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ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAA
PURPOSE
The Worid Bank/UNDP/Bllateral Aid Energy Sector Management Assistance Program (ESKAP)was launched in 1983 to complement the Energy Assessiment Program which had been establIshedthree years eariier, The Assessment Program was Oesigned to Identify the most serlous energyproblems facIng some 70 developing countries and to proposf remedial action. ESMAP wasconcelved, In part, as a preinvestment facility to help implement recommendations made duringthe course of assessment, Today ESMAP is carrying out preinvestment and prefeasibilityactivities in about f0 countries and Is providing a wide range of institutional and policyadvice. The program plays a significant role in the overal International effort to providetechnical assistance to the energy sector of developing countries. 1t attempts to strengthenthe Impact of bliateral and multilaterai resources and private sector Investment, Thef indIngs and recommendations emerging from ESMAP country activities provide governments,donors, and potential investors with the Information needed to identify economicalIy andenvironmental Iy sound energy projects and to accelerate their preparation andImplementation. ESNAP#s policy and research work analyzing cross-country trends and Issues Inspecific energy subsectors make an Important contribution in highllghting critical problemsand suggesting solutions.
ESMAP's operationai activities are managed by three units within the Energy StrategyManagement and Assessment Division of the Industry and Energy Department at the World Bank,
- The Energy EffIclency and Strategy Unit engages in energy assessments addressingInstitutional, financial, and pollcy Issues, design of sector strategles, thestrengthening of energy sector enterprises and sector management, the defining ofInvestment programs, efficlency Improvements in energy suppIy, and energy use,training and research,
The Household and Renewable Energy Unit addresses technicaI, economic, f InancIal,Institutionai and pol Icy Issues in the areas of energy use by urban and ruralhousehoids and smali Industries, and Includes traditional and modern fuel supplies,prefeasibilIty studies, pilot activities, technology assessments, seminars andworkshops, and policy and research work,
- The Natural Gas Development Unit addresses gas Issues and promotes the developmentand use cf naturel gas In developing courtries through preinvestment work,formulating natural gas development and related environmental strategles, andresearch.
FUND I NG
The ESMAP Program is a major international effort supported by the World Bank, theUnited Nations Development Programme, and Bilaterai Aid from a number of countries lncludingAustralia, Belgium, Canada, Denmark, Finland, France, Iceland, lreland, Italy, Japon, theNetherlands, New Zealand, Norway, Portugal, Sweden, SwitzerIand, the Unlted Kingdom, and theUnIted States.
FURTHER INFORMATION
For further Information or copies of the completed ESMAP reports iIsted at the endof this document, contact:
Energy Strategy Management OR Division for Global and Interregionaland Assessment Division Programmes
industry and Energy Departmetnt United Nations Development ProgrammeThe World Bank One United Nations Plaza1818 H Street N.W. New York, NY 10017Washington, D.C. USA 2043.> USA
CONGO
POWER DEVELOPMENT STUDY
MAY 1990
Energy Efficiency and Strategy UnitIndustry and Energy DepartmentWorld BankWashington, D.C. 20433
FOREORD
This reports summarizes the results and conclusions of thepover planning study carried out within the World Bank/UNDP/Bilateral Aidprogram in the People's Republic of Congo. 1/
Participation of the engineers and economists of the Ministèredes Mines et de l'Energie was particularly important during data analysiscollection and demand forecast.
While on a mission in Washington, Messrs. Rigobert Adoua(Energy Manager, MME), Simon Manouana (Planning Manager, MME), and JulesObami (Hydraulic Engineer, MME) were involved in discussions on theresults of the first phase and the pleparation of the strategyalternatives.
1/ Members of the study team vere: Noureddine Berrah (Economist, incharge of the study); Christiane Oudin (Electrical Engineer, datacollection and demand forecast); Pierre Cordier (Economist, datacollection and demand forecast); Roger Guilhot (Electro-mechanicalengineer, review of hydro projects); Michel Patou (Dr. engineer,analysis of the strategies). Ms. Jacqueline Klopner was responsiblefor report processing.
ABTI0TOII/ACRONS
CC Combined cycle-CCC8 Caisse Centrale de Coopération EconomiqueCFAP CFA FrancIMF International Monetary FundGDP Gross Domestic ProductCT Cas turbinesIAEA International Atomie Energy AgencyMME Ministère des Mines et de l'EnergieRPC République Populaire du CongoSNE Société Nationale d'Electricité (Congo)SUEL Société Nationale d'Electricité (Zaire)
BIEBGY NEàSURES
v VoltkV kilovoltkVA kilovolt ampereMVA Megavolt ampereMW MegawattkW kilowattkWh kilowatt hour.Wh Cigavatt hourTWh Terawatt hour
CO aRT
1 US$ = 320 CFA?
TABlL 0V coWIIT
Page
EXECUTIVE SUNMARY.. .................., .... i-i
Objectives and Scope of the Study ..................... 1t4ethodology ... ......................... ....... ......*.... 2
II. TaESETN ......, 5
General Dt ........................ 5The Blectric Pover 8ector............................. 5
ZIII« DENMAN RN8........ 12
Determining Factors for Power Demand.................. 12Projected Power Consumption.......................... 13Preparation of Load Curves and Load Duration Curves... 14Demand Projection Hypotheses Used in the Study........ 15
17
IV. AVAILABLE BNERGY RESQURCES AND ELECTRIC PONERCENERATION RESOURCES .................. .................... 18
iydro Sitese................................. ....... 18
atural .................................................... 21Electricity Imot .............................23
V. PLANNING CRITERIA AND APPROACH. .... ....................... 25
Approach ................................................... 26
VI* ANALYSIS OF TUE POWER SYSTEN DEVELOPMENT ALTERNATIVES.... et 28
Results of the Self-Reliance Alternative.............. 28Results of the Regional Cooperation Strategy.......... 30Incorporation of the Kinshasa-Brazzaville Line...... 30Advantages of Install_ng an Inga-Pointe NoireInterconnection ................. e 32
Conclusions of the Optimization....................... 37
VII. RI8K ANALYSIS AND DEVHLOP4ENT STPATEGY .................... 39
Sensitivity Study .............................. 39Cost of the Inga-Pointe Noire Line.................. 39cas Cot...............................40Costs of lydropower Projects........................ 40
Economuc Loos ('Regret') Evaluation................... 41Economic Risk Analysis. ............... e 41Technical Riuk 8tudy................................ 42
Dean"d Uncertainties....................... 44Resulta of the Risk Analysis........................ 45
VIII. IMVESTMENT DECISIONS AND PROBLENS RELATBDTO THEIR IMPLEME ATION .................................. 46
Investment Decisions e.e..e.................e......e... 46Particular Problems Relating to the Implementationof Investm,nt Decisions.................... 48
Enviroumental Iuipact.................................. 50
IX. `LECTRIFICATION OF REGIONS NOT SUPPLIEDBY THE IINTERCONMECTED ................................... 53
Current Poiin.......................... 33lements of an Electrification Study.................. S5Recoumendations. ................... .......................... 5S
TABLES
2.1 Current Thermal Ceieration Syste......................... 92.2 Pover Usage - 1987..... ................ 103.l Power Demand Trends$ Base Case........................... 5S3.2 Poyer Demand Trendss Loy Case ....... 164.1 Characteristics of Main Hydropover Projects Identified.... 186.1 Self-Reliance Strategy: Principal Characteristics
of the Optimal ................. ........................ 296 2 Comparison of Solutions Including Hydro Projects
with Self-Reliance Thermal So1utions.................... 306.3 Comparison of the Alternatives Incorporating Hydropower
with the Solution Combining Thermal Generationvith the Kinshasa-BrazzavilleLink...................... 32
6.4 Advantages of the Inga-Pointe Noire Linein Relation to its Installation Date and theCost of Imported Pover .................................. 33
6.5 Regional Cooperation: Main Characteristica of theOptimal ............... ................................. 35
6.6 Comparison of Solutions Incorporating Hydropovervith the Optimal Regional Cooperation Solution.......... 36
6.7 Summary of Analysis of Alternativese...................... 37
7.1 Economic Lossess Doubling of Pover Priceor Interruption of 8upply......................... ..... 41
7.2 Additional Costa of Three Alternative StrategiesCompared vith the Proposed Solution.........,........... 42
7,3 Single Contingency Criterion: Load Coverage inthe Regional Cooperation Solution Incorporatingthe Inga-Pointe Noire Line............................, 43
8.1 Supplying Demand According to the Single ContingencyCriterion in Line vith Investment Decisions............. 47
9.1 Technical and Economic Specifications ofThree Very Small-Scale Hydropover Projects.............. 54
ANNEXES
1 The Wasp Model for Elactric GenerationExpansion Analysis..6................ .................... S6
2 Energy Supply Contract from Snel (Zaire) to SNE (Congo)... 673 Pover Consumption Forecasts............................... 694 Analysis of Hydrological Data............................, 785 Natural Cas Resources in Congo........................... 796 Basic Technical and Economic Constraints.................. 817 Characteristics of the Nain Development Alternatives
Base Demand Hypothesis ................................. 878 Characteristics of the Main Development Alternatives
Lov-Growth Hypothesis .................................. 113
MAPS
IBRD 21541: Alternatives for Interconnection between Inga andPointe Noire (following page 48)
IBRD 18242-Rl: Generating Pacilities and Transmission Systeas
UEuTiYEt SUNMY
Introduction
1. This report presents the results of the pover planning studycarried out by ESMAP in close collaboration with the Ministère des Mineset de l'Energie (MME) and the Société Nationale d'Electricité (SUE). Itis part of a vider ESMAP effort in assisting the Congolese Government tostrengthen the planning and management of the Energy Sector. The studyrecommendations complement the previous Bank/ESMAP recommendationsrelated to institutional issues and resource mobilization in the energysector.
2. The main objective of the study was to identify a least-costinvestment strategy for the interconnected grid development in Congo, andevaluate the impact of the uncertainties that will influence the powerinvestment decision3, in order to allow Congolese authorities to makeshort-term investment and electricity supply decisions, which willminimize risk of economic losses.
3. During the Congolese mission to Washington it was agreed thatthe analysis would examine two strategies:
(a) Determination of the least-cost investment program withoutelectricity imports: "Self-Reliance Strategy".
(b) Determination of the least-cost investment program, in-cluding electricity imports from Zaire: "Regional CooperationStrategy".
4. Least-cost generation programs were estimated, in both cases,using the model ELECTRIC, the microcomputer version of the WASP-III modelprogram (see Annex 1). The risk analysis was carried out by estimatingthe economic consequences of changes in the base case assumptions. Arisk-averse strategy vas then identified, according to "minimax"criterion, to avoid the woret consequences.
5. This broad summary of the results of the study is presentedaccording to the contents of the main report:
(a) Context of the study and existing pover system (Chapter II);
(b) Demand forecast (Chapter III);
(c) Generation resources (Chapter IV);
(d) Planning criteria and approach (Chapter V);
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(e) Analysis of the pover system development alternatives (ChapterVI);
(f) Risk analysis (Chapter VII); and
(<) Investment decisions and problems related to their implementa-tion (Chapter VIII).
6. Issues related to the electrification of centers not suppliedby the interconnected grid are not addressed in this study. They arebriefly discussed in chapter IX to rutline how existing studies might bestrengthened through:
(a) preparing a national electrification plan which shoulddetermine priorities, means, financial resources andinstitutional framework to develop electricity whereeconomically justified; and
(b) clarifying the institutional framework of private electricitygeneration by entrepreneurs or consumer cooperatives byaddressing the issues raised by private investors interested inthe potential of developing generation pover plants.
Context and Existing Pover System
7. In the Republique Populaire du Congo (RPC), only 6 'commues'(Brazzaville, Pointe Noire, Moubomo, Mossendjo, Nkayi and Ouesso),and 21 small urban centers are supplied vith electricity (cf. IBRD map18242-R). Even though the population of the supplied centers accountsfor 70% of the total population, only 18% of the population has acces. toelectricity.
8. In 1987 the total electricity consumption vas estimated at 540GWh: 281 GWh (52%) generated by SNE; 148 GWu (27.5%) imported fromZaire; and 111 CWh (20.5%) self-generated.
9. Electricity supplied by SUS to the consumera vas 365 GWh in1987. Per capita consumption vas 172 kWh, or 224 kWh, taking auto-generation into account. Consumption is essentially concentrated inBrazzaville (50%) and Pointe Noire (42Z).
10. The main generation plants are interconnected to the two mainconsumption centers by 110 and 220 kV lines. Principal SNE supplysources are:
(a) the Moukoukoulou hydro pover plant, on the Bouenza river: 74MW installed, 23 MW firm, and 400 GWh/year generated on theaverage;
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(b) the Djoué hydropover piant on the Djoué rivert 15 MW ins-talled, 12 MW firm, and 118 GWh/year generated on the average;
(c) the 220 kV interconnection line vith Zaire, alloving bycontractual agreem&nt electricity importe from Inga hydropowerplants up to 50 MW at a price estimated by the Energy Assess-ment Mission at 10 FCFA (USé 3,13/kWh); and
(d) diusel pover plants in Brazzaville (8 MW installed), and PointeNoire (20 MW installed), are run by 8NE for back-up only. Mostgeneration units are obsolete or are in poor condition fortechnical reasons or lack of maintenance, especially inBrazzaville.
Demand Forecast
V. The energy forecast vas based on a hybrid approach combininganalytical ard econometric methods. Hlectricity consumption wasdisaggregated by consumption center among five categories of consumera.Specific surveys and historical demand analysis were carried out toproject the nuaber of subscribers and their specific consumption patternsas vell as the growth rate by category. Afterwards, tLe global demandand the interconnected grid demand vere evaluated. The load curves veredetermined on the basis of the hourly, daily, weekly, and seasonalvariations of the demand.
12. The main results of the two cases demand are given in thefollowing table:
Base Case Low Gteth CaseIntercoon- Intercon- Intercon- Intercon-
Total nected Grid nected Grid Totol nbcted Grid nected GridDmand (GWh> Dlmand ($Wh) Peak Load (MW) Demmnd (GWh) Oemand (GWh) Peak Load (MW)
1987 428.9 427.9 72 428.9 427.9 721990 521.3 519.8 87 495,7 494,3 831995 706.0 701.4 122 628.0 624.0 1102005 1439.0 1421.0 252 1150.0 1136.0 2012015 2845.0 2007.0 501 2118,0 2090.0 378
13. The annual growth of the base case demand, 7X during the studyperiod, is only 2/3 of the historic annual grovth between 1963 and1987. It la based on the recovery of the economy, an increase andetabilization of the price of exported oil at US$ 18 (1988 prices), andfinally an ambitious electrification program to supply 80% of thepopulation in 2015.
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14. The annual gi:owth of the low alternative is 5% untit 1995, then6% until the end of the study period. It is based on a slow recovery ofthe economy, a depressed hydrocarbons market reducing the country's oilrevenues by 20%, and an electrification program to supply 65% of thepopulation in 2015.
Generation Resources
15. An inventory of the hydro-sites vas compiled for the northernpart of the country but for the southern part supplied by theinterconnected grid, only some potential projects vere identified and notall fully assessed.
16. The characteristics of potential projects are as follows:
Power (MW) Production Project Cost Cost/kWhlnstalled Firm GWh/yr US$ million 1988 US« Remarks
DJoué 2 10.0 7.0 90 100 10.9 ExtensionImboulou 100.075.0 645 438 6.9Lekoulou (Bouenza) - 37.0 90 125 - Regulation reservoirFoulkary 58.5 17.5 388 344 8.8Sounda 1000*0 - 6400 - -Sounda (partial 60.0 40.0 200 250 12.5equ ppment)
Only the first three projects demonstrate potential to meet theelectricity needs in Congo. The others vere dropped from considerationafter a first analysis because of study status, project size andgeneration costs.
17. Thermal generation candidates vere selected to use indigenousfossil fuels which are already produced (fuel oil) or identified and notyet developed (natural gas). The chsracteristics of the candidates areshown in the table below.
Aval labi I'iyCapital Cost Meat Rote Fuol Cost Factor
Unit Size 588/kw kcal/kwh S88/ecal
Diesel (<012) 12 875 2142 11,8 77Gas turbine (TCG25) 25 560 35W0 9,4 80Combined cycle (CG7S) 75 685 2076 9.4 78Interconnection (lino) 200 160 860 2,8 93
v
18. Imports of electricity from the Inga hydropover plant canbe regarded as a reliable source of electricity because the inter-connection between Congo and Zaire has already proved successful andInga's potential generation is very much higher than the needo ofZaire: 1774 MW installed for a current demand of 500 to 600 MW.Congolese authorities agreed on considering a 220 kV line from Inga toPointe Noire among the supply candidates.
Planning Criteria and Approach
19. Planning criteria (level of reliability, biggest unit sise,economic paramaters, etc.) vere difficult to determine in as difficult anoperating environment as prevails in Congo. In this case, the planningcriteria vere determined by comparison with accepted standards forsimilar systems and adapted to local conditions.
20. Generation expansion alternatives were analyzed by theoptimization model, and the least-cost generation expansion sequence,(i.e., minimizing the discounted capital and operation costs), vasdetermined for both cases: the "Self-Reliance Strategy" and the"Regional Cooperation Strategy." Aftervards, sensitivity and riskanalysis were carried out to test the robustness of the optimal solution.
Analysis of Development Alternatives
21. All the resulta shown in this section are based on the BaseCase forecast because the optimization has shown that the demand leveldoes not affect the medium-term investments in the case of the RegionalCooperation Strategy, and only delays commissioning of the thermal unitsin the case of the Self-Reliance Strategy, if the demand was notattained. The proposed strategy is flexible enough to adapt to changingenergy demand. It is important to note that the long term strategy isnot a fixed "plan" but a background against which immediate decisions canbe taken.
22. The analysis carried out has shown that the RegionalCooperation Strategy is the least-cost solution for meeting the inter-connected pover system demand for the next two decades. It is based onstrengthening the interconnection with Zaire from Inga to Pointe Noire,in 1997, and installing 2 x 25 MW gas turbines in 1992 and 75 MW combinedcycle units after 2000. This strategy is predicated on an import priceat about é$ 2.4/kWh (FCPA 7.8/kWh) in 1988 prices.
23. Additional computer analyses showed that if the Inga-PointeNoire line could be commissioned in 1992, it would have been selectedfirst, and the first gas turbine would have been delayed until 2002,and the second one until 2005. Total discounted costs would be more than5Z lover.
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24. If a complote Self-Reliance Strategy is chosen, electricitywould be supplied by thermal units only, and generation cost would be 302higher than the least-cost solution. However, during the ninetieselectricity generation cost would be 60% higher than the RegionalCooperation Strategy because 80% of additional expenses would be incurredduring the first ten-year period.
25. Even in the case of the Self-reliance Strategy based on thermalunita, gas consumption vould reach the required level of economicviability for development only after the year 2000. Thus, it isrecommended that a study on gas resource development be carried out,which identifies complementary gas utilization to electric generation,and evaluates the long-term price of the gas delivered at Pointe Noireand Brazzaville.
26. Hydro projects were not competitive during the study period; ifa hydro strategy vere preferred, generation cost would be up to 80%higher than the least-coet solution, depending on the number ofcommissioned projecta and the commission dates. A sumary description ofoptimal solutions and a hydro solution are given in the table below.
Present value ofgeneration oost
Solution Summary Description (19C8 prices) Index
Regional Cooperation Strategy
* I-PN able to be coommissioned 220 kV line Inga-Pointe Noire 202,4 100from 1995 4 X 25 MW GT and
4 x 75 MW CC
* l-PN able to be commissioned Installation of Inga-Pointe Noire 192,0 94from 1995 line In 1992, plus 4 x 25 MW GT
end 4 x 75 MW CC
Self-Rellance Stretegy 6 x 75 MW CC and 260,5 1295 x 25 MW GT
Hydro Strategy Bouenza (1996), Djoué 2 (1999) 335,8 166lmboulou (2006) andcomplementary thermal units
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26. Only the Bouenza vater regulation pruject might play a role inthe least-cost development plan if a feasibility study could show thatestimated construction could be cut by about 25k. Therefore, it lerecommended that a feasibility study of the Bouenza regulation project becarried out.
Risk Analysis
27. A least-cost investment strategy is not necessarily the mostappropriate if the assumed conditions do not prevail. Therefore, it isnecessary to estimate the economic consequences of each decision in casethe expected assumptions do not materialize. An investment decision isconsidered robust and risk-averse if it minimizes the economic loss inthe case of changes in economic assumptions or the occurrence of anunexpected event.
28. The sensitivity studies and risk analysis carried out confirmedthat the Regional Cooperation Strategy is a very robust and risk-aversestrategy. In cases of changed assumptions or unexpected events, theeconomic losses incurred are lover than the excesa costs incurred byalternative strategies.
Investment Decisions
29. To meet the projected demand on the interconnected grid for thenext decade the following two investment alternatives are possible:
(a) installation of Inga-Pointe Noire after 1995:
(i) two 25 MW gas turbines in Pointe Noire in 1992; and
(ii) a 220 kV line from Inga to Pointe Noire as soon aspossible and no later than 1997.
(b) installation of Inga-Pointe Noire in 1992
(i) installation of the 220 kV line from Inga to Pointe Noirein 1992; and
(ii) installation, according to the demand increase and theneeded quality of service, two gas curbines between 1998and 2002.
The investment cost is estimated at US$ 28 million (1988 prices) for thegas turbines and US$ 32 million (1988 prices) for the interconnectionline.
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30. The WASP solution, which assumes that supply and demand areconcentrated in one node, vas complemented by analyzing the electricitysupply of the two main consumption centers based on the single contin-gency cricerion (failure of the largest supply sourceS generation unitor 220 kV line). The results show that the commitment of the 2 x 25 MWgas turbines or the Inga-Pointe NoLre line in 1992 is essential to ensurea reliable supply to Pointe Noire, even in the case of low demand growth.
31. A feasibility study of the Inga-Pointe Noire interconnection isrecommended. The study should assess and clarify all the legal andinstitutional problems related to the implementation of the project, andprepare contract dravings.
32. Three alternatives might be considered for the layout of theinterconnection line: Inga-Pointe Noire (210 kms), Inga-Moanda-Cabinda-Pointe Noire (290 kms) and Inga-Loudima-Pointe Noire (180 kms) (see para.8.7).
33. Some legal and institutional problems are new and should befully assessed. Particularly, the implementation of the project dependson the financial and operational capabilities of the pover sectorcompanies in the concerned countries. Among the possible alternatives,the line can be owned by one of the pover companies, jointly by the twocompanies or by a private company.34. Cas turbines are a nev generation technology for SNE, and SNEshould:
(a) learn f rom UPDEA countries' experiences to avoid "teethingproblems" (start-up difficulties) through, for example, studytours; and
(b) attach particular attention to sustained operator training inbid documents and ensure adherence to maintenance proceduresrecommended by the manufacturer.
Environmental Impact
35. The proposed strategy has an acceptable environmental impactbecauses
(a) the population of the region concerned is not dense anddeforestation is insignificant compared to the impact of woodfuel demand and the size of the forest resource in the region;and
(b) exhaust gas (S0 , NOx, Co and C02), and particulate emissionsin short and meÏium terms, are low because the only rural plantcommissioned during the next decade consists of two 25 MW gasturbines. In the long terms, the improved performance of
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Combined Cycle technology and the use of natural gas vouldcomply vith the most stringent inte>rnational standards forenvironment protection.
Strengthening Pover Planning Capabilities of SNE
36. Power planning's improvement is part of "the need to strengthenthe national pover utility, SNE, and give the pover sector an unambiguousand commercially efficient organizational structure" (Energy Assessment).
37. Pover planning is a permanent task because:
(a) investment decisions need to be annually adjusted in theframevork of rolling medium-term plans, utilizing updateddemand forecast, and new technical and economic information;and
<b) long-term strategy studies should be updated every five yearsor so, to define a background against which to evaluate themedium-term decisions.
38. Therefore, it is recommended to organize the planning(function) of the pover sector development by:
(a) creating, in SNE, a central small unit, which will be in chargeof generation and network studies and responsible for technicaland economic analysis to prepare pover investment decisions;
(b) assigning two or three engineers/economists to the unit andensuring their training in load forecast and powor planningtechniques;
(c) equiping the unit with a high speed pover planning micro-computer, and pover planning and network optimization/simulation models;
(d) giving the responsibility of maintaining and improving the database collected during the study to the unit; and
(e) providing the SNE vith technical assistance, if needed, inorder to help it start these activities.
39. It is recommended that the responsibilities of the Ministèredes Mines et de l'Energie and the Société Nationale d'Electricité beclarified. Recommendations were already made by the Bank and ESMAP tostrengthen SNE and allow it, in the medium term, to take completeresponsibility for public sector commercial electricity supply.
I.* INTRO WCTION
Background
1.1 This report is the outcome of a study forming part of the VorldBank/UUDP/bilateral aid Energy Sector Management Assistance Program(HSMAP). The study was conducted at the request of the CongoleseGovernment and in close cooperation with representatives of MME (theMinistry of Mines and Energy) and SNE (Société Natic taled'Electricité). Collaboration with the latter was particularly importantduring data collection.
1.2 The staff and consultants carried out a number of missions, forthe following purposes:
(a) finalizing terme of reference for the study;
(b) reviewing existing studies, participating in data collection,and supervising the work of Congolese staff;
(c) presenting the study and discussing the results with theCongolese Government.
1.3 An MME mission visited Washington for the folloving purposes:
(a) discussing the report on data collection and projected electricpower consumption;
<b) defining the options and strategies to be studied;
(c) participating in a seminar for presenting the model tsed foroptimization of the generation system that may be provided forthe People's Republic of the Congo (PRC), if the Covernment sorequests.
Objectives and Scope of the Study
1.4 The main purpose of the study is to assese options fordeveloping the electric pover system in order to enable the CongoleseGoverament to prepare an investment plan for the 1990-2000 period,minimising long-term electric pover supply costs.
1.5 Obviously, the development of the system depends on thestrengthening and upgrading of the sector's institutional and technicalaspects and its human resources. In this document, reference is madeonly to those items relating to planning, but it must be noted that theyform part of the general framework of assistance provided by SSMAP, which
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began vith a study of energy problems and options, and is to continuevith a study intended to reduce losses and improve the performance of thepover sector.
1.6 The general procedure for any planning study is to examine thepossible ways of satisfying medium and long-term pover demand in light ofavailable resources and the technical constraints affecting the system,and then to classify them so as to identify the best solution, bothtechnically and economically.
1.7 In particular, this study consists of the folloving components:
(a) assessment of medium and long-term power needs;
(b) identification of available resources for pover generation;
(c) identification of the optimal combination, or least-costsolution, for meeting demand at a particular level of servicequality;
(d) study of the impact of the uncertainties inherent in anylong-term projection, in order to propose an investmentstrategy minimizing such risks;
(e) identification of the capital investment decisions necessaryfor meeting demand.
The study has been restricted to the pover generation system, ensurîng ateach stage that line capacity vas adequate to cope properly vith energytransmissions to the consumption nodes, vith emphasis on the advantagesof solutions that provide for a reliable supply to the main centers, evenif the main supply source fails (the "single contingency" criterion).
1.8 The data collection phase showed the weaknesses of thestatistical system and the inadequacies of data relating to certainhydropover projects. Estimates had to be used in place of the missingdata and the resulting impact upon the results of the study assessed bythe senaitivity studies.
Methodology and Resources
1.9 As agreed vith the Congolese counterparts the study vas dividedinto the following twa stages:
(a) determination of the optimal (least-cost) generation systemnecessary for meeting power demand vithout imports;
(b) determination of the optimal system including pover importsfrom Zaire.
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1.10 In both cases, the optimal solution was sought by applying arepetitive procedure to the ELECTRIC model, a microcomputer version ofWASP III (Vien Automatic System Planning Package; see Figure 1).
1.11 ELECTRIC is a modular program that allows for considerableflexibility. It consista of the folloving seven modules, three beingused for data input, three for developing the optimal solution, and thefiral one for preparing a summary report of the results:
LOADSY: Load duration curve data for the entire study period.
FIXSYS: Specifications of existing system, as predetermined at thebeginning of the study.
VARSYS: Data relating to units selected for developing thegeneration system.
CONGEN: Production of various configurations (i.e. combinations ofgeneration sets or "candidates") for supplying load.
MBRSIM: Simulation (year by year) of the operation of theconfigurations generated by CONGEN.
DYMPRO: Dynamic programming for determining the optimaldevelopment plan.
REPROBATs Summary of data and results.
Annex 1 provides a brief description of the model.
rELECTRIC ENERGY FORECAST - L'p
POWER GENERATING SYSTENS DEVELOPHENT STUDIES
_ NFUT DT FUEL RESOURCES .
_ POWER PLANT TECHNICAL PARANIETERS
ENVIRONMENTAIO PROTECTIONPTIONSCRITERIA
1 OIE PLANT CAPITAL COSTS FUTURE HYDROELECTRIC
PROJECT *[ au
1%~~~~ REHABILITATION CRITERIAGROUNDRYLES FOR ECONONIC
EVALUATION_AND OPTTMtIZATION SCOUtai
POWER GENERATING SYSTEH ESOPERATION PRACTICES.
Figure 1 -- ouE
'~~~~~WASP SENSITIVITY STUDIES . .O"R
INPUT DATA MODEL_
| ~REPORTING OPTIONS
BASIC INFORMATION INPUT DATA WASP MODULES
Source: Expansion Planning for Electrical Generating Systems: A Guide Book,AIREA, Vienna (Austria), 1984.
- 5 -
Il. THE SHTUIG
Ceneral Data
2.1 The People's Republic of the Congo has an area of 342,000 km2and is situated in West Africa. It has a 160 km Atlantic coastline, andextends inland for 1200 km.
2.2 In 1987 the estimated resident population vas 2,127,000, vithabout half the inhabitants living in the capital, Brazzaville (689,000),and Pointe Noire, the main port on the Atlantic (349,000). 802 of thecountry's population is concentrated in the south, on the corridorconnecting these two cities. In addition, the country is characterizedby high population growth (an average rate of 3.471 per year in theperiod between the 1974 and 1984 censuses), and a considerable ruralexodus, the rates of increase being 1Z for the rural population, and 6.5Xfor the urban population.
2.3 The climate is hot and humid vith two seasons: a dry seasonrunning from June to September and a rainy season lasting the% rest of theyear. Daily temperatures range on average from 24VC to 26' in the dryseason, and from 26'C to 30'C in the rainy season.
2.4 In 1986, the Cross Domestic Product (CDP) vas CFAF 688.3billion (about US$ 2.55 billion), a per capita income of US$ 1250. Theoil industry dominates the economy (47Z of nDP) followed by services,commerce and government (32X). Falling oil prices account for thedecline in CDP in 1986 (by 28X in current CFAF and 35X in constant 1980CFA?) compared vith U1e 1984 level.
2.5 As a result of this sharp fall (which followed a period ofsustained growth), the Congolese Covernment vas obliged to review itseconomic policy. It called upon the International Monetary Fund and theVorld Bank to assist it in implementing a structural adjustment programto prepare the way for a recovery in growth and to reduce economicdependence on oil revenues.
The Electric Power Sector
2.6 SU vas established by the Lav of 1967, and is responsible forgenerating, transmitting and distributing electric pover. It inpermanently supervised by MWE. The Ministry is also responsible for the
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planning and engineering of generation and transmission works, and formonitoring their execution. 1/
2.7 Electrification is limited to the country's siX 'communes'(Brazzaville, Pointe Noire, Loubomo, Mossendjo, Nkayi and Ouesso), and to21 small urban centers, mort of these being the main towns of districts(see IBRD map 18242-R at the end of the report). Although the totalpopulation of the areas served is about 70% of the total, only 18% ofinhabitants have access to an electric pover supply (30% in Brazzavilleand Pointe Noire, and less than 5% in certain secondGry centers). 2/
2.8 Figure 2 below shows the 110 kV and 220 kV interconnectedsystem supplying the main consumption centers in the south and center ofthe country. It consists of:
(a) the Moukoukoulou plant located on the Bouenza River, which hasa total installed capacity of 74 MW (4 sets of 18.5 MW), butthe firm capacity is only 23 MW due to the Bouenza's very lowwater mark from July to October. The w ter head is about 70 mand the inflow through the turbines 32 m/s;
(b) the Djoué plant located on the Djoué River, which has aninstalled capacity of 15 MW (2 x 7.5 MW) and a firm capacity of12 MW because of the reduction of the water head averaging from26 m to 21 m in December during the high water period of theCongo river;
(c) the diesel plants in Brazzaville (installed capacity = 8 MW)and Pointe Noire (installed capacity 20 MW) which are kept onstandby;
(d) the 220 kV interconnection line from Zaire permitting powerfrom the Inga hydropower plant to be imported via Kinshasa. Byagreement, transmission capacity is 50 MW at a price estimatedby the Energy Assessment mission at 10 FCFA/kWh (about USé3.13/kWh). An outline of the energy supply contract from SNEL(Zaire) to SNE (RPC) is given in Annex 2; and
1/ According to the purpose of this study, this section is limited toan outline description of the interconnected system as a backgroundfor the pover sector development. Por the global situation of SNEone can refer to the latest document of the Caisse Centrale deCoopération Economique: "Société Nationale d'Electricité du Congo"(November 1987).
2/ The rate of accesa is calculated on the basis of the number ofhouseholds connected to a power supply, assuming an average of ninepersons per household (i.e., married couple plus dependents).
94km
a u 3t ci 62k 4ji
| §~~~~ t tkV 1 tOkV t lOkltT
C3uS14VA@s t4VA HSMVA (32O7.5MA 16 U16VA
lo101 1 OIciV lOIgV lOlWV IttOW
<23 <2>i ~~~~~~~~~~~~~~~~49 km liI 10S t22SH«
LOV6M CI 1 .225t4VA
° ELf - i° 1*~~~~~ POINTE toi)RE ai | 10-UOlO 1 40lN
225W mou226W *
{1 225kV 1 225 kV 1 225kV 2251V
H2tVA )25MYA 2#30 HVA 2"311Y
3]~~~~~~~~~zkV Io0ttV il 20tV
LEGENDE kO 225kv LIGNEU366b0aAU4MELEC OJOUE
0 225kV LION£, S7OMn2 A LNELEC 33kV
a 110Wk LCIGE, AEISI 1811510mmn2 le t0 KVA
a 11OkV LIGNE, AIvS1 2&010unm2
Y 22lkV LIGNE. 95«m 2 ALU4ELEC
Figure 2. Interconnected Grid, Société Nationale d'Electricité
Source: Ministry of Mining and Energy
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(e) a high voltage transmission network consisting of 450 km of 220kV lines and 267 km of 110 kV lines, linking the supply sourcesto four substations, of which two supplying Brazzaville,M'Bouono (220/30 kV) and Tsielampo (220/20 kV), and twosupplying Pointe Noire, Mongo-Kamba (220/20 kV) and N'Goyo(220/30 kV).
2.9 SNE faced extreme operating difficulties due to delays ofrehabilitation and inadequate renovation investments. Service tocustomers, especially in Pointe Noire, was poor, with blackouts occurringdaily.
2.10 The situation improved dramatically since:
(a) the commissioning of the transmission line interconnectingBrazzaville to Pointe Noire, which allows better utilization ofthe Moukoukoulou pover plant;
<b) the rehabilitation of the Djoué pover plant; and
(c) the Moukoukoulou's overall maintenance.
2.11 The rehabilitation/modernization work and regular maintenanceshould be carried out as previously recommended by the Vorld Bank/ESMAPstudies and should be given high pricrity in the rehabilitation measuresfor SNE.
2.12 The availability of the diesel sets is very low because theyare obsolete or in poor condition due to lack of maintenance and repair<see Table 2.1). Only the sets in Pointe NJire have been included in thegeneration system as of the beginning of the study period (1991) becausethey are newer and in better shape.
2.13 The commissioning of the 220 kV interconnection line improvedthe reliability of the supply, particularly in Pointe Noire. Forexample, total blackout at Pointe Noire vas avoided by importingelectricity from Inga (Zaire) during the breakdown of Noukoukoulou inDecember 1987. However, the creation of a control center, evensimplified, is needed to obtain all the benefits from the interconnectionline.
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Table 21: CURRENT THERMAL GENERATION SYSTEM
Max. Powers AnnualSpeed steady state Year of Avallability
Plant (rp>) (in kW) Manufacture Factor (S) Remarks
Set Make Rated output
Pointe Noire Plant
3 AGO-240-G 2,400 HP 1,00o 1,2s0 1968 704 AGO-24-B 2,400 HP 1,000 1,250 1968 705 AO-240-0 2,400 HP 1,000 1,250 1968 776 AGC-240-0 2,400 HP 1,000 1,250 1968 709 12PC2-2V 6,000 HP 500 3,700 1972 -- Undergoing major
repairs10 12PC2-2V 6,000 HP 5SO 3,700 1974 75il SULZER Z40-148 6,000 HP 6Q0 3,900 1981 75
Loubomo Plant
1 MAN G8-VU-42 454 HP 37S 300 1954 75 Operable2 MQO V12 1,200 HP 1,500 600 1967 75 6ood condition
Brazzaville Plant
1 SLM-VD 32 1,250 HP 500 500 1948 25 Obsolete2 MANN 9 1,800w HP 37 600 1948 30 Obsolete3 TOSI QT 38B 1,250 HP 428 600 1950 60 Obsolete4 TOSI QT 3a8 1,250 HP 428 6Q0 1950 60 Obsolete5 ERDA 12 YLC 2,080 HP 1,030 1,150 1972 2S Unrellable
6 RDA 12 YLC 2,080 1W 1,000 - 1972 - Serlous breakdown ofsets; to be excluded
7 ER£DA 12 YLC 2,080 HP 1,000 1972 - Serlous breakdown otsets; to be excluded
8 EREOA 12 YLC 2,080 HP 100 1972 - Serlous breakdown ofsets; to bedowngraded
Source: TRANSENERG: Date collection end doend projections; final report (August 1988).
2.14 There is considerable autogeneration in both industrial andagricultural enterprises and in residential property because the overallreliability of service vas poor and the supply from the public systeavery limited. It is estimated to be between 20X and 25Z of SUN's totalsupply, but statistics are often unreliable or unavailable.
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2.15 In 1987, SNE's pover supply totaled 429 GWh, so that totalsupply at national level can be estimated to be 540 GWh, consisting of281 GWh (52%) generated by SNE, 148 GWh (27.5%) imported from Zaire, and:11 GWh (20.5%) of in-plant generation.
2.16 For the same year, SNE's electric power sales totaled 365 GWh,a per capita consumption of 172 kWh (224 kWh, including autogeneration),a lov level of consumption compared with other countries with comparableincome levels. As Table 2.2 indicates, consumption is basicallyconcentrated on Brazzaville (50%) and Pointe Noire (42%).
Table 2.2: POWER USAGE - 1987
Total SNE Supply Losses (2)xlCO In-plantSaies: LV Sales: MV Sales GWh GWh (1) Generetton
Centor (GWh) (GWh} (Wh1) i (1) (2) (1> (Gwh)
Brazzavllle 105.4 77.2 182.6 50.0 216.3 33.7 15.6Pointe Noire 64.6 86.9 151.5 41.7 177.3 25.8 14.6 95Secondary CentersIn south 7.8 21.8 29.6 8.1 34.3 4.7 13,7 3
Isolated centers 0.9 0.9 0.2 1.0 0.1 10.0 10Total 178.7 185.9 364,5 100.0 428.9 64.3 15.0 111
2.17 Losses are calculated to be 15% of SNE supply, but this figurenust be approached vith considerable caution, like all electric powerstatistics, because of the lack--or unsuitability--of measuringinstruments, the defective condition of many meters, frequent mistakes inreadinga, and the estimated billings applied to many consumers. In spiteof these reservations, it must be noted that the historical analysis inthe first phase of the study vas conducted consistently, so thatsignificant trends in the sector could be identified.
2.18 Prom 1963 to 1987, pover generation incraesed steadily by about10%. The increase vas larger during periods of strong economic growth,but it muet be noted that it remained significant in spite of theeconomic recession (i.e., over 6% in 1985, 1986 and 1987).
2.19 To conclude this summary of the general background to thestudy, two important commdnts should be made:
(a) electric poter is in process of making inroads into Corgo, butat present barely approximates the country's economic andsocial needs. Demand vill continue to increase significantly,particularly because the Government'e economic adjustmentpolicy includes the development of new industrial activities
- il -
designed to reduce the economy's vulnerability resulting fromdependence on oil export revenues; and
(b) demand is concentrated almost entirely on the interconnectedsystem rerv;i1g the Brazzaville-Pointe Noire corridor. It seemsevident that any medium-term expansion of the system into theinterior of the country vill depend on the development there ofa large center of electric power generation and/or consumption.
Recommendations
2.20 The data collection phase revealed the extreme shortcomings ofSNE's statistical system. Although the reorganization of consumerservices in Brazzaville and Pointe Noire and the establishment of a dataprocessing center viLl improve matters, much remains to be done.
2.21 In the short term, the demand database established for thepurposes of the study must be maintained by adopting the follovingmeasures:
(a) ensuring that existing meters operate properly;
(b) regularly gathering and checking the reliability of the data onvhich the development of the power system must be based.
2.22 In the medium term, the statistical system muet be completelyrethought (as part of the current preparation of data processingguidelines), in light of the need for the existing tariff structure to besimplified and adapted, and the customers' management to be improved.
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III. DEKAN» TREND8
Determining Factors for Pover Demand
3.1 Demand projections constitute an important stage in the plan-ning of pover generation resources, because they determine investment,and require commitments to be made to choices that are oftenirreversible. This sort of gambling on the future involves risks, and soit is very important to clarify the socioeconomic options determiningpower consumption, in order to ensure that the decisions taken in thepover sector are consistent vith economic and social development. It isalso necessary to identify the factors that determine demand and aresubject to variations that elude decisionmakers, so that the risks facedin situations other than those anticipated by planners can be properlyassessed.
3.2 The following methods vere used to carry out a detailedhistorical demand analysis by center of consumption over the 1963-87periods
(a) a study of time-series at national level, and an examination oflinks betveen pover consumption and CDP;
(b) a breakdown of consumption by voltage level and consumercategory;
(c) a study of consumer consumption patterns based on a sampletaken from billing records;
(d) an examination of a limited but representative sample of thevaricus socio-occupational categories, in order to assess theequipment possessed by households having access to electricpover, and the intentions of others to apply for connections ifthe system is extended.
3.3 This analysis indicated that electric pover consumption,although affected by economic circumstances, continues to increase evenin periods of recession. For example, in 1976/77 and 1985/86, GDP fellby 8.5% and 30.7%, but power consumption increased by 17.8% and 5.7%.Thus, the assumption that economic recessions andlor changes in hydrocar-bon prices produce immediate and lasting effects on pover consumption inCongo must be qualified, and the risk that demand vill be influenced byfactors external to the economic adjustment policy undertaken by thecountry vith IKH and World Bank assistance is lessened. Adjustmentrequires the sustained growth of industrial demand in order to utilizeexisting production capacity more efliciently and develop new productioncapacity so as to reduce the economy's dependence on oil.
- 13 -
3.4 The analysis also showed that household consumption vas highcompared vith neighboring and other countries having the same per capitaincome, the average being 260 kWh per subscriber per month, vith over 400kWh per subscriber per month for half the households supplied inBrazzaville, and even more in Pointe Noire. The main reason is theintensive use of ventilation and air conditioning stimulated by veryregressive block tariffs for thermal uses. 3/ Consequently, theelectrification rate and the energy conservation, consecutive to theconsidered adjustment of the tariffs, were taken into account indetermining the future electricity demand.
3.5 A consulting firm vas hired to prepare demand forecasts andgather project data. The forecasts vere made by determining energyconsumption, followed by load curves and load duration curves. Theresults vere discussed vith the Congolese staff during the mission toWashington. Hovever, only two alternatives vere selected for the studyof the generation system (see 3.9 below).
Projected Pover Consumption
3.6 The folloving procedure was adopted for preparing the loverconsumption projections$
(a) a population forecast vas prepared, based on the Covernment'sprojections for the total population, and assuming a slowdownia the considerable urban growth vitnessed over the last twodecades;
(b) three possible economic development scenarios vere designedusing the medium-term hypotheses and projecting them over thelong term, vith the different levels of growth depending on thedegree of success achieved in adjustment, and on changes in oilpricess
(c) future demand (by consumption center) vas determined for eachof the economic scenarios by adopting the folloving proceduress
Ci) disaggregating demand among the five main categoriesof consumers: residential and hotel; Governmert andembassies; major industries; other industries andservices; public lighting;
3/ In an agreement between SUE and the Government, the Ministry ofFinance and Budget approved a tariff adjustment, which vill be basedon LRMC and structure simplification (see Annex 18.2 of the documentmentioned in 1/.
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(ii) determining future energy consumption for each of thesecategories by preparing hypotheses regarding overallconsumption growth and/or increases in the number ofsubscribers and unit consumption. These hypothesesare consistent vith assumptions regarding economicdevelopment, and are based on a survey of large indus-trial projects and intensification of electrification.
Annex 3 contains a more detailed description of the method, hypothesesand results.
Preparation of Load Curves and Load Duration Curves
3.7 The process of using consumption data to calculate the poverdemand from the system is very important, because the latter determinesthe specifications of the generation system. More especially, use of theELBCTRIC model requires demand to be represented by annual or seasonalload duration curves.
3.8 In the first phase, the pover generated on the interconnectedsystem is calculated by adding together consumption and pover losses.Projected load duration curves are then produced by the following stepss
(a) historical analysis of existing load curves and load durationcurves;
(b) preparation of standard load curves for three days of the week(a vorking day, Saturday, Sunday and holiday) in each of thetwo seasons (i.e., the dry season and the rainy season);
(c) establishment of the consumption patterns of various categoriesof consumer;
(d) assessment of changes in load curves due to differences in theconsumption trends of the various categories of consumer; and
(e) establishment of load duration curves characteristic of the dryand rainy seasons, for four different stages of the study(1987-89, 1990-94, 1995-2005 and 2005-15).
Complementary results are contained in Annex 2, and the completehypotheses and detailed results are presented in the consultant's finalreport. 4/ All the data gathered, together vith the methods forpreparing projections on microcomputer using LOTUS 1-2-3, have beenpresented MME and SNE to provide a basis for regular data collection.
41 TRANSENERC: Collecte des données et prévision de la demande(Data collection and demand projections: final report), Neuilly,August 1988.
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Demand Projection Hypotheses Used in the Study
3.9 Tvo hypotheses of demar.d trends vere selected for the study,after detailed analysis of the consumption projections. The "thigh'thypothesis vas eliminated because the large increase in householdconsumption it forecast was incompatible vith the policy of conservingand rationalizing pover consumption. In the other two cases, consumptioncontinues to increase rapidly (making up for the delays inelectrification), but the differences between them result from thegreater or lesser degree of succese achÎeved by the economic adjustmentand rehabilitation policy> and al%e the extent of new electrification.
3.10 The base hypothesis makes the folloving assumptions:
(a) the structural adjustient program is successful;
(b) the hydrocarbons market stabilizes at about US$18 (1988) perbarrel of oil; and
(c) an ambitious electrification policy is implemented vith atarget rate of about 80% by the year 2015.
Table 3.1: POWER DEMANO TRNDOS: BASE CASE
Category 1987 1990 1995 2005 2015
Total demand (GWh) 428.9 521.3 706.0 1,439.0 2,845.0Rate of increase (E1 - 6.7 6.3 7.4 7.0Per capita consumption(kwh) 202.0 - - - 529.0
Interconnected grid dmand(CWh) 427.9 519.8 701.4 1,421.0 2,807.0
Interconnected gridpeak load (OW) 72.0 87.0 122.0 252.0 501.0
Load factor (<) 68.0 68.0 66.0 64.0 64.0Estimated number ofhouseholds served(population: 9) xelectrlf[cation rate 42,500 - - - 478,000
According to this hypothesis, pover demand increases from 429 cGi in 1987to 2,845 Clh in 2015, a 7X rate of increase (i.e., tvo thirds of the ratefor the 1963-87 period). Per capita consumption increases tvo and a halftimes over the same period, so that by 2015 it slightly exceeds 500 kWhper year, a considerable improvement over the current position, althoughthis is still a loy rate in absolute terms. It muet be noted that power
- 16 -
deuand increases slightly more quickly than pover generation. This isbecause of increases in household consumption, particularly lightingneeds, which coincide with peak load.
3.11 The low case is based on the folloving assumptionss
(a) an improvement in the country's economic position, althoughthis is slightly hindered by the international situation;
(b) movements in the hydrocarbon and/or US$ markets that vork tothe country's disadvantage, producing oil revenue 202 loverthan the level assumed in the base case; and
<c) an electrification policy which, although improving on thecurrent position, produces modest results, the objective beingabout 65 by the year 2015.
Table 3.2: POWER DEMANO TRENDS: L0W CASE
Category 1987 1990 1995 2005 2015
Total demand (GWh) 428.9 495.7 628.0 1,150.0 2,118.0Rate of increase (%) - 4.9 4.8 6.2 6.3Per capita consumption
(kWh) 202.0 - - - 394.0
Interconnected grid demand(.Gh) 427.9 494.3 624.0 1,136.0 2,090.0
Inter-onnected gridpeak Ioad (MW) 72.0 83.0 110.0 201.0 378.0
Load factor (%) 68.0 68.0 65.0 65.0 63.0Estlmated number of
households served(Population: 9) xelectrification rate 42,500 - - - 385,000
In this case, pover demand increases at about 52 from 1987 to 1995, andjust over 6X subsequently. Although this rate is considerably lover thanthat for the 1963-87 period, it is consistent with a less rapid economicrecovery than is assumed in the base scenario. Per capita poverconsuuption increases at lesa than 32 over the period, totaling only 392kWh per year in 2015. The load factor declines slightly, for the sanereasons as in the former case.
3.12 It muet be noted that, in both cases, demand could be limitedby SUE's connection capacity (the requirements being for over 15,000householde per year in the base case or over 12,000 households per year
- 17 -
in the low case), and by its ability to service commercially andtechnically. However, the rehabilitation program applied to SUE overrecent years suggests that these problems vill be overcome through themeasures for institutional and technical strengthening that are currentlybeing adopted or studied (i.e., reorganization and initialcomputerization of management procedures, with particular regard toconsumer services; establishment of a pover monitoring and loadingcenter; strengthening of the MV systems; balancing and strengthening ofthe LV systems; reactivation of the vocational training center, etc.).
Recommendations
3.13 The pover generationi projections are based on a reduction inthe system's losses from the current level of over 15% to 10%. Theactions and methode necessary for achieving (and even exceeding) thisobjective will be defined in the loss reduction study to be conducted bySNE vith ESMAP assistance.
3.14 This study is already planned, and is to be complemented by astudy of ways to rationalize energy consumption and conserve energy (withparticular regard to electric power), at final consumer level.
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IV. AVAULABLE HNERCY RESOURCES àliD LHCTRIC POMlR GENSRATIOU RESOURCES
4.1 The selection of generation resources to meet future poverneeds is linked to the development of energy resources in the countryand/or region. Congo possesses local sources of energy for povergeneration (i.e., hydropover, oil and gas), but it is also close to theInga hydroelectric plant, where generation capacity will considerablyexceed Zaire's needs beyond the end of this century. Fuelwood was alsoconsidered, but discarded as a possible energy source because it vouldonly contribute marginally to satisfying needs in centers distant fromforest areas distant from the SNE grid.
Hydro Sites
4.2 An inventory of the hydro sites vas compiled for the northernand central parts of the country, but has yet to be completed for thesouth. The potential projects identified could produce about 1,300 MW,or about 7.5 TWh in an average year. A hydroelectric expert thoroughlyreviewed the existing studies during a two-week mission to Congo, and theresults are contained in a separate report. Table 4.1 shows thecharacteristics of the main projects identified, and the consultant'sfinal report contains detailed results. 5/
Table 4,1: CHARACTERISTICS 0F MAIN HYIROPOWER PR0JECTS IDENT1IF IED
Project Cost Cost In bill ofProduction Power (MW) (in bil of CFAF per (MW) Cost per kWh(OWh/year) Installed Firm CFAF) Installed Firm (CFAF)
DJoué 2 90 10.0 7,0 32 3.2 4.6 35.0Imboulou 645 100.0 75,0 140 1.4 1,9 22,0Lekoulou CBouenza) 90 a/ 37.0 40 - 1.68 22.0Foulkary 388 58.5 17.5 110 1.9 6.3 28.3Scunda 6,400 1,000.0 - - - - _
Sounda (partialequlpxent) 200 60.0 40.0 80 1.33 2.0 40.0
Source: Collecte et analyse de données concernant les projets hydrauliques, R. Gulhbot,May 1988.
a/ Without extension et Moukoukoulou,
5/ R. Guilhot, Collecte et analyse des données concernant les projetshydrauliques, May 1988.
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4.3 Studies for the various projects have reached different stages,and a detailed design has been produced only in the case of Imboulou.The various characteristics, and especially execution costs as of January1, 1988, provide a sound basis for a planning study, but vill have to berefined by means of more detailed studies if the projects prove to becompetitive. A preliminary analysis has identified the folloving threeprojects to be included in the studys
(a) Dioué 2: The Djoué plant vas originally intended to have four7.5 Ni sets. Only two have been installed, as an initial stagein its development. The technical specifications presented inthe study are more favorable than those shown in Table 4.1,which are considered quite restrictive: 15 MW installed, 12 MNfira, and an average of 145 CWh per year, for the sameinvestment. It should be noted that the reservoit is adequateto provide for daily regulation, and use in meeting peak demandfrom Brazzaville.
(b) Imboulou plants This site (located about 170 km north ofBrazzaville) is quite interesting, although somewhat distantfrom consumption centers. The characteristics noted in thestudy are identical to those shown in the Tables 4 x 25 MWinstalled and 70 MW f irm. The level of pover generation isconsidered to be too optimistic, and has been reduced to anaverage of about 600 CWh per year.
Cc) Vater Regulation at Bouenza: Lack of regulation on the Bouenzaadversely affects the plant at Noukoukoulou. The projectexamined in the study consists of regulating the Bouenza bybuilding a reservoir upstream from Moukoukoulou in order toincrease the latter's firm pover (by 37 MW) and its averageannual output (by an average of 90 GWh per year). Because ofthe constraints imposed by the hydroelectric model, theregulation project is represented by a theoretical plant viththe folloving characteristics:
(i) poaer generated is equal to the output from the dam-sideplant plus the supplementary power produced inNoukoukoulou;
(ii) f irm pover is equal to the f irm pover in the nov plantplus the supplementary firm poaer from Noukoukoulou.Although not perfect, this approach meets the overallneeds of the planning study.
4.4 The other projects identified during the preliminary analysishave not been selected for the folloving reasons:
(a) complete development of the Sounda site vould result in a plantsise disproportionate to the scale of the Congolese system; and
- 20 -
(b) execution costs for Foulkary and the partial equipment ofSounda are very high.
These decisions were subsequently justified by the results of theoptimization.
Oil
4.5 Congolese oil reserves are estimated to total 150 million tons,with an output of about 6 million tons per year, much of this beingexported. About 10% of output is refined locally to meet the country'soil product needt. The follovting oil producta are used in powergeneration:
(a) gas oit, for diesel sets of lest than 4 MW. Iowever, adequatesupplies are not always available because of the quality ofCongolese crude, which is comparatively heavy. Consequently,4 MW diesel sets have not been included in the developmentstudy;
(b) medium fuel oil for large diesel sets. These have beenincluded in this study (unit size - 12 MV; investment -US$ 875/kW; specific consumption - 2,142 kcal/kWh); and
(c) heavy fuel oil for steam and eventually gas turbines if currentengineering problems are resolved. There are surpluses of thelatter two products, and they are currently exported onunfavorable terms.
4.6 The economic prices for these fuels are set in light ofconditions on the international market, their volume of supply, and theconditions under which they can be delivered to the final consumer:
(a) the economic price of gas oil is also brought into linevith the CIF price plus distribution costs (a total of aboutUS$ 26.4/Ocal); and
(b) The price of light and heavy fuel oil is equal to the POBprice plus the cost of delivery to power plants (a total ofabout US$ 11.8/Gcal).
Obviously, the sensitivity of the various options to these price levelsmust be carefully assessed.
- 21 -
Natural Cas
4.7 Congo's natural gas reserves total about 100 billion m3, andhave not yet been developed. It is beyond the scope of this study todefine economic conditions for gas production, but a preliminaryexamination of this issue is provided in a document describing Congo' senergy problems and options. 6/ One of its conclusions is that the gasreserves cannot be developed unless they are used for electric povergeneration once the condensate has been extracted.
4.8 tivwever, it should be noted that alL available information ongas is unreliable, and that the resuits of the general studies arequestionable. Only an exhaustive study of the technical and economicalaspect's of gas development can remove these uncertainties. Annex 5contains a survey of the situation prepared in 1984, but which is stillrelevant. 71
4.9 The gas-fueled pover generation units examined in this studyare 25 kW gas turbines and 100 MN and 75 MW combined cycle units:
(a) gas turbines have nov come to be regarded as a conventionalmeans of generating pover. TI'eir reliability has considerablyimproved and their MTBF (Mean rime Between Failures), which wasoriginally 500 hours, is now about 10,000 hours (somemanufacturers even claim 28,000 hours for new units). Gasturbines are characterized by a low capital cost (US$ 560 perkW installed 8/), and high fuel consumption or low efficiency(3500 kcal/kWht.
(b) Although less common, combined cycle units are based on aproven and developing technology. 9/ A combined cycle powerunit consisto of the following components:
6/ Congot Energy Assessment, ESMAP, January 1988.
7/ See also: Congo: Energy Assessment, page 47.
8/ Because the model used does not allow for the retirement ofcandidated, this cost incudes the discounted costs incurred after 15or 20 years in order to prolong the turbine's useful life to 30years.
9/ For further information on the future of combined cycle units, seethe following: for Europe, Wharton Econometrics European NationalCas Study, London, 1988; for the United States, Regional Applicationof Natural Cas-Fired Combined Cycle Power Generation, prepared byArgonne National Laboratory for Cas Research Institute, March 1988.
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(i) two gas turbines;
(ii) a heat recovery device for producing steat using theturbine exhaust gases; and
(iii) a steai turbine.
The gas and steam turbines can be coupled to a single shaftdriving one generator, or to three separate shafts, vith eachturbine driving a separate generator. Both configurations havebeen considored in the study.
The folloving are the main characteristics of combined cycleunit$*B
- a higher capital cost than gas turbines CUS$ 685 per kWinstalled);
- high efficiency (up to 502, the maximum achieved in povergeneration), with a specific consumption of 2,076 kcal perkWh; and
- modularity, when the units are coupled separately. This is acansiderable advantage for small-scale installations such asthe Congolese system.
4.10 As regards natural gas, it should be noted that there is not asingle international market, but three regional marketss North America;Burope/Africa/USSR; and Asia (Japan). Price formation is different inthese three msrkets, but increasingly experts agree that gao prices forindustrial use and pover generation muet become competitive at the burnertip vith those of other forms of energy. Proven gas reserves in Congoare too amall for it to be anticipated that the fuel can be exported andthe economic cost determined by reference to the European market. As aresult, the cost of gas has been determined in light of the follovingconsiderationss
(a) To penetrate the industrial thermal fuel market, the price ofnatural gas should be at most 802 of the economic cost of fueloil (US$ 9.44 per Gcal).
(b) The marginal cost of transporting gas by 10-inch pipe toBrazzaville (the most distant location in which povergeneration is planned) is about US$ 2.5 per Gcal. 10/
10/ This calculation is based on a Vorld Bank project, cost beingadjusted to 1988 prices.
- 23 -
(c) The onshore gas cost in Pointe Noire can be calculat d to beabout US$ 7 per Ccal, i.e., about US$ 2 per 1,000 ft . Thisvellhead price is higher than the average price for developingonshore or shallow-water resources.
It should be noted that the risk of making wrong investment decisions inthe pover sector as a result of miscalculating gas costs is reduced bythe folloving factors:
- first, if the volume of gas reserves is found to be larger,the economic coît of gas will be lover, because it vill beequal to the long-term marginal co0t of development; and
- second, the results of the study have shown that theleast-cost development strategy for the pover sector remainsunchanged as long as the price of gas remains lover thonthree times the reference price (see 7.5 through 1.7).
Slectricity Importa
4.11 Currently, the Congolese system is interconnected to theZairian system by a 220 kV line. As a resuLt of this, the Ingahydropover plant supplied over 30% of Congo's pover consumption in 1986and 1987.
4.12 The current scale and development prospects of the Inga plantfar exceed Zaire's needs. and it can supply a more or less considerablepart of Congo's future needs if both countries become avare of theeconomic advantages of this. 11/
4.13 After a preliminary examination of the possible alternatives,the Congolese authorities agreed to consider a 220 kV line from Inga toPointe Noire among the candidates for supplying Congo's future poverdemand.
4.14 Because the model used did not provide for interconnectionlines among the various means of supplying demand, the interconnectionproject vas examined by introducing a theoretical generation unit vith aninstalled capacity equal to the line's transit capacity, using as fuelthe pover supplied by Inga.
4.15 The capital cost of this unit is US$160 per kW installed (i.e.,about US$ 152,400 per km), the cost of the electric energy being equalto the cost of importing electric power from Zaire (i.e., ranging fromUS$ 28.3/Gcal to US$ 32.7/Gcal).
11/ Inga's installed pover is 1774 MV, for a current desand ofapproximately 500 MV or 600 MW.
- 24 -
Recommendations
4.16 A feasibility study should be made of the Lekoulou hydropowerproject (Bouensa river regulation). The World Bank has already madeseveral recomendations on this subject. The study should removecurrent uncertainty regarding the design of this project and itsexecution cost and, if it proves economical, should enable installedpower at Moukoukoulou to be better utilized. In addition, the plant' 8
advantageous location between the country's two main consumption centersshould help increase the stability of the system.
4.17 A study should be made of the possible development of naturalgas resources, with the folloving purposes:
(a) identifying uses to complement pover generation, because, evenif maximum use is made of gas, consumption in pover generationvould justify development of these resources only after theyear 2000 (see 6.5 belov); and
(b) determining the long-term costs of supplying gas to PointeNoire and Brazzaville.
4.18 As a lover priority, it ia desirable as recommended by thehydropover report and precedent studies to:
<a) carry out a thorough investigation and evaluation of all thepotential hydro sites, taking into account the results of thisstudy; and
(b) strengthen the station for hydrologic data measurement (seeAnnez 5).
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V. PLANNING CRITIRIA AND APPBOACH
5.1 Planning criteria are alvays difficult to determine for a studyin such a difficult operating environment as Congo. In this case, theyvere selected by comparison with accepted standards for similar systems,then adapted to allow for the constraints revealed by the optimizationmodel.
5.2 The selection of appropriate generating units for meeting poverdemand presents problems in cases when peak load is low. In general,planners are faced vith two conflicting requirements: on the one hand,to increase unit size, so as to reduce capital costs; on the other, tomaintain the system's stability. In the case of Congo, the 100 MWcombined cycle plants that were initially considered vere abandoned inlight of the initial results of the optimization and replaced by 75 MWplants consisting of three 25 MW units coupled to separate shafts andconsistent with the scale of the system.
5.3 The spinning reserve is an important operating parameter,generally enabling failures in the main unit to be managed vithout loadshedding. In order to avoid overinvestment and use the existinginterconnection vith Zaire to the best advantage, the value used in thisstudy is equal to the size of the largest unit minus 3% of peak pover.
5.4 The failure criterion-i.e., the acceptable degree of risk ofnot supplying peak load (LOLP: Loos of Load Probability)--that vas usedto analyze the generation system by means of the optimization model is 25hours per year, after maintenance. This represents a considerableimprovement in SNE's generating service quality, even though theacceptable level of risk may appear high in comparison vith biggernetvorks.
5.5 The choice of a discount rate involves trade-offs in theallocation of resources over different periode of time and, sometimes,among different sectors. For this study, the choice is all the moreimportant because the generation system vill consist of eitherhydroelectric vorks (vith a high initial capital cost and low operatingcosts) or thermal units and/or interconnection lines (with low capitalcosts and high operating costs). The difficulty of selecting a suitablediscount rate vas emphasized by the local specialists during datacollection, because of the country's difficult economic circumatances.Nevertheless, they advised that a rate of 10% be adopted, and that thesensitivity of the results be tested at 8Z.
5.6 In addition to the fuel prices already mentioned, the price oflocal labor should be replaced, according to the local specialists, by anopportunity cost between 20% and 25X lover. However, it should be notedthat this readjustment, which vas tested during the optimization, has noeffect on the choice of the best solution.
- 26 -
5.7 The planning criteria selected serve to complement the basicdata necessary for optimizing the generation system. It is essential tonote that these choices are far from being final, and that the criteriamust be studied in greater depth whenever the guidelines for for povergeneration are updated.
Approach
5.8 Identification of the optimal solution requires successiveiterations based on minimization of the total distorted costs (objectivefunction, all costs discounted to 1991, the base year for the study).Intermediate resulta of the annual simulation of generation systemmanagement are examined in detail in order to ensure the overallconsistency of the basic data and reviev the suitability of the technicalhypotheses. If needed, additional analyses or consultations vill beundertaken in order to upgrade or adapt the basic data to thecircumatances of the system in question.
5.9 The folloving approach vas adopted for the study:
(a) identification of an optimal solution for satisfying demandbased on the development of Congolese resources (referred to asthe Self-Reliance Strategy);
(b) identification of an optimal solution for developing the poversystem by including possible imports from Zaire (referred to asthe Regional Cooperation Strategy).
5.10 For each of these basic alternatives, the procedure forobtaining the optimal solution can be reconstructed as follovss
(a) Analysis of the Self-Reliance alternative:
- An optimal solution based exclusively on thermal generationvas sought, for the folloving two essential reasons:
the initial calculations showed the economic advantage ofthermal projects;
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* because computing capacity is in all cases a considerableconstraint, the optimal solution must be approached bystages, in order to keep calculation time vithin reasonablelimits. 12/
- sydropover vas included in the optimization in order toconfirm the results of the first phase.
- Certain projects considered by the Congolese Government andnot included in the optimal solution were incorporated.
(b) Analysis of the Regional Cooperation alternative:
- An optimal solution taking into account the interconnectionvith Zaire was sought, including examination of the follovingtwo subsidiary alternatives: the existing line, with andvithout a new line;
- Certain projects considered by the Congolese Covernment andnot included in the optimal solution were incorporated.
(c) Sensitivity and risk analysis.
12/ It should be noted that examination and discussion of theintermediate results from the first pass made it possible to adaptequipment failure criteria more closely to the conditions of thecountry, and abandon the option of a 100 MW combined cycle unitcoupled to a single shaft in favor of three 25 MW combined cycleuiita coupled to separate shafts (see para. 4.9).
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VI. ANALYSIS OF THE POURB SYSTE DIVELOPHT ALTERNATIVES
6.1 Ail the alternatives have been studied in light of thetechnical and economic constraints describea above and gathered togetherfor reference purposes in Annex 6.
6.2 The results shown in this section are based on the base casedemand forecast because the optimization has shown the following (see7.21 through 7.23):
(a) the level of demand does not affect medium-term investment inthe case of the Regional Cooperation Strategy; and
(b) in the case of the Self-Reliance Strategy, which is flexibleenough to permit such adaptions, the results of the base casecan be extrapolated to the low-demand hypothesis if lags areallowed for in the commissioning of the thermal units lastingabout one or two years in the 1990-2000 period and three orfour years after 2000.
Results of the Self-Reliance Alternative
6.3 In order to satisfy demand by using power generated exclusivelyin Congo, 575 MN would have to be installed between 1991 and 2015.Because of the technical and economic constraints noted, electricityvould be supplied exclusively by the following thermal unitss
(a) 6 x 75 MW combined cycle units (two sas turbines and one steamturbine--25 MW each--coupled to separate shafts);
(b) 5 x 25 MW gas turbines.
6.4 Table 6.1 shows the main characteristics of the solution.Total investment over the period (1991-2015) is US$ 378.25 million (at1988 prices), i.e., CFAF 121 billion (1988), representing an annualinvestment of about US$ 15 million (1988), i.e., CFAF 4.6 billi n(1988). Total natural gas consumption over the period is 5.3 billion m ,over 5S of Congo's reserves. The solution is presented in detail inAnnex 7.
6.5 It must be noted that, if gas reserves are developed only forpower generation, the consumption level regarded by the experts asproviding economic justification for the development of the reserves isreached only after the year 2000, even in this case, in which maximum useis made of gas.
6.6 Nowever, it must be noted that combined cycle technology is notadopted for the optimal solution if the three component units are coupled
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to a single shaft. The solution adopted in this case is purely thermal(installed powers 24 x 12 MW diesel wnits and 10 x 25 MW gas turbines),and increases the total discounted costs by about 4X.
Table 6.1: SEIF-RELIANCE STRATEGY:PRINCIPAL CHARACTERISTICS OF THE OPTIMAL SOLUTION
Category 1987 1990 1995 2005 2015
1. Peak power demand (iMW) 91 123 176 251 359
2. Installed power (MW) 157 207 276 368 493% combined cycle - - 27 41 61gos turbines 32 48 36 34 20
t hydropower 57 44 33 24 1J%diesel a/ il 8 4 1 1
3, Reserve rate 73 68 57 47 37
4. Loss of Load Probability* Before maintenance
(hours/year) il 5 3 3 3* After maintenance
(hours/year) 23 il il 17 18
5. Cumulative new Investment(in millions of iSS atat 1988 prices) 37.7 62 108 185 240
6. Consumption of Congolesegas (in millions of * ) 11.6 60 135 242 337
a/ Excluding Isolated systems.
6.7 The optimiization has shown that hydropover is not competitiveand any projects would be implemented during the study period. Thisconclusion is confirmed by the supplementary studies, which have shownthat the discounted costs become larger as the number of hydropoverprojects introduced to replace thermal generation increases andior theirconstruction dates are brought forvard. As an illustration, Table 6.2shows the results of incorporating some of the hydropower alternativesstudied, and Annex 7 shows the detailed results of an alternative thatincludes all three hydropower projects.
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Table 6.2: COOPARISON OF SOLUTIONS INCiWDIN6HY W PROJECTS WITH "SELF-RELIANCE" THERMAL SOLUTIONS
TotalDates hydroproJects discounted costs
introaduced (in mi. of USS IndexSolutions Lekoulou DJoué Imboulou at 1988 prices) (OS4C00)
Optimal strategy(CC+GT) - - - 260.5 100
Thermal (O + 1T) - - - 270.6 104
Hydroprojects 1995 2001 359.3 138replacing CC + GT 1997 - - 274.4 105
Hydroprojects 1998 1995 2002 373.2 143replacing D + ¢T 1998 1995 2006 346.4 133
2003 2006 2007 312.0 120
The results show that the alternative discounted costs range fro. 201 to50% higher. It is even morer for certain solutions not shown in thistable. Only execution of the Bouensa river regulation project would becompetitive vith thermal generation methods, alloving for theuncertainties likely to affect construction costs. The sensitivity ofthese results to the various economic hypotheses vill be examined in thenext section.
Results of the Regional Cooperation Strategy
6.8 This development strategy vas analyzed in the folloving twophases:
(a) the optimal thermal program vas modified by adding the existingKinshasa-Brazzaville line as a source of supply, instead ofregarding it as merely a standby; and
(b) the advantages of installing an interconnection line betweenInga and Pointe Noire vere studied.
Incorporation of the Kinshasa-Brazzaville Line
6.9 The existing Kinshasa-Brazzaville line uas examined as a sourceof supply limited to 50 MW, in accordance with the current agreements
- 31 -
between the two countries. 13/ The relevant technical and economiccharacteristics are presented in Annex 6.
6.10 Integration of the line as an additional pover source reducedthe discounted costs over the study period by 17%, as compared vith theleast-cost optimal thermal solution (t.e., CC + CT). The folloving arethe reasons for this saving:
(a) The reduction by 50 MW in the generation equipment that must beinstalled over the period (525 MW instead of 575 MW):
(i) 2 x 12 MW diesel units; 14/
(ii) 2 x 25 MW gas turbines;
(iii) 6 x 75 MW combined cycle units.
The capital coet over the period vould therefore be US$ 357.25million (at 1988 prices), i.e., 5% less than the solution basedon exclusively thermal generation (CC + CT).
(b) the extension of the installation schedule for severalgeneration unite from three years to five years, particularlyat the beginning of the period.
(c) The reduction of annual operating coste throughout the period,resulting in a total saving of about 7%.
6.11 Power importe from Zaire total about 965 CWh, about 2.8% of thecountry's total consumption over the period. Import coste over theperiod are US$ 27 million (at 1988 prices), i.e., CFAP 8.6 billion<1988).
6.12 Although hydropover projects vere also excluded from thissolution, the complementary alternatives that vere studied showed thatthe inclusion of hydropover to replace thermal generation would produceadditional costs equivalent to those identified in the exclusivelythermal alternative (see para. 6.7).
13/ In theory, the Kinshasa-Brazzaville line can transmit larger amountsof pover. The limit is mainly the result of the transmissioncapacity vithin the Zairian system itself, between Inga andKinshasa.
14/ These two diesel unite are kept to be consistent with the optimalsolution given by the model and presented in Annex 7. It is obviousthat if such a solution is chosen, the two diesel sets vill bereplaced by a 25 MW turbine to ensure homogeneity of the generationsystem.
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Table 6.3: COOPARISON 0F THE ALTERNATIVES INCORPORATINGHYDROPOWER WITH THE SOLUTION CO4BINING THERMAL GENERATION
WITH THE KINSHASA-BRAZZAVILLE LINK
TotalDates hydroprojects discounted costs
(in mil. of USS IndexSolution Lekoulou DJoué 2 Imboulou at 1988 prices) (OS=100)
Optimal:completelythermal+ K-B lInk - - - 216.6 100
Hydroprojects x 1995 2001 317.8 147replaclng thermal x 1995 2006 284.6 131generation 1995 x x 234.9 108Installations 1997 2001 x 253.8 117
Advantages of Installing an Inga-Pointe Noire Interconnection Line
6.13 The advantages of the Inga-Pointe Noire link vere studied inthe folloving two phasess
(a) The line's competitiveness in a Self-Reliance Strategy vascompared with diesel and gas turbine units, in order todetermine the import cost of electricity for use in theoptimization.
(b) The optimization vas carried out, in order to compare all thepossible means of pover generation.
6.14 In the first case, the Inga-Pointe Noire link vas used toreplace thermal generation at different dates and at import costs ofelectricity, ranging from CFAP 12 per kWh to CFAF 7.8 kWh (i.e., fromUSé 3.75 to USé 2.44 per kWh).
- 33 -
Table 6.4: ADVANTAGES OF THE IN6A-POINTE NOIRE LINEIN RELATION TO ITS INSTALLATION DATE AND
THE COST OF NMPORTED POWER
TotalCost of dtscounted costs
lmported pow.r (In Mei. of UqS IndexSolution (in USdkWh> (it 1988 prices) (OS a 100)
Optimal self-rellance(CC + 6T) 260.5 100
Soif-rolaence(D + 6T) - 270.16 104
2 Itnos la 1988 nd 2007 3.75 286.4 110* *lne Un 1948 3.75 273.4 1051 lino In 1998 2,81 267.5 103i lino In 1995 2.81 260.1 100
The main results (see Table 6.4 above) show that, in the cases examined,the Inga-Pointe Noire link is competitive with the thermal solutions whenthe price of imported pover is about USé 2.8 per kWh. An examination ofthe generation system simulation shows that, at this price, the saving ismainly due to the line's contribution to firn pover. The line is used asa standby interconnection, and not for pover imports, because it is leasexpensive to generate the basic pover in Pointe Noire, even usingheavy-fuel diesel units, which are the most expensive. Zaire may not beparticularly interested in such a project, because revenue vould beow. The cost of imported power has therefore been reduced until athreshold price can be set at a level at which the line can becomp etitive with base generation units. Because of the economiccircumstances assumed for this study, this threshold price is aboutUSé 2.4/kUh (i.e., CFAF 7.8/kWh).
6.15 In the second case, the optimization took account of allavailable generation/supply sources, including the Inga-Pointe Noire linefrom 1995, 15/ assuming a price for imported pover of USé 2.41 per kWh(CPAF 7.8/kIii0 for the Inga-Pointe Noire line, and USé 2.8 per kWh (CFAl9/kWh) for the Kinshasa-Brazzaville line. In this case, the optimalsolution calls for the installation of the Inga-Pointe Noire
15 This constraint is due to the time needed to carry out a detailedfeasibility study, discuss and resolve the contractual issues, andbuild the line.
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interconnection line in 1997, and the provision of 400 MW from thermalsources botveen 1991 and 2015, as follova:
(a) 4 x 25 MW Sas turbines;
(b) 4 x 75 MN combined cycle.
This solution enables demand to be met at least cost, and is the mootadvantageous economically (and also technically, as vill be seen later)s
- Total discounted cost. are 22X lover than in the best Self-Reliance solution, and 6X lover than the solution incorporatingonly the existing Kinshasa-Brazzaville line.
- Capital costs are about US$ 85 million (CFAP 27 billion) less thanthe Self-Reliance solution, and US$ 64 million (CFAl 20 billion)leso than the solution incorporating only the Kinshasa-Brazzavilleline.
- Discounted operating costs are about 15 lover than theSelf-Reliance solution, and 3X les. than the solutionincorporating the Kinshasa-Brazzaville line.
6.16 Table 6.5 shows the main features of the solution. Totalinvestment over the period is US$ 298.5 million (at 1988 prices), i.e.,about CPAF 96 billion (1988). This i. an average annual investment ofUS$ 11.94 million (1988), i.e., CFAP 3.82 billion (1988). Moreimportantly, medium-term investment (1991-2000) is reduced by over onethird. Pover importe are 7 TWh, or 201 of total consumption over theperiod. 951 of importe are transmitted via the IpSa-Pointe Noire line.Finally, natural gas consumption is 3.5 billion ma. Annex 7 contains adetailed description of the solution.
6.17 It should be noted that:
(a) 80% of the savings obtained through the Regional CooperationStrategy appear at the beginning of the period, i.e., beforethe year 2000. Consequently, they are less likely to beaffected by the long-term risks arising in demand forecastingand changes in the economic and technical environment; and
(b) additional computer runs showed that if the line could bscommissioned in 1992, it vould have been selected firat, andthe firet gas turbine vould have been delayed until 2002 andthe second one until 2005. Total discounted costs vould bsmore than 5X lover.
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Table 6.5: REGIONAL COCPERATION:MAIN CHARACTERISTICS OF P£E OPTIMAL SOLUTION
Category 1991 1995 2000 2005 2010
1. Peak load (MW) 91 123 176 251 359
2. Instelled power (MW) a/ 134 159 151 243 343Coibined cycle ($) - - - 20 44Gas turbines (S) 19 31 33 41 29Hydro 66 56 59 37 26Diesel (%) b/ 1S 13 8 2 1
3. Fallures after maintenance(LOLP) (hours/year) 4 il 2 il 18
4. Reserve rate (S): A considerable factor, If the lines trans-mission cepacity 1a token Into account.
5. Cumulative new investuent 16 52 n3 139 221(in millions of USS et1988 prices)
6* Power Imports (GWh) 27 133 415 318 253
7. Gas coonsumption 0.5 2.6 1 160 290(in millions of M)
ai In addition to Installation of the inga-Pointe Noire fine ln 1997.
bl Excluding Isolated systems.
6.18 As with the other alternatives, the hydropover projectsexcluded in the optimal solution were incorporated into the ocheme assubatitutes for thermal generation, and it vas also tested with andvithout postponement of the installation of the Inga-Pointe Noire line.
- 36 -
Table 6.6: COIMARISON CF SOLUTIONS INCORPORATIN3HYCRCPOMER WITH T1HE OPTIMAL "IEGIONAL COOPERATION" SOLUTION
Datelu et whichInge- hydroower projects Objective function
Pointe Noire Incorporated (In mil. of USS IndexSolution lino Lekoulou Djoué Imboulou et 1988 prices) (OS * 100)
Optimal:RogionslCooperetion 1997 - - - 202,4 100
Hydropowerprojectsreplac 1gCC + OT 1997 1997 2002 2011 231t2 114
2000 1997 2007 2011 242.4 1201997 2002 - - 211.7 105
6.19 Table 6.7 shows that hydropover projects (as in the otheralternatives) generate additional costs ranging from about 15X to 20%when all three are incorporated and/or when installation of theInga-Pointe Voire line i8 postponed until after 1997. It should be notedthat the additional costs are smaller in this alternative because thehydropover projecte (particularly Imboulou) can be introduced only at theend of the period, as a result of installation of the line in 1997.
- 37 -
Table 6.?: SUMMARY OF ANALYSIS OF ALTERNATIVES
IndexTotal (Loast-
Discounted costCosts (in solution
Solution Summary Descrlption m11. of USS) * 100)
1. "Regional Cooporation,"with K-8 and l-P linos
* I-PN able to be Installation of Inga-Pointe Noire 202.4 100commissioned fro 1995 lino ln 1991, plus 4 x 25 MW GT
end 4 x 75 MW CC
* I-PN able to be Installation of Inga-Pointe Noire 192,0 94oummissioned from 1992 line In 1992, plus 4 x 25 MW GT
end 4 x 75 MW CC
2. "Roglonal Cooperation," lmports via oxlsting K-B lino, 216.6 107with K-3 lino plus 2 x 12 MW D, 2 x 25 MW BT,
and 6 x 75 MW CC
3. "Soîf-Rollance," with Installation of 6 x 75 MW CC 260.S 129combined cycle units and 5 x 25 MW BT, wIthout
power lmports
4. "Self-Reulance," vithout Installation of 24 x 12 MW D 270.6 134combined cycle units and 10 x 2S NW GT, without
power Imports
Conclusions of the Optimisation
6.20 Progressive examination of the development alternativesavailable co the Congolese system has shown the folloving:
(a) the Self-Reliance alternatives are more expensive than theRegional Cooperation alternatives (see Table 6.7)>
(b) if the line Inga-Pointe Noire can be installed earlier than1995, it vould be more coset-effective to install it in 1992instead of the two gas turbines, and the total discounted costsvould be reduced by more than 5%;
- 38 -
(c) the new electric pover plant£ are thermals 25 NU gas turbinesand 75 MW combined cycle units consisting of three 25 MWsets. However, the diesel sets (12 MW and 18 MW, operating onheavy fuel) are nearly competitive vith the combined cycleequipment included in the optimal Self-Reliance solution. Iftheir use is justified by local conditions that have not beentaken into account, the additional cost is about 42.
(d) under the technical and economic conditions assumed, hydropoverprojects are not included in the optimal solution. In allcases, their early execution increases the discounted cost perkWh by the folloving amounts:
(i) between 4% and 8%, if the Lekoulou project alone is usedto replace other forms of generation;
(ii) between 142 and about 50X or more in all other cases.
The additional cost increases with the number of projectsintroduced, and/or the earlier the project execution dates arescheduled.
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VII. U 8RK ANAYSIS AUD DBVEYOPNBUT STRATU
7.1 The vhole analysis contained in the preceding section vasprepared according to assumed future conditions. However, riaka arisingfrom possible changes in demand and future economic circumstances areinevitable, however refined the projection methodology may be. Anyinvestment decision is a "gamble on the future," and economic risks mustbe minimized. Consequently, the analysis of economic risks inherent indeveloping the Congolese pover system consiste of the folloving threephasess
(a) a study of the solution's sensitivity to changes in theselected parameters;
(b) assessment of the possible economic loss ('regrets') affectingthe various development strategies in the case of large andunforeseen economitc and technical changes;
(c) an analysis of the risks arising in demand forecasts.
Sensitivity Study
7.2 The optimal solution is dependent in all cases on the assumedtechnical and economic conditions (see Annex 7). It is thereforeessential to test this solution to see whether it is robust enough tovithstand any changes that may affect the basic data. These studies areperformed by changing the value of one variable (other items remainingthe same), and observing the impact of the change on the follovingaspects:
(a) the composition of the generation system, if the model ispermitted to change the optimal solution;
(b) the objective function, if the optimal solution is imposed onthe model.
Cost of the Inga-Pointe Noire Line
7.3 The cost of the Inga-Pointe Noire line vas multiplied by afactor of between 1.5 and 5, and the total discounted costs of thesolution vere then compared vith the other development alternatives.
7.4 The results show the folloving effects on the solutionincorporating the Inga-Pointe Noire line:
(a) it remains the least expensive solution, provided that the costof the line is less than US$ 59 million (at 1988 prices), i.e.,1.85 times the assumed cost.
- 40 -
(b) it becomes equivalent to the solution consisting of thermalgeneration plus the Kinshasa-Braszaville line if the cost inUS$59 million (at 1988 prices).
(c) it does not raise the total discounted cost above the level ofthe exclusively thermal Sfelf-Reliance solutions unless its costexceeds US$ 180 million (at 1988 prices), i.e., more than fivetimes the basic execition colt.
Cas Costa
7.5 The sensitivity to gas prices of the various solutions vasstudied in two ways; first, by allowing the model to substitutehydropover projects for thermal units; and second, by changing the coltof gas in the optimal solution and also in an alternative that includedhydropover projects and capacity. The objective functions for each casevere compared.
7.6 The results are consistent, and show that hydropower projectsare competitive vith gas thermal units only if the price of gas is overUS$ 27/Gcal, i.e., 2.9 times the assumed price.
7.7 This result in extremely important, because it shows that thesubstitution of heavy fuel, or even lighter products, for gas incombustion turbines if gas suRplies are unavailable does not makecombined cycle units and combustion turbines any less competitive withhydropover projects. Moreover, in viev of the currently foreseeablelevelas of hydrocarbon price rises, th<, trade-off that has to be made isbetween locally generated and imp,rtsd pover on the one hand, and theappropriate proportions of combined cycle and gas turbine generators, onthe other.
Costa of Hydropover Projects
7.8 Because in general there is considerable uncertainty regardingthe execution costs of hydropover projects, particular care vas given tostudying the sensitivity of the various solutions to changes in theexecution conts of the hydropover projects. The model vas permitted toincorporate hydropover projects at different dates and with differentcapital costs, the project capital costs for various solutionsincorporating hydropower vere reduced, and the results vere compared withthe objective functions for the various optimal solutions.
7.9 The results are consistent, and indicate the follovings
(a) The Imboulou and Djoué 2 projects are competitive vith theother generation/supply arrangements only if their executioncosts are 502 lesa than the assumed cost.
(b) The Lekoulou project (i.e., the regulation of the Bouenzariver) is competitive vith other generation/supply arrangementsonly if the execution colt is 27Z less than the assumed level.
- 41 -
7.10 Hxisting studies indicate that reductions in execution costeare impossible in the case of Imboutou and highly unlikely in the case ofDjoué 2. Neverthelesst the regulation of the Bouenza river could stillbe an attractive project to study, because the current estimate of theexecution cost could conceivably be reduced by a considerable amount.Similarly, a snall additional cost in the project at generation levelcould be offset by savings in the transmission system, as a result of thesite's favorable location between tvo important consumption centers.
Economic Loss ('Regret') Evaluation
8conomic Risk Analysis
7.11 The economic riska to the Regional Cooperation alternativeresulting from unforeseen changes or the occurrence of an unexpectedevent are quantified in terms of economic loss, i.e., the discountedcosts additional to those of the original (least-cost) solution. Twosuch cases vere studieds
(a) a doubling of electricity prices after installation of theInga-Pointe Noire line; and
(b) an interruption of supply in the year 2005.
7.12 Table 7.1 shows the economic losses resulting from theseevents, for the two alternative demand scenarios.
Table 7.1: ECOtOMIC LOSSES: DOUBLING OF POWER PRIOEOR INTERUJPTION OF S"PPLY
(US$ million)
Averge MNximumBase Low economic economic
Event demend Demand loss loss
Conditions assumed Ia study O O O ODoubilng of power price 42.2 26.5 34.4 42.2Supply Interruption 24.2 26.9 25.6 26.9
7.13 The economic losses associated with such events must becompared with the additional costs inherent in alternative strategiesthat may be preferred by decisionmakers because they offer a means ofavoiding such risks. Although these additional costs are calculated inthe sane way as leconomic losses," they are interpreted differently fromthe economic viewpoint. They represent an additional cost accepted bythe decisionmaker in order to avoid an unacceptable risk.
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Table 7.2: AODITIONAL COTS 0F 1HREE ALTERNATIVESTRATEGIES OC"ARED WITH TRE PROPOSED SOLUTION
(USS millIon)
Average M bxumStrstgy Ebse Ommnd Low Demmnd econo.lc loss economic los$
Hydropower strategy:liboulou mnd DJou6 157 >157 >157 >157Lekoulou 72 >72 >72 >72
Therual strategy 58.1 57.8 58 58.1
7.14 A comparison of these two tables ohows that the economic losses(i..e, long-term coste) associated vith unforeseen events affecting the"Regional Cooperation" strategy that includes execution of theInga-Pointe Noire line are smaller than the additional costs incurred inavoiding them. This shows that the solution is attractive and 'robust,"and is, in fact, the best choice for meeting pover demand at leastcost. Its execution requires choices to be made and poses institutionalproblems that vill be discussed later.
Technical Risk Study
7.15 Like almost all the optimisation models that are applied topover generation investment, the ELECTRIC (VASP) model excludes thetransmission network, which is assumed to be capable in all circuastancesof alloving for the pooling of all generating systems in order to satisfytotal demand (i.e., generation and demand are concentrated on a singlenode).
7.16 Although this hypothesis is perfectly acceptable in the case ofmeshed networks, it may involve "technical uncertainties" in the case ofCongo, where the main consumption centers are connected to the generationcenters by simple links.
7.17 In order to remove these uncertainties, a simple networkanalysis must be made in order to ensure that supply is sufficientlyreliable, particularly in the cases of Brassaville and Pointe Noire.This vas done by using a very simple method, consisting of calculatingthe coverage rate for the load in the system as a whole and in each ofthe centers, in the event of failure of the main supply source (i.e.,the single contingency criterion). As an example, Table 7.3 shows the
- 43 -
calculations for the Regional Cooperation solution incorporating theInga-Pointe Noire lino. 161
Table 7.3s SINGLE CONTINENCY CRITERION: LOAD COVERAGE INTHE "REIOINAL COERATION" SOLUTION INOOW0MTING 1}E INGA-POINTE NOIRE LINE
Peak demand I nsto I led Power Coverage rate(NW) Pointe Noire Brazzov IIe lsîngle cootingency)
Total b_Inter- Moukou-
Brazza. P. Noire connected 0002 GT25 I-PN koulou GT25 Kinshasa Total Total PN BrazzaYear Node Node Notwork D004 CC7? Lino a/ DJoué 1 CC75 Inter. MW (<i) (S) <>
1991 45 37 91 18 25 24 15 50 132 90 100 1001992 47 39 97 85 90 1001993 51 42 104 79 74 1001994 54 44 il 25 157 96 100 1001995 60 47 123 87 100 1001996 65 50 132 81 84 1001997 70 54 142 200 357 111 100 1001998 75 58 153 12 351 99 100 1001999 81 62 164 92 100 1002000 87 67 176 86 95 1002001 93 72 189 80 80 1002002 100 77 203 8 50 372 85 93 1002003 107 83 218 50 397 90 100 1002004 115 90 234 4 75 418 93 100 1002005 123 97 251 75 443 97 100 1002006 133 102 271 90 100 1002007 143 111 291 100 468 92 100 1002008 154 120 312 100 493 94 100 1002009 160 129 33S 125 518 95 100 10021O0 177 140 359 125 543 96 100 1002011 190 151 386 150 564 94 100 1002012 103 162 413 150 589 94 100 1002013 217 174 442 175 175 639 99 100 1002014 233 187 474 200 664 98 100 1002015 250 201 506 225 200 714 101 100 100
a/ For power.
b! Hypothesîs: prîorîty supply for Brazzaville provîded that lood for PoInte NoIre Is over SO.
16/ It should be noted that, while this method is adequate for the needsand objectives of this study, a more detailed analysis of thetransmission network is necessary, and could be carried out as partof the feasibility study of the Inga-Pointe Noire line.
- 44 -
7.18 These results show that, vith a proper distribution of thermalunits between Brazzaville and Pointe Noire, coverage of total loadaccording to the single contingency criterion is in general over 902,except for certain transitional years. The results are consistent viththe 0.285 failure probability at generation level. If the singlecontingency criterion is applied, the coverage rate by consumption centeris sometimes lover, but service security at the beginning of the periodcould be brought to an acceptable level by bringing forvard theinstallation of a gas turbine or the Inga-Pointe Noire line. Hovever, ithas already been shown that installing the line earlier reduced theobjective function (see para. 6.17(b) and 7-20(b). Consequently, theRegional Cooperation solution that includes the Inga-Pointe Noire lineminimizes the "technical uncertainties" and enables reliable service tobe provided in accordance with the single contingency criteriont and atan acceptable risk level, particularly because the Kinshasa-Brazzavillelink is capable of transmitting more than 50 MN and compensating forfailures in the Inga-Pointe Noire line.
7.19 The Self-Reliance solution using exclusively thermal generationalso provides good coverage according to the single contingencycriterion, but the "Self-Reliance" solution incorporating hydropover canprovide equivalent service only at the cost of the Imboulou-Brazzavilleline installation, and the capital cost would be over US$ 25 million at1988 prices.
Demand Uncertainties
7.20 Uncertainties relating to demand involve economic riaksassociated vith the development of the pover system, particularly vhenthe construction period of generation unita is long and/or their size iSlarge compared to the peak demand. However, the risk is small in thecase of thlê least-cost solutions for the Congolese pover system, for thefollowing two reasons:
(a) the construction time for the thermal equipment is about two orthree years, and the installations can also be developed on amodular basis in order to match demand increases. The maximumeconomic loss (i.e., the long-term cost of a wrong decision) isequal to the coat of advancing the installation of a gasturbine or a 25 MW combined cycle module by one or two years atthe beginning of the period (about US$ 1.7 million at 1988prices);
(b) the Inga-Pointe Noire interconnection line offers adv"ntages,and, in both demand scenarios, the savings are larger theearlier the construction date is scheduled. If the Inga-PointeNoire line could be brought into service in 1992, the totalcosts of discounted pover generation over the period--would bereduced by about 62 in the base case and over 3X in thelow-growth case.
- 45 -
7.21 The analysis of the risk of failure in a major supply source-particularly the Kinshasa-Brazzaville line at the beginning of theperiod-has demonstrated the need to install two gas turbines in PointeNoire or the Inga-Pointe Noire 220 kV line no later than 1992, even inthe low-demand scenario.
7.22 The same analysis vas applied to a 42 increase in deaandbetween 1987 and 2000, a consumption level 8S lover than the basehypotheois in 1995 and about 18X lover in 2000. The results confirmedthe need to install two gas turbines or the Inga-Pointe Noire line in1992 in order to ensure a reliable supply for the entire system,particularly for Pointe Noire in case of a failure, during the dryseason, in the Kinshasa-Brazzaville line at the beginning of the period.
Results of the Risk Analysis
7.23 The sensitivity studies, supplemented by studies of theinstallation costs for the thermal units, discount rates, etc., haveconfirmed that the optimal solutions vould renain stable even if theassumed technical and economic conditions changed.
7.24 The most important conclusion is that hydropoverprojects--either those studied, or any other potential projects-are notcompetitive vith other sources of pover serving the interconnected systeaunder either current or anticipated technical and economic conditions.Only the project for regulating the Douenza river could help meet demandat an economically acceptable cost, provided that the project'spreliminary feasibility study confirms that the capital cost, ascurrently assessed, could be reduced.
7.25 Risk analysis has confirmed that the Regional Cooperationsolution is robust and offers advantages over the alternatives, because,even if supply conditions change in e way that is not economicallyjustified or is a result of technical problems not anticipated in thestudy, the resulting economic losses vould be less tlun the additionalcosts involved in the "Thermal Self-Reliance" solution, and thusnecessarily less than the cost of a solution based on the development ofImboulou.
7.26 A demand increase even lover than that of the lov-growthscenario does not affect the decisions on generation units equipsentnecessary in the medium term ti.e., from five to seven years) forsatisfying demand at an acceptable level of reliability, especially atPointe Noire.
- 46 -
VIII. IZUSVIIHET DCISIONS AND PROtLENS REL&TUDTO TIRU LU AION
8.1 Analysis of the various alternatives for supplying the existinginterconnected system has led to the identification of the least-cost andleast-risk solution for satisfying medium and long-term demand. However,it should bc noted that investment decisions muet be taken only for themedium term, i.e. a period lasting between f ive and seven years andnecessary for the study and implementation of power projects. Wheninvestment decisions have to be adapted to specific conditions, thedivergence from the optimal solution must be as amall as possible (i.e.,to produce the "second-best solution").
Investment Decisions
8.2 To meet medium-term demand on the interconnected grid, thefollowing two investment alternatives are possible:
(a) installation of Inga-Pointe Noire after 1995:
Ci) installation of two 25 MW gas turbines in 1992,preferably in Pointe Noire; and
sii) installation of a 220 kV line from Inga to Pointe Noirebefore 1997.
(b) installation of Inga-Pointe Noire in 1992:
Ci) installation of the 220 kV line from Inga to Pointe Noirein 1992; and
(ii) installation, according to the demand increase and theneeded quality of service, of two gas turbines between1998 and 2002.
These decisions diverge very little from the optimal solution, and arejustified by the objective problems of preparing studies for a gasturbine plant or a 220 kV line and installing it, even on an existingsite, in less than three years, and by the need to improve servicereliability in Brazzaville and Pointe Noire in the event of the failureof a major supply source (i.e.t the single contingency criterion).
8.3 Table 8.1 shows the improvement in supply conditions under thesingle contingency criterion compared with the optimal solution(calculated on the assumption that supply and demand are concentrated atone point).
- 47 -
Table 8.1: SUPPLYINS OENANO ACCORIN TOTIE SINGLE 0ONTINGENCY CRITERION IN LINE WITH INVESTMENT OECISIONS
Peak de.and Installed Power Coverage rate(14W> Pointe Noire Brazzaville (single contlngency
Total hiInter- Noukou-
Breua. P. Noire connected 0002 GT25 I-m koulou GT25 Knashasa Total Total PN BrazziYear Nbde Node Network 0004 CC75 Line a/ DJou& I CC5 Inter. M1 (%> (S> (S>
1. Co<msslonina of Inga-Pointe Noire In 1997
1991 45 37 91 18 24 15 50 107 63 49 871992 47 3 97 50 157 110 100 1001993 51 42 104 103 100 1001994 54 44 il 96 100 1001995 60 47 123 87 100 1001996 65 50 132 81 84 100199? 70 54 142 200 357 111 100 100
seotly: As for optimal solution
2. Comissioninp of Inga-Pointe Noire In 1992
1991 45 37 91 18 24 15 50 107 63 49 871992 47 9 97 200 307 110 100 1001993 51 42 104 103 100 1001994 54 44 il 96 100 1001995 60 47 123 87 100 1001996 65 50 132 81 84 1001997 70 54 142 200 307 75 69 100Subsoquently: As for optimal solution
et Fire poer.bk Hypotheels: priority supply for Brazzaville provided that lood coverage for Pointe Noire is over 50.
The above results indicate the following:
(a) in 1991, demand cannot be met in the event of a failure of theBrazzaville-Kinshasa line during the critical period ofoperations (i.e., vith reduced pover at Noukoukoulou). Sincegenerating resources vill not be deployed at that date,measures for maintaining operations in such an eventuality villbe recommended subsequeantly.
- 48 -
(b) once the two 25 MW gas turbines have been installed in PointeNoire, demand--both total and in individual centers--vill beproperly met, even if the single contingency criterion isapplied, until the 220 kV Inga-Pointe Noire line is broughtinto service (i.e., between 1995 and 1997); and
(c) in the case where installation of the Inga-Pointe Noire lineis possible in 1992, demand--both total and by individualcenters--vill be properly met during all the study period vithno contingency and until 1995/96 if the single contingencycriterion is applied. The thermal generation units should bebrought forvard to meet the demand in the case of a singlecontingency during the study period.
Particular Problems Relatina to the Implementationof Investment Decisions
8.4 Technically, installing the gas turbines presents no particulardifficulties, except that the engineering design study must examine theproblems arising from the use of fuel oil (or lighter products) and gas,because it is still uncertain whether gas can be obtained at acompetitive price.
8.5 In addition, because this is a neo generation technology for8MN, the enterprise must pay particular attention to the training ofoperators. Although gas turbines can nov be considered a proven means ofgeneration, 8NE muet give special care to operating problems andtraining. In viev of the introduction of this nev technology, SN8shoulds
(a) learn from UPD8A countries' experiences, in order to avoid"teething problems" with the equipment;
(b) arrange for the constructor, or enterprises possessing the sameequipment, to provide thorough training for operators.
8.6 As regards the Inga-Pointe Noire line, the feasibility studyshould pay particular attention to contract dravinge, the legal andinstitutional problems related to project implementation, and theconditions under which it in to be operated.
8.7 The folloving three alternatives might be considered forsupplying Pointe Voire from Inga (see folloving map):
(a) Inga-Pointe Noire (210 km): this alternative (included in thestudy) requires the installation of a 210 km line from Inga toPointe Noire through Cabinda (Angola). This is the most directroute for supplying Pointe Noire exclusively and providing aservice quality acceptable even under the single contingency
- 49 -
criterion. However, it would have the disadvantage of crossinga country that may not be interested in the project.
(b) In8a-Moanda-Cabinda-Pointe Noire (290 km): as pover demand inPointe Noire vill be less than 100 MW until 2005, the economicadvantages of the line can be increased by exporting power toCongo through a line supplying the Moanda industrial area inZaire and providing a standby supply for Cabinda, Angola. Thisvould have the advantage of directly involving each of thethree countries in the project. It should be noted that thisalternative offers advantages over the Self-Reliance solution(see 7.3 and 7.4 above), even though capital conts would beabout 40% higher than the preceding alternative.
(c) Inga-Loudima-Pointe Noire (180 km): the main advantage of thisalternative is that it simplifies institutional and legalproblems by limiting the project to the two most directlyinvolved countries. However, the immediate saving in capitalcosts (about 15%) does not mean that this solution is moreeconomical than the others in the long term, since in order toprovide an equivalent service quality for Pointe Noire, it villeventually be necessary to bring forvard the installation ofthermal generation facilities, or double the Loudima-PointeNoire link, the operation of which is already posing a numberof problems for SNE.
8.8 The Congolese and Zairian systems have been linked for severalyears, and this interconnection has operated vithout any major legal orcontractual problems. This experience vill certainly benefit bothcountries if the decision to install a line from Inga to Pointe Noire istaken. However, som. new problems vould arise, particularly if Angola isbrought into the project, and these should be subjected to an exhaustiveand detailed examination; this is, however, beyond the scope of thepresent study. The alternatives to be studied depend on the financingcapacities of the pover sector operators in the countries concerned, andalso their capacities for operating and maintaining the vorks. Suchvorks could be executed in the folloving wayst
(a) by the national pover enterprise of one of the countriesconcerned;
(b) by the national pover enterprises of the countries concerned,acting jointly (each executing the section on its ownterritory, or else by establishing a joint venture); and
(c) by one private-sector enterprise, either froe the countriesconcerned or elsewhere, which would buy pover from SNEL (Zaire)and sell it to SNE (Congo).
50 -
Whichever alternative is selected, the operator muet be assured of accesato the line for maintaining lt and taking prompt action la the case ofany failure.
8.9 Upon initial examination, the length of the line and the poverto be tranemitted do not appear to prenent any technical problems.Hovever, the feasibility study muet carry out simulations of the twosysteas when operating normally and when affected by major probleus, andverify that the two interconnected systems remain stable. These studies,together with the past experience of the tvo countries, vill provide thematerial necessary for establishing the rules and contractual dutiesapplicable to operations.
Enviroumental Impact
8.10 The enviroamental impact of the recommended investmentdecisions is amall compared with the other alternatives, for thefolloving reasonsS
(a) the Inga-Pointe Noire line crosses a region that is not dens.lypopulated;
(b) deforestation resulting from installation of the lin. isinsignificant compared to the scale of forest resources in theregion, and is insignificant compared vith the impact offuelwood demand;
(c) compared vith the "Self-Reliance" solution, exhaust gases (80,,N 0 , CO and 002) and particulate emissions are low because onytwo gas turbines are to be comissioned before the year 2000.In the longer term, the introduction of combined cycletechnology, the use of natural gas, and technologicalimprovements vould allow the most stringent environumentalprotection standards to be met; and
(d) the proposed solution in preferable to one incorporating theImboulou project, because the reservoir may interfere vith thenormal drainage of the groundwater table (vhich is only 1 mbelow grouad level) and turn the land around the village ofBwanbi into marsh, necessitating the relocation of its 400inhabitants.
8.11 Neasures should be adopted for solving the problems likely toarise before installation of the nev generation facilities, especially inthe event of a failure of the current interconnection vith Zaire, by thefolloving memnss
(a) performing preventive maintenance on the generation andtransmission facilities, in order to ensure their maximumavailability during critical periods;
- 51 -
(b) studying and establishing a load shedding plan so that anymajor problem can be solved vithout the system collapsing.
8.12 If ;he Inga-Pointe Noire line cannot be installed in the early1990s, specifications should be prepared and an invitation to bid issuedfor the installation of two gas turbines at Pointe Noire, either on anexisting site or one soon to be ioentified.
8.13 A feasibility study should be launched for a 220 kV line tolink up with Pointe Noire, after preliminary consultations among thethree countries likely to be involved in the project. This study shouldclarify all the legal and institutional aspects of the execution of thevorks, so that the agreement among the countries can be drawn up.
8.14 Because the generation and network investment plans must bereviewed annually, and long-term development studies muet normally bereviewed every five years, the planning function for the pover systemmuet be organized by adopting the folloving measures:
(a) clarifying the responsibilities of MME and SNE, the Bank havingalready submitted relevant proposals;
(b) establishing a amall centralised unit in SNE to prepare studieson the development of the generation systm and the network; itshould be responsible for the technical and economic analysesnecessary for investment decision-mak'ffli
(c) assigning two or three engineers/ecor.,mists to the planningunit; they should be trained in load forecasting and networkplanning;
(d) providing the unit vith optimization modela for the generationsystemi, and network modela that can be operated onmicrocomputers; for example, MME and/or SNE could be furnishedvith the model used in this study, at the Government's request
(e) regularly collecting data for the development of the powersystem and checking their reliabil.ty; this is essential inorder to offset the inadequacies identified during datacollection, and requires the establishment of a statisticalsystem integrated with SNE's varlous functions; and
(f) obtaining external support to assist in launching theseactivities, in the form of technical assistance, specializedcomputer and software material, short courses and exchanges ofexperience, etc.
8.15 As already noted in 1.5 above, development of the power systemis linked to the strengthening and upgrading of the sector' 8institutional, technical and human resource aspects, many suchrecommendations having already been presented by the Bank and ESNAP.
- 52 -
Certain of these recomuendations have already been implemented, andothers are being studied. The only recomendation to be reiteratedhere-because of its importance--is that a tariff study should beprepared once the development strategy has been adopted, in order toestablish a system vith the folloving characteristics:
(a) a simplified structure reflecting the cost of supplying pover,so as to match the needs for efficiency at consumer level andat community level; and
(b) price levels such as to enable SUR to mobilize resources fordeveloping the sector.
- 53 -
IX. LECTRIVICMTIOI OF fiGIONS NOT SUPPLIED BY TUE I lTHRCCOUNECTD MEID
Current P"sition
9.1 Outside the areas served by the existing interconnected system,there are 20 centers in which pover is produced solely by dieselgenevators vith a pover per unit generally lover than 300 kW. They areoperated aither by SUE or by private entrepreneurs. The pover isdistributed over small-scalq LV networks.
9.2 In these centers, service is somewhat precarious and generallylimited to a few hours per day. , This has strengthened the belief thatimproved electrification in existing centers and the electrification ofnew center is possible only if the UV system is extended northward.Hovever, extension of the 220 kV network tovard the north of the countryin order to satisfy such a very low demand cannot be economicallyjustified, especially since the Imboulou hydropover project has proven tobe uncompetitive vith other sources of supply.
9.3 A 1981 inventory of the hydropover potential in the centerand north of the country identified a number of sites suitable for verysmall-scale hydropover installations vith povers ranging from 0.5 MW to5 MW. Of about 50 sites vith varying degrees of potential, a certainnuuber that vere considered promising vere made the subject of one ormore development studies. The results of studies on the Adinga, Indoumaand Assoumoudele sites are presented in Table 16.
9.4 There is a vide range of costs (particularly in the case ofAdinga), for the folloving reasonss
(a) the degree of precision in the topographic vork and leveling;
(b) the investment rate (between 1.5 and 0.3/module); and
(c) the degree of sophistication in the installations.
9.5 Aside from the technical quality of the proposed installations,it should be noted that the cost per kWh in these studies is calculatedon the assumption that all the pover that the facilities are capable ofproducing vill be sold, the implications being as follovss
(a) that, as soon as the hydropover plant begins to operate, demandmatches the pover that can be produced; and
(b) production can be perfectly adapted to daily and seasonalchanges in demand.
9.6 The 8ank's experience in several coantries shows that thesehypotheses are unrealistic for saall run-of-the-river plants supplying
- 54 -
isolated systems. Investment decisions taken by comparing costscalculated in this way vith the colt of diesel generation, or bydetermining a project's cost/benefit ratio uuing these hypotheses, villnot necessarily lead to the choice of the least-cout electrificationsolution. 17/
Table 9.1: TECHNICAL AND EMMOMIC SPECIFICATIONS OF1HREE VERY SMALL-SCALE HYDROPOIER PROJECTS
Installed Average Turbine Investment SpecIf c CostsPlant/ Power CapbilittY: Head Rate In mil. of CFAF US5/kW USd/kWhAlternative <kW) GWh/yr. (m) (m3s) et 1987 prices) Installed a/
Study A 1981 2,60n 19.7 6 70 13,600 16,346 23.46Study B 1982 564 4.37 4 20.4 3,150 17,453 24.30Study C 1984 S,100 13.5 7 90 6,100 3,738 16.06Study D 1987 2,200 14.6 7 38 2,200 3,125 5.41
Indouma
Study A 1981 1,400 10 19 9.6 4,837 10,797 16.5SStudy 8 1984 1,740 7 19.5 7.5 3,307 5,939 16.44Study D 1987 990 4.5 26 4.8 1,732 5,467 13.43
Assoumoudele
Study C 1984 1,500 3.5 45 3 2,600 5,417 25.94
a/ Hypotheses:
- Annuel operating end maintenance coste; UMS 24/kW . 0.5% (Investment).- Annuel capital cost: 10.23% (investuent) a bo1ual payents over 40 years, et 10%.- AI power gmnereted con be consumed.
Source: Roger Gullhot, Etude de planîficetion du r6seau du Congo: Collecte et analysedes données concernant les projets hydrauliques, June 1988.
17/ Set Vorld Bank Bxperience vith Minihydro in Malaysia and Indonesia,, Energy Development Information Note No. 10, June 1988
- 55 -
Elements of an Electrification Strategy
9.7 Although it is an investment project of national significance,the economic viability of the electrification of areas vithout a powersupply muet be ensured through stringent planning and the selection ofthe solutions that are least expensive to the community.
9.8 The preparation of an electrification strategy is beyond thescope of this study, but it is useful to identify the items to beconsidered in the adoption of any strategy consistent vith thedevelopment of the interconnected system.
9.9 The preparation of an electrification strategy consiste of thefollowing three phases:
(a) a survey of the centers to be supplied;
(b) a study of demand, by center or "cluster" of centers to besupplied; and
(c) a study of supply alternatives.
9.10 A survey must be made of the centers in order to provideeconomic, demographic, sociological, climatic and other data for theotudy of demand, and in order to provide an inventory of local resourcesfor power generation.
9.11 The demand study must not be limited to medium and long-termpover consnumption forecasts. Information on daily and seasonal aspectsis essential for ensuring reliable and least-cost supplies.
9.12 As in the case of the interconnected system, the least-costsupply solution is identified from among all possible alternatives byselecting the one which minimizes discounted costs, a rate being usedthat is equal to the local opportunity coat of capital.
Recommendations
9.13 A national electrification plan should be prepared determiningpriorities, means, financial resources and the institutional frameworkfor extending and developing power use, on the basis of itscompetitiveness vith other forms of energy.
9.14 It vill be necessary to clarify the institutional framework ofthose local cooperatives and private entrepreneurs, both Congolese andnon-Congolese, concerned with the generation/distribution of electricpover, on the basis of experience from projects currently beingnegotiated. This vill permit the mobilization of additional financing tocomplement the government contribution, and the reduction of theoperating and management constraints faced by SNE in auch amall centers.
- 56 - Annex 1Page 1 of il
TUS MS?P NODEL FOR ELECTRIC GINERAUIO0 18/EXPANSION ANALYSIS
Introduction
1. The Vien Automatic System Planning Package (WASP) vasoriginally developed by the Tennessee Valley Authority (TVA) and OakRidge National Laboratory (ORNL) in the USA to meet the needs of theMarket Survey for Nuclear Pover in Developing Countries conducted by theIAEA in 1972-73 (1,2). Based on the experience gained in using theprogram, many improvements vere made to the computer code by IAEA staff,leading to the WASP-II version in 1976, which has been widely used by theAgency and Member States (3-7). Later, the needs of the United NationsEconomic Commission for Latin America (ECLA) in a study of theinterconnection of the electrical grids of the six Central Americancountries, vhere a large potential of hydroelectric resources isavailable, together vith further recommendations given in 1979 by an IAEAAdvisory Croup on Electric System Expansion Planning, led to a jointECLA/IAEA effort from June 1978 to November 1980 to develop the VASP-IIIversion (8). VASP is used by the IAEA, in conjunction vith the Model forAnalysis of Energy Demand (MAED) for carrying out energy and nuelearpover planning (ENPP) studies for Member States which request them. Forthis purpose NAED and WASP are executed in tandem to produce optimalelectricity generation expansion programs consistent vith the overallenergy requirements of the country so as to achieve the economict socialand industrial development objectives.
Outline of the VASP-III Model
2. The WASP-III program permits the economically optimal expansionplan to be found for a pover generating system over a period of up tothirty years, vithin constraints given by the planner. The optimum isevaluated in terme of minimum discounted total costs. WASP-III usesprobabilistic estimation of production costs, amount of energy notserved, and rellability, together vith the dynamic method of optimizationfor comparing the costs of alternative system expansion policies. Aoimplified description of the model follovs.
18/ Extract from chapter 11 of "Expansion Planning from ElectricalCenerating Systems: A Guidebook", International Atomic EnergyAgency, Technical Report Series No. 241, Austria (1984).
-57 - Annex 1Page 2 of 11
#810ULE 1 MODULE 2 MODULE 3LQAOSY Jù FIX"S , VA5M
IMiT MODLE
MDLS MOOU
: U OATA
Mi SES SOUY\
<*li ITATO'4 PUATT!fN 1,REOROg SOLUTIONt &O&YFIA
r! com PotA i > \.ATmMESI am - f - m -F
IT$APN.%m IF.
ISCONBE tAit SOO F ItLE Numat
Figure 3. Simplified Flow Chart of the WASP-III Program
58 - Annex 1Page 3 of 11
3. Rach possible sequence of pover units added to the system(expansion plan or expansion policy) meeting the constraints is evaluatedby a cost function (the objective function) composed ofs
- Capital investment costa (I)- Salvage value of investment costa (s)- Fuel coste (F)- Fuel inventory costs (L)- Non-fuel operation and maintenance costs (M)- Cost of the energy not served (O)
Thus, t-T
Bi t [ jt -jSt Fj,t j,t °, t
vhere B is the objective function attached to the expansion plan j; t isthe timt in years (1,2,...,T); T in the length of the study period (totalnumber of years). The bar over the symbole has the meaning of discountedvalues to a reference date at a given discount rate i. The optimalexpansion plan is defined by Minimum B; among all j.
4. If (K ) is a vector containing the number of aIl generatingunits which are in operation in year t for a given expansion plan, then[K3j muet satisfy the following relationship:
[KjJ [Kt_,] + [At] + [Ut]
ihere [At] is the vector of committed additions of units in year t; |R Ris the vector of committed retirements of units in year t; [Ut] is tLevector of candidate generating units added to the system in year t, suchas [Utl2[0].
5. (At] and [Rt] are given data, and [Ut] is the unknovn variableto be determined; the latter is called in the system configuration vectoror, simply, the system configuration.
6. VASP-III permits the year to be subdivided into an equal numberof periods in order to better represent the seasonal variations of theload and the hydroelectric plant characteristics, as vell as for moreaccurate treatment of the maintenance requirements of thermal plants.Defining the critical period (p) as the period of the year for which thedifference between the corresponding available generating capacity andthe peak demand has the smallest va1lae, if P(K ) is the installedcapacity of the system in the critical perio,' 1ig/ the followingconstraints should be met by every acceptable configuration:
(1 at) Dto,p S9 (Ktt,p) (1 bt) t,p
19/ Period of the year during which the difference between the availableproduction capacity and the peak demand is the lovest.
- 59 - Annex 1Page 4 of 11
which simply states that the installed capacity in the critical periodmust lie between the given minimum and maximum reserve margins at and btabove the peak demand Dt p in the critical period of the year.
7. The reliability of the system configuration is evaluated byVASP in terms of the los of load probability (LOLP) index. The index iscalculated by the program for each period and each hydrocondition of theyear; from these values it determines the average annual LOLP for theperiod, which in turn are calculated as the sum of the LOLPs for eachhydrocondition (in the same period), weighted by the hydroconditionprobabilities.
8. If LOLP(Kt a) and LOLP(Kt ) are, respectively, the annual andperiod's LOLPs, ever4 acceptable corfiguration muet respect the follovingconstraints:
LOLP(K W ) < Ctp (for all periods)
where Ct,a are inputs data specified by the user.
9. If an expansion program contains system configuration for whichthe annual energy demand Et is greater than the expected annualgeneration GF of all units existing in the configuration for thecorresponding year t, the total costs of the program should be penalizedby the resulting cost of the energy not served. This cost io a functionof the amount of energy not served, Nt, which is calculated as:
Nt ' Et - Gt
The user may also impose 'tunnel' constraints on the configuration vector[Ut] so that every acceptable configuration must respect:
[U°l s [Ut SUt°*[l + [AU 1
vhere (U0] is the smallest value permitted to the configuration vector[Ut] and 5 Ut1 is the tunnel constraint or tunnel vidth.
10. The problem as stated here corresponds to finding the values ofvector [Ut] over the period of study which satisfy the aboveexpressions. This will be the 'best' system expansion program vithin theconstraints given by the user. The WASP code finds this best expansionplan by using the dynamic programming technique. In doing this, theprogram also detects whether the solution has hit the tunnel boundariesof vector (Ut] and gives a message in its output. Consequently, the usershould proceed to nev iterations, relaxing the constraints as indicatedby the VASP output, until a solution free of messages is found. Thisvill be the 'optimum expansion plan' for the system under consideration.
- 60 - Annex iPage 5 of il
Calculation of Costs
11. The various cost components in expression B. are calculated inWASP with certain modela, in order to account for:
(a) Characteristics of the electric load forecast(b) Characteristics of thermal and nuclear plants(c) Characteristics of hydroelectric plants(d) Stochastic nature of hydrology (hydrological conditions)(e) Cost of the energy not served.
In the above list and throughout this description, the word plant is usedwhen referring to a combination of one or more generating units (forthermal) and one or more projects (for hydroelectric).
12. The load la modelled by the peak load and the energy demand foreach period (up to 12) in each year (up to 30), and their correspondinginverted load duration curves. The latter represent the probability thatthe load vill equal or exceed a value taken at random in the period.(For computational convenience, the inverted load duration curves areexpanded in Fourier series by the computer program.)
13. The models for nuclear and thermal plants are each describedbys
- Maximwm and minimum generating capacities.- Heat rate at minimum capacity and incremental heat rate between
minimwm and maximum capacities.- Maintenance requirements (scheduled outages).- Pailure probability (forced outage rate).- Capital investment costs (for expansion candidates).- Variable fuel cost.- Fuel inventory cost (for expansion candidates).- Pixed component and variable component of (non-fuel) operating
and maintenance (O&U) coste.- Plant life (for expansion candidates).
The modela for hydroelectric projects are for run-of-river, dailypeaking, veekly peaking and seasonal storage regulating cycle. They aredefined (identifying for each project) by:
- Minimum and maximum capacities.- Energy storage capacity of the reservoirs.- Energy available per periad.- Capital investment costs (for projects used as expansion
candidates).- Pixed O&M costs.- Plant life (for projects used as expansion candidates).
The hydroelectric plants are assumed to be lOOX reliable and have noassociated cost for vater.
-61- Annex I
Page 6 of Il
118 ______ ''J+ .. I T., I 1 '.1;_.
t~~~. Ie .
D3-j CAPITALt + OPRATINGt ) - SALVACE
Uj: Oboetiv. tu'aatio (total oe.t) for the expansion planCAPITALt: sum of lnvestmout eots tfor th vartous units 4eUd lu
>war t et the studyOPEfAWiNC: Sum of all system oporating cotte (fuel. operation and
maintenance and onorgy Sot borvod) in y.ar t of the studySLYACV Suui oet *alvge values at horizon of the thvntmonts for *11
uniat add.4 by the expansion plan over the study priod%O: ifumber of years betweon the rotorence date for discouating
and tbh fiirt y*ar o the suudyS: Léanti d tt; l tudy pri od Un aumber ot yeans)£: Cumulated sum overthob yearm. trom bu to <w'
Figure 4. Schehti¢ Diagram of Cash Flows for one Expansion Program
-62 - Annex lPage 7 of il
14. The stochastic nature of the hydrology is treated by means ofhydrological conditions (up to five) or equivalent years of rainfall(e.g. dry year, average year, vet year). Each hydrological condition isdefined by its probability of occurrence a, which is determined fromstatistical information applicable to the whole hydroelectric system.For each hydrocondition, the user muet specify the capacity and energyavailable from each hydroelectric project.
1S. The cost of energy not served reflects the expected damages tothe economy of the country or region under etudy when a certain amount ofelectrical energy is not supplied. In VASP this cost is modelled througha quadratic function which relates the incremental unit cost of theenergy not served to the amount of energy not supplied. The cost of theenergy not served permits an automatic definition of the adequate amountof reserve capacity it the pover system.
16. To calculate the present worth values of the cost components ofexpression B., the present worth factors used are evaluated assuming thatthe full caeatal investment for a plant added by the expansion plan ismade at the beginning of the year in which it goes into service and alsothat ite salvage value is the credit at the horizon for the remainingeconomic life of the plant. Fuel inventory costs are treated asinvestment costes but full credit is taken at the horizon (i.e., thesecosta are not depreciated). All the other costs (fuel, O&M and energynot served) are assumed to occur in the middle of the respective year.
17. According to this, the cost components of expression Bi arecalculated as follows: 20/
(a) Capital inveotment cost and salvage value
3t* (l + i)t s [UIkIkNuk
9* t (l1* i) - S [ k,t UIk kI
vhere:
S is the sum calculated considering ail (thermal or hydro)units k addçd in year t by the expansion plan j;
UIk .ein the capital investment cost of unit k, expressed inmonetary units per MW;
NVk ie the capacity of unit k expressed in MV;
20/ The expressions are more complex as the model takes into account theactualisation rates and the fluctuations of the foreign and localcurrencies for each type of energy generation.
- 63 - Annex 1Page 8 of 11
4dt is the salvage value factor at the horizon for unit k;
i is the discount rate;
t' t + to
T' - T + lo
and t, to and T are as defined in Figure 4.
(b) Fuel costs
Fj t 8(1 + i t 0*5 E [ah* jt h]h1l
where a is the probability of the hydrocondition h;* hie the total fuel cost (sum of fuel costs for thermaland'h 6lear units) for each hydrocondition; and NHYD representsthe total number of hydroconditions defined in the study.
The energy generated by each unit in the system is calculatedby probabilistic simulation. In this approach, the forcedoutages of thermal units are convolved with the inverted loadduration curve and, consequently, the effect of unexpectedoutages of thermal units upon other units is accounted forprobabilistically. The net effect is an increase in thegeneration of peaking units in order to make up the reductionof base units generated oving to scheduled outages formaintenance and unit failures, thus increasing the expectedgenerating costs of the system. Obviously, the fuel cost of aparticular block of energy generated by a given unit iscalculated as the amount of generation times the unit fuel costtimes the unit heat rate.
(c) Fuel inventory cost
Lj it - t(i + i) t _ (1 + i)-Tj, £tUFIC kto tMWktotl
where the indicated sum Z is calculated over all thermal units(kt) added to the system in year t, and UFICkt,t is the unitaryfuel inventory cost of unit kt (in monetary units per MW).
(d) 0OU costs
MjWt ' (li) Z[UFO&MII4Nu+ W UVO&MG t]
ihere :
S is the sum over all units, Q , existing in the system inyear t,
-64 - Annex 1Page 9 of 11
UFO&M in the unitary fixed O&M colt of unit £ , expressedin monetary units per MW a,
UNVOIMN is the unitary variable O&M cost of unit 1, expressedin monetary units per kWh, and;
GZIt is the expected generation of unit t in year t, inkWh.
The expected generation of a unit is calculated as the sum ofthe energy generated by the unit in each hydroconditionweighted by the probabilities of the hydroconditions.
(e) Energy-not-served colt
o. 1 -t-O.5 h=NHYD Nt h 2 b hNét,att 1£3ai) t { (EA ) + 2 (A a} h
vhere3
a,b,care constants (S/kWh) given as input data.
Nt,h is the amount of energy not served (kWh) forhydrocondition h in the year t, and
lAt is the total energy demand (kWh) of the system in year t.
18. The cost components of the objective function (expression - )are all presented in expressions from (a) through (e) in a simplifi dform. In fact, all these expressions have been derived assuming eachexpansion candidate plant to be composed of one single unit(hydroelectric, thermal or nuclear), vhereas in the WASP-III program theexpansion candidates are de'fined as plants, and the number of units (orprojects) from each plant to be added each year is to be determined bythe WASP study. In addition, the VASP-III programs
- combines capital investment cost and the corresponding salvagevalue vith the fuel inventory cost and its salvage value;
- aggregates operating cost and its salvage value;- separates aIl expenditure (capital or operating) into local and
foreign components;- permits escalation of all costs as the study progresses;- has provisions to apply different discount rates and escalation
ratios for each year for the local and foreign cost components,and for the various types of plants defined for the case underconsideration, and to change the constants (a, b and c) of theexpression for evaluating the energy-not-served colt from year toyear.
Table 1 lists the most important capabilities of the WASP-11I computercode.
- 65 - Annez 1Page 10 of Il
Table It PRINCIPAL CAPABILITIES OF THE WASP-111 PROGRA
30 years of study period.12 periods (seasons per year.360 lood duration curves (one for each period end for ench year).100 cosine terms ln the Fourier representation of the lnverted load duration curve
of each period,7 types of plants grouped by 'fuel' types, composed of:5 types of thermal plants2 composite hydroelectric plants.58 thermal plants of multiple units. This hlit corresponds to the total number of
plants ln the fixed system plus those thermal plants considered for systemexpansion which ore described ln the variable system.
14 tvpes of candidate plants for system expansion, composed of:12 types of thermal plants2 hydroelectric plant types, each composed of up to 30 projects.5 hydrological conditions (hydrofogical years).
300 configurations of the system ln any given year (ln one single InterationInvolved, sequential runs of modules 4 to 6.
300 system configurations In all the study perlod (ln one single iteration lnvolvingsequential runs of modules 4 to 6).
60 discourir rates on capital Investment costs (one for domestic(2X30) and or* stpital costs each year).
60 discount rates on operating costa (one for domestic and one for(2x30) forelgn capital costs of each expansion candidates>.
840 escalation ratios on capital Investment costs per year (one(2x14x30) for domestic and one for forelgn capital Invest ent costs of each expansion
candidate)>480 escaltiton ratios on operating costs per year (one for domestic
C2x8x30) and one for foreign operating costs of each 'fuel' type (7) and for the cost ofenergy not served).
The VASP-III modules
19. Figure 3 is a simplified flow chart of the VASP-III modelillustrating the flow of information from the various WASP modules andassociated data files. The numbering of the first three modules isarbitrary, since they can be executed independently of each other in anyorder. For convenience, however, these modules have been numbered 1, 2and 3. On the other hand, modules 4, 5, and 6 muet be executed in order,after execution of modules 1, 2, and 3. There is also a seventh module,REPROBAT, which produces a summary report of the first six modules.
Module 1, LOAD8Y (Load System Description), processesinformation describing period peak loads and load duration curves for thepover system over the study period.
-66 - Annex 1Page 11 of 11
Module 2, FIXSYS (Fixed System Description), processesinformation describing the exsting generating system and anypredetermined additions or retirements.
Module 3, VARSYS (Variable System Description) processesinformation describing the varo-us generating plants which are to beconsidered as candidates for expanding the generation system.
Module 4, CONGEN (Configuration Generator), calculates allpossible year-to-year combinat ions of expansion candidate addit'3ns whichsatisfy certain input constraints and which, in combination vith thefixed systemt can satisfy the projected loads.
Module 5, MERSIN (Merge and Simulate), considers allconfigurations put forvard by COGEN and uses probabilistic simulation ofsystem operation to calculate the associated production costs, eraergy notserved, and system reliability for each configuration. The module alsocalculates plant loading orders if desired and makes use of allpreviously simulated configurations.
Module 6, DYNPRO (Dynamic Programming Optimization), determinesthe optimum expansion plan based on previously derived operating costsalong vith input information on capital costs, energy-not-served cost,economic parameters, and reliability criteria.
Module 7, REPROBAT (Report Write of WASP in a BatchedEnvironment), vrites a report summarizing the t<tal or partial resultsfor the optimum or near optimum pover system expansion plan and for fixedexpansion schedules.
- 67 - Annex 2Pag-e of 2
HMERCY SUPPLY CONUbCT POM SUNL (UaE) TO SUE (CONGO)(From Congos Pover Sector Memorandum, Vorld Dank, September 1984)
Background
1. Interconnection between the pover systems serving Brazzaville(Congo) and Kinshasa (Zaire) dates back the to mid-1960s. It vas esta-blished by a single 30 kV aerial line (capacity (15 MV) crossing theCongo River some 10 km southwest of both capitals, reaching the Djouésubstation. Through this line pover from Zaire Zongo hydroplant (75 MV,commissioned 1965) anJ Inga I (350 MW, commissioned 1974) hydroplant hasbeen sold to Brazzaville every year since 1968. Pover purchased fromZaire peaked in 1978 (72.1 CWh), 21/ due to a lack of local generationbecause of a major overhaul of the Djoué hydro station. During the years1970-1972 SUE (Congo) sold substantial amounts of electricity to Zairethrough this line (17 GWh) in 1972). Since 1977, SNE has been a netpurchaser of the Inga I generation, as Zaire has a large surplus ofhydropower. Through the commissioning of the 1,400 MW Inga II hydroplantin 1982, available capacity, compared to Brazzaville's system demand(25 MW), may be considered an unlimited supply source for many years tocome. Folloving recommendations from an Electricité de France study 21/a new 225 kV line from Lingwuala (Zaire's svitching station on the 225 kVtransmission system from Inga I to Kinshasa) to Mbouno (Congo's nev225/30 kV substation downstream from Djoué) vas built, and commissionedin September 1983. The transformer capacity at Mbouno i. 2 x 31.5 MVA,and a single 30 kV aerial line vith 22 MW maximum transport capacity,links the Mbouno substation to the old 30 kV interconnection line andBrazzaville's distribution network through the Djoué substation. Thisline is presently a bottleneck, limiting supply from Zaire.
The Pover Supply Contract
2. Folloving the decision to build the nev 225 kV interconnectionfacilities, a nev supply contract vas negotiated between SNEL and SNE.This nev agreement, which vas signed on March 11, 1981, has a seven-yearterm renevable by mutual consent, but it can be canceled by anyone of theparties vith a six-month notice period before the expiration date. Themaximm demand to be furnished corresponds to the transformer' s capacityat Mbouno, and energy supply is guaranteed from 45 to 130 GWh per year,
21/ In 1987, 148 GWh vere imported from Zaire, i.., 27.5X of thenational supply or 34.52 of the electricity supplied by SNE.
22/ Plan de développement des moyens de production et de transportd'énergie pour la partie méridionale du Congo, March 1981.
- 68 - Annex 2Page 2 of 2
according to load dispatching arrangements to be established from time totime. The first take-or-pay supply vas f ixed at 45 GWh per year for1984. There is no charge for capacity, and the energy is priced byblocks, starting at 6.8 FCFA/kWh for the first block between 45 and 49GWh, decreasing to 4.9 FCFA/kWh for purchase variations between the FCFAand the SDR: when variations of 5% or more occur in this rate the saleprice vill be adjusted proportionally. Reactive energy will be chargedif cos phi is lower than 0.837, and if £t declines to 0.75 SNEL isentitled to stop supply. Billing is done by SNEL on a monthly basis. Ifminimum guaranteed energy agreed each year is not consumed by SNE, anadditional bill vill be sent to SNE covering the difference between theminimum guaranteed energy and the actual energy consumed. SNE must pay(in FCFA Francs) within 45 days of receiving the bill, otherwise a 20Zannual interest charge will be added to the amount not paid vithin thattime. Metering is done through counters installed by SNEL at the Mbounosubstation, on which daily readings are taken. The prices fixed for thisenergy suppiy are free from all taxes and duties which might beestablished for the production, transport and distribution of power inboth countries. If duties or taxes are applied, SNEL is authorized tomodify its prices. This contract came into operation in September 1983,vhen the interconnection vorks were handed over by the contractor. Alldifferences arising over the interpretation of this contract, whichcannot be resolved by both parties, are to be submitted to arbitration bythree experts appointed by the parties involved, or by the Chamber ofCommerce International if agreement is not reached on the appointment ofexpert arbiters.
Conclusions
3. The present contract is beneficial to both parties. In Zaire'scase, it is an outlet for its substantial unutilized generation capacity,and is a source of hard currency. For Congo, this supply at a very lowprice (USé 1.3 per kWh), allows it to serve the Brazzaville market andadds flexibility to its maintenance operations; it also delays the needfor new investment in generation capacity, and reduces the consumption ofpetroleum products that would be used in thermal generation. It isundoubtedly the least-cost solution for expansion of Brazzaville's powersupply, and every effort should be made to establish good operating andfinancial relations between SNEL and SNE. Delays in paying monthly billshave occurred, and if the amount owed grows rapidly, it could become asource of friction between the two utilities and even their respectivegovernments.
Annez 3Page 1 of 9
POim FORCcAM
1. This annex consists of extracts from the TRANSENERG documentCollecte des données et prévision de la demande, vhich provided a basisfor the study of the long-term development of the pover system in thePeople's Republic of the Congo.
Pover Demand Forecasts
Hypotheses
2. Three hypotheses of consumption trends vere devised, in linevith the country's macroeconomic development.
3. In the base hypothesis, corresponding to the "central" scenariofor the development of the oil industry, GDP is assumed to remainconstant over the entire 1987-92 period. From this base hypothesis, ahigh-growth hypothesis and a low-grovth hypothesis were developed.
4. The Table 1 summarizes the main characteristics of thescenarios proposed for centers supplied by the interconnected system.
Table lt POPULATION ESTI4ATES: TH PEOPLE'S REPUJBIC Of THE 0Ho0
1987: 2000: 2015:Population Population PopulationNumr ( Number (%) Number (%)
1 . Communes
Brazzaville 689 32 1,305 38 2,187 41
Total for Colmunes 1,162 55 2,213 69 3,686 68
2* Raglons 965 45 1,129 36 1,694 32
Grand Total 2,127 100 3,442 100 5,380 100
5. In the case of centers not forming part of the interconnectedsystem, the forecasta took account of the policy of intensifying ruralelectr fication, adopted by the Congolese Covernment in order to checkthe rural exodus. Using the current electrification rates of 1% forsecondary centers (l.e. close to the interconnected system) and 4% forisolated centers, the study set targets for 2015 of a 30% electrificationrate in the base hypothesis, with 40% and 20% respectively for the
- 70 - Annez 3Page 2 of 9
hiah-provth and lov-grovth hypotheses. Consumption per subscriber inthese centers vas assumed to increase over the first 18 years follovingelectrification, and then to stabilise. The values are as follovs:
(a) 530 khhlyear for the first year;
(b) 870 klhlyear after five years;
(c) 1,500 kWh/year after the 18th year.
6. In each of the scenarios, these values have been increased inorder to allov for the effects on consumers of their improved standard ofliving.
7. The folloving Table 2 summarizes population projections (inthousands of inhabitants).
Table 2 : EASE HYPOTESIS AND POER OONSUPrTION TFIIND
Current Position (t987) Forecests Base HighGrowt Le-6routhCenter Cons_ume Cherecteristics Poriode Hypothesis Hypothesis Hypotb is
sumpt ion (CM)
Srazzaville Residentlal 70.,03 Eiertrlfication rate: Eiectrlfication rate29.13%; consuuption r Iin 2015 77 S 85. S 6 Ssubscriber 262 kWh/me Unit ¢onsumption:
- 1987 subsoribers 262 kWhJMo 262 kmb/o 262 khMa- 201t subscoibers 258 kWhbo 385 kwbAu 199 kWhMooAnoual rate of lmprovemeotIn living standards 2 S 3.SS S 1 S
Population growth rate 5.7 S 5.7 S 5.7 SMotels 6.48 Consu.ption linknd to Annual rate of Increose:
Industriel activity 1987-92 4.5 % 5 S 4 S1992-2015 6 % 7 % 5 %
covernment Md 35.26 Annuel rate of Incronsesecbtssies 1987-42 0% 3.SS% 0O
1992-2015 3% 5 2I"1arge-scale 17.58 Annual rate of Increase:Industrye (brewing, 1987-92 3S 4S 2 S 'textiles, livestock 1992-2015 6% 7 % 4* sftnd)
Other enterprises, 49.42 Consu ption related to Current rate of Increase 8a 8S 8SInsurance and banks MaOI i nd oedlu-sired
enterprIses
Public lighting 3.8 6.5S 7 S5.7%Fiointe Noire Low voltoge 64.43 Electrification rate: Electrîfication rate 75 S 83 % 63 S
26.9%; consumption per In 2015subscriber:
514.7 kWh/mo Unit Consuoption:- 1987 subscrIbefs 514.7 kWh/mo 514.7 kWh/mo 514.7 kWh/mo- 201S subscribers 402 kWh/mo 752 kWh/mo 391 kWh/oAnnuel rate of Improvemontin living standards 2% 3.55% 1%Annual population growth rate 6.03% 6.03S 6.03% 5
Oll-related 49.33 Annuel rate of increase:Industries 1987-88 0O 0% 0 ou
198t-89 1% 1% 1o1989-90 0.4$ 0.4% 0.4%199091 -3.3% -3% -3.3%1991-92 -4.9% -1.7% -4.9%1992-93 +1.8u2 +3.5% .1 .81993-2015 +.3 .5% +2.
«Large-scale 9.3 Annual rate of Increose:Industrym 1987-92 3% 4S 2S
1992-2015 6% 7S 4S
Wood Industries 3.03 Annuel rate of increase 8 S 7t esand developoont of +4 0Mb/yr 6 Mh/Jyr +3 Mb/wyeucalyptus projects
Other iV consuoers 25.25 Consumption related to Annual rate of Increase 8S 8S 8Sactivitles of mrait andoedlum-sized enterprises
Public lighting 0.12 Insufficient: totaled 1973 level to be regained beten 1908 and 19921.11 0Mb ln 1973 (<ie. +56% per year), thon:
Annuel rate of Increase n B.5S 6.03SBoueoza/ LV, excluding 2.94 Eiectrlficetion rate: Electrification rateLekouaou Louboto 15.64% ln 2015 77ns 8 65S
Consumption per subscri- Unit consumption:ber 166.75 kWh/no - 1987 subscribers 166.75 kWh/no 166.75 kW/0o 166.75 kWh/mo
- 2015 subscribersAnnual rate of improvemestln living standards 2S 3.55 S1 SAnnuel population growth rate 2.81 S 2.81 S 2.81 S
Louboto 0.01 Nouhoukoutou "workers t Rate of lacreoase rate ofcityw lmprovommnt ln living
standards 2% 3.SS SIHV and PY 17.51 Consumption mainly by Annuel rate of Increase:
'large-goale Industryu 1987-92 3 S 4 t 2 S1992-2015 6S 7 4N
Loubo Residential 3.35 Electrification rate: Eiectrification rate34.83% In 201S: 77 85% 65
Unit consuoption:Consumption per subscriber:- 1987 subscribers 127 kWh/mo 127 kWh/mo 127 kWh/mo- 2015 subcrribers 166 kWh/mo 242 kWh/»o 146 kWh/moAnnuel rate of Improvementla living standards 2 3.55 S 1 SAnnuel population growth rate 5.13 S 5.13 S 5.13 S
LV other thon 1.33 Consumption related to Annuel rate of Increose:rosidential overall Industriel sector 1987-92 4.5 S 5 S 4 S
1992-2015 6S 7 5SWood Industries 2.91 * 1989 SOOOBIS Increase (0.8 0Mh), plus
Annual rate of Increase: 8 7S 8SMV other thon 1.28 Essentlally sual aInd Annuel rate of Increase:.+ hospital la 1989 (1.75 CMb) owood Industries »ediuu-slzed enterprises + FERCO: 8 S 8 S 8 S
1990-94 4 G0h 4 0Wb 00Mb '
1995-99 8 0Mb 8 hbh 4 0Mh2000-15 89Gbh 8 0Wh 8 6mb
Public llghting 0.15 Insufficient Annuel rate of Increase:1987-90 23.7 % 23.7 S 23.7 t1990-2015 6 $ 7 % 5.13 %
- 73- Annex 3Page S of 9
Losses
8. It has been es.imated that losses should decline from the 1987level to reach 102 of consumption by 2005. This is a reasonable levelfor systeme of this scale.
9. The current and planned upgrading of the MV distributionnetworks will contribute to this reduction. Nevertheless, if this targetis to be achieved, it must be supplemented by action to reduce technicallosses in the transmission and distribution networks (30 kV inBrassaville) and in the LV networks.
10. In addition, action taken in SNE to reduce nontechnical lossesmut be continued.
The Transition to Load Curves
1i. The different trends shown by the various pover consumers inthe sectors concerned made it necessary to analyse the changes in loadduration curves from 1987 to 2015.
12. After determining the various total volumes of energy consumed,the study established load duration curves for four characteristicperioda: 1987-89, 1990-94, 1995-2005 and 2006-15. These vere preparedby reconstituting total demand from the development of each of itscomponents, vith an estimate of losses.
13. To this end, the folloving approach vas adopteds
(a) Characteristic load curves for current demand vere established,adopting the folloving procedure for each center:
(i) identification and analysis of available daily curves;
(ii) treatment of these curves in order to obtain averagemonthly load curves for various characteristic days(i.e. working days, Saturdays, Sundays and holidays);
(iii) analysis of results and establishment of standardaverage seasonal curvess
- vorking days in the rainy season;
- Saturdays in the rainy season;
- Sundays and holidays in the rainy season;
- working days in the dry season;
- 74 Annex 3Page 6 of 9
- Saturdays in the dry season;
- Sundays and holidays in the dry season.
The above vere determined by processing the daily loadeurves for Brazzaville for the 365 days of the calendaryear, vith the folloving breakdownS
- 243 days in the rainy season (169 working days, 35Saturdays, and 39 Sundays and holidays);
- 122 days in the dry season (88 vorking days, 17Saturdays, and 17 Sundays and holidays).
By using the information gained from the Brazzavilleutudy, it vas possible to limit the analysis for PointeNoire to the daily curves for six characteri.tic months.
(b) ihe behavior of each standard user vas determined, and thecharacteristic load curves for current demand verereconstructed.
(c) Characteristic load curves vere projected for the period from1987 to 2015.
Sd) Load duration curves vere established representing the averageload curve veighted for the number of various types of day inthe period in question.
As an example, Table 3 and Figure 5 show the results obtained for peakpover (base hypothesis), and Figure 6 shows the load duration curves forthe dry and rainy seasons in the 1995-2005 period.
- 75 - Annex 3Page 7 of 9
Table 3: OEMAND FORCASTSt EAS£ HYPOTHESIS
Power Consumed by the Centers (<Wh>) Ma_ _xumBrazza- Pointe Lou- Second- lsoloted Total Con- Losses Total UF 1/ Power
Yter ville Noire Bouenia bomo dary Centers sumption (S) 6enerated (hours) (MW)
1987 132.57 151.45 20.45 9.03 0.39 0.88 364.77 18.5 423.85 5,956.25 72.01968 193.67 158.92 29.84 9.76 0.45 1.01 393.66 18.5 466.49 5,956.25 78.31989 205.22 168.81 31.08 13.11 0.52 1.17 419.91 18.5 497.59 5,956.25 83.51990 218.25 182.52 32.38 18.18 0.58 1.32 453.32 15.0 521.32 6,030.97 86.41991 231.86 191.25 33.72 19.28 0.64 1.46 478.22 15.0 549.96 6,030.97 91.21992 246.44 201.11 35.13 20.47 1.45 2.00 506.61 15.0 582.60 6,030.97 96.61993 263.97 215.22 37.48 21.78 2.40 2.63 543.48 15.0 625.00 6,030.97 103.61994 282.84 230.08 39.98 23.19 3.46 3.31 582.84 15.0 670.27 6,030.97 111.11995 303.15 247.11 42.62 28.70 4.68 4.10 630.37 12.0 706.02 5,724.80 123.31996 324.09 265.53 45,42 30.33 5.97 4.93 676.28 12.0 757.43 5,724.80 132.31997 347.56 285.45 48.39 32.09 7.46 5.89 726.84 12.0 814.06 5,724.80 142.2
1998 372.82 305.75 51.54 33.98 8.99 6.86 779.94 12.0 873.53 5,724.80 152.61999 398.92 328.93 54.88 36.01 10.73 7.98 837.45 12.0 937.94 5,724.80 163.82000 428.10 353.97 58.41 38.20 12.60 9.18 900.45 12.0 1,008.50 5,724.80 176.2
2001 460.72 379.57 62.15 40.56 14.60 10.48 968.97 12.0 1,084.24 5,724.80 189.4
2002 493.32 407.15 66.11 43.09 16.70 11.84 1,038.21 12.0 1,162.80 5,724.80 203.1
2003 528.31 438.48 70.31 45.82 18.97 13.33 1,115.23 12.0 1,249.05 5,724.80 218.2
2004 565.89 470.59 74.76 48.7S 21.39 14.92 1,196.31 12.0 1,339.87 5,724.80 234.02005 606.23 507.01 79.47 51.90 23.67 16.42 1,284.71 12.0 1,438.88 5,724.80 251.32006 651.16 544.38 84.46 55.30 26.05 18.01 1,379.36 10.0 1,517.30 5,597.98 271.02007 697.79 586.68 89.75 58.9S 28.58 19.71 1,481.46 10.0 1,629.60 5,S97.98 291.12008 746.05 630.16 95.35 62.87 31.01 21.37 1,586.81 10.0 1,745.50 5,597.98 311.82009 799.66 678.36 101.28 67.09 33.58 23.14 1,703.10 10.0 1,873.41 5,597.98 334.72010 856.00 732.29 107.55 71.63 36.24 24.99 1,828.70 10.0 2,011.57 5,S97.98 359.3
2011 918.97 786.89 114.20 76.51 38.76 26.77 1,962.11 10.0 2,158.32 5,S97.98 385.6
2012 983.05 845.65 121.25 81.75 41.38 28.64 2,101.72 10.0 2,311.89 5,597.98 413.0
2013 1,051.70 908.88 128.70 87.39 44.08 30.61 2,251.36 10.0 2,476.50 5,597.98 442.42014 1,127.77 976.90 136.60 93.46 46.87 32.67 2,414.27 10.0 2,655.70 5,597.98 474.42015 1,206.78 1,050.08 144.97 99.98 49.76 34.83 2,586.39 10.0 2,845.03 5,597.98 508.2
1/ UF a Annuel utllizatlon factor of peak power.
- 76 - Amex 3Page 8 of 9
Congolese SystenHuergy supply Projections
i /
Case not considered in Low case
the study Xca
(GWh)~ ~ ~ ~ ~~~~~~~~~~~~i Base case,
p7 gê 909S99la lS4175 997 t a 3 * S I 7 I 9 t01:2 U314:5Yeare
Congoleue SystePeak Domand Projections
Case not considered inthe study 1* v i
Capacity dl - 1ig s
-*-Base case,
mi US 4 se SU tU 3 * ô SI I -9 t Si@113:4:SYears
Figure 5. Consumption and aid Peak Demand
- 77- An«e 3page ot 9
CoPlese System - Iaiy séasonLod flratios Curves 1995-2005
Ps~ ~ ~ ~~~~~or
6rf9
;. _
vt:
0..
i4i
Ps t
'C *
t *ee *0 110 1100 t 00 1400 a l a
Eours
Figure 6. Loa t Dration Curves for the 1995-20QS Period
-78 - Annez 4Page 1 of 1
ANALYSIS OF RYDROIOCICAL DATA 23/
Current Situation
1. Congo's hydrology is followed by ORSTOM, which operates S2measuring stations spread over the country, of which 8 are equipped vithlimnographa (OTT); the others, only equipped vith liminological scales,are read twice a day. Caugings (20 to 30 pet year) allow the stabilityof the "gauging" curves (courbes de tarage) to be established andverified.
2. Almost all these stations are implanted in the catch basins(from 50,OOO to 3,000 kni2). Only tvo of them control basin loverthan lO0O km2s the Lekoury at M'bouma (225 km2) and the N'Kenne at IRCT(503 ka ).
3. A hydrological book is published yearly by ORSTON. It givesaverage daily flows of the operated stations.
Improvement of hydrological data collection
4. During the inventory of hydroelectric resources of the north ofCongo in 1951, UNIFICO established a list of 12 hydrological stationsneeded for improving hydrological data for hydropover pIwojects.Othervisep UNIFICO estimated that the estimation of flovs are knovn at± 20Z in the average year and ± 50O in a vet or dry year.
5. The recommendation vas not implemented.
6. It is recommended to extend the actual measurement network by10 to 12 stations equipped vith limnographa. They should be adequatelyimplemented to aLlov the specific. flova of major rivera and to docorrelations between new basins of the same importance.
7. The current cost of a station equipped vith a limnograph isabout 1 million FCFA (about US$ 3,125) and the total cost of the projectabout 10 to 12 million FCFA (about US$ 31,250 million to US$ 37,500million).
23/ Excerpta from R. Guilhot s report: "Collecte et Analyse des DonnéesC-cncernant les Projets Hydrauliques".
-79_ Anne-SPage 1 of 2
NATUEAL GA8 BSOURCES Il CONCO 24/
1. Two issues arise with regard to natural gas in Congo:
(a) the existence of a surplus of associated gas resulting from oilproduction, and its possible uses;
(b) the existence of natural gas reserves, and their possible uses.
2. As regards the firet item, the oil companies operating in Congohave stated that there is no associated gas àvailable, and that in factit vill be necessary in the near future to consider developingsmall-scale natural gas fields in order to meet the requirements of oilproduction.
3. Natural gas reserves are as follovs:
(a) Pointe Indienne: This is a small onshore gas deposit that vasdeveloped between 1968 and 1980, and subsequently closed.Remaining reserves total less than 100 million m3. Theoperator plans to use this for oil operations (in the Djenoterminal). Since there is no replacement supply, this volumeis totally inadequate to justify the establishment of atransportation and distribution system.
(b) Vandji Coakouatis Currently, this deposit contains the largestproven re erves. It vould be capable of producing up to 200million`mJ per year for 20 years. It is located in quiteshallov vater in the northern offshore area on the MandingoMaritime concession, held jointly by Agip Recherche Congo (theoperator), Elf Congo and Hydrocongo.
The operator's initial estimated costs of production andtransportation to the Pointe Noire region show that the outputlevel is a determining factor in such costs. Only the largestoutput (i.e. 200 million mJ per year) would result in anacceptable cost level (taking taxes also into account).
(c) Other gas deposits: Many offshore discoveries have been made,but so far appraisals have not indicated the existence ofsubstantial reserves.
24/ Extract from the summary report entitled Etude de Rationalisationdes Choix Energétiques, TEANSSNERO, 1984.
- 80 - Annex 5Page 2 of 2
4. This brief review of gas resources in tho People's Republic ofthe Congo shows that only the Vandji Conkouati deposit bas sufficientpotential to be considered as a candidate for development and production.
5. Hovever, the rather marginal nature of this deposit means thatthe economic succesa of a project vould depend very much on thepossibility of selling the planned volumes of output to existingconsumera (through conversion to gas use), or to new consumera. Anannual volume of liquified gas of this order of magnitude could not beexported.
-81 - Annex 6PaÎê I of 6
BASIC TeŒIICAL AND £COMNIC CONSTRAINTS
1. This annex liste the basic technical and economic data includedin the study, as presented by the reporting feature (REPROBAT)t
(a) the list of thermal units, hydropover projects andinterconnection lines selected to meet demand;
(b) the base hypothesis concerning demand trends;
(c) a description of the existing fixed system (FIXEDSYSTEM-FIXSYS);
(d) the technical and economic specifications of the thermal units,hydropover projects and interconnection lines selected formeeting demand (VARIABLE SYSTEM--VARSYS);
(e) the investment costs, constraints and economic parametersincorporated into the optimization using the dynamicprogramuing module (DYNAMIC PROCRAMMINC--DYNPRO).
-82 - Annex 6Page 2 of 6
?338 SS À LSSS or S1 D SUIN TWU or ILICC P0un PLANTSUScm ZN SU S?UD'.
M* Uoec COSDs AU o air s co1?f McPAS
O DOSZ 02138, ASOZL PUNItrIL 4v L PLA
a S o* aTENA us PLANT
a uIC U ZC L*SIX* £LZ3 .EC. ss08 IZZA
LM' LOMI TMI SoSaSIIR *15. 1111<SRI SSORACt
AIIIL LoAS DtSCt5:P0mSOOcS PI! UA s 3
P onl.A?E N25*LOAD GiJAt 3815.0? da.Un LOADTOI
lui 91.0 - .s - 544.9 ' 6.60
39# 91.0 .6 S.1 6.6 552.9 6.6 U.60
19931 104.0 t.2, 5.3 1.2 825.0 7.2 U.60
19% t^X-.0 6.7 n.o 6.7 "0.1 6.7 68.60
199 123.0 10.8 63.9 8.4 721.7 9.1 61.54
199 133.0 1.3 68.4 7.3 uma.0 7.3 61.16
187 148.0 1.6 73.8 7.6 140.2 7.6 61.56
9n Us.0 1.7 19.5 7.7 905.2 7.1 61.54
1f" 164.0 7.2 é5- 7.2 910.3 7.2 61.54
2000 176.0 . 2.3 84.O .8 1003.6 3.4 65.08
net 189.0 1.4 92.3 7.4 1017.5 .4 65.08
3002 203.0 7.4 I.s .4 1151.3 7.4 65.08
2003 2S.0 7.4 106.5 1.4 1824.8 7.4 6s.08
2004 234.0 7.3 114.3 7.3 1334-0 1.3 65.08
1005 231.0 7.3 122.8 7.3 1430.9 7.3 65.08
2006 271.0 8.0 132.4 8.0 aS4S.@ 8.0 65.08
207 291.0 7.4 142.1 1.4 16S9.0 7.4 65.08
300o 312.0 7.3 UZ.6 7.2 1718.7 7.2 65.00
3009 335.0 7.4 163.6 7.4 1909.8 7.4 65.08
3110 359.0 7.2 171.9 5.0 i963.1 3.8 63.03
2011 386.0 1.5 184.8 7.$ 2131.2 7.5 6303
Z013 413.0 1.0 191.7 7.0 2280.2 1.0 63-03
l01t 462.0 7.0 211.6 1.0 2440.4 7.0 63.03
2014 '16.0 7.2 220.9 1.2 2611.0 7.2 43.03
3413 508.0 7.2 363.3 7.2 3404.1 .1 65.03
- 83 - Annex 6Page 3 of 6
FIu $YSTIMsoar DCRTUm or MW< PITS la YSW 1991
MAT SATU Tm COSTS T
MO. MII. CJ %lUL cursi bpJS ?m O"YS MAISN Ou 0&4
OJ LMO c:YCt SU AvO: rn.:ou VCM Tut. US 8GHZ GLAS <CTX) (VAS)
X0 StCW SSTS m m LM V<C OmsTG PtMU ME I MAIS mu 511IXM SIMWR
3 0002 4 O. 2. 3760. 1990. .0 2640.0 O :5 5.0 le 2. 1.36 .59* DOO4 3 1. 4. 3798. 1S98. .0 2fto.0 0 10 1l.0 28 *. 1.4 .59
lXZ;D SYStIE2SIMIOUAR OuSZTzI or cOOST r t= :C pAst T?un sut
*** C2ACT SI * tNU n lu N *-
V=I oe o COSS* .C50 situ-NomP 8VOIOCONDtZON 1 I_uSSSONTzO àR M .t .s 0 1oPM. .10O £ CAACéy m= CAPACIT t 10Y
Year J a bAS t A PAK
jîlI 2 1 l8. 0. 227. 58. O. 189.
a 54. 0. %V. là. 0. 112.
3 78. O. 227. M. O. lof.
It.CAI. of.TAL DErO 811. 450.
T SYSTD
MOUL A TImo As ut usu»M« 0? $T A0DED Aul Ut (-)
1991 tO Sou
WM 19.. (200.120..)
mO. aIm sa 99 O 1 a 3 4 s I i S 91 % 01
* 5002-4 . . . . ..... .
Su"TY or NstaLLS CAPACIT2S(NISilUAL CA1ACZtIIS (m»
U=ioU0C TEIMU TOLAL
*L0S SU * UT F L t yP S
O 1 a 3 4
UAl SP. CAP ?a. CAP OitS nu ChS sLuc Eun
1991 0 O. a et. 18. 0. 0. 0. 0. lOJ
1991 12. O. O. O. o. loi.
2002 S. 0. 0. 0. 0. 97.
2004 4. 0. 0. 0. o. 93.
2agt 0. 0. 0. 0. O. 89.
- 84- Annex 6Page 4 c4 6
VA1.ZAIL: SYSS£#
SuiRY otSCRtP.:ON or ?UIA.t PLNTS
suA 5t1S VUL COSCi tAST
NO. tN. CAWA KCALItKvC cVsS SltN FO5t 0AYS MAIN CU3 ;tl
or LOA0 C:St umS AVCz MILL:CN 2CAL rui. us scC8L CLAS r:x (VAR)
NO. N Z:C SeS Nu Nu .0A0 lSCR DoS?C FOlCN tIFs 1 S S AIN MW StKlC1 StMiN
1 Cola 0 2. *l. 3702. 1752. :s80.0 .0 1 10 15.0 :U 12. :.82 .56
a tGU 0 4. 2s. ô91:. 2tS9. 944.0 .0 2 s 12.0 28 as. 1.17 .- 8
3 CCOS O 9. 2s. 2819. 1676. 944.0 .0 a 10 12.0 là Sa. 1.%3 .39
4 L:Nt 0 5 . 230. 860. 886. .0 2814.e 3 0 S.0 6 200. :o . o
S :Nta 0 1. 50. 860. 860. .0 3270.0 4 O 5.0 6 50. .02 .0Q
VARiABLE SYTS?V
S41'.a.UY EZSCd22P?COU 0COOSz:z IMYSROESLZCR.C PIS mr w N
CUACS Y Zn 5W * tNCY tu Cml *
Fivo OL COStS .313 Situ-MNts
r gutSOlCoeôS:Ox 1. 8YRaOCODt:tON 2
3 J fl08.a .90 .: .10
O1 W AAC:tIy zxx=y CalZt t!o
Year . a un PUR DSm Pt
1996 i i 7-. j. 5. 7. 197. 45.
a 7. 38. 109. 7. 34. S7.
3 7. 16. S9. 1. Il.' 43.
t:lS?.CA. 60.
=OTAL c£Elt 226. 177.
V3ZAS sYStS
OSAY DtSdITWU c0V wOe M DOLZU=tC PtLS lut SUt
W* cAPO Zn Nu lu* SO ^3 Ci "m *.^n o cosi s * 5.10 sgtu-sou
I iDIaouD::o 1 YDa*OUDTf O* 2
p P* .: .90 PM. .10
O s CuAcIT mr CAPAtYear j a un un am PM
1995 i 1 la. O. 35. O. U. le.
2 O. 1l. 22. O. 15. 14.
s S2. O. 35. 0. 15. le.
Ns?t.Co. U.
tOTAL £Im. 91. 50.
1996 2 a 17. 95. 241. 3. 110. 180.
2 5. 110. 213. S. 11O. 170.
3 17. 9S. 141. 5. 110. 18.
huS?.CAP. ls5.
TOTAL £350Y 695. 330.
-8B5 - Annex 6Page 5 of 6
0yNPROSD~8Y V AflALCmtOrI ALWIAUVM S tu S/KV
CAItSAL COSSS ZNUSIW CIISTE. PLUT CAfl?.L COSTSPuai? <oh :ASE PARJlT> tDC t: Mt LISJ tNONMOEPUC. PART)
ooos: io No S <yzS> t)as C0~eT:: roa:sitUINEAUL PUai? CAPt'AL COOSS
bois 06.4 8.9 10.50 3.00 30. 9.S 0lois 33.0 s14.9 10-.0 2.00 20. 10.1 .0CCUS *0.5 635.3 10.50 3.00 30. 9.2' .0LUn; 32.0 :28.0 10.50 2.00 30. .0 0tUI .0 .5 4.50 1.00 20. .0 .0LOM - MM PJtCS CAPITAL COSTS. ?RUCT LM 40.
t 414.4 144.4 14.10 *.00SMt - UyDa@ tlOUW CAPITAL. cSS. PROJCT UPn: 40.
1 1333.0 5333.0 12.30 5.00à 02.0 3300.0 14.70 6.00
SN tPROtcoumc PAJAgTUS MMI coumtts
ALL COITS VI U DUCOzIwnD TO na 1991Sa ". Fa ZoCAUTOV cALo.0W s t2 1991
u1o91 DTZAL VuS c tXX - ZN= M s. ( O) * No msa noD
voit un tS L lm LM STOzS$S Sun m TO au. OC4SC CPIL COMM Il 10.0iscOt u SOl APLUR TO MAL COSSS CAI- cmS g UTS 10.0sC OP 1UTIOS 101 CAPITAL COSSS C 0)
ooSSC 1.00 1.00 1.00 1.00 1.00 1.00 1.001088103 1.00 1.00 1.00 1.00 1.00 1.00 1.00MW MO M 0 MUS VSUCS CAU S MM 0)
< 111U 0V UN0IS MUIc I 5I#t U O Dt8 t 0>
o o o o e o o
-86 - Annex 6Page 6 of 6
O Y N RO a 0cNT0.)SCOseIC P»moeRS meO cONSmSTxIttS
1901 :I2?ZA VALuu <(oe> ^ m Muen, o *) NO tN DX .
T Et E a £ A L UYOROELCiuRC LtaNYoDS PZSWC tV£' LON SU lC SNRSX V
Dssc0T RTE zAPLIE To M-L D0<ESTIC OPEtSAfON COsTs - lTR (<14 :0.0
DuScKu lIE oA tLo tO ASL F CxN OPStSO* colIS - lIYR (15) 10.0E.sU.L.:u RO tIOS tl outzuTu cosSs 0)
I)rmes::c 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00»g£;U S1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00
>Vi::PLlISOîA= roi vu v cos.s c o>
b nC S1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.C:FUz:au 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1. 0
C;çres:ms or Uu<Y UOT suv: cosS vCTZON (11>. cri cri crn
(Situa) 5.0000 .0000 .0000emzw.n àc rn on iuzcu wvorM Ul < o) t.moooCt:.:UL LOSS c wuO moISLzT in s <12> 2.8500
CZCu:Ou OTON (10 * -
smîuo vw
-87- Amex 7Page 1 of 26
oEAi*CTRI811CS OF TSI KA DIEVMLDO?T ALHIIYIStU*8S DUAiD HYPOTUrSIS
1. This amie: dotails the main alternatives for developing thegeneration system in the People's Republic of the Congo in order tosatisfy the level of demand calculated according to the basehypothesis. The results of the analysis of each of the four alternativesare sumarized in the folloving table and presented bolow.
Objective Index:Function Least-Cost(In m11. Solution
Solution Brief Description of US$) 100
le "Roglonai Cooperation" Installation of the Inge- 202.4 100with K-3 and 1-4N lines Pointe Noire line In 1997,
plus 4 x 25 MW GT and4 x 75 MW CC
2. MAqsIonal Cooperationn lmports via existing K-B lne, 216.6 107with n-3 line plus 2 x 12 NW D, 2 x 25 MW 6T
mad 6 x 75 NU CC
3. 'Self-rel lance" with nstaillation of 6 x 75 MW CC and 260.5 129combined cycle units 5 x 25 MW ST, without power
Importe
4. Hydropower projects Imboulou 1996, DJoué 2 1999, 335.8 166Included I'boulou 2006. Complementary
thermal power.
2. The four alternatives have been described according to the sameproceduret
(a) review of the list of the various candidates;
(b) review of demand;
(c) type and number of generation units to be installed, by year;
(d) changes in the objective function (total discounted costs; baseyear a 1991);
(e) total installed pover and service quality, by year;
(f) investment, by year.
-88 - Annex 7Page 2 of 26
"REGIONAL COOPHIATION" VITE KINSUSA-BRAZZAVILLEAND INCA-POINTE NOIRE LIMES
SUtWIRY REPORTOS £ CEIERSTION XPMASION PU
cOcO t
PlOCtSSED SY TE T ASP-Iz comp=t PRoGI pAC=E
Oc Tu S A
sTUIY PEIIOD
1991 - 2015
PLANNIN PEIUOD
1991 - 2015
OUSTRCION cOSTS
la mILLON S
ARu R1PSRED OIILY FORPUT CWO<!520NED
DUPRJS TUE PUJINI PECOD.FOR OTuER v= $O Y ION CVON TU VOLE STUDY PER!O0.
-89- Annex ?Page 3 of 26
"REGIOVAL COOPEATION" WITH KINSHASA-BRAZZAVILLBAND INCA-POINTE NOIRE LINES
TRIS ZS A LIST CP TUE OFERENT STYES CF ELECSRSC POE PLANTS
USEiD ZN E StUDY.
TUIE 1UW C CODES ARt UED BY SIIE COU PER=AS
O DS1S DESEL 0S0SL PLT
1 FUEL 1RVI FUL PLANT
2 AZ XNATURL AS PLAN
3 ELtC DELCTS=C 7.11K
4 ELEI ELEA=. DOUT amAA
LONC LMIS TEMU SORUAE
S8iT sO5 TER STOR
ANWL LOMD DESCRPTION
PERIOS) FElt YAR *3
AR PEAXLOAD OR.RATE la.LoA GLATE E O GtE.RATE LMDFA
N X hW x ou S I
31991 91.0 - 48.3 - !46.9 - 68.60
192 n97.0 1.6 51.5 6.6 582.9 6.6 68.60
1993 104.0 7.2 5$.3 7.2 625.0 7.2 68.60
1994 111.0 6.7 59.0 6.7 667.1 6.7 68.60
1993 123.0 10.8 13.9 8.4 72?.? 9.1 67.54
19"6 132.0 7.3 68.6 7.3 781.0 7.3 67.S4
197 142.0 7.6 73.8 7.6 840.2 7.6 67.54
1"9P 153.0 7.7 79.5 7.7 905.2 7.7 67.54
1999 164.0 7.2 85.2 7.2 970.3 7.2 67.54
2000 176.0 7.3 80.0 .8 1003.4 3.4 65.08
2001 189.0 7.4 92.3 7.4 1077.5 7.4 65.08
2002 203.0 7.4 9.1 7.4 1157.3 7.4 65.08
2003 218.0 7.4 106.5 7.4 1242.8 7.4 65.08
2004 234.0 7.3 114.3 7.3 1334.0 7.3 05.08
2005 251.0 7.3 122.6 7.3 1430.9 7.3 65.08
2006 271.0 8.0 132.4 8.0 1545.0 8.0 65.08
2007 291.0 7.4 142.1 7.4 1659.0 7.4 65.08
2008 312.0 7.2 152.4 7.2 1778.7 7.2 65.08
2009 333.0 7.4 163.6 7.4 1909.8 7.4 65.08
2010 3S9.0 7.2 171.9 5.0 1982.1 3.8 63.03
2011 386.0 7.5 184.8 7.5 2131.2 7.5 63.03
2012 413.0 7.0 197.7. 7.0 2280.2 7.0 63.03
2013 442.0 7.0 211.6 7.0 2440.4 7.0 63.03
2014 474.0 7.2 226.9 7.2 2617.0 7.2 63.03
2015 508.0 7.2 243.2 7.2 2804.7 7.2 63.03
* N N N N N N N N N N N N N N N O O O N N O N N O N
...... ~.... ... ...... . . . . .
. . . . . . . . . . . . . .^ . . . . . . . . . . . . w g 0
. . . . . . . . . . . . . . . . . . . Wv|,
. .. .. . . . . .l . . 4 sNN
.N N N 0 0 @ . . . . . . .
0 N. . . t 4. . . . . N o O @.. . . .. . .
S.N. . . . . . .. . . . . . . . . . . . . .O .S . .
*0. . . .. . . . . . . . . . . . . . . . . . . . .
N No~~~~~~~~~~o
- 91- Annezs 7Page 5-of 26
"RIEcO mAL COOPERATION" iTU KIis&uSA-BRAZZAVILLEAND INGA-POINTE NOIRE LIMES
O Y£AR- PRSSENt WOlT? COSt Ot SHE tu AR ( K8 )- ODJ.1UU. LOw C D012 CCS SNSB S9RtO CONCSS SALVAL OPCOST ESCSS TOTAL (cM.>) t TG2S LiSN LONG
__... __«_...____. __.... ___*.__. _.... __.. _..... ... __ ... . . . .. . . . .
0 2015 1739 1571 $593 354 6114 202478 .279 0 4 12 1 1 0 0
0 2014 1913 1561 5725 286 6362 196364 .229 0 4 Il 1 1 0 00 2013 4208 3099 5863 210 7183 190002 .173 0 4 10 1 1 0 0- 2012 2314 1537 5963 387 7127 182819 .27» 0 4 8 1 1 0 03 2011 2546 1523 6079 369 7471 175692 .258 0 4 7 1 1 0 00 2010 2800 1508 6229 293 7815 168221 .210 0 4 6 1 1 0 0v 2009 3080 1491 6543 2U 8417 160406 .219 0 4 S 1 1 0 00 2008 3388 1472 6634 304 8854 151989 .211 0 4 4 1 1 0 00 2007 3727 1452 6746 350 9371 143135 .236 0 4 3 1 1 0 00 2006 0 0 6861 432 7293 133764 .265 0 4 2 1 1 0 00 2005 4510 1405 6839 192 10136 126471 .124 0 4 2 1 1 0 0o 2004 4961 1378 6964 149 10697 116335 .144 0 4 1 1 1 0 00 2003 4461 1103 5876 319 9553 105638 .195 0 4 0 1 1 0 00 2002 4907 1076 5606 345 9781 96086 .256 0 à 0 1 1 0 00 2001 0 9 5309 178 5487 86304 .195 0 2 0 1 1 0 00 2000 0 0 5070 0 5070 80817 .018 0 a 0 1 1 0 00 1999 0 a 5198 0 5198 7$747 .000 0 a 0 1 1 0 00 1998 0 0 4924 0 4924 70549 .000 0 2 0 1 1 0 0
0 1997 18063 2035 4904 0 20932 65625 .000 0 2 0 1 1 0 00 1996 0 0 4361 801 5162 44693 .243 0 2 0 0 1 0 00 1995 0 0 3874 238 4111 39530 .128 0 2 0 0 1 0 00 1"4 10519 741 3257 143 13177 35419 .054 0 2 0 0 1 0 00 1993 0 0 2694 749 3443 22242 .187 0 1 0 0 1 0 00 1992 0 0 2434 141 2575 18799 .100 0 1 0 0 1 0 00 1991 14325 546 2254 190 16223 16223 .049 0 1 0 0 1 0 0ALL POSSIBLE PATHS tluCED
-92- Annex ?Page 6 of 26
"REGIONAL COOPERATION" WITE KINSHASA-BRAZZAVILLEAND INCA-POINTE NIOIRE LIMES
CAPITAL CuS nLOW SURY
VFMi CONSSTUCTIOU 1DC
YUl DOM. FOm. SOTAL DM1. FOR. TOTAL DO. FOR. TOTAL ¢R. TOT.
198 .0 .0 .0 .1 1.1 1.2 .0 .3 .3 1.5
1989 .0 .0 .0 .4 6.8 7.2 .1 1.0 1.1 8.3
1990 .2 .0 .2 .2 4.0 4.2 .0 .3 .3 4.7
1991 .0 .0 .0 .1 1.1 1.2 .0 .3 .3 1.5
1992 .0 .0 .0 .4 6.8 7.2 .1 1.0 1.1 8.3
1993 .2 .0 .2 .2 3.7 3.9 .0 .2 .3 4.4
1994 .0 .0 .0 .6 2.2 2.8 .1 .6 .7 3.6
1995 .0 .0 .0 3.4 13.4 16.8 .5 2.0 2.5 19.S
1996 .0 .0 .0 1.8 7.2 9.0 .1 .5 .6 9.)
1997 .0 .0 .0 .0 .0 .0 .0 .0 .0 .0
1998 .0 .0 .0 .0 .0 .0 .0 .0 .0 .0
19" .O .0 .f .1 1.1 1.2 .0 .3 .3 1.5
2000 . .0 .0 .5 7.9 8.4 .1 1.3 1.4 9.8
2001 .3 .0 .3 .8 11.8 12.6 .1 1.6 1.7 14.6
2002 .3 .0 .3 .9 13.4 14.2 .1 1.9 2.0 16.5
2003 .2 .0 .2 .8 12.8 13.6 .1 1.6 1.7 15.5
2004 .2 .0 .2 .4 5.9 6.3 .0 .7 .7 7.2
2005 .0 .0 .0 .6 9.7 10.3 .1 1.6 1.7 12.1-
2006 .2 .0 .2 .9 14.2 . 15.1 .1 1.9 2.0 17.4
2007 .2 .0 .2 .9 14.2 15.1 .1 1.9 2.0 17.4
2008 .2 .0 .2 .9 14.2 15.1 .1 1.9 2.0 17.4
2009 .1 .0 .2 .9 14.2 15.1 .1 1.9 2.0 17.4
2010 .2 .0 .2 1.0 15.6 16.6 .1 2.3 2.4 19.3
2011 .3 .0 .3 1.4 22.5 24.0 .2 3.2 3.4 *27.6
2012 .4 .0 .4 1.2 18.7 19.9 .1 2.2 2.4 22.7
2013 .2 .0 .2 .8 12.8 13.6 .1 1.6 1.7 15.5
2014 .2 .0 .2 .3 4.5 4.8 .0 .3 .3 5.3
3.8 .0 3.8 19.6 240.1 259.6 2.6 32.5 35.1 298.5
_93_ A-me:?PÎÎe 7 of 26
"SGIONAL COOPUATION" VITE KINSRSA-1RAZZAVILLEAID INCA-POINTE NOIRE LINES
SUMMWARY OFFiED SYSTEM PLUS OP?ZM J SOLUtION
(MOMIUAL wACIT! ZN MW, ENERY lu GCH)sYDckIoCTRIC THEMAL FUmL TYPE TOTAL SSSTEN ENERGY nOT SERVELONC SmRT CAPACITXES CAP RES. LCIP. HYDROCOIONITZO
lmER O 1 2 3 4 1 2ER. CAP PR. CAP DlES FUEL GAZ ELEC ELuE X X
1991 0 0 89 l8 0 25 0 50 182 100.4 .049 0 O1992 0 0 89 18 0 25 O 50 182 88.0 .100 0 01993 0 0 89 l8 O 25 0 50 t82 75.4 .187 O 11994 0 2 89 18 O 50 0 50 207 84.8 .054 0 01995 0 0 2 89 18 0 50 O 50 207 08.6 .128 0 O1996 0 0 2 89 18 O 50 0 50 207 57.1 .245 0 11991 0 0 2 89 18 0 50 200 50 401 180.9 .000 0 O1998 0 0 2 89 12 0 50 200 50 401 162.1 .000 0 01999 0 0 89 À2 0 50 200 50 401 144.5 .000 0 0i000 0 0 89 12 0 50 200 50 401 127.8 .018 0 02001 0 0 2 89 12 O 50 200 50 401 112.-2 .195 0 12002 0 0 2 89 8 0 75 200 50 422 107.9 .256 0 12003 0 0 2 89 8 0 100 200 50 447 105.0 .195 0 02004 0 0 2 89 4 0 123 200 50 468 100.0 .144 0 O2005e 0 2 89 4 0 150 200 50 493 96.4 .124 0 O20060 O 2 89 4 0 150 200 50 493 81.9 .26 0 12007 0 0 89 4 0 173 200 50 518 78.0 .236 0 12008 0 0 2 89 4 0 200 200 50 $43 74.0 .217 0 12009 0 2 89 4 0 225 200 0 se 69.6 .219 0 12010 0 0 89 4 0 250 200 50 593 65.2 .210 0 12011 0 0 2 89 0 0 273 200 50 614 59.1.258 0 12012 0 0 2 89 0 9 300 200 50 639 54.7 .273 1 12013 0 0 2 89 0 0 350 200 50 689 55.9 .173 0 S2014 0 0 a 89 0 0 373 200 50 714 50.6 .229 0 120150 0 2 89 0 0 40 200 50 739 4.5 .279 1 1
_94 -nuex 7Page 8 of 26
"REGIONAL COOPERATION" WITE KINSHASA-BRAZZAVILLEAND INCA-POINTE NOIRE LINES
EXPECSED COSt Or OPERATION
TO=AL COSS
DOMESTZC AND FORIGN
TME r PLAR s DIES FUEL uAt ELuE ELEB LONM S$RS EN8
YE^é TOTAL COSS BY P?LT TYPE (1000$>
1991 2563 383 0 394 O 786 0 801 199
1992 2971 396 0 415 0 1197 0 a80 163
1993 4370 418 0 435 0 1766 0 801 951
1994 4746 399 0 873 0 2473 0 801 200
1995 6313 441 0 956 0 3750 0 801 365
1996 8720 475 0 1106 0 4985 0 801 1353
1997 9112 345 0 2207 5480 279 0 801 0
1198 10063 226 0 862 7774 400 0 801 0
1999 11687 241 0 773 9407 465 0 801 0
2000 12538 244 0 794 10206 493 0 801 0
2001 14927 261 0 863 11974 542 0 801 485
2002 17807 184 0 1341 13876 573 0 801 1032
2003 20391 186 0 1856 15918 582 0 801 1048
2004 25758 628 0 13717 9406 664 0 801 541
2005 28006 627 0 17491 7737 583 0 801 766
2006 31950 629 0 17651 10302 674 0 801 1893
2007 34196 628 0 21438 9027 616 0 801 1687
2008 36781 628 0 25122 8049 567 0 801 1614
2009 39813 628 0 28742 7449 532 0 801 1661
2010 41838 626 0 11S01 6265 466 0 801 lUO
2011 45494 0 0 35390 6242 457 0 80s 2604
2012 49279 0 0 39026 6011 441 0 SO1 3000
2013 51854 0 0 44567 4328 363 0 801 1795
2014 56444 0 0 47994 4602 367 0 801 2683
2015 61434 0 0 51704 4911 365 0 801 3654
TOTILS 629058 8593 0 387518 158964 24385 0 20025 29573
- 95 - Annxez Page 9 of 26
"REGIONAL COOPERATION" WITE KINSHASA-BRAZZAVILLE LIrES
SUMUIRY REPORT
PROCESSED BY TU W5P-IUI cOHUtER PROCIUW PAACG1or TU LtAl
S?UDY 111200
1991 - 2015
PLANINC PERZOD
1991 - 2010
CONSRUCTXON CoSys;l MILLION $
AU RIEPOIO ONILY FOR
PLANTS COOISSIONSD
OUR 1NC PLANNIN 1ERIOD.
ALL OzI= DSOuXA IS C15GlFOU TUE UOLE StUDTY P1RIO.
- 96 - Ames 7Page 10 of 26
"REGIOMAL COOPSATION" VITE KIINSHASA-BRAZZAVILLE LIMES
UIS 15 à LZS OF DI IEU S GO CTNC FOI PLMfS
US3E Dl Tu S&UOT.
Tu IWC CODES Au U8ED nT T coae< PIOO
O DZES DUESEL ASOIL PLU?
1 FUEL 84VW FUEL 11*11:
2 au NATURAL auS PFUIE
3 ELEC ELECT LI4 ELmE tLECS. DORS 81
Lon LtA l STOUAQESUT SUOET S3t STORAC
MtNUAL LAD DESOIfI
?ERXOD<S) PER YEJR : 3YLR 11a41.8 .R1tE 1UN.LO*D GR.1tS ENERCY 1.421t LO8FACT
nu MW Gu C X
199 91.0 - 48.3 - 546.9 - 68.60
1992 97.0 6.0 51.5 6.6 582.9 6.6 68.60
1"9 104.0 7.2 35.3 7.2 625.0 7.2 68.60
1994 111.0 4.7 59.0 6.7 667.1 6.7 68.60
1995 123.0 10.8 63.9 8.4 727.7 9.1 67.54
199f 132.0 7.3 68.6 7.3 781.0 7.3 67.54
197 142.0 7.4 73.8 7.6 840.2 7.6 67.54
1"8 153.0 7.7 79.5 7.7 905.2 7.7 67.54
1999 164.0 7.2 85.2 7.2 970.3 7.2 67.54
2000 176.0 7.3 86.0 .0 1003.4 3.4 65.082001 189.0 7.4 92.3 7.4 1077.5 7.4 63.08
2002 203.0 7.4 99.1 7.4 1157.3 7.4 65.08
2003 218.0 7.4 106.5 7.4 1242.8 7.4 65.08
2004 234.0 7.3 114.3 7.3 1334.0 7.3 65.08
2005 251.0 7.3 122.6 7.3 1430.9 1.3 65.08
2006 271.0 8.0 132.4 8.0 U54S.0 8.0 65.08
2007 291.0 7.4 142.1 7.4 1659.0 7.4 65.08
200a 312.0 7.2 152.4 7.2 1778.7? 7.2 65.08
2009 335.0 7.4 163.6 7.4 1909.8 7.4 * 65.08
2010 359.0 7 2 171.9 S.0 1982.1 3.8 63.03
2011 38.O 7 5 184.8 7.5 2131.2 7.5 63.03
2012 413.0 t 0 197.7 7.0 2280.2 7.0 63.03
2013 442.0 7.0 211.6 7.0 2440.4 7.0 43.03
2014 474.0 7.2 226.9 7.2 2617.0 7.2 43.02
2015 508.0 ? 2 243.2 7.2 2804.7 7.2 63.03
. . . . . . . . . . . . . . . . . . . . . . . . ..4
%MAM * Oeo"| f" 4 Oa# "a4 OW I U j O
O b a O O a O O o o O O O O O S O OI
bè . . . . . . . . . . . . . . ........ ..............
. .
.4.
-. . . . . . . . . . . . B .. . .1. . . . . . .
. .... . . . . . . . . . . . . . . . . . . ... d .:
je
................. .... . ........ §fi"
o
- 98 - Am«e 7Page là of 26
"REGIONAL COOPDÀTION" WITE KINSRASA-BRAZZÂVILLE LIMES
SUMfAT 0
FVXYD SYSTEN PLUS OPTIMU SOLUTION(NVaIaL CPACITY tif MW, ImY lit GU)
WlRO SC SIIEAL FUEL TE TTMAL SYSSN £O NOT SiEam
LONM Smt . CAPACITIES CAP US. LO?. HOROCONOITION
YEA O 1 2 3 4 1 2
PR. CAP PR. CAP DIES FUEL M AZ ELEC ELtB M X
1991 0 .0 89 18 0 23 0 50 182 100.4 .049 0 0
1992 0 0 2 89 18 0 25 0 50 182 88.0 .100 O O
1993 0 0 a 89 18 0 25 0 50 8a 735.4 .187 O 11994 0 0 i 89 18 0 50 O 50 207 86.8 .054 0 0
l"s 0 0 a 89 18 0 50 0 50 207 68.6 .128 0 0
1999 0 0 a 89 18 0 5O O 5O 207 57.1 .245 0 1
1997 0O 89 18 0 75 O 50 232 63.7 .118 0 01998 0 0 a 89 12 0 100 0 50 251 64.1 .103 I7 0
1999 0 0 a 89 12 0 100 0 50 251 53.0 .205 0 1:000 0 0 a 89 12 0 125 0 50 276 51.8 .094 0 0
2001 0 0 a 89 12 0 125 0 $O 276 4*.0 .200 0 1
2002 0 0 a 89 8 0 150 0 50 297 46.3 .209 0 12003 0 0 2 89 8 12 150 0 50 309 41.7 .259 0 1
2004 0 0 2 89 4 12 175 0 50 330 41.0 .263 0 12005 0 0 a 89 4 12 200 0 50 355 41.4 .232 0 1
2006 0 0 2 89 4 12 225 0 50 380 40.2 .231 0 1
200i 0 O a 89 4 12 250 0 50 405 39.2 .203 0 1
20080 0 a 89 4 12 275 0 50 430 37.8 .193 0 O
2009 0 0 a 89 4 12 300 0 50 455 3S.8 .207 0 1
2010 0 0 2 89 4 12a 25 0 50 480 33.7 .229 0 1
2011 0 0 a 89 0 12 t37 O 50 524 36.3 .142 0 0
2012 0 à 89 0 12 400 0 50 551 33.4 198 0 1
2013 0 O 2 89 0 12 425 0 50 576 30.3 .281 0 1
2014 0 0 a 89 0 12 475 O 50 626 32.1 .193 0 0
201o 0 0 a 89 0 24 500 0 30 663 30.5 .227 0 1
- 99 - Ana l 7Page 13 of 26
"REGIONAL COOPERATION" NITE KINSHSA-BRAZZAVILLE LIMES
EUPECSW COSS Or OPERATIONTOTAL COST
DOCWSTZC AND FORECN
TPE OF PLANT DIES FUEL uAs SLC uLnS LONM Sm ENS
A MOTAL COST BY PLANT TYPE (1000$)
1991 2563 383 0 394 0 786 o 801 199
1992 2971 396 0 415 0 1197 0 801 163
1993 4370 418 0 435 0 1766 0 801 951
1994 4746 399 o 873 0 2473 o 801 200
1995 6313 441 0 956 0 3750 0 801 365
1996 8720 475 0 1106 0 4985 o 501 1353
1997 11656 2122 0 7044 0 1244 0 801 446
1998 12869 1428 0 9475 0 751 0 801 414
1999 15546 1633 0 10530 0 1202 0 801 1379
2000 15780 1565 0 12431 0 656 0 801 327
2001 18498 1761 0 13607 0 101t o 801 1312
2002 19737 1153 o 16111 0 891 n 801 780
2003 22447 1213 1260 17070 0 952 0 801 1151
2004 24346 609 1203 19855 0 801 0 801 1078
2005 26898 612 1157 22616 0 696 o 801 1016
2006 29867 581 1133 25612 0 648 0 801 1093
2007 32460 537 1099 28477 0 569 0 801 977
2008 35162 496 1063 31386 0 507 0 801 909
2009 38152 442 1018 34413 0 483 0 801 995
2010 39985 361 897 35266 0 443 O 801 1216
2011 425i2 0 704 40041 0 251 0 801 725
2012 46073 O 617 43305 0 268 0 801 1082
2013 50502 0 717 46869 0 478 0 801 1638
2014 53729 O 557 50987 0 308 o 801 1076
2015 58156 0 1102 54665 0 312 0 801 1276
TOTALS 624066 17024 12526 524940 0 27431 o 20025 22120
0 0 Ô 0000 *0 0 0 0 0 0 * * OG0 O O O O * e O O iO O O G Go G s * là b là N o 0> O G .1 b b là Nt N o o C G
....... . . . . ... .... . . . . . . . . . . . . . . .
~~~i 0 i 0 m " O O
là I
. . . . . . . . . . . . . . . . . . . . .
a ~ ~ ~ ~ ~ ~ ~ ~~~~Ut 14 °W
Ob~ ~ ~ ~ ~ ~ ~ ~
o
-101 - Annex tPage 15 of 26
"SBL-RELIANCE" VITE CONBINSD CYL UJITS
StY Ue?OU A G AI991 U oASS0 PA
00100 EbflPmaaL TUENQG MtoaufjLaaagnosoSOCt TED BYI- CIttt PflOM PCAE
S1IIDY PEZUOD
1991 - 2015
3991 - 2015
cONSTRUCTIOn COstsIl N=IIN $
AUE IPoNREO CIILT FOR
PLANTS CO0SStOUEDUR311 TuS PLAN¢ PF180.
.!L 0111 ntOUATION is ¢iFOm Tac veLux STUOY PERtOD.
- 102 - Annez 7Faso 16 of 26
"SELF-RELIANCE" WITE CO ID CYCLE UNITS
UzsIo8 à LIST OF E DIPPREN E"S O £EL C VOU PTSUSED lI TuE STUDY.
TUE uwoxc =Oa AU UU D 8Ym co COtt PRWORM
O DiEs DIES AOIL PLT
1 FMUL liUVYE. PFm IE?2 GZ IATIL unS LANT
3 S= EL£UC LNS4 LE ECT. ImmSRAZA
LONG LMON MM STORMt
Smt S80o Tlm 8201*0
ARUL LOAD DESRIio
11eO(S) VE YL8R * 3
YEUR 18*81.010 O8.GRASIE 1<1.1.04W CR.RTE ENEROT GR.RAST LO4PACT
MW Z MW Z QU Z
1991 91.0 - 48.3 - 546.9 - 68.60
1992 97.0 6.6 51.5 6.6 582.9 6.6 68.60
1993 104.0 7.2 55.3 7.2 625.0 7.2 68.60
1994 111.0 6.7 59.0 6.7 667.1 6.7 68.60
1995 123.0 10.8 63.9 8.4 727.7 9.1 67.54
19f 132.0 7.3 68.6 7.3 781.0 7.3 67.54
1997 142.0 7.6 73.8 7.6 840.2 7.6 67.54
1998 153.0 7.7 79.5 7.7 905.2 7.7 67.54
199 164.0 7.2 85.2 7.2 970.3 7.2 67.54
2000 176.0 7.3 86.0 .8 1003.4 3.4 65.08
2001 189.0 7.4 92.3 7.4 1077.5 7.4 65.08
2002 203.0 7.4 99.1 7.4 1157.3 7.4 65.08
2003 218.0 ` 7.4 106.5 7.4 1242.8 7.4 45.08
2004 234.0 7.3 114.3 7.3 1334.0 7.3 65.08
2005 251.0 7.3 122.6 7.3 1430.9 7.3 65.082006 271.0 8.0 132.4 8.0 1545.0 8.0 63.08
2007 291.0 7.4 142.1 7.4 1659.0 7.4 65.08
2008 31X.0 7.2 152.4 7.2 1778.7 7.2 65.08
2009 335.0 7.4 163.6 7.4 1909.8 7.4 65.08
2010 359.0 7.2 171.9 5.0 1982.1 3.8 63.03
2011 380.0 7.5 184.8 7.5 2131.2 7.5 63.03
2013 413.0 7.0 197.7 7.0 2280.2 7.0 63.03
2013 442.0 7.0 211.6 7.0 2440.4 7.0 63.03
2014 474.0 7.2 226.9 7.2 2617.0 7.2 63.03
201 508.0 7.2 243.2 7.2 2804.7 7.2 43.03
<4
o
" ~ dle no~~~~~~~~~~g~ lU
s oW
if~~~~~~49 ..44*4 .4 .4.4 .4 . 4 e 4.4 .4 .4 4f.4 V4 .04
a . ~~~~~~~~~~~~~~ ..... ..
W.4 .4 ~ ObC è, 4949 4 40
> ~ ~~~ o oe oe o ,
, | gg0|R0^° :::::::::::::oe ::: ::::::::::.4
g~~~~~~~~~F !d . . . . . . . . . . ^. . . . . . .
3~ ~~ ~ ~~~~~~~~ .1 1 l '" i °1 °. s ;°a ° 1 aà 1 *1 à 1 n a 1
-104- Amex 7Page 18 of 26
"SELF-RELIANCEW WITH COMNIERD CYCLE UNITS
O "a ------ PRESNt wu"8 COSu cr tB nu t as ) ------ OW U.n LO?P Do012 CC?5 lmT SHR.O CONCS SLVAL OPCOt tNSCSt TOTAL <CUM)0 z TOC5 LIU LM.C
;1 ^1739 I571 $568 152 5088 260492 .282 0 S le ° ° ° °014 $347 28a7 5722 84 6447 254604 .159 0 S 17 0 0 0 0
1 2013 8104 1549 3773 151 6478 348157 .243 0 4 16 0 0 0 002012 *628 3013 5931 toi 7587 241679 .158 0 4 là O ° ° °
!°011 2$66 1533 6074 214 7311 234092 .284 0 4 as 0 0 0 010s 2t 20 1507 6226 129 7648 226781 .175 o * l 0 0 0 0
0 2009 3080 1491 6859 111 8359 219133 .150 O 4 il 0 0 0 03 200o $388 1473 6856 104 8876 210773 .10 0 4 10 0 O 0 O02007 $727 1453 7000 113 9388 20189? .138 0 4 9 0 0 0 0
02006 4100 1430 7138 134 9943 192510 .146 0 à a 0 0 0 00 2005 4$10 1405 7247 187 10538 182567 .163 0 4 7 0 0 0 002004 4961 1378 7278 21t 11079 172029 .181 0 4 6 0 0 0 002003 5457 1348 7343 222 11676 160950 .169 0 4 S 0 O o o02002 6002 1315 7242 278 12207 149274 .218 0 4 4 0 0 D 0
102001 0 0 7261 313 7574 137067 .238 0 4 3 0 0 0 0I 2000 7263 1240 7087 216 13327 129493 .089 0 4 3 0 0 0 0
0le999 0 0 285 724 8010 116166 6238 0 * 0 0 0 0
0 1998 878 1148 6973 116 14729 108157 .104 0 4 2 0 0 0 0
0 l997 966 1096 6873 253 15698 93428 .097 0 4 1 0 0 0 001996 0 0 6634 374 7009 77730 .167 0 4 0 0 0 0
0 199 9562 198 $930 230 14924 70721 .072 0 4 0 0 0 0 001994 0 0 4697 345 3042 $5797 .169 0 0 0 0 0 001993 0 0 4203 260 f&63 50755 .079 9 3 0 0 0 0
0 1992 12727 610 3753 41 15912 46292 .010 0 3 0 0 0 O O
0 1991 28000 1067 3119 327 30380 30380 .140 0 2 0 0 0 0 0
- 105 - Anne? 7Page 19 of 26
"SELF-RELIANCE" WITH COMBINED CYCLE UNITS
sUNMAR? OF
VZXED SYS< nLus OPTs SOLUTion(=CN0UL wACI? rN Zn , M.ERCY ZN MMR)
EYDROCLECUC THERMAL FUEL TYPE TOTAL SYSTS ENERCY NOT SERVED
LONM SUT cwAACITEs CAP REu. LOLP. IYDROCOODITION
Y£ZR 0 1 2 3 4 1 2PR. ClIfP. CAP DiES ULoz ELEC ELEB X
1991 0 0 a 89 18 0 50 0 0 1577 3.0 .140 0 0
192 0 0 a 89 18 0 75 0 0 182 8.0 .040 0 01993 0 0 2 89 18 0 75 0 0 182 75.4 .079 0 01994 0 0 2 89 18 0 »s 0 0 182 64.3 .169 0 11995 0 0 2 89 18 0 100 0 0 207 68.6 .072 0 01996 0 0 2 89 18 0 100 0 0 207 37.1 .167 0 0
1997 0 0 2 89 18 0 125 0 0 232 63.7 .097 0 01998 0 0 2 89 12 0 150 0 251 64.1 .104 0 0
1999 0 0 2 89 12 0 150 0 251 53.0 .28 0 12000 0 0 2 89 12 0 175 0 0 276 56.8 .089 0 0
2001 0 0 2 89 12 0 15 0 0 276 46.0 .238 0 1
2002 0 0 89 8 0 200 0 0 297 46.3 .218 0 12003 0 0 a 89 a 0 225 0 0 322 47.7 .169 0 0
2004 0 0 2 89 4 0 250 0 0 $43 46.6 .181 0 02005 0 0 2 89 4 0 275 0 0 368 46.6 .163 0 0
2006 0 O 2 89 4 0 300 0 0 393 45.0 .146 0 02007 0 0 2 89 4 0 325 0 0 418 43.6 .138 0 0
2008 0 0 2 89 4 0 350 0 0 443 42.0 .1SS 0 02009 0 0 2 89 4 0 375 0 0 468 39.7 .150 0 0
2010 0 0 2 89 4 0 400 0 0 493 37.3 .175 0 0
2011 0 0 2 89 0 0 425 0 0 514 33.2 .284 0 12012 0 0 2 89 0 0 47 0 0 564 36.6 .158 0 0
2013 0 0 2 89 0 0 500 0 0 589 3.3 .243 0 1
2014 0 0 2 89 0 0 550 0 0 639 34.8 .159 0 02015 0 O 2 89 0 0 55 0 0 664 30.7 .282 0 1
-106 - Annex 7Page 20 of 26
"SELF-RELIANCE" VITE COMBINIED CYCLE UVITS
MECTED COST aF OPERATZO
TOAL cosuDOSTZC AuD VOIEGu
TYPt Or PLNSt DIES FUEL GAZ ELEC EFSm LOnM SERT tuNTUAi TOUTL COS BY PLANT TYPt <1OOO)
1991 3615 653 0 1818 0 0 0 801 3431992 4378 615 0 2914 0 0 0 801 481995 5463 188 0 3715 0 0 C 01 3291W94 7039 1083 0 4673 0 0 0 801 482
1995 9460 1148 0 715? 0 0 0 801 3541996 11839 1521 0 8884 0 0 0 801 632
1997 13242 1480 0 10490 0 0 0 801 47119§8 14490 1038 0 12413 0 0 0 801 2371999 18008 1331 0 14247 0 0 0 801 1629
2000 18063 1172 0 15555 0 0 0 801 335
2001 20603 1510 0 17442 0 0 0 801 8512002 22502 1022 0 19847 0 0 0 801 8332003 24909 1050 O 22326 0 0 0 01 732
2004 27143 543 0 25007 0 0 0 801 792ZOOS 29607 459 0 27604 0 0 0 801 743
2006 31862 400 0 30072 0 0 0 801 589
2007 34278 368 0 52546 0 0 0 801 543
2008 36897 294 0 35249 0 0 0 801 $54
2009 39477 226 0 37801 0 0 0 801 6492010 40766 181 0 5955 0 0 0 801 8282011 44369 0 0 42058 0 0 0 801 1509
2012 4681? 0 0 45232 0 0 0 801 7842013 50573 O 0 48486 0 0 0 801 1286
2014 54540 0 0 52934 0 0 0 801 805
2015 59097 0 0 56724 0 0 0 801 1572
lOt"LS 649235 16912 0 414168 0 o 0 20025 18129
-107 - Annex 7Page 21 of 26
"SELF-RELIANCB" VIT} COMBINED CYCLE UNITS
caPZTL cAS now smtAY
FUEL CONSTRUCTOUYE DJ0M. FOR. TOAL DCMI. PMa. OTAL OR. TOS.
198 .0 .0 .0 .1 2.3 2.4 2.4
1989 .0 .0 .0 .9 14.7 15.6 15.71990 .5 .0 .5 .9 14.1 15.0 15.51991 .2 .0 .2 .2 3.7 3.9 4.11992 .0 .0 .0 .1 1.1 1.2 1.21993 .0 .0 .0 .4 6.8 7.2 7.21994 .2 .0 .2 .3 5.0 5.4 5.61995 .0 .0 .0 .6 9.7 10.3 10.41996 .2 .0 .2 .8 12.8 13.6 13.91997 .2 .0 .2 .4 5.9 6.3 6.51998 .0 .0 .0 .5 8.3 8.9 8.91999 .2 .0 .2 .4 5.9 6.3 6.52000 .0 .0 .0 .6 9.7 10.3 10.42001 .2 .0 .2 .9 14.2 15.1 15.42002 .2 .0 .2 .9 14.2 15.1 15.42003 .2 .0 .2 .9 14.2 15.1 15.42004 .2 .0 .2 .9 14.2 15.1 15.42005 .2 .0 .2 .9 14.2 15.1 15.42006 .2 .0 .2 .9 14.2 15.1 15.42007 .2 .0 .2 .9 14.2 15.1 15.42008 .2 .0 .2 .8 12.8 13.6 13.92009 .2 .0 .2 .3 4.5 4.8 5.0
3.8 .0 3.8 13.8 216.8 230.7 234.4
-108 - Annex Page 22 of 26
lYDROPOWER PROJECTS INCLUED
SUH!URY POt?OS AY GNUTioU E,SIN PFLAN PFm
?TU S lAPC
19*1 - 2015
PUNIAS P1120
19g, - 20u5
CoUSEmWCtZOW CO818
sa NIzOS $
Au RIPC=D ont FO
PLU"S CO0SuiO
DWZISG MtR PLAM P£R1OO0MLL 01S CuOWAu 28 GIE
FOm S III SUMY P9210.
-109 - Annax 7Page 23 of 26
HYDROPOW R PROJECTS INCLUDED
mil 28£ à28 CVs or DIVVBUN TYE Or ELECTUC POUR PAUJ?SU81S lu TU SSMDY.
u uw C COmuS USS D Dy T81 COWUM P_OOLN
O DtES DES CSOL PLS?n N!L IVY nL
2 Z NuL US ?UL?
3 lmC EITC LUn4 LE13. DWOR EAZ
LML. m STORMun8? sBu" TMN STOSC
àNUA LM DESCRZOIU
:ZIODcS) PE Yz t unAR hAuOD GRlmA .LOAD OR."IA SUSY CR.UATE LODIACSTOR
lu X Z X X
1991 91.0 - 48.3 - 546.9 - 68.60
lm91 97.0 6.6 51.5 6.6 582.9 6.6 68.60
1993 104.0 7.2 55.3 7.2 625.0 7.2 68.601994 111.0 6.7 59.0 6.7 667.1 6.7 68.60
l"5 113.0 10.8 63.9 8.4 727.7 9.1 67.54
196 132.0 7.3 68.6 7.3 781.0 7.3 67.541997 142.0 7.6 73.8 7.6 840.2 7.6 67.54
1998 153.0 7.7 79.5 7.7 905.2 7.7 67.54
1999 164.0 7.2 85.2 7.2 970.3 7.2 67.542000 176.0 7.3 86.0 .a 1003.4 3.4 65.082001 189.0 7.4 92.3 7.4 1077.5 7.4 65.08
2002 20S.0 7.4 99.1 7.4 1157.3 7.4 65.08
2003 218.0 7.4 106.5 7.4 1242.8 7.4 65.082004 234.0 7.3 114.3 7.3 1334.0 7.3 65.08
200a 251.0 7.3 122.6 7.3 14iO.9 7.3 65.082006 271.0 8.0 132.4 8.0 1545.0 8.0 65.082007 291.0 7.4 14t.1 7.4 1659.0 7.1 65.08ao00 $12.0 7.2 152.4 7.2 1778.7 7.2 65.082009 $»3.0 7.4 163.6 7.4 1909.8 7.4 65.08
2010 U39.0 7.2 171.9 5.0 1982.1 $.8 63.03
2011 388.0 7.5 184.8 7. 2131.2 7.5 63.03
2012 413.0 7.0 197.7 7.0 2280.2 7.0 63.03201 442.0 7.0 211.6 7.0 2440.4 7.0 63.03
2014 474.0 7.2 226.9 7.2 1617.0 7.2 63.03025 508.0 7.2 243.2 7.2 1804.7 7.2 63.03
-110- Annez 7Page 24 of 26
HYDROPOWER PROJECTS INCLUDED
0 3015 198 2890 4281 12 4601 335790 .084 16 a 0 0 1 2
0 20t4 8736 a2$ 4121 a2 4647 $31189 .034 13 * O 0 1 a
0 sois s010 tao1 3891 25 4709 326542 .044 la 7 O O I a0201a 2nu8 1084 3619 24 45à9 321033 .044 11 6 O O 1 a
o mOa: Ulà 1867 33i0 24 4648 317234 .026 9 6 O O 1 2O as:. 4006 2157 3062 7 *919 $1258 .011 7 6 0 0 1 2
02009 0 0 2921 a 2923 30766? .016 * à O 0 1 2
000J O 0 20 517 3044 .003 5 0 0 1 2
0200t 0 0 2078 . 20a 302221 .000 0 0 O O 1a2
02006 98749 36701 1638 0 34 $00147 .000 6 à O 5 1 2
02005 3687 1149 5251 12 7913 236461 .106 6 8 0 0 10 2004 3041 844 4894 94 7185 228548 .116 6 4 O O 1 10 200 4441 110 4722 41 8121 221363 .055 S 4 O 0 1 10200t 4907 1076 4292 56 U79 213242 .065 5 à O O 1 1
0 2001 0 0 3001 148 $949 205063 .059 5 2 0 0 1 1
0 2000 5937 1015 3020 48 7990 201114 .015 t0 0 1 1
0 i99 46446 8383 2758 il 41032 193124 .022 à I O 0 1 1
0 1993 538 703 3272 lis 8071 152092 .037 5 1 0 0 1 0
0 997 0 0 2657 2 58 144021 .016 2 . 0 0 1 0
o 1996 77640 10042 2459 17 70037 141365 .002 4 * O O I °
0 199 7172 $96 5755 202 12533 71326 .121 4 I O O O °
0 199 0 0 4713 192 4905 58793 .129 3 1 0 0 0 00 19 8678 0 4315 334 12821 5s888 .030 3 1 0 0 0 00 1993 o 3736 201 3937 41068 .09 9 2 3 0 0
01991 3s000 1326 3376 80 7130 37130 .035 à 1 O O O O
MLL *his= uS I
-111- Annex 7Page 25 of 26
HYDROPOVER PROJECTS INCLUDED
EXECSD cm OF OPEuAUSoNTOU^L CO
DOHESTZC mAD FOmiRoNTMPE O? PULE DliES FUEL CAu 8LEC unII LONM SuRS EUSlema totAL cos? n PLU? TYPM (10008)
1991 3572 68d 1114 177 5 0 0 801 1921992 4435 900 1352 1019 0 0 0 801 3631993 5720 1070 2225 1143 0 0 0 801 4811994 6971 1355 2739 1403 0 0 0 801 6731995 9198 1688 4281 1715 0 O 0 soi 7131996 4172 661 1707 673 o o 225 801 1051997 4883 803 2220 786 0 0 225 soi 491998 6848 603 3970 971 0 0 225 801 2771999 6236 506 3619 833 0 0 225 936 1172000 7484 405 *09f 1722 0 0 225 936 1012001 10494 503 5875 2519 0 0 225 936 4342002 13051 280 7150 4050 0 0 225 936 4002003 15792 239 8304 5838 0 0 225 936 2492004 18451 130 11011 5493 0 0 225 936 6562005 21703 179 12231 7506 0 0 225 936 6862006 7157 75 3243 1777 0 0 225 1836 02007 10100 76 5970 1923 0 0 225 1836 712008 13294 81 8544 2549 0 0 225 1836 192009 17116 144 11428 3468 0 0 225 1836 152010 19749 98 13375 4160 0 0 225 1836 552011 24182 0 17684 4238 0 0 225 1836 1992012 28597 0 22048 4263 0 0 225 1836 2262013 $3681 0 25774 5578 0 0 225 1836 2682014 39335 0 29806 7145 0 0 225 1836 3232015 45008 0 35677 6833 0 0 225 1836 437bOTALS 377290 10485 245493 78382 0 0 4500 31320 7110
-112 - Anne 7Page 26 of 26
KYDROPOWER PROJBCTS INCLUDED
CAflTL CMS am.0 SUIIA
lm cousTIUCx0 roc
ma DM. t. mOuL D. . =OtA DO. To. TOL OR. mT.
1900 .0 .0 .0 .3 2.8 3.0 .1 .7 .8 3.8
1989 .0 .0 .0 I.J 16.6 18.1 .2 2.5 2.7 20.9
1990 .4 .0 .4 1J. 12.2 13.7 .5 2.6 3.2 l?.3
199 .0 .0 .0 2.0 10.9 . 12.9 .I 4.0 4.0 17.8
1992 .1 .0 .1 5.0 21.9 26.9 1.l 7.8 9.7 36.7
1993 .0 .0 .0 8.4 36.5 44.9 2.3 9.5 11.0 56.7
1994 .1 .0 .1 5.2 26.3 32.5 1.3 5.1 6.4 38.9
1995 .0 .0 .0 4.2 11.3 21.6 1.1 4.7 5.8 27.4
1996 .0 .0 .0 6.5 28.9 35.4 1.7 }.1 8.8 44.2
1997 .1 .0 .1 6.6 28.7 35.3 1.1 4.7 5.7 41.1
1998 .0 .0 .0 2.4 14.0 17.3 .2 1.5 1.7 19.0
1999 .2 .0 .2 .3 4.8 5.1 .0 .5 .6 $.9
2000 .0 .0 .0 2.5 15.8 18.3 1.6 7.3 8.9 27.2
2001 .1 .0 .3 5.7 30.9 36.6 2.8 12.1 14.9 51.y
2002 .2 .0 .2 16.0 70.4 86.5 6.3 25.8 32.1 11$.8
200z .1 .0 .1 26.8 113.6 140.4 7.3 30.1 37.4 177.9
2004 .2 .0 .2 17.6 73.2 90.8 2.8 11.5 14.3 105.3
2005 .0 .0 .0 4.8 19.4 24.2 .3 1.3 1.6 235.8
2006 .0 .0 .0 .0 .0 .0 .0 0 0 .0
2007 .0 .0 .0 .2 2.0 2.1 .0 .5 .6 2.7
20a8 .0 .0 .0 1.2 13.3 14.5 .2 2.2 2.4 16.9
2009 .4 .0 .4 1.8 27.7 19.5 .2 2.3 2.6 22.5
2010 .2 .0 .2 1.8 17.0 18.9 .2 2.3 2.6 21.7
2011 .2 .0 .2 1.7 18.9 20.6 .2 2.6 2.9 23.8
2012 .4 .0 .4 1.8 20.4 22.2 .3 2.8 3.1 235.7
ton .4 .0 .4 2.2 21.0 23.2 .3 2.6 2.9 26.4
2014 .3 .0 .3 .9 7.9 0.8 .1 .5 .6 9.7
3.8 .0 3.8 130.0 6*3.3 793.3 33.9 154.8 1U.7 985.9
- 113- Annex 8Page 1 de 14
CEUJUU:TEU STICS OP TEZ NAIN Dm VBIOPNNT LOiU-GROITUM RYPOTHESIS
1. This annex presents the two most important developmentalternatives studied in the case of the low-growth hypothehis. Theresults of the analysis of each of these are sumarized in the follovingtable and presented below.
Index:Objective Least-CostFunction Solution a
Solution Brief Description (In oil. of USI) 100
"Rogional Cooperationn i-M line in 1996, and 140.2 100alternative 2 x 25 MW GT + 3 x 75 MW CC
uSeif-reliancen 5 x 2S MW GT + 4 x 75 MW CC 193.9 138alternative
The two alternatives have been described according to the same procedure:
- review of the list of the various candidates;
- review of demand;
- type and number of generation units to be installed, by year;
- changes in the objective function (total discouated coste; baseyear 1 1991);
- operating coste, by year;
- investment, by year.
- 114 - AnneS 8Page 2 de 14
"REGIONAL COOPERATION" ALTERNATIVE
SUMOY REPOiT
on A CENERATION XPANSION PLN 0
COO11010 DZom CMSE'
P&OCESSED BY TB L COMPUTR PROA PACE
OF rE rZA
s$uDY PERSOD
1991 - 2015
P=LANIN2 PERIOD
1991 - 2015
coNsTRUCTrON COSTS
ZR MILLION $
ARu NUPRTRED ONLY FOp
PLAITS 0mO(ssionD
OUR-IN Tu PLNNI PERION.
AU. OTRER INroRmoT O s CGIVEN
FOR TUE WHOLE StUDY PEROD.
- Annex 8Page 3 de 14
"RECIOIAL COOPERATION" ALTERNATIVE
Z88 28£ LIST CF E DI7UU T OP CTRC POWER PL=S$USED luE 8t 8TUY.
SUl NUCe COOES AuE 08 aETU COe@ PRANS
O DiE DIES CASOIL PLU
I FUEL lll" L FUIT2 OAU AUtSL aU8 PtL$ ZLEC EZC LtiE4 L .L . neORT aIZ
WOLMII 8mmmS0iUCSISM UOR lm STORUE
AMUL D U DExCRZTOu
12D08) Mli 11 3YUR PEALO 08.3411 NI.LOAD CR.RA EM = CR.8R LOM :AC
IU11 Z 11I1 S COlll Z X
1991 U4.0 - 43.7 - 516.8 - 68.60
1992 90.0 4.? 47.8 4.7 $40.9 4.7 68.60
1993 $5.0 5.6 50.5 5.6 570.9 .5.6 68.60
19"4 100.0 5.3 53.1 5.5 601.0 3.3 68.60
19"S 110.0 - 57.2 - 450.8 - 67.54
1996 116.0 5.5 60.3 5.5 686.3 5.5 67.54
199? 125.0 6.0 63.9 6.0 727.7 6.0 67.54
1998 131.0 6.5 68.1 6.5 775.1 6.5 67.54
1999 139.0 6.1 72.2 6.1 822.4 6.1 67.54
2000 148.0 6.5 72.3 .1 843.7 2.6 65.08
2001 1S7.0 6.1 74.7 6.1 895.0 6.1 65.08
2002 167.0 6.6 81.6 6.4 952.1 6.4 65.08
2003 178.0 6.6 85.9 6.6 1014.8 6.6 65.08
2004 189.0 6.2 9a.3 6.2 1077.5 6.2 65.08
2005 201.0 6.3 98.2 6.3 1145.9 6.3 65.08
2006 215.0 7.0 105.0 7.0 1225.7 7.0 65.082007 229.0 6.5 111.8 6.5 1305.5 6.5 65.082008 244.0 6.6 119.2 6.6 1391.0 6.6 65.082009 259.0 6.1 126.5 6.1 1476.5 6.1 65.08
2010 276.0 6.6 132.1 4.3 1523.8 3.2 63.032011 294.0 6.3 140.7 6.5 1623.2 6.5 63.032012 314.0 8.8 150.3 6.8 1733.6 6.8 63.03
2013 334.0 6.4 159.9 6.4 1844.1 6.4 63.032014 355.0 6.3 169.9 6.3 1960.0 6.3 63.03201 378.0 6.5 181.0 6.5 1087.0 6.5 63.03
- 116 - Annex 8Page 4 de 14
"REGIONAL COOPERATION" ALTERNATIVE
OPStIN SOLUtIONMUAL ADDZTIONS: CAPACItYO) A11D NUMER CO UNttS OR PROJZCTS
MOX DEtAILS or :uDIVIoDUtl ututS OR PROJECTS SU VARIAI557 SYST11 REOTSU ALSO FIXtD SYSSt l REPORtt tOR OV71 ADDITONS OR ETISR<MTS
UMSE: D012 CC75 2NTS SURt
TC25 LtIE LONC
SUE£ O)t 12. ZS. S0. 0.xLOt 25. 200. 0.
TZR 4AMI g0 CAP
1991 .242 .239 50. . . . . 1
1992 .046 .045 25. . 1
1993 .084 .073 O.
1994 .125 .118 O.
1915 .2S2 .233 0.
1996 .000 .000 200. . . . 1
1997 .000 .000 0.
1998 .000 .000 0.
1999 .000 .000 0.
2000 .000 .000 0. . . .
2001 .000 .000 O. * . * *
2002 .063 .029 0.
2003 .552 .262 0.
2004 .421 .1Au 25. . . .
2005 .250 .079 25. . 1
2006 .175 .049 25. . . 1
2007 .134 .039 25. . . .
2008 .256 .141 0.
2009 .193 .088 25. . . 1
2010 .146 .062 2S. . . 1
2011 .145 .054 25. . . .
2012 .273 .121 0.
2013 .247 .104 25. . . *
2014 .222 .091 25. . . 1
2015 .213 .087 25. . . *
tOTALS 525. . 2 9 1 1
-117- Antex 8Page 5 de 14
"REGIONAL COOPERATION" ALTERNATIVE
O YE - RES- tST 80R?U O0SS Cm 9Tu Y ------ OBJ.FUU. LOLP D012 OCt5 18TM SUR?
O CO0S SILVAL OPoOSS ENSCS? =OL (CUMM.) 2 1023 LInB LOXG
0 2015 1729 1571 3851 13 4*212 140246 .213 0 a 9 1 1 0 0o 204i u913 1u41 3914 210 4482 13*034 .222 0 2 a 1 1 0 0o 2013 2104 1549 3976 2M5 4786 131552 .247 0 2 7 1 1 0 00 2012 0 0 4023 295 4318 126760 .273 0 2 6 1 1 0 03 2011 2546 1523 4116 132 5271 122448 .145 0 2 6 1 1 0 00 2010 2800 1508 4209 133 5635 117177 .146 0 2 3 1 1 0 03 2009 3080 1491 4373 241 6203 111542 .193 0 2 4 1 1 0 002008 0 0 4417 324 4741 105338 .256 0 2 3 1 1 0 00 2007 3727 1452 4470 166 6911 100597 .134 0 2 3 1 1 0 002006 4100 1430 4475 198 7342 93686 .175 0 2 2 1. 1 0 00 200o 3687 1149 4487 248 7273 86343 .250. 0 2 1 1 1 0 03 2004 4961 1378 4090 464 8137 79070 .421 0 1 1 1 1 0 002003 0 0 3762 553 4315 7093 .552 0 1 0 1 1 0 002002 0 0 3604 37 3641 66618 .063 0 1 0 1 1 0 002001 0 0 3467 0 3467 62977 .000 *0 1 0 1 1 0 002000 0 0 3490 0 3490 $9510 .000 0 1 0 1 1 0 001999 0 0 3555 0 3555 56020 .000 0 1 0 1 1 0 001998 0 0 3418 0 3418 52464 .000 0 1 0 1 1 0 00199"7 0 0 372 0 3372 49046 .000 0 1 0 1 1 0 00 1996 19869 1925 3245 0 21189 45674 .000 0 1 0 1 1 0 00o.99 0 0 2514 531 3045 2448 .252 0 1 0 0 1 0 001994 0 0 2192 245 2438 .21440 .1» 0 1 0 0 1 0 001993 0 0 2087 174 2261 19002 .084 0 1 0 0 1 0 00 1992 12728 610 1992 164 14275 16742 .046 0 1 0 0 1 0 001991 325 12 1640 514 2467 2467 .242 0 0 0 0 1 0 0ALL 0$si8BLt ?A198 TRAMZD
-118 - Annex8Page 6 de 14
"REGIONAL COOPERATION" ALTERNATIVE
MEMCtED COSS Or OPERATION
TOMAL COSS
DOKS0TiC AD 7OE8G0
lYP QD PLAIS t Dilu FUIL CUZ ELEC ETRP L09C SRRS viS
12*8 TOmL COSS IIY PUIS? TYPS 1000t)
:991 2259 404 0 0 0 Sf5 0 801 539
1992 2488 379 S 393 0 725 0 801 190
1993 286 388 0 405 0 1054 0 801 2201994 3403 409 0 425 0 1426 0 801 343
1995 4676 429 a 462 0 2168 0 801 81a
1996 5481 985 0 1293 2278 124 0 801 0
1997 6265 998 0 1231 3130 105 0 801 01998 1986 670 0 1161 4238 116 0 801 01999 7993 450 0 1103 5395 243 0 801 0
2000 8631 616 0 941 5941 332 0 801 0
2001 9432 242 0 430 7574 386 0 801 0
2002 10894 163 0 391 8980 449 0 801 1102003 14204 176 0 425 10477 505 0 801 1819
2004 16491 629 0 6294 6535 330 0 801 1681
2005 10862 628 0 8$57 7113 573 0 801 9892006 20469 626 0 12294 5404 479 0 801 8652007 22$42 623 0 15457 4248 412 0 801 801
2008 25135 629 0 15987 5526 473 0 801 1718
2009 26905 628 0 19151 4S06 417 0 801 14032010 27854 626 0 21643 3370 361 0 801 85
2011 29974 o o 24641 3260 342 0 801 929
2012 33516 0 0 25740 4292 $89 0 801 2293
2013 36124 0 0 2a863 3915 368 0 801 2178
2014 38786 0 0 32050 3538 347 0 801 2029
2015 41782 0 0 $35279 3370 334 0 801 1999TOTALS 423821 10698 0 254817 103311 13195 0 20025 21774
-119 - Annex 8Page 7 de 14
"REOIONAL COOPSRATION" ALTRATIVE
FUL C0U8'IRUCTaO IOC
YEAR DON. roE. MTO DN. ro. TOTAL DON. FOU. MOTAL 0. T02.
1988 .0 .0 .0 .0 .0 .0 .0 .0 .0 .0
i98§ .0 .0 .0 .1 1.1 1.2 .0 .S .3 l.5
1990 .0 .0 .4 .4 7.1 7.5 .1 1.0 1.1 8.6
1991 .2 ., .2 .2 5.7 3.9 .0 .2 .3 4.4
199 .0 .0 .0 .0 .0 .0 .0 .0 .0 .0
1993 .0 .0 .0 .6 2.2 2.8 .1 .6 .7 5.6
1994 .0 .0 .0 3.4 13.4 16.8 .5 ?a.0 2.5 19.5
1995 .0 .0 .0 1.8 7.2 9.0 .1 .5 .6 9.7
1996 .0 .0 .0 .0 .0 .0 .0 .0 .0 .0
1t997 .0 .0 .0 .0 .0 .0 .0 .d .0 .0
.998 .0 .0 .0 .0 .0 .0 .0 .0 .0 .0
1999 .0 .0 .0 .0 .0 .0 .0 .0 .0 .0
2000 .0 .0 .0 .0 .0 .0 .0 .0 .0 .0
2001 .0 .0 .0 .1 1.4 1.5 .0 .4 .4 1.9
2002 .0 .0 .0 .6 9.5 10.1 .1 1.6 1.7 11.7
-00; .2 .0 .2 .8 12.7 15.5 .1 1.? 1.8 15.5
2006 .s .0 .5 .9 13.4 14.2 .1 1.9 2.0 16.5
1005 .2 .0 .2 .8 12.8 13.6 .1 1.6 1.7 15.5
1006 .a .0 .2 .4 5.9 6.5 .0 .7 .7 7.2
2007 .0 .0 .0 .6 9.7 10.3 .1 1.6 1.7 12.1
200a .2 .0 .2 .9 14.2 15.1 .1 1.9 2.0 17.4
2009 .2 .0 .2 .8 12.8 15.6 .1 1.6 1.7 15.5
2010 .2 .0 .2 .4- 5.9 6.3 .0 .7 .7 7.2
2011 .0 .0 .0 .6 9.1 10.5 .1 1.6 1.7 12.1
2012 .8 .0 .2 .9 14.2 15.1 .1 1.9 2.0 17.4
201@ .2 .0 .2 .8 12.8 1S.6 .1 1.6 1.7 15.5
2014 .2 .0 .2 .5 4.5 4.8 .0 .5 .3 5.5
2.4 .0 2.6 15.4 174.5 189.6 2.1 21.6 25.6 217.9
120 - Annex 8Page 8 de 14
"SELF-RELIANCE" ALTERNATIVE
SUKARY REPORSON A GENERATION EXPPNSOH PLAU FOR
coNGo 1PROCESSED 8Y tHE WASP-ZIZ COHPUtER PROGRAM PACXACE
OF TuE IAZ
STUY PERSOD
1991 - 2015
PLANNINC PERIOD
1991 - 2015
CONSTRUCTION COSTS
lu MILLION $AEu REPORTED ONLY FOR
PLANTS COMMISSIONEDDURTINC TUE PLASNINC PERIOD.
ALL OTEER INFORMATION IS GIVEN
FOR TUE W80LE STUDY PERIOD.
Page 9 de 14
"SHLF-RBLIANCE" ALTERNATIVB
lISZ 15£A LZS? OP ME DIPTRUT TYPES orV EL CTZ poNtE pLANTs115KD 1l TU STUDY.
TU NUIRT CODES Au1 118 $Y TuE c0WpuT PIORAN
O DIES DIESEL <1401 PLAN
2 GA AiTUA UAS PLANT
4 11.1 ELCT. DWORT IRAZu
LMN tomG lm3 STO&AG
MyI 5101 TM STORAG
41111*1 LM0 DESCRMIPTO
PEIOD<5>) Pl TEA : iY=A PEAV.OA G.lAE 1<111.01 GR.EATI ca10?G.PATE LO*OACTO
mu Z II Z GU Z
1991 86.0 - 45.7 - 516.8 - 68.60
1992 90.0 4.7 47.0 4.7 540.9 4.7 68.60
1993 95.0 5.6 50.5 5.6 570.9 5.6 68.60
1994 100.0 5.3 55. 1 5.3 601.0 5.3 68.60
1995 110.0 - 57.2 - 650.8 - 67.54
1996 116.0 5.5 60.3 5.5 686.2 5.S 67.54
1997 123.0 6.0 63.9 6.0 727.7 6.0 67.54
1998 131.0 6.5 68.1 6.5 775.1 6.5 67.54
1999 139.0 6.1 72.2 6.1 822.4 6.1 67.54
2000 148.0 6.5 72.3 .1 843.7 2.6 65.08
2001 137.0 6.1 76.7 6.1 895.0 6.1 65.08
2002 167.0 6.4 81.6 6.4 952.1 6.4 65.08
2003 178.0 6.6 86.9 6.6 1014.8 6.6 65.08
2004 189.0 6.2 92.3 6.2 1077.3 6.2 65.08
2005 201.0 6.3 98.2 6.3 1145.9 6.3 65.082006 215.0 7.0 105.0 7.0 1225.7 7.0 65.08
2007 229.0 6.5 111.8 6.5 1305.5 6.5 65.08
2008 244.0 6.6 119.2 6.6 1391.0 6.6 65.08
2009 259.0 6.1 126.5 6.1 1476.5 6.1 65.08
2010 276.0 6.6 132.1 4.5 1525.8 3.2 -63.03
2011 294.0 6.5 140.7 6.5 1623.2 6.5 63.03
2012 314.0 6.8 150.3 6.8 1733.6 6.8 63.03
2013 334.0 6.4 159.9 6.4 1844.1 6.4 63.03
2014 355.0 6.3 169.9 6.3 1960.0 6.3 63.03
2015 378.0 6.5 181.0 6.5 2087.0 6.5 63.03
-122- Annex 8Page X0 de 14
"SELF-RELIANCE" ALTERNATIVE
OPTIMUM SOLUTION
ANNUAL ADDITIONS: CAPACITY<NV) AND VMIBER OF U}NITS OR PROJECIS
FOR DETAILS OF lNDIVIDUAL UNITS OR PROJECTS SES VARIABLE SYSTEN REPORT
SU ALSO F!XED SYSTEN REPORT FOR OTHER ADDITIONS OR RETIREMENTS
NA04« 0012 CC75 lNTS SORT
TC25 LIRE LONG
SIZE (MN); 12. 25. 50. 0.
3LOLP 25. 200. 0.
TEAR MaNT 108? CAP
itl" .077 .074 50. . 2 . .
19"2 .225 .115 0. . . . .
1993 .218 .193 0. . . . .
1994 .052 .045 25. . 1 . .
1995 .123 .106 0. . . . .
1996 .22S .181 0. . . . .
1997 .072 .053 25. . 1 . .
1998 .267 .201 0. . . . .
1999 .126 .06 25. . . 1 .
2000 .248 .104 0. . . . .
2001 .099 .037 25. . . 1 .
2002 .283 .118 0. . . . .
2003 .140 .051 25. . . 1 .
2004 .105 .034 25. . . 1 .
2003 .246 .075 0. . . . .
2006 .179 .048 25. . . 1 .
2007 .132 .027 25. . . 1 .
2008 .106 .018 25. . . 1 .
2009 .259 .049 0. . . . .
2010 .186 .037 25. . . 1 .
2011 .193 .038 25. . . 1 .
2012 .177 .035 25. . . 1 .
2013 .166 .033 25. . . 1 .
2014 .169 .032 25. . . 1 .
2015 .193 .035 25. . 1 . .
TOTALS 425. . 5 12 .
-123- Annex 8Page 11 de 14
"SELF-RELIANCE" ALTERNATIVE
SUMMARY OF
PIXED SYSTEM PLUS OPTIMUM SOLUTION
(NOM1NAL CAPACITY lu MW, ENER¢Y lu OC)HYDROELECTRIC TSERMAL FUEL TYPE TOTAL SYSTEN EMERGY NOS SERWD
LONG SHT CAPACItIES CAP RES. LOLP. HYDROCONDITION
TEA O 1 2 3 4 1 2
PR. CAP PR. CAP DIES FUEL GAZ ELEC EMEM S X
1991 0 0 2 89 18 0 50 0 0 157 83.0 .077 0 0
1992 0 0 2 89 18 0 50 O 0 157 74.9 .125 0 0
1993 0 0 2 89 18 0 50 0 0 157 65.7 .218 0 1
1994 0 0 2 89 18 0 75 0 0 182 82.4 .052 0 0
1995 0 0 2 89 18 0 75 0 0 182 65.8 .123 O 0
1996 0 0 2 89 18 0 75 0 0 182 57.2 .225 0 1
1997 0 0 2 89 18 0 100 0 0 207 68.6 .072 0 0
1998 0 O 2 89 12 0 100 0 0 201 53.4 .267 0. 1
1999 0 0 2 89 12 0 125 0 0 226 62.6 .126 0 0
2000 0 0 2 89 12 0 125 0 0 226 52.7 .248 0 1
2001 0 0 2 89 12 0 150 0 0 251 59.9 .099 0 0
2002 0 0 2 89 8 0 150 0 0 241 47.9 .283 0 1
2003 0 0 2 89 8 0 175 0 0 272 52.8 .140 0 0
2004 0 0 2 89 4 0 200 0 0 293 55.0 .105 0 0
2005 0 0 2 89 4 0 200 0 0 293 43.8 .246 0 1
2006 0 0 2 89 4 0 225 O 0 318 47.9 .179 0 0
2007 0 0 2 89 4 0 250 0 0 343 49.8 .132 0 0
2008 0 0 2 89 4 0 275 0 O 368 50.8 .106 0 02009 0 0 2 89 4 0 275 0 0 368 42.1 .259 0 12010 0 0 2 89 4 0 300 O 0 393 42.4 .186 0 0
2011 0 0 2 89 0 0 325 0 0 414 40.8 .193 0 02012 0 0 2 89 0 0 350 0 0 439 39.8 .177 0 ô2013 0 0 2 89 0 0 375 0 0 464 38.9 .166 0 O2014 0 0 2 89 0 0 400 O O 489 37.7 .169 0 02015 0 0 2 89 0 0 425 0 0 514 36.0 .193 0 0
- 124 - Annex 8Paie 12 de 14
"SELF-RELIANCE" ALTERNATIVE
O YUl------ PREStNS IOSTE COST OF TEE YA ( K )- ----- OJ.FU. LOLP D012 CC75 lImE SKRTO CONCST SALVAL OPCOSt ENSCST TOTAL (Cm.>) X SC25 LIME LOgo
0 2015 1421 1284 4135 93 4364 193934 .193 0 S 12 0 0 0 03 2014 1913 1561 4183 85 4620 189569 .169 0 4 12 0 0 0 0. 2013 2104 1549 4354 91 3000 184949 .166 0 4 1 0 0 0 0* 2012 2314 1537 4S02 104 5384 179949 .171 0 4 10 0 0 0 0- 2011 2546 1523 4612 120 5756 174565 .193 0 4 9 0 0 0 0* 2010 2800 1508 4789 122 6204 168810 .186 0 4 8 0 0 0 00 2009 0 0 5112 202 5314 162606 .259 0 4 7 0 0 0 03 2008 3388 1472 5284 91 7292 157292 .106 0 4 7 0 0 0 0a 2007 3727 1452 5337 119 7731 150001 .132 0 4 6 0 0 0 03 2006 4100 1430 5327 182 8179 142270 .179 0 4 5 0 0 0 00 2005 0 0 5263 220 5483 134091 .246 0 4 4 0 0 0 0o 2004 4961 1378 5289 150 9022 128608 .105 0 4 4 0 0 0 00 2003 5457 1348 5333 251 9693 119586 .140 0 4 3 0 0 O 00 2002 0 0 5200 369 5569 109893 .283 0 4 2 0 0 0 0o 2001 6603 1279 5117 143 10583 104324 .099 0 4 2 0 0 0 00 2000 0 0 5010 334 5344 93740 .248 0 4 1 a 0 0 00 1999 7989 1196 5211 164 12160 88397 .126 0 4 1 0 0 0 00 1998 0 0 5177 629 5805 76228 .267 0 4 0 0 0 0 0G 1997 7903 898 4901 190 12097 70423 .072 0 4 0 0 0 0 00 1996 0 0 4248 369 4617 5832? .225 0 3 0 0 0 0 00 1995 0 0 3934 291 4225 53710 .123 0 3 0 0 0 0 00 1994 10519 741 3393 42 13213 49485 .052 0 3 0 0 0 0 a0 1993 0 0 2950 535 3485 36272 .218 0 2 0 0 0 2 00 1992 0 0 2741 266 3008 32787 .125 0 2 0 0 0 0 00 1991 28001 1067 2652 194 29779 29779 .077 0 2 0 0 0 0 0ALL POSS!3LE PATHS TRACED
-125- Annex 8Page 13 de 14
"SELF-RELIANCE" ALTERNATIVE
EXPECTED COSS OP OPZRATIONTOTAL COST
DOMESTIC MAD FORESCNTUE OP PLANT DIES FUEL PAM LEC ELEB LONM SUt EuSTRAN TSOAL COST BY PLANT TYPE (1000$)
1991 2985 538 O 1443 0 0 0 801 2031992 3470 628 O 1734 0 0 0 801 3071993 4422 766 0 2176 0 0 0 801 6791994 4796 690 0 3246 0 0 0 801 591995 6488 970 0 4270 0 0 0 801 447L996 7799 1189 0 5186 0 0 0 801 6231997 9460 1148 0 7157 0 0 0 801 3541998 11865 982 0 8797 0 0 0 soi 12851999 12084 907 0 10008 0 0 0 8Ol 3692000 13216 1036 0 10552 0 0 0 soi 8272001 14309 959 0 12160 0 0 0 soi 3892002 16664 831 0 13928 0 0 0 801 11042003 18382 827 0 15927 0 0 0 801 8s82004 19695 416 0 17935 0 0 0 801 3432005 21857 502 0 19658 0 0 0 801 8762006 24134 512 0 22023 0 0 O 801 7982007 26294 520 0 24399 0 0 0 801 5742008 28496 431 0 26781 0 0 0 801 4842009 309*6 495 0 28512 0 0 0 801 11782010 31500 386 0 29531 0 0 0 801 7832011 33394 0 0 31743 0 0 0 801 8302012 35752 0 0 34141 0 0 0 801 8102013 37952 0 0 36373 0 0 0 so1 7762014 40087 0 0 38485 0 0 0 801 8022015 43669 0 0 £1911 0 0 0 801 958TOTALS 499735 14732 0 448075 0 0 0 20025 16903
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IEmma SECTOR ASSISTANCE PROCRAU
Activitie. Completed
Country Project Date Number
8 YG smciEcY LD STRATOTr
Africa Regional Participants' Reports - Regional Pover Seminaron Reducing Electric System Losses in Africa 8/88 087/88
Bangladesh Pover System Efficiency Study 2/85 031/85Botswana Pump Electrification Prefeasibility Study 1/86 047/86
Review of Electricity Service Connection Policy 7/87 071/87Tuli Block Farms ElectrificationPrefeasibility Study 7/87 072/87
Burkina Technical Assistance Program 3/86 052/86Burundi Presentation of Energy Projects for the
Fourth Five-Year Plan (1983-1987) 5/85 036/85Review of Petroleum Import and DistributionArrangements 1/84 012/84
Burundi/Rvanda/Zaire (EGL Report)Evaluation de l'Energie des Pays des Grands Lacs 2/89 098/89
Costa Rica Recommended Technical Assistance Projects 11184 027/84Ethiopia Pover System Efficiency Study 10/85 045/85The Gambia Petroleum Supply Management Assistance 4/85 035/85Chana Energy Rationalization in the Industrial
Sector of Chana 6/88 084/88Cuinea- Recommended Technical AssistanceBissau Projects in the Electric Pover Sector 4/85 033/85
Management Options for the Electric Powerani Water Supply Subsectors 2/90 100/90
Indonesia Energy Efficiency Improvement in the Brick,Tile and Lime Industries on Java 4/87 067/87
Pover Generation Efficiency Study 2/86 050/86Diesel Generation Efficiency Improvement Study 12/88 095/88
Jamaica Petroleum Procurement, Refining, andDistribution 11/86 061/86
Kenya Pover System Efficiency Report 3/84 014/84Liberia Pover System Efficiency Study 12/87 081/87
Recommended Technical Assistance Projects 6/85 038/85Madagascar Power System Efficiency Study 12/87 075/87Malaysia Sabah Pover System Efficiency Study 3/87 068/87Mauritius Power System Efficiency Study 5/87 070/87Panama Pover System Loos Reduction Study 6/83 004/83Papua New Energy Sector Institutional Reviev: ProposalsCuinea for Strengthening the Department of
Minerals and Energy 10/84 023/84Pover Tariff Study 10/84 024/84
Senegal Assistance Given for Preparation of Documentsfor Energy Sector Donors' Meeting 4/86 056186
Seychelles Electric Pover System Efficiency Study 8/84 021/84
ENERGY SECTOR KANAGEMENT ASSISTANCE PROCRA
Activities Completed
Country Project Date Number
HNERCY SIPICIENCY AUD STRATEGY (Continued)
Sri Lanka Pover System Loss Reduction Study 7/83 007/83Syria Electric Power Efficiency Study 9/88 089/88
Energy Efficiency in the Cement Industry 7/89 099/89Sudan Pover System Efficiency Study 6/84 018/84
Management Assistance to the Ministry ofEnergy and Mining 5/83 003/83
Togo Power System Efficiency Study 12/87 078/87Uganda Energy Efficiency in Tobacco Curing Industry 2/86 049/86
Institutional Strengthening in the Energy Sector 1/85 029/85Power System Efficiency Study 12/88 092/88
Zambia Energy Sector Institutional Review 11/86 060/86Energy Sector Strategy 12/88 094/88Poaer System Efficiency Study 12/88 093/88
Zimbabwe Pover Sector Management Assistance ProjectsBackground, Objectives, and Work Plan 4/85 034/85
Power System Loss Reduction Study 6/83 005/83
BOUSMEOLD9 RURAL, AID RENEIABLE KERMGY
Burundi Peat Utilization Project 11/85 046/85Improved Charcoal Cookstove Strategy 9/85 042/85
China Country-Level Rural Energy Assessments:A Joint Study of ESMAP and Chinese Experts 5/89 101/89
Fuelwood Development Conservation Project 12/89 105/89Côte d'Ivoire Improved Biomass Utilization--Pilot Projects
Using Agro-Industrial Residues 4/87 069/87Ethiopia Agricultural Residue Briquetting: Pilot Project 12/86 062/86
Bagasse Study 12/86 063/86The Gambia Solar Water Heating Retrofit Project 2/85 030/85
Solar Photovoltaic Applications 3/85 032/85Chana Sawmill Residues Utilization Study, Vol. I & II 10/88 074/87Global Proceedings of the ESMAP Eastern and Southern
Africa Household Energy Planning Seminar 6/88 085/88India Opportunities for Commercialization of
Non-Conventional Energy Systems 11/88 091/88Jamaica FIDCO Sawmill Residues Utilization Study 9/88 088/88
Charcoal Production Project 9/88 090/88Kenya Solar Water Heating Study 2/87 066/87
Urban Woodfuel Development 10/87 076/87Malawi Technical Assistance to Improve the Efficiency
of Fuelwood ese in the Tobacco Industry 11/83 009/83Mauritius Bagasse Power ?-t«ntia1 10/87 077/87Niger Household Energy Conservation and Substitutioa 12/87 082/87
Improved Stoves Project 12/87 080/87Pakistan Assessment of ?!.)tovo1taic Programs,
Applications and Markets 10/89 103/89Peru Proposal for a Stove Dissemination Program
in the Sierra 2/87 064/87
Activities Completed
Country Project Date Vumber
OUSDHOLD, RURAL, AUO RUERABLE 8MBGY (Continued)
Rwanda Improved Charcoal Cookstove Strategy 8/86 059/86Improved Charcoal Production Techniques 2/87 065/87
Senega! Industrial Energy Conservation Project 6/85 037/85Urban Household Energy Strategy 2/89 096/89
Sri Lanka Industrial Energy Conservations FeasibilityStudies for Selected Industries 3/86 054/86
Sudan Wood Energy/Forestry Project 4/88 073/88Tanzania Woodfuel/Forestry Project 8/88 086/88
Small-Holder Tobacco Curing Efficiency Project 5/89 102/89Thailand Accelerated Dissemination of Improved Stoves
and Charcoal Kilns 9/87 079/87Rural Energy Issues and Options 9/85 044/85Northeast Region Village Forestry and WoodfuelPre-Investment Study 2/88 083/88
Togo Wood Recovery in the Nangbeto Lake 4/86 055/86Uganda Fuelwood/Forestry Feasibility Study 3/86 053/86
Knergy Effidiency Improvement in theBrick and Tile Industry 2/89 097/89
PEOPLE'S REPUBLIC 0F THE CONGOREPUBLIàQUE PGPUL4 RE DU CQNGCO
ALTERNATIVES FOR INTERCONNECTIONBETWEEN INGA AND POINTE NOIRE
VARIANTES POSSIBLES POUR LA REALISATION D'UNEINTERCONNEXION INCA-POINTE NOIRE EN 220kV
TRANSMISSION UNES: TOWNS _ ROADSLIGNES TRANSMISSION: ° ILLS ROUTES
- 220kV, EXIS1NGGS, TANTES 5 NATIONAL CAPITALS RAILROADS
220kV, ALTERNTWE INTERCONNECTIONS 4CPITALfES NATIONALES CHEMINS DE FERVARMN7ES INTERCONNEVON
STATIONS -- RIVERS _ . INTERNATIONAL BOUNDARIESPOS7fS - FiLEUVES FRONTlEfS INFNtSATIONALES
MALj Doliste ~~~~~~~~~~~~~~~~~~~MINDOUTI ZAIL
NOIRE R e
0C~~~~~~~~~~~~6Atlantic .--
I r - ' \. 2 * t D , >' ' 16° 180l
tJIGERIA !< v.vA WDAN i g"Ma 'sæ-/ 9 CENTRAL AFRICAN REPUBLIC
- EOPLE S ZAIREUC 8 KEN YA i / -s / Y
X -.. ) N A
G-T- 1 AMERON p. i-Q 2- C A V TA I A I A N O A C E A- - N(k o
ZAMM ~~ ~ AERO
20 j .2*~~~~~~~~~~~SUNK .0M
*PEOPLE'S REPUBUC 0F HECOGGENERA11NG FACIUTIES AND
TRANSMISSION SYSTEMSINSTALLED CAPACITYExiatg Projected mfl
|~~~~~~~~~m PEOUEREUBCO COGa tv/ J
MM MM Hydro Plant ETOUMBI
3 ILLE qg}/ fTRANSMISSION UNESE~dsling P-oJ.'ted
226 kV
_ 10 kV
- Prim" roda. paved W.
- Primy roada, gavel and .rmth
pOUNrv wYO AI