a/ Z Internal Cash Generation (NEC/NEA) 363 22 14 Less: Debt Service 263 16 10 Net Internal Cash Generation 100 6 4 Gov't. Equity Contribution (Local Funds) 306 19 13 Grant (Foreign Exchange) 837 52 34 Long-c. rm Loans (Foreign Exchange) 1,196 75 49 Total 2,439 b/ 152 100 a/ US$1 = NRs 16.0 (Avg. exchange rate 1981/82-1985/86). b/ This total excludes investments implemented and operated by ED and SHDB; it includes increases in working capital. Sources: Ministry of Finance and NEA.  -63- 6.04 The financial performance of NEC/NEA, as reflected in the financial statements for 1981/82-1985/86 (Annex 6.1, pages 1-3) was unsatisfactory through 1984/85. NEC/NEA's rate of return (ROR) on historically valued average net fixed assets in service varied from 0.1Z in 1981/82 to a peak of 2.5% in 1983/84 while in 1984/85 the ROR was estimated to be -0.6%. 1/ These low RORs were caused primarily by inadequate tariff increases and high system losses (para. 3.16). NEA's financial performance improved with the introduc- tion of major tariff increases (of 56%, 35% and 22% in May 1983, March 1985 and August 1985, respectively). These improvements raised the average revenue per kWh from NRs 0.52 in 1981/82 to NRs 1.16 in 1986/87, improving the operating ratio from 96Z to 60% and the ROR from 0.1% to 5.8%. 6.05 The increasing use of long-term debt to finance fixed assets is altering NEA's capital structure. Prior to 1984/85, when the Kulekhani I project and debt obligations were transferred to NEC for operation, the capital structure contained little debt. This unusual situation for a public utility was due to the financing of past modest additions of plant through bilateral grants and treating the financing as equity when the asset was transferred to NEC. As a result of a new policy of utilizing long-term debt, the capital structure has changed substantially, with the debt/equity ratio rising from 7/93 in 1983/84 to 44/56 in 1985/86 and debt service increasing from NRs 15.1 million to NRs 134.9 million. While a debt/equity ratio in the 50/50 to 60/40 range is a more normal capital structure for an electric utility, the increasing use of debt to finance capital investment will require NUA to monitor its debt position closely. When a position of maximum debt is reached (either 65% of total capitalization or when internal cash generation falls below 1.5 times the debt service coverage), HMG/N should make equity capitai available to NEA as required to maintain an acceptable debt servicing position. Government Arrears 6.06 NEA's accounts receivable are generally satisfactory, ranging from 2-3 months of sales. However, there is a problem of large arrears owed by the Government. NEA's latest estimate shows that at the end of 1985/86, Government arrears amounted to NRs 38 million, equivalent to more than one year of Government billings (about 50% of NEA's total receivables, although Government billings are about 10% of total billings). The high level of Government arrears has meant that a significant amount of internal funds 1/ The negative rate of return is a result of non-recurring expenses in connection with the transition of operations from NEC to NEA and an initial full year's depreciation charge on the Kulekhani I Project trans- ferred to NEC at the beginning of 1984/85, which increased gross fixed assets in that year by 128%. Otherwise, the return would have been about 3.5%.  -64- generated by NEA had to be diverted from investment to finance working capi- tal requirements. Any measures that can be taken to resolve the Government arrears problem will release appreciable funds to finance system expansion. HMG/N should therefore take action, including collection at the source tiudgetary allocation) and, where pertinent, disconnection of service to ensure that Government agencies and departments pay their electricity bills within two months. C. Future Investment 6.07 An NEA investment program for 1986/87-1995/96 was constructed on the basis of existing information. The new project content of the generation and transmission investment program was based on the LCGEP analysis (para. 4.16) and on load flow studies conducted by NEA for the interconnected sys- tem. The distribution investment program (including a loss reduction com- ponent) was designed to be compatible with the base case load forecast (para. 4.04). Each item of physical data was assigned a unit cost based on mid-1987 price levels. Annual cash flow disbursements for foreign and local costs were assessed for all principal projects on a simple proportion basis. Where information was not available, estimates were inserted. The resulting NEA 1986/87-1995/96 investment program is presented in Annex 6.1 and sum- marized in Table 6.3. 6.08 Project costs include physical and price contingencies and taxes and duties (7X of foreign costs and 5% local costs). During this ten-year period, capital investment would amount to NRs 29.6 billion (US$1.06 bil- lion), consisting of ongoing works of US$376 million and planned future investment of US$681 million. Expenditures to increase generation capacity would account for 60X of the planned investment, about 20X for extension and reinforcement of the transmission system and about 20% for distribution. Expenditures on activities such as studies and training have been included as part of the estimates for the capital works projects (e.g., generation) with which they would be associated. The composition of the nroposed investment program is projected to change significantly compared to past investment profiles (para. 6.02). There would be a decrease in the relative importance of generation, which accounts for 60% of the NEA investment program compared to 65Z historically. The balance in investment is considered appropriate, especially as regards distribution, which has been relatively neglected in the past (para. 6.02). However, future detailed transmission and distribu- tion financing requirements should be based on the projects recommended in the proposed transmission/distribution master plan (para. 4.21).  -65- Table 6.3: NEA'S INVESTMENT PROGRAM, 1986/87-1995/96 (current prices) Percent NRs US$ Under Million Million a/ Construction Planned Total Generation Under construction 7,602 271.5 72 Planned 10,069 359.6 53 Subtotal 17,671 631.1 60 Transmission Under constru ion 1,128 40.3 11 Planned 4,948 176.7 26 Subtotal 6,076 217.0 20 Distribution Under construction 1,798 64.2 17 Planned 4,054 144.8 21 Subtotal 5t852 209.0 20 Total 29,598 1,057.1 100 100 100 Under construction 10,528 376.0 Planned 19,070 681.1 a/ Weighted exchange rate used of US$1 = NRs 28.0. Source: Mission estimates. Financing Future Investment 6.09 NEA's financing requirements will be met from a combination of internal and external sources. The total financial requirement including the cost of NRA's projected investment program for 1986/87-1995/96, as shown in Table 6.4 (Scenario B), amounts to URs 31.6 billion (US$1.13 billion), of which the foreign cost component is NRs 22.8 billion (US$813 million) and the local cost component is NRs 8.9 billion (US$316 million). The financing plan calls for the foreign exchange funds to be secured by HMG/N from multilateral and bilateral aid donors on highly concessional terms and to be passed on to  -66- NEA eithier as equity or long-term debt on commercial terms. Of the US$813 million requirement in foreign exchange, about US$294 million has been arranged or is in the process of being arranged. In addition, HMG/N has requested IDA to take the lead in mobilizing about US$400 million for the Arun-3 Hydroelectric Project. This leaves approximately US$119 million of foreign financing still to be arranged for planned future works primarily in transmission and distribution. If it became apparent that part of this financing gap could not be closed, NEA would need to pare down its investment program accordingly and be unable to meet the forecast demand for electricity in the interconnected system. NEA is most concerned that such an eventuality be avoided. 6.10 Foreign funds are unlikely to be available to finance the program's local costs in the period up to 1995/96, because of the financing gap which exists for foreign currency costs (para. 6.09). Therefore, the local funds requirements will have to be met from NEA's own internal sources and con- tributions from HMG/N, either in the form of loans or equity. NEA's ability to finance local cost expenditures from its own operations will depend on future tariff increases approved by HMG/N and on NEA's ability to collect accounts receivable, reduce system losses and control operating expenses. NEA's Financial Performance Objectives and Financing Plan 6.11 NEA's principal financial performance objective is to achieve finan- cial viability, defined as maintaining a suitable debt/equity structure (para. 6.05) and earning sufficient revcnues to cover all operating expenses and debt service obligations while financing a reasonable proportion of its capital expenditures. Moreover, in view of the minimal prospects for obtain- ing foreign funds to finance local costs (para. 6.10) and taking into account H1MG/N's own budgetary constraints to provide local funds, NEA should strive to finance all local funding requirements from its own operations. This would imply that NEA's financial strategy should be to set tariffs and con- trol costs to enable it to self-finance about 20-251 of the investment Program. NEA's ability to implement this strategy would, particularly, depend upon the size and timing of future tariff increases. In addition, complementary measures are needed to ensure appropriate control over costs, collection of accounts receivable and reductions in system losses. Two different financial performance scenarios and supporting assumptions were reviewed to test their suitability in meeting NEA's financial performance objectives and cash generation requirements. The detailed results are provided in Annex 6.1 and summarized in Tables 6.4 and 6.5. 6.12 Scenario A was based on NEA achieving compliance with the existing IDA financial performance target, which requires it to achieve a 6% rate of return on historically valued net fixed assets in operation. Scenario B consisted of tariff iv'treases in 1988/89 and 1989/90 likely to be required to satisfy an existing agreement with IDA, followed by a series of 20% increases in alternate years beginning with 1991/92 to enable NEA to self-finance all  -67- projected local cost expenditures. This latter scenario, involving appreci- able tariff increases, would allow NEA to self-finance 24% of its investment program, before taxes, including nearly all of its local costs. In this scenario, NEA would be ab,le to achieve the aforementioned financial perfor- mance objectives. Scent.rio A, geared to compliance with the existina finan- cial covenant, would require two tariff increases over ten years: 19% in 1988/89 and 471 in 1989/90 equivalent to an average annual increase of about 5.7% in current terms, compared to the projected annual average inflation rate of 62. Under this scenario, NEA would satisfy the covenanted 6% rate of return, but its self-financing level would be only 12% (before tax) and the burden to finance the bulk of local costs included in the investment program would fall on HMG/N. 1/ This analysis suggests that a rate of return target is no longer appropriate as NEA's primary financial objective; instead NEA and HMG/N should emphasize NEA's capital structure and self-financing capacity in developing financial performance objectives and agreements. This recommendation reflects the current arrangements for handling investment projects. Prior to the establishment of NEA, most major capital expenditures in the power sector were undertaken by the Electricity Department (ED) and transferred to NEC upon completion. NEC's self-financing requirements were minimal compared to NEA, which is responsible for capital works formerly undertaken by ED. Therefore, a revision of the financial performance targets for NEA is appropriate. 6.13 Table 6.4 indicates that Scenario B would enable NEA to self-finance about 14% (24% before income tax) of its funding requirements, including capital investment, after covering operating and debt service requirements. It would require NEA to raise the average revenue per kWh from the present level of NRs 1.16/kWh in 1986/87 to NRs 3.51/kWh in 1995/96. This would be equivalent to an average annual increase of 13.11 in current terms. As a percentage of LRMC, the average revenue per kWh would rise from 35% to 60%. The RORs (para. 6.04) would range between 6% and about 12%, with a rising trend. A rate of return of 12% would be equivalent to the onlending rate for IDA funds esLablished under previous power sector lending operations in Nepal. This scenario would also enable NEA to satisfy its debt service coverage covenant with ADB. Given the need to maintain the financial viability of NEA and provide for a reasonable amount of self-financing, it is recommended that as a medium-term target NEA should adopt the self-financing of a percentage of its least cost investment program (before taxes) that would cover all local costs (approximately 20%-25% of total costs, depending on the rate of inflation). In the interiun (1988/89-1989/90), NEA should seek tariff increases that would comply with the existing financial performance covenant. 1/ Under this scenario, ADB's financial covenant of a 1.5 times coverage of debt would not be met for 6 of the 10 years under discussion.  -68- Income Tax 6.14 NEA is subject to a 55% income tax calculated on net operating income after interest. Before 1985/86, when earnings were generally depressed, income tax remittances to the Government were not significant. However, as earnings improve, the amount would be substantial, resulting in a two-way flow of funds between HMG/N and NUA. On the basis of the planned investment program and implementation of the proposed series of regular rate increases over the next ten years (para. 6.12), forecasts show an income tax flow from 1lBA of about NRs 3.1 billion over the ten-year period, which compares with transfers from HMG/N to NEA of an estimated NRs 3.8 billion as equity con- tributions over the same period. If customs duties and taxes are taken into account (estimated at NRs 1.1 billion), the net transfer from NUA to HMG/N would be approximately NRs 400 million. Macroeconomic Perspective of NEA's Investment Program 6.15 The investment program and the amounts of financing involved are large in both relative and absolute terms and raise questions regarding the program's size in relation to Nepal's economy and whether the investment program is feasible from the standpoint of both financing and physical execu- tion. Overall, the ten-year $1.06 billion capital investment program for the power subsector would represent an estimated 31% of 1MG/N's total investment program for the period 1986/87-1995/96 (Table 6.6), compared to 9% during the period 1981/82-1985/86. However, since NEA would be expected to self-finance about 24% of the power subsector investment program (para. 6.12), the net burden on the HMG/N overall investment program would be reduced to approximately 23%. These costs need to be balanced against the potential benefits for Nepal of the power subsector investment program because it will facilitate the development of a bulk export market for electricity. 1/ HMG/N is currently analyzing the macroeconomic aspects of the NUA's investment program, especially the opportunity cost implications vis-a-vis investment in other sectors. It is also proposed that the issues of macroeconomic and budgetary impacts plus strategies for mobilizing financial resources for the NUA investment program be addressed as part of the action program for the development of large-scale electricity exports (para. 7.04). The principal bottlenecks to the implementation of the investment program occur in the preparation and execution of distribution works. Technical assistance has been proposed to strengthen NUA's project management capabilities in this important area (para. 4.24). 1/ For example, if Nepal were to enter into a contract to sell 200 MW load at 50% capacity factor at an average tariff of IRs 0.60 (US$0.045), annual revenue would equal US$39.42 million, in 1987 prices; this is equivalent to about 6% of projected total imports for 1986/87 (see para. 7.05 for a discussion on power contracts).  -69- Table 6.4: NEA FINANCING PLANS FOR 1986/87-1995/96 UNDER TWO SCENARIOS Scenario A Scenario B Targets6X Rate of Target:NEA Self-Financing Return of all Local Costs a/ b/ NRs US$ NRs US$ Million Million c/ X Million Million X Requirement of Funds d/ 30,741 1,098 100 30,943 1,10S 100 ==- ==== = == === == of which Foreign 22,758 813 74 22,758 813 74 Local 7,983 285 26 8,185 292 26 Sources of Funds Internal cash generation before taxes 9,583 342 31 13,323 476 42 Less: Taxes 1,041 37 3 3,098 111 10 Debt service 5,795 207 19 5,795 207 18 Net internal cash generation 2,747 98 9 4,430 158 14 Grants and borrowings-arranged 8,232 294 27 8,232 294 26 (foreign exchange) Sub-total 10,979 392 36 12,662 452 40 Grants and borrowings-to be arranged (foreign exchange) 14,551 520 47 14,551 520 47 Local funds to be arranged 5,236 186 17 4,435 134 13 Sub-total 19,762 706 64 18,984 654 60 TOTAL 30,741 1,098 100 30,943 1,105 100 a/ Under Scenario B it is assumed that NEA would implement tariff increases of about 20X, every other year, commencing in 1988/89. In this scenario, NEA would finance nearly all local costs (on a pre-tax basis). b/ Some numbers may not add up due to rounding error. c/ Weighted exchange rate used of US$1 = NRs 28.0. d/ Includes increases in working capital and investments in government bonds. The small difference in requirement of funds between the two scenarios is due to a slightly greater requirement for working capital under Scenario B. Source: Mission estimates.  Table 8 5s SUMMARY OF NEA S FORECAST OPERATIN6 RESULTS UNDER SCENARtO (A)t 6S RATE OF RETURN AND SCENARIO (B)s SELF-FINANCING OF LOCAL COSTS 1960/87-1995/96 (I) Scenarto (A)s 1988JB7 1987/88 1988J89 1S9/90 1990/91 1 1 11194/95 19 Operating Income (after tax) (NRS H) 170 197 258 468 682 738 785 759 792 948 Net Income (after tax and 1nt.) (MRS N) 46 61 12 16 53 79 107 45 54 209 Income Tax (NRS M) S5 75 1S 223 G5 97 131 55 67 256 Interest Expense 126 136 246 281 609 659 679 714 736 759 Average Revenue/kWH (NRS) 1.16 1t24 1.38 2.03 2.03 2.03 2.03 2.03 2.03 2.03 Operating Ratio (S) s6 66 67 62 51 51 52 58 60 S4 Rate of Return (S) 5.8 6.0 6.0 6.0 6.4 7.1 7.2 6.3 6.1 7.4 Debt Service Coverage (times) 1.6 1.7 1.3 2.0 1.4 1.4 1.4 1.4 1.4 1.6 Debt Equity Ratio 0.7 1.0 1.0 1.0 1.0 1.1 1.2 1.2 1.3 1.3 Current Rat1o (times) e/ 1.5 1.7 2.2 1.5 2.7 2.8 2.5 3.0 2.9 2.1 Percentage of self-financing 10-year capital program: 9% after income tax; 12% before tax. (It) Scenario M6I: Operating Income (after tax) (MRS U) 170 197 258 468 682 870 930 1108 1172 1645 Net Income (after tax and int.) (NRS N) 45 61 12 186 53 211 252 394 434 687 Income Tax (MRS N) 55 75 iS 228 65 258 308 482 531 1084 Interest Expense 126 136 246 281 609 659 679 714 738 759 Average Revenue/kWH (MRS) 1.16 1.24 1.38 2.03 2.03 2.44 2.44 2.92 2.92 3.51 Operating Ratio (S) 68 68 67 62 51 51 53 57 58 54 Rate of Return (S) 6.8 6.0 6.0 6.0 6.4 8.4 8.5 9.1 9.0,. 12.6 Debt Service Coverage (times) 1.6 1.7 1.3 2.0 1.4 1.6 1.6 1.8 1. 2.3 Debt Equity Ratio 0.7 1.0 1.0 1.0 1.0 1.1 1.2 1.3 1.3 1.3 Current Ratio (times) g/ 1.5 1.7 2.2 1.S 2.7 1.9 1.8 1.5 1.5 1.0 Percentage of self-financing 10-year capital program: 14% after Income tax; 24% before tax. a/ Includes current portion of long-term debt.  -71- Table 6.6: COMPARISON OF THE NEA INVESTMENT PROGRAM WITH THE HMG INVESTMENT PROGRAM, 1986/87-1995/96 Fiscal HMG Investment NEA Investment NEA Power Investment Program Year Program a/ Program b/ as % of HMG Investment Program (USS million) (USs millIon) 1987 206.6 57.2 27.7 1988 216.4 68.4 31.6 1989 250.8 28.2 11.2 1990 283.7 266.2 93.8 c/ 1991 316.9 72.6 22.9 1992 149.9 81.0 23.2 1993 388.6 122.6 31.6 1994 413.5 '143.7 34.8 1995 479.3 127.6 26.6 1996 532.3 88.8 16.7 Total 3,438.0 1,O56.3 30.7 Sources: a/ Data for 1986/87-1990/91 were extracted from the publication NEPAL: Financial Stability and Economic Growth, Washington D.C., The World Bank, March 1987, Table A.4. Data for years subsequent to 1991 were developed using a Markovian chain relationship chain relationship (based on data from the above publication and historical data) assuming the public share of investments stabilizes at 35X in 1991/92 and subsequent years. b/ Data extracted from and update of the Generation, Transmission and Distribution Capital Investment Plan, Kathmandu, Nepal Electricity Authority (April 1987). c/ For 1989/90, this ratio is more apparent than real because it indicates that NMA would take ownership of the Marsyangdi Hydro- electric Project after it has been commissioned. The construction of the project began in 1986 and is being managed by the Marsyangdi Hydroelectric Development Board. All costs are in current price terms.  -72- VII. ELECTRICITY TRADE WITH INDIA 7.01 HMG/N has made the efficient exploitation of Nepal's enormous water resource potential (para. 1.10) one of the nation's highest economic priorities. It wants to reduce substantially the cost and improve the availability of power to the domestic market for development purposes and to induce a substantial shift away from the use of fuelwood. More impor- tantly, the export of competitively priced hydropower to India represents Nepal's most attractive medium-term foreign exchange-earning option. The prospects for a hydropower-led export strategy are particularly good since the Government of India's (GOI) estimates of India's load growth call for an addition of more than 5000 MW capacity per annum in the foreseeable future. A. Development of an Export Strategy 7.02 Until recently, 1MG/N's strategy for the export of hydro electricity to India consisted of (a) sponsoring some of the necessary site studies of potential regional export-oriented projects at Karnali and Pancheawar, as part of a long-term (i.e., after 2005) strategy for developing electricity exports to India; and (b) handling current electricity export issues on an ad hoc basis (para. 3.21). With the expansion of the capacity of the Nepal national grid and the possibility of economically justifying the commission- ing of medium-sized (200 MW or more) hydroelectric plants,1 HMG/N recognizes that the opportuni.y is now ripe for developing a medium-term (1988-2005) strategy for the bulk export of electricity to India. At present, the exchange of electricity between the countries is covered by an agreement that limits power exports from Nepal to India to 25 MW, with a similar arrangement for im.irts into Nepal, at a price (approximately US$0.01/kWh) that has not changed since 1971. Historically, Nepal has been a net importer of elec- tricity, but its deficit is projected to be substantially reduced by 1992/93 once the Nepal national grid has been extended to areas that were primarily dependent on imported Indian power. HMG/N's present electricity export strategy is three-pronged and is linked to the planned commissioning of the Arun-3 Project when substantial shiort-term excess capacity could be made available: (a) until the Arun-3 project is commissioned, possibly in 1995/96, NEA will commit itself only to meeting the 1.5 MW load at about 50X capacity factor at Raxaul, in Bihar State in India (paras. 4.05, 4.12); 1/ 1/ NEA's present policy is, unless adequate hydro capacity is available, to supply only 1.5 MW of firm capacity to India. This is because the existing tariff of NRs 0.24 kWh is considerably less than the operating cost of diesel plant, NRs 2.11/kWh.  -73- (b) after Arun-3's commissioning, NUA would endeavor to increase exports to India up to the 25 MW capacity (with related energy at about 50Z capacity factor), as allowed under the present India-Nepal Power Exchange Agreement. A price of IRs 0.60(NRs 1.01 or US$0.045)/kWh has been agreed by the relevant electric utilities, but is still subject to Government ratification; and (c) after Arun-3's commissioning, NEA would also seek to implement a bulk export agreement with India, initially in the range of 100-200 MW, at about 50% capacity factor and possibly at more than one location. This agreement would be unrelated to the prevailing tariff agree- ments. This strategy is consistent with the stated desire of the Government of India "to import any available quantities of power [from Nepal] over the medium term." 1/ It should also include the possibility of exporting suitably priced secondary energy to India, which, at present, could reach the equiv- alent of 40-100 MW, depending upon the time of day and/or the time of year (para. 3.08); once the Arun-3 project is commissioned, secondary energy exports of 200 MW or more could be feasible at certain times. Because of the complexity of the issues involved, the informal ad hoc approach used at present would not be suitable in implementing this strategy (para. 3.21). Instead, it is proposd that HMG/N follow the export strategy outlined belowt that consists of development of an appropriate framework and a four-step action program for negotiating a bulk power export agreement. 7.03 The framework of HMG/N's electricity export strategy would focus on the following four issues: (a) the wide-ranging contractual, financial and technical implications of bulk supply agreements will require negotiations between the GOI and HMG/N and the participation of NEA staff in managing an extensive project preparation program (and its subsequent implementation and operation using inputs from pertinent Indian State Electricity Boards (such as Bihar and Uttar Pradesh) or from a national utility, such as the National Thermal Power Corporation; (b) although the character and scope of the arran- gements entered into under regional export-oriented projects will differ in many aspects from the agreements that would form part of the medium-term strategy (in aspects such as ownership, binational location (Pancheswar), institutions, operational procedures, etc.), close coordination of policies will be necessary on the principles/procedures for determining prices, treat- ing hydrological risk, determining price escalation factors, and resolving disputes, etc.; (c) the successful implementation of bulk supply agreements depends largely on engendering a climate of trust and open cooperation among all the interested parties, including the central governments and the 1/ Extract from official protocol of visit of the Minister of Finance (MOP) of HMG/N to India, December 1986.  -74- affected utilities; and (d) as a consequence of the points mentioned above and of the close linkages between the development of hydroelectric and water resources, the approach taken in addressing riparian issues between Nepal and India should not adversely affect the development of bulk supply electricity agreements between the two countries. 7.04 An action program for the development of large-scale electricity exports (100-200 MW) from Nepal would include the following steps: first, a task force should be established within the Planning Directorate of NEA with a time-bound mandate to (a) review the contractual, financial, budgetary, technical, institutional, economic and political ramifications of bulk electricity export agreements; and (b) negotiate a bulk export agreement with an Indian utility. The task force could be advised by appropriate WERDP staff and by outside experts, as necessary. The task force would keep the NEA Board regularly informed of the status of its activities. Through NEA's Chairman of the Board, the Minister of Water Resources, it would route key decisions to the Cabinet for approval. 1/ 7.05 Second, the development of a negotiating position will require NEA to carry out a number of study activities, including: (a) Review of Existing International/Inter-Utility Power Contract Agree- ments. Some information on such agreements has already been assem- bled by the Canadian WERDP consultants. This and other pertinent documentation should be reviewed and analyzed by the task force in terms of the formulas used for determining tariff levels; 2/ tariff escalation clauses; procedures for addressing currency fluctuations as well as other factors such as form of delivery, compensation, force majeure, damages, billing and provisions for resolving dis- putes; and risk sharing, especially hydro. 1/ An alternative arrangement could consist of a task force, chaired by the Minister of MOWR atid including representatives of various ministries such as Finance and Law and Justice with the Managing Director of NEA as Member Secretary. All the preparatory work and detailed negotiations would be implemented by NEA. This task force would route key decisions to the Cabinet for approval. 2/ For example, Hydro-Quebec has signed a contract with the New England utilities to sell them 7,000 GWh of firm energy, over a 10-year period beginning in 1990, at a varying price equivalent to 80X of the cost of electricity generated in New England by a combination of fossil fuels including coal, oil and natural gas.  -75- (b) Estimation of the Possible Range of Export Prices. The range will lie between the economic cost of supply from Nepal (which could be determined by a series of follow-up analyses to the Least Cost Gener- ation Expansion Plan (LCGEP), in constant price terms, together with a suitable escalation clause) and the value of electricity imports to the Indian state and/or national utilities. The agreed sales price would be in that range. The impact of the results of this analysis on the long-term financial viability of NEA should also be assessed. (c) Interconrection for Power Exports between Nepal and India. This study activity would have three objectives: (1) a feasibility study to determine the most suitable interconnec- tion option(s); (2) detailed design, development of specifications and preparation of bidding documents for the chosen option. The bidding documents will be prepared to invite bids, on an international competitive basis, for construction, erection and commissioning of substa- tions, transmission lines and ancillary equipment; and (3) development of operational procedures (including annual planning procedures, weekly/daily operation procedures, handling of emer- gency situations, etc.). This study would review at least two scenarios: (1) export of 40-100 MW of secondary energy, already existing in the Nepal interconnected system (para. 3.08); and (2) export of firm energy, in the 100-200 MW range, to a market or markets, the size and location of which would be determined by the GOI, in consultation with HMG/N. (d) Strategies for Mobilizing Financial Resources. IDA will assist HMG/N and NEA in the design and implementation of strategies for mobilizing foreign and local financial resources, including possible commercial sources, for executing the first phase of the Arun-3 Project. In the context of mobilizing financial resources, two issues should be given particular attention. First, contracts for the export of electricity to India may enjoy guarantees from one of the State Electricity Boards (SEBs) of the states contiguous to Nepal, namely Bihar and Uttar Pradesh, the states themselves and/or the Government of India. This could make the project more attractive for commeruial financing. Second, the most appropriate levels and mix of government financing (through either loans and/or equity contributions) and self-financing by NEA of the project costs should be identified. If commercial financing of part of the project seems feasible, criteria would be  -76- developed for evaluating financing and bid package options to help ensure the success of the project while minimizing costs and risks. These include identification of foreign exchange exposure and means to mitigate it, such as swapping schemes and bonding and guarantee arrangements. (e) Macroeconomic and Budgetary Impacts of the NVA Investment Program. Since investments in the power subsector represent a major component of HMG/N's capital budget, it is necessary to evaluate the impact of the NUA investment program (including the export-oriented Arun-3 Project) on GDP and the balance of payments. The objectives of such a study activity would include the evaluation of the impact of power subsector investments on convertible foreign exchange reserves; HMG/N's ability in mobilize the local component of the NEA investment program and to meet the debt service requirements; the "crowding out" impact of meeting power subsector investment requirements on invest- ments in other sectors; and the potential of power exports for aug- menting the supply of foreign exchange (convertible and non-convertible). Once these analyses have been completed, NEA would then be in a position to develop a strategy for negotiating a bulk power export agreement with India. This would then be reviewed by NUA's Board and subsequently the Cabinet. 7.06 The third step involves consultation between HMG/N and GOI. It will be necessary for HMG/N and the GOI to consult regularly and provide overall guidance by laying down the principles and general conditions on the develop- ment of bulk electricity export contracts. These would include: (a) the agreement, in principle, to establish a bulk electricity export contract; (b) principles covering the sharing of costs and benefits; (c) principles of price determination; and (d) principles for joint operation/maintenance of the interconnection line(s). A suitable avenue for consultation between 1MG/N and the GOI could be through the binatic4al Comittee on Water Resources Development, composed of the secretaries of Power, Irrigation and Water Resources. This committee is de facto also a forum for discussing power export contracts.  -77.- 7.07 The fourth step would involve the negotiation of a bulk power export areeement. This should preferably be conducted by a technical committee consisting of equal numbers of utility representatives from Nepal (NMA) and India (to be designated by the GOI), acting under broad guidelines agreed by 110/N and the GOI (see para. 7.06). On the Nepalese side, it would be pru- dent to have the advice of specialists with expertise in negotiating the financial and the technical aspects of similar contracts.  Annex 1s PROPOSED STRATEGY FOR THE DEVELOPMENT OF THE POWER SU8SECTOR Studies/Technical Assistance I*sues Objective Recggmendations Needed Priority I. I IPROVNA INSTITUTIONAL PERFRORANCE (a) NEAas autonomy Is To improve NEA s corporate lUG/N should undertake a review No. Medium inappropriate for the performance and make it a of the Nepal Electricity requiremnts of a rapidly more efficient power Authority Act (1984) with respect groving power utility and utility. to (1) delineating the aress the most important public where NEA can take decisions corporation in the country without consultation with Govern- (pars. 2.05). ment and (i1) Changing board composition to increase repre- *entation of NEA management and electricity consumers nd to reduce the number of government representatives (para. 2.05). (b) NEA has conflicting goals. To clarify NEA's corporate lUG/N should also review the No. Medium It is required to supply goals. NEA Act with respect to electricity to all, regard- emphasizing unabiguously NEA s less of ability to pay, and commereal character and the simultaneousey to operate on concomitant requirement that commercial principles consumers should bear the cost (para. 2.07). of supply, except in cases of supplies made at the specific Government request for which the Government would compensate NEA (pera. 2.07). (c) The laborious bureau- To expedite communication MGI/N should issue a directive No. Mdium t cratic communication pro- between staff of NEA. at to all Government departments cess between NEA and HMG/N level 7 and above, and and agencies that NEA staff at departments and agencies is departments and agencies level 7 and above are authorized impeding NEA in effective of HMG/N. to deal directly with them in management of its business the normal course of business. (para. 2.06). (para. 2.07) ld) NEA has failed to mold the To facilitate internal NEA should announce as a policy No. Low former NEC and ED staff communications within NEA that professional staff career into a well-coordinated and the establishment of advancement would be generally entity (para. 2.08). its own corporate identity, dependent on gaining wide ex- perience in the organization that, as a minimum. would encom- pas upstream (planning. engineer- ing, construction and downstrea (OMN) activities (para. 2.08).  StudiosIe/chnical Assistanco Issues Objective R_commendations Neded Priority (e) NEA has not resolved some To complete the integration NEA should review its prosent TA could be provided to High fundamental holdover prob- of ED and NEC staff and organization and staffing levels conduct the review and lams (related primarily to establish a separate with particular reference to advise on Its implement- the amalgamation of NEC and corporate Identity for NEA. consolidating all RE activities ation. ED). which are undermining in a single dtrectorate and corporate performance eliminating surplus staff (pars. 2.08). (pars. 2.12) (f) Inadequate conditions of To provide incentives for NEA should review the present Yes. High service are contributing improved staff performance, conditions of service to Identify to poor staff discipline areas where they could be improved and morale at NEA (para. focusing on a) the compensation 2.10). package; and b) establishing criteria for measuring and rewarding/ improving Individual management and staff performance, as appro- priate (para. 2.11). (s) NEA lacks well-defined. To enable NEA to formulate N