NILE BASIN INITIATIVE - World Banksiteresources.worldbank.org/EXTAFRNILEBASINI/Resources/...THE WORLD BANK In collaboration with 016223-007-02 NILE BASIN INITIATIVE NILE EQUATORIAL

THE WORLD BANK

In collaboration with

016223-007-02

NILE BASIN INITIATIVENILE EQUATORIAL LAKES

SUBSIDIARY ACTION PROGRAM

Strategic/Sectoral, Social and Environmental Assessment of Power Development Options

in The Nile Equatorial Lakes Region

Stage II

Synopsis of the Final Report

November 2005

SSEA II - Synopsis i 016223-007-02

Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in the Nile Equatorial Lakes Region Stage II Burundi, Democratic Republic of Congo, Kenya, Rwanda, Tanzania and Uganda

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

2 INTRODUCTION............................................................................5

3 REGIONAL DEVELOPMENT CONTEXT......................................8

4 ALTERNATIVE SCENARIOS OF REGIONAL POWER NEEDS 10

5 POWER OPTIONS IDENTIFICATION AND SCREENING..........12 5.1 Options Identification 12 5.2 Project Screening 12

6 DESCRIPTION OF POWER DEVELOPMENT OPTIONS...........15 6.1 Introduction 15 6.2 Hydroelectric Options 15 6.3 Gas-fired and Coal-fired Thermal Options 19 6.4 Geothermal Power Options 19 6.5 Wind Power Options 20 6.6 Lake Kivu Methane Development 20

7 COMPARATIVE ANALYSIS OF OPTIONS ................................21 7.1 Introduction 21 7.2 Multi-Criteria Analysis 21 7.3 Risk Analysis 21 7.4 Results of the Multi-Criteria Analysis 22 7.5 Selection of Options to be Included in Power Development Portfolios 24

8 POWER DEVELOPMENT PORTFOLIOS – DEFINITIONS AND COMPARISONS ..........................................................................27 8.1 Load – Resource Balance 27 8.2 Definition of Development Strategies 28 8.3 Definition of Portfolios for each Strategy 28 8.4 Transmission Requirements 30 8.5 Cumulative Impacts 32 8.6 Comparison of Strategies under Base Load Growth Scenario 33 8.7 Sensitivity Analyses 35 8.8 Comparison of Strategies Across Load Growth Scenarios 37

9 CONCLUSIONS AND RECOMMENDATIONS ...........................38 9.1 Conclusions 38 9.2 Recommendations 39 9.3 Benefits of Key Power Development Options 41 9.4 Institutional Issues 41

SSEA II - Synopsis 1 016223-007-02

1 EXECUTIVE SUMMARY

The Nile Basin Initiative (NBI) provides for an agreed basin-wide framework to collectively fight poverty and promote socio-economic development in the ten Nile countries (Burundi, the Democratic Republic of Congo (DRC), Egypt, Eritrea, Ethiopia, Kenya, Rwanda, Sudan, Tanzania and Uganda). Under the NBI framework, the Strategic/Sectoral, Social and Environmental Assessment (SSEA) of Power Development Options in the Nile Equatorial Lakes Region (Burundi, Eastern Democratic Republic of Congo, Kenya, Rwanda, Tanzania and Uganda) was carried out. This assessment, financed by the Canadian Government, was made by Canadian consultants retained by the World Bank, under the guidance of a steering committee and a group of stakeholders, both representing the participating countries.

This assessment, which is a part of the strategic planning for NELSAP, is also a prerequisite to IDA investment in selected power generation activities under NELSAP. This SSEA has therefore been undertaken in partnership with the NELSAP riparian countries and involved them in each step of its implementation.

Objectives

The objective of this SSEA of Power Development Options is therefore two-fold. Firstly, it will serve as an instrument to prepare the Bank and other investors for possible requests to support the NELSAP power development program. Secondly, it will assist the NELSAP riparian countries in their selection of supply options (including interconnections) by contributing to informed and transparent decision-making before major funds to investigate individual options are committed.

The expected result is better definition of the actions that must, in the advancement and approval of new generation and transmission projects, be taken to improve electricity supply, in terms of reliability of supply, cost, environmental and social acceptability, and regional integration.

Scope

To achieve these results the scope of the assessment included the following seven steps:

• Review of energy policy, legal and administrative frameworks

• Energy needs assessments (load growth forecasts)

• Identification and screening of new power options

• Definition of portfolios of options (future generation plans) for each of the selected development strategies

• Assessment of cumulative impacts for each sequence of development

• Risk analysis and comparative analysis of power options

• Evaluation of requirements for mitigation measures for selected options


The assessment was carried out in two stages. Stage I covered Burundi, Rwanda and West Tanzania, while Stage II added the eastern region of the Democratic Republic of the Congo, Kenya, Tanzania and Uganda, and considered the region as a whole.

Portfolios were developed for, and comparisons made for three development strategies:

Strategy 1 - Maximise the use of best-evaluated options

Strategy 2 - Technological diversification - to avoid over dependence on hydro

Strategy 3 - Geographic diversification to approximately match loads and supply in each country

Key findings:

• The total demand for electricity in the six-country region will increase by 2,800 MW, and 16,000 GWH over the period 2005 to 2020 under base (i.e. average or medium) load growth conditions. By comparison the peak demand would increase by 4,100 MW in a high economic growth scenario. These values exclude the additional amount of reserve that would be required for supply reliability.

• By the end of the period of analysis (2020) virtually all of the identified power development options that have low environmental and social impacts will have been used to meet demand increases under the base load growth scenario.

• Development strategies that seek to improve geographical (by country) or technological (limit hydro dependency) diversification will result in selection of more projects with environmental/social risks.

• Apart from options located in national parks, the cumulative impacts on the social and physical environment are relatively minor; the most significant are emissions from thermal plants and potential impacts on wetlands in the Kagera River and the Rufiji River.

• Even the most hydro-intensive portfolio would not have any effects on the Albert Nile leading to Sudan and the Sudd Marshes.

Recommendations

This SSEA assessment resulted in the following recommendations that were developed from consultations with the PSC and stakeholders:

• Recommendation A: Three projects: Bujagali, Rusumo Falls (both hydro) and diesel type generation using naturally occurring methane gas at Lake Kivu should be implemented as soon as possible. Justification: the countries involved (Uganda, Rwanda and Burundi) are now suffering from serious power outages. The only power options that could be installed in the short to mid-term are those listed, and these are also low cost and with acceptable environmental and social


impacts. This recommendation is not affected by the choice of development strategy.

• Recommendation B: A number of other projects, notably: Kabu 16, Kakono, Ruzizi III and Ruhudji (all hydro), geothermal in Kenya and Songo Songo gas-fired plant in Tanzania should be prepared for implementation at an early date. Justification: all planning studies show that these projects will be required on-power in the mid-term say 2014-2018, based on the medium or base load growth scenario, irrespective of the development strategy selected.

• Recommendation C: The countries in the region should move immediately towards a high degree of power system interconnection and ultimately integration. Justification: Economies of scale are likely to reduce costs in most of the countries involved and synergies would be available from the mix of technological resources (geothermal in Kenya, methane gas from Lake Kivu, natural gas in Tanzania and hydro in Uganda as well as DRC, Tanzania and Rwanda. Integration would facilitate use of projects with the lowest environmental and social risks

• Recommendation D: In the DRC, actions should be taken as soon as possible to prepare, develop and finance in the order of 100 MW of existing hydro options that need to be rehabilitated, and to strengthen the associated transmission, in the eastern DRC provinces.

Recommendations resulting from this assessment, in the form of year-by-year actions required by each country, are presented at the end of this report. These are actions that are urgently required in order to eliminate the current shortages of power and to ensure that sufficient power is available in the future to meet the load with a reasonable and realistic reserve margin.


Map showing the Nile River Countries

SSEA II – Synopsis 5 016223-007-02

2 INTRODUCTION

The Nile Basin Initiative (NBI) provides for an agreed basin-wide framework to fight poverty and promote socio-economic development in the ten Nile countries (Burundi, the Democratic Republic of Congo (DRC), Egypt, Eritrea, Ethiopia, Kenya, Rwanda, Sudan, Tanzania and Uganda). Under the NBI framework, the Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in the Nile Equatorial Lakes was carried out in two stages; a first stage covering Burundi, Rwanda and Western Tanzania and a second stage that adds the remainder of Tanzania, Kenya, Uganda and the eastern provinces of the Democratic Republic of Congo.

The overall objective of the SSEA is to facilitate informed and transparent decision-making - specifically directed to those power projects (generation and transmission) that should be implemented.

The assessment of Stage I was presented in February 2005; this assessment of Stage II is presented in three separate reports: this summary synopsis report, a main report and a report on stakeholder consultation.

The main conclusions of Stage I were:

• Some diesel plant should be installed as soon as possible to alleviate the current power shortages.

• Two hydro projects: Rusumo Falls (62 MW, Tanzania/Rwanda) and Kabu 16 (20 MW, Burundi) should be prepared for implementation, also as soon as possible.

• Generation from the first set of diesel type engines using naturally occurring methane gas in Lake Kivu (Rwanda/DRC – with project in Rwanda, 30 MW groups of engines) should be implemented as soon as possible.

• A backbone transmission system should be constructed to link the three power systems and permit power interchanges.

The Stage I SSEA provides one basic starting point for Stage II in that it has defined the basic characteristics of potential power projects in the Stage I region. The second key reference source of data is the East African Power Master Plan (EAPMP). This was documented in a final report dated February 2005.

The EAPMP covered the three EAC countries: Kenya, Tanzania and Uganda. It was a conventional least cost system expansion planning assessment. However although project selection and prioritization reflected environmental issues; unlike the SSEA, it does not consider social and environmental risks in the same level of detail, and does not include cumulative assessment of impacts. The main focus of the EAPMP was to analyze the viability of large-scale interconnection of the three power systems. The main conclusion of the EAPMP was to endorse full integration of the power systems as soon as possible. The

The Nile Basin Initiative (NBI) provides for an agreed basin-wide framework to fight poverty and promote socio-economic development in the ten Nile countries

Work included: ♦ Review of existing

situation ♦ Review legal and

administrative frameworks

♦ Assessment of needs ♦ Identification and

technical screening of options

♦ Comparison of options using environmental and social criteria

♦ Definition of portfolios of options,

♦ Identification of cumulative impacts and mitigation measures


EAPMP report provided basic data on the potential power projects in the EAC countries.

The Stage II assessment therefore took the SSEA I and EAPMP information and results, added an assessment of eastern DRC needs and options, and integrated these with further investigations and analyses to provide the complete SSEA II assessment for the six-country region.

The figure below provides an overview of the process followed by the SSEA project to respond to the terms of reference and to respond to the issues raised by the Steering Committee and the stakeholder representatives.

Process Followed for SSEA of Power Development Options

Selection of medium and long - term portfolios of options

Indicative sub - regional power development

Detailed preparation and implementation atregional NBI/NELSAP level in Burundi, Rwanda and Western Tanzania

Policy, Legal and Administrative Review

Regional Power Needs AssessmentInventory of Options

Screening of Options

Comparative Analysis of Options (Multi-criteria analysis on environmental and social issues and Risk assessment)

Definition of Strategies to meet power demand

Selection of medium and long - term portfolios of options

Cumulative impact assessment and mitigation measures for portfolios

System Planning and Indicative Least Cost Plan for the NEL region

Detailed preparation and implementation at regional NBI/NELSAP level

By Consultant and reviewed by PSC and Stakeholders Participation of Stakeholders (including PSC)By Countries, subsequent to SSEA

Legend:

Ranking of Options (Best evaluated and other options)

This synopsis report summarizes the detailed presentations given in the main report, and is organized as follows:

Chapter 2 Introduction - to define the starting point for the stage 2 assessment for the six countries and to outline the methodological process that has been applied.

Chapter 3 Regional development context – that provides the socio-economic context in the region as a basis for the projection of power needs.

The assessment takes account of the EAPMP and SSEA Stage I results

Regional power experts and other stakeholders had key involvement in the process


Chapter 4 Scenarios of regional power needs – that outlines the basis for the different growth rates and consequent forecasts of electricity demands that have been developed for the period 2005 to 2020.

Chapter 5 Power options identification and screening – that describes how all the known new power options for the region were identified and passed through an initial screening process.

Chapter 6 Description of Power Development Options – including size, location and associated socio-economic and environmental issues.

Chapter 7 Comparative analysis of new power options – which describes the multi-criteria method of analysis to provide an assessment that combines cost-effectiveness with social and environmental facts and risk. this resulted in the separation of candidate options into a “best evaluated” group and the remaining group, which in turn provided the basis for priorization of new power options in the development of new generation sequences (portfolios).

Chapter 8 Power development portfolios, definition and comparison – which defines the alternative power development strategies to meet load growth that were developed, the corresponding regional transmission grid additions, cumulative socio-environmental impacts that could result from the construction of each sequence of power options, and comparison of total system costs for the alternative portfolios and thus strategies. These comparative results should provide the key inputs for the development of policies in the region for new power and transmission development.

Chapter 9 Conclusions and recommendations – that focuses on the findings of this SSEA assessment and the conclusions that may be drawn in defining the way forward.

This report is in nine chapters: ♦ The executive

summary ♦ Introduction ♦ Regional context ♦ Power needs ♦ Identification and

screening of options Description of options

♦ Comparison of options♦ Development of

portfolios ♦ Conclusions and

recommendations


3 REGIONAL DEVELOPMENT CONTEXT

The Nile Equatorial Lakes region has, for this assessment, been defined to include Burundi, Kenya, Rwanda, Tanzania, Uganda and the eastern part of the Democratic Republic of Congo (e.g.: Kivu-Sud and Kivu-Nord provinces and the eastern parts of Orientale, Maniema and Katanga provinces). The combined population of the region was estimated to be in the order of 120 million in 2002-2003, including 7.0 million in Burundi, 31.9 million in Kenya, 8.0 million in Rwanda, 35.2 million in Tanzania, 25.3 million in Uganda and 12.5 million in eastern DRC.

The Nile Equatorial Lakes region is dominated by a series of interconnected lakes that provide natural storage and act as a purifier and oxygenator for the White Nile: Lake Victoria, which is by far the largest at 69,000 km2, followed by the three other major lakes of the East African Rift Valley – Lakes Albert (5,660 km2), Kyoga (5,600 km2) Edward (2,340 km2) that are linked to Lake Victoria by the Victoria Nile. The network of lakes that characterizes this sub-basin is rich with floodplains, wetlands and smaller satellite lakes that support an abundant diversity of animals and plants and many water-dependant ecosystems. It constitutes one of the most important areas in Africa for biological diversity and food production.

Table 1 provides a regional overview of historic growth rates, with recent encouraging trends and investment rates.

Table 1– Summary of Regional Trends Related to Annual Growth Rates of Gross National Income (1982-2004)

Country Annual Growth

Rates (1982-1992)

Annual Growth Rates (1992-

2002) Growth Rate

in 2003 Estimated

Growth Rate in 2004

Investment Rate (% of GNI

2001-03)

Burundi 4.1 -1.8 -1.0 5.1 6.7

DR of Congo 0.0 0.0 5.0 6.3 5.1

Kenya 3.4 1.9 1.5 2.2 13.9

Rwanda 2.5 1.4 3.2 6.0 18.3

Tanzania 3.4 4.0 5.5 6.3 16.9

Uganda 3.4 7.0 4.9 5.7 20.2

Sources: World Bank, World Development Indicators Database, 2005; IMF, World Economic Outlook, 2005; L’État du monde, Annuaire géopolitique 2005, Ed. La Découverte/Boréal, 2004; and Jeune Afrique, The Africa Report, Africa Survey 2005, May 2005. Each of the countries is currently served by more-or-less independent power systems. There some very limited power exchanges and interconnections. The total combined installed capacity in 2002 was 2340 MW. The combined peak demand at that time was estimated at some 1700 MW. However, given the lack of interconnections these two values do not indicate an adequate supply situation. Table 2 presents the estimated situation in 2002. The figures are approximate for two reasons:

Region studied: Burundi, Kenya, Rwanda, Tanzania, Uganda and Eastern Provinces of DRC

Regional economies seem to be improving


• Some of the existing generation is unreliable so cannot be counted upon to meet the load.

• For some countries with where the supply was insufficient to meet the demand, the demand required if there had been enough supply needs to be estimated.

Table 2 – Comparison of Supply and Demand in 2002

Capacity Available Estimated Demand Country

(MW) Year (MW) Year

Current deficit or estimated

year of deficit Rwanda 28.7 MW 2002 30 MW 2002 2004 Burundi 37.2 MW 2002 30 MW 2002 2004 Uganda 327 MW 2002 280 MW 2002 by 2005 Tanzania 785 MW 2002 500 MW 2002 by 2005-2007 Kenya 1,121 MW 2002 800 MW 2002 by 2005-2007 East-DRC 40 MW 2002 50 MW 2002 10 MW

Currently, load cannot be met in some countries


4 ALTERNATIVE SCENARIOS OF REGIONAL POWER NEEDS

A Regional Power Needs Assessment provides the fundamental input to the power planning process. It serves as a vital component for the subsequent consideration, evaluation and comparison of power generation options in the NELSAP region.

Because of the high degree of uncertainty in the forecasting of electric power consumption (or, for that matter, the consumption of any good) for many years into the future, a range of forecasts is provided for the region as a whole – a base growth scenario and a range about this base that gets wider over the years. These were based in large part on existing forecasts (following critical review), including those in the EAPMP. These forecasts are based primarily on the extrapolation of historic growth of gross national product, and rate of electrification, using various degrees of optimism.

As noted earlier, the load in 2002 was estimated at 1690 MW. The forecasts suggest that this would increase to 3400 MW for the low load growth scenario, 4700 MW for the base scenario and to 6100 MW. For the high scenario. The difference is based on the assumed growth rates of gross domestic product and the rate of electrification, particularly in rural areas.

From a planning perspective it is conservatively logical to plan for the possible higher load forecast.

An alternative ‘transformation’ scenario was also considered. Transformation, in this case, denotes a degree of development sufficient to meet the ‘Lake Victoria Vision’ which assumes that the population of the region would enjoy “a comfortable standard of living” by 2020. The vision does not define the level of comfort; for purposes of this assessment it is assumed that the region would have to reach a level of gross national income per capita equal to one of the best in Africa1 (excluding those countries whose wealth comes from natural resources). This would require annual growth rates of both GNP and electricity consumption of about 15%. The net result is an expected peak demand of some 10,500 MW in 2020, more than twice the base case forecast.

The results of the regional load forecast are illustrated graphically in Figure 1. The relative contribution of each country to the total energy requirements and peak demand over time is illustrated for the base case in Figure 2.

The loads in this section exclude any allowance for reserve margin.

1 The best five are Republic of South Africa, Botswana, Morocco, Algeria and Egypt;

the first two were not considered and Egypt is situated between the remaining two and was used as the target

Needs assessment is a fundamental input

Because of uncertainties, forecast should be considered as a range of likely values

Base, low and high values are variations on status quo

Need also to consider how to transform the region out of poverty


Figure 1 - Regional Power Needs Assessment in the NELSAP

Region for the Period 2005-2020

Regional Peak Demand

0

2,000

4,000

6,000

8,000

10,000

12,000

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Year

Pea

k P

ower

(MW

Low

High

Base

Regional Transformation Forecast

Figure 2 - Regional Power Needs Assessment per Country – Base Case

-

500

1 000

1 500

2 000

2 500

3 000

3 500

4 000

4 500

5 000

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Year

Peak

Dem

and

(MW

) Peak Demand - Base Case

Kenya

Tanzania

Uganda RwandaBurundiEast DRC

Peak demand in 2020:♦ 3400 to 6100 MW

under variations on present economic expectations

♦ 10,500 MW needed to transform

♦ To this must be added an allowance for reserve margin


5 POWER OPTIONS IDENTIFICATION AND SCREENING

5.1 Options Identification

All potential sources of information were researched to obtain information on options that had been previously identified, and to collect the information required for this SSEA assessment, however the EAPMP and Stage I SSEA provided the most data. Both studies developed information on new power options directly from the latest project reports, including reconnaissance, pre-feasibility and feasibility studies, as well as environmental assessments. The main information required included: the physical characteristics, generation capability, estimated cost, social and environmental impacts in so far as these had been assessed in any prior studies. For thermal options information on fuel costs was also a major component. A key additional factor was the relative quality of the data, which is in turn a function of the quality (and date of issue) of the last assessment. The information on options, notably cost estimates, was updated and completed in supplementary studies by the consultant, with further information being provided by the Steering Committee and the Stakeholders.

The main energy resources within the region are hydro, geothermal, natural gas and coal but with the relative exception of hydro, none of these natural resources are abundant.

The softer renewable energy sources i.e. wind, solar and biomass were also evaluated, but they are unlikely to make any significant contribution over the planning horizon in the context of the expected load increase. Demand Side Management and more particularly efforts to reduce losses and improve efficiency in energy usage are promising and should be continuously pursued, but of their very nature cannot be expected to offset a significant portion of the growth in demand, and thus affect overall estimated new generation requirements.

5.2 Project Screening

The objective of the screening analysis was to eliminate those projects unlikely to be implemented – for a variety of reasons – during the planning period, which extended to 2020. Four screening criteria were established;

• A: quality and availability of data. This was effectively applicable only to the hydro projects which of their nature require relatively extensive investigations and detailed assessment. The general principle adopted was to accept those projects with pre-feasibility level (or better) assessment reports available.

All sources studied: ♦ EAPMP ♦ SSEA Stage I ♦ Steering

Committee ♦ Stakeholders ♦ Consultant’s

internal files


• B: Options with no severe negative social or environmental impacts that were unlikely to be mitigated or offset.

• C: Options with an estimated firm energy cost of less than 10c/kWh. This value was adopted after analysis showed that the majority of the hydro projects had a significantly lower cost. This is also a representative cost for coal-fired thermal plant at the coast – the ultimate back-up energy source.

• D: Options above a minimum project size; set at 30 MW for the EAC countries and 10 MW for Burundi, Rwanda and the Eastern DRC. Smaller projects are unlikely to have any significant impact in the regional context and are hence not assessed in this regional SSEA.

The net result was to eliminate some 2480 MW of hydro projects. All of the geothermal, natural gas, Mchuchuma coal and Lake Kivu methane capacity was retained. The rationale for eliminating the hydro projects was:

• 520 MW due to lack of adequate data, typically these projects (many of which are in the DRC) had been studied at reconnaissance level only. (Criterion A above);

• 830 MW due to probable unacceptable social or environmental impacts (Criterion B);

• 1100 MW due to high energy cost, mostly in Kenya (Criterion C);

• 30 MW were too small (Criterion D).

Table 3 shows the options that were retained based on the above criteria.

7940 MW of resources identified ♦ 5460 MW

retained after screening

♦ 2480 MW screened out

Of 2480 MW screened out, 520 MW were due to lack of information: with additional study some or all of these could be considered


Table 3 - NELSAPSAP Region - New Power Options Retained after Screening


6 DESCRIPTION OF POWER DEVELOPMENT OPTIONS

6.1 Introduction

The power development options that were retained from the screening process are described briefly below. These options are then taken the next step of being compared using the multi-criterion analysis which explicitly considers socio-economic and environmental issues. For each option, the size and location are given as well as the significant environmental and social issues related to it.

Power development options all have environmental and social impacts some of which are positive and some of which are negative. All options create employment, both during construction and during operation. In addition, all power projects that are located in areas with no access to electricity facilitate rural electrification, which in turn allows for improved health and education services and more opportunities for business development. Other positive impacts are specific to hydroelectric projects with a reservoir that offer opportunities for other uses such as flood control, irrigation, fisheries and water supply.

6.2 Hydroelectric Options

Ayago South Hydroelectric Development:

234 MW run of river project with no pondage on the Victoria Nile in Murchison National Park in Uganda (alternate to Ayago North).

Reservoir impact would be minimal and would provide additional habitats for wildlife.

The dam would constitute a barrier to fish movement. Located in Murchison National Park.

Bujagali Hydroelectric Development:

250 MW run of river project with pondage on the Victoria Nile in Uganda, 8 km downstream of the existing Kiira/Owen Falls hydroelectric projects.

Would result in loss of habitats for birds, bats and other animals. There would be no additional impacts on water flows downstream Resettlement in project-affected areas has already been carried

out. The flooding would involve impacts on aesthetics and loss of white

water rafting opportunity over 2.5 km from Bujagali Falls to Dumbbell Island.

A risk of increase of breeding sites for snail vectors of bilharzia.

Impacts can be positive or negative

Positive impacts include: ♦ job creation ♦ improve access to

electrification in rural areas

Ayago South ♦ 234 MW ♦ located in

National Park

Bujagali ♦ 250 MW ♦ some loss of

white water rafting opportunities


Kabu 16 Hydroelectric Development:

20 MW run of river project with hourly pondage in Burundi on the Kaburantwa River, 16 km above its confluence with the Ruzizi River.

The reservoir impact would be minimal. There would be a 3 km river stretch with reduced flow between

dam and tailrace. During the dry period of 5 months/year, flow and level variations

would be experienced downstream in the river stretch between the tailrace and the Ruzizi River.

Some 75 persons would be displaced from the head pond and project area.

Kakono Hydroelectric Development:

53 MW in Tanzania on the Kagera River near the Uganda border, approximately 90 km to the west of the city of Bukoba and Lake Victoria.

Part of the benefit would be the provision of irrigation water. The project would flood part of the Minziro Forest Reserve. The plant could cause downstream flow and level variations over

75 % of the year. The reservoir could involve significant resettlement.

Kalagala Hydroelectric Development:

315 MW run of river project with hourly pondage on the Victoria Nile in Uganda, 25 km downstream of Kiira/Owen Falls.

The reservoir would involve the loss of 330 ha in Mabira Forest Reserve, of 44 ha of habitats for water birds on Nile Islands and of natural habitats.

There would be no effects on the Nile regime downstream of Kalagala.

The reservoir would entail significant resettlement. The project involves some loss of white water rafting opportunity. The aesthetic value of Kalagala, Busowoko and Buyala Falls

would be lost. A risk of increase of breeding sites for snail vectors of bilharzia.

Karuma Hydroelectric Development:

200 MW run of river project with hourly pondage on the Victoria Nile in Uganda, immediately upstream of the limit of Murchison National Park.

The reservoir impact would be minimal. There would be no natural flow modification downstream from the

outlet. About 7 hectares of terrestrial habitat would be lost. Resettlement of some 35 households. Reduction of the visual amenity of Karuma Falls and of potential

for tourism.

Kabu 16 ♦ 20 MW ♦ minor

resettlement

Kakono ♦ 53 MW ♦ significant

resettlement

Kalagala ♦ 315 MW ♦ loss of habitat ♦ significant

resettlement ♦ loss of aesthetic

value if Bujagali also built

Karuma ♦ 200 MW ♦ minor

resettlement


Masigira Hydroelectric Development:

118 MW in Tanzania on the Ruhuhu River, 80 km to the east of Lake Nyasa.

High erosion risk. Located in a pristine environment rich in wildlife. Change in flow and nutrient transport could affect Nyasa Lake. Resettlement issue is likely to be minor.

Mpanga Hydroelectric Development:

144 MW in Tanzania on the Mpanga River, 40 km downstream of the Lower Kihansi project.

Could affect the hydrology of the Mpanga River. No settlement or farmland would be affected by the reservoir.

Murchison Falls Hydroelectric Development:

222 MW run of river project with hourly pondage located at Murchison Falls on the Victoria Nile in Uganda in Murchison National Park.

The reservoir impact would be minimal. Some loss of crocodile breeding grounds. There would be a loss of mist flora and associated fauna. No population to displace. A reduction of the visual amenity of Murchison Falls and Gorges,

an internationally recognized landscape.

Mutonga Hydroelectric Development:

60 MW run-of-river project with pondage on the Tana River in Kenya, immediately downstream of the Kiambere hydroelectric power plant.

Loss of some terrestrial habitat. Sediment trapping in the reservoir would lead to degradation of

productivity in the reservoir. Possible reduction of riverine forest area. Resettlement of some 1000 people. A risk of increase of malaria and bilharzia.

Ruhudji Hydroelectric Development:

358 MW on the Ruhudji River in Tanzania, approximately 70 km to the east of Njombe. The project would include a separate upstream reservoir.

Modification of terrestrial to lacustrine habitats, especially in the Zanziberi storage reservoir.

Modification of hydrological and nutrient transport conditions. The length of the bypassed river section would be approximately

15 km. The project could affect the hydrology of the Ruhudji River which

flows into Kilambero, a Ramsar site. The resettlement issue is likely to be minor.

Masigira ♦ 118 MW ♦ located in

pristine environment rich in wildlife

♦ minor resettlement

Mpanga ♦ 144 MW ♦ small impact

Murchison Falls ♦ 222 MW ♦ located in

National Park

Mutonga ♦ 60 MW ♦ sediment ♦ significant

resettlement

Ruhudji ♦ 358 MW ♦ 15 km of river

affected


Rumakali Hydroelectric Development:

222 MW on the Rumakali River in Tanzania, 85 km west of Njombe.

The reservoir would involve the modification of terrestrial to lacustrine habitat.

There would be a 17 km river stretch with reduced flow between dam and tailrace.

The project could entail a modification of water flows and levels in the wetlands downstream of the dam before Nyasa Lake.

The reservoir would involve the flooding of agricultural land and of a village with 80 buildings.

The storage reservoir would allow for a reduction of flood risks downstream.

Rusumo Falls Hydroelectric Development:

62 MW on the Kagera River at the border between Rwanda and Tanzania.

Flooding is estimated in the order of 400 km2, which would include 125 km2 of existing lake, 250 km2 of existing wetlands and 15 km2 of valley slopes. The reduction of flood flows and levels could affect wetlands downstream, including in the Akagera National Park.

The creation of the reservoir would have a negligible effect on net evaporation.

Approximately 3000 persons may be affected and some displaced. Increase in water areas upstream could increase health risks due

to bilharzia and malaria.

Ruzizi III Hydroelectric Development:

82 MW on the Ruzizi River which forms the border between Rwanda and the DRC, 25 km downstream (south) of the outlet of Lake Kivu. The river flows into Lake Tanganyika which forms part of the Congo Basin.

Reservoir impact would be minimal. Downstream flows may vary considerably during normal daily

operation.

Songwe Hydroelectric Development:

330 MW project of three dams and hydro plants in cascade on the Songwe River, partly in Tanzania but mostly in Malawi.

Loss of wetlands, the modification of terrestrial habitat to lacustrine habitats and a seasonal regulation of water flows.

Increase in riverbank erosion downstream of the dams. Dams would block fish migration. The projects could involve encroachment in protected areas. Significant population displacement. Increased health risks (malaria and bilharzia). Significant flood control and irrigation benefits.

Rumakali ♦ 222 MW ♦ 17 km of river

affected ♦ wetlands

affected

Rusumo Falls ♦ 62 MW ♦ significant

resettlement ♦ wetlands affected ♦ possible increase

in health risks

Ruzizi III ♦ 82 MW ♦ little impact

Songwe ♦ 330 MW ♦ loss of wetlands ♦ riverbank

erosion ♦ significant

resettlement


Stiegler’s Gorge Hydroelectric Development:

2100 MW (300 MW for the first phase of four) on the Rufiji River in Tanzania, 230 km from the Indian Ocean.

Would entail the transformation of terrestrial to lacustrine habitat in the Selous Game Reserve, renowned for its biodiversity and the quality of its natural habitats.

Degradation of the riverbed in a 100 km river section downstream. The modification of the hydrological regime could have effects on

the configuration of the delta and on salt intrusion. The size of the reservoir could lead to significant evaporation. The reservoir would affect several thousand people. There would be significant downstream effects on traditional

agriculture and animal husbandry. The storage reservoir would allow for less frequent flood damage. Irrigation areas could be developed downstream and reservoir

operation rules.

Upper Kihansi Hydroelectric Development

The Upper Kihansi development consists of the construction of a storage dam to regulate flows to an existing downstream hydro project. The dam would be on the Kihansi River in the Rufiji River basin, 12 km upstream of Lower Kihansi existing power project.

The regulation of river flows would allow for an increase in the average annual generation of the existing plant by about 124 GWh.

The reservoir would possibly encroach on primary forest habitat. The project could regulate the flow of the Kihansi River, which

flows into Kilambero, a Ramsar site. The project would not involve any population displacement. A 3 km road stretch would be flooded.

6.3 Gas-fired and Coal-fired Thermal Options

The main environmental and social issues of fossil-fuelled thermal stations are the following:

Social and environmental impacts of climate change due to greenhouse gas emissions.

Impacts of acid rain due to sulphur dioxide (SO2) and nitrogen oxide (NOx) emissions.

Impacts on public health: (breathing problems, reduced lung function, asthma and reduced resistance to cold and other infections; permanent damage to lungs).

Impacts on land use, habitats and resources due to ash disposal in the case of coal-fired power plants.

6.4 Geothermal Power Options

Geothermal power stations, with appropriate siting and plant design, do not involve significant environmental and social issues.

Stiegler’s Gorge ♦ 2100330 MW ♦ impact on Selous

Game Reserve ♦ degradation of

river bed ♦ significant

resettlement

Upper Kihansi ♦ No firm capacity

Thermal ♦ Various sites

and fuels ♦ (SO2) and

(NOx) emissions

Geothermal ♦ Various sites ♦ No significant

impact


6.5 Wind Power Options

Most impacts of wind power options can be minimized with an appropriate selection of the wind farm site.

6.6 Lake Kivu Methane Development

No significant negative impacts have been identified.

Wind ♦ Various sites ♦ No significant

impact

Lake Kivu Methane ♦ 120 MW ♦ No significant

impact


7 COMPARATIVE ANALYSIS OF OPTIONS

7.1 Introduction

The power development options that passed through the screening process were then analysed taking into account environmental, socio-economic and risk issues. The process selected is able to rank options on the basis of a mix of quantitative and qualitative criteria and consists of five steps:

Step 1: Identification of evaluation criteria and indicators; Step 2: Determination of the relative importance of criteria; Step 3: Ranking of options for each criterion using indicators; Step 4: Ranking of options within each category of criteria taking into account the relative importance of criteria; Step 5: Selection of options to be included in power development portfolios.

Stakeholders participated principally in the first two steps:

• In step 1, they rejected several criteria, added several and modified many of the remainder;

• In step 2 they changed the relative importance of several of the criteria.

Steps 3 are the result of the application of steps 1 and 2; thus no involvement was needed. Step 5 was qualitative and carried out by the consultant.

7.2 Multi-Criteria Analysis

The power development options are compared on the basis of a multi-criterion analysis (MCA). With this method, each option is scored against each criterion on the basis of qualitative and quantitative indicators and not simply ranked from the most preferred to the least preferred. Percentage points are associated with each criterion as an indication of their relative importance (the sum of the weights must add to 100). The final value score of each option is obtained as a weighted average of the scores for the individual criteria. The criteria, split into three groups and their relative importance shown in Table 4 were used:

7.3 Risk Analysis

During the review of power development options, several risks were identified:

• Risk of opposition from internal or external groups • Risks related to institutional and legal framework • Use of local resources

Options retained were compared taking account of: ♦ Lifetime unit

cost of power ♦ Environmental

impacts (six criteria)

♦ Socio-economic impacts (four criteria)

♦ Project risks (nine criteria)

Comparative analysis – broad and transparent process

Two main considerations in selecting criteria: ♦ Must represent

full range of impacts

♦ Must help in discriminating between options


• Gestation period • Increased risks to public health • Risks to designated habitats or natural sites • Risk of sedimentation • Hydrological risk • Financial risks

Although these risks are, in general, non-quantifiable, a process similar to the multi-attribute method was used to assess the overall level of risk of each power development option.

Table 4 – Criteria Used for Comparison of Options and their Relative Importance

Criteria Importance Category: Cost

Unit cost of firm energy 100% Category: Socio-economic Issues

Impacts due to population displacement 15% Promotion of rural electrification 35% Socio-economic impacts on downstream reaches 15% Land issues 35%

Category: Environment Impact on resource depletion 25% Impacts of greenhouse gas emissions 10% Impacts of air pollutant emissions on the biophysical environment

10%

Land requirements 25% Waste disposal 5% Environmental impacts on downstream reaches 25%

7.4 Results of the Multi-Criteria Analysis

Figure 3 overleaf presents graphically the results of the comparative analysis taking account of unit cost of firm power2, environmental and social impacts, and project risks. Each option is rated on a score of 0 (best) to 10 (worst). Each bar on the chart is a weighted average of the scores for each of the criteria used in each category (simple average used for the Risk . Thus the ideal option is one where all four bars are very short.

2 The equivalent annual cost of an option taking account of the capital cost of the

option converted to an annual cost using a discount rate and the useful life of the option plus the operation and maintenance cost of the option all divided by the energy the option is expected to produce during a dry year.

Criteria and weighting selected with stakeholders

Comparison shows no option to be “bad” but also none are ideal

For most criteria, least impact is best BUT for rural electrification, most impact is best

Assessment of risks followed similar process EXCEPT: ♦ criteria were

mostly non-quantifiable and

♦ several indicators used to assess each criterion


Figure 3 – Comparison of Options

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

Aya

go

Buj

ig.

Kabu

Kak

ono

Kal

ag.

Karu

ma

Mas

igira

Map

anga

Mur

ch.

Mut

onga

Ruh

uji

Rum

ak.

Rus

umo

Ruz

izi

Song

we

Stie

g

Kiha

nsi

Win

d

Geo

th.

Mom

b G

as

Mom

b St

eam

Mch

uch. GT

CC

Kiv

u

Scor

e (0

= b

est;

10 =

wor

st).

Cost Performance Social Performance Environ. Performance Risk Performance


7.5 Selection of Options to be Included in Power Development Portfolios

Two groups of options to be considered in power development portfolios can be identified: 1) best evaluated options and 2) other options, as presented in Table 5. In each group, options are listed in order of increasing cost.

Table 5 – Options to be considered in Power Development Portfolios

(listed in order of increasing unit cost)

Best Evaluated Options Other Options

Ruzizi III Karuma Ruhudji Gas Turbine 60 MW gas - generic x 4 units Combined Cycle gas x 3 units Bujagali Rusumo Falls Rumakali Geothermal – Generic Kivu methane engines 30 MW x 4 units Mombasa – LNG Kabu 16 Kakono Generic wind Mutonga

Murchison Falls Mpanga Stiegler’s Gorge Ayago South Songwe Kalagala Masigira Mchuchuma – Coal steam Mombasa - Coal Upper Kihansi

The rationale for the allocation of each option to each group is presented below.

Best evaluated options

Rusumo Falls is strategically placed in the region to: a) strengthen, electrically, the backbone transmission system required for the benefits of regional power planning to be enjoyed by all parties and b) meet the new loads from the mines in the Kagera District that are being implemented. However, Rusumo Falls has a relatively high risk score of 4.1. Environmental impact studies are required to better assess its environmental issues, especially with regards to potential downstream effects and the impacts of the creation of a reservoir that include some 250 km2 of wetlands. In particular, its project design could be re-evaluated so as to minimize reservoir impacts on natural habitats; operation rules could be determined so as not to alter riverine habitats in the Akagera National Park; a mitigation plan should be developed to control risks of increase of malaria and bilharzia. A resettlement and rehabilitation plan is also required. Finally, a power

Rusumo Falls ♦ Strategically

placed ♦ Relatively rapid

installation ♦ Large number of

people affected; some of whom may need resettlement

♦ Possible impact on wetlands


sharing agreement between Burundi, Rwanda and Tanzania will also have to be negotiated, possibly within the framework of the Kagera River Basin Integrated Water Resources Management Project3.

Bujagali, Karuma, Ruhudji and Rumakali do not raise significant dilemmas and can be considered among the best evaluated options.

The following options have a relatively overall good score (better than 3.6) against risks as well as Socio-economic and Environmental criteria. Since their cost is less than the threshold value of 10 ¢/kWh, they can be considered among the best evaluated options, assuming that the dilemmas they raise can be resolved satisfactorily:

Ruzizi III: an agreement between Burundi, Rwanda and the D.R. of Congo for the development of this option could be reached on the basis of the SINELAC experience.

Kabu 16 and Kakono: both options have a higher unit cost but they have a very good performance against Socio-economic and Environmental criteria. Besides, Kakono could incorporate an irrigation component.

Mutonga: this option has the highest unit cost among screened options. It can be considered in the longer term but would require additional studies with regards to sediment trapping and downstream effects and the definition of reservoir operation rules taking into account power generation and controlled release of downstream floods.

Gas fired thermal stations (including Kivu methane engines): despite their lower rank against Environmental criteria, these options are the best ranked options among fossil-fuelled options and they have a good performance against project risks.

Geothermal and wind options: despite a higher unit cost, these options can be considered among the best evaluated options because of their good performance with regards to project risks, Environmental criteria and Socio-economic criteria (except for their limited contribution to rural electrification).

Other options

Other options include:

Stiegler’s Gorge: this option has a low unit cost and potential flood control and irrigation benefits. It could thus be considered as a long term candidate with appropriate mitigation measures with regards to downstream impacts and impacts on the Selous Game Reserve.

3 WSP and International Sweden AB in association with BCEOM and ERM. August

2003. Kagera River Basin Integrated Water Resources Management Project.

Bujagali, Karuma, Ruhudji and Rumakali among the first ranked

Ruzizi III, Kabu 16, Kakono, Mutonga, gas-fired thermal, geothermal and wind relatively good from environmental and social points of view but expensive


Murchison Falls and Ayago South: these options also have a low unit cost and could be considered in the longer term with appropriate mitigation measures because the Ugandan legislation does not explicitly prohibit hydropower development in a National Park.

Songwe: the irrigation and flood control benefits of Songwe could justify the development of this option provided it incorporates a well designed resettlement and rehabilitation plan and an agreement can be reached between Tanzania and Malawi.

Kalagala: considering the cumulative impacts of developing both Bujagali and Kalagala (see Section 10.8), it seems that only Bujagali can be considered among the best evaluated options as this project is advanced to the point of the affected population being already resettled; in addition, Kalagala performs less well than Bujagali in regards to Cost, Socio-economic criteria and project risks.

Coal-fired thermal options: with unit costs of more than 6 ¢/kWh, these options have the highest greenhouse gas and air pollutant emissions among the considered options. Besides, the Mombasa - Coal steam option in Kenya could have significant impacts in relation to increased risks of pulmonary diseases.

Mpanga, Masigira and Upper Kihansi: these hydropower options have been included under other options as existing information does not allow to properly assess their socio-economic and environmental impacts and related project risks.

Stiegler’s Gorge, Murchison Falls, Ayago South, Songwe, Kalagala, coal-fired thermal in second tier

Mpanga, Masigira and Uppr Kihansi could not be ranked because of lack of data


8 POWER DEVELOPMENT PORTFOLIOS – DEFINITIONS AND COMPARISONS

8.1 Load – Resource Balance

The first step in the planning process is to determine if a sufficient amount of new generation options have been identified to meet the forecast load. The comparison of load and available resources shown in the Table 6 below shows that there are sufficient identified new generation resources in the region to meet the projected base (median) load forecast until 2020. No generic projects are included at this stage.

Table 6 - Load Resource Balance

YearPeak

DemandNominal Reserve

Demand + Reserve

Capacity Available

Surplus/ Deficit

MW 20% MW MW MW

2005 1900 380 2280 2327 47

2006 2100 420 2520 2551 312007 2200 440 2640 2642 22008 2300 460 2760 2717 -432009 2500 500 3000 3197 1972010 2600 520 3120 3138 18

2011 2800 560 3360 3138 -2222012 2900 580 3480 3658 1782013 3100 620 3720 4146 4262014 3300 660 3960 5120 11602015 3500 700 4200 6080 1880

2016 3700 740 4440 6851 24112017 3900 780 4680 6851 21712018 4100 820 4920 6851 19312019 4400 880 5280 6851 15712020 4600 920 5520 6851 1331

Load in Base load growth scenario can be met by using all best-evaluated options plus either generic thermal options or other options


8.2 Definition of Development Strategies

Three alternative strategies have been developed, each with its core concept.

A. Core concept strategies:

Strategy 1 – Maximize the use of Best-Evaluated Options

This strategy minimizes the environmental and social impacts on power development in the region. Thus, under this strategy, all of the “best evaluated” options would be used first, followed by any additional options required to meet the load forecast with the selected level of reliability.

Strategy 2 – Technological Diversification

For this strategy, a balance is maintained between hydroelectric power development options and thermal options. This constraint is defined numerically as having a target of between 33% and 50% of the new power development options being hydro options. This implies that some of the best-evaluated options will be replaced by some of the other options.

Strategy 3 – Geographical Diversification

For this strategy, the portfolio needs to provide as much security of supply to each country as could be reasonably possible given the availability of resources even at the expense of having to select options with some environmental, social or risk concerns.

B. Sensitivity analyses

In addition, sensitivity analyses have been carried out to determine the cost impact of the following further options:

Major imports from the Southern African Power Pool (SAPP);

Inclusion of Options for which only basic information is available;

Inclusion of options with environmental and social impacts.

8.3 Definition of Portfolios for each Strategy

The portfolios selected for each strategy are shown on Table 7. The process used in selecting the order and timing of the power development options was to meet the development scenario loads with a reserve margin of about 20% based on the following algorithm

• Select options from the group of best evaluated options up to the limits imposed by the definition of the strategy then use other options or generic (thermal) options;

Three strategies examined: ♦ Maximize use of

best evaluated options

♦ Technological diversification

♦ Geographic diversification

Three sensitivity analyses examined: ♦ Impact of imports ♦ Inclusion of options

for which only preliminary data are available

♦ Reduce importance of environmental, socio-economic and risk issues


Table 7 - Portfolios for each Strategy

YEAR BEST EVALUATED TECHNOLOGICAL DIVERSIFICATION GEOGRPAHIC DIVERSIFICATION2004 All existing EAPMP + SSEA + DRC All existing EAPMP + SSEA + DRC All existing EAPMP + SSEA + DRC

2005 Kiira Units 14-15 Kiira Units 14-15 Kiira Units 14-15GT GT GT

2006 Kiambere extension Kiambere extension Kiambere extensionGT GT GTDiesel 3 x 10 Diesel 3 x 10 Diesel 3 x 10

2007 GT GT GTDiesel 1 x 10 Diesel 1 x 10 Diesel 1 x 10

2008 Sondu Miriu Sondu Miriu Sondu MiriuOlkaria II Olkaria II Olkaria IIGT GT GTDiesel 1 x 10 Diesel 1 x 10 Diesel 1 x 10Kivu engine No. 1 Kivu engine No. 1 Kivu engine No. 1

2009 GT GT GTGT GT GTCombined cycle unit Combined cycle unit GTDiesel 1 x 10 Diesel 1 x 10 Diesel 1 x 10

2010 Geothermal Geothermal Kivu engine No. 2Kivu engine No. 2 Kivu engine No. 2 GTCombined cycle unit Combined cycle unit Geothermal

2011 Kivu engine No. 3 Kivu engine No. 3 Geothermal SuswaGT GT Combined cycle unit

Kivu engine No. 32012 Bujagali 1-4 Bujagali 1-4 Bujagali 1-4

Rusumo Rusumo Rusumo2013 Geothermal Suswa Geothermal Suswa

Kabu 16 Kabu 16 Kabu 16Kakono Kakono Combined cycle unit

2014 Bujagali Unit 5 Bujagali Unit 5 Bujagali Unit 5GT Ruzizi III Ruzizi IIIRuzizi III GT

2015 Ruhudji Ruhudji Kivu engine No. 4Menengai Geothermal

2016 Karuma Menengai Geothermal KarumaMombasa 1Kakono

2017 Rumakali Kivu engine No. 4 MutongaGeothermal 2 x 70 Geothermal 2 x 70Karuma

2018 Menengai Geothermal Wind RuhudjiKivu engine No. 4 Mombasa 1Geothermal 2 x 70

2019 Songwe Mombasa 2 Kalagala 1-72020 Mutonga Rumakali Mombasa 2

Wind Mchuchuma Mombasa 3Ayago south Mombasa 3 Wind

Options common to all three portofolios

Options other than the Best Evaluated

POWER DEVELOPMENT OPTIONS


• Respect the lead times requirements for each option being considered;

• Select options within the above constraints in order of increasing unit cost of firm energy.

Key issues regarding each of these portfolios are:

• Most of the power development options shown in the period up to 2015 are common to all three portfolios;

• The portfolio representing the strategy of maximizing the use of best evaluated options contains options that are not so rated; Ayago South and Songwe, as all the best evaluated options have already been used;

• The portfolio representing the technological diversification strategy (i.e. not too great a reliance on hydro) includes some coal-fired thermal plants which are not attractive from an environmental point of view;

• The portfolio representing the geographical diversification strategy (i.e. no country places too great a reliance on any other) includes less coal-fired thermal BUT includes the Kalagala option, which is not attractive from a socio-economic point of view; it needed to be included to allow the definition of the strategy to be met.

8.4 Transmission Requirements

The generation/load balance in 2020 indicates a regional surplus of Uganda, Kenya and Tanzania of close to 890 MW while the regional deficit of Burundi, Rwanda, DRC-East and Western Tanzania is 27 MW. The interconnection capacity should be sufficient to cover the peak load deficit plus the loss of the largest generating plant within the importing region. The largest plant size is 82 MW, corresponding to the Ruzizi III unit shared by Rwanda and Eastern-DRC. The resulting interconnection capacity requirement is 109 MW (27 + 82 MW).

The selected alternative, as shown in Figure 4 would consist of:

A 132 kV single-circuit line from Mbarara, Uganda to Kigali, Rwanda (150 km);

A 132 kV single-circuit line from Bulyanhulo to Biharamulo (both in West Tanzania), connecting to the Biharamulo-Rusumo Falls (West Tanzania/Rwanda) 132 kV line (150 km);

Because of geographic spread of options and loads, only two new transmission lines required: ♦ A 132 kV single-

circuit line from Mbarara to Kigali (150 km.)

♦ A 132 kV single-circuit line from Bulyanhulo to Biharamulo, connecting to the Biharamulo-Rusumo Falls 132 kV line (150 km.).

This applies for all three strategies.


Figure 4 - Transmission Requirements


The existing international tie-lines RDC-Rwanda, Rwanda-

Burundi, Uganda-Tanzania and Tanzania-Kenya are sufficient to meet the net power flows estimated for the year 2020.

The estimated cost of this interconnection scheme is US$ 34 million.

The transmission requirements of the portfolios representing the other two strategies would be the same.

8.5 Cumulative Impacts

The cumulative impacts discussed below apply to the portfolio representing Strategy 1 – Maximization of the use of the best-evaluated options. The cumulative impacts for the other strategies would depend upon the portfolio selected. In general, the cumulative impacts related to thermal plants would be more intensive and those related to hydro would be less so.

As mentioned in 6.1 the cumulative impacts can be either positive or negative.

Geothermal Power, Wind Power and Transmission Lines.

Geothermal power plants – minimal.

Wind farms - conflicts in land tenure and land use, possible negative visual aspect, noise and the possible collision of birds with the rotors.

Transmission – conflicts over land tenure and land use.

Fossil Fuel Thermal Power Options

CO2 Equivalent Emissions: 0.02 tCO2 equivalent per person for the six countries of the Nile Basin, compared to 0.7 tCO2 equivalent for sub-Saharan Africa or 3.8 for the world as a whole.

SO2 Equivalent Emissions: 6,100 tSO2 equivalent for year 2020.

Hydroelectric Developments

Changes in Flow Regime:

• No effects on the Albert Nile leading to Sudan and the Sudd Marshes;

• Little incidence on the level variations of Lake Victoria;

• Little incidence on the level variation of Lake Tanganyika;

• The hydrologic conditions on the Tana River are already disturbed and it is not clear whether the addition of a sixth power station would have any additive consequences on the flow of the river and on its downstream habitats.

Cumulative Impacts of geothermal, wind and transmission: ♦ minimal

Cumulative Impacts of thermal options: ♦ CO2 and SO2

Emissions significant in a local context but very small from a regional context


Aesthetics:

• The combined presence of Bujagali and Kalagala would have a cumulative impact on issues such as aesthetics, cultural and existing and potential tourism.

Habitats and Natural Sites:

• Cumulative impact on the wetlands along the Kagera River;

• An important wetland and a related bird area on the Ruhudji River leading to Rufiji River Basin and the Watershed of Rumakali River Flowing to Lake Nyasa could be affected.

Sediment:

• No important charge of sediments on Victoria Nile;

• The combined reduction of organic and inorganic nutrient into Lake Victoria will decrease productivity of the Lake; the extent of such a reduction and its significance cannot be assessed at this time;

• The reduction of organic and inorganic nutrients as a result of the construction of power plants could be noticeable at the mouth of the Ruzizi River into Lake Tanganyika;

• The Watershed of Rumakali River Flowing to Lake Nyasa is heavily populated and agricultural practices can have a significant contribution to soil erosion that could lead to increasing sediment loads in the river and finally in Lake Nyasa.

• Important sedimentation problems due, in part, to agricultural practices on the watershed of Tana River could lead to a cumulative impact.

Water Hyacinths:

• Water hyacinths are trapped upstream from Owen Falls Dam and will not create a cumulative impact downstream;

• A significant reduction of water hyacinth flowing into Lake Victoria as they would be trapped by the Rusumo falls dam.

Health:

• Risk of malaria and bilharzias in options with reservoirs.

8.6 Comparison of Strategies under Base Load Growth Scenario

Table 8 present a comparison of the portfolios for the strategies examined in this report in terms of investment, present value of lifetime costs, diversification and geographic diversification as well as the use of power development options other than those that are best evaluated.

The present value of the stream of costs is calculated by this software for the entire period considered.

Cumulative Impacts of hydro options: ♦ No change in flow

regime in Sudan ♦ Aesthetics if

Kalagala to be built with Bujagali

♦ Wetlands and other habitats at several sites

♦ Resettlement at several sites

♦ Sedimentation in reservoirs


This analysis indicates that:

• The portfolio representing technological diversification would cost4 US$ 180 million (or 4.5%) more than the portfolio, which ignores any diversification and concentrates on using only the best-evaluated options, regardless of where they are located.

• The portfolio representing geographic diversification would cost about the same as the technological diversification strategy.

• These results hold over a wide range of discount rates.

• The total investment over the period 2005 to 2020 in all three portfolios would be very similar: US$ 5.83 billion for Strategy 1, US$ 5.75 billion for Strategy 2 and US$ 5.67 billion for Strategy 3.

• The portfolio illustrating technological diversification would have less cumulative impact (changes in flow regime, sedimentation, erosion, proliferation of invasive aquatic vegetation and habitats) on the watersheds of the region than the portfolio, which ignores any diversification. On the other hand, emissions would be substantially greater due to the replacement of three hydro options with coal-fired thermal plants – annual emissions of SO2 would increase from 5,000 tonnes to 14,000 tonnes and greenhouse gas emissions would increase from 2.6 million tonnes to 7.4 million.

• The portfolio illustrating geographical diversification would have slightly more impact on the watersheds of the region than the portfolio that illustrates technological diversification because a coal-fired thermal unit in Tanzania is deleted from the portfolio and replaced by Kalagala hydro option in Uganda in order to provide a better geographical balance. For this reason, emissions would be slightly lower – annual emissions of SO2 would decrease from 14,000 tonnes to 11,000 tonnes and greenhouse gas emissions would decrease from 7.4 million tonnes to 6.0 million.

• Kalagala is included in the geographical diversification portfolio as it is the “least bad” option available that would provide the balance required to satisfy the definition of the strategy.

4 in terms of the present value at a discount rate of 10% of new capital costs plus total

system operating and fuel costs over the period of analysis (2005 to 2054)

Comparison of portfolios on lifetime costs ♦ Very little

difference

Comparison of portfolios on investments ♦ Very little

difference

Comparison of options in portfolios ♦ Reduction in

reliance on hydro adds to air emissions

♦ Getting balance between countries requires the construction of Kalagala; not considered appropriate


Table 8 -Comparison of Portfolios Using Base Load Growth Scenario

Strategy 1 “Best Evaluated”

Strategy 2 Technological Diversification

Strategy 3 Geographical Diversification

Present Value of annual costs at 10% discount rate – US$ 1,000 million

4.03 4.21 4.19

Total Investment– US$ 1,000 million 5.83 5.75 5.67 Technological Diversification - % of new plant using each technology

♦ Hydro 62% 42% 48% ♦ Geothermal 14% 14% 14% ♦ Gas 13% 13% 13% ♦ Coal - 20% 14% ♦ Other 11% 11% 11% ♦ Total 100% 100% 100%

Selection of Options - % of new plant ♦ Best Evaluated 83% 80% 77% ♦ Other 17% 20% 23% Geographical Diversification - % of new plant located in each country

♦ Burundi (load = 3%) 1% 1% 1% ♦ Eastern DRC (load = 2%) 4% 4% 4% ♦ Kenya (load = 43%) 24% 35% 37% ♦ Rwanda (load = 3%) 5% 5% 5% ♦ Tanzania (load = 29%) 43% 39% 27% ♦ Uganda (load = 20%) 23% 16% 26% ♦ Total 100% 100% 100%

8.7 Sensitivity Analyses

Table 9 presents a comparison of the sensitivity of the Technological Diversification portfolios to variations in key parameters in terms of investment, present value of lifetime costs, diversification and geographic diversification as well as the use of power development options other than those that are best evaluated. This analysis indicates that:

If the screening criteria were to be relaxed so that the level of information available was no longer a consideration, the overall cost of power development in the region could be reduced by about US$ 100 million (2.4%) relative to the portfolio representing technological diversification. This analysis includes the following power development options that have not yet been studied beyond the reconnaissance level:

o Kiymbi, 43 MW o Budana, 13 MW o Piana Mwanga, 38 MW o Bangamisa, 48 MW and o Babeda 1, 50 MW

Several options in DRC should be studied further


If the comparative analysis is not carried out and a portfolio is defined using cost and on-power dates as the only criteria, there could be a reduction in overall present value of costs of up to US$ 140 million or about 3.3%.

If power is available from outside the region for less than 3 US¢/kWh, it would be beneficial to the power development of the region (i.e. imports at 3 US¢/kWh would reduce the overall system costs by about US$ 210 million or about 5.0%).

Table 9 - Comparison of Sensitivity Tests Using Base Load Growth Scenario

Sensitivity Test to: Strategy

2 Insufficient data

Imports @ $0.03/kWh

Environmental and Social

Issues Present Value of annual costs at 10% discount rate – US$ 1,000 million

4.21 4.11 4.00 4.07

Total Investment– US$ 1,000 million 5.75 5.63 5.26 5.68 Technological Diversification - % of new plant using each technology

♦ Hydro 42% 47% 41% 47% ♦ Geothermal 14% 10% 14% 14% ♦ Gas 13% 13% 10% 13% ♦ Coal 20% 21% 21% 17% ♦ Imports at US$ 0.03/kWh - - 9% - ♦ Other 11% 9% 5% 9% ♦ Total 100% 100% 100% 100% Selection of Options - % of new plant

♦ Best Evaluated 80% 73% 79% 57% ♦ Other 20% 27% 21% 43% Geographical Diversification - % of new plant located in each country ♦ Burundi (load = 3%) 1% 1% 1% 1% ♦ Eastern DRC (load = 2%) 4% 10% 4% 4% ♦ Kenya (load = 43%) 35% 25% 25% 24% ♦ Rwanda (load = 3%) 5% 4% 5% 5% ♦ Tanzania (load = 29%) 39% 44% 40% 40% ♦ Uganda (load = 20%) 16% 16% 16% 26% ♦ Imports at US$ 0.03/kWh - - 9% - ♦ Total 100% 100% 100% 100%

Imports are attractive if less than 3 US¢/kWh


8.8 Comparison of Strategies Across Load Growth Scenarios

Table 10 present a comparison of the two strategies (technological diversification and geographical diversification) across load growth scenarios in terms of power development installations as well as investment, life-cycle cost, technologies used, geographical location and use of best evaluated options. The main feature of this comparison is that the base load growth scenario uses up most of the best evaluated options. As the load grows, a greater share of the installations becomes less attractive from an environmental and social point of view.

Table 10 - Comparison of Strategies to Various Load Growth

Scenarios Strategy 2 Strategy 3

Base Scenario

High Scenario

Base Scenario

High Scenario

Trans-formation Scenario

Present Value of annual costs at 10% discount rate – US$ 1,000 million

4.21 6.02 4.19 5.86 9.45

Total Investment– US$ 1,000 million 5.75 8.25 5.67 8.26 16.18 Technological Diversification - % of new plant using each technology

♦ Hydro 42% 44% 48% 50% 32% ♦ Geothermal 14% 9% 14% 9% 5% ♦ Gas 13% 9% 13% 9% 4% ♦ Coal 20% 24% 14% 16% 55% ♦ Other 11% 14% 11% 16% 4% ♦ Total 100% 100% 100% 100% 100% Selection of Options - % of new plant

♦ Best Evaluated 80% 63% 77% 65% 30% ♦ Other 20% 37% 23% 35% 70% Geographical Diversification - % of new plant located in each country

♦ Burundi (load = 3%) 1% 1% 1% 1% 1% ♦ Eastern DRC (load = 2%) 4% 3% 4% 3% 1%

♦ Kenya (load = 43%) 35% 38% 37% 40% 59% ♦ Rwanda (load = 3%) 5% 3% 5% 3% 2% ♦ Tanzania (load = 29%) 39% 39% 27% 31% 23% ♦ Uganda (load = 20%) 16% 16% 26% 22% 14% ♦ Total 100% 100% 100% 100% 100%


9 CONCLUSIONS AND RECOMMENDATIONS

9.1 Conclusions

The analysis in the previous chapter leads to the following conclusions:

Prior to 2009:

• Because of the lead times required to select and implement power development options, need to begin studies immediately on selected options for the period 2009-2015.

Availability of Resources:

• By the end of the period of analysis (2020), all of the best evaluated options plus another 560 to 760 MW (depending upon the portfolio selected) of other options are required to meet the base load growth scenario.

• For the high forecast, an additional 1100 MW of other options would be required.

• The transformation scenario would need to draw heavily upon resources from outside the region (over 5000 MW of power or fuel imports).

Environmental Issues:

• Even the most hydro-intensive portfolio (the one representing the strategy that maximizes the use of the best-evaluated options) would not have any significant effect on the Albert Nile leading to Sudan and the Sudd Marshes, whether in terms of flow regime, volume lost due to evaporation or sediment load.

• The cumulative impacts on the environment from multiple hydro projects in a river basin or several thermal plants are relatively minor; the most significant would be emissions from thermal plants and potential impacts on wetlands in the Kagera River and the Rufiji River.

Investments Required:

• The total capital investment required over the period 2005 to 2020 to meet the base case load growth scenario are very similar for each of the three development strategies:

o Portfolio maximizing the use of best evaluated options regardless of technology used or geographic location – US$ 5.83 billion;

Impact on Nile River downstream of Lake Albert is negligible

Investment in all three strategies is similar

Expansion plan uses all of “Best Evaluated” options


o Portfolio emphasizing technological diversification – US$ 5.75 billion;

o Portfolio emphasizing geographic diversification – US$ 5.67 billion.

These include US$ 0.7 billion up to 2009 inclusive.

• The high load growth scenario would require over 50% more investment – US$ 8.25 billion.

• The transformation scenario would require over three times more investment – US$ 16 billion.

9.2 Recommendations

The following are specific recommendations (based on the base case load growth scenario):

Power Development Options:

• Because of lead times required, each of the following options would have to be designed and built as soon as possible

o Rusumo Falls (62 MW) between Rwanda and Western Tanzania,

o Bujagali 1-4 (200 MW) in Uganda, o Bujagali Unit 5 (50 MW), o Kabu 16 (20 MW) in Burundi, o Kakono (53 MW) in Tanzania, o Geothermal plants in Kenya (2 by 70 MW plants), o The second and third phases of the Lake Kivu gas

engines (30 MW) in Rwanda/DRC, o Ruhudji (358 MW) in Tanzania, and o Ruzizi III (82 MW) between Rwanda and DRC.

All of these options are required during the period 2009 to 2015. The order of installation of these options would depend upon the speed with which the additional studies required for each can be completed.

• During the same period 2009 and 2015 additional gas turbines, diesels and some combined cycle plants will be needed to fill an expected shortfall.

• Carry out studies on several of the power development options in the DRC that have only been identified and studied to the reconnaissance level. These include:

o Kiymbi, 43 MW (rehabilitation) o Budana, 13 MW (rehabilitation) o Piana Mwanga, 38 MW (rehabilitation)

Urgent need to commit to 1025 MW for installation prior to 2015

Need to improve level of information on several options


o Bangamisa, 48 MW o Babeda 1, 50 MW o Sisi 3/5, 174-205 MW

• Carry out further studies of the Malagarasi Cascade (including Igamba Fall) in Western Tanzania from the point of view of development for the region (current information is for options that use only a small fraction of the potential of the cascade).

• Replace local plants with imports from outside the region IF such imports cost less than US 3¢/kWh (levelized unit cost over the life of the purchases).

Transmission Requirements5:

• The transmission backbone components recommended in the SSEA Stage I report are reiterated:

o A 110 kV line from Kigoma, Rwanda to Rwegura, Burundi,

o A 132 kV line from Kabarondo, Rwanda passing near Ngara to Biharamuro in Kagera province of Tanzania,

o A 132 kV line from Ngara, Tanzania to Gitega, Burundi, o A 110 kV line from Gitega, Burundi to to Kigoma,

Tanzania.

• The transmission recommended in the EAPMP for the integrated case is reiterated:

o A new 220 kV line from Arusha, Tanzania to Nairobi, Kenya,

o A upgrade of the existing 132 kV line from Lessos, Kenya to Jinja, Uganda to 220 kV.

• Add two new lines to connect the SSEA Stage I area to the EAC area:

o A 132 kV line from Mbarara, Uganda to Kigali, Rwanda, and

o A 132 kV line from Bulyanhulo to Biharamulo, Tanzania to Rusumo Falls Rwanda/Tanzania.

Urgent Actions:

Table 11 and Table 12 together present an indicative expansion plan based on technological diversification, and the base case or reference load forecast. Figure 5 presents a map of the region that includes new power development options recommended for installation between now and 2015; installations after that depend upon policy decisions be each country on the level of dependence on any one

5 These recommendations take account of regional needs only; strengthening

of internal networks may also be required but these are not considered in this assessment

For regional benefits to be obtained, there is an urgent need to build: ♦ EAC backbone ♦ SSEA I

backbone ♦ Two additional

lines connecting these two areas


resource such as hydro as well as dependence on sources outside the country.

9.3 Benefits of Key Power Development Options

Table 11 indicates that urgent action is required on the following hydroelectric options:

Rusumo Falls, Bujagali, and Ruzizi III.

The relative attractiveness of these options from the points of view of firm energy cost, environmental and socio-economic impacts and project risks are all given in the relevant chapters of this report. One issue that is not covered is the impact that each of these options has on the overall system cost. An approximate estimate of such system costs is provided below. The Technological Diversification portfolio includes all three of these options with their in service dates as soon as technically feasible. In this section, the impact of removing these options, one at a time is assessed.

If Rusumo Falls were to be considered not available (for whatever hypothetical reason), it would need to be replaced by another option at an extra cost of about US$ 69 million6.

If Bujagali were to be considered not available (for whatever hypothetical reason), it would need to be replaced by another option at an extra cost of about US$ 173 million as well as provide significant additional atmospheric emissions.

If Ruzizi III were to be considered not available (for whatever hypothetical reason), it could be replaced either by Mombasa coal or a combination of Mutonga and a low-speed diesel. At an extra cost of about US$ 40 million as well as significant additional atmospheric emissions or by about US$ 80 million with only a slight increase in atmospheric emissions.

In general, the process followed was to install options on the basis of least cost options from among the best-evaluated group. Thus if any of the options are replaced, the implication will be that the new portfolio would either be more costly or have higher socio-economic or environmental impacts.

9.4 Institutional Issues

There does not seem to be any legal or regulatory impediment to regional cooperation. Indeed, there is currently cross-border trade in electric power.

6 Present value at a discount rate of 10% of investment, fuel, fixed and variable

operating costs

Economic analyses suggest the development of Rusumo falls, Bujagali and Ruzizi III are economically attractive. Process followed suggests others would also be.

Significant cross-border trade may require strengthening of transmission systems


Significant cross-border trade may require strengthening of transmission systems as well as close cooperation between the load dispatch centres of each affected country. In this context, for the efficient functioning of a regional electricity market (at some point in the future) the member countries need to articulate a minimum platform for cross-border power trade that embraces the following:

• Each member country should decide on the degree of security of power that is appropriate to it, given the availability and cost of resources and the level of reliance it is willing to place on the power systems of neighboring countries.

• Imports/exports need not be regulated per se or, if they are, as little as possible, ensuring only that (a) such trading is not more costly than native generation when such supply is available; and (b) operational security of the network and quality of supply are not compromised.

If the country opts for a multi-buyer system to facilitate and foster regional trade, then it is important to have:

Open access to transmission network is transparent and non-discriminatory (existing generators and IPPs) rules for pricing and volume of trade;

Functional unbundling7, at least in the initial stages, be limited to transmission and generation coupled with the creation of an independent transmission system operator at the national level that would provide transmission services and open access same-time information;

Transparent pricing arrangements for transmission services (also called wheeling charges or transit fees) and ancillary services.

7 Restructuring an integrated utility so that the functions of generation, transmission

and distribution become cost or profit centres

Very little change in laws and regulations if trading to be done between existing utilities

If multi-buyer system adopted, significant changes in laws and regulations needed. This would foster spread of independent power producers.


Table 11 - Short to Mid Term On-Power Dates and Required Actions to Achieve These

ActionYear Addition (on Power) Country Regional Actions to be taken by

(MW)2005 Kiira Units 14-15 Uganda 80 Study and commit backbone transmission - SSEA 1 B/R/T

Gas Turbine Tanzania 40 Commitment to design update for Rusumo Falls B/R/TStart design and procurement for Kivu gas engines R/DRCApprove and procure SSEA 1 region 3 x 10 MW diesels B/R/TInstall 40 MW GT Tanzania

2006 Kiambere extension Kenya 20 Install 3 x 10 MW diesels - SSEA 1 B/R/TGas Turbine Tanzania 40 Procure 1 x 10 MW diesel BurundiDiesel (3x10) B/R/WT 30 Bujagali - final studies/approval/design Uganda

Ruzizi III studies and approval R/DRCDesign for SSEA 1/DRC transmission system B/R/TDesign for EAC transmssion additions K/T/UStart design update and EIA for Rusumo B/R/TLongonot geothermal final studies/EIA and approval KenyaProcure 60 MW GT Tanzania

2007 Gas Turbine Kenya 60 Install 1 x 10 MW diesel BurundiDiesel (1x10) Burundi 10 Procure 1 x 10 MW diesel Rwanda

Longonot geothermal - start design KenyaProcure 2 x 60 MW GT TanzaniaProcure 60 MW steam cycle CC unit TanzaniaRusumo - complete studies and approval B/R/TKakona final study and approval TanzaniaKabu 16 final study and approval Burundi

2008 Sondu Miriu Kenya 60 Complete installation of 1 x 10 MW diesel RwandaOlkaria II Kenya 35 Complete installation of No 1 Kivu gas engine group R/DRCGas Turbine Tanzania 60 Start procurement of Kivu gas engine No. 2 group R/DRCLake Kivu Gas (30 MW) No. 1 R/DRC 30 Complete transmission construction K/T/UDiesel (1x10) Rwanda 10 Bujagali 1-4 start construction Uganda

Rusumo final approval and construction contract B/R/TKabu 16 - design start BurundiKakono - design start TanzaniaRuzizi III design R/DRCProcure 60 MW steam cycle CC unit TanzaniaSuswa geothermal investigations and approval KenyaLongonot geothermal construction Kenya

2009 Gas Turbine Tanzania 60 Complete installation of 1 x 10 MW diesel TanzaniaDiesel (10 MW) Tanzania 10 Rusumo start construction B/R/TCombined cycle steam unit Tanzania 60 Kabu 16 - tender Burundi

Kakono tender TanzaniaKaruma approval and start design UgandaProcure 60 MW GT KenyaStart procurement of Kivu gas engine No. 3 group R/DRCLongonot approval and financing Kenya

2010 Lake Kivu Gas (30 MW) No. 2 R/DRC 30 Kabu 16 - start construction BurundiCombined cycle steam unit Tanzania 60 Kakono start construction TanzaniaGeothermal - Longonot Kenya 70 Rumakali approval and start design Tanzania

Longonot on power Kenya

Capacity Additions


Table 12 - Mid-Long Term On Power Dates - Indicative Plan

Year Addition (on Power) Country(MW)

2011 GT Tanzania 60Lake Kivu Gas (30 MW) No.3 R/DRC 30

2012 Bujagali 1-4 Uganda 200Rusumo Falls (Full) R/B/WT 61.5

2013 GT Tanzania 60Suswa geothermal Kenya 70Kabu 16 Burundi 20

2014 Bujagali 5 Uganda 50GT (oil) Kenya 60Ruzizi III R/DRC 82

2015 Ruhudji Tanzania 358

2016 Menengai geothermal Kenya 140

2017 Karuma Uganda 200Lake Kivu Gas (30 MW) No.4 R/DRC 30Non-specified geothermal Kenya 140

2018 Wind (2 plants) Kenya 60Mombasa 1 Kenya 150

2019 Mombasa 2 Kenya 150

2020 Rumakali Tanzania 222Mchuchuma coal steam (1-2) Tanzania 200Mombasa 3 Kenya 150

B/R/T Burundi + Rwanda + Tanzania / SSEA 1 regionR/DRC Rwanda + Democratic Republic of the CongoRuzizi III could be developed by Rwanda, DRC and Burundi

Capacity Addition


Figure 5 – Map Showing Regional Development of Power and Transmission Requirements to 2015

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