joint undp/world bank energy sector management assistance

ESMAP

Joint UNDP/World BankEnergy Sector Management Assistance Programme

(ESMAP)

SADC ENERGY PROJECT AAA.3.8Regional Generation and Transmission Capacities

including Interregional Pricing Policies(ESMAP Project: SADC Regional

Power Interconnctioii Study)

Phase IIVolume I

ESMAP Overview andExecutive Summary Report by Consultants

December 1993

This docmnent has restricted distribution and may be used by recipients only inthe performance of their official duties. Its contents may not otherwise bedisclosed without UNDP or World Bank authorization.

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SADC Energy Project AAA.3.8

Regional Generation and Transmission Capacitiesincluding Interregional Pricing Policies

(ESMAP Project: SADC RegionalPower Interconnection Study)

Phase II

Volume I

ESMAP Overview and

Executive Summary Report by Consultants

December 1993

Power Development, Efficiency and Household Fuels DivisionIndustry and Energy DepartmentThe World Bank1818 H Street, NW.Washington, D.C. 20433

TABLE OF CONTENTS

Page

VOLUME I

Foreword .............................

Glossary of Terms .......................... iv

ESMAP Overview .......................... viii

Consultants Executive Summary .......................... P-1

VOLUME II

Consultants SADC Core Country Studies

* Load Forecasts .3-1* lHydrology Study .4-1* Modes of Hydro Operation .5-1* Generation Planning Studies .6-1* Transmission Planning .7-1* Economic Analysis .8-1

VOLUME m

Consultants Supplementary Analysis

Power Development in Non-core SADC Countries .9-1Supplementary Transmission Analyses .10-1'Intermediate' and 'Drought' Scenarios. 1-1

VOLIJME IV

Consultants Hydrological Report

* Existing Studies and Available Data .2-1* Zambezi Basin Surface Water .3-1* Zambezi Basin Water Balance .4-1* Reservoir Evaporation .5-1* Water Balance for Kariba and Bahora Bassa Reservoirs .6-1* Influence of Basin Development .7-1

Foreword

1. This is a SADC Project in which ESMAP is the Executing Agency. The Activity InitiationBrief (AIB) required that this project be undertaken in three phases. Phases 1 and 2 have beencompleted. It is the intention to prepare an ESMAP comprehensive Final Report at the completionof all three phases. However, a delay in the funding of Phase mII, the so-called institutional phaseof the study, has meant that an ESMAP Consultants report for Phase II would make the results ofthis technical phase available to a wider audience at this time. This report also includes an ESMAPOverview which brings out the principal conclusions of this regional work. Complete details are tobe found in the Consultants report.

2. Phases I and 2 have been carried out in close cooperation with a Project SteeringCommittee (PSC) of SADC Electric Utilitiesl and the SADC Technical Administrative Unit (TAU)which is based in Luanda. As well, the electric utilities of the Republic of Zaire (SNEL) and SouthAfrica (ESKOM) have reviewed the report and the results of the study have been made available tothem. Their interest in all aspects of the study and their contributions are gratefully acknowledged.

3. In fact, because of SADC internal politics, ESKOM could not be invited to the PSCmeetings nor to the SADC Sub-Committee Meetings in which this study was discussed. SNELattended a few meetings as observers. In this regard it may be mentioned that it is now possiblefor ESKOM to participate as observers to future PSC meetings, a very welcome change in SADCpolitics, since ESKOM's input and contribution are deemed essential if this project is to truly be aregional project and promote Regional Cooperation.

4. Phase II was carried out essentially during 1992 with a draft report for Phase II presentedat a PSC meeting in Gaborone in February 1993. The draft report was approved in principle bythe PSC. After the recommended changes and suggestions were incorporated in the report, finalapproval for the report was received in writing by all SADC Electric Utilities by August 1993.

5. This report presents the consultants' findings and does not necessarily represent the viewsof the UNDP nor the World Bank. The report includes the following: (i) Volume I including anESMAP Overview and the Consultants Executive Summary, (ii) Volume II consisting of Part B ofthe Consultants Report, (iii) Volume III, consisting of Part C of the Consultants Report and (iv)Volume IV consisting of the Consultants Hydrology Report.

6. Phase II of this SADC project was finalized with a Seminar on Interutility Power Exchangeand Pricing Policies that took place in Malawi during August 30-September 1, 1993. It wasintended for this Seminar to be part of Phase m. However, upon request from the PSC, it wascarried out as part of Phase II. In the ESMAP Overview, a brief summary of the principalconclusions of the Seminar are provided.

7. Phase I was completely funded by SIDA. Phase II has been funded by SIDA, ODA andNORAD. ODA funded an extension of work to this project: the so-called 'drought' and'intermediate' scenarios. The 'drought' scenario was conceived to incorporate the exceptionallylow flows in the Zambezi River over the last 10 years, and it replicates the 10 year flow sequencesin the hydrological simulation studies. The 'intermediate' scenario was conceived to determine theimpact of a national decision (i.e. Kapichira in Malawi to reduce Malawi's import dependency asrequired by a regional plan) over a regional 'optimal' plan. NORAD funds contributed to the (i)

1 In August 1992 the Heads of State of the ten Members States signed a treaty establishing SADC andreplacing SADCC (Southem African Development Cooperation Conference). The 10 SADC Member States are:Angola, Botswana, Lesotho, Malawi, Mozambique, Namibia, Swaziland, Tanzania, Zambia and Zimbabwe.

extensive hydrological studies that were required and (ii) to defray costs of the PSC Meetings andSeminar referred to above. The interest and support of SIDA, ODA and NORAD in fundingPhases I and II of this SADC Project is gratefully acknowledged.

8. The principal consultant to Phase I was Norconsult International. The principal consultantsto Phase II was Engineering and Power Development Consultants Limited from the UK. The teamof consultants consisted of international and local consultants. Phases I and II were carried outwith the assistance of a SADC utility support team.

9. This report concentrates fundamentally on the results for Phase II of this SADC regionalproject.

Glossary of Terms

Units used throughout this report conform to the System Internationale (SI). The definition ofsome of the concepts used are provided below in the footnotes. Where other units are used theyare explained in the text.

Abbreviations and/or MeaningAcronyms

AC alternating current

AIB activity initiation brief

BPC Botswana Power Corporation

CAPCO Central African Power Corporation

CIDA Canada International Development Agency

CSC controlled series compensator2

DC direct current

DTR Draft Technical Report

E) economic dispatch3

EDM Electricidade de Mozambique

ENE Empresa Nacional de Electricidade

ESCOM Electricity Supply Commission of Malawi

ESKOM Electricity Supply Commission of the Republic of South Africa

ESMAP Joint UNDP/World Bank Energy Sector Management AssistanceProgramme

FACTS flexible AC transmission system4

GDP gross domestic product

HVDC high voltage direct current

kg kilogram

2 A device to dampen power swings by reducing the series impedance of a transmission line.

3 Economic dispatch is to be understood as the allocation of generation among available generating unitswithin a power system so that the total cost of supplying energy demand is minimized.

4 FACTS technology allows the secure loading of transmission lines to their full thermal capacity throughthyristor control. A fundamental notion behind FACTS is that it is possible to continuously vary the apparentimpedance of a transmission line as to control the power flow in the line.

.V-

kV kilovolt

kVA kilovolt ampere

kVAR reactive kilovolt ampere

kW kilowatt

kWh kilowatt-hour

LEC Lesotho Electricity Corporation

LF load factor5

LOLP loss of load probability6

LRMC long run marginal cost

m3 cubic meter

MW megawatt

MWh megawatt-hour

NORAD Norwegian Agency for Development

NPV net present value

ODA Overseas Development Administration

PSC Project Steering Committee

RSA Republic of South Africa

SADC Southern African Development Community

SCR short circuit ratio

SEB Swaziland Electricity Board

SIDA Swedish International Development Authority

SIL surge impedance loading7

SNEL Societe Nationale d¶Electricite

5 Ratio of average electricty demand to maximum demand.

6 Probabirty that peak demand will exceed available capacity.

7 Defined as the unit power factor load that can be delivered over a resistanceless transmission line such thatthe reactive losses are equal to the charging loading of the line. It Is defined as the square of the line-to-line voltagedivided by the surge impedance. The surge impedance is equal to the square root of the inductance of the linedivided by the capacitance of the line. The SIL Is assumed to be the natural' loading of the line.

- vi.-

SPD System Development Plan

SUST SADC Utilities Support Team

SVC static VAR compensator8

SWAWEK South West Africa Water and Electricity Corporation

TANESCO Tanzania Electric Supply Company Limited

TAU Technical and Administrative Unit (Energy) of SADC, based inLuanda

TOR Terms of Reference

UNDP United Nations Development Programme

ZCCM Zambia Consolidated Copper Mines Limited

ZESA Zimbabwe Electricity Supply Authority

ZESCO Zambia Electricity Supply Corporation Limited

ZRA Zambezi River Authority

B A device that produces and absorbs VAR and maintains voltage stability.



(ESMAP Project: SADC RegionalPower Interconnection Study)

Phase II

ESMAP OVERVIEW

- viii -

Background

1. The Activity Initiation Brief9 (AEB) for the entire study divided the scope of work in threephases, namnely:

(a) Phase I. An Inception Phase dealing with the identification and collection ofdata on which further work for this project is to be based.

(b) Phase II. An Intermediate Phase dealing with a detailed evaluation ofalternative development scenarios and identification of an integrated and optimumregional power development plan.

(c) Phase III. A Final Phase dealing with the institutional arrangements needed forachieving appropriate regional coordination in the power sector includingInterregional pricing policies.

2. The main purpose for subdividing the work in three phases was to be able to better controlthe progress of work of the consultants and to make mid-course corrections if required.

3. The overall objective of this regional prefeasibility study is to assess the scope ofcoordinated utilization and development of regional generation and transmission facilities and toevaluate the potential benefits and costs of increased regional cooperation related to transfers ofelectrical power and energy, taking into account the requirements of individual Member States interms of reliability, quality of service and planning criteria, security of supply and self-relianceconsiderations as well as institutional, contractual and pricing matters. The study will also includean assessment of the opportunities and potential benefits of power exchanges with neighboringnon-SADC countries including Zaire and South Africa.

4. Phase I was initiated on 15 September 1990 and a draft report was submitted to the TAUand to Members of the PSC attending the SADC Energy Sector Third Electricity Subcommitteeduring 19-21 March 1991. The Inception Report (in three volumes) includes vast amount of dataand information on the SADC and non-SADC neighboring utilities which was obtained fromquestionnaires and visits. The Inception Report was accepted by TAU (the Client).

5. Phase I report made a preliminary identification of important issues within SADC that needto be addressed and analyzed in subsequent phases of the Study, including inter alia (i) degree ofinterdependence which participating SADC countries are willing to accept in regional cooperation,(ii) mutual trust and openness among SADC countries, (iii) incorporation of regional generationoptions into national plans (iv) wheeling procedures and allocation of benefits and risks, (v)institutional and contractual aspects of developing further regional interconnections (vi) impact toSADC utilities generation expansion plans of Zaire's hydro potential available (vii) riparian rights(viii) conjunctive operation of hydro facilities on the Zambezi and impact on national and regionalgeneration plans and (viii) possible exports of firm and non-firm power to RSA and its impact onSADC electric utilities generation plans.

6. Phase II of the Study had the following three objectives:

(a) Assess the scope for coordinated utilization of regional generation and transmissionfacilities;

9 The Activity Initiation Brief was completed in August 1990 and approved by the SADC PSC.

-ix-

(b) Evaluate potential benefits and costs of regional cooperation by interconnection, andthe distribution of these costs between countries using a scenario approach;

(c) Determine the different development plans within an interconnected framework andidentify the criteria to be applied to reach and integrated regional development.

7. Phase II was undertaken in three stages, namely: (i) Stage 1, which included a verificationof system data collected during Phase I; evaluation of energy and load demand forecasts;identification and /or preparation of generation expansion plans and supply/demand balances and adetailed hydrology study, (ii) Stage II, which included an assessment of interconnectionalternatives and economic evaluation studies, and (iii) Stage III, which included advanced short-circuit and stability transmission studies, wheeling-through studies of power in the regionparticular from Zaire to RSA, and the extension of work demanded by the 'intermediate' and'drought' scenarios.

8. Phase m would undertake the organizational, institutional, regulatory and pricing aspectsof the Study. The objectives of Phase m can be stated succinctly as:

(a) Formulate a strategy for fostering regional cooperation through powerinterconnection in the region as a means of providing opportunities for enhancedelectricity trade;

(b) Determine the most appropriate interutility tariff pricing principles for poolingoperation;

(c) Analyze the institutional, contractual and organizational aspects for establishing aregional power pool, determining the most appropriate organizational structure forpossible introduction in the region and its mode of introduction, and considering thepotential for coordinated planning and development as well as integrated operationsof the regional interconnected system.

9. The main focus for Phase III of the study is therefore to provide a framework for increasedregional cooperation and for progressive - stage-wise - integration of regional power suppliesbased on a realistic assessment of the options that will increase opportunities and benefits forelectricity trade. This includes recommendations on providing increased opportunities forinterutility trade; recommendations on establishing interutility pricing principles, recommendationson establishing bilateral contracts supported by power sales agreements; recommendations onownership of generating plants and transmission facilities; recommendations on interconnectionbetween independent control areas; recommendations on power pooling and establishing a regionalcoordinating body.

Motivation for the Study

10. The SADC region is characterized by a considerable untapped hydroelectric potential.Hydro resources are available and partly developed in all SADC countries except for Botswana.The greatest potential is found in the Zambezi basin which is shared between Zambia, Zimbabweand Mozambique. Its total potential has been estimated at 13,000MW with a firm energyproduction of about 78,OOOGWh per year. In the Kwanza and Cunene river basins in Angola, ithas been estimated that the hydro potential reaches approximately 16,000MW and 65,OOOGWh peryear.

11. If the term 'regional' is expanded to include neighboring SADC countries, with whichenhanced cooperation can only be beneficial, the figures above are increased considerably. Thepotential of the Zaire river basin has been estimated at 100,OOOMW, of which the Inga scheme nearthe Angolan border represents about 40,000MW.

_X_

12. Vast coal reserves exist in Botswana, Swaziland, Tanzania, Mozambique and Zimbabwe.The largest coal reserves in the region, however, are found in RSA, which has been estimated at60 billion tons. Angola is the only current SADC producer of oil with a daily crude production ofabout 500,000 barrels.

13. It is clear that there exist an abundance of regional sources of energy and a large potentialfor cooperation and interaction, including the cooperative development of new facilities. Largebenefits can be obtained from conjunctive operation of hydro facilities and of hydro/thermalcoordination.

14. Interconnections between electric utilities in the region is a very effective means for animproved and more complete utilization of regional electricity resources. Interconnections fosterinterutility trade and thus can promote power system objectives as they relate to the improvedresource utilization which will lead to economic and financial advantages that all participants willwant to share in appropriate measure. Interconnection benefits may be realized in different degreesaccording to the institutional organization adopted. They can be classified as either operatingbenefits or expansion benefits.

15. Operating benefits can be obtained (once tie lines are in service) through coordinatedplanning and operations backed by suitable interutility power exchange agreements. Operatingbenefits result mainly from the following:

(a) Short-term hydro discharge optimization taking advantage of hydrological diversitybetween countries;

(b) Short-term thermal plant dispatch optimization for the interconnected power systemas a whole;

(c) Demand diversity mainly at a daily level: peak demand in one system may be met byoff-peak energy from another system;

(d) Emergency support whereby operations can be scheduled with smaller reservemargin by counting on tie lines to provide backup during emergencies;

(e) Increase spinning reserve in the overall system for better frequency stability, controland improved voltage profiles.

16. Expansion benefits are attainable on a longer-term basis and usually imply a substantialamount of investment coordination. The principal benefits are:

(a) Lower reserve requirement for long-term generation expansion planning;

(b) Economies of scale either by jointly-owned plant or firm interchange commitments;

(c) Postponement of some investments and/or optimal loading of large units that wouldotherwise not be fully utilized from the start if developed by a single country;

(d) Long-term hydrologic complementarity that can reduce storage requirements.

Brief Overview of Phase II

17. To develop further the interconnection arrangements which have already been achieved inthe region, the Phase II Studies concentrated on the five countries of Botswana, Malawi,Mozambique, Zambia and Zimbabwe. These countries all have close access to the existing Zambia-Zimbabwe 330kV transmission system and are therefore able to participate directly in thecoordinated development of regional generation and transmission capacities. Phase II also dealt

-xi -

with the rest of the SADC countries, namely: Angola, Lesotho, Namibia, Swaziland and Tanzania,although not to the same level of detail. In addition, the analysis took account of the opportunitiesfor electricity trade offered of the neighboring countries of Zaire and South Africa.

18. To secure an effective utilization of existing regional generation, transmissioninterconnections are the main priority developments identified by the study, which can supplydemand till about 2004 with the formation of transmission corridors. The study identifies a'second' transmission corridor from Zambia through Malawi to Mozambique which has beenincorporated as a basic strategy in all expansion plans assessed. The following were identified aspriority developments:

* Completion of the 400kV interconnector between Mozambique (at Songo in CahoraBassa) and Zimbabwe ( at Bindura);

* Completion of the 400kV interconnection between RSA (at Matimba) and Zimbabwe(Insukamini) passing thorough Botswana (at Selebi-Phikwe);

* Completion of a 220kV link between Zambia and Malawi and between Mozambiqueand Malawi to bring Malawi into the regional network;'0

a Reinforcement and upgrading of interconnection with Zaire;

* Reinforcement of the Kariba-Alaska line;

* Replacement of switchgear at Kariba to improve fault rating;

* Proceed with study of Lower Kafue (450 MW hydro plant).

19. A number of further developments were also studied that would enhance the benefits ofregional cooperation and interutility trade. These include:

* Upgrading of the Inga-Kolwesi DC line to deliver its full capacity of 1120MW toZambia and the region;

* Building a 400kV line from Kolwesi (Zaire) to Luano (Zambia);

* Upgrading of the 'second corridor' to Malawi to a 400kV double-circuit line;

* Completing the hydro plants at Mepanda Uncua (1600MW hydro plant) and CahoraBassa North (55OMW hydro plant).'2

10 The concept of interconnecting Malawi with Zambia and Mozambique effectively creates a secondnorth/south transmission corridor, albelt at 220kV rather than at 132kV. The latter would unduly restrict the loadtransfer capability of this line and the integration of Malawi into the regional scenario.

11 A joint study, finalized in May 1993, was undertaken by ESKOM, SNEL, ZESCO and ZCCM to investigatethe Kolwezi (Zaire)-Luano(Zambia) power transfer capability and potential improvement. The study findings support,for the short and medium terms, the strengthening at 220kV of the existing transmission system between Kolweziand Luano to achieve increased power transfer, improved voftage profiles and static firm supply for singlecontingencies. For the longer term, the study concludes with the recommendation that additional strengthening at33OkV or 400kV is required. This supports the recommendations of this SADC project.

12 A prefeasibility study on the prospects of building an additional hydro plant at the North Bank of CahoraBassa and/or a new hydro scheme at Mepanda Uncua, 70km downstream of Cahora Bassa, has been carried out byElectricidade de Mozambique and ESKOM.

- xii -

20. Comparing the so-called Plan A (base-case) of integrated regional development withindependent development shows that Plan A provided savings of US$785 million in constant 1992monetary terms over the period 1995-2010 with a real discount rate of 10 percent. Plan A includesthe upgrading and building of tie-lines with Zaire, building of the 'second' transmission corridorthrough Malawi and the completion of stage 1 (400MW) and stage 2 (400MW) of Batoka after theyear 2000. Batoka (1600MW, 800MW for Zimbabwe and 800MW for Zambia) is considered asan eminent regional project with the potential of supplying the increasing expected demand in RSAafter the turn of the century. Plan A assumes that the Songo (Cahora Bassa) - Bindura(Zimbabwe) interconnector is completed by 1995 with a take-or-pay supply agreement for importof 400MW till 2003. It also assumes that the Songo-Apollo (RSA) DC line is refurbished by1995. The completion of these two projects by 1995 appear less likely at this time.

21. The least cost option identified in the study is the so-called Plan D. This provides athermal/hydro combination for the next power generation projects and is thus the most prudentdevelopment track in the event of continuation of the present drought.

22. The so-called drought scenario calls for thermal support either through an additionalproject such as Hwange EII (Units 7&8, 2x220MW) or the preferred option of import thermalcapacity from RSA through a new 400kV transmission line between Matimba Power Station inRSA and Insukamini substation in Zimbabwe and passing through Botswana close to the SelebiPhikwe Power Station. This line will be a reality in the foreseeable future, in line with the prioritydevelopments identified above.

23. The 'Intermediate' scenario was simulated in competition with Plan A, to test the cost ofreducing import dependency for Malawi by adding Kapichira into an 'optimal' regionaldevelopment. As expected, the cost of a 'national' decision over a 'regional' decision reduces thebenefits from US$785 million (see 20 above) to US$608 million.

24. In the so-called 'wheeling through' studies, up to a total of 1250MW can be delivered toRSA for about 1000MW export from Zaire at Kolwezi to Luano. This assumes Batoka at1600MW to effect a good power balance in the region and the availability of the full power outputat Inga with the Stage II converters in operation. It also assumes double-circuit 400kV lines fromKolwezi to Luano, for the 'second' corridor through Malawi and for the Matimba-Bulawayointerconnector. It is also prudent to add a fourth 330kV line to the Kariba-Alaska corridor inZimbabwe which is required in any case.

SADC Seminar on Interutility Power Exchange and Pricing Policies.

25. During the February 1993 SADC PSC Meeting in Gaborone for Phase II of SADC EnergyProject AAA.3.8: 'Regional Generation and Transmission Capacities Including InterregionalPricing Policies' it was recommended by the PSC that a Seminar be organized, with the assistanceof ESMAP, on interutility power exchange agreements and pricing policies, including wheeling. Itwas felt that SADC Electric Utilities lack sufficient knowledge on this topic, and that a commonunderstanding of principles would be helpful in promoting regional cooperation and coordinateddevelopment, including reinforcement of the regional grid and strengthening of the ties with RSAand Zaire.

26. The Seminar was held in Lilongwe, Malawi during August 30- September 1, 1993. It waswell attended by SADC Electric Utilities, regional representatives from SNEL (Societe Nationaled'Electricite), ESKOM (Electricity Supply Commission of RSA), ZRA (Zambezi River Authority),HCB (Hidroelectrica de Cahora Bassa, CIDA, SADC Energy Sector as well as representativesfrom the Volta River Authority, Statkraft SF, Statnett SF, American Electric Power Co., NationalGrid Company (UK), Eurolectric, ECC Inc., Power Technologies Inc. (PTI) and localconsultants.

- xfijj-

27. ESKOM was officially invited to participate at this SADC/TAU Seminar and in all futureSADC/TAU meetings. This was considered a breakthrough and augurs a step forward in regionalcooperation.

28. There was a general consensus from participants in the Seminar was very helpful inidentifying the key issues, limitations and potential conflict areas in interutility exchangeagreements. The main conflict areas may be due inter alia to: (i) applicable law, (ii) lack of trust andgoodwill, (iii) O&M responsibilities, (iv) definition of terms, (v) understanding of the 'product' tobe sold or exchanged, (vi) force-majeure interpretations, (vii) regulatory framework androadblocks, (viii) complexity of contractual arrangement, (ix) inequity in evaluation of net benefitsto parties to the trade, and (x) escalation and price adjustment formulae. These are matters thatmust be further clarified.

29. It is clear the developing power exchange agreements involves a great deal of uncertaintyand risk. To minimize this risk, the development of prices for interutility services should be basedon clear cut and transparent principles. The following principles were formulated at the Seminar:

* There is no supranational regulator with responsibility and authority to maximize socialwelfare in the region;

• Prices must be negotiated between willing buyers and sellers;

* All transactions must be undertaken within a win-win framework;

* Intergovernmental arrangements must allow utilities to honor their commitments;

* Keep contractual agreements and related matters simple.

30. The lessons learned from experience within SADC regarding interutility trade and powerexchange agreements were identified to be:

* Base decision on a thorough and complete understanding of the technical,administrative, and financial implications of the transactions;

* Understand thoroughly the alternatives and the objectives of the trade;

* Develop trust and goodwill before entering into a trade agreement;

* Provide information to make equitable decisions;

* Parties must obtain net and fair benefits from the transaction;

* Pursue a long-term relationship - avoid short-term gains; and

* Be fair but firn in the negotiations.



(ESMAP Project: SADC Regional Power InterconnectionStudy)

Executive Summary - Phase II

Report by Consultants

Engineering & Power Development Consultants LimitedW. P. Lewis, Study Coordinator

Gilbert/Commonwealth International, Inc.S. S. Qadri

A. A. Herman

Mott MacDonald Water & Land DevelopmentT. E. Evans

Power & Water SystemsP. E. Robinson

Konkarni (PVT) LTDN. Q, A. Seaman

Stewart Scott KennedyF. M. E. Wibberley

J. Santa Clara

SADC ENERGY PROJECT AAA3.8

FINAL TECHNICAL REPORTPART A - EXECUTIVE SUMMARY

CONTENTS

PageNo

PREFACE

Organisation of Report P-iContents of Report P-2Project Meetings P-2Information P-3

SECTION 1 - REPORT SUMMARY

1.1 Basis of Study and TOR Objectives 1-11.2 Core-Country Planning Methodology 1-31.3 Load Forecast Review 1-41.4 Hydrology Study 1-51.5 Hydroelectric Operabons 1-91.6 Generation Planning Studies 1-131.7 Transmission Planning Studies 1-181.8 Advanced Transmission Studies 1-231.9 Wheeling-through Studies 1-261.10 Review of interconnection Options 1-291.11 Power Development in Non-Core Countries 1-32

- Tanzania 1-32- Angola 1-33- Namibia 1-34- Lesotho 1-34

Swaziland 1-351.12 Intermediate and Drought Scenarios 1-36

- Intermediate Scenario 1-36- Drought Scenario 1-37

1.13 Economic Analysis 1-39

Exhibits 1.1 - 1.24

SECTION 2- DEVELOPMENT ISSUES AND OPTIONS

2.1 Introduction 2-12.2 Core-Country Situation 2-22.3 Independent versus Integrated Development 2-42.4 Integrated Development Plans 2-62.5 Secondary Projects 2-82.6 Effect of Continued Drought Conditions 2-102.7 Drought Strategies for System Operations 2-122.8 Intermediate Development Scenarios 2-142.9 Other Dependency Issues 2-162.10 Recommended Actions (following the Lusaka Meeting) 2-17

Exhibits 2.1 - 2.2

PREFACE

Organisation of Report P-1Contents of Report P-2Project Meetings P-2Information P-3

PREFACE AAA3.8 PHASE 2

PREFACE

Organisation of Report

This Executive Summary, termed Part A, presents an overview of the work done intwo Sections:

Section 1 - Report SummarySection 2 - Development Issues and Options.

The Core-Country Studies are presented in Part B of the Main Report. Effort wasconcentrated on load forecasting, economics, hydrology, generation planning andtransmission planning, with emphasis on identifying a Base Plan (A) and alternatives(B, C & D). This was done for the five core countries as an integrated regionaldevelopment within an interconnected framework. These activities are reported inSections 3 to 8 as follows:

Section 3 - Load ForecastSection 4 - Hydrology StudySection 5 - Modes of Hydro OperationSection 6 - Generation Planning StudiesSection 7 - Transmission PlanningSection 8 - Economic Analysis

The Supplementary Analyses, in Part C of the Main Report, are concerned withwidening the scope to include the non-core countries and determine whether anyadditional benefits accrue from regional cooperation. These analyses concern powerdevelopment reviews and more advanced transmission studies with particular respectto power wheeling over long distances. Also included in Part C are analyses for theintermediate and drought scenarios, which respond to an extension to the TOR.These activities are reported in Sections 9, 10 and 11, as follows:

Section 9 - Power Development in Non-Core CountriesSection 10 - Supplementary Transmission AnalysesSection 11 - Intermediate and Drought Scenarios

With a study of this type, there are many detailed results, data and exhibits, and theseare all presented in Appendices. The Appendices also include specialist notes anddiscussion on issues that are referenced in the Main Report, or otherwise required bythe TOR. In this latter respect Appendix T is the Issues Paper and Draft TOR for theAAA 3.8 Phase 3, Institutional Studies.

P-i

PREFACE AAA3.8 PHASE 2

Contents of Report

Originally, the TOR required the Intermediate Phase to be performed in three stageswith a report at each Stage.

These stages were to comprise: an Inception Stage, i.e a review of system data, loadforecasts and expansion plans; an Intermediate Stage, presenting alternative scenariosfor interconnection; and a Final Stage, confirming the interconnection proposals,evaluating the status of non-core countries and assessing the impact ofwheeling-through power from Zaire to RSA.

Project Meetings

To begin Phase 2, a Kick-Off (KO) Meeting was held in Harare on November 18-19,1991. This meeting was chaired by TAU and attended by representatives of theSADC Utilities, the EPD Study Coordinator and local team and the ESMAP TaskManager. At the meeting, SADC views on the the objectives of Phase 2 werediscussed with ESMAP amd EPD. It was also confirmed by SADC utilityrepresentatives that the Phase 1 data and information had been scrutinized and couldbe accepted as the basis for the Phase 2 analyses. Finally, SADC TAU stressed theimportance of the March 2, 1992 PSC Meeting, at which the initial ranking ofinvestments were to be presented.

Because of delays in the award of the Contract, but not the key milestones, it wasdecided that the Phase 2 studies would be undertaken by initially focussing onpriorities for interconnecting the five core-Countries. Stages 1 and 2 were thereforeto be combined and completed by the issue of a Draft Technical Report (DTR). Thisreport was to be issued for presentation to the PSC (on March 2). Phase 3 was tothen continue as originally conceived.

An important component of the March 2 presentation was the need to provide an initialranking of investments so that TAU could prepare suitable project descriptions to bepresented at the SADCC Energy Ministers' meeting in June 1992. For this reason, itwas emphasised by TAU that the DTR must be ready by March 2, 1992.

EPD undertook to meet this deadline, provided the report would be accepted as anInterim Report giving an initial screening of potential candidates for generation andinterconnection in the core-Region. The Interim Report comprised all the analysis inexhibit form (tables and charts) but, because of the short preparation time available,the written material was kept to a minimum except for a summary of developmentoptions and priority projects. This Report was then formally issued with the full textin April as the DTR.

P-2

PREFACE AA3.8 PHASE 2

At the KO meeting, it was also agreed that EPD would issue the Phase 2 InceptionReport (IR) by December 20, 1991, and this undertaking was fulfilled on schedule.Comments on this IR were received via ESMAP, and taken into account in proceedingwith the Technical Phase of the Study. Particular concerns in the comments received(to the IR) were that undue reliance should not be placed on support frominterconnections with RSA and that "wheeling" considerations should not be givenpriority. These concerns were respected in developing core-Country generation andtransmission capacity expansion programs.

The Draft Technical Report (DTR) for the combined Stages 1 and 2 was scheduledfor completion by April 3 1992 (according to the original TOR schedule). In the event,it was issued in mid-April with the agreement of ESMAP.

At the March 2 (Lusaka) Meeting it was decided that in addition to the fully integratedscenario (Plan A) for interconnecting the five core countries, there should also bedeveloped "intermediate" and "drought" scenarios. These scenarios were tospecifically address import dependencies, with particular respect to Malawi and thetreatment of hydropower as a scarce and uncertain resource. These scenarios wereapproved as extensions of the original TOR for inclusion in the Stage 3 studies.

Information

As is often the case with extensive and complex studies of this nature, much of thebasic information that had to be used called for verification, correction and updating.It is thought nevertheless that the final proposals put forward in the Main Report reston a sound footing and that the cost estimates are sufficiently reliable to underwritethe conclusions reached. It is to be hoped that the study will make a usefulcontribution to closer technical and economic cooperation throughout the SADCRegion.

The data and information used in the Core-Country analyses was current inJanuary 1992, and was included in the Technical Report of April 1992, submitted forreview and comments by all PSC Members. This followed a presentation of theanalyses at the Lusaka Meeting of the PSC in March 1992.

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SECTION 1

REPORT SUMMARY

1.1 Basis of Study and TOR Objectives 1-11.2 Core-Country Planning Methodology 1-31.3 Load Forecast Review 1-41.4 Hydrology Study 1-51.5 Hydroelectric Operations 1-91.6 Generation Planning Studies 1-131.7 Transmission Planning Studies 1-181.8 Advanced Transmission Studies 1-231.9 Wheeling-through Studies 1-261.10 Review of Interconnection Options 1-291.11 Power Development in Non-Core Countries 1-32

- Tanzania 1-32- Angola 1-33- Namibia 1-33- Lesotho 1-34- Swaziland 1-35

1.12 Intermediate and Drought Scenarios 1-36- Intermediate Scenario 1-36- Drought Scenario 1-37

1.13 Economic Analysis 1-39

Exhibits 1.1 - 1.24

SECT. 1 AAA3.8 PHASE 2

1. REPORT SUMMARY

1.1 Basis of Study and TOR Objectives

This Study, now known as SADC Energy Project AAA 3.8 "Regional Generationand Transmission Capacities including Inter-regional Pricing Policies", has, asits overall objective, to assess the scope of coordinated utilization anddevelopment of regional generation and transmission facilities for the ten SADCcountries of southem Africa. Exhibit 1.1 is a map of the complete region, andgives the basic configurations of the existing power networks. The ten SADCcountries are Angola, Botswana, Lesotho, Malawi, Mozambique, Namibia,Swaziland, Tanzania, Zambia and Zimbabwe. The SADC region is boundedby Zaire to the north and the Republic of South Africa (RSA) to the south, bythe Atlantic Ocean to the West and the Indian Ocean in the East.

The SADC Energy Project AM 3.8 is divided into 3 Phases:-

Phase 1 - The Inception Phase, which covers data gathering forRegional Electricity Supply Development.

Phase 2 - The Intermediate Phase, which deals with the Technicaland Economic Evaluation of Regional Electricity SupplyScenarios.

Phase 3 - The Final Phase, which is to consider Institutional Issuesarising from Regional Integration of the Electricity SupplySector.

The present study is concerned with Phase 2, and has the following three mainobjectives as set out in the Terms of Reference (TOR):

1. Assess the scope for coordinated utilization of regional generation andtransmission facilities;

2. Evaluate potential benefits and costs of regional cooperation byinterconnection, and the distribution of these benefits and costs betweenthe countries using a scenario approach;

3. Determine the different development plans within the framework of aninterconnected system and identify the criteria to be applied to achievean integrated regional development.

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The TOR further require that "the above objectives must take account ofopportunities for eiectricity trade with non-SADC countries including Zaire andSouth Africa (RSA)". Moreover, in developing scenarios the Consultant musttake account of the requirements of the individual SADC Member States withregard to reliability, quality of service and planning criteria, security of supplyand self-reliance considerations as well as institutional, contractual and pricingmatters.

The TOR specify that the scope for coordinated capacity expansion andutilization of regional generation and transmission facilities must haveparticular reference to the core-Countries. These are defined as thecountries with close access to the existing Zambia-Zimbabwe 330kVtransmission system and therefore able to participate directly in the coordinateddevelopment of regional generation and transmission capacities. The countriesare Botswana, Malawi, Mozambique, Zambia and Zmbabwe, shown onExhibit 1.2.

The map of Exhibit 1.2 shows the transmission system as it is expected to beinterconnected in 1995 if all the committed transmission projects areimplemented. A central activity is therefore to determine the efficacy of theexisting network so that it may be combined into a single system for integrateddevelopment.

Those SADQ countries that cannot be easily interconnected are termed non-core countries, and in their case the TOR emphasises that an evaluation bemade to determine how they may gain benefits from regional cooperation.These non-core countries are Angola, Namibia, Lesotho, Swaziland andTanzania. Referring to the regional map of Exhibit 1.1, Lesotho is landlockedwithin RSA and therefore cannot have any direct access to the SADC Grid.

Distances across the sub-continent are very large. For example, the ±500kVHVDC link in Zaire from Inga to Kolwesi, shown on the map (Exh.1.1), coversa distance of 1700km. Angola and Namibia are also too remote for any directconnection to the existing Zambia/Zimbabwe grid. In the case of Tanzania itmay be practicable to interconnect to the existing grid at Serenje (Pensulo) inZambia, but in this case also transmission distances may be too large forconventional ac network extension.

Analysis of the non-core countries, according to the TOR, is therefore to betreated as supplementary to the main brief of expansion planning for the corecountries. Given this perspective, in the case of the non-core countries theapproach is to provide country and power sector profiles in sufficient depth toclarify how development might take place within a regional framework. Thismust involve long-distance transmission, and so the issues and options in thistechnology are also examined.

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In the case of the core-country networks the intent of the TOR is clearly todistribute equitably the benefits of interconnection and integrated developmentof generation and transmission capacities as a single power system or uMtightupool arrangement. This is best undertaken by formal expansion planningmethods, applying least-cost investment analysis, in which alternative plans aremade technically equal and then economically ranked in order of least cost. Tomeasure the benefits of integration, compansons are to be made with theaggregated costs of independent development plans for each of the five corecountries. In undertaking this exercise, every effort has been made to identifystrategies that strengthen and complement individual-country plans in strictaccordance with the TOR.

1.2 Core-Country Planning Methodology

The analysis of the five core countries is presented in detail in Part B of theMain Report. Integrated and independent development plans are comparedusing least-cost investment planning principles. The aggregated costs foreach country developing independently are much larger than the costs of anyof the plans for integrated development. Thus the cost savings represent thebenefits of regional development, and the least-cost integrated plan is, bydefinition, the one with the largest savings.

Integrated plans have been developed as though the five SADC countries werea single entity or a "tight" pool in terms of electricity supply. Projects weretherefore selected and compared for their efficacy in meeting aggregateddemand over the horizon of the study with a given norm of reliability and atleast discounted cost. No account was taken of national preferences orconcerns, as the "tight pool" approach" assumes total integration. The planswere developed according to the long term planning criteria and objectivesdiscussed below.

New capacity must be made available if forecasts are to be met withoutinfringing the reserve capacity margin. In practical terms, reserve capacity isthe increment of generation above demand that must be set aside to provideassurance that demand can be met in nominal circumstances. The margin isbased on reliability criteria, measured as a loss of load probability (LOLP)index, and used in planning models to determine the amount and timing of newcapacity.

The objective of capacity plans are thus to establish when, where, and whattype and size of plant to build in order to ensure economic and reliableresources for supplying forecast load. Since different types of plant capacityhave different cost characteristics, the total system operating costs in eachfuture year vary with the type of capacity and the manner in which it isdispatched. A total systems cost approach is thus applied in optimizing thecombination of new and existing plant so that least cost is achieved. This is inessence the methodology used in the Study.

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The integrated plans were developed from candidate generation andtransmission projects identified in Phase 1 of this AAA3.8 Project. In theabsence of utility-verified forecasts, World Bank judgement was taken. TheLOLP criteria was 24hrs/annum as proposed by ESMAP, the Task Manager.As explained earlier, and required by the TOR, these "integrated plans werecompared with those for "independent" development by each country. These"independent" plans were analysed using exactly the same methodology asapplied to the integrated plans.

The aggregated costs of each core-country developing independently and ofintegrated development were then composed, to show the costs and benefitsof regional cooperation in electricity supply. Cost, in this context, was taken as"economic" cost, which values resources in terms of their next best alternative.Benefit was measured as the economic cost differential in favour of integrateddevelopment. In practical terms, the analysis involves the allocation ofavailable economic resources on the basis of present values of the appropriatecost, ie. by discounting the annual expenditures to establish the net presentvalue (NPV) of each plan, taking account of market or "shadow" prices.

1.3 Load Forecast Review

A review was made of the latest forecast for each of the five core countries inthe SADC region. This data was checked for reasonableness in determiningpatterns and trends in regional MW demand and energy balances over thestudy horizon to the year 2010. The calender year was selected as the studybase, for regional comparisons and aggregation, and conversions of publisheddata from a fiscal to a calender base were made as necessary. In making thereview some forecasts have been changed to reflect updated information, butno account has been taken of demand changes due to drought, or of any of theongoing economic structural adjustment programs.

Overall, it was found that the five core countries of the SADC region can expectto experience significant growth in electricity demand to the study horizon.Zimbabwe and Zambia together represent almost 90% of the total demand.The calender year non-coincident MW peak demands are estimated to growfrom 2800MW in 1990 to almost 5700MW in 2010. Thus MW demand isexpected to double in 20 years with an actual increase close to 2900MW, andan average annual rate of 3.6%.

Of the total :990 MW demands, Zimbabwe represents close on 55%, whileZambia has 30%. However, by 2010, Zimbabwe's share drops to 51% of thetotal, and Zambia's to 24.5%, as the other three core countries are estimatedto grow at a higher percentage annual compound rate. This accounts for aslightly decreasing share by the two larger countries, but ranking remainsunchanged and their combined demand in 2010 still totas over 70%.

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It should be noted that the total (regional) energy forecast is only slightlydifferent from that of the MW demand forecast. Again, Zimbabwe and Zambiatogether share over 87% of the regional energy requirements in 1990, and thisshare only falls to 77.5% by 2010. It follows that MW demand and energybalances will remain dominated by Zambia and Zimbabwe, and thus anystructural economic changes or energy resource problems in these countrieswill significantly impact on the region.

Combining demands in each country on a coincident basis it was expected thatpeaks would be reduced compared with aggregated non-coincident peaks.However, it was found that the demands in the three countries, Botswana,Zambia and Zimbabwe, with over 75% of the MW demand, peaked on thesame day in the year and within hours of the each other. It was thus decidedthat no diversity factor should be applied in the generation planning process.

Exhibits 1.3 & 1.4 give the regional demand and energy forecasts determinedfrom this review. It should be noted that the combined load factor is almost75% in 1992, and drops to just below 70% in 2010. This high load factor isentirely consistent with the level of mining and industrial demand in the region.The 5% fall in load factor to the study horizon demonstrates the expectation ofrapid growth in the domestic sectors resulting from relieving the suppresseddemand.

To prepare for plant optimization studies when developing generation expansionscenarios, it is necessary to create load profiles for each utility network. Theseprofiles should include annual and monthly load duration curves together with24-hour load shapes for typical weekdays, weekend days and peak-load daysin each month. This data was available in detail from Zimbabwe for the 1987/8System Development Plan (SDP) Study, and complemented by typical dailyload shapes were obtained during the visits to Botswana (BPC) and Zambia(ZESCO). This data was then put together for resource planning.

1.4 Hydrology Study

Hydrological analysis has focussed on the preparation of data sets formodelling hydropower resources and optimising power development within theZambezi Basin. As such it has been necessary to estimate surface runoff fromungauged catchments and also to infill incomplete inflow series. In addition, anoverall catchment balance was made to check both the adequacy of the infilleddata and the long term flow records downstream of Cahora Bassa.

In the preparation of inflow sequences, the choice generally lies between usingstochastically generated data or recorded data. It is not only the length of theperiod of record which dictates the choice but also its variability and trendswhich exist within the series. In this respect significant and unexplained trendsin Zambezi flows have occurred since the beginning of this century.

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The mean annual flows at Victora Falls, given below, demonstrate three longcontinuous sequences with very different flow regimes.

Period Mean Annual Flow(m3 x 109)

1924 - 1946 341947 - 1980 481981 - 1990 29

Unless such trends can be explained stochastic generation techniques shouldnot be used. In reviewing these trends it was concluded that the post-1924 andpost-1981 mean flows resulted from drought sequences which affected thewhole continent. Furthermore, rainfall variations alone did not appear sufficientto be the sole cause for the increased flow from 1947 to 1980. Changes incatchment vegetation cover, particularly removal of natural forest, wereconsidered to be a major contributing factor.

On this premise, reversal to the extreme low flow regime experienced since1981 is highly significant. The approach selected therefore was to userecorded data, and three flow sequences were chosen to form the basis of thesimulation studies. These are:

- Extreme drought (10 years) (1981/82 - 1990/91)- Moderate drought (20 years) (1971/72 - 1990/91)- Long Term (61 years) (1930/31 - 1990/91)

It has been concluded by research climatologists that drought in Africa is theresult of differential warming between the oceans of the northern and southemhemispheres. They believe that this differential warming is likely to continue ifnot strengthen. If this hypothesis is accepted it would be prudent to evaluatethe water resources of the Zambezi River on the assumption that the droughtwhich has affected southem Africa since 1980 and the Sahel since the late1960s is likely to continue. Flow sequences based on this assumption havethus been prepared to investigate their effect on power generation.

In undertaking the basin studies, account has been taken of future waterdemands in development programmes and increases due to doubling ofpopulation in the next 20 years. A scenario was selected which assumed thatthe increased population would be provided with a minimum level of watersupply and that the area under irrigation would double; but would be limited to50,000 ha owing to physical constraints imposed by the implementation of largeschemes within a relatively short time-scale.

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As a result of this analysis, reductions in available water resources in sub-basins of the Zambezi River for the year 2010 were calculated and aresummarised below:

Sub-catchment Long-term Reduced runoff Percentagerunoff (by abstraction reduction (%)

(km3/year) for otherpurposes)(km3/year)

Above Victoria Falls 37 0.8 2Lower Kariba Catchment 8 0.8 10Kafue Catchment 10 0.8 8Luangwa Catchment 18 0.3 2Lower Cahora Bassa 5 0.5 10CatchmentTotal 83 3.2 4

It should be noted that the reduction in runoff by the year 2010 is an order ofmagnitude less than that evident during the drought of the 1980s.

The sub-basin runoff summarised above does not include for reservoir lossesto evaporation or over-year storage fluctuations. Evaporation rates are highand, for example, 20% of the flow recorded at Victoria Falls is lost toevaporation from Lake Kariba. Taking these losses into account and incomparison with flows measured at Tete the following errors were found:

1974 - 1990, Kariba, Kafue system, mean error +2.67 km3/year1961 - 1973, Kariba only operating, mean error -0.23 kM3/year

This level of accuracy is high and justifies the recorded flows and the sub-basin estimated runoff.

Work on CAPCOIZRA and CIDA/SADC Report No. 3.0.4 reservoir balances forKariba and Cahora Bassa reservoirs was reviewed and revised balancesprepared. In the results tabulated below, it should be noted that the presentstudy column is adjusted to eliminate the error term in the balance equation.

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KARIBA Monthly Volumes (km3)Water Balance (Monthly balance, 1930 - 1990)Component CAPCO/ CIDA/ Present

ZRA SADC Study

Flow at Victoria Falls 41.7 41.7 41.3Karba Lower Catchment 7.2 7.7 7.7Kariba Rainfall 3.9 3.9 3.9Karba Dam Outflow 41.5 41.6 41.6Karba Evaporation 8.7 8.1 10.1

Inflow - Outflow Error 2.5 2.4 -0.2

CAHORA BASSA Monthly Volumes (km3)Water Balance (Monthly balance, 1930 - 1988)Component CIDAISADC CIDA/SADC Present

3.0.4 corrected Study

Kariba Outflow 43.3 42.6 42.6Kafue G Outflow 11.0 10.9 10.9Luangwa Flow 21.6 22.0 19.4C B Lower Catchment 4.8 5.0 4.4Lake Rainfall 1.4 1.4 1.4Lake Evaporation 3.0 4.4 4.4Spillway Flow 57.9 58.5 58.5Turbine Flow 13.0 12.3 12.3

Inflow - Outflow +5.6 +3.21 -0.04

Assuming the most likely sources of error to be due to Victoria Falls for Karibaand to Luanga and the lower catchment for Cahora Bassa, it was found that1% and 12% reductions respectively in flow estimates were needed toeliminate the error term as indicated. This was ignored as overall catchmentbalances were so satisfactory.

Based on the foregoing analysis a number of specific recommendations weremade for adoption in simulating the modes of hydroelectric operation. Theseare:

(i) Make computer simulations with the extreme-drought,moderate-drought and long-term flow data sets, extending the shorterflow periods to 100 years by re-ordering the flows as follows: (1981 to1990) + (1982 to 1990 + 1981) + (1983 to 1990 + 1981 + 1982) etc.,and (1971 to 1990) + (1975 to 1990 + 1971 + 1972 + 1973 + 1974) etc.,and thus maintain serial correlation while redistributing major eventsduring the series.

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(ii) Take initial starting levels as the mean reservoir levels recorded duringthe period of record used, ie, 1930 to 1990, 1981 to 1990, 1971 to 1990.

(iii) Use monthly recorded rainfall in the simulations because of the widerange of precipitation experienced.

(iv) Make allowance for reduced surface runoff during the year 2010planning horizon.

The flow data sets thus prepared can be used to investigate any major dam tobe sited below Kariba with satisfactory accuracy.

1.5 Hydroelectric Operations

The principal purpose of this analysis is to calculate firm and average energycapabilities of hydroelectric schemes operating both separately and inconjunction, as required for generation expansion planning. For all suchcalculations, the same definition of firm energy has been adopted as appliedin CIDAISADCC Project No. 3.0.4. Firm energy is thus that obtainable with amonthly reliability of 99 percent, which for the 61 years of hydrological record(from 1930 to 1991), allows a maximum of 10 months of failure to meetdemand.

Simulated reservoir operation is set up for each month of hydrological recordusing the data and recommendations arising from the hydrological analysis.This data is combined with the power plant data to provide site specificoperational models. Details of the data, models employed, and results aregiven in Appendix B. The monthly releases from reservoirs are made so as to:

- satisfy the total electricity demands,- accommodate run-of-river outputs,- minimize spill,- satisfy any water demands,- comply with physical constraints, andbalance end-of-month reservoir states.

For all combinations of hydroelectric schemes simulated, the reservoirbalancing procedure employed is the "percentage fulness" rule. This ensuresthat the end-of-month contents as a percentage of active storage are as faras possible the same for all reservoirs in the system to achieve the essentialobjective of maximizing total storage utilization. This procedure is robustinsofar as consistent and comparable results can be quickly obtained for a largenumber of combinations of schemes such as are required for generationplanning analyses.

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The possible effects of a continuation of the present drought conditions hasbeen considered, and are used in the reservoir simulations for the "droughrscenario. The effect of the current drought is best illustrated by thecharacteristic of total system storage (ie. the total of Karba, Itezhitezhi andKafue Gorge storages) resulting from firm conjunctive operation of the existingKariba and Kafue installations. This is shown in Exhibit 1.5, from which it isevident that conditions for the last 10 years are radically different from thosefor the previous 50 years. This is confirmed by the principal flow series fromthe 61-year record and for the last 10 years as shown below:

Flow series Average flow rate (m3/s)Reduction

1930-91 1981-91 (percent)

Uvingstone 1234.1 867.5 -30Lower catchment 262.1 159.9 -39ltezhitezhi 314.4 218.7 -30Luangwa 579.0 503.9 -13Cahora Bassa 155.8 111.3 -29Lower

The critical period of operation of a reservoir providing firm yield extends fromthe time storage was last full to the time it is empty and starts to refill. Clearly,any increase of demand in this period will increase the likelihood of failure tosupply, and from Exhibit 2.3 it is evident that the critical period may not yet beover. This information confirms the prognosis presented in 1987 for theZimbabwe System Development (SDP) Plan.

Modelling of the long-term drought scenario has been developed in the mannerrecommended in the hydrological analysis. The flow sequences of the last10 years have thus been followed by the same sequences replicated 5 timesbut with 1 year of data being moved to the end of the 10-year period of recordat each replication. The results of this "drought" analysis are tabulated belowand compared with the available hydro energy based on "normal"(historical-series) analysis.

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Independent Conjunctive GainOperation Operation

Kariba Kafue Karba & Kariba & KafueKafue

a) HistoricalFirm: GWH/a 7849 5299 13148 13624 +4%

LF % 66 67 67 69Avge: GWH/a 8415 6189 14604 14396 -1%

LF % 71 79 74 73% Non-firm 7 17 11 6

b) DroughtFirm: GWH/a 6246 5057 11303 11799 +4%

LF % 53 64 57 60Avge: GWH/a 6196 5495 11691 11737 0%

LF % 52 70 59 60% Non-firm Nil 9 3 Nil

c) Reductionby droughtFirm: GWH/a 1603 242 1845 1835

% chg 20 5 14 13Avge: GWH/a 2219 694 2913 2659

% chg 26 11 20 18

The reservoirs are taken as 80 percent full for both the "drought" and "normal"scenarios, since these are about the same as the conditions reached in thehistorical record simulations for 1980. It therefore follows that the basic inflowsequences are reduced in the case of the "drought" scenario. Thus, tomaintain reservoir performance, it is necessary to reduce abstractions.

It should be noted from the above hydro energy table, that the firm energyoutput reduction for the "drought" condition is much larger for Karba than forKafue, 20% versus 5%, and that there is no gain in firm energy by conjunctiveoperation. This reduction of presently available energy is very serious, asKariba and Kafue together supply the bulk of the system load with thermalsupport (principally from Hwange) and some import from Zaire.

With Karba and Kafue in conjunctive operation, the MW capacity from thermalsources to cover a drought shortfall of 1835GWH/a is 300MW at a 70% loadfactor (LF). The point is thus made that a relatively small thermal capacity isrequired to cater for droughts. This capacity is best accommodated byreducing the hydroplant capacity factors and supplementing the output with highload factor thermal generation. This is the basic logic applied in formulatingcapacity and energy plans for the "drought" scenario.

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Future options for increasing the hydroplant inventory are Batoka and KafueLower Gorge. Further development at Cahora Bassa was also considered,focussing on the future scope for energy trading. Batoka is favoured as thenext regional plant because of energy enhancements by conjunctive operationwith Kariba/Kafue as shown by Exhibit 1.6.

Previous studies have shown that the full benefits of Batoka can be realisedonly when it is operated in conjunction with Kariba. For example the SDP studyshowed that conjunctive operation could double the available energy for thesame inflow regime. Thus assuming that Kariba alone with h"normalu inflowscan produce 7849GWH/a or 1350MW at 66% load factor, it follows that1200MW at Batoka will double the available energy with a similar load factor.

Load factor provides a practical expression of plant utilization, and so theconjunctive operation presented by Table 5.1 in the Main Report is convertedbelow to show the LF profiles for 1350MW at Kariba and 40OMW incrementsadded at Batoka.

Scheme MW Combined Total LF % Batoka LF %Capacity Firm Annual Firm Annual

Average Average

Kariba 1350MW 1350 66 71with Batoka at 40OMW 1750 74 78 100 100

at 800MW 2150 74 78 88 89atl200MW 2550 67 73 68 75atl 600MW 2950 60 68 54 65

The above analysis shows that the overall LF would be significantly improvedwith 40OMW at Batoka and reduces to about the same level as Kariba alonewith 1200MW at Batoka.

The foregoing figures are based on the historical record of 1930 to 1991 andthus represent a Anormalu scenario. It can be shown that for the "droughtscenario and 400MW at Batoka and with conjunctive operation with both Karibaand Kafue, there is a reduction of 11% in firm energy and 15% in averageenergy.

Very little data exists for the Lower Kafue Gorge. This was only envisaged asa 45OMW power station immediately downstream of the existing installation.For the purposes of generation planning this option has therefore beenmodelled as 3 x 150MW units with a head of 200m and utilizing the fulldischarge from the existing plant. On this basis, and in conjunction with Karibaat 1350MW, the firm and average energy components are 2798GWH/a and2907GWH/a, to give effective load factors of 71% and 74%.

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In order to determine the future scope for energy trading the operations of theexisting Kariba and Kafue systems were extended to include Cahora Bassa.Of the output available from this station, it is understood that 1600MW at 65%capacity factor, ie. about 91 OOGWH/a, is committed to the RSA at some futuredate. Allowing for the possibility of 1 of the 5 generating sets at Cahora Bassabeing unavailable at any one time, the firm capacity must be regarded as1660MW, but, by conjunctive operation with Kariba and Kafue, the firm energycapability is about 16000GWH/a.

Cahora Bassa clearly has a substantial uncommitted energy capability.However, until such time as additional plant capacity is provided this can beregarded only as a source of energy available for trade on a "non-firm" basis,and not as firm power. It was been noted from an ESKOM report that ESKOMfigures are of similar order with an LOLP of 5%. Using the ESKOM data itwould seem that with a sixth unit of 550MW added the incremental increase infirm energy is only 64OGWH/a. This shows a LF reduction from 88% to 72%,and so the merit of further development at Cahora Bassa may be questionableunless the development is combined with the 1600MW Mepanda Unca projectproposed by ESKOM.

1.6 Generation Planning Studies

Generation planning studies have been performed to assess the scope forcoordinated regional generation expansion. The basic study methodologyapplied is illustrated by Exhibit 1.7, and has the objective of establishing theoptimum combination of new and existing generation for a given expansionscenario in order to secure economic and reliable resources for supplyingforecast load.

The studies are based on the generation data and expansion plans obtainedfrom the Phase 1 studies and on the data obtained during the course of thePhase 2 studies. Assumptions are made on the data which is not available.

The capacity and energy availability from the hydro-electric plants in the corecountries with conjunctive operation of the existing and proposed projects arederived from the hydrological and reservoir simulation studies. It should benoted that for the basic independent and integrated plans "normal" flow regimesbased on those studies are assumed, and no account is taken of the presentdrougct crisis. The impact of drought is examined as a separate exercise afterthe basic plans are developed and ranked.

The peak demand and energy demand projections used in these studies areobtained from the load forecast review discussed earlier. The operating andmaintenance costs for the generating units, and costs of intertie transfers andcost data used for the production cost calculations were compiled as part of theeconomic study. Exhibit 1.8 provides a simplified presentation of this cost data,assembled for illustrative purposes only, because the fuel cost in $/MWH (in the

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first column) is based on an assumed heat rate. In reality, the heat rate variesdepending upon the output of the plant at any given time, and this is animportant part of the production cost simulation. It follows that $/MMBTU is thecorrect fuel cost representation for direct entry into a production cost computerprogram. Similarly, i. should be clearly understood that non-fuel variable costs,as defined for the purposes of production cost analysis, are basicallyconsumables of chemicals, oil and water. These vary according to the outputof the plant over time, and thus are also expressed in $/MWH. It is coincidentalthat the non-fuel variable costs for Harare are the same as those for KarbaSouth. The final column of Exhibit 1.8 shows fixed charges per year that cannotbe otherwise allocated. These charges are treated as a sunk cost, payableunder each scenario, and thus ignored in the analysis.

The analysis and review of capacity and energy demand and supply for theintegrated and independent development plans, allocation of resources andpower transfer scenarios are developed in the form of spread-sheet programstailored for this project. Expansion plans are based on the LOLP index andproduction cost calculations of the integrated and independent expansion plansare made utilizing the Gilbert/Commonwealth Production Cost Program(EVOLVE-p).

The production cost model (EVOLVE-p) uses the equal incremental costmethod for economic dispatch. The concept of this model is that the nextincrement of system load should be picked up by the unit for which theincremental cost is lowest. Economic dispatch (ED) is a procedure whichallocates generation among available generating units within the system so thatthe total cost of supplying the energy demand is minimized, subject to securityconstraints: these are to ensure that reserve requirements are also met.

Classically, ED involves the calculation of individual unit loadings withgeneration distributed so that the incremental cost of power delivered is thesame for each unit being dispatched. This equal incremental cost objective issatisfied by the solution of a set of simultaneous equations based on theLagrange multiplier technique. Critical data in the analysis are thereforeinput/output curves, which are quadratic and follow the average cost curves(which in tum follow the heat rate). The derivative (slope) of the inpuVoutputcurve is the incremental cost curve used to determine unit loading.

The EVOLVE-p model thus presents a simulation of practical power plantoperation. Based on this economic dispatch the production costs for each unitare computed. EVOLVE-p can be run in two modes: deterministic, forproduction cost analysis; and probabilistic, for calculating the two reliabilityindices - loss of load probability (LOLP) and consequential unserved energy.In the probabilistic mode the program deals with adequate generation to meeta given load with capacity reserve margins adapted to particular capacityoutage conditions.

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The production cost scenarios are developed from the system load shapes.These load shapes represent typical weekday, weekend day and peak day24-hour load profiles. Load and generation data are updated on a monthlyand/or annual basis according to the demand characteristics and supplyoptions. Similarly, data describing the operating and cost characteristics ofscheduled generation can be adjusted annually, together with unit additions andretirements, maintenance schedules and forced outage statistics.

The regional system comprises hydropower and thermal generation, and, insuch a mixed hydro/thermal system, the production cost of hydro energy inabsolute terms may be very small. However, the marginal worth of every kWhof this energy is equal to the the marginal cost of thermal generation. Thus itis imperative that hydro energy be used to displace highest cost thermalenergy, ie. peak energy. Another important consideration is to manage themonthly draw-down of hydro resources such that thermal production isminimized.

Draw-down analyses form part of the reservoir simulation studies. Theyinvolve linear programming to determine the monthly hydro requirements withthermal energy fitted into its optimum position in the load-duration diagram.The technique is to base-load hydro to the maximum extent possible, subjectto load requirements and hydro/thermal capacity constraints. The results ofthese analyses are fed into the programme EVOLVE-p in the form of loadmodifiers. These load modifiers adjust the load shapes to take account ofhydro energy dispatch, purchases and sales before the dispatch of thermalplant.

In setting reliability criteria it was found that reserve margins varied in eachcountry, from a spinning reserve margin of largest unit to 15 percent and 25percent of the peak demand. Zambia and Mozambique have an installedcapacity, mainly hydro, much greater than their demand and therefore do nothave a reserve margin criterion.

In order to provide a uniform basis for evaluation, a planning criterion of24 hours LOLP (1 day/year) is assumed (as directed by ESMAP). This criterionis applied to determine capacity additions for the core countries both inintegrated development plans and independent development plans, as acommon base for comparson.

Generation planning data were developed for the analysis of production costs.The data were taken from statistical information, complemented by estimateswhere necessary. They included heat rates, forced outage rates, fuel type andcost, start-up costs and operating and maintenance costs. Fixed and variablegeneration costs as presented in Exhibit 1.8 were determined from this dataand applied in the analysis. Particular emphasis was placed on informationoriginally collected from the SDP Study and updated by ZESA for productioncost analyses.

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In comparing resources and demands, there is an aggregate of 6162MWgenerating capacity in 1990 for the five core countries compared with acombined undiversified peak load of 2822MW. Furthermore, even with thepeak demand projected to double, to 5679MW, by the horizon year (2010)there is still sufficient 1990 generation capacity in the region to meet demand,albeit with a reduced capacity margin, as tabulated below:

Peak Load (MW)1990

1990 2000 2010 GeneratingCapacity (MW)

Botswana 160 255 415 197

Malawi 119 252 520 160

Mozambique 139 274 446 2360

Zambia 866 1031 1396 1622

Zimbabwe 1538 2201 2902 1823

Total: 2822 4013 5679 6162

From the above table it should be noted that three countries, Botswana, Malawiand Zimbabwe, are expected to experience a shortfall in generation, whereasMozambique and Zambia should have generation in excess of their individualdemand. Furthermore, the capacity margin falls from 3340MW (118%) in 1990to 2149MW (54%) in 2000 and 483MW (8.5%) in 2010. On this basis, andwith a 25% reserve margin, about 1000MW of new generating resourcesshould be developed to meet the horizon year demands.

The power balances do not take account of the 1600MW at 65% capacityfactor pledged to RSA from Cahora Bassa, which is the principal source ofsurplus generation within the region. This pledge is unlikely to be called before2000, and this confirms that generation resources need only be added to satisfyregional demands and meet external obligations in the post 2000 period. In thepre-2000 period the priority for regional cooperation is identified astransmission development to ensure that all core-countries benefit from theexisting and surplus generating resources. This is therefore the basis of allregional planning strategies considered in this exercise.

At the time of this study, early in 1992, it was considered that any newgeneration or transmission project identified could not be commissioned priorto 1995. Therefore, the study focussed on the new projects which can becompleted after 1995. However, those projects committed for completion by1995 were assumed to be included in the base plan, Plan A, which is describedbelow:

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For Plan A, projects proposed in order to meet the demand and comply with thedeclared strategy over the period from 1995 to 2010 are the following:

1. Songo-Lilongwe transmission intertie (200MW) between Mozambiqueand Malawi in 1997.

2. Serenje-Lilongwe transmission intertie (150MW) between Zambia andMalawi in 2003.

3. Kolwezi-Luano transmission intertie (500MW) between Zambia andZaire in 2002.

.4. Batoka hydro-electric plant Stage 1 (400MW) in 2004, Stage 2 (400MW)in 2007.

This plan assumes the Songo-Bindura interconnector is completed before 1995as one of the committed projects, and thus give Zimbabwe access to CahoraBassa generation. On this premise, the initial action is to interconnect Malawiwith Zambia and Mozambique and then to upgrade the existing intertie withZaire (at Kolwesi). The latter gains access to up to 500MW from Inga toreplace capacity at Cahora Bassa exported to RSA.

In this way new generation can be delayed until 2004, which is the earliestfeasible date for the first stage (400MW) at Batoka to be commissioned.Batoka Stage II is then scheduled for 2007 to add a further 40OMW to meet thehorizon year balances. In this Plan A, as with all other plans, the LOLP ismaintained to less than 24 hours/year, and, on this basis, the demand isbalanced with a reserve margin of 1384MW, or 24.4% of peak regional demandin the year 2010, shown by Exhibit 1.9.

Three alternative Plans, for regional development, B, C & D were evaluated,together with plans for independent development of each of the core countries.The main features of all plans are summarised in Exhibit 1.10, which alsoshows the power plant changes assumed to take place before 1995. Withregard to independent development, it should be noted that this is defined asexpansion to meet projected demand without support from other countries inthe region. It thus assumes complete self-sufficiency in power supply.

Altemative regional plans evaluate development without the Songo-Bindurainterconnector (Plan B) by adding Kafue Lower Gorge. Plan C is a thermalequivalent to Plan B, by choosing Hwange l1l, and Plan D is Plan A withoutBatoka, substituting Lower Kafue Gorge and Hwange Ill. Kapichira was notincluded in any regional plan at this stage of the study, because it is notneeded to achieve regional power balance. As will be discussed later,Kapichira was included in an intermediate scenario of Plan A, to reduceMalawi's import dependency.

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SECT. 1 MA3.8 PHASE 2

1.7 Transmission Planning

Adequate interconnections where economically justified provide the key tolarge-scale, low-cost diversity, to the sharing of reserve generating capacity,and to the most efficient utilization of existing and planned generating capacity.In short, interconnection is the coordinating medium that makes possible themost economic use of resources in the SADC region. Transmission planningis thus concerned with assessing the efficacy of existing bulk transmissionnetworks and reviewing opportunities for extending these networks to facilitateintegrated generation expansion meet regional demands to the year 2010.

The main priority is to ensure that there are no network constraints on reliableand economic balancing of generation and load across the power system. Afurther priority is to assess the options for developing a second transmissioncorridor from Zambia through Malawi to Mozambique, a basic strategy in allexpansion Plans. This corridor is proposed to facilitate full integration of Malawiinto the regional network and also to enhance the security of the bulk powersystem. This second corridor, at the right voltage, will permit interconnectionof Tanzania to the SADC Grid, and facilitate "wheeling through" optionsbetween Zaire and RSA; these are also objectives of the overall Study.

Capacity transfers for regional balances are unlikely to exceed 1000MW andthis is generally within the capability of the present ac bulk transmissionnetwork. Only in the event of very large "wheeling through" power transferswould it be economically feasible to consider new dc developments, and so dcis discounted in assessing transmission facilities to meet needs of the SADCCore Region within this horizon of this Study.

The capability of long ac lines at any given voltage is a function of transmissiondistance, because of the transient stability constraint, as explained by the curvein Exhibit 1.11, in which line load is represented as a multiple of 'surgeimpedance load' (SIL). This curve, known as the St. Clair Curve, is widelyaccepted as a conservative guide to ac line loading versus transmissiondistance in planning interconnections. It is presented to provide a simplemethod of assessing the capability of the SADC Grid: the starting point forfurther analysis. Originally taken from Fig. 2.4.2 of the Transmission LineReference Book (published by EPRI), it has been modified to be representativeof SADC 50Hz system and voltages, and with distances measured inkilometres. Reference should be made to Appendix E for further details onSADC transmission lines.

The existing Zambia/Zimbabwe 330kV bulk transmission network ischaracterized by power generation sources that are remote from the main loadcentres, and therefore many of the lines are about 200km (125 miles) long.These lines are therefore limited to 700MW (2xSIL) by stability considerations,as shown on the St Clair Curve. This is close to the thermal load (719MW) ofthe existing twin-conductor (Bison) lines. In the case of very long lines, for

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example from Hwange to Sherwood (355km) it is prudent to limit the loadtransfer to about SIL, say 360MW. This is to minimize the voltage angle (acrossthe line) and obtain reasonable balance between line VAR generation andlosses.

The MW losses of transmission lines basically are proportional to the squareof the power transferred. The, also are inversely proportional to the square ofthe conductor cross-sectional area. Thus doubling the power transfer willquadruple the losses, but if the conductor size is also doubled the MW lossescan be held constant. As a general rule the economic conductor loading isbetween 40% and 60% of the conductor thermal rating. Furthermore, ateconomic loadings the losses per 200km are about 2-3% of load carried. Atthese loadings also, the regulation (voltage drop) is not an undue problem.

The performance of any network and associated upgrade or planning proposalis basically assessed on normal loadings, MW losses, voltage profiles (andangles) and transfer capabilities (under disturbed conditions). Voltage anglesand transfer levels as a percentage of SIL give a measure of stabilityperformance, and, in this respect, the power system is most stressed underfault conditions when the system must recover following the loss of a circuitelement - an (N-1) condition.

The most practical way of providing information on voltage profiles and angles,active (MW) and reactive (MVAR) power flows and the loading of elements ofthe power system - generators, transformers, overhead lines, etc., is toundertake power (load) flow studies. These power flow studies are a computersimulation of the operation of the power system by a "power flow" (PFLOW)program that models steady-state performance. This is the methoa used inthese analyses to ensure a balanced relationship between power systemelements so that, under normal (N-0) conditions and single outage (N-1),economic generator dispatch can be achieved without undue power flowcurtailment and network overloading.

Based on planning experience, it is generally accepted utility practice that atransmission system properly planned for single fault contingencies will have asatisfactory performance. This criterion assumes the role of a quality index; itis implicitly accepted that double or multiple contingencies are remote. Itshould also be noted that many major utilities plan transmission for supplyingthe peak load and apply the (N-1) criterion. This defines 'firm' transfercapability.

Most faults involve overhead line circuits, typically -at an occurrence of 2 faultsper 100 miles per year from all causes. Transformers are very reliable andforced outages with this equipment can often be disregarded. It follows that asit is unusual to arrange planned outages at times of peak demand, the onlypractical (N-1) contingency at system peak is one involving a line outage; thisis the rule adopted in these studies.

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SECT. I AAA3.8 PHASE 2

Power flow analyses have been carried out for the 1995, and 2010 load years.The studies have been performed mostly with operating conditions at annualpeak (APK) load and economic dispatch (ED) generation. The basis of thestudies and assigned objectives have been summarised above and arepresented in detail in Appendix F of the Main Report as a future planning guidefor SADC Utilities.

All five national networks have been examined and modelled to include all bulksupply point (BSP) load buses. Networks have been reduced as necessary torepresent practical operation without, undue detail, and loads have beenassigned according to the latest available Control Centre information.Appendices D and E in the Main Report provide details of the database andmodels.

As necessary, internal networks were assumed to be reinforced toaccommodate the load growth and to anticipate future development to ensuregood voltage profiles and avoid overloads. However, no attempt was made tooptimize or update internal networks that are not relevant to bulk power flowsacross the interconnected system. Internal network updates and optimizationare considered to be an exercise outside the scope of this Project and requiringspecific planning and design analysis by planners in the individual SADCutilities on an ongoing basis.

New generation, such as Batoka, was taken to be connected to existingnetworks as proposed in feasibility reports. In the case of Batoka, one circuitwill be taken to Kadoma and two circuits to Bulawayo, as proposed in theZimbabwe System Development Plan (SDP Report). Kapichira is assumed tobe connected into the Malawi network at 132kV via Blantyre, and Lower Kafueis considered part of the Kafue complex and so not separately represented.

Interconnection with the 330kV system at Bindura, Bulawayo andSelebi-Phikwe is made through 500MVA autotransformer banks. At Songo itis assumed that a new 40OkV substation will be constructed with interbartransformers to the existing 22OkV substation (for the DC line and CahoraBassa). The existing 220kV connection from the Copperbelt to Zaire (SNEL)via the Michelo-Tee from Luano was included in the model, together with adirect 400kV connection from Kolwesi to Luano. Finally, 22OkV (and alternate400kV) interconnections were assumed between Pensulo (Serenje), Ulongweand Songo.

Some twelve cases were examined to represent the expected base-case andcontingency conditions for the 1995 and 2010 load years under variousinterconnection (INET) scenarios. The loads applied were selected on thedeclared aggregate peak MW demands identified in the load forecast and takento include losses. The loads were then distributed in each network, generallyaccording to their present disposition (in the absence of specific data) anc

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increased using the ratio of present to forecast aggregate load. Nointermediate year scenarios were considered because it was found that noexisting bulk transmission corridor was overloaded, nor were there any unduevoltage problems requiring specific correction.

In order to review the minimum interconnection needs of Malawi and test theuse of a link with RSA (other than for power wheeling) it was decided to not linkBulawayo to Selebi Phikwe and also to only interconnect Malawi at 220kVrather than at 400kV. This is considered the least-cost arrangement. Itdisallows opportunities for system support from RSA and inhibits powerwheeling. It thus notionally represents the regional network as an isolatedpower system. For power balance purposes, each country is divided into zonesand areas, and zone/area summaries for final computer runs were produced toprovide the 1995 and 2010 power balances shown in Exhibits 1.12 & 1.13.

The overall conclusions from the 1995 scenarios are that, with the existingnetwork, there are no undue power flow problems. Furthermore, there issufficient capacity margin in the 330kV bulk transmission system toaccommodate significant increases in load growth. There is a perrenialproblem of an excess of charging MVAR, but this will ease with load increases.However, it will be prudent to undertake VAR management studies to optimizecompensation arrangements over the practical range of load conditions. Thiswill hold down voltage angle excursions which are nearly 50 deg.. permittinggood overall system voltage profiles and a reduction in system losses, all as aresult of minimizing VAR flows.

The 1995 power balance is 3426MW after discounting export of 1600MW toRSA. This represents the generation "sent-out" to meet the demand and coverthe losses. This scenario is summarised in Exhibit 1.12, in which it is assumedthat the Songo-Bindura line is commissioned and Zmbabwe is supplied with40OMW from Cahora Bassa. It is also assumed that a tie-line exists betweenMalawi and Zambia over which there is a small surplus exported from Malawi.Other ties are as they presently exist (in 1992). The transfers are 337MW fromZambia to Zimbabwe of which 30MW is wheeled through to Botswana. Powerbalance is achieved in Botswana by a small import of 15MW from RSA. In thisscenario there is no import from Zaire.

The most severe contingency in 1995, assuming no interconnection from Songoto Bindura, is the loss of one of the Kariba-Alaska lines. This results in theremaining lines becoming slightly overloaded and a reduction in voltages to justbelow the 95% margin. This case is most easily accommodated byrescheduling generation to reduce line loadings. For example, flows across theKariba interconnector can be reduced by increasing generation at Hwange.

Exhibit 1.13 shows the 2010 base-case with Malawi interconnected to Zambiaand Mozambique at 220kV. It is the preferred scenario for regionaldevelopment without due allowance for "wheeling through" by third parties.

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This case thus represents the minimum transmission reinforcement to permitexchange of power within the core-Country system to meet 2010 loaddemands.

It is assumed that, in 2010, Kapichira and Batoka are both in operation at125MW and 800MW respectively and that the infeed from Zaire is 60OMW. Allinterconnections are in place, with each country linked to at least two sources.The maximum power flow is at Kariba N/S at 626MW. The 220kV Botswanalink is loaded to 100MW. There are no overloads on the bulk system and busvoltages are within assigned limits. All machines are at or within theirmaximum continuous rating (MCR). Voltage angles across system are +20/-31deg., with Songo at 0 deg.

It should be noted that with Kapichira there is a power import to Malawi of173MW, to achieve full power balance for a demand of 512MW. Thus theimport is 34% of the 2010 peak demand. For this reason it is consideredessential that Malawi has two infeed sources and that each should be capableof carrying the full 173MW under an N-1 contingency. This suggests that theminimum transmission voltage should be 22OkV, and this is confirmed by moreadvanced studies discussed later in this Report Summary.

For this 2010 scenario, supply and demand in Zambia is basically in balancewith a small surplus of 73MW. The 600MW import from Zaire is thus 'wheeledthrough" to Zimbabwe. Furthermore, the net import to Zimbabwe, afterdiscounting Batoka and the 1 OOMW export to Malawi, is 648MW or 22% of thepeak demand. Of the total import, 122MW is from Mozambique (Songo) overthe Songo-Bindura line; it is assumed that it is over this link that reservecapacity support will mostly be obtained.

For Botswana, the import level of 252MW is 61% of peak demand and is thehighest import level (in percentage terms) of any core-Country. Most of thisimport (1 52MW) is from RSA and is assumed to be imported from Matimba toSelebi Phikwe at 40OkV.

As with all cases, the Mozambique resource inventory is taken to includeCahora Bassa (2075MW), assumed connected to the Songo 22OkV bus. It isfurther assumed that the pledged export of 1600MW is transported to RSA overthe Songo-Apollo HVDC line. In the development of the intemal network forMozambique, it is assumed that the North-Central areas are inter-connectedat 22OkV as proposed by Swedpower. The load assigned to Mozambique isthus only the North-Central component, and the balance of demand (for thesouthem area) is assumed to be supplied by ESKOM (RSA).

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With respect to 2010 contingencies, Kapichira is not included in the integratedplans, and thus an outage of the Songo-Lilongwe 22OkV line is a valid casewhich tests the capability of the Pensulo (Serenje) - Ulongwe 220kVinterconnector to balance the Malawi demand. For Malawi to achieve powerbalance without Kapichira, 296MW must be imported at Lilongwe, and thisrepresents 58% of the demand. Furthermore, as the load at Pensulo is 152MWthe power sent-out from Kabwe to Pensulo (Serenje) is 550MW and the losseson the Kabwe-Pensulo-Lilongwe circuits total close on 100MW or 22% of thedelivered power for line loadings at 80-90%.

The voltage angle across the 22OkV line section alone is over 35 deg., and thusis at the limit of stable power transfer at 22OkV assuming infinite bus capacityat each line end. A forced outage of the Songo-Lilongwe line, as postulatedis thus expected to result in system instability. This is confirmed by thetransient stability analysis reviewed later in this Report Summary. It isinteresting to note that for the case of a 400kV Pensulo-Lilongwe line and thesame delivered power (296MW), the voltage angle across the line section isonly 10 deg., and the total line losses (from Kabwe) are reduced to 36MW, thusdemonstrating the 40OkV transfer capability.

It is noteworthy that Botswana also faces the same basic contingency problemas Malawi with the loss of the stronger 400kV link (from RSA). The remaining22OkV line from Bulawayo to Francistown becomes overloaded and this wouldresult in Botswana being "islanded" with a loss of about 60% of peak demand.Again the solution is full 40OkV interconnection. However, given that theexposure period for these contingenies is only at times of peak demand - about5% of the load year - and also the low fault incidence - typically two faults per100 miles per year - the economic justification for a "full" 40OkV interconnectionis questionable. In fact, this level of security can only be economically justifiedif the interconnectors are developed for "wheeling through" in addition to theiruse for integration of regional development.

1.8 Advanced Transmission Studies

The advanced transmission studies dealt with in the Main Report compriseshort-circuit and transient stability analyses. These are undertaken to confirmthat there are no undue constraints on power transfer for regional balances,and that the system recovers from all plausible disruptions to steady-stateoperation. The studies are completed with an analysis of the impact ofwheeling power through from Zaire to RSA, and a review of the issues andoptions improving long-distance bulk power transfer capabilities. This lattermatter is of obvious interest and concern to the non-core countries, but is alsorelevent in the established grid.

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Short-circuit studies are mostly required to assess switchgear ratings and ac/dcsystem strength. These have been carried out with all circuit elements innormal operation for peak load scenarios in the boundary years of 1995 and2010. All existing 330kV 7500MVA switchgear, with the exception of KaribaSouth and North, are within their rupturing capacity (fault rating), and remainso over the study horizon. As shown by Exhibit 1.14 the fault level at KaribaSouth is about 8300MVA in 1995, and this level is increased to circa 8700MVAin 2010. The same fault levels apply at Kariba North because the transferimpedance between the two substations is practically zero.

The results show that Karba switchgear is at risk of rupturing under faultconditions in 1995, and this supports a conclusion first identified over 5 yearsago, in 1987. As this section of the 330kV network has remained basically thesame since 1987 and will remain so over the complete study horizon to 2010,it follows that even now the switchgear is at risk. It is thus a clearrecommendation of this Report that this matter be rectified forthwith, andregardless of any regional or national power expansion. Once this matter hasbeen addressed there will be no undue fault level problems with respect toswitchgear ratings in the present or extended network.

The bulk interconnected network is characterised by long transmissiondistances. Transmission buses are typically more than 200km from anygeneration (source) bus. Fault levels throughout the networks are thusattenuated by large transfer impedances. For example, the maximumtheoretical three-phase fault level infeed from a 200km twin-Bison 330kV lineis 1624MVA with an "infinite bus" (zero impedance) generating source. For atypical 132kV circuit of the same length and also with an "infinite" bus source,the fault level is only 191MVA. This explains why there is generally nosignificant change in fault levels in the existing 330kV system over the planhorizon. High transfer impedances can also lead to problems of transientstability resulting from faults in which lines are tripped, such as theSongo-Ulongwe line. Stability problems are usually created by attempting tocome too close to the limits of steady-state operation, so that the powersystem fails to recover from a disturbance. For example, attempting to transfertoo much power over too long a distance at an inadequate voltage level willlead to system collapse. This will be the case for the 22OkV tie-lines toUlongwe from Pensulo (Serenje) and Songo without the benefit of Kapichirageneration.

This situation is only likely to occur when there is a fault trip of thePensulo-Lilongwe line under peak demand conditions in the horizon year. Asnoted earlier, the risk exposure is not significant and thus upgrading to 400kVcannot be justified economically unless linked to revenue earning activities suchas "wheeling through". Upgrading is thus bracketed with Kapichira assub-optimal in terms of least-cost investment. The fact that Kapichira, at amere 125MW, facilitates system recovery suggests only that the system isclose to the limit at 22OkV. Even so, this does not provide a reason for

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upgrading since system trips and load curtailment can be applied in periods ofexposure to risk. The position is thus taken that, with this link, only revenueearning "wheeling through" contracts can economically justify upgrading.

A similar study examining the stability of the Bulawayo-Matimba link via SelebiPhikwe demonstrated that the system would become unstable if only theSelebi-Matimba section was installed and was tnpped under fault conditions.The remaining Botswana link, at 22OkV from Bulawayo to Francistown wouldbe unable to support this contingency and the system would collapse. It wasfound that, for stable operation, the complete 400kV line from Bulawayo toMatimba via Selebi Phikwe must be built.

Exhibit 1.15 best illustrates the stability problem with just theBulawayo-Francistown 220kV link, as it shows an increasing angular voltagedisplacement across the 220kV line following fault clearance and an even widerdisplacement with the Selebi Phikwe bus. The run was terminated in 0.62swhen the angular displacement between Hwange and Spitskop exceeded140 degrees. The Hwange angle remained constant throughout the run atabout +28 degrees, although the terminal voltage fell 3% from 1.02pu to 0.99puas a result of a 100MVAR swing from -51MVAR to +55MVAR. The Kariba,Kafue and Songo (CB) machines similarly moved to supply VARs but to alesser extent. However, the Spitskop source was the most affected as thetransfer impedance over the 132kV couple was too large. The source anglewent to -112 degrees and, when added to Hwange, reached the 140 degreelimit. Because of the very high transfer impedances at 132kV as discussedearlier, adding more lines from Spitskop would have no practical effect incontaining the power swing.

A review of "critical clearing time" studies, originally developed for the SDPReport, showed that the bulk system generally had a very adequate stabilitymargin, except when Hwange is on maximum dispatch and there is no importfrom Zambia. However, adding Batoka retrieves the margin for this unlikelycontingency. The scenarios are similar to those used for contingencies in thepresent studies, and so it is concluded that the 330kV bulk power system isbasically stable for faults at major generating buses provided maximumclearance times for three-phase faults are not greater than 7 cycles (1 40ms).

With the proposal to build now the complete 400kV Bulawayo-Matimba line,there should be no undue stability problems on the SADC network. However,this conclusion assumes operating regimes in which circuits generally are notloaded above SIL so that maximum power angles across lines are kept to about20 degrees. It is therefore concluded that the SADC network based upon thepresent 330kV bulk power system is adequate for balancing regional supplyand demand over the Study horizon to 2010. On this premise, reinforcementsthat now become necessary to support wheeling-through transfers representan impact on the SADC network regardless of the system benefits that mayotherwise accrue.

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1.9 Wheeling-Through Studies

In the core-Country studies (without "wheeling through") the gross import fromKolwesi was about 500MW to make up for the generation deficit in SADC andbalance power demand. With the full capacity of the Inga-Kolwesi HVDC lineavailable, it should be practicable to increase the import to 100OMW, enablingcirca 500MW to be "wheeled through" to RSA. The import level could beincreased to 1500MW by upgrading the HVDC line with more convertor banks,and depending on the actual surpluses available from Inga. In such a case themaximum net power that can be wheeled to RSA from Zaire will be about1OOOMW.

If the SADC integrated Plan A development is assumed, Batoka, as the nextregional power plant, would be taken to Stage 2 (800MW). To simulate anexport from Zaire a negative load of the assigned amount is applied to theKolwesi bus. Import to RSA is also assumed over the HVDC line at Songo, butin this case after discounting the 1600MW export already pledged to RSA. Theexisting 330kV bulk transmission system with the proposed Plan Ainter-connections is taken as the basic network, as this satisfies regionalbalances. The impact of wheeling is thus measured by determining theminimum reinforcements to this network for each power level and transfer path.

The practical measure of impact on a transmission system, as a consequenceof providing access for "wheeling", is the need for upgrades and reinforcementsin order to preserve the integrity of the system at the level enjoyed prior towheeling. Impact is thus measured as a technical issue in terms of capabilityand cost ratios. For example, if a proposed single-circuit 22OkV line must bereplaced by a double-circuit 400kV line in order to satisfy "wheeling-through"options the installed cost and "firm" capability ratios are about equal at 4/1.These ratios correspond to a double-circuit 400kV line cost of aboutUS$0.5m/km, and a "firm* capabUity of 63OMW (based on a one circuit outage,N-1, security).

In determining the transmission arrangements for wheeling through, a trialloadflow study was carried out. This showed that 500MW could be transferredover a single 40OkV line from Bulawayo to Matimba, but the voltage angleacross the line was over 30 deg. This suggested that a second circuit wouldbe required for stable performance, and, in any event, this reinforcement isdeemed necessary for "firm" transfers. By a similar token, 40OkV double-circuitlines are assumed from Kolwesi to Luano for transfer of 1 OOOMW or above, andalso for the second corridor through Malawi from Kabwe via Pensulo andUlongwe to Songo. All proposed interconnections are thus of "double-circuitconstruction at 400kV where power transfers include a wheeling component.

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For "wheeling through" from Zaire to be effective above a net power flow of500MW, it is expected that Batoka generation will need to be increased to alevel of more than 800MW. On this basis Batoka would directly export to RSAthrough Matimba, as the nearest power plant, with Zaire imports supporting thecore-Country power demand balances. The studies therefore also review thenotion of Batoka as an "export" power plant, to support the "wheeling through"concept and also provide an export opportunity for SADC. Batoka is, of course,initially justified ': satisfy regional power balance, and so generation isincrementally increased to 1600MW.

To test the impact of "wheeling through" on the SADC interconnected system,seven scenarios have been studied in three major categories, as given belowand with the paths illustrated on the map of Exhibit 1.16. These are:

1. Scenario 1: The eastern (Malawi) corridor at 22OkV, Kolwesi export at1000MW and 500MW import to RSA from Matimba. This scenario is aninitial test on the wheeling capability of the main 330kV network.

2. Scenarios 2,3 & 4: The eastern (Malawi) corridor at 400kV, and powerimport to RSA from Songo (on HVDC line) as well as Matimba. Thisgroup tests the 330kV network performance for different power transfers.

3. Scenarios 5,6 & 7: a 40OkV eastern corridor, as (2), but with the Batokageneration increased to 1200MW and 1600MW. This group examinesthe system benefits resulting from Batoka generation additions.

It should be noted that a part of the Kolwesi import is pledged to SADC forbalancing the regional power demand. The balance is available for wheeling,and to this, in the category 3 scenarios, is added generation from Batoka. Theeffect of increased generation at Batoka is therefore to raise the exportpotential to RSA above that otherwise possible from Zaire. This provides anopportunity for SADC to also trade energy with RSA, but more importantly, itshows how much more SADC generation is required If Zaire exports areexclusively committed to RSA.

The loadflow study results of the seven scenarios, together with thecorresponding single line diagrams, are presented in Appendix X of the MainReport. The map of Exhibit 1-16 and tables of Exhibit 1.17 provideexport/import summaries and voltage angle displacements across the system.The summary shows that, without increased generation at Batoka, the angleacross the system is generally too large for acceptable operation. Furthermore,even with Batoka at 1600MW, large angle displacements are apparent if toomuch power is exported via the Matimba-Bulawayo line.

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Using angle displacements as a measure of system capability, it was found thatScenario #7 has the most secure wheeling mode. In this scenario imports toRSA via Matimba and Songo are approximately equally shared. With thisarrangement, and also operating Batoka at 1600MW, a total of 1250MW canbe delivered to RSA for an export of 1 OOOMW from Zaire at Kolwesi; the actualimport via Songo is 60OMW and at Matimba 650MW. There is a particularlygood margin for stable operation over the eastem corridor from Kolwesi toSongo via Kabwe and Pensulo, as the overall vottage angle is 36.70. Also, withBatoka at 1600MW there is now a good power balance in the southem network.This has the benefit of reducing the power transfer over the Kariba-Alaska link,which, even for regional balances only, is the main bottleneck in the 330kVinterconnected system.

The above with is thus considered the best "wheeling through" option. Withwheeling equally shared between the 330kV network and the eastem (second)corridor, and sufficient generation support to balance the Zimbabwe system,the full capacity of the Inga-Kolwesi HVDC line in Zaire (1000MW) can betransferred to RSA. The impact on the regional system is confined toupgrading the already proposed interconnectors to double-circuit at 40OkV. Itis also prudent to add a fourth circuit to the Kariba-Alaska corridor; but this isneeded anyway.

Although not studied in detail, there is an option of a third (western) corridorfrom Kafue via Uvingstone and Selebi Phikwe to Matimba. This wheelingoption would have to be at HVDC because the straight distance would be closeto 1000km. For this reason, and also for reasons of economics, the capacityshould be at least 1500MW. This corridor has the advantage that It bypassesthe southem section of the existing 33OkV network, which is the area of mostconcern in wheeling through the region.

Using this new corridor, it would be possible to transfer all available power fromZaire to RSA and also any surpluses that Zambia may wish to export to RSAon a bilateral basis. With this option there would also be no need to upgradethe second corridor (through Malawi) from 22OkV to 400kV. Hence, there is noimpact on the main 330kV system or the second corridor, or on any proposalmade to satisfy regional balances. The estimated cost for this line is US$400m,assuming a 1000km bipole design operating at ±500kV with terminals at Kafueand Matimba.

The proposal of a third corridor as described above has merit. However, itshould be noted that it is only as a multi-terminal HVDC line that it can beproperly considered a regional option. Multi-terminal HVDC designs are onlyjust becoming possible, and this is why the proposal has not been developedin detail in the Study. Of course, this corridor could be developed as an HVACline, but the voltage would have to be 765kV, and the line would cost at leastUS$750m, which is not considered feasible.

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With a multi-terminal line, it would be unnecessary to continue the 40OkV linefrom Selebi Pikwe to Bulawayo, because regional support to Botswana couldbe provided at Selebi Phikwe directly from Zambia. Extending themulti-terminal HVDC concept further, Batoka can be interconnected atLivingstone, and developed as an "export" power plant. Finally, with amulti-terminal HVDC development as described, it becomes possible tointerconnect with Tanzania at Mbeya via Pensulo (Serenje) by extending theHVDC line to form a regional transmission backbone.

1.10 Review of Interconnection Options

The main purpose of the advanced transmission studies was to confirm thefeasibility of interconnection options for the core-country expansion plans, andalso to evaluate the impact of wheeling through the main SADC Grid.However, to complete the exercise for the region as a whole, including thenon-core countries, a review was made of the concepts and criteria forlong-distance ac and dc transmission, including ac/dc interconnection, and oftheir impact on the region.

First, it should be noted that for very long distances coupled with large powertransfers, the HVDC option has clear technical and economic advantages overac transmission provided certain criteria are followed. Of these, the mostimportant is the ac/dc system strength, which directly impacts on HVDC linksterminating in relatively weak ac power systems. The SADC system isinherently weak because of its longitudinal dimension, and so bulk power HVDCcannot be considered without increased system strength.

The strength of the ac/dc system interface is determined in terms of theShort-Circuit Ratio (SCR), which is the controlling factor for maximum availablepower (MAP) from a dc link. The SCR is defined as the ratio of ac systemadmittance in terms of short-circuit MVA to the dc power on a base of ratedvoltage. The effective SCR includes shunt capacitors used as ac filters. Therelationship between the MAP and the required power is used to classify theac/dc system strength. For values of SCR below 3 there is a danger ofunstable operation of the dc link. This applies particularly for cases whereSCR < 2, since it is then not possible to switch in additional shunt capacitorsto maintain ac voltage and therefore the required dc power level.

In the case of the Inga-Kolwesi HVDC line it should be noted that the firststage (convertor) rating is 560MW, and the fault level at Kolwesi is 1360MVA.This gives a nominal SCR value of 2.4, which may be just satisfactory for stablelink operation. However, it is not practicable to double the link capacity to thedesign rating of 1120MW (with second stage conversion) without also at leastdoubling the ac th-s-phase fault level. This is why in these studies powersupport for SADC from Zaire has been limited to circa 500MW in the absence

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of firm knowledge on the status of Shaba generation. This issue also reinforcesthe need for double-circuit 400kV development for wheeling through scenarios,as the resulting reduction in transfer impedance will about double the fault levelat Kolwesi.

The main problem with moving bulk power over long distances is one ofdynamic performance (stability), as already discussed and illustrated by the StClair Curve of Exhibit 1.11. Power flow on a transmission line is a function ofphase angle, line-end voltages and line impedance, and it has always beenunderstood that these parameters could not be controlled fast enough to handledynamic conditions. As a consequence dynamic system problems have beensolved by overdesign, in which generous margins have been allowed to ensuresystem recovery from operating contingencies such as faults and generatoroutages without the benefit of real-time system control of line parameters.

Using Flexible AC Transmission System (FACTS) technology, the name givento concepts of transmission line control using thyristers, it has now beendemonstrated that high speed control of transmission parameters is practicable.The integrated application of these devices is now expected to allow secureloadings of transmission lines to their full thermal capacity. This will remove theconservative power-distance constraints presently applied in long distance actransmission. It may thus now be feasible to improve the dynamic performanceof power networks such as the 330kV interconnected system without addingmore lines. However, this approach does not do away with the need forupgrading where thermal limits have been reached, or where a loss evaluationshows the need for reinforcement as an optimum economic solution.

A fundamental notion behind FACTS is that it is possible to continuously varythe apparent impedance of specific transmission lines so as to force power toflow along a "contract path". This is clearly important in the SADC system,assuming the network is used for wheeling-through power between Zaire andRSA in addition to satisfying regional balances. The "contract path" idea is anentirely new concept in system planning, and relies on the use ofthyristor-controlled series and shunt compensation. By this means it ispossible to provide precise control of the impedance of transmission lines andthus maintain constant power flow along a desired path in the presence ofcontinuous changes of load levels in the extemal ac network.

The Static VAR Compensator (SVC) was introduced years ago, acting as ashunt capacitor or reactor, to produce or absorb VARs. In this way voltagestability can be maintained. The latest development is Controlled SeriesCompensation (CSC), which can effectively damp power swings by reducingthe series impedance of the transmission line. These FACTS devices are thusalready available, and should be allowed for in the detailed design ofinterconnections arising from these studies.

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FACTS is expected to be of particular value in Angola, Namibia and Tanzania,because these non-core countries are large and remote from the establishedSADC Grid. FACTS offer a way to reduce transmission costs and encourageinterconnection. All three countries enjoy considerable hydro and gasresources, and can thus benefit from interconnection provided these resourcescan be competitively developed and made available to reasonably substantialmarkets. This suggests bulk generation and transmission and a sufficientlylarge energy market to enable the delivered price to be competitive with theavoided cost of energy production either in the receiving power system(s) or inmore expensive plants outside, eg, thermal rather than hydro plants.

Firm energy sales (energy brokerng) between ublities is often the motivatingforce promoting interconnection and the sizing of plants larger than for localneeds. Other benefits from interconnection such as economies of scale andreserve capacity sharing may follow if a power pool is formed and developmentis integrated. But the fundamental economics of interconnection are usuallypredicated on firm energy exchanges on a bilateral basis or supplies to a powerpool at a competitive price. The key issue is to have a sufficiently large powersurplus to make transmission to more distant markets worthwhile. Traditionally,power export potential has thus relied essentially on the larger hydro plants andwill perhaps in the future also depend on gas-fired combined cycle plants.

The present (1992) aggregated energy requirements in the five SADC corecountries are 20,379GWH, this is 14% of the current RSA demand, which isabout 1 40,000GWH. Thus assuming reasonable supply/demand balance withinthe established SADC Grid, the market for trading energy surpluses in theSADC Region is clearly in the RSA where 98% of the demand is satisfied bycoal-fired generation.

Currently, the average cost of energy from coal in the RSA is 133.54mills(Rand) per kWh, or about 50 mills(US)/kWh. This is therefore the marginalproduction cost in competing for the RSA energy market and the assumedbreakeven price for imported energy. It is roughly equivalent to a delivered costof US$1 700/kW, assuming a 20% fixed charge rate over 30 years and a 70%load factor. For the third (HVDC) corridor from Kafue to Matimba discussedearlier, the transmission costs for say 1500MW delivered are aboutUS$300/kW. This leaves about US$1400/kW for any costs associated withmaking the power available in the sending system.

It is suggested that a sub-study is made in which the focus is to determinefeasible bulk power corridors to interconnect large generation resources to bulkpower markets. The dichotemy of resources and markets must be properlyaddressed to ensure economic realism, and these analyses must assess howpower corridors can provide system benefits to associated networks andfacilitate development of secondary (intra-regional) markets. Thus, instead ofmeasuring the impact of wheeling-through on a system developed to meetregional demands, the emphasis is placed on creating dedicated corridors for

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bulk power transmission that transcends several countries and regions. Thisis the concept discussed earlier with respect to the third corridor becoming aregional backbone. The concept gives a new dimension to the study ofinterconnection in southern Africa that cannot be addressed within theconstraints of the present TOR.

1.11 Power Development in Non-Core Countries

The TOR required that analyses be extended to include all SADC countries "todetermine whether any additional regional benefits accrue" beyond thoseobtained by integration of the five core-country networks. The remainingcountries in the 10-nation SADC Region are: Tanzania, Angola, Namibia,Lesotho and Swaziland. These countries are either remote from theestablished bulk transmission grid or otherwise cannot be directlyinterconnected. This is the reason why they have not been considered in thecore-country analyses, as explained in introducing this Report Summary.

Each of these five non-core countries was studied in tum to establish thecriteria under which interconnection or some other facility would permit sharingof regional benefits. A country-by-country overview is made of the presentpower sector status against the background of energy and economic resources.This work is mostly based on a scrutiny of available reports from IBRD andAfDB sources, together with the Inception Report of this Study. Developmentoptions have then been reviewed to determine the scope for benefits fromregional cooperation in the power sector, as now presented in this ReportSummary.

Tanzania

The scope for Tanzania to benefit from regionally integrated powerdevelopment is predicated on upjo 1 00MW import support (from Zambia) in theshort-term followed by substantial exports to an established SADC Grid in thelonger term; the latter is subject to sufficient capacity being built in Tanzania.

The forecast outline of the Development Plan, given by Exhibit 1.18, suggestsa significant uncertainty in demand in the long-term. Following thecommissioning of Kihansi in 1997, it would seem prudent to plan to coverdemand variations by imports (from the SADC grid) rather than construct smallhydoplants as proposed in the 1985 Development Plan and 1989 Plan Update.This suggests transmission interconnection from Serenje, also known asPensulo (in Zambia) to Mbeya (in Tanzania), a distance of about 600km; seethe map of Exhibit 1.1

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Furthermore, this strategy of interconnection should be combined with are-evaluation of opportunities to utilise Tanzania's coal and gas energyresources in electricity supply. Hydropower is now becoming a scarce anduncertain resource, given the expected continuation of the present drought insouthem and eastern Africa. A strategy that promotes development of thermalgeneration would therefore greatly benefit an extended SADC grid system.

Stiegler's Gorge has been dropped from discussion in the latest developmentreview as it is too large for internal demand progression as at present foreseen.However, this scheme may well become economic if there are substantialexport possibilities to the SADC Grid. Interconnection with the SADC Grid istherefore basic to any benefits of regional cooperation that can accrue toTanzania.

Interconnection has been proposed at 22OkV from Pensulo (Serenje) to Mbeya,but a 22OkV line will only permit delivered power up to about 100MW. Topermit substantial export opportunities, as discussed above, it is concluded thatHVDC is the only feasible option, given the large transmission distances. It isthus recommended that interconnection is planned between Tanzania andZambia, basically as proposed in the 1989 Plan Update; that is by building aline at 330kV or 40OkV from Mbeya to Pensulo. This line should be constructedto permit conversion from ac to dc operation for bulk power HVDC transfer at±500kV. The line can only be fully justified economically if ultimately used forbulk power exports.

Angola

According to the Inception Report (Phase 1 of this project), it appears thatAngola does not foresee any north-south interconnections with Namibia and/orZaire, such as a Luanda-Inga link. Neither is an east-west interconnectionwith Zambia envisaged. The distances are considered too great forconventional HVAC transmission. While HVDC may overcome some technicaldifficulties the economics may still remain prohibitive. Nevertheless, Angola isendowed with the largest potential hydro resources of any SADC country andopportunities for hydro development and energy trading should be excellent ifthe problem of long transmission distances can be resolved economically.

For the present, however, it must be accepted that Angola is too remote fromthe established bulk transmission grid to gain any immediate benefit fromcooperation in power development with the SADC core-countries.Interconnecting the internal networks of Angola is thus considered the firstpriority and should be phased to complement hydro projects such as atCapanda, which is also large enough and conveniently located to facilitateenergy trade with Namibia.

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In the long-term, bulk power transfer over large distances will be economicprovided the internal system is sufficiently strong, and innovative solutions, suchas FACTS and multi-terminal DC technology, are used to overcome thepresent technical and economic constraints. These techniques should beconsidered in any event, regardless of opportunities for bilateral or regionalelectricity trade, because Angola is such a very large country with aNorth-South length of about 1600km.

Namibia

Following up the recommendations of the UN/UNDP exercise with particularrespect to the proposed Epupa project, it may become feasible for the southemgrid of Angola to be interconnected with Namibia, either at Ruacana or Epupa.This could be a condition of the rparian agreement, and, if also associatedwith the repair of the breached dam (in Angola), it would provide substantialbenefits for both countries within the spirit of the UN/UNDP study.

Regulation of the Cunene above Ruacana would remove the present operatingconstraints at Ruacana due to variable flows. Furthermore, it is understood thatEpupa is to have a storage capacity of about 5 km3 and thus it may bepracticable to operate Ruacana and Epupa conjunctively and so enhance theavailable energy. In this respect, it should be remembered that the potentialof the Cunene river system is estimated at 803OGWH.

There is already transmission at 330kV and 220kV spanning the length ofNamibia and interconnecting with the ESKOM (RSA) network, as shown byExhibit 1.19. Reinforcing this transmission as proposed with a 40OkV line fromEpupa will provide Namibia with an export opportunity and reverse the presentdependence on RSA. However, at a basic line cost of about US$0.25m/km, theproposed line would cost about US$350 million or about one-half of the capitalcost of Epupa (assuming 300MW at US$2000/kW). It may thus be prudent toconsider methods of extending the present transmission capability by the useof FACTS techniques, which are now becoming available.

Lesotho

As Lesotho is a landlocked country bordering solely with RSA it cannot directlyreceive or contribute power to the SADC Grid. However, it is not necessary tohave a direct connection to the SADC Grid to participate in a power exchange.By offset contracts between a SADC Pool and ESKOM, it may be possible forLesotho to receive most of the benefits available to a contiguous network, andthis must be one of the investigations of the next, "instfiutional", phase of thisStudy.

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A prerequisite for such arrangements is interconnection of the SADC Grid withthe ESKOM network and energy trading agreements in which Lesotho is treatedas a SADC Pool member. For example, Lesotho could effectively wheel powerthrough the ESKOM network to the SADC Grid or altematively, provide ESKOMwith power together with other SADC partners. These contractualarrangements must be based on appropriate institutional and pricing policies tobe addressed in to the Phase 3 studies, the TOR being set out in Appendix Tof the Main Report.

Swaziland

Swaziland imports now more than half its power from RSA. No reservecapacity is carried in Swaziland. The generating capacity is 51MW. Some75km of transmission lines at 132kV interconnect with the RSA grid. Thesystem peak demand was 92MW in 1990 and the energy consumption498GWH. The demand is expected to reach 207MW by 2010, with an energyconsumption of 1062GWH.

The study of interconnection scenarios led to the conclusion that the bestsolution would be for Swaziland and Southem Mozambique to form a sub-region. This could be supplied from Cahora Bassa by recalling 200MW of thepower transmitted to RSA via a Swaziland tie. In the meantime, an offsetarrangement such as proposed for Lesotho may offer advantages forSwaziland.

The strategy that is most likely to provide scope for long-term regional benefitsis to develop Swaziland and Southern Mozambique as a sub-region, asbasically proposed in SADC Project 3.5.2, with 200MW of Cahora Bassa powerrecalled from RSA via a Swaziland tie. In the meantime, offset arrangementssuch as proposed for Lesotho are considered the most practical means to gainbenefits that may accrue from regional cooperation. The same basicarguments apply with respect to institutional and pricing matters, and should beaddressed in the "institutional" phase of this Project.

The above strategy depends upon acceptance of the SADC Project 3.5.2proposal. As the proposal involves a bilateral agreement between the twoSADC parties - Mozambique and Swaziland, much may depend o n whetheran advantage is gained by Mozambique, who owns the resource. Thealternative to the SADC proposal for Swaziland is to follow an "offset"contractual arrangement as proposed for Lesotho under the auspices of aSADC Pool. This track may be particularly attractive if the Komati River studiesresult in a scheme similar to the Lesotho Highland Project being developed, orif it becomes feasible to develop coal resources for power generation.

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For the longer term, water supply development on the Komati River inSwaziland may yield some power also. There are plans for two dams on theriver, one at Driekoppies in RSA and another at Maguga, just inside theSwaziland border. Output figures for possible power plants built in associationwith water supply schemes have not yet been determined.

1.12 Intermediate and Drought Scenarios

An "intermediate" variation of regional Plan A together with a "drought" scenariohave been undertaken as extension to the original TOR as arranged at theMarch '92 PSC Meeting in Lusaka. At the Lusaka Meeting, it was agreed thatIt would be prudent to plan for a continuation of the current drought insouthem Africa rather than accept past flow records as indicative of futurecatchment behaviour. It was also accepted that Malawi had too high adependence on extemal supplies, and thus Kapichira should be committed inthe integrated Plan to reduce this dependence. This section describes thesenew scenarios.

The general criteria and assumptions on reserve margin and reliability LOLPcriteria remain the same as in the earlier analyses. Thus, the present nationalforecasts are a given (as used in the integrated study) and, similarly, thereliability (LOLP) index is taken as one day in one year (24hrs).

Intermediate Scenario

In the intermediate scenario, a departure from the benefits of unconstrainedintegrated development is studied with the assumption that Malawi will build theKapichira hydro-electric project to increase power supply reliability and self-sufficiency. The proposal is thus to follow the integrated scenario (Plan A), butto introduce Kapichira as a "committed" project to be commissioned in twostages, 50MW in 1997 and 75MW 2000. The inclusion of this project in theintegrated development Plan A reduces the import requirements for Malawi to34% of the the 2010 demand.

The commissioning of Kapichira will delay the 220kV transmission line intertieprojects with Zambia and Mozambique. This is also reflected in the importsfrom Zambia and Mozambique given in columns D & E of Exhibit 1.20, toprovide power balance for the Malawi loads (col.B).

It should be noted from Exhibit 1.20 that there is no import from Mozambiqueuntil 2008 when the 22OkV line from Songo (Mozambique) to Ulongwe (Malawi)is put into commission. Similarly, the import from Zambia is limited to 40MWuntil the assumed 132kV tie from Ulongwe to Pensulo is upgraded to 220kV in2004. The import values increase to 100MW from Zambia in 2004, and againto 150MW in 2007. Once the Mozambique intertie is available in 2008, powerbalance is achieved by importing 1 00MW from this source without changing theZambia import level, as shown by column D.

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The capacity interchanges between Zambia, Zimbabwe, Mozambique, andBotswana are not expected to be affected by the addition of Kapichira andPlan A is unchanged except for the transmission iine delays noted above. Inthis respect, it should be understood that Kapichira is a committed project forMalawi, and therefore NOT one of the "regional" projects, such as Batoka,selected for integrated development.

Drought Scenario

The drought scenario represents a-reduction in the reservoir inflows, curtailingthe availability of energy particularly from the hydro-electric power stations inZambia and Zimbabwe. The power stations affected by the drought scenarioinclude Kariba (North & South), Kafue, Batoka and Victoria Falls.

The "drought scenario" is thus conceived as a contingency plan for regionalgeneration and transmission expansion in which hydropower is treated as ascarce and uncertain resource. The objective is to accommodate the possibilityof the present drought continuing indefinitely. On this premise, promotion ofconjunctive operation of hydro-plants and the use of thermal plants to enableenergy banking and water conservation are strategies to be investigated,including power imports from RSA.

For the "drought" scenario, the methodology for deriving the firm and averageenergy production of hydroelectric schemes operating in combination isunchanged from that described for "normal" operations. Firm energy is asdeclared in Sect.1.5, namely a monthly reliability of 99 per cent over the 60-year hydrological period.

Modelling for the "drought" scenario has been described in Sect.1.5 (p.1-10).A 60-year series has been developed from the records of the last 10 years ofdrought. Starting conditions were derived by iteration as those that can besustained on average over the whole drought sequence. On this basis, thereservoirs were taken to be 80% full as for the 'normal" scenario.

The basic impact of drought thus leads to reduced inflows and hence reducedavailability of "firm" and "average" hydro energy. There is virtually no benefitfrom conjunctive operation between Karba and Kafue, which are on differentrivers, so that the combined plant performance shows a 13% reduction in "firm"and an 18% reduction in average energy, as tabulated in Sect.1.5 (p.1-10).

Assuming conjunctive operation with Batoka (at 400MW), the effects of droughtcan be slightly mitigated. This results in "firm" and "average" energy reductionsof 11% compared with 13 and 15% compared with 18%. As noted in closingthe drought discussion in Sect.1.5, the reduced hydro energy can be generallycovered by 300MW of thermal capacity operating at a 70% load factor toproduce 1 84OGWH/a.

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The integrated development of the five SADC core countries for the droughtscenario depends on meeting the energy deficiency caused by drought throughalternative means. These include the development of an additional project suchas Hwange 3 (Units 7 & 8) for 44OMW, or facilities for the purchase of similarthermal capacity from RSA (ESKOM) through a new 40OkV transmission linebetween Matimba and Bulawayo via Selebi Phikwe.

The transmission line option, and thus import from RSA, is preferred for studyin this case as the energy is immediately available. The cost will be less thanthat of adding units at Hwange and the construction time for the transmissionline shorter. The line will also complete a strong loop between Cahora Bassain Mozambique, RSA and Zimbabwe which is expected to provide additionalLOLP reliability and transmission security. This was originally proposed wheninitiating this Study.

This strategy represents quite a radical change in the Plan A development,particularly the acceptance of thermal power imports from RSA. Power importfrom this source is crucial to the overall strategy for two reasons. First, sincethe power is immediately available, advantage can be taken of energy bankingopportunities to return the hydro reservoirs to their normal levels. Secondly, tocope with drought the thermal component must be reliably increased in thehydrolthermal mix; this is only possible from RSA.

The basic arrangements for the drought variant of the regionally integratedPlan A are presented in Exhibit 1.21 on a country-by-country basis. The peakdemand and generation capacity balances for the region are shown inExhibit 1.22, and should be compared with Plan A balances in Exhibit 1.9.

In summary, the energy generated from the hydroplants in Zambia andZimbabwe will be curtailed by lower flow regimes. As a result, capacity andenergy interchanges between Zambia and Malawi and between Zambia andZimababwe are reduced. Malawi will proceed with Kapichira and thetransmission intertie upgrade with Zambia will be delayed.

It is expected that imports from Zaire will ng be used for wheeling toZimbabwe, as in Plan A. Instead, they will be needed to support energyproduction and reliability of supplies in Zambia during the later years of theplanning period. Thus, in order to meet the demand and reliability inZimbabwe, Batoka II will need to be advanced one year to 2006, with importsfrom ESKOM over the Matimba-Bulawayo line making up the deficits in energyand for underwriting the LOLP criteria. In these circumstances, Zimbabwe willnot be able to export power to Botswana.

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In the absence of imports from Zimbabwe, the Botswana demand is assumedto be met by increasing imports from ESKOM to 275MW as compared to theprevious level of 175MW in Plan A. However, the increased imports toBotswana can be tapped from the Matimba-Bulawayo transmission line atSelebi-Phikwe. It is considered necessary that this transmission line be adouble circuit line to provide adequate reliability to both Botswana andZimbabwe.

As part of the development of the "drought" scenario, a review was made of theload forecasts, and tested against the findings of the subsequent ESMOD andIBRD Missions. It was concluded that the forecast for Zimbabwe would begreatly affected during 1993-1994. However, thereafter it is expected that theintroduction of the Matimba-Bulawayo and Cahora Bassa interconnectorswould provide sufficient energy supplies for a reversal of the short-run impactin both Zambia and Zimbabwe. With the pent-up demand from two years ofcurtailment, and the expected improvement of economic activity, it wasconsidered that the original forecast for 1995 would be achieved in bothcountries.

1.13 Economic Analysis

The objective of this entire project, as set out in the TOR, was to demonstratewhether regional cooperation in the development of the electrical power sectoris beneficial to the members of SADC, or whether a continuation of independentdevelopment is the least-cost stragegy. In undertaking the economic analysis,it was intended that the "economic" capital costs should represent theanticipated impact of the project(s) on the various economies of the region.The TOR also required that this analysis be presented in a common currency,so as to evaluate the regional costs and benefits of the various projects on auniform basis. This has resulted in a misunderstanding of the economic capitalcosts given in the Main Report, which is clarified by presenting in this ReportSummary the proper economic comparisons of the alternative Plans.

The methodology employed to rationalise costs to a common base or currencyrelies on the theory that the economic costs of major power projects, in thecurrency of the country developing the project(s), are greater than the financialcosts due to the shadow exchange rates and the shadow prices associated withthe project(s). On this premise the economic costs presented in the analysisand expressed US dollars should be multiplied by the "official exchange rate"at the time the expenditure is incurred when in current dollars, or the "officialexchange rate" in 1992 when presented in constant 1992 US dollars.

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Use of this methodology introduces the complexities of dealing with differentinflation rates, different currency values and different shadow prices. At therequest of the World Bank (IBRD), the results previously presented in the MainReport were analysed in a slightly different manner. This was to ensure thatany subsequent decisions reached are based on methods of economicevaluation that can be underwritten by IBRD. Therefore, Independent Plansand Regional Plans A to D, together with the "intermediate" and "drought"scenarios, were recast.

In this analysis, the major change is the use of the financial costs of foreignmaterials and labour for the economic cost. For local capital costs, thematerials component was considered to be the economic costs to the country,converted to US dollars at the official exchange rate. No adjustment wasdeemed necessary in converting the local costs of materials to economic costs.

For the labour component, a +5% adjustment was made to reflect what isbelieved to be the actual economic costs of labour in each country. This isbased on previous analyses in the Region, where labour costs were found tobe greater in economic than financial terms. In fact, labour is such a smallcomponent of the total costs that at any level, it would not influence the finalresults.

In order to avoid confusion in interpreting the results obtained by the differentmethods of economic analysis, the comparisons presented in Exhibit 1.23 arebased on this methodology, although they may be an under-estimate of actualcosts. The results therefore give the lowest limit of the cost envelope and thusthe most conservative evaluation of benefits. In comparing these results withthose developed previously, it was found that the rankings were identicalalthough the actual values were different, whether in current or constant USdollars. The ranking of the regional plans was Plan D, A, C, and B, with D andA of the same order of magnitude. The cost of independent development ismuch higher than any regional scheme. Reference should be made to the MainReport for the detailed computation and analysis of costs for the three differentmethods of economic evaluation. The three methodologies are summarised inExhibit 1.24, and it should be noted that the relative rankings of the scenariosremain the same, regardless of the methodology.

Plans A and D are compared in Exhibit 1.23, which also summarises theaggregated cost for "independent" development and for the "droughr and"intermediate" scenarios. As expected, Plan D remains the least-cost option.Comparing total system costs (in constant dollars) the cost of independentdevelopment comes to some US$5300m, whereas the least-cost regionalscheme (Plan D) costs US$4364m, showing a saving of US$936m.

1-40


The difference between Plans A and D is US$150m, which is quite marginal.Both plans consider import from Zaire and from Cahora Bassa, but generationcapacity additions are wholly hydro (Batoka) in Plan A. The same capacityaddition is required in Plan D, but is assigned equally to thermal and hydro.Thus Plan D is theoretically a better balanced scheme as well as being of leastcost. However, the situation remains that the capital and operating costsassociated with the Lower Kafue Gorge have a lower confidence level at thecurrent time than those associated with Batoka. It is therefore suggested thata study of Lower Kafue to at least pre-feasibility level is undertaken.Nevertheless, Plan D is still expected to be a reasonable alternative to Plan A,if the results of the present feasibility study for Batoka should suggest that thisplant is postponed or cancelled.

The difference between Plan A and the "intermediate" scenario is the additionof Kapichira, and this is reflected mostly in an extra capital cost of US$1 72.0m,compared with the total system cost differential of US$176.8m (both in constantdollars). As expected and discussed in the March presentation to the PSG inLusaka, the addition of Kapichira as a committed project, increases the totalcosts when evaluated for a regional concept. Under the criteria set by thedesire to minimise the risk of power imports for a single country, and thecontinuing impact of the drought, the added cost is considered to be negligibleover the study horizon to 2010.

It should be noted that the operating cost totals for both the thermal and hydrounits are lower under the drought scenario than under the intermediateScenario. This is due to the decision to import power from ESKOM. With theMatimba-Bulawayo line providing significant imports to the region, the cost ofthat power has been included in the analysis by assuming the same cost fordemand and energy as that currently agreed to by Mozambique for the sale ofCahora Bassa power. Purchase power costs increase to almost US$300million as a direct result of ESKOM purchases via Matimba to the study horizonof 2010.

With the indefinite continuation of one of the worst droughts in the SADCregion's history, hydro production has declined significantly, giving addedimpetus to the need for interconnections. The total estimated cost forintegrated development of the five-core countries with Plan A-DR (the droughtplan) in constant U.S. Dollars is US$5041 million, and indicates an increase inpower costs of approximately US$530 million over Plan A for the study periodfrom 1995 to 2010.

Thus, in concluding this discussion, it should be clearly understood that theabove cost increase is the least-cost differential, and contingent on the rapidinstallation of the Matimba-Bulawayo and Songo-Bindura transmission lines.Without these lines, Zimbabwe would suffer greatly as a result of a significantincrease in unserved energy. Ukewise, Zambia would be unable to rely onZimbabwe for support and power for water management at Kariba; the fabricof cooperation would disintegrate and lead to unpredictably high costs.

1-41

Exhibit 1.1

CENTRAL AFRICAN REPUBL 1 SUDAN ,,<ETHI10

CAMEROON 7-,

-'UGANDA K)~ ~ ~ ~ ~~~~~K { . LAO KENYA

'' CONGO * --GABON ) /

a' ~~ZAIRE cf--#~~ , -i .<URAZ2AVILL* --

-" U

: kt t_ s ¢ 4_ T-

\- \ &,TANZAN.y,v SI

\~~ NILUWQ ILum N. 5

town ANGOLA l*A' I- - 1j46 m.~~

maNLAK~-vv -ol<t l ctt 7v5T'--___ E

-- .J BOTSWANA r -t At; i ~~~~<ty ' / j ~~INDIAN

/ S ,/ \ l * ' .i_n,O C E A NATLANTIC | : ;,T" VOCEAN \ \ , L / SWAZILANO

' ASn J /AY

i 0 ~REPUBLIC Of

/W:.. S~ ~ ~~~~~ti TAT

;; ~ ~ LSOH ( /OT FIA /a"

~~~~~~~~~~~~~~~~~~~~~~h.-'REPUBLIC OF si~~~~~~~~~~am.7i_II5..~ .. Sm_1

_3

f~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

Exhibit 1.2

ZAIRE

ZAMBIA

, 2 L~~~~~US' ( 1'A

* \^ \/ZIMBABWE

BOTSWANA 'a'."

0 - / ft 0- eoomv a euv Dc-ISO S1 400k1V

| ~~G"ORONE> \an02wunAna,a, J REPUBLIC OF "ll LU

5 osv ^, SOUTH AFRICA o

Exhibit 1.3

FIVE-CORE COUNTRY DEMANDS1992-2010

__ .iTWAisiA -MALAWi MOdZMBiOUE ZAMiKA ZIMBABWE REGIONALCALENDAR DEMAND DEMAND DEMAND DEMAND DEMAND DEMAND

YEAR (MW) (MM (MW (MM (MM (MW)

1992 177 143 156 966 1,680 3,1241993 186 153 167 978 1,756 3.2401994 195 185 177 988 1,835 3,3601995 204 177 194 1,000 1,918 3.4921996 213 190 210 1,013 1.971 3,5971997 223 204 224 1,027 2,026 3,7041998 235 219 240 1,027 2,083 3,6031999 248 235 255 1,028 2,142 3,9052000 255 252 274 1,031 2,201 4,0132001 268 271 293 1,0I0 2,263 4,1542002 281 291 309 1,090 2,328 4,2982003 295 313 323 1,122 2,392 4,4452004 310 337 338 1,156 2,459 4,5992005 325 362 353 1,191 2.527 4,7592006 342 389 371 1,228 2,596 4,9282007 359 418 388 1,287 2,671 5,1032008 377 450 406 1,308 2,746 5.282009 396 484 425 1,351 2,823 5,4782010 415 520 44e 1,396 2,90 5,679

REGIONAL LOAD FORECAST1992-2010 DEMANDS (MW)

LUl o #~~~~~~~~~~~~o 3m 3 m 2 0

YBARSE BO'IWANA M) MALAWI 1I MOZAMBIOUEC ZAMBIA ZIMBABWE

Exhibit 1.4

FIVE-CORE COUNTRY ENERGY REQUIREMENTS1992-2010

BIWANA MALAWi MOZAM8CiUE ZAMBIA AMBA REGIONALCALENDAR ENERGY ENERGY ENERGY ENERGY ENERGY ENERGY

YEAR (GWH) (GWH) (GWH) (GWH) (GWH) (GWH)

1992 1,122 789 827 6.s90 10,751 20.3791993 1,175 847 882 6.903 11,234 21,0411994 1,232 908 940 6,906 11,740 21,7271995 1,291 974 1,020 6.915 12.172 22.3711996 1,351 1,044 1,105 6,930 12.512 22.9421997 1,414 1,120 1,180 6,951 12,863 23,5281996 1,486 1,201 1,259 6.893 13222 24.0511999 1.557 1.288 1.342 6,821 13.593 24.6012000 1,832 1,382 1,439 6,765 13.973 25.1912001 1,697 1,486 1,543 6,912 14,365 26,0032002 1,777 1,597 1,627 7,053 14,767 28,8212003 1,868 1,718 1,701 7,196 15,160 27,6632004 1,960 1,847 1.781 7,350 15,605 28,5422005 2,058 1,986 1,865 7,506 16,042 29,4582006 2.160 2.135 1,953 7,672 16,491 30,4112007 2,268 2,296 2,049 7,842 16,953 31,4082006 2.382 2.468 2,146 8,057 17,428 32.4812009 2.501 2,e54 2252 8,282 17,915 33,6042010 2,626 2,853 2,362 8,519 18,417 34,777

REGIONAL LOAD FORECAST1992-2010 ENERGY (OWN)

40

20 - - ;- -

;] i33EAbE~~~~~~EAS0rL

I0317SWANA EJ3 MALAWI CM MOZAMBIQUEZAMBIA = MBABWE

Exhibit 1.5

1992 Zimbabwe / Zambia systemTotal storage

With firm operation80

Maximum storage70 . .. . . ...

60 -E a 50 0

40-

2 30-Co

20

1930 1935 1940 1945 1950 1955 1960 1965 1970 1975 1980 1905 1990Hydrological year

Exhibit 1.6

Firm and average enrgy hrauses fromexisting and potentiaJ hydro scemes

Energy output (TWia)10

Fm. Av. Fm. Av. Fm. Av. Fm. Av. Fm. Av.

Indepndent firm operation withU Krwiba upgaded to 1350 MW

*_As ahow but with conjunctive firmoperation of Kariba & Kafue

E As above but with 300 MW Karibaextension

As above but conjunctive operationwith Batoka 1600

.~ As above but with a Sth unit1~ 1 at Cahora Bana

Exhibit 1. 7

GENERATION PLANNING

Methodology followed:

1. Comparison of generation - capacity and energyproduction - with predicted demands.

2 Modelling of daily generation and demand rising the'Evolve- P' programme of Gilbert/Commonwealth (theProbabilistic Production Costing Programme).

a Selection of Generation and Transmission projects whichcan meet predetermined LOLP criteria and fitting these intothe generation/demand model.

4. Identification of a basic plan for regional development of aninterconnected power system.

S Identification of a basic plan for continued independe,risystem development by the five core countries.

6 Investigation of alternatives to the basic plan consideredunder (4).

7. Determination of production costs for the plans adopted forstudy.

Exhibit 1.8

OPERATING COST SUMMARY1992 BASIS - US$

OPERATING PER UNIT COSTS PURCHASES

COUNTRY PLANT FUEL COST START-UP VARIABLE FIXED DEMAND ENERGY FIXED

$IMWH $START $MWH SMW $KWIYEAR $KWH S/YEAR

BOTSWANA SELEBIPHIKWE $11.61 $683.55 $2.07 $22.33 _ _

MORUPULE $6.23 $683.55 $1.06 $48.30 - -

PURCHASES-RSA _- - - $99.49 S0.0094 $270,113*

-ZESA _ - - $0.0092 _

-ZAMBIA _- - - $29.45 $0.0099 _

MALAWI ALL HYDRO'S _- $0.44 $10.50 - -

PURCHASES-MOZAMBIQUE - - - - $66.74 $0.0012 _

-ZAMBIA _- - - $29.45 $0.0099 _

MOZAMBIQUE CAHORA BASSA _- $0.76 $6.64 - -

ZAMBIA VICTORIA FALLS _ - $1.27 $7.17 -

KARIBA NORTH _ - $0.95 $8.06 - _

KAFUE _- $1.17 $9.85 - -

PURCHASES-ZAIRE _- - - $66.74 $0.0012 _

ZIMBABWE HWANGE 1-6 $2.39 $6,835.50 $0.27 $30.87 - -

HARARE $14.51 $683.55 $1.06 $25.94 - -

MUNYATI $13.54 $683.55 $3.00 $29.23 - -

BULAWAYO $12.13 $683.55 $2.62 $25.94 - -

KARIBA SOUTH _- $1.06 $8.95 - -

BATOKA $ 0.85 $7.38 - -

HWANGE III $2.39 $6,835.50 $0.27 $30.87 - -

PURCHASES-MOZAMBIQUE _ - - - $66.74 $0.0012 _

-ZAMBIA _ _ _ $72.16 S0.0020 _

NOTES: * INDICATES A FIXED CHARGE FROM RSA TO BOTSWANA1992 costs have been developed from 1990 costs at an escalated rate of 10.25%Fuel Costs based on an assumed heat rate of 10,000Btu's/Kwh

Exhibit 1.9

PLAN A: SADCC CORE COUNTRIESCAPACITY AND PEAK LOAD COMPARISON

7

2j , 39& . us, , fi 3 " , 4

3

1990 1991 199219931994 l99S 1996 199 1998 1999 2000 2001 2002 2003 20042005 20062007 20082009 2010YEARS

.. i_ PEAK DEMAND + GENERATION CAPACITY

_* WITH RSA EXPORTS -- WITH IMPORT ZAIRE

Exhibit 1.10

PMan A 8 C 0 Indapindt

Inmpot from Zak. sn 1992 star 1992 sun 1992 stan 1992 stn 1993upgrade 2002 upgrade 1997 upgrad 97 upgras 2002 no uP9a

Maimum MW 450MW In 2010 650MW in 2001 650MW in 2001 600MW m 2010 150MW in2010

Transter fromZambta to Zimbabwe 150MW inMammum MW 2002 :50MW 2002: 95OMW 2001 : 750MW 2004 950MW 1991

Imot from Cahora stan 2000 Nil Nil stan 2000 NilBa to Zimbabe* Maximum MW 40OMW In 1997 400MW in 1997

Res mwargin vs.D demand for

Zlmbabwe & Zanbiawoma nd in:

2000:% 23 23 23 23 242010:% 13 13 i 18 18

t from Cahorn sta 1997Baan to Malawv NilI Ma,amum MW SOMW in 2006

hnport trom Za5ba start 19t start 199to Malaw 4OMW in* MaxImum MW t50MW In 2006 1998

Now power staionu 1991: Kariba upgraa (90MWI: 1992: Nkula (5) (20MW)1992: Munyai t fine (30MW): 1994:' Teoeri 3 (SOMVW)

2002I1JK(ahf 1999(450MWA lwaeI

2004Bafta 1 2004.Satoks i 2004:.atoka I 2004:UKaho (210MW)(400MW) (40OMW) (40MW) (400MW 2001:

2007:8a1kca 2 2007:Batoa 2 2007.1atola 2 2007*11wanqe Hwae Nl(40OMWW) (40OMW) (40iMW) III (420MW) (21004 )

2004:Bataks (400MW)

2007:_ _ _ _ ~~~~~~~(400MW

Exhibit 1.114 -

.I PIE NUFOfi & StZE OF stow I CKaGMOoVnli TACF AMS CCbDUCT0ItS LOAOIII NVA P01

mmtC Psn IASF lV .

kV . VA 20s

132 1 *250 S9.5220 1 x 250 116 24.6

3.5 220 2 a 250 158 33.5330 2 x350 347 73.4330 3 .350 392 82.74*0 3 a 350 576 121.5400 4 x40 631 t32.9

see Appedla E rev eoe detatl.

2.5 -

1 a__\_l

_ j

o 20 a 0 a0 0 o 0

0

2

1.5

1 .

0.5

0 -

0 200 400 Soo 800 1000 1200

LINE LENGTH IN KU (NO SERIES COMPENSATION)

The above curve is based on Fig 2.4.2 of the Transmission Line reference Book - 345kV andabove, published by the Electrical Power Research Institte, Palo Alto, CA. The curveoriginates in a report prepared by a committee of utility engineers for the Federal PowerCommission (FPC) and is representatve of practice with respect to per unit surge-imedanceloading of uncompensated lines as a function of line length. Surge-impedance load (SIL) isthe load that a line would carry if the reactive power loss in the distributed line inductance isexactly equal to and neutralised by the distributed line dcging reactive power.

St. Clair Curve

Exhibit 1.12

1995 POWER BALANCESAND INTERCHANGES

(CASE: INETr6-2)

ZAIRE KAPICHIRA

OPEN OPEN

ZAMBIA MALAWILOAD 1033MW LOAD 183MWLOSSES 26MW LOSSES lgMW

32MW .1058MW M lB2MW

GEN 1303MW GEN 214MW

BAL(./-) *308MW 8AL(+/-) *32MW

t3377MW/ OPEN

BATOKA ZIMBABWE M-QZAMRIQUELOAD 1828MW LOAD 70MW

OPEN LOSSES 7eMW LOSSES 3MWj%\ OPEN 399MW

1904MW 79MWz GEN 1198MW GEN 2078MW

BAL(+/-) -700MW BAL(-/-) .1999MW

30 10o0

BOTSWANALOAD 200MW

LOSSES 3MW < w R S.203MW RSA

GEN 168MW

BAL(*/-) -"6MW

Exhibit 1. 13

2010 POWER BALANCESAND INTERCHANGES

(CASE. INETlO-7)

ZAIRF KAPIrCIRA

800 126

ZAMBIA MALAWILOAD 1377MW LOAD 478MWLOSSES 23MW LOSSES 34MW

_ ~4 7MW>1400MW W 612MW

GEN 1473MW GEN 214MW

BAL(-/-) *73MW BAL(*/-) -298MW

BATOKA ZIMBABWE MOZ7AMBI QUFLOAD 2772MW LOAD 167MWLOSSES 127MW W M LOSSES eMW

MW yb 2899MW 183MWGEN 1461MW GEN 2011MW

BAL(./-) -1448MW BAL(-/-) *1848MW

MAW

BOTSWAN ALOAD 399MWLOSSES llMW RISIAD

410MW ,C,GEN 168MW

SAL(./-) -262MW

Exhibit 1.14......................................................................... ................................................................................................................................... ............. .........................

TITLE: ADeCC USE CASE FAULT StfO1 FOR 995. FILE: ZS5WCOS TITLE: SA*CC BASE CASE FAULT SltOY FOR 2010. FILE :2ISAOCII

us IDENt. IUIT.YOLTAGE (kv) ANGAE(dgree) OUS IDENT. INIT.VOLTAGE tkv) ANGLE(degree)

TYPE .. . CURRENT. ............. .. VOLTAGE P-. .... TYPE *--...... CURRENT .. . ...- .VOLTAGE P-G .--

NODULE ANGLE NODULE POW. BREA OOtULE ANGLE NODULE MODULE ANGLE NODULE POW. UREA NODULE ANGLE NODULE

(p.u.) (degree) (MP) (uVa) (p.u.) (degree) (kv) (p.u.) (degree) (p) (ova) (p.u.) (degree) (kv).......................................................................... ....................................................................................................................... .....................................

FAULT AT FAULT AT

62.3CRIA 1 341.6 *12.9 620R11A 5 1 341.6 8.7

LLLA 80.16 -95." 14024 8296 0o 0.00 0.00 0.00 LLLA o33.8 *n.33 14666 8676 02 0.00 0.00 0.00

Z00.1 * 0.0016.1 0.0128 (p.u.) XIN * 8.212 2001- a 0.0019.1 0.0122 (p.u.) X/i * 6.345

FIRST RING CONTRIBUTIONS FIRST RING CONTRIBUTIONS

*> 600ALASKA I 1 340.S *22.5 a 600ASKA 1 1 332.6 -1.2

LLL-A 6.09 *116.15 1065 628 0.32 -33.97 60.55 LLL-A 6.17 .88.67 1079 622 0.32 -6.48 61.33

ZQP-1 a 0.0018#J 0.0088 (p.u.) ZaP-1 a 0.0023+1 0.0079 (p.u.)600ALASKA 1 2 340.5 -22.5 J, 600ASKA 1 2 332.6 -1.2

LLL-A 6.09 *116.15 1065 628 0.32 -33.97 60.55 LtL-A 6.17 -88.67 1079 622 0.32 *6.48 61.33

ZOP-1 * 0.0018.j 0.0088 (p.u.) Z2P-t a 0.0023+J 0.0079 (p.u.)

.> 600ALASKA 1 3 340.5 -22.5 600ASKA 1 3 332.6 -1.2

LLL-A 6.07 *116.18 1061 626 0.32 *33.97 60.55 LLL-A 6.15 -88.70 1075 619 0.32 -6.48 61.33

20P-1 a 0.0018J 0.0088 (p.u.) 2OP-1 a 0.0023*j 0.0079 (p.u.)

*> 900KRIUA- I I 341.6 *12.9 .> 90013A Ni 1 341.6 8.8

LLL-A 19.44 -92.25 3402 2013 0.01 -9.85 1.12 LLL-A 20.40 -65.20 3569 2112 0.01 17.20 1.18

20P-1 0.0016+j 0.0127 (p.u.) ZaP-i a 0.0019+4 0.0121 (p.u.)

.) 900KI1A- 1 2 341.6 -12.9 *a 900RIUA N 1 2 341.6 8.8

LLL-A 19.44 -92.25 3402 2013 0.01 -9.85 1.12 LLL-A 20.40 *65.20 3569 2112 0.01 17.20 1.18

Z2P-1 * 0.0016*J 0.0127 (p.u.) zaP-1 a 0.0019.j 0.0121 (p.u.)

COUTRIUUWTIO FROM GENERATOR CONTRIBUTION FROM GENERATOR

LL-A 24.52 -87.16 4290 2538 LLLA- 25.61 *72.01 4480 2650

KARIBA SOUTH 1995 AND 2010FAULT ANALYSES (3-PHASE)

Exhibit 1.151.00 X.OE+01 DEG Fault on Matimba-Selebe line

0.00 A

-1.00

-2.00

-3.00

-4.00

-5.00

-6.00

-7.00

-8.00

-9.00

-10.00 I r0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00

X 1.OE-01 SECOND

1: BUS 220 ANGLE

2: BUS 240 ANGLE

3: BUS 250 ANGLE

SADCC TRANSIENT STABILITY STVDY NO.3

Exhibit 1.16

EXPORT FROM KOLWESIScenaro 1 - 1000MWScenado 2 - 1000MWScenado 3 - 1500MW _ Scenado 4- 1500MW KOLWESIScenado 5 - 1000MW MALAWIScenaro 6 - 1000MWScenario 7 - 1000MW

ZAMBIA6

ZIBASW dIMPORT VIA SONGO

Scenario 1 - OMW| OOTSWANA \ > ) ll / Scenario 2 - 200MW

I X 4 ~~~~~~~~~~~~~~Scenario3- 700MWIMPORT VIA MATIMBA Scenano 3 - 700MWScenano I -SO0OMW § / Scenaro 4 - 200MWScenano 2 - 250MW Scenaro 5 -200MWScenario 3 - 250MW K ~ / \ t (Scenado 6 - 200MWScenado 4 - 750MW MAtM S ,1Scenario 5 -650MW 7 - 6Scenaro 6 - 1000MWScenanio75-650MWScenario 7 - 650MW

WHEELING THROUGH PATHS AND EXPORT/IMPORT POWER FLOWS

Exhibit 1.17WHEELING THROUGH SCENARIOS

POWER EXPORTS AND IMPORTS (MW)

SCENARIO EXPORT FROM IMPORT TO RSANo. KOLWESI BATOXA MATIMBA SONGO TOTAL

1 1000 800 500 0 500

2 1000 800 250 200 450

3 1500 800 250 700 950

4 1500 800 750 200 950

5 1000 1200 650 200 850

6 1000 1600 1000 200 1200

7 1000 1600 650 600 1250

SYSTEM ANGLE DISPLACEMENTS (DEG)

SCENARIO KOLWESI- KOLWESI- MATIMBA- KARIBA- KARIBA-No. MATIMBA KABWE BULAWAYO MATIMBA SONGO

1 74.6 14.8 11.1 47.2 9.8

2 45.4 12.2 6.6 32.6 14.1

3 59.6 20.8 6.6 34.0 22.0

4 94.9 20.8 16.1 61.8 5.9

5 59.9 12.0 14.1 46.5 12.4

6 74.6 12.0 22.6 62.5 11.1

7 48.8 12.5 14.3 39.5 22.6

Exhibit 1. 18TANZANIA MW & ENERGY DEMAND

1990-2010

LOAD DEMAND AAR% ENERGY AAR% % LOADYEAR (MW) GROWTH (GWH) GROWTH FACTOR

SCENARIO A

1990 261 - 1639 - 71.81995 378 7.7 2148 5.6 64.92000 516 6.4 2869 6.0 63.52005 694 6.1 3820 5.9 62.82010 925 5.9 5052 5.7 62.3

SCENARIO B

1990 272 - 1587 - 66.51995 330 3.9 1872 3.4 64.82000 404 4.1 2252 3.8 63.72005 491 4.0 2715 3.8 63.12010 594 3.9 3261 3.7 62.6

SCENARIO C

1990 261 - 1639 - 71.81995 383 8.0 2180 5.9 64.92000 534 6.8 2968 6.4 63.52005 731 6.5 4021 6.3 62.82010 990 6.2 5400 6.1 62.3

TANZANIA MW & ENERGY DEMAND1990, 195, 2000, 2006, 2010

1000 00

6000~~~~800~ ~~~~~40

~~~~~~~~I'

400

LU 2 11111000 LSCENARIOS A. S. C

UPeak Load C3 Energ

Exhibit 1.19TRANSMISSION MAP OF NAMIBIA NETWORK

"I *C

\\~~*11~ A r-----

Exhibit 1.20

SADCC REGONAL POWER INTERCONNECTION STtDYPEAK DEMAND AND GENERATION CAPACITY IN WIAWATTS

PLANA INTERMEDIATE: MALAI

YEAR PEAK GENERATDN TRANSM2SION CAPACrTY NET

LOAD CAPArrY IMPORTS FROM EXRPORTS TO TRAM2U2ON CAPARffYAVAJLABLE ZAMBIA MoZ8o CA rOTT MARGIN REMARKS

A B C 0 E F G H.D0E+F-G I C+H-9 I

19_ _29 120 0 0 0 41

299 133 160 a 0 a 27293 143 I80 0 0 37 n4KULA 8 -2eW

129 153 I80 30 0 30 3719 163 30 30 0 30 9T EDZASI 3 - 50 W1795 179 230 40 0 40 *t295 190 230 J0 0 40 s097W 204 2nO 40 0 40 116 KAI AC4IRA SO MW

t9w 219 280 40 0 40 lot

195 235 280 40 i *s20I 'J2 15S JO O 143 KAPAOIIRA 75MW

202 7 155 40 0 40 24

20W 291 253 5 0 0 40 1042W 313 315 40 a 40 822(ft 337 335 200 0 too ttD ZAMBLA 2.tUPORADE205 361 333 too 0 to o205 mg 335 100 0 200 4,IN 41J 335 IS3 0 IS0 87no * 435035 I30 00 250 35$ MDZO TtL2ce U4 355 ISO 100 250 12120D 52e 3355 IO 2OD 230 i

4am

In

W onI loO go - -S N W S-

>~~~. _AUAFY CU £hCDI. 1M2

Exhibit 1.21DROUGHT VARIANT OF PLAN A

ZIMBABWE

* import from RSA via Matimba line, will start with 40OMW fromcommissioning to 1996 when the Songo-Bindura line is expected to bein service. From 1 January 1996 onwards there is a fixed commitmentof 150MW;

* Plan A export arrangements to Botswana for 100MW from 2004indefinitely discontinued;

* import from Zambia reduced to 200MW after 2004 as the energyshortage at Kariba and Kafue will not permit capacity export;

* Batoka 11 (400MW) advanced one year to 2006 from 2007 in Plan A.

ZAMBIA

* increase in export to Malawi of 100MW from 40MW delayed one year,to 2005;

* export to Zimbabwe reduced from 2004;* imports from Zaire maintained as Plan A to compensate for energy and

capacity shortages.

BOTSWANA

* import from Zimbabwe discontinued from 2005;* import from RSA increased to 275MW from 2005.

MALAWI

* Kapichira I (50MW) in 1997 to replace Mozambique intertie, andKapichira II (75MW) in 2000 are included to reduce importdependency;

* Zambia import increase to 100MW delayed until intertie upgraded;* import from Mozambique delayed until intertie commissioned in 2008.

MOZAMBIQUE

* 1200MW export to RSA from 1995 as Plan A;* Zimbabwe intertie assumed from 1995 and export as Plan A except

end years are held at 20OMW;* no exports to Malawi until interie in service from 2008, and then

100MW;* imports from RSA are maintained as Plan A.

Exhibit 1.22

SADCC REGIONAL POWER INTERCODNNECnION STWYPEAK DEMAND AND GENERATlON CAPACTY IN MEGAWATTS

PLAN A: SADCC CORE COUNTRES

i EAR PEAK GENERATION CAPACITY CAPACITY CAPACITY CAPACITY NETLOAD CAPACITY MARGIN IMPORTS IMPORTS EXPORTS CAPACITY

INSTALLED ZAIRE RSA RSA MARGIN

A a c D.C-B E F 0 H.D+E+F.G REMARKS

IO 222 6162 130 0 125 0 344S199 3025 6235 3226 0 125 0 1351192 3124 6271 3147 IS0 125 0 3422199S 3240 6252 3012 I50 125 O 3217

199 3340 6302 2142 IS0 12S 0 3211I99 349 62W4 276 IS0 22 -1200 194

199 3597 6264 2"7 IS0 22 - 129 1342

3"7 3704 6314 2610 IS0 zts -1200 1785998 3304 4314 2310 ISO 27S -1200 1733

19" 396 6314 2406 "0 273 - 1200 16332e 4013 639 2376 Iso 273 -1200 1603200, 41SS 63" =34 230 2s -1200 15592002 4297 63" 20"1 d0 75 - 120 342003 44s 6389 1943 4so 325 -1200 3s3326 4400 678 213 IS0 3s -13200 142003 4757 673 2031 300 425 -1200 15354200 4921 67 1361 100 425 -12te 13

2007 103l 71 203o 40 473 -12W 1741

~0U 5237 7139 3"9 400 475 -1200 137720M 479 71" 370 400 473 -120 135t2030 579 71n i30 450 43 -1200 124

a CAP~~~1IY AND CAP94 1 7LA &f mMPAW SR U A

4 vm^,e

1 \

_ emIUNCnAT ___ eU o7 cw*aY* ~1A I04f

Exhibit 1.23

COMPARISON BETWEEN INDEPENDENT DEVELOPMENT VS REGIONAL PLANSECONOMIC COSTS - CONSTANT 1992 DOLLAR ESTIMATES US $ (000'S)

IBRD METHODOLOGY

ITEM INDEP'DENT DEV PLAN 'A' PLAN 'D' DROUGHT INTERMEDIATE

CAPITAL COST $2,367,635 $1,620,469 $1,327,778 $1,907,226 $1,792,461

OPERATING COSTS:THERMAL COSTS $1,326,828 $992,698 $1,074,147 $986,740 $992,698HYDRO COSTS $1,093,513 $1,113,306 $1,107,801 $1,069,958 $1,123,511PURCHASES $462,466 $786,394 $853,090 $1,076,130 $780,944

TOTAL OPERATING COSTS $2,882,807 $2,892,398 $3,035,038 $3,132,828 $2,897,153

UNSERVED ENERGY COSTS $48,269 $892 $894 $904 $960

TOTAL SYSTEM COSTS $5,298,711 $4,513,759 $4,363,710 $5,040,957 $4,690,574

NET PRESENT VALUE @ 10% $2,438,593 $1,947,445 $1,780,063 $2,276,421 $2,075,646

SAVINGS -REGIONAL PLANS VSINDEPENDENT DEVCONSTANT US $ _ $784,952 $935,001 $257,753 $608,137NET PRESENT VALUE @ 10% _ $491,148 $658,529 $162,172 $362,947

Exhibit 1.24 - Economic Analysis Methods

CURRENT S METHODOLOGY CONSTANT & METHODOLOGY IBRD METHODOLOGY

Capital costs presented in most 1 Capital costs presented in 1 Forex capital costs in financialrecent estimate for forex and current $ analysis are converted terms presented In US$ andlocal expenditures in local to constant $ by NPV factor of assumed to be equal tocurrencies. 5% (US Inflation). economic costs for this analysis.

2 Cost streams escalated by 2 Constant $ financial costs 2 Local financial capital costs forinflation rates for both forex and adjusted by estimated country material were assumed to be,local to point of expenditure. 'shadow price' to arrive at equal to economic costs based

economic costs. on work done in Zimbabwe.

3 Costs then devalued by annualexchange rates for year of 3 Operating cosis deflated by NPV 3 Local expenditures for laborexpenditure to convert to US of 5%. associated with capital projects

dollars. adjusted by shadow price of4 Stream of costs discounted at 1.05.

4 Those financial costs are then 10%.adjusted by estimated 'shadow 4 Local capital costs thenprice' for the country. converled to US dollars at

official exchange rate.5 While the economic costs

exceed the financial costs, If 5 Operating costs were shadowadjusted by the official priced using factors shown inexchange rate, to convert to exhibit 8-16.local currency, this serves as aproxy amount. 6 Stream of costs discounted at

10%.6 Operating costs were developed

In local currendes, thenescalated to 1992, andconverted to US$ at currentexchange rate.

7 Production costing done in US$using US inflaion rates.

8 Stream of costs discounted at10%. ._ _ _ __

SECTION 2

DEVELOPMENT ISSUES AND OPTIONS

2.1 Introduction 2-12.2 Core-Country Situation 2-22.3 Independent versus Integrated Development 2-42.4 Integrated Development Plans 2-62.5 Secondary Projects 2-82.6 Effect of Continued Drought Conditions 2-102.7 Drought Strategies for System Operations 2-122.8 Intermediate Development Scenarios 2-142.9 Other Dependency Issues 2-162.10 Recommended Actions (following the Lusaka Meeting) 2-17

Exhibits 2.1 - 2.2


2. DEVELOPMENT ISSUES AND OPTIONS

2.1 Introduction

The SADC energy project is charged with assessing the scope for coordinatedcapacity expansion and utilization of regional generation and transmissionfacilities with particular respect to the core-Countries. These are countries withclose access to the existing Zambia-Zimbabwe 330kV transmission system andtherefore able to participate directly in coordinated development of regionalgeneration and transmission capacities. The core countries are Botswana,Malawi, Mozambique, Zambia and Zimbabwe. It is proposed to combine theirnetworks ultimately into a single system for integrated development. Tomeasure the benefits of integration, comparisons are made with theaggregated costs of independent development plans for each of the fivecountries.

Those SADC countries that cannot be interconnected are termed non-corecountries. The emphasis in their case is to examine how they may gainbenefits from regional cooperation. These countries are Angola, Namibia,Lesotho, Swaziland and Tanzania. Swaziland and Lesotho are both land lockedbordering RSA and therefore cannot have any direct access to a SADC Grid,whereas Angola and Namibia are too remote for any direct connection to theexisting grid. In the case of Tanzania, it may be practicable to interconnect tothe existing grid at Pensulo (in Zambia), but even in this case transmissiondistances may be too great for conventional linkage with the core-countrynetworks. Analysis of the non-core countries is therefore supplementary to themain brief.

Given this perspective of the study requirements, every effort was made toidentify strategies that strengthen and compiement individual country plans. Inthe case of the core-country networks, the intent is to equitably distribute thebenefits of interconnection and integrated development of generation andtransmission capacities that can lead to a single power system or 'tight" poolarrangement. Formal expansion planning methods can then be applied inidentifying the development issues and options discussed in this Section,originally written for the DTR.

In the case of the non-core countries, the approach is to provide country andpower sector profiles in sufficient depth to clarify how development might takeplace within a regional framework. This must involve long-distancetransmission, and so the issues and options for this technology are alsoexamined. These matters have been carefully reviewed in discussingInterconnection Options (in Section 1.10), whereas this Section is solelyconcemed with the core-country studies.

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SECT. 2 AAA3.8 PHARF 2

2.2 Core-Country Situation

Within the core-country framework, the main part of the study examines thepotential integrated development and inter-country transmissioninterconnections as a means to foster least-cost investment strategies thatwould otherwise be denied in independent (country) development. The basisfor this approach is that regional cooperation may enable a reduction incapital-intensive power sector costs to be achieved through economies ofscale, the sharing of reserves and the postponement of new investments.

By 1995, all known intemal and bilateral projects and agreements are expectedto be in place. Thus all peak planning capacities in each core-Country aretaken as covered with an adequate margin to permit implementation of the first

- "regional" project in the recommended expansion sequence. The knowncore-Country intemal and bilateral projects and the agreements expected to beeffective in 1995 are:

Botswana: Retirement of Selebi Phikwe generation (45MW) and upgrading (to175MW) of supply from ESKOM.

Malawi: Additional generation in operation at Nkula (20MW) and Tedzani(50MW).

Mozambique: North/Central network interconnection completed, withcontinuation of supply support from RSA for the southem network.

Zambia: Completion of Pensulo substation and link to Malawi for cross-bordersupply of circa 35MW.

Zimbabwe: Old thermal plants rehabilitated (120MW) and Kariba S upgraded(to 750MW). Completion of Songo-Bindura 400kV line and Hararereinforcements, with a take-or-pay supply agreement for import of 400MWfrom Cahora Bassa until 2003.

This concept was prepared before the severity of the present drought becameapparent, and therefore responds to the power balances assuming no droughtcrisis. The immediate effects of this crisis, however, might be expected to beless severe by 1995. This year is selected as the base year for considenngSADC core-Country regional plans covering generation and transmissiondevelopment. The effect of the drought on power supply will be reduced waterinflows and this will mark the technical difference between "normal" and"drought' scenarios.

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It follows that the status of the core-country power systems is deemed to beunchanged from that presented in the DTR under the heading of "PresentStatus" (to 1995). These notes are therefore repeated unabridged below, toprovide the nght basis for dealing with the 1995 balances in the integratedplanning exercise presented in Part B, and also in the "intermediate" and"drought" scenarios analysed after the issue of the DTR and presented inPart C of the Report. This is the only way to proceed in order to avoidrepetition and provide a clear baseline for comparison.

Present Status (in 1992)

In examining the present means (in 1992) for balancing demand with therequired reserves, it is noted that three of the five core-Countries already facea power shortfall which is addressed by existing and committedinterconnections as shown in the map of Exhibit 1.2 presented in Section 1.

Zambia provides contract power to Botswana over the 330kV and 22OkVtransmission system and also capacity and energy support for Zimbabwe froma surplus of about 40OMW after discounting "in-country" demand plus reserve.Malawi is just in balance on the premise that the fifth 20MW Nkula B unit isalready in commission. Finally, Southem Mozambique and Botswana aresensibly in balance, given existing supply arrangements with RSA. It should benoted from Exhibit 1.2 that only Malawi is isolated from the existing andcommitted bulk transmission network. This is a situation that must be rectifiedif the concept of full regional integrated development is to be realised.

Status in 1995

By 1995, Zimbabwe will require an import of about 40OMW to cover peakplanning capacity (demand+reserve), provided that the planned upgrading andrehabilitations of existing plant, totalling 354MW, is completed. This import isto be covered by a supply from Cahora Bassa via a new line from Songo toBindura; this link is expected to be completed by 1995.

In the case of Botswana, it is expected that Selebi Phikwe generation (45MW)will be retired and replaced by an increase in imports from RSA to cover adeficit of about 100MW in the peak planning capacity. Given this increaseabove present contract imports, Botswana will have sufficient capacity to coverpost-1 995 demand growth through to the horizon year (2010).

Malawi will also be just in balance, provided that Tedzani 3 (50MW) iscommissioned on schedule and that it can cover demand growth to 1997 whenit is understood Kapichira Phase I (at 125MW) will be commissioned.

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Zambia's surplus, of about 400MW is marginally reduced. However, assumingcontract exports to decline to about 200MW, the net surplus in 1995 isestimated at about 180MW above planned (demand+reserve) requirements.

It is estimated that, by 1995, the Songo-Apollo DC line will be refurbished andhence there will be a surplus of about 50OMW in the north/central areas ofMozambique, after discounting exports (from Cahora Bassa) to Zimbabwe andRSA. This margin over peak planning capacity is expected to be substantiallymaintained until 1998.

It is expected that Southern Mozambique will continue to be supplied from RSAwith up to about 11 OMW. The north- central areas are assumed to be suppliedaccording to the efficacy of the existing networks, given that internal stabilityhas been restored.

Development to 2010

The core-Country power balances in 2010, the "horizon" year for this study, areshown in Exhibits 1.12 and 1.13. The corresponding transmission developmentis described in Section 1.7. In the base case (Exhibit 1.13), the total powerflows into, out of and within the core-Country region are expected to be asfollows (power inflows are +ve, power outflows are -ve);

Botswana + 262MW (162MW from RSA)Malawi + 173MW (125MW from Kapichira)Mozambique - 1848MW (1600MW to RSA)Zambia - 73MW (600MW from Zaire)Zimbabwe + 648MW (800MW from Batoka)

The power balances will of course change if different assumptions are made,as explained in Section 1.7, but the position of the power-importing and power-exporting countries is clearly shown by these figures.

2.3 Independent versus Integrated Development

With the exceptions of Malawi and Zambia, each of the core-Countries alreadyrelies upon interconnection with neighbouring countries to enable reservemargins to be covered. The concept of independent development impliesself-sufficiency in meeting demand, except for emergency support and tradein economy energy over existing interconnections.

Zimbabwe in particular, is heavily reliant on imports, and will continue to be sodependent until 2004, even with the planned completion of internal generationprojects and agreements. In order to follow a completely independentdevelopment program, Zimbabwe would need to implement immediately theHwange 3 thermal plant (44OMW) although the timing might be adjusted in line

2-4


with potential imports from Cahora Bassa which have already been agreed.This would be followed with Batoka (already planned). Both these projects willprovide firm capacity and energy, the latter enhanced by conjunctive operationwith Kariba. The cost of independence will be the value of energy not servedfrom 1995 to 1997 and the additional investment in Hwange 3 for completionin 1997.

Under pre-drought conditions, Zambia can continue to meet planned capacitygrowth without external support to the study horizon, assuming the forecastdemand scenarios are not exceeded. The penalty of independent developmentfor Zambia is denial of revenues that otherwise accrue from opportunities forelectricity trade, in addition to those already in place on a bilateral basis overexisting links.

Malawi can continue to satisfy peak planning capacity from internal resourcesuntil 2002, given the addition of Kapichira, after which there will be modest butincreasing deficits unless additional generating units are installed at Nkula andTedzani. It is clear that Malawi must add a further 250MW of generation tomeet load projections of 520MW at the study horizon (2010) if remainingindependent. The main cost to Malawi of independent development is thusadditional investment in generation in the post-2000 period.

Without further investment in intemal capacity, Botswana will have to relyincreasingly on support from RSA, at least in the medium term. However, if theproposed 2400MW thermal plant is built for energy sales to RSA, projectedrevenues from these sales must be reduced to cover the cost of meeting theintemal demand tnat otherwise would be supplied from a SADC interconnectedsystem.

The main benefits of interconnection are reserve capacity sharing andfirm/economy energy trading, the latter because of the larger market. Sharingreserves enables more effective use to be made of existing generation inmeeting demand growth and it may thus be possible to delay investments innew plant. If interconnection costs are less than the aggregated cost of meetingreserve capacity requirements in independent development there is merit inadopting interconnection strategies.

Zambia and Mozambique are the only SADC countries with a sufficient surplusof generation capacity to provide reserve and demand growth support. Zambiaalready has trading agreements with Botswana and Zimbabwe and is presentlydiscussing a tentative agreement to supply Malawi with 35MW from Chipata(via Pensulo). Mozambique (from Cahora Bassa) has undertaken to supply thecapacity and energy requirements of Zimbabwe from 1995 to 2002 but only200MW of the Cahora Bassa capacity is reserved for Mozambique. The onlyreal surplus arising out of this entitlement is the amount that cannot beabsorbed by the Northem and Central systems, the Southern system remainingdependent on imports from RSA.

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The demand growth within the core Countries is of such a magnitude thalsubstantial generation expansion must be undertaken. No sensible delays inexpansion programs should occur if demand projections are to be met.Zimbabwe in particular, will thus benefit substantially from integrateddevelopment.

There is an opportunity for Zambia to provide support to Malawi via aninterconnection. For this reason, it may be expedient to review the role otKapichira (125MW). Furthermore, by extending the interconnection throughMalawi to Songo in Mozambique, Malawi can be supplied from two independentsources. This facility is considered essential if Malawi is to rely on externalsupply sources to balance demand, which in any event will become necessarytowards the horizon year (2010).

The concept of interconnecting Malawi with Zambia and Mozambique effectivelycreates a second north/south transmission corridor, albeit at 22OkV rather thanat 132kV which would unduly restrict the load transfer capability of this line andthe integration of Malawi into the regional scenario. This new corridor couldtherefore provide additional capacity and security for north-south powertransfers within or through the region, the latter by upgrading to 40OkV. Thisoption also permits altemative contract paths for energy trading.

2.4 Integrated Development Plans

Four plans have been developed (A to D). Plan A is regarded as the BasePlan since it most easily satisfies the basic requirements by assumingimplementation of projects for which design studies are already completed orin progress. The altemate plans (B,C,D) test the value of the main Plan bysubstituting alternative resources and changing the sequence and/or timing ofprojects. Exhibit 2.1 shows the transmission proposals associated with the BasePlan A, including interconnection of Batoka to the bulk system, securing Zaireas a supply source and connecting Malawi to the core-Country network.

All plans address generation expansion according to actual and projecteddeficits, and are thus deemed to be technically equivalent. In essence, thisplanning study reviews the choice of new generating and transmission capacity,assuming integrated operation and a given aggregated demand forecast. Themethodology applied compares total system costs (investments-maintenance-operations) for combinations of new and inherited capacity to meet thedemand at least discounted cost.

Concurrently with following the main development track (of any Plan), it isconsidered that attention must be given to projects that widen opportunities forequitablv sharing of benefits between the core-Countries.

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PLAN A The following developments are envisaged for main generationand transmission additions

PROJECT DESCRIPTION COMPLETIONDATE

1. Upgrade existing Zaire 22OkV line 1995

2. Build a 22OkV line from Songo toUlongwe (Malawi) 1997

3. Build 40OkV Kolwesi-Luano line 2002

4. Build a 22OkV line from Pensuloto Ulongwe 2003

5. Build Batoka Stage 1 (400MW) to supplyZimbabwe capacity and energy needs 2004

6. Complete Batoka Stage 2 (400MW) 2007

The assumptions implicit within this main Plan A are that individualcore-Country developments are completed by 1995 as described in introducingthis Review.

Plan A presents a boundary scenario for comparison with continuedindependent operation. Its economic merit is reviewed in Section 1.13. It iscompared with the least cost option (Plan D) and continued independentoperation in Exhibit 1.23.

PLAN B (no 500MW from Cahora Bassa)

This Plan assumes that the Songo-Bindura project is delayed or cancelled andconsequently, in 1995, Zimbabwe would face an unavoidable deficit in capacityand energy based on the loss of 500MW of firm generation from Cahora Bassa.If there is such a delay, it may not be economical to proceed with thetransmission project.

To cover for this event, it is proposed that Zaire is substituted as the source offirm capacity and energy, and the Kolwesi-Luano line in Plan A is broughtforward for operation in 1997.

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The project requires the addition of the stage 2 convertors for the Inga-KoiwesiDC line to enable the full 1120MW capability of that existing link to be realised,and the building of a 170km, 400kV AC line from Kolwesi to Luano (in theCopperbelt). The convertor upgrading will ensure at least 500MW firm capacityfor export after discounting demand in Shaba Province (Zaire).

As the Kolwesi-Luano line has been brought forward, a substitute project isrequired to provide circa 500MW of additional capacity in 2002, and this isLower Kafue.

Once Lower Kafue is commissioned in 2002, it is to be followed by BatokaStages 1 and 2 in 2004 and 2007 respectively as originally scheduled inPlan A.

PLAN C (substitute Hwange 3 for Lower Kafue in Plan B)

This Plan tests the effect of replacing hydro with thermal generation in 2002.Hwange 3 (at 44OMW) has been selected, as all the feasibility and designstudies are complete and it can be implemented without undue delay. Theinclusion of a thermal plant also evaluates the impact of improving the operatingbalance between thermal and hydro, which, in ongoing drought conditions, willoffer opportunities for energy banking and conservation of hydro resources.

PLAN D (alternate to building Batoka in Plan A)

There is evidence to suggest that a radical change is taking place inhydrological conditions, and thus there may be uncertainty with respect to theavailability of firm hydro energy. The viability of Batoka is heavily dependentupon conjunctive operation with Kariba; if the conjunctive multipliers are notrealised, Batoka may become uneconomic. In this Plan, Batoka Stage 1 istaken to be replaced by Lower Kafue in 2004, and Hwange 3 in 2007. All othersequences of Plan A remain as scheduled.

2.5 Secondary Projects

In setting out the Study Objectives the TOR also require account to be takenof "opportunities for electricity trade with non-SADC countries including Zaireand South Africa (RSA)". This requirement is addressed in terms of"Secondary Projects". These projects consider transfers from Zaire above the500MW scenario for meeting any capacity/energy shortfalls in the core-Countryplans. Also included in this category are the Mepanda Uncua and CahoraBassa North Bank projects that have been jointly studied by ESKOM and EDM.

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These secondary projects are considered to overlay any of the main plans asset out in Sect.2.4 above, and they are assumed to come into effect from 2002.This is considered to be the earliest practical date for implementation, given theneed for feasibility and design studies prior to construction. It is furtherpostulated that these projects will be "non-SADC" or "bilateral" with individualSADC countries and thus are unlikely to attract finance from traditional SADCfunding sources. However, these projects will have an impact on the overallcore-Country plan scenarios, and are expected to provide secondary benefitsto individual SADC Countries.

SP1 - 500MW+ EXPORT FROM ZAIRE TO RSA

This project assumes that the present DC line from Songo to Apollo isupgraded from 1920MW to 2150MW on being reinstated by increasing thetransmission voltage from ±5OOkV to ±600kV and adding convertor banks ateach terminal station. This is considered only a nominal step, as it should benoted that a similar vintage DC tie in the Pacific NW (US) has recently beenupgraded by 50% to carry 31 OOMW over about the same distance (1 500km)with no change to the line conductor configuration.

Assuming the full 11 20MW capacity of the Inga-Kolwesi DC line is available forexport from Zaire, the only upgrading required is to add the Stage 2 convertorsat each DC terminal. Higher transfers would require further line upgrading asdescribed above and, presumably, an increase in the Inga generationspecifically dedicated for export.

Furthermore, if not already undertaken as foreseen in Plan B, the 400kV AClink between Kolwesi and Luano will need to be implemented.

In presenting this project, it is assumed that both stages of the 40OkV link fromPensulo via Ulongwe and Blantyre to Songo are already in place, and that anet 500MW can be delivered via this link to Songo. Transfers greater than50OMW would require reinforcement of this corridor, if this is the preferredcontract path. Altematively, by offset agreements, transfers can be made toRSA via the Bulawayo-Matimba line, assuming Batoka Stage 1 being availableto supply firm capacity and energy.

SP2 - MEPANDA UNCUA & CAHORA BASSA NORTH BANK

In June 1991 a joint ESKOM/EDM prefeasibility study was completed fordevelopment of Mepanda Uncua and Cahora Bassa (North Bank). Animportant conclusion of this study was that an installed capacity of 1600MWis feasible at Mepanda Uncua if operated in conjunction with Cahora Bassa toregulate the flow. The principal purpose of a dam at Mepanda Uncua wouldbe to create head to drive the turbines and the reservior would be keptcontinuously full, or almost full.

2-9

SECT. 2 AAA3.8 PHASE I

It was aiso concluded that the earlier Swedpower view was correct, "that thepresent spillway capacity at Cahora Bassa may be inadequate to deal with thedesign flood, and that the dam has to be partially emptied to provide floodstorage". This reduces the power available (at Cahora Bassa) at 95%assurance to 1945MW (92% load factor), or at 88% assurance for the present2075MW installed capacity. However, by constructing additional spillwaytunnels, the Cahora Bassa reservior need not be emptied for flood storage, withthe benefit that the 2075MW at the South bank will reach the 95% assurancelevel and 550MW will be available for installation on the North Bank.

Cost estimates were prepared in this pre-feasibility study, includingtransmission costs of interconnection with Songo and a second DC line fromSongo to RSA. These estimates suggest that the delivered cost of 2000MWin RSA for the combined project (1 600MW + 550MW) is US$916/kW in 1991dollars after discounting transmission losses. This is a very favourableconclusion and advanced feasibility studies in collaboration with studiesconducted under the auspices of SADC are therefore strongly recommended.

While the ESKOM/EDM Report assumed that all the power would betransmitted to RSA, a variant of this project would be its addition to the SADCcore-Country resource inventory either to replace or supplement Batoka, if thqeconomics of the latter become unattractive, or if some other impedimentlreduces the design capacity. On this basis, the ESKOM/EDM Reportrecommendation for advanced feasibility studies in collaboration with SADC isfully endorsed.

These studies should begin without delay to cover the event that Batoka andMepanda Uncua together with Cahora Bassa (North Bank) are mutuallyexclusive. Furthermore, now that the effects of the drought are beginning to befully appreciated, this project may well displace Batoka.

2.6 Effect of Continued Drought Conditions

The possibility that drier than average hydroiogical conditions experienced overthe last 10 years might continue became evident in the hydrologicalinvestigation as discussed earlier in Section 1.4. This message was conveyedto the PSC Meeting at Lusaka, with the concerns recorded as set out below.These concems were accepted and, as a consequence, the scope of work wasextended to include a "drought" scenario for the integrated Plan A development.This scenario is discussed in detail in Section 1.12. The following discussionsets the scene for the analysis.

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In translating the sets of hydrological data into hydroelectric operating modesin Section 1.5 is shown that the reduction in generating capability as a resultof a drought scenario would be substantial. Detailed consideration of thehydrological impact of drought, and also the impact on electricity demand dueto depressed economic activity, is beyond the scope of this study, althoughserious work has now been done for the drought scenario. Nevertheless, it isappropriate to make recommendations for further study. Most certainly thisissue must be a subject for institutional study as it will critically affectcoordinated strategies for attaining economic efficiency in power supply.

Flows in the River Shire (in Malawi) over the last 10 years do not appear tohave been affected to the same extent as those in the Rivers Zambesi andKafue. Moreover, in the medium term, it would seem that Mozambique willhave considerable energy surpluses. Accordingly, the core countries mostaffected by continued drought conditions would appear to be Zambia andZimbabwe, with Botswana only affected to the extent of having less opportunityto purchase relatively cheap hydro energy.

The estimated loss of firm energy from Kariba and Kafue operating conjuctivelyis equivalent to more than four years' load growth as forecast for Zambia andZimbabwe for normal (non-drought) conditions. In other words, it would haveabout the same effect as if the amount of energy needed in the year 1998 hadin fact to be supplied in 1994. Although showing itself primarily as a reductionof capacity factors, the loss can also be viewed as a reduction of effectivegenerating capacity and on this basis it is equivalent to more than two year'sforecast growth in maximum demand for the two countries. It is clear that theimpact on generation requirements would be critical but on the other hand, thepower and energy requirements would undoubtedly be lower.

Under independent development, Zambia would be affected in the medium termonly to the extent of experiencing some reduction in the energy surplusesotherwise available. Zimbabwe's share of the estimated loss of firm energyfrom Kanba can be equated, however, to between one and two year's loadgrowth forecast for the country. It is clear this would have a substantial effecton the independent development plan and the urgency with which expansionplanning decisions would have to be made.

As indicated above, irrespective of whether integrated or independentdevelopment were to be pursued, continued drought conditions would haveserious consequences for electricity supplies in Zambia and Zimbabwe. It isrecommended that these consequences be studied in detail as a matter ofurgency. The effects described are so large that a proper evaluation willrequire an additional plan to be prepared for each likely, development track. Itis further recommended that the expected growth in water demands for otherpurposes in the Zambesi basin be considered in such studies as referenced inSection 1.4 (p1-6). Furthermore, additional studies are needed to explore theeffect of drought on the pattems of demand and consumption.

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2.7 Drought Strategies for System Operations

The hydrological effect of drought was studied as an addition to the originalscope of work with emphasis on generation planning. The work is reported inSection 1.12. Some thought was given to system operation in a droughtenvironment. The following notes set out a strategy for the coordinatedmanagement of SADC hydro resources, in which reference should be made toExhibit 1.21.

Integrated operation can in most cases result in a greater demand beingsatisfied by a power supply system than is obtainable if each component isoperated in isolation. This is particularly true for a hydro-thermal system withlarge reservoir storage; it has been shown consistently in Section 1.5 and theTable on page 1-11 that this also applies for the SADC system: the larger thesystem considered the more can its demand coverage exceed that of the sumof its parts.

Whilst such considerations may have only minor influence on the determinationof broad development strategy, whatever the strategy adopted for the SADCregion and whatever the new generating plant or transmission line built, therewill always be significant benefits obtainable through collaboration in integratedoperation. Assessment of these benefits may be an important part of thejustification for specific generation and transmission projects.

In the terms of reference proposed for Phase IlIl of this study, it is suggestedthat institutional development should progress through the three stages ofbilateral cooperation, a loose power pool and finally a tight power pooi. Thethird stage of this development implies fully integrated operation with all thebenefits this can bring. An immediate start should therefore be made toestablish procedures for optimising system operation in the core Countries.

As experience is gained, increasing benefits will be derived, even in the firststage of bilateral cooperation. Accordingly, it is recommended that the requiredprocedures for such cooperation are developed during Phase l1l. These willhave the added advantage not only in helping to justify the construction of thenecessary generation and transmission facilities, but also in defining the quality,availability and value of the energy supplies and hence in providing importantinformation for preparing proposals on tarffs and institutional arrangements.

The simple examples in Exhibit 1.6 for the interconnected systems, with andwithout Cahora Bassa, illustrate that optimisation of SADC system operationrequires decisions to be made which, in principle, are no different from normalpractice in a hydro-thermal system, i.e

1. On an annual and monthly basis, the proportion of system demand tobe supplied by hydroelectric and thermal plant needs to be determinedhaving regard to the availability of the power plants in question.

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2. Each month, the hydroelectric demand needs to be assigned to thedifferent sources that can participate in meeting this demand.

3. On a daily and weekly basis, system operation needs to be plannedin detail and controlled to suit changing circumstances of demand andwater and plant availability within the targets set by the monthlyallocation.

With respect to (1) two simple operating policies which assist these decisionshave been tested, but more sophisticated policies can and need to bedeveloped. This is necessary to enable existing and potential generating unitsin the SADC countries to play their proper role and cope with a variety ofpossible exports and imports with different tariff arrangements.

All examples of (2) in this report assume load allocation in accordance with asimple reservoir percentage fullness rule. However, more sophisticated rulesare available and should be tested for the combined system since, for suchlarge reservoirs, they may yield substantial additional benefits.

Finally, with respect to (3) simple illustrations of operation for one day areshown in Exhibit 2.2 whilst the operating plan for the month might well requireall thermal plant to operate. Maintenance requirements or considerations ofmaximising system efficiency may lead to less thermal plant being operated fora few days such as shown. It is extremely important on days such asillustrated to plan the starting and stopping of hydroelectric plant so as to followthe changing load whilst avoiding inefficient part-load operation, especially inthermal plant.

Optimisation of system operation could be expected to be particularly valuablefor the next few years when electricity may continue to be in short supply in theregion. It is thus recommended that two aspects in particular be given urgentattention, either in Phase Ill of this study or as a separate exercise.

Reservoir levels are, as stated earlier, exceptionally low at present and it hasaccordingly become necessary to ration supplies of electricity in Zambia andZimbabwe. There is the possibility of this critical situation being prolonged forsome time, and there is clearly a need for a coordinated plan to ensure thatmore normal reservoir levels and hence normal electricity supplies can berestored as soon as possible and then maintained. It is suggested that thisplan be based on consideration of ranges of.

- probable reservoir inflows

- probable thermal plant availaibilites in Zimbabwe

- phased load shedding or load reductions imposed for varying periods

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SECT, 2 AAA3.8 PHASE 2

The second aspect to which urgent attention is drawn is the efficiency of hydrogeneration. Because much of the inflow into Lake Kariba comes fromungauged tributaries of the Zambesi, current practice is necessarily for theamount of inflow received from these sources each month to be established bycarrying out water balances relying on back calculation from generation records.This is done assuming an average generating efficiency of 86 per cent, but thisvalue may not be correct nor the best that could be achieved.

If the average Karba efficiency assumed is incorrect, then clearly not only willthe calculated inflows be similarly in error but so also will any long-termplanning of future system operation. A further difficulty arising from the truevalue being unknown is that, since the sharing of Karba water between Zambiaand Zimbabwe is defined in terms of energy production, there is little incentivefor either country to generate as efficiently as possible.

Since 1 per cent gain of efficiency would be equivalent to nearly half a percentof total Karba storage capacity every year, it is suggested there could beconsiderable value in carrying out a study of short-term system operation toestablish what efficiency is achieved in practice and how this could best bemaximised. Experience elsewhere suggests that the efficiency gain obtainableis likely to be at least as much as 2 per cent and possibly greater throughcareful management of reservoir operation.

2.8 Intermediate Development Scenarios

A primary motivation for interconnection is the ability to purchase firm energyfor a contract period so that the demand can be satisfied within a least-coststrategy for generation expansion. However, a problem arises if dependenceis for an extended period or the purchase of firm energy is a significantproportion of the total demand in the. importing country. This is because someautonomy is lost by each participant. The energy-deficient country in particularmay have self-sufficiency concerns if this is a policy objective.

As shown in the transmission analysis, the import scenarios for Malawi andBotswana without Kapichira and the 2400MW "export" station would result inimport levels of about 60% of projected 2010 maximum demand. This level ofimport is a matter for concern in fully securing electricity supply in contingencysituations. The practical as distinct from the regionally least-cost integratedsolution to this problem is to add power plants to the in-country resourceinventories and thus increase supply autonomy. In the case of Botswana,supply autonomy would be achieved with a considerably smaller additionalcapacity than the 2400MW "export" station. For Malawi, Kapichira is indeedalready committed.

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An intermediate scenario to include Kapichira, as now carried out, shows thatalthough Malawi does not need to be self-sufficient (in the independent case),practical limits on import dependence are justified. This is one of several"intermediate" scenarios that should be reviewed in the Institutional Phase ofthis Project. The reasoning is that one objective of the institutional appraisalwould be to determine the dependency policy of each country in balancing itspower and energy demand.

The network of Botswana is closely tied to the ESKOM power system and cantherefore receive support other than from the SADC system. The importrequirement is not critical if interconnections are at 40OkV and planned forwheeling-through power from Zaire to RSA, as shown in Section 1.9. This isa system benefit of wheeling.

Finally, Zimbabwe with Batoka at 800MW still has to import about 22% of itsdemand; this is probably about the optimum. The remaining two countries,Mozambique and Zambia, have surpluses and so the policy on dependency ofthe importing countries will affect their revenues from electricity trading. Thepurpose of the intermediate scenarios would thus be to determine adependency strategy to which all countries can subscribe and then develop afeasible "least-cosr expansion plan based on that strategy.

The Intermediate (or mutuai dependency) scenario approach can be classffiedas follows:

- planned and committed projects for each country are accepted (thisretains some planning autonomy);

- within each country, the priority of hydro projects is kept, butcommissioning dates are adjusted in order to achieve a bettergeographical distribution of new projects over time (this should preservethe integrity of the analysis in terms of least-cost);

- energy and power transfers between neighbouring countries should belimited, as far as possible, to a lower percentage of a country's ownpower and energy demand so that supply security under all feasible N-1contingencies is preserved (feasible imports will probably be between20-40% of peak demand excluding "wheeling through" transfers);

- thermal power plant installations should be limited, subject to the needsof water conservation and energy banking (this permits the impact of adrought scenario to be evaluated in a regional context).

This approach is the basis of the intermediate scenario adopted for the studyof Kapichira by extending the present scope of work for this Phase. It clearlyserves as a guide for any further studies that may become necessary as thepractical details of cooperation are worked out in the Institutional Phase.

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2.9 Other Dependency Issues

It is advisable to comment on other dependency issues that must be addressedwhen considering integrated development.

The dependency issues generally involve technical and supply matters, asdiscussed above, together with financial issues. It can also be expected thatthere will be potential problems with regulatory and organisational matters. Theoperation of the participating systems will require close coordination. All ofthese must be discussed in the Institutional Phase and appropriate studiesinstituted to determine "decision rules" for implementing an integrated policy.

Financial dependence arises when the power export revenues accruing to asupplier country are necessary for ensuring the financial viability of thatcountry's power sub-sector. This may involve substantial risks for the suppliercountry, particularly so if revenues must be in a stronger and scarce thirdcurrency. Means of coping with financial dependence may be special loanterms for the countries involved or possibilities of counter-trade. Financialdependence is not necessarily a deterrent if agreements are equitable andcovered through binding contracts.

The operation of interconnected power systems usually requires much closercoordination than when systems operate independently. Area interchangestake place across the interconnections in response to changes in differentnetworks which can also be due to system disturbances or unexpected loadvariations. Where these interchanges exceed agreed limits, they may constitutea problem for other participating systems and need to be corrected within ashort period, say ten minutes, via the ACE (area control error) mechanism. Thiscan be difficult depending upon the degree of technical compatibility andintegration of the participating systems. In essence, short of a system collapse,load is always followed by generation via the frequency response mechanismof the entire interconnected system so that power balance is maintained.

The degree of load following is not an individual choice. Uniformity throughoutthe interconnected systems must be maintained to avoid chaotic unbalancesand ultimate system collapse. Each control area (utility/pool) must providesuitable automatic generation control (AGC) equipment and maintain responsivegeneration in reserve at all times to meet agreed obligations to system balanceand interchange requirements. This will invariably involve increasedtransmission requirements in terms of inherent capability and controlsophistication.

As already evident, planning for regional interconnection can be a problem,particularly with regard to the complexities of the studies and the conflicts ofinterest that may be involved. Planning becomes a particular issue as longlead times may affect the economic viability and attractiveness of the

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interconnection options. For this reason, there should not be any undue delayin continuing these studies into Phase IlIl and in raising the technical studies tothe required level so that priority actions presented in Lusaka and describedbelow can be promptly taken.

The various dependency issues discussed above have been addressed inpreparing the TOR for Phase Ill. The TOR sets out a framework forcooperation and proposes a stage-wise institutional development, beginningwith bilateral cooperation, moving on to a "loose" pool and finally converging ona "tight" pool if the discipline this arrangement imposes is acceptable.

2.10 Recommended Actions (following the Lusaka Meeting)

The purpose of the Interim Report (presented in Lusaka) was to proposeactions that should be taken immediately in order to progress integrateddevelopment within -the framework of regional cooperation. Regardless of thePlan that may be adopted, it is necessary to proceed with some initial projectsby undertaking feasibility and design studies.

It was therefore RECOMMENDED at Lusaka that the following projects shouldbe presented for approval to the Energy Ministers.

1. 220kV Interconnection to Malawi

2. Study of Lower Kafue

3. Interconnection with Zaire

These projects, taken through to full feasibility and design level, will in anyevent help to extend the inventory of options for regional development. Thisproject list should now be extended to include:

4. 40OkV Matimba-Selebi Phikwe-Bulawayo Une

This project should be undertaken as soon as possible as it is pivotal forresolving the drought crisis. All of the feasibility analyses have been carried outand it should therefore be possible to proceed with the work once approval isgiven and funding organised. It is estimated that, with good projectmanagement, the line can be in commission within 18 months.

In dealing with the supplementary analyses, it has become clear that certainactions are necessary if the integrity of the network is to be upheld, regardlessof any further power developments which are:

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S. Kariba switchgear replacement

6. Additional Kariba-Alaska line

It was stated various times that the fault current for a fault at Kariba is nowlikely to be above the rupturng capacity of the switchgear. It is consideredimperative that the switchgear is replaced and that, in the meantime, action istaken to reduce the fault levels by opening bus-sections and limiting generationinfeeds. It has also been shown in the studies that the weak link in the SADCsystem is between Kariba and Alaska. This link has three circuits and a fourthcircuit needs to be built.

It is hoped that, in this way, a significant contribution to regional cooperation inthe electricity supply sector will have been made.

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Exhibit 2.1

ZAIRE -( _

%DI MALW

X \ ~ M *'*--.i I K

| ) ~~~~~~~~ULOtJGWt' @

ZAMBIA

tx ' .5\iisE

ZIMBABWE (

BOTSWANA

i / X { ~~~~~~~~~~~~~~~~~~~ui

s / - TR .-.- ~~~~~~~~~~~~~~~~~

Exhibit 2.2

OPERATION WITH AND WITHOUT CAHORA BASSA

ZamDicn cni ZimDcowecn SystemsGenerating piant scheaule for 3 Wfeonesday in July 1992

3000 -

-_Katie .. *

- --ki 20 / S.. .

2250 - _ , , >

_ _ -- w ektono Fa

- - - - - -F- - -- .-'

~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~- _ _,

7 t as ---- _--_-__-_--'--------_

24.00 4.00 6.00 12.00 16.00 20.00 24.00

Time (hours)

Zcmbian and ZimDabwean Systems with Cohoro BassaGenerating plant schedule for a Wednesday in July 1992

3000 -Kariba

,ooo_ . a. . Katu-- &4Wa20 _

_-- EhjlezzqrZO __, -S 2 -w-w-- u -0 .2200 .- - w- I ' _

_ . _ .*wws. - .. _._ ._5 .-. _ :_a- C*h- _m i

24500 4.00 t.00 12.00 l6.00 20.00 24.0

Tirme (hours).

I~ __

ADDENDUM

Update Figures received from Botswana Power Corporation on 22 February 1993

(a) Page 1-16

Peak Load 2000 = 305MW not 255MWPeak Load 2007 = 423MW, 2010 at 4.5% = 483MW not 415MW.

(b), Page 122

Paragraph five presupposes that there is no additional generation expansion inBotswana before 2010! It is unlikely that Botswana would import beyond year2005.

(c) Page 1-3811-39

Similar comment to above.

(a) Exhibit 1.3 & Exhibit 1.4

For Botswana:

YEAR ENERGY DEMAND

1992 1231 1941993 1268 2051994 1339 2171995 1426 2321996 1489 2431997 1550 2531998 1738 2841999 1811 2962000 1882 3072001 1955 3192002 2043 3332003 2132 3482004 2230 3642005 2327 3802006 2440 4042007 2556 423

Thereafter, say 4% - 5%

joint undp/world bank energy sector management assistance

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