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*KenyaPower Loss Reduction Study

Report No. 186/96

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JOINT UNDP/ WORLD BANKENERGY 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'sIndustry and Energy Department. ESMAP provides advice to governments onsustainable energy development. Established with the support of UNDP and 15 bilateralofficial donors in 1983, it focuses on policy and institutional reforms designed to promoteincreased private investment in energy and supply and end-use energy efficiency; naturalgas development; and renewable, rural, and household energy.

GOVERNANCE AND OPERATIONS

ESMAP is governed by a Consultative Group (ESMAP CG), composed of representativesof the UNDP and World Bank, the governments and other institutions providingfinancial support, and the recipients of ESMAPs assistance. The ESMAP CG is chairedby the World Bank's Vice President, Finance and Private Sector Development, andadvised by a Technical Advisory Group (TAG) of independent energy experts thatreviews the Programme's strategic agenda, its work program, and other issues. ESMAPis staffed by a cadre of engineers, energy planners, and economists from the Industry andEnergy Department of the World Bank. The Director of this Department is also theManager of ESMAP, responsible for administering the Programme.

FUNDING

ESMAP is a cooperative effort supported by the World Bank, UNDP and other UnitedNations agencies, the European Community, Organization of American States (OAS),Latin American Energy Organization (OLADE), and public and private donors fromcountries 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. Forfurther information or copies of completed ESMAP reports, contact:

ESMAPc/o Industry and Energy Department

The World Bank1818 H Street, N.W.

Washington, D.C. 20433U.S.A.

KENYA

POWER LOSS REDUCTION STUDY

September 1996

Power Development, Efficiency &Household Fuels DivisionIndustry and Energy DepartmentThe World Bank1818 H Street, N.W.Washington, D.C. 20433

This document has restricted distribution and may be used by recipients only in the performanceof their official duties. Its contents may not otherwise be disclosed without UNDP or WorldBank authorization.

Table of Contents

FOREWORD .............................................................. i

EXECUTIVE SUMMARY ..............................................................1I

I. INTRODUCTION .............................................................. 12Background .............................................................. 12

Power Sector Organization .............................................................. 12Consumption Characteristics and Future Projections ..................................................... 2.........., 12The Study .13

Study Objectives .14

II. ANALYSIS OF SYSTEM LOSSES .16Transmission System Losses .17Overall Distribution System Losses .18Analysis of Losses by Voltage Level .20

III. STUDY METHODOLOGY AND SYSTEM CHARACTERISTICS .22Background .22Establishing a Computerized Distribution Planning Unit .23

Load Measurements .24Distribution Planning Software .24

Economic Analysis .26System Characteristics .............................................................. 29

IV. MEDIUM VOLTAGE SYSTEM IMPROVEMENT FOR NAIROBI CITY .30Overall supply arrangements .30Present System Operation .30Development Proposals .31

New Substation at Kiambu .31New Substation at Kileleshwa .32Feeder Reconductoring and Introduction of New Feeders .32Reactive Compensation .33Summary of Network Improvements Proposed .34

V. COASTAL AREA MV SYSTEM DEVELOPMENT .35Overall Supply Arrangements .35Present System Operation .36Development Proposals .37

Proposed 132 kV line Rabai to Diani and 132/33 kV Substation at Diani .37Improvements to 11 kV Tiwi Feeder from Diani Substation .38Proposed New Substation at Galu .39Proposed 132 kV Line to Bamburi .................................. 40Proposed 132 kV Supply to Malindi .................................. 41Proposed Developments at Mazeras and Rabai .................................. 4211 kV Feeder Tom Mboya From Makande .................................. 4311 kV Feeder Bamburi No.1 From Nyali ................................... ,,.. 44Application of Capacitors for Reactive Compensation .................................. 44

Summary of MV Development Proposals for the Coastal Area .................................. 44

VI. L.V. NETWORK STUDY ................................................... 46Existing System Characteristics .................................................... ,. 46

Network Losses ....................................................... 46Transformer Losses ................................................... 47

LV System Optimization ................................................... 48Study Results ................................................... 49Estimated Investment Requirements ................................................... 51

VII. NON-TECHNICAL LOSSES ................................................... 53Meter Testing Methodology ................................................... 54

MV Bulk Power Consumers ................................................... 55LV Bulk Supply Consumers ................................................... 56Retail Consumers .................................................... 59'Dead' Accounts ................................................... 60Consumer Billing System ................................................... 62Conclusion and Recommendations ................................................... 63

Recommendations ................................................... 64Special Task forces ................................................... 64Billing System Changes ................................................... 67

Improvements Under Implementation ................................................... 68

ViII. GENERAL CONSIDERATIONS ................................................... 71Lessons Leamed ................................................... 71

Particular Characteristics Of Distribution Systems ................................................... 71Organizational Issues ................................................... 71Planning Studies and Development Proposals ................................................... 73Non-Technical Loss Reduction ................................................... 74

Economic Parameters ................................................... 75Complementary Issues ................................................... 75

Impact of Improved Tariff Setting and Load Management ................................................... 75Impact on Sector Reform ................................................... 77

ANNEXES ................................................... 78

MAPS

IBRD 26458 Transmission System and Distribution Area CoverageIBRD 26459 Inner Nairobi 11 kV Distribution SystemIBRD 26460 Nairobi City 11 kV Distribution SystemIBRD 26461 Single Line Diagram of KPLC Transmission SystemIBRD 26526 Central and South Coastal Area Medium Voltage Distribution NetworkIBRD 27805 Northern Coastal Area Medium Voltage Distribution Network

ABBREVIATIONS AND ACRONYMS

km - KilometerkV - KilovoltkVA - Kilovolt amperekVAr - Kilovolt ampere, reactivekW - KilowattkWh - Kilowatt hourMVA - Megavolt amphereMVAr - Megavolt amphere reactiveMW - Megawattin.sq. - Inch Square (Used for conductor cross section)LF - Load Factor, a ratio expressing the average to peak power suppliedLLF - 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 CostESMAP - Energy Sector Management Assistance Programme organized jointly by the

UNDP and the World BankKPLC - Kenya Power and Lighting Company Ltd.SIDA - Swedish International Development AgencySCA - 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 personnelfrom September 1991 to mid 1993. The ESMAP team comprised of Messrs. Winston Hay,Principal Power Engineer and Chrisantha Ratnayake, Senior Power Engineer. Messrs. Jon-EricJohnson and Bergsvein Wang, Consultants from IVO International assisted in training KPLCcounterpart staff during field assignmnents over a period of six months and one monthrespectively. The extensive contributions made by KPLC counterpart staff in carTying out thefield 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 andLighting 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 plantsowned by a number of other companies. Although about 40% of KPLC's shares are privatelyowned it is closely controlled by government. After recording high growth rates for aconsiderable 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 systemlosses, which have remained at around 15% of net generation over the last five years, are notexcessive by standards in most other developing country utilities. However, in the context ofcapacity shortages and the resulting load shedding, reductions that can be achieved in both peakpower and energy losses are of considerable value. A number of economic improvements aredeemed feasible in both the transmission and distribution systems. Requirements for thetransmission system have been identified recently by KPLC's consultants. These measuresinclude introduction of reactive compensation in the short term and the construction of a numberof new lines, particularly Kiarnbere-Nairobi, Nairobi-Mombassa and Lessos-Olkaria-Nairobi allat 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 distributionsystem, KPLC decided to undertake a study which would both identify needed economicinvestments and develop its own competence in continuing such activities in the future. Inaddition 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 werefinalized with the World Bank-UNDP sponsored Energy Sector Management AssistanceProgram (ESMAP) and financial support was obtained from the Swedish IntemationalDevelopment Agency (SIDA). The ESMAP study commenced in October, 1991 with theestablishment of a special unit within KPLC's Corporate Planning Division. The studies wererestricted 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 counterpartstaff in the skills of computerized distribution system planning so that loss monitoring andnetwork development planning activities would be carried out on a continuing basis. ESMAPstaff organized and supervised the study and provided the necessary technical guidance. Shortterm consultancy support to train KPLC personnel was arranged by engaging IVO Intemationalof Finland (one distribution consultant for 6 months and one commercial consultant for 3 weeks).

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Objectives and Overall Achievements

3. The principal objectives of the project were to:

* identify the main sources of technical and non-technical losses and developestimates of the contribution of each of these to overall losses;

* introduce state-of-the-art techniques of data collection and distribution systemplanning and train KPLC staff in such applications;

* develop specific proposals for Nairobi city and the Coastal Area to reducetechnical 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 capabledistribution planning unit within KPLC. The counterpart unit in KPLC which commenced as atemporary cell with staff released from a number of different branches, was subsequentlyestablished as a permanent unit within the Corporate Planing Division. The staff of the newlyestablished unit made commendable progress in acquiring the skills necessary to undertakecomputerized analysis of distribution systems. Microprocessor based measuring instrumentswere used in obtaining network loads at important locations and key distribution systemcharacteristics such as loading densities, load and loss factors, power factor, etc., weredetermined. A computerized mapping data base has been fully developed for the mediumvoltage' (MV) networks which were studied in Nairobi City and the Coastal Area. Two softwarepackages --LOWO purchased from IVO International of Finland for low voltage (LV) systemstudies, and DPA/G supplied by Scott & Scott of USA (for both MV and LV systems)-- are fullyfunctional in KPLC's distribution planning unit and were extensively used in the networkanalyses 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 extensivelywith the counterpart staff of KPLC in establishing data collection methodologies and in carryingout the planning studies. Such close interaction and training was seen to be a vital part of thetechnology 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 wereuseful in training personnel from other power utilities. In early 1993 members of the KPLC teamparticipated in two assignments to train staff from the People's Republic of China on similarprojects being undertaken with ESMAP assistance. In mid 1994 a KPLC representative visitedBangladesh to train and work with counterpart staff from the Rural Electrification Board ofBangladesh 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.

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month long training exercise. The knowledge and experience gained by the counterpart staff andthe institutionalization of the unit augurs well for the continued development of KPLC'sdistribution planning function.

5. Distribution network studies carried out were based on the application of themeasuring instruments and software described above. In order to obtain an analysis of estimatedoverall system losses, data from the distribution systems studied were combined withinfornation from KPLC's records on consumer sales and transmission flows. In general the datapertains to that of FY91-92 (July 1991 to June 1992). Two geographic areas (representingtogether almost half the total load of the country) were selected for the distribution study. Thefirst consisted of a section of the Nairobi city and the second included all major networks in theCoastal Area.

6. The analysis and conclusions of the study indicate that loss reduction should beseen as one of a multiple set of network development objectives, which should include reliabilityimprovement and increasing network capacity to meet future load growth. It was also observedthat the omission of one or another of these benefits precludes the selection of the optimumalternative. The planning concept should thus be a systemic approach to the overallimprovement of network performance. Accordingly, proposals contained in the report are basedon the evaluation of all three of the major benefits: loss reduction, reliability improvement andthe ability to meet future network load growth. A general observation from the results is that it isoften economic to advance investments which are necessary to meet technical considerations at afuture 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 toeconomically acceptable performance levels. These investments would provide substantialeconomic benefits with an overall benefit to cost ratio of approximately 25:1. Many of theproposals identified need to be implemented without delay in view of the critical networkconditions presently being experienced. Major developments identified consist of 5 gridsubstations (66/11 kV and 132/33 kV) and 2 primary substations (33/11 kV). The proposals alsoinclude reconductoring of certain line sections as well as the addition of some new sections andfeeders. Capacitors aggregating 9.1 MVAr are also included for power factor correction, eachcapacitor addition selected providing a pay back period of less than 18 months.

8. With respect to low voltage (LV) systems, the operational performance can beoptimized by substantial decentralization of the existing networks (by adding new transformersto reduce the area covered by each unit). Investment requirements for LV system improvementover the next five years is estimated at US$8.5 million for the study area yielding a benefit tocost ratio of approximately 10:1. Unlike MV investments which can usually be planned a fewyears in advance, LV improvements should be based on the system configuration and expectednew loads at the time of the investment in view of the rapidly changing circumstances.

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9. Loss reduction and system development proposals identified in the report yieldhigh benefit to cost ratios and are substantially robust in relation to variations in the relevantparameters (growth rate, cost of power, interest rate etc.). They are also particularly important inthe context of the present load shedding and power shortages experienced in Kenya and shouldtherefore be implemented as soon as possible. In addition they will improve KPLC's operationalefficiency and fmancial performance, thus complementing current efforts at sector reform --private sector power generation being sustainable only in the context of the fmancial viability ofthe operating utility.

10. Section 1 of this report provides a general background of the power sector andexplains the initiation of the present study. Section 2 provides an overall analysis of systemlosses and their breakdown in relation to various network components. The methodologyfollowed in carrying out the technical and economic analysis is explained in Section 3. Sections4 and 5 describe the studies carried out for medium voltage (MV) systems in Nairobi city and theCoastal 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 andproposals presented for remedial action. Section 8 addresses some general considerations on thelessons learned from the study and other complementary matters. The main conclusions of thestudy are reviewed in the following paragraphs.

Overall System Loss Analysis

11. An analysis of KPLC's power system losses is presented in Section 2. Energyconsumption in generation stations and losses in the transmission system were obtained fromKPLC system control records based on metered data at power plants and substations. MV andLV studies carried out provided the basis for estimates of technical losses in these networks. Thedifference between overall energy losses and technical losses provided an approximate estimateof the non-technical energy losses. In addition, investigations of non-technical losses were alsocarried out during the study and although only relatively few samples were checked in relation tothe overall system, it is noteworthy that the results of the two methods employed were in closeagreement. Unlike energy losses, power losses2 cannot be measured as there is no convenientmethod of measuring the coincident demand of all consumers (either for the total system or for agiven 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, powerlosses are extremely important as it is the peak load that determines the capacity requirements ofthe system (and therefore the extent of load shedding necessary when shortfalls exist). Hence anestimate of the possible range of both non-technical and overall power losses are provided (onthe basis of computed technical losses and an estimated conversion of the non-technical energylosses to power losses). Accordingly, the power and energy losses of the networks (based on netgeneration) are estimated as follows:

2 Power losses are usually computed at system peak.

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Overall System Losses

Power (%) Energy (%)Transmission system loss 5.5 4.5Distribution (technical) loss 11.3 6.3Non-technical loss 7.9 (6 to 10%) 4.4Total 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). KPLCshould continue to expand its loss monitoring activities and refine these estimates on a periodicbasis. Although the losses in the Kenyan power system are not high in comparison to those ofmany 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 withminimum capital investment. The overall power loss at system peak is estimated to be in theregion of 23% to 27% and represents a sizable erosion of valuable power supply capability in thecontext of the present capacity shortages. Reduction of technical losses in the distributionsystem to about half the present amount can be carried out economically. Improvements are alsopossible in transmission system losses, particularly by reactive compensation in the near ternand 220 kV system improvements in the longer term (as demonstrated in separate studies carriedout by KPLC and its consultants). Thus, with well planned investment and good operationalpractice 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 ofthis study.

13. The technical losses in the distribution system may be further disaggregated onthe basis of (a) input to the distribution network (at grid substations), as well as (b) input toindividual network components. A summary of the results obtained is presented below:

Distribution System Losses by System Components

As % of input to As % of input toeach component Distribution SystemPower Energy Power Energy

Grid SS Transformers 1.0 0.8 1.0 0.8MV Lines 5.1 3.5 4.9 3.2LVTransformers 1.1 0.7 0.9 0.5LV Direct Lines 1.0 0.5 0.9 0.3LV Retail Lines 5.4 3.6 4.2 1.7

Total technical loss 12.0 6.6Non-technical loss 8.2 4.5Total distribution system loss 20.1 11.1

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Development Proposals for Nairobi City

14. The 11 KV networks covering an area of around 500 sq. km. and containing thehighest load concentration in the Nairobi city were subjected to a detailed technical analysisusing the specialized distribution planning software supplied. The overall loss level was found tobe reasonable --2.6% for power and 1.8% for energy at present loading levels. This is mainlydue to a well configured 11 kV system (with the average feeder distances of 2.5 km for thehighly loaded areas) supplied by seven 66/11 kV substations. However, in the absence of systemimprovements, these losses are expected to increase to about 6.4% and 4.6% in 10 years fromnow for power and energy losses respectively. Again, if no improvements are carried out therespective losses would rise to 9.6% and 6.8% in 15 years. This indicates that timely actionneeds 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 higherthan the rest of the network, were identified in the western and north western sections outside thecentral city. Investigation of development proposals in this area resulted in recommendations fortwo 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 andreconductoring, amounting to $ 0.6 million at a benefit to cost ratio of 13.7:1 were alsoidentified.

16. A number of feeders with poor power factors were identified resulting in therecommendation of 6.7 MVAr of capacitors at a cost of $73,800. These investments have a payback period of only 18 months. For the longer term improvement of feeder power factors aprogram to improve consumer load power factor is recommended. Further, both the feeder losslevels 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 ofcapacitors is still recommended in view of the low pay back period and the possibility of movingthese units to other locations yielding additional benefits when the system improvements referredto are effected.

Development Proposals for the Coastal Area

17. Network load flows carried out for the Coastal Area indicates that MV line lossesare considerably higher than in Nairobi, with the overall losses being 6.4% and 4.4% for powerand energy respectively for present loading conditions. Without system improvement theselosses increase to 11.2% and 8.2% in 10 years and to 18.8% and 12.5% in 15 years for power andenergy 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 considerabledistances from the main supply substation at Kipevu.

18. Three 132/33 kV grid substations at Diani, Malindi and Bamburi and two 33/11kV primary substations at Galu and Rabai are required to improve MV system performance.

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These developments, together with the 11 kV system improvements recommended, result in lossreduction benefits of 4.2 MW and 19.3 GWh per year at present loading levels. The proposalsyield a benefit to cost ratio of approximately 28:1. Reactive compensation of 2.4 MVAr is alsorecommended for identified low power factor feeders at a cost of $31,170. This investmentwould 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 bothnetwork 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 specializedLV system software package supplied. These studies indicated an aggregate technical loss (atpresent loading levels) of 5.4% and 3.6% for power and energy respectively. However, morethan 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 determineimprovements that could be carried out to reduce losses to "optimum" levels. A major findingfrom these studies is that the supply area of existing transformers should be sub-divided to anumber of smaller areas, each supplied by a separate distribution transformer. This will entailincreasing 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 beintegrated into the planned development. Extrapolation of the results of the sample studyindicates that investment requirements to optimize system performance for the selected studyarea (in Nairobi City and the Coastal Area) over the next five years will amount to approximatelyUS$8.5 million. These investments will also cater to the general load growth of both existingand smaller retail consumers in the area (and will exclude system additions required to cater tolarger 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 ofapproximately 9.7:1.

20. The loss levels of KPLC's distribution transformers are higher than economicallyacceptable, particularly with respect to iron losses. Spreadsheet based methods were developedto compute transformer iron and copper losses at various operating characteristics and to developappropriate evaluation factors to account for the losses sustained over their operational lifetime.Since poorly utilized transformers can cause energy losses exceeding 5%, a suitable transformerload management program is recommended to be carried out to match unit ratings with the loadsupplied. Poor transformer utilization was particularly noticed in low load density areas and apilot study identified possible reduction of energy losses from 2.6% to 0.6%. In order to secureunits with better loss performance, KPLC should also include loss evaluation in transformerprocurement. Such a program may commence with evaluation factors of US$5000/kW andUS$1000/kW for iron and copper losses respectively and after periodic review and bettertransformer load management in the field, these values should be revised and increased to aboutUS$8000/kW and US$2000/kW respectively.

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Nontechnical Losses

21. Non-technical losses consist of the difference between electricity actuallysupplied and the amount billed to consumers. They are caused by direct pilferage as well as byerrors and imperfections in the metering and billing systems. During the study field tests andenergy audits were carried out to detect instances of non-technical losses. As in the otherexercises conducted under the study, particular attention was given to the training of KPLCpersonnel so that such work could be carried out regularly. The results of the sample studiesconducted are summarized in the following paragraphs3.

22. Tests carried out on large MV bulk consumer metering yielded an average losslevel of 2%. A particularly disturbing feature of the results is that a relatively high proportion ofdetections was in Mombassa (63%) resulting in a loss of 5.3%.

23. Tests carried out on meter installations at LV bulk consumers resulted in thedetection of losses amounting to 4.5%. The analysis of faults detected in this category showedthat 39% were caused by meter defects (including defects in the demand meters), 18% fromdirect tampering, 6% caused by partial metering of consumer supplies, 18% due to faulty ordamaged metering transformers (CT's and PT's) and 15% due to faulty wiring. Rectification ofthe defects detected and charging consumers for past dues are being handled by KPLC'scommercial 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 determinationgenerally agrees with the random tests carried out on a number of retail consumers whichindicated a metering loss of 8%. During the random test, a number of meters were also detectedto over read (possibly due to calibration errors) but the margin of error in such instances wassubstantively lower than that of under reading meters.

25. The investigations carried out indicated that the exception reports (which listinstances of suspect consumption) issued by the KPLC billing system are inadequate in manyrespects. The tests carried out on installations selected from the exceptions report produced lessinstances of metering errors than those selected at random. Similarly the majority of "dead"accounts (consumer installations which have been reported as disconnected from service andtherefore removed from the billing system) consisted of those which have been subsequentlyreinstated. Hence, substantial modification is required in the preparation of these reports toprovide useful assistance in the monitoring of non-technical losses.

3 Losses detected are presented as percentages of consumer billing.

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Proposals for the Reduction of Non-Technical Losses

26. Sample studies conducted for non-technical losses indicate a billing loss of around5% for both bulk and retail sales. Accordingly, measures to identify these losses and rectify thedefects by using special task forces is recommended. Two separate field teams, one attending tothe detection of metering installation defects and the other attending to consumer verificationshould carry out investigations on a systematic basis covering each area comprehensively beforemoving to the next. Personnel for this assigmnent should be hand picked and freed from allother 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 thebilling system expeditiously. Procedures for carrying out such a non-technical loss detectionprogram are provided in Section 7 (para 7.32). KPLC has already commenced a company wideprogram for the monitoring of non-technical losses and consideration may be given toincorporation of the above recommendations in this exercise.

27. KPLC's billing system (in use during the study) has outlived both its technical andeconomic life and needs to be speedily replaced by a more up to date system. At the time of thisreport (end 1995) a new billing system is being installed and on completion, would redress anumber 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 meterreading system.

Summary of Proposals

28. The system improvement proposals identified in the report are summarizedbelow:

uS$o0001. Nairobi City, MV system

1.1 New 66/11 kV Substation at Kiambu 2,2361.2 New 66/11 kV Substation at Kileleshwa 2,2671.3 Reconductoring and New Feeders 5951.4 Capacitors - (6.7 MVAr) on 11 kV Lines 74

Total for Nairobi 5.172

2. Coastal Area, MV system2.1 New 132/33 kV Substation at Diani 3,5002.2 New 132/33 kV Substation at Bamburi 7,9902.3 New 132/33 kV Substation at Malindi 3,3372.4 New 33/11 kV Substation at Galu 3662.5 New 33/11 kV Substation at Rabai 4002.6 11 kV feeder improvements 2242.7 Capacitors - (2.4 MVAr) on 11 kV Lines 31

Total for Coastal Area 15

3. LV system improvements 8,500Total Cost of Proposals, Nairobi

and Coastal Areas 29_520

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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 meterinspections, consumer verification and rectification of billing anomalies. A new billing andconsumer database system in keeping with current developments in this field is alsorecommended4.

Lessons Learned

30. A number of important lessons may be gained from the experiences of the presentstudy. 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 importantinformation for improving operational efficiencies and yield investments/improvementswith high economic and financial returns;

2. These investigations (and related planning tasks) are best coordinated by a separate unitwith 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 inisolation. However, in order to avoid sub-optimal solutions a systemic concept should beadopted, accounting also for benefits of improving network reliability and ability tosatisfy future load growth. The analysis and ranking of a number of alternativedevelopment proposals on the basis of all such benefits form the best method ofdetermining optimum investment;

4. The sequence of network developments to be considered in a planning exercise varies forlong term and short ternm options. A convenient sequence of examining long termdevelopments is to follow the hierarchy of the power flow, investigating suitableinvestments required at each stage. Accordingly, the following sequence of networkimprovements 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).

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LV systems - (a) decentralization of networks by installing larger numbers of transformersand 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 sequencein reverse. Phase balancing (in LV networks) and reactive compensation followed bynetwork rationalization are likely to provide the fastest returns. Short term improvementsshould also be suitably coordinated with long term system development plans. In manydeveloping countries the short term options are particularly important in view of the longlead time required for financing large investments. Furthermore, short term solutionssuch as phase balancing and network rationalization are fully complementary with thelong term solutions. Benefits of other short term investments such as reactivecompensation, can also be extended by shifting the equipment to other locations.

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1. INTRODUCTION

Background

1.1 The Republic of Kenya is situated on the east coast of Africa bordered on thenorth by Ethiopia and Sudan, on the west by Uganda, on the south by Tanzania and on the eastby Somalia and the Indian Ocean. The country covers 582,646 sq. km. but about two thirds ofthis area especially towards the north is arid. The bulk of the population is thereforeconcentrated in and around Nairobi and the adjacent highlands, and in the east coast close toMombasa.

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, theindustrial sector is heavily dominated by agricultural product processing. The gross per capitanational product was approximately US$260 in 1994 and the per capita electricity consumptionstood at 110 kWh.

Power Sector Organization

1.3 The installed generating capacity in 1992 amounted to 788 MW composed of 598MW of hydro power, 145 MW thermal and gas turbine (GT) and 45 MW geothermal. Although30 MW of imports are possible from the Ugandan Electricity Board (UEB) this supply is notnormally 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: KenyaPower Company (KPC), Tana River Development Company (TRDC), Tana and Athi RiverDevelopment Authority (TARDA) and Kerio Valley Development Authority (KVDA). Ageographical representation of the Kenyan power system is shown in Map IBRD 26458 and asingle line diagram of the transmission network shown in IBRD Map 26461.

1.4 The Kenya Power and Lighting Company (KPLC) operates and maintains allpower plants of the generating companies (through management agreements) and also possessessome generating plant of their own. In addition, KPLC owns and operates most of thetransmission and distribution networks. KPLC has been established under the CompaniesOrdinance (with private shares of approximately 40%) but is in effect substantially controlled bythe 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

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electrified. Total sales for the year 1991/92 (during which the study was made) were 2,846GWh, of which 52% was consumed in the Nairobi Area and 23% in the Coastal Area (aroundMombasa). 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 lastfew years partly due to power rationing necessitated by shortage of generation capacity.Exceptionally low rainfall also contributed substantially to the reduction of available capacity. Inthe four years up to 1990/91 the annual energy demand grew at an average rate of 6.9% while theincrease recorded from 1990/91 to 1992/93 averaged to 4.3%. Thereafter the growth reducedfurther to around 3%. Apart from the loss of sales due to load shedding the reduction in growthrate 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 yearsapproximates to 5.6% p.a. and the generation developments envisaged by KPLC up to 2010comprise 370 MW of geothermal, 250 MW of conventional thermal, 240 MW of hydro and 150MW of medium speed diesel plant.

1.7 The expected new geothermal plant will be located close to the existing fields inOlkaria (near Naivasha) and the majority of the remaining thermal additions at Mombasa. Inview 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 the220 kV system to Mombasa. The western transmission system also needs to be augmented by anextension 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 countryutilities. However, the present power shortages underscore the high economic value that needs tobe placed on power and energy losses. In the short term when capacity improvement is notpossible the economic value of denied consumption is many times the cost of production. In thelonger term too, the value attributable to power and energy losses is relatively high as gasturbines with high operating costs would carry the main burden of marginal consumption.Arrangements were therefore made with the World Bank-UTNDP sponsored Energy SectorManagement Assistance Program (ESMAP) to provide assistance in developing a power systemloss reduction program in KPLC. In view of the studies already conducted on the transmissionsystem by KPLC's consultants, only improvements to the distribution system were addressed inthe present study. The study was also restricted to certain networks in Nairobi City and theCoastal Area. KPLC is expected to continue the activities commenced, complete studies for eachof the remaining distribution systems in the country and also arrange a program for the continuedmonitoring of distribution system performance. Financial support for the project was obtained

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from the Swedish International Development Agency (SIDA) and the study was launched inOctober, 1991. The installation of the computer systems and initial training of counterpart staffwas carried out through end 1991 and beginning of 1992 and the collection of network data andsystem analysis was mainly undertaken during 1992 and early 1993. It may be noted that due tothe continuous changes being made in distribution systems, details of individual networksstudied may not be up to date in certain respects. Since counterpart staff of KPLC has beentrained in the techniques of computerized distribution planning and the analysis software anddata base has already been established, the changes to the networks and continuation of thestudies can be carried out by KPLC staff.

Study Objectives

1.9 The study seeks to assist KPLC in developing an effective program to reducedistribution system losses. Major objectives relates to the transfer of technology currently usedby 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 developreliable estimates of the contribution of each of these to overall losses;

(b) to introduce state-of-the-art techniques of data collection and distribution systemplanning to KPLC and enable continuity of such applications;

(c) to commence the development of a reliable distribution system database to be ofcontinuing use in distribution planning and related work,

(d) development of specific proposals for Nairobi city and the Coastal Area to reducetechnical losses to economic levels; and

(e) estimation of the incidence of non-technical losses and introduction of proceduresto detect and rectify such instances.

1.10 The study, supervised by World Bank staff, was conducted through a special unitestablished in KPLC to collect and document the distribution system data and thereafterundertake the required analyses. Five engineers and two technical assistants were assigned on afuill 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 Finlandwho provided a distribution consultant for 6 months and a conmmercial consultant for a period of3 weeks. Staff of the World Bank operating under ESMAP, provided technical guidance anddirected the studies. Two software packages were employed in the technical analysis; LOWO, aprogram obtained from Messrs. IVO International and DPA(G)/DIG a package purchased fromMessrs. Scott & Scott of U.S.A. The KPLC counterpart staff assigned to the study unitperformed extremely well in mastering the new techniques and conducting the required field

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work. Much of the credit for the successful implementation of the project is therefore due to theparticipating KPLC personnel. The competence achieved by the study unit can be gauged fromthe fact that personnel from the unit were employed to train staff of other power utilities on twoseparate occasions during the study. In a similar project organized by ESMAP for the Ministryof Water Resources in the Republic of China personnel from the study unit undertook thedigitizing of distribution networks and training counterpart staff from China to carry out thiswork. In another assignment the unit provided support to the Rural Electrification Board ofBangladesh to carry out field measurements using the microprocessor based measuringinstruments obtained during the present study. Utility personnel from both Bangladesh andNepal visited the KPLC study unit for a period of one month in August 1994 and were trained inthe use of the analytical software.

1.11 The study unit which was first formed by personnel seconded from variousoperational units, was subsequently established as a regular division within the CorporatePlanning Department. Such institutionalizing of the distribution planning function is essential tobuild up the data base and establish a continuity of the loss monitoring and planning tasks. Thecompetence of the KPLC staff and the training received (including exposure to the distributionsystems of other developing countries) augurs well for KPLC's continued efforts at reducingdistribution system losses to economically acceptable levels.

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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 thedifference between units actually consumed and that billed for. Technical losses for individualpower lines and consequently for an overall network can be calculated if the relevant physicaland electrical characteristics are known. Such computations are conveniently made fortransmission systems as they have a limited number of 'buses' or nodes (connected by linesections or segments) and can therefore be represented accurately and in required detail bytheoretical models. Thus analytical software has been in use by system planners for many yearsin studying transmission systems. In distribution systems however, the networks are extensivelyspread 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 ofapproximate modeling techniques in order to facilitate the computation of power flowcharacteristics. The development of computer technology in recent years, particularly thewidespread use of personal computers, has led to the availability of a number of softwareprograms capable of analyzing distribution systems. The present study applied a number of suchtechniques, further explained in Section 3. The results of the studies carried out on mediumvoltage (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 computationsfor 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 inthe meter reading and billing process. An estimation of such losses may be made by carrying outenergy audits as well as by investigations of metering installations and billing records. Section 7describes the procedures used and the results of the non-technical loss investigations. Theselosses can also be determined by measuring the overall system losses and subtracting thetechnical losses attributable to the network considered.

2.3 Losses are also expressed in terms of both power and energy supplied. Powerlosses (expressed in kW or MW) occur at a given instant and depend on the network flow at thattime. Usually5 the maximum power loss occurs at peak demand and for this reason losses arenormally calculated for this time (a distinction being made between peak load of a feeder and thesystem peak, which may not be coincident). Energy losses (expressed in KWh or GWh) consistof the integrated power losses occurring over a given period, usually a year. The energy lossesare therefore dependent on the loss levels at different times as expressed by the loss durationcurve. Although losses are more often expressed in energy terms it is important to bear in mindthat in the context of system operations, peak power losses are important as they represent theperiod 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 increasedgeneration at load centers at this time.

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Transmission System Losses

2.4 Electric power is produced at generators located in the power stations and thensupplied via the transmission and distribution systems to the ultimate consumers. Some lossesare incurred before the generated power can be supplied to the transmission network, mainly dueto the consumption of auxiliary equipment within the power stations. Power that is ultimatelysupplied to the transmission system is termed 'net generation'. Metering instruments areprovided at each power station to record the output of each generation unit, the totals aggregatingto gross energy produced. The transmission lines carrying the generated power out of thestations are also metered. The difference between the above sets of readings will correspond toauxiliary consumption which is considered as the station loss. The overall transmission systemenergy loss can be determined by deducting the energy supplied at the grid substations (theinterface between the transmission and distribution systems) from net generation. Thecomputation 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 GWhAuxiliary consumption (station losses) = 32.7 GWh

= )0.97% gross generationNet energy generated = 3,352.6 GWhEnergy delivered at Grid substations6 = 3,201.5 GWhTransmission 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 thepower losses (expressed as a percentage) reaches a maximum at system peak. In KPLC'stransmission system, however, this need not be the case as increased thermal generation providedclose to the load centers (specially at Mombasa and Nairobi) during peak has the effect ofreducing the flow on the transmission network. Further, a substantial component of thetransmission losses occurs in the 132 kV section between Juja and Tororo and this is dependenton the generation at Turkwel as well as imports from Uganda. Thus at some times of the daytransmission system power losses could exceed those experienced at system peak. Theperformance of the transmission network has been studied by KPLC's Consultants who haveanalyzed network power flows over a number of operating conditions. It is expected that peakpower losses would vary in the region of 4% to 6% (depending on operating conditions). Thedata 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 lossesof such plant being also added to the overall auxiliary consumption. Losses in the 66 kV network feeding Nairobi Area istaken as part of the distribution system.

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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 andSections 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 energysupplied. The overall distribution system energy losses (including both technical and nontechnical losses) of each Area has been computed by comparison of the sales with the supplyreceived from grid substations (and local generation where relevant) for the year 1991/92 and ispresented in Table 2.2 below7.

Table 2.2: Summary of Distribution Losses (Energy) by Areas(199111992)

Received at Sales Losses LossesArea Grid SS (GWh) (GVVh) (GWh) %

Nairobi 1,674.0 1,486.6 187.4 11.2Coastal 723.2 619.6 103.6 14.3West Kenya 316.3 292.9 23.4 7.4Mt. Kenya 149.1 125.2 23.9 16.0Central Rift 191.4 179.0 12.4 6.5North Rift 147.5 142.8 4.8 3.2Total 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 monthlysupplies injected to the distribution network from the step down transformers (i.e. the interfacebetween the transmission and distribution systems). Since the readings of the energy meters atthe power stations and grid substations are regularly taken on the hour, a consistent set of data isexpected for transmission losses; any variation in the loss values corresponding to changes in thegeneration pattern. With respect to distribution losses however, the same consistency is notexpected as consumers' meter readings are not coincident with the system metering. A numberof validation checks were carried out to verify the related meter readings (particularly at the gridsubstations) and some of the records have been adjusted when errors were detected. It isrecommended that a monthly analysis of the system losses be carried out using the systemmetering 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 WestKenya to North Rift-a connected load of about 1.4 MVA).

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supply Areas (distribution system) and individual sections of the transmission network on thelines of exercises carried out during the study. Correction of any anomalies in the meter readingsis feasible if the exercise is carried out in a timely manner. Furtherinore, such an analysis willgreatly 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 theNairobi 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-technicallosses. Although loss values shown above are not too excessive in comparison to those in manydeveloping countries they are high compared to economically attainable levels which would beof the order of 5% (some variation is expected depending on the nature and dispersion of the loadsupplied).

2.9 Aggregate loss values provide a general guidance on the technical appropriatenessand operating efficiency of a distribution system. However, aggregate values often mask manyinstances of poor performance. If the majority of the load flows through relatively wellperforming feeders or are located very close to grid substations, the impact of a number ofuneconomically high loss feeders in the system may not be substantial. The study of the CoastalArea (Section 5) presents a particularly interesting exarnple of such a situation. The MombasaIsland load together with the direct supply to the petroleum refinery (close to the grid substationat Kipevu) accounts for 49% of the Area load. Due to the short feeders involved, technical lossesof the related medium voltage distribution system (33 and 11 kV network) is only 1.1%. The restof the system (supplying the peripheral areas --Diani, Malindi etc.) account for the remaining51% of the Coastal Area load and the combined medium voltage distribution system losses forthis 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 anenergy loss of 4.3%, masking the heavy losses occurring in the peripheral areas (which accountsfor half the overall load). The wide disparity of loss levels is even more evident if individualfeeders are examined. Thus in distribution system network analysis it is important to targetattention to feeders and sections of the network with poor performance rather than at overallaggregate loss values.

2.10 Sections 4 and 5 of the report present a detailed analysis of the MV distributionsystems of Nairobi and Coastal Areas and identify improvements required to bring the networksto acceptable economic levels. The analysis of the LV system and a recommended strategy forits improvement are dealt with in Section 6. In addition, an examination was also made of somefeeders outside the selected study area where high loss feeders could be identified. The results ofthis analysis are presented in Section A1.2 of the Annex where feeder (technical) losses as highas 15 to 30% have been calculated. KPLC should undertake detailed system studies for networksassociated with these feeders and prepare system development proposals as carried out inSections 4 and 5 (for Nairobi and Mombasa Areas).

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Analysis of Losses by Voltage Level

2.11 A power flow and network (technical) loss contribution by voltage level ispresented in Tables A1.1.1 to 1.1.3 of the Annex by using (a) percentage losses determined fornetwork components and (b) system loads at each voltage level. The sales made and lossesincurred at each voltage level are deducted from the input at each level to determine the flow tothe next level and the process continued until the remaining balance is consumed at the lowvoltage level. Network flows for both (peak) power and annual energy are presented in threetables for, Nairobi City, Coastal Area and the entire distribution system. While typical valueswere used for transformer losses, weighted average of loss rates (calculated for each voltagelevel) in the two study areas were used for the overall distribution system. Unlike the case ofenergy sales, consumer peak demands at each voltage level is not available as only few suppliesare measured for power demand and even so such measurement is not made specifically atsystem peak. Thus, estimated aggregate load factors and peak contribution factors have beenused in the tables 'to compute the power demand at each voltage level. Table A1.1.3 alsocombines the distribution system losses with those of the transmission system to complete thepicture for the whole system.

2.12 Non-technical energy losses may be determined by deducting the calculatedtechnical 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 ofrecorded consumption. Thus most non-technical losses from day time industrial consumers areexpected 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 thebasis of this estimation Tables Al.l.l to A1.1.3 also indicate estimated values for non-technicalpower losses and consequently for the total estimated power losses. In view of the level ofuncertainty regards the incidence of non-technical power losses we would expect the true valuesto 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 asoverall aggregate values) computed in Tables A1.1.1 to A1.1.3 of the Annex is presented inTable 2.3. It is found that technical energy losses account for 10.8% of net generation --4.5% inthe transmission system and 6.3% in the distribution system. The overall system energy loss for1991/92 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 theorder of 5.5% and 11.3% respectively and the non-technical loss estimated at 7.9% indicating anoverall power loss of the order of 25%. The above figures indicate that while KPLC's loss levelsdo not appear to be excessive by the standards of many developing countries there is stillconsiderable room for efficiency gains from the reduction of both technical and non-technicallosses. In the context of capacity shortages expected to continue for some time, the reduction ofpeak power losses will, in particular prove to be of considerable economic value. It should benoted that the loss figures provided in this analysis are on the basis of the limited samples studied

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and approximations deemed relevant. KPLC should continue the exercise of refining theanalysis of system losses by (i) increasing the number of networks analyzed (particularly for LVsystems), (ii) undertaking similar exercises for other Areas, (iii) validating the data recorded atgrid 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 toComponent Input Distribution SystemPower Energy Power Energy

Grid SS transformers 1.00 0.80 I 1.00 0.80MV Lines 5.06 3.45 I 4.92 3.24LV transformers 1.10 0.70 j 0.95 0.48LV direct lines 1.00 0.50 0.86 0.34LV retail lines 5.40 3.60 I 4.21 1.72Distribution system technical loss 11.95 6.59Distribution system non-technical loss 8.17 4.51Total distribution system loss 20.12 11.10

Summary of Network Losses (Based on Net Generation)

Power (%) Energy (%)

Transmission system losses 5.5 4.5Distribution system losses 11.3 6.3Non-technical losses 7.9 (6 to 10%) 4.4

Total System losses 24.7 (23 to 27%) 15.2

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III. STUDY METHODOLOGY AND SYSTEM CHARACTERISTICS

Background

3.1 Distribution systems spread out over wide geographic areas and are composed ofnumerous line segments with varying characteristics. Analyzing the power flow in a distributionsystem is therefore numerically complex and requires the collection of an extensive amount ofdata. The complexity of the data requirements is particularly significant in comparison totransmission networks which only require information of loads at a limited number of gridsubstations and the characteristics of the lines interconnecting these stations. In modelingdistribution systems however, even the network of one city will contain segments (sections offeeders 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 ofconnected equipment (transformers, switching/isolating positions) and the loads supplied atvarious points of the system. Another important characteristic of distribution systems is thefrequent changes which occur to the network data (again unlike transmission systems) with newextensions, additional consumers etc. being a regular feature. Thus the establishment andmaintenance of a data base for distribution systems is both voluminous and time consuming.

3.2 Maintaining geographic network drawings is an essential feature of distributionsystem planning. Prior to the use of computerized planning techniques utilities maintaineddrawings of line routes on area maps of suitable scale or on transparencies which can be overlaidon such maps'. There were many difficulties in maintaining such systems in an up-to-date anduseful manner. Entire maps have to be redone following a few network alterations or changes tothe base land maps --activities which are quite routine in distribution systems and urbandevelopment. To retain useful information a number of maps of varying scales are necessarycreating problems in both documentation and retrieval of information. Survey maps are usuallyprepared according to a standard geographic grid, while information required for system planningpurposes often requires a combination of many such maps, such combinations varying accordingto the system studied. In view of these difficulties, maintaining the distribution system data inhard copy geographic maps proved to be cumbersome and tedious. Accordingly, many utilitiesfailed to retain the documentation up-to-date. Even when the maps were maintained fairlyaccurately, the planning process using these maps was in itself quite tedious. For these reasonsthe design of distribution systems was usually dependent on the judgment of field personnelsubject 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 tochanging circumstances such as the increasing cost of power supply. Furthermore, alternativedevelopment 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 theransparencies.

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3.3 With recent advancements in computerized techniques, particularly the storageand retrieval of information using digital technology (e.g. by use of mapping software), manyutilities are now computerizing their distribution system data bases. Computation of power flowcharacteristics are facilitated by specialized software. The improvement of the quality of the database and analysis tools have allowed network planners to undertake more detailed technicalstudies. In particular, network performance can now be examined for alternative developmentsand future performance of planned systems can be predicted with greater accuracy. Currently anumber of vendors market software with many user friendly features to establish computerizeddata bases and undertake load flow and other related technical studies. These developments haveresulted 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 aswell as retrieval of information for planning (and operational) purposes. Thus, an importantobjective of the present study was to transfer this new technology to KPLC and upgradedistribution system studies in keeping with the current state-of-the-art. ESMAP experienceelsewhere indicates that such technological improvements in planning departments havenumerous benefits which include greater motivation and job satisfaction among parastatalemployees in developing countries. Accordingly these developments have been found to besustainable and conducive to greater ownership of system expansion/improvement plans (whichis 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 thefollowing 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) andidentification 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 availablenetwork drawings, maps and completion reports of construction activities. Thereafter anextensive survey of each area to be studied was conducted and information collected on networkparticulars such as conductor size, connected transformers as well as important consumercharacteristics. The existing network diagrams were then modified to reflect the current situationand the information compiled on geographic maps. MV network data was entered using 1:5000and where required 1:2500 scale maps. For the LV networks, maps of 1:2500 scale were found

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to be necessary to obtain an accurate representation. The external consultant from IVOInternational supervised this process and introduced systematic procedures to enable the work tobe carried out methodically.

Load Measurements

3.6 Load data of key network components are usually scarce in many developingcountry utilities. A number of recording instruments were obtained to address this deficiency.Many of these instruments were microprocessor controlled, enabling the measurement andstorage of the required parameters at preset intervals without user intervention. The stored datacould subsequently be retrieved by a computer and analyzed either using firnware supplied or byconversion to standard spreadsheet programs. To measure changed loading profile of a feeder ortransformer, two sets of instruments, the Load Logger and Load Profiler from RochesterInstruments 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 andcan be used on lines up to 600 V. Measurement intervals of 1, 15 or 30 minutes can be selectedin both instruments. The software provided can plot the load readings in graphical form orconvert this data to spreadsheet format enabling further calculations to be performed. Since thecomputations are usually repetitive in nature, a set of "macros" was designed to obtain importantsystem 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 (forboth day and night peaks)9

3.7 A couple of other instruments (also employing microprocessors and analysissoftware) were also employed to obtain an even wider range of parameters; these being, theDranetz Logger from Dranetz Technologies (USA), Rustrak Load Logger from RustrakInstruments (USA) and NEM Monitor from Electricity Data Services (UK). These instrumentsmeasure both the voltage and current characteristics and consequently provide additionalinformation on power factor, reactive and active power (and energy, over a given period). Thesoftware provided also enables the presentation of a variety of graphs on the measuredparameters. The data collected from these instruments can also be retrieved as spreadsheets tocarry 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 therequired analyses. The LV study package, LOWO was supplied by IVO International of Finlandand 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 instrumentsimplifies the otherwise tedious data entry process and enables the data base to be established in

9 See Annex A for definition of terms.

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a relatively short time. Network data is entered by tracing the power lines with an electroniclover' a geographic map placed on the digitizer board. A set of pull-down menus is used tosupply data concerning the electrical characteristics of the network sections. The data enteredconsist of conductor size, phasing arrangement, load data and information on connectedequipment such as transformers. In addition to the electrical characteristics geographicinformation such as roads, key physical features etc. are also entered in background 'layers'. Theanalysis programs are capable of extrapolating network loads over future years (given the growthrates to be used in each section) and load flow runs can be performed for any given switchingconfiguration and year of study. The load flow runs provide details of the electricalcharacteristics (such as active and reactive power carried, voltage level and losses) in allcomponent sections of the network.

3.9 The LOWO programn used for LV-studies includes a number of optimizationfacilities that enables the program to select the most economic network configuration undercertain defined conditions. Development alternatives such as new transformer locations and linesections can be identified and the program carries out a sequence of runs for all possible networkalternatives (with the existing system and identified possible new additions); checking foradherence to technical requirements specified and computing the losses and investment costs foreach alternative. The optimum system development and network configuration is then identifiedby the program. However, experience gained during the studies indicate that some limitationsneed to be imposed in applying the results of the optimization program. The main difficultyrelates to the representation of network loads over time. Section loads, particularly in LVnetworks, do not grow at a constant rate in all sections. While the growth rate applicable to agiven area or region can be forecast with a fair degree of accuracy (and may even be representedby a constant factor over many years), the incidence of such growth is not uniformly distributedover individual network sections. In fact, most load additions of future years occur in sectionswhich are initially poorly loaded. Thus when LV systems are modeled, new loads should oftenbe imposed on sections that had little or no load in previous years, usually representing vacantblocks of land. Further, each section reaches a saturation level at a rate substantially in variancewith that of the entire area or region. In view of such limitations the optimization facilities of theprogram were used only where applicable such as in determining the best possible networkswitching configuration for a fixed loading condition. This example underscores the importanceof validating the assumptions used in computerized modelling and optimization exercises andsuch considerations were given careful attention during the study as well as in the trainingprovided to KPLC counterparts.

3.10 The difficulties discussed above are particularly relevant to the study of LVsystems where presently available software does not provide adequate techniques to establishreliable load models for the individual network sections. The load data of the present system wasbased on the service connections provided to existing consumers and the apportioning of theoverall load to the individual sections presented little difficulty. In order to obtain reliable resultsfor the system expansion and optimization exercise, the loads expected in future years need to beallocated among individual network sections in a realistic manner. This was accomplished by

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site investigations to determine the possibilities for load increase in each section. Thus, sectionsrepresenting vacant blocks suitable for buildings were assigned higher load additions and thoserepresenting unusable land given no increase at all. Sections representing allotments alreadybuilt-up were given marginal increases commensurate with the growth rate expected for existingconsumers. In the LV network study such load models were built for three time periodsrepresenting 0-5 years, 5-10 years and 10-15 years. Although this method is time consuming itprovides 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 andthat different load distribution patterns yield varying development scenarios.

3.11 With respect to the MV network studies the spatial variation of load growth hasless influence on the final development proposals. However, particular attention is required insections containing certain large loads (such as major industrial consumers). This aspect wasaddressed by the ability of the program to model two types of loads in each section --spot loadsand variable loads. Suitable combinations of the two load types were used to ensure that the loadmodel reasonably represents the expected future conditions.

3.12 Once network and load models are established the operating performance isexamined by load flow studies carried out on a feeder by feeder basis. Important information tobe gained by these studies are the system losses (both for the overall feeder and for the high losssections) and the voltage drops experienced (particularly at the peripheral locations). Once theoperational performance of the networks (at present and expected future loading conditions) areknown, proposals to reduce such losses are designed and analyzed. A key feature in improvingdistribution planning techniques is the preparation of a number of alternative developmentproposals for each area needing improvement. The options available are then subjected toeconomic analyses to determine the viability of each development alternative.

Economic Analysis

3.13 Quantifiable economic benefits attributable to network development mainlyconsist 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 reducedfluctuations) are more difficult to quantify in the absence of reliable consumer surveys thatenable the determination of the willingness to pay for such qualitative improvements. Suchbenefits have therefore not been accounted for in the analysis.

3.14 The benefits of category (a), system loss reduction have been computed using thesoftware provided and is therefore reasonably accurate. Benefits of category (b), improved

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system reliability results mainly from the ability to feed a given section or area of the networkfrom more than one supply source. This flexibility allows alternative feeding arrangements to bemade in the event of the failure of a particular network component. Reducing feeder lengths alsoimproves reliability by restricting the area affected by a failure of a network component. Theestirnated reduction in outages resulting from the network improvement is valued in order toquantify the benefits of category (b) --reliability improvements. The saved outages (inkWh/annum) are usually detemlined by estimating the expected reduction of the number ofoutages per year combined with the average duration per outage. Determination of the economicvalue of losses caused by power outages was beyond the scope of the study and in the absence ofspecific 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 thedistribution network impose a restriction on new connections. The economic value of supplyingsuch additional loads vary according to the applicable time frame. In the immediate term, suchcosts could even reach the value of outages while over the medium term they would bedependent on available alternate supply sources such as captive generation. In the longer termthe costs may be considered to approximate to LRMC"'. In the present analysis, the additionalload that can be supplied (due to new capacity provided) over and above the limitations imposedby the network as presently constituted has been computed for each year of the analysis periodusing a spreadsheet (deducting the difference between the projected load demand and existingcapacity when the former exceeds the latter). The additional energy served over the entire periodby 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 isonly that of energy (the total costs of new supplies being composed of capacity and energycomponents), the technique used is considered to be conservative in spite of the fact that someoperational savings exist in not meeting the additional load.

3.15 In order to make the complex stream of benefits manageable for computation, thebenefits are first evaluated for a particular year (often the beginning of the analysis period orrelated sub-periods). Thereafter, multiplication factors have been established to convert thebenefits of the beginning year to the present worth of the overall period (or sub-period) ofanalysis. Economic benefits of network developments generally increase with time due toincrease of system load. Loss reduction benefits in particular, increase at a rate much higher thanthe load growth rate. This is due to the fact that conductor losses are proportional to the squareof the load resulting in a growth rate for loss reduction benefits equal to the square of the loadgrowth rate. For the other two categories, growth rates of benefits may usually be taken as theload growth rate, subject to the constraint that the benefits should remain applicable over theperiod 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 alsodisregarded.

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continuing increase of these benefits, and care should be exercised in limiting the extension ofbenefits over such periods). For each category of benefits, the growth rates can be adjusted bythe annual discount factor to arrive at a stream of present worth benefits. Alternatively, a singlemultiplying factor can be used to convert benefits of the current year to the present worth over aperiod of analysis (provided that the annual growth of benefits remain constant). Tables A1.6.1and A1.6.2 in the Annex provide such multiplying factors for varying load growth and discountrates.

3.16 The unit rates assigned to power and energy losses have been obtained from aLRMC study carried out by Acres International in 1991. While the ESMAP study was inprogress a new study was also carried out by London Economics which provided values close tothose determined by the earlier study. These rates together with the values used for reliabilityand additional capacity benefits are presented in Table 3.1 below. The economic analysis wascarried out over 10 and 15 year periods, residual values being assigned to account for remaininglifetime of the investments. Economic life assigned to various investments were: 30 years forgrid substations (132 kV or 66 kV), 20 years for primary substations (33/11 kV), and 15 years fornew 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 availableinformation. Only the LRMC (appropriate for loss reduction benefits) are based on recentstudies applicable for KPLC. Costs used for the other two items are considered to beconservative. In order to improve the accuracy of system development studies KPLC shouldcarry out the required consumer surveys and field studies to improve information on theseeconomic 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/kWat low voltage (LV) - $ 358/kW

(b) Energy losses:at medium voltage (MV) - $ 0.068/kWhat low voltage (LV) - $ 0.098/kWh

For reliability benefits:Estimated outage savings:at medium voltage (MV) - $ 0.34/kWhat low voltage (LV) - not evaluated

For new capacity benefits:Additional energy supplied:at medium voltage (MV) - $ 0.068/kWhat low voltage (LV) - $ 0.098/kWh

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System Characteristics

3.18 In order to obtain the system characteristics required for the study a large amountof network data has been compiled and analyzed. Such data is also valuable for numerous otherstudies. Load curves obtained provide a good indication of the consumption characteristics ofconsumer categories or supply areas. Network loads when converted to information such as loaddensity (kW/km.sq.) provide valuable information for load forecasting purposes. The loadingdensity information is also a good index of comparison of the different supply areas for variousplanning characteristics. The data gathered during the non-technical loss study also providedvaluable information on consumption patterns of different types of consumers. During the latterexercise numerous instances of low power factor loads were also detected and action taken toenforce penal tariff charges. While the study was in progress, information collected on networklosses and consumer characteristics were used by KPLC's Consultants (London Economics) incarrying out a tariff study. The information gathered is thus extremely valuable for keyfunctional areas including, distribution planning, operational planning, load forecasting and tariffformulation. Hence, the network and consumer data collected should be suitably compiled andsupplemented regularly. The planning cell established during the study is quite capable ofcontinuing these tasks and should be encouraged to carry out the activities commenced on acontinuing basis.

3.19 A sample of the information gathered is presented in the tables and figures of theAnnex 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

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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 systemfor the Nairobi City and its environs. A 220 kV transmission line from the Kamburu/Kiamberehydro complex to the substation at Dandora constitute the main supply source. At Dandora, a220 kV connection supplies the Embakasi substation (feeding the southern parts of the city) anda short 132 kV connection supplies the substation at Juja Road. The latter substation is alsosupplied from Kindaruma power station at 132 kV and the Tana & Wanji power stations at 66kV. In addition the western transmission system (which extends up to Owen Falls in Uganda andthe Turkwel supply, connected at Lessos) connects to Juja Road substation at 132 kV and alsofeeds 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 someadjoining areas as shown in Map IBRD 26459. The 11 kV network is fed from ten 66/11 kVsubstations: Parklands, Jeevanjee, Buckleys, Industrial Area, Nairobi South, Cathedral, SteelBillets, New Airport, Ruaraka and Karen. The first six of these together with some feeders fromthe seventh (Steel Billets) feed the 'city center'. This area --about 100 sq.km.-- has a high loadconcentration and is supplied by a well configured 11 kV system with the average distancebetween adjacent substations being of the order of 2.5 km. The consequent short feeder distanceshave resulted in a reasonably low loss distribution system. The only area where feeder distancesincrease significantly is in the north western section and the analysis to follow shows that twonew substations can profitably be introduced in this area. The peripheral areas of the city (notcovered 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 substationsRuiru and Nyaga in the north east.

Present System Operation

4.3 The data collection exercise carried out for the study area as described in Section3 yielded information on the key characteristics of feeders such as maximum and minimumloads, power factor, load and loss factors and peak contribution. These data are presented inTable A2.1 of the Annex. Loadflow computations were also carried out for each feeder andsummary results of these studies are presented in Table A2.2 of the Annex. The tables provideinformation on the loss levels and terminal voltage drops of the feeders operating with thepresent network peak loads as well as with the expected loads in the next 10 and 15 years. Anumber of feeders outside the specific area selected for the study were also analyzed in view oftheir impact in considering investment options. At current loading levels the technical losses arereasonable --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

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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 therespective loss values will increase to 9.61 and 6.8% respectively. Furthermore, there are manyfeeders which have high loss levels even with the present load and profitable investment can bemade 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) andRidgeways (feeder 28) supplied from Ruaraka substation. The power loss levels of these twofeeders at present peak loads are 6.8 and 9.5% respectively. Without system improvements thelosses will increase to 13.3 and 17.0% respectively in 10 years time. System development of thisarea is best effected by introducing a new substation in the Kiambu area and rationalizing the1 1kV feeder arrangements from the existing and new substations. Two locations for the possibleintroduction of such a substation have been studied. In the first alternative the resulting networkrearrangement will mainly benefit the targeted feeders (nos. 23 and 28). In the second alternativethe substation location is further north west of the two feeders thus enabling the new substationto also pick up some load from Muthaiga feeder (supplied from Limuru substation) and UNEPfeeder (supplied from Kitisuru substation). The second proposal will have additional costs inview of the longer length of 66 kV line extension involved and the reconductoring of some 11kV 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 asagainst 635 kW for present system loads). A substantial additional benefit from the secondproposal is that the new substation can relieve the demand on Limuru substation which ispresently close to its designed rating. An economic analysis of the two proposals is presented inTable A2.3 of the Annex, a summary of which is presented in Table 4.1 below. Both alternativesyield high benefits and if only loss reduction benefits are considered they are about equallyadvantageous. With reliability benefits and the ability to service new loads however, alternative2 is clearly preferable and thus this alternative is reconimended. Existing network details and thealtered feeding arrangement from the proposed new substation are shown in Figures A2.1 A andB, of the Annex.

Table 4.1: Economic Evaluation of Alternative Locations for Kiambu Substation

Location 1 Location 2B/C ratios NPV B/C ratios NPV

Period of analysis 1 OYr 1 5Yr 1 5Yr 1 OYr 1 5Yr 1 SYr1. Only loss reduction 6.9 7.1 5.1 6.8 7.0 6.72. Loss reduction plus reliability 9.5 10.1 7.7 9.6 10.3 10.43. 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.

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New Substation at Kileleshwa

4.5 The area west of the Parklands and Buckleys substations is presently supplied bya number of feeders from these substations as well as from the east bound feeders from Karensubstation. This is one of the heavily loaded areas of the city and contains a number of feederswith 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, 7.6and 5.9% respectively in 10 years. Since the area is already built up there are only limitedpossibilities of finding suitable land for a new substation to improve the supply arrangement forthe feeders concerned. Although a number of alternative locations for introducing a newsubstation were considered only one proposal is presented due to the difficulty of securing therequired land and lower economic attractiveness of the other alternatives. An economic analysisof this proposal is presented in Table A2.4 of the Annex. Figure A2.2.2 shows the location of theproposed substation. A peak time loss reduction close to 1 MW and an annual energy saving ofabout 3.4 GWh is achieved at present loading levels and the proposal yields a benefit to cost ratioof 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 whichcontribute to high network losses. Selective reconductoring of such sections were investigatedduring the study and those that provided significant loss reduction benefits were subjected to aneconomic analysis. In addition, the possibility of introducing new feeders to relieve the loadinglevels of existing feeders has also been investigated. Only loss reduction benefits have beenconsidered 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 anotherbenefit applicable to most new feeders. However, in the particular instances examined thesebenefits were found to be applicable only after about 10 years; they were thus excluded in thecomputations. Key results of the analyses carried out for reconductoring options are presented inTable A2.5.1 of the Annex. In some instances the reconductoring options have been comparedwith alternative developments involving new feeders (including selective reconductoring ofcertain sections). The results of such comparative economic analyses are presented in TablesA2.5.2 and A2.5.3 of the Annex for the systems presently supplied by Feeder Nos. 30 and 38. Acomparison of benefit to cost ratios of this analysis is presented in Table 4.2 below. In bothinstances it is observed that if only loss reduction benefits are counted the reconductoringproposals are superior. However, when the reliability benefits are included the new feederproposals emerge as the winners. Further, the incremental benefits of adding the new feedersections are compared to the incremental costs in Tables A2.5.2 and A2.5.3, indicating benefit tocost ratios over 25:1 in both instances. Accordingly, proposals incorporating new feeders arerecommended.

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Table 4.2: Economic Evaluation of Reconductonng vs. New Feeder OptionsBenefiVCost Ratios

Feeder 30 Feeder 38Recond- New Record- NewOption Feeder Option Feeder

1. Only loss reduction 14.7 8.6 18.0 9.92. 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, theidentified improvements proved to be economic with an overall loss reduction from 3.1% to1.2% of the aggregate power supplied to the feeders concerned. These improvements will resultin peak time power saving of almost 1 MW and an annual energy saving of 5.1 GWh at currentloading 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 powerfactors, particularly during day time hours (see Table A2.1 of the Annex). Loss savings thatcould be achieved by reactive compensation (installing capacitors) at suitable locations wereexamined with the aid of special programs in the network analysis software supplied. The resultsof 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 restvaried between 0.80 and 0.93. With the introduction of capacitors the performance of the feedersimproved with reduced losses as well as improved feeder voltage profiles. Due to a number ofconsiderations the increase of benefits with load growth of future years has not been takenaccount of in the analysis. Firstly, it is possible in certain instances that developments proposedelsewhere in this section (addition of new substations and feeders) would change thecharacteristics of the system substantially, reducing the benefits introduced by the capacitors.Secondly, feeder power factors could improve considerably if action is taken to improveconsumer load power factors. Table A1.4 of the Annex provides the results of the investigationsmade during the study on sampling the power factors of bulk consumers. Clearly many of theseconsumers should be encouraged to improve their power factors by compensation measureswithin their installations. In view of these considerations the capacitors recommended to beapplied 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 systemdevelopment and rectification of the consumer power factors would take about this time toimplement under present conditions. Accordingly, the study recommends reactive compensationmeasures at nine installations totalling 6.7 MVAr of compensation at a cost of $ 73,800. Theseapplications would provide an aggregated benefit to cost ratio of 8.3 and pay-back-period of 18months.

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Summary of Network Improvements Proposed

4.9 Power system studies conducted for the area selected within the Nairobi cityresulted in the identification of network investment proposals amounting to $ 5.2 million. Thesedevelopments are expected to provide peak time power savings of 2.5 MW and annual energysavings of 15.5 GWh at current loading levels. As discussed in Section 3 these benefits willincrease with the expected increase of network loads over time. The proposals for newsubstations (and feeders) will also provide substantial reliability benefits as well as neededcapacity to connect new loads. The overall benefit to cost ratio of the proposals for a 15 yearanalysis period works out to 21.4 A summary of the recommendations of the economic analysescamed out for the network improvement measures is provided in Table 4.3 below:

Table 4.3: Summary of Proposed Network Improvements

Feeder PeakPower Losses in kW Power Savings (kW)

AnnualAt Energy Investment

Feeders Existing Designed At Feeder System Savings CostImproved 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 &74I1,82__ 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 19.04 91 46 45 27 245 35 9.839 128 46 81 74 242 39 12.840 115 27 88 84 275 55 10.3X 1 202 83 122 110 399 28 27.513 43 IS 25 22 125 14 12.614 143 62 81 73 395 37 26.618 103 44 59 53 297 27 15.524 212 74 138 88 695 42 18.925 145 67 78 50 459 - 40 16.2l 52 l 74 37 37 23 198 32 8.955 88 46 42 38 117 34 6.31 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 20.238 117 i 22 i 94 183 S 369 711 23.7

Capacitors for Low Power Factor Feeders6.7 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

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V. COASTAL AREA MV SYSTEM DEVELOPMENT

Overall supply arrangements

5.1 Maps IBRD 26526 and 27805 show the important features of the supply systemfor the Coastal Area. Power from the national grid is supplied from the 220/132/33 kVsubstation at Rabai. This main grid substation feeds three injection points to the distributionsystem. The first is at Rabai itself off a 23 MVA 132/33 kV transformer, providing supply toloads in the southern and western sections in the Area. The second is at Kipevu (90 MVAsubstation) fed by short 132 kV connection from Rabai and supplying the loads in and aroundMombasa Island. The third is at Kilifi (15 MVA substation) fed by a 132 kV line from Rabaiand supplying the loads at the northern periphery. To augment the grid supply (which is unableto maintain satisfactory voltage levels at system peak), 63 MW of oil-steam and 31.5 MW of gasturbine power plant are installed at the Kipevu substation.

5.2 For purposes of network studies, the distribution system can be convenientlygrouped 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 feederfrom Rabai;

(b) the area to the west of Mombasa supplied from two 33/11 kV substations, one atMiritini and the other a direct supply to the Kenya Oil Refinery, these twosubstations 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 atMakande (23 MVA), Mbaraki (46 MVA) and Likoni (7.5 MVA), with 33 kVsupply provided by two feeders from Kipevu; and

(d) the northern coastal section interconnected by a 33 kV network with three circuitsbetween Kipevu and Bamburi and continued thereafter by a long single circuitfrom Bamburi to Malindi. This section is fed from two sources, 33 kV at Kipevuand a 15 MVA, 132/33 Grid substation at Kilifi (supplied by a 132 kV line fromRabai). A number of 33/11 kV substations at, Nyali (10 MVA -spur off mainline), Bamburi (30 MVA), Ribe (0.5 MVA -spur off main line), Shanzu (15MVA), 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.

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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, loadand loss factors and peak contribution were obtained during the data collection exercise and arepresented in Table 3.1.1 of the Annex. Loadflow computations for each feeder were also carriedout using the software described in Section 3 and summary results of these studies are presentedin Tables A3.2 and A3.3 of the Annex,. These tables provide information on the loss levels andterminal voltage drops of the feeders operating with the present network peak loads as well as thewith the expected loads in the next 10 and 15 years. A summary of the network losses by voltagelevel is provided in Table 5.1. This Section examines those feeders with poor performance levelsand 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 15Yr11 kVsystem losses 2.5 5.0 9.6 1.7 3.3 6.333 kV system losses 4.8 9.0 13.1 3.5 6.5 9.3Combined 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 presentsystem loads. However, performance of the 33 kV system is not as satisfactory, thus increasingthe MV system losses as a whole. The table also indicates how the overall losses would increasewith time in the absence of suitable system development. Furthermore, the details of theindividual feeders show that the poor performance of a number of feeders are masked by the lowlosses of heavy load concentrations close to the supply substations. It will be seen from theensuing analysis that many feeders are not performing economically and that there isconsiderable scope for economic system improvements.

5.5 A number of 33 kV feeders in the Coastal Area presently operate at exceptionallypoor performance levels. The 33 kV feeder to Diani from Rabai has a 10.4% power loss and aterminal voltage drop of 15.6%. The Malindi feeder from Kilifi is a very long feeder with theload concentrated towards its end and has a peak loss of 23.1% and a terminal voltage drop ofabout 30%. These feeders should be relieved immediately to service the existing consumerssatisfactorily and to enable new consumers to be connected. The Miritini feeder from Rabai isalso operating at a high loss level 6.0% (and a voltage drop of 7.2%). Although the three feedersto Bamburi from Kipevu have reasonable loss levels (2.6 to 4.1%) their performance cannot beconsidered as satisfactory. The low loss levels are due to the short lengths and Bamburi Feeder 1is already close to its thermal rating. The reliability of supply from these feeders to the importantloads supplied is low and there are limited possibilities of load transfers in the event systemfailures. In contrast, only a few of the 11 kV feeders are in need of immediate relief. Those thatrequire improvement are the Kwale and Diani 1 feeders from Diani Substation (present losses at

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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 Mbarakivia the submarine link for optimum system performance. This is not possible at present due tothe unserviceability of this submarine cable. If the necessary repairs/replacements are carried outand the supply arrangements altered the loading on the Diani feeder from Rabai can be reducedfrom 12.8 MW to 8.3 MW. This will result in the feeder losses being 7.9% (reduced from10.4%) and the voltage drop 11.2% (reduced from 15.6%). System improvement proposalsconsidered 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 presentlysupplying the load concentration around Diani is grossly inadequate to meet the existing load. Anumber 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 temporaryshutdown of operations. There are indications that this load will resume; and if it does, thesupply situation in the area will become even more critical. The rest of the load in the areaconsists of medium and low demand domestic and commercial consumers as well as someagricultural 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, theDiani substation should be able to feed Likoni as an altemative operating condition (forexigencies) 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 thevoltage drop to increase to 20.4% --values which cannot sustain system operation without serioustechnical problems. A new 132/33 kV substation is therefore urgently required at Diani with theintroduction of which the peak losses from Rabai to Diani will decrease to a mere 0.5% for thepresent system load and 0.8% for the load expected in 10 years time. The 132 kV line proposedfor the Diani substation can be constructed either with the conventional steel tower structures asin KPLC's current construction standards for 132 kV lines or with wooden poles (which willprovide a saving of about 50% for the line costs). The 132 kV connection will also improve thereliability level of the area up to Likoni. Although there will be no substation capacity shortagefor some time the low voltage levels in the existing system precludes the addition of new loadswithout the proposed development and hence new capacity additions form a part of theassociated 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 summarizedin Table 5.2 below. Both options provide positive benefits over costs even if only the lossreduction effects are considered. The benefits increase when reliability improvement and ability

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to supply new loads are included. In view of the relatively low load and since this area is at theperiphery of the network, line construction on wood poles is recommended.

Table 5.2: Economic Evaluation of Alternative Line Construction 132 Kv Line toDiani

Wood pole line Steel supportsB/C ratios NPV B/C ratios NPV

Period of analysis 1 OYr 1 5Yr 1 5Yr 1 OYr 1 5Yr 1 5Yr1. Only loss reduction 2.8 2.8 3.2 1.6 1.6 1.92. Loss reduction plus reliability 3.8 3.9 5.1 2.2 2.3 3.93. 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 are3.4%, 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. Thefirst proposal consists of reconductoring the initial sections to 300 mm.sq. In the second, a newline is added to enable the load to be split up to two separate feeders. The third proposalintroduces a new primary substation to restrict the area of coverage of the Diani substation. Alloptions give satisfactory technical operation over the 15 year analysis period. Since there is nocapacity shortage or other technical inability to meet new loads, such benefits have not beencomputed for all alternatives. Both the new feeder and the new substation will however improvesystem reliability and related benefits have been included for these two options. Key results ofthe cost benefit analysis for these options are presented in Table A3.5 of the Annex and summaryresults are provided in Table 5.3 below. In view of the higher benefit to cost ratios of the newfeeder proposal this option is recommended.

Table 5.3: Economic Evaluation of Alternative Improvements to Tiwi Feeder

Reconductor New Feeder Newsubstation

B/C NPV B/C NVP B/C NPV1. Only loss reduction 1.9 0.1 3.1 0.1 1.8 0.12. 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.

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Proposed New Substation at Galu

5.9 The present Diani No. 1, 11 kV feeder from Diani substation has excessive lossand voltage drop characteristics even at present loading levels. The calculated values for peakconditions are 8.5% and 12.7%, respectively. This area has a high load growth potential with adeveloping 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 totallyunacceptable both technically and economically; losses rising to 18.1% and 32.3% and voltagedrops rising to 28.4% and 49.6% for the two future periods respectively. Urgent systemimprovements are required to provide better supply conditions to this area.

5.10 In view of the pressing difficulties experienced, KPLC is constructing a lineconnecting this feeder with Galu substation further south of Diani. Accordingly, systemperformance with this interconnector has also been considered in the analysis. It is seen that thenew interconnector will improve performance to some extent with power losses being reduced to5.3% (at present loads) but the perfornance still remains unsatisfactory. This is mainly becauseof the limited load transfer possibility in view of the low capacity of the Galu substation. Inorder to further improve the situation two proposals have been considered. In the first, thecapacity of the Galu substation is increased to 7.5 MVA while retaining the 11 kV network aspresently configured (inclusive of the above mentioned interconnector). The second proposal isan improvement of the first with a number of sections of the feeder being reconductored to300AA and 0.150SCA conductor. The results of the benefit to cost analysis are presented inTable A3.6 of the Annex and summarized in Table 5.4 below. The second proposal has higherbenefit to cost ratios if only loss reduction and reliability benefits are considered but the firstproposal is better if all benefits are included. However, if net present values are considered thesecond proposal is more advantageous under all conditions. Closer investigation howeverindicates that if incremental benefits are considered (those attributed to reconductoring, giventhat sub-station augmentation will take place) the second proposal is preferable and accordinglythis proposal is recommended.

Table 5.4: Economic Evaluation of Improvements to Galu Substation and Associated 11kV Lines

With 11 kV lineWith only SS augmentation reconductoringB/C ratios NPV B/C ratios NPV

Period of analysis I OYr 15Yr 15Yr I Yr 15Yr 15Yr1. Only loss reduction 3.0 3.2 0.4 5.2 5.5 1.12. Loss reduction plus reliability 4.5 4.9 0.7 7.0 7.6 1.73. 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.

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Proposed 132 kV Line to Bamburi

5.11 The 33 kV Bamburi I, II and III feeders from Kipevu feed a number of importantloads just north of the Mombasa Island. The major load in this area is the 30 MVA BamburiCement Company fed directly from the 33/11 kV substation at Bamburi. The rest of the loadssupplied 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 theBamburi cement factory will increase its load to meet the rising demand for cement by thebuilding industry. The concentration of hotel loads along the coastal areas also augur for ahigher 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 figurewhich is not too excessive, the computations for the fuiture loads show the losses increasing to5.4% in 10 years and 7.15% in 15 years. The present voltage drops of the three feeders are all ofthe order of 5%. With the future load growth however, the voltage drop of feeder I increases to10.3% 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 analysisperiod, but a load transfer to this feeder from the higher loss feeders II and III is not possible inview of the large capacities of the connected load and the need to keep the feeders separate forreliability considerations.

5.13 Substantial economic benefits and improved technical performance can beobtained by providing a 132 kV supply from Rabai to Bamburi. This additional injection pointto the distribution system of the northern section has many advantages in addition to lossreduction benefits. The new supply will enable the Makande substation to receive power fromeither Kipevu or Bamburi, providing an enhanced reliability of supply. During normal operationthe Makande load will be supplied from the existing three circuits from Kipevu leaving thenorthern load to be fed from the new substation at Bamburi. Any future load increase at thecement factory can be handled expeditiously in view of the 132 kV supply availability at thislocation. The proposals analyzed consist of using 0.15 in.sq. as well as 0.2 in.sq. conductor inboth single (SC) and double (DC) circuit configurations. Key results of the benefit to costanalysis of the proposals are presented in Table 3.7 of the Annex and summarized in Table 5.5below. In general with increasing conductor cross-section the economic benefits are observed toimprove. However, the benefit to cost ratios (both for the 10 and 15 year periods) of the DC 0.2in.sq. option is lower than that of the DC 0.15 option. Consideration of the incremental costs andbenefits between these two alternatives result in a positive benefit in using the higher crosssection. Thus the selection of the DC 0.2 in.sq. 132 kV line option is recommended. TheBamburi grid substation will be initially installed with two transformers of 23 MVA each butsubstation equipment should be capable of accommodating a third unit.

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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 NPV1. Only loss reduction 5.9 15.0 6.7 19.3 6.9 21.3 7.1 24.12. Loss reduction plus reliability 8.4 23.0 9.4 28.4 12.0 39.3 11.7 42.23. 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 loadconcentrations in the northern periphery of the Coastal Area. A 33 kV feeder to the south (whichconnects 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 suppliesthe substations Gede (1.5 MVA), Malindi (7.5 MVA) and various distribution transformers witha total capacity of 4 MVA at Marerene. Scattered loads are also fed directly from the 33 kV linesrunning south and north of Kilifi. Apart from the loads close to the grid substation at Kilifi, thelargest load concentration in the area is at Malindi, fed by a 33 kV line of 59 km. The area has anumber of hotels, agro-based industrial consumers and some commercial load in addition to thedomestic 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. Thisfeeder is the worst performing feeder in the Mombasa Area. Although the section to Marerene isvery lightly loaded the concentrated load at Malindi itself is far above the acceptable limits forthe 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 increaseto 39.4% and 51.4% respectively. The load flow analysis program fails to converge for the loadconfiguration of 15 years indicating impossible operating conditions. Thus it is clear thatimprovements required to this feeder are long overdue. Due to the long length involved and therelatively low load supplied, KPLC has been reluctant to construct a 132 kV line to feed thisload. The recommended solution in instances of this nature is to use a low cost approach to the132 kV line and substation construction. Wood poles using lower clearance would be admissiblein view of the terrain over which the line passes"2. Furthermore the 132/33 kV substation couldconsist of free standing reclosers on both the 132 and 33 kV sides with direct connections to asingle 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 tovehicular traffic lower line clearances are generally admissible.

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levels of protection are acceptable in view of the low fault level and the limited load served. Thebreaker 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 a132/33 kV, 15 MVA substation at Malindi and (c) construction of a wood pole 132 kV line and a132/33 kV transformer with simple switching arrangements at Malindi. Option (c) uses the lowcost 132 kV line and substation approach as advocated in the previous paragraph. Key results ofthe benefit to cost analysis are presented in Table A3.8 of the Annex and summarized in Table5.6 below. For the 33 kV development option it was assumed that a load up to 12 MW can besustained (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 alsoaccounted for. For the 132 kV options, the load of the full 15-year analysis period could be metfrom the proposed investment. The 33 kV option though slightly superior to the 132 kV steelpole option is not as attractive as the 132 kV wood pole option. Hence a wood pole 132 kV linefrom Kilifi to Malindi with a single 15 MVA, 132/33 kV transformer and a simple 33 kVswitching arrangement is recommended.

Table 5.6: Economic Evaluation of Improvements to Malindi Feeder

Wood pole 13233 kV line Steel pole 132 kV kV

132 kV line details B/C NPV B/C NPV B/C NPV1. Only loss reduction 8.2 11.5 4.4 11.9 6.2 13.02. Loss reduction plus

reliability 7.1 11.5 6.3 18.7 8.4 18.63. 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 feederfrom Miritini 33/11 kV substation. This feeder is spread over a wide area containing relativelydispersed 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 growthrate of around 5% could be expected over the future period of about 15 years. The presentsystem power loss is computed at 7.3% and the voltage drop at 15.1%. The situation worsenswith the future load growth and losses increase to 13.5% and 21.9% in 10 and 15 yearsrespectively, the corresponding voltage drop increasing to 27.3% and 42.6% respectively.

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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 andare summarized in Table 5.7 below. The 33 kV conversion proposal although superior on lossreduction 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 kVhave not been accounted for in the analysis. The new 33/11 kV substation at Rabai is moreeconomical than the alternative development at Mazeras. Further, the substation location atRabai 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 conversionSystem development: B/C NPV B/C NPV B/C NPV

a. Only loss reduction 2.9 0.6 1.5 0.2 2.9 0.6b. Loss reduction plus reliability 4.4 1.0 2.7 0.6 2.9 0.6c. 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 loadedfeeder (5.2 MW) feeding important loads within the Mombasa Island. Thus, proposals toimprove the performance of this feeder were considered. The developments examined were theintroduction of a new feeder (with associated reconductoring of certain existing sections) and theintroduction of a new 33/11 kV substation at Buxton. Table A3.10 in the Annex provides theresults of the economic evaluation of the two alternatives. The new feeder proposal is moreadvantageous with a benefit to cost ratio of 6.3 (compared to 3.1 for the new substation). TableA3. 1O also considers the additional benefits of rationalizing other feeders in the neighborhood ofthe 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 substationcould be reconsidered at a latter date depending on the load development in the Island).

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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 powerlosses are at 7.9% and the voltage drop is 13.6%. In the absence of system improvements losseswill increase to 20.7% and the voltage drop to 34.1% in 10 years. The network performance canbe improved by introducing a new feeder (with reconductoring of certain existing sections) toachieve substantial loss reduction and improved network performance. Table A3.11 in theAnnex provides the results of the economic evaluation indicating a very high benefit to cost ratioof 65:1.

Application of Capacitors for Reactive Compensation

5.21 Proposals considered above provide for the major system improvement necessaryto meet future loads and improve network performance in an economic manner. Some of thesedevelopments, particularly those involving 132 kV construction work will require at least twoyears to commission in view of the necessity to secure funds and attend to the necessaryprocurement. Studies have also shown that substantial economic benefits as well as immediateimprovements 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 theAnnex provides the results of studies where economic application of capacitors is possible. Atotal of 2.4 MVAr of capacitors in banks of 300 to 900 kVAr can be utilized with an overall payback 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 CoastalArea indicate that there are a number of major network improvements that are required to beimplemented in the immediate term. Amongst the most urgent requirements are the 132 kVdevelopments required for Malindi and Diani. These 132 kV system extensions required couldbe constructed on wooden poles to minimize construction costs, in particular as the loadssupplied are at peripheral locations in the system. A 132 kV injection to Bamburi is anotherimportant system development required, providing reliability benefits to the loads in theMombasa Island and environs.

5.23 Investrnents identified total $15.9 million with aggregate loss reduction benefitsof 4.3 MW at peak demand and 20.0 GWh, annual energy savings at present loading levels. Theoverall benefit to cost ratio of the MV network development proposals is 27.7 indicating higheconomic returns. A summary of the individual proposals is indicated in Table 5.8 below:

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Table 5.8: Summary of Development Proposals

Present System Proposed System Invest. B/CLosses Losses Loss Saving Cost Ratio

kW MWh/yr kW kW MWh/yr Million132/133 kV Substation23 MVA at Diani 653 3066 47 606 2843 3.500 7.6132/33 kV Substation(3 x23 MVA) at Bamburi 1552 8456 187 1365 7438 7.990 40.5132/33 kV Substation(23 MVA) at Malindi 1842 7907 138 1704 7314 3.337 14.133111 kV Substation(5 MVA) at Rabai 169 391 15 154 356 0.400 5.0Galu SS (2.5 MVA)Augmentation to 7.5 MVA 193 796 38 155 639 0.366 26.511 kVFeeder,Tom 58 164 38 19 55 0.060 6.3Mboya11 kV Feeder, Bamburi II 260 934 122 138 495 0.084 65.311 kVFeederforTiwi 60 317 29 31 165 0.080 4.882400 kVAr of Capacitors 100 165 0.031 13.1

Total 4787 22031 614 4272 19470 15.85 27.7

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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 feddirectly from higher voltage networks, the LV consumers still account for about 45% of theoverall energy supply. In terms of contribution during system peak the LV system demand iseven more pronounced, with an estimated 83% of net generation (about 590 MW) flowingthrough LV networks. Existing LV networks have been designed according to traditionalpractices that were established many years ago. These practices did not adequately addresseconomic considerations of loss optimization, nor were facilities available at that time forcomprehensive study and analysis of distribution systems. The current study introducedcomputerized network planning facilities and an extensive amount of work lies ahead for KPLCto redesign its LV systems to meet economically acceptable standards. Thus, an importantobjective of the present study was to examine whether some general methodologies could beestablished for carrying out such exercises. While the results of the sample studies carried outare presented in this section some general guidelines on procedures to be followed in suchstudies are presented in Section 8.

Network Losses

6.2 LV networks of 18 transformer supply areas selected at random were surveyed inorder to examine their operating characteristics. During the survey the networks were drawn on1:2500 scale maps, a census made of consumer connection by each pole and the daily loadprofile determined for each transformer. Samples of the transformer load profiles are shown insection A1.3 of the Annex. In view of the need to coordinate the developments within each areawith the adjoining networks four other transformer supply areas were incorporated in to thestudy, increasing the study areas to those supplied by 22 transformers.

6.3 Each of the supply areas was modeled using the LOWO software programdescribed in Section 3 and the results of the load flow studies and sample network diagrams areshown in section A4 of the Annex. The aggregate power and energy losses of the LV systemsstudied 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 thatover half the networks have loss values of over 3.4% for power and 2.1% for energy. More than20% of the systems have power loss values of over 10% (corresponding energy loss value being6.9%). Since well configured LV networks should have power losses of about 2% or lessKPLC's LV systems are in need of substantial investment to improve their operatingperformance.

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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 fluxin the transformer core) and a current dependent component, termed copper losses (similar to thelosses of a conductor in the network). A spreadsheet to compute the transformer losses atvarious loading levels (utilization factors) and load and loss factors was prepared in order toanalyze performance under different operating conditions. Tables and figures in the Annex(A4.2.1 onwards) provide the results of these computations for transformer characteristicscommonly found in Kenya as well as for typical lower loss transformers currently availableinternationally. Percentage losses are observed to be very high for the lower rating transformersand also at lower utilization factors. For example, a 50 kVA transformer in the KPLC systemloaded to 20% of its rating with a load factor of 30% would have a power loss of 2.5% and anenergy loss of 10.0%. A normal low loss transforners under the same operating conditionswould have only half the above loss values and a low loss unit of appropriate rating will havelosses of about 1/5th the original values. Thus substantial savings in transformer losses arepossible 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 ina life-cycle cost comparison during transformer procurement. Parameters involved in thecomputation of the cost of losses include economic factors (interest rate, expected lifetime, costof power and energy losses) and those dependent on system characteristics (transformerutilization level, peak contribution, load factor and loss factor). The method of computing forthese costs is presented in Table A4.3(A) in the Annex. A spreadsheet has also been prepared toassist KPLC in determining appropriate evaluation factors for various system conditions and costcharacteristics and Table A4.3(B) in the Annex provides the results for a range of values of therelevant parameters. It is seen that the evaluation factor for iron losses will remain independentof system characteristics. However, these characteristics will have a substantial impact on theevaluation factor for copper losses (loss load factor and peak contribution being the keydeterminants). Since transformers can not be purchased for specific locations the evaluationfactor to be used for copper losses should be based on average operating conditions in thesystem. KPLC should introduce without delay the practice of evaluating the cost of lossesduring transformer procurement. In order to ensure that prospective suppliers will useappropriate designs, they should be kept informed of the evaluation factors being used. Theprogram 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 moreappropriate figures of about $8000/kW and $2000/kW respectively when better transformermanagement practices are also concurrently established.

6.6 The second aspect to be addressed in transformer loss reduction is the review ofdistribution transformer loadings and carrying out a replacement and relocation exercise tooptimize utilization levels. During the study it was observed that many of the under utilizedtransformers were found in low load density areas. A special study was conducted in Kwale (arural district in the southern Coastal Area) and the results of this study is presented in Table

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A4.2.4 in the Annex. Twenty inappropriately loaded transformers were identified serving a loadof approximately 500 kVA with an aggregate transformer capacity of 1650 kVA. By using lowloss transformers of appropriate ratings transformer power losses can be reduced from 1.6% to0.6% and energy losses from 2.6% to 0.6%. Considerable reduction in losses can therefore beachieved by a suitable transformer load management program to improve the utilization ofdistribution 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 studiedin further detail to determine suitable development proposals which would optimize theireconomic performance. In four of these networks selected it was feasible to study systemimprovements by examining only the targeted network (fed by a single transformer). In theremaining three areas, it was found that the optimization exercise necessarily involved the supplynetworks of adjoining transformers. This is an important factor that should be borne in mind instudying network optimization; it is necessary to ensure that the recommended solutions remainindifferent to the selected study boundary.

6.8 Section 3 describes the software used for the study and the general methodologyadopted. For reasons discussed in paras 3.9 and 3. 10, the full automatic optimization capabilitiesof the L.V. network study program were not utilized over the entire study period. To overcomedifficulties connected with the spacial allocation of load growth, the overall analysis period of 15years was divided into three separate sub-periods of 5 years each, with the network loadsassumed to remain constant within each sub-period. The loading profile of each of the threeperiods was determined by (a) using an estimated load growth rate for the entire area relevant tothe 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 thebest possible combination of the optimization possibilities of the program with the knowledgegained from field investigations. The network optimization facilities of the software wasthereafter used as appropriate within each of the individual sub-periods.

6.9 Possible new network construction as well as suitable transformer locations areprovided as input data to the program. The program selects the investrnents required to optimizethe networks within each period (residual values being used for each item to avoid the effects ofthe short time slice used). All selected improvements are considered to be introduced at thebeginning of the relevant period and investments selected during a previous period areconsidered as being part of the existing system for subsequent periods. When an existingtransformer becomes overrated by virtue of the reduction of its feeding area caused by theintroduction of new transformers, it is replaced by one with an appropriate rating. Neither supplyand 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 tocancel each other. The investments selected within each period and the corresponding benefits

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were thereafter summed to determiine the overall benefit to cost ratio for the phased systemimprovement exercise.

Study Results

6.10 The options available to improve the technical and economic performance of thenetworks may be classified in three categories, these being:

a. introduction of additional transformers and consequent network rearrangementincluding new feeders;

b. addition of new sections or feeders with corresponding rearrangement of theexisting network; and

c. reconductoring of existing sections.

6.11 The first category, the introduction of additional transformers effectivelydecentralizes the L.V. network arrangement by reducing the area of coverage of each distributiontransformer and correspondingly increasing the number of transformers in the system. The effectof increasing the number of transformers may be perceived by a simple example. On anapproximate basis, doubling the number of transformers may be considered as shortening thefeeders 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 transformersthere would be an increase in transformer iron losses but this increase can be minimized (or evenreversed) if low loss transformers are used (see para 6.4 to 6.6). The second category ofinvestment options, the introduction of new sections and feeders is basically a rationalizationexercise of existing networks. The third category, reconductoring, reduces network losses by thelower resistivity of the current carrying cables by use of larger cross sections. The studyindicated that, in general, improvements under the first two categories proved to be moreeconomic than those of the third category.

6.12 As indicated in para 6.8 the LV network improvement study was carried out bydividing the overall period into three sub periods, termed periods I, II and III. Seven separateareas (consisting of a total of 11 transformer supply networks) were analyzed. During period Ithe LV optimization resulted in the selection of 9 new transformers; an additional 9 transformerswere selected in period II and a further 3 in period III. The progressive decentralization of one ofthe networks studied over the three periods is seen in Figures A4.4 (A), (B) and (C) in theAnnex. Investments selected by the program also included the addition of new sections ofaggregate length 910, 95 and 86 meters and reconductoring of existing sections of aggregatelength 4,953, 1,359 and 1,363 meters respectively for Periods I, II and III. The present KPLCstandards for L.V. network design are based on 100 mm.sq. all aluminum as the major lineconductor with 50 and 25 mm.sq. all aluminum also in use. There are also some older lines inthe system with copper conductors of 32 and 16 mm.sq. respectively. The network analysis

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program allowed, in addition, the selection of twin conductor 100 mm.sq. arrangement. Thehighest gauge selected for the reconductoring exercise is a twin 100 mm.sq. and the sections tobe reconductored in Period I have been of the order of 5 to 10% of the total network length. Inone of the systems, the main load carrying sections have only 50 mm. sq. conductor and hencethe program selected 63.4% of the total line length of this sample for reconductoring in additionto two new transformers, during Period I. This sample accounted for 46.8% of linereconductoring selected in all 7 systems.

6.13 This analysis shows that the improvements required for the LV networks are notexpected to follow a uniform pattern over the entire system and actual requirements should bedetermined by a careful examination of the individual network characteristics. The results of thesamples studied would however, provide useful general guidelines for the estimation of networkimprovement requirements over larger areas. LV systems are characterized by frequent changescaused by local conditions and implementation of a LV system improvement program shouldfollow the planning exercise. If substantial time has lapsed it would be prudent to reexamine thenetworks 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 resultingnetwork development recommendations is presented in Tables 6.1 and 6.2 below.

Table 6.1: Existing System Data

No. of separate network areas = 7No. of transformers in all areas = 11Area covered in meters sq. = 986,000Total load = 1537 kWSum of transformer capacities = 3535 kVAAggregate length of L.V. network = 24.8 kmAverage 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 IlIlTotal cost of proposals $84,880 $72,204 $27,001No. of additionai transformers 9 9 3Sum of new transformercapacities in kVA 1,287 991 466

Sum of new sections (in meters) 910 95 86Reconductoring ofexisting sections (in meters) 4,953 1,359 1,363

Benefit/Cost ratio 9.66 8.68 9.80

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Estimated Investment Requirements

6.15 The study results indicate that economically attractive investment possibilitiesexist for the improvement of the L.V. distribution networks. Each of the networks studiedrequired substantial network improvement. The seven sample areas investigated cover a totalarea of 10 sq.km. and identified investments totalling $84,880 for period I, $72,204 for period IIand $27,001 for period III. The reduction of investrnent requirements for succeeding periods isdue to the fact that networks become saturated with time. It signifies that older or moredeveloped networks will require lower investments and that a higher proportion of investmentrequirements will be channeled to new development sites. In Kenya, particularly close to themajor cities, urban expansion is a high growth activity and investments for L.V. systemimprovement 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 provideapproximate estimates of the investment requirements for the overall LV systems in urban areasof 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 validfor the Coastal Area as well). In more rural areas however the development requirements areexpected to be somewhat different. Three characteristics (conversion factors) have been used totranslate 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 6.3presents the results of such an analysis with the funding requirements limited to a five yearperiod (i.e. study period I). Also indicated are the main items of work (as per the results of thesample 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 Conversionstudied study area factor

Estimating characteristics:Area covered (km.sq.) 9.86 100013 101Length of LV lines (km) 24.8 3118 125.7Existing transformer capacity (kVA) 3535 450,00014 127.3Selected 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) 1,287 128,700New line sections (km) 910 91,000Reconductoring (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).

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6.17 The three conversion factors computed agree fairly closely; the selectedfigure (100) approximating to the lowest, is used as the multiplying factor to obtain thedevelopment requirements for the total study area. The requirements for such an LV networkimprovement program will be about US$ 8.5 million. Detailed planning exercises of thenetworks 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 loadcharacteristics. Once detailed studies are carried out for the initial investment (targeted to meetthe first 5 year period within the study area), a better appreciation will be gained on the fundsrequired to carry out an overall LV network improvement exercise for the entirety of KPLC'ssystem. In the study of the sample systems the average network energy losses decreased from4.7% to 1.5% for the loads in Period I (i.e. equivalent to Year 1994) and the overall benefit tocost ratio of the recommended improvements was 9.7. We may therefore expect the same levelof benefits to apply to the recommended LV system improvement program.

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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 thelatter to organizational deficiencies metering defects and consumer fraud. Non-technical lossesrepresent energy consumed for which bills are not issued. Unrecovered revenue from billedconsumption is a financial loss to the utility but is not included under non-technical losses. Thusnon-technical losses arise from shortcomings in the metering, meter reading and/or billingsystems 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 accountsand 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 ofmetering equipment such as CTs and PTs, tilted meters etc.);

(c) meter defects including faulty calibration, slowing due to ageing or by deliberatetampering 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 maynot be transferred at all);

(f) failure to include some consumers in the billing system (preventing the issue ofbills although meter readings may be regularly taken);

(g) billing system deficiencies such as inability to process bills due to mis-match ofconsumer 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 bywilful pilferage, they can in theory, be completely eliminated with careful management of meterinstallations, meter reading, consumer billing and associated services. Furthermore,implementation of measures to reduce such losses will not require the level of investment andtime associated with the reduction of technical losses. Thus in systems which exhibitappreciably high non-technical losses, substantial financial gains can be obtained by theirreduction. For this purpose suitable monitoring and control procedures need to be established tocover a range of activities commencing with the connection of the consumer to the system,

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through initiation of billing records and accurate meter readings on a regular basis, down to thefinal issue of bills. To rectify existing anomalies extensive field investigations are required toensure that the actual consumption in the system is correctly metered and billed for. Howeverreduction of non-technical losses will not result in an equivalent drop in demand as would beachieved in the case of technical loss reduction. Nevertheless, some load reduction is to beexpected due to consumers restricting the consumption which hitherto was partially orcompletely free.

7.3 During the study a number of field tests were carried out in order to estimate theextent of non-technical losses in the system as well as to ascertain their causes. Tests werecarried out for both bulk supply and retail consumers. The former category are the powerconsumers charged on the basis of both energy and maximurn demand; many of these are beingsupplied at medium voltage. The latter category is supplied at LV and charged only for energysupplied. While the majority of connections are made to retail consumers the greater proportionof consumption is from the bulk consumers. It should be noted that the field tests carried outduring 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 theexercise on a regular basis to obtain more meaningful inforrnation. Aspects of KPLC's billingsystem relating to the control of non-technical losses were also examined. A particular matter ofconcern was the usefulness of the current 'exceptions reports' produced by the billing system toassist in tracing inaccurate bills. KPLC counterpart personnel assigned to the study, assisted byconsultants and ESMAP staff, carried out the field work and related investigations. Apart fromthe information provided and the additional revenue gained by the detections, the exercise provedto 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 instrumentsdescribed in section 3 (paras. 3.6 and 3.7) were used for a limited time in series with the existingmeter installation. These instruments provide accuracy levels of the order of +/- 0.5% and can beconsidered to be on par with field calibration instruments. However, due to the time availableand the use of these instruments for measurement of system loading data (needed for thetechnical 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 todetermine the load current and power factor over a short time interval, measured with a stopwatch. The calculated value of the energy supplied during this time was compared with thatrecorded by the meter (obtained by multiplying the revolutions of the meter disc with the meterconstant). The method is acceptable if the power flow remains substantially constant over themeasuring period. Therefore, when load fluctuations were observed the test was interrupted andrepeated once steady power flow conditions reconimenced. These tests do not detect errors dueto tampering of the internal mechanism of the meter preventing the accurate conversion of diskrotations to registered units. While such tampering is possible they are in practice, very

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infrequent. In order to validate the accuracy of the method a sample of the installations (from thebulk supply consumers tested) were revisited and the meters checked a second time using one ofthe microprocessor based recording instruments. The comparison of the results of thisverification 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 MeterQuick Test Accurate Test

194201860 -32.0 -38.4199509570 -62.3 -62.9194206510 -35.9 -27.9194208360 -9.8 +0.05299510500 +0.05 +0.03194209340 -1.4 -0.8153427001 -16.2 -0.5199502111 +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 methodused is very effective for quick determination of the accuracy of the meter installed. Of the 8installations tested by both methods, six showed remarkably close readings while two showeddivergences of 15% and 10% respectively, in both instances the meter error reducing at thesecond, more accurate test. It may also be noted that the tests were carried out on different daysand at different loading levels and it is even possible that any meter tampering present during theprevious day was rectified by consumers who were alerted by the testing activity. This rathersimple method of checking meter accuracy was used to undertake a preliminary level testing ofconsumer installations. If substantial deviations were observed the installations were subjectedto 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 becarried out by KPLC's operations units on all defective installations detected) more informationon the extent and nature of the defect will be obtained. This method has the advantage of beingable 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 powerconsumers supplied at 11 kV or higher voltage by using the microprocessor based measuringinstruments 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 aloss level of 1.94% for the entire sample. Of the detections made, one installation had a loss of

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24% and two were over 15%. Both the percentage of errors and losses detected in Mombasagreatly exceeded that of Nairobi and this result requires further investigation by KPLC. Of 33consumers tested in Nairobi 5 were defective, resulting in a loss level of 1.4%. In Mombasa, outof 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 % EnergyGroup Tested No. Faulty Consumption Lost Loss of Sample

Nairobi 33 5 5,089,423 72,376 1.42Mombasa 8 5 786,260 41,893 5.33Total 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, thistime using the hand held instrument and stop watch method described in para 7.5 above. Thesamples 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 Table7.3 below.

7.9 The divergence of the meter recordings from the measured values contained manyinstances with an error range of +/- 10% followed by a smaller group with errors over 14%. Inorder to concentrate on installations with the largest contribution to non-technical losses and toeliminate 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 errorscaused by incorrect connections and meter tampering. However other errors where the reductionin units captured is relatively small will escape this selection. Uncaptured defects willparticularly include meters falling out of calibration (caused by the tendency of meters to slowdown with time due to damping and frictional effects).

7.10 A number of instances where the meters recorded values higher than measuredwere also observed within the excluded range. The number of such instances seem to indicatethat meter calibration is more often allowed to err on the side of excessive readings. KPLC'sstandard of allowed meter error is plus or minus 3% which is high by standards used in otherutilities (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.

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passed on to KPLC's commercial operating units which investigated the matter further. A fewinstances 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

EnergyNo. Total Monthly Total Monthly Loss of

Group Tested No. Faulty Consumption Units Lost SampleMombasa Random 54 9 2980249 147655 4.95Mombasa Exceptional 27 1 1994385 3755 0.19Nairobi Random 55 4 1611964 114399 7.10Nairobi Exceptional 53 9 1258984 77915 6.19Totals 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 thefact 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%. Consideringthe detections from both lists, the figure for Nairobi (7.66%), was considerably higher than thatfor Mombasa (3.32%). Furthermore the number of installations detected with non-technicallosses arnounted to 14.2% of those examined (in this instance Nairobi recording 11.4%, a lowervalue than that for Mombasa, 17.6%). The percentage of non-technical losses detected, both interms of energy lost and in the number of detections are exceptionally high and represent asubstantial drain on KPLC's revenues. If the results of the sample studies are typical for thiscategory of consumers (tariff category B), the 4.38% loss level corresponds to 25 GWh perannum representing KSh 45 million. This indicates the urgency of introducing a program totrack 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 causesof inaccurate readings, such as incorrect connections and evidence of tampering with themetering equipment. The results of these investigations (on 278 consumers), classified accordingto the type of defect are presented in Table 7.4 below:

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Table 7.4: Summary of Defects Detected on Bulk Supply Metering

Observed defect nos. % of defects1. CT faulty I2. CTs mismatched with meter 1 ) 24%3. meter running slow 6

4. meter shows signs of tampering 6 - 18%

5. CT short circuited 36. CT open circuited 1 ) 18%7. PT fuse blown 2 )

8. wrong PT wiring 19. wrong CT wiring 4 ) 15%

10. meter bypassed 2 - 6%

11. faulty demand meter 6 - 18%

Total inspected 278Defective installations 33Percentage defective 12%

7.13 24% of the detections were caused by faulty equipment. Meter tampering anddefects in the CT's and PT's accounted for 18% each. Since it is also probable that a substantialnumber of defects in the CT's and PT's are also caused by illegal tampering with the meteringinstallation --as in the case of short-circuited CT's-- this would increase the percentage oftampering to over a third of all detections. Wiring defects accounted for 15% and in 6% of thedetections the supplies were only partially metered.

7.14 Following the findings of the investigations, arrangements were made with theCommercial Operations Division to rectify the defective installations and to recover arrears due.This process is necessarily time consuming involving notifying the consumer (often leading toprotracted discussions), installation of new meters and assessment of past consumption after atrial period with the new meters. To date arrears for low billings amounting to KSh 2,057,041have been recovered from 13 such consumers. In addition, all suspected defective meteringinstallations have been replaced thus reducing the continuation of the under billing. Theestimated additional monthly revenue which would be recovered from the 33 detectionscorresponding to 0.5 GWh and 2.5 MW maximum demand, valued at approximately KSh. 2.5million (per month).

7.15 An interesting finding relevant to both Nairobi and Mombasa is that the selectionof installations from the exception lists --provided by the billing system-- resulted in lowerpercentage losses than those selected on a random basis. The same situation applies to thenumber 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

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for exceptional consumption needs careful investigation and re-design. One probable reason isthat most installation defects have been in place for so long that the average recordedconsumption (on which the exception report is based) has no bearing on the accuracy of thereadings.

Retail Consumers

7.16 Two methods were used to obtain an estimate of the non-technical losses presentin supplies to retail consumers. The first method involved energy audits of systems supplied bythree transformer stations. The energy supplied (output of the transformers) adjusted fortechnical losses in the network was compared with the sum of the metered consumption for allconnected consumers. The initial readings of the bulk meters measuring the supply input wasmade at approximately the mid-period of the meter readings taken on the individual consumerinstallations (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, 16and 17 months in the three samples) to even out any discrepancies due to estimated consumptionand 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 119consumers respectively while the third transformer supplied an under ground (UG) cable systemand had only 29 consumers. Technical losses (energy) of the two OH systems were computed tobe 1.6% and 1.2% respectively while the technical losses of the UG system were estimated to belower than 0.2%. However, for the non-technical loss analysis a conservative estimate of 2% and0.3% was used for technical losses of the OH and UG systems respectively. The results of thestudy are summarized in Table 7.5 below. Non-technical losses of the overhead systemsamounted to 7.7 and 8.6% respectively while the UG system showed losses less than 0.5%. Theoverall non-technical loss calculated for all three systems was 7.6%. While losses computed foreach individual month showed some variations the results generally were comparable with theoverall findings. (High readings for some months being offset by low readings in subsequentmonths --the aggregation generally producing consistent results).

Table 7.5: Results of Energy Audit Study of Retail Consumers

Energy Technical Non-Technical % Non-TechnicalSubstation Supplied Energy Billed Losses Losses LossesSS2261B 508931 459524 10179 39228 7.7SS4522B 503770 450645 10075 43050 8.6SS4440B 82571 81947 248 376 0.5

Total 1095272 992116 20502 82654 7.6

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7.18 In the second method employed, the hand held power meter and stop watchmethod (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 testedonly 58% were within an error margin of +/- 5%, the proportion extending to 86% if the errormargin is increased to +/- 10%. The possible error margin of this test was discussed in para 7.6on the basis of a comparison made with superior test equipment. The use of this method forretail 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 primarypurpose of the test is to detect instances with high contribution to losses while carrying out asmany tests as possible within the limited time period. If instances with errors over 15% areexamined it is found that there is one which recorded 16% in excess consumption and eightwhich recorded lower consumption by between 20 and 100%. These eight meters wereexamined closely, confirming the defects. One meter had stopped and failed to record anyconsumption. Another was barely moving (recording only 3.4% of the actual consumption); ofthe other six (errors ranging between 22 and 60%) one showed clear signs of tampering, one wastilted to an unacceptable level resulting in a low reading and the other four were confirmed asreading low.

7.19 From the data above it was concluded that about 8% of the meters in the sampleregister substantially lower than actual values (errors over 20%) for the energy consumed. Thereis also the possibility that some meters record consumption higher than the actual values, but it isunlikely that the over billing will be close to the under billing that occurs in the system. Theconfirmed detections of low reading meters indicate that the non-technical losses in the sampleare equivalent to about 4.5%. This figure may be compared to the loss level of 7.6% obtainedwith 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 variousreasons and remain so over extended periods are potential sources of non-technical losses. Themajority of the disconnections arise from consuners moving out of the premises and from thosewhose accounts are terminated for non payment of bills. In both these categories it would bereasonable to expect the new occupant or the defaulting consumer to apply for a reconmectionwithin a short period and it will only be in special circumstances such as the demolition ofbuildings that a subsequent application for reconnection will not be made. KPLC's billingsystem contains a procedure to identify such accounts. At each billing cycle a print out of suchdisconnected consumers (termed 'dead' accounts) is provided and these installations are expectedto be checked by field investigators to ensure that irregular reconnections have not occurred. Atotal of 65 such 'dead' accounts were inspected during the study resulting in the followingobservations:

(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

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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 accountopened for a new occupant; in (b) the account is terminated and the service connection and meterhad 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 areunnecessarily long. This has a detrimental effect on the quality of checking as it diverts theinvestigators from installations that require to be targeted. It is also preferable to list accountsunder item (b) separately from those under item (c) to facilitate the supervision activities. Theremoval 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 fraudulentsupply --by a meter/cut-out bypass. These buildings may still obtain illegal supply by devicesconnected to the distribution lines or from extensions from adjoining consumer installations.However for control purposes it is preferable to present these installations under a separatelisting. It is therefore recommended that suitable procedures be instituted to ensure that the deadaccount lists are maintained in a manner which will better assist those carrying out theinvestigations.

7.22 In category (c) representing 14 installations (or 21.5% of the sample) the powerconnection (up to the supply cut-outs) and the meter had been allowed to remain for periodsgenerally exceeding one year after the accounts were closed. It is this category that should betreated as the "true" dead accounts. In 4 instances (representing 6% of the total investigated and29% of category (c)), the reading at the time of inspection was in excess of the final reading atdate of disconnection, indicating that uncaptured consumption had occurred through the meterafter the date of disconnection. This consumption represents a non-technical loss. In oneinstance the consumption after the disconnection date was as much as 64,731 kWh (representingas much as 40 times the annual average consumption for a typical domestic consumer inNairobi). In the other three instances the unrecorded consumption amounted to an aggregate of3494 kWh (representing 26 months of average consumption). In none of the cases investigatedwas there any direct evidence of by-passing the meters. However, the investigation carried out ateach installation was not sufficiently comprehensive to detect such instances in view of the timerequired for such an exercise. Some form of fraud could still occur particularly in installations ofcategory (c). In order to verify such possibilities a joint ESMAP and KPLC team made adetailed check on 3 of these installations including a night visit (to ascertain whether electricallighting was being used in the premises). This investigation revealed that one out of the threehouses had obtained supply by an unauthorized extension from a neighbor. (Although thisconnection did not contribute to a non-technical loss as the consumption was recorded via themeter 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 onretail installations no longer active in the billing process ('dead' accounts):

(a) about 65% of disconnections carried out are eventually reconnected to the same ora different consumer within about one year. However the billing software andassociated procedures do not capture such reconnections, and the installation

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continues to be listed as a 'dead' account. This hampers and complicates thecontrol process and does not assist the field investigators to focus on theinstallations that require investigation;

(b) contrary to KPLC's regulations, meters and services were not removed from about61% of the premises that have been disconnected and remained disconnected overan extended period, thus providing an opportunity for unauthorized connections;

(c) about 17% of premises remaining disconnected could be expected to continueconsuming some power after being removed from the billing system.

7.24 Based on the findings of the study, the following recommendations are made toimprove KPLC's procedures concerning consumers disconnected from the billing system:

(a) ensure that premises which are subsequently officially reconnected are removedforthwith from the listing of dead consumers;

(b) it is necessary to ensure that KPLC's existing regulations concerning the removalof service connections and meter installations are enforced when the premisesremain disconnected over an extended period (about 3 months);

(c) systematic checking of premises that remain disconnected is needed to ensure thatthese 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 installedin the late 1970's. Since then, KPLC's power system has undergone considerable expansion witha tripling of power generation and a doubling of the consumer base. Much of the hardware isnow in a poor state of repair and frequent breakdowns (often involving long periods of downtime) disrupt the billing operation. With a total invoice level of KSh 4000 million per year, asingle 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 relatedequipment (including printers, storage media, access terminals) are now nearing the end of theirtechnical life and there is imminent danger of a complete breakdown. Such a situation wouldresult in substantial financial loss and operational problems to KPLC.

7.26 Given the shortcomings of the facilities in use, the billing system performs fairlywell 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.

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limited number of experienced personnel competent in its operation. Meter readings are taken inbooks and forwarded to a manager of the section who performs a brief visual check on thereadings before dispatching them to the head office electronic data processing (EDP) sectionwhere the data entry takes place. Some tests on the validity of the data are carried out in the EDPsection and corrections are sometirnes made without the approval of the area office. The billingis then done on a batch oriented system.

7.27 A major weakness of the system is the inability to maintain the data onconnections 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 (paras7.8 to 7.11) and the discussion on 'dead' accounts (paras 7.20 and 7.21) the reports generated forthe control of non-technical losses are of little value.

7.28 A utility's billing system should retain valuable information required by manyfunctions within the organization and be capable of coordination with other data bases. Currentcomputer technology (particularly information systems based on relational data bases) presentsan excellent opportunity in this connection. Establishing a meter history follow-up record is animportant area of application. Identifying consumers in relation to network connections (feedersand supply transformers) can help in monitoring system losses and in obtaining loading datarequired for planning purposes. Transformer load management is another application ofcorrelating the billing data with the consumer supply location. KPLC will therefore benefitgreatly from a more versatile and up-to-date billing and information system. In view of the ageand poor operational state of the present computer system, both software and hardware, it isrecommended 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 ofconsumers we may conclude the following:

(a) MV bulk supply consumers - Approximately 20% of metering installations werefaulty resulting in a loss of the order of 1.9%. The incidence of losses inMombasa was exceptionally high (60% faulty with losses of 5.3%) and needs tobe scrutinized further.

(b) LV bulk supply consumers - Approximately 12% of metering installations werefaulty 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%),

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Faulty maximum demand meters (18%),wiring defects (15%) andload bypassing the meter (6%).

(d) Retail (LV) consumers - The audits carried out in three networks resulted in theidentification of losses of the order of 7.6% while individual testing of metersresulted 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 asdisconnected 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 intracing non-technical losses.

Recommendations

7.30 A substantially large number of irregularities were detected during theinvestigations of non-technical losses, representing approximately 5% of the energy supplied toconsumers. This indicates that a concerted attempt needs to be made by KPLC to reduce suchlosses. It is therefore recornmended that a systematic and comprehensive non-technical lossreduction program be instituted. The experience in Kenya, as well as in other countries wheresimilar work has been carried out, indicates that the main thrust of the work should be bome byspecially assigned task forces rather than relying on line management. This observation does notdetract from the recommendation that the ability of line management to improve its proceduresand 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 whichoccupy line management (which cannot be avoided) it is not realistic to expect to have thisfunction attended to successfully under present conditions. The task forces should be seen as aservice to line management in carrying out a crash program and establishing proper procedureswhich 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 presentedbelow.

7.31 The other major area associated with non-technical losses that needs immediateattention is the introduction of new computer billing and data base systems in line with currenttechnology. 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 byspecial task forces. These groups should coordinate closely with operational personnel and otherfunctional groups, such as those in the billing and commercial departments. Three task forces

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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 Areato carry out field checks of both bulk and retail meters. The personnelshould be specially selected and used exclusively for this exercise --atleast during the initial period during which targeted loss reductions are tobe achieved.

(ii) The field tests may be carried out in approximately the same manner inwhich the exercise was conducted during the ESMAP study. However alarger number of standard field testing meters and microprocessor-basedinstruments is recommended. Accordingly KPLC should purchase asufficient quantity of such equipment.

(iii) For bulk consumers the testing should be carried out on a comprehensivebasis visiting all consumers on a feeder by feeder basis. For retailconsumers tests may be carried out on a more selective basis by examiningthe 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 rectifiedforthwith, including replacement of poor wiring installations andreplacement of seals. Hence the task forces should be properly equippedwith materials and equipment to carry out this work.

(v) For greater security against meter tampering the existing lead seals shouldbe replaced by padlock (Hoop) seals for meters and cutouts during theexercise.

(b) Consumer verification exercise

(i) A consumer verification program should be arranged in coordination withmeter reading staff (both for bulk supplies and retail supplies) to ascertainwhether all consumers connected to MV and LV lines are included in thebilling system. As this would involve additional time and effort it issuggested that one or even two billing cycles be made on an estimatedbasis for each area under investigation and this extra time available used toundertake a systematic examination of all premises supplied from thesystem. Since this exercise can be carried out successively from one smallarea to another (either by feeder or billing/meter reading group), thesuggested billing estimation would not occur simultaneously for all

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consumers. Careful attention should be made to ensure that the overallprogram is carried out systematically. The person or persons conductingthe test in each area should be recorded along with the results andsystematic documentation made on the findings.

(ii) The consumer verification exercise may be combined with obtaininginformation required for the improvement of the distribution system database; such as, account numbers of LV consumers connected to eachtransformer and bulk consumers connected to each MV feeder, etc.

(iii) The main purpose of the exercise is to ensure that all those obtainingsupply from the system are recorded in the billing system and properlymetered. Accordingly each MV and LV feeder should be followed alongits route and all connections checked.

(iv) A moratorium may be advertised inviting consumers to declare if they areaware of any defects in their metering installation or if they do not receivebills for the supply provided. When consumers volunteer information, asystem of waiving arrears resulting from previous anomalies may beintroduced.

(c) Rectification of anomalies detected

(i) A special group/s (based in the head office or the regional offices) shouldbe entrusted with the task of speedily rectifying the discrepancies notedduring both the meter inspection and consumer verification exercise. Ifnecessary this group should be authorized to discuss and negotiate with theconsumers on any assessed consumption and fines applicable. Theemphasis should be on speedy rectification of the anomalies rather than anattempt to collect all arrears. Many exercises of this nature have beenthwarted by protracted delays in negotiation with the consumers (whooften have legitimate concerns that need to be equitably resolved).

(ii) This group should also scrutinize all 'dead accounts' and other anomaliesin the billing system and establish a 'clean' and accurate consumer recordfile.

(iii) Coordination of the activities of the two groups on meter inspection andconsumer verification should be attended to by this group.

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Billing System Changes

7.33 A completely new computerized billing and consumer data base system isnecessary for KPLC in order to meet its current needs. The development of a new system maybe 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 developmentmethods.

(ii) An information resource strategy should be developed which specifiesdata 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 bedeveloped within the Company and selected personnel trained in thevarious functions and disciplines involved. The need to invest in high-level recruitment and training combined with a good remunerationpackage cannot be over-stressed as the lack of capable staff will prove tobe very costly in the long run.

(b) Software capabilities

(i) The software should be capable of providing shared data for variousfunctional units including those on billing history, meter inventory, meterand installation service particulars, system data required for distributionplanning (based on geographic coordinates).

(ii) The meter reading entry should be in an on-line environment which willreject incorrect data and flag these for verification.

(iii) On-line query facilities should be available at all Area offices and otherselected customer service centers.

(iv) Updating of consumer information such as reconnections, new accountnumbers to previously discormected installations etc. should becoordinated in the data base so that all relevant data updating takes placesimultaneously.

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(c) Billing/meter reading procedures

(i) The meter readings must be made on computer printed lists obtained fromupdated consumer lists and should not contain the previous readings. Themeter readers should not have access to the previous reading in order toavoid possible estimation of the readings without actually visiting the site.In addition to recording the reading there should be provision for him toreport any irregularities such as incorrect meter number, tampering withmeter or seals.

(ii) Data entry and initial validation may be done at the Area control officesand any irregularity checked by a special team before bill calculations arecommenced. This requires an EDP extension to the Area offices.

(iii) The validated readings may be transferred to the head office billing centerby diskette or electronic transfer if facilities in Kenya allows such use.

(iv) An effective procedure needs to be developed for the exceptions reportingsystem 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 readingindependently of defects reported by the billing system. As an example,sample checking of the readings may be carried out by supervisorypersonnel who will input such data regularly and produce an exceptionsreport if irregularities are found. The meter readers should also beregularly rotated among the different routes and a statistical control madeof 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 ofimplementing a number of improvements in non-technical loss investigations and the consumerbilling system. Actions being taken in this regard include the following:

(a) a permanent task force has been established to investigate bulk supply meteringand billing. The team is based in headquarters and will cover each KPLCoperational area in turn investigating all bulk supply consumers during eachexercise;

(b) retail consumer audits are being carried out by special teams which carry outrandom checks in each area;

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(c) all new large consumer installations are being verified by a senior engineer as apreventive 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 fullyintegrated IT environment combining customer billing, data processing andmanagement information. A new Management Information Systems division hasbeen established to carry out these functions.

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Fig 7.1

ERRORS DETECTED -LV RETAIL SUPPLIES20

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 metererrors in retail consumer installations.

No. of installations tested - 101installations 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%)

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VilI. GENERAL CONSIDERATIONS

Lessons Learned

8.1 The study provides a number of useful lessons for conducting loss reduction anddistribution planning functions for developing country power utilities. High growth rates,expansive nature of the networks and sub-optimal investment in distribution systems over manyyears (in comparison to generation and transmission investment) in many developing countrieshave increased the feasibility of highly economic investment opportunities. In addition, there isa considerable scope for recovery of unbilled consumption. Thus, loss reduction and distributionplanning activities are often found to result in substantial improvement in the utility's financialperformance. Listed below are some important lessons leamt during the execution of the presentstudy 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 ofdistribution systems. Computerized techniques (such as digitizers, specializedplanning software and electronic measuring instrurnents) are now available for thecollation and analysis of this voluminous data base. Although some time wouldbe required initially to train the necessary staff in using the new techniques, oncethis is accomplished the work can be carried out expeditiously and efficiently.

ii. The establishment of the data base involves simple repetitive tasks covering theentirety of an extensive network. Furthermore, the characteristics of distributionsystems change frequently and there is need for regular monitoring and updatingof information. Knowledge of local conditions and familiarity with the terrain isalso of considerable importance in distribution planning work. For these reasonsexternal consultants are not effective substitutes for the utilities' own staff'7 .External support is however useful in establishing the new techniques and intraining activities. Once such a unit is established, the data base should beregularly expanded and updated and periodic planning studies carried out.

Organizational Issues

i. This ESMAP activity demonstrated that building a successful in-housedistribution 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 isbest to have local staff trained in this aspect as well).

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the utility personnel. The proliferation of computerized technology combinedwith the high interest shown by the younger professional cadres augers well forthe successful establishment of such units in developing countries.

ii The studies involve combining the specialized new computerized planningactivities with the field data concerning system and load characteristics. In viewof the day-to-day responsibilities of operational staff, assigning the overallresponsibilities to in-line management often fails to produce the desired results.Thus, the activity is best introduced by establishing a dedicated unit with staffhaving system planning background. This unit however, must establish goodcoordination with operational staff to ensure that the field data and assumptionsregarding future load development is realistic. The best way to establish a strongrelationship is to ensure that operational staff is regularly supplied with the resultsof the planning studies and a consultative process established for mutual benefit.A consolidation of this coordination is often only achieved when the benefits ofthe analysis are used in resolving operational problems'".

iii. Conflicting demands arise with respect to the placement of distribution planningunit/s within the utility organization structure. In keeping with the trend towardsdecentralization of distribution operations, it would be advantageous to establish aplanning unit at each of the main distribution operations divisions. On the otherhand, the need to develop the specialized competence in the techniques used,limited availability of suitable staff as well as funds for the necessary equipmentfavor establishing a central unit, perhaps within the central planning division.This dilemma is best resolved by first introducing a central unit with the necessaryfacilities and subsequently decentralizing the responsibilities in a gradual manner,still retaining the technical competence of the central unit. Good dialogue andexchange of data and study results are necessary between the central unit anddistribution operations. The central unit may also exercise overall responsibility,maintain records of important data and review and approve the work of theregional units.

18 During the studies a number of instances of such support to resolve operational problems arose which helped to institutionalizethe role of the study unit.

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Planning Studies and Development Proposals

1. It is observed that loss reduction investigations are extremely beneficial (even in acountry such as Kenya, with loss levels substantially lower than in manydeveloping countries) and lead to investments with high economic and financialreturns.

ii. Development proposals should be considered from a systemic concept; networkdemands in meeting load growth, improving system reliability and reducinglosses being addressed simultaneously to obtain the best results. Consideration ofonly any single one of the benefit categories (e.g. loss reduction) will, in manyinstances, lead to sub optimum investment.

iii. The sequence of network developments to be considered in a planning exercisevaries for long term and short term options. A convenient sequence of examininglong term developments is to follow the hierarchy of the power flow, investigatingsuitable investments required at each stage. Accordingly, the following sequenceof network improvements is an useful guide in carrying out a long term systemdevelopment 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 increasedtransformers 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 otheroptions considered.

iv. The long term solutions may be generalized as network 'decentralization'strategies; increasing substations and feeders in the case of MV systems andincreasing distribution transformers (thus reducing the lengths of secondaries) inLV systems. Rationalization of feeding arrangements and reconductoring linesections offer secondary opportunities to improve network performance.

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v. When short term solutions are required to redress immediate operating problemsthe sequence of options may generally be tried in reverse (in view of timelimitations) i.e. the first options being reactive compensation and reconductoringof heavily loaded sections for MV systems and reconductoring and rationalizationfor LV systems. Often the two strategies (short and longer term solutions) need tobe combined, the time period required for commissioning of long term solutionsbeing filled in by the short termn options. A particular example being reactivecompensation which can be used within a very short time to relieve poor voltageconditions. When their effects (at a particular location) are diminished withsubsequent network developments they can be moved to other locations offeringmore promising benefits.

vi. The use of network optimizing programs should be applied with due considerationto assumptions used in the software. As observed during the study someassumptions used in optimization techniques of particular programs may notcorrelate with actual field conditions.

vii. Simple spreadsheet based techniques may be effectively used when quickcomputations of losses and voltage conditions are required, particularly whensystem maps etc. are not available for a digitizing exercise.

viii. Low average overall losses in a particular area do not necessarily signify thateconomic investments are not possible. Feeders with high loads situated close tosupply substations tend to mask the high loss feeders when aggregate values areconsidered. Thus either a feeder by feeder analysis or a preliminary screeningexercise is necessary to identify poorly performing feeders.

Non-Technical Loss Reduction

i. Dedicated task forces are the most effective medium of detecting and rectifyingnon-technical losses.

ii. The tasks may be segregated to meter inspections, consumer verification (orcensus) and rectification (including negotiation/agreement on arrears with theconsumer and correction of billing system records). The three operations may becarried out by separate teams but need to be well coordinated.

iii. Exception reports and other triggers in the billing system need to be effectivelydesigned 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 systemchanges in the field is the key to preventing many lapses in billing capture. Most

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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 apart of an overall management information system).

vi. Meter reading procedures should be designed to minimize possible errors andinaccuracies. Some measures to be addressed are: meter readers should not haveaccess to previous readings, an independent control and monitoring facility toascertain the accuracy of readings, validation of readings before entry in thebilling 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 computationof benefits related to system development proposals. Studies carried out previously in Kenyaand elsewhere were used to obtain quantitative values to be used in these computations and noindependent investigations were carried out to verify or validate these figures. The LRMCvalues computed by Acres International in 1991, essentially confirmed by a study carried out byLondon Economics in 1993, were used as the basis of computing loss reduction and additionalcapacity (to meet suppressed demand) benefits. In computing reliability benefits, the value offive times the LRMC of energy was taken as a representative figure, based on experience in othercountries. The figures used are generally of a conservative nature and the proposals aresubstantially 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 relevanteconomic parameters. Particular items that need to be followed up are information onconsumer's willingness to pay (including the value placed on system reliability) and theeconomic 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 costsit 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 itsknowledge of the dynamics of consumer behavior, particularly for tariff setting and loadforecasting 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 andnon-technical-- leading to the determination of specific improvements to reduce these toeconomic levels. It is important however, to remember that improvements identified need to beviewed in the context of a broader set of principles and actions that should encompass KPLC's

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overall system development and efficiency goals. These include price and non-price basedmeasures necessary to improve the efficiency of the power system. Among the principle actionsrelevant 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 --eitheron account of any increase to the overall rate or any structural changes within/between the tariffcategories-- did not fall within the scope of the present study. Tariff setting is however animportant instrument in the management of system load and consequently has an impact onsystem losses. It may also be noted that higher tariffs provide greater incentives for fraud andrequire increased utility vigilance. KPLC already uses a ripple control system for interruptableloads provided at a reduced tariff --an important instrument in load management. Improved useof time of day metering and the application of differential tariff rates can play a useful part ininfluencing the size and shape of the load curve. Similarly, load management strategies such asconservation measures, encouraging the use of efficient appliances and appropriate matching ofenergy sources with end uses (e.g. LPG for cooking and heating loads) also have an importantbearing in altering load patterns. KPLC and the Government of Kenya should improve itsattention 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 onrecommendations made in this report is the improvement of consumer power factor to offset theneed for compensation to be applied on the system. For this reason reactive compensationproposals have been evaluated on the basis of a very short pay-back period. Such short pay backperiods (less than 18 months) enable both strategies --compensation at system level as well asimprovement of individual power factors-- to be effectively used. A large number of consumerswere detected with low power factor during the study and this information can be used to furthera program for power factor improvement. Further, as discussed in the report, once the powerfactor a particular feeder is improved (or alternatively the feeder characteristics are altered byother system developments) the capacitors installed can be shifted to other locations to optimizetheir usage. In view of the high load growth rates in the Kenyan power system and the fact thatonly a small portion of the distribution system has been studied, the 9 MVAr of capacitorsrecommended 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 powerfactor.

8.6 In general, the quantitative and qualitative effect of appropriate tariff setting andload management may be considered as the reduction of system load growth and changing theshape of the load curve, respectively. In view of the high load growth rates presently applicablein Kenya the combined effect of these measures (if and when introduced) is not expected to makean appreciable impact on the overall system load. Thus, load management and tariff settingshould be treated as complementary actions to and not alternatives for the system developmentproposals identified in the report.

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Impact on Sector Reform

8.7 Currently there is an increasing trend among developing country power utilities toincrease the role of private participation in the sector, particularly by encouraging independentpower producers (IPPs). The principal obstacle in attracting IPP participation is the lack ofconfidence in the utility's ability to generate sufficient funds to be able to pay for the powerpurchased. 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 itmore attractive for IPPs. KPLC is also a limited liability company with a substantial portion ofits shares being privately owned. Thus improving the financial position of the company willimprove 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 bearingon the success of any contemplated sector reform program. In addition, improving networkvoltages, system capacity and reliability will also have a major positive impact on the growth inother sectors, particularly industry and tourism.

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KENYA

POWER LOSS REDUCTION STUDY

ANNEXES

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ANNEX A

LIST OF TABLES AND FIGURES

Section Al - Loss Calculation Tables and System Characteristics

Al.1 - Distribution System Power and Energy Flow TablesTable Al.l.l - Nairobi City Power and Energy Flow

A1.1.2 - Coastal Area Power and Energy FlowA1.1.3 - Overall Distribution System Power and Energy Flow

A1.2 Loss Calculation of Feeders Outside Nairobi andCoastal Areas

Table A1.2.1 - Summary ResultsA1.2.2 - Loss Calculation of Meru FeederA1.2.3 - Loss Calculation of Kambura-Kgeni FeederA1.2.4. - Loss Calculation of Kisii FeederA1.2.5 - Loss Calculation of Flouspar FeederA1.2.6 - Loss Calculation of Chemelil FeederA1.2.7 - Loss Calculation of Moi BaracksA1.2.8 - Loss Calculation of Maralal FeederA1.2.9 - Loss Calculation of Narok Feeder

A1.3 - Examples of Daily Load Curves of Feeders and ConsumersFigure A1.3.1 - Lavington Feeder from Karen Substation

A1.3.2 - Parklands Feeder from Jeevanjee SubstationA1.3.3 - 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 CharacteristicsTable A1.4 - Bulk Consumers Detected With Poor Power Factors

A1.5 - Load Characteristics of LV Systems

A1.6 - Present Worth Factors for Economic ComputationsTable 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 FeedersA2.1.2 - Load Characteristics of Nairobi City 66 & 40 kV FeedersA2.1.3 - Load Density of 11 kV Feeder Areas, Nairobi CityA2.2 - Summary of Load Flow Results 11 kV Feeders, Nairobi

A2.3-A2.6 - Results of Economic AnalysisTable A2.3 - Proposal for New Substation at Kiambu

A2.4 - Proposal for New Substation at KileleshwaA2.5.1 - Prr-,osals for Reconductoring and New Feeder additionsA2.5.2 - Proposals for Feeder No. 30, Lower HillA2.5.3 - Proposals for Feeder No. 38, Nairobi SouthA2.6 - Capacitor Installations

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Network DiagramsFigure 2.1.1 - Existing System - Kiambu Area

2.1.2 - Proposed System - Kiambu Area2.2.1 - Existing System - Kileleshwa Area

2.2.2 - Proposed System - Kileleshwa Area2.3.1 - Existing System - Feeders No. 38 and 692.3.2 - Proposed System - Feeders No. 38 and 69

Section A3 - Coastal Area Network Analysis

Table A3.1.1 - Load Characteristics Coastal Area FeedersA3.1.2 - Load Density - Coastal Area 11 kV Feeder

A3.2 - Summary of Load Flow Results - 33 kV FeedersA3.3 - Summary of Load Flow Results - 11 kV Feeders

A3.4-A3.12 - Results of Economic AnalysisTable A3.4 - Proposals New Substations at Diani

A3.5 - Proposals for Tiwi FeederA3.6 - Proposals for New Substation at GaluA3.7 - Proposals for New Substation at BamburiA3.8 - Proposed developments for MalindiA3.9 - Proposals for Improvements to Mazeras and RabaiA3.10 - Proposals for Improvements to Tom Mboya FeederA3.11 - Proposals for Improvements to Bamburi Feeder from NyaliA3.12 - Application of Reactive Compensation

Section A4 - LV System Analysis

Table A4.1 - L.V. System Losses

A4.2 - Transformer Losses for Varying Loadinc LevelsTable A4.2.1A - 25 kVA KPLC Transformer

A4.2.1B - 25 kVA Low Loss TransformerA4.2.2A - 50 kVA KPLC TransformerA4.2.2B - 50 kVA Low Loss TransformerA4.2.3A - 100 kVA Low Loss TransformerA4.2.3B - 100 kVA Low Loss TransformerA4.2.4 - Benefits of a Transformer Replacement Program

Figure A4.2.3A - Energy Losses of KPLC 100 kVA TransformerFigure A4.2.3B - Power Losses of KPLC 100 kVA Transformer

A4.3 - Economic Evaluation of Transformer Losses

Table A4.3A - Economic Evaluation of Transformer LossesA4.3B - 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 StudvFigure A4.4A - L.V. System Optimization - Proposals in Period I

A4.4B - L.V. System Optimization - Proposals in Period IIA4.4C - L.V. System Optimization - Proposals in Period III

Table A1.1.1NAIROBI 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 components2% for overall technical and non-technical losses

Table A1.1.2COASTAL 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 0.80Direct consumers at HT 32 5.2 0.75 0.45 2.2 1.5 4.7MV Lines, 33 kV I 4.77 97.5 4.65 I 3.47 94.5 3.28Consumers at 33 kV 60 9.7 0.60 0.30 3.4 I 2.3 8.9MV Lines, 11 kV I 2.47 90.5 2.24 1.68 82.3 1.38Consumers at 11 kV 162 26.2 0.55 0.30 10.1 6.8 24.0LV transformers I 1.10 90.5 1.00 | 0.70 82.3 0.58LV direct lines I 1.00 89.5 0.90 | 0.50 81.7 0.41LV Direct sales 144 23.3 0.40 0.25 10.3 | 7.0 | 21.3 1LV retail lines | 5.40 81.7 4.41 I 3.60 60.0 2.16 °oLV 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 91.4Technical losses 58 20.5 14.19 | 8.61Non-technical losses 37.2 13.0 I 9.38 | 5.69Total losses 95.0 33.5 I 23.57 | 14.30System 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 A1.1.3DISTRIBUTION 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 0.80Direct consumers at HT 157 0.75 0.45 10.8 1.7 5.2MV Lines I 5.06 97.3 4.92 I 3.45 94.0 3.24MV Consumers 659 0.58 0.28 36.3 5.6 j 21.6LV transformers 1.10 86.8 0.95 I 0.70 69.2 0.48LV direct lines 1.00 85.8 0.86 I 0.50 68.7 0.34LV Direct sales 627 0.32 0.20 44.7 | 7.0 I 20.6LV retail lines I 5.40 78.0 4.21 I 3.60 47.8 1.72LV Retail sales 1403 0.33 1.00 485.3 75.5 | 46.0

Total 2846 566.4 . 88.1 93.4Technical losses 200 75.8 11.95 6.59 1Non-technical losses 134.1 50.1 8.17 4.51 0Total losses 334.1 125.8 20.12 11.10 LSystem Load Factor 0.54

COMBINED TRANSMISSION AND DISTRIBUTION SYSTEM LOSSES

Power Input Losses Energy Input LossesTechnical 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 4.5Distribution system 11.9 94.5 11.3 6.6 95.5 6.3

Total technical loss, transmission and distribution 16.8 10.8Non-technical loss 7.9 4.4Total 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 AreasAfter 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 AREASSUMMARY RESULTS

Feeders Max P.F. Power Main Feeder POWER ENERGYStudied 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 23.4KYENI 86.0 0.85 4,178 51 6.0 5.8Total studied 13,378 26.4 17.9Total demand for Area 36,000Percentage load studied 37.2

WEST KENYA AREA:KISII 205.0 0.87 10,194 175 34.6 25.1Total demand for Area 64,160Percentage load studied 15.9

NORTH RIFT VALLEY AREA:FLOUSPAR 100.9 0.85 4,900 121 8.4 7.2CHEMELIL 70.0 0.90 3,601 17 2.0 1.7MOI BARRACKS 137.0 0.90 7,048 104 12.2 8.7Total studied 15,549 8.6 6.4Total demand for Area 27,000Percentage load studied 57.6

CENTRAL RIFT VALLEY AREA:MARALAL 79.3 0.80 3,626 197 14.0 10.4NAROK 98.0 0.90 5,041 93 5.3 3.1Total studied 8,667 9.0 5.6Total demand for Area 47,600Percentage load studied 18.2

Total of all feeders studied 47,788 19.2 13.7Total demand of all associated Areas 1 74,760Percentage load studied (all feeders) 27.3

N=i1. Feeder power factors have been estimated2. 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 A1.2.94. 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 AREASMT. 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/ Energykm 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 13.790Embori-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 4.800Tee 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 1.923Marania-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 4.454Meru-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 2.903Toff-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 0.61Total Losses (kWI 3288 Loss Load Factor 0.40Power 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/ Energykm 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 2.589KIRITIRI-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 1.132SIAKAGO-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 1.289KARURUMO-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 1T 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 coTOTAL KVA CONNECTED 5205 Ln

Feeder power input (kW) 4178 Load Factor 0.61Total Power Losses(kW) 249 Loss Load Factor 0.59Power 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 Energykm 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 6.55T-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 7.80SOTIK-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 12.06TOFF-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 0.49TOFFTOKIAMOKAMA-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 1.86KISII-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 3.51AWENDO-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 0.29T-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 0.52TOFF- 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 0.35Connected KVA 39405

Feeder power input (kW) 10194 Load Factor 0.69Total Power Losses(kW) 3526 Loss Load Factor 0.50Power 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 Energykm 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 2.60X98-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 0.56X311-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 0.32X99-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 0.22FLOUS.-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 1.30KABAR.-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 1.45X99-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 0.12X311-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 0.11X98-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 3.09TIMB.-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 1.70MAKU.-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 0.17MAKU.-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 0.54TOTAL KVA CONNECTED 20585

Shorten forms for feeder names:Feeder power input (kW) 4900 Load Factor 0.69 Kabar = Karbarnet; Mari = Marigat; fious = Flouspar; Timb = TimboroaTotal Losses IkW) 413 Loss Load Factor 0.59 Maku = Makutano; Chin = Chinese Camp; Lond = LondianiPower 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 Energykm 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 0.69Total Losses (kW) 71 Loss Load Factor 0.59Power 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/ Energykm 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 0.46X364-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 0.17RAI-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 3.94MOI-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 7.20OXT3-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 0.59Total Losses (kW) 859 Loss Load Factor 0.42Power 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 9.63NYAHUR.-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 1.16RUMUR.-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 3.21TOTAL 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 = MaralalPower 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/ Energykm 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 3.03DCK-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 1TOTAL KVA CONNECTED 4065 00

.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

Feeder power input (kW) 5041 Load Factor 0.69Total Losses (kW) 268 Loss Load Factor 0.40

DAILY LOAD VARIATIONKAREN S/S/ LAVINGTON 11 KV FEEDER/ WEEKDAY APRIL1992

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DAILY POWER FACTOR'VARIATIONINDUSTRIAL AREA S/S/ NAIROBI SOUTH NO 2,11 KY FEEDER/ WEEKDAY FEBRUARY,19920.98 -

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- 93 - Table Al1.4BULK 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 0.732 ALPHA MOTORS 194210330 0.32 44 SUPER FOAM LTD. 198090450 0.733 CHODA FABRICATORS 199520800 0.36 45 LYONS AND CO LTD 199502111 0.744 AUTOANXILLIARIES 194210290 0.40 46 COCA COLA BOTTLING 199504600 0.745 NATIONAL FOOD 194210550 0.41 47 LYONS & CO LTD 199502111 0.746 VIRANI CARRY POWDER 160014070 0.41 48 KENYA TIMES LTD 199504270 0.747 ENGLISH PRESS 199507380 0.46 49 CUSSIONS AND CO. 199501610 0.748 JADVA KARSAN & BROS 199507090 0.48 50 PREMIER FOOD INDUSTRIES 153460021 0.759 to be identified 153881160 0.49 51 FRIGO. KEN 199502170 0.76

10 MOORE AGENCIES 153600400 0.51 52 EAST A. SPECTRE 199530850 0.7811 PROPWA LTD. 194207040 0.53 53 DOTHIA PACKAGING 199506320 0.7812 BIDCO INDUSTRIES 194210661 0.55 54 E.A CABLES 199505950 0.7913 WARREN ENGINEERING 194208970 0.56 55 W.E. TILLEY MUTHAIGA 199501631 0.7914 HENKEL CHEMICALS 198015002 0.56 56 OMEGA INVESTMENTS 199501881 0.7915 WARREN CONCRETE 194209016 0.57 57 to be identified m/n353294 0.8016 BELFAST MILL. 199504640 0.57 58 PLASTICS ANDRUBBER IND. 199505520 0.8117 CAR AND GENERAL 199504876 0.57 59 HIGHLAND CANNERS 194209340 0.8118 CITY RADIATORS 199502830 0.57 60 D.C.A. 194210920 0.8219 VACU LUG TYRES 199503050 0.58 61 A.M.R.E.F. 194206510 0.8320 WARREN CONCRETE 194209016 0.58 62 NAIROBI CITY CONCIL 194209650 0.8321 MOBILIA LTD. 199540210 0.59 63 K.A.R.I. 199507950 0.8322 MANSION HART LTD 153427001 0.59 64 K. M. C. 194210690 0.8323 CITY RADIATORS 199506330 0.60 65 EAGLE FISHERIES 153684450 0.8324 STATIONARY EXPRESS 194208531 0.61 66 BRUCE LTD 194210350 0.8425 LACHMANDAS 199506910 0.61 67 NCC WATER SEWERAGE 194209550 0.8426 MEDICAL MANUF. 199509570 0.62 68 INDUSTRIAL PLANT E. A. 199506050 0.8427 CARBACID 1961 LTD 161001500 0.63 69 TOWEL INDUSTRIES LTD 199550111 0.8428 PREMIER FOOD IND. LTD 153460005 0.64 70 RECKITT AND COLMAN 160097700 0.8429 CAR AND GENERAL 199506250 0.64 71 INTERPRODUCTS (K) LTD. 199502160 0.8530 HIGHLAND CANNERS LTD. 194209340 0.64 72 BIDS MATCH 199504990 0.8531 KENS METAL 194210270 0.66 73 PLASTIC PRODUCTS 199506546 0.8532 PENESAR CONSTRUCTION 160308600 0.66 74 VACU LUG TYRES 199501780 0.8533 KENS METAL LTD 160420610 0.66 75 K. M. C. 199507210 0.8634 W.E.TELLY MUTHAIGA 199501631 0.67 76 MALINDI DISHES 178664650 0.8735 R.B. SHAH 199502336 0.68 77 ARROW INVESTMENTS 194201860 0.8736 K.C.C. LTD 199504850 0.68 78 DOTHIA PACKAGING 199506301 0.8737 TAWS LTD. 199504480 0.69 79 to be identified m/n467856 0.8738 SPORTS VIEW HOTEL 194208960 0.70 80 OTIENDE POLICE 194206710 0.8739 E.A.SPECTRE 194210340 0.71 81 U.S. INT. UNIVERSITY 194209190 0.8840 NAIROBI CITY COUNCIL 199506660 0.71 82 E.A.POST AND TEL. 194206080 0.8941 W.E. TILLY MUTHAIGA 199501631 0.72 83 RAMJI H. DEVAJI 199505920 0.8942 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 0.742 COACH WORKS 280440000 0.45 24 MOMBASA GRAIN MILLERS 299525032 0.743 BAYUSUF 299533100 0.46 25 MARINE PRODUCTS 299410800 0.774 STEEL AFRICA 299530930 0.61 26 KAYDEE CONSTRUCTION 299416300 0.775 SGS(K)LTD. 299518981 0.62 27 FISHERMANNS INN 299420200 0.776 J.M VIRJI 299524000 0.62 28 K.B.C 299403651 0.787 AFROMEAT 299409980 0.63 29 POLYCANS 299518900 0.798 TEXTILES AND PLASTICS 299405630 0.64 30 DIAMOND PERFUMERY WORK 299524680 0.799 KAYDEE CONSTRUCTION 299533650 0.64 31 RUBI PLASTICS 299525980 0.79

10 MVITA BOTTLERS 299502202 0.65 32 D ENG.COAST 299403801 0.8011 MIRITINI BRICKS 299534251 0.65 33 FREIGHT FOWARDERS 299407050 0.8112 CONSOLIDATED 299410550 0.66 34 to be identified 299535501 0.8213 CORRUGATED 299532051 0.67 35 STAR DUST 299433950 0.8514 KENYA COLD STORAGE 299510550 0.68 36 ELITE ENTERPRISES 299525580 0.8515 LINT M.BOARD 299417001 0.71 37 SIGNON FREIGHT 299403400 0.8616 UMOJA RUBBER PRODUCTS 299537200 0.71 38 to be identified 299536101 0.8617 IRON INTERNATIONAL 299532100 0.72 39 CAR AND GENERAL 299406301 0.8718 ATTA LTD. 299525012 0.73 40 COASTAL BOTTLERS 299535501 0.8719 BIRCH INVESTMENTS 299534011 0.73 41 KENYA SUITCASE MAN. 299523150 0.8820 PAN AFRICA INS. 299403870 0.74 42 WANANCI MARINE P. 299536502 0.8821 M.I.T. CENTRE 299430050 0.74 43 PANTY HOSE MAN. 299519100 0.8922 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 0.860535 0535 22.4.92 Com 91 9 0.60 0.26 82 315 820 3377 0.940587 0587 18.9.92 Res/Com 91 6 0.61 0.24 105 200 1,082 3523 0.960711 0711 2.7.92 Res 25 1 0.72 0.40 151 300 5,808 4641 0.970721 0721 1.9.92 Res 34 11 0.66 0.18 116 315 2,578 3963 0.940741 0741 7.5.92 Res/Com 123 1 0.37 0.16 126 315 1,016 1477 0.960744 0744 26.8.92 ReslCom 212 7 0.50 0.25 122 300 557 2455 0.960754 0754 22.2.92 Res/Com 454 1 0.48 0.29 130 315 286 2279 0.960757 0757 13.6.92 Res 163 0 0.48 0.13 108 150 663 2325 0.990762 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 xo12759 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 0.912346 2346 18.9.92 Res 127 0 0.56 0.34 97 200 764 2979 0.972723 2723 20.2.92 Res 229 22 0.51 0.17 456 630 1,817 2529 0.972724 2724 1.9.92 Res 192 0 0.49 0.24 98 315 510 2359 0.972768 2768 2.8.92 Res 113 3 0.58 0.26 76 315 655 3144 0.713414 3414 18.9.92 Res/Com 29 2 0.51 0.15 51 315 1,645 2551 0.894080 4080 4.4.92 Res 497 0 0.43 0.15 228 315 459 1938 0.964511 4511 26.8.92 Res/Com 113 3 0.57 0.17 82 150 707 3084 0.794610 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# STATEImisis&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 0.22P.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.t4CumlltatPWd 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 Nt0rAEnrestud 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 0.22P.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 o0.4CUmMO 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 PATElnef4&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 0.22P.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.t8Curnb116 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 INTEFESTRAtEItntownd 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 1161Cu,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 PATEtIrwamd 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 0.20P.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 reliabilitybenefits of the current year to the present worth of benefitsover a period of analysis -- for varying load growth rates anddiscount 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 bett1Th, 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 RATEInuosa.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 4.76Dheount 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 0.22P.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 1.04Cumilitlv. 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? EsTPATEInc,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 0.22P.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 1.90Cumiltailv 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 StPATEtncoased 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 0.22P.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 3.43Curnlatlov 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 NTEflESTPATEInclo.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 28.21Discount 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 .DP.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 ONCumilsOvs 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 IInceagsed 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 4.78Discount 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 0.29P.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 1.30CumiisIlo. 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 lossreduction benefits of the current year to the present worth ofbenefits over a period of analysis --for varying load growthrates 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 factotsThe iabis provides mukipfying fdacttr thtt convec the pl0tset year bonefha Io that of the dlcour4od benelke ol a petIod of ftruIr years11 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 0.74SR-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 0.73SR-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 0.79SR-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 0.69SR-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 0.94SR-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 0.63SR-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 0.82SR-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 SUBSTATIONSR-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 0.65SR-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 0.73SR-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 0.69SR-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 0.76SR-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 0.66SR-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 0.73SR-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 0.73SR-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 SUBSTATIONSR-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 1.05SR-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 0.83SR-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 0.81SR-26' Kahawa 208.3 107.9 3969 1905 2560 0.48 0.65 0.46 3768 0.98 0.96 0.98 0.92 0.72SR-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 0.97SR-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 0.73SR-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 0.68SR-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 SUBSTATIONSR-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 0.75SR-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 1.74SR-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 0.70SR-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 0.70SR-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 0.73SR-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 0.64SR-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 SUBSTATIONSR-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/LFNumber 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 0.74SR-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 0.64SR-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 0.73SR-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 0.87SR-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 0.76SR-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 0.72SR-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 SUBSTATIONSR-52 Allsopps 254.8 134.1 4739 2276 3494 0.48 0.74 0.62 4959 0.94 0.88 0.94 0.86 0.84SR-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 0.73SR-54 Kayole 99.3 31.8 1841 442 1095 0.24 0.59 0.44 3502 0.96 0.77 0.98 0.59 0.74SR-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 0.66SR-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 0.94SR-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 SUBSTATIONSR-59 Langata 159.3 63.8 2836 1068 1825 0.38 0.64 0.45 3877 0.97 0.97 0.97 0.89 0.69SR-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 0.70SR-61 Hurlingham 307.3 71.2 5763 1216 2621 0.21 0.45 0.24 2087 0.97 0.91 0.97 0.88 0.53SR-62 Kiserian 119.6 40.2 2109 656 992 0.31 0.47 0.28 2075 0.97 0.87 0.97 0.84 0.60SR-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 SUBSTATIONSR-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 00SR-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 ISR-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 0.68SR-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 0.92SR-67 Rollmill 170.3 18.6 1857 17 408 0.01 0.22 0.23 675 0.95 0.03 0.99 -0.98 1.02SR-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 0.68SR-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 SUBSTATIONSR-70 Athi 274.5 143.9 4673 2389 3288 0.51 0.70 0.54 4477 0.87 0.88 0.90 0.84 0.77SR-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 1.28SR-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 3.56SR-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 SUBSTATIONSR-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 0.73SR-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 0.57Sf-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 0.67SR-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 0.76SR-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 0.60SR-79 Intercontinental 63.3 20.9 930 395 680 0.42 0.73 0.53 4937 0.70 0.67 0.81 0.65 0.72SR-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 1.44SR-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 LOADNAME 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 2530.2MUTHAIGA 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 25.001 189.1KAYOLE 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 LOADNAME 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 66.3AIRPORT II 73 785 34 1 8.1 102.9 0.4 102.5 Single consumerK.P.C 72 303 70 1 0.2 100.7 FEEDER SUPPLIES 0 Single consumerAIRPORT 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 consumerNAIROBI SOUTH 2 69 3666 91 3 27.1 100 1.7 98.3 0.286 12818.2NAIROBI SOUTH 1 68 1219 79 3 3.4 101.4 0.5 100.9 0.722 1688.4DARA II 64 818 93 4 1.7 101.8 0.4 101.4 0.449 1821.8DARA I 63 2761 86 3 21.6 100.8 1.6 99.2 0.145 19041.4E. A. OXYGEN 66 1555 93 3 3.9 99.5 0.3 99.2 Single consumerKAMPALA 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 34.9LAVINGTON 61 5688 97 5 404.4 100.2 10.5 89.7 9.016 630.9NGONG-VOK 60 1445 92 4 12.3 100.9 1.5 99.4 47.652 30.3NGONG RD. 82 5517 98 4 305.3 99.5 8.3 91.2 15.785 349.5LANGATA 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 4432.3NGARA(GWASI) 51 4749 97 5 57.3 100.1 2.5 97.6 3.203 1482.7DEVELOPMENT HSE 50 2112 91 1 5.1 99.4 0.4 99.0 City centreCAPITOL 11 46 4997 83 3 50.1 101 1.1 99.9 City centreCAPITOL I 45 5060 90 3 40.8 100.8 0.9 99.9 City centreDOONHOLM 41 3923 95 3 76.3 98.7 2.4 96.3 2.597 1510.6PARKLANDS 42 2931 87 6 171.9 103.7 9.3 94.4 14.484 202.4CITY SQUARE 43 1516 79 3 4.8 103.7 0.3 103.4 City centreTEMPLE RD. 44 2490 92 3 6 97.6 0.3 97.3 City centreNEW 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 centreUNIVERSITY 2 78 817 74 3 0.5 100.2 0.06 100.1 City centreG.P.O 77 3021 92 3 0.6 99.7 0.7 99.7 City centreINTERCONTINENTA 79 819 69 5 0.2 98.2 0.2 98.2 City centreDARA NO. 2 81 3737 90 4 2.5 100.2 100.2 Single consumerHILL 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 A2.2SUMMARY OF LOAD FLOW RESULTS -11 KV FEEDERS, NAIROBI

PRESENT SYSTEM LOADS SYSTEM LOADS IN 1OYrs. SYSTEM LOADS IN 15Yrs. Load ENERGY LOSSES

growth IN PERCENTFEEDER 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 0.52 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 1.34 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 3.26 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 1.87 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 6.38 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 0.310 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 1.711 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 3.212 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 3.013 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 1.614 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 0.2 116 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 1.617 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 H18 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 5.021 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 0.023 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 0.424 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 0.525 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 2.326 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 2.927 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 5.328 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 5.129 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 7.630 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 6.831 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 0.633 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 1.734 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 2.236 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 2.038 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 PERCENTFEEDER 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 4.641 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 3.442 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 42.744 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 1.145 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 0.351 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 0.952 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 6.455 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 11.756 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 1058 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 0.960 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 1.961 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 2.465 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 0.467 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 0.368 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 A2.3PROPOSALS 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 1142Energy, MWh/yr. 3323 4856

Load factor (combined) 0.676 0.717Loss factor (combined) 0.446 0.473Load growth rate (p.a.), pu 0.06 0.06Existing system load, MW 10.2 14.6Maximum system capacity, MW 16.0 17.0Capacity shortfall in: 2000 1996

PROPOSED SYSTEM 66 kV line 0.1 5SCA, 23 MVA substationlocation 2 location 2

Losses in new systemPeak losses. kW 200 313Energy, MWh/yr. 799 1188

Loss savings at present load:kW at peak 635 829MWh/year 2524 3668

Outage savings based on:saved outages/yr. 12 12hrs./outage 3 3

Analysis period (Years): 10 15 10 1 5Investment costs:

Investment cost 1.688 1.688 2.236 2.236PW of Residual value 1.125 0.844 1.491 1.118Net Investment 0.563 0.844 0.745 1.118

Value of benefits:Loss reduction benefits 3.8 5.8 5.1 7.8Reliability benefits 1.5 2.6 2.1 3.7Additional load supplied 0.7 4.5 8.2 17.9Total benefits 5.9 12.8 15.4 29.4

Benefit/cost ratiosLoss reduction only 6.7 6.8 6.8 7.0Loss red. + reliability 9.3 9.9 9.6 10.3All three benefits 10.6 15.2 20.6 26.3

Net present valuesLoss reduction only 3.2 4.9 4.3 6.7Loss red. + reliability 4.7 7.5 6.4 10.4All three benefits 5.4 12.0 14.6 28.3

Note:All investments and benefits in US$ millionsEconomic parameters used in computations:

217 $/kW - value of peak power losses0.068 $/kWh - value of energy losses0.076 S/kWh - value of additional load (new connections)

0.38 $/kWh - value of outage savings0.75 p.u. load at (avoided) outage

0.1 p.u. discount factor

33 kV Feeders altered:Location 1 - Kiambu and RidgewaysLocation 2 Kiambu, Ridgeways, UNEP and Muthaiga

- 105 -

ECONOMIC ANALYSIS: Table A2.4PROPOSALS FOR NEW SUBSTATION AT KILELESHWA

EXISTING SYSTEM:

Existing system loss:Peak losses, kW 1494Energy, MWh/yr. 4815

Load factor (combined) 0.717Loss factor (combined) 0.473Load growth rate lp.a.), pu 0.06Existing system load, MW 14.6Maximum system capacity, MW 17.0Capacity shortfall in:

PROPOSED SYSTEM 66/11 kV, 23 MVA substationand 11 kV feeder rearrangement

Losses in new systemPeak losses, kW 497Energy, MWh/yr. 1377

Loss savings at present load:kW at peak 997MWh/year 3437

Outage savings based on:saved outageslyr. 1 2hrs./outage 3

Analysis period (Years): 10 15Investment costs:

Investment cost 2.267 2.267PW of Residual value 1.511 1.133Net Investment 0.756 1.133

Value of benefits:Loss reduction benefits 4.4 6.2Reliability benefits 3.8 6.4Additional load supplied 4.9 12.7Total benefits 13.1 25.2

Benefit/cost ratiosLoss reduction only 5.8 5.4Loss red. + reliability 10.9 11.0All three benefits 17.3 22.2

Net present valuesLoss reduction only 3.6 5.0Loss red. + reliability 7.5 11 .4All three benefits 12.4 24.4

Note:All investments and benefits in US$ millionsEconomic parameters used in computations:

217 $/kW - value of peak power losses0.068 $/kWh - value of energy losses0.076 $/kWh - value of additional load (new connections)

0.38 $/kWh - value of outage savings0.75 p.u. load at (avoided) outage0.1 p.u. discount factor

Table A2.5.1

Key Results of Proposals forReconductoring and New Feeder additions - Nairobi City

Valuation of BenefitsFeeder Loss Savings

No. Name Reconductored Investment Present Present Power Feeder Load Loss Peak Feeder Present Peak EnergY Present Benefit NetSections Cost Feeder Power Loss Load Factor Factor Respon- Power Worth Worth to Present

Load Loss after Growth sibility Factor Factor Loss BenefitsImprove- 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 454835523, 524 (all to300 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 63940to 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 338719584, 585 (all from0.100 CU to 300AACI

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 308723from 0.15 SCA to300 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 455423Nairobi from 0.075 CU toWest 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 508749804, 805 (all from C0.075 SCA to 300AAC)

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 7504250.100 SAC to 300AAC, 1.6 km);362A, 362B,362C, 362 (trom0.100 CU to 300AAC, 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 164412140C, 140, 141A(all from 0.100 CUto 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 958640251C, 251D, 251,252A, 2528,252C, 252D,252E (from 0.100CU to 300 AAC,2.3 km); 250(from 150mm UGto 300mm UG,0.2 km)

Table A2.5.1

Key Results of Proposals forReconductoring and New Feeder additions - Nairobi City

Valuation of BenefitsFeeder Loss Savings

No. Name Reconductored Investment Present Present Power Feeder Load Loss Peak Feeder Present Peak Energy Present Benefit NetSections Cost Feeder Power Loss Load Factor Factor Respon- Power Worth Worth to Present

Load Loss after Growth sibility Factor Factor Loss BenefitsImprove- 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 397173ItOC, 180, 181A.1818, 181C, 181(all from 0.100 CUto 300 AAC, 2.9km)

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 741464101C, iOIA,102A, 102 (allfrom 0.100 SCAto 300 AAC, 4.4ktn)

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 600318121, 122 (from0.100 CU to 300AAC, 0.8 kmr;122A, 122B (from 1-0.15 SCA to 300AAC. 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 251360SCA to 300 AAC,0.9 km); 1023(from 0.100 SCAto 300 AAC, 1.2km); 1021 (from0.075 SCA to0.150 SCA, 1.9km)

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 SCAto 300 AAC, 2.2km); 983 (from0.075 SCA to 300AAC, 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 421668Engineering from 0.100 SCA

to 300 AACI

Table A2.5.1

Key Results of Proposals forReconductoring and New Feeder additions - Nairobi City

Valuation of BenefitsFeeder Loss Savings

No. Name Reconductored Investment Present Present Power Feeder Load Loss Peak Feeder Present Peak Energy Present Benenit NetSections Cost Feeder Power Loss Load Factor Factor Respon- Power Worth Worth to Present

Load Loss after Growth sibility Factor Factor Loss BenefitsImprove- Ratio

mentIkWI 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 251000from 0.100 CU to300 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 909000feeder 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 589000South B 943 (to 300

AAC; 950, 951,944 Ito 0.15SCA)

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 1616000South B 943 (to 300

AACI; 950, 951,944 to 0.15SCA); + newfeeder section

Note:

The following economic parameters have been used in the above computations:

Period of analysis - 15 yearsInterest rate - 10%Cost of power losses - $217/kwCost of energy losses - $0.068/kWhFor 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 andselected sections partial reconductoring

Existing system loss:Peak losses, kW 76 76Energy, MWh/yr. 394 394

Load factor 0.740 0.740Loss factor 0.590 0.590Load growth rate (p.a.), pu 0.02 0.02Existing system load, MW 3.345 3.345Maximum system capacity, MW 5.0 5.0Capacity shortfall in: Not in study period

PROPOSED SYSTEM

Losses in new systemPeak losses, kW 32.1 18.5Energy, MWh/yr. 166 96

Loss savings at present load:kW at peak 44.1 57.7MWh/year 228 298

Outage savings based on:saved outages/yr. 0 12hrs./outage 3 3

Analysis period (Years): 10 15 10 15Investment costs:

Investment cost 0.022 0.022 0.047 0.047PW of Residual value 0.007 0.000 0.016 0.000Net Investment 0.014 0.022 0.032 0.047

Value of benefits:Loss reduction benefits 0.212 0.273 0.273 0.351Reliability benefits 0.000 0.000 0.383 0.605Total benefits 0.212 0.273 0.656 0.956

Benefit/cost ratiosLoss reduction only 14.7 12.6 8.6 7.4Loss red. + reliability 14.7 12.6 20.8 20.2

Net present valuesLoss reduction only 0.198 0.251 0.241 0.304Loss 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 0.026Incremental benefits 0.444 0.683Benefit/cost ratio 26.0 26.7Net present value on incremental investment 0.427 0.658

Note:All investments and benefits in US$ millionsEconomic parameters used in computations:

217 $/kW - value of peak power losses0.068 $/kWh - value of energy losses0.076 $/kWh - value of additional load (new connections)0.38 $/kWh - value of outage savings0.75 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 117Energy, MWh/yr. 466 466

Load factor 0.623 0.623Loss factor 0.456 0.456Load growth rate ip.a.), pu 0.04 0.04Existing system load, MW 4840 4840Maximum system capacity, MW 5.0 5.0Capacity shortfall in: Not in study period

PROPOSED SYSTEM Reconductor New feeder andselected sections partial reconductoring

Losses in new systemPeak losses, kW 25.9 - 22.2Energy, MWh/yr. 103 89

Loss savings at present load:kW at peak 90.7 94.4MWh/year 362 377

Outage savings based on:saved outages/yr. 0 12hrs./outage 3 3

Analysis period (Years): 10 15 10 15Investment costs:

Investment cost 0.037 0.037 0.071 0.071PW of Residual value 0.012 0.000 0.024 0.000Net Investment 0.025 0.037 0.047 0.071

Value of benefits:Loss reduction benefits 0.449 0.627 0.467 0.652Reliability benefits 0.000 0.000 0.620 1.034Total benefits 0.449 0.627 1.087 1.686

Benefit/cost ratiosLoss reduction only 18.0 16.8 9.9 9.2Loss red. + reliability 18.0 16.8 23.1 23.9

Net present valuesLoss reduction only 0.424 0.589 0.420 0.582Loss 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 0.033Incremental benefits 0.638 1.060Benefit/cost ratio 28.8 31.9Net present value on incremental investment 0.616 1.026

Note:All investments and benefits in US$ millionsEconomic parameters used in computations:

217 $/kW - value of peak power losses0.068 S/kWh - value of energy losses0.076 S/kWh - value of additional load (new connections)

0.38 S/kWh - value of outage savings0.75 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

PaybackP.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 2.12 Industr. l 0.84 0.94 1,400 14,350 13.4 4,903 29.3 2.9 4.43 Mogadishu 0.87 0.94 750 7,150 17.6 6,440 38.5 1.1 11.74 Doonholm Il 0.86 0.91 750 7,150 14.1 5,159 30.9 1.4 * 9.45 Muthaiga 0.90 0.94 500 6,350 4.8 1,756 10.5 3.6 3.66 Brewery II 0.90 0.96 900 8,000 23.9 8,745 52.3 0.9 14.27 Lower hill 0.84 0.92 800 11,850 15.6 5,708 34.2 2.1 * 6.38 Industrial 0.85 0.88 300 5,500 2.2 805 4.8 6.8 1.99 City square 0.79 0.90 400 6,000 1.2 439 2.6 13.7 1.010 Capitol II 0.83 0.89 750 7,150 7.0 2,561 15.3 2.8 4.711 Lower kab. 0.87 0.91 300 5,500 18.2 6,660 39.9 0.8 ' 15.712 Allsopps 0.93 0.97 750 7,150 7.1 2,598 15.5 2.8 4.713 Kayole 0.76 0.84 300 5,500 11.4 4,171 25.0 1.3 9.914 Dara I 0.86 0.91 300 5,500 2.3 842 5.0 6.5 2.015 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 unityif a 10 year analysis period is considered on the basis of retaining existingsystem in present configuaration (multiplying factor used for present worthcomputation being 13.0), only those with a payback period less than 3 years isselected 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 <RKiombu Feeder

\ ~~~~~RedhWi Feeder >tO P N0

\ \ KITISURU A/ RURAKA

> ~~~~~~~~~~~~66/1lKV 66/11KV/ ~~~~~~~~~~~~~2XIOMVA J \ 2X23MVA

0 1 J 51<m ~~~~~~~~~~Unep Feeder--"'t Ridgeways Feeder=L 2 1 4 1 < aAIRGREAK SWTCH

YOPE SWITCH NUMBEROPEN4 STATUS

PROPOSED SYSTEM - KIAMBU AREA FIG. A2.1.2

j , . , w~~~~~~~~~~~X5MVA-

,Jedr F-eeder 2

.LIMUR \\S 6 r tsFeeder I

0 6/1 3 5km

\\%2 4 Feeder! ( open at SI,52 aFeeder

Y23 Si3 1N6

OPeN Setos S d Sec

PEN~~~~~~~~~~

O 1 3 5km \| y1 ' 2 1 41 :\ .', .s2 , ,

Proposed new constci[on mO V iI g ; S S8 < Federl ( open at St,S2 ond Sl RAKA an . ; A;A SWITC1

New Seclitxns: Secl and Sec3 66/1K\/ x3VA

Feeder2 ( open at S4, S5, and Y8012 )UNEP Feeder-------g - >

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 WEST66/11KV

KAREN sT' LAVINGION FEEDER (61) FEEDER (34)

O 1 2 3km a AIRBREAK SWITCH

YSi SWTCH NUMBEROPEN 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 SVMICHY5I1 SWITCH NUMBEROPEN NORMAL SlATUS

EXISTING SYSEM - FEEDERS NO. 38 & 69 FIG. 2.3.1

-NAIROBI WEST 66/1 I<V

INDUSTRIAL 66/11KVS/STN

& 953/<, oNAIROBI SOUTH 2(FEEDER NO. 69)

941 NAIROBI SOUTH B ,,-\.\ < < ~~~~~(FEEDER NO. 38)

1> X "' .-..- \ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-

Q AIRD1REAK SWJITCII (OPEN)

AIRBREAK SWITCFl (CLOSED)

PROPOSED SYSEM - FEEDERS NO, 38 & 69 FIG. 2.3.2

NAIROBI SOUTH BNAIROBI WEST 66/1 1KV (FEEDER NO. 38)

S/STN

NAIROBI SOUTH 2R/ / / ~~~~~~~(NEW FEEDER)

NAIROBI SOUTH 2SEC-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 3.1.1LOAD 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 densityno: Amps kW meter sq. kW/km.sq.

KIPEVU SUBSTATION1. CHANGAMWE 125.3 2229 8,815,582 2532. ISLAND NO 1 189.2 3101 bus bar3. ISLAND NO 2 179.4 3024 bus bar4. PORT 154.7 1959 Single consumer

RIBE SUBSTATION5. RIBE FDR 6.0 105 6,373,629 16

SHANZU SUBSTATION6. SHIMOLA TEWA 145.0 2542 10,039,475 2537. OCEANIC 227.0 4325 3,908,252 1107

NYALI SUBSTATION8. BAMBURI 11 KV 184.6 3040 14,121,897 2159. NYALI LOCAL 207.8 3665 4,200,336 87310. KISAUNI 77.5 1232 3,863,694 319

MAKANDE SUBSTATION11. TOMMBOYA 309.9 4613 3,986,661 115712. MWANGEKA 203.6 3411 677,779 503313. PORT 155.3 2738 1,453,441 188414. SHIMANZI 130.7 2215 168,464 13148

MBARAKI SUBSTATION15. DIGO 323.3 5313 1,265,290 419916. NYALI 1 198.9 3410 1,995,527 170917. NYALI 2 210.4 3680 . bus bar18. SHIMANZI 236.3 , 3727 580,435 642119. MAKUPA 182.0 3060 1,090,061 280721. LIKONI 2 54.1 1035 1,629,327 63520. LIKONI 1 Open22. KENYA GLASS Open

LIKONI SUBSTATION23. MTONGWE 79.0 1320 4,951,082 26724. MBARAKI 1 139.3 2535 1,530,529 165626. SHELLY BEACH 13.8 290 8,845,498 3325. MBARAKI NO 2-OPEN(SEE MBARAKI S/S)

DIANI SUBSTATION27. KWALE 19.0 322 11,776,654 2728. DIANI NO 1 209.0 3744 9,626,973 38929. DIANI NO 2 101.0 1712 2,573,318 66530. TIWI 101.0 1751 25,481,448 69

K.P.R SUBSTATION31. CHANGAMWE 93.5 1630 1,313,827 124132. PORTREITZ 112.3 2212 35,705,002 6233. KENYA PIPELINE 83.2 1570 Single consumer

MIRITINI SUBSTATION34. AIRPORT 51.0 894 581,003 153935. MAZERAS 136.0 2332 18,200,406 12836. ENDI TEXTILES 32.0 875 1,128,772 775

Table A3.2SUMMARY OF LOAD FLOW RESULTS - 33 KV FEEDERS, COASTAL AREA

PRESENT SYSTEM LOADS SYSTEM LOADS IN lOYrs. SYSTEM LOADS IN 15 Yrs. Load Connld FDR. FACTORSgrowth 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 LLFNO. (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 10.82 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 0.14 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 1.45 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 33.66 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 1.38 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 o9 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 8.111 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 0.412 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 0.413 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 4.80Average 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. FACTORSgrowth 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 LLFNO (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 3.02 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 1.03 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 0.95 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 0.26 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 1.07 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 2.48 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 28.19 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 0.411 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 1.112 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 1.613 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 1.414 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 0.615 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 2.416 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 1.517 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 2.018 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 1.221 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 2.822 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 1.823 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 0.324 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 7.225 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 22.626 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 3.927 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 5.128 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 0.629 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 2.430 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 0.431 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 0.132 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 13.033 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 3.97Average power factor for system: 0.89Average 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 A3.4PROPOSALS 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 653Energy, MWh/yr. 3066

Load factor (combined) 0.715Loss factor (combined) 0.536Load growth rate (p.a.), pu 0.05Existing system load, MW 8.3Maximum system capacity, MW 10.0Capacity shortfall in: 1997

PROPOSED SYSTEM SC 0.15 SC 0.15on wood poles on steel poles

Losses in new systemPeak losses, kW 47 47Energy, MWh/yr. 223 223

Loss savings at present load:kW at peak 606 606MWh/year 2843 2843

Outage savings based on:saved outages/yr. 12 1 2hrs./outage 3 3

Analysis period (Years): 10 15 10 1 5Investment costs:

Investment cost 3.500 3.500 6.038 6.038PW of Residual value 2.333 1.750 4.025 3.019Net Investment 1.167 1.750 2.013 3.019

Value of benefits:Loss reduction benefits 3.289 4.961 3.289 4.961Reliability benefits 1.123 1.927 1.123 1.927Additional load supplied 2.616 6.457 2.616 6.457Total benefits 7.028 13.345 7.028 13.345

Benefit/cost ratiosLoss reduction only 2.82 2.83 1.63 1.64Loss red. + reliability 3.78 3.94 2.19 2.28All three benefits 6.02 7.63 3.49 4.42

Net present valuesLoss reduction only 2.122 3.211 1.276 1.942Loss red. + reliability 3.245 5.138 2.399 3.869All three benefits 5.861 11.595 5.015 10.326

Note:All investments and benefits in US$ millionsEconomic parameters used in computations:

217 S/kW - value of peak power losses0.068 $/kWh - value of energy losses0.076 $/kWh -value of additional load (new connections)0.38 $/kWh - value of outage savings0.75 p.u. load at (avoided) outage0.1 p.u. discount rate

- 123 -

ECONOMIC ANALYSIS: Table A3.5PROPOSALS FOR IMPROVEMENTS TO TIWI FEEDER

EXISTING SYSTEM: 11 kV Tiwi feeder from Diani Substation

Existing system loss:Peak losses, kW 60Energy, MWh/yr. 317

Load factor (combined) 0.777Loss factor (combined) 0.603Load growth rate (p.a.), pu 0.04Existing system load, MW 1.8Maximum system capacity, MW no restriction

PROPOSED SYSTEM New 33/11 kV New 11 kV ReconductorSub Station Feeder selected sections

Losses in new systemPeak losses, kW 14 29 26Energy, MWh/yr. 75 151 136

Loss savings at present load:kW at peak 46 31 34MWh/year 242 165 181

Outage savings based on:saved outages/yr. 12 5 0hrs./outage 3 3 0

Analysis period (Years): 10 15 10 15 10 15Investment costs:

Investment cost 0.265 0.265 0.080 0.080 0.141 0.141PW of Residual value 0.132 0.066 0.027 0.000 0.047 0.000Net 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 0.259Reliability benefits 0.224 0.374 0.093 0.156 0.000 0.000Additional load supplied 0.000 0.000 0.000 0.000 0.000 0.000Total benefits 0.465 0.721 0.258 0.393 0.180 0.259

Benefit/cost ratiosLoss reduction only 1.82 1.75 3.07 2.95 1.92 1.84Loss red. + reliability 3.52 3.64 4.81 4.88 1.92 1.84

Net present valuesLossreductiononly 0.109 0.149 0.111 0.157 0.086 0.118Loss red. + reliability 0.333 0.523 0.204 0.312 0.086 0.118

Note:All investments and benefits in US$ millionsEconomic parameters used in computations:

217 $/kW - value of peak power losses0.068 $/kWh - value of energy losses0.076 $/kWh - value of additional load (new connections)

0.38 $/kWh - value of outage savings0.75 p.u. load at (avoided) outage

0.1 p.u. discount rate

- 124 -

ECONOMIC ANALYSIS: Table A3.6AUGMENTATION AND IMPROVEMENTS TO GALU SUBSTATION

EXISTING SYSTEM: 2.5 MVA Substation and existing 1 1 kV network

Existing system loss:Peak losses. kW 193Energy, MWh/yr. 796

Load factor (combined) 0.675Loss factor (combined) 0.472Load gro wth rate (p.a.), pu 0.06Existing system load, MW 3.6Maximum system capacity, MW 4.0

PROPOSE-D SYSTEM New 33/1 1kV Sub Station augmentation to 7.5 MVAwith reconductoring no reconductoring

Losses in new systemPeak losses, kW 38 129Energy, 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 4hrs./outage 3 3

Analysis period (Years): 10 1 5 1 0 1 5Investment costs:

Investment cost 0.336 0.336 0.236 0.236PW of Residual value 0.168 0.084 0.118 0.059Net Investment 0.168 0.252 0.118 0.177

Value of benefits:Loss reduction benefits 0.867 1.375 0.358 0.567Reliability benefits 0.303 0.535 0.173 0.305Additional load supplied 2.366 4.771 2.366 4.771Total benefits 3.536 6.681 2.897 5.644

Benefit/cost ratiosLoss reduction only 5.16 5.46 3.03 3.21Loss red. + reliability 6.96 7.58 4.50 4.93All three benefits 21.05 26.51 24.55 31.89

Net present valuesLoss reduction only 0.699 1.123 0.240 0.390Loss red. + reliability 1.~002 1.657 0.413 0.696All three benefits 3.368 6.429 2.779 5.467

Exarninatron of additional investmgnt for new feeder gotion:

Incremental investment with reconductoring 0.075Incremental benefits 1.037Benefit/cost ratio 13.8Net present value on incremental investment 0.962

Note:All investments and benefits in USS millionsEconomic parameters used in computations:

21 7 $/kW - value of peak power losses0.068 $/kWh - value of energy losses0.076 $/kWh - value of additional load (new connections)

0.38 $/kWh - value of outage savings0.75 p.u. load at (avoided) outage

0.1 p.u. discount rateThe existing system includes some reinforcements under way to reduce system lossesThe 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 1552Energy, MWh/yr. 8456

Load factor (combined) 0.770Loss factor (combined) 0.622Load growth rate (p.a.), pu 0.1Existing system load, MW 50.4Maximum system capacity, MW 75.0Capacity shortfall in: 1998

PROPOSED SYSTEM All alternatives with 132 kV Line, Kinevu-Bamburi and 132/33 kV Substation at BamburiDC line 0.20 SCA DC line 0.15 SCA SC line 0.20 SCA SC line 0.15 SCA

Losses in new systemPeak losses, kW 187 342 445 552Energy, MWh/yr. 1019 1863 2425 3008

Loss savings at present load:kW at peak 1365 1210 1107 1000MWh/year 7438 6593 6032 5449

Outage savings based on:saved outages/yr. 12 12 6 6hrs. /outage 3 3 3 3

Analysis period (Years): 10 15 10 15 10 15 10 15Investment costs:

Investment cost 7.9 7.9 7.2 7.2 6.8 6.8 6.2 6.2PW of Residual value 5.3 4.0 4.8 3.6 4.5 3.4 4.1 3.1Net 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 18.1Reliability benefits 9.1 18.1 9.1 18.1 4.5 9.0 4.5 8.0Additional load supplied 40.8 113.9 40.8 113.9 40.8 113.9 40.8 113.9Total benefits 63.9 160.0 62.3 156.8 56.7 145.7 55.6 139.9

Benefit/cost ratiosLoss reduction only 5.3 7.1 5.2 6.9 5.0 6.7 5.0 5.9Loss red. + reliability 8.8 11.7 9.0 12.0 7.0 9.4 7.2 8.4All three benefits 24.3 40.5 26.0 43.7 25.1 42.9 27.0 45.3

Net present valuesLoss reduction only 11.4 24.1 10.1 21.3 9.1 19.3 8.2 15.0Loss red. + reliability 20.5 42.2 19.1 39.3 13.7 28.4 12.8 23.0All 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 0.305Incremental total benefits 1.596 3.183 1.102 5.735Benefit/cost ratio 6.7 8.8 5.4 18.8Present value of incremental investme 1.596 3.183 1.102 5.735

All investments and benefits in US$ millionsEconomic parameters used in computations:

217 $/kW - value of peak power losses0.068 $/kWh - value of energy losses0.076 $/kWh - value of additional load (new connections)0.38 S/kWh - value of outage savings0.75 p.u. load at (avoided) outage

0.1 p.u. discount rate

- 126 -

ECONOMIC ANALYSIS: Table A3.8PROPOSED DEVELOPMENTS FOR MALINDI

EXISTING SYSTEM:

Existing system loss:Peak losses, kW 1842Energy, MWh/yr. 7907

Load factor 0.730Loss factor 0.490Load growth rate (p.a.), pu 0.06Existing system load, MW 8.0Maximum system capacity, MW 8.0Capacity shortfall in: 1994

PROPOSED SYSTEM Wood pole Steel pole Reconductor to132 kV line 132 kV line 300 mm. sq.

Losses in new systemPeak losses, kW 138 138 400Energy, MWh/yr. 592 592 1717

Loss savings at present load:kW at peak 1704 1704 1442MWh/year 7314 7314 6190

Outage savings based on:saved outages/yr. 4 4 0hrs./outage 25 30 0

Analysis period (Years): 10 15 10 15 10 15Investment costs:

Investment cost 3.337 3.337 7.082 7.082 1.850 1.850PW of Residual value 1.669 0.834 4.721 3.541 0.617 0.000Net 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 13.099Reliability benefits 3.179 5.614 3.815 6.737 0.000 0.000Additional load supplied 7.940 14.261 7.940 14.261 5.278 7.409Total benefits 20.882 35.354 21.518 36.477 13.541 20.509

Benefit/cost ratiosLoss reduction only 5.85 6.18 4.14 4.37 7.77 8.22Loss red. + reliability 7.76 8.43 5.75 6.27 6.70 7.08All three benefits 12.52 14.13 9.12 10.30 10.98 11.09

Net present valuesLoss reduction only 8.095 12.977 7.403 11.938 7.200 11.505Loss red. + reliability 11.274 18.591 11.218 18.675 7.200 11.505All 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 losses0.076 $/kWh - value of additional load (new connections)0.38 $/kWh - value of outage savings0.75 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 169Energy, MWh/yr. 391

Load factor 0.444Loss factor 0.264Load growth rate (p.a.), pu 0.05Existing system load, MW 2.3Maximum system capacity. MW 4.0Capacity shortfall in: 2004

PROPOSED SYSTEM SS at Rabai SS at Mazeras Conversion to 33 kV

Losses in new systemPeak losses, kW 15 72 15Energy, MWh/yr. 35 167 35

Loss savings at present load:kW at peak 154 97 154MWh/year 356 224 356

Outage savings based on:saved outages/yr. 10 10 0hrs./outage 3 3 0

Analysis period (Years): 10 15 10 15 10 15Investment costs:

Investment cost 0.400 0.400 0.493 0.493 0.305 0.305PW of Residual value 0.200 0.100 0.247 0.123 0.102 0.000Net 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 0.879Reliability benefits 0.263 0.452 0.263 0.452 0.000 0.000Additional load supplied 0.000 0.160 0.000 0.160 0.000 0.160Total benefits 0.846 1.491 0.631 1.166 0.583 1.039

Benefit/cost ratiosLoss reduction only 2.91 2.93 1.49 1.50 2.86 2.88Loss red. + reliability 4.23 4.44 2.56 2.72 2.86 2.88All three benefits 4.23 4.97 2.56 3.15 2.86 3.40

Net present valuesLoss reduction only 0.383 0.579 0.121 0.185 0.379 0.574Loss red. + reliability 0.646 1.031 0.384 0.637 0.379 0.574All three benefits 0.646 1.191 0.384 0.796 0.379 0.734

Note:All investments and benefits in US$ millionsThe existing system includes some reinforcements under wayto reduce system lossesThe SS augmentation enables operating configuration of feeders to be changedEconomic parameters used in computations:

217 $/kW - value of peak power losses0.068 $/kWh - value of energy losses0.076 $/kWh - value of additional load (new connections)

0.38 $/kWh - value of outage savings0.75 p.u. load at (avoided) outage0.1 p.u. discount rate

- 128 -

ECONOMIC ANALYSIS: Table A3.10PROPOSED DEVELOPMENTS FOR TOM MBOYA FEEDER

EXISTING SYSTEM: 11 kV feeder from Makande

Existing system loss:Peak losses, kW 58Energy, MWh/yr. 164

Load factor 0.622Loss factor 0.325Load growth rate (p.a.), pu 0.04Existing system load, MW 5.1Maximum system capacity. MW 10.0Capacity shortfall in: 2010

PROPOSED SYSTEM New substation New substation New feeder andat Buxton at Buxton reconductoring

Losses in new systemPeak losses, kW 17 17 38Energy, MWh/yr. 48 48 110

Loss savings at present load:kW at peak 51 * 41 19MWh/year 144 * 116 55

Outage savings based on:saved outages/yr. 3 3 3hrs./outage 5 5 3

Analysis period (Years): 10 15 10 15 10 15Investment costs:

Investment cost 0.349 0.349 0.279 0.279 0.060 0.060PW of Residual value 0.174 0.087 0.139 0.070 0.020 0.000Net 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 0.104Reliability benefits 0.274 0.457 0.274 0.457 0.165 0.274Additional load supplied 0.000 0.000 0.000 0.000 0.000 0.000Total benefits 0.464 0.731 0.427 0.677 0.237 0.378

Benefit/cost ratiosLoss reduction only 1.09 1.05 1.10 1.05 1.80 1.73Loss red. + reliability 2.66 2.80 3.06 3.24 5.91 6.30Total benefits 2.66 2.80 3.06 3.24 5.91 6.30

Net present valuesLoss reduction only 0.016 0.012 0.013 0.011 0.032 0.044Loss red. + reliability 0.290 0.470 0.287 0.468 0.197 0.318Total 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 feedersIn 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 losses0.076 $/kWh - vaiue of additional load (new connections)

0.38 $/kWh - value of outage savings0.75 p.u. load at (avoided) outage

0.1 p.u. discount rate

- 129 -

Table A3.11ECONOMIC ANALYSIS:PROPOSED DEVELOPMENTS FOR BAMBURI FEEDER FROM NYALI

EXISTING SYSTEM: 11 kV Bamburi feeder from Nyali

Existing system loss:Peak losses, kW 260Energy, MWh/yr. 934

Load factor 0.583Loss factor 0.410Load growth rate (p.a.), pu 0.07Existing system load, MW 3.2Maximum system capacity, MW 4.0Capacity shortfall in: 1997

PROPOSED SYSTEM New feederand reconductoring

Losses in new systemPeak losses, kW 122Energy, MWh/yr. 439

Loss savings at present load:kW at peak 138MWh/year 495

Outage savings based on:saved outages/yr. 3hrs./outage 8

Analysis period (Years): 10 15Investment costs:

Investment cost 0.084 0.084PW of Residual value 0.028 0.000Net Investment 0.056 0.084

Value of benefits:Loss reduction benefits 0.797 1.333Reliability benefits 0.324 0.589Additional load supplied 1.496 3.566Total benefits 2.617 5.487

Benefit/cost 'atiosLoss reduction only 14.24 15.87Loss red. + reliability 20.02 22.87All three benefits 46.74 65.32

Net present valuesLoss reduction only 0.741 1.249Loss red. + reliability 1.065 1.837All 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 savings0.75 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 LossSubstation 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 0Annual energy savings = $165177 x 0.068

= $11232Total value of savings per year = $32,932Investment cost = $31170Payback period = 11.35 monthsBenefit to Cost ratio = 13.7

Table A4.1Results of LV system loss studies (existing networks)

Power Loss Energy Loss per yearTransformer 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 17,519514610 405 232 1,036,483 3.6 1.6 20.4 8.8 59.2 8,903 0.9 50449 4.9 146,476510762 2329 266 1,561,207 3.4 1.3 7.2 2.7 4.6 10,200 0.7 21600 1.4 13,657510754 4415 Included In Tf. No. 510762632015 178 124 325,872 1.3 1.0 0.6 0.5 10.7 1,320 0.4 609 0.2 10,846630056 188 142 410,494 1.4 1.0 1.2 0.8 13.9 1,726 0.4 1480 0.4 17,079582010 606 18 59,918 0.3 1.7 2.4 13.3 4.5 462 0.8 3694 6.2 6,858422346 526 167 819,235 2.2 1.3 2.4 1.4 8.7 6,554 0.8 7150 0.9 26,062584511 1410 100 499,320 1.9 1.9 2.4 2.4 3.0 5,860 1.2 7402 1.5 9,404630000 668 398 1,359,727 2.9 0.7 1.2 0.3 6.1 5,008 0.4 2072 0.2 10,600260587 2163 137 732,073 1.7 1.2 27.6 20.1 13.5 5,989 0.8 97235 13.3 47,727582768 2420 70 355,656 0.9 1.3 2.4 3.4 1.4 2,830 0.8 7546 2.1 4,288423414 936 334 1,492,178 3.4 1.0 8.4 2.5 12.6 11,475 0.8 28350 1.9 42,562420711 633 Included in Tf. No.423414141741 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 12,399250721 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 70,145234080 3044 Included in Tf. No. 2312759120741 354 117 379,220 1.1 0.9 1.3 1.1 6.8 1,625 0.4 1920 0.5 10,028260586 1894 63 292,496 0.6 1.0 2.4 3.8 1.6 1,646 0.6 6583 2.3 4,345582723 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 0.20Loss 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 30.5420 166 3.61 5.46 6.43 10.39 15.4230 199 2.88 3.96 4.57 7.14 10.4540 244 2.65 3.30 3.72 5.57 8.0250 303 2.63 2.99 3.28 4.68 6.6060 374 2.71 2.84 3.05 4.13 5.6870 459 2.85 2.79 2.93 3.77 5.0680 556 3.02 2.81 2.88 3.53 4.6290 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 Watts650 = Full load loss in Watts

0.92 = power factor of loadFormula used for loss load factor:

LLF = 0.2*LF + 0.8*LF^2

Table A4.2.11BTRANSFORMER POWER AND ENERGY LOSSES(For varying Load Factors)

25 KVA Low Loss Transformer

Load Factor = 0.60 0.50 0.30 0.20Loss 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 12.4520 73 1.58 2.30 2.68 4.28 6.3230 92 1.33 1.72 1.96 2.98 4.3140 119 1.30 1.49 1.65 2.36 3.3450 155 1.34 1.40 1.50 2.03 2.7860 197 1.43 1.38 1.44 1.82 2.4370 248 1.54 1.40 1.42 1.70 2.2080 307 1.67 1.44 1.43 1.63 2.0490 373 1.80 1.50 1.47 1.59 1.93

100 447 1.94 1.57 1.51 1.57 1.85

Nte1Particulars used in the computation:

57 = No load loss in Watts390 = Full load loss in Watts

0.92 = power factor of loadFormula used for loss load factor:

LLF = 0.2*LF + 0.84 LF^2

- 133 -

Table A4.2.2ATRANSFORMER POWER AND ENERGY LOSSES(For varying Load Factors)

50 KVA KPLC Transformer

Load Factor = 0.60 0.50 0.30 0.20Loss 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 19.6620 228 2.48 3.62 4.23 6.75 9.9730 288 2.09 2.71 3.08 4.69 6.8040 372 2.02 2.34 2.58 3.72 5.2750 480 2.09 2.19 2.35 3.18 4.3860 612 2.22 2.15 2.24 2.86 3.8270 768 2.39 2.17 2.21 2.67 3.4580 948 2.58 2.23 2.23 2.55 3.2090 1152 2.78 2.32 2.28 2.48 3.02

100 1380 3.00 2.43 2.35 2.45 2.90

NolParticulars used in the computation:

180 = No load loss in Watts1200 = Full load loss in Watts0.92 = power factor of load

Formula used for loss load factor:LLF = 0.2*LF + 0.84LF^2

Table A4.2.2BTRANSFORMER POWER AND ENERGY LOSSES(For varying Load Factors)

50 KVA Low Loss Transformer

Load Factor = 0.60 0.50 0.30 0.20Loss 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 10.9120 122 1.32 1.97 2.31 3.73 5.5230 149 1.08 1.45 1.66 2.57 3.7540 186 1.01 1.23 1.37 2.02 2.8950 235 1.02 1.12 1.22 1.71 2.3960 294 1.07 1.08 1.15 1.52 2.0770 365 1.13 1.08 1.11 1.40 1.8580 446 1.21 1.09 1.11 1.32 1.7090 537 1.30 1.12 1.12 1.27 1.59

100 640 1.39 1.16 1.14 1.24 1.51

NoteParticulars used in the computation:

100 = No load loss in Watts540 = Full load loss in Watts

0.92 = power factor of loadFormula 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 0.20Loss 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 13.6620 328 1.78 2.55 2.97 4.72 6.9530 426 1.54 1.94 2.19 3.30 4.7640 562 1.53 1.71 1.87 2.64 3.7050 738 1.60 1.63 1.72 2.28 3.1060 952 1.72 1.62 1.67 2.07 2.7270 1206 1.87 1.66 1.67 1.95 2.4880 1498 2.04 1.72 1.70 1.88 2.3190 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 Watts1950 = Full load loss in Watts0.92 = 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 0.20Loss 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 9.2720 205 1.11 1.67 1.96 3.16 4.69

30 249 0.90 1.22 1.40 2.18 3.1840 310 0.84 1.03 1.15 1.71 2.4550 389 0.85 0.94 1.02 1.44 2.0260 485 0.88 0.90 0.96 1.28 1.7570 599 0.93 0.89 0.93 1.17 1.5680 730 0.99 0.90 0.92 1.10 1.4390 879 1.06 0.92 0.92 1.06 1.33

100 1045 1.14 0.95 0.94 1.03 1.27

NotParticulars used in the computation:

170 = No load loss in Watts875 = Full load loss in Watts

0.92 = power factor of loadFormula 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 annumTransf. 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 0.677014 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 0.617016 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 0.677006 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 0.496833 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 0.686756 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 0.536834 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 0.586867 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 0.696752 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 2.846832 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 0.536761 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 0.596764 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 0.706795 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 0.476763 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 1.487700 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 0.586774 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 0.676863 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 0.816836 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 un6841 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 0.60Power 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 AreaPoorly 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 unit0.5 = Load factor Ir --iron losses0.3 = Loss factor Cu --copper losses

- 136 -TRL-100 Chart 6 Figure A4.2,3A

KPLC 100 kVA Transformer Energy Losses

14 --

12 ---------

-4-- LF-0.6at 8 -- - - - - - - - -- - - - - - - - - -- - - - - - - - - - -- LF -O .5

-i-LF-0.3U) 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 A4.3ACOMPUTATION 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)A2Total power loss = Sum of above (say, Lp)

Energv Losses computationIron losses per annum = L(i)*8760

Copper losses per annum = L(cu)*(Ppk)A2*LLF*8760Total 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 timeit 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 figuresso 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 contribution2. 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 *LFA23. 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 loadsParameters 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 0.50Peak 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 0.35Loss 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 0.2b= 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 10interest 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 ($/kW/yr.) 217 217 217 217 217 217 217 217 217 217 217 217LRMC energy ($/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

Nots1. 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 4.4SUMMARY OF RESULTS - LV SYSTEM DEVELOPMENT STUDIES

Investment Selected Cost of Losses___________ ________________ _________ ________ _______ (Present W orthed)

Residual NetArea 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 9.31,11 & III - - 12865 P 598 12270 156042 30425 125617 10.24

I x 200TR 0587 1 (1994-1998) 1 x315 680 11058 A 4577 6481 169738 16788 152960 23.6

I x 5011 (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 12.831,11 & 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 1.44t1,1 & 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 NetArea 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

andTR 12759 11 (1999-2003) 2 x 75 - 124 12395A - - - - -

50111 (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 3414and 11 (1999-2003) - - - - - - - -

TR 1741111 (2004-2008) 1 x 100 114 4235 A - - - - -

I&ll . - - 11741 P 1509 10238 67822 47171 20651 2.02I,&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

andTR 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 1998P - 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 DevelopmentNetwork ID. 0066 - Period I

< 913t sJz I

to ot sit Addition of Transformer4 |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 0I

LV SYSTEM OPTIMIZATION -PROPOSALS IN PERXOD II

Proposed LV Network DevelopmentlNetwork 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 DevelopmentNetwork ID. 0066 - Period III

2)1 1 52 34

l 17

3 . /sx2 "' /ss l

11 .ATransformer Selectedto 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 14S4S~~~~~~~~~I

Original Transformer/sTransformer/

Note: No Tranaformer added but network L SJ STN 006rearranged in Period III. L..S/T 0-

PERIOD:- 2004-2008

1: 2500

JOINT UNDP/WORLD BANKENERGY 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'sIndustry and Energy Department. ESMAP provides advice to governments onsustainable energy development. Established with the support of UNDP and 15 bilateralofficial donors in 1983, it focuses on policy and institutional reforms designed to promoteincreased private investment in energy and supply and end-use energy efficiency; naturalgas development; and renewable, rural, and household energy.

GOVERNANCE AND OPERATIONS

ESMAP is governed by a Consultative Group (ESMAP CG), composed of representativesof the UNDP and World Bank, the governments and other institutions providingfinancial support, and the recipients of ESMAPs assistance. The ESMAP CG is chairedby the World Bank's Vice President, Finance and Private Sector Development, andadvised by a Technical Advisory Group (TAG) of independent energy experts thatreviews the Programme's strategic agenda, its work program, and other issues. ESMAPis staffed by a cadre of engineers, energy planners, and economists from the Industry andEnergy Department of the World Bank. The Director of this Department is also theManager of ESMAP, responsible for administering the Programme.

FUNDING

ESMAP is a cooperative effort supported by the World Bank, UNDP and other UnitedNations agencies, the European Community, Organization of American States (OAS),Latin American Energy Organization (OLADE), and public and private donors fromcountries 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. Forfurther information or copies of completed ESMAP reports, contact:

ESMAPc/o Industry and Energy Department

The World Bank1818 H Street, N.W.

Washington, D.C. 20433U.S.A.

Joint UNDP/World BankENERGY 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) 07/88 085/88Regional Power Seminar on Reducing Electric Power SystemLosses in Africa (English) 08/88 087/88

Institutional Evaluation of EGL (English) 02/89 098/89Biomass Mapping Regional Workshops (English) 05/89--Francophone Household Energy Workshop (French) 08/89 103/89Interafrican 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 Improvementin Sub-Saharan Africa 06/96 182/96

Angola Energy Assessment (English and Portuguese) 05/89 4708-ANGPower Rehabilitation and Technical Assistance (English) 10/91 142/91

Benin Energy Assessment (English and French) 06/85 5222-BENBotswana Energy Assessment (English) 09/84 4998-BT

Pump Electrification Prefeasibility Study (English) 01/86 047/86Review of Electricity Service Connection Policy (English) 07/87 071/87Tuli Block Farms Electrification Study (English) 07/87 072/87Household 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-BURTechnical Assistance Program (English) 03/86 052/86Urban Household Energy Strategy Study (English and French) 06/91 134/91

Burundi Energy Assessment (English) 06/82 3778-BUPetroleum Supply Management (English) 01/84 012/84Status Report (English and French) 02/84 011/84Presentation 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) 09/85 042/85Peat Utilization Project (English) 11/85 046/85Energy Assessment (English and French) 01/92 9215-BU

Cape Verde Energy Assessment (English and Portuguese) 08/84 5073-CVHousehold Energy Strategy Study (English) 02/90 110/90

Central AfricanRepublic Energy Assessement (French) 08/92 9898-CAR

Chad Elements of Strategy for Urban Household EnergyThe Case of Ndjamena (French) 12/93 160/94

Comoros Energy Assessment (English and French) 01/88 7104-COMCongo Energy Assessment (English) 01/88 6420-COB

Power Development Plan (English and French) 03/90 106/90C6te dIvoire Energy Assessment (English and French) 04/85 5250-IVC

Improved Biomass Utilization (English and French) 04/87 069/87Power System Efficiency Study (English) 12/87 --Power Sector Efficiency Study (French) 02/92 140/91Project 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) 10/85 045/85Agricultural Residue Briquetting Pilot Project (English) 12/86 062/86Bagasse Study (English) 12/86 063/86Cooking Efficiency Project (English) 12/87 --Energy Assessment 02/96 179/96

Gabon Energy Assessment (English) 07/88 6915-GAThe Gambia Energy Assessment (English) 11/83 4743-GM

Solar Water Heating Retrofit Project (English) 02/85 030/85Solar Photovoltaic Applications (English) 03/85 032/85Petroleum Supply Management Assistance (English) 04/85 035/85

Ghana Energy Assessment (English) 11/86 6234-GHEnergy Rationalization in the Industrial Sector (English) 06/88 084/88Sawmill Residues Utilization Study (English) 11/88 074/87Industrial Energy Efficiency (English) 11/92 148/92Industrial Energy Efficiency Technical Assistance Phase II 08/96 185/96

Guinea Energy Assessment (English) 11/86 6137-GUIHousehold Energy Strategy (English and French) 01/94 163/94

Guinea-Bissau Energy Assessment (English and Portuguese) 08/84 5083-GUBRecommended Technical Assistance Projects (English &Portuguese) 04/85 033/85

Management Options for the Electric Power and Water SupplySubsectors (English) 02/90 100/90

Power and Water Institutional Restructuring (French) 04/91 118/91Kenya Energy Assessment (English) 05/82 3800-KE

Power System Efficiency Study (English) 03/84 014/84Status Report (English) 05/84 016/84Coal Conversion Action Plan (English) 02/87 --Solar Water Heating Study (English) 02/87 066/87Peri-Urban Woodfuel Development (English) 10/87 076/87Power Master Plan (English) 11/87 --Power Loss Reduction Study 09/96 186/96

Lesotho Energy Assessment (English) 01/84 4676-LSOLiberia Energy Assessment (English) 12/84 5279-LBR

Recommended Technical Assistance Projects (English) 06/85 038/85Power System Efficiency Study (English) 12/87 081/87

Madagascar Energy Assessment (English) 01/87 5700-MAGPower System Efficiency Study (English and French) 12/87 075/87Envirownental Impact of Woodfuels (French) 10/95 176/95

Malawi Energy Assessment (English) 08/82 3903-MALTechnical Assistance to Improve the Efficiency of FuelwoodUse in the Tobacco Industry (English) 11/83 009/83

Status Report (English) 01/84 013/84Mali Energy Assessment (English and French) 11/91 8423-MLI

Household Energy Strategy (English and French) 03/92 147/92Islamic Republicof Mauritania Energy Assessment (English and French) 04/85 5224-MAU

Household Energy Strategy Study (English and French) 07/90 123/90Mauritius Energy Assessment (English) 12/81 3510-MAS

Status Report (English) 10/83 008/83Power System Efficiency Audit (English) 05/87 070/87Bagasse Power Potential (English) 10/87 077/87Energy Sector Review (English) 12/94 3643-MAS

- 3 -

Region/Country Activity/Report Title Date Number

Morocco Energy Sector Institutional Development Study (English andFrench) 07/95 173/95

Mozambique Energy Assessment (English) 01/87 6128-MOZHousehold Electricity Utilization Study (English) 03/90 113/90Electricity Tariffs Study 06/96 181/96

Namibia Energy Assessment (English) 03/93 11320-NAMNiger Energy Assessment (French) 05/84 4642-NIR

Status Report (English and French) 02/86 051/86Improved Stoves Project (English and French) 12/87 080/87Household Energy Conservation and Substitution (Englishand French) 01/88 082/88

Nigeria Energy Assessment (English) 08/83 4440-LUNIEnergy Assessment (English) 07/93 11672-UNI

Republic ofSouth Africa Options for the Structure and Regulation of Natural Gas

Industry (English) 05/95 172/95Rwanda Energy Assessment (English) 06/82 3779-RW

Energy Assessment (English and French) 07/91 8017-RWStatus Report (English and French) 05/84 017/84Improved Charcoal Cookstove Strategy (English and French) 08/86 059/86Improved Charcoal Production Techniques (English and French) 02/87 065/87Commercialization of Improved Charcoal Stoves and CarbonizationTechniques 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 Programnfor Energy Surveys and Policy Analysis (English) 11/91

Sao Tomeand Principe Energy Assessment (English) 10/85 5803-STP

Senegal Energy Assessment (English) 07/83 4182-SEStatus Report (English and French) 10/84 025/84Industrial Energy Conservation Study (English) 05/85 037/85Preparatory Assistance for Donor Meeting (English and French) 04/86 056/86Urban Household Energy Strategy (English) 02/89 096/89Industrial Energy Conservation Program 05/94 165/94

Seychelles Energy Assessment (English) 01/84 4693-SEYElectric Power System Efficiency Study (English) 08/84 021/84

Sierra Leone Energy Assessment (English) 10/87 6597-SLSomalia Energy Assessment (English) 12/85 5796-SORepublic of Options for the Structure and Regulation of Natural

South Africa Gas Industry (English) 05/95 172/95Sudan Management Assistance to the Ministry of Energy and Mining 05/83 003/83

Energy Assessment (English) 07/83 4511-SUPower System Efficiency Study (English) 06/84 018/84Status Report (English) 11/84 026/84Wood Energy/Forestry Feasibility (English) 07/87 073/87

Swaziland Energy Assessment (English) 02/87 6262-SWTanzania Energy Assessment (English) 11/84 4969-TA

Peri-Urban Woodfuels Feasibility Study (English) 08/88 086/88Tobacco Curing Efficiency Study (English) 05/89 102/89Remote 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-TOWood Recovery in the Nangbeto Lake (English and French) 04/86 055/86

Togo Power Efficiency Improvement (English and French) 12/87 078/87Uganda Energy Assessment (English) 07/83 4453-UG

Status Report (English) 08/84 020/84Institutional Review of the Energy Sector (English) 01/85 029/85

* Energy Efficiency in Tobacco Curing Industry (English) 02/86 049/86Fuelwood/Forestry Feasibility Study (English) 03/86 053/86Power System Efficiency Study (English) 12/88 092/88Energy Efficiency Improvement in the Brick andTile Industry (English) 02/89 097/89

Tobacco Curing Pilot Project (English) 03/89 UNDP TerminalReport

Zaire Energy Assessment (English) 05/86 5837-ZRZambia Energy Assessment (English) 01/83 4110-ZA

Status Report (English) 08/85 039/85Energy Sector Institutional Review (English) 11/86 060/86

Zambia Power Subsector Efficiency Study (English) 02/89 093/88Energy Strategy Study (English) 02/89 094/88Urban Household Energy Strategy Study (English) 08/90 121/90

Zimbabwe Energy Assessment (English) 06/82 3765-ZIMPower System Efficiency Study (English) 06/83 005/83Status Report (English) 08/84 019/84Power Sector Management Assistance Project (English) 04/85 034/85Petroleum Management Assistance (English) 12/89 109/89Power Sector Management Institution Building (English) 09/89Charcoal Utilization Prefeasibility Study (English) 06/90 119/90Integrated Energy Strategy Evaluation (English) - 01/92 8768-ZIMEnergy Efficiency Technical Assistance Project:Strategic Framework for a National Energy EfficiencyImprovement Program (English) 04/94 --

Capacity Building for the National Energy Efficiencylmprovement Programme (NEEIP) 12/94 --

EAST ASIA AND PACIFIC (EAP)

Asia Regional Pacific Household and Rural Energy Seminar (English) 11/90China County-Level Rural Energy Assessments (English) 05/89 101/89

Fuelwood Forestry Preinvestment Study (English) 12/89 105/89Strategic Options for Power Sector Reform in China (English) 07/93 156/93Energy Efficiency and Pollution Control in Township andVillage Enterprises (TVE) Industry (English) 11/94 168/94

Energy for Rural Development in China: An Assessment Basedon a Joint Chinese/ESMAP Study in Six Counties 06/96 183/96

Fiji Energy Assessment (English) 06/83 4462-FIJIndonesia Energy Assessment (English) 11/81 3543-IND

Status Report (English) 09/84 022/84Power Generation Efficiency Study (English) 02/86 050/86Energy Efficiency in the Brick, Tile andLime Industries (English) 04/87 067/87

- 5 -

Region/Country Activit/Report Title Date Number

Indonesia Diesel Generating Plant Efficiency Study (English) 12/88 095/88Urban Household Energy Strategy Study (English) 02/90 107/90Biomass Gasifier Preinvestment Study Vols. I & II (English) 12/90 124/90Prospects for Biomass Power Generation with Emphasis on

Palm Oil, Sugar, Rubberwood and Plywood Residues (English) 11/94 167/94Lao PDR Urban Electricity Demand Assessment Study (English) 03/93 154/93Malaysia Sabah Power System Efficiency Study (English) 03/87 068/87

Gas Utilization Study (English) 09/91 9645-MAMyannar Energy Assessment (English) 06/85 5416-BAPapua NewGuinea Energy Assessment (English) 06/82 3882-PNG

Status Report (English) 07/83 006/83Energy Strategy Paper (English) -- --Institutional Review in the Energy Sector (English) 10/84 023/84Power Tariff Study (English) 10/84 024/84

Philippines Commercial Potential for Power Production fromAgricultural Residues (English) 12/93 157/93Energy Conservation Study (English) 08/94 --

Solomon Islands Energy Assessment (English) 06/83 4404-SOLEnergy 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) 09/85 044/85Accelerated Dissemination of Improved Stoves and

Charcoal Kilns (English) 09/87 079/87Northeast Region Village Forestry and WoodfuelsPreinvestment 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-TONVanuatu Energy Assessment (English) 06/85 5577-VAVietnam Rural and Household Energy-Issues and Options (English) 01/94 161/94

Power Sector Reform and Restructuring in Vietnam: Final Reportto the Steering Committee (English and Vietnamese) 09/95 174/95

Household Energy Technical Assistance: Improved CoalBriquetting and Commercialized Dissemination of HigherEfficiency 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-BDPriority Investment Program (English) 05/83 002/83Status Report (English) 04/84 015/84Power System Efficiency Study (English) 02/85 031/85Small Scale Uses of Gas Prefeasibility Study (English) 12/88

India Opportunities for Commercialization of NonconventionalEnergy 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 andCanal Drops Vols. I, 11 and III (English) 07/91 139/91

WindFarm Pre-Investment Study (English) 12/92 150/92Power Sector Reform Seminar (English) 04/94 166/94

Nepal Energy Assessment (English) 08/83 4474-NEPStatus Report (English) 01/85 028/84NepalEnergy 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) 10/89 103/89National Household Energy Survey and Strategy Fomulation

Study: Project Terminal Report (English) 03/94 --Managing the Energy Transition (English) 10/94Lighting Efficiency Improvement ProgramPhase 1: Commercial Buildings Five Year Plan (English) 10/94 --

Sri Lanka Energy Assessment (English) 05/82 3792-CEPower System Loss Reduction Study (English) 07/83 007/83Status Report (English) 01/84 010/84Industrial Energy Conservation Study (English) 03/86 054/86

EUROPE AND CENTRAL ASIA (ECA)

Eastern Europe The Future of Natural Gas in Eastern Europe (English) 08/92 149/92Poland Energy Sector Restructuring Program Vols. I-V (English) 01/93 153/93Portugal Energy Assessment (English) 04/84 4824-POTurkey Energy Assessment (English) 03/83 3877-TU

MEIDDLE EAST AND NORTH AFRICA (MNA)

Morocco Energy Assessment (English and French) 03/84 4157-MORStatus Report (English and French) 01/86 048/86Energy Sector Institutional Development Study (English and French) 05/95 173/95

Syria Energy Assessment (English) 05/86 5822-SYRElectric Power Efficiency Study (English) 09/88 089/88Energy Efficiency Improvement in the Cement Sector (English) 04/89 099/89Energy 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) 02/92 136/91Energy Management Strategy in the Residential and

Tertiary Sectors (English) 04/92 146/92Yemen Energy Assessment (English) 12/84 4892-YAR

Energy Investment Priorities (English) 02/87 6376-YARHousehold 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 Reductionin the Caribbean (English) 07/89 -

Bolivia Energy Assessment (English) 04/83 4213-BONational Energy Plan (English) 12/87 --National Energy Plan (Spanish) 08/91 131/91La Paz Private Power Technical Assistance (English) 11/90 111/90Natural Gas Distribution: Economics and Regulation (English) 03/92 125/92Prefeasibility Evaluation Rural Electrification and DemandAssessment (English and Spanish) 04/91 129/91

Private Power Generation and Transmission (English) 01/92 137/91Household Rural Energy Strategy (English and Spanish) 01/94 162/94Natural Gas Sector Policies and Issues (English and Spanish) 12/93 164/93

Brazil Energy Efficiency & Conservation: Strategic Partnership forEnergy Efficiency in Brazil (English) 01/95 170/95

Chile Energy Sector Review (English) 08/88 7129-CHColombia Energy Strategy Paper (English) 12/86 --

Power Sector Restructuring (English) 11/94 169/94Energy Efficiency Report for the Commercial and Public Sector 06/96 184/96

Costa Rica Energy Assessment (English and Spanish) 01/84 4655-CRRecommended Technical Assistance Projects (English) 11/84 027/84Forest Residues Utilization Study (English and Spanish) 02/90 108/90

DominicanRepublic Energy Assessment (English) 05/91 8234-DO

Ecuador Energy Assessment (Spanish) 12/85 5865-ECEnergy 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-ECEnergy Pricing, Poverty and Social Mitigation (English) 08/94 1283 1-EC

Guatemala Issues and Options in the Energy Sector (English) 09/93 12160-GUHaiti Energy Assessment (English and French) 06/82 3672-HA

Status Report (English and French) 08/85 041/85Household Energy Strategy (English and French) 12/91 143/91

Honduras Energy Assessment (English) 08/87 6476-HOPetroleum Supply Management (English) 03/91 128/91

Jamaica Energy Assessment (English) 04/85 5466-JMPetroleum Procurement, Refining, andDistribution Study (English) 11/86 061/86

Energy Efficiency Building Code Phase I (English) 03188 --Energy Efficiency Standards andLabels Phase I (English ) 03/88 --

Management Information System Phase I (English) 03/88 --

Charcoal Production Project (English) 09/88 090/88FIDCO Sawmill Residues Utilization Study (English) 09/88 088/88Energy Sector Strategy and Investment Planning Study (English) 07/92 135/92

Mexico Improved Charcoal Production Within Forest Management for 08/91 138/91the State of Veracruz (English and Spanish)

Energy Efficiency Management Technical Assistance to theComision 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) 06/83 004/83Paraguay Energy Assessment (English) 10/84 5145-PA

Recommended Technical Assistance Projects (English) 09/85 --

Status Report (English and Spanish) 09/85 043/85Peru Energy Assessment (English) 01/84 4677-PE

Status Report (English) 08/85 040/85Proposal for a Stove Dissemination Program inthe Sierra (English and Spanish) 02/87 064/87

Energy Strategy (English and Spanish) 12/90 --Study of Energy Taxation and Liberalizationof the Hydrocarbons Sector (English and Spanish) 120/93 159/93

Saint Lucia Energy Assessment (English) 09/84 5111-SLUSt. Vincent andthe Grenadines Energy Assessment (English) 09/84 5103-STV

Trinidad andTobago Energy Assessment (English) 12/85 5930-TR

GLOBAL

Energy End Use Efficiency: Research and Strategy (English) 11/89 --

Guidelines for Utility Customer Management andMetering (English and Spanish) 07/91 --

Women and Energy--A Resource GuideThe International Network: Policies and Experience (English) 04/90 --

Assessment of Personal Computer Models for EnergyPlanning in Developing Countries (English) 10/91

Long-Term Gas Contracts Principles and Applications (Englishj 02/93 152/93Comparative Behavior of Firms Under Public and PrivateOwnership (English) 05/93 155/93

Development of Regional Electric Power Networks (English) 10/94 --

Roundtable on Energy Efficiency (English) 02/95 171/95Assessing 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 STUDYs U D A N TRANSMISSION SYSTEM AND DISTRIBUTION AREA COVERAGE

' DENSELY POPULATED AREAS - KPLC DISTRIBUTION AREAS1 } # OLKARIA GEOTHERMAL FIELD 220 kV TRANSMISSION LINESA 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' -

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INNER NAIROBI 11 kV DISTRIBUTION SYSTEM IIkVTRANSMISSIONLINES

1 I v UNDERGROUJND CABLES

DISTRIBUTION TRANSFORMER STATIONSCIRCUIT BREAKERS FOR SWITCHING ORMV CONSUMER

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I ICK 0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~FO 2TL IlT /I.

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Io IS 13~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1 ~-

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FOR INSUSTEAL AREA IN~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~W .RI17 FJA AD 140 AD~~~-AR 1

N 1-,' F-EII -E~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~JL'19

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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 STUDYNAIROBI 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 66kV0100 ( ~~~~~~~SE W26459

-225 kv

-1 IkV UNDERGROUND CABLES

DISTRIBUTION TRANSFORMER STATIONS

/ SITES to oooootoo, O~~~~~~~~~~~CRCUIT BREAK~ERS FOR SWITCH-ING ORIkl ~~~~~~~~~~~~~~~~~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]

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RIBE FDRir 6 kVA

-, .. RIBE_4 3 3/II kV

N KIKOAMBAA33/I1IEV~-

S '' ___,,',. .-IMOLAEWA

'\> / MAZERAS FDR >g , i,,~~~~~~~~~~~~~~~~~~~~~~~~DR.

r X ~~~~~~~~~~~~~~~~~O. - HAZ

'5-"' B~~~~ABAIB. "fl''"' 2~~~~~~~20/1 32/33EkV

-SHANZU33/1 I v

*'K* .\ y!OCEANIC FDR.0116 kVA

BAMBURI

5" ENDI E0XTkILVFA34No

y58 kV5 A

AI 3/R POO. .EIIB7 D'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 O266 EVA

U00 KONINO 33/11EkV

SHELLY BEACH FOB.32 kVA

K EN Y A

POWER LOSS REDUCTION STUDYCENTRAL 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 STATIONS6R kVA

CIRCUIT BREAKERS FOR SVITCHING ORMV CONSUMER

it \I/-I1 ISOLATORS (NORMALLY OPEN POSITIONS)

\ ES DIANI 4 --- INTERNATIONAL BOUNDARIES32\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

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w / / ' -w-' =-~~~~~~~~~~~~~~~' te_Gr'7 _ t w~~~~~~~~~~0 (b-, _.

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0 2 4 4 K 10h4 R

3I.,ko.wj 310

l * * fll~~~~~~~~~AUNDIf o.A MAIJNDI 33/I1 kV

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; SUBSTATIONS

tK,bS,0 TRANSMISSION UNES:. KIULF t 11kV

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JARIBUN|I , KILIFI --------- 33 kvI * / ' - 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' OZM2AKISAUNI . 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

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I 4

ESMAPc/o Industry and Energy DepartmentThe World Bank1818 H Street, N. W.Washington, D. C. 20433U. S. A.