NILE BASIN INITIATIVE - documents.worldbank.org · 4 SSEA –Final Report: Synopsis 2 POWER NEEDS...

NILE BASIN INITIATIVENILE EQUATORIAL LAKES

SUBSIDIARY ACTION PROGRAM

THE WORLD BANK

In collaboration with

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

in the Nile Equatorial Lakes Region

Synopsis Report

Stage I - Burundi, Rwanda

and Western Tanzania

February 2005

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SSEA –Final Report: Synopsis i

Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in the Nile Equatorial Lakes Region Stage I Burundi, Rwanda and Western Tanzania

1 INTRODUCTION ..........................................................................................1

2 POWER NEEDS OF THE BURUNDI, RWANDA, AND WESTERN TANZANIA SUB-REGION IN THE NEXT 15 YEARS..................................4 2.1 Current Power Needs 4 2.2 Power Needs in 2020 5

3 POWER OPTIONS .......................................................................................6 3.1 Options Examined 6 3.2 Short-term Options 7 3.3 Medium and Long Term Options (beyond about 2010) 7

4 COMPARISON OF OPTIONS......................................................................9 4.1 Approach and Criteria 9 4.2 Comparison 10

5 BACKBONE TRANSMISSION NETWORK...............................................13

6 PROPOSED POWER DEVELOPMENT STRATEGY TO MEET DEMAND IN THE SUB-REGION FOR NEXT 20 YEARS ..........................................15 6.1 Strategies Examined 15 6.2 Strategy Selected by the Project Steering Committee 15

7 AN INDICATIVE POWER DEVELOPMENT PORTFOLIO FOR THE SUB-REGION......................................................................................................16 7.1 Medium and Long term Development 16 7.2 Cumulative Impacts 17 7.3 Mitigation Measures 18

8 NEXT STEPS IN IMPLEMENTING THE POWER DEVELOPMENT STRATEGY ................................................................................................19 8.1 Regional Actions Required 19 8.2 Financing Needs to Support the Proposed Strategy 20 8.3 Longer Term Actions 20 8.3.1 Adjustments Needed to the Legal and Regulatory Framework............... 20 8.3.2 National Energy Policies to Support Regional Power Trade................... 21

SSEA –Final Report: Synopsis 1

1 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, Rwanda, Uganda, Tanzania, Kenya, Sudan, Eritrea, the Democratic Republic of Congo (DRC), Ethiopia and Egypt). Under the NBI framework, two subsidiary action programs have been established: The Nile Equatorial Lakes Subsidiary Action Program (NELSAP) and the Eastern Nile Subsidiary Action Program (ENSAP). ENSAP includes Egypt, Ethiopia, and Sudan and focuses on integrated water resources management, flood management, power generation and interconnection, irrigation and drainage and watershed management. NELSAP includes Burundi, D.R. Congo, Egypt, Kenya, Rwanda, Sudan, Tanzania, and Uganda and targets investments in power development, transmission interconnection and trade, water resources management, management of lakes and fisheries, agricultural development, and water hyacinth control.

Following a dialogue between the Nile Equatorial Lakes (NEL) countries and the World Bank, the need for a comprehensive strategic regional assessment of different power options was formulated for the Nile Equatorial Lakes region, building on the ranking study of hydropower projects identified by the Nile Equatorial Lakes Subsidiary Action Program (NELSAP)1. The approach to undertake a broad based power options analysis including issues covering Strategic/Sectoral, Social and Environmental Assessment (SSEA) was agreed at the Nile Equatorial Lakes Power Experts Retreat that took place in May, 2002 in Kisumu, Kenya2. According to IDA policies the World Bank also needs to undertake an assessment of the cumulative effects of the existing and potential hydropower developments in the NEL region as a part of its support to the strategic planning for NELSAP3 4.

The SSEA was split into two components; this first stage covering Burundi, Rwanda and Western Tanzania and a second stage to follow that add the remainder of Tanzania, Kenya, Uganda and the eastern provinces of the Democratic Republic of Congo. The assessment of Stage I is presented in three volumes; a main report, a report on stakeholder consultation and this Synopsis Report. The main report covers the following issues:

• Current situation in the sub-region; • A review of energy policies and legal and administrative frameworks as

they apply to the promotion of power development options; • An assessment of the power needs; • The identification and initial screening of power development options; • A comparative analysis and ranking of power development options that

were retained after the first screening; • An overview of cumulative impacts on the sub-region of the

development of such options;

1 Nile Equatorial Lakes Subsidiary Action Program ICCON 1proposal for preparation phase, P 5 sub-region

power development and trade sub-programme 1: hydropower development, 2001. 2 Nile Equatorial Lakes Subsidiary Action Program (NELSAP): Proceedings from NEL Power Experts Retreat

Next Steps in Preparing the NEL Power Development and Trade Program, May 29 – 30, 2002, Kisumu, Kenya.

3 The World Bank Group, The Inspection Panel: Investigation Report: UGANDA Bujagali Project (June 17, 2002)

4 The SSEA of Power Development Options is financed by the Canadian International Development Agency.

Work included: - Review of existing

situation - Review legal and

administrative frameworks

- Assessment of needs - Identification and

comparison of options- Definition of portfolios

of options, - Identification of

cumulative impacts and mitigation measures

The need for a comprehensive strategic regional assessment of different power options was identified for the NEL region

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

2 SSEA –Final Report: Synopsis

• Mitigation measures that can be applied to reduce the social and environmental impacts of these options;

• The development of portfolios of power options; and • The identification and involvement of stakeholders.

The Stakeholders report covers, in some detail the interactions with stakeholders in carrying out the work described in the main report. This synopsis report focuses on and summarizes the main report.

The work has been carried out by a consulting team led by SNC-Lavalin International Inc. Canada and in collaboration with Hydro-Quebec International, Canada. The Consultant reports to a Steering Committee5. The Steering Committee was instrumental in guiding the Consultant in such areas as:

• The identification of power development options and the provision of guidance in the screening process;

• The proposal of comparison criteria;

• Ensuring that the assessment reflected the regional and political realities; and

• Contribution, along with the stakeholders, in the areas enumerated below.

Two independent reviewers provided advice, expertise and strategic guidance throughout the process. The reviewers reported to the Steering Committee.

A consultation plan was developed to promote the public participation in the region. The key contributions by the stakeholder included:

• Reviewing and adjusting the power needs assessment for the sub-region;

• Reviewing and adjusting the identification of power options and the criteria selected for the preliminary screening of power options;

• Reviewing and adjusting the categories of evaluation criteria, the selection of criteria within each category and the corresponding indicators used for the comparison and ranking of selected power options;

• Assigning importance levels to each of the criteria for the purpose of comparing and ranking the selected power options;

• Reviewing and adjusting the methodology used for assessing potential impacts related to power options; and

• Reviewing the criteria that could be applied to the identification of alternative mid-term and long-term power development strategies for the sub-region and proposing a set of alternative strategies to allow for the development of investment portfolios to reflect each strategy.

5 The Steering Committee is composed of representatives from the World Bank, power experts and the Technical Advisory Committee of NEL members from Rwanda, Burundi and Tanzania, the coordinating unit of NELSAP, and a representative from the Canadian International Development Agency (CIDA)

A Canadian consulting team provided support

Public consultation was an integral part of the work

The Steering Committee was instrumental in guiding the Consultant


370 MW additional capacity needed to meet load in region to 2020

Build following plants as quickly as possible to eliminate the current power deficit in the region:

− Rehabilitate Ruzizi I − Add 40 MW of diesel units burning imported fuel − First module of Lake Kivu methane-fuelled plant

Commit to the construction of Kabu 16 and Rusumo Falls Hydropower Projects

Build backbone transmission system to permit power transfers within region

Revise the existing legal and regulatory frameworks in each country to facilitate regional electricity trades

Carry out a strategy of using indigenous resources while diversifying technologies and plant locations

− Use methane produced in Lake Kivu to generate power from diesel-like engines

− Use hydro resources Rusumo Falls and Kabu 16, Kakono, and Ruzizi III Mule 34 and Nyabarongo Each group in the order shown; within each group,

the order of their development to be determined through more detailed studies

− Consider imports when available Ensure legal and administrative framework is in

place on all three countries to facilitate such transfers

Final Recommendations from Assessment


2 POWER NEEDS OF THE BURUNDI, RWANDA, AND WESTERN TANZANIA SUB-REGION IN THE NEXT 15 YEARS

2.1 Current Power Needs

Much of the electricity produced in Rwanda and Burundi is generated through hydroelectricity. Hence, the highly variable climate in central and eastern Africa exposes the power systems of the two countries to great fluctuation in hydropower generation. This has resulted in power rationing of various degrees being introduced in recent years. Even in wet years, there is insufficient reliable energy for supplying new customers and rural electrification. Industrialization processes and, hence, their economic development are severely constrained by the lack of power.

The Kigoma and Kagera Districts of Tanzania are isolated from the main grid. In the Kigoma District some electricity is provided to the District capital (the town of Kigoma) but most of the rest of the district is without formal power supply. There is thus a large unsupplied demand in the other population centres of the District.

The Kagera District of Tanzania is supplied by Uganda, which is also facing shortages at the time of their system peak. This, in turn, also leads to load shedding6 in the supply of power.

It should be noted that, apart from the few small diesel plants now under construction, there have been no power plants built since about 1989.

The location of the existing generation facilities in the region is presented in Figure 1. An estimate of the level of suppressed (or unmet) demand in the region suggests that there is an immediate need for at least 25 MW to meet the current demand for power, as shown below:

2002 figures

Capacity Available (MW)

Estimated Demand (MW)

Estimated Deficit (MW)

Rwanda 46 58 – 61 12 – 15 Burundi 28 36 - 38 8 – 10 Western Tanzania 7 9 2 Total 81 103 – 108 22 – 27

This does not include any allowance for reserve capacity in case of plant maintenance and unforeseen plant outages.

6 Load shedding is the deliberate cutting of power to a group of customers by the electric utility to the reduce load being supplied. This is usually for a relatively short period and is done to prevent the electrical collapse of the whole system.

The current deficit in the region is about 25 MW.

The current needs in the region are about 105 MW.


2.2 Power Needs in 2020

The table below illustrates the additional capacity that must be installed in the region in order or imported to satisfy the needs of the region under three scenarios:

A low forecast with moderate rural electrification and no mining loads;7 A base case with significant rural electrification (five times the current

level) and currently identified potential mining loads in Western Tanzania being connected to the system; and

A high forecast where the level of electrification in the region is increased by a factor of eight times and the amount of mining loads is doubled over the next fifteen years.

Incremental Capacity Requirements (MW) 2002-2020 Low Base High 2002 – 2005 38 48 58 2005 – 2010 29 113 135 2010 – 2020 74 208 449 2002 - 2020 141 368 643 Rounded (2002 – 2020) 140 370 640

It should be noted that there is a significant amount of diesel generation installed currently which uses expensive imported fuel. However, as additional hydroelectric plants are installed, the use of these diesels will be reduced, thereby reducing the fuel expenses of the utility. Eventually, these plants may only be used for short periods to cover daily peak requirements or only when the other units are out of service for maintenance or unscheduled outages. It should be noted that when these units are retired or are moved to serve isolated loads, the amount of that capacity would need to be replaced.

The analysis that follows is based on the base case energy needs assessment, which acknowledges the accelerated pace of rural electrification as well as the intention to interconnect the mining loads in Western Tanzania to the grid. Because of the size of the mining loads being considered, their connection to the system would need to be coordinated with the implementation of major new generation in the region.

7 It is understood that there are two mining companies currently planning to open mines in the Kagera district of Western Tanzania and they are negotiating with TANESCO for electricity service.

The expected needs by 2020 are about 370 MW including - Burundi: 140 MW - Rwanda: 150 MW - Tanzania: 80 MW

Assessment includes about 75 MW of reserve margin

Low and high sensitivity analyses illustrate level of uncertainty in region


3 POWER OPTIONS

3.1 Options Examined

The following is a list of power development options identified. These were then screened to remove those that did not meet the following criteria:

• availability of sufficient data to permit analysis; • reasonable unit cost; and • not likely to have severe environmental or socioeconomic risks that

could not be mitigated.

Type Name Location

Installed Capacity -

MW (MW) Hydro Igamba Falls FSL = 865 m (Stage 2)* Western Tanzania 8 Hydro Igamba Falls FSL = 980 m * Western Tanzania 80 Hydro Jiji 03 Burundi 15.5 Hydro Kabu 16 Burundi 20 Hydro Kagunuzi Complex Burundi 34 Hydro Kakono Western Tanzania 40 Hydro Kishanda Western Tanzania 207 Hydro Luiche Western Tanzania 15.3 Hydro Mpanda Burundi 10.4 Hydro Mule 34 Burundi 16.5 Hydro Nyabarongo Rwanda 27.8 Hydro Malagarasi Phase II Western Tanzania 11.4 Hydro Malagarasi Cascade Western Tanzania 40 Hydro Rusumo Falls Border of Rwanda and Tanzania 61.5 Hydro Ruzizi III Border of Rwanda and RDC 82 Hydro Ruzizi I rehab Border of Rwanda and RDC 8.7 Hydro Siguvyaye Burundi 90 Thermal Methane-fueled Engines at Lake Kivu - I Rwanda 30 Thermal Methane-fueled Engines at Lake Kivu - II Rwanda 30 Thermal Methane-fueled Combined cycle plants

at Lake Kivu Rwanda 100 Thermal New Diesel (imported fuel) Generic 50 Thermal New Diesel (local fuel) Generic 50 Thermal New Combined Cycle using No. 2 Fuel Generic 100 Thermal Geothermal Rwanda UnknownThermal Biomass Unknown Unknown Interconn.Mbarara - Gikondo Uganda - Rwanda 20 - 40 MWInterconn.Goma - Mukungwa DRC - Rwanda 20 - 40 MW Demand-side Management Generic Unknown Retained for further analysis Retained as project to be implemented; no further analysis required Rejected (too small, too expensive or severe environmental risks)

Thermal using conventional petroleum-based fuels are too expensive, except to satisfy urgent needs

17 hydro options examined ranging in size from 8 MW to 207 MW

Only thermal at competitive costs are modified diesel units fueled with methane gas extracted from Lake Kivu; however, this technology still needs to be proven at the large scale being considered.


Descriptions of the retained options are provided in text boxes at the end of this synopsis report. Their locations are shown in Figure 1 in Section 5.

3.2 Short-term Options

A review of the projects identified and the power needs indicates that there is a severe shortage of power in the region and that there are only the following three options available to overcome the deficit in the short term (i.e. installation before November 2008):

Generator sets powered by diesel engines using normal diesel fuel oil in unit sizes of 4 to 6 MW to a total of about 40 MW. The most urgent needs for these plants are:

− Rwanda (particularly Kigali) - 12 MW (in addition to the 12 MW currently under construction);

− Burundi (particularly Bujumbura) – 20 MW; − Western Tanzania (particularly Kigoma) – 6 MW (in addition to

the 1.7 MW currently under construction). The rehabilitation of Ruzizi I plant will add 8 MW but no additional

energy8; The installation of modified diesel engines using methane gas from

Lake Kivu – studies have been completed that indicate that such an installation of 30 MW appears feasible.

The installation of the standard diesels will imply severe financial constraints on the utilities in that the cost of power from those units is likely to significantly exceed the revenue the utility would earn from selling the power produced from them. The expansion plan suggested above is based on the assumption that the utility will do all in its power to ensure the supply of adequate power (or that the Government will subsidize the utility to the extent necessary to ensure that this objective is fulfilled). It is, of course, a business decision by the Government and/or the utility as to the level of subsidy and deficit that is acceptable.

3.3 Medium and Long Term Options (beyond about 2010)

A review was carried out of all reasonable and realistic technologies, including the classic options of hydro and thermal generation and renewables such as geothermal, wind, solar and demand side management. All thermal plants based on imported fossil fuels were screened out on the basis of high cost. The renewables were screened out either due to high cost and small size (solar) or lack of identified resources (wind or geothermal) or lack of information (demand side management – no information on the potential benefits nor programs that could be considered).

The hydroelectric projects that have been retained for the comparative analysis based on the selected evaluation criteria are as follows:

8 All the water available at the plant is now being used. The rehabilitation of the unit would permit some water to be stored for use during the peak period – i.e. the energy from the water would be shifted from non-peak time to the time of system peak

Urgent needs to be met by: - Expensive but quickly

installed diesels in load centres

- Rehabilitation of Ruzizi I

- First Stage of Lake Kivu gas

All options considered: Standard technologies Renewables Demand-side management

Renewables and DSM screened out on basis of very high cost or lack of information


Hydroelectric plant Installation (MW) Country Kabu 16 20.0 Burundi Kagunuzi Complex 34.0 Burundi Kakono 53.0 Tanzania Mule 34 16.5 Burundi Nyabarongo 27.8 Rwanda Rusumo Falls 61.5 Rwanda, Tanzania Ruzizi III 82.0 Rwanda, DRC Siguvyaye 90.0 Burundi

The thermal options retained are:

Medium speed engines using methane gas from Lake Kivu as fuel, constructed in modules of 30 MW – Stage I;

A combined cycle gas turbine plant of about 100 MW using methane gas from Lake Kivu.

The most realistic candidate projects, in terms of preparedness, generation cost and size are the following:

Medium speed engines using methane gas from Lake Kivu as fuel, constructed in modules of 30 MW – Stage 1;

Kabu 16; Nyabarongo; Rusumo Falls; Ruzizi III.

All of the other candidate options require additional studies to prove their technical and financial viability.

Thermal resources at Lake Kivu exceed 100 MW

• Lake Kivu gas • Kabu 16 • Nyabarongo • Rusumo Falls • Ruzizi III

Most attractive options (on technical grounds)

Hydro resources retained amount to about 335 MW


4 COMPARISON OF OPTIONS

4.1 Approach and Criteria

The process used to rank options on the basis of a mix of quantitative and qualitative criteria is called Multi-Criteria Analysis (MCA). There are a number of different MCA methods and the ordinal method of evaluation developed by J.C. Holmes9 has been selected. The major advantages of using this method are that:

a) it optimizes stakeholder involvement in the analytical process; and

b) it accounts for data limitations that are inherent to studies of the nature of this SSEA.

The comparative analysis is carried out in the following 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 quantitative and

qualitative indicators; • Step 4: Ranking of options within each category of criteria taking into

account the relative importance of criteria; and • Step 5: Selection of options to be included in power development

portfolios.

The following list of criteria, and associated indicators was used. For convenience, they are grouped according to the following five categories:

• Economic and Financial • Technical • Project Risks • Socio-economic • Environmental

Note that all costs and other parameters used in this comparative analysis are derived from previous project reports carried out by various authors; care needs to be taken in making and using these comparisons.

9 Holmes, J.C. 1972. An Ordinal Method of Evaluation. Urban Studies 9 (1): 179-191.

Options were compared using a structured approach


Table 1 - Criteria Used for Evaluating Power Options Category: Economic and Financial Economic Viability Financial Viability Gestation Period in Delivering Benefits

Category: Technical Level of Service and Flexibility Option’s Level of Preparedness

Category: Project Risks Technical Risks Financial Risks Risks for Investors and Power Utility Clients

Category: Socio-economic Public Health Impacts Due to Population Displacement Contribution of Project to Poverty Reduction Multiple-Use Benefits Impacts on Cultural, Historical and Religious Sites Impacts on Indigenous Communities Impacts on Vulnerable Groups Socio-economic Impacts on the Downstream Reaches

Category: Environmental Impact on Resource Depletion Impacts of Greenhouse Gas Emissions Land Requirements Impacts of Air Pollutant Emissions on Biophysical Environment Impacts on Designated Habitats and Natural Sites Impacts of Sedimentation and Erosion within the Reservoir and Downstream Proliferation of Invasive Aquatic Vegetation and Reservoir Eutrophication Environmental Impacts on the Downstream Reaches

4.2 Comparison

The ranking of the options are shown in the table on the next page. This table indicates that there is a wide variation in the ranking of options across categories of criteria. There is, thus, no single option that stands out as ranking well under each category. It should also be noted that the rankings reflect only the order of attractiveness but NOT the relative attractiveness of an option. In other words, an option that ranks seventh means that there are six other options that rank higher; it could be that all are virtually equal but the six are only slightly more attractive than the seventh.

The ranking of options in the Economic and Financial category is as follows: 1. Ruzizi III (82 MW) 2. Mule 34 (17 MW) 3. Lake Kivu (Engines) (30 MW) 4. Kabu 16 (20 MW) 5. Kakono (53 MW) 6. Rusumo Falls (61.5 MW) 7. Lake Kivu (Combined Cycle) (100 MW) 8. Nyabarongo (28 MW)

Options compared across five categories using 25 criteria


9. Kagunuzi Complex (34 MW) 10. Siguvyaye (90 MW)

If one considers only the economic viability within the Economic and Financial category (unit cost per kWh), three projects have a much better performance: Ruzizi III (2.9 ¢/kWh), Rusumo Falls (3.2 ¢/kWh) and Kakono (also at 3.2 ¢/kWh). The next best unit cost, Kabu 16 at 4.4 ¢/kWh is almost 40% more expensive. After Kabu 16 comes the two thermal plants at Lake Kivu, which are another 40% more expensive than Kabu 16.

The Kabu 16, Kakono, Rusumo and Ruzizi III hydro options can be considered as good candidates for portfolio development – apart from the estimated on-power dates, all can be considered to be similar:

• Kabu 16, Burundi: this option has a good overall performance (among the top four hydro options in four of the five categories), except in the environmental category. Anticipated impacts are on the Ruzizi River downstream and are acceptable.

• Kakono, Western Tanzania: this option has a reasonably good overall performance (among the top four hydro options in three of the five categories). The project was designed as power plus irrigation. The reservoir impact is minimal due to small area and volume. Plant could provide daily peaking, with consequent downstream flow and level variations over three quarters of the year. In addition, the feasibility study will have to consider the issue of the impact of the reservoir on the Minziro Forest Reserve.

• Rusumo Falls, Rwanda, Burundi and Tanzania: this option has a fair overall performance (among the top four hydro options in two of the five categories). Although ranked 6 in the economic and financial category, this low ranking was due to the high investments required because of the size of the option. However, it is less attractive in the Project Risks,

Overall Summary of Ranking of Options

CANDIDATE

Lead-time (Yrs)

Time-frame

Economic &

Financial

Technical Project Risks

Socio-Economic

Environ-mental

Kabu 16 5.0 MT 4 3 3 6 9Kagunuzi Complex 5.0 MT 9 2 9 2 10Kakono (High) 5.0 MT 4 6 4 1 7Mule 34 6.0 MT 2 9 7 3 4Nyabarongo 5.0 MT 8 3 4 8 5Rusumo Falls (Full) 5.0 MT 6 1 6 9 8Ruzizi III 7.0 LT 1 7 7 7 1Siguvyaye 6.0 MT 10 3 10 10 6

Lake Kivu (Engines) 3.0 MT 3 7 1 4 3Lake Kivu (Combined Cycle) 3.0 MT 7 9 2 5 2

MT = Medium Term - 8 to 10 years LT = Long term - beyond 10 years

Note: Highlighted rankings are four best hydro projects in the category

CATEGORIES OF CRITERIA

Least cost options are: (¢/kWh) • Ruzizi III: 2.9 ¢ • Rusumo: 3.2 ¢ • Kakono: 3.2 ¢ • Kabu 16: 4.4 ¢ • Lake Kivu: 6.1¢

Four “best” hydro options taking account of all criteria: • Kabu 16 • Kakono • Rusumo • Ruzizi III


Socio-economic and Environmental categories because of the following potential main issues: population resettlement, public health (increase of malaria and bilharzias), impacts on natural habitats such as flooding of 250 km2 of wetlands, impacts of changes in the hydrological and sediments regime on the Akagera National Park and water hyacinth accumulation in the reservoir. An environmental impact study is required to better assess these issues. This option is strategically placed in the region to (a) meet the new loads from the mines in the Kagera District that are being implemented and (b) strengthen, electrically, the backbone transmission system required for the benefits of regional power planning to be enjoyed by all parties.

• Ruzizi III, Rwanda and Democratic Republic of Congo: this option has the best rank in the Economic and Financial and in the Environmental categories; it does not involve any population resettlement and has no major negative impacts in the technical, risks and socio-economic categories. However, this option is less well strategically placed in the region and would come on line at least one year later than other options.

Among other hydroelectric options, Mule 34 and Nyabarongo can also be considered as candidates for portfolio development although both will require a well-designed resettlement plan.

The Siguvyaye and Kagunuzi Complex options are less attractive in most categories, including the Economic and Financial category, and should not be considered, at the present time, in portfolio development.

Because both thermal options are at a pre-feasibility level and provide a lower level of service than hydroelectric options with storage, they are at a lower rank in the Technical category. However, they have a good overall performance in all other categories. They can thus be included in power development portfolios in the medium or long term.

• Kabu 16, • Kakono • Rusumo Falls • Ruzizi III • Lake Kivu Gas Engines

Best evaluated options

Can also consider: • Mule 34 • Nyabarongo

Should NOT consider: • Siguvyaye (ranks

poorly) • Kagunuzi (not an

option if Kabu 16 built)


5 BACKBONE TRANSMISSION NETWORK

Before a regional development strategy can be implemented, a ”backbone” transmission system is required to ensure that the output from regional power development options can be transmitted to all parts of the region. There is currently an interconnection between Rwanda and Burundi but there is none connecting the districts of Kigoma or Kagera in Tanzania to either of the countries. To ensure that any power development option can be of regional benefit, the following allowances for transmission investments have been included: L1. 110 kV line from Kigoma, Rwanda to Rwegura, Burundi: 100 km at an

estimated cost of US $11 million. L2. 132 kV line from Kabarondo, Rwanda passing near Ngara to Biharamuro in

Kagera Province of Tanzania: about 150 km at an estimated cost of US$ 17 million.

L3. 132 kV line from near Ngara, Tanzania to Gitega, Burundi: about 200 km at an estimated cost of US$ 22 million.

L4. 110 kV line from Gitega, Burundi through Bururi to Kigoma, Tanzania: 240 km at an estimated cost of US$ 24 million.

Figure 1 below shows the existing 70 kV and 110 kV systems in the region and the above lines. These lines should be considered as an indicative allowance of the transmission needs for the region in order for it to benefit from the advantages of regionalization. The routing, voltages, line and substation characteristics would be determined through appropriate studies.

Backbone of transmission required for regional planning

Backbone requires investment of about US$80 Million

• Between Eastern Kagera District of Tanzania and Western Rwanda • Between Rwandan grid and the city of Kigoma in Western Tanzania

via Burundi • Between Burundian and Rwandan grids via the Interconnection

with the DRC at Ruzizi I and II

Backbone provides strong reinforcement of system


Figure 1 - Proposed Transmission Line Backbone


6 PROPOSED POWER DEVELOPMENT STRATEGY TO MEET DEMAND IN THE SUB-REGION FOR NEXT 20 YEARS

6.1 Strategies Examined

Discussions with the PSC members and Stakeholders at the meetings held in Dar es Salaam in September 2004 suggested that the following strategies should be examined to meet the power demand for the next 20 years:

Scenario 1A – Low diversification – thermal priority; Scenario 1B – Low diversification – hydro priority; Scenario 2 – Medium diversification; Scenario 3 – Maximum diversification, including imports.

In the above scenarios, diversification should be taken in a wide context; covering a wide geographic area, using various technologies and source of fuel, representing the three countries, and various sizes of project. The strategies serve as illustrations to allow decision makers compare between different regional development opportunities and to allow the comparison of cumulative impacts and the determination of mitigation measures for portfolios of projects.

6.2 Strategy Selected by the Project Steering Committee

Scenario 2 has been retained for the following reasons: There are insufficient resources to follow Scenario 1A (methane gas in

Lake Kivu) or 1B (local and attractive hydro); There are no known sources of low-cost power currently available from

outside the region that would be accessible to the region; It protects against the wide fluctuations in water flows that are common

in the region and therefore provides some security of supply during drought periods;

It makes use of local resources available throughout the region.

Wide range of development strategies considered

Strategy retained is one of medium diversification of resources from within the region


7 AN INDICATIVE POWER DEVELOPMENT PORTFOLIO FOR THE SUB-REGION

7.1 Medium and Long term Development

The portfolio proposed is the following: • The short-term program defined in Section 3.2; • Continue by alternating with hydro plants and an expansion of Lake

Kivu in the medium to long term. The definition of the portfolio is shown in the table below – those options in bold should be considered as requiring immediate decisions as to implementation.

Option name Type Year of commission

Average Annual Energy

(GWh/year)

Peak Capacity

(MW) Ruzizi I Rehab Hydro 2006 N/A10 8 Diesel using imported fuel

Thermal 2006/07/08/09 390 60

Lake Kivu Gas Engines 1

Thermal 2008 200 30

Kabu 16 Hydro 2010 112 20 Rusumo Falls Hydro 2011 403 61 Lake Kivu Gas Engines 2

Thermal 2012 200 30

Kakono Hydro 2014 300 53 Lake Kivu Gas Engines 3

Thermal 2016 200 30

Ruzizi III Hydro 2018 418 82

The chart below displays the contribution of the new power plants to the region’s power demand:

Indicative Development Portfolio

0

100

200

300

400

500

2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

Years

Dem

and

and

Cap

acity

- M

Load Load + 20% Reserve Planned Expansion

10 Rehabilitation will improve plant’s flexibility and availability of power, but add little extra energy

Reserve margin included to allow for maintenance and unforeseen plant shutdowns. Level selected is very low.


The above portfolio should be considered as an indicative power development proposal as future studies may suggest a different order to the development of each of the options included in the portfolio. These uncertainties include:

• The extraction of methane gas from a lake to feed a diesel engine is a new technology that has not been tried on a large scale (the existing plant is about 1 MW);

• Kabu 16 has been studied to the feasibility level; detailed design is required;

• Rusumo Falls has been studied to the design stage (according to the reports prepared); however, a review of these reports indicates that there are gaps in the database; and

• Kakono and Ruzizi III have only been studied at the prefeasibility level. Completion of the required studies and experience at Lake Kivu could identify difficulties in the implementation of any of the options proposed which could delay their commissioning (or even eliminate them from further consideration).

7.2 Cumulative Impacts

The cumulative greenhouse gas emissions (GHG) for this portfolio are about 700 thousand metric tons equivalent of CO2 per year once all options have been installed. The magnitude of these emissions represent 12% of 2000 emission levels for the three countries’ joint emissions. Compared to the world emissions these cumulative emissions are not significant (0.003%). However, even if they are not significant, these additions to the environment will still contribute in a cumulative way towards climate change.

Forty percent of the energy produced will come from thermal options, mainly from diesel engines burning methane gas extracted from Lake Kivu. Because of the nature of the fuel used, the total amount of nitrous oxides and sulphur dioxide (NOx and SO2) produced by Lake Kivu gas engines will have a minor cumulative impact. The location of the Lake Kivu power plants being away from large cities also contributes to maintain this attribute.

The hydro portion of the portfolio includes two options in the Lake Victoria basin and two options on the Lake Tanganyika basin. The cumulative impacts on both of these basins of adding these hydro projects would generally be in the areas of:

• Some resource depletion as related to deforestation; • Significant loss of remaining wetlands and some loss of forest reserve; • Minor modification of the sediment load and nutrient transport in the

basin. A basic assumption is that a backbone of transmission lines will be built to facilitate the transfer of power between countries. The transmission requirements include about 2,000 hectares of right-of-way along about 700 kilometres of transmission line. Because most of these lines will be through agricultural lands and savannah, the amount of deforestation should be small.

Cumulative Greenhouse gas emission from all options included would increase national level by 12%; an insignificant amount in a world-wide context.

Hydro impacts are in deforestation, loss of wetlands and modification of sediment load and nutrients going into Lakes Victoria and Tanganyika.

Impacts of transmission is mainly in deforestation on right-of-way

Additional studies required to confirm the order and timing of implementation of these power development options


7.3 Mitigation Measures

A wide variety of mitigation measures are available for thermal plants. Mitigation measures for standard thermal plants include:

1. For diesel generation using imported fuel, choose the cleanest fuel economically available.

2. Comprehensive maintenance, monitoring and reporting system should be followed throughout the operational life of the power plant.

For the Hydro options the following main measures are proposed: • Conservation of land adjoining the reservoir for erosion prevention and

changes in agriculture practices on slopes susceptible to erosion are the most appropriate measures in the region. A conservation management plan should be initiated as soon as a decision to build a power development option is taken;

• Creation and protection of spawning and rearing habitats for fish in reservoirs or in tributaries is needed if a fisheries program is planned;

• Water release policies are needed take into account ecological issues downstream of the dam. The application of a minimum flow at all times is now the norm for new hydro installations. Periodic releases of water to recreate annual flooding cycle are also part of a good ecological management practice;

• When required, development and implementation of a resettlement plan to assist all members of affected communities in their efforts to improve their livelihoods and standards of living, or at least to restore them to their pre-displacement levels;

• Control of public health risks through cooperation between the project developer and public health authorities; and

• Maximization of local employment during construction and operation and development of multiple-use of reservoir and facilities.

Mitigation for thermal: Clean fuel Good O & M

Mitigation for hydro: Erosion protection Protect spawning

and rearing habitats Maintain water

releases for environmental purposes

• Lake Kivu Gas (indigenous, low cost, low impact on physical and

social environment). • Kabu 16 (low cost, fast implementation). • Rusumo Falls (low cost, needed to supply mining loads AND

strengthen backbone BUT some environmental and socio-economic impacts).

• Ruzizi III (lowest cost and lowest impacts BUT not ready for implementation).

• Kakono (reasonable cost, some environmental issues). • Portfolio has minor impact on greenhouse gases and some impact

on deforestation, loss of wetlands and modification of sediment load and nutrients going into Lakes Victoria and Tanganyika.

• Design of all options need to take into account mitigation measures.

Proposed portfolio

Mitigation for transmission backbone: Small amount of

deforestation


8 NEXT STEPS IN IMPLEMENTING THE POWER DEVELOPMENT STRATEGY

8.1 Regional Actions Required

In order to achieve the schedule of transmission and generation additions required to meet the regional demand, a series of actions must be taken by the respective governments and project proponents. The key actions are summarized below:

Year Action Required Action by:

2005 Study and commit backbone transmission All three countriesCommitment to final studies for Kabu 16 BurundiCommitment to design update for Rusumo Falls All three countriesStart design update and EIA for Rusumo All three countriesFinal agreements/committment of first phase of Lake Kivu plants Rwanda, DRCApprove and procure 3 x 10 MW diesels All three countriesStart Kabu 16 final studies BurundiStart design and procurement for Kivu gas engines Project Proponent

2006 Install 3 x 10 MW diesels All three countriesProcure 1 x 10 MW diesel Project ProponentStart rehab of Ruzizi I Units 1 and 2 DRCAgreement on implementation of Ruzizi III All three countriesStart Ruzizi III feasibility study Burundi, Rwanda, DRCDesign for transmission system All three countriesApproval and implementation plan for Kivu gas engines RwandaStart procurement of Kivu gas engine No. 1 RwandaKabu 16 - approval and implementation plan, design BurundiKakono - start feasibility study Tanzania

2007 Install 1 x 10 MW diesel Project ProponentProcure 1 x 10 MW diesel Project Proponent Kabu 16 - begin construction Project ProponentComplete transmission construction Project ProponentStart construction of Rusumo Project ProponentComplete Kakono feasibility study Tanzania

2008 Complete installation of 1 x 10 MW diesel Project ProponentComplete installation of No 1 Kivu gas engine Project ProponentApproval and implementation plan for Rusumo All three countries

2009 Complete installation of 1 x 10 MW diesel Project ProponentKakono approval and implementation plan Tanzania

2010 Kakono design TanzaniaConstruction / installation of No 2 Kivu gas engine Project Proponent

2011 Kakono begin construction Project ProponentCommitment to construction of Ruzizi III Burundi, Rwanda, DRCRuzuzi III - approval/plan/design Burundi, Rwanda, DRC

20122013 Ruzizi III - begin construction Burundi, Rwanda, DRC20142015 Construction / installation of No 3 Kivu gas engine Project Proponent

Actions Required to Achieve On-Power Schedule Shown


8.2 Financing Needs to Support the Proposed Strategy

The need for investment is examined without consideration of the ownership of the projects; whether private or public funds are used, the level of investment is likely to be the same. The requirements are shown in three different time periods:

Investment (US$ millions) Project Size (MW) 2005 – 2010 2011 – 2015 2016-2020

Ruzizi I Rehab 8 2 Diesel using imported fuel 60 52 Lake Kivu Gas Engines 1 30 68 Kabu 16 20 44 Rusumo Falls 61 114 Lake Kivu Gas Engines 2 30 34 34 Kakono 53 86 Lake Kivu Gas Engines 3 30 68 Ruzizi III 82 104 Transmission Backbone N/A 80 Total Requirements 394 188 104

8.3 Longer Term Actions

The following points are actions that can facilitate the implementation of regional power trade but are not required to implement the retained projects. Though they are important, they affect the longer term and cannot be considered as requirements for the short term.

8.3.1 Adjustments Needed to the Legal and Regulatory Framework Generally, no legal or regulatory barriers to the implementation of cooperative power generation or regional power trade between Burundi, Rwanda or Tanzania were found.

However, the legal and regulatory frameworks will need to be adjusted so as to expressly address the following issues:

• How to encourage foreign investments: This particular issue is legally addressed in the Rwanda Investment Code, as well as in the Tanzania National Energy Policy. It will need to be addressed specifically in Burundi.

• The right of foreign investors to own assets, including properties (land, buildings) in the country: This right should be granted specifically in each country.

• The right to export profits out of the country: The Rwanda Investment Code sets down the instances where funds can be “externalised.” Similar conditions should also be formulated in Burundi and Tanzania.

• The government protection offered to foreign investors: The Rwanda Investment Code explicitly guarantees such protection and

No legal or regulatory barriers were found that hinder the regional power trade

Legal and regulatory frameworks need to be adjusted to explicitly address: Encouragement of

foreign investment Right to export

profits Environmental

protection Involuntary

resettlement

Investments of over US $ 606 million required for generation alone over next 15 years; additional US$ 80 million required early for transmission backbone.


sets down clear rules for resolution of disputes between foreign investors and the Rwanda Investment Promotion Agency or the Government of Rwanda. Similar rules and procedures should also be put into effect in Burundi and Tanzania.

• The existence of a credible environmental assessment process of projects to help ensure that they are environmentally sound and sustainable: To qualify for financing and to generally facilitate the smooth realization of hydropower generation projects, the legal and regulatory frameworks of Burundi, Rwanda and Tanzania will need to ensure credible protection of critical natural habitats against significant conversion or degradation. These legal and regulatory frameworks will also need to ensure that, whenever a project affects an international waterway, and in the absence of appropriate agreements between the riparian countries, negotiations in good faith are carried out so as to reach appropriate agreements or arrangements.

• Involuntary resettlement: To qualify for financing and to generally facilitate the smooth realization of hydropower generation projects, Burundi, Rwanda and Tanzania will need to ensure that they have in place adequate compensation and involuntary resettlement policies.

8.3.2 National Energy Policies to Support Regional Power Trade Energy policy at the national level should guide the development of a minimum policy platform to support regional power trade in the following areas:

• Each country should make the security of power supply a fundamental goal in its energy policy. Both Burundi’s and Tanzania’s energy policies set as a goal the improvement of the security of supply. It is recommended that this also be the case in Rwanda’s Energy Policy.

• Imports need not be regulated or, if they are, as little as possible, ensuring only they are not more costly than native generation when such is available.

• As for exports, a disposition of the law on energy should contain a clause authorizing the Minister responsible for energy matters to issue license to an applicant for an “international transmission line” that set conditions to limit exports for the purpose of operational security of the network and quality of supply as is the case in Burundi.

One other question that should be addressed is that of access of independent power producers to transmission networks, notably for regional trade. This would involve modifying the status of the present utilities, from single buyer to supplier of transmission services, require putting in place transmission system operators, the creation of open access same-time information systems with grid codes, ancillary services, etc.

International experience from regional electricity power trading arrangements such as those in Southern Africa Power Pool highlight that the core elements of a minimum policy platform to facilitate and support the development of a regional electricity market include:

• At least a functional separation of transmission from generation with appropriate ring-fencing between the two functions;

Facilitate power trading by providing clear ground rules: Security of power supply Regulation of imports (little as possible) Set conditions for exports Access by IPPs


• Non-discriminatory open access to national transmission networks operated by a transmission system operator (TSO);

• Transparent and harmonized pricing principles for transmission access, wheeling (energy transit), and ancillary services;

• Transparent and harmonized standards for transmission interconnection, metering, reliability, types of ancillary services, and system safety;

• De-monopolization of import and export of electrical energy by a single national entity.

The networks of Tanzania, Rwanda and Burundi should embark on a process for reforms that would foster regional trade. In the development of regional power trade, all of the policy elements need not be in place to establish cross-border trade between the three countries. However, it must be recognized that as the regional electricity market develops and matures these policy elements will need to be addressed over time.


Appendix - Project Summaries

Conceptual diesel – No. 2 oil Type Combustion diesel plant – burning No. 2 Oil Location To be installed as required in Kigali – Rwanda, Bujumbura -

Burundi and Kigoma – Western Tanzania. Project description Units would be 4-8 MW each, medium speed units, depending

on supplier and financing. Capacity and Energy Installed capacity per unit 7.5 MW (nominal size)

Annual energy at 60 % PF 40 GWh Annual energy at 80 % PF 53 GWh

Transmission Plants would be located at nearest substation to load centre.

Costs (2004) Capital cost 7.5 MW - engines 6.00 $ Million IDC 0.54 Env. mitigation allowance Included Total 6.54 Average generation cost 75% PF 12.8c/kWh (Crude - 40 $/bbl)

Implementation • Financing • Procurement and installation • Earliest on-power assumed as 2006

Environmental issues CO2, and air pollutant emissions will be high in comparison to hydro. Production of NOx and SO2 emissions in urban areas. Energy payback ratio is low.

Socio-economic Public health impacts related to air pollutant emissions Need for comprehensive maintenance to be implemented.

Previous studies and reports

N/A

Conventional diesel plant Rapid installation Low capital cost Earliest on-power: 2006 VERY high operating and fuel cost


Kabu 16 Hydroelectric Development Type Hydroelectric project – with hourly pondage Location Burundi, on the Kabarantwa river 16 km above confluence

with Ruzizi, 50 km north of Bujumbura. Project description Project would comprise a small conventional gravity dam in

the main river channel with a full supply level of 1081m, approximately 11 metres above normal river levels. The dam would create a small headpond (0.02 km2 area) with live storage equal to 2 hours of plant output. The dam would be 18.5 metres high, and include spillway gates. Power facilities would include intake above the dam, a 3400 m of power tunnel and penstock, and a two unit powerhouse with an installed capacity of 20 MW under a head of 191 m.

Capacity and Energy Installed capacity 20 MW Firm capacity 13 MW Average annual energy 112 GWh Firm energy 67 GWh

Transmission Proposed new backbone grid would extend to Rwegura. 6 km of 110 kV line with a cost of 2.5 $ million for the line and upgraded substation at Rwegura has been included in the total project capital cost.

Costs (2004) Capital cost 38.34 $ Million IDC 6.01 Env. mitigation allowance 0.00 Total 44.35 Average generation cost 4.4 cents/kWh

Implementation • Field investigations and final engineering design required • Environmental impact assessment and resettlement

action plan are required • Preparation of tender documents • Earliest on-power estimated as 2010

Environmental issues During the dry period of 5 months/year hourly flow and level variations would be experience downstream for the 16 km to the Ruzuzi river. Effects on the Ruzizi river and in the Ruzizi reserve should be acceptable.

Socio-economic Some 75 persons (1995 estimate) would be displaced from the small headpond and project area. Riparian users downstream of dam would be affected severely over 3.5 km for 5 months/year unless a minimum flow release is established.


• SOGREAH Feasibility study of Kabu 16 for Burundi MEM, November 1995, including an environmental impact study.

• Project was included in a series of studies (Coyne and Bellier in 1983, Lahmeyer in 1983, EDF in 1988 and SOGREAH in 1993

Kabu 16 hydro 20 MW 4.4 ¢/ kWh Earliest on-power: 2010 Displacement of 75 persons Riparian users for 3.5 km downstream affected


Kakono Hydroelectric Development Type Hydroelectric project – with daily pondage Location In Tanzania, on the Kagera river near the Uganda border,

approximately 90 km to the west of Bukoba and Lake Victoria. Project description Project would comprise a 35 m high concrete gravity dam and

spillway and earthfill dam, with a full supply level of 1182 m. The dam would create a small reservoir with live storage equal to 30 hours of plant output. Power facilities would include intake in the dam, and a two-unit powerhouse at the toe of the dam with an installed capacity of 53 MW under a head of 26 m. Project was identified for power and for water supply to downstream irrigation (potential 70 000 ha). Reservoir would extend 40 km, however be about 15 km2 in area. Firm energy and flows would be increased if Rusumo dam is constructed.


Transmission Power would be delivered to the proposed new grid at Rusumo Falls over a 150 km 110 kV line.


Implementation • Field investigations and feasibility study required, jointly with planning for downstream irrigation project at Kyaka

• Assessment of downstream irrigation benefits • Environmental impact assessment and resettlement action

plan are required • Preparation of final design and tender documents • Earliest on-power estimated as 2011

Environmental issues Reservoir impact minimal due to small area and volume. Project would flood part of the Minziro Forest Reserve, a unique forest habitat type in Tanzania. Plant could provide daily peaking, with consequent downstream flow and level variations over 75 % of the year.

Socio-economic Generation cost assumes 50% dam cost allocated to irrigation project. Several potential irrigation areas near Kyaka exist.


• KBO study on the development of the Kagera river basin, 1982

• Norconsult - prefeasibility studies of hydropower developments on the Kagera River in 1976

• Norconsult – Kagera river basin - indicative basin plan 1976

Kakono hydro 53 MW 50% of dam costs attributed to irrigation 3.2¢/ kWh Earliest on-power: 2011 Reservoir has minimal impact Riparian users for 3.5 km downstream affected


Lake Kivu Methane Engines Type Combustion thermal plant – burning Lake Kivu methane

gas as fuel Location On Rwanda side of Lake Kivu – Note Lake Kivu is on the border

between DRC and Rwanda. Possible sites are at Kibuye and Kiguf.i

Project description For comparison purposes it is proposed that the project would consist of up to four 30 MW generating plants, to be built over a number of years. Power supply to the grid would be via a power purchase contract. Each 30 MW plant would comprise 4 modified 7.5 MW medium or slow speed Diesel engines, and each plant would have its gas collection and processing system. A proposal by Dane to Rwanda Ministry of Energy, Water and Natural Resources in 2003 proposed an initial plant of 3 x 7.5 MW medium speed engines, followed by 2 x 12 MW units, followed by combined cycle gas turbine plants of 32 MW each. No public information is available on whether the technical viability of generation in this size range is feasible, and on probable costs

Capacity and Energy Installed capacity - future 30MW Annual energy at 60 % PF 160 GWh Annual energy at 80 % PF 210 GWh

Transmission Power from the Kivu plants would be delivered to the grid at Kigoma. No transmission cost has been added to the original Dane estimates.

Costs (2004) Capital cost 30 MW - engines 25.44 $ Million Capital cost – gas collection 36.27 Total capital cost 61.71 IDC 5.61 Env. mitigation allowance Unknown Total 67.32 Average generation cost 75% PF 6.1 c/kWh (economic cost) Actual price will be a PPA, which would normally include cost of delivery to the grid.

Implementation • Agreement between DRC and Rwanda on resource use • Final design and testing for gas system • EIA • Due diligence • Final proposal by promoter and PPA • Construction • Earliest on-power assumed as 2008

Environmental issues No significant negative impacts have been identified. CO2 and air pollutant emission will be high in comparison to hydro. There will be some impact of Lake Kivu water quality from higher CO2 levels in return degassed water. Energy payback ratio is very low.

Socio-economic Health impacts related to air pollutant emissions. Need for pollution abatement measures following international standards.


• Data Environnement – Exploitation of methane in Lake Kivu, 2003

• Dane Associates – Electricity, transmission and gas production systems - 2002

• Lake Kivu gas development – safe and environmentally sound exploitation, Klaus Tietze, 2000

• Lake Kivu gas development and related issues – Moiffak Hassan, 2000

Kivu gas 30 MW modules 6.1¢/ kWh at 75% plant factor Earliest on-power, assumed at 2008 Requires power purchase agreement with proponent No significant environmental or socio-economic impacts


Rusumo Falls Hydroelectric Development

Type Hydroelectric project – with storage Location Border between Rwanda and Tanzania, close to Burundi, on the

Kagera river, at highway crossing between Rwanda and Tanzania. Project description

Project would comprise a conventional gravity dam in the main river channel with a full supply level of 1325 m, approximately 5 metres above normal river levels. The raised river levels from the forebay would provide some flooding upstream in the Ruvuvu river, and would marginally affect levels in Lake Rweru, approximately 70 km upstream on the Nyabarongo river. The dam would be 12 metres high, and include spillway gates. Power facilities would include intake above the dam, a 460 m power tunnel and a three unit powerhouse with an installed capacity of 61.5 MW under a head of 35 m.

Capacity and Energy

Installed capacity 61.5 MW Firm capacity 55 MW Average annual energy 403 GWh Firm energy 308 GWh

Transmission Proposed new backbone grid would pass the site. A nominal 10 km of 110 kV line with a cost of 1.4 $million has been included in the total project capital cost.


Implementation • Final engineering studies required to confirm reservoir levels and available storage, and to finalize the civil works design

• Environmental impact assessment and resettlement action plan are required

• Agreements required between Tanzania, Burundi and Rwanda • Earliest on-power estimated as January 2011

Environmental issues

Extent of upstream flooding on the Ruvuvu and Nyabarongo rivers and on Lake Rweru to be confirmed and impacts assessed. Upstream flooding from the dam estimated as in the order of 400 km2, that includes 125 km2 of existing lake and 250 km2 of existing wetlands and 15 km2 of valley slopes. Reduction in downstream flood flows and levels will affect wetlands downstream, including in the Akagera National Park. Sediment loads should not be an issue.

Socio-economic

Approximately 3000 persons upstream of the dam may be affected and some displaced. Increase in water areas upstream could increase health risks due to bilharzias and malaria.


• Acres, Review of existing documents for the Rusumo Falls 2003 • Tractebel, KBO, Institutiona/ tariff studies, Rusumo Falls,1997 • Tractebel, Rusumo Falls – transmission studies 1994-1995 • Tractebel, KBO, Rusumo Falls, Tender documents, civil works,

electromechanical equipment, April 1989, revised January 1992. • Tractionel, KBO, Rusumo Falls, technical feasibility, preliminary

study of structures and works, June 1987 • Tractionel-Electrobel - Rusumo Falls, Agriculture & other

implications – inventory of the agriculture situation, March 1979 • Norconsult A.S./Electrowatt, Kagera River Basin Development,

Prefeasibility Studies, including Rusumo Falls Hydropower Project, April 1976

Rusumo Falls Hydro: 61.5 MW 3.2¢/ kWh Earliest on-power at 2011 Extent of upstream flooding needs to be confirmed by additional studies Wetlands downstream to be affected 3,000 persons could be affected and some displaced Increased health risks


Ruzizi I Hydroelectric Development - Rehabilitation Type Hydroelectric project – with lake Kivu storage – rehabilitation of

existing plant Location At the outlet of Lake Kivu, on the Ruzizi river that forms the

boundary between Rwanda and the DRC. Project description Existing Ruzizi project comprises 4 units –Units 1 and 2 are 6.3

MW each, units 3 and 4 are 7.8 MW each – Total 28.2 MW. Unit 4 has been out of service since mid-1994, and rehabilitation should be completed within a few months. Procurement has been completed. Funding by WB. Upgraded output will be 8.7 MW. Units 1 and 2 will then be upgraded to 7.3 MW each, resulting in a total station capacity of 31.1 MW. Date for completion of rehabilitation of units 1 and 2 has not been provided. Ruzizi I forebay affects lake Kivu level and outflow by backwater effect. Plant head is 23.2 m. No additional energy generation would result from the rehabilitation program. Peak output and short term energy reserve would be increased.

Capacity and Energy Capacity after rehab No. 4 29.1 Present capacity Units 1/2/3 20.4 Nominal Increment from rehab 8.7 Average annual energy 148 GWh Firm energy 148 GWh

Transmission Power from Ruzizi I is delivered to the Mururu substation, which supplies to Kigoma and Bubanza.

Costs (2004) Capital cost Unit 4 0.84 $ Million Capital cost Units 2 and 3 1.60 $ million IDC N/A Env. mitigation allowance N/A Total 2.44 Average generation cost N/A

Implementation • Re-assembly Unit 4 • Re-assembly Units 1 and 2

(No information on financing for Units 1 and 2) • Earliest on-power Unit 4 estimated as mid 2005

Environmental issues Socio-economic

Existing plant. Peak plant discharges could increase from 150 to 170 m3/s due to upgrades, affecting reach 15 km to Ruzizi II. Average flow after 1961 is 100 m3/s.


• Lahmeyer – rehabilitation study – report not available for assessment

Ruzizi I Hydro: Rehabilitation of existing plant 8.7 MW added Earliest on-power mid-2005


Ruzizi III Hydroelectric Development Type Hydroelectric project – with hourly pondage Location Site RD 2 on the Ruzizi river, which forms the border between

Rwanda and the DRC. 25 km downstream (south) of the outlet of Lake Kivu.

Project description Project would be located downstream of the Ruzizi I and II existing plants, and flows would be nearly completely regulated by Ruzizi I operation of Lake Kivu as a reservoir. Project would comprise a 20 m high concrete gravity spillway and earthfill dam, with a full supply level of 1082m. The dam would create a small headpond (0.1 km2 area) with live storage equal to 1 hour of plant output. Power facilities would include intake in the dam, a 340 m power tunnel and penstock, and a three unit powerhouse with an installed capacity of 82 MW under a head of 62 m.


Transmission Power would be delivered to the Mururu 2 substation at the Ruzizi I plant over a 23 km 110 kV line.


Implementation • Field investigations and feasibility study required • Environmental impact assessment is required • Preparation of final design and tender documents • Earliest on-power estimated as 2012

Environmental issues Reservoir impact minimal due to small area and volume. River flows would be diverted through the power facilities at all times except during floods, affecting 1 km of river. Downstream flows may vary considerably during normal daily operation (from 50 to 175 m3/s. (Note project is planned with a plant factor of 58 %, year round). Downstream effects on the Ruzizi river should be assessed.

Socio-economic Riparian users downstream of dam would be affected severely over 1 km unless a minimum flow release is established. (This would reduce energy generation). Population farther downstream would also be affected by flow and level variations.


• Tractabel - study of the hydroelectric potential of the Ruzizi valley. 1993

• Tractabel prefeasibility study of RD2 site in 1992

Ruzizi III Hydro: 825 MW 2.9¢/ kWh Earliest on-power at 2012 Reservoir impact minimal Downstream impacts need to be assessed Riparian users downstream for 1 km. may be affected

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