i AdEE =^2 7777-Energy Sector Management Assistance Programme ESfiS /Pl1 *Kenya Power Loss Reduction Study Report No. 186/96 JOINT UNDP/ WORLD BANK ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) PURPOSE The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) is a special global technical assistance program run by the World Bank's Industry and Energy Department. ESMAP provides advice to governments on sustainable energy development. Established with the support of UNDP and 15 bilateral official donors in 1983, it focuses on policy and institutional reforms designed to promote increased private investment in energy and supply and end-use energy efficiency; natural gas development; and renewable, rural, and household energy. GOVERNANCE AND OPERATIONS ESMAP is governed by a Consultative Group (ESMAP CG), composed of representatives of the UNDP and World Bank, the governments and other institutions providing financial support, and the recipients of ESMAPs assistance. The ESMAP CG is chaired by the World Bank's Vice President, Finance and Private Sector Development, and advised by a Technical Advisory Group (TAG) of independent energy experts that reviews the Programme's strategic agenda, its work program, and other issues. ESMAP is staffed by a cadre of engineers, energy planners, and economists from the Industry and Energy Department of the World Bank. The Director of this Department is also the Manager of ESMAP, responsible for administering the Programme. FUNDING ESMAP is a cooperative effort supported by the World Bank, UNDP and other United Nations agencies, the European Community, Organization of American States (OAS), Latin American Energy Organization (OLADE), and public and private donors from countries including Australia, Belgium, Canada, Denmark, Germany, Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal, Sweden, Switzerland, the United Kingdom, and the United States. FURTHER INFORMATION An up-to-date listing of completed ESMAP projects is appended to this report. For further information or copies of completed ESMAP reports, contact: ESMAP c/o Industry and Energy Department The World Bank 1818 H Street, N.W. Washington, D.C. 20433 U.S.A. KENYA POWER LOSS REDUCTION STUDY September 1996 Power Development, Efficiency & Household Fuels Division Industry and Energy Department The World Bank 1818 H Street, N.W. Washington, D.C. 20433 This document has restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without UNDP or World Bank authorization. Table of Contents FOREWORD ..............................................................i EXECUTIVE SUMMARY ..............................................................1I I. INTRODUCTION .............................................................. 12 Background .............................................................. 12 Power Sector Organization .............................................................. 12 Consumption Characteristics and Future Projections .....................................................2.........., 12 The Study .13 Study Objectives .14 II. ANALYSIS OF SYSTEM LOSSES .16 Transmission System Losses .17 Overall Distribution System Losses .18 Analysis of Losses by Voltage Level .20 III. STUDY METHODOLOGY AND SYSTEM CHARACTERISTICS .22 Background .22 Establishing a Computerized Distribution Planning Unit .23 Load Measurements .24 Distribution Planning Software .24 Economic Analysis .26 System Characteristics .............................................................. 29 IV. MEDIUM VOLTAGE SYSTEM IMPROVEMENT FOR NAIROBI CITY .30 Overall supply arrangements .30 Present System Operation .30 Development Proposals .31 New Substation at Kiambu .31 New Substation at Kileleshwa .32 Feeder Reconductoring and Introduction of New Feeders .32 Reactive Compensation .33 Summary of Network Improvements Proposed .34 V. COASTAL AREA MV SYSTEM DEVELOPMENT .35 Overall Supply Arrangements .35 Present System Operation .36 Development Proposals .37 Proposed 132 kV line Rabai to Diani and 132/33 kV Substation at Diani .37 Improvements to 11 kV Tiwi Feeder from Diani Substation .38 Proposed New Substation at Galu .39 Proposed 132 kV Line to Bamburi .................................. 40 Proposed 132 kV Supply to Malindi .................................. 41 Proposed Developments at Mazeras and Rabai .................................. 42 11 kV Feeder Tom Mboya From Makande .................................. 43 11 kV Feeder Bamburi No.1 From Nyali ...................................,,.. 44 Application of Capacitors for Reactive Compensation .................................. 44 Summary of MV Development Proposals for the Coastal Area .................................. 44 VI. L.V. NETWORK STUDY ................................................... 46 Existing System Characteristics ....................................................,. 46 Network Losses ....................................................... 46 Transformer Losses ................................................... 47 LV System Optimization ................................................... 48 Study Results ................................................... 49 Estimated Investment Requirements ................................................... 51 VII. NON-TECHNICAL LOSSES ................................................... 53 Meter Testing Methodology ................................................... 54 MV Bulk Power Consumers ................................................... 55 LV Bulk Supply Consumers ................................................... 56 Retail Consumers .................................................... 59 'Dead' Accounts ................................................... 60 Consumer Billing System ................................................... 62 Conclusion and Recommendations ................................................... 63 Recommendations ................................................... 64 Special Task forces ................................................... 64 Billing System Changes ................................................... 67 Improvements Under Implementation ................................................... 68 ViII. GENERAL CONSIDERATIONS ................................................... 71 Lessons Leamed ................................................... 71 Particular Characteristics Of Distribution Systems ................................................... 71 Organizational Issues ................................................... 71 Planning Studies and Development Proposals ................................................... 73 Non-Technical Loss Reduction ................................................... 74 Economic Parameters ................................................... 75 Complementary Issues ................................................... 75 Impact of Improved Tariff Setting and Load Management ................................................... 75 Impact on Sector Reform ................................................... 77 ANNEXES ................................................... 78 MAPS IBRD 26458 Transmission System and Distribution Area Coverage IBRD 26459 Inner Nairobi 11 kV Distribution System IBRD 26460 Nairobi City 11 kV Distribution System IBRD 26461 Single Line Diagram of KPLC Transmission System IBRD 26526 Central and South Coastal Area Medium Voltage Distribution Network IBRD 27805 Northern Coastal Area Medium Voltage Distribution Network ABBREVIATIONS AND ACRONYMS km - Kilometer kV - Kilovolt kVA - Kilovolt ampere kVAr - Kilovolt ampere, reactive kW - Kilowatt kWh - Kilowatt hour MVA - Megavolt amphere MVAr - Megavolt amphere reactive MW - Megawatt in.sq. - Inch Square (Used for conductor cross section) LF - Load Factor, a ratio expressing the average to peak power supplied LLF - Loss Load Factor, a ratio expressing average losses to peak losses in a defined part of the system. MV - Medium Voltage (11KV and 33KV) LV - Low Voltage (240/415 volts) LRMC - Long Run Marginal Cost ESMAP - Energy Sector Management Assistance Programme organized jointly by the UNDP and the World Bank KPLC - Kenya Power and Lighting Company Ltd. SIDA - Swedish International Development Agency SCA - Steal Cored Aluminum (a conductor type) ACSR - Aluminum Conductor Steel Reinforced (a conductor type) FOREWORD This report is based on the studies carried out by KPLC and ESMAP personnel from September 1991 to mid 1993. The ESMAP team comprised of Messrs. Winston Hay, Principal Power Engineer and Chrisantha Ratnayake, Senior Power Engineer. Messrs. Jon-Eric Johnson and Bergsvein Wang, Consultants from IVO International assisted in training KPLC counterpart staff during field assignmnents over a period of six months and one month respectively. The extensive contributions made by KPLC counterpart staff in carTying out the field work and data analysis is readily acknowledged. The report was prepared by Mr. Chrisantha Ratnayake. Mmnes. Cindy Wong and Renee Williams provided secretarial support. EXECUTIVE SUMMARY 1. The power system in Kenya is managed and operated by Kenya Power and Lighting Company (KPLC). KPLC owns most of the transmission and distribution networks, some generation plant and has an agreement to operate and maintain the remaining power plants owned by a number of other companies. Although about 40% of KPLC's shares are privately owned it is closely controlled by government. After recording high growth rates for a considerable period, the load increases from 1992 onwards reduced to around 3% per annum, partly due to power rationing caused by shortage of generation capacity. The overall system losses, which have remained at around 15% of net generation over the last five years, are not excessive by standards in most other developing country utilities. However, in the context of capacity shortages and the resulting load shedding, reductions that can be achieved in both peak power and energy losses are of considerable value. A number of economic improvements are deemed feasible in both the transmission and distribution systems. Requirements for the transmission system have been identified recently by KPLC's consultants. These measures include introduction of reactive compensation in the short term and the construction of a number of new lines, particularly Kiarnbere-Nairobi, Nairobi-Mombassa and Lessos-Olkaria-Nairobi all at 220 kV in the medium term. A systematic investigation of the distribution system had, however, not been undertaken before the present study. 2. In order to carry out an efficiency improvement program in the distribution system, KPLC decided to undertake a study which would both identify needed economic investments and develop its own competence in continuing such activities in the future. In addition to addressing technical aspects, it was deemed necessary to reduce as far as practicable, losses resulting from non-technical sources. Arrangements to undertake such a study were finalized with the World Bank-UNDP sponsored Energy Sector Management Assistance Program (ESMAP) and financial support was obtained from the Swedish Intemational Development Agency (SIDA). The ESMAP study commenced in October, 1991 with the establishment of a special unit within KPLC's Corporate Planning Division. The studies were restricted to the distribution systems in the central part of Nairobi City and the Coastal Area (Mombassa and its environs). A major objective of the project was to train KPLC counterpart staff in the skills of computerized distribution system planning so that loss monitoring and network development planning activities would be carried out on a continuing basis. ESMAP staff organized and supervised the study and provided the necessary technical guidance. Short term consultancy support to train KPLC personnel was arranged by engaging IVO Intemational of Finland (one distribution consultant for 6 months and one commercial consultant for 3 weeks). -2 - Objectives and Overall Achievements 3. The principal objectives of the project were to: * identify the main sources of technical and non-technical losses and develop estimates of the contribution of each of these to overall losses; * introduce state-of-the-art techniques of data collection and distribution system planning and train KPLC staff in such applications; * develop specific proposals for Nairobi city and the Coastal Area to reduce technical losses to economic levels; and * introduce procedures to assist KPLC to detect and rectify instances of non- technical losses. 4. A singular achievement of the project was the establishment of a very capable distribution planning unit within KPLC. The counterpart unit in KPLC which commenced as a temporary cell with staff released from a number of different branches, was subsequently established as a permanent unit within the Corporate Planing Division. The staff of the newly established unit made commendable progress in acquiring the skills necessary to undertake computerized analysis of distribution systems. Microprocessor based measuring instruments were used in obtaining network loads at important locations and key distribution system characteristics such as loading densities, load and loss factors, power factor, etc., were determined. A computerized mapping data base has been fully developed for the medium voltage' (MV) networks which were studied in Nairobi City and the Coastal Area. Two software packages --LOWO purchased from IVO International of Finland for low voltage (LV) system studies, and DPA/G supplied by Scott & Scott of USA (for both MV and LV systems)-- are fully functional in KPLC's distribution planning unit and were extensively used in the network analyses carried out. This is an important achievement as it lays the foundation for state-of-the- art distribution planning activities. The Consultants and ESMAP staff interacted extensively with the counterpart staff of KPLC in establishing data collection methodologies and in carrying out the planning studies. Such close interaction and training was seen to be a vital part of the technology transfer necessary for KPLC to carry out these activities on a continuing basis. KPLC staff responded commendably and built up their expertise to a level at which they were useful in training personnel from other power utilities. In early 1993 members of the KPLC team participated in two assignments to train staff from the People's Republic of China on similar projects being undertaken with ESMAP assistance. In mid 1994 a KPLC representative visited Bangladesh to train and work with counterpart staff from the Rural Electrification Board of Bangladesh and subsequently a joint team from Bangladesh and Nepal visited Nairobi for a 1 Medium voltage (MV) refers to 33 and 11 kV; low voltage (LV) refers to 400/230 volts. -3 - month long training exercise. The knowledge and experience gained by the counterpart staff and the institutionalization of the unit augurs well for the continued development of KPLC's distribution planning function. 5. Distribution network studies carried out were based on the application of the measuring instruments and software described above. In order to obtain an analysis of estimated overall system losses, data from the distribution systems studied were combined with infornation from KPLC's records on consumer sales and transmission flows. In general the data pertains to that of FY91-92 (July 1991 to June 1992). Two geographic areas (representing together almost half the total load of the country) were selected for the distribution study. The first consisted of a section of the Nairobi city and the second included all major networks in the Coastal Area. 6. The analysis and conclusions of the study indicate that loss reduction should be seen as one of a multiple set of network development objectives, which should include reliability improvement and increasing network capacity to meet future load growth. It was also observed that the omission of one or another of these benefits precludes the selection of the optimum alternative. The planning concept should thus be a systemic approach to the overall improvement of network performance. Accordingly, proposals contained in the report are based on the evaluation of all three of the major benefits: loss reduction, reliability improvement and the ability to meet future network load growth. A general observation from the results is that it is often economic to advance investments which are necessary to meet technical considerations at a future date. 7. The study of the medium voltage (MV) systems within the areas considered, resulted in identifying investments of approximately US$ 21.0 million to bring these networks to economically acceptable performance levels. These investments would provide substantial economic benefits with an overall benefit to cost ratio of approximately 25:1. Many of the proposals identified need to be implemented without delay in view of the critical network conditions presently being experienced. Major developments identified consist of 5 grid substations (66/11 kV and 132/33 kV) and 2 primary substations (33/11 kV). The proposals also include reconductoring of certain line sections as well as the addition of some new sections and feeders. Capacitors aggregating 9.1 MVAr are also included for power factor correction, each capacitor addition selected providing a pay back period of less than 18 months. 8. With respect to low voltage (LV) systems, the operational performance can be optimized by substantial decentralization of the existing networks (by adding new transformers to reduce the area covered by each unit). Investment requirements for LV system improvement over the next five years is estimated at US$8.5 million for the study area yielding a benefit to cost ratio of approximately 10:1. Unlike MV investments which can usually be planned a few years in advance, LV improvements should be based on the system configuration and expected new loads at the time of the investment in view of the rapidly changing circumstances. -4 - 9. Loss reduction and system development proposals identified in the report yield high benefit to cost ratios and are substantially robust in relation to variations in the relevant parameters (growth rate, cost of power, interest rate etc.). They are also particularly important in the context of the present load shedding and power shortages experienced in Kenya and should therefore be implemented as soon as possible. In addition they will improve KPLC's operational efficiency and fmancial performance, thus complementing current efforts at sector reform -- private sector power generation being sustainable only in the context of the fmancial viability of the operating utility. 10. Section 1 of this report provides a general background of the power sector and explains the initiation of the present study. Section 2 provides an overall analysis of system losses and their breakdown in relation to various network components. The methodology followed in carrying out the technical and economic analysis is explained in Section 3. Sections 4 and 5 describe the studies carried out for medium voltage (MV) systems in Nairobi city and the Coastal Area respectively while Section 6 deals with the analysis of low voltage (LV) systems. In Section 7, the investigations carried out to detect non-technical losses are described and proposals presented for remedial action. Section 8 addresses some general considerations on the lessons learned from the study and other complementary matters. The main conclusions of the study are reviewed in the following paragraphs. Overall System Loss Analysis 11. An analysis of KPLC's power system losses is presented in Section 2. Energy consumption in generation stations and losses in the transmission system were obtained from KPLC system control records based on metered data at power plants and substations. MV and LV studies carried out provided the basis for estimates of technical losses in these networks. The difference between overall energy losses and technical losses provided an approximate estimate of the non-technical energy losses. In addition, investigations of non-technical losses were also carried out during the study and although only relatively few samples were checked in relation to the overall system, it is noteworthy that the results of the two methods employed were in close agreement. Unlike energy losses, power losses2 cannot be measured as there is no convenient method of measuring the coincident demand of all consumers (either for the total system or for a given network section). Thus, in the absence of a definitive knowledge of the overall power loss, the non-technical component cannot be determined with reasonable confidence. However, power losses are extremely important as it is the peak load that determines the capacity requirements of the system (and therefore the extent of load shedding necessary when shortfalls exist). Hence an estimate of the possible range of both non-technical and overall power losses are provided (on the basis of computed technical losses and an estimated conversion of the non-technical energy losses to power losses). Accordingly, the power and energy losses of the networks (based on net generation) are estimated as follows: 2 Power losses are usually computed at system peak. - 5 - Overall System Losses Power (%) Energy (%) Transmission system loss 5.5 4.5 Distribution (technical) loss 11.3 6.3 Non-technical loss 7.9 (6 to 10%) 4.4 Total system loss 24.7 (23 to 27%) 15.2 12. These figures are estimates based on the limited work carried out during the study. They are also based on the system conditions of FY91-92 (July 1991 to June 1992). KPLC should continue to expand its loss monitoring activities and refine these estimates on a periodic basis. Although the losses in the Kenyan power system are not high in comparison to those of many developing countries, considerable benefits can still be gained by efficiency improvements. In particular, the system non-technical loss could be reduced to more acceptable figures with minimum capital investment. The overall power loss at system peak is estimated to be in the region of 23% to 27% and represents a sizable erosion of valuable power supply capability in the context of the present capacity shortages. Reduction of technical losses in the distribution system to about half the present amount can be carried out economically. Improvements are also possible in transmission system losses, particularly by reactive compensation in the near tern and 220 kV system improvements in the longer term (as demonstrated in separate studies carried out by KPLC and its consultants). Thus, with well planned investment and good operational practice it is feasible to approximately halve the existing power and energy losses. Accordingly, it is recommended that KPLC assign a high priority to implementing the recommendations of this study. 13. The technical losses in the distribution system may be further disaggregated on the basis of (a) input to the distribution network (at grid substations), as well as (b) input to individual network components. A summary of the results obtained is presented below: Distribution System Losses by System Components As % of input to As % of input to each component Distribution System Power Energy Power Energy Grid SS Transformers 1.0 0.8 1.0 0.8 MV Lines 5.1 3.5 4.9 3.2 LVTransformers 1.1 0.7 0.9 0.5 LV Direct Lines 1.0 0.5 0.9 0.3 LV Retail Lines 5.4 3.6 4.2 1.7 Total technical loss 12.0 6.6 Non-technical loss 8.2 4.5 Total distribution system loss 20.1 11.1 - 6 - Development Proposals for Nairobi City 14. The 11 KV networks covering an area of around 500 sq. km. and containing the highest load concentration in the Nairobi city were subjected to a detailed technical analysis using the specialized distribution planning software supplied. The overall loss level was found to be reasonable --2.6% for power and 1.8% for energy at present loading levels. This is mainly due to a well configured 11 kV system (with the average feeder distances of 2.5 km for the highly loaded areas) supplied by seven 66/11 kV substations. However, in the absence of system improvements, these losses are expected to increase to about 6.4% and 4.6% in 10 years from now for power and energy losses respectively. Again, if no improvements are carried out the respective losses would rise to 9.6% and 6.8% in 15 years. This indicates that timely action needs to be taken to identify high loss sections and undertake the necessary improvements. 15. Some feeders with power loss values (ranging from 3 to 5%), significantly higher than the rest of the network, were identified in the western and north western sections outside the central city. Investigation of development proposals in this area resulted in recommendations for two new 66/11 kV substations at a cost of about $4.5 million to strengthen system performance (benefit to cost ratios being 26:1 and 22:1 respectively). Investments in new feeders and reconductoring, amounting to $ 0.6 million at a benefit to cost ratio of 13.7:1 were also identified. 16. A number of feeders with poor power factors were identified resulting in the recommendation of 6.7 MVAr of capacitors at a cost of $73,800. These investments have a pay back period of only 18 months. For the longer term improvement of feeder power factors a program to improve consumer load power factor is recommended. Further, both the feeder loss levels and the effectiveness of the capacitors could decrease with other system developments (e.g. new substations) which may be introduced in the future. However, the addition of capacitors is still recommended in view of the low pay back period and the possibility of moving these units to other locations yielding additional benefits when the system improvements referred to are effected. Development Proposals for the Coastal Area 17. Network load flows carried out for the Coastal Area indicates that MV line losses are considerably higher than in Nairobi, with the overall losses being 6.4% and 4.4% for power and energy respectively for present loading conditions. Without system improvement these losses increase to 11.2% and 8.2% in 10 years and to 18.8% and 12.5% in 15 years for power and energy respectively. The highest contribution to these losses are from the long 33 kV feeders (both in the southern and northern directions) supplying load concentrations at considerable distances from the main supply substation at Kipevu. 18. Three 132/33 kV grid substations at Diani, Malindi and Bamburi and two 33/11 kV primary substations at Galu and Rabai are required to improve MV system performance. - 7- These developments, together with the 11 kV system improvements recommended, result in loss reduction benefits of 4.2 MW and 19.3 GWh per year at present loading levels. The proposals yield a benefit to cost ratio of approximately 28:1. Reactive compensation of 2.4 MVAr is also recommended for identified low power factor feeders at a cost of $31,170. This investment would be paid back within a period of only one year. As discussed for installations in Nairobi, the capacitors can be transferred to other feeders once suitable system improvements in both network feeding arrangements and consumer characteristics are introduced. Improvements to the LV Networks 19. The performance of a number of LV networks were studied using the specialized LV system software package supplied. These studies indicated an aggregate technical loss (at present loading levels) of 5.4% and 3.6% for power and energy respectively. However, more than 20% of the networks studied showed individual loss values of over 10% for power and 6.9% for energy. Seven of the LV networks were analyzed in further detail to determine improvements that could be carried out to reduce losses to "optimum" levels. A major finding from these studies is that the supply area of existing transformers should be sub-divided to a number of smaller areas, each supplied by a separate distribution transformer. This will entail increasing the number of transformers in the system and reducing the area covered by each unit. Other complementary requirements (new sections, feeders and reconductoring) need also to be integrated into the planned development. Extrapolation of the results of the sample study indicates that investment requirements to optimize system performance for the selected study area (in Nairobi City and the Coastal Area) over the next five years will amount to approximately US$8.5 million. These investments will also cater to the general load growth of both existing and smaller retail consumers in the area (and will exclude system additions required to cater to larger new consumers who need direct supply from dedicated transformers or the MV system). System loss reduction from these proposals would provide a benefit to cost ratio of approximately 9.7:1. 20. The loss levels of KPLC's distribution transformers are higher than economically acceptable, particularly with respect to iron losses. Spreadsheet based methods were developed to compute transformer iron and copper losses at various operating characteristics and to develop appropriate evaluation factors to account for the losses sustained over their operational lifetime. Since poorly utilized transformers can cause energy losses exceeding 5%, a suitable transformer load management program is recommended to be carried out to match unit ratings with the load supplied. Poor transformer utilization was particularly noticed in low load density areas and a pilot study identified possible reduction of energy losses from 2.6% to 0.6%. In order to secure units with better loss performance, KPLC should also include loss evaluation in transformer procurement. Such a program may commence with evaluation factors of US$5000/kW and US$1000/kW for iron and copper losses respectively and after periodic review and better transformer load management in the field, these values should be revised and increased to about US$8000/kW and US$2000/kW respectively. - 8 - Nontechnical Losses 21. Non-technical losses consist of the difference between electricity actually supplied and the amount billed to consumers. They are caused by direct pilferage as well as by errors and imperfections in the metering and billing systems. During the study field tests and energy audits were carried out to detect instances of non-technical losses. As in the other exercises conducted under the study, particular attention was given to the training of KPLC personnel so that such work could be carried out regularly. The results of the sample studies conducted are summarized in the following paragraphs3. 22. Tests carried out on large MV bulk consumer metering yielded an average loss level of 2%. A particularly disturbing feature of the results is that a relatively high proportion of detections was in Mombassa (63%) resulting in a loss of 5.3%. 23. Tests carried out on meter installations at LV bulk consumers resulted in the detection of losses amounting to 4.5%. The analysis of faults detected in this category showed that 39% were caused by meter defects (including defects in the demand meters), 18% from direct tampering, 6% caused by partial metering of consumer supplies, 18% due to faulty or damaged metering transformers (CT's and PT's) and 15% due to faulty wiring. Rectification of the defects detected and charging consumers for past dues are being handled by KPLC's commercial division. 24. An energy audit carried out for LV systems (three retail transformer stations) resulted in the detection of non-technical losses amounting to 7.0%. This determination generally agrees with the random tests carried out on a number of retail consumers which indicated a metering loss of 8%. During the random test, a number of meters were also detected to over read (possibly due to calibration errors) but the margin of error in such instances was substantively lower than that of under reading meters. 25. The investigations carried out indicated that the exception reports (which list instances of suspect consumption) issued by the KPLC billing system are inadequate in many respects. The tests carried out on installations selected from the exceptions report produced less instances of metering errors than those selected at random. Similarly the majority of "dead" accounts (consumer installations which have been reported as disconnected from service and therefore removed from the billing system) consisted of those which have been subsequently reinstated. Hence, substantial modification is required in the preparation of these reports to provide useful assistance in the monitoring of non-technical losses. 3 Losses detected are presented as percentages of consumer billing. -9- Proposals for the Reduction of Non-Technical Losses 26. Sample studies conducted for non-technical losses indicate a billing loss of around 5% for both bulk and retail sales. Accordingly, measures to identify these losses and rectify the defects by using special task forces is recommended. Two separate field teams, one attending to the detection of metering installation defects and the other attending to consumer verification should carry out investigations on a systematic basis covering each area comprehensively before moving to the next. Personnel for this assigmnent should be hand picked and freed from all other duties. The progress of these groups should also be closely monitored by management. Another group should be assigned the responsibility of rectifying the resulting anomalies in the billing system expeditiously. Procedures for carrying out such a non-technical loss detection program are provided in Section 7 (para 7.32). KPLC has already commenced a company wide program for the monitoring of non-technical losses and consideration may be given to incorporation of the above recommendations in this exercise. 27. KPLC's billing system (in use during the study) has outlived both its technical and economic life and needs to be speedily replaced by a more up to date system. At the time of this report (end 1995) a new billing system is being installed and on completion, would redress a number of concerns in this regard. The reconmmendations provided in Section 7 (para 7.33) provide certain key requirements to be addressed when establishing a new billing and meter reading system. Summary of Proposals 28. The system improvement proposals identified in the report are summarized below: uS$o000 1. Nairobi City, MV system 1.1 New 66/11 kV Substation at Kiambu 2,236 1.2 New 66/11 kV Substation at Kileleshwa 2,267 1.3 Reconductoring and New Feeders 595 1.4 Capacitors - (6.7 MVAr) on 11 kV Lines 74 Total for Nairobi 5.172 2. Coastal Area, MV system 2.1 New 132/33 kV Substation at Diani 3,500 2.2 New 132/33 kV Substation at Bamburi 7,990 2.3 New 132/33 kV Substation at Malindi 3,337 2.4 New 33/11 kV Substation at Galu 366 2.5 New 33/11 kV Substation at Rabai 400 2.6 11 kV feeder improvements 224 2.7 Capacitors - (2.4 MVAr) on 11 kV Lines 31 Total for Coastal Area 15 3. LV system improvements 8,500 Total Cost of Proposals, Nairobi and Coastal Areas 29_520 - 10- 29. In view of the substantial financial gains that can be achieved by reduction of non- technical losses proposals are also presented in the report to establish three task forces for meter inspections, consumer verification and rectification of billing anomalies. A new billing and consumer database system in keeping with current developments in this field is also recommended4. Lessons Learned 30. A number of important lessons may be gained from the experiences of the present study. These are elaborated in para 8.1 in Section 8 and may be summarized as follows: 1 . Network loss investigations (both technical and non-technical) provide important information for improving operational efficiencies and yield investments/improvements with high economic and financial returns; 2. These investigations (and related planning tasks) are best coordinated by a separate unit with undivided responsibility for this function. The unit should be supplied with state-of- the-art equipment (computers, advanced hardware such as digitizers, planning software, electronic measuring instruments etc.) to be fully effective; 3. System improvements in loss reduction often yield high benefits even when treated in isolation. However, in order to avoid sub-optimal solutions a systemic concept should be adopted, accounting also for benefits of improving network reliability and ability to satisfy future load growth. The analysis and ranking of a number of alternative development proposals on the basis of all such benefits form the best method of determining optimum investment; 4. The sequence of network developments to be considered in a planning exercise varies for long term and short ternm options. A convenient sequence of examining long term developments is to follow the hierarchy of the power flow, investigating suitable investments required at each stage. Accordingly, the following sequence of network improvements is an useful guide in carrying out a long term system development study: MV systems - (a) introducing new substations; (b) introducing new feeders; (c) rationalizing feeding arrangements; (e) reconductoring line sections; (f) reactive compensation by capacitors installations; 4 KPLC is already carrying out some of these recommendations (see para 7.34). - 11 - LV systems - (a) decentralization of networks by installing larger numbers of transformers and smaller secondaries; (b) rationalization of feeding arrangements; (c) reconductoring line sections; and (d) phase balancing; 5. When planning for short term benefits, it is advantageous to consider the above sequence in reverse. Phase balancing (in LV networks) and reactive compensation followed by network rationalization are likely to provide the fastest returns. Short term improvements should also be suitably coordinated with long term system development plans. In many developing countries the short term options are particularly important in view of the long lead time required for financing large investments. Furthermore, short term solutions such as phase balancing and network rationalization are fully complementary with the long term solutions. Benefits of other short term investments such as reactive compensation, can also be extended by shifting the equipment to other locations. -12- 1. INTRODUCTION Background 1.1 The Republic of Kenya is situated on the east coast of Africa bordered on the north by Ethiopia and Sudan, on the west by Uganda, on the south by Tanzania and on the east by Somalia and the Indian Ocean. The country covers 582,646 sq. km. but about two thirds of this area especially towards the north is arid. The bulk of the population is therefore concentrated in and around Nairobi and the adjacent highlands, and in the east coast close to Mombasa. 1.2 Agriculture and tourism constitute the main economic activities in the country. Other important sectors of the economy are also based on these two activities, in particular, the industrial sector is heavily dominated by agricultural product processing. The gross per capita national product was approximately US$260 in 1994 and the per capita electricity consumption stood at 110 kWh. Power Sector Organization 1.3 The installed generating capacity in 1992 amounted to 788 MW composed of 598 MW of hydro power, 145 MW thermal and gas turbine (GT) and 45 MW geothermal. Although 30 MW of imports are possible from the Ugandan Electricity Board (UEB) this supply is not normally available during system peak and the available capacity may be treated as 788 MW. All major generating plants are owned by a number of government owned companies: Kenya Power Company (KPC), Tana River Development Company (TRDC), Tana and Athi River Development Authority (TARDA) and Kerio Valley Development Authority (KVDA). A geographical representation of the Kenyan power system is shown in Map IBRD 26458 and a single line diagram of the transmission network shown in IBRD Map 26461. 1.4 The Kenya Power and Lighting Company (KPLC) operates and maintains all power plants of the generating companies (through management agreements) and also possesses some generating plant of their own. In addition, KPLC owns and operates most of the transmission and distribution networks. KPLC has been established under the Companies Ordinance (with private shares of approximately 40%) but is in effect substantially controlled by the Government of Kenya. Consumption Characteristics and Future Projections 1.5 KPLC's distribution operation is decentralized to six regional units called 'Areas'. Map IBRD 26458 indicates the demarcation of the Area boundaries and the areas presently - 13 - electrified. Total sales for the year 1991/92 (during which the study was made) were 2,846 GWh, of which 52% was consumed in the Nairobi Area and 23% in the Coastal Area (around Mombasa). The balance (25%) was shared between West Kenya (10%), Central Rift Area (6%), North Rift Area (5.2%) and Mount Kenya (4.6%). 1.6 The high growth rates experienced in the 1980's suffered a setback over the last few years partly due to power rationing necessitated by shortage of generation capacity. Exceptionally low rainfall also contributed substantially to the reduction of available capacity. In the four years up to 1990/91 the annual energy demand grew at an average rate of 6.9% while the increase recorded from 1990/91 to 1992/93 averaged to 4.3%. Thereafter the growth reduced further to around 3%. Apart from the loss of sales due to load shedding the reduction in growth rate was influenced by stagnation in the demand of industrial and large commercial installations. In contrast, the domestic and small commercial sector recorded a steady growth rate averaging to about 6% over the last five years. The projected growth rate over the next 14 years approximates to 5.6% p.a. and the generation developments envisaged by KPLC up to 2010 comprise 370 MW of geothermal, 250 MW of conventional thermal, 240 MW of hydro and 150 MW of medium speed diesel plant. 1.7 The expected new geothermal plant will be located close to the existing fields in Olkaria (near Naivasha) and the majority of the remaining thermal additions at Mombasa. In view of the long distance of the load center at Mombasa from the indigenous energy resources (hydro and geothermal), the main future transmission improvement will consist of extending the 220 kV system to Mombasa. The western transmission system also needs to be augmented by an extension of the 220 kV network. The Study 1.8 Power system energy losses varied between 14.5 and 15.5% (of net generation) over the last five years, figures which are not considered high among developing country utilities. However, the present power shortages underscore the high economic value that needs to be placed on power and energy losses. In the short term when capacity improvement is not possible the economic value of denied consumption is many times the cost of production. In the longer term too, the value attributable to power and energy losses is relatively high as gas turbines with high operating costs would carry the main burden of marginal consumption. Arrangements were therefore made with the World Bank-UTNDP sponsored Energy Sector Management Assistance Program (ESMAP) to provide assistance in developing a power system loss reduction program in KPLC. In view of the studies already conducted on the transmission system by KPLC's consultants, only improvements to the distribution system were addressed in the present study. The study was also restricted to certain networks in Nairobi City and the Coastal Area. KPLC is expected to continue the activities commenced, complete studies for each of the remaining distribution systems in the country and also arrange a program for the continued monitoring of distribution system performance. Financial support for the project was obtained - 14 - from the Swedish International Development Agency (SIDA) and the study was launched in October, 1991. The installation of the computer systems and initial training of counterpart staff was carried out through end 1991 and beginning of 1992 and the collection of network data and system analysis was mainly undertaken during 1992 and early 1993. It may be noted that due to the continuous changes being made in distribution systems, details of individual networks studied may not be up to date in certain respects. Since counterpart staff of KPLC has been trained in the techniques of computerized distribution planning and the analysis software and data base has already been established, the changes to the networks and continuation of the studies can be carried out by KPLC staff. Study Objectives 1.9 The study seeks to assist KPLC in developing an effective program to reduce distribution system losses. Major objectives relates to the transfer of technology currently used by advanced power utilities and in developing specific proposals for both technical and non- technical loss reduction. The specific objectives of the study may be summed up as follows: (a) to identify the main sources of technical and non-technical losses and develop reliable estimates of the contribution of each of these to overall losses; (b) to introduce state-of-the-art techniques of data collection and distribution system planning to KPLC and enable continuity of such applications; (c) to commence the development of a reliable distribution system database to be of continuing use in distribution planning and related work, (d) development of specific proposals for Nairobi city and the Coastal Area to reduce technical losses to economic levels; and (e) estimation of the incidence of non-technical losses and introduction of procedures to detect and rectify such instances. 1.10 The study, supervised by World Bank staff, was conducted through a special unit established in KPLC to collect and document the distribution system data and thereafter undertake the required analyses. Five engineers and two technical assistants were assigned on a fuill time basis and additional support such as drafting services were also arranged as required. Consultancy support for the study unit was arranged by engaging IVO International of Finland who provided a distribution consultant for 6 months and a conmmercial consultant for a period of 3 weeks. Staff of the World Bank operating under ESMAP, provided technical guidance and directed the studies. Two software packages were employed in the technical analysis; LOWO, a program obtained from Messrs. IVO International and DPA(G)/DIG a package purchased from Messrs. Scott & Scott of U.S.A. The KPLC counterpart staff assigned to the study unit performed extremely well in mastering the new techniques and conducting the required field - 15 - work. Much of the credit for the successful implementation of the project is therefore due to the participating KPLC personnel. The competence achieved by the study unit can be gauged from the fact that personnel from the unit were employed to train staff of other power utilities on two separate occasions during the study. In a similar project organized by ESMAP for the Ministry of Water Resources in the Republic of China personnel from the study unit undertook the digitizing of distribution networks and training counterpart staff from China to carry out this work. In another assignment the unit provided support to the Rural Electrification Board of Bangladesh to carry out field measurements using the microprocessor based measuring instruments obtained during the present study. Utility personnel from both Bangladesh and Nepal visited the KPLC study unit for a period of one month in August 1994 and were trained in the use of the analytical software. 1.11 The study unit which was first formed by personnel seconded from various operational units, was subsequently established as a regular division within the Corporate Planning Department. Such institutionalizing of the distribution planning function is essential to build up the data base and establish a continuity of the loss monitoring and planning tasks. The competence of the KPLC staff and the training received (including exposure to the distribution systems of other developing countries) augurs well for KPLC's continued efforts at reducing distribution system losses to economically acceptable levels. -16- II. ANALYSIS OF SYSTEM LOSSES 2.1 Power system losses may broadly be classified to two categories; technical losses, resulting from the electrical characteristics of the network and non-technical losses, being the difference between units actually consumed and that billed for. Technical losses for individual power lines and consequently for an overall network can be calculated if the relevant physical and electrical characteristics are known. Such computations are conveniently made for transmission systems as they have a limited number of 'buses' or nodes (connected by line sections or segments) and can therefore be represented accurately and in required detail by theoretical models. Thus analytical software has been in use by system planners for many years in studying transmission systems. In distribution systems however, the networks are extensively spread out and contain a large number of consumer connections dispersed over the supply lines. The detailed representation of these systems is therefore not practicable leading to the use of approximate modeling techniques in order to facilitate the computation of power flow characteristics. The development of computer technology in recent years, particularly the widespread use of personal computers, has led to the availability of a number of software programs capable of analyzing distribution systems. The present study applied a number of such techniques, further explained in Section 3. The results of the studies carried out on medium voltage (33 and 11 kV) systems are presented in Sections 4 and 5 and for the low voltage (240/415 volt) system in Section 6. The result of these studies are combined with computations for the transmission system in this section to provide an analysis of the overall system losses. 2.2 Non-technical losses result from power theft, metering deficiencies and errors in the meter reading and billing process. An estimation of such losses may be made by carrying out energy audits as well as by investigations of metering installations and billing records. Section 7 describes the procedures used and the results of the non-technical loss investigations. These losses can also be determined by measuring the overall system losses and subtracting the technical losses attributable to the network considered. 2.3 Losses are also expressed in terms of both power and energy supplied. Power losses (expressed in kW or MW) occur at a given instant and depend on the network flow at that time. Usually5 the maximum power loss occurs at peak demand and for this reason losses are normally calculated for this time (a distinction being made between peak load of a feeder and the system peak, which may not be coincident). Energy losses (expressed in KWh or GWh) consist of the integrated power losses occurring over a given period, usually a year. The energy losses are therefore dependent on the loss levels at different times as expressed by the loss duration curve. Although losses are more often expressed in energy terms it is important to bear in mind that in the context of system operations, peak power losses are important as they represent the period during which the network is at maximum stress. In some transmission systems the power losses at system peak can be lower than at certain other times due to increased generation at load centers at this time. - 17- Transmission System Losses 2.4 Electric power is produced at generators located in the power stations and then supplied via the transmission and distribution systems to the ultimate consumers. Some losses are incurred before the generated power can be supplied to the transmission network, mainly due to the consumption of auxiliary equipment within the power stations. Power that is ultimately supplied to the transmission system is termed 'net generation'. Metering instruments are provided at each power station to record the output of each generation unit, the totals aggregating to gross energy produced. The transmission lines carrying the generated power out of the stations are also metered. The difference between the above sets of readings will correspond to auxiliary consumption which is considered as the station loss. The overall transmission system energy loss can be determined by deducting the energy supplied at the grid substations (the interface between the transmission and distribution systems) from net generation. The computation for the KPLC system for the year 1991/92 is provided in Table 2.1 below: Table 2.1: Transmission System (Energy) Losses (1991192) Gross annual energy generated = 3,385.3 GWh Auxiliary consumption (station losses) = 32.7 GWh = )0.97% gross generation Net energy generated = 3,352.6 GWh Energy delivered at Grid substations6 = 3,201.5 GWh Transmission Losses (energy) = 151.1 GWh 4.51% net generation 2.5 The above computation is for energy losses occurring over a period of one year. As explained in para 2.3 the percentage losses at system peak would be different. Usually the power losses (expressed as a percentage) reaches a maximum at system peak. In KPLC's transmission system, however, this need not be the case as increased thermal generation provided close to the load centers (specially at Mombasa and Nairobi) during peak has the effect of reducing the flow on the transmission network. Further, a substantial component of the transmission losses occurs in the 132 kV section between Juja and Tororo and this is dependent on the generation at Turkwel as well as imports from Uganda. Thus at some times of the day transmission system power losses could exceed those experienced at system peak. The performance of the transmission network has been studied by KPLC's Consultants who have analyzed network power flows over a number of operating conditions. It is expected that peak power losses would vary in the region of 4% to 6% (depending on operating conditions). The data on station auxiliary consumption and transmission losses is presented in this report in order 6 Includes energy delivered at power stations supplying directly to the distribution system (eg: at Kipevu); the station losses of such plant being also added to the overall auxiliary consumption. Losses in the 66 kV network feeding Nairobi Area is taken as part of the distribution system. - 18- to present a picture of the overall system losses. The main objective of the present study, however, is the analysis of losses in the distribution system which is discussed in the paras and Sections to follow. Overall Distribution System Losses 2.6 The power supply in Kenya is divided into six operational Areas: Nairobi, Coastal, West Kenya, Mt. Kenya, Central Rift and North Rift, as shown in map IBRD 26458. The Nairobi Area accounts for over half -and the Coastal Area for about 20% of the total energy supplied. The overall distribution system energy losses (including both technical and non technical losses) of each Area has been computed by comparison of the sales with the supply received from grid substations (and local generation where relevant) for the year 1991/92 and is presented in Table 2.2 below7. Table 2.2: Summary of Distribution Losses (Energy) by Areas (199111992) Received at Sales Losses Losses Area Grid SS (GWh) (GVVh) (GWh) % Nairobi 1,674.0 1,486.6 187.4 11.2 Coastal 723.2 619.6 103.6 14.3 West Kenya 316.3 292.9 23.4 7.4 Mt. Kenya 149.1 125.2 23.9 16.0 Central Rift 191.4 179.0 12.4 6.5 North Rift 147.5 142.8 4.8 3.2 Total 3,201.5 2,846.1 355.5 11.1 2.7 A key source of data for the computations in Tables 2.1 (for transmission losses) and 2.2 (for distribution losses) is the records maintained at each grid substation on the monthly supplies injected to the distribution network from the step down transformers (i.e. the interface between the transmission and distribution systems). Since the readings of the energy meters at the power stations and grid substations are regularly taken on the hour, a consistent set of data is expected for transmission losses; any variation in the loss values corresponding to changes in the generation pattern. With respect to distribution losses however, the same consistency is not expected as consumers' meter readings are not coincident with the system metering. A number of validation checks were carried out to verify the related meter readings (particularly at the grid substations) and some of the records have been adjusted when errors were detected. It is recommended that a monthly analysis of the system losses be carried out using the system metering data compiled by KPLC's system control center, inclusive of the breakdown of losses to 7 Only a negligible transfer of power occurs between the individual Areas (adjustments were made to transfers from West Kenya to North Rift-a connected load of about 1.4 MVA). - 19- supply Areas (distribution system) and individual sections of the transmission network on the lines of exercises carried out during the study. Correction of any anomalies in the meter readings is feasible if the exercise is carried out in a timely manner. Furtherinore, such an analysis will greatly assist KPLC's on-going program of the control of system losses. 2.8 The overall distribution system energy losses amounted to 1 1. 1% while that of the Nairobi and Coastal Areas (as a percentage of individual inputs) were 11.2% and 14.3% respectively. Being measured quantities these values include both technical and non-technical losses. Although loss values shown above are not too excessive in comparison to those in many developing countries they are high compared to economically attainable levels which would be of the order of 5% (some variation is expected depending on the nature and dispersion of the load supplied). 2.9 Aggregate loss values provide a general guidance on the technical appropriateness and operating efficiency of a distribution system. However, aggregate values often mask many instances of poor performance. If the majority of the load flows through relatively well performing feeders or are located very close to grid substations, the impact of a number of uneconomically high loss feeders in the system may not be substantial. The study of the Coastal Area (Section 5) presents a particularly interesting exarnple of such a situation. The Mombasa Island load together with the direct supply to the petroleum refinery (close to the grid substation at Kipevu) accounts for 49% of the Area load. Due to the short feeders involved, technical losses of the related medium voltage distribution system (33 and 11 kV network) is only 1.1%. The rest of the system (supplying the peripheral areas --Diani, Malindi etc.) account for the remaining 51% of the Coastal Area load and the combined medium voltage distribution system losses for this section have been calculated to be 7.4% (with the losses in the 33 kV network being 5.8%). The overall technical losses of the MV system in the Coastal Area will therefore record an energy loss of 4.3%, masking the heavy losses occurring in the peripheral areas (which accounts for half the overall load). The wide disparity of loss levels is even more evident if individual feeders are examined. Thus in distribution system network analysis it is important to target attention to feeders and sections of the network with poor performance rather than at overall aggregate loss values. 2.10 Sections 4 and 5 of the report present a detailed analysis of the MV distribution systems of Nairobi and Coastal Areas and identify improvements required to bring the networks to acceptable economic levels. The analysis of the LV system and a recommended strategy for its improvement are dealt with in Section 6. In addition, an examination was also made of some feeders outside the selected study area where high loss feeders could be identified. The results of this analysis are presented in Section A1.2 of the Annex where feeder (technical) losses as high as 15 to 30% have been calculated. KPLC should undertake detailed system studies for networks associated with these feeders and prepare system development proposals as carried out in Sections 4 and 5 (for Nairobi and Mombasa Areas). - 20 - Analysis of Losses by Voltage Level 2.11 A power flow and network (technical) loss contribution by voltage level is presented in Tables A1.1.1 to 1.1.3 of the Annex by using (a) percentage losses determined for network components and (b) system loads at each voltage level. The sales made and losses incurred at each voltage level are deducted from the input at each level to determine the flow to the next level and the process continued until the remaining balance is consumed at the low voltage level. Network flows for both (peak) power and annual energy are presented in three tables for, Nairobi City, Coastal Area and the entire distribution system. While typical values were used for transformer losses, weighted average of loss rates (calculated for each voltage level) in the two study areas were used for the overall distribution system. Unlike the case of energy sales, consumer peak demands at each voltage level is not available as only few supplies are measured for power demand and even so such measurement is not made specifically at system peak. Thus, estimated aggregate load factors and peak contribution factors have been used in the tables 'to compute the power demand at each voltage level. Table A1.1.3 also combines the distribution system losses with those of the transmission system to complete the picture for the whole system. 2.12 Non-technical energy losses may be determined by deducting the calculated technical values in Tables Al 1.1 to Al.1.3 in the Annex from the measured values in Table 2.2. Very little information is available to predict the incidence of non-technical losses at system peak. It may however, be safely assumed that the non-technical losses will follow' the pattern of recorded consumption. Thus most non-technical losses from day time industrial consumers are expected off-peak while most losses from domestic consumers are expected during system peak. A reasonable estimation would be to use the ratio (power losses to energy losses) obtained for technical losses to convert non-technical energy losses to non-technical power losses. On the basis of this estimation Tables Al.l.l to A1.1.3 also indicate estimated values for non-technical power losses and consequently for the total estimated power losses. In view of the level of uncertainty regards the incidence of non-technical power losses we would expect the true values to be within +/- 2 percentage points of the computed figure. 2.13 A summary of the loss values (as components of the distribution system as well as overall aggregate values) computed in Tables A1.1.1 to A1.1.3 of the Annex is presented in Table 2.3. It is found that technical energy losses account for 10.8% of net generation --4.5% in the transmission system and 6.3% in the distribution system. The overall system energy loss for 1991/92 was 15.2% which indicates that the non-technical losses amount to about 4.4%. Technical power losses (at system peak) for the transmission and distribution systems are of the order of 5.5% and 11.3% respectively and the non-technical loss estimated at 7.9% indicating an overall power loss of the order of 25%. The above figures indicate that while KPLC's loss levels do not appear to be excessive by the standards of many developing countries there is still considerable room for efficiency gains from the reduction of both technical and non-technical losses. In the context of capacity shortages expected to continue for some time, the reduction of peak power losses will, in particular prove to be of considerable economic value. It should be noted that the loss figures provided in this analysis are on the basis of the limited samples studied - 21 - and approximations deemed relevant. KPLC should continue the exercise of refining the analysis of system losses by (i) increasing the number of networks analyzed (particularly for LV systems), (ii) undertaking similar exercises for other Areas, (iii) validating the data recorded at grid substations, and (iv) improving the accuracy of estimated factors (such as peak contribution, incidence of non-technical losses etc.) Table 2.3: Losses in Distribution System Components As % of As % of input to Component Input Distribution System Power Energy Power Energy Grid SS transformers 1.00 0.80 I 1.00 0.80 MV Lines 5.06 3.45 I 4.92 3.24 LV transformers 1.10 0.70 j 0.95 0.48 LV direct lines 1.00 0.50 0.86 0.34 LV retail lines 5.40 3.60 I 4.21 1.72 Distribution system technical loss 11.95 6.59 Distribution system non-technical loss 8.17 4.51 Total distribution system loss 20.12 11.10 Summary of Network Losses (Based on Net Generation) Power (%) Energy (%) Transmission system losses 5.5 4.5 Distribution system losses 11.3 6.3 Non-technical losses 7.9 (6 to 10%) 4.4 Total System losses 24.7 (23 to 27%) 15.2 - 22 - III. STUDY METHODOLOGY AND SYSTEM CHARACTERISTICS Background 3.1 Distribution systems spread out over wide geographic areas and are composed of numerous line segments with varying characteristics. Analyzing the power flow in a distribution system is therefore numerically complex and requires the collection of an extensive amount of data. The complexity of the data requirements is particularly significant in comparison to transmission networks which only require information of loads at a limited number of grid substations and the characteristics of the lines interconnecting these stations. In modeling distribution systems however, even the network of one city will contain segments (sections of feeders and distributors) many times more than that required for a typical transmission system. Network models need to be built up with the electrical characteristics of each segment, details of connected equipment (transformers, switching/isolating positions) and the loads supplied at various points of the system. Another important characteristic of distribution systems is the frequent changes which occur to the network data (again unlike transmission systems) with new extensions, additional consumers etc. being a regular feature. Thus the establishment and maintenance of a data base for distribution systems is both voluminous and time consuming. 3.2 Maintaining geographic network drawings is an essential feature of distribution system planning. Prior to the use of computerized planning techniques utilities maintained drawings of line routes on area maps of suitable scale or on transparencies which can be overlaid on such maps'. There were many difficulties in maintaining such systems in an up-to-date and useful manner. Entire maps have to be redone following a few network alterations or changes to the base land maps --activities which are quite routine in distribution systems and urban development. To retain useful information a number of maps of varying scales are necessary creating problems in both documentation and retrieval of information. Survey maps are usually prepared according to a standard geographic grid, while information required for system planning purposes often requires a combination of many such maps, such combinations varying according to the system studied. In view of these difficulties, maintaining the distribution system data in hard copy geographic maps proved to be cumbersome and tedious. Accordingly, many utilities failed to retain the documentation up-to-date. Even when the maps were maintained fairly accurately, the planning process using these maps was in itself quite tedious. For these reasons the design of distribution systems was usually dependent on the judgment of field personnel subject to certain general guidelines and rules of practice developed with past experience. Techniques were not readily available to verify these guidelines or update them with respect to changing circumstances such as the increasing cost of power supply. Furthermore, alternative development options could not be evaluated with any reasonable degree of accuracy. 8 The latter method is more advantageous as updated geographic maps could be used with network drawings on the ransparencies. - 23 - 3.3 With recent advancements in computerized techniques, particularly the storage and retrieval of information using digital technology (e.g. by use of mapping software), many utilities are now computerizing their distribution system data bases. Computation of power flow characteristics are facilitated by specialized software. The improvement of the quality of the data base and analysis tools have allowed network planners to undertake more detailed technical studies. In particular, network performance can now be examined for alternative developments and future performance of planned systems can be predicted with greater accuracy. Currently a number of vendors market software with many user friendly features to establish computerized data bases and undertake load flow and other related technical studies. These developments have resulted in a fundamental change in the techniques available for distribution system analysis. Utilities can now maintain a data base with complete flexibility in updating network changes as well as retrieval of information for planning (and operational) purposes. Thus, an important objective of the present study was to transfer this new technology to KPLC and upgrade distribution system studies in keeping with the current state-of-the-art. ESMAP experience elsewhere indicates that such technological improvements in planning departments have numerous benefits which include greater motivation and job satisfaction among parastatal employees in developing countries. Accordingly these developments have been found to be sustainable and conducive to greater ownership of system expansion/improvement plans (which is often not the case when these plans are developed by external consultants). Establishing a Computerized Distribution Planning Unit 3.4 The establishment of a computerized distribution planning facility involves the following activities: (a) network data collection, validation and documentation; (b) determination of load data at important network points such as medium voltage (33 and 11 kV) feeders and transformers; (c) computerizing the data base using the selected software; (d) analysis of existing feeder performance (for both present and future loads) and identification of system weaknesses; and (e) study of alternative development proposals and their economic analysis. 3.5 The network data collection phase commenced with the collection of all available network drawings, maps and completion reports of construction activities. Thereafter an extensive survey of each area to be studied was conducted and information collected on network particulars such as conductor size, connected transformers as well as important consumer characteristics. The existing network diagrams were then modified to reflect the current situation and the information compiled on geographic maps. MV network data was entered using 1:5000 and where required 1:2500 scale maps. For the LV networks, maps of 1:2500 scale were found - 24 - to be necessary to obtain an accurate representation. The external consultant from IVO International supervised this process and introduced systematic procedures to enable the work to be carried out methodically. Load Measurements 3.6 Load data of key network components are usually scarce in many developing country utilities. A number of recording instruments were obtained to address this deficiency. Many of these instruments were microprocessor controlled, enabling the measurement and storage of the required parameters at preset intervals without user intervention. The stored data could subsequently be retrieved by a computer and analyzed either using firnware supplied or by conversion to standard spreadsheet programs. To measure changed loading profile of a feeder or transformer, two sets of instruments, the Load Logger and Load Profiler from Rochester Instruments were used. The load logger can be used on overhead lines (up to 69kV) using a hot- stick to fix the instrument to the line conductor. The Load Profiler is mainly for indoor use and can be used on lines up to 600 V. Measurement intervals of 1, 15 or 30 minutes can be selected in both instruments. The software provided can plot the load readings in graphical form or convert this data to spreadsheet format enabling further calculations to be performed. Since the computations are usually repetitive in nature, a set of "macros" was designed to obtain important system characteristics such as: load factor; loss factor; utilization time of losses; maximum, minimum and average loads and their times of occurrence; and peak contribution factors (for both day and night peaks)9 3.7 A couple of other instruments (also employing microprocessors and analysis software) were also employed to obtain an even wider range of parameters; these being, the Dranetz Logger from Dranetz Technologies (USA), Rustrak Load Logger from Rustrak Instruments (USA) and NEM Monitor from Electricity Data Services (UK). These instruments measure both the voltage and current characteristics and consequently provide additional information on power factor, reactive and active power (and energy, over a given period). The software provided also enables the presentation of a variety of graphs on the measured parameters. The data collected from these instruments can also be retrieved as spreadsheets to carry out further analysis of the data where required. Distribution Planning Software 3.8 Two software packages were used to establish the data base and undertake the required analyses. The LV study package, LOWO was supplied by IVO International of Finland and MV networks were studied using DPA(G)/DIG supplied by Messrs. Scott & Scott of USA. In both programs network data is compiled in digital format using a digitizer. This instrument simplifies the otherwise tedious data entry process and enables the data base to be established in 9 See Annex A for definition of terms. - 25 - a relatively short time. Network data is entered by tracing the power lines with an electronic lover' a geographic map placed on the digitizer board. A set of pull-down menus is used to supply data concerning the electrical characteristics of the network sections. The data entered consist of conductor size, phasing arrangement, load data and information on connected equipment such as transformers. In addition to the electrical characteristics geographic information such as roads, key physical features etc. are also entered in background 'layers'. The analysis programs are capable of extrapolating network loads over future years (given the growth rates to be used in each section) and load flow runs can be performed for any given switching configuration and year of study. The load flow runs provide details of the electrical characteristics (such as active and reactive power carried, voltage level and losses) in all component sections of the network. 3.9 The LOWO programn used for LV-studies includes a number of optimization facilities that enables the program to select the most economic network configuration under certain defined conditions. Development alternatives such as new transformer locations and line sections can be identified and the program carries out a sequence of runs for all possible network alternatives (with the existing system and identified possible new additions); checking for adherence to technical requirements specified and computing the losses and investment costs for each alternative. The optimum system development and network configuration is then identified by the program. However, experience gained during the studies indicate that some limitations need to be imposed in applying the results of the optimization program. The main difficulty relates to the representation of network loads over time. Section loads, particularly in LV networks, do not grow at a constant rate in all sections. While the growth rate applicable to a given area or region can be forecast with a fair degree of accuracy (and may even be represented by a constant factor over many years), the incidence of such growth is not uniformly distributed over individual network sections. In fact, most load additions of future years occur in sections which are initially poorly loaded. Thus when LV systems are modeled, new loads should often be imposed on sections that had little or no load in previous years, usually representing vacant blocks of land. Further, each section reaches a saturation level at a rate substantially in variance with that of the entire area or region. In view of such limitations the optimization facilities of the program were used only where applicable such as in determining the best possible network switching configuration for a fixed loading condition. This example underscores the importance of validating the assumptions used in computerized modelling and optimization exercises and such considerations were given careful attention during the study as well as in the training provided to KPLC counterparts. 3.10 The difficulties discussed above are particularly relevant to the study of LV systems where presently available software does not provide adequate techniques to establish reliable load models for the individual network sections. The load data of the present system was based on the service connections provided to existing consumers and the apportioning of the overall load to the individual sections presented little difficulty. In order to obtain reliable results for the system expansion and optimization exercise, the loads expected in future years need to be allocated among individual network sections in a realistic manner. This was accomplished by - 26 - site investigations to determine the possibilities for load increase in each section. Thus, sections representing vacant blocks suitable for buildings were assigned higher load additions and those representing unusable land given no increase at all. Sections representing allotments already built-up were given marginal increases commensurate with the growth rate expected for existing consumers. In the LV network study such load models were built for three time periods representing 0-5 years, 5-10 years and 10-15 years. Although this method is time consuming it provides a more realistic estimation of the actual conditions that could be expected in the future. The study also confirmed that the accuracy of load estimation on a spatial basis is important and that different load distribution patterns yield varying development scenarios. 3.11 With respect to the MV network studies the spatial variation of load growth has less influence on the final development proposals. However, particular attention is required in sections containing certain large loads (such as major industrial consumers). This aspect was addressed by the ability of the program to model two types of loads in each section --spot loads and variable loads. Suitable combinations of the two load types were used to ensure that the load model reasonably represents the expected future conditions. 3.12 Once network and load models are established the operating performance is examined by load flow studies carried out on a feeder by feeder basis. Important information to be gained by these studies are the system losses (both for the overall feeder and for the high loss sections) and the voltage drops experienced (particularly at the peripheral locations). Once the operational performance of the networks (at present and expected future loading conditions) are known, proposals to reduce such losses are designed and analyzed. A key feature in improving distribution planning techniques is the preparation of a number of alternative development proposals for each area needing improvement. The options available are then subjected to economic analyses to determine the viability of each development alternative. Economic Analysis 3.13 Quantifiable economic benefits attributable to network development mainly consist of: (a) system loss reduction; (b) improvement of network reliability; and (c) ability to service new loads. Benefits such as improved quality of supply (mainly acceptable voltage level and reduced fluctuations) are more difficult to quantify in the absence of reliable consumer surveys that enable the determination of the willingness to pay for such qualitative improvements. Such benefits have therefore not been accounted for in the analysis. 3.14 The benefits of category (a), system loss reduction have been computed using the software provided and is therefore reasonably accurate. Benefits of category (b), improved - 27 - system reliability results mainly from the ability to feed a given section or area of the network from more than one supply source. This flexibility allows alternative feeding arrangements to be made in the event of the failure of a particular network component. Reducing feeder lengths also improves reliability by restricting the area affected by a failure of a network component. The estirnated reduction in outages resulting from the network improvement is valued in order to quantify the benefits of category (b) --reliability improvements. The saved outages (in kWh/annum) are usually detemlined by estimating the expected reduction of the number of outages per year combined with the average duration per outage. Determination of the economic value of losses caused by power outages was beyond the scope of the study and in the absence of specific studies carried out for Kenya, the value of saved outages has been taken as five times'° the LRMC of energy costs (applicable at the particular network voltage). Benefits of category (c), the ability to supply new loads has been included when technical limitations of the distribution network impose a restriction on new connections. The economic value of supplying such additional loads vary according to the applicable time frame. In the immediate term, such costs could even reach the value of outages while over the medium term they would be dependent on available alternate supply sources such as captive generation. In the longer term the costs may be considered to approximate to LRMC"'. In the present analysis, the additional load that can be supplied (due to new capacity provided) over and above the limitations imposed by the network as presently constituted has been computed for each year of the analysis period using a spreadsheet (deducting the difference between the projected load demand and existing capacity when the former exceeds the latter). The additional energy served over the entire period by the improved system is then valued at LRMC of energy. Since the ability to serve new loads (including both the short and long term) has been valued at LRMC, and since the LRMC value is only that of energy (the total costs of new supplies being composed of capacity and energy components), the technique used is considered to be conservative in spite of the fact that some operational savings exist in not meeting the additional load. 3.15 In order to make the complex stream of benefits manageable for computation, the benefits are first evaluated for a particular year (often the beginning of the analysis period or related sub-periods). Thereafter, multiplication factors have been established to convert the benefits of the beginning year to the present worth of the overall period (or sub-period) of analysis. Economic benefits of network developments generally increase with time due to increase of system load. Loss reduction benefits in particular, increase at a rate much higher than the load growth rate. This is due to the fact that conductor losses are proportional to the square of the load resulting in a growth rate for loss reduction benefits equal to the square of the load growth rate. For the other two categories, growth rates of benefits may usually be taken as the load growth rate, subject to the constraint that the benefits should remain applicable over the period of analysis (in some instances the increased load in future years may set a limit to the 10 Studies carried out elsewhere suggest values in the range of 5 to 15 times LRMC. l It is assumed that all other upstream investment required to meet the new loads are available (i.e. there are no system wide power shortages or transmission constraints). Further any operational savings due to not meeting the new loads are also disregarded. - 28 - continuing increase of these benefits, and care should be exercised in limiting the extension of benefits over such periods). For each category of benefits, the growth rates can be adjusted by the annual discount factor to arrive at a stream of present worth benefits. Alternatively, a single multiplying factor can be used to convert benefits of the current year to the present worth over a period of analysis (provided that the annual growth of benefits remain constant). Tables A1.6.1 and A1.6.2 in the Annex provide such multiplying factors for varying load growth and discount rates. 3.16 The unit rates assigned to power and energy losses have been obtained from a LRMC study carried out by Acres International in 1991. While the ESMAP study was in progress a new study was also carried out by London Economics which provided values close to those determined by the earlier study. These rates together with the values used for reliability and additional capacity benefits are presented in Table 3.1 below. The economic analysis was carried out over 10 and 15 year periods, residual values being assigned to account for remaining lifetime of the investments. Economic life assigned to various investments were: 30 years for grid substations (132 kV or 66 kV), 20 years for primary substations (33/11 kV), and 15 years for new lines and reconductoring. 3.17 As described in the previous paragraphs the economic benefits of loss reduction, reliability improvement and additional capacity have been computed on the basis of available information. Only the LRMC (appropriate for loss reduction benefits) are based on recent studies applicable for KPLC. Costs used for the other two items are considered to be conservative. In order to improve the accuracy of system development studies KPLC should carry out the required consumer surveys and field studies to improve information on these economic parameters. Table 3.1: Unit Rates for Computation of Benefits For loss reduction benefits: (a) Peak power losses (capital cost per year): at medium voltage (MV) - $ 217/kW at low voltage (LV) - $ 358/kW (b) Energy losses: at medium voltage (MV) - $ 0.068/kWh at low voltage (LV) - $ 0.098/kWh For reliability benefits: Estimated outage savings: at medium voltage (MV) - $ 0.34/kWh at low voltage (LV) - not evaluated For new capacity benefits: Additional energy supplied: at medium voltage (MV) - $ 0.068/kWh at low voltage (LV) - $ 0.098/kWh - 29- System Characteristics 3.18 In order to obtain the system characteristics required for the study a large amount of network data has been compiled and analyzed. Such data is also valuable for numerous other studies. Load curves obtained provide a good indication of the consumption characteristics of consumer categories or supply areas. Network loads when converted to information such as load density (kW/km.sq.) provide valuable information for load forecasting purposes. The loading density information is also a good index of comparison of the different supply areas for various planning characteristics. The data gathered during the non-technical loss study also provided valuable information on consumption patterns of different types of consumers. During the latter exercise numerous instances of low power factor loads were also detected and action taken to enforce penal tariff charges. While the study was in progress, information collected on network losses and consumer characteristics were used by KPLC's Consultants (London Economics) in carrying out a tariff study. The information gathered is thus extremely valuable for key functional areas including, distribution planning, operational planning, load forecasting and tariff formulation. Hence, the network and consumer data collected should be suitably compiled and supplemented regularly. The planning cell established during the study is quite capable of continuing these tasks and should be encouraged to carry out the activities commenced on a continuing basis. 3.19 A sample of the information gathered is presented in the tables and figures of the Annex and contain information for both feeders and consumers on: * daily load curves * load duration curves * load and loss factors * peak responsibility factors * load density * power factor at day and night peak - 30- IV. MEDIUM VOLTAGE SYSTEM IMPROVEMENT FOR NAIROBI CITY Overall Supply Arrangements 4.1 Maps IBRD 26459 and 26460 shows the important features of the supply system for the Nairobi City and its environs. A 220 kV transmission line from the Kamburu/Kiambere hydro complex to the substation at Dandora constitute the main supply source. At Dandora, a 220 kV connection supplies the Embakasi substation (feeding the southern parts of the city) and a short 132 kV connection supplies the substation at Juja Road. The latter substation is also supplied from Kindaruma power station at 132 kV and the Tana & Wanji power stations at 66 kV. In addition the western transmission system (which extends up to Owen Falls in Uganda and the Turkwel supply, connected at Lessos) connects to Juja Road substation at 132 kV and also feeds Ruaraka, to the north of Juja Road. A 66 kV system with supply injections at Juja Road, Embakasi and Ruaraka, formns the backbone of the city distribution system. 4.2 The study area is about 575 sq. km and covers the Nairobi city and some adjoining areas as shown in Map IBRD 26459. The 11 kV network is fed from ten 66/11 kV substations: Parklands, Jeevanjee, Buckleys, Industrial Area, Nairobi South, Cathedral, Steel Billets, New Airport, Ruaraka and Karen. The first six of these together with some feeders from the seventh (Steel Billets) feed the 'city center'. This area --about 100 sq.km.-- has a high load concentration and is supplied by a well configured 11 kV system with the average distance between adjacent substations being of the order of 2.5 km. The consequent short feeder distances have resulted in a reasonably low loss distribution system. The only area where feeder distances increase significantly is in the north western section and the analysis to follow shows that two new substations can profitably be introduced in this area. The peripheral areas of the city (not covered by the present study) are supplied by 66/11 kV substations at Athi River in the south, Kitisuru and Kikuyu in the west and Limuru in the north west together with 33/11 kV substations Ruiru and Nyaga in the north east. Present System Operation 4.3 The data collection exercise carried out for the study area as described in Section 3 yielded information on the key characteristics of feeders such as maximum and minimum loads, power factor, load and loss factors and peak contribution. These data are presented in Table A2.1 of the Annex. Loadflow computations were also carried out for each feeder and summary results of these studies are presented in Table A2.2 of the Annex. The tables provide information on the loss levels and terminal voltage drops of the feeders operating with the present network peak loads as well as with the expected loads in the next 10 and 15 years. A number of feeders outside the specific area selected for the study were also analyzed in view of their impact in considering investment options. At current loading levels the technical losses are reasonable --power loss for the 11 kV system being 2.63% and energy loss being 1.84%. However, the overall losses will increase steadily if no system development is carried out. For - 31 - the expected load in 10 years the power and energy loss will increase to 6.4% and 4.6% respectively with the existing system. In 15 years, if no development work is carried out the respective loss values will increase to 9.61 and 6.8% respectively. Furthermore, there are many feeders which have high loss levels even with the present load and profitable investment can be made for loss reduction and other system benefits. Development Proposals New Substation at Kiambu 4.4 Two of the worst performing feeders in the area are Kiambu (feeder 23) and Ridgeways (feeder 28) supplied from Ruaraka substation. The power loss levels of these two feeders at present peak loads are 6.8 and 9.5% respectively. Without system improvements the losses will increase to 13.3 and 17.0% respectively in 10 years time. System development of this area is best effected by introducing a new substation in the Kiambu area and rationalizing the 1 1kV feeder arrangements from the existing and new substations. Two locations for the possible introduction of such a substation have been studied. In the first alternative the resulting network rearrangement will mainly benefit the targeted feeders (nos. 23 and 28). In the second alternative the substation location is further north west of the two feeders thus enabling the new substation to also pick up some load from Muthaiga feeder (supplied from Limuru substation) and UNEP feeder (supplied from Kitisuru substation). The second proposal will have additional costs in view of the longer length of 66 kV line extension involved and the reconductoring of some 11 kV feeder sections to accommodate the proposed load transfers from the additional feeders. However, loss reduction benefits will increase from that of the first alternative (829 kW as against 635 kW for present system loads). A substantial additional benefit from the second proposal is that the new substation can relieve the demand on Limuru substation which is presently close to its designed rating. An economic analysis of the two proposals is presented in Table A2.3 of the Annex, a summary of which is presented in Table 4.1 below. Both alternatives yield high benefits and if only loss reduction benefits are considered they are about equally advantageous. With reliability benefits and the ability to service new loads however, alternative 2 is clearly preferable and thus this alternative is reconimended. Existing network details and the altered feeding arrangement from the proposed new substation are shown in Figures A2.1 A and B, of the Annex. Table 4.1: Economic Evaluation of Alternative Locations for Kiambu Substation Location 1 Location 2 B/C ratios NPV B/C ratios NPV Period of analysis 1 OYr 1 5Yr 1 5Yr 1 OYr 1 5Yr 1 SYr 1. Only loss reduction 6.9 7.1 5.1 6.8 7.0 6.7 2. Loss reduction plus reliability 9.5 10.1 7.7 9.6 10.3 10.4 3. Loss reduction, reliability plus 10.8 15.6 12.3 20.6 26.3 28.3 new loads Note: NPV is in $millions and is worked out for the 15 year analysis. - 32- New Substation at Kileleshwa 4.5 The area west of the Parklands and Buckleys substations is presently supplied by a number of feeders from these substations as well as from the east bound feeders from Karen substation. This is one of the heavily loaded areas of the city and contains a number of feeders with relatively high losses. Among them, feeders Lavington (No.61), Kabete (No.16), Hurlingam (No.36) and Ngong Road (No.34) currently exhibit peak losses of 7.1, 5.5, 4.6, 3.6%, respectively. In the absence of system improvements these losses will increase to 13.3, 14.3, 7.6 and 5.9% respectively in 10 years. Since the area is already built up there are only limited possibilities of finding suitable land for a new substation to improve the supply arrangement for the feeders concerned. Although a number of alternative locations for introducing a new substation were considered only one proposal is presented due to the difficulty of securing the required land and lower economic attractiveness of the other alternatives. An economic analysis of this proposal is presented in Table A2.4 of the Annex. Figure A2.2.2 shows the location of the proposed substation. A peak time loss reduction close to 1 MW and an annual energy saving of about 3.4 GWh is achieved at present loading levels and the proposal yields a benefit to cost ratio of around 22.2 (for a 15 year period of analysis). Feeder Reconductoring and Introduction of New Feeders 4.6 The load flows of individual feeders provide information on line sections which contribute to high network losses. Selective reconductoring of such sections were investigated during the study and those that provided significant loss reduction benefits were subjected to an economic analysis. In addition, the possibility of introducing new feeders to relieve the loading levels of existing feeders has also been investigated. Only loss reduction benefits have been considered as relevant for the reconductoring options. For proposals establishing new feeders, improved reliability was also considered in the economic analysis. The ability to feed new loads (otherwise not possible due to poor voltage conditions in the undeveloped network) is another benefit applicable to most new feeders. However, in the particular instances examined these benefits were found to be applicable only after about 10 years; they were thus excluded in the computations. Key results of the analyses carried out for reconductoring options are presented in Table A2.5.1 of the Annex. In some instances the reconductoring options have been compared with alternative developments involving new feeders (including selective reconductoring of certain sections). The results of such comparative economic analyses are presented in Tables A2.5.2 and A2.5.3 of the Annex for the systems presently supplied by Feeder Nos. 30 and 38. A comparison of benefit to cost ratios of this analysis is presented in Table 4.2 below. In both instances it is observed that if only loss reduction benefits are counted the reconductoring proposals are superior. However, when the reliability benefits are included the new feeder proposals emerge as the winners. Further, the incremental benefits of adding the new feeder sections are compared to the incremental costs in Tables A2.5.2 and A2.5.3, indicating benefit to cost ratios over 25:1 in both instances. Accordingly, proposals incorporating new feeders are recommended. -33 - Table 4.2: Economic Evaluation of Reconductonng vs. New Feeder Options BenefiVCost Ratios Feeder 30 Feeder 38 Recond- New Record- New Option Feeder Option Feeder 1. Only loss reduction 14.7 8.6 18.0 9.9 2. Loss reduction plus reliability 14.7 20.8 18.0 23.1 Note: Only results of the 10 year analysis is presented. 4.7 In the analyses carried out for reconductoring and addition of new feeders, the identified improvements proved to be economic with an overall loss reduction from 3.1% to 1.2% of the aggregate power supplied to the feeders concerned. These improvements will result in peak time power saving of almost 1 MW and an annual energy saving of 5.1 GWh at current loading levels with an overall benefit to cost ratio of 13.7. Reactive Compensation 4.8 A number of feeders which were investigated during the study had low power factors, particularly during day time hours (see Table A2.1 of the Annex). Loss savings that could be achieved by reactive compensation (installing capacitors) at suitable locations were examined with the aid of special programs in the network analysis software supplied. The results of studies conducted for the worst performing feeders are presented in Table A2.6 of the Annex. Three of the fifteen feeders selected for analysis had power factors lower than 0.8 while the rest varied between 0.80 and 0.93. With the introduction of capacitors the performance of the feeders improved with reduced losses as well as improved feeder voltage profiles. Due to a number of considerations the increase of benefits with load growth of future years has not been taken account of in the analysis. Firstly, it is possible in certain instances that developments proposed elsewhere in this section (addition of new substations and feeders) would change the characteristics of the system substantially, reducing the benefits introduced by the capacitors. Secondly, feeder power factors could improve considerably if action is taken to improve consumer load power factors. Table A1.4 of the Annex provides the results of the investigations made during the study on sampling the power factors of bulk consumers. Clearly many of these consumers should be encouraged to improve their power factors by compensation measures within their installations. In view of these considerations the capacitors recommended to be applied at present are those which will provide a very quick return on investment. A pay-back- period of three years was selected in view of the fact that both new investment in system development and rectification of the consumer power factors would take about this time to implement under present conditions. Accordingly, the study recommends reactive compensation measures at nine installations totalling 6.7 MVAr of compensation at a cost of $ 73,800. These applications would provide an aggregated benefit to cost ratio of 8.3 and pay-back-period of 18 months. - 34 - Summary of Network Improvements Proposed 4.9 Power system studies conducted for the area selected within the Nairobi city resulted in the identification of network investment proposals amounting to $ 5.2 million. These developments are expected to provide peak time power savings of 2.5 MW and annual energy savings of 15.5 GWh at current loading levels. As discussed in Section 3 these benefits will increase with the expected increase of network loads over time. The proposals for new substations (and feeders) will also provide substantial reliability benefits as well as needed capacity to connect new loads. The overall benefit to cost ratio of the proposals for a 15 year analysis period works out to 21.4 A summary of the recommendations of the economic analyses camed out for the network improvement measures is provided in Table 4.3 below: Table 4.3: Summary of Proposed Network Improvements Feeder Peak Power Losses in kW Power Savings (kW) Annual At Energy Investment Feeders Existing Designed At Feeder System Savings Cost Improved System System Peak Peak (MWh) (US$000) B/C Ratio New 66/11 kV Substation at Kiambu 23,28 l 1142 313 r 829 T 747 0 3667 2236 26.3 &13 _ l l 1 New 66/11 kV Substation at Kileleshwa 16,19,34,36,6 1 _ 1,S2 &74I 1,82__ 74 14940 497 997 987 3437 2267 22.2 Reconductoring of feeders: _ _ 3 _ -102 34 68 41 341 36 13.7 2_ _ 30 14 16 6 61 19 4.4 =-9 104 41 63 37 384 19 19.0 4 91 46 45 27 245 35 9.8 39 128 46 81 74 242 39 12.8 40 115 27 88 84 275 55 10.3 X 1 202 83 122 110 399 28 27.5 13 43 IS 25 22 125 14 12.6 14 143 62 81 73 395 37 26.6 18 103 44 59 53 297 27 15.5 24 212 74 138 88 695 42 18.9 25 145 67 78 50 459 - 40 16.2 l 52 l 74 37 37 23 198 32 8.9 55 88 46 42 38 117 34 6.3 1 58 l 91 36 56 50 162 21 21.3 Introducing new feeders: (with partial reconductoring): 30 76 l 18 1 57 l 48 1 295 l 47 20.2 38 117 i 22 i 94 183 S 369 711 23.7 Capacitors for Low Power Factor Feeders 6.7 MVAr of Capacitors 1 128 | 60 280 74 1 8.3 Total for all improvements 2.5 MW 15.5 GWh 5.2 million 21.4 - 35 - V. COASTAL AREA MV SYSTEM DEVELOPMENT Overall supply arrangements 5.1 Maps IBRD 26526 and 27805 show the important features of the supply system for the Coastal Area. Power from the national grid is supplied from the 220/132/33 kV substation at Rabai. This main grid substation feeds three injection points to the distribution system. The first is at Rabai itself off a 23 MVA 132/33 kV transformer, providing supply to loads in the southern and western sections in the Area. The second is at Kipevu (90 MVA substation) fed by short 132 kV connection from Rabai and supplying the loads in and around Mombasa Island. The third is at Kilifi (15 MVA substation) fed by a 132 kV line from Rabai and supplying the loads at the northern periphery. To augment the grid supply (which is unable to maintain satisfactory voltage levels at system peak), 63 MW of oil-steam and 31.5 MW of gas turbine power plant are installed at the Kipevu substation. 5.2 For purposes of network studies, the distribution system can be conveniently grouped to four supply zones as follows: (a) the southern section supplied from 33/11 kV substations at Diani (15 MVA) Galu (2.5 MVA) and Msambweni (2.5 MVA), 33 kV supply being provided by a feeder from Rabai; (b) the area to the west of Mombasa supplied from two 33/11 kV substations, one at Miritini and the other a direct supply to the Kenya Oil Refinery, these two substations being fed from 33 kV lines from Rabai and Kipevu respectively; (c) the Mombasa island and load in its vicinity supplied from 33/11 kV substations at Makande (23 MVA), Mbaraki (46 MVA) and Likoni (7.5 MVA), with 33 kV supply provided by two feeders from Kipevu; and (d) the northern coastal section interconnected by a 33 kV network with three circuits between Kipevu and Bamburi and continued thereafter by a long single circuit from Bamburi to Malindi. This section is fed from two sources, 33 kV at Kipevu and a 15 MVA, 132/33 Grid substation at Kilifi (supplied by a 132 kV line from Rabai). A number of 33/11 kV substations at, Nyali (10 MVA -spur off main line), Bamburi (30 MVA), Ribe (0.5 MVA -spur off main line), Shanzu (15 MVA), Mtwapa (0.315 MVA), Kikarnbala (2.5 MVA), Kilifi (2.0 MVA), Gede (1.5 MVA) and Malindi (7.5 MVA) feed the load concentrations along the way. - 36 - Present System Operation 5.3 The medium voltage system consists of two network voltages, 33 kV and 11 kV. Key characteristics of the feeders such as daily maximum and minimum loads, power factor, load and loss factors and peak contribution were obtained during the data collection exercise and are presented in Table 3.1.1 of the Annex. Loadflow computations for each feeder were also carried out using the software described in Section 3 and summary results of these studies are presented in Tables A3.2 and A3.3 of the Annex,. These tables provide information on the loss levels and terminal voltage drops of the feeders operating with the present network peak loads as well as the with the expected loads in the next 10 and 15 years. A summary of the network losses by voltage level is provided in Table 5.1. This Section examines those feeders with poor performance levels and presents proposals for their improvement. Table 5.1: MV Feeders, Mombasa - Aggregated Power and Energy Losses Power Loss in % Energy Loss in % Time from present OYr 1OYr 15yr OYr I0Yr 15Yr 11 kVsystem losses 2.5 5.0 9.6 1.7 3.3 6.3 33 kV system losses 4.8 9.0 13.1 3.5 6.5 9.3 Combined system losses 6.4 11.2 18.8 4.4 8.2 12.5 5.4 Overall losses of the 11 kV system are not excessive for the present system loads. However, performance of the 33 kV system is not as satisfactory, thus increasing the MV system losses as a whole. The table also indicates how the overall losses would increase with time in the absence of suitable system development. Furthermore, the details of the individual feeders show that the poor performance of a number of feeders are masked by the low losses of heavy load concentrations close to the supply substations. It will be seen from the ensuing analysis that many feeders are not performing economically and that there is considerable scope for economic system improvements. 5.5 A number of 33 kV feeders in the Coastal Area presently operate at exceptionally poor performance levels. The 33 kV feeder to Diani from Rabai has a 10.4% power loss and a terminal voltage drop of 15.6%. The Malindi feeder from Kilifi is a very long feeder with the load concentrated towards its end and has a peak loss of 23.1% and a terminal voltage drop of about 30%. These feeders should be relieved immediately to service the existing consumers satisfactorily and to enable new consumers to be connected. The Miritini feeder from Rabai is also operating at a high loss level 6.0% (and a voltage drop of 7.2%). Although the three feeders to Bamburi from Kipevu have reasonable loss levels (2.6 to 4.1%) their performance cannot be considered as satisfactory. The low loss levels are due to the short lengths and Bamburi Feeder 1 is already close to its thermal rating. The reliability of supply from these feeders to the important loads supplied is low and there are limited possibilities of load transfers in the event system failures. In contrast, only a few of the 11 kV feeders are in need of immediate relief. Those that require improvement are the Kwale and Diani 1 feeders from Diani Substation (present losses at - 37 - 6.6 and 8.5 % respectively), Mazeras feeder from Miritini substation (present losses at 7.3%), and the Bamburi II and Nyaliloc feeders from Nyali substation (present losses at 7.9 and 5.7 % respectively). 5.6 The Likoni substation presently supplied from Diani, should be fed from Mbaraki via the submarine link for optimum system performance. This is not possible at present due to the unserviceability of this submarine cable. If the necessary repairs/replacements are carried out and the supply arrangements altered the loading on the Diani feeder from Rabai can be reduced from 12.8 MW to 8.3 MW. This will result in the feeder losses being 7.9% (reduced from 10.4%) and the voltage drop 11.2% (reduced from 15.6%). System improvement proposals considered in this report assume that these alterations will be carried out. Development Proposals Proposed 132 kV Line Rabai to Diani and 132/33 kV Substation at Diani 5.7 The single circuit 33 kV, 0.150 in.sq. SCA conductor line of 47 km presently supplying the load concentration around Diani is grossly inadequate to meet the existing load. A number of tourist hotels requiring high supply reliability form the bulk of the load in this area. There is also a sugar factory at Ramisi which consumes no load at present due to temporary shutdown of operations. There are indications that this load will resume; and if it does, the supply situation in the area will become even more critical. The rest of the load in the area consists of medium and low demand domestic and commercial consumers as well as some agricultural load. Even with the alterations to the network operations as indicated in para 5.6, system losses and voltage drops will still be in excess of acceptable values. Furthermore, the Diani substation should be able to feed Likoni as an altemative operating condition (for exigencies) with an acceptable voltage profile. In the absence of the suggested improvements, the load growth over the next 10 years will cause the power losses to increase to 14.4% and the voltage drop to increase to 20.4% --values which cannot sustain system operation without serious technical problems. A new 132/33 kV substation is therefore urgently required at Diani with the introduction of which the peak losses from Rabai to Diani will decrease to a mere 0.5% for the present system load and 0.8% for the load expected in 10 years time. The 132 kV line proposed for the Diani substation can be constructed either with the conventional steel tower structures as in KPLC's current construction standards for 132 kV lines or with wooden poles (which will provide a saving of about 50% for the line costs). The 132 kV connection will also improve the reliability level of the area up to Likoni. Although there will be no substation capacity shortage for some time the low voltage levels in the existing system precludes the addition of new loads without the proposed development and hence new capacity additions form a part of the associated benefits. Key results of the cost benefit analysis for both construction arrangements (with steel and wooden supports) are presented in Table A3.4 of the Annex and are summarized in Table 5.2 below. Both options provide positive benefits over costs even if only the loss reduction effects are considered. The benefits increase when reliability improvement and ability - 38 - to supply new loads are included. In view of the relatively low load and since this area is at the periphery of the network, line construction on wood poles is recommended. Table 5.2: Economic Evaluation of Alternative Line Construction 132 Kv Line to Diani Wood pole line Steel supports B/C ratios NPV B/C ratios NPV Period of analysis 1 OYr 1 5Yr 1 5Yr 1 OYr 1 5Yr 1 5Yr 1. Only loss reduction 2.8 2.8 3.2 1.6 1.6 1.9 2. Loss reduction plus reliability 3.8 3.9 5.1 2.2 2.3 3.9 3. Loss reduction, reliability plus new loads 6.0 7.6 11.6 3.5 4.4 10.3 Note: NPV is in $millions and is calculated for the 15 year analysis. Improvements to 11 kV Tiwi feeder from Diani Substation. 5.8 This feeder has a total length of 28 km and the power loss levels computed are 3.4%, 5.3% and 6.6% for the present loads and those expected in 10 and 15 years respectively (load growth assumed being 4% p.a.). The corresponding voltage drop levels are 5.3%, 6.3% and 10% respectively. Three proposals are considered for the development of this feeder. The first proposal consists of reconductoring the initial sections to 300 mm.sq. In the second, a new line is added to enable the load to be split up to two separate feeders. The third proposal introduces a new primary substation to restrict the area of coverage of the Diani substation. All options give satisfactory technical operation over the 15 year analysis period. Since there is no capacity shortage or other technical inability to meet new loads, such benefits have not been computed for all alternatives. Both the new feeder and the new substation will however improve system reliability and related benefits have been included for these two options. Key results of the cost benefit analysis for these options are presented in Table A3.5 of the Annex and summary results are provided in Table 5.3 below. In view of the higher benefit to cost ratios of the new feeder proposal this option is recommended. Table 5.3: Economic Evaluation of Alternative Improvements to Tiwi Feeder Reconductor New Feeder New substation B/C NPV B/C NVP B/C NPV 1. Only loss reduction 1.9 0.1 3.1 0.1 1.8 0.1 2. Loss reduction plus reliability 1.9 0.1 4.8 0.2 3.5 0.3 Note: Both benefit/cost ratios and NPV are for a 10 year analysis. NPV is in $millions. - 39 - Proposed New Substation at Galu 5.9 The present Diani No. 1, 11 kV feeder from Diani substation has excessive loss and voltage drop characteristics even at present loading levels. The calculated values for peak conditions are 8.5% and 12.7%, respectively. This area has a high load growth potential with a developing tourist industry and a growth rate of 6% per annum has been used in the analysis. The forecast loads for 10 and 15 years indicate power losses and voltage levels that are totally unacceptable both technically and economically; losses rising to 18.1% and 32.3% and voltage drops rising to 28.4% and 49.6% for the two future periods respectively. Urgent system improvements are required to provide better supply conditions to this area. 5.10 In view of the pressing difficulties experienced, KPLC is constructing a line connecting this feeder with Galu substation further south of Diani. Accordingly, system performance with this interconnector has also been considered in the analysis. It is seen that the new interconnector will improve performance to some extent with power losses being reduced to 5.3% (at present loads) but the perfornance still remains unsatisfactory. This is mainly because of the limited load transfer possibility in view of the low capacity of the Galu substation. In order to further improve the situation two proposals have been considered. In the first, the capacity of the Galu substation is increased to 7.5 MVA while retaining the 11 kV network as presently configured (inclusive of the above mentioned interconnector). The second proposal is an improvement of the first with a number of sections of the feeder being reconductored to 300AA and 0.150SCA conductor. The results of the benefit to cost analysis are presented in Table A3.6 of the Annex and summarized in Table 5.4 below. The second proposal has higher benefit to cost ratios if only loss reduction and reliability benefits are considered but the first proposal is better if all benefits are included. However, if net present values are considered the second proposal is more advantageous under all conditions. Closer investigation however indicates that if incremental benefits are considered (those attributed to reconductoring, given that sub-station augmentation will take place) the second proposal is preferable and accordingly this proposal is recommended. Table 5.4: Economic Evaluation of Improvements to Galu Substation and Associated 11 kV Lines With 11 kV line With only SS augmentation reconductoring B/C ratios NPV B/C ratios NPV Period of analysis I OYr 15Yr 15Yr I Yr 15Yr 15Yr 1. Only loss reduction 3.0 3.2 0.4 5.2 5.5 1.1 2. Loss reduction plus reliability 4.5 4.9 0.7 7.0 7.6 1.7 3. Loss reduction, reliability plus new loads 24.5 31.9 5.5 21.1 26.5 6.4 Note: NPV is in $millions and is calculated for the 15 year analysis. - 40 - Proposed 132 kV Line to Bamburi 5.11 The 33 kV Bamburi I, II and III feeders from Kipevu feed a number of important loads just north of the Mombasa Island. The major load in this area is the 30 MVA Bamburi Cement Company fed directly from the 33/11 kV substation at Bamburi. The rest of the loads supplied are fed from 1 1 kV lines from four substations, Makande (7.5 MVA feeding the Island), Nyali (10 MVA), Shanzu (2 x 7.5 MVA) and Ribe (0.5 MVA). Current plans indicate that the Bamburi cement factory will increase its load to meet the rising demand for cement by the building industry. The concentration of hotel loads along the coastal areas also augur for a higher than average load growth rates for this region. Accordingly an overall growth rate of 10% has been used in the analysis conducted for this area. 5.12 Although the present overall power losses of the three feeders are 3.08%, a figure which is not too excessive, the computations for the fuiture loads show the losses increasing to 5.4% in 10 years and 7.15% in 15 years. The present voltage drops of the three feeders are all of the order of 5%. With the future load growth however, the voltage drop of feeder I increases to 10.3% and 14.5% respectively. The values for feeder II also show an unsatisfactory performance (9.1% and 1 1.4% respectively). The losses of the Bamburi feeder I remain low over the analysis period, but a load transfer to this feeder from the higher loss feeders II and III is not possible in view of the large capacities of the connected load and the need to keep the feeders separate for reliability considerations. 5.13 Substantial economic benefits and improved technical performance can be obtained by providing a 132 kV supply from Rabai to Bamburi. This additional injection point to the distribution system of the northern section has many advantages in addition to loss reduction benefits. The new supply will enable the Makande substation to receive power from either Kipevu or Bamburi, providing an enhanced reliability of supply. During normal operation the Makande load will be supplied from the existing three circuits from Kipevu leaving the northern load to be fed from the new substation at Bamburi. Any future load increase at the cement factory can be handled expeditiously in view of the 132 kV supply availability at this location. The proposals analyzed consist of using 0.15 in.sq. as well as 0.2 in.sq. conductor in both single (SC) and double (DC) circuit configurations. Key results of the benefit to cost analysis of the proposals are presented in Table 3.7 of the Annex and summarized in Table 5.5 below. In general with increasing conductor cross-section the economic benefits are observed to improve. However, the benefit to cost ratios (both for the 10 and 15 year periods) of the DC 0.2 in.sq. option is lower than that of the DC 0.15 option. Consideration of the incremental costs and benefits between these two alternatives result in a positive benefit in using the higher cross section. Thus the selection of the DC 0.2 in.sq. 132 kV line option is recommended. The Bamburi grid substation will be initially installed with two transformers of 23 MVA each but substation equipment should be capable of accommodating a third unit. - 41 - Table 5.5: Economic Evaluation of 132 kV Line to Bamburi SC 0.15in.sq. SC 0.2in.sq. DC 0.15in.sq DC 0.2in.sq. 132 kV line details B/C NPV B/C NPV B/C NPV B/C NPV 1. Only loss reduction 5.9 15.0 6.7 19.3 6.9 21.3 7.1 24.1 2. Loss reduction plus reliability 8.4 23.0 9.4 28.4 12.0 39.3 11.7 42.2 3. Loss reduction, reliability plus new loads 39.9 120 42.9 142 43.7 153 40.5 156 Note: NPV is in $millions and is calculated for the 15 year analysis. Proposed 132 kV Supply to Malindi 5.14 A 132/33kV, 15 MVA grid substation at Kilifi presently feeds the load concentrations in the northern periphery of the Coastal Area. A 33 kV feeder to the south (which connects with the northern feeder from Bamburi) feeds substations Kuruwetu (0.15 MVA), Kikambala (2.5 MVA) and the Mtwapa agricultural station. Another feeder to the north supplies the substations Gede (1.5 MVA), Malindi (7.5 MVA) and various distribution transformers with a total capacity of 4 MVA at Marerene. Scattered loads are also fed directly from the 33 kV lines running south and north of Kilifi. Apart from the loads close to the grid substation at Kilifi, the largest load concentration in the area is at Malindi, fed by a 33 kV line of 59 km. The area has a number of hotels, agro-based industrial consumers and some commercial load in addition to the domestic load. A load growth rate of around 10% per annum is expected for this area. 5.15 The 33 kV line from Kilifi to Malindi (59 km) is constructed with 0.05 in.sq. conductor. The feeder extends a further 44 km to Marerene with 0.075 in.sq. conductor. This feeder is the worst performing feeder in the Mombasa Area. Although the section to Marerene is very lightly loaded the concentrated load at Malindi itself is far above the acceptable limits for the voltage and conductor size of this feeder. The losses computed on the present load are 23.1% and the voltage drop is 29.7%. With the load expected in 10 years time the these values increase to 39.4% and 51.4% respectively. The load flow analysis program fails to converge for the load configuration of 15 years indicating impossible operating conditions. Thus it is clear that improvements required to this feeder are long overdue. Due to the long length involved and the relatively low load supplied, KPLC has been reluctant to construct a 132 kV line to feed this load. The recommended solution in instances of this nature is to use a low cost approach to the 132 kV line and substation construction. Wood poles using lower clearance would be admissible in view of the terrain over which the line passes"2. Furthermore the 132/33 kV substation could consist of free standing reclosers on both the 132 and 33 kV sides with direct connections to a single transformer. Even fuse arrangements may be used for the 33 kV feeders. Such reduced 12 This recommendation is subject to the review of KPLC's regulations. For areas which are sparsely populated and not subject to vehicular traffic lower line clearances are generally admissible. - 42 - levels of protection are acceptable in view of the low fault level and the limited load served. The breaker at the sending end of the new 132 kV line can be relied on for the main protection. 5.16 Three proposals were studied for the network improvement required at Malindi, these being: (a) reconductoring of the existing line up to Malindi using 300 mm.sq. conductor (b) construction of a steel tower 132 kV line with 0.15 SCA conductor --Kilifi to Malindi and a 132/33 kV, 15 MVA substation at Malindi and (c) construction of a wood pole 132 kV line and a 132/33 kV transformer with simple switching arrangements at Malindi. Option (c) uses the low cost 132 kV line and substation approach as advocated in the previous paragraph. Key results of the benefit to cost analysis are presented in Table A3.8 of the Annex and summarized in Table 5.6 below. For the 33 kV development option it was assumed that a load up to 12 MW can be sustained (from the present 8.0 MW) in accounting for the benefits of new load additions. Further reliability benefits of saving 5 outages a year (each of 4 hrs. duration) were also accounted for. For the 132 kV options, the load of the full 15-year analysis period could be met from the proposed investment. The 33 kV option though slightly superior to the 132 kV steel pole option is not as attractive as the 132 kV wood pole option. Hence a wood pole 132 kV line from Kilifi to Malindi with a single 15 MVA, 132/33 kV transformer and a simple 33 kV switching arrangement is recommended. Table 5.6: Economic Evaluation of Improvements to Malindi Feeder Wood pole 132 33 kV line Steel pole 132 kV kV 132 kV line details B/C NPV B/C NPV B/C NPV 1. Only loss reduction 8.2 11.5 4.4 11.9 6.2 13.0 2. Loss reduction plus reliability 7.1 11.5 6.3 18.7 8.4 18.6 3. Loss reduction, reliability plus new loads 11.1 21.4 10.3 32.9 14.1 32.9 Note: NPV is in $millions and is calculated for the 15 year analysis Proposed Developments at Mazeras and Rabai 5.17 The present supply network at Mazeras and Rabai is the 11 kV Mazeras feeder from Miritini 33/11 kV substation. This feeder is spread over a wide area containing relatively dispersed loads. Although for some time the load in this area remained predominantly domestic, lately there has been an increasing growth of commercial and industrial loads. An overall growth rate of around 5% could be expected over the future period of about 15 years. The present system power loss is computed at 7.3% and the voltage drop at 15.1%. The situation worsens with the future load growth and losses increase to 13.5% and 21.9% in 10 and 15 years respectively, the corresponding voltage drop increasing to 27.3% and 42.6% respectively. - 43 - 5.18 The network development proposals considered for this area are: (a) construction of a 33/11 kV 5 MVA substation at Rabai; (b) construction of a 33/11 kV 5 MVA substation at Mazeras; and (c) conversion of the line to 33 kV. Benefit to cost computations for these proposals are presented in Table A3.9 in the Annex and are summarized in Table 5.7 below. The 33 kV conversion proposal although superior on loss reduction benefits provides less reliability benefits in view of the single supply source. Furthermore, the losses resulting from the long outages necessary to convert the line to 33 kV have not been accounted for in the analysis. The new 33/11 kV substation at Rabai is more economical than the alternative development at Mazeras. Further, the substation location at Rabai will also offer the possibility of expanding the network northwards towards Kaloleni area. Accordingly, the establishment of the new substation at Rabai is recommended. Table 5.7: Economic Evaluation of Improvements to Mazeras Feeder SS at Rabai SS at Mazeras 33 kV conversion System development: B/C NPV B/C NPV B/C NPV a. Only loss reduction 2.9 0.6 1.5 0.2 2.9 0.6 b. Loss reduction plus reliability 4.4 1.0 2.7 0.6 2.9 0.6 c. Loss reduction, reliability plus new loads 5.0 1.2 3.2 0.8 3.4 0.7 Note: NPV is in $millions, both B/C and NPV is calculated for 15 year analysiS. 11 kV Feeder Tom Mboya From Makande 5.19 Although this feeder has a present loss level of only 1.1% it is a heavily loaded feeder (5.2 MW) feeding important loads within the Mombasa Island. Thus, proposals to improve the performance of this feeder were considered. The developments examined were the introduction of a new feeder (with associated reconductoring of certain existing sections) and the introduction of a new 33/11 kV substation at Buxton. Table A3.10 in the Annex provides the results of the economic evaluation of the two alternatives. The new feeder proposal is more advantageous with a benefit to cost ratio of 6.3 (compared to 3.1 for the new substation). Table A3. 1O also considers the additional benefits of rationalizing other feeders in the neighborhood of the proposed substation, still resulting in the marginal superiority of the new feeder proposal. The introduction of the new feeder is therefore recommended (introduction of the new substation could be reconsidered at a latter date depending on the load development in the Island). -44 - 11 kV Feeder Bamburi No.1 From Nyali 5.20 Bamburi No. 1 is a high loss feeder in spite of its short length. The present power losses are at 7.9% and the voltage drop is 13.6%. In the absence of system improvements losses will increase to 20.7% and the voltage drop to 34.1% in 10 years. The network performance can be improved by introducing a new feeder (with reconductoring of certain existing sections) to achieve substantial loss reduction and improved network performance. Table A3.11 in the Annex provides the results of the economic evaluation indicating a very high benefit to cost ratio of 65:1. Application of Capacitors for Reactive Compensation 5.21 Proposals considered above provide for the major system improvement necessary to meet future loads and improve network performance in an economic manner. Some of these developments, particularly those involving 132 kV construction work will require at least two years to commission in view of the necessity to secure funds and attend to the necessary procurement. Studies have also shown that substantial economic benefits as well as immediate improvements to the technical performance can be obtained by the installation of capacitors, particularly in areas which presently suffer from excessively low voltages. Table A3.12 in the Annex provides the results of studies where economic application of capacitors is possible. A total of 2.4 MVAr of capacitors in banks of 300 to 900 kVAr can be utilized with an overall pay back period as short as 11.4 months. The aggregate benefit to cost ratio achieved is 13.7:1. Summary of MV Development Proposals for the Coastal Area 5.22 Techno-economic analyses of system developments conducted for the Coastal Area indicate that there are a number of major network improvements that are required to be implemented in the immediate term. Amongst the most urgent requirements are the 132 kV developments required for Malindi and Diani. These 132 kV system extensions required could be constructed on wooden poles to minimize construction costs, in particular as the loads supplied are at peripheral locations in the system. A 132 kV injection to Bamburi is another important system development required, providing reliability benefits to the loads in the Mombasa Island and environs. 5.23 Investrnents identified total $15.9 million with aggregate loss reduction benefits of 4.3 MW at peak demand and 20.0 GWh, annual energy savings at present loading levels. The overall benefit to cost ratio of the MV network development proposals is 27.7 indicating high economic returns. A summary of the individual proposals is indicated in Table 5.8 below: - 45 - Table 5.8: Summary of Development Proposals Present System Proposed System Invest. B/C Losses Losses Loss Saving Cost Ratio kW MWh/yr kW kW MWh/yr Million 132/133 kV Substation 23 MVA at Diani 653 3066 47 606 2843 3.500 7.6 132/33 kV Substation (3 x23 MVA) at Bamburi 1552 8456 187 1365 7438 7.990 40.5 132/33 kV Substation (23 MVA) at Malindi 1842 7907 138 1704 7314 3.337 14.1 33111 kV Substation (5 MVA) at Rabai 169 391 15 154 356 0.400 5.0 Galu SS (2.5 MVA) Augmentation to 7.5 MVA 193 796 38 155 639 0.366 26.5 11 kVFeeder,Tom 58 164 38 19 55 0.060 6.3 Mboya 11 kV Feeder, Bamburi II 260 934 122 138 495 0.084 65.3 11 kVFeederforTiwi 60 317 29 31 165 0.080 4.88 2400 kVAr of Capacitors 100 165 0.031 13.1 Total 4787 22031 614 4272 19470 15.85 27.7 - 46 - VI. L.V. NETWORK STUDY Existing system characteristics 6.1 About 98% of KPLC's consumers receive supply through the LV network. Although the average consumption of these consumers is much lower than that of consumers fed directly from higher voltage networks, the LV consumers still account for about 45% of the overall energy supply. In terms of contribution during system peak the LV system demand is even more pronounced, with an estimated 83% of net generation (about 590 MW) flowing through LV networks. Existing LV networks have been designed according to traditional practices that were established many years ago. These practices did not adequately address economic considerations of loss optimization, nor were facilities available at that time for comprehensive study and analysis of distribution systems. The current study introduced computerized network planning facilities and an extensive amount of work lies ahead for KPLC to redesign its LV systems to meet economically acceptable standards. Thus, an important objective of the present study was to examine whether some general methodologies could be established for carrying out such exercises. While the results of the sample studies carried out are presented in this section some general guidelines on procedures to be followed in such studies are presented in Section 8. Network Losses 6.2 LV networks of 18 transformer supply areas selected at random were surveyed in order to examine their operating characteristics. During the survey the networks were drawn on 1:2500 scale maps, a census made of consumer connection by each pole and the daily load profile determined for each transformer. Samples of the transformer load profiles are shown in section A1.3 of the Annex. In view of the need to coordinate the developments within each area with the adjoining networks four other transformer supply areas were incorporated in to the study, increasing the study areas to those supplied by 22 transformers. 6.3 Each of the supply areas was modeled using the LOWO software program described in Section 3 and the results of the load flow studies and sample network diagrams are shown in section A4 of the Annex. The aggregate power and energy losses of the LV systems studied were respectively: 5.4 and 3.6% for the networks and 1.1 and 0.7% for the transformers. Table A4.1 of the Annex provides the results of the individual network loss data. It is seen that over half the networks have loss values of over 3.4% for power and 2.1% for energy. More than 20% of the systems have power loss values of over 10% (corresponding energy loss value being 6.9%). Since well configured LV networks should have power losses of about 2% or less KPLC's LV systems are in need of substantial investment to improve their operating performance. -47 - Transformer Losses 6.4 Distribution transformers in the system are another source of technical loss. These losses contain a constant component, termed iron losses (resulting from the magnetic flux in the transformer core) and a current dependent component, termed copper losses (similar to the losses of a conductor in the network). A spreadsheet to compute the transformer losses at various loading levels (utilization factors) and load and loss factors was prepared in order to analyze performance under different operating conditions. Tables and figures in the Annex (A4.2.1 onwards) provide the results of these computations for transformer characteristics commonly found in Kenya as well as for typical lower loss transformers currently available internationally. Percentage losses are observed to be very high for the lower rating transformers and also at lower utilization factors. For example, a 50 kVA transformer in the KPLC system loaded to 20% of its rating with a load factor of 30% would have a power loss of 2.5% and an energy loss of 10.0%. A normal low loss transforners under the same operating conditions would have only half the above loss values and a low loss unit of appropriate rating will have losses of about 1/5th the original values. Thus substantial savings in transformer losses are possible by: (a) the use of low loss units, and (b) changing out those with inappropriate ratings. 6.5 In order to secure low loss transformers KPLC should include the cost of losses in a life-cycle cost comparison during transformer procurement. Parameters involved in the computation of the cost of losses include economic factors (interest rate, expected lifetime, cost of power and energy losses) and those dependent on system characteristics (transformer utilization level, peak contribution, load factor and loss factor). The method of computing for these costs is presented in Table A4.3(A) in the Annex. A spreadsheet has also been prepared to assist KPLC in determining appropriate evaluation factors for various system conditions and cost characteristics and Table A4.3(B) in the Annex provides the results for a range of values of the relevant parameters. It is seen that the evaluation factor for iron losses will remain independent of system characteristics. However, these characteristics will have a substantial impact on the evaluation factor for copper losses (loss load factor and peak contribution being the key determinants). Since transformers can not be purchased for specific locations the evaluation factor to be used for copper losses should be based on average operating conditions in the system. KPLC should introduce without delay the practice of evaluating the cost of losses during transformer procurement. In order to ensure that prospective suppliers will use appropriate designs, they should be kept informed of the evaluation factors being used. The program may commence with conservative values, suggested at $5000/kW for iron losses and $1000AkW for copper losses and the evaluation factors increased after regular review to more appropriate figures of about $8000/kW and $2000/kW respectively when better transformer management practices are also concurrently established. 6.6 The second aspect to be addressed in transformer loss reduction is the review of distribution transformer loadings and carrying out a replacement and relocation exercise to optimize utilization levels. During the study it was observed that many of the under utilized transformers were found in low load density areas. A special study was conducted in Kwale (a rural district in the southern Coastal Area) and the results of this study is presented in Table - 48 - A4.2.4 in the Annex. Twenty inappropriately loaded transformers were identified serving a load of approximately 500 kVA with an aggregate transformer capacity of 1650 kVA. By using low loss transformers of appropriate ratings transformer power losses can be reduced from 1.6% to 0.6% and energy losses from 2.6% to 0.6%. Considerable reduction in losses can therefore be achieved by a suitable transformer load management program to improve the utilization of distribution transformers combined with the use of low loss designs. LV System Optimization 6.7 Seven of the LV systems that were examined (see paras 6.2 and 6.3) were studied in further detail to determine suitable development proposals which would optimize their economic performance. In four of these networks selected it was feasible to study system improvements by examining only the targeted network (fed by a single transformer). In the remaining three areas, it was found that the optimization exercise necessarily involved the supply networks of adjoining transformers. This is an important factor that should be borne in mind in studying network optimization; it is necessary to ensure that the recommended solutions remain indifferent to the selected study boundary. 6.8 Section 3 describes the software used for the study and the general methodology adopted. For reasons discussed in paras 3.9 and 3. 10, the full automatic optimization capabilities of the L.V. network study program were not utilized over the entire study period. To overcome difficulties connected with the spacial allocation of load growth, the overall analysis period of 15 years was divided into three separate sub-periods of 5 years each, with the network loads assumed to remain constant within each sub-period. The loading profile of each of the three periods was determined by (a) using an estimated load growth rate for the entire area relevant to the period, and (b) allocating the future load additions on the basis of site investigations (e.g. expected loads of new consumers being apportioned to vacant lots). This procedure enabled the best possible combination of the optimization possibilities of the program with the knowledge gained from field investigations. The network optimization facilities of the software was thereafter used as appropriate within each of the individual sub-periods. 6.9 Possible new network construction as well as suitable transformer locations are provided as input data to the program. The program selects the investrnents required to optimize the networks within each period (residual values being used for each item to avoid the effects of the short time slice used). All selected improvements are considered to be introduced at the beginning of the relevant period and investments selected during a previous period are considered as being part of the existing system for subsequent periods. When an existing transformer becomes overrated by virtue of the reduction of its feeding area caused by the introduction of new transformers, it is replaced by one with an appropriate rating. Neither supply and installation costs for transformer replacements nor the credit for the recovered (higher rated) transformer were taken account of, and on a conservative estimate, the two costs are assumed to cancel each other. The investments selected within each period and the corresponding benefits - 49 - were thereafter summed to determiine the overall benefit to cost ratio for the phased system improvement exercise. Study Results 6.10 The options available to improve the technical and economic performance of the networks may be classified in three categories, these being: a. introduction of additional transformers and consequent network rearrangement including new feeders; b. addition of new sections or feeders with corresponding rearrangement of the existing network; and c. reconductoring of existing sections. 6.11 The first category, the introduction of additional transformers effectively decentralizes the L.V. network arrangement by reducing the area of coverage of each distribution transformer and correspondingly increasing the number of transformers in the system. The effect of increasing the number of transformers may be perceived by a simple example. On an approximate basis, doubling the number of transformers may be considered as shortening the feeders by half, thus reducing the load carried by each feeder as well as the feeder length by 50%. Since line losses are proportional both to the square of the load and the line length, losses will reduce to 1/8th of the original value. However, with the addition of the number of transformers there would be an increase in transformer iron losses but this increase can be minimized (or even reversed) if low loss transformers are used (see para 6.4 to 6.6). The second category of investment options, the introduction of new sections and feeders is basically a rationalization exercise of existing networks. The third category, reconductoring, reduces network losses by the lower resistivity of the current carrying cables by use of larger cross sections. The study indicated that, in general, improvements under the first two categories proved to be more economic than those of the third category. 6.12 As indicated in para 6.8 the LV network improvement study was carried out by dividing the overall period into three sub periods, termed periods I, II and III. Seven separate areas (consisting of a total of 11 transformer supply networks) were analyzed. During period I the LV optimization resulted in the selection of 9 new transformers; an additional 9 transformers were selected in period II and a further 3 in period III. The progressive decentralization of one of the networks studied over the three periods is seen in Figures A4.4 (A), (B) and (C) in the Annex. Investments selected by the program also included the addition of new sections of aggregate length 910, 95 and 86 meters and reconductoring of existing sections of aggregate length 4,953, 1,359 and 1,363 meters respectively for Periods I, II and III. The present KPLC standards for L.V. network design are based on 100 mm.sq. all aluminum as the major line conductor with 50 and 25 mm.sq. all aluminum also in use. There are also some older lines in the system with copper conductors of 32 and 16 mm.sq. respectively. The network analysis - 50 - program allowed, in addition, the selection of twin conductor 100 mm.sq. arrangement. The highest gauge selected for the reconductoring exercise is a twin 100 mm.sq. and the sections to be reconductored in Period I have been of the order of 5 to 10% of the total network length. In one of the systems, the main load carrying sections have only 50 mm. sq. conductor and hence the program selected 63.4% of the total line length of this sample for reconductoring in addition to two new transformers, during Period I. This sample accounted for 46.8% of line reconductoring selected in all 7 systems. 6.13 This analysis shows that the improvements required for the LV networks are not expected to follow a uniform pattern over the entire system and actual requirements should be determined by a careful examination of the individual network characteristics. The results of the samples studied would however, provide useful general guidelines for the estimation of network improvement requirements over larger areas. LV systems are characterized by frequent changes caused by local conditions and implementation of a LV system improvement program should follow the planning exercise. If substantial time has lapsed it would be prudent to reexamine the networks to ascertain whether the original plans are still the optimum development. 6.14 A summary of the main characteristics of the systems studied and the resulting network development recommendations is presented in Tables 6.1 and 6.2 below. Table 6.1: Existing System Data No. of separate network areas = 7 No. of transformers in all areas = 11 Area covered in meters sq. = 986,000 Total load = 1537 kW Sum of transformer capacities = 3535 kVA Aggregate length of L.V. network = 24.8 km Average losses in Period I -power = 7.7 % Average losses in Period I -energy = 4.7 % Table 6.2: Summary of Development Proposals Period I Period II Period IlIl Total cost of proposals $84,880 $72,204 $27,001 No. of additionai transformers 9 9 3 Sum of new transformer capacities in kVA 1,287 991 466 Sum of new sections (in meters) 910 95 86 Reconductoring of existing sections (in meters) 4,953 1,359 1,363 Benefit/Cost ratio 9.66 8.68 9.80 - 51 - Estimated Investment Requirements 6.15 The study results indicate that economically attractive investment possibilities exist for the improvement of the L.V. distribution networks. Each of the networks studied required substantial network improvement. The seven sample areas investigated cover a total area of 10 sq.km. and identified investments totalling $84,880 for period I, $72,204 for period II and $27,001 for period III. The reduction of investrnent requirements for succeeding periods is due to the fact that networks become saturated with time. It signifies that older or more developed networks will require lower investments and that a higher proportion of investment requirements will be channeled to new development sites. In Kenya, particularly close to the major cities, urban expansion is a high growth activity and investments for L.V. system improvement and expansion are expected to remain high over an extended period. 6.16 The studies carried out on the sample systems may be used to provide approximate estimates of the investment requirements for the overall LV systems in urban areas of Nairobi and the Coastal Area. (Although the samples have been selected from Nairobi only, the characteristics of the networks in most cities are similar and results are expected to be valid for the Coastal Area as well). In more rural areas however the development requirements are expected to be somewhat different. Three characteristics (conversion factors) have been used to translate the results of the sample study to the overall requirements of the study area. These are: area of coverage, length of existing LV lines and existing transformer capacities. Table 6.3 presents the results of such an analysis with the funding requirements limited to a five year period (i.e. study period I). Also indicated are the main items of work (as per the results of the sample study) which could be used to carry out the procurement needs of the exercise. Table 6.3: Investment Requirements for LV System Development Sample Total Conversion studied study area factor Estimating characteristics: Area covered (km.sq.) 9.86 100013 101 Length of LV lines (km) 24.8 3118 125.7 Existing transformer capacity (kVA) 3535 450,00014 127.3 Selected conversion factor 100 Investment requirements in $000's for a 5 year period 84.9 8,490 Breakdown of investment requirements: New transformers of combined capacity (kVA) 1,287 128,700 New line sections (km) 910 91,000 Reconductoring (km) 4,953 495,300 3 Estimated on the basis of MV system coverage. 4 From the total transformer capacities in the system the capacities of those that supply bulk consumers directly have been estimated as follows: all transfonners above 500 kVA, 50% of 500 kVA and 10% each of 315 and 200 kVA). - 52 - 6.17 The three conversion factors computed agree fairly closely; the selected figure (100) approximating to the lowest, is used as the multiplying factor to obtain the development requirements for the total study area. The requirements for such an LV network improvement program will be about US$ 8.5 million. Detailed planning exercises of the networks to be developed should be carried out just prior to the intended work as LV networks, in particular, are subject to frequent alterations carried out to meet changes in load characteristics. Once detailed studies are carried out for the initial investment (targeted to meet the first 5 year period within the study area), a better appreciation will be gained on the funds required to carry out an overall LV network improvement exercise for the entirety of KPLC's system. In the study of the sample systems the average network energy losses decreased from 4.7% to 1.5% for the loads in Period I (i.e. equivalent to Year 1994) and the overall benefit to cost ratio of the recommended improvements was 9.7. We may therefore expect the same level of benefits to apply to the recommended LV system improvement program. - 53 - VIl. NON-TECHNICAL LOSSES 7.1 As discussed in Section 2, system losses are composed of technical and non- technical components, the former being due to the physical characteristics of the system and the latter to organizational deficiencies metering defects and consumer fraud. Non-technical losses represent energy consumed for which bills are not issued. Unrecovered revenue from billed consumption is a financial loss to the utility but is not included under non-technical losses. Thus non-technical losses arise from shortcomings in the metering, meter reading and/or billing systems and their primary sources may be summarized as follows: (a) unmetered supplies; --these deficiencies may be caused by consumer malpractice (unauthorized direct connections to the supply system), failure to open accounts and incorrect meter installation which allows part of the load to bypass the meters; (b) errors of meter installation (this category includes wiring defects, mis-matching of metering equipment such as CTs and PTs, tilted meters etc.); (c) meter defects including faulty calibration, slowing due to ageing or by deliberate tampering with the meter mechanism; (d) (i) incorrect readings or (ii) incorrect estimates (e.g. premises/meters inaccessible, defective meters including those removed and new meters yet to be installed); (e) incorrect transfer of the readings to the billing system (some of the readings may not be transferred at all); (f) failure to include some consumers in the billing system (preventing the issue of bills although meter readings may be regularly taken); (g) billing system deficiencies such as inability to process bills due to mis-match of consumer records; and (h) incorrect computation of bills (errors in key records such as meter constants). 7.2 Since non-technical losses are either caused by instrument! procedural errors or by wilful pilferage, they can in theory, be completely eliminated with careful management of meter installations, meter reading, consumer billing and associated services. Furthermore, implementation of measures to reduce such losses will not require the level of investment and time associated with the reduction of technical losses. Thus in systems which exhibit appreciably high non-technical losses, substantial financial gains can be obtained by their reduction. For this purpose suitable monitoring and control procedures need to be established to cover a range of activities commencing with the connection of the consumer to the system, - 54 - through initiation of billing records and accurate meter readings on a regular basis, down to the final issue of bills. To rectify existing anomalies extensive field investigations are required to ensure that the actual consumption in the system is correctly metered and billed for. However reduction of non-technical losses will not result in an equivalent drop in demand as would be achieved in the case of technical loss reduction. Nevertheless, some load reduction is to be expected due to consumers restricting the consumption which hitherto was partially or completely free. 7.3 During the study a number of field tests were carried out in order to estimate the extent of non-technical losses in the system as well as to ascertain their causes. Tests were carried out for both bulk supply and retail consumers. The former category are the power consumers charged on the basis of both energy and maximurn demand; many of these are being supplied at medium voltage. The latter category is supplied at LV and charged only for energy supplied. While the majority of connections are made to retail consumers the greater proportion of consumption is from the bulk consumers. It should be noted that the field tests carried out during the study represents only a very small percentage of the total load in the KPLC system. Thus while indicative figures can be obtained from these tests KPLC should continue with the exercise on a regular basis to obtain more meaningful inforrnation. Aspects of KPLC's billing system relating to the control of non-technical losses were also examined. A particular matter of concern was the usefulness of the current 'exceptions reports' produced by the billing system to assist in tracing inaccurate bills. KPLC counterpart personnel assigned to the study, assisted by consultants and ESMAP staff, carried out the field work and related investigations. Apart from the information provided and the additional revenue gained by the detections, the exercise proved to be valuable training experience to enable such activities to be made a continuous exercise. Meter Testing Methodology 7.4 Two methods were used for field testing of meter installations during the study. In the more accurate method employed, specialized microprocessor based recording instruments described in section 3 (paras. 3.6 and 3.7) were used for a limited time in series with the existing meter installation. These instruments provide accuracy levels of the order of +/- 0.5% and can be considered to be on par with field calibration instruments. However, due to the time available and the use of these instruments for measurement of system loading data (needed for the technical studies) only limited application was possible for non-technical loss investigations. 7.5 In the other testing method employed a hand held instrument was used to determine the load current and power factor over a short time interval, measured with a stop watch. The calculated value of the energy supplied during this time was compared with that recorded by the meter (obtained by multiplying the revolutions of the meter disc with the meter constant). The method is acceptable if the power flow remains substantially constant over the measuring period. Therefore, when load fluctuations were observed the test was interrupted and repeated once steady power flow conditions reconimenced. These tests do not detect errors due to tampering of the internal mechanism of the meter preventing the accurate conversion of disk rotations to registered units. While such tampering is possible they are in practice, very - 55 - infrequent. In order to validate the accuracy of the method a sample of the installations (from the bulk supply consumers tested) were revisited and the meters checked a second time using one of the microprocessor based recording instruments. The comparison of the results of this verification is shown in Table 7.1 below: Table 7.1: Accuracy of Measuring Method for Non-Technical Loss Investigation Consumer Account Number Error Percentage of Installed Meter Quick Test Accurate Test 194201860 -32.0 -38.4 199509570 -62.3 -62.9 194206510 -35.9 -27.9 194208360 -9.8 +0.05 299510500 +0.05 +0.03 194209340 -1.4 -0.8 153427001 -16.2 -0.5 199502111 +4.9 +0.5 Note - indicates under recording + indicates over recording 7.6 The comparison of the results of the two tests indicate that the simple method used is very effective for quick determination of the accuracy of the meter installed. Of the 8 installations tested by both methods, six showed remarkably close readings while two showed divergences of 15% and 10% respectively, in both instances the meter error reducing at the second, more accurate test. It may also be noted that the tests were carried out on different days and at different loading levels and it is even possible that any meter tampering present during the previous day was rectified by consumers who were alerted by the testing activity. This rather simple method of checking meter accuracy was used to undertake a preliminary level testing of consumer installations. If substantial deviations were observed the installations were subjected to more accurate tests to determine the extent of error as well as the nature of the defect. Furthermore, during the process of rectification and assessment of arrears (which were or will be carried out by KPLC's operations units on all defective installations detected) more information on the extent and nature of the defect will be obtained. This method has the advantage of being able to test a large number of installations within a short time. MV Bulk Power Consumers 7.7 Tests were carried out on a number of bulk metering installations for power consumers supplied at 11 kV or higher voltage by using the microprocessor based measuring instruments and installations showing errors larger than 3% were considered as being defective. Out of the 41 consumers tested 8 installations (19.5%) were found to be defective, leading to a loss level of 1.94% for the entire sample. Of the detections made, one installation had a loss of - 56- 24% and two were over 15%. Both the percentage of errors and losses detected in Mombasa greatly exceeded that of Nairobi and this result requires further investigation by KPLC. Of 33 consumers tested in Nairobi 5 were defective, resulting in a loss level of 1.4%. In Mombasa, out of only 8 consumers tested 5 detections (62.5%) were made, resulting in a loss level of 5.3%. The results of the investigations are summarized in Table 7.2 below: Table 7.2: Non-Technical Losses from Investigation of MV Bulk Supply Consumers No. Total Monthly Total Monthly Units % Energy Group Tested No. Faulty Consumption Lost Loss of Sample Nairobi 33 5 5,089,423 72,376 1.42 Mombasa 8 5 786,260 41,893 5.33 Total 41 8 5,875,684 114,270 1.94 LV Bulk Supply Consumers 7.8 Testing of a number of LV bulk'5 supply consumers were also conducted, this time using the hand held instrument and stop watch method described in para 7.5 above. The samples were selected on a random basis from consumer lists as well as from the 'exceptions' lists generated by the billing system. The results of the investigation are summarized in Table 7.3 below. 7.9 The divergence of the meter recordings from the measured values contained many instances with an error range of +/- 10% followed by a smaller group with errors over 14%. In order to concentrate on installations with the largest contribution to non-technical losses and to eliminate those caused by the inaccuracies of the method used, only differences greater than +/- 10% were further investigated. This criterion is expected to capture all major metering errors caused by incorrect connections and meter tampering. However other errors where the reduction in units captured is relatively small will escape this selection. Uncaptured defects will particularly include meters falling out of calibration (caused by the tendency of meters to slow down with time due to damping and frictional effects). 7.10 A number of instances where the meters recorded values higher than measured were also observed within the excluded range. The number of such instances seem to indicate that meter calibration is more often allowed to err on the side of excessive readings. KPLC's standard of allowed meter error is plus or minus 3% which is high by standards used in other utilities (generally not exceeding 2%). Instances that showed higher meter deviations were is These are consumers generally over 25 kVA and supplied directly off a transformer station. - 57 - passed on to KPLC's commercial operating units which investigated the matter further. A few instances where the over reading exceeded 3% were detected and such meters were replaced. Table 7.3: Non-Technical Losses from Investigation of LV Bulk Supply Consumers Energy No. Total Monthly Total Monthly Loss of Group Tested No. Faulty Consumption Units Lost Sample Mombasa Random 54 9 2980249 147655 4.95 Mombasa Exceptional 27 1 1994385 3755 0.19 Nairobi Random 55 4 1611964 114399 7.10 Nairobi Exceptional 53 9 1258984 77915 6.19 Totals 189 23 7845582 343724 4.38 Note: Although 278 installations were tested in all the results of only 189 is presented here in view of the fact that the determination of the units lost etc. is not concluded in the remaining cases. 7.11 The overall percentage energy losses detected amounted to 4.38%. Considering the detections from both lists, the figure for Nairobi (7.66%), was considerably higher than that for Mombasa (3.32%). Furthermore the number of installations detected with non-technical losses arnounted to 14.2% of those examined (in this instance Nairobi recording 11.4%, a lower value than that for Mombasa, 17.6%). The percentage of non-technical losses detected, both in terms of energy lost and in the number of detections are exceptionally high and represent a substantial drain on KPLC's revenues. If the results of the sample studies are typical for this category of consumers (tariff category B), the 4.38% loss level corresponds to 25 GWh per annum representing KSh 45 million. This indicates the urgency of introducing a program to track down non-technical losses and ensure the billing of all energy consumed. 7.12 During the tests, the installations were also examined to identify possible causes of inaccurate readings, such as incorrect connections and evidence of tampering with the metering equipment. The results of these investigations (on 278 consumers), classified according to the type of defect are presented in Table 7.4 below: - 58- Table 7.4: Summary of Defects Detected on Bulk Supply Metering Observed defect nos. % of defects 1. CT faulty I 2. CTs mismatched with meter 1 ) 24% 3. meter running slow 6 4. meter shows signs of tampering 6 - 18% 5. CT short circuited 3 6. CT open circuited 1 ) 18% 7. PT fuse blown 2 ) 8. wrong PT wiring 1 9. wrong CT wiring 4 ) 15% 10. meter bypassed 2 - 6% 11. faulty demand meter 6 - 18% Total inspected 278 Defective installations 33 Percentage defective 12% 7.13 24% of the detections were caused by faulty equipment. Meter tampering and defects in the CT's and PT's accounted for 18% each. Since it is also probable that a substantial number of defects in the CT's and PT's are also caused by illegal tampering with the metering installation --as in the case of short-circuited CT's-- this would increase the percentage of tampering to over a third of all detections. Wiring defects accounted for 15% and in 6% of the detections the supplies were only partially metered. 7.14 Following the findings of the investigations, arrangements were made with the Commercial Operations Division to rectify the defective installations and to recover arrears due. This process is necessarily time consuming involving notifying the consumer (often leading to protracted discussions), installation of new meters and assessment of past consumption after a trial period with the new meters. To date arrears for low billings amounting to KSh 2,057,041 have been recovered from 13 such consumers. In addition, all suspected defective metering installations have been replaced thus reducing the continuation of the under billing. The estimated additional monthly revenue which would be recovered from the 33 detections corresponding to 0.5 GWh and 2.5 MW maximum demand, valued at approximately KSh. 2.5 million (per month). 7.15 An interesting finding relevant to both Nairobi and Mombasa is that the selection of installations from the exception lists --provided by the billing system-- resulted in lower percentage losses than those selected on a random basis. The same situation applies to the number of detections, if the detections from Nairobi and Mombasa are taken together --8.1% from the exception list and 16.0% from the random list. This indicates that the reporting system - 59 - for exceptional consumption needs careful investigation and re-design. One probable reason is that most installation defects have been in place for so long that the average recorded consumption (on which the exception report is based) has no bearing on the accuracy of the readings. Retail Consumers 7.16 Two methods were used to obtain an estimate of the non-technical losses present in supplies to retail consumers. The first method involved energy audits of systems supplied by three transformer stations. The energy supplied (output of the transformers) adjusted for technical losses in the network was compared with the sum of the metered consumption for all connected consumers. The initial readings of the bulk meters measuring the supply input was made at approximately the mid-period of the meter readings taken on the individual consumer installations (to reduce discrepancies resulting from the non-coincidence of the readings). Further, the recording of such readings was repeated monthly over an extended period (14, 16 and 17 months in the three samples) to even out any discrepancies due to estimated consumption and other over/under charges which would be corrected in subsequent billing periods. 7.17 Two of the transformer stations supplied overhead (OH) lines with 139 and 119 consumers respectively while the third transformer supplied an under ground (UG) cable system and had only 29 consumers. Technical losses (energy) of the two OH systems were computed to be 1.6% and 1.2% respectively while the technical losses of the UG system were estimated to be lower than 0.2%. However, for the non-technical loss analysis a conservative estimate of 2% and 0.3% was used for technical losses of the OH and UG systems respectively. The results of the study are summarized in Table 7.5 below. Non-technical losses of the overhead systems amounted to 7.7 and 8.6% respectively while the UG system showed losses less than 0.5%. The overall non-technical loss calculated for all three systems was 7.6%. While losses computed for each individual month showed some variations the results generally were comparable with the overall findings. (High readings for some months being offset by low readings in subsequent months --the aggregation generally producing consistent results). Table 7.5: Results of Energy Audit Study of Retail Consumers Energy Technical Non-Technical % Non-Technical Substation Supplied Energy Billed Losses Losses Losses SS2261B 508931 459524 10179 39228 7.7 SS4522B 503770 450645 10075 43050 8.6 SS4440B 82571 81947 248 376 0.5 Total 1095272 992116 20502 82654 7.6 - 60 - 7.18 In the second method employed, the hand held power meter and stop watch method (see para 7.5) was used to investigate a number of retail supplies selected at random. The results of the study are presented in graphical form in Figure 7.1. Of 101 installations tested only 58% were within an error margin of +/- 5%, the proportion extending to 86% if the error margin is increased to +/- 10%. The possible error margin of this test was discussed in para 7.6 on the basis of a comparison made with superior test equipment. The use of this method for retail supplies would involve a slightly higher margin of error due to the lower current levels, higher load fluctuations and shorter time spent in conducting the test. However, the primary purpose of the test is to detect instances with high contribution to losses while carrying out as many tests as possible within the limited time period. If instances with errors over 15% are examined it is found that there is one which recorded 16% in excess consumption and eight which recorded lower consumption by between 20 and 100%. These eight meters were examined closely, confirming the defects. One meter had stopped and failed to record any consumption. Another was barely moving (recording only 3.4% of the actual consumption); of the other six (errors ranging between 22 and 60%) one showed clear signs of tampering, one was tilted to an unacceptable level resulting in a low reading and the other four were confirmed as reading low. 7.19 From the data above it was concluded that about 8% of the meters in the sample register substantially lower than actual values (errors over 20%) for the energy consumed. There is also the possibility that some meters record consumption higher than the actual values, but it is unlikely that the over billing will be close to the under billing that occurs in the system. The confirmed detections of low reading meters indicate that the non-technical losses in the sample are equivalent to about 4.5%. This figure may be compared to the loss level of 7.6% obtained with the energy audits of the LV systems (see para 7.17). 'Dead' Accounts 7.20 Buildings for which power supply accounts have been disconnected for various reasons and remain so over extended periods are potential sources of non-technical losses. The majority of the disconnections arise from consuners moving out of the premises and from those whose accounts are terminated for non payment of bills. In both these categories it would be reasonable to expect the new occupant or the defaulting consumer to apply for a reconmection within a short period and it will only be in special circumstances such as the demolition of buildings that a subsequent application for reconnection will not be made. KPLC's billing system contains a procedure to identify such accounts. At each billing cycle a print out of such disconnected consumers (termed 'dead' accounts) is provided and these installations are expected to be checked by field investigators to ensure that irregular reconnections have not occurred. A total of 65 such 'dead' accounts were inspected during the study resulting in the following observations: (a) Accounts corrected and supply restored: 42 (b) Closed accounts with meters and services removed; 9 (c) Closed accounts but meters not removed: 14 Total inspected 65 -61 - 7.21 In categories (a) and (b) the required actions have been correctly taken. In (a) either the same account had been restored with the same or different meter or a new account opened for a new occupant; in (b) the account is terminated and the service connection and meter had been recovered. Accounts under item (a) should not be continued to be listed as 'dead' accounts. Since 65% of the listings were items which should have been purged, the lists are unnecessarily long. This has a detrimental effect on the quality of checking as it diverts the investigators from installations that require to be targeted. It is also preferable to list accounts under item (b) separately from those under item (c) to facilitate the supervision activities. The removal of the service connections (wires connecting the building to the distribution lines), 'cut- outs' and meters of these consumers prevents the most frequent method of obtaining fraudulent supply --by a meter/cut-out bypass. These buildings may still obtain illegal supply by devices connected to the distribution lines or from extensions from adjoining consumer installations. However for control purposes it is preferable to present these installations under a separate listing. It is therefore recommended that suitable procedures be instituted to ensure that the dead account lists are maintained in a manner which will better assist those carrying out the investigations. 7.22 In category (c) representing 14 installations (or 21.5% of the sample) the power connection (up to the supply cut-outs) and the meter had been allowed to remain for periods generally exceeding one year after the accounts were closed. It is this category that should be treated as the "true" dead accounts. In 4 instances (representing 6% of the total investigated and 29% of category (c)), the reading at the time of inspection was in excess of the final reading at date of disconnection, indicating that uncaptured consumption had occurred through the meter after the date of disconnection. This consumption represents a non-technical loss. In one instance the consumption after the disconnection date was as much as 64,731 kWh (representing as much as 40 times the annual average consumption for a typical domestic consumer in Nairobi). In the other three instances the unrecorded consumption amounted to an aggregate of 3494 kWh (representing 26 months of average consumption). In none of the cases investigated was there any direct evidence of by-passing the meters. However, the investigation carried out at each installation was not sufficiently comprehensive to detect such instances in view of the time required for such an exercise. Some form of fraud could still occur particularly in installations of category (c). In order to verify such possibilities a joint ESMAP and KPLC team made a detailed check on 3 of these installations including a night visit (to ascertain whether electrical lighting was being used in the premises). This investigation revealed that one out of the three houses had obtained supply by an unauthorized extension from a neighbor. (Although this connection did not contribute to a non-technical loss as the consumption was recorded via the meter of the other house, it was a violation of KPLC's supply regulations). 7.23 The following conclusions may be drawn from the investigations carried out on retail installations no longer active in the billing process ('dead' accounts): (a) about 65% of disconnections carried out are eventually reconnected to the same or a different consumer within about one year. However the billing software and associated procedures do not capture such reconnections, and the installation - 62 - continues to be listed as a 'dead' account. This hampers and complicates the control process and does not assist the field investigators to focus on the installations that require investigation; (b) contrary to KPLC's regulations, meters and services were not removed from about 61% of the premises that have been disconnected and remained disconnected over an extended period, thus providing an opportunity for unauthorized connections; (c) about 17% of premises remaining disconnected could be expected to continue consuming some power after being removed from the billing system. 7.24 Based on the findings of the study, the following recommendations are made to improve KPLC's procedures concerning consumers disconnected from the billing system: (a) ensure that premises which are subsequently officially reconnected are removed forthwith from the listing of dead consumers; (b) it is necessary to ensure that KPLC's existing regulations concerning the removal of service connections and meter installations are enforced when the premises remain disconnected over an extended period (about 3 months); (c) systematic checking of premises that remain disconnected is needed to ensure that these premises do not obtain illegal connections. Consumer Billing System 7.25 The consumer billing system in use during the study"6 is one which was installed in the late 1970's. Since then, KPLC's power system has undergone considerable expansion with a tripling of power generation and a doubling of the consumer base. Much of the hardware is now in a poor state of repair and frequent breakdowns (often involving long periods of down time) disrupt the billing operation. With a total invoice level of KSh 4000 million per year, a single day's delay in processing bills (and consequently revenue collection) sustained over a year, may be valued at about KSh 1 million in terms of lost interest. Furthermore, all related equipment (including printers, storage media, access terminals) are now nearing the end of their technical life and there is imminent danger of a complete breakdown. Such a situation would result in substantial financial loss and operational problems to KPLC. 7.26 Given the shortcomings of the facilities in use, the billing system performs fairly well without serious discrepancies. The billing program is well documented and KPLC has a 16 KPLC has since made arrangements to procure a new billing system and at the time of this report the new system in being installed. - 63 - limited number of experienced personnel competent in its operation. Meter readings are taken in books and forwarded to a manager of the section who performs a brief visual check on the readings before dispatching them to the head office electronic data processing (EDP) section where the data entry takes place. Some tests on the validity of the data are carried out in the EDP section and corrections are sometirnes made without the approval of the area office. The billing is then done on a batch oriented system. 7.27 A major weakness of the system is the inability to maintain the data on connections and reconnections as well as threshold values for exception reports in a current state. As was seen in the discussion of the non-technical losses of LV bulk supply consumers (paras 7.8 to 7.11) and the discussion on 'dead' accounts (paras 7.20 and 7.21) the reports generated for the control of non-technical losses are of little value. 7.28 A utility's billing system should retain valuable information required by many functions within the organization and be capable of coordination with other data bases. Current computer technology (particularly information systems based on relational data bases) presents an excellent opportunity in this connection. Establishing a meter history follow-up record is an important area of application. Identifying consumers in relation to network connections (feeders and supply transformers) can help in monitoring system losses and in obtaining loading data required for planning purposes. Transformer load management is another application of correlating the billing data with the consumer supply location. KPLC will therefore benefit greatly from a more versatile and up-to-date billing and information system. In view of the age and poor operational state of the present computer system, both software and hardware, it is recommended that action be taken to obtain a new system with the least possible delay. Conclusion and Recommendations 7.29 From the investigations made on non-technical losses of various categories of consumers we may conclude the following: (a) MV bulk supply consumers - Approximately 20% of metering installations were faulty resulting in a loss of the order of 1.9%. The incidence of losses in Mombasa was exceptionally high (60% faulty with losses of 5.3%) and needs to be scrutinized further. (b) LV bulk supply consumers - Approximately 12% of metering installations were faulty resulting in losses of the order of 5%. (c) The major causes of losses in the LV bulk supply group were: faulty or mismatched meters and CTs (24%), tampering of meters (18%), CT or PT links tampered/defective (18%), - 64 - Faulty maximum demand meters (18%), wiring defects (15%) and load bypassing the meter (6%). (d) Retail (LV) consumers - The audits carried out in three networks resulted in the identification of losses of the order of 7.6% while individual testing of meters resulted in a loss detection amounting to 5.0% (caused by 8% of consumers). Some meters were also observed to read higher than the actual values. (e) Energy consumption continued in 7.7% of the installations reported as disconnected and dropped from the monthly billing. (f) Billing system procedures which provide exception reports and information on 'dead' accounts are not up-to-date and sufficiently selective to be of much use in tracing non-technical losses. Recommendations 7.30 A substantially large number of irregularities were detected during the investigations of non-technical losses, representing approximately 5% of the energy supplied to consumers. This indicates that a concerted attempt needs to be made by KPLC to reduce such losses. It is therefore recornmended that a systematic and comprehensive non-technical loss reduction program be instituted. The experience in Kenya, as well as in other countries where similar work has been carried out, indicates that the main thrust of the work should be bome by specially assigned task forces rather than relying on line management. This observation does not detract from the recommendation that the ability of line management to improve its procedures and techniques for the detection of non-technical losses should be strengthened. However, taking cognisance of the magnitude of the problem and the number of routine tasks which occupy line management (which cannot be avoided) it is not realistic to expect to have this function attended to successfully under present conditions. The task forces should be seen as a service to line management in carrying out a crash program and establishing proper procedures which can thereafter be maintained in a satisfactory state by the line management. Accordingly, proposals to carry out such a program by establishing three special task forces are presented below. 7.31 The other major area associated with non-technical losses that needs immediate attention is the introduction of new computer billing and data base systems in line with current technology. Some recommendations on the selection of such a system are provided below. Special Task forces 7.32 As discussed above, the control of non-technical losses is best carried out by special task forces. These groups should coordinate closely with operational personnel and other functional groups, such as those in the billing and commercial departments. Three task forces - 65 - are recommended for the exercise for: (a) meter inspections, (b) consumer verification and (c) rectification of anomalies detected. The main tasks of these groups are as follows: (a) Task force for meter inspections (i) Establish a non-technical loss monitoring task force in each operating Area to carry out field checks of both bulk and retail meters. The personnel should be specially selected and used exclusively for this exercise --at least during the initial period during which targeted loss reductions are to be achieved. (ii) The field tests may be carried out in approximately the same manner in which the exercise was conducted during the ESMAP study. However a larger number of standard field testing meters and microprocessor-based instruments is recommended. Accordingly KPLC should purchase a sufficient quantity of such equipment. (iii) For bulk consumers the testing should be carried out on a comprehensive basis visiting all consumers on a feeder by feeder basis. For retail consumers tests may be carried out on a more selective basis by examining the billing history of consumers (of each L.T. supply scheme or area) subject to a minimum percentage being checked from each scheme or area. (iv) During this exercise all defects in the installations should be rectified forthwith, including replacement of poor wiring installations and replacement of seals. Hence the task forces should be properly equipped with materials and equipment to carry out this work. (v) For greater security against meter tampering the existing lead seals should be replaced by padlock (Hoop) seals for meters and cutouts during the exercise. (b) Consumer verification exercise (i) A consumer verification program should be arranged in coordination with meter reading staff (both for bulk supplies and retail supplies) to ascertain whether all consumers connected to MV and LV lines are included in the billing system. As this would involve additional time and effort it is suggested that one or even two billing cycles be made on an estimated basis for each area under investigation and this extra time available used to undertake a systematic examination of all premises supplied from the system. Since this exercise can be carried out successively from one small area to another (either by feeder or billing/meter reading group), the suggested billing estimation would not occur simultaneously for all - 66 - consumers. Careful attention should be made to ensure that the overall program is carried out systematically. The person or persons conducting the test in each area should be recorded along with the results and systematic documentation made on the findings. (ii) The consumer verification exercise may be combined with obtaining information required for the improvement of the distribution system data base; such as, account numbers of LV consumers connected to each transformer and bulk consumers connected to each MV feeder, etc. (iii) The main purpose of the exercise is to ensure that all those obtaining supply from the system are recorded in the billing system and properly metered. Accordingly each MV and LV feeder should be followed along its route and all connections checked. (iv) A moratorium may be advertised inviting consumers to declare if they are aware of any defects in their metering installation or if they do not receive bills for the supply provided. When consumers volunteer information, a system of waiving arrears resulting from previous anomalies may be introduced. (c) Rectification of anomalies detected (i) A special group/s (based in the head office or the regional offices) should be entrusted with the task of speedily rectifying the discrepancies noted during both the meter inspection and consumer verification exercise. If necessary this group should be authorized to discuss and negotiate with the consumers on any assessed consumption and fines applicable. The emphasis should be on speedy rectification of the anomalies rather than an attempt to collect all arrears. Many exercises of this nature have been thwarted by protracted delays in negotiation with the consumers (who often have legitimate concerns that need to be equitably resolved). (ii) This group should also scrutinize all 'dead accounts' and other anomalies in the billing system and establish a 'clean' and accurate consumer record file. (iii) Coordination of the activities of the two groups on meter inspection and consumer verification should be attended to by this group. - 67 - Billing System Changes 7.33 A completely new computerized billing and consumer data base system is necessary for KPLC in order to meet its current needs. The development of a new system may be based on the following characteristics: (a) General enviromnent (i) The billing system should be a part of a larger information technology (IT) platform using 4th generation languages and system development methods. (ii) An information resource strategy should be developed which specifies data sharing policies, data base management systems and data security. (iii) The hardware purchases should have KPLC's long term IT needs in view. A coordinated policy for mainframe equipment, servers, storage devices, printers and other peripherals needs to be developed. (iv) An enhanced electronic data processing (EDP) organization must be developed within the Company and selected personnel trained in the various functions and disciplines involved. The need to invest in high- level recruitment and training combined with a good remuneration package cannot be over-stressed as the lack of capable staff will prove to be very costly in the long run. (b) Software capabilities (i) The software should be capable of providing shared data for various functional units including those on billing history, meter inventory, meter and installation service particulars, system data required for distribution planning (based on geographic coordinates). (ii) The meter reading entry should be in an on-line environment which will reject incorrect data and flag these for verification. (iii) On-line query facilities should be available at all Area offices and other selected customer service centers. (iv) Updating of consumer information such as reconnections, new account numbers to previously discormected installations etc. should be coordinated in the data base so that all relevant data updating takes place simultaneously. - 68 - (c) Billing/meter reading procedures (i) The meter readings must be made on computer printed lists obtained from updated consumer lists and should not contain the previous readings. The meter readers should not have access to the previous reading in order to avoid possible estimation of the readings without actually visiting the site. In addition to recording the reading there should be provision for him to report any irregularities such as incorrect meter number, tampering with meter or seals. (ii) Data entry and initial validation may be done at the Area control offices and any irregularity checked by a special team before bill calculations are commenced. This requires an EDP extension to the Area offices. (iii) The validated readings may be transferred to the head office billing center by diskette or electronic transfer if facilities in Kenya allows such use. (iv) An effective procedure needs to be developed for the exceptions reporting system to be sufficiently selective for use in tracking down cases of non- technical losses. (v) Procedures should be developed to control and monitor the meter reading independently of defects reported by the billing system. As an example, sample checking of the readings may be carried out by supervisory personnel who will input such data regularly and produce an exceptions report if irregularities are found. The meter readers should also be regularly rotated among the different routes and a statistical control made of meter reading errors for which each meter reader is accountable. Improvements Under Implementation 7.34 During the finalization of this report KPLC has commenced the process of implementing a number of improvements in non-technical loss investigations and the consumer billing system. Actions being taken in this regard include the following: (a) a permanent task force has been established to investigate bulk supply metering and billing. The team is based in headquarters and will cover each KPLC operational area in turn investigating all bulk supply consumers during each exercise; (b) retail consumer audits are being carried out by special teams which carry out random checks in each area; - 69 - (c) all new large consumer installations are being verified by a senior engineer as a preventive measure; (d) an on-going program exists for replacements of aging meters; (e) meter readers are being supervised more closely; (f) a new billing system is presently being installed and will eventually lead to a fully integrated IT environment combining customer billing, data processing and management information. A new Management Information Systems division has been established to carry out these functions. - 70 - Fig 7.1 ERRORS DETECTED -LV RETAIL SUPPLIES 20 10 0 -10 -20 o -40 -50 -60 -70 -80 -90 -100- -110 The graph demonstrates the results of using a hand held mete-r and stop watch to detect meter errors in retail consumer installations. No. of installations tested - 101 installations wvithin +-5% error - 58% installations within IO 1% error - 86% meters over-reading, by 15% or more - 1 installation (+16%) meters under-reading by 15% or more - 8 installations (ranging, from 20 to 100%) -71 - VilI. GENERAL CONSIDERATIONS Lessons Learned 8.1 The study provides a number of useful lessons for conducting loss reduction and distribution planning functions for developing country power utilities. High growth rates, expansive nature of the networks and sub-optimal investment in distribution systems over many years (in comparison to generation and transmission investment) in many developing countries have increased the feasibility of highly economic investment opportunities. In addition, there is a considerable scope for recovery of unbilled consumption. Thus, loss reduction and distribution planning activities are often found to result in substantial improvement in the utility's financial performance. Listed below are some important lessons leamt during the execution of the present study and key issues to be addressed for successful implementation of such projects. Particular Characteristics Of Distribution Systems i. An extensive data base needs to be established to carry out effective planning of distribution systems. Computerized techniques (such as digitizers, specialized planning software and electronic measuring instrurnents) are now available for the collation and analysis of this voluminous data base. Although some time would be required initially to train the necessary staff in using the new techniques, once this is accomplished the work can be carried out expeditiously and efficiently. ii. The establishment of the data base involves simple repetitive tasks covering the entirety of an extensive network. Furthermore, the characteristics of distribution systems change frequently and there is need for regular monitoring and updating of information. Knowledge of local conditions and familiarity with the terrain is also of considerable importance in distribution planning work. For these reasons external consultants are not effective substitutes for the utilities' own staff'7. External support is however useful in establishing the new techniques and in training activities. Once such a unit is established, the data base should be regularly expanded and updated and periodic planning studies carried out. Organizational Issues i. This ESMAP activity demonstrated that building a successful in-house distribution planning unit can be achieved given the interest and commitment of 17 In contrast transmission and generation planning can be perforned by extemal experts with minimal local support (although it is best to have local staff trained in this aspect as well). - 72 - the utility personnel. The proliferation of computerized technology combined with the high interest shown by the younger professional cadres augers well for the successful establishment of such units in developing countries. ii The studies involve combining the specialized new computerized planning activities with the field data concerning system and load characteristics. In view of the day-to-day responsibilities of operational staff, assigning the overall responsibilities to in-line management often fails to produce the desired results. Thus, the activity is best introduced by establishing a dedicated unit with staff having system planning background. This unit however, must establish good coordination with operational staff to ensure that the field data and assumptions regarding future load development is realistic. The best way to establish a strong relationship is to ensure that operational staff is regularly supplied with the results of the planning studies and a consultative process established for mutual benefit. A consolidation of this coordination is often only achieved when the benefits of the analysis are used in resolving operational problems'". iii. Conflicting demands arise with respect to the placement of distribution planning unit/s within the utility organization structure. In keeping with the trend towards decentralization of distribution operations, it would be advantageous to establish a planning unit at each of the main distribution operations divisions. On the other hand, the need to develop the specialized competence in the techniques used, limited availability of suitable staff as well as funds for the necessary equipment favor establishing a central unit, perhaps within the central planning division. This dilemma is best resolved by first introducing a central unit with the necessary facilities and subsequently decentralizing the responsibilities in a gradual manner, still retaining the technical competence of the central unit. Good dialogue and exchange of data and study results are necessary between the central unit and distribution operations. The central unit may also exercise overall responsibility, maintain records of important data and review and approve the work of the regional units. 18 During the studies a number of instances of such support to resolve operational problems arose which helped to institutionalize the role of the study unit. - 73 - Planning Studies and Development Proposals 1. It is observed that loss reduction investigations are extremely beneficial (even in a country such as Kenya, with loss levels substantially lower than in many developing countries) and lead to investments with high economic and financial returns. ii. Development proposals should be considered from a systemic concept; network demands in meeting load growth, improving system reliability and reducing losses being addressed simultaneously to obtain the best results. Consideration of only any single one of the benefit categories (e.g. loss reduction) will, in many instances, lead to sub optimum investment. iii. The sequence of network developments to be considered in a planning exercise varies for long term and short term options. A convenient sequence of examining long term developments is to follow the hierarchy of the power flow, investigating suitable investments required at each stage. Accordingly, the following sequence of network improvements is an useful guide in carrying out a long term system development study: MV systems - (a) introducing new substations; (b) introducing new feeders; (c) rationalization of feeding arrangements; (d) reconductoring line sections; (e) reactive compensation (capacitors); LV systems - (a) decentralization of networks with increased transformers and reduced secondaries; (b) rationalization of feeding arrangements; (c) reconductoring of line sections. In addition phase balancing of LV systems is an efficiency requirement irrespective of the other options considered. iv. The long term solutions may be generalized as network 'decentralization' strategies; increasing substations and feeders in the case of MV systems and increasing distribution transformers (thus reducing the lengths of secondaries) in LV systems. Rationalization of feeding arrangements and reconductoring line sections offer secondary opportunities to improve network performance. - 74 - v. When short term solutions are required to redress immediate operating problems the sequence of options may generally be tried in reverse (in view of time limitations) i.e. the first options being reactive compensation and reconductoring of heavily loaded sections for MV systems and reconductoring and rationalization for LV systems. Often the two strategies (short and longer term solutions) need to be combined, the time period required for commissioning of long term solutions being filled in by the short termn options. A particular example being reactive compensation which can be used within a very short time to relieve poor voltage conditions. When their effects (at a particular location) are diminished with subsequent network developments they can be moved to other locations offering more promising benefits. vi. The use of network optimizing programs should be applied with due consideration to assumptions used in the software. As observed during the study some assumptions used in optimization techniques of particular programs may not correlate with actual field conditions. vii. Simple spreadsheet based techniques may be effectively used when quick computations of losses and voltage conditions are required, particularly when system maps etc. are not available for a digitizing exercise. viii. Low average overall losses in a particular area do not necessarily signify that economic investments are not possible. Feeders with high loads situated close to supply substations tend to mask the high loss feeders when aggregate values are considered. Thus either a feeder by feeder analysis or a preliminary screening exercise is necessary to identify poorly performing feeders. Non-Technical Loss Reduction i. Dedicated task forces are the most effective medium of detecting and rectifying non-technical losses. ii. The tasks may be segregated to meter inspections, consumer verification (or census) and rectification (including negotiation/agreement on arrears with the consumer and correction of billing system records). The three operations may be carried out by separate teams but need to be well coordinated. iii. Exception reports and other triggers in the billing system need to be effectively designed to indicate possible irregularities but remain sufficiently discriminative (so as not to overburden the investigation process). iv. Maintaining the billing system and consumer data base up to date with system changes in the field is the key to preventing many lapses in billing capture. Most - 75 - important in this respect is the timely processing and data entry of system changes (new connections, meter change outs, consumer changes etc.). v. The billing system should be based on current EDP technology (preferably as a part of an overall management information system). vi. Meter reading procedures should be designed to minimize possible errors and inaccuracies. Some measures to be addressed are: meter readers should not have access to previous readings, an independent control and monitoring facility to ascertain the accuracy of readings, validation of readings before entry in the billing process and statistical control of errors by source (e.g. by meter reader). Economic Parameters 8.2 A number of economic parameters need to be valued to facilitate the computation of benefits related to system development proposals. Studies carried out previously in Kenya and elsewhere were used to obtain quantitative values to be used in these computations and no independent investigations were carried out to verify or validate these figures. The LRMC values computed by Acres International in 1991, essentially confirmed by a study carried out by London Economics in 1993, were used as the basis of computing loss reduction and additional capacity (to meet suppressed demand) benefits. In computing reliability benefits, the value of five times the LRMC of energy was taken as a representative figure, based on experience in other countries. The figures used are generally of a conservative nature and the proposals are substantially robust and insensitive to wide variations of these values. It is, however, recommended that KPLC carry out further studies and surveys to improve data on the relevant economic parameters. Particular items that need to be followed up are information on consumer's willingness to pay (including the value placed on system reliability) and the economic costs of outages and supply restrictions (both in the short and long term). In addition, since the LRMC study carried out in 1993 did not differentiate between demand and energy costs it is advisable to carry out the necessary studies to obtain supply costs differentiated on this basis. Improving information on aspects detailed above, will strengthen KPLC's ability to make reliable estimates of the benefits of system development proposals and also improve its knowledge of the dynamics of consumer behavior, particularly for tariff setting and load forecasting exercises. Complementary Issues Impact of Improved Tariff Setting and Load Management 8.3 The present exercise deals with the study of system losses --both technical and non-technical-- leading to the determination of specific improvements to reduce these to economic levels. It is important however, to remember that improvements identified need to be viewed in the context of a broader set of principles and actions that should encompass KPLC's - 76 - overall system development and efficiency goals. These include price and non-price based measures necessary to improve the efficiency of the power system. Among the principle actions relevant in this context are appropriate tariff setting and demand side management activities. 8.4 Modifications required to KPLC's tariffs and their impact on load growth --either on account of any increase to the overall rate or any structural changes within/between the tariff categories-- did not fall within the scope of the present study. Tariff setting is however an important instrument in the management of system load and consequently has an impact on system losses. It may also be noted that higher tariffs provide greater incentives for fraud and require increased utility vigilance. KPLC already uses a ripple control system for interruptable loads provided at a reduced tariff --an important instrument in load management. Improved use of time of day metering and the application of differential tariff rates can play a useful part in influencing the size and shape of the load curve. Similarly, load management strategies such as conservation measures, encouraging the use of efficient appliances and appropriate matching of energy sources with end uses (e.g. LPG for cooking and heating loads) also have an important bearing in altering load patterns. KPLC and the Government of Kenya should improve its attention to these matters in order to realize a broad set of efficiency goals. 8.5 An aspect of load management which will have a substantial impact on recommendations made in this report is the improvement of consumer power factor to offset the need for compensation to be applied on the system. For this reason reactive compensation proposals have been evaluated on the basis of a very short pay-back period. Such short pay back periods (less than 18 months) enable both strategies --compensation at system level as well as improvement of individual power factors-- to be effectively used. A large number of consumers were detected with low power factor during the study and this information can be used to further a program for power factor improvement. Further, as discussed in the report, once the power factor a particular feeder is improved (or alternatively the feeder characteristics are altered by other system developments) the capacitors installed can be shifted to other locations to optimize their usage. In view of the high load growth rates in the Kenyan power system and the fact that only a small portion of the distribution system has been studied, the 9 MVAr of capacitors recommended is expected to be useful (at about the currently forecasted level of annual benefits) over the foreseeable future even in the event of a substantial improvement in consumer power factor. 8.6 In general, the quantitative and qualitative effect of appropriate tariff setting and load management may be considered as the reduction of system load growth and changing the shape of the load curve, respectively. In view of the high load growth rates presently applicable in Kenya the combined effect of these measures (if and when introduced) is not expected to make an appreciable impact on the overall system load. Thus, load management and tariff setting should be treated as complementary actions to and not alternatives for the system development proposals identified in the report. - 77 - Impact on Sector Reform 8.7 Currently there is an increasing trend among developing country power utilities to increase the role of private participation in the sector, particularly by encouraging independent power producers (IPPs). The principal obstacle in attracting IPP participation is the lack of confidence in the utility's ability to generate sufficient funds to be able to pay for the power purchased. Improving distribution system operations by loss reduction --both technical and non- technical-- will result in substantial improvement of the utility's financial position, thus making it more attractive for IPPs. KPLC is also a limited liability company with a substantial portion of its shares being privately owned. Thus improving the financial position of the company will improve the value of its shares and assist in any further divestiture of government interests. Thus, the proposals contained in this report are complementary to and have an important bearing on the success of any contemplated sector reform program. In addition, improving network voltages, system capacity and reliability will also have a major positive impact on the growth in other sectors, particularly industry and tourism. - 78 - KENYA POWER LOSS REDUCTION STUDY ANNEXES - 79 - ANNEX A LIST OF TABLES AND FIGURES Section Al - Loss Calculation Tables and System Characteristics Al.1 - Distribution System Power and Energy Flow Tables Table Al.l.l - Nairobi City Power and Energy Flow A1.1.2 - Coastal Area Power and Energy Flow A1.1.3 - Overall Distribution System Power and Energy Flow A1.2 Loss Calculation of Feeders Outside Nairobi and Coastal Areas Table A1.2.1 - Summary Results A1.2.2 - Loss Calculation of Meru Feeder A1.2.3 - Loss Calculation of Kambura-Kgeni Feeder A1.2.4. - Loss Calculation of Kisii Feeder A1.2.5 - Loss Calculation of Flouspar Feeder A1.2.6 - Loss Calculation of Chemelil Feeder A1.2.7 - Loss Calculation of Moi Baracks A1.2.8 - Loss Calculation of Maralal Feeder A1.2.9 - Loss Calculation of Narok Feeder A1.3 - Examples of Daily Load Curves of Feeders and Consumers Figure A1.3.1 - Lavington Feeder from Karen Substation A1.3.2 - Parklands Feeder from Jeevanjee Substation A1.3.3 - 11/0.4 kV Transformers No. 4080 (Residential Load) A1.3.4 - 11/0.4 kV Transformers No. 0711 (Residential Load) A1.3.5 - Power Factor Variation, Nairobi South Feeder No.2 Al4 and 1.5 LV System Characteristics Table A1.4 - Bulk Consumers Detected With Poor Power Factors A1.5 - Load Characteristics of LV Systems A1.6 - Present Worth Factors for Economic Computations Table A1.6.1 - Conversion Factors for Loss Reduction Benefits A1.6.2. - Conversion Factors for Reliability Benefits Section A2 - Nairobi City Network Analysis Table A2.1.1 - Load Characteristics of Nairobi City 11 kV Feeders A2.1.2 - Load Characteristics of Nairobi City 66 & 40 kV Feeders A2.1.3 - Load Density of 11 kV Feeder Areas, Nairobi City A2.2 - Summary of Load Flow Results 11 kV Feeders, Nairobi A2.3-A2.6 - Results of Economic Analysis Table A2.3 - Proposal for New Substation at Kiambu A2.4 - Proposal for New Substation at Kileleshwa A2.5.1 - Prr-,osals for Reconductoring and New Feeder additions A2.5.2 - Proposals for Feeder No. 30, Lower Hill A2.5.3 - Proposals for Feeder No. 38, Nairobi South A2.6 - Capacitor Installations -80 - Network Diagrams Figure 2.1.1 - Existing System - Kiambu Area 2.1.2 - Proposed System - Kiambu Area 2.2.1 - Existing System - Kileleshwa Area 2.2.2 - Proposed System - Kileleshwa Area 2.3.1 - Existing System - Feeders No. 38 and 69 2.3.2 - Proposed System - Feeders No. 38 and 69 Section A3 - Coastal Area Network Analysis Table A3.1.1 - Load Characteristics Coastal Area Feeders A3.1.2 - Load Density - Coastal Area 11 kV Feeder A3.2 - Summary of Load Flow Results - 33 kV Feeders A3.3 - Summary of Load Flow Results - 11 kV Feeders A3.4-A3.12 - Results of Economic Analysis Table A3.4 - Proposals New Substations at Diani A3.5 - Proposals for Tiwi Feeder A3.6 - Proposals for New Substation at Galu A3.7 - Proposals for New Substation at Bamburi A3.8 - Proposed developments for Malindi A3.9 - Proposals for Improvements to Mazeras and Rabai A3.10 - Proposals for Improvements to Tom Mboya Feeder A3.11 - Proposals for Improvements to Bamburi Feeder from Nyali A3.12 - Application of Reactive Compensation Section A4 - LV System Analysis Table A4.1 - L.V. System Losses A4.2 - Transformer Losses for Varying Loadinc Levels Table A4.2.1A - 25 kVA KPLC Transformer A4.2.1B - 25 kVA Low Loss Transformer A4.2.2A - 50 kVA KPLC Transformer A4.2.2B - 50 kVA Low Loss Transformer A4.2.3A - 100 kVA Low Loss Transformer A4.2.3B - 100 kVA Low Loss Transformer A4.2.4 - Benefits of a Transformer Replacement Program Figure A4.2.3A - Energy Losses of KPLC 100 kVA Transformer Figure A4.2.3B - Power Losses of KPLC 100 kVA Transformer A4.3 - Economic Evaluation of Transformer Losses Table A4.3A - Economic Evaluation of Transformer Losses A4.3B - Computation of Transformer Loss Evaluation Formula A4.4 - LV Network optimization Table A4.4 - Summary of Results of LV Optimization Study LV Network Diagrams for Sample Studv Figure A4.4A - L.V. System Optimization - Proposals in Period I A4.4B - L.V. System Optimization - Proposals in Period II A4.4C - L.V. System Optimization - Proposals in Period III Table A1.1.1 NAIROBI CITY - POWER & ENERGY FLOW Network power flow t%i Network energy flow 1%) Annual % LF Peak contribution % loss Input Losses Sales j % loss Input Losses Sales Sales Sales Factor MW | Power E Energy (GWH) (see note 2) (as % of dist. system input) (see note 2) (as % of dist. system input) Grid SS transformers I 1.00 100.0 1.00 I 0.80 100.0 0.80 66 kV lines 1.43 99.0 1.42 1.06 99.2 1.05 66 kV Consumers 45 3.0 0.75 0.45 3.1 1.0 2.8 11 kV lines | 2.63 96.6 2.54 I 1.84 95.3 1.75 11 kV Consumers 306 20.6 0.60 0.30 17.5 5.6 j 19.3 LV transformers I 1.10 88.4 0.97 f 0.70 74.3 0.52 LV direct lines | 1.00 87.5 0.87 f 0.50 73.8 0.37 1 LV Direct sales 305 20.5 0.55 0.30 19.0 | 6.1 I 19.2 OD LV retail lines I 5.40 80.5 4.35 j 3.60 54.2 1.95 LV Retail sales 830 55.9 0.40 1.00 236.9 I 76.1 52.3 Total 1486 100 276 I 88.85 I 93.6 Technical losses 102.0 34.3 I 11.15 | 6.45 Non-technical losses 74.0 24.6 | 8.22 I 4.75 Total losses 176.0 58.9 | 19.37 | 11.20 System Load Factor 0.58 Note 1: The first section of the table converts energy sales to peak power by using peak contribution factors. Network power and energy losses are calculated in the second and third sections respectively. After computing the technical energy losses non-technical energy losses are determined by the difference with the overall measured loss value. Non-technical power losses are determined by assuming the same ratio (non-technical: technical) as for energy losses. Non-technical power losses represent the power component of non-technical energy loss (which is different from the uncaptured demand charges) Note 2: percentage values in these columns are based on component inputs and not input to distribution system as in the other columns. Note 3: The accuracy of the analysis is estimated as: 1 % for individual (technical) loss components 2% for overall technical and non-technical losses Table A1.1.2 COASTAL AREA - POWER & ENERGY FLOW Network power flow M%) Network energy flow 1%) Annual % LF Peak contribution % loss Input Losses Sales % loss Input Losses Sales Sales Sales Factor MW | Power | Energy (GWH) I (see note 2) (as % of dist. system input) I (see note 2) (as % of dist. system input) Grid SS transformers I 1.00 100.0 1.00 | 0.80 100.0 0.80 Direct consumers at HT 32 5.2 0.75 0.45 2.2 1.5 4.7 MV Lines, 33 kV I 4.77 97.5 4.65 I 3.47 94.5 3.28 Consumers at 33 kV 60 9.7 0.60 0.30 3.4 I 2.3 8.9 MV Lines, 11 kV I 2.47 90.5 2.24 1.68 82.3 1.38 Consumers at 11 kV 162 26.2 0.55 0.30 10.1 6.8 24.0 LV transformers I 1.10 90.5 1.00 | 0.70 82.3 0.58 LV direct lines I 1.00 89.5 0.90 | 0.50 81.7 0.41 LV Direct sales 144 23.3 0.40 0.25 10.3 | 7.0 | 21.3 1 LV retail lines | 5.40 81.7 4.41 I 3.60 60.0 2.16 °o LV Retail sales 220 35.6 0.25 1.00 100.5 | 68.2 | 32.5 Total 618.0 100.0 126.4 I 85.8 I 91.4 Technical losses 58 20.5 14.19 | 8.61 Non-technical losses 37.2 13.0 I 9.38 | 5.69 Total losses 95.0 33.5 I 23.57 | 14.30 System Load Factor 0.53 Note 1: The first section of the table converts energy sales to peak power by using peak contribution factors. Network power and energy losses are calculated in the second and third sections respectively. After computing the technical energy losses, non-technical energy losses are determined by the difference with the overall measured loss value. Non-technical power losses are determined by assuming the same ratio (non-technical: technical) as for energy losses. Non-technical power losses represent the power component of non-technical energy loss (which is different from the uncaptured demand charges) Note 2: percentage values in these columns are based on component inputs and not input to distribution system as in the other columns. Note 3: The accuracy of the analysis is estimated as: 1 % for individual (technical) loss components - 2% for overall technical and non-technical losses Table A1.1.3 DISTRIBUTION SYSTEM POWER & ENERGY FLOW (AGGREGATE CONDITIONS FOR OVERALL SYSTEM) Network power flow (%) Network energy flow (%) Annual LF Peak contribution % loss Input Losses Sales % loss Input Losses Sales Sales Factor MW I Power I Energy (GWH) (see note 2) (as % of dist. system input) ( (see note 2) (as % of dist. system input) Grid SS transformers j 1.00 100.0 1.00 | 0.80 100.0 0.80 Direct consumers at HT 157 0.75 0.45 10.8 1.7 5.2 MV Lines I 5.06 97.3 4.92 I 3.45 94.0 3.24 MV Consumers 659 0.58 0.28 36.3 5.6 j 21.6 LV transformers 1.10 86.8 0.95 I 0.70 69.2 0.48 LV direct lines 1.00 85.8 0.86 I 0.50 68.7 0.34 LV Direct sales 627 0.32 0.20 44.7 | 7.0 I 20.6 LV retail lines I 5.40 78.0 4.21 I 3.60 47.8 1.72 LV Retail sales 1403 0.33 1.00 485.3 75.5 | 46.0 Total 2846 566.4 . 88.1 93.4 Technical losses 200 75.8 11.95 6.59 1 Non-technical losses 134.1 50.1 8.17 4.51 0 Total losses 334.1 125.8 20.12 11.10 L System Load Factor 0.54 COMBINED TRANSMISSION AND DISTRIBUTION SYSTEM LOSSES Power Input Losses Energy Input Losses Technical losses loss % (as % of net gen.) loss % (as % of net gen.) (see note 2) (see note 2) Transmission system 5.5 100.0 5.5 4.5 100.0 4.5 Distribution system 11.9 94.5 11.3 6.6 95.5 6.3 Total technical loss, transmission and distribution 16.8 10.8 Non-technical loss 7.9 4.4 Total system loss (inclusive of non-technical loss) 24.7 15.2 Note 1: The first section of the table converts energy sales to peak power by using peak contribution factors. Network power and energy losses are calculated in the second and third sections respectively. Network component loss percentages are based on weighted averages for the Nairobi and Coastal Areas After computing the technical energy losses, non-technical energy losses are determined by the difference with the overall measured loss value. Non-technical power losses are determined by assuming the same ratio (non-technical: technical) as for energy losses. Non-technical power losses represent the power component of non-technical energy loss (which is different from the uncaptured demand charges) Note 2: percentage values in these columns are based on component inputs and not input to distribution system as in the other columns. Note 3: The accuracy of the analysis is estimated as: 1% for individual (technical) loss components - 84 - Table A1.2.1 LOSS CALCULATIONS OF FEEDERS OUTSIDE NAIROBI AND COASTAL AREAS SUMMARY RESULTS Feeders Max P.F. Power Main Feeder POWER ENERGY Studied Amps (see note 1) Input Length in km LOSSES LOSSES kW (See note 2) % % MT. KENYA AREA: MERU 185.0 0.87 9,200 132 35.7 23.4 KYENI 86.0 0.85 4,178 51 6.0 5.8 Total studied 13,378 26.4 17.9 Total demand for Area 36,000 Percentage load studied 37.2 WEST KENYA AREA: KISII 205.0 0.87 10,194 175 34.6 25.1 Total demand for Area 64,160 Percentage load studied 15.9 NORTH RIFT VALLEY AREA: FLOUSPAR 100.9 0.85 4,900 121 8.4 7.2 CHEMELIL 70.0 0.90 3,601 17 2.0 1.7 MOI BARRACKS 137.0 0.90 7,048 104 12.2 8.7 Total studied 15,549 8.6 6.4 Total demand for Area 27,000 Percentage load studied 57.6 CENTRAL RIFT VALLEY AREA: MARALAL 79.3 0.80 3,626 197 14.0 10.4 NAROK 98.0 0.90 5,041 93 5.3 3.1 Total studied 8,667 9.0 5.6 Total demand for Area 47,600 Percentage load studied 18.2 Total of all feeders studied 47,788 19.2 13.7 Total demand of all associated Areas 1 74,760 Percentage load studied (all feeders) 27.3 N=i 1. Feeder power factors have been estimated 2. The main feeder length is the distance from the supply substation up to the furthest key load point. 3. Feeder loss computations have been made using a spread sheet methodology and detailed results are provided in Tables A1.2.2 to A1.2.9 4. The feeders studied include the major loads of the four Areas and account for 19.2% power losses and 13.7% energy losses. LINE LOSSES CALCULATIONS FOR FEEDERS OUTSIDE NAIROBI AND COASTAL AREAS MT. KENYA AREA: Meru feeder. Table A1.2.2 SECTION LENGTH CONN. MAX I CONDUCTOR DISTR. FAC OHMS POWR FACTOR IND. POWER POWER-LOSSES VOLT-DROP LLF/ Energy km KVA (Amps) Type Size Losses Voltage per km (Cos) (Sin) per km kW kW % kV % LF ratio loss % Nanyuki-Embori 33.00 1525 185 SCA 0.05 1.00 1.0 0.57 0.87 0.49 0.34 9200 1935 21.03 7.03 21.29 0.66 13.790 Embori-Tee off To Isiolo 12.50 0 170 SCA 0.05 1.00 1.0 0.57 0.87 0.49 0.34 8454 619 7.32 2.45 7.41 0.66 4.800 Tee off To Isiolo-Marania 6.50 1500 131 SCA 0.05 1.00 1.0 0.57 0.87 0.49 0.34 6514 191 2.93 0.98 2.97 0.66 1.923 Marania-Meru 20.00 7400 116 SCA 0.05 0.85 0.9 0.57 0.87 0.49 0.34 5769 392 6.79 2.40 7.28 0.66 4.454 Meru-Keigoi 60 4275 42 SCA 0.08 0.70 0.8 0.42 0.87 0.49 0.33 2089 92 4.43 1.83 5.56 0.66 2.903 Toff-Isiolo 31 3865 39 SCA 0.08 1.00 1.0 0.42 0.87 0.49 0.33 1939 59 3.03 1.10 3.33 0.66 1.990 Feeder power input (kW) 9200 Load Factor 0.61 Total Losses (kWI 3288 Loss Load Factor 0.40 Power Losses 1%) 35.7 Energy Losses (%) 23.4 Kamburu-Kyeni Feeder Table A1.2.3 LENGTH CONN. MAX I CONDUCTOR DISTR. FAC OHMS POWR FACTOR IND. POWER POWER-LOSSES VOLT-DROP LLF/ Energy km KVA (Amps) Type Size Losses Voltage per km (Cos) (Sin) per km kW kW % kV % LF ratio loss % KAMBURU-KIRITIRI 15.75 2155 86.00 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 4178 145 3.48 1.26 11.46 0.74 2.589 KIRITIRI-SIAKAGO 11.75 25 50.39 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 2448 37 1.52 0.55 5.01 0.74 1.132 SIAKAGO-KARURUMO 13.50 0 49.98 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 2428 42 1.73 0.63 5.71 0.74 1.289 KARURUMO-KYENI 10.00 2625 43.37 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 2107 23 1.11 0.40 3.67 0.74 0.829 1 T OFF-ISHIARA 15.50 400 6.61 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 321 1 0.26 0.10 0.87 0.74 0.196 co TOTAL KVA CONNECTED 5205 Ln Feeder power input (kW) 4178 Load Factor 0.61 Total Power Losses(kW) 249 Loss Load Factor 0.59 Power Losses(%) 6.0 Energy Losses (%) 5.8 WEST KENYA AREA: Kisii Feeder Table A1.2.4 SECTION LENGTH CONN. MAX I CONDUCTOR DISTR. FAC OHMS POWR FACTOR IND. POWER POWER-LOSSES VOLT-DROP LLFI Energy km KVA (Amps) Type Size Losses Voltage per km (Cos) (Sin) per km kW kW % kV % LF ratio loss % 12.80 1140 205 SCA 0.05 1.00 1.00 0.57 0.87 0.49 0.33 10194 921 9.04 3.00 9.09 0.72 6.55 T-OFF TO SOTIK 22.20 2700 176 SCA 0.05 0.80 0.90 0.57 0.87 0.49 0.33 8751 942 10.77 4.02 12.18 0.72 7.80 SOTIK-TOFF TO KIAMOKAMA 37.30 3905 162 SCA 0.05 0.80 0.90 0.57 0.87 0.49 0.33 8052 1340 16.64 6.21 18.83 0.72 12.06 TOFF-TO KIAMOKAMA 13.00 2900 15 SCA 0.05 1.00 1.00 0.57 0.87 0.49 0.33 750 5 0.68 0.22 0.68 0.72 0.49 TOFFTOKIAMOKAMA-KISII 10.70 9195 127 SCA 0.05 0.55 0.80 0.57 0.87 0.49 0.33 6292 161 2.56 1.24 3.75 0.72 1.86 KISII-AWENDO 41.00 9965 59 SCA 0.08 0.80 0.90 0.42 0.87 0.49 0.33 2927 142 4.85 1.98 5.99 0.72 3.51 AWENDO-MIGORI 28 1350 7 SCA 0.08 0.80 0.90 0.42 0.87 0.49 0.35 349 1 0.39 0.16 0.50 0.72 0.29 T-OFF TO KILGORIS 44.00 3810 20 SCA 0.08 0.33 0.50 0.42 0.87 0.49 0.35 986 7 0.72 0.40 1.22 0.72 0.52 TOFF- MOGOGOSIEK 12.00 4440 23 SCA 0.08 0.70 0.80 0.42 0.87 0.49 0.35 1149 6 0.49 0.21 0.62 0.72 0.35 Connected KVA 39405 Feeder power input (kW) 10194 Load Factor 0.69 Total Power Losses(kW) 3526 Loss Load Factor 0.50 Power Losses(%) 34.6 Energy Losses 1%) 25.1 LINE LOSSES CALCULATIONS FOR FEEDERS OUTSIDE NAIROBI AND COASTAL AREAS (Cont.) NORTH RIFT VALLEY AREA Flouspar feeder Table A1.2.5 SECTION LENGTH CONN. MAX I CONDUCTOR DISTR. FAC OHMS POWR FACTOR IND. POWER POWER-LOSSES VOLT-DROP LLFf Energy km KVA (Amps) Type Size Losses Voltage per km (Cos) (Sin) per km kW kW % kV % LF rati loss % LESSOS-X98 29 100 100.9 SCA 0.15 1.00 1.00 0.19 0.85 0.53 0.33 4900 171 3.49 1.71 15.53 0.74 2.60 X98-FLOUS. 13 250 48.7 SCA 0.15 1.00 1.00 0.19 0.85 0.53 0.33 2364 18 0.75 0.37 3.34 0.74 0.56 X311-X99 9 350 40.1 SCA 0.15 1.00 1.00 0.19 0.85 0.53 0.33 1950 8 0.43 0.21 1.90 0.74 0.32 X99-FLOUS. 8 150 33.4 SCA 0.15 1.00 1.00 0.19 0.85 0.53 0.33 1624 5 0.30 0.15 1.32 0.74 0.22 FLOUS.-KABAR. 30 4215 32.9 SCA 0.10 1.00 1.00 0.29 0.85 0.53 0.34 1600 28 1.74 0.72 6.55 0.74 1.30 KABAR.-MARI. 40 2100 19.0 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 924 18 1.95 0.71 6.44 0.74 1.45 X99-KAPKOI 23 1500 7.3 SCA 0.08 0.39 0.55 0.42 0.85 0.53 0.35 355 1 0.17 0.09 0.78 0.74 0.12 X311-CHEROP 23 1315 6.4 SCA 0.08 0.39 0.55 0.42 0.85 0.53 0.35 312 0 0.15 0.08 0.69 0.74 0.11 X98-TIMB. 31 1965 52.2 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 2536 105 4.16 1.51 13.69 0.74 3.09 TIMB.-MAKU. 21 42.5 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 2066 47 2.28 0.83 7.52 0.74 1.70 MAKU.-LOND. 6 2925 14.4 SCA 0.08 1.00 1.00 0.42 0.85 0.53 0.35 699 2 0.22 0.08 0.73 0.74 0.17 MAKU.-CHIN. 26 5715 28.1 SCA 0.08 0.39 0.55 0.42 0.85 0.53 0.35 1367 10 0.72 0.37 3.37 0.74 0.54 TOTAL KVA CONNECTED 20585 Shorten forms for feeder names: Feeder power input (kW) 4900 Load Factor 0.69 Kabar = Karbarnet; Mari = Marigat; fious = Flouspar; Timb = Timboroa Total Losses IkW) 413 Loss Load Factor 0.59 Maku = Makutano; Chin = Chinese Camp; Lond = Londiani Power Losses 1%) 8.4 Energy Losses I%) 7.2 Chemelil feeder Table A1.2.6 SECTION LENGTH CONN. MAX I CONDUCTOR DISTR. FAC OHMS POWR FACTOR IND. POWER POWER-LOSSES VOLT-DROP LLFI Energy km KVA (Amps) Type Size Losses Voltage per km (Cos) (Sin) per km kW kW % kV % LF rati loss % LESSOS-NANDI 17.00 70.00 SCA 0.10 1.00 1.00 0.29 0.90 0.44 0.34 3601 71 1.98 0.83 7.58 0.85 1.69 Feeder power input (kW) 3601 Load Factor 0.69 Total Losses (kW) 71 Loss Load Factor 0.59 Power Losses 4%) 1.98 Energy Losses 1%) 1.7 Mol Baraks feeder Table A1.2.7 SECTION LENGTH CONN. MAX I CONDUCTOR DISTR. FAC OHMS POWR FACTOR IND. POWER POWER-LOSSES VOLT-DROP LLF/ Energy km KVA (Amps) Type Size Losses Voltage per km (Cos) (Sin) per km kW kW % kV % LF rati loss % RIVATEX-X364 4.00 0 137 SCA 0.15 1.00 1.00 0.19 0.90 0.44 0.34 7050 43 0.61 0.30 2.76 0.74 0.46 X364-RAI 1.00 2500 136 SCA 0.10 1.00 1.00 0.29 0.90 0.44 0.34 7007 16 0.23 0.10 0.87 0.74 0.17 RAI-BARACKS 19.00 3280 115 SCA 0.08 1.00 1.00 0.42 0.90 0.44 0.34 5913 313 5.30 1.97 17.94 0.74 3.94 MOI-OXT3 46.60 7500 86 SCA 0.08 1.00 1.00 0.42 0.90 0.44 0.34 4406 427 9.68 3.61 32.79 0.74 7.20 OXT3-KAPEN. 33.60 2965 38 SCA 0.08 1.00 1,00 0.42 0.90 0.44 0.34 1945 60 3.08 1.15 10.44 0.74 2.29 Feeder power input (kW) 7050 Load Factor 0.59 Total Losses (kW) 859 Loss Load Factor 0.42 Power Losses (%) 12.2 Energy Losses (%) 8.8 LINE LOSSES CALCULATIONS FOR FEEDERS OUTSIDE NAIROBI AND COASTAL AREAS (Cont.} CENTRAL RIFT VALLEY AREA Maraial feeder Table A1.2.8 SECTION LENGTH CONN. MAX I NDUCTOR DISTR.FAC. RES. POWR-FACT IND. POWER POWER-LOSS VOLT-DROP LLFI LOSSES (Km) KVA (Amps) Type Size Loss Vol U Km) (Cos) (Sin) (/Km) (Kw) (Kw) (%) (Kv) (%M LF (KWH LANET-NYAHUR. 48.40 14860 79 SCA 0.05 0.90 0.80 0.57 0.80 0.60 0.38 3628 470 12.95 3.65 33.18 0.74 9.63 NYAHUR.-RUMU. 35.00 2790 16 SCA 0.08 1.00 1.00 0.42 0.80 0.60 0.35 745 12 1.56 0.54 4.87 0.74 1.16 RUMUR.-MARAL. 114.00 1050 14 SCA 0.08 1.00 1.00 0.42 0.80 0.60 0.35 634 27 4.31 1.48 13.49 0.74 3.21 TOTAL KVA CONNECTED 18700 Feeder power input (kW) 3628 Load Factor 0.50 Shorten forms for feeder names: Total Losses IkW) 509 Loss Load Factor 0.37 Nyahur = Nyahururu: Rumu = Rumuruti; Maral = Maralal Power Losses (%1 14.0 Energy Losses 1%) 10.4 Narok feeder Table Al.2.9 SECTION LENGTH CONN. MAX I CONDUCTOR DISTR. FAC OHMS POWR FACTOR iND. POWER POWER-LOSSES VOLT-DROP LLF/ Energy km KVA (Amps) Type Size Losses Voltage per km (Cos) (Sin) per krm kW kW % kV % LF rati loss % NAIVASHA-DCK 24.30 2500 98 SCA 0.10 1.00 1.00 0.29 0.90 0.44 0.34 5041 200 3.97 1.67 15.18 0.76 3.03 DCK-NAROK 68.50 1565 38 SCA 0.05 0.41 0.57 0.57 0.90 0.44 0.36 1941 68 3.51 1.71 15.59 0.76 2.68 1 TOTAL KVA CONNECTED 4065 00 .~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ Feeder power input (kW) 5041 Load Factor 0.69 Total Losses (kW) 268 Loss Load Factor 0.40 DAILY LOAD VARIATION KAREN S/S/ LAVINGTON 11 KV FEEDER/ WEEKDAY APRIL1992 320- 300 280 - 260 - 240 - 220 - 200- 2*~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~c 160 - \ 120 - 100 60- ... ... .. . ...... 0 2 4 a 8 10 12 14 16 18 20 22 24 TIME (HOURS) ('4 ci) bo.,I ~~~~~~~~~~~~~(SWJACIM1 P4 fZ Z Oa 91 9l lV L E Ol 9 9 e a 0 , ....i .'l. ,.*...... .... A A ....... I., I - l,,,, ,,,,,,,.,,,,,,.,,,,,,a,,,,,,,. oc 09 09 09 06~ NOIlYlUtA dV01 111vA~~~~~~~~01 OOL OCL 014 OS1 09L 01-1 MVGIJMMW3aU laA33 MAIM03l A)1 it saUNV1ivd /S/S 33PA3Ih NOIIVIUJVA aVO1 iliva 11/0.4 kV Transformer s/s 4000. Residenlial load, Weekday April 1992 300 Z50 ,1 X tw~~~~~~~~~~~~~~~~~~~~~A ,/ .'\ N L ' ~~~~~~~ eps elowpa - - Blephs w0 I' ~~~~~~~~~~~~~~rIr I~~~~~~I l0- -n C, 0 c, 4t5 %.*** *. ., *t*. nc v.-. /,' , c Oc nc o I11111111111 1:1111-1C.: C,111 T11 111111111 I 11111 " 11111 5ii " In I 1111 - - - - - - - - - C'I CNJ~~~~~~~~~~~~~~~~~~~C' Red phase - --Yellow phase ......l..ue phase Current. A 0:45 1:30 . 2-15 .,t 30 . * '~~~~~'. 3:00 M 3:45 .M:; 4:30 - . -. 5:15M 8:00 6:45 N - 7:30 _ 9:4 * -70 9:00 e_,,, . 9-45 ,-IA I9:45 t o 21:31 D" / 24:00 15 e, *£'1:-645 M 13:30 - 17:15 - * 15:00 coE 15:30 M* 219:00M 21:45 20:15 24:00 1 6 DAILY POWER FACTOR'VARIATION INDUSTRIAL AREA S/S/ NAIROBI SOUTH NO 2,11 KY FEEDER/ WEEKDAY FEBRUARY,1992 0.98 - 0.97, 0.95- 0.94- 0.93- '.0 0.92- 0.91 0.69 . 0 2 4 6 a 10 12 14 1 18 20 22 24 TIME IHOURS) a (D. M-. Ul - 93 - Table Al1.4 BULK CONSUMERS DETECTED WITH POOR POWER FACTORS (NAIROBI) NAME ACC NO. PF. NAME ACC NO. PF. 1 KANGAITA COFFEE ESTATE 160081054 0.25 43 E.A. PACKAGING 199505905 0.73 2 ALPHA MOTORS 194210330 0.32 44 SUPER FOAM LTD. 198090450 0.73 3 CHODA FABRICATORS 199520800 0.36 45 LYONS AND CO LTD 199502111 0.74 4 AUTOANXILLIARIES 194210290 0.40 46 COCA COLA BOTTLING 199504600 0.74 5 NATIONAL FOOD 194210550 0.41 47 LYONS & CO LTD 199502111 0.74 6 VIRANI CARRY POWDER 160014070 0.41 48 KENYA TIMES LTD 199504270 0.74 7 ENGLISH PRESS 199507380 0.46 49 CUSSIONS AND CO. 199501610 0.74 8 JADVA KARSAN & BROS 199507090 0.48 50 PREMIER FOOD INDUSTRIES 153460021 0.75 9 to be identified 153881160 0.49 51 FRIGO. KEN 199502170 0.76 10 MOORE AGENCIES 153600400 0.51 52 EAST A. SPECTRE 199530850 0.78 11 PROPWA LTD. 194207040 0.53 53 DOTHIA PACKAGING 199506320 0.78 12 BIDCO INDUSTRIES 194210661 0.55 54 E.A CABLES 199505950 0.79 13 WARREN ENGINEERING 194208970 0.56 55 W.E. TILLEY MUTHAIGA 199501631 0.79 14 HENKEL CHEMICALS 198015002 0.56 56 OMEGA INVESTMENTS 199501881 0.79 15 WARREN CONCRETE 194209016 0.57 57 to be identified m/n353294 0.80 16 BELFAST MILL. 199504640 0.57 58 PLASTICS ANDRUBBER IND. 199505520 0.81 17 CAR AND GENERAL 199504876 0.57 59 HIGHLAND CANNERS 194209340 0.81 18 CITY RADIATORS 199502830 0.57 60 D.C.A. 194210920 0.82 19 VACU LUG TYRES 199503050 0.58 61 A.M.R.E.F. 194206510 0.83 20 WARREN CONCRETE 194209016 0.58 62 NAIROBI CITY CONCIL 194209650 0.83 21 MOBILIA LTD. 199540210 0.59 63 K.A.R.I. 199507950 0.83 22 MANSION HART LTD 153427001 0.59 64 K. M. C. 194210690 0.83 23 CITY RADIATORS 199506330 0.60 65 EAGLE FISHERIES 153684450 0.83 24 STATIONARY EXPRESS 194208531 0.61 66 BRUCE LTD 194210350 0.84 25 LACHMANDAS 199506910 0.61 67 NCC WATER SEWERAGE 194209550 0.84 26 MEDICAL MANUF. 199509570 0.62 68 INDUSTRIAL PLANT E. A. 199506050 0.84 27 CARBACID 1961 LTD 161001500 0.63 69 TOWEL INDUSTRIES LTD 199550111 0.84 28 PREMIER FOOD IND. LTD 153460005 0.64 70 RECKITT AND COLMAN 160097700 0.84 29 CAR AND GENERAL 199506250 0.64 71 INTERPRODUCTS (K) LTD. 199502160 0.85 30 HIGHLAND CANNERS LTD. 194209340 0.64 72 BIDS MATCH 199504990 0.85 31 KENS METAL 194210270 0.66 73 PLASTIC PRODUCTS 199506546 0.85 32 PENESAR CONSTRUCTION 160308600 0.66 74 VACU LUG TYRES 199501780 0.85 33 KENS METAL LTD 160420610 0.66 75 K. M. C. 199507210 0.86 34 W.E.TELLY MUTHAIGA 199501631 0.67 76 MALINDI DISHES 178664650 0.87 35 R.B. SHAH 199502336 0.68 77 ARROW INVESTMENTS 194201860 0.87 36 K.C.C. LTD 199504850 0.68 78 DOTHIA PACKAGING 199506301 0.87 37 TAWS LTD. 199504480 0.69 79 to be identified m/n467856 0.87 38 SPORTS VIEW HOTEL 194208960 0.70 80 OTIENDE POLICE 194206710 0.87 39 E.A.SPECTRE 194210340 0.71 81 U.S. INT. UNIVERSITY 194209190 0.88 40 NAIROBI CITY COUNCIL 199506660 0.71 82 E.A.POST AND TEL. 194206080 0.89 41 W.E. TILLY MUTHAIGA 199501631 0.72 83 RAMJI H. DEVAJI 199505920 0.89 42 KENYA SHOE CO. 197089690 0.73 Out of 108 installations checked 83 (i.e.77%) were found to have a power factor below 0.9 pu BULK CONSUMERS DETECTED WITH POOR POWER FACTORS (MOMBASA) NAME ACC NO. PF. NAME ACC NO. PF. 1 MOMBASA MILLERS 299525811 OA1 23 KENYA COLD STORAGE 299521500 0.74 2 COACH WORKS 280440000 0.45 24 MOMBASA GRAIN MILLERS 299525032 0.74 3 BAYUSUF 299533100 0.46 25 MARINE PRODUCTS 299410800 0.77 4 STEEL AFRICA 299530930 0.61 26 KAYDEE CONSTRUCTION 299416300 0.77 5 SGS(K)LTD. 299518981 0.62 27 FISHERMANNS INN 299420200 0.77 6 J.M VIRJI 299524000 0.62 28 K.B.C 299403651 0.78 7 AFROMEAT 299409980 0.63 29 POLYCANS 299518900 0.79 8 TEXTILES AND PLASTICS 299405630 0.64 30 DIAMOND PERFUMERY WORK 299524680 0.79 9 KAYDEE CONSTRUCTION 299533650 0.64 31 RUBI PLASTICS 299525980 0.79 10 MVITA BOTTLERS 299502202 0.65 32 D ENG.COAST 299403801 0.80 11 MIRITINI BRICKS 299534251 0.65 33 FREIGHT FOWARDERS 299407050 0.81 12 CONSOLIDATED 299410550 0.66 34 to be identified 299535501 0.82 13 CORRUGATED 299532051 0.67 35 STAR DUST 299433950 0.85 14 KENYA COLD STORAGE 299510550 0.68 36 ELITE ENTERPRISES 299525580 0.85 15 LINT M.BOARD 299417001 0.71 37 SIGNON FREIGHT 299403400 0.86 16 UMOJA RUBBER PRODUCTS 299537200 0.71 38 to be identified 299536101 0.86 17 IRON INTERNATIONAL 299532100 0.72 39 CAR AND GENERAL 299406301 0.87 18 ATTA LTD. 299525012 0.73 40 COASTAL BOTTLERS 299535501 0.87 19 BIRCH INVESTMENTS 299534011 0.73 41 KENYA SUITCASE MAN. 299523150 0.88 20 PAN AFRICA INS. 299403870 0.74 42 WANANCI MARINE P. 299536502 0.88 21 M.I.T. CENTRE 299430050 0.74 43 PANTY HOSE MAN. 299519100 0.89 22 KMC 299516002 0.74 Out of 81 installations checked 43 (i.e.53%) were found to have a power factor below 0.9 pu Table A1.5 LOAD CHARACHERISTICS - LV CONSUMERS Record Type of No. of Consumers Load Loss Peak Transf. Peak load Loss Avg. Pow. Consumer s ~~~~~~Power Rating duration Fco Trf. No. Trf. No. period Consumer 1- Ph 3 Ph Factor Factor (k) (kVA) W cons. (hrs.) 0066 0066 26.8.92 ReslCom 238 21 0.56 0.27 137 315 529 3003 0.86 0535 0535 22.4.92 Com 91 9 0.60 0.26 82 315 820 3377 0.94 0587 0587 18.9.92 Res/Com 91 6 0.61 0.24 105 200 1,082 3523 0.96 0711 0711 2.7.92 Res 25 1 0.72 0.40 151 300 5,808 4641 0.97 0721 0721 1.9.92 Res 34 11 0.66 0.18 116 315 2,578 3963 0.94 0741 0741 7.5.92 Res/Com 123 1 0.37 0.16 126 315 1,016 1477 0.96 0744 0744 26.8.92 ReslCom 212 7 0.50 0.25 122 300 557 2455 0.96 0754 0754 22.2.92 Res/Com 454 1 0.48 0.29 130 315 286 2279 0.96 0757 0757 13.6.92 Res 163 0 0.48 0.13 108 150 663 2325 0.99 0762 0762 11.6.92 Res/Com 228 13 0.67 0.30 87 315 361 4117 0.71 12073 12073 18.9.92 Ind 0 2 0.52 0.12 29 200 14,500 2631 0.83 xo 12759 12759 1.9.92 Res 141 2 0.58 0.17 60 200 420 3209 0.93 1741 1741 1.4.92 Com 138 6 0.55 0.30 148 315 1,026 2932 0.91 2346 2346 18.9.92 Res 127 0 0.56 0.34 97 200 764 2979 0.97 2723 2723 20.2.92 Res 229 22 0.51 0.17 456 630 1,817 2529 0.97 2724 2724 1.9.92 Res 192 0 0.49 0.24 98 315 510 2359 0.97 2768 2768 2.8.92 Res 113 3 0.58 0.26 76 315 655 3144 0.71 3414 3414 18.9.92 Res/Com 29 2 0.51 0.15 51 315 1,645 2551 0.89 4080 4080 4.4.92 Res 497 0 0.43 0.15 228 315 459 1938 0.96 4511 4511 26.8.92 Res/Com 113 3 0.57 0.17 82 150 707 3084 0.79 4610 4610 20.6.92 Ind 40 14 0.51 0.18 249 315 4,611 2566 0.72 Note: Note: All transformers were selected from the Nairobi City Table A1.6.1 PRESENT WORTH FACTORS OF REIABIUTY BENEFITS OF FrTURE YEARS 1e91 1902 1t02 102t 0104 105 109e 1007 1008 io0 2000 2001 2002 2003 2004 2008 2000 1.05 -CVFtNNfAE I I - WNM FEt# STATE Imisis&d iliabtlky p.u. .wilh load growth 1.00 1.05 S.10 l.t8 1.22 1.26 1.34 1.4t 1.48 1.55 1.83 t.71 1.80 1.80 1.08 2.06 2t.t DOluA factot t.o o e.li 0.83 0.7S 0.08 0.52 0.56 0.51 0.47 0.42 0.30 0.35 0.32 0.20 0.28 0.24 0.22 P.W. s,ltsily b.l*ileg t,Oo 0.0e 0.0S 0.07 0.83 0.7t 0.76 0.72 0.80 0.88 0.43 0.80 0.57 O.SS . 0.12 0.10 0.t4 CumlltatPWd bernIs t1.00 L.OS 2.87 3.74 4.57 S.3 8.11I 8.84 7.53 8.10 S.S1 8.41 0.09 1O.53 11.01 II.S5 t2.02 1.071.tPAtlW' 1. t Nt0rAE nrestud ltt*lity P.&L -with load giowth 1.00 t.t7 1,14 1.2s 1.31 t.40 t.40 1.61 1.72 1.64 1.07 2.10 2.25 2.4S 2.5t 2.78 2.9S Dttoount letICt 1.00 0.01 0.83 0.75 0.88 0.62 0.58 0.51 0.47 0.42 0.30 U.3S 0.32 0.20 0.28 0.24 0.22 P.W. ralabhyb steneis 1.00 0.07 O95 0.t2 0.e0 0.87 0.85 0.82 0.o0 0.78 0.16 0.74 0.72 0.70 00.6 0.6t o0.4 CUmMO tPW'ofbunt1,s 1.80 I.l7 2.92 2.84 4.73 1.01 6.45 7.20 8,08 6.88 0.62 IO.S5 t I07 A 17? 12.46 ISM 11 4.75 i.00 *GA:AM PAYIE S.1 ItSlEEST PATE lnef4&i4d tlobilky p.u. .Whh load giowb 1.00 1.00 t.1l 1.20 1.41 1.54 1.6t 1,83 I1.0t 2.17 2.27 2.58 2.81 3.07 3.24 3.84 3.07 DlOcoun1t tIto.t 1.0 8.01 0.2 0.7is 0.e8 0.S2 .S1 O'.St 0.47 0.42 0.30 0.3t 0.32 0.2t o.28 0.24 0.22 P.W. .llabtiey bandits 1.00 0.00 0.08 0.07 0.C8 0.0e 00os 0.04 0.0t 002 0.01 0.00 0.00 0.81 0.88 0.87 0.t8 Curnb116 PW 04 bee1its 1.00 i.40 2.07 3.05 4.0t 5.87 C.ot 7.75 8.68 .800 10.51 11.42 12.31 13.20 14.08 14,05 16.82 t.11 -GrYM ttRATE 1.1 INTEFESTRAtE Itntownd t0bllitky p.u. .with load growth 100 4.11 1.23 4.37 1.52 1.80 t1.8 2.0t 2.30 2.56 2.84 3.S5 3.50 3.88 4.31 4.78 5.31 Discounl 140ot 1.00 8,01 0.82 0.os 0.68 0.62 0.s6 O.51 0.47 0.42 0.30 0.35 0.32 0.20 0.28 0.24 0.22 P.W. Iablihy b.tlits 1.00 1.01 1.02 1.03 4A 1. 1.08 1.07 t.,0 lo 1.0 1.0 l.to t .t 1 L.l2 t.14 1.16 1161 Cu,n&latttPWcIb.noes t.o0 2.01 3.03 4.05 5.09 0.1 i4 7.1 8.28 0.33 10.42 11.51 12.42 13.73 14.88 15.90 17.14 18.20 1.05 -.t3' PRAtE 1.08 .l EST PATE tIrwamd uelibally p.u.I *rIlh load groth t1.00 t.0S 1.10 1.18 1.22 1.28 t.54 1.4t 1.48 1.55 1.823 IJ. 1.80 t.80 1. 6 2.08 2,18 Dscourti factor 1.00 0.03 0.8 0.70 0.74 0.84 0.83 .56 0.54 0.50 0.48 0.43 0.40 0.27 0.34 0.32 0.20 P.W. eOIAbfly bnelAs 1.00 0.07 0.05 0.02 0.80 0.87 0.84 0.82 0.80 0.78 0.75 O.1S 0.71 0.69 0.67 0.08 0.84 Cumltal PW oft Wonule 1.00 1.09 2.02 3.84 4.73 5.60 6.44 7.28 8.06 6.84 0.00 10.33 14.04 11.73 t2.41 1.06 13.7O The computation of multiplying factors to convert reliability benefits of the current year to the present worth of benefits over a period of analysis --for varying load growth rates and discount factors - - are presented in this table. Note, Tho sbovi rnrprutalon asstans thAt the. sytewn bsd can bo met In lutiw y.ato both by ihe sxlOing and proposed oy*t1ms. The griavh tat* sn dbcorwd ral tsth bn Coatsld as 94c unk1 bett1 Th, table provldes muktpyng lucton that cotrwr Via pPuissr year bsftfls to that of ths dieteoutrld bnsils olf period d4 MIut ycars Ithe porliod of benefits s1tn li hsutM yosl 8 eubtlidlont ol tho telOtard 1ltt4n* In thl tablb wl ptovie ths appoptiate mtlAlplylng tlaot Table A1.6.2 PRESENr WORTH FACTORS FOR LOSS REDUCTlON BENEFITS OF FlUTUlRE YEARS 1tot 1992 t993 1994 t995 l99go 107 l09o t999 2000 2001 2002 2003 2004 2005 2000 2007 I.05 .os offtmRATE 1.1 . INlTEEST RATE Inuosa.d ossso p.u. *with load groth 1.00 1.10 1.22 1.34 1.48 1.63 1.90 1.98 2.10 2.41 2.65 2.03 3.23 3.58 3.02 4.32 4.76 Dheount factor 1.00 0.91 0.83 0.75 0.68 0.62 0.56 0.51 0.47 0.42 0.39 0.35 0.32 0.20 0.26 0.24 0.22 P.W. loss toductin benefits 1.00 1.00 1.00 1.01 1.01 1.01 1.01 1.02 1.02 1.02 1.02 1.03 1.03 1.03 1.03 1.03 1.04 Cumilitlv. PWof b6nolkts 1.00 2.00 3.01 4.01 5.02 8.03 7.05 8.00 9.08 10.10 11.13 12.15 13.18 14.21 15.24 10.28 17.31 1.07 GA.YlFATE t.t .iiNTE? EsTPATE Inc,eas.d oss.c p.u. *wilh load growth 1.00 1.14 1.31 1.50 1.72 1.97 2.25 2.58 2.S5 3.36 3.87 4.43 5.07 5.8t 8.65 7.61 6.12 Dbcount lacto, 1.00 0.01 0.63 015 0.o8 0.62 0.56 0.51 0.47 0.42 0.30 0.3S 0.32 0.29 0.26 0.24 0.22 P.W. lost induction bensfits 1.00 1.04 1.06 1.13 1.17 1.22 .127 1.32 1.38 t.43 1.49 1.55 1.62 t.68 1.75 1.82 1.90 Cumiltailv PW of bonelfs 1.00 2.04 3.12 4.25 5.43 6.65 7.92 9.24 10.62 t2.05 i3.54 15.10 16.71 16.39 20.16 21.07 23.56 1.09 -GrtNl RATE 1.1 .tN FE StPATE tncoased bss. p.u. -with load growth 1.00 1.19 1.41 1.6' 1.99 2.37 2.81 3.34 3.07 4.72 5.60 6.66 7.91 9.40 It.17 13.27 16.78 DOcounl lacIat 1.00 0.91 0.83 0.75 0.68 0.62 0.56 0.51 0.47 0.42 0.39 0.35 0.32 0.20 0.26 0.24 0.22 P.W. foil t&duclorsbenstlis 1.00 1.0S 1.17 1.28 1.38 1.47 t.59 1.71 1.65 2.00 2.16 2.33 2.52 2.72 2.94 3.16 3.43 Curnlatlov PW of benetis 1.00 2.06 3.25 4.51 5.87 7.34 0.93 10.64 t2.49 14.49 16.65 16.09 21.51 24.23 27.17 30.35 33.76 1.t1 -t .t;1F RATE .1 -l NTEflESTPATE Inclo.asd bs"s pu. .wiIh losd groWth 1.00 1.23 1.52 1.87 2.30 2.64 3.50 4.3t 5.31 6.54 0.06 *.93 12.24 t5.08 16.58 22.00 28.21 Discount factol 1.00 0.91 0.3 0.75 0.68 0.62 0.56 0.51 0.47 0.42 0.30 0.35 0.32 0.29 0.20 0.24 0.22 .D P.W. toss roducilon bensfits 1.00 1.12 1.25 1.41 1.57 1.78 1.97 2.21 2.46 2.75 3.11 3.48 3.90 4.31 4.89 5.48 6.14 ON CumilsOvs PW olt bnelks 1.00 2.12 3.37 4.78 0.35 6.12 10.09 12.30 14.78 17.56 20.66 24.15 28.05 32.41 37.31 42.70 48.93 1 t.05 .GtN1tllP ATE 1.06 . INtEFESTPATE I Inceagsed los.. pu. .*ith load growth 1.00 1.10 1.22 1.34 1.48 1.63 1.80 1.98 2.18 2.41 2.65 2.93 3.23 3.60 3.82 4.32 4.78 Discount factor 1.00 0.03 0.86 0.79 0.74 0.68 0.83 0.59 0.54 0.50 0.48 0.43 0.40 0.37 0.34 0.32 0.29 P.W. lio toducaion benfhis 1.00 1.02 1.04 1.06 1.0o t.1t 1.13 1.18 1.16 1.20 1.23 1.25 1.26 1.31 1.33 1.36 1.30 CumiisIlo. PW of benolfs t.00 2.021 3.06 4.13 5.21 6.32 7.45 8.61 9.70 10.9 112.22 13.4 14.76 16.06 17.40 tt.76 20.16 The computation of multiplying factors to convert loss reduction benefits of the current year to the present worth of benefits over a period of analysis --for varying load growth rates and discount factors-- are presented in this table. "*tI: The abovo cosnrulaffon aiswnms that thO systm boad con be met In fubjtr yerts both by the oxIsting and proposed oystems. The provth rat. and dicount Itte has boon qpxoss d as psi urit factots The iabis provides mukipfying fdacttr thtt convec the pl0tset year bonefha Io that of the dlcour4od benelke ol a petIod of ftruIr years 11 the pstniod of bnefith CtaltI In a Mutro ytlr a stbtreilcon of tho salovart factors In the tabte will provid the appropates multiplying factor LOAD CHARACTERISTICS - NAIROBI CITY 11 kV FEEDERS Table A2.1.1 Feeder Feeder name Feeder Amps Max kW Min kW Avg kW min/max LF LLF annual Power Factor at given system periods LLF/LF Number Maximum Minimum Util. time peak day peak max. min. NAIROBI SOUTH SUBSTATION SR-01 Industrial 1 279.3 161.8 4442 2620 3418 0.59 0.77 0.57 5299 0.87 0.83 0.91 0.82 0.74 SR-02 Industrial No:2 178.9 49.0 2986 796 1893 0.27 0.63 0.43 3906 0.95 0.90 0.99 0.90 0.67 SR-03 Mogadishu 193.5 102.0 3184 1820 2482 0.57 0.78 0.57 5454 0.87 0.87 0.91 0.85 0.73 SR-04 Kampala No 1 207.4 105.6 3572 1836 2822 0.51 0.79 0.63 5652 0.93 0.93 0.95 0.90 0.79 SR-05 Kampala No 2 128.7 17.3 2151 263 1329 0.12 0.62 0.43 3944 0.94 0.88 0.98 0.84 0.69 SR-06 Airport Feeder 43.6 12.9 801 198 432 0.25 0.54 0.39 2873 0.97 0.85 0.98 0.78 0.73 SR-07 Outer ring 118.9 68.7 1935 662 920 0.34 0.48 0.46 2082 0.94 0.76 0.94 0.61 0.94 SR-08 Donholm 1 211.5 49.6 3927 985 2027 0.25 0.52 0.32 2628 0.94 0.86 0.97 0.84 0.63 SR-09 Doonholm 11 319.3 220.4 5400 3908 4600 0.72 0.85 0.70 6416 0.88 0.86 0.93 0.84 0.82 SR-10' Gen Motors 112.0 79.7 2015 1375 1712 0.68 0.85 0.76 6396 0.85 0.93 0.96 0.84 0.90 SRA57 Athi feeder 128.5 25.6 2307 369 1099 0.16 0.48 0.27 2385 0.95 0.86 0.98 0.80 0.57 PARKLANDS SUBSTATION SR-11 Eastleigh feeder 280.8 93.9 5437 1743 3091 0.32 0.57 0.37 3083 0.97 0.90 0.98 0.88 0.65 SR-12 norfork feeder 116.9 42.3 2172 773 1497 0.36 0.69 0.50 4473 0.91 0.90 0.97 0.88 0.73 SR-13 Muthaiga feeder 232.2 49.1 4120 892 2323 0.22 0.56 0.39 3192 0.95 0.90 0.97 0.76 0.69 SR-14 Westlands feeder 271.8 106.4 4783 1722 3502 0.36 0.73 0.56 5017 0.93 0.90 0.95 0.81 0.76 SR-16 Kabete feeder 247.4 43.5 4503 685 2289 0.15 0.51 0.33 2717 0.97 0.89 0.98 0.87 0.66 SR-18^ Welbeck feeder 219.5 92.8 4031 1548 2595 0.38 0.64 0.47 3869 0.96 0.94 0.98 0.85 0.73 SR-19 Riverside feeder 218.5 93.2 4432 1825 2944 0.41 0.66 0.49 4089 0.96 0.94 0.97 0.90 0.73 SR-20* Cathedral int.con. 85.9 34.5 1624 702 1160 0.43 0.71 0.51 4700 0.97 0.97 0.99 0.94 0.72 RUARAKA SUBSTATION SR-22' Sports Complex 53.8 34.6 561 200 294 0.36 0.52 0.55 2554 0.35 0.47 0.99 0.33 1.05 SR-23' Kiambu feeder 272.2 129.6 4907 2090 2861 0.43 0.58 0.40 3102 0.96 0.94 0.97 0.84 0.68 SR-24 Brewery no1 249.6 166.6 4298 2868 3493 0.67 0.81 0.67 5858 0.96 0.97 0.98 0.96 0.83 SR-25 Brewery no 2 213.4 106.3 3918 1809 2764 0.46 0.71 0.57 4557 0.95 0.88 0.95 0.88 0.81 SR-26' Kahawa 208.3 107.9 3969 1905 2560 0.48 0.65 0.46 3768 0.98 0.96 0.98 0.92 0.72 SR-27* Central Glass 66.7 45.2 1064 518 764 0.49 0.72 0.70 4700 0.98 0.99 0.99 0.98 0.97 SR-28 Ridgeways feeder 268.9 133.0 4930 2329 3328 0.47 0.68 0.50 4153 0.95 0.92 0.96 0.90 0.73 SR-ROY Roysambu 11 kV- New 147.1 66.9 2732 1090 1556 0.40 0.57 0.39 2984 0.97 0.88 0.97 0.83 0.68 SR-R23 Kiambu -new arran. 236.9 49.9 3566 596 1726 0.17 0.48 0.33 2447 0.77 0.76 0.80 0.63 0.67 NAIROBI WEST SUBSTATION SR-30 Lower Hill 209.0 88.1 3426 1363 2543 0.40 0.74 0.59 5110 0.93 0.82 0.96 0.79 0.80 SR-32 Dara no 1 205.4 47.8 2838 393 1388 0.14 0.49 0.37 2548 -0.49 -0.64 -0.40 -0.66 0.75 SR-33 Dara 2 inds 8.3 6.8 94 16 36 0.17 0.39 0.67 1550 0.14 0.27 0.37 0.07 1.74 SR-34^ Ngong Rd. 246.8 88.1 4482 1428 2727 0.32 0.61 0.43 3540 0.94 0.92 0.95 0.81 0.70 SR-35 Industrial feeder 224.9 46.8 3576 747 2384 0.21 0.67 0.47 4384 0.89 0.85 0.97 0.83 0.70 SR-36 Hurlingham feeder 346.5 138.0 6209 2277 4026 0.37 0.65 0.46 3951 0.96 0.93 0.97 0.91 0.70 SR-37 KNA &PC 19.2 12.7 196 25 88 0.13 0.45 0.62 2194 0.16 0.44 0.99 0.12 1.37 SR-38 Nairobi south B 261.6 102.6 4832 1540 3010 0.32 0.62 0.46 3710 0.95 0.83 0.98 0.75 0.73 SR-39' Langata feeder 237.8 84.0 4522 1363 2392 0.30 0.53 0.34 2682 0.96 0.91 0.96 0.83 0.64 SR-40 Nairobi dam 141.4 49.6 2633 783 1457 0.30 0.55 0.36 2949 0.96 0.84 0.98 0.79 0.64 JEEVANJEE SUBSTATION SR-41 Donholm 218.7 74.0 3981 1364 2774 0.34 0.70 0.50 4582 0.98 0.95 0.99 0.93 0.72 SR-42 Parkland 179.4 33.3 2996 578 1546 0.19 0.52 0.35 2723 0.88 0.87 0.89 0.81 0.68 SR-43'- City Square 96.8 39.6 1449 569 927 0.39 0.64 0.46 3814 0.79 0.82 0.85 0.76 0.71 SR-44 Temple rd. 146.2 28.8 2452 483 1377 0.20 0.56 0.41 3198 0.88 0.92 0.94 0.82 0.73 LOAD CHARACTERISTICS - NAIROBI CITY 1 1 kV FEEDERS (CONT) Table A2.1.1 fCont.) Feeder Feeder name Feeder Amps Max kW Min kW Avg kW minlmax LF LLF annual Power Factor at given system periods LLF/LF Number Maximum Minimum Util. time peak day peak max. min. SR-45'- Capital no 1 292.7 62.8 4944 1121 2914 0.23 0.59 0.44 3460 0.91 0.91 0.98 0.88 0.74 SR-46 Capital 2 312.8 66.6 5132 1166 2823 0.23 0.55 0.35 3025 0.87 0.87 0.90 0.78 0.64 SR-47*- Cathedral 1 177.9 38.9 3351 679 2078 0.20 0.62 0.45 3845 0.98 0.98 0.99 0.96 0.73 SR-48'- Dara cath 242.8 184.5 4413 3354 3907 0.76 0.89 0.77 6910 0.96 0.95 0.97 0.94 0.87 SR-49 New KPCU 142.2 41.4 2449 590 1384 0.24 0.57 0.43 3169 0.79 0.92 0.96 0.72 0.76 SR-50 development hse 122.3 30.8 2023 455 1115 0.23 0.55 0.39 3042 0.97 0.92 0.99 0.82 0.72 SR-51' Gwasi Feeder 257.0 103.7 4747 1811 3106 0.38 0.65 0.47 4004 0.96 0.93 0.97 0.84 0.72 STEEL BILLET SUBSTATION SR-52 Allsopps 254.8 134.1 4739 2276 3494 0.48 0.74 0.62 4959 0.94 0.88 0.94 0.86 0.84 SR-53' K.C.C. Dandora 146.9 67.9 2719 1123 1638 0.41 0.60 0.44 3338 0.94 0.88 0.95 0.78 0.73 SR-54 Kayole 99.3 31.8 1841 442 1095 0.24 0.59 0.44 3502 0.96 0.77 0.98 0.59 0.74 SR-55'- Sunrise feeder 242.3 70.0 4734 997 2271 0.21 0.48 0.32 2329 0.98 0.87 0.99 0.75 0.66 SR-56 V.O.K-Komaroc 44.8 28.0 820 221 576 0.27 0.70 0.66 4736 -0.99 -0.99 0.99 -0.99 0.94 SR-58' City Electrical 224.1 79.7 4268 1310 2265 0.31 0.53 0.33 2691 0.97 0.91 0.97 0.86 0.63 KAREN SUBSTATION SR-59 Langata 159.3 63.8 2836 1068 1825 0.38 0.64 0.45 3877 0.97 0.97 0.97 0.89 0.69 SR-60- Ngong Hills V.O.K 78.2 34.7 1553 672 1002 0.43 0.65 0.45 3825 0.95 0.92 0.96 0.86 0.70 SR-61 Hurlingham 307.3 71.2 5763 1216 2621 0.21 0.45 0.24 2087 0.97 0.91 0.97 0.88 0.53 SR-62 Kiserian 119.6 40.2 2109 656 992 0.31 0.47 0.28 2075 0.97 0.87 0.97 0.84 0.60 SR-82 Ngong Rd. 296.8 99.9 5726 1925 3558 0.34 0.62 0.40 3666 0.98 0.99 0.99 0.96 0.65 INDUSTRIAL AREA SUBSTATION SR-63 Dara 1 inds 167.1 61.7 2728 1099 1834 0.40 0.67 0.47 4202 0.91 0.86 0.94 0.84 0.70 00 SR-64, Dara no 2 45.5 22.9 707 337 473 0.48 0.67 0.50 4077 0.74 0.73 0.99 0.69 0.75 I SR-65 Kampala lindst SS) 52.7 18.0 850 270 483 0.32 0.67 0.38 3083 0.99 0.79 0.99 0.73 0.68 SR-66' East Af. Oxy. 88.2 70.8 1546 1238 1403 0.80 0.91 0.84 7245 0.94 0.92 0.95 0.90 0.92 SR-67 Rollmill 170.3 18.6 1857 17 408 0.01 0.22 0.23 675 0.95 0.03 0.99 -0.98 1.02 SR-68 Nairobi Si 79.9 20.9 1467 394 743 0.27 0.51 0.34 2498 0.73 0.69 0.96 0.67 0.68 SR-69 Nairobi S2 197.9 91.2 3430 1641 2539 0.48 0.74 0.55 4999 0.94 0.91 0.98 0.89 0.75 NEW AIRPORT SUBSTATION SR-70 Athi 274.5 143.9 4673 2389 3288 0.51 0.70 0.54 4477 0.87 0.88 0.90 0.84 0.77 SR-71 Airport No 1 22.0 20.9 27 11 20 0.42 0.74 0.95 5092 0.05 0.06 0.14 0.03 1.28 SR-72 K.P.C. feeder 22.5 20.9 96 7 25 0.07 0.26 0.91 784 0.11 0.08 0.70 0.05 3.56 SR-73 Airport no 2 117.3 84.9 930 615 751 0.66 0.81 0.78 5779 -0.32 -0.31 -0.27 -0.37 0.96 CATHEDRAL SUBSTATION SR-74 Hill no 1 167.0 62.4 2945 1060 2000 0.36 0.68 0.50 4337 0.97 0.96 0.99 0.91 0.73 SR-75 Hill no 2 116.4 30.7 1947 536 1138 0.28 0.58 0.34 3329 0.90 0.92 0.92 0.83 0.57 Sf-76 Market feeder 282.6 114.0 5277 2117 3315 0.40 0.63 0.42 3660 0.98 0.96 0.98 0.94 0.67 SR-77 G.P.O. feeder 172.3 54.1 2810 751 1636 0.27 0.58 0.44 3314 0.93 0.92 0.97 0.72 0.76 SR-78 UnirvesityfK.T.O.C. 68.4 15.9 1084 141 513 0.13 0.47 0.28 2412 -0.43 -0.76 -0.38 -0.83 0.60 SR-79 Intercontinental 63.3 20.9 930 395 680 0.42 0.73 0.53 4937 0.70 0.67 0.81 0.65 0.72 SR-80 P.C.S. office 6.8 6.8 25 12 18 0.47 0.69 1.00 4401 0.20 0.22 0.27 0.13 1.44 SR-81 Dara no 2 228.2 161.7 3946 2925 3417 0.74 0.87 0.73 6617 0.93 0.90 0.95 0.89 0.84 Notes!: . indicates when readings were taken during week ends; *- indicates when readings included both weak ends and weak days. Feeder numbers 15, 21 and 31 are normally open and were not monitored. Feeder number 17 operates alternatively half day each from two sub stations. A new feeder, SR-ROY IRoysambu), was introduced at Ruaraka substation during the study. SR-R23 gives the load on Kiambu feeder after the new feeder SR-ROY is introduced. LOAD CHARACTERISTICS - NAIROBI 66 kV AND 40 kV FEEDERS Table A2.1.2 Feed, no: Feeder name Max I Min I Max KW Min KW min/max LF LLF Ut. time annual Power Factor at: PF Max PF Min LLF/LF Ut. time Peak Day Peak JUJA SUBSTATION SR-PLN1 PARKLAND 1 66 KV 186.2 67.85 18530 6886 0.372 0.715 0.551 13.21 4788 0.91 0.85 0.94 0.85 0,769 SR-jelc JEEVANJEE 1 66 KV 157.7 60.31 16010 6499 0.406 0.719 0.546 13.10 4790 0.94 0.86 0.95 0.86 0.760 SR-JE2 JEEVANJEE 2 66 KV 134.3 55.52 14240 5963 0.419 0.706 0.551 13.23 4606 0.95 0.9 0.97 0.87 0.781 SR-rka2 RUARAKA 2 66KV 421.8 202 42140 19960 0.474 0.679 0.499 11.97 4204 0.91 0.87 0.92 0.87 0.735 SR-EMCO EMCO 66 KV-WEEKDAY 263.9 142 27870 13930 0.500 0.753 0.621 14.90 5148 0.98 0.95 0.98 0.92 0.825 SR-mco2 EMCO 66-WEEKEND 256.2 133.5 27100 12910 0.476 0.671 0.507 12.16 4094 0.98 0.97 0.99 0.9 0,755 RUARAKA SUBSTATION SR-iimu LIMURU 66 KV 265.4 109.7 28040 11300 0,403 0.631 0.441 10.57 3695 0.9 0.a7 0.91 0.84 0.698 SR-RU66 RUIRU 66KV 32.08 3.11 3801 417.3 0.110 0.462 0.279 6.70 2340 0.92 0.9 0.99 0.79 0.604 SR-TKA1 THIKA 40 KV 1 112 54.62 6550 2987 0.456 0.803 0.700 16.80 5888 0.88 0.8 0.89 0.8 0.871 x0 SR-TK2 THIKA 40KV NO 2 106.2 49.02 6596 2910 0.441 0.816 0.712, 17.10 6082 0.93 0.89 0.93 0.85 0.873 EMBAKASI 220166 KV SUBSTATION SR-nwl 6 NAIROBI WEST 1 66 KV 269.4 127.9 27700 10700 0.386 0.738 0.605 14.52 5059 0.98 0.92 0.99 0.78 0.820 SR-ew26 BURCKLEY NO 2 66 KV 337 135.5 35750 13660 0.382 0.608 0.410 9.83 3447 0.93 0.9 0.94 0.87 0.674 SR-mag MAGADI 66 KV LINE 25.59 16.31 2339 813.3 0.348 0.789 0.757 18.17 5782 -0.85 0.85 0.85 -0.9 0.959 SR-66AT ATHI 66 KV FEEDER 102.3 55.75 10610 5383 0.507 0.791 0.646 15.50 5674 0.95 0.88 0.96 0.87 0.816 SR-nsl NAIROBI SOUTH 1 66 KV-NW 348 74.28 35950 6427 0.179 0.703 0.494 11.87 4859 0.99 0.98 0.99 0.74 0.703 SR-ARP1 AIRPORT 1 66 KV EMB. 45.68 27.25 4015 2391 0.596 0.779 0.618 14.82 5433 0.84 0.85 0.86 0.83 0.792 SR-ARP2 AIRPORT 2 66 KV-EM 35.28 20.67 3438 2018 0.587 0.744 0.560 13.44 4948 0.85 0.83 0.88 0.82 0.752 SR-ns26 NAIROBI SOUTH 2 66 KV-EM 194.9 83.84 19070 9313 0.488 0.728 0.512 12.28 4821 0.95 0.87 0.98 0.87 0.703 - 100 - Table A2.1.3 LOAD DENSITY OF 11 kV FEEDERS - NAIROBI AREA Existing System Load Flow Results FEEDER FEEDER MAX. P.F Load POWER OP. VOL. MIN. AREA LOAD NAME NO. LOAD Gr. rate LOSSES VOL. DROP VOL. SUPPLIED DENSITY kW % % kW % % % km. sq. kW/km.sq. NORFOLK 12 2042 91 2 10.6 100.5 0.7 99.8 0.301 6784.1 CATHEDRAL 20 1632 96 2 11.4 103.5 0.8 102.7 0.645 2530.2 MUTHAIGA 13 4091 90 4 43.4 101.6 1.56 100 14.529 281.6 RIVERSIDE 19 4139 97 4 95.3 102.3 3.77 98.53 3.690 1121.7 WELBECK 18 4124 96 4 103.1 102.6 4.47 98.13 4.264 967.2 WESTLANDS 14 4842 94 8 143.1 99.4 4.77 94.63 3.626 1335.4 EASTLEIGH 11 5192 97 5 205.5 99.8 5.7 94.1 6.745 769.8 KABETE 16 4576 97 7 252 99.9 9.26 90.64 10.836 422.3 VOK-KOMAROCK 56 811 99 1 1.8 103.1 0.7 102.4 Single consumer KCC 53 2718 95 5 29.3 102.3 2.11 100.2 2.039 1333.0 CITY ENGINEERING 58 5546 97 7 91.6 104.3 2.3 102 2.846 1948.7 ALLSOPPS 52 4675 93 5 74.3 103.5 2.8 100.7 2.241 2086.1 SUNRISE 55 4727 98 4 88.2 104.4 3.9 100.5 25.001 189.1 KAYOLE 54 1475 76 4 51.5 102.3 5.7 96.6 50.976 28.9 SPORTS COMPLEX 22 608 60 1 1.4 98.7 0.3 98.4 Single consumer GLASS WORKS 27 1298 98 5 10 103.9 1.1 102.8 Single consumer BREWERY I 24 4631 96 3 212.2 101.4 6.3 95.1 4.519 1024.8 BREWERI II 25 3948 95 5 145 102.2 6.3 95.9 1.355 2913.7 RIDGEWAYS 28 5100 95 6 486.5 104.7 17 87.7 35.239 144.7 KAHAWA 26 3953 98 9 63.2 101.6 4.7 96.9 36.430 108.5 KIAMBU 23 5140 97 6 348.1 102.2 13.3 88.9 43.609 117.9 DARA 2 33 53 33 2 0.0 101.1 0.0 101.1 Supplies an 11 kV busbar KNA-PC'S OFFICE 37 26 57 2 0.1 98.4 0.1 98.3 0.064 406.3 INDUSTRIAL 35 3664 85 3 23.0 100.5 1.6 98.9 0.364 10065.9 DARA 1 32 2368 -60 4 49.3 100.4 1.4 99.0 0.423 5598.1 LOWER HILL 30 3349 84 2 76.9 100.0 3.8 96.2 0.703 4763.9 NAIROBI SOUTH B 38 4416 98 6 116.6 99.1 5.1 94.0 3.376 1308.1 NGONG RD. 34 4463 94 4 161.7 101.5 7.3 94.2 1.068 4178.8 NAIROBI DAM 40 2435 96 5 115.5 100.0 6.3 93.7 4.866 500.4 HURLINGHAM 36 5965 90 4 271.6 105.0 9.0 96.0 6.524 914.3 LANGATA 39 3179 96 5 127.6 101.4 7.6 93.8 16.994 187.1 AIRPORT 6 787 92 3 4 102.9 1.3 101.6 10.097 77.9 INDUSTRY II 2 3146 90 5 30 100.5 2 98.5 0.268 11738.8 INDUSTRIAL I 1 4525 84 5 52.9 101.6 2.7 98.9 1.097 4124.9 OUTERING RD. 7 2240 94 3 30.5 102.2 2.6 99.6 3.218 696.1 KAMPALA II 5 2170 87 5 33.3 101.9 2.4 99.5 0.353 6145.6 DOONHOLM II 9 5310 86 2 104.1 101.6 3.3 98.3 Supplies an 11 kV busbar ATHI 57 2355 93 6 48 103.3 4.3 99.0 4.315 545.8 GENERAL MOTORS 10 2026 94 5 49.3 100.8 3.5 97.3 2.601 778.9 KAMPALA I 4 3705 92 5 91 102.2 3.9 98.3 0.477 7767.3 DOONHOLMI 8 3813 92 4 106.5 102.5 4.6 97.9 0.210 18157.1 MOGADISHU 3 3247 87 5 101.9 101.1 4.3 96.8 0.937 3465.3 - 101 - Table A2.1.3 Icont.) LOAD DENSITY OF 11 kV FEEDERS - NAIROBI AREA Existing System Load Flow Results FEEDER FEEDER MAX. P.F Load POWER OP. VOL. MIN. AREA LOAD NAME NO. LOAD Gr. ra LOSSES VOL. DROP VOL. SUPPLIED DENSITY kW % % kW % % % km. sq. kW/km.sq. ATHI 70 4728 89 9 303.3 101.8 13.1 88.7 71.270 66.3 AIRPORT II 73 785 34 1 8.1 102.9 0.4 102.5 Single consumer K.P.C 72 303 70 1 0.2 100.7 FEEDER SUPPLIES 0 Single consumer AIRPORT I 71 25 6 1 0.3 100.5 0.1 100.4 Single consumer ROLLMILL 67 2048 64 1 40.3 98.5 2.4 96.1 Single consumer NAIROBI SOUTH 2 69 3666 91 3 27.1 100 1.7 98.3 0.286 12818.2 NAIROBI SOUTH 1 68 1219 79 3 3.4 101.4 0.5 100.9 0.722 1688.4 DARA II 64 818 93 4 1.7 101.8 0.4 101.4 0.449 1821.8 DARA I 63 2761 86 3 21.6 100.8 1.6 99.2 0.145 19041.4 E. A. OXYGEN 66 1555 93 3 3.9 99.5 0.3 99.2 Single consumer KAMPALA 65 800 79 5 1.5 100.9 0.2 100.7 0.186 4301.1 KISERIAN 62 2254 97 8 59.5 101.7 5.8 95.9 64.520 34.9 LAVINGTON 61 5688 97 5 404.4 100.2 10.5 89.7 9.016 630.9 NGONG-VOK 60 1445 92 4 12.3 100.9 1.5 99.4 47.652 30.3 NGONG RD. 82 5517 98 4 305.3 99.5 8.3 91.2 15.785 349.5 LANGATA 59 2944 97 4 162 100 9.6 90.4 16.358 180.0 HILL I(CATHEDRAL) 47 3045 98 4 20.4 97.6 1 96.6 0.687 4432.3 NGARA(GWASI) 51 4749 97 5 57.3 100.1 2.5 97.6 3.203 1482.7 DEVELOPMENT HSE 50 2112 91 1 5.1 99.4 0.4 99.0 City centre CAPITOL 11 46 4997 83 3 50.1 101 1.1 99.9 City centre CAPITOL I 45 5060 90 3 40.8 100.8 0.9 99.9 City centre DOONHOLM 41 3923 95 3 76.3 98.7 2.4 96.3 2.597 1510.6 PARKLANDS 42 2931 87 6 171.9 103.7 9.3 94.4 14.484 202.4 CITY SQUARE 43 1516 79 3 4.8 103.7 0.3 103.4 City centre TEMPLE RD. 44 2490 92 3 6 97.6 0.3 97.3 City centre NEW K.P.C.U 49 2508 92 1 8.4 99.5 0.5 99.0 City centre MARKET 76 5322 98 3 25.2 100.6 0.8 99.8 City centre UNIVERSITY 2 78 817 74 3 0.5 100.2 0.06 100.1 City centre G.P.O 77 3021 92 3 0.6 99.7 0.7 99.7 City centre INTERCONTINENTA 79 819 69 5 0.2 98.2 0.2 98.2 City centre DARA NO. 2 81 3737 90 4 2.5 100.2 100.2 Single consumer HILL 2 75 1914 88 4 0.8 97.7 1.1 97.7 2.220 862.2 Totals 224027 5887.1 556.426 402.6 For feeders supplying City Center: Sum of feeders 28662 2.056 13940.7 Table A2.2 SUMMARY OF LOAD FLOW RESULTS -11 KV FEEDERS, NAIROBI PRESENT SYSTEM LOADS SYSTEM LOADS IN 1OYrs. SYSTEM LOADS IN 15Yrs. Load ENERGY LOSSES growth IN PERCENT FEEDER P.F LOAD LOSSES Volt Dr. LOAD LOSSES Volt Dr. LOAD LOSSES Volt Dr. rate LF LLF Prest. lOYrs 15Yrs NAME NO. % (KW) KW % % (KM KW % % (KW) KW % % % 1 NORFOLK 12 91 2042 11 0.5 0.7 2489 15 0.6 0.8 2748 18 0.7 0.9 2 0.69 0.50 0.4 0.4 0.5 2 CATHEDRAL 20 96 1632 11 0.7 0.8 1989 16 0.8 1.0 2196 19 0.9 1.1 2 0.71 0.51 0.5 0.6 0.6 3 MUTHAIGA 13 90 4091 43 1.1 1.6 6056 99 1.8 2.4 7368 144 2.0 2.9 4 0.56 0.39 0.7 1.1 1.3 4 RIVERSIDE 19 97 4139 95 2.3 3.8 6127 222 3.6 5.8 7454 1859 24.9 17.6 4 0.66 0.49 1.7 2.7 18.3 5 WELBECK 18 96 4124 103 2.6 4.5 6105 241 3.9 6.9 7427 326 4.4 7.0 4 0.64 0.47 1.8 2.9 3.2 6 WESTLANDS 14 94 4842 143 3.0 4.8 10454 78 0.7 11.2 15380 356 2.3 8.4 8 0.73 0.56 2.3 0.6 1.8 7 EASTLEIGH 11 97 5192 206 4.0 5.7 8457 566 6.7 9.5 10794 1047 9.7 13.1 5 0.57 0.37 2.6 4.4 6.3 8 KABETE 16 97 4576 252 5.5 9.3 9002 1289 14.3 21.6 12625 3780 29.9 38.7 7 0.51 0.33 3.6 9.4 19.7 9 VOK-KOMAROCK 56 99 811 2 0.2 0.7 896 2 0.2 0.7 942 3 0.3 0.8 1 0.70 0.66 0.2 0.2 0.3 10 KCC 53 95 2718 29 1.1 2.1 4427 77 1.7 3.4 5651 135 2.4 4.5 5 0.60 0.44 0.8 1.3 1.7 11 CITY ENGINEERING 58 97 5546 92 1.7 2.3 10910 386 3.5 6.0 15302 792 5.2 8.7 7 0.53 0.33 1.0 2.2 3.2 12 ALLSOPPS 52 93 4675 74 1.6 2.8 7615 74 1.0 2.8 9719 346 3.6 6.1 5 0.74 0.62 1.3 0.8 3.0 13 SUNRISE 55 98 4727 88 1.9 3.9 6997 205 2.9 5.9 8513 205 2.4 5.9 4 0.48 0.32 1.2 1.9 1.6 14 KAYOLE 54 76 1475 52 3.5 5.7 2183 121 5.6 8.8 2656 180 6.8 10.7 4 0.60 0.44 2.6 4.1 5.0 15 SPORTS COMPLEX 22 60 608 1 0.2 0.3 672 2 0.2 0.4 706 2 0.3 0.4 1 0.52 0.35 0.2 0.2 0.2 1 16 GLASS WORKS 27 98 1298 10 0.8 1.1 2114 26 1.2 1.7 2698 45 1.7 2.3 5 0.72 0.70 0.7 1.2 1.6 17 BREWERY I 24 96 4631 212 4.6 6.3 6224 374 6.0 8.4 7215 594 8.2 10.7 3 0.71 0.58 3.7 4.9 6.7 H 18 BREWERI II 25 95 3948 145 3.7 6.3 6431 401 6.2 10.5 8208 743 9.1 14.4 5 0.81 0.67 3.0 5.2 7.5 19 RIDGEWAYS 28 95 5100 487 9.5 17.0 9133 2631 28.8 41.1 12222 4500 36.8 53.7 6 0.68 0.50 7.0 21.1 27.0 20 KAHAWA 26 98 3953 63 1.6 4.7 9358 401 4.3 12.2 14399 1003 7.0 20.0 9 0.65 0.46 1.1 3.1 5.0 21 KIAMBU 23 97 5140 348 6.8 13.3 9205 1505 16.3 28.7 12318 3000 24.4 37.2 * 6 0.58 0.40 4.6 11.2 16.6 22 DARA 2 33 33 53 0 0.0 0.0 65 0 0.0 0.0 71 0 0.0 0.0 2 0.39 0.22 0.0 0.0 0.0 23 KNA-PC'S OFFICE 37 57 26 0 0.4 0.1 32 0 0.6 0.1 35 0 0.6 0.1 2 0.45 0.28 0.2 0.4 0.4 24 INDUSTRIAL 35 85 3684 23 0.6 1.6 4924 39 0.8 2.0 5708 39 0.7 2.0 3 0.67 0.47 0.4 0.6 0.5 25 DARA 1 32 -60 2368 49 2.1 1.4 3505 112 3.2 2.3 4265 131 3.1 5.3 4 0.49 0.37 1.6 2.4 2.3 26 LOWER HILL 30 84 3349 77 2.3 3.8 4082 111 2.7 4.5 4507 163 3.6 2.2 2 0.74 0.59 1.8 2.2 2.9 27 NAIROBI SOUTH B 38 98 4416 117 2.6 5.1 7908 405 5.1 9.5 10583 762 7.2 13.1 6 0.62 0.46 1.9 3.7 5.3 28 NGONG RD. 34 94 4463 162 3.6 7,3 6606 390 5.9 11.4 8038 588 7.3 14.1 4 0.61 0.43 2.5 4.1 5.1 29 NAIROBI DAM 40 96 2435 116 4.7 6.3 3966 322 8.1 10.5 5062 600 11.9 14.3 5 0.55 0.36 3.1 5.2 7.6 30 HURLINGHAM 36 90 5965 272 4.6 9.0 8830 675 7.6 14.4 10743 1043 9.7 18.1 4 0.65 0.46 3.2 5.4 6.8 31 LANGATA 39 96 3179 128 4.0 7.6 5178 582 11.2 16.5 6609 1306 19.8 25.2 5 0.53 0.34 2.6 7.2 12.7 32 AIRPORT 6 92 787 4 0.5 1.3 1058 7 0.7 1.7 1226 11 0.9 2.2 3 0.54 0.39 0.4 0.5 0.6 33 INDUSTRY II 2 90 3146 30 1.0 2.0 5125 78 1.5 1.2 6540 137 2.1 2.2 5 0.85 0.70 0.8 1.2 1.7 34 INDUSTRIAL I 1 84 4525 53 1.2 2.7 7371 77 1.0 3.3 9407 91 1.0 3.6 5 0.77 0.57 0.9 0.8 0.7 35 OUTERING RD. 7 94 2240 31 1.4 2.6 3010 52 1.7 3.4 3490 80 2.3 4.2 3 0.48 0.45 1.3 1.6 2.2 36 KAMPALA II 5 87 2170 33 1.5 2.4 3535 88 2.5 3.9 4511 155 3.4 5.2 5 0.62 0.43 1.1 1.7 2.4 37 DOONHOLM II 9 86 5310 104 2.0 3.3 6473 152 2.3 3.9 7147 179 2.5 4.3 2 0.85 0.70 1.6 1.9 2.0 38 ATHI 57 93 2355 48 2.0 4.3 4217 165 3.9 8.0 5644 308 5.4 11.0 6 0.48 0.27 1.2 2.2 3.1 SUMMARY OF LOAD FLOW RESULTS -11 KV FEEDERS, NAIROBI Table A2.2 (cont) PRESENT SYSTEM LOADS SYSTEM LOADS IN 1 OYrs. SYSTEM LOADS IN 1 SYrs. Load ENERGY LOSSES growth IN PERCENT FEEDER P.F LOAD LOSSES Volt Dr. LOAD LOSSES Volt Dr. LOAD LOSSES Volt Dr. rate LF LLF Prest. 1OYrs 15Yrs NAME NO. % (KVW KW % % (KVV KW % % (KYW KW % % % 39 GENERAL MOTORS 10 94 2026 49 2.4 3.5 3300 132 4.0 5.7 4212 236 5.6 7.7 5 0.85 0.76 2.2 3.6 5.0 40 KAMPALAI 4 92 3705 91 2.5 3.9 6035 245 4.1 6.5 7702 442 5.7 8.8 5 0.79 0.63 1.9 3.2 4.6 41 DOONHOLM I 8 92 3813 107 2.8 4.6 5644 252 4.5 7.2 6867 375 5.5 8.9 4 0.52 0.32 1.8 2.8 3.4 42 MOGADISHU 3 87 3247 102 3.1 4.3 5289 275 5.2 7.1 6750 498 7.4 9.5 5 0.78 0.57 2.3 3.8 5.4 43 ATHI 70 89 4728 303 6.4 13.1 11193 5204 46.5 43.4 17222 9500 55.2 52.8 * 9 0.70 0.55 5.0 36.0 42.7 44 AIRPORTII 73 34 785 8 1.0 0.4 867 10 1.1 0.4 911 12 1.3 0.5 1 0.74 0.61 0.8 0.9 1.1 45 K.P.C 72 70 303 0 0.1 0.1 335 1 0.1 0.2 352 2 0.6 0.3 + 1 0.26 0.12 0.0 0.1 0.3 46 AIRPORT I 71 6 25 0 1.2 0.1 28 0 1.1 0.1 29 0 1.4 0.1 1 0.81 0.70 1.0 0.9 1.2 47 ROLLMILL 67 64 2048 40 2.0 2.4 2262 49 2.2 2.6 2378 49 2.1 2.6 1 0.22 0.10 0.9 1.0 0.9 48 NAIROBI SOUTH 2 69 91 3666 27 0.7 1.7 4927 47 0.9 2.3 5712 71 1.2 2.8 3 0.74 0.55 0.6 0.7 0.9 49 NAIROBI SOUTH 1 68 79 1219 3 0.3 0.5 1638 6 0.3 0.7 1899 9 0.5 0.8 3 0.51 0.34 0.2 0.2 0.3 50 DARA II 64 93 818 2 0.2 0.4 1211 4 0.3 0.5 1473 6 0.4 0.6 4 0.67 0.50 0.2 0.2 0.3 51 DARAI 63 86 2761 22 0.8 1.6 3711 37 1.0 2.1 4302 57 1.3 2.6 3 0.67 0.47 0.5 0.7 0.9 52 E. A. OXYGEN 66 93 1555 4 0.3 0.3 2090 7 0.3 0.4 2423 10 0.4 0.5 3 0.91 0.84 0.2 0.3 0.4 53 KAMPALA 65 79 800 2 0.2 0.2 1303 4 0.3 0.4 1663 7 0.4 0.5 5 0.57 0.39 0.1 0.2 0.3 54 KISERIAN 62 97 2254 60 2.6 5.8 4866 320 6.6 13.7 7150 757 10.6 21.5 8 0.47 0.28 1.6 4.0 6.4 55 LAVINGTON 61 97 5688 404 7.1 10.5 9265 1229 13.3 18.8 11825 2627 22.2 28.3 5 0.46 0.24 3.8 7.0 11.7 56 NGONG-VOK 60 92 1445 12 0.9 1.5 2139 28 1.3 2.3 2602 40 1.5 2.7 4 0.65 0.45 0.6 0.9 1.1 57 NGONG RD. 82 98 5517 305 5.5 8.3 8167 755 9.2 13.4 9936 1164 11.7 16.8 4 0.62 0.40 3.6 6.0 7.6 1 0 58 LANGATA 59 97 2944 162 5.5 9.6 4358 401 9.2 15.3 5302 617 11.6 19.1 4 0.64 0.45 3.8 6.4 8.1 a 59 HILL I(CATHEDRAL) 47 98 3045 20 0.7 1.0 4507 46 1.0 1.5 5484 67 1.2 1.8 4 0.62 0.45 0.5 0.7 0.9 60 NGARA(GWASI) 51 97 4749 57 1.2 2.5 7736 151 1.9 4.1 9873 265 2.7 5.5 5 0.65 0.47 0.9 1.4 1.9 61 DEVELOPMENTHS 50 91 2112 5 0.2 0.4 2333 6 0.3 0.4 2452 7 0.3 0.4 1 0.55 0.39 0.2 0.2 0.2 62 CAPITOL II 46 83 4997 50 1.0 1.1 6716 85 1.3 1.4 7785 130 1.7 1.8 3 0.55 0.35 0.6 0.8 1.1 63 CAPITOL I 45 90 5060 41 0.8 0.9 8800 69 1.0 1.2 7883 105 1.3 1.5 3 0.59 0.44 0.6 0.8 1.0 64 DOONHOLM 41 95 3923 76 1.9 2.4 5272 201 3.8 3.9 6112 201 3.3 3.9 3 0.70 0.50 1.4 2.7 2.4 65 PARKLANDS 42 87 2931 172 5.9 9.3 5249 8 0.2 0.4 7024 491 7.0 15.8 6 0.52 0.35 4.0 0.1 4.8 66 CITY SQUARE 43 79 1516 5 0.3 0.3 2037 10 0.5 6.5 2362 12 0.5 0.5 3 0.64 0.46 0.2 0.4 0.4 67 TEMPLE RD. 44 92 2490 6 0.2 0.3 3346 10 0.3 -1.3 3879 15 0.4 0.5 3 0.56 0.41 0.2 0.2 0.3 68 NEW K.P.C.U 49 92 2508 8 0.3 0.5 2770 648 23.4 14.0 2912 12 0.4 0.6 1 0.57 0.43 0.3 17.7 0.3 69 MARKET 76 98 5322 25 0.5 0.8 7152 43 0.6 1.0 8292 65 0.8 1.3 3 0.63 0.42 0.3 0.4 0.5 70 UNIVERSITY2 78 74 817 1 0.1 0.1 1098 1 0.1 1.1 + 1273 1 0.1 2.1 + 3 0.47 0.28 0.0 0.0 0.1 71 G.P.O 77 92 3021 1 0.0 0.7 4060 1 0.0 1.0 + 4707 1 0.0 2.0 + 3 0.58 0.45 0.0 0.0 0.0 72 INTERCONTINENTA 79 69 819 0 0.0 0.2 1334 0 0.0 1.0 + 1703 0 0.0 2.0 + 5 0.73 0.53 0.0 0.0 0.0 73 DARA NO. 2 81 90 3737 3 0.1 0.8 + 5532 4 0.1 1.0 + 6730 6 0.1 2.0 + 4 0.87 0.73 0.1 0.1 0.1 74 HILL 2 75 88 1914 1 0.0 1.1 2833 1 0.0 1.0 + 3447 2 0.1 1.9 + 4 0.58 0.34 0.0 0.0 0.0 For total system: 224027 5887 2.63 350132 22272 6.36 442734 42549 9.61 1.84 4.56 6.80 Average growth rate between periods: 4.6 4.8 Note: All feeder results have been computed by using Ihe load flow program DPA/G. indicates where the program failed to converge (estimated values used) and + indicates estimated values where losses are negligible. - 104 - ECONOMIC ANALYSIS: Table A2.3 PROPOSALS FOR NEW SUBSTATION AT KIAMBU EXISTING SYSTEM: Feeders Kiambu (no.23), Ridgeways (no.28), UNEP and Muthaiga (no.1 3) fed off Ruaraka, Kitisuru and Limuru SS Feeders 23 & 28 All 4 feeders Existing system loss: Peak losses, kW 835 1142 Energy, MWh/yr. 3323 4856 Load factor (combined) 0.676 0.717 Loss factor (combined) 0.446 0.473 Load growth rate (p.a.), pu 0.06 0.06 Existing system load, MW 10.2 14.6 Maximum system capacity, MW 16.0 17.0 Capacity shortfall in: 2000 1996 PROPOSED SYSTEM 66 kV line 0.1 5SCA, 23 MVA substation location 2 location 2 Losses in new system Peak losses. kW 200 313 Energy, MWh/yr. 799 1188 Loss savings at present load: kW at peak 635 829 MWh/year 2524 3668 Outage savings based on: saved outages/yr. 12 12 hrs./outage 3 3 Analysis period (Years): 10 15 10 1 5 Investment costs: Investment cost 1.688 1.688 2.236 2.236 PW of Residual value 1.125 0.844 1.491 1.118 Net Investment 0.563 0.844 0.745 1.118 Value of benefits: Loss reduction benefits 3.8 5.8 5.1 7.8 Reliability benefits 1.5 2.6 2.1 3.7 Additional load supplied 0.7 4.5 8.2 17.9 Total benefits 5.9 12.8 15.4 29.4 Benefit/cost ratios Loss reduction only 6.7 6.8 6.8 7.0 Loss red. + reliability 9.3 9.9 9.6 10.3 All three benefits 10.6 15.2 20.6 26.3 Net present values Loss reduction only 3.2 4.9 4.3 6.7 Loss red. + reliability 4.7 7.5 6.4 10.4 All three benefits 5.4 12.0 14.6 28.3 Note: All investments and benefits in US$ millions Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 S/kWh - value of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount factor 33 kV Feeders altered: Location 1 - Kiambu and Ridgeways Location 2 Kiambu, Ridgeways, UNEP and Muthaiga - 105 - ECONOMIC ANALYSIS: Table A2.4 PROPOSALS FOR NEW SUBSTATION AT KILELESHWA EXISTING SYSTEM: Existing system loss: Peak losses, kW 1494 Energy, MWh/yr. 4815 Load factor (combined) 0.717 Loss factor (combined) 0.473 Load growth rate lp.a.), pu 0.06 Existing system load, MW 14.6 Maximum system capacity, MW 17.0 Capacity shortfall in: PROPOSED SYSTEM 66/11 kV, 23 MVA substation and 11 kV feeder rearrangement Losses in new system Peak losses, kW 497 Energy, MWh/yr. 1377 Loss savings at present load: kW at peak 997 MWh/year 3437 Outage savings based on: saved outageslyr. 1 2 hrs./outage 3 Analysis period (Years): 10 15 Investment costs: Investment cost 2.267 2.267 PW of Residual value 1.511 1.133 Net Investment 0.756 1.133 Value of benefits: Loss reduction benefits 4.4 6.2 Reliability benefits 3.8 6.4 Additional load supplied 4.9 12.7 Total benefits 13.1 25.2 Benefit/cost ratios Loss reduction only 5.8 5.4 Loss red. + reliability 10.9 11.0 All three benefits 17.3 22.2 Net present values Loss reduction only 3.6 5.0 Loss red. + reliability 7.5 11 .4 All three benefits 12.4 24.4 Note: All investments and benefits in US$ millions Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - value of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount factor Table A2.5.1 Key Results of Proposals for Reconductoring and New Feeder additions - Nairobi City Valuation of Benefits Feeder Loss Savings No. Name Reconductored Investment Present Present Power Feeder Load Loss Peak Feeder Present Peak EnergY Present Benefit Net Sections Cost Feeder Power Loss Load Factor Factor Respon- Power Worth Worth to Present Load Loss after Growth sibility Factor Factor Loss Benefits Improve- Ratio ment (i) (kWI (kW) (kWI t%t JkW) (kWhlyrt iS) 1 3 Mogadishu 520. 521, 522, 35,840 3727 101.9 33.8 5 0.780 0.572 0.78 0.87 15.24 41.4 341,230 490,675 13.7 454835 523, 524 (all to 300 AACI 2 2 Industrial It 541, 542, 543 fall 18,865 3495 30.0 13.6 5 0.633 0.425 0.60 0.90 15.20 5.9 61,057 82,805 4.4 63940 to AAC) 3 9 Doohholm 581, 582, 583, 18,865 5308 104.1 41.2 2 0.852 0.697 0.77 0.86 10.45 37.3 384,050 357,584 19.0 338719 584, 585 (all from 0.100 CU to 300 AACI 4 4 Kampalat 1030. 1031 fall 34.900 3715 91.0 46.4 5 0.79 0.562 0.78 0.92 15.24 27.1 244,966 343,623 9.8 308723 from 0.15 SCA to 300 AACI 5 39 Langata Ex. 1090,1091 (all 38,674 4409 127.6 46.1 5 0.529 0.339 0.95 0.96 15.24 73.6 242,026 494,097 12.8 455423 Nairobi from 0.075 CU to West 300 AAC) 6 40 Nairobi Dam 801,802,803, 54,710 3345 115.5 27.1 5 0.553 0.356 0.95 0.96 15.24 84.0 275,681 563,459 10.3 508749 804, 805 (all from C 0.075 SCA to 300 AAC) 7 11 Eastleigh 360, 361A (from 28,300 4124 205.5 83.1 5 0.569 0.372 0.95 0.97 15.24 110.5 398,867 778,725 27.5 750425 0.100 SAC to 300 AAC, 1.6 km); 362A, 362B, 362C, 362 (trom 0.100 CU to 300 AAC, 1.4 km) 8 13 Muthaiga 140A, 140B, 14,150 4091 43.4 18.5 4 0.564 0.388 095 0.90 13.36 22.5 124,767 178,562 12.6 164412 140C, 140, 141A (all from 0.100 CU to 300 AAC) 9 14 Westlands 251A, 251B, 37,450 4824 143.1 62.4 8 0.732 0.559 0.95 0.94 15.24 72.8 395,175 996,090 26.6 958640 251C, 251D, 251, 252A, 2528, 252C, 252D, 252E (from 0.100 CU to 300 AAC, 2.3 km); 250 (from 150mm UG to 300mm UG, 0.2 km) Table A2.5.1 Key Results of Proposals for Reconductoring and New Feeder additions - Nairobi City Valuation of Benefits Feeder Loss Savings No. Name Reconductored Investment Present Present Power Feeder Load Loss Peak Feeder Present Peak Energy Present Benefit Net Sections Cost Feeder Power Loss Load Factor Factor Respon- Power Worth Worth to Present Load Loss after Growth sibility Factor Factor Loss Benefits Improve- Ratio ment (1 (IkWI (kW) (kWi % (W IkWh/yr) (6, 10 16 Welbeck 180A, 180B, 27,360 4124 103.0 43.8 4 0.644 0.470 0.95 0.96 13.36 53.4 296.635 424,533 15.5 397173 ItOC, 180, 181A. 1818, 181C, 181 (all from 0.100 CU to 300 AAC, 2.9 km) 11 24 Breweryl 100, 101, 101B, 41,500 4631 212.2 74.2 3 0.706 0.575 0.80 0.96 11.79 88.3 695,106 782,964 18.9 741464 101C, iOIA, 102A, 102 (all from 0.100 SCA to 300 AAC, 4.4 ktn) 12 25 Brewery 11 120A, 1208. 120, 39,600 3948 145.0 67.30 5 0.813 0.674 0.80 0.95 15.24 49.7 458,759 639,918 16.2 600318 121, 122 (from 0.100 CU to 300 AAC, 0.8 kmr; 122A, 122B (from 1- 0.15 SCA to 300 AAC. 0.8 km) 13 52 AMlsopps 1020 (irom 0.150 31,900 4675 74.2 37.5 5 0.737 0.617 0.80 0.93 15.24 23.5 198,361 283,260 8.9 251360 SCA to 300 AAC, 0.9 km); 1023 (from 0.100 SCA to 300 AAC, 1.2 km); 1021 (from 0.075 SCA to 0.150 SCA, 1.9 km) 14 55 Sunrise 980, 981, 982 34,000 4727 88.2 46.4 4 0.480 0.319 0.95 0.98 13.36 37.7 116,808 215,562 6.3 181562 (from 0.150 SCA to 300 AAC, 2.2 km); 983 (from 0.075 SCA to 300 AAC, 1.4 km) 15 58 City 50, 51, 52 (all 20,800 5546 91.6 35.8 7 0.531 0.332 0.95 0.97 20.15 50.4 162,284 442,468 21.3 421668 Engineering from 0.100 SCA to 300 AACI Table A2.5.1 Key Results of Proposals for Reconductoring and New Feeder additions - Nairobi City Valuation of Benefits Feeder Loss Savings No. Name Reconductored Investment Present Present Power Feeder Load Loss Peak Feeder Present Peak Energy Present Benenit Net Sections Cost Feeder Power Loss Load Factor Factor Respon- Power Worth Worth to Present Load Loss after Growth sibility Factor Factor Loss Benefits Improve- Ratio ment IkWI IkW) (kWI 1%) (kW) fkWh/yr) I) 16 30 Lower Hill 510, 511, 512 (all 21,700 3345 76.2 32.1 5 0.742 0.594 0.92 0.84 15.24 44.1 228,000 273,000 12.6 251000 from 0.100 CU to 300 AACi 17 30 Lower Hil 512A 1+ new 47,000 3345 76.2 18.5 5 0.742 0.594 0.92 0.84 15.24 57.7 298,000 956.000 20.2 909000 feeder section? 18 38 Nairobi 940, 941, 942, 37,335 4840 116.6 25.9 5 0.623 0.456 0.95 0.98 15.24 90.7 362,000 627,000 16.8 589000 South B 943 (to 300 AAC; 950, 951, 944 Ito 0.15 SCA) 19 38 Nairobi 940, 941. 942. 70,559 4840 116.6 22.2 5 0.623 0.456 0.95 0.98 15.24 94.4 377.000 1886.000 23.9 1616000 South B 943 (to 300 AACI; 950, 951, 944 to 0.15 SCA); + new feeder section Note: The following economic parameters have been used in the above computations: Period of analysis - 15 years Interest rate - 10% Cost of power losses - $217/kw Cost of energy losses - $0.068/kWh For the new feeder option reliability benefits have also been computed - 109 - ECONOMIC ANALYSIS: PROPOSALS FOR FEEDER 30, LOWER HILL Table A2.5.2 EXISTING SYSTEM: Feeder 'Lower Hill' no. 30 from Reconductor New feeder and selected sections partial reconductoring Existing system loss: Peak losses, kW 76 76 Energy, MWh/yr. 394 394 Load factor 0.740 0.740 Loss factor 0.590 0.590 Load growth rate (p.a.), pu 0.02 0.02 Existing system load, MW 3.345 3.345 Maximum system capacity, MW 5.0 5.0 Capacity shortfall in: Not in study period PROPOSED SYSTEM Losses in new system Peak losses, kW 32.1 18.5 Energy, MWh/yr. 166 96 Loss savings at present load: kW at peak 44.1 57.7 MWh/year 228 298 Outage savings based on: saved outages/yr. 0 12 hrs./outage 3 3 Analysis period (Years): 10 15 10 15 Investment costs: Investment cost 0.022 0.022 0.047 0.047 PW of Residual value 0.007 0.000 0.016 0.000 Net Investment 0.014 0.022 0.032 0.047 Value of benefits: Loss reduction benefits 0.212 0.273 0.273 0.351 Reliability benefits 0.000 0.000 0.383 0.605 Total benefits 0.212 0.273 0.656 0.956 Benefit/cost ratios Loss reduction only 14.7 12.6 8.6 7.4 Loss red. + reliability 14.7 12.6 20.8 20.2 Net present values Loss reduction only 0.198 0.251 0.241 0.304 Loss red. + reliability 0.198 0.251 0.624 0.909 Examination of additional investment for new feeder option: Incremental investment with new feeder 0.017 0.026 Incremental benefits 0.444 0.683 Benefit/cost ratio 26.0 26.7 Net present value on incremental investment 0.427 0.658 Note: All investments and benefits in US$ millions Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - value of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate - 110 - ECONOMIC ANALYSIS: PROPOSALS FOR FEEDER 38, NAIROBI SOUTH Table A2.5.3 EXISTING SYSTEM: Feeder no. 38, Nairobi South B Existing system loss: Peak losses, kW 117 117 Energy, MWh/yr. 466 466 Load factor 0.623 0.623 Loss factor 0.456 0.456 Load growth rate ip.a.), pu 0.04 0.04 Existing system load, MW 4840 4840 Maximum system capacity, MW 5.0 5.0 Capacity shortfall in: Not in study period PROPOSED SYSTEM Reconductor New feeder and selected sections partial reconductoring Losses in new system Peak losses, kW 25.9 - 22.2 Energy, MWh/yr. 103 89 Loss savings at present load: kW at peak 90.7 94.4 MWh/year 362 377 Outage savings based on: saved outages/yr. 0 12 hrs./outage 3 3 Analysis period (Years): 10 15 10 15 Investment costs: Investment cost 0.037 0.037 0.071 0.071 PW of Residual value 0.012 0.000 0.024 0.000 Net Investment 0.025 0.037 0.047 0.071 Value of benefits: Loss reduction benefits 0.449 0.627 0.467 0.652 Reliability benefits 0.000 0.000 0.620 1.034 Total benefits 0.449 0.627 1.087 1.686 Benefit/cost ratios Loss reduction only 18.0 16.8 9.9 9.2 Loss red. + reliability 18.0 16.8 23.1 23.9 Net present values Loss reduction only 0.424 0.589 0.420 0.582 Loss red. + reliability 0.424 0.589 1.040 1.616 Examination of additional investment for new feeder option: Incremental investment with new feeder 0.022 0.033 Incremental benefits 0.638 1.060 Benefit/cost ratio 28.8 31.9 Net present value on incremental investment 0.616 1.026 Note: All investments and benefits in US$ millions Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 S/kWh - value of energy losses 0.076 S/kWh - value of additional load (new connections) 0.38 S/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate - 111 - Table A2.6 Economic Analysis of Capacitor Installion in Nairobi 11 kV lines Payback P.F. P.F. Rating Cost Savings Savings Savings Period B/C Feeder Name before after kvar US$ kW/yr $/yr MWh/yr Years Ratio 1 Outer ring rd. 0.73 0.96 200 4,950 2.2 805 4.8 6.1 2.1 2 Industr. l 0.84 0.94 1,400 14,350 13.4 4,903 29.3 2.9 4.4 3 Mogadishu 0.87 0.94 750 7,150 17.6 6,440 38.5 1.1 11.7 4 Doonholm Il 0.86 0.91 750 7,150 14.1 5,159 30.9 1.4 * 9.4 5 Muthaiga 0.90 0.94 500 6,350 4.8 1,756 10.5 3.6 3.6 6 Brewery II 0.90 0.96 900 8,000 23.9 8,745 52.3 0.9 14.2 7 Lower hill 0.84 0.92 800 11,850 15.6 5,708 34.2 2.1 * 6.3 8 Industrial 0.85 0.88 300 5,500 2.2 805 4.8 6.8 1.9 9 City square 0.79 0.90 400 6,000 1.2 439 2.6 13.7 1.0 10 Capitol II 0.83 0.89 750 7,150 7.0 2,561 15.3 2.8 4.7 11 Lower kab. 0.87 0.91 300 5,500 18.2 6,660 39.9 0.8 ' 15.7 12 Allsopps 0.93 0.97 750 7,150 7.1 2,598 15.5 2.8 4.7 13 Kayole 0.76 0.84 300 5,500 11.4 4,171 25.0 1.3 9.9 14 Dara I 0.86 0.91 300 5,500 2.3 842 5.0 6.5 2.0 15 Hill 11 0.88 0.91 200 4,950 1.4 512 3.1 9.7 1.3 Total for selected applications 6,700 73,800 46,948 280.9 1.6 8.3 Note: (1) While all applications studied shows a benefit to cost ratio greater than unity if a 10 year analysis period is considered on the basis of retaining existing system in present configuaration (multiplying factor used for present worth computation being 13.0), only those with a payback period less than 3 years is selected for aplication. (2) The selected applications are marked *. EXISTING SYSTEM - KIAMBU AREA FIG. A2.1.1 Muthoigo Feeder < - a ~~~~~~~~~~~~~~~~~~NYAGA \ / 9 \ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~40/llKV 66/11KV \ - X5 V Welbeck Feeder Y23 OPEN >m?~< OPENl/+14C - \ / X tO P N0 \ \ KITISURU A/ RURAKA > ~~~~~~~~~~~~66/1lKV 66/11KV / ~~~~~~~~~~~~~2XIOMVA J \ 2X23MVA 0 1 J 51 New Sections: Sec4 ond Sec5 , N R Ettder3 ( open ot St, SS, S6, Y283, ond Y237 13 ASRBRTEA TUSMEE Ne Selo:Sc mSAU EXISTING SYSTEM - KILELESHWA AREA FIG. 2.2.1 YS0S KABETE FEEDER(16) OPEN ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~PARKLANDS S/STN 0 | ] - RIVERSIDE FEEDER(19) 31 SwHILL 1 FEEDER(74) KIL PER CAUHEORAL S/Sm1N \ aosEo Y~~~~~~~~~~~~~~~~~~~5221l-I HURLINGHAM c HILL 2 FEEDER (75) B6O N FEEDER (36) \IYS 5 ^~~~~~~~~~~~~~~~~~~~~~~~~OEN NCONG RD. FEEDER (82) NAIRUBI WEST 66/11KV KAREN sT' LAVINGION FEEDER (61) FEEDER (34) O 1 2 3km a AIRBREAK SWITCH YSi SWTCH NUMBER OPEN STATUS PROPOSED SYSTEM - KILELESHWA AREA FIG. 2.2.2 Y420 iY462 OPEN KABETE FEEDER(16) OPEN I / ) , \ PARKLANoS S/STN \ FEEDER-\ X RIVERSIDE FEEDER(19) 7 / k Y5~~ ~ ~~~~~~~~~~~~~3# KAtlt N 0 FEEDER HILL 1 FEEDER(74) K LPROPOSED SITE FOR AL S/STN TN.~~~~~~~~~~~~~~~~~~~~~~~~~- Y6 q~" FEEDEHURLIN ( N HILL 2 FEEDER(75) ~~~~~~~~~~~~~~~FEEDER (3) |= ##zIvs NGON RD/NGOG D.2 ) FEEDER (82) NAIROBI WEST KAEN> LAVINGTON(61i\ FEEDER (34) J ff FEEDER (61 ) 0 1 2 3km o AIRBREAK SVMICH Y5I1 SWITCH NUMBER OPEN NORMAL SlATUS EXISTING SYSEM - FEEDERS NO. 38 & 69 FIG. 2.3.1 -NAIROBI WEST 66/1 I X "' .-..- \ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~- Q AIRD1REAK SWJITCII (OPEN) AIRBREAK SWITCFl (CLOSED) PROPOSED SYSEM - FEEDERS NO, 38 & 69 FIG. 2.3.2 NAIROBI SOUTH B NAIROBI WEST 66/1 1KV (FEEDER NO. 38) S/STN NAIROBI SOUTH 2R / / / ~~~~~~~(NEW FEEDER) NAIROBI SOUTH 2 SEC-I (FEEDER NO. 69) 40C~~~~~~~~~~~~~~~~~~~~- 9Q 4 NAIROBI SOUTH BR S (OPEN) I-<1 (NEW FEEDER) SWITCH (CLOSED) / _ < -zt ~~~~~~~~4 /STN A 942AR z> . > ~~~~~~~~~~~~4 0 AIRBREAK SWITCH (OPEN) (D AIRBREAK SWITCH (CLOSED) - 118 - Table A 3.1.1 LOAD CHARACTERISTICS - COASTAL AREA FEEDERS Feeder FEEDERNAME Ma" Min Peak Min Load Loss Loss LLF/ Feeder power factor data: No: Amps. Amps. Power Pwer Factor Fator TUbliln LF @ Night @ D.y Max Mat Avg. MW MW (LF) (LLF) Hrs/yr ratio Peak Peak 33 kV FEEDERS RABAI 220/1233 KV S/S I MIRIIN FEEDER 157 46 S200 2.300 0.61 0.39 3565 0.64 0.96 0.85 1.00 079 0.92 2 DIANI FEEDER 232 125 13.000 6.900 0.72 0.54 4609 0e75 0.93 0.93 0.9t 0.93 0.94 KILIFT 132133/ I KV S/S 5 MAUNDI FEEDER 155 g0 7900 4.600 O.73 0.49 4771 0.68 0.68 0.65 0.78 0,64 070 6 SHANZUFEEDER 35 2S 1.158 0.800 0.86 0.S1 652S 0.94 0.94 0.95 0.98 0.6 0.87 KIPEWV 132/33/11 KV S/S a BAM3BURI NO I (wk. end) 355 239 19.700 13.600 0.77 0.58 5229 0.75 0.98 0.97 0.99 0.96 0.93 8 BAMBLBURINO 1 (wk. day) 436 196 24.000 11.000 0.77 0.62 5423 0.81 0.96 0.97 0.93 0.91 0.97 9 8AMBULRINO2 FEEDER 213 154 12.000 9.100 0. 0.71 6314 0.84 0.90 0.97 0.98 0.96 0.97 10 BAMBURINO3 FEEDER 107 89 6.900 5.500 0.91 0.83 7236 0.97 . 0.04 0.36 0.37 0.77 0.82 11 KPRNO I FEEDER 63 53 3.500 2.600 0.87 0.33 6673 0.96 0.97 0.92 0.99 0.92 0.96 12 KPRNO 2 FEEDER 105 71 4900 3.400 0.35 0.66 6462 0.73 0.9 0.83 0.94 0.05 0.89 13 KPRNO3 FEEDER 35 31 2.400 2.100 0.91 0.83 7340 0.97 0.87 0.37 0.37 0.37 0.87 11 kV FEEDERS KTPEVU SUBSTATION SR-I CHANGAMWE FEEDER 125.3 32,16 2,229 1.478 0.79 0.69 5536 0,37 0.96 0.91 0.96 0.39 0.92 SR-2 ISLANDNO I FEEDER I39.2 %.36 3.101 1.731 0,31 0,63 5340 0.73 0.38 0.37 0.91 0.35 0.83 SR-3 ISLANDNO2FEEDER 179.4 98,71 3.024 1.877 0.82 0.63 5960 0.77 0.90 0.91 0.94 0.36 0.90 SR-4 PORT FEEDER 154.7 95.75 1.959 1.044 0.79 0.65 5633 0.32 0.32 0.77 0.33 0.65 0.76 NYALI S/S sr-inc NYALIINCOMER 444 336 3.000 3.600 0.65 0.42 3921 0.65 1.00 100 1.00 0.96 0.99 SR-S BAMBURI FEEDER 334.6 04.53 3.040 1.227 0.53 0.41 3130 0.70 0.95 0.35 0.96 0.31 0.39 SR-9 NYALI LOCAL FEEDER 207.3 13S.3 3.665 2.504 0.73 0.62 5339 0.79 0.92 0.37 0.93 0.36 0.39 SR-10 KISAUNI FEEDER 77.54 45.67 1.232 0.632 0.64 0.48 3626 0.76 0.95 0.91 0.97 0.39 0.92 MAKANDE S/S SR-inc MAKANDEINCOMER 311.3 156,4 5.380 2.656 0.69 .52 4325 075 0.92 0.90 0.93 0.84 0.33 SR-Il TOMMBOYA FEEDER 309.9 112.3 4.613 1.837 0.62 0.33 3579 0.52 0.92 0.86 0.94 0.77 0.37 SR-12 MWANGAKIFEEDER 203.6 84.2 3.411 1.550 0.71 0.50 4670 0.71 0.38 0.85 0.91 0.34 0.07 SR-13 PORTFEEDER 155.3 35.9 2.738 0.577 0.54 0.35 2917 0.65 0.96 0.94 0.97 0.39 0.94 SR-14 SHIMANZIFEEDER 130.7 71.68 2.215 1.365 0.79 0.53 5521 0.74 0.93 0.92 0.95 0.89 0.93 MBARAKI S/S SR-IN MBARAKIIINCOMERI 494 193.2 8.093 2.956 0.65 049 4031 0.75 0.04 0.87 0.90 0.75 0.84 Cn2 SR-IN MBARAKI INCOMER2 857.4 313.1 14.770 5.590 0.55 0.33 2793 0.60 o.g 0.96 0.99 0.95 0.98 In? SR-15 DIGO FEEDER 300.9 104.9 4.915 1.606 0.65 048 4059 0.74 0.82 0.86 0.36 0.74 0.83 SR-I5 DIGO(Repeat) 323.3 133.7 5.313 2.046 0.54 0.33 2731 0.61 0.85 0.87 0,90 0.34 0.86 SR-16 NYALI I FEEDER 198.9 47.8 3.410 0.906 0.48 0.27 2278 0.56 0.34 0.83 0.S6 0.70 0.SI SR-16 NYALI I (Repeat) 146.4 12.69 2.538 0.119 0.42 0.29 2059 0.68 0.34 0.35 0.86 0.63 0.77 SR-17 NYALU2FEEDER 210.4 80.9 3630 1.390 0.59 0.42 3256 0.72 0.92 0,91 0.93 0.S3 0.91 SR-IS SHIMANZIFEEDER 221.1 89.28 3.577 1.492 0.60 0.33 3363 0.63 0.85 0.84 0.85 0.82 O.34 SR-18 SHIMAANZ (Repeat) 236.3 76.79 3 727 1.304 0.68 0.49 4302 0.73 0.85 0.34 0.36 0.79 0.83 SR-19 MAKUPA FEEDER 12 106 3.060 3.S00 0.69 0.49 4190 0.71 0.09 0.88 0.92 0.85 0.88 SR-21 LIKONI 2FEEDER 54 1 21.5 1.035 0.423 0.66 0.44 4067 0.66 0.37 0.83 0.90 0.70 0.33 SR-20 LUKONI I-OPEN (SEE LIKONI SIS) SR-22 KENYA GLASS FEE-DER (OPEN) LIIONI S/S SR-23 MTONGWEFEEDER 79.0 43.3 1.320 0.5S9 0.59 0.47 3168 0.79 0.92 0.73 0.94 0.70 0.S3 SR-24 MBARAKI I FEEDER 139.3 55.34 2.535 0.994 0.66 0.40 4004 0.73 0.89 0.84 0.89 0.75 0.84 SR-26 SHELLY BEACH FEEDER 13.32 6.49 0.290 0.071 0.48 0.44 2297 0.90 0.97 0.94 0.99 0.93 0.97 SR-25 MBARAKT NO 2-OPEN (SEE MBARAKI S/S) KP.R S/S SR31I CHANGAMWEFEEDER 93.5 56.4 1630 1.065 0.30 0.58 5613 0.73 0.94 0.91 0.97 0.90 0.94 SR-32 PORTREITZ FEEDER 112.3 66.98 2.212 1.278 0.70 0,55 4338 073 0.95 0.91 0.96 0.90 0.92 SR-33 KENYA PIPEUNE FEEDER 33.2 67.49 1.570 1.299 0.39 0.76 6960 0.36 o.99 0.99 0.99 0.99 0.99 NIM: Mbaraki incomer has been measured with tnol. and without In21, the capacitor in service - 119 - Table A3.1.2 LOAD DENSITY OF 11 kV FEEDER AREAS - COASTAL AREA Feeder Feeder name Max Max power Area supplied Load density no: Amps kW meter sq. kW/km.sq. KIPEVU SUBSTATION 1. CHANGAMWE 125.3 2229 8,815,582 253 2. ISLAND NO 1 189.2 3101 bus bar 3. ISLAND NO 2 179.4 3024 bus bar 4. PORT 154.7 1959 Single consumer RIBE SUBSTATION 5. RIBE FDR 6.0 105 6,373,629 16 SHANZU SUBSTATION 6. SHIMOLA TEWA 145.0 2542 10,039,475 253 7. OCEANIC 227.0 4325 3,908,252 1107 NYALI SUBSTATION 8. BAMBURI 11 KV 184.6 3040 14,121,897 215 9. NYALI LOCAL 207.8 3665 4,200,336 873 10. KISAUNI 77.5 1232 3,863,694 319 MAKANDE SUBSTATION 11. TOMMBOYA 309.9 4613 3,986,661 1157 12. MWANGEKA 203.6 3411 677,779 5033 13. PORT 155.3 2738 1,453,441 1884 14. SHIMANZI 130.7 2215 168,464 13148 MBARAKI SUBSTATION 15. DIGO 323.3 5313 1,265,290 4199 16. NYALI 1 198.9 3410 1,995,527 1709 17. NYALI 2 210.4 3680 . bus bar 18. SHIMANZI 236.3 , 3727 580,435 6421 19. MAKUPA 182.0 3060 1,090,061 2807 21. LIKONI 2 54.1 1035 1,629,327 635 20. LIKONI 1 Open 22. KENYA GLASS Open LIKONI SUBSTATION 23. MTONGWE 79.0 1320 4,951,082 267 24. MBARAKI 1 139.3 2535 1,530,529 1656 26. SHELLY BEACH 13.8 290 8,845,498 33 25. MBARAKI NO 2-OPEN(SEE MBARAKI S/S) DIANI SUBSTATION 27. KWALE 19.0 322 11,776,654 27 28. DIANI NO 1 209.0 3744 9,626,973 389 29. DIANI NO 2 101.0 1712 2,573,318 665 30. TIWI 101.0 1751 25,481,448 69 K.P.R SUBSTATION 31. CHANGAMWE 93.5 1630 1,313,827 1241 32. PORTREITZ 112.3 2212 35,705,002 62 33. KENYA PIPELINE 83.2 1570 Single consumer MIRITINI SUBSTATION 34. AIRPORT 51.0 894 581,003 1539 35. MAZERAS 136.0 2332 18,200,406 128 36. ENDI TEXTILES 32.0 875 1,128,772 775 Table A3.2 SUMMARY OF LOAD FLOW RESULTS - 33 KV FEEDERS, COASTAL AREA PRESENT SYSTEM LOADS SYSTEM LOADS IN lOYrs. SYSTEM LOADS IN 15 Yrs. Load Connld FDR. FACTORS growth Trans ENERGY LOSSES IN % FDR SUB-STN. FEEDER NAME LOAD P.F LOAD LOSSES Volt Dr LOAD OSSES Volt Dr LOAD LOSSES Volt Dr rate capacity L.F LLF NO. (KVA) % (KW % % (KW) % % (KW % % % KVA presft 1 OYrs 1SYrs 1 RABAI Mlritini 9245 93 8600 6.0 7.2 16486 11.7 14.0 23361 17.0 20.1 6 10000 0.61 0.39 3.8 7.5 10.8 2 Diani 13743 93 12779 10.4 15.6 23352 21.5 32.4 29804 35.0 55.0 * 5 22500 0.72 0.54 7.8 16.1 26.2 3 KILIFI Jaribuni 572 88 503 0.2 0.3 503 0.2 0.3 553 0.2 0.4 3 730 0.48 0.27 0.1 0.1 0.1 4 Baricho 1715 88 1509 2.0 3.0 1819 2.4 3.6 1974 2.6 3.9 3 4175 0.48 0.27 1.1 1.3 1.4 5 Malindi 9031 90 7984 23.1 29.7 12596 39.4 51.4 16856 50.0 65.0 * 6 16300 0.73 0.49 15.5 26.5 33.6 6 Shanzu 4001 88 3521 4.5 6.7 5117 5.4 8.2 6394 8.8 10.4 3 8010 0.86 0.81 4.3 5.0 6.4 7 KIPEVU Mbaraki-1 17719 94 16657 0.9 1.4 25104 1.4 2.2 30212 1.7 2.6 4 46000 0.75 0.59 0.7 1.1 1.3 8 Bamburl 1 24998 96 23997 2.6 5.3 44296 5.1 10.3 60384 7.1 14.5 10 27500 0.77 0.62 2.1 4.1 5.8 o 9 Bamburi2 14861 97 14413 4.1 5.7 22152 6.4 9.1 27018 7.9 11.4 4 25000 0.85 0.71 3.4 5.3 6.5 10 Bamburi 3 13146 92 12096 3.3 5.1 18497 5.2 8.0 22478 6.3 9.8 4 10700 0.91 0.88 3.2 5.0 8.1 11 Kpr1(33KV) 3241 95 3079 0.3 0.4 3697 0.4 0.5 4007 0.4 0.5 2 17500 0.87 0.83 0.3 0.4 0.4 12 Kpr2(33"V) 6859 90 6174 0.4 0.6 7415 0.5 0.7 8036 0.5 0.8 2 12500 0.85 0.66 0.3 0.4 0.4 13 Kpr3(33KV) 9717 91 8844 0.6 0.8 10625 0.7 1.0 11517 0.7 1.1 2 5000 0.91 0.88 0.5 0.7 0.7 ForTolalSystem 128845 120156 4.8 191659 9.0 242594 13.1 203915 3.47 6.47 9.30 Average annual growth rate between periods: 4.78 4.80 Average power factor for system: 93% Average transformer utilization in % 0.63 Note: Alt feeder results have been computed by using the load flow program DPAtG. . indicates where the program failed to converge (estimated values used) Table A3.3 SUMMARY OF LOAD FLOW RESULTS - 11 RV E1EDERS, COASTAL AREA PRESENT SYSTEM LOADS SYSTEM LOADS IN 1OYrs. SYSTEM LOADS IN 15 Yrs. Load Conn/d FDR. FACTORS growth Trans ENERGY LOSSES IN % FDR SUB-STN. FEEDER NAME LOAD P.F LOAD LOSSES Volt Dr LOAD OSSES Volt Dr LOAD LOSSES Volt Dr rate capacity L.F LLF NO (KVA) % (KVV % % (KW)I % % (KV0 % % % KVA preslt lOYrs 15Yrs 1 KIPEVU Changamwe 2294 96 2103 1.7 2.6 3560 2.6 4.2 4714 3.4 5.6 5 14660 0.79 0.69 1.4 2.2 3.0 2 Island 1 3470 87 3019 0.9 1.2 3630 1.1 1.5 3937 1.2 1.6 2 13875 0.81 0.63 0.7 0.9 1.0 3 Island 2 3235 89 2879 0.9 1.1 3461 1.1 1.4 3753 1.2 1.5 2 3265 0.82 0.63 0.7 0.8 0.9 5 RIBE Ribe(Kaloleni) 114 92 105 0.3 0.5 115 0.3 0.5 128 0.4 0.6 1 700 0.58 0.37 0.2 0.2 0.2 6 SHANZU Shimolatewa 2763 92 2542 0.9 2.5 3057 1.1 3.0 3315 1.2 3.3 2 7185 0.75 0.58 0.7 0.9 1.0 7 Oceanic 4326 92 3980 2.1 4.2 5208 2.7 5.5 6455 3.4 6.9 3 11790 0.65 0.46 1.5 1.9 2.4 8 NYALI Bamburi-11 3447 95 3275 7.9 13.6 7601 20.7 34.1 10661 40.0 55.0 7 13702 0.58 0.41 5.6 14.5 28.1 9 Nyaliloc 3875 92 3566 5.7 8.3 4733 7.6 11.1 5960 9.7 14.1 3 7955 0.78 0.62 4.5 6.0 7.7 10 Kisauni 1390 95 1321 0.3 0.8 1984 0.5 1.2 2383 0.6 1.4 4 6870 0.64 0.48 0.2 0.3 0.4 11 MAKANDE Tom mboya 5904 87 5137 1.1 2.8 7722 1.7 4.2 9337 2.1 5.1 4 11930 0.62 0.33 0.6 0.9 1.1 12 Mwangeka 3847 85 3271 1.0 2.0 5267 1.7 3.2 6952 2.2 4.3 5 10435 0.71 0.51 0.7 1.2 1.6 13 Port 2959 94 2782 1.3 2.3 3631 1.7 3.0 4488 2.1 3.7 3 9715 0.54 0.35 0.8 1.1 1.4 14 Shimanzi 2427 90 2185 0.4 0.6 3504 0.6 1.0 4608 0.8 1.3 5 4910 0.79 0.58 0.3 0.5 0.6 15 MBARAKI Digo 6868 81 5402 2.9 5.0 6528 3.6 6.1 7096 4.0 6.8 2 9975 0.55 0.33 1.8 2.2 2.4 16 Nyali 1 3790 81 3070 2.1 2.2 3700 2.5 2.6 4017 2.7 2.9 2 1830 0.48 0.27 1.1 1.4 1.5 17 Nyali 2 4009 91 3648 2.1 3.0 4398 2.5 3.7 4775 2.7 4.0 2 10765 0.59 0.42 1.5 1.8 2.0 18 Shimanzl 4382 83 3638 1.3 2.4 4749 1.8 3.1 5870 2.2 3.9 3 7535 0.68 0.49 1.0 1.3 1.6 > 19 Makupa 5906 88 5198 1.5 2.4 6790 1.9 3.1 8397 2.4 3.9 3 8455 0.69 0.49 1.0 1.4 1.7 ' 20 Likoni 2 2575 81 2085 1.0 1.5 3145 1.5 2.3 3786 1.8 2.7 4 4970 0.66 0.44 0.7 1.0 1.2 21 LIKONI Mtongwe 1505 92 1385 2.2 3.1 1813 2.9 4.1 2248 3.6 5.0 3 5050 0.59 0.47 1.7 2.3 2.8 22 Mbaraki-1 2667 83 2214 1.9 2.7 2667 2.3 3.3 2896 2.4 3.6 2 5975 0.66 0.48 1.4 1.6 1.8 23 Shelly 572 97 554 0.2 0.5 722 0.3 0.6 889 0.3 0.8 3 2495 0.48 0.44 0.2 0.2 0.3 24 DIANI Kwale 362 89 322 6.6 7.1 429 8.7 9.5 541 11.0 12.0 3 1555 0.62 0.41 4.3 5.7 7.2 25 Diani 1 3982 94 3744 8.5 13.4 7528 18.1 28.4 12146 32.3 49.6 6 12260 0.68 0.47 5.9 12.6 22.6 26 Diani 2 1924 89 1712 2.7 3.6 2607 4.1 5.5 3157 5.0 6.7 4 4220 0.77 0.60 2.1 3.2 3.9 27 Tiwi 1924 91 1751 3.4 5.3 2680 5.3 8.2 3257 6.5 10.0 4 3125 0.77 0.60 2.7 4.2 5.1 28 KPR Changamwe 1781 94 1675 0.4 0.6 2686 0.7 1.0 3533 0.9 1.4 5 14460 0.80 0.58 0.3 0.5 0.6 29 Portreitz 2140 92 1969 1.7 2.8 2980 2.5 4.2 3596 3.1 5.1 4 10515 0.70 0.55 1.3 2.0 2.4 30 Kpi 1585 99 1569 0.3 0.4 2042 0.4 0.5 2515 0.5 0.6 3 2000 0.89 0.76 0.2 0.3 0.4 31 MIRITINI Airport 972 92 894 0.1 0.2 1073 0.1 0.2 1163 0.1 0.2 2 2630 0.79 0.63 0.1 0.1 0.1 32 Mazeras 2591 90 2332 7.3 15.1 3999 13.5 27.3 5814 21.9 42.6 5 11570 0.44 0.26 4.3 8.0 13.0 33 Endi-Textile 972 90 875 0.42 0.54 1138 0.6 0.7 1403 0.7 0.87 3 2615 0.39 0.22 0.2 0.3 0.4 ForTotal System 90358 80202 2.47 115147 4.95 143787.8 8.84 238992 1.68 3.31 5.83 Average annual growth rate between periods: 3.68 3.97 Average power factor for system: 0.89 Average transformer utilization In % 38 Note: All feeder results have been computed by using the load flow program DPAIG. indicates where the program failed to converge (estimated values used) - 122 - ECONOMIC ANALYSIS: Table A3.4 PROPOSALS FOR NEW SUBSTATION AT DIANI EXISTING SYSTEM: SC 0.15 in.sq. 33 kV line from Rabai to Diani Existing system loss: Peak losses, kW 653 Energy, MWh/yr. 3066 Load factor (combined) 0.715 Loss factor (combined) 0.536 Load growth rate (p.a.), pu 0.05 Existing system load, MW 8.3 Maximum system capacity, MW 10.0 Capacity shortfall in: 1997 PROPOSED SYSTEM SC 0.15 SC 0.15 on wood poles on steel poles Losses in new system Peak losses, kW 47 47 Energy, MWh/yr. 223 223 Loss savings at present load: kW at peak 606 606 MWh/year 2843 2843 Outage savings based on: saved outages/yr. 12 1 2 hrs./outage 3 3 Analysis period (Years): 10 15 10 1 5 Investment costs: Investment cost 3.500 3.500 6.038 6.038 PW of Residual value 2.333 1.750 4.025 3.019 Net Investment 1.167 1.750 2.013 3.019 Value of benefits: Loss reduction benefits 3.289 4.961 3.289 4.961 Reliability benefits 1.123 1.927 1.123 1.927 Additional load supplied 2.616 6.457 2.616 6.457 Total benefits 7.028 13.345 7.028 13.345 Benefit/cost ratios Loss reduction only 2.82 2.83 1.63 1.64 Loss red. + reliability 3.78 3.94 2.19 2.28 All three benefits 6.02 7.63 3.49 4.42 Net present values Loss reduction only 2.122 3.211 1.276 1.942 Loss red. + reliability 3.245 5.138 2.399 3.869 All three benefits 5.861 11.595 5.015 10.326 Note: All investments and benefits in US$ millions Economic parameters used in computations: 217 S/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - value of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate - 123 - ECONOMIC ANALYSIS: Table A3.5 PROPOSALS FOR IMPROVEMENTS TO TIWI FEEDER EXISTING SYSTEM: 11 kV Tiwi feeder from Diani Substation Existing system loss: Peak losses, kW 60 Energy, MWh/yr. 317 Load factor (combined) 0.777 Loss factor (combined) 0.603 Load growth rate (p.a.), pu 0.04 Existing system load, MW 1.8 Maximum system capacity, MW no restriction PROPOSED SYSTEM New 33/11 kV New 11 kV Reconductor Sub Station Feeder selected sections Losses in new system Peak losses, kW 14 29 26 Energy, MWh/yr. 75 151 136 Loss savings at present load: kW at peak 46 31 34 MWh/year 242 165 181 Outage savings based on: saved outages/yr. 12 5 0 hrs./outage 3 3 0 Analysis period (Years): 10 15 10 15 10 15 Investment costs: Investment cost 0.265 0.265 0.080 0.080 0.141 0.141 PW of Residual value 0.132 0.066 0.027 0.000 0.047 0.000 Net Investment 0.132 0.198 0.054 0.080 0.094 0.141 Value of benefits: Loss reduction benefits 0.241 0.347 0.165 0.237 0.180 0.259 Reliability benefits 0.224 0.374 0.093 0.156 0.000 0.000 Additional load supplied 0.000 0.000 0.000 0.000 0.000 0.000 Total benefits 0.465 0.721 0.258 0.393 0.180 0.259 Benefit/cost ratios Loss reduction only 1.82 1.75 3.07 2.95 1.92 1.84 Loss red. + reliability 3.52 3.64 4.81 4.88 1.92 1.84 Net present values Lossreductiononly 0.109 0.149 0.111 0.157 0.086 0.118 Loss red. + reliability 0.333 0.523 0.204 0.312 0.086 0.118 Note: All investments and benefits in US$ millions Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - value of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate - 124 - ECONOMIC ANALYSIS: Table A3.6 AUGMENTATION AND IMPROVEMENTS TO GALU SUBSTATION EXISTING SYSTEM: 2.5 MVA Substation and existing 1 1 kV network Existing system loss: Peak losses. kW 193 Energy, MWh/yr. 796 Load factor (combined) 0.675 Loss factor (combined) 0.472 Load gro wth rate (p.a.), pu 0.06 Existing system load, MW 3.6 Maximum system capacity, MW 4.0 PROPOSE-D SYSTEM New 33/1 1kV Sub Station augmentation to 7.5 MVA with reconductoring no reconductoring Losses in new system Peak losses, kW 38 129 Energy, MWh/yr. 157 532 Loss savings at present load: kW atpeak 155 -64 MWh/year 639 264 Outage savings based on: saved outages/yr. 7 4 hrs./outage 3 3 Analysis period (Years): 10 1 5 1 0 1 5 Investment costs: Investment cost 0.336 0.336 0.236 0.236 PW of Residual value 0.168 0.084 0.118 0.059 Net Investment 0.168 0.252 0.118 0.177 Value of benefits: Loss reduction benefits 0.867 1.375 0.358 0.567 Reliability benefits 0.303 0.535 0.173 0.305 Additional load supplied 2.366 4.771 2.366 4.771 Total benefits 3.536 6.681 2.897 5.644 Benefit/cost ratios Loss reduction only 5.16 5.46 3.03 3.21 Loss red. + reliability 6.96 7.58 4.50 4.93 All three benefits 21.05 26.51 24.55 31.89 Net present values Loss reduction only 0.699 1.123 0.240 0.390 Loss red. + reliability 1.~002 1.657 0.413 0.696 All three benefits 3.368 6.429 2.779 5.467 Exarninatron of additional investmgnt for new feeder gotion: Incremental investment with reconductoring 0.075 Incremental benefits 1.037 Benefit/cost ratio 13.8 Net present value on incremental investment 0.962 Note: All investments and benefits in USS millions Economic parameters used in computations: 21 7 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - value of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate The existing system includes some reinforcements under way to reduce system losses The SS augmentation enables operating configuration of feeders to be changed - 125 - ECONOMIC ANALYSIS: 132 kV UNE AND SUBSTATION AT BAMBURI Table A3.7 EXISTING SYSTEM: Existing system loss: Peak losses, kW 1552 Energy, MWh/yr. 8456 Load factor (combined) 0.770 Loss factor (combined) 0.622 Load growth rate (p.a.), pu 0.1 Existing system load, MW 50.4 Maximum system capacity, MW 75.0 Capacity shortfall in: 1998 PROPOSED SYSTEM All alternatives with 132 kV Line, Kinevu-Bamburi and 132/33 kV Substation at Bamburi DC line 0.20 SCA DC line 0.15 SCA SC line 0.20 SCA SC line 0.15 SCA Losses in new system Peak losses, kW 187 342 445 552 Energy, MWh/yr. 1019 1863 2425 3008 Loss savings at present load: kW at peak 1365 1210 1107 1000 MWh/year 7438 6593 6032 5449 Outage savings based on: saved outages/yr. 12 12 6 6 hrs. /outage 3 3 3 3 Analysis period (Years): 10 15 10 15 10 15 10 15 Investment costs: Investment cost 7.9 7.9 7.2 7.2 6.8 6.8 6.2 6.2 PW of Residual value 5.3 4.0 4.8 3.6 4.5 3.4 4.1 3.1 Net Investment 2.6 4.0 2.4 3.6 2.3 3.4 2.1 3.1 Value of benefits: Loss reduction benefits 14.1 28.0 12.5 24.8 11.4 22.7 10.3 18.1 Reliability benefits 9.1 18.1 9.1 18.1 4.5 9.0 4.5 8.0 Additional load supplied 40.8 113.9 40.8 113.9 40.8 113.9 40.8 113.9 Total benefits 63.9 160.0 62.3 156.8 56.7 145.7 55.6 139.9 Benefit/cost ratios Loss reduction only 5.3 7.1 5.2 6.9 5.0 6.7 5.0 5.9 Loss red. + reliability 8.8 11.7 9.0 12.0 7.0 9.4 7.2 8.4 All three benefits 24.3 40.5 26.0 43.7 25.1 42.9 27.0 45.3 Net present values Loss reduction only 11.4 24.1 10.1 21.3 9.1 19.3 8.2 15.0 Loss red. + reliability 20.5 42.2 19.1 39.3 13.7 28.4 12.8 23.0 All three benefits 61.3 156.1 59.9 153.2 54.5 142.3 53.6 136.9 Examination of increase of line sections from 0.15 to 0.2 SCA Incremental net investment 0.240 0.360 0.203 0.305 Incremental total benefits 1.596 3.183 1.102 5.735 Benefit/cost ratio 6.7 8.8 5.4 18.8 Present value of incremental investme 1.596 3.183 1.102 5.735 All investments and benefits in US$ millions Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - value of additional load (new connections) 0.38 S/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate - 126 - ECONOMIC ANALYSIS: Table A3.8 PROPOSED DEVELOPMENTS FOR MALINDI EXISTING SYSTEM: Existing system loss: Peak losses, kW 1842 Energy, MWh/yr. 7907 Load factor 0.730 Loss factor 0.490 Load growth rate (p.a.), pu 0.06 Existing system load, MW 8.0 Maximum system capacity, MW 8.0 Capacity shortfall in: 1994 PROPOSED SYSTEM Wood pole Steel pole Reconductor to 132 kV line 132 kV line 300 mm. sq. Losses in new system Peak losses, kW 138 138 400 Energy, MWh/yr. 592 592 1717 Loss savings at present load: kW at peak 1704 1704 1442 MWh/year 7314 7314 6190 Outage savings based on: saved outages/yr. 4 4 0 hrs./outage 25 30 0 Analysis period (Years): 10 15 10 15 10 15 Investment costs: Investment cost 3.337 3.337 7.082 7.082 1.850 1.850 PW of Residual value 1.669 0.834 4.721 3.541 0.617 0.000 Net Investment 1.669 2.503 2.361 3.541 1.233 1.850 Value of benefits: Loss reduction benefits 9.763 15.479 9.763 15.479 8.262 13.099 Reliability benefits 3.179 5.614 3.815 6.737 0.000 0.000 Additional load supplied 7.940 14.261 7.940 14.261 5.278 7.409 Total benefits 20.882 35.354 21.518 36.477 13.541 20.509 Benefit/cost ratios Loss reduction only 5.85 6.18 4.14 4.37 7.77 8.22 Loss red. + reliability 7.76 8.43 5.75 6.27 6.70 7.08 All three benefits 12.52 14.13 9.12 10.30 10.98 11.09 Net present values Loss reduction only 8.095 12.977 7.403 11.938 7.200 11.505 Loss red. + reliability 11.274 18.591 11.218 18.675 7.200 11.505 All three benefits 19.214 32.851 19.158 32.936 14.237 21.385 Note: All investments and benefits in US$ millions Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - value of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate - 127 - ECONOMIC ANALYSIS: PROPOSED DEVELOPMENTS AT MAZERAS AND RABAI Table A3.9 EXISTING SYSTEM: 11 kV Mazeras feeder from Miritini Existing system loss: Peak losses, kW 169 Energy, MWh/yr. 391 Load factor 0.444 Loss factor 0.264 Load growth rate (p.a.), pu 0.05 Existing system load, MW 2.3 Maximum system capacity. MW 4.0 Capacity shortfall in: 2004 PROPOSED SYSTEM SS at Rabai SS at Mazeras Conversion to 33 kV Losses in new system Peak losses, kW 15 72 15 Energy, MWh/yr. 35 167 35 Loss savings at present load: kW at peak 154 97 154 MWh/year 356 224 356 Outage savings based on: saved outages/yr. 10 10 0 hrs./outage 3 3 0 Analysis period (Years): 10 15 10 15 10 15 Investment costs: Investment cost 0.400 0.400 0.493 0.493 0.305 0.305 PW of Residual value 0.200 0.100 0.247 0.123 0.102 0.000 Net Investment 0.200 0.300 0.247 0.370 0.204 0.305 Value of benefits: Loss reduction benefits 0.583 0.879 0.368 0.555 0.583 0.879 Reliability benefits 0.263 0.452 0.263 0.452 0.000 0.000 Additional load supplied 0.000 0.160 0.000 0.160 0.000 0.160 Total benefits 0.846 1.491 0.631 1.166 0.583 1.039 Benefit/cost ratios Loss reduction only 2.91 2.93 1.49 1.50 2.86 2.88 Loss red. + reliability 4.23 4.44 2.56 2.72 2.86 2.88 All three benefits 4.23 4.97 2.56 3.15 2.86 3.40 Net present values Loss reduction only 0.383 0.579 0.121 0.185 0.379 0.574 Loss red. + reliability 0.646 1.031 0.384 0.637 0.379 0.574 All three benefits 0.646 1.191 0.384 0.796 0.379 0.734 Note: All investments and benefits in US$ millions The existing system includes some reinforcements under way to reduce system losses The SS augmentation enables operating configuration of feeders to be changed Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - value of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate - 128 - ECONOMIC ANALYSIS: Table A3.10 PROPOSED DEVELOPMENTS FOR TOM MBOYA FEEDER EXISTING SYSTEM: 11 kV feeder from Makande Existing system loss: Peak losses, kW 58 Energy, MWh/yr. 164 Load factor 0.622 Loss factor 0.325 Load growth rate (p.a.), pu 0.04 Existing system load, MW 5.1 Maximum system capacity. MW 10.0 Capacity shortfall in: 2010 PROPOSED SYSTEM New substation New substation New feeder and at Buxton at Buxton reconductoring Losses in new system Peak losses, kW 17 17 38 Energy, MWh/yr. 48 48 110 Loss savings at present load: kW at peak 51 * 41 19 MWh/year 144 * 116 55 Outage savings based on: saved outages/yr. 3 3 3 hrs./outage 5 5 3 Analysis period (Years): 10 15 10 15 10 15 Investment costs: Investment cost 0.349 0.349 0.279 0.279 0.060 0.060 PW of Residual value 0.174 0.087 0.139 0.070 0.020 0.000 Net Investment 0.174 0.261 0.139 0.209 0.040 0.060 Value of benefits: Loss reduction benefits 0.190 0.274 0.152 0.220 0.072 0.104 Reliability benefits 0.274 0.457 0.274 0.457 0.165 0.274 Additional load supplied 0.000 0.000 0.000 0.000 0.000 0.000 Total benefits 0.464 0.731 0.427 0.677 0.237 0.378 Benefit/cost ratios Loss reduction only 1.09 1.05 1.10 1.05 1.80 1.73 Loss red. + reliability 2.66 2.80 3.06 3.24 5.91 6.30 Total benefits 2.66 2.80 3.06 3.24 5.91 6.30 Net present values Loss reduction only 0.016 0.012 0.013 0.011 0.032 0.044 Loss red. + reliability 0.290 0.470 0.287 0.468 0.197 0.318 Total benefits 0.290 0.470 0.287 0.468 0.197 0.318 Note: All investments and benefits in US$ millions. The new SS option will also provide additional loss reduction benefits of 10 kW from other adjacent feeders In the first evaluation these benefits and corresponding costs are also added to the computation. (However additional reliability benefits are not included) Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses 0.076 $/kWh - vaiue of additional load (new connections) 0.38 $/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate - 129 - Table A3.11 ECONOMIC ANALYSIS: PROPOSED DEVELOPMENTS FOR BAMBURI FEEDER FROM NYALI EXISTING SYSTEM: 11 kV Bamburi feeder from Nyali Existing system loss: Peak losses, kW 260 Energy, MWh/yr. 934 Load factor 0.583 Loss factor 0.410 Load growth rate (p.a.), pu 0.07 Existing system load, MW 3.2 Maximum system capacity, MW 4.0 Capacity shortfall in: 1997 PROPOSED SYSTEM New feeder and reconductoring Losses in new system Peak losses, kW 122 Energy, MWh/yr. 439 Loss savings at present load: kW at peak 138 MWh/year 495 Outage savings based on: saved outages/yr. 3 hrs./outage 8 Analysis period (Years): 10 15 Investment costs: Investment cost 0.084 0.084 PW of Residual value 0.028 0.000 Net Investment 0.056 0.084 Value of benefits: Loss reduction benefits 0.797 1.333 Reliability benefits 0.324 0.589 Additional load supplied 1.496 3.566 Total benefits 2.617 5.487 Benefit/cost 'atios Loss reduction only 14.24 15.87 Loss red. + reliability 20.02 22.87 All three benefits 46.74 65.32 Net present values Loss reduction only 0.741 1.249 Loss red. + reliability 1.065 1.837 All three benefits 2.561 5.403 Note: All investments and benefits in US$ millions. Economic parameters used in computations: 217 $/kW - value of peak power losses 0.068 $/kWh - value of energy losses - 0.076 S/kWh - value of additional load (new connections) 0.38 S/kWh - value of outage savings 0.75 p.u. load at (avoided) outage 0.1 p.u. discount rate Table A3.12 Application of capacitors for 11 kV feeders in Mombasa Present Feeder Present Energy Power Loss Substation Capacitor Size Power Loss Loss with Capacitor Power Saved Energy Saved Investment Feeder No. Naine Feeder Name kVAr kW kWh/yr. kW kW kWh/yr Cost $ 8 NYALI BAMBURI 300 260 934,929 243 17 30,457 5,500 15 MBARAKI DIGO 900 161 470,992 133 28 41,466 8,000 16 MBARAKI NYALI 1 600 86 365,898 71 15 31,078 6,670 25 DIANI DIANI 1 300 317 1310,210 300 17 35,848 5,500 28 MIRITINI MAZERAS 300 169 391,969 146 23 26,328 5,500 TOTAL - _ 2400 993 3,473,998 L 895 100 165,177 31,170 l Value of loss reduction benefits: Peak power savings = $100 x 217 = $21700 0 Annual energy savings = $165177 x 0.068 = $11232 Total value of savings per year = $32,932 Investment cost = $31170 Payback period = 11.35 months Benefit to Cost ratio = 13.7 Table A4.1 Results of LV system loss studies (existing networks) Power Loss Energy Loss per year Transformer Network Total Transformer Network Total Transformer No. Total Peak load Ann. Ener. length m kW kWh kW % kW % kW/km kWh % kWh % kWh/km 510757 625 127 534,010 2.4 1.9 2.4 1.9 7.7 5,472 1.0 5472 1 17,519 514610 405 232 1,036,483 3.6 1.6 20.4 8.8 59.2 8,903 0.9 50449 4.9 146,476 510762 2329 266 1,561,207 3.4 1.3 7.2 2.7 4.6 10,200 0.7 21600 1.4 13,657 510754 4415 Included In Tf. No. 510762 632015 178 124 325,872 1.3 1.0 0.6 0.5 10.7 1,320 0.4 609 0.2 10,846 630056 188 142 410,494 1.4 1.0 1.2 0.8 13.9 1,726 0.4 1480 0.4 17,079 582010 606 18 59,918 0.3 1.7 2.4 13.3 4.5 462 0.8 3694 6.2 6,858 422346 526 167 819,235 2.2 1.3 2.4 1.4 8.7 6,554 0.8 7150 0.9 26,062 584511 1410 100 499,320 1.9 1.9 2.4 2.4 3.0 5,860 1.2 7402 1.5 9,404 630000 668 398 1,359,727 2.9 0.7 1.2 0.3 6.1 5,008 0.4 2072 0.2 10,600 260587 2163 137 732,073 1.7 1.2 27.6 20.1 13.5 5,989 0.8 97235 13.3 47,727 582768 2420 70 355,656 0.9 1.3 2.4 3.4 1.4 2,830 0.8 7546 2.1 4,288 423414 936 334 1,492,178 3.4 1.0 8.4 2.5 12.6 11,475 0.8 28350 1.9 42,562 420711 633 Included in Tf. No.423414 141741 1792 Included in Tf. No.423414 70066 2887 108 529,805 1 0.9 9.6 8.9 3.7 3,377 0.6 32419 6.1 12,399 250721 3038 115 664,884 1.4 1.2 15.6 13.6 5.6 5,548 0.8 61823 9.3 22,175 2312759 422 212 798,562 3.1 1.5 8.4 4.0 27.3 7,979 1 21622 2.7 70,145 234080 3044 Included in Tf. No. 2312759 120741 354 117 379,220 1.1 0.9 1.3 1.1 6.8 1,625 0.4 1920 0.5 10,028 260586 1894 63 292,496 0.6 1.0 2.4 3.8 1.6 1,646 0.6 6583 2.3 4,345 582723 3737 474 2,117,642 2.8 0.6 57.6 12.2 16.2 7,081 0.3 145670 6.9 40,879 Total 34670 3204 13,968,784 35.4 174 93,054 503095 Average per transformer 1576 1.00 4.62 0.58 2.81 23,320 Average for group 1.10 5.40 5.02 0.67 3.60 14,513 - 132 - Table A4.2.1A TRANSFORMER POWER AND ENERGY LOSSES (For varying Load Factors) 25 KVA KPLC Transformer Load Factor = 0.60 0.50 0.30 0.20 Loss Factor = 0.41 0.30 0.13 0.07 Load in Power Losses Energy Losses in percent % rating in W in % 10 147 6.37 10.34 12.34 20.41 30.54 20 166 3.61 5.46 6.43 10.39 15.42 30 199 2.88 3.96 4.57 7.14 10.45 40 244 2.65 3.30 3.72 5.57 8.02 50 303 2.63 2.99 3.28 4.68 6.60 60 374 2.71 2.84 3.05 4.13 5.68 70 459 2.85 2.79 2.93 3.77 5.06 80 556 3.02 2.81 2.88 3.53 4.62 90 667 3.22 2.86 2.88 3.37 4.30 100 790 3.43 2.94 2.91 3.27 4.06 N= Particulars used in the computation: 140 = No load loss in Watts 650 = Full load loss in Watts 0.92 = power factor of load Formula used for loss load factor: LLF = 0.2*LF + 0.8*LF^2 Table A4.2.11B TRANSFORMER POWER AND ENERGY LOSSES (For varying Load Factors) 25 KVA Low Loss Transformer Load Factor = 0.60 0.50 0.30 0.20 Loss Factor = 0.41 0.30 0.13 0.07 Load in Power Losses Energy Losses in percent % rating in W in % 10 61 2.65 4.25 5.06 8.34 12.45 20 73 1.58 2.30 2.68 4.28 6.32 30 92 1.33 1.72 1.96 2.98 4.31 40 119 1.30 1.49 1.65 2.36 3.34 50 155 1.34 1.40 1.50 2.03 2.78 60 197 1.43 1.38 1.44 1.82 2.43 70 248 1.54 1.40 1.42 1.70 2.20 80 307 1.67 1.44 1.43 1.63 2.04 90 373 1.80 1.50 1.47 1.59 1.93 100 447 1.94 1.57 1.51 1.57 1.85 Nte1 Particulars used in the computation: 57 = No load loss in Watts 390 = Full load loss in Watts 0.92 = power factor of load Formula used for loss load factor: LLF = 0.2*LF + 0.84LF^2 - 133 - Table A4.2.2A TRANSFORMER POWER AND ENERGY LOSSES (For varying Load Factors) 50 KVA KPLC Transformer Load Factor = 0.60 0.50 0.30 0.20 Loss Factor = 0.41 0.30 0.13 0.07 Load in Power Losses Energy Losses in percent % rating in W in % 10 192 4.17 6.70 7.98 13.16 19.66 20 228 2.48 3.62 4.23 6.75 9.97 30 288 2.09 2.71 3.08 4.69 6.80 40 372 2.02 2.34 2.58 3.72 5.27 50 480 2.09 2.19 2.35 3.18 4.38 60 612 2.22 2.15 2.24 2.86 3.82 70 768 2.39 2.17 2.21 2.67 3.45 80 948 2.58 2.23 2.23 2.55 3.20 90 1152 2.78 2.32 2.28 2.48 3.02 100 1380 3.00 2.43 2.35 2.45 2.90 Nol Particulars used in the computation: 180 = No load loss in Watts 1200 = Full load loss in Watts 0.92 = power factor of load Formula used for loss load factor: LLF = 0.2*LF + 0.84LF^2 Table A4.2.2B TRANSFORMER POWER AND ENERGY LOSSES (For varying Load Factors) 50 KVA Low Loss Transformer Load Factor = 0.60 0.50 0.30 0.20 Loss Factor = 0.41 0.30 0.13 0.07 Load in Power Losses Energy Losses in percent % rating in W in % 10 105 2.29 3.70 4.42 7.30 10.91 20 122 1.32 1.97 2.31 3.73 5.52 30 149 1.08 1.45 1.66 2.57 3.75 40 186 1.01 1.23 1.37 2.02 2.89 50 235 1.02 1.12 1.22 1.71 2.39 60 294 1.07 1.08 1.15 1.52 2.07 70 365 1.13 1.08 1.11 1.40 1.85 80 446 1.21 1.09 1.11 1.32 1.70 90 537 1.30 1.12 1.12 1.27 1.59 100 640 1.39 1.16 1.14 1.24 1.51 Note Particulars used in the computation: 100 = No load loss in Watts 540 = Full load loss in Watts 0.92 = power factor of load Formula used for loss load factor: LLF = 0.2*LF + 0.8*LF^2 - 134 - Table A4.2.3A TRANSFORMER POWER AND ENERGY LOSSES (For varying Load Factors) 100 KVA KPLC Transformer Load Factor = 0.60 0.50 0.30 0.20 Loss Factor = 0.41 0.30 0.13 0.07 Load in Power Losses Energy Losses in percent % rating in W in % 10 270 2.93 4.67 5.56 9.15 13.66 20 328 1.78 2.55 2.97 4.72 6.95 30 426 1.54 1.94 2.19 3.30 4.76 40 562 1.53 1.71 1.87 2.64 3.70 50 738 1.60 1.63 1.72 2.28 3.10 60 952 1.72 1.62 1.67 2.07 2.72 70 1206 1.87 1.66 1.67 1.95 2.48 80 1498 2.04 1.72 1.70 1.88 2.31 90 1830 2.21 1.80 1.75 1.85 2.20 100 2200 2.39 1.89 1.82 1.84 2.12 Particulars used in the computation: 250 = No load loss in Watts 1950 = Full load loss in Watts 0.92 = power factor of load Formula used for loss load factor: LLF = 0.2*LF + 0.8*LF^2 Table A4.2.3B TRANSFORMER POWER AND ENERGY LOSSES (For varying Load Factors) 100 KVA Low Loss Transformer Load Factor = 0.60 0.50 0.30 0.20 Loss Factor = 0.41 0.30 0.13 0.07 Load in Power Losses Energy Losses in percent % rating in W in % 10 179 1.94 3.14 3.75 6.20 9.27 20 205 1.11 1.67 1.96 3.16 4.69 30 249 0.90 1.22 1.40 2.18 3.18 40 310 0.84 1.03 1.15 1.71 2.45 50 389 0.85 0.94 1.02 1.44 2.02 60 485 0.88 0.90 0.96 1.28 1.75 70 599 0.93 0.89 0.93 1.17 1.56 80 730 0.99 0.90 0.92 1.10 1.43 90 879 1.06 0.92 0.92 1.06 1.33 100 1045 1.14 0.95 0.94 1.03 1.27 Not Particulars used in the computation: 170 = No load loss in Watts 875 = Full load loss in Watts 0.92 = power factor of load Formula used for loss load factor: LLF = 0.2*LF + 0.8*LF^2 BENEFITS OF A TRANSFORMER REPLACEMENT PROGRAM Table A4.2.4 EXISTING TRANSFORMER PROPOSED NEW TRANSFORMER Rated loss Peak Losses per annum Rated loss Peak Losses per annum Transf. Max Energy Transf. in Watts loss in KWh New transf. in Watts loss in KWh Computation of savings energy loss % Location kVA kWh/yr. kVA Ir Cu kW Ir Cu Total kVA Type Ir Cu kW Ir Cu Total kW kWh/yr. $/yr. Old TF New TF 7013 22.9 100,127 100 320 2000 0.42 2803 275 3078 30 3S 30 270 0.19 263 412 675 0.24 2403 215 3.07 0.67 7014 47.9 209,627 200 500 3000 0.67 4380 451 4831 50 3Ph 50 350 0.37 438 843 1281 0.30 3551 307 2.30 0.61 7016 22.1 96,973 50 190 1150 0.42 1664 593 2257 30 3-S 30 270 0.18 263 386 649 0.24 1608 161 2.33 0.67 7006 47.0 205,860 100 320 2000 0.76 2803 1161 3964 100 3Ph 75 600 0.21 657 348 1005 0.55 2959 321 1.93 0.49 6833 24.3 106,390 100 320 2000 0.44 2803 310 3113 30 3^S 30 270 0.21 263 465 728 0.23 23B5 212 2.93 0.68 6756 30.0 131,400 100 320 2000 0.50 2803 473 3276 45 3-S 39 300 0.17 342 350 692 0.33 2584 247 2.49 0.53 6834 34.3 150,190 50 190 1150 0.73 1664 1421 3086 50 3Ph 50 350 0.21 438 433 871 0.52 2215 263 2.05 0.58 6867 25.0 109,500 50 190 1150 0.48 1664 756 2420 30 31S 30 270 0.22 263 493 756 0.26 1664 170 2.21 0.69 6752 2.1 9,373 50 190 1150 0.19 1664 6 1670 30 3*S 30 270 0.03 263 4 266 0.16 1404 130 17.82 2.84 6832 30.0 131,400 100 320 2000 0.50 2803 473 3276 45 31S 39 300 0.17 342 350 692 0.33 2584 247 2.49 0.53 6761 30.0 131,400 50 190 1150 0.60 1664 1088 2752 50 3Ph 50 350 0.18 438 331 769 0.43 1983 228 2.09 0.59 6764 12.9 56,327 50 190 1150 0.27 1664 200 1864 30 3*S 30 270 0.08 263 130 393 0.19 1471 140 3.31 0.70 6795 76.4 334,763 200 500 3000 0.94 4380 1151 5531 100 3Ph 75 600 0.43 657 921 1578 0.51 3953 380 1.65 0.47 6763 4.3 18,790 50 190 1150 0.20 1664 22 1687 30 3'S 30 270 0.04 263 15 277 0.16 1409 131 8.98 1.48 7700 34.3 150,190 200 500 3000 0.59 4380 232 4612 50 3Ph 50 350 0.21 438 433 871 0.37 3741 335 3.07 0.58 6774 22.9 100,127 50 190 1150 0.43 1664 632 2296 30 3*S 30 270 0.19 263 412 675 0.24 1621 163 2.29 0.67 6863 3.1 13,666 50 190 1150 0.19 1664 12 1676 10 SPh 10 90 0.02 88 23 111 0.18 1566 145 12.27 0.81 6836 2.4 10,512 25 130 650 0.14 1139 16 1155 10 SPh 10 90 0.02 88 14 101 0.12 1053 98 10.98 0.96 ' 6835 11.4 50,063 50 190 1150 0.25 1664 158 1822 30 3'S 30 270 0.07 263 103 366 0.18 1457 138 3.64 0.73 un 6841 3.8 16,819 25 130 650 0.15 1139 40 1179 10 SPh 10 90 0.02 88 35 122 0.12 1057 98 7.01 0.73 1 Totals 487.1 2,133,498 1650 8.86 46078 9469 55547 790 3.20 6377 6501 12878 5.7 42669 4130 2.60 0.60 Power loss = 1,82% Energy loss = 2.60% Power loss =066% Energy loss = 0.6Q% Notes: The area studied, Kwale, is a rural district in the southern Coastal Area Poorly utilized transformers are replaced with low loss transformers of appropriate rating Evaluation factors used: Notations: 217 = Peak power cost $/kW 3S denotes three single phase transformers 0.068 = Energy cost $/ kWh 3Ph -- denotes a three phase unit 0.5 = Load factor Ir --iron losses 0.3 = Loss factor Cu --copper losses - 136 - TRL-100 Chart 6 Figure A4.2,3A KPLC 100 kVA Transformer Energy Losses 14 -- 12 --------- -4-- LF-0.6 at 8 -- - - - - - - - -- - - - - - - - - -- - - - - - - - - - -- LF -O .5 -i-LF-0.3 U) N X LF _ _0_ ____ _ _2 0 6 . y -- ---------- ------------------------------ - - 4 --- 0 I I 10 20 30 40 50 60 70 80 90 100 Load in % of Transformer rating TRL-100 Chart 5 Figure A4.2.3B KPLC 100 kVA Transformer Power Losses 2. 5 - - - - - - - - -- --- - -- - - - - - - - - - - - - - - - - - -- -- - - - - 2 - - - - - -- - - - - - - - ------ -- - - - - - - - - - 1 .5 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3 - o 1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - U,, 0. --- - - -- - -- -- - -- -- - -- -- - -- -- - --- ---!- -- -- -- -- 1 0 20 30 40 50 60 70 80 90 100 0.5 1- Load in % of Transformer rating - 137 - Table A4.3A COMPUTATION OF TRANSFORMER LOSS EVALUATION FORMULA Parameters involved in the computation:- System characteristics: peak loading level = Ppk in pu. (see note 1) Load factor = LF in pu. Loss factor = LLF in pu. (see note 2) Present worth factor = D (see note 3) Cost of losses: LRMC peak = Cp per kW per annum LRMC energy = Ce per kWh Transforner loss data: iron losses in kW = L(i) provided by supplier copper losses full load in kW = L(cu) provided by supplier COMPUTATION Power Loss computation: Iron loss = L(i) Copper loss = L(cu)*(Ppk)A2 Total power loss = Sum of above (say, Lp) Energv Losses computation Iron losses per annum = L(i)*8760 Copper losses per annum = L(cu)*(Ppk)A2*LLF*8760 Total energy losses per annum = Sum of above (say, Le) Present worth of losses = Lp*Cp*D + Le*Ce*D = L(i) * D*(Cp+8760*Ce) + L(cu) * D*(Ppk)A2*(Cp+LLF*8760*Ce) In order to account for transformer losses that occur over its life time it is necessary to add the above computed present worth of losses to the transformer price. Thus, transformer iron loss value will be multiplied by: D*(Cp+8760*Ce) transformer copper loss value will be multiplied by: D*(Ppk)A2*(Cp+LLF*8760*Ce) It is very important that bidders are provided with these figures so that they may optimize the design based on the particular loading characteristics. 1. Peak loading level (Ppk) is usually computed by the product of the maximum load expected (Pm), and the peak contribution 2. Empirical formulae can be used to compute the Loss Load Factor from the Load Factor factor. An often used formula is: LLF= 0.8 *LF + 0.2 *LFA2 3. Present worth formula: D = (I-(1/1+i)An) / (I-l/(l4i)) where n= no. of years and i= interest rate in pu. Table A4.3B COMPUTATION OF TRANSFORMER LOSS EVALUATION FORMULAE Combined Res/com. loads Industrial loads Combined Res/com. loads Industrial loads Parameters involved (in pu): Transforner utilization factor 0.95 0.75 0.50 0.95 0.75 0.50 0.95 0.75 0.50 0.95 0.75 0.50 Peak contribution factor 0.95 0.85 0.80 0.50 0.40 0.25 0.95 0.85 0.80 0.50 0.40 0.25 Load factor 0.60 0.50 0.40 0.60 0.50 0.35 0.60 0.50 0.40 0.60 0.50 0.35 Loss load factor 0.41 0.30 0.21 0.41 0.30 0.17 0.41 0.30 0.21 0.41 0.30 0.17 Loss factor formula used:- a *LF + b *LFA2 where: a = 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 b= 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 Life span used 25 25 25 25 25 25 10 10 10 10 10 10 interest rate in pu 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Present worth factor 9.98 9.98 9.98 9.98 9.98 9.98 6.76 6.76 6.76 6.76 6.76 6.76 Cost of losses: LRMC peak ($/kW/yr.) 217 217 217 217 217 217 217 217 217 217 217 217 LRMC energy ($/kWh) 0.068 0.068 0.068 0.068 0.068 0.068 0.068 0.068 0.068 0.068 0.068 0.068 Evaluation factors ($/kW): for iron losses 8114 8114 8114 8114 8114 8114 5493 5493 5493 5493 5493 5493 for copper losses 3741 1606 545 4146 2222 49 2806 1087 369 702 241 33 Nots 1. The declared iron loss and copper loss (in kW) of the transformer is to be multiplied by the factor provided above and added together to obtain the present worth of losses. 2. The copper loss evaluation factor depends on the usage pattern. Hence a typical transformer usage profile for the system should be determined. 3. Each vertical column of the table provides the values of the parameters involved in the computation and the resulting multiplication factor to be used for evaluating transformer losses. 4. The loss load factor has been computed using the empirical formula indicated above (note: other versions of this formula are also available). Alternatively actual loss load factors determnined can be used. 5. Variation of transformer loading is not considered in the analysis (an efficient transformer management program should ensure fairly levelized loading). Table A 4.4 SUMMARY OF RESULTS - LV SYSTEM DEVELOPMENT STUDIES Investment Selected Cost of Losses ___________ ________________ _________ ________ _______ (Present W orthed) Residual Net Area Period New New Recon. Total Cost Value Investment Original New Loss B/C T.F. Sections (meters) ($) ($) ($) System System Reduct.. Ratio (no.xkVA) (meters) Present Present Value Benefit Value TR0066 1 (1994-1998) I x 167 271 8907A 3687 5220 62686 13150 49536 9.5 11 (1999-2003) 1 x 50 247 5887 A - 111 (2004-2008) 115 794 A - - - - - - I&I1 - 12557 P 2658 9905 114621 22506 92115 9.3 1,11 & III - - 12865 P 598 12270 156042 30425 125617 10.24 I x 200 TR 0587 1 (1994-1998) 1 x315 680 11058 A 4577 6481 169738 16788 152960 23.6 I x 50 11 (1999-2003) 130 13733 A - - - - - - 111 (2004-2008) 38 313 A - - - - - - I&I1 - 19583 P 4951 14634 341789 28510 313279 21.4 _________ 1,1I & 1- 19710 P 1150 18559 513939 38682 475257 25.0 TR2723 T (1994-1998) 2 x 167 70 2321 22315 A 9237 13078 195569 28534 167035 12.77 11 (1999-2003) 1 x 250 - 438 7109 A - - - 47944 - - III (2004-2008) 1 x 315 573 8767 A - - - 59000 - - 1&1 - 26729 P 4695 22034 341030 58303 282727 12.83 1,11 & III1- 30109 P 1971 28138 489947 81051 411898 14.64 TR 2768 I (1994-1998) I x 100 130 53 5844 A 2419 3425 15854 8112 7742 2.26 11 (1999-2003) I x25 - 66 111 (2004-2008) 1 x 75 206 4184 A - - 1&1 - 8288 P 1763 6525 24148 14735 9413 1.44 t1,1 & III 9901 P 984 8916 33525 19761 13754 1.54 ft. Table A 4.4 (cont.) SUMMARY OF RESULTS - LV SYSTEM DEVELOPMENT STUDIES (Cont.) Investment Selected Cost of Losses ($1 (Present Worthed) _Residual Net Area Period New New Record Total Cost Value Investment Original New Loss B/C T.F. Sections (meters) ($) ($) ($) System System Reduct.. Ratio (no.xkVA) (meters) Present Present Value Benefit I ___________ .__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ V alue .__ _ _ _ _ _ __V l TR 4080 1 (1994-1998) I x 167 606 402 12963 A 5366 7597 75765 21976 53789 7.08 and TR 12759 11 (1999-2003) 2 x 75 - 124 12395A - - - - - 50 111 (2004-2008) 196 1275 A - - - - - - I&Il 20659 P 4852 15808 87355 36517 50828 3.22 I, ifll & II21151 P 1196 19955 113182 47438 65744 3.29 TR0711, 1 (1994-1998) 2x75 5 456 11741 A 4860 6881 47872 29103 18769 2.73 TR 3414 and 11 (1999-2003) - - - - - - - - TR 1741 111 (2004-2008) 1 x 100 114 4235 A - - - - - I&ll . - - 11741 P 1509 10238 67822 47171 20651 2.02 I,&11 & - 13374 P 678 12696 79559 63276 16283 1.28 TR 0754 I (1994-1998) I x 167 99 720 12052 A 4989 7063 58746 28130 30616 34.33 and TR 0762 11 (1999-2003) 1 x 50 95 334 - - - - 111 (2004-2008) 1 x 75 36 121 7423 A - i&I1 - - - 18040 P 4028 14013 91980 52555 39425 2.81 1,111 & III - 20902 P 1959 18943 127526 65538 61988 3.27 Total for period 1 49743 480447 9.66 Total for period I & If 93157 808438 8.68 Total for period 1, 11 & III 119477 1120541 9.80 Note: A - denotes investtnent at current cost I -denotes periond from 1994 to 1998 P - denotes present value 11 -denotes periond from 1999 to 2003 III -denotes periond from 2004 to 2008 LV SYSTEM OPTIMIZATION -PROPOSALS IN PERIOD I Proposed LV Network Development Network ID. 0066 - Period I < 913t sJz I to ot sit Addition of Transformer 4 |01w ftrI for Period I e 4~~~~~~~~~~~ s4 $1 4. l Original Transformer 1 for Network L.V. S/STN 0066 PERIODt- 1994-199L - 1:25 0 0 I LV SYSTEM OPTIMIZATION -PROPOSALS IN PERXOD II Proposed LV Network Development lNetwork ID. 0066 - Period 11 14 3~~~~~~~~~~~~~~~~~~~3 I-Transformer Selected '* in Period It Transformer Selected > 341~~~~~~~~~~~~~~~ t4 4 \tl4 1lls~~ ~ ~ ~~~~~~~~~~~~~~~~~~~~~~~~~ I! s4 Original Transfortiter L .. .SISTN 13065 PERIOD:- 1999-2003 e 1 2500 .. LV SYSTEM OPTIMIZATION -PROPOSALS IN PERIOD III Proposed LV Network Development Network ID. 0066 - Period III 2)1 1 52 34 l 17 3 . /sx2 "' /ss l 11 .ATransformer Selected to in Period II 4 Transformer Selected 4 3 S I in Period I L , d , l \ 11 z a s 4 \ \ fo 1 |; ~ ~<~as 1~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ 1.4 14 S4S~~~~~~~~~I Original Transformer/s Transformer/ Note: No Tranaformer added but network L SJ STN 006 rearranged in Period III. L..S/T 0- PERIOD:- 2004-2008 1: 2500 JOINT UNDP/WORLD BANK ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) PURPOSE The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) is a special global technical assistance program run by the World Bank's Industry and Energy Department. ESMAP provides advice to governments on sustainable energy development. Established with the support of UNDP and 15 bilateral official donors in 1983, it focuses on policy and institutional reforms designed to promote increased private investment in energy and supply and end-use energy efficiency; natural gas development; and renewable, rural, and household energy. GOVERNANCE AND OPERATIONS ESMAP is governed by a Consultative Group (ESMAP CG), composed of representatives of the UNDP and World Bank, the governments and other institutions providing financial support, and the recipients of ESMAPs assistance. The ESMAP CG is chaired by the World Bank's Vice President, Finance and Private Sector Development, and advised by a Technical Advisory Group (TAG) of independent energy experts that reviews the Programme's strategic agenda, its work program, and other issues. ESMAP is staffed by a cadre of engineers, energy planners, and economists from the Industry and Energy Department of the World Bank. The Director of this Department is also the Manager of ESMAP, responsible for administering the Programme. FUNDING ESMAP is a cooperative effort supported by the World Bank, UNDP and other United Nations agencies, the European Community, Organization of American States (OAS), Latin American Energy Organization (OLADE), and public and private donors from countries including Australia, Belgium, Canada, Demnark, Germany, Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal, Sweden, Switzerland, the United Kingdom, and the United States. FURTHER INFORMATION An up-to-date listing of completed ESMAP projects is appended to this report. For further information or copies of completed ESMAP reports, contact: ESMAP c/o Industry and Energy Department The World Bank 1818 H Street, N.W. Washington, D.C. 20433 U.S.A. Joint UNDP/World Bank ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) LIST OF REPORTS ON COMPLETED ACTIVITIES Region/Country ActiviyReport Title Date Number SUB-SAHARAN AFRICA (AFR) Africa Regional Anglophone Africa Household Energy Workshop (English) 07/88 085/88 Regional Power Seminar on Reducing Electric Power System Losses in Africa (English) 08/88 087/88 Institutional Evaluation of EGL (English) 02/89 098/89 Biomass Mapping Regional Workshops (English) 05/89-- Francophone Household Energy Workshop (French) 08/89 103/89 Interafrican Electrical Engineering College: Proposals for Short- and Long-Term Development (English) 03/90 112/90 Biomass Assessment and Mapping (English) 03/90 -- Symposium on Power Sector Reform and Efficiency Improvement in Sub-Saharan Africa 06/96 182/96 Angola Energy Assessment (English and Portuguese) 05/89 4708-ANG Power Rehabilitation and Technical Assistance (English) 10/91 142/91 Benin Energy Assessment (English and French) 06/85 5222-BEN Botswana Energy Assessment (English) 09/84 4998-BT Pump Electrification Prefeasibility Study (English) 01/86 047/86 Review of Electricity Service Connection Policy (English) 07/87 071/87 Tuli Block Farms Electrification Study (English) 07/87 072/87 Household Energy Issues Study (English) 02/88 -- Urban Household Energy Strategy Study (English) 05/91 132/91 Burkina Faso Energy Assessment (English and French) 01/86 5730-BUR Technical Assistance Program (English) 03/86 052/86 Urban Household Energy Strategy Study (English and French) 06/91 134/91 Burundi Energy Assessment (English) 06/82 3778-BU Petroleum Supply Management (English) 01/84 012/84 Status Report (English and French) 02/84 011/84 Presentation of Energy Projects for the Fourth Five-Year Plan (1983-1987) (English and French) 05/85 036/85 Improved Charcoal Cookstove Strategy (English and French) 09/85 042/85 Peat Utilization Project (English) 11/85 046/85 Energy Assessment (English and French) 01/92 9215-BU Cape Verde Energy Assessment (English and Portuguese) 08/84 5073-CV Household Energy Strategy Study (English) 02/90 110/90 Central African Republic Energy Assessement (French) 08/92 9898-CAR Chad Elements of Strategy for Urban Household Energy The Case of Ndjamena (French) 12/93 160/94 Comoros Energy Assessment (English and French) 01/88 7104-COM Congo Energy Assessment (English) 01/88 6420-COB Power Development Plan (English and French) 03/90 106/90 C6te dIvoire Energy Assessment (English and French) 04/85 5250-IVC Improved Biomass Utilization (English and French) 04/87 069/87 Power System Efficiency Study (English) 12/87 -- Power Sector Efficiency Study (French) 02/92 140/91 Project of Energy Efficiency in Buildings 09/95 175/95 Ethiopia Energy Assessment (English) 07/84 4741-ET -2 - Region/Country Activity/Report Tite Date Number Ethiopia Power System Efficiency Study (English) 10/85 045/85 Agricultural Residue Briquetting Pilot Project (English) 12/86 062/86 Bagasse Study (English) 12/86 063/86 Cooking Efficiency Project (English) 12/87 -- Energy Assessment 02/96 179/96 Gabon Energy Assessment (English) 07/88 6915-GA The Gambia Energy Assessment (English) 11/83 4743-GM Solar Water Heating Retrofit Project (English) 02/85 030/85 Solar Photovoltaic Applications (English) 03/85 032/85 Petroleum Supply Management Assistance (English) 04/85 035/85 Ghana Energy Assessment (English) 11/86 6234-GH Energy Rationalization in the Industrial Sector (English) 06/88 084/88 Sawmill Residues Utilization Study (English) 11/88 074/87 Industrial Energy Efficiency (English) 11/92 148/92 Industrial Energy Efficiency Technical Assistance Phase II 08/96 185/96 Guinea Energy Assessment (English) 11/86 6137-GUI Household Energy Strategy (English and French) 01/94 163/94 Guinea-Bissau Energy Assessment (English and Portuguese) 08/84 5083-GUB Recommended Technical Assistance Projects (English & Portuguese) 04/85 033/85 Management Options for the Electric Power and Water Supply Subsectors (English) 02/90 100/90 Power and Water Institutional Restructuring (French) 04/91 118/91 Kenya Energy Assessment (English) 05/82 3800-KE Power System Efficiency Study (English) 03/84 014/84 Status Report (English) 05/84 016/84 Coal Conversion Action Plan (English) 02/87 -- Solar Water Heating Study (English) 02/87 066/87 Peri-Urban Woodfuel Development (English) 10/87 076/87 Power Master Plan (English) 11/87 -- Power Loss Reduction Study 09/96 186/96 Lesotho Energy Assessment (English) 01/84 4676-LSO Liberia Energy Assessment (English) 12/84 5279-LBR Recommended Technical Assistance Projects (English) 06/85 038/85 Power System Efficiency Study (English) 12/87 081/87 Madagascar Energy Assessment (English) 01/87 5700-MAG Power System Efficiency Study (English and French) 12/87 075/87 Envirownental Impact of Woodfuels (French) 10/95 176/95 Malawi Energy Assessment (English) 08/82 3903-MAL Technical Assistance to Improve the Efficiency of Fuelwood Use in the Tobacco Industry (English) 11/83 009/83 Status Report (English) 01/84 013/84 Mali Energy Assessment (English and French) 11/91 8423-MLI Household Energy Strategy (English and French) 03/92 147/92 Islamic Republic of Mauritania Energy Assessment (English and French) 04/85 5224-MAU Household Energy Strategy Study (English and French) 07/90 123/90 Mauritius Energy Assessment (English) 12/81 3510-MAS Status Report (English) 10/83 008/83 Power System Efficiency Audit (English) 05/87 070/87 Bagasse Power Potential (English) 10/87 077/87 Energy Sector Review (English) 12/94 3643-MAS - 3 - Region/Country Activity/Report Title Date Number Morocco Energy Sector Institutional Development Study (English and French) 07/95 173/95 Mozambique Energy Assessment (English) 01/87 6128-MOZ Household Electricity Utilization Study (English) 03/90 113/90 Electricity Tariffs Study 06/96 181/96 Namibia Energy Assessment (English) 03/93 11320-NAM Niger Energy Assessment (French) 05/84 4642-NIR Status Report (English and French) 02/86 051/86 Improved Stoves Project (English and French) 12/87 080/87 Household Energy Conservation and Substitution (English and French) 01/88 082/88 Nigeria Energy Assessment (English) 08/83 4440-LUNI Energy Assessment (English) 07/93 11672-UNI Republic of South Africa Options for the Structure and Regulation of Natural Gas Industry (English) 05/95 172/95 Rwanda Energy Assessment (English) 06/82 3779-RW Energy Assessment (English and French) 07/91 8017-RW Status Report (English and French) 05/84 017/84 Improved Charcoal Cookstove Strategy (English and French) 08/86 059/86 Improved Charcoal Production Techniques (English and French) 02/87 065/87 Commercialization of Improved Charcoal Stoves and Carbonization Techniques Mid-Term Progress Report (English and French) 12/91 141/91 SADC SADC Regional Power Interconnection Study, Vol. I-IV (English) 12/93 -- SADCC SADCC Regional Sector: Regional Capacity-Building Programn for Energy Surveys and Policy Analysis (English) 11/91 Sao Tome and Principe Energy Assessment (English) 10/85 5803-STP Senegal Energy Assessment (English) 07/83 4182-SE Status Report (English and French) 10/84 025/84 Industrial Energy Conservation Study (English) 05/85 037/85 Preparatory Assistance for Donor Meeting (English and French) 04/86 056/86 Urban Household Energy Strategy (English) 02/89 096/89 Industrial Energy Conservation Program 05/94 165/94 Seychelles Energy Assessment (English) 01/84 4693-SEY Electric Power System Efficiency Study (English) 08/84 021/84 Sierra Leone Energy Assessment (English) 10/87 6597-SL Somalia Energy Assessment (English) 12/85 5796-SO Republic of Options for the Structure and Regulation of Natural South Africa Gas Industry (English) 05/95 172/95 Sudan Management Assistance to the Ministry of Energy and Mining 05/83 003/83 Energy Assessment (English) 07/83 4511-SU Power System Efficiency Study (English) 06/84 018/84 Status Report (English) 11/84 026/84 Wood Energy/Forestry Feasibility (English) 07/87 073/87 Swaziland Energy Assessment (English) 02/87 6262-SW Tanzania Energy Assessment (English) 11/84 4969-TA Peri-Urban Woodfuels Feasibility Study (English) 08/88 086/88 Tobacco Curing Efficiency Study (English) 05/89 102/89 Remote Sensing and Mapping of Woodlands (English) 06/90 -- Industrial Energy Efficiency Technical Assistance (English) 08/90 122/90 -4- Region/Country Activit/Report Title Date Number Togo Energy Assessment (English) 06/85 5221-TO Wood Recovery in the Nangbeto Lake (English and French) 04/86 055/86 Togo Power Efficiency Improvement (English and French) 12/87 078/87 Uganda Energy Assessment (English) 07/83 4453-UG Status Report (English) 08/84 020/84 Institutional Review of the Energy Sector (English) 01/85 029/85 * Energy Efficiency in Tobacco Curing Industry (English) 02/86 049/86 Fuelwood/Forestry Feasibility Study (English) 03/86 053/86 Power System Efficiency Study (English) 12/88 092/88 Energy Efficiency Improvement in the Brick and Tile Industry (English) 02/89 097/89 Tobacco Curing Pilot Project (English) 03/89 UNDP Terminal Report Zaire Energy Assessment (English) 05/86 5837-ZR Zambia Energy Assessment (English) 01/83 4110-ZA Status Report (English) 08/85 039/85 Energy Sector Institutional Review (English) 11/86 060/86 Zambia Power Subsector Efficiency Study (English) 02/89 093/88 Energy Strategy Study (English) 02/89 094/88 Urban Household Energy Strategy Study (English) 08/90 121/90 Zimbabwe Energy Assessment (English) 06/82 3765-ZIM Power System Efficiency Study (English) 06/83 005/83 Status Report (English) 08/84 019/84 Power Sector Management Assistance Project (English) 04/85 034/85 Petroleum Management Assistance (English) 12/89 109/89 Power Sector Management Institution Building (English) 09/89 Charcoal Utilization Prefeasibility Study (English) 06/90 119/90 Integrated Energy Strategy Evaluation (English) - 01/92 8768-ZIM Energy Efficiency Technical Assistance Project: Strategic Framework for a National Energy Efficiency Improvement Program (English) 04/94 -- Capacity Building for the National Energy Efficiency lmprovement Programme (NEEIP) 12/94 -- EAST ASIA AND PACIFIC (EAP) Asia Regional Pacific Household and Rural Energy Seminar (English) 11/90 China County-Level Rural Energy Assessments (English) 05/89 101/89 Fuelwood Forestry Preinvestment Study (English) 12/89 105/89 Strategic Options for Power Sector Reform in China (English) 07/93 156/93 Energy Efficiency and Pollution Control in Township and Village Enterprises (TVE) Industry (English) 11/94 168/94 Energy for Rural Development in China: An Assessment Based on a Joint Chinese/ESMAP Study in Six Counties 06/96 183/96 Fiji Energy Assessment (English) 06/83 4462-FIJ Indonesia Energy Assessment (English) 11/81 3543-IND Status Report (English) 09/84 022/84 Power Generation Efficiency Study (English) 02/86 050/86 Energy Efficiency in the Brick, Tile and Lime Industries (English) 04/87 067/87 - 5 - Region/Country Activit/Report Title Date Number Indonesia Diesel Generating Plant Efficiency Study (English) 12/88 095/88 Urban Household Energy Strategy Study (English) 02/90 107/90 Biomass Gasifier Preinvestment Study Vols. I & II (English) 12/90 124/90 Prospects for Biomass Power Generation with Emphasis on Palm Oil, Sugar, Rubberwood and Plywood Residues (English) 11/94 167/94 Lao PDR Urban Electricity Demand Assessment Study (English) 03/93 154/93 Malaysia Sabah Power System Efficiency Study (English) 03/87 068/87 Gas Utilization Study (English) 09/91 9645-MA Myannar Energy Assessment (English) 06/85 5416-BA Papua New Guinea Energy Assessment (English) 06/82 3882-PNG Status Report (English) 07/83 006/83 Energy Strategy Paper (English) -- -- Institutional Review in the Energy Sector (English) 10/84 023/84 Power Tariff Study (English) 10/84 024/84 Philippines Commercial Potential for Power Production from Agricultural Residues (English) 12/93 157/93 Energy Conservation Study (English) 08/94 -- Solomon Islands Energy Assessment (English) 06/83 4404-SOL Energy Assessment (English) 01/92 979/SOL South Pacific Petroleum Transport in the South Pacific (English) 05/86 -- Thailand Energy Assessment (English) 09/85 5793-TH Rural Energy Issues and Options (English) 09/85 044/85 Accelerated Dissemination of Improved Stoves and Charcoal Kilns (English) 09/87 079/87 Northeast Region Village Forestry and Woodfuels Preinvestment Study (English) 02/88 083/88 Impact of Lower Oil Prices (English) 08/88 -- Coal Development and Utilization Study (English) 10/89 -- Tonga Energy Assessment (English) 06/85 5498-TON Vanuatu Energy Assessment (English) 06/85 5577-VA Vietnam Rural and Household Energy-Issues and Options (English) 01/94 161/94 Power Sector Reform and Restructuring in Vietnam: Final Report to the Steering Committee (English and Vietnamese) 09/95 174/95 Household Energy Technical Assistance: Improved Coal Briquetting and Commercialized Dissemination of Higher Efficiency Biomass and Coal Stoves (English) 01/96 178/96 Westem Samoa Energy Assessment (English) 06/85 5497-WSO SOUTH ASIA (SAS) Bangladesh Energy Assessment (English) 10/82 3873-BD Priority Investment Program (English) 05/83 002/83 Status Report (English) 04/84 015/84 Power System Efficiency Study (English) 02/85 031/85 Small Scale Uses of Gas Prefeasibility Study (English) 12/88 India Opportunities for Commercialization of Nonconventional Energy Systems (English) 11/88 091/88 Maharashtra Bagasse Energy Efficiency Project (English) 07/90 120/90 Region/Country Activity/Report Title Date Number India Mini-Hydro Development on Irrigation Dams and Canal Drops Vols. I, 11 and III (English) 07/91 139/91 WindFarm Pre-Investment Study (English) 12/92 150/92 Power Sector Reform Seminar (English) 04/94 166/94 Nepal Energy Assessment (English) 08/83 4474-NEP Status Report (English) 01/85 028/84Nepal Energy Efficiency & Fuel Substitution in Industries (English) 06/93 158/93 Pakistan Household Energy Assessment (English) 05/88 -- Assessment of Photovoltaic Programs, Applications, and Markets (English) 10/89 103/89 National Household Energy Survey and Strategy Fomulation Study: Project Terminal Report (English) 03/94 -- Managing the Energy Transition (English) 10/94 Lighting Efficiency Improvement Program Phase 1: Commercial Buildings Five Year Plan (English) 10/94 -- Sri Lanka Energy Assessment (English) 05/82 3792-CE Power System Loss Reduction Study (English) 07/83 007/83 Status Report (English) 01/84 010/84 Industrial Energy Conservation Study (English) 03/86 054/86 EUROPE AND CENTRAL ASIA (ECA) Eastern Europe The Future of Natural Gas in Eastern Europe (English) 08/92 149/92 Poland Energy Sector Restructuring Program Vols. I-V (English) 01/93 153/93 Portugal Energy Assessment (English) 04/84 4824-PO Turkey Energy Assessment (English) 03/83 3877-TU MEIDDLE EAST AND NORTH AFRICA (MNA) Morocco Energy Assessment (English and French) 03/84 4157-MOR Status Report (English and French) 01/86 048/86 Energy Sector Institutional Development Study (English and French) 05/95 173/95 Syria Energy Assessment (English) 05/86 5822-SYR Electric Power Efficiency Study (English) 09/88 089/88 Energy Efficiency Improvement in the Cement Sector (English) 04/89 099/89 Energy Efficiency Improvement in the Fertilizer Sector(English) 06/90 115/90 Tunisia Fuel Substitution (English and French) 03/90 -- Power Efficiency Study (English and French) 02/92 136/91 Energy Management Strategy in the Residential and Tertiary Sectors (English) 04/92 146/92 Yemen Energy Assessment (English) 12/84 4892-YAR Energy Investment Priorities (English) 02/87 6376-YAR Household Energy Strategy Study Phase I (English) 03/91 126/91 -7 - Region/Country Activity/Report Title Date Number LATIN AMERICA AND THE CARIBBEAN (LAC) LAC Regional Regional Seminar on Electric Power System Loss Reduction in the Caribbean (English) 07/89 - Bolivia Energy Assessment (English) 04/83 4213-BO National Energy Plan (English) 12/87 -- National Energy Plan (Spanish) 08/91 131/91 La Paz Private Power Technical Assistance (English) 11/90 111/90 Natural Gas Distribution: Economics and Regulation (English) 03/92 125/92 Prefeasibility Evaluation Rural Electrification and Demand Assessment (English and Spanish) 04/91 129/91 Private Power Generation and Transmission (English) 01/92 137/91 Household Rural Energy Strategy (English and Spanish) 01/94 162/94 Natural Gas Sector Policies and Issues (English and Spanish) 12/93 164/93 Brazil Energy Efficiency & Conservation: Strategic Partnership for Energy Efficiency in Brazil (English) 01/95 170/95 Chile Energy Sector Review (English) 08/88 7129-CH Colombia Energy Strategy Paper (English) 12/86 -- Power Sector Restructuring (English) 11/94 169/94 Energy Efficiency Report for the Commercial and Public Sector 06/96 184/96 Costa Rica Energy Assessment (English and Spanish) 01/84 4655-CR Recommended Technical Assistance Projects (English) 11/84 027/84 Forest Residues Utilization Study (English and Spanish) 02/90 108/90 Dominican Republic Energy Assessment (English) 05/91 8234-DO Ecuador Energy Assessment (Spanish) 12/85 5865-EC Energy Strategy Phase I (Spanish) 07/88 -- Energy Strategy (English) 04/91 -- Private Minihydropower Development Study (English) 11/92 -- Energy Pricing Subsidies and Interfuel Substitution (English) 08/94 11798-EC Energy Pricing, Poverty and Social Mitigation (English) 08/94 1283 1-EC Guatemala Issues and Options in the Energy Sector (English) 09/93 12160-GU Haiti Energy Assessment (English and French) 06/82 3672-HA Status Report (English and French) 08/85 041/85 Household Energy Strategy (English and French) 12/91 143/91 Honduras Energy Assessment (English) 08/87 6476-HO Petroleum Supply Management (English) 03/91 128/91 Jamaica Energy Assessment (English) 04/85 5466-JM Petroleum Procurement, Refining, and Distribution Study (English) 11/86 061/86 Energy Efficiency Building Code Phase I (English) 03188 -- Energy Efficiency Standards and Labels Phase I (English ) 03/88 -- Management Information System Phase I (English) 03/88 -- Charcoal Production Project (English) 09/88 090/88 FIDCO Sawmill Residues Utilization Study (English) 09/88 088/88 Energy Sector Strategy and Investment Planning Study (English) 07/92 135/92 Mexico Improved Charcoal Production Within Forest Management for 08/91 138/91 the State of Veracruz (English and Spanish) Energy Efficiency Management Technical Assistance to the Comision Nacional para el Ahorro de Energia (CONAE) (English) 04/96 180/96 Region/Country Activity/lReport Title Date Number Panama Power System Efficiency Study (English) 06/83 004/83 Paraguay Energy Assessment (English) 10/84 5145-PA Recommended Technical Assistance Projects (English) 09/85 -- Status Report (English and Spanish) 09/85 043/85 Peru Energy Assessment (English) 01/84 4677-PE Status Report (English) 08/85 040/85 Proposal for a Stove Dissemination Program in the Sierra (English and Spanish) 02/87 064/87 Energy Strategy (English and Spanish) 12/90 -- Study of Energy Taxation and Liberalization of the Hydrocarbons Sector (English and Spanish) 120/93 159/93 Saint Lucia Energy Assessment (English) 09/84 5111-SLU St. Vincent and the Grenadines Energy Assessment (English) 09/84 5103-STV Trinidad and Tobago Energy Assessment (English) 12/85 5930-TR GLOBAL Energy End Use Efficiency: Research and Strategy (English) 11/89 -- Guidelines for Utility Customer Management and Metering (English and Spanish) 07/91 -- Women and Energy--A Resource Guide The International Network: Policies and Experience (English) 04/90 -- Assessment of Personal Computer Models for Energy Planning in Developing Countries (English) 10/91 Long-Term Gas Contracts Principles and Applications (Englishj 02/93 152/93 Comparative Behavior of Firms Under Public and Private Ownership (English) 05/93 155/93 Development of Regional Electric Power Networks (English) 10/94 -- Roundtable on Energy Efficiency (English) 02/95 171/95 Assessing Pollution Abatement Policies with a Case Study of Ankara 11/95 177/95 10/03/96 Il IBRD 26458 360 K E N Y A 400 POWER LOSS REDUCTION STUDY s U D A N TRANSMISSION SYSTEM AND DISTRIBUTION AREA COVERAGE ' DENSELY POPULATED AREAS - KPLC DISTRIBUTION AREAS 1 } # OLKARIA GEOTHERMAL FIELD 220 kV TRANSMISSION LINES A DIESEL POWER STATIONS 132 kV TRANSMISSION LINES * STEAM POWER STATION 66 kV TRANSMISSION LINES * HYDRO POWER STATIONS --------- 33 kV TRANSMISSION LINES /7 ...-.. * POSSIBLE SITES OF HYDRO --- INTERNATIONAL BOUNDARIES // ,, ~~~~~~~~~~~~~POWER STATIONS ; -4 t , E T H I O P I A A' - L:;-A ake .j **._-*-%.< *1* Turkano , N R T H \ AS El Molo Camp | M rabi ?VA LLEY OM e it08 UGANDA Turkwel 0 6 2 | ~~~~~CENTRAL|\ < > Toro~ RIF Haas '.. KENYA ~ ~ ~ ~ ~ ~ ~ Y TANZANLA OCEAN Mamlsczsa Mop Design LInIp of The Wd ann N R . G h oudrrsissosdnacnoin s 8 ETHIOPIA >0- 9 oXT \ C OA S T OLKAR A40 , A in 6ur , \f . < *: SS *. ;;:: e X . :. t ... > h ) \, X _ X 0 ;: S : fendanyofindrininonof inforation shwnnon thi n itsiio do no impl on th pac of e t e .,rw4 .> ; t f ' ~~~0 25 50 7.5 't00 fooleau of any Mrr7 a uz an SUDAN A TO 3' ILS 0 EMI~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~~~~~~~~~~UY19 ISRD 26459 K EN Y A IAASS/E POWER LOSS REDUCTION STUDY * SUBSTATIONS INNER NAIROBI 11 kV DISTRIBUTION SYSTEM IIkVTRANSMISSIONLINES 1 I v UNDERGROUJND CABLES DISTRIBUTION TRANSFORMER STATIONS CIRCUIT BREAKERS FOR SWITCHING OR MV CONSUMER * ISOLATOR s | . / > 0 F O R E S T t _ 4 y N OlN O \ M AIN ROADS .- I N0 RNP . - - -'- INTERNATIONAL BOUNDARIES I ICK 0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~FO 2TL IlT /I. ,,i . ,,' " K ' 1 ^ ' . t I ) .F Io IS 13~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1 ~- H~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~II 1990E AI0 R RBASEIII FOR INSUSTEAL AREA IN~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~W .RI1 7 FJA AD 140 AD~~~-AR 1 N 1-,' F-EII -E~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~JL'19 N,~~~~~~~~~~~~~~~~IIII IBRD 26460 h limv; u J < ' 0 wLi2°3 ' '\ << s f R,l;srd 4 i e > _ ; = 2 h ThiL: K E N Y A IbRD 26Y A POWER LOSS REDUCTION STUDY NAIROBI CITY 11 kV DISTRIBUTION SYSTEM UGUGA.,,.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ SUBSTATIONS fO Limuru \4UGUGA q + T ' ov .7, , 0,, x ' l, i [COFFEt) ~~ / - 1 / D TRANSMISSION LINESR k, ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~11 kV 33 kV O-PEO PEN SPAC Y0 V FOR 44i~~~~~~~~~~~~~~~~~~ SPACE ~ ~~ ~~ ~--- 4k KIKUYUI A S 66kV 0100 ( ~~~~~~~SE W26459 -225 kv -1 IkV UNDERGROUND CABLES DISTRIBUTION TRANSFORMER STATIONS / SITES to oooootoo, O~~~~~~~~~~~CRCUIT BREAK~ERS FOR SWITCH-ING OR Ikl ~~~~~~~~~~~~~~~~~MV CONSUMER -I-ISOLATORS MAIN ROADS STUDY AREA j- ;'! (GCENG * z 1N.CN 10HSl INATIONALTIONRE BOUNDARIES 5 , ooAtoOFotn .ot onoow 0,0.A 1 )~~~~~~~~~~~~~~~~~~~~~~~~~~AI 66! E_YS S /\Ti" \2 , / V 5 MARIMFET0 ,30 Em + Ct , > jjb ii- , , 5 10 KOLOMETERS S BEttRS K0N Ohi, -op po.d ...d oed by th.e Mop D.siBo ,nit oR tOt.dWotM -otk. 1990 Pt o,oht.,o-ltd.,,thti-t wnonottmono,otICoo] JULY 0996 RIBE FDR ir 6 kVA -, .. RIBE _4 3 3/II kV N KIKOAMBAA 33/I1IEV~- S '' ___,,',. .-IMOLAEWA '\> / MAZERAS FDR >g , i,,~~~~~~~~~~~~~~~~~~~~~~~~DR. r X ~~~~~~~~~~~~~~~~~O. - HAZ '5-"' B~~~~ABAI B. "fl''"' 2~~~~~~~20/1 32/33EkV -SHANZU 33/1 I v *'K* .\ y!OCEANIC FDR. 0116 kVA BAMBURI 5" ENDI E0XTkILVFA34No y58 kV5 A AI 3/R POO. .EIIB7D'6., -N 1338~~~~~~~5 kVA ."'V%J.S00 33 """ BORBR FOR. LOA FDR0 - ~ ~ ~~."":~ 0 266EV .V r MIRITINI K O oo' ~30* 33/11 kV N , KIAN F .V IL~~~~~~~~~~~~~~~~~~~~'A CHANGA.WE FOR KIEV NYAI LOCAL FOR. 252 EVA 132EVO33/1) I V872 EVA 33/11 EV MRTONGW O 266 EVA U00 KONI NO 33/11EkV SHELLY BEACH FOB. 32 kVA K EN Y A POWER LOSS REDUCTION STUDY CENTRAL AND SOUTH COASTAL AREA MEDIUM VOLTAGE DISTRIBUTION NETWORK * SUBSTATIONS TRANSMISSION LINES. 11 kV t 27 EVA . 33 kV 132 kV - / - = 220t.V c .\. TIWI FDR, DISTRIBUTION TRANSFORMER STATIONS 6R kVA CIRCUIT BREAKERS FOR SVITCHING OR MV CONSUMER it \I/-I1 ISOLATORS (NORMALLY OPEN POSITIONS) \ ES DIANI 4 --- INTERNATIONAL BOUNDARIES 32\3/11EkV OIDIANI NO.2 FDR. AB kVA CONNECrED TiANSFORMER CAACITIES AE INDICATED IN BVA FOR EACH FEEDER DIN NOR OIC EARN ' C E, / '' o ~~~~~~~~~~~~~~~~~~~~~~~~~~~, , , . ; . 3°5R 3L'AMB 5. W pADI by . Mp . , _ .... w / / ' -w-' =-~~~~~~~~~~~~~~~' te_Gr'7 _ t w~~~~~~~~~~0 ( b-, _. wm A.A c____________0 39w40' t0 00'O 40.l0 MARERENI K E N YA POWER LOSS REDUCTION STUDY NORTHERN COASTAL AREA FUNDISAKIBAoNI MEDIUM VOLTAGE DISTRIBUTION NETWORK 0 2 4 4 K 10h4 R 3I.,ko.wj 310 l * * fll~~~~~~~~~AUNDI f o.A MAIJNDI 33/I1 kV .M-f.~~~~~~1 * - D GEDE 33/ II LV 4-bh. -3-30'"""" 532 P-d. K.6o R.,k ~ L-oe S,o.6 upp. s kk ; SUBSTATIONS tK,bS,0 TRANSMISSION UNES: . KIULF t 11kV 132/ 31kV1 k JARIBUN|I , KILIFI --------- 33 kv I * / ' - KIUFI PLANTATION 132 V 3 33/I1 LV DISTRIDUlTON TRANSFORMER STATIONS 3'- / ik Tk..., -. CIRCUIT BREAKERS FOR SWITCHING OR MV CONSUMER ------ tKibc AIRFIELDS 0 SELECTED CITIES AND TOWNS /' 8 NATIONAL CAPITAL (INSET) ff 'A/lO uri Moyo _ _ INTERNATIONAL BOUNDARIES (INSET) ,/ .' ,-. -3-sW/ 3-sg / KURUWITU 33/11 LV, 315 LVA RIBE 33/11 kV 7 KKDDL 40'10' '7 / ~ * *' -KIKAMBALA 33/11 kV 2.5 MVA 30 zJ 4 or RABAI 220/132 LV 0 * *r0000. , , 7,. ,>_nt, 7, ' RAMBURI 33/11 kV 40' OZM2A KISAUNI . Omo wod Ar A. 4 p .Dorism U., .1 of Ihu 0..4 Dn . -. TA~~~~~~~~~~F. d-.d.. . ~2.p2 ...,0..., RIPEV1IU , .( ."..ob"d.e2,. 8p.,,,lrUW'44&,,AG. .nr /; 4 3 0 . UN-MOM'ASAi 3N 52 eod'6 sf v.nmn k 3 00-c 00-50 .0-d- 0 I 4 ESMAP c/o Industry and Energy Department The World Bank 1818 H Street, N. W. Washington, D. C. 20433 U. S. A.