Angola Elect Master PlanMP 02
Angola Elect Master PlanMP 02
Angola Elect Master PlanMP 02
Final Report
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Existing SS
Planned SS
(Source: RNT)
Figure 7-1 Transmission system map of Angola (July 2017)
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Existing SS
Planned SS
(Source: RNT)
Figure 7-3 Transmission system map of Angola (2025)
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(Source: RNT)
Figure 7-4 Transmission system map of Angola (2027)
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Figure 7-5 66 kV concrete pole Figure 7-6 66 kV one circuit angle tower
Figure 7-7 60 kV underground cable branch tower Figure 7-8 60 kV steel pipe tower
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Figure 7-9 220 kV steel pipe tower (tension) Figure 7-10 220 kV steel pipe tower (suspension)
Figure 7-11 220 kV Transmission line along the road Figure 7-12 220 kV steel angle tower
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Table 7-2 and Table 7-3 list the 400 kV and 220 kV transmission lines of Angola, respectively. As
shown in the outline of the Angola power system of August 2016, the country’s 400 kV transmission
lines ran a total distance of 281 km on 2 lines and the country’s 24 kV transmission lines ran a
distance of 1964.1 km on 24 lines. As of October 2017, less than a year later, the 400 kV transmission
lines spanned 1183 km on 11 lines and the 220 kV transmission lines spanned 2597.4 km on 36 lines.
The quantity of transmission line facilities is rapidly increasing.
Table 7-2 List of 400 kV transmission lines (as of October 2017)
Area Start point
Name of Transmission line End point Voltage[kV] Circuit Length [Km] Type of Conductor
Capanda_elv - Lucala Capanda_elve Lucala 400 1 61 3 x ACSR Crow 409 mm²
Lucala – Viana Lucala Viana 400 1 220 3 x ACSR Crow 409 mm²
Cambutas - Catete Cambutas Catete 400 1 123 2 x AAAC Sorbus 659,4 mm²
Soyo TPS - Soyo Soyo TPS Soyo 400 2 40 3 x AAAC Sorbus 659,4 mm²
Soyo - N'Zeto Soyo N'Zeto 400 2 142 3 x AAAC Sorbus 659,4 mm²
North N'Zeto - Kapary N'Zeto Kapary 400 2 194 3 x AAAC Sorbus 659,4 mm²
Kapary - Catete Kapary Katete 400 2 57 3 x AAAC Sorbus 659,4 mm²
Catete - Viana Catete Viana 400 1 39 2 x AAAC Sorbus 659,4 mm²
Lauca - Capanda_elve Lauca Capanda_elve 400 1 41 2 x AAAC Sorbus 659,4 mm²
Lauca - Cambutas Lauca Cambutas 400 1 76 3 x AAAC Sorbus 659,4 mm²
Lauca - Catete Lauca Catete 400 1 190 2 x AAAC Sorbus 659,4 mm²
Total Length of 400kV Transmission lines [Km] 1183
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Figure 7-16 220 kV vertical Figure 7-17 Indoor type gas-insulated switchgear
type gas-insulated circuit
breaker
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(Source: RNT)
Figure 7-18 Example of a multiple bus configuration (220 kV Futungo substation)
Table 7-4 and Table 7-5 list Angola’s 400 kV and 220 kV substations, respectively. As shown in the
Angola Electric Power System Outline of August 2016, one 400 kV substation with a total generation
capacity of 420 MVA in one facility and fifteen 220 kV substations with a total capacity of 2129
MVA were in operation. As of October 2017, nine 400 kV substations with 4950 MVA capacity and
twenty-three 220 kV substations with 4086 MVA capacity were in operation. The quantity of
substation facilities is also rapidly increasing.
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7.6 Information gathering and analysis of the latest transmission development plan
7.6.1 Existing development strategies and plans
Based on Angola Energia 2025, the plan through 2027 is currently under consideration at RNT.
The skeletal system from the northernmost Soyo thermal power plant to Luanda and the
transmission line from the hydraulic power plant in the Kuwanza River basin to Luanda are already
being completed. A 400 kV core line to transmit this electricity to the central and southern regions is
planned for the future. Under the plans by SAPP, this line will eventually be connected to the
international linkage line with Namibia, the neighboring country to south of Angola. For this purpose,
electricity sales to the African electricity market and interchange during the drought period are
considered. Moreover, the 400 kV transmission line also plays a role as a power supply line for a
newly developed large-scale power plant.
The current plans for the 400 kV main transmission lines and substations are shown in Table 7-7
and Table 7-6.
The 220 kV lines now connect the northern system and central system, but they will take on a
growing role as a regional supply lines from the main 400 kV substation in each province. They also
serves as a power line for small-scale thermal power plants.
Similarly, the existing plans for the 220 kV transmission lines and substations are shown in Table 7-9
and Table 7-8.
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Table 7-6 Existing 400 kV main power transmission plans by RNT (~ 2027)
number Line Year
Project# Area Voltage Starting point End point of Length of Project Status Donar
(kV) circuit (km) operation
1 Central 400 Lauca Waco kungo 1 177 2020 Under Construction(Cmec) China
2 〃 400 Waco kungo Belem do Huambo 1 174 2020 〃 China
3 Northern 400 Catete Bita 1 54 2022 Project in progress(Odebrecht ) Brazil
4 〃 400 Cambutas Bita 1 167 2022 〃 Brazil
5 Central 400 Belem do Huambo Lubango 1 337 2022 Plannning(or No information) -
6 〃 400 Belem do Huambo Capelongo 1 202 2022 〃 -
7 Northern 400 Cambutas Caculo Cabaca 1 49 2023 〃 -
8 〃 400 Caculo Cabaca Bita 1 214 2023 〃 -
9 Central 400 Caculo Cabaca Nova Biopio 1 348 2025 〃 -
10 〃 400 Nova Biopio Lubango 1 317 2025 〃 -
11 Southern 400 Lubango Cahama 1 179 2025 〃 -
12 〃 400 Cahama Baynes 1 312 2025 〃 -
13 Eastern 400 Capanda_elev Xa-Muteba 2 266 2025 〃 -
14 〃 400 Xa-Muteba Surimo 2 335 2025 〃 -
15 Southern 400 Capelongo Ondjiva 1 312 2027 〃 -
16 〃 400 Cahama Ondjiva 1 175 2027 〃 -
Nova Biopio
17 〃 400 Caluquembe 2 5 2027 〃 -
- Lubango
Belem do Huambo
18 〃 400 Quilengues 2 5 2027 〃 -
- Lubango
19 〃 400 Cahama Ruacana 2 125 2027 〃 -
Total 3753
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Table 7-8 Existing 220 kV main power transmission line plans by RNT (~ 2027)
number Year
Project# Area Voltage Starting point End point of Line Length of Project Status Donar
(kV) circuit (km) operation
1 Northern 220 Kapary Caxito 1 18 2022 Plannning(or No information) -
2 〃 220 Filda Golf 2 7 2022 〃 -
3 〃 220 Bita Camama 1 17 2022 〃 -
4 〃 220 Bita Rammiros 1 23 2022 〃 -
5 〃 220 Capanda Marange 1 101 2022 〃 -
6 Central 220 Cambambe Gabela 1 134 2022 〃 -
7 〃 220 Gabela Alto Chingo 1 64 2022 〃 -
8 〃 220 Gabela Quibala 1 64 2022 〃 -
9 〃 220 Quibala Waco Kungo 1 68 2022 〃 -
10 〃 220 Lomaum Cubal 1 4 2022 〃 -
11 〃 220 Belem do Huambo Cubal 1 146 2022 〃 -
12 Southern 220 Lubango Namibe 2 151 2022 〃 -
13 〃 220 Namibe Tombwa 1 110 2022 〃 -
14 〃 220 Lubango Matala 1 154 2022 〃 -
15 〃 220 Matala HPS Matala 1 15 2022 〃 -
16 〃 220 Capelongo Cuchi 2 71 2022 〃 -
17 〃 220 Cuchi Menongue 2 77 2022 〃 -
18 Northern 220 Viana PIV 1 4 2027 〃 -
19 〃 220 Cazenga PIV 1 21 2027 〃 -
20 〃 220 Sambizanga Chicala 1 5 2027 〃 -
21 〃 220 Futungo de Belas Chicala 1 12 2027 〃 -
22 〃 220 Catete Maria Teresa 2 50 2027 〃 -
23 Central 220 Alto Chingo Cuacra 2 15 2027 〃 -
24 〃 220 Alto Chingo Port Amboim 2 50 2027 〃 -
25 〃 220 Quileva Catumbela 1 8 2027 〃 -
26 〃 220 Benguela Sul Catumbela 1 33 2027 〃 -
27 〃 220 Nova Biopio Bocoio 1 5 2027 〃 -
28 〃 220 Lomaum Bocoio 1 5 2027 〃 -
29 〃 220 Cubal Ukuma 1 5 2027 〃 -
30 〃 220 Belem do Huambo Ukuma 1 5 2027 〃 -
31 〃 220 Belem do Huambo Catchiungo 1 9 2027 〃 -
32 〃 220 Kuito Catchiungo 1 9 2027 〃 -
33 〃 220 Belem do Huambo Kuito 1 144 2027 〃 -
34 〃 220 Kuito Andulo 1 110 2027 〃 -
35 Southern 220 Cahama Xangongo 1 88 2027 〃 -
36 〃 220 Ondjiva Xangongo 1 90 2027 〃 -
37 〃 220 Capelongo Matala 1 158 2027 〃 -
38 〃 220 Matala Jamba Mina 2 83 2027 〃 -
39 〃 220 Jamba mina Jamba Oma 2 49 2027 〃 -
40 〃 220 Capelongo Tchamutete 2 93 2027 〃 -
41 Eastern 220 Saurimo Lucapa 1 157 2022 〃
42 〃 220 Lucapa Dundo 1 135 2022 〃
43 〃 220 Saurimo Luena 1 246 2027 〃 -
44 〃 220 Saurimo Muconda 1 169 2027 〃 -
45 〃 220 Muconda Luau 1 100 2027 〃 -
46 〃 220 Luau Cazombo 1 187 2027 〃 -
Total 3269
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For reference, the transmission system diagrams as of 2022 and 2027 obtained from RNT are shown
in Figure 7-19 to Figure 7-22.
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Figure 7-19 Existing plan for the northern system as of 2022 by RNT
Figure 7-20 Existing plan for the northern system as of 2027 by RNT
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Figure 7-21 Existing plan for the central, southern and western systems as of 2022 by RNT
Figure 7-22 Existing plan for the central, southern and western systems as of 2027 by RNT
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7.6.2 Analysis of the technical data and the latest cost in existing facilities
In order to confirm the design content of the existing facilities, we asked for technical information on
the transmission lines and substations by questionnaire, during interviews, etc. We were only able,
however, to obtain fragmentary technical standards and technical specifications on individual projects.
The information confirmed that the transmission line and substation designs were basically based on
IEC standards.
We examined details related to the transmission lines and substations from two packages of materials
obtained from RNT: “ESPECIFICAÇÕES TECHNICAS GERAIS Redes de Distribution Technical
specifications for AT, MT e BT (high voltage (60 kV - 35 kV), medium voltage (35 kV - 1 kV), low
voltage (less than 1 kV) distribution equipment ET - E - 001 to 008, 2014.10)" and "ESPECIFICA ES
TECHNICAS GERAIS Rede de Transporte MAT (General technical specifications for special
high-voltage (60 kV or higher) transmission system, ET-E-101 to 121, 2014.7)."
By examining the contents of "Projectos de Linhas aéreas de MAT" (project of special high-voltage
overhead transmission line: ET-E-110) and "Projects de Substitution de E de Postos de Seccionamento
de MAT" (project of special high-voltage substation or switch station: ET-E-119), we confirmed the
design methods and parameters used in the world standard 400 kV or 220 kV transmission lines and
substations, based on IEC standards, etc.
Regarding the cost of the transmission lines and substations in Angola, only one example of 220 kV
transmission line and substation construction work was available locally. For the cost estimation, we
therefore considered the recent international procurement prices in developing countries that have
installed transmission lines and substations based on IEC standards.
To estimate the cost per km of the 400 kV transmission line, we adopted a cost estimate used in a
Bangladesh country project based on the recent international procurement price. To estimate the cost
per km of the 220 kV transmission line we referred to the result in the Angola project.
As this cost estimate was for a two circuit transmission line, the cost per km of a one-circuit
transmission line was estimated to be 80% of that for a two-circuit line, from the past record. The
estimated cost per km for the transmission lines is shown in Table 7-10
Table 7-10 Estimated transmission line cost per km
Number of TL cost per km
Voltage
cct (Unit:MUSD/km)
1 0.78
400kV
2 0.98
1 0.36
220kV
2 0.45
(Source: JICA Survey Team)
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As for the cost of the substations, five cost estimates for 400 kV substation constructions were
available from recent cases (3 in Mozambique and 2 in Bangladesh). The cost of substations is known
to correlate with the transformer capacity. By knowing this correlation, we were able to linearize the
cost of the 400 kV substations by the least squares method and make estimations from the data.
90
80
70
60
50
MUS$
40
30
Actual cost
20
Estimate
10
0
0 500 1000 1500 2000 2500
Substation Capacity (MVA)
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Likewise, the two recent cost estimastes for 220 kV substations elsewhere (Angola 1 case,
Mozambique 1 case) allowed us to linearize the value by the least squares method and make an
estimate.
30
29
28 Actual substation cost
27
26
MUS$
25
24
23
22
21
20
100 150 200 250 300
Substation Capacity (MVA)
According to the above results, the cost per substation based on the transformer total capacity is as shown in
Table 7-11.
Table 7-11 Cost per substation based on the total transformer capacity
Cost per substation
based on total transformer
Voltage
capacity P
(Unit:MUSD/substation)
400kV 0 .0 2 4 xP(MVA) +2 9 .6 7
220kV 0 .0 5 4 xP(MVA) +1 1 .5 8
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Turning to the current status of the examination, information gathered from RNT reveals the
following contact points with SAPP (Southern Africa Power Pool) in the field. The concept for I is as
follows: the electric power produced by the large-scale development of the Inga hydropower station
in the Democratic Republic of Congo is transmitted through the power system of Angola, then onward
through the SAPP international interconnection line, and finally to South Africa.
The investigation has been suspended, however, because of political problems with the Democratic
Republic of Congo. When the investigation is resumed, the SAPP team currently examining the
feasibility study for interconnection with Namibia will to do the same for this interconnection plan.
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As for Ⅱ, there is no power transmission system that can be connected to the Congo side at present.
There are reports that electric power is being received by a private line from a small hydropower
station on the Congo side. A similar scheme will be conducted after the development of the Western
transmission line. Thus, we confirmed that international connection with Congo would not take place.
As for Ⅲ, there were once plans to sell electricity to the Copper Belt region, a mining development
zone in Zambia. Those plans are now abandoned.
As for Ⅳ , the purposes are to sell electricity to South Africa through the international
interconnection line passing through Namibia and to aim to ensure a stable supply of electricity by
receiving power in drought periods. The SAPP team is currently considering a feasibility study. The
concept study has been completed, and international linkage is judged to be possible. The final report
of the feasibility study is scheduled to be submitted in FY 2018, after financing. We believe that the
project will be started in 2025 after the environmental impact assessment procedure is completed.
The concept for the international interconnection line consists of establishing a new 400 kV
transmission line from the Cahama substation in Angola to the Ruakana substation in Namibia,
boosting the 330 kV transmission line between the Ruakana substation and Omburu substation in
Namibia to 400 kV, establishing a new 400 kV transmission line from the Omburu substation to the
Auasa substation in Namibia, the end point of the international interconnection line between South
Africa and Namibia, and connecting to the existing 400 kV international interconnection line.
Figure 7-26 shows the concept for the international interconnected transmission lines.
Since the international interconnection line from Angola to South Africa will be a long distance
transmission line of over 2,000 km, it will be necessary to carefully consider the system stability
problem. While the stability problem falls outside the direct scope of this survey, we want to call
attention to it. An interchange power of 400 MW is assumed. If the power development is carried out
smoothly in Angola, we believe that there will be no big influence on the electricity supply and
demand.
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The Angola side was apprised of this situation at the JCC meeting and workshop.
Moreover, in order to conduct international interconnection, it will be necessary to first establish a
plan to monitor and control the domestic power system. The maintenance of power frequency and
economic operations seems to be severely challenged in the current monitoring and control system in
Angola.
At the workshop, therefore, we urged the Angola side to understand the need for system monitoring
and control. In this report we also introduced the SCADA system to the central dispatching center, the
entity supervising and controlling the entire system, in order to enhance the grid monitoring control we
would like to propose.
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Peak Demand
Total Peak Demand
Forecasting for each
Forecasting
Province
220kV Substation
Power Development
planning
Planning
400kV Substation
Planning
Transmission Line
Planning
Power system
analysis
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Based on the anticipated demand for each province, the JICA Survey Team chose the location of the
demand center and decided the substation position, working in consultation with RNT. In areas
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small-scale demand will continue in the future, the substation capacity (originally set to less than 60
MVA) was standardized to 120 MVA or 240 MVA according to the demand scale. For heavy load
areas in Luanda area, 480 MVA or 720 MVA was adopted.
In Table 7-12, the red indicates the existing substation and its capacity, and the blue indicates the
new substation and its capacity and the capacity of the substation after expansion. The year of new
establishment and year of enhancement are stated in the remarks column.
The same applies to Table 7-13 to Table 7-15.
Table 7-13 220 kV Substation plan based on the demand forecast for the central region
Area Provincia Capital Year 2020 2025 2030 2035 2040
Forecasted Demand (MW) 101 174 263 369 494
> 220kV Gnenrator (MW)
Neccesary Capacity (MVA) 113 193 292 410 549 Remarks
Existing Capacity(MVA) 240 240 480 480 480 (Operation Year)
Insufficient capacity (MVA) - -47 -188 -70 69
Total Planned Capacity(MVA) 240 480 480 480 600
Cuanza Sul Sumbe Subastation Name Substation Capacity(MVA)
Alto Chingo 120 120 120 120 120 exsitng
Gabela 120 120 120 120 180 exsitng upgrade 2037
Waco Kungo 60 60 60 60 2022
Quibala 60 60 60 120 2022
Porto Amboim 120 120 120 120 2025
Cuacra 60 60 60 60 2025
Forecasted Demand (MW) 300 415 563 734 882
> 220kV Gnenrator (MW)
Neccesary Capacity (MVA) 333 462 625 815 980
Remarks
Existing Capacity(MVA) 550 550 910 1150 1270
(Operation Year)
Insufficient capacity (MVA) - -88 -285 -335 -290
Total Planned Capacity(MVA) 550 910 1150 1270 1390
Subastation Name Substation Capacity(MVA)
Benguela Benguela
Quileva 310 310 310 310 310 exsitng
Benguela Sul 240 240 240 240 240 2018
Catumbela 120 120 240 240 2025 upgrade2035
Cubal 120 120 120 240 2022 upgrade2038
Centeral Alto Catumbela 120 120 120 2030
Baria Farta 120 120 120 2030
Bocoio 120 120 120 120 2025
Forecasted Demand (MW) 132 205 318 454 614
> 220kV Gnenrator (MW)
Neccesary Capacity (MVA) 147 228 354 505 682
Remarks
Existing Capacity(MVA) 240 240 420 540 540
(Operation Year)
Insufficient capacity (MVA) - -12 -66 -35 142
Huambo Huambo Total Planned Capacity(MVA) 240 420 540 540 780
Subastation Name Substation Capacity(MVA)
Belém do Dango 240 240 240 240 480 exsitng upgrade2036
Ukuma 60 60 60 60 2025
Catchiungo 120 120 120 120 2025
Bailundo 120 120 120 2030
Forecasted Demand (MW) 41 82 131 208 323
> 220kV Gnenrator (MW)
Neccesary Capacity (MVA) 46 91 145 231 359
Remarks
Existing Capacity(MVA) 120 120 180 300 360
(Operation Year)
Insufficient capacity (MVA) - -29 -35 -69 -1
Bié Kuito
Total Planned Capacity(MVA) 120 180 300 360 480
Subastation Name Substation Capacity(MVA)
Kuito 120 120 240 240 360 exsitng upgrade2027 2037
Andulo 60 60 60 60 2025
Camacupa 60 60 2035
Subtotal 1150 1990 2470 2650 3250
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Table 7-14 220 kV Substation plan based on the demand forecast for the southern region
Area Provincia Capital Year 2020 2025 2030 2035 2040
Forecasted Demand (MW) 121 201 311 443 602
> 220kV Gnenrator (MW) 121
Neccesary Capacity (MVA) 0 224 345 493 668 Remarks
Existing Capacity(MVA) 0 0 780 840 840 (Operation Year)
Insufficient capacity (MVA) - 224 -435 -347 -172
Total Planned Capacity(MVA) 0 780 840 840 900
Subastation Name Substation Capacity(MVA)
Huíla Lubango Lubango 240 240 240 240 2022
Nova Lubango 120 120 120 120 2025
Matala 120 120 120 120 2022
Caluquembe 60 60 60 120 2025 upgrade2040
Quilengues 60 60 60 60 2025
Tchamutete 120 120 120 120 2025
Capelongo 60 60 60 60 2022
Chipindo 60 60 60 2030
Forecasted Demand (MW) 39 83 137 200 273
> 220kV Gnenrator (MW) 39
Neccesary Capacity (MVA) 0 92 152 223 304 Remarks
Existing Capacity(MVA) 0 0 240 240 360 (Operation Year)
Cunene Ondjiva Insufficient capacity (MVA) - 92 -88 -17 -56
Total Planned Capacity(MVA) 0 240 240 360 360
Subastation Name Substation Capacity(MVA)
Ondjiva 120 120 240 240 2025 upgrade2032
Southern
Cahama 60 60 60 60 2025
Xangongo 60 60 60 60 2025
Forecasted Demand (MW) 42 86 141 204 275
Planned Gnenrator (MW) 42
Neccesary Capacity (MVA) 0 96 157 227 306
Remarks
Existing Capacity(MVA) 0 0 300 300 360
(Operation Year)
Insufficient capacity (MVA) - 96 -143 -73 -54
Cuando-Cubango Menongue Total Planned Capacity(MVA) 0 300 300 360 420
Subastation Name Substation Capacity(MVA)
Cuchi 60 60 60 60 2022
Menangue 240 240 240 240 2022
Cuito Cuanavale 60 60 2035
Mavinga 60 2040
Forecasted Demand (MW) 65 129 169 212 259
Planned Gnenrator (MW) 65
Neccesary Capacity (MVA) 0 143 188 236 287
Remarks
Existing Capacity(MVA) 0 0 360 360 360
(Operation Year)
Namibe Namibe Insufficient capacity (MVA) - 143 -172 -124 -73
Total Planned Capacity(MVA) 0 360 360 360 360
Table 7-15 220 kV Substation plan based on the demand forecast for the western region
Are a Provin c ia Capital Ye ar 2020 2025 2030 2035 2040
Forecasted Demand (MW) 28 75 109 157 224
Planned Gnenrator (MW) 28
Neccesary Capacity (MVA) 0 84 122 175 249 Re marks
Existing Capacity(MVA) 0 0 240 360 360 (Ope ration Ye ar)
Insufficient capacity (MVA) - 84 -118 -185 -111
Moxico Luena
Total Planned Capacity(MVA) 0 240 360 360 360
Subastation Name Substation Capacity(MVA)
Luena 240 240 240 240 2025
Cazombo 60 60 60 2027
Luau 60 60 60 2027
Forecasted Demand (MW) 38 97 144 198 260
Planned Gnenrator (MW) 38
Neccesary Capacity (MVA) 0 107 160 221 289
Remarks
Existing Capacity(MVA) 0 0 300 300 300
(Operation Year)
Insufficient capacity (MVA) - 107 -140 -79 -11
Easte rn Lunda Norte Lucapa
Total Planned Capacity(MVA) 0 300 300 300 420
Subastation Name Substation Capacity(MVA)
Lucapa 60 60 60 60 2022
Dundo 120 120 120 240 2022 upgrade2036
Xa-Muteba 120 120 120 120 2025
Forecasted Demand (MW) 26 77 92 135 181
Planned Gnenrator (MW) 26
Neccesary Capacity (MVA) 0 86 103 149 201
Remarks
Existing Capacity(MVA) 0 0 120 180 300
(Operation Year)
Lunda Sur Saurimo Insufficient capacity (MVA) - 86 -17 -31 -99
Total Planned Capacity(MVA) 0 120 180 300 300
Subastation Name Substation Capacity(MVA)
Saurimo 120 120 240 240 2022 upgrade2032
Muconda 60 60 60 2027
Subtotal 0 660 840 960 1080
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7.7.3 220 kV power transmission line plan based on the regional supply substation
plan
Based on the result of 7.7.2, the connections between the regional supply substations and main
system in the existing plan are decided based on the geographical positions and the starting year of
operation. Table 7-17 shows the power transmission line plan compiled based on the result of the
power flow analysis.
With regard to the connecting transmission line, a two-line connection was basically adopted in
consideration of the N-1 reliability criteria.
Also, a loop circuit formed with a 220 kV system could cause unexpected overloads at the time of
an accident. Power transmission lines with one circuit connection were removed to reduce the
complexity of the system and make the system as easy to operate as possible.
Regarding the substations located nearby the existing transmission line, we decided to divide the
power transmission line into 4 lines π.
Finally, we formed an appropriate power transmission equipment plan by considering these factors
and working through a process of repeated trials and errors.
Projects stricken out by red line lines in Table 7-16 are deleted to avoiding the aforementioned loop
circuit.
Projects stated in blue are new substation facility plans derived from the demand forecast up to the
2040 fiscal year. All have been added to the existing plans.
The revised number of lines and operation starting years in the existing plan are written in blue.
According to the review of the plan based on the substation supply plan, the length of the
transmission line work increased by about 500 km, from 3,269 km to 3,766 km.
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Table 7-16 Review of the Transmission Line plan accompanying the regional supply substation plan
number Year
Line Length
Project# Area Voltage Starting point End point of of Remarks
(kV) circuit (km) operation
1 Northern 220 Filda Golfe 2 7 2022
2 Northern 220 Bita Camama 2 21 2022
Northern 220 Bita Rammiros 1 2022 Avoiding Loop circuit
3 Northern 220 Catete Zango 2 40 2022
4 Northern 220 Capanda elev. Maranje 2 110 2022
5 Northern 220 Kapary Caxito 2 26 2025
6 Northern 220 N'Zeto Tomboco 2 5 2025 Substation inserted
7 Northern 220 M'banza Congo Tomboco 2 5 2025 Substation inserted
8 Northern 220 Sambizanga Chicala 2 7 2025
Northern 220 Futungo de Belas Chicala 1 2025 Avoiding Loop circuit
9 Northern 220 Catete Maria Teresa 2 51 2025
10 Northern 220 Viana PIV 2 7 2035
Northern 220 Cazenga PIV 1 2035 Avoiding Loop circuit
11 Northern 220 Uige Negage 2 5 2030 Substation inserted
12 Northern 220 Pambos de Sonhe Negage 2 5 2030 Substation inserted
13 Northern 220 Negage Sanza Pombo 2 109 2035
Central 220 Cambambe Gabela 1 2022 Avoiding Loop circuit
14 Central 220 Gabela Alto Chingo 1 81 2022 Dualization
Central 220 Gabela Quibala 1 2022 Avoiding Loop circuit
15 Central 220 Quibala Waco Kungo 2 92 2022
16 Central 220 Lomaum Cubal 2 2 2022
Central 220 Belem do Dango Cubal 1 2022 Avoiding Loop circuit
17 Central 220 Alto Chingo Cuacra 2 25 2025
18 Central 220 Alto Chingo Port Amboim 2 60 2025
19 Central 220 Quileva Nova Biopio 1 18 2025 Dualization
20 Central 220 Quileva Catumbela 2 8 2025
21 Central 220 Nova Biopio Bocoio 2 5 2025 Substation inserted
22 Central 220 Lomaum Bocoio 2 5 2025 Substation inserted
Central 220 Cubal Ukuma 1 2025 Avoiding Loop circuit
23 Central 220 Belem do Huambo Ukuma 2 66 2025
24 Central 220 Belem do Huambo Catchiungo 2 9 2025 Substation inserted
25 Central 220 Kuito Catchiungo 2 9 2025 Substation inserted
Central 220 Belem do Dango Kuito 1 2027 Avoiding Loop circuit
26 Central 220 Kuito Andulo 2 124 2025
27 Central 220 Cubal Alto Catumbela 2 47 2030
28 Central 220 Benguela Sul Catumbela 2 26 2025
29 Central 220 Catchiungo Bailundo 2 66 2030
30 Central 220 Benguela Sul Baia Farta 2 30 2030
31 Central 220 Kuito Chitembo 2 145 2035
32 Southern 220 Lubango2 Lubango 2 30 2020
33 Southern 220 Lubango2 Namibe 2 162 2020
34 Southern 220 Namibe Tombwa 2 97 2020
35 Southern 220 Lubango2 Matala 2 168 2022
36 Southern 220 Matala HPS Matala 1 5 2022
37 Southern 220 Capelongo Cuchi 2 91 2022
38 Southern 220 Cuchi Menongue 2 94 2022
39 Southern 220 Cahama Xangongo 2 97 2025
40 Southern 220 Ondjiva Xangongo 1 97 2025
Southern 220 Capelongo Matala 1 2027 Avoiding Loop circuit
41 Southern 220 Matala Jamba Mina 1 86 2035
42 Southern 220 Jamba mina Jamba Oma 1 37 2035
43 Southern 220 Capelongo Tchamutete 2 98 2025
44 Southern 220 Menongue Cuito Cuanavale 2 189 2035
45 Southern 220 Cuito Cuanavale mavinga 2 176 2035
46 Eastern 220 Saurimo Lucapa 2 157 2020
47 Eastern 220 Lucapa Dundo 2 135 2020
48 Eastern 220 Saurimo Luena 2 265 2025
49 Eastern 220 Saurimo Muconda 2 187 2027
50 Eastern 220 Muconda Luau 2 115 2027
51 Eastern 220 Luau Cazombo 2 264 2027
Total 3,766
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Table 7-17 Result of Transmission Line connection based on the power generation plan
Hydropower Plant (River) Area Installed 2017 2018 2020 2025 2030 2035 2040 Transmission Line
<Existing PP (Available Capacity)> - - 1,699 1699 1649 1649 1594 1594 1594 1594 Connected Distance
Voltage
<Development Plan> 931.5 1928 2169 4341 4851 6701 7154 Substation (km)
HPP Lauca Kwanza North 2,070 931.5 1863 2070 2070 2070 2070 2070 400kV Cambutas 224
HPP Caculo Cabaça Kwanza North 2,172 2172 2172 2172 2172 400kV Cambutas 54
HPP Zenzo Kwanza North 950 950 950 400kV Cambutas 41
HPP Túmulo Caçador Kwanza North 453 453 220kV Cambutas 16
HPP Quissonde Kwanza North 121 220kV - -
HPP Genga ② Quive North 900 900 900 400kV Benga Switch-yard 30
HPP Benga Quive North 1,000 400kV - -
HPP Quilengue ⑤ Quive North 210 210 210 210 220kV Gabera 37
HPP Lomaum Extension Catumbela Central 215 65 65 65 65 65 65 220kV Nova_Biopio 81
HPP Lomaum2 Catumbela Central 150 220kV - -
HPP Baynes (50% Angola) Cunene South 300 300 300 300 400kV Cahama 195
HPP Jamba Ya Oma Cunene South 79 220kV HPP Jamba Ya Mina 37
HPP Jamba Ya Mina Cunene South 205 220kV Matala 86
HPP Luachimo (extention) East 34 34 34 34 34 34 60kV Dundo 5
Candidate Total = 7,154 2631 3577 3818 5935 6445 8295 8748
Transmission Line
Thermal Power Plant
Type Area (MW) 2017 2018 2020 2025 2030 2035 2040 Connected Distance
<Development Plan> Voltage
Substation (km)
TPP Soyo 1 CCGT Zaire 750 250 750 750 750 750 750 750 400kV Soyo_SS 5
TPP Soyo 2 CCGT Zaire 750 750 750 750 750 400kV Soyo_SS 5
TPP Lobito CCGT No.1 CCGT Benguela 750 375 750 750 750 400kV Nova_Biopio_SS 23
TPP Lobito CCGT No.2 CCGT Benguela 750 750 750 400kV Nova_Biopio_SS 23
TPP Namibe CCGT No.3 CCGT Namibe 750 750 220kV Namibe_SS 17
TPP Lobito CCGT No.4 CCGT Benguela 375 375 400kV Nova_Biopio_SS 23
TPP Cacuaco GT No.1 GT Luanda 375 125 250 375 375 220kV Cacuaco 5
TPP Cacuaco GT No.2 GT Luanda 375 125 125 250 375 220kV Cacuaco 5
TPP Boavista GT No.3 GT Luanda 375 125 125 250 375 220kV Sambizanga 5
TPP Quileva GT No.4 GT Benguela 250 125 250 250 220kV Quileva 1
TPP Quileva GT No.5 GT Benguela 250 125 250 250 220kV Quileva 1
TPP Quileva GT No.6 GT Benguela 250 125 250 250 220kV Quileva 1
TPP Soyo GT No.7 GT Zaire 375 125 250 375 400kV Soyo_SS 5
Candidate Total = 6,375 250 750 750 2,250 3,250 4,875 6,375
The following pages show schematic figures of each transmission line connecting to the power
station.
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7.7.5 400 kV main Transmission Line and Substation Plan based on electric power
system analysis
Based on the existing power grid development plan for RNT and subsequent studies, we determined
the load from the demand assumption for each region, determined the capacity of the regional supply
substation, and analyzed the data using the power system analysis program (PSSE), the de facto world
standard.
A review of the 400 kV transmission and transformation plan described in 7.6.1 based on the results
is shown in Table 7-18 and Table 7-19.
With respect to the 400 kV substation plan, based on the demand assumption of 2040, we plan to
establish four (4) new substations and review the capacities and operation years of the planned
substations. The required incremental capacities of existing substations were also added.
The total capacity of the new substation is 12,720 MVA, that is, about 5,500 MVA more than the
7,290 MVA capacity of the existing plan up to 2027. In 2040, the rapid increase in the scale of the
system will bring the capacity up to 21,840 MVA. The main factor will be the approximately 2,000
MVA increase in the existing substation to meet increased demand from the capital Luanda, about
5,000 MVA (mainly Viana substation). It will be necessary to strengthen the local system by about
2,000 MVA.
Table 7-18 400 kV main Substation plan based on electric power system analysis
Year Final
Upgrade
Project# Area Voltage Substation Capacity of Capacity
(kV) Name (MVA) operation 2025 2030 2035 2040 (MVA)
1 Cuanza Sul 400 Waco kungo 450 2020 450 900
2 Huambo 400 Belem do Huambo 1,350 2020 1,350
3 Luanda 400 Bita 900 2022 450 450 1,800
4 Huila 400 Lubango 900 2025 900
5 Huila 400 Capelongo 900 2025 900
6 Huila 400 Caluquembe 120 2025 120
7 Benguera 400 Nova Biopio 900 2025 900
8 Southern 400 Cahama 900 2025 900
9 Eastern 400 Saurimo 900 2025 900
10 Lunda Norte 400 Xa-Muteba 360 2025 360
11 Cunene 400 Ondjiva 900 2035 900
12 Huila 400 Quilengues 120 2025 120
13 Cuanza Sul 400 Gabela 900 2025 900
14 Luanda 400 Sambizanga 1,860 2025 1,860
15 Malanje 400 Lucala 900 2025 450 1,350
16 Chipindo 400 Chipindo 360 2025 360
17 Zaire 400 N'Zeto 450 existing 450 900
18 Luanda 400 Viana 210 existing 2,790 930 3,720
19 Bengo 400 Kapary 450 existing 450 450 1,350
20 Luanda 400 Catete 900 existing 450 1,350
New Substation capacity Total 12,720 Sub Total 4,590 1,830 900 0 21,840
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As for the 400 kV transmission lines, we will satisfy the N-1 reliability criteria by dualizing the
transmission lines connecting to important large-scale hydropower stations and adding a new
construction of 6 transmission lines. We reexamined several single circuit transmission lines
connecting to the large-scale hydropower station to be changed to double circuit. Also, in response to
the addition of four (4) substations to the plan, we re-examined the plan with a total of (10) related
transmission lines. We also decided to construct two (2) lines for connection of the Caculo Cabaca
hydropower station and to transmit to the Catete substation via the Lauca substation.
Table 7-19 400 kV main Transmission Line plan based on electric power system analysis
number Line Year
Project# Area Voltage Starting point End point of Length of Remarks
(kV) circuit (km) operation
1 Northern 400 Catete Bita 2 54 2022
Northern 400 Cambutas Bita 1 2022
2 Northern 400 Cambutas Caculo Cabaca 2 54 2023 Dualization
3 Northern 400 Caculo Cabaca Bita 1 2023
4 Northern 400 Cambutas Catete 1 123 2025 Dualization
5 Northern 400 Catete Viana 1 36 2025 Dualization
6 Northern 400 Lauca Capanda elev. 1 41 2025 Dualization
7 Northern 400 Kapary Sambizanga 2 45 2025 For New Substation
8 Northern 400 Lauca Catete 2 190 2025 Changing Connection Plan
9 Northern 400 Lauca Caculo Cabaca 2 25 2025 Changing Connection Plan
10 Central 400 Lauca Waco kungo 1 177 2020
11 Central 400 Waco kungo Belem do Huambo 1 174 2020
Central 400 Belem do Dango Lubango 1 2022
Central 400 Belem do Dango Capelongo 1 202 2022
12 Central 400 Lauca Waco kungo 1 177 2025 Dualization
13 Central 400 Waco kungo Belem do Huambo 1 174 2025 Dualization
Central 400 Caculo Cabaca Nova Biopio 1 2025
14 Central 400 Cambutas Gabela 2 131 2025 For New Substation
15 Central 400 Gabela Benga 2 25 2025 For New Substation
16 Central 400 Benga Nova Biopio 2 200 2025 For New Substation
Central 400 Nova Biopio Lubango 1 2025
17 Central 400 Benga Genga 2 30 2035
18 Southern 400 Belem do Huambo Caluquembe 2 175 2025 For New Substation
19 Southern 400 Caluquembe Lubango2 2 168 2025 For New Substation
20 Southern 400 Belem do Huambo Chipindo 2 114 2025 For New Substation
21 Southern 400 Chipindo Capelongo 2 109 2025 For New Substation
22 Southern 400 Nova Biopio Quilengues 2 117 2025 For New Substation
23 Southern 400 Quilengues Lubango2 2 143 2025 For New Substation
24 Southern 400 Lubango2 Cahama 2 190 2025
25 Southern 400 Capelongo Ondjiva 1 312 2035
26 Southern 400 Cahama Ondjiva 1 175 2035
Southern 400 Biopio - Lubango kaluquembe 2 5 2027
Southern 400 Dango - Lubango Quilengues 2 5 2027
27 Southern 400 Cahama Ruacana 2 125 2027 International Interconnection
28 Southern 400 Cahama Baynes 2 195 2030
29 Eastern 400 Capanda_elev Xa-Muteba 2 266 2025
30 Eastern 400 Xa-Muteba Surimo 2 335 2025
Total 4,292
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Currently, electric power is supplied to the center of Luanda mainly from the 400/220 kV
substations(Viana, Kapary, Catete) using 220 kV T/L. In addition, this system is a loop system of
400/220 kV, with many small DGs connected in the loop.
In 2040, the demand for this area will be more than 4,000MW, which is about four times the
current level demand, so it is planned to establish 400/220 kV substation (Bita, Sambizanga) and
others several 220/60 kV substations.
In the future, we propose to abolish the DG in order, and introduce CCGT into the 220 kV power
system and make the system configuration simple by making it a radial system.
Figure 7-35 Main power system of the center of Luanda in 2017(400 kV, 220 kV)
According to the plan of RNT, Golfe substation (the new 220/60 kV substation) is planned to be
connected to the 400/220 kV Viana substation. In this plan, the load will be concentrated on the Viana
substation.
Figure 7-36 Main power system of the center of Luanda in 2040(RNT’s draft)
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The connection between the Golfe substation to the Sambizanga substation results in a balanced
system structure as shown in the figure below.
The distance between the Golfe substation and the Sambizanga substation is about 5 km, but
because it is a densely populated residential area, it is considered difficult to construct an overhead
power transmission line.
However, according to the RNT, in the future there is also a land readjustment plan in this area,
in which case, there is a possibility that it is possible to construction of overhead transmission lines.
Moreover, construction is possible if it is an underground transmission line.
Therefore, JICA survey team adopted this plan as a master plan.
Figure 7-37 Main power system of the center of Luanda in 2040(JICA’s draft)
Even in 2040, in the state of two lines, there is no problem in both voltage and load flow, but if it
becomes one line, the voltage sensitivity of the bus becomes extremely high as shown in the following
table, and It may be verry difficult to operate this network.
Therefore, the three-line configuration is a measure for securing the situation of two lines even in
the situation of N-1 (one line stop).
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As a representative measure against high voltage sensitivity, installation of SVC (Static Var
Compensator) is conceivable.
The following figure shows the situation when the Capanda = Xa - Mutenba T/L and the Mutenba
= Saurimo T/L each become one line in the case where the SVC is installed at the 400 kV bus of the
Saurimo substation.
Even if it becomes one circuit line(N-1 contingency), there is no problem situation, indicating
that installation of SVC is effective.
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Figure 7-39 Eastern bulk power system calculation result in 2040(Mutenba = Saurimo T/L :
N-1)
The following table shows the cost comparison of Statcom type SVC installation and one line
enhancement of a 400 kV transmission line (making this Capanda = Xa - Mutenba = Saurimo T/L 3
circuit lines).
Just to be sure, even if two units of SVC are installed as troubleshooting measures, since the cost
of installing SVC is significantly lower, JICA survey team proposes a SVC installation plan.
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1440
M’Banza Congo Angola power system –
Soyo
(220/60) (MW)
(400/60/15)
2040
Nzeto
(400/220/60) Tomboco Maquela Zombo
(220/60) (220/60/30/15)
1110
(220/60)
220kV T/L
Cacuaco
Sambizanga Negage
(220/60)
(400/220/60) (220/60) 220kV
Chicala PIV
(220/60)
Cazenga
(220/60) 380 Pambos de Sonhe(220/30)
outage T/L
(220/60)
420
Lucala (400/220/60)
Futungo de Belas
(220/60)
Golfe Filda
220/60 (220/60) Viana
(400/220/60)
Catete (400/220/60) Capanda Dundo
(400/220/110) Malange
1150 Maria N’Dalatando (220/60) 1030 Lucapa
Teresa(220/60) Xá-Muteba
Camama
(220/60)
860
Zango 270 550 Saurimo
740 (220/60)
Zenzo
60 1520
Muconda
470 Gabela
(400/220/60)
Quibala 600
P. Amboim (220/60)
(220/60)
70
840
Alto Chingo Waco Kungo
Cuacra
(220/60) (400/220/60)
(220/60)
Genga
Nova Biopio 480 Bailundo
(220/60)
Andulo
(220/60)
Lobito CCGT
(400/220)
540
Quileva Kuito
(220/150/60) Bocoio Belém do Huambo
(220/60)
Catumbela (220/60) Ukuma (400/220/60)
(220/60) CH Alto (220/60)
Lomaum Catumbela Catchiungo Chitembo
Baia Farta (220/60)
(220/60) Benguela Sul 840Cubal (220/60)
220
(220/30)
(220/60) CH Gove
Quilengues (220/60) Chipindo
(400/60)
Lubango
Caluquembe 600 (400/60)
(400/60) CH
Namibe
(400/220/60) Jamba OMA e MINA
(400/220/60)
Capelongo
Matala (400/220) Cuito Cuanavale
Tômbwa
430 170 (220/60) (220/30)
(220/60) Cahama Matala(CH) Cuchi Menongue
(400/220/30) (220/30) (220/60)
Mavinga
Tchamutete
(220/30)
(220/60)
430
Baynes 50
220
(400)
400 Xangongo Ondjiva
to SAPP (220/60) (400/220/60)
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Camama
190 Teresa(220/60) Xá-Muteba
(220/60)
260 360 620
Zango 850 Muconda
(220/60) Zenzo Saurimo
100 1170
610 330
Ramiros 190 Luau
(220/60)
520 30 460 Lauca
Luena
Bita (400/220/60) 780 (400)
130 Cambutas
(400/220/60) Caculo Cabaça Cazombo
Gabela 560
280 (400/220/ Quibala 440
60)
P. Amboim (220/60)
(220/60)
100
Benga 40
Alto 710 Waco Kungo
Cuacra
Chingo (400/220/60)
(220/60) (220/60)
Genga
Bailundo Andulo
Nova Biopio
430 (220/60)
Lobito CCGT
(400/220) 410 (220/60)
Quileva
(220/150/60)
520 Kuito
Bocoio
Catumbela (220/60) Ukuma
200 Belém do Huambo
(400/220/60)
(220/60)
Figure 7-41 RNT’s power system plan in 2040(400 kV, 220 kV)
(Source: JICA Survey Team)
Table 7-22 shows the results of a comparison of the transmission loss between the drafts of the JICA
Survey Team and RNT. There is no difference in the substation demand condition between the two
plans in the comparison. The power plant outputs (Soyo power plant included) are basically the same.
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Sambizanga
Cacuaco
(220/60) 220kV T/L
(400/220/60)
Chicala
(220/60) 350 Pambos de Sonhe(220/30) 220kV T/L
Cazenga
(220/60)
420 (planed ; ~2025)
Lucala (400/220/60)
Futungo de Belas 220kV
(220/60) Filda
Golfe
220/60
(220/60) Viana outage T/L
(400/220/60)
Capanda Dundo
Catete (400/220/60)
(400/220/110)
Malange
480 Maria N’Dalatando (220/60) 560 Lucapa
Teresa(220/60) Xá-Muteba
Camama
(220/60)
610
Zango 230 120 Saurimo Muconda
480 (220/60) 50 360
Ramiros 370 820
(220/60) 650 150 Lauca
Luena
Bita (400/220/60) (400)
Cambutas
320 (400/220/60)
Caculo Cabaça (400)
290 Gabela
(400/220/60)
Quibala 290
P. Amboim (220/60)
(220/60)
10
130
Alto Chingo Waco Kungo
Cuacra
(220/60) (400/220/60)
(220/60)
Baynes
(400)
Xangongo Ondjiva
(220/60) (220/60)
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Nzeto
(400/220/60) Tomboco
(220/60)
Maquela Zombo
(220/60/30/15)
400kV T/L
790
400kV T/L
Kapary
ADA (400/220/60) Caxito
(220/110)
(planed ; 2026~30)
Uíge
800 (220/60)
220kV T/L
Cacuaco
Sambizanga Negage
(220/60)
(400/220/60) (220/60) 220kV T/L
Chicala
(220/60) 450 Pambos de Sonhe(220/30)
(planed ; 2026~30)
Cazenga
(220/60)
490
Lucala (400/220/60) 220kV
Futungo de Belas
(220/60) Golfe
Filda outage T/L
220/60 (220/60) Viana
(400/220/60)
Capanda Dundo
Catete (400/220/60) (400/220/110)
Malange
620 Maria N’Dalatando (220/60) 740 Lucapa
Teresa(220/60) Xá-Muteba
Camama
(220/60)
780
Zango 200 210 Saurimo Muconda
590 (220/60) 80 710
Ramiros 460 1030
(220/60) 1030 470 Lauca
Luena
Luau
320 Gabela
(400/220/60)
Quibala 610
P. Amboim (220/60)
(220/60)
20
90
Alto Chingo Waco Kungo
Cuacra
(220/60) (400/220/60)
(220/60)
Baynes
(400) 400 Xangongo Ondjiva
to SAPP (220/60) (220/60)
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Nzeto
(400/220/60) Tomboco
(220/60)
Maquela Zombo 400kV T/L
(220/60/30/15)
720
400kV T/L
Kapary Damba
Sambizanga
Cacuaco 220kV T/L
Negage
(220/60)
(400/220/60) (220/60) 220kV T/L
Chicala
(220/60)
PIV
(220/60) 850 Pambos de Sonhe(220/30)
(planed ; 2031~35)
Cazenga
(220/60)
530
Lucala (400/220/60) 220kV
Futungo de Belas
(220/60)
Filda
(220/60)
outage T/L
Viana
(400/220/60)
Golfe Capanda Dundo
Catete (400/220/60) (400/220/110)
220/60
870 Malange
Maria N’Dalatando (220/60) 980 Lucapa
Teresa(220/60) Xá-Muteba
Camama
(220/60)
950
Zango 250 Zenzo 370 Saurimo Muconda
660 (220/60) 50 1190
Ramiros 410 1560
(220/60) 750 1050 Lauca
Luena
Luau
120 Gabela
(400/220/60)
Quibala 640
P. Amboim (220/60)
(220/60)
40
420
Alto Chingo Waco Kungo
Cuacra
(220/60) (400/220/60)
(220/60)
Genga
Nova Biopio 580 Bailundo
(220/60)
Andulo
(220/60)
Lobito CCGT
(400/220)
130
Quileva Kuito
(220/150/60) Bocoio Belém do Huambo
(220/60)
Catumbela (220/60) Ukuma (400/220/60)
(220/60) CH Alto (220/60)
Lomaum Catumbela Catchiungo Chitembo
Baia Farta (220/60)
(220/60) Benguela Sul 780Cubal (220/60)
240
(220/30)
(220/60) CH Gove
Quilengues (220/60) Chipindo
(400/60) Caluquembe 240 (400/60)
(400/60) CH
Namibe
Lubango Jamba OMA e MINA
(400/220/60)
(400/220/60)
Capelongo
Matala (400/220) Cuito Cuanavale
Tômbwa
240 200 (220/60) (220/30)
(220/60) Cahama Matala(CH) Cuchi Menongue
(400/220/30) (220/30) (220/60)
Tchamutete
(220/60)
260
30
Baynes
(400) 100
400to SAPP Xangongo
(220/60)
Ondjiva
(400/220/60)
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1440
M’Banza Congo Angola power system –
Soyo
(220/60) (MW)
(400/60/15)
2040
Nzeto
(400/220/60) Tomboco
(220/60)
Maquela Zombo 400kV T/L
(220/60/30/15)
1120
Kapary Damba
Caxito (220/30) Sanza Pombo
ADA (400/220/60)
(220/110) (220/60)
Uíge
1110
(220/60)
220kV T/L
Cacuaco
Sambizanga
(400/220/60)
(220/60)
Negage
(220/60)
220kV T/L
Chicala PIV (planed ; 2036~40)
(220/60)
Cazenga
(220/60) 380 Pambos de Sonhe(220/30)
(220/60)
420 220kV
Lucala (400/220/60)
Futungo de Belas
(220/60)
Golfe Filda
outage T/L
220/60 (220/60) Viana
(400/220/60)
Catete (400/220/60) Capanda Dundo
(400/220/110)
Malange
1150 Maria N’Dalatando (220/60) 1030 Lucapa
Teresa(220/60) Xá-Muteba
Camama
(220/60)
860
Zango 270 550 Saurimo
740 (220/60)
Zenzo
60 1520
Muconda
470 Gabela
(400/220/60)
Quibala 600
P. Amboim (220/60)
(220/60)
70
840
Alto Chingo Waco Kungo
Cuacra
(220/60) (400/220/60)
(220/60)
Genga
Nova Biopio 480 Bailundo
(220/60)
Andulo
(220/60)
Lobito CCGT
(400/220)
540
Quileva
Kuito
(220/150/60) Bocoio Belém do Huambo
(220/60)
Catumbela (220/60) Ukuma (400/220/60)
(220/60) CH Alto (220/60)
Lomaum Catumbela Catchiungo Chitembo
Baia Farta (220/60)
(220/60) Benguela Sul 840Cubal (220/60)
220
(220/30)
(220/60) CH Gove
Quilengues (220/60) Chipindo
(400/60)
Lubango
Caluquembe 600 (400/60)
(400/60) CH
Namibe
(400/220/60) Jamba OMA e MINA
(400/220/60)
Capelongo
Matala (400/220) Cuito Cuanavale
Tômbwa
430 170 (220/60) (220/30)
(220/60) Cahama Matala(CH) Cuchi Menongue
(400/220/30) (220/30) (220/60)
Mavinga
Tchamutete
(220/30)
(220/60)
430
Baynes 50
220
(400)
400 Xangongo Ondjiva
to SAPP (220/60) (400/220/60)
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First, the JICA Survey Team reviews the ‘Doing Business 2017’ Report to learn about the business
environment of Angola.
The World Bank (WB) publishes a ‘Doing Business’ report on the ease of doing business based on
indicator sets every year. The latest ’Doing Business 2017’ report evaluates data such as the days
necessary to complete the application process and the required fees. Out of 190 countries covered in a
country ranking, Angola ranks 182nd (versus rankings of 25th for Portugal, 74th for South Africa, 137th
for Mozambique, and 169 for Nigeria).
Item by item, Angola ranks 181st in ‘Getting Credit,’ 183rd in ‘Trading across Borders,’ 186th in
‘Enforcing Contracts,’ and 169th in ‘Resolving Insolvency.’ The rankings are based on the distance to
the frontier score for each topic: i.e., the best country on the frontier is scored 100 and the other
countries are scored from 0 to 100 according to their absolute distances to the frontier.
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The JICA Survey Team understands that the problems of Angola concentrate around these low-scored
items. The World Bank issued the following explanations in this regard.
Credit information systems are not widely used. → Collateral laws or Bankrupcys law are not
enacted. Borrower financial credit histories are not shared. Financial statements are not used
effectively in providing credit.
Contracts are not widely enforced. → no commercial dispute resolution system is established.
Liquidation or insolvency systems are not well established. → Angola has not experienced any
liquidation or insolvency.
This section identifies bottlenecks in the private investment environment and summarizes plans to
develop a private electric power project.
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The report describes problems in Angola’s private investment environment broken down into three
factors: the ‘institutional factor,’ ‘economical factor,’ and ‘other factors.’ The problems are summarized in
the table below.
The JICA Survey Team reviewed the ‘Private Sector Country Profile: Angola in 2012,’ the first
comprehensive business guidebook on Angola. The profile began with the geographical conditions of the
country and then moved onto the recent political conditions, economic conditions, and finally the
conditions of the investment environment. In 2015, the African Development Bank published its
Portuguese edition. Unlike the ‘Doing Business Report’ from the World Bank, the contents of the
Portuguese edition have not been updated.
The report describes problems in Angola’s private investment environment organized into three factors:
the ‘institutional factor,’ ‘economical factor,’ and ‘other factors.’ The problems are summarized in the table
below.
The legal system in Angola is principally based on Portuguese law. Laws, Decrees, and Acts
restated to private investment, meanwhile, are being enacted apart from basic laws such as the Civil
Law, Labor Law, etc.
The National Bank of Angola (BNA) has a statutory authority to adopt the accounting standards for
financial institutions. Especially banks that meet at least one of the criteria in 2015 must adopt IFRS.
Other banks also must adopt IFRS issued by IASB but may do so voluntarily from 2016. Many
companies other than financial institutions mentioned above do not adopt IFRS. They are said to
prepare the financial statements in conformity with the Angolan Accounting Law and the General
Accounting Plan (PGC) that was adopted by the Presidential Decree as of 2001.
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In this section the JICA Survey Team extracts the laws and regulations it considers important for private
investment in Angola, out of those described in the report on the business environment. Note, however,
that no laws intended for specific sectors other than the power sector are selected. The new Private
Investment Law (newPIL), a law that will be important for private investment, will be reviewed in a later
section.
Commercial Societes Law Law 01/04 Feb. 2004 defines types of fims
In October 2017, the JICA Survey Team interviewed three Japanese companies doing business in
Angola: Sumitomo Corporation (Sumitomo Syoji), Marubeni, and Toyota de Angola, S.A (Toyota Tusho).
Sumitomo Corporation and Marubeni operate Representative Offices in the country, and Toyota de Angola,
S.A. is a Joint Stock Company. Sumitomo Corporation is said to have concluded a Minutes of
Understanding (MOU) with the Government of Angola for the construction of Japan-made diesel power
plants, but the details of the plan are not known.
Issues
① What hardships are they going through in doing business in Angola?
② What bottlenecks are there in Angola’s legal system?
③ Is the New Private Investment Law (new PIL) of help in developing new projects?
④ Other
(results)
① Hardships in doing business
・The low oil price binds the foreign reserves of Angola. Private companies are therefore unable to freely remit money
outside of Angola. (Nacional Banco of Angola conducts a bid every week and only companies awarded bids are entitled to
remit money.)
・ The laws are drafted in Portuguese, the official language, which makes them hard to read and understand.
② Legal bottlenecks
・New Presidential Decrees are being enacted. Actual business follows not the basic laws but the Decrees.
・Interpretation of law varies.
③ Request and opinions on the newPIL
・Laws are enacted, but direct negotiations will prevail.
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④ Other
・The monetary market in Angola is weak and provides no good financial products
・Chinese companies doing business in Angola are said to settle their services not by cash but barter for oil. They are
therefore immune to the influences of the strict regulations on bank remittance.
The New Private Investment Law, a law expected to have strong influence on private investment and
project formation in Angola, was approved on August 11, 2015. It was entered into force on the same day
that the former private investment law was repealed (Law No.20/11 of May 20, 2011).
A new agency called APITEX (Angolan Investment and Export Promotion Agency) was also formed to
promote investments and exports.
The newPIL no longer includes minimum thresholds for investments. But to qualify for tax
benefits and incentives, a foreign investor must invest at least $1 million and a domestic investor
must invest at least $500,000.
Decisions regarding private investments are in principle taken by the ministers responsible for the
main sectors in which the investments are made, or by the Angolan executive (i.e., the President).
The New Private Investment Law restricts indirect investment.
An investor can be granted certain tax benefits and incentives, albeit no longer automatically.
In the electricity and water sectors, the Angolan party should retain an interest of at least 35% in a
joint venture.
An investor can repatriate dividends, profits, and royalties. Any portion of a repatriated amount
exceeding the funds of the company is subject to an additional tax.
8.4.2 Private power project in accordance with the New Private Investment Law
In order to qualify for tax benefits and incentives, a foreign investor must invest at least $1
million and a domestic investor must invest at least $500,000. Negotiations are held directly with
the Minister of Energie and Aqua (MINEA) or the Angolan executive (i.e., the President).
Any tax incentives are decided and applied through negotiation.
A foreign investor forms a joint venture with Angolan individuals or an Angolan company. The
Angolan party retains an interest of at least 35% in the joint venture.
After paying additional taxes, a foreign investor is eligible to repatriate dividends, profits, and
royalties.
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At present, the private investment environment in Angola is still underdeveloped. While every country
and company recognizes the big potential of Angola, they are still reluctant to go ahead.
A power project by a private sector differs from an ODA project, in general, as no guarantees from the
government are obtained. The private sector must therefore bear all of the risks such as the fluctuating
prices of fuel and materials, foreign exchange, interest rates, etc. by itself.
Finally, the following are requested when private electric power projects are formed in Angola.
Every party member observes and acts in accordance with the contract.
The political system in Angola is stable and assets will not be nationalized.
A reasonable long-term PPA (Power Purchase Agreement) is concluded. Tariffs are set to
adequately secure a certain profit level over the long term.
Profits earned are allocated in accordance with equity or the contract.
A foreign investor is free to remit profit and dividends outside of Angola irrespective of the
economy of Angola. (※)
Funds from the monetary market of Angola are preferred: reasonable interest rates (not so
high) and longer repayment periods.
※The auction system to settle payments for foreign countries re-started in 2018, with which the winner
of the auction is entitled to receive foreign currencies for remittance. However this system seems to
work only for a winner so that it does not meet requests from all import companies in Angola.
Factors apart from the private investment issues tend to affect candidate projects. As a
consequence, there seems to be little incentive to develop private investments overall. The
Government needs to promote the observance of contracts and high transparency in
appraising and approving projects.
The lack of actual private investment projects to date leaves Angola with little experience in
completing specific PPA agreements. As a result, negotiations and approvals may take
longer.
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The progress of power development in Angola is mainly driven by PRODEL, RNT, and ENDE in an
environment where private companies lack strong inclination to develop power projects by themselves.
Under these circumstances, PRODEL will become a major implementing agency for generation, while
ENDE will become the main implementing agency for transmission and distribution.
The JICA Survey Team reviews the financial statements for PRODEL, RNT, and ENDE. Given the
apparent difficulty these companies would have in investing more with their own profits, they are likely to
request funds from outside.
First, the JICA Survey Team reviews whether it will be able to raise funds by issuing a bond or taking
out a loan in a monetary market of Angola. As for the recent market condition, the official website of
Banco Nacional de Angola (BNA) as of October 26, 2017 indicates a loan condition in terms of AOA,
with an interest rate of 20.04% and repayment period of 1-3 years. The average interest rates for Treasury
Bills with maturities of 91, 182, and 364 days, meanwhile, have been 16.12% (91 days), 23.19% (182
days), and 23.94% (364 days). In 2015 Angola raised $1.5 billion by selling its first Eurobond, offering a
yield of 9.5% with a maturity of 10 years. Considering this information, conditions for a non-sovereign
bond would be more difficult.
Note: Fitch assigned the bond a “highly speculative” rating of B+ in line with Angola’s sovereign
ratings at the time. Angola was rated Ba2 by Moody’s and B+ by Standard & Poor’s and Fitch.
The issue of stock in Angola is improbable, as no stock market exists in the country. Actual fundraising
must therefore depend on international monetary intermediaries such as the World Bank (WB), African
Development Bank (AfDB), and Japan International Corporation Agency (JICA).
According to the definition of the Development of Co-operation Directorate (DAC), an ODA loan is a
loan that includes a grant element of more than 25%. A loan with a greater grant element is advantageous
to the borrower or borrowing country. International donor organizations such as the World Bank, AfDB,
and JICA are eligible to extend such ODA loans.
Note: The grant element reflects the concessionary nature (i.e., softness) of a loan. The ratio of the
grant element rises as the interest rate falls and the repayment period lengthens.
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The World Bank (WB), European Bank for Reconstruction and Development (EBRD), and African
Development Bank (AfDB) are all international financial institutions that provide ODA loans. Among
them, however, the AfDB would be more familiar to Angola, a country located in the Sub-Saharan
Region. The JICA Study Team visited the official website of AfDB to review the conditions of a
Sovereign Guaranteed Loan (SGL) from the bank.
According to the official website of AfDB on March 12, 2018, the 6MLIBOR (Fixed Spread Loan
in USD), including the lending spread, was set at 1.85%, and the front-end fee was 25bp.
Japan International Corporation Agency (JICA) provides ODA loans, including Yen loans,
under the frameworks of bilateral corporation between Japan and recipient countries. The JICA
Study Team visited the official website of JICA on March 12, 2018 to review the loan conditions
for Yen loans. According to the website, Angola is classified as an LDC country. The following
conditions are applied to LDC countries.
AfDB can only extend an SGL loan to a regional member country (RMC).
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A guarantee from the Government of Angola is needed when AfDB provides a loan to a
project in Angola.
A certain procedure is required to conclude a JICA Yen Loan. First, the Government of
Angola must send an official request for an ODA loan. Next, the Government of Japan
appraises the candidate project. Next, the Government of Japan exchanges an E/N with the
Government of Angola and finally concludes the L/A. It will actually take at least 2-3 years
to conclude the L/A.
A guarantee from the Government of Angola is needed when JICA provides a loan to a
project in Angola.
In a case where the implementing agency does not expect the ODA loan or may not receive the
ODA loan, it may request Export Credit from Export Credit Agencies (ECA) in foreign countries as
an alternative option. When Angola plans to import plants from Japanese manufacturing companies, it
requests export credit from the Japan Bank for International Corporation (JBIC), the ECA of Japan.
The provision of Export Credit needs a guarantee from the Government. An ECA loan is faster than
an ordinary ODA loan when the implementation agency successfully obtains the Government’s
guarantee and commercial banks forming a syndicate with JBIC are ready to provide co-financing.
Moreover all OECD member countries, including Japan, are to provide the Export Credit in
accordance with ‘the Arrangement on Officially Supported Export Credits.’ Consequently, the
condition of Export Credit provided by each OECD member country shall be the same.
Meanwhile, historically Angola has been receiving loans or ECAs from the Chinese Export-Import
Bank. As a country outside of the OECD, China can provide loans with different loan conditions.
When the JICA Study Team visited the official website of the China Export-Import Bank to find the
specific loan conditions, no specific loan conditions with figures were disclosed.
Here is the ECA condition JBIC provides as of March 12, 2018, based on information from the
official website of JBIC. Commercial Interest Reference Rates (CIRR) is as follows.
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The table below summarizes typical loan conditions for ① an AfDB Loan (AfDB), ② Yen
Loan (JICA), ③ commercial loan in Angola, ④ ECA. Each of the foregoing types has its
own procedures, appraisal system, and conditions. While it is difficult at this juncture to
determine which of the above types is best, a loan with a longer repayment period and
lower interest would impose a lighter financial burden.
Note also that the funds are provided with a sub-loan instead of an original loan the implementation
agency may lose the merit of the latter.
c u rre n c y: JPY
in te re st rate : 1 .0 %
matu rity: 3 0 ye ars ( grac e pe riod: 1 0 ye ar)
2 Yen Loan (JICA) ODA prin c ipal: e qu all in stallme n ts
oth e rs: -
c u rre n c y: AoA
in te re st rate : 2 0 % (e stimate d)
commercial matu rity: 3 ye ars
3 Commercial Loan
loan prin c ipal: -
oth e rs: -
The JICA Study Team reviewed the long-term power development plan as of March, 2018. The
development plan has two parts: the power development plan to meet the demand forecast and the
development plan for the transmission lines and sub-stations.
The table below shows the unit prices necessary to construct power plants, transmission lines, and
sub-stations. (The unit prices for hydro and thermal power plants are shown in section 6.3.)
The power development plan up to Year 2040 consists of hydropower projects, thermal power
projects (CCGT and GT), transmission line projects (220 kV and 400 kV), and sub-station projects
(220 kV and 400 kV). Meanwhile, construction of the renewable energy (wind and solar) facilities
will be left to other developers, and power will be purchased from them.
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Following are investment plans by the commissioning year. The total investment comes to 31,548
million USD: hydropower (19,083 million USD), thermal power (6,413 million USD), renewable
energy (0 million USD), transmission lines (4,417 million USD) and sub-stations (1,636 million
USD).
Table 9-3 Long-term Investment Plan up to 2040 (commissioning Year )
(unit: mil. $)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Hydro 0 0 5,589 34 0 0 0 0 5,864 810 0 567 0 0
TPP 300 0 0 0 1,050 531 0 531 81 0 81 450 81 163
Renewable 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Transmission 208 0 2 279 0 878 556 2 1,614 0 785 0 0 18
Sub-station 0 25 0 225 0 444 51 0 196 0 426 0 0 18
total 508 25 5,591 539 1,050 1,854 607 533 7,756 810 1,293 1,017 82 199
(unit: mil. $)
2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 t o t al
Hydro 0 2,565 0 0 2,430 0 0 1,223 0 0 19,083
TPP 450 163 325 450 163 450 244 450 0 450 6,413
Renewable 0 0 0 0 0 0 0 0 0 0 0
Transmission 34 0 0 8 6 0 6 0 18 2 4,417
Sub-station 129 0 0 0 103 0 0 0 18 0 1,636
total 613 2,728 325 458 2,701 450 250 1,673 36 452 31,548
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Figure 9-1 Annual Investment up to 2040 (in terms of the Construction Schedule)
The following describes the JICA Study Team’s review of the scale of the long-term investment
plan. As PRODEL is responsible for generation and RNT is responsible for transmission and
sub-stations, the review estimates the size of the investment amounts compared to the sales and net
profit levels of PRODEL and RNT in 2016.
Table 9-4 Long-term Investment and 2016 Sales and Net Profit levels of PRODEL and RNT
total investment amount up to Financial Statement (2016)(b) (a)/(b)
2040
investment for generation: PRODEL
sales: 1,025 mil. $ 25,6
26,262 mil. $ (=220,420.7 mil. AOA)
The total investment in hydro and thermal power is 24.9 times the sales of PRODEL in 2016, or
2,944 times the net profit of PRODEL in the same year. The total investment in transmission and
sub-stations is 14.9 times the sales of RNT in 2016, or 298.1 times the net profit of RNT in the same
year. The investment amounts are so big, neither PRODEL nor RNT seems capable of obtaining the
necessary funds with its current retained earnings. Thus, the new investment must be funded through
borrowings from financial institutions.
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The agency implementing the new project will not need all of the funds in the commissioning year.
Rather, it will require the funds year by year in accordance with the construction schedule. A
standardized construction schedule for each facility is shown below.
Table 9-5 Standardized Annual Construction Schedule during the Construction Period.
-8 -7 -6 -5 -4 -3 -2 -1
Hydro (Large) 5% 10% 15% 20% 20% 15% 10% 5%
TPP 1 (CC) 25% 30% 30% 15%
TPP 2 (Gas) 15% 25% 20% 15% 25%
Renewable (wind) no construction but purchase power 25% 35% 40%
Renewable (solar) 30% 35% 35%
Transmission (220kV) 5% 40% 45% 10%
Transmission (400kV) 5% 40% 45% 10%
Sub-station (220kV) 5% 40% 45% 10%
Sub-station (400kV) 5% 40% 45% 10%
The total investment amount over the construction schedule is 26,023 million USD, consisting of
14,867 million USD for hydropower projects, 6,113 million USD for thermal power projects, 0
million USD for renewable energy projects, 3,339 million USD for transmission projects, and 1,705
million USD for sub-station projects.
Table 9-6 Long-term Investment Amount up to 2040 (in terms of the Construction Schedule)
The following study assumes that the necessary funds will be borrowed in accordance with the
annual construction schedule. Depreciation and O&M expenses are incurred after the
commissioning year. The interest and principal payments take place in accordance with the
repayment schedule.
In other countries, the agency implementing a project generally becomes both the borrower
and repayer of the loan. This means that the implementing agency is responsible for repaying
the loan. In Angola, however, GAMEK seems to responsible for construction with a loan
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obtained from an outside party. The newly constructed facility is to be handed over to
PRODEL, RNT, or ENDE after commissioning, and the Government of Angola is
responsible for repaying the loan. In this case, we cannot clearly discern who will borrow the
loan and who will pay it off afterwards.
It does not appear that PRODEL, RNT, and ENDE will be directly responsible for repaying
the loan. This study assumes, however, that the implementing agency will be both the
borrower and the repayer. It also assumes that all financial costs related from the borrowings,
along with depreciation and O&M costs, will be debited in the financial statements of
PRODEL and RNT.
Considering the current financial conditions of PRODEL and RNT, they are very unlikely to
be able to develop new projects with their own retained earnings. Thus, all projects are
assumed to be developed through borrowings.
The following three loans will be available for projects of Angola: (1) a Yen loan extended
by JICA, (2) an ODA loan extended by African Development Bank (AfDB), (3) Export
Credit extended by JBIC. Over the past few years, ODA agencies have tended to provide
ODA loans to hydropower projects, transmission projects, and sub-station projects that have
slim prospects for high profitability. Conversely, the agencies are unlikely to provide ODA
loans to thermal power projects that have strong prospects for commercial profitability and
are expected to be developed as IPP projects.
The study therefore assumes that the hydropower projects and transmission and sub-station
projects will be developed with ODA loans, while the thermal power projects will be
developed with ECAs.
The Yen loan extended by JICA and the ODA loan extended by AfDB are assumed to have
upper ceilings of 85% of the total borrowing. This means that the implementing agency must
fill the remaining 15% by itself while requesting to borrow 85% of the total investment.
Likewise, the Export Credit is also assumed to be capped by a ceiling of 85% of the total
investment.
The study also considers the Interest During Construction (IDC) as part of the total asset
after the commissioning year.
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maturity grace
type interest rate currency front end fee reference
year year
Yen Loan 1 1.00% JPY 30 10 0.20% up to 85%
AfDB/(WB) loan 2 1.855% USD 20 5 0.25% up to 85%
(AfDB FSL USD)
JBIC ECA USD 3 3.78% USD 10 0 12.88%
The total loan amount up to 2040 is 22,120 million USD. The interest, front-end fee, and repayment
of principal respectively come to 2,963 million USD, 674 million USD, and 3,936 million USD.
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New facilities are commissioned on the 1st of January of the commissioning year.
Construction of transmission lines to be connected to newly constructed power plant will be
completed one year in advance of the commissioning year of the power plant.
Annual depreciation is calculated by the straight-line method. The residual value is zero.
The O&M expense for a power plant, a transmission line, and a sub-station is to be
calculated based on a certain percentage of the newly constructed asset. The O&M expense
for a thermal power plant consists of the O&M expense and cost of fuel consumed at the
power plant. The O&M expense for renewable power (wind power and solar power) includes
no cost for plant construction, as construction is left to other parties. PRODEL is assumed to
purchase power from other parties with a pre-determined power tariff.
Interest during construction (IDC) is counted as a part of an asset after commissioning.
Depreciation and the O&M expense are based on the abovementioned asset.
Table 9-9 Details on Depreciation and IDC
project O&M cost IDC (%) construction
period (%) /100mil.$ period (years)
Hydro (Large) 40 1 4.6 8
TPP 1 (CC) 25 3 10.41 4
TPP 2 (Gas) 20 5 11.51 5
Renewable (wind) 20 - - 3
Renewable (solar) 20 - - 3
Transmission (220kV) 40 2 2.42 4
Transmission (400kV) 40 2 2.42 4
Sub-station (220kV) 40 2 2.42 4
Sub-station (400kV) 40 2 2.42 4
The JICA Survey Team hereby calculates a long-run marginal cost (LRMC) in accordance with the
‘Internal Rate of Return (IRR) Manual for Yen Loan Projects’ (JBIC). LRMC is calculated as follows.
Long Run Marginal Cost (LRMC)= total project cost × capital recovery factor + O&M expences
capital recovery factor= r / (1-(1+r) ) -n
r:10%
n:durable years (hydropower, 40 years; thermal power, 25 years (CCGT) and
20 years (GT))
O&M expense = O&M expense + fuel cost (thermal)
O&M expense: calculated for a certain percent of the total construction cost
Fuel cost: annual fuel cost for thermal power plants
(2) The Total Investment Cost and LRMC for Generation, Transmission, and Sub-station
The total Investment Cost and unit cost per kWh shown below indicate the LRMC of the long-term
investment plan. The unit cost may vary, but generally stays near 5-6 cents per kWh.
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Figure 9-3 Total Annual Cost and Unit Cost for Generation
annual construction cost and unit cost for transmission lines and sub-stations are shown below.
Unlike the thermal power plants, the transmission lines and sub-stations have fixed costs (e.g.
construction and O&M costs) but no variable costs (e.g., fuel costs). The annual construction cost and
unit cost for transmission lines and sub-stations are as follows. The unit cost peaks (1.5 cents/kWh) in
2027 and then falls to 0.8 cents/kWh in ensuing years.
Figure 9-4 Total Annual Cost and Unit Cost for Transmission and Sub-station
From here we review how much the incremental cost will rise based on the investment and O&M
cost up to 2040, as well as the repayment schedule. (*)The cost consists of the construction cost,
O&M cost, and depreciation. Thermal power plants bear fuel costs, as well. The payment of the
interest, principal, and IDC will be considered after borrowings.
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*: Actual construction cost for each year may fluctuate, depending on the construction
schedule and repayment schedules. For this study, however, we adjust the annual cost for
each candidate project to an equal level by applying the capital recovery factor.
The results are as follows. The unit price for generation will reach 8.5 cents USD at maximum,
while the unit price for transmission and substation will reach 2 cents USD.
Table 9-10 Annual Unit Incremental Cost for Generation (hydro and thermal)
($ /kwh)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
incremental cost /kWh 0.002 0.003 0.003 0.006 0.006 0.013 0.016 0.015 0.019 0.018 0.022 0.021 0.020 0.019
($ /kwh)
type 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 t o t al
incremental cost /kWh 0.018 0.018 0.017 0.016 0.015 0.014 0.014 0.013 0.013 0.012 -
Table 9-11 Annual Unit Incremental Cost for Transmission and Sub-station
($ /kWh)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
incremental cost $/kWh 0.002 0.003 0.003 0.006 0.006 0.013 0.016 0.015 0.019 0.018 0.022 0.021 0.020 0.019
($ /kWh)
type 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 t o t al
incremental cost /kWh 0.018 0.018 0.017 0.016 0.015 0.014 0.014 0.013 0.013 0.012 -
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Figure 9-6 Annual Unit Incremental Cost for Transmission and Sub-station
From here we review the current unit revenue prices for PRODEL and RNT to cover the
incremental cost as well as the existing cost.
The unit cost for PRODEL in 2016 is 19.86 AOA/kWh, which equals 0.09 $/kWh. The unit cost for
RNT in 2016 is 8.15 AOA/kWh, which equals 0.037 $ /kWh.
A guest attending the workshop in 2018 pointed out that PRODEL did not debit the fuel cost. With
this factored in, the total cost for PRODEL in 2016 seems to be smaller, as its unit price cost is also
smaller than the real unit price cost, reflecting the missing fuel cost.(※)
※A guest attending the workshop held in January 2018 pointed out that PRODEL did not debit the
fuel cost in its P/L. The JICA Study Team interpreted this as an indication that PRODEL did not
count the fuel cost because it receives the fuel for free. Meanwhile, the JICA Study Team found
amounts of 25,152 AOA listed under ‘fuel cost’ in the ‘Other Costs’ component of PRODEL’s P/L
in 2016.This guest must have meant that the fuel was consumed by offices and buildings for
administration activities, not by thermal power plants for generation.
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Meanwhile, the unit revenue price (generation) derived from the long-term investment is 18.3
AOA, and the total unit cost consisting of the current unit cost and long-term investment cost will be
38.19 AOA, or 0.177 $. Likewise, the unit revenue price (transmission) derived from the long-term
investment is 4.3 AOA, and the total unit cost consisting of the current unit cost and long-term
investment cost will be 12.45 AOA, or 0.57 $/kWh. (conversion rate: $1=215.064 AOA (T.T.M))
These figures indicate that the unit cost price for PRODEL needs to increase by 15 AOA, starting
from the current 23.11 AOA. Likewise for RNT, the unit cost price needs to increase by 3.59 AOA,
starting from the current 8.86 AOA.
Table 9-13
Unit Prices and Unit Incremental Costs
PRODEL RNT
1. unit revenue price in 2016 @0.09 $ /kWh @0.043 $ /kWh
(=@20.17 AOA/kWh) (=@9.34 AOA/kWh)
2. unit cost price in 2016 @0.09$ /kWh @0.039 $ / kWh
(=@19.74 AOA/kWh) (=@8.45 AOA/kWh)
3. incremental cost based on the @0.085$/ kWh @0.02$/ kWh
long-term investment (=@18.3 AOA/kWh) (=@4.3 AOA/kWh)
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Domestic in Low Voltage (contracted power: up to 3.0 kVA) is based on a gradual increase
of prices. Consumed power per kWh is divided into two stages: up to 120 kWh and 120 kWh
to 200 kWh. The unit price goes up from 2.46 AOA /kWh to 3.0 AOA /kWh.
The unit price for General and Special Domestic (contracted power: more than 3.0 kVA) is
double that of Domestic in Low Voltage (contracted power: up to 3.0 kVA). The calculation
assumes that the amount the customer pays rises as the customer uses more power. The
customer also has to pay more when the customer takes more days to pay the electricity bill.
The formula for Commerce and Industry in Middle Voltage and in High Voltage considers
the number of days (d) passed. The bill gets bigger as more days pass.
Sales of Commerce and Industry in Middle Voltage and in High Voltage do not increase in
proportion to the number of days (d). Rather, the figure increases with P (the maximum
power (KW)) and W (power (kWh) consumed).
The current level of tariff per kWh is around 7 AOA, while the unit cost price calculated
with the accounting figures of ENDE is 13.28 AOA. The unit cost price calculated with the
accounting figures of ENDE is double that of the current tariff. This reflects the national
policy not to impose a high tariff on Angolan nationals, and to compensate the loss with
subsidies.
The tariff of ENDE shall generally include all costs of PRODEL and RNT, and the
investment- related costs of the long-term investment plan is to to be added to the existing
costs for distribution. In line with this approach, the incremental cost of the long-term
investment is 0.232 $ (=50.64 AOA). In this sense, decision-making on the subsidy shall be
separated from the calculation of the necessary revenue and cost.
※Table 9-13 The incremental unit cost of the long-term investment consists of one component
coming from PRODEL and one component coming from RNT.
(1) Recommendations
As stated in the section 9.3.2, the unit cost caused by the investment up to 2040 is estimated at
0.175$ for generation and 0.057$ for transmission and sub-station. These estimates imply that the
tariff must be raised to meet the increasing cost.
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Considering the current financial condition of PRODEL and RNT, it will be difficult for both to go
on investing solely with their own retrained earnings. The study therefore assumes that both will
depend on borrowing, and explains the candidate loan conditions available. Note, meanwhile, that
some loans will need government guarantees and data on the project cycles and time by which the
loans must be received.
If the agency implementing the project goes on borrowing, the equity ratio will decrease. A
decreasing equity ratio would be unfavorable from a financial viewpoint, as it would increase the
default risk. In this case, equity must be injected at the proper time. A 20-30% of equity ratio is
generally favorable, though there seems to be no standard for a proper equity ratio in the power sector.
The table below shows the total assets, total equity, and equity ratios for PRODEL and RNT in
2016. The equity ratios for PRODEL and RNT were higher than 40% in 2016, which would be. If
both companies go on investing solely with borrowing, their equity ratios will decrease: PRODEL
(47.0%→3.8%) and RNT (41.1%→5.3%).
(2) Conclusion
The key implementing agencies in the Power Sector of Angola are PRODEL (generation), RNT
(transmission and sub-station), and ENDE (distribution). ENDE receives a subsidy, which helps to
lessen the financial burden for Angolan nationals.
The long-term investment plan consists of the generation development plan and transmission and the
sub-station development plan. The plan requires increases in the unit revenue prices for PRODEL and
for RNT, while direct tariff increases will not necessarily be required for ENDE. Revenue and
expenditure will have to be calculated in each sector, but this might not lead to a higher tariff. This
calculation of revenue and expenditure will be necessary even if a subsidy is provided to the
distribution sector.
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As each financial institution has its own project-formation cycle and appraisal procedure, the
implementation agency will select the financial institutions that are to be requested to provide loans.
Taking the example of a project-formation cycle of JICA, the implementation agency may also
request a grant to complete an Implementation Report (I/P) in the process of a project cycle.
If the candidate project needs a guarantee from the Government, the implementation agency has to
pass through a step-by-step approval process within the Government. This implies that the
Government of Angola sets up an official approval procedure internally.
Compulsive injection of equity to a new project would be useful to maintain a certain equity ratio.
An implementing agency for a new power project in India, for example, is requested to raise funds
with a ratio of 70% (borrowing) and 30% (equity). In India, either the Central Government or the
State Government provides equity to the implementing agency out of the budget or the long-term
borrowing.
In fact, both the Central Government and the State Government in India are suffering from a red-ink
budget and would be hard-pressed to provide equity from the start. The Government often provides
funds to the implementing agency as long-term borrowing at the beginning but waives the liability if
the implementing agency meets certain conditions. Thus, the implementing agency is finally able to
keep a certain equity ratio by changing the status of the long-term liability into equity in future. (*)
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10.1.1 RNT
(1) Financial Analysis of RNT
The financial statements of RNT report figures in units of 1000 AOA.
(a) P/L
Operating Income in 2016 consisted of Sales (82,297 million AOA), other operating income (4,489
million AOA), and other. The main component of Costs in 2016 was the cost of goods (67,206 million
AOA). Gross profit totaled 8,293 million AOA after deducting financial costs (-859 million AOA) and
Corporate income tax (2,145 million AOA). Finally, RNT posted net profit 4,381 million AOA for the
Year (2016).
Subsidies and affiliate company results 0 0 Subsidies and affiliate company results 0 0
Non-operating costs / income -906,109 -579,007 Non-operating costs / income -3,348 -2,140
Pro fit be fo re Tax 6,527,596 7,427,198 Profit before tax 24,122 27,446
Corporate income tax 2,145,834 2,228,159 Corporate income tax 7,930 8,234
Ne t Pro fit 4,381,762 5,199,039 Net result from ordinary activities
Extraordinary results 0 0 Extraordinary results 0 0
Corporate income tax 0 0 Corporate income tax 0 0
Ne t Pro fit o f the Y e ar 4,381,762 5,199,039 Net profit of the year 16,192 19,212
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(b) B/S
Tangible assets in 2016 (134,178 million AOA) were the biggest component of non-current assets.
Accounts payable in 2016 were the biggest component of current assets (101,955 million AOA),
exceeding operating income for the year.
(c) C/F
Cash Flow from Operating Activities in 2016 was 446 million AOA, although RNT paid 18,881
million AOA to extraordinary items. Cash Flow from Investment in 2016 went into the red due to
investment in subsidies and payment to tangible fixed assets. Meanwhile, RNT borrowed a loan of
4,649 million AOA, as net cash for the year was 2,328 million AOA. Finally, cash and cash
equivalents at the end of that year totaled 7,805 million AOA.
Table 10-3 Cash Flow Statement (C/F)
(unit: 1000 AOA) (unit: 1000 USD)
2016 2015 2016 2015
Cash Flow from Operational Activities Cash Flow from Operational Activities
Receipt from customers 26,038,515 1,709,371 Receipt from customers 96,222 6,317
Payments to suppliers 46,224,491 1,121,398 Payments to suppliers 170,817 4,144
Payment to employees 0 1,572,087 Payment to employees 0 5,809
Cash flow from operation -20,185,976 -984,114 Cash flow from operation -74,595 -3,637
Other receipts related to operational Other receipts related to operational
39,916 0 148
activities activities
Interest paid 1,750,305 Interest paid 6,468 0
Cash Flow from Extraordinary Cash Flow from Extraordinary items -68,127 -3,489
-18,435,671 -944,198
items
Payments with extraordinary items 18,881,692 10,430,988 Payments with extraordinary items 69,775 38,546
Cash Flow from Operating Cash Flow from Operating activities 1,648 -42,036
446,021 -11,375,186
activities
Cash Flow from Investment Cash Flow from Investment Activities
Activities
Receipt from: Receipt from:
Tangible fixed assets
Tangible fixed assets
Intangible fixed assets 0 0
Intangible fixed assets 0
Financial investment
Financial investment
Investment to subsidy 8,262 74,604
Investment to subsidy 2,235,645 20,188,370
Interest and similar income
Interest and similar income
Dividends
Dividends
2,235,645 20,188,370 Total receipts 8,262 74,604
Total receipts
Payment to:
Payment to: Tangible fixed assets 16,439
Tangible fixed assets 4,448,443
Intangible fixed assets 0
Intangible fixed assets 0
Financial investment
Financial investment Subsidy to investment 12,330
Subsidy to investment 3,336,508
Total payment 16,439 12,330
Total payment 4,448,443 3,336,508
Cash Flow before Extraordinary -8,177 62,274
Cash Flow before Extraordinary -2,212,798 16,851,862 A
A Cash Flow from Financial Activities
Cash Flow from Financial Activities
Receipts from: 37,845
Receipts from: 10,241,186
Capital increase, supplementary paymants and own
Capital increase, supplementary paymants and share sales
own share sales
Damage coverage
Damage coverage
Loan obtained 17,183
Loan obtained 4,649,741
Subisidy and donations
Subisidy and donations
Total receipts 17,183 0
Total receipts 4,649,741 0 0
Payment to:
Payment to: 0
Capital decrease, supplementary provisions
Capital decrease, supplementary provisions
Purchase of shares
Purchase of shares Loan obtained
Loan obtained
Depreciation of leasing contracts
Depreciation of leasing contracts
Interest and similar interest 2,048
Interest and similar interest 554,144 Total payment 2,048
Total payment 554,144
Cash F low from F inancial Activities 15,135 0
Cash F low from F inancial Activities 4,095,597 0
Net Cash Increase and its Equivalents 8,606 20,238
Net Cash Increase and its 2,328,819 5,476,676 Cash and its Equivalents at the Beginning of the
20,238 0
Cash and its Equivalents at the Beginning of Year
5,476,676 0
the Year Cash and its Equivalents at the End of the
28,844 20,238
Cash and its Equivalents at the End of Year
7,805,495 5,476,676
the Year
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(d) Conclusion
The major financial ratios were as follows.
The net profit margin in 2016 was 5.0 %, which was quite good. Return on Assets (ROA) in 2016
was quite small, falling to 1.8%, because accounts receivables were quite big compared to operating
income. The current ratio, an indicator of financial stability, was 0.82, which was less than 1.0. The
average collection (days) in 2016 was 426 days because the outstanding accounts receivables were
bigger than operating income.
Table 10-4 Major financial ratios
2016 2015
net profit margin 5.0% 9.5%
10.1.2 PRODEL
The financial statements of PRODEL report figures in units of 1000 AOA.
(a) P/L
The major component of operating income in 2016 was sales (42,255 million AOA). Other
operating income consisted of subsidies (178,182 million AOA). More than 70% of the operating costs
were costs of goods (164,235 million AOA). Gross profit was positive, though subsidies and affiliates
and corporate income tax followed. Net profit for the Year in 2016 was 1,862 million AOA.
One guest attending the workshop held in January 2018 pointed out that PRODEL did not debit the
fuel cost on its financial statement. The JICA Study Team found that PRODEL’s Financial Statement
in 2016 debited 25,152,000 AOA of fuel cost as ‘Other Costs.’ This guest must have meant that
PRODEL consumed the fuel for administrative purposes in offices or buildings.
Table 10-5 Profit and Loss Statement (P/L)
unit: 1000 AOA
2016 2015 (unit: 1000 USD)
Ope rating Inco me s 220,420,796 116,631,357 2016 2015
Sales 42,238,471 25,655,726 Ope rating Inco me s 814,539 430,997
Services rendered 0 0 Sales 156,087 94,808
Other operating profits 178,182,325 90,975,631 Provision of service 0 0
Other operating profits 658,452 336,190
Ope rating Co sts 215,757,239 126,819,841
Changes in inventories of finished goods and work
Ope rating Co sts 645,351 389,741
0 0 Variation in the finished product and in the
in progress
process of manufacturing
Works capitalized 0 0 Work for the company itself 0 0
Cost of goods sold and the materials consumed 164,235,499 98,320,782 Cost of goods sold and the raw materials and
606,913 363,333
Personnel costs 10,401,554 7,146,216 supplies consumed
Amortizations 15,055,711 11,246,853 Personnel costs 38,438 26,408
Amortizations
Other costs and operating Loss 26,064,475 10,105,990
Other costs and Operating Loss
Gro ss Pro fit 4,663,557 -10,188,484
Financial results 1,297,742 -431,536
Gro ss Pro fit 17,233.63 -37,650.34
Financial results 4,796 -1,595
Subsidies and affiliate company results -192,245 0 Results from Subsidiaries and associated
Non-operating costs / income 66,470 -83,047 companies
Pro fit be fo re tax 5,835,524 -10,703,067 Non-operating results
Corporate income tax 0 0 Profit before tax 21,564 -39,552
Ne t re sult from o rdinary activitie s 5,835,524 -10,703,067 Taxes on income
Extraordinary results 0 11,033,610 Net result from ordinary activities
Corporate income tax -3,972,868 -99,357 Extraordinary results
Ne t pro fit o f the ye ar 1,862,656 231,186 Taxes on income
Net profit of the year 6,883.23 854.32
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(b) B/S
Almost all of the non-current assets in 2016 were tangible assets (416,818 million AOA). Accounts
payable in 2016 were 311,917 million AOA, exceeding accounts receivables. There was also a
middle-term borrowing in 2016 (3,000 million AOA).
(c) C/F
Cash Flow from Operating Activities in 2106 went into the red (-69,075 million AOA) because
payments to suppliers were much bigger than receipts and other incomes. Cash Flow from
Investment Activities in 2016 was 49,988 million AOA because receipts from subsidy exceeded
those to subsidy. Cash Flow from Financial Activities in 2016 mainly consisted of loans. (11,046
million AOA). Moreover, PRODEL received 151 million AOA as income from exchange rates.
As a result, net cash decreased -8,916 million AOA for the year and cash and cash equivalents at
the end of the year totaled 17,870 million AOA.
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Receipts from loans 11,046,446 10,241,186 Receipts from loans 40,821 37,845
Cash Flow from Financial Activities 10,170,216 10,241,186 Cash Flow from Financial Activities 37,583 37,845
Net Cash Increase and its -8,916,962 20,328,492 Net Cash Increase and its Equivalents -32,952 75,122
Income / loss from exchange rates 151,938.00 6,307,029.00 Income / loss from exchange rates 561 23,307
Cash and its Equivalents at the Beginning of the Cash and its Equivalents at the Beginning of the
26,635,522 0 98,428 0
Year Year
Cash and its Equivalents at the End of the Cash and its Equivalents at the End of the
17,870,498 26,635,521 Year
66,038 98,428
Year
(d) Conclusion
The major financial ratios were as follows.
The net profit margin in 2016 was positive, albeit small (0.8%). Given the low net profit margin,
Return on Assets (ROA) in 2016 was also small (0.6%). The current ratio, an indicator of financial
stability, was 0.6, which was less than 1.0. The average collection (days) in 2016 was 91 days, which
was quite good compared to the other two corporations.
10.1.3 ENDE
The financial statements of ENDE originally reported figures in units of AOA. To keep consistency
with the statements of the other corporations (PRODEL and RNT), the financial statements are
analyzed on a 1000 AOA basis.
(a) P/L
Major operating income in 2016 consisted of subsidies in process (68,414 million AOA), as well as
electricity power sales (48,336 million AOA) and other. The biggest portion of operating costs was
subsidized and consumed raw materials (82,436 million AOA), followed by personnel expenses
(17,209 million AOA). Gross profit was positive, though ENDE incurred both financial loss (-7,024
million AOA) and non-operating loss (-12,193 million AOA). Finally, the net profit for the Year in
2016 was -16,318 million AOA.
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Cash and equivalents 12,112,350 4,760,025 Cash and equivalents 44,760 17,590
Other current assets 2,212,187 1,250,476 Other current assets 8,175 4,621
Total Liabilities and Net Assets 471,355,346 435,526,300 Total Liabilities and Net Assets 1,741,838 1,609,436
(b) B/S
Accounts receivables were prominent in current assets, and accounts payables were prominent in current
liabilities. Outstanding accounts receivables and payables in 2016 were 267,923 million and 167,799
million AOA, respectively. Accounts receivables far exceeded the operating income for the year, so the
collection (days) was 770 days. The total billed amounts during the year 2015 to June 2017 are:
52,621,339,094.34 AOA for Law Voltage and 35,046,795,121.71 AOA for Medium Voltage. Meanwhile
ENDE collected during the same period 38,292,121.097 AOA for Law Voltage and 20,138,340,323 AOA
for Medium Voltage. It means that collection rate for Law Voltage is 72.7% but that for Medium Voltage is
57.4%. It seems that the bill collection of Medium Voltage is harder than that of Law Voltage.
As a result, some accounts receivables of Medium Voltage have gone bad. One possible reason for
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the gap was the practice of crediting bills to clients without necessarily collecting in some cases.
Uncollected receivables accumulated, as some receivables were no longer collected. The same thing
happened with accounts payables.
(c) C/F
Cash Flow from Operating Activities in 2016 was negative because payments to suppliers and payments
to employees were bigger than receipts from clients. Cash flow from Investment Activities was negative
(-1,936 million AOA). Cash Flow from Financial Activities included 26,708 million AOA of allocations to
Exploration and Contributions. Moreover, ENDE borrowed 5,000 million AOA. Cash Flow from Financial
Activities made up the losses for Cash Flow from Operating Activities and Cash Flow from Investment
Activities.
Table 10-11 Cash Flow Statement (CF)
(unit: 1000 AoA) (unit: 1000 USD)
2016 2015 2016 2015
Cash Flow from Operational -19,750,661 -1,703,503 Cash Flow from Operational Activities -72,986 -6,295
Cash flow from operation -11,557,392 1,866,526 Cash flow from operation -42,709 6,898
Cash receipts from clients 36,938,612 16,532,900 Cash receipts from clients 136,502 61,095
Cash payments to suppliers -32,928,684 -4,507,034 Cash payments to suppliers -121,684 -16,655
Payment to employees -15,567,320 -10,159,340 Payment to employees -57,527 -37,543
Profits tax -272,885 -137,051 Profits tax -1,008 -506
Cash flow before other operational activi -7,791,191 -3,331,305 Cash flow before other operational activities -28,791 -12,310
Other receipts from operational activities 609,652 0 Other receipts from operational activities 2,253 0
Other paymentes from operational activities -8,400,844 -3,331,305 Other paymentes from operational activities -31,044 -12,310
Cash flow before nonstandard items -129,193 -101,672 Cash flow before nonstandard items -477 -376
Receipts from nonstandard items 27,094 50,420
Receipts from nonstandard items 100 186
Payments from nonstandard items -156,287 -152,093
Payments from nonstandard items -578 -562
0 0
Cash Flow from Investment Activiti -1,936,745 -2,039,147
Cash Flow from Investment Activities -7,157 -7,535
Receipts from: 880,317 241,319
Receipts from: 3,253 892
Tangible fixed assets 3,753 2,081 Tangible fixed assets 14 8
Financial investments 0 0
Financial investments 0 0
Interests 3,239 884
Interests 876,563 239,237 Payments to -10,410 -8,427
Payments to -2,817,062 -2,280,466 Fixed tangible assets -10,410 -8,427
Fixed tangible assets -2,817,062 -2,280,466 Fixed intangible assets 0 0
Fixed intangible assets 0 0
Casf flow from Financial Activities 107,313 16,019
Casf flow from Financial Activities 29,039,731 4,334,991 Receipts from 117,175 17,168
Receipts from 31,708,536 4,645,763 Loans 18,477 0
Loans 5,000,000 0 Allocations to Exploration and Contributions 98,698 17,168
Allocations to Exploration and Contributions 26,708,536 4,645,763 Payments to -9,862 -1,148
Payments to -2,668,804 -310,772 Loans -4,530 -626
Loans -1,225,882 -169,412
Interests -5,332 -522
Interests -1,442,922 -141,360
0 0
0 0
Net Cash Increase or Decrease of the Year 27,170 2,189
Net Cash Increase or Decrease of the Yea 7,352,325 592,341 Cash and Equivalent at the Beginning of the
Cash and Equivalent at the Beginning of 17,590 0
4,760,025 0 Year
the Year
Impact of the Addition of Cash Balances and its
Impact of the Addition of Cash Balances and its 0 15,401
0 4,167,684 Equivalent from Winded -up ENE and EDEL
Equivalent from Winded -up ENE and EDEL
Cash and its Equivalent at the End of Cash and its Equivalent at the End of the
12,112,350 4,760,025 Year
44,760 17,590
the Year
(d) Conclusion
The major financial ratios were as follows.
The net profit margin in 2016 was negative (-12.8%). Return on Assets (ROA) in 2016 was small,
falling to -3.5%, because accounts receivables were big due to the far bigger total assets versus
operating income. The current ratio, an indicator of financial stability, was 1.33 because current
assets were bigger than current liabilities. The average collection (days) in 2016 was 770 days,
which was bigger than 1 year (365 days).
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ENDE offers an explanation for this issue in its Activity Report: “ENDE sets the goal of collecting
from 70% to up to 85% of billed amounts.” If a collection-day extends beyond 365 days, some of the
accounts receivables go bad, making further collection almost impossible. This, in turn, makes it
necessary to increase the collection rate further. At the same time, ENDE must review whether or not
outstanding accounts receivables go bad.
Table 10-14 Collection (days) for Bills (days)
days 2016 2015
PRODEL 91 96
RNT 426 357
ENDE 770 1,198
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10.3.3 Borrowing
The liabilities of PRODEL, RNT and ENDE RNT are currently limited to short-term or
middle-term liabilities. There are no long-term liabilities. If the three companies depend solely on
borrowing, the credibility of each company will decline commensurately with the decreases in its
equity ratio. In order to maintain a proper equity ratio, funds should be raised from a mixture of
borrowings and equity, or from a forgivable loan, the approach followed India.
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GDP. If the Government of Angola goes on undertaking government guarantees, the total debt will almost
reach Angola’s 2017 GDP. This would not be favorable for the long-term sustainability of the country.
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