FEASIBILITY STUDY of a HYDROPOWER FACILITY in EASTERN ANGOLA Civil Engineering

Home , Cunene River, Kasai River, Saurimo

FEASIBILITY STUDY OF A HYDROPOWER FACILITY IN EASTERN ANGOLA

João Pedro Marques Santos Coelho

Thesis to obtain the Master of Science Degree in Civil Engineering

Hydraulics and Water Resources

Supervisor:

Prof. António Bento Franco

Examination Committee

Chairperson: Prof. António Alexandre Trigo Teixeira

Supervisor: Prof. António Bento Franco

Members of the Committee: Prof. António Alberto do Nascimento Pinheiro

December 2015

ABSTRACT

The increasing demand in the energy sector and global energy needs, determined by the growth of the world’s population and socio economic development, is considered by many experts as an opportunity for the definition and implementation of a sustainable energy model, which enables energy access to all potential users in a perspective of rational and efficient use of the available energy resources. Among the renewable energy technologies used worldwide, hydropower plays a major role being the most used renewable energy source at the moment.

In Angola there is a great abundance of this natural resource and a great potential in the hydropower sector, which is not yet developed. In the country there is also a great deficit in what concerns the available energy per capita. In this master thesis, it is presented a feasibility study of a hydropower facility in the Eastern Angola, one of the most deprived areas in terms of access to energy, within the Angolan territory. The hydropower facility is supposed to supply the city of Saurimo, the capital of the Lunda Sul province, that has an estimated population of about 200 000 inhabitants.

The present study includes an analysis of the Chiumbe River, in all its extents inside the Angolan boarders, in order to determine the best possible location to build a hydropower facility. After the selection of the best location, an optimization of some of the parameters of the facility is made, as well as a pre-study and primarily analysis on floods, hydraulic structures, equipment’s and construction materials. Also a preliminary estimative of the quantities and works associated with the construction of the facility is elaborated, as well as an economic analysis, for the best location in the Chiumbe River to construct a hydropower facility, and also for the more adequate configuration. This economic analysis gives the first idea whereas the facility will be profitable.

Keywords: Angola, Saurimo, Chiumbe River, hydropower facility, feasibility study.

ii RESUMO

As perspectivas futuras para o crescimento da população mundial e o crescimento socioeconómico esperado, determinam, entre outros aspectos, um aumento das necessidades energéticas a nível global. Este aumento das necessidades no sector energético é considerado por muitos especialistas como uma oportunidade para definição e implementação de um modelo energético sustentável. Este modelo permitirá o acesso a energia por todos os potenciais utilizadores usando, de forma racional e o mais eficiente possível, os recursos energéticos disponíveis. De entre as fontes energéticas utilizadas actualmente, a hidroelectricidade tem um papel muito significativo, sendo a fonte renovável mais utilizada a nível mundial.

Em Angola existe uma grande abundância deste recurso natural, e consequentemente um grande potencial no sector da hidroelectricidade que ainda não se encontra aproveitado. Além disso, verifica-se um grande deficit em termos de energia disponível por habitante. Na presente tese de mestrado, é realizado um estudo de viabilidade de um aproveitamento hidroeléctrico no Nordeste de Angola, uma das zonas menos desenvolvidas do país ao nível do acesso à energia. O aproveitamento hidroeléctrico em questão, tem como objectivo abastecer a cidade de Saurimo, capital da província de Lunda Sul, com uma população estimada de 200 000 habitantes.

O projecto passa por uma análise do rio Chiumbe em toda a sua extensão, dentro do limite das fronteiras Angolanas, com o objectivo de determinar a melhor localização para a construção de um aproveitamento hidroeléctrico. Uma vez definida a localização mais adequada, foram também analisados alguns dos parâmetros do aproveitamento, nomeadamente um pré- estudo relativo às cheias, principais estruturas hidráulicas, equipamentos e materiais de construção. É também definido um mapa de quantidades e desenvolvida uma análise económica, para aquela que foi considerada a melhor localização para o aproveitamento, e para a configuração mais adequada. Esta análise económica permite ter uma primeira ideia se o aproveitamento será rentável.

Palavras-chave: Angola, Saurimo, rio Chiumbe, aproveitamento hidroeléctrico, estudo de viabilidade.

iii

iv AGRADECIMENTOS

Esta tese surgiu no âmbito do meu programa Erasmus, realizado em Lausanne mais concretamente na École Polytechnique Fédéral de Lausanne (EPFL). O presente tema era uma das propostas da Universidade e foi um dos motivos que despertou interesse em embarcar neste programa. Desde que voltei de Erasmus continuei a desenvolver este projecto, já no IST e com o apoio do Professor António Bento Franco. O tema em questão consistia num projecto bastante ambicioso que não teria sido possível desenvolver sem a ajuda e o apoio de várias pessoas a quem gostaria de agradecer nos parágrafos que se seguem.

Em primeiro lugar gostaria de agradecer a toda a minha família por estarem sempre no meu canto e a torcer pelo meu sucesso académico, nomeadamente aos meus pais, ao meu irmão e aos meus avós. Um especial obrigado ao meu “velhote” por toda a dedicação, empenho e tempo investido a rever a minha tese, contribuindo para um resultado final que, sem qualquer dúvida, apresenta mais qualidade. Ao meu avô Fernando que, apesar de já não estar presente fisicamente, sei que ficaria orgulhoso ao ver concluída esta jornada.

Quero também agradecer a Andreia pelo apoio incondicional, por ter sido sempre um pilar nas situações difíceis e pela ajuda na revisão da tese. Um abraço também para o Chico Panda que me ajudou na revisão final do extended abstract. Aos meus amigos, sempre presentes, um grande obrigado, “estamos juntos”.

Não poderia deixar de agradecer ao meu amigo e orientador, o Professor Doutor António Bento Franco, por toda a sua disponibilidade e empenho ao longo deste projecto.

Gostava de agradecer também a todas as pessoas que trabalharam comigo na EPFL e que me ajudaram neste projecto, nomeada ao Professor Pedro Manso e à Irene Samora. Também ao Professor Doutor Anton Schleiss, por me ter orientado e por me ter proporcionado todas as condições para o desenvolvimento deste projecto, durante a minha estadia em Lausanne.

Durante os últimos quatro meses tenho estado a estagiar na GIBB Portugal S.A. no departamento de hidráulica e recursos hídricos. Esta experiencia para além de benéfica e formadora a nível profissional, tem sido também um complemento no desenvolvimento deste projecto sendo que tive oportunidade de contactar com engenheiros de diversas áreas, com uma vasta experiência profissional e que inúmeras vezes me ajudaram com alguns problemas que foram surgindo ao longo deste estudo. Quero agradecer especialmente ao meu amigo e colega Paulo Salvado, que nesta recta final do projecto tem sido incansável em todo o apoio que me tem dado, nomeadamente no desenvolvimento das peças desenhadas relativas ao aproveitamento em questão. Um obrigado também ao Arquitecto Rui Pacheco, pelo auxilio e esclarecimento de duvidas relativas ao REVIT.

vi TABLE OF CONTENTS

1 INTRODUCTION ...... 1 2 HYDROPOWER ...... 3

2.1 HYDROPOWER GENERATION ...... 3 2.2 CLASSIFICATION OF HYDROPOWER PLANTS ...... 3 2.3 RENEWABLE ENERGIES AND SUSTAINABLE DEVELOPMENT ...... 5 2.4 ROLE OF HYDROPOWER IN RENEWABLE ENERGY SOURCES ...... 7 3 CONTEXT IN ANGOLA ...... 11

3.1 GEOGRAPHY AND MAJOR RIVER BASINS ...... 11 3.2 CLIMATE ...... 12 3.3 CIVIL WAR ...... 14 3.4 ANGOLA’S ECONOMY AND CURRENT SITUATION ...... 15 3.5 DESCRIPTION OF THE CURRENT ANGOLAN ENERGY MATRIX AND OBJECTIVES FOR THE FOLLOWING YEARS ...... 17 3.6 HYDROELECTRIC POTENTIAL OF ANGOLA ...... 19 3.7 ANGOLA’S ELECTRIC SYSTEM, ANALYSIS OF THE CURRENT INSTALLED CAPACITY AND MAJOR PROJECTS IN ANGOLA ... 19 3.8 CASE STUDY AND BASE DATA ...... 23 4 METHODOLOGY ...... 25

4.1 INTRODUCTION ...... 25 4.2 STAGE 1: SCREENING OF POSSIBLE ALTERNATIVES...... 25 4.3 STAGE 2: FEASIBILITY STUDY OF THE SELECTED OPTION ...... 26 4.4 STAGE 3: ECONOMIC ANALYSIS ...... 27 5 CASE STUDY AND RESULTS ...... 29

5.1 STAGE 1: SCREENING OF POSSIBLE ALTERNATIVES...... 29 5.1.1 Zoom in to the Location ...... 29 5.1.2 Parameters for Site Location ...... 29 5.1.3 Topography Analysis ...... 30 5.1.3.1 Definition of the Basin ...... 30 5.1.3.2 Characterization of the Basin ...... 31 5.1.4 Definition of Alternatives ...... 35 5.1.5 Characterization of Alternatives ...... 37 5.1.6 Available Water Resources for Energy Production ...... 39 5.1.6.1 Analysis of the Precipitation Data ...... 39 5.1.6.2 Runoff Data ...... 41 5.1.6.3 Calculation of the Flow Duration Curves ...... 44 5.1.7 Reservoir Volumes ...... 46 5.1.8 Cost Estimation ...... 51 5.1.9 Comparison of Alternatives ...... 54 5.2 STAGE 2: FEASIBILITY STUDY OF THE SELECTED OPTION ...... 60 5.2.1 Reservoir Analysis ...... 60 5.2.1.1 Base Data and Definition of the Model ...... 60 5.2.1.2 Conclusions of the Reservoir Analysis ...... 76 5.2.2 Construction Materials and Possible Dam Types ...... 78 5.2.3 Flood Analysis ...... 82 5.2.4 Hydraulic Structures ...... 88 5.2.4.1 Preliminary Study of the Hydraulic Structures ...... 88 5.2.4.2 Pre Dimensioning of the Spillway ...... 90 5.2.4.3 Considerations for the Remaining Hydraulic Structures ...... 92 5.2.5 Pre Dimensioning of the Turbines ...... 93

vii 5.2.6 Pre Study Drawings and Preliminary Bill of Quantities ...... 97 5.3 STAGE 3: ECONOMIC ANALYSIS ...... 100 6 CONCLUSIONS ...... 105 7 FUTURE WORK ...... 107 8 REFERENCES ...... 109 APPENDICES I ...... 111

APPENDICES I – FIGURES AND TABLES ...... 111 APPENDICES II – DRAWINGS ...... 184

viii LIST OF FIGURES

Figure 2.1 - Percentage of each energy renewable technology worldwide ...... 7 Figure 2.2 - Regional distribution of the cumulated installed capacity, of each renewable energy technology in 2013 ...... 8 Figure 3.1 – Angola’s boundaries and some of the main cities ...... 11 Figure 3.2 - Sothern Africa major river basins ...... 12 Figure 3.3 – Mean annual rainfall in Angola ...... 13 Figure 3.4 – Coefficient of variation of annual rainfall ...... 14 Figure 3.5 – Angola’s energy matrix in 2011 ...... 17 Figure 3.6 – Prediction for the energy consumption per capita in Angola for the next years ...... 18 Figure 3.7 – Available power per capita in Angola in 2013 ...... 20 Figure 3.8 - Available power per capita in Angola in 2015 ...... 20 Figure 3.9 – Estimated available power per capita in Angola in 2017 ...... 20 Figure 3.10 - Estimated available power per capita in Angola after 2017 ...... 21 Figure 4.1 – Methodology followed in this study ...... 25 Figure 5.1 - Location of the Chiumbe River Basin in Angola ...... 29 Figure 5.2 - Chiumbe River longitudinal profile ...... 31 Figure 5.3 – Phytogeographic map of Angola adapted to the Chiumbe River basin ...... 33 Figure 5.4 - Adaptation of the Soil Atlas of Africa for the region in the case study using the Quantum GIS software ...... 34 Figure 5.5 – Legend from the Soil Atlas of Africa ...... 34 Figure 5.6 – Mean monthly precipitation values for Saurimo, Dala and Lucapa ...... 35 Figure 5.7 - Mean monthly temperature values for Saurimo, Dala and Lucapa ...... 35 Figure 5.8 - Representation of the alternatives 1 - 5 in the Chiumbe River basin map ...... 36 Figure 5.9 - Representation of the possible sections in the longitudinal profile of the river ...... 37 Figure 5.10 - Hydrodynamic curve of the Chiumbe River ...... 37 Figure 5.11 – Satellite precipitation in the Chiumbe River basin (Mean monthly values) ...... 40 Figure 5.12 – Location of hydrometric stations ...... 43 Figure 5.13 – Flow duration curve for section 1 ...... 45 Figure 5.14 – Comparison between sections in terms of mean discharge ...... 46 Figure 5.15 - Comparison between sections in terms of mean affluent volume ...... 46 Figure 5.16 – Accumulated affluent volumes and accumulated volume demand curve for an equipped discharge equal to the one that is only exceeded 180 days per year in section 1 ...... 48 Figure 5.17 – Accumulated affluent volumes and accumulated volume demand curve for an equipped discharge equal to the one that is only exceeded 140 days per year in section 1 ...... 48 Figure 5.18 – Accumulated affluent volumes and accumulated volume demand curve for an equipped discharge equal to the mean annual discharge in section 1 ...... 48 Figure 5.19 – Accumulated affluent volumes and accumulated volume demand curve for an equipped discharge equal to the one that is only exceeded 90 days per year in section 1 ...... 49 Figure 5.20 - Depth volume curve and depth area curve for the reservoir in section 1 ...... 50 Figure 5.21 – Cost per MW of installed capacity and cost per GWh generated per year for the equipped discharge exceeded 90 day per year and for the mean annual discharge ...... 57 Figure 5.22 – MW of installed capacity per km2 of reservoir for each section and different alternatives ...... 58 Figure 5.23 – Cost per MW of installed capacity for sections 1 and 8 ...... 59 Figure 5.24 – Cost per GWh generated per year for sections 1 and 8 ...... 59 Figure 5.25 – MW of installed capacity per km2 of reservoir for sections 1 and 8 ...... 59 Figure 5.26 – Comparison between the flow duration curves using the measured data and the satellite data ...... 61 Figure 5.27 - Comparison between the mean affluent volumes using the measured data and the satellite data ...... 62 Figure 5.28 – Reservoir levels (WRE lectures, EPFL, 2014/2015 1st semester) ...... 64 Figure 5.29 – Reservoir analysis for the scenario C1 ...... 65 Figure 5.30 – Reservoir analysis for the scenario C2 ...... 66 Figure 5.31 – Reservoir analysis for the scenario C3.1 ...... 66 Figure 5.32 – Reservoir analysis for the scenario C3.2 ...... 66

ix Figure 5.33 – Reservoir analysis for the scenario C3.3 ...... 67 Figure 5.34 – Reservoir analysis for the scenario C4 ...... 67 Figure 5.35 – Reservoir analysis for the scenario C5 ...... 68 Figure 5.36 – Reservoir analysis for the scenario C6 ...... 68 Figure 5.37 – Reservoir analysis for the scenario C7 ...... 69 Figure 5.38 – Reservoir analysis for the scenario C8 ...... 69 Figure 5.39 – Reservoir analysis for the scenario C9 ...... 70 Figure 5.40 – Reservoir analysis for the scenario C10 ...... 70 Figure 5.41 – Reservoir analysis for the scenario C11.1 ...... 71 Figure 5.42 – Reservoir analysis for the scenario C11.2 ...... 71 Figure 5.43 – Reservoir analysis for the scenario C12.1 ...... 71 Figure 5.44 – Reservoir analysis for the scenario C12.2 ...... 72 Figure 5.45 – Reservoir analysis for the scenario C13.1 ...... 72 Figure 5.46 – Reservoir analysis for the scenario C13.2 ...... 72 Figure 5.47 – Cost per MW of installed capacity, for each scenario ...... 75 Figure 5.48 – Cost per GWh generated per year ...... 75 Figure 5.49 – MW of installed capacity per km2 of reservoir ...... 75 Figure 5.50 – Energy and power generation for each scenario ...... 75 Figure 5.51 – Firm energy ...... 77 Figure 5.52 – Energy generated each month with each turbine, for the worst possible situation and with scenario C12.1 ..... 78 Figure 5.53 – Google Earth image of section 1 (16/09/2015) ...... 79 Figure 5.54 – Geology map of Angola in the region of section 1 (Adapted using Quantum GIS) ...... 80 Figure 5.55 – Adjustment of the Gumbel law to the precipitation series ...... 84 Figure 5.56 – Udometric Curves for the return periods of 20, 50, 100 and 1000 years ...... 85 Figure 5.57 - Sub basins of the catchment area in study ...... 86 Figure 5.58 – Conceptual representation used in HEC-HMS ...... 87 Figure 5.59 – Flood hydrographs for different return periods ...... 88 Figure 5.60 – Location of the hydraulic structures and dam type ...... 90 Figure 5.61 - Conceptual representation used in HEC-HMS to simulate the flood weakening ...... 91 Figure 5.62 - Weakening of the floods in the reservoir for a return period of 1000 years ...... 92 Figure 5.63 – Domains of application of Pelton, Francis and Kaplan turbines (Quintela 1981) ...... 94 Figure 5.64 – Efficiency of the different types of turbines versus Q/Qmax ...... 95 Figure 5.65 – Runner dimensions (Siervo and Leva 1976) ...... 96 Figure 5.66 – Spiral case dimensions (Siervo and Leva 1976) ...... 97

x LIST OF TABLES

Table 2.1 - Small-scale hydropower by installed capacity (MW) as defined by various countries ...... 5 Table 2.2 - Worldwide installed power capacity of renewable energy technologies and estimated annual energy generation in 2013 ...... 7 Table 2.3 – Summary of the global hydropower market in 2013 ...... 8 Table 2.4 – Main Hydropower Facilities in Brazil ...... 9 Table 3.1 – Major power facilities existing in Angola and facilities predicted for the next years ...... 22 Table 5.1 – Characterization of the hydrographic network of the Chiumbe River basin ...... 31 Table 5.2 – Characterization of the hydrographic basin of the Chiumbe River ...... 32 Table 5.3 - Soil coverage/vegetation in the Chiumbe River basin ...... 33 Table 5.4 – Percentage of each soil type in the Chiumbe River basin ...... 34 Table 5.5 - Characterization of sections ...... 38 Table 5.6 - Mean annual values of precipitation (mm) in each catchment area ...... 40 Table 5.7 – Mean annual values of the eight year-long series in the Port-Francqui hydrometric station ...... 42 Table 5.8 – Hydrometric stations and specific discharge value ...... 42 Table 5.9 – Runoff coeffient values ...... 43 Table 5.10 – Runoff coefficient in the Chiumbe River basin ...... 43 Table 5.11 – Flow duration curve for section 1 ...... 45 Table 5.12 – Comparative analysis between the 10 sections ...... 45 Table 5.13 - Determination of the reservoir volume for different values of equipped discharge in section 1 ...... 47 Table 5.14 - Depth volume curve and depth area curve for the reservoir in section 1 ...... 49 Table 5.15 – Reservoir characterization for each section ...... 50 Table 5.16 - Calculation of quantities in each section for different values of equipped discharge ...... 52 Table 5.17 – Comparative costs ...... 53 Table 5.18 - Cost estimates for each section and for different values of equipped discharge ...... 53 Table 5.19 –Cost estimations for the facility ...... 53 Table 5.20 – Calculation of the net head, installed capacity and energy generation ...... 54 Table 5.21 – Calculation of comparative indicators ...... 56 Table 5.22 - Calculation of comparative indicators ...... 56 Table 5.23 - Mean monthly discharge values in section 1 obtained using the measured values of discharge ...... 61 Table 5.24 - Mean monthly evaporation in section 1 ...... 63 Table 5.25 – Comparison between hypotheses for section 1 ...... 74 Table 5.26 – Physiographic characteristics of the catchment area controlled by section 1 ...... 83 Table 5.27 – Concentration time in the catchment area controlled by section 1 ...... 83 Table 5.28 – Calculation of the maximum precipitation for different return periods and calibration of the coefficient a ...... 85 Table 5.29 - Physiographic characteristics and the concentration time of the three sub basins ...... 87 Table 5.30 – Weakening of the floods in the reservoir ...... 91 Table 5.31 – Dimensions of the turbine ...... 97 Table 5.32 – Initial values for economic analysis ...... 100 Table 5.33 – Different scenarios and associated interest and discount rate ...... 101 Table 5.34 - Distribution of the CAPEX and OPEX in each year ...... 101 Table 5.35 – Cost and revenues in the present year for each of the scenarios ...... 101 Table 5.36 – Calculation of economic indicators for each scenario ...... 102 Table 5.37 – Variations of the costs and benefits ...... 103 Table 5.38 – Calculation of economic indicators for different variations of the costs and benefits ...... 103 Table 5.39 – Calculation of the cost price ...... 104

xii LIST OF APPENDICES I

LIST OF FIGURES IN APPENDICES I

Figure A- 1 - Transversal profile of the section 1 ...... 113 Figure A- 2 - Transversal profile of the section 2 ...... 113 Figure A- 3 - Transversal profile of the section 3 ...... 113 Figure A- 4 - Transversal profile of the section 4 ...... 113 Figure A- 5 - Transversal profile of the section 5 ...... 113 Figure A- 6 - Transversal profile of the section 6 ...... 114 Figure A- 7 – Transversal profile of the section 7 ...... 114 Figure A- 8 - Transversal profile of the section 8 ...... 114 Figure A- 9 - Transversal profile of the section 9 ...... 114 Figure A- 10 - Transversal profile of the section 10 ...... 114 Figure A- 11 - Concrete dam cross section ...... 114 Figure A- 12 - Catchment area defined by the hydrometric station considered ...... 119 Figure A- 13 - Satellite precipitation in the catchment area defined by the GRDC station (mean daily values) ...... 119 Figure A- 14 - Flow duration curve in section 2 ...... 121 Figure A- 15 - Flow duration curve in section 3 ...... 122 Figure A- 16 - Flow duration curve in section 4 ...... 123 Figure A- 17 - Flow duration curve in section 5 ...... 124 Figure A- 18 - Flow duration curve in section 6 ...... 125 Figure A- 19 - Flow duration curve in section 7 ...... 126 Figure A- 20 - Flow duration curve in section 8 ...... 127 Figure A- 21 - Flow duration curve in section 9 ...... 128 Figure A- 22 - Flow duration curve in section 10 ...... 129 Figure A- 23 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 2 ...... 130 Figure A- 24 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 3 ...... 131 Figure A- 25 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 4 ...... 132 Figure A- 26 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 5 ...... 133 Figure A- 27 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 6 ...... 134 Figure A- 28 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 7 ...... 135 Figure A- 29 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 8 ...... 136 Figure A- 30 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 9 ...... 137 Figure A- 31 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 10 ...... 138 Figure A- 32 - Angolan electric grid. Focus in the regions of Lunda Norte and Lunda Sul ...... 140 Figure A- 33 - Cost of E&M equipment in powerhouses per unit with Francis turbine ...... 141 Figure A- 34 – Reservoir analysis for the worst possible situation with scenario C12.1 ...... 171 Figure A- 35 - Precipitation hyetograph for a return period of T=1000 years and a duration t=tc ...... 173 Figure A- 36 - Precipitation hyetograph for a return period of T=1000 years and a duration t=2tc ...... 173 Figure A- 37 - Precipitation hyetograph for a return period of T=100 years and a duration t=tc ...... 174 Figure A- 38 - Precipitation hyetograph for a return period of T=100 years and a duration t=2tc ...... 174 Figure A- 39 - Precipitation hyetograph for a return period of T=50 years and a duration t=tc ...... 174 Figure A- 40 - Precipitation hyetograph for a return period of T=50 years and a duration t=2tc ...... 175 Figure A- 41 - Precipitation hyetograph for a return period of T=20 years and a duration t=tc ...... 175 Figure A- 42 - Precipitation hyetograph for a return period of T=20 years and a duration t=2tc ...... 175 Figure A- 43 - Main runner dimensions versus specific rotation speed ...... 177 Figure A- 44 - Main spiral case dimensions versus the specific rotation speed ...... 177 Figure A- 45 – Work planning ...... 181 Figure A- 46 – Discount cumulated cash flow curve for scenario A-1.1 ...... 182 Figure A- 47 - Discount cumulated cash flow curve for scenario A-1.2 ...... 182 Figure A- 48 - Discount cumulated cash flow curve for scenario A-1.3 ...... 182

xiii Figure A- 49 - Discount cumulated cash flow curve for scenario A-2.1 ...... 182 Figure A- 50 - Discount cumulated cash flow curve for scenario A-2.2 ...... 183 Figure A- 51 - Discount cumulated cash flow curve for scenario A-2.3 ...... 183

xiv LIST OF TABLES IN APPENDICES I

Table A- 1 - Mean monthly values of rainfall in each basin for a 16 year-long series ...... 115 Table A- 2 – Characterization of the hydrometric station located in the Kasai River Basin ...... 119 Table A- 3 - Typical values of the runoff coefficient...... 120 Table A- 4 - Typical values of the runoff coefficient ...... 120 Table A- 5 - Characteristics of the flow duration curve in section 2 ...... 121 Table A- 6 - Characteristics of the flow duration curve in section 3 ...... 122 Table A- 7 - Characteristics of the flow duration curve in section 4 ...... 123 Table A- 8 - Characteristics of the flow duration curve in section 5 ...... 124 Table A- 9 - Characteristics of the flow duration curve in section 6 ...... 125 Table A- 10 - Characteristics of the flow duration curve in section 7 ...... 126 Table A- 11 - Characteristics of the flow duration curve in section 8 ...... 127 Table A- 12 - Characteristics of the flow duration curve in section 9 ...... 128 Table A- 13 - Characteristics of the flow duration curve in section 10 ...... 129 Table A- 14 - Determination of the reservoir volume for different values of equipped discharge in section 2 ...... 130 Table A- 15 - Determination of the reservoir volume for different values of equipped discharge in section 3 ...... 131 Table A- 16 - Determination of the reservoir volume for different values of equipped discharge in section 4 ...... 132 Table A- 17 - Determination of the reservoir volume for different values of equipped discharge in section 5 ...... 133 Table A- 18 - Determination of the reservoir volume for different values of equipped discharge in section 6 ...... 134 Table A- 19 - Determination of the reservoir volume for different values of equipped discharge in section 7 ...... 135 Table A- 20 - Determination of the reservoir volume for different values of equipped discharge in section 8 ...... 136 Table A- 21 - Determination of the reservoir volume for different values of equipped discharge in section 9 ...... 137 Table A- 22 - Determination of the reservoir volume for different values of equipped discharge in section 10 ...... 138 Table A- 23 - Depth volume curve and depth area curve for the reservoirs in sections 1 to 10 ...... 139 Table A- 24 – Mean monthly discharge values in the station of Dala ...... 142 Table A- 25 – Flow duration curve in the station of Dala ...... 142 Table A- 26 - Flow duration curve in section 1 ...... 142 Table A- 27 - Number of hours of radiation for each month at various latitudes ...... 143 Table A- 28 - Reservoir analysis with the scenario C1 ...... 144 Table A- 29 - Reservoir analysis with the scenario C2 ...... 145 Table A- 30 - Reservoir analysis with the scenario C3.1 ...... 146 Table A- 31 - Reservoir analysis with the scenario C3.2 ...... 147 Table A- 32 - Reservoir analysis with the scenario C3.3 ...... 148 Table A- 33 - Reservoir analysis with the scenario C4 ...... 149 Table A- 34 - Reservoir analysis with the scenario C5 ...... 150 Table A- 35 - Reservoir analysis with the scenario C6 ...... 151 Table A- 36 - Reservoir analysis with the scenario C7 ...... 152 Table A- 37 - Reservoir analysis with the scenario C8 ...... 153 Table A- 38 - Reservoir analysis with the scenario C9 ...... 154 Table A- 39 - Reservoir analysis with the scenario C9 (Continuation - Totals) ...... 155 Table A- 40 - Reservoir analysis with the scenario C10 ...... 156 Table A- 41 - Reservoir analysis with the scenario C10 (Continuation - Totals) ...... 157 Table A- 42 - Reservoir analysis with the scenario C11.1 ...... 158 Table A- 43 - Reservoir analysis with the scenario C11.1 (Continuation - Totals) ...... 159 Table A- 44 - Reservoir analysis with the scenario C11.2 ...... 160 Table A- 45 - Reservoir analysis with the scenario C11.2 (Continuation - Totals) ...... 161 Table A- 46 - Reservoir analysis with the scenario C12.1 ...... 162 Table A- 47 - Reservoir analysis with the scenario C12.1 (Continuation - Totals) ...... 163 Table A- 48 - Reservoir analysis with the scenario C12.2 ...... 164 Table A- 49 - Reservoir analysis with the scenario C12.2 (Continuation - Totals) ...... 165 Table A- 50 - Reservoir analysis with the scenario C13.1 ...... 166

xv Table A- 51 - Reservoir analysis with the scenario C13.1 (Continuation - Totals) ...... 167 Table A- 52 - Reservoir analysis with the scenario C13.2 ...... 168 Table A- 53 - Reservoir analysis with the scenario C13.2 (Continuation - Totals) ...... 169 Table A- 54 – Analysis of a run of river type facility ...... 170 Table A- 55 - Reservoir analysis for the worst possible situations with the scenario C12.2 (Continuation - Totals) ...... 171 Table A- 56 – Reservoir analysis for the worst possible situation with scenario C12.1 ...... 172 Table A- 57 - χ2 verification test ...... 173 Table A- 58 - Typical values of the curve number in rural areas ...... 176 Table A- 59- Preliminary bill of quantities ...... 178

xvi LIST OF DRAWINGS IN APPENDICES II

Drawing 01 – Implementation of the facility in the site location...... 188 Drawing 02 – Pre study drawings: General layout of the facility, upstream and downstream views; profiles of the dam, profile of the adduction system; plan and profile of the powerhouse...... 189

(Both of these drawings are inserted in separated folders in Appendices II)

xvii

xviii LIST OF ABREVIATIONS AND ACRONYMS

GEA – Global Energy Assessment Mton – Mega tons of oil equivalent IEA – International Energy Agency TPES – Total Primary Energy Supply HPP – Hydroelectric power plant RoR – Run-of-river REMIPEG – Renewable Energy Market, Installed Power and Annual Energy Generation MPLA – Movimento Popular de Libertação de Angola (Popular Movement for the Liberation of Angola) UNITA – União Nacional para a Independência Total de Angola (National Union for the Total Indenpendence of Angola) GDP – Gross Domestic Product OPEC – Organization of the Petroleum Exporting Countries OEDC – Organization for Economic Co-operation and Development SADC – Southern Africa Development Community ENE – Empresa Nacional de Electricidade de Angola (National Electricity Company of Angola) eia – US Energy Information Administration MINEA – Ministry of Energy and Water GAMEK – Gabinete de Aproveitamentos do Médio Kwanza EDEL – Empresa de Distribuição de Electricidade ASTER GDEM V2 – Advanced Spaceborn Thermal Emission and Reflection Radiometer, Global Digital Elevation Model Version 2 SRTM – Shuttle Radar Topography Mission GRDC – Global Runoff Data Center CAPEX – Capital Expenditure OPEX – Operational Expenditure NPV – Net Present Value IRR – Internal Rate of Return GIS – Geographic Information System ISRIC – World Soil Information C – Runoff coefficient USSCS – United States Soil Conservation Service

QXXX – Discharge exceeded only XXX days per year γ – Specific weight η – Efficiency of the turbine MDDL – Minimum Drawdown Level MWL – Maximum Water Level

xix FRL – Full Reservoir Level USD – United States Dollar MW/km2 – MegaWatt per square kilometer of reservoir F(x) – Distribution Function HEC – Hydrologic Engineering Center HMS – Hydrologic Modeling System CN – Curve number

xx 1 INTRODUCTION

The future prospects for growth of the world's population and the expected socio-economic development determine, among other aspects, an increase in global energy needs.

The predictions of several analysts suggest that the fossil fuels will continue, in the medium term, to be the predominant source of energy. However, the global paradigm of energy dependence on fossil fuels and the associated global problems (such as the greenhouse gas effect, reduction of energy security, increase in air pollution at local and regional level with consequent health problems for world’s population, and the lack of universal access to energy services), determine considerable challenges to sustainability, in terms of investment in alternative and low carbon energy technologies as well as diversification of energy sources (GEA 2012).

According to a report data from the International Energy Agency in 2014, global energy supply increased from 1973 to 2012 of 6.106 Mton to 13.371 Mton (iea 2014). In Africa, in the same period, the total energy supply increased from 3.4 % to 5.5 % of the world Total Primary Energy Supply (TPES). According to the same source, in 1973 the hydroelectric power supply corresponded to 1.8 % of the total supply, and in 2012 the relationship between the supply of hydroelectricity and the total supply rose to 2.6 %.

In the KPMG Angola conference recap from 2013, the importance of widespread access to electricity was highlighted as a fundamental condition for economic growth and development of the country. In the same document, it is also evident that the actions performed by the Angolan Government in the energy sector will be directed to an expansion of the electricity network to the entire territory, with the purpose of using, in a sustainable and integrated manner, the unique natural features available in Angola, namely water, fossil and solar resources, resulting in a suitable combination of different energy sources supported in new technologies. When implemented, these actions are expected to improve the efficiency of the energy sector and the quality of living of the populations (KPMG Angola 2013).

According to the NEW ANGOLA’S ENERGY STRATEGY, regulated by the Presidential Decree N.º. 256/11, 29th September, a deep transformation of the Angolan energy sector is intended by strengthening their infrastructures and by establishing the main strategic guidelines for the sector. This transformation is implemented in two phases: a stabilization phase, which corresponds to the implementation of several initiatives with short and medium term impact; and the consolidation phase, which will lay the foundations for a major sector transformation, preparing it for an effective response to medium and long term needs. Furthermore, throughout the long term consolidation phase, it is predicted an increase in the energy generation supported by enhancing renewable energy sources, with a special focus in hydropower and, on a smaller scale, in wind and solar energies, as well as other endogenous resources.

Considering the importance of the energy sector to Angola, it was launched the challenge towards the development of a feasibility study for the implementation of a hydroelectric facility in Angola, more precisely in the Chiumbe River basin. The Chiumbe River is located along the provinces of Lunda Norte and Lunda Sul, in northeast of Angola. Therefore, the aim of this study is to define, along the Chiumbe River, the best location and optimal configuration, from a technical and economic

1 point of view, to build a hydropower facility with an installed capacity of 100 MW, which should be able to supply the city of Saurimo, the capital of Lunda Sul that has an estimated population of 200 000 inhabitants.

The report is organized in eight chapters. In the introduction (first chapter) the objective and motivation of the study are presented, as well as the structure of the report. In the second chapter is made a literature review on hydropower and its importance in renewable energy sources around the world. In the third chapter, the context in Angola is given including the description of the country’s geography, background and current situation, also, the Angolan energy matrix and energy needs are analyzed and an approach to the estimation of the hydroelectric potential is presented. Also in this chapter, the base data used in the study is described. The fourth chapter of the report describes the methodology that was followed in the development of this work and in the fifth chapter this methodology is applied to the case study and the results obtained are presented and discussed. The main conclusions and future developments are described in chapters 6 and 7 and, lastly, in the eighth chapter it is presented the list of references consulted to elaborate this report.

2 2 HYDROPOWER

2.1 HYDROPOWER GENERATION

The hydraulic power, or hydropower, is one of the oldest energy sources used by man, namely for irrigation and industry.

The hydroelectric power plants (HPP) traditionally use a natural or artificial head difference in a river. The flowing water is used to move the wheel of a turbine, generating mechanical energy, and finally that energy is converted into electricity by the generator installed in the powerhouse. The water is led to the turbines in the power plant trough hydraulic conveyance systems such as pressurized pipes, penstocks and/or canals. From the power house and after a voltage transformation, the electricity is carried out to the communities or to the national grid, by proper transmission lines.

After this process the water is returned to the river, so it’s considered a non-consumptive use and will continue to flow downstream remaining available as resource for men and environmental needs. In addition and for environmental protection downstream of the facility it must be considered an ecological discharge. This “reserved” discharge helps to protect the wildlife habitats downstream of the HPP and preserve the migration of the species with the construction of fish-passages in the facility.

Hydropower is a renewable and clean energy source based on simple and well-advanced technology that is easily updated in order to incorporate new developments. It is also a technology based on more than a century of experience. Hydropower today is an extremely flexible power technology with one of the best conversion efficiencies of all known energy sources.

The utilization of hydropower allows quick and controlled variations of production, enabling a number of advantages, such as frequency control and use of intermittent renewable sources (such as wind and biomass) being able to compensate with efficiency the fluctuations of generation of these sources. It also contributes to multiple uses of water, such as supply of drinking water, recreation, irrigation for agriculture, tourism and even transport. The reservoirs created by hydropower facilities allow an adaptation to climate changes, acting as a regulatory element in the case of excessive flow rates and supply element in times of drought.

Nevertheless, there is still room for further improvement by refining operation, reducing environmental impacts, adapting to new social and environmental requirements and developing more robust and cost-effective technological solutions (Ellabban, Abu-Rub, and Blaabjerg 2014). There is also the problem of influencing the cycle of rivers, with impacts on biodiversity and communities.

2.2 CLASSIFICATION OF HYDROPOWER PLANTS

Besides energy generation, water resources can be used in different ways for the society’s benefit, being that there’s always a rising demand from different social and economic sectors. Simultaneously the exploitation of water resources aims to obtain the maximum benefits while mitigating the natural hazards and environmental impacts.

3 So, besides the power generation other uses are generally incorporated in the HPP, making it a multipurpose facility. These uses can be arranged in two main categories (Schleiss 2008):

 Hydraulic facilities for water uses: The main purposes of these facilities are water storage and supply, irrigation and navigation.

 Hydraulic facilities for water protection: In this category, the main purposes can be divided in water treatment, drainage, flood control and protection against erosion.

In the present project the objective of the facility is only the production of energy, so the focus has been given to that particular use exclusively. The classification of hydropower plants can be based on different factors:

 Head: low (less than 50 meters); medium (between 50 and 250 meters) and high (with head greater than 250 meters), according to ESHA, 1994 in (Ramos and Almeida 2000);

 Exploitation and storage: daily (or seasonal) flow regulation which is called a reservoir type hydropower plant; without inflow regulation, this is called run-of-the-river type and is commonly applied to small hydropower plants.

 Conveyance system: pressurized system (penstock) and mixed circuit (canal and penstock);

 Powerhouse site: located inside or at the base of the dam or downstream of a diversion scheme. The utilization of diversion structures such as tunnels, canals, galleries or low pressure conduits makes it possible to achieve a higher net head. With this scheme, a small dam can be used with a long hydraulic circuit in order to take advantage of natural drop in the topography and increase the net head of the facility.

 Energy conversion mode: turbining; reversible pumping-turbining;

 Type of turbines: impulse (the wheel of the turbine is actuated by the water at the atmospheric pressure, the most common is the Pelton turbine), reaction (the turbine wheel is crossed by a flow under pressure, the most common types are Francis and Kaplan turbines) and reversible which can work in both directions, as a pump or a turbine (Quintela 1981);

 Installed capacity: Classification according to size as led to concepts such as ‘small hydro’ and ‘large hydro’, based in the installed capacity, measured in MW, as the defining criteria. Nevertheless, there is no worldwide definition regarding installed capacity. Various countries and groups of countries define small and large hydropower facilities differently. As an example, in Table 2.1 are presented some criteria for small-scale hydropower according to different locations, In Portugal, small-scale hydropower facilities are characterized by installed capacities lower than 10 MW.

4 Table 2.1 - Small-scale hydropower by installed capacity (MW) as defined by various countries (Kumar et al. 2011) Small-scale hydro as Country defined by installed Reference Declaration capacity (MW)

Brasil ≤ 30 Brazil Government Law No. 9648, of May 27, 1998

Canada < 50 Natural Resources Canada, 2009

China ≤ 50 Jinghe (2005); Wang (2010)

EU Linking Directive ≤ 20 EU Linking directive, Directive 2004/101/EC, article 11a, (6)

India ≤ 25 Ministry of New and Renewable Energy, 2010 Norwegian Ministry of Petroleum and Energy. Facts 2008. Norway ≤ 10 Energy and Water Resources in Norway; p.27 Sweden ≤ 1.5 European Small Hydro Association, 2010 US National Hydropower Association. 2010 Report of State USA 5 - 100 Renewable Portfolio Standard Programs (USRPS)

Regarding its operation, as stated before, hydropower plants can be divided in three categories: run-of-river (RoR), storage (reservoir) and pumped storage HPP.

The reservoir scheme uses a dam to create a reservoir which is used to regulate the outflow discharge; the dam also allows an increasing of the net head and, hence, the power generation for the same discharge. In a daily regulation scheme the power is generated according to the natural fluctuations of the daily demand, by storing the water in the reservoir at off-peak times (when the demand is lower) and discharging at peak hours. A seasonal regulation scheme is normally applied to larger reservoirs, where there is a need to store water in the rainy season and then discharge it in the dry season, allowing a constant energy supply throughout the entire year. The reservoir reduces the dependence on the variability of the inflow and its dimensions depend on the dam’s height, topography/landscape and hydrology of the watershed.

A RoR facility creates a reservoir which has a small ability to regulate the inflow discharge. In some cases this type of facility may include short term storage in order to adapt to the demand profile but the power generation will vary according to the river flow conditions. Therefore the power generation depends on precipitation and runoff, so there may have substantial monthly or seasonal variations that are directly related with the weather in the region and runoff parameters, such as soil type, soil coverage and evapotranspiration.

Finally, in a pumped storage facility the water is pumped from a lower reservoir to an upper reservoir, normally during off- peak hours while the energy is cheaper. The inverted flow is then used to produce energy during the daily peak-load periods. Although the energy losses in the pumping activity make this facility an energy consumer, it is able to provide large scale energy storage, in the form of potential energy. In fact, pumped storage are the largest-capacity form of grid energy storage available worldwide(Ellabban et al. 2014).

2.3 RENEWABLE ENERGIES AND SUSTAINABLE DEVELOPMENT

The world population is rising rapidly, notably in developing countries. According to a United Nations report in 2013, the world population of 7.2 billion is expected to increase by 1 billion in 12 years and reach 9.6 billion in 2050. Along with this

5 demographic growth, there is an increasing urbanization, which results in cities growing in number, population and complexity (United Nations 2013).

Energy is a vital input for economic and social development of any country. Without energy the whole structure of society as we know it would fall apart. As populations grow, the demand for energy increases more and more, reaching to a point when it becomes almost impossible to control the problems that arise from supplying this amount of energy using only traditional energy sources. Not only does this increasing demand place significant strains on the current energy infrastructures, but it can also potentially damage the environment, essentially because of the uprising emissions of gases that largely contribute to the global warming.

But problems with energy supply and use are not only related to global warming, there are also some other environmental concerns such as air pollution and acid precipitation, the depletion of the ozone layer, the destruction of natural forests, the problem of waste management, the increasing emission of radioactive substances and the global climatic change. That being said, if humanity wants to achieve a sustainable energy future by minimizing the environmental impacts and controlling the environment degradation, the issues described before have to be taken into account.(Dincer 2000)

Consequently, in the last years the focus has been turning to non-traditional energy sources, which are renewable in nature, and the concern about investing in this renewable energy sources as been increasing. This is bound to have less environmental effects and also the availability can be guaranteed. In addition there is the constant increase of fossil fuel prices. Investing in renewable energies allows the fulfilling of the common concept of sustainable development: “a development that meets the needs of the present without compromising the ability of future generations to meet their own needs”.

To evaluate the importance and the role of renewable energy sources in the global energy market, as well as the percentage for the main technologies in this sector, the latest REMIPEG (Renewable Energy Market, Installed Power and Annual Electricity Generation) report from 2014, was taken into consideration (Renewable Energy Focus 2014). This report presents an overview on the status of the renewable energy market through the end of 2013. According to the report, the total energy consumption worldwide in 2013 was about 170 PWh (Petawatts hour 1 PWh = 1015 Wh). In the same year, the total electricity generation worldwide was about 23 PWh, which represents almost 14 % of the total annual energy generation. From this 23 PWh, 22 %, so more a less 5 PWh, are produced using renewable energy sources with a total installed capacity of 1 658 GW.

The 5 PWh of electricity generated annually using renewable energy sources, represent 3 % of the total energy consumption worldwide, in that same year (Kleineidam et al. 2014).

The values observed follow the trends verified in the last decade. As said before, in this period the demand for renewable energy sources has been increasing as a result of environmental policies and economic related factors. Taking into account all the renewable energy technologies, the cumulative installed power capacity grew from 1 591 GW to 1 658 GW during the year of 2013.(Kleineidam et al. 2014)

6 2.4 ROLE OF HYDROPOWER IN RENEWABLE ENERGY SOURCES

In what concerns the renewable energy technology, hydropower leads the pack representing more than three times the cumulated capacity of the second largest contributor, the wind power, as it is presented in Table 2.2. The percentages of each renewable energy technology are presented in Figure 2.1 where it´s easy to understand the major role of hydropower in the renewable energy sector worldwide, with almost 67 % of the renewable market worldwide.

Table 2.2 - Worldwide installed power capacity of renewable energy technologies and estimated annual energy generation in 2013 (Kleineidam et al. 2014) Cumulated Installed New Installed Growth of Cumulated Estimated Electricity Renewable Energy Capacity in 2013 Capacity in 2013 Installed Capacity Generation in 2013 Type [GW] [GW] [%] [TWh/year] Hydropower 1103.8 39.9 5% 3704.9 Windpower 315.7 35.5 13% 683.0 Solar PV 134.7 36.3 41% 140.6 Solar CSP 3.8 1.2 56% 6.8 Biomass 88.0 4.3 5% 308 - 616 Geothermal 12.0 0.5 4% 73.0 World Total 1658.0 117.7 21% 4916.4 - 5224.4

66.6% Hydropower Windpower Solar PV 19.0% Solar CSP Biomass Geothermal 8.1% 0.7% 5.3% 0.2%

Figure 2.1 - Percentage of each energy renewable technology worldwide

Also, and as it is possible to observe in Table 2.2, the major projects created in 2013 (new installed capacity in 2013) were in Hydropower, Windpower and Solar PV. The highest growth occurred in Solar PV (photovoltaic) and Solar CSP (concentrator photovoltaic), although the initial values of installed capacity (in the beginning of 2013) were much lower than the ones presented for Hydropower and Windpower.

In Figure 2.2 is shown the regional distribution, in each continent, of the cumulated installed capacity, per renewable energy technology in the year of 2013. This allows a different perspective of the distribution of hydropower along the world. As already referred hydropower plays a major role in the renewable energy sources controlling almost 67 % of the market, followed by windpower with 19 %, less than 1/3 of the percentage controlled by hydropower. Solar Photovoltaic (PV) is the third largest contributor and Solar Concentrator Photovoltaic (CSP) is the lowest contributor.

7 700

600

500

Solar PV 400 Solar CSP 300 Geothermal

200 Windpower

Cumulated Capacity (GW) Capacity Cumulated Hydropower 100

0 Asia Europe North and South Oceania Africa Central America America

Figure 2.2 - Regional distribution of the cumulated installed capacity, of each renewable energy technology in 2013 (Renewable Energy Focus 2014)

As shown in Figure 2.2, hydropower is the most important renewable energy source in all the continents wherein in Asia, most significantly in China, it is by far the most important one. Only with hydropower, Asia exceeds the total installed capacity in Europe for all renewable energy sources considered. In the Table 2.3, it is presented the values of cumulated installed capacity and annual energy generation by hydropower. This table allows the verification of Asia’s domain in hydropower. It also introduces the values of annual electricity generation by hydropower in each continent, which reveals that in Asia the generation is more than double than it is in North America, the second largest producer.

Table 2.3 – Summary of the global hydropower market in 2013 (Renewable Energy Focus 2014) Cumulated Installed Installed Capacity Estimated Electricity Region Capacity 2013 2013 Generation 2013 [GW] [GW] [TWh/year] North America 194.1 2.2 728.4 South America 142.7 2.4 643.9 Europe 240.7 2.9 657.7 Asia 484.6 32.4 1512.8 Oceania 14.2 0.0 41.4 Africa 27.6 1.0 120.7 World Total 1103.9 40.9 3704.9

Also, as it possible to observe in Table 2.3, besides the fact that in Africa and Oceania hydropower is almost the only renewable energy source used at the moment (as it happens in South America), they present the lowest values of installed capacity and energy generation from hydropower, of all the continents.

8 In this section is also made a small overview of the main Hydropower facilities (some already finished and some under construction) in Brazil, which is located in South America at similar latitudes as Angola. This information is presented in Table 2.4.This overview is made in order to provide a framework and comparison parameters, and serve as baseline for possible hydropower facilities in Angola. Also in the Context in Angola chapter some HPP’s located in Angola are described, which is also a good comparison against the results obtained in this study.

Table 2.4 – Main Hydropower Facilities in Brazil

Installed Capacity Reservoir Area Facility Name River State of the Facility MW/km2 (MW) (km2) Belo Monte Xingu Under construction 11223 668 16.8 Tucurui Tocantins Operational 8370 3014 2.8 São Luiz do Tapajós Tapajós Planned 8040 729 11.0 Jirau Madeira Operational 3750 258 14.5 Santo Antônio Madeira Operational 3568 271 13.2 São Simão Alto Juruena Planned 3509 289 12.1 Chacorão Tapajós Planned 3336 616 5.4 Jatobá Tapajós Planned 2338 646 3.6 Teles Pires Teles Pires Under construction 1820 123 14.8 Salto Augusto Baixo Juruena Planned 1461 129 11.3 Serra da Mesa Tocantins Operational 1275 1784 0.7 São Manoel Teles Pires Under construction 746 53 14.1

In the table it is calculated the Megawatt (MW) of installed capacity per square kilometer (km2) of reservoir for each of the facilities described. This indicator is often used as a comparative measure between facilities, and also in order to decide about their feasibility. This indicator is an indicator of environmental efficiency, and the higher its value the better, since it means that less area is being flooded and more energy can be generated, since the installed capacity is bigger.

10 3 CONTEXT IN ANGOLA

3.1 GEOGRAPHY AND MAJOR RIVER BASINS

Angola is an African country with an estimated population of 24.14 million inhabitants, according to the World Bank in 2014.

Angola is located in the western Atlantic coast of southern Africa. The total area is estimated at 1 246 000 km2, 7 680 of which form the northern coastal province of Cabinda, isolated from mainland Angola. To the north, Cabinda is bordered by the Republic of Congo and to the east and the south by the Democratic Republic of Congo. The mainland Angola is bordered to the north and northeast by the Democratic Republic of Congo, to the east by Zambia, and to the south by Namibia, while the western border is formed by the Atlantic Ocean, as it is presented in the Figure 3.1.

Figure 3.1 – Angola’s boundaries and some of the main cities (Source: UNCS, ESRI, Natural Earth)

The Angolan territory is characterized by the extensive plateau areas of the interior and by the intense reliefs in the central area near the city of Huambo that descends to the Atlantic Ocean. A noticeable characteristic in the Angolan territory is the almost complete absence of natural lakes in its river system, a phenomenon that frequently occurs in Southern Africa. The river system of Angola can be divided into five main drainage basins that are represented in Figure 3.2, which gives the perception of the basins sizes as well as the differences in area between them, and they are also described in the following topics:

[1] The drainage basins of Western Angola, which are composed by the Cuanza (or Kwanza) River Basin and the Cunene River Basin. These two basins drain into the Atlantic Ocean and their catchment areas cover an area of about 500 000 km2 that represents 40 % of the total area of Angola. The described basins develop almost entirely within the Angolan boarders;

11 [2] The Congo River Basin (usually called Zaire in Angola), which has the second largest drainage basin in the world (behind the Amazonas), with a total area of 3 800 000 km2. About 290 000 km2, which represents 8 % of catchment area develops inside the boarders of Angola. This area corresponds to 23 % of the total area of Angola (Pettersson 2004);

[3] The Cuvelai River Basin that includes intermediate rivers in southern Angola and northern Namibia that drain to the Etosha Pan, a low-lying lake in Namibia without any outlet, as it is possible to observe in Figure 3.2. The area in Angola that drains to the Etosha Pan covers about 56 000 km2, which represents about 4.5 % of the total area of Angola;

[4] The Okavango River Basin that, like the Cuvelai drainage basin, drains to a low-lying area in Botswana with no outlet to the sea, the Okavango Delta. The area in Angola that drains to the Okavango, covers about 156 000 km2, which represents more a less 12.5 % of the total area of Angola;

[5] Finally the Zambezi River Basin, which drains into the Indian Ocean and crosses eight different countries. This river basin covers nearly 247 000 km2 in eastern Angola, which is equivalent to 20 % of its total area.

Figure 3.2 - Sothern Africa major river basins (Source: reliefweb, 02/02/2015)

3.2 CLIMATE

The climate in Angola is generally tropical, tempered by the sea and, but varying considerably with the altitude. Its geographical location, its morphology and the cold Benguela current are the three main factors that determine the climate characteristics in the country. The climate is more humid in the north region and drier in the south as well as near the coast. There are also some tropical deserted regions in the southwest that cover the cities of Benguela and Namibia. In the center region, particularly near the city of Huambo, the climate is mainly conditioned by the high altitudes.

12 Like the rest of tropical Africa, Angola experiences distinct, alternating rainy and dry seasons with precipitation close to zero in the summer. In the north, the rainy season may last for as long as seven months, usually from September to April, with perhaps a brief loosening in January or February. In the south, the rainy season begins later than it does in the north, starting in October and lasting until February.

Figure 3.3 – Mean annual rainfall in Angola (Rodrigues 2014)

In general, and as presented in Figure 3.3, the mean annual precipitation is higher in the north of the country. Although at any latitude, it tends to increase from the coast to the interior. As it is possible to observe in the figure, along the coast (close to the Atlantic Ocean) the precipitation values are the lowest in all the country, being that in some regions it is very close to zero. The highest values of mean annual rainfall occur in the north and northeast regions of the country, as well as in the regions with higher values of altitude. In these regions the annual precipitation varies between 1 400 mm and 1 700 mm.

On the other hand, the areas with lowest values of precipitation are also the areas with more variability of the precipitation through the years, as it is presented in Figure 3.4. This variability decreases from the coast to the interior. In these coastal areas with high variability, the precipitation occurs mainly in the months of March and April.

In what concerns the temperature, along the country, it tends to fall with distance to the equator and with altitude. On the other hand, it rises with the proximity to the Atlantic Ocean. The lowest values of mean annual temperature are verified in higher altitudes of the interior. Near Luanda, the average annual temperature is close to 26°C, but it is under 16°C near Huambo on the temperate central plateau. The coldest months are normally July and August (in the middle of the dry

13 season), when frost may sometimes form at higher altitudes. This is easily deduced by revising the mean monthly values of temperature in each region of the country.

Figure 3.4 – Coefficient of variation of annual rainfall (Rodrigues 2014)

The evapotranspiration varies with altitude and latitude, and also with the proximity to the sea, presenting average values between 3 and 2.5 mm per day. The average annual relative humidity is very low in the south of Angola, being less than 50 % close to the city of Lubango and in the southern end of the Cuvelai basin.

In conclusion, the coastal areas are dryer and experience higher temperatures and the regions at high altitudes of the interior are more humid and experience the lowest values of temperature. The evapotranspiration increases mainly with the latitude.

3.3 CIVIL WAR

Angola is still rebuilding its country after a long period of civil war that lasted for 27 years, which caused profound marks in the Angolan society until now. This conflict was mainly due to the different political ideologies that arise from different ethnic groups during the rebuilding of the country, immediately after Angola’s independence from Portugal. The fight between the Popular Movement for the Liberation of Angola (MPLA), led by José Eduardo Dos Santos, and the National Union for the Total Independence of Angola (UNITA), led by Jonas Savimbi, began in 1975 and lasted until 2002. Finally, in 2002 peace was brought to Angola. The civil war has generated many severe economic and social consequences in Angola. This conflict

14 was considered one of the longest and most violent of history, causing more than 1.5 million deaths and internally displacing more than four million citizens, which represent one third of Angola’s total population at the time.

The United Nations estimated that after the 27 years of civil war, approximately 80 % of the population lacked access to basic medical care, about two thirds of the population did not have access to drinking water, 30 % of Angolan children died before the age of five, raising the infant mortality rate to one of the highest in the world and the average national life expectancy was less than 40 years of age (New York Times 2003). Other socio-economic consequences that came from the war were the fact that agricultural production, oil extraction and gold mining virtually ground to a halt, a generation of Angolans missed out on education being that the government still struggles to reintegrate them back into society and also the lack of skilled labor existent in the country.

During this period, most of Angola's infrastructures were destroyed, mainly because of an excessive abuse of landmines. In order to isolate some cities, several railways, bridges and roads were shattered. It is estimated that the military forces placed more than 15 million landmines in the Angolan territory (Furley 2006). This problem still affects the country and places a lot of constraints in the reconstruction of infrastructures and development of economic sectors, such as agriculture. In this context, years of poverty and slow socio-economic recovery were predicted for the Angolan people, strengthening the gap between social classes.

3.4 ANGOLA’S ECONOMY AND CURRENT SITUATION

Angola’s economy is replete with contrasts and contradictions. On the one hand, with its abundance of natural resources, the country has been registering record levels of growth; on the other hand it remains one of the poorest countries in Africa. On paper Angola’s potential is noticeable. In 2008, the country surprised many when it temporarily overtook Nigeria as Africa’s biggest oil producer. Its GDP (Gross Domestic Product) has been in double figures for the several years over the last decade. The countries oil sector is booming and interest in its diamond-mining potential is reported to have reached record- breaking levels. Infrastructure development projects have also been thriving, with roads, bridges and railways being restored at an incredible speed. Unsurprisingly, foreign interest in Angola with respect to all these sectors is intensifying and the outlook seems very bright for Angola (African Business 2012).

Yet Angola’s economic progress is precarious and it remains one of the poorest countries in the world. Indeed in a World Bank’s poverty head-count ratio, it was found that nearly 55 % of the population lives on less than 1.25 $ per day. The richest fifth of the population holds almost two thirds of the country’s total wealth. Accusations of corruption are frequently levelled at the country’s government, let by the long standing president José Eduardo Dos Santos.

Angola is also a recovering economy, as explained in the previous topic (chapter 3.3) its infrastructure, production and labor pool were left almost annihilated after the civil war. In some ways, the determination with which Angola has bounced back since the conflict has been remarkable. In other ways, there have been some serious rehabilitation failures. All of this makes it tricky to elaborate the economic analysis of the country. Both delusive optimism, infused with utopian visions of Angola standing alongside South Africa and Nigeria as an African superpower, and gloomy despair that Angola is yet another African country doomed to be defined by poverty and corruption are depending on what figures are invoked (African Business 2012).

15 Considering the traumas that the country’s economy has been exposed to in the recent past, its current growth level is all the more impressive. In 2005, Angola has experienced an economic “boom”. It has moved from the disarray caused by a quarter of century of war to being the second fastest growing economy in Africa and one of the fastest in the world. Its GDP growth rate was of 18 % in 2005 and it would rise above 20 % in the following years, 2006 and 2007. Such growth has been overwhelming due to Angola’s exports of its most lucrative natural resource: oil. The government has invested heavily in oil exploration and infrastructure in order to boost production and capacity. Its enthusiasm is now paying dividends: in 2011 oil accounted for 90 % of export revenues and represented about 80 % of the country’s GDP. Using its new oil-based fortune, Angola has been able to make considerable strides in terms of rebuild their infrastructures.

In the last years the foreign interest in Angola has been increasing. China, in particular, has been pumping millions into the country in form of loans and credit lines in an attempt to gain favored access to Angola’s oil reserves. Such financial assistance has mainly focused on public investment projects in infrastructures, agriculture and telecommunications. The bilateral trade between Angola and China makes Angola China’s largest African trade partner. Recently European countries, such as the UK and Germany have also been eager to step up their relations with Angola, has have Brazil. In 2007 Angola join the organization of the petroleum exporting countries (OPEC).

Yet, the drawbacks of Angola’s reliance on revenues from oil exports became clear during the global crisis of 2008-2009, when slowing demand from oil-consuming countries caused a huge reduction of the average price per barrel. GDP growth collapsed in Angola, dropping to 2.4 % in 2009 and 2.3 % in 2010. This being said, any projections when it comes to Angola’s GDP growth prospects for the years to come are inevitably volatile, being ultimately connected to the variations of the oil prices. Experts warn that Angola’s economy is dangerously undiversified and overly dependent on oil for capital. It is, however, true that, to a very limited degree, other non-oil aspects of the Angolan economy are also anticipated to grow over the next few years. Unsurprisingly perhaps, the one non-oil aspect of the economy that is perhaps set to flourish the most in coming years also comes within the extractive category – the mining sector, namely diamonds (African Business 2012).

In many ways the country has a long way to go. Take the country’s agricultural sector. Before the war Angola was self- sufficient in almost all food crops and exported various products, including banana, tobacco, sisal and maize. It was also the fourth largest coffee producer in the world. At the moment, a large proportion of food is imported and only 10 % of the country’s cultivable land is being used for agriculture.

In the last years, Angola’s oil dependent economy is set to slow as the oil prices collapse. The impact of low oil revenues will be reflected in the growth of Africa’s second biggest oil producer at the moment. Many projects might not happen and that will have a big impact on the companies and Angola’s economy (The World Bank 2015).

Probably the most challenging task that Angola faces over the next years is creating a skilled labor pool. The overall proportion of skilled workers is very low, according to the OECD and the implications that this has in terms of boosting non- oil aspects of the economy and encouraging foreign firms to invest in both industry and agriculture is massive. There have been some attempts to tackle this issue – a major three-year government plan to boost technical education levels was announced in 2005, which included the construction of 35 technical institutes with Chinese support in the form of capital. Yet, according to the OECD, the curriculum needs updating and there are no known plans to train new teachers. There are also nowhere near enough vocational training centers in Angola to meet demand. Worryingly, alleged corruption is also reportedly depriving Angola of the capital investment that the non-oil sectors of its economy need to develop.

16 Worryingly, alleged corruption is also reportedly depriving Angola of the capital investment that the non-oil sectors of its economy need to develop. Angola is awash with advantages; from its natural resources stockpile to its enviable demographics, the country has several pillars of strength which it will be able to lean on when propelling itself towards further economic growth. Experts assess that impressive growth should materialize in coming years, as long as the prices of its major export, oil, remains high. Yet, the country’s economy is dangerously undiversified and faces some daunting macro- economic challenges. With both political and economic power still heavily concentrated in the hands of very few in Angola, perhaps it is fair to assert that whether these will be tackled depends, more than anything, on the mettle and appetite for change of its government.

3.5 DESCRIPTION OF THE CURRENT ANGOLAN ENERGY MATRIX AND OBJECTIVES FOR THE FOLLOWING YEARS

Angola does not present a well-developed energy panorama. This comes as an impeditive factor for the economic development in the country and improvement of the populations living conditions. Inefficient organization, insufficient infrastructures and distribution systems make it almost impossible to satisfy the population’s energy needs.

The energy matrix is the quantitative representation of all available energy resources in a given territory, region or country. In 2011, according to the US Energy Information Administration (eia), the main primary energy sources in Angola are the solid biomass & waste, petroleum, hydropower and natural gas. Figure 3.5, presented below, illustrates the division of the Angolan energy consumption according to their primarily energy sources. Approximately 55 % of the energy consumed in Angola came from solid biomass & waste and about 33 % came from oil; the remaining 12 % were distributed between natural gas and hydropower.

55.00% 5.00% 7.00%

Solid Biomass and Waste Natural Gas Hydropower Petroleum

33.00%

Figure 3.5 – Angola’s energy matrix in 2011 (Source: eia – Energy Information Administration, 24/01/2015)

Also in 2011, and according to the World Bank, Angola produced more energy than it consumed, which was about 14 % of their total production and, therefore, exported abroad, which makes sense since that, as explained, the country’s economy is overly depend on the oil exports. Angola produces about 11 % of the total energy produced by Sub-Saharan Africa, gaining the third position in the larger energy producers in the continent, behind Nigeria and South Africa. On the other hand, in the past years Angola consumed on average only 3 % of the continent’s total energy consumption, getting substantially below the average of the continent.

17 The fact that the Angolan economy is overly dependent on oil caused the emersion of an action plan with medium and long term results. This plan is the NEW ANGOLA’S ENERGY STRATEGY, regulated by the Presidential Decree N.º 256/11, 29th September (2011). The main goal of this plan is to quadruple the existing energy supply, by making the best possible use of the endogenous resources and allocating the most efficient technologies.

For this reason, it is expected that the Angolan energy matrix suffers severe changes, including a strong growth in production and consumption of renewable energy through hydropower, wind and geothermal plants. Thus, the energy matrix will tend to be increasingly more balanced and sustainable, regarding the energy sources used in the country. Concerning the hydropower sector, it is expected that in 2017 the total installed capacity will be almost 10 times higher than it was in 2010.

Angola's has also plans to commercialize more of its natural gas resources. Natural gas fueled generation is likely to become increasingly important in the coming years. There have been discussions about building gas-fired facilities near the country's oil operations, in part to support industry there, but firm proposals have yet to emerge.

Thereafter, another goal of the Angolan government for 2017 is to increase the annual average energy consumption per capita in Angola in order to match the African consumption in 2007 (increase from 190 kWh per capita to 640 kWh per capita). For 2025, the goal is to catch up to the emerging countries annual average consumption of 2 000 kWh per inhabitant, which represents an increase of 8 500 MW in the country’s installed capacity since 2010. This will result in a more balanced and sustainable energy matrix. In Figure 3.6 it is presented the evolution described in this paragraph. As foreseen in the above mentioned program, Angola aims to improve the power supply in the country, but also become an exporter of energy in Southern African development community (SADC) (Government of Angola 2013).

10 000

8 500 MW

2 700 MW kWh/Inhabitant/Year 2 000 640 190

Developed Emerging Africa Angola Countries Countries

Figure 3.6 – Prediction for the energy consumption per capita in Angola for the next years

The lack of access to energy is due to several weaknesses in the system not only at the production level but also at the distribution level, mainly: the lack of infrastructures to transport electricity, high fees and costs, independent electrical systems inside the country, system instability, outdated cartography and difficulties in regulating voltage (Balão 2012).

As already explained, in recent years the economic development of Angola has been pronounced. Major investments in infra-structuring the country were made, particularly in buildings, hospitals and roads but as well as in the water and energy sectors. In large cities the energy demand has increased significantly and is considerably higher than energy supply. The country's electrification rate is currently about 30 %, and is expected to reach 60 % in 2025, supported on heavy investments

18 in building new power plants and distribution networks and also in the rehabilitation of infrastructure and equipment already existing (Stauber 2014).

The energy sector in Angola is majority-owned by public companies that belong to the Ministry of Energy and Water (MINEA). The major companies are ENE (Empresa Nacional de Electricidade de Angola) with relevance in generation, transmission and distribution, GAMEK (Gabinete de Aproveitamentos do Médio Kwanza) which is the authority in the Kwanza River and EDEL (Empresa de Distribuição de Electricidade) responsible for electricity distribution in Luanda. Some private companies in the extractive industries of oil and gas built their own hydropower plants to run their operations. Angola is planning to open the energy market for private investors in the near future (Stauber 2014).

The Energy and Water Ministry, at a conference about clean energy sources in Angola, highlighted some of the measures to improve the structure of the electric system (production, transport and distribution). It intends to give penetration space for independent producers but keep the electricity transmission as a state monopoly. It also intends to geographically distribute the existing capacity and create a single distribution entity, with the objective of connecting the independent electric systems.

3.6 HYDROELECTRIC POTENTIAL OF ANGOLA

As already referred, Angola intends to significantly invest in its energy sector in the coming years. Recently, a lot of work has been implemented with the objective of increasing the hydroelectric potential of the country. As part of this, a considerable share of the enhanced energy generation is supposed to be from hydropower.

Angola has an estimated hydropower potential of 150 000 GWh/year, of which 80 000 GWh/year is the average energy and 65 000 GWh/year is considered to be firm and feasible potential, in three of the five main river basins: Kwanza in the north, Catumbela in the central region and Cunene in the south. This hydropower potential represents 18 000 MW of potential installed capacity. About 150 hydropower plants could be built, not counting with mini and micro plants, considering those plants to have an installed capacity of less than 2 MW (Hydropower and Dams 2013).

In 2011, Angola generated about 5.5 million kWh with an estimated installed capacity of 1 700 MW, of which, around 60 % was contributed by hydropower facilities. So, until now, Angola has only exploited about 4 % of its hydropower potential. From the 5.5 million kWh of energy generated, coming from hydro and fossil fuel sources, more than 70 % (about 71 %) was generated at the country's hydroelectric facilities, primarily from hydroelectric dams on the Kwanza , Catumbela, and Cunene Rivers (Hydropower and Dams 2013).

3.7 ANGOLA’S ELECTRIC SYSTEM, ANALYSIS OF THE CURRENT INSTALLED CAPACITY AND MAJOR PROJECTS IN ANGOLA

The Angolan national electric system is divided into five independent groups, as presented in Figure 3.7: Cabinda (A); Northern System (B); Central System (C); Southern System (D) and finally the Eastern System (E), which includes the provinces of Lunda Norte and Lunda Sul, where the Chiumbe River develops. In 2013, as shown in Figure 3.7, there was a pattern of low installed capacity available per capita, in all the five groups. The Northern System is connected to the Kwanza river basin and is the country's largest system, serving the country's capital, Luanda. The Central and Southern Systems are linked to the Catumbela and Cunene river basins, respectively. Southern and Eastern systems presented the lowest installed

19 capacity available per capita, in all five groups (0-10 W/capita) and the Northern System presented the highest (95 W/capita). In 2013 the national average available power was about 40 W per inhabitant.

Figure 3.7 – Available power per capita in Angola in 2013 (Steiger-Garção and Reis 2013)

In 2015 a small increase was verified in each group, but the most market increases were in groups (A) and (B), as it is represented in Figure 3.8. In this year the average available power per inhabitant was 101 W, being that groups (C), (D) and (E) are far below the average in that year. For 2017 it is expected an increase of the available power per capita in all groups that will raise the national average to 192 W per inhabitant, although the increase will be smaller in Group E and significantly higher in the Northwest Angola (groups (B), (C) and (D)), as presented in Figure 3.9. For group (A) it is not predicted any increase between 2015 and 2017.

Figure 3.8 - Available power per capita in Angola in 2015 (Steiger-Garção and Reis 2013)

Figure 3.9 – Estimated available power per capita in Angola in 2017 (Steiger-Garção and Reis 2013)

20 Finally in the years after 2017 it is predict a major increase in the available power per capita, raising the total available power to 786 W per inhabitant. The increments per sector are presented in Figure 3.10. There will also be made improvements in the national electric grid in order to allow energy transfers from the center region to the south and eastern regions. This being said, the systems will be independent but connected between themselves.

Figure 3.10 - Estimated available power per capita in Angola after 2017 (Steiger-Garção and Reis 2013)

In Table 3.1 it is presented the available power increments in each of the 5 groups as well as the facilities that contribute to this increase. A considerable percentage of the facilities presented in this table are hydropower facilities, since hydropower is Angola’s big bet for energy generation, in the next years. The Soyo facility in group (A) is a combined cycle facility. Some of the other facilities, besides hydropower, are diesel, gas and thermal plants.

As it can be observed in the table presented before, the major hydropower facilities existing in Angola are:

 Cambambe: an arch concrete dam located in the Kwanza River, in the Kwanza Norte region with an installed capacity of 780 MW;

 Capanda: a concrete gravity dam located in the Kwanza River, in the province of Malange and with an installed capacity of 520 MW;

 Lomaum: located in the province of Benguela, in the Catumbela River and with an installed capacity of 37 MW;

 Gove: an embankment dam in the Cunene River, in the province of Huambo and with an installed capacity of 60 MW;

 Matala: located in the Cunene River, in the province of Huila with an installed capacity of 40 MW

 Luachimo: located in the Luachimo River, in the province of Lunda Norte with an installed capacity of 36 MW;

 Chicapa: located in the Chicapa River, in the Lunda Norte province with an installed capacity of 18 MW;

 Chiumbe-Dala: a run-off-river type facility located in the province of Lunda Sul, in the Chiumbe River that supplies the city of Luena, in the Moxico province, with an installed capacity of 12 MW;

21 Table 3.1 – Major power facilities existing in Angola and facilities predicted for the next years (Steiger-Garção and Reis 2013)

Group A Energy Production (MW) Population 1937100 2013 2015 2017 2017+ Soyo 70 500 750 1700 Total A 70 500 750 1700 Available Power (W / hab.) 36 258 387 878 Group B Energy Production (MW) Population 7334200 2013 2015 2017 2017+ Cambambe I 180 180 180 180 Cambambe II 380 780 780 Capanda 520 520 520 520 Láuca 400 2070 Caculo Cabaça 2047 Total B 700 1080 1880 5597 Available Power (W / hab.) 95 147 256 763 Group C Energy Production (MW) Population 6106900 2013 2015 2017 2017+ Queve/Longa/N'Gunza 774 6284 Lomaum 37 37 90 2000 Cuemba 4 4 4 Camacupa 4 4 4 Total C 37 45 872 8292 Available Power (W / hab.) 6 7 143 1358 Group D Energy Production (MW) Population 3508800 2013 2015 2017 2017+ Gove 60 60 60 60 Jama ya Omo 78 78 Jama ya Mina 227 227 Matala 40 40 40 Calueque 30 Tombwa 100 Luandege 225 Bayes 180 Cutato das Ganguelas 30 Total D 60 100 405 970 Available Power (W / hab.) 17 28 115 276 Group E Energy Production (MW) Population 1722400 2013 2015 2017 2017+ Luachimo 36 36 36 Chiumbe-Dala 12 12 12 Chicapa 18 18 18 18 Chicapa II 18 Total E 18 66 66 84 Available Power (W / hab.) 10 38 38 49

22 It is desirable to increase the use of other energy resources to produce electricity, although the contribution of hydropower production tends to be higher in the coming years. The major contributions will be from Cambambe II, which will have an increase of the total installed capacity by raising the dam and implementing the second powerhouse with 700 MW of installed capacity. It should also be noted the construction of three major hydropower facilities, which are Laúca, a RCC dam already under construction in the Kwanza River that will have a total installed capacity of 2070 MW; Caculo Cabaça also in the Kwanza River, which is predicted to have an installed capacity of 2047 MW and finally Catumbela that will provide a major increase after the predicted construction works.

3.8 CASE STUDY AND BASE DATA

The collection of data for Angola was a very challenging task due to lack of information available in the country, more specifically the lack of on-site measurements made for the location of the case study.

As explained earlier in the text, the case study is a feasibility study of a hydropower facility in the Chiumbe River. The river is located in the provinces of Lunda Sul and Lunda Norte, in eastern Angola, and is a tributary river of the Kasai River which belongs in the Congo River basin. The purpose of the facility is to supply the city of Saurimo with an estimated population of 200 000 inhabitants.

The input data that was needed for this study was, in a first stage, topography information and hydrology data. For the topography information, besides Google Earth (that was considered in parallel with the other topography information) a numerous of elevation datasets are available online and for this study two of those datasets were used:

 Raster elevation data from the project Advanced Spaceborn Thermal Emission and Reflection Radiometer (ASTER) Global Digital Elevation Model Version 2 (GDEM V2). This is a 30 m resolution elevation raster map, so it means that for a 30 per 30 meter square there is a value of altitude. These data cover 99 % of the land surface from 83 degrees north latitude to 83 degrees south latitude. Version 2 of these data was released in October 2011 and is a significant improvement over the initial data release. In order to download the DEM (Digital Elevation Model) data from ASTER is necessary to access the Reverb website (https://reverb.echo.nasa.gov Date: 4/10/2014).

 SRTM version 2 (Raster elevation data from Shuttle Radar Topography Mission) elevation data, which is a 90 meter resolution elevation raster map that covers most of the land surfaces of the earth. In this second version, most voids have been filled in, lake surfaces have been corrected, and coastlines have been properly defined and aligned. These data are available at the USGS Earth Explorer site (http://earthexplorer.usgs.gov/ Date: 4/10/2014). Care should be taken when using SRTM data in areas with accentuated reliefs, as there are still data voids in some of these areas, which is not the case of the Chiumbe River basin.

In a first approach the ASTER elevation data was used for the analysis of the topography. But when obtaining the longitudinal profile, the ASTER data showed values that did not make sense, presenting the river moving up downstream in slopes with more than 7-8 % in some regions, which is not possible and does not correspond to the reality. Faced with this situation the river profile was calculated using different methods but the values still didn’t make sense.

The problem prevailed, so it could be a problem of the elevation data used. So, the SRTM elevation data was used. With this raster elevation data, the profile obtained revealed much better values and a very good correlation with the Google earth

23 elevation data. In fact, according to a study made in the UTM (Universiti Teknologi Malaysia) for a watershed in Malaysia, for flat terrains, which is the case of the Chiumbe River basin, Google Earth shows a better correlation with SRTM (R2 in the order of 0.80) than it does with ASTER (R2 of 0,24) (Rusli, Majid, and Din 2014). Also, according to (Matos 2014) in chapter four of its Thesis, the SRTM information shows better results than the ASTER information, and also with a better correlation with Google Earth, for the case study of the Zambezi River Basin.

The lack of information was heavily noted when searching for hydrological data. There is a huge lack of recent information regarding the water resources in Angola, which was even more noticed for the case study region, nevertheless some information was obtained. For the hydrology studies, the information obtained was:

 Satellite precipitation: a 0.25 per 0.25 degree squares with precipitation series from the first of January 1998 to the 31 of December of 2013 that covered the whole region of the case study. The series of precipitation have daily values, so for each series the total number of values is 365*16=5 840 values. This information was provided by José Pedro Matos in the product TRMM 3B42 v7a, which aggregated the data to daily values. Then the information was extracted using the MATLAB R2014a software.

 Specific discharge data from the document “Quality check - historical hydrological data in Angola” by the Norwegian Water Resources and Energy Directorate, in three hydrometric stations close to the Chiumbe River basin (Bjoru 2004).

 Runoff data from a hydrometric station in the Kasai River basin, downloaded from the GRDC (Global Runoff Data Center) website. This data is an eight year-long series of mean annual discharge (GRDC n.d.).

Some maps concerning the Angolan territory were also found online, which were used for the characterization of the basin, namely the soil coverage, vegetation and typology, as well as analyze the geology. These maps are described in the following topics:

 Phytogeographic map of Angola. Source: http://4cce.org/photos/186-DOC-Mapa-1939-Carta-Fitogeografica-deAngola .jpg Date:5/10/2014

 Generalized soil map of Angola. Source: http://eusoils.jrc.ec.europa.eu/esdbarchive/eudasm/africa/images/maps/downl oad/afrcgndsda.jpg Date:5/10/2014

 Volumes I and II of the Soil Atlas of Africa: (European Comission 2013a) and (European Comission 2013b)

 Geology map of Angola elaborated by the author Heitor de Carvalho, “Laboratório de Estudos Petrológicos e Paleontológicos do Ultramar”, based in a compilation of geology studies made until 1974.

This was the information collected in the beginning of the project. In a more advanced stage of the study, more information regarding the topography and hydrology was obtained. In what concerns the topography the program PlexEarth was used, which is an AutoCAD extension and allows obtaining contour lines from the Google Earth elevation data. This is important since it is more information that can be compared with the ASTER and SRTM elevation data described in the previous topics. The hydrology data was a series of mean monthly discharge values measured in an hydrometric station in the Chiumbe River, near the city of Dala.

24 4 METHODOLOGY

4.1 INTRODUCTION

The methodology followed in this research is divided into three sequential stages. The first stage includes the screening of possible locations for the hydropower facility resulting in a wide range of alternatives and a comparison between those alternatives. In second stage a feasibility study is made for the selected alternative and the correspondent solution is defined. First it is made an optimization of the chosen alternative, regarding the dam height, the equipped discharge and the number of turbine-generator groups. Then another analysis is made, concerning a preliminary study for the hydraulic structures, an analysis on floods and of the construction materials and the definition of a preliminary bill of quantities. The third stage is an economic analysis based on the information obtained in the stages one and two. This process is explained in the flowchart presented in Figure 4.1 and for each stage it is made a more complete explanation in each section of this chapter.

DEFINITION OF A PRE STYDY DRAWINGS SOLUTION

1 STAGE 1: SCREENING OF POSSIBLE LOCATIONS POSSIBLE DAM TYPES HYDRAULIC STRUCTURES BILL OF QUANTITIES

1.1 CONSTRUCTION 1ST LOOP FLOOD ANALYSIS MATERIALS COST ESTIMATION

3 SELECTION OF THE STAGE 3: ECONOMIC COLLECTION OF DATA RESERVOIR ANALYSIS OPTIMAL CONFIGURATION ANALYSIS

2 PARAMETERS FOR SITE STAGE 2: FEASIBILITY STUDY DEFINITION OF SCENARIOS LOCATION FOR THE SELECTED OPTION WORK PLANNING

AVAILABLE WATER NEVESSARY RESERVOIR SELECTION OF THE BEST TOPOGRAPHY ANALYSIS ECONOMIC INDICATORS RESOURCES VOLUMES LOCATION

1.2 DEFINITION OF COST ESTIMATION FOR CALCULATION OF 2ND LOOP CONCLUSIONS AND ATERNATIVES EACH ALTERNATIVE INDICATORS FUTURE WORK

CHARACTERIZATION OF ALTERNATIVES Figure 4.1 – Methodology followed in this study

4.2 STAGE 1: SCREENING OF POSSIBLE ALTERNATIVES

In the first stage of this study (1), the objective was the definition of the best location for the implementation of a hydropower facility, in the Chiumbe River. This stage was divided in two different sub stages (or loops).

In the first loop (1.1), a definition of the best possible locations for the facility was elaborated, along the Chiumbe River and within the borders of the Angolan territory. For the implementation of a hydropower facility in a section of a river, there are several parameters that need to be taken into account and analyzed, in order to make the best decisions concerning the

25 location of the facility. These parameters were defined and then taken into consideration when analyzing the topography of the Chiumbe River basin. When analyzing the topography of the catchment area, it was also made a characterization of the basin, namely its physiographic characteristics, vegetation, soil typology and climate.

With the alternatives defined, it was considered a second loop (1.2) with the purpose of comparing them and selecting the best one, which means obtaining the best location for the hydropower facility. To compare the alternatives, it was made their characterization, namely the areas of the basins controlled by each section as well as the length of the main water course, the altitude of each section, the possible location of the powerhouse that would take most advantage the topographic difference as well as the length of the conveyance system and the head losses, the distance to Saurimo and the total of accesses. It was also considered the available water resources in each section. The precipitation data was analyzed, the flow duration curves were calculated and the necessary reservoir volumes for each section and different dam heights were determined. Finally and in order to compare the different sections, it was made a cost estimation and the calculation of indicators, such as the cost per installed capacity, the cost per GWh of energy generated per year and the MW of installed capacity per square kilometer of reservoir. When the comparison of alternatives was finalized, from the 10 initial possible sections it was chosen the best one, for the implementation of the hydropower facility.

4.3 STAGE 2: FEASIBILITY STUDY OF THE SELECTED OPTION

After deciding on the best location for the implementation of the facility, it was made an analysis of the reservoir. It is very important to analyze the behavior of the reservoir through the whole year and calibrate parameters such as the equipped discharge, the dam height and the number of turbines used in order to allow seasonal regulation and to take the most advantage out of the facility, more specifically generate the maximum energy per year. After this analysis, the optimal configuration for the facility was defined, namely the previously described parameters.

The selected alternative was the center of a more detailed study. After the definition of the best location for the construction of a hydropower facility, within the Chiumbe River limits, as well as the best configuration for that facility, a feasibility study was conducted in order to determine whether or not that facility would be feasible, from a technical and environmental perspective.

As shown in Figure 4.1, first it was made an analysis on floods and construction materials available in the case study region. Then the hydraulic structures were analyzed, more specifically possible types for those structures and their displacement in the facility. It was also made a pre-dimensioning of the spillway, being calculated its length and the maximum water level. The objective when analyzing the construction materials is to best decide which type of facility would be the best option. Of course that there is a connection between the decisions concerning the hydraulic structures and the dam types.

Finally and with those decisions made, some pre-dimensioning drawings and sketches were elaborated. These drawings were very important in order to estimate the quantities associated with the construction of this hydropower scheme, and for the definition of a preliminary bill of quantities. For the elaboration of the drawings, some assumptions and pre dimensioning studies were made, regarding the turbines, the powerhouse, the water intake, adduction circuit and bottom outlet. Also some assumptions and hypothesis were considered for the costs. With the bill of quantities defined, it was made the cost estimation for the facility. This cost estimation is elaborated with more detail than the previous ones, since the parameters regarding the hydropower facility were optimized and the calculation of quantities was better substantiated.

26 4.4 STAGE 3: ECONOMIC ANALYSIS

After analyzing the technical and environmental feasibility of the hydropower facility, an economic analysis needs to be made in order to determine if the construction of that facility would compensate, from an economic point of view. Of course that in the Angolan actual context and within the framework of this thesis, the main purpose of the facility is not to generate profit but to supply the population of Saurimo, aiming towards the development of the city and improvement of the population’s living conditions. Although, in order for a project of this dimension to go forward, a lot of capital needs to mobilized and invested, so if the project reveals to be profitable it’s much easier to collect those investments. The described economic analysis was elaborated using the costs obtained in the previous analysis, which are based on the quantities calculated and the unitary costs defined.

The effectiveness of an economic analysis as a decision tool of whether or not the investment is profitable depends on the accuracy of the project’s costs and benefits estimates. These estimates are not easy to reach, especially in the first stages of design where some of the scheme characteristics are only preliminary defined. So the economic analysis made in this study as a limited validity, since that some of the quantities and costs considered are based on hypotheses. Nevertheless it allows to have a founded idea of what is expected, monetarily speaking, from the implementation of this facility.

Apart from the costs and revenues, to complete the economic analysis, the number of years for the completion of the project had to be defined, as well as the discount rate and interest rate. The discount rate depends on the state of the economy, the risk that involves the investment and the future rate of inflation, which is considered constant during the projects useful live. The discount rate is directly related to the present value concept: a given monetary unit is more worthy than in the future, through the years, this situation generates different “appetencies” to transfer money from the present to the future and vice- versa, this “appetencies” can be expressed in terms of discount rates, being that the higher the discount rate, lower is the value of year X in the present day (Ramos and Almeida 2000). The interest rate varies considerably for each situation depending on the loan contract negotiation and risk profile; it is sometimes renegotiated after the project’s completion, although it was considered constant trough the project’s useful live. In order to obtain a sensitivity analysis, there were considered and tested several values for the discount rate and the interest rate in the economic analysis, being defined six different scenarios.

To define the number of years for the completion of the project it was developed a timetable for the works associated with the construction of the facility. The evaluation of the profitability of the hydropower facility can be based on economic indexes or parameters. Among these parameters the next four ones will be used in evaluation of the profitability: net present value (NPV), benefit/cost ratio (B/C), internal rate of return (IRR) and payback period (T).

28 5 CASE STUDY AND RESULTS

5.1 STAGE 1: SCREENING OF POSSIBLE ALTERNATIVES

5.1.1 Zoom in to the Location

As already referred in the text, the case study of this research is the Chiumbe River. In Figure 5.1 is presented a schematic representation of the river and its basin within the borders of Angola. The river continues to flow in to the Democratic Republic of the Congo until it reaches the Kasai River but, in this study, only the Angolan part of the river has been analyzed. The Kasai River is part of the Congo River basin which is the second largest river basin in the world and the biggest one in Africa, with a total area of 3.7 million square kilometers. The Chiumbe River basin is located in the Northeast of Angola in the provinces of Lunda Norte and Lunda Sul. The river begins in the south of Lunda Sul, between the cities of Alto Chicapa and Dala and flows close (almost parallel) to the rivers Luachimo and Chicapa, also located in the northeast of Angola.

Figure 5.1 - Location of the Chiumbe River Basin in Angola (UNCS, ESRI, Natural Earth. Adapted with Quantum GIS)

5.1.2 Parameters for Site Location

The site location for a hydropower facility is mainly conditioned by head and flow requirements, since this are the parameters that most influence the power potential and consequently the energy output. In a preliminary stage, the hydroelectric potential of the river is taken into account as well as the quantity of works and cost estimation associated with each possibility, more specifically each of the locations considered.

The hydroelectric potential is dependent on the available water resources for energy production, namely the available discharge, which increases with the catchment associated with each possible location. Also the net head strongly influences this potential, so locations where it is possible to take advantage of the topographic difference in order the increase the total

29 head are more attractive. The quantity of works depends on many factors, but at this stage it was analyzed mainly the topography.

Depending upon the topographic characteristics of the available site, the hydropower scheme can have high or low head, which is directly related with the dam’s height. High head schemes, for the same equipped discharge, can be more expensive because the required hydraulic equipment’s and construction works (e.g. dam, powerhouse, turbines, valves and others) will be higher. So, in a first screening of the possible locations, one of the most important aspects to considerer was the transversal profile of the topography (e.g. cross section) where the facility is supposed to be inserted. From this point of view, the best sections are the ones that present banks with big slopes that make it possible to create dams with small crest lengths, obtaining smaller dam volumes.

Geotechnical characteristics can also represent major constrains for the type and alignment of the conveyance system as well as the type of dam and its size. The decisions regarding the dam type, more concretely whether it will be a concrete or an embankment dam, are made taking into consideration mainly the geotechnical characteristics, such as the soil stability and the nature of the streambed of the river, and the available construction materials in the location.

Another important factor is the proximity to the main operational roads, since the higher the proximity less will be the cost of accesses to the facility, and of the national grid extend. It is also important to considerer the existence of protected natural areas, as well as populations that can be affected by the construction of the hydropower facility.

5.1.3 Topography Analysis

5.1.3.1 Definition of the Basin

To analyze the topography, the Quantum GIS software was used. Quantum GIS is a freeware program and has very similar functionalities as ArcGIS. The input data for the program were the elevation maps described in chapter 3.8. Based on the elevation data and using the functionalities of the program, namely the GRASS plugin, more specifically the watershed analysis functions, the Chiumbe River basin was defined, as well as all the water courses and the Chiumbe River itself. After this process the basin and the water courses were exported to Google Earth to confirm the approximation between the generated files and the satellite images.

With the Chiumbe River defined as well as its basin, an elevation map of the Chiumbe basin was created. In the elevation map it was easy to understand that the altitudes vary between 1 400 meters in the source and 600 meters near the border between Angola and the Democratic Republic of Congo. The basin has a total area of 20 649.7 km2 and the length of the main water course is 682.6 km. To calculate these values, the Chiumbe basin and its water courses were projected from the WGS-84 ellipsoid to the Albers projection. This conic projection was first tested for Angola by calculating the area of the Angolan territory and then comparing it with its real value, and the projection system revealed itself a very good projection for the measurement of areas.

30 The longitudinal profile of the river was obtained using the SRTM elevation data and is presented in Figure 5.2. This profile might be a little misleading since the length of the river is considerable and the horizontal scale has 25 km intervals. Looking at the profile it’s noticeable the big fall in the beginning of the river. Immediately upstream of this drop is where the Chiumbe- Dala hydropower facility is located.

1400

1300 River Profile Chiumbe-Dala small hydro 1200

1100

1000

Altitude (m) Altitude 900

800

700

600 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 Distance (km) Figure 5.2 - Chiumbe River longitudinal profile

The 12.5 MW Chiumbe-Dala facility is located near the city of Dala and supplies the city Luena, which is the capital of the Moxico province. It is a run-of-river type facility, that dominates a catchment area of 2 100 km2 and has a total head of about 60 meters. The hydro power station is located at a downstream end of a rapids section. Along the river it is possible to notice other interesting topographic differences and in some sections small rapids. Altought the section where the Chiumbe-Dala facility is inserted apears to be, at a first glance, one of the most interesting locations for the implementation of a hydropower facility, since the topographic difference is considerable, on the other hand the catchment area dominated by this section presents a small area, which means fewer available water resources for energy production.

5.1.3.2 Characterization of the Basin

After the definition of the main elements of the Chiumbe River basin in the software, it was made a characterization of the basin and five topics were covered: the hydrographic network, geomorphological characteristics, the soil coverage and vegetation, the soils typology and finally the climate.

In Table 5.1 is presented a summary of the main characteristics of the hydrographic network. The length of the main water course from the source till it reaches the border between Angola and the Democratic Republic of the Congo is 682.6 km. With a maximum altitude of 1 370 m and a minimum altitude of 640 m, the river is characterized by a mean slope of 0.11 %. This is a very low value since the area of the case study is very flat, being that the provinces of Lunda Norte and Lunda Sul are located in a plateau area, typical of the interior regions of the Angolan territory.

Table 5.1 – Characterization of the hydrographic network of the Chiumbe River basin Lenght of the main water course (km) 682.6 Maximum altitude (m) 1370 Minimum altitude (m) 640 Mean slope (%) 0.11

31 The characterization of the Chiumbe River hydrographic basin is presented in Table 5.2, namely the physiographic characteristics, as well as two important indicators to characterize the basin’s shape. The basin presents a total area of 20 649.7 km2 and a perimeter of 1 672.7 km.

Table 5.2 – Characterization of the hydrographic basin of the Chiumbe River

Area (km2) 20649.7 Perimeter (km) 1672.7 Compactness index 3.28 Shape factor 0.044

The compactness index makes it possible to analyze the basins shape since it indicates how close the basin is to a circumference with the same area of the basin, being that for a perfect circumference the shape factor equals 1. The more irregular is the shape of the basin, the higher will be the value of the compactness index. The referred index is calculated based on the expression below, where P and A represent the perimeter and area of the basin, respectively.

푃 퐶 = 0.282 (1) 퐼 √퐴

The shape factor is the ratio between the average width and the length of the main water course and it can be calculated using expression (2), where A is the value of the basins drainage area and L is the length of the main water course.

퐴 푆 = (2) 푓 퐿2

The shape factor expresses the tendency for the occurrence of flash floods. For lower values of the shape factor, the basins are narrower and the tendency for flash floods is smaller since the concentration time of the basin is higher.

Based on the values in Table 5.2 for the coefficients described, it’s easily concluded that the Chiumbe River basin is a very narrow and elongated basin, as it is shown for example in Figure 5.1, and there is a low probability for the occurrence of flash floods due to its high concentration time.

After analyzing the physiographic characteristics of the basin, the soil coverage and vegetation was taken into consideration. The provinces of Lunda Norte and Lunda Sul are characterized by their dense and green forests, following the interfluves or the sources of the rivers. In the region there is predominance of wooded savannas and some dry forests.

To analyze the soil coverage in more detail it was used the phytogeographic map of Angola combined with some information from google earth. The phytogeographic map of Angola is from 1939, when Angola was still a Portuguese colony and was created with a scale of 1:2 000 000, covering the entire Angolan territory. Using the Quantum GIS software, the map was adapted to the basin region and this is presented in Figure 5.3. Although the map is quite old, along with recent satellite images of the region, accessed with Google Earth, it gives an idea, minimally founded, of the vegetation and soil cover in the area of the watershed under study.

Once the described map was analyzed, it was concluded that the northeast region of Angola more specifically the provinces of Lunda are characterized by semi desert, grassland savanna and deciduous forest (woodland savanna). With the support of the created map and using the Quantum GIS functionalities, the percentages that each soil cover occupies in the basin were obtained. These values are presented in Table 5.3.

Figure 5.3 – Phytogeographic map of Angola adapted to the Chiumbe River basin

Table 5.3 - Soil coverage/vegetation in the Chiumbe River basin Vegetation % Occupied in the Basin Forest / savanna 35% Grove / Savanna / Woodland 35% Open Forest 25% Dry Woods 5%

To characterize the soil typology it was used the Generalized soil map of Angola, mentioned in the input data, and the first two volumes from the Soil Atlas of Africa (European Comission 2013a), (European Comission 2013b), in order to add more detail and accuracy to the map, since that this a more recent document and presents more detail than the referred map.

The part of the Soil Atlas of Africa that contains the Angola region corresponds to pages 114 and 115 of the Atlas and its adaptation to the case study area, more specifically the Chiumbe River Basin is shown in Figure 5.4. The legend is found in page 64 of the document, and the entrances that matter to the case study were selected and are presented in Figure 5.5.

By analyzing these documents, it’s easily understood that the main soil types in Angola are Ferralsols and Arenosols. There can also be noted also some Cambisols near the coast and Gleysols in small quantities. Based on the presented information, Table 5.4 was obtained, in which is presented the percentages of each soil type in the Chiumbe River basin.

Figure 5.4 - Adaptation of the Soil Atlas of Africa for the region in the case study using the Quantum GIS software

Figure 5.5 – Legend from the Soil Atlas of Africa

Table 5.4 – Percentage of each soil type in the Chiumbe River basin Type of Soils % Occupied in the Basin Ferralsols 35% Arenosols 63% Gleysols 2%

According to ISRIC - World Soil Information (ISRIC n.d.), the main characteristics of the ferralsols and arenosols are the following:

 Ferralsols: are deep (200 cm as a reference value), intense weathered soils with diffuse or gradual horizon boundaries that are normally red or yellow in some cases. They have week macrostructure, strong microstructure and friable consistence, making them easily crumbled and easy to work. With high percentages of clay, they have similar pore volume and mechanical characteristic as light textured soils. Ferralsols have good permeability, are well drained but may in times be droughty because of their low available water storage capacity. Because of their great soil depth, good permeability and stable microstructure make ferralsols less susceptible to erosion than other intensely weathered red tropical soils.

34  Arenosols: have a texture which is loamy sand at least to a depth of 100 cm. In this 100 cm of soil surface they present less than 35 % of rock fragments. Due to their coarsely texture they hold more water than finer soils and the infiltration is much faster than in clay soils.

Finally, to characterize the climate, in particular the mean annual temperature and mean annual precipitation, three meteorological stations were used. For a better understanding of the climate in the entire basin, the meteorological stations used were: the station of Dala in the south of the basin, the station of Saurimo in the middle and the station of Lucapa in the north. The mean monthly values of precipitation and temperature are presented in Figure 5.6 and Figure 5.7, respectively.

250

Saurimo 200 Dala Lucapa 150 100

Precipitation (mm) Precipitation 50 0 Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec.

Figure 5.6 – Mean monthly precipitation values for Saurimo, Dala and Lucapa

22 20 Saurimo 18 Dala Lucapa

Temperature(ºC) 16 14 Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec.

Figure 5.7 - Mean monthly temperature values for Saurimo, Dala and Lucapa

The mean annual precipitation is very similar in the entire basin, although it slightly increases from the south to the north. The humid season starts in September and finishes in April, and then the dry season starts with monthly values of precipitations close to zero. The mean annual values of precipitation are between 1 300 mm and 1 400 mm.

The mean annual temperature increases from the south to the north as we get close to the equator. The yearly variations are more marked in the south than they are in the north of the basin, where temperatures are very similar the entire year and around 23 ºC. The coolest months are June and July and lower values of temperature occur during the dry season, a typical behavior of tropical hot humid climate.

5.1.4 Definition of Alternatives

Once the basin was analyzed, the next objective was to obtain the best possible sections in the Chiumbe River to build a hydropower facility. In order to find these sections two different approaches (screenings) were used.

35 In a first screening the sections with higher natural topographic difference in the less possible length were searched for, by analyzing the river profile already defined. This parameter is very important since it will increase the net head for the same dam height, which means more power generation. After this first phase five sections were selected. In the second screening, the goal was to find places with more attractive cross sections, which means higher bank slopes and less volume for the dam, as well as a smaller length of the dam’s crest. Again from this phase, five more sections were defined leaving the total number of possible sections in 10. These sections are represented on the Chiumbe River basin map in Figure 5.8.

Figure 5.8 - Representation of the alternatives 1 - 5 in the Chiumbe River basin map

It was also made a representation of the 10 selected sections in the river longitudinal profile. This representation is presented in Figure 5.9. With these two types of representation it is possible to compare the chosen locations in terms of altitude and catchment areas controlled by each section. Since the sections are situated in very distinct locations and the drainage areas associated with each one of them are also very different, a hydrodynamic curve of the river was defined and the sections were represented in that curve. This curve is a representation of the altitudes versus the drainage areas above those altitudes and it’s represented in Figure 5.10. This allows a different perspective when comparing the different locations.

36 River Profile 1400 Chiumbe-Dala HPP 1300 Section 1 Section 2 1200 Section 3 Section 4 1100 Section 5 1000 Section 6 Section 7

Altitude (m) Altitude 900 Section 8 800 Section 9 Section 10 700

600 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700

Distance (km) Figure 5.9 - Representation of the possible sections in the longitudinal profile of the river

1300 Hydrodinamic Curve Section 1 1200 Section 2 Section 3 1100 Section 4

Section 5 1000 Section 6 900 Section 7

Section 8 Altitude (m) Altitude 800 Section 9 Section 10 700

600 0 5000 10000 15000 20000 25000 Area (km2)

Figure 5.10 - Hydrodynamic curve of the Chiumbe River

The hydrodynamic curve provides an idea of the increasing hydropower potential from each section to the other since it shows the increasing in drainage area which is directly related to the runoff and discharge. As shown in Figure 5.10, there is a big difference, in terms drainage area, between sections 6, 7 and 8 from section 1 and an even bigger difference from sections 2, 3, 4, 9 and 10 in relation to section 1. Section 5 is the one with a higher drainage area since is located more downstream on the river and almost includes the whole basin area within the Angola territory. Finally and as it is possible to notice in Figure 5.10 from sections 7 and 8 to section 1 there is a big increase in the drainage area for a small decrease in the elevation. This is due to the fact that section 1 is located immediately downstream of a confluence, making the drainage area increase almost to the double.

5.1.5 Characterization of Alternatives

For the section described earlier, the river basin was defined and the area and length of the main water course were calculated, allowing the definition of the drainage area controlled by each section. Table 5.5 shows a characterization of the main parameters associated with each alternative.

37 Table 5.5 - Characterization of sections Section ID 1 2 3 4 5 6 7 8 9 10 21º 06' 21º 06' 21º 05' 21º 02' 21º 07' 20º 39' 20º 58' 20º 59' 21º 08' 21º 05' Longitude 36.00'' E 53.10'' E 42.00'' E 09.98'' E 13.03'' E 00.00'' E 40.80'' E 09.60'' E 29.40'' E 24.00'' E Coordinates 09º 39' 08º 50' 08ª 42' 08º 14' 07º 38' 10º 39' 09º 55' 09º 52' 08º 57' 08º 38' Latitude 24.37'' S 48.30'' S 32.40'' S 09.23'' S 37.37'' S 21.60'' S 48.00'' S 58.80'' S 30.24'' S 48.84'' S Basin area (km2) 9412 12536 12767 13974 19351 3820 5149 5249 12192 12907 Physiographic Main water course (km) 332.4 444.3 463.2 528.3 615.6 182.7 286.9 292.5 428.9 471.3 characteristics Altitude (m) 960 850 820 770 690 1070 1010 1000 860 807 Mean slope (%) 0.12 0.12 0.12 0.11 0.11 0.16 0.13 0.13 0.12 0.12 Altitude (m) 940 830 800 760 680 1070 1000 990 860 800 Power Plant Lenght from the source (km) 334.7 449.3 465.7 530.6 615.8 183.0 288.1 292.9 429.0 471.6 location Topographic difference (m) 20 20 20 10 10 0 10 10 0 7 Conveyance Lenght (m) 3.06 6.49 3.27 3.06 0.29 0.37 1.60 0.52 0.08 0.48 system Head losses (m) 6.13 12.98 6.53 6.12 0.58 0.75 3.19 1.04 0.17 0.97 Distance to Saurimo (km) 78 119 129 173 236 114 71 70 111 135 Connections Total of accesses (km) 22.1 63.7 54.6 5.2 19.5 62.4 16.9 11.7 71.5 54.6

As a hypothesis at this stage, the power plant was assumed to be located downstream of the facility in a location that would take most advantage of the river beds natural topographic difference. In the region of some of the locations the slope of the river bed is very low and a long distance would have to be considered in order to use that head. In this process, the head losses would be too big to compensate the cost of a long hydraulic circuit. In these situations, the powerhouse is located at the “foot” of the dam, as it happens in section 6 and section 9, being that only the dam height contributes to the net head. To calculate the head losses in this preliminary stage it was assumed a unitary loss of two meters per kilometer. The distance to the city of Saurimo is measured in a straight line and the total for road access is calculated considering the nearest roads to the locations, shown in Google Earth.

Also the transversal profile was determined in each section, through the same process used for the definition of the river profile. In Figure A- 1 to Figure A- 5 of the Appendices I, the transversal profiles of the sections 1 to 5 are presented. In the definition of these first five sections, only the natural drop of the river bed was taken into account. As a consequence, some of the sections display a transversal profile that is not the most appropriate to build a hydropower facility because they present a very wide section. This would result in enormous volumes of construction materials and very big lengths of the dam’s crest in sections 2, 3 and 5. The cross sections of the locations that resulted from the second screening (sections 6 to 10) are presented in Figure A- 6 to Figure A- 10 of the Appendices I. As it is possible to observe, in these last figures, the cross sections present banks characterized by higher slopes and the area of the cross section is much smaller than in most of the sections obtained from the first screening. After determining the transversal profiles in each section, the dam volumes were calculated for the case of a concrete dam. At this stage of the project it was not yet decided on the dam type, so to calculate the dam volumes it was considered a concrete dam. It should be noted that the volume of materials associated with a concrete dam is much smaller than it is for the case an embankment or rockfill dam. Of course that the cost of the concrete is higher, but at this stage the main objective is to make a comparison between the sections defined so the dam type is not relevant.

To calculate the dam volume, a typical and simplified cross section was assumed for each case. The typical concrete cross section considered for the dam is presented in Figure A- 11 of the Appendices I. The calculation of the dam volume was made for each section and for different dam heights, in order to obtain a wide range of possibilities and allow a more complete comparison between them. In a first stage, dam heights of 10 m, 20 m, 80 m and the heights that close the topography were considered. This last height is a parameter only to give an idea of the maximum value of the head and

38 volume of the dam that could be obtained in each section. An algorithm was created allowing the automatized calculation of the volume for different dam heights in the 10 sections, based on the transversal profiles and typical cross section considered for the dam. It was also calculated the length of the dams crest, the reservoir areas and volumes obtained for the different dam heights.

All the quantities, including the dam volumes, were majored in 30 % to account for possible errors in the measurements, although when comparing different possibilities this is not important. To determine the reservoir volume associated with each dam height, the Quantum GIS software was used, since it allows to obtain the depth-volume curves in the different sections. After analyzing the values there were noticed accentuated differences between the dam volumes for each section as well as in the reservoir areas and volumes.

Finally, using the Google Earth software, an analysis of the affected areas by the insertion of the facility was made. This analysis shows that apparently no populations would be affected by the insertion of a hydropower facility in each of the selected sections and there would not be any need for reallocation. The section 5 is located near small areas used for agriculture.

5.1.6 Available Water Resources for Energy Production

5.1.6.1 Analysis of the Precipitation Data

The precipitation data available for this study was a 16 year-long series of precipitation covering the case study region. For this region it was generated a 0.25 degrees per 0.25 degrees square grid, and for each square there is a 16 year-long series of precipitation data. The series of precipitation are composed by daily values, so for each series the total number of values is 5 840 as already explained in the base data (chapter 3.8). This data format is not the most common one in which the precipitation data is measured in pluviometric stations located at certain coordinates or provided in the isohyet format, so the conventional approach of the Thiessen polygons or the isohyetal method could not be used.

In order to obtain the rainfall values in the catchment areas controlled by each of the 10 selected sections, a weighted average was considered, making it possible to obtain a series of 16-year rainfall for each of the 10 catchment areas, controlled by each of the 10 sections defined. Following this process, 10 series of 16 years-long precipitation were hence obtained. To do this, the Quantum GIS software was used in order to calculate the area that each 0.25 by 0.25 square occupies in each basin. Dividing the calculated areas by the total area of the basin, the percentage (i.e. the influence) that each square occupies in the basin was obtained. A schematic representation of the satellite precipitation (average of the monthly values for the 16 year-long series) in the Chiumbe River basin is presented in Figure 5.11.

Figure 5.11 – Satellite precipitation in the Chiumbe River basin (Mean monthly values)

The complete series of precipitation are not presented in the present report, since it is an enormous series of values. Instead, the mean monthly values for each year and for each basin are presented, as well as the mean annual values. The mean monthly values are presented in Table A- 1 of the Appendices I, and the mean annual values in each basin are presented in the Table 5.6 below.

Table 5.6 - Mean annual values of precipitation (mm) in each catchment area

SECTION ID 1 2 3 4 5 6 7 8 9 10 Chiumbe Characterization 1998 1359 1317 1315 1306 1252 1410 1393 1391 1320 1314 1228 Average 1999 1340 1330 1329 1327 1353 1398 1370 1367 1331 1329 1370 Average 2000 1375 1313 1311 1313 1319 1390 1402 1397 1316 1310 1338 Average 2001 1568 1531 1531 1552 1574 1562 1562 1562 1533 1532 1581 Humid 2002 1396 1383 1383 1390 1398 1343 1369 1369 1383 1383 1426 Average 2003 1349 1344 1341 1343 1358 1311 1328 1329 1348 1341 1374 Average 2004 1348 1397 1399 1410 1431 1371 1367 1368 1395 1400 1437 Average 2005 1445 1434 1431 1420 1397 1482 1457 1455 1438 1430 1406 Average 2006 1437 1485 1485 1484 1508 1450 1425 1425 1486 1484 1522 Average 2007 1646 1694 1693 1702 1740 1562 1610 1610 1695 1693 1744 Humid 2008 1042 1012 1009 1012 994 1097 1068 1067 1017 1010 1007 Dry 2009 1318 1290 1289 1296 1302 1323 1319 1317 1292 1288 1312 Average 2010 1143 1158 1160 1166 1185 1144 1120 1121 1154 1162 1187 Average 2011 1302 1301 1302 1312 1305 1256 1266 1269 1299 1303 1302 Average 2012 1216 1220 1220 1219 1223 1137 1170 1174 1218 1221 1230 Average 2013 966 1035 1040 1046 1090 885 914 917 1026 1041 1105 Dry Average 1250 1328 1327 1331 1339 1320 1321 1321 1328 1328 1348 -

40 In the bigger catchment areas, like the ones defined by sections number 4, 5 or even the entire Chiumbe River basin, the mean annual precipitation values are higher than they are in smaller ones since they include areas closer to the equator where the precipitation is higher. Nevertheless the mean annual values of precipitation are much similar in all the basins. In Table 5.6 is also made a classification of each year of the series as humid, dry or average year, considering the average value of the entire series and the standard deviation.

5.1.6.2 Runoff Data

Once the rainfall values were obtained for the catchment areas controlled by the 10 sections in study, there was the need to obtain the runoff values in those same catchment areas. The problem was the fact that at this stage, no measurements of runoff or discharge were found for the catchment areas in question. In order to obtain the runoff in the catchment areas, a coefficient between the total precipitation (TP) and the precipitation that generates runoff (PGR) had to be calibrated and the lack of data to calibrate it turned out to be a problem. This coefficient accounts for the precipitation losses such as the infiltration, surface retention, and evapotranspiration.

푃퐺푅 퐶 = (3) 푇푃

The only available data was the specific discharge values in three hydrometric stations and some discharge measurements in a station downstream in the Kasai River downloaded from GRDC (Global Runoff Data Center), as explained in section 3.8 of this study. This was the data used for the definition of the coefficient.

In a first approach the GRDC data was used. Based on the coordinates of the hydrometric station its catchment area was defined in Quantum GIS. After the definition of the catchment area and following the same process used for the Chiumbe River basin and for the 10 sections defined, the weighted average for the satellite precipitation series was made and a 16 year-long precipitation series was defined. Then by comparing the discharge data (that was converted to runoff data) available in the hydrometric station with the average values of the precipitation data in the catchment area, the C coefficient was calibrated. In Table A- 2 of the Appendices I, it is presented the information concerning the hydrometric station used, namely its location, coordinates, catchment area, mean annual values of stream flow (i.e. mean annual discharge) and runoff. As showed in Table A- 2, the section is called Port-Francqui located in the Kasai River which is a tributary of the Congo River. The eight year-long series of mean annual values are presented in Table 5.7.

The catchment area defined and controlled by the hydrometric station is presented in the Appendices I, in Figure A- 12. In this figure it is possible to understand the difference in the basins size. The catchment area defined by the GRDC hydrometric station has an area of 232 560 km2 and the Chiumbe River basin as total area of 20 649.4 km2, which represents approximately 9 % of the Kasai River basin. Also in Figure A- 13 is presented a map of the satellite precipitation in the catchment area controlled by the hydrometric station (mean daily values).

41 Table 5.7 – Mean annual values of the eight year-long series in the Port-Francqui hydrometric station

Mean Annual Mean Annual Mean Annual Year Discharge (m3/s) Volume (hm3) Runoff (mm) 1951 2252.4 71032.9 305 1952 2146.4 67688.7 291 1953 1887.8 59533.2 256 1954 2001.9 63131.8 271 1955 2080.8 65620.4 282 1956 2370.5 74757.5 321 1957 2296.2 72411.8 311 1958 1816.3 57279.2 246 Average 2106.5 66431.9 286

By comparing these average values, namely the mean annual runoff, with the average mean annual values from the satellite precipitation series in the catchment area controlled by the GRDC station (Port-Francqui), the runoff coefficient is estimated. The mean annual precipitation in the catchment area defined by the GRDC station was estimated and it’s equal to 1384.5 mm. In Figure A- 13 of the Appendices I, it is presented schematically the mean daily values of satellite precipitation in the catchment area controlled by the hydrometric station. Finally, the runoff coefficient obtained:

286 퐶 = = 0.206 (3.1) 1384.5

This method has several limitations, mainly the fact that the basins considered have very different areas, and also the fact that the basins characteristics are very different from each other. Another limitative hypothesis is that it’s being assumed that the coefficient is the same for the entire year, which does not correspond to the reality. In fact in the dry season it will be smaller since the soil is dry and the infiltration will be higher and in the humid season it will be higher. Although and as an approximation, this value of the coefficient was considered to be the same in the Chiumbe River basin.

The second approach took into consideration the specific discharge in the hydrometric stations located near the Chiumbe River. To account the influence that each station holds in the Chiumbe River Basin, the Thiessen polygons method was used. The stations used are found in the “Quality check - historical hydrological data in Angola” document (Bjoru 2004) and are presented in Figure 5.12. The stations are Chiumbe Dala in the Chiumbe River, Cassai Ponte in the Kasai River and Chicapa Saurimo in the Chicapa River. The values of the specific discharge and runoff are presented in Table 5.8.

Table 5.8 – Hydrometric stations and specific discharge value

Hydrometric station Chicapa Saurimo Chiumbe Dala Cassai Ponte max 11.1 9.2 12.8 Specific discharge (L/s/km2) min 10.3 7.7 10 max 0.4 0.3 0.4 Specific runoff (hm3/km2) min 0.3 0.2 0.3

Figure 5.12 – Location of hydrometric stations

The specific discharge values were converted to specific runoff, as presented in the previous table, and compared with the mean precipitation in the Chiumbe River basin. The value of precipitation is 1 348 mm as already presented in Table 5.6, and it corresponds to 1.348 hm3 / km2. The values for the runoff coefficient (C) were calibrated and are presented in Table 5.9. This second approach had the same kind of problems as the one used before, namely because the coefficient (C) determined is the same for the whole year. Table 5.9 – Runoff coeffient values

Hydrometric station Chicapa Saurimo Chiumbe Dala Cassai Ponte

max 0.26 0.22 0.30 Runoff Coefficient min 0.24 0.18 0.23

Considering the Thiessen polygons approach, almost all the basin is influenced by the Chicapa Saurimo station and the rest is influenced by the Chiumbe Dala station. Although the Chicapa Saurimo hydrometric station is conditioning according to the Thiessen polygons approach, it is located in the Chicapa River while the Chiumbe Dala is located in the Chiumbe River, so it was considered 70 % for the Chiumbe Dala station and 30 % for the Chicapa Saurimo station in the definition of the runoff coefficient. In Table 5.10, it is presented the maximum and minimum values for C, considering the two hydrometric stations referred. The value obtained in the first approach is actually very similar to the ones obtained with the specific discharge method. Table 5.10 – Runoff coefficient in the Chiumbe River basin max 0.23 Runoff Coefficient min 0.20

43 This value was compared with some typical values for the runoff coefficient used in the rational formula. This is also an approximation since the rational formula is used to obtain peak discharge values that occur during extreme rainfall events and is recommended to be used in small watersheds. So, normally this value is higher than the runoff coefficient. The typical values for the C coefficient used in rational formula are presented in the Table A- 3 according to the slope of the watershed, soil use and return period. Also in Table A- 4 it is presented a similar table in which the soil type is taken into account. The four soil groups are identified as A, B, C, and D. The classification of a given soil into one of these USSCS (United States Soil Conservation Service) groups can be based on a description of the soil characteristics or in infiltration rate for the soil. The descriptive characteristics for the four soil groups are presented in the following topics:

 Group A: Deep sand, deep loess and aggregated soils (a loess soil is an non-stratified soil deposit formed by the accumulation of sediments);

 Group B: Shallow loess; sandy loam;

 Group C: Clay loams; shallow sandy loam; soils low in organic content; soils usually with high percentage of clay;

 Group D: Soils that swell significantly when wet; heavy plastic clays; certain saline soils.

According to the USSCS classification, the predominant soil type in the Chiumbe River basin should be something between group C and group B. Based on Table A- 3 the runoff coefficient should be 0.25 for a return period of 2 years and considering an undeveloped surface covered by pasture and for flat terrain, with a watershed mean slop of less than 2 %.

Considering that, in the Chiumbe River basin, the main soil coverage is woodland savanna and open forest, that the mean slope is 0.11 % and the soil group is something between group B and C, the correspondent value in Table A- 4 would be between 0.15 (average value considering forest and meadow in soil group B for slope smaller than 2 %) and 0.19 (average value considering forest and meadow in soil group C for slope smaller than 2 %). Considering the values estimated for the runoff coefficient, as well as the approaches made in this chapter, the runoff coefficient considered for the Chiumbe River basin was fixed in 0.21. As already mentioned, along this process a lot of limitations and simplifying assumptions were considered that should be revised and better founded. Also, for the whole year, the coefficient should not be considered the same. It only makes sense to consider one value when analyzing an extreme event that only lasts for a short period of time.

5.1.6.3 Calculation of the Flow Duration Curves

With the runoff coefficient fixed, the flow duration curves were calculated in each of the 10 basins defined before. In Table 5.11 and Figure 5.13, the flow duration curve corresponding to section 1 is presented, in the table is also made a resumed characterization of the curve, including the probability of exceedance for different values of discharge. For the other sections, these elements are presented in the Appendices I from Figure A- 14 to Figure A- 22, since they don’t add much to the text in terms of perception. It is also presented a resumed characterization of these curves, as it made for section 1, from Table A- 5 to Table A- 13.

44 Number of days Probability of Dischage 10000 Q/Qmod exceeded exccedence (m3/s)

0 - 1793.9 21.6 37 10% 263.4 3.2 73 20% 147.1 1.8 80 22% 134.6 1.6 1000 90 25% 115.8 1.4 100 27% 100.0 1.2

110 30% 86.1 1.0

120 33% 72.6 0.9 /s) 3 130 36% 60.8 0.7 100 140 38% 48.9 0.6 146 40% 43.0 0.5

180 49% 16.4 0.2 (m Discharge 183 50% 14.5 0.2 219 60% 2.5 0.03 256 70% 0.2 0.0 10 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 83.2 Number of days exceeded (days) 112.0 1 0 100 200 300 Maximum Discharge (m3/s) 1793.9 3 Number of days exceeded Mean Annual Affluent Volume (hm ) 2625.1 Table 5.11 – Flow duration curve for section 1 Figure 5.13 – Flow duration curve for section 1

As shown in these figures, the discharge values corresponding to a probability of exceedance higher than 80 % are zero. This is due to the fact that the method used to calculate the discharge values considers only the precipitation data and uses a constant runoff coefficient. So if there is no precipitation in a certain day there is no discharge, which could not correspond to the reality.

Finally, in Table 5.12 a comparative analysis is made between each of the 10 sections. In these table is represented the mean annual precipitation in each catchment area as well as the mean annual affluent volume. The discharge values that are exceeded in 90 days, 140 days and 180 days per year are also calculated, as well as the mean annual discharge and the mean annual discharge corresponding only to 90 % of the discharge value is also determined, this last one is excluding the discharge values that are exceeded only 10 % of the time (i.e. 36 days per year).

Table 5.12 – Comparative analysis between the 10 sections Section ID 1 2 3 4 5 6 7 8 9 10 Mean annual precipitacion (mm) 1328 1328 1327 1331 1339 1320 1321 1321 1328 1328 Mean Annual Discharge 90 % (m3/s) 46.6 64.6 66.0 73.9 104.5 17.1 24.7 25.3 62.5 66.9 3 Mean Annual Discharge - Qmod (m /s) 83.2 110.8 112.8 123.9 172.6 33.6 45.3 46.2 107.8 114.1 Discharge 90 days (m3/s) 115.8 158.8 161.9 181.9 255.7 43.6 61.9 63.2 153.9 164.2 Discharge 140 days (m3/s) 48.9 74.0 75.8 85.0 125.9 14.7 25.2 26.0 71.4 76.6 Discharge 180 days (m3/s) 16.4 27.2 28.2 35.4 55.2 3.5 7.5 7.9 25.7 29.1 3 Mean annual affluent volume (hm ) 2625.1 3495.0 3558.8 3906.3 5442.5 1058.8 1428.5 1456.1 3400.9 3598.4

45 As it is possible to verify analyzing the values presented in Table 22, section 5 is the one with higher discharge values and by far the largest affluent volume. This is mainly due to the fact that the basin area in this section is much bigger than it is in the other ones. Sections 2, 3, 4, 9 and 10 have very similar values since they are located very close to each other in the main water course and there are no significant confluences between them. Sections 7, 8 and mainly section 6 have very low values of discharge when compared with the remaining ones. This is also verified in Figure 5.14 and in Figure 5.15.

200 180 Daily Mean Discharge - Qmod (m3/s) 160 /s) Daily Mean Discharge 90 % (m3/s) 3 140 120 100 80 Discharge (m Discharge 60 40 20 0 1 2 3 4 5 6 7 8 9 10

Section ID

Figure 5.14 – Comparison between sections in terms of mean discharge

) 6000 3 5000 4000 3000 2000 1000

Mean Affluent (hm Affluent Mean Volume 0 1 2 3 4 5 6 7 8 9 10

Section ID

Figure 5.15 - Comparison between sections in terms of mean affluent volume

5.1.7 Reservoir Volumes

At this stage there were determined the reservoir volumes necessary to turbinate a certain equipped discharge. To do so, the mean affluent volume curve, as well as the turbinated volumes curve, had to be determined in each section. The accumulated volumes curves corresponding to the affluent and turbinated volumes were also determined. The necessary reservoir volumes, for the case of equipped discharge values lower or equal to the mean annual discharge (Qmod, Q140 and

Q180 in this analysis), is obtained by summing the negative differences between the affluent and turbinated volumes. For the case of discharge values higher than the mean annual discharge (Q90 for this analysis), the reservoir volume is given by the sum of the maximum and minimum differences between the accumulated curves.

The mean affluent volume curves are obtained from the mean discharge values, already calculated. First, the sum of the daily discharge in each month was calculated and then the monthly discharge values were converted to monthly affluent volumes for each one of the 16 years of data and for the 10 catchment areas defined. Finally the mean affluent volume

46 curves are obtained by making the average of the previous values per month, resulting in a series of 12 values for each catchment area.

Depending on the value of the equipped discharge, the turbines can work more or less days per year, so that in the end of the year the accumulated turbinated volume is equal to the accumulated affluent volume, which means that the balance in the reservoir is equal to zero. The turbinated volumes are calculated considering different values of equipped discharge in order to provide a wide range of comparative values, for the same section and between different sections. The values of equipped discharge considered were the discharge values exceeded 180, 140 and 90 days per year, as well as the mean annual discharge (Qmod). In Table 5.13 it is presented, for section 1, the mean affluent volumes curve and the accumulated turbinated volumes curve (e.g. the volume demand) for the different values of equipped discharge. In the table it was also obtained the necessary reservoir volume associated with each equipped discharge.

Table 5.13 - Determination of the reservoir volume for different values of equipped discharge in section 1

Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent 438.8 403.6 502.9 184.6 14.7 2.1 2.4 26.5 83.8 191.1 360.8 413.9 Volumes (hm3) Acomulated Affluent 438.8 842.4 1345.3 1529.9 1544.5 1546.6 1549.0 1575.5 1659.2 1850.3 2211.1 2625.1 Volumes (hm3) Qmod 223.0 201.4 223.0 215.8 223.0 215.8 223.0 223.0 215.8 223.0 215.8 223.0 Volume Q90 310.0 280.0 310.0 300.0 310.0 300.0 310.0 310.0 300.0 310.0 300.0 310.0 Demand (hm3) Q140 131.1 118.4 131.1 126.9 131.1 126.9 131.1 131.1 126.9 131.1 126.9 131.1 Q180 43.8 39.6 43.8 42.4 43.8 42.4 43.8 43.8 42.4 43.8 42.4 43.8 Qmod 223.0 424.3 647.3 863.0 1086.0 1301.7 1524.7 1747.6 1963.4 2186.4 2402.1 2625.1 Acomulated Q90 310.0 590.1 900.1 1200.1 1510.1 1810.2 2120.2 2430.2 2625.1 2625.1 2625.1 2625.1 Volume Q140 131.1 249.5 380.6 507.4 638.5 765.3 896.4 1027.5 1154.3 1285.4 1412.3 1543.4 Demand (hm3) Q180 43.8 83.4 127.3 169.7 213.5 255.9 299.8 343.6 386.0 429.9 472.3 516.1 Qmod 215.8 202.2 279.9 -31.2 -208.3 -213.7 -220.6 -196.5 -132.0 -31.9 145.1 191.0 Difference Q90 128.8 562.4 1035.2 1229.8 1234.5 1246.6 1239.0 1265.4 1359.2 1540.3 1911.1 2315.0 (hm3) Q140 91.9 83.0 91.9 88.9 91.9 88.9 91.9 91.9 88.9 91.9 88.9 91.9 Q180 266.2 240.4 266.2 257.6 266.2 257.6 266.2 266.2 257.6 266.2 257.6 266.2 Qmod 215.8 418.1 698.0 666.8 458.6 244.9 24.3 -172.2 -304.2 -336.1 -191.0 0.0 Difference - Q90 -87.1 -388.7 -677.1 -984.4 -1287.2 -1594.4 -1897.2 -2207.3 -2409.3 -2402.1 -2409.3 -2402.1 accumulated Q140 178.9 30.6 -70.5 -207.4 -328.5 -465.3 -586.4 -717.5 -854.3 -975.4 -1112.2 -1233.3 values(hm3) Q180 87.2 35.0 3.8 -42.8 -82.4 -129.1 -168.7 -212.5 -259.2 -298.8 -345.4 -385.0 Qmod 1003.4 Reservoir Q90 2322.2 Volume (hm3) Q140 6550.8 Q180 1924.0

It is also made a representation of the two curves described, for the different values of equipped discharge analyzed at this stage. This representation is made in Figure 5.16 to Figure 5.19 presented below. The figures represent the differences between the mean affluent volumes to section 1 and the turbinated accumulated volumes, for the equipped discharges of Q180, Q140, the mean annual discharge and Q90, respectively.

47 3000 Affluent Volumes

2500 Q180

) 3 2000

1500

1000 Volume (hm Volume 500 0 0 2 4 6 8 10 12 Months Figure 5.16 – Accumulated affluent volumes and accumulated volume demand curve for an equipped discharge equal to the one that is only exceeded 180 days per year in section 1

3000 Affluent Volumes 2500

Q140

) 3 2000

1500

Volume (hm Volume 1000

500

0 0 2 4 6 8 10 12 Months

Figure 5.17 – Accumulated affluent volumes and accumulated volume demand curve for an equipped discharge equal to the one that is only exceeded 140 days per year in section 1

3000 Affluent Volumes 2500

Qmod

) 3 2000

1500

Volume (hm Volume 1000

500

0 0 2 4 6 8 10 12 Months

Figure 5.18 – Accumulated affluent volumes and accumulated volume demand curve for an equipped discharge equal to the mean annual discharge in section 1

48 3000

2500

) 2000 3 1500

1000 Volume (hm Volume Affluent Volumes 500 Q90 0 0 2 4 6 8 10 12 Months

Figure 5.19 – Accumulated affluent volumes and accumulated volume demand curve for an equipped discharge equal to the one that is only exceeded 90 days per year in section 1

The same elements were calculated for the remaining sections, using the same procedure. Since the results are similar in terms of aspect it was decided to present them in the Appendices I, from Table A- 14 to Table A- 22 and from Figure A- 23 to Figure A- 31.

As it is noticeable in these figures, for values of equipped discharge equal or inferior to the mean annual discharge, there is a constant increase of the accumulated turbinated volume along the year. For higher values of equipped discharge, the turbinated volume remains constant during some time. This means that the affluences are not sufficient to fulfill the demand through the entire year or, in other words, the turbines cannot work during the whole year. For equipped discharges of less than the mean annual discharge, the turbines can work during the entire year and the necessary reservoir volumes are lower. Of course that in these cases, the spillage volume will be higher since the turbinated volume is lower than the affluent volume. The definition of the depth versus volume curve for section 1, which was determined for 10 meter intervals using the Quantum GIS software, is represented in Table 5.14 as well as in Figure 5.20. For the remaining sections and since the results are much similar to section 1, the depth versus volume curves are presented in Table A- 23 of the Appendices I. Some values are interpolated in order to obtain a dam height associated with the reservoir volume.

Table 5.14 - Depth volume curve and depth area curve for the reservoir in section 1

Reservoir Reservoir Area Depth (m) Volume (hm3) (km2) 0 0 0 10 41 6 16 130 13 20 190 17 30 486 33 31 530 35 40 928 49 42 1066 54 48 1478 68 50 1615 73 51 1724 77 60 2706 119 70 4232 171 80 6302 230

7000 250 6000 Depth-Volume

Depth-Area 200

) 5000

) 4000 150 2

3000 100

Area Area (km Volume (hm Volume 2000 50 1000 0 0 0 20 40 60 80 100 Depth (m)

Figure 5.20 - Depth volume curve and depth area curve for the reservoir in section 1

Finally, based on the estimated reservoir volumes and in the depth versus volume curves obtained, the dam heights necessary to integrate those volumes were determined in a way that the dam’s height generates a reservoir volume bigger than the one estimated before, in an iterative calculation process.

In Table 5.15 are represented, for each section and for each value of equipped discharge, the number of days a year the turbines are working, the necessary reservoir volume and the associated dam height. With this dam height and the depth versus volume curves, the actual reservoir volume and area are determined for each section.

Table 5.15 – Reservoir characterization for each section

Equipped Discharge Section ID Parameter (m3/s) 1 2 3 4 5 6 7 8 9 10

Q180 128 216 224 286 434 22 56 60 203 232 Necessary Q 518 779 798 885 1286 147 266 274 752 804 Reservoir 140 Q 1034 1324 1344 1447 1922 425 567 577 1294 1355 Volume (hm3) mod Q90 1411 1797 1825 2011 2769 573 783 796 1758 1839

Q180 16 13 20 14 26 5 3 11 8 23

Minimum dam Q140 31 24 34 27 39 14 12 19 21 37

height (m) Qmod 42 29 42 34 45 22 19 26 29 44

Q90 48 33 47 39 51 25 24 31 33 50

Q180 13 23 22 29 41 3 8 8 22 25

Reservoir Area Q140 35 59 55 62 87 12 30 29 58 55 2 (km ) Qmod 54 95 85 92 116 30 44 45 88 83

Q90 68 119 101 117 146 40 53 56 109 113

Q180 130 224 230 298 467 23 66 76 203 257

Reservoir Q140 530 839 800 920 1305 153 299 287 756 829 3 Volume (hm ) Qmod 1066 1384 1378 1536 1992 440 573 590 1360 1360

Q90 1478 1893 1864 2083 2776 632 839 841 1807 1926

Q100 365 365 365 365 365 365 365 365 365 365 Number of days Q60 262 255 254 249 246 281 267 266 256 254 working (days/year) Qmod 365 365 365 365 365 365 365 365 365 365 Q91 365 365 365 365 365 365 365 365 365 365

50 As observed in the table, the smaller the equipped discharge, lower will be the turbinated volume and consequently the necessary reservoir volume. Lower reservoir volumes implicate smaller dams and dam heights. For these cases, and when turbining with the same equipped discharge the whole year, the facility is not taking advantage of all the affluences. As a consequence the spillage volume is bigger and volume that could be turbinated might be wasted.

5.1.8 Cost Estimation

In order make a comparative analysis between the sections in study, a cost estimation was elaborated. Some essential parameters were considered and the unit rates (i.e. unitary costs) were defined for those parameters in a way that, in a first approach, the cost of the facility could be estimated. For this first approach the parameters considered were the ones described in the following topics:

 Accesses: In this first stage, the total of accesses was determined considering the connection to the roads already existing in the region;

 Connection to Saurimo: Since the objective of the facility is to supply the city of Saurimo, one important parameter to considerer is the cost of the connection to the city. In order to do this, the national electric grid of Angola was analyzed. This analysis was based on an ENE´s document concerning the transport and electric grid of Angola, from 2013 (Bernardo and Moniz 2013) and presented in Figure A- 32 of the Appendices I. As shown in the figure, the regions of Lunda Norte and Lunda Sul are still isolated from national energy distribution grid in Angola. The dotted lines represent connection lines that are projected or under construction. Since the Angolan electric grid does not extend to the case study region, the total connection was considered in a straight line from the sections in study to the city of Saurimo. This has already been determined in the characterization of the alternatives (chapter 5.1.5);

 Construction materials: The construction materials considered in this stage were only the construction materials for the dam itself, namely the volume of concrete. As already explained, it was considered a concrete dam, despite the fact that this parameter has not yet been studied, since the objective at this stage is to make a comparative analysis between possible sections and it makes no difference to consider a concrete or an embankment dam for the effect. For this phase, the cost of the spillway, water intake and bottom discharge were considered to be part of the construction materials;

 Conveyance system: At this stage the length of the conveyance system considered was in a straight line from the section where the dam is located (i.e. the section itself) to the location of the power plant, assumed at an earlier stage to be located at the bottom of the natural river bed drop considered in each section. Also, and only as a comparative approach, the conveyance system was assumed to be a steel penstock for all the sections. Of course, this was not yet studied at this stage and after a more detailed analysis, other solutions might be a better option, for example with a tunnel, channel or even a mixed system, but for now it is only a comparative parameter between sections;

 Reservoir deforestation: The deforestation is very important since if it’s not done correctly it can represent a big amount of organic that might contaminate the water in the reservoir. At this phase the deforestation area was assumed to be equal to the reservoir area.

 Equipment: At this stage the total cost of the equipment was determined in a very simple way. This cost was calculated using a Water Power Magazine (www.waterpowermagazine.com) document from their 60th anniversary in 2009 called “Project Finance, estimating the cost of E&M equipment”. This document gives information about the project cost for different types of turbines, based on the net head, equipped discharge and installed capacity. The information used is

51 presented in Figure A- 33 of the Appendices I. It was considered a Francis turbine, due to the range of discharge and net head obtained for the alternatives and based on the described document.

At this stage of the project, the excavations were not considered since there is still no information about its quantities, also the differences in the final costs were not considered to be relevant. The engineering work was considered to be a percentage of the total, although it is not a crucial element at this point because the purpose is a comparative analysis.

Some of the parameters described such as the dam volumes, the reservoir area, the connection to Saurimo and the total of accesses have already been determined in the characterization of the alternatives. As already referred, the measured quantities are majored in 30 % to account for possible errors. These values are presented for all the 10 selected sections and for the different values of equipped discharge considered, in Table 5.16.

Table 5.16 - Calculation of quantities in each section for different values of equipped discharge

Section ID 1 2 3 4 5 6 7 8 9 10 Distance to Saurimo (km) 101.4 154.7 167.7 224.9 306.8 148.2 92.3 91 144.3 175.5 Total of accesses (km) 22.1 63.7 54.6 5.2 19.5 62.4 16.9 11.7 71.5 54.6

Q180 71 137 301 178 1379 8 4 13 15 94

Dam volume Q140 278 484 1207 583 3161 39 24 42 86 384 3 3 (×10 m ) Qmod 543 714 2025 910 4313 93 57 94 164 711

Q90 728 985 2722 1179 5565 124 97 140 219 1069

Q180 1020 2531 4307 2295 8993 252 125 363 391 753

Lenght of the Q140 1453 4065 6660 3038 10420 613 463 608 726 1190

dam's crest (m) Qmod 1725 4738 9205 3380 10826 825 629 821 900 2947

Q90 1871 5416 10141 3587 11267 898 747 979 986 5429

Q180 13 23 22 29 41 3 8 8 22 25

Reservoir area Q140 35 59 55 62 87 12 30 29 58 55 2 (km ) Qmod 54 95 85 92 116 30 44 45 88 83

Q90 68 119 101 117 146 40 53 56 109 113

Q180 130 224 230 298 467 23 66 76 203 257

Reservoir Q140 530 839 800 920 1305 153 299 287 756 829 3 Volume (hm ) Qmod 1066 1384 1378 1536 1992 440 573 590 1360 1360 Q90 1478 1893 1864 2083 2776 632 839 841 1807 1926

.After the definition of these quantities, the unitary prices (e.g. unit rates) were defined in order to make an estimation of the cost for each alternative. This was made using as a source the values researched in the LCH laboratory database. The unitary prices considered are presented in Table 5.17. The cost estimation is presented in Table 5.18 for each of the quantities described. The estimation of the total cost of the facility, for different values of equipped discharge and for each of the 10 sections is presented in Table 5.19.

52 Table 5.17 – Comparative costs

Parameter Unit rate Transmission lines (USD/m) 100 Accesses (USD/m) 400 Concrete (USD/m3) 60 Steel (USD/kg) 6 Escavations (USD/m3) 25 Deforestation (USD/km2) 250 Engeneering (%) 10

Table 5.18 - Cost estimates for each section and for different values of equipped discharge

Section ID 1 2 3 4 5 6 7 8 9 10 Conection to Saurimo cost (USD*106) 10.1 15.5 16.8 22.5 30.7 14.8 9.2 9.1 14.4 17.6 Total cost of accesses (USD*106) 8.8 25.5 21.8 2.1 7.8 25.0 6.8 4.7 28.6 21.8

Q180 4.3 8.2 18.1 10.7 82.8 0.5 0.3 0.8 0.9 5.6

Dam cost Q140 16.7 29.1 72.4 35.0 189.6 2.3 1.5 2.5 5.2 23.0 6 (USD*10 ) Qmod 32.6 42.9 121.5 54.6 258.8 5.6 3.4 5.7 9.9 42.6

Q90 43.7 59.1 163.3 70.7 333.9 7.4 5.8 8.4 13.1 64.1

Q180 0.003 0.006 0.005 0.007 0.010 0.001 0.002 0.002 0.006 0.006 Deflorestation Q 0.009 0.015 0.014 0.016 0.022 0.003 0.007 0.007 0.014 0.014 cost 140 Q 0.013 0.024 0.021 0.023 0.029 0.007 0.011 0.011 0.022 0.021 (USD*106) mod Q90 0.017 0.030 0.025 0.029 0.036 0.010 0.013 0.014 0.027 0.028

Q180 5.0 6.5 7.5 7.5 12.0 0.1 1.0 1.7 3.0 7.0 Total cost of Q 12.5 15.0 22.5 17.5 35.0 3.5 6.0 6.5 12.0 19.0 the equipment 140 Q 24.0 27.0 33.0 33.0 45.0 7.5 9.5 10.5 24.0 34.0 (USD*106) mod Q90 38.0 39.0 47.0 45.0 57.0 9.0 13.5 14.5 37.0 47.0

Table 5.19 –Cost estimations for the facility

Section ID 1 2 3 4 5 6 7 8 9 10

Q180 31.1 61.2 70.6 47.0 146.6 44.4 19.0 17.9 51.7 57.2

Total cost Q140 53.0 93.5 146.9 84.7 289.4 50.2 25.8 25.1 66.2 89.6 6 (USD*10 ) Qmod 83.1 121.9 212.5 123.4 376.5 58.1 31.8 32.9 84.6 127.6 Q90 110.7 153.0 273.9 154.4 472.4 61.8 38.9 40.4 102.5 165.6

As it is noticeable in Table 5.19, there is a big disparity between the different alternatives and also between the different sections considered. This is mainly due to the topography in the regions of each cross section, which influences the dam volumes, the distance to Saurimo and to the nearest accesses, the possible locations for the power plant that are directly connected to the conveyance system length and finally the cost of the equipment’s.

53 5.1.9 Comparison of Alternatives

The parameters taken into consideration when comparing the different alternatives were the total cost estimated for the facility, the length of the dams crest as well as its volume and finally some indicators, which were obtained for the 10 sections and different values of equipped discharge that allowed a more visual and detailed comparison between the sections. To obtain these indicators, first a few parameters had to be calculated, using the expression bellow and are present in Table 5.20.

 Net head: obtained for the different values of equipped discharge considered, using the following expression:

NH (m)=TH-HL (4)

Where NH represents the neat head, TH represents the total head, given by the sum of the topographic difference with the dam height and HL represents the head losses.

 Installed capacity: Calculated using the expression presented below.

η*NH*Q*γ P (MW)= (5) 106

Where P represents the power generation (i.e. the installed capacity) in MW, η is the efficiency of the turbine

generator group (considered at this stage to be equal to 0.82), Q is the discharge in m3/s, γ the specific weight of the water in N/m3 and NH the net head in m.

 Energy generation: Finally to calculate the energy generated per year, the power generation obtained and the number of days that the turbines are working in the year were considered as it presented in the expression:

E=P*∆t (6)

Table 5.20 – Calculation of the net head, installed capacity and energy generation

Section ID 1 2 3 4 5 6 7 8 9 10 Conduit lenght (km) 3.1 6.5 3.3 3.1 0.3 0.4 1.6 0.5 0.1 0.5 Energy losses (m) 6.1 13.0 6.5 6.1 0.6 0.7 3.2 1.0 0.2 1.0

Q180 29.9 20.0 33.5 17.9 35.4 4.3 9.8 20.0 7.8 28.6

Q140 44.9 31.0 47.5 30.9 48.4 13.3 18.8 28.0 20.8 42.6 Net head (m) Qmod 55.9 36.0 55.5 37.9 54.4 21.3 25.8 35.0 28.8 49.6

Q90 61.9 40.0 60.5 42.9 60.4 24.3 30.8 40.0 32.8 55.6

Q180 3.9 4.4 7.6 5.1 15.7 0.1 0.6 1.3 1.6 6.7

Installed capacity Q140 17.6 18.4 28.9 21.1 49.0 1.6 3.8 5.8 12.0 26.2

(MW) Qmod 37.4 32.1 50.3 37.7 75.5 5.7 9.4 13.0 25.0 45.5

Q90 57.6 51.1 78.7 62.7 124.2 8.5 15.3 20.3 40.6 73.4

Q180 34.4 38.4 66.5 44.5 137.7 1.1 5.2 11.1 14.1 58.6 Energy Q140 154.6 161.5 253.4 184.8 429.2 13.7 33.3 51.1 104.7 229.8 generation (GWh/year) Qmod 327.4 281.0 440.7 330.3 661.1 50.2 82.3 113.6 218.9 398.5 Q90 362.6 312.2 480.4 373.9 734.0 57.3 98.2 129.9 249.2 446.7

54 For the comparison of the different alternatives, the cost per installed capacity, the cost per energy generated per year and the MW of installed capacity per km2 of reservoir area were calculated. The referred indicators are presented in Table 5.21 and Table 5.22, as well as their comparison shown in the graphs from Figure 5.21 to Figure 5.22, that allowing a better visualization and comparison of all the considered sections. The ID of the alternatives is defined as SxQy, were x represents the section ID and Qy represents the discharge exceeded y days per year.

As observed in the tables, there is a big difference between the cost indicators for the alternatives with Q180 and Q140 to the other two. This happens in every section and more evidently in sections 6 and 7. Faced with this situation, these two alternatives were rejected because the equipped discharge would be to low and the power generated would not compensate, when compared with alternatives associated with higher equipped discharges. Also, this is why in the presented figures the comparison is only made for the alternatives concerning the equipped discharge of Qmod and Q90.

The objective in this phase is to differentiate the best sections from the total of sections considered, in a first screening. In a second screening the same type of comparison is made with more values of equipped discharge for the sections still remaining after the first screening. This second screening allows a wider range of values to compare the remaining sections.

0.4

2.3

0.6

3.8

166

164

0.65

73.4

472

256

0.85

5429

446.7

734.0

124.2

11267

S5_Q90

S10_Q90

0.3

2.8

0.6

5.0

128

114

0.55

45.5

377

173

0.65

75.5

2947

398.5

661.1

10826

S5_Qmod

S10_Qmod

0.4

3.4

0.7

5.9

0.48

26.2

289

126

0.57

49.0

1190

229.8

429.2

10420

S5_Q140

S10_Q140

1.0

8.6

6.7

1.1

9.3

753

0.27

58.6

147

0.38

15.7

8993

137.7

S5_Q180

S10_Q180

0.4

2.5

0.4

2.5

102

986

154

182

0.37

40.6

0.53

62.7

3587

249.2

373.9

S9_Q90

S4_Q90

0.4

3.4

0.4

3.3

900

108

123

124

0.28

25.0

0.41

37.7

3380

218.9

330.3

S9_Qmod

S4_Qmod

0.6

5.5

0.5

4.0

726

0.21

12.0

0.34

21.1

3038

104.7

184.8

S9_Q140

S4_Q140

3.7

1.6

1.1

9.3

5.1

391

0.07

32.0

14.1

0.18

44.5

2295

S9_Q180

S4_Q180

0.3

2.0

0.6

3.5

979

274

162

0.36

20.3

0.78 78.7

129.9 480.4

10141

S8_Q90

S3_Q90

0.3

2.5

0.5

4.2

821

212

113

0.29

13.0

0.59

50.3

9205

113.6

440.7

S8_Qmod

S3_Qmod

0.5

4.3

5.8

0.6

5.1

608

147

0.20

51.1

0.53

28.9

6660

253.4

S8_Q140

S3_Q140

1.6

1.3

1.1

9.3

7.6

363

0.16

14.2

11.1

0.35

66.5

4307

S8_Q180 S3_Q180

Calculation comparativeof indicators

Calculation of comparativeof indicatorsCalculation

62 33

0.4

2.5

0.5 3.0

747

153

159

0.29

98.2

15.3

0.43 51.1

- 5416

– 312.2

S7_Q90 S2_Q90

0.4

3.8

0.4

3.4

9.4

122

111

629

0.34

32.1

0.21

82.3

4738 281.0

Table

S2_Qmod

S7_Qmod

0.6

5.1

0.8

6.8

3.8

463

0.31

18.4

0.13

33.3

4065

161.5

S2_Q140

S7_Q140

1.6

4.4

3.7

5.2

0.6

125

0.19

14.0

38.4

0.08

32.3

2531

S2_Q180

S7_Q180

0.3

1.9

1.1

7.3

8.5

111

116

898

0.85

57.6

0.21

57.3

1871

362.6

S1_Q90

S6_Q90

0.3

2.2

1.2

5.7

825

0.70

37.4

0.19

10.1

50.2

1725

327.4

S1_Qmod

S6_Qmod

0.3

3.0

3.7

1.6

613

0.51

17.6

0.13

32.1

13.7

1453

154.6

S1_Q140

S6_Q140

0.9

7.9

3.9

1.1

0.1

252

0.31

34.4

0.05

42.1

1020

369.0

S1_Q180

S6_Q180

)

/s)

of of

/GWh/year)

/kW)

/GWh/year)

/kW)

reservoir(MW/km

MW per km MW

(USD*10

Cost per GWh/year Cost

(USD*10

Cost per installed kW kW per installed Cost

Total cost (USD*10 cost Total

crest (m) crest

Lenght of the dam's dam's the of Lenght

(GWh/year)

Energy generation

Installed capacity (MW) capacity Installed

Dam height (m) height Dam

Discharge (m Discharge

AlternativeID

reservoir(MW/km

MW per km MW

(USD*10

Cost per GWh/year Cost

(USD*10

Cost per installed kW kW per installed Cost

Total cost (USD*10 cost Total

crest (m) crest

Lenght of the dam's dam's the of Lenght

(GWh/year)

Energy generation

Installed capacity (MW) capacity Installed

Dam height (m) height Dam Discharge (m Discharge AlternativeID

56 12.0 1.4

1.2 10.0

1.0 Section 1 8.0 Section 1 Section 2 Section 2 Section 3 0.8 Section 3 Section 4 Section 4 Section 5 6.0 Section 5 Section 6 0.6 Section 6 Section 7

Section 7 ) ) capacity MW installed of per 6 Section 8

) ) per GWhYear generated energy of per Section 8 4.0 Section 9 6 Section 9 Section 10 0.4

Section 10

Cost Cost (USD*10 Cost Cost (USD*10

2.0 0.2

0.0 0.0 Qmod Q90 Qmod Q90

Figure 5.21 – Cost per MW of installed capacity and cost per GWh generated per year for the equipped discharge exceeded 90 day per year and for the mean annual discharge

By analyzing the tables and the figures above, section 6 clearly stands out as being the worst of the considered sections in terms cost per benefits.

The alternatives for sections 2, 3, 4 and 5, in addition to having associated very large crest lengths, which probably would not be feasible, present very high costs per installed capacity and GWh per year, which are not competitive with the remaining sections (not including section 6). In section 5 it would be possible to achieve the objective of 100 MW of installed capacity, although this solution does not seem to be possible due to the dimension of the construction works. At the same time the equipped discharge is very high and thus the HPP could only work for a limited number of days per year. By analyzing the remaining sections, the two best sections are sections 1 and section 8, since they present the less cost per GWh of energy generated per year and the less cost per MW of installed capacity.

By analyzing the indicators presented, it is easily noted that the cost per installed capacity decreases as the equipped discharge increases, which makes sense since the installed capacity is higher and the cost of having a bigger dam and more expensive equipment’s does not increase in proportion. On the other hand the cost per GWh generated per year increases

57 with the increase of the equipped discharge from Qmod to Q90, since the number of days that the turbines work is lower and consequently the energy generated per year decreases, despite the increasing in the installed capacity.

In Figure 5.22 it’s shown the MW of installed capacity per reservoir area. Also in this indicator section 1 reveals itself to be one of the best, along with section 5. On the other hand, section 8 presents’ lower values than the ones described. Of course that the higher this indicator is, the better, since lower reservoir areas represent less cost and less potential problems, for example with expropriations and occupancy of territory or reallocations for the affected population.

0.9

0.8

0.7 Section 1

0.6 Section 2 Section 3

0.5 Section 4

of of reservoir

2 Section 5

0.4 Section 6 Section 8 0.3 Section 9

Section 10 MW installed installed perkm MW 0.2 Section 7

0.1

0.0 Q180 Q140 Qmod Q90

Figure 5.22 – MW of installed capacity per km2 of reservoir for each section and different alternatives

The values presented in the Figure 5.22, regarding the MW per reservoir area, are much different from the ones presented earlier in this report, in the chapter where It’s made a review on hydropower (Chapter 2), for the major facilities in Brazil. This is mainly due to the fact that those facilities have associated considerably higher values of installed capacity. Also the Chiumbe River basin is located in a plateau area, typical from the interior of Angola, which implies reservoirs with bigger areas.

Another important aspect to take into consideration regarding sections 1 and 8 is the difference between their installed capacity, energy generation per year and estimated total cost of the facility. By looking at Table 5.21 and Table 5.22 it is evident that section 1 generates the triple than section 8, but costs 3 times more. This is why the indicators are similar, but, in terms of power, energy and investment the order of magnitude of the values is much different from one section to another. Given this situation it was decided to continue the study for both of these sections, removing the rest of the sections from the picture.

58 In a second stage of this comparison between alternatives, more calculations were made, considering more values of equipped discharge. The equipped discharges considered at this phase in each of the sections were Q70, Q80, Q90 Q100 Qmod,

Q105, Q110, Q120 and Q130, so nine alternatives for each section in total. The process for the calculations was exactly the same as before and the results, namely the indicators, are presented in Figure 5.23, Figure 5.24 and Figure 5.25.

4.0

3.5

3.0 2.5 2.0 Section 1 Section 8

) ) MW installed per 1.5 6 1.0 0.5

Cost Cost (USD*10 0.0 Q130 Q120 Qmod Q110 Q105 Q100 Q90 Q80 Q70

Figure 5.23 – Cost per MW of installed capacity for sections 1 and 8

0.5 0.4 0.4 0.3 0.3 Section 1

0.2

) ) GWh generated per 6 peryear Section 8 0.2 0.1

0.1 Cost Cost (USD*10 0.0 Q130 Q120 Qmod Q110 Q105 Q100 Q90 Q80 Q70

Figure 5.24 – Cost per GWh generated per year for sections 1 and 8

1.4

1.2

1.0

0.8 of reservoir of

Section 1 2 0.6 Section 8

0.4 MW per km per MW 0.2

0.0 Q130 Q120 Qmod Q110 Q105 Q100 Q90 Q80 Q70

Figure 5.25 – MW of installed capacity per km2 of reservoir for sections 1 and 8

59 As it was already concluded and as it can be observed in the figures above, the cost per installed capacity decreases as the equipped discharge increases and the MW per square kilometer of reservoir increases with the increasing equipped discharge. The cost per GWh generated per year decreases until it reaches a minimum that occurs around the mean annual discharge (Qmod) and after starts rising.

Based on this, if the purpose would be to guaranty a peak demand supply during short periods in a year, then the best equipped discharge would be the maximum discharge that allows supplying for those periods. On the other hand, if the purpose is to constantly supply a certain amount of energy, then equipping a discharge close to the mean annual discharge would probably be the best solution since the energy generated is higher.

Based on the studies conducted so far, section 1 was considered to be the best section to build a hydropower facility. Of course, this depends on the available money to invest, because section 1 is almost 3 times more expensive than section 8, but on the other hand generates much more energy. So the final choice depends on the objective and available funds to invest. The rest of the study is made considering section 1 as the optimal section to construct a HPP in the Chiumbe River.

5.2 STAGE 2: FEASIBILITY STUDY OF THE SELECTED OPTION

5.2.1 Reservoir Analysis

5.2.1.1 Base Data and Model Definition

At this phase of the study more information on runoff for the Chiumbe River basin was obtained. The information obtained was a mean monthly discharge series from 1965/66 to 1973/74 in the station of Dala in the Chiumbe River, which is presented in Table A- 24 of the Appendices I. The drainage area associated with the station is 2 142 km2 with a mean annual discharge of 16.7 m3/s and an elevation of 1 250 m. Also the flow duration curve in the described station is presented in Table A- 25 of the Appendices I. This information regarding the water resources was used from this point on in all the studies.

The flow duration curve was extrapolated from the Dala station to section 1, using a relation between the drainage areas and is presented in Table A- 26 of the Appendices I. The mean monthly discharge values and the mean affluent volumes were obtained in section 1 and are presented in Table 5.23.

Finally in Figure 5.26 is made a comparison between the flow duration curve obtained with the measured discharge values and the one obtained in an earlier phase of this study, with the satellite data, as well as a comparison between the mean affluent volumes for the two situations, in Figure 5.27.

As it is possible to observe, with the measured runoff data the flow duration curves are more homogenous than with the runoff obtained with the satellite precipitation and using a constant runoff coefficient. Additionally it is possible to observe that with the measured runoff data the values never reach zero as it occurs with the satellite precipitation data, and they describe more accurately what happens in reality. The mean annual discharge calculated for section 1 was 75 m3/s, which is lower than the 83.2 m3/s obtained with the satellite precipitation, also the maximum values (exceeded an inferior number of days per year) are higher for the curve obtained using the satellite precipitation.

60 Table 5.23 - Mean monthly discharge values in section 1 obtained using the measured values of discharge

Year Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Average (m3/s) 1965/66 41.3 52.3 79.5 87.0 116.4 143.2 91.4 52.3 46.1 44.4 41.7 41.3 69.8 1966/67 45.7 57.1 61.1 61.1 94.0 125.7 113.8 78.2 49.7 43.5 38.7 35.2 67.0 1967/68 50.5 102.8 112.0 87.0 163.0 142.8 110.7 60.6 52.7 51.0 46.1 41.3 85.1 1968/69 39.1 62.8 87.4 103.3 156.4 182.4 160.8 58.9 49.7 47.5 44.4 41.3 86.2 1969/70 67.2 75.1 115.1 108.1 161.3 151.6 73.8 60.2 55.4 54.0 52.3 48.8 85.2 1970/71 58.4 84.4 107.2 87.4 82.6 93.6 86.6 52.3 47.5 45.3 41.3 36.0 68.5 1971/72 40.4 47.9 69.4 115.6 71.6 130.1 85.7 52.3 43.1 40.4 38.2 40.9 64.6 1972/73 46.1 67.7 93.2 109.0 77.8 164.3 97.5 47.0 42.2 40.4 37.3 33.0 71.3 1973/74 33.8 52.7 83.5 86.6 86.6 105.0 129.2 53.6 34.7 36.5 36.0 38.2 64.7

Average (m3/s) 47.0 67.0 89.8 93.9 112.2 137.6 105.5 57.3 46.8 44.8 41.8 39.5 Standart dev. 10.4 17.9 18.8 16.8 38.2 27.8 26.8 9.0 6.2 5.5 5.1 4.7 (m3/s) Maximum 67.2 102.8 115.1 115.6 163.0 182.4 160.8 78.2 55.4 54.0 52.3 48.8 Discharge (m3/s) Minimum 33.8 47.9 61.1 61.1 71.6 93.6 73.8 47.0 34.7 36.5 36.0 33.0 Discharge (m3/s) Mean Volumes 125.8 179.4 240.6 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 (hm3) Minimum 3 33.8 47.9 61.1 61.1 71.6 93.6 73.8 47.0 34.7 36.5 36.0 33.0 Volumes (hm )

12.0 Satellite Data 10.0 Measured Data

8.0

6.0

4.0 Discharge (m3/s) Discharge 2.0

0.0 0 50 100 150 200 250 300 350 400 Number of days exceeded Figure 5.26 – Comparison between the flow duration curves using the measured data and the satellite data

Taking into consideration the comparison made in Figure 5.27, it is noted that with the measured values the maximum value of the mean affluences occurs in March instead of April, which makes sense that in the Northeast of Angola the maximum rainfall values occur in March and the rainy season ends in mid/end of April. For the reservoir analysis it was considered the civil year, which means that the simulation starts in January.

61 600.0 Satellite Data 500.0 Measured Data

400.0

) 3

300.0

200.0 Volume (hm Volume

100.0

0.0 Out. Nov. Dec. Jan. Feb. Mar. Apr. May June July Aug. Sep.

Month Figure 5.27 - Comparison between the mean affluent volumes using the measured data and the satellite data

To analyze the reservoir, a model was created to make a balance in the reservoir considering the inputs and outputs in each month. The parameters considered in the balance for this model were:

 Inflows: The inflows considered were the mean monthly affluent volumes calculated with the measurements from the Chiumbe-Dala hydrometric station. The inflows were considered to be constant in each month represented by the average value and not varying trough the next year.

 Evaporation in the reservoir: The mean monthly values of evaporation in the reservoir had to be accounted for. This was complicated since there were no available measurements of evaporation and it was not possible to elaborate a direct calculation. To solve this problem, the Thornthwaite method for computing the potential evapotranspiration was used. Of course, this is an approximation since the evapotranspiration and the evaporation are different parameters. The evapotranspiration it´s a complex phenomenon that results from the plant transpiration and from the evaporation in the surrounding environment. The Thornthwaite method considers the following expression:

10T ETP =16N ( m )a (7) m m I

Where:

 퐸푇푃푚 represents the potential evapotranspiration in month m (mm),

 푁푚 it’s an adjustment factor that considers the number of days in month m and the number of hours of radiation. The number of hours of radiation is presented in Table A- 27 of the Appendices I and the factor is calculated using

the following expression, in what 퐷푚 represents the number of days in month m and 퐻0푚 the mean daily hours of solar radiation in month m.

H D N = 0m m (8) m 360

 푇푚 is the mean monthly temperature in month m (ºC), 12  퐼 is an annual thermic index, obtained using: I= ∑i=1 im 푇 Where 푖 = ( 푚)1,5 , the thermic index in month m 푚 5  푎 is coefficient calculated using the expression: a=6.75×10-7 I3-7.71×10-5 I2+1.792×10-2I+0.49239

62  Ecological discharge: The ecological discharge in each month was considered to be 10 % of the inflows in that same month.

 Turbinated volume: The turbinated is calculated as a function of the equipped discharge but is limited by the live storage in the reservoir which is a function of the inputs and outputs in the reservoir. At this phase, it was considered that the turbines performance was 90 %, for a Francis turbine working with Q/Qmáx higher than 0.8 (Quintela 1981).

The model was defined in a way that the inputs are the inflows, which are constant in each month, and the evaporation, which is a constant value per area (mm/km2) in each month. The affluent volumes have already been presented in Table 5.23 and the mean monthly evaporation is presented in Table 5.24. The parameters that are optimized are the equipped discharge, the dam height and the number of machines (turbines), being the model fully automatized for the remaining parameters.

Table 5.24 - Mean monthly evaporation in section 1

Month Sep. Out. Nov. Dec. Jan. Feb. Mar. Apr. May June July Aug. Mean Evaporation Values 97.04 98.39 89.61 92.08 90.94 81.74 87.63 86.31 80.67 64.75 68.58 87.74 (mm per month)

First the depth volume curve and the depth area curve were adjusted to polynomial functions in order to facilitate the process of obtaining the reservoir area and volume at different levels. Then the reservoir levels that are presented in Figure 5.28 were defined. The entrance sill of the bottom outlet (river sluice in the figure) was defined at 10 meter level, the minimum drawdown level for hydropower use (MDDL) at 15 meters, the maximum water (MWL) level at 1 meter bellow the height of the dams crest and finally, the full reservoir level (FRL) was fixed 2 meters below the MWL. The full reservoir level corresponds to the maximum level that can be controlled.

In a first step the model considers that in the first month the initial live storage is equal to the ideal turbinated volume (i.e. the volume corresponding to operate with the equipped discharge all the days in the month). September was considered to be the beginning of the hydrological year. Based on the live storage the total storage and the reservoir are computed.

Then the inflows, the ecological discharge and the evaporation are accounted for. The evaporation is calculated based on the reservoir area in each month. After this the ideal turbinated volume is calculated which, as explained before, considers the equipped discharge and the number of turbines. The real turbinated volume takes into account the available water in that month. Finally the spillage volume is determined; which only works if the remaining water is above the maximum water level.

At the end of each month, the final reservoir volume and level are computed. To make it easier to visualize the model and optimize the parameters, the model is computed in a graph. In the graph, it is represented for each month the inflows, the initial live storage, the spillage volume as well the initial and final water levels in the reservoir.

Figure 5.28 – Reservoir levels (WRE lectures, EPFL, 2014/2015 1st semester)

In the reservoir analysis different scenarios were considered. All this scenarios were studied for section 1 and compared between them. The scenarios considered are the ones described in the following topics:

 Scenario 1 (C1): The turbines working all the days in the year with only one machine.

 Scenario 2 (C2): Don’t turbinate in June, July, August and September with only one machine.

 Scenario 3 (C3): Don’t turbinate in two of the dryer months of the year. This scenario considers three hypothesis: don´t turbinate in July and September (C3.1), don´t turbinate in June and August (C3.2) and don’t turbinate in August and September (C3.3).

 Scenario 4 (C4): Don’t turbinate in August.

 Scenario 5 (C5): Equip a discharge that allows reaching the installed capacity of 100 MW. The number of days that the turbines are working will be fixed in a way that the turbinated volume does not surpass the inflows.

 Scenario 6 (C6): In August and September, turbinate only part of the discharge.

 Scenario 7 (C7): In August, turbinate only part of the discharge.

 Scenario 8 (C8): The turbine working all the days in the year with only one machine, but with a dam height of 80 meters allowing a higher installed capacity. This scenario is considered in order to obtain very high values for the power generation, with the objective of reaching an installed capacity of 100 MW;

 Scenario 9 (C9): Use two turbines the entire year and two times a year, for small periods of time, only one of the turbines is working in order to allow reparations if needed. The months when the turbines will be stopped were optimized in order to generate as much energy per year as possible.

 Scenario 10 (C10): The same as scenario 9 but with three turbines.

 Scenario 11 (C11): Use two turbines with one of them working with Q/Qmáx = 20 %. For this scenario two hypothesis were considered: one where one of the turbines only works with Q/Qmáx = 20 % from May to September (C11.1) and another one where it happens during the whole year.

64  Scenario 12 (C12): Use two turbines with one of them working with Q/Qmáx = 40 %. For this scenario two hypothesis were considered: one where one of the turbines only works with Q/Qmáx = 40 % from May to September (C12.1) and another one where it happens during the whole year(C12.2).

 Scenario 13 (C13): Use two turbines with one of them working with Q/Qmáx = 60 %. For this scenario two hypotheses were considered: one where one of the turbines only works with Q/Qmáx = 60 % from May to September (C13.1) and another one where it happens during the whole year (C13.2).

When modeling the reservoir, the objective was to maximize the energy gains by turbining the maximum volume without exceeding the inflows. So the main goal was to guaranty the initial live storage in the first month of the next year after the “simulated year” (which was designated in the model as Jan. +) and at the same time do not use the spillway in order to not waste water that could be used to generate energy. The tables concerning the reservoir analysis for section 1, including the 13 scenarios defined in the methodology, are presented in Table A- 28 to Table A- 53 of the Appendices I, in these tables it is possible consult the values regarding the reservoir analysis, also there are presented the net head, the energy generated per month per group and for each scenario and the number of days that each group is working. In Figure 5.29 to Figure 5.46 that follow, the graphs equivalent to those tables are also presented.

900.0 40.00

800.0 35.00

700.0 )

3 30.00 Spillage Volume (hm3) 600.0 25.00 Inflow (hm3) 500.0 20.00 400.0 Initial live Storage (hm3) 15.00 300.0 Final Water Level (m)

200.0 10.00 Initial Water Level (m) Water Volumes (hm Volumes Water 5.00 100.0 (m) Reservoir Level Water 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month

Figure 5.29 – Reservoir analysis for the scenario C1

For this scenario, since the turbines are working the whole year, the equipped discharge has to be lower than in solutions where the turbines would only work part of the year (as it happens in scenario C2 for example). According to this, the volume in the reservoir tends to rise once the inflows surpass the outflows. Once the dryer months are reached, the level starts to go down because the turbinated volume is higher than the affluences. At this point the water stored in the humid months are used for energy generation. In order to store enough water (which is basically all the affluences since the objective is not waste water that could be used for energy generation) to turbinate in the dryer months, the dam’s height must be enough in order to create sufficient storage volume.

65 800.0 40.00

700.0 35.00

) 3 600.0 30.00 Spillage Volume (hm3) 500.0 25.00 Inflow (hm3) 400.0 20.00 Initial live Storage (hm3) 300.0 15.00 Final Water Level (m)

Water Volumes (hm VolumesWater 200.0 10.00 Initial Water Level (m)

100.0 5.00 (m) Reservoir Level Water 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month

Figure 5.30 – Reservoir analysis for the scenario C2

Scenario C2 consists on not turbinate in the driest months, which are June, July, August and September. In these months the affluences are kept in the reservoir, increasing the water level and consequently the net head. This type of scenario allows equipping a higher discharge but the turbines work during less days a year. With this configuration it’s possible to have higher installed capacity and fulfill bigger peak demands; on the other hand, it will generate less energy per year.

800.0 35.00

700.0 30.00

) 600.0 Spillage Volume (hm3) 3 25.00 500.0 Inflow (hm3) 20.00 400.0 Initial live Storage (hm3) 15.00 300.0 Final Water Level (m) 10.00

200.0 Initial Water Level (m) Reservoir (m) Reservoir Level Water Water Volumes (hm VolumesWater 100.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug.Sep. Out. Nov.Dec. Jan. + Month

Figure 5.31 – Reservoir analysis for the scenario C3.1

800.0 35.00

) 700.0 30.00 3 Spillage Volume (hm3) 600.0 25.00 500.0 Inflow (hm3) 20.00 400.0 Initial live Storage (hm3) 15.00 300.0 Final Water Level (m) 10.00

Water Volumes (hm VolumesWater 200.0 Initial Water Level (m) 100.0 5.00 (m) Reservoir Level Water 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month

Figure 5.32 – Reservoir analysis for the scenario C3.2

66 800.0 35.00

700.0

30.00

) 3 600.0 25.00 Spillage Volume (hm3) 500.0 20.00 Inflow (hm3) 400.0 Initial live Storage (hm3) 15.00 300.0 Final Water Level (m) 10.00 Water Volumes (hm VolumesWater 200.0 Initial Water Level (m)

100.0 5.00 (m) Level Water Reservoir 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.33 – Reservoir analysis for the scenario C3.3

Scenario C3 works in a similar way as scenario C2, but with scenario C3 the turbines are only stopped during two of the driest months of the year. In the months that the turbines don’t work (July and September in C3.1; June and August in C3.2 and August and September in C3.3), the water level in the reservoir rises and the water is used afterwards, allowing to equip higher discharges.

800.0 40.00

700.0 35.00

) 3 600.0 30.00 Spillage Volume (hm3) 500.0 25.00 Inflow (hm3) 400.0 20.00 Initial live Storage (hm3) 300.0 15.00 Final Water Level (m)

Water Volumes (hm VolumesWater 200.0 10.00 Initial Water Level (m) 100.0 5.00 (m) Reservoir Level Water 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month

Figure 5.34 – Reservoir analysis for the scenario C4

Scenario C4 is similar to C3 with the difference that the only month that the turbines don’t work is during August. The same as C2 and C3, this scenario is not the most appropriate when the objective is to supply a city, since it cannot fulfill its needs throughout the entire year. In order to use this configuration, other energy sources have to be included to guarantee the supply during the months that the turbines are stopped.

67 1600.0 50.00 45.00

1400.0

) 40.00 3 1200.0 35.00 Spillage Volume (hm3) 1000.0 30.00 Inflow (hm3) 800.0 25.00 Initial live Storage (hm3) 20.00 600.0 Final Water Level (m) 15.00

Water Volumes (hm VolumesWater 400.0

10.00 Initial Water Level (m) Reservoir (m) Reservoir Level Water 200.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. Month + Figure 5.35 – Reservoir analysis for the scenario C5

The objective of scenario C5 is obtain an installed capacity of 100 MW, for this to occur there is the need to equip a discharge much higher than the ones studied so far. The number of days that the turbines work is fixed in a way that the turbinated volume does not surpass the inflows. With this scenario the turbines are only working from March to July, being that in the other months the affluent volumes are being stored allowing the water level and reservoir volume to rise. In order to cope with this option, the dam height needs to be considerably higher than in the remaining scenarios, to increase the storage capacity.

800.0 40.00

700.0 35.00

600.0 30.00 Spillage Volume (hm3) 500.0 25.00 Inflow (hm3) 400.0 20.00 Initial live Storage (hm3) 300.0 15.00 Final Water Level (m)

Water Volumes (hm3) VolumesWater 200.0 10.00 Initial Water Level (m) Reservoir (m) Reservoir Level Water 100.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.36 – Reservoir analysis for the scenario C6

68 800.0 40.00

700.0 35.00

)

3 600.0 30.00 Spillage Volume (hm3) 500.0 25.00 Inflow (hm3) 400.0 20.00 Initial live Storage (hm3) 300.0 15.00 Final Water Level (m) Initial Water Level (m) Water Volumes (hm VolumesWater 200.0 10.00

100.0 5.00 (m) Reservoir Level Water 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.37 – Reservoir analysis for the scenario C7

Scenarios C6 and C7 work in a similar way as scenario C1; the difference is that during some days the turbines are stopped in order to allow reparations if needed. Since that during these periods the turbinated volume is zero, the amount of water available to turbinate the rest of the year will be higher, resulting in a higher equipped discharge and consequently higher installed capacity. On the other hand the total energy generated will probably decrease and the supply is not guaranteed during those periods.

5600.0 83.00

5400.0 82.00

) 3 Spillage Volume (hm3) 5200.0 81.00 Inflow (hm3)

5000.0 80.00 Initial live Storage (hm3) Final Water Level (m) 4800.0 79.00

Initial Water Level (m) Water Volumes (hm VolumesWater

4600.0 78.00 (m) Level Water Reservoir

4400.0 77.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.38 – Reservoir analysis for the scenario C8

Scenario C8 is the same as C1, but now it is considered a dam height of 80 meters and a full reservoir in the beginning of the modeling. This allows a much higher installed capacity and energy generation per year since the net head is much bigger than it was in the previous scenarios. Although, the construction costs associated with this dam height will be much bigger.

It was also considered the possibility of incorporating two and three groups of turbines in the hydropower facility (scenario 9 and scenario 10, respectively). This allows one of the turbines to be stopped (in order to allow repairs, maintenance or simply because a malfunctioning) and assure the energy supply to the city, since one of the turbines is always working. These two scenarios present the same advantages as C6 and C7 but without compromising the supply to Saurimo.

69 For the scenario C9, with two turbines, the simulation was made considering one stop of five days per year, for each turbine (ten days in total). It was also determined the months for the turbines to stop, which would result in higher energy generation at the end of the year.

Scenario C10 works the same way as scenario C9, the difference is that with C10 there are three groups of turbines and there are three stops per year. On the other hand, when one of the turbines is stopped there are two other still working, allowing more energy supply during this periods.

900.0 40.00 800.0

35.00

700.0 ) 30.00

3 Spillage Volume (hm3) 600.0 25.00 Inflow (hm3) 500.0 20.00 Initial live Storage (hm3) 400.0 15.00 Final Water Level (m) 300.0 10.00 Initial Water Level (m)

Water Volumes (hm VolumesWater 200.0 Reservoir (m) Reservoir Level Water 100.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.39 – Reservoir analysis for the scenario C9

900.0 40.00

800.0 35.00

) 700.0 3 30.00 Spillage Volume (hm3) 600.0 25.00 Inflow (hm3) 500.0 20.00 Initial live Storage (hm3) 400.0 15.00 Final Water Level (m) 300.0

Water Volumes (hm VolumesWater Initial Water Level (m)

200.0 10.00 Reservoir (m) Reservoir Level Water 100.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.40 – Reservoir analysis for the scenario C10

It was also studied the possibility of equipping two identical groups of turbines (with the same equipped discharge), with one of them working with Q/Qmáx lower than 1 during some periods. This allows equipping higher discharges, since that during some time there is only one turbine working hence there is more water available to turbinate, resulting in bigger installed capacities and at the same time the energy supply is assured.

Scenario C11 works with Q/Qmáx = 0.2, C12 works with Q/Qmáx = 0.4 and C13 works with Q/Qmáx = 0.6. With Q/Qmáx = 0.8 it is very similar to working with only the equipped discharge. Like this the turbines are always working but one of them works with only part of its full capacity, this causes the efficiency and the discharge to decrease as well as the power and energy generation during this periods. On the other hand since the equipped discharge is higher and the other turbine works at its

70 full capacity, so the power and energy generation increase. The objective is to optimize this tradeoff in order to maximize the equipped discharge and hence the installed capacity, allowing the HPP to be able to respond in peak situations and also to maximize the energy generated per year.

800.0 35.00 700.0

30.00

) 3 600.0 Spillage Volume (hm3) 25.00 500.0 Inflow (hm3) 20.00 400.0 Initial live Storage (hm3) 15.00 300.0 Final Water Level (m)

Water Volumes (hm VolumesWater 10.00

200.0 Initial Water Level (m) Reservoir (m) Reservoir Level Water 100.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. Month + Figure 5.41 – Reservoir analysis for the scenario C11.1

1000.0 40.00 900.0 35.00

800.0

)

3 30.00 Spillage Volume (hm3) 700.0 Inflow (hm3) 600.0 25.00 500.0 20.00 Initial live Storage (hm3) 400.0 15.00 Final Water Level (m) 300.0 Initial Water Level (m) Water Volumes (hm VolumesWater 10.00

200.0 Reservoir (m) Water Level 100.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.42 – Reservoir analysis for the scenario C11.2

800.0 35.00 700.0

30.00

) 3 600.0 25.00 Spillage Volume (hm3) 500.0 20.00 Inflow (hm3) 400.0 Initial live Storage (hm3) 15.00 300.0 Final Water Level (m) 200.0 10.00 Water Volumes (hm VolumesWater Initial Water Level (m) 5.00 100.0 (m) Reservoir Level Water 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month

Figure 5.43 – Reservoir analysis for the scenario C12.1

71 900.0 40.00

800.0 35.00

700.0 ) 30.00 3 Spillage Volume (hm3) 600.0 25.00 Inflow (hm3) 500.0 20.00 Initial live Storage (hm3) 400.0 15.00 Final Water Level (m) 300.0 Water Volumes (hm VolumesWater Initial Water Level (m) 10.00 200.0 (m) Reservoir Level Water 100.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.44 – Reservoir analysis for the scenario C12.2

800.0 40.00

700.0 35.00

) 3 600.0 30.00 500.0 25.00 Spillage Volume (hm3) Inflow (hm3) 400.0 20.00 Initial live Storage (hm3) 300.0 15.00 Final Water Level (m) Initial Water Level (m)

Water Volumes (hm VolumesWater 200.0 10.00

100.0 5.00 Reservoir (m) Reservoir Level Water 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. Month + Figure 5.45 – Reservoir analysis for the scenario C13.1

900.0 40.00

800.0 35.00

700.0

) 30.00 3 Spillage Volume (hm3) 600.0 25.00 Inflow (hm3) 500.0 20.00 Initial live Storage (hm3) 400.0 Final Water Level (m) 15.00 300.0 Initial Water Level (m)

Water Volumes (hm VolumesWater 10.00

200.0 (m) Reservoir Level Water 100.0 5.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month Figure 5.46 – Reservoir analysis for the scenario C13.2

72 Turbining with lower values of Q/Qmáx, as it happens with C11, it is possible to equip higher discharge values (since one of the turbines uses less amount of water, hence there is more water available), on the other hand the energy generated will be lower.

Scenarios C11.1, C12.1 and C13.1 consider that one of the turbines works with Q/Qmáx lower than 1 from May to September wherein scenarios C11.2, C12.2 and C13.2 consider that only one of the turbines is working at its full capacity during the entire year. The difference relies on the fact that with the first three scenarios (C11.1, C12.1 and C13.1) the energy generation is higher and with the last three scenarios (C11.2, C12.2 and C13.2) the installed capacity is higher because the turbines consume less water at the end of the year and it is possible to equip higher discharge values. Of course that, regardless of the chosen scenario, the facility can be operated in different ways depending upon the situation and more importantly the energy needs. Q/Qmáx can increase or decrease and the percentage of time during the year that both the turbines work at full capacity can also change, in order for the facility to adapt to the city’s needs.

Finally it was studied the possibility of a runoff river facility, in order to compare the indicators and to see if there is the need to have a reservoir associated with this facility. Even before this analysis, probably the indicators will be more attractive with the reservoir since the discharge values in the Chiumbe River variate a lot through the year and the reservoir allows a seasonal regulation, storing water in the rainy season and then discharge it the dry season, allowing to turbinate with a fixed discharge the entire year and a constant energy supply throughout the entire year. The reservoir reduces the dependence on the variability of the inflow, being that the facility is not totally dependent on the affluences.

Using the flow duration curve in section 1 it was analyzed a series of possible discharge values in order to determine the optimal value for this parameter. For each value of discharge considered, it was determined the power generation and the energy generation. The total cost of the facility was also calculated for each discharge value, considering a linear variation between 2 330 USD/kW for 1 MW and 1 700 USD/kW for 20 MW, according to Ramos, H.M. (Ramos 2010). This cost does not include the power lines, so the cost of connection to Saurimo had to be added to this value. With these quantities, the cost per installed MW and the cost per GWh produced per year were calculated. These calculations are presented in Table A- 54 of the Appendices I.

As it is possible to observe in Table A- 54, for lower discharge values the turbinated volume is higher. The reason for this is the shape of the flow duration curve. So for higher discharge values the power generation rises but since the turbinated volume decreases, the total energy generated per year is lower. Since the objective is to supply the city of Saurimo, it was decided to equip the discharge that allows more energy generation, which corresponds to 71.3 m3/s.

A comparison between the hypotheses studied so far, including the 13 scenarios and the possibility of a run of river facility, is made in Table 5.25 that follows.

The comparison is made based on a group of indicators. The indicators considered were the cost per installed MW of capacity, the cost per GWh generated per year and finally the MW per reservoir area. The indicators are the same as the ones considered in the first and second screenings already made for all the 10 sections, but the difference here is that the parameters are more accurate, after the reservoir analysis is made. The more attractive values of the indicators are marked in grey in the table. The more attractive values of the indicators are marked in grey in the table. Also in Figure 5.47 to Figure 5.50, some of the quantities presented in the table, namely the indicators, installed capacity and energy generation, are presented. This gives another perspective when comparing the scenarios studied so far.

365

25.1

26.1

13.9

71.3

River

0.961

3.174

847.0

Runof

365

75.4

36.1

44.4

49.9

0.46

41.0

1651

0.813

0.360

2.090

209.5

720.5

C13.2

2068.8

365

68.0

30.4

40.8

47.9

0.41

36.0

1602

0.745

0.303

2.237

224.5

632.3

C13.1

2080.2

365

80.2

42.2

46.3

50.9

0.48

47.0

1676

0.912

0.383

1.901

209.4

767.8

C12.2

2075.1

365

68.7

31.4

39.2

46.9

0.39

38.0

1577

0.802

0.298

2.187

230.6

591.3

C12.1

2095.3

365

84.4

50.3

48.3

51.9

0.51

55.0

1700

1.043

0.405

1.677

208.6

817.3

C11.2

2081.4

365

68.7

33.1

39.2

46.9

0.39

40.0

1577

0.844

0.305

2.077

225.3

591.3

C11.1

2099.9

360

C10

72.8

29.1

42.5

48.9

0.44

22.5

1626

0.684

0.350

2.502

208.2 675.4

2099.5

360

69.5

29.3

42.5

48.9

0.44

34.0

1626

0.689

0.333

2.371

208.8

675.4

2114.1

365

48.9

90.9

2.39

61.0

3589

0.217

0.470

4.283

209.4

445.9

224.8

5624.7

1923.7

355

70.6

29.3

42.5

48.9

0.44

68.0

1626

0.689

0.343

2.408

205.8

675.4

2083.7

345

70.6

30.2

42.5

48.9

0.44

70.0

1626

0.709

0.345

2.339

204.9

675.4

2084.5

C5 C5

Comparison between hypotheses for section 1 Comparison between hypotheses

109

68.6

59.9 0.76

1896

1.617

0.541

1.185

131.5

243.1

110.9

210.0

1307.5 1983.2

–

334

67.5

30.4

40.8

47.9

0.41

72.0

1602

0.745

0.328

2.219

205.9

632.3 2077.7

Table

304

68.3

32.4

37.6

45.9

0.37

80.0

C3.3

1552

C3.3

0.861

0.337

2.111

202.9

552.1

2101.2

304

69.8

33.1

39.2

46.9

0.39

80.0

C3.2

1577

C3.2

0.844

0.333

2.111

209.6

591.3

2101.2

304

68.3

32.0

37.6

45.9

0.37

79.0

C3.1

1552

C3.1

0.851

0.336

2.137

203.3

552.1

2075.0

243

80.9

44.0

44.4

49.9

0.46

1651

0.992

0.387

1.839

208.8

720.5

100.0

2099.5

365

69.5

28.5

42.5

48.9

0.44

66.0

1626

0.669

0.337

2.443

206.0

675.4

2081.4

)

/s)

)

of of

/GWh/year)

/MW)

)

reservoir(MW/km

MW per km MW

(USD*10

Cost per GWh/year Cost

(USD*10

Cost per installed MW MW per installed Cost

INDICATORS

Total Cost (USD*10 Cost Total

(GWh/year)

Energy Generated

areworking (days/turbine)

Time during the turbines turbines during the Time

Power Generation (MW) PowerGeneration

(hm

Maximum Reservoi Volume Reservoi Volume Maximum

(km

Maximum Reservoir Area Maximum

Net Head (m) Net

Dam's Volume (hm Volume Dam's

(m)

Lenght of the dam's crest crest dam's the of Lenght

Dam's Height (m) Height Dam's

Nunmber Turbines Nunmber (-)

Turbinated Volume (hm Volume Turbinated Equiped Discharge (m Discharge Equiped TOTALS

74 4.5 4.0 3.5

3.0

2.5 /MW) 6 2.0 1.5

1.0 (USD*10 0.5

0.0

Cost per Installed Capacity Installed Capacity Cost per

C9 C1 C2 C4 C5 C6 C7 C8

C10 Run…

C3.1 C3.2 C3.3

C11.1 C12.1 C13.1 C12.2 C13.2 Scenario C11.2 Figure 5.47 – Cost per MW of installed capacity, for each scenario

1.2

1.0 0.8

0.6 /GWh/year) 6 0.4

0.2 Cost per GWh/year GWh/year Cost per

(USD*10 0.0

C1 C2 C4 C5 C6 C7 C8 C9

C10 Run…

C3.2 C3.1 C3.3

C11.1 C12.1 C12.2 C13.1 C13.2 Scenario C11.2 Figure 5.48 – Cost per GWh generated per year

1.8 1.6 1.4

1.2

1.0

of Reservoir Reservoir of

2 0.8

0.6 (MW/km2) 0.4 0.2

MW per km per MW 0.0

C8 C1 C2 C4 C5 C6 C7 C9

C10 Run…

C3.1 C3.2 C3.3

C13.1 C11.2 C12.1 C12.2 C13.2 Scenario C11.1 Figure 5.49 – MW of installed capacity per km2 of reservoir

480 120 Energy Generation (GWh/year) 400 Installed Capacity (MW) 100

320 80

240 60

160 40

80 20 Installed Capacity (MW) Installed Capacity

Energy Generation (GWH/year) EnergyGeneration 0 0

C1 C2 C4 C5 C6 C7 C8 C9

C10 Run…

C3.1 C3.2 C3.3

C12.1 C11.2 C12.2 C13.1 C13.2 Scenario C11.1 Figure 5.50 – Energy and power generation for each scenario

75 5.2.1.2 Conclusions and final considerations about the Reservoir Analysis

By analyzing the table and figures presented above, the main conclusions that can be reached are the ones presented below:

 Scenario C8 is the one that allows more energy gains. On the other hand has an associated dam height of 80 m that results in a very big length for the dam’s crest and enormous dam volume when compared with other solutions. This is also revealed in the indicators, since that is the solution that presents higher costs per installed MW and energy generated.

 The run of river possibility reveals very low values of energy production when compared to the other solutions. Also in terms of installed capacity it’s not a very interesting solution. Its cost does not compensate either, which is easily understood by analyzing the cost per installed capacity and the cost per energy generated, some of the highest in all the scenarios.

 Despite the fact that scenario C5 presents the second bigger dam height of all the scenarios, it is still the one that presents the lower cost per installed capacity. This makes sense since the installed capacity is much bigger for this scenario than it is for the other ones, as it is shown in Figure 5.50. In terms of cost per energy generated this is not a very competitive solution. The major problem with this scenario is that it can only work for a limited number of days per year and in specific months, so it is not a very good solution when the objective is to supply a city.

 The remaining scenarios show similar values for the considered indicators. Although, based on the elements analyzed so far and on the analysis made individually, scenarios C11, C12 and C13 are the best solutions since they present the best values for the indicators and with these scenarios there is always one turbine working, assuring the supply to the city. Also with two turbines there is the possibility of stopping one of them, if needed or in case of a malfunctioning, and the facility keeps operating with the other one.

 By analyzing the values in Table 5.25, and considering scenarios C11, C12 and C13, scenario C11.2 presents the best values in terms of cost per installed capacity and C12.1 presents the best values in terms of cost per energy generated per year. C12.1, which corresponds to having one of the two turbines working at 40 % of its full capacity during five months, has associated the lowest cost per GWh generated per year and C11.2, that is the same as C12.1 but during the whole year and with the turbines working at 20 % of their capaity, corresponds to the lowest cost per MW of installed capacity.

Based on these facts, it is not possible to create a HPP in the Chiumbe River with an installed capacity of 100 MW that consists in a feasible project. As shown in this analysis, in order to achieve such a value one of two consequences are going to occur: either the cost of the facility is so big, with enormous and unfeasible construction works associated (for example dams with a crest length higher than 10 km, which happens for section 5 with the equipped discharge of Q90) that it does not compensate the investment when compared to other solutions; or the facility would have to be equipped with very high values of discharge, meaning it could only work a few months per year. Since the objective is to constantly supply the city of Saurimo along the year and not to fulfill peak demands in some periods, this is not a feasible solution. The only to achieve the 100 MW would be by studying the possibility of constructing several small hydropower facilities in the Chiumbe River basin that, all together, could reach this value.

Faced with these conclusions, it was decided to select scenario C12.1, which means equipping two turbines with a discharge of 38 m3/s with one of them working from May to September at 40 % of its capacity, and the other one working at its full

76 capacity the entire year. As already referred, regardless of the chosen scenario the facility can be operated in different ways depending upon the situation. The relation between the discharge that the turbine is working with and the equipped discharge (Q/Qmáx) can increase or decrease and the percentage of time during the year that both the turbines work at fully capacity can also change, in order for the facility to adapt to different situations.

Scenario C12.1 presents an installed capacity of 31.4 MW. Considering this value and assuming that the objective of the facility would be only to supply the city of Saurimo, there would be 31.4×1 000 000/200 000=157 W/inhabitant which is higher than the national average predicted for 2015 and equal to about 100 W/inhabitant (as explained in chapter 3.4), which means that about 11.4 MW could be used to supply the Catoca mining society, located near Saurimo. It should also be noted that the objective for after 2017 is to have an available power per capita equal to 49 W/inhabitant in group E (where Lunda Norte and Lunda Sul are included and as explained in chapter 3.4) so the facility in study with scenario C12.1 allows to achieve this value with a big margin.

After deciding the best scenario and configuration for the facility, it was analyzed the concept of firm energy. Firm energy is the amount of energy guaranteed to be available at a given time. The definition of firm energy of a hydro plant is often dictated by the system requirement for such guaranteed energy. Typically, firm energy from a hydro power plant may be defined as the energy that could be generated by the plant during low flow sequences. Mean energy is an estimate of average annual energy production of a hydro power plant if historical river flows were repeated. The estimate is derived by simulating proposed plant operation using historical flows.

To calculate the firm energy, it was made a reservoir analysis with the scenario C12.1 for each of the nine years of data (instead of using the average values as it was made before when comparing the different scenarios) and the total annual energy generation was calculated. The value considered for the firm energy was the minimum annual energy generation from nine year long series of data, which corresponds to the driest year of the series. The value corresponds to 188.8 GWh and it is safe to assume that it as a probability of occurrence of about 89 % (1-1/9).

The mean energy corresponds to the energy generation calculated with the series of mean affluent volumes, which is 230.6 GWh. This is illustrated in Figure 5.51.

300.0 300

250.0 250

200.0 200

150.0 150 Non-firm energy Firm energy 100.0 100 Mean energy 50.0 50

Annual energyproduction (GWh) Annual 0.0 0

1966/67 1967/68 1968/69 1969/70 1970/71 1971/72 1972/73 1973/74 1965/66 Figure 5.51 – Firm energy

The difference between mean energy and firm energy is called secondary energy, or non-firm energy, and is particularly important in the design and negotiation of power contracts. Non-firm energy refers to all available energy above and beyond

77 firm energy. Energy benefits of both firm and non-firm energy are measured in terms of the fuel and other variable operating costs that would otherwise be required to produce that amount of energy by the least expensive technically feasible alternative.

Finally it was made an analysis with scenario C12.1 for the worst possible situation in terms of affluent volumes, taking in consideration the available hydrological data. In order to achieve this, it was defined a series of minimum monthly affluent volumes, in which each entry corresponds to the minimum monthly value of the entire series for that month. This series of minimum volumes is represented in Table 5.23, presented in the beginning of this chapter. This is just a hypothetical situation and probably nothing similar will ever occur, although it provides a reference value for the lowest energy generated by the facility. The reservoir analysis for this situation is presented in Figure A- 34 and Table A- 56 of the Appendices I. With this affluent volumes and scenario C12.1, the total turbinated volume is 1 488.8 hm3 and the total energy generated per year is 44.2 GWh. The total energy generated per month with each turbine is presented in Figure 5.52. These values correspond to the worst situation, so it can assured with a high probability that the minimum amount of energy generated by the facility is

44.2 GWh.

2.5 Turbine 1 Turbine 2 2.0 1.5 1.0 0.5

0.0 Energy generated (GWh) Energygenerated Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Month Figure 5.52 – Energy generated each month with each turbine, for the worst possible situation and with scenario C12.1

In conclusion, after the reservoir analysis it was decided that the best configuration for the hydropower facility was a 36 m height dam, with two groups of turbines and with an equipped discharge of 38 m3/s each and with one of them working at 40 % of its full capacity from May to September and the other one working at its full capacity the entire year. This configuration generates a total of 230.6 GWh per year and the facility has an installed capacity of 31.4 MW (15.7 MW per group).

5.2.2 Construction Materials and Possible Dam Types

The selection of the dam type is highly dependent on the geology and topography of the location, on the type and location of the hydraulic structures and on the cost of construction. In this chapter the geology of the location was first analyzed in order to determine whether or not it is possible to build a concrete dam since the foundation conditions can difficult this process, and also if there are available resources near the construction site that can be used as construction materials. To analyze the construction materials, the geology and the soil types were taken into consideration. The Soil Atlas of Africa was used for the soil analysis and the geology study was based on a geology map of Angola. The geology map was adapted to the region of the case study where section is located, using the Quantum GIS software, this is presented in Figure 5.54. Also Google Earth was used to analyze the local conditions in section 1 and an image of this area is presented in Figure 5.53.

78 By analyzing the geology map of Angola it is easily noted that the superficial layer is mainly composed by sand formations. These formations are homogeneous deposits without stratification of thin sand with clay and iron hydroxides, which are responsible by their color. An analysis of the soil typology was already conducted in chapter 5.1.3.2 when it was made the characterization of the Chiumbe River basin.

According to the geology map, the superficial formation lays on a siliceous sandstone layer, although in the region of section 1, it lies directly on the formations of the substrate. These formations are from the archaic period and include gneisses, granites, migmatites, gabbros, quartzites, schists and some granite-migmatite complexes. The granites, gabbros and gneisses are plutonic rocks that evolve, normally from schists, during a slow metamorphic process at a considerable depth. These rocks form crystals during a chemical process and present a very high mechanical resistance. Migmatites are similar to granites but are characterized by higher foliation. The schists have an accentuated foliation, which considerably reduces their resistance in the weaker direction of the rock. Finally the quartzites, which evolve initially from sands, are characterized for being very resistant and abrasive, also they present considerably good mechanic performance.

Of course that some geological survey studies need to be conducted in the region to determine more accurately the type of rocks and to determine the state of those rock foundations, mainly their state of fracturing, permeability and deformability. If the rock is much fractured there is the need to inject the fractures in order to reduce the permeability and increase the resistance. Even if the foundation presents good conditions, the superficial layer of soil and decomposed rock needs to be removed, and this practice in the case of concrete dams can have high costs associated.

Figure 5.53 – Google Earth image of section 1 (16/09/2015)

Figure 5.54 – Geology map of Angola in the region of section 1 (Adapted using Quantum GIS)

To more accurately determine the type of rock formation in the region of section 1, first a surface geological survey study should be conducted (at a scale of 1:5000 would be acceptable). This allows identifying the superficial formations and the ones with few coverage. Then some survey studies at higher depths using double sampler are carried out. These studies make it possible to understand the geology at higher depths and in specific locations, which are defined considering the superficial surveys and the topography. It should be considered vertical but also inclined surveys.

As it is possible to observe in the geological map, the formations of the substrate appear at smaller altitudes (close to the bottom of the valley) where the river bed develops, washing away the superficial layers. This phenomenon sometimes occurs due to the existence of discontinuities or weaknesses of the terrain, to where the water flow is oriented. Even if the river is meandered, the discontinuities might be present at higher depths, and can be hidden by the superficial layers and deposits of sediments. Based on this, it should be considered inclined surveys, essentially in the bottom of the valley, despite the fact that they are more expensive. During the survey phase, reports of the current situation should be elaborated by the geologists and in the end a classification is made by the geologists and engineers.

The two most common types of dams are the ones presented in the following topics:

80  Embankment dams: Embankment dams can be divided in earth dams and rockfill dams. They can also be defined as homogeneous or zoned dams. Embankment dams are most commonly used when there are embankment materials nearby the dam site and are normally applied on foundations with relatively poor quality, where concrete dams could not be founded.

 Concrete dams: These dams can be divided in the following categories:

 Concrete gravity dams: These dams can be used in a large range of scenarios, if the soil conditions allow it.  Arch dams: Applicable in narrow valleys characterized by resistant rock formations. There can also be multiple arch dams.  Buttress dams: these types of dams are used to reduce the uplift force on the dam foundation.  Mobile dams: These are normally low height dams, where most of the valleys obstruction is due to spillway gates.

For the case study the most suitable dam types would be a homogeneous or zoned embankment dam, or a concrete gravity dam. An arch dam would not work because the valley does not present adequate conditions, and a mobile would not be a good alternative since the dam heights that where studied are considerable (close to 40 m). About the buttress dams further studies could be made in order to decide about their applicability to this case study. As analyzed using the geologic map, the formations of the substrate appear to have acceptable characteristics to found a concrete dam.

Nevertheless in order to build these types of structures the available materials in the location must be considered. As already referred, embankment dams require more volume of materials but are normally cheaper. So even if the surrounding conditions allow the construction of a concrete dam, the possibility of an embankment dam should not be removed from the picture until more information is available, since that a lot of parameters interfere in this decision and might as well influence the total cost of the facility.

Considering the concrete dam type, the main construction materials needed are:

 Steel: this is used for the reinforced concrete and in the Angolan actual context it has to be imported, since there is no supply in the country;

 Cement and binders for concrete: this depends on the type of concrete and the percentages used in the formula but it is not dependent on the available materials on site. There are currently some production centers in Luanda that belong to companies like MUNDIBETÃO;

 Aggregates: The choice of aggregates to use is very dependent on the geology of the region. In the region in study there are alluvial deposits, but normally the sand in alluvial deposits consists in rolled sand which is not adequate for concrete. Also, in Angola, there are a few granite quarries available. Granite after crushing can serve well as an aggregate and this alternative should be studied. There might be the need to mobilize a crusher machine depending on the dimensions of the rocks and the dimensions needed for the aggregates, but in terms of availability it appears that there will be no problem. It should be elaborated an inventory of all the quarries available in the location and to know about the amount of supply that they are able to provide as well as its quality in order to determine if it is enough to fulfill the needs;

 Water: For this element the problem is not the quantity since there is a lot of water available, the problem might be the quality. The quality of the water should be analyzed in order to decide if it’s good for production of concrete, and this

81 analysis needs to be done with caution since the quality of the water can affect the type of cement and aggregates used;

If the conditions described before, mainly the availability of the construction materials and the foundation conditions, are verified and if after a more detailed analysis the costs do not increase considerably, a concrete gravity dam seems to be a good solution.

In the case of an embankment dam the main construction materials are granular materials with variable dimensions and considerable permeability. These materials will assure the stability of the dam. Also for the impermeable area of the dam, a clay core could be considered, since the soils in the regions have considerable percentages of clay.

In conclusion and mainly based on what was described in this topic, namely the available materials and geology in the region where section 1 is located, there is the possibility of constructing an embankment or a concrete dam. The volume of materials associated with an embankment dam are normally higher than they are in a concrete dam, on the other hand the cost of concrete per cubic meter is higher than the cost of the materials used in the an embankment dam, which are available in the case study region, so the first solution (embankment) is normally cheaper. Nevertheless in a concrete dam it is easier to allocate the hydraulic structures.

5.2.3 Flood Analysis

In an initial phase, the physiographic characteristics of the catchment area controlled by section 1 were analyzed. Also the concentration time was calculated using different methods and the average value was assumed as the concentration time for the catchment area. The methods used to calculate the concentration time were the ones presented in the following topics:

퐿0.77  Kirpich: 푡푐 = 0.0663 0.385 (9) 푑푚

L 0.76  Temez: tc=0,3( 0,25 ) (10) dm

4√A+1.5L  Giandotti: tc= (11) 0.8√hm

L 0.47  NERC: tc=2.8( ) (12) √d10:85

Where:

 tc - Concentration time (h);  L - Length of the main water course (km);

 dm - Mean slope of the main water course (m/m);  A - Corresponds to the area of the catchment area (km2);

 hm – Mean height of the catchment area (m);

 d10:85 – mean slope between 10 % and 85 % of the length of the main water course

The physiographic analysis and the calculation of the concentration times for the catchment area in study are presents in Table 5.26 and Table 5.27 respectively.

Table 5.26 – Physiographic characteristics of the catchment area controlled by section 1

Area (km2) 9411.9

hm (m) 105.5 L (km) 333.4 Lenght at 100% (m) 0.0 Altitude at 100 % (m) 1370 Lenght at 85% (m) 50.0 Altitude at 85 % (m) 1270 Lenght at 10% (m) 300.1

Altitude at 10 % (m) 990

Lenght at 0% (m) 333.4 Altitude at 0 % (m) 950

dm (m/m) 0.13% Difference between the lenght at 10 % and 250.1 the lenght at 10 % (km) d10:85 (m/km) 1.12

Table 5.27 – Concentration time in the catchment area controlled by section 1

Kirpich (h) 76 Temez (h) 88 Giandotti (h) 73 NERC (h) 42 Average (h) 70 Adopted tc (h) 70 tc adoptado (min) 4180

To analyze the floods, first the maximum precipitation in 24 hours (P24) was determined for each year of the 16 years-long series of data. Then a statistical law was adjusted to this series. In this case the Gumbel law was considered. The series of

P24 is not a very long series of data, which of course would be better in order to obtain a more precise adjustment of the statistical law.

The maximum values of precipitation in 24 hours that occurred in each of the 16 years of precipitation data available are presented in the Figure 5.55. In this figure, the values of P24 are already presented in a descendent order and is also made the adjustment to the Gumbel distribution function, by calculating the parameters a and x0 of the distribution function, the F(x) empiric and the F(x) theoretical. In Figure 5.55 the adjustment is presented graphically.

83 n P24 (mm) F(x)emp. F(x)teo_Gumbel F(x)emp. F(x)teo_Gumbel 1 28.1 0.059 0.091 2 31.0 0.118 0.164 1.0 3 31.6 0.176 0.181 4 33.4 0.235 0.236 0.9 5 34.4 0.294 0.269 6 35.8 0.353 0.317 0.8 7 36.5 0.412 0.343 8 38.7 0.471 0.419 0.7 9 38.9 0.529 0.424 0.6 10 39.0 0.588 0.427 11 47.1 0.647 0.676 0.5 12 50.8 0.706 0.760 13 51.5 0.765 0.773 0.4 14 57.3 0.824 0.863 0.3 15 60.3 0.882 0.895 16 78.4 0.941 0.980 0.2

Dimension 16 0.1 Average 43.3 Standart Dev. 13.44 0.0 Assimetric coef. 1.33 20.0 40.0 60.0 80.0 a 0.0954 Precipitation (mm) x0 37.25 Figure 5.55 – Adjustment of the Gumbel law to the precipitation series

By analyzing the figure it is possible to observe that the adjustment is acceptable, but in order to be sure about this conclusion, the χ2 adjustment test was used and the calculations made are summarily presented in Table A- 57 of the Appendices I. As shown in this table, the value calculated is inferior to the standard value for a confidence interval of 95 %, so this means that the Gumbel law presents a good adjustment to the precipitation series.

After the adjustment, the values of maximum daily precipitation were determined for different return periods, based on the Gumbel law. The return periods considered were 20, 50, 100 and 1000 years.

According to (Gresillon and Puech 1996) for the countries in the western region of Africa the value of the parameter b in the udometric curves (see equation (13)) can be considered as 0.12. The assumption of this value consists on an approximation and the fact that this value is considered the same for all the return periods is a simplification, which was made since there is no more available information. Based on the value of b and considering the values of P24, the coefficient a was calibrated and the udometric curves, whose equation is represented below, were calculated for each of the return periods described. These calculations are presented in Table 5.28 and the curves are presented in Figure 5.56.

푃 = 푎푡푏 (13)

In the equation, P represents the precipitation in mm, t is the time in hours, a and b are parameters adjusted according to the values of precipitation and for different return periods.

This is also an approximation since the calibration of the parameter a is made only based on the precipitation for t=24 hours and for a short series of data. To calibrate this parameter properly, more values of precipitation corresponding to smaller intervals should be considered, but this was the only available information.

84 Table 5.28 – Calculation of the maximum precipitation for different return periods and calibration of the coefficient a T (years) F(x)teor. k P 24h (mm) a 20 0.950 1.9 68.4 46.7 50 0.980 2.6 78.2 53.4 100 0.990 3.1 85.5 58.4 1000 1.0 4.9 109.7 74.9

140

120

100

Precipitation (mm) Precipitation T= 20 years 40 T = 50 yeras T= 100 years 20 T= 1000 years

0 0 20 40 60 80 Time (h) Figure 5.56 – Udometric Curves for the return periods of 20, 50, 100 and 1000 years

Once the udometric curves were obtained, the precipitation hyetographs were calculated for each of the return periods (20, 50, 100 and 1000 years) by obtaining the precipitation for consecutive durations of time and calculating the differences (ΔP) between those values. Finally the hyetographs are obtained by organizing the values of ΔP in an alternate way.

These hyetographs were defined for durations equal to the concentration time (tc) and double the concentration time (2tc) of the hydrographic basin defined by section 1. The blocks were defined with a duration D of two and four hours for the tc and 2tc, respectively so, for each hyetograph there are 35 blocks. The hyetographs obtained are presented in Figure A- 35 to Figure A- 42 of the Appendices I.

Regarding the precipitation hyetographs, the higher the number of blocks for the same duration of the rainfall considered, the higher will be peak discharge, since the maximum intensity of precipitation (mm/h) is also higher. The consideration of an alternate distribution for the precipitation blocks, results in higher values of peak discharge. Considering the same amount of blocks for hyetographs with the durations of tc and 2 tc, the first one is associated with more severe values of peak discharge and the second one in higher volumes of flood. So in order to calculate the spillway, the hyetograph with the duration of tc should be used.

With the hyetographs concluded, the flood analysis was made using the HEC-HMS software. For the catchment area in study, three sub-basins were defined and the respective concentration times were calculated. It is important to separate the sub basins since they have considerably different concentration times and areas and this will influence the peak discharge

85 values. These sub-basins are present in Figure 5.57. The physiographic characteristics and the concentration time of the sub-basins defined are described in Table 5.29.

To use the model in the HEC-HMS software it is necessary to calibrate the curve number parameter, which is a coefficient that accounts for with the precipitation losses, or the precipitation that is not converted into runoff. The curve number which is going to be used is CN(III) that considers the soil to be humid or saturated before the occurrence of the extreme event, and like this the flood event will be more severe. The curve number for medium soil conditions, the CN(II) can be found tabulated according to the soil type and the soil coverage. The values for CN (II) are presented in Table A- 58 of the Appendices I.

As already stated, the soils in the Chiumbe River basin are sandy clay loam soils, which correspond to something in the interval of soil groups B and C. The region is characterized by woodland and mainly savannas. From the table it is considered a value for woods with fair hydrological conditions, so a value between 60 and 73. The value considered was CN(II)=67. In order to calculate the value of CN(III) from the one obtained from the table, the following expression is used:

23CN(II) CN(III)= =82.36 (14) 10+0.13CN(II)

Figure 5.57 - Sub basins of the catchment area in study

86 Table 5.29 - Physiographic characteristics and the concentration time of the three sub basins

Basin Name Sub Basin 1 Sub Basin 2 Sub Basin 3 Area (km2) 5679 3401 332

hm (m) 91.9 62.1 15.8 L (km) 317.4 180.6 16.0 Lenght at 100% (m) 0.0 0.0 0.0 Altitude at 100 % (m) 1370 1170 970 Lenght at 85% (m) 47.6 27.1 2.4 Altitude at 85 % (m) 1270 1130 970 Lenght at 10% (m) 285.7 162.6 14.4 Altitude at 10 % (m) 1010 990 960 Lenght at 0% (m) 317.4 180.6 16.0 Altitude at 0 % (m) 970 970 950

dm (m/m) 0.13% 0.11% 0.12% Difference between the lenght at 10 % and 238.0 135.5 12.0 the lenght at 10 % (km)

d10:85 (m/km) 1.09 1.03 0.83

Kirpich (h) 73 50 7 Temez (h) 85 57 9 Giandotti (h) 72 52 13 NERC (h) 41 32 11 Average (h) 68 48 10 Adopted tc (h) 68 48 10 tc adoptado (min) 4067 2860 603

Finally, after applying the HEC-HMS to the conceptual representation presented in Figure 5.58, the flood hydrographs were determined. In the program the loss method considered was the SCS Curve Number and the transform method was the SCS unit hydrograph. The base flow was not considered in these calculations and the value for tlag (response time) used was 0,6tc. To account for the propagation of the flood in the reach, the Muskingum-Cunge routing method was used, considering a Manning’s value of 0.02 and a trapezoidal shape of the channel with dimensions measured in Google Earth, which consists in an approximation.

Figure 5.58 – Conceptual representation used in HEC-HMS

Finally the flood hydrographs are presented for each of the return periods, being that only the most severe hydrographs, between tc and 2tc, which correspond to the duration of tc, as explained before.

87 4000 T=20, t=tc 3500 T=50, t=tc

3000 T=100, T=tc

/s) 2500

3 T=1000, t=tc

2000

1500 Discharge (m Discharge 1000

500

0 0 25 50 75 100 125 150 175 200 225 250

Time (hours) Figure 5.59 – Flood hydrographs for different return periods

From the flood hydrograph the peak discharge is obtained. This value is going to be important in future works in order to design the spillway. For a return period of 1000 years the correspondent peak discharge value is 3 637 m3/s.

5.2.4 Hydraulic Structures

5.2.4.1 Preliminary Study of the Hydraulic Structures

In this section a resumed analysis is made for the possible types of hydraulic structures as well as their location in the facility. The hydraulic structures analyzed where the spillway, the water intake, bottom outlet and the conveyance/adduction system.

The spillway can be dimensioned with gates to control the flow, or it can be a free discharge spillway. The gates have the advantage of allowing the MWL (Mean Water Level) to coincide with the FRL (Full Reservoir Level), which results in a smaller reservoir area with less cost of expropriations and deforestation or in bigger live storages that allow the facility to generate more energy along the year. On the other hand the gates have operational costs, higher investments associated and consist on major risk for the dam safety.

For the spillway, a lot of solutions can be considered. It could by a simple chute spillway (composed by a channel on the hillside) that can be applied to every kind of dam since it is independent from the dam structure. There is also the possibility of using a shaft spillway (vertical or inclined) but there is probably no need for that and it is normally more expensive than the chute spillway. Finally, a fuse gate spillway could also be considered that would work in emergency situations.

The spillway could also be located over the dam. This type of spillway should only be used in concrete dams in order to have good foundation conditions or in a mixed dam where for the center of the dam is used concrete and for the remaining parts of the dam it can be used embankment material, which is cheaper. In an embankment dam this should not be implemented since the dam’s body does not function very well as a foundation for the spillway. For this type of spillway there are a lot of alternatives that can be installed with or without the use of gates. Some of the possible and most common alternatives for a spillway over the dam are the ones presented in the following topics:

 Spillway over the dam with guided fall and an energy dissipation structure;

88  Spillway over the dam with guided jet and downstream ski jump, normally dimensioned with energy dissipation on the river bed;

 Stepped spillway, that allows energy dissipation in the spillway;

 Spillway over the dam with free fall that releases water when it reaches a certain level, and plunging pool downstream for energy dissipation and protection of the dam structure.

Another type of spillway that can be used is a spillway trough orifices in the dam. This kind of structure needs to have gates associated that control the flow, and can be located at different heights in the dam. This type of spillway can only be used in a concrete dam.

For the facility in question the use of a channel for the conveyance system was not considered because with that configuration, it would not be taken advantage of the dam height in the head difference. The power house is located at an altitude of 940, as considered before, allowing a maximum total head of 56 meters, since the FRL was considered at an elevation of 996 meters.

In order to take full advantage of the natural drop of the river’s bed, the conveyance system was considered to be composed by a concrete tunnel and a steel penstock/conduit in some places, namely the ones where the soil coverage didn’t had enough depth to assure que security of the concrete structure. Depending on the dam type and location of the water intake, the conveyance system could be implanted in several locations. In the case of a concrete dam, with the water intake located on the dam body, and in the case of an embankment dam with separated water intake structure, the layout of the conveyance system can be different. Of course that by using a channel the cost would be lower, since the materials are cheaper and there is no need for big excavations. Also the penstock and the tunnel have elevated cost associated, not only in terms of fabrication and the ground movements associated, but also in terms of transportation.

The bottom outlet can be dimensioned to use the diversion scheme created during the construction of the dam. The diversion scheme is used to divert the river from its natural course in order to dry the location for the dam construction. It is dimensioned considering a certain discharge corresponding to a return period, taking into account the costs and the risks associated. The diversion scheme was considered to be elaborated in two phases. In a first phase, a cofferdam is constructed to isolate the left bank of the dam. Then the center and left part of the dam are constructed, leaving a hole in the center part of the dam’s body, where the bottom outlet will be located. After this, the cofferdam is removed and another one is constructed to isolate the right bank of the dam. Finally the remaining part of the dam is constructed, the cofferdam is removed and the bottom outlet is constructed. At the end of this process, the bottom outlet is closed so that the reservoir starts filling for the facility to start operating.

Based on the hypotheses presented before and also in what was presented in chapter 5.2.1 the decisions regarding the displacement of the main hydraulic structures and the type of the dam were:

 Dam type: It was considered a mixed dam, composed by an embankment part and a central part made out of concrete. This allows a simple allocation of the hydraulic structures in the center of the dam, and at the same time the costs of construction are expected to be lower since the embankment materials are less expensive than the concrete. The central part of the dam was considered to be a typical gravity dam;

 Spillway: It was considered a spillway over the dam with guided fall and an energy dissipation structure;

89  Water intake: It was considered to be located in the dam’s body;

 Conveyance system: Starts in the end of the water intake and it is connected to the power house. It’s composed by a conduit, tunnel in concrete and penstock with the layout made in a straight line. The adduction system was considered to have always the same slope and at this stage the water hammer was not considered;

 Bottom outlet: It was considered to be located in the dam’s body;

 Powerhouse: Located at an altitude of 940 m;

Based on the contours already obtained in Quantum GIS and considering satellite images from Google Earth that were used as a comparative item for the information obtained with the software, a map is created for the location of section 1 and a sketch for the possible locations of the hydraulic structures was elaborated, based on the comments presented before. This map shows the location of the section in the Chiumbe River basin, as well as the catchment area defined by this section and the reservoir created by the dam. This sketch is presented in Figure 5.60. The map created is scaled but the sketches are not, since they consist only in an auxiliary for the explanation of the hypotheses. More accurate and detailed drawings were also elaborated in a more advanced stage, as explained in the methodology.

Figure 5.60 – Location of the hydraulic structures and dam type

5.2.4.2 Pre Dimensioning of the Spillway

In order to calculate the spillway, it was first considered the flood weakening in the reservoir. To consider this weakening the program HEC-HMS was used and the conceptual representation of the catchment area and the reservoir was the one presented in Figure 5.61.

Figure 5.61 - Conceptual representation used in HEC-HMS to simulate the flood weakening

The model is basically the same as the one used before to analyze the floods, with the difference that the reservoir was included. The analysis was made for the return period of 1000 years and in the program the reservoir was simulated as an outflow structure with an elevation-storage method. It was considered one spillway and several lengths (L) were tested, as it is presented in Table 5.30. As it is possible to observe in the table, for higher lengths of the spillway the weakening of the flood is smaller, which means that the maximum outflow discharge is higher than it is for smaller lengths of the spillway. On the other hand the maximum water level upstream is lower, which means a lower total height of the dam.

Table 5.30 – Weakening of the floods in the reservoir

L (m) Storage (hm3) Outflow (m3/s) H (m) FRL (m) MWL (m) 250.0 926.2 2291.4 2.6 995.6 260.0 921.2 2324.9 2.5 995.5 270.0 916.3 2356.4 2.5 995.5 993.0 300.0 903.0 2444.4 2.4 995.4 500.0 842.1 2838.1 1.9 994.9 1000.0 772.7 3249.7 1.3 994.3

To calculate the maximum water level, it was calculated the water height over the full reservoir level (H), that was estimated at 993 in the reservoir analysis. The equation used in this calculation is the one presented below:

Q=CL√2gH3/2 (15)

In the equation Q (m3/s) represents the discharge capacity of the spillway for water height of H (m), g (m/s2) is the acceleration of gravity and C is a coefficient, which has the value of 0.5 for this type of spillway. The decision regarding the length of the spillway is made considering a tradeoff between the length of the spillway and the total dam height. For smaller lengths, the dam height will be bigger since the maximum water level is higher and for bigger lengths, it happens the opposite. In the end it was considered a length of the spillway of 250 m, which corresponds to a maximum water level of 995.6 m. It was considered that the top of the dam would be at an altitude of 998 m and the maximum water level would be at 997 m, in order to allow a gap of 5 m between the top of top of the dam and the spillway. This is a little higher than the total high estimated in the reservoir analysis, since that in the reservoir analysis the dimensions of the spillway were not considered.

91 The weakening of the flood in section 1 for a return period of 1000 years and for a spillway length of 250 m is presented in Figure 5.62.

4000 3500 Inflow (m3/s) Outflow (m3/s)

3000 /s) 3 2500 2000 1500 Discharge (m Discharge 1000 500 0 0.00 5.00 10.00 15.00 20.00 25.00 Time (days)

Figure 5.62 - Weakening of the floods in the reservoir for a return period of 1000 years

Using equation (15) it was determined the discharge capacity of the spillway considering a length of 250 m and a maximum water level of 4 meters. It was obtained the value of 2 291 m3/s, which corresponds to the maximum discharge capacity of the spillway. This value is considerably over the maximum value of peak discharge of the flood hydrograph, without the weakening and for a return period of 1000 years, which means that the probability of overtopping is very low. Although the floods were determined using a very short series of values that might not be representative of the real flood for a return period of 1000 years. Also the spillway develops along the body of the dam, in the concrete region as explained before, and in the end there is an energy dissipation structure.

5.2.4.3 Considerations about the Remaining Hydraulic Structures

In this topic some considerations on the remaining hydraulic structure were made, namely the water intake, the bottom outlet and the adduction system. These considerations and assumptions, as well as the pre dimensioning of the spillway, were very important when elaborating the pre study drawings and are presented in the following topics:

 Water intake:

 The water intake structure is considered as part of the dam. There were considered two vertical gates. The entrance of the water intake has a rectangular shape and then it is made a transition to a circular shape;  It is located at an elevation of 975 m and the connection to the adduction circuit is made at an elevation of 960 m, which corresponds to the surface of the terrain, meaning that the adduction systems starts bellow the surface;  The shape of the water intake needs to be dimensioned in a way that local pressures do not reach the vapor pressure of the water in order not to occur cavitation. It should be avoided the formation of vortices, the separation of the flow from the walls of the water intake and the entrance of sediments in the water circuit. This being said, the minimum submersion has to be verified in order to avoid cavitation, and a grid needs to be dimensioned for the entrance of the water intake to keep the sediments from entering the circuit, which might damage the remaining hydraulic organs (e.g. valves , turbines, filters) or that might be undesirable in terms of maintenance;  The minimum submersion was verified using expression (24) (Gordon, 1970), where v is the velocity in the intake, D the diameter and C a coefficient equal to 1.7:

92 S 1 V ≥ +C (24) D 2 √gD  To dimension the diameter of the water intake it was considered a maximum velocity of 4 m/s and considering the total discharge the diameter should be fixed at 5 m;

 For the dimensioning of the grid it was considered an inclined rectangular metal grid with the bars welded to the rectangular structure. When dimensioning the grid it is determined the spacing between the bars and their section. In most cases, what conditions the spacing is the hydraulic machines, in this case the turbines, being that the spacing should be recommended by the manufacturer. The bars were considered to have a rectangular section and their width has be enough to resist the axial forces in the direction of the flow;  It was also considered a cleaning mechanism for the grid;

 Hydraulic circuit:

 The adduction system was considered to be composed by a conduit, a tunnel and two penstocks that connect the tunnel to the powerhouse (e.g. the turbines);  To dimension the adduction system it was defined the longitudinal profile of the terrain and then designed the longitudinal profile of the circuit;  The first part of the circuit is composed by a steel conduit with 10 cm of thickness. When the depth, relative to the surface of the terrain reaches the double of the conduits diameter (approximately 10 m), the circuit continues in a concrete tunnel with a thickness of 20 cm. Finally when the depth becomes lower than 10 m the tunnel is divided in two penstocks with 3.5 m of diameter, in order not to have velocities higher than 4 m/s. The two penstocks are connected with the two turbines in the power house. The specific weight considered for the steel conduit was 80 kN/m3, in order to determine its total weight in kg;  For the tunnel it was considered a maximum velocity of 2.5 m/s and there were considered 80 cm extra to the diameter of the tunnel in order to account with the excavations. The cost was defined per meter of tunnel;

 Bottom outlet

 The bottom outlet is located near the water intake at an elevation of 967 m in the concrete part of the dam. The final part of the structure is at an elevation of 960 m;  It is installed one vertical gate upstream of the transition from a rectangular section to a circular section;  It was assumed a diameter of 2 m for the bottom outlet and the in the end of the structure there is a Howell-Bunger valve installed and the jet lands in the energy dissipation structure;  Since that the bottom outlet uses the river diversion scheme used in the construction stage of the dam, its diameter is related to the risk associated at this stage. The smaller the diameter, the higher the risk and the smaller the costs. But this does not influence the total cost of the facility so it was not considered;

5.2.5 Pre Design of the Turbines

Turbines can be classified in two different groups, whether the wheel of the turbine is moved by flow at the atmospheric pressure (action turbines) or by pressurized flow (reaction turbines). The most used action turbines are Pelton turbines, and the reaction turbines can be classified according to the direction of the flow relatively to the wheel of the turbine, being that the most used ones are Francis turbines (radial turbines) and Kaplan turbines (axial turbines) (Quintela 1981).

93 The first thing that was done was deciding on the more appropriated type of turbine to use, until this stage it was assumed a Francis turbine for the comparison of alternatives but it was not made an analysis on this topic. The decision of the type of turbine was made based on an abacus adapted from the Bureau of Reclamation that describes de domains of applications of each of the turbines referred (Pelton, Francis and Kaplan) and is presented in Figure 5.63. The decision is made using the power (15.7 MW per group), the equipped discharge (38 m3/s per turbine) and the net head (46.9 m), parameters which were already defined in the reservoir analysis (section 5.2.1).

Figure 5.63 – Domains of application of Pelton, Francis and Kaplan turbines (Quintela 1981)

For some values it is possible to use different types of turbines. In these situations the choice between the pre-selected types (using the parameters described in the previous paragraph) is made considering the advantages and disadvantages of each type, in what concerns the functioning, installation and maintenance.

For the present study it was decided to use a Francis turbine, which has the advantages of occupying less space, allowing higher rotation speeds and having better performances for high installed capacities. Also has the advantage of using the water difference in the tailrace, bellow the maximum flood level and always working under water. The disadvantage of the Francis turbines is that their performance for values of discharge lower than the equipped discharge is not as good as it is for a Pelton or Kaplan turbine. This is possible to observe in Figure 5.64.

Figure 5.64 – Efficiency of the different types of turbines versus Q/Qmax

After the definition of the type of turbine it is important to calculate the rotation speed. The rotation speed can be obtained using expression (16). In the expression P represents the power in kW, H represents the net head in m and ns represents the specific rotation speed, which is the rotation speed of a turbine geometrically similar to the one that is being calculated that works with the same efficiency and unitary power and net head.

H5/4 n=n (16) s P1/2

In the equations (17) and (18) is presented the relation between the net head and the specific number of rotations of a Francis turbine that the experience allows to recommend, in order to obtain turbines with good efficiency and a turbine- alternator group well dimensioned. In terms of cost of the group, it is important to have the highest rotation speed as possible

(so the highest ns as possible) (Quintela 1981).

1550 n = (17) s √H

2700 n = (18) s √H

For the turbines considered in this study the specific number of rotations can be estimated between 226 and 394 for a Francis turbine, so it was assumed 310 rotations per minute. Finally the rotation speed is estimated at 304 rotations per minute. It is usual to adopt a rotation speed n’ similar to n in order to obtain a multiple of four poles, which is the most common for standard generators, although it can also be a multiple of 2 poles. This calculation is made using equation (19) where f represents the frequency.

60*f n'= (19) nº poles

Considering a value of frequency of 50 Hz, the value of n’ was estimated at 300 r.p.m for 10 pair of poles. Using equation (19) the specific rotation speed can be determined based on the net head and power of the turbine, and has a value of 306.27 rotations per minute.

95 Based on this and after determining the number of poles and the rotation speed, the power and net head can be fixed accordingly. Also the maximum suction height of the turbine in order not to occur cavitation can be estimated, which is made using the following expressions, where patm represents the atmospheric pressure (101 235 Pa) and tv represents vapor pressure of the water, considered at 20 ºC (2 330 Pa) and γ represents the specific weight of the water (9 800 kg/m3).

p t h = atm - v – Σh (20) s max γ γ

n1.64 σ= s (21) 50000

The maximum suction height is defined as the difference between the elevation of the wheel (in the case of horizontal and vertical axis) and the water level downstream of the tailrace. So the maximum aspiration height is estimated as -1.33 m. This means that downstream level would need to be 1.33 m above the turbine and it works in counter pressure, being that the turbine will have more tendency for the occurrence of cavitation.

Finally, the main dimensions of the turbine can be obtained using parameters whose relations with ns have been established by several authors, based on the analysis of the characteristics and dimensions of already constructed turbines. This gives an idea of the dimensions of the turbines in a pre-study stage that allows estimating the dimensions of the powerhouse in order to calculate the costs associated with it. But the final dimensions of the turbines are very dependent on the technology and on the manufacturer. The same happens with the alternator and generator.

According to (Siervo and Leva 1976) the main runner dimensions, presented in Figure 5.65, can be obtained based on the specific rotation speed ns, being that all the dimensions are dependent on D3, which can be obtained from the expression (22) and represents the discharge diameter of the turbine. The remaining dimensions can be estimated using the abacus in Figure A- 43.

Figure 5.65 – Runner dimensions (Siervo and Leva 1976)

√H D =84.5K × n (22) 3 u n

-3 Ku=0.31+2.5×10 ns (23)

The parameters in expression (22) and (23) assume the values 2.07 m and 1.085 m, respectively and for this situation. Also according to (Siervo and Leva 1976) the spiral case dimensions can also be determined using a similar process as the one used for the runner dimensions. The dimensions of the spiral case depend especially on the value assumed for the water

96 velocity in the inlet section. The spiral case dimensions are presented in Figure 5.66 and using the abacus presented in

Figure A- 44 that relates the specific rotation speed with the dimensions as a percentage of D3, the spiral case can be defined. Based on the process described, the main dimensions of the runner and spiral case are presented in Table 5.31.

Figure 5.66 – Spiral case dimensions (Siervo and Leva 1976)

Table 5.31 – Dimensions of the turbine

Runner Dimensions Spiral Case Dimensions ID H1 H2 D1 D2 D3 A B C D E F G H L M % of D3 0.17 0.36 0.71 0.93 1 1.14 1.28 1.48 1.66 1.19 1.43 1.21 1.06 1.03 0.6 Dimension (m) 0.35 0.75 1.47 1.93 2.07 2.36 2.65 3.07 3.44 2.46 2.97 2.5 2.19 2.14 1.25

In conclusion, it will be installed two groups of turbines with 15.7 MW of installed capacity each (31.4 MW in total) that work with an equipped discharge of 38 m3/s. The turbines should have a vertical axis since their dimensions are considerable and it this way it’s easier to connect to the generator and alternator, which will be located above the turbine. As already referred in the reservoir analysis, one of the turbines will be working at 40 % of its full capacity from May to September and the other one will be working at its full capacity the entire year. This configuration generates a total of 230 GWh per year.

5.2.6 Pre Study Drawings and Preliminary Bill of Quantities

In this topic a preliminary bill of quantities is elaborated. To accomplish this, first a set of pre study drawings were elaborated, which include a general layout of the facility, a plan and profile of the dam, a transversal profile trough the concrete area (namely the spillway) and embankment area, a profile of the water intake and bottom outlet, a longitudinal profile of the adduction circuit and a plan and profile of the power house. In order to obtain the referred drawings, it was used the software REVIT and AutoCAD, being that the drawings are in the Appendices II.

At this stage of the study more topographic information was obtained. This was made using the Program PlexEarth, which is an extension for AutoCAD that allows importing images and elevation data, namely contours, from Google Earth. This

97 information was then compared to the previous one and treated accordingly in order to obtain a topographic map with more detail (contours of one meter) and more accurate. At this stage, and by analyzing the topography in more detail, it was decided to push section 1 a few meters downstream, as it possible to observe in the drawings. This allows to have less volume for the dam, since the transversal profile is narrower, to have a smaller length of the adduction circuit as well as less head losses, since it is closer to the power house. This transition will allow a lower total cost of the facility.

The referred drawings were elaborated in a preliminary stage since a lot of hypotheses were assumed and they were based on typical and already tested solutions for other similar hydropower facilities. The objective with this drawings is to allow a more visual understanding of the facility as well as its implementation in the case study region, namely in section 1. Also these elements allow a more reliable and better founded estimation of the quantities associated with the construction of this hydropower facility. This is why, at this point, the bill of quantities is only at a preliminary stage.

Besides the ones already presented in the topic of the hydraulic structures (chapter 5.2.4), the hypothesis and assumptions considered for the elaboration of the drawings were the ones presented in the following topics:

 The dam is located in section 1 at the altitude of 960 m and the crest is at an elevation of 998 m. The excavations considered were eight meters depth in the concrete part of the dam and three meters in the embankment part. The excavations are used to remove the soil layer in the surface and also the damaged rock in more superficial layers, being that a drainage curtain and a ground curtain of cement are normally created through injections in order to reduce the permeability and increase the stability;

 In the concrete part of the dam, an area where the water intake and the bottom outlet were inserted is incorporated. This is connected to the area where the spillway is located, which, as already referred, has a length of 250 meters. The spillway develops along the concrete part of the dam, with a height of four meters between the full reservoir level and the maximum water level. The bollards, which are small piers that support the crest of the dam in the spillway area and are connected to the crest of the spillway, are spaced 50 m. Also for the spillway there will be incorporated wing walls made of reinforced concrete, in order to contain the flow from the reservoir;

 The energy dissipation structure was considered to be founded eight meters below the surface of the terrain with a length of 27 m and a surface of gravel was considered downstream of this structure at the rivers elevation. The limits of the energy dissipation structure were surrounded by wing walls to control the flow, as it happens along the spillway;

 In the embankment part of the dam, there were considered platforms and a clay core protected with very low permeability material. There were considered support walls to contain the embankment parts of the dam;

 Powerhouse:  The powerhouse is situated at an elevation of 940 m;  The parts of the power considered were the machine room, the transformers area, the tailrace, an access area, an auxiliary area that connects to the staff room, the work room, the switch gear and the control room. These elements were not dimensioned, to account with them, other powerhouses from different studies were considered and were then adapted to the present case study. The most conditioning was the machine room and more attention was given to this area. Also the tailrace was given some attention to account with the elements described in chapter 5.2.5, namely the altitude of the wheel and the water level downstream of the structure;

98 At this stage it was also retrieved more information regarding the unitary costs of construction, which is presented in the bill of quantities that is shown in Table A- 59 of the Appendices I. The unit rates were obtained based on contacts from GIBB Portugal and GIBB Angola and by analyzing the market prospections in Angola, also some values retrieved from database of the LCH laboratory in EPFL and by analyzing similar projects in similar locations. Some of the prices obtained were majored with a percentage in order to account for the differences between the Angolan market and current situation and other markets. Of course that bill of quantities can be more or less detailed based on the available information, the studies and designs developed until its elaboration.

There were also made some assumptions regarding the costs and quantity of works, which influenced the bill of quantities. The engineering work was considered to be 10 % of the total cost of the facility, and for the installation of the construction site it was considered 4 % of the total cost of the facility.

For the hydrometric station it was assumed a cost of 50 000 USD, being that these values can variate a lot depending on the equipment’s used and man power hired. If the hydrologic studies are entirely subcontracted the cost can be much higher. The main equipment’s that have to be considered for the hydrometric station is a device to measure flow velocities and one to measure water levels (rulers for example), also a structure to incorporate these equipment’s. The chosen section for the measurements should be characterized by a transversal profile with highly inclined slopes and fixed river bed, since that if there is a lot of sediment transport the measurements can be compromised.

The cost of accesses is very dependent on the terrain conditions and characteristics. Also if there is the need to construct bridges, the cost will be higher. To define the quantities it was made an estimation using Google Earth and for the access roads in the facility itself it was made an estimation based on the pre study drawings. There were not considered accesses to the power house and dam crest at this stage. For the clearing of the facility it was considered a unitary cost per square meter and the area was measured in the drawings. The deforestation was only considered for 2/3 of the total area of the reservoir.

It should be noted that it was considered three different classes of resistance for the concrete used in this facility. For the regulation and cleaning concrete it was considered a C16/20, which has lower resistance and is much cheaper (55 USD/m3). The concrete considered for the dam and diversion scheme was a C20/25 (200 USD/m3) and finally for the hydraulic structures and powerhouse it was considered a C25/30 (380 USD/m3). For the hydraulic structures maybe there is the need to use a concrete with more resistance (C30/37 for example) but more studies need to be considered in order to decide on this topic with more certain.

The embankment materials were divided in 3 categories: the filling materials (estimated at 3 USD/m3), the main materials for the embankment dam, which are granular materials with variable dimensions and considerable permeability (cost estimated at 30 USD/m3) and finally embankment materials with low permeability for the core of the dam (40 USD/m3).

For this study it was considered that the superficial layer had a width of 3 m composed by soft terrain and for deeper formations it was considered rock in good conditions. The cost for the excavations was considered to be 3 USD/m3 and 10 USD/m3, respectively. It was considered the cost of miscellaneous to by 20 % of the dam´s construction costs. This includes monitoring, a ground curtain, a drainage curtain, consolidative grouting, galleries, wells, the dam’s crest and instrumentation.

Also some the quantities were majored in 10 % in order to account for possible measurement errors and inaccuracies in the used data. The contingencies and unexpected works were not considered at this stage and the same happened for general

99 and administrative expenses as well as salaries. After the conclusion of the preliminary bill of quantities the total cost of the facility was estimated at 194.2 MUSD.

5.3 STAGE 3: ECONOMIC ANALYSIS

The costs considered in the economic analysis include the capital costs which occur during the construction period and are defined as the sum of all the expenditures required to bring a project to its completion; the annual operation costs which include the exploitation/operation costs and the maintenance costs. The maintenance costs include two parcels, one related with the civil works and the other with the equipment’s.

For the benefits, it´s simpler since the only tangible revenue is the annual income with the energy sale. The average annual energy generation has already been calculated in previous chapters, and there is only the need to define the sale price per kWh of energy, which is mainly dependent on the energy market in Angola. For this case and as a first hypothesis, the value of 0.075 USD per kWh (75 USD per MWh) was considered. This value appears to be a good hypothesis, when compared for example with the European market where the sale prices for hydroelectric energy range from 40 to 60 € per MWh (≈45 to 47 USD nowadays). Also it is a conservative value because nowadays the energy sell price in Angola reaches 100 USD/MWh

Since that normally a dam as an estimated lifetime period of 50 – 100 years, it was considered a lifetime period of 50 years for this facility, which is only an assumption since the durability of the materials depends on many factors. The lifetime period is defined as the period that as structure is intended to operate, with the predicted maintenance operations, but without any big reparations. For the equipment’s, the lifetime period is estimated to be around 20 to 25 years. For developing the economic analysis, the initial values considered were the ones presented in Table 5.32.

Table 5.32 – Initial values for economic analysis CAPEX (MUSD) 194.2 OPEX (MUSD/year) 0.2 Annual gross income (MUSD/year) 17.3 Net annual income (MUSD/year) 17.1

In the table the CAPEX (capital expenditure) is the total cost of the facility, obtained from engineering design and presented in the bill of quantities. The OPEX is the operational expenditure that is based on pay role, maintenance expenses, insurances and all the running expenses. As an assumption it was considered to be 0.2 MUSD per year. The annual gross income was estimated based on the energy generated per year, which is an average value estimated in the reservoir analysis and equal to 230.6 GWh/year.

As stated in the methodology (chapter 4.4), there were considered several values for the interest rate and discount rate, being defined six different scenarios, which are presented in Table 5.33. Based on the interest rate, the annual interest can be calculated, this value is assumed fixed each year and the payment was assumed to last for 15 years, after the construction of the facility, which might be risky but will depend on the negotiated contract. Of course that for the scenario that considers no interests, the number of years is equal to zero.

In this economic analysis it was not included the cost for replacement of electro mechanic equipment or heavy maintenance, since it would not be relevant in the total cost of the facility (the electro mechanic equipment’s represent about 10 MUSD in a

100 total of 194 MUSD as it is possible to observe in the preliminary bill of quantities, not counting with the medium tension lines that connect the facility to Saurimo).

Table 5.33 – Different scenarios and associated interest and discount rate Scenario A-1.1 A-1.2 A-1.3 A-2.1 A-2.2 A-2.3 Discount rate (%) 5 5 5 10 10 10 Interests rate (%) 0 2.5 5 0 2.5 5 Annual interest (MUSD/year) 0.0 4.9 9.7 0.0 4.9 9.7 Number of years payment (years) 0.0 15.0 15.0 0.0 15.0 15.0

For the construction of the facility it was assumed a construction time of four years, being the capital cost distributed in those four years according to the work planning. The timetable regarding the work planning was developed using the software MSProject and is presented in Figure A- 45 of the Appendices I. The distribution of the CAPEX and OPEX in the four years of construction is made in Table 5.34.

Table 5.34 - Distribution of the CAPEX and OPEX in each year YEAR 1 2 3 4 CAPEX (MUSD) 33.6 121.9 15.9 22.8 OPEX (MUSD/year) 0.2 0.2 0.2 0.2

In the economic analysis the following expressions were considered, where C represents the capital costs that occur in the first k=4 years, actualized to the present year; O represents the annual operation costs that occur during the facility’s lifetime n=50 years, in the present year; R represents the revenues during the lifetime of the facility, in the present year and finally, I represents the total of interests in the present year. For the last three expressions, the numerator provides the value in the beginning of year k+1, which corresponds to the beginning of the exploitation of the facility and the denominator performs the transference of the previous value from year k=4 to the beginning of year 1 (present time). In Table 5.35 that follows, the values calculated with the previous expressions are presented for each scenario.

퐶 퐶 = ∑푘 푖 (25) 푖=1 (1+푟)푖

푛 푂푗 ∑푗=푘+1 푗 푂 = (1+푟) (26) (1+푟)푘

푛 푅푗 ∑푗=푘+1 푗 푅 = (1+푟) (27) (1+푟)푘

푛 퐼푗 ∑푗=푘+1 푗 퐼 = (1+푟) (28) (1+푟)푘

Table 5.35 – Cost and revenues in the present year for each of the scenarios Scenario A-1.1 A-1.2 A-1.3 A-2.1 A-2.2 A-2.3 Capital Costs (MUSD) 175.0 175.0 175.0 158.8 158.8 158.8 Operational Costs (MUSD) 2.8 2.8 2.8 1.2 1.2 1.2 Interests (MUSD) 0.0 39.5 79.0 0.0 22.9 45.9 Revenues (MUSD) 242.3 242.3 242.3 106.0 106.0 106.0

101 With all these values obtained it is possible to compare the costs and benefits since the values all correspond to the same year. Also the economic indicators can be calculated, which are presented in the topics below. The values of the indicators, for each of the scenarios are presented in Table 5.36.

 Net present value: represents the cumulative sum of all expected benefits during the lifetime of the project minus the sum of all its cost during the same period, both expressed in terms of present values.

푁푃푉 = 푅 − 퐶 − 푂 − 퐼 (29)

If the value isn’t negative, the facility will generate profit. The net present value can also be evaluated by obtaining the discount cumulative cash flow. This cash flow gives, through each year of the economic analysis period, the value of the cumulative sum of the present values of the costs minus the present values of the benefits. The curves regarding the discount cumulative cash flow are presented in Figure A- 46 to Figure A- 51 of the Appendices I.

 Benefits/cost ratio: This indicator compares the present values of the benefits withdraw from the facility, with the costs of the hydropower scheme, through a ratio (B/C). For a value of B/C less than one the project would be undesirable, but since it is higher than one, the bigger the value the better, corresponding to a higher margin between the benefits and the cost, and consequently to a more profitable hydropower scheme.

푅−푂−퐼 퐵⁄ = (30) 퐶 퐶  Internal rate of return: This rate is defined as the discount rate that makes the net present value equal to zero. A discount rate equal to the IRR will originate a unitary B/C and a null NPV. If the IRR is higher than the discount rate considered, the scheme will generate profit, if not it won’t and should be rejected.

 Payback period: The payback period indicates the number of years that it takes before the cumulative forecasted cash flows equal the initial investment or, in other words, the moment after which the scheme turns profitable. This corresponds to the moment when the discount cumulative cash flow turns positive. The representation of the discount cash flow curves is made, as already referred, for the different scenarios in Figure A- 46 to Figure A- 51 of the Appendices I. In Table 5.36 the values presented for the payback period are relative to the beginning of the construction works, to obtain the payback period from the point when the facility starts operating, it should be deduced four years to the values presented.

Table 5.36 – Calculation of economic indicators for each scenario Scenario A-1.1 A-1.2 A-1.3 A-2.1 A-2.2 A-2.3 Net Present Value 64.45 24.97 -14.51 -53.97 -76.90 -99.82 Benefits/Costs Ratio 1.37 1.14 0.92 0.66 0.52 0.37 Internal Rate of Return 6.94 5.75 4.64 6.94 5.75 4.64 Payback Period 26 37 >50 >50 >50 >50

After this analysis, and as expected, it is concluded that for higher values of the discount and interest rates, the higher the chances of the facility not being profitable, since the values in the present day are lower and the annual interests are higher. As it is possible to observe in Table 5.36, and based on what was presented in this chapter, for scenarios A-1.1 and A-1.2 the facility is profitable and for the remaining scenarios, corresponding to discount rates higher than 5 % and interest rates of 5 % for the case of a discount rate of also 5 %, the facility will not generate profit. As explained the rates considered can variate a lot and depend on many factor. For further analysis it was considered scenario A-1.2, which corresponds to a discount rate of 5 % and an interest rate of 2.5 %.

102 Since that the studies conducted so far are characterized by a lack of certainty about the capital costs, future annual costs (operational costs and reparations) and future value of the energy (sale price of the kWh), a sensitivity analysis should be performed in order to analyze the project response to different scenarios that consider variations in the costs and benefits. For this case study there were considered variations from ± 10 % to ± 20 % and the economic indicators, already described in this chapter, were calculated for each of the situations. The values of the costs and benefits actualized to the present year are presented in Table 5.37 and the values of the indicators are presented in Table 5.38.

Table 5.37 – Variations of the costs and benefits Variation -20% -10% 0% 10% 20% Capital Costs 140.0 157.5 175.0 192.5 210.0 Operational Costs 2.2 2.5 2.8 3.1 3.4 Interests 31.6 35.5 39.5 43.4 47.4 Benefits 193.8 218.1 242.3 266.5 290.8

Table 5.38 – Calculation of economic indicators for different variations of the costs and benefits

Variation of the Benefits Variation of the Benefits NPV IRR -20% -10% 0% 10% 20% -20% -10% 0% 10% 20% -20% 19.98 44.28 68.48 92.68 116.98 -20% 5.72 6.54 7.32 8.06 8.78

-10% -1.75 22.55 46.75 70.95 95.25 -10% 4.94 5.72 6.45 7.15 7.82

0% -23.48 0.82 25.02 49.22 73.52 0% 4.29 5.02 5.72 6.38 7.01

10% -45.21 -20.91 3.29 27.49 51.79 10% 3.72 4.42 5.09 5.72 6.32

Variation of the Costs Variation 20% -66.94 -42.64 -18.44 5.76 30.06 of the Costs Variation 20% 3.23 3.90 4.54 5.14 5.72 Variation of the Benefits Payback Variation of the Benefits B/C -20% -10% 0% 10% 20% Period -20% -10% 0% 10% 20% -20% 1.14 1.32 1.49 1.66 1.84 -20% 36 30 24 22 20

-10% 0.99 1.14 1.30 1.45 1.60 -10% >50 37 30 26 23

0% 0.87 1.00 1.14 1.28 1.42 0% >50 49 37 31 27

10% 0.77 0.89 1.02 1.14 1.27 10% >50 >50 48 37 31

Variation of the Costs Variation 20% 0.68 0.80 0.91 1.03 1.14 of the Costs Variation 20% >50 >50 >50 47 37

By analyzing Table 5.38 regarding this sensitivity analysis, and taking into consideration that for this sensitivity analysis, the interest rate and the discount rate were fixed at 2.5 % and 5 %, respectively, the main conclusions that can be obtained are:

 For some combinations of variations of the costs and benefits, the facility will not be profitable. These values are market with a light gray in the table. This means that this facility does not have a great margin, regarding its economic feasibility, being that for some variations of the costs or the benefits the economic indicators show that it might not be profitable. To be more specific, for fixed benefits it is necessary an increase of 20 % in the costs or, for fixed costs the benefits need to decrease 20 %, for the rejection of this project, in what concerns its economic feasibility;

 Regarding the NPV and the B/C ratio, they present negative values and smaller than one, respectively, for the non- profitable situations, as it is possible to observe in the table. For the best possible situation these indicators present the values of 116.98 and 1.84, respectively for the NPV and B/C ratio;

103  As it happened for the previous analysis, the payback period is higher than 50 years for the situations where the facility will not generate profit. The best possible situation as associated a payback period of 20 years;

 Finally, considering the internal rate of return (IRR), for lower values than 5 %, which was the value considered for the discount rate for this analysis, it means that the facility will not generate profit. For the worst situation, where the costs increase to the maximum and the benefits decrease to the minimum, the IRR is equal to 3.23, so if a discount rate equal or lower to this value is considered, the facility will always generate profit, even if the cost and benefit estimations reveal themselves to be inaccurate. The best possible situation happens, of course, with the benefits 20 % higher than the ones calculated at a previous stage and the costs 20 % lower. For this situation the IRR corresponds to 8.78 meaning that for discount rates equal, for example to 8 % the facility will still be profitable;

Another approach that was considered was a simple estimation of the cost price for the kWh. This is a useful indicator that can be compared with the sale price and the margin between both of them is what will dictate the profits of the hydropower scheme. This estimate and the associated calculations are presented in Table 5.39.

Table 5.39 – Calculation of the cost price Parameter Units Value CAPEX MUSD 194.2 Payback Period Years 37.0 Debt Reinbursement MUSD/year 5.2 Interest Rate %/year 2.5 Annual Interest MUSD/year 4.9 OPEX MUSD/year 0.2 Annuity MUSD/year 10.3 Production GWh/year 230.6 Cost Price USD/kWh 0.0447

For this procedure, the payback period was assumed to be 37 years, which corresponds to the payback of scenario A-1.2, but it may depend on the legal requirements and on the project horizon. This estimation was based on fixed interests rate and annuity and it does not include the cost for replacement of the electro mechanical equipment or heavy maintenance. Also the investment of the shareholders is not considered, being assumed that the bank provides 100 % of the capital which is a simplification. As presented in the table, the cost price considers the CAPEX, in order to obtain the debt reimbursement, which is included in the annuity. So once the scheme is reimbursed (i.e. the payback period is achieved), the cost price will be lower, allowing a higher margin for profits if the sale price does not decrease (dependent on the energy market).

Based on the cost price estimated and on the sale price assumed, it is obtained a margin of 0.075-0.0447=0.0303 USD/kWh. Considering this margin and the energy generated per year it is possible to obtain the value of 6.99 MUDS of profit per year after the plant starts operating. This is then reduced in the initial investment until the payback period is achieved. Of course that these values are calculated in the present year and there might be variations of the cost price along the years.

The cost price can also be a very useful indicator in order to make comparisons with other energy sources and it should be considered in future approaches.

104 6 CONCLUSIONS

Despite the difficulties associated to the lack of information available for this case study, it has been very challenging and at the same time formative in terms of acquired competences, in the way that it allowed to perceive what can be developed only with freeware information available online and by taking advantage of new technologies that have been in development in the last years, mainly satellite information and some of its derivative products. This information is nowadays a very powerful tool for hydrology work and it’s essential for studies in developing countries that have deficient measurement stations, don´t have sufficient on-site measurements and lack on a lot of needed information.

Nevertheless, it should be pointed out that the lack of more extensive and accurate field data could always compromise the reliability of these kinds of studies. In fact, and more importantly when considering hydrological studies, there is nothing like solid measurements made in the locations, as well as topography measurements made on site. It would be a valuable initiative to invest in this type of studies for Angola and other developing countries, with rising economies, with a lot of unexplored potential (namely in the hydropower field) and lack of important information, which is priceless for a wide range of base studies. The lack of information made it difficult to create and calibrate a good and well-founded rainfall-runoff hydrological model. Of course that, as explained in this report, in a more advanced stage of the study, it was acquired on site measurements of discharge in the Chiumbe River (in the station of Dala), but this information was only used in a more advanced stage of the study, being that the best section for the implementation of the facility had already been determined using the satellite information.

Based on the studies within the framework of this study for the Chiumbe River basin, the best location to build a hydropower facility is section 1. This section is located 78 km from the city of Saurimo at the coordinates 21.1 East and 9.7 South, in the kilometer 332.4 of the Chiumbe River (from the source of the river). The catchment area dominated by this section is 9 412 km2, the mean slope of the river is 0.12 % and section 1 is located at an altitude of 960 m.

At this stage, it was assumed that the best configuration for the facility is considered to be a mixed dam composed by a concrete gravity dam and an embankment dam. The concrete part of the dam will be in the center of the valley, with 38 m of height and a crest length of 250 m, with a spillway over the dam. The hydraulic structures, namely the bottom outlet and the water intake, will be located in the concrete part of the dam next to the spillway, as it is presented in the drawings in the Appendices I. The embankment dam fills the remaining parts of the valley. The total crest length is estimated to have 1 111 m, based on the drawings elaborated and for the final location considered for secion1. The reservoir created will have a total area of 39.2 km2 and a maximum volume of 591.3 hm3. Considering the resumed analysis of the construction materials, it seems possible and adequate to construct a concrete dam and there are also available materials in the region to construct an embankment dam, being that the mixed solution considered is feasible.

The total energy generated by the HPP should be around 230.6 GWh per year, with a total installed capacity of 31.4 MW, with two groups of turbines (of 15.7 MW each) and an equipped discharge of 38 m3/s per group. The turbines should have a vertical axis. One of the turbines will be working at 40 % of its full capacity from May to September and the other one will be working at its full capacity the entire year.

105 Based on the studies elaborated so far, it is not possible to create a HPP in the Chiumbe River with an installed capacity of 100 MW that consists in a feasible project. As shown in the presented study, in order to achieve such a value one of two consequences are going to occur: Either the cost of the facility is so big, with enormous and unfeasible construction works associated (for example dams with a crest length higher than 10 km, which happens for section 5 with the equipped discharge of Q90) that it does not compensate the investment when compared to other solutions; or the facility would have to be equipped with very high values of discharge, meaning it could only work a few months per year. Since the objective is to constantly supply the city of Saurimo along the year and not to fulfill peak demands in some periods, this is not a feasible solution. The only way to achieve 100 MW of installed capacity would be to construct more than one hydropower facility in the Chiumbe River.

At this stage, the estimated cost of the facility, based on the preliminary bill of quantities elaborated, was estimated on about 194.2 million USD.

As a result from the economic analysis elaborated, this hydropower scheme associated with the considerations described above, reveals itself to be profitable with an associated payback period of approximately 37 years after the facility starts operating, for a considered discount rate of 5 %, an interest rate of 2.5 % and the sale price of the energy fixed in 0.075 USD/kwh. Of course the profitability of this scheme can variate in the cost or benefit estimates are inaccurate, since this economic analysis is mainly depended on the hypothesis considered for some of the elements in the bill of quantities and also the sale price. The economic analysis did not show very good margins, although they were considered to be reasonable so, after elaborating a more detailed analysis and detailed study of the Angolan market, if the costs and sale price don’t present considerable variations, probably the facility will still be profitable. For fixed benefits it is necessary an increase of 20 % in the costs or, for fixed costs the benefits need to decrease 20 %, for the rejection of this project, in what concerns its economic feasibility.

Of course, this study has its limitations due to the hypotheses considered and the precision of the satellite information used. Also some of the unit rates considered should be defined with more detail, for this specific situation. In terms of comparison of different alternatives is acceptable but in order to have a more founded decision, more information needs to be acquired. Nevertheless this seems to be a feasible and profitable project in a first approach and more studies should be carried out.

106 7 FUTURE WORK

As explained, this study was based only on satellite information, in what concerns the topography analysis. Although these sources of information have been constantly improving, it would be good to acquire some topographic information based on site measurements, and compare it with the satellite information used. Particularly in the best identified locations for the facility this information would be very important and serve as a solid base to more detailed studies.

The definition of the runoff coefficient that relates the total precipitation with the precipitation that effectively generates runoff should be calibrated using other data sources, preferably runoff or discharge measurements made in the catchment area of the case study. A model should be defined that takes into account the fact the coefficient varies along the year, and the runoff values obtained should be revised and founded in more reliable information. This should be one of the main goals for the continuation of this work. The runoff coefficient is one of the most important features because it is the base of all the discharge values obtained and its calibration should be done with on-site measurements in order to minimize the probability of errors. Probably with more reliable information, the decisions made regarding the selection of the best location for the hydropower facility will be maintained, although, and using the same methodology presented in this study, the comparative analysis should revised with more accurate and supported data. After this revision section 1 will probably remain the best location for the construction of a hydropower facility, which would mean that the data used so far does not have a lot of errors associated and, also, a lot of the analysis done so far would not be repeated.

With more reliable information, the topics considered in the feasibility study should also be revised and the pre dimensioning made for the hydraulic structures and equipment’s can be made with more detail. The pre study drawings might need to be adjusted, which will influence the bill of quantities and probably the costs. Also a more founded work planning and execution scheme could be developed after the revision of te bill of quantities. This is important since it influences (and is at the same time influenced by) the location of some of the hydraulic structures, the construction materials and the time for construction of the HPP, which will influence the economic analysis indicators, mainly the payback period.

With a more detailed bill of quantities and the construction stages defined, there is more information that can be added to economic analysis, which will lead to more founded conclusions about the feasibility of this facility and about the benefits that can be expected from its implementation in the Chiumbe River.

It should also be considered an environmental impact assessment (EIA). This was not considered in this thesis since it was not the purpose of the study, but being a feasibility study it makes sense to consider the environmental impacts that are inherent to the construction of a hydropower facility of this dimension. The purpose of an environmental impact assessment applied to a hydropower facility consists on evaluating the favorable and unfavorable impacts, in natural and social environmental context. Natural impacts include hydrology and sediment effects, as well as the water temperature and quality, ecology, engineering construction, biology, landscape and effects on archelogy and cultural assets, soils and geology, air, noise and, eventually, climate local change (in case of large reservoirs). Social impacts involve social, cultural and economic developments, inducing local industrialization and changes in populations live quality as well as potential displacement of people due submersion by the creation of the reservoir. To elaborate an EIA, firstly, it is necessary to identify potential

107 impacts based on characteristics of the hydropower facility and on the site, taking into consideration the experience and the knowledge of impacts provoked by similar projects and contributions from the technical team. According to the magnitude and the importance of impacts, the prediction techniques, based on quantitative and qualitative analysis, must be carried out, in order to classify them as positive, significant or not, whenever occurs a violation of standards or rules legally approved or accepted by the scientific community (Ramos and Almeida 2000).

Being the water an essential resource that sustains all life on Earth, it is important to plan its use correctly. Nowadays it is obligatory to provide all information about watercourses through suitable catchment management plans, which includes several aspects, such as water abstraction, effluent disposal, flood defense, amenity and recreation, pollution, land uses, flow variation and wildlife conservation.

The pre-design of a hydrometric station would be desirable. This station would provide very useful information for further studies.

Finally, after its revision with more accurate information, if the study reveals itself to be feasible, from a technical, environmental and economic point of view, if it guaranties the objectives for what it is destined, namely the energy supply for the population of Saurimo, if it benefits the parties involved and, more importantly, if it is decided to go forward with it, other stages need to be considered, namely a preliminary design project, the planning and the construction project.

108 8 REFERENCES

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109 [22] New York Times. 2003. “Angolans Come Home to ‘Negative Peace.’” Retrieved December 29, 2014 (http://www.nytimes.com/2003/07/30/world/angolans-come-home-to-negative-peace.html). [23] Pettersson, Lars-Evan. 2004. “National Strategy Plan for Rehabilitation of the Hydrometric Network in Angola.” Resources, Norwegian Water Directorate, Energy. [24] Quintela, António de Carvalho. 1981. Hidráulica. Fundação Calouste Gulbenkian, 2009. [25] Ramos, H. M. 2010. “Fundamentos E Orientações No Projecto de Aproveitamentos Hidroeléctricos : Critérios E Dimensionamento Texto de Apoio À Disciplina de Estruturas E Aproveitamentos Hidráulicos Do.” 1–113. [26] Ramos, Helena, and A. Betâmio De Almeida. 2000. “Small Hydropower Plants.” [27] Renewable Energy Focus. 2014. “Hydropower Regains the Lead in Several Key Categories.” Renewable Energy Focus 15(4):20–22. Retrieved December 2, 2014 (http://linkinghub.elsevier.com/retrieve/pii/S1755008414700924). [28] Rodrigues, Ana Cristina Barreira. 2014. “Simulação Hidrológica de Cheias Na Bacia Do Rio Cavaco Em Angola.” [29] Rusli, N., M. R. Majid, and a H. M. Din. 2014. “Google Earth’s Derived Digital Elevation Model: A Comparative Assessment with Aster and SRTM Data.” IOP Conference Series: Earth and Environmental Science 18:012065. Retrieved December 30, 2014 (http://stacks.iop.org/1755- 1315/18/i=1/a=012065?key=crossref.1dd8f36abf80ddb096bf0b090f151082). [30] Schleiss, Anton. 2008. Aménagements Hydrauliques. Civil, Section D E Genie Ressources, D E S Environnement, E T D E L. [31] Siervo, F., and F. Leva. 1976. “Modern Trends in Selecting and Designing Francis Turbines.” Water Power & Dam Construction 28–35. [32] Stauber, Andreas. 2014. “Angola, Significant Development in a High Promising Market.” Hydro News (26). [33] Steiger-Garção, Adolfo, and Francisco Reis. 2013. “First International Conference on Energy and Water. Angola’s Electric System.” [34] The World Bank. 2015. “Angola: Aspectos Gerais.” Retrieved May 25, 2015 (http://www.worldbank.org/pt/country/angola/overview). [35] United Nations. 2013. “UN News - World Population Projected to Reach 9.6 Billion by 2050 – UN Report.” Retrieved December 19, 2014 (http://www.un.org/apps/news/story.asp?NewsID=45165#.VJMSeV4gA).

110 APPENDICES I

APPENDICES I – FIGURES AND TABLES

111

112

160 120 80 40

Elevation (m) Elevation 0 0 2 000 4 000 6 000 8 000 10 000 Distânce (m) Figure A- 1 - Transversal profile of the section 1

200

160 120 80 40 Elevation (m) Elevation 0 0 2 000 4 000 6 000 8 000 10 000 12 000 14 000 16 000 18 000 20 000 22 000 Distance (m) Figure A- 2 - Transversal profile of the section 2

200 160 120 80 40 Elevation (m) Elevation 0 0 2 000 4 000 6 000 8 000 10 000 12 000 14 000 16 000 18 000 Distance (m) Figure A- 3 - Transversal profile of the section 3

120 80 40

0 Elevation (m) Elevation 0 2 000 4 000 6 000 8 000 10 000

Distance (m) Figure A- 4 - Transversal profile of the section 4

160 120 80 40

Elevation (m) Elevation 0 0 2 000 4 000 6 000 8 000 10 000 12 000 14 000 16 000 18 000 20 000 22 000

Distance (m) Figure A- 5 - Transversal profile of the section 5

113 120 80 40 0 Elevation (m) Elevation 0 2 000 4 000 6 000 8 000 10 000 Distance (m) Figure A- 6 - Transversal profile of the section 6

120 80 40 0 Elevation (m) Elevation 0 2 000 4 000 6 000 Distance (m) Figure A- 7 – Transversal profile of the section 7

120 80 40 0 Elevation (m) Elevation 0 2 000 4 000 6 000 8 000 Distance (m) Figure A- 8 - Transversal profile of the section 8

120 80 40

0 Elevation (m) Elevation 0 2 000 4 000 6 000 8 000 Distance (m)

Figure A- 9 - Transversal profile of the section 9

80 40 0

Elevation (m) Elevation 0 2 000 4 000 6 000 8 000

Distance (m) Figure A- 10 - Transversal profile of the section 10

Figure A- 11 - Concrete dam cross section

114 Table A- 1 - Mean monthly values of rainfall in each basin for a 16 year-long series

SECTION ID 1 2 3 4 5 6 7 8 9 10 1998 1359.3 1317.0 1315.1 1306.3 1251.7 1410.1 1393.2 1390.7 1320.1 1314.0 Jan. 191.3 173.9 173.2 172.9 159.7 222.8 207.7 206.0 175.1 173.0 Feb. 149.0 146.6 146.6 150.0 148.8 133.0 139.1 139.7 147.0 146.8 Mar. 223.4 228.0 228.0 223.1 216.8 216.4 221.3 221.4 227.6 227.6 April 96.1 107.1 108.0 111.3 115.5 100.1 99.0 99.0 105.8 108.8 May 3.7 3.8 3.7 3.4 2.9 3.3 3.3 3.4 3.9 3.7 June 0.8 1.1 1.1 1.2 1.1 0.6 0.7 0.7 1.0 1.1 July 1.2 1.0 0.9 0.9 1.2 1.9 1.5 1.5 1.0 0.9 Aug. 12.7 13.6 13.7 14.6 16.4 13.6 13.1 13.1 13.3 13.8 Sep. 110.0 100.3 99.5 96.2 93.2 110.5 111.2 111.2 101.4 98.9 Oct. 71.5 62.8 62.3 61.4 55.9 102.8 88.8 87.7 63.6 62.2 Nov. 205.4 195.8 195.2 192.3 181.4 193.4 199.5 199.3 196.7 194.6 Dec. 294.2 283.1 282.8 279.0 258.8 311.8 307.9 307.6 283.7 282.6 1999 1340.3 1329.8 1329.3 1327.0 1352.5 1398.3 1369.6 1367.4 1330.6 1328.8 Jan. 235.0 208.4 206.6 198.5 177.9 238.6 234.8 233.9 211.1 205.6 Feb. 195.1 203.9 202.9 198.2 200.9 193.0 190.2 190.9 205.4 202.3 Mar. 319.1 303.0 302.1 294.0 274.2 365.1 344.6 342.1 303.7 300.9 April 81.7 94.4 96.0 99.1 114.0 68.5 72.4 73.4 91.9 96.7 May 4.9 4.7 4.7 5.4 7.9 6.7 6.4 6.3 4.7 4.7 June 0.7 0.8 0.8 0.7 0.6 0.8 0.8 0.8 0.8 0.8 July 0.8 0.8 0.8 0.7 0.6 1.1 1.0 1.0 0.8 0.8 Aug. 38.3 47.5 47.7 51.2 67.1 21.6 31.2 31.4 47.4 47.9 Sep. 22.6 24.3 24.4 26.6 29.3 21.2 22.4 22.3 24.3 24.7 Oct. 69.2 74.4 75.0 77.2 91.1 84.7 80.3 79.6 73.4 75.3 Nov. 226.0 230.2 231.6 239.2 255.3 251.0 240.7 240.5 228.4 232.6 Dec. 147.1 137.5 136.9 136.1 133.7 145.9 144.9 145.1 138.7 136.6 2000 1374.6 1312.8 1310.8 1313.4 1318.5 1390.1 1401.8 1397.2 1316.3 1310.0 Jan. 198.4 194.7 193.8 191.0 189.4 192.8 198.2 199.0 196.1 193.3 Feb. 165.4 156.7 156.2 155.5 151.6 167.6 170.0 169.2 157.5 155.9 Mar. 310.1 293.1 292.6 290.2 280.2 327.1 320.1 317.7 293.8 292.3 April 64.7 62.5 62.4 63.3 67.7 58.0 61.7 61.9 62.8 62.5 May 5.7 5.7 5.8 6.5 8.0 6.8 6.1 6.1 5.5 5.9 June 0.7 0.7 0.6 0.6 0.6 0.5 0.8 0.8 0.7 0.6 July 0.9 1.1 1.2 1.3 1.4 0.4 0.7 0.7 1.1 1.2 Aug. 2.0 3.0 3.1 4.4 12.0 2.0 2.4 2.4 3.0 3.2 Sep. 75.9 79.9 80.6 84.3 89.0 76.9 79.1 78.8 78.8 81.1 Oct. 93.6 92.3 92.2 94.2 95.1 113.6 106.4 105.5 92.8 92.4 Nov. 200.9 185.3 185.5 190.2 199.4 191.1 200.2 199.3 184.9 185.7 Dec. 256.3 237.9 236.8 231.9 224.1 253.3 256.2 255.9 239.4 236.1 2001 1568.1 1530.9 1530.8 1552.1 1574.1 1561.8 1562.2 1562.1 1532.8 1532.2 Jan. 247.8 227.0 226.7 225.6 215.8 255.2 249.8 248.8 227.8 226.7 Feb. 196.7 184.5 183.6 187.8 195.2 200.4 205.4 204.5 186.3 183.6 Mar. 323.1 298.2 296.9 295.5 287.8 311.8 314.3 314.8 300.5 296.6 April 105.1 109.4 109.5 110.2 120.6 96.3 100.5 100.7 109.4 109.4 May 2.4 3.2 3.2 4.1 5.6 1.0 2.2 2.2 3.2 3.2 June 0.9 1.4 1.4 1.8 2.4 0.5 0.7 0.7 1.4 1.4 July 0.6 0.9 1.0 1.0 2.3 0.5 0.6 0.6 0.8 1.0 Aug. 42.2 36.6 36.1 37.1 34.0 47.0 46.8 46.2 37.6 36.1 Sep. 23.8 24.6 24.8 25.2 27.7 23.7 24.4 24.3 24.2 25.0 Oct. 181.1 180.6 180.3 183.0 187.8 202.8 188.2 187.6 181.6 180.5 Nov. 228.2 245.0 247.9 260.1 273.0 229.3 227.8 228.4 240.3 249.3 Dec. 216.2 219.4 219.3 220.7 221.9 193.3 201.6 203.4 219.6 219.4

115 SECTION ID 1 2 3 4 5 6 7 8 9 10 2002 1396.2 1382.9 1383.1 1389.8 1398.0 1343.1 1369.1 1369.1 1382.9 1383.4 Jan. 193.3 201.9 202.7 202.2 201.9 169.1 178.0 178.7 200.6 203.1 Feb. 278.6 246.7 245.6 239.4 215.5 286.8 285.4 283.4 248.4 244.9 Mar. 301.2 286.1 284.1 278.0 259.3 260.8 279.4 280.1 289.6 283.2 April 113.7 119.5 119.3 119.0 132.8 113.9 114.1 114.4 119.8 119.2 May 2.4 6.9 7.9 10.8 12.5 1.5 2.0 2.0 5.1 8.3 June 1.1 1.6 1.6 1.8 2.9 0.4 0.5 0.6 1.6 1.6 July 0.8 0.8 0.8 0.8 0.7 1.1 1.0 1.0 0.9 0.8 Aug. 31.9 38.9 40.0 47.5 65.4 29.0 29.4 29.5 37.3 40.9 Sep. 41.7 46.6 46.7 49.0 55.4 33.1 36.8 37.3 46.6 46.9 Oct. 84.1 84.6 84.7 86.1 87.2 88.8 87.4 87.4 84.6 84.8 Nov. 121.4 129.2 130.2 135.5 146.2 109.2 115.3 115.6 127.6 130.8 Dec. 226.1 220.0 219.4 219.6 218.0 249.5 239.8 239.1 220.7 218.9 2003 1349.4 1343.8 1341.4 1343.0 1358.1 1310.5 1327.6 1328.6 1348.4 1340.8 Jan. 278.9 288.5 287.9 287.0 299.5 259.9 264.7 266.2 289.9 287.8 Feb. 226.9 207.9 206.9 207.8 202.4 235.4 230.9 230.1 210.3 206.8 Mar. 261.5 246.2 244.4 238.6 225.9 243.6 254.2 254.2 249.2 243.5 April 161.2 158.9 158.0 154.9 151.6 151.5 156.4 155.7 160.5 157.5 May 8.0 12.7 13.3 16.0 26.6 6.9 7.1 7.1 12.0 13.7 June 0.8 0.9 0.9 1.2 1.9 1.4 1.1 1.1 0.8 0.9 July 1.0 1.3 1.3 1.3 1.2 0.7 0.9 0.9 1.3 1.3 Aug. 10.4 12.9 13.3 15.4 20.6 5.8 8.5 8.5 12.4 13.5 Sep. 30.0 27.2 27.0 26.2 26.8 32.7 32.1 32.0 27.4 26.9 Oct. 60.3 69.2 70.3 75.3 79.9 56.9 58.7 59.0 67.5 71.0 Nov. 109.4 102.8 102.7 102.0 102.5 118.1 115.9 115.2 102.9 102.6 Dec. 200.8 215.2 215.5 217.1 219.0 197.8 197.1 198.5 214.3 215.4 2004 1347.6 1396.9 1398.6 1410.3 1430.7 1371.0 1366.6 1367.5 1395.0 1400.3 Jan. 190.8 200.0 199.2 193.9 185.0 181.4 185.8 186.6 200.9 198.6 Feb. 229.9 248.4 250.0 260.9 281.2 205.0 218.9 219.6 246.7 251.7 Mar. 157.3 158.7 159.1 159.7 157.4 157.9 159.4 159.3 157.9 159.2 April 110.9 105.1 105.5 106.6 105.6 127.6 121.6 120.2 104.3 105.4 May 3.8 3.7 3.7 3.6 2.9 2.2 2.7 2.9 3.7 3.6 June 0.3 0.4 0.4 0.4 0.7 0.4 0.4 0.4 0.4 0.4 July 3.1 4.0 4.0 4.0 3.8 1.6 2.6 2.6 4.0 4.0 Aug. 9.1 10.7 10.7 10.6 10.8 6.1 8.8 8.9 10.8 10.6 Sep. 49.4 55.4 56.3 61.1 72.0 57.2 56.0 55.8 54.3 57.1 Oct. 104.2 105.3 105.2 105.1 104.5 108.9 104.5 104.9 105.5 105.2 Nov. 176.6 179.9 179.7 181.9 185.3 169.7 173.3 174.3 180.9 180.1 Dec. 312.2 325.4 324.9 322.4 321.5 353.0 332.4 332.2 325.7 324.3 2005 1444.7 1434.3 1431.4 1420.0 1396.7 1481.5 1457.4 1454.6 1438.5 1429.7 Jan. 221.6 213.0 211.9 207.8 198.1 214.6 219.1 218.5 215.0 211.4 Feb. 254.9 246.2 244.4 233.0 216.5 267.1 259.7 258.8 248.6 243.2 Mar. 295.5 282.6 281.4 276.8 255.7 290.4 290.6 290.3 285.0 281.0 April 70.7 79.4 79.6 84.2 87.7 85.5 78.1 77.7 79.5 80.0 May 12.2 11.0 11.0 11.0 11.2 10.0 10.2 10.4 11.1 11.0 June 1.0 0.8 0.8 0.7 0.7 1.5 1.3 1.3 0.8 0.8 July 5.5 6.0 5.9 5.6 4.8 2.9 4.4 4.5 6.1 5.8 Aug. 12.2 13.6 13.7 13.7 13.6 9.8 11.8 11.8 13.4 13.8 Sep. 32.3 45.2 45.7 48.9 60.3 16.1 23.6 24.3 44.5 46.0 Oct. 157.9 158.2 158.1 154.9 156.0 191.2 176.7 175.5 157.9 157.7 Nov. 210.6 210.7 211.0 210.4 206.0 209.7 206.0 206.7 209.4 210.7 Dec. 170.3 167.6 168.0 173.1 186.2 182.7 175.8 174.8 167.2 168.3

116 SECTION ID 1 2 3 4 5 6 7 8 9 10 2006 1437.0 1485.0 1484.5 1484.3 1508.4 1450.3 1425.2 1424.9 1485.5 1484.1 Jan. 173.1 167.6 167.1 163.5 151.6 199.3 188.3 186.9 168.7 166.8 Feb. 225.5 231.3 229.5 222.2 219.8 201.2 203.9 205.1 234.3 228.6 Mar. 260.1 268.0 268.2 268.2 262.7 264.4 261.3 261.3 267.6 268.2 April 130.3 138.9 140.0 143.6 145.7 126.3 125.7 126.2 137.3 140.7 May 2.5 3.9 3.9 3.8 6.2 1.6 2.0 2.0 4.0 3.8 June 0.2 0.2 0.2 0.3 0.5 0.4 0.3 0.3 0.2 0.2 July 0.8 0.6 0.6 0.6 0.5 0.7 0.8 0.8 0.7 0.6 Aug. 14.4 12.9 12.8 12.2 12.2 8.4 12.2 12.3 13.1 12.7 Sep. 49.4 55.8 56.4 59.2 67.8 68.1 59.6 59.2 55.0 56.7 Oct. 100.9 95.0 94.6 93.9 92.7 111.1 104.7 103.9 95.7 94.4 Nov. 207.8 204.5 204.9 206.4 212.3 207.8 208.8 208.0 203.7 205.1 Dec. 272.2 306.0 306.3 310.4 336.2 261.1 257.7 259.0 305.3 306.2 2007 1645.8 1693.7 1693.1 1701.6 1739.8 1561.5 1609.9 1610.3 1695.3 1693.4 Jan. 289.2 275.7 273.9 265.1 240.4 306.1 296.1 294.8 278.2 272.6 Feb. 318.7 299.1 298.7 295.5 288.4 337.0 327.6 325.5 299.9 298.8 Mar. 189.8 177.9 176.8 172.4 162.7 226.8 208.8 207.4 179.7 176.2 April 144.3 162.2 161.6 160.4 163.5 112.5 129.4 130.8 163.1 161.1 May 1.8 1.7 1.8 2.6 4.9 4.4 3.3 3.2 1.5 2.0 June 2.3 3.0 3.0 3.8 5.5 1.3 1.7 1.8 2.9 3.1 July 1.2 1.3 1.3 1.2 1.5 0.4 0.8 0.8 1.3 1.3 Aug. 8.8 14.1 14.4 17.3 24.6 7.1 7.8 7.8 14.0 14.8 Sep. 57.1 72.9 73.7 77.5 90.3 41.0 48.8 49.5 71.7 74.2 Oct. 183.6 200.1 201.4 210.8 247.6 127.1 157.1 159.1 198.4 202.5 Nov. 240.3 267.0 268.9 282.5 314.4 211.4 229.5 230.9 264.1 270.1 Dec. 208.7 218.7 217.6 212.5 195.9 186.7 199.1 198.8 220.3 216.8 2008 1042.0 1011.6 1009.4 1012.0 994.2 1096.7 1067.9 1067.3 1016.8 1009.6 Jan. 258.6 230.1 228.0 222.6 209.6 285.9 267.8 267.1 234.0 227.1 Feb. 145.4 129.7 128.8 123.3 115.0 144.7 145.2 144.4 130.7 128.1 Mar. 169.4 160.7 160.2 157.9 149.7 175.8 175.7 175.3 161.4 159.8 April 100.6 105.2 105.7 112.0 125.3 65.9 85.0 86.0 104.9 106.6 May 32.5 30.9 30.3 28.5 23.5 47.1 39.1 38.9 31.7 30.0 June 0.5 0.4 0.4 0.4 0.3 0.9 0.8 0.7 0.4 0.4 July 1.0 1.0 1.0 1.0 1.5 1.2 1.1 1.1 1.0 0.9 Aug. 6.7 8.6 8.6 8.5 8.0 4.1 4.2 4.7 8.7 8.5 Sep. 18.8 36.9 38.0 45.4 54.3 17.1 16.4 16.8 35.8 39.0 Oct. 37.9 36.1 36.1 35.5 33.7 52.5 47.7 47.2 36.1 36.0 Nov. 141.6 150.4 151.5 158.2 162.1 146.3 141.3 141.8 149.1 152.5 Dec. 128.8 121.7 120.9 118.6 111.1 155.2 143.6 143.1 122.9 120.6 2009 1317.8 1289.8 1288.6 1295.6 1301.9 1322.9 1318.6 1317.0 1292.1 1288.5 Jan. 205.3 185.6 183.5 175.0 150.7 234.8 222.2 220.7 188.8 182.4 Feb. 193.0 176.5 175.7 170.8 161.2 199.6 189.6 189.5 177.4 175.1 Mar. 352.4 320.0 317.3 310.3 284.4 378.1 370.1 368.5 324.8 316.1 April 81.4 82.3 82.7 87.1 104.6 81.8 84.0 83.3 81.6 83.1 May 20.0 32.7 33.5 40.9 50.9 12.9 14.1 14.8 31.6 34.2 June 7.2 9.3 9.4 9.6 9.0 5.5 6.0 6.0 9.2 9.4 July 0.1 0.2 0.2 0.2 0.3 0.1 0.1 0.1 0.2 0.2 Aug. 0.1 2.2 2.6 2.6 3.4 0.4 0.3 0.3 1.4 2.7 Sep. 25.7 34.9 35.2 37.6 43.4 11.9 18.4 19.0 34.4 35.5 Oct. 88.5 91.9 93.5 103.7 119.4 69.3 76.4 77.3 89.8 94.8 Nov. 153.3 141.3 140.6 142.1 154.5 166.8 164.2 163.3 142.7 140.4 Dec. 190.6 212.9 214.3 215.6 220.2 161.7 173.3 174.2 210.1 214.7

117 SECTION ID 1 2 3 4 5 6 7 8 9 10 2010 1143.0 1158.0 1160.4 1166.2 1185.2 1144.4 1120.5 1121.3 1154.4 1161.8 Jan. 186.6 171.3 170.7 168.9 159.4 198.6 190.9 189.8 172.3 170.5 Feb. 154.0 164.0 163.6 158.9 162.9 128.3 134.3 135.6 164.4 163.3 Mar. 263.2 245.3 243.8 235.8 210.4 308.2 284.5 282.7 247.5 242.7 April 94.0 97.3 98.4 105.3 128.1 77.6 82.5 83.0 96.0 99.3 May 13.8 13.9 13.9 14.1 15.0 9.1 12.0 12.2 14.0 13.9 June 0.1 0.1 0.1 0.1 0.4 0.2 0.1 0.1 0.1 0.1 July 0.0 0.0 0.0 0.4 1.7 0.0 0.0 0.0 0.0 0.0 Aug. 0.1 0.5 0.6 1.2 5.2 0.3 0.2 0.2 0.4 0.6 Sep. 28.0 28.7 29.2 32.1 33.7 37.1 34.7 34.4 27.9 29.5 Oct. 54.1 57.0 57.2 56.8 57.1 57.4 56.8 56.7 56.6 57.2 Nov. 202.1 209.6 210.3 214.6 222.7 189.4 189.3 189.7 208.6 210.7 Dec. 146.9 170.4 172.8 178.2 188.6 138.3 135.1 137.0 166.5 173.9 2011 1302.0 1300.8 1302.1 1312.3 1304.9 1256.4 1266.2 1268.7 1299.3 1303.4 Jan. 347.8 315.6 312.6 297.5 266.3 304.9 322.8 323.9 320.1 310.7 Feb. 182.9 168.2 167.3 165.7 160.4 160.1 170.0 170.1 169.7 166.9 Mar. 255.2 238.0 237.0 232.0 219.1 255.3 249.9 250.6 239.7 236.4 April 25.9 30.5 30.9 32.3 35.7 36.3 31.4 31.3 29.8 31.0 May 0.9 0.7 0.7 0.8 1.4 1.9 1.4 1.4 0.7 0.7 June 0.0 0.0 0.0 0.0 0.4 0.0 0.0 0.0 0.0 0.0 July 1.6 5.1 5.2 6.5 8.0 0.0 0.8 0.9 4.9 5.3 Aug. 0.1 0.8 1.0 2.5 3.2 0.0 0.0 0.0 0.7 1.1 Sep. 31.7 51.0 52.1 56.2 61.5 27.5 26.4 27.0 49.4 52.8 Oct. 57.7 76.4 78.7 91.4 115.5 47.3 50.7 51.4 73.2 80.5 Nov. 194.7 232.2 234.6 246.5 267.8 193.9 196.6 197.2 228.4 236.0 Dec. 203.5 182.3 182.1 180.9 165.7 229.1 216.1 214.8 182.6 182.0 2012 1215.9 1219.7 1220.4 1219.0 1223.2 1137.1 1170.4 1174.0 1218.2 1220.6 Jan. 223.9 217.5 217.1 212.4 197.8 252.3 241.9 240.9 217.8 216.6 Feb. 194.7 184.5 183.5 174.4 153.5 197.8 191.3 192.3 185.7 182.7 Mar. 219.9 207.4 206.2 200.6 189.9 189.6 201.0 201.6 209.3 205.3 April 23.0 33.8 35.5 41.4 61.1 21.0 21.0 21.3 31.1 36.4 May 1.6 1.6 1.6 2.1 4.2 0.0 1.1 1.1 1.4 1.7 June 0.0 0.0 0.0 0.0 0.2 0.0 0.0 0.0 0.0 0.0 July 0.5 1.1 1.1 1.0 1.0 0.0 0.2 0.2 1.2 1.1 Aug. 19.7 25.3 25.7 26.4 33.8 7.5 16.4 16.4 24.7 25.8 Sep. 65.2 68.7 68.3 67.8 67.3 31.9 45.5 46.9 69.2 68.1 Oct. 103.9 103.4 103.9 106.8 113.9 112.3 108.0 107.3 102.8 104.3 Nov. 139.3 148.5 149.1 153.7 164.1 119.5 129.8 131.3 147.9 149.8 Dec. 224.2 227.8 228.4 232.4 236.4 205.2 214.1 214.6 227.1 228.9 2013 966.3 1035.0 1039.6 1045.9 1090.2 884.6 913.8 917.2 1026.2 1041.0 Jan. 110.4 105.8 105.0 101.2 96.4 91.4 96.5 97.3 107.0 104.6 Feb. 156.4 201.2 204.4 212.0 234.8 131.4 137.6 139.5 195.4 205.7 Mar. 169.7 170.0 169.8 167.8 171.0 153.6 159.8 159.7 170.2 169.7 April 90.8 118.5 120.6 125.9 149.4 60.8 75.2 76.3 114.9 121.6 May 2.7 12.8 13.2 14.7 19.6 0.1 0.3 0.4 12.1 13.4 June 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 July 0.3 0.9 0.9 1.2 0.9 0.7 0.5 0.5 0.9 1.0 Aug. 5.4 6.3 6.3 6.3 7.3 2.3 3.7 3.8 6.4 6.3 Sep. 16.3 15.0 15.0 15.7 18.2 17.3 17.0 17.1 15.2 15.0 Oct. 98.4 104.8 105.3 106.1 106.1 71.1 81.4 82.9 103.8 105.3 Nov. 163.4 164.7 164.6 160.6 153.3 176.9 171.9 171.4 164.5 164.2 Dec. 152.6 135.0 134.4 134.4 133.2 178.9 170.0 168.3 136.0 134.2

118 Table A- 2 – Characterization of the hydrometric station located in the Kasai River Basin

Lat. Long. Catchment Altitude Mean annual Mean annual Mean annual Station River (º) (º) Area (km2) (m) discharge (m3/s) volume (km3) runoff depth (mm) PORT-FRANCQUI Kasai -4.33 20.58 232560 365.02 2106.543 66.432 286

Figure A- 12 - Catchment area defined by the hydrometric station considered

Figure A- 13 - Satellite precipitation in the catchment area defined by the GRDC station (mean daily values)

119 Table A- 3 - Typical values of the runoff coefficient. APPLIED HYDROLOGY, page 498 (Chow, Maidment, and W. Mays 1988)

Return Period (years) Character of Surface 2 5 10 25 50 100 500 Developed Asphaltic 0.73 0.77 0.81 0.86 0.90 0.95 1.00 Concrete/Roof 0.75 0.80 0.83 0.88 0.92 0.97 1.00 Grass Areas Poor Condition (grass < 50%) Flat, 0-2% 0.32 0.34 0.37 0.40 0.44 0.47 0.58 Average, 2-7% 0.37 0.40 0.43 0.46 0.49 0.53 0.61 Steep, over 7% 0.40 0.43 0.45 0.49 0.52 0.55 0.62 Fair Condition (50% < grass <75%) Flat, 0-2% 0.25 0.28 0.30 0.34 0.37 0.41 0.53 Average, 2-7% 0.33 0.36 0.38 0.42 0.45 0.49 0.58 Steep, over 7% 0.37 0.40 0.42 0.46 0.49 0.53 0.60 Good Condition (grass > 75%) Flat, 0-2% 0.21 0.23 0.25 0.29 0.32 0.36 0.49 Average, 2-7% 0.29 0.32 0.35 0.39 0.42 0.46 0.56 Steep, over 7% 0.34 0.37 0.40 0.44 0.47 0.51 0.58 Undeveloped Cultivated Land Flat, 0-2% 0.31 0.34 0.36 0.40 0.43 0.47 0.57 Average, 2-7% 0.35 0.38 0.41 0.44 0.48 0.51 0.60 Steep, over 7% 0.39 0.42 0.44 0.48 0.51 0.54 0.61 Pasture/Range Flat, 0-2% 0.25 0.28 0.30 0.34 0.37 0.41 0.53 Average, 2-7% 0.33 0.36 0.38 0.42 0.45 0.49 0.58 Steep, over 7% 0.37 0.40 0.42 0.46 0.49 0.53 0.60

Table A- 4 - Typical values of the runoff coefficient (source: http://www.brighthubengineering.com/hydraulics-civil-engineering/93173- runoff-coefficients-for-use-in-rational-method-calculations/, 14/03/2015)

Group: Soil Group A Soil Group B Soil Group C Soil Group D Slope: < 2% 2-6 % > 6% < 2% 2-6 % > 6% < 2% 2-6 % > 6% < 2% 2-6 % > 6% Forest 0.08 0.11 0.14 0.10 0.14 0.18 0.12 0.16 0.20 0.15 0.20 0.25 Meadow 0.14 0.22 0.30 0.20 0.28 0.37 0.26 0.35 0.44 0.30 0.40 0.50 Pasture 0.15 0.25 0.37 0.23 0.34 0.45 0.30 0.42 0.52 0.37 0.50 0.62 Farmland 0.14 0.18 0.22 0.16 0.21 0.28 0.20 0.25 0.34 0.24 0.29 0.41 Res. 1 acre 0.22 0.26 0.29 0.24 0.28 0.34 0.28 0.32 0.40 0.31 0.35 0.46 Res. 1/2 acre 0.25 0.29 0.32 0.28 0.32 0.36 0.31 0.35 0.42 0.34 0.38 0.46 Res. 1/3 acre 0.28 0.32 0.35 0.30 0.35 0.39 0.33 0.38 0.45 0.36 0.40 0.50 Res. 1/4 acre 0.30 0.34 0.37 0.33 0.37 0.42 0.36 0.40 0.47 0.38 0.42 0.52 Res. 1/8 acre 0.33 0.37 0.40 0.35 0.39 0.44 0.38 0.42 0.49 0.41 0.45 0.54 Industrial 0.85 0.85 0.86 0.85 0.86 0.86 0.86 0.86 0.87 0.86 0.86 0.88 Commercial 0.88 0.88 0.89 0.89 0.89 0.89 0.89 0.89 0.90 0.89 0.89 0.90 Streets: ROW 0.76 0.77 0.79 0.80 0.82 0.84 0.84 0.85 0.89 0.89 0.91 0.95 Parking 0.95 0.96 0.97 0.95 0.96 0.97 0.95 0.96 0.97 0.95 0.96 0.97 Disturbed Area 0.65 0.67 0.69 0.66 0.68 0.70 0.68 0.70 0.72 0.69 0.72 0.75

120 10000

1000

/s) 3

100 Discharge (m Discharge

1 0 50 100 150 200 250 300 350 Number of days exceeded Figure A- 14 - Flow duration curve in section 2

Table A- 5 - Characteristics of the flow duration curve in section 2

Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 2085.6 18.8 37 10% 334.9 3.0 73 20% 202.6 1.8 80 22% 185.4 1.7 90 25% 158.8 1.4 100 27% 138.8 1.3 110 30% 119.0 1.1 120 33% 102.3 0.9 130 36% 87.1 0.8 140 38% 74.0 0.7 146 40% 65.7 0.6 180 49% 27.2 0.2 183 50% 24.6 0.2 219 60% 5.5 0.05 256 70% 0.6 0.0 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 110.8 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 2085.6 3 Mean Annual Affluent Volume (hm ) 3495.0

121 10000

1000

/s) 3

100 Discharge (m Discharge

1 0 50 100 150 200 250 300 350

Number of days exceeded

Figure A- 15 - Flow duration curve in section 3

Table A- 6 - Characteristics of the flow duration curve in section 3

Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 2093.5 18.6 37 10% 341.0 3.0 73 20% 206.1 1.8 80 22% 188.2 1.7 90 25% 161.9 1.4 100 27% 141.4 1.3 110 30% 122.0 1.1 120 33% 104.0 0.9 130 36% 89.4 0.8 140 38% 75.8 0.7 146 40% 67.8 0.6 180 49% 28.2 0.2 183 50% 25.4 0.2 219 60% 5.7 0.05 256 70% 0.7 0.0 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 112.8 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 2093.5 3 Mean Annual Affluent Volume (hm ) 3558.8

122 10000

1000

/s) 3

100 Discharge (m Discharge 10

1 0 50 100 150 200 250 300 350

Number of days exceeded

Figure A- 16 - Flow duration curve in section 4

Table A- 7 - Characteristics of the flow duration curve in section 4

Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 2130.1 17.2 37 10% 369.7 3.0 73 20% 227.7 1.8 80 22% 208.3 1.7 90 25% 181.9 1.5 100 27% 156.9 1.3 110 30% 137.1 1.1 120 33% 117.6 0.9 130 36% 101.5 0.8 140 38% 85.0 0.7 146 40% 77.7 0.6 180 49% 35.4 0.3 183 50% 31.8 0.3 219 60% 8.0 0.06 256 70% 1.1 0.0 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 123.9 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 2130.1 3 Mean Annual Affluent Volume (hm ) 3906.3

123 10000

1000

/s) 3

100 Discharge (m Discharge 10

1 0 50 100 150 200 250 300 350

Number of days exceeded

Figure A- 17 - Flow duration curve in section 5

Table A- 8 - Characteristics of the flow duration curve in section 5 Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 2664.2 15.4 37 10% 510.4 3.0 73 20% 315.9 1.8 80 22% 291.1 1.7 90 25% 255.7 1.5 100 27% 221.8 1.3 110 30% 194.3 1.1 120 33% 167.3 1.0 130 36% 147.6 0.9 140 38% 125.9 0.7 146 40% 114.5 0.7 180 49% 55.2 0.3 183 50% 51.3 0.3 219 60% 15.6 0.09 256 70% 2.1 0.0 292 80% 0.1 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 172.6 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 2664.2 3 Mean Annual Affluent Volume (hm ) 5442.5

124 1000

100

/s) 3

10 Discharge (m Discharge

1 0 50 100 150 200 250 300 350

Number of days exceeded

Figure A- 18 - Flow duration curve in section 6

Table A- 9 - Characteristics of the flow duration curve in section 6

Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 947.0 28.2 37 10% 107.5 3.2 73 20% 57.5 1.7 80 22% 51.3 1.5 90 25% 43.6 1.3 100 27% 36.0 1.1 110 30% 29.8 0.9 120 33% 24.2 0.7 130 36% 19.1 0.6 140 38% 14.7 0.4 146 40% 12.3 0.4 180 49% 3.5 0.1 183 50% 3.0 0.1 219 60% 0.4 0.01 256 70% 0.0 0.0 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 33.6 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 947.0 3 Mean Annual Affluent Volume (hm ) 1058.8

125 10000

1000

/s) 3

100 Discharge (m Discharge

1 0 50 100 150 200 250 300 350

Number of days exceeded

Figure A- 19 - Flow duration curve in section 7

Table A- 10 - Characteristics of the flow duration curve in section 7

Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 1170.1 25.8 37 10% 140.0 3.1 73 20% 80.3 1.8 80 22% 72.8 1.6 90 25% 61.9 1.4 100 27% 53.0 1.2 110 30% 44.7 1.0 120 33% 37.1 0.8 130 36% 31.3 0.7 140 38% 25.2 0.6 146 40% 21.5 0.5 180 49% 7.5 0.2 183 50% 6.5 0.1 219 60% 1.1 0.02 256 70% 0.1 0.0 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 45.3 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 1170.1 3 Mean Annual Affluent Volume (hm ) 1428.5

126 10000

1000

/s) 3

100 Discharge (m Discharge

1 0 50 100 150 200 250 300 350

Number of days exceeded Figure A- 20 - Flow duration curve in section 8

Table A- 11 - Characteristics of the flow duration curve in section 8

Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 1181.1 25.6 37 10% 141.8 3.1 73 20% 82.3 1.8 80 22% 74.3 1.6 90 25% 63.2 1.4 100 27% 54.1 1.2 110 30% 45.8 1.0 120 33% 37.8 0.8 130 36% 32.2 0.7 140 38% 26.0 0.6 146 40% 22.3 0.5 180 49% 7.9 0.2 183 50% 6.9 0.1 219 60% 1.2 0.03 256 70% 0.1 0.0 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 46.2 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 1181.1 3 Mean Annual Affluent Volume (hm ) 1456.1

127 10000

1000

/s) 3

100 Discharge (m Discharge

1 0 50 100 150 200 250 300 350

Number of days exceeded

Figure A- 21 - Flow duration curve in section 9

Table A- 12 - Characteristics of the flow duration curve in section 9

Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 2071.6 19.2 37 10% 328.0 3.0 73 20% 198.2 1.8 80 22% 179.6 1.7 90 25% 153.9 1.4 100 27% 134.4 1.2 110 30% 115.5 1.1 120 33% 97.9 0.9 130 36% 83.9 0.8 140 38% 71.4 0.7 146 40% 63.1 0.6 180 49% 25.7 0.2 183 50% 23.7 0.2 219 60% 5.1 0.05 256 70% 0.6 0.0 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 107.8 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 2071.6 3 Mean Annual Affluent Volume (hm ) 3400.9

128 10000

1000

/s) 3

100 Discharge (m Discharge

1 0 50 100 150 200 250 300 350

Number of days exceeded Figure A- 22 - Flow duration curve in section 10

Table A- 13 - Characteristics of the flow duration curve in section 10

Number of days Probability of Dischage Q/Qmod exceeded exccedence (m3/s)

0 - 2096.4 18.4 37 10% 344.0 3.0 73 20% 208.2 1.8 80 22% 191.2 1.7 90 25% 164.2 1.4 100 27% 143.0 1.3 110 30% 124.2 1.1 120 33% 104.8 0.9 130 36% 90.2 0.8 140 38% 76.6 0.7 146 40% 69.2 0.6 180 49% 29.1 0.3 183 50% 26.2 0.2 219 60% 6.1 0.05 256 70% 0.7 0.0 292 80% 0.0 0.0 329 90% 0.0 0.0 365 100% 0.0 0.0

Mean Annual Discharge (m3/s) 114.1 Number of days exceeded (days) 112.0 Maximum Discharge (m3/s) 2096.4 3 Mean Annual Affluent Volume (hm ) 3598.4

129 Table A- 14 - Determination of the reservoir volume for different values of equipped discharge in section 2 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent 555.6 525.7 638.9 264.1 24.6 3.4 4.3 40.7 126.3 261.9 493.2 556.3 Volumes (hm3) Acomulated Affluent 555.6 1081.3 1720.2 1984.3 2009.0 2012.3 2016.7 2057.4 2183.7 2445.6 2938.8 3495.0 Volumes (hm3) Qmod 296.8 268.1 296.8 287.3 296.8 287.3 296.8 296.8 287.3 296.8 287.3 296.8 Volume Q90 425.4 384.2 425.4 411.6 425.4 411.6 425.4 425.4 411.6 425.4 411.6 425.4 Demand (hm3) Q140 198.2 179.0 198.2 191.8 198.2 191.8 198.2 198.2 191.8 198.2 191.8 198.2 Q180 73.0 65.9 73.0 70.6 73.0 70.6 73.0 73.0 70.6 73.0 70.6 73.0 Qmod 296.8 565.0 861.8 1149.1 1445.9 1733.2 2030.0 2326.8 2614.1 2910.9 3198.2 3495.0 Acomulated Q90 425.4 809.6 1234.9 1646.6 2071.9 2483.5 2908.9 3334.3 3495.0 3495.0 3495.0 3495.0 Volume Q140 198.2 377.1 575.3 767.1 965.2 1157.0 1355.2 1553.3 1745.1 1943.3 2135.0 2333.2 Demand (hm3) Q180 73.0 138.9 211.8 282.4 355.4 426.0 498.9 571.9 642.5 715.4 786.0 859.0 Qmod 258.7 257.6 342.1 -23.2 -272.2 -283.9 -292.5 -256.1 -161.0 -34.9 205.9 259.4 Difference Q90 130.2 141.5 213.6 -147.6 -400.7 -408.3 -421.0 -384.6 -285.4 -163.4 81.5 130.9 (hm3) Q140 357.4 346.8 440.8 72.3 -173.5 -188.4 -193.9 -157.4 -65.5 63.8 301.4 358.1 Q180 482.6 459.8 566.0 193.5 -48.3 -67.2 -68.6 -32.2 55.7 189.0 422.6 483.3 Qmod 258.7 516.4 858.5 835.3 563.1 279.2 -13.3 -269.4 -430.4 -465.3 -259.4 0.0 Difference - Q90 130.2 271.8 485.3 337.8 -62.9 -471.2 -892.3 -1276.9 -1311.4 -1049.4 -556.3 0.0 accumulated Q140 357.4 704.2 1144.9 1217.3 1043.7 855.3 661.5 504.1 438.6 502.3 803.7 1161.9 values(hm3) Q180 482.6 942.5 1508.4 1701.9 1653.6 1586.4 1517.7 1485.5 1541.2 1730.2 2152.7 2636.1 Qmod 1323.8 Reservoir Q90 1796.7 Volume (hm3) Q140 778.7 Q180 216.4

4000 4000 3500 Affluent Volumes 3500 Affluent Volumes

Q180 Q140

) 3000 3000

)

3 3 2500 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 4000 4000 3500 Affluent Volumes 3500

Qmod

) 3000 3000

) 3 2500 3 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 Affluent Volumes 500 500 Q90 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 23 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 2

130 Table A- 15 - Determination of the reservoir volume for different values of equipped discharge in section 3 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent Volumes 563.0 534.2 648.1 270.4 25.5 3.5 4.4 41.9 129.5 267.9 504.1 566.4 (hm3) Acomulated Affluent 563.0 1097.2 1745.3 2015.6 2041.1 2044.6 2049.0 2090.9 2220.4 2488.3 2992.4 3558.8 Volumes (hm3) Qmod 302.3 273.0 302.3 292.5 302.3 292.5 302.3 302.3 292.5 302.3 292.5 302.3 Volume Q90 433.5 391.6 433.5 419.5 433.5 419.5 433.5 433.5 419.5 433.5 419.5 433.5 Demand (hm3) Q140 203.1 183.5 203.1 196.6 203.1 196.6 203.1 203.1 196.6 203.1 196.6 203.1 Q180 75.5 68.2 75.5 73.1 75.5 73.1 75.5 75.5 73.1 75.5 73.1 75.5 Qmod 302.3 575.3 877.5 1170.0 1472.3 1764.8 2067.0 2369.3 2661.8 2964.1 3256.6 3558.8 Acomulated Q90 433.5 825.1 1258.6 1678.2 2111.7 2531.2 2964.8 3398.3 3558.8 3558.8 3558.8 3558.8 Volume Q140 203.1 386.6 589.7 786.3 989.5 1186.0 1389.2 1592.3 1788.9 1992.0 2188.6 2391.7 Demand (hm3) Q180 75.5 143.8 219.3 292.4 368.0 441.1 516.6 592.2 665.3 740.8 813.9 889.5 Qmod 260.8 261.2 345.8 -22.1 -276.8 -289.0 -297.9 -260.4 -163.0 -34.4 211.6 264.2 Difference Q90 129.5 142.6 214.6 -149.2 -408.0 -416.1 -429.1 -391.6 -290.0 -165.6 84.6 132.9 (hm3) Q140 359.9 350.7 445.0 73.8 -177.6 -193.1 -198.7 -161.2 -67.1 64.8 307.5 363.3 Q180 487.5 465.9 572.6 197.3 -50.1 -69.6 -71.2 -33.6 56.4 192.4 431.0 490.9 Qmod 260.8 521.9 867.8 845.6 568.8 279.8 -18.1 -278.4 -441.4 -475.8 -264.2 0.0 Difference - Q90 129.5 272.1 486.7 337.5 -70.6 -486.6 -915.8 -1307.4 -1338.4 -1070.5 -566.4 0.0 accumulated Q140 359.9 710.6 1155.5 1229.3 1051.7 858.6 659.8 498.6 431.5 496.3 803.8 1167.1 values(hm3) Q180 487.5 953.4 1526.0 1723.2 1673.2 1603.5 1532.4 1498.7 1555.1 1747.5 2178.5 2669.4 Qmod 1343.5 Reservoir Q90 1825.1 Volume (hm3) Q140 797.8 Q180 224.5

4000 4000 3500 Affluent Volumes 3500 Affluent Volumes

Q180 Q140

) 3000 3000

)

3 3 2500 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 4000 4000 Affluent Volumes 3500 Affluent Volumes 3500

Qmod Q90

) 3000 3000

) 3 2500 3 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 24 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 3

131 Table A- 16 - Determination of the reservoir volume for different values of equipped discharge in section 4 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent Volumes 602.5 578.8 697.1 303.8 30.9 4.1 5.1 49.8 148.4 301.2 564.2 620.5 (hm3) Acomulated Affluent 602.5 1181.3 1878.4 2182.2 2213.0 2217.2 2222.3 2272.1 2420.4 2721.6 3285.9 3906.3 Volumes (hm3) Qmod 331.8 299.7 331.8 321.1 331.8 321.1 331.8 331.8 321.1 331.8 321.1 331.8 Volume Q90 487.3 440.1 487.3 471.6 487.3 471.6 487.3 487.3 471.6 487.3 471.6 487.3 Demand Q140 227.7 205.7 227.7 220.3 227.7 220.3 227.7 227.7 220.3 227.7 220.3 227.7 (hm3) Q180 94.7 85.6 94.7 91.7 94.7 91.7 94.7 94.7 91.7 94.7 91.7 94.7 Acomulated Qmod 331.8 631.4 963.2 1284.3 1616.1 1937.1 2268.9 2600.7 2921.7 3253.5 3574.6 3906.3 Volume Q90 487.3 927.4 1414.7 1886.3 2373.5 2845.1 3332.4 3819.7 3906.3 3906.3 3906.3 3906.3 Demand Q140 227.7 433.3 661.0 881.4 1109.1 1329.4 1557.1 1784.8 2005.1 2232.8 2453.1 2680.8 3 (hm ) Q180 94.7 180.3 275.0 366.6 461.4 553.0 647.7 742.5 834.1 928.8 1020.5 1115.2 Qmod 270.7 279.1 365.3 -17.3 -300.9 -316.9 -326.7 -282.0 -172.7 -30.6 243.2 288.7 Difference Q90 115.2 138.6 209.8 -167.8 -456.4 -467.4 -482.2 -437.5 -323.2 -186.1 92.7 133.2 (hm3) Q140 374.8 373.1 469.4 83.4 -196.8 -216.2 -222.6 -177.9 -72.0 73.5 343.9 392.8 Q180 507.8 493.2 602.4 212.1 -63.8 -87.5 -89.6 -44.9 56.7 206.5 472.6 525.8 Qmod 270.7 549.8 915.2 897.9 597.0 280.1 -46.6 -328.6 -501.3 -531.9 -288.7 0.0 Difference - Q90 115.2 253.9 463.7 295.9 -160.5 -627.9 -1110.1 -1547.6 -1485.9 -1184.7 -620.5 0.0 accumulated Q140 374.8 747.9 1217.3 1300.8 1104.0 887.8 665.2 487.3 415.3 488.8 832.7 1225.5 values(hm3) Q180 507.8 1001.0 1603.4 1815.5 1751.7 1664.2 1574.5 1529.6 1586.3 1792.8 2265.4 2791.1 Qmod 1447.0 Reservoir Q90 2011.3 Volume (hm3) Q140 885.5 Q180 285.9

4500 4500 4000 Affluent Volumes 4000 Affluent Volumes

3500 Q180 3500 Q140

)

) 3 3000 3 3000 2500 2500 2000 2000

1500 1500

Volume (hm Volume Volume (hm Volume 1000 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 4500 4500 4000 Affluent Volumes 4000 Affluent Volumes Qmod Q90

3500 3500

)

) 3 3000 3 3000 2500 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 25 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 4

132 Table A- 17 - Determination of the reservoir volume for different values of equipped discharge in section 5 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent Volumes 787.2 789.5 916.2 459.4 51.6 6.9 8.0 85.7 226.1 442.9 812.8 856.0 (hm3) Acomulated Affluent 787.2 1576.7 2492.9 2952.4 3004.0 3010.9 3018.9 3104.7 3330.8 3773.6 4586.4 5442.5 Volumes (hm3) Qmod 462.2 417.5 462.2 447.3 462.2 447.3 462.2 462.2 447.3 462.2 447.3 462.2 Volume Q90 684.9 618.6 684.9 662.8 684.9 662.8 684.9 684.9 662.8 684.9 662.8 684.9 Demand Q140 337.3 304.6 337.3 326.4 337.3 326.4 337.3 337.3 326.4 337.3 326.4 337.3 (hm3) Q180 147.9 133.6 147.9 143.1 147.9 143.1 147.9 147.9 143.1 147.9 143.1 147.9 Acomulated Qmod 462.2 879.7 1342.0 1789.3 2251.5 2698.9 3161.1 3623.3 4070.7 4532.9 4980.2 5442.5 Volume Q90 684.9 1303.5 1988.4 2651.2 3336.1 3998.9 4683.8 5368.7 5442.5 5442.5 5442.5 5442.5 Demand Q140 337.3 641.9 979.2 1305.6 1642.8 1969.2 2306.5 2643.8 2970.1 3307.4 3633.8 3971.1 3 (hm ) Q180 147.9 281.4 429.3 572.4 720.3 863.4 1011.3 1159.2 1302.3 1450.1 1593.2 1741.1 Qmod 325.0 372.0 454.0 12.1 -410.6 -440.4 -454.2 -376.5 -221.2 -19.4 365.5 393.8 Difference Q90 102.3 170.8 231.3 -203.4 -633.2 -655.9 -676.9 -599.2 -436.7 -242.0 150.0 171.1 (hm3) Q140 450.0 484.8 579.0 133.1 -285.6 -319.5 -329.3 -251.5 -100.3 105.6 486.4 518.8 Q180 639.4 655.9 768.4 316.3 -96.2 -136.2 -139.9 -62.1 83.0 295.0 669.7 708.2 Qmod 325.0 697.0 1151.0 1163.1 752.5 312.1 -142.2 -518.7 -739.9 -759.3 -393.8 0.0 Difference - Q90 102.3 273.2 504.5 301.2 -332.1 -988.0 -1664.9 -2264.0 -2111.7 -1668.8 -856.0 0.0 accumulated Q140 450.0 934.8 1513.8 1646.8 1361.2 1041.7 712.5 460.9 360.6 466.2 952.6 1471.4 values(hm3) Q180 639.4 1295.3 2063.6 2380.0 2283.7 2147.5 2007.7 1945.5 2028.5 2323.5 2993.2 3701.4 Qmod 1922.3 Reservoir Q90 2768.6 Volume Q140 1286.2 (hm3) 434.4 Q180

6000 6000 Affluent Volumes Affluent Volumes

5000 Q180 5000 Q140

)

) 3 4000 3 4000 3000 3000

2000 2000

Volume (hm Volume Volume (hm Volume 1000 1000 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 6000 6000 Affluent Volumes Affluent Volumes 5000 5000

Qmod Q90

)

) 3 4000 3 4000 3000 3000

2000 2000

Volume (hm Volume Volume (hm Volume 1000 1000 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 26 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 5

133 Table A- 18 - Determination of the reservoir volume for different values of equipped discharge in section 6 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent 240.9 216.2 276.7 97.2 7.7 1.0 1.1 13.3 44.1 106.3 196.6 227.4 Volumes (hm3) Acomulated Affluent 240.9 457.1 733.8 831.0 838.6 839.7 840.8 854.1 898.2 1004.5 1201.2 1428.5 Volumes (hm3) Qmod 121.3 109.6 121.3 117.4 121.3 117.4 121.3 121.3 117.4 121.3 117.4 121.3 Volume Q90 165.8 149.8 165.8 160.4 165.8 160.4 165.8 165.8 160.4 165.8 160.4 165.8 Demand Q140 67.5 60.9 67.5 65.3 67.5 65.3 67.5 67.5 65.3 67.5 65.3 67.5 (hm3) Q180 20.0 18.1 20.0 19.3 20.0 19.3 20.0 20.0 19.3 20.0 19.3 20.0 Acomulated Qmod 121.3 230.9 352.2 469.7 591.0 708.4 829.7 951.1 1068.5 1189.8 1307.2 1428.5 Volume Q90 165.8 315.5 481.3 641.8 807.6 968.0 1133.8 1299.6 1428.5 1428.5 1428.5 1428.5 Demand Q140 67.5 128.4 195.9 261.1 328.6 393.9 461.4 528.8 594.1 661.6 726.9 794.3 3 (hm ) Q180 20.0 38.0 58.0 77.4 97.4 116.7 136.7 156.7 176.0 196.0 215.4 235.3 Qmod 119.6 106.6 155.4 -20.2 -113.7 -116.4 -120.2 -108.0 -73.3 -15.0 79.2 106.1 Difference Q90 75.1 66.4 110.9 -63.3 -158.1 -159.4 -164.7 -152.5 -116.4 -59.4 36.2 61.6 (hm3) Q140 173.4 155.3 209.3 31.9 -59.8 -64.3 -66.3 -54.2 -21.2 38.9 131.4 159.9 Q180 220.9 198.1 256.7 77.8 -12.3 -18.3 -18.9 -6.7 24.7 86.4 177.3 207.4 Qmod 119.6 226.2 381.6 361.3 247.6 131.3 11.1 -97.0 -170.3 -185.3 -106.1 0.0 Difference - Q90 75.1 141.5 252.5 189.2 31.0 -128.4 -293.0 -445.5 -530.4 -424.0 -227.4 0.0 accumulated Q140 173.4 328.7 537.9 569.8 510.0 445.8 379.4 325.3 304.1 342.9 474.3 634.2 values(hm3) Q180 220.9 419.0 675.8 753.6 741.3 723.0 704.1 697.4 722.2 808.5 985.8 1193.2 Qmod 566.8 Reservoir Q90 782.8 Volume Q140 265.8 (hm3) Q180 56.2

1200 1200 Affluent Volumes Affluent Volumes 1000 1000

Q180 Q140

)

) 3 800 3 800 600 600

400 400

Volume (hm Volume Volume (hm Volume 200 200 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 1200 1200 Affluent Volumes Affluent Volumes 1000 1000 Q90

Qmod

)

) 3 800 3 800 600 600

400 400

Volume (hm Volume Volume (hm Volume 200 200 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 27 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 6

134 Table A- 19 - Determination of the reservoir volume for different values of equipped discharge in section 7 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent 240.9 216.2 276.7 97.2 7.7 1.0 1.1 13.3 44.1 106.3 196.6 227.4 Volumes (hm3) Acomulated Affluent 240.9 457.1 733.8 831.0 838.6 839.7 840.8 854.1 898.2 1004.5 1201.2 1428.5 Volumes (hm3) Qmod 121.3 109.6 121.3 117.4 121.3 117.4 121.3 121.3 117.4 121.3 117.4 121.3 Volume Q90 165.8 149.8 165.8 160.4 165.8 160.4 165.8 165.8 160.4 165.8 160.4 165.8 Demand Q140 67.5 60.9 67.5 65.3 67.5 65.3 67.5 67.5 65.3 67.5 65.3 67.5 (hm3) Q180 20.0 18.1 20.0 19.3 20.0 19.3 20.0 20.0 19.3 20.0 19.3 20.0 Acomulated Qmod 121.3 230.9 352.2 469.7 591.0 708.4 829.7 951.1 1068.5 1189.8 1307.2 1428.5 Volume Q90 165.8 315.5 481.3 641.8 807.6 968.0 1133.8 1299.6 1428.5 1428.5 1428.5 1428.5 Demand Q140 67.5 128.4 195.9 261.1 328.6 393.9 461.4 528.8 594.1 661.6 726.9 794.3 3 (hm ) Q180 20.0 38.0 58.0 77.4 97.4 116.7 136.7 156.7 176.0 196.0 215.4 235.3 Qmod 119.6 106.6 155.4 -20.2 -113.7 -116.4 -120.2 -108.0 -73.3 -15.0 79.2 106.1 Difference Q90 75.1 66.4 110.9 -63.3 -158.1 -159.4 -164.7 -152.5 -116.4 -59.4 36.2 61.6 (hm3) Q140 173.4 155.3 209.3 31.9 -59.8 -64.3 -66.3 -54.2 -21.2 38.9 131.4 159.9 Q180 220.9 198.1 256.7 77.8 -12.3 -18.3 -18.9 -6.7 24.7 86.4 177.3 207.4 Qmod 119.6 226.2 381.6 361.3 247.6 131.3 11.1 -97.0 -170.3 -185.3 -106.1 0.0 Difference - Q90 75.1 141.5 252.5 189.2 31.0 -128.4 -293.0 -445.5 -530.4 -424.0 -227.4 0.0 accumulated Q140 173.4 328.7 537.9 569.8 510.0 445.8 379.4 325.3 304.1 342.9 474.3 634.2 values(hm3) Q180 220.9 419.0 675.8 753.6 741.3 723.0 704.1 697.4 722.2 808.5 985.8 1193.2 Qmod 566.8 Reservoir Q90 782.8 Volume Q140 265.8 (hm3) Q180 56.2

1600 1600 1400 Affluent Volumes 1400 Affluent Volumes

Q180 Q140

) 1200 1200

)

3 3 1000 1000 800 800

600 600 Volume (hm Volume 400 (hm Volume 400 200 200 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 1600 1600 Affluent Volumes 1400 Affluent Volumes 1400

Qmod Q90

) 1200 1200

) 3 1000 3 1000 800 800

600 600 Volume (hm Volume 400 (hm Volume 400 200 200 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 28 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 7

135 Table A- 20 - Determination of the reservoir volume for different values of equipped discharge in section 8 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent Volumes 245.2 220.3 281.5 99.3 7.9 1.1 1.2 13.6 45.2 108.4 200.6 231.9 (hm3) Acomulated Affluent 245.2 465.5 747.0 846.3 854.2 855.2 856.4 870.0 915.2 1023.6 1224.2 1456.1 Volumes (hm3) Qmod 123.7 111.7 123.7 119.7 123.7 119.7 123.7 123.7 119.7 123.7 119.7 123.7 Volume Q90 169.4 153.0 169.4 163.9 169.4 163.9 169.4 169.4 163.9 169.4 163.9 169.4 Demand Q140 69.6 62.8 69.6 67.3 69.6 67.3 69.6 69.6 67.3 69.6 67.3 69.6 (hm3) Q180 21.1 19.0 21.1 20.4 21.1 20.4 21.1 21.1 20.4 21.1 20.4 21.1 Acomulated Qmod 123.7 235.4 359.0 478.7 602.4 722.1 845.8 969.4 1089.1 1212.8 1332.5 1456.1 Volume Q90 169.4 322.4 491.8 655.7 825.1 989.1 1158.5 1327.9 1456.1 1456.1 1456.1 1456.1 Demand Q140 69.6 132.4 202.0 269.3 338.9 406.2 475.7 545.3 612.6 682.2 749.5 819.1 3 (hm ) Q180 21.1 40.1 61.2 81.6 102.6 123.0 144.1 165.2 185.5 206.6 227.0 248.1 Qmod 121.5 108.6 157.9 -20.4 -115.8 -118.6 -122.5 -110.1 -74.5 -15.3 81.0 108.2 Difference Q90 75.8 67.3 112.1 -64.7 -161.5 -162.9 -168.2 -155.8 -118.7 -61.0 36.7 62.5 (hm3) Q140 175.6 157.5 212.0 31.9 -61.7 -66.3 -68.4 -56.0 -22.1 38.8 133.3 162.3 Q180 224.1 201.3 260.5 78.9 -13.2 -19.3 -19.9 -7.5 24.8 87.3 180.3 210.8 Qmod 121.5 230.1 388.0 367.6 251.8 133.2 10.7 -99.4 -173.9 -189.2 -108.2 0.0 Difference - Q90 75.8 143.1 255.2 190.6 29.1 -133.8 -302.0 -457.8 -540.9 -432.6 -231.9 0.0 accumulated Q140 175.6 333.1 545.1 577.0 515.3 449.1 380.7 324.7 302.6 341.4 474.7 637.0 values(hm3) Q180 224.1 425.4 685.9 764.8 751.6 732.2 712.3 704.9 729.7 817.0 997.2 1208.1 Qmod 577.2 Reservoir Q90 796.2 Volume Q140 274.4 (hm3) Q180 59.9

1600 1600 1400 Affluent Volumes 1400 Affluent Volumes

Q180 Q140

) 1200 1200

)

3 3 1000 1000 800 800

600 600 Volume (hm Volume 400 (hm Volume 400 200 200 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 1600 1600 Affluent Volumes 1400 Affluent Volumes 1400

Qmod Q90

) 1200 1200

) 3 1000 3 1000 800 800

600 600 Volume (hm Volume 400 (hm Volume 400 200 200 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 29 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 8

136 Table A- 21 - Determination of the reservoir volume for different values of equipped discharge in section 9 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent Volumes 544.6 513.3 625.3 254.9 23.4 3.3 4.2 39.1 121.6 253.4 476.9 540.9 (hm3) Acomulated Affluent 544.6 1057.9 1683.2 1938.1 1961.5 1964.7 1968.9 2008.0 2129.7 2383.0 2859.9 3400.9 Volumes (hm3) Qmod 288.8 260.9 288.8 279.5 288.8 279.5 288.8 288.8 279.5 288.8 279.5 288.8 Volume Q90 412.2 372.3 412.2 398.9 412.2 398.9 412.2 412.2 398.9 412.2 398.9 412.2 Demand Q140 191.2 172.7 191.2 185.0 191.2 185.0 191.2 191.2 185.0 191.2 185.0 191.2 (hm3) Q180 68.7 62.1 68.7 66.5 68.7 66.5 68.7 68.7 66.5 68.7 66.5 68.7 Acomulated Qmod 288.8 549.7 838.6 1118.1 1406.9 1686.5 1975.3 2264.1 2543.7 2832.5 3112.0 3400.9 Volume Q90 412.2 784.6 1196.8 1595.7 2007.9 2406.8 2819.1 3231.3 3400.9 3400.9 3400.9 3400.9 Demand Q140 191.2 363.9 555.1 740.2 931.4 1116.4 1307.6 1498.8 1683.9 1875.1 2060.1 2251.3 3 (hm ) Q180 68.7 130.8 199.5 266.0 334.8 401.3 470.0 538.8 605.3 674.0 740.5 809.2 Qmod 255.8 252.4 336.4 -24.6 -265.5 -276.3 -284.7 -249.7 -157.9 -35.5 197.4 252.1 Difference Q90 132.4 141.0 213.1 -144.0 -388.8 -395.7 -408.0 -373.1 -277.3 -158.9 78.0 128.7 (hm3) Q140 353.4 340.6 434.1 69.8 -167.8 -181.8 -187.0 -152.1 -63.4 62.2 291.9 349.7 Q180 475.9 451.2 556.5 188.4 -45.4 -63.3 -64.5 -29.6 55.1 184.6 410.4 472.2 Qmod 255.8 508.2 844.6 820.0 554.5 278.3 -6.4 -256.1 -414.0 -449.5 -252.1 0.0 Difference - Q90 132.4 273.4 486.4 342.4 -46.5 -442.1 -850.2 -1223.3 -1271.2 -1017.8 -540.9 0.0 accumulated Q140 353.4 694.0 1128.1 1197.9 1030.1 848.3 661.3 509.2 445.8 508.0 799.8 1149.5 values(hm3) Q180 475.9 927.1 1483.7 1672.0 1626.7 1563.4 1498.9 1469.3 1524.4 1709.0 2119.4 2591.6 Qmod 1294.1 Reservoir Q90 1757.6 Volume (hm3) Q140 752.1 Q180 202.8

4000 4000 3500 Affluent Volumes 3500 Affluent Volumes

Q180 Q140

) 3000 3000

)

3 3 2500 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 4000 4000 Affluent Volumes 3500 Affluent Volumes 3500

Qmod Q90

) 3000 3000

) 3 2500 3 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 30 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 9

137 Table A- 22 - Determination of the reservoir volume for different values of equipped discharge in section 10 Month 1 2 3 4 5 6 7 8 9 10 11 12 Mean Affluent 567.6 539.4 653.7 274.3 26.0 3.5 4.5 42.7 131.7 271.8 510.8 572.4 Volumes (hm3) Acomulated Affluent 567.6 1107.0 1760.7 2035.0 2061.1 2064.6 2069.0 2111.8 2243.5 2515.2 3026.0 3598.4 Volumes (hm3) Qmod 305.6 276.0 305.6 295.8 305.6 295.8 305.6 305.6 295.8 305.6 295.8 305.6 Volume Q90 439.8 397.3 439.8 425.7 439.8 425.7 439.8 439.8 425.7 439.8 425.7 439.8 Demand Q140 205.2 185.3 205.2 198.6 205.2 198.6 205.2 205.2 198.6 205.2 198.6 205.2 (hm3) Q180 77.9 70.3 77.9 75.4 77.9 75.4 77.9 77.9 75.4 77.9 75.4 77.9 Acomulated Qmod 305.6 581.7 887.3 1183.0 1488.7 1784.4 2090.0 2395.6 2691.4 2997.0 3292.8 3598.4 Volume Q90 439.8 837.1 1277.0 1702.6 2142.5 2568.1 3008.0 3447.8 3598.4 3598.4 3598.4 3598.4 Demand Q140 205.2 390.5 595.7 794.3 999.5 1198.1 1403.3 1608.5 1807.1 2012.3 2210.9 2416.1 3 (hm ) Q180 77.9 148.2 226.1 301.5 379.3 454.7 532.6 610.5 685.8 763.7 839.1 917.0 Qmod 262.0 263.4 348.1 -21.5 -279.6 -292.2 -301.2 -262.9 -164.1 -33.9 215.0 266.8 Difference Q90 127.8 142.1 213.9 -151.4 -413.8 -422.1 -435.4 -397.1 -294.0 -168.1 85.1 132.5 (hm3) Q140 362.4 354.1 448.5 75.7 -179.2 -195.0 -200.8 -162.5 -66.9 66.6 312.2 367.2 Q180 489.7 469.1 575.8 198.9 -51.8 -71.8 -73.4 -35.1 56.3 193.9 435.4 494.5 Qmod 262.0 525.4 873.4 852.0 572.4 280.2 -21.0 -283.9 -447.9 -481.8 -266.8 0.0 Difference - Q90 127.8 269.9 483.8 332.4 -81.4 -503.5 -938.9 -1336.0 -1354.9 -1083.2 -572.4 0.0 accumulated Q140 362.4 716.5 1165.0 1240.7 1061.5 866.5 665.7 503.3 436.4 502.9 815.1 1182.3 values(hm3) Q180 489.7 958.8 1534.6 1733.6 1681.7 1609.9 1536.5 1501.3 1557.6 1751.5 2186.9 2681.4 Qmod 1355.2 Reservoir Q90 1838.7 Volume Q140 804.3 (hm3) Q180 232.2

4000 4000 3500 Affluent Volumes 3500 Affluent Volumes

Q180 Q140

) 3000 3000

)

3 3 2500 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months 4000 4000 Affluent Volumes 3500 Affluent Volumes 3500

Qmod Q90

) 3000 3000

) 3 2500 3 2500 2000 2000

1500 1500 Volume (hm Volume 1000 (hm Volume 1000 500 500 0 0 0 2 4 6 8 10 12 0 2 4 6 8 10 12 Months Months Figure A- 31 - Mean affluent volume curves versus the accumulated turbinated volume curves in section 10

138

Table A- 23 - Depth volume curve and depth area curve for the reservoirs in sections 1 to 10

Section 1 Section 2 Section 3 Section 4 Section 5 Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Depth (m) Volume Area Volume Area Volume Area Volume Area Volume Area (hm3) (km2) (hm3) (km2) (hm3) (km2) (hm3) (km2) (hm3) (km2) 0 0 0 0 0 0 0 0 0 0 0 10 40.5 6.4 147.6 19.6 60.2 9.7 161.7 19.9 28.1 7.0 20 189.8 17.1 403.2 30.1 230.3 21.6 502.7 42.5 224.1 26.7 30 485.9 33.2 1493.5 101.7 544.1 39.1 1098.7 70.9 629.3 50.3 40 928.3 48.9 2826.8 158.1 1183.1 78.1 2192.9 122.5 1379.8 90.6 50 1614.9 72.7 4835.1 234.4 2155.8 111.1 3682.2 170.0 2603.4 140.5 60 2706.5 119.0 7645.1 316.6 4194.3 208.1 5876.3 244.8 4328.9 194.6 70 4232.4 171.4 11354.1 410.4 6698.3 285.0 8823.6 329.0 6655.7 260.3 80 6302.1 230.3 15961.5 496.9 10102.3 382.0 12686.6 425.6 9907.5 356.6 Section 6 Section 7 Section 8 Section 9 Section 10 Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Reservoir Depth (m) Volume Area Volume Area Volume Area Volume Area Volume Area (hm3) (km2) (hm3) (km2) (hm3) (km2) (hm3) (km2) (hm3) (km2) 0 0 0 0 0 0 0 0 0 0 0 10 46.7 5.0 220.5 25.8 49.6 5.2 254.2 28.0 33.4 4.0 20 312.5 22.3 612.1 46.5 312.8 31.6 681.0 53.6 167.0 20.0 30 951.1 58.5 1179.9 63.2 775.6 54.3 1436.0 92.3 467.5 36.6 40 1769.0 89.5 2246.1 117.9 1430.1 72.7 2673.9 147.9 983.7 62.9 50 2863.0 119.5 3665.0 163.5 2600.2 128.4 4520.5 212.4 1925.6 113.1 60 4266.2 153.5 5616.4 220.8 4133.9 176.3 7084.4 289.0 3301.7 156.3 70 6069.0 191.1 8318.1 299.6 6233.9 238.2 10412.6 364.2 5905.6 269.0 80 8268.2 237.0 11975.8 400.4 9160.3 326.0 14490.2 442.7 9071.1 355.6

139

)

(Bernardo and (Bernardo and 2013) Moniz

Focus in the regions of Lunda Norte and Lunda Sul (adapted from an ENE’s document ENE’s Norte Lunda an regions andSul (adapted of from Lunda document inthe Focus

tric grid.

Angolan elec Angolan

FigureA

140

(Water Power Magazine, 2009) Magazine, (Water Power

Cost of E&M equipment in powerhouses Francis with powerhouses per unit in turbine equipment E&M of Cost

FigureA

141 Table A- 24 – Mean monthly discharge values in the station of Dala

Year Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Average 1965/66 9.4 11.9 18.1 19.8 26.5 32.6 20.8 11.9 10.5 10.1 9.5 9.4 15.9 1966/67 10.4 13 13.9 13.9 21.4 28.6 25.9 17.8 11.3 9.9 8.8 8 15.2 1967/68 11.5 23.4 25.5 19.8 37.1 32.5 25.2 13.8 12 11.6 10.5 9.4 19.4 1968/69 8.9 14.3 19.9 23.5 35.6 41.5 36.6 13.4 11.3 10.8 10.1 9.4 19.6 1969/70 15.3 17.1 26.2 24.6 36.7 34.5 16.8 13.7 12.6 12.3 11.9 11.1 19.4 1970/71 13.3 19.2 24.4 19.9 18.8 21.3 19.7 11.9 10.8 10.3 9.4 8.2 15.6 1971/72 9.2 10.9 15.8 26.3 16.3 29.6 19.5 11.9 9.8 9.2 8.7 9.3 14.7 1972/73 10.5 15.4 21.2 24.8 17.7 37.4 22.2 10.7 9.6 9.2 8.5 7.5 16.2 1973/74 7.7 12 19 19.7 19.7 23.9 29.4 12.2 7.9 8.3 8.2 8.7 14.7

Table A- 25 – Flow duration curve in the station of Dala

Days Q/Qmod Q (m3/s) 1 5.8 96.9 5 3.0 49.4 10 2.5 41.7 15 2.2 37.4 30 1.9 31.4 60 1.5 24.9 90 1.2 20.8 120 1.1 17.9 150 0.9 15.2 180 0.8 13.3 210 0.7 11.7 240 0.7 10.9 270 0.6 10.3 300 0.6 9.6 330 0.5 9.0 365 0.4 6.3

Table A- 26 - Flow duration curve in section 1

Days Q (m3/s) 1 425.7 5 217.3 10 183.2 15 164.1 30 138.2 60 109.5 90 91.2 120 78.5 150 66.7 180 58.4 210 51.2 240 47.9 270 45.3 300 42.3 330 39.4 365 27.9

142

Table A- 27 - Number of hours of radiation for each month at various latitudes

Latitude Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. 60 6.5 8.8 11.5 14.3 16.9 18.3 17.6 15.2 12.4 9.6 7.1 5.6 55 7.6 9.4 11.6 13.9 15.9 17.0 16.5 14.6 12.4 10.1 8.0 7.0 50 8.4 9.8 11.6 13.6 15.2 16.1 15.6 14.2 12.3 10.4 8.7 7.9 45 9.0 10.2 11.7 13.3 14.7 15.4 15.0 13.8 12.3 10.6 9.3 8.6 40 9.5 10.5 11.7 13.1 14.2 14.8 14.5 13.5 12.2 10.9 9.7 9.2 35 9.9 10.7 11.8 12.9 13.8 14.3 14.1 13.3 12.2 11.1 10.1 9.7 30 10.3 11.0 11.8 12.7 13.5 13.9 13.7 13.0 12.1 11.2 10.5 10.1 25 10.6 11.2 11.9 12.6 13.2 13.5 13.4 12.8 12.1 11.4 10.8 10.5 20 10.9 11.3 11.9 12.5 13.0 13.2 13.1 12.7 12.1 11.5 11.0 10.8 15 11.2 11.5 11.9 12.3 12.7 12.9 12.8 12.5 12.1 11.6 11.3 11.1 10 11.5 11.7 11.9 12.2 12.5 12.6 12.5 12.3 12.0 11.8 11.5 11.4 5 11.7 11.8 12.0 12.1 12.2 12.3 12.3 12.2 12.0 11.9 11.8 11.7 0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 -5 12.3 12.2 12.0 11.9 11.8 11.7 11.7 11.8 12.0 12.1 12.2 12.3 -10 12.5 12.3 12.1 11.8 11.5 11.4 11.5 11.7 12.0 12.2 12.5 12.6 -15 12.8 12.5 12.1 11.7 11.3 11.1 11.2 11.5 11.9 12.4 12.7 12.9 -20 13.1 12.7 12.1 11.5 11.0 10.8 10.9 11.3 11.9 12.5 13.0 13.2 -25 13.4 12.8 12.1 11.4 10.8 10.5 10.6 11.2 11.9 12.6 13.2 13.5 -30 13.7 13.0 12.2 11.3 10.5 10.1 10.3 11.0 11.9 12.8 13.5 13.9 -35 14.1 13.3 12.2 11.1 10.2 9.7 9.9 10.7 11.8 12.9 13.9 14.3 -40 14.5 13.5 12.3 10.9 9.8 9.2 9.5 10.5 11.8 13.1 14.3 14.8 -45 15.0 13.8 12.3 10.7 9.3 8.6 9.0 10.2 11.7 13.4 14.7 15.4 -50 15.6 14.2 12.4 10.4 8.8 7.9 8.4 9.8 11.7 13.6 15.3 16.1 -55 16.4 14.6 12.4 10.1 8.1 7.0 7.5 9.4 11.6 13.9 16.0 17.0 -60 17.5 15.2 12.5 9.7 7.1 5.7 6.4 8.8 11.6 14.4 16.9 18.4

143 Table A- 28 - Reservoir analysis with the scenario C1

Dam's Height (m) 38 Equiped Discharge (m3/s) 66 η 0.9

Height Volume Area Reservoir Levels (m) (hm3) (km2) NPA 35 675.4 39.2 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 37 767.8 42.5 Volume Reservoir Volumes (hm3) Maximum Volume 767.8 Live Storage 571.1 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 176.8 159.7 176.8 171.1 176.8 171.1 176.8 176.8 171.1 176.8 171.1 176.8 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 176.8 224.2 332.3 484.1 563.8 521.7 460.6 389.1 310.7 233.2 168.4 157.6 195.6 Total Storage (hm3) 281.0 328.5 436.5 588.4 668.0 625.9 564.8 493.3 415.0 337.5 272.7 261.9 299.9 Initial Water Level (m) 20.22 22.33 26.78 32.24 34.77 33.46 31.45 28.93 25.94 22.72 19.84 19.34 21.07 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 176.8 159.7 176.8 171.1 176.8 171.1 176.8 176.8 171.1 176.8 171.1 176.8 176.8 Real Turbinated Volume (hm3) 176.8 159.7 176.8 171.1 176.8 171.1 176.8 176.8 171.1 176.8 171.1 176.8 176.8 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 439.2 591.5 671.6 629.3 567.6 496.0 417.3 339.3 273.9 263.1 301.6 349.4 (hm3) Reservoir Level 1 (m) 22.4 26.9 32.3 34.9 33.6 31.5 29.0 26.0 22.8 19.9 19.4 21.2 23.2 Reservoir Area 1(km2) 21.9 27.6 35.1 39.0 36.9 33.9 30.5 26.5 22.3 18.6 17.9 20.2 22.9 Evaporation (hm3) 2.1 2.7 3.1 3.6 3.4 2.8 2.7 2.3 1.8 1.2 1.2 1.8 2.2 Total Final Reservoir Volume 328.5 436.5 588.4 668.0 625.9 564.8 493.3 415.0 337.5 272.7 261.9 299.9 347.2 (hm3) Final Water Level (m) 22.33 26.78 32.24 34.77 33.46 31.45 28.93 25.94 22.72 19.84 19.34 21.07 23.14 Reservoir Area (km2) 21.7 27.5 34.9 38.8 36.8 33.8 30.3 26.4 22.2 18.5 17.8 20.1 22.8 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 176.8 159.7 176.8 171.1 176.8 171.1 176.8 176.8 171.1 176.8 171.1 176.8 - Net Head (m) 34.1 36.2 40.7 46.1 48.6 47.3 45.3 42.8 39.8 36.6 33.7 33.2 - Power Generation (MW) 19.8 21.1 23.7 26.8 28.3 27.6 26.4 24.9 23.2 21.3 19.6 19.3 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 14.8 14.2 17.6 19.3 21.1 19.8 19.6 18.5 16.7 15.9 14.1 14.4 -

144 Table A- 29 - Reservoir analysis with the scenario C2

Dam's Height (m) 39 Equiped Discharge (m3/s) 100 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2) NPA 36 720.5 40.8 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 38 817.3 44.4 Volume Reservoir Volumes (hm3) (hm3) Maximum Volume 817.3 Live Storage 616.2 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 267.8 241.9 267.8 259.2 267.8 259.2 267.8 267.8 259.2 267.8 259.2 267.8 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 267.8 224.2 250.4 312.0 304.7 173.2 283.9 389.1 486.8 579.0 422.3 322.7 269.2 Total Storage (hm3) 372.1 328.5 354.7 416.2 408.9 277.4 388.1 493.4 591.1 683.2 526.5 426.9 373.5 Initial Water Level (m) 24.19 22.33 23.46 25.99 25.70 20.06 24.85 28.93 32.33 35.22 30.13 26.41 24.25 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 267.8 241.9 267.8 259.2 267.8 259.2 267.8 267.8 259.2 267.8 259.2 267.8 267.8 Turbinated Volume (hm3) 267.8 241.9 267.8 259.2 267.8 0.0 0.0 0.0 0.0 267.8 259.2 267.8 267.8 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 357.0 418.6 411.4 279.2 390.2 496.1 594.1 686.4 528.6 428.8 375.6 332.0 (hm3) Reservoir Level 1 (m) 22.4 23.6 26.1 25.8 20.1 24.9 29.0 32.4 35.3 30.2 26.5 24.3 22.5 Reservoir Area 1(km2) 21.9 23.3 26.6 26.2 18.9 25.1 30.5 35.2 39.7 32.0 27.1 24.3 21.9 Evaporation (hm3) 2.1 2.3 2.4 2.4 1.7 2.1 2.7 3.0 3.2 2.1 1.9 2.1 2.1 Total Final Reservoir Volume 328.5 354.7 416.2 408.9 277.4 388.1 493.4 591.1 683.2 526.5 426.9 373.5 329.9 (hm3) Final Water Level (m) 22.33 23.46 25.99 25.70 20.06 24.85 28.93 32.33 35.22 30.13 26.41 24.25 22.40 Reservoir Area (km2) 21.7 23.2 26.4 26.1 18.8 25.0 30.3 35.1 39.5 31.9 27.0 24.2 21.8 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 267.8 241.9 267.8 259.2 267.8 0.0 0.0 0.0 0.0 267.8 259.2 267.8 - Net Head (m) 38.1 36.2 37.3 39.9 39.6 33.9 38.7 42.8 46.2 49.1 44.0 40.3 - Power Generation (MW) 33.6 31.9 32.9 35.2 34.9 29.9 34.2 37.8 40.8 43.3 38.8 35.5 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 0.0 0.0 0.0 0.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 25.0 21.5 24.5 25.3 26.0 0.0 0.0 0.0 0.0 32.2 27.9 26.4 -

145 Table A- 30 - Reservoir analysis with the scenario C3.1

Dam's Height (m) 35 Equiped Discharge (m3/s) 79 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2) NPA 32 552.1 34.6 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 34 632.3 37.6 Volume Reservoir Volumes (hm3) (hm3) Maximum Volume 632.3 Live Storage 447.8 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 211.6 191.1 211.6 204.8 211.6 204.8 211.6 211.6 204.8 211.6 204.8 211.6 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 211.6 224.2 301.0 418.3 444.8 368.5 274.5 379.8 266.9 359.8 259.9 215.2 218.2 Total Storage (hm3) 315.9 328.5 405.2 522.5 549.0 472.8 378.8 484.1 371.1 464.1 364.2 319.4 322.5 Initial Water Level (m) 21.78 22.33 25.55 29.98 30.91 28.17 24.47 28.59 24.15 27.84 23.86 21.94 22.07 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 211.6 191.1 211.6 204.8 211.6 204.8 211.6 211.6 204.8 211.6 204.8 211.6 211.6 Turbinated Volume (hm3) 211.6 191.1 211.6 204.8 211.6 204.8 0.0 211.6 0.0 211.6 204.8 211.6 211.6 Spillage Volume (hm3) 0.0 0.0 0.0 20.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 407.8 525.4 552.1 475.5 380.8 486.7 373.2 466.4 365.7 320.9 324.4 337.2 (hm3) Reservoir Level 1 (m) 22.4 25.6 30.1 31.0 28.3 24.6 28.7 24.2 27.9 23.9 22.0 22.2 22.7 Reservoir Area 1(km2) 21.9 26.0 31.9 33.2 29.4 24.6 30.0 24.2 29.0 23.8 21.3 21.5 22.2 Evaporation (hm3) 2.1 2.6 2.9 3.1 2.7 2.0 2.6 2.1 2.3 1.5 1.5 1.9 2.2 Total Final Reservoir Volume 328.5 405.2 522.5 549.0 472.8 378.8 484.1 371.1 464.1 364.2 319.4 322.5 335.1 (hm3) Final Water Level (m) 22.33 25.55 29.98 30.91 28.17 24.47 28.59 24.15 27.84 23.86 21.94 22.07 22.62 Reservoir Area (km2) 21.7 25.9 31.7 33.0 29.3 24.5 29.9 24.1 28.9 23.7 21.2 21.4 22.1 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 211.6 191.1 211.6 204.8 211.6 204.8 0.0 211.6 0.0 211.6 204.8 211.6 - Net Head (m) 35.7 36.2 39.4 43.9 44.8 42.0 38.3 42.5 38.0 41.7 37.7 35.8 - Power Generation (MW) 24.8 25.2 27.5 30.6 31.2 29.3 26.7 29.6 26.5 29.1 26.3 25.0 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 30.0 0.0 31.0 0.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 18.5 17.0 20.4 22.0 23.2 21.1 0.0 22.0 0.0 21.6 18.9 18.6 -

146 Table A- 31 - Reservoir analysis with the scenario C3.2

Dam's Height (m) 36 Equiped Discharge (m3/s) 80 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2) NPA 33 591.3 36.1 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 35 675.4 39.2 Volume Reservoir Volumes (hm3) (hm3) Maximum Volume 675.4 Live Storage 487.0 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 214.3 193.5 214.3 207.4 214.3 207.4 214.3 214.3 207.4 214.3 207.4 214.3 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 214.3 224.2 298.6 413.2 457.1 378.1 484.1 375.2 472.9 358.6 256.0 208.7 209.1 Total Storage (hm3) 318.5 328.5 402.8 517.5 561.3 482.4 588.4 479.4 577.2 462.8 360.3 312.9 313.4 Initial Water Level (m) 21.90 22.33 25.45 29.80 31.33 28.53 32.24 28.42 31.87 27.79 23.70 21.65 21.67 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 214.3 193.5 214.3 207.4 214.3 207.4 214.3 214.3 207.4 214.3 207.4 214.3 214.3 Turbinated Volume (hm3) 214.3 193.5 214.3 207.4 214.3 0.0 214.3 0.0 207.4 214.3 207.4 214.3 214.3 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 3.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 405.4 520.3 564.4 485.1 591.3 482.1 580.2 465.2 361.8 314.4 315.2 325.4 (hm3) Reservoir Level 1 (m) 22.4 25.6 29.9 31.4 28.6 32.3 28.5 32.0 27.9 23.8 21.7 21.8 22.2 Reservoir Area 1(km2) 21.9 25.9 31.6 33.8 29.9 35.1 29.8 34.5 28.9 23.6 20.9 21.0 21.6 Evaporation (hm3) 2.1 2.5 2.8 3.1 2.7 2.9 2.6 3.0 2.3 1.5 1.4 1.8 2.1 Total Final Reservoir Volume 328.5 402.8 517.5 561.3 482.4 588.4 479.4 577.2 462.8 360.3 312.9 313.4 323.3 (hm3) Final Water Level (m) 22.33 25.45 29.80 31.33 28.53 32.24 28.42 31.87 27.79 23.70 21.65 21.67 22.11 Reservoir Area (km2) 21.7 25.8 31.5 33.6 29.8 34.9 29.6 34.4 28.8 23.5 20.8 20.9 21.4 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 214.3 193.5 214.3 207.4 214.3 0.0 214.3 0.0 207.4 214.3 207.4 214.3 - Net Head (m) 35.8 36.2 39.3 43.7 45.2 42.4 46.1 42.3 45.7 41.7 37.6 35.5 - Power Generation (MW) 25.2 25.5 27.7 30.8 31.9 29.9 32.5 29.8 32.3 29.4 26.5 25.1 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 0.0 31.0 0.0 30.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 18.8 17.2 20.6 22.2 23.7 0.0 24.2 0.0 23.2 21.9 19.1 18.7 -

147 Table A- 32 - Reservoir analysis with the scenario C3.3

Dam's Height (m) 35 Equiped Discharge (m3/s) 80 η 0.9

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 214.3 193.5 214.3 207.4 214.3 207.4 214.3 214.3 207.4 214.3 207.4 214.3 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 214.3 224.2 298.6 413.2 444.8 365.9 269.3 161.3 260.0 353.0 250.5 203.2 203.6 Total Storage (hm3) 318.5 328.5 402.8 517.5 549.0 470.1 373.5 265.6 364.3 457.3 354.7 307.4 307.9 Initial Water Level (m) 21.90 22.33 25.45 29.80 30.91 28.07 24.25 19.51 23.86 27.58 23.46 21.41 21.43 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 214.3 193.5 214.3 207.4 214.3 207.4 214.3 214.3 207.4 214.3 207.4 214.3 214.3 Turbinated Volume (hm3) 214.3 193.5 214.3 207.4 214.3 207.4 214.3 0.0 0.0 214.3 207.4 214.3 214.3 Spillage Volume (hm3) 0.0 0.0 0.0 12.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 405.4 520.3 552.1 472.8 375.5 267.2 366.3 459.6 356.2 308.8 309.7 319.9 (hm3) Reservoir Level 1 (m) 22.4 25.6 29.9 31.0 28.2 24.3 19.6 24.0 27.7 23.5 21.5 21.5 22.0 Reservoir Area 1(km2) 21.9 25.9 31.6 33.2 29.3 24.3 18.1 23.8 28.6 23.3 20.6 20.7 21.2 Evaporation (hm3) 2.1 2.5 2.8 3.1 2.7 2.0 1.6 2.1 2.3 1.5 1.4 1.8 2.1 Total Final Reservoir Volume 328.5 402.8 517.5 549.0 470.1 373.5 265.6 364.3 457.3 354.7 307.4 307.9 317.9 (hm3) Final Water Level (m) 22.33 25.45 29.80 30.91 28.07 24.25 19.51 23.86 27.58 23.46 21.41 21.43 21.87 Reservoir Area (km2) 21.7 25.8 31.5 33.0 29.2 24.2 18.0 23.7 28.5 23.2 20.5 20.6 21.1

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 214.3 193.5 214.3 207.4 214.3 207.4 214.3 0.0 0.0 214.3 207.4 214.3 - Net Head (m) 35.8 36.2 39.3 43.7 44.8 41.9 38.1 33.4 37.7 41.5 37.3 35.3 - Power Generation (MW) 25.2 25.5 27.7 30.8 31.6 29.6 26.9 23.6 26.6 29.3 26.3 24.9 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 30.0 31.0 0.0 0.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 18.8 17.2 20.6 22.2 23.5 21.3 20.0 0.0 0.0 21.8 19.0 18.5 -

148 Table A- 33 - Reservoir analysis with the scenario C4

Dam's Height (m) 37 Equiped Discharge (m3/s) 72 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2) NPA 34 632.3 37.6 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 36 720.5 40.8 Volume Reservoir Volumes (hm3) (hm3) Maximum Volume 720.5 Live Storage 528.1 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 192.8 174.2 192.8 186.6 192.8 186.6 192.8 192.8 186.6 192.8 186.6 192.8 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 192.8 224.2 317.8 453.7 518.0 460.2 383.8 296.6 394.7 301.3 220.3 193.8 215.6 Total Storage (hm3) 297.1 328.5 422.1 558.0 622.3 564.4 488.1 400.9 499.0 405.6 324.6 298.0 319.9 Initial Water Level (m) 20.95 22.33 26.22 31.22 33.34 31.44 28.74 25.37 29.14 25.56 22.16 20.99 21.96 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 192.8 174.2 192.8 186.6 192.8 186.6 192.8 192.8 186.6 192.8 186.6 192.8 192.8 Turbinated Volume (hm3) 192.8 174.2 192.8 186.6 192.8 186.6 192.8 0.0 186.6 192.8 186.6 192.8 192.8 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 424.7 561.0 625.7 567.5 490.5 403.2 501.6 407.7 326.0 299.4 321.7 353.3 (hm3) Reservoir Level 1 (m) 22.4 26.3 31.3 33.5 31.5 28.8 25.5 29.2 25.6 22.2 21.1 22.0 23.4 Reservoir Area 1(km2) 21.9 26.9 33.6 36.7 33.9 30.2 25.8 30.7 26.0 21.6 20.1 21.4 23.1 Evaporation (hm3) 2.1 2.6 3.0 3.4 3.1 2.5 2.3 2.7 2.1 1.4 1.4 1.9 2.2 Total Final Reservoir Volume 328.5 422.1 558.0 622.3 564.4 488.1 400.9 499.0 405.6 324.6 298.0 319.9 351.1 (hm3) Final Water Level (m) 22.33 26.22 31.22 33.34 31.44 28.74 25.37 29.14 25.56 22.16 20.99 21.96 23.31 Reservoir Area (km2) 21.7 26.7 33.5 36.6 33.8 30.1 25.7 30.6 25.9 21.5 20.0 21.2 23.0 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 192.8 174.2 192.8 186.6 192.8 186.6 192.8 0.0 186.6 192.8 186.6 192.8 - Net Head (m) 34.8 36.2 40.1 45.1 47.2 45.3 42.6 39.2 43.0 39.4 36.0 34.9 - Power Generation (MW) 22.1 23.0 25.5 28.6 30.0 28.8 27.1 24.9 27.3 25.0 22.9 22.1 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 30.0 31.0 0.0 30.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 16.5 15.5 18.9 20.6 22.3 20.7 20.1 0.0 19.7 18.6 16.5 16.5 -

149 Table A- 34 - Reservoir analysis with the scenario C5

Dam's Height (m) 49 Equiped Discharge (m3/s) 210 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2) NPA 46 1307.5 62.7 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 48 1460.3 68.6 Volume Reservoir Volumes (hm3) (hm3) Maximum Volume 1460.3 Live Storage 1203.3 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 562.5 508.0 562.5 544.3 562.5 544.3 562.5 562.5 544.3 562.5 544.3 562.5 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 562.5 783.9 1048.2 812.9 519.5 93.8 -0.6 -0.6 98.9 192.6 304.1 463.2 675.9 Total Storage (hm3) 666.7 888.2 1152.5 917.2 623.8 198.1 103.7 103.6 203.1 296.8 408.4 567.5 780.1 Initial Water Level (m) 34.73 40.66 45.97 41.33 33.39 16.28 11.39 11.39 16.53 20.94 25.67 31.54 37.96 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 562.5 508.0 562.5 544.3 562.5 544.3 562.5 562.5 544.3 562.5 544.3 562.5 562.5 Turbinated Volume (hm3) 0.0 0.0 562.5 544.3 562.5 206.6 107.3 0.0 0.0 0.0 0.0 0.0 0.0 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 893.0 1158.6 921.8 627.2 199.4 104.3 104.3 204.4 298.5 410.1 569.8 784.0 1006.5 (hm3) Reservoir Level 1 (m) 40.8 46.1 41.4 33.5 16.3 11.4 11.4 16.6 21.0 25.7 31.6 38.1 43.3 Reservoir Area 1(km2) 49.9 62.9 51.3 36.8 13.8 7.4 7.4 14.2 20.0 26.1 34.0 44.5 55.5 Evaporation (hm3) 4.8 6.2 4.6 3.4 1.3 0.6 0.6 1.2 1.6 1.7 2.3 3.9 5.4 Total Final Reservoir Volume 888.2 1152.5 917.2 623.8 198.1 103.7 103.6 203.1 296.8 408.4 567.5 780.1 1001.1 (hm3) Final Water Level (m) 40.66 45.97 41.33 33.39 16.28 11.39 11.39 16.53 20.94 25.67 31.54 37.96 43.14 Reservoir Area (km2) 49.6 62.6 51.1 36.6 13.8 7.4 7.4 14.1 19.9 26.0 33.9 44.3 55.2 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 0.0 0.0 562.5 544.3 562.5 206.6 107.3 0.0 0.0 0.0 0.0 0.0 - Net Head (m) 48.6 54.5 59.8 55.2 47.3 30.2 25.3 25.3 30.4 34.8 39.5 45.4 - Power Generation (MW) 90.0 101.0 110.8 102.3 87.5 55.9 46.8 46.8 56.3 64.5 73.2 84.1 - Time during the turbines are 0.0 0.0 31.0 30.0 31.0 11.4 5.9 0.0 0.0 0.0 0.0 0.0 - working (days/turbine) Energy Generated (GWh) 0.0 0.0 82.5 73.6 65.1 15.3 6.6 0.0 0.0 0.0 0.0 0.0 -

150 Table A- 35 - Reservoir analysis with the scenario C6

Dam's Height (m) 38 Equiped Discharge (m3/s) 70 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2) NPA 35 675.4 39.2 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 37 767.8 42.5 Volume Reservoir Volumes (hm3) (hm3) Maximum Volume 767.8 Live Storage 571.1 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 187.5 169.3 187.5 181.4 187.5 181.4 187.5 187.5 181.4 187.5 181.4 187.5 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 187.5 224.2 322.6 463.9 533.3 480.7 409.4 327.4 300.9 273.3 197.8 176.5 203.7 Total Storage (hm3) 291.7 328.5 426.9 568.1 637.5 584.9 513.7 431.7 405.2 377.6 302.0 280.7 308.0 Initial Water Level (m) 20.71 22.33 26.41 31.56 33.83 32.13 29.67 26.60 25.55 24.42 21.17 20.21 21.43 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 187.5 169.3 187.5 181.4 187.5 181.4 187.5 187.5 181.4 187.5 181.4 187.5 187.5 Turbinated Volume (hm3) 187.5 169.3 187.5 181.4 187.5 181.4 187.5 125.0 121.0 187.5 181.4 187.5 187.5 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 429.6 571.2 641.0 588.1 516.2 434.1 407.4 379.6 303.3 282.0 309.8 346.8 (hm3) Reservoir Level 1 (m) 22.4 26.5 31.7 33.9 32.2 29.8 26.7 25.6 24.5 21.2 20.3 21.5 23.1 Reservoir Area 1(km2) 21.9 27.1 34.1 37.5 34.9 31.4 27.4 26.0 24.5 20.3 19.0 20.7 22.8 Evaporation (hm3) 2.1 2.7 3.1 3.5 3.2 2.6 2.4 2.2 2.0 1.3 1.3 1.8 2.2 Total Final Reservoir Volume 328.5 426.9 568.1 637.5 584.9 513.7 431.7 405.2 377.6 302.0 280.7 308.0 344.6 (hm3) Final Water Level (m) 22.33 26.41 31.56 33.83 32.13 29.67 26.60 25.55 24.42 21.17 20.21 21.43 23.03 Reservoir Area (km2) 21.7 27.0 34.0 37.3 34.8 31.3 27.2 25.9 24.4 20.2 19.0 20.6 22.6 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 187.5 169.3 187.5 181.4 187.5 181.4 187.5 125.0 121.0 187.5 181.4 187.5 - Net Head (m) 34.6 36.2 40.3 45.4 47.7 46.0 43.5 40.5 39.4 38.3 35.0 34.1 - Power Generation (MW) 21.4 22.4 24.9 28.1 29.5 28.4 26.9 25.0 24.3 23.6 21.6 21.0 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 30.0 31.0 20.7 20.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 15.9 15.0 18.5 20.2 21.9 20.4 20.0 12.4 11.7 17.6 15.6 15.7 -

151 Table A- 36 - Reservoir analysis with the scenario C7

Dam's Height (m) 38 Equiped Discharge (m3/s) 68 η 0.9

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 182.1 164.5 182.1 176.3 182.1 176.3 182.1 182.1 176.3 182.1 176.3 182.1 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 182.1 224.2 327.4 474.0 548.5 501.2 435.0 358.3 335.2 252.4 182.2 166.1 198.8 Total Storage (hm3) 286.4 328.5 431.7 578.2 652.8 605.4 539.3 462.5 439.4 356.6 286.5 270.4 303.0 Initial Water Level (m) 20.47 22.33 26.60 31.90 34.30 32.80 30.57 27.78 26.90 23.54 20.47 19.74 21.21 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 182.1 164.5 182.1 176.3 182.1 176.3 182.1 182.1 176.3 182.1 176.3 182.1 182.1 Turbinated Volume (hm3) 182.1 164.5 182.1 176.3 182.1 176.3 182.1 121.4 176.3 182.1 176.3 182.1 182.1 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 434.4 581.3 656.3 608.7 541.9 465.0 441.8 358.5 287.7 271.7 304.8 347.2 (hm3) Reservoir Level 1 (m) 22.4 26.7 32.0 34.4 32.9 30.7 27.9 27.0 23.6 20.5 19.8 21.3 23.1 Reservoir Area 1(km2) 21.9 27.4 34.6 38.2 35.9 32.7 28.9 27.8 23.4 19.4 18.4 20.4 22.8 Evaporation (hm3) 2.1 2.7 3.1 3.5 3.3 2.7 2.5 2.4 1.9 1.3 1.3 1.8 2.2 Total Final Reservoir Volume 328.5 431.7 578.2 652.8 605.4 539.3 462.5 439.4 356.6 286.5 270.4 303.0 345.0 (hm3) Final Water Level (m) 22.33 26.60 31.90 34.30 32.80 30.57 27.78 26.90 23.54 20.47 19.74 21.21 23.05 Reservoir Area (km2) 21.7 27.2 34.4 38.0 35.8 32.6 28.8 27.6 23.3 19.3 18.3 20.3 22.7 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 182.1 164.5 182.1 176.3 182.1 176.3 182.1 121.4 176.3 182.1 176.3 182.1 - Net Head (m) 34.3 36.2 40.5 45.8 48.2 46.7 44.4 41.7 40.8 37.4 34.3 33.6 - Power Generation (MW) 20.6 21.7 24.3 27.5 28.9 28.0 26.7 25.0 24.5 22.4 20.6 20.2 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 30.0 31.0 20.7 30.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 15.3 14.6 18.1 19.8 21.5 20.2 19.8 12.4 17.6 16.7 14.8 15.0 -

152 Table A- 37 - Reservoir analysis with the scenario C8

Dam's Height (m) 80 Equiped Discharge (m3/s) 61 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2)

NPA 77 5624.7 213.6 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 79 6070.7 224.8 Volume Reservoir Volumes (hm3) (hm3) Maximum Volume 6070.7 Live Storage 5520.5 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 163.4 147.6 163.4 158.1 163.4 158.1 163.4 163.4 158.1 163.4 158.1 163.4 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 4949.1 4989.6 5089.2 5236.0 5309.7 5262.4 5197.4 5121.1 5038.3 4957.0 4892.2 4880.0 4913.2 Total Storage (hm3) 5053.4 5093.8 5193.5 5340.2 5414.0 5366.6 5301.6 5225.4 5142.6 5061.2 4996.4 4984.3 5017.5 Initial Water Level (m) 79.67 80.06 80.94 82.08 82.55 82.25 81.80 81.21 80.50 79.75 79.11 78.99 79.32 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbines 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume (hm3) 163.4 147.6 163.4 158.1 163.4 158.1 163.4 163.4 158.1 163.4 158.1 163.4 163.4 Turbinated Volume (hm3) 163.4 147.6 163.4 158.1 163.4 158.1 163.4 163.4 158.1 163.4 158.1 163.4 163.4 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 5116.3 5216.7 5361.9 5436.4 5388.7 5321.3 5246.2 5162.7 5079.8 5011.1 4999.8 5037.5 5080.4 (hm3) Reservoir Level 1 (m) 80.3 81.1 82.2 82.7 82.4 81.9 81.4 80.7 79.9 79.3 79.1 79.5 79.9 Reservoir Area 1(km2) 231.6 236.1 241.5 243.7 242.3 240.1 237.3 233.8 229.8 226.2 225.6 227.6 229.8 Evaporation (hm3) 22.5 23.2 21.6 22.4 22.0 19.6 20.8 20.2 18.5 14.6 15.5 20.0 22.3 Total Final Reservoir Volume 5093.8 5193.5 5340.2 5414.0 5366.6 5301.6 5225.4 5142.6 5061.2 4996.4 4984.3 5017.5 5058.1 (hm3) Final Water Level (m) 80.06 80.94 82.08 82.55 82.25 81.80 81.21 80.50 79.75 79.11 78.99 79.32 79.72 Reservoir Area (km2) 230.5 235.1 240.8 243.0 241.6 239.4 236.5 232.8 228.9 225.4 224.8 226.6 228.7 ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 163.4 147.6 163.4 158.1 163.4 158.1 163.4 163.4 158.1 163.4 158.1 163.4 - Net Head (m) 93.5 93.9 94.8 95.9 96.4 96.1 95.7 95.1 94.4 93.6 93.0 92.9 - Power Generation (MW) 50.3 50.5 51.0 51.6 51.9 51.7 51.5 51.2 50.8 50.4 50.0 50.0 - Time during the turbines are 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - working (days/turbine) Energy Generated (GWh) 37.4 34.0 38.0 37.2 38.6 37.2 38.3 38.1 36.6 37.5 36.0 37.2 -

153 Table A- 38 - Reservoir analysis with the scenario C9

Dam's Height (m) 38 Equiped Discharge (m3/s) 34 η 0.9

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 91.1 82.3 91.1 88.1 91.1 88.1 91.1 91.1 88.1 91.1 88.1 91.1 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 182.1 239.3 342.5 488.9 563.4 531.1 464.8 387.9 304.3 221.6 151.6 135.6 168.4 Total Storage (hm3) 286.4 343.5 446.7 593.2 667.7 635.4 569.1 492.2 408.5 325.9 255.8 239.9 272.7 Initial Water Level (m) 20.47 22.99 27.18 32.40 34.75 33.76 31.60 28.89 25.68 22.22 19.06 18.31 19.84 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbine 1 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 1 75.9 82.3 91.1 88.1 91.1 88.1 91.1 91.1 88.1 91.1 88.1 91.1 91.1 (hm3) Turbinated Volume 1 (hm3) 75.9 82.3 91.1 88.1 91.1 88.1 91.1 91.1 88.1 91.1 88.1 91.1 91.1 # Turbine 2 1.0 1.0 1.0 1.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 2 91.1 82.3 91.1 88.1 75.9 88.1 91.1 91.1 88.1 91.1 88.1 91.1 91.1 (hm3) Turbinated Volume 2 (hm3) 91.1 82.3 91.1 88.1 75.9 88.1 91.1 91.1 88.1 91.1 88.1 91.1 91.1 Total Turbinated Volume (hm3) 167.0 164.5 182.1 176.3 167.0 176.3 182.1 182.1 176.3 182.1 176.3 182.1 182.1 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 345.8 449.5 596.4 671.3 638.8 571.9 494.9 410.8 327.6 257.0 241.0 274.3 316.9 (hm3) Reservoir Level 1 (m) 23.1 27.3 32.5 34.9 33.9 31.7 29.0 25.8 22.3 19.1 18.4 19.9 21.8 Reservoir Area 1(km2) 22.7 28.1 35.3 38.9 37.4 34.1 30.4 26.2 21.7 17.5 16.5 18.6 21.1 Evaporation (hm3) 2.2 2.8 3.2 3.6 3.4 2.8 2.7 2.3 1.7 1.1 1.1 1.6 2.0 Total Final Reservoir Volume 343.5 446.7 593.2 667.7 635.4 569.1 492.2 408.5 325.9 255.8 239.9 272.7 314.8 (hm3) Final Water Level (m) 22.99 27.18 32.40 34.75 33.76 31.60 28.89 25.68 22.22 19.06 18.31 19.84 21.74 Reservoir Area (km2) 22.6 28.0 35.2 38.8 37.2 34.0 30.3 26.1 21.6 17.4 16.5 18.5 21.0

154 Table A- 39 - Reservoir analysis with the scenario C9 (Continuation - Totals)

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 167.0 164.5 182.1 176.3 167.0 176.3 182.1 182.1 176.3 182.1 176.3 182.1 - Net Head (m) 34.3 36.9 41.1 46.3 48.6 47.6 45.5 42.8 39.6 36.1 32.9 32.2 - Power Generation 1 (MW) 10.3 11.1 12.3 13.9 14.6 14.3 13.6 12.8 11.9 10.8 9.9 9.7 - Power Generation 2 (MW) 10.3 11.1 12.3 13.9 14.6 14.3 13.6 12.8 11.9 10.8 9.9 9.7 - Power Generation (MW) 20.6 22.1 24.6 27.8 29.2 28.6 27.3 25.6 23.7 21.6 19.8 19.3 - Time Turbine 1 25.8 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Time Turbine 2 31.0 28.0 31.0 30.0 25.8 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Energy Generated 1 (GWh) 6.4 7.4 9.2 10.0 10.8 10.3 10.1 9.5 8.5 8.1 7.1 7.2 - Energy Generated 2 (GWh) 7.7 7.4 9.2 10.0 9.0 10.3 10.1 9.5 8.5 8.1 7.1 7.2 - Energy Generated (GWh) 14.0 14.9 18.3 20.0 19.9 20.6 20.3 19.1 17.1 16.1 14.2 14.4 -

155 Table A- 40 - Reservoir analysis with the scenario C10

Dam's Height (m) 38 Equiped Discharge (m3/s) 22.5 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2)

NPA 35 675.4 39.2 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 37 767.8 42.5

Volume Reservoir Volumes (hm3) (hm3)

Maximum Volume 767.8 Live Storage 571.1 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 60.3 54.4 60.3 58.3 60.3 58.3 60.3 60.3 58.3 60.3 58.3 60.3 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 180.8 234.2 347.6 495.4 567.5 531.4 466.4 390.9 308.5 227.1 158.4 143.7 177.8 Total Storage (hm3) 285.1 338.4 451.9 599.7 671.8 635.7 570.7 495.1 412.8 331.4 262.7 248.0 282.1 Initial Water Level (m) 20.41 22.77 27.38 32.61 34.88 33.77 31.65 29.00 25.85 22.46 19.38 18.69 20.27 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbine 1 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 1 50.2 54.4 60.3 58.3 60.3 58.3 60.3 60.3 58.3 60.3 58.3 60.3 60.3 (hm3) Turbinated Volume 1 (hm3) 50.2 54.4 60.3 58.3 60.3 58.3 60.3 60.3 58.3 60.3 58.3 60.3 60.3 # Turbine 2 1.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 2 60.3 45.4 60.3 58.3 60.3 58.3 60.3 60.3 58.3 60.3 58.3 60.3 60.3 (hm3) Turbinated Volume 2 (hm3) 60.3 45.4 60.3 58.3 60.3 58.3 60.3 60.3 58.3 60.3 58.3 60.3 60.3 # Turbine 3 1.0 1.0 1.0 1.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 3 60.3 54.4 60.3 58.3 50.2 58.3 60.3 60.3 58.3 60.3 58.3 60.3 60.3 (hm3) Turbinated Volume 3 (hm3) 60.3 54.4 60.3 58.3 50.2 58.3 60.3 60.3 58.3 60.3 58.3 60.3 60.3 Total Turbinated Volume (hm3) 170.7 154.2 180.8 175.0 170.7 175.0 180.8 180.8 175.0 180.8 175.0 180.8 180.8 Spillage Volume (hm3) 0.0 0.0 0.0 3.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 340.6 454.7 602.8 675.4 639.1 573.5 497.8 415.1 333.2 263.8 249.2 283.7 327.6 (hm3) Reservoir Level 1 (m) 22.9 27.5 32.7 35.0 33.9 31.7 29.1 25.9 22.5 19.4 18.7 20.3 22.3 Reservoir Area 1(km2) 22.4 28.4 35.6 39.1 37.4 34.2 30.5 26.4 22.0 17.9 17.0 19.1 21.7 Evaporation (hm3) 2.2 2.8 3.2 3.6 3.4 2.8 2.7 2.3 1.8 1.2 1.2 1.7 2.1 Total Final Reservoir Volume 338.4 451.9 599.7 671.8 635.7 570.7 495.1 412.8 331.4 262.7 248.0 282.1 325.5 (hm3) Final Water Level (m) 22.77 27.38 32.61 34.88 33.77 31.65 29.00 25.85 22.46 19.38 18.69 20.27 22.21 Reservoir Area (km2) 22.3 28.3 35.5 39.0 37.2 34.1 30.4 26.3 21.9 17.9 17.0 19.0 21.6

156 Table A- 41 - Reservoir analysis with the scenario C10 (Continuation - Totals)

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 171 154 181 175 171 175 181 181 175 181 175 181 - Net Head (m) 34 37 41 46 49 48 46 43 40 36 33 33 - Power Generation 1 (MW) 7 7 8 9 10 9 9 9 8 7 7 6 - Power Generation 2 (MW) 7 7 8 9 10 9 9 9 8 7 7 6 - Power Generation 3 (MW) 7 7 8 9 10 9 9 9 8 7 7 6 - Power Generation (MW) 20 15 16 18 19 19 18 17 16 14 13 13 - Time Turbine 1 26 28 31 30 31 30 31 31 30 31 30 31 - Time Turbine 2 31 23 31 30 31 30 31 31 30 31 30 31 - Time Turbine 3 31 28 31 30 26 30 31 31 30 31 30 31 - Energy Generated 1 (GWh) 4 5 6 7 7 7 7 6 6 5 5 5 - Energy Generated 2 (GWh) 5 4 6 7 7 7 7 6 6 5 5 5 - Energy Generated 3 (GWh) 5 5 6 7 6 7 7 6 6 5 5 5 - Energy Generated (GWh) 14 14 18 20 20 20 20 19 17 16 14 14 -

157 Table A- 42 - Reservoir analysis with the scenario C11.1

Dam's Height (m) 36 Equiped Discharge (m3/s) 40 η 0.9

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 107.1 96.8 107.1 103.7 107.1 103.7 107.1 107.1 103.7 107.1 103.7 107.1 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 214.3 224.2 298.6 413.2 457.1 463.5 449.1 425.6 395.1 363.7 261.1 213.7 214.1 Total Storage (hm3) 318.5 328.5 402.8 517.5 561.3 567.7 553.3 529.9 499.4 467.9 365.3 318.0 318.4 Initial Water Level (m) 21.90 22.33 25.45 29.80 31.33 31.55 31.06 30.24 29.15 27.99 23.91 21.88 21.90 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbine 1 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 1 107.1 96.8 107.1 103.7 107.1 103.7 107.1 107.1 103.7 107.1 103.7 107.1 107.1 (hm3)

Turbinated Volume 1 (hm3) 107.1 96.8 107.1 103.7 107.1 103.7 107.1 107.1 103.7 107.1 103.7 107.1 107.1

# Turbine 2 1.0 1.0 1.0 1.0 0.0 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 Q/Qmáx 1.00 1.00 1.00 1.00 0.20 0.20 0.20 0.20 0.20 1.00 1.00 1.00 1.00 η 0.90 0.90 0.90 0.90 0.45 0.45 0.45 0.45 0.45 0.90 0.90 0.90 0.90 Q 40.0 40.0 40.0 40.0 8.0 8.0 8.0 8.0 8.0 40.0 40.0 40.0 40.0 Ideal Turbinated Volume 2 107.1 96.8 107.1 103.7 21.4 20.7 21.4 21.4 20.7 107.1 103.7 107.1 107.1 (hm3) Turbinated Volume 2 (hm3) 107.1 96.8 107.1 103.7 21.4 20.7 21.4 21.4 20.7 107.1 103.7 107.1 107.1 Total Turbinated Volume (hm3) 214.3 193.5 214.3 207.4 128.6 124.4 128.6 128.6 124.4 214.3 207.4 214.3 214.3 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 405.4 520.3 564.4 570.8 556.0 532.7 502.0 470.3 366.9 319.4 320.3 330.4 (hm3) Reservoir Level 1 (m) 22.4 25.6 29.9 31.4 31.7 31.2 30.3 29.2 28.1 24.0 21.9 22.0 22.4 Reservoir Area 1(km2) 21.9 25.9 31.6 33.8 34.1 33.4 32.2 30.7 29.2 23.8 21.2 21.3 21.8 Evaporation (hm3) 2.1 2.5 2.8 3.1 3.1 2.7 2.8 2.7 2.4 1.5 1.5 1.9 2.1 Total Final Reservoir Volume 328.5 402.8 517.5 561.3 567.7 553.3 529.9 499.4 467.9 365.3 318.0 318.4 328.3 (hm3) Final Water Level (m) 22.33 25.45 29.80 31.33 31.55 31.06 30.24 29.15 27.99 23.91 21.88 21.90 22.33 Reservoir Area (km2) 21.7 25.8 31.5 33.6 33.9 33.2 32.1 30.6 29.1 23.8 21.1 21.2 21.7

158 Table A- 43 - Reservoir analysis with the scenario C11.1 (Continuation - Totals)

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 214.3 193.5 214.3 207.4 128.6 124.4 128.6 128.6 124.4 214.3 207.4 214.3 - Net Head (m) 35.8 36.2 39.3 43.7 45.2 45.4 44.9 44.1 43.0 41.9 37.8 35.8 - Power Generation 1 (MW) 12.6 12.8 13.9 15.4 15.9 16.0 15.9 15.6 15.2 14.8 13.3 12.6 - Power Generation 2 (MW) 12.6 12.8 13.9 15.4 8.0 8.0 7.9 7.8 7.6 14.8 13.3 12.6 - Power Generation (MW) 25.2 25.5 27.7 30.8 23.9 24.0 23.8 23.3 22.8 29.5 26.7 25.2 - Time Turbine 1 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Time Turbine 2 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Energy Generated 1 (GWh) 9.4 8.6 10.3 11.1 11.9 11.5 11.8 11.6 10.9 11.0 9.6 9.4 - Energy Generated 2 (GWh) 9.4 8.6 10.3 11.1 5.9 5.8 5.9 5.8 5.5 11.0 9.6 9.4 - Energy Generated (GWh) 18.8 17.2 20.6 22.2 17.8 17.3 17.7 17.4 16.4 22.0 19.2 18.8 -

159 Table A- 44 - Reservoir analysis with the scenario C11.2

Dam's Height (m) 41 Equiped Discharge (m3/s) 55 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2)

NPA 38 817.3 44.4 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 40 923.5 48.3

Volume Reservoir Volumes (hm3) (hm3)

Maximum Volume 923.5 Live Storage 713.0 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 147.3 133.1 147.3 142.6 147.3 142.6 147.3 147.3 142.6 147.3 142.6 147.3 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 294.6 341.4 448.9 600.3 679.4 636.8 575.3 503.3 424.4 346.4 281.2 270.0 307.4 Total Storage (hm3) 398.9 445.7 553.2 704.5 783.7 741.1 679.5 607.5 528.7 450.7 385.5 374.2 411.7 Initial Water Level (m) 25.29 27.14 31.06 35.85 38.05 36.89 35.11 32.87 30.20 27.33 24.74 24.28 25.81 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbine 1 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 1 147.3 133.1 147.3 142.6 147.3 142.6 147.3 147.3 142.6 147.3 142.6 147.3 147.3 (hm3) Turbinated Volume 1 (hm3) 147.3 133.1 147.3 142.6 147.3 142.6 147.3 147.3 142.6 147.3 142.6 147.3 147.3 # Turbine 2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Q/Qmáx 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 η 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 Q 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 Ideal Turbinated Volume 2 29.5 26.6 29.5 28.5 29.5 28.5 29.5 29.5 28.5 29.5 28.5 29.5 29.5 (hm3) Turbinated Volume 2 (hm3) 29.5 26.6 29.5 28.5 29.5 28.5 29.5 29.5 28.5 29.5 28.5 29.5 29.5 Total Turbinated Volume (hm3) 176.8 159.7 176.8 171.1 176.8 171.1 176.8 176.8 171.1 176.8 171.1 176.8 176.8 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 448.4 556.5 708.2 787.8 745.0 682.8 610.7 531.5 453.0 387.1 375.9 414.0 461.2 (hm3) Reservoir Level 1 (m) 27.2 31.2 36.0 38.2 37.0 35.2 33.0 30.3 27.4 24.8 24.3 25.9 27.7 Reservoir Area 1(km2) 28.1 33.4 40.7 44.7 42.5 39.5 36.0 32.2 28.3 24.9 24.3 26.3 28.7 Evaporation (hm3) 2.7 3.3 3.7 4.1 3.9 3.2 3.2 2.8 2.3 1.6 1.7 2.3 2.8 Total Final Reservoir Volume 445.7 553.2 704.5 783.7 741.1 679.5 607.5 528.7 450.7 385.5 374.2 411.7 458.5 (hm3) Final Water Level (m) 27.14 31.06 35.85 38.05 36.89 35.11 32.87 30.20 27.33 24.74 24.28 25.81 27.63 Reservoir Area (km2) 27.9 33.2 40.6 44.4 42.4 39.3 35.9 32.0 28.2 24.8 24.2 26.2 28.6

160 Table A- 45 - Reservoir analysis with the scenario C11.2 (Continuation - Totals)

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 176.8 159.7 176.8 171.1 176.8 171.1 176.8 176.8 171.1 176.8 171.1 176.8 - Net Head (m) 39.2 41.0 44.9 49.7 51.9 50.8 49.0 46.7 44.1 41.2 38.6 38.2 - Power Generation 1 (MW) 19.0 19.9 21.8 24.1 25.2 24.6 23.8 22.7 21.4 20.0 18.7 18.5 - Power Generation 2 (MW) 1.9 2.0 2.2 2.4 2.5 2.5 2.4 2.3 2.1 2.0 1.9 1.9 - Power Generation (MW) 20.9 21.9 24.0 26.5 27.7 27.1 26.1 24.9 23.5 22.0 20.6 20.4 - Time Turbine 1 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Time Turbine 2 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Energy Generated 1 (GWh) 14.1 13.4 16.2 17.4 18.7 17.7 17.7 16.9 15.4 14.9 13.5 13.8 - Energy Generated 2 (GWh) 1.4 1.3 1.6 1.7 1.9 1.8 1.8 1.7 1.5 1.5 1.3 1.4 - Energy Generated (GWh) 15.5 14.7 17.8 19.1 20.6 19.5 19.4 18.6 16.9 16.4 14.8 15.1 -

161 Table A- 46 - Reservoir analysis with the scenario C12.1

Dam's Height (m) 36 Equiped Discharge (m3/s) 38 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2)

NPA 33 591.3 36.1 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 35 675.4 39.2

Volume Reservoir Volumes (hm3) (hm3)

Maximum Volume 675.4 Live Storage 487.0 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 101.8 91.9 101.8 98.5 101.8 98.5 101.8 101.8 98.5 101.8 98.5 101.8 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 203.6 224.2 308.2 433.5 483.8 476.2 448.3 411.0 366.7 321.9 230.2 193.3 204.4 Total Storage (hm3) 307.8 328.5 412.4 537.7 588.0 580.4 552.6 515.2 471.0 426.2 334.4 297.5 308.7 Initial Water Level (m) 21.43 22.33 25.84 30.52 32.23 31.98 31.03 29.72 28.10 26.38 22.59 20.97 21.47 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbine 1 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 1 101.8 91.9 101.8 98.5 101.8 98.5 101.8 101.8 98.5 101.8 98.5 101.8 101.8 (hm3) Turbinated Volume 1 (hm3) 101.8 91.9 101.8 98.5 101.8 98.5 101.8 101.8 98.5 101.8 98.5 101.8 101.8 # Turbine 2 1.0 1.0 1.0 1.0 0.0 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 Q/Qmáx 1.00 1.00 1.00 1.00 0.40 0.40 0.40 0.40 0.40 1.00 1.00 1.00 1.00 η 0.90 0.90 0.90 0.90 0.75 0.75 0.75 0.75 0.75 0.90 0.90 0.90 0.90 Q 38.0 38.0 38.0 38.0 15.2 15.2 15.2 15.2 15.2 38.0 38.0 38.0 38.0 Ideal Turbinated Volume 2 101.8 91.9 101.8 98.5 40.7 39.4 40.7 40.7 39.4 101.8 98.5 101.8 101.8 (hm3) Turbinated Volume 2 (hm3) 101.8 91.9 101.8 98.5 40.7 39.4 40.7 40.7 39.4 101.8 98.5 101.8 101.8 Total Turbinated Volume (hm3) 203.6 183.9 203.6 197.0 142.5 137.9 142.5 142.5 137.9 203.6 197.0 203.6 203.6 Spillage Volume (hm3) 0.0 0.0 0.0 3.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 415.0 540.7 591.3 583.6 555.3 518.0 473.5 428.4 335.9 298.9 310.5 331.5 (hm3) Reservoir Level 1 (m) 22.4 25.9 30.6 32.3 32.1 31.1 29.8 28.2 26.5 22.7 21.0 21.5 22.5 Reservoir Area 1(km2) 21.9 26.4 32.6 35.1 34.7 33.3 31.5 29.3 27.1 22.1 20.0 20.7 21.9 Evaporation (hm3) 2.1 2.6 2.9 3.2 3.2 2.7 2.8 2.5 2.2 1.4 1.4 1.8 2.1 Total Final Reservoir Volume 328.5 412.4 537.7 588.0 580.4 552.6 515.2 471.0 426.2 334.4 297.5 308.7 329.3 (hm3) Final Water Level (m) 22.33 25.84 30.52 32.23 31.98 31.03 29.72 28.10 26.38 22.59 20.97 21.47 22.37 Reservoir Area (km2) 21.7 26.3 32.5 34.9 34.6 33.2 31.4 29.2 27.0 22.1 20.0 20.6 21.8

162 Table A- 47 - Reservoir analysis with the scenario C12.1 (Continuation - Totals)

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 203.6 183.9 203.6 197.0 142.5 137.9 142.5 142.5 137.9 203.6 197.0 203.6 - Net Head (m) 35.3 36.2 39.7 44.4 46.1 45.9 44.9 43.6 42.0 40.3 36.5 34.8 - Power Generation 1 (MW) 11.8 12.1 13.3 14.9 15.5 15.4 15.1 14.6 14.1 13.5 12.2 11.7 - Power Generation 2 (MW) 11.8 12.1 13.3 14.9 12.9 12.8 12.5 12.2 11.7 13.5 12.2 11.7 - Power Generation (MW) 23.7 24.3 26.6 29.8 28.3 28.2 27.6 26.8 25.8 27.0 24.4 23.4 - Time Turbine 1 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Time Turbine 2 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Energy Generated 1 (GWh) 8.8 8.2 9.9 10.7 11.5 11.1 11.2 10.9 10.1 10.0 8.8 8.7 - Energy Generated 2 (GWh) 8.8 8.2 9.9 10.7 9.6 9.2 9.3 9.1 8.4 10.0 8.8 8.7 - Energy Generated (GWh) 17.6 16.3 19.8 21.4 21.1 20.3 20.5 19.9 18.6 20.1 17.6 17.4 -

163 Table A- 48 - Reservoir analysis with the scenario C12.2

Dam's Height (m) 40

Equiped Discharge (m3/s) 47

η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2)

NPA 37 767.8 42.5 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 39 869.2 46.3

Volume Reservoir Volumes (hm3) (hm3)

Maximum Volume 869.2 Live Storage 663.5 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 125.9 113.7 125.9 121.8 125.9 121.8 125.9 125.9 121.8 125.9 121.8 125.9 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 251.8 299.3 407.5 559.6 639.4 597.5 536.6 465.3 387.2 309.9 245.3 234.7 272.9 Total Storage (hm3) 356.0 403.6 511.8 663.8 743.7 701.8 640.9 569.6 491.5 414.1 349.6 339.0 377.1 Initial Water Level (m) 23.52 25.48 29.60 34.64 36.96 35.77 33.93 31.61 28.86 25.90 23.24 22.79 24.40 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbine 1 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 1 125.9 113.7 125.9 121.8 125.9 121.8 125.9 125.9 121.8 125.9 121.8 125.9 125.9 (hm3) Turbinated Volume 1 (hm3) 125.9 113.7 125.9 121.8 125.9 121.8 125.9 125.9 121.8 125.9 121.8 125.9 125.9 # Turbine 2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Q/Qmáx 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 η 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75 Q 18.8 18.8 18.8 18.8 18.8 18.8 18.8 18.8 18.8 18.8 18.8 18.8 18.8 Ideal Turbinated Volume 2 50.4 45.5 50.4 48.7 50.4 48.7 50.4 50.4 48.7 50.4 48.7 50.4 50.4 (hm3) Turbinated Volume 2 (hm3) 50.4 45.5 50.4 48.7 50.4 48.7 50.4 50.4 48.7 50.4 48.7 50.4 50.4 Total Turbinated Volume (hm3) 176.2 159.2 176.2 170.6 176.2 170.6 176.2 176.2 170.6 176.2 170.6 176.2 176.2 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 406.1 514.9 667.3 747.6 705.5 644.0 572.6 494.1 416.2 351.1 340.5 379.3 427.2 (hm3) Reservoir Level 1 (m) 25.6 29.7 34.7 37.1 35.9 34.0 31.7 29.0 26.0 23.3 22.9 24.5 26.4 Reservoir Area 1(km2) 25.9 31.4 38.8 42.7 40.6 37.6 34.2 30.4 26.4 23.0 22.4 24.5 27.0 Evaporation (hm3) 2.5 3.1 3.5 3.9 3.7 3.1 3.0 2.6 2.1 1.5 1.5 2.2 2.6 Total Final Reservoir Volume 403.6 511.8 663.8 743.7 701.8 640.9 569.6 491.5 414.1 349.6 339.0 377.1 424.6 (hm3) Final Water Level (m) 25.48 29.60 34.64 36.96 35.77 33.93 31.61 28.86 25.90 23.24 22.79 24.40 26.32 Reservoir Area (km2) 25.8 31.2 38.6 42.5 40.4 37.5 34.0 30.2 26.3 22.9 22.3 24.4 26.9

164 Table A- 49 - Reservoir analysis with the scenario C12.2 (Continuation - Totals)

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 176.2 159.2 176.2 170.6 176.2 170.6 176.2 176.2 170.6 176.2 170.6 176.2 - Net Head (m) 37.4 39.4 43.5 48.5 50.8 49.6 47.8 45.5 42.7 39.8 37.1 36.7 - Power Generation 1 (MW) 15.5 16.3 18.0 20.1 21.1 20.6 19.8 18.9 17.7 16.5 15.4 15.2 - Power Generation 2 (MW) 5.2 5.4 6.0 6.7 7.0 6.9 6.6 6.3 5.9 5.5 5.1 5.1 - Power Generation (MW) 20.7 21.8 24.0 26.8 28.1 27.4 26.4 25.1 23.6 22.0 20.5 20.3 - Time Turbine 1 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Time Turbine 2 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Energy Generated 1 (GWh) 11.5 11.0 13.4 14.5 15.7 14.8 14.7 14.0 12.8 12.3 11.1 11.3 - Energy Generated 2 (GWh) 3.8 3.7 4.5 4.8 5.2 4.9 4.9 4.7 4.3 4.1 3.7 3.8 - Energy Generated (GWh) 15.4 14.6 17.9 19.3 20.9 19.8 19.7 18.7 17.0 16.4 14.8 15.1 -

165 Table A- 50 - Reservoir analysis with the scenario C13.1

Dam's Height (m) 37 Equiped Discharge (m3/s) 36 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2)

NPA 34 632.3 37.6 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 36 720.5 40.8

Volume Reservoir Volumes (hm3) (hm3)

Maximum Volume 720.5 Live Storage 528.1 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 96.4 87.1 96.4 93.3 96.4 93.3 96.4 96.4 93.3 96.4 93.3 96.4 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 192.8 224.2 317.8 453.7 518.0 498.6 459.2 410.1 354.1 298.1 217.0 190.5 212.4 Total Storage (hm3) 297.1 328.5 422.1 558.0 622.3 602.8 563.5 514.4 458.4 402.3 321.3 294.8 316.6 Initial Water Level (m) 20.95 22.33 26.22 31.22 33.34 32.72 31.41 29.69 27.62 25.43 22.02 20.85 21.82 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbine 1 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 1 96.4 87.1 96.4 93.3 96.4 93.3 96.4 96.4 93.3 96.4 93.3 96.4 96.4 (hm3) Turbinated Volume 1 (hm3) 96.4 87.1 96.4 93.3 96.4 93.3 96.4 96.4 93.3 96.4 93.3 96.4 96.4 # Turbine 2 1.0 1.0 1.0 1.0 0.0 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 Q/Qmáx 1.00 1.00 1.00 1.00 0.60 0.60 0.60 0.60 0.60 1.00 1.00 1.00 1.00 η 0.90 0.90 0.90 0.90 0.85 0.85 0.85 0.85 0.85 0.90 0.90 0.90 0.90 Q 36.0 36.0 36.0 36.0 21.6 21.6 21.6 21.6 21.6 36.0 36.0 36.0 36.0 Ideal Turbinated Volume 2 96.4 87.1 96.4 93.3 57.9 56.0 57.9 57.9 56.0 96.4 93.3 96.4 96.4 (hm3) Turbinated Volume 2 (hm3) 96.4 87.1 96.4 93.3 57.9 56.0 57.9 57.9 56.0 96.4 93.3 96.4 96.4 Total Turbinated Volume (hm3) 192.8 174.2 192.8 186.6 154.3 149.3 154.3 154.3 149.3 192.8 186.6 192.8 192.8 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 330.6 424.7 561.0 625.7 606.1 566.3 517.1 460.8 404.4 322.7 296.1 318.5 350.1 (hm3) Reservoir Level 1 (m) 22.4 26.3 31.3 33.5 32.8 31.5 29.8 27.7 25.5 22.1 20.9 21.9 23.3 Reservoir Area 1(km2) 21.9 26.9 33.6 36.7 35.8 33.9 31.5 28.7 25.8 21.4 19.9 21.2 22.9 Evaporation (hm3) 2.1 2.6 3.0 3.4 3.3 2.8 2.8 2.5 2.1 1.4 1.4 1.9 2.2 Total Final Reservoir Volume 328.5 422.1 558.0 622.3 602.8 563.5 514.4 458.4 402.3 321.3 294.8 316.6 347.9 (hm3) Final Water Level (m) 22.33 26.22 31.22 33.34 32.72 31.41 29.69 27.62 25.43 22.02 20.85 21.82 23.17 Reservoir Area (km2) 21.7 26.7 33.5 36.6 35.6 33.7 31.4 28.6 25.7 21.3 19.8 21.1 22.8

166 Table A- 51 - Reservoir analysis with the scenario C13.1 (Continuation - Totals)

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 192.8 174.2 192.8 186.6 154.3 149.3 154.3 154.3 149.3 192.8 186.6 192.8 - Net Head (m) 34.8 36.2 40.1 45.1 47.2 46.6 45.3 43.6 41.5 39.3 35.9 34.7 - Power Generation 1 (MW) 11.1 11.5 12.7 14.3 15.0 14.8 14.4 13.8 13.2 12.5 11.4 11.0 - Power Generation 2 (MW) 11.1 11.5 12.7 14.3 14.2 14.0 13.6 13.1 12.4 12.5 11.4 11.0 - Power Generation (MW) 22.1 23.0 25.5 28.6 29.2 28.8 28.0 26.9 25.6 25.0 22.8 22.0 - Time Turbine 1 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Time Turbine 2 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Energy Generated 1 (GWh) 8.2 7.7 9.5 10.3 11.2 10.7 10.7 10.3 9.5 9.3 8.2 8.2 - Energy Generated 2 (GWh) 8.2 7.7 9.5 10.3 10.5 10.1 10.1 9.7 9.0 9.3 8.2 8.2 - Energy Generated (GWh) 16.5 15.5 18.9 20.6 21.7 20.7 20.8 20.0 18.4 18.6 16.4 16.4 -

167 Table A- 52 - Reservoir analysis with the scenario C13.2

Dam's Height (m) 39 Equiped Discharge (m3/s) 41 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2)

NPA 36 720.5 40.8 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 38 817.3 44.4

Volume Reservoir Volumes (hm3) (hm3)

Maximum Volume 817.3 Live Storage 616.2 Inactive Storage 69.0 Dead Storage 35.3

Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Ideal Turbinated Volumes per 109.8 99.2 109.8 106.3 109.8 106.3 109.8 109.8 106.3 109.8 106.3 109.8 - machine per month(hm3) ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + # Days 31 28 31 30 31 30 31 31 30 31 30 31 31 Initial live Storage (hm3) 219.6 267.9 376.7 529.4 609.9 568.7 508.4 437.8 360.3 283.6 219.7 209.7 248.5 Total Storage (hm3) 323.9 372.1 481.0 633.7 714.2 673.0 612.7 542.0 464.6 387.8 324.0 314.0 352.8 Initial Water Level (m) 22.14 24.19 28.47 33.70 36.13 34.91 33.04 30.67 27.86 24.84 22.14 21.70 23.38 Inflow (hm3) 251.5 300.5 368.6 282.6 153.4 125.3 119.9 111.9 105.9 125.8 179.4 240.6 251.5 Ecological Discharge (hm3) 25.1 30.0 36.9 28.3 15.3 12.5 12.0 11.2 10.6 12.6 17.9 24.1 25.1 # Turbine 1 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Ideal Turbinated Volume 1 109.8 99.2 109.8 106.3 109.8 106.3 109.8 109.8 106.3 109.8 106.3 109.8 109.8 (hm3) Turbinated Volume 1 (hm3) 109.8 99.2 109.8 106.3 109.8 106.3 109.8 109.8 106.3 109.8 106.3 109.8 109.8 # Turbine 2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Q/Qmáx 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.60 η 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.85 Q 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 24.6 Ideal Turbinated Volume 2 65.9 59.5 65.9 63.8 65.9 63.8 65.9 65.9 63.8 65.9 63.8 65.9 65.9 (hm3) Turbinated Volume 2 (hm3) 65.9 59.5 65.9 63.8 65.9 63.8 65.9 65.9 63.8 65.9 63.8 65.9 65.9 Total Turbinated Volume (hm3) 175.7 158.7 175.7 170.0 175.7 170.0 175.7 175.7 170.0 175.7 170.0 175.7 175.7 Spillage Volume (hm3) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total Final Reservoir Volume 1 374.5 483.9 637.0 718.0 676.5 615.7 544.9 467.1 389.9 325.4 315.4 354.8 403.4 (hm3) Reservoir Level 1 (m) 24.3 28.6 33.8 36.2 35.0 33.1 30.8 28.0 24.9 22.2 21.8 23.5 25.5 Reservoir Area 1(km2) 24.3 29.9 37.3 41.2 39.2 36.3 32.8 29.0 25.1 21.6 21.0 23.2 25.8 Evaporation (hm3) 2.4 2.9 3.3 3.8 3.6 3.0 2.9 2.5 2.0 1.4 1.4 2.0 2.5 Total Final Reservoir Volume 372.1 481.0 633.7 714.2 673.0 612.7 542.0 464.6 387.8 324.0 314.0 352.8 400.9 (hm3) Final Water Level (m) 24.19 28.47 33.70 36.13 34.91 33.04 30.67 27.86 24.84 22.14 21.70 23.38 25.37 Reservoir Area (km2) 24.1 29.7 37.1 41.0 39.0 36.1 32.7 28.9 25.0 21.5 20.9 23.1 25.7

168 Table A- 53 - Reservoir analysis with the scenario C13.2 (Continuation - Totals)

ID 1 2 3 4 5 6 7 8 9 10 11 12 13 Month Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Turbinated Volume (hm3) 175.7 158.7 175.7 170.0 175.7 170.0 175.7 175.7 170.0 175.7 170.0 175.7 - Net Head (m) 36.0 38.1 42.3 47.6 50.0 48.8 46.9 44.5 41.7 38.7 36.0 35.6 - Power Generation 1 (MW) 13.0 13.8 15.3 17.2 18.1 17.6 17.0 16.1 15.1 14.0 13.0 12.9 - Power Generation 2 (MW) 7.4 7.8 8.7 9.7 10.2 10.0 9.6 9.1 8.6 7.9 7.4 7.3 - Power Generation (MW) 20.4 21.6 24.0 27.0 28.3 27.6 26.6 25.2 23.6 21.9 20.4 20.2 - Time Turbine 1 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Time Turbine 2 31.0 28.0 31.0 30.0 31.0 30.0 31.0 31.0 30.0 31.0 30.0 31.0 - Energy Generated 1 (GWh) 9.7 9.3 11.4 12.4 13.5 12.7 12.6 12.0 10.9 10.4 9.4 9.6 - Energy Generated 2 (GWh) 5.5 5.2 6.5 7.0 7.6 7.2 7.2 6.8 6.2 5.9 5.3 5.4 - Energy Generated (GWh) 15.2 14.5 17.8 19.4 21.1 19.9 19.8 18.8 17.0 16.3 14.7 15.0 -

169

/GWh/year)

8.3

8.6

7.8

7.1

6.2

5.9

5.8

5.6

4.4

3.7

3.2

2.9

2.7

2.5

2.3

2.0

1.8

1.5

1.4

1.2

1.0

0.9

0.8

0.7

0.6

Cost per GWh/year Cost

(USD*10

/MW)

1.5

1.6

1.7

1.8

1.9

(USD*10

Cost per installed MW MW per installed Cost

)

31.31

31.09

30.58

30.05

29.51

29.26

28.95

28.37

27.77

27.15

26.51

26.02

25.85

25.18

24.49

23.78

23.05

22.30

21.83

21.53

20.75

19.95

19.12

18.83

18.28

17.43

16.59

15.65

14.97

14.74

Total Cost Cost Total

(USD*10

1506.3

1514.0

1530.6

1547.3

1563.9

1571.3

1580.6

1597.2

1613.9

1630.5

1647.2

1659.7

1663.8

1680.5

1697.1

1713.8

1730.4

1747.1

1757.4

1763.7

1780.4

1797.0

1813.7

1819.5

1830.3

1847.0

1862.8

1880.3

1892.7

1896.9

(USD/kW) Unitary Cost UnitaryCost

3.8

3.6

3.9

4.2

4.8

4.9

5.0

5.1

6.4

7.4

8.4

9.1

9.4

10.1

10.4

11.8

13.1

14.9

15.7

15.8

17.3

20.4

20.7

20.4

21.2

22.6

23.5

25.1

26.1

26.8

E(GWh)

9.4

8.9

8.3

7.9

7.8

20.8

20.5

20.0

19.4

18.9

18.6

18.3

17.8

17.2

16.6

16.1

15.7

15.5

15.0

14.4

13.9

13.3

12.8

12.4

12.2

11.7

11.1

10.5

10.3

10.0 P (MW) P

run of riverrun of facility type

121.9

117.3

127.6

136.6

154.5

160.3

162.1

165.0

206.3

239.1

272.7

296.1

305.1

326.2

338.4

382.9

424.0

482.9

510.5

512.8

562.3

661.2

670.3

660.5

686.3

733.8

762.0

815.4

847.0

868.6

Turbinated Turbinated volume (hm3) volume

Analysis a of

–

631521

662817

731087

799356

870471

924314

992306

1114141

1235976

1432194

1700644

1902631

1969094

2237544

2505994

2922359

3408452

3894546

4194930

4380640

4866733

5449106

6212410

6482082

6975713

7739017

8764855

9920026

Tmax(s)

10742566 11018654

TableA

101

115

124

128

Tmax

(days)

99.0

93.5

88.3

82.5

78.4

77.0

206.0

203.5

198.0

192.5

187.0

184.6

181.5

176.0

170.5

165.0

159.5

155.4

154.0

148.5

143.0

137.5

132.0

126.5

123.1

121.0

115.5

110.0

104.5

102.6

Qmax

Tmin (s) Tmin

11514276

11711066

12140344

12569621

13015422

13285720

13627048

14238673

14850299

15461924

16153379

16684016

16858621

17563862

18416449

19952309

21676210

23563348

24605034

25249047

26986785

28583563

29097146

29278594

29610730

30124314

30611465

31151481

31536000

31665065

133

136

141

145

151

154

158

165

172

179

187

193

195

203

213

231

251

273

285

292

312

331

337

339

343

349

354

361

365

366

Tmin Tmin

(days)

74.9

74.0

72.0

70.0

68.0

67.1

66.0

64.0

62.0

60.0

58.0

56.5

56.0

54.0

52.0

50.0

48.0

46.0

44.8

44.0

42.0

40.0

38.0

37.3

36.0

34.0

32.1

30.0

28.5

28.0

Qmin

120

150

180

210

240

270

300

330

365

nºdays

exceeded

95.0

93.2

90.0

85.0

80.3

75.0

71.3

70.0

68.2

59.7

52.4

49.0

46.3

43.2

40.3

28.5

Qdim

187.3

185.0

180.0

175.0

170.0

167.8

165.0

160.0

155.0

150.0

145.0

141.2

140.0

135.0

130.0

125.0

120.0

115.0

111.9

110.0

105.0 100.0

170

200.0 20.00

180.0 18.00

) 160.0 16.00 3 140.0 14.00 Spillage Volume (hm3) 120.0 12.00 Inflow (hm3) 100.0 10.00 Initial live Storage (hm3) 80.0 8.00 Final Water Level (m) 60.0 6.00 Water Volumes (hm VolumesWater Initial Water Level (m)

40.0 4.00 Reservoir (m) Reservoir Level Water 20.0 2.00 0.0 0.00 Jan. Feb. Mar. Apr. May June July Aug. Sep. Out. Nov. Dec. Jan. + Month

Figure A- 34 – Reservoir analysis for the worst possible situation with scenario C12.1

Table A- 55 - Reservoir analysis for the worst possible situations with the scenario C12.2 (Continuation - Totals)

171 Table A- 56 – Reservoir analysis for the worst possible situation with scenario C12.1

Dam's Height (m) 41 Equiped Discharge (m3/s) 55 η 0.9

Height Volume Area Reservoir Levels (m) (m) (hm3) (km2) NPA 38 817.3 44.4 Nme - Entrance sill of P.Intake 15 104.3 12.1 Entrance sill of Bottom Outlet 10 35.3 5.7 NMC 40 923.5 48.3 Volume Reservoir Volumes (hm3) (hm3) Maximum Volume 923.5 Live Storage 713.0 Inactive Storage 69.0 Dead Storage 35.3

Reservoir Area (km2) 27.9 33.2 40.6 44.4 42.4 39.3 35.9 32.0 28.2 24.8 24.2 26.2 28.6

172 Table A- 57 - χ2 verification test

ParameterValueInterval M 5- Pj 0.2- Ej 3.2- O1 30.04 O2 40.64 O3 30.04 O4 30.04 O5 30.04 Σ 16 0.8 χ2 calculated 0.25 χ2 tables 5.991

90 80 70 60 50 40

Prcipitation (mm) Prcipitation 30 20 10 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70

Duration D Figure A- 35 - Precipitation hyetograph for a return period of T=1000 years and a duration t=tc

100 90 80 70 60 50 40 Prcipitation (mm) Prcipitation 30 20 10 0 4 8 12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72 76 80 84 88 92 96 100 104 108 112 116 120 124 128 132 136 140 Duration D Figure A- 36 - Precipitation hyetograph for a return period of T=1000 years and a duration t=2tc

173

50 40 30

20 Prcipitation (mm) Prcipitation 10

2 4 6 8

16 26 10 12 14 18 20 22 24 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 Duration D Figure A- 37 - Precipitation hyetograph for a return period of T=100 years and a duration t=tc

60 50 40 30 Prcipitation (mm) Prcipitation 20 10

4 8

12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72 76 80 84 88 92 96

100 104 108 112 116 120 124 128 132 136 140 Duration D Figure A- 38 - Precipitation hyetograph for a return period of T=100 years and a duration t=2tc

40 30 20

Prcipitation (mm) Prcipitation 10

2 4 6 8

16 26 10 12 14 18 20 22 24 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 Duration D Figure A- 39 - Precipitation hyetograph for a return period of T=50 years and a duration t=tc

174

60 50 40 30

Precipitation (mm) Precipitation 20 10

4 8

76 80 84 88 12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72 92 96

100 104 108 112 116 120 124 128 132 136 140 Duration D Figure A- 40 - Precipitation hyetograph for a return period of T=50 years and a duration t=2tc

40 30

20 Prcipitation (mm) Prcipitation 10

2 4 6 8

38 40 42 44 10 12 14 16 18 20 22 24 26 28 30 32 34 36 46 48 50 52 54 56 58 60 62 64 66 68 70

Duration D Figure A- 41 - Precipitation hyetograph for a return period of T=20 years and a duration t=tc

50 40 30

20 Prcipitation (mm) Prcipitation 10

4 8

76 80 84 88 12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72 92 96

100 104 108 112 116 120 124 128 132 136 140

Duration D Figure A- 42 - Precipitation hyetograph for a return period of T=20 years and a duration t=2tc

175

Table A- 58 - Typical values of the curve number in rural areas (Chow et al. 1988)

COVER HYDROLOGIC SOIL GROUP LAND USE TREATMENT OR PRACTICE HYDROLOGIC CONDITION A B C D Fallow Straight row - 77 86 91 94 Row crops Straight row Poor 72 81 88 91 Straight row Good 67 78 85 89 Contoured Poor 70 79 84 88 Contoured Good 65 75 82 86 Contoured and terraced Poor 66 74 80 82 Contoured and terraced Good 62 71 78 81 Small grain Straight row Poor 65 76 84 88 Good 63 75 83 87 Contoured Poor 63 74 82 85 Good 61 73 81 84 Contoured and terraced Poor 61 72 79 82 Good 59 70 78 81 Close-seeded Straight row Poor 66 77 85 89 Legumes Straight row Good 58 72 81 85 Contoured Poor 64 75 83 85 Rotation Contoured Good 55 69 78 83 Meadow Contoured and terraced Poor 63 73 80 83 Contoured and terraced Good 51 67 76 80 Pasture or range Poor 68 79 86 89 Fair 49 69 79 84 Good 39 61 74 80 Contoured Poor 47 67 81 88 Contoured Fair 25 59 75 83 Contoured Good 6 35 70 79 Meadow Good 30 58 71 78 Woods Poor 45 66 77 83 Fair 36 60 73 79 Good 25 55 70 77 Farmsteads - 59 74 82 86 Roads (dirty) - 72 82 87 89 Roads (hard surface) - 74 84 90 92

176

Figure A- 43 - Main runner dimensions versus specific rotation speed (Siervo and Leva 1976)

Figure A- 44 - Main spiral case dimensions versus the specific rotation speed (Siervo and Leva 1976)

177 Table A- 59- Preliminary bill of quantities

ID DESCRIPTION Units Quantities Unit Rates Amount (USD) Amount (KZ)

0.1 INVESTIGATION WORK

0.1.1 Engineering work (Estimated at about 10% of the ls 1.00 - 18 598 168 2 361 967 301 total value of the work) 0.1.2 Hydrometric station in the site location ls 1.00 - 50 000 6 350 000 0.1.3 Geological and geotechnical prospecting studies ls 1.00 - 300 000 38 100 000 0.1.4 Topography ls 1.00 - 100 000 12 700 000

SUB TOTAL AMOUNT OF 0.1 LS 19 048 168 2 419 117 301

0.2 CONSTRUCTION SITE

0.2.1 Instalation 0.2.1.1 Supply and installation of infrastructures (Estimated at about ls 1.00 - 3 719 634 472 393 460 2% of the total value of the work) 0.2.1.2 Maintenance (Estimated at about 1 % of the total value of the ls 1.00 - 1 859 817 236 196 730 work) 0.2.1.3 Disassembly and replacement of the initial conditions of the terrain (estimated at around 1% of the total value of the ls 1.00 - 1 859 817 236 196 730 work) 0.2.2 Site Access 0.2.2.1 Full service access roads, including excavations, m 16 000.00 300.00 4 800 000 609 600 000 embankment, paving and drainage

SUB TOTAL AMOUNT OF 0.2 LS 12 239 267 1 554 386 920

1 CONSTRUCTION WORK

1.1 PREPARATION

1.1.1 Clearing and grubbing 1.1.1.1 Cleaning, deforestation and excavations in any terrain km2 40.00 5 000.00 200 000 25 400 000

1.1.2 River diversion 1.1.2.1 2 embankment cofferdams m³ 23 400.00 30.00 702 000 89 154 000

SUB TOTAL AMOUNT OF 1.1 LS 902 000 114 554 000

1.2 WATER INTAKE AND BOTTOM OUTLET

1.2.1 Excavations 1.2.1.1 Common excavations m³ 5 100.00 3.00 15 300 1 943 100 1.2.1.2 Rock excavations m³ 8 500.00 10.00 85 000 10 795 000

1.2.2 Concrete 1.2.2.1 Supply and application of regulation and cleaning concrete C16/20, including formework and all the necessary works m³ 170.00 55.00 9 350 1 187 450 and equipments 1.2.2.2 Supply and application of structural reinforced concrete C25/30, A500, including formework and all the necessary m³ 49 000.00 380.00 18 620 000 2 364 740 000 works and equipments

178 ID DESCRIPTION Units Quantities Unit Rates Amount (USD) Amount (KZ)

1.2.3 Equipment's 1.2.3.1 Total of equipment's for the water intake and bottom outlet, including gates, metal grids, valves and elevation ls 1.00 - 936 483 118 933 278 mechanisms (considered as 5 % of the total cost of construction works for these structures)

SUB TOTAL AMOUNT OF 1.2 LS 19 666 133 2 497 598 828

1.3 PENSTOCK AND TUNNEL

1.3.1 Penstock 1.3.1.1 Stainless steel for the penstock ton 2 028 950.00 1 926 732 244 694 908

1.3.2 Tunnel 1.3.2.1 Supply and application of structural reinforced concrete C25/30, A500, including excavations, formework and all the m 463.00 1 321.04 611 641 77 678 456 necessary works and equipments

SUB TOTAL AMOUNT OF 1.3 LS 2 538 373 322 373 364

1.4 DAM CONSTRUCTION

1.4.1 Embankment 1.4.1.1 Embankment volume, including crushing and all the m³ 760 000.00 30.00 22 800 000 2 895 600 000 necessary works 1.4.1.2 Low permeability material, including compacting m³ 190 000.00 40.00 7 600 000 965 200 000 1.4.1.3 Common excavations m³ 222 300.00 3.00 666 900

1.4.2 Concrete (Spillway over the dam) 0 1.4.2.1 Supply and application of regulation and cleaning concrete C16/20, including formework and all the necessary works m³ 14 820.00 55.00 815 100 103 517 700 and equipments 1.4.2.2 Supply and application of structural reinforced concrete C20/25, A500, including formework and all the necessary m³ 260 000.00 200.00 52 000 000 6 604 000 000 works and equipments 1.4.2.3 Common excavations m³ 86 100.00 3.00 258 300 32 804 100 1.4.2.4 Rock excavations m³ 143 500.00 10.00 1 435 000 182 245 000 1.4.2.5 Miscellaneous (considered as 20% of the concrete dam ls 1.00 - 19 325 900 2 454 389 300 cost) 1.4.2.6 Support walls for the embankment part of the dam and wing m³ 29 090.00 380.00 11 054 200 1 403 883 400 walls for the spillway

SUB TOTAL AMOUNT OF 1.4 LS 115 955 400 14 726 335 800

1.5 POWERHOUSE

1.5.1 Ground movement 1.5.1.1 Common excavations m³ 1 236.00 3.00 3 708 470 916

179 ID DESCRIPTION Units Quantities Unit Rates Amount (USD) Amount (KZ)

1.5.2 Concrete 1.5.2.1 Supply and application of regulation and cleaning concrete C16/20, including formework and all the necessary works m³ 82.40 55.00 4 532 575 564 and equipments 1.5.2.2 Supply and application of structural reinforced concrete C25/30, A500, including formework and all the necessary m³ 264.80 380.00 100 624 12 779 248 works and equipments

1.5.3 Tail-race 1.5.3.1 Common excavations m2 1 800.00 10.00 18 000 2 286 000 1.5.3.2 Concrte for the tail-race tunnel, C20/25 m3 4 500.00 200.00 900 000 114 300 000

SUB TOTAL AMOUNT OF 1.5 LS 1 026 864 130 411 728

2 ELECTRO & HYDRO MECHANIC EQUIPMENT

2.1 GENERATION EQUIPMENT

2.1.1 Turbines and Generator 2.1.1.1 Two groups of Francis turbines with the power of 15.7 MW (net head of 46.9 m and equipped discharge of 38 m3/s) , including all the associated equipments. Generator with ls 1.00 - 9 000 000 1 143 000 000 vertical axis including all the associated accessories ad equipments.

SUB TOTAL AMOUNT OF 2.1 LS 9 000 000

2.2 EQUIPMENT FOR THE POWER HOUSE

2.2.1 General equipment 2.2.1.1 Elevation equipment and other mechanical equipment, cables and connections, ilumination, electric frames, transformers, ventilation and workshop equipment, including ls 1.00 - 900 000 114 300 000 accessories and installation (considered as 10% of the generation equipment cost).

2.2.2 Electric installations 2.2.2.1 Connection to the electric grid. Medium tension lines (60 kV) km 80.00 150 000.00 12 000 000 1 524 000 000 that connect the facility to the city of Saurimo

2.2.3 Hydraulic equipment 2.2.3.1 Conduits, valves, intake grids and other equipment ls 1.00 - 900 000 114 300 000 (considered as 10% of the generation equipment cost).

SUB TOTAL AMOUNT OF 2.2 LS 13 800 000 1 752 600 000

TOTAL COST 194 176 204 23 517 377 941

180

Work planning

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FigureA

181 100

0 0 5 10 15 20 25 30 35 40 45 50 -50

Flow (MUSD) Flow -100

-150 Discount Cumulative Cash Cumulative Discount -200

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Figure A- 46 – Discount cumulated cash flow curve for scenario A-1.1

0 0 10 20 30 40 50 -50

-100 Flow (MUSD) Flow -150

Discount Cumulative Cash Cash Cumulative Discount -200

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Figure A- 47 - Discount cumulated cash flow curve for scenario A-1.2

0 10 20 30 40 50 -50

-100

-150

Cash Flow Cash (MUSD) Discount Cumulative Cumulative Discount -200

Years

Figure A- 48 - Discount cumulated cash flow curve for scenario A-1.3

0 0 10 20 30 40 50

-50

-100

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Discount Cumulative Cash Cumulative Discount -200

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Figure A- 49 - Discount cumulated cash flow curve for scenario A-2.1

182 0 0 10 20 30 40 50 -50

-100

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Figure A- 50 - Discount cumulated cash flow curve for scenario A-2.2

0 0 10 20 30 40 50 -50 -100 -150 Cash FlowCash (MUSD) Discount Cumulative Cumulative Discount -200 Years

Figure A- 51 - Discount cumulated cash flow curve for scenario A-2.3

183 APPENDICES II – DRAWINGS

184 Location of the facility - Representation in Google Earth

View of the dam 1 - Downstream

View of the facility 1 - General Layout

View of the facility 2 - General Layout View of the dam 2 - Upstream

Project: Feasibility Study of a Hydropower Facility in Eastern Angola

Implementation of the facility in the site location

João Pedro Marques Santos Coelho 01 7 6 8 5 998.0 m 02 02 02 993.0 m 02

Upstream View of the Dam 1 1 : 1000 5 8 6 7 02 02 02 02 998.0 m 993.0 m

985.0 m 985.0 m

975.0 m 975.0 m

960.0 m 958.0 m

Downstream View of the Dam 2 1 : 1000

Steel Conduit Concrete Tunnel Steel Conduit

Massif of Reinforced Concrete Power House Long. Prof. of the Adduction System 3 1 : 1000

998.0 m

- ---

3 02 - 960.0 m --- 958.0 m 952.0 m

Profile 1-1 Plan of the power house 5 1 : 1000 09 1 : 1000

Turbine 1: Turbine 2: ddd 988.0 m Turbine Type:Francis with vertical axis Turbine Type: Francis with vertical axis Head: 46.9 m Head: 46.9 m Rated Discharge: Q=38 m3/s Rated Discharge: Q=38 m3/s 994.0 m Power Capacity: 15.7 MW Power Capacity: 15.7 MW 978.0 m 972.5 m 971.6 m

6 5 948.0 m 02 02

7 02 Profile 2-2 Profile 5-5 6 1 : 1000 10 1 : 200

998.0 m 998.0 m 948.0 m

985.0 m

975.0 m 8 Turbine 2: 02 Turbine Type: Francis with vertical axis Head: 46.9 m Rated Discharge: Q=38 m3/s Power Capacity: 15.7 MW 940.0 m

937.8 m

Profile 3-3 Profile of the Powerhouse 7 1 : 1000 11 1 : 200 998.0 m

967.0 m

959.0 m

Profile 4-4 8 1 : 1000

Project: Feasibility Study of a Hydropower Facility in Eastern Angola

General Layout of the Facility Pre study drawings João Pedro Marques Santos Coelho 4 1 : 5000 02