ESM 2C9
VolI. P1
WD<DnOq Urnieen P<;onEDO V(DOSC E3Q0p1<3Q  'Ornerm   / W  rDd Bank
aWpLDESMAAP
Energy Sector Management %asistance Programme
Tanzania
Power Loss Reduction Study
Volume 1: Transmission and Distribution System
Technical Loss Reduction and
Network Development
Report No. 204A/98
June 1998



JOINT UNDP I WORLD BANK
ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP)
PURPOSE
The Joint UNDP/World Bank Energy Sector Management Assistance Programme
(ESMAP) is a special global technical assistance program run as part of the World Bank's
Energy, Mining and Telecommunications Department.  ESMAP provides advice to
governments on sustainable energy development. Established with the support of UNDP
and 15 bilateral official donors in 1983, it focuses on the role of energy in the
development process with the objective of contributing to poverty alleviation, improving
living conditions and preserving the environment in developing countries and transition
economies. ESMAP centers its interventions around three priority areas: sector reform
and restructuring; access to modern energy for the poorest; and promotion of sustainable
energy practices.
GOVERNANCE AND OPERATIONS
ESMAP is governed by a Consultative Group (ESMAP CG), composed of representatives
of the UNDP and World Bank, other donors, and development experts from regions
benefiting from ESMAP's assistance. The ESMAP CG is chaired by a World Bank's Vice
President, and advised by a Technical Advisory Group (TAG) of four independent energy
experts that reviews the Programme's strategic agenda, its work plan, and its
achievements. ESMAP relies on a cadre of engineers, energy planners, and economists
from the World Bank to conduct its activities under the guidance of the Manager of
ESMAP, responsible for administering the Programme.
FUNDING
ESMAP is a cooperative effort supported over the years by the World Bank, the UNDP
and other United Nations agencies, the European Union, the Organization of American
States (OAS), the Latin American Energy Organization (OLADE), and public and private
donors from countries including Australia, Belgium, Canada, Denmark, Germany, Finland,
France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal,
Sweden, Switzerland, the United Kingdom, and the United States.
FURTHER INFORMATION
An up-to-date listing of completed ESMAP projects is appended to this report. For further
information, a copy of ESMAP Annual Report or copies of completed projects, contact:
ESMAP
c/o Energy, Mining and Telecommunications Department
The World Bank
1818 H Street, NW
Washington, DC 20433
U.S.A.



TANZANIA
POWER LOSS REDUCTION STUDY
VOLUME 1:
TRANSMISSION AND DISTRIBUTION SYSTEM
TECHNICAL LOSS REDUCTION
AND NETWORK DEVELOPMENT
November 1992



I



ABBREVIATIONS
km                 Kilometer
kV                  Kilovolt
kVA                 Kilovolt ampere
kVAr               Kilovolt ampere, reactive
kW                  Kilowatt
kWh                Kilowatt hour
MVA                 Megavolt ampere
MVAr               Megavolt ampere, reactive
MW                 Megawatt
MWh                Megawatt hour
var                reactive volt ampere
US$                United States Dollar
ACRONYMS
ESMAP               Joint UNDP/World Bank Energy Sector
Management Assistance Programme
IDA                International Development Association
JICA                Japan International Corporation Agency
SIDA                Swedish International Development Agency
SVS                Static var compensation System
TANESCO            Tanzania Electric Supply Company Ltd.
TIRDO              Tanzania Industrial Research and Development Organization



I



TABLE OF CONTENTS
EXECUTIVE SUMMARY . ..................................................  i
Project Objectives  .             ..................................................    ii
Achievements and Conclusions  .........................................                                                      ii
System  Loss Analysis  .               ................................................    iii
Reactive Compensation  Requirements for the Transmission System   ....                                         .........   iv
Reactive Compensation  Requirements for the Distribution  System   ....                                      ..........   vii
Total Project Costs   .             ..................................................   x
1. INTRODUCTION ......................................................I 
Background .........................................................  1
ESMAP Assistance ...................................................  2
2.  THE  TANESCO  POWER  SYSTEM    ........................................                                                             3
Generation .........................................................  3
Transmission  .            ......................................................                                            4
Distribution ........................................................  4
Consumers and Demand . ..............................................  5
System  Operations .              ..................................................                                         5
System  Expansion   .             ..................................................                                         6
3. ANALYSIS OF  SYSTEM   LOSSES   .........................................    9
Network Losses in the Distribution System   ................................   10
Transmission System  Losses   ............                             ...............................   13
Loss Analysis for Total System    .........................................    14
4. REACTIVE COMPENSATION FOR THE TRANSMISSION SYSTEM  ....                                                                ........ 21
Background ......................................................... 21
Methodology for Load Flow  Studies   .....................................   22
Preliminary System  Improvements .......................................   23
The Study of Network Operation at Different Load Levels  ....................   27
Results of Load Flow  Studies   ............                             ..............................   29
System  Performance for 1991  .....................................   30
System  Performance for 1992  .....................................   30
System  Performance for 1993  .....................................   31
System  Performance for 1994  .....................................   32
System  Performance for 1995  .....................................   32
System  Performance Beyond  1995  .................................   34
Effect of the Singida-Arusha Connection  ............................   34
System  Performance for 1998  .....................................   35
Power Export Possibilities to Kenya  ................................   36
System  Operation  at Base Load  .........................................   37
System  Operation During Outages .......................................   37
Slippage of Planned Investment  ...................................   39
Loss Reduction Benefits .                    .............................................. 40
Selection of var Compensating Systems  ...................................   40
Compensation  Requirements at Ubungo   ............................   41
Compensation  Requirements at Arusha  .............................   42



5. ECONOMIC ANALYSIS OF PROPOSALS FOR POWER FACTOR
COMPENSATION AT THE TRANSMISSION LEVEL ......................  48
Benefits of Investment in Reactive Compensation ...........................  48
The value of unsupplied or poorly supplied energy .....................  50
The value of loss reduction benefits ................................  51
Cost of outage savings ..........................................  51
Cost of Compensation Equipment ........................................  51
Calculation of benefits and benefit to cost ratios ............................  52
Compensation to be provided at Ubungo/ilala ........................  52
Compensation to be provided at Arusha  ............................  53
6. DISTRIBUTION SYSTEM DEVELOPMENT AND PLANNING GUIDELINES ..... 56
Background  .        .......................................................  56
Economic Analysis of Development Proposals ..............................  60
Existing Distribution Networks  .........................................  62
Planning Concepts .............                ......................................  63
Planning Guidelines ............               ......................................  64
7. REACTIVE COMPENSATION ON THE DISTRIBUTION  SYSTEM  ....                                     ..........  68
General Considerations and Methodology .................................  68
Economics of Capacitor Installation for Power Factor Control .................  70
Recommendations for Reactive Compensation on the Distribution System  ....                  ....  74
Summary of Recommendations  ...................................  75
8. DEVELOPMENT PROPOSALS FOR DAR ES SALAAM   ......................  77
The present distribution system  .........................................  77
Network Development proposals ........................................  78
9. SYSTEM DEVELOPMENT PROPOSALS FOR TANGA REGION ....                                         ........... 83
The present distribution system  .........................................  83
Network Development proposals ........................................  84
10. DEVELOPMENT PROPOSALS FOR THE MOSHI REGION   ..................  88
The present distribution system  .........................................  88
Network Development proposals ........................................  89
1 1. DEVELOPMENT PROPOSALS FOR THE ARUSHA  REGION  .....                                     ............  91
The present distribution system  .........................................  91
Network Development Proposals ........................................  92
12. REHABILITATION, RATIONALIZATION, AND NETWORK EXPANSION ...... 95
Network rehabilitation and reinforcement .................................  96
Rationalization of L.V. Systems .........................................  98
Network Expansion to New Development Areas ............................  99



List of Annexes
The following Annexes provides details of the computations used in the analysis:
Annex A - Distribution System Characteristics
Annex B - Transmission System Load Flow Studies
Annex C - Economic Evaluation of Reactive Compensation Requirements
For Transmission and Distribution Systems
Annex D - Planning Methods and Guidelines for Distribution Systems
Annex E - Economic Analysis for Distribution System Development
Annex F - Distribution System Network Drawings
This report was prepared in 1992 consequent to a study conducted during 1990 to 1992 in
association with a distribution planning unit established in the Tanzania Electric Supply
Company (TANESCO).
The report is in two volumes; volume 1 dealing with the technical studies conducted on
transmission and distribution systems and volume 2 dealing with non-technical loss
issues. The Bank team carrying out the study consisted of Messrs. Winston Hay,
Chrisantha Ratnayake, and Ms. Paivi Koljonen. Volume 1 was prepared by Mr.
Ratnayake and volume 2 by Mr. Hay. The assistance and participation of the distribution
planning unit in TANESCO in carrying out the detailed studies on which this report is
based is readily acknowledged.



I
I



EXECUTIVE SUMMARY
1.          The Tanzania Electric Supply Company (TANESCO), a state-owned utility, is
responsible for the generation, transmission, and distribution of electricity in mainland Tanzania.
Over the past several years, TANESCO's operations have suffered from poor system performance
in the East and Northeast regions at times of peak demand. Despite use of all available thermal
generation and curtailment of supply to certain major consumers, network voltages remain
excessively low, and the system suffers from frequent outages that may affect the entire network.
Concomitantly, equipment damage and burnouts occur in the installations of the supply authority
and its consumers. In many areas, requests for new consumers cannot be met because of the poor
system voltages. Symptomatic of the problem are energy losses of some 21 percent of net
generation, a level considerably higher than the economic limits for the TANESCO system (after
allowing for nontechnical losses). The shortcomings of the system have resulted in substantial
economic losses to the country and financial constraints on the company. Moreover, high load
growth rates are expected over the next few years, and the situation will worsen considerably
without timely corrective action.
2.          The major cause of the low system voltages has been identified as deficiencies in the
transmission system. The network supplying the eastern and northeastern parts of the system is
heavily overburdened and has clearly exceeded technical and economic loading levels, causing the
distribution system to receive power at voltages far below the required level. In contrast, the
western sections of the network experience high system voltages because of the long and
comparatively lightly loaded 220 kV lines, thus further complicating the control of the transmission
system voltages.
3.          Two major development projects have been implemented for the distribution systems
within the last five years, alleviating supply conditions to a large extent. But the rapid increase of
load during this period and the absence of systematic network planning have caused many parts of
the system to revert once again to poor operating conditions. A major contributory factor has also
been the difficulty faced by TANESCO in undertaking sufficient network improvements outside of
externally funded projects because of the lack of foreign exchange. Thus, considerable inputs are
still required in the distribution systems to bring the networks to a satisfactory operating condition.
4.          In 1989, TANESCO requested the joint UNDP/World Bank Energy Sector
Management Assistance Programme (ESMAP) to assist in the development of a program of
activities that would improve network voltage levels, reduce overall energy losses and generally
improve the quality of supply to consumers. A study was commenced in late 1989 with funds
provided by the Swedish International Development Authority (SIDA). A team of consultants
comprising of a specialist each in the fields of transmission, distribution, commercial operations,
load forecasting, and nontechnical losses was engaged for short termn visits to assist in the study.
In addition, a local consultancy firm was engaged to undertake the study of the economic costs of
outages with respect to industrial consumers. Counterpart staff provided by TANESCO also worked



. -
in close coordination with the ESMAP staff and consultants and provided valuable inputs.
Project Objectives
5.           The project seeks to find solutions to redress the poor supply conditions in
TANESCO's power network and to reduce the existing high level of system losses. In particular
possibilities of any short term actions to improve network voltages and enable new consumers to
be added to the system at locations where such difficulties exist are to be explored. A major goal
is also the development of TANESCO's competence in the field of distribution system planning so
that timely action would continue to be taken to keep the networks at acceptable technoeconomic
standards. Specific objectives are as follows:
*     Identification of the main reasons for the poor system performance in the east and
northeast regions of the network and development of solutions for rectification
*     Identification of the sources of technical and nontechnical losses and development
of reliable estimates of the contribution of each to overall losses
*     Development of projects to reduce technical losses to economic levels
v     Introduction to TANESCO of state-of-the-art techniques of data collection and
distribution system planning and training counterpart staff to ensure the continuity
of the applications.
6.           The study report is issued in two volumes, undertaking the technical and nontechnical
problems, respectively. The present report, volume (i), Transmission and Distribution System
Technical Loss Reduction and Network Development deals with the diagnoses of problems and
provides proposals to improve the technical condition of the transmission and distribution systems.
Achievements and Conclusions
7.           The principal cause of the low system voltages experienced in many areas of the east
and northeast was identified as the insufficiencies of the 220 kV transmission lines from Kidatu to
Dar es Salaam as well as the 132 kV lines supplying the northeast loads. The study has identified
solutions that can be applied in the short term to enable the system performance to be strengthened
considerably.  These consist of introducing reactive compensation equipment both in the
transmission and distribution systems. The report recommends 45 MVAr of switched capacitors
at Dar es Salaam and 30 MVAr of variable compensation using a Static var Compensation unit
(SVS) at Arusha for the transmission system; it recommends 22 MVAr of capacitors for installation
in the distribution system. Some subsidiary improvements to the transmission system, consisting
of a 10 MVAr reactor at Mbeya (to contain the voltage rise in the western sections of the grid
system) and shifting of an existing reactor from Ubungo to Ras Kiromany (for voltage control and
loss reduction), are also identified.



8.          In addition to the above recommendations some improvements of an operational
nature was carried out while the studies were in progress. These consisted of the rearrangement of
generator tap settings at the power stations and the introduction of a circuit breaker to control a
reactor in service at Ubungo.
9.          System studies were conducted on the distribution networks in the four major load
centers: Dar es Salaam, Tanga, Moshi, and Arusha. Although the reactive compensation measures
recommended (para 7) will provide some immediate relief, more substantial developments involving
major changes to the network configurations are required in the longer term. Such requirements
are presented as a package of proposals for which international funding will require to be secured.
These development proposals will improve system performance considerably and reduce network
losses to economic levels.
10.         The study was conducted in close cooperation with TANESCO staff and emphasized
training of the counterpart staff in the techniques and methodologies of distribution system
planning. A study unit was established to undertake collection and analysis of network data on the
distribution system. Microprocessor based instrumentation was provided to record and store
network load data for subsequent downloading to a computer. The unit was provided with
computers and state-of-the-art software packages to establish a mapping data base and undertake
the required system analysis of the transmission and distribution networks. The hard work and
dedication of the counterpart staff was recognised by TANESCO's management and the unit was
soon institutionalized in the organization structure within the operations directorate responsible to
oversee the functions of the zonal distribution organizations.
System Loss Analysis
11.         Important load characteristics on the networks were collected by conducting extensive
field measurements using electronic recording loggers, and these data were used to compute the
losses of medium voltage (MV) and low voltage (LV) feeders. Using the data together with the
monthly billing information from the sales summaries enabled development of a power and energy
flow table. The table provides information on the losses (as well as supplies) at each voltage level
as a percentage of the net power generated and indicates that the overall technical losses of the
system amount to 19.3 percent for peak power and 11.5 percent for energy, based on net generation.
Because the overall energy losses are approximately 21 percent, it can be inferred that the
nontechnical losses account for 9.5 percent of the energy produced.
12.         The transmission system presently exhibits peak losses of about 8.0 percent and
energy losses of about 4.4 percent. These loss levels will drop with the commissioning of a second
circuit to Dar es Salaam (1995) and the Singida-Arusha connection (possibly by 1996). A further
reduction will occur with the commissioning of the new Pangani power station, expected in 1995.
The peak losses will fall to about 5 percent with all these developments in place. However, loss
levels will again increase when the Kihansi power station is commissioned because of the increased



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load transmitted to the main load center at Dar es Salaam.
13.         The overall loss levels of the MV system are not excessive. This is attributable to
the development work carried out by two recent distribution system improvement projects-the Dar
es Salaam rehabilitation project, funded by the Japan International Corporation Agency (JICA) and
the Power Project IV, funded by IDA. However, a number of feeders still have excessive loss levels,
and the situation will worsen considerably with the expected load growth. Proposals to reduce the
losses of these feeders to economically acceptable levels are contained in sections 8 to 11 of this
report.
14.         In comparison with the losses of the MV system, the losses of the LV networks are
extremely high, with average values of the samples studied in the four regions ranging from 6.5 to
10.5 percent for peak losses. These high levels, combined with the fact that a substantial portion
of the system load flows through the LV system, mean that LV line losses account for 45.7 and 35.1
percent of the overall peak and energy losses, respectively. Two major factors contribute to the high
loss levels in the LV networks: the high imbalance between phase currents in the three phases and
the long lengths of LV feeders used in the network design. The former can be corrected without
any capital investment, and savings of perhaps up to 25 percent of the existing losses on the LV
lines could be made if such an exercise is carried out. To reduce the remaining LV line losses, the
number of transformers in the network should be increased substantially, so that the lengths of LV
lines can be reduced. The shortening of these lines will also reduce the area of supply of the
individual transformers and increase the overall reliability of the system. An estimate for such
requirements is included under LV rationalization in section 12. Loss improvement in the LV
system should also include a program to purchase lower loss transformers by evaluating the
annualized cost of losses together with the purchase price (a common practice among utilities but
not presently followed by TANESCO). Further, the existing high core losses in a number of
underloaded transformers can be reduced by implementing a transformer load management
program to reallocate transformers to better suit the loads supplied.
Reactive Compensation Requirements for the Transmission System
15.         Preliminary studies have indicated that the poor system voltages in many parts of
the system are caused by the deficiencies in the transmission network. TANESCO has plans to
rectify these deficiencies by constructing new transmission lines (a second circuit to Dar es Salaam
from Kidatu and the Singida-Arusha connection). However, at the commissioning dates presently
feasible for these lines, a number of years of continued poor system conditions will have to be
endured, and load additions at important locations will have to be suppressed unless other
developments are introduced. Load flow studies were therefore conducted on the transmission
system to ascertain possible solutions of meeting the expected load additions in the immediate
future. The results of these studies (described in section 4) indicate that reactive compensation
equipment can be used to improve system performance substantially, particularly in the period
before the new lines are commissioned. These reactive compensation measures are recommnended



for Dar es Salaam and Arusha, the two extremities of the eastern and northeastern sections of the
transmission network. With these measures in place, the voltage regulation problems in the
transmission system will be resolved, and supply can be provided to the distribution networks at
acceptable voltage levels for all normal operating conditions.
16.         Several benefits will accrue from these proposals, but only a few can be quantified
accurately. The compensation recommended for installation at Dar es Salaam will ensure that the
expected additional loads in the city and its environs can be met at acceptable voltage levels without
resorting to additional thermal generation (which would otherwise be necessary) during the period
up to the commissioning of the second circuit from Kidatu. Similarly, the compensation to be
provided at Arusha will ensure that the network can bear the expected load additions in the
northeast until the Singida-Arusha connection is introduced. The compensation to be provided at
Dar es Salaam will also provide a substantial reduction of losses and improve system reliability.
17.         After the commissioning of the new transmission lines, both installations will
continue to play a useful function. The installation at Dar es Salaam will provide significant savings
during times of line outages. Further, after the Kihansi power project is commissioned (by 1998),
the capacitive compensation required at Dar es Salaam will increase substantially (up to about 75
MVAr) because of the increased power transfer over the Kidatu-Morogoro-Dar es Salaam lines,
and the proposed installation will form a part of this requirement. After the Singida-Arusha line
is commissioned, the installation at Arusha will serve a voltage control function by operation in
reactive mode (particularly at times of low load).
18.         The benefits of connecting additional load (as will be possible with the Arusha SVS)
and the reduction of thermal generation requirements (with capacitors at Dar es Salaam) have been
valued at US $0.10/kWh, equal to the average incremental cost (AIC) of supply at distribution level
in the TANESCO system. Arusha, too, will experience a reduction of thermal generation that will
otherwise be required (to support a limited load possible), but the value of such avoided generation
has not been costed in view of the close correspondence between thermal generation costs and the
value of new sales. The alternative cost of supporting the additional load is in fact considerably
higher in Tanzania (see Table CL.I for the cost of supply using small diesel generators). The value
of the savings on outage energy units (used for capacitor installation at Dar es Salaam) has been
estimated at US$1.00/kWh, ten times the AIC of supply, a figure that compares favorably with
studies done elsewhere. A research study conducted as part of the project by the Tanzania
Industrial Research and Development Organization (TIRDO) indicated a value of US$2.29/kWh
to industrial consumers for unannounced outages. Cost-benefit analyses conducted with the values
indicated above ($0. 10/kWh for additional load supplied and $1.00/kWh of outages saved) provided
benefit/cost ratios of 28.8:1 and 5:1 for the proposals at Dar es Salaam and Arusha, respectively.
Even if the rates used for the benefits are reduced by 50 percent, the high economic viability of the
proposals is obvious. In addition, a number of benefits of the proposals have not been quantified:
the reduced incidence of damage to equipment owned by TANESCO and its consumers, improved
quality of service and increased consumer satisfaction, reduced operation and maintenance
expenses, and reduced adverse effects of delays to planned investment in generation and



- vi -
transmission.
19.         The reduction of adverse effects of delays to planned investment in generation and
transmission is worthy of particular consideration in the context of TANESCO's previous
experiences. The present plans are for the transmission line from Kidatu to Dar es Salaam to be
commissioned in two sections by 1993 and 1995, respectively, and for the Singida-Arusha line to be
commissioned in 1996. In the past difficulties faced by TANESCO in obtaining the necessary
foreign exchange, and other shortcomings in project management have forced considerable slippage
of planned investment. The benefits of the present proposals will increase substantially in the event
of such delays; in the absence of reactive compensation at the scale proposed, TANESCO will be
forced to resort to extensive load shedding and increased thermal generation over the period of
such delays. In any event heavy demands will be placed on thermal generation to meet the hydro
generation shortfall until 1998, when the Kihansi project is expected to be commissioned and the
present plans for meeting the extent of the shortfall are far from satisfactory. Thus, any marginal
relief of the need for thermal generation will be of enhanced value, as it is highly probable that
TANESCO will not be able to meet the future demand. Therefore, the reactive compensation
measures proposed could be justified even solely on the basis of providing sufficient security for the
possible slippage of the planned investment in major generation and transmission projects.
20.          The proposed installation at Arusha is a Static var System (SVS), employing
Thyristor-controlled reactors. It will provide the best technical solution to the complex problems
at this location. If TANESCO is unable to procure the necessary funds for this installation in a
timely manner, switched capacitors up to the same rating should be purchased instead. This
solution will provide a lesser technical performance but will still provide high economic benefits, at
a benefit/cost ratio of 6.4, assuming only half the value of benefits attributed to the prefered
solution. This alternative proposal is made because of the urgency of the requirements. In fact,
compensation requirements at both locations are already overdue; early implementation will enable
TANESCO to recoup higher savings, and delays in implementation will cause substantial losses.
On the average for both installations, four months of delay are equivalent to the loss of half the
value of the installation costs. This indicates the need for immediate action to capture the full
benefits of the proposals.
21.          Three other recommendations are made to improve the perfonnance of the
transmission system. The first is shifting the existing 20 MVAr reactor at Ubungo to Ras Kiromany,
the mainland terminal of the submarine cable supplying power to Zanzibar. This proposal will
provide substantial loss reduction and voltage control benefits. Considering only the former, a
benefit/cost ratio of 20:1 and a pay back period of 4.5 months have been demonstrated. The
second is installing a 10 MVAr switchable reactor at Mbeya to enable better control of the
transmission voltages in the southwestern section of the network. The third is providing 10 MVAr
of switched capacitors in the distribution network at Tanga; the compensation will provide
substantial relief to the northeastern sections of the system. This proposal is justified by the loss
reductions that will be achieved along the 132 kV line to Tanga at a benefit/cost ratio of 21:1.



- vii -
Reactive Compensation Requirements for the Distribution System
22.          Long-term improvement of the conditions in the distribution system is dealt with in
sections 8 to 11. However the developments identified will require at least three to five years for
implementation because of the necessity to arrange for external financing as well as other logistical
difficulties in procurement and project management. However, it is possible to provide early relief
for the high losses and excessive voltage drops by installing capacitor banks in the distribution
system. Providing compensation in the distribution system will also reduce the compensation
requirements in the transmission system. In fact, progressive improvements of the existing power
factors at the grid substations have been taken into account in the studies that determined the
requirements of the transmission system.
23.         The lead time for the purchase of these capacitors (particularly those to be fixed on
distribution lines) is extremely short (about six months), and installation can be undertaken by
TANESCO's own staff as the items are received. The selection of appropriate locations for the
capacitors and the resulting loss reduction benefits at various voltage levels in the distribution
system are discussed in section 7, and a summary of the recommended installations with related
benefit/cost ratios is provided in Table 7.1. Total savings of 3,180 MWh per annum can be
expected from the application of the capacitors recommended for the distribution system, giving an
overall benefit/cost ratio of 10.6:1. The loss reduction represents a 3 percent reduction of the
existing overall distribution system technical losses (estimated at 100 GWh), equivalent to 0.2
percent of the annual energy produced.
Distribution System Development and Training of TANESCO staff in Distribution Planning
24.         Distribution systems in the four major load centers of the country-the regions
encompassing Dar es Salaam, Tanga, Moshi, and Arusha-were selected for detailed study. These
four regions collectively account for 75 percent of the energy consumed in the grid-supplied system.
The study was conducted by a team of TANESCO engineers established in a newly formed
distribution planning department. A program was carried out to collect all relevant distribution
system data, such as the conductor sizes and connected loads, and network maps were compiled for
the study areas. The loading patterns at selected locations were measured using a number of
instruments-in particular, electronic loggers capable of storing the required characteristics for
subsequent downloading to a computer. A package of computerized mapping and distribution
planning software was provided to set up the data base and undertake the analysis. TANESCO staff
has mastered the operation of the software and completed the establishment of the digital mapping
data base in all four of the regions included in the study. They are also proficient in operating the
load flow programs that interlink with the data base and have conducted a number of studies using
the software. In addition to these studies, simpler techniques using calculations performed on
computer spreadsheets (see Annexes A and D1) have been used to compute the required
characteristics of all the MV feeders as well as a sufficiently representative sample of LV feeders
in the study regions.



- viii -
25.         The network planning procedure consists of modeling the system to be studied either
using the specialized software package or the spreadsheet methodology and determining operating
characteristics such as technical losses, loading levels, and line voltage drops. Studies were also
made to determine the ability to extend normal supply configurations (to provide alternative supply
sources that can be utilized during network outages). The present situation as well as the network
conditions in future years were studied, and the effects of various development possibilities
examined. The studies were also used to prepare guidelines corresponding to optimum economic
performance levels to facilitate the planning procedures. These guidelines include tables and graphs
(see Annex D2) that can be applied conveniently to determine the operating characteristics (losses
and voltage drops) at various loading levels.
26.         The study has addressed two major long-term goals related to institutional
development. First, the distribution networks that constitute a vast number of segments of lines and
equipment have been collated in a computerized data base that can be updated continuously as
network improvements proceed. Second, TANESCO engineers have been trained in conducting the
required technical and economic analyses. Software and other study aids have been supplied to
predict network performance, such as losses and line-end voltages. In addition, methodologies of
computing economic benefits of proposed development options have been established. The unit
established is expected to continue the task of monitoring the distribution systems in the future and
planning the required developments in a timely manner to maintain the networks at optimal
performance levels. The unit is also expected to play an important role in refining the proposals,
monitoring the work, and updating the computerized data base as the work is implemented.
27.         Sections 8 to 11 of this report deal with the major distribution system development
requirements for the four regions. The proposals presented consist of the introduction of new grid
substations (132/33 kV) and primary substations (33/11 kV) and uprating the voltage of certain
feeders. These efforts are designed to enhance the "bulk supply" function of the distribution systems
and to provide economically acceptable loss levels and reliability standards. The individual
proposals have been subjected to economic analyses, and the related cost/benefit tables are
presented in Annex E. The benefits accounted for are the reduction of losses, the ability to supply
new consumers (where supply restriction existed formerly), and the reduction of outages. When
all three components are evaluated, the benefit/cost ratios generally exceed 5:1. When the latter
benefits mentioned above are not readily quantifiable, the proposals are justified on the basis of the
loss reduction benefits alone.
28.         Section 12 deals with improvements required to the distribution system
supplementary to the major developments dealt with in sections 8 to 11. These requirements consist
of three categories of work:
*     reinforcement of MV systems combined with network rehabilitation,
*     rationalization of LV systems, and
*     system expansion.



- ix -
29.          The reinforcements required in the first category consist mainly in reconductoring
MV line sections presently conductored with gauges too small for the economic dispatch of the load
carried. In addition, some new lines are also deemed advantagous in order to reduce the feeder
routes in the network. Many of the lines to be reconductored are also antiquated and need
extensive rehabilitation. It is for this reason that reinforcement and rehabilitation are conjoined
under the same category of work. The rehabilitation will cover requirements of both the MV and
LV lines (including those which are not being reconductored) as well as requirements at substations
and transformer stations. Rehabilitation-in effect, delayed maintenance efforts-constitutes the
major portion of the costs.
30.          Specific economic analyses to justify rehabilitation efforts is in reality quite
superfluous; if the utility is to remain in business it must keep the existing networks serviceable
enough to supply existing consumers. Also if major maintenance is further postponed, the networks
will deteriorate rapidly, resulting in burnouts and damage to healthy equipment, with potentially
high costs. Finally, no convenient procedures are available to measure the varied benefits of
rectifying delayed or neglected maintenance, and engineering judgment often determines the nature
and extent of rehabilitation requirements. Nonetheless, an analysis of the possible savings of outage
costs that can be achieved by conducting rehabilitation can be gauged from Tables E6.1 to E6.4 of
Annex E for the four regions, respectively. At an estimated outage saving of 1 percent of the power
supplied and a cost of US$1.00/kWh, the benefit to cost ratios are in the range of 7.5:1 to 17.7:1
for the four regions. The net benefits remain positive even if the outage savings are reduced to 0.3
percent of power supplied and valued at US $ 0.75/kWh along with a reduction of the sales growth
rate to 0.04 percent (from 0.08 percent).
31.          The second category of suplementary work (see para 28) is LV rationalization,
required in view of the high losses existing in the LV systems. The loss analysis detailed in section
3 indicates that 45.7 percent of the total power losses and 35.1 percent of the total energy losses
occur in the LV lines. A substantial portion of these losses can be removed by balancing the load
of the three phases. At Dar es Salaam in particular, more than 30 percent of the total LV line
losses can be attributed to unbalanced conditions. The remaining losses can be reduced to
economic levels by introducing a greater number of transformers to reduce the line lengths of the
LV network. Estimated requirements for carrying out this work are included under the LV
rationalization category. An economic analysis using estimated loss savings is provided in Table E7
in Annex E.
32.          System expansion work (identified as the third category of suplementary work in
para 28) is designed to extend the networks to cover new areas that have very promising load
growth potential. These areas are in close proximity to the existing supply systems, and in many
instances unorthodox extensions from the existing networks are already being erected to meet the
pressing demand for power. Each of the new areas to be electrified is being subjected to an
economic analysis (see Table E8 in Annex E) by computing the benefits from expected sales (less
the upstream costs incurred in supplying power to the distribution network). The results of such
analyses for the developments studied in detail so far are presented in the report and indicate very



x -
high returns. The total cost of the areas that require electrification have been compiled based on
presently available data. TANESCO's planning staff will continue the task of designing and
analyzing each individual network expansion proposal and ensure that only the economically
acceptable projects are included.
Total Project Costs
33.            The total costs of the proposed development work in the transmission and
distribution systems are presented below.
Costs of Development Work in Tanzaa's Trnz=m ion and Development Sysems
Costs of Reactive Compensation Requirements                   US$'000
Switched capacitor banks at Ubungo/Ilala                          825
SVS unit at Arusha                                               5,000
10 MVAr reactor at Mbeya                                          200
Shifting of existing reactor from Ubungo to Ras Kiromany           10
Reactive compensation requirements in the distnbution
system (inclusive of 10 MVAr at Tanga)                          175
Contingencies                                             790
TOTAL                                                   7,000
Cost of Distribution System Development
Dar es
Activity                     Salaam    Moshi  Anmsha   Tanga  US$'OOO
MV network development        7,002     1,543    1,332    4,344    14,221
Transmission stns., LV reinf.  3,014    1,279     996    1,544     6,833
Network expansion             5,703     1,088    1,002    2,038    9,831
MV and LV rehabilitation       5,233    1,689    1,568    1,892    10,363
Contingencies                                               1,753
TOTALS                 20,951    5,599    4,879    9,819   43,000
TOTAL COST FOR DEVELOPMENTS
IN TRANSMISSION AND DISTRIB1TION SYSTEMS:                 $50,000



1. INTRODUCTION
Background
1.1         The United Republic of Tanzania is situated on the east coast of Africa, its eastern
coast lying between 20 and 110 south of the equator. -The country comprises a large mainland area
and a number of islands, the largest of which is Zanzibar. Mainland Tanzania, with an area of
about 940,000 square kilometers, is bordered on the east by the Indian Ocean; on the north by
Kenya, Lake Victoria, and Uganda; on the northwest by Rwanda and Burundi; on the west by Lake
Tanganyika, Zambia, Malawi, and Lake Malawi; and on the south by Mozambique. The most
recent census (1988) assessed the population of Tanzania as 23 million, 1.5 million of whom lived
in Dar es Salaam, the nation's largest city and commercial capital. The overall annual rate of
population growth in recent years has been 3A percent, but the rate of urbanization is appreciably
higher. It is estimated that the current (1991) population of Dar es Salaam is about 2 million
persons.
1.2         The economy of Tanzania depends heavily on agricultural products, but there is
some mining activity, primarily in diamonds and other gems, gold, and coal. Significant increases
in industrial output have occurred over the last few years, and tourism is also an important and
growing foreign exchange earner. The per capita gross national product was estimated at
approximately $110 in 1990.
1.3         The Tanzania Electric Supply Company Limited (TANESCO) is responsible for the
generation, transmission, and distribution of electricity throughout mainland Tanzania. Although
TANESCO sends electricity to Zanzibar through an interconnecting submarine cable, power
supplies within Zanzibar are administered by a separate authority, the State Fuel and Power
Corporation.
1.4         Over the past several years TANESCO's operations have suffered from low system
voltages in the eastern and northeastern regions at times of peak demand. This has necessitated
operation of diesel generating plant solely for voltage regulation. Despite the use of thermal
generation. TANESCO has had to curtail supply to certain major consumers and reduce the rate
at which new consumers are added to the system in areas where the distribution lines are
overloaded. System disturbances often result in extensive outages sometimes affecting the entire
network. Consumers who require a stable supply of power are therefore compelled to procure
standby generating equipment. In addition energy losses on the system have increased steadily,
currently exceeding 20 percent of net generation. The effects of these undesirable conditions have
contributed to substantial economic losses to the country as well as to financial constraints on the
company's operations.



-2 -
ESMAP Assistance
1.5         In 1989, TANESCO requested the joint UNDP/World Bank Energy Sector
Management Assistance Programme (ESMAP) to assist in the development of a program of
activities that would improve system voltage levels, reduce overall energy losses and generally
improve the quality of supply to its consumers. Funds provided by the Swedish International
Development Authority enabled ESMAP to respond positively to TANESCO's request and the
study was initiated in October 1989. ESMAP staff and consultants have worked closely with
TANESCO counterpart staff in analyzing the problems and in identifying economic solutions. In
the course of the study extensive use has been made of computerized techniques for power system
mapping and analysis and as a result TANESCO's staff has developed significant skills in these
areas.
1.6         This report describes the results of the studies on the transmission and distribution
systems. Network losses are analyzed and solutions identified for the low voltages in the
transmission system and poor supply conditions in the distribution systems at Dar es Salaam, Tanga,
Moshi, and Arusha, which collectively constitute 75 percent of the total grid supplied load in the
country. The recommendation for the voltage improvement in the transmission system consist of
the provision of reactive compensation to enable the network to be operated at satisfactory voltage
levels until planned transmission system developments can be introduced. The recommendations
for the improvement of the distribution systems contain proposals for the major developments
required to provide supply at economic loss levels and improve the system reliability. They also
cover improvements necessary for the rehabilitation and rationalization of the existing networks in
the study areas as well as system extensions required to provide supply to adjacent areas where
significant urban development is already in progress. A separate report deals with the high
nontechnical losses observed in the system. It describes the efforts made to reduce these losses by
conducting systematic field operations and provides solutions to manage nontechnical losses in the
longer term.



-3 -
2. THE TANESCO POWER SYSTEM
2.1         The majority of mainland Tanzania is supplied from an interconnected power grid.
There are a number of isolated systems supplied by diesel generators but these are very smaU in
comparison to the interconnected grid and account for less than five percent of the electric energy
consumed annually. This report will be concerned only with the interconnected grid system and
especially with the problems of low voltages experienced in the northern and northeast regions.
Map IBRD 22162 shows the geographic distribution of TANESCO's generation and transmission
system.
Generation
2.2          More than 98 percent of annual generation is from six hydroelectric stations with
aggregate rated capacity of 327 MW, as shown in Table 2.1 below.
Table 2.1
Station                River               Rated Capacity
(MW)
Kidatu                 Great Ruaha         200
Mtera                  Great Ruaha         80
Hale                   Pangani             21
Pangani Falls          Pangani             17
Nyumba ya Mungu        Pangani             8
Kikuletwa              Pangani             1
2.3         There are a number of diesel stations and a single gas-turbine generator (not in
operation at present) connected to the grid but these are normally used only for emergency
generation or voltage support. The aggregate rated capacity of thermal generating units on the grid
system is about 100 MW. The capacity available at the end of 1990 was only about 30 MW. Since
then a program of rehabilitation of the thermal station at Ubungo, adjacent to the major
220/132/33/11 kV substation supplying Dar es Salaam has increased the available capacity by a
further 31 MW (with all six diesel units rehabilitated).



-4 -
Transmission
2.4         Figure B4 of Annex B is a one-line schematic of the transmission system, which
consists of lines operating at 220, 132 and 66 kV. Over three quarters of the power generated is
transmitted by the single circuit 220 kV line (of 132 km) running east from Kidatu to Morogoro.
Bulk of the load continues eastward thereafter on a single circuit line (of 178 km) to the principle
load center, Dar es Salaam. The remaining power is transformed to 132 kV at Morogoro and a line
operating at this lower voltage runs parallel to the 220 kV line between Morogoro and Dar es
Salaam. This line has a switching station approximately mid way at Chalinze from which the north
eastern network is supplied. Areas in Western Tanzania are supplied from a separate 220 kV
system by lines running from Kidatu and Mtera to Mbeya on the southwest and Mwanza on the
northwest. The north western network also has two 132 kV spurs supplying Tabora and Musoma.
2.5         The 132 kV system is the backbone of the transmission grid north of Dar es Salaam,
with a line extending from Chalinze through Hale to Moshi and Arusha, with a spur from Hale to
Tanga, the second largest city of Tanzania. All generating stations on the Pangani River system
feed into this 132 kV network. The TANESCO grid is interconnected with that of Zanzibar at 132
kV through overhead lines on land and a submarine cable from Ras Kiromany on the mainland to
Ras Fumba in Zanzibar.
2.6         The only 66 kV line currently in regular operation is that between the Nyumba Ya
Mungu generating station and the 132/66 kV substation at Kiyungi near Moshi. The 66 kV
interconnection between Kiyungi and Arusha is still operable but since the completion of the
Kiyungi/Arusha 132 kV line the 66 kV circuit is not normally energized. Subtransmission lines
operating at 33 kV emanate from the grid substations shown in Figure B4 (Annax B) and are used
to energize distribution substations as well as to supply certain consumers directly.
2.7      . All transmission lines are of single-circuit construction with limited or no supply
alternatives in the event of unavailability of any one line.
Distribution
2.8         In city areas the majority of primary distribution lines operate at 11 kV with the
secondary voltage being 400 V three-phase or 230 V single-phase. 33 kV is used as a
subtransmission voltage for bulk supply to distribution substations, but some distribution
transformers and major consumers are also directly energized from this voltage. In rural areas 33
kV forms the bulk of the primary distribution voltage.



-5-
Consnmers and Demand
2.9          At the end of 1990 TANESCO had approximately 155,300 consumers with annual
average energy consumption of about 10,000 kWh. The peak system demand was 264 MW. As is
shown in Table 2.2 below, peak demand and annual energy consumption over the past five years
have been increasing at an average annual rate of 11 percent. The number of consumers in Dar
es Salaam and its immediate environs at the end of 1990 was about 70,000 with a peak demand of
approximately 100 MW and annual consumption of 590 GWh.
Table 2.2. Power and Energy Demand TANESCO Grid System,
1984 to 1990
11985    11986        1987    11988    11989    11990
Peak demand MW         176        183        200       219        253        264
Generation GWH         915        1041      1169       1303       1436       1565
Sales GWH              696        822        871       1005       1110      1254
Consumers 000s         126        133        111        129       144        155
Losses GWH             219        219        298       298        326        311
Losses (% gen)         24.0       21.0       25.4       22.9      22.7      19.9
% inc. Peak                        3.9       9.4       9.5        15.5       4.4
% inc Gener/n                     13.8       12.1      11.5       10.2       9.0
% inc Sales                       18.2       6.0        15.3      10.5      13.0
% inc. Consu/m                                          16.0      12.0       7.6
Note:  There are number of inaccuracies in the data compiled at TANESCO and the figues should be taken to represent
appraximate values. The consumer records were adjusted in 1987 resulting in the removal of a number of 'dead'
accounts.
System Operations
2.10         Since the mid-1980s, TANESCO's operations have been handicapped by low system
voltages in Dar es Salaam and areas in the northeast. At times of peak system demand that
normally occurs between 9 a.m and 3 p.m. in the daylight hours and 6 and 9 p.m. in the evening (see
Figure 3) the voltage on the 220 kV busbars at Ubungo, the 220/132 kV substation supplying Dar
es Salaam, falls to 175 kV or less. At Arusha in the northeast it is necessary to run the diesel



-6-
generating units and in addition shed certain loads at times of peak demand in order to maintain
system voltages. Even then the voltage conditions are below acceptable levels. The long and
relatively lightly loaded transmission lines in the west limit the level to which the voltage on the
generator busbars at Kidatu and Mtera can be raised without resulting in unacceptably high voltages
at the peripheral grid substations.
2.11        The low-voltage conditions on the transmission system in Dar es Salaam and other
areas in the east are compounded by overloaded distribution circuits. Many consumers frequently
experience single-phase supply voltages of less than 180 volts instead of the nominal 230 volts. The
overloaded distribution circuits are, in part, the result of inadequate distribution planning and the
fact that investment in distribution over the past decade has not been commensurate with the
increase in consumer demand. TANESCO has had to restrict the rate at which it adds new
consumers to the system in certain areas of Dar es Salaam because of the overloaded condition of
existing distribution circuits. The overloaded distribution lines and poor power factor control by
some consumers have contributed to a steady increase in system energy losses. As can be seen from
Table 2.3 above, system losses have remained at a high level (around 20 to 25%) in spite of two
major distribution development projects undertaken during the last five years. However not all of
these losses are due to overloaded lines or other technical considerations. A significant proportion
is due to the failure of the metering and billing system to capture all of the units consumed.
2.12         The low voltages experienced in the high load-density areas of eastern and
northeastern Tanzania often result in lost production and equipment damage. The high voltages
in the western areas place undue stress on consumers equipment and are believed to have resulted
in failure of a number of grid substation transformers. Inadequate investment in the distribution
system not only increases losses and restricts the rate at which consumers are added to the system
as previously mentioned but also contributes to poor physical condition of much of the distribution
plant. In consequence certain areas experience frequent supply outages many of which are of long
duration.  The various undesirable characteristics of current operations on TANESCO's
transmission and distribution systems cause substantial economic loss to the country as well as
financial penalties to TANESCO itself.
System Expansion
2.13         TANESCO's system expansion plans are based on a study undertaken by the
Canadian consultants Acres International and completed in 1985. The demand forecasts have since
been revised regularly by TANESCO and Acres, most recently in 1990. The projected demand for
the period 1991 to 2005 is as shown in Table 2.3.



-7 -
Table 2.3. Forecast of Power and Energy demand upto 2005
IActal<                                Projected
1990    1991     1992    1993    1994    1995        1996     1997    2002
Peak         264      297      325      352      373     395      416      438      569
Demand
(MW)                                                                                        l
Annual        1254    1395     1507    1614    1722       1842     1977    2118    2853
Energy
(GWh)
Annual        13.1     11.2    8.0       7.1     6.6      7.0      73       7.1       -
Growth (%)                                      __I I_I          __I__I_
Load Factor   67.6    66.6    66.0    65.0    65.0        65.0    65.0    65.0    65.0
Note:  The 1990 values represent actual system perfornance. The values for other years are projected. The figures for 1991
have still not been finalized by TANESCO.
2.14           It is seen that the high load growth over the last few years are expected to continue
though at a slightly reduced rate. There is also a good possibility that TANESCO will experience
a more rapid increase in demand than is currently projected.
Generation Expansion
2.15           TANESCO's plans to increase generating capacity in the period 1991 to 2000 are as
follows:
*      To undertake further rehabilitation of the diesel plant in the western parts of the
grid system to provide an additional 20 MW by 1994.
*       Redevelopment of the Pangani Falls site to provide an increase of 49 MW  in 1995
*      Construction of a new generating station on. the Kihansi River (the Lower Kihansi
plant, near Iringa) to provide 150 MW in 1998.
2.16           Comparison of planned investment in generation with projected demand indicates
a severe capacity shortage if any large generating unit should be out of service over the period
beyond 1992. This situation would be compounded in the event of unfavorable hydrologic
conditions, especially in the Great Ruaha/Kihansi watersheds. Adverse rainfall conditions in the
catchment areas combined with the non availability of hydro generation units have in fact caused
large scale load shedding during many periods in 1992.



-8 -
Investments in Transmission
2.17        From now until 2000 TANESCO plans to invest in two major transmission projects.
The first is a second 220 kV line (300 km) from Kidatu to Dar es Salaam (probably to a new
substation site and not Ubungo) via Morogoro. Construction has already begun for the section
Kidatu to Morogoro.  Funds are still being sought for the section from Morogoro to Dar es
Salaam, which is planned to be in service by the end of 1994. The second major investment in
transmission will be the Singida to Arusha 220 kV line (about 280 km) expected to be completed
by the end of 1995.
Improvements in Distribution
2.18        TANESCO is currently developing plans to rectify the effects of past inadequacies
in investment in the distribution systems and to be well positioned to meet the consumer demands
of the future. The current ESMAP study will provide the required assistance in determining the
investments at the major load centers of Dar es Salaam, Tanga, Moshi and Arusha. TANESCO is
independently developing distribution plans for the other service areas. Investment financing is
expected from a new World Bank (International Development Agency) power credit as well as from
bilateral financial agencies.



-9 -
3. ANALYSIS OF SYSTEM LOSSES
3.1          A power system can be divided conveniently into a number of sections in accordance
with the voltage of operation. All major generation stations feed into the transmission system,
which in the case of TANESCO consists of a radial network of 220 kV and 132 kV lines. At
present, only one load (the power supply to Zanzibar) is supplied directly at the transmission
voltage. Grid substations on the transmission system located at major load centers transform power
to 33 kV, and feeders at this voltage are used as the first stage of the distribution system. Some
of the larger loads are supplied from the 33 kV lines, while others are fed directly off transformers
connected to these lines. 33 kV lines are also used to provide supply to rural areas with 33 kV/LV
transformers supplying the low voltage networks. The remaining load undergoes a further
transformation at primary substations (33 kV/11 kV) resulting in an additional system voltage of
11 kV. Part of the load supplied is fed at the same voltage (11 kV) to larger consumers; a second
part is supplied to consumers directly from step down transformers at low voltage; and a third part
is carried along LV lines and supplies the rest of the consumers. Consumers supplied at 33 and 11
kV are classified as medium voltage loads. Those supplied at LV are considered as bulk LV loads
if fed directly off transformer stations and as retail LV load if fed from the LV lines. The system
consists of a hierarchial structure as shown in Fig. 3.1. A substantial portion of the total network
load flows along the 11 kV and LV systems.
3.2          Technical losses on the system occur in all sections of the network. Almost the
entirety of these losses are caused by the heating effect of an electric current when flowing along
a conductor. The exception is the losses caused in magnetizing transformer cores. In addition to
the network losses described above, losses also occur at power stations due to the consumption of
auxiliary equipment as well as losses on generator transformers. The overall losses (inclusive of the
losses in generation stations) are termed gross losses, while the portion of the losses that occur in
the transmission and distribution networks are considered as net losses. In the present exercise we
will concern ourself with the analysis of net losses, that is, those occurring in the transmission and
distribution systems.
3.3          Power supply systems also contain nontechnical losses. These losses are caused by
deficiencies in billing and meter reading as well as by consumption not captured by meters. The
difference between units sent out of the power stations and units sold (as appearing in the billing
statement) are the net system losses consisting of the sum of the two components, technical and
nontechnical losses described above. The present report deals with the technical component; a
complementary report is being issued regarding nontechnical losses.l/
1/      This Report is entitled Tanzania: Reduction of Nontechnical Losses.



- 10 -
3.4          The load at various sections of a power network can be expressed in power demand
(MW) as well as in energy (MWh) terms. Similarly, system losses are also expressed in power
(MW) and energy (MWh) terms; the energy loss being the integration of the power losses over the
relevant time period. The ratios of the average to peak values for the power demand and power
loss are termed the load factor and the loss factor respectively; the relationships between the
various parameters are provided in Annex D. During the study an extensive measurement program
was conducted using electronic instruments capable of recording and storing the required power
flow characteristics and subsequently downloading these measurements to a computer. One of the
instruments used, the DIP 6000, uses three clip-on current transformers and three voltage
transducers to record the current, voltage, power factor and power values of three phase networks.
Two others, the load logger (which can be placed on overhead lines) and the load profiler records
the current of individual phase conductors. All the instruments can be programmed to perform
measurements at pre determined intervals and are also supplied with software to facilitate down
loading the data and performing analyses of the results.
3.5          The program of power flow measurements carried out included all the 33 and 11 kV
feeders in the study area as well as a representative sample of low voltage (LV) feeders and
distributors. Some typical results of daily loading profiles and other characteristics are given in
Annex A. These results provided values for the load factor and loss factor of individual feeders as
well as for network components at various operational levels. These values have been used when
necessary to convert the power and power loss figures to energy and energy loss terms in the
various computations appearing hereafter.
Network Losses in the Distribution System
3.6         In contrast to the transmission system, distribution networks contain an extremely
large number of line sections and the building up of the necessary data base as well as its modeling
for analysis is far more complex. An important initial step has been made by introducing computer
programs to build up a data base and conduct the required system studies for the distribution
networks (see Section 7 for a description of the software provided). During the course of the
project significant progress has been made in establishing the data bases and performing studies in
limited areas of the network. This work is continuing and the study team established is expected
to complete modeling the medium voltage distribution systems in the entirety of the Coastal and
North Eastern Zones (consisting of the cities Dar es Salaam, Tanga, Moshi, Arusha as well as the
associated peripheral areas) by end 1992. However, in order to obtain an early assessment of the
existing technical losses in the system an approximate methodology (as explained in Annex D1) has
been developed and applied in parallel with the more exhaustive computer applications. This
procedure has been used to compute the line losses and terminal voltage drops of all medium
voltage networks in the study areas for three typical loading conditions consisting of peak, mid and
base load. A similar study has been made on a sample of LV systems in the four regions. The
sample consisted of a total of 105 transformer stations having 367 distributors and is therefore
considered to be sufficiently representative of the total LV network. Sample results of these



- 11 -
studies are presented in Annex A. The losses and voltage drops have been worked out for the 1991
year loads as well as the expected load in 1995 with no developments made to the existing system.
The calculations have been repeated with the proposed system developments described in sections
8 to 11.
3.7             The results of the power loss studies for both MV and LV systems indicate a wide
diversity of performance among the various feeders. Summaries of the total losses obtained for
each region are presented in Tables 3.1 and 3.2 below:
Table 3.1. Total Power and Energy Losses in Percent of Input at Each Voltage
Level, 1991 Loads
Dar-es- Tanga Tanga   Tanga whole
Salaam  Town  District  Region   Moshi Arusha
1) 33 KV lines
Power losses  2.0    2.20   130      1.91      3.80    3.7
2) 33 KV lines
Energy losses 1.50    1.65   2.38    1.43      2.90    2.8
3. 11 KV lines
Power losses  2.80    1.80   2.61    2.04      3.00    5.7
4. 11 KV lines
Energy losses 2.10   135   1.96      1.50      2.30    4.3
5. LV lines
Power losses  8.90    -     -        7.80      1.04    6.5
6. LV lines
Energy losses 6.20    -     -        5.50      0.72    4.6
Table 32. Total Power and Energy Losses in Percent of Input at Each Voltage
Level: 1995 Loads with existing system configuration
Dar-es- Tanga Tanga   Tanga whole
Salaam  Town  District  Rezion   Moshi Arusha
1) 33 KV lines
Power losses  236    2.6    1.6      2.1       4.46    435
2) 33 KV lines
Energy losses 1.77    1.95   1.2     1.58      3.34    3.26
3. 11 KV lines
Power losses  3.83    2.20   3.08    2.44      3.55    6.37
4. 11 KV lines
Energy losses 2.86    1.65   231     1.83      2.66    4.77
S. LV lines
Power losses  1035    -     -        9.07      121    7.56
6. LV lines
Energy losses 7.21    -     -        632       0.84    5.27



- 12 -
3.8            The percentage losses provided in Tables 3.1 and 3.2 are based on the input power
at the respective voltages. These percentages can be converted to the base of the input power and
energy of the total system by consecutively accounting for the loads and calculating the losses along
each section of the network hierarchy (described in para 3.1 and shown in Figure 3.1). Such an
analysis has been conducted for the distnbution system using the monthly billing data for the year
1990 for the four regions and is presented in Table A4 in Annex A In this analysis the maximum
demands (kVA) recorded in the various tariff categories have been converted to peak loads by use
of estimated coincidence factors and the consumption of retail units (where the kVA demand is not
recorded) has been converted using an estimated overall load factor. The estimated figures have
been derieved from the data collected from field measurements and the total demand figures have
been reconciled with recorded values thus indicating a good degree of reliability for the results
obtained. Thereafter the average values for power and energy losses at various voltage levels
(presented in Table 3.1) have been used to develop a hierarchial power and energy flow table
consisting of the loads and losses occurring at each level in the network. Finally the losses and
loads at each voltage level are expressed as percentages of the input to the distribution system. A
summary of the results of these tables is presented in Table 3.3 below. Charts indicating the
comparative losses of the four regions, the total sales and loss breakdown and the breakdown of
overall distribution losses are presented in Figures 3.2 to 3.4.
Table 3.3. Distribution Network Losses in Percent of Input to Distribution System
FOR ALL 4  DAR ES  TANGA   MOSFI ARUSHA
R8GNS SALAAM
PCWER LOSSES
33 kV line loss   2.26    2.00    1.20    3.79    3.70
SS T/f loss   1.22    1.26    1.02    1.18    1.21
t1 kV line loss   2.44    2.32    1.34    2.32    4.53
LV t/f loss   1.16    1.19    0.88    1.31    1.19
LV line loss  5.97    6.22    4.42   7.61    4.74
Sum of losses   13.05   12.98    8.86   16.22   15.36
B'ENPGYLOSSES
33 kV line loss   1.69    1.50    0.90    2.85    2.77
SS T/f loss   1.14    1.18    0.75   z1.34    1.22
11 kV line loss   1.74    1.63    0.74    1.98    3.42
LV t/f loss   1.00    1.01    0.86    1.17    0.97
LV line loss  3.02    3.26    1.96    3.67    2.41
Sum of losses    8.59    8.58    5.21   11.00   10.80
3.9           An examination of the distribution system losses developed above indicate that the
overall network loss levels for the medium voltage feeders are not excessive (particularly in
comparison to those in many developing countries). The low loss values in many parts of the
network is the result of two major distribution development projects carried out recently. However,
there still remains a number of feeders where the loss levels are considerably high. Further with the



- 13 -
expected load growth between now and 1995 the situation will worsen considerably unless corrective
action is undertaken. A number of system improvements to reduce losses in areas where they are
exceptionally high have been formulated in sections 8 to 11. A particular difficulty that TANESCO
faces is that it can not often mobilize the funds (particularly foreign exchange) necessary to
undertake development requirements in a timely manner. It is therefore very necessary to ensure
that all necessary steps are taken to limit the time delays associated securing the necessary financing
facilities.
3.10        The sample studies conducted for the low voltage systems indicate that the network
losses in this section of the network is exceptionaLy high. The average peak losses for LV networks
in the four regions yielded results between 6.5 and 10.5% of the input power. The LV line losses
together with the transformer losses exceeded half the overall distribution system peak losses. In
energy losses too this figure came close to the half mark (46.7%, see Fig. 3.4.). Clearly this is an
area where considerable loss reduction inputs are required. One major factor is the high unbalance
existing in many of the schemes studied. The losses due to line unbalance is exceptionally high in
Dar es Salaam and Tanga where savings as high as 30 and 20% of the existing losses can be realized
by undertaking a program of load balancing, without incurring any capital investment. The other
major loss reduction improvement required in the LV networks is the introduction of a substantial
number of additional distribution transformers to reduce the LV line lengths. A program of
transformer replacements and interchanges need also to be carried out to enable more efficient
loading levels to be achieved (to optimize transformer losses). TANESCO should also change its
present practice regarding transformer purchases by including the evaluation of lifetime cost of
losses thereby ensuring that low loss transformers are secured in the future. These developments
are discussed in section 12.
Transmission System Losses
3.11        Losses in the transmission system can readily be obtained by the results of the load
flow studies conducted. Section 4 discusses these studies and Annex B presents the results of the
computations made. Typical peak, mid and base load flows for each year from 1991 to 1998 have
been performed. In order to calculate the energy losses a simplified load duration curve consisting
of 25% of average peak load, 42% of average mid load (taken at 80% of peak) and 33% of base
load has been assumed. While the peak and base load values have been taken direct from the
results of the studies, the mid load values have been estimated by reference to load flows conducted
with similar operating conditions. These results are presented in Table 3.4 below:



- 14 -
Table 3.4. Transmission System Losses in Percent
Mid- Base-
Year Proposed Developments  Peak LoadLoad
1991                      8.0  3.0  5.5
1992                      9.0  3.0  4.7
1993 Kidatu-Morogoro 2nd cct. 5.8  3.5  4.4
1994                      6.0  3.8  4.8
1995 Morogoro-Ubungo 2nd cct. 5.5  4.0  4.3
New Pangani P.S.
1996 Singida-Arusha Line  5.0  4.0  4.2
1997                      5.4  4.2  4.4
1998 Kihansi P.S.         6.2  43  4.6
3.12          The results indicate a number of step changes to the loss levels that occur with
various network developments introduced. System losses decrease with the transmission
developments of the second circuit to Dar es Salaam and the Singida-Arusha connection as well as
the New Pangani Falls power station. Peak losses decrease in certain years due to thermal
generation inputs (supplied at Ubungo, the main load center) to meet the hydro power deficit.
With the commissioning of the Kihansi project the necessity of thermal generation is removed and
the power flow along the Kidatu-Morogoro-Ubungo lines is increased resulting in higher
transmission system losses. The introduction of reactive compensation (proposed in this report)
at IJbungo will also contribute to substantial loss reduction both before 1995 and after 1998.
Loss Analysis for Total System
3.13          The present level of network losses derived for the transmission system and the load
supplied at this level (to Zanzibar) has been combined with results of the distribution system power
flow developed (in Table A4 of Annex A) to obtain the overall network power flow and system
losses based on net generation (ie. input to the transmission system). For this purpose the
percentage figures obtained for supplies and losses for the four regions studied are assumed to
represent the entire grid supplied distribution system. Summary information from this table is
provided at Table 3.5. It is seen that line losses of transmission and distribution systems are
approximately of equal significance. The results of the above loss analysis for the total system
(based on net generation) is also presented in Fig. 3.5.



- 15 -
Table 3.5. Breakdown of System Losses and Supplies by Voltage Level
POWER                       ENERGY
Values Expressed as % of:-   Values Expressed as % of:-
Total                        Total
Net Gen    losses            Net Gen    losses
BREAKDOWN OF LOSSES
132 kV loses             8.00    41.52                4.00    34.85
33 kV line loss          1.98    10.27                1.50     13.03
SS tUf loss              1.03     5.36                0.97      8.43
11 kV line loss          2.06    10.71                1.50    13.03
LV t/f loss              1.03     5.36                0.88     7.66
LV line loss             5.16    26.78                2.64    22.99
SUM of Losses           19.27    100.00              11.48    100.00
Total transmission       8.00    41.50                4.00     34.85
Total Distribution      11.30    58.50                7.50     65.15
BREAKDOWN OF SUPPUES
132 kV Supplies         5.91      7.32                8.11     9.16
33 kV Supplies           8.86    10.97               12.49     14.11
11 kVSupplies            5.50     6.82               12.58    14.21
LV Supplies            60.46     74.89               55.34    62.51
SUMofSupplies          80.73   100.00                88.52    100.00
Total losses + supplies  100.00                     100.00



- 16 -
Figure 3.1
POWER SYSTEM SUPPLY HIERARCHY
N=KQzki components   -   Sources gf losses    Slies         'e
Power station generators   generator axiflaries
W   Generator transformers     transfonner losses
transmission
O                  *           system Iosses
E                                                   IIYHV consumers
(Zanzibar)
_   Grid Substation
transformers               transformer losses
220 or 132/33 kV
33 kV line
losses
33 kV
consumers
E
C  Primary Substations        transformer losses
33/11 kV
11 kV line
. ~    _losses
11kV
consumers
Supply transformers        transformer losses
33 or 11 kV/400V
LV line
losses
LV
consumers



- 17 -
Figure 3.2
0.080
0.070                                                               U 33 kV line loss
0.060 -     
0.050                                             C~~~~~~~~~~~~~~~~Ss T/f loss
0.030   ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~*~LV line loss
0.020-
0.000
TOTAL      DAR ES      TANGA       MOS1       ARUSHA
Distribution System Peak Power Losses (expressed as % power input at 33kv).
0.040
0.035
*33 kV line loss
0.030
0.025                                                                  Ss 5  TIf loss
0.015 - ~~~~~~~~~~~~~~*LV V/f 'loss
0.0 10 
0.005   ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~2LV line loss
0.000
TOTAL      DAR ES      TANGA       MOSH       ARUSHIA
Distribution System Energy Losses (expressed as % energy supplied at 33 kv).



-18 -
2.26%                      Figue 33
*33kV linlot"
or 33 kV Supplies                                  2omn
*Ss Td? loss
IE  avs rw loss
1I kcV Supplies
1.16%
OLV Vt' loss
LV line loss                                                                              5.96%
3 LV Supplies
Distribution System Peak Power Supplies and Loss Composition
(expressed as % power  input at 33kv)
1.69%
*33 kv rwe loss
CD 33 kV Supplies114
*SS TI loss                                                                            1.74%
11I kV line loss
II kV Supplies
0v LV f loss
14.31%
LV line loss
IILv supplies
62.88%
Distribution System Erler2y Supplies and Loss ComDosition
(expressed as % e-nergy supplied at 33 kV)



-19 -
Figure 3.4
j   j  g          t~~~7,35%
\33 kV line loss
9.32%       Ss Tf loss
1 1: kV line loss
,  LV t/f loss
LV Iine loss
8.89%  't) ;'¢ ~ 18.73%
Compositioa of Peak Distribution Losses by Category
(expressed as Z of total Distribution System Power Loss).
19.71%
35.11%                                              *33 kV line loss
ESST/f loss
* 11 kV line loss
13.26%
- LV tUf loss
- ........ ...... . :/ El  LV  line  loss
~~~~~~~~~~~... ...  ......    . ,.
11.67%                   2025%
Composition of Energy Losses by category
(expressed as % of total Distribution System Energy Loss).



- 20 -
Figure 3.5
OVERALL SYSTEM NET POWER LOSSES
26.78%                             
*132 kV loses
41.52%      0 33 kV line loss
. ~ ~~~~~~~~~~~~~~~~~~ 1 kV line t loss
5.36%                                                               LV t/f loss
||  |   t       _                       E] ~~~~~~~~~~~~LV line loss
10.71 
5.36%         10.27%
NOTE: Total power losses amnount to 19.3 % of net generation
OVERALL SYSTEM NET ENERGY LOSSES
34.85%           132 kV loses
7.66%             K                     K                                 line 
8.1114i 1 3%m                               LV t4f loss
111 l  I_  l        7                   B ~~~~~~~~~~LV fine loss
13.03% ' i t l [~/3.03%
8.43%



- 21 -
4. REACTIVE COMPENSATION FOR THE TRANSMISSION SYSTEM
Background
4.1         At present the transmission system is severely overloaded in the east and northeast
sections leading to very poor voltages at the main 220/132 kV receiving station at Ubungo (Dar es
Salaam) as well as at the peripheral substations of Tanga and Arusha. The extent of the voltage
depression experienced at day and night peak loads can be seen from Figures 4.1 and 4.2, which
indicate the voltage readings obtained on a typical week day at the substations at Ubungo and
Arusha. This depression of voltage at the substations is a principal cause of the low system voltage
existing in the distribution system. In contrast to the east and northeast sections the network in the
west is comparatively lightly loaded and care must be exercised to prevent the voltage at the
extremities exceeding safe limits. For this purpose a number of reactors (both switchable and
directly connected) are installed at seven of the nine substations in the west. The dangers of
possible high voltage in the west further complicate the control of the voltage conditions in the east
and northeast.
4.2         TANESCO's current plans to redress the transmission system deficiencies of the east
and north east are as follows:
*     Construct a second circuit 220 kV line from Kidatu to Dar es Salaam via Morogoro
(the contract for the first section, Kidatu to Morogoro has already been awarded and
the line is expected to be commissioned by early 1993; funds for the second section
Morogoro to Dar es Salaam are presently being sought and the line is expected to
be in service by January 1995).
-     Construct a 220 kV connection between Singida in the north west and Arusha in the
north east (expected to be in service by 1996).
The above developments have been selected after studies carried out by TANESCO's
consultants ACRES International and represent the long term least cost solutions among the
limited options available. However, these proposals by themselves and at the commissioning dates
presently feasible are insufficient to resolve the poor voltage conditions that would continue to be
experienced for some time.
4.3         Load flow studies on the transmission network were therefore conducted in order
to examine possible short and medium term solutions for the rectification of the voltage control
problems. Normally the maximum load on transmission lines occur at times of system peak load.
However in some situations the most severe loading conditions are experienced at other operating
periods. Such situations occur in the TANESCO network when the thermal generation
requirements to meet the hydro shortfall results in a lower transfer of power along the main



- 22 -
transmission lines at peak times than at other operational periods. The studies have therefore
covered a number of such operational periods. Consideration has also been given to exigencies such
as the outage of transmission lines supplying important load centers. It is seen from these studies
that network voltages can be considerably improved by introducing reactive compensation at certain
line extremities.  A further benefit of reactive compensation is the reduction of losses in the
network. The studies presented in this section therefore seek to determine the best possible
application of reactive compensation measures to improve the transmission system voltage levels
and obtain loss reduction benefits.
Methodology for Load Flow Studies
4.4         The performance of the transmission network during various future periods will vary
considerably according to the addition of various generation and transmission developments as well
as with the expected load growth. For this reason and in order to establish the usefulness of the
reactive compensation measures to be employed over a reasonable period load flow studies have
been performed yearly from 1991 to 1998. Some studies beyond these years have also been done
particularly to assess the impact of possible export of power to Kenya. As discussed in para 4.2
above, studies have been performed to represent system performance at maximum system peak for
the various years as well as at lower loading conditions. Table Bl of Annex B report provides the
expected yearly maximum loads for the total system as well as the distribution of the loads at each
grid substation. The import/export requirements indicating the power transfer conditions between
the various load and generation centers in the system are also presented in this table. The overall
load forecast tallies with the present forecast in use by TANESCO (prepared by ACRES) and
represents an average annual load growth of around 6.75%. Transmission line data including
impedances used in the study are provided in Table B2 of Annex B. In performing the load flow
studies the range of bus voltages considered acceptable for technically satisfactory operation was
chosen to be between +5% and -5% of nominal voltage. An exception was made for the Ubungo
220 kV bus voltage, which was allowed to drop to as low as -10% in view of the possibility of
keeping the 132kV bus voltage at about -5% by use of the tap-changing facilities of the 220/132 kV
transformers. Three other 220/132 kV transformations are used in the system; these being at
Morogoro, Shinyanga and Mwanza. The latter two locations do not present any particular problem
as any fluctuations on the 220 kV system can be accommodated by small variations of the
tapchanger from the standard position. In Morogoro the 220 kV voltage will be higher than at
Ubungo. Further the chief concern here will be the necessity to maintain the 132 kV side voltage
as high as possible due to the need to maintain voltages along the Chalinze-Hale-Arusha line. Thus
no special voltage conditions need to be applied for the 230/132 kV transformers other than the
one at Ubungo. For all 220/132 kV transformers the tap changer operating range allowed was +/-
6% of nominal and a suitable selection within this range was used to obtain the best possible
operating conditions.
4.5         The best candidate locations for applying reactive compensation are the heavily
loaded line extremities. In the TANESCO transmission system these locations are found at Dar



- 23 -
se Salaam (the extremity of the eastern radial) and at Arusha and Tanga (the extremities of the
north eastern radial). Once the overall requirements at or close to these two locations are
determined consideration should be given to their distribution among adjacent substations. The
extent of the such distribution will depend on the total capacity required as well as the operational
demands on the compensators. Thus in the discussion hereafter the reactive compensation
requirements are indicated by their principal locations, Ubungo and Arusha. After finalizing the
overall quantities required, consideration will be given to operational aspects as well as secondary
advantages and recommendations will be made as to the distribution of the compensation to be
applied among adjacent locations. Thus the requirements indicated in the following discussion at
Arusha may in fact be distributed between Arusha and Moshi and the requirements indicated at
Ubungo may in fact be distributed between Ubungo and Ulala (the second step down station, 132/33
kV, in Dar es Salaam). Further it should be noted that the existing capacitors in the system (5
MVAr at Moshi and 2.5 MVAr at Arusha) are included within the quantities provided in the
various load flow results.
Preliminary System Improvements
4.6         At the commencement of the study two operational measures were identified to
improve the poor voltage conditions experienced at peak load. The first consist of the installation
of a circuit breaker to control the operation of the 20 MVAr reactor installed at Ubungo to enable
this reactor to be switched off during normal operation and introduced only when required at very
low load (see also para 4.11). The second measure consist of adjustments to the generator
transformer tap possitions at Kidatu in order to raise the 220 kV voltage at this station to a higher
value. Both these measures were put in practice during the study resulting in incremental
improvements -to the voltage profile.
4.7          Certain other improvements requiring minimal capital investment can also be
effected to rationalize and improve the performance of the existing system. It is necessary to
address such possibilities prior to undertaking an analysis to determine the extent of major reactive
compensation requirements (at the east and northeast system extremities). Consideration could
then be focussed on the direct benefits of the main reactive compensation proposals after allowing
for improvements that are possible to be achieved by other means. The various measures that could
be employed in this respect are discussed below:
Reducing the Voltage Rise in the Western Section of the Network
4.8         As discussed earlier, the line voltage in the northwest (extending up to Musoma) and
the southwest (extending up to Mbeya) will rise to unacceptable levels unless the reactors installed
are switched on and the Kidatu and Mtera bus voltages are restrained. It is thus appropriate to
examine if this restriction on the increase of the generation station voltages could be relaxed. This
is particularly so since a higher voltage at Kidatu will reduce the reactive compensation
requirements at Ubungo by allowing for a greater voltage drop. With respect to the compensation



- 24 -
requirements at Arusha the Ubungo voltage is not so critical as the tap changer at Morogoro as well
as the generation at Hale will allow the voltage to be raised at these intermediate points. However
during the initial years (until the new Pagani power station is introduced) when the generation at
Hale is sometimes insufficient to allow for the maintenance of the maximum desired voltage and
the drop in the Kidatu-Morogoro section is excessive the rise in the Kidatu voltage does have a
positive effect on the compensation requirements at Arusha too.
4.9          Under normal peak load conditions, the Kidatu voltage can be raised to about 1.03
p.u. without causing the peripheral station voltages in the north and south western sections to
exceed the upper limit of 1.05 p.u. However there are some particular circumstances that cause
concern in keeping to such a voltage level. These aspects are discussed below:
*     Three diesel generation stations Nayakato (13.5 MW, connected to Mwanza),
Mwanza South (4.5 MW), and Mbeya (10 MW) are connected to the grid in the
southwest section. When thermal generation is required to meet peak shortages
these stations will need to be operated. In fact during the early period of 1991 much
of the peak period diesel generation (required due to the unavailability of a machine
at Kidatu) came from the station at Nayakato. Such local generation will reduce the
loading on the 220 kV lines and result in considerably high voltages at the grid
substations of Mbeya and Mwanza if the Kidatu voltage is also maintained at a high
level.
*     The loads in the southwest are mainly dependent on two large industrial loads, a
paper mill and a cement factory. Quite often either or both the factories are not in
operation. At such times the loading on this section is very light when the rest of
the system experiences peak load conditions. A saturated reactor providing variable
output up to 30 MVAr is available at Mwanza. However the reactor is designed to
maintain a constant voltage at 11 kV to the paper factory and the output cannot be
varied as required by the grid operating conditions.
*     A situation similar to the abnormally low loads discussed above is that caused by the
tripping of large loads. Since the loads at both the northwest and the southwest
consist basically of a few large load concentrations, tripping of 33 kV feeders or grid
substation loads will cause sharp voltage rises that can be detrimental to equipment
connected to the system. In fact, there has already been instances of damage to grid
substation transformers due to core saturation caused by exposure to high voltages.
A particular problem has also arisen at Mbeya where the transformers were found
to be inadequately designed to withstand high voltages.
4.10         The reactors presently installed in the system as well as the dispersed nature of the
loads do not cause such serious concerns in the north west. In the south west however the only
reactor connected at Mwanza (whose output is controlled by the paper mill load) is insufficient to
effect the necessary control. It is therefore proposed that a 10 MVAr switchable reactor be



- 25 -
installed at Mbeya. Load flow runs conducted with such a reactor at Mbeya indicates that the
voltage rise can be effectively controlled. For example, the 1991 peak load flow with 1.03 p.u.
voltage at Kidatu caused a voltage of 1.043 p.u. at Mbeya without a reactor and the voltage was
reduced to 1.004 p.u. with the use of a 10 MVAr reactor. In order to give sufficient leverage for
the variation of the Kidatu voltage therefore the analysis is conducted with a 10 MVAr reactor at
Mbeya being included in the proposals.
Installation of a Reactor at Ras Kiromanv
4.11        The 38 km submarine cable that provides power from the TANESCO system to
Zanzibar generates about 33 MVAr of reactive power. The MW and MVAr load in Zanzibar is
relatively small compared to this var generation and consequently the line load is dominated by the
var flow to Ubungo. In addition the line losses remain practically unchanged during varying load
conditions, even increasing slightly during base load periods due to the higher cable var generation
resulting from the higher base load system voltages. Line losses from Ubungo to Ras Kiromany
(the mainland end of the cable) can be substantially reduced by installation of compensating
reactors at either or both ends of the cable. At present a compensating reactor is installed at
Ubungo to help reduce the voltage rise due to the cable during light load periods. This reactor was
originally directly connected to the line with no possibility of switching it in or out. However at
peak periods there is a need for capacitive injection on the system and not for an inductive load.
After recommendations made during the ESMAP studies TANESCO instaUed a circuit breaker in
order to allow the reactor to be connected to the bus only when required to limit the voltage rise
at periods of low loads. Although this arrangement helps to resolve the present critical voltage
problems it is unsatisfactory in many respects. As a result of the reactor being installed at Ubungo
rather than at the cable that is the source of the var generation, the voltages at Ras Kiromany, Ras
Fumba and Mtoni (the latter two locations being in Zanzibar) are higher than at Ubungo and
thereby limit the value to which the Ubungo voltage can be raised. The load flow results indicate
that the voltage rise from Ubungo to Ras Fumba varies from 2.7 to 3.5 percent, depending on the
extent of the cable var generation with changing voltage levels as well as on the load in Zanzibar.
The resultant limitation on the Ubungo voltage will affect the ability to control voltage levels in the
northeast, which would normally require maintaining as high a voltage as possible at Ubungo and
Morogoro. Another disadvantage is the higher losses in the Ubungo Ras Kirosmany section
discussed earlier. Yet another drawback of the present reactor arrangement is that the switching
on and off of the reactive load of 20 MVAr wiU cause considerable step changes in voltage at all
busses in the east and northeast. In fact the present switching operation of the reactor should be
viewed as an emergency procedure to help achieve some voltage improvement until a more
technically acceptable arrangement is made.
4.12        The technically optimal solution is to have two reactors of equal size, one at each
end of the cable. This wiUl limit the var flow in the Ubungo-Ras Kiromany line and in the cable
itself. However since a 20 MVAR reactor is already available at Ubungo, the most feasible practical
solution is to transfer this reactor to Ras Kiromany. (The loss reduction would be about the same
if the reactor were transferred to either of the two cable ends but the cost of transport by sea to



- 26 -
Ras Fumbo would make overall costs much higher for this location). The load flow results indicate
that the installation of 10 or 20 MVAR reactors at Ras Kiromany will restrain the voltage rise
between Ubungo and Ras Fumbo to about 2.0 and 1.0 percent respectively (in comparison to an
average of about 3.0 percent with the reactor at Ubungo). The loss reduction benefits are
evaluated in Table C2 of Annex C and indicate benefit to cost ratios as high as 20 to 1 and pay
back periods as low as 4.5 months. Having the reactor in fixed service at Ras Kiromany will require
an increase in the capacitance of the reactive compensation equipment to be installed at Ubungo
by an amount equivalent to the rating of the reactor when compared with the alternative of being
able to disconnect the existing reactor from the system. For this reason the cost/benefit analysis
shown in Table C2 includes the cost of the additional capacitance required in the overall cost of
transferring the reactor. Use of a single 20 MVAR reactor is the primary suggestion because the
existing 20 MVAR reactor at Ubungo can be conveniently transferred whereas the 10 MVAR
reactors currently installed on the system are all rated for 33 kV, which voltage is not available at
Ras Kiromany or Ras Fumba. Transfer of the existing 20 MVAR reactor to Ras Kiromany is
therefore recommended in view of the high economic rates of return and substantial technical
advantages. Once transferred, switching the reactor on and off in accordance with low and high
system demands will not be feasible. Therefore the transfer can only take place after adequate
variable/switchable compensation is provided at Ubungo.
Eimploying Part of the Reactive Compensation Requirements at Tanga
4.13        The ability to maintain the voltage at Hale (where generation capacity is available)
at the upper limit is a critical factor in obtaining the best possible voltage profile in the northeast.
However such ability is dependent on sufficient MW and MVAr generation at Hale together with
the supply of the required reactive compensation at Ubungo (to enable the Morogoro voltage to
be raised as high as possible). Until the commissioning of the new Pangani Falls power station
generation support at Hale is not always able to maintain this desired voltage level. Further with
increasing load over the years the voltage drop between Hale and Tanga wil increase to excessive
values. Thus for the 1992 load the voltage drop between Hale and Tanga, with the Hale voltage
maintained at 1.04 p.u. is 0.033 p.u. while for the 1998 load the drop increases to 0.09 p.u. Voltage
improvement at Tanga as well as support in maintaining the required voltage level at Hale can be
accomplished by providing reactive compensation at Tanga. In consideration of the load at Tanga
a 10 MVAr of compensation is expected to provide the required support. The compensation may
be effected by power factor correction within the power installation of the cement factory itself
(which is the major load fed from this substation) combined if necessary by additional compensation
at the other major loads and 33/11 kV substation at Majani Mpana. If adequate compensation is
not provided directly within the cement factory installation capacitors may be installed at the step-
down (33/6.6 kV) substation feeding the factory. In addition to the benefits of improved voltage
the capacitors can be justified by the energy loss reduction in 132 kV Hale-Tanga line as well as in
the 11 km 33 kV line to the cement factory. The double benefits of improved voltage and reduced
losses as well as relaxation of the necessity for high var generation at Hale make it important to
introduce reactive compensation at Tanga at the earliest possible opportunity. As this compensation
will be provided at the distribution level the matter is further dealt with in Section 6 (see paragraph



- 27 -
6.19). The loss reduction benefits are computed at Table C3 in Annex C. For the purpose of
evaluating the reactive compensation requirements in the transmission system the load at Tanga
is assumed to be compensated by a capacitor of 10 MVAr.
Improving Low Power Factor Levels in the Distribution System
4.14        The existing power factors at the major grid substations are presently at very low
values, with some stations as low as 0.8 p.u. (which represents a var load of half the active power
load). With various system development and loss reduction measures (including capacitor
applications) under consideration for the distribution system the future power factors at the grid
substations are expected to improve from the existing low values. The reactive loads used for the
study at the various substations are thus computed on the assumption of the improvement of the
power factors to 0.82 by 1995 and 0.85 by 2001. To effect this improvement 37 MVAr of capacitors
are required to be introduced between now and 1995. This enables the benefits of the reactive
compensation proposals in the transmission system to be computed after giving due allowance to
the developments expected in the distribution systems.
4.15        In accordance with the above discussion, the reactive compensation requirements for
the transmission system are examined on the assumption that the following preliminary
developments are also introduced:
*     The installation of a 10 MVAr (switchable) reactor at Mbeya. With this reactor in
place the Kidatu voltage is allowed to be raised to 1.03 p.u. under normal peak
operating conditions.
*     The shifting of the 20 MVAr reactor presently at Ubungo to Ras Kiromani.
*     The improvement of the power factor at Tanga by the installation of 10 MVAr of
capacitors in the distribution system.
*     The improvement of the power factor of the distribution system load from the
present low values to 0.90 by 1995.
The Study of Network Operation at Different Load Levels
4.16        The yearly peak loads provided in Table Bl in Annex B represent the highest system
load expected for that particular year. This situation would occur only for a few hours during
relatively few days in each year and represents the maximum load demand to which the system
would be subjected. Hence, it indicates the generation and transmission capacity required. The
system need also to be evaluated at other operating loads, particularly those that are sustained over
a long period. Such studies will provide a better measure of the benefits of loss reduction and saved
thermal generation.



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4.17         The load duration curve for the system indicates the period over which a particular
load is exceeded. Typical load duration curves for a normal working day, for weekends, and a
consolidated curve for the whole year are presented in Figures BI to B3, in Annex B. The yearly
load duration curve can also be approximated using a step function in which the value of each step
represents the average load over a certain loading period. In the first instance, load-flow studies
need to be conducted for the maximum expected load of a particular year. To relate the results of
these studies to other loading periods of later years, the steps of the approximated load duration
curve have been selected to coincide with the maximum loads of previous years. Using this
methodology, it is possible to use each load flow study to predict the system behavior at different
loading periods over a number of years. The steps selected and their correspondence with the loads
of previous years are shown in Table 4.1.
Table 4.1
% of Max.  No. years back   % time
Yearly   corresponding   load
Peak   max. system peak exceeded
Maximum yearly system peak 100     0          0.1
Load step 1           93           1           8
Load step 2            87          2          30
Load step 3            81          3          40
Load step 4            76          4          50
Load step 5            67          6          67
Load step 6            62          8          83
System base load       50         10         100
4.18         Column 2 of Table 4.1 indicates the loading level of each step as a percentage of the
maximum system peak for the year, and column 3 indicates the number of years backward necessary
for the maximum system peak of such previous year to be equivalent to the load step of the current
year under consideration. Thus, the maximum yearly system peak load for a particular year
represents the highest loading conditions for that year as well as a number of subsequent loading
steps for the succeeding years. For example, the 1992 maximum yearly system peak load would
represent load step 1 of 1993, load step 2 of 1994, and so on. Load steps 1 and 2 could be
considered as within the peak loading periods, and load steps 3, 4, and 5 could be considered as
within the mid-loading period of the load duration curve. By selecting the generation availability
and other system conditions, such as transmission developments, to suit the particular year under
consideration, the procedure provides means of evaluating the network performance not only at the
system peak of a particular year but at the various loading conditions of future years. In the system
studies conducted, load flow computations have been performed for the maximum yearly system
peak, the four subsequent loading steps, and the minimum load represented by the system base
load. It can also be seen that some of the system studies representing normal operating conditions
in a particular year will represent periods of system outages (at different loading steps) in future
years. This will be applicable when there are expected developments in generation or transmission



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facilities between the two years in question.
Results of Load Flow Studies
4.19        A large number of computations representing different generation and transmission
line availability conditions have been performed for the various loading conditions described earlier.
The studies have been conducted taking into account the operating principles and system conditions
detailed in paras 4.4 and 4.15. In particular, the Kidatu bus voltage is not raised above 1.03 p.u. in
order to contain the voltages of other 220 kV buses in the west (particularly in the event of any
local load rejection at the substations combined with thermal generation in the west). The var
generation at Hale is adjusted to maintain a target voltage of 1.04 p.u at this bus. In interpreting
the results of the load flow studies, it must be borne in mind that the compensation applied at the
buses at Ubungo and Arusha are dependent on each other if the Hale voltage is below the target
level. The chief concern in the northeast is to maintain voltage levels. This often requires a var
flow in the reverse direction to the active power flow and hence there are no loss reduction benefits
by increasing the extent of the compensation. At Ubungo, however, loss reduction benefits can be
realized by increasing the compensation over the minimum requirements for voltage control.
Studies have been performed to indicate the extent of such benefits. For the period before the
commissioning of the new Pangani Falls power station the generation availability at Hale is critical
to satisfactory system performance. At periods of low rainfall the firm power availability at Hale
and Moshi reduces to 24 MW and 4 MW respectively. The studies up to the year 1995 therefore
include both the maximum (34 MW at Hale and 8 MW at Moshi) as well as firm generation
availability conditions in the north east.
4.20        Bus voltages and other important characteristics of each load flow study have been
extracted and presented in a number of tables in Annex B. The tables are numbered according to
the year and the loading step. The studies with line outages are prefixed by the letter 0. In
addition two summary tables are presented in Annex B. Table B3 indicates the loss reduction and
voltage improvement in various years by incremental changes to the capacitive injection provided
at Ubungo while Table B4 indicates the network voltage changes that occur with incremental
changes to the injection provided at Arusha. A discussion, on the results of the load flow studies
for each year is given in the succeeding paragraphs. The situation at the maximum system load as
well as at lower loading levels (see paras 4.17 and 4.18 are discussed and compensation
requirements to maintain minimum satisfactory network voltage levels are indicated. In the
discussion, it is assumed that the preliminary system improvements detailed in para 4.15 are already
effected. Further the locations for reactive compensation is mentioned as Ubungo and Arusha with
the understanding that the actual application may be distributed among the adjacent grid substations
(see para 4.5). With respect to the compensation in the northeast since 5 MVAr is already
available at Moshi this compensation is applied at the Moshi bus and the additional requirements
placed at Arusha. The Arusha compensation indicated in the discussion includes the 2.5 MVAr
presently available at this location.



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System Perfommance for 1991
4.21        Thermal generation is not required to meet the maximum load in 1991 if the
maximum output of all hydro stations are available. However, in the absence of var compensation
at Ubungo network voltages are depressed to unacceptable levels at that location as well as in the
northeast. With full hydro generation availability in the northeast (34 MW at Hale and 8 MW at
Moshi), the minimum var compensation requirements for satisfactory voltage levels can be
considered as 30 MVAr at Ubungo, 10 MVAr at Tanga, 5 MVAr at Moshi and 13.6 MVAr at
Arusha. This level of compensation will result in the Ubungo HV (nominal 220 kV) voltage
dropping down to 0.92 p.u. at peak with Kidatu voltage maintained at 1.03 p.u. (a drop of 11
percent). Additional compensation provided at Ubungo will increase the system voltages and
provide substantial loss reduction benefits as evidenced from Table B3, Annex B. It is also seen
that with a compensation level of 35 MVAr or more at Ubungo the Hale voltage can be maintained
at the desired level of 1.04 p.u. thus enabling better system performance particularly in the
northeast.
4.22        With firm generation conditions in the northeast (24 MW at Hale and 4 MW at
Moshi), there is a supply shortfall of about 10 MW to meet peak load requirements with hydro
resources alone. With this power together with 30 MVAr of reactive power supplied at Ubungo,
the compensation required at Arusha increases from 13.6 MVAr to 33.5 MVAr. A particular
problem encountered with the restricted generation in the northeast is the inability to keep the Hale
voltage at a high level, thus requiring increased compensation at the northeast line extremities. The
Hale voltage can be increased however with increased var injection at Ubungo resulting in reduced
compensation requirements in the northeast. Thus, the compensation requirements at Arusha drop
to 28.9, 21.6 and 15.9 MVAr corresponding to increases of var supply at Ubungo to 35, 45 and 55
MVAr respectively. The increase of var compensation (at Ubungo) is also accompanied by
substantial loss reduction benefits (see Table B3 of Annex B). Desirable compensation levels for
the 1991 maximum load situation would thus be either 50 var at Ubungo with 16 MVAr at Arusha
or 40 MVAr at Ubungo with 21.5 MVAr at Arusha (keeping in mind that when generation is
provided at Ubungo some var supply is also possible from the generators).
System Perfomzance for 1992
Maximum Load Condition for 1992
4.23        To meet the expected maximum load in 1992, thermal support of about 12 MW is
required in addition to the full availability of all hydro stations. In addition substantial reactive
compensation is also required at Ubungo and in the northeast. With 12 MW and 30 MVAr
supplied at Ubungo (6 MVAr of which could be supplied by the generators) and 5, 10 and 21.4
MVAr at Moshi, Tanga and Arusha respectively, the Ubungo HV drops to 0.89 p.u. (Arusha being
at 0.95 p.u.). The voltage improvement and loss reduction benefits by successive additions of var
compensation is seen from Table B4 in Annex B.



- 31 -
4.24        For firm hydrogeneration conditions in the northeast, 27 MW of thermal power will
be required to meet the shortfall in generation capacity. With all of this active power supplied at
Ubungo, a reactive supply of about 50 MVAr is also required, primarily for the purpose of keeping
the Hale voltage sufficiently high. For these conditions, the compensation required at Arusha is
30 MVAr (compared to the 21.4 MVAr required for the full hydro availability condition). If the
var injection at Ubungo is now raised to 60 MVAr, the requirement at Arusha drops to 25 MVAr.
4.25        The required compensation at Ubungo and Arusha for the year 1992 could thus be
considered as 45 MVAr and 25 MVAr respectively (to meet the firm generation conditions in the
northeast along with a generation of 27 MW and 15 MVAr at Ubungo).
4.26        Load Step 1 for 1992. The system conditions at the load step 1 for 1992 will be the
same as the maximum load condition for 1991 and the discussion in paras 4.18 and 4.19 will also
apply to this situation.
Systen Performnce for the Year 1993
1993 Maximum Load Condition
4.27        The second circuit from Kidatu to Morogoro is expected to be available for operation
by this time. In order to meet the maximum expected load for the year about 30 MW of thermal
generation need to be provided in addition to maximum output from all hydro plant. Even with
such generation injection and the var compensation required to maintain voltages in the northeast,
the Ubungo voltage will be substantially depressed, unless sufficient var compensation is also
provided at this busbar. With 10, 5 and 25 MVAr at Tanga, Moshi and Arusha, respectively, a 30
MW, 10 MVAr supply at Ubungo results in the HV bus at Ubungo being depressed to 0.90 p.u.
Furthermore, the Hale voltage can only be maintained at about 0.994 p.u. under these conditions.
Successive addition of var compensation at Ubungo will increase the system voltage and reduce
network losses as seen from Table B3 of Annex B.
4.28        It is observed that 50 MVAr of injection will be required at Ubungo (15 MVAr from
the generators and 35 MVAr from capacitors) in order to maintain the target voltage of 1.04 p.u.
at Hale. Due to the increase of voltage at Hale, successive increase of var injection at Ubungo
results in the reduction of the var requirements at Arusha. Thus, an increase from zero to 50 var
at Ubungo causes a reduction of the requirement at Arusha from 29.4 VAr to 18.3 VAr.
1993 Load Step 1
4.29        For the load step 1 loading condition about 10 MW thermal generation is required
to be supplied at Ubungo when all hydro plant is in operation. The improvement of the voltage
levels and reduction of system losses with additional var injection is depicted in Table B3 of Annex
B. As in the yearly maximum load condition, successive additional var injection at Ubungo results
in an improvement of the Hale voltage and the reduction of the var requirements at Arusha. The



- 32 -
desired var requirement for the selected conditions are 25 MVAr at Ubungo and 20 MVAr at
Arusha.
1993 Load Step 2
4.30        The loading conditions during load step 2 for 1993 enables the System to be operated
without thermal support if the full output of all hydro plant is available. In the absence of reactive
compensation at Ubungo, however, the system voltage remains low. With 10, 5 and 12.9 MVAr at
Tanga, Moshi and Arusha, respectively (necessary to keep the northeast voltages above 0.95 p.u.)
the Ubungo HV level is at 0.90 p.u. if no compensation is applied at this bus. The Hale voltage
(1.032 p.u.) is also below the target level (1.04 p.u.). The reduction of system losses and
improvement of voltage with the addition of var compensation at Ubungo is seen from Table B3
in Annex B.
4.31        If only the firm generation outputs of 24 MW at Hale and 4 MW at Moshi are
available, a minimum of 6 MW of thermal generation support is required. In such circumstances,
maintaining the Hale voltage becomes increasingly difficult. The required compensation at Arusha
increases from approximately 12 MVAr (in the full generation availability condition) to a value
ranging from 21.5 to 30.0 MVAr for var injections at Ubungo ranging from 27 MVAr to zero
(inclusive of the vars produced by the generators).
System Perfoomance for the Year 1994
4.32        For the year 1994 the network will remain unchanged from that of 1993. Thus,
operating performance for a number of loading conditions for this year may be determined from
the studies for the year 1993. The 1993 year studies, corresponding to the loading periods in 1994,
are as follows:
1994 load step 1 = 1993 maximum system load, see paras 4.27 to 4.28
1994 load step 2 = 1993 load step 1, see para 4.29
1994 load step 3  = 1993 load step 2, see para 4.30
System Perfomance for the Year 1995
4.33        New developments expected to be available for the year 1995 are the second circuit
line from Kidatu to Morogoro and the new Pangani Falls power station. The former will bring
added reliability benefits, particularly to the load at Ubungo and reduce losses (in that section of
the network) considerably. The line capacitive generation produced will also eliminate the need for
reactive compensation at Ubungo. The new generation will help reduce the hydro generation
shortfall and assist in reducing the system losses particularly in the northeastern sections. The
additional generation injection in this region will also help maintain network voltages and reduce
the need for reactive compensation at Arusha. There is, however, a reasonable probability of the
new Pangani Falls power plant being delayed until late 1995 or early 1996. Hence, the system



- 33 -
performance for 1995 has been studied both with and without the availability of the new Pangani
Falls power station.
1995 Maximum Load Condition (with new Pangani Falls available)
4.34        Despite the added hydro generation facility, thermal generation of about 30 MW is
required to meet the maximum system load of 1995. If this generation is provided at Ubungo,
additional var contribution from the generators can also be used. Under these circumstances,
reactive compensation is not required at Ubungo to maintain voltage control. The addition of
capacitors will contribute to loss reduction benefits but to a lesser extent than in previous years.
4.35        The increased generation availability at Hale (from new Pangani Falls) now enables
the bus voltage to be raised as high as desired at this bus bar. Thus with Hale maintained at a
voltage of 1.04 p.u. and with the existing 5 MVAr capacitor at Moshi the compensation
requirements at Arusha are 31, 25, 21 MVAr, respectively for generation of 0, 4 and 8 MW at
Moshi.
1995 Load Steps 1 to 3 (with new Pangzani Falls available)
4.36        As the load decreases from the maximum load condition for the year the
requirement for thermal generation at Ubungo will decrease. Accordingly the power flow along the
Kidatu-Morogoro-Ubungo lines will increase slightly up to the step 2 condition at which point
thermal generation at Ubungo will become redundant (for the full hydro availability condition).
Capacitive injection is not required at Ubungo and system voltages can be maintained without
difficulty except at Arusha-Moshi The compensation requirement at Arusha will also reduce as the
load is reduced from the peak condition and will be 18 and 20 MVAr respectively for the load step
2 condition for a generation availability of 8 and 4 MW respectively at Moshi. For the load step
3 condition the Arusha compensation will reduce further to 6 and 10 MVAr respectively.
1995 Maximum Load Condition (new Panqani Falls not available)
4.37        If the new Pangani Falls station is delayed and is unavailable for operation the
thermal generation requirements will be increased considerably by the year 1995. For the maximum
expected load in 1995 the shortfall will be 75 MW. Existing thermal facilities and presently
proposed developments will not cover this shortfall and substantial new thermal generation facilities
will be necessary to cater for this contingency. If such generation facilities are provided at Ubungo
the loading on the Kidatu-Morogoro-Ubungo lines will be further reduced and there will be no
necessity for reactive compensation at Ubungo. The compensation requirements at Arusha will
however increase substantially due to the difficulty of maintaining a satisfactory voltage at Hale in
the absence of the added generation capacity. In order to maintain a minimum bus voltage of 0.95
p.u. at Arusha with the availability of the existing north eastern hydro plant at full capacity and the
generation shortfall supplied at Ubungo, capacitive injection totalling xx will be required at Arusha -
Moshi.



- 34 -
1995 Load Steps 1 to 3 (new Pangani Falls not available)
4.38        The thermal requirements will keep reducing as the load falls and by the load step
3 condition of 1995 it will almost be eliminated. The compensation required at Arusha will reduce
likewise along with the improvement of the voltage at Hale and the reduced loads on the lines and
by the step 1 condition only 6 MVAr will be required at Arusha (with the existing 5 MVAr at
Moshi). However, if only the existing firm generation availability of 24 MW at Hale and 4 MW at
Moshi can be relied upon the hydro generation shortfall will be about 25 MW for the load step 3
condition. Under these conditions the difficulty of maintaining the Hale voltage will require the
compensation at Arusha to be raised to 29 MVAr.
Systen Perormance Beyond 1995
4.39        The thermal requirements to bridge the hydro generation shortfall increases each
year until the next expected hydro addition, Kihansi is introduced (1998). Thus, with the required
thermal generation provided at Ubungo the active and reactive power carried over the Kidatu-
Morogoro-Ubungo lines will in fact decrease (although by a small margin) over this period in
relation to the corresponding load step of the preceding year (with a corresponding increase of the
Kidatu and Mtera generation feeding the western loads). The system will therefore not require any
capacitive injection at the Ubungo bus bars. In the northeast, however, the network loads will
continue to increase with no additional assistance available from generation or transmission
development (after the new Pangani Falls station is introduced). Thus, the period 1995 onwards
will see a continued increase of var compensation requirements at Arusha -Moshi until the
proposed Singida-Arusha line is commissioned. Current expectations are for this line to be
commissioned in 1996. However, it would be useful to examine the implications of the delay as well
as the effect of expediting this line. Accordingly load flow studies have been performed with the
line introduced as early as 1995 as well as the without the line in service up till 1998. The results
of these studies (presented in Annex B) can be used to evaluate system performance with and
without the line in operation during this period.
Effect of the Singida-Arusha Connecrion
4.40        When the Singida-Arusha connection is introduced the power flows on the Kidatu -
Morogoro-Ubungo line as well as the lines in the north eastern network will be substantially reduced
improving the performance of the system considerably. There will be a direct power transfer from
the western section to the northeastern section resulting in a substantial reduction of system losses.
Capacitive compensation will now not be required in the northeast in view of the power injection
provided at Arusha as well as the vars introduced by the line charging current. If the line is
introduced in 1995 the maximum load conditions for that year will show a loss saving of about 3.0
MW and the thermal generation will correspondingly be reduced. The loss reduction for the
maximum load of 1996 will be about 5 MW. The importance of this line increases greatly with the
introduction of the Kihansi station, which will result in the flow of a considerably larger amount of
power from the central highlands to the east and north eastern areas of the network (with a



- 35 -
corresponding reduction of thermal power injection otherwise required at Ubungo). The network
performance after the introduction of the Kihansi project is dealt with in the succeeding paragraphs.
System Performunce for the Year 1998
4.41        The Kihansi hydro plant is expected to be commissioned for operation during late
1997 and will be available during the year 1998. With this development, thermal support will no
longer be required for a number of years. The loading on the Kidatu-Ubungo lines will be
substantially increased and once again the need for reactive compensation at Ubungo will arise.
The Kihansi power will be connected to the grid at Iringa from whence it will flow to Ubungo via
Kidatu. Hence, the bus voltage at Iringa will need to be higher than that maintained at Kidatu.
The Mtera voltage too will be at the level of the Iringa bus voltage as no substantial power flow is
expected to occur from Iranga to Mtera. In order to contain the voltage at these busbars it is found
that var absorption has to be resorted to at the Kihansi and Mtera generation stations. The extent
of var absorption required will depend on the reactors employed in the western section and the
voltage maintained at Kidatu. It is also seen from the load flow studies that the system voltages in
the northwest are very sensitive to incremental changes in the reactive compensation employed.
The studies conducted indicate that it is not advisable to maintain Kidatu at voltages higher that
1.03 p.u. under normal operating conditions. The corresponding Iringa voltage will be around 1.04
p.u.
4.42        As discussed earlier the role of the Singida-Arusha 220 kV connection will be
substantially enhanced with the addition of the Kihansi station. In order to assess the impact of this
line as well as to understand the implications of its delay, the system behavior for the year 1998 is
studied both with and without the operation of the Singida-Arusha line.
1998 Maximum Load Condition (with the Singida-Arusha line!
4.43        The power flow to Arusha from the northwest considerably reduces the loading of
the northeastern 132 kV line sections. The total system losses reduce to approximately half the
value in the absence of the new line. The available hydro generation exceeds the requirements for
the maximum expected load of 1998 and the maximum stress on the transmission network occurs
when generation in the northeast is reduced allowing for full power output from the major hydro
stations in the center. Accordingly, generating 50 MW at Hale/Pangani with no generation at
Moshi provides the most onerous conditions for the system. For these conditions a minimum of
25 MVAr of var injection is required at Ubungo to maintain a satisfactory voltage profile (Kidatu
at 1.03 p.u. and Ubungo HV bus at 0.92 p.u.). The increase of var compensation from this
minimum value will provide substantial loss reduction benefits as shown in Table B3 in Annex B.
4.44        With the Hale and Moshi generation increased to the maximum values the power
transmission throughout the network is reduced. The minimum compensation required at Ubungo
for a satisfactory voltage profile is now about 18 MVAr.



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1998 Maximum Load Condition (Without the Singida-Arusha Line)
4.45        Without the Singida-Arusha connection the system is considerably overburdened in
carrying the maximum load of 1998. The total system losses (with sufficient var compensation
applied) rises to 9 percent and the northeast section losses rise to 15 percent (of input power). Due
to this high level of losses, there is very little slack in generation capacity. With the 8 MW at Moshi
being unavailable and Kihansi supplying 140 MW all other hydro plant has to operate at maximum
capacity to meet the system load. With the Hale voltage maintained at 1.04 p.u. var compensation
of 25 and 30 respectively is required at Moshi and Arusha when there is no generation at Moshi.
If full generation (8 MW, 4 MVAr) is available at Moshi, the additional (static) compensation at
Moshi may be reduced to 10 MVAr (while maintaining Arusha at 30 MVAr). (In this instance var
compensation requirements are stated at both Arusha and Moshi deviating from the previous
practice of stating the new requirements lumped at Arusha. This is because the application of the
total requirements at Arusha will depress the Moshi voltage to unacceptably low values).
4.46        With the above compensation levels provided in the northeast at least 25 MVAr is
required at Ubungo to maintain a satisfactory voltage. Increase of var compensation will improve
the voltage profile and reduce the system losses as shown in Table B3 of Annex B.
Power Export Poasibifities to Kenya
4.47        Possibilities of exporting power to Kenya are being considered to supply the
shortages in the Kenyan power system either at Nairobi or at Mombasa. The use of the Singida-
Arusha line extension by making a connection from Arusha to Nairobi is being considered for the
Nairobi supply. 1998 peak power flows with this connection (using Bison conductor, which is used
for all the 220 kV lines in the western section, for both Singida-Arusha and Arusha-Nairobi lines)
indicate the necessity of 35 MVAr of compensation at Arusha for a 50 MW, 25 MVAr supply to
Nairobi (with full available hydro generation plus 30 MW of thermal supply at Ubungo). With this
transfer the loading on the initial sections of the lines in the west (Iranga-Dodoma-Singida) rises
to over 50 percent of therrnal rating. The losses in the western section also rises to 6 percent of
the power flow. At any rate if power supply to Nairobi via Arusha is to be provided at a future
date, the compensation at Arusha will be a necessity.
4.48        A connection from the east up to Mombasa with a 220 kV line from Chalinze to
Mombasa via Hale and Tanga seems to be more appropriate on considerations of the network
power flows. In addition the gas development from Songo Songo enables exportable power to be
available in the eastern section of the network. A 2001 year peak power flow with full hydro
generation (inclusive of the second stage Kihansi) and 120 MW (gas fired thermal plant) at Ubungo
gives a satisfactory power flow and voltage profile for a 100 MW transfer to Mombasa. No reactive
compensation is required along the new transmission line or elsewhere in the system.
4.49        The above discussion is not intended to arrive at specific conclusions for the
possibilities of power export to Kenya but in order to form an idea of the capacity of the network



- 37 -
for meeting possible new demands in the future.
System Operation at Base Load
4.50         A number of studies for base load operation has been conducted in order to examine
the behavior at low load times. Some of the studies include the rejection of half the load at Ilala
(the second step down station in Dar es Salaam) in order to provide a situation which could arise
with a lower than normal base load. Another method of considering loads lower than the given
base load for the year is to consider base load runs of previous years (while allowing for network
changes relevant to the future year).
4.51         For the initial years after the commissioning of the second circuit to Dar es Salaam
the generators will have to operate at substantial leading power factors if both circuits are placed
in service. If for example the 1992 average base load is taken as a minimum load in 1995, it is seen
that the machines at Kidatu and Mtera will have to operate at leading power factors of around 0.85.
Since the power output is low at these times, the operation is within the generator capabilities.
However, a number of other factors may need to be considered in such situations. Firstly it is
normal for a number of machines to be taken off the system at base load times. Secondly, machine
stability aspects need to be examined as generation operating regimes are more restrictive for
leading than lagging operation. Thirdly, it is possible that both machines at Mtera may not be
available during certain base periods, thus requiring further var absorption at Kidatu and causing
problems for the voltage control of the north western lines. A full examination of these aspects
inclusive of stability studies in the network at base load is beyond the scope of this study. It could,
however, be concluded that greater flexibility of operation would be possible if var absorption
facilities were available at Ubungo.
4.52         The difficulties of high leading vars produced by the machines can also be avoided
by disconnecting the second circuit (or one of its sections) during low load times. The studies show
that with any one section of the second circuit out of service the situation is considerably improved.
Hence this mode of operation could be resorted to if difficulties are anticipated for the stable
operation of the system at base load. However, considerable step changes in voltages will be
experienced with the switching on and off of the line sections.
System Operation During Outages
4.53         A basic reliability standard usually applied to transmission system planning is the "n-
1" criteria, which requires the system loads (or as a minimum, the important load centers) to be
maintained in the event of the outage of any one of the major transmission lines. The present
TANESCO transmission system does not allow for such a contingency for any of its major loads.
With the increase of system load over the coming years it would be necessary to place greater
emphasis on reliability standards and allow some possibility of maintaining supply to important load



38 -
centers in such circumstances. In particular with the introduction of the second circuit Kidatu-
Morogoro-Dar es Salaam the network should be able to meet at least most of the load at Dar es
Salaam with one of the line sections out of service. The incidence of line outages vary from short
duration line trippings caused by atmospheric disturbances to longer duration outages caused by
failure or damage to line hardware. With the increase of the service life of the existing transmission
line it would also be reasonable to expect a greater incidence of the latter category and thus an
added concern on maintaining adequate reliability standards are further justified.
4.54        Load flow studies have been conducted to determine the ability of the system to
meet various outages. Some of the load flow studies specifically relate to certain outage conditions
with a line section taken out of service. Other outage conditions can be deduced from the normal
load flow results of previous years during which time the line to be disconnected was not in service
(with the loading levels selected to provide the required bus loads for the condition studied).
Outages which are meaningful in the context of system operation are (i) one of the line sections in
the Kidatu-Morogoro-Ubungo lines, (ii) the Singida-Arusha connection and (iii) a line section in
the north eastern network from Hale to Arusha. The latter two outages will be of relevance after
the Singida-Arusha line is commissioned by about 1996. With respect to the Kidatu-Morogoro-
Ubungo lines the outage of the Morogoro-Ubungo section is more demanding on the system than
the Kidatu-Morogoro section and hence the study will be limited to the analysis of the former.
With respect to item iii, the Hale-Same line outage will be considered. This condition will enable
the Arusha and Moshi loads to be supplied by the north west leaving Hale to supply the load at
Hale and Tanga and export any remaining power to the eastern load center of Ubungo-Ilala. The
most severe outage in the northeast in the later years is clearly the outage of the Singida-Arusha
line, which will require the entire load of the north east to be supplied by the power stations at
Hale/Pangani and the Kidatu-Morogoro-Ubungo line. The following paragraphs describe the
system capabilities of meeting the above outages during various future years.
4.55        The ability to maintain service during line outages will commence from 1993 when
the Kidatu-Morogoro section of the second circuit is expected to be completed. Outage studies for
the 1993 maximum load condition indicates that along with a 30 MW (and 20 MVAr) thermal
generation at Ubungo a further 20 MVAr of compensation is required to support the system load
if one of the Kidatu-Morogoro sections is outaged. At lower loading levels the 1993 system outage
conditions can be deduced from the normal system operation of 1992 (since an outage of one of
the Kidatu-Morogoro lines will correspond to the network conditions prevailing in 1992). Thus the
results of the maximum system load of 1992 indicates that the load step 1 condition of 1993 will
require 12 MW (and 7 MVAr) of thermal generation and 18 MVAr of reactive compensation. At
a lower load level corresponding to load step 2 (maximum system load of 1991) 30 MVAr of
compensation will provide the ability to supply the full load without resorting to thermal generation.
The requirements indicated above (from maximum load to load step 2 of 1993) will also correspond
exactly to the 1994 load conditions reduced by one load step (load step 1 to average mid load
step 3).



- 39 -
4.56        The additional reliability to be gained by reactive compensation will acquire greater
significance after 1995 when the second circuit is fully commissioned and when additional hydro
generation (Hale/Pangani increased to 80 MW) is available in the north east. At the maximum
load of 1995 a thermal generation of 25 MW will be required to meet the hydro generation
shortfall. To meet the Morogoro-Ubungo outage condition 15 MVAr from the thermal generation
together with a further 10 MVAr of var compensation will be required. When the load drops to
load step 1 the system can operate without thermal injection if all hydro plant is fully operational.
To support an outage of one of the Morogoro-Ubungo circuits during load steps 1 or 2 var
compensation of around 15 MVAr is required for the various hydro generation combinations
possible. The above operational conditions for 1995 could be related to the equivalent loading
conditions during the years 1996 and 1997 with the system remaining unchanged (i.e., with the
Singida-Arusha line unavailable).
4.57        From 1998 onwards, both the Singida-Arusha connection and the Kihansi power are
expected to be available. An outage of the Singida-Arusha connection can be withstood without
supply interruption during the 1998 maximum load condition by having a minimum of 20 MVAr of
compensation at Ubungo together with 50 MVAr of compensation at Arusha and Moshi. Outages
of both the Singida-Arusha connection and one circuit of the Morogoro-Ubungo line can be met
satisfactorily if the compensation at Ubungo is raised to 30 MVAr. An outage of the connection
between Hale and Same will separate the network once again with the loads at Arusha and Moshi
transferred to the north western side. The compensation required at Ubungo to support this outage
at the maximum load of 1998 exceeds the compensation required for the Singida-Arusha outage in
view of the lack of mvar flow from Arusha-Moshi to Ubungo. For the above outage a minimum
of 50 MVAr is required at Ubungo (HV voltage at Ubungo being 0.885 p.u.).
4.58        The outage studies described above indicate that about 30 MVAr at Ubungo and 30
MVAr at Arusha will provide the ability to cover most contingencies from 1995 to 1997 with
minimal thermal support. If a further 20 MVAr is provided at Moshi the full load of the system
can be met for an outage of the Singida-Arusha line during 1988.
Slippage of Plakued Invwestment
4.59        The results of the outage studies can also be used to ascertain the performance of
the system in the event of the delay of introducing any of the planned developments. Delays in
procurement of funds as well as in the award and management of construction projects are fairly
common experiences with TANESCO. It would thus be prudent to have sufficient system capacity
to be able to meet (say) the expected maximum load condition for at least one year of slippage for
projects under construction and two years slippage for projects in the planning stage.
4.60        A special case of the ability to meet a slippage of planned investment is the flexibility
provided to change the investment portfolio when new opportunities arise or there is a change of
the conditions assumed for system planning. A matter of some concern in the present instance is
the possibility of an extended delay of the Kihansi project (unexpected delays of hydro projects of



- 40 -
this nature are fairly common occurrences). This fact coupled with the possibility of advancing the
exploitation of the Songo Songo gas supply for power generation is of particular significance in
TANESCO's strategic planning decisions. If such a situation arises the availability of sufficient
capacitors at Ubungo will enable the Morogoro-Ubungo section of the second circuit to be delayed.
The importance of this line will be greatly diminished if there is sufficient injection of thermal
power at Ubungo. Hence TANESCO's ability to shift its priorities and options will be a substantial
advantage to be considered for the introduction of reactive compensation measures.
4.61        Another possibility is a 220 kV development from Ubungo to Mombasa. This
possibility is also connected with the gas generated power option at Ubungo. Studies have shown
that if any power export to Kenya is to be considered the possibility of extending the proposed
Singida-Arusha connection to Nairobi has only limited power transfer capability. The connection
to Mombasa with substations at Hale and Tanga can be a viable option depending on the amount
of power to be transported. If this possibility becomes promising it is possible that the extension
of the proposed 220 kV system in the north east from Hale to Arusha could become more
beneficial than the presently planned Singida-Arusha connection. The economic choice will depend
on the expected load growth in the north eastern and north western sections, the power available
for export and its value at the possible receiving points of Mombasa and Nairobi The advantage
of having reactive compensation installed at Arusha, however, is that if required by any change of
circumstances TANESCO will have more flexibility in its ability to revise future investment options.
Loss Reduction Benefits
4.62        The preceding discussions related to the provision of the minimum reactive
compensation requirements in order to maintain the system voltage during normal and exigency
situations. The compensation provided at Arusha results in a flow of reactive power in a direction
opposite to the active power due to the low capacity of the network and no loss reduction benefits
will accrue with any increase of compensation. At Ubungo however, the compensation in excess
of the amount required to maintain minimum voltages at any given loading condition will provide
considerable loss reduction benefits. In addition the voltage profile could be considerably improved
with additional capacitors and there will be a general improvement of reliability standards. These
benefits will vary according to the loading and generation conditions prevailing at a given time.
Some examples of the additional loss reduction benefits achievable by using compensation levels
in excess of the minimum requirements are given in Table B.3 of Annex B. These benefits should
clearly be taken into account in determining the extent of compensation to be employed.
Selection of var Compensating Systems
4.63        The foregoing paragraphs discussed the var compensation requirements necessary
at Ubungo and Arusha in order to maintain a satisfactory system voltage profile. Additional loss
reduction benefits derived from increasing the level of compensation over the minimum



- 41 -
requirements have also been discussed. The studies conducted to cover a 10 year period from 1991
indicate the changing requirements of var compensation with time. The requirements also change
with loading conditions which vary with the time of day. As discussed in para 45 the locations
Ubungo and Arusha were selected as reasonable representations of the eastern and north eastern
line extremities. It is now necessary to identify the types of compensation and the extent to which
the compensation to be applied should be distributed (if so required) among adjacent locations.
Comnpsation Requc4imt at Ubungo
4.64        Of the two main locations requiring compensation the most pressing need is at
Ubungo. Further the compensation would have its maximum benefits in the immediate short term
by enabling the system to meet the load growth expected in the years before the commissioning of
the second circuit, Kidatu-Morogoro-Dar es Salaam. If the TANESCO system was equipped with
suitable var compensation at the present time the benefits realized due to the ability to meet the
load growth at satisfactory voltage levels and in avoiding thermal generation would be exceptionally
high. In these early years the compensation requirements will vary widely with the loading
conditions and the ideal solution would have been a variable var compensation system. If the
system could handle variable var supply it would in addition provide benefits during network
outages, tripping and energization of transmission lines, as well as during sudden load variations.
Stable operation would even be possible in the event of a disturbance as heavy as the tripping or
energization of the Zanzibar cable or either of the 220 kV circuits to Dar es Salaam (after the
second line is introduced). However if action is now taken to obtain a variable var compensating
system it could only be commissioned by about late 1993 or early 1994. This would leave a period
of only just over one year to reap the high benefits from the period before the commissioning of
the second circuit up to Ubungo. On the other hand switched capacitors could be introduced much
faster and if acted upon immediately at least two years of benefits could be realized before the
second circuit is completed up to Ubungo. The benefits will continue even after the second circuit
has been commissioned as previous discussions of the various operating scenarios show.
4.65        In view of the urgency of the requirements therefore it is recommended that the
quickest method of obtaining the required compensation be pursued. Tables C.5 of Annex C
discussed in Section 5 indicate the benefits achievable from reactive compensation of 30 MVAr in
two switchable banks followed by a third switchable bank of a further 15 MVAr. While the
inclusion of the first two banks provide a benefit to cost ratio of 39 to 1 the addition of a third bank
is also beneficial at a ratio of over 8 to 1. For this reason it is recommended that three banks of
capacitors of 15 MVAr each be purchased on an immediate basis. If action is taken immediately
(early 1992) it is possible for the capacitors to be in service by the beginning of 1993. The banks
need to be switchable and control circuit breakers and associated equipment should be provided.
Two of these banks may be placed at Ubungo at the 33 kV supply point earlier used by reactors.
The third bank is recommended to be installed at Ilala in order to capture in addition, the loss
reduction benefits on the Ubungo-ilala line. This separation will also assist in reducing the excess
capacitance on the system in the event of tripping of the Ilala line.



- 42 -
4.66        The installation will have a high benefit period up to the commissioning of the
second circuit to Ubungo. Thereafter the benefits will be mainly in the reduction of system outages
until additional power is transported along the Kidatu-Morogoro-Ubungo lines consequent to the
commissioning of the Kihansi power plant. At this time the compensation required at Ubungo/Iala
will rise to about 70 MVAr. Thus the present application should be considered both as an
immediate necessity and as an advancement of future requirements.
Compnsaon Requirements atArusha
4.67        With respect to the reactive compensation requirements for the northeast the initial
period of high benefits is considerably longer than for the application at Ubungo/Ilala. The ability
to supply additional load consequent to the improvement of network voltages will also keep
increasing with time until the Singida-Arusha line is introduced (presently expected in 1996).
Further the recommendation in para 4.13 to install capacitors in the distribution system at Tanga
could be acted upon immediately to provide some relief until the compensation at Arusha can be
installed. After the Singida-Arusha connection is introduced the requirement for compensation will
shift from capacitive to inductive for normal system operation while requirements to meet an outage
of the new Singida-Arusha connection will remain capacitive. The above considerations need to be
taken account of in determining the most suitable mode of application of the reactive compensation
measures to be installed.
4.68        A major consideration in instances where var compensation is relatively high
compared to the power flow on the lines is the variation of network voltages when changes are
affected either to the compensation level or to other network operating parameters. Table B.4 in
Annex B indicates the variations of (the steady state) system voltages to be expected for incremental
changes of var compensation at various operating conditions. When network voltages are highly
sensitive to the compensation provided, var injection is best accomplished by static var
compensation systems (SVS) using thyristor controlled reactors (TCR). These SVS installations are
capable of reacting within about one cycle to any alteration of system conditions and producing the
exact level of compensation required to maintain the reference voltage at the preset value. If the
compensation were to be provided by a mixture of switched capacitors a number of operational
problems may arise. Fairly high voltage variations could be experienced in the network and sections
of the system could also be subjected to unacceptable voltage levels both high and low for short
periods of time. If switched capacitors are to be provided the size of each unit needs to be small
(about 5 MVAr) and switching facilities will need to be provided for each unit. The operation will
need to be coordinated by a voltage supervisory system to allow the units to be introduced or
disconnected in sequence in accordance with the compensation requirements. It is possible that the
precise coordination of the large number of switched units required to obtain satisfactory operation
of the system for all normal system variations may not be technically feasible. Without the rapid
response characteristics (which can be provided by the TCR unit of an SVS) additional problems
such as hunting of switching operations is also to be expected in view of the high sensitivity of
network voltages to var injection changes.



- 43 -
4.69        In addition to maintaining network voltages during normal operational changes of
the system load and the generation pattern an SVS installation would be of invaluable benefit during
network outages. The fast response characteristic of the SVS will enable network stability to be
maintained following major system disturbances (such as line outages or generator trippings).
Although difficult to quantify in precise terms considerable advantages are expected from the
improved system stability provided by an SVS unit installed at Arusha.
4.70        In view of these operational benefits as well as the fact that the higher costs of SVS
units are more than justified by economic evaluation (see Section 5) it is recommended that the
compensation at Arusha be provided by an SVS unit. The unit would consist of a TCR and the
required capacitor banks (including filters) providing a var variation from 0 to +30 2/ MVAr.
Arusha has been selected for the northeast location, in consideration of the current installation of
5 MVAR of capacitors in the substation at Moshi (Kiyungi), and the requirement for reactive
compensation at Arusha or Singida when the planned Singida to Arusha line is placed in operation
(see para below).
4.71        When the Singida-Arusha line is in service the SVS unit would not be called upon
to provide any substantial capacitive var injection duty under normal operation conditions.
However the capacitive mode could be used to maintain continuity of supply during outages of the
Singida-Arusha line. Alternatively the capacitor banks could be shifted to other locations at which
var compensation would then be required. With the Singida-Arusha line in operation the
compensation needs will change from capacitive to inductive. Hence the best technical solution
would be to add circuit breaker control to the capacitor units to enable the SVS operating range
to be increased to (say) -25 to +30 thus providing for the inductive requirements during normal
operation and capacitive requirements during line outages.
4.72        Although thyristor-controlled reactors can be purchased to operate at up to 33 kV,
cost considerations make voltages of about 11 kV the optimum level if units operating at higher
voltages cannot be connected directly to the system. The grid substation transformer capacity at
Arusha energizing the 33 kV bus is inadequate to carry both the combined loads of the system and
that of the SVS. Therefore since a new step down transformer would be required for the SVS unit
to function at 33kV, operation of the SVS at 11 kV would be more economical. The capacitive
units could be installed in three groups-one supplying the necessary filters for the suppression of
harmonics and the other two providing the banks that will be subsequently converted to switched
units when the inductive mode of operation is required.
V/     (+) indicates capacitive compensation and (-) indicates inductive compensation.



UBUNGO 220 K\/ BUS DAILY VOLTAGE PROFILE
in KV
240
220
200
120
100   _.                 _     __ ___              __    _   __I___              _  _   __    _   _   __    _   _
1       3           5        7          9        11HOURS 13          15        17        19         21       23
-a-mitivi.ar -1-NAXva'Lr                                                                                                   A
Hota:DnatU collactud on March 21, 1990



UBUNGO 132 KV BUS DAILY VOLTAGE PROFILE
In KV
140
o5
1SO
1 1 -
3        5          7         9         1t        19        15         17        19         21        23
HOU RS
-MInvolt   -Maxvolt
NsIS,DIIS ll*.I.d em Match at, Cloan



KIYUNGI 132 KV BUS DAILY VOLTAGE PROFILE
In KV
145,3
143
lh3
123
113
103
1        3         5          7        9        11        13        15        17        19        21        23
HOURS
-6-1UINVOLT -|MAKYOL.Y
Note: Daka collected on Match 21, 1990



KIYUNGI 66 KV BUS DAILY VOLTAGE PROFILE
InKV
73
68
62
60
58
1         3         5         7         9          11        13        15        17         19        21       23
HOURS
--MINVDLT +41AXVOU                                                                                                            i
Notes Data collected on March 21, 1890



- 48 -
5. ECONOMIC ANALYSIS OF PROPOSALS FOR POWER FACTOR COMPENSATION
AT THE TRANSMISSION LEVEL
5.1         At present the loads (active and reactive) on the east and northeast sections of the
TANESCO grid are considerably in excess of the capacity of the network if voltages are to be
maintained within the limits required by statutory regulations and the range generally considered
as being technically acceptable. The high reactive currents flowing through certain sections of the
system result in high power and energy losses. Furthermore although the system is not currently
generation constrained (if all commissioned plants are operational at rated power) the addition of
new loads is restricted in a number of locations in the east and northeast due to the difficulty in
maintaining satisfactory consumer supply voltages in those locations.
Benefits of Investment in Reactive Compensation
5.2         The power transfer capabilities of the network can be increased by application of
reactive compensation measures. In addition a number of other subsidiary benefits can be achieved.
For the reactive compensation applications under consideration the following economic benefits can
be realized:
(a)   Increases in energy supply, above that which the network can currently sustain while
maintaining satisfactory voltages
(b)   Reduction or elimination of thermal generation otherwise required for voltage
support
(c)   Lower power and energy losses in certain sections of the network which currently
experience high reactive power flows
(d)   Reduced operating and maintenance expenses
(e)   Reduced incidence of damage to equipment owned by TANESCO and by its
consumers
(f)   Improved quality of supply to consumers and therefore greater consumer satisfaction
(g)   Reduced impact of any slippage or postponement of planned investment in
transmission and generation as a result of the ability to transmit increased loads over
existing circuits



- 49 -
(h)   Possible postponement of transmission and generation investment.
5.3         Not all of these benefits can be accurately quantified. The data available is
insufficient to allow development of realistic estimates of the economic value of reduced operating
and maintenance expenses, of reduced incidence of equipment damage or of improved consumer
satisfaction. In addition TANESCO is presently firmly committed to a generation and transmission
expansion program over the period covered by this study and the recommendations presented in
this report will have little or no effect on these investment plans. However the application of
reactive compensation will enable the system to increase its load carrying capabilities and will
therefore provide a crucial role in alleviating difficulties of meeting the network loads. This
increased capability is of particular significance in view of the shortage of transmission capacity to
meet the expected load with the developments currently planned. It will also assume added
significance in the event of any unanticipated slippage of planned investment in transmission and
generation projects. Another significant advantage is with respect to the possible change of
investment plans, particularly in connection with the proposed use of natural gas from the Songo
Songo gas field for power generation. The Government of Tanzania is now actively considering the
early usage of this energy source in power generation. Once again the presence of reactive
compensation measures will provide additional flexibility in changing investment planning decisions
by increasing the critical time periods for new developments to be commissioned. In particular it
may also be possible for the second line from Morogoro to Dar es Salaam to be substantially
delayed if firm thermal generation is available at Dar es Salaam. However, it is not possible to
quantify the extent of benefits provided in the event of unanticipated slippage of investment projects
or in providing added flexibility of planning options. Therefore although these benefits are very real
and pertinent in the context of TANESCO's system planning strategy, no credit is assigned to
possible postponement of investment in generation and transmission in the present analysis. For
these reasons the economic evaluation undertaken in this report will consider only a part of the
benefits that will actually accrue from the proposals.
5.4         In the case of compensation to be provided at Ubungo the major portion of the
benefits arise from the reduction of thermal generation that would otherwise be required at Ubungo
up to the year of commissioning the second transmission circuit to Dar es Salaam to maintain
minimum acceptable voltage levels. The ability to maintain system operations with the full network
load during outages of any of the transmission circuits (when both circuits are installed) to Dar es
Salaam has also been computed as benefits by estimating the increase in energy sales as a result
of reduced outages. In addition the resulting loss reduction benefits have been evaluated.
5.5         In the case of compensation to be provided at Arusha the benefits evaluated are the
value of the additional loads that can be connected to the system over and above the maximum load
that can otherwise be supplied at an acceptable voltage. The maximum demands which can be
supplied by the existing network (at the various bus bars), while maintaining satisfactory voltage
conditions are in fact less than the loads supplied at present. Therefore the methodology employed
for economic evaluation of increased consumption recognizes as benefits not only the new consumer
demands which can be accommodated but also that increment of the existing demand which is the



- 50 -
cause of the unsatisfactory voltage conditions.
The Value of Unupplied or Poorly Supplied Energ
5.6         The economic losses which occur due to deficiencies of the power system cannot be
accurately quantified because of their varied and diverse nature. In general, such losses greatly
exceed the cost of the measures which would be required to correct those deficiencies. However,
an estimate of the value of the possible new sales which TANESCO is unable to supply (including
that portion of additional sales which cause poor supply conditions in the network) may be obtained
by determining the cost to TANESCO's consumers of providing such energy from alternative
sources. The most practical alternative, and by far the most commonly applied in Tanzania, is the
use of small diesel generators installed on the consumers' premises. Table C. 1.1 in Annex C shows
the cost (at border prices) of power supply from a 2 MW diesel generator. The table indicates that
these costs vary approximately between $0.12/kWh (all costs are stated in U.S. dollars) and
$0.33/kWh, depending on the degree of utilization of the plant. In a country such as Tanzania the
actual costs may be much higher as is illustrated by the fact that the table indicates the investment
cost of the plant to be $800 /KW whereas the cost of a similar diesel plant being supplied to the
Harbors Authority in Dar es Salaam has been reported to be as high as $2000 /KW. Operation and
maintenance costs of isolated diesel plant on the TANESCO system are also reported to be
considerably higher than the comparable costs given in the table. The generator used as the basis
of the calculations is rated at 2 MW which is a higher rating than that of the average autogenerating
unit installed in Tanzania. Costs from smaller units would tend to be higher because of economies
of scale. It may therefore be safely assumed that in Tanzania the overall costs of energy from diesel
generating units installed as an alternative to grid supplied energy will be higher than the equivalent
costs indicated in Table C.1.1.
5.7         An alternative method of quantifying the value of electric energy is to use the Long
Range Marginal Cost (LRMC) or the Average Incremental Cost (AIC) of power supply as the
economic value of the energy supplied. The AIC for the Tanzanian power supply has been
calculated and is summarized in Table C.1.2. This table indicates that the AIC works out to
US$0.104 and $0.094 per KWh at discount rates of 12 and 10 percent respectively for energy
supplied at the distribution level.
5.8         Of the two methods of determining the value of energy not (or unsatisfactorily)
supplied, the former, based on the installation of small diesel generators at individual load centers,
may be considered as the medium term supply cost (requiring a lead time of about two to three
years in the situation prevailing in Tanzania). The latter method is based on the optimal cost of long
term supply options (with a lead time of roughly four to seven years). The poor voltages and the
inability to supply consumer demand are current realities and the benefits attributed to the
proposed investments are specifically those which would be realized in the immediate to medium
term. Therefore the true energy cost to be used in evaluating any measures which would bring rapid
relief to the network should be the short term costs, which would be higher than both alternative
costs discussed above. However in order to ensure that the recommended solutions are truly



- 51 -
economical a conservative figure of $0.10/KWh has been used in the evaluation of economic
benefits. This figure is also conservative with respect to studies done elsewhere in Africa3/ where
higher values have been obtained as the willingness to pay for the provision of electrical power.
T7he value of loss reduction benef%
5.9         Loss reduction achieved by reactive compensation occurs mainly during the day and
night peak hours. Hence the value of these benefits will be closer to the peak power costs than to
the average energy costs (discussed in the preceding paragraphs). However, once again
US$0.10/KWh has been selected to represent a conservative estimate of the benefits.
Cost of outage saYings
5.10        The cost of announced as well as unannounced supply outages for connected
consumers will be many times higher than the value of energy designed to prospective consumers.
These costs are associated with a wide variation of circumstances ranging from high value items
such as lost production to inconveniences of lower value such as leisure or enjoyment foregone. A
study conducted as a part of the project using a Tanzanian research organization (Tanzanian
Industrial Research and Development Organization) yielded the average value of US$2.25 per kWh
for unannounced outages for a selected sample of industrial organizations in Tanzania. With
respect to classes of consumers not covered under the study (such as residential and commercial
consumers) the value would be somewhat lower. Studies conducted by Acres International and
USAID in 1992 yielded values ranging from US$0.30 to US$1.00 per kWh depending on the
duration of outage as well as the type of economic activity interrupted as a result of the outage.
Since the outages saved as a result of the reactive compensation measures proposed are at peak
hours and at the major load centers a value at the higher limit is more appropriate. For the
purpose of evaluating such benefits an estimated value of US$1.00 per kWh has been taken to
represent the value of such outage savings. This figure agrees with the studies conducted elsewhere
where the cost of outages approximates to about five to ten times the LRMC of supply.
Cost of Compensation Equipment
5.11        Budgetary costs for various sizes of capacitors to be used in distribution lines along
with the associated equipment required for their installation (at medium voltages of 11 and 33 kV)
and at various capacities under switched and unswitched conditions are provided in Tables C.7.1
to C.7.3 in Annex C. The unit cost of the capacitors themselves (without support structures,
switching and protection equipment, in $/kVAr) do not vary with the voltage of application. The
cost of switchgear however will vary substantially according to the operating voltage. For capacitors
to be used at substations the additional cost will consist of the support structure, control equipment
3/     1991 studies conducted for residential consumers produced values of US$ 0.11 in Burundi and Rwanda
and US$ 0.18 to 0.20 in West Africa.



- 52 -
and switchgear. These costs are developed in the benefit to cost table for the Ubungo application
(Table C.5 in Annex C).
5.12        Proposals including budgetary costs for static var compensation systems (SVS) with
capacities of between 20 and 55 Mar employing combinations of a thyristor controlled reactor and
fixed capacitor banks were obtained from four internationally recognized suppliers of such
equipment. From these proposals estimates of the cost of installing SVS units were developed.
These estimates are shown in Table C.4 in Annex C. The cost of installing the recommended SVS
units is expected to vary from approximately $90/kVAr to $200/kVAr depending on the rating, the
necessity for a step-down transformer and the number of switched capacitor banks required. The
proposal for the SVS unit at Arusha is for an output variation from 0 to 30 Mar without the
provision of circuit breakers at the initial stage. The expected cost for such a system based on
international competitive bidding procedures is expected to be around US$4.25 million. However
there are only a limited number of suppliers of this equipment and the value of US$5 million is
taken for the economic analysis.
Calculation of benefits and benefit to cost ratios
Compensation to be provided at Ubwngo/Ilala
5.13        In the immediate term the reactive compensation to be provided at Ubungo will
result in a saving of thermal generation otherwise required to support the voltage up to the
commissioning of the second 220 kV circuit to Ubungo. The load flow studies indicate that up to
1OMW of thermal generation can be avoided during the load steps 1 and 2 of 1993 and load steps
2 and 3 of 1994. From 1995 onwards savings will accrue through load sheddings avoided during line
outages. These benefits have been computed in Tables C5.2 in Annex C. In addition to the above
benefits the installation of the recommended amount of capacitors will provide loss reduction
benefits at various loading conditions (see para 5.14 below). After 1998 when generation from
Kihansi should be available the loading on the Kidatu-Morogoro-Ubungo lines will increase
considerably and the compensation required will greatly exceed the present recommendations. Thus,
in the period after 1998, high benefits will again be reaped from the reactive compensation
measures. However, in order to focus on the benefits that will accrue in the short term the benefits
after 1998 are not evaluated. Instead, the discounted value of the capacitors in 1998 is subtracted
from the economic cost in the benefit/cost analysis.
5.14        The loss reduction component of the benefits have been computed from the results
of the load flow studies conducted at a number of operating periods in different years with the
application of varying amounts of compensation (see Section 4 para 4.62). The results of these
studies are summarized in Table B3 of Annex B. Loss reduction benefits will be high when there
is a necessity to transport a large amount of reactive power along the Kidatu-Morogoro-Ubungo
lines in the absence of reactive compensation. Conversely the benefits will be low when either the
power transfer along this line is low or when there is sufficient thermal generation at Ubungo to



- 53 -
supply most of the required reactive power. Due to the complexity of accommodating all operating
conditions only the periods during which the benefits are substantial have been computed.
Table C 5.1 in Annex C provides the loss savings evaluated for the recommended compensation at
different operating periods. The benefits indicated are the power and energy savings resulting from
the application of the recommended amount of compensation in comparison with the condition
when no compensation is applied. In some of the operating periods considered however the system
voltages are lower than acceptable levels in the absence of reactive compensation. If the network
load is to be supported without reactive compensation, thermal generation is required to be
provided during these periods as indicated in para 5.13 above. Thus it is more appropriate to
compute the value of saved generation during these periods rather than that of loss reduction.
(Since the capacitors will not produce substantial loss reduction benefits with the thermal generation
operational in these periods both benefits cannot be counted).
5.15         The benefit to cost ratios computed in Tables C5.1 and C5.2 in Annex C have been
summarized for various combinations of benefits and are presented in Table 5.1 below.
Table 5.1. Benefit-to-Cost Ratios for Capacitor Application at Ubungo/Ilala
30 Mar      Additional       Total
Benefits considered             Application    15 Mar    45 Mar application
Loss reduction benefits only
(with no generation supplied
for voltage improvement)            8.8         2.5             6.7
Loss reduction benefits only
(with generation supplied for
voltage improvement)                5.0         0.9             3.6
Avoided generation and outages     30.1         6.0            22.1
Avoided generation and outages
plus loss reduction                39.0         8.6            28.8
Payback period considering all benefits = 3.0 months
5.16         It is clear that the proposal is extremely beneficial with high benefit to cost ratios
as well as quick pay back. In addition the benefits remain high even with substantial changes to the
capital costs as well as the rates used to value the benefits. It is important to realize that the
benefits will decline with delay of implementation of the proposal. Thus early implementation of
the proposals is a key element to their success.
Conpmsation to be Pmvied at Arusha
5.17          Without reactive compensation at Arusha no new loads could be added to the system
at Moshi or Arusha as network voltages are already depressed below acceptable levels. Even at



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present loading levels there is considerable load shedding during peak hours and new connections
are withheld in certain areas which experience severe voltage problems. When the generation at
Hale is weak the problems are further compounded as reactive injection at this point will also be
low. In the years before the commissioning of new Pangani Falls there will be difficulties in
maintaining the Hale voltage at a high value (required to keep the line end voltages acceptable)
when operating Hale and Moshi at their firm capacities. In such circumstances the compensation
provided at Arusha will also benefit Tanga by increasing the var flow from Hale to Chalinze.
Correspondingly the compensation provided at Tanga will also benefit Arusha.
5.18        The benefits of the compensation provided at Arusha are evaluated by the increased
load which can be supplied at Arusha and Moshi. The secondary benefits at Tanga have not been
taken account of. (These benefits will only be present when the generation at Hale is low and it
would be difficult to quantify such benefits sufficiently accurately). The benefits are evaluated only
up to commissioning of the Singida-Arusha line. There will however be continuing benefits due to
the ability to meet system outages (of the Singida-Arusha line or any of the line sections between
Hale and Arusha) as well as the possibility of supplying any inductive compensation necessary to
stabilize network voltages when the Singida-Arusha line is introduced. (By installing circuit breakers
on the capacitor units of the SVS, it could be made to operate in the reactive mode as well). Due
to the very long length of the Singida-Arusha line (approx. 300 km) the provision of variable
inductive supply will be a necessity when this line is introduced. The required inductive
compensation could be provided (though less effectively) by other means such as switched or
saturated reactors. Thus in order to allow for the continuing benefits after the commissioning of
this line the net economic cost of the proposal is computed by crediting 30 percent of the total cost
of the SVS unit (considered to represent the alternative cost of inductive compensation) to be
effective 1 year before the line is commissioned. The cost benefit analysis of the proposal is
provided in Table C6 in Annex C and indicates a benefit/cost ratios of 5.0 and 3.1 respectively for
the cost of the proposal being computed with and without the credit for continuing benefits
mentioned above (the SVS installation commissioned by end 1993 and Singida-Arusha line to be
commissioned by end 1995). It is seen that with delays in the commissioning of this line the
benefit/cost ratio of the reactive compensation will increase substantially.
5.19        An alternative solution to enable TANESCO to meet the expected load increases
in Moshi and Arusha is to install switched capacitors (preferably 3 x 5 MVAr each at Moshi and
Arusha). This solution will give a lower level of technical performance and much care will have to
be exercised in the design of the control systems to ensure that satisfactory voltage levels are
maintained and other technical problems (such as possible hunting of circuit breaker operations)
are avoided. However if TANESCO is unable to procure the necessary funds for the recommended
solution with the SVS installation the next best alternative is to proceed with the installation of
switched capacitors thus being able to meet the expected load increases of the two cities although
at a lower level of technical performance. Accordingly Table C6 in Annex C also provides a cost
benefit analysis for this option. An economic comparison of the two options is not feasible as the
technical advantages of the superior solution are not readily quantifiable. Table 5.2 provides a
summary of the benefit to cost ratios and pay back periods achievable for the two options including



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their sensitivity to the capital costs used as well as to the valuation of benefits.
5.20           The benefit-to-cost ratios and pay back periods obtained for the compensation
proposals for both Ubungo and Arusha clearly indicate that it would very advantageous for
TANESCO to install the recommended reactive compensation devices as quickly as possible. The
network is already unable to support the current load and delays in providing the necessary
solutions will result in considerable losses to TANESCO as well as to the national economy. Thus
the urgency of the requirements cannot be over stressed.
Table 5.2. Benefit-to-lost Ratios for Reactive Compensation at Arusha
Years of benefits counted               SVS Installation     Switched Capacities
B/C ratio 1    B/C ratio 2
With Commissioning in 1993 beginning
1993 and 1994                 3.3           5.5           6.6
1993 to 1995                  4.7           7.5           9.6
1993 to 1996                  6.3           9.5           12.8
1993 to 1997                  7.9           11.5          16.2
With Commissioning in 1994 beginning
1994 only                     1.7           2.9           3A
1994 to 1995                  3.1           5.0           6A
1994 to 1996                  4.7           7.1           9.6
1994 to 1997                  6.4           9.2           13.0
Note:   B/C ratio 1    is made without giving consideration to the value of the SVS equipment after
commissioning the Singida-Arusha line.
B/C ratio 2    is made with a rebate of half the value of the SVS given at time of
construction of the new line.



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6. DISTRIBUTION SYSTEM DEVELOPMENT AND PLANNING GUIDELINES
Background
6.1          More than 75 percent of the existing load on the TANESCO system is concentrated
in the cities (and environs) of Dar es Salaam, Tanga, Moshi, and Arusha. Furthermore, the highest
load growth rates are in these same areas. Because of the importance of these areas, and also
because of time limitations, the present study is limited to their distribution systems (the 33 kV and
lower voltage networks). Overall distribution network losses are 13 percent for power and 8.6
percent for energy (see section 3). For the 33 kV lines, power and energy losses are 2.26 percent
and 1.69 percent, respectively. For the 11 kV lines, the losses are 2.44 percent and 1.74 percent,
respectively. Aggregate values, however, do not sufficiently indicate the complexity of the problem
of poor performance or overloading of particular areas of the network. This is because distribution
systems are typically nonhomogeneous, and the poor performance and high loss levels of a number
of feeders are masked by a relatively large number of others with satisfactory performance
characteristics. In addition, the network sections that are already stressed are most often the ones
subjected to further high increases in load demand, so the situation becomes more serious as time
passes.
6.2          The network studies conducted on individual feeders indicate that a number of
supply areas are presently in need of considerable reinforcement and rehabilitation because of high
load growth during the last few years (averaging to as much as 9 percent per annum) in combination
with a lack of adequate investment and planning. The voltage levels at some of the locations are
so poor that existing loads are restricted, and a moratorium is imposed on new connections. In
part, these low voltages stem from poor voltage conditions in the transmission system (discussed
in sections 4 and 5). But rectifying the input voltage levels to the distribution networks alone will
not be enough to alleviate the poor supply standards experienced by the ultimate consumers. The
distribution systems themselves need considerable inputs and carefully planned development to
reduce the high losses and improve the reliability of supply in a number of specific areas. Further,
networks that have deteriorated because of poor maintenance and overloading of equipment over
a number of years also need considerable investment for rehabilitation.
6.3          Over the last six years two major distribution development projects were undertaken:
the Dar es Salaam Rehabilitation Project, funded by the Japan International Corporation
Association (JICA), and the National Rehabilitation Project funded by the International
Development Association (IDA). The Dar es Salaam project carried out certain major
improvements to the primary supply system of that city. The work included augmenting the capacity
of the Ilala Grid Substation, introducing two new primary (33/11 kV) substations, and increasing
the capacity of the 33 kV subtransrnission network by increasing the conductor sizes of a number
of major 33 kV feeders. Improvements to the secondary distribution facilities however, were limited
to certain parts of the city. In the areas covered, approximately one hundred new distribution



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transformers were introduced, low voltage (LV) systems were strengthened, and network
rehabilitation was carried out. The IDA-sponsored National Rehabilitation Project addressed all
three sectors of the power system: generation, transmission, and distribution. Only about 30 percent
of project funds were allocated for distribution system development, spread among 11 towns. The
project was limited mainly to rehabilitation and reconductoring of some lines, addition of
transformer stations, and other augmentation work (such as replacement of overloaded
transformers). Planned network development was not addressed in a comprehensive manner. As
a result, no new primary injection points or major system developments were introduced.
6.4         Despite certain limitations of the two projects, TANESCO's distribution systems
benefitted greatly from them, and without them much of the load addition from 1986 to date would
not have been possible. However, realization of suppressed demand and the addition of new loads
have again reduced many parts of the network to poor operating condition, high system losses, and
poor reliability. The situation is compounded by the fact that TANESCO was unable to supplement
the work carried out by these two projects with regular and sufficient network improvement, mainly
because it lacked sufficient foreign exchange.
6.5         Another matter of concern with respect to the distribution system is that a further
release of suppressed demand will occur when the developments contemplated to improve the
transmission network voltages are commissioned (TANESCO is already actively pursuing the
recommendations contained in Section 5 of this report, and these developments are expected to be
in place within the next two years). Thus, substantial improvements in the distribution networks
are urgent. The improvements must be designed to cater to the expected load growth in the
medium term (the next 5 to 10 years) and blend with the long-term planning possibilities. The
network also needs to be expanded to cover a number of urban developments presently in progress,
and the resulting load development should be anticipated in the system development plans.
Establishment of a Distribution Planning Department
6.6         Distribution networks comprise a vast number of line segments spread over large
geographic areas. Any effective development planning of these networks requires the systematic
collection of a large amount of network data. Such data consists of the physical characteristics of
the existing systems (particularly conductor and transformer sizes), network loads (preferably at
different times of the day), and expected growth rates. The data to be collected are voluminous and
need also to be suitably organized to model the systems so that their performance can be subjected
to the required technical studies. These technical studies will yield information on a number of
important aspects, particularly with respect to system losses, voltage levels, and conductor loadings.
The ability to perform these studies for different network connections as well as alternative network
development proposals for the loading conditions of selected future years make them particularly
important in selecting between various possible alternative development proposals. As in most
power utilities in developing countries, the distribution planning function in TANESCO had not
been adequately institutionalized. The documented data on the distribution systems were inadequate
to undertake any comprehensive distribution planning. Network layouts on geographical maps,



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which constitute the first step in any distribution planning exercise, were unavailable in many
locations, and line diagrams that were available were often outdated. Load readings on important
feeders had not been taken, and whatever information that was available was poorly documented
and not utilized by the planning staff. Because of the shortage of funds to undertake any major
system improvements no serious attempts were made to prepare comprehensive development
proposals. A notable exception is the planning study for Dar es Salaam carried out in 1987; but
such efforts were not followed up to develop the data base or the planning capabilities of the
relevant staff. Further, the improvements that were planned or considered were only short-term
measures to resolve specific local issues, and system-wide network studies were not carried out.
6.7         A major objective of the current project was therefore to transfer the technology
required and establish within TANESCO a distribution planning department capable of applying
state-of-the-art techniques. This is one function that can not be adequately substituted for by
external consultancy services obtained from time to time. The long-term data gathering and
documentation required can be carried out effectively only by TANESCO personnel who are well
acquainted with the networks and other relevant local conditions. Further militating against the use
of consultants is the fact that the data collection phase is time consuming and requires only limited
technical knowledge. Moreover, much of the required data-particularly data related to the past
such as load readings-are already available in various departments within TANESCO. The network
planning studies to be conducted are also fairly repetitive and can be grasped easily by the technical
staff of the utilities in developing countries. Hence, the project work was carried out by establishing
a separate unit within TANESCO to undertake the systematic collection, documentation, and
analysis of the data.
6.8         The new unit established functioned as a centralized distribution planning
department collecting data from the field, coordinating with the various zonal and regional offices
(distribution centers), establishing a centralized data base, and performing the necessary studies.
The staff of the unit was trained in the various techniques of distribution system planning. They
were introduced to state-of-the-art technology in the instrumentation to be used for gathering
system data and in conducting the studies using distribution planning software.
6.9         All aspects of training necessary to enable the TANESCO planning unit to perforrn
unaided after the ESMAP study is completed were provided. The instrumentation used for the data
collection exercise contained electronic logging equipment that can store the load characteristics of
power lines or consumer installations at predetermined intervals for subsequent downloading to a
computer in spreadsheet format. A set of Lotus 'macros" was established to retrieve important
characteristics such as load factors, loss factors, and power factor at selected time periods from the
information downloaded to the spreadsheets. A computer workstation was provided, consisting of
an IBM PS2 unit, a digitizer, and a plotter. The distribution planning software supplied consisted
of a package of programs from Messrs. Scott & Scott of Seattle, USA. The programs in CMED
(Computerized Mapping and Engineering Data) enabled the assimilation of the physical data and
electrical characteristics of networks directly off system maps using the digitizer. The programs in
DPA (for distribution primary analysis) enabled this data to be used for system modelling and



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analysis. The networks are modeled by representing the distribution lines by a number of sections
(with the connected load within the section treated as a point load acting at the center of the
section). The analysis programs enable load-flow studies to be conducted, providing information
on the power carried along various sections, the voltage level at any system location (including the
terminal voltage drop), and line losses. The programs also include the capability of providing load
growth rates in individual sections to enable analysis of system performance for a given future year.
It also enables the location of a given number of capacitors to be optimized for minimizing system
losses on a particular feeder.
6.10         In addition to the network analysis programs described above, an alternative
procedure involving a less rigorous methodology has also been developed to order cover the analysis
of all the networks to be studied within the available time frame. The latter procedure enables the
(approximate) determination of the principal characteristics required (total line losses and tail-end
voltage drop) using certain simplifications and requiring only basic network information. A
description of the methodology used for these simplified calculations is provided in Annex D. The
results of these studies have been checked with the results of the more rigorous analysis where the
computerized data base has been sufficiently developed, and they have been found acceptable. The
use of this procedure has made it possible to undertake the study of all the medium voltage (11 and
33 kV) lines in the study area consisting of the load centers at Dar es Salaam, Arusha, Moshi and
Tanga.
6.11         The calculations described above have provided the losses and tail-end voltages of
existing networks at the present loading levels as well as at those expected in future years. In
particular, the year 1995 has been selected as representative of the period in which the proposed
developments could be commissioned. Using the results of these studies, it was possible to identify
the specific areas of the networks that need to be developed. The next step is to make a number
of proposals to improve system performance and to subject these proposals to the network
computations discussed above, in order to determine the operating characteristics to be expected
from the proposed systems. The proposals that are technically acceptable are then subjected to an
economic analysis using as benefits the network loss reduction and reliability improvements that are
to be achieved. The latter benefits are computed by determining the additional load that can be
supplied by extending the feeders beyond their normal operating positions. A fuller discussion of
the methodology used for the economic analysis is given in paras 6.13 to 6.18 below. Such analyses,
conducted for a number of alternative development proposals, also enable comparisons of their
relative merits.
6.12         The distribution system studies conducted have yielded a wealth of information on
the physical networks as well as on the load characteristics of system components and individual
consumers. The value of this data base transcends the ability to formulate a set of proposals for
the improvement of the present system. The information collected and the techniques introduced
would be invaluable in improving many aspects of TANESCO's long-term planning capabilities.
Distribution system planning can henceforth be done with a full knowledge of the capabilities of the
future systems proposed. The information collected, as well as other data generated during the



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studies, can also be invaluable in load forecasting, load management, and tariff formulations
exercises. Some items of particular importance are loading densities by geographical localities or
feeder coverage, consumer characteristics revealed by their load duration curves, diversity factors
for feeders and consumer groups, load factors, loss factors, and power factors of various system
components. The establishment of computerized system maps and the association of the electrical
data to such a system greatly enhances the value of the data base. One aspect that needs to be
emphasized is the necessity of maintaining the data base keeping it current at all times, with regular
updates of changes in the system. A concerted effort also needs to be made to increase the
application areas and usage of the data gathered. This is the only way to increase the companywide
awareness of the importance of the technology enhancement that has been introduced. The
establishment of the study unit as a permanent branch within the organization of the Deputy
Managing Director (Operations) augurs well for the continuation of the unit to produce useful work
after the conclusion of the ESMAP studies.
Economic Analysis of Development Proposals
6.13         The improvements to the distribution systems proposed in the present study can be
classified as follows:
(a)   System development works for the purpose of loss reduction and improvement of
reliability levels;
(b)   Expansion of the network to new areas to meet urban development needs; and
(c)   Physical rehabilitation of existing networks.
6.14         An economic evaluation of the proposals under the first category can be made by
determining the extent of loss reduction and reliability improvements that will be achieved over an
identified time period. Load flow studies carried out on the existing and proposed systems directly
provide the value of loss reduction benefits. The losses derived from these studies are in kilo Watts
(kW) and are related to the time and date for which the load flow is valid (usually peak time and
applicable for a particular year). The peak time losses can be converted to energy losses (for a
whole year) by using the loss load factor. The losses in subsequent years increase in proportion to
the square of the load growth rate as the line losses are proportional to the square of the current
carried. Thus system losses and correspondingly the loss reduction benefits of development
proposals increase substantially each year, particularly if the load growth of the area is high.
6.15         Reliability benefits arise from saved outages as a result of the ability to feed sections
of the network from more than one feeder (thus allowing for alternative feeding possibilities in the
event of outages). Such 'saved outages' have been estimated by the total expected annual units
consumed multiplied by the estimated per unit increase of reliability. The reliability benefits are
thus proportional to the system load and the increases in future years are directly proportional to



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the growth rate (until the load increases to a level that does not allow for alternative feeding
possibilities).
6.16         The methodology used to compute the loss reduction and reliability benefits over a
period of future years is detailed in Annex D. The multiplying factors (for varying rates of load
growth) to obtain aggregate values for loss reduction and reliability benefits over a given period of
years are also provided in two tables. The Average Incremental Costs (AIC) of power supply in
the TANESCO system at various voltage levels have been computed and the results are presented
in Table C 1.2 of Annex C (see also paras 5.6 to 5.9). The value at the distribution level at 10
percent interest rate, $0.094 per kWh, has been used as the cost of loss savings from the proposed
developments. With respect to the reliability improvements the value of outages saved is generally
many times the cost of the normal power supply. A discussion on the value of reliability benefits
are presented at para. 5.10 in Section 5. For the distribution system developments the value of the
energy saved by reduced outages have been estimated at five times the AIC of power. However in
order to test the sensitivity of the results to lover values the reliability benefit computations have
been repeated at values as low as twice the cost of energy.
6.17         The second category of work covered in the study (see para 6.13) is the expansion
of the existing distribution systems to supply new areas where substantial urban development is
already in progress. Providing electricity to these areas is expected to enhance the development
process and correspondingly increase the rate of consumption growth within a short period. The
economic benefits realized from this work is clearly the value of the expected additional sales. The
best representative figure for such new sales is the cost of alternative production given by the cost
incurred if small diesel plants are employed (see Table C1.2 of Annex C and discussion in previous
para). In evaluating the cost of supply the energy costs attributable to the upstream sections
(generation and transmission developments) necessary to bring supply to the point of
commencement of the distribution investment need to be added to the investment costs.
Alternatively the net benefits of the additional sales are computed based on the difference in value
between the alternative supply costs (of independent diesel generation, which is at distribution level)
and the AIC of supply at the transmission level and these benefits are compared with the cost of
the investment. The latter method has been used in the computations.
6.18         The third category of work envisaged in the proposed development is the
rehabilitation of existing networks which have deteriorated due to poor maintenance as well as by
natural ageing. The upgrading of these networks are more or less mandatory for TANESCO which
has an obligation and even a contractual commitment to continue to supply the existing consumers.
In fact, due to the above reason this work should be given priority over the other two components.
The economic value of the work is in maintaining the assets of the company and its ability to
continue profitable operations. Considering the state of the network components marked for
rehabilitation it is quite evident that the alternative cost (at present value) of postponement of the
rehabilitation works (which inevitably will result in more extensive network replacement at a latter
date) together with the cost of outages in the intervening period will be much higher. It is thus
considered that the specific economicjustification of rehabilitation works identified are superfluous.



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Nevertheless, an approximate cost benefit computation is presented based on the outage savings
estimated to be achieved by rehabilitating the networks. What is more important is to ensure that
an effort is made to ensure that the nature and extent of the rehabilitation works undertaken are
consistent with optimum cost effectiveness. This cannot be achieved by any specific cost/benefit
computations but needs to be made by good engineering judgement.
Existing Distribution Networks
6.19        As discussed at para 6.6 there were no specific guidelines or standards which
TANESCO's distribution planning engineers could have used for measuring the performance of
existing networks or for preparing proposals to meet the load increases expected in the future. This
situation resulted in the networks being haphazardly extended or loaded without consideration for
system performance such as voltage and loss levels, as well as reliability considerations. Unlike
generation and transmission projects which are necessarily lumpy and staggered, distribution system
development should be a continuous process of meeting the gradually increasing load demand in
the various locations. In order to proceed methodically with the development of the distribution
systems to cope with this continuously increasing load demand, TANESCO needs to adopt a set of
procedures, guidelines and performance criteria. These rules need, of course, to be reviewed and
modified from time to time; however it is important that system planners have at any given time
a set of rules and procedures by which to measure network performance and to plan development
works. They should not have to wait until network performance is so intolerable for the consumer
that crisis solutions become necessary.
6.20        As previously discussed, major distribution system reinforcement and expansion
works have been undertaken by a number of externally funded projects. These projects were often
confined to certain areas of supply or had other limitations defining their scope of work to specific
activities (such as rehabilitation or the development of a specific area). Thus these activities have
not produced any company-wide guidelines which can be applied for the development of distribution
systems. On the other hand these projects as well as TANESCO's own practices built up over a
number of years have introduced certain system configurations such as voltage levels, equipment
and conductor sizes etc. Further these characteristics are so widespread within the system that any
new arrangement or alteration needs to take account of the cost of alterations to the existing
networks where this is required. An appropriate strategy would therefore be to examine the existing
network characteristics, evaluate their appropriateness and then examine opportunities for
improvements, rationalizations and developments of new concepts in the context of the resulting
economic benefits.
6.21        The existing primary distribution networks are based on network voltage levels of
33 and 11 kV. The 11 kV systems are generally restricted to developed urban areas while the 33 kV
networks provide supply to the 33/11 kV substations and the larger bulk consumers. In low density
(rural) areas the 33 kV networks run for long distances and supply consumers either directly off
step down transformers or from LV lines connected to such transformers. In some instances the
11 kV lines are also extended for long distances, often commencing from a town and extended to



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over 20 or 30 km to supply rural loads. Many of the high load carrying conductors have been
uprated from a number of lower gauges to 100 or 150 mm. sq. during the course of previous
distribution development projects. Other conductor sizes in use for primary distribution are 50 and
35 mm. sq. The step down transformers providing supply to the LV network range from 50 to as
high as 630 kVA. Many of these are of the higher ratings (200 kVA and over) and are combined
with the use of long secondaries. In most heavily loaded areas 100 mm. sq. conductors have been
introduced for LV feeders. The studies conducted by modeling the feeders and direct measurements
performed indicate that a number of poorly performing MV feeders have peak line end voltages
which drop to as low as 80 percent of nominal and peak loss levels as high as 15 percent of the
power supplied.
Planning Concepts
6.22         The major load centers in the country already have extensive 33 and 11 kV networks
and hence it is not considered economical to introduce any other voltage level (such as 22 kV) at
this time. Further, a review of the feeder losses and tail end voltages of the MV systems indicate
that 150 and 100 mm. sq. ACSR conductor could continue to perform as the standard conductor
cross sections of the main feeders for the loading levels that are to be expected in the foreseeable
future. However, computations carried out (as well as studies carried out eleswhere) indicate that
the economic loading level of conductors is in the region of 25 to 40 percent of thermal limits. Thus
the network configurations need to be designed to provide loading conditions not exceeding these
values. Such reduction of loading levels is best achieved by increasing the number of MV feeders
and 33/llkV substations. This strategy will not only reduce network losses but also allow for
alternate supply possibilities to be arranged in the event of outages on the normal mode of supply.
6.23        As discribed in para 6.21 a number of primary distribution lines which commence
from major load centers have been extended over excessive distances without regard to the voltage
drop that will be experienced at the line extremities. In addition, the reliability of the more
importent loads located at the commencement of the feeder is affected as suitable interupting
devices are not installed along the line. In many of these instances the 1 lkV lines which have been
so extended can be economically uprated to 33kV operation (line losses reducing by a factor of nine
from the former value). The construction work involved will entail the change out of line cross arms,
insulators and transformers along the feeder. In instances where the loads closer to the
commencement of the feeder requires a higher reliability standard the existing 11 kV line can be
retained to feed these loads and a new 33 kV line could pick up the load of the rest of the feeder
by connecting to the section which is uprated.
6.24        In addition to the 11 kV lines there are also a number of 33 kV lines where the loads
and/or the distances are still too great to be supported at this voltage (distances exceeding 100 km
have been encounted). In many of these instances the loads are also too small for the justification
of the next higher standard voltage, 132 kV, particularly in view of the high cost of the step down
substations, 132/33 kV or 132/11 kV which will then be required. The use of 66 kV networks to



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supply these loads could often prove to be economical. (This voltage was formally in use extensively
in the system but alnost all such networks have now been replaced by 132 kV). However the design
considerations to be used for these 66 kV system should follow those for rural networks (with
minimum use of switchgear) in order to keep the costs reduced in line with the level of importance
of the load. Sometimes the existence of decommissioned 66 kV networks available in close proximity
allows salvaged equipment to be used in order to reduce investment costs. An example of the use
of 66 kV as a network voltage is seen from the proposals for the Marangu - Rombo area dealt with
in para 10.6
6.25        Another concept that needs to be developed is the decentralization of the LV
systems. During previous distribution development projects a number of additional MV/LV
transformers have been introduced. This process needs to be continued further and lower capacity
transformers employed to serve smaller areas of coverage. Where feasible it will also be prudent
to obtain supply to the LV distribution network from a number of transformers installed to feed
bulk consumers. With this practice one could also take advantage of the loading diversity between
most bulk supplies (which operate in the day time hours) and the LV networks (which usually have
their peak at night).
Planning Guidelines
6.26        The results of detailed system studies for a large number of MV networks are
presented in the chapters to follow. These studies also include the economic cost benefit analysis
of proposed alternatives. Based on the knowledge gained from these studies it is possible to
establish a set of general guidelines which would approach optimum system performance levels with
respect to network losses and supply reliability. These guidelines may be used as performance
indicators for the continued development of TANESCO's distribution systems. It must however be
emphasized that major network developments must be subjected to system studies and economic
analyses as performed for the proposals contained in this report. The guidelines are to be used
mainly to provide general acceptability criteria. Further in particular instances economic analysis
may dictate the need to deviate from the standards of performance that are provided in the
guidelines.
(A) MV systems in City areas:
A 1. A primary MV system at 33 kV, fed off the grid substations shall be used to feed
33/11 kV substations and where possible large bulk supplies (preferably consumers
over 1 MVA).
A 2. Alternative 33 kV supply routes shall be provided to the 33/11 substations and bulk
supplies over 5 MVA.
A 3. Standard ratings of the 33/11 kV substations shall be 2 x 10, 1 x 15, 2 x 5, and 1 x



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5 MVA. In general substations of smaller capacities are not expected to be economic
as 33 kV could continue to be used for the downstream sections. However where
existing 11 kV networks or other special considerations exist substations of 1 x 2.5
MVA may be considered.
A 4.  Standard sizes of 150 and 100 mm. sq. ACSR 4/ shall be used for the main 33 and
11 kV feeders. The branch lines (where the currents to be carried are not expected
to exceed 50 Amps) will be based on 50 mm. sq. ACSR.
A 5.  The normal operating peak currents shall not exceed 200 Amps for 150 mm. sq.
conductor and 150 Amps. for 100 mm. sq. conductor. Where these values would be
exceeded double circuit construction or additional feeders shall be provided.
A 6.  Insulated conductors and underground cables will not normally be used. Such
construction will only be resorted to when special construction difficulties such as
maintaining clearances are encountered.
A 7.  The 11 kV feeders shall be erected and operated as 'open rings' from the same
substation or be fed from adjacent substations at either end with a normally open
position along the way. The entire feeder shall be capable of being fed from one
source.
(B) MV systems in rural areas
B 1.  The normal MV distribution voltage shall be 33 kV for rural areas. Substations of
33/11 kV and 11 kV distributors shall only be used if it can be demonstrated that
the total costs (inclusive of the 33/11 kV substation and additional network losses)
will be less than for a 33 kV network development.
B 2.  When long transmission distances are involved to lightly loaded areas 33 kV lines
may not be able to satisfy the performance criteria detailed in section D below. In
such instances the use of sub transmission lines at 66 kV shall be considered. When
the use of such an intermediary voltage appears to be advantageous the feasibility
of constructing the line at 132 kV and operating it at 66 kV for an initial period
should also be investigated.
B 3.  The uprating of existing 11 kV distributors to 33 kV shall be evaluated when the
loading density is low and line lengths are long.
4/     ACSR - Aluminum conductor steel reinforced.



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(C) LV networks
C 1. The use of a larger number of transformers and smaller supply areas from each
transformer shall be the main strategy of development. This should lead to over 80
percent of the transformers being of the ratings between 50 and 200 kVA. It is found
that many consumer transformers exhibit peak loads during the day time periods.
These can be effectively used to feed the LV distribution system during the night
time, thus utilizing the load diversity between the consumer groups and enabling the
total load to be supplied by a lower installed capacity. The peak loading of
transformers shall be between 75 percent and 100 percent of nameplate rating.
C 2.  100 and 50 mm. sq. conductors shall continue to be used for the main feeders of LV
systems.
C 3. In city areas all outgoing feeders shall be three phase. Special efforts shall be made
to achieve a good load balance right along the feeders and distributors by systematic
assignment of successive loads to each of the three phases. Regular (possibly annual)
cheks of phase balances are to be made and adjustments made as necessary. Any
single phase branches shall be restricted to the supply of less than eight consumers.
c 4.  In rural areas the use of single phase transformers shall be considered for the supply
to small localities below 50 kVA that are situated close to the MV lines.
(D) Target performance criteria for network planning
D 1.  Systematic load forecasting shall be undertaken to provide the basic inputs to
network planning. The forecasts shall be prepared in a sufficiently decentralized
manner to determine the requirements of each small area of local distribution. The
loading densities of existing systems, both on the LV retail network and the MV
feeders shall be calculated regularly to provide information on the load growth in
these particular areas as well as information on typical loading patterns to be
expected in other developing areas.
D 2. The following maximum limits for peak power loss and voltage drop levels shall be
used for network planning:
Peak      Peak
Power    Voltage
Loss      Drop
NV feeders, City areas      4.0%       6%
MV feeders, Rural areas     5.5%       9%
LV feeders, City areas      3-0%       5%
LV feeders, RuraL areas     5.0%       9%



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D 3.  In order to assist network planners to predict the operating characteristics of the
conductors used in the system a set of graphs indicating the maximum line distance
that can be allowed for varying loading levels in order to maintain the line end
voltage drop below indicated values have been prepared during the study for (a)
lines loaded at their extremities and (b) those with typical load distribution
characteristics. Those that pertain to the maximum voltage drops indicated in the
table above are given in a set of charts (D2) in Annex D.



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7. REACTIVE COMPENSATION ON THE DISTRIBUTION SYSTEM
General Considerations and Methodology
7.1          The previous section detailed the methodology of the studies that need to be
performed to reduce losses and improve the reliability of TANESCO's distribution systems. These
studies have been performed for the networks in Dar es Salaam, Tanga, Moshi, and Arusha and
proposals to bring the systems up to economically acceptable standards are presented in Sections 8
to 12. However, because of difficulties in financing and other logistical problems, TANESCO will
likely require at least four to seven years to complete the work planned. In the meantime,
substantial relief to the poorly performing sections of the distribution system can be achieved
through reactive compensation. The present section deals exclusively with reactive compensation
measures that could be economically applied in the short term on the existing distribution feeders.
7.2         Ideally, reactive compensation should be located as close to the reactive loads as
possible to obtain the greatest benefits in loss reduction. This is so because, with compensation
installed at the source of the reactive demand, the current-and therefore the losses-are reduced
in all components upstream of that source. In contrast, if the compensation is placed between the
source of reactive demand and the source of input power, the current is reduced only upstream of
the compensation.
7.3         A number of considerations complicate the application of the general principle of
installing compensation at the source of reactive demand, however. These are:
*     The fact that compensation may be uneconomical at downstream  locations
individually, but the summation of the loads further upstream may provide economic
opportunities.
*     The need to vary the compensation by switching off excess capacitance as the
reactive load reduces (usually with reduction in active power) could be eliminated
by placing the capacities sufficiently upstream.
*     Since costs of switching and isolation greatly exceed that of the capacitor banks,
considerable economies of scale are realized for larger capacitor installations (which
require that capacities are placed further upstream), particularly when switched
operation is required (see para. 7.9).
7.4         In view of these factors, the most economical program of reactive compensation for
a given distribution system must be determined by a study of the loss reduction benefits obtained
by the application of various sizes of switched and unswitched capacitors at various locations and
a comparison of the benefits with the costs of the respective applications. Several points should be



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noted about loss reductions provided by the use of capacitors for reactive compensation. First, as
the load decreases, the benefits for a particular application decrease substantially; therefore, most
of the benefits are realized during the day and night peak load periods. In fact, overcompensation
can occur during base load, resulting in a small increase of losses. Second, the benefits of each
successive kVAr of capacitance installed on any given feeder decrease incrementally with increases
in power factor caused by the previous applications, creating an optimal point beyond which the
benefits obtained from additional capacitance on the feeder will not be commensurate with the
additional investment required. The initial capacitor installations in a system will thus provide the
highest benefits, and in each successive installation thereafter the incremental benefits will decline
proportionally. Finally, benefits will continue to be realized upstream of a particular feeder of the
distribution system considered, even after they are fully realized in that feeder itself. This is
because improvement of the power factors downstream will also improve the power factor in all
upstream sections (as noted in para 7.2 above). This also implies that the benefits to be computed
should also include the relevant upstream sections of the network.
7.5          The results of a large number of studies on capacitor applications in distribution
systems indicate that the compensation requirements close to optimal application can be determined
by using the following procedure. Firstly, the requirements in the peripheral sections of the
networks which would operate without overcompensation at system base load are identified.
Thereafter further applications at suitable upstream locations are examined in a successive manner
always maintaining approximately full compensation at base load. At each stage the loss reduction
benefits (of both power and energy) should be computed and analyzed for economic acceptability.
Clearly those feeders exhibiting excessive voltage drops and power losses will yield the highest
benefits and particular attention needs to be given to such feeders. The benefits over the initial
years when the existing distribution system is expected to remain unchanged will be high and would
in fact increase as the load grows. However, major network developments to reduce network losses
and improve reliability of supply have been identified in Sections 8 to 11. These developments will
introduce new feeders and substations and would cause substantial alterations to the existing
network arrangements particularly in lines exhibiting high losses at present. With the introduction
of such developments (expected to be effective over the next four to seven years) a substantial
reduction of benefits of the capacitor applications are to be expected. At this stage the suitability
of retaining the capacitors in the existing locations should be examined by conducting new power
flow studies. Sometimes this is possible due to the increased load at that time. If their retention is
not justified or better locations are identified they can be transferred (as an entirety or only the
excess quantity) to other locations requiring reactive compensation for optimum system
performance.
7.6          The feeders that would benefit from var compensation measures were identified from
the network studies carried out (as detailed in Section 6) and additional information on their
physical characteristics and loading conditions were obtained, in particular the power factor at
various times of the day. The losses currently being experienced on these feeders were calculated
using both the approximate analysis methodology and the computer software for network analysis.
Thereafter, the improvement of system losses by the application of capacitors of various sizes was



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determined. The software enabled the selection of the locations along the relevant feeders at which
capacitor installations would provide the maximum benefits in loss reduction. A discussion of the
loss reduction computations made at various voltage levels is provided in paras 7.12 to 7.14 below,
and a summary of the results and corresponding benefit/cost ratios is presented in Tables C.8, C.9,
and C.10 in Annex C.
Economics of Capacitor Installation for Power Factor Control
7.7          Capacitors are installed on distributions systems to control the system power factor
and thereby reduce losses and improve voltage regulation. The benefits listed in para. 5.2 in section
5 for the transmission system are applicable to reactive compensation on the distribution system as
well. However, although the primary objectives of the reactive power control measures proposed
for the transmission system are voltage improvement and the consequent ability to supply additional
loads, the predominant benefits resulting from capacitor installation on the distribution system are
loss reduction (and to a lesser extent voltage improvement). In the TANESCO system the
correction of distribution system voltages to conform to acceptable limits is achieved primarily by
(a) adjustment of the transmission system voltage (discussed in Sections 4 and 5), and (b) changes
to the physical configuration of the distribution system by increasing the number of feeders and/or
new transformer stations (discussed in Sections 8 to 11). Further, although the introduction of
capacitors will enable some new consumers to be supplied in certain networks presently exhibiting
poor voltages, it is not feasible to identify and quantify such benefits. The economic benefits
obtained are therefore evaluated only on the basis of the reduction in energy losses experienced on
the feeder as a result of the improved power factor. The value placed on each unit of energy by
which losses have been reduced was taken as the same as that used for increases in consumer sales
and reduction of losses in the evaluation of transmission voltage improvement measures, namely
US$0.092/kWh (see para. 5.8, Section 5).
7.8          In general, the loading of the lines (on which loss reduction benefits are achieved)
will increase with time. Further, the yearly benefits of a particular capacitor application will
increase at a higher rate than the rate of load growth because an uncompensated line will
experience a rate of increase of line losses equal to the square of the load growth rate. Detailed
studies have revealed that the rate of increase of loss reduction benefits from capacitor applications
has been closer to the rate of increase of uncompensated feeder losses than the rate of increase of
the feeder load growth. If the lower value of the feeder load growth rate is assumed as being the
rate of increase of benefits from capacitor applications, the present worth factor for loss reduction
benefits over a period of 10 years (at an interest rate of 10 percent) would work out to 11.5, 10.5,
and 9.6 for load growth rates of 11, 9, and 7 percent, respectively. The present worth factors over
a period of 6 years would be 7.2, 6.8, and 6.5, respectively, at the same load growth rates given
above. In computing the benefits of capacitor applications in the distribution system, a conservative
estimate of 6.0 has been used for the present worth factor.



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Cast of Capacitor Instalations
7.9         The cost of capacitor installations on the distribution system was estimated by
determining the market costs of the individual components and the installation costs applicable to
Tanzania. Equipment costs for capacitors, switches and other ancillaries are shown in Table C 7.1.
in Annex C. The installed costs of unswitched capacitors are presented in Table C 7.2 and for
switched capacitors in Table C 7.3. For unswitched capacitor banks rated between 50 and 600 kVAr
the estimates of installed costs range from $ 46/kVAr to $ 5.2/kVAr respectively (all costs are
stated in United States dollars at mid 1991 prices) for installation on the 11 kV system and from
$ 65/kVAr to $ 6.7/kVAr for operation at 33 kV. Specific costs for switched banks of similar ratings
range between $ 72.3 and $ 7.4/kVAr installed on the 11 kV system and between $ 166.7 and $
15.3/kVAr if installed on the 33 kV system. Installation of the capacitors on the 11 kV system
(instead of 33 kV) will provide the dual benefits of greater reduction in losses as well as lower
investment costs. It will be seen from the tables that the specific costs of capacitor banks rated less
than about 200 kVAr are too high for their application on the TANESCO system to be economical.
7.10        For efficient inventory management, the ratings of capacitor banks applied on the
distribution lines should be restricted to a small number of standard sizes. The calculations made
during the course of the study showed that for the loading conditions experienced in the TANESCO
system, banks with standard ratings of 600 kVAr would be best suited for the first stage of
application for the most heavily loaded feeders. When placed at the substation busbars (i.e., at
11 kV), the ratings could be as large as required in each case, generally providing up to full
compensation at base load. Capacitors varying from 1,000 to 3,000 MVA could be used at the
various substations.
Coanputaon of Loss Reducton Benfis
7.11         Loss reduction benefits (in terms of kilowatts saved for a given loading condition)
for the various feeders and networks studied have been obtained using both the approximate
spreadsheet methodology (see Annex D) and the software package mentioned earlier. The software
program used also selects the location at which a given capacitance should be installed to maximize
the loss reduction benefits. However, as the analysis using the software package has not been
completed for the entirety of the systems in the four study areas, the results of the spreadsheet
computations have been selected for the analysis. The loss reduction benefits are usually highest
when the feeder is carrying its maximum load. At lower loads (off peak, usually represented by
shoulder and base-load steps), the loss reduction achieved will be lower than at peak. The situation
is complicated, however, by the fact that the power factor of the feeders vary considerably between
the different periods of the day. In many instances, the daytime power factor is substantially worse
than at night, even if the loading of the feeder is higher during the latter period. Further, a simple
relationship is not available between the loss reduction (of capacitor applications) at the different
times of day as in the case of loss reduction achieved by reduction of feeder currents or conductor
resistances. In view of these complications, the reduction of energy losses (in kWh) achieved by
capacitor applications are computed for most applications by determining the loss reduction



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achievable at the three selected steps of the load duration curve; peak, shoulder (mid load) and base
load. Multiplying the loss reduction at each level by the duration for that level and adding the
resulting energy losses for all three tiers will yield the total loss reduction over the period
considered (usually one year). Alternatively, the energy savings can be calculated from the peak
load power loss reduction by use of the loss reduction load factor-a factor that will convert the
reduction in power losses at times of peak demand achieved by specific corrective measures to the
corresponding energy loss reduction over the (yearly) load cycle. The peak loss reduction (in kW)
multiplied by the loss reduction load factor and 8,760 (hours per year) will provide the annual
reduction in energy losses (in kWH). As with the loss reduction benefits (noted in para 7.4 above),
the loss reduction load factor will also be higher for the application of the first capacitor bank and
will decrease thereafter for successive applications. This is because with a fixed capacitor in the
system the power factor will keep increasing as the load decreases from peak load to base load.
Using the three-tiered load duration curve as before the loss reduction load factor can be computed
from the loss reduction at each load condition using the following formula:
loss reduction load factor
(APPxT7p) + (APmxTm) + (A PbXTb)
A Ppx ( Tp+ Tm+ Tb)
where          aPp, Tp          refer to the peak loss reduction and time in hours (per year),
respectively. The corresponding values for shoulder (mid) load and base load are given by the
subscripts m and b, respectively. When the loss reduction load factor method is employed, only
the peak loss reduction is determined, and a suitable loss reduction load factor is selected using the
factors determined for feeders having similar loading characteristics. The studies carried out
indicate that for the heavily loaded feeders, the first application of banks of 600 kVA rating gives
loss reduction load factors of about 70 percent or higher, whereas subsequent applications produce
loss reduction load factors of between 60 to 40 percent.
Loss Reduction Benfls at Various Voltage Levels
7.12         Drawing Fl-i in Annex F shows the 33 kV network in Dar es Salaam, which is
supplied by the grid substations at Ubungo (220/132/33 kV) and Ilala (132/33 kV). The drawing
shows the geographical layout of the 33 kV feeders from these grid substations to the 33/11 kV
distribution substations and the major consumers fed at this voltage. Drawing F.2 in Annex F shows
the 11 kV network, which obtains supply from the above substations and performs the distribution
function to the various areas of the city. The benefits of capacitor applications have been computed
in three stages. First, the loss reduction benefits on the 11 kV lines themselves by the application
of capacitors on these lines have been computed. Next, benefits on the 33 kV lines because of the
capacitors considered earlier (installed on the 11 kV lines downstream), followed by new
applications at the 33/11 kV substations (usually at the 11 kV bus bars), were computed. Finally,



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the transmission load flow program was used to compute the loss reduction that will be achieved
on the transmission system (in particular in the 132 kV line from Ubungo to Ilala) for the
applications already selected at a lower voltage level.
7.13        Table C8 A and B in Annex C provides the results of the capacitor application
studies on 11 kV feeders at Dar es Salaam. In section A, the feeders are modeled according to the
present network arrangement. In section B, the arrangement is altered to represent the changes
that will be introduced by the system development proposals recommended in section 8 of this
report. Applications of 300 and 600 kVA have been studied on a large number of feeders, and the
tables provide details of power factor improvement and loss reduction achieved at the three load
steps. The energy savings achievable for the network loads of 1991 and 1995, together with the loss
reduction load factor and the rate of increase of benefits (over the period 1991 to 1992), are also
computed. The latter two figures provide valuable information on the characteristics of loss
reduction benefits of capacitor applications and may be used for feeders exhibiting similar loading
characteristics. Section B of Table C8 provides information on the reduction of the benefits
realizable from feeders that undergo changes consequent to the introduction of the recommended
network improvements.
7.14        The benefits realizable in the 33 kV networks are presented in Table C9 of Annex
9. The network alterations described above cause only minor changes in this case (restricted mainly
to the Wazo hill feeders I and II) and are indicated in the table. A summary of the benefits
achievable in the transmission system is presented in Table C10 of Annex C. Loss reduction
benefits in the transmission system are presented with the system conditions as at present for the
network loads of 1992, with the introduction of the second circuit Kidatu to Morogoro for the loads
in year 1993 and with the completion of the second circuit up to Dar es Salaam for the loads of year
1995. It is seen that substantial benefits are realized for the initial years but reduce considerably
when the proposed transmission line developments are commissioned. Thus, a peak time loss
reduction of 320 kW and 195 kW per 1000 kVAr of capacitor application are obtained for the whole
system for the initial installation and when the total capacitor installation increases from 7,000 to
8,000, respectively. For the subsequent years studied, namely 1993 and 1995, the corresponding
benefits reduce to 25 and 89 kW in 1993 and 16 and 59 kW in 1995, respectively. These reductions
are caused by the increased reactive generation of the transmission lines as well as the improved
system voltages in the later two years. Even the loss reduction of the Ubungo-Ilala line shows a
corresponding reduction, varying from 20 to 10 kW per 1,000 kVAr of compensation. In computing
the economic benefits of the capacitor applications only, the benefits along the Ubungo-Ilala line
(for capacitors placed on lines downstream of Ilala) is considered, at a conservative figure of 10 kW
per 1000 kVAr. The benefits for the overall system have been omitted, particularly in view of the
recommendations to install other reactive compensation equipment for the transmission
system-whose introduction will greatly reduce the benefits that can be achieved by the capacitors
in the distribution network. The larger quantities and switching facilities required by the
compensation for the transmission system also do not allow its function to be provided solely by the
compensation in the distribution networks.



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Recommendations for Reactive Compensation on the Distribution System
7.15         Based on the results of the benefits at various voltage levels, ten 11 kV feeders have
been selected in Dar es Salaam for capacitor applications by units of 600 kVAr each. The benefits
computed at each level are assembled in Table Cll (section A) of Annex C to present the total
benefits that can be attributed to a particular application. In considering upstream benefits on the
33 kV lines for applications at 11 kV, each application associated with a particular 33 kV line is
taken in turn, and only incremental benefits are credited. The installations are expected to be
commissioned in 1993, and the benefits based on the existing system is assumed to occur up to 1996.
Thereafter the 11 and 33 kV networks are assumed to be altered by the proposed system
developments (given in section 8). An examination of the results of capacitor applications after the
new developments are introduced (see Table C8B) indicates that most of the high-benefit
applications in the earlier system now show a substantially low level of benefits. This is particularly
because it is the poorly performing feeders that are substantially altered in the new developments.
It is therefore proposed that the capacitors be removed from their former application and
reassigned to feeders that produce better loss reduction benefits. The best locations for their
reallocation are presented in section B of Table Cll, and the benefits are computed for the years
1997 to 2008, providing for a 15-year lifetime. These benefits are added on to the benefits
computed for 1993 to 1996, and the total discounted benefits and the resulting benefit to cost ratios
are given in section A of Table C1l.
7.16         It is seen that the selected applications have very high benefit-to-cost ratios (ranging
from 12.5:1 to 43:1) and low payback periods (ranging from 9 to 1.5 months), indicating the highly
profitable nature of the use of reactive compensation measures in the distribution system,
particularly as short-term measures. The overall benefit-to-cost ratio for the 10 applications in the
11 kV lines works out to 23: 1, and a total of 1.4 MWh per year of energy can be saved at 1991 load
levels.
7.17         In addition to the capacitors placed on the 11 kV network, additional compensation
can be effectively employed at a number of 33/11 kV substations. The loss-reduction benefits that
can be achieved on the 33 kV lines is seen from Table C9 in Annex C. Benefits that can be
assigned to the application at the substations are only those that are incremental to the applications
already considered at 11 kV. A computation of the benefit-to-cost ratios and payback periods of
selected applications at the substations are presented at Table C12 of Annex C. It is seen that
about 5,300 MVAr of additional capacitors can be economically employed at the substations
selected. Even after allowing for only the incremental benefits, the benefit-to-cost ratios for these
applications still remain substantially high (varying from 8.7:1 to 17:1).
7.18         As discussed earlier, the installation of capacitors in the distribution system improves
the power factor and reduce losses in the transmission system. The capacitors will thus assist the
transmission system operation during system peak and at other heavy load times (when a reduction
of the power factor is desired). The proposals in this section recommend the installation of 15.3
MVAr of capacitors in unswitched mode. In para. 4.10 of Section 4, a recommendation was also



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made for an unswitched 20 MVAr reactor to be installed at Ras Kiromany. The capacitors
recommended in the distribution system may be considered to offest most of the reactive vars
introduced by the reactor at Ras Kiromany. This further means that the cost of the additional 20
MVAr of compensation included in the economic evaluation of the proposal to shift the reactor to
Ras Kiromany could be reduced substantially from the analysis when all the proposals are
considered together.
7.19        In para. 4.11 of Section 4, the necessity for compensation of the reactive load at the
Tanga grid substation was discussed. The benefits of this investment (loss reduction on the 132 and
33 kV lines) are evaluated in Table C 3. Clearly, compensation would be best provided at or as
close as possible to the cement factory, which is the major consumer supplied from this station and
is fed by an 11-km-long 33 kV feeder. Since this compensation is to be applied at distribution level
details of the recommendation are included in this section.
7.20        The compensation at Tanga and at two other installations selected at Dar es
Salaam-Wazo Hill and ALAF-are primarily dependent on the power factors of the large factories
supplied at these locations. The studies conducted on the basis of power factors determined by
measurements at these locations take into account any compensation presently employed.
Installation of compensation at these locations must be carefully coordinated with the major
consumers, who may have plans of their own for improving the power factor of their operations.
Summary of Recommendtions
7.21        In consideration of the loss reduction benefits presented in Tables C.8 to C.12 of
Annex C and the discussion above, it is concluded that very high economic benefits will be achieved
by proceeding with the early application of reactive compensation measures in the distribution
system. A summary of the applications selected on the lines as well as the substations is provided
at Table 7.1, along with the benefit-to-cost ratios and payback periods. With respect to the
installation of capacitors at consumer substations, careful coordination is required with the
consumers' own programs.
7.22        Total distribution system energy losses are estimated at about 73 percent of gross
generation (see Section 3). This percentage corresponds to approximately 100 GWh per annum.
The loss reduction that would be achieved by implementation of the recomnmendations made above
for installation of capacitors would result in reduction of distribution losses by about 2.5 percent
(which represents 0.2 percent of the total energy produced). The major reduction in technical losses
to be achieved on the distribution system will be accomplished by various network improvement
measures dealt with in Sections 8 to 11. The reactive compensation measures proposed for the
distribution system in this section provide loss savings (at present loading levels) of 2.8 GWh/year,
an overall benefit/cost ratio exceeding 10/1 and a payback period less than 7 months.



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Table 7.1. Capacitors Recommended for Installation in the Distribution System
capacl   Total units saved      Pay    B/C
Feeder        Change location size    MWh/year               Back in ratio
Installed     (after 1996)   kVAr        1991   1995         months
On 11 kV lines
K4, Industrial   Kigam Fl         600    295    339              1.4   39.7
K3, Kilwa road   Kigan F2         600    130    133              3.1   18.5
Port          Port                600    129    181              3.1   20.7
03, Packers    04, Kinondoni      600    170    174              2.4   22.0
Dio, Magomeni D2,Town1           '600    105      94             3.9   13.3
MK1,Msasani   MK4,north east      600      61     87             6.6   12.5
MK2,Tandale   F31,industrial      600    131    211              3.1   31.2
Kunduchi      F2, RTD             600    274    492              1.5   43.1
Ul,Kisiwani    U1,Kisiwani        600      57     99             7.1   15.1
U2,Menzeese   Lugalo              600      50     67             8.1   13.9
TOTALAPPLICATIONSON11 KVLINES            1402   1877                    23.0
AT 33/11 kV Substations and consumer installations
ALAF                              500      53     59             8.6   15.8
WAZOHILLCEMENT FACTORY           3000    450    566              6.1    8.7
K;URASM                           600      49     72            11.2   20.9
OYSTERBAY                         600      59     69             9.3   16.0
MBEZ                              600      33     53            16.6   17.1
TOTAL APPLICATIONS AT SS.
DARESSALAAM                      5300    644    819              7.5   12.5
TANGACEMENTFACTORY            2 x 4000    815   1349             5.3   21.0
Total for applications
on lines and substations                 2861   4045             2.9



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8. DEVELOPMENT PROPOSALS FOR DAR ES SALAAM
The present distribution system
8.1         The present peak load on the Dar es Salaam network is approximately 110 MVA
and is supplied from the transmission network by two grid substations, one at Ubungo (2 x
50 MVA) and the other at Ilala (2 x 45 MVA). Four bulk consumers (Wazo hill cement factory,
ALAF, Tazara and Friendship Textiles) supplied at 33 kV contribute 20 MW and the rest of the
load (90 MW) is distributed along the 11 kV network supplied by eleven 33/11 kV (primary) step
down transformers. The present feeder loads on the 33 and 11 kV network as well as calculated
peak losses and end voltages are presented in Table A.2.1 of Annex A.
8.2         The present overall loss level (2.2 percent at peak) on the 33 kV system is generally
acceptable. Currently the only feeder exhibiting an excessive loss level is the Wazo Hill II feeder
(supplying the Wazo Hill cement factory) with present peak losses of 4.9 percent (and a terminal
voltage drop of 5.7 percent). The load on Wazo Hill I feeder will also increase substantially over
the next few years and the network covering the area supplied by the two feeders will need suitable
augmentation. In addition the Factory Zone Im feeder also shows a moderately high peak power
loss of 4.1 percent. Proposals to reduce the losses on the Wazo Hill II feeder and to optimize
feeding arrangements for the area supplied by the Wazo Hill I feeder (while catering for the
expected load increases) are provided in this report. The losses on the Factory Zone IH feeder are
best reduced with the altered feeding arrangements to be made consequent to the second 220/132
grid substation expected to be introduced in Dar es Salaam (see para 8.11) along with the
introduction of the second Kidatu-Morogoro-Dar es Salaam 220 kV line. Thus possible
improvements to this feeder are not considered to be economical at this stage.
8.3         The overall losses in the 11 kV system (averaging about 3 percent at the 1991 peak)
are also not excessive. However there are a few feeders that individually exhibit excessive losses
and line end voltage drops. Five of the worst performing feeders are the Kunduchi feeder from
Mbezi, Industrial feeder from Kurasini, 04 and 06 feeders from Oyster Bay and the MK2 feeder
from Mickocheni. The first of the above feeders already has a peak losses exceeding 10 percent
while that of the others range from 5 to 8 percent. The loss levels of all feeders would however
increase with load growth if system improvements are not carried out. Thus in order to ascertain
the state of the system in the future a calculation of the losses and voltage drops to be expected in
1995 in the absence of any system development works is also provided in Table A.2.1. The loading
densities of the areas as supplied by the existing feeding arrangements provide important
information particularly in estimation of load growth both for the existing networks as well as for
future expansions and are presented in Table A.5 of Annex A. In the following paragraphs various
areas of the network that require improvements are examined and solutions proposed to overcome
excessive loss levels and poor reliability conditions. The proposals are intended to provide
economically acceptable network configurations over the next five to ten years allowing for some



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additional investment that may be required due to various local load development not currently
identifiable. Loss reduction and reliability benefits for the development proposals are computed
as discussed at Section 6 and cost benefit analyses of the proposals are also presented. While these
proposals primarily cater to the development of the existing systems the capacities of the substations
and main feeders are also configured to accommodate the expansion of the networks to new areas
that would be electrified shortly.
Network Development proposals
Wazo MI and RUwdh wea=
8.4         The area north west of the Msasani Bay has a load of about 7 MW at a cement
factory at Wazo Hill with a large number of tourist hotels along the Kunduchi and Mbezi beach
fronts. The 33 kV Wazo Hill feeders from Ubungo feed the loads; with feeder No II supplying the
Cement factory and feeder No I supplying the Mbezi Substation. Mbezi and Kunduchi areas are
supplied from 11 kV feeders from the latter. A new housing development has commenced
stretching from Mbezi and extending north along Tegeta and Boku up to Ras Kiromany. An urban
development plan has also been prepared for the area and water supply, schools and community
facilities are in the process of being developed. In addition tourist hotels are also expanding and
new ventures are being introduced. The 11 kV feeder supplying the area presently has the highest
percentage losses (11.5 percent) and clearly will not be in a position to pick up any additional load.
Thus a network rearrangement with additional injection from the subtransmission system is very
desirable. The 132 kV line to Zanzibar via Ras Kiromany passes through the area in close
proximity to the cement factory. This line is very lightly loaded and increasing the load on the line
would also help in controlling the transmission system voltages at the line extremity. A suitable
location has been identified for a proposed grid substation close to the Bagamoyo road. The
identified location lies approximately mid way between the two load centers, 2.5 km from the
cement factory and 2.0 km from the Kunduchi area. Two short double circuit 33 kV feeders from
the grid substation could be constructed, one to the Cement Factory and the other to a new
33/11 kV substation at Kunduchi. An economic analysis of this proposal is presented in Table E. 1.1
and is found to be very economical with a benefit to cost ratio of 8.0. The benefits from the
proposed system consist of a substantial loss reduction by transferring load from the 33 kV system
to the 132 kV system, introduction of new capacity to cater to the growing load demand in the
Kunduchi area and the improvement of reliability to the cement factory as well as the Kunduchi-
Mbezi areas. The substation at Kunduchi will be of initial capacity of 5 MVA (with provision for
expansion to 2 x 5 MVA when the load grows sufficiently). The new substation will have 5 feeders:
north along Bagamoyo Road, north along the Kunduchi beach, west to feed some local distribution,
and two circuits south along Bagamoyo Road.



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The Msasani Peninular
8.5          The Msasani peninsula is presently fed by Feeders 0 3 and 0 6 from the Oyster Bay
primary substation together with feeder MK 1 from the Mikochnai primary substation. Feeder 03
in particular is heavily loaded and exhibits high losses. The two primary substations are situated
at a considerable distance from the main load center and the arrangement of the feeders does not
provide sufficient reliability. This is a significant disadvantage since the area covers the best
residential district in the city. The load growth over the last few years has been quite substantial
and is expected to be maintained at a high rate for a few more years before reaching saturation
levels. The high growth rate will cause the network performance to worsen in the coming years.
In addition to the poor performance of the feeders the two substations supplying the feeders are
also heavily loaded. Oyster Bay substation is already loaded up to its capacity and it is expected
that the Mikochani substation will reach its design rating by 1995. Thus an additional supply point
within the peninsula is clearly required at a very early date. Obtaining suitable land at the center
of the peninsula (approximating to the load center) is difficult due to the prime value of land in the
area. TANESCO has however been able to secure a site a short distance away. The feeders from
the proposed substation have therefore been designed from this location and the loss reduction
benefits and capital costs computed accordingly. The cost benefit analysis of the proposal is
presented in Table E 1.2 of Annex E. It is however recommended that efforts be made to obtain
a more central location, which will further increase both the loss reduction and reliability benefits.
The City Center area
8.6          The existing city center substation has the highest load among the primary
substations in Dar es Salaam. Many large buildings presently under construction will cause a
substantial increase of load in the near future. In planning the developments required a growth rate
of 7 percent has been used for the period up to 1993. Thereafter, the growth rate is assumed to
level off gradually down to 2 percent to account for the saturation that would occur as the available
land is built up. Although the network losses are quite low in the existing feeders off the City
Center substation due to the short distances, the feeders are highly loaded, two of them being in
the range of 250 to 300 Amps and two others being in the range of 150 to 200 Amps. The high
loading of the feeders prevents their extension for exigency situations. Being the administrative and
commercial center of the country the area should have a high reliability of supply. A suitable site
for an additional primary substation has been located at Sokoine Drive, which is situated in the area
experiencing the highest load growth. The cost/benefit analysis of the introduction of an additional
primary substation (33/11 kV, 15 MVA) at this location is given in Table E 1.3 of Annex E. In the
absence of this development the capacity of existing primary substation at City Center would need
to be augmented in the near future. This alternative investment required and the high value to be
assigned to reliability benefits are specific advantages of the proposal and a benefit to cost ratio of
18.6 is attainable.



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Kidongo-Chekundu and C*ang'ombe areas
8.7         The area along Pugu road south of Ilala is another location that can benefit by
injection from the 33 kV system. The southern section is fed by two feeders one from Kurasini and
the other from Ilala. Both these feeders are loaded at the line extremities. The feeder from
Kurasini in particular has a very high loss level (7.3 percent at peak). The western side, closer to
the city is fed by feeders D 2 and D 9 from Ilala and feeder C 5 from City Center. These feeders
do not have high losses due to the short distances. However the loading levels are high (close to
200 Amps) and the loads supplied do not have sufficient alternate feeding possibilities. TANESCO
is presently considering the possibility of two substations one at Kidongo-Chekundu (for the western
section) and the other at Chang'ombe (for the southern section) and sites for the two substations
have already been identified. Possible 11 kV connections investigated if both substations are to be
constructed give quite low loading levels for the substations as well as the feeders. The introduction
of a single substation would suffice for the next ten years or so and the Chang'ombe site is
considered to be the more economic to be introduced at the first stage. A substation at this site
is capable of reducing the high losses of the Industrial and the D 1 feeders as well as in providing
the reliability back up for the Kidongo-Chekundu areas. The new substation will feed a double
circuit line along Pugu road. These circuits would take over the existing D 1 feeder load (Keko
Mwanga area) and the end portion of the port access feeder (north Kurasini). The latter area will
now obtain supply from a rearrangement of the feeders D 1, D 2 and D 9 from Ilala. Part of the
load of the D 3 feeder from Ilala will also be transferred to a new feeder from the proposed
Chang'ombe substation. The cost benefit analysis of this proposal is presented in Table E 1.4 and
is justifiable with a benefit to cost ratio of 12.6.
Magomeni, Manzese and Tandale areas
8.8         The area between Ilala and Ubungo on either side of the Morogoro road is of
medium load density with a mixture of residential and industrial load. The area is fed from the line
extremities of four feeders one each from the primary substations flala (D 10), Oyster Bay (O 4),
Mikocheni (MK 2) and Ubungo (U 2). The loading levels and feeder lengths can be approximately
halved by a suitably located primary substation. It may be noted that such an arrangement will
reduce the network losses to one eighth of the former value resulting in a loss reduction of
approximately 88 percent! At present TANESCO is considering a site for a future substation at
Magomeni. However the location selected is not so centrally situated as to enable the reduction
of the load on most heavily loaded feeder, MK 2. This feeder is one of the five most poorly
performing feeders in Dar es Salaam with peak losses of 4.7 percent and a voltage drop of 8.0
percent. Thus any development proposals for this area should address the poor performance of
feeder MK 2. It is thus recommended that the proposed substation be shifted towards Mwembe-
Chai so that the ends of the four feeders mentioned above can be connected to the new substation.
A cost / benefit analysis of this proposal is given in Table E 1.5 of Annex E and yields a very
economic ratio of 31.2.



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Load development in the southern and south western suburbs
8.9         A number of new developments are taking place in the southern and south western
suburbs of the city. The areas with the highest load growths consist of Tabata (in the western side,
a short distance north of the airport), Temeke-Yombo (south of Pugu road and east of Kurasini)
and Mbagala (south of Kurasini). Studies were made to ascertain the system improvements that
are required to ensure that the load growth can be met at technically satisfactory and economically
optimum levels. The Tabata area is only about 3 km away from the primary substation at Factory
Zone II and a separate primary substation would not be required at the loading levels to be
expected in the medium term. The new load should therefore be met by additional 11 kV feeders
as required by the load concentrations. The specific development of the networks in this area may
also be postponed until a firm decision is taken on the location of the proposed receiving substation
for the additional 220 kV circuit from Kidatu.
8.10        In the Mbagala area a 33 kV line has already been constructed from Kurasini to feed
a glass factory, which, however, failed to go into production. This line, currently unused, could be
used to connect a new primary substation that could then reduce the supply length of the existing
Kilwa road feeder from Kurasini. The new substation could in fact separate the Kilwa Road feeder
to 3 portions, two being fed from the new Mbagala substation (on either side) and the remaining
section being fed from Kurasini. The Temeke-Yombo areas can also be supplied from the new
Mbagala and existing Kurasini substations by constructing the required 11 kV lines. The cost
benefit analysis of the proposal is given in Table E 1.6 of Annex E and indicates a very economic
ratio of 14.0
Future bwusmison developments and overall feeding arrangements for Dar es Salaan
8.11        A second 220 kV transmission line is planned for construction from Kidatu to Dar
es Salaam (the first stage up to Morogoro being already under construction) to rectify network
voltages, improve reliability and reduce system losses. This additional circuit will also be particularly
useful with the commissioning of the Kihansi project by about 1989. TANESCO is presently
considering a new step down station in the Temeke area (south of Ubungo) to receive power from
the new line. This option is clearly advantageous for a number of reasons. Firstly it enables an
additional injection point to the distribution network to be provided instead of increasing the
capacity of the existing step down station thus improving the reliability of the network. To
maximize the system reliability transmission connections should be provided from the new station
to Ubungo (preferably at 220 kV) and Ilala (at 132 kV). The network will then form a solid
interconnection between the three feeding points of the Dar es Salaam area providing optimum
security of supply to each point. Secondly, feeders from the new station can rationalize the 33 kV
network reducing a number of feeder lengths considerably. In particular the Temeke area is
situated close to the load concentrations at Pugu Road (consisting of the Factory Zones I & II, and
the directly supplied industries TAZARA and ALAF) and it wiU be logical to transfer these loads
to the new station. Further supply can also be conveniently provided to Kurasini and the proposed
Mbagala substations. Due to the expected development of the new receiving substation in the



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Temeke area the development proposals for Temeke and Tabata areas are best postponed until the
location and arrangements for the new receiving station is finalized.
8.12        In contrast, the area north of Ubungo is unlikely to receive any additional
transmission connections for the foreseeable future. Thus it would be prudent to proceed with the
early introduction of a 132 step down station at Wazo hill utilizing the existing line to Zanzibar (see
para 8.4). An examination of the existing grid substations and the two proposals indicate that the
network would be geographically well positioned to provide the city and suburbs of Dar es Salaam
with an efficient power supply system. Ubungo and Ilala already provide two main supply points
with Ilala conveniently located to feed the city center area. Future load growth is expected towards
the north and south of the presently developed areas and convenient locations for grid substations
are proposed for both. Adequate 33 kV network routing possibilities are also available to provide
the required supply lines and interconnections. The proposed primary substation development
envisaged in this report is also observed to blend well with the anticipated transmission
development. TANESCO should therefore pursue the identified options as early as time permits.
Summary of MV development proposals for Dar es Salam
8.13        The system development proposals described above for the city of Dar es Salaam
are summarized below. These proposals aim to reduce network losses to economic levels, improve
reliability of operation and provide the necessary capacity for the expected future load.
Item                               Ref to C/B      Cost in US$    B/C Ratio
table          000
Grid SS5/ at Wazo & Pr. SS            E.1.1           2278            7.9
Pr. SS at Msasani                     E.1.2           983            11.7
Pr. SS at City Center                 E.1.3            898           18.6
Pr. SS at Chang'ombe                  E.1.4           555            12.6
Pr. SS at Mwembe-Chai                 E.1.5           651            31.2
Pr. SS at Mbagala                     E.1.5           493            14.0
5/     SS denotes substation and Pr. SS denotes primary subatation (33/11 kV)



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9. SYSTEM DEVELOPMENT PROPOSALS FOR TANGA REGION
The Present Distribution System
9.1         The area studied under the Tanga region extends much beyond the Tanga town and
its environs. It covers nearly 100 kilometers westward from the coast and about 80 kilometers along
the North-South direction. Supply to the distribution network is provided from two main sources.
The Tanga town, adjoining areas westward, and the coastal belt are supplied from the 132/33 kV
grid substation at Majani Mapana (2 X 20 MVA). The inland area is supplied from the Hale
complex (power plant and 132/33 kV grid substation) and the Pangani power station feeding
directly on to the 33 kV lines. The largest load in the region is the Tanga Cement Factory, which
is supplied by an 11 km double circuit 33 kV line from the Majani Mapana grid substation. The
Tanga town has an 11 kV distribution system fed from a 33/11 kV substation situated adjacent to
the grid substation. More than 20 other small capacity (300 to 2000 KVA) 33/11 kV substations
are dispersed over the region to feed small 11 kV townships networks. Supplies are also provided
to some localities and bulk consumers, notably sisal and tea estates, by the 33 kV network. The
feeder losses and voltage drops on the 11 and 33 kV lines in the region are given in Table A 2.2
of Annex A for the present loads and those expected in 1995.
9.2         Because of the poor voltages received from the transmission system, the Tanga
Cement Factory is restrained from operating at its full capacity. However, the deficiencies of the
transmission system are anticipated to be resolved within the next two years, and the distribution
system should then be capable of providing the full load expected from this consumer in the most
economic manner.6/ In addition to the restriction on the load of the Tanga Cement Factory, a
load of about 2.0 to 2.5 MW is shed at system peak due to the capacity shortage at the Majani
Mapana 33/11 kV substation. The network feeding Tanga town also needs to be rationalized and
its reliability improved in keeping with the importance of this load center. The geographical lay out
of the medium voltage network in Tanga town and its vicinity is shown in Drawing F 2.1 in
Annex F.
9.3         The interior areas of the Tanga region are of very low loading density and are
supplied by very long subtransmission lines at 33 kV. The network arrangement is shown in
Drawing F.2.2 of Annex F. Two 33 kV developments from the switching station at Neusegan, one
stretching westward via Korogwe to Toronto and Handeni and the other stretching eastward up to
the switching station at Kange (close to Tanga) form the backbone of the supply system. From the
Kange switching station two 33 kV feeders supply the northern (Moa) and southern (up to Kigombe
and Bushuri) coastal areas. There is also a feeder proceeding south from the Hale 33 kV switching
station towards Mgambo. The western feeders towards Toronto and Handeni are both
6/     By recommendations discussed in Sections 4 and 5 as well as the New Pangani power station expected
in 1995.



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approximately 110 km long and exhibit losses of 5 and 4 percent respectively at present loading
conditions. The voltage drop at Toronto is of the order of 7.5 percent The loads are however too
small and dispersed to justify injection from the transmission system (at 132 kV) or a development
at an intermediate voltage of 66 kV. Satisfactory voltage to the consumer can be maintained at
present by regulating the 33/11 kV transformer tapchangers. If required a regulating transformer
could also be installed mid way along the line at a later date.
9.4         In addition to the long 33 kV lines there are a number of 11 kV lines that are
excessively long and exhibit high losses. These include the Mazinde-Lushoto feeder with the longest
branch extending up to 50 km, Bushiri II feeder (32 km), Korogwe II feeder (25 km) and the
Magunga-Amani feeder (20 kum). The rest of the 11 kV feeders have acceptable loss levels and
voltage profiles due to their low loading levels.
Network Development proposals
Supply to the Tanga Cement Factory
9.5         This is the largest single load in the region and is presently served by a 11 km 100
mm. sq. double circuit. line from the grid substation at Majani Mapana. Proposals have been
formulated to develop this factory and increase its output; but these proposals are hampered by the
inadequate and unreliable power supply presently provided. The 132 kV line to Tanga in fact
passes very close to the factory but the supply is provided after stepping down at the Majani
Mapana grid substation (132/33 kV) and transmission back to the factory over lower voltage (33
kV) lines. A step down facility close to the factory would improve system performance in a number
of ways. The primary benefit will be the elimination of the losses in the 33 kV transmission lines
and the high security and supply reliability that can be provided to the Cement Factory. In addition
the 33 kV lines from Neusagan to Kange could be reconnected to the new grid substation reducing
losses and improving the reliability of these lines and relieving further capacity from the Majani
Mapana grid substation. This 132/33 kV substation has been recently augmented during the
National Rehabilitation Project and the additional capacity which will be made available with the
transfer of the Cement Factory load to the new substation is not a necessity immediately. However
apart from the load increase expected at the Cement Factory, a number of other loads are expected
to go up steeply with the correction of the network voltages and the provision of sufficient capacity
at the 33/11 kV substation feeding the Tanga town. Load increases are also expected at the two
other major consumers, the Tanzania Fertilizer Corporation and the Steel Rolling Mill. Thus the
existing capacity of the Majani Mapana grid substation is expected to be reached by about 1997-98
in the absence of the proposed grid substation. The two grid substations will also act as back up
for each other and increase the system reliability for the loads supplied from both. The
arrangement will also provide TANESCO with a spare 20 MVA 132/33 kV transformer that could
be very useful to cater for any unexpected grid substation transformer failures particularly as
sufficient spare transformers are not readily available. The economic analysis for this proposal is
provided at Table C 2.1. It is seen that the investment is justifiable by considering only the loss



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reduction benefits (benefit/cost ratio of 1.7). With the inclusion of reliability benefits at even an
outage saving of 1 percent of the energy supplied and a value for saved outages of five times the
energy cost the benefit/cost ratio rises to 6. Thus the investment could be considered to be fully
justifiable even without considering the additional grid substation capacity provided.
Additional 33/11 kVSubstation for Tanga Town
9.6         The geographical layout of the 33 and 11 kV lines in the Tanga town and its vicinities
is shown at Drawing F 2.1 of Annex F. The existing 2 x 5 MVA substation adjacent to the grid
substation at Majani Mapana situated on the western side of the town presently feeds the entire
11 kV system. This substation is presently incapable of meeting the system peak and 2 to 2.5 MVA
of load are already being shed. Thus the load growth in the Tanga town is already constrained.
Increase of capacity at the substation will not be sufficient due to two major considerations. Firstly,
the 11 kV feeder losses will increase to uneconomical values with the expected load growth.
Secondly, the supply reliability to this important town is inadequate as the entire network is fed
from a single 33 kV source situated at one extremity. The provision of an additional substation
from the eastern side will address both these issues. The new feeders from the substation will
approximately halve the length of almost all the existing feeders and will thus considerably reduce
the losses on the 11 kV lines. The supply possibilities from either source of supply can be provided
to almost 90 percent of the loads and this will increase the reliability of supply considerably. A
suitable site has been identified at Sahare for the new substation and the 33 kV line to the Fertilizer
Factory could be utilized to provide supply to it. The substation could initially be equipped with
a 5 MVA transformer but the layout would provide accommodation for a second 5 MVA
transformer (which may be required by about 1999). Three 11 kV feeders extending towards
Raskazone, Usagara, and Kwakaheza respectively could be provided immediately from the new
substation as shown in Drawing F 2.1. Both the Usagara and Kwakaheza areas are earmarked for
high load growth and the sitting of the new substation is optimally placed with respect to this
development. A cost ratio of 11.8 is achievable and the benefit analysis is presented at Table E 2.2
of Annex E.
Lushoto town and outying areas
9.7         The Lushoto town together with a large area extending to the east as far as Herculo
and Balangai is supplied by a single circuit 11 kV line from the Mazinde substation. The furthest
point in the 11 kV feeder is 50 km along the line route from Mazinde. Due to the low loading
densities in the outlying areas the voltage profile and loss levels, though poor, are not as bad as
could be expected from such long line lengths. However the Lushoto area is presently experiencing
a high load growth and in a few years time it will not be possible to sustain such long line lengths.
One solution considered is the establishment of a 33/11 kV substation at Lushoto that will enable
the 11 kV lines to be divided to three feeders (Lushoto town area, Soni/Bumbuli and Mkuzi). A
33 kV line of about 10 km will have to be constructed tapping the existing Mazinde line at Kasiga.
The 33 kV supply at Lushoto will enable the subsequent extension of the system to areas such as
Lukozi and Mlalo , which are potential areas for electrification in the future. The network layout



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is shown in Drawing F.2.31 of Annex F. The economic analysis shown in Table E.2.31 of Annex E
indicates that at the discount rate and load growth considered the proposal is marginally
inadmissable (benefit/cost ratio 0.9).
9.8         Another alternative is to convert the eastern part of the 11 kV network to 33 kV and
to feed it from a 33 kV line extension from Mlemua. This supply arrangement could be
accomplished by the conversion of the existing 11 kV line from Mlemua towards Kulasi and then
constructing a 33 kV line up to Bumbuli. The load removed from the 11 kV network wil also be
removed from the 33 kV line from Magunga to Mazinde, a distance of about 50 km. Due to the
reduction of the load along the 33 kV line considerable additional loss reduction benefits are
obtained in this alternative. The network layout is shown in Drawing D 2.32. The economic
analysis shown in Table E 2.32 of Annex E indicates a benefit/cost ratio of 1.2. Hence this
alternative is recommended instead of the installation of a 33/11 kV substation at Lushoto.
Abrogwe North feeder
9.9         The northern feeder from  Korogwe substation extends 30 km  to feed the
Kwamndolwa area and a number of tea factories. The peak losses are of the order of 6.5 percent
and the line end voltage drops by 8.8 percent. Alternative proposals considered to develop the
network consists of:
(a)   installation of a 33/11 kV substation at Kwamndolwa by a 6 km line extension,
(b)   conversion of the existing line to 33 kV, retaining the existing copper 25 mm.sq.
conductor.
(c)   conversion of the line to 33 kV together with the replacement of existing conductors
with 100 mm. sq. ACSR conductor.
9.10        The network is shown in Drawing F 2.4 of Annex F and the cost/benefit analysis is
shown in Tables E 2.41, E 4.42 and E 4.43 respectively of Annex E. Proposals (a) and (c) indicate
a higher cost than the present value of benefits. Proposal (b), the conversion of the line with the
existing conductors show a benefit/cost ratio of 1.7. This solution is therefore recommended for
selection. There are two significant additional benefits in this alternative. Firstly, the copper
installed is capable of lasting a considerable period and the replacement of insulators and cross
arms can be done with minimum damage to the conductor. It is expected that the uprated and
rehabilitated line will last for another 10 to 15 years, which would also be close to the expected
technical life of the system configuration. Secondly the voltage conversion will afford an opportunity
to change the high loss transformers carrying low loads and optimize transformer losses. There is
a good possibility of obtaining significant benefits by the use of low loss single phase transformers.
Thus there are a number of additional benefits not quantified in the benefit to cost analysis.



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Korogwe West feeder
9.11        The western feeder from Korogwe is 25 km long with peak losses of 8 percent and
line end voltage drop of 9.3 percent at present loading conditions. The conversion of this line to
33 kV with the two alternatives of (a) retaining the existing conductor (25 mm.sq. copper) and (b)
with a conductor change out to 100 mm.sq. ACSR has been evaluated in Tables E.2.51 and E.2.52.
The uprating of the line while retaining the existing conductor is shown to be advantageous with a
benefit/cost ratio of 1.5. The change over to 100 mm.sq. conductor while uprating the voltage
indicated a higher cost than the present value of loss reduction benefits. The additional advantages
of retaining the existing conductor discussed in the para 9.10 (Korogwe North feeder) apply to this
case too. Hence the conversion of this feeder to 33 kV while retaining the existing copper
conductor is recommended.
Establishing a 33/11 kVsubstation at Oiblaga
9.12        The southern feeder at 11 kV from Lanzoni substation meets the northern feeder
(also at 11 kV) from Muheza substation at Kibaranga. In addition there is a spur line to the west
(to Mjesani) from this location. A 33/11 kV substation can conveniently be located at this
intersection as the 33kV line to the substation at Lanzoni passes close by. The economic analysis
of establishing a substation Kibaranga is presented in Table E 2.6 of Annex E indicates a high
benefit/cost ratio of 6.5 and the proposal is recommended for acceptance.
Swmmay of MVdevelopment propoal for Tanga
9.13        The system development proposals recommended at MV for the Tanga region are
summarized hereunder. These proposals aim to reduce network losses to economic levels, improve
reliability of operation and provide the necessary capacity to meet future load expectations.
Item                                Ref. to C/B
table         Cost in US$     B/C ratio
20 MVA grid SS at cement mill            E.2.1          1490            24.0
15 MVA SS at Sahare                     E.2.2           533             11.8
Conversion of Lushoto-Bambuli to 33 kV   E.2.3.2         945             1.1
Conversion of Korogwe North to 33 kV     E.2.4.2        563              1.5
Conversion of Korogwe West to 33 kV      E.2.5           408             1.4
5 MVA substation at Kibaranga            E.2.6           195             5.4



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10. DEVELOPMENT PROPOSALS FOR THE MOSHI REGION
The Present Distribution System
10.1        Supply to the Moshi town and surrounding rural areas is provided from the
2 x 20 MVA grid substation at Kiyungi. The load at Moshi town is distributed entirely from a
11 kV system, which in turn is supplied by two primary substations at Boma la Mbuzi and Trade
School. The rural areas north of the town (Uru, Madukani Kifumbu, Mkombone etc.) are also
supplied by extensions off the 11 kV feeders supplying the town. The connection of the rural load
has adversely affected the performance of the feeders supplying the important loads at the town
center by increasing the feeder load and adding to the line lengths (thus reducing the feeder
reliability). The three main feeders supplying important loads in the town area, M 2 and M 3
feeders from the Trade School substation and the Town feeder from Boma la Mbuzi substation are
those mainly affected by the connection of the rural loads. The remaining 11 kV feeders from the
two substations show satisfactory performance. The rural area immediately west of the town (Weri
Weru) is also supplied by a 11 kV feeder from the Trade School substation but the loss levels are
satisfactory due to the low loading density.
10.2        The rural areas in the region other than those mentioned above are supplied from
four 33 kV feeders; the TPC feeder supplying the area immediately to the south of the grid
substation, Machame and KIA feeders supplying the north eastern rural districts and the Rombo
feeder supplying the north western districts. The KIA feeder extends west and connects up the
Kikuletwa power station (1.16 MW) before proceeding north up to the 33/11 kV substation at
Lawati. The Machame feeder extends from the Trade School substation up to the 33/11 kV
substation at Machame. The Rombo feeder extends some 122 km from Boma la Mbuzi to supply
the areas west of the Moshi town. Although the feeder is lightly loaded the voltage profile is poor
with a voltage drop of 6.4 percent at the line extremity due to the extremely long length. Further
loading of this feeder will worsen the situation. The KIA and Machame feeders although
excessively long are still acceptable with respect to losses and voltage levels due to the very low
loading density of the supply areas.
10.3        The geographical layout of the distribution system is shown in drawings F3.1 and
F3.2 at Annex F. The peak losses and voltage conditions for the present network for the loads in
1990 and 1995 are computed in Table A.2.3.



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Network Development proposals
33/11 kVsubstation at Majengo area
10.4        The primary distribution capacity of the Moshi town area needs to be increased to
meet the expected load growth in the next five to eight years. The most economical method of
providing the required capacity is to provide an additional 33/11 kV substation at a location capable
of reducing the lengths of those feeders that presently operate at poor performance levels. The
supply arrangement should also provide increased reliability benefits to the overall supply area. The
town is presently fed from the western (Trade School substation) and the southern (Boma la Mbuzi
substation) directions. A suitable site for a new substation is available in the north eastern area of
the town at Majengo. Four 11 kV feeders could be arranged from the new substation; southward
up to the town area at Unga, eastward up to the town center presently fed by the M 3 feeder (with
the feeder also taking the KCMC area load), eastward up to Kibororoni and northwards taking over
the rural area of Uru (thus separating this load from the others). The proposed feeding
arrangements from the new substation are shown in drawing F.3.1 of Annex F and an economic
analysis of the proposal is presented in Table E.3.1 of Annex E. The analysis indicates that the
proposal can be justified considering only the loss reduction benefits achievable (benefit/cost ratio
of 1.1). However, The location of the new substation is such that supply to most of the town load
is firmed up. Loads presently fed off the M 3 feeder from Trade School substation and the Town
feeder from the Boma la Mbuzi substation will now have supply possibilities from more than one
primary source. At an outage saving of only 1 percent of the energy supplied the benefit/cost ratio
is 4.0.
Convm-ion of the runal section of the Makombone feeder (M 2 from Trade School) to 33 kV
10.5        The M 2 feeder from the Trade School substation feeds a high load density area
around the western section of the town and then extends about 18 km northwards to feed a very
low load density area at Kifumbu, Chome and Makombone. The present power losses of this feeder
(12 percent) and the tail end voltage drop (15.7 percent) are far too excessive. By 1995 these values
will rise to 14 percent and 18.4 percent respectively if system improvements are not carried out.
A further disadvantage is the low reliability caused by the long rural line sections on the important
town loads. A conversion of the rural sections of this feeder to 33 kV operation would thus be very
advantageous. This can be conveniently accomplished by constructing a short line section from the
substation to Sambarai and converting the rest of the line to Makombone to 33 kV. The M 2
feeder would then be restricted to the town area. The proposed feeding arrangements from the new
substation are shown in drawing F 3.2 of Annex F and an economic analysis of the proposal is
presented in Table E 3.2 of Annex E. The analysis indicates that the proposal can be justified
considering only the loss reduction benefits achievable (benefit/cost ratio of 1.3). The improved
reliability to section feeding the town area will enhance the benefit/cost ratio substantially; at an
outage saving of only 1 percent of the energy supplied the benefit/cost ratio increases to 7.0.



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Proposed 66 kVdevelopment from Kiywgi to Marangu
10.6        The 33 kV feeder Boma la Mbuzi-Himo-Marangu-Rombo extends for 122 km
resulting in a peak power loss of 8.2 percent and a tail end voltage drop of 17 percent at present
loading levels. The area supplied by this feeder is widely dispersed and of a low loading density.
The total power to be transmitted is also too low at present to justify an additional grid substation
at the standard transmission voltage level of 132 kV. However the 66 kV system between Kiyungi
and Njiro is now not operational due to its replacement with a 132 kV system and the existing
66 kV feeder bay as well as the possibility of using some of the line hardware provides an
alternative to supply bulk power to Marangu at 66 kV. Further there is also an unused 66/33 kV
10 MVA transformer available at Arusha and this can be utilized for the stepdown station. The
optimum location for the substation is at Marangu from which location three feeders can be
arranged; the first feeder to supply Holili and the local area of Marangu, the second to feed Rombo
and Rongai areas and the third to feed the Himo township and Taveta areas. The introduction of
a 132 kV subtransmission to this area is not foreseen for the next 15 to 20 years. Thus it will not
be necessary to consider any alternative construction strategies such as the construction to 132 kV
standards but with initial operation at 66 kV. The proposed feeding arrangements from, the new
substation is shown in drawing D 3.3 and an economic analysis of the proposal is presented in
Table E 3.3 of Annex E. The cost/benefit ratio considering only the loss reduction benefits is 3.0.
With the reliability benefits introduced by the separation of the Rombo feeder from the Boma la
Mbuzi load as well as the separation of the Rombo feeder to three sections the benefit/cost ratio
will increase to 5.0.
Summary of MV developmepmroposis for Moshu
10.7        The system development proposals for the Moshi region to provide ecomical loss and
reliability levels are summarized hereunder together with their benefit to cost ratios.
Item                                Ref. to C/B    Cost in US$     B/C ratio
table         '000
5 MVA primary substation at Majengo     E.3.1          745            4.0
Conversion of 11 kV lines at            E.3.2          361            7.0
Makombone to 33 kV
Construction of 66 kV line to Marangu   E.3.3          482            5.0



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11. DEVELOPMENT PROPOSALS FOR THE ARUSHA REGION
The present distribution system
11.1        At present power supply to Arusha is severely hampered by the low transmission
system voltages experienced during both the night and day peaks and daily power cuts are required
to maintain system voltages. However measures to resolve this problem both immediately (see
Sections 4 and 5) and in the long term (construction of the Singida-Arusha line) have been
identified and thus the existing difficulties in the transmission system are expected to be resolved
shortly. When this is accomplished the release of suppressed demand will bring an added burden
to the distribution system. Thus network planning of the distribution system should anticipate this
increase of demand and ensure that the expected load can be met at satisfactory technical and
economic performance levels.
11.2        The Arusha region is supplied from the 40 MVA 132/33 kV grid substation at
Kiyungi. Four primary substations of combined capacity of 20 MVA steps down the supply to the
11 kV system that distributes power to the town area. Two of the 11 kV lines however extend well
beyond the town limits and supplies rural areas up to Monduli and Ngaramtoni (west of Arusha).
These lines have feeder lengths of 46 and 37 km respectively and exhibit high losses and poor
voltage profiles. Clearly additional loads cannot be connected to these lines unless substantial
system improvement is carried out. In addition to the loads supplied at 11 kV two large industrial
consumers in the city, General Tyre factory (capacity 6 MVA) and Sunflag factory (capacity
6 MVA) are supplied directly off the 33 kV network. The rural area east of Arusha is fed by the
33 kV Arusha-Moshi feeder. Due to the low load density of this feeder the network losses and
voltage conditions are not of immediate concern and major network development to this section
would not be required for at least the next 7 years. The geographical layout of the distribution
system is seen in drawings F 4.1 and F 4.2 in Annex F. The network losses and voltage conditions
for the present system are computed in Table A 2.4 with the existing loads and the loads expected
in 1995 respectively.
11.3        The main issues to be resolved in the distribution system are the shortage of existing
primary distribution capacity and the improvement of supply conditions to the areas presently fed
by the long 11 kV feeders, Monduli and Ngaramtoni (Feeder No: 2). The solutions need to ensure
reduction of the present high network losses to economic levels.



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Network Development proposals
Uprating of the Mondidi Feeder to 33 kV
11.4        In order to reduce the line losses and to achieve a satisfactory voltage profile on the
existing 11 kV feeder to Monduli, it is proposed to convert this feeder to 33 kV operation. Such
a conversion has in fact been envisaged during the original line construction and 33 kV insulation
has already been provided. Hence the investment required is only in replacing the transformers,
isolators and associated fusing equipment etc. connected to the line sections to be uprated. In
addition a section of the line (approximately 8 km) that traverses an area subjected to flooding
needs to be diverted. The new line could conveniently be routed by the side of a new highway that
has been constructed recently. The construction work should also include the replacement of
supports that have deteriorated (expected to be about one third of the total). The costs of diversion
and rehabilitation need not be taken account of in conducting an economic evaluation as these are
necessitated by the normal maintenance requirements of the existing system. However, it is seen
that the loss reduction benefits are sufficiently high as to make the proposal very attractive even
with the inclusion of such costs.
11.5        The loading profile of the line consists of a high load concentration at the Monduli
town and very lightly loaded areas up to and beyond the town limits. Thus if the line conversion
is done only up to the Monduli town and a 33/11 kV substation installed at this location the existing
11/LV transformers at the Monduli town and the 11 kV operated lines proceeding north and south
can be retained. It is also proposed that the new 33 kV line be fed from a separate feeder direct
from the Njiro grid substation instead of the present feeding position (from the Power House
substation busbar). This arrangement will reduce the losses on the 33 kV interconnector and also
provide better security of supply. The loads close to the town could be maintained on the existing
1 1 kV line thus separating the town supply from that of the rural areas. The economic analysis of
the proposal is given in Table E 4.1 of Annex E and indicates a benefit to cost ratio of 8.1. It is
seen that the cost of the additional new line section to connect to the grid substation can be justified
by the loss reduction on the interconnector alone. In addition to loss reduction benefits, substantial
reliability benefits are also achieved. The important loads close to the town are presently adversely
affected by the long rural line and the separation of this section will bring substantial reliability
benefits to these consumers.
33/11 kVsubsation at Magereza
11.6        The other excessively long 11 kV feeder at Arusha is Feeder No. 2, also supplied
from the Power House substation. This feeder extends 40.5 km up to and beyond Ngaramtoni. The
calculated figures for feeder peak power losses is 17.5 percent, and, for the tail-end, the voltage
drop is 28.9 percent; these figures indicate a severely overstressed loading condition. Clearly no
new loads should be connected until system improvements are effected. The poor reliability due
to the long feeder length also affects the important loads in the Arusha town supplied at the
beginning of this feeder. The most suitable development for this feeder is to construct a new



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33/11 kV substation at Magereza. The present long line length outside the town area can then be
split to two feeders supplied from this substation. The short section within the town limits would
continue to be fed from the Power House substation. The new 33/11 kV substation is best fed from
the 33 kV operated line proposed for the Monduli feeder. The change of the feeding arrangement
on the 33 kV system will also provide loss reduction benefits as the Power House interconnector
is more heavily loaded than the Monduli feeder. An economic analysis of the proposal is presented
in Table E 4.2 and indicates a benefit to cost ratio of 12.3.
33/11 kVsubstation at Mt Meru hotel
11.7        Feeder no. 3 from the Power House substation (feeding the important load complex
in the Mt. Meru area) is presently carrying a load of over 200 Amps. The capacity of the Power
House substation that feeds the central town area is also fully utilized. Although the proposed
conversion of the Monduli and Ngaramtoni feeders will release about 3 MVA of primary capacity
the expected future loads in the Arusha town would still need about 1.6 to 2.0 MVA of additional
capacity to provide reliable operation conditions up to about 1998. Further the Power House
substation is located at the southern periphery of the town and it would be advisable to have a
feeding point from the northern side in order to provide alternate feeding possibilities for the 11
kV feeders. An ideal site to meet the above requirements has been identified by TANESCO close
to the Mt. Meru Hotel. This new substation will ensure that the central area of the Arusha town
is supplied from two 11 kV sources. It will provide substantial loss reduction benefits as well as a
high level of reliability for the loads presently supplied by Feeder Nos. 1 (Mt. Meru) and 3 (Ilboru)
from the Power House substation. The 11 kV outlets will be arranged by 3 feeders as shown in
Drawing F 4.3 of Annex F. Two 33 kV supply sources are proposed for the new substation. The
main source proposed consist of the construction of a second circuit from the grid substation at
Njiro to the Power House and then extending this circuit along the existing 11 kV line up to the
proposed site. An alternative supply source is also recommended from the existing Arusha-Moshi
33 kV feeder. This short connection will not only enhance the reliability of the entire town area
but also that of the loads supplied along the Arusha-Moshi feeder. The additional reliability can
be achieved by installation of line switches or isolators positioned at suitable locations to enable all
network sections to be supplied from either of the two 33 kV feeders. The economic analysis of
the proposal is given in Table E 4.3 and indicates a benefit to cost ratio of 7.0.
33/11 kVsubstwion at Usa/Are7ru
11.8        The village of Arumeru has been established as the local government district
headquarters for the Usa area situated towards the west of Kilimanjaro. There is a rapid load
growth in the area and the existing supply system with long secondaries from a few 33kV/LV
transformers is inadequate to meet the expected loading conditions. It is therefore necessary to
increase the number of distribution transformers substantially and rationalize the LV networks in
order to provide supply at acceptable technical and economic levels. The most suitable method of
increasing the distribution transformers in the area is by converting the primary distribution system
to 11 kV. Accordingly a 33/11 kV substation of capacity 2.5 MVA is proposed to be established



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at Usa. Details of the expected system loads and the appropriate network configuration is being
designed by the TANESCO/ESMAP study unit. An economic evaluation will be conducted when
the design is completed. The present indications are that a high economic return is to be expected.
33/11 kV substaron at Ma *umira
11.9        The existing 11 kV network at Makumira is supplied by three transformers in series;
33kV/400V, 400V/llkV and an 1lkV/400V/11kV earthing transformer. This arrangement has
clearly been a result of ad-hoc arrangements made due to funding or equipment limitations. It is
necessary to rationalize the arrangement by replacing these three transformers with a single
33/11 kV stepdown transformer. The new transformer will be of 2.5 MVA rating, which will also
accommodate the expected future load additions in the area.
Suma7y of the MVdevelopment forArusha
11.10       The system development proposals for the Arusha region to provide economical loss
and reliability levels are summarized hereunder together with their benefit to cost ratios.
Item                                  Ref. to C/B    Cost in US$    B/C ratio
table
33 kV line conversion Monduli feeder     E.4.1           471            8.1
5 MVA substation at Magereza             E.4.2           356            12.3
5 MVA substation at Mt. Meru Hotel       E.4.3           771            7.0
2.5 MVA substation at Usa/Arumeru        E.4.4           328
|2.5 MVA substation at Makumira            E.4.5          330



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12. REHABILITATION, RATIONALIZATION, AND NETWORK EXPANSION
12.1         Power supply in distribution networks is typically achieved in a number of successive
stages. These stages generally consist of (a) the transport of bulk power (say at 33 kV) from the
terminal points of the transmission system (grid substations) to distribution substations or switching
stations at the same voltage level, (b) voltage transformation to a lower, medium voltage (say
11 kV), (c) medium voltage (MV) feeders and distributors7/ (d) voltage transformation to low
voltage (LV) and (e) low voltage distributors to retail consumers. The larger loads are usually
tapped off upstream at various voltage levels of the system. Sometimes some of the intermediate
levels are not utilized, for instance when 33 kV distributors are provided direct off grid substations.
The power flow structure however always retains its hierarchial nature and deficiencies upstream
will affect conditions at the lower levels of the supply system. Sections 8 to 11 dealt with the major
improvements to the MV distribution system in the four regions under study. These developments
would ensure that the main characteristics of the power system (up to the MV distributors) would
be at adequate technical and economic levels to meet the expected developments in the medium
term (from 5 to 10 years). In addition to these works a number of other improvements and
developments at the lower levels of the network hierarchy as well as rehabilitation aspects of the
entire network are required to bring the system to satisfactory operational standards. These
additional items consist of:
(a)   rehabilitation of lines (both MV and LV) and substations together with secondary
level reinforcements to MV distributors,
(b)   rationalization of the LV systems, and
(c)   expansion of the existing system to cover new areas requiring electrification.
12.2         Items a and b deal with improvements required for the existing systems. Item a
covers rehabilitation works (resulting from a number of years of inappropriate maintenance) as well
as secondary level reinforcements for the existing system.  The latter aspect deals with
improvements required to the MV system at network levels lower than the main developments
addressed in Sections 8 to 11. The rationalization of the LV networks covered in item b addresses
requirements necessary to improve these networks to acceptable condition by loss reduction and
reliability improvement measures. Item c addresses system expansion needs to meet the
geographical expansion of the supply area.
7/     In general a feeder will transport bulk power without tapping off loads at intermediate points while
a distributor will supply a large number of loads along its length. Often the definition is blurred in
common usage, particularly as outgoing supply lines off a substation are commonly termed 'feeders'
whether they are tapped along the way or not.



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Network rehabilitation and reinforcement
12.3         Field inspections carried out during the study in the four regions indicate that the
distribution networks are in need of considerable rehabilitation. The extent of work required to
bring the networks to a satisfactory condition varies among different locations. The main
shortcomings and deficiencies requiring remedial action are as follows:
(a)   conductor connections being made by inappropriate methods resulting in loose
connections,
(b)   various temporary and unorthodox methods used for connections from  the
transformers to the overhead lines. In many locations these connections are made
without the necessary protective fuses or switchgear. They are also often extremely
shabby and constitute a danger to repair workmen,
(c)   defective equipment on overhead lines and transformer stations such as isolators and
circuit breakers,
(d)   defective or malfunctioning equipment and meters in substations,
(e)   poor pole top dressings and decayed or corroded cross arms,
(f)   decayed poles on distribution lines, and
(g)   decayed or partially burnt out service connections.
12.4        The poor condition of the networks has been caused by the shortage of funds to
procure necessary material for the required work to be performed in time (particularly as a large
number of items are imported), the absence of systematic planning of development works and the
lack of suitable maintenance scheduling procedures. The only major network overhauls that were
carried out were those organized by foreign funded projects. The JICA funded Dar es Salaam
project and the IDA funded National rehabilitation project during the last five years carried out
extensive rehabilitation in many sections of the network. However the immediate increase of load
in the rehabilitated areas resulted in some of these networks becoming overloaded once again
within a short time. This has resulted in burn out of equipment, damage to connectors etc. thus
reducing the beneficial effects of the rehabilitation carried out. Hence there still remains a
significant extent of work to be done both in areas that have not been rehabilitated in previous
projects as well as in some of the areas that were rehabilitated recently.
12.5        As explained in para 12.2 secondary level improvements (not covered in the
proposals for the development of the distribution systems in Sections 8 to 11) required to the MV
system are also included in this category. These improvements consist mainly of the reconductoring
of some line sections presently constructed with conductor gauges too low for the economic dispatch



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of the load carried. Most of these lines have been constructed many years ago and the lines almost
always require extensive rehabilitation in addition to reconductoring.  Hence the cost of
reconductoring cannot be conveniently separated from that of rehabilitation and the need to group
these two items under the same category. In addition a small number of network improvement
works such as short interconnections to rationalize the network arrangements are also included
under this item.
12.6        The specific rehabilitation and reinforcement requirements such as the extent of pole
changing and reconductoring of lines to be included in the project are being assessed by carrying
out field inspections of the networks. These inspections are conducted by regional engineers with
the support of the ESMAP unit and lists of the works to be carried out are in preparation. Total
requirements for this item have been estimated from the information collected so far and a
summary of the work to be performed in each area is provided in Table E5 of Annex E. In addition
to specific items of work identified by the inspections, bulk provision is made for the materials
required for the rehabilitation of substations, transformer stations, line connectors and service
connections as well as the tool and equipment required to undertake the work.
12.7        A comprehensive and systematic procedure needs to be followed in organizing the
rehabilitation program. The following are some of the important aspects to be addressed:
(a)   The work should be programmed area by area, covering each in a comprehensive
manner. Arrangements should be made to organize systematic maintenance
procedures to the rehabilitated areas so that they will continue to be maintained at
the required standards. The areas rehabilitated should be indicated in progress
maps and the performance adequately supervised.
(b)   The rehabilitation work in the field need to be combined with the training of
TANESCO personnel in construction and maintenance methods and procedures.
(c)   Appropriate tools and equipment should be supplied and the maintenance staff
trained in the correct use of these items.
12.8        The work involved in rehabilitation of existing networks is in fact delayed
maintenance and specific justification may well be considered to be superfluous. If the utility is to
continue in the business of providing power supply to its existing consumers (which it is legally
obliged to do) it is virtually mandatory to have the existing networks maintained in a state of
acceptable operation. Further if major maintenance requirements are postponed the networks
deteriorate rapidly resulting in burnouts and damages to healthy components. This results in
further increase of costs to bring the networks to the required operating condition. In addition
deteriorated networks result in a large loss of power supply due to network outages. Networks in
poor operating conditions also result in an increase of standby plant installed by consumers. Thus
rehabilitating networks that are in a poor state of maintenance result in the following benefits:
saving network components from further damage; increased sales due to the reduction of outages;



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higher consumer satisfaction and reduced necessity for consumers to procure stand by plant.
12.9         Preventing the networks from further damage may well bring about the greatest
benefits. These benefits, however, cannot be readily quantified. Regarding increased sales, an
attempt has been made to assess the resulting savings by estimating the extent of outages that can
be saved by bringing the networks to acceptable operating condition. An economic analysis
considering the benefits of such outage savings is presented in Tables E 6.1 to E 6.4 of Annex E in
respect of the four regions under study. At an outage saving of 1 percent of the units sold and an
economic cost of outages at $1.00/KWh benefit to cost ratios between 7 and 17 are obtained for
the four regions. The results are tested by examining the sensitivity to the estimated figures used
for the amount of outages saved; the value of such savings and the load growth rate. A summary
of the results of the computations is provided in Table 12.1 below. It is seen that even under the
most conservative assumptions the rehabilitation work on the existing systems will produce
substantial economic benefits. Thus rehabilitation works while being of the highest priority due to
operational necessities are also economically justifiable.
Table 12.1. Cost/Benefit ratios obtained for proposed rehabilitation works
Sensitivity parameters
Saved outages (as % of units sold)   1.0  0.75  0.50  0.30
Value of saved outages $/kWh  1.0  0.75  0.75  0.75
Load growth rate % (to 1994)  8.0   4.0   4.0   4.0
Load growth rate % (beyond 1994)  9.0   4.5   4.5   4.5
BENEFIT/COST RATIOS:
Dar es Salaam                17.7  6.0   4.0   2.4
Tanga                        9.5   3.2   2.1   13
Moshi                        7.9   2.7   1.8   1.1
Arusha                       7.8   2.6   1.8   1.1
Rationalization of LV. Systems
12.10        There are two aspects that need to be addressed in the development of the low
voltage system. The first consists of the rationalization of existing network configurations so that
the system complies with technical and economic guidelines developed in Section 6. The second
component consists of rehabilitation requirements; replacement of defective or damaged hardware
and bringing the installation up to acceptable maintenance standards.
12.11        A sample of LV networks were studied in the four cities and the results of the line
loss and voltage drop computations are provided in Section 3 and Annex A. As discussed in Section
3, a significant number of networks showed loss levels higher than economically acceptable levels.
One of the simplest means of reducing existing losses is to better balance the phase loads. The



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sample studies have shown that as much as 15 percent of the existing LV network losses can be
reduced by correcting the existing imbalance. It is recommended that an immediate program be
instituted to undertake a systematic phase balancing exercise commencing with the transformer
stations with the longest line lengths. While the service connections are changed from one phase
to the other, an effort should also be made to improve the work standards with the use of suitable
materials and working tools. A frequently occurring defect is the use of poorly twisted wire bindings
for interconnecting conductors. Either parallel grove clamps or compression crimping methods
should be employed for this purpose.
12.12       The next major technical improvement that can be effected is the reduction of the
long secondary lengths of LV distributors. Reducing the lengths of LV lines by introducing
additional transformers (at locations selected to increase the number of possible feeders from each
transformer) will have a substantial impact on the reduction of LV losses. TANESCO counterpart
staff are already engaged in the task of selecting the appropriate locations and computing the
transformer capacities and other associated investment (new feeder connections etc.) required. As
discussed in Section 6 the requirements of additional transformers to inject supply to the LV system
would have been much higher and the capacities of the transformers considerably lower if the
system was being designed afresh. The presence of the existing network with conductors of 100 and
50 mm. sq. gauge is so widespread that it is not economical to introduce different conductor
standards for the addition of the new transformers. It is expected that approximately 50 percent
of the existing LV network losses can be reduced by the proposed investment. A benefit to cost
analysis of the proposal work is given in Table E7 of Annex E.
LV network rehabilitation
12.13       The rehabilitation requirements of LV networks is similar to those stated in paras
12.3 to 12.4 for MV networks. A particular concern is the transformer station and associated LV
connections. It estimated that over 75 percent of these stations require considerable rehabilitation
inputs (exceeding work that can be considered under normal maintenance). The benefit to cost
computation of Tables E 6.1 to 6.4 includes the work to be undertaken both on MV as well as LV
networks and a separate analysis is not attempted in view of the difficulty of obtaining accurate
estimates of the benefits.
Network Expansion to New Development Areas
12.14       In all four major cities studied there are a number of areas presently outside the
supply system in which new housing and community development has been in progress for some
time. These areas adjoin the existing infrastructure of roads and power networks. Further, most
of the areas presently covered by the existing distribution systems are already developed close to
saturation and the possibility of expansion of the cities mainly rests in the peripheral areas.
Tanzania operates an urban development planning system in which the land is surveyed and divided
into plots marked out for various types of land usage. These plots are then sold or leased to



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individuals and corporate bodies. A number of new areas in all four of the cities studied has been
subjected to such town planning and survey drawings of the developments envisaged are available.
It is reported that in most such areas all the plots demarcated have already been sold. In the areas
selected other investment activities have already commenced and are in various stages of
development. A number of new buildings as well as many units under construction are observed.
It is clear that the lack of infrastructural facilities such as electricity, water and roads is a major
constraint to the development of these areas. Once such facilities are introduced there is bound
to be a sharp increase of activity and an acceleration of the development process. In particular
electricity appears to be the major constraint as water supply can be obtained either by wells in the
premises or by community water supply available close by and roads are in any case not well
provided even in the areas already developed. Thus in these new developing areas the load growth
is expected to be quite high when a reliable power supply is provided.
12.15       Supply to a few of the buildings already constructed in these areas has in fact been
already provided. However these connections are being provided in a haphazard manner with long
extensions from the peripheries of existing systems and sometimes from the bulk supply
transformers available in the area. Such inappropriate construction methods are resorted to mainly
because of funding limitations and the desire to limit the cost for each individual customer. This
process has resulted in a suboptimal development of the distribution system without giving due
consideration to appropriate technical standards. In particular, inappropriate conductor sizes are
being used and in many cases it was observed that the lines are being drawn over other plots not
yet developed. If such unplanned development is allowed to continue TANESCO will be faced with
a number of problems. These include the overloading of existing systems, low voltages at the
network peripheries, the inability to supply the increasing load on the extended lines and the
excessive costs of repeatedly replacing unplanned construction.
12.16       It is therefore very necessary that comprehensive development proposals be prepared
with respect to each such area of network expansion. Thus the present study has undertaken an
investigation of these areas consisting of estimation of the expected long term load and the design
of appropriate networks to satisfy the planning guidelines detailed in Section 6. Town planning
maps are first collected for such areas and the sites examined to ascertain the present state of
development as well as the possible supply configurations. The maximum load to be planned for
is computed on the basis of the area covered and the expected loading density after comparing the
area concerned with similar locations in the existing network for which the load densities have been
determined. The development proposals are prepared so that they could be effected in a number
of stages. Such a procedure will enable the expected load increases to be met satisfactorily but
without over investment at each stage of development. The initial network will be constructed so
that the conductor sizing and line routing is such as to be able to accommodate the expected final
load. Subsequent stages of the development will include the increase of the number of transformers
as well as the augmentation of transformer capacities, additional MV spur lines and further
coverage of the LV network.



- 101 -
12.17       A cost benefit analysis is conducted for each development plan (see sample
computations in Table series E 8.1 of Annex E). This is accomplished by computing the benefits
at the Average Incremental Cost (AIC) of ultimate supply (taken as $ 0.10) less the AIC at
transmission level (taken as $ 0.075), thus giving a net benefit of $ 0.025 per unit of sales. From
the computations completed by the ESMAP study unit up to date it is seen that the benefit to cost
ratios are high (generally over 3.0). This is due to the fact that these new areas selected for
electrification are very close to the existing MV network. In some cases the MV feeders actually
pass through the areas but the associated MV distributors and supply transformers have not been
provided. In addition the major load growth of the cities is expected to occur in these new areas
as there are only limited opportunities for new loads to materialize in the already developed areas
of these cities particularly in view of the town planning procedures in existence. The details of the
work envisaged over the duration of the proposed project in the four regions and a summary of
their costs are provided in Table E 8.2 of Annex E.



I
I



ANNEX A
DISTRIBUTION SYSTEM CHARACTERISTICS



I



-105-
Annex A
DISTRIBUTION SYSTEM CHARACTERISTICS
List of Figures and Tables
Figures
A.1          Typical feeder load curves obtained from field measurements
Tables
A.1.         Load factor and loss factor of typical feeders
Loss calculations on medium voltage lines
A.2.1        -     do    - Dar es Salaarn
A.2.2        -     do    - Tanga
A.2.3        -     do    - Moshi
A.2.4        -     do    - Arusha
A.3.1        Sample loss calculations on low voltage lines
A.3.2        Summary of results of LV loss calculations
A.4          Analysis of sales, losses and power flow by voltage level
A.5          Loading densities of MV feeders
A.6          Particulars of LV Transformer Loading Data
A.7          Historical load growth in the study regions



I



-107-
Annex A
DISTRIBUTION SYSTEM CHARACTERISTICS
This annex provides a sample of the information obtained on network characteristics from
the analysis of the field data collected. The program of feeder measurements using electronic
logging instruments provided valuable information on the load variation with time of day (see
Figure 1A). This data was transferred to spreadsheet formats enabling the load factor and loss
factor of each feeder to be computed (see Table A. 1). In addition, loading densities provide
important information for planning purposes and such data has been computed by combining the
feeder loads with the supply area obtained from the digitized maps. A sample of the results is
presented at Table A.5 (for MV feeders) and Table A.6 (for LV feeders).
Computations have been performed to obtain the losses and tail end voltage of feeders and
distributors using a spreadsheet format based on the methodology developed in Annex D. 1.
Results of the computation for the 1991 and 1995 peak loading condition at the four regions are
presented in Tables A.2.1 to A.2.4. Table A.2.1 for Dar es Salaam contains the full spreadsheet
used, while Tables A.2.2 to A.2.3 for the rest of the regions show only summarized information.
The spreadsheet format lends itself well to enable a wide variety of computations to be
carried out once the initial data base is established. For example, the mid-load and base load
conditions can be simulated by copying out a new set of input current and power factor figures to
the relevant columns. The effects of capacitor additions can be modeled by including suitable
additional columns to compute the revised input current and power factor. Revised loading data on
network rearrangement involving new substations and feeders can be obtained by using ratios for
load allocation. By "linking" previously computed data where required, a variety of important
information can be obtained. For example, the altered feeders can be combined with those
unaffected to provide revised substation loadings; substation loads can be linked to the load on the
supply line, etc. These techniques have been used in the computations to produce information on
the different load steps (representing peak, mid-load and base load conditions), effects of
development proposals and capacitor applications. Due to space limitations, the resulting
spreadsheets are not presented.
A simplified computation has been performed for LV feeders and a sample is given in Table
A.3. 1. In this calculation, the total feeder load is divided into the various sections and spurs of the
LV system in proportion to the number of houses in each section. The losses for each section is
computed (using the methodology in Annex D.1) and the total losses for the feeder is added up.
The computations are made assuming a balanced loading situation (for three phase sections) and
the percentage increase for the existing imbalance is also provided. Table A.3.2 summarizes the
results of studies obtained from 367 feeders off 105 transformer stations.
The above computations resulted in the determination of the loss levels in the medium
voltage (33 and 11 kV) and low voltage (0.4 kV) networks. Studies detailed in Section 4 and
Annex B provide the results of the loss levels of the transmission system. The information
obtained on the losses at each voltage level has, thereafter, been combined with the respective power
and energy sales at the respective voltage levels to build a power and energy flow analysis given in
Table A.4. This table provides a breakdown of losses as a percentage of the net power supplied to
the system.



I



_1009                               Figure Al
Daily Load curve - Arusha F2 Feeder
180
160
140
120
ARUSH-A F2\
.100                       AVG             114
a.                         MAX             176
E                   M~~~~tN          55
80                      Load Factor   0.648
MIN/MAX       0.318
60        J             Night Peak      176
Day Peak       152
40 -                    Loss Factot    0.461
20
CN0D  0      -  N C D                         C Yc 0  Cl   N _ l
-  -  _  -  _  _  _       N N Cl   N  N
Time In Hrs.
AFUSHA F3
AVG       133
Daily Load Curve -Arusha F3                 MAX       203
MAN       76
Load Factor    0.656
250                                                                  MINMX       0.374
Might Peak     176
Day Peak      14 9
Loss Factor    0.463
200
150
100 - /
50
O - N 0) t f 0 1.D  0 0 O _ N 0~  tO 0 ?- 0 tS 0  - N C'X
_    - _   _  _  _ -  -    _ I  N  N N  N
Time In Hrs.



-110-*
Table A 1
Feeder Characteristics Obtained from Load Logger Measurements
Current in Amps. for:           Night      Day      Load     Loss
Feed/name                 AVG       MAX       MIN  MIN/MAX      Peak     Peak    Factor    Factor
ARUSHA REGION FEEDERS
NGARENARO                  43        68       12    0.176        68       57    0.629    0.423
MONDUUSECTION              27        43       17    0.395        43       27    0.629    0.421
OLURUVANISPUR              24        30       11    0.367        30       30    0.810    0.678
ARUSHA Fl                  72       110       41    0.373       110        95    0.656    0.464
ARUSHAF2                  114       176       56    0.318       176       152    0.648    0.461
ARUSHAF3                  133       203       76    0.374       176       149    0.656    0.463
MOSH TOWN FEEDERS
TOWN-URUSPUR                9        20        4    0.200        20        10    0.449    0.239
MOSHI Ml                   1 2       23        7    0.304        23        1 2    0.501    0.278
MACHAME33KV                11        25        5    0.200        25        12    0.454    0.240
TOWNFEEDER                101       178       60    0.337       178       131    0.565    0.351
MOSHIM311KV                99       167       61    0.365       167       124    0.591     0.377
MOSHIM211KV                41        74       28    0.378        74       46    0.559    0.335
BOMA MBUZI-RONGAI.         18        38       12    0.316        38        17    0.486    0.263
MOSHI BOMA11KV             23        40       11    0.275        40       28    0.571      0.375
TANGA REGrON FEEDERS
MAZINDE S/S
MOMB0KWALUKONGE             1         5        1    0.200         1         5    0.295    0.125
MAZINDE-WSHOTO             30        48       18    0.375        48       36    0.625    0.413
MAZINDE-MKUMBARA            7        1 5       1    0.067         8        1 5    0.488    0.274
MAJANI MAPANA(TANGA) S/S
NGUVUMAU                   70       104       49    0.471       104       87    0.671    0.471
TANGAl                     98       137       67    0.489       131       137    0.718    0.541
TANGA2                     87       152       41    0.270       152       102    0.571     0.360
TFC 33KV                    14       17        8    0.471        17        16    0.827    0.696
DAR ES SALAAM REGION FEEDERS
MK1 feeder                163       219      141    0.644       219      160    0.745    0.566
D9 feeder                 221       325      166    0.511       325      236    0.679    0.477
C3 feeder                 146       225       95    0.422       120      223    0.649    0.471
D3 feeder                  95       152       58    0.382        94       152    0.625    0.432
F2 feeder                 118       177       70    0.395       156      176    0.668    0.484
MK3 feeder                184       298      139    0.466       298      215    0.617    0.400
F32 feeder                 89       160       40    0.250        83       151    0.558    0.349
Note: The above is a sample of the data obtained off 'Lotus' spreadsheets created using the
information downloaded from the electromic data loggers.



MV-DAR-Niht                      MEDIUM VOLTAGE FEEDERS LOSS CALCULATIONS ON PRESENT SYSTEM  1991/1995 -DAR ES SALAAM                                          Page 1 of 3
LOADS AT SYSTEM PEAK
POWER AND LOSS CALCULATICNS                 VOLTAGE DROP CALCULATIONS
1990    1995                                                  1991    1995  1991   1995  1991   1995  1991    1995  1991  1995
FEERR            Growth   Length   Con/d Max, I   Max I Conductor Dist. Factor Resist.   RF   Induct.  Power   Power  Loss   Loss  Lossesin %    Voltage Drop    Voltage Drop
NAME            Rare(%)     (km)  (KVA) (Amps)  (Amps) Type, Size loss Volt dr.per km  Coso  Sino per km    (KW)    (KW)  (KW)   (KW)           in (KV)  in (KV) in (%) in (%)
UBUNGO S/S 11 KV FEEDERS         15 - SS Capacity (MVA)   76 .SS lading in % by 1995
Ul, Kisiwani         8      8.98  10840   175      257  ACSR100  0.4  0.56  0,331  0.94  0.34  0.34    3134    4605   109    236  3.49   5.12  0.65        0.96  5.92  8.70
U2, Menzese          4      8.36    3810   146     178 ACSR 100  0.4  0.56  0.331  0.90  0.44  0.34    2504    3046    71    105  2.83   3.44  0.53        0.64  4.80  5.84
U7, Factory          9      3.91    6345    75     115 ACSR1O0  0.4  0.56  0.331  0.93  0.37  0.34    1329    2045        9     21  0.66   1.01  0.12      0.19  1.12  1.72
U8, Universily       4      4.35    5300    40      49 ACSRIO0  0.9  0.95  0.331  0.94  0.34  0.34       716     872      6      9  0.87   1.06  0.12      0.15  t.11  1.35
0.93  0.38          7683   10568   195    370  2.54   3.51
KUJRASINI SIS 11KVFEEDERS        15 -SS Capacity (MVA)    86  SS loading in % by 1995
K4, INDUSTRIAL       4      9.52   13245   168    204 ACSR 100  0.8  0.9  0.331  0.91  0.41  0.34    2911    3542   213    316  7.32   8.91  1.10          1.34 10.02 12.19
K3, KILWARD          4      8.50   10605   231     281 ACSR 100  0.4  0.56  0.166  0.91  0.41  0.17    4005    4873    90    133  2.25   2.74  0.42        0.51  3.83  4.66
PCRT                 8      4.32   17800   133     195 ACSR 100  0.9  0.95  0.331  0.99  0.28  0.34    2433    3574    68    147  2.81   4.12  0.39        0.57  3.55  5.22
0.92  0.38          9349   11980   372    596  3.97   4.97
ILALASIS11 KVFEEDERS             45 - SS Capacity (MVA)   58 _SS loading in % by 1995
DO, Brewery          4      0.30    4400    90     109   CU 185   1    1  0,118  0.93  0.37  0.08    1595    1940         1      1  0.05   0.07  0.01      0.01  0.06  0.07
Di, Azamia           3      5.45    4720   120     139 ACSR 100  0.4  0.56  0,331  0.93  0.37  0.34    2130    2469    31       42  1.47   1.70  0.29      0.32  2.50  2.90
D2, Town I           5      6.05    6700   110    141 ACSR 100  0.4  0.56  0.331  0.93  0.37  0.34    1955    2495    29        48  1.50   1.91  0.28    0.36  2.55  3.25
D3, Kurasini         3      2.82    5130   180     209 ACSR100  0.4  0,56  0,331  0.91  0.41  0.34    3121    3616    36        49  1.16   1.35  0.22      0.25  1.99  2.29
D7,                  3      2.95    2045   110     129 ACSR100  0.6  0.7  0.331  0.96  0.28  0.34    2012    2332    21         29  1.06   1.23  0.16      0.19  1.48  1.71
D8, Industrial       2      1.53    300    10       11 ACSR 100  0.9  0.95  0.331  0.96  0.28  0.34      183     202      0      0  0.07   0,08  0.01      0.01  0.09  0.10
D9, Town 2           6      2.53    5515   300    401  ACSRtO0  0.4  0.56  0.331  0.93  0.37  0.34    5316    7114    90    162  1.70   2.28  0.32         0.43  2.90  3.88
DIO, Magomeni        4      6.51    6575   199     242 ACSR 100  0.4  0.56  0.331  0.93  0.37  0.34    3520    4282   102    151  2.90   3.53  0.54        0.66  4.94  6.00
0.93  0.37         19831   24453   312    481   1.57   1.97                    16
ClTYCENTERSiSI1KVFEEDERS         30 -SSCapacity(MVA)      71 -SS loading in %by 1995
02,Upanga            4      3.26    6230    80      97 ACSR100  0.4  0.56  0.331  0.98  0.20  0.34    1494    1817        8     12  0.55   0.67  0.10      0.12  0.90  1.10
C3, City Center 1    5      1.20    8715   128     163 ACSR 100  0.4  0.56  0.331  0.93  0.37  0.34    2268    2895       a     13  0.34   0.44  0.06    0.08  0.59  0.75
04, City Center 2    5      2.21   10430   141     180 ACSR100  0.4  0.56  0.331  0.93  0.37  0,34    2505    3197    18        29  0.70   0.09  0.13      0.17  1.19  1.52
C5, MnaziMneja 1     5      1.44    5115   195    249 ACSR 100  0.4  0.56  0.331  0.93  0.37  0.34    3455    4410    22        35  0.63   0.80  0.12      0.15  1.07  1.37
C6. MnaziMnela2      4      1.76    9605   118     144 ACSR 100  0.4  0.56  0.331  0.96  0.28  0.34    2158    2626    10       14  0.46   0.55  0.08      0.10  0.76  0.92
C8, Tanesco          5      1.44    9260   226     288 ACSR 100  0.4  0.56  0.331  0.93  0.37  0.34    4005    5111    29       48  0.73   0.93  0.14      0.17  1.24  1.59
0.94  0.34         15885   20056    94    151  0.59   0.75
MIKOCHENI S/EI 1 KVFEEDERS       15 - SS Capacity (MVA)    100 - SS loading in % by 1995
MK1, Msasani         5      8.20    6155   155     198 ACSR100  0.4  0.56  0.331  0.93  0.37  0.34    2747    3505    78    127  2.89   3.64  0.53         0,68  4.85  6.19
MK2,Tandale          8    10.84  11710   190       279 ACSRI00  0.4  0.56  0.331  0.91  0.41  0.34    3294    4840   15S    336  4.72   6.93  0.88         1.30  8.03 11.80
MK3, Lugalo          3      4.80    3950    80      93 ACSR 100  0.4  0.56  0.331  0.90  0.44  0.34    1372    1590    12       16  0.89   1.03  0.17      0.19  1.51  1.75
MK4, north east      5      4.50    6955   174    222 ACSR100  0.4  0.56  0,331  0.98  0.20  0.34    3249    4147    54         88  1.67   2.13  0.30      0.36  2.71  3.45                       H
0.94  0.34         10662   14083   300    568  2.81    4.03
H
(D
OYSTERBAYSiS11KVFEEDERS          15 -SS Capacity (MVA)    129 - SS loading in%by 1999
02, Mwenge           3      4.22   2715   135      157 ACSR100  0.4  0.56  0.331  0.98  0.20  0.34    2521    2922    31        41  1.21   1.40  0.22    0.25  1.97  2.28
03, Packers          4      9.64    9115   296     360 ACSR 100  0.4  0.56  0,331  0.98  0.20  0.34    5527    6726   336    497  6.07   7.39  1.09    1.32  9.87 12.00
04, Kinondoni        4      2.79    1145   177    216    CU25   1    1  0.741  0.90  0.44 0.383    3040    3699   195    289  9.42   7.81  0.71            0.87  6.50  7.91
4     2.79    3790   123     150  ACSRSO  0.6   0.7    0.7  0.90  0.44 0.385    2109    2566    53        79  2.52   3.06  0.33       0.40  3.01  3.67
04 (TOTAL)           3      5.58   4935   177    206                               0.90  0.44           3040    3525   248    367  8.16  10.42  0.00       0.00  0.00  0,00
O5, Seaview          2      3.58    3245   116     127 ACSR1oo  0.4  0.56  0.331  0.92  0.39  0.34    2016    2226    19        23  0.93   1.03  0.17      0.19  1.59  1.75
06. Oyster bay       3      4.28   4320   120      139 ACSRI00  0.4  0,56  0.331  0.93  0.37  0.34    2126    2465    24        33  1.15   1.33  0.22      0.25  1.96  2.27
0.93  0.36         15231   18037   658    961  4.32   5.33



MEDIUM VOLTAGE FEEDERS LOSS CALCULATIONS ON PRESENTSYSTEM   1991/1995 -DAR ES SALAAM  (ContinuPage 2 of 3)
LOADS AT SYSTEM PEAK
POWER AND LOSS CALCULATIONS                   VOLTAGE DROP CALCULATICNS
1990    1995                                                    1991    1995  1991   1995  1991   1995  1991    1995  1991  1995
FEEDEE            Growth   Length   Con/d  Max. I   Max I Conductor Dist. Factor Resist. COkPF   Old Induct.   Power   Power  Loss   Loss   Losses in %    Voltage Drop    Voltage Drop
NAME            Rare(%)      (lm)  (KVA) (Amps)  (Amps) Type, Size loss  Volt dr.per km  Cosd   Sino per km    (KW)    (KW)  (KW)   (KW)              in (KV)  in (KV) in (%) in (%)
MBEZI S/S I1 KV FEEDERS
15 . SS Capacity (MVA)    67 - SS loading In % by 1995
KUNDUCHI             10    13.46   10065   180       290   ACSR50  0.4  0.56    0.7  0.93  0.37 0,385    3189    5137   366    950 11.49   16.50  1.66           3.00 16.93 27.27
PACKERS               3      3.36    2230    60       70     CU 25  0.4  0.56  0.741  0.93  0.37 0.383    1063    1232    11         14  1.01    1.17  0.16      0.19  1.46  1,71
LUGALO                2      6.96    3950   150      166  ACSR100  0.4  0.56  0.331  0.92  0.39  0.34    2629    2903    62          76  2.37    2.61   0.44     0.49  4.03  4.45
0.93  0.38           6862    9272   439   1040  6.38  11.22
FACTORYZONE1S/S11KVFEEDERS    10 - SSCapacity(MVA)          57 -.SS oadingin% by 1995
F5 BUGURUNI           3       3.2  15420    70        81  ACSR100  0.4  0.56  0.331  0.71   0.70  0.34       944    1094      6       6  0.66    0,76  0.10      0.12  0.93   1.08
F2. RTD               5       2.5   8610   170       217  ACSR100  0.4  0.56  0.331  0.71   0.70  0.34    2300    2935    29         47  1.25    1.69  0.20      0.25   1.76   2.27
0.71  0.70           3244    4030    35       55  1.08    1.37
FACTORYZONEIIS/S11KVFEEDERS       10 .SSCapacily(MVA)       23 - SS loading in% by 1995
KILTEX                1       0.5   2000    21        22 CU195 U/G    1     1  0,228  0.89  0.46  0.06       356      374     0       0  0.04    0.04   0,00     0.00   0.04  0.04
KISARAWE              1      17.8   7050    28        29   ACSR50  0,4  0.56    0.7  0,89  0.46 0.385        475      499    12      13  2.47   2.59  0.39       0.41   3.51   3.69
UKONGA                3         5    2265    60       70   ACSR50  0.4  0.56    0.7  0.89  0.46 0.385    1017    1179    15          20   1.49   1.72  0.23      0.27  2.11   2.45
0.89  0.46           1848    2053    27       33   1.46    1.63
FACTORYZONE III 5/S! 11KV/FEEDERS    10 - SSCapacity (MVA)  83  SS loading in% by 1995
F31,INDUSTRIAL        4       2.6  16545   187      228 ACSR100  0.4  0.56  0.331  0.71   0.70  0.34    2532    3081    36           54  1.43    1.74  0.22      0.27  2.04  2.48
F32,AIRWING           1      3.38    1775    51       54  ACSR100  0.4  0.56  0.331  0.88  0.47  0.34        855      899     3       4  0.41    0.43  0.08      0.08  0.69  0.72
F33,AIRWING           1       2.3   3360    66        71  ACSR 100  0.4  0.56  0.331  0.79  0.61   0.34    1016    1068       4       5  0.41    0.43  0.07      0.07  0.64  0.68
F34, KIWALANI         5       5.8   9245    70        89  ACSR100  0.4  0.56  0.331  0.91  0.41   0.34    1214    1549    11         18  0.93    1.19  0.17      0.22   1.58  2.02
TOTAL                                                                                  0.79  0.61           5617    6597    55       60  0.96    1.22
KIGAMBONI S/S 11 KV FEEDERS        5 - SS Capacity (MVA)    61 - SS loading In % by 1095
Kigam Ft              6       10             75      100   ACSR50  0.4  0.56    0.7  0.69  0.46 0.385    1272    1702    47          85  3.72   4.97  0.568    0.76  5.28  7.07
Kigam F2              6        6             84      112   ACSRSO  0.4  0.56    0.7  0.69  0.46 0.385    1424    1906    36          64  2.50   3.34  0.39       0.52  3.55  4.75
0.89  0.46           2696    3608    83    148  3.07   4.11
TOTAL FOR ALL11 KV (Without dversOy)                                                                     96347  121251  2602   4452  2.70   3.67
TOTAL FOR ALL 11 KV (Whh diversity allowed for)               0.98  .Diversity Factor                      94420  118826  2498   4276  2.65    3.60
I
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MEDIUM VOLTAGE FEEDERS LOSS CALCULATIONS ON PRESENT SYSTEM 1991/1995 -DAR ES SALAAM (ContlntiPeg. 3 of 3)
LOADS AT SYSTEM PEAK
POWER AND LOSS CALCULATIONS                  VOLTAGE DROP CALCULATIONS
1990    1999                                                   1991    1995  1991   1995  1991   1995  1991    1995  1991  1995
FEECER           Growth   Length   Con/d Max. I   Max I Conductor DiOt. Factor Resist. OktPF   Old Induct.   Power   Powar  Loss   Loss   Losses in %    Voltage Drop    Vohage Drop
NAME            Rare(%)     (km)  (KVA) (Amps)  (Amps) Type, Size loss Vol dr,per km  Cos 6  Sin 6 per km    (KW)    (KW)  (KW)   (KW)             in (KV)  in (KV) in (-/%) in (¾/6)
DAR ES SALAAM 33 KV FEEDERS
ILALA GRD SUBSTATION
ILALA-C.C 1         4.8      2.5  30000   148      187 AOSR 100   1       1  0.331  0.94  0.34  0.39    7943   10028    54        86  0.69    0.89  0.28    0.35  0.84  1,09
ILALA-C.C 1         4.8      2.5  30000   148      187 ACSR100    1       1  0.331  0.94  0.34  0.36    7943   10028    s4        86  0.68   0.86  0.28    0.35  0.84  1.06
ILALA-KURASINI      5.3      5.9  15000   232      301  ACSR100    1      1  0.331  0.91  0.42  0.36   12045   10697   316    530  2.63    3.40  1.07         1.39  3.25  4.21
KJRASNI-KIGOMBON    6.0        4    5000    53       71 ACSR 100    I     1  0.331  0.89  0.49  0.36    2696    3608    11        20  0.41    0.55  0.17      0.23  0.51   0.68
ILALA.OYSTERBAY     3.4      5.6  15000   285      338 ACSR 100    1      1  0.331  0.93  0.36  0.36   15231   19037   453    635  2.97   3.52  1.21          1.43  3.67  4.35
ILALA-FZI           4.4      4.7  15000    80        99 ACSR 100    1     1  0,331  0.71  0.70  0.36    3244    4030    30        46  0.92    1.14  0.32      0.39  0.96  1.20
ILALA 11 KV         4.3        0  46000   373      460                               0.93  0.37          19831   24453   312    481  1.57    1.97
TOTALILALASS.                     110000   946    1259                               0.92               96236   82173  1230   1885   1.86   2.29
TOTAL FOR 33kV FEEDERS ONLY OFF ILALA S/S                                                                46405   57720   918   1404   1.98   2.43
UBUNGO GRID SUBSTATION
UBUNGO-ALAF         2.0     9.24   45000    93     103 ACSR 100   1       1  0.331  0.89  0.46  0.36    4731    5223    79        97  1.68   1.85  0.68       0.75  2.07  2.28
UBUNGO-WAZO1        6.1      8.8  20000   130      175 AOSR100    1       1  0.331  0.93  0.38  0.36    6882    9272   148    268  2.15    2.89  0.88         1.18  2.96   3.58
UBUNGO-WAZOII'    2.5       18.2  15000   123       139 ACSR 100   1      1  0.331  0.80  0.60  0.36    5626    6365   274    350  4.86   5.50  1.96    2.11   5.65  6.39
UBUNGO-TAZARA-      1.5     7.85   10000    55       59 ACSR 100   I      1  0.331  0.85  0.53  0.36    2650    2855    23        27  0.88   0.94  0.35       0.38   1.06  1.14
UBUNGOMtKODRENI    5.7      5.15   15000   199     262  ACSR100   1       1  0.331  0.94  0.34  0.36   10662   14083   202    352  1.89   2.50  0.77          1.02  2.33  3.08
UBUNGO-Fl1          3.0       11   15000   155     180 ACSR100    1       1  0.331  0.84  0.54  0.36    7466    8649   263    353  3.52    4.08  1.40         1.62  4.24  4.91
Fili-FIl            2.1        7    5000    36      40 ACSR 100    1      1  0.331  0.89  0.46  0.36    1848    2053        9     11  0,50   0.50  0.20       0.22  0.61  0.68
UBUNGOF.TX2-        2.0     1.75    4706    40      44 ACSR 100    1      1  0.331  0.80  0.60  0.36    1829    2019        3      3  0.15    0.17  0.06      0.06  0.18  0.20
UBUNGO-NORDIC       5.0       55    8410    64       82 ACSR 100  0.4  0.56  0.331  0.92  0.39  0.36    3366    4295    89    146  2.66    3.39  1.52         1.94  4.61   5.85
UBUNGOIIKV          6.6        0   30000   145     200                               0,93  0.38     0    7683   10568   195    370  2.54   3.51
TOTALUBUNGOSS,                    168116  1004     998                               0.89                50894   63330  1285   1978  2.53   3.12
TOTAL FOR 33kV FEEDERS ONLY OFF UBUNGO SlS                                                               43211   52763  1090   1608  2.52    3.05
Note: For 33 kV lines items marked with an * have been computed based on feeder curronts
All other 33 kV line loads have been computed from data derived from 11 kV loads
TOTAL FOR 33 KV FEEDERS DAR ES SALAAM  and based on total load supplied to 33 kV system                 117130  145503  2009   3012   1.71    2.07
TOTALFOR33KVFEEDERSDARESSALAAM andbasedonloado133kVfesdersonly                                           89616  110483  2009   3012  2.24    2.73
TOTALFOR 33KVFEEDERSDARESSALAAM  andbasedontotalloadsur4pliedto33kVsystem-diversityallowo   0.98        114787  142593  1929   2892   1.68   2.03
TOTAL FOF 33KV FEEDERS DAR ES SALAAM  and based on load of33 kV feeders only -with diversity allowed for  87823  108273  1929   2892  2.20    2.67
TOTALFOR 11 and 33 FEEDERS DARESSALAAM andbasedontotal loadsuppliedto33 kVsystem                        117130  145503  4610 7483.6  3.94    5.13                                                PN
TOTALFOR 1and33 FEEDERS DARESSALAAM andbaaedonloadotf land33kVfeedersonly                              89615,7  110483  4610 7463.6  5.14    6.76                                                g  g)
TOTAL FOR II and 33 FEEDERS DAR ES SALAAM and based on total load supplied to 33 kV system -with divershy allowed for    114787  1 42593  4428 7168.1  3.86   5.03                               r  I-
TOTALFOR 11 and 33 FEEDERS DAR ES SALAAM andbased on loadof 11and33 kVfeeders only.whhdiversdyallowedfor  87823.4  108273  4428 7168.1  5.04    6.62
0 >)



-114-
TABLE A 2.2
MEDIUM VOLTAGE SYSTEM LOSS CALCULATIONS 1991/1995 - TANGA REGION.
Gowth        1991  1995    1991    1995   1991  1995   1991  1995
Feeder                rate Length  Maxl MaxI   Power   Power   Loss  Loss   Vottage drop
Name                 used %   (km) (Amps) (Amps)   (kW)    (kW)    (%)   (%)    (%)  (%)
MAJANI MAPANA S/S
NGUVUMALI(i)           4.20   3.5 104.0 122.6   1684    1986   1.12  1.32    1.77  2.08
NGUVUMALIii)           4.20   3.0  64.0  75.4   1036    1222   0.62  0.73    1.04  1.23
NGUVUMALITOTAL         4.20  6.50 104.0 122.6   1684    1986   1.50  1.76    2.81  3.32
ClC                    4.20   3.6 142.2 167.6   2303    2715   3.14  3.70    3.71  4.38
TANGAI                 4.20  11.4 137.0 161.5   2219    2616   3.83  4.52    6.34  7.48
TANGAD                 4.20   2.0 152.0 179.2   2462    2902   0.93  1.10    1.46  1.74
SARWI SPUR()           4.20   2.8  32.0  37.7    518      611   0.22  0.26    0.36  0.43
(ii)             4.20   5.0 12.10  14.3    196      231   0.33  0.39    0.44  0.52
MiSAMBWENISPUR         4.20   0.9  9.60  11.3    155      183   0.03  0.03    0.04  0.05
USAGARASPUR            4.20   4.0 78.00  92.0   1263    1489   0.96  1.13    1.52  1.79
TANGAIITOTAL           4.20         152   179   4595    5416   0.80  0.95    3.84  4.53
TOTAL(Tanga Town 11k v)                         10801   14718    2.0   2.1
KOROGWE SS
KOROGWEI               4.20   7.0  24.0  28.3    389      458   0.92  1.09    1.23  1.45
KORFOGWEI              4.20  24.6  43.0  50.7    696      821   5.81  6.85    7.76  9.15
TOTAL                                            1085    1279   4.06  4.79
KWAMGWE SIS
KWAMGWE                4.20   7.0  11.8  13.9    191       225   0.68  0.80    0.76  0.89
TONGONI SrS
MWAKIDILA              4.20   8.0  28.0  33.0    453       535   0.55  0.65    0.96  1.13
MAZiNDE SIS
LUSHOTO(i)             4.20  12.5  48.0  56.6    777       916   8.24  9.71    7.86  9.27
LUSHOTO (ii)           4.20  21.5  19.2  22.6    311      367   2.27  2.67    3.03  3.57
LUSHOTO(iii)           4.20  38.5  28.8  34.0    466       550   6.09  7.1B    8.14  9.60
SUBTOTAL               4.20  72.5  48.0  56.6    777       916  12.80 15.09    19.0  22.4
MKUMBARA               4.20  16.5  15.2  17.9    246      290   3.10  3.65    3.12  3.68
MAZINDE                4.20   5.0   8.0   9.4    130       153   0.55  0.65    0.52  0.62
TOTAL                                            1153    1359  16.45 19.39
BLHURI SIS
BEHURii                4.20   5.0  10.0  11.8    162       191   0.34  0.40    0.44  0.52
MUHEZA TOWN SIS
TOWNI                  4.20  10.0  10.6  12.4    171       202   1.23  1.45    1.26  1.49
MUHEZAli               4.20   5.0  30.7  36.2    497       586   1.26  1.49    1.41  1.66
TOTAL                                             668      788   1.26  1.48
MUHEZA HOSPITAL S/S
MAGILA                 4.20   2.0   1.6   1.9      26       31   0.04  0.05    0.04  0.05
GOMEA S/S
GOMiBAI                4.20   3.0  14.2  16.7    230       271   0.41  0.48    0.45  0.53
GOMBAII                4.20   5.0   6.6   7.8    107       126   0.36  0.43    0.39  0.46
TOTAL                                             337      397   0.39  0.47
MOMBO SS
WOMBO                  4.20  17.7  11.9  14.0    193       227   1.73  2.04    1.93  2.27
LANZONI S/S
LANZONII               4.20   5.0   7.0   8.3    113       134   0.29  0.34    0.32  0.38
LANZONIII              4.20  20.0  69.1  81.5   1119    1319   3.39  4.00    5.61  6.62
TOTAL                                            1232    1453   3.10  3.66
MOA S/S
MOA                    4.20  15.6   9.3  11.0    150       177   1.19  1.41    1.33  1.57
BWEMBWERA SIS
BWFEMEWERA             4.20   4.0   9.9  11.7    160       189   0.44  0.51    0.47  o.65
NEW SAGEN S/S
NEWSAGEN               4.20  15.0  26.2  30.9    424       500   2.16  2.54    2.88  3.40
BUSHIRI SiS
BLISHIRII              4.20  14.2  10.0  11.8    162       191      1     1      1.0   1.2
BEJSHIRIII             4.20  32.2  30.0  35.4    486       573      5     6      7.1   8.4
TOTAL                                             648      764      4     5      8.1   9.6



-115-
TABLE A 2.2 Cont.
Gowth       1991  1995   1991    1995  1991  1995   1991  1995
Feeder               rate Length  Maxl Max]  Power   Power  Loss  Loss   Voltage drop
Name                 used %   (km) (Amps) (Amps)   (kW)    (kW)   (h)   (%)    ()  (
MAGUNGA S/S
MAGUNGA               4.20  20.0  63.0  74.3   1020    1203   6.92  8.16    9.24  10.9
PONGWE S/S
P.GNWE                4.20   4.0   5.5   6.5      89      105   0.27  0.32    0.27  0.32
MARALMA S/S
MARAMBA               4.20   7.0  55.2  65.1    894    1054   2.12  2.50    2.83  3.34
MNYUI S/S
PANYLU                4.20  12.0   5.0   5.9      81       95   0.33  0.39    0.44  0.52
MLEMUA S/S
LEMUA                 4.20   8.0  32.0  37.7    518      611   1.41  1.66    1.88  2.21
HALE S/S
HALE                  4.20   5.0  40.0  47.2    648       764   1.10  1.30    1.47  1.73
TORONTO S/S
TORONTO               4.20   1.6  11.0  13.0    178       210   0.11  0.13    0.14  0.17
KILLLU SIS
KILULU                4.20   7.0   5.0   5.9      81       95   0.24  0.28    0.31  0.36
AMBONI S/S
AMBONI                4.20   1.5   1.6   1.9      25       30   0.02  0.02    0.02  0.02
33 KV LINES
FROM HALEIPANGANI POWER STATIONS VIA SONGA SWITCHING STATION.
KDROGWE I             4.20    33
sections
SDNGAY 0RDROGWE       4.20    33  45.0  53.0   2186    2577   2.64  3.11   3.45  4.07
RANDENISPJR           4.20    80  11.0  13.0    534      630   0.72  0.85    1.22  1.44
MAZINDE SPUR[with sections)
I,0ROGWE-MAZ9DE       4.20    56  34.0  40.1   1652    1947   1.35  1.59    2.48  2.92
MA!NDE-TORONTO        4.20    23   7.0   8.3    340      401   0.19  0.22    0.29  0.35
TOTAL-KOROGWEI        4.20        45.00  53.0   2186    2577    3.9   4.6
KIROGWEII             4.20    33
sections
SONGA-MAGUNGA         4.20    23  33.0  38.9   1603    1890   0.67  0.79    1.18  1.39
MUBAU SPR             4.20    20  10.0  11.8    486      573   0.42  0.50    0.53  0.62
MAGUNGA4<)ROGVE       4.20    10 21.20  25.0   1030    1214   0.38  0.44    0.49  0.58
TOTAL-KOROGWEi        4.20         33.0  38.9   1603    1890   1.04  1.23
KANGEI                4.20    67
sections
SONGA-MUHEZA          4.20    10  41.2  48.6   2002    2360   0.66  0.78    0.91  1.07
BJS-RtSPUR            4.20    70 22.00  25.9   1069    1260   1.09  1.29    2.00  2.36
MUHEZA4CFHOTE         4.20    22 19.20  22.6    933    1100   0.75  0.88    0.98  1.16
MOA SPUR [with sections)
CHOTE-PANDE           4.20    10 15.00  17.7    729       859   0.28  0.33    0.35  0.42
PANDE-MOA             4.20    38  8.10   9.5    394      464   0.22  0.26    0.40  0.47
TOTAL                 4.20         41.2  48.6   2002    2360   1.73  2.05
KANGEII               4.20    67
sections
SONGA-MLNGANO         4.20    14  41.2  48.6   2002    2360   1.06  1.25    1.36  1.60
LANZONISPUR           4.20    16 16.60  19.6    807       951   0.49  0.58    0.63  0.74
NGOMENI SPUR          4.20    15 15.40  18.2    748      882   0.47  0.56    0.57  0.67
MUNGANO-CHOTE         4.20    18  9.20  10.8    447       527   0.30  0.36    0.39  0.46
TOTAL                 4.20         41.2  48.6   2002    2360   1.50  1.77
FROM MAJANI MAPANA S/S
T.F.C                  4.20    5  20.6  24.3   1001    1180   0.47  0.56    0.47  0.55
S.RM                  4.20     2  24.7  29.1   1200    1415   0.21  0.25    0.21  0.24
CEMENT 1W              2.00    11 309.0 334.5  15013   16250   3.54  3.83   4.29  4.64
TOTAL                                          17214   18845   3.13  3.35
PANGANIOUARRY         4.20     4   8.4   9.9    408      481   0.14  0.16    0.13  0.16
KWARANGURU            4.20     1  17.6  20.7    855    1008   0.09  0.11    0.10  0.12
TOTAL                                           1263    1489   0.11  0.12



-116-
TABLE A 2.3
MEDIUM VOLTAGE SYSTEM LOSS CALCULATIONS 1991/1995 - MOSHI REGION.
1991   1995    1991   1995   1991   1995         1991   1995
Feeder           Growth Length  MaxI   Max.I  Power  Power   Loss   Loss         Voltage Drop
Name            Rate(%)  (Km) (Amps) (Amps)   (Kw)   (Kw)    (%)    (%)          (%)    (%)
11 KV FEEDERS
LAWATI S/S
SANYAJ.JU          4.0   8.3  10.0   11.7    162    189   0.20   0.24           0.34   0.39
MASAMA             4.0   23  25.0   29.2    405    474   1.41   1.65            2.33   2.73
TOTAL                          35.0            567    663   1.07   1.25
MACHAME S/S
HOSPITAL           4.0    1 l46.0   53.8    745    872   1.24   1.45            2.05   2.40
KIBO 11            4.0     6  14.0   16.4    227    265   0.21   0.24           0.34   0.40
TOTAL                          60.0            972   1137   1.00   1.17
BOMA MBUa YS1
KBO                4.0     5  30.2   35.3    489    572   0.82   0.96           1.02   1.19
BOMA               4.0   14  10.7   12.5    173    203   0.54   0.63            0.74   0.87
TCWNNFEEDER        4.0     4 219.0  256.2   3547   4149   2.15   2.51           3.56   4.16
URU SECTION
URU (i)            4.0   4.7  20.0   23.4    324    379   0.75   0.88           0.94   1.09
URU (ii)           4.0   6.8   7.6    6.9    123    144   0.27   0.31           0.37   0.43
IKBORCLONISPUR     4.0   2.8  74.0   86.6   1198   1402   0.51   0.59           0.84   0.98
UNGASPUR           4.0   2.2  29.0   33.9    470    549   0.16   0.18           0.26   0.30
TOWNFDRTOTAL                  219.0  256.2   3547   4149   2.42   2.83
TOTAL                         259.9           4209   4924   2.16   2.52
TRADE SCHOOL SIS
Ml                4.0  15.5  23.0   26.9    372    436   1.96   2.29           2.62   3.06
M2                4.0   29  74.0   86.6   1198   1402  11.79  13.79           15.74  18.42
M3(i)S/S-CCM       4.0   4.4 168.0  196.5   2721   3183   1.85   2.16           3.13   3.66
M3f(1)CCM-KCMC     4.0   6.9  67.0   78.4   1085   1269   2.54   2.97           3.39   3.97
SUBTOTAL(M3)             11.3 168.0  168.0   2721   3183   2.86   3.34          6.52   7.63
TOTAL                         265.0  310.0   4292   5021   5.27   6.17
MWANGA S/S
TOWNFEEDER         4.0   26  23.0   26.9    372    436   1.47   1.72            2.43   2.84
SAME SIS
BOMAFEEDER         4.0 12.24  21.9   25.6    354    415   1.74   2.03           2.25   2.64
GONJA SIS
NDUWiU             4.0  12.5  14.0   16.4    227    265   0.54   0.63           0.85   1.00
33 KV FEEDERS
KIYUNGI S/S
TPC                 t 1.0   17  72.0   74.9   3498   3640   1.00   1.04          1.69   1.76
KIA                4.0  47.3  27.0   31.6   1312   1535   1.58   1.85           2.36   2.77
KrYUNG-B'M;BLZ     4.0     7 150.0  175.5   7288  8526   2.15   2.51            2.60   3.04
B1MBUZ-RONGAI      4.0 121.5  58.6   68.6   2847   3331   5.82   6.81           9.86  11.53
KIYUNG-T/SCH       4.0   13 131.0  153.3   6365   7446   3.48   4.07            4.21   4.93
TISCH-MACHAME       4.0  22.2  25.0   29.2   1215   1421   0.45   0.53          0.77   0.90
TOTAL                                        18462  21146   3.28   3.87
NYUMBA YA MUJNGU PCWER STATION
MWANGA             4.0   29  14.5   17.0    704    824   0.52   0.60            0.73   0.85
SAME S/S
GONJA              4.0   53   5.8    6.8    282    330   0.31   0.37            0.51   0.60
SAMETOWN           4.0  0.01   7.3    8.5    355    415 0.0001 0.0002         0.0002 0.0002
TOTALPOWERANDPOWERLOSS                       19803  22715   4.78   5.65



-117-
TABLE A 2.4
MEDIUM VOLTAGE SYSTEM LOSS CALCULATIONS 199111995 - ARUSHA REGION
Growth        1991   1995      1991   1995   1991 1995    1991 1995
Feeder             Rate Length MaxJI  Maxl       Power  Power   Loss Loss   Voltage Drop
Name              used %   (km) (Amps) (Amps)     (Kw)  (Kw)   (%) (%)        (%)  (%)
I1KV FEEDERS
THEMI SIS
THEM                4.00   3.4   100    117       1620   1895   0.82 0.96    1.36  1.59
KILTEX S/S
KILTEX              4.00   2.1    35      41      571    668   0.27 0.31    0.37  0.43
KILTEXFACT.         4.00   0.1    12      14      194    227   0.01 0.01   0.004  0.01
TOTAL                                              765    895   0.20 0.23
POWVER HOUSE S!S
MONDULI(i)          4.00   2.0   156    182      2526   2956   1.91 2.24    2.26  2.65
MONDULI(ii)         4.00  29.0    43      50      696    815   7.65 8.94    9.04  10.6
MONDULI(iii)        4.00  14.0    38      44      615    720   2.76 3.23    3.74  4.38
MONDULI TOTAL       4.00  45.0   156    182      2526   2956   4.69 5.49
FEEDER1             4.00   3.6   110    129       1781   2084   1.21 1.42    1.92  2.25
FEEDER2Town         4.00   2.2   176    206      2850   3334   2.14  2.5    2.67   3.1
FEEDER2Rural        4.00  30.0    28      33      455    532   3.62  4.2    4.89   5.7
FEEDER 2 Total                                   2850   3334   2.71  3.2
FEEDER3             4.00   7.2   203    237      3288   3846   3.58 4.19    5.93  6.94
TOTAL                                             7919   9265   2.74 3.20
TENGERU SIS
TENGERU             4.00   6.0    34      40       548   641   1.32 1.54    1.71  2.00
MAKUMIRA S/S
MAKUMIRA            4.00   7.9    16      18      255    298   1.37 1.60    1.47  1.72
33 KV FEEDERS
NJIRO GRID SIS
INTER-CONNECTOR     4.00   7.0   280    328    13604  15915   4.01 4.69    4.85  5.67
INDUSTRIAL          4.00   9.4   170    199      8260   9662   2.78 3.25    3.75  4.39
FROM POVNER HOUSE eSS
MOSHVARUSHA         4.00  48.6    65      76     3158   3694   2.58 3.02    4.37  5.12
TOTALFORARUSHAREGION                             21863 25577   5.02 5.88



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S  A M  P  L  E   O  F   L  V   L I N E    L O  S S              C A L C U L A T I O  N S                            TABLE A3
DAR  ES  SALAAM  REGION.1991 LOADS
LOAD
MAIN      PHS    DIST.   NO.    RES.   NO.        DISTR.    LOAD  PCWER  LOSS   '%LOSS  LOADING OF INDMDUAL PHASES IN AMPS  AVG    % inc. DENSrrY
LINE              (KM)   WSES   OHiKM  SECT.  FACTOR   AMP.           KVA  KW               RPH       YPH       BPH       NPH   LOAD    for   Amp os
unbalance house
MBURAHATI NHC 200KVA
MAN F2         3    0.74     213    0.70       3      0.52    137   94.3    15.09    15.2    180.0    130.0    100.0   55.0 136.7   11.2   1.9
S1             1   0.41       16    0.32       5      0.44      31    7.1      0.11     1.5
S2             1   0.44       39   0.32        8      0.40      75   17.3      0.63    3.5
S3             1   0.36        35    0.70      8      0.40      67   15.5      0.92    5.6
houses in spum                 g0        Total ior spurs             39.8       1.66    4.0
houses in main line           123        Total for fender            94.3    16.75    16.9
MAINFl         3   0.62       317    0.32      5      0.44    130   89.7       4.43    4.7    200.0    120.0         70.0   60.0 130.0   24.1   1.2
Si             1   0.38        36    0.70      8      0.40      44    10.2     0.41     3.8
S2             1   0.40       29    0.70       8      0.40      36    8.2      0.29    3.3
S3             1   0.30       32    0.70       7      0.41      39    9.1      0.27    2.8
S4             1   0.25       22    0.70       6      0.42      27    6.2      0.11     1.6
housesinspurs                 119        Total for spum              33.7      1.07    3.0
houses in main line          188         Tot.l for lender            89.7      8.50     5.8
Total for the Transformer     530                                0    184    22.25    11.5
MWENGE BUS STOP S/S 315 KVA
MAINF1         3    0.54      136    0.32      5      0.44    112   77.1       2.84     3.5    125.0    100.0    110.0   18.0 111.7    1.7   2.5
S1             3   0.14        10    0.70      4      0.47       8    5.7      0.01     0.2
52             3    0.13       18    0.70      4      0.47      15   10.2      0.03     0.3
S3             3   0.11       10    0.70       4      0.47       8    5.7      0.01     0.1
84             3    0.14        7    0.70      4      0.47       6    4.0      0.00     0.1
houses in spurs                45        Total for spurs              25.5      0.05    0.2
houses in man line             91        Total for eeds,              77.1     2.89     3.6
MAINF2         3    0.23       41    0.32      3      0.52      33   23.0      0.13     0.5      40.0      40.0      20.0   20.0  33.3   20.0   2.4
S1             3    0.09       13    0.70      2      0.63      1t    7.3      0.01     0.2
82             3   0.08         6    0.70      2      0.63       5     3.4     0.00     0.1
houses in spurs               1 9        Total for spurs              10.7     0.02     0.1
houses in main line           22         Total fI, feeder            23.0      0.14     0.6
MAINF3         3   0.30       31    0.32       3      0.52      28   19.1    0.115   0.57        45.0      28.0      10.0   30.0  27.7   65.9   2.7
S1             3    0.12        3    0.70      3      0.52       3     1.8    0.001    0.05
22             3    0.08        8   0.32       2      0.63       7     4.9    0.002   0.05
houses in spurs                11        Total Ifor spur               6.8    0.003   0.05
houses in main line            20        Total sor,feder              19.1    0.118   0.59
Total for the Transformer     208                                0    119     3.155   2.52
ILALA ARUSHA STREET S/S 315KVA
MAINFl         3    0.45     117    0.23       6      0.42    163  112.7       3.48    2.93     200.0    130.0    140.0   80.0 163.3   10.6   4.2
Si             3    0.07      11    0.70       1      1.00      15   10.6      0.03    0.31
S2             3    0.11        9    0.70      3      0.52      13    8.7      0.02    0.21
23             3    0.15       14    0.23      3      0.52      20   13.5      0.02    0.14
S4             3    0.12        9    0.23      3      0.52      13    8.7      0.01    0.07
25             3    0.11        5    0.70      2      0.63       7     4.8     0.01    0.14
houses in spur                48         Total fr spur               46.2       0.1   0.18
houses inmain line             69        Total for fender            112.7     3.57    3.01
MAINF2         3    0.57     223    0.32       8      0.40    213  147.2       9.96    6.43     160.0    260.0    220.0   20.0 213.3    4.0   2.9
51             3    0.09        6    0.70      3      0.52       6     4.0      0.00    0.08
S2             3    0.15       11    0.70      6      0.42      11    7.3      0.01    0.19
S3             3    0.21       11   0.70       6      0.42      11    7.3      0.02   0.27
54             3    0.15       18   0.70       5      0.44      17    11.9     0.04    0.33
S5             3    0.05        6    0.70      2      0.63       6     4.0      0.00    0.05
s6             1   0.44        33    0.70     10      0.39      95   21.8       2.13    9.28
S7             3    0.05        5    0.70      2      0.63       5    3.3      0.00    0.04
houses in spue                 60        Total lor spur               59.4       2.2   3.53
houses in main line          133         Total for feeder            147.2    12.17    7.86
MAINF3         3    0.24       35    0.23      2      0.63      45   31.1      0.21    0.65      30.0      50.0      55.0   20.0  45.0   12.3   3.9
S1             1   0.15        21    0.23      5      0.44      81    18.6     0.20    1.02
houses in spue                 21        Total for spur               18.6       0.2   1.02
houses in main line            14        Total for feeder             31.1     0.41    1.26
Total for the Transformer     375                                0    404        16   3.80
NOTE:
The comnpulations for line losses are made using balanced load conditns
The increase of losses due to existing unbaance is presented separately
The average loud in Amps per house is also presented for each feeder



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ANALYSIS OF SYSTEM LOSSES AND SALES BY VOLTAGE LEVEL                             Table A 4
Dar es Salaam                  Tanga                   Arusha                    Moshi
TARFF            Energy sales KWhlmonth
Residential                     18,498,636                1,953,995                2,821,276                2,051,777
Light Commercial                 4,848,489                 879,279                  820,261                   772,778
Light Industrial                 1.433,871                 567,801                  400,680                   431,933
Gen Purpose LV, with KVA charge  7,051,182                 537,082                  818,093                   562,809
High Voltage Supply              6,424,823                1,186.309                2,268,517                1,128,851
Public lighting                    226,412                   48,592                   75,739                   75,585
TANESCOstaff                       094,322                   41,988                   13,610                   27,408
NUWA (Water supply)              3,532,613                 271.280
Agriculture                        152,744                1,574,275                   49,895                1,385,144
High Voltage Supply -energy intensive   7,904,800         2,662,885                       0                         0
Zanzibar                         5,702,050                    0,000                        0                        0
TOTAL UNITS                     55,869,942                9,723.486                7,268,071                6,436,286
Demand in KVA
Gen Purpose LV, with KVAcharge      36,124                    2,194                    3,635                    5,048
High Voltage Supply                 27,127                    5,155                    7,625                    3,037
Zanzibar KVA                         9,045
Agriculture                            755                    6,946                    0,363                    4,110
High Voltage Supply -energy intensive  18,802                10,748                       0                         0
NUWA (Water supply)                  4.555                     589                        0                         0
TOTALKVA                            87,363                   25,633                   11,623                   12,195
BREAKDOWN OF CONSUMPTION TO VOLTAGE LEVEL
Energy supply:
in KWh per month
132 kV supplies                 5,702,050
33 kV supplies                  8,336,800                 2,662,885                        0                        0
11 kV supplies                  5,992,823                 1,457,590                2,268,517                1,128,851
Supplies at Substations         7,203,926                 2,111,357                  867,988                1,947,953
LVsupplies                     25,101,730                 3,491,654                4,131,566                3,359,482
Supply from M'dizi              3,532,613
TOTAL UNITS                    55,869,942                 9,723,486                7,268,071                6,436,286
in per unit
132 kV supplies                       0.11
33 kV supplies                        0.16                     0.27                     0.00                     0.00
11 kVsupplies                         0.11                     0.15                     0.31                     0.18
Supplies at Substations               0.14                     0.22                     0.12                     0.30
LV supplies                           0.48                     0.36                     0.57                     0.52
Power demand
KVA Demand (non-coincident)
132 kV supplies                      9,045
33 kV supplies                      19,802                10748.333                    0.000                    0.000
11 kVsupplies                      26,127                 5211.333                 7625.333                 3037.182
Supplies at Substations             36,879                 9140.583                3998.083                  9157.909
LV supplies
Computation of coincident peak demand
Co.F   LF                Co.F   LF                Co.F   LF                Co.F   LF
132 kV supplies     1.0              9,045
33 kV supplies     .500              9,901  .500              5,374  .000                  0  .000                  0
11 kV supplies     .200              5,225  .300              1,563  .250              1,906  .250              0,759
At Substations     .200              7,376  .200              1,828  .200              0,800  .200              1,832
LV supplies              .550       63,388        .500        9,899        .500       11,477        .500        9,332
Total system peak                   94,935                   18,465                   14,183                   11,923
P.U break down ot coincident peak demand
132 kV supplies                       0.10
33 kV supplies                        0.10                     0.29                     0.00                     0.00
11 kV supplies                        0.06                     0.08                     0.13                     0.06
At Substations                        0.08                     0.10                     0.06                     0.15
LV supplies                           0.67                     0.53                     0.81                     0.78
Note:
Co.F- Coincidence factor
LF- Load factor
Cont. page 2



-120-
ANALYSIS OF SYSTEM LOSSES AND SALES BY VOLTAGE LEVEL                          Table A 4 Cont.
ANALYSrIS OF PEAK POWER (kVA) FLOW:
loss %                  bss %                   loss %                  loss%
33 kV input                        98,707                  18,440                  16,756                  14,231
33 kV line loss  .020   1,973        .012         221        .037         619        .038         540
33 kV Supplies          9,901                   5,374                       0                       0
Power to SS                       82,929                   12,537                  13.483                 11,204
SStf loss  .015      1,244        .015         188        .015         202        .015         168
11 kV loss  .028     2,285        .020         247        .057         759        .030        331
11 kVSupplies           5,225                   1,563                    1.906                    759
To LV from 33 kV                    3,904                   3,254                   2,654                   2,487
To LV from 11 kV                  74,175                    7,593                  10,616                   9,946
Power to LV tVf                   78,079                   10,847                  13,270                 12,433
LV tUf loss  .015    1,171        .015         163        .015         199         .015        186
Suppliesa1SS            7,376                    170                     800                    1,832
LVlineloss  .089      6,144        .078        816         .065        794         .105       1,083
LV Suppfies          63,388                   9,699                  11,477                   9,332
Analvsis of peak contribution in n.u
33 kV input                 1.000                   1.000                    1.000                   1.000
33 kV line loss         0.020                   0.012                   0.037                    0.038
33 kV Supplies          0.100                   0.291                    0.000                   0.000
Power to SS                        0.840                    0.680                   0.805                   0.787
SS t/f loss          0.013                   0.010                   0.012                    0.012
11 kV line loss         0.023                   0.013                   0.045                    0.023
11 kV Supplies          0.053                   0.085                    0.114                   0.053
Power to LV tt1                    0.791                    0.588                   0.792                   0.874
LV ttf loss          0.012                   0.009                   0.012                    0.013
LV line loss         0.062                    0.044                   0.047                   0.076
LV Supplies           0.717                   0.535                   0.733                   0.784
Sumof losses                        0.130                   0.089                   0.154                   0.162
ANALYSIS OF ENERGY (KWh) FLOW:
losses pu.              bsses pu.              losses pu.               losses pu.
33 kV input                   46,374,783               10,258,421               8,147,685               7,232,146
33 kV line loss  .015    695,468      .009     92,318        .028    225.929          .029    205,954
33 kV Supplies      7,578,909                2,662,885                   0,000                      0
Power to SS                   36,532,948                5,146,245               6,602,955               6,460,458
SS tAf loss  .015    547,873      .015      77,177        .015      99,022        .015      96,885
11 kV loss  .021    755,360       .015      76,019        .043    279.012         .023    143,110
11 kV Supplies      5,448,020                1.457,590               2,268,517               1,128,851
To LV from 33kV                1,567,458                2.356,973               1,318.801                565,735
To LV from 11 kV              29,781,695                3,535,459               3,956,403               5,091,613
Power to LV ttf               31,349,152                5,892,432               5,275,204               5,657,347
LV t/f loss  .015    470,133       .015     88,367        .015      79,111        .015      84,841
Supplies at SS     6,549,024                2,111,357                 867,988               1,947,953
LV line loss  .062  1,510,241      .055    201,054         .046     196,540        .074    265,071
LV Supplies     22,819,755                3,491,654               4,131,586               3,359.482
Energy flow (consumotion and lossesl in D.U.
33 kV input                         1.000                   1.000                   1.000                    1.000
33 kV line loss         0.015                   0.009                   0.028                    0.028
33 kV Supplies          0.163                    0.260                   0.000                   0.000
PowertoSS                           0.788                   0.502                   0.810                   0.893
SS ltf loss          0.012                   0.008                   0.012                    0.013
11 kV line loss         0.016                   0.007                   0.034                    0.020
11 kVSupplies           0.117                   0.142                    0.276                   0.156
Power to LV t/tf                   0.676                    0.574                   0.647                   0.782
LV ft loss           0.010                   0.009                   0.010                    0.012
LV line loss         0.033                    0.020                   0.024                   0.037
LVSupplies            0.633                   0.546                   0.614                   0.734
Sum of losses in pu.                0.086                   0.052                   0.1 08                  0.11
System Load Factor in pu.                                    76.2                    66.6                   0.890
Notes to com1ufat.orIs:
Allocation of LV supplies (pu) by capacity:
by voltage level:      33 kV        11 kV      33 kV        11 kV       33 kV       11 kV        33 kV       11 kV
At Substations            .05        .95          .30         .70          .20        .80         .20         .80
Fed from LV lines         .05        .95          .40        .60          .25         .75          .10        .90
Allocation of LV supplies (pu) by energy.:
by voltage level:      33 kV       11 kV       33 kV        11 kV       33 kV       11 kV       33 kV       11 kV
At Substations            .05        .95          .30         .70          .20        .80          .20        .80
Fed from LV lines         .05        .95          .40        .60          .25         .75          .10        .90
LLFILF for MV                        0.75                    0.75                    0.75                    0.75
LLF/LF for LV                        0.70                    0.70                    0.70                    0.70



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TABLE A 5
LOADING DENCMES OF MV FEEDERS
RtitEFt        SUPPUED      RETER       PEAK     PEAK     PEAK POWERDENSTY
NAME        AREA(SCKM)           KM  CURFENT  VOLTAGE      KVA   KVA/SC.KM
AMP.      KV.
MBEZI SIS
LUGALO             9.30        8.40   1S0.00    10.50)    3274          352
PACKEFRS           6.00       10.70    60.00    10.80     1122          187
iUJNDU0&          18.20       20.30   180.00    10.00     3118          171
MIKOCHENI SIS
MKt                3.50       17.50   155.00    10.50     2819          805
MK2                9.40       15.30   285.00    10.00     4936          525
MK3                3.10        8.20    40.00    10.90      755          244
MK4                2.50       10.60   174.00    10.70     3225         1290
OYSTERBAY SIS
02                 2.20        6.70   135.00    10.70     2502         1137
03                 3.90       15.00   296.00    10.00     5127         1315
04                 4.30       10.00   177.30    10.50     3225          750
05                 1.90        7.30   115.00    10.50     2092         1101
06                 3.10       10.70   120.00    10.50     2182          704
UBUNGO SIS
Ul                13.00       17.40   175.00    10.50     3183          245
U2                 5.10       11.50   140.00    10.50     2546          499
U7                 3.60        4.50    40.00    10.90      755          210
us                 4.70        9.70    70.00    10.90     1322          281
FACTORY ZONE I S/S
F2                 2.00        5.60   170.00    10.80     3180         1590
FS                 2.20        7.30   110.00    10.80     2058          935
ILALA  S/S
Di                 2.30        8.70   250.00    10.50     4547         1977
02                 0.80        6.00   190.00    10.50     3456         4319
D3                 1.10        5.40   175.00    10.50     3183         2893
D7                 2.70        7.20   110.00    10.70     2039          755
D8                 3.00        3.00    10.00    10.90      189           63
D9                 0.90        5.00   145.00    10.80     2712         3014
D10                5.20        9.90   240.00    10.30     4282          823
CITY CENTER SIS
C2                 1.40        7.30    75.00    10.90     1416         1011
C3                 2.60        3.00   240.00    10.90     4531         1743
C4                 0.50        3.20   270.00    10.80     5051        10102
Cs                 0.40        3.80   195.00    10.90     3682         9204
C8                 1.90        7.30   118.00    11.00     2248         1183
C8                 1.30        1.40   180.00    10.90     3398         2614
KURASINI SIS
PoRT               2.60        8.60   156.30    10.50     2843         1093
INDUSTrAL          4.90       10,50   185.00    10.50     3365          687
KtLWA/ROAD        22.00       27.50    98.00    10.80     1833           83
33 KV FEEDERS TANGA REIGION
MAZINDE          29.019                34.00    33.00     1943         0.07
TORDNTO          12.982                 11.20    33.00     640         0.05
HANDENI          22.516                 7.00    33.00      400         0.02
MAGUNGAII         6.539                21.00    33.00     1200         0.18
11 KV FEEDERS TANGA REIGION
WSHOTO           42.326                34.80    11.00      663         0.02
MUHEZAII          7.844                30.70    11.00      585         0.07
LANZONIII         6.577                69.10    11.00     1317         0.20
MARANtBA         12.230                55.20    11.00     1052         0.09
TANGATOWN         17.40       36.70   520.00    11.00     9906          569



-122-
PARTICULARS OF L.V TRANSFORMER LOADING DATA                                                                   TA8LEA6
SAMPLE DATA FROM DAR ES SALAAM
TRANSFOTMER             TRANSFCRMER                RATED  TRANSFORMERLOADS(AMPS)         TOTAL  AVERAGE %LOADING  PCWER  AREA   LOAD
LOCATION                NAME           CAPACITY  CW8    RPH    YPH    B PH       N      LOAD    LOAD       CF       KW    KM2    DENSTY
IDENTITY                               KVA    [AMPS]                                                    TRANSF.  p.1-0.9          [WIMsq4
OYSTERBAY - MSASANI PENINSULAR
11 KV FEEDER: 06
06.25                   TAZAMAFLATS         200       288       77    125    ISO      51      332      111      38.4      69   0.129       0.5
06.30E2                                     315       455      380    420    199    162       999      333      73.2     208   0.084       2.5
06.30E8                                     315       455      406    405    410      79    1221      407       89.5     254   0.105       2.4
06.34                    KIMAR1O            315       455      330    400    380      46    1110       370      61.3     231    0.113      2.0
06.34W4                  MAHENGE            200       288      260    350    210      58      820      273      94.9     170
06.39E4                                     315       455      280    300    304    125       884      295      64.8     164    0.208      0.9
06.39E8                  OYSTERBAYHOTEL    300        433      310    315    303      42      928      309      71.4     193   0,119       1.6
06.43W2                                     200       288      140    130      70     80      340      113      39.4      71
06.51                                       500       722      420    360    300    182    1080        360      49.9     224    0.209      1.1
06.56E3                                     200       288      285    275    204    147       764     255       88.4     159   0.119       1.3
11 KV FEEDER: 03
03.6E13N1                                   500       722       75     98      64     59      237       79      10.9      49    0.029      1.7
03.245E14                                   300       433      243    143    156      74      542      181      41.7     113   0.067       1.7
03.61W4                                     500       722      231    196    290    106       717      239      33.1     149
03.59                    DERJA              500       722      320    360    200    120       880      293      40.6     183   0.123       1.5
03.63E4                 ITAIAN VILLAGE      315       455      300    340    290    115       930      310      68.1     193   0.108       1.8
03.64                    EUROPASIMARKET    315        455      208    272    302    113       782      261      57.3     163   0.078       2.1
03.65E3                                     300       433      230    160    220    103       630      210      48.5     131    0.075      1.7
03.68W4                  RUSSIANVILLAGE     315       455      300    400    400    112    1100        367      80.6     229   0.192       1.2
03.70E4                  DARTAGtNE          500       722      410    410    380    116    1200        400      55.4     249   0.149       1.7
03.75                    CANADIANYILLAGE   500        722      310    290    170      26      770      257      35.5     160   0.135       1.2
03.75W4                  BAOEABVILLAGE      300       433      388    412    600    247    1400        467     107.8     291    0.063      4.6
03.78E4                  RNNIDAVILLAGE      315       455      420    180    380    220       980      327      71.8     204    0.067      3.0
03.81                    SALIMA SAUM        315       455      340    260    400      94    1020       340      74.7     212   0.06S       3.3
03.3N2                                      300       433      210    192    180      34      582      194      44.8     121    0.087      1.4
03.4A                    DFRVEINTANESCO    315        455      222    236    236    118       694     231       50.8     144   0.086       1.7
11 KV  FEEDER  MK1
MK1-03.2DE45EIA                             315       455      320    340    340      62    1000      333       73.3     208   0.062       3.4
MK1-03.20E45E4A                             500       722      474    418    430    121    1322       441       61.0     275   0.141       1.9
MK1-03.20E45E9           NICFLATS           soo       722      202    164    202    118       568      189      26.2     118   0.061       1.9
MK1-03.20E45E45S3                           500       722      318    424    340    140    1082       361       50.0     225   0.097       2.3
OVERALL AVERAGE FOR TRANSFORMER STATIONS (FEEDERSA 06,03. & MKE)                                                        4937   2.771       1.8
MWENGE AREA:
11 KV FEEDER: MK2
MWENGEPrSCH        200       288      170    180    170    158       520      173      60.2     108   0.134       0.8
MWENGEBISTOP      315        455      210    168    140      68      518      173      37.9     108   0.164       0.7
OVERALL AVERAGE FOR TRANSFORMER STATIONS FEEDER MK2                                                                      216   0.29 8      1.5
NOTE:
The high value of neutral current is observable in almost all 1ransformers
The load density (Wattsimeter sq.) provides imponant data for planning purposes
PREPARED BY ESMAAPTANESCO STUDY UNIT.



-123-
HISTORICAL LOAD DEVELOPMENT IN DAR ES SALAAM ARUSHA, MOSHI AND TANGA      Table A.7.
ANNUAL LOADS IN GWH
Arusha     Moshi      Tanga      Dar es S.  Total/4R
1979       48.8       23.4       68.5      370.7       511.4
1980       49.6       22.4       76.2      379.8       528.0
1981       50.8       23.0       76.7      385.4      535.9
1982       53.4       21.7       74.7      389.7      539.5
1983       57.4       33.6       68.0      361.1       520.1
1984       57.9       36.4       63.2      368.2       525.7
1985       56.1       39.4       74.4      392.4       562.3
1986       64.0       43.8       85.9      415.1       608.8
1987       66.9       49.5       73.9      453.6       643.9
1988       70.4       65.3       95.3      491.9       722.9
% annual load increase
Arusha     Moshi      Tango      Dar es S.  Total/4R
1979 - 1980             1.6      -4.3        11.2        2.5        3.2
1980 - 1981            2.4         2.7        0.7        1.5        1.5
1981 - 1982            5.1       -5.7       -2.6         1.1        0.7
1982 - 1983             7.5       54.8      -9.0       -7.3        -3.6
1983 - 1984            0.9         8.3      -7.1         2.0        1.1
1984 - 1985           -3.1         8.2       17.7        6.6        7.0
1985 - 1986            14.1       11.2       15.5        5.8        8.3
1986 - 1987             4.5       13.0     -14.0         9.3        5.8
1987 - 1988             5.2       31.9       29.0        8.4       12.3
% annual increase within selected periods
1979 - 1982             3.0      -2.5         2.9        1.7        1.8
1979 - 1983             4.1       14.5      -3.7        -1.7       -0.5
1979 - 1984             3.5       16.5      -6.2        -1.5       -0.6
1982 - 1987             3.8       14.7      -0.2         2.6        3.0
1983 - 1987             3.1        8.1        1.7        4.7        4.4
1984 - 1987             3.7        8.0        4.0        5.4        5.2
1985 - 1987             6.0        7.9      -0.2         4.9        4.6
1982 - 1988             4.7       20.2        4.1        4.0        5.0
1983 - 1988             4.2       14.2        7.0        6.4        6.8
1984 - 1988             5.0       15.7       10.8        7.5        8.3
1985 - 1988             7.9       18.3        8.6        7.8        8.7
1979 - 1988             4.2       12.1        3.7        3.2        3.9



I



ANNEX B
TRANSMISSION SYSTEM - LOAD FLOW STUDIES



I



-127-
Annex B
TRANSMISSION SYSTEM - LOAD FLOW STUDIES
List of Figures and Tables
Figures
B. 1        Daily load profile for a typical weekday
B.2         Daily load profile for a typical weekend
B.3         Consolidated yearly load duration curve
B.4         Single line diagram of the Transmission system
Tables
B. 1        Forecast yearly system loads and power balance
B.2         Transmission line data used for load flow studies
B.3         Effects of Capacitor applications at Dar es Salaam
B.4         Effects of capacitor applications at Arusha
Key results of load flow studies
The key results of load flow studies undertaken are provided in a number of tables in this
Annex. Among the data presented are total system losses (including the contribution from the
various sections of the network), bus voltages, the generation particulars at the power stations,
reactive compensation applied (both inductive and capacitive), tap positions of voltage
transfonnation buses and the power flows along key transmission lines.



I
I



-129-
Load duration curve for Thursday, Nov. 14, 1991
300
250                                                                            Figure B1
200
150
100
50
0         4          8          12        16         20         24
Houns
300 ~
Load duradon curve for Sunday.
Nov. 17, 1531
250                                                                             Figure  B2
200- 
150  
100
50
0t
a                    8         12         16         20         24
Ifours
300 - _
COMPOSr ANNULIDALOA DURATION CURVE
250- -                                                                          Figure  B3
200
150
100
50
0
0.00      4.00      8.00      12.00      16.00     20.00     24.00
Equivalent daiiy hours



SCHflC:,lfAFlC REPRESENVATIONV OF TAXES CO  TRANSMIISS10IV ETIVORIC
~~~~ms  132 3{gr) 
DI~~~~~~~~~~~~~~ A7*oxv
30
DIESEL       n_mu                    t I 0    AI     9           Ir.U
28           T29                                                                         -32Bus ,Aus.
32~~~~~~~~~~~~~~~~~~~~~~~~N 3
A3022          2     7                    4.U i aW
DIESED 25Il1E.
J7.sl17 .   - t ZV3 ~ sa
MurA 220             go JWnO                                 16
2 1
V.S L1lc II!
3             ~~~1 2
Wmono
22~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~(
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24 ;It ......... ~~~~~~~~~~~DJIESF;LS   -_ltJ1>t IJZ                      4s
rilE taLI'ACE IN XV IS L'ICA7) AT EAc1 UUE.                       M 4
,LCJ ,. ,iJ,_ , 1t



FORECAST YEAStLY SYSTM LOADS AND POWEFI BALANCE
WMUAM0q. 12O1Dt0tf1PEIJDMWA0ttYEM  WOWO9JSTA11OM
PA     1ool    fell    1503    1109       IOSS    I55      1004    1004    toss    loss       Ise 1050 100    109?    too?    l0ot    1500    1ess    1ots    3000    3000    2001    2001
MW    S ON             km     WNAR      SOW   WOAR        WMN   WOAR       VWI   WNAI       SiN   UVAR        W AR     MW U    VAR               kW IVM  I    SNAIl    MON    SOAR  UON    SVAIl
PoDAI'                    I      0.0     3.5        7       3       7.6     3.0      7.0      3.0     0.5      4.1      0.0     4.4      6.0      4.0    10.2       4.0    10.0      3.0    11.$       4.2    12.3       4.0
s12OOF104M*               a      o.0      O.o       0        a      0.0     0.0      0.0      0,0     0.0      0.0      0.0     0.0      0.0      0.0      0.0      0.0      0.0     0.0      0.0      0,0      0.0      0.0
tbJNOO 4VV         3      0.0      0.0       0        0      0.0      0.0      0.0     0.0      0.0      0.0     0.0      0.0      0.0     0.0      0.0      0.0      0.0      0.0o     0.0      0.0      0.0      0.0
U8J400-LV                 4     10.     30.2    13.0    33.3    57.4    27,7    01.4    20.7    05.7    3I.S    70.3    34.0    71.2    36.4    00.4    30.0    11.1    31.2    02.1    33.4    00.01    30.0
S5000,uiOI4I.             I     II.?      1.0    is.?      0.4    17.0       0.0    11.0,     9,2    20.2      0.2    21.1    10.4    22.0    11.1    24.4    II.0    20.0           0.4    27.0    10.0    20.4    11.0
G1AL04M                   0      2.3      1.1     2.4      II2      2.0      1.2     2.7      1.3     2.0      0.4      2.1     1.5      3.3      2.0      3.5      1.7      3.7     1.4      4.0      1.4      4.2      I.?
YiAM.                     7      3.4      I.?     3.0      1.6      3.0     1.5      4.1      3.0     4.3      3.1      4.0     2.2      40       2.4      1.3      2.1      1.0     2.0      0,0      2.2      0.3      2.1
IA&E                      0      2.3      I,2     2.4      1.3      2.0     1.2      2.7      1.3     2.9      1.4      3.1     1.1      3.3      1.0      3.5      1.7      3.7     1.4      4.0      1.4      4.2      1.7
Los0                      S     17.0    10.0    10.A    11.1    00.3        0.0    31,7    10.1    23.1    11.2    24.0    11.0    20.2    12.7    27.9    13.5    30.7    l0.l    31.0               It'5    33.7    13.3
AFKJ"              I ~~0   20.1    12.0    21.4    121.0    22.0    11.0    24.3    IIJ?    35.0    12.0    27.01    13.3    20.3    14.2    31.2    15.1    33.3    12.1    35.4    12.0    37.7    14.5
TANGOA                   I I    22.3    13.4    23,0    14.3    25.3    12.3    27.0    13.1    20.7    13.0    30.1    14.0    32,0    11.0    34,7    10.5    37.0    13.4    30,4                  143      41.0     10.0
1SASt0fD                 I I     0.0      0.0       0        0      0.0      0.0     0.0      0.0      0.0     0.0      0.0     0.0      0.0      0.0      0.0      0.0      0.0     0.0      0.0      0.0      0.0      0.0
ZANZIA                   13a   12.3       1,4    13.1I     7.5    14.0      0.7    14.0       7.2    16.1      7.7    10.0      8.2    17.9       0.7    15.1       0.2    20.4      7.4    21.7       7.0    23.1       0.1
ILALA                    1 4    06 0    33.0    00.0    30,0    03.0    30.6    00.2    33.0    73.0    30,3    70. 1    37.0    83.0    40.4             00.4    43.3    55.7    34.7   f02,4    37.2   100,0    43.3
Km                       I 10    1.0      3.4       0      3.0      0.4     3.1      6.0      3.3     7.2      3.0      .7      3.7      0.2      4.0      5.0      4.2      0.3     2.4      0,0      3.0    lo.6       4.2
mwm               a I~~2   0.0     0.0        0       0      0.0      0.0      0.0     0.0      0.0      0.0     0.0      0.0      0.0      0.0      0.0     0.0      0.0      0.0      0,0      0.0      0.0      0.0
FV40              it~~3   1.1      3.0      0.4      3.7     0.5      2.0      0.1     3,0      0.5      3.3     0.0      3.4      7.4      3.0      7.0     3.8      0.4      3.0      0.5      3.2      0.5      3.0
sa0W3                    23    20.I    1.1A      21.4    13.0    32.       10.0    23.1    11.2    24.1    11.0    25.0    12.1    20.0    12.6    27.1    13.1    20.2    I0.2    20,3    10.0    30.6    13.0
MMA              ~~~~24   10.0     0.7    15.0       I's    10.1      0.0    17.0      0.1    10.7       0.6    10.0      0.0    23.2    10.3    23.0    10.0    24.1          S.7    20.7       0.3    27.3      130
ODDWA            ~~~25     0.2     3.1      0.0      3.3     7.0      3.4      7.5     3.0      0.0      3.0     0.5      4.1      0.0      4.4      0.0     4.7    10.3       3.7    10.0       4.0    11.0       4.0
W4IN'.                   as      I.7      0.0     l.A      0.0     1.0      0.0      2.0      1.0     2.2      I.1      2.3     1.1      2.5      1.2      2.6      1.3      2.0    1. 0      3,0      1.1      3,2      1.3
014NYM INV               271     0.0      00a       0        0      0.0     0.0      0.0      0.0     0.0      0.0      0.0     0.0      0,0      0.0      0.0      0.0      0.0     0.0      0,0      0.0      0,0      0.0
SOIANANNtA               2s      0.4      0.0      I0 a      0     10.7     0,2    11.3       0.0    13. I     5.0    12.0      0.2    II.?       0.0    14.0       7.1    15.1      0.0    l0.6       0.0     17.0      7.0
MWAN4ZA IN               2t      0.0      0.0       0        0      0.0     0.0      0.0      0.0     0.0      0.0      0.0     0.0      0.0      0,0      0.0      0.0      0.0     0,0      0.0      0.0      0.0      0.0
IAWANI4A IV              30     1 1.2     0.0    11.5      7.0    13.0      0.S    14.1       0.0    10.4      7.5    10.0      0.1     10.3      0,0     20.0      0.7    21.0      7.0    23.7       0.0    33.0      10.2
S0XAA                    3 i     0.0      0. .00,            3      0.3     3.0      0.7      3.2     7.1      3.4      7.0     3.?      0.1      3.0      0.6      4.2      0.2     3.3      0.0      3,0    10.4       4.1
TABOR                    32      3.4      1.7     3.0      6.5      3.0     1.0      4.1      2.0     4.3      2.1      4.6     3.3      4.0      2.4      5.3      2.5      5.0     3.0      0.0      2.2      0,3      2.1 
IOTAL LOAD at~d VM st"SM       Sol.0   200.0   310.0   100.0   321.3   100.3   353.3   17. 370.0 $S          10f2.   401.0   104.2   421.2   307.1   450.7   220.0   487.0   170.8   50A5    USA.   114.0   310.0 
LOADOCMROS1ION BY atc3ON INMW, WOAR
Nort*.0ast a.d                  00.3    40.3    72.7    42.0    77.4    27.0 0.6            35.so'   07.0    42.5    03.0    45.2    00.0    41.2   100.1    £1.3   113.0    41.0   120.3    43.7   412.1    30.0
East Losd                      110.0    03.1   140.0      01.0   100.3     77.0   270.2    02.3   101.0    00.0   104.4    04.0   307.0   100.1   222.1   107.4   237.4    85.2   *5337               02.1   271.2    107.1
Noth Wool Load                  37.4    20.0    30.0      SU.     42.1    30.0    41.0    22.1    40.1    23.5    52.7    35.5    10.5    27.3    60.7    20.3    65.1    23.0    05.5    20.4    70,0    20.6
Sot*~ Wat Laid                 40.3    20.3    45.3    07.5    02.0    05.1    64.0    20.5    17.0    27.0    60.5    20.0    64.3    31.2    07.5    32.0    71.1    20.0    75.5    27,4                    70.0     31.1
Total Load W#WWo. I....')      Sit.$   105.0   310.5   I00.0   I31.    100.3   3513.2   t70.6   370.0   182.2   401.0   104.2   420.3   307.1   450.7   220.8   407.0   176.0   010.4   100s.5   054.0   210.5
59atamp.Sookltasipu            0.070            0.000             0.000            0.070            0.010             0.042            0.043             0.040            0.050             0.050             C.0t0
ToItol    Sitd.OA  las12.3                      315.?            313.0             375.0            30.5.             41,4.4           440.0             470.0             611.4            545.4             501.7
Iou goas Al NM014                 0                 5                                                                    S'. 0             0                                                    It0                S
N.ow       a x10.5      21               of                it               21               It                So               21                31               32                  It              21
Pu~~~gu4          IS~~4            IS                S3               2S                                 a 00              000                               00                506               00
Total                   40                0                        424                       000                                 0000                                                 50
ftwh Wesit 00s1a      4 i50     to00o 300                          200              t0o               too0             200               200              2oo               200               200               200
L KowW                                              I                                                                                             53               153              103               153
U. lOhan4t
Toale                  200              300              200               200              200              200               to0               363              363               313               400
ToWI 144*s 0Qib"t               322               322        .     322              322            .305                300,              360               022              522               022               g6oo-
WfUOW  XPOAT (*jIMSPORlT EO 10YR ON (01MW)                                                                                                                                                                   .
100              2003             100               204                               lotsS 00          l557              10ts             Ise$              3000              2001                  U
H0I*4ot-tl                       .20              .3t               *31              .40                                 S  i5.1                          .27                -24              .$1               *$5
faot                            .140             .145         .    160              .170             -fit              .104             .300             .222              -217              .254            . 271
NoihtWedt                        43                40               37                34               31               27                23                IS               ISl               to                 1
hOAi WM54                                       ist              240              145               142           ,130                ISO          .   306                2S1              I70               320
Tota *w.ai tiy,o mspabNtS In MW
in sYalom Orduslv. of 106681)    0.7             U.13         .   31.0              .50.0            .28.5            *45.4            .77.6              43.1              60.0            .23.4             .12.7 



-132-
TRANSMISSION LINE DATA                                 Table B.21
(used for load flow studies)
Thermal
LINE (with bus numbers)              Resistance Inductance Capadtance   rating
1 KIDATU     2 MOROGORO-HV                     0.007    0.055    34.94      832
1 KIDATU     22 IRINGA                         0.025    0.136    20.83      252
2 MOROGORO-HV   1 KIDATU                       0.007    0.055    34.94      832
2 MOROGORO-HV   3 UBUNGO-HV                    0.018    0.149    23.48       416
4 UBUNGO-LV    16 RUVU                         0.049    0.112     2.31       92
4 UBUNGO-LV    12 RAS-KIRO                     0.043    0.098      2.02       92
4 UBUNGO-LV    14 ILALA                        0.012    0.026     0.50       92
5 MOROGORO-LV   6 CHALINZE                     0.086    0.196      4.03       92
6 CHALINZE    16 RUVU                          0.053    0.119     2.46       92
6 CHALINZE     7 HALE                          0.184    0.418     8.60       92
7 HALE       8 SAME                            0.210    0.478     9.83       92
7 HALE       11 TANGA                          0.063    0.143     2.95       92
8 SAME       7 HALE                            0.210    0.478     9.83       92
8 SAME       9 MOSHI                           0.053    0.119     2.46       92
9 MOSHI      10 ARUSHA                         0.079    0.177     3.70       92
12 RAS-KIRO    13 ZANZIBAR                     0.052    0.030    36.35        92
21 MTERA      22 IRINGA                        0.016    0.089    13.67       252
21 MTERA      25 DODOMA                        0.022    0.118    17.97       252
22 IRINGA    23 MUFINDI                         0.020    0.111    16.93      252
23 MUFINDI    24 MBEYA                          0.034    0.187    28.64      252
25 DODOMA      26 SINGIDA                       0.033    0.180    27.47      252
26 SINGIDA    27 SHINYAN-HV                     0.034    0.187    28.64      252
27 SHINYAN-HV    29 MWANZA-HV                  0.022    0.118    18.10       252
28 SHINYAN-LV    32 TABORA                     0.213    0.485      9.97       92
29 MWANZA-HV    27 SHINYAN-HV                  0.022    0.118    18.10       252
30 MWANZA-LV    31 MUSOMA                      0.263    0.597    12.28        92
32 TABORA      28 SHINYAN-LV                    0.213    0.485     9.97       92
Note: Resistances and reactances are on a 100 MVA base
Capadtances are in MVAr
The thermal rating is in Amps.



Table B.3   Effects of Capacitor Applications at Dar es Salaamw
Year               Ubongo                           Hale
end       -..-..--------..-..-----.         --------..---------.        Hoshl     Arusha   Morogoro   System      Loss
Load     Generation  Capac.   H.T                                                                   Losses    Reductn.
Step      MU    MVAr  MVAr   Vltoe         MU     MVAr   Vitre    MU    MVAr   HVAr         LV Volt.    MW         MU
Ulth Double circuit  frnes from Kidatu to Morogoro
93 Max   30      20     -     .924          34     18.0    1.014      8      9    22.2       1.042     20.43       -
30     20    30     .980         34      17.3    1.040      a      9    18.3      1.045      18.53     1.90
30     20    45    1.012         34      15.8    1.040      8      9    18.3      1.046      18.31      .22
93 API    5       3     -     .886          34     20.0    1.025      8      9    17.0       1.037     20.60
5      3    30     .951         34     16.6    1.040       8      9    14.8      1.041      18.01     2.59
5      3    45     .983         34     15.6    1.040       8      9    14.8      1.041      17.56     3.04
93 AP2     0      0     0     .901          34     18.8    1.040      8      9    11.7       1.036     17.55        -
0      0    30     .960         34     12.6    1.040       8      9    11.7      1.036      15.45     2.10
0      0    45     .989         34     10.1    1.040       B      9    11.7      1.038      14.99     0.46
94 Max    51     30     0     .970         34      20.0     .991      8      9    24.95      1.041     22.24
51     30    30    1.029         34     20.0    1.004       8      9    22.50     1.036      21.35     0.89
Wlth Double circuit tfries from KIdatu-Norooro-Ubungo
95 Max    25     15     0     .973         80      -1.8    1.040      8      9    21.1       1.039     15.79        -
25     15    30    1.013         80     -4.7    1.040       8      9    21.1      1.041      15.38      .41
25     15   45    1.040          80     -4.2    1.040       8      9    21.1      1.035      15.40       -
95 API    10      5     0     .981          80     12.2    1.040      0      5    26.4       1.042     17.79
10     5    30    1.021          80      9.3    1.040      0       5    26.4      1.044      17.37    0.42
0      0     0     .968         80      7.8    1.04        8      9    17.2      1.034      15.00
0      0    30    1.009         80      4.7    1.04        8      9    17.2      1.036      14.46    0.54
0      0    45    1.029         80      3.45   1.04        8      9    17.2      1.037      14.39    0.07
95 AP2     0      0     0     .956          80     -1.4    1.04       8      9    18.3       1.037     13.18
0      0    30     .999         80      -4.7    1.04       8      9    18.3      1.035      12.44    0.74
0      0     0     .957         57      9.23   1.04        8      9    18.3      1.038      14.93
0      0    30    1.000         57      5.7    1.04        8      9    18.3      1.041      14.03    0.90
95 AM1     0      0     0     .964          80     -7.2    1.062      8      9    15.9       1.034     11.13
0      0    30    1.005         80    -10.4    1.04        8      9    14.9       1.037     10.72    0.41
5      0     0     .963         34     20       1.009      8      9     8.55      1.042     16.36
5      0    30    1.005         34     20       1.018      8      9     8.22      1.039     15.72    0.64
-I
p
0i
(.



-134-
TABLE B.4
EFFECTs OF INCREMENTAL INCREASE OF CAPACITOR APPUCATIONS AT ARUSHA
BUS VOLTAGES (inpu)
With bus numberrs indicated below
Run#      Totai KJDATU  RG   HALE MOSil ARUSA    UBUNGO  ARUSi U       ARUSHA       - .- .
bosses                                 iYW MWAR MWAR    MVAR VOLTAGE
inMW    1     5     7      9    1 0                      CHANGE  CHANGE
In pu
LOAD CONDmONS CORRESPONDING TO: 1992 MAX, 1993AP1 AND 1994AP2
Hale 24 MW, 12 MVAr Moshi 4MW. 7MVAr
92-5L6     22.39 1.030 1.028 0.960 0.931 0.950    1 5     7  31.8
92-5L5     22.12 1.030 1.031 0.973 0.951 0.970    1 5     7  32.1      0.4   0.020 2
92-5L4     21.93 1.030 1.033 0.986 0.970 0.990    1 5     7  32.6      0.5   0.020
92-5L3     21.71 1.030 1.041 1.029 1.038 1.062    1 5     7  35.0      2.4   0.072
LOAD CONDriTONS CORRESPONDING TO: 1995 MAX, 1996AP1AND 1997AP2
Hade 80 MW, variable MVAr to maintainl.04 PU Voltage Mosi!i OMW, 5MVAr
B95MAX-A1 20.62 1.020 1.043 1.040 0.846 0.838    35    1 7  20.0
B95MAX-A2 19.89 1.020 1.043 1.040 0.892 0.894    35    1 7  25.0       5.0   0.056
B:9SMAX-A3 19.81 1.020 1.043 1.040 0.929 0.941    35    1 7  30.0      5.0   0.047
B:95MAX-3  19.79 1.020 1.043 1.040 0.936 0.950    35    1 7  31.0      1.0   0.009
B.9SMAX-A4 19.94 1.020 1.043 1.040 0.962 0.983    35    1 7  35.0      4.0   0.033
Hale 80 MW, vauiable MVAr to maintaint.04 PU Voltage Mosh 4MW, 7MVAr
95M-Bt     17.S1 1.020 1.043 1.040 0.900 0.893    35    1 7  20.0
B95MAX-B2 17.31 1.020 1.043 1.040 0.938 0.941    35    17  25.0        5.0   0.048
B:S5MAX-B5  17.3 1.020 1.043 1.040 0.956 0.963    35    17  27.5       2.5   0.022
BS5MAX-B8  17.4 1.020 1.043 1.040 0.959 0.967    35    1 7  28.0       0.5   0.004
B:9SMAX-B9  17.4 1.020 1.043 1.040 0.966 0.976    35    1 7  29.0      1.0   0.009  - -
Hale 80 MW. variable MVAr to maintain1.042PU Voltage MoshI 8MW, 9MVAr
95M-C2     15.57 1.020 1.042 1.040 0.906 0.889    35    17  15.0
B95MAX-C3 15.34 1.020 1.042 1.040 0.945 0.939    3S    1 7  20.0       5.0   0.050
B95MAX-C4 15.42 1.020 1.042 1.040 0.979 0.982    35    17  25.0        5.0   0.043
B:95MAX-C5 15.73 1.020 1.042 1.040 1.009 1.021    35    1 7  30.0      5.0   0.039



-135-
91Max             POWER FLOW RESULTS - 1991 MAXIMUM AND 1992 MAXIMUM BUS LOADS
System Details:   Single ect. Kidatu-Morogoro-Ubungo
1991 MAXIMUM BUS LOADS                   1992 MAXIMUM BUS LOADS
Load Flow Run No:                161      1B4 B:91MAX-1 B:91MAX-3    B:92MAX-5 B:92MAX-6 B:92MAX-7 B:92MAX-8 B:92MAX-9
TOTAL POWER INPUT              311.5    313.3    308.7    310.2         337.5    335.2    330.5    331.1    333.1
TOTALLOAD                      292.0    292.0    292.0    292.0         310.8    310.8    310.8    310.8    310.8
TOTALLINECHARGING              312.9    321.0    330.8    324.3         312.5    319.7    317.9    312.7    305.3
TOTALLOSS                      20.68    21.99    17.61    19.01         26.21    23.94    19.49    20.51    22.56
Bus Voltages:
Bus no.
KIDATU                   1    1.030    1.030    1.030    1.030          1.030    1.030    1.030    1.030    1.030
MOROGORO-HV              2    0.974    0.998    0.992    0.971          0.978    0.998    0.991    0.975    0.953
UBUNGO-HW                3    0.927    0.978    0.960    0.918          0.944    0.981    0.960    0.930    0.888
UBUNGO-LV                4    0.969    1.029    1.006    0.959          0.989    1.032    1.007    0.972    0.924
MOROGORO-LV              5    1.025    1.054    1.046    1.022          1.026    1.052    1.045    1.026    0.998
CHAUNZE                  6    1.003    1.037    1.029    1.000          0.994    1.029    1.027    1.003    0.966
HALE                     7    1.030    1.038    1.040    1.037          0.971    1.005    1.040    1.028    0.997
SAME                     8    0.969    0.972    0.978    0.976          0.937    0.953    0.977    0.971    0.957
MOSHI                    9    0.955    0.957    0.962    0.961          0.934    0.944    0.962    0.958    0.950
ARUSHA                   10    0.950    0.950    0.950    0.950         0.950    0.950    0.950    0.950    0.950
TANGA                    11    1.014    1.022    1.024    1.020         0.949    0.985    1.022    1.008    0.976
RAS-KCRO                 12    0.973    1.034    1.011    0.961         0.992    1.036    1.010    0.974    0.924
ZANZIBAR                 13    0.969    1.031    1.008    0.958         0.988    1.033    1.007    0.970    0.920
ILALA                   14    0.953    1.014    0.991    0.942          0.972    1.016    0.990    0.955    0.906
RLNU                    16    0.983    1.031    1.015    0.976          0.989    1.028    1.014    0.985    0.941
MTERA                   21    1.036    1.036    1.036    1.036          1.036    1.036    1.036    1.036    1.036
IRINGA                  22    1.029    1.029    1.029    1.029          1.034    1.034    1.034    1.034    1.034
MURFNDI                 23    1.017    1.017    1.017    1.017          1.032    1.032    1.032    1.032    1.032
,MBEYA                  24    1.004    1.004    1.004    1.004          1.038    1.038    1.038    1.038    1.038
DODOMA                  25    1.016    1.016    1.033    1.033          1.012    1.012    1.012    1.012    1.012
SINGIDA                 26    1.009    1.009    1.053    1.053          1.001    1.001    1.001    1.001    1.001
SHINYAN-HV              27    1.012    1.012    1.082    1.082          0.998    0.998    0.998    0.998    0.998
SHINYAN-LV              28    1.013    1.013    1.085    1.085          0.999    0.999    0.999    0.999    0.999
MWANZA-HV               29    1.010    1.010    1.096    1.096          0.995    0.995    0.995    0.995    0.995
MWANZA-LV               30    1.006    1.006    1.098    1.098          0.990    0.990    0.990    0.990    0.990
MUSOMA                  31    1.011    1.011    1.110    1.110          0.992    0.992    0.992    0.992    0.992
TABORA                  32    1.022    1.022    1.097    1.097          1.007    1.007    1.007    1.007    1.007
Power Generation and variable var inputs:
KIDATU        MW             193.488  201.335  186.698  188.151        202.48  200.201   196.519  197.093  199.129
MWAR              30.93    9.735   13.809   32.819        23.195    4.159   11.047   25.313   46.302
LBLUNGO       MW                   0        4        0        0           27       27        12       12       12
MWAR                 35       55       45       30           50       60        50       40       30
HALE           MW                 34       24       34       34           24       24        34       34       34
MWAR                 17       17   10.154       17           14        14   14.667       17       17
MOSHI          mW                  4        4        8        8            4        4         8        8        8
MWAR                  7        7        7        7            7        7         9        9        9
ARUSHA         MW                  0        0        0        0            0         0        0        0        0
MWAR             16.647     15.9   13.216   13.742        29.874   24.458    14.89   16.704   21.409
MTERA         MW                  S0       80       80       80           80       80        80       80       80
MWAR              -4.177   -4.178  -18.952  -18.953       -6.431    -6.43    -6.43    -6.43    -6.43
IRANGA         MW                  0        0        0        0            0        0         0        0        0
MWAR                  0        0        0        0            0        0         0        0        0
Diesels in     MW                  0        0        0        0            0         0        0        0        0
East         MWAR                  0        0        0        0            0        0         0        0        0



-136-
Cont. pg.2
POWER FLOW RESULTS - 1991 MAXIMUM AND 1992 MAXIMUM BUS LOADS Cont. Page 2
System Details:
Single cct. Kidatu-Morogoro-Ubungo
1991 MAXIMUM BUS LOADS                    1992 MAXIMUM BUS LOADS
Load Flow Run No:           B:T91-1B1 B:T91-1B4 B:91MAX-1 B:91MAX-3    B:92MAX-5 B:92MAX-6 B:92MAX-7 8:92MAX-8 B:92MAX-9
Section Power flows:
NORTH-EAST                    112.274   106.58   111.45   113.30        109.46   107.45   115.37   116.54   118.37
EAST                          109.055  116.376   107.26   106.54        131.90   131.92   119.50   118.79   118.58
KID-MOROLUNE                  187.918  195.765   180.92   182.38        191.43   189.15   185.47   186.05   188.08
EAST& N/EAST TOTAL            225.918  227.765   222.92   224.38        246.43   244.15   239.47   240.05   242.08
WEST                            78.97    78.97    79.18    79.18         84.05    84.05    84.05    84.05    84.05
SYSTEMTOTAL                   311.488  313.335   308.70   310.15        337.48   335.20   330.52   331.09   333.13
Section Power LDsses in percent
NORTH-EAST                      0.094    0.112    8.085    8.913        16.140   14.339    9.761    10.415   11.667
EAST                            0.032    0.028    3.176    3.478         3.145    2.955    3.212    3.405    3.793
KD-MOROUNE                      0.026    0.026    4.377    4.642         4.987    4.707    4.579    4.751    5.155
EAST&N'EASTTOTAL                0.084    0.089   15.638   17.033        24.272   22.001    17.552   18.571   20.615
WEST                            0.022    0.022    1.974    1.973         1.945     1.945    1.945    1.945    1.945
SYSTEMTOTAL                     0.066    0.070   17.613   19.007        26.217   23.946   19.497   20.515   22.559
Power flows in main lines:
Kidatu to Moro.   MWN         187.918  195.765  180.922  182.376       191.433  189.154  185.471   186.046  188.081
MVAR        37.964   16.769   20.885   39.894         34.638   15.602    22.49   36.756   57.745
LOSS(MW)    4.848    5.037    4.376    4.641          4.981       4.7    4.572    4.744    5.148
Moro. to Ubungo   MW          109.055  112.376  107.257  106.542       104.898  104.915  107.499  106.788  106.581
MVAR        15.247   -2.817    5.165     19.23         6.869   -4.765    4.488   14.379   27.109
LOSS(MVV)    2.428    2.336    2.192    2.379          2.168    2.029    2.203      2.32    2.577
Moro. to Chalinze  Ka          58.313   62.655   53.685   55.598        64.623   62.626   56.568   57.736   59.562
MVAR       -12.168  -16.318  -13.599  -11.184         -9.262  -13.496   -14.246  -11.786   -7.709
LOSS(MW)    2.868    3.195    2.371      2.614         3.458    3.153     2.64    2.803    3.094
ChalinzetoHale    MW           34.635   46.317   29.197   29.572        54.795   53.336   35.238   35.567   36.438
MVAR       -22.519  -19.697  -17.717  -23.296        -15.213  -15.199   -19.76  -22.051   -22.813
LOSS(MW)    2.798    4.054    1.781    2.274           5.811    5.135    2.567    2.886    3.315
Transformer Tap Possilions:
Morogoro                0.95     0.95     0.95      0.95         0.95     0.95      0.95     0.95      0.95
Ubungo                  0.95     0.95     0.95      0.95         0.95     0.95      0.95     0.95      0.95
Mwanza                    1         1        1        1             1        1         1        1        1
Fixed Capacitors I Reactors used:
bus no:
Ubungo           4        0        0         0        0             0        0        0         0        0
Moshi            9        0        0         0        0             0        0         0        0        0
Arusha          1 0       0         0        0        0             0        0         0        0        0
Tanga           11       10        10       10       10            10       10        10       10       10
RasKiromarr     1 2     -20       -20      -20      -20           -20      -20       -20      -20       -20
Iringa          22      -20       -20      -20      -20           -20      -20       -20      -20       -20
Mufindi         23      -10       -10      -10       -10          -10      -10       -10      -10       -10
Mbeya           24       -10      -10      -10       -10            0        0         0        0        0
Dodoma          25      -30       -30      -30      -30           -30      -30       -30      -30       -30
Singida         26       -30      -30      -30       -30          -30      -30       -30      -30       -30
Shinyanga       27      -20       -20      -20       -20          -20      -20       -20      -20       -20
Shiny/LV        28        0         0        0        0             0        0         0        0        0
Mwanza          29      -10       -10        0        0             0        0        0         0        0



-137-
Yr93          POWER FLOW RESULTS YEAR 1993
System Details:     With Kidatu - Morogoro second circuit
1993 MAXIMUM BUS LOADS                1993 LOAD STEP 1       1993 LOAD STEP I
Load Flow Run No:         1R5    B1R6     m-4     m-6      92-Ri   92-R2   92-R3     91-1A2  91-1A5
TOTALPOWERINPUT         351.0   348.9   351.4   349.7      332.4   328.9   329.8       311.7   310.5
TOTALLOAD               331.2   331.2   331.2   331.2      310.8   310.8   310.8       292.0   292.0
TOTALLINECHARGING       331.4   331.4   324.5   331.6      332.6   329.2   335.1       331.4   335.8
TOTALLOSS               22.19   20.00   20.43    18.8      21.62   18.14   18.74       19.48   17.64
Bus Voltages:
Bus no.
KIDATU             1   1.030   1.030   1.030   1.030       1.030   1.030   1.030       1.030   1.030
MOROGORO-HV        2   1.004   1.004   0.998   1.014       1.004   0.998   1.000       0.994   1.008
UBUNGO-HV          3   0.942   0.942   0.924   0.966       0.965   0.925   0.932       0.908   0.952
UBUNGO-LV          4   0.980   0.980   0.959   1.008       0.997   0.960   0.970       0.940   0.993
MOROGORO-LV        5   1.052   1.052   1.042   1.046       1.049   1.043   1.047       1.039   1.058
CHAUNZE            6   1.017   1.019   1.001   1.026       1.012   1.004   1.010       0.999   1.028
HALE               7   1.040   1.040   1.014   1.036       0.985   1.015   1.020       1.040   1.040
SAME               8   0.978   0.979   0.961   0.971       0.950   0.969   0.972       0.973   0.973
MOSHI              9   0.967   0.966   0.951   0.957       0.946   0.960   0.961       0.958   0.958
ARUSHA            10   0.970   0.960   0.950   0.950       0.960   0.960   0.960       0.950   0.950
TANGA             11   1.027   1.025   0.992   1.015       0.964   0.995   1.000       1.027   1.024
RAS-KIRO          12   0.992   0.992   0.960   1.011       1.000   0.962   0.972       0.942   0.997
ZANZIBAR          13   0.987   0.987   0.955   1.007       0.997   0.958   0.968       0.938   0.993
ILALA             14   0.962   0.962   0.941   0.991       0.980   0.943   0.953       0.923   0.977
RLAU              16   0.995   0.996   0.977   1.015       1.002   0.979   0.987       0.967   1.008
MTERA             21   1.036   1.036   1.030   1.030       1.036   1.036   1.036       1.036   1.036
IRINGA            22   1.032   1.032   1.028   1.028       1.035   1.035   1.035       1.035   1.029
MUFINDI           23   1.028   1.028   1.024   1.024       1.036   1.036   1.036       1.036   1.017
MBEYA             24   1.032   1.032   1.028   1.028       1.045   1.045   1.045       1.043   1.004
DODOMA            25   1.008   1.008   1.001   1.001       1.017   1.017   1.017       1.016   1.016
SINGDA            26   0.990   0.990   0.983   0.983       1.013   1.013   1.013       1.009   1.009
SHINYAN-HV        27   0.983   0.983   0.974   0.974       1.016   1.016   1.016       1.012   1.012
SHINYAN-LV        28   0.983   0.983   0.975   0.975       1.017   1.017   1.017       1.013   1.013
MWANZA-HV         29   0.977   0.977   0.968   0.968       1.015   1.015   1.015       1.010   1.010
MWANZA-LV         30   0.972   0.972   0.963   0.963       1.010   1.010   1.010       1.006   1.006
MUSCMA            31   0.970   0.970   0.960   0.960       1.013   1.013   1.013       1.011   1.011
TABORA            32   0.990   0.990   0.980   0.980        1.026   1.026   1.026      1.022   1.022
Power Generation and variable var inputs:
KIDATU    MW          202.997 204.856 199.372 197.659    199.639 182.165 192.759    193.671 192.468
MWAR           3.567   3.738  17.556  -11.528        5.2  16.246  12.958     22.176    0.76
UBUINGO   MW              30      22       30      30         10      10       0          0       0
MWAR          15.901  18.279      20      40          5  18.995  26.997        3.87      25
HALE      MW              34       34      34      34         24      34      34         34      34
MWAR          17.994  15.119      18      18         12      12      12      19.187  13.681
MOS-HI    MVW              4        8       8       8          4       8       8          4       4
MWAR               7       9       9       9          7       7       7          7        7
ARUSHA    MW                0       0       0       0          0       0       0          0        0
MWAR          24.543   19.06  22.185  18.859     28.933  21.452   20.68      15.685  15.751
MTERA     MW              80       80      80      80         80      80      80         80      80
MWAR           -1.01  -1.008  -2.908  -2.908    -12.384  -12.384  -12.384    -11.259  -4.179
IRANGA    MW               0        0       0       0          0       0       0          0       0
WVAR               0       0       0       0          0       0       0          0        0
Diesels in   MW            0        0       0       0          8       8       8          0       0
East    WVAR               0        0       0       0          0       0       0          0       0
Cont. pg.2



-138-
Yr93          POWER FLOW RESULTS YEAR 1993 CONT. PAGE i
System Details:     With Kidatu - Morogoro second circuit
1993 MAXIMUM BUS LOADS                1993 LOAD STEP 1        1993 LOAD STEP 1
Load Flow Run No:         1RS    BiR6      m-4     m-6      92-RI   92-R2   92-R3      91-1A2  91-1A5
Section Power tlows:
NORTH-EAST             118.92 121.158  120.69  116.65    100.266  11B.77 121.118    115.578 113.108
EAST                  132.906 128.502  131.20  133.67    139.002 117.411  115.414    107.997 109.346
KD-MORO UNE           185.811  187.67  182.16  180.44    204.085 186.611 197.204       188.09 186.899
EAST&NN/EASTTOTAL     253.811  251.67  254.16  252.44    242.085 238.611 239.204       226.09 224.899
WEST                   89.685  89.686   89.72   89.72      83.554  83.554  83.554      78.981  78.969
SYSTEMTOTAL           350.997 348.856  351.37  349.66    332.639 329.165 329.759    311.671 310.468
Section Power Losses in percent:
NORTH-EAST              0.120   0.098   0.103   0.097       0.145   0.089   0.088       0.098   0.090
EAST                    0.026   0.028   0.027   0.023       0.020   0.031   0.034       0.036   0.031
K0-MOROLUNE             0.013   0.013   0.013   0.012       0.014   0.013   0.014       0.013   0.012
EAST& N/EAST TOTAL      0.079   0.071   0.072   0.066       0.083   0.070   0.072       0.078   0.071
WEST                    0.024   0.024   0.025   0.025       0.017   0.017   0.017       0.023   0.022
SYSTEM TOTAL            0.063   0.057   0.058   0.054       0.065   0.055   0.057       0.063   0.057
Power flows in rnain lines:
Kidatu to Moro.  MW   185.811  187.67 182.156 180.443    204.085 186.611 197.204       188.09 186.899
MVAR     14.769   14.94  25.906  -3.178      14.655  25.701  22.414      33.861    7.794
LOSS      2.317   2.363   2.286   2.133       2.781   2.392   2.638       2.479   2.317
Moro. toUbungo MW     102.906 106.502 101.199  103.67    129.002 107.411 115.414    107.997 109.346
MVAR    25.297  25.555  32.851  15.728       19.019  32.957  29.475      41.012  21.305
LOSS      2.171   2.311   2.245   2.049       1.703   2.484   2.748       2.673   2.352
Moro. to Chalinze MNW  63.075  61.324  60.788  56.764      55.461  59.953  62.297      61.757  59.276
MVAR     -7.364   -7.69  -3.643  -13.221     -3.477  -4.051  -6.046       -4.44  -8.556
LOSS      3.117   2.949   2.931   2.632       2.407   2.846   3.062       3.044   2.732
ChalinzetoHale  MW     46.662  40.595  41.913  41.167       54.36   35.77  35.625      35.806  35.346
MVAR    -24.419  -22.736  -20.821  -20.354    -14.563  -19.066  -18.922    -25.613  -19.553
LOSS      4.578   3.508   3.719   3.394       5.494   2.729   2.669       3.195   2.564
Transformer Tap Possitions:
Morogoro          0.95    0.95    0.95    0.97        0.95    0.95    0.95        0.95    0.95
Ubungo            0.95    0.95    0.95    0.95        0.95    0.95    0.95        0.95    0.95
Mwanza               1       1       1        1          1       1        1          1       1
Fixed Capacitors I Reactors used:
bus no:
Ubungo      4        0       0       0       0           0       0       0           0       0
Moshi       9        0       0       0        0          0       0       0           0       0
Arusha     1 0       0       0       0        0          0       0        0          0       0
Tanga      11       14      14       10      10         10      10       10         12      10
RasKirom   1 2     -10     -10      -20     -20        -20     -20      -20        -20     -20
Iringa     22      -20     -20      -20     -20        -20     -20      -20        -20     -20
MuGindi    23      -10     -10      -10     -10        -10      -10     -10        -10     -10
Mbeya      24        0       0       0        0          0       0       0           0     -10
Dodoma     25      -30     -30      -30     -30        -30     -30      -30        -30     -30
Singida    26      -30     -30      -30     -30        -30      -30     -30        -30     -30
Shinyang.   27     -20     -20      -20     -20        -20      -20     -20        -20      -20
Shiny/LV    28       0       0       0        0          0       0        0          0       0
Mwanza     29        0       0       0        0          0       0       0           0       0



-139-
POWER FLOW RESULTS - YEAR 1995 & 1998 MAXIMUM BUS LOADS
WITH NEW PANGANI AVAILABLE BUT WITHOUT SINGIDA-ARUSHA UNE
Yr95/98T
System Details:  Double ccl. lines Kidatu- Morogoro - Ubungo
1995 year Maximum  loads         1998 Max loads
Load Flow Run No:      M-C2   M-C5   M-B1   M-84   M-A1   M-A4      98-D5  98-D9
TOTALPOWERINPUT        392.5  392.7  394.5  393.8  396.9  396.9     499.7  497.0
TOTAL LOAD             376.6  376.6  376.6  376.6  376.6  376.6    456.7  456.7
TOTALLINECHARGING      353.2  355.2  353.1  367.8  352.2  354.3    348.4  360.4
TOTALLOSS              15.57  15.73  17.51   16.9  20.62  19.94     42.83  40.02
Bus Voltages:
Bus no.
KIDATU             1  1.020  1.020  1.020  1.020  1.020  1.020      1.030  1.030
MOROGORO-HV        2  1.005  1.005  1.005  1.018  1.005  1.005      0.973  1.010
UBUNGO-HV          3  0.971  0.971  0.971  0.993  0.971  0.971      0.911  0.985
UBUNGO-LV          4  1.004  1.004  1.004  1.032  1.004  1.004      0.957  1.020
MOROGORO LV        5  1.042  1.042  1.043  1.067  1.043  1.043      1.038  1.033
CHAUNZE            6  1.029  1.029  1.030  1.075  1.029  1.029      1.001  1.024
HALE               7  1.040  1.040  1.040  1.164  1.040  1.040      1.040  1.040
SAME               8  0.928  1.011  0.922  1.160  0.876  0.969      0.949  0.949
MOSH               9  0.906  1.009  0.900  1.162  0.846  0.962      0.947  0.947
ARUSHA            10  0.889  1.021  0.893  1.181  0.838  0.983      0.949  0.949
TANGA             11  1.019  1.019  1.019  1.149  1.019  1.019      1.010  1.010
RAS-KiRO          12  1.006  1.006  1.007  1.035  1.007  1.007      0.955  1.020
ZANZIBAR          13  1.001  1.001  1.002  1.030  1.002  1.002      0.947  1.013
ILALA             14  0.986  0.986  0.986  1.014  0.986  0.986      0.934  0.998
RLJVU             16  1.014  1.014  1.014  1.051  1.014  1.014      0.975  1.019
MTERA             21  1.020  1.020  1.020  1.020  1.020  1.020      1.030  1.030
IR-NGA            22  1.021  1.021  1.021  1.021  1.021  1.021      1.037  1.037
MURNDI            23  1.013  1.013  1.013  1.013  1.013  1.013      1.030  1.030
MBEYA             24  1.017  1.017  1.017  1.017  1.017  1.017      1.029  1.029
DODOMA            25  0.988  0.988  0.988  0.988  0.988  0.988      1.006  1.006
SINGDA            26  0.985  0.985  0.985  0.985  0.985  0.985      1.003  1.003
SHINYAN-HV        27  0.995  0.995  0.995  0.995  0.995  0.995      0.998  0.998
SHINYAN -LV       28  0.996  0.996  0.996  0.996  0.996  0.996      0.998  0.998
MWANZA-HV         29  1.002  1.002  1.002  1.002  1.002  1.002      0.999  0.999
MWANZA-LV         30  1.002  1.002  1.002  1.002  1.002  1.002      0.997  0.997
MUSOMA            31  0.998  0.998  0.998  0.998  0.998  0.998      0.983  0.983
TABORA            32  1.001  1.001  1.001  1.001  1.001  1.001      0.998  0.998
Power Generation and varable var inputs:
KIDATU    NW          189.52 189.72 195.47 194.79 201.86 201.89    199.73 197.02
MWAR         -15.07  -15.07 -15.21  -39.79  -15.01  -15.01    84.861 16.152
LBLINGO    MW            35     35     35    35       35    35          0      0
MWAR             17     17     17    17      17    17         20     70
HALE      MW             80     80      80     80     80    80         80     80
MWAR          6.003  -10.63  9.063     0 20.591  1.878    30.953 24.812
MOSHI     MW              8       8      4      4      0      0         0      0
MWAR             9       9      7      7      5      5        25     25
ARUSHA    MW              0       0      0      0      0      0         0      0
MWAR             15     30     20     35     20     35        30     30
MTERA     MW             80     80      80     80     80    80         80     80
MWAR         -3.382  -3.382  -3.382  -3.382  -3.382  -3.383    -16.63  -16.63
IRANGA    MW              0      0      0       0      0      0       140    140
MWAR             0       0      0      0      0      0       -20    -20
Diesels in    WV          0      0      0       0      0      0         0      0
East    MWAR              0      0      0       0      0      0         0      0
Cont. pg.2



-140-
POWER FLOW RESULTS - YEAR 1995 & 1998 MAXIMUM BUS LOADS
WITH NEW PANGANI AVAILABLE BUT WITHOUT SINGIDA-ARUSHA UNE
Yr9S/98T
System Details:  Double cct. lines Kidatu - Morogoro- Ubungo
1995 year Maximum  loads         1998 Max loads
Load Flow Run No:      M-C2   M-C5   M-B1   M-B4   M-Al   M-A4      98-D5  98-D9
Section Power flows:
NORTH-EAST            134.63 134.73 133.88 133.95 133.53 133.42    170.89 163.36
EAST                   146.3 146.38 148.86 148.17 151.56 151.62    188.43 193.84
IQD-MORO UNE          159.68 159.88 165.63 164.95 172.02 172.05    285.17 282.46
EAST&N/EASTTOTAL    282.68 282.88 284.63 283.95 287.02 287.05    365.17 362.46
WEST                  101.34 101.34 101.34 101.34 101.34 101.34    124.36 124.36
SYSTEM TOTAL          392.52 392.72 394.47 393.79 396.86 396.89    499.73 497.02
Section Power Losses in MW:
NORTH-EASTinMW         8.308  8.469 10.085  9.604 13.000 12.326     24.63  23.29
EAST                   2.616  2.617  2.650  2.549  2.700  2.701      6.31   5.45
ID-MOROUNE             1.820  1.824  1.948  1.926  2.091  2.091      8.06   7.46
EAST&N/EASTTOTAL      12.744 12.910 14.683 14.079 17.791 17.118     39.00  36.20
WEST                   2.882  2.882  2.882  2.882  2.882  2.881       4.94   4.95
SYSTEMTOTAL           15.625 15.792 17.565 16.961 20.673 19.999     43.94  41.14
Section Power Losses in percent:
NORTH-EAST             0.062  0.063  0.075  0.072  0.097  0.092     0.144  0.143
EAST                   0.018  0.018  0.018  0.017  0.018  0.018     0.033  0.028
lCD-MOROLUNE           0.011  0.011  0.012  0.012  0.012  0.012     0.028  0.026
EAST& NIEAST TOTAL     0.045  0.046  0.052  0.050  0.062  0.060     0.107  0.100
WEST                   0.028  0.028  0.028  0.028  0.028  0.028      0.040  0.040
SYSTEMTOTAL            0.040  0.040  0.045  0.043  0.052  0.050     0.088  0.083
Power flows in main lines:
Kidatu to Moro.  MAW  159.68 159.88 165.63 164.95 172.02 172.05    285.17 282.46
MVAR   -3.643  -3.647  -3.782  -28.37 -3.578  -3.579    72.546  3.837
LOSS (M  1.705  1.709  1.833  1.811  1.976  1.977     5.828  5.221
Moro.toUbungo MW       111.3 111.38 113.86 113.17 116.56 116.62    188.43 193.84
MVAR   13.164  13.15 12.699  0.159 12.376 12.361    49.376  -0.741
LOSS(MI 1.266  1.268  1.316  1.202  1.372  1.373       3.99  3.472
Moro. to Chabinze MW  26.374 26.482 29.625 29.697 33.287 33.155    66.327  58.82
MVAR   -6.364  -6.398  -7.339 -18.77 -8.313  -8.285    -7.652    -19
LOSS (M  0.566   0.57  0.716  0.872  0.906    0.9    3.543   3.02
Chalinze to Hale  MW   4.568  4.755 10.227   9.49 16.677 16.348    43.325 42.804
MVAR   -9.095  -9.169 -11.29  -31.16  -13.7 -13.58    -26.89  -22.25
LOSS (MI 0.072  0.076   0.26  1.233  0.628  0.605     4.376  3.766
Transformer Tap Possitions:
Morogoro         0.96   0.96   0.96   0.96   0.96   0.96       0.93   0.98
Ubungo           0.95   0.95   0.95   0.95   0.95   0.95      0.93   0.96
Mwanza             1       1      1      1      1      1         1      1
Fixed Capacitors I Reactors used:
bus no:
Tanga      11     10      10     10     10     10     10        10     10
RasKirom    12    -20    -20    -20    -20    -20    -20       -20    -20
Iringa     22    -10    -10    -10    -10    -10    -10          0      0
Muiindi    23    -15    -15    -15    -15    -15    -15        -10    -10
Dodoma     25    -40    -40    -40    -40    -40    -40        -30    -30
Singida    26    -30    -30    -30    -30    -30    -30        -20    -20
Shinyang.    27    -20    -20    -20    -20    -20    -20       -20    -20



-141-
POWER FLOW RESULTS - YEAR 1995, 1998 and 2001 MAXIMUM BUS LOADS
WITH SINGIDA-ARUSHA UNE
YrS9S-03M
System Details:  Double cct. lines Kidatu - Morogoro - Ubungo and 220 kV Singida - Arusha connection
1995           1998 max Loads               2001 Max Loads
Load Flow Run No:       5-C1Q    98-2D3 98-2D4 98-2S1 98-2S2        1-A2   1-A3   1-A4
TOTALPOWER INPUT        388.4     481.4  480.2  481.9  482.6       579.7  579.6  578.8
TOTAL LOAD              376.6     456.7  456.7  456.7  456.7       553.7  553.7  553.7
TOTALLINECHARGING       400.5     391.9  398.8  371.3  365.8       396.4  396.3  405.0
TOTALLOSS                11.9     24.36  23.15  28.09  29.19       26.18  26.15  25.21
Bus Voltages:
Bus no.
KIDATU              1  1.020      1.030  1.030  1.020  1.020       1.030   1.030   1.030
MOROGORO-HV         2  1.016      0.981  0.996  0.989  0.978       0.994  0.992   1.015
IBUNGO-HV           3  0.993      0.917  0.948  0.934  0.900       0.940  0.941   0.987
UBUNGO-LV           4  1.022      0.940  0.980  0.980  0.940       0.979  0.980   1.033
MOROGORO-LV         5  1.042      0.997  1.015  1.011  0.997       1.042   1.040   1.036
CHAUNZE             6  1.036      0.982  1.006  1.001  0.978       1.018   1.017  1.035
HALE                7  1.040      1.033  1.040  1.040  1.034       1.040  1.040  1.040
SAME                8  0.994       1.003   1.006  1.006   1.004    1.025   1.025  1.024
MOSH                9  0.982      0.993  0.994  0.995  0.993       1.021   1.021   1.020
ARLUSH-A           10  0.984       1.010  1.010  1.010  1.010      1.002   1.002  1.001
TANGA              11  1.019      0.988  0.995  0.995  0.988       0.990  0.990  0.990
RAS-KIRO           12  1.025      0.937  0.978  0.978  0.937       0.975  0.977  1.032
ZANZBAR            13  1.020      0.928  0.970  0.970  0.928       0.965  0.967  1.023
ILALA              14  1.004      0.928  0.969  0.969  0.928       0.966  0.968  1.021
RlUJVU             16  1.026      0.956  0.989  0.985  0.953       0.993  0.994  1.030
MTERA              21  1.020       1.030  1.030  1.020  1.020      1.020  1.020  1.020
IRNGA              22  1.021      1.040  1.040  1.030  1.030       1.034  1.034  1.034
MUIRNDI            23  1.013      1.033  1.033  1.022  1.022       1.025   1.025   1.025
MBEYA              24  1.017      1.033  1.033  1.021   1.021      1.022   1.022   1.022
DODOMA             25  0.994      1.003  1.004  0.994  0.994       0.994  0.994  0.994
SINGIDA            26  1.005       1.019  1.020   1.012  1.011     1.014  1.014  1.014
SHINYAN-HV         27  1.018       1.016  1.017  1.009  1.008      1.022  1.022  1.021
SHINYAN-LV         28  1.019       1.016  1.017  1.009  1.009      1.022  1.022  1.021
MWANZA-HV          29  1.025       1.017  1.018  1.010  1.010      1.021  1.020  1.020
MWANZA-LV          30  1.026       1.016  1.017  1.009  1.009      1.019  1.019  1.018
MUSOMIA            31  1.025       1.004  1.005  0.996  0.996      1.002  1.002  1.001
TABORA             32  1.025      1.017  1.018  1.010  1.009       1.021  1.021   1.020
ARUSHA-HV               0.974      1.015  1.015  1.014  1.013      1.009  1.009  1.008
Power Generation and variable var inputs:
KIDATU     MW           190.4    201.38 200.18 201.88 202.56    204.65 204.63 203.83
MWAR          -36.21    54.934 27.959 22.287 42.108    34.136 39.014  -3.655
LBULNSO    kW             30          0      0       0      0         47     47      47
MWAR             30    17.947 37.146 88.305 72.715           20     25      60
HALE       MW             80         50     50      50     50         80     80      80
MWAR          -12.79        25 21.552 22.152      25      7.405  7.509  3.269
MOSH       MW               8         0      0       0      0          8      8       8
MWAR              4          5      5       5      5         30     30     30
ARUSHA     MW               0         0      0       0      0          0      0       0
MWAR              0      7.602  6.436  8.448  9.444         -10    -10    -10
MTERA      MW             80         80     80      80     80         80     80      80
MWAR           -7.26    -12.01  -12.67  -11.64  -11.21   -14.79  -14.77  -14.76
IRANGA     MW              0        150    150    150    150         160    160    160
MWAR              0        -20    -20    -20    -20         -20    -20    -20
Diesels in   MW             0         0      0       0      0          0      0       0
East     MWAR               0         0      0       0      0          0      0       0



-142-
POWER FLOW RESULTS - YEAR 1995,1998 and 2001 MAXIMUM BUS LOADS
WITH SINGIDA-ARUSHA UNE
YrS95-03M
System Details:  Double cct. lines Kidatu - Morogoro - Ubungo and 220 kV Singida - Arusha connection
1995          1998 max Loads              2001 Max Loads
Load Flow Run No:     5-CdO    98-2D3 98-2D4 98-2S1 98-2S2      1-A2   1-A3   1-A4
Section Power flows:
NORTH-EAST            123.01    116.53 115.45 133.18 134.23    156.30 156.05 151.54
EAST                 137.70    175.38 176.47 159.13 157.95    215.30 215.46 219.82
KID-MOROUNE          144.09    246.23 246.03 246.31 246.29    240.51 240.45 240.09
EAST&NIEASTTOTAL    262.09    296.23 296.03 296.31 296.29    375.51 375.45 375.09
WEST                  117.81    174.95 173.95 175.37 176.07    191.85 191.88 191.44
SYSTEMTOTAL          388.40    481.38 480.18 481.88 482.56    579.65 579.63 578.83
Section Power Losses in MW:
NORTH-EASTinMW          3.87     4.56   4.21   6.38   6.77      5.71   5.69   5.44
EAST                   2.50      5.26   4.76   7.03   7.49      4.89   4.85   4.42
KIDMOROUNE              1.73     5.03   4.83   4.86   4.98      4.49   4.52   4.33
EAST&N/EASTTOTAL       8.10     14.85  13.81  18.27  19.24     15.10  15.06  14.19
WEST                    3.98      9.87   9.72  10.18  10.30    11.37  11.37  11.30
SYSTEM TOTAL           12.07     24.72  23.53  28.45  29.54    26.47  26.44  25.49
Section Power Losses in percent:
NORTH-EAST             0.031     0.039  0.036  0.048  0.050    0.037  0.036  0.036
EAST                  0.0 18    0.030  0.027  0.044  0.047     0.023  0.022  0.020
KID-MOROUNE           0.012     0.020  0.020  0.020  0.020     0.019  0.019  0.018
EAST&N/EASTTOTAL      0.031     0.050  0.047  0.062  0.065     0.040  0.040  0.038
WEST                   0.034     0.056  0.056  0.058  0.058    0.059  0.059  0.059
SYSTEM TOTAL           0.031     0.051  0.049  0.059  0.061    0.046  0.046  0.044
Power flows in main lines:
Kidatu to Moro.  MWV    144.09    246.23 246.03 246.31 246.29    240.51 240.45 240.09
MVAR   -22.59    56.753 29.501 23.432 43.446    32.764 37.651  -5.134
LOSS    1.378     4.312  4.087  4.139  4.275     3.933  3.965  3.761
Moro. to Ubungo MW     107.7   175.38 176.47 159.13 157.95     168.3 158.46 172.82
MVAR   -3.196    52.061 30.257 25.639 40.752    37.971 33.433  3.038
LOSS    1.085     3.509  3.188  4.991  5.285     3.017  2.986  2.764
Moro. to Chalinze  WN    14.786    42.035 40.968 58.682 59.794    38.859 38.606 34.103
MVAR   -5.147    -10.58  .13.44 -18.38 -14.66    -4.615  -5.531  -15.21
LOSS    0.181     1.595  1.511  3.124  3.237     1.201  1.195   1.07
Chalinze to Hale  MW  -15.14     8.83  9.533    6.4  5.578     1.657  1.625  2.193
MVAR    1.555    -19.59 -16.32 -16.21  -19.16    -10.61  -10.7 -6.733
LOSS    0.459     0.604  0.425  0.336  0.494     0.072  0.074  0.016
SingidatoArusha MW   67.645    115.76 114.74 116.36 117.06    122.79 122.83 122.37
MVAR    3.499    -0.014 -0.486  -0.63  -0.332    -0.489  -0.474 -0.391
LOSS    0.984     2.747  2.698  2.827  2.862     3.147  3.149  3.125
Transtorner Tap Possitions:
Morogoro        0.97      0.98   0.98   0.98   0.98      0.95   0.95   0.98
Ubungo          0.96      0.95   0.95   0.95   0.95      0.95   0.95   0.95
Mwanza             1         1      1      1      1         1      1      1
Arusha           0.98        1      1      1      1         0      0      0
Fixed Capacitors / Reactors used:
RasKirorn    12   -20      -20    -20    -20   -20        -20    -20    -20
Iringa     22    -10         0      0      0      0         0      0      0
Muiindi    23    -15       -10    -10    -10   -10        -10    -10    -10
Mbeya      24      0         0      0      0      0         0      0      0
Dodoma     25    -40       -30    -30    -30   -30        -30    -30    -30
Singida    26    -30       -20    -20    -20   -20        -20    -20    -20
Shinyang    27    -20      -20    -20    -20   -20        -10    -10    -10



ANNEX C
ECONOMIC EVALUATION OF REACTIVE COMPENSATION REQUIREMENTS
FOR THE TRANSMISSION AND DISTRIBUTION SYSTEMS



I



-145-
Annex C
ECONOMIC EVALUATION OF REACTIVE COMPENSATION REQUIREMENTS
FOR THE TRANSMISSION AND DISTRIBUTION SYSTEMS
List of Tables
C.1.1        Cost of power supply using small diesel generators
C.1.2        Average incremental cost by voltage level
C.2          Loss reduction and benefit to cost ratio by installation of a reactor at Ras Kiromany
C.3          Loss reduction and benefit to cost ratio by installation of a capacitor at Tanga
cement factory
C.4          Costs of variable static var compensating systems (SVS)
C.5.1        Loss reduction by use of capacitors at Dar es Salaam
C.5.2        Benefit to cost analysis of switched capacitor banks at Dar es Salaam
C.6          Benefit to cost analysis of installing a SVS system at Arusha
C.7.1        Unit cost of medium voltage capacitors and associated equipment
C.7.2        Costs of unswitched capacitor banks on overhead lines
C.7.3        Costs of switched capacitor banks on overhead lines
C.8.A        Capacitor applications: loss reduction benefits on existing 11 kV systems
C.8.B        Capacitor applications: loss reduction benefits on 11 kV lines after network
rearrangement
C.9          Capacitor applications: loss reduction benefits on 33 kV lines
C.10         Loss reduction on Ubungu-Ilala 132 kV line and total system by down stream
capacitor applications
C. 11        Economic analysis of selected capacitor applications on 11 kV lines
C.12         Economic analysis of capacitor applications at 33/11 kV substations and consumer
installations.



I



Table C. 1 .1
-147-
Printed 02/28/92
COST OF POWER SUPPLY
FROM SMALL DIESEL PLANTS
Discount Rate 12%               Discount Rate 10%
Plant     Plant      Plant      Plant     Plant     Plcnt
factor    factor     factor    factor    factor    factor
25%      12 %        6 %        25%      12 %       6 %
Investment Cost US$ Million                         1.6       1.6         1.6       1.6        1.6       1.6
Capacity MW                                           2         2           2         2         2          2
Energy MWh/year                                   4380      2102        1051       4380      2102      1051
Plant Factor                                       0.25      0.12        0.06      0.25      0.12       0.06
Plant Capacity Cost USS/kW                         800        800        800        800       800       800
PW of Annuity Factor 10 years                      5.65      5.65        5.65      6.14      6.14       6.14
Discount Rate                                       12%        12%        127        10%       10%       10%
Fuel Cost (diesel oil) US3/kWh                     0.05      0.05        0.05      0.05      0.05       0.05
O&M Cost of Diiselplant US$/kWh                   0.007     0.007      0.007      0.007     0.007      0.007
Fixed Maintenance Cost US$/kW/year                  7.1       7.1         7.1       7.1        7.1       7.1
PW of Energy Benefits MWh                        24748      11879       5940    26913       12918      6459
PW Fuel Cost US$ Million                           1.24      0.59        0.30      1.35      0.65       0.32
PW O&M Cost US$ Million                            0.17      0.08        0.04      0.18      0.09       0.04
PW Fixed Maintenance Cost US$ Million              0.08      0.08        0.08      0.09      0.09       0.09
PW Total Cost USS Million                          3.09      2.35        2.02      3.22      2.42       2.05
Total Cost USS/kWh                                 0.12      0.20        0.34      0.12       0.19      0.32
Total Cost Adjusted for 4 % station use US$/kWh    0.13      0.21        0.35      0.12       0.20      0.33



Table C.1.2
(page 1)
Printed 02/26/92                                      -148-
ESTIMATED AVERAGE INCREMENTAL COST BY VOLTAGE LEVEL IN 1989 AND 1991 USS.
PLANNING PERIOD 1990-2015
Discount Rate
12%          10%
PV Generation investment                             US$ Million                    453           535
PV Hydro generation O&M                                     "                          8            11
PV Diesel operating+fuel+fixed maintenance                  "                         13            14
PV Energy benefits without genr losses               GWh                           8249         10714
AIC AT GENERATION LEVEL US$/kWh                                                  0.057         0.052
PV Transmission investment + 2 % O&M                 USS Million                    112            131
PV Energy benefits without genr and trans losses     GWh                           7849         10192
AIC AT TRANSMISSION LEVEL US$/kWh                                                0.072         0.065
PV Distribution investment + 1,5 % O&M               US$ Million                    171            193
PV Energy benefits without total losses              GWh                           7420          9643
AIC AT DISTRIBUTION LEVEL in 1989 US$/kWh                                        0.095         0.085
AIC converted to 1991 US$/kWh
AIC at Generation Level                                                          0.063         0.058
AiC at Transmission Level                                                        0.079         0.072
AIC at Distribution Level                                                        0.104         0.094
Note: Calculations are based on "Investment Program", TANESCO, March 1990 and the Lecst Cost Hydroelectric Development
Plcn prepared by Acres International Ltd. for TANESCO in July 1989 "Review of Power Sector Development Program".
Detoils of the investment portfolio cre presented in Annex II.



Table C. 1.2
-149--                                 (page 2)
TANESCO'S INVESTMENT PROGRAM
by year of commissioning of investment
Year         Generation                       Transmission                     Distribution
1990         Diesei Rehabilitation
1991                                                                          Mbeya/Mufindi
1992         New Diesel                      Transmission Rehab.
1993         Ubungo Gas Turb. Rehabilitation    Reactive Compensation         Rural Electrific.
Kidatu/Morogoro II cct
1994                                          Morogoro/Dar es Saloam II cct.
1995         Pongani Redevel.                 Pangani
1996                                          Singida/Arusha                  Major Distr. I
1997         Kihansi I                        Kihcnsi
199B
1999         Kihonsi Il/Retire Diesel
2000                                                                           Future Distribution
2001
2002         Masigira                         Masigira
2003
2004
2005         Rumakoli/Retire Diesel           Rumakali
2006                                                                           Future Distribution
2007         Retire Diesel                    Future Transmission
2008
2009         Ruhudj                           Ruhudj
2010
2011                                                                           Future Distribution
2012         Mpcnga                           Mpanga
2013
2014
2015
In addition, TANESCO's expenditure on local distribution expansion works incurred annually are counted for.
Investments outside the interconnected grid not included
Source: "Investment Program" Tonesco March 1990 and
"Review of 1985 Power Sector Development Plan" Tonesco and Acres International Ltd. July 19B9
The need for investments for "Future Transmission" and "Future Distribution" estimated by ESMAP.



-150-
TABLE C.2
LOSS SAVINGS BY INSTALLING A REACTOR AT RASKIROMANY
Reactor used at Ras Kiromany
No React.    10 MVAr  20 MVAr
Peak Line Losses in MW
Ubungo to Ras Kiromani            0.47       0.23       0.08
Loss Savings MW                               0.24        0.39
Loss load factor of savings                       1          1
Annual savings GWH                           2.102       3.416
Value of savings /yr. $ O00's                  210         342
Present worth of loss savings
in S OOO's              1598       2596
Cost of reactor installation S OOO's
Reactor transport and labour                    5           2
Isolator, struct. etc.                          5           5
Additioncl cost for equivalent
capacitor SOO's                               60        120
Total cost$ 000's                                70        127
BENEFIT/COST ratio                               23         20
Pay back period in months                       4.0        4.5
Note:
0.1 = energy costs in $/ kWh
7.6 = Present worth factor (calculated at 10% interest
and for 15 years of benefits)
6 = cost in S/kVAr for equivalent capacitor



-151-                             TABLE C3
LOSS SAVINGS BY CAPACITOR INSTALLATION AT TANGA CEMENT FACTORY
1990 - 1992            1993 onwards
PEAK LOSS SAVINGS (kW)
132 kV Hole Tango line                                          58                     100
33 kV line at Tanga                                             75                     120
Total peak loss Savings kW                                        133                     220
Loss Reduction Load Factor                                         0.7                    0.7
Annual lass savings kWH                                       815556                 13A9.040
Value of savings /yr. $ 000's                                  81.556                 134.904
Present worth of loss savings $ 000's from 1992                               750
COST OF CAPACITOR INSTALLATION (2 X 4 MVAR)
Capacitor banks in $ 000s                                                    28
Switchgear cost in $ 000s                                                     8
Total cost in $ 000s                                                         36
BENEFIT/COST ratio                          21
PAY BACK PERIOD                            5.3  Months
Note:
3.5 = Capacitor cost used in $/kVAR
The loading in 1993 is expected to increase due to the removal of the existing constraints.
The present worth of loss ieduction has been worked out with one year (1992) at
the existing load and thereafter at the new expected load.
The present worth factor used for the streem of losses after 1993 is 6.



-152-
TABLE C 4
COSTS OF VARIABLE STATIC VAR COMPENSATING SYSTEMS ATGRID SUBSTATIONS
MVAR     MVAR      MVAR
Rabing of Installabon                         20        30        55
ESTIMATED PRPCES OF COMPONENTS                              COST IN US $ OODs
Thyristor controlled reactor
with control and protection systems                   1900      2350      3475
Capadtor banks, at         5 Sper KVAR                 100       150       275
Step down transformer                                  350       350       550
Civil works and miscellaneous costs                    150       175       200
Switchgear Cost in US $ 000s
132 kV breaker and associated equipnient    300
11 kV breaker and associated equipment       75
Additional cost for insurance, freight and installal  25 %
as % of base costs
COST OF COMBINED UNIT WITH STEP DOWN TRANSFORMER
TOTAL COST OF SVS UNIT IN US $ 000s
No. of switched capacitor banks
(no. of circuit breakers)
0                         3594      4250      6094
2                         3781     4438       6281
3                         3875      4531      6375
4                         3969      4625      6469
5                         4063      4719      6563
COST OF COMBINED UNIT WITHOUT STEP DOWN TRANSFORMER
TOTAL COST OF SVS UNIT IN US $ DOs
No. of switched capacitor banks
(no. of circuit breakers)
0                         2781      3438      5031
2                         2969      3625      5219
3                         3063      3719      5313
4                         3156      3813      5406
5                         3250      3906      5500



Table C.5.1
-153-
LSS$AVWGS BY USE Of CAPACMS AT UWJNGOI LLA
Lo.s s*s by 30 MVAr ocnipenSbion         Los svings by -ML 15 MVAr corrpenataofn
bW      K994        PV        PV      kw        KWH        PV        PV
m       s 000                         4mi    5 000
1993MAX       1.90       333                          0.22       39
1993AP1       2.25      2562                          0.45      512
*1993AP2         2.0S     3609                          0.50      878
1993AM1          0         0                            0         0
1993AM2          0         0                            0         0
TOTAL 1993              6504      S375      536                1427      1179       116
Ton wthoutA             2895      2393      239                 551       455        46
1994AiAX      0.89       156                            0         0
1994AP1        1.90     2164                          0.22      251
'1994AP2         2.25     3942                          0.45      766
1994AM1       2.06      1605                          0.45      394
1994AM2          0         0                            0         0
TOTAL 1994              606S      6060      606                1433      1077       106
Tot wihut'              2320      1743       174                251       1S6        19
9951MAX       0.41        72                            0         0
1995AP1       0.54       61S                          0.07       60
1995AP2       0.82      1437                            0         0
1995AMI       0.41       359                            0         0
1995AM2       0.32       561                            0         0
TOTAL 1995              3043      2079      208                  so        54         g
1996MAX          0         0                            0         0
1996AP1       0.41       467                            0         0
i996AP2        0.54      946                          0.07      123
1996AMI       0.82       718                            0         0
1996AM2       0.41       718                            0         0
TOTAL 1996              2850      1769      177                 123        76         a
1997MAX          0         0                            0         0
1997AP1          0         0                            0         0
1907AP2        0.41      716                            0         0
1997AMI       0.54       473                          0.07       61
1997AM2       0.82      1437                            0         0
TOTAL 1997              2626      1483      148                  61        35         3
TOTALLORE=TION BENEFFITS
1993 TO END 1997 (OWs)                     1677                                    242
BENEFITICOST RATIO Boss rducion only)        8.8                                    2.5
Overall bmneftloost ratio for 45  MVAr                          6.7
Loss redun benefis oxcljding period
1993 API&2 and 1994 APItAMI (set note 5)    947                                     61
Benrefit I Cost atio (addf. k redurtion)     5.0                                    0.9
Overat bweftCot  raio for 45  MVAr                              3.6
Notes to romputations:
(1) Detitil of load dwartion crv:               (2) Irtrest rate in %    10.0
p.u. time   period
0.02  MAX                        (3) Enrgyot:
0.13  API                                     S I kWH      0.1
0.2  AP2
0.1  AtI                        (4) Net PV of capector itallaton
0.2  AU2                                               S 0005
0.3  BASE                                    30 KVA     190.0
0.05  LB                                   d 15 KVA       95.0
(s  Table 87)
(S  in the prriods 1993 APi aid AP2 anrd 1994 AP2 and AtI the swt voltge awe too
bow bo be supported wthoLA camp citors. The equivalcnt generation reqrsd at UbungO
i 10ndSMWrepspecsly. N tho btmtofing this    mtion i rsound (Ta)
the benetis of ls reduction tor these periods must not be counted again.



Table C.5-2.
-154-
BENEFrr/COST ANALYSE OF SWITCHED CAPACiTORS AT UBUNGO
Value of generation saved at Ubungo                     Value of saving of outages
by using 30 MVAr of capacitors                          by using 30 MVAr of capacitors
Year      VW    Tirne      MWh    Value       PiV       MW      MWh    Value         PV
avoided     p.u.   saved  inS000    $000    saved    saved    $000    $000
1993       10      0.33   28908    2891       2389        30      360      360       298
1994       10      0.30   26280    2628    1974           30      360      360       270
1995                                                      30      360      360       246
1996                                                      35      420      420      261
1997                                                      40      480      480      271
Total NPV of savings $ O00's   4364                                  1346
For 30 MVAr       NPV of benefits: saved generabon and avoided outages (in $000):      5709
InstallaSon       Benefit I cost ratio for saved generation and avioded outages         30.1
Additbonal benefits from loss reducbon benefits (see TabieC54) in $ 000's  1677
Total savings: saved generabon, avoided outages and loss reducton    7386
Benefit I cost ratio counting al related benefits                    39.0
For additonal     Estimated benefits of saved generation and avoided outages in $ 000's
15 MVAr installation                 at 10% of saving for 30 MVAr installation           571
Benefit / cost ratio for saved generabon and avioded outages           6.0
Additonal benefits from loss reduction benefts (see TableC6'i) in $ 000's  242
Benefit / cost rato counting all related benefits                      8.6
For toial instaliation
of 45 MVAr        Benefit I cost ratio for saved generation and avioded outages         22.1
Benefit / cost ratio counting ail related benefits                    28.8
Computabon of Pay back period:
Benefits of year 1993 (considering only a 30 MVAr applicabon)        3251
Cost of tot^i installation (45 MVA,) at 1991 prices                   825
Pay back period (months)                                               3.0
COST OF CAPACITOR INSTALLAT1ON
Unit    Rate      Oty.     Cost Addl Otry Addi cost
$000              $0O0               $000
Cost of capacitors    MVAr         5       30       150       15       75
Circuit breakers       Nos.      150        2      300         1      150
Misc. works            Item                         25                 25
Contngencies                                         75                25
Total Cost                                         550                275
PV of cost (incured in 1992)                       500                250
PV for installabon in 1998 (cost in 1987)          310                155
PV of net cost of proposal                          190                95
Notes:
10 . Interest rate in %
0.1 * Value of generation saved in $1kW
1 = Value of saved outages in $/kW
3 = Hrs. per outage
4 . No. of outages per year



-155-
BENEFT I COST ANALYSIS OF NiSTALLIG REACTIVE COMPENSATION AT ARUSHA       TABLE C 6
Year                               1992      1993      1994      1995       1996      1997      1998
Expected load at Moshi MW           19.1      20.3      21.7      23.1      24.6      26.2       27.9
Expected load at Arusha MW          21.4      22.8      24.3      25.9      27.5      29.3       31.2
Total load in MW                    40.5      43.1      45.9      48.9      52.1       55.5      59.1
Expected energy sales
in GWh (av. I of 0.65)            230.6    245.6    261.6    278.6    296.7    316.0            336.5
Sales possible with no
addiional compensabon. GWh         159.4    159.4      159.4    182.2    182.2        182.2     182.2
AdditonalsalesinGWh                 71.2      86.2    102.1       96.4     114.5    133.7       154.3
Value of addl. sales, MS             7.1       8.6      10.2       9.6      11.4       13.4      15.4
PVofaddl.sales, MS                             7.1       7.7       6.6       7.1        7.5       7.9
SVS INSTALLATION                         SWITCHED CAPACITORS
NPV of      B/C        B/C              NPV of       B/C           Singida - Arusha
Benefits:   ratio I    ratio 2          Benefits:     ratio         lne comnissioning in
see Note 3
With commissioning of proposal in 1993 (begining):
NPV 1993 - 1994 in MS    14.8        3.3       5.5                 7.4       6.6                1994 end
NPV 1993 - 1995 in M$    21.4        4.7       7.5                10.7       9.6                1995 end
NPV 1993 - 1996 in MS    28.5        6.3       9.5                14.2      12.8                1996 end
NPV 1993 - 1997 in MS    36.0        7.9      11.5                18.0      16.2                1997 end
Pay back in months        8.4                                      1.9
With commissioning of proposal in 1994 (begining):
NPV 1994 - 1994 in MS      7.7       1.7       2.9                 3.8       3.4                1994 end
NPV 1994 - 1995 in MS    14.3        3.1       5.0                 7.1       6.4                1995 end
NPV 1994 - 1996 in MS    21.4        4.7       7.1                10.7       9.6                1996 end
NPV 1994 - 1997 in MS    28.9        6.4       9.2                14.5      13.0                1997 end
Pay back in months         7.8                                     1.7
Notes:
1. Load supported with existing capacitors at Moshi & Arusha  5. COST OF SVS 0 TO 30 MVAR (see Table C5):
with Hale voltage at max. and firm generation at Moshi is 28 MW               Cost of SVS unit (1992) MS            5.0
with present generation, and 32 MW with New Pangani (1995)                    Cost discounted to 1991              4.5
2  Value of addi. sales for fully acceptable                 5. COST OF 6 X 5 MVA SWITCHED CAPAC7TOR BANKS:
technical soluton, ie. SVS S/kW1  0.1                                               Unit      Rate      Oty.       Cost
for switched cap.  S/kWh        0.05                                                         S000                 $000
Cost of capacitors       MVAr          5        30       150
3. B/C calculabon 1 is made without any rebate for the value of  Circuit breakers      Nos.      150          6       900
the SVS unit at the commissioning of the Singida - Arusha rIne  Control cct. A misc.  Item                         100
B/C calculation 2 is made with a rebate of half the value of  Contngencies                                          75
the SVS at the tire of consaucton of the new line.       Total Cost                                               1225
4. Interest rate in %                1 0                     PV of cost (incured in 1992)                            1114



-156-
TABLE C.7.1
UNIT COST OF MEDIUM VOLTAGE CAPACITORS AND ASSOCIATED EQUIPMENT
TO BE INSTALLED ON DISTRIBUTORS
COST F.OB in $ 000 's         Capacitor cost
1 1kV     33kV              in $ per KVAR
CAPACITOR BANK
THREE-PH.        50 kVAR            1.20      1.20                24.0
THREE-PH        100 kVAR            1.20      1.20                 12.0
THREE-PH        150 kVAR            1.20      1.20                  8.0
THREE-PH        200 kVAR            1.35      1.35                  6.8
THREE-PH        250 kVAR            1.40      1.40                 5.6
THREE-PH        300 kVAR            1.43      1.43                  4.8
THREE-PH        400 kVAR            1.55      1.55                  3.9
THREE-PH        500 kVAR            1.70      1.70                  3.4
THREE-PH        600 kVAR            1.90      1.90                  3.2
FUSED CUTOUT                       0.20       0.50
MV OIL SWITCH                       1.35      4.85
SURGE ARRESTERS                    0.16       0.68
POWER TF./CONT. UNIT               0.80       1.25
Local Transport & Installafion
Unswitched banks                   0.50       0.50
Switched 6anks                     0.60       0.60
Note:
The above unit costs have been used for the computation
of the cost of capacitor banks to be used on 11 and 33 kV networks.
(See Tables C ZR and C..75)



-157-
TABLE C 7.2
COST OF UNSWlTCiED CAPACITOR BANKS AT 1 I W, POLE MOUNTED
RATING 3 PHASE in KVAR            50       100      150       200      250       300      400       500      600
Installed Cost in S 000's
CAPACITOR                         1.2      1.2       1.2     1.35       1.4     1.43      1.55       1.7      1.9
FUSED CUTOUT                      0.2      0.2       0.2      0.2       0.2      0.2       0.2      0.2       0.2
SURGE ARRESTORS                  0.16     0.16      0.16     0.16      0.16     0.16      0.16     0.16      0.16
TOTAL FOB                        1.56      1.56     1.56      1.71     1.76      1.79     1.91      2.06     2.26
FREIGHT & INS. (at 15% FOB)      0.23     0.23      0.23     0.26      0.26     0.27      0.29      0.31     0.34
L TRANS. & INSTALATION           0.50     0.50      0.50     0.50      0.50     0.50      0.50      0.50     0.50
TOTAL COST                       2.29     2.29      2.29     2.47      2.52     2.56      2.70      2.87     3.10
Cost per KVAR in S per KVAR
FOB                            31.20     15.60    10.40      8.55     7.04      5.97     4.78      4.12      3.77
Installed                      45.88     22.94    15.29     12.33    10.10      8.53     6.74      5.74     5.17
COST Of UNSW1TCiED CAPACITOR BANKS AT 33kV, POLE MOUNTED.
RATING 3 PHASE in KVAR            50       100       150      200      250       300       400      500       600
Installed Cost in S 000's
CAPACITOR                        1.20      1.20     1.20      1.35     1.40      1.43    .1.55      1.70     1.90
FUSED CUTOUT                     0.50      0.50     0.50     0.50      0.50      0.50     0.50      0.50     0.50
SURGE ARRESTORS                  0.68      0.68     0.68     0.68      0.68      0.68     0.68      0.68     0.68
TOTAL FOB                        2.38      2.38     2.38     2.53      2.58      2.61     2.73      2.88     3.08
FREIGliT & INS. (at 15% FOB)     0.36      0.36     0.36     0.38      0.39     0.39      0.41      0.43     0.46
L TRANS. & INSTAIATION           0.50     0.50      0.50     0.50      0.50     0.50      0.50      0.50     0.50
TOTAL COST                       3.24      3.24     3.24     3.41      3.47      3.50     3.64      3.81     4.04
Cost per KVAR in S per KVAR
FOB                            47.60     23.80     15.87    12.65    10.32      8.70     6.83      5.76      5.13
Installed                      64.74     32.37    21.58     17.05    13.87     11.67     9.10      7.62      6.74



-158-
TABIE C7.3
COST OF SWITCHED CAPACITOR BANKS AT 1 IkV, POLE MOUNTED
RATING 3 PHASE in KVAR             50      100       150      200       250       300      400       500      600
Installed Cost in S 000's
CAPACITOR                        1.20      1.20     1.20      1.35      1.40     1.43      1.55     1.70      1.90
OIL SWITCH                       1.35      1.35     1.35      1.35      1.35     1.35      1.35     1.35      1.35
SURGE ARRESTORS                  0.16      0.16     0.16      0.16     0.16      0.16      0.16     0.16      0.16
TOTAL FOB                        2.71      2.71     2.71      2.86      2.91     2.94      3.06     3.21      3.41
FREIGHT & INS. (at 15% FOB)      0.41      0.41     0.41      0.43     0.44      0.44      0.46     0.48      0.51
L TRANS. & INSTALATION           0.50      0.50     0.50      0.50      0.50     0.50      0.50     0.50      0.50
TOTAL COST                       3.62      3.62     3.62      3.79     3.85      3.88      4.02     4.19      4.42
Cast per KVAR in S per KVAR
FOB                             54.20    27.10     18.07    14.30     11.64      9.80     7.65      6.42     5.68
Insralled                       72.33    36.17    24.11     18.95     15.39     12.94    10.05      8.38     7.37
COST OF SWITCHED CAPACITOR BANKS AT 33kV, POLE MOUNTED.
RATING 3 PHASE in KVAR             50      100       150      200       250       300      400       500      600
Installed Cost in S 000's
CAPACTOR                          1.2       1.2      1.2      1.35       1.4     1.43      1.55       1.7      1.9
OIL SWITCH                       4.85      4.85     4.85      4.85      4.85.    4.85      4.85     4.85      4.85
SURGE ARRESTERS                  0.68      0.68     0.68      0.68      0.68     0.68      0.68     0.68      0.68
TOTAL FOB                        6.73      6.73     6.73      6.88     6.93      6.96      7.08     7.23      7.43
FREIGHT & INS. (at 15% FOB)      1.01      1.01     1.01      1.03      1.04     1.04      1.06     1.08      1.11
L TRANS. & INSTAIATION           0.60      0.60     0.60      0.60     0.60      0.60      0.60     0.60      0.60
TOTAL COST                       8.34      8.34     8.34      8.51      8.57     8.60      8.74     8.91      9.14
Cost per KVAR in S per KVAR
FOB                            134.60    67.30    44.87     34.40     27.72    23.20     17.70     14.46    12.38
Installed                      166.79    83.40    55.60     42.56     34.28    28.68     21.86     17.83    15.24



CAPACITOR APPLICATIONS
LOSS REDUCTION BENEFITS ON EXISTING 11 KV SYSTEMS
LOSS SAVINGS IN MW'9                  '1
Feeder CIdPF  CdPF   OldPF  Peak   Day   Base    Capacit 1991   1995   1991   1995   1991   1995  UnIlts  Units  Annual
FGIIR              Length Peak   Cos 6  Cos 6  Cos 6  NewPF  NewPF  NewPF  applied night   night  day    day   base   base Saved  Saved  % Inc.  LWLF LRLF
NAME               (km)  Amps  Peak   Day    Base   Cos6  Cos6  Cos6    (kVA)                                               MWh   MWh   savings 1991 1995
U1. Kisiwani           9.0   175   0.94   0.82   0.94   0.99   0.95   1.00   600    9.9   16.2   10.0   16.3    3.2    6.3    57    99         15 0.66 0.70
U2,Menzese             8.4   146   0.90   0.87   0.90   0.97   0.98   1.00   600   10.0   12.9   7.1    9.4    3.4    4.8    50    67           8 0.57 0.60
U7, Factory            3.9    75   0.93   0.90   0.93   1.00   1.00   0.89   600    1.2   2.6    1.4    2.9   -0.2   0.5         5      16    32 0.48 0.64
K4, INDUSTRIAL         9.5   185   0.91   0.83   0.91   0.97   0.91   1.00   600   25.7   32.9   41.7   52.3    9.1   12.7   199   256          7 0.88 0.89
K3, KILWA RD           8.5   231   0.91   0.85   0.91   0.96   0.94   0.99   600    8.5   10.7    6.3    8.0    3.4    4.5    46        59      7 0.61 0.63
PORT                   4.3   157   0.96   0.86   0.96   1.00   0.94   0.98   600    5.2   9.5   15.7  24.8    0.7    2.8    56         99      15 1.23 1.19
01, Azamia             5.5   250   0.93   0.96   0.93   0.99   0.99   0.99   600    3.9    4.8    7.4    8.9    0.9    1.3    31       39       6 0.91 0.92
D2, Town 1            6.1   190   0.93   0.83   0.93   1.00   0.90   0.98   600    3.8    5.5   13.7   18.1    0.7    1.5    48        68       9 1.47 1.41
D3, Kurasini           2.8   180   0.91   0.90   0.91   0.97   0.97   1.00   600    4.2    5.0    3.3    4.0    1.5    1.9    22       28       5 0.62 0.63
D9, Town 2            2.5   300   0.93   0.96   0.93   0.96   0.99   0.99   600    6.0    8.4    2.9    4.2    2.5    3.7    28        41      10 0.53 0.55
D10, Magomeni          6.5   230   0.93   0.96   0.93   0.98   0.99   1.00   600    9.3   11.9   7.9   10.2    3.4    4.7    52    68           7 0.63 0.65
C3, City Center 1      1.2   240   0.93   0.96   0.93   0.99   0.99   0.99   600    0.9    1.3    1.5   2.1    0.2    0.4        7      10    10 0.84 0.86
C4, City Center 2      2.2   270   0.93   0.96   0.93   0.99   0.99   1.00   600   ,2.0    2.8   3.3    4.5    0.6    1.0    15    21           9 0.86 0.87
C5,MnaziMnela1         1.4   195   0.93   0.96   0.93   0.98   1.00   1.00   600    2.0    2.7    1.0    1.4   0.7    1.1        9      13      9 0.51 0.54
CS, Mnazi Mneja 2      1.8   118   0.96   0.96   0.96   1.00   1.00   0.97   600    0.8    1.1    0.5    0.8    0.0    0.2       3       5     14 0.43 0.51    H
C8,Tanesco             1.4   226   0.93   0.96   0.93   0.97   0.99   1.00   600    2.4    3.3    1.5   2.1    0.9    1.3    12    17           9 0.56 0.58
MK1,Msasanl            8.2   155   0.93   0.90   0.98   0.98   0,98   0.98   600    8.5   11.7   7.2   10.0   *0.1    0.8    33         50     11 0.45 -0.49
MK2,Tandale           10.8   190   0.91   0.83   0.91   0.96   0.92   1.00   600   17.1   27.2   20.0   31.5    6.4   11.4   112    182        13 0.74 0.76
MK3. Lugalo            4.8    80   0.90   0.87   0.90   1.00   0.98   0.93   600    2.3    3.0    1.0    1.4    0.2    0.5       7      11    11 0.35 0.42
MK4, north east        4.5   174   0.98   0.90   0.98   1.00   0.98   0.99   600    2.1    3.2    4.6    6.4    0.2    0.7    17    27    11 0.93 0.94
02, Mwenge             4.2   135   0.98   0.90   0.98   1.00   1.00   0.96   600    1.2    1.6   2.2    2.9   *0.2               7      11     10 0.70 0.74
03, Packers            9.6   296   0.98  KO.90   0.98   1.00   0.95   1.00   600   10.4   13.5   17.6  22.2    3.3    4.9    81    106          7 0.89 0.89
04, Kinondoni          2.8   177   0.90   0.81   0.90   0.96   0.92   1.00   600   24.1   30.6   24.3  30.9    8.9   12.2   145    189          7 0.69 0.70
05,Seaview             3.6   115   0.92   0.91   0.92   0.99   1.00   0.99   600    2.6    3.0    1.9    2.3    0.6    0.8    12        15      5 0.53 0.55
06, Oyster bay         4.3   120   0.93   0.90   0.93   0.99   1.00   0.99   600    3.0    3.8    2.4    3.1    0.7    1.1    14        19      7 0.54 0.57
KUNDLUCHI             13.5   180   0.93   0.79   0.93   0.98   0.91   1.00   600   35.9   64.8   44.4   78.4   12.3   26.8   236   441         17 0.75 0.78
LUGALO                7.0   150   0.92   0.90   0.92   0.98   0.99   1.00   600    7.5    8.6   5.1    6.0    2.4    2.9    36         43       4 0.55 0.57
F5,EBUGURUNI          3.2   110   0.71   0.85   0.71   0.94   0.96   0.96   600    2.7    3.3    3.4    4.1    0.7    1.0    17    21          6 0.72 0.74
F2,RTD                2.5   170   0.71   0.85   0.71   0.81   0.97   0.91    600    6.5    8.6    2.4    3.3    2.8    3.8    29       39      8 0.50 0.52
UKONGA                 5.0    60   0.89   0.90   0.89   1.00   0.96   0.83   600    3.1    4.2    1.0    1,9   *0.5    0.0       5      12    23 0.19 0.32
F31,INDUSTRIAL        2.6   195   0.71   0.85   0.71   0.80   0.92   0.89   600    7.6    9.4    5.7   7.1    3.3    4.2    42         53       6 0.63 0.64
F33.AIRWING           2.3    75   0.79   0.78   0.79   0.98   0.97   0.93   600    1.5    1.6    1.8    1.9    0.3    0.3        9      9      2 0.67 0.68
F34, KIWALANI         5.8   100   0.91   0.85   0.91   1.00   0.97   0.88   600    1.9   3.1    5.4    7.5   *0.2    0.4    18    28           12 1.05 1.04
FEEDER1               10.0    75   0.89   0.90   0.89   1.00   0.96   0.92   600    9,8   15.9   2.0    5.6    0.7    3.8    23        56     24 0.27 0.40
FEEDER2               6.0    84   0.89   0.90   0.89   1.00   0.98   0.95   600    7.2   11.3    2.0    4.3    1.1    3.1    21        43    20 0.33 0.43    ..
CD
00



CAPACITOR APPLICATIONS LOSS REDUCTION BENEFITS ON 11 KV LINES
AFTER NETWORK REARRANGEMENT
New   O d                                                   LOSS SAVINGS IN MW           ' 9    '    Growth
New   Old  Feeder Feeder    NIGHT       DAY        BASE   Capacil 1991  1995  1991  1995  1991  1995 Units  Units rate of  1991  1995
FEEDER             Length Length PeJ  Poa  CfldPF NewPF OIdPF NewPF OIdPF. NewPF appi1ed Night  Night   Oay  Day  Base Base Save4d Saved loss red/lLFLF  LFLF
NAME                (km)  (km) Amps Amps Cos6 Cos6 Cos6 Cos6 Cos6 Cos6  (kVA)                                            MWih  MWh  p.a.
Ul,<Klsjwani         8.98  8.98  167   175  0.94  0.99  0.82  0.95  0.94  1.00  600   9.9  16.2  10.0  16.3  3.2  6.3   57    99   14.6  0.66  0.70
U2,Menzeso           3.30  8.36   75   146  0.90  1.00  0.87  1.00   0.9  0.94  600   1.7   2.3   1.0   1.5  0.2  0.5        6    10   12.6  0.43  0.60
U7, Factory          3.91  3.91   70    75  0.93  1.00  0.90  1.00  0.93  0.89  600   1.2  2.6   1.4  2.9  -0.2  0.5         5    15   32.1  0.48  0.64
K4, INDUSTRIAL       4.20  9.52   53   185  0,91  0.99  0.83  1.00  0.91  0.62  600   1.7  2.7   4.1   5.7  -1.6  -1.2       7    15   19.7  0.51  0.64
K3. KILWARD          5.70  8.50  105  231  0.91  0.99  0.85 - 1.00  0.91  0.99  600   2.2   3.0   1.5  2.1   0.6  0.9   10    14    9.3  0.52  0.56
PORT                 2.20  4.32  116   157  0.96  1.00  0.86  0.95  0.96  0.97  600   2.2   4.2  7.1  11.3  0.1   1.1   25    44   15.7  1.25  1.20
D0, Brewery          0.30  0.30   84   90  0.93  1.00  0.96  0.99  0.93  0.94  600   0.1  0.2   0.0  0.1   0.0   0.0         0     1   16.2  0.32  0.42
Di, Azamia           1.70  5.45  103  250  0.93  1.00  0.96  0.99  0.93  0.98  600   1.1   1.3  2.1   2.5  0.2   0.3         8    11    6.2  0.91  0.92
D2, Town 1           2,90  6.05  221   190  0.93  0.97  0.83  0.89  0.93  0.99  600   5.0   6.7   9.3  12.1   1.9  2.8   43    57    7.6  0.98  0.98
D3.Kurasini          1.80  2.82  131   180  0.91  0.98  0.90  0.99  0.91  1.00  600   1.9  2.3   1.5   1.8  0.6  0.8   10    12    6.0  0.58  0.60
D9, Town 2           2.00  2.53  133  300  0.93  0.99  0,96  1.00  0.93  1.00  600   1.8  2.7   0.6   1.1   0.5  0.9         7    11   13.9  0.43  0.48
010, Magomeni        3.20  6.51   93  230  0.93  1.00  0.96  1.00  0.93  0.96  600   1.7  2.3   1.3   1.9  0.2   0.5         7    11   11.5  0.49  0.55
02, Upanga           3.30  3.26   80    80  0.98  0.98  0.96  0.98  0.98  0.86  600  -0.1   0.1   0.2   0.5  -0.6  -0.5   -2   -1  -32.1  3.17 -0.39
03, Chy Cemner 1     1.10  1.20   49  240  0.93  0.97  0.96  1.00  0.93  0.73  600   P.1   0.2   0.3   0.5  -0.2  -0.1       0     1   52.4  0.34  0.69
C4. Chy Center 2     0.90  2.21   43   270  0.93  0.93  0.96  0.99  0.93  0.64  600          0.1   0.2   0.3  -0.2  -0.1           0         11.53  0.53
C5, Mnazl Mnela 1    1.40  1.44  186   195  0.93  0.98  0.96  1.00  0.93  1.00  600   2.9  4.1   1.0   1.4  0.7   1.1   10    15    9.8  0.40  0.41
C6,MnazlMneja2       1.80  1.76  113   118  0.96  1.00  0.96  1.00  0.96  0.97  600   0.6   0.8   0.6   0.8  0.0  0.2        3     4   14.2  0.53  0.65
C8, Tanesoo          1.30  1.44   63   226  0.93  0.99  0.96  0.97  0.93  0.86  600   0.3   0.5   0.0  0.2  -0.1   0.0       0     1   94.7  0.04  0.30   1
MKI,Msasani          4.50  8.20   87   155  0.93  1.00  0.90  0.99  0.98  0.89  600   2.1   3.1   2.9   4.2  -0.8  -0.5      8    15   15.8  0.45  0.54  m0
MK2, Tandale         4.50 10.84   69   190  0.91  1.00  0.83  0.99  0.91  0.93  600   2.0   3.9   2.5   4.5  0.1   1.0   11    23   21.5  0.60  0.67    1
MK3,Lugalo           4.80  4.80   72   80  0.90  1.00  0.87  0.98   0.9  0.93  600   2.3   3.0   1.0   1.4  0.2  0.5         7    11   11.3  0.35  0.42
MK4, north east      4.50  4.50  171  174  0.98  1.00  0.90  0.98  0.98  0.99  600   2.1   3.2   4.6   6.4  0.2  0.7   17   26   11.1  0.93  0.94
02, Mwengo           4.20  4.22  132   135  0.98  1.00  0.90  1.00  0.98  0.96  600   1.3   1.8   2.2  2.8  -0.2             7    11   10.3  0.64  0.68
03,Packers           3.20  9.64  116  296  0.98  1.00  0.90  1.00  0.98  0.95  600   0.8   1.3   1.6  2.2  -0.3  -0.1        4     8   15.5  0.63  0.69
04, Klnondoni        2.80  2.79   74   177T  0.90  1.00  0.81  1.00   0.9  0.94  600   7.9  10.9   6.4  9.1  0.8  2.4   34    53   11.8  0.49  0.55
05,Seavlew           3.60  3.58  107   115  0.92  0.99  0.91  1.00  0.92  0.99  600   2.5   2.9   1.9  2.3  0.6  0.8   12    15    4.9  0.54  0.57
06, Oyster bay       2.80  4.28   67   120  0.93  1.00  0.90  1.00  0.93  0.88  600   0.6   0.9   1.2   1.5  -0.2            4     6   12.1  0.63  0.71
KUNDUCH              4.20 13.46   38   180  0.93  0.88  0.79  0.99  0.93  0.56  600  -0.6   1.2   2.3   5.8  -2.0  -1.1   -3   14         .  0.62  1.27
PACKER6              3.40  3.36   57   60  0.93  0.99  0.85  1.00  0,93  0.81   600   1.1   1.7   3.6   4.6  -0.9  -0.6      8    14   13.7  0.86  0.91
LUGALO               7.00  6.96  141   150  0.92  0.98  0.90  0.97  0.92  1.00  600   7.2   8.2   8.9  10.2  2.4  2.9   47    54    3.7  0.75  0.76
F5.BUGURUN           1.30  3.20   37   110  0.71  0.99  0.85  0.97  0.71  0.81  600   0.7  0.9   0.2  0.3  0.1   0.2         2    3   11.0  0.34  0.40
F2,RTD               2.50  2.50  150  170  0.71  0.81  0.85  0.97  0.71  0.91  600   6.5   8.6   2.4   3.3  2.8  3.8   28    39    8.0  0.50  0.52
KISARAWE            17.80 17.80   31    28  0.89  0.80  0.90  0.79  0.89  0.44  600  -2.8  -2.2  -3.3  -2.7  -8.8  -8.5  -52   -48   -1.9  2.13  2.53
UKONGA               5.00  5.00   54   60  0.89  1.00  0.90  0.96  0.89  0.83  600   3.1   4.2   1.0   1.9  -0.5  0.0        5    12   23.2  0.19  0.32
F31,INDUSTRIAL       2.60  2.60  167  195  0.71  0.80  0.85  0.92  0.71  0.89  600   7.6   9.4   5.7  7.1   3.3  4.2   42    53    6.0  0.63  0.64
F33,AIRWING          2.30  2.30   54   75  0.79  0.98  0.78  0.97  0.79  0.93  600   1.5   1.6   1.8   1.9  0.3  0.3         9     9    2.4  0.67  0.68
F34,KIWALANI         5.80  5.80   64   100  0.91  1.00  0.85  0.97  0.91  0.88  600   1.9  3.1   5.4   7.5  -0.2  0.4   18   28   12.3  1.05  1.04   --
Kigarn Fl           10.00 10.00   67   75  0.89  1.00  0.90  0.96  0.89  0.92  600   9.8  15.9   2,0   5.6  0.7  3.8   23    56   24.4  0.27  0.40   r-
Kigam F2             6.00  6.00   75   84  0.89  1.00  0.90  0.98  0.89  0.95  600   7.2  11.3   2.0  4.3  1.1  3.1   21    43   19.6  0.33  0.43  (D
00



CAPACITOR APPLICATIONS
LOSS REDUCTION BENEFITS ON 33 KV LINES
Foodr P8ak    Day     Bas Pee        y           Capack <--------- LOSS SAViNGS IN MW .'    ---.. -> Unhs   Units   Annual        Inc. of unhIs Ino. of MWh per
FEFMR              Length Peak   OkIPF  0kFF   OkPf  NvwPF  Nwff  NewPF  appflid    1991   1995  1991   1995   1991   19965 Saved  Saved  %ino.  LRWF IRF saved MWh kVA of capasis
NAME                (km)  Amps  CosJ6  Cos   Cos4  Cos6  Cosd   Cos6  (kVA)    night  night   day    day   base   base MWh   MWh   savings 1991 1996 1991 1995 1991  1995
ILALAC.C1              2.5   148   0.94   0.06   0,94   0.95   0.97   0.98    300    1.2    1.6   1.2    1.5    0.6    0.8         a     10      6 0.72 0.73
ILALAC.C 11            2.5   148   0.94   0.96   0.94   0.96   0.97   0.98    600    2.4    3.0   2.2    2.9    1.0    1.4    16         19      7 0.70 0.71    7    9  0.02  0.03
ILA9A4(UA-qNI          5.9   232   0.91   0.87   0.91   0.92   0.88   0.92    300    5.9    7.8   5.5    7.3    2.8    3,7    37         49      7 0.72 0.73
ILAiAKURA9NI           5.9   232   0.91   0.97   0.91   0.92   0.90   0.94    600   11.4   14.9   10.7   14.2    6.4    7.1    71        94      7 0.72 0.72  34  46  0.11  0.15
ILALA-KURASNI          5.9   232   0.91   0.87   0.91   0.94   0.92   0.97   1200   21.5   28.8   20.1   27.1   9.4   13.0   131    178          8 0.70 0.71   60  83  0.10  0.14
ILALAKURASNI           5.9   232   0.91   0.87   0.91   0.95   0.94   0.99   1800   30.3   40.9  28.2   38.7   12.2   17.5   180    249          8 0.68  0.70  49. 72  0.08  0.12
ILALA4IA$INI           5.9   232   0.91   0.87   0.91   0.98   0.97   1.00  3000   44.0   81.8  40.8  58.1   13.9   22.8   244    380           10 0.83 0.86   84  110  0.05  0.09
XURASINH4OGAM8011      4.0    53   0.89   0.90   0.89   0.93   0.98   0.96   300    0.9    1.2   0.5    0.7    0.4    0.8          4      6      9 0.58 0.57
l0JPASNHKGAMBON        4.0    53   0.69   0.90   0.89   0.96   0.99   1.00    600    1.6    2.3   0.7    1.1    0.6    0.9         7     t 1    11 0.50 0.53    2    4  0.01  0.01
ILALA-OYSTEiAY         5.8   285   0.93   0.88   0.95   0.95   0.91   0.97    600   11.3   13.5   10.2   12.2    5.3    5.8    70        80      3 0.71 0.88
LALA,OYSTEiBAY         5.8   285   0.93   0.88   0.95   0.96   0.93   0.98   1200   21.4   25.7   19.3   23.2    9.5    9,9   129    149         4 0.89 0.86   59  89  0.10  0.12
ILALOYSTEilEAY         5.8   285   0.93   0.88   0.95   0.97   0.94   0.99   1800   30.2  38.8   27.0   33.0   12.3   13.1   177    207          4 0.67 0.64  48  58  0.08  0.10
ILALA-OYSTEiBAY        5.8   285   0.93   0.88   0.95   0.98   0.98   1.00   2400   37,8   48.8  33.8   41.5   14.0   15.0   21t    255          4 0.65 0.62  38  48  0.08  0.08
ILALAOYSTEFiAY         5.6   285   0.93   0.88   0.93   0.98   0.97   1.00   2600   40.1   49.7  56.0   72.8   14.3   19.1   285    369          7 0.81 0.85  70  114  0.35  0.57
ILALA,OYSTEFEAY        5.8   285   0.93   0.88   0.93   0.98   0.97   1.00   2800   42.2   52.8  57.8   75.2   14.4   19.6   293    382          7 0.79 0.83
ILALAOYSTEF8AY         5.8   285   0.93   0.88   0.93   0.98   0.97   1.00  3000   44.2  55.3   59.4   77.5   14.4   20,0   301    394           7 0.78 0.81
ILALLAOYSTEiSAY        5.8   285   0.93   0.88   0.93   0.99   0.98   1.00  3200   46.1   57.9  60.9   79.7   14.3   20.2   308    406           7 0.76 0.80
ILALAOYSTEFOiAY        5.6   285   0.93   0.88   0.93   0.99   0.98   1.00  3400   47.8  60.3   62.3   81.7.  14.0   20.3   313    418           7 0.75 0.79
ILALiA.FZI             4.7    80   0.71   0.85   0.71   0.74   0.88   0.78    300    2.0    3.3    1.7   2.1    1.3    1.6    14         18 a    60.2 0.62
ILALAFZI               4.7    80   0.71   0.85   0.71   0.78   0.91   0.85   600    5.0   6.3    3.1   3.9    2.2   .2.9    28           33      6 0.60 0.60   12  18  0.04  0.05
UBUNGO-ALAF            9.2   105   0.89   0.80   0.89   0.91   0.91   0.91    300    3.8    4.3   3.7    4.2    3.8    4.3    33         37      3 0.99 0.90
UBUNGOAAF *            9.2   105   0.89   0.89   0.89   0.93   0.93   0.93    500    6.1    6.8   8.0    8.7   6.1    6.8    53          59      3 0.99 0.99  20  22  0.10  0.11               i
UBUNGOAAF *            9.2   lOS   0.89   0.89   0.89   0.96   0.95   0.96   1000   10.9   12.3   12.8   14.2   10.8   12.2   100    113         3 1.05 1.05  47  54  0.09  0.11                H
UBUNGONWA701           8.8    88   0.93   0.84   0.93   0.95   0,90   0.97    600    8.0   11.1   7.8   10.7    3.5    5.1    50         70      9 0.71 0.72
UBUNGO-WAZOI1          8.8    68   0.93   0.84   0.93   0.97   0.94   1.00   1200   14.1   20.4   13.8   19.5   5.1    8.3    83    123         10 0.67 0.69   33  53  0.05  0.09
UBUJNGO-WAZOI-         8.8    68   0.93   0.84   0.93   0.99   0.98   0.99   1800   18.3  27.7  17.5   26.4    4.8    9.5    99    159          13 0.62 0.66  16  36  0.03  0.06
UBUNGOWAZOI            8.8    68   0.93   0.84   0.93   1.00   1.00   0.96   2400   20.6   33.0   19,5   31.3    2.8    8.8    98    178        16 0.55 0.62   -1  19-0.001  0.03
UBUNGOWAZO11          18.2   140   0.80   0.92   0.92   0.87   0.98   0.97   1000   41.2   47.3  26.5   30.8   25.0   29.0   247    288          4 0.68  0.69
UBUNGO-WAZO11         18.2   140   0.80   0.92   0.92   0.93   0.99   0.99   2000   71.2   83.5   42.0   50.4   38.9   46.9   397    474         5 0.84 0.65  150  189  0.15  0.19
U3UNGOWAZ011          18.2   140   0.80   0.92   0.92   0.98   1.00   1.00  3000   90.3  108.7   40.4   59.1   41.7   53,7   450    566          8 0.57 0.80  53   92  0.05  0.09
UBUNGO-TAZARA'         7.9   100   0.85   0.85   0.65   0.99   0.98   0.99   1200    6.0    6.7   7.0    7.8    6.0    6.7    55         62      3 1.06 1.06
U1UNGO0TAZARA-         7,9   100   0.85   0.85   0.85   1.00   1.00   1.00   1800    6.4    7.5   7.9    9.2    6.4    7.5    60         70      4 1.08 1.08   5    8  0.0i  0.01
UBUNGO-TAZARA          7.9   100   0.85   0.85   0.85   0.96   0.98   0.96  2400    5.1    6.5   7.2    8.8   5.1    6.5    50           64      6 1.14 1.12  -10   -7 -0.02 -0.01
LUEL4>MKOCHEN          5.2   199   0.94   0.87   0.95   0.96   0.90   0.98    600    6.8   9.1    7.3    9.9    2.6    3.7    43         68      8 0.72 0.73
LU KNGOKO)EN           5.2   199   0.94   0.87   0.95   0.97   0.93   1.00   1200   12.4   17.2   13,6   18.7    4.2    8.2    78    107         9 0.70 0.71   33   49  0.06  0.08
UElt)G,tKOCIENl        6.2   199   0.94   0.87   0.95   0.98   0.95   1.00   1800   17.0  24.0  18.8   26.4    4.5    7.8    99    146          10 0.67 0.69  23  39  0.04  0.06
UBUNGO.F11l           11.0   155   0.84   0.87   0.84   0.94   0.95   0.99   2000   50.7  60.9   48.0   58.5   18.7   23.8   296    364          6 0.67 0.68
UBUNGO-F11            11.0   155   0.84   0.87   0.64   0.97   0.98   0.99  3000   66.1   81,3   62.0   77.7   18.0   25.6   356    458          8 0.82 0.84  80   94  0.06  0.09
UBUNGO.F111           11.0   155   0.84   0.87   0.84   0.99   1.00   0.92   4000   74.7  95.0  69.3   90.3   10.0   20.8   358    493           8 0.55 0.59    2   35  0.00  0.04             -i
a)
F1t1-F1t               7.0    36   0.89   0.90   0.89   0.94   0.96   0.98    300    1.0   1.2   0.7    0.8    0.4    0.5         5       6      3 0.62 0.82                                   T
FtIl-FIt               7.0    36   0.89   0.90   0.89   0.98   1.00   0.99    600    1.7    1.9   1.1    1.3    0.4    0.6        8       9.     5 0.53 0.55    2    3  0.01  0.01             (D
UBUNGO-F.TX2-          1.8    60   0.80   0.80   0.80   0.86   0.85   0.86    300    0.4    0.4   0.5    0.6    0.4    0.4        4       4      3 1.09 1.09                                   n
UBUNGt>F.TX2-          1,8    50   0.80   0.77   0.80   0.92   0.87   0.92    600    0.7   0.8    1.0   1.1    0.7    0.8         7       a      3 1.14 1.14    3    4  0.01  0.01             1°
UBSJN.NSOCC           55.0    64   0.92   0.92   0.92   0.97   0.99   0.97    600    9.1   12.3   5.3    7.4    9.1   12.3    68         93      8 0.88 0.87
UEJNGO-NORiC-         5.0    84   0.92   0.92   0.92   1.00   0.99   1.00   1200   13.4   19.7   5.7    9.9   13.4   19.7    e5    144          11 0.81 0.83  26  51  0.04  0.09
Note: LnLF - Loss teduction load lactor
The loss reduction load lactor has boen calculated based on the system peak values and not the Indivifual paak values (lor maximum savings)



LOSS REDUCTION ON UBUNGO - ILALA 132 KV LINE AND TOTAL SYSTEM
BY DOWN STREAM CAPACITOR APPLICATIONS
Year 1992 wlth existing system
Incremental
UIB llala          Capacit.  UB- llala  Tot. sys. Incremental loss red/n  Energy tosses p.a.  energy savings
line loss  Tot. sys.   at tlala loss red/n loss red/n   UB- liala  Tot. sys.  UB-IL  Tot. sys.  UB-IL    Tot. sys.
WW   Loss MW      kVAr        kW       kW       UB-IL  Tot. sys.    MWh       MWh         MWh         MWh
0.713    21.48
0.69    21.16      1000        23      320         23      320        101     1402          101        1402
0.668    20.86      2000        45       620        22       300       197     2716           96        1314
0.648    20.59      3000        65       890        20       270      285      3898           88        1183
0.629    20.37      4000        84      1110        19       220      368      4862           83         964
0.611    20.165     5000       102      1315        18       205      447      5760           79         898
0.594    19.965     6000       119      1515        17      200       521      6636           74         876
0.578    19.765     7000       135      1715        16      200       591      7512           70         876
0.563    19.57      8000       150      1910        15       195      657      8366           66         854
Year 1993 with double circuit Kldatu - Morogoro
0.654    18.79         0
0.629    18.68      2000        25       110        25       110       109      482          109         482
0.607    18.57      4000        47       220        22       110      206       964           96         482
0.585    18.47      6000        69       320        22       100      302      1402           96         438
0.565    18.38      8000        89       410        20        90      390      1796           88         394
Year 1995 with double circuit Kidatu - Morogoro - Ubungo
0.763    17.59         0
0.747    17.56      1000        16        30        16        30        70      131           70         131
0.736    17.53      2000        27        60        11        30       118      263           48         131
0.725    17.49      3000        38       100        11        40       166      438           48         175
0.714    17.44      5000        49       150        11        50      215       657           48         219
0.704    17.38      7000        59       210        10        60      258       920           44         263
Loss reduction load factor used for
computation of energy savings = 0.50                                                                                                     r
(0



-163-
ECONOMIC ANALYSIS OF SELECTED CAPACITOR APPLICATIONS ON II kV LINES                                          TABLE C 11
SECTION A
ANALYSIS OF BENEFITS WITH NETWORK UNCHANGED
growth         MFfor  PW of benefits      Benefit Pay   total  Benefit
FEEOERNAME   Capacdor        Units Saved MWWIfeeder  rate of        loss redl '93 to 96       to Cost Back in benetftrto Cost
KVA              1991   1995 load gr. benefits        benefits in $000          ratio    months      ratio
rate                                              93-'96 only    1993-2008
Fed from liala Grrid SS
Benefits on 11 kV lines                       11 kV lines         11I kV lnes oni
K4, Industrial           600    199    256         4     6.5            3.69    67.6              26.4   2.0  75.1  27.5
K3, Kilwa road           600      46      59       4     6.4            3.68    15.6               6.1   8.8  20.1   7.3
Port                     600      56      99       8    15.3            4.51    23.2               9.1   7.2  26.9   9.8
03. Packers              600      81    106        4     7.0            3.73    27.8              10.9   5.0  31.5  11.5
D10, Magomeni            600      52      68       4     6.9            3.73    17.8               7.0   7.8  20.9   7.6
Benefits on 33 kV lines                          33 kV   33 & 11  1 1 & 33 kV lines
lines   kV lines
K4, Industrial           600      43      57             7.3            3.76    14.9        82    32.2   1.7  93.1  34.0
K3, Kilwa road           600      31      48            11.6            4.14    11.8        27    10.7   5.3  35.2  12.8
Port                     600      20      56            29.4            6.10    11.2        34    13.4   5.3  41.2  1t.0
03, Packers              600      36      42             3.9            3.48    11.5        39    15.3   3.5  44.9  16.4
D10, Magomeni            600                                                                18     7.0         20.9   7.6
Benefits on UB-IL 132 kV line                   132kV         All   All.iAries
line     lines
K4, Industrial           600      53      26                            3.17    15.5      97.9   38.2   1.4 108.6  39.7
13, Kilwa road           600      53      26                            3.17    15.5      42.9   16.7   3.1  50.6  18.5
Port                     600      53      26                            3.17    15.5      49.9   19.5   3.1  56.6  20.7
03, Packers              600      53      26                            3.17    15.5      54.8   21.4   2.4  60.3  22.0
010, Magomeni            600      53      26                            3.17    15.5      33.3   13.0   3.9  36.4  13.3
Fed from Ubungo Grid SS
Benefits on 11 kV lines                       11 kV lines        I1 kV lines onov
MKI,Msasani              600      33      50       8    10.9            4.09    12.4               4.8  12.3  17.3   6.3
MK2,Tandale              600    112    182         8    12.9            4.27    44.0              17.2   3.6  54.4  19.9
Kunduchi                 600    236    441        10    16.9            4.67   101.4              39.6   1.7 103.7  37.9
Ul, Kisiwani             600      57      99       8    14.8            4.46    23.4               9.1   7.1  41.3  15.1
U2, Menzeese             600      50      67       4     7.6            3.79    17.4               6.8   8.1  28.2  10.3
33 kV   33 & 11
Benefits on 33 kV lines                           lnes   kV lines  11 & 33 kV lines
MK1,Msasani              600      28      37             7.2            3.75     9.7        22     8.6   6.6  34.1  12.5
MK2,Tandale              600      19      29            11.2            4.11     7.2       51    20.0   3.1  85.3  31.2
Kunduchi                 600      38      51             7.6            3.79    13.2      115    44.7   1.5  117.9  43.1
Ul1,Kisiwani             600                                                               23      9.1   7.1  41.3  15.1
U2,Menzeese              600                                                                17     6.8   8.1  38.1  13.9
TOTAL FOR ALL 10 APPLICATIONS                                                                                 629.1  23.0
Note:                                                            See section B (next page) for computation of
0.092 = Value of loss red/n benefits $/ kWh             benefits beyond 1996, after mnajor network
3100 = Cost of application, 600 kVA, $                 develoments are affected
2560 = Cost of application, 300 kVA, $
1 0 = Discount factor in %
1 996  = year of termination of benefits of tines to be altered
1 993 = year of commencement of benefits
1991  = base year for discounting



-164-
ECONOMIC ANALYSIS OF SELECTED CAPACITOR APPLICATIONS ON 11 kV LINES (Cont.)    TABLE C 11
SECTION B
WfTH NETWORK CHANGES AND RELOCATION EFFECTIVE 1997 (section B)
growth   gr. rate  effect-  MF for PW of loss red/n   BiC
FEEDER NAME                   Capaci. MWhlpa Saving  feeder   rate of  ive gr. benefits  benefits in $000   ratio
KVA      1991   1995  load gr. benefits    rate            1997 to 2008
rate %        f    after
NEW            OLD                                                     discount.
LOCATION       LOCATION
Fed from liala Grrid SS
Benefits on 11 kV lines                                            11 kV lines onil
Kigam Fl       K41. Industrial    600       23      56       4    24.9    1.14      3.6        7.5           43.1
Kigam F2       K3. l(Ilwa road    600       21      43       4    19.6    1.09      2.3        4.5           25.5
Port           Port               600       25      44       8    15.2    1.05      1.6        3.6           20.8
04, Kinondoni   03, Packers       600       34      53       4    11.7    1.02      1.2        3.7           20.9
F2,RTD         Kunduchi           600       28      39      10      8.6   0.99      0.9        2.3           13.0
D2.Townl       D10, Magomeni      600       43      57       4      7.3    0.98     0.8        3.1           17.6
Benefits on 33 kV lines                                      33 kV  11 & 33 kV lfnes
only
lKgam Fl       K4, Industrial     600       43      57              7.3   0.98      0.8        3.1    10.6  60.8
Kigam F2       K3, Kiwa road      600       31      48             11.6   1.01      1.2        3.3     7.7  44.3
Port           Port               600       43      57              7.3    0.98     0.8       3.1      6.7  38.5
04, Kinondoni   03, Packers       600       36      42              3.9   0.94      0.6        1.9     5.5  31.6
F2,RTD                                      15      19              6.1    0.96     0.7        1.0     3.2  18.5
D2,Townl       D10, Magomeni      600                                                          0.0     3.1  17.6
Fed from Ubungo Grid SS
Benefits on 11 kV lines                                            11 kV lines only
MK4,north east  MK1, Msasanr      600       17      26       8    11.2  1.011       3.1         5            27.7
F31,1ndustrial   MK2, Tandale     600       42      53       8     6.0  0.9635      2.7        10           59.3
Lugalo         U2, Menzeese       600       47      54              3.5  0.9412     2.5        11            61.9
Ul.1,lsiwani   Ul, Kisiwani       600       57      99       8    14.8  1.0436      3.4        18          102.3
Benefits on 33 kV lines                                      33 kV  11 & 33 kV lines
only
MK4,north east  MK1, Msasani      600       28      37              7.2 0.9747      2.8         7      12   68.6
F31,lndustrial   MK2, Tandale     600       99    120               4.9 0.9539      2.6        24      34  194.9
Lugalo         U2, Menzeese       600       38      51              7.6 0.9785      2.8        10      21  118.0
Ul, Kisiwani   Ut, Kisiwani       600                                                                  1 8 102.3
0.092 = Value of loss red/n benefits $1 kWh                     The benefit to cost ratio has been worked
310 = Cost of application. 600 kVA                            out assuming a new investment year in 1997
256 = Cost of application, 300 kVA                            and counting the benefits from 1997 to
1 0 = Discount tactor in %                                   2008. The present value of these benefits is
2008  = year of termination of benefis of lines to be altered  taken account in page lwhen computing for
1997  = year of commencement of benefits                       the period 1997 to 2003.
1991  = base year for discounting
Note: Losses for 1991 and 1995 are calculated as if the new proposed arrangements have been affected



BENEFIT TO COST ANALYSIS FOR CAPACITOR APPLICATiONS AT THE 33/11 kV SUBSTATIONS
INCLUDING CONSUMER INSTALLATIONS
CapacH.      Cost of    Savings in year 1991    Savings in year 1995      savings     savings      benefit      MF for     Value of      Benefit    Pay back
FEEDER                In kVA   Instaliatlon   night peak     Units   night peak      Units     growth       growth      counted      Savings     Savlngs      to Cost       perlod
NAME                   at SS     at ss In S       kW        MWh           kW         MWh    rate In %     rate in %       up to                In $000's        ratlo    (months)
(discounted)
iLAiA-OYSTERBAY         600         4200          7.6        37.6         9.6        47.6         6.09        0.96        2003          8.9         30.8         7.3         14.6
ILALA-OYSTERBAY         800         5600          9.9       107.4        12.9        161.4       10.72        1.01        2003         11.4        113.1        20.2          6.8
UBUNGO-ALAF *           1000        7000         10.9         100        12.3         113         3.12        0.94        2003          7.6         70.0        10.0          9.1
UBUNGO-WAZO11           1000        7000         41.2         247        47.3         266         3.71        0.94        1997          4.2         95.5        13.6          3.7
UBUNGO-WAZOtl          2000        14000         71.2         397        83.5         474         4.56        0.95        1997          4.3        157.2        11.2          4.6
UBUNBO-WAZO11          3000        21000         90.3         450       108.7         566         5.92        0.96        1997          4.5        185.1          8.8         6.1
UBUNGO-F111            2000        14000         50.7         296        60.9         364         5.29        0.98        2003          8.5        232.6        16.6          6.2
UBUNGO-F11i            3000        21000         66.1         356        81.3         458         6.48        0.97        2003          9.1        298.1         14.2         7.7
UBUNGO-F111            4000        28000         74.7         358        95.0         493         6.36        0.99        2003         10.1       331.2          11.6        10.2
Note:              0.092 Value of loss reductlon beneflts In $ per kW
7 Cost of capacitors at Substations In $ per kVAr
1 0 Dlscount factor In %
1991 base year for discounting
The OysterBay loss reductlon Is computed on the Incremenal benefits
after allowing for downstream development
(B
rD
r\j



I



ANNEX D
PLANNING METHODS AND GUIDELINES FOR DISTRIBUTION SYSTEMS



I



-169-
Annex D
PLANNING METHODS AND GUIDELINES FOR DISTRIBUTION SYSTEMS
Contents
Introduction
Description of commonly used terms and formulae
Section D. 1       Computation of line losses and voltage drop of distributors
- Table D. 1. 1: Conversion factors for distributors
- Figure D.l.l: Representation of a distributor
Section D.2        Charts of line length vs. load for constant voltage drop
D.2. 1.1           - 33 kV lines, tail and voltage, 5% voltage drop
D.2.1.2            - 11 kV lines, tail and voltage, 5% voltage drop
D.2.1.3            - LV lines, tail and voltage, 5% voltage drop
D.2.2. 1           - 33 kV lines, distributed load, 5% voltage drop
D.2.2.2            - 11 kV lines, distributed load, 5% voltage drop
D.2.2.3            - LV lines, distributed load, 5% voltage drop
Section D.3        Present worth factor tables used for economic analysis
D.3.1              Present worth factors of loss reduction benefits of future years (constant
load growth)
D.3.2              Present worth factors of reliability benefits of future years (constant load
growth)
D.3.3              Present worth factors of loss reduction and reliability benefits for variable
load growth rates



I



-171-
ANNEX D
PLANNING METHODS AND GUIDELINES FOR DISTRIBUTION SYSTEMS
Introduction
This annex provides some basic information on the planning methods which were employed
in the study of power distribution systems and the associated economic analysis. A description of
the commonly used terms together with the relevant formulae is provided in page 2. During the
course of the project specialized software to build network geographical data bases and to conduct
load flow analysis was provided and TANESCO staff trained in their application. However due to
the need to undertake extensive field verification of the existing networks the building up of this
data base is quite time consuming. Thus in addition to the more detailed analysis provided by the
computer programs an approximate methodology is also provided to determine the main
characteristics required for the planning exercise, namely the determination of system losses and the
tail end voltage conditions of the feeders. The method employed for this analysis is detailed in
section D 1 and relies on the ability of modeling the distributor as a radial line with loads of equal
magnitude acting at equally spaced distances along the distributor. The method provides a set of
multiplying factors which can be used to convert the losses and tail end voltage drops of a tail end
load condition (which is readily ascertainable) to that of a distributor. In instances where the
distributor is too complex to be modeled in this manner it has been divided into a number of
sections which are then amenable to such representation and the results for the original distributor
has been built up from the individual components. In the course of the studies it has been found
that the methodology provides results well within the limits of acceptable accuracy. Computer
spreadsheets have also been built to use the formulae in a convenient fashion. Due to the simplicity
of this method, results for all feeders and distributors can be obtained in a short time with minimum
data requirements. Thus this method is recommended to be used when data and time limitations do
not warrant a more detail analysis.
Section D 2 presents a sample from a set of charts which show the variation of the feeder or
distributor load with line length for stipulated values of tail end voltage drops. These charts have
also been developed using spreadsheets based on the computation described in section D 1. The
charts can be used to determine the acceptable loading levels for different line lengths and
conductor sizes; they are thus a convenient means of determining conductor configurations required
for acceptable network performance.
The benefits of loss reduction and reliability improvement over a period of years need to be
computed in order to undertake economic analyses of development proposals. Technical studies
are usually done with the maximum loading of a particular year. However both loss reduction and
reliability improvement benefits increase with network load over time. It is therefore necessary to
find convenient methods of evaluating the discounted value of such benefits over a given period of
time. Section D 3 contains tables providing factors that can be used to convert the benefits of a
particular year to the present worth of a series of future benefits extending over a number of years.
These tables are once again derived from simple computer spreadsheets which can be used to
provide the required values for varying time periods, growth rates and discount factors. Tables D
3.1 and D 3.2 assume a constant rate of growth over the period of analysis. In Table D 3.3 the
study period is broken down to a variety of sub periods and the growth rate could be varied between
the sub periods. Thus the technique can be used to obtain the most appropriate conversion factor to
suit the particular condition of the situation under study.



-172-
A DESCRIPTION OF COMMONLY USED TERMS AND FORMULAE
Each term described is followed by the symbol used, formulae connected with its use (if applicable),
units used and a brief description.
Feeders:    Lines that transport power over some distance. In general a feeder is higher in the
supply hierarchy than a distributor. A line which will transport power between two points in the
system without intermediate tappings will always be termed a feeder and a line which is tapped
along its way will be termed a distributor.
Distributor: A power supply line which is tapped along its length to feed loads or consumers.
Load factor:       LF    - E = P . T. (LF)         - ratio or %
The ratio of average load (kW) to the peak load (kW) over some time period (usually one month or
one year).
Loss load factor:        LLF  - AE =AP. T. (LLF)         - ratio or %
The ratio of average losses (kW) to the peak losses (kW) over some time period (usually one
month or one year).
Loss reduction load factor:     LRLF - AAE = AAP . T. (LRLF) - ratio or %
When loss reduction is achieved by the use of capacitors, the reduction in power losses has a wide
variation over different loading conditions. In some instances a loss reduction at peak time may be
accompanied by a loss increase during base load times. The loss reduction load factor is the total
energy saved by the application divided by both the peak time loss savings and the applicable time
period.
Coincidence factor: Cf    - Cf = P* -- P           - ratio or %
The ratio of the load (of the line or network section considered) at system peak time to its own peak
load. This term is also called the Peak responsibility factor.
Note:
P (in kW)          = power supplied at peak load for the line, equipment or
network considered over the time period, T
E (in kWh)         = energy supplied over time period, T
AE (in kWh)        = energy losses in time period, T
AP (in kW)         = peak power losses in
ME (in kWh)        = reduction in energy losses by a specified application (usually capacitors)



-173-
Annex D 1
COMPUTATION OF LINE LOSSES AND VOLTAGE DROP OF DISTRIBUTORS
The line losses and voltage drop of a short distribution line with a single load at its
extremity can be found from the following simple formulae:
line losses        =     3. 12. r. L
Line end voltage drop=   I. L. (r. cos e + x sin 8)
where:      I = line current
L   line length
r  resistance in Ohms per unit length
x = inductance in Ohms per unit length
e = power factor angle
In practice however a distribution line consist of a number of branches or tapping points
and is loaded at various points along its length at irregular intervals. In such instances, the power
flow characteristics including line losses and tail and voltage drops can only be accurately
determined by using suitable computer programs to handle the iterative nature of the solution.
However a simplified methodology can be developed to obtain an approximate solution which will
yield results within acceptable accuracy limits.
The computation is made with the distributor modeled as a simple radial line with a
number of loads of equal magnitude (acting at nodes along the line) separated from each other by
equal distances (line sections) as shown in Fig: D 1. Experience has shown that it is fairly
convenient to represent typical distributors by such models. The total length will be the radial
length of the distnrbutor ignoring the branch lines and the number of sections will be determined
according to the magnitude and the dispersion pattern of the loads. In certain cases branch lines
can be modeled separately and the total load of a branch taken as acting at the appropriate location
along the main distributor (which is also modeled separately).
The power flow along each section of the model is the flow along the previous section less
the load acting at the node at the beginning of the section. Neglecting the difference in the phase
angle of the currents flowing along the various sections the following relationships can be derived.
Where: no. of sections = n
Load at each node = I amps
n
Current flowing along the sections, commensing with the start of the distributor:
L  I (n-l) ,      (-22, ................  I
n        n                     n
The power loss along the section (r + 1) will be:
3rL  [I  n -r  ] 2  and
n        n



-174-
Annex D 1
the voltage drop in the section will be:
I (n-r  (r cose + jx sin e)
n
The total line loss and tail end voltage drop could now be obtained by summing up as follows:
Total line loss
= 3.rL [I2 n   + I2 n-    + I2 (n-2)2  +    . . .+  2
= 3. r LI'  n n2    + (n-1)2 + (n-2)2+        +12]
n3
=-3.rLI    1+ 22+ 3+                  + n
n 3
= (losses if total load was at line end) . (1 2 22  +.......  + n
n3
and,
Line end voltage drop
= (rcose + jxsine)L  [In + I(n- -1 + I(n-2) +          .      +I]
n            n          n                    n
= (rcose + jxsine) L  [ 1 + 2 + 3 + ..... .... + n]
n2
= (r Cose + j sine) L (1 + n)
2n
= (voltage drop if total load was at line end) . (I + n)
2n
Using the above relationship a set of multiplying factors could be derived to convert the tail end
load situation to that of a distributor with the same length and sending end load. Table D1.1
provides a summary of such multiplying factors.



-175-
Annex D I
Table D 1.1
CONVERSION FACTORS FOR DISTRIBUTORS
no. of Sectiom
(uith Identical                            Nultiplying factor for
Line end voltace          Line losses
CTail end load)                           1.0                     1.0
2                              0.750                   0.625
3                              0.667                   0.519
4                              0.625                   0.469
5                              0.600                   0.440
6                              0.583                   0.421
7                              0.571                   0.408
8                              0.563                   0.398
9                              0.556                   0.391
10                              0.550                   0.385
11                              0.545                   0.380
Uniformly distributed load              0.500                   0.333
Note:   The above factors convert the line end voltage and line losses of a
terminally loaded line to that of a symetrical linear distributor of
equaL load consisting of a number of equalby loaded sections.
Fig. Di    Representation of a distributor.
<   (erl >  -  2rs  is  Tercioatio o
Seodiag                                         - - - - - - - - - -                               ot the
Is                    -Is               is   4|                             Distributor
L                                     L             L
n          i           n              n.
L



LENGTH vs LOAD 33 kV, 5% VOLT DROP
Dist. Load (0.6). PF-0.85
210
200
190
180
170
160EX<                                                      ltX
1 60                  -=__                                         =_ __   _ ___ _]
150
140
130
z1120-
0~~1
z        100-                             O5m
-j     ~90 -
z         8
70-                                                 _
60   -_ _ _                                _ _ __ _ _
50-
40    -_            _ _
30-
20
1000   1500   2000   3000   4000   5000   6000   7500   10000  15000                     CT
LOAD IN KVA
0   1 O0mmsq    +   50mmsq



-177-                                       Table D.2.2.2
LENGTH vs LOAD 11 kV, 5% VOLT DROP
Dist. Load (0.6), PF-Q.E5
90 -
70 -
v         60   -               -       --
50-               - -                       -
z
-L        40    ---                                    ----                                   -
30   -                                    _
20 -
10
250    500      750    1000    1500   2000    2500    3000   3500    4Q000
LOAD IN KVA
-     O     OOmmsq    +   50mmsq
Table D.2.1.2
LENGTH vs LOAD 11 KV, 5% VOLT DROP
Tail end load, PF-0.85
26
24 -
22
20   -            _                 __ =
Z          16                                                              _     _  ___       =
65   -                             _ ___
14-
z
LLI
4       ___
24                                    -                                     ___
2-
0-
500      750     1000      1500    2000    2500       3000     3500      4000



-178-                                         Table D.2.2.3
LENGTH vs LOAD LV, 5% VOLT DROP
Dist Load (0.6), PF=0.B5
1.4 - _____                                                     ___ ___
n.      2-               __  _ _  _ _   __  _  _ _  _   ____   _._
1.2-
1.1
1-
0.9
z
0.   5 -D7                                        0              2              7
L 0.7   -
-L
0.2 ~ ~ ~ ~ ~    ~     ~    ~     ~     ~    ~    ~ ~ ~ al -...
0.4 ~ ~ ~ ~~~~oledlod   F08
0.1   -
25             50             75            100             125            175
LOAD IN KVA
0   1 00mmnsq     +   50mmrsq
Table Dl.2.1.3
LENGTH vs LOAD LV, 5% VOLT DROP
Tail end locd. PF=0.B5
0 .9  -                    _ _ _  _ _    _  _ _ _ _  __                  _ _  _ _  _
0.7 
0.5 
0.5 
z
La   0.4 -
LIL
z
0.2-
0.1   -                                                                 _  _ _  _  _
25             50             75            100             125            1 75



PRESENT WORTH FACTORS FOR LOSS REDUCTION BENEFITS OF FUTURE YEARS
1991      1992      1993      1994      1995      1996      1997      1998      1999      2000      2001       2002      2003      2004       2005      2006      2007
1.05 .GPOWTH RATE              1.1 -INTERESTRATE
Increased losses p.u.
-with load growlh                 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      3.56      3.92       4.32      4.76
Discount factor                    100       0.91      0.83      0.75      0.68      0.62      0.56      0.51      0.47       0.42      0.39      0.35      0.32       0.29      0.26      0.24       0.22
P.W. loss reduction benefits       1.00      1.00      1.00      1.01      1.01      1.01       1.01      1.02     1,02       1.02      1.02      1.03      1.03       1.03      1.03      1.03       1.04
Cumilative PW of benefits          1.00      2.00      3.01      4.01      5.02      6.03       7.05      8.06      9.08     10.10     11.13     12.15     13.18      14.21     15.24     16.28      17.31
1.07 .RGPOWTH RATE             1.1 -INTERESTRATE
Increased losses p.u.
-with load growth                 1.00      1.14       1.31      1.50      1.72      1.97      2.26      2.58      2.95      3.38      3.87       4.43      5.07      5.81      6.65       7.61      8.72
Discount 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       0.29      0.26      0.24       0.22
P.W. loss reduction benefits       1.00      1.04      1.08      1.13      1.17      1.22       1.27      1.32      1.38      1.43      1.49      1.55       1.62      1.68      1.75      1.82       1.90
Cumilalive PW of benefits          1.00      2.04      3.12      4.25      5.43      6.65       7.92      9.24     10.62     12.05     13.54     15.10     16.71      19.39     20.15     21.97     23.86
1.09 -GROWTHRATE               1.1 -INTERESTRATE
Increased losses p.u.
-with toad growth                 1,00      1.19      1.41       1,68      1.99      2.37      2.91      3.34      3.97      4.72      s.60       6.66      7.91      9.40     11.17      13.27     15.76
Discount factor                    1.00      0.91      0.83      0.75      0.69      0.62       0.56      0.51     0.47       0.42      0.39      0.35      0.32       0.29      0.26      0.24       0.22
P.W. loss reduction benefits       1.00      1.0       1.17      1.26      1.36      1.47       1.59      1.71      1.95      2.00      2.16      2.33      2.52       2.72      2.94      3.18       3.43
Cumilative PW of benoefts          1.00      2.09      3.25      4.51      5.87      7.34       8.93     10.64     12.49     14.49     16.65     19.99     21.51      24.23     27.17     30.35     33.78
1.11 -GROWTIH RATE             1.1 -INTERESTRATE
Increased losses p.u.
-with load growth                 1.00      1.23      1.52       1.87     2.30       2.84      3.50      4.31      5.31      6.54      8.06       9.93     12.24     15.08     18.58     22.89      28.21
Discount 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       0.29      0.26      0.24       0.22
P.W. loss reduction benefits       1.00      1.12      1.25      1.41      1.57      1.76       1.97      2.21      2.48      2.78      3.11      3.48      3.90       4.37      4.89      5.48       6.14
Cumilative PWof benefits           1.00      2.12      3.37      4.78      6.35      8.12      10.09     12.30     14.78     17.66     20.66     24.15     28.05      32.41     37.31     42.79     48.93       _
1.05 .GROWTH RATE             1.08 -INTEREST RATE
Increased losses p.u.
-with load growth                 1,00      1.10       1.22      1,34      1.48      1.63      1.80      1.98      2.18      2.41      2.66       2.93      3.23      3.56      3.92       4.32      4.76
Discount factor                    1.00      0.93      0.86      0.79      0.74      0.69       0.63      0.58      0.54      0.50      0.46      0.43      0.40       0.37      0.34      0.32       0.29
P.W. lossreductionbenefits         1.00      1.02      1.04      1.06      1.09      1.11       1.13      1.16      1.18      1.20      1.23      1.25       1.28      1.31      1.33      1.36       1.39
Cumilative PWof benefits           1.00      2.02      3.06      4.13      5.21      6.32       7.45      9.61      9.79     10.99     12.22     13.48     14.76      16.06     17.40     16.76     20.15
1.07 -GRPOWTH RATE            1.08 -INTERESTRATE
Increased losses p.u.
-with load growlh                 1.00      1.14      1.31       1.50      1.72      1.97      2.25      2.56      2.95      3.38      3.87       4.43      5.07      5.81      6.65       7.61      8.72
Discount factor                    1.00      0.93      0.86      0.79      0.74      0.68       0.63      0.58     0.54       0.50      0.46      0.43      0,40       0.37      0.34      0.32       0.29
P.W. loss reduction benefits       1.00      1.06      1.12      1.19      1.26      1.34       1.42      1.50      1.59      1.69      1.79      1.90      2.01       2.14      2.26      2.40       2.54
Cumilatrve PW of benefts           1.00      2.06      3.18      4.38      5.64      6.98       8.40      9.90     11.50     13.19     14.98     16.88     18.89      21.03     23.29     25.69     28.24
1,09 .GROWTHRATE              1.08 -INTEPESTRATE
Increased losses p.u.
-with load growth                 1.00      1.19      1.41       1.69      1.99      2.37      2.81      3.34      3.97      4.72      5.60       6.66      7.91      9.40     11.17      13.27     15.76
Discount factor                    1.00      0.93      0.86      0.79      0.74      0.68       0.63      0.58      0.54      0.50      0.46      0.43      0.40       0.37      0.34      0.32      0.29
P.W. toss reduction benefits       1.00      1.10      1.21      1.33      1.46      1.61       1.77      1.95      2.15      2.36      2.60      2.86      3.14       3.46      3.80      4.18       4.60
Cumilative PW of bonefits          1.00      2.10      3.31      4.64      6.11      7.72       9.49     11.44     13.58     15.94     18.54     21.40     24.54      27.99     31.80     35.69      40.59
Note:   The above computation assumes that the system load can be met in future years both by the existing and proposed systems.                                                                                  (D
The growth rate and discount rate has been expressed as per unit factors
The table provides muhiplying factors that convert the present year benefits to that of the discounted benefits of a period of future years                                                               LA
If the perriod of benefits starts in a future year a subtraction of the relevant factors in the table will provide the appropriate multiplying factor



PRESENT WORTH FACTORS OF REIABIUTY BENEFITS OF FUTURE YEARS
1991      1992      1992      1993      1994      1995      1996      1997      1998      1999      2000       2001      2002      2003      2004       2005      2006
1,05 GRF NTHtRATE             1.1 .INTERESTRATE
Increased reliabiliy p.u.
-with load growth                 1.00      1.05      1.10      1.16       1.22      1.28      1.34      1.41      1.48      1.55      1.63      1.71       1.80      1.89      1.98      2.08       2.18
Dtscount 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       0.29      0.26      0.24      0.22
P.W. reliabil1y benefits           1.00      0.95      0.91      0.87      0.93      0.79      0.76      0.72       0.69      0.66      0.63      0.60      0.57       0.55      0,52      0.50      0.48
Cumilatve PW of benefts            1.00      1.95      2.87      3.74      4.57      5.36      6.11      6.84       7.53      6.18      8.81      9.41      9.98      10.53     11.05     11.55      12.02
1.07 -GROWTHIRATE             1.1 .INTERESTRATE
Increased reliabilny p.u.
-with load growth                 1.00      1.07      1.14      1.23       1.31      1.40      1.50      1.61      1.72      1.94      1.97      2.10      2.25       2.41      2.56      2.76       2.95
Discount 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       0.29      0.26      0.24      0.22
P.W. reliability benefits          1.00      0.97      0.95      0.92      0,90      0.97      0.85      0.82       0.90      0.79      0.76      0.74      0.72       0.70      0.68      0.66      0.64
Cumilativo PW of benefts           1.00      1.97      2.92      3.84      4.73      5.61      6.46      7.26       8.08      8.96      9.62     10.35     11.07      11.77     12.45     13.11      13.75
1. 0 9 - GPaVVTH RATE         1.1 .INTEREST RATE
Increased reliabilky p.u.
-with toad growth                 1.00      1.09      1.19      1.30       1.41      1.54      1.69      1.83      1.99      2.17      2.37      2.58      2.81       3.07      3.34      3.64       3.97
Discount factor                    1.00      0.91      0.83      0.75      0.69      0.62      0.56      0.51       0.47      0.42      0.39      0.35      0.32       0.29      0.26      0.24      0.22
P.W. reliabilty benefits           1.00      0.99      0.98      0.97      0.96      0.96      0.95      0.94       0.93      0.92      0.91      0.90      0.90       0.89      0.88      0.87      0.86
Cumilative PW of benefits          1.00      1.99      2.97      3.95      4.91      5.87      6.81       7.75      8.68      9,60     10.51     11.42     12.31      13.20     14.08     14.95     15.82
1.11 -GROWTH RATE             1.1 -INTEREST RATE
Increased reliabiliy p.u.
-with load growth                 1.00      1.11      1.23       1.37      1.52      1.69      1.87      2.08      2.30      2.56      2.84      3.15      3.50       3.88      4.31      4.78       5.31
Discount 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       0.29      0.26      0.24      0.22        1
P.W. reliabiliy benefits           1.00      1.01      1.02      1.03      1.04      1.05      1.06       1.07      1.08      1.08      1.09      1.10      1.11       1.12      1.14      1.15       1.16       -
Cumilative PW of baneffls          1.00      2.01      3.03      4.05      5.09      6.14      7.19      8.26       9.33     10.42     11.51     12.62     13.73      14.86     15.99     17.14     18.29        o
C
1.0 5 -GROWTH RATE           1.06 - INTEREST RATE
Inoreased reliabiliy p.u.
-with load growth                 1.00      1.05      1.10      1.16       1.22      1.28      1.34      1.41      1.48      1.55      1.63      1.71       1.80      1.89      1.98      2.08       2.18
Discoun1 factor                    1.00      0.93      0.86      0.79      0.74      0.68      0.63      0.58       0.54      0.50      0.46      0.43      0.40      0.37       0.34      0.32      0.29
P.W. reliabiliy bono8ats           1.00      0.97      0.95      0.92      0.89      0.87      0.84      0.82       0.80      0.78      0.75      0.73      0.71      0.69       0.67      0,66      0.64
Cumilabtive PW of baneafs          1.00      1.97      2.92      3.84      4.73      5.60      6.44       7.26      8.06      8.84      9.59     10.33     11.04      11.73     12.41     13,06     13.70
* 1.07-GROWTHRATE               1.08 - INTEPEST RATE
Increased reliability p.u.
-with load growth                 1.00      1.07      1.14      1.23       1.31      1.40      1.50      1.61      1.72      1.84      1.97      2.10      2.25       2.41      2.58      2.76       2.95
Discount factor                    1.00      0.93      0.86      0.79      0.74      0.68      0.63      0.58       0.54      0.50      0.46      0.43      0.40      0.37       0.34      0.32      0.29
P.W. reliabilfy benafits           1.00      0.99      0.98      0.97      0.96      0.95      0.95      0.94       0.93      0.92      0.91      0.90      0.89      0.99       0.60      0.7      0.86
Cumilotive PW of banefis           1.00      1.99      2.97      3.04      4.91      5.86      6.81       7.75      8.67      9.59     10.50     11.41     12.30      13.19     14.07     14.94     15.80
1.09 o hGROWTH RATE          1.06 -INTERESTRATE
Increased reliabilly p.u.
-with load growth                 1.00      1.09      1.19      1.30       1.41      1.54      1.68      1.83      1.99      2.17      2.37      2.58      2.81       3.07      3.34      3.64       3.97
Discount factor                    1,00      0.93      0.96      0.79      0.74      0.66      0.63      0.59       0.54      0.50      0.46      0.43      0.40      0.37       0.34      0.32      0.29
P.W. reliabilRy benefits           1.00      1.01      1.02      1.03      1.04      1.05      1.06       1.07      1.08      1.09      1.10      1.11      1.12       1.13      1.14      1.15      1.16
Cumilative PW of benefits          1.00      2.01      3.03      4.06      5.09      6.14      7.20       8.26      9.34     10.43     11.52     12.63     13.75      14.87     16.01     17.16     18.32           -
Note:   The above computation assumes that the system load coan be mat In future years both by the existing and proposed systems.                                                                                 CD
The growth rata and disocount rate has been expressed as per unit factors
The table provides muhiptying factors that conver the present yaar benefits to that ot the discounted beneft0s of a period of future years
It the perriod of benefits starts in a future year a subtraction of the relevant factors in the table will provide the appropriate multiplying factor



PRESENT WORTH OF LOSS REDUCTION AND RELIABILITY BENEFITS OF FUTURE YEARS
WITH VARIABLE GROWTH RATES BETWEEN SUB-PERIODS
YEAR OF COMMENCEMENT OF SUB PERIOD
1.1 = Discount factor
1990      1 993       1998      2001        2005       2007       2010
Load growth rate p.a.                                    1.08       1.05       1.04       1.03       1.02        1.01
Load at year as pu. of load in yr. 1                        1       1.26       1.61       1.81       2.04        2.12       2.18
Loss red. benefits as pu. of benefits in yr. 1              1       1.59       2.58       3.27       4.14        4.48       4.76
Reliab. benefits as pu. of benefits in yr. 1                1       1.26       1.61       1.81       2.04        2.12       2.18
Benefit growth per yr./discount fac.
- loss reduction                                       1.060      1.002     0.983       0.964      0.946      0.927
- reliability                                         0.982      0.955      0.945      0.936       0.927      0.918
Years in sub period (from yr. in column to yr. in next colui  3        5          3          4          2           3
Present Worth (to begining) of sub period
loss reduction                                          3.18       7.97       7.63      12.40       8.06      12.50
reliability                                             2.95      5.75       4.56        6.57       3.92       5.85                           1
Present Worth factor for Yr. to yr. 1                   1.000      0.751      0.467      0.350      0.239      0.198                           F-
TOTAL      TOTAL
PRESENT WORTH FACTORS           '90-'08    '93-'08
loss reduction                  21.48    18.296       3.185      5.988      3.557      4.347       1.930      2.473
reliability                     13.80    10.850       2.946      4.321      2.130      2.304      0.939       1.157
Note: (1) The above is an example of a Lotus format prepared in order to calculate
the present worth of benefits of loss reduction and reliability improvements over a period
of analysis where the load growth varies in each sub period.
(2) The second total column allows the benefits from the first period to be omitted.
(3) The variables are: discount rate, length and no. of sub periods, growth rate in each sub period.
(4) The benefits in the first year (1990 in this case) when muntiplied by the present worth factor (in the total column)
will provide the present worth of benefits of the total period discounted to the first year (1990)
-H
a-
a



I



ANNEX E
ECONOMIC ANALYSIS FOR DISTRIBUTION SYSTEM DEVELOPMENT



I



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Annex E
ECONOMIC ANALYSIS FOR DISTRIBUTION SYSTEM DEVELOPMENT
List of Tables
Cost benefit analysis for development proposals
Dar es Salaam
E.1.1       - 30 MVA grid SS at Wazo Hill and 5 MVA primary SS at Kunduchi
E.1.2       - 15 MVA primary SS at Msasani Peninsula
E.1.3       - 15 MVA primary SS at Sokoine Drive
E.1.4        - 5 MVA primary SS at Chang'ombe
E.1.5        - 5 MVA primary SS at Mwembe-Chai
E.1.6        - 5 MVA primary SS at Mbagala
Cost benefit analvsis for development proposals
Tanga region
E.2.1       - 20 MVA grid SS at Cement Mill
E.2.2        - 15 MVA primary SS at Sahare
E.2.3.1     - 5 MVA primary SS at Lushoto
E.2.3.2     - Conversion to 33 kV, Lushoto-Bumbuli
E.2.4       - Developments to Korogwe North area
E.2.4. 1    - 2.5 MVA primary SS at Kwamndoluwa
E.2.4.2     - Conversion to 33 kV with existing copper conductors
E.2.4.3     - Conversion to 33 kV with new 100 mm.sq. conductors
E.2.5       - Developments to Korogwe West area
E.2.5. 1     - Conversion to 33 kV with existing copper conductors
E.2.5.2      - Conversion to 33 kV with new 100 mm.sq. conductors
E.2.6       - 5 MVA primary SS at Kibaranga
Cost benefit analysis for development proposals
Moshi region
E.3.1       - 5 MVA primary SS at Majengo
E.3.2       - conversion to 33 kV, Makombone
E.3.3       - 66 kV line to Marangu
Cost benefit analysis for development proposals
Arusha region
E.4.1        - 33 kV line conversion Monduli feeder
E.4.2        - 5 MVA primary SS at Magereza
E.4.3       - 5 MVA primary SS at Mt. Meru hotel
E.5.1        Summary of requirements for MV rehabilitation and transformers for LV
rationalization
E.5.2       Summary of requirements for LV rehabilitation and reinforcement



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Annex E
(cont'd)
List of Tables
Cost benefit analysis for rehabilitation of MV and LV systems
E.6.1       - Dares Salaam
E.6.2       - Tanga
E.6.3       - Moshi
E.6.4       - Arusha
E.7          Cost-benefit anaylsis of LV rationalization
E.8.1       Sample calculation of cost-benefit analysis for individual system expansion works
E.8.2       Total costs of network expansion



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COST BENEFIT ANNALYSIS FOR
PROPOSED 30 MVA GRID SUBSTATION AT WAZO HILL AND 5 MVA PRIMARY SUBSTATION AT KUNDUCHI                       TABLE E 1.1 pg 1
(1) LOAD CHARACTERISTICS OF AFFECTED FEEDERS
Period          '90-'93     '93-'96     '96-'99      99-'02     '02-'05     '05-'08
(1.1) Lood growth characteristics
Estimoted load growth pu. for feeders                              0.07        0.07        0.07        0.07        0.07        0.07
Estimated load growth pu. for cement fac.                        0.015       0.015        0.015       0.015       0.015       0.015
YEAR       1990        1993        1996        1999        2002        2005        2008
(1.2) Peak Load in MW
Cement Factory load                                   7.100      -7.424       7.763       8.118       8.489       8.877       9.282
Kunduchi SS load                                      2.267       2.777       3.402       4.168       5.106       6.255       7.662
Mbezi - Kunduchi feeder                               0.800       0.980       1.201       1.471       1.802       2.207       2.704
Total Load affected by loss red/n
and reliability improvement                        10.167      11.181     12.366       13.757      15.396      17.338      19.648
Overall load growth p.a.                                           3.19        3.38        3.58        3.79        4.00        4.21
New load at Mbezi SS                                  4.936       6.047       7.408       9.075      11.117      13.619      16.683
(1.3) Annual energy in GWH
0.85 = Load fartor for Cement Fadory
0.65 = Load factor for all feeders
Cement Factory load                                 52.867      55.281      57.807       60.447      63.208      66.096      69.115
Kunduchi SS load                                     12.908      15.813      19.371      23.731      29.071      35.613      43.628
Moezi - Kunduchi feeder                               4.555       5.580       6.836       8.375      10.259      12.568      15.396
Total Load affected by loss red/n
and reliability improvement                       70.330      76.675      84.014       92.552    102.539    114.277    128.139
Overall load growth p.a.                                           2.89        3.06        3.25        3.44        3.64        3.85
New load at Moezi SS                                28.106      34.430      42.179      51.671       63.299      77.544      94.995
12) CONCLUSIONS FROM ESTIMATED LOAD DISTRIBUTiON:
Capocity of Kunduchi SS                                     1 -5 MVA by (1993) with augmentation to 2 5 MVA by Yr. 2000
Capacity required at existing Mcezi SS                      Existing 1 - 15 Mva is sufficient up to 6eyond Yr. 2000
Estimation of benefits -            76.7 GWH of sales 6y 1993 increasing at 3% pa. will 6e benefitted 6y
(1) Loss reduction as calculated 6elow on an analysis by feeder
(2) Additional capacity provided ta meet new loads
and      (3) Reliability benefits estimated by outages saved (as % of total sales)
(3) CAPITAL WORKS (all costs in S 000's)
Grid SS                                                                 Unit                (ty         Rate        Cost
132/33 kV transformer 30 MVA                                           nos                   1         450         450
132 kV incommer                                                        nos                   1         220         220
33 kV feeder CB units                                                  nos                   4         120         480
Substation structure & auxiliaries                                     item                  1         100         100
33 kV feeders dc 100 mm sq                                             krm                   5          35         175
Primary SS
33 kV feeder CB units                                                  nos                   2         120         240
33/11 kVtransformerS MVA                                               nos                   1         170         170
11k V CB units                                                         nos                   6          55         330
Substation structure & auxiliaries                                     item                  1          50          50
11 kVfeeders                                                           km                    3          21          63
TOTAL COST (Work proposed in 1991)                               2278
Cost of augmentation of Kunduchi SS in 2000                        345
Total Costs discounted to 1990                                    2204



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COST BENEFIT ANNALYSIS FOR                                                                           TABLE E 1.1  pg 2
PROPOSED 30 MVA GRID SUBSTATION AT WAZO HILL AND S MVA PRIMAY SUBSTATION AT KUNDUCHI
(4) COMPUTATION OF BENEFTS            -
(4.11 LOSS REDUCTION BENEFITS            0.1 =Energy cost S/k*h (ot dist.)           0.25 =Energy cost at dist less up streem
0.35 =Loss load factor, feeders               1.1 = discouni factor
0.85 =Loss load factor for cement fcc.
Original system losses 1990                  Proposed system losses 1990
Feeder                Losses kW              Feeder                Losses kW
Kunduchi 11 IkV F            366             K/SS 11k Vfeeders              9
Ub - Mbezi 33 kV              36             Mbezi-K 11kV feed.             4
W/Hill cement fac.           300             Ub - Mbezi 33 kV              21
U6 - new G/SS                  3
Total loss                                   Totol Ioss
W/Hill cement fac.           300             W/Hill cement fac.             3
Other feeders                402             Other feeders                 37
Loss reduction benefits fTom 1993
1990     1990        Value of benefts in S 000's
KW    KVvH       Yr. 1990    MF '               Period '93-'08
W/Hill cement fac.           297   2211462   221.146          9.87              2182.712
otherfeeders                 365   1118814    111.881        20.15              2254.410
TOTAL            662   3330276   333.028                            4437.123
Value of benefits discounted to 1990 S 000's                         3333.676
BENEFIT/COST RATIO WITH LOSS REDN. BENEFITS ONLY                                      1.5
(4.2) BENEFITS FROM ADDmONAL CAPACITY TO SUPPLY NEW LOADS
YEAR            1993        1996       1999       2002        2005       2008
New Kunduchi SS load                                         2.777      3A02       4.168       5.106      6.255       7.662
Load which could 6e supplied by formner network              2.000      2.000      2.000       2.000      2.000       2.000
New load possible by additional capacity                     0.777      1.402       2.168      3.106      4.255       5.662
p.u growth of additional capacity                                       0.217      0.156       0.127      0.111       0.100
PW to 1993, new Kunduchi SS load (15 years from 1993) GWH                         34.575       12.45 =MF-
PW to 1993 possible supply (15 years from 1993) with existing system GWH          16.740        8.37 =MF
PW Ito 1993) of benefits from new capacity in S 000's                               4459
Vadue of benefits discounted to 1990, S 000's                                       3350
BENEFIT/COST RATIO WITH LOSS REDN. PWS NEW CAPACITY                                   3.0
(4.3) REUABIUTY BENEFITS
Estimated    Sensitivity for variations in % units saved
Values   and cost value of saved energy
Est. outagessaved as % of annual energy                        1.5         1.5          1          1         0.5        0.5
Est. outages saved 1993 GWH                                  1.150      1.150       0.767      0.767      0.383       0.383
PW fac. (MF) of relicb. benefits (I5yrs.ct 3% Load.gr.)       9.85       9.85        9.85       9.85        9.85       9.85
PW outages saved 15 yrs from 1993 discounted to 1990. (GWH)  8.511      8.511       5.674      5.674      2.837       2.837
Volue of relia6ility benefits
Value soved outages - multiple of energy cost                   10          5           5          3           3          2
PW reliability benefits $ 000's                              8511        4256       2837        1702        851         567
Total 6enefits (1ass redn & reliabi.) 5000's                17407       13152      11733       10598       9747        9463
BENEFIT/COST RATIO WTH ALL BENEFITS USTED ABOVE                7.9         6.0        5.3         4.8        4.4         4.3
Note:    MF - Provides the muntiplying factor for PW of benefits extended
over a given period taing into account the load growth (see annex 2)



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COST BENEFIT ANALYSIS FOR                                                                              TABLE E 1.2
PROPOSED PRIMARY SUBSTATION 15 MVA AT MSASANI PENINSULAR                                               pg. 
(1) LOAD CHARACTERISTICS OF AFFECTED FEEDERS
Period       '90-'93   '93-'96   '96-'99   '99-'02    '02-'05   '05-'08
Estimated load growth pu. for all leeders     0.05       0.05      0.03      0.02       0.02      0.02
YEAR                                          1990      1993       1996      1999      2002      2005       2008
New Msasani substabon feeders
FeederF1 Amps                                  101       117        135       148       157        167       177
FeederF2 Amps                                  109       126        146       160       169        180       191
Feeder F 3 Amps                                167       193       224        245       260        275       292
Total load Amps                                377       436        481       558       616        680       751
TotaldemandonSS(MVA)                         7.183      8.315     9.168    10.628    11.734    12.955    14.303
System peak loads - affected sectfons
NewsubstafionloadMW                          6.465      7.484     8.663     9.467    10.046    10.661    11.314
MK1andO2&06loadMW                            4.218      4.883     5.653     6.177      6.555     6.957     7.382
Total load MW                               10.683    12.367    14.316    15.644    16.601    17.618    18.696
Overall load growth p.a.                                 4.95      4.95      2.97       1.98      1.98       1.98
Av.load factor            0.65
TotalenergyMWH                               60829    70418    81517    89076    94528   100314   106454
Overall load growth p.a.                                 4.95      4.95      2.97       1.98      1.98       1.98
(2) CONCLUSiONS FROM ESTIMATED LOAD DISTRIBUTION
Capacity of Msasani Substation:    1 x 15 MVA is sufficient up to and beyond Yr.2000
Estimation of benefits: (1) Loss reduction as calculated below on an analysis by feeder.
(2) The Oyster Bay substation is already fully loaded (considering also the other feeders not indicated above.
Thus the cost of augmenting the existing SS to 2*15 may be set off as being avoided costs.
Since the above avoided cost is taken account of no aditional benefits from new consumers
are included in the analysis.
(3) Reliability benefits estimated by outages saved (as % of total sales).
(3) CAPITAL WORKS (all costs in $ 000's)
Unit            Qty       Rate      Cost
33 kV S.C.Iine 100 mm sq ACSR                                km               5.3        23       122
33 kV feeder CB units                                        nos                2       120       240
33/11 kV transformer 15 MVA                                  nos                1       225       225
11 kV feeder CB units                                        nos                4        55       220
Substation structure & auxiliaries                           item               1        50        50
11 kV line 100 mm sq ACSR                                    km                6         21       126
TOTAL COSTS                                    983
Avoded Costs of augumentation of Oyster Bay SE  225
(only the cost of one 15 MVA Tt. is included
as the existing 3*5 MVA Tf. will be recovered)
NET COSTS FOR ECONOMIC ANALYSIS                758
Net Costs discounted to 1990                   689
NOTE: Expenditure is assumed in 1991 and benefits are computed from 1993                    Cont. pg.2



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COST BENEFIT ANALYSIS FOR                                                                      TABLE £ 1.2
PROPOSED PRIMARY SUBSTATION 15 MVA AT MSASANI PENINSULAR (CONT)                                pg. 2
(4) COMPUTATION OF BENEFITS
(4.1) LOSS REDUCTION BENEFITS                    0. 1 = Energy cost $/KWH        1.1 =Discount factor
0.35 = Feeder load loss factor
Original system losses 1990               Proposed system lossBs 1990
Feeder      Amps       Losses kW          Feeder       Amps      Losses kW
06               120         24           06                 32          1
0 3              296       335            0 3              119         18
MK1              155        78            MK1               95         16
OIBAY33K1       260        376            F 1              101          7
MK 33KV                                   F 2              109         11
F3                68         4
F4                99         7
OIBAY33K1        208       240
TO MS33KV        126        83
MK 33KV
TOTAL                      814            TOTAL                       388
Loss reduction benefits from 1993:-
1990      1990                       VALUE OF BENEFITS
KW       KWH        MF*            1993 - 2008 discounted to1990
All feeders                426  1306718        12.58                 1644
BenefiVCost ratio considering only loss red.                          2.4
(4.2) RELIABILITY BENEFITS
Estimate(    Sensitvity for variations in % units saved
Values      and cost of saved energy
Est. outages saved as % of annual energy                    1.5        1.5         1          1        0.5       0.5
Est. outages saved 1990 loads (MWH)                        912        912        608       608        304        304
PW fac. reliability benefits '93-08 (MF')                  8.83      8.83       8.83       8.83      8.83       8.83
PW outages saved 1993 to 2008 MWH                         8057       8057      5371       5371       2686      2686
Value of reliability benefits
Value saved outages - multiple of energy cost                 8         5          5          3         3          2
PW-reliability benefits $ 000's                           6445       4028      2686       1611        806        537
TOTAL BENEFITS (loss redn & reliabi.) $000's              8089       5672      4329       3255       2450       2181
Benefit / Cost ratio                                       11.7        8.2       6.3        4.7        3.6       3.2
Note:    MF - Provides the muntiplying factor for PW of benefits discounted to 1990
extended over a given period from 1993 (taking into account the load growth effects (see annex D)



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COST BENEFIT ANALYSIS FOR
PROPOSED PRIMARYSUBSTATION 15 MVA AT SOKONI DRIVE                                            TABLEE11.3
(1) ESTIMATED LOAD DISTRIBUTION
Period       '90-'93    93-'96    96-199   '99-'02   '02-'05    '05-'08
Estimated load growth pu.                      0.07       0.07      0.06      0.03       0.02      0.02
YEAR                                           1990      1993      1996       1999      2002       2005
New Sokoini Drive Sub Station
Total feeder load in Amps                       367       450        505       586        647       714
Total substation load MVA                     6.992      8.566     9.625    11.158    12.319    13.601
Newsubstation load MW                         6.293     7.709      8.662    10.042    11.087    12.241
c 3, 04, C8 Load MW                           8.500     9.095      9.732    10.316    10.625    10.838
Total load MW                                14.793    16.804    18.394    20.358    21.712    23.079
Overall load growth p.a.                                  4.30      3.03       3.40      2.15       2.03
Av.load factor            0.65
Total energy MWH                             84233    95685   104736   115916   123630   131410
Overall load growth p.a.                                  4.30      3.03      3.40       2.15       2.03
(2) CONCLUSIONS FROM ESTIMATED LOAD DISTRIBUTION
Capacity of Sokoini Drive SS.             1 15 MVA is sufficient up to and beyond Yr.2000
Estimation of benefits                   (1) Loss reduction as calculated below on an analysis by feeder.
(2) The City Center substabon would be fully loaded by 1993
Thus the cost of augmenting the existing SS to 21 5 may be set off as being avoiaA  -k
Since the above avoided cost is taken account of no aditional benefits from new co
are included in the analysis.
(3) Reliability benefits estmated by outages saved (as % of total sales).
(2) CAPITAL WORKS (all costs in S 000's)
Unit      Oty       Rate       Cost
33 kV S.C.Iine 100 mm sq ACSR                                 km               3.8        23         87
33 kV feeder CB units                                         nos                2       120       240
33/11 kV transformer 15 MVA                                  nos                 1       225       225
11 kV feeder CB units                                         nos                5        55       275
Substation structure & auxiliaries                           item                1        50        50
11 kVline100mmsqACSR                                          km                 1        21        21
TOTAL COST                 898
Avoded Costs of augumentabon of City Center SS            225
(only the cost of one 15 MVA Tf. is included
as the existing 3 5 MVA Tf. will be recovered)
NET COSTS FOR ECONOMIC ANALYSIS                           673
Net Costs discounted to 1990                              612
NOTE: Expenditure is assumed in 1991 and benefits are computed from 1993                      Cont pg.2



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COSTBENEFITANALYSIS FOR                                                                       TABLE x1.3
PROPOSED PRIMARY SUBSTATION 15 MVA AT SOKONI DRIVE (Cont)                                     pg. 2
(4) COMPUTATION OF BENEFITS
(4.1) LOSS REDUCTION BENEFITS                   0.1 = Energy cost $/KWH         1. 1 =Discount factor
0.35 = Feeder load loss factor
Original system losses 1990               Proposed system losses 1990
Feeder    Amps      Losses kW            Feeder    Amps       Losses kW
C3              240         27            C3               32         12
C4              270         64           C4               119         11
C8              180         19           C8                95         17
IL-City         320        254           SK1              101          4
Center 33 kV                             SK2              109          5
SK3              68          2
SK4              99          4
IL-CC           198         97
IL-SkD          122         56
TOTAL                      364           TOTAL                       208
Loss reduction benefits from 1993:-
1990      1990                      VALUEOFBENEFITS
KW       KWH        MF'            1993 - 2008 discounted to1990
All feeders                156   478333       17.70                  847
BenefittCost ratio considering only loss red.                        1.4
(4.2) REUABILITY BENEFITS
Estimate(    Sensitvity for variations in % units saved
Values     and cost of saved energy
Est outages saved as % of annual energy                    1.5       1.5          1         1        0.5       0.5
Est. outages saved 1990loads (MWH)                       1263      1263        842        842       421        421
PWfac. reliability benefits 93-08 (MF-)                   10.4      10.4       10.4      10.4       10.4      10.4
PW outages saved 1993 to 2008 MWH                       13140     13140       8760      8760       4380       4380
Value of reliability benefits
Value saved outages - multple of energy cost                8          5          5         3          3         2
PW reliability benefits $ 000's                         10512      6570       4380       2628      1314        876
TOTAL BENEFITS (loss redn & reliabi.) $O0's             11359       7417      5227       3475      2161       1723
Benefit I Cost ratio                                      18.6      12.1        8.5       5.7        3.5       2.8
* Note:    MF - Provides the muntplying factor for PW of benefits discounted to 1990
extended over a given period from 1993 (taking into account the load growth effects (see annex  > '



-193-
cb-Chang                                                                                      Table E 1.4
COST BENEFIT ANNALYSIS FOR NEW PRIMARY SUBSTATIN AT CHANG'OMBE
6 = %load growth             0.1 = Energy costs $/KWH
1 5 = analysis period        0.35 = loss load factor
1.124 = loss gr.fac. pa.         1.1 = discount factor pa.
17.48 = P.W. factor for loss redn. over period of analysis
COMPUTATION OF BENEFITS:
(a) LOSS REDUC77ON BENEFITS
1991      1991      1993
KW    KWH/yr.  KWH/yr.
Existing line losses                 638 1,956,108 2,469,541
Losses after new dev.                274   840,084 1,060,587
Peak loss savings                    364 1,116,024 1,408,955
Value of savings 1993-2008 in $ 000's                    2462
Value of savings discounted to 1991                      2035
COST OF CAPITAL WORKS in $ 000's
Qty.      rate      Cost
33 kV line 100 mmsq.                            0.7       22.8      16.0
Substation Costs:
Transformer 5 MVA 33/11 kV                        1      170.1     170.1
33 kV circuit breaker and bay                     1      123.0     123.0
1 1 kV circuit breaker and bay                    5      49.2      246.0
Total Cost (assumed in 1992) US $000's                  555.1
Cost discounted to 1991                                 504.6
Benefit/Cost ratio considering loss reduction benefits only  4.0
(b) RELIABILITY BENEFITS
Estimated    Sensitivity for variations in % units saved
Values     and cost of saved energy
Est outages saved as % of annual energy                    1.5       1.5         1          1        0.5       0.5
Est. outages saved 1991 loads (MWH)                       460       460        307        307       153        153
PW fac. reliability benefits '93-08 (MF*)                 10.4      10.4       10.4      10.4       10.4      10.4
PW outages saved 1993 to 2008 MWH                        4783      4783       3189      3189       1594       1594
Value of reliability benefits
Value saved outages - multiple of energy cost               8          5         5          3          3         2
PW reliability benefits $ 000's                          3826      2391       1594       957        478        319
TOTAL BENEFITS (loss redn & reliabi.) $000's             4331      2896       2099       1461       983        823
Benefit / Cost ratio (loss reducton & reliability benefits)  12.6    9.8        8.2       6.9        6.0       5.7
Note:    MF - Provides the muntiplying factor for PW of benefits discounted to 1990
extended over a given period from 1993 (taking into account the load growth effects (see annex 2)
30660 = System load in MWh (at 1991 level) benefiting by increased reliability



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cb-MbCh                                                                  Table E 1.5
COST BENEFIT ANNALYSIS FOR NEW PRIMARY SUBSTATION AT MWEMBE-CHAI
Computation factors
1.1 = discount factor p.a.
9 = % annual load growth    0.10 = Energy costs $/KWH
1 5 = analysis period        0.60 = load factor
1.188 = loss growth factor p.a  0.35 = loss load factor
27.17 = P.W. factor for loss reducton over period of analysis (MFIr)
COMPUTATION OF BENEFITS:
(a) Loss reduction benefits
1991      1991       1993
KW   MWHlyr.  MWH/yr.
Existing line losses                            866      2,655     3,748
Losses after new dev.                           345      1,058     1,493
Peaklosssavings                                 521      1,597     2,255
Value of savings 1993-2008 in $ 000's                               6127
Value of savings discounted to 1991 ($000)                          5063
COST OF CAPITAL WORKS in $ 000's
Qty.      rate      Cost
33 kV line 100 mmsq.                             1.1      22.8      25.1
Substation Costs:
Transformer 15 MVA 33/11 kV                       1      225.5     225.5
33 kV circuit brreaker and bay                    1      123.0     123.0
11 kV circuit brreaker and bay                    5       49.2     246.0
11 Kv line additions (100mmsq.)                  1.5      20.7      31.1
Total Cost (assumed in 1992) US $000's                   650.6
Cost discounted to 1991 ($000)                           591.5
Benefit/Cost rato considering loss reduction benefits only  8.6
(b) Reliability benefits
System load in MW (at 1991 level) benefiting by increased reliability  11.7
Annual load, MWh (1991) of section with reliablity improvement    102493
Estimated    Sensitivity for variations in % units saved
Values      and cost of saved energy
Estimated outages saved as % of annual energy              1.5        1.5         1         1        0.5        0.5
Estimated outages saved 1991 loads (MWH)                 1537       1537      1025       1025       512        512
PW factor for reliability benefits '93-08 (MFrb*)         10.4      10.4       10.4       10.4      10.4       10.4
PW outages saved 1993 to 2008 MWH                       15989      15989     10659      10659      5330       5330
Value of reliability benefits:
Value saved outages - multiple of energy cost                8         5          5         3          3         2
PW reliability benefits $ 000's                         12791       7994      5330       3198      1599       1066
TOTAL BENEFITS (loss redn&reliabi.)$000's               13383       8586      5921       3789      2190       1657
Benefit / Cost ratio (loss reduction & reliability benefits)  31.2  23.1       18.6       15.0      12.3       11.4
* Note:    MFrb - Provides the muntiplying factor for PW of benefits discounted to 1991
extended over a given period from 1993 (taking into account the load growth effects (see annex B)



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cb-Mb                                                                    Table E 1. 6
COST BENEFIT ANNALYSIS FOR NEW PRIMARY SUBSTATION AT MBAGALA
Computation factors
1.1 = discount factor p.a.
9 = % annual load growth    0.10 = Energy costs $1KWH
1 5 = analysis period        0.60 = load factor
1.188 = loss growth factor p.s  0.35 = loss load factor
27.17 = P.W. factor for loss reduction over period of analysis (MFIr)
COMPUTATION OF BENEFITS:
(a) Loss reduction benefits
1991      1991      1993
IKN   MWH/yr.  MWH/yr.
Exisling line losses                             82       251        355
Losses after new dev.                            28        86        121
Peaklosssavings                                  54       166        234
Value of savings 1993-2008 in $ 000's                                635
Value of savings discounted to 1991 ($000)                           525
COST OF CAPITAL WORKS in $ 000's
Oty.      rate      Cost
33 kV line 100 mmsq.                             1.4      22.8      31.9
Substation Costs:
Transformer 5 MVA 33/11 kV                        1      170.1     170.1
33 kV circuit brreaker and bay                    1      123.0     123.0
11 kV circuit brreaker and bay                    3       49.2     147.6
11 KV line additions (100mmsq.)                   1       20.7      20.7
Total Cost (assumed in 1992) US $000s                    493.3
Cost discounted to 1991 ($000)                          448.5
BenefiVCost ratio considering loss reduction benefits only  1.2
(b) Reliability benefits
System load in MW (at 1991 level) benefiting by increased reliability  4.873
Annual load, MWh (1991) of section with reliablity improvement    42688
Estimated    Sensitivity for variations in % units saved
Values     and cost of saved energy
Estimated outages saved as % of annual energy              1.5       1.5         1          1        0.5       0.5
Estimated outages saved 1991 loads (MWH)                  640       640        427       427        213       213
PW factor for reliability benefits 93-08 (MFrb*)          10.4      10.4       10.4      10.4       10.4      10.4
PW outages saved 1993 to 2008 MWH                        6659      6659       4440      4440       2220      2220
Value of reliability benefits:
Value saved outages - multiple of energy cost                8         5          5         3          3         2
PW reliability benefits $ 000's                          5327      3330       2220       1332       666        444
TOTAL BENEFITS (loss redn & reliabi.) $000's             5776       3778      2668       1780      1114        892
Benefit / Cost ratio (loss reduction & reliability benefits)  14.0   9.6        7.1       5.1        3.7       3.2
* Note:    MFrb - Provides the muntiplying factor for PW of benefits discounted to 1991
extended over a given period from 1993 (taking into account the load growth effects (see annex B)



-196-
PROPOSED GRID SUBSTATION 30 MVA AT TANGA CEMENT FACTORY                                 TABLE E 2.1
ESTIMATED LOAD DISTRIBUTION
Period                                             '90-'93   '93-'95   '95-'97   '97-'00   '00-'02   '02-'05
Estimated load growth pu. for feeders                 0.07      0.07     0.07      0.07      0.07      0.07
Estimated load growth pu. for cement fac.              0.7    0.015     0.015     0.015         0         0
YEAR                                    1990          1993     1995      1997      2000      2002      2005
Cement Factory load MW                    10.000    17.000    17.514    18.043    18.589    18.589    18.589
Moafeeder MW                               1.000     1.145     1.311    1.501     1.838     2.105     2.579
Bushiri feeder MW                          1.000     1.225     1.403    1.606     1.967     2.252     2.759
Totalload MW                              12.000    19.370   20.227    21.150   22.394    22.946    23.926
CAPITAL WORKS (costs in $ 000's)
Unit      Qty      Rate      Cost
132/33 kV transformer 30 MVA                              nos               1      450       450
132 kV incommer                                           nos               1      220       220
33 kV feeder CB units                                     nos               6      120       720
Substation structure & auxiliaries                       item               1      100       100
TOTAL COST                                                                                  1490
COMPUTATION OF BENEFITS
(a) LOSS RECDUCTION BENEFITS                 0.1 =Energy cost $/kwh                          0.35
and loss load factors   0.35 For feeders
0.85 For cement fac.
Original system losses 1993            Proposed system losses 1990
Feeder    Amps     Losses kW           Feeder    Amps     Losses kW
K 1                       52           K 1/1                      2
K2                        52           K 2/1                      2
Cement                   490           K 1 /2                     2
K 2 /2                     2
Cement                    1 0
Total loss                             Total loss
Cement         490                     Cement           10
Feeders        104                     Feeders           8
kW        $ 000's



-197-
Loss reduction benefits 1993
1993     1993  VALUE in $ 000s
KW      KWH       1993     MF  Value'93-'06
Cement         480  1471680   147.168       7.04 1036.063
Feeders         96   714816   71.482       20.74  1482.528
TOTAL          576  2186496  218.650             2518.591
Value of loss redn. benefits 1993 - 2003
(b) RELIABILITY BENEFITS
Sections wth enhanced reliability
Period                                          '90-'93   '93-'95   '95-'97   '97-'00   '00-'02   '02-'05
Estimated load growth pu. for feeders                 0.07      0.07     0.07      0.07      0.07      0.07
Estimated load growth pu. for cement fac.              0.7    0.015     0.015    0.015         0         0
Estimated load growth pu. for Tanga & ass.            0.04      0.04     0.04      0.04      0.04      0.04
YEAR                                    1990         1993      1995      1997      2000     2002      2005
CementFactoryload MW                      10.000    17.000    17.514    18.043    18.589    18.589    18.589
Moafeeder MW                               1.000     1.145     1.311    1.501     1.838     2.105     2.579
Bushiri feeder MW                          1.000     1.225     1.403    1.606     1.967     2.252     2.759
TangacityandK1 K2loads                     7.000     7.874     8.857    9.963    11.207    12.607    14.181
Total load MW                             19.000   27.244   29.084    31.113   33.601    35.552   38.107
Overall load growth p.a.                             12.63      2.18     2.25      2.57      1.88      2.32
Energy cement fac. (85%1f) MWH            74460   126582   130408   134350   138410   138410   138410
Energyotherloads(65%lf)MWH                51246    58329    65883    74419    85483    96591   111137
Total energy MWH                          125706   184911   196291   208768   223893   235001   249547
Overall load growth p.a.                             13.58      1.99     2.05      2.34      1.61      2.00
Est. outages saved as % of annual energy                5         5         3         3         1        1
Est. outages saved 1993 MWH                          9246      9246      5547      5547     1849      1849
PW fac. reliability benefits '93-06 at 2% gr.         7.15      7.15     7.15      7.15      7.15      7.15
PW outages saved 1993 to 2006 MWH                   66106    66106    39663    39663    13221    13221
Value of reliability benefits
Value saved outages - multiple of energy cost            5        1         5         1         5         1
PW reliabiliy benefits $ 000's                      33053      6611    19832       3966     6611      1322
Total benefits (loss redn & reliabi.) $000's        35571      9129    22350       6485     9129      3841
Beneft I Cost ratio                                    24         6        1 5        4         6        3



-198-
cb-Sah                                                                                           Table E 2.2
COST BENEFIT ANALYSIS FOR NEW PRIMARY SUBSTATION AT SAHARE
Computation factors
1.1 = discount factor p.a
6 = % annual load growth     0.10 = Energy costs $/KWH
1 5 = analysis period         0.75 = load factor
1.124 = loss growth factor p.E   0.40 = loss load factor
17.48 = P.W. factor (MFlr') for loss reduction over analysis period indicated above
COMPUTATION OF BENEFITS:
(a) Loss reduction benefits
1991      1991       1993
KW   MWH/yr.  MWH/yr.
Existing line losses                             122        427        540
Losses after new development                      92        322        407
Peak loss savings                                 30        105        133
Value of savings 1993-2008 in $ 000's                                  232
Value of savings discounted to 1991 ($000)                             192
COST OF CAPITAL WORKS in $ 000's
Oty.      rate       Cost
33 kV line 100 mmsq.                                1      22.8       22.8
Substation Costs:
Transformer 5 MVA 33/11 kV                          1     170.1      170.1
33 kV circuit breaker and bay                       1     123.0      123.0
11 kV circuit breaker and bay                      4       49.2      196.8
11 KV line additions (100mmsq.)                     1      20.7       20.7
Total Cost (assumed in 1992) US $000's                    533.4
Cost discounted to 1991 ($000)                            484.9
BenefitCost ratio considering loss reduction benefits only   0.4
(b) Reliability benefits
System load in MW (at 1991 level) benefiting by increased reliability  4.6
Annual load, MWh (1991) of section with reliability improvement     40297
Estimated    Sensitivity for variations in % units saved
Values      and cost of saved energy
Estimated outages saved as % of annual energy                1.5        1.5         1          1        0.5        0.5
Estimated outages saved 1991 loads (MWH)                    604        604       403        403        201        201
PW factor for reliability benefits '93-08 (MFrb*)          10.4       10.4       10.4       10.4       10.4       10.4
PW outages saved 1993 to 2008 MWH                          6286      6286       4191       4191       2095       2095
Value of reliability benefits:
Value saved outages - multiple of energy cost                 8          5          5          3          3          2
PW reliability benefits $ 000's                            5029       3143      2095       1257        629        419
TOTAL BENEFITS (loss redn & reliability) $000's            5514       3628      2580       1742       1114        904
Benefit I Cost ratio (loss reduction & reliability benefits)  11.8     7.9        5.7        4.0        2.7        2.3
Note:    See Annex D for determination of multiplying factors to obtain PW of benefits
over a future time period (given a constant annual load growth)
MFIr - represents the factor for loss reduction benefits and
MFrb - represents the factor for reliability benefits



-199-
CB-Lusol                                                         Table £ 2.32
COST BENEFIT ANALYSIS FOR TRANSFER OF ZELEVA-BUMBUL LOADS TO 33 kV
BY CONVERTING AND REHAB. OF EXISTING CU 25 LINES TO 33 kV
4 = %load growth               0.1 = Energy costs S/KWH
15 = analysis period           0.35 = loss load factor
1.082 = loss gr.fac. pa.           1.1 = discount factor pa.
13.36 = P.W. foctor for loss redn. over period of analysis
COMPUTATION OF BENEFITS:
1990       1990       1993
33 kV system losses                     KW    KWH/yr.  KWH/yr.
Existing line losses                   251    769566    973746
Proposed system line losses             184   564144    713822
loss savings                        67   205422    259924
Value of savings 1993-2008 in $ 000's                         347
Value of savings discounted to 1990                           261
COST OF CAPITAL WORKS in $ 000's
Qty.       rate       Cost
convertion and rehab of line                       45          14      630.0
construction of new line                            12         18      216.0
Conversion of distribution stafions
300 KVA trans.                            1       10.5       10.5
200 KVA trans.                            1        9.2        9.2
150 KVA trans.                            3        8.4       25.2
100 KVA trans.                           3         7.8       23.4
50 KVA trans.                            2        5.8        11.6
25 KVA trans.                            1          5        5.0
10 KVA trans                             7          2       14.0
Total cost                 944.9
Cost saving due to deferment of augumt. of 33/11 kv SS                 100.0
-Cost saving due to avoiding of rehab. dist stn(20%new)                 189.0
Cost saving due to avoiding of rehab. line (@8 kS/km)                  360.0
Economic costs (assumed incurred in 1992)                              295.9
Economic costs discounted to 1990                                      244.6
Benefit/Cost ratio           1.1



-2 00-
cb-kornl                                                       Table E.2.4.1
COST BENEFIT ANNALYSIS FOR ERRECTION OF A 2.5 MVA PRIMARRY SS AT KWAMNDOLWA
FOR LOSS REDUCIION OF THE KOROGWE NORTH FEEDER
3 = %load growth             0.1 = Energy costs $/KWH
1 5 = analysis period        0.35 = loss load factor
1.061 = loss gr.fac. pa.         1.1 = discount factor pa.
11.79 = P.W. factor for loss redn. over period of analysis
COMPUTATION OF BENEFITS:
1990      1990       1993
KW   KWH/yr.  KWH/yr.
Existing line losses                  41   125706   150100
Losses after new dev.                  8    24528       29288
loss savings                          33   101178   120812
Value of savings 1993-2008 in $ 000's                      142
Value of savings discounted to 1990                       107
COST OF CAPITAL WORKS in $ 000's
Qty.      rate       Cost
Conversion of 33 kV line (km)                   6.2         23     142.6
Substation Costs:
Transformer 2.5 MVA 33/11 kV                      1        125      125.0
33 kV OCB                                         1         18       18.0
11 kVOCB                                          1         10      10.0
Total Cost US $000's      295.6
Cost savings by deferment of aug. of Korogwe SS                    150.0
Economic costs (assumed incurred in 1991)                          145.6
Economic costs discounted to 1990                                  132.4
Benefit/Cost ratio          0.8
Note: In addition to the loss reduction benefits there are
reliability benefits which are not accounted for.



-201-
cb-korn3                                                          TableF2.42
COST BENEFIT ANALYSIS FOR CONVERTION OF KOROGWE NORTH FEEDER TO 33 kV
(B) Converting and rehab. the existing line CU 25 to 33 kV.
3 = %load growth               0.1 = Energy costs $/KWH
15 = analysis period           0.35 = loss load factor
1.061 = loss gr.fac. pa.            1.1 = discount factor pa.
11.79 = P.W. factor for loss redn. over period of analysis
COMPUTATION OF BENEFITS:
1990       1990       1993
KW    KWH/yr.  KWH/yr.
Existing line losses                     39    119574    142778
Proposed line losses                      4     12264       14644
jak loss sovings                          35    107310    128134
Value of savings 1993-2008 in $ 000's                         151
Value of savings discounted to 1990                           113
COST OF CAPITAL WORKS in $ 000's
Qty.       rote       Cost
converion and reha6 of line                       32.5         14      455.0
Convertion of distri6ution stations
300 KVA trans.                            1       10.5        10.5
200 KVA trans.                            1        9.2         9.2
150 KVA trans.                            2        8.4       16.8
100 KVA trans.                            2        7.8       15.6
50 KVA trans.                            7         5.8       40.6
25 KVA trans.                            3           5       15.0
Total cost                562.7
Cost saving due to deferment of augumt. of 33/1 1 kV SS                100.0
Cost saving due to avoiding of rehab. dist stn(20%new)                 112.5
Cost saving due to avoiding of rehab. line (@8 kS/km)                  260.0
Economic cost (assumed incurred in 1992)                                90.2
Economic costs discounted to 1990                                       74.5
Benefit/Cost ratio           1.5



-202-
cb-korn2                                            Table - E.2.4.3
COST BENEFiT ANNALYSIS FOR CONVERTION OF KOROGWE NORTH FEEDER TO 33 kV
(B) Constructing a new line with 100 mmsq. ACSR
3 = %load growth             0.1 = Energy costs $/KWH
1 5 = analysis period        0.35 = loss load factor
1.061 = loss gr.fac. pa. -       1.1 = discount factor pa.
11.79 = P.W. factor for loss redn. over period of analysis
COMPLUTATION OF BENEFITS:
1990      1990       1993
KW   KWH/yr.   KWH/yr.
Existing line losses                  39   119574   142778
Proposed line losses                   2      6132       7322
loss savings                          37   113442   135456
Value of savings 1993-2008 in $ 000's                      1 60
Value of savings discounted to 1990                       120
COST OF CAPITAL WORKS in $ 000's
Qty.      rate       Cost
Constructing of line (km)                      32.5         23     747.5
Conversion of distribution stations
300 KVA trans.                          1      10.5       10.5
200 KVA trans.                          1        9.2       9.2
150 KVA trans.                          2       8.4       16.8
100 KVA trans.                          2        7.8      15.6
50 KVA trans.                          7        5.8      40.6
25 KVA trans.                          3          5      15.0
Total cost                855.2
Cost saving due to deferment of augumt. of 33/11 kV SS             100.0
Cost saving due to avoiding rehab ofline 32.5 km @8k$              260.0
Cost saving due to avoiding rehab of dist.t/f (20%new)              171.0
Economic costs (assumed incurred in 1992)                          324.2
Economic costs discounted to 1990                                  267.9
Benefit/Cost ratio          0.4



-203-
cb-korwl                                                      Table E2.6 1.
COST BENEFIT ANNALYSIS FOR CONVERTION OF KOROGWE WEST FEEDER TO 33 kV
(A) Converting and rehab. the existing line CU 25 to 33 kV.
3 = %load growth             0.1 = Energy costs $/KWH
1 5 = analysis period        0.35 = loss load factor
1.061 = loss gr.fac. pa.         1.1 = discount factor pa.
11.79 = P.W. factor for loss redn. over period of analysis
COMPUTATION OF BENEFITS:
1990      1990      1993
KW    KWH/yr.  KWH/yr.
Existing line losses                  41   125706   150100
Proposed line losses                 3.5    10731      12813
loss savings                        37.5   114975   137286
Value of savings 1993-2008 in $ 000's                     162
Value of savings discounted to 1990                       122
COST OF CAPITAL WORKS in $ 000's
Oty.      rate      Cost
Constructng of line (km)                         25        14     350.0
Conversion of distribution stations
500 KVA trans.                         1         12      12.0
300 KVA trans.                         1       10.5      10.5
200 KVA trans.                         1        9.2       9.2
100 KVA trans.                         2        7.8      15.6
50 KVA trans.                          1       5.8        5.8
25 KVA trans.                          1         5        5.0
Total cost               408.1
Cost saving due to deferment of augumt. of 33/11 kV SS             100.0
Cost saving due to avoiding rehab of line 25 km @ 8k$             200.0
Economic costs (assumed incurred in 1992)                         108.1
Economic costs discounted to 1990                                   89.3
Benefit/Cost ratio         1.4



-204-
cb-korn2                                                       Table E.25. 2.
COST BENEFIT ANNALYSIS FOR CONVERTION OF KOROGWE WEST FEEDER TO 33 kV
(B) Constructing a new line with 100 mmsq. ACSR
3 = %load growth              0.1 = Energy costs $/KWH
1 5 = analysis period         0.35 = loss load factor
1.061 = loss gr.fac. pa.          1.1 = discount factor pa.
11.79 = P.W. factor for loss redn. over period of analysis
COMPUTATION OF BENEFITS:
1990      1990       1993
KW    KWH/yr.   KWH/yr.
Existing line losses                   41    125706   150100
Proposed line losses                    1      306 6      3661
loss savings                           40    122640    146439
Value of savings 1993-2008 in $ 000's                      1 73
Value of savings discounted to 1990                        130
COST OF CAPITAL WORKS in $ 000's
Oty.       rate      Cost
Constructing of line (km)                         25        23      575.0
Conversion of distribution stations
500 KVA trans.                          1         12       12.0
300 KVA trans.                          1       10.5       10.5
200 KVA trans.                          1        9.2        9.2
100 KVA trans.                          2        7.8       15.6
50 KVA trans.                           1       5.8        5.8
25 KVA trans.                           1         5        5.0
Total cost                633.1
Cost saving due to deferment of augumt. of 33/11 kV SS              100.0
Cost saving due to avoiding rehab of line 25 km @ 8k$               200.0
Economic costs (assumed incurred in 1992)                           333.1
Economic costs discounted to 1990                                   275.3



-205-
cb-kibar                                                       Table E. 2.6
COST BENEFIT ANNALYSIS FOR ERRECTION OF A 2.5 MVA PRIMARRY SS AT KIBARANGA
3 = %load growth              0.1 = Energy costs $/KWH
1 5 = analysis period        0.35 = loss load factor
1.061 = loss gr.fac. pa.          1.1 = discount factor pa.
11.79 = P.W. factor for loss redn. over period of analysis
COMPUTATION OF BENERTS:
1990      1990       1993
KW    KWH/yr.  KWH/yr.
Existing rine losses                 209   640794   765142
Losses after new dev.                 65   199290   237963
loss savings                         144   441504   527179
Value of savings 1993-2008 in $ 000's                     621
Value of savings discounted to 1990                       467
COST OF CAPITAL WORKS in $ 000's
Oty.      rate      Cost
Substation Costs:
Transformer 2.5 MVA 33/11 kV                      1        1 25    125.0
33 kV OCB                                         1         50       50.0
11 kVOCB                                          1         20      20.0
Total Cost US $000's     195.0
Cost savings by deferment of aug. of Mazinde SS                    100.0
Economic costs (assumed incurred in 1991)                           95.0
Economic costs discounted to 1990                                   86.4
BenefitlCost ratio         5.4



-206-
cb-Majen                                                                 Table E 3.1
COST BENEFIT ANNALYSIS FOR ESTABUSHING A 33/11 kV SUBATATION AT MAJENGO
AT MOSHI TOWN
7 = %load growth                  0.1 = Energy costs S/KWH
15 = analysis period              0.35 = loss load factor
1.145 = loss gr.fac. pa.             0.55 = load factor
1.07 = load gr.fac. pa                1.1 = discount factor pa.
Present worth factors over period of analysis:
20.15 = for loss redn.              12.45 = for reliability impt.
COST OF CAPITAL WORKS in $ OO's
Qty.        rate        Cost
Const. of 33 kV line 100 mmsq. (kmj                        5          23       115.0
Substation Costs:
Transformer 5 MVA 33/11 kV                                 1         170       170.0
33 kV bays                                                 2         120       240.0
11 kV bays                                                4           55       220.0
Total Cost US $000's          745.0
PW of postponement of augn. of existing substations                            150.0
Economic costs (assumed incurred in 1991)                                      595.0
Economic costs discounted to 1990                                              540.9
COMPUTATION OF BENEFITS:
Loss reduction 6eneFits                                 1990        1990        1993
KW     KWH/yr.    KWH/yr.
Existing line losses                                    124      380184      570554
Losses after new dev.                                    47      144102      216258
Loss savings                                             77      236082      354295
Value of savings 1993-2008 in $ 000's                                            714
Value of savings discounted to 1990                                              536
Benifit / Cost ratio for loss red/n benefits only                                 1.0
Reliability benefits                                    1990        1990        1993
KW    MWH/yr.   MWH/yr.
feeder sections with enhanced reliability
M 3 from T/school                          2429       11703       14337
Town F from Boma                           1458        7025         8605
Total loads with enhanced reliability                              22942
Estimated   Sensitivity for variations
Values  of energy cost & est. savings
Estimated energy saved (%)                   1.5         1.5           1            1
Value in (pu. of en.cost)                     5            2           5            2
Value of sav. energy $ 000's               2142         857         1428         571
Savings discounted to 1990                 1609         644         1073         429
Total savings $ 0OO's                      2146        1180         1609         965
Benefit / Cost ratio                         4.0         2.2         3.0          1.8



-207-
cb-Makomb.                                                    Table E 3.2
COST BENEFIT ANNALYSIS FOR CONVERTION OF MAKOMBONE FEEDER TO 33 kV
3 = %load growth             0.1 = Energy costs $1KWH
1 5 = analysis period        0.35 = loss load factor
1 .061 = loss gr.fac. pa.        1 .1 = discount factor pa.
11.79 = P.W. factor for loss redn. over period of analysis
COMPUTATION OF BENEFITS:
1990      1990      1993
KW   KWH/yr.  KWH/yr.
Existing line losses                  41   125706   150100
Proposed line losses                  3.5    10731      12813
Peak loss savings                   37.5   114975   137286
Value of savings 1993-2008 in $ 000's                     1 62
Value of savings discounted to 1990                       122
COST OF CAPITAL WORKS in $ 000's
Qty.      rate      Cost
Constructing of line (km)                        1 8       1 4     252.0
Convertion of distribution stations
200 KVA trans.                         1        9.2        9.2
100 KVA trans.                         2        7.8      15.6
50 KVA trans.                          6       5.8       34.8
25 KVA trans.                         1 0        5       50.0
Total cost               361.6
Cost saving due to deferment of augumt. of 33/11 kV SS             100.0
Cost saving due to avoiding rehab of line @ 8k$/ Km                144.0
Economic costs (assumed incurred in 1992)                          117.6
Economic costs discounted to 1990                                   97.2
Benefit/Cost ratio         1.3



cb-Maron                               -208-                                    Table E 3.3
COST BENEFiT ANALYSIS OF CONSTRUCTING A 66 kV LINE
AND 66/33 kV SUBSTATION AT MARANGU
3 = %load growth                0.1 = Energy costs S/KWH
15 = analysis period            0.35 = loss load factor
1.061 = loss gr.fac. pa.           0.55 = load factor
1.03 = load gr.fac. pa             1.1 = discount factor pa.
Present worth factors over period of analysis:
11.79 = for loss redn.             9.85 = for reliability impt.
COST OF CAPITAL WORKS in S 000's
Qty.       rate        Cost
Construction of 66 kV line
with part recovered material                      30         15      450.0
Construction of 66/33 substation
33 kV breakers                             1         50        50.0
33 kV load breck switches                  3         10        30.0
Costs (assumed incurred in 1991)                                         530.0
Economic costs discounted to 1990                                        481.8
COMPUTATION OF BENEFITS:
Loss reduction benefits:                           1990        1990        1993
-------------------------                    KW    KWH/yr.  KWH/yr.
Existing line losses                                557   1707762   2039157
Proposed line losses                                105    321930    384401
Loss savings                                        452   1385832   1654756
Value of savings 1993-2008 in $ 000's                                     1950
Value of savings discounted to 1990                                       1465
Benifit / Cost ratio for loss red/n benefits only                           3.0
Reliability benefits                               1990        1990        1993
--------------------                                 KW   MWH/yr.  MWH/yr.
feeder sections with enhanced reliability
Loads on Boma and Majengo (new) SS                 5186      24986       27303
Loads on new 66 kV line                            2721      13110       14325
Total loads with enhanced relia6ility                        41628
Estimated  Sensitivity for variations
Values of energy cost & est. savings
Estimoted energy saved (%)               1.5         1.5           1          1
Value in (pu. of en.cost)                  2         1.5          2  -        1
Value of sav. energy $ 000's            1231        923         820        410
Savings discounted to 1990               925        693         616        308
Total savings $ 000's                  2390        2159        2082        1773
Benefit / Cost ratio                     5.0         4.5        4.3         3.7



-209-
cb-Mon                                                                                         Table E4.1
COST BENEFIT ANALYSIS FOR CONVERTION OF THE MONDUU UNE TO 33 kV OPERATION
AND CONSTRUCTION OF A PRIMARY SUBSTATION AT MONDUU
Computation factors
1.1 = discount factor p.a.
4 = % annual load growth     0.10 = Energy costs $1KWH
15 = analysis period          0.50 = load factor
1.082 = loss growth factor p.E   0.30 = loss load factor
13.36 = P.W. factor (MFlr*) for loss reducton over analysis period indicated above
COMPUTATION OF BENEFITS:
(a) Loss reduction benefits
1991      1991       1993
KW   MWH/yr.  MWH/yr.
Existing line losses                             119       313        366
Losses after new development                      33        87        101
Peak loss savings                                 86       226        264
Value of savings 1993-2008 in $ 000's                                 353
Value of savings discounted to 1991 ($000)                            292
COST OF CAPITAL WORKS in $ 000's
Qty.       rate      Cost
33 kV line 100 mmsq. (inifial section)             6       22.8     136.8
Substation Costs:
Transformer 2.5 MVA 33/11 kV                       1      170.1     170.1
33 kV circuit breaker and bay                      1       55.4      55.4
11 kV circuit breaker and bay                      4      24.6       98.4
11 KV line additions (100mmsq.)                  0.5      20.7       10.4
Total Cost (assumed in 1992) US $000's                    471.1
Cost discounted to 1991 ($000)                           428.2
Benefit/Cost ratio considering loss reduction benefits only  0.7
(b) Reliability benefits
System load in MW (at 1991 level) benefiting by increased reliability  2.5
Annual load, MWh (1991) of section with reliability improvement    21901
Estimated    Sensitivity for variations in % units saved
Values      and cost of saved energy
Estimated outages saved as % of annual energy               1.5        1.5         1          1       0.5        0.5
Estimated outages saved 1991 loads (MWH)                   329        329       219        219        110       110
PW factor for reliability benefits '93-08 (MFrb*)          10.4      10.4       10.4       10.4      10.4       10.4
PW outages saved 1993 to 2008 MWH                         3416       3416      2278       2278       1139      1139
Value of reliability benefits:
Value saved outages - multple of energy cost                  8         5          5          3         3          2
PW reliability benefits $ 000's                           2733       1708      1139        683        342       228
TOTALBENEFITS (loss redn& reliability) $000's             3161       2136       1567      1112        770       656
Benefit / Cost ratio (loss reduction & reliability benefits)  8.1     5.7        4.3        3.3       2.5        2.2
Note:    See Annex D for determination of multiplying factors to obtain PW of benefits
over a future fime period (given a constant annual load growth)
MFir - represents the factor for loss reduction benefits and MFrb - represents the factor for reliability benefits



-210-
cb-Magereza                                                                                   Table E 4.2
COST BENEFIT ANALYSIS FOR NEW PRIMARY SUBSTATION AT MEGAREZA
Computation factors
1.1 = discount factor p.a.
3 = % annual load growth    0.10 = Energy costs $/KWH
1 5 = analysis period        0.75 = load factor
1.061 = loss growth factor p.E  0.40 = loss load factor
11.79 = P.W. factor (MFIr') for loss reduction over analysis period indicated above
COMPUTATION OF BENEFITS:
(a) Loss reduction benefits
1991      1991      1993
KW   MWH/yr.  MWH/yr.
Existing line losses                           77.4       271        305
Losses after new development                   26.5        93        105
Peak loss savings                              50.9        178       201
Value of savings 1993-2008 in $ 000's                                237
Value of savings discounted to 1991 ($000)                           196
COST OF CAPITAL WORKS in $ 000's
Qty.      rate      Cost
33 kV line 100 mmsq.                              1       22.8      22.8
Substation Costs:
Transformer 2.5 MVA 33/11 kV                      1      170.1     170.1
33 kV circuit breaker                             1       55.4      55.4
11 kV circuit breaker                             2       24.6      49.2
11 KV line additions (100mmsq.)                   1       20.7      20.7
Total Cost (assumed in 1992) US $000's                   318.2
Cost discounted to 1991 ($000)                          289.3
Benefit/Cost rabo considering loss reduction benefits only  0.7
(b) Reliability benefits
System load in MW (at 1991 level) benefiting by increased reliability  2.8
Annual load, MWh (1991) of section with reliability improvement    24529
Estimated    Sensitvity for variations in % units saved
Values     and cost of saved energy
Estimated outages saved as % of annual energy              1.5        1.5         1         1        0.5        0.5
Estimated outages saved 1991 loads (MWH)                  368        368       245        245        123       123
PW factor for reliability benefits '93-08 (MFrb*)         10.4      10.4       10.4       10.4      10.4       10.4
PW outages saved 1993 to 2008 MWH                        3826       3826      2551       2551       1275      1275
Value of reliability benefits:
Value saved outages - multiple of energy cost                8         5          5         3          3          2
PW reliability benefits $ 000's                          3061       1913      1275        765        383       255
TOTAL BENEFITS (loss redn & reliability) $000's          3350       2203      1565       1055        672       544
Benefit I Cost ratio (loss reducton & reliability benefits)  12.3    8.3        6.1        4.3       3.0        2.6
* Note:    See Annex D for determinabon of multiplying factors to obtain PW of benefits
over a future time period (given a constant annual load growth)
MFIr - represents the factor for loss reduction benefits and MFrb - represents the factor for reliability benefits



SUM-RR1
SUM MARY  OF  MV   RE HABI LITATION  &  TRAN SF. FOR  LV  RE IN FOR CM ENT
M.V. REHABILITATION REQTS.         MV LINE EXTENSIONS AND ASSOCIATED TRANSFORMER STATIONS.
Reconduct.        Pole        33 kV         11 kV              33KV/LV Trans.         11 KV/LV Transformers by KVA
REGION     100 mmsq 50 mmsq   Replace    100 mmsq  100 mmsq 50 mmsq   160/200   25to100    200/250   100/160   25to63
ARUSHA             10          1        606        6.4        11.8        2.1         1                      1          8           1
MOSHI             21                    171                   3.8         2.7                                8          4
TANGA               1                    77        5.0        13.1                    2           2          4          2          5
DAR ES S         152                  1281         5.0       24.0                                10         40         20
TOTAL
Identif/d        184           1      2135        16.4       52.7         4.8         3          12         53         34          6
Project          200          10      2500          20         60         20         10          15         60         50         40
FOREIGN COST
Rate              12          10       0.22         21         18         13          9         5.5        9.3        6.5         4.4
Cost $000       2400         100       550         420       1080        260         90          83        55B        325        176
LOCAL COST
Rate              0.8        0.6       0.03          1        0.9         0.6       0.43       0.25       0.44        0.3         0.2
Cost $000        160           6         75         20         54         12         4.3        3.8       26.4        15.0        8.0
rOT. COST       2560        106        625         440       1134        272         94          86        584        340         184
TOTAL COSTS in $ 000's:                                     MV REHABILITATION            TRANSF. AND LV REINFORCEMENT
Foreign     Local       Total    Foreign      Local       Total
Works identified above $000                       3050        241       3291       2992         143       3135
S/Ph transf. & LV lines                                                             500          50        550     ,
Rehab. material for MVlines                       1000        100       1100                                       j
Rehab. material for Pr. SS                        1500        200       1700
Total cost in $ 000's                             5550        541       6091       3492         193       3685



SUM-RR2
SUMMARY FOR REHABILITATION AND REINFORCEMENT OF LV LINES
NEW LV EXTENSIONS    RECOND. & REHAB           REPLACE PHASE ADDITION
REGION                  #100        #50       #100         #50      POLES       #100        #50
-------------------------------------------------------------- -----------------
Presently Identified Works in km:
ARUSHA                  11.4                   9.0        9.1        297                     1
MOSHI                    9.8                              3.6        131                     4
TANGA                   18.3       12.2       25.8        2.7        667         13         18
DAR ES S                81.0                  75.0       24.0       1000         10         12
TOTAL
Identif/d              120.5       12.2      109.8       39,3       2095         23         35
Project                150.0       50.0      150.0       75.0       2500         30         50
FOREIGN COST
Rate                      16         12         10          8        0.2          6          5
Cost $000              2400         600       1500        600        500        180        250
LOCAL COST
Rate                     0.8        0.6        0.7        0.5       0.01        0.3       0.30
Cost $000                120         30        105       37.5         25          9        15.0
TOT. COST              2520         630       1605        638        525        189        265
TOTAL COST FOR LV REHAB & REINFORCEMENT IN $ 000's:
LV Reinforcement        Rehabilitation
Foreign      Local    Foreign      Local
Works listed above $ 000's                    3000        150       3030        192                                                                 1)
Rehab. (only) of LV lines                                            500         25
Rehab of trans. stns.                                                500         25
TOTAL                                         3000        150       4030        242



Table E.6.1.
-213-
REHDAR
COST/ BENEFIT ANALYSIS OF REHABIIrrATION OF MV AND LV SYSTEMS AT DAR ES SALLAM
(based on outage savings)
Estimated value Sensitivity to changes in the value of the variables involved
for variables
P.UOUTAGESAVOIDED                   0.010      0.0075    0.0075   0.0075      0.005     0.003
VALUEOFOUTAGESSAVEDS/KiWH            1.00         1.00     0.75      0.75      0.75      0.75
PERIOD OF ANALYSIS (years)            1 5          1 5       1 5       1 5       1 5       1 5
GROWTH OF ENERGYSALES(PU)            0.09         0.09    0.045     0.045     0.045     0.045
DISCOUNT FACTOR IN (PU)              0.10         0.10     0.10      0.10      0.10      0.10
PRESENTVALWEFACTOR                  14.08        14.08    10.73     10.73     10.73     10.73
UNITS SOLD IN 1989 (GWH)         491.927      491.927  491.927  491.927  491.927  491.927
Growth rate 1989-1994 (pa)           1.08         1.08     1.08      1.04      1.04      1.04
Addl. increase due to syst dev. (m.f.)  1.1        1.1      1.05     1.05      1.05      1.05
EXPECTED SALES 1994 (GWH)        795.082      795.082  758.942  628.430  628.430  628.430
Benefits and Costs in $ '000:
P.V.OFOUTAGESAVINGS               101785        83973    41659    34495    22997    13798
COSTOF REHABIi-TATION               5756         5756      5756      5756      5756     5756
BENEFIT/COST RATIO                   17.7         14.6       7.2      6.0       4.0       2.4
NOTES:
1. The Rehabilitation costs are assumed to be incurred in 1993 and the benefits computed from 1994.
2. The 1994 sales have been computed based on the growth rate indicated and a one time increase
to account for the voltage improvement and removal of the capacity restriction
(multiplying factor indicated in Table)
3. A number of associated benefits have been unaccounted for. These include:
(a) damage/burnout of equipment belonging to both the utility and the consumers
(b) avoided costs of 'breakdown maintenance'
4. All costs are in constant 1991 US $. The PV is worked out for the investment year, 1993
CR/2-12-92



Table E.6.2
-214-
REH-TAN
COST/ BENEFIT ANALYSIS OF REHABILITATION OF MV AND LV SYSTEMS AT TANGA
(based on outage savings)
Estimated value  Sensitivity to changes in the value of the variables involved
for variables
P.U OUTAGESAAVOIDED               0.010       0.0075    0.0075    0.0075      0.005     0.003
VALUE OF OUTAGES SAVED $/KWH       1.00         1.00       0.75      0.75      0.75      0.75
PERIOD OF ANALYSIS (years)           1 5          1 5       1 5       1 5       1 5        1 5
GROWVHOFENERGYSALES(PU)            0.09         0.09     0.045      0.045     0.045     0.045
DISCOUNTFACTORIN(PU)               0.10         0.10       0.10      0.10      0.10      0.10
PRESENTVALUEFACTOR                14.08        14.08     10.73      10.73     10.73     10.73
UNITS SOLD IN 1989 (GWH)         95.284       95.284    95.284    95.284    95.284    95.284
Growth rate 1989-1994 (pa)         1.08         1.08       1.08      1.04      1.04      1.04
Addl. increase due to syst. dev.(N2)  1.1         1.1      1.05      1.05      1.05      1.05
EXPECTED SALES 1994 (GWH)       154.004      154.004   147.004   121.724   121.724   121.724
Benefits and Costs in $ '000:
P.V.OFOUTAGESAVINGS              19715         14787      8069      6682      4454      2673
COSTOFREHABIUTATION                2081         2081      2081      2081      2081      2081
BENEFIT/COSTRATKO                   9.5          7.1        3.9       3.2       2.1       1.3
NOTES:
1. The Rehabilitation costs are assumed to be incurred in 1993 and the benefits computed from 1994.
2. The 1994 sales have been computed based on the growth rate indicated and a one time increase
to account for the voltage improvement and removal of the capacity restriction
(multiplying factor indicated in Table)
3. A nuinber of associated benefits have been unaccounted for. These include:
(a) damagelburnout of equipment belonging to both the utility and the consumers
(b) avoided costs of 'breakdown maintenance'
4. All costs are in constant 1991 US $. The PV is worked out for the investment year, 1993
CR12-12-92



Table E.6. 3
-215-
REH-MOS
COST / BENEFIT ANALYSIS OF REHABILITATION OF MV AND LV SYSTEMS AT MOSHI
(based on outage savings)
Estimated value   Sensitivity to changes in the value of the variables involved
for variables
P.UOUTAGESAVOIDED                 0.010       0.0075    0.0075    0.0075      0.005     0.003
VALUEOFLOUTAGESSAVED $KWH          1.00          1.00      0.75      0.75      0.75      0.75
PERIODOFANALYSIS(years)              1 5          1 5       1 5        1 5       1 5       1 5
GROWrHOFENERGYSALES(PLO            0.09          0.09     0.045     0.045     0.045     0.045
DISCOUNT FACTOR IN (PU)            0.10          0.10      0.10      0.10      0.10      0.10
PRESENTVALUEFACTOR                14.08        14.08      10.73     10.73     10.73     10.73
UNITS SOLD IN 1989 (GWH)          64.76        64.76      64.76     64.76     64.76     64.76
Growth rate 1989-1994 (pa)         1.08          1.08      1.08      1.04      1.04      1.04
Addl. increase due to syst dev. (m.f  1.1         1.1      1.05      1.05      1.05      1.05
EXPECTED SALES 1994 (GWH)       104.669      104.669    99.911    82.730    82.730    82.730
Benefits and Costs In $ '000:
P.V.OFOOUTAGESAVINGS              13400        10050      5484      4541      3027       1816
COSTOF REABILITATION               1703         1703      1703      1703      1703       1703
BENEFIT/COST RATMO                  7.9           5.9       3.2       2.7       1.8       1.1
NOTES:
1. The Rehabilitation costs are assumed to be incurred in 1993 and the benefits computed from 1994.
2. The 1994 sales have been computed based on the growth rate indicated and a one time increase
to account for the voltage improvement and removal of the capacity restriction
(multiplying factor indicated in Table)
3. A number of associated benefits have been unaccounted for. These include:
(a)  damage/bumout of equipment belonging to both the utility and the consumers
(b) avoided costs of 'breakdown maintenance'
4. All costs are in constant 1991 US $. The PV is worked out for the investment year, 1993
CR/2-12-92



Table E.6.4
-216-
REH-ARU
COST/ BENEFITANALYSIS OF REHABILITATION WORKS - MVAND LVSYSTEMSATARUSHA
(based on outage savings)
Estimated value Sensitivity to changes in the value of the variables involved
for variables
P.UOUTAGESAYOIDED                 0.010       0.0075   0.0075    0.0075      0.005      0.003
VALUEOFOUTAGESSAVED$KWH            1.00          1.00      0.75      0.75      0.75      0.75
PERIOD OF ANALYSIS (years)           1 5          1 5       1 5       1 5       1 5       1 5
GROWrH OFENERGYSALES (Po           0.09         0.09     0.045     0.045      0.045     0.045
DISCOUNT FACTOR IN (PU)            0.10         0.10      0.10       0.10      0.10      0.10
PRESENTVALUEFACTOR                14.08        14.08     10.73     10.73      10.73     10.73
Computation of Expected Sales in 1994:
Units sold in 1989 (GWH)         70.114       70.114   70.114    70.114    70.114    70.114
Growth rate 1989-1994 (pa)         1.08          1.08      1.08      1.04      1.04      1.04
Addl. increase due to syst dev. (N2)   '  1.1     1.1      1.05      1.05      1.05      1.05
EXPECTEDSALES1994(GWH)          113.323      113.323   108.171    89.570    89.570    89.570
Benefits and Costs in $ '000
P.V.OFOUTAGESAVINGS               14507        10881      5938      4917      3278      1967
COSTOFREHABILITATION               1858         1858      1858      1858      1858      1858
BENEFIT/COSTRATMO                   7.8           5.9       3.2       2.6       1.8       1.1
NOTES:
1. The Rehabilitation costs are assumed to be incurred in 1993 and the benefits computed from 1994.
2. The 1994 sales have been computed based on the growth rate indicated and a one time increase
to account for the voltage improvement and removal of the capacity restriction
(multiplying factor indicated in Table)
3. A number of associated benefits have been unaccounted for. These include:
(a) damage/burnout of equipment belonging to both the utility and the consumers
(b) avoided costs of 'breakdown maintenance'
4. All costs are in constant 1991 US $. The PV is worked out for the investment year, 1993
CR/2-12-92



CBEWENoO                                     ECONOMIC EVALUATION OF NETWORK EXPANSION
NAMEOF SCHEME:    MAJENGOAREA
IWESTMENT DErAILS FOR FNAL SYSTEM
11 KV LINES       TRANSFOPMERS               L V LINES
#100      #50      100  200 KVA  315 KVA     #100      #50
OLANTflY                 0        0        0        2        0       0.9        0
RATE $000              18.9     13.6      7.0      7.5      8.5     16.8     12.6
COST                    0.0      0.0      0.0     1 5.0     0.0     15.1      0.0
COST OF NEVM)RK EXPANSION
2003
TOTAL     1992     1993     1994     1995    1996      1997     1998     1999      2000     2001     2002   TOEND
INVESTMENTCOST          30       12        0        9        0        9
PU OF TOTAL                    0.4               0.3               0.3
OP & MAINT. (2p.p)               0.6      0.6      0.6      0.6      0.6      0.6      0.6       0.6      0.6      0.6      0.6      6.6
TOTALCOST                       12.7      0.6      9.6      0.6      9.6      0.6      0.6       0.6      0.6      0.6      0.6      6.6
PVOFOOST                29      11.5      0.5      7.2      0.4      6.0      0.3      0.3      0.3       0.3      0.2      0.2      2.1
0.5 - AREA OF SUPPLY IN km sq      500 - LOAD DENSITY IN KW/krn sq
250- EXPECTED FINALLOADINKW                                                                         -,
VALUE OF BENEFRTS
LOAD (PU) OF FINAL               0.2      0.4      0.5      0.6     0.65      0.7     0.75       0.8     0.85      0.9    0.925
LOADINKW                         s0      100       125      150    162.5      175    187.5      200    212.5      225   231.25   2543.7
LOADFACTOR                      0.33     0.33     0.33     0.33     0.35     0.35     0.35       0.4      0.4      0.4      0.4     0.45
LOADIN MWH                     144.5    289.1    361.4    433.6    498.2    536.6    574.9    700.8    744.6    788,4    810.3  10027.5
VALUEOFSALES                    14.5    28.9      36.1     43.4     49.8     53.7     57.5      70.1     74.5     78.8     81.0   1002.7
UPSTREAMOOSTS                   11.6    23.1      28.9     34.7     39.9     42.9     46.0      56.1     59.6     63.1     64.8    802.2
VALUEOFBENEFITS                  2.9      5.8      7.2      8.7     10.0     10.7      11.5     14.0     14.9     15.8     16.2    200.5
PVOFBENEFfTS           125       2.6      4.8      5.4      5.9      6.2      6.1      5.9       6.5      6.3      6.1      5.7     63.9
B/CRATIO                4.3
NOTES:
O . VALUE OF SALES IN $
0.08 UPSTREAM 0OSTS N18
m
00



TOTAL COSTS FOR NETWORK EXPANSION TO SUPPLY NEW DEVELOPING AREAS IN $ 000's
MEDIUM VOLTAGE LINES                 MV/LV TRANSFORMER STATIONS                 LV NETWORK
11 kV LINES         33 kV LINES           11 kV/LV TRANSF.      33 kV/LV TRANSF.      CONDUCTOR
REGION       100MMSQ   50 MMSQ   100MMSQ   50 MMSQ    50/100   100/200    50/100   100/200   100MMSQ   50 MMSQ
ARUSHA           7.8        4.7                                4          3          5                  15.3        8.4
MOSHI &
MWANGA           5.1                   0.5        0.6          6          6          2          1       20.6
TANGA            7.4         1.7        45                     4          2          3          1       22.7
DAR ES S        50.1                    1.6                   89         60          4                 103.7      127.4
TOTAL WORK:
Identif/d:        70          6         47          1        103         71         14          2        162        136
Project           80         15         60         10        110         80         20         10        200        150            c0o
FOREIGN COST
Rate              18         13         21         16          5          7        5.5          9         16         12
Cost $000       1440        195       1260        160        550        560        110         90       3200       1800
LOCAL COST
Rate             0.9        0.6          1          1       0.25       0.35       0.25       0.43        0.8        0.6
Cost $000       72.0        9.0       60.0        10.0      27.5       28.0        5.0        4.3      160.0       90.0
TOT. COST       1512        204       1320        170        578        588        115         94       3360       1890
TOTAL COST FOR NETWORK EXPANSION                           Foreign      Local      Total
MV LINES                   3055        151       3206                                              H
TRANSF.                    1310         65       1375
LV LINES                   5000        250       5250
TOTAL                      9365        466       9831



Annex F
Distribution System network drawings



I



-221-
\  '              Fig. F.l.l
4!
'S    o: 
'e=            ';VA                                                        1     -C
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|   \ts  \ \                                         ~~~~~~~LEGEND  --
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SN           I. I '                                               1   PROPOSED 51£STATON
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hAll                                      PS  motIrli(ALi  P3
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AIRPORT
33 KV DISTRIBUTION NETWORK IN DAR ES SALAAM



I



-223-
X                t           Fig. F.1.2
- 1 KXLINE- 
~~~~~~-               N46
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P LEG                                   E       ND               
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P3 MA00OM 54 515
p4 SaOiME S"                                                                I
PS CHANGOMBE S/S
PS 4BAGALA S/s                                         __
-'~~ 1I. 
11 KDITIUINNTOKIDAESSA   -JUEe |ESMAP STUDY
11 KV  DISTRIBUTION  NETWORK -IN OAR ES SAIAAM         JUNE 1991    ESMAP STUDY



I



Fig. F.2.1: Tanga District - Medium voltage distribution lines
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-229-
Fig. F.2.6
MW L,      -1
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MARAMBA         e       m
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MLWGOE  /          J1
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C!L CWITmS5STlY   E-- UISTI7C U2Kv LINE
V= Zs                                 vDZ912                           e   ON AN SAX WlI
- _U n2 KVD                     - o T         . AT
MAJAM QAJI S UO SMTATUN
A~~~~~~~~~~r+t
ESMAP STUDY
JOY
PROPOSED KIBARANGA SUB STATION 33/ 1KV & TANGA CEMENT SUB STATION 132 /33KV                            TRAED Sy
ORG N! - ES/TAN/MV-002  APPSSE wp 



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-  < -  M -  fi W          FLgAS.I.  HOSIfI DISTIXCT - Maelum vo1tage
>_  ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ 
To~~~~~~~~~~~~~~~~~~~~~~~~~ '. v I   I 
*           W                 ~~~~~~~~~~~~~~~~~~~~*' - - 
_ -t ri05-k01
*~~~~~c



I



-233-
Fig. F.3.2: Moshi District (Drawing No.2)
Main. 3.3JLV Feding. Arrangement and
Proposed 66kV line to Marangu
REPUBULC OF KENYA
LEGEND
5ur4  MI LMV
.~ ~ ~ ~~Ei ,:          l 5It2X                       - \~ATM
'~~~~~~~~xm mm st                                                       VS4/
rA  0
:~~~~~ ~ ~ ~~~~~~~ ~~~~~~~~~~ *I -                                        XA) -  IJ  
TMAPE STUD
.01~~~~~~~~~~~~~~~~~~~£
ES /MOS/003



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-235-
Fig. F.3.4
IUFW
25 f1X                                      ...
.    \,1O*47JN /C\ //
Si~~~~~~~~~~~~~s
) ,w                  /     g      ,           I
S                                       I~~~~~~~~~I
1''''-501                            ,                     1 
a           I      I z     asts
,WSnwJCU~ ~~~ S        \      I__
rXc~~~o
l                                     _~~~~~~~~~~ESMAP STUDY
PROPOSED CONVERSION OF M2 FEEDER 11 To 33KV MOSHI RURA             CHeo
N                                                      ES/MOS/002    >
_~~~~~~~~~~~~~A



I



t~~                  ~~                 ~    ~     ~     ~ (\- ;  0 
-  r y~~~~~~~~~~~~~~~~~~~~~~~~~~~r
-LtZ-~~~~~~~~~~~~~~~r



I



Fig.f.4.2
NGUIK
NDIJRUHE7
~ u nmu                                                      OEUE
MONDULI
( NGARAMlONI
",~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~to ta.                
k ~~~~~~~~~~~~~~~~~~~~- man
rom9a oltiom I HMCW~ ~~~~~~~~~~~~~~~~  ~I.
PROPOSED CONVERSION 11 TO 33KV MONDULI FEEDER                                           -le----u
/                                                           .                         ..tC               _



I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~



-241-
Fig.f.4.3
Acu
W50
U ,
amM
mamm
Wpt   Md*CUA
X   ~          ~~~~ ina ,~
m ms   L1~~AWmo
wGR2POSEOHGREASS331K
,ROPOSE   .AGEZ S.    S                  ,, _OK



I



Joint UNDP/World Bank
ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP)
LIST OF REPORTS ON COMPLETED ACTIVITIES
Region/Country                      Activity/Report Title                   Date  Number
SUB-SAHARAN AFRICA (AFR)
Africa Regional Anglophone Africa Household Energy Workshop (English)      07/88   085/88
Regional Power Seminar on Reducing Electric Power System
Losses in Africa (English)                                08/88   087/88
Institutional Evaluation of EGL (English)                  02/89   098/89
Biomass Mapping Regional Workshops (English)                05/89   --
Francophone Household Energy Workshop (French)              08/89   --
Interafrican Electrical Engineering College: Proposals for Short-
and Long-Term Development (English)                       03/90   112/90
Biomass Assessment and Mapping (English)                    03/90   --
Symposium on Power Sector Reforn and Efficiency Improvement
in Sub-Saharan Africa (English)                           06/96   182/96
Commercialization of Marginal Gas Fields (English)          12/97   201/97
Angola         Energy Assessment (English and Portuguese)                  05/89   4708-ANG
Power Rehabilitation and Technical Assistance (English)     10/91   142/91
Benin          Energy Assessment (English and French)                      06/85   5222-BEN
Botswana       Energy Assessment (English)                                 09/84   4998-BT
Pump Electrification Prefeasibility Study (English)         01/86   047/86
Review of Electricity Service Connection Policy (English)   07/87   071/87
Tuli Block Farms Electrification Study (English)            07/87   072/87
Household Energy Issues Study (English)                     02/88   --
Urban Household Energy Strategy Study (English)             05/91   132/91
Burkina Faso    Energy Assessment (English and French)                     01/86   5730-BUR
Technical Assistance Program (English)                     03/86   052/86
Urban Household Energy Strategy Study (English and French)  06/91   134/91
Burundi        Energy Assessment (English)                                 06/82   3778-BU
Petroleum Supply Management (English)                       01/84   012/84
Status Report (English and French)                         02/84   011/84
Presentation of Energy Projects for the Fourth Five-Year Plan
(1983-1987) (English and French)                          05/85   036/85
Improved Charcoal Cookstove Strategy (English and French)  09/85   042/85
Peat Utilization Project (English)                          11/85   046/85
Energy Assessment (English and French)                      01/92   9215-BU
Cape Verde     Energy Assessment (English and Portuguese)                  08/84   5073-CV
Household Energy Strategy Study (English)                   02/90   110/90
Central African
Republic      Energy Assessement (French)                                 08/92   9898-CAR
Chad           Elements of Strategy for Urban Household Energy
The Case of N'djamena (French)                             12/93   160/94
Comoros        Energy Assessment (English and French)                      01/88   7104-COM
Congo          Energy Assessment (English)                                 01/88   6420-COB
Power Development Plan (English and French)                 03/90   106/90
C6te d'Ivoire    Energy Assessment (English and French)                    04/85   5250-IVC
Improved Biomass Utilization (English and French)          04/87   069/87
Power System Efficiency Study (English)                     12/87   --
Power Sector Efficiency Study (French)                      02/92   140/91
Project of Energy Efficiency in Buildings (English)         09/95   175/95



-2 -
Region/Country                       Activity/Report Title                   Date  Number
Ethiopia        Energy Assessment (English)                                  07/84   4741 -ET
Power System Efficiency Study (English)                     10/85   045/85
Agricultural Residue Briquetting Pilot Project (English)     12/86   062/86
Bagasse Study (English)                                      12/86   063186
Cooking Efficiency Project (English)                         12/87   --
Energy Assessment (English)                                 02/96   179/96
Gabon           Energy Assessment (English)                                 07/88   6915-GA
The Gambia      Energy Assessment (English)                                  11/83   4743-GM
Solar Water Heating Retrofit Project (English)              02/85   030/85
Solar Photovoltaic Applications (English)                   03/85   032/85
Petroleum Supply Management Assistance (English)            04/85   035/85
Ghana           Energy Assessment (English)                                  11/86   6234-GH
Energy Rationalization in the Industrial Sector (English)   06/88   084/88
Sawmill Residues Utilization Study (English)                11/88   074/87
Industrial Energy Efficiency (English)                      11/92   148/92
Guinea          Energy Assessment (English)                                  11/86   6137-GUI
Household Energy Strategy (English and French)              01/94   163/94
Guinea-Bissau   Energy Assessment (English and Portuguese)                  08/84   5083-GUB
Recommended Technical Assistance Projects (English &
Portuguese)                                                04/85   033/85
Management Options for the Electric Power and Water Supply
Subsectors (English)                                       02/90    100/90
Power and Water Institutional Restructuring (French)        04/91    118/91
Kenya           Energy Assessment (English)                                 05/82   3800-KE
Power System Efficiency Study (English)                     03/84   014/84
Status Report (English)                                     05/84   016/84
Coal Conversion Action Plan (English)                       02/87   --
Solar Water Heating Study (English)                         02/87   066/87
Peri-Urban Woodfuel Development (English)                    10/87   076/87
Power Master Plan (English)                                  11/87   --
Power Loss Reduction Study (English)                        09/96   186/96
Lesotho         Energy Assessment (English)                                  01/84   4676-LSO
Liberia         Energy Assessment (English)                                  12/84   5279-LBR
Recommended Technical Assistance Projects (English)         06/85   038/85
Power System Efficiency Study (English)                      12/87   081/87
Madagascar      Energy Assessment (English)                                  01/87   5700-MAG
Power System Efficiency Study (English and French)           12/87   075/87
Environmental Impact of Woodfuels (French)                   10/95   176/95
Malawi          Energy Assessment (English)                                  08/82   3903-MAL
Technical Assistance to Improve the Efficiency of Fuelwood
Use in the Tobacco Industry (English)                       11/83   009/83
Status Report (English)                                     01/84   013/84
Mali            Energy Assessment (English and French)                       11/91   8423-MILI
Household Energy Strategy (English and French)              03/92   147/92
Islamic Republic
of Mauritania   Energy Assessment (English and French)                     04185   5224-MAU
Household Energy Strategy Study (English and French)        07/90   123/90
Mauritius       Energy Assessment (English)                                  12/81   3510-MAS
Status Report (English)                                     10/83   008/83
Power System Efficiency Audit (English)                     05/87   070/87



-3 -
Region/Country                      Activity/Report Title                  Date  Number
Mauritius      Bagasse Power Potential (English)                           10/87   077/87
Energy Sector Review (English)                             12/94   3643-MAS
Mozambique    Energy Assessment (English)                                 01/87   6128-MOZ
Household Electricity Utilization Study (English)          03/90   113/90
Electricity Tariffs Study (English)                        06/96   181/96
Sample Survey of Low Voltage Electricity Customers         06/97   195/97
Namibia        Energy Assessment (English)                                03/93   11320-NAM
Niger          Energy Assessment (French)                                 05/84   4642-NIR
Status Report (English and French)                         02/86   051/86
Improved Stoves Project (English and French)               12/87   080/87
Household Energy Conservation and Substitution (English
and French)                                               01/88   082/88
Nigeria        Energy Assessment (English)                                08/83   4440-UNI
Energy Assessment (English)                                07/93  11672-UNI
Rwanda         Energy Assessment (English)                                06/82   3779-RW
Status Report (English and French)                         05/84   017/84
Improved Charcoal Cookstove Strategy (English and French)  08/86   059/86
Improved Charcoal Production Techniques (English and French)    02/87   065/87
Energy Assessment (English and French)                     07/91   8017-RW
Commercialization of Improved Charcoal Stoves and Carbonization
Techniques Mid-Term Progress Report (English and French)  12/91   141/91
SADC           SADC Regional Power Interconnection Study, Vols. I-IV (English)  12/93   --
SADCC          SADCC Regional Sector: Regional Capacity-Building Program
for Energy Surveys and Policy Analysis (English)          11/91   --
Sao Tome
and Principe    Energy Assessment (English)                               10/85   5803-STP
Senegal        Energy Assessment (English)                                07/83   4182-SE
Status Report (English and French)                         10/84   025/84
Industrial Energy Conservation Study (English)             05/85   037/85
Preparatory Assistance for Donor Meeting (English and French)  04/86   056/86
Urban Household Energy Strategy (English)                  02/89   096/89
Industrial Energy Conservation Program (English)           05/94   165/94
Seychelles     Energy Assessment (English)                                01/84   4693-SEY
Electric Power System Efficiency Study (English)           08/84   021/84
Sierra Leone    Energy Assessment (English)                                10/87   6597-SL
Somalia        Energy Assessment (English)                                 12/85   5796-SO
South Africa    Options for the Structure and Regulation of Natural
Republic of    Gas Industry (English)                                     05/95   172/95
Sudan          Management Assistance to the Ministry of Energy and Mining  05/83   003/83
Energy Assessment (English)                                07/83   4511-SU
Power System Efficiency Study (English)                    06/84   018/84
Status Report (English)                                    11/84   026/84
Wood Energy/Forestry Feasibility (English)                 07/87   073/87
Swaziland      Energy Assessment (English)                                02/87   6262-SW
Household Energy Strategy Study                            10/97   198/97
Tanzania        Energy Assessment (English)                                11/84   4969-TA
Peri-Urban Woodfuels Feasibility Study (English)           08/88   086/88
Tobacco Curing Efficiency Study (English)                  05/89   102/89
Remote Sensing and Mapping of Woodlands (English)          06/90   --
Industrial Energy Efficiency Technical Assistance (English)  08/90   122/90



-4 -
Region/Country                      Activity/Report Title                  Date  Number
Tanzania       Power Loss Reduction Volume 1: Transmission and Distribution
SystemTechnical Loss Reduction and Network Development
(English)                                                 06/98   204A/98
Power Loss Reduction Volume 2: Reduction of Non-Technical
Losses (English)                                          06/98   204B/98
Togo           Energy Assessment (English)                                06/85   5221-TO
Wood Recovery in the Nangbeto Lake (English and French)    04/86   055/86
Power Efficiency Improvement (English and French)          12/87   078/87
Uganda          Energy Assessment (English)                               07/83   4453-UG
Status Report (English)                                   08/84   020/84
Institutional Review of the Energy Sector (English)        01/85   029/85
Energy Efficiency in Tobacco Curing Industry (English)     02/86   049/86
Fuelwood/Forestry Feasibility Study (English)              03/86   053/86
Power System Efficiency Study (English)                    12/88   092/88
Energy Efficiency Improvement in the Brick and
Tile Industry (English)                                   02/89   097/89
Tobacco Curing Pilot Project (English)                     03/89   UJNDP Terminal
Report
Energy Assessment (English)                                12/96   193/96
Zaire          Energy Assessment (English)                                05/86   5837-ZR
Zambia         Energy Assessment (English)                                01/83   4110-ZA
Status Report (English)                                    08/85   039/85
Energy Sector Institutional Review (English)               11/86   060/86
Power Subsector Efficiency Study (English)                 02/89   093/88
Energy Strategy Study (English)                            02/89   094/88
Urban Household Energy Strategy Study (English)            08/90   121/90
Zimbabwe       Energy Assessment (English)                                06/82   3765-ZIM
Power System Efficiency Study (English)                    06/83   005/83
Status Report (English)                                    08/84   019/84
Power Sector Management Assistance Project (English)       04/85   034/85
Power Sector Management Institution Building (English)     09/89   --
Petroleum Management Assistance (English)                  12/89   109/89
Charcoal Utilization Prefeasibility Study (English)        06/90   119/90
Integrated Energy Strategy Evaluation (English)            01/92   8768-ZIM
Energy Efficiency Technical Assistance Project:
Strategic Framework for a National Energy Efficiency
Improvement Program (English)                             04/94   --
Capacity Building for the National Energy Efficiency
Improvement Programme (NEEIP) (English)                   12/94
EAST ASIA AND PACIFIC (EAP)
Asia Regional   Pacific Household and Rural Energy Seminar (English)       11/90
China          County-Level Rural Energy Assessments (English)            05/89   101/89
Fuelwood Forestry Preinvestment Study (English)            12/89   105/89
Strategic Options for Power Sector Reform in China (English)  07/93   156/93
Energy Efficiency and Pollution Control in Township and
Village Enterprises (TVE) Industry (English)              11/94   168/94
Energy for Rural Development in China: An Assessment Based
on a Joint Chinese/ESMAP Study in Six Counties (English)  06/96   183/96
Fiji           Energy Assessment (English)                                06/83   4462-FIJ



-5 -
Region/Country                      Activity/Report Title                  Date  Number
Indonesia      Energy Assessment (English)                                11/81   3543-IND
Status Report (English)                                   09/84   022/84
Power Generation Efficiency Study (English)                02/86   050/86
Energy Efficiency in the Brick, Tile and
Lime Industries (English)                                04/87   067/87
Diesel Generating Plant Efficiency Study (English)         12/88   095/88
Urban Household Energy Strategy Study (English)            02/90   107/90
Biomass Gasifier Preinvestment Study Vols. I & II (English)  12/90   124/90
Prospects for Biomass Power Generation with Emphasis on
Palm Oil, Sugar, Rubberwood and Plywood Residues (English)    11/94   167/94
Lao PDR        Urban Electricity Demand Assessment Study (English)        03/93   154/93
Malaysia       Sabah Power System Efficiency Study (English)              03/87   068/87
Gas Utilization Study (English)                           09/91   9645-MA
Myanmar        Energy Assessment (English)                                06/85   5416-BA
Papua New
Guinea        Energy Assessment (English)                                06/82   3882-PNG
Status Report (English)                                   07/83   006/83
Energy Strategy Paper (English)
Institutional Review in the Energy Sector (English)        10/84   023/84
Power Tariff Study (English)                               10/84   024/84
Philippines    Commercial Potential for Power Production from
Agricultural Residues (English)                           12/93   157/93
Energy Conservation Study (English)                       08/94   --
Solomon Islands Energy Assessment (English)                               06/83   4404-SOL
Energy Assessment (English)                               01/92   979-SOL
South Pacific    Petroleum Transport in the South Pacific (English)       05/86   --
Thailand       Energy Assessment (English)                                09/85   5793-TH
Rural Energy Issues and Options (English)                 09/85   044/85
Accelerated Dissemination of Improved Stoves and
Charcoal Kilns (English)                                 09/87   079/87
Northeast Region Village Forestry and Woodfuels
Preinvestment Study (English)                            02/88   083/88
Impact of Lower Oil Prices (English)                      08/88   --
Coal Development and Utilization Study (English)           10/89   --
Tonga          Energy Assessment (English)                                06/85   5498-TON
Vanuatu        Energy Assessment (English)                                06/85   5577-VA
Vietnam        Rural and Household Energy-Issues and Options (English)    01/94   161/94
Power Sector Reform and Restructuring in Vietnam: Final Report
to the Steering Committee (English and Vietnamese)        09/95   174/95
Household Energy Technical Assistance: Improved Coal
Briquetting and Commercialized Dissemination of Higher
Efficiency Biomass and Coal Stoves (English)              01/96   178/96
Western Samoa  Energy Assessment (English)                                06/85   5497-WSO
SOUTH ASIA (SAS)
Bangladesh     Energy Assessment (English)                                10/82   3873-BD
Priority Investment Program (English)                     05/83   002/83
Status Report (English)                                   04/84   015/84
Power System Efficiency Study (English)                   02/85   031/85
Small Scale Uses of Gas Prefeasibility Study (English)     12/88   --



-6 -
Region/Country                      Activity/lReport Title                  Date  Number
India          Opportunities for Commercialization of Nonconventional
Energy Systems (English)                                   11/88   091/88
Maharashtra Bagasse Energy Efficiency Project (English)     07/90   120/90
Mini-Hydro Development on Irrigation Dams and
Canal Drops Vols. I, II and III (English)                  07/91   139/91
WindFarm Pre-Investment Study (English)                     12/92   150/92
Power Sector Reform Seminar (English)                       04/94.  166/94
Nepal          Energy Assessment (English)                                 08/83   4474-NEP
Status Report (English)                                    01/85   028/84
Energy Efficiency & Fuel Substitution in Industries (English)  06/93   158/93
Pakistan       Household Energy Assessment (English)                       05/88   --
Assessment of Photovoltaic Programs, Applications, and
Markets (English)                                          10/89   103/89
National Household Energy Survey and Strategy Formulation
Study: Project Terminal Report (English)                  03/94   --
Managing the Energy Transition (English)                    10/94
Lighting Efficiency Improvement Program
Phase 1: Commercial Buildings Five Year Plan (English)     10/94
Sri Lanka      Energy Assessment (English)                                 05/82   3792-CE
Power System Loss Reduction Study (English)                 07/83   007/83
Status Report (English)                                     01/84   010/84
Industrial Energy Conservation Study (English)              03/86   054/86
EUROPE AND CENTRAL ASIA (ECA)
Bulgaria       Natural Gas Policies and Issues (English)                    10/96   188/96
Central and
Eastern Europe  Power Sector Reform in Selected Countries                  07/97   196/97
Eastem Europe  The Future of Natural Gas in Eastem Europe (English)        08/92   149/92
Kazahstan      Natural Gas Investment Study, Volumes 1, 2 & 3               12/97   199/97
Kazahstan &
Kyrgyzstan     Opportunities for Renewable Energy Development              11/97   16855-KAZ
Poland         Energy Sector Restructuring Program Vols. I-V (English)     01/93   153/93
Portugal       Energy Assessment (English)                                 04/84   4824-PO
Romania        Natural Gas Development Strategy (English)                   12/96   192/96
Turkey         Energy Assessment (English)                                  03/83   3877-TU
MIDDLE EAST AND NORTH AFRICA (MNA)
Arab Republic
of Egypt       Energy Assessment (English)                                 10/96   189/96
Morocco        Energy Assessment (English and French)                       03/84   4157-MOR
Status Report (English and French)                          01/86   048/86
Energy Sector Institutional Development Study (English and French) 07/95   173/95
Syria          Energy Assessment (English)                                 05/86   5822-SYR
Electric Power Efficiency Study (English)                   09/88   089/88
Energy Efficiency Improvement in the Cement Sector (English)  04/89   099/89
Energy Efficiency Improvement in the Fertilizer Sector (English)    06/90   115/90



-7-
Region/Country                      Activit/Report Title                    Date  Number
Tunisia        Fuel Substitution (English and French)                      03/90   --
Power Efficiency Study (English and French)                02/92   136/91
Energy Management Strategy in the Residential and
Tertiary Sectors (English)                                04/92   146/92
Renewable Energy Strategy Study, Volume I (French)          11/96   190A/96
Renewable Energy Strategy Study, Volume II (French)         11/96   190B1/96
Yemen          Energy Assessment (English)                                  12/84   4892-YAR
Energy Investment Priorities (English)                     02/87   6376-YAR
Household Energy Strategy Study Phase I (English)          03/91   126/91
LATIN AMERICA AND THE CARIBBEAN (LAC)
LAC Regional   Regional Seminar on Electric Power System Loss Reduction
in the Caribbean (English)                                07/89   --
Elimination of Lead in Gasoline in Latin America and
the Caribbean (English and Spanish)                       04/97   194/97
Elimination of Lead in Gasoline in Latin America and
the Caribbean Phase II - Status Report (English and Spanish)  12/97   200/97
Harmonization of Fuels Speficifications in Latin America and
the Caribbean (English and Spanish)                       06/98   203/98
Bolivia        Energy Assessment (English)                                 04/83   4213-BO
National Energy Plan (English)                              12/87   --
La Paz Private Power Technical Assistance (English)         11/90   111/90
Prefeasibility Evaluation Rural Electrification and Demand
Assessment (English and Spanish)                          04/91   129/91
National Energy Plan (Spanish)                              08/91   131/91
Private Power Generation and Transmission (English)        01/92   137/91
Natural Gas Distribution: Economics and Regulation (English)  03/92   125/92
Natural Gas Sector Policies and Issues (English and Spanish)  12/93   164/93
Household Rural Energy Strategy (English and Spanish)      01/94   162/94
Preparation of Capitalization of the Hydrocarbon Sector     12/96   191/96
Brazil         Energy Efficiency & Conservation: Strategic Partnership for
Energy Efficiency in Brazil (English)                     01/95   170/95
Hydro and Thermal Power Sector Study                       09/97   197/97
Chile          Energy Sector Review (English)                              08/88   7129-CH
Colombia       Energy Strategy Paper (English)                             12/86   --
Power Sector Restructuring (English)                        11/94   169/94
Energy Efficiency Report for the Commercial
and Public Sector (English)                               06/96   184/96
Costa Rica     Energy Assessment (English and Spanish)                     01/84   4655-CR
Recommended Technical Assistance Projects (English)         11/84   027/84
Forest Residues Utilization Study (English and Spanish)    02/90   108/90
Dominican
Republic      Energy Assessment (English)                                 05/91   8234-DO
Ecuador        Energy Assessment (Spanish)                                  12/85   5865-EC
Energy Strategy Phase I (Spanish)                          07/88   --
Energy Strategy (English)                                  04/91   --



-8 -
Region/Country                      Activity/Report Title                  Date  Number
Ecuador        Private Minihydropower Development Study (English)          11/92   --
Energy Pricing Subsidies and Interfuel Substitution (English)  08/94   11798-EC
Energy Pricing, Poverty and Social Mitigation (English)    08/94   1283 I-EC
Guatemala      Issues and Options in the Energy Sector (English)          09/93   12160-GU
Haiti          Energy Assessment (English and French)                     06/82   3672-HA
Status Report (English and French)                         08/85   041/85
Household Energy Strategy (English and French)             12/91   143/91
Honduras       Energy Assessment (English)                                08/87   6476-HO
Petroleum Supply Management (English)                      03/91   128/91
Jamaica        Energy Assessment (English)                                04/85   5466-JM
Petroleum Procurement, Refining, and
Distribution Study (English)                              11/86   061/86
Energy Efficiency Building Code Phase I (English)          03/88   --
Energy Efficiency Standards and Labels Phase I (English)   03/88   --
Management Information System Phase I (English)            03/88   --
Charcoal Production Project (English)                      09/88   090/88
FIDCO Sawmill Residues Utilization Study (English)         09/88   088/88
Energy Sector Strategy and Investment Planning Study (English)    07/92   135/92
Mexico         Improved Charcoal Production Within Forest Management for
the State of Veracruz (English and Spanish)               08/91   138/91
Energy Efficiency Management Technical Assistance to the
Comision Nacional para el Ahorro de Energia (CONAE) (English)  04/96   180/96
Panama         Power System Efficiency Study (English)                    06/83   004/83
Paraguay       Energy Assessment (English)                                 10/84   5145-PA
Recommended Technical Assistance Projects (English)        09/85   --
Status Report (English and Spanish)                        09/85   043/85
Peru           Energy Assessment (English)                                01/84   4677-PE
Status Report (English)                                    08/85   040/85
Proposal for a Stove Dissemination Program in
the Sierra (English and Spanish)                          02/87   064/87
Energy Strategy (English and Spanish)                      12/90   --
Study of Energy Taxation and Liberalization
of the Hydrocarbons Sector (English and Spanish)         120/93   159/93
Saint Lucia    Energy Assessment (English)                                09/84   5111-SLU
St. Vincent and
the Grenadines Energy Assessment (English)                               09/84   5103-STV
Trinidad and
Tobago        Energy Assessment (English)                                 12/85   5930-TR
GLOBAL
Energy End Use Efficiency: Research and Strategy (English)  11/89
Women and Energy--A Resource Guide
The International Network: Policies and Experience (English)  04/90   --
Guidelines for Utility Customer Management and
Metering (English and Spanish)                            07/91
Assessment of Personal Computer Models for Energy
Planning in Developing Countries (English)                10/91
Long-Term Gas Contracts Principles and Applications (English)  02/93   152/93



-9 -
Region/Country                      Activity/Report Title                  Date  Number
GLOBAL (Continuation)
Comparative Behavior of Firms Under Public and Private
Ownership (English)                                      05/93   155/93
Development of Regional Electric Power Networks (English)  10/94   --
Roundtable on Energy Efficiency (English)                  02/95   171/95
Assessing Pollution Abatement Policies with a Case Study
of Ankara (English)                                       11/95   177/95
A Synopsis of the Third Annual Roundtable on Independent Power
Projects: Rhetoric and Reality (English)                 08/96   187/96
Rural Energy and Development Roundtable (English)         05/98   202/98
06/26/98



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ESMAP
The World Bank
1818 H Street, N. W.
Washington, D. C. 20433
U. S. A.
Joint United Nations Development Programme / World Bank
KLIQ  E S AMAP
Energy Sector Management Assistance Programme