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Chapter 6:

6.1                GENERAL

                   This chapter describes the proposed project in a simplified manner to give a general
                   overview of its technical features.

                   The following major project components are described below for the solution with one
                   power station and with two power stations:

                       Dam
                       Reservoir
                       Power plant
                       Access to Project Area
                       Construction Camp and Operators Village
                       Transmission Facilities
                       Environmental Mitigation


                                                 Mean annual runoff      160 m3/s
                                                 Sediment inflow         3 mill. m3/yr
                                                 Total average inflow    5.0 billion m3/year

                   Dam       Main Dam       Volume (RCC)                 2.14 million m3
                                            Height                       200 m
                                            Length                       700 m
                             Right Flank    Volume (RCC)                 0.26 million m3
                                            Height                       50 m
                                            Length                       500 m
                             Spillway Capacity                           11,000 m3/s (PMF)

                   Reservoir                     HWL                     580 m.a.s.l.
                                                 LWL                     530 m.a.s.l.
                                                 TWL                     380 m.a.s.l.
                                                 Inundated area (HWL)    56.7 km2
                                                 Inundated area at LWL   18.8 km2
                                                 Total Volume            2.55 billion m3
                                                 Active storage          1.76 billion m3

                   Power plant, One Station

                             Waterways           Intake Tower            2 per station (2 total)
                                                 Headrace                30 m2
                                                 Shaft                   25 m2
                                                 Tailrace                95 m2
                             Power Plant         Installed Capacity      360 MW
                                                 Unit Size/Type          120 MW/Francis

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                                            Gross head                       200 m
                             Total Investment Costs                          554.38 Million USD

                   Power plant, Two Stations

                             Waterways      Intake Tower                     1 per station (2 total)
                                            Headrace (cross-sec. area)       30 m2
                                            Shaft (cross-sec. area)          25 m2
                                            Tailrace (cross-sec. area)       50 m2
                             Power Plant    Installed Capacity per station   180 MW (360 MW tot.)
                                            Unit Size/Type                   90 MW/Francis
                                            Gross head                       200 m
                             Total Investment Costs                          613.31 Million USD

                   Construction Camp and Operators Village

                             Const. Camp Temporary Fac., Angola              900 People
                             Const. Camp Permanent Fac., Angola              30 Families
                             Operators Village, Namibia                      80 Families

                   Access Roads                  Angola Upgraded Bitum.      75 km
                                                 Angola New Bitum.           200 km
                                                 Namibia Upgraded Gravel     84 km
                                                 Namibia New Gravel          21 km

                   Transmission Line             Voltage                     330 kV
                                                 Length                      697 km

                   Environmental Mitigation

                                                 Design Considerations       Tower Intake
                                                                             Spillway Design
                                                                             Construction Camp
                                                 Construction                Mitigation Plan
                                                 Operation                   Min. Flow Releases

6.3                THE BAYNES DAM

                   The dam site for this scheme is located approximately 40 km downstream of Epupa Falls
                   at river El. 400. The scheme develops the head from reservoir level 580 and down to El.
                   380 with a 2 km long tailrace tunnel (see Figure 6.1).

                   Four dam types, concrete faced rockfill dams (CFRD), roller compacted concrete (RCC)
                   gravity dam, RCC arch gravity, and traditional concrete arch dams were evaluated as the
                   most likely options for the Baynes Dam. The arch-gravity RCC dam proved to be the
                   economically best solution. The dam will be about 200 m high.

                   The type of right flank dam to be selected depends on the type of the main dam. The
                   dams should preferable be of the same type to avoid different construction processes.
                   The rockfill dam options for the main dam also include an extension over the right flank.
                   With the RCC main dam options, the right flank dam has been shown as an RCC gravity

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                   The spillway is on natural rock in a col to the left of the main dam. The spillway consists
                   of a concrete overflow section and a blasted rock channel chute.

6.3.1              Design Assumptions

                   Reservoir Levels

                   The highest regulated water level was determined by optimisation of reservoir level and
                   installed turbine capacity (see Chapter 5). The level obtained is +580 m. The freeboards
                   required to contain the floods and, in the case of the rockfill dam, also wave run-up, were

                   The following reservoir levels have been used in the design:
                                                                    Concrete dam             CFRD
                   Normal maximum reservoir level:                  + 580.0                  + 580.0
                   1000-year flood level:                           + 582.8                  + 582.8
                   PMF level:                                       + 585.6                  + 585.6

                   For the rockfill dam alternative wave run-up is important. This is determined from wind
                   speed and fetch. For a design wind speed of 20 m/s and the fetch of 3.4 km, the
                   significant wave height is hs = 0.9 m. Based on a wave run up diagram (CIRIA, 91), the
                   wave run up on a smooth surface will be maximum 3.5 x h s (3.15 m) for 98% of the

                   Spillway Capacities and Floods

                   The spillway capacities have to be designed to pass any flood without any risk of
                   damaging the dam such that a catastrophic release of reservoir water might occur. This is
                   normally the Probable Maximum Flood (PMF).

                   A design flood has to be defined at which no damage should occur to the dam or
                   spillway. This is normally taken as the 1:1000 year flood. These criteria are applied
                   strictly to embankment, including rockfill, dams because of their poor resistance to
                   overtopping, and in practice the PMF becomes the design flood. In some countries only
                   the PMF is considered in design. Some overtopping of a concrete dam during a PMF
                   might be acceptable, but this has not been considered as an option in this study phase as
                   any cost savings would be marginal.

                   All spillways will be free overflows, i.e. there will be no gates because of concern about
                   their correct operation, particularly in the long term.

                   The floods have been routed through the reservoir to obtain the corresponding spillway
                   flows. The table shows the floods used in this feasibility study.

                                                                      Inflow              Routed flood
                     Design flood, 1 000-year return period         3,800 m /s             3,800 m3/s
                     Probable Maximum Flood (PMF) m3/s              11,000 m3/s           10,900 m3/s

                     Table 6.Error! Bookmark not defined.1    Peak inflow flood flows used in dam and
                                                      spillway design

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                   Earthquake Loads

                   The earthquake load adopted for this study is 11% g horizontally and 60% of this acting
                   vertically and simultaneously in the most unfavourable direction. This corresponds to the
                   1:1000 year event as defined in the report on seismicity. The maximum credible event
                   (MCE) has not be estimated for this study. The likelihood of finding active faults in the
                   project area with a significant earthquake potential is considered to be very slight and a
                   deterministic approach to fixing an MCE will probably not yield useful results. For the
                   purposes of the feasibility study we have adopted the 1:10,000-year event of 27% g.
                   These values do not have a significant effect on the design of the dams.

                   Silt Loads

                   We have assumed that the reservoir formed behind the dam will eventually silt up to
                   some extent and that a silt load may then be applied to the dams. We have assumed that
                   the silt level for concrete dams is at a height of 30%. The silt load is calculated assuming
                   the silt is a fluid with a relative density of 1.36 when calculating horizontal loads and a
                   relative density of 1.92 when calculating vertical loads. This load has a stabilising effect
                   on concrete faced rockfill dams and other embankment dams, but affects the stability of
                   concrete dams adversely.

                   Foundation Conditions and Excavation Depths

                   The foundation conditions at the dam site are good to excellent with hard rock present at
                   the surface or at modest depth. Jointing is also moderate. The depth of excavation
                   required for each dam type was estimated from the results of the drilling on the site, the
                   geological field mapping and site inspection. A distinction was made between excavation
                   of superficial deposits and rock. The excavation depths for a gravity dam are shown in
                   Table 6.2. The excavation profile for the arch-gravity dam is governed by geometrical
                   constrains as well as rock quality and the required excavation is shown on Drawing 421.

                           Right abutment                            River bed         Left abutment
                          Soil        Rock                    Soil            Rock   Soil         Rock
                           0            2                      1               0      0             2

                      Table 6. Error! Bookmark not defined.2  Foundation excavation depths, m, for
                                                     RCC gravity dam

                   The excavation depths shown in Table 6.2 apply also to the concrete faced rockfill dam
                   where the soil excavation depths and rock excavation depths apply to the rockfill and
                   upstream concrete plinth respectively.

6.4                THE BAYNES RESERVOIR

                   The reservoir formed by the dam provides a place for storage of water to regulate
                   seasonal and annual variation in precipitation. The height of the dam, which controls the
                   inundated area, was determined based on analysis of the least cost for expansion of the
                   Namibian power system.

                   The reservoir at high water level will inundate 56.7 km2, at low water level the inundated
                   area will be 18.8 km2, leaving 37.9 km2 periodically inundated (see Figure 6.2).

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                   Constructing a dam on the Cunene River for the purpose of hydro-electric power
                   production achieves two objectives, i.e, to establish hydraulic head and to provide
                   storage for retaining high flows and flood water that later can be released at controlled
                   rates to meet fluctuating power demand.

                   The Baynes reservoir will provide regulation of the variable flow in the Cunene River; on
                   long-term basis between wet and dry series of years, on annual basis between wet and
                   dry seasons and on short term basis over weeks and days.

                   The yearly flow in the Cunene River shows great seasonal variations. The flow records
                   show also substantial variations over series of years. Dry periods lasting for several years
                   have been recorded in the past, the most recent beginning in 1993. Simulations of
                   hydropower generation over a 50 years period of flow records, have demonstrated that
                   the reservoir at Baynes will not have sufficient capacity for long term regulation, but will
                   provide annual regulation between wet and dry season

                   Maximum monthly average flow at Baynes, as derived from the hydrological series on
                   record, is 1294 m3/s, while minimum monthly flow has been estimated at 3 m3/s.

                   Reservoir volume and area

                   The Baynes dam will be about 200 m high and provide a head, also of 200 m, between
                   the high operating water level of the reservoir and the water level at the outlet of the
                   tailrace tunnel.

                   Normal high water level (HLW) of the Baynes reservoir has been optimised at elevation
                   580 m a.s.l., and the lowest water level (LWL) for operating the plant has been set at
                   elevation 530 m a.s.l. The reservoir will contain a gross volume of 2.55 billion m3 of
                   water of which the active storage - between HWL and LWL - will be 1.76 billion m3 and
                   the dead storage - below LWL - will be 0.79 billion m3. The volume of the active storage
                   corresponds to about 35% of the average annual inflow.

                   The artificial lake formed by the dam will extend some 40 km upstream and inundate an
                   area of 57 km2. Maximum depth at the dam will be 200 m and the average depth,
                   calculated as maximum storage volume divided by maximum surface area, will be 45 m.
                   The reservoir will be relatively narrow. Incremental change of inundated area will be
                   about 0.8 km2 per m within the operating range

                   Annual evaporation rate will be 113 million m3 at HWL and 38 million m3 at LWL
                   corresponding to 3.6 m3/s and 1.2 m3/s respectively.

                   In addition, the existing Gove dam, with its active storage of 2.57 billion m3, is intended
                   to regulate an average annual runoff of 1.08 billion m3 from a catchment of 4667 km2.
                   The Gove regulation has thus a considerable carry-over potential.

6.5                POWER PLANT

                   Two alternative schemes, both having underground power stations, have been developed
                   for this site. One is based on a single power station located on the side of the river with
                   the lowest cost for development. Another scheme is based on the development of two
                   independent power plants, one on each side of the river. The single station alternative
                   will be equipped with three equal units of 120 MW and the alternative with two power
                   plants, one on each side of the river will be equipped with two equal units of 90 MW

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6.5.1              Location

                   The dam site for this scheme is located approximately 40 km downstream of Epupa Falls
                   at river El. 400. The scheme develops the head from reservoir level 580 and down to El.
                   380 with a 2 km long tailrace tunnel.

                   The power plant has been placed as close to the dam and as far upstream as possible.
                   The upstream location has the following advantages:

                    A short headrace tunnel.

                    An upstream surge chamber is not needed with a short headrace as the distance
                     between free water surfaces is short compared to the total head power plant. With a
                     reservoir draw down of 50 m and a discharge capacity of 210 m3/s a surge chamber
                     would be a costly item.

                    With a short headrace tunnel, a double intake to provide reliable water supply in case
                     of breakdown or maintenance will have a smaller addition cost over a single intake
                     design. The value of generation otherwise lost during breakdown or maintenance will
                     likely compensate for this additional cost.

                    The tailrace tunnel is located more freely than a headrace tunnel as less rock cover is
                     required for low pressure tunnels. It can therefore be shorter and hence less costly
                     than a high pressure tunnel. With the highly competent rock in the area it is also
                     possible to cross beneath the upper reaches of the river itself.

                   A disadvantage with a low laying tailrace tunnel is the need for pumps when draining the
                   tunnel. However, with the very competent rock in the area, the need for inspection and
                   maintenance works is expected to be very limited.

                   The location of the power station, shown on the drawings as being on the Namibian side
                   of the river, was found to be the least cost option. An alternative on the Angolan side is
                   slightly more costly but also a viable alternative.

6.5.2              One Station, 3x120 MW

                   This section describes the alternative with a single power station for the entire project.
                   All optimisations and generation simulation were performed based on this optimal option
                   (see Figure 6.3).            Waterways

                   Intake - In order to satisfy the environmental requirement for water from multiple levels
                   of the reservoir, intake towers were found to be the most practical, economical, and
                   flexible option (see Figure 6.4). Three intake levels are required. Each opening will be
                   provided with gates and trashracks. Two towers are provided to improve reliability and
                   allow for maintenance of towers and tunnels without taking the power station off line.
                   The outlet at the base of each tower is provided with a roller gate, capable of being
                   closed under flow conditions.

                   Headrace, shaft and penstock - The headrace is defined for the purpose of this report as
                   being the portion of horizontal waterway between the intake and the steel lined penstock.

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                   The shaft is the vertical section of the waterway that will connect the upper portion of the
                   headrace to the lower headrace or penstock. The two parallel penstocks will each
                   bifurcate providing four smaller penstocks that will provide flow to the three turbines.

                   Valves - The valve chamber will include four 3,000 mm spherical valves such that the
                   central turbine can utilise flow from either of the two intake towers. This configuration
                   was developed to maintain generation during maintenance or repair of the intake, and
                   headrace passage.

                   Gates - Gates will be provided for inspection and maintenance of the intake, headrace
                   and tailrace, tunnels.

                   Tailrace - The tailrace tunnel has a length of 2 km and a cross-section of 95 m2.
                   Stoplogs slots are located at the outlet, designed for use during normal flow conditions.            Civil

                   Powerhouse - The powerhouse will be located in a cavern 17 m wide, 100 m long and 45
                   m high (see Figure 6.5). Access will be through a 800 m long tunnel 6 m wide and 5 m
                   high. Two bridge cranes will be located within the powerhouse, designed to be able to
                   lift the heaviest piece of equipment (generator rotor) using a yoke spanning between the
                   main hooks of the cranes.

                   Valve Chamber - A separate valve chamber just upstream of the powerhouse will house
                   the spherical valves described above.

                   Transformer Hall - The transformers will be placed adjacent to the powerhouse in a
                   separate cavern. A cable shaft will take the main power cables out of the plant to the
                   outdoor switchyard. The cable shaft will also serve as an emergency exit.            Mechanical

                   The optimised power station installed capacity has been has been found to be 360 MW.
                   Assuming 98% generator efficiency and 99% transformer efficiency, each of the three
                   identical turbines will be rated 123 MW.

                   Main turbine data is as follows:

                             Number:                                 3
                             Type:                                   Francis
                             Maximum unit output:                    123 MW
                             Net head:                               195 m
                             Design net head (at best eff. point):   177 m
                             Nominal rotating speed:                 272.7 rpm
                             Maximum runaway speed:                  540 rpm (approx.)
                             Turbine setting:                        7.0 m below lowest tailwater level

                   The Governor will be electro-hydraulic PID type.

                   Heads and Losses

                   According to the elevations given above, the gross head will vary between 135 and
                   207 m (extreme values). The simulations of energy production indicate a weighted mean
                   net head of 177 m, which is taken to be the design net head of the turbines. The total
                   headloss at full load operation of all units is approximately 5 meters.

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                   Turbine Output and Discharge

                   The maximum turbine output listed above has been defined as the output at net head
                   195 m corresponding to the maximum gross head of 200 m and assuming a headloss
                   corresponding to the total discharge when all three units are running at full gate. At
                   higher net heads, i.e. with a reduced number of units in operation, it is anticipated that
                   the gate opening will be adjusted such that the turbine output will not exceed nominal
                   output. This definition has been the basis for the optimisation of the total plant output.

                   The maximum turbine discharge at net head 195 m will be approximately 69 m3/s.
                   Maximum turbine discharge at design net head (177 m) is 67 m3/s and best efficiency
                   point at this head corresponds to a turbine discharge of 55 m3/s.

                   Turbine Setting

                   Selection of setting is critical in that improper setting can result in turbine cavitation.
                   The water level at turbine outlet when one unit is operating at maximum discharge
                   (approximately 69 m3/s) governs selection of turbine setting. The submergence
                   requirements given here are tentative, based on assumptions of the turbine size and
                   specific speed. Final turbine setting will depend upon the exact requirements from the
                   selected turbine manufacturer.

                   Tailrace Surges

                   Surge chambers, each with a cross section of 50 m2, are located at the outlet of each draft
                   tube, just before the tailrace tunnel. The surge chamber inlets are throttled to an area of
                   approximately 7 m2. In addition to the individual surge chambers, the tailrace access
                   tunnel as well as the adit near the tailrace tunnel outlet will also be part of the surge
                   system. Both tunnels are inclined between 1:8 and 1:10 and have a cross sectional areas
                   of and 30 m2 each. Highest upsurge in the three individual surge shafts near the draft
                   tube outlets and in the tailrace access tunnel will reach El. 410. The upsurge in the adit
                   reaches El. 399.

                   Speed and Pressure Rise

                   The maximum pressure rise during load rejection will be limited to 20% of maximum
                   static head. The corresponding speed rise is tentatively calculated to be maximum 55%
                   of rated speed. The final values will be subject to guarantees from the turbine

                   It should be noted that highest speed and pressure rises will take place when two units
                   are running with only one of the intake towers/headrace tunnels in operation.

                   The figures given above are based on a generator moment of inertia GD2 = 5,200 tm2
                   corresponding to a unit acceleration time Ta = 8.5 seconds.

                   Frequency Stability

                   The power plant needs to be capable of regulating the frequency when operating alone at
                   full load on a separate electrical network. Pure resistive load has been assumed.
                   Waterways, surge chamber and generator and turbine data are as described in this report
                   and shown on drawings.

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                   Analyses of the entire system comprising waterways, surge shafts and turbine, generator
                   and governor show satisfactory stability margins, i.e. that the relative frequency deviation
                   caused by a load change will be within 60%. This means for example that the temporary
                   frequency drop resulting from a load acceptance of 10% of full load will be
                   approximately 6% or 3 Hz.

                   The damping is also satisfactory and within the values recommended by The Institute of
                   Electrical and Electronic Engineers (IEEE) Standard 125. Calculations also show that
                   the inlet to the individual surge chambers at the draft tube outlet will have to be throttled
                   in order to avoid oscillation between these and the tailrace access tunnel.

                   Design Pressure

                   The design pressure for turbines and inlet valves shall be limited to 255 meters of water,
                   corresponding to approximately 120% of maximum static head at highest operating
                   headwater level, El. 587.

                   Speed of Rotation

                   The speed of 272.7 rpm is chosen as a compromise between the economic benefit of high
                   speed, and the hydraulically and mechanical considerations which limit the speed. The
                   selected speed is on the conservative side, and the velocity of the water passing through
                   the runner is moderate thus eliminating any risk of cavitation and undue noise and
                   vibration.            Electrical

                   The objective of the electrical installation layout is efficient and easy operation
                   combined with optimum safety in a cost efficient way.

                   The power systems in Angola as well as in Namibia are expected to experience extensive
                   future development. The electrical installations have been planned with sufficient
                   flexibility to cope with unknown future conditions, particularly with respect to the
                   connection to Angola.

                   In the initial stage the connection to Angola may consist of a secondary feeder for local
                   distribution. To cater for future increased demand, the design also allows for addition of
                   a high capacity transmission link to the extended Angolan power system.

                   The Project will constitute one of the few large power plants in the area, therefore the
                   design includes redundancy such that essential components may be taken out of service
                   for maintenance without disturbing the operation of the rest the plant.

                   The different technical solutions have been selected among numerous alternatives which
                   have been evaluated against the general considerations as described above. In addition,
                   electrical installations are, as far as possible, concentrated to the underground power
                   house. This provides a safe and well protected installation which is easy to operate and
                   maintain. Similar layouts are used and have been proven efficient in numerous
                   underground power plants throughout the world.

                   The three generators will be 120 MW each with power factor of 0.85.

                   Three step up transformers (oil insulated water cooled OFWF type) are located in the
                   transformer hall, with the voltage at the high voltage side of 330 kV.

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                   An outdoor 330 kV switchyard is planned near the surface opening to the cable shaft.
                   There will be one bay for the 330 kV line to Etosha, a 40 MVA transformer bay
                   330/66 kV for regional supply and space for a future external connection to Angola.

6.5.3              Two Stations, 2 x 90 MW each

                   The two station concept is similar to the one station concept described above. The
                   general layout is shown in Figure 6.6. The major components that differ from the one
                   station development are as follows:

                       Two stations on opposite sides of the river with two 90 MW turbines each
                       A single intake tower, headrace tunnel, shaft and penstock for each plant
                       Different configuration of headrace shaft and penstock
                       The tailrace tunnels for each plant have a smaller cross section
                       The tailrace gates and surge chambers are smaller
                       The valves are housed in the power house cavern (no separate valve chamber)
                       Each powerhouse has two 90 MW turbines and generators
                       The powerhouse has a single crane capable of lifting the largest piece of equipment
                        as opposed to two cranes with connecting yoke
                       Each station will have 330 kV switchyards
                       A 330 kV line across the river will connect the 330 kV outdoor switchyards

6.6                ACCESS TO PROJECT

                   Permanent access to the site, for either one of the scheme solutions, is required from both
                   Angola and Namibia. A high quality road is required during the construction phase for
                   transport of construction materials and equipment. After construction, high quality
                   access is required for maintenance and potential equipment replacement.

                   A technical, economic and environmental analysis considering the cost of road
                   construction and upgrade, environmental and social impacts as well as the price and
                   transportation cost of construction material found that the most favourable supply port
                   and main access route for the project would be from Namibe, Angola. The roads on the
                   main access route are assumed to be constructed or upgraded to include bituminous

                   The route will follow the existing paved road from Namibe to Tombua for 75 km, from
                   there follow the track to Foz do Cunene to Tambor then along a south easterly track into
                   the Iona National Park at Pediva. At this point it will cross the Curoca River, continue
                   past Otchifengo up to a point approximately halfway between Moimba and Oncocua,
                   from which a new road will be required to reach the Baynes Site.

                   On the Namibian side, there is existing bituminous road from Walvis Bay to Kamanjab
                   via Ojiwarongo. Existing gravel and dirt roads in various conditions exist from
                   Kamanjab along Main Road 67 to Main Road 100 at Opuwo then along district Road
                   3700 via Okongwati to Epupa Landing Strip. For 17 km from the Epupa Landing Strip to
                   the construction site, an existing track will be followed, however major re-alignment will
                   be necessary since long sections of the existing track will become flooded when the
                   Baynes Dam is constructed. A new alignment is required which will increase the
                   distance to 21 km and require heavy to very heavy earthwork. These roads would be
                   constructed or upgraded to a reasonable gravel standard.

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                   The concept for the construction camp and operators village is to have a combination of
                   temporary and permanent accommodations. The main access route is through Angola,
                   therefore the construction camp and storage areas have been planned in Angola. There
                   will also need to be some construction facilities available on the Namibian side, which is
                   planned to be incorporated into the permanent operators village.

6.7.1              Construction Camp

                   The construction camp will consist of two components, a large temporary camp
                   constructed to house 900 people and a smaller permanent facility. The temporary portion
                   of the camp will be constructed under the maximum reservoir water level. A smaller
                   permanent facility, designed for 30 families will compliment the temporary facilities.

6.7.2              Operators Village

                   The main operators village for the one-station power plant will be on the Namibian side,
                   constructed to house 80 families. The two-station power plant will have permanent
                   operators villages of equal size on each side of the river.

6.8                POWER TRANSMISSION

                   A number of alternatives have been studied on how to arrange the power transmission
                   from the new power Project to the Namibian interconnected grid. All the alternatives are
                   investigated under some common assumptions as described below.

                   It is assumed that the power from the new plant would be transmitted to the major
                   330/220 kV substation of Omburu. This station is a major junction in the Namibian
                   power system where the 330 kV line coming from Ruacana hydro power plant in the
                   North connects to a 220 kV line running westwards to Walmund, a 220 kV line running
                   eastward to Otjikoto and two 220 kV lines running in parallel southwards to Windhoek.

                   Power transmission lines of 400 kV, 330 kV and 220 kV are potential options for power
                   transmission from the new Project. Using the same voltage as already introduced for the
                   transmission from Ruacana would involve several obvious advantages in terms of
                   standardisation of the installations, reduced stock-holding of spares, operational routines
                   etc., therefore 330 kV has been selected. It is suitable for handling the output from the
                   plant, and would require less investments as compared with a single circuit 400 kV line
                   or a double circuit 220 kV line. 330 kV is already in use for the transmission from
                   Ruacana and would thus facilitate to achieve redundancy by paralleling the two lines. In
                   the calculations the electrical characteristics of the new line are assumed to be the same
                   as those of the existing Ruacana line.

                   The calculations show that considerable reactive generation would be required in order to
                   maintain acceptable voltage conditions. To cater for this it is anticipated that a shunt
                   capacitor bank of 4x50 MVAr would be installed at the 220 kV busbar at Omburu. Part
                   of the capacity might instead be provided by a SVC installation in order to further
                   improve the system stability.

                   Shunt reactors are foreseen to be connected to each section of the new line in order to
                   compensate for its reactive generation and maintain the voltage within the acceptable
                   limits at varying load. The reactors at the power plants and at Omburu are foreseen to be
                   fixed to the line while the reactors at Etosha are anticipated to be connected via circuit-

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                   breakers. The size of each switched reactor has been selected such that the voltage
                   variation would remain within acceptable limits at switching.

6.8.1              Alternative A: Baynes-Ruacana

                   The Project would include a new 330 kV line section from the new power plant to
                   Ruacana. The length of the new section would measure some 171 km. From Ruacana the
                   existing 330 kV line will be used in common for transmission of power from the two
                   power plants to Omburu.

6.8.2              Alternative B: Baynes-Etosha

                   A new 330 kV transmission line would be installed from the new plant to the intersection
                   with the existing 330 kV line located 89 km from Ruacana power plant at a place referred
                   to as Etosha. The new line would have a length of approximately 264 km. A new 330 kV
                   switching station is foreseen to be installed at the intersection as part of the Project. The
                   existing 330 kV line would be used in common for the two power plants from Etosha to
                   Omburu, a distance of 433 km.

6.8.3              Alternative C: Baynes-Etosha-Omburu

                   The Project would include a new 330 kV transmission line to be installed all the way
                   from the new power plant to Omburu. The new line is foreseen to intersect with the
                   existing 330 kV line at Etosha. From here the two lines would run in parallel to Omburu.
                   A new 330 kV switching station would be installed at Etosha as part of the Project. The
                   line section Baynes-Etosha would be 264 km and the section Etosha-Omburu would be
                   433 km.

6.8.4              Alternative D: Baynes-Omburu

                   The new power plant will be connected directly to Omburu by a 330 kV transmission
                   line with a total length of about 691 km.

6.8.5              Selected Alternative

                   The ranking of the alternatives in respect of the evaluation criteria is summarised in the
                   table below. The table verifies the rather apparent general conclusion that a higher price
                   would result in better technical performance.

                   Ranking (1-4) in respect of Evaluation Criteria
                   Alternative                             A       B         C      D
                   Power Transfer Capability               4       3         2      1
                   Losses                                  4       3         1      2
                   Transient stability                     4       3         1      2
                   Reliability                             4       3         1      2

                   Investments (MUSD)                               34   50           96       83

                   For further comparison the alternatives may be referred to two groups. Alternatives A:
                   Baynes-Ruacana and B: Baynes-Etosha both anticipate that the existing 330 kV line
                   would be used in whole or partly for the transmission of the total combined output from
                   the two stations on the Cunene. From this follows that these two alternatives would ask
                   for substantially less investments. None of them would, however, be capable of

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                   transmitting the full output of the two stations in combination. It is deemed that this
                   limitation constitutes a technical and economic weakness which cannot be accepted at
                   least not in the long time perspective. In addition to this shortcoming alternatives A and
                   B also would entail other important weaknesses such as inferior stability and reliability
                   as well as higher losses. These two alternatives are thus ruled out.

                   The second group includes alternatives C: Baynes-Etosha-Omburu and D: Baynes-
                   Omburu. Both alternatives would be capable of transmitting the full output from the two
                   power plants on the Cunene. In addition the power transfer from the two hydro power
                   plants would not depend on one single transmission line. Alternatives C and D are
                   furthermore found to be superior in respect of system stability and losses. Against this
                   background it is deemed that one of this latter group should be selected.

                   Alternative C possesses one important quality which makes it superior to Alternative D.
                   The new line is anticipated to run in parallel with the existing Ruacana line between
                   Etosha and Omburu i.e. over a substantial part of its length. The distance over which
                   power from any one of the hydro plants would be transmitted by a single line is in this
                   case limited to the sections Ruacana-Etosha and Baynes-Etosha which account for
                   353 km in all. The corresponding distance for alternative D would be 1,213 km. The
                   difference indicates a significant advantage in respect of transmission redundancy which
                   is deemed to compensate for the rather small difference in cost.

                   Alternative C could be developed in two stages, if found appropriate at the time of
                   Project implementation. In the first stage the new station could be connected to Etosha at
                   about half the total cost. The line to Omburu might follow at a later stage when needed to
                   meet the demand. Phased implementation might furthermore be advantageous in case
                   power for the construction of the new power plant and the dam should be supplied from

                   In view of the above Alternative C: Baynes-Etosha-Omburu is selected as the most

                   The type and size of the line will be the same as the existing line from Ruacana to


                   Engineering planning and design of the project has been carried out in parallel with the
                   environmental assessment work. As far as possible during the planning process,
                   environmental findings have been integrated in the engineering considerations and
                   engineering facts have been channelled to the environmental planners for them to
                   properly identify the problems and opportunities being created by the project. Thus
                   environmental mitigation and environmental management, two similar but not
                   synonymous concepts, have been applied in continuous efforts of creating an
                   environmentally sound and technically and economically optimised project.

                   In the context of hydropower planning mitigation relates to the prevention or
                   minimisation of undesirable impacts whilst the management concept focus on using
                   environmental facts and linkages as decision variables in the formulation and operation
                   of the power scheme. Whereas the former concept can be described as reactive in nature
                   and the latter as proactive, the two are being applied interactively on the Baynes
                   Hydropower Scheme and this report pays little attention to their differences. The
                   important thing has been to inject environmental considerations in the engineering work
                   through environmental criteria, operational constraints and variables for the generation
                   simulations and sensitivity analyses. Feedback from engineers to environmentalists has

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                   also been vital to ensure that the environmental studies are underpinned by relevant
                   understanding of project features and that significant issues are focused upon.

6.9.1              Impact Mitigation Through Planning and Design

                   Tower Intake - The intake has been designed to accommodate selective withdrawal
                   from the reservoir in order to regulate downstream temperature and water quality. The
                   towers have been designed with three separate intake levels to allow withdrawal from
                   different levels and temperatures within the reservoir.

                   Spillway Design - The Baynes dam has a built in service spillway and an auxiliary
                   spillway located in a saddle on the south abutment. The service spillway is designed to
                   handle flows of up to 2,200 m3/s before the auxiliary spillway is operated. The
                   frequency of operation of the service spillway is anticipated to be once every 10 years,
                   the auxiliary spillway is anticipated to be used once every 100 years. The frequency of
                   operation for the auxiliary spillway precludes stagnant water in the spillway stilling
                   basins becoming sources for breeding of disease bearing insects.

                   Construction Camp - The temporary portion of the construction camp will be
                   constructed under the reservoir high water line to discourage settlement after the project
                   is completed and minimise the area above the reservoir impacted by the construction

6.9.2              Construction

                   Mitigation Plan - The Environmental mitigation plan sets out conditions for standards ,
                   methods, procedures plant requirements etc. which will be used during engineering
                   supervision to insure good environmental practices are carried out during the
                   construction process.

6.9.3              Operation

                   Minimum Flow Releases - A minimum environmental flow release has been established
                   at 20 m3/s. The reach between the dam and the power plant has a minimum release of
                   2 m3/s. The dam will be designed such that it can accommodate flows of either 2-
                   20 m3/s, depending on whether the power plant is releasing water or not.

                   Studies and Compensation - There will be continuing studies to better establish
                   environmental issues and compensations for effects to the bio-physical and human
                   environments during both construction and operation.

6.9.4              Costs of Environmental Measures and Restrictions

                   Costs or foregone revenues arising from environmental mitigation and management
                   discussed in this chapter are accounted for in four principally different manners. First
                   come the planning and design considerations which are directly reflected in the
                   engineering cost estimate. Second are the increased “General and Preliminaries” item and
                   unit rates in the contractor‟s tender to account for costs associated with the
                   environmental demands and restrictions of the EMP. The third item is of a forgone
                   revenue nature which stems from operational restrictions and are accounted for in the
                   simulations and economic analysis of the Project. The most important items are the
                   defined environmental mitigation and monitoring costs worked out by NAMANG‟s EA
                   team and included in Chapter 16 of the EA report.

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                   In addition to these costs which are borne by the project, there are external environmental
                   costs, partly quantifiable, partly non-quantifiable. These are not charged to the project,
                   however, those that are quantifiable are included as costs in the economic analysis, but
                   not in the financial analysis.

                   Costs Arising from Engineering Planning and Design

                   Major items of this nature are the selective withdrawal system, the compensation flow
                   release valves, access road routing and transmission line alignment. These
                   environmentally based construction costs are included in the engineering cost estimate
                   for the Baynes Project.

                   Increased Tender Rates

                   The EMP places a variety of restrictions on the contractor to control his approach,
                   methods, actions, use of site, pollution control, social responsibility etc. Specific
                   demands are placed on location and standard of contractors‟ camps, quarrying
                   operations, materials deposits, landscaping and other issues that can not easily be priced
                   individually. As these costs are not identifiable on an item for item basis at the planning
                   stage they have been included in the 25% allocation to the “General and Preliminaries”
                   item in the engineering cost estimate for civil works.

                   Costs of Operational Constraints

                   The costs of (or revenues forgone by) demanding compensation and minimum flows and
                   possibly requiring that floods be simulated or restrictions be imposed on rate of change
                   of turbine flows do not show up in any of the cost estimates, but they are accounted for
                   through the operational constraints. They can be calculated on the basis of energy
                   production and energy values at various points in time applying the assumptions used for
                   diurnal variations and future tariff rates in the economic analysis. However, the correct
                   cost picture can only be attained through complete simulations of the system for each
                   flow restriction scenario as discussed in Chapter 5. These simulations demonstrate there
                   is no simple means of valuing each one m3/s released at the Baynes Dam rather than
                   through its turbines; a simplistic water value calculation would be misleading as it is
                   unable to reflect alternative system supply options and temporal differences.

                   Mitigation and Monitoring Costs

                   A detailed account of all identifiable bio-physical and human environment mitigation and
                   monitoring costs, which add to costs discussed above, is found in Chapter 16 of the EA
                   report. The cost of the Social Mitigation Programme is included as 1.0% of project
                   construction cost excluding environmental mitigation. This figure is derived by
                   considering international experience of resettlement costs and comparing it to
                   NAMANG‟s assessment of costs associated with the originally conceived Social
                   Mitigation Programme which could not be completed.

                   The mitigation and monitoring costs have been classified in accordance with those
                   associated with the bio-physical environment and those that are attributable to the human
                   environment. The costs are related to 7 impact zones defined for the Project. Financial
                   costs are classified in four different types depending on their nature and disbursement
                   characteristics. Investment costs are either construction costs (suitable for inclusion in
                   tender document) or cost of studies (consultancies, research, support to government
                   agencies etc.). Compensation and other costs include compensation/replacement
                   expenses, annual costs limited to the 5 year period of construction and other outlays the
                   Project may have outside of the main engineering contracts. The fourth cost type is

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                                                           6 - 16

                   annual outlays for the life of the Project which typically constitute the cost of the
                   monitoring programme. A 20% contingency item is included to account for uncertainties
                   and omissions which are inherent in a cost estimate of this nature.

                   In summary the environmental mitigation costs identified for the Baynes Hydropower
                   Project alternative to be added to the engineering investment costs are:

                   Investment Costs
                          Bio-physical env.;              construction:             USD        855,000
                          Bio-physical env.;              studies:                  USD        710,000
                          Bio-physical env.;              compensation:             USD      1,080,000
                          Human env. ;                    construction              USD        820,000
                          Human env.;                     studies                   USD        185,000
                          Human env.;                     compensation              USD      5,509,000

                             Sub-Total Environmental Mitigation Investment Costs    USD     9,109,000
                             Contingency (20%)                                      USD     1,822,000
                             Total Environmental Mitigation Investment Costs        USD    10,931,000

                   The environmental monitoring costs associated with the Baynes Hydropower Project
                   alternative which should be added to the allocation for O&M expenses are:

                   Annual Recurrent Costs
                          Bio-physical env.;                                        USD        180,000
                          Human env.;                                               USD      1,102,000

                             Sub-Total Environmental Annual Recurrent Costs         USD      1,282,000
                             Contingency (20%)                                      USD        256,000
                             Total Environmental Annual Recurrent Costs             USD      1,538,000

                   Economic Costs

                   A fifth cost classification, external economic costs, is included in Chapter 15 of the EA
                   report. These costs do not result in cash outlays for the project and are excluded from
                   the financial cost estimate presented in this chapter. However, the economic costs
                   represent real resource use and are included in the economic analysis for the project.

                   Environmental Costing Principles Summarised

                   The total additional cost to the Baynes Hydropower Project stemming from
                   environmentally sound planning and operation, and from environmental management,
                   mitigation and monitoring is the sum of several cost items many of which are integrated
                   with technical aspects of the Project. Of the four cost groups discussed above only the
                   last group comprising mitigation and management costs is monetised here. Costs arising
                   from environmentally sound planning and design can only be identified by carrying out
                   an „environmentally insensitive‟ planning exercise and calculate differences. Increased
                   tender rates by contractor to meet EMP requirements will only be after tenders are
                   received and evaluated. Identification of costs inflicted on the Project as a result of
                   environmental operational restrictions require that the selected Project scenario be
                   simulated over the planning period with and without such operational restrictions.
                   Indications are given in the sensitivity analysis in Chapter 5.

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                   Such attempts of isolating environmental factors in the Project cost picture would be
                   incompatible with sound hydropower planning since they alienate environment as a
                   planning dimension. The sum of environmental costs to be assigned to the Baynes
                   Hydropower Project is thus not an interesting figure and should not be presented in a
                   planning context.

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                                                                 6 - 18

                               6.1 GENERAL ..................................................................................................... 1
                               6.2 SUMMARY OF MAIN CHARACTERISTICS ............................................ 1
                               6.3 THE EPUPA DAM ........................................................................................ 2
                               6.4 THE EPUPA RESERVOIR ........................................................................... 3
                               6.5 POWER PLANT ............................................................................................ 3
                               6.5.1 One Station, 3x120 MW ............................................................................. 3
                      Waterways ................................................................................................ 3
                      Civil .......................................................................................................... 4
                      Mechanical ............................................................................................... 4
                      Electrical .................................................................................................. 4
                               6.5.2 Two Stations, 2 x 90 MW each ................................................................... 4
                               6.6 ACCESS TO PROJECT ................................................................................ 5
                               6.7 CONSTRUCTION CAMP AND OPERATOR‟S VILLAGE ....................... 5
                               6.7.1 Construction Camp...................................................................................... 5
                               6.7.2 Operator‟s Village ....................................................................................... 6
                               6.8 POWER TRANSMISSION ........................................................................... 6
                               6.9 ENVIRONMENTAL MITIGATION ............................................................ 6
                               6.9.1 Impact Mitigation Through Planning and Design ....................................... 6
                               6.9.2 Construction ................................................................................................ 6
                               6.9.3 Operation ..................................................................................................... 6

d:\docstoc\working\pdf\f427197b-293f-43b7-8e3a-79a5b867858b.doc                                                                      2 December 2011

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