power sector reform a kenyan case study

Power Sector Reform in SubSaharan Africa

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Power Sector Reform inSubSaharan AfricaEdited by

John K. TurksonEnergy EconomistUNEP Collaborating Centre on Energy and EnvironmentRisø National LaboratoryRoskildeDenmark

Foreword by

John M. ChristensenHead, UNEP Collaborating Centre on Energy and Environment

First published in Great Britain 2000 byMACMILLAN PRESS LTDHoundmills, Basingstoke, Hampshire RG21 6XS and LondonCompanies and representatives throughout the world

A catalogue record for this book is available from the British Library.

ISBN 978-1-349-41236-5 ISBN 978-0-230-52455-2 (eBook)

First published in the United States of America 2000 byST. MARTIN’S PRESS, INC.,Scholarly and Reference Division,175 Fifth Avenue, New York, N.Y. 10010

ISBN 978-0-312-22778-4

Library of Congress Cataloging-in-Publication DataPower sector reform in SubSaharan Africa / edited by John K. Turkson; foreword by John M. Christensen.p. cm.Papers presented at an international conference.Includes bibliographical references and index.ISBN 978-0-312-22778-4 (cloth)1. Energy policy—Africa, Sub-Saharan Congresses. 2. Energyindustries—Deregulation—Africa, Sub-Saharan Congresses.3. Privatization—Africa, Sub-Saharan Congresses. I. Turkson, JohnK.HD9502.A49922P68 1999333.793'0967—dc21 99–41122

CIP

© UNEP Collaborating Centre on Energy and Environment 2000

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DOI 10.1057/9780230524552

Softcover reprint of the hardcover 1st edition 2000 978-0-333-75129-9

Contents

Lists of Tables and Figures viii

Notes on the Contributors x

Abbreviations and Acronyms xiii

Foreword by John M. Christensen xix

Preface and Acknowledgements xxi

1 Introduction 1John K. Turkson

2 Power Sector Reform: Conceptual Issues 6John K. Turkson

Introduction 6Conceptual issues 7Concluding remarks 23

3 Privatization of the Power Sector in Côte d’Ivoire 26Etienne K. N’Guessan

Introduction 26The power sector in Côte d’Ivoire 27Reasons for power sector reform 31New institutional and regulatory structure 40Experiences from implementing reforms 46Conclusions 48

4 Power Sector Restructuring in Ghana: Reforms to Promote Competition and Private Sector Participation 50Michael A. Opam and John K. Turkson

Introduction 50Motivation for reforms 51Overview of the power sector prior to reforms 54Regulation and management 59Reform programme and process 64New industry structure and trading arrangements 66Distribution market 73

v

Maintenance of system integrity/regulation 74Managing the transition 78Some key lessons and challenges 79Conclusion 81

5 Power Sector Reform: A Kenyan Case Study 83Stephen Karekezi and Donella Mutiso

Introduction 83The energy sector 85Institutional, legal and regulatory framework 89Power sector problems 96Reform options 98The power sector reform process in Kenya 102Experiences from implementing reforms 110Lessons from experiences 117

6 Power Sector Reform Experiences in Zimbabwe 121Ikhupuleng Dube

Introduction 121The Zimbabwean power system 122Power sector regulatory and institutional framework 123Reasons for power sector reforms 128Reform strategy 141Other relevant issues 146Conclusions 149

7 Power Sector Reform Experiences in Uganda 152John E. Mugyenzi

Introduction 152Electric power resources 152Uganda electricity board’s performance – an overview 154Power sector institutions 155Motivation for reform 155The reform process 156Experiences of reform implementation 164Impact of reform 168Obstacles to reform implementation 171Lessons from experience 173

vi Contents

8 Power Sector Reforms in SubSaharan Africa: The Mauritius Experience 176René Noel

Introduction 176Historical features and existing framework 176Electricity supply and consumption 177

9 Cross-Country Comparisons 186John K. Turkson and Robert Y. Redlinger

Introduction 186Motivations for reform 186Process of reform 188Paths of reform 191Open competition 195Regulatory issues 196Managing the transition 198Power sector reform and rural electrification 199Energy efficiency and integrated resource planning 201Benefits and deficiencies 202Conclusion 203

10 Conclusions and Policy Summary 204John K. Turkson

Introduction 204Assessing reform process and implementation 204Critical issues 205Lessons 207Relevance of the six-country experiences to rest of SSA 215Concluding remarks 216

Index 217

Contents vii

List of Figures and Tables

Figures

2.1 Country power sector reform matrix: ownership and structure 10

2.2 Traditional value chain in the power sector 153.1 Power sector in Côte d’Ivoire 444.1 Old industry structure 554.2 New industry structure 674.3 Contractual arrangements 705.1 Conceptual framework of the study 845.2 Energy sources in Kenya 875.3 Electricity consumption for the years 1991, 1993 and

1995 885.4 Major energy institutions 905.5 KPLC’s organizational structure 935.6 Structural change and privatization 995.7 Reform changes in the power sector 1075.8 Past, present and future scenarios for the Kenyan power

sub-sector 1127.1 Proposed industry structure 1609.1 Country power sector reform direction: existing and

proposed 192

Tables

3.1 Côte d’Ivoire electricity network 294.1 Installed generating capacity (MW) 574.2 Installed distribution lines in Ghana (1991–2) 574.3 Trends in power supply between Ghana and her

neighbours (in GWh) 594.4 Summary of performance of VRA 624.5 Summary of performance of ECG (1989–92) 635.1 Kenya’s installed capacity from 1992–95 865.2 Least-cost generation expansion plan 895.3 Operating income of power sector companies

(ksh million) (1986–91) 976.1 ZESA system parameters 1226.2 Zimbabwe interconnection 123

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6.3 ZESA financial indicators 1346.4 Level of investment required to meet Zimbabwe’s power

needs 1376.5 Zimbabwe: outstanding debt by source 1386.6 Share of electricity costs as compared to total production

costs 1396.7 Net inflows of long-term private capital in developing

countries (US$ billion) 1406.8 ZESA strategic objectives 1437.1 New independent power producers 1618.1 Electricity generation by source 178

List of Figures and Tables ix

Notes on the Contributors

Ikhupuleng Dube works as a research engineer at the ZimbabweElectricity Supply Authority (ZESA), a post he has held since 1993. Priorto this he held the post of Assistant Research Engineer in the sameorganization. He holds an MSc in electrical engineering fromTechnische Hochschule Zwickau in Germany. He is a member of theZimbabwe Institute of Engineers and the Standards Association ofZimbabwe (SAZ). Mr Dube has also been a member of the NationalEnergy Committee where he was in charge of overseeing the imple-mentation of the GEF-funded Zimbabwe Solar Project for Householdsand Energy Efficiency Programmes. He is also Chairman of the BiomassTechnical Committee of Zimbabwe. Currently, he is a PrincipalResearcher of the African Energy Policy Research Network (AFREPREN)Institutions Theme Group.

Stephen Karekezi is the Director of the African Energy Policy ResearchNetwork (AFREPREN), as well as the Executive Secretary of theFoundation for Woodstove Dissemination (FWD), Nairobi, Kenya. In1995, he was appointed member of the Scientific and TechnicalAdvisory Panel (STAP) of the Global Environment Facility (GEF) co-managed by the World Bank, UNDP and UNEP. Stephen Karekezi is anengineer, with post-graduate qualifications in management and econ-omics. He has written, co-authored and edited some 87 publications,journals, papers and reports on sustainable energy development. In1990, he received the Development Association Award in Stockholm,Sweden, in recognition of his work on the development and dissemi-nation of the Kenya Ceramic Jiko energy-efficient cooking stove.

John E. Mugyenzi holds a BSc. in mechanical engineering fromMakerere University in Uganda. Currently, he is the PrincipalGeneration Engineer of the Uganda Electricity Board (UEB), a post hehas held since 1992. He has held several other posts in UEB since 1982.He has co-ordinated various UEB projects, such as the Owen FallsExtension Project and the Maziba Power Station Rehabilitation Project.John Mugyenzi has attended several workshops on hydro equipmentmaintenance, industrial techniques and equipment procurement man-agement. Some of the publications he has authored are on power

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sector reform in Uganda. John Mugyenzi is currently a PrincipalResearcher of the African Energy Policy Research Network (AFREPREN)Institutions Theme Group.

Donella Mutiso (BCom) is a social scientist with specialized training inmanagement science. Donella Mutiso has wide experience in energypolicy research and energy information and documentation support ser-vices. She has worked with the AFREPREN/FWD Secretariat in Nairobi,Kenya for the past four years in various capacities and is currently assist-ing in the coordination of the AFREPREN Energy Institutions and PowerSector Reform Research Programme. Donella Mutiso has participated asa resource person and research fellow in energy policy workshops andresearch fellowships in Kenya, Ghana and Denmark.

Etienne K. N’Guessan holds a Master’s degree in electrical power engi-neering (RPI 74), and has taken part in several studies of the electricalgrid of Côte d’Ivoire, together with the implementation of numerousprojects related to that system. He was first in charge of the implemen-tation of power general equipment and building construction(1974–86), then Technical Director of Distribution (1986–91), Directorfor Corporate Planning (1991–92) and Director, Assistant to theGeneral Manager of EECI in charge of the co-ordination of the controlof the activities of ‘la Compagnie Ivoirienne d’Electricité’. In 1995,Etienne N’GUESSAN was appointed Vice-President of ‘Groupe ProjetEnergie’, a structure composed of staff from the Ministry, BNETD andEECI, set up to supervise all activities related to the CIPREL project, thefirst IPP in Côte d’Ivoire. In May 1996, Etienne N’Guessan wasappointed Technical Advisor for Energy to the Minister of EconomicalInfrastructures.

René Noel is a chartered engineer, UK. Currently, he is chairman andmanaging director of a Mauritius sugar consultancy firm, and theChairman of the Board of Directors of the Mauritius Sugar IndustryResearch Institute. Prior to this, he held the post of director in severalsugar companies, such as Compagnie de Besu Vallon Ltd, Société deRiche en Eau, Mauritius Molasses Co Ltd, Mauritius Sugar IndustryResearch Institute and Mauritius Sugar Authority. René Noel also heldthe post of Director in the Central Electricity Board (CEB), MauritiusElectricity Utility. He holds a BSc. in mechanical engineering, from theUniversity of Strathclyde, Scotland and a Diploma from the MauritiusCollege of Agriculture.

Notes on the Contributors xi

Michael A. Opam is Director of Technical Operations and RateEconomics at the Public Utilities Regulatory Commission in Ghana. Heworked previously as the Deputy Director responsible for Policy andPlanning at the Ministry of Mines and Energy in Ghana. He played animportant role in the power sector reforms in Ghana. He has madeseveral presentations at international fora sponsored by the WorldBank and the African Development Bank on Energy Sector Reform inAfrica, particularly on the power sector.

Robert Y. Redlinger is a senior energy scientist at the UNEPCollaborating Centre on Energy and Environment in Denmark. He hasworked previously as an energy consultant with Synergic ResourcesCorporation and as an environmental engineer with Kennedy/Jenks/Chilton, Inc., both in the USA. Robert Redlinger has worked throughoutthe world on energy planning, restructuring, and climate change issuesand has taught numerous courses on integrated resource planning,energy analysis, and demand side management. He is co-author of thetextbook Integrated Resource Planning: Improving Energy Efficiency andProtecting the Environment (UNEP Centre, 1997) and of an upcoming bookon wind energy. Robert Redlinger holds an MSc. in financial economicsfrom the University of London, and an MS in environmental engineer-ing and science and BS in civil engineering from Stanford University.

John K. Turkson is a energy economist at the UNEP CollaboratingCentre on Energy and Environment (Roskilde, Denmark). He hasworked previously as a lecturer in the Department of Planning at theUniversity of Science and Technology in Ghana, and served as a con-sultant to the World Bank, and United Nations DevelopmentProgramme (UNDP) and the Ministry of Mines and Energy in Ghana.Dr Turkson is the author of several articles on energy planning andpolicy issues in the energy sector in Ghana. He has also made severalpresentations at academic conferences on power sector reforms and thetransport sector in SubSaharan Africa. He was a member of the WorldEnergy Council study committee that published the three volumes onBenefits and Deficiencies of Energy Sector Liberalisation. Dr Turkson is alead author in the Intergovernmental Panel on Climate Change (IPCC)special report on Technology Transfer and the Third AssessmentReport. He holds a Ph.D in energy management and policy from theUniversity of Pennsylvania, an MBA from the Catholic University ofLeuven in Belgium and a BA in economics from the University ofGhana.

xii Notes on the Contributors

Abbreviations and Acronyms

AAG Affirmative Action GroupADB African Development BankAFREPREN African Energy Policy Research NetworkAGC Ashanti Goldfields CompanyANFA Average Re-valued Fixed AssetsBCF Billion Cubic FeetBEDP Bagasse Energy Development ProgrammeBITS Swedish Agency for International Technical and

Economic CooperationBLT Build, Lease, TransferBNETD Bureau National d’Etudes Techniques et de

DévéloppementBOAD La Banque Ouest-Africaine de DévéloppementBOO Build Own OperateBOOT Build Own Operate TransferBOT Built, Own, Transfer¢ Cedis (Ghanaian currency)CAA Caisse Autonome d’AmortissementCAPCO Central African Power CorporationCBP Corporate Business PlanCDB Compact Distribution BoardCDC Commonwealth Development CorporationCEB Central Electricity BoardCEB Communauté Electrique du BeninCFD Caisse Française de DévéloppementCIDA Canadian International Development AgencyCIE Compagnie Ivoirienne d’ElectricitéCINERGY Côte d’lvoire EnergyCIPREL Compagnie Ivoirienne de Production d’ElectricitéCMB Cotton Marketing BoardCPI Consumer Price IndexCSC Cold Storage CommissionDAV Distribution Added ValueDDO Distillate Diesel OilDEEN La Direction de l’Energie Electrique et des Energies

Nouvelles

xiii

DIP Direction des Investissements PublicsDMB Dairy Marketing BoardDMP Direction des Marchés PublicsDOE Department of EnergyDSC Distribution Service ChargeDSM Demand Side ManagementEAPLC East African Power and Lighting CompanyECG Electricity Corporation of GhanaEDF Electricité de FranceEECI Energie Electrique de Côte d’IvoireEIB European Investment BankEIU Economist Intelligence UnitERB Electricity Regulatory BoardERP Economic Recovery ProgrammeESAP Economic Structural Adjustment ProgrammeESBI Electricity Supply Board of IrelandESC Electricity Supply CommissionESI Electricity Supply Industry (Ghana)ESMAP Energy Sector Management Assistance ProgrammeFCFA CFA FrancFNEE Fonds National de l’Energie ElectriqueFWD Foundation for Woodstove DisseminationGBP Great Britain PoundGDP Gross Domestic ProductGEF Global Environment FacilityGELDIC Ghana Economic Dispatch CentreGibb (EA) Gibb (East Africa)GMB Grain Marketing BoardGOU Government of UgandaGPE Groupe Projet Energie Côte d’Ivoire–Banque MondialeGSPER Groupe Spécial Programme Electrification RuraleGTB Government Tender BoardGWh Giga watt-hourHDMP Hydropower Development Master PlanHV High VoltageHVO Heavy Vacuum OilIBDC Indigenous Business Development CentreIBWO Indigenous Business Women’s OrganizationICB International Competitive BiddingICEA Insurance Company of East Africa IDA International Development Association

xiv Abbreviations and Acronyms

IFC International Finance CorporationIMF International Monetary FundIPCC Intergovernmental Panel on Climate ChangeIPG Independent Power GeneratorIPPs Independent Power ProducersIPS Industrial Promotion ServicesIRP Integrated Resource PlanningISDB Islamic Development BankKFW Kreditanstalt für WeideraufbauKm kilometerKNAC Kenya National Assurance CompanyKPC Kenya Power CompanyKPLC Kenya Power and Lighting CompanyKshs Kenya ShillingsKV Kilo VoltKVA Kilo-Volt-AmpereKVDA Kerio Valley Development Authority (Kenya)KW KilowattsKwh Kilowatt-hourLRMC Long-run Marginal CostLV Low VoltageMFCFA Million CFA FrancsMIS Management Information SystemMME Ministry of Mines and EnergyMNR Ministry of Natural ResourcesMOE Ministry of EnergyMOF Ministry of FinanceMOJ Ministry of JusticeMPU Ministry of Public UtilitiesMTE Ministry of Transport and EnergyMW MegawattNED Northern Electricity DepartmentNEMA National Enviromental Management AuthorityNEPS National Energy Planning StudyNES National Electrification SchemeNIP Nile Independent PowerNIT National Investment TrustNORAD Norwegian Agency for Development Co-operationNSSF National Social Security FundO & M Operations and MaintenanceODA Overseas Development Assistance

Abbreviations and Acronyms xv

OECF Overseas Economic Corporation FundOFE Owen Falls ExtensionOFFER Office of Electricity RegulationOFPS Owen Falls Power StationPE Public EnterprisePETROCI National Petroleum CompanyPFS Power Factor SurchargePIP Performance Improvement ProgrammePNE Plan National d’EnergiePPA Power Purchase AgreementPROPARCO Société de Promotion et de Participation pour la

Coopération EconomiquePSRC Power Sector Reform CommitteePURC Public Utilities Regulatory CommissionPV PhotovoltaicRDAs Regional Development AuthoritiesRPC Rusitu Power Corporation (Zimbabwe)SAP Structural Adjustment ProgrammeSAUR Société pour l’Aménagement Urbain et RuralSAZ Standards Association of ZimbabweSCADA System Control and Data AquisitionSIDA Swedish International Development AgencySISP Société Internationale des Services PublicsSOE State-owned EnterpriseSONABEL Société Nationale Burkinabé d’ElectricitéSRMC Short-run Marginal CostSSA SubSaharan AfricaT & D Transmission and DistributionTARDA Tana and Athi Rivers Development Authority TOP Take or PayTOR Terms of ReferenceTRDC Tana River Development Company TSC Transmission Service ChargeUCCEE UNEP Collaborating Centre on Energy and EnvironmentUDI Unilateral Declaration of IndependenceUEB Uganda Electricity BoardUIA Uganda Investment AuthorityUK United KingdomUMA Uganda Manufacturers AssociationUMC United Meridian CorporationUMIC United Meridian International Corporation

xvi Abbreviations and Acronyms

UNDP United Nations Development ProgrammeUNEP United Nations Environment ProggrammeUSC United States CentUSh Uganda ShillingVALCO Volta Aluminium CompanyVRA Volta River AuthorityWB World BankWPC Western Power CompanyZ$ Zimbabwe DollarZC Zimbabwe CentZESA Zimbabwe Electricity Supply AuthorityZIMPREST Zimbabwe Programme for Economic and Social

Transformation

Abbreviations and Acronyms xvii

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Foreword

Over the past few years, countries across the globe have been introduc-ing changes to the structure of their electric utility industry. Onceregarded as a natural monopoly and critical ‘national security’ sectorbest suited for state ownership, the industry has been undergoing atransformation under which the new catch words have becomeunbundling, privatization and deregulation.

Most countries in SubSaharan Africa (SSA) are making serious effortsto turn their economic development away from the path of persistentdecline. These efforts have included the restructuring of various sectorsof the economy. Encouraged by the World Bank and other financialinstitutions, the economic reforms taking place in the region haveentailed significant increase in private sector participation in previ-ously state-run activities including electric power. This, in part, is dueto the recognition of the important role electricity plays in the socioe-conomic development of any country. This reflects the recognitionthat if the countries in the region intend to pursue sustained economicgrowth and development, reliable supply of electricity is crucial.

SSA, in general, is endowed with vast potential primary energyresources – renewable and non-renewable energy – which can be har-nessed to meet the electricity needs of the countries in the region.However, electric utilities are confronted with the twin problem of lowaccessibility to electricity by the majority of their population and lackof financial resources to expand installed generation capacity, trans-mission and distribution networks. These problems are exacerbated byinefficient management of the electric utility companies. Providinglasting solutions to these problems is a main driver of power sectorreforms in SSA. The characteristics of the industry such as size of thesystem, low maturity of the system and low consumer accessibility toelectricity provide interesting challenges and opportunities as well asconstraints to the policy-makers in the region as they consider reformof their respective power sectors.

Restructuring of the electric utility industry can take different forms,varying both in terms of degree of private sector participation and thedegree of unbundling (splitting vertically integrated monopolies intoseparate generation, transmission and distribution entities). In somecountries, the state-owned monopoly structure has been fundamen-

xix

tally maintained, but private independent power producers (IPPs) havebeen invited to construct new power plants and sell their power to thestate monopoly. Other countries have privatized but maintained thevertically integrated system, while others embark on a more radicalapproach of unbundling the state monopoly, privatizing the separatedentities, and establishing a regulatory body to deal with the segment ofthe industry which is not amenable to competition.

Regardless of the model used, the fundamental objective of powersector restructuring has been the same in all countries: to improve theefficiency of electricity provision, utility financial performance andservice. The potential gains through such restructuring and reform ofthe regulatory system can be enormous, particularly in countries wherestate utilities are subsidized and currently sell power below the cost ofsupply.

The UNEP Collaborating Centre on Energy and Environmenttogether with the Ministry of Mines and Energy of Ghana and AfricanEnergy Policy Research Network has conducted and co-ordinateddetailed studies on issues which are central to the power sector restruc-turing process. The ultimate objective of this work has been to estab-lish a better understanding of the possible economic gains and thesocial and environmental implications of the restructuring efforts. Theregional workshop documented here is part of this activity. The case-studies contained in this volume provide an array of different countryexperiences which examine the different reform strategies and reformpaths adopted. These different experiences provide invaluable lessonsfor other countries in the region considering reform of their powersectors.

Researchers and policy-makers, public policy analysts and researchersand energy economists and planners will welcome this book whichaddresses key issues and challenges associated with restructuring thepower sector in SubSaharan Africa.

JOHN M. CHRISTENSEN

Head, UNEP Collaborating Centre on Energy and Environment, Denmark

xx Foreword

Preface and Acknowledgements

This book contains selected papers from the international workshop ofthe same title held in Accra, Ghana from 17–19 November 1997. Theworkshop was sponsored and organized by the UNEP CollaboratingCentre on Energy and Environment (UCCEE), Risoe NationalLaboratory and African Energy and Policy Research Network(AFREPREN), and hosted by the Ministry of Mines and Energy ofGhana. The workshop, in part, was the culmination of UCCEE’s collab-oration with the Ministry of Mines and Energy of Ghana in its powersector reform process. The workshop aimed to bring together policy-makers and researchers/policy analysts, mainly from Africa, to addressone of the most important emerging issues in SubSaharan Africa,reform of the power sector. Designing an efficient and workable indus-try structure, and incentive-based regulatory mechanisms for a sectorwhich is small and yet to be developed, is a daunting yet a challengingtask. The chapters in this book are concerned with the presentationand discussions of different country experiences in the reform of theirrespective power sectors.

Perhaps the most important characteristic of the workshop was theinternal balance in the presentations which provided insights of theexperiences of countries at different stages of reforming their powersectors and the involvement of Independent Power Producers (IPPs).There are pressures on governments in the region to reform theirpower sectors, and the papers presented at the workshop gave insightsinto how different countries at various stages of reform conceptualizeand have initiated the reform of their power sector. The structure ofthe book reflects these reform experiences.

The workshop could not have taken place without the guidance ofkey individuals who identified themes and the countries representedhere. Thanks are also due to the international scholars and policy-makers who participated. The editor is grateful to Ian. H. Rowlands,Robert Redlinger, Stephen Karekezi, Beverly Ann Brereton and NorbertWohlgemuth for critical commentary and review of the enclosed

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papers. The editor also recognizes John M. Christensen, head ofUCCEE, for his support in this undertaking, and the Ministry of Minesand Energy for hosting the workshop. Finally my special thanks foreditorial assistance to Cassandra Brooke and Gordon Mackenzie, bothof UCCEE.

The responsibility for the individual chapters, however, lies solelywith the authors identified with each chapter.

JOHN K. TURKSON

xxii Preface and Acknowlegements

1IntroductionJohn K. Turkson

The efficiency of the electric utility industry’s performance is a matterof great public concern in SubSaharan African (SSA) countries. A basicissue is whether or not significant productivity and social welfare gainswould result from ownership/management changes, industry structuralchanges and regulatory reforms of the power sector. The unstructuredand ad hoc nature of government ‘regulation’ of the industry, reluc-tance of governments in the region to allow efficient pricing of elec-tricity and the countries’ serious macroeconomic problems contributeto the power sector inefficiencies which exist in the region at thepresent time.

At independence, most countries in SubSaharan Africa adopted adevelopment strategy that was spearheaded by the public sector. Thereis no doubt that this approach to power sector development in theregion originally sought an efficient and stable functioning of thepower sector. However, political and economic circumstances havetended to obscure the distinction between bureaucratic administrationand entrepreneurial initiatives. This process gradually hindered allpotential private sector activity in the power sector. Government own-ership does not relieve the need for supervision, and proper regulation(external or internal) requires clearly defined areas of permissible inter-vention, a set of operational and monitorable regulatory objectives,auditing and reporting standards to which the regulated utility can beheld accountable. Sadly enough in most countries in SSA, regulatorypractice is only a shadow of this regulatory ideal.

During colonial times and since independence, the power sector inSSA has been organized mainly on the basis of electric utility companiesthat are vertically integrated or linked by common state-ownership,and governed by the obligation to supply all consumers in their fran-

1

chise areas (normally a whole country). This obligation is to be metwithout price discrimination or the undue preference to any segmentof society or the franchise area.

Successive governments have used the power sector as part of a strat-egy to achieve social equity in the development effort. Over the yearsgovernments have deliberately provided electricity at very low rates,and consequently the issue of electricity pricing has become a politi-cally sensitive issue. To realize the efficiency and productivity improve-ment objectives of the power sector in SSA, the issue of reforming thesector in the countries of the region has been at the forefront of thepublic policy debate. This change in attitude is partly due to theserious financial crises facing a number of electric utilities. These criseshave been a drain on national budgets. The entities in the sector, likeother public enterprises, are typically asked to meet both social andcommercial objectives, which are not always compatible. The magni-tude of the deficits accumulated by most power sector companies inSSA is an important element of the debate over the future of the indus-try. Furthermore there is a consensus that power sectors in mostSubSaharan African countries have been performing badly (Gutierréz,1996). The causes of this dismal performance include poor manage-ment, government interference in daily operations and investment andpricing decisions, and opaque regulatory systems. These and otherfactors, such as the economic crises facing many SSA countries and lackof capital to invest in rehabilitation and expansion of the powersystems, are putting pressure on governments in the region to reformtheir power sectors. Donor agencies (multilateral and bilateral institu-tions) are also putting pressure on governments to reform their powersectors along the lines of privatization and the introduction of competition.

Efforts at restructuring the power sectors in SubSaharan Africa seemto be dominated by a desire to attract Independent Power Producers(IPPs) into the industry. This tends to suggest that there is a single pathto reform the industry. Other equally important issues need to be con-sidered as well, such as definition of the direction of reform of theentire industry, efficient regulatory systems, efficient pricing of electric-ity and which industry and ownership structures to adopt. The six casestudies presented in this volume examine the power sector reformexperiences in the region together with how the choice of reform pathhas been made in each case and attempt is made to draw some conclu-sions from this experience. It is important for countries consideringreform of, or already in the process of reforming, their power sectors to

2 Introduction

be clear from the outset what industry structure they are aiming at,and how to get there. Clarity on these issues would enable countries toanticipate and plan for related issues such as abuse of monopoly powerby utility companies, improvement in accessibility of electricity to themajority of the population and affordability for low-income groupswithin the context of reform of the power sector.

As countries move to restructure their power sectors, many elementshave yet to be played out. Thus assessment of the experience of coun-tries where reasonable restructuring has been implemented is neces-sarily tentative. In countries where restructuring is now beinginitiated, the discussions are quite prospective. In countries whererestructuring is under way, the assessment at this point can be basedon accumulated knowledge, and a much better understanding of thestrengths and weaknesses, of the changes in ownership and industrystructure.

As countries in the region ponder these issues and respond to exter-nal pressures to reform the power sector, we felt that it would beworthwhile to study and share the experiences of countries that haveimplemented some reform of their power sectors as well as those wherereform is under way. The prime reason for this book is to informpeople, particularly researchers, policy-makers and policy analysts,about the power sector reform experiences in countries in the regionand thus provide some perspective on the competing reform strategiesproposed by multilateral and bilateral organizations. The importanceof conceptualizing and properly designing reform strategies on the onehand and political commitment on the other, needs to be noted, asdoes the different system sizes, configuration and maturity, and politi-cal circumstances.

The chapters in this volume reflect the changes that are currentlytaking place in the power sector in SSA. Although changes are occur-ring in the energy sector, there is little doubt that the electric utilityindustry in the region is currently undergoing more ‘upheaval’ thanthe other public utilities – water, postal services and telecommunica-tions. In the face of declining electric utility industry efficiency,financial crises, and inability of governments in the region to providethe needed investments in the sector, the need to reform the powersector has become paramount. Nevertheless, despite these pressures,only a few countries have initiated or implemented restructuring oftheir power sectors. Most countries in SSA are, however, either unde-cided or still considering what reform route they should follow. Thus,power sector reform is just starting in many countries in the region,

John K. Turkson 3

and as such it is too early in the process to undertake an in-depthanalysis of the impact of reform on the performance of the powersector in these countries.

The reform of the power sector involves changes in both the owner-ship/management structure and in the industry structure. For manycountries in the region, the question still looms, ‘will such changesresult in a more efficient governance structure?’ The World Bank andbilateral organizations have been using the positive results of powersector reform in developing countries such as Chile, Argentina andMalaysia to show that power sector reform can lead to more efficientsystems. This book attempts to throw light on the experiences of coun-tries in SSA at different stages of reforming their respective powersectors, explaining why and how these changes are taking place. Thecontributors to this volume continue the debate as to whether theeffects of power sector reform will lead to greater efficiency. Implicationsfor the structure of the power sector, as well as the nature of regula-tion, are discussed. The chapters also consider the challenges posed toregulation by changes in ownership/management and in the structureof the industry. Our objective, therefore, is to tell the story of powersector reform in countries at different stages of the process in SSA witha view to discussing the problems being encountered by these coun-tries and the lessons to be learnt for other countries in the developingworld contemplating reform of their power sectors.

Chapter 2 by John K. Turkson revisits the question ‘what is powersector reform?’ In doing so he discusses, in a much broader sense, therationale or the motivation for power sector reform and looks at theconceptual issues underlying the reform debate. Turkson provides ananalytical framework for discussing the different elements of owner-ship/management and industry structure changes.

Chapters 3, 4 and 5 present cases of countries that have undertakensubstantial reform of their power sectors. The Ivorian case study inChapter 3, presented by Etienne K. N’Guessan, shows that Côte d'lvoireis the country in SSA that has gone furthest in reforming its powersector. The country study presents an analysis of the reform. Thereform actually involves the transfer of the operation of generation,transmission and distribution of electricity to a private company, whilethe state-owned utility company retains responsibility for the infra-structure of the industry. N’Guessan also discusses the impact ofreform on different stakeholders as well as the lessons that have beenlearned. Opam and Turkson present the Ghanaian case in Chapter 4.The case study emphasizes the importance of initiating the reform

4 Introduction

process, putting the legal and institutional aspects of the reform inplace before any major restructuring occurs, that is, unbundling or split-ting the distribution companies into a number of distribution zones tobe operated by different limited liability companies. Stephen Karekeziand Donella Mutiso discuss Kenya’s experience in Chapter 5. TheKenyan experience involves the unbundling of a vertically integratedindustry and private sector involvement in the generation segment ofthe industry. An analysis of the timing of regulatory/institutionalreform and private sector involvement/privatization is also undertaken.

Chapter 6 by Ikhupuleng Dube discusses the power sector reform inZimbabwe. This country study presents a case of reform that empha-sizes efficiency improvement of the existing structure, and the involve-ment of the private sector in the generation segment of the industry.

Chapter 7, Power Sector Reform Experiences in Uganda, by JohnMugyenzi, presents a case of a country in the process of reforming itspower sector, and confronted with such questions as which industryand ownership structures are envisaged. The author discusses howthese questions were addressed and what problems were encounteredin designing a framework to guide the reform of the power sector inUganda.

Attracting independent power producers into the power sector hasbeen one of the major focuses of the reform of the power sector in SSA.Chapter 8, Power Sector Reform Experiences in Mauritius, by RenéNoel, presents the Mauritian experience of an IPP dealing with a statu-tory body that is under direct government control in terms of powerprocurement, pricing and other issues which affect its operation.

John K. Turkson and Robert Redlinger provide, in Chapter 9, a cross-country comparison of the reform strategies and experiences of the six-country studies. They highlight the similarities and differences in thesix countries’ approaches to reform of their respective power sectors,and more importantly, in the reform paths that these countries havepursued.

Chapter 10, Conclusions and Policy Summary, by John K. Turkson,discusses the policy issues central to the reform strategies in the differ-ent countries, and finally presents some reflections on the lessonslearned and their relevance for other countries considering reform oftheir power sectors.

John K. Turkson 5

2Power Sector Reform: ConceptualIssuesJohn K. Turkson

Introduction

As part of the wave of liberalization sweeping most parts of the world,power sectors around the globe are coming under intense scrutiny,with some being restructured. Since the early 1980s, two related trendshave been evident in many parts of the world. The first is the revival ineconomic theorizing about the desirability of market solutions toresource-allocations extending into new areas such as telecommunica-tions, health and other sectors that were previously thought mostefficiently dealt with in the political or hierarchical allocation systems(Surrey, 1996). The second is the emergence of a political climate thatfacilitates advocacy for privatization as the main means of change. Athird trend, which is very much evident in developing countries (par-ticularly SubSaharan Africa), is the shortage of capital for infrastructuredevelopment, and the poor technical, economic and financial perfor-mance of electric utility companies. This has interacted with the firsttwo factors to encourage a growing interest in industry structure andownership restructuring of public utility industries in these parts of theworld.

The over-riding issue in the power sector reform debate is howimprovement in economic and technical efficiencies in the industrycan be achieved. The achievement of such efficiency improvements isbeing pursued along different lines such as changes in industry struc-ture and ownership/management, and reform of the regulatory system.These changes are not mutually exclusive. However, industry restruc-turing can take place without privatization (ownership/management

6

changes) as was the case in New Zealand, Norway and Malaysia.Similarly, privatization of the industry can take place without industryrestructuring, as occurred in Scotland. Industry restructuring and priva-tization can also take place simultaneously as the England and Walesexperience shows. The foregoing suggests that there are numerousoptions or reform paths available, and countries have opted for a par-ticular option or path based on their own circumstances.

Embarking on the reform process involves a hierarchy of decisions.Such decisions include: the sale or retention of existing sector entities,regulatory reform, future industry structure and the creation of anenabling environment to attract private investors. From a developingcountry perspective, public/private sector participation in the reform ofindustry and regulatory structures are at the top of the hierarchy ofdecisions to be made about reform of the sector. Thereafter, otherefficiency issues that link both operation contracting and market orga-nization through the price mechanism are considered. This chapterpresents and discusses some of the major conceptual issues involved inthese initial decisions by policy-makers regarding the reform of thepower sector.

Conceptual issues

Governments in most countries have started to implement changes intheir respective power sectors. These changes have involved either own-ership structure, industry structure, or both, in an effort to improveefficiency in operations through incentive-based regulatory mechanisms.Countries such as the United Kingdom, Chile, Argentina, Australia andNew Zealand have undertaken far-reaching restructuring of their electricutility industries. All these restructuring efforts are, in large measure,consistent with the view that competition should be introduced into theelectricity supply industry wherever it is technologically feasible.Achieving the goal of greater economic efficiency in the electricitysupply industry has been one of the major motivations for reform.

Power sector reform – what is it?

Power sector reform, in a broad sense, is ‘to seek to improve theperformance – financial performance, or the extent to which the sectoris covering its costs and contributing to future investments; supply-sideefficiency, the efficiency with which electricity is produced and deliv-ered to consumers; and demand-side efficiency, the efficiency withwhich electricity is used by the consumer’ (World Bank, 1994).

John K. Turkson 7

Reforming the power sector is not only a problem for developingcountries. This reform is taking place across the globe. What is differ-ent are the drivers of the reforms in countries undertaking them. Fordeveloping countries such as Chile, Argentina, Brazil, Pakistan,Malaysia and countries in SubSaharan Africa, the major driving-forcesare the need to improve efficiency, inability of governments and utili-ties to finance expansion and rehabilitation of the existing systems,and the need to attract foreign and domestic private capital into thesector. For developed countries such as the UK, the main drivers areimprovement in efficiency as well as the economic philosophy ofallowing competition into an industry which, hitherto, has been con-sidered a natural monopoly.

There are also differences in the drivers of power sector reformbetween countries in both developing and developed countries. Thedifferences in motivation and driving-forces behind the reform suggestthat countries are likely to adopt different reform strategies. Thus it isthe thesis of this chapter that there are many ‘paths’ to reforming thepower sector.

Another critical aspect of the reform process is the reform of the reg-ulatory system operating in the industry. The experience of powersector reforms in some developing countries such as Chile, Argentina,Bolivia, Brazil, Philippines and Malaysia suggests that setting up aproper regulatory framework is critical to the success of the entirereform process (Galal et al., 1994; Spiller and Martorell, 1996). One ofthe major issues in the reform process is ownership change. The econ-omic efficiency of the electric utility industry affects a large number of consumers. If the form of the enterprise (that is, municipal, co-operative or proprietary) is a factor which affects economic efficiency,then it implicitly affects consumer welfare (Hollas and Stansell, 1988).It also carries with it a process of removing the inefficiencies whethertheir causes are managerial, undue interference by the politicalestablishments or inadequate institutional capacity.

Successful restructuring of the industry to ensure competitionrequires unbundling the price and other service attributes associatedwith the stages (from generation to distribution and billing) of electricpower supply. Vertical de-integration or separation is central to achiev-ing the benefits of competition. However, if vertical de-integration isdone inefficiently (that is, de-integration which leaves undue re-contracting or regulatory problems in its wake) it may impede anddissipate all the expected benefits of competition. There are potentialproblems associated with such inefficiency. Some of these problems are:

8 Conceptual Issues

(i) the issue of assuring system stability and integrity and the associ-ated issue of reliability;

(ii) structuring an appropriate solution to the stranded cost recoveryproblem during the transition, and

(iii) determining the appropriate structure of ownership, control andregulatory governance of transmission services (Fernando andKleindorfer, 1996).

Whatever the motivations or drivers of power sector reform are, policy-makers should ideally be aware of reform alternatives and their likelyimplications.

Ownership/management and industry structure framework

The changes taking place in the electric utility industry are toocomplex to be presented in a simplified framework. Past and currentreform experiences are varied, and reforms do not only involveownership/management and industry structure changes, but also regu-latory changes, mixture of public and private enterprises, powerpooling, bilateral contracting and others. However, the ownership/management–industry structure framework is adopted to examine thevarious issues associated with changes in these dimensions.

Reform of the sector has been taking place globally within theownership/management industry-structure space. This is presented inFigure 2.1 below. The vertical axis presents the ownership/manage-ment changes spectrum and the horizontal axis shows the industry-structure changes spectrum, characterized as models 1, 2, 3 and 4(Hunt and Shuttleworth, 1996). The models are described in detail laterin this section. These models suggest different degrees of competitionin the industry – from no competition to a high level of competition.

The changes along the ownership/management axis involve move-ment from government department to public corporation, and toprivate corporation. In principle, a movement from governmentdepartment to public corporation entails the adoption of commercialprinciples in the operation of the utility.

The industry structure, as presented on the horizontal axis in Figure 2.1, shows the traditional structure of the sector, that is a verti-cally integrated monopoly. This is presented as model 1. The industrystructural changes ultimately aim at competition in the generation anddistribution segments of the industry (model 4), as typified by theexamples in England and Wales and New Zealand. Between the twoends of the spectrum are different industry structure models that are

John K. Turkson 9

characterized as model 2 and model 3. Model 2 represents an industrystructure where many generators compete to supply a single purchaser,and model 3 represents a structure where distribution companies andlarge consumers can choose their supplier.

Ownership/management change

Ownership/management change is one of the dimensions of theownership/management-structure space. For countries in SSA, allowingmore private participation and control in the power sector can meanmore efficient management and new sources of financing. The issue of

10 Conceptual Issues

Figure 2.1 Country power sector reform matrix: ownership and structure

Note: A schematic view of position of selected countries in the ownershipindustry-structure space.Source: This figure is adapted from Hunt and Shuttleworth (1996:14).

efficiency improvements resulting from such ownership changes,however, is a contentious one. Any ownership restructuring processmay change previous market structures. It is a common theoreticalassumption – and one with a sound empirical basis – that competitionimproves the performance of public and private firms. When, for tech-nological reasons, it is desirable that only one firm should occupy amarket, it is necessary to consider how to control the benefits accruingfrom (productive) efficiency so that the firm’s monopoly power doesnot inflict a loss upon consumers. This, then, raises the question – doesownership matter?

There is a huge theoretical and empirical literature on public–private firm differences, drawing on property rights, transaction cost,and public choice and principal-agent theory, among others. Asurvey of the literature indicates mixed results. Some of the earlystudies report that the evidence was in favour of the private sector(Alchian, 1965; De Alessi, 1980; Frech, 1980; Bennett and Johnson,1979; Davies, 1981). The study of Borcherding et al. (1982), citingmore than 50 studies from 5 countries, reports that ‘the findings inmost of the studies … are consistent with the notion that publicfirms have higher unit cost structures’. They imply some slightadvantage for private ownership. They further state that it is not somuch the difference in the transferability of ownership but the lackof competition that leads to the often observed less efficient produc-tion in public firms (most of them in monopoly markets). Boardmanand Vining (1989) conclude in their study that there is greaterefficiency in a private firm’s operations as compared to the publicfirm. Other studies have reached similar conclusions (Megginson,Nash and Randenborgh, 1992; Galal et al., 1994). However, anotherwidely cited survey by Millward and Parker (1983) arrives at the con-clusion that there is no systematic evidence that public enterprisesare less cost-effective than private firms. Boyd (1986) also concludesthat there is no systematic difference between performance underpublic and private ownership.

Recent research on efficiency issues relating to ownership changeshas adopted the principal-agent approach to analysing the effects ofownership structure and regulatory regimes on allocative and internalefficiencies (Bös, 1991; Vickers and Yarrow, 1988; Bös and Peters,1991). In a public firm the government operates as the principalwhereas in the private firm the shareholders take the lead. In bothcases the management can be treated as the agent. In the context ofasymmetries of information, when attempting to achieve his goals, the

John K. Turkson 11

principal is handicapped by lack of information, which the manage-ment precisely knows. In state-owned enterprises, the traditionalsource of inefficiency resides not only in inadequate knowledge andcontrols but also the gap between managerial and social benefits,which are government’s social objective. The issue here is for the gov-ernment to make them coincide. Thus, as the government, the princi-pal, defines the reward structure of the management, it has to take intoaccount the agent’s objectives which may lead him to choose effortlevels that are not efficient. The principal-agent theoretic approach tostate-owned enterprises predicts that in a situation where there is infor-mation asymmetry, that is when the manager can observe certain vari-ables in the operation of the firm and the government cannot, the firm typically fails to achieve both allocative and internal efficiency(Bös, 1991).

In the context of privatization, the management faces a better-informed principal. There are also changes in the objectives of thefirm, from welfare maximization to profit maximization; and changesin the character of management. The changes in objectives, informa-tion and character lead to differences in incentives and efficiencybetween the public and the privatized firm.

In conclusion, proponents of privatization contend that governmentinterference can be curtailed and improvement in efficiency in publicenterprise (PE) can be attained through privatization. Nevertheless, evenif a firm is fully privatized, the principal-agent relationship between thegovernment and the firm may not be completely eliminated. For pri-vatized public monopolies, the government may decide to regulate the firm with respect to prices, investment and employment.

The changes in ownership take different forms, and both small andlarge systems can take steps along the ownership/management axis, asshown in Figure 2.1. These involve changes from government toprivate ownership, and private ownership is the end-point of a contin-uum of changes in management/ownership. Most power sector compa-nies have moved from their status as departments in governmentministries (government ownership) to corporate entities (governmentcorporation). The movement from government department to govern-ment corporation implies, in principle, that government is one stepremoved from the day-to-day management of the company. Manage-ment is invested in the board of directors of the corporation. The cor-poration may still be required to pursue government policies but hasthe objective to operate on a commercial basis. In most developingcountries, it has been difficult for most of these government power


utilities to make the transition from government department togovernment corporation. The inability to make the transition and theconsequent inefficiencies in these corporations represent the driving-forces towards privatization.

Nevertheless, not all systems need to privatize completely. Theoptions along the ownership continuum may involve commercializa-tion, performance contract, and management contract and partialprivatization.

• Commercialization: a public enterprise is said to be commercializedwhen the government relinquishes detailed control in favour ofautonomy for the enterprise and a focus on profitability. The utilityalso becomes subject to corporate legislation and is required tocompete where possible with other private companies on equalterms. This normally involves the adoption of commercial account-ing, economic tariffs, and the development of a corporate strategythat enables the enterprise to distinguish between its commercialand social objectives, and to focus more on the commercialobjectives.

• Performance Contract: this is a contract that defines the relationshipbetween government and public employees managing a state-ownedenterprise. The process is obviously part of the effort of the govern-ment to enhance efficiency. Performance contracts set targets forstate-owned enterprise (SOE) managers to attain. Such contracts alsoprovide bonuses for management and workers based on achieve-ment. In the contracts the government pledges to provide greaterautonomy to the utilities or meet other obligations as agreedbetween the parties to the contract. For a performance contract tobe successful, the contract should include three main elements:information, reward and penalty, and commitment. Informationissues arise because the contracting parties (government on the onehand and managers of SOEs on the other) have different sets ofinformation, and each side can use the information it holds toimprove its bargaining position. Competition is one way the gov-ernment can gain access to more information about managerial per-formance, since they can compare a firm’s performance with itscompetitors. This may not be appropriate in a monopoly situation.In this case the government uses rewards and penalties to inducemanagement to reveal information and to comply with the contractprovisions. There is also a need for each party to be convinced ofthe other party’s commitment to honour its promises.

John K. Turkson 13

• Management Contract: this is a contract that defines the relation-ship between a government and a private firm contracted to managean SOE for a fee. It is often considered the first step towards privatesector participation in SOEs. A management contract offers a muchbetter chance of success since governments can use competition toreduce management’s information advantage if the SOEs operate ina competitive environment. In a monopoly situation, the use ofcompetitive bidding to award contracts can also reduce such infor-mation advantages.

• Partial Privatization: this involves the sale of part of government’sequity holdings in an SOE to the private sector (institutionalinvestors and general public).

• Full Privatization: this involves the outright sale of an SOE to aprivate investor. Incentives for efficiency are considered even greaterif management is subject to the discipline of stock market valuationof the company, which happens when the enterprise is privatized.

The distinction is never rigid in practice. Any step away from thepresent status toward the end of the continuum, it has been argued,can bring significant efficiency improvements (World Bank, 1994;Hunt and Shuttleworth, 1996).

Industry structural change

Electricity supply – generation, transmission and distribution – is tradi-tionally considered to constitute a natural monopoly. Economies ofscale in the generation of electricity and the need to extend transmis-sion and distribution networks to deliver it to final consumers seem tofavour supply by a single firm for a given geographic area. That schoolof thought has given way to a consensus that the generation segmentof power supply in today’s environment would be more efficient andeconomical if left to the forces of an open market. In support of thisnew consensus, Joskow (1987) argues that economies of scale in elec-tricity production at the generation level are exhausted at a unit size ofabout 500 MW. This and other studies have concluded that scaleeconomies do not exist at the generation level of the industry.Furthermore there is also dissatisfaction with the level of incentives forefficient operation by state-owned utilities, particularly in developingcountries. According to this view, even if economies of scale in the pro-duction of electricity exist, because of the incentives for input choiceprovided by state-ownership, the mode of production chosen by thefirm does not allow efficiency gains to be realized.


Many countries have used the industry structural reforms as a meansof introducing competition and increasing sector efficiency. In Chileand England, for example, generation assets have been separated fromtransmission and distribution, and competition introduced. The ra-tionale for industry restructuring has been to enable the introductionof competition. The traditional structure of the industry has been char-acterized by a supply-side perspective, with self-regulating state-ownedutilities that are either fully or partially vertically integrated. Final con-sumers’ choices are limited, with respect to the purely physical side ofsuch services as well as pricing and billing options.

Figure 2.2 shows the traditional structure of electricity provision.Beginning with fuel supply contracts for non-hydro-based systems,through generation and transmission to distribution and consumption,this structure has been dominated by vertically integrated state-ownedmonopolies. Traditionally, transmission and distribution have beenprovided as a bundled service to customers, and priced accordingly. AsFernando et al. (1995) indicate, there is no clear connection betweencosts and customer valuations of generation, transmission and distrib-ution services. This makes the alignment of investment and operatingdecisions difficult and clouds the determination and provision ofefficient levels of each of these respective services on the supply side.

The point of departure in the discussion on industry restructuring isthe introduction of competition into the commercial arrangement forselling electricity and separating or unbundling industry structure.Total unbundling and introduction of competition is the end-point ofa spectrum of structural changes. The following presents a briefdescription of each model. It is not our intention to give an exhaustivetreatment of these models.1

John K. Turkson 15

Figure 2.2 Traditional value chain in the power sector

• Model 1: this is usually a vertically integrated monopoly (no compe-tition and no choice of supplier). This model shows a high degree ofvertical integration of generation, transmission and distribution.The utility’s monopoly over generation, transmission and distribu-tion, and the service areas may cover a whole country as is thecase in most developing countries. In return for this monopolypower in the franchise area, the utility is required to serve customersin the service area, at a regulated price. The emergence ofIndependent Power Producers in countries with this type of modelmay suggest a movement towards some form of competition at thegeneration level, but evidence on the ground suggests no suchthing. In many cases contracts awarded to IPPs are not based on acompetitive bidding process. The basic arrangement for sellingpower from IPPs is based on a power purchase agreement (PPA).There may often be a ‘take or pay’ clause which guarantees the IPP agiven market.

• Model 2: this model of the industry allows a single buyer to choosefrom a number of generators to encourage competition in genera-tion. All power must be sold to this single buyer. In a situationwhere countries are interconnected, the single purchaser has theoption of buying power from a neighbour. The issue in this model iswhether the purchaser should be an existing utility company or anindependent entity. This model, or a variant of it, is used inNorthern Ireland. It was designed to deal with a relatively smallsystem (2400 MW). This model, as it were, is the precursor of com-petition in the industry as presented in models 3 and 4.

• Model 3: wholesale competition allows distribution companies tobuy directly from a producer and deliver over a transmissionnetwork (open access). Distribution companies still have a monop-oly over final consumers. In this model multiple generators may bidto be dispatched, with the purchaser relying on competition toensure that their bids approximate their marginal operating costs.However, in small power sectors, as in many SubSaharan Africancountries, it may be difficult to introduce genuine competitionbetween generators because there are too few plants to form mean-ingful companies (Bacon and Gutiérrez, 1995). Experience fromcountries such as Chile, England and Wales has shown that if indi-vidual generators control a large share of the market they can oftenmanipulate output or availability to increase profits.

• Model 4: this industry model allows the introduction of retail com-petition into the industry. It facilitates the choice of suppliers by


consumers. This requires multiple generators to have equal access tothe transmission and distribution networks so that they cancompete to supply final consumers. The introduction of retail com-petition requires several suppliers. It also requires that it be econom-ically sensible to split distribution into several entities, so that nosingle distributor has monopoly power with respect to purchasesfrom producers.

As indicated earlier, these models are just broad categorizations ofpotential industry-structures. The movement on the industry-structureaxis towards retail competition would involve changes in contractingrelationships, and transmission and distribution will remain regulated.These industry structures, as represented by the four models, can beassociated with different ownership/management structures. Forexample, the restructuring of the electric utility industry toward opencompetition in the UK, Chile and Argentina involved ownership/management changes (privatization). In a similar industry restructuringin New Zealand and Norway, ownership/management of the industryhas remained predominantly in the public sector. The different loca-tions of countries in the industry-structure – ownership/management-structure space depicted in Figure 2.1 underscores the point that thereare numerous paths to reforming the power sector. One must,however, hasten to stress the dynamic nature of the whole process. Theindustry-structure models presented suggest that model 4 could possi-bly be the envisaged end-state industry structure that embodies thecharacteristics of an efficient, dynamic and competitive market forpower. But certain developments in the industry, such as acquisitionand mergers, could affect the realization of the ultimate objective ofthe entire restructuring process, that is, open competition.

Choice of industry structure

In the face of a plethora of options for industry restructuring, countriesreforming their power sectors have to choose which industry structureto adopt. This amounts to deciding whether to aim at introducingcompetition into the industry or to maintain the existing monopolystructure. If the decision is to introduce competition, the next questionis how this can be achieved? In a general sense there are twoapproaches: an incremental/gradual approach and the ‘big bang’approach. The former involves a more measured sequential strategy tointroducing competition into the industry. This would involve themovement through model 1 to model 4 with thorough assessment of

John K. Turkson 17

the impact at each stage of the process. The latter would involve ajump from model 1 to either model 4 through model 3 or directly tomodel 4. The UK, New Zealand, Australia, Chile and Argentina areexamples of the ‘big bang’ approach to industry restructuring.

It is difficult to suggest ex ante the factors that would influence thechoice of a particular approach to introducing competition. However,assessment of countries that have used one or the other approach sug-gests some factors that might have influenced their choice. For thosecountries that adopted the ‘big bang’ approach, commitment on thepart of the respective governments both to reform the industry and tothe economic philosophy of introducing competition was evident inevery case. Another factor is that all countries had a relatively well-developed institutional foundation. For the most part, the rule of lawwas respected and enforced, and the broader political and socioeco-nomic environment was enabling to the private sector. In addition tothese institutional characteristics, there were also physical factors incommon to these countries. For one, the level of maturity of thesecountries’ systems was, at the outset of the reform process, quite high.All of them had relatively well-developed infrastructure in the powersector. Moreover, they also had high accessibility rates: for example,the UK at 100 per cent, Norway, 99 per cent, Chile, 92 per cent andArgentina, 97 per cent (Gutierréz, 1996); consequently, only relativelymodest demand growth was anticipated. Whether these factorsplayed a role in the successful restructuring of these countries’ powersectors is difficult to determine. There are neither theoretical norempirical studies to support or reject propositions relating to theinfluence of level of accessibility and infrastructure development onthe success of reforms. Nevertheless, their presence in every case is atleast suggestive.

For countries that adopted the incremental/gradual approach, eitherthese factors are not present or policy-makers have not been swayed bythe arguments in favour of introducing competition into the industry.Consequently, adopting an incremental/gradual approach allows themto assess the effects of the incremental changes before deciding to takethe next step towards introducing more competition. In terms of size,the experience in the United Kingdom may be instructive here. The(smaller) Scottish and Northern Irish power sectors were not modelledaccording to the England and Wales system. One of the major reasonswas that the size of these systems was not suitable. In NorthernIreland, for example, to ensure some competition at the generationlevel, the system was interconnected to the Scottish one through sub-


marine cables. Similarly, a gas pipeline was built from Scotland toensure that gas was available for power generation (and also forheating and other economic and environmental purposes).

The expansion plan of the sector is important in determining thefuture structure, since a rapidly growing sector may soon be able toaccommodate enough firms to make competition possible with time.Furthermore, the configuration of the transmission system must betaken into account in deciding whether there can be effective competi-tion between generators. Where there are weaknesses in the transmissionsystem, one plant can have effective monopoly power despite the pres-sure of several plants. Thus, an important lesson from the Scottish andNorthern Irish reform experiences is that the small size of the systemmay not necessarily preclude competition. The interconnection betweenthese two systems on the one hand and interconnection with France andEngland and Wales, on the other, allowed sufficient competition.

The arguments for industry restructuring are mixed. Vertically inte-grated monopolies under government control remain the mostcommon industry structure in industrialized, developing and transi-tion economies. In many countries, the wave of energy sector liberal-ization is leading countries to adopt industry structures that allowcompetition. Once the new structure of the power sector has beendetermined then the regulatory system can be adjusted to match thatstructure.

Regulatory reform

Many of the present problems in the SubSaharan African power sectorstem from government intervention in price setting, often resulting inlow tariff levels. In pursuing their social policies, governments in theregion have interfered in both the input and output markets of thesector, through ill-defined regulatory systems. Regulatory tasks andresponsibilities in combination with the latitude for informal regula-tory actions have led to highly politicized decision-making. Regulatorydeficiencies in the sector have worsened the poor performance of theindustry. This implies that in the reform of the sector, policy-makerswill be faced with the decision to redesign the regulatory system.

No matter how private or unbundled the system becomes, the statewill maintain the role as a regulator. The regulatory role of the state, asenvisaged in the reformed power sector, would be totally differentfrom the present system of regulation. Regulatory and institutionalchanges that take place in the event of reform of the sector shouldmove away from a non-transparent regulatory system and direct

John K. Turkson 19

intervention by government administration on pricing and investmentdecisions in the electric power companies. Regulatory Reform is verycritical to the success of the reform of the power sector in developingcountries. Regulatory approaches differ considerably around the world,but have underlying similarities. The regulatory mechanisms areintended to mimic the effects of competitive markets, and so ensurethat companies in the sector earn a return which is similar to their costof capital. The two main forms of regulation – American-type regula-tion (rate-of-return) and price cap – seek to achieve this objective. Avast economic literature exists on rate-of-return regulation (see Averchand Johnson, 1962; Baumol and Klevorick, 1970; Courville, 1974;Peterson, 1975) that examining its effectiveness in providing incentivesfor efficiency in regulated companies to be efficient. The seminal workof Averch and Johnson supports the claim that cost-plus or rate-of-return regulation tends to result in inefficiency in production.

In recent times, regulators in various settings have begun to use pricecap as a means of regulating the firm. Proponents argue that it offersmuch better incentives to regulated companies to be more efficientcompared to rate-of-return regulation (Mathios and Rogers, 1989).They argue that price-cap regulation provides enhanced incentives forcost reduction. Some opponents argue that the regulated firms may beafforded too much freedom to set prices and plan investments. Actonand Vogelsang (1989) suggest that the interest in price-cap regulationalso reflects a growing understanding that governmental regulation islimited in what it can accomplish. One can infer from such a sugges-tion that firms that are the object of regulation are almost always betterinformed than the regulators about their costs and the consequences ofadopting a particular detailed regulatory scheme for prices or condi-tions of services. Thus, rather than creating regulation based on thepremise of an all-knowing regulator able to set an optional price basedon full knowledge of cost and demand, a more realistic regulatory goalis to design incentive mechanisms for the regulated firm such that itwill maximize society’s objectives while pursuing self-interest.

Both types of regulation provide incentives for cost reduction. Withrate-of-return regulation, the firm can earn some extra profit if itmanages to reduce its cost while the price is fixed at the original costlevel. With price cap regulation, the firm can enjoy a profit if its costsare below the ceiling. In addition, if it can make ‘drastic’ cost reduc-tion, it can charge the monopoly price, thus increasing its profit still further. This second possibility is absent in rate-of-returnregulation.


In reforming the regulatory system, it is important to avoid whole-sale adoption of regulatory models designed for entirely different envi-ronments without consideration of the specific country circumstances.In the choice or design of a regulatory mechanism, the following mustbe borne in mind:

• It should provide incentives to the utilities to perform moreefficiently;

• Efficient utilities should be allowed to earn a return on assets equiv-alent to their cost of capital;

• It should protect the interests of consumers;• The regulatory mechanism should be monitorable;• The regulatory mechanism should induce utilities to perform

efficiently;• Disclosure of important information.

Significance of regulatory reform

At the centre of any electric utility industry restructuring has been thewillingness of the government to restrain itself from interfering withprice-setting. Regulatory reform is crucial in influencing the risk per-ception of would-be investors in the sector in SSA. In the absence ofthis, countries promoting private sector involvement find potentialinvestors requiring substantial government guarantee such as:

• repayment guarantees for external debt;• minimum purchase requirements;• exchange convertibility guarantees.

All these seem to allocate most of the risk to the government. A well-designed and smoothly functioning regulatory regime can, in conjunc-tion with an appropriate commercial/legal framework, greatly reducethe perceived risk in power sector investment. Thus a regulatory processthat demonstrates an independence from political decision-makingtends to reduce this risk. A regulatory agency whose independence isperceived to be respected by government and which is perceived to becompetent and timely in its decisions will significantly reduce theinvestment risk as perceived by the investor. Once it is obvious that thegovernment is willing to allow electricity tariffs to rise to cover costsfrom their previous loss-making levels, and that it will continue to doso, there is an incentive for new investment in the industry. Such regu-latory reform confers benefits on all stakeholders.

John K. Turkson 21

The importance of regulatory reform to the success of power sectorreform is underscored by the experiences in countries such as the UKand Chile. The UK, as part of the restructuring of the sector, createdthe Office of Electricity Regulation (OFFER) and introduced a price-capregulatory system. The Chilean restructuring of the power sector wasmeasured. It began with a regulatory reform that forced the state-owned electricity companies to behave according to the new regulatoryrules. This allowed for a critical learning period in which the regulatoryagency, for example, was able to gather experience in regulatingmonopoly enterprises. This was even more significant in view of thefact that Chile had no history of formal electric utility industryregulation.

The timing of regulatory reform with respect to that of industry andownership restructuring is also an important factor to consider. In theUK, reforms were introduced almost simultaneously, probably becausethe UK had adequate capacity, both human and institutional. TheChilean experience, on the other hand, involved a gradualist approach.Chile started with a regulatory reform that forced the state-owned elec-tricity companies to behave according to the new regulatory rules. Thiswas done before de-integrating and privatizing the companies, and itallowed important learning and experience to accrue. This particularexperience of the Chilean power sector reform provides a useful lessonfor SSA countries, most of which have no history and experience offormal regulation.

An important complement to regulatory reform is the existence ofsafeguarding institutions and an enabling environment including:

• a well functioning judicial system;• a properly functioning independent regulatory body.

From the study of power sector reforms in Chile, Spiller and Mortorell(1996) conclude that Chile’s success can be attributed to the transfor-mation of its regulatory structure and institutions, the existence of awell-functioning legal system (including respect for property rights)and a properly functioning independent regulatory body. They indi-cate that Chile has not only been successful in transferring ownershipfrom government to private hands, but that it has also promoted largeprivate investments in the power sector. Spiller and Mortorell contendthat most countries trying to promote private sector participation havean extremely ad hoc regulatory system, which not only generates verylarge inefficiencies but also lacks the assurances of fair play that private


sector investors naturally would require (Spiller and Mortorell, 1996).Development of similar institutions in SSA would thus appear to beimportant to the prospects for successful power sector reform.

Concluding remarks

This chapter has discussed the conceptual issues associated with reformof the power sector from its current vertically integrated regulatedstructures to different restructuring models and regulatory systems. Thereform strategy involving changes in ownership/management struc-tures, and industry structure and regulatory environments is a complexoperation, and a sequence of phases needs to be planned and imple-mented. There appears to be no single superior model, and differentcountries have taken different approaches. Each country has to designand articulate the appropriate reform it intends to undertake. For thereform to work, it is necessary that there is political commitment; theownership and the leadership of the reform process must be local; andthere should be resources to respond to the requirement of the pro-gramme. For SubSaharan Africa, the issue is not to decide which ofthese regulatory regimes is better, but to understand what it takes toadopt and implement any regime in terms of institutional and humancapacity, legal systems and the cost involved.

Note

1 See Hunt and Shuttleworth for more detailed discussion on this subject.

References

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Alchian, A. A. (1965). ‘Some economics of property rights’, Il Politico, 30, 816–29.Averch, H. and Johnson, L. (1962) ‘Behaviour of the firm under regulatory

constraint’, American Economic Review, 1052–67.Bacon, R. and Gutiérrez, L. E., (1995). ‘Global Reform Trends and Institutional

Options for Sub-Saharan Africa’, in Proceedings of the Symposium on PowerSector Reform and Efficiency Improvement in Sub-Saharan Africa, 5–8 December,World Bank.

Baumol, W. J. and Klevorick, A. K. (1970). ‘Input Choices and rate of ReturnRegulation: An overview of the discussion’, Bell Journal of Economic andManagement Science, I, 162–90.

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John K. Turkson 23

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Boyd, C. W. (1986). ‘The comparative efficiency of state-owned enterprises’, inMultinational corporation and state-owned enterprises: A new challenge ininternational business. Vol. 1 of International Business and InternationalRelations, edited by R. Negandhi, H. Thomas and K. L. L. Rao, pp. 179–94.Greenwich Conn. JAI.

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Fernando, C. S, Kleindorfer, P. R., Tabors, R. D., Pickel, F. and Robinson, S. J.(1995). Unbundling the US Electric Power Industry: A Blueprint for Change.

Frech, H. E. (1980). ‘Property Rights, the theory of the firm and competitivemarkets for top decision makers’, Research in Law and Economics, 2, 49–63.

Galal, A., Jones, L., Tandon, P. and Vogelsang, I. (1994). Welfare Consequences of Selling Public Enterprises: An Empirical Analysis. (Published by OxfordUniversity Press for the World Bank. Oxford University Press.)

Gutierréz, L. E. (1996). ‘How do Sub-Saharan African Utilities Compare?’ inProceedings of Symposium on Power Sector Reform and Efficiency Improvement inSub-Saharan Africa, ESMAP Report No. 182/96.

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Megginson, W. L., Nash, R. C. and M. Van Randenborgh (1992). Efficiency Gainsfrom Privatization: An international Empirical Analysis (Athens: University ofGeorgia, Department of Banking and Finance).


Millward, R. and Parker, D. M. (1983). ‘Public and Private Enterprise:Comparative Behaviour and Relative Efficiency’ in R. Millward, D. M.Parker, L. Rosenthal, M. T. Summer and N. Topman (eds), Public SectorEconomics (London: Longman).

Peterson, H. (1975) ‘An empirical test of regulatory effects’, Bell Journal ofEconomics 6, 11–26.

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John K. Turkson 25

3Privatization of the Power Sector inCôte D’ivoireEtienne K. N’Guessan

Introduction

Historical background

From the country’s independence in 1960 up until the early 1980s, thepower sector of Côte d’Ivoire experienced rapid changes. During this20-year period, the annual electricity demand growth rate was over 10 per cent on average. The financial health of the state-owned elec-tricity company, Energie Electrique de Côte d’Ivoire (EECI), was verygood. That financial status enabled EECI to engage in an ambitiousprogramme of rural electrification, which was costly, but very highlyappreciated. Today, it is estimated that about 60 per cent of Côted'lvoire’s 14 million inhabitants have access to electricity, with about1400 cities and villages electrified.

Before 1983, power generation in Côte d’Ivoire was based mostly onhydropower plants. In 1983, a severe drought forced EECI to switch tothermal generation, leading to severe load-shedding and a dramaticincrease in fuel consumption. Thus the bill for fuel costs in 1983–1984was six times the normal level, with adverse consequences for thefinancial position of EECI. Subsequently, EECI was not able to regain asound financial strength for more than five years in spite of severaladjustment programmes supported by international lenders such as theWorld Bank, African Development Bank, European Investment Bankand Caisse Française de Développement.

In October 1990, the government of Côte d’Ivoire decided to privat-ize the operations of EECI by signing a Concession Agreement withCompagnie Ivoirienne d’Electricité (CIE). In July 1994 the government

26


authorized a private developer, la Compagnie Ivoirienne de Productiond’Electricité (CIPREL) to build, own, operate and transfer a power plantthat is to sell electricity to the national grid.

In September 1997, the government of Côte d’Ivoire selected theconsortium ABB/IPS to build, own, operate and transfer another powerplant dedicated to sell electricity to the national grid, following aninternational competitive bidding process. As can be seen from thisshort historical overview, the power sector in Côte d’Ivoire has beentransformed in the period 1990 to 1997 from a totally state-owned andoperated structure, to a structure now almost completely operated byprivate entities.

The power sector in Côte d’Ivoire

The power system, demand and supply situation

At independence in 1960, only 14 cities had electricity in Côte d’Ivoire.That number was increased to 108 in 1970; 475 in 1980; 1027 in 1990and 1400 in 1997. This electrification covered all of the 16 administra-tive regions of the country, and it is estimated today that in each region,more than 60 per cent of the population have access to electricity. Before1990, rural electrification was not directly supported by the government,but undertaken solely through funds generated by EECI, either from itsown assets, or through loans secured from the banks.

The main characteristics of the national grid of Côte d’Ivoire are asfollows:

i) Total installed generation capacity is about 1100 MW, of which 480 MW is thermal plant (270 MW belonging to the state and 210 MW belonging to CIPREL, the first IPP authorized in Côted’Ivoire), and about 620 MW in total for the five existing hydro-electric plants

ii) Transmission and distribution networks are made of 1720 km of225 kV transmission line, 2526 km of 90 kV line, 11 substations atthe voltage level of 225 kV/90 kV/33 kV (or 15 kV), and 30 sub-stations at the voltage level of 90 kV/33 kV (or 15 kV). The 15 kVvoltage level is used for distribution in large cities, while the 33 kVvoltage level is used for rural distribution over long distances. Thedistribution network is composed of about 12 300 km of mediumvoltage line (both 33 and 15 kV), 10 000 km of low voltage distrib-ution line and 180 000 public lighting points.

Etienne K. N’Guessan 27

iii) The national grid of Côte d’Ivoire is interconnected with thenational grid of Ghana, through a 225 kV transmission line on theIvorian side and a 161 kV transmission line on the Ghanaian side.Interconnection with Burkina Faso is planned, to supply electric-ity to Bobodioulasso in Burkina Faso from the Ivorian networkthrough a 225 kV transmission line. Studies are under way for thesupply of Sikasso in Mali from the Ivorian network as well.

iv) At the end of fiscal year 1995–6, total generation was 3210 GWh,of which 56 per cent was from thermal plants, and 44 per centfrom hydroelectric plants. National consumption was at 2440 GWh,of which 1300 GWh was for domestic consumers and 1110 GWhfor industrial consumers. Total low voltage consumers numberapproximately 586 000 and medium voltage consumers about2000. Table 3.1 gives a summary of the power system in Côted’Ivoire.

Historically, growth in electricity consumption in Côte d’Ivoire hasoutpaced related economic variables, largely reflecting a relatively highgrowth rate of new consumer connections and a resilience of powerconsumption per customer. It is expected that electricity demandwould grow at the pace of 10 per cent from 1997 to 2000, and 8–9 percent during the following period of five years.

For a long period of time, hydroelectric power stations and thethermal plant at Vridi-1 (100 MW gas turbine and 214 MW steamturbine) met power demand growth in Côte d’Ivoire. Since 1985, lowavailability at the ageing Vridi steam plant combined with lower thananticipated power generation from the hydroelectric plants, in particu-lar during the prolonged drought period of 1983–4, has forced Côted’Ivoire to supplement domestic electricity generation on occasionwith hydroelectric generation from Ghana.

Since 1993, electric power generation in Ghana has become increas-ingly insufficient to meet both domestic demand and its commitmentto supply power to Togo/Benin. This has led these countries to increasepower import from Côte d’Ivoire. However, the present electricitydemand situation in the Ghanaian market has changed since the con-struction of a 300 MW combined cycle thermal plant in Takoradi andother potential developments are currently under consideration.Although Côte d’Ivoire has been exporting power, its own rapidlyexpanding domestic power demand due to the recovery of itseconomy, the rural electrification programme, and the demand from

28 Privatization in Côte d’Ivoire

large mining and industrial concerns is currently creating a deficit inpower generation. An additional capacity of 140 MW is now required.

Following the discovery of offshore oil and gas fields in 1993–4, Côted’Ivoire has been able to reduce its dependency on imported fuel bygenerating electricity from natural gas.

Structure

The formulation of the general policy for the power sector, as well asthe setting of the regulatory framework, has been assigned exclusivelyto two ministries:

i) the Ministry in charge of Energy, for all technical matters relatingto the power sector;


Table 3.1 Côte d’Ivoire electricity network

EXISTING GENERATION CAPACITYState-owned thermal plants 270 MWIPP (thermal) 210 MWHydroelectric power 620 MWTotal 1100 MWAdditional projected thermal plant (1999) 420 MW

TRANSMISSION NETWORK225 kV line 1720 km90 kV line 2526 km225/90 kV substations 1190 kV/MV substations 30

DISTRIBUTION NETWORKMedium voltage Line 12 300 kmLow voltage line 10 000 kmPublic lighting point 180 000 km

CUSTOMERSMedium voltage 2000Low voltage 584 000

ANNUAL TURNOVER FCFA 143 000 mn

ANNUAL ENERGY CONSUMPTIONDomestic 3210 GWhExport 770 GWh

ii) the Ministry of Finance, for the supervision of the financial oper-ation of the power sector.

Until November 1990, electricity generation, transmission and distrib-ution in Côte d’Ivoire was managed by the state-owned monopoly,Energie Electrique de Côte d’Ivoire (EECI). In addition to the day-to-day operation, EECI was in charge of all activities related to thedevelopment of the power sector, including building new power plants,new transmission and distribution lines and rural electrification.

EECI is a state-owned company with an initial capital of eight billionFCFA, reduced to one billion FCFA in 1992 after the privatization. Theshare-ownership of EECI, which was not modified after restructuring ofthe power sector, is as follows:

i) 92.3 per cent for the State of Côte d’Ivoire.ii) 7.7 per cent for various private partners: Caisse Française de

Développement (CFD) with 4.7 per cent, Electricité de France (EDF)with 1.3 per cent and miscellaneous Ivorians with 1.7 per cent.

Regulatory framework before reforms

The law No. 85-583 of 29 July 1985 regulates the power sector of Côted’Ivoire. This law stipulates and regulates the principles of electricitygeneration, transmission and distribution. In particular, the lawstipulates that:

i) electricity transmission, distribution, as well as the importationand exportation of electricity are a state monopoly;

ii) the state can contract the above-mentioned monopoly to beoperated as a public service to one or several operators;

iii) electricity generation is not a state monopoly;iv) all existing power generation equipment belonging to the state

shall be operated as a public service;v) independent power generation is authorized under the conditions

that the electricity is generated locally, is not distributed and soldto the public and utilizes fuel sources that are authorized by thestate of Côte D’Ivoire.

vi) all existing or future equipment earmarked for electricity transmis-sion and distribution shall be incorporated in ConcessionAgreements as assets belonging to the state of Côte d’Ivoire;

vii) electricity tariffs are set by the state, after consultation with theoperator of the system. Tariff-setting is made to ensure balance


between all charges of the electricity sector, including provisionfor rural electrification, network expansion, debt service andpayment to the operator of the system.

It is very clear that the existence of the above-mentioned law enabledthe State of Côte d’Ivoire to privatize EECI in a very short period oftime, in spite of some public opposition during the first stage of priva-tization in 1990. The formal decision to privatize EECI was taken inAugust 1990 and the new operator had started its activities by 1 November 1990. This quick action was made possible by the govern-ment’s commitment to encourage private sector participation in thepower sector as well as by the existence of the appropriate institutionalframework. As noted earlier, the existence of the law No. 85-583 gavethe government the legal support to proceed with the privatization.

Reasons for power sector reform

Uncertain hydrology

Until the second half of the 1970s, power generation was based on thethermal plant of Vridi with an installed capacity of 204 MW. Powergeneration was approximately 60 per cent thermal and 40 per centhydro. The only existing hydroelectric plants, Ayamé 1 (2*10 MW),Ayamé 2 (2*15 MW) and Kossou (3*65 MW), were marginal inmeeting total demand of about 200 MW at peak load for the followingreasons:

i) The water level in the reservoir at Ayamé 1 has been very modest;thus the two plants of Ayamé played a significant role only duringthe rainy season, from May to about December;

ii) Since its commissioning in 1973, the reservoir of Kossou, with aplanned maximum capacity of about 26 billion cubic metres, hasnot stored more than five to six billion cubic meters of water.Hence, the Kossou plant was used mostly for peaking purposes.

From the time of the second oil crisis at the end of the 1970s, powergeneration switched from a thermal to a hydroelectric base (60 per centhydro and 40 per cent thermal) following the commissioning of theTaabo hydroelectric plant (3*70 MW) downstream of Kossou, and theBuyo hydroelectric plant (3*55 MW) in the western area of Côted’Ivoire.


The 1983–84 severe drought, however, drastically reduced thegenerating capacity of the hydro plants, leaving the satisfaction ofdemand to the Vridi plant, which was not able to meet total demandof about 320 MW. This caused EECI to undertake the followingactions:

i) as early as November 1983, EECI proceeded with load-shedding,with very bad effects on the public, and catastrophic consequencesfor the national economy as power imports from Ghana throughthe new interconnection commissioned in October 1983, were notable to solve the problem because Ghana itself was experiencingthe same drought;

ii) therefore in December of the same year EECI was forced to orderfour gas turbines of 25 MW each, which were installed andcommissioned by mid February 1984.

Financial constraints at EECI

The financial consequence of this situation was that the total bill forfuel rose from a planned spending of about 6 billion FCFA to 36billion for the fiscal year October 1983–September 1984. For acompany with an annual turnover of about 80 billion FCFA, this wasa severe shock to absorb. The financial crisis that followed made thefinancial structure of EECI very precarious, especially since manage-ment continued with the costly rural electrification programmethrough high interest commercial bank loans.

From 1985 to early 1990, several international lending agencies suchas the World Bank, African Development Bank, European InvestmentBank and Caisse Française de Développement recommended financialrestructuring of EECI, but management overlooked most of their rec-ommendations for sound financial management. The financial criseswere further exacerbated by the economic crisis resulting from the lowinternational selling prices of Côte d’Ivoire’s two main export crops(coffee and cocoa). The country was also experiencing social unrest,with the population making demands such as salary increases andgreater democracy.

Pressure was also mounting on the government to do somethingabout the mismanagement of state-owned companies. This includedEECI in particular because of power outages in sensitive areas ofAbidjan, the capital of Côte d’Ivoire. EECI was the biggest of the state-owned companies, and its restructuring was one of the top priorities ofthe international lending agencies.


In spite of EECI’s management problems, its technical operation ofthe power system was very good. EECI had competent and dedicatedtechnical staff made up of Ivorian engineers and technicians, most ofwhom were trained in the best French engineering and technicalschools through scholarships from EECI. The total system loss, that isthe percentage of total energy billed divided by total energy generated,varied from 13–17 per cent depending on the type of generation.Losses were high when thermal generation was predominant, becauseof power plant internal consumption. Total staff of EECI was about3500, all of whom were properly assigned; hence excess staff was not amajor problem.

Electricity bill collection for industrial consumers, about 40 per centof total consumption, was high (90–95 per cent). Bill collection forprivate and domestic consumers was also good (more than 90 per centof total bills collected at deadline). However, bill collection from gov-ernmental agencies was irregular and insufficient. Nevertheless, urgentmaintenance programmes for the thermal power plants were crippledby the lack of liquid financial resources.

Reform of the Ivorian power sector

Power sector reform in Côte d’Ivoire was prompted by the need toimplement urgent changes in the management of EECI, which hadbeen operating the company since 1967–8, and was headed by a politi-cally powerful general manager. The only specific goals assigned topower sector reform were to stop the financial mismanagement andrestore financial equilibrium in the sector.

Chronology of the Ivorian power sector reform

After 31 October 1990, the government restructured the power sector:

i) by Concession Agreement signed on 25 October 1990 the govern-ment entrusted to the private company, Compagnie Ivoirienned’Electricité (CIE), the duty of operation of the national publicservice for generation, transmission, distribution, commercializa-tion, importation and exportation of electricity in Côte d’Ivoire;

ii) by another Agreement signed on 12 December 1990, the govern-ment charged EECI with management of the state-owned assetsoperated by CIE as well as the right of supervision of the technicalfunctioning of CIE;


iii) on 20 July 1995, the government signed an Agreement with theprivate company, la Compagnie Ivoirienne de Productiond’Electricité (CIPREL) by which the government authorized CIPRELto build, own, operate and transfer a thermal plant of 165 MWinitial installed capacity;

iv) on 5 September 1997 the government signed a new Agreementwith a consortium made of ABB Energy Ventures (ABB-EV) andIndustrial Promotion Services SA (IPS) to build, own, operate andtransfer a thermal plant of 420 MW final installed capacity.

Reform approaches

In reforming the power sector, Côte d’Ivoire opted for two approaches.These are: (a) handing over the management of the existing utility to aprivate management firm (management contract) and (b) opening upthe generation segment of the industry to Independent PowerProducers (IPPs).

Management contract

Campagnie Ivorienne d’Electricité (CIE) is a privately owned companywith an initial subscribed capital of 10 billion FCFA. This capital hasbeen upgraded to 14 billion FCFA. The main shareholders of CIE are:

i) 51 per cent to Société Internationale des Services Publics (SISP).SISP is jointly owned by Société pour l’Aménagement Urbain etRural (SAUR), a subsidiary of the French group BOUYGUES andElectricité de France (EDF);

ii) 49 per cent for the Ivorian part, of which 20 per cent is for thestate, 20 per cent for the Ivorian public share holders through theAbidjan Stock Exchange, 5 per cent for the workers of CIE, and 4 per cent for other Ivorian private parties.

The main duties of CIE, as specified in the 1990 Concession Agreement,are:

i) operation and maintenance of the existing and future power gen-eration units belonging to the state, including isolated small dieselgenerating units;

ii) operation and maintenance of all equipment for transmission anddistribution of electricity in Côte d’Ivoire;

iii) operation and maintenance of all equipment for importation orexportation of electricity to or from Côte d’Ivoire.


The Concession Agreement with CIE was signed for a duration of 15years, with a possibility of extension for two more consecutive periodsof three years each. The main stipulations of the CIE ConcessionAgreement are as follows:

i) as the operator of the national electricity network, CIE is not incharge of major repairs of the units, their renewal or rehabilitation,nor new investments in the national grid. This duty has beenentrusted to EECI;

ii) all generation units, transmission and distribution lines as well asall connections to customers are to be operated and maintained ingood order by CIE, at its own expense;

iii) works of maintenance executed by CIE shall comprise all actionsand activities necessary to keep all equipment in good workingorder to optimize its lifetime which shall not be less than certainspecified values contained in the Concession Agreement;

iv) major maintenance or renewal of equipment is decided upon bythe state after a proposal by CIE. Those major works are containedin periodical subsidiary agreements contracted for a minimumperiod of one year. The subsidiary agreements outline the sharingof costs between the state and CIE.

The electricity tariff is decided by the government in order to maintaina balanced financial structure in the power sector, including thefinancing of major works, development of the grid and ruralelectrification. For the fiscal year 1995/6, the average electricity tariffwas about 56 FCFA per kWh. The division of the average electricitytariff among the various partners is as follows:

i) the share dedicated to pay CIE for the operation and mainte-nance of the national network includes all elements of thebalance sheet of CIE: expenses, profits, risks associated with theoperation, taxes, and duties. This share is estimated at about 21FCFA per kWh;

ii) the share for buying fuel (liquid or natural gas) and/or electricityfrom IPPs is estimated at about 11 FCFA per kWh;

iii) the share for the state for debt servicing, financing new invest-ments, major repair and rehabilitation and new development ofthe grid is estimated at about 24 FCFA per kWh.


Independent power producers

The Ivorian government has a policy of increasing the contributionof thermal power generation to the electricity supply in Côted’Ivoire. This policy shift is mainly a result of increasing uncertaintyregarding the hydrology of the river system on which the hydroelec-tric plants are installed, and the desire to utilize the gas associatedwith the country’s oilfields. To achieve this policy objective, the gov-ernment has encouraged IPPs to enter the generation segment of theindustry.

Independent Power Producers (IPP) are a new feature of the powersector in Côte d’Ivoire. The first IPP project was more of an accidentthan a planned endeavour for the following reasons:

i) 1995 appeared to be a critical year, since the new President was tostand for election;

ii) social unrest, the immediate cause of which was the accidentalpower outages in some sensitive areas of Abidjan;

iii) careful evaluation of the network showed that available generatingcapacity was sufficient to cover demand, but any unplannedoutage, or an inability to import energy from Ghana, could lead tothe same situation of power shedding that occurred in 1983–4;

iv) in early 1994, additional oil fields were discovered off the coastof Côte d’Ivoire. The government planned to commercialize thevery substantial quantity of natural gas associated with the crudeoil;

v) the only alternative for extracting the crude oil without flaring theassociated natural gas was to use it for electricity generation;

vi) the four 25MW gas turbines of the Vridi plant could be rapidlyconverted to burn natural gas, while the other steam turbinescould not be easily adapted for that kind of transformation;

vii) the political decision to build a new power plant with an initialcapacity of anywhere from 50 to 150MW was taken by the newPresident. His goal was to have the new power plant online byMarch 1995, both to be able to use the natural gas, and to ensurethe security of electricity supply for the elections scheduled duringthe last quarter of 1995.

Compagnie Ivoirienne de Production d’Electricité (CIPREL) is the firstIndependent Power Producer (IPP) to operate in the power sector ofCôte d’Ivoire with a capital investment of 9.2 billion FCFA.


The initial installed capacity of CIPREL was set at 165 MW and was tobe built in two stages:

i) the first stage, composed of three gas turbine units of 33 MW each,was built as planned, and was commissioned in March 1995 at atotal cost of 36.7 billion FCFA. This stage was entirely financedthrough private resources;

ii) the second stage, which was to consist of two additional units of33 MW each, was to be financed from an InternationalDevelopment Association (IDA – World Bank) credit to the govern-ment of Côte d’Ivoire, on loan to CIPREL. This scheme wasdesigned to reduce the overall financial cost of the project in orderto reduce the final tariff of the electricity generated by CIPREL.After International Competitive Bidding (ICB), it was decided toacquire a single unit rated at 111 MW for a total cost of about 20billion FCFA. This second stage has been online since mid July1997.

The final installed capacity of CIPREL has been increased to 210 MW.Under the CIPREL Agreement, the state has pledged to buy all of theelectricity generated by CIPREL on an annual ‘Take or Pay’ (TOP) basisfor a total of 1410 GWh per year at a cost of about 11.5 FCFA per kWh.The CIPREL Agreement was signed for a period of 20 years, at whichpoint the power plant will be transferred to the state.

The CIPREL Agreement established a system of bonus and malus, inwhich the annual energy supplied by CIPREL is either superior (bonus)or inferior (malus) by 5 per cent to the annual contractual quantity ofenergy. This bonus and malus system does not include the carry overof the energy that was not supplied by CIPREL. When the annualquantity of energy not supplied by CIPREL is greater than 5 per cent ofthe contractual annual quantity of energy, but less than 50 per cent ofthe same, the energy that is not delivered by CIPREL is carried over forthe future contractual years. However, every four years, the sum ofcarry-over energy is set to nil. If during two consecutive contractualyears the energy delivered by CIPREL is less than the contractualenergy, the CIPREL Agreement is automatically cancelled. In otherwords, when the annual generation by CIPREL is less than 5 per centbelow the annual contractual energy, CIPREL is lightly penalized bythe state. On the other side, when demand requires CIPREL to generatemore than the annual contractual energy by up to 5 per cent, CIPRELis rewarded for this extra effort; by sharing the profit generated with


the state. However, when CIPREL is not able to satisfy its contractualobligations, that is if it is not able to generate at least 95 per cent of theannual contractual energy, CIPREL has the obligation to generate at nocost to the state, the paid energy it was not able to generate during theprevious years.

The CIPREL project was negotiated by direct agreement:

• the first stage of the project was to be built through privatefinancing, and this could lead to high electricity tariffs;

• since the World Bank has been pushing for the introduction of IPP,it agreed to lend the state funds that could be used to implementthe second stage of CIPREL;

• the combination of commercial loan and soft IDA loan to CIPRELcontributed to reduce the tariff from 15 FCFA per kWh for the firststage (private financing), to 11.7 FCFA per kWh for the overall project.

The Azito thermal power project, CINERGY, was the second IPP to startoperating in Côte d’Ivoire. The project was awarded after followingInternational Competitive Bidding (ICB), preceded by pre-qualification.The Azito project is the natural follow-up to the success of the CIPRELproject. The state, following the general world trend, has decided to leaveall new investments in the power generation sector to private investors,while concentrating its financial resources on rural electrification, whichis socially important, but commercially unattractive.

The 420 MW Azito Project, to be developed on an IPP basis, wasofficially announced by the President of Côte d’Ivoire in February1996. Development of the project is a key element of the infrastructureinvestment programme of Côte d’Ivoire, designed to alleviate loomingelectricity shortfalls and the resulting negative effects on the country’seconomic growth.

According to the specifications of the ICB issued by the governmentof Côte d’Ivoire in September 1996, the Azito Project will be developedand implemented by the consortium, ABB/IPS, on a Build OwnOperate Transfer (BOOT) basis, for an expected initial ownership termof construction and operation of 24 years. The government of Côted’Ivoire will act, through the Fonds National de l’Energie Electrique(FNEE), as the electricity off-taker as well as the fuel supplier underlong-term power purchase and fuel supply arrangements.

The Azito Project is scheduled to be developed in three stages:

i) the first stage, composed of one gas turbine unit of rating 142 MW,was inaugurated in January 1999;


ii) the second stage, composed of another gas turbine of rating 142 MW, is scheduled to be on line in January 2000;

iii) the third and last stage, composed of either an additional gasturbine or a combined cycle steam turbine of rating 140 MW, isscheduled to be online by June 2002.

A 225 kV network to be built as part of the project is to transmit elec-tricity generated by the Azito Project. The government will financethis, but CINERGY is to be responsible for its construction. Fuel supplyfor thermal plants has always been a major priority for the operatingbudget of the power sector. During the 1990 restructuring, for instance,a specific amount was set aside for fuel supply, managed on behalf ofthe state by CIE. The government has also signed production-sharingcontracts with the various oil operating companies. In this contractthere is a scheme in which the national Petroleum Company,PETROCI, trades off its share of crude oil against natural gas, thusallowing the state to ensure a stable price of natural gas for internalconsumption. Whenever there is a financial crisis, allocation is firstmade for fuel supply before any other spending.

The CIPREL project was negotiated on a TOP basis, while the Azitoproject was negotiated on the payment of a fixed amount for powerand operation and maintenance costs, and a variable amount forenergy. The highlights of the involvement of IPPs in the power sectorof Côte d’Ivoire are as follows:

i) an Agreement was signed on 20 July 1995 between CIPREL and thegovernment of Côte d’Ivoire, and another Agreement was signedon 5 September 1997 between the Azito Power Company(CINERGY) and the government of Côte d’Ivoire. Under the termsand conditions of those Agreements, CIPREL and CINERGY areauthorized by the government of Côte d’Ivoire to construct,operate and sell electricity.

ii) the electricity will be off-taken by CIE, on behalf of the government,and revenue payments to CIPREL and CINERGY will be made byFonds National de l’Energie Electrique (FNEE) through CIE;

iii) natural gas or liquid fuel is supplied to both CIPREL and CINERGY inaccordance with fuel supply protocols agreed with the government.

The government has decided to make fuel available to CIPREL andCINERGY and other new IPPs at no cost. The fuel is purchased by theFonds National de l’Energie Electrique (FNEE), either from the nationalpetroleum company (PETROCI) for natural gas, or from the refinery


(SIR) for liquid fuel: heavy vacuum oil (HVO) or distillate diesel oil(DDO). Currently, three natural gas supply contracts have been signedon a TOP basis with oil operators in association with their nationalpartner, PETROCI:

i) the first contract, which has been in operation since October 1996,was signed with United Meridian International Corporation(UMIC), a private company under majority ownership of UMC ofTexas (USA), for a maximum of 50 BCF per day;

ii) the second contract signed with UMIC in March 1997 is also for amaximum of 50 BCF per day, scheduled to start delivery as of July1998;

iii) the third contract was also signed in March 1997 with APACHEand is for a maximum of 50 BCF per day scheduled to start deliveryas of January 1999.

New institutional and regulatory structure

With the reform, two ministries are in charge of the power sector.These are the Ministry in charge of Energy, which has the duty ofsupervising all technical structures in the power sector, and theMinistry of Finance, in charge of the financial matters of all operatorsin the power sector.

Under the new structure, EECI has been assigned new responsibili-ties. The main duties of EECI after 1990 are as follows:

i) management of all assets of the state embodied in the ConcessionAgreement of CIE;

ii) management of the financial assets and execution of the generalaccounting of the power sector;

iii) supervision of the technical operation of CIE;iv) development of the assets of the power sector;v) definition and execution after approval by the government of all

programmes for rehabilitation, reinforcement and extension of thenational grid;

vi) engineering and supervision of work executed on the national grid.

Under the CIE Concession Agreement the government, in addition tothe technical supervision done by EECI, set up three new structures:


i) le Commissaire du Gouvernement in charge of the general super-vision of all activities of EECI;

ii) the Technical Commission, composed of representatives of theMinistry in charge of Energy, the Bureau National d’EtudesTechniques et de Développement (BNETD), and EECI. ThisTechnical Commission has the responsibility:a) to prepare the tender documents,b) to evaluate the submissions,c) to prepare the contracts;

iii) the Supervisor, BNETD, in charge of supervising all works done byEECI for the engineering of projects in the Power sector.

By a decree signed by the President of Côte d’Ivoire (No. 94-244 of 28April 1994) the government of Côte d’Ivoire established the FondsNational de l’Energie Electrique (FNEE) to ensure the balanced manage-ment of financial resources of the power sector. FNEE was establishedas part of the Caisse Autonome d’Amortissement (CAA), the State Bankthat had been created for the financing and management of theforeign debt of Côte d’Ivoire. Given the need for better tracking andmanagement of the flow of funds within the power sector, the mainobjectives of FNEE are:

i) to service the debt contracted by EECI at the time when it was incharge of the development of the power sector;

ii) to make available funds for renewal and new development ofequipment;

iii) to supervise the regular payment by CIE of amounts due to thestate.

FNEE is administered by a Managing Committee made of representa-tives from the Ministry of Energy, the Ministry of Finance, the CAA,the BNETD and EECI. A Technical Committee consisting of representa-tives from the Ministry of Energy, the BNETD, EECI and CIE assists theManaging Committee on an advisory basis.

Since May 1994 a new Department has been created in the Ministryof Energy. The objective of La Direction de l’Energie Electrique et desEnergies Nouvelles (DEEN) is to implement the national policy fordeveloping and managing electricity as well as renewable energy. Assuch, DEEN’s role is:


i) to contribute to and update the execution of the national energyprogramme ‘Plan National d’Energie’ (PNE);

ii) to create and maintain a database on energy;iii) to define and publish the operating rules of the power sector;iv) to clarify the duty of each public structure operating in the power

sector;v) to supervise the implementation of all Agreements between the

government and the various operators in the power sector;vi) to define and supervise the strategy for development of the power

sector;vii) to participate in the financial management of the power sector by

helping to set the level of the electricity tariff;viii) to promote investments and private undertaking in the power

sector;ix) to define the framework for international co-operation, especially

in the area of interconnection of national networks;x) to promote the usage of new and renewable energy;

xi) to execute the national policy of energy conservation;xii) to contribute to the execution of the national programme aimed

at protecting the environment.

In March 1995, the Ministry in charge of Energy established theGroupe Spécial Programme Electrification Rurale (GSPER) 1995–6 withthe main objective of creating the best conditions for the implementa-tion of the rural electrification programme adopted by the governmentfor the period 1995–2000. As such, GSPER:

i) gives its approval to the planning and execution of each annualrural electrification programme;

ii) analyses all bidding documents and contracts;iii) makes sure all contracts are signed by the authorities in due time;iv) supervises all payments to contractors and entrepreneurs.

GSPER is composed of representatives of the Ministry in charge ofEnergy, the Ministry of Finance, the DEEN, the Direction desInvestissements Publics (DIP), the Direction des Marchés Publics(DMP), the Customs office, BNEDT, EECI and CIE.

In January 1995, the Ministry in charge of Energy established theGroupe Projet Energy Côte d’Ivoire – Banque Mondiale (GPE) with thefollowing main objectives:


i) to supervise the implementation of the conditions of the IDA loanobtained for stage 2 of the CIPREL project;

ii) to supervise the implementation of the CIPREL project and allother investments associated with the IDA loan;

iii) to co-ordinate the actions of all technical structures (EECI, BNETD,PETROCI), within the scope covered by the IDA loan.

In addition to the above-mentioned mission, the Ministry of Energyassigned new objectives to GPE in June 1995, including:

i) the examination by GPE of all problems related to the capacity ofthe existing generation units, as well the adequacy of the existingtransmission network;

ii) the supervision of all matters related to importation and/or ex-portation of electricity;

iii) the provision of advice to the government on all matters in thepower sector.

From a temporary structure, GPE was transformed within six monthsinto a permanent structure composed of representatives of theMinistry in charge of Energy, BNETD, EECI, PETROCI and CIE (on anadvisory basis). As one can see, the organization of the power sector inCôte d’Ivoire has become very complicated since the privatization ofEECI in 1990 (see Figure 3.1). While the private operators seem tooperate efficiently, things are complicated on the state side by thelarge number of structures, all of which have the administrative legit-imacy required, but which seem to overlap each other when it comesto operation of projects. As strange as it may appear, when one looksat the professionals in charge of each of these public structures, onefinds the same persons from the Ministry in charge of Energy, EECIand BNETD. Thus the need for a reorganization of the power sector of Côte d’Ivoire is pressing, and a study is currently under way tooptimize its function.

It is therefore apparent that because of rapid and unplanned privat-ization of the power sector in Côte d’Ivoire the institutional frameworkhas become inadequate to deal with the intricacies of the emergentstructure. With the introduction of two IPPs in addition to the opera-tor of the Concession Agreement, the need for a new institutionalframework has become very urgent. Conscious of the pressing need forreorganization of the power sector, the state of Côte d’Ivoire has


44

POWER SECTOR IN COTE D’IVOIRE

Government

FNEE (CAA)

CIE

DEEN

GPE

CIPREL

CINERGY

BNETD

EECI

IPP(420 MW)

IPP(210 MW)

GSPER

Ministry in charge of Energy

Management of Financial Resourcesof the Power Sector

Technical Supervision of EECIin its engineering duties

– Management of the state-owned assets operated by CIE– Development of the assets of the Power Sector– Execution of all programs for rehabilitation and extension of the network– Supervision of the technical operation of CIE– Engineering and supervision of all works executed on the network

– Operation of state-owned generation plants, transmission and distribution network,– Importation and exportation of electricity– Commercialization of electricity

Ministry in charge of Finances

Figure 3.1 The structure of the power sector in Côte d’Ivoire

launched a World Bank financed study. The conclusions of the studyare not yet available, but from the terms of reference (TOR), one cansummarize the objectives of the study as follows:

i) the proposed new organization of the power sector in Côte d’Ivoireshall take into account all of the new operators introduced sincethe first privatization in 1990;

ii) the main objective of the reorganization shall be to switch, as soonas possible, from the vertically integrated monopoly in which asingle operator controls generation, transmission, distribution andcommercialization, to a horizontally integrated system in whichseveral promoters operate distinctly in generation, transmissionand distribution.

The main characteristics of the new organization shall be as follows:

i) to ensure transparency of operation and functioning between thethree main components of operation, i.e. generation, transmissionand distribution;

ii) to ensure equal treatment for all of the operators in the powersector, from the operator of the existing equipment owned by thestate, to the new IPPs authorized by the government to produceand sell electricity to the national grid;

iii) to ensure better transparency in the importation and/or exporta-tion of electricity, which represents an annual value of about 6billion FCFA.

The new organization shall set clear guidelines for state supervision ofthe functioning of the power sector. The various existing governmentalstructures should be reorganized to make room for reduced structuresin charge of:

i) regulation and arbitration of conflicts between private operatorsand/or between customers and operators;

ii) management of financial and physical assets of the power sectorand implementation of consolidated accounting of the powersector.

On the operator side, the existence of the CIE Agreement, which expiresin the year 2005, makes things more delicate in the immediate future.However, it should be possible to accommodate the CIE Agreement


with a transitional structure in which there is a clear demarcationbetween generation, transmission, energy dispatch and distribution.

Experiences from implementing reforms

Regulatory setting

As described above, the basis for regulation of the power sector of Côted’Ivoire is the Law No. 85-583 of 29 July 1985. This law establishes astate monopoly on transmission and distribution of electricity, butallows the possibility of privatization by stating that electricity genera-tion is not a state monopoly and that private operators could partic-ipate upon authorization by the government. Although that lawallowed the government to introduce private operators into the powersector, it appears that the more private participants in the sector, themore urgent becomes the need to reformulate the law on electricity.

Even after privatization, the government continues to set electricitytariffs after consultation with all operators, be they public or private.As indicated earlier, electricity tariffs are set in order to ensure thefinancial viability of the companies operating in the sector.

Today, the operation of the power sector in Côte d’Ivoire is based onthe various agreements signed between the government and the opera-tors in the sector. The agreements for IPPs do not appear to pose anysignificant problem, given that the rights and duties of both the stateand the private operators are clearly defined and that the implementa-tion of the agreements is thus facilitated. However, one can note thatas long as an IPP is paid regularly and on time, there is no incentive forit to take part in the optimization of the financial operation of thepower sector.

The EECI Agreement entrusted the management of the power sectoras well as the development of assets and equipment to EECI, while CIEwas entrusted with the operation and maintenance of the existingnetwork. This sharing of responsibility seems logical at first sight, butin reality, the system has not been functioning as planned for thefollowing reasons:

i) there has never been a contractual arrangement between EECI andCIE on how the technical supervision by EECI of the operation ofCIE should be carried out;

ii) secondly, EECI has neither the means nor the necessary co-operation from other power sector actors needed to correctlyperform its mission;


iii) for various reasons, EECI has not been able to execute fully its con-tractual mission of the general planning of the development of thepower sector. Nor was it able to properly implement the generalaccounting of the power sector;

iv) the division of maintenance responsibilities between EECI and CIEis very difficult to implement because of the need to differentiatebetween day-to-day maintenance and major repair, rehabilitationor replacement of damaged equipment.

As a consequence of these kinds of discrepancies, EECI tends to accuseCIE of being responsible for the poor technical performance of certainequipment, with the argument that CIE did not properly execute itspreventive maintenance duties. On the other hand, CIE responds withcharges that EECI did not execute the programmed investments in duetime.

The CIE Agreement planned to designate a Commissaire duGouvernement with the responsibility of supervising the finance andaccounting system of CIE. This position was vacant for a long period(the appointment occurred in June 1997), and so there was nobody toensure that CIE supplied accurate financial information to the govern-ment. For example, while the CIE Agreement clearly specifies thatpayment by CIE to the FNEE shall occur on the fifth day of eachmonth at the latest, CIE never respected this stipulation and hasinstead chosen to make random payments. There is no means bywhich the state can verify that the amount paid by CIE is the actualamount due.

The existing institutional framework in the power sector, with CIE asthe operator of the whole system except for IPPs, and EECI as the staterepresentative for technical supervision, is inoperable. Responsibilitiesare neither clearly defined nor willingly accepted. The duties of CIE asthe operator are not clearly set. With the addition of IPPs, the statemust be able to arbitrate conflicts between operators, which is not thecase at this time.

Multiplicity of government structures

At the time of privatization, there was a complete lack of confidencebetween EECI and the various governmental agencies in charge ofsetting the new rules of the game. There were recommendations fromsome of these agencies to dissolve EECI due to accusations of misuse ofstate monopoly power and mismanagement of power sector assets. Butgiven the high professional quality of the staff at EECI, it was agreed


that EECI was the best-qualified state institution to supervise the tech-nical operation of CIE. Nevertheless, numerous new structures,described above, were established to supervise the activities of EECIand to regulate CIE.

Ideally, one or two institutions should regulate the power sector andmake transactions with the various private operators on behalf of thegovernment. However, multiple government structures operating inthe power sector have resulted in a situation where each private opera-tor can literally pick the government body with which it is comfortablein order to solve its problem with the lowest possible risk. When itcomes to real operation of all these governmental structures, onenotices that it is always the same people that are acting as representa-tives of the different companies.

Conclusions

As can be seen from this chapter, the privatization of the power sectorin Côte d’Ivoire was performed very rapidly, without specific prepara-tion. This privatization was the first major reorganization of the powersector in SubSaharan Africa. It involved a transfer from a state-ownedcompany to a privately owned company and was done without areduction of staff in the two new companies.

After privatization the maintenance programme of the steam units ofVridi-1 power plant was able to resume, with the support of the majorfinancial lending agencies (CFD, ADB and World Bank). Performanceof the new private operator is judged by various means:

i) based on the technical data supplied to the government by CIE,the payment of bills by private consumers has not shown the sharpincrease expected by privatization;

ii) by the account of CIE, the quality of service has been improved byreducing the annual hours of service interruptions from a peak ofmore than 70 hours to less than 20 hours. Some experts argue thatthe 70 hours quoted by CIE is for 1990, when the whole countrywas experiencing political and social turmoil. They maintain thatexcepting the period 1983–4, the performance of EECI has beenless than 18 hours of outage per year.

The main conclusion that one can draw from the experience of Côted’Ivoire is that each country should initiate reforms of its power sectorat its own pace. It is crucial to ensure the existence of the appropriate


electricity law and governmental structures to regulate and superviseprivate operators, avoiding overlapping institutional objectives andmandates.

In Côte d’Ivoire, the financial stability of the power sector has beenrestored, and in this sense one could argue that the privatization wassuccessful in achieving one of its major goals.


4Power Sector Restructuring inGhana: Reforms to PromoteCompetition and Private SectorParticipationMichael A. Opam and John K. Turkson

Introduction

The power sector of Ghana was institutionalized in the early 1960sunder the Electricity Department of the then Public Works Departmentof the Ministry of Works and Housing. Since then, the sector hasevolved as a public monopoly. In 1967 the Electricity Department wastransformed into the Electricity Corporation of Ghana (ECG), also afully state-owned electricity distribution enterprise.

The Volta River Authority (VRA), currently the only power generat-ing company (referred to hereafter as generator), appeared on the sceneunder the Volta Development Act of 1961. VRA built the firsthydropower plant in 1965. This was then followed by the constructionof a very extensive national transmission grid under the ownership ofVRA. The Northern Electricity Department (NED) was also set up in1987, as a semi-autonomous distribution company under VRA, to takeover responsibility for electricity distribution in the northern part ofGhana from ECG.

Quite recently however, a number of significant changes havetaken place in the power sector, as part of the process of re-structur-ing to create competition and encourage private investment in theelectricity supply industry. The ECG has been transformed into aprivate company limited by shares to be subsequently broken up intodistribution concession companies. The operations of VRA have also

50

been unbundled into separate ‘business units’ for its hydropowergeneration, transmission services and distribution businesses in theNED operational area. The unbundling of VRA’s operations into‘business units’ is a transition to a fully unbundled power sector. Inaddition, two new generation entities, Western Power CompanyLimited and Takoradi Power Company, both thermal plants,beingdeveloped as private–public investment ventures, have appeared onthe electricity market. The appearance of these new generators wouldenhance competition in the generation business.

On the end-user side, the Ashanti Goldfields Company (AGC), thesecond largest single consumer of power in Ghana, has put out arequest for bids for the supply of power to its gold-mining facilitiesunder a long-term contract. New generators (besides VRA) are free tobid for the supply of power to AGC and would be licensed under thenew market arrangements to do so.

While all these developments are underway, a new power sector reg-ulatory law has been passed establishing a Public Utilities RegulatoryCommission (PURC) to regulate the delivery of public utility servicesincluding electricity. An Energy Commission Bill has also been passedby Parliament. The Bill provides legislative backing for the new struc-ture of the electricity market and regulation of the technical aspects ofthe operations of electric utility companies.

The power sector of the country is undergoing sweeping reforms. Thischapter discusses the ongoing reforms. It specifically looks at thereasons behind them, the programme and process of their implementa-tion, the contractual and pricing arrangements in the new market,issues related to the maintenance and regulation of the technicalintegrity of the system and finally presents lessons learnt in the process.

Motivation for reforms

The general economic decline in the country in the late 1970s andearly 1980s, the creation of a dynamic institutional environment inthe energy sector, the growing difficulties with traditional financingsources and the imminent appearance of Independent/Private PowerGenerators have worked together to provide the impetus for the reformof the electric power sector of Ghana.

General economic decline and macroeconomic restructuring

The Ghanaian economy, which has always depended on the exportof primary products, chiefly cocoa, gold and tropical hardwoods and

Michael A. Opam & John K. Turkson 51

lumber, enjoyed the largest per capita income in SubSaharan Africa atindependence in 1957. The rapid economic growth after indepen-dence could not be sustained at the turn of the 1970s and early1980s. The worse period of economic stagnation occurred betweenthe mid 1970s to the early 1980s evidenced by negative growth ratesin Gross Domestic Product (GDP), decline in agriculture and indus-trial output and rapid deterioration in infrastructure (Hutchful,1996).

In terms of economic indicators, Ghana registered negative GDPgrowth rates between 1980 and 1983, during which time per capitaGross National Product declined by about 17 per cent, exports earningsby over 53 per cent, and gross domestic income by about 17 per cent.External debts rose by 17 per cent while the country’s internationalreserves declined by about 12 per cent (Kapur, et al., 1991).

The severe degeneration in the economy triggered the govern-ment’s Economic Recovery Programme (ERP) in 1983, which was sub-sequently consolidated into the Structural Adjustment Programme(SAP) in 1986. Since then the economy has been growing at anaverage of 5 per cent per annum. The ERP and SAP saw the revamp-ing of the infrastructural and institutional base of the country inwhich the power sector was given priority attention. The new think-ing led to innovative institutional changes in the energy sector of thecountry.

Government divestiture strategy

The second factor has been the government policy on divestiture. Avery important component of the SAP has been the strategy of privatiz-ing public sector enterprises to reduce government’s involvement incommercial activities. In view of this strategy, Parliament, in 1993,enacted the Statutory Corporations (Conversion to Companies) Act461 which established the basis for converting 35 state-owned compa-nies into public limited liability companies. Act 461 was enacted as acore element of the government’s strategy to encourage private sectorparticipation and investment, reduce direct government control ofoperations, improve efficiency, and reduce government expenditure inseveral spheres of economic activity, including energy services.Included in the 35 state-owned companies covered under Act 461 isthe Electricity Corporation of Ghana, the main electricity distributioncompany in Ghana. The provisions of this Act gave legal backing for

52 Restructuring in Ghana

restructuring of the whole sector in order to redefine the new role ofthe electricity distribution company.

Growing demand and constraints in power supply

The third factor that has brought about reforms is the rapidly growingdemand and the need to remove bottlenecks in the supply network ofelectric power. The general deterioration in the economy in the early1980s combined with the effects of oil price rises and prolonged andsevere drought during the period led to the most difficult era in thehistory of the country’s energy sector. By 1983 power generation haddeclined to only 30 per cent of its 1980 level and the distribution infra-structure had deteriorated badly. Indeed the power sector has sincebeen characterized by power shortages causing overall productivitylosses to the economy.

Domestic consumption of electricity has also seen substantial growthin the last few years, spurred on by positive economic growth and thenational electrification scheme. At the national level annual growthreached 13 per cent in 1993. Recent load forecast studies suggest thatpeak demand on the Ghana system would double in 10 years requiringover 2000 MW of peak capacity compared to the present peak demandof 980 MW.

Difficulties with traditional financing sources

A fourth and indeed a major factor that has inspired reforms are thegrowing difficulties with financing new infrastructure projects, such aspower projects, from traditional sources. It is estimated that overUS$1.5 billion will be required over the next decade to finance infra-structure developments in the electricity sector. This involves US$1.2billion for new generation capacity to meet domestic consumption ofelectricity, which has been growing at an average rate of about 10 percent per year in the last decade. Over US$100 million is also requiredfor transmission expansion and reinforcements. The required invest-ment in improving distribution infrastructure alone is estimated toamount to about US$100 million in the next five years while extensionof distribution networks would cost several million dollars more. Thegovernment is currently pursuing a National Electrification Scheme(NES) which is aimed at providing electricity to all communities of thecountry by the year 2020.

These major investments are needed at a time when the WorldBank, which has been the traditional financier of the power sector of


Ghana, as a matter of policy, has also been pushing for reformsdirected towards mobilizing alternative resources for power sectorinvestments. The dwindling financial resources available to meet thehuge demand for development projects worldwide have precipitatedthis push.

Appearance of independent power generators

The fifth major factor is the appearance on the electric power scene ofnew independent power generators. A number of power projects thatare currently either being constructed and/or planned are expected tobe owned by generators other than VRA, which is at present the onlygenerator of power in the country. A 300 MW thermal power plant,which became operational at the end of 1997, was constructed underthe joint ownership of VRA and a strategic private investor. Besides theVRA, other power generators are in the process of entering theGhanaian electric power market. Western Power PLC, a subsidiary ofthe Ghana National Petroleum Corporation, is financing a 130 MWpower plant to be fuelled from indigenous natural gas. The govern-ment also plans to develop run-off-the-river hydropower plants in theTano, Ankobra and Pra river basins (Western Rivers), with a combinedcapacity of 300 MW, as private sector initiatives. With the eventualappearance of new power generators on the Ghanaian electricitymarket there is a need to reformulate the ‘rules of the game’ to governthe market and enable the new entrants to compete without any hin-drances.

Of all the motivations discussed above the most compelling forreforms has been the need for greater financial resources to meet powerdemand through the private sector.

Overview of the power sector prior to reforms

Institutional structure

The management of generation and transmission activities was verti-cally integrated in the VRA while two separate companies performeddistribution activities, namely, ECG and NED. Figure 4.1 shows thestructure of the electric power market before reforms took place. TheVolta River Authority (VRA) was established in 1961 and has beenresponsible for electric power generation, transmission and sales inbulk. VRA owns and operates the national transmission lines and also asubsidiary, Northern Electricity Department (NED), which is responsi-


ble for electricity distribution in the northern parts of the country.There was only one distribution company, Electricity Corporation ofGhana (ECG), in the country until 1987 when NED was created.Currently, ECG provides services to about 400 000 consumers in thesouthern part of the country. Sixty-seven per cent of ECG’s consumersare concentrated in the three largest cities of Accra, Kumasi and Tema.

The second distribution company, (NED), is a semi-autonomousunit, established within VRA to manage the Northern Grid ExtensionProject and to undertake the distribution of electricity to final con-sumers in the Northern Regions of the country. Northern ElectricityDepartment (NED) serves about 30 000 consumers in the northern partof the country. Other major consumers supplied directly by VRA,under bulk supply agreements, include:

(i) VALCO Aluminium Smelter which consumes about 45 per cent ofpower generated in Ghana;

(ii) several large mining and industrial consumers that are supplieddirectly from the transmission grid;


Imports

NED

Mines,LargeIndustries

Exports(Togo,Benin)

ValcoECG

VRA Transmission–Limited Access

HV Consumers Distributors

VRAHydro

VRADispatchCentre

Figure 4.1 Old industry structure

(iii) exports to the power utilities in neighbouring countries (CIE inCôte D’Ivoire and CEB in Togo/Benin).

Ghana’s power system is connected with Côte d’Ivoire on the west andTogo/Benin on the east. Future plans include a 225kV line to intercon-nect the grid to Ouagadougou (SONABEL of Burkina Faso).

The Ministry of Energy and Mines (MME) has ministerial oversightresponsibility for the power sector. In discharging its functions, theMME also played the role of a regulator especially in the area of electrictariff review and approval.

Supply and demand performance

Installed capacity and generation

The Ghana Electricity Supply Industry (ESI) plays a very important rolein the socio-economic development of the country. In 1993 per capitaconsumption of electricity was estimated at about 190 kilowatt hours(kWh). Per capita electricity consumption has grown steadily in thepast five years at an annual average rate of 9 per cent.

The total installed generation capacity for public electricity supply inGhana is estimated at about 1122 Megawatt (MW), of which 95 percent (1072 MW) is from the Akosombo (912 MW) and Kpong (160 MW)hydropower plants on the Volta River. The construction of theAkosombo station commenced in 1961 and was completed (912 MWcapacity) in 1972. Commercial production of power began in 1965.The Akosombo dam has a storage volume of 148 000 million cubicmeters and the surface area is almost 8500 square kilometres. Bothhydro plants are owned and operated by VRA. Total diesel generationcapacity on the grid is less than 50 MW, of which 30 MW is from theTema Diesel Plant. Table 4.1 shows the installed generating capacitybetween 1992 and 1996.

Electricity generation by the Ghana ESI suffered a serious decline in1983 as a result of drought. Generation dropped by about 40 per centbetween 1982–3. It reached its lowest level in 1984 when generationwas only about 36 per cent of the 1982 level. However, it picked upfrom 1985 upwards and by 1989 had reached its 1982 level.

Transmission and distribution system

The existing National Transmission Grid System comprises close to2800 km of 161 kV lines. Transmission losses are estimated at about 3.2 per cent of total energy transmitted. The existing network for


distribution of electricity comprises over 120 km of 33 kV sub-transmission systems, 450 km of 11 kV distribution circuits within themajor urban centres, and approximately 900 km of other lower voltagedistribution circuits for retailing of electricity. Public electricity supplyand distribution in the southern sector of Ghana is operated by theElectricity Corporation of Ghana (ECG), and the VRA’s NorthernElectricity Department (NED) handles the northern sector operations.Table 4.2 shows the installed distribution lines in Ghana in 1991 and1992.

Distribution losses are estimated at about 19 per cent. This is madeup of technical losses and non-technical losses (commercial losses) duemainly to pilferage, non-payment, theft, un-metered suppliers, anddefective meters.


Table 4.1 Installed generating capacity (MW)

Generating Station 1992 1993 1994 1995 1996

Hydro SystemsAkosombo 912 912 912 912 912Kpong 160 160 160 160 160

Thermal SystemsTema – – – – 30

Total 1072 1072 1072 1072 1102

Source: VRA Annual Report, 1996.

Table 4.2 Installed distribution lines in Ghana (1991–2)

1991 1992

kV per kilometre installed225 kV 57 114.8161 kV 221 442.4

69 kV 375 749.2

Transformer capacity 16 043 32 085


Trends in electric power consumption

Per capita electricity consumption is estimated at less than 200 kWh.Electricity consumption, however, has been growing rapidly over thepast decade reaching about 6657 GWh in 1996, outstripping thegeneration from the country’s available capability which amounted to6 626 GWh. Ghana has recently become a net importer of electricityfrom neighbouring Côte d’Ivoire.

The largest consumer of electricity in the country is VALCO, an alu-minium smelting company. VALCO’s share of total consumption,however, has declined in the last six years, from 59 per cent in 1991 to39 per cent, as a result of the reduced generating capacity from thehydropower plants caused by unfavourable hydrological conditions.Other industrial consumers, including the mining companies,accounted for about 28 per cent of electricity consumed in the countryin 1996. The mines alone accounted for about 13 per cent of total con-sumption in 1996. VALCO and other industrial consumers includingthe mines, with a combined share of about 68 per cent, constitute thelargest category of consumers of electricity in Ghana.

In 1996, the residential sector accounted for 26 per cent of total elec-tricity consumed in Ghana. Electricity consumption by the residentialsector has grown consistently over the past six years at an average rateof 14 per cent per year. This sector is expected to continue to showstrong growth in the future.

Commercial consumers, such as offices, shops, institutions andhotels account for 5–6 per cent of total electricity consumed in thecountry. This sector, however, has shown consistent growth in con-sumption over the past six years, averaging 15.5 per cent per year.

Demand and supply gap: export and imports

Ghana’s power system is connected with Côte d’Ivoire and Togo/Benin. The interconnection between Ghana and Togo is provided by adouble circuit 161 kV line while a 225 kV line connects Ghana(Prestea) and Côte d’Ivoire. The Ghana–Côte d’Ivoire line is capable ofsupplying a demand of 100MW and has been in operation since 1983.Table 4.3 shows the supply of power between Ghana and her intercon-nected neighbours.

The power supply position of Ghana, however, has moved from aposition of surplus to one of deficit. Since 1994 power supply transac-tions between Ghana and Côte d’Ivoire has been in favour of Côted’Ivoire.


Regulation and management

Tariffs

Electricity tariffs were set between the Ministry of Energy and Mines,VRA and ECG. The VRA development Act provides for VRA to set itsown tariffs as contained in article 21, section 4. In the case of ECG, theECG decree of 1967 paragraph 11 (1), (2) and (3) makes provision for itto operate along commercial lines and ECG’s tariffs must cover the fullcost of operation but also ensure that it receives a ‘fair value’ of itsassets, a reasonable return measured by taking net operating income asa percentage of the fair value of fixed assets in operation plus an appro-priate allowance for working capital. In determining what constitutes areasonable return, all pertinent economic and financial considerationsshall be taken into account.

The current procedure is that the utilities make tariff proposals to theMinistry of Energy and Mines which reviews and revises the proposedtariffs in consultation with the utilities. Thus the Ministry plays a regu-latory role in tariff setting. The agreed tariffs are then submitted to theCabinet for approval. Following Cabinet approval, the tariffs, especiallythe level of taxes built into the tariff, are sent to Parliament for finalapproval.

Electricity pricing

Electricity tariffs in Ghana have undergone a number of structuralchanges after Coopers and Lybrand Associates conducted the firstmajor tariff study in 1987. Before then the structure of tariffs in the


Table 4.3 Trends in power supply between Ghana and her neighbours (in GWh)

1989 1990 1991 1992 1993 1994 1995 1996

ImportsCIE 8.4 – – – – – 319 228CEB 16.51 3.52 0 0 0 0 0 0

ExportsCIE 89.85 12.86 449 409 84 18 0 0CEB 335.65 52.08 359 485 311 400 284.8 348.1


country had remained unchanged since 1976. Following the study,Coopers and Lybrand recommended a new tariff structure based on theLong-run Marginal Cost (LRMC) concept. They also proposed a newclassification of consumers based on the groupings of consumers whoimpose similar costs on the system. The classification had previouslybeen based on economic activity. They further recommended thatresidential consumers be grouped by level of consumption. The tariffswere progressive with provision for lifeline consumption of 50 kWhper month.

After the Coopers and Lybrand study, ACRES International ofCanada carried out a major study on tariffs in 1990–2. As part of thestudy, the Coopers and Lybrand recommendations were reviewed.ACRES International indicated that the inverted block rate structurethat was recommended was difficult to administer and was an ongoingsource of customer dissatisfaction. ECG had found itself unable to readall meters on an ongoing 30- or 31-day cycle. This tends to push somecustomer readings over their point at the end of the required cycle,meaning that the incremental consumption is charged at a higher ratethan if the meter were read on time.

The study recommended the use of ‘Adjusted LRMC’, that is LRMCthat is adjusted to cater for the financial requirements of the utilities.They further recommended that apart from the introduction of thelifeline supply tariff, the residential tariff structure be collapsed into asingle energy rate. Thus, besides the lifeline, the other four categoriesbe collapsed into one.

To address any timing issue associated with meter-reading and theapplication of a lifeline supply tariff to the first 50 kWh, the lifelinesupply could be converted to a daily use (50 kWh per 30 days) andapplied to the number of days between meter readings. In January1992, new tariffs based on Acres recommendation, and actively sup-ported by the World Bank, were introduced.

Since 1994, there has been a shift from the LRMC concept to a morefinancially based tariff concept whereby the only critical factor in tariffformulation is ensuring that the utilities are able to cover all costs andalso make a rate of return (ROR) on Average Re-valued Net Fixed Assets(ANFA) of 8 per cent. The 8 per cent target reflects the convenantreached with the World Bank in the provision of a loan facility to con-struct the Takoradi thermal power plant in Ghana. One of the majorproblems with this approach to rate-setting is that there is no incentivefor the utilities to reduce or eliminate waste (internal inefficiencies) toreduce cost of electricity supply.


In addition, the residential customers are classified into four cate-gories, including a new lifeline customer class with consumption below100 kWh per month. The residential customers therefore face an incre-mental tariff structure similar to that recommended by Coopers andLybrand. Industrial customers also face a peak and off-peak tariff struc-ture but have the option for time-of-use meters or a flat surchargewhile a Power Factor Surcharge (PFS) has also been introduced tosupport power correction in the industries (mainly HV and LVconsumers).

Spatial discrimination in tariffs

Electricity tariffs are uniform throughout the country. One of thestated objectives of the power sector development is to have uniformrates for all customers who are served under similar conditions, regard-less of geographic location or suppliers. The objectives of uniformtariffs are to facilitate regional development and to reduce the imbal-ances between urban and rural areas.

Planning and investments

Planning for the total electric power system has been done by the VRAwith the assistance of consultants. The participation of other stake-holders has been very limited. Significant investment has occurred inGhana, most of which has been financed from foreign loans guaran-teed by government. Major foreign sources have been the World Bank,the United States of America, the United Kingdom, the CanadianInternational Development Agency (CIDA) and the AfricanDevelopment Bank, just to mention a few.

Cost and financial performance

Since 1989, the performance of State-owned Enterprises (SOEs) hasbeen governed by a Performance Contract, which the SOEs sign withgovernment. The performance-contracting concept was created as partof the SOE Reform Programme under the government’s StructuralAdjustment Programme introduced in 1986. The performance con-tracting idea is to ensure that the utilities change their managementpractices and improve upon their performance. Table 4.4 is a summaryof the technical and financial performance of the VRA.

VRA’s financial performance before reforms has been generally satis-factory. Sales and net profits have both grown over the past five years.However, it is important to note that the depreciation of the cedi(exchange rate increases) has worked in favour of VRA in terms of its


62

Table 4.4 Summary of performance of VRA

1989 1990 1991 1992 1993 1994 1995 1996

FinancialSales (¢m) 28 899 37 233 45 872 58 450 72 636 89 190 170 35 213 016Net Profit (¢m) 12 442 11 929 15 790 18 940 16 171 2821 32 303 33 926Operating Ratio (%) 44 46.7 57.9 70.2 56.3 N/A N/A N/ADebt Service 3.39 3.61 4.07 4.55 3.35 2.39 1.87 2.79Current Ratio 1 1.3 1.0 1.0 1.32 1.24 1.87 2.57Receivables 2.0 2.0 2.2 3.2 N/A N/A N/A N/ADebt/Equity 0.27 0.26 0.22 0.20 N/A N/A N/A N/AROR on ANFA (%) 9.6 10.2 8.3 6.7 6.0 3.8 6.17 5.21TechnicalGeneration (GWh) 5231 5717 6106 6599 6291 6101 6129 6622Energy Sales (GWh) 5125 5541 5912 6377 6207 N/A N/A N/ASales/Employee (GWh) 2.2 2.0 2.3 2.6 2.5 N/A N/A N/AGen. AvailabilityAkosombo (%) 89 92 96 98 N/A N/A N/AKpong (%) 95 86 98 98 N/A N/A N/ATransmission Losses (%) 2.4 3.1 3.2 3.3 2.1 3.16 2.72

Note: ¢m – Million cedis; N/A – Not Available.Source: VRA Annual Report, 1996.

sales revenue given the fact that over 50 per cent of sales are paid inforeign exchange.

While sales and net profits have grown, VRA’s rate of return on re-valued average fixed assets in operations has declined from 9.6 per cent in1989 to 6 per cent in 1993. In 1991 the fixed assets of VRA were re-valuedand this, combined with the low tariffs approved for 1992, resulted in thelow rate of return recorded in 1992. Other reasons for the decline in RORare the gradual increase in operating expenses, which increased by aboutthree times between 1989–93. The increases in operating expenses were aresult of a general escalation in price due to the cedi devaluation (12.6 percent between 1990–1991), and salaries and wages adjustment.

Except for its operating ratio, which has worsened from 44 per centin 1989 to 70 per cent in 1992 and 57 per cent in 1993, all the otherfinancial and technical indicators have shown consistent improve-ments over the past five years. Over the same period, ECG recordedincreases in sales every year with sales rising from ¢9.633 billion in1989 to ¢27.678 billion in 1992. Even though sales increased consis-tently, the corporation’s net profits declined leading to substantiallosses in 1990 and 1991 before recovering to positive net profits in1992. The losses in 1990 have been attributed mainly to depreciationin the value of the local currency (cedi) which resulted in increasedloan interest and high exchange fluctuation charges. Table 4.5 is asummary of the financial and technical performance of ECG.


Table 4.5 Summary of performance of ECG (1989–92)

1989 1990 1991 1992

FinancialSales (million) 9633.2 10 880. 14 243 27 946Net Profit (million) 305.6 (1121.6) (4065.1) 4151.07Operating Ratio (%) 78 95 137 5Debt Service Ratio 1.28 0.29 2.28 2.7Current Ratio 3.50 1.50 2.28 2.75Debtor/Sales Ratio 0.42 0.42 0.49 0.39Debt/Equity Ratio 0.89 1.14 0.47 0.62

TechnicalEnergy Sales (GWh) 1206 1249 1403 1565Sales (GWh)/Employee 0.39 0.42 0.49 0.58Operating Cost/kWh 7.10 8.50 12.32 14.34Distribution Losses (%) 17 20 19.90 20

Source: ECG Annual Report, 1992.

Nevertheless, the major problem that ECG has faced over the pastfive years is basically low tariffs approved by government. The tariffshave often been too low and thus unable to ensure the financialhealth of the corporation. However, some of the operationaldifficulties of the utility have to do with the management control ofcertain operational elements resulting in: (i) high debtor to salesratio (ii) high operating ratio and (iii) high distribution losses. ECG’sdebtor to sales ratio is relatively high (49 per cent in 1992 up from42 per cent in 1991 and 39 per cent in 1989 and 1990). This is aresult of very low debt collection and subsequently low revenuegeneration for ECG.

Reform programme and process

Objectives of the reforms

Essentially, the issues that had to be dealt with at the initiation of thereform process were:

(i) How to introduce more effective commercialization and competi-tion in the operations of the existing power utilities;

(ii) How to encourage private sector investment in the power sectorthrough the establishment of independent power productionschemes, and the provision of an ‘open access grid’ to facilitatedirect electricity sales by independent power producers to consumers;

(iii) How to establish a regulatory framework that would ensure trans-parency and enable healthy competition to occur in the powermarket and provide incentive-based regulatory mechanisms forthe regulated segment of the industry.

The approach used in the re-structuring programme in Ghana hasbeen influenced by the government’s emphasis on ‘private sector par-ticipation’ and not outright privatization or sale of assets of existingutilities. The Ghanaian experience recognizes the strengths of theexisting public electric power companies and intends to build onthem rather than dissipate them. The primary focus, therefore, hasbeen to create a market in which both public and private electricpower generators would coexist on the merit of their capacity toperform efficiently.

The reform programme was carried out in 3 main phases covering anumber of steps and milestones.


Phase I

Diagnostic studies. As a first step in the process, the Ministry of Minesand Energy, in December 1993, engaged the services of a consultant tostudy the opportunities for restructuring the Ghana power sector toenhance competition and efficiency. The consultants (SYNEX ofSantiago, Chile) concluded their study in June 1994 in which they pro-posed a new power market for the country.

Sector policy letter. On the basis of the diagnostic studies, a sectorpolicy letter was prepared. The document laid out the sector objectives,institutional guidelines and regulatory principles. The letter was theactual beginning of a comprehensive policy drive towards reforms inthe power sector.

Phase II

Establishment of the Power Sector Reform Committee (PSRC). Followingthe work of the consultants and their recommendations, the Ministryof Mines and Energy set up a Power Sector Reform Committee (PSRC)to co-ordinate the design and implementation of reforms in the powersector following the recommendations of the consultants. The PSRCwas made up of eight members representing the private sector, theMinistry of Mines and Energy and the electric power utilities (VRA and ECG). The PSRC took over all responsibilities for the reform pro-gramme from then onwards.

The Terms of Reference (TOR) of the PSRC sought specifically todevelop the detailed strategy and agenda for the reforms by

(i) defining a regulatory framework for establishing and revisingprices and tariffs for public electricity supply in a transparentmanner;

(ii) establishing a stable and comprehensive legal and institutionalframework to enhance transparency in the regulation of powersector operations by the state.

The PSRC, in carrying out its work, used Task Forces with members drawnfrom the utilities and the Ministry of Mines and Energy and chaired by amember of the PSRC. Consultants were used very sparingly.

Formation of task forces. On the basis of the report and findings of thediagnostic studies in June 1994, the PSRC established two task forces to


develop further the recommendations of SYNEX Consultants. TaskForce I was to review and develop the necessary tools for the opera-tional technicalities of the reform programme, particularly pricing andcommercial organization of the power market. SYNEX Consultantsassisted this task force. Task Force II was responsible for reviewing thelegal implications of the proposals for the reform and was assisted byLeBeouf, Lamb, Greene and MacRae Attorneys of Washington DC, USA.

Following the work of the two task forces, a workshop, involvingmost of the stakeholders, was organized in August 1996 in Accra todiscuss the proposals emerging from the work of Task Forces I and II.Participants were drawn from a cross-section of the business commu-nity (both local and foreign), including representatives from the Mines,VALCO and all Energy sector institutions. Also invited for the work-shop were some international organizations including the World Bankand International Finance Corporation (IFC).

Review task forces. Following the workshop, a number of task forceswere set up to address specific issues emerging from the stakeholders’,conference and to make recommendations for implementation. ThisReview Task Force comprised the following: (i) Distribution Task Force,(ii) Grid Code Task Force and (iii) Consumer Services Task Force.

Phase III

Power sector reform implementation secretariat. The PSRC subsequentlyconsolidated the findings of the various task forces into a report andrecommendations, which were submitted to government. A secretariatwas established to co-ordinate implementation of the recommenda-tions. The secretariat prepared the necessary bills and model contractsfor generation and distribution concessions.

New industry structure and trading arrangements

The ultimate objective of the reforms is to create a framework forenabling a competitive and unbundled industry structure to evolve.Figure 4.2 shows the proposed framework.

Generation

The following are the key elements of the power generation market asenvisaged under the reforms:


(i) The generation of electricity is open to other generators besidesVRA. A framework has been developed to allow competitive marketstructure to evolve, where electric power supply would be procuredon a competitive basis;

(ii) The Volta River Authority (VRA) would compete as a generatorand would not be privatized. Thus both private and public elec-tric power generators would operate in the market;

(iii) Electric power generators can trade power among themselves orsell power directly to distribution enterprises, major consumers,intermediaries, or the system.

Transmission

The transmission system is to be operated by a publicly ownednational grid company as an ‘open access’, ‘non-discriminatory’facility. This implies that all generators and distributors will haveaccess to its use based on agreements reached with the grid company.The institution of the transmission system as a ‘common carrier’


Figure 4.2 New industry structure

IPG IPGVRA

Hydro

Economic LoadDispatch Centre

GELDIC

Mines,LargeIndustries

Exports VALCO

IPP – Independent Power GeneratorsGELDIC – Economic Load Dispatch Centre

Legend

VRA – Volta River AuthorityWPC – Western Powers Co. LtdLTC – Long-Term Contract

National Transmisson company – ‘Open Access’

De-Regulated Market(Demand >5 MW)

Regulated Market(Demand <5 MW)

CapitalConcession

SouthCentralConcession

SouthEasternConcession

SouthWesternConcession

NorthernConcession

facility is critical to enhancing competition in the restructured market.On the other hand, however, the wholesale competition is limited asonly distribution concessions and large consumers have access rights totransmission services.

Distribution

Distribution companies are to provide unbundled transmission at dis-tribution voltages and sell electricity to retail customers within andoutside their traditional service areas. Like the transmission company,the distribution companies have a common carrier obligation on theirwire services. Some progress has been made at this level with regard toimplementation of the reforms. ECG has already been transformedinto a limited liability company to be operated initially as a holdingcompany with autonomous distribution concession companies. Thecountry has been divided into five distribution concessions: (i) capitalzone (ii) south-central (iii) south-eastern (iv) south-western (v) north-ern. The distribution concessionaires purchase power in bulk for distri-bution to smaller consumers within their franchise areas.

The division of the country into five concession zones has beenbased on reasons of economic and management efficiency. Before thereforms the organization of ECG was too centralized, geographicallytoo unwieldy and difficult to manage. Data on customers and assetswere not precise, making it extremely difficult for operational andfinancial management of the corporation.

The concession zones were demarcated to ensure that each zone had arevenue base large enough to survive as a separate economic entity. TheNED area, which is currently a low density area but fast-growing, was leftintact. Breaking it up further would mean the newly created concessionswould not have adequate revenue base. As the area grows, however, newconcessions could be created.

Final consumers

Final consumers, on the other hand, have been divided into two maincategories: (i) de-regulated market and (ii) regulated market.

De-regulated market

The de-regulated market would consist of all consumers with demand5 MW or more. This market is currently made up of nine consumers.Consumers in this market include Volta Aluminium Company(VALCO) (approximately 350 MW), Ashanti Goldfields Company (70 MW) and Wahome Steel (14 MW).


Regulated market

This market comprises consumers with a demand of less than 5 MWand who are served by the five distribution concessions. This categoryof consumers consists primarily of residential, commercial and smallindustrial consumers. There are about 400 000 of such consumers inthe five distribution concessions, and over 90 per cent of them are inthe categories of residential and commercial consumers. These cus-tomers are generally captive to the distribution concession companiesas they do not have access to other power suppliers because they donot have rights to use the utilities’ transmission facilities.

Economic Load Dispatch Centre (GELDIC)

At the heart of the new market is the issue of co-ordination of transac-tions and physical operations in the market. This activity would beundertaken by the Ghana Economic Load Dispatch Centre (GELDIC)which would specifically be responsible for co-ordination and dispatchin the whole system. The basic objectives of the GELDIC are thefollowing:

(i) to preserve the electricity system’s reliability,(ii) to guarantee the operation, at a minimum cost, of the system’s

generating/transmission installations,(iii) to facilitate the shared use of the transmission systems by the

various generating entities, (iv) to invoice the electricity transfers amongst generating companies.

The management of the GELDIC is to be made up of representatives ofall generators, distributors, operators of the transmission grid and thePublic Utilities Regulatory Commission.

Contractual and commercial arrangements

Generation market

Before reforms, VRA was the only company that generated electricpower in the country. It generated electricity from its own powerplants and also imported extra energy from Côte d’Ivoire for sale toVALCO, and to the Electricity Corporation of Ghana for distribution tothe domestic market. VRA also sells power to some mines and indus-tries. Under the reforms, the market is going to have a larger number ofplayers, both generators and distributors. The contractual arrange-ments in the generation market are discussed below. Figure 4.3 showsthe framework for such contractual arrangements.


Generator to generator trading

Contractual arrangements. Generators can trade power among them-selves in the event of unforeseen difficulties afflicting any one of thegenerators. Such a situation may be one of the following: (i) economyenergy, (ii) scheduled outage service, (iii) unscheduled outage service,(iv) deficiency service, and (v) operating reserve service. This would bea mutual agreement among the generators themselves. Indeed thearrangements would be a ‘paper transaction’ since physically therewould be no difference.

On the other hand, it may sometimes be expedient for hydro facili-ties in the system to purchase energy from thermal power producers inorder to firm up the hydro energy supply. For example, the Takoradithermal plant, owned by VRA and a strategic investor (CMSGeneration), could enter into a long-term contract with VRA hydro tosupply power to it in order that VRA can provide the maximum firmenergy capability from its hydro plants. It would also enable VRAhydro to supply firm energy close to its long-term average energy of6100 GWh as against its actual firm energy of 4800 GWh. Pricing for


Figure 4.3 Contractual arrangements

WPC(130 MW)

VRAHydro

GELDIC

EconomicDispatch

VRA/CMSThermal

(300 MW)

LTC

LTC (PPA)

LTCLTC

National Transmisson Company – ‘Open Access’

Regulated Market(Demand <5 MW)

CapitalConcession

SouthCentralConcession

SouthEasternConcession

SouthWesternConcession

NorthernConcessionMines,

LargeIndustries

Exports VALCO

CMS – CMS Generation, MichiganGELDIC – Economic Load Dispatch Centre

Legend

VRA – Volta River AuthorityWPC – Western Powers Co. LtdLTC–Long-Term Contract

De-Regulated Market(Demand >5 MW)

energy transfers between generators should be negotiated. It should,however, not be less than the system short-run marginal cost.

Generator to de-regulated market

Contractual arrangements. Beyond being able to trade power amongthemselves, generators can sell power to the de-regulated market on along-term contract basis. The current arrangements under which VRAsells power to VALCO under a long-term contract (negotiated about 30years ago) is a typical example of this type of ‘Generator-DirectCustomer Arrangement’. The contract was recently renewed foranother 20 years and VRA would continue to honour the contractunder the reforms. Customers in the de-regulated market are free tonegotiate their supply and prices with generators.

Generator to regulated market

Contractual arrangements. VRA, by law, is required to provide ECGand NED with all their power needs. VRA has since been supplyingECG and NED under contract and would continue to do so under thenew market environment.

Besides VRA, other generators (private or public) can sell power tothe regulated market. An example of a case where another generatorbesides VRA can sell power to the central dispatch for supply to theregulated market is the current arrangement that Western PowerCompany Limited (WPC) has entered into. WPC has signed a PowerPurchase Agreement (PPA) with the government guaranteeing to supplyall the power from its 130 MW barge-mounted power plant through thedispatch centre to complement hydropower.

Pricing arrangements

Procurement of electric power to serve the public would occur throughthe regulated market and prices would be regulated on the basis of thesystem short-run marginal cost (SRMC) concept. The SRMC conceptstipulates that the only costs relevant in deciding how much toproduce in plants already constructed, with production capacityalready installed, are variable costs of operating that plant. This pricingconcept is in conformity with the principle of least-cost operation ofthe power supply system. In terms of actual operations, procurementof power supply would be on the basis of ‘economic merit order dis-patch’ under which generating units are dispatched, with prioritygiven to those generating units with the lowest energy payments.


Generally, bulk power prices to the regulated market would consistof two components:(i) capacity charges and (ii) energy charges. Thecost of the single-cycle gas turbine will be used as the benchmark forpricing capacity and energy since it is considered the most efficientsource of additional power supply to any well-adapted power supplysystem.

Transmission services

Contractual arrangements

The transmission company will have a loose type of contractualarrangement with all generators and distributors. This is necessary toprovide services for transmitting all their power supply require-ments. However, the contractual obligations would be reviewedannually, or when necessary, to conform to the actual requirementsof the system.

Transmission service pricing

Transmission pricing affects the operational and investment decisionsmade by the entire industry, as the provision of transmission servicesplay a central role in the supply of electricity. The objectives of trans-mission pricing should, therefore, be to provide a reasonable rate ofreturn to shareholders while maintaining its physical assets in a safeand reliable condition. In terms of operation, transmission pricesshould be calculated in order to maximize the benefits of the systemoperation by correctly signalling short-run costs so that users are awareof the costs that their load or generation imposes on the transmissionsystem. Transmission pricing should also meet the objective of fairness.Since electricity transmission is a natural monopoly, the fairnessconcept is to allocate charges to users fairly. On the basis of theseobjectives, the appropriate price structure for transmission services canbe broken into 1assets-related costs, energy-related charges, and 2trans-mission network charges.

It is important to reflect all these costs in transmission prices. Whileit is important to ensure fairness in setting transmission prices, it maysometimes be better and less cumbersome to charge uniform averageprices for transmission services. In the case of Ghana, transmissionservices would be on the basis of uniform average prices, at least duringthe transition to the fully competitive regime when transmissionpricing could be based on the SRMC concept. Transmission charges aretherefore based on cost recovery of transmission assets and operation


and maintenance costs averaged over total energy transmitted. Theimplication is that all kWh of energy transmitted have the same trans-mission charge.

Distribution market

This market is made up of both a de-regulated and a regulated market.

De-regulated market


The customers in the de-regulated market (direct consumers such asthe mines and industries whose demand is up to 5 MW and above) arefree to enter into contracts with any generator or the transmissioncompany for the supply of its requirements. The primary concern ofthese consumers is to obtain electric power that is reliable with regardto supply and at prices which are transparent, objective and pre-dictable.

A typical case is well illustrated by Ashanti Goldfields Company(AGC). AGC has recently sent out a request for proposals for the supplyof power to its mines on a long-term contract basis to start in 1999.VRA, WPC and other IPPs have sent proposals to AGC for the supply ofpower under this new arrangement. This represents a case where alarge consumer in the de-regulated market can source its own powersupply from any generator who either has some installed capacity inthe system already or is a new generating company.

Large consumers such as Wahome Steel Mill are also in the process offinding dedicated power suppliers on a long-term contract basis.

Regulated market


The regulated market is to service the general public through distribu-tion companies. The distribution companies would consist of conces-sion areas. The country has been demarcated into five concessionzones or areas: (i) capital concession, (ii) south-central, (iii) southeastern, (iv) south western concession, and (v) northern concession.These concessions would provide electricity to all consumers withdemand less than 5 MW including domestic, commercial and smallindustrial consumers. All concessionaires are obliged to serve all con-sumers within their concession areas.


Distribution service pricing

Distribution companies would be paid a Distribution Service Charge(DSC). The DSC is based on the concept of distribution added value(DAV) which stipulates that distributors are paid a margin that reflectsthe value-added of distribution services they provide. Economicefficiency requires that distribution costs are calculated as the long-run marginal cost (LRMC) of the activity since the magnitude of thenon-variable component of distribution costs is small. Furthermore,for a given density of the grid, it is possible to calculate LRMC as theaverage cost (monthly capital plus O&M costs per kW) of an efficientmodel distribution grid of that density. These two concepts serve asthe basis for distribution pricing under the new electric power marketin Ghana.

The value-added of distribution service would be regulated on thebasis of an efficient enterprise model. The reference model establishes astandard for efficiency for an optimal size in the high-medium or low-density zone classifications for power distribution companies. Thisstandard encourages utilities to match or exceed the reference level ofoperating efficiency, and thus maximize their profits. The DSC hasthree basic components: (i) distribution infrastructure capital cost; (ii) operation, maintenance, administrative, billing and other costs notrelated directly to consumption; and (iii) peak period losses. Thesethree components are used in devising formulas for the various tariffoptions for consumers.

This pricing formula would ensure general transparency in tariffs,especially as it tries to separate costs associated with distribution ser-vices from those associated with transmission services and generationsupply. Before reforms, tariffs had been set based on the concepts ofLRMC which also sought to ensure a rate of return of 8 per cent onaverage re-valued net fixed assets (ANFA) and a minimum debt serviceratio requirement of 1.4. Under the reforms, subsidization of low-income residential consumers (lifeline tariffs is currently practised)would be continued. The subsidization of residential consumption, ifnecessary, should be explicit.

Maintenance of system integrity/regulation

There are three dimensions to the maintenance of system integrity: (i) legal, (ii) regulatory, and (ii) system operation and planning.


Legal environment

Even though macroeconomic factors such as stability in interest rates,falling inflation and foreign exchange policy are imperative for avibrant private capital investment market, the regulatory and legalenvironments governing the business environment provide a verystrong impetus for promoting private capital flow into the economy.This is especially so when investments are in such highly capital-intensive infrastructure sectors as the electric power industry. The legalenvironment is most critical because it provides the basis for theenforcement of regulations or ‘rules of the game’ governing the opera-tion of the market.

Three approaches to the legal issue were considered. The firstapproach is to enact a single comprehensive electricity law whichdefines all aspects of the industry in detail, including regulation andinstitutional arrangements. The electricity laws in the UK and Chile arefashioned along these lines and indeed many private investors aremore comfortable with this approach, which does not leave any ambi-guity. Another school of thought views this approach to be too rigidand not easily amenable to change if ever it becomes necessary to doso.

In the second approach a simple electricity law is enacted to providejust the right framework for the industry but give the executive (forexample the Minister responsible for Energy) the mandate to regulatethe sector by separate legislative instruments. This enables the execu-tive to change regulations governing the industry easily when theydeem it necessary. Private sector investors are generally apprehensiveof this approach since the issue of regulation is left with politicians andis not predictable.

The third approach is where a comprehensive regulatory law isenacted outside the existing electricity law. The focus of this approachis actually towards formulating an appropriate regulatory frameworkand leaving the existing electricity law intact, transfering of regulatorypowers to an independent regulatory body.

The choice of approach will depend to a large extent on the legalenvironment existing in the country. The third approach has beenadopted in Ghana. Two new Acts have been passed: the Public UtilitiesRegulatory Commission (PURC) Act 1997 and the Energy Commission(EC) Act 1997. These Acts have created two institutions: the PublicUtilities Regulatory Commission and the Energy Commission. The


VRA Act has been amended only to remove the regulatory power ofVRA while the Electricity Decree has been repealed with the transfor-mation of ECG into a company limited by shares.

Regulatory framework

In general, regulatory safeguards in the electric power industry arenecessary in four key areas:

(i) Control of entry (Licensing);(ii) Price-setting,

(iii) Prescription of quality and conditions of service;(iv) Imposition of an obligation to serve all applicants under reason-

able conditions.

The ‘rules of the game’, as regulation may be called, may be stipulatedby contract and/or legislation. Where there is limited experience ofregulatory institutions, the rules may be set out in detail in the elec-tricity law that creates the regulatory scheme. On the other hand,where there exists an independent judiciary with a reputation forimpartiality and enforcement of private property rights and contractsit is best to consider using the license or contract to achieve the sameregulatory objectives. Both approaches have their ‘pros and cons’. Inany case, it is widely believed that it is crucial to institutionalize theregulatory process in order to reduce the number of conditions thatneed to be included in contractual arrangements for private powerprojects.

In Ghana regulation has been institutionalized through the PURClaw and the EC law. The two institutions (PURC and EC) created underthese laws provide the institutional oversight for the regulation of thewhole system and the enforcement of compliance of operationalobligations. The PURC would also be responsible for the regulation ofelectricity and water. Telecommunications, petroleum products andnatural gas would be added as and when necessary.

The regulatory powers of the PURC would specifically cover thefollowing:

(i) Tariff-setting;(ii) Ensuring compliance of the obligation, for all concessionaires, to

serve all consumers in their area of operation;(iii) Arbitration of disputes between power utilities or between power

utilities and customers.


The Energy Commission (EC) would be responsible mainly for licensingand development of rules to cover the technical operation of the utili-ties. These are to be embodied in a ‘Grid Operations Code’. The ECwould also provide policy support for the Ministry of Mines and Energy.Before the reforms, utilities had self-regulating powers. The statute thatestablished VRA gave it the mandate to set its own tariffs and decide itsoperations. Similarly ECG had the power to set up its own tariffs andalso license new generators except VRA. Practically, however, electricitytariffs were regulated both by the Ministry of Mines and Energy andParliament. The tariff-setting process required that VRA and ECG maketariff proposals to the Ministry of Mines and Energy for approval. TheMinistry vets the tariffs in consultation with the utilities, followingwhich it is sent to Parliament for ratification before it becomes effective.

Under the reforms the PURC would be directly responsible for pro-viding guidelines on tariff-setting and approving tariffs withoutrecourse to government or Parliament. The PURC is independent anddoes not report to anybody, not even the President. The PURC insetting tariffs, however, would open the tariff issues to public hearingand special representations from stakeholders.

Tariffs are to be set with due consideration for the interest ofinvestors and consumers and the financial integrity of the utility com-panies. These concerns in setting tariffs have been specified in thePURC law. As discussed earlier in this paper, generation procurementwould be based on SRMC, transmission services would be regulated onthe basis of a TSC which would reflect SRMC of transmission while dis-tribution tariff regulation would be based on the DAV of a ‘referenceefficient’ distribution company.

Technical integrity of system operation

The technical integrity of the system is regulated by a grid operationscode. The grid operations code, in effect, contains the guidelines, rulesand procedures for the effective operation of the whole system to safe-guard the reliability and quality of electricity supply to all customers.The code covers the following:

(i) system operation and planning;(ii) scheduling and dispatch;

(iii) connection.

The details of these are specified in the National Grid Operations Code,the administration of which is the responsibility of a Grid Code


Committee. Members of the Committee are representatives of all gen-erators, transmission companies and distributors while compliancewould be enforced by the Regulatory Commission. The code would bereviewed and updated periodically.

Managing the transition

The key transition issues that the reforms present are: (i) institutionalengineering; (ii) tariff; (iii) extension of national grid and ruralelectrification issues.

Institutional engineering

The primary concern for managing the transition period is to ensurethat the institutions can continue to survive financially as thesystem is moved from wholly monopoly institutions to market-oriented institutions. The transitional arrangements for a fullyunbundled system involve the de-integration of VRA generation andtransmission into separate ‘business units’ with different accountingand management operations. This involves the de-coupling of gener-ation and transmission assets and operations. ECG will be trans-formed into a liability company with a new board of directors. Theintention is to move ECG towards a more commercial and business-like operation with the aim of improving ECG’s overall financialstanding to attract private sector participation in this segment of theindustry.

Tariffs

Reforms and re-structuring invariably bring about higher tariffs as akey objective of reform is to enhance efficient pricing and tariffs. Thisobjective may be at variance with the bottom-line interest of cus-tomers, which is to see tariffs that are reasonable, fair and above allaffordable. The objective of ensuring proper transition to the fully re-structured market is to minimize the negative impacts of tariffincreases, especially for poorer/low-income consumers. During thetransition period, cross-subsidies, especially to ensure a reasonablelifeline tariff, are to be maintained.

Rural electrification

Another transition issue is how to deal with investment in theelectrification of rural areas. A major objective of the government’spolicy is to make electricity accessible to the entire population of the


country by the year 2020. Currently it is estimated that 35–40 per centof the country has access to electricity. Rural electrification would con-tinue to be the prerogative of the government, in which case extensionof electricity to rural communities would be carried out with conces-sionary loans contracted by the government for that purpose.

Some key lessons and challenges

Lessons

A number of lessons have been learnt in the process of initiating andreforming the power sector of Ghana that may prove useful to othercountries who are in the process of reforming or are contemplatingreforms in their electricity supply industry.

First, there is the need for the government’s macroeconomic policyto articulate the role of private investment as a priority objective.Other macroeconomic instruments such as (i) exchange rate policies,(ii) interest rate policies, (iii) financial and economic (tax) incentiveshave to be clearly defined. All these are important ingredients forattracting private capital investment.

Second, the ‘political will or commitment’ of the government toimplement policies must be unambiguously demonstrated. More oftenthan not, politicians themselves have been the most elusive impedi-ments in privatization efforts. Such commitment from the politicalauthority calls for ‘demythifying’ the ‘myth’ and the beliefs regardingthe power sector in particular and the energy sector in general, whichare deeply ingrained in most political authorities in SSA and a largesection of the population. Among these, it is worth mentioning con-cepts such as energy self-sufficiency and energy independence, the‘strategic’ nature of certain energy resources and the common accept-ance of arbitrary subsidies in fuel prices and electricity tariffs due totheir being ‘essential inputs’.

Thirdly, there is the need to develop appropriate policy frameworksand implementation plans for reforms. This process, however, shouldnot be exclusively controlled by the utility companies. The group thatis mandated to carry out the reforms should be a multidisciplinary(possibly led by the private sector) group. Under no circumstanceshould the responsibility for the design, development and implemen-tation of reforms be vested in the existing utilities, especially in thecase where they are monopolies, simply for the reason that they havea vested interest in the outcome of the exercise. Nevertheless, theyshould be involved in the exercise. This is exemplified in the setting


up and the composition of the PSRC. The process has been spear-headed by a multidisciplinary group (Power Sector Reform Committee)made up of private individuals, academics, and the executive arm ofgovernment represented by the ministries and the electric powerutility agencies. The reform or re-structuring processes in many coun-tries are being led by the public utilities themselves while in othercases reform has occurred by executive orders. A very important aspectof the committee’s work was to acknowledge from the outset thatthere are no miraculous short-term, easy, quick and low-cost solutionsto the power sector problems, and that it is only possible to handlethe tasks successfully if there is wide support from all stakeholders inthe sector.

Fourthly, the management of the whole process is a challenging task,both with regards to conceptualization and implementation, and itrequires time. This process has to evolve. This requires the formulationof well-defined goals and objectives that show the difficult measureslikely to be adopted. This would ensure that the process evolves in theright direction, and also brings concrete, rational, achievable and fairsolutions, rather than short-lived improvisation of high cost solutionsfor some sectors of the population. The process in Ghana recognizesthis fact and therefore opted for a process that relies on careful consid-eration of all aspects of the reform process.

The fifth lesson is the adoption of a realistic strategy for implement-ing different decisions based on the reform. Implementation strategiesmust minimize the adverse impacts of decisions such as tariff increaseson consumers. Such sensitivities may not have been seriously consid-ered in the recent (May–June 1997) tariff increase which caused anational uproar, and which caused the President to intervene tosuspend its implementation. This was clearly an example of a manifes-tation of bad implementation strategy of a good policy. The issue hereis that electricity rates are definitely going to go up and a suitable strat-egy is needed to implement the tariff increases without causing anynegative public reaction.

Finally there is the need to seek assistance from people who havebeen involved in similar exercises before to ensure that avoidable mis-takes are not made.

Challenges

While the government has undertaken an elaborate and meticulousprocess to restructure the power sector, and mapped out strategies to


manage the transition, the challenge now is how to guide the imple-mentation process and make the restructured industry work. One ofthe major challenges is for the Ministry of Mines and Energy to easeitself out of the regulatory role and allow the PURC to function. Forthe credibility of the reform process and the PURC, involvement of theministry should be at a minimum. The other challenge is the potentialof regulatory capture by the big actors in the market. This is a real pos-sibility in the present situation where the industry has no history of aformal regulatory system and processes such as those being tried now.The ability of the PURC to shake off any such attempt – overt or covert– would depend on the capacity of the Commission constantly toextract information from the actors in the market (mainly generators,transmission and distribution companies), evaluate the quality of theinformation, process the information and monitor the performance ofthe power market.

Conclusion

The cornerstone of the reform is to allow competitive market princi-ples to operate in the generation segment of the industry, while thetransmission and distribution segments are regulated by an indepen-dent regulatory body. This regulatory body would institute incentiveregulatory regimes for the operators in those segments of the indus-try, and also meet the government’s objective of making electricityaccessible to all Ghanaians by the year 2020. The reform has theadditional objective of improving the quality of service to all classesof customers in the country. The extent to which these objectives arerealized will determine the ultimate success of the reform of thepower sector.

Notes

1 Asset-related charges consist of a connecting point charge, transmissionnetwork charge and demand-related charges.

2 The transmission network charges are constituted by (i) a spinning reservecharge and, (ii) an overhead charge. The spinning reserve charge recovers thecost of providing spinning reserve and interruptible load. Spinning reserve isrequired to provide cover against sudden losses of generation on the system.The alternative to keeping a spinning load is to shed load without notice fora limited duration which results in much higher costs associated withunserved energy.


References

Hutchful, E. (1996). ‘Ghana 1983–1994’ in Poul Engberg-Pedersen, PeterGibbon, Phil Raikes and Lars Udsholt (eds), Limits of Adjustment in Africa,(Centre for Development Research/James Currey).

Kapur, I., Hadjimichael, M. T., Hilbers, P., Schiff, J., & Szymczak, P. (1996).Ghana: Adjustment and Growth – 1983–1991 (Washington, DC: IMFOccasional Paper No. 86 September).

VRA (1996). VRA Annual Report.


5Power Sector Reform: A KenyanCase StudyStephen Karekezi and Donella Mutiso

Introduction

Motivation and rationale of study

For many years, Kenya has faced many problems with its power sector.Some of the key problems include:

– unreliable power supply; – inefficient operation of power utilities; – failure to meet growing demand for electricity resulting in frequent

power outages; – inability to extend electricity to a large proportion of the country’s

population;– financial losses; and, – failure to generate sufficient revenue to finance the power sector

investment programme.

Current power sector literature underlines the importance of powersector reform (that is ownership changes, unbundling of the utilities,legal and regulatory reform) as an important option for addressing theproblems faced by power utilities in Africa and other developingcountries. Of particular interest has been some form of private sectorparticipation. This can take place in several forms. Examples includecontracting-out services such as rehabilitation, maintenance, meter-reading and bill collection etc.; contracts for operation and manage-ment of the entity; joint ventures with government utilities, based on competitive bidding; and private equity investment in power

83


corporations or new projects and outright sale of existing power sectorcompanies.

Structural changes may take the form of vertical or horizontalunbundling of the power sector. Regulatory reform usually impliessome form of institutional restructuring that often results in the estab-lishment of an independent regulatory body and design of incentive-based regulatory schemes as well as related legal reforms. There arethus many options available and choices to be made if Kenya is tochoose the reform path that best suits its own economic, political andfinancial characteristics.

The on going reforms in Kenya’s power sector are the focus of thischapter with the aim of sharing Kenya’s experiences in power sectorreform with other countries in SubSaharan Africa. Figure 5.1 highlightskey elements of the paper’s conceptual framework.

84 Experiences in Kenya

Figure 5.1 Conceptual framework of the study

The energy sector

Kenya’s energy sector is one of the most important sectors in thecountry. Its performance has a direct impact on the general economy.During the 1995/96 fiscal year, Kenya Power and Lighting Company,KPLC (Kenya’s main power utility) contributed sh 1.86 billion (US$31 million) in the form of various taxes and dividends to thenational revenue (Kenya Times, 1997a). For comparitive purposes, US$31 million is equivalent to about 10 per cent of what, on average,Kenya earns from tea, its leading export crop. Conversely, broadchanges in the national economy have a major impact on thecountry’s electricity industry. For instance, real GDP growth declinedbetween 1989 to 1993 due to structural policies; the 1991–3 drought;foreign exchange shortages (this affected the Kenyan power industry’sability to import necessary machinery and equipment); and,unfavourable external terms of trade. These factors, in turn, impactednegatively on the energy industry triggering several problems in thesector (Republic of Kenya, 1995a).

In Kenya, wood fuel is the most prevalent source of energy for allsectors except the commercial and transport sectors. It accounts forapproximately 70 per cent of the total energy demand (Bhushan, 1995;Republic of Kenya, 1995b).

Petroleum is in next most important energy source and accounts forabout 21 per cent of the total energy demand (EIU, 1996; Republic ofKenya, 1995b). Up until very recently, Kenya had not discovered anyexploitable resources of oil or gas. There has been a recent discovery ofpetroleum that still remains uneconomic to exploit. The Mombasa-based Kenya Petroleum Refineries operates the country’s sole oilrefinery, which meets most of its crude oil needs from the United ArabEmirates (EIU, 1997).

Ethanol accounts for less than 1 per cent (Nyoike and Okech, 1992)of Kenya’s energy requirement. It is produced as a by-product of sugarrefining in western Kenya and is used for blending with petrol. Sinceonly a small quantity is produced, it is consumed only in Nairobi andnearby areas.

Electricity is the third largest in terms of energy demand in thecountry. It accounts for about 8 per cent of total national energydemand. Installed capacity in 1995 was about 808.7 MW (CentralBureau of Statistics, 1996), a tenfold increase in the installed capacityof 79 MW at independence in 1963. The sources of electricity include

Stephen Karekezi and Donella Mutiso 85

hydro, geothermal and thermal/diesel (Bhushan, 1997; Republic ofKenya, 1997). Electricity from the Ol-Karia geothermal plant isexpected to supply a larger proportion of the country’s electricityrequirements in the future. Currently, geothermal accounts for 45 MWor about 5 per cent of the country’s total installed electricity capacity.It is estimated that the country’s installed capacity of geothermal-basedelectricity could increase to about 320MW by the year 2015 (KenyaEnergy Review, 1990). The table above shows the increase in installedcapacity during a four-year period.

The country’s installed capacity went down marginally from 808.7 MW in 1995 to 805.0 MW in 1996, as a result of a fall of hydro-based installed capacity by 0.7 per cent. This was attributed to mechan-ical problems at Kindaruma dam.

Other alternative energy sources include biogas, solar energy andwindpower. A small amount of coal is used in the cement industrywhere it acts as a substitute for petroleum. Kenya has a large potentialof solar and wind energy, which have economic potential for meetingfuture energy requirements for rural communities. At least 40 000 pho-tovoltaic units have been sold by the private sector since 1987(Karekezi and Ranja, 1997). Wind energy is used in a limited scale.Currently some 200 wind pumps are in operation, many of them man-ufactured locally. KPLC operates a 200 kW wind turbine which in 1995provided 1.1 GWh to the grid and a 350 kW hybrid wind/diesel systemto serve the electricity needs of the surrounding community (WorldBank, 1997). Figure 5.2 shows the distribution of the main energysources in Kenya.


Table 5.1 Kenya’s installed capacity from 1992–5

Year/source Installed capacity (MW)

Hydro Thermal Geothermal Total

1992 603.5 156.3 45.0 804.81993 603.5 156.3 45.0 804.81994 603.5 159.3 45.0 807.81995 603.5 160.2 45.0 808.71996 599.5 160.5 45.0 805.0

Source: Central Bureau of Statistics, 1996.

Status of the power sector

Over the last five years, the power sector has experienced several tech-nical, operational and financial problems. This has led to stagnation ingenerating capacity expansion and in transmission and distributionsystem reinforcement. Energy analysts argue that this difficult situationhas been caused by a combination of internal deficiencies and inade-quate support and investments from donors and multilateral develop-ment banks. This section gives an overview of the past and currentinstitutional structure of Kenya’s power sector. It also assesses Kenya’sdemand and supply scenario as well as some of the major problemsfacing the sector, making an attempt to show how they may be linkedto the institutional structure.

Electricity demand and supply

National electricity consumption has been growing steadily (Figure 5.3)for the last five years (Republic of Kenya, 1995b). This rise in consump-tion has been driven mainly by increased demand for electricity in the


Figure 5.2 Energy sources in Kenya

Source: Bhushan, 1997:74 and Republic of Kenya, 1995:6 1995b.

Woodfuel 70.0%

Others 1.0%

Petroleum 21.0%

Electricity 8.0%

categories of small-scale enterprises and domestic consumption(Bhushan, 1997). The Kenyan power sector is estimated to require atleast 40 MW of additional electricity generation capacity every year, ifit is to meet the increasing demand of electricity. The level of invest-ment in the sector in the last five years cannot accommodate suchexpansion (Kenya Times, 1997b; EIU, 1997).

The Least Cost Power Sector Expansion Plan prepared for theGovernment of Kenya indicates the need for an additional installedcapacity of 1288 MW by the year 2013 if projected demand is to bemet (Republic of Kenya, 1995b). This implies more than a doubling ofcurrent installed capacity. Official government documents envisagethat power sector reform combined with private sector participationwould assist in mobilizing the required investment to finance thisplanned expansion and development programme.


3500

3000

2500

2000

1500

Con

sum

ptio

n in

kW

h m

1000

500

1991 1993

Years

1995

Street Lighting and Rural ElectrificationDomestic

Off PeakIndustrial

0

Figure 5.3 Electricity consumption for the years 1991, 1993 and 1995

Source: adapted from Bhushan, 1997.

The electricity power transmission system is operated as an inte-grated network, with load and generation centres linked by both 132 kV and 220 kV transmission lines. The total circuit lengths for the132 kV and 220 kV transmission systems are 1980 km and 877 kmrespectively (Republic of Kenya, 1995b).

Institutional, legal and regulatory framework

The Kenyan government has traditionally been the pivotal actor in thecountry’s power sector. The Ministry of Energy is mainly in charge ofmaking policy related to the energy sector as a whole. The supply ofelectricity in Kenya has been, for a long time, the mandate of thefollowing five organizations, all of which are state-owned entities.


Table 5.2 Least cost generation expansion plan

Fiscal year Generation additions

Hydro (MW) Geothermal LS Diesel* MS Diesel**(MW) (MW) (MW)

1997–1998 6 × 12.51998–1999 2 × 32 1 × 50 6 × 12.51999–2000 2 × 30Sondu/Miriu2000–2001 2 × 322001–2002 2 × 45Ewaso A2002–2003 2 × 18 + 2 × 27 2 × 32Ewaso B2003–2004 1 × 502004–2005 2 × 322006–2007 2 × 322007–2008 2 × 502008–2009 2 × 322009–2010 1 × 502010–2011 2 × 32 1 × 502011–2012 1 × 502012–2013 2 × 50

TOTAL 240 MW 448 MW 450 MW 150 MW

Notes:* – Means low speed diesel** – Means high speed dieselSource: Republic of Kenya, 1995b.

– The Kenya Power and Lighting Company (KPLC); – The Kenya Power Company (KPC); – The Tana and Athi Rivers Development Authority (TARDA) and– The Tana River Development Company (TRDC);– The Kerio Valley Development Authority (KVDA).

Other important non-government institutions involved in the electric-ity sector include existing auto-generators of electricity particularly inthe agro-processing industry (e.g. sugar companies), research institu-


Figure 5.4 Major energy institutions

Source: Compiled by authorsNotes: KPLC is partly privately owned, but most of the shares are state-ownedKPLC Kenya Power and Lighting CompanyKPC* Kenya Power CompanyTARDA Tana and Athi Rivers Development AuthorityTRDC Tana River Development CompanyNOCK National Oil Corporation of KenyaKPRL Kenya Petroleum Refineries LimitedKPC** Kenya Pipeline Company

tions, NGOs and small-scale private solar electricity companies. Theagro-processors produce electricity for their own internal purposes.KPLC has always resisted buying electricity generated by other produc-ers (e.g. agro-processors) despite a general feeling within official circlesthat small-scale generation using indigenous resources should beencouraged. The figure above shows the major institutions in Kenya’senergy sector.

Created in 1979, the primary objectives of the Ministry of Energy(MOE) were initially outlined as:

– Formulation and implementation of government energy policy; – Development of hydro electric power; – Co-ordination of oil exploration activities; – Procurement of petroleum products and other fossil fuels;– Promotion and implementation of energy conservation pro-

grammes;– Development and exploitation of renewable energy technologies

such as solar, wind, biogas, geothermal and wood fuel (Okech andNyoike, 1995).

The Ministry has five divisions namely: Finance and Administration,Planning, Geo-exploration, Biomass and Engineering. The Finance andAdministration division deals with matters pertaining to finance andpersonnel. The functions of the Planning division include energydemand forecasting, supply planning, project planning, evaluation andmonitoring and pricing. The Geo-exploration division co-ordinatesexploration of petroleum and geothermal energy resources. TheBiomass division is in charge of woodfuel development and the promo-tion of efficient cookstoves and biogas. The Engineering Division is incharge of power generation planning; rural electrification; licensing ofelectrical contractors; energy conservation; and, promotion of solarand wind energy technologies (Okech and Nyoike, 1995).

The origins of the Kenya Power and Lighting Company (KPLC) dateback to 1922 (Okech and Nyoike, 1995). Before and just after independ-ence (1963), it was known as the East African Power and LightingCompany (EAPLC) which served the whole of East Africa region. TheEAPLC was started in 1922 to generate and distribute electricityproduced by thermal generators in response to the demand fromgeographically dispersed urban centres. It changed its name to KenyaPower and Lighting Company (KPLC) in 1983 through a special resolu-tion of shareholders. The present set-up and evolution of KPLC can be


seen to have evolved in response to increasing power demand and theneed for a more systematic development of the energy sector. KPLCwas responsible for the preparation of the sub-sector’s expansion pro-grammes and was the state’s executing agency for the design, construc-tion and operation of rural electrification schemes.

KPLC is a limited liability company quoted on the stock market withthe government having majority share holding (Daily Nation, 1997a).The government has 59 per cent of the shares. This includes the sharesheld by two state corporations, namely the National Social SecurityFund (NSSF) and Kenya National Assurance Company (KNAC), cur-rently under liquidation. The rest of the shares are owned by theprivate entities such as the Insurance Company of East Africa (ICEA)and private individuals (Republic of Kenya, 1995b; Okech and Nyoike,1995). Over the years, the government’s control of KPLC has beenensured through its majority ownership of the company’s shares andthe presence of Permanent Secretaries of the Ministries of Energy andFinance as well as appointees with other political and government con-nections on KPLC’s Board of Directors (Nyoike and Okech, 1996). Upuntil June 1997, KPLC held a de facto monopoly in the transmissionand distribution of electricity in the country. KPLC is run by a govern-ment-appointed board of directors which is answerable to the Ministryof Energy (MOE) on policy matters. KPLC owns and operates hydroplants at Ndula, Sagana, Gogo, Selby and Mesco as well as somethermal plants at Kipevu, all of which total about 174.38MW (about20.7 per cent of the total installed capacity in Kenya).

KPLC had, until recently, the mandate of overseeing and managingthe other organizations operating in the power sub-sector, i.e. KPC,TARDA, TRDC and KVDA. The links with these organizations havetaken different forms. KPLC provides staff to carry out administrative,technical and management functions in all the projects undertaken byKPC and TRDC. KPLC had the task of maintaining and operating theMasinga and Kiambere power facilities owned by TARDA. The Turkwellpower project was managed on the same lines, even though there wasno formal agreement on its management by KPLC. These managementcontracts required KPLC to operate and maintain in good order allplants owned by these companies and to provide the following ser-vices: engineering, legal, secretarial, personnel and office accommoda-tion. In return KPC, TRDC and TARDA pay KPLC, in addition to amanagement fee agreed upon from time to time, an amount equal tothe total expenditures incurred by KPLC in carrying out its obligationsunder such agreements (Nyoike and Okech, 1996).


Figure 5.5 shows KPLC’s organogram. For a long time, KPLC was theonly institution licensed to market and distribute electricity and, there-fore, effectively owned all the distribution facilities.

The Kenya Power Company (KPC) was created in 1954, as a de factosubsidiary of KPLC and charged with two major responsibilities:

– purchasing bulk power (45 MW) from the Uganda Electricity Board(UEB) and transmit this to Nairobi

– generating electricity at a station on the Upper Tana and Maraguarivers.

It was to sell both supplies to what was then EAPL. Until 1970, KPC’sshareholders were the colonial Kenya government, EAPL and thePower Security Corporation Limited (London). The main justificationfor the establishment of KPC was the need to raise capital from the


Figure 5.5 KPLC’s organizational structure

Source: Nyoike and Okech, 1996.

KPLC Board

Managing Director

Deputy ManagingDirector

Project Development

Generation

Distribution

Corporate planning

CommercialRural electrification &internal wiring

Research and devt.

Finance

Credit control

Personnel

Transport & supplies

Administration

CompanySecretary

Internal audit

PublicRelations

ExecutiveCommittee

international markets to construct the transmission line to Uganda(Nyoike and Okech, 1996). With very little management and staff of itsown, KPC was effectively a state-created entity with the primarypurpose of attracting investment and loans that are normally restrictedto government and government-owned agencies. The bulk of its opera-tional activities were undertaken by KPLC’s staff.

KPC is wholly owned by the state (East African Standard, 1997b;Republic of Kenya, 1995b). KPC is in charge of Ol-Karia geothermalplant (about 45 MW nominal capacity), two small hydropower plants,Tana (14 MW) and Wanji (7 MW), 132 kV and 66 kV transmissionlines from the western border of Kenya to Nairobi (Karekezi et al., 1996;Republic of Kenya, 1995b; East Africa Standard, 1997b). These plantsaccount for 12 per cent of Kenya’s total installed capacity. In June1997, KPC was separately reconstituted and given the mandate to gen-erate and sell power to KPLC.

The Tana River Development Company (TRDC) was created in 1964to co-ordinate and finance hydroelectric development in the middleTana river where Kamburu, Gitaru and Kindaruma hydroelectric powerstations are located. TRDC was also in charge of the transmission linesfrom the power stations to Nairobi (ibid, 1995b). The Kindarumahydroelectric power station (44 MW) was commissioned in 1968. Upuntil 1970, the shareholding capital of TRDC was a nominal £100million sterling that was held equally by EAPLC, the Kenya govern-ment, the Power Security Corporation and the CommonwealthDevelopment Corporation. In 1970, a decision was made to sell all theequity shareholdings in TRDC to the Kenya government at the originalnominal value, to enable the government to get a loan from the WorldBank (Nyoike and Okech, 1996) for financing the development of theKamburu hydropower station.

TRDC accounts for the largest electricity generation capacity in thecountry, with a total of 280.5 MW installed capacity and 273 MWeffective capacity (Nyoike and Okech, 1996). Since KPC and TRDC didnot have any technical staff to operate and maintain their power facili-ties, KPLC provided this service and thus, effectively, transformed itselfinto the most dominant power utility in Kenya (Karekezi et al., 1996).In many respects, KPLC has been the principal de facto, monopolypower sector entity in Kenya.

The Tana and Athi Rivers Development Authority (TARDA) was for-merly known as Tana River Development Authority (TRDA). TARDAwas created in 1974 and established in 1984 to develop the Tana Riverand Athi River basins. TARDA has two hydropower facilities located at


different sites. It owns and manages the Masinga and Kiambere hydro-electric power stations. Their total capacity is about 184 MW (Nyoikeand Okech, 1996).

The Kerio Valley Development Authority (KVDA) was created in1979 with similar objectives to TARDA. It implemented the TurkwellHydro Plant (106 MW), completed in 1991 (World Bank, 1997). Thisplant accounts for about 13 per cent of the national installed capacityand about 15 per cent of the national effective capacity (Nyoike andOkech, 1996). KVDA is fully owned by the government.

In addition to these bulk producers, there are several auto-generatorsin the agro-processing industry (e.g. sugar companies and tea estates)as well as institutions and private individuals licensed to generate elec-tricity for their own exclusive use (Republic of Kenya, 1995b).

Kenya’s power sector is regulated by the following three principalActs:

– the Electric Power Act;– the State Corporations Act;– the Geothermal Resources Act.

The Electric Power Act is an Act of Parliament designed to facilitate andregulate the generation, transmission, transformation, distribution,supply and use of electric energy for lighting and other purposes. TheAct was enacted in 1920. According to the current Electric Power Act(1997), CAP 314 Section 4, ‘no public or local authority, company,person or body of persons not being a bulk supply or local generatinglicensee or an authorized distributor shall generate, transmit, con-struct, maintain or operate works for such generation or transmissionof electrical energy’ (Government Printer, 1986). According to CAP 314section 10 (1), the Minister of Energy may grant a bulk supply licensefor a period not exceeding 50 years to any public or local authority,company and person to supply energy in bulk to bulk supply licenseesor authorized distributors within the area described in the license. TheMinister in any such license may authorize the generation of electricity(Government Printer, 1986).

The State Corporations Act gives the President and the responsibleMinister wide discretionary powers over state corporations (WorldBank, 1997; GOK, 1996). Up until 1997, KPLC and KPC operated underthis Act. The Geothermal Resources Act (1982) is meant to regulate theuse of Kenya’s geothermal resources. It establishes that geothermalresources belong to the state and confers power to the Minister of


Energy to issue licenses for exploration and exploitation of geothermalresources. The Act allows the Minister of Energy to impose levies,rentals and royalties for use of the country’s geothermal resources(World Bank, 1997)

Currently, no form of regulatory body in charge of the power sectorexists. In effect, the Minister of Energy is the sole regulator of thepower sector (World Bank, 1997), but the government is workingtowards establishing a regulatory board to manage the country’s powersub-sector. The new Electricity Bill, which is discussed in the latersection of the chapter, provides for the creation of a regulatory body toregulate the activities of the power sector.

Power sector problems

Over the years, Kenya’s power sector has suffered from both institu-tional and operational (technical and financial) problems. While someof the problems faced by Kenya’s power sector are of a technical andmanagement nature, a large number of constraints faced by thecountry’s electricity industry can be traced to its unwieldy structureand complex and opaque institutional interrelationships.

The management contracts between KPLC and the other organiza-tions (KPC, TRDC and TARDA) discussed in the prior section, seemcomplex. Whether these companies possess the institutional and tech-nical capability to determine what is a fair value for the services ren-dered is an open question.

On the other hand, debt related to the acquisition of generatingassets is not incurred by KPLC but effectively remains with the otherstate power sector entities. This may, to a significant degree, explainthe rather positive financial status of KPLC. TARDA and KVDA areRegional Development Authorities (RDAs) which do not have anyspecific mandate over activities in the power sector. They seem to beinvolved in the power sector simply because hydropower resourceshappen to be in their area of jurisdiction. This complicates the institu-tional framework. With the exception of KPLC, many of the other statecorporations involved in the power sector have been operating at a loss and regularly require injections of financial support from the statetreasury. Table 5.3 below shows the operating income of some powersector companies.

The trends shown in Table 5.3 indicate poor financial performance,which is partially linked to the complex institutional relationshipbetween the organizations listed. Of particular importance is the


ability of KPLC to pass on investment-related liabilities to other statepower corporations while using these assets to generate revenue foritself.

Kenya’s power sector has, for a long time, suffered from intermittentelectricity supply, frequent blackouts, power rationing and illegal con-nections. In 1994, the system losses were estimated to be 15.4 per cent(Gutiérrez, 1996) compared to the international standard of about10–12 per cent. Contrary to popular opinion, power rationing tohomes and industries is as much a headache to KPLC as to consumers,since it directly translates into lower sales.

The sub-sector has suffered from a decline in electricity imports fromUganda (Republic of Kenya, 1995a) and has also experienced capitalconstraints for new power installations. The decline of the electricityimports from Uganda has been mainly due to increased power demandin Uganda and the continual reluctance to provide power because ofthe very low tariffs paid by the Kenyan counterparts.

According to an agreement made in 1955, Uganda was to supplyKenya with 30MW, daily at a fixed rate, for 50 years (i.e. up to the year2004). Uganda has been supplying power to Kenya at a rate of two UScents per unit for over 35 years whereas it spends six US cents toproduce a unit of electricity. On the other hand the Uganda ElectricityBoard (UEB) currently supplies Rwanda and Tanzania with power at acost of 8.25 US cents and 8 US cents per unit, respectively. Ugandanshave called upon their Kenyan counterparts to revise these tariffs madethrough a colonial agreement, by agreeing to pay market rates for thepower (The New Vision, 1996a). In October 1996, a new arrangementbetween the two countries was put into place. Uganda now suppliesKenya with a minimum of 10 MW of power between 5am and 6pm at6.50 US cents per unit and as much power as Kenya requires at night


Table 5.3 Operating income of power sector companies (ksh million) from1986–1991

Year KPC TRDC KPLC Total

1986/87 –23 –209 135 –971987/88 –86 –109 93 –1021988/89 262 –51 309 5201989/90 26 –330 79 –2251990/91 64 –167 139 36

Source: Nyoike and Okech, 1996.

(off-peak times) at 6 US cents per unit (The East African, 1996).Uganda’s domestic and industrial demand for power has shot up to220 MW, while power generation has slumped (The New Vision,1996b), thus making it unrealistic for the country to provide as muchpower to Kenya as it did before.

Lack of sufficient maintenance on the interconnected-grid systemhas led to a number of break-downs. Some of the equipment, such asswitch-gear in some substations, are old and underrated. The droughtof 1995–6 further aggravated the power shortages. System operationshave been constrained due to insufficient reserve margin and furtheraffected by the damage suffered by one of Gitaru’s generating unitswhich took about a year to repair (World Bank, 1997). Because of rapidurban population growth and housing growth, some sections of thedistribution network are overloaded. These sections are affected by lowvoltages and increased network losses (Republic of Kenya, 1995b). Theaforementioned factors reduced the available capacity to between 570 MW and 670 MW while peak demand varied from 650 MW to 680 MW. The gap between the peak demand and available capacitynecessitated load shedding during the peak hours.

Frequent power outages and rationing have had a very negativeimpact on Kenya’s industry. For example, audited accounts of Kenya’smain cement factory in Mombasa showed that the company had tocancel some vital export business due to power rationing. Thecompany was forced to install large and expensive generators to meetits electricity needs. The increased production costs eroded the returnon the company’s turnover substantially (East African Standard, 1997a).

For many years, the average electricity tariff remained substantiallybelow the economic and financial cost of supply. As a result, the powersector experienced financial difficulties which impacted on its ability toservice external debt obligations (World Bank, 1997).

Reform options

The problems faced by the electricity industry in Kenya, discussed inthe previous section, constituted an important impetus for reform ofthe power sector in Kenya. Existing literature and past experience inother countries indicates that a wide spectrum of reform options exists.One of the key challenges is to identify the most appropriate optionsthat best suit the prevailing economic, political and cultural features ofa given economy. There does not appear to be a reform blueprint thatis applicable to every country.


This chapter subdivides reform options into two categories, namely:structural changes and ownership (privatization) changes. The two termsare often used interchangeably and power reform initiatives are often amix of the two. For conceptual clarity, this study defines structuralchange as distinctively different from ownership (privatization) change.Figure 5.6 attempts to portray the two reform paths in a diagrammaticform. In many cases, options on both structural change and ownershipchange axes are undertaken concurrently but, for reasons of conceptualclarity, this chapter keeps the discussion on the two reform paths sepa-rate. The underlying rationale in both cases is to improve the perform-ance of the industry by streamlining management and ensuring moretransparent oversight. Another important objective is often the intro-duction of market forces which should presumably lead to moreefficient operation. Several other measures designed to increase marketforces include freeing the entry of new actors into the power sector


Completeverticalunbundling

R

e

s

t

r

u

c

t

u

r

i

n

gVerticallyintegratedutility

Verticallyintegratedutility

National utility

MinistryDepartment

Corporatization(arm’s-lengthrelation togovernment)

Contractmanagement

Commercialization

Privatization/Ownership changes

ParastatalIPPs –Privatization ofgeneration

Privatization ofgeneration anddistribution

Complete PublicOwnership

ComplatePrivateOwnership

Provincial distributioncompanies, nationalgeneration andtransmission

Provincial distributionand generation,national transmission(Common carrier)

Complete horizontalunbundling (Provincialutilities which arevertically integrated)

Unbundledgeneration anddistribution

Unbundledgeneration,commontransmissionand distribution

Figure 5.6 Structural change and privatization

market, encouraging competition and permitting joint ventures(Beesley and Littlechild, 1983). The prevailing conventional wisdomlargely asserts that private ownership as opposed to public ownershipalmost always results in superior performance and management.

Structural change

Structural change often precedes privatization of the power system.Structural change can take the form of vertical or horizontal unbundlingof the system (Reinier Lock, 1996). Vertical unbundling is expected tolead to separate generation, transmission and distribution units whichare treated as independent entities.

In practice, however, vertical unbundling starts with the separation ofgeneration from transmission and distribution mainly because of theease with which this can be accomplished without losing oversight andcontrol by a national regulatory agency. In theory, at least, anotherimportant objective of vertical unbundling is to separate distributionfrom generation and transmission (G&T) and free the newly indepen-dent distribution entity from G&T management, which often domi-nates vertically integrated monopolies. This form of vertical unbundlinghas been rarely implemented in Africa. Vertical unbundling is alsodesigned to bring the distribution function closer to consumers, hope-fully leading to improved service. The newly unbundled distributionunit is then expected to adopt a more independent approach and act inthe consumers’ interest when negotiating with generation and trans-mission entities. Splitting generation, transmission and distribution isexpected to facilitate relating costs to output and making managementdecisions and performance more transparent and thus easy to monitor.

Horizontal unbundling often involves dividing a national utility intoseveral vertical integrated regional or district utilities (Karekezi, Majoro& Gathu, 1996). Available literature argues that horizontal unbundlingcan bring utilities closer to the customer and thus prove more respon-sive to local needs. Depending on the original structure of the utility,horizontal unbundling may prove easy to implement by allowing easysubdivision of important generation, transmission and distributionassets. The main drawbacks of horizontal unbundling include possibleincrease in commercial inflexibility and re-emergence of monopolistictendencies at provincial and district level.

Ownership (privatization) changes

Ownership changes or popularly known as privatization is the transfer ofownership or control from the government to the private sector. The


transfer should be sufficient to vest the private operators or ownerswith substantive independent power (IFC, 1995). Ownership changesoften involve deregulation and competitive tendering, together withthe introduction of private ownership and market management.Privatization is likely to come in stages, take considerable time andmay never cover the entire power sector (Reinier Lock, 1996).Ownership patterns have evolved over the years from private to publicand recently back to private (IEA, 1994). In developing countries, thebulk (57 per cent by value) of privatization took place in the LatinAmerica and Caribbean region, followed by Central Asia with 18.7 percent. Being late starters, SubSaharan Africa, the Middle East and NorthAfrica have, to date, accounted for a relatively small share of totalpower privatization although this is changing rapidly (IFC, 1995). InNigeria, for example, private investment in the power sector was firstaccepted as recently as 1996 (Financial Times, 1997).

Ownership of power utilities can take various forms, namely:Commercialization and corporatization; Contract management;Independent power producers (IPPs).

• Commercialization and corporatization (often implemented simultane-ously) means that conduct of the business entity is based on com-mercial principles. Organizations are treated like commercialenterprises and they have to earn a market-related return on equity,conform to commercial accounting standards and be exposed to‘market discipline’. Often the payment of taxes and dividends is alsoinvolved. Corporatization and commercialization provide a way ofreforming public utilities with the aim of exposing the organizationto the discipline enforced by the market, while retaining the advan-tages of public ownership (Steyn, 1994). The process of corporatiza-tion is usually combined with commercialization, with the aim ofimproving management efficiency.

• Contract management usually involves an agreement through whichoperational control of a company or part of a company is delegatedto an external operator. In management lexicon, outsourcing of keycompany activities can be in the form of a contract managementagreement. A contract management agreement is usually formalizedthrough a medium-term contract. In some contract managementagreements, personnel from the external operating company occupysome of the companies’ key positions, but the company remains theowner of its installations and controls most investment decisions.The operating company’s intervention is generally limited to service


provision. In addition to placing high-level personnel within thecompany’s hierarchy, it may carry out one-off short-term supportmissions. The operator is paid either by the company it is managingor by financial backers and does not, therefore, bear the risks relatedto operation. When the operator’s remuneration is linked to man-agement improvement criteria (billing rate, recovery rate, and soon), the contract is called a management performance contract.Contract management has been widely practised in some industrial-ized countries. It was perceived to be an effective tool for giving util-ities more autonomy within the framework of a performanceagreement. Utilities were held accountable for desired outcomes, asmeasured by a negotiated set of performance indicators covering awider scope than simply a return on investment or electricity price.

• Independent Power Producers (IPPs) are, typically, limited-liability,investor-owned enterprises that generate electricity either for bulksale to an electricity utility or for retail sale to industrial or othercustomers. At global level, the introduction of IPPs is becoming amore widespread form of private sector intervention in the electric-ity industry. IPPs have for some time been a major source of powergeneration capacity in the United States and, increasingly, in someEuropean countries, notably the United Kingdom and Portugal. TheUSA has been a leading example both in the volume of capacityadded by IPPs and in experience with designing and implementingcontracts under which energy and power are sold to the integratedsystem. Many countries in Africa are also turning to independentpower producers to expand their electricity supply. The design of anIPP differs according to the ownership structure of the project.Typical ownership structures for IPPs in the power sector include:Build, Own, Operate (BOO); Build, Operate, Transfer (BOT) andBuild, Lease, Transfer (BLT)

The power sector reform process in Kenya

In the late 1980s, it was foreseen that new investments in Kenya’spower sector were needed in the 1990s if severe supply shortages wereto be avoided. The World Bank through its International DevelopmentAssociation (IDA) affiliate could not support new investments in theabsence of an agreement on power sector reform policies and imple-mentation programmes (World Bank, 1997). This was, in manyrespects, the single most important impetus to current ongoingreforms in Kenya’s power sector. The role of World Bank’s IDA to


Kenya’s power sector cannot be overlooked. The World Bank, throughits IDA affiliate, provided seven loans and credits totalling aboutUS$212.2 million for financing power investments in Kenya between1971 and 1988 (World Bank, 1997). It has been, for a long time, theprime financing agency for the electricity sector and has been instru-mental in mobilizing investment finance for Kenya’s electricity sectorfrom major bilateral development agencies and banks.

The World Bank’s emphasis on power sector reform and involve-ment of private enterprise in the electricity sector is driven by a beliefthat the state has generally proven to be a poor manager of productiveassets and consequently its role in the productive economy should besharply curtailed. While this view had been aggressively pursued inother sectors such as industry and agriculture, the encouragement ofprivate sector participation in the power sector of Africa is a morerecent development.

More recently, Kenya’s principal donor agencies, led by the WorldBank, have made it very clear that continued provision of financingsupport for the power sector is strictly contingent on power sectorreform and involvement of the private sector. This has been amplydemonstrated by the response of the World Bank and other bilateraldonor agencies to the initial power sector reform steps undertaken bygovernment. The World Bank pledged to provide Kshs 7.2 billion forthe reinforcement of the power sector, while the Japanese EconomicCo-operation Fund committed funds for the development of the two75 MW diesel power stations at Kipevu (East African Standard, 1997b).

Consequently, many independent analysts believe that the powersector reform process in Kenya is largely donor-driven with limitedlocal input both at the conceptual level and at the level of imple-mentation. Existing literature on power sector reform in other devel-oping countries tends to emphasize the role played by other factorssuch as:

– government commitment to privatization;– growing demand and constraints to power supply;– limited availability of traditional financing resources.

While the above factors were important in influencing the powersector reform process in Kenya, they appeared to be largely of a sec-ondary nature. The primary impetus clearly emanated from the WorldBank which was and continues to be the most important champion ofpower sector reform in Kenya.


Generally public involvement in the power sector reform process hasbeen very limited and largely restricted to feeble complaints about theincreased frequency of power outages and higher tariffs that have beenrecently implemented. With the exception of AFREPREN researcherssuch as Okech of the University of Nairobi, the involvement of indepen-dent research institutions and NGOs in the power sector debate has beenminimal. The authors believe that limited involvement of the public andcivil society has contributed to opaque decision-making in the reform ofthe power sector and may eventually undermine some of the achieve-ments that power sector reform initiative was designed to attain.

The reform process

A number of studies undertaken with the help of IDA financing andunder a Project Preparation Facility led to the preparation of theongoing Power Development Project. The total cost of the programmeis estimated at US$699.9 million equivalent excluding taxes and dutiesand interest during construction (World Bank, 1997). Many of thepower sector reform initiatives in Kenya’s electricity industry havebeen initiated by this World Bank project.

Restructuring

Vertical unbundling. Some form of vertical unbundling was already inplace in Kenya because many of the country’s electricity generationstations were owned by state river development authorities and not bythe country’s dominant utility, Kenya Power and Lighting CompanyLtd (KPLC). On the other hand, many of state river developmentauthorities had virtually no technical personnel and staff with theskills to run the power stations. Consequently, most power stationswere run by KPLC thus transforming it into a de facto vertically inte-grated power utility.

Early in 1997, KPLC’s generation assets were separated from its distri-bution and transmission facilities. Its power generation assets as well asthose of other main power companies in Kenya were transferred to thenewly formed Kenya Power Company (initially, a de facto subsidiary ofKPLC), ahead of its possible privatization (Financial times, 1997; DailyNation, 1997a). KPC will now be exclusively in charge of power genera-tion. The assets that KPC will take over include Masinga, Kamburu,Kindaruma, Kiambere, Gitaru, Turkwell Power station and other mini-hydro stations currently owned by TARDA, TRDC, KVDA, and KPLC(Daily Nation, 1997a). With the entry of independent power producers,KPC will be the biggest bulk supplier of electricity to KPLC, whose


function will now be confined to transmission and distribution. Thegovernment expects the new status of KPC to enable it to compete onan equal footing with the independent power producers for bulksupply of electricity to KPLC (Daily Nation, 1997a; and East AfricanStandard, 1997b).

KPC remains wholly owned by the state, but will now have its ownmanagement and staff. KPC’s Board and Managing Director wereappointed by the Minister of Energy in December 1996. The personneltask force was appointed in February 1997. The power purchase agree-ments between KPLC and KPC were signed in June 1997 (World Bank,1997: Annex 7.6). The government expects the takeover of assets andoperations by KPC will be conducted gradually to ensure that the tran-sition provides continuity, stability and harmony of operations in bothKPC and KPLC, and customer interests are safeguarded. Kenya’s busi-ness community are positive that the new changes will reduce thecomplexity of the relationship between the KPLC and the other powerproducers. From an investment point of view, Kenyan stockbrokersview the separation of management of generations assets from trans-mission and distribution as an extremely important development(Daily Nation, 1997a).

Privatization/ownership changes

Commercialization. The Kenya Power and Lighting Company (KPLC)has had a relatively long track-record in running itself on a commercialbasis. This is attributed to the involvement of the private sector whichowns a substantial chunk of the KPLC’s shares as well as its quotationon the Nairobi Stock Exchange. This exposes it to the oversight of theprivate sector as a well as state entities that regulate the Nairobi StockExchange. The government of Kenya underlined its commitment tothe commercialization of the power sector, in a recent Power SectorPolicy guide document that requires the power sector to operate on acommercial basis without burdening the government budget byrequesting subsidies from the state treasury (World Bank, 1997). Energyanalysts, however, pointed out that the low electricity tariffs that pre-vailed in the country for the long period, undermines the power indus-try’s ability to run on a commercial basis. In March 1994 tariffadjustment, the government allowed KPLC automatically to adjust thelevel of consumer tariffs to reflect changes in fuel prices (Republic ofKenya, 1995b; GOK, 1996). In June 1995, the government agreed tohigher end-user electricity tariffs and managed to achieve an averagetariff equivalent to 67 per cent of the long-run marginal cost of


electricity supply (Republic of Kenya, 1995b; GOK, 1996). Adjustingthe average tariff has enabled the power sector to realize an operationalprofit and raise some capital to sustain additional investments in theelectricity sector. Increased tariffs are expected to attract new entrantsinto the power market.

Contract management. The Kenya Power and Lighting Company(KPLC) has made an attempt at contracting out certain non-core activ-ities. It has contracted out security services and the construction of one33 kV sub-transmission line (Republic of Kenya, 1995b) and is activelyexamining the possibility of contracting out additional activities andtasks. On a more conventional note, the Kenya Power Company (KPC)signed an engineering consultancy services contract in 1997. The con-tract with Nippon Koei Company of Japan is for the implementation ofthe 60 MW Sondu-Miriu hydropower project (Daily Nation, 1997b).

Independent power producers. It can be argued that Kenya has had somekind of independent power industry for some time. These early inde-pendent power producers were largely limited to auto-generators ofelectricity in the agro-processing industry. Most of the auto-generatorsused the bulk of the electricity generated with very limited sales to thegrid. The majority of auto-generators were in the sugar-processing andtea-processing industries. The sugar-industry-based auto-generatorsused bagasse as the feedstock fuel for their power generation unitswhile the tea-processing industries relied on small hydro schemes togenerate electricity for their outlying tea estates and factories.

As stop-gap measures designed to address the power sector crisis thatwas affecting the country in 1995–6, Kenya signed its first privatepower scheme in September 1996 with Iberafrica of Spain andWestmont Power (Kenya) Limited to generate 43 MW and 46 MWrespectively (Financial Times, 1997). The companies would be usingthermal power units.

The Westmont Power (Kenya) Limited is a limited liability companyowned by Malaysian interests. It entered into a power purchase agree-ment in early 1997 to supply bulk power to KPLC. The generating system(situated in Mombasa) comprises of a barge-mounted combustionturbine generator, operating in single cycle, capable of generating a netelectrical output of approximately 46 MW at ISO conditions, togetherwith a 11/33 kV, step-up transformer, dead-end structure and SF6 circuitbreakers (Kenya Gazette, 1997). It will undertake generation of electricityand sell it to KPLC for distribution (East African Standard, 1997a).


The Iberafrica Plant, owned by Spanish interests, is situated inNairobi. The plant is already supplying 24 MW of electricity to KPLCfor distribution (EIU, 1997). The Kenya Power employees’ pension fundwas used to buy 1 130 000 shares worth Ksh 113 million so as toincrease local participation in the Independent Power Producing firms(Daily Nation, 1997c).

According to the East African Standard (1997c), one of the country’sleading daily papers, discussions are about to be concluded for twoother private power projects. One of the plants is a 75 MW dieselproject at Kipevu II and the other, a 64 MW geothermal project (a BOOarrangement for both), at Ol-Karia, Naivasha.

Independent Power Producers have been invited to invest $106 millionin the Kipevu II project and $195 million in Olkaria III geothermalproject. Construction of a geothermal power plant at Olkaria willearmark 800 million Kenya shillings (Indigo Publications, 1997a). Theonly funding secured for a $699 million expansion programme for1997–2001 is a loan from the Japanese Government of $83 million forKipevu 1 for which bids are now being evaluated by the designatedconsultant in the United Kingdom (EIU, 1997). Figure 5.7 attempts toillustrate various changes in structure and ownership of Kenya’s power


Complete verticalunbundling

Privatization/Ownership Changes

Restructuring

Scenario 2

Scenario 1

19971996–971995

1983

Unbundledgeneration and

distribution

MinistryDepartment

ParastatalComplete PublicOwnership

CompletePrivateOwnership

Commercialization

ContractManagement

IPPs –Privatization of

generation

Privatization ofgeneration and

distributionPrivatization of

generation,transmission and

distribution

Corporatization(arm’s-length relation

to Government)

Unbundledgeneration,

commontransmission and

distribution

Verticallyintegrated utility

Figure 5.7 Reform changes in the power sector

sector that have taken place to date, and the paths the reform is likelyto take in the future.

Legal and regulatory changes

It appears that most of the major changes to the country power sectorare relatively recent with the bulk of changes taking place between1995 and 1997. KPLC and KPC were recently exempted from the StateCorporations ACT which severely limited the entities’ managementand operational autonomy.

The new Electricity Power Bill that has just been passed byParliament and forwarded to the President for ratification is expectedto result in additional power sector structural changes. This Billamends and consolidates the laws pertaining to the generation, trans-mission, distribution, supply and use of electrical energy for lightingand other purposes. Some of the key changes that the Bill seeks torealize, as outlined in the Kenya Gazette (Bills No. 17) are reproducedbelow:

• Before applying for a licence, the applicant should give a notice by public advertisement, not more than 90 days and not less than60 days before the application is to be made.

• An application for a licence shall be submitted to the regulatoryboard for consideration and recommendation to the Minister.

• All licence applications for the generation, distribution and trans-mission of electric power shall be processed within 180 days afterthe Electricity Regulatory Board confirms to the Minister in writingthat the application is materially complete in all respects.

• Before granting a licence, the Minister shall give notice in the KenyaGazette.

• Licences to electricity power producers shall be issued for a term ofnot less than 15 years. Licences to public electricity suppliers shallbe issued for a term of not less than 30 years.

• The Minister may establish a fund (the imposition of a 5 per centlevy on all electricity consumers in the country) to be known as theRural Electrification Programme Fund to support the electrificationof rural areas and other areas, considered economically not viablefor electrification by public electricity suppliers (Republic of Kenya,1997b).

This new Electric Power bill also provides for the establishment of anElectricity Regulatory Board (ERB). The Electricity Regulatory Board


shall be a body corporate with perpetual succession and a common sealand shall be capable of suing and being sued in its corporate name.The body shall perform the function of regulating the generation,transmission and distribution of electric power in Kenya (Republic ofKenya, 1997b). According to the Kenya Gazette Supplement No. 61, thefunctions of the Electricity Regulatory Board will be to:

a) Set, review and adjust tariffs for all persons who transmit or dis-tribute electrical energy for sale;

b) Investigate tariff structure even when no specific application for atariff adjustment has been made;

c) Enforce environmental and safety regulations in power sub-sector;d) Investigate complaints made by parties on any matter required to

be regulated under this ACT;e) Ensure that there is genuine competition;f) Approve electric power purchase contracts and transmission and

distribution service contracts between and among electric powerproducers, public electricity suppliers and large retail customers.

Funding of the Board shall be obtained through a levy which theMinister of Energy may impose on electricity sales for this purpose(Republic of Kenya, 1997b). The Minister shall direct the Board onpolicy relating to the power sector (Republic of Kenya, 1997b).

The membership of the ERB, shall comprise persons with aUniversity Degree or its equivalent and not less than 15 years practicalexperience in matters related to industry, finance, economics, engi-neering, energy or law (Republic of Kenya, 1997). The Board shallconsist of the following persons:

a) A Chairman appointed by the President;b) Permanent Secretary to the Ministry for the time being responsible

for energy policy and development;c) Five members appointed by the Minister as follows:

• Two members to represent the private sector in general;• Three members each appointed from a panel of three nominees

submitted by each of the national bodies for the time being rec-ognized by the government as representing organizations forworkers, employers and manufacturers.

According to the new bill, the Chairman shall hold office for four yearsand shall be eligible for reappointment for a further term of three


years. The other members apart from the ex-officio member shall holdoffice for three years, after which they shall be eligible for reappoint-ment for a further term of three years (Republic of Kenya, 1997b).

Experiences from implementing reforms

Kenya’s power sector is in a transition period. The key reform measure,the Electric Power Bill still awaits ratification by the President. It is,therefore, particularly difficult to undertake a comprehensive assess-ment of the reforms that have taken place to date.

In general, however, the power sector reform process has had limitedinvolvement of the public and consequently drawn criticism from theindependent press for not being a transparent process (EIU, 1997). Thismay be due to the public’s limited understanding of power sectorissues and the absence of sufficiently qualified and interested consumerbodies that are willing to address power sector issues.

It would, however, be right to state that the need for power sectorreform was not extensively discussed within or outside Parliament.Apart from general policy support for reduced government involve-ment in production activities of the economy, the case for powersector reform has yet to be made to the general public and it is stillunclear whether there exists consensus even within key policy-makingbodies, such as the Parliament. In the view of the authors, this omis-sion of public debate may create problems in future. A populist wavecould conceivably reverse the ongoing power sector reform initiatives.The situation in Kenya contrasts sharply with Uganda where the gov-ernment has initiated a very public and highly successful campaign togarner public support for privatization. For each major sector that isslated for reform and privatization, the Ugandan government hasmade strenuous efforts to make the case to the public and invite publicdebate and discussion. No such initiative has been undertaken inKenya for the power sector nor for the economy as a whole.Consequently, the public’s reaction to liberalization and privatizationcontinues to be less than enthusiastic. The case for the advent of thetwo IPPs was not extensively debated nor was the public fully informedof the negotiation terms that the government agreed upon. Theabsence of detailed documentation on the two IPPs has fuelled wide-spread suspicion both within Parliament and with the independentpress. Consequently, the two IPPs have become a target of speculationand were recently cited by the independent press as constituting animportant impediment to resumption of balance of payment support


from the International Monetary Fund (IMF) as well as the World Bank(Daily Nation, 1997c).

Speculative reports in the press indicate that the negotiated contractperiod was too short (published newspaper reports cite a seven-yearperiod) resulting in higher-than-normal electricity purchase prices(Daily Nation, 1997c). In the absence of publicly available documenta-tion, it is difficult to assess the extent to which these accusations arecorrect or are largely driven by competing political interests. Thisinitial controversial experience, however, does not bode well for thefuture of the power sector reforms.

In response to strenuous complaints from Parliamentarians on thenegotiation terms of the two IPPs, the government recently hired theinternational auditing firm, Price Waterhouse, to undertake an in-depth evaluation of the agreement between the government of Kenyaand the independent power producers. According to recent mediareports (Daily Nation, 1997e), the Price Waterhouse report, which wasrecently submitted to the Ministry of Energy stated, among others,that: ‘KPLC did not fully employ transparent procedures in invitingbids and did not provide adequate information to the bidders to enablethem to submit their best bid … attempts to find out the shareholdersof the Iberafrica and Westmont power companies have been futile.’

According to the country’s leading daily, the Price Waterhouse reportattributes the flaws experienced in awarding the tenders in the initialstages to inexperience by KPLC staff and the emergency situation pre-vailing in the power sector requiring immediate action (Daily Nation,1997e).

Because of the recent nature of the changes in the power sector andthe absence of publicly available documentation, it is very difficult topredict what the electricity industry in Kenya might look like in thefuture. It is notable that this chapter has been compelled to rely onspeculative newspaper articles because of limited availability of rel-evant documents accessible to the public. The authors have, however,attempted to outline two scenarios that portray alternative future pro-jections of the structure of Kenya’s electricity industry (Figure 5.8).

The prevailing power sector structure (prior to the advent of IPPs)severely constrained competition in the power sector because of thedominant nature of KPLC. The proposed legal and regulatory changescould conceivably lead to two scenarios. The base case scenarioassumes the entry of numerous IPPs (including co-generators) compet-ing with the recently reconstituted government-owned Kenya PowerCompany (KPC), with transmission and distribution being the domain


112

Figure 5.8 Past, present and future scenarios for the Kenyan power sub-sector

of KPLC. Currently, this scenario seems to be the most likely in thenear to medium term.

Essentially, some level of competition will be introduced at the gen-eration stage but the transmission and distribution will remain firmlyin the hands of the dominant utility, KPLC. It is envisaged that therecently reconstituted KPC will inherit existing low-cost hydro plantswhich are largely paid for. This should place KPC at some advantageover new entrants, which may constrain competition at the generationstage. On the other hand, control of transmission and distributionwould retain KPLC’s stranglehold on the power industry. With theexception of some limited competition at the generation end, this sce-nario would not be particularly different from the prevailing situationbefore the advent of independent power producers.

In the high case scenario, more generators are expected to enterKenya’s power market to compete with KPC and existing co-generators.The transmission system would be jointly controlled by all key actorsthrough a joint-stock company or government-owned but private-sector-managed transmission company. Several distribution companieswould compete with KPLC. This is a very competitive structure, whichwould only be realized if the proposed Regulatory Board proves to beeffective and aggressively pursues the goal of establishing a competitivepower market in the country.

Current developments indicate that the possibility of such a compet-itive power market being established in the country is fairly limited. Itis, however, important to note that continued public support for powersector reform will largely depend on the extent to which the positiveimpacts of power sector reform are perceived to be significantly moresubstantive than the negative impacts, the subject of the next section.The next section will, therefore, begin by outlining the beneficialimpacts and drawbacks associated with past and current power sectorreform measures. Thereafter, the authors attempt to outline what thefuture structure of the power sector might be and end by drawinglessons learned from the reforms undertaken to date.

Beneficial impacts of power sector reform in Kenya

In the past, the electricity tariff levels were well below the long-runmarginal cost (LRMC) of electricity supply. The recent adjustment ofthe electricity prices (an important pre-requisite for power sectorreform initiatives), which allows the utility to attain 67 per cent of theLRMC, has been an important factor in enabling KPLC to realize an operational profit and contribute to the sectors investment


programme. During the 1995/96 fiscal year, the company registered apre-tax profit of Sh 1.51 billion equivalent to about US$25 million atthe current exchange rate (Kenya Times, 1997a). The governmentallows KPLC to automatically adjust the level of consumer tariffs toreflect changes in fuel prices. It is also expected that the higher electric-ity tariff will attract the interest of independent power producers.

A staff reduction programme at KPLC is already in progress (Republicof Kenya, 1995a). In 1993, KPLC had 10 616 employees serving 300 000 customers, which translates to a customer employee ratio of28:1. By December 1994, the ratio was 35.4:1 and currently stands at50:1. This reduction was achieved mainly through voluntary staffreductions and outsourcing of non-core activities such as security pro-vision through contract management. There are, however, concernsthat the staff reduction may have led to the departure of a largenumber of experienced and skilled professional staff members and leftbehind a diminished and less skilled staff complement.

The decision by the government to split the functions of KPLC, lim-iting its activities to transmission and distribution of electricityresulted in a positive response from investors who showed their enthu-siasm by buying and selling its shares in a frenzy. Both foreign andlocal investors are fighting to acquire a stakehold in the extremelyprofitable company. According to stock exchange analysts, this share-buying frenzy is a ringing endorsement by investors of the policies andabilities of the current chief executive and his excellent track record.

The vertical unbundling makes KPLC leaner. This move also doesaway with cross-subsidies. For instance, if the generating side makeslosses, it will not automatically be bailed out by other sections. Theadvent of the two IPPs has already had a visible impact on poweroutages which are no longer as frequent as they used to be. Clearly IPPshave greatly assisted in addressing the power crisis that Kenya is facing.The new Electric Power Bill underlines the government’s commitmentto private sector participation in the power sector and is a strongmessage to external power sector investors that the level of high-levelpolicy support is substantial. This should lower the government’s needto allocate its scarce investment funds to the power sector and allowthe private sector to carry a larger share of this investment load.

As the number of IPPs increase in the power sector, bulk supplytariffs for purchases from IPPs may begin to be based on theInternational Competitive Bidding (ICB) process (World Bank, 1997)which could conceivably bring down costs and tariffs for bulk purchaseof electricity. Similar trends in the recently liberalized petroleum sector


have taken place with substantial price reductions in bulk supply ofpetroleum products. This, however, has not been the case for retail-level sale of petroleum products.

The new Electrical Power Bill also provides for the separation ofpolicy and regulatory functions, which have both hitherto been exer-cised by the Minister of Energy. This reduces the government’s directinvolvement in the power sector which has been often cited as animportant constraint to effective operation and management of theelectricity industry.

Drawbacks associated with the power sector reform process

The reform process has not been very smooth and has experiencedsome flaws. As mentioned earlier, the IPP awards have been particu-larly controversial. Several international contractors have questionedthe transparency of the awards (EIU, 1997). The method used in award-ing the contracts has been a bone of contention between the govern-ment and the International Monetary Fund (IMF), with the latterarguing that the seven-year supply period was too short and the unitcost was on the higher side (Daily Nation, 1997c).

Even though the new Bill has attempted to reduce the role of thegovernment in regulation, critics of the Bill argue that ultimately theMinister of Energy will effectively remain in charge because of thepivotal role that the Minister will play in selecting board members aswell as his role in determining the budget of the board (Republic ofKenya, 1997b). The new Bill provides no special incentives to local co-generators that would probably limit their participation in the liberal-ized power market. This may result in limited local support for thepower sector reform process. For example, special incentives couldhave been provided for small-scale independent power producers forplants of less than 20 MW. Many co-generators in the agro-processingindustry would have been interested. This would not only garner morelocal support for the power sector reform process but the aggregatedtotal from all co-generators could constitute a substantial proportion ofthe country’s electricity generation installed capacity.

Independent legal analysis of the proposed Electric Power Bill indi-cates that substantial barriers to the new entrants will remain and thatthe licensing procedures are cumbersome. For example, the proposedBill requires applicants to set up an office in Nairobi even as they awaita decision from the board. This is a costly process bearing in mind thefact that the bids could be turned down. In addition, the applicant issupposed to supply a draft of the licence which may be an indication


that the responsible government agency may not have the necessaryexpertise. The proposed Bill is also unclear on issues related to acquir-ing land for the purposes of power generation. The Land Act states thatland can only be acquired for ‘public purposes’. The proposed Billremains silent on whether independent power projects will be consid-ered public or private initiatives. The proposed Bill does not outline therules and guidelines that the Board will use to evaluate licence applica-tions. The numerous grey areas of the proposed Bill are particularlyworrisome because of the rather cumbersome and elaborate objectionprocedure that the Bill recommends.

A highly emotive debate on the proposed Electric Power Bill inParliament demonstrated that many Parliamentarians were wary ofpower sector reform and were uncomfortable with the involvement ofthe private sector in the electricity sector. In a recent Parliamentarydebate, a number of Parliamentarians insisted that the new ElectricPower Bill would favour the rich and politically connected individualsat the expense of the rural poor (Daily Nation, 1997d). One of thereasons why power sector reform (particularly privatization) continuesto face resistance from Parliamentarians and independent energy ana-lysts is the prevalent belief that it may constrain rural electrification, ahighly emotive issue that is often a bone of contention among seniordecision-makers. Many independent energy analysts argue that thelimited revenue that rural electrification will generate for suppliers willmake it particularly unattractive to private sector entrants to the powersector.

The imposition of a 5 per cent levy on all electricity consumers inthe country to enable the Minister to establish a fund for purposes ofrural electrification (Republic of Kenya, 1997b) should assist in expand-ing access to electricity in rural areas. According to the proposed newBill (Republic of Kenya, 1997b), the fund is to be established to supportthe electrification of rural and other areas considered economicallyunviable for electrification by public electricity suppliers. According tothis new Bill, nothing is mentioned on how the fund shall be run andmost importantly who shall be responsible for it. Independent ana-lysts, however, argue that the fund is likely to remain under thecontrol of the Minister of Energy and may be used to advance politicalobjectives rather than developmental objectives. If this fund is intro-duced, then the new Bill should make it very clear how the fund is tobe managed and run so as to avoid problems in the future, such asthose that have arisen in the past in relation to other funds in theenergy sector. A number of analysts call for control of the fund by all


the key stakeholders in the power sector to ensure impartial manage-ment of the fund.

Lessons from experiences

The power sector reform process in Kenya is still embryonic. It is,therefore, difficult to draw definitive lessons from the limited experi-ence to date. A few tentative conclusions and suggestions can,however, be deduced. The first is the need for public awareness anddebate to ensure that the power sector reform process is perceived to beparticipatory, open and transparent. This would minimize accusationsof impropriety and garner broader support for power sector reformmeasures that might be implemented. It is absolutely vital for the gov-ernment to ensure that consensus within government is reached onhow the power sector reform process should evolve. It then needs toconvince the general public and civil society of the benefits of powersector reform. Of particular interest to the public is the impact ofpower reform on electricity prices and on rural electrification.

Secondly, the power sector reform process needs to be preceded bydetailed assessment of the potential benefits and drawbacks of variouspower sector reform measures. This assessment should draw on theexperience of other developing countries to ensure that full advantageis taken of lessons learned and experience acquired to date. Of particu-lar interest is the impact of power sector reform on low-income house-holds as well as the potential role of local investors in the liberalizedpower sector. A clear policy and regulatory framework that encourageslocal private sector participation would mobilize local support forpower sector reform and ensure its long-term continuity and sustain-ability. In addition, careful assessment needs to be made of the costsand the skills and resource requirements associated with the transac-tion costs of moving to a new power sector structure.

Thirdly, the debate on power sector reform should preferablydevolve on the best means of ensuring competition rather than simplyensuring private sector participation. The advent of the competitivemarket is one of the most compelling rationales for power sectorreform. Consequently, decision-makers need to assess carefully thevarious measures and differing strengths of various key actors tomaximize competition and ensure a level playing-field for all actors. Ofparticular importance is the central role of the transmission anddispatch centre in ensuring competition. To date, reforms in Kenyawill result in the dominant utility, KPLC, retaining overall control of


the transmission and dispatch centre. This is likely to stifle competi-tion and substantially reduce the perceived benefits of power sectorreform.

Fourthly, it appears important to ensure that an independent andfully functional regulatory mechanism is in place before reform is initi-ated. In Kenya, the establishment of the regulatory mechanism is beingconsidered after substantial reforms have taken place and IPPs arealready operational. This could create future legal problems and deterfuture independent power investors. A competitive multiple-playerpower market is a complex undertaking and requires a very resourcefuland skilled regulatory body to ensure a level playing-field and the rightlevel of co-ordination.

References

Beesley, M. and Littlechild, S. (1983). ‘Privatisation, Principles, Problems andPriorities’, in Lloyds Bank Review, United Kingdom.

Bhushan, K. (1995). Kenya 1995–96 Factbook: Uhuru 32, 14th Edition, NewspreadInternational, Nairobi, Kenya.

Bhushan, K. (1997). Kenya 1997–1998 Factbook, 15th Edition, NewspreadInternational, Nairobi, Kenya.

Central Bureau of Statistics (1996). Economic Survey, Ministry of Planning andNational Development, May, Nairobi, Kenya.

Daily Nation (1996). ‘Uganda Scraps Electricity Deal: Pay us Per Market Rate’, 15 October, Nation Newspapers Ltd, Nairobi, Kenya.

Daily Nation (1997a). ‘KPC Solution to Power Woes’, 21 January, NationNewspapers Ltd, Nairobi, Kenya.

Daily Nation (1997b). ‘Japan Grants Kenya Sh 442m’, 16 July, Nation NewspapersLtd, Nairobi, Kenya.

Daily Nation (1997c). ‘Firm to Probe Electricity Deal’, 8 August, Nation NewspapersLtd, Nairobi, Kenya.

Daily Nation (1997d). ‘Bill Favours the Rich – Ndicho’, 19 September, NationNewspapers Ltd, Nairobi, Kenya.

Daily Nation (1997e). ‘Power Deal Firms Mystery’, 10 November, NationNewspapers Ltd, Nairobi, Kenya.

East African Standard (1977a). ‘Power Cuts Cost Bamburi Dearly’, 9 April, TheStandard Ltd, Nairobi, Kenya.

East African Standard (1977b). ‘Power Sector Bows to Reform’, 6 May, TheStandard Ltd, Nairobi, Kenya.

East African Standard (1977c) ‘Power Plant to Start Work’, 31 July, The StandardLtd, Nairobi, Kenya.

EIU (1996). Country Profile: Kenya 1995–1996, Economist Intelligence Unit,London, United Kingdom.

EIU (1997). Country Report – Kenya: 1st Quarter, Economist Intelligence Unit,London, United Kingdom.


Financial Times (1997). ‘Global Private Power Update’, Issue 97/2, FinancialTimes Energy Publishing, London, United Kingdom.

GOK (1996). Kenya: Economic Reforms For 1996–1998: The Policy Framework Paper,Government of Kenya, February.

Government Printer, (1986). Laws of Kenya: The Electric Power Act – Chapter 314,The Government Printer, Nairobi, Kenya.

Gutiérrez, L. E. (1996). ‘How do Sub-Saharan Africa Utilities Compare’, inProceedings of Symposium on Power Sector Reform and Efficiency Improvement inSubSaharan Africa, World Bank, Washington DC, USA.

Indigo Publications (1997a). ‘Indian Ocean Newsletter No. 768’, 7 June, IndigoPublications, Paris, France.

Indigo Publications (1997b). ‘Africa Energy and Mining No. 208’, 2 July, IndigoPublications, Paris, France.

Institute of Economic Affairs (IEA) (1994). Agenda ‘94: People, Economic Affairsand Politics, Institute of Economic Affairs, Nairobi, Kenya.

International Finance Company (IFC) (1995). Privatization: Principle and Practice.International Finance Corporation, Washington DC, USA.

Karekezi S., Majoro, L. and Gathu, P. (1996). ‘Power Sector and Privatization –Literature Review for Africa.’ Institutions Theme Group, AFRPREN, Nairobi,Kenya.

Karekezi S. and Ranja T. (1997). Renewable Energy Technologies in Africa, ZedBooks Ltd, London and New Jersey.

Kenya Energy Review, The (1990). ‘Earthly Power’, Jan–Feb, The Kenya EnergyReview, Kenwide Media Publications, Nairobi, Kenya.

Kenya Gazette (1997). Government Printer, January, Nairobi, KenyaKenya Times (1997a). ‘KPLC Ready for Changes’, 3 March, Kenya Times Media

Trust Ltd, Nairobi, Kenya.Kenya Times (1997b). ‘Concern Expressed Over Power Supply’, July, Kenya Times

Media Trust Ltd, Nairobi, Kenya.Lock, R. (1996). ‘Financing of private sector development and power sector

reform in emerging nations: An essential nexus?’ Energy policy, 23(11),955–65.

Nyoike P. M. and Okech B. A. (1992). ‘The Case of Kenya’ in M. R. Bhagavan(ed.), Energy Management in Africa, African Energy Policy Research Network,Nairobi, Kenya.

Nyoike P. M. and Okech B. A. (1996). ‘Energy Utilities and Institutions inKenya’ in M. R. Bhagavan (ed.), Energy Utilities and Institutions in Africa,African Energy Policy Research Network, Nairobi, Kenya.

Okech, B. A. and Nyoike, P. (1995). Appropriateness and Performance of KenyanEnergy Sector Institutions: Case Studies and Comparative Analysis of Public,Power and Petroleum Sectors and Implications to Energy and EnvironmentalManagement. African Energy Policy Research Network, Nairobi.

Republic of Kenya (1995a). Kenya’s Energy Sector Investment Programme:1995/96–1999/2000 Presented for Discussion at Consultative DonorsMeeting in Paris, Government Printer, Nairobi, Kenya. September.

Republic of Kenya (1995b). Economic Survey – 1997, Ministry of Planning andNational Development, Nairobi, Kenya.

Republic of Kenya (1997a). Economic Survey – 1997, Ministry of Planning andNational Development, Nairobi, Kenya.


Republic of Kenya (1997b). Kenya Gazette Supplement No. 61: The Electric PowerBill, Government Printer, Nairobi, Kenya, 25 August.

Steyn, G. (1995). ‘Restructuring the South African Electricity Supply Industry:Appropriate governance in a newly democratised South Africa’. Utilitiespolicy, 5(2), 95–108.

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The New Vision (1996a). ‘Uganda, Kenya in Electricity Bargain’, The New VisionPrinting and Publishing Corporation, Kampala, Uganda, 30 August.

The New Vision (1996b). ‘Electricity Agreement, a Raw Deal for Uganda’, The New Vision Printing and Publishing Corporation, Kampala, Uganda. 15 October.

Walubengo, D. and Onyango A. (1992). ‘Energy Systems in Kenya: Focus onRural Electrification’, KENGO Regional Wood Energy Programme for Africa,Nairobi, Kenya.

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6Power Sector Reform Experiencesin ZimbabweIkhupuleng Dube

Introduction

In the majority of SubSaharan countries there are growing concernsabout the inability of most electric utilities to deliver a reliable, afford-able and widely available service at acceptable levels of financial andtechnical performance. This has mainly been attributed to poorperformance, a low customer base, poor revenue collection, inadequatepower pricing-levels and rigid state control. In order to reverse thisnegative trend most SubSaharan countries have embarked on therestructuring and privatization of the power sector.

This privatization trend has not, however, gone unchallenged.Opponents of privatization contend that private ownership does notnecessarily translate into efficiency. It is argued that private sector man-agers have no compunction about adopting profit-making strategies orcorporate practices that make services affordable or available to largesegments of the population. They point out that in most SubSaharancountries rural electrification rates are very low, and beset by viabilityproblems that arise from low loads and the long sub-transmission anddistribution networks that are needed to connect centres remote fromthe grid. The problem is further compounded by the low incomes thatcharacterize rural areas. Concern is also voiced over the cost-effective-ness of unbundling small systems. Large-scale retrenchments and theresultant socioeconomic problems are stated as a further reason againstprivatization. The opponents of privatization argue that the key ques-tion is not simply whether ownership is private or public, but underwhat conditions is ownership most likely to act in the public interest.

121


The objectives of this chapter are to analyse the various technicaland economic factors affecting the performance of the power sector inZimbabwe, and to examine possible restructuring scenarios.

The Zimbabwean power system

The Zimbabwe Electricity Supply Authority (ZESA) is responsible forthe generation, transmission and distribution of electricity inZimbabwe. The Authority has an installed capacity of 1961 MW. Anadditional 68 MW is generated on a seasonal basis by privately ownedsugar estates for their own consumption (Triangle: 45 MW; HippoValley Estates 23 MW). A small private company, Rusitu PowerCorporation, operates a 750 kW mini-hydro plant. The system parame-ters are shown in Table 6.1.

Imports account for up to 30 per cent of demand and are supplied bythe interconnectors shown in Table 6.2. Transmission and distributionlosses are about 4 per cent and 6 per cent of energy supplied respec-tively. The system peak is 1824 MW.

122 Experiences in Zimbabwe

Table 6.1 ZESA system parameters

a) Generating capacityPower station Type Installed capacity

(MW)

Hwange Thermal 920Munyati Thermal 120Harare Thermal 135Bulawayo Thermal 120Kariba Hydro 666

b) ZESA sales (1997)Customer group Number of Sales Per cent

customers (GWh) share

Industrial 1887 3951.82 42.2Mining 693 1579.10 16.7Commercial 358 935 1385.87 14.8Farming 10 51 690.48 7.4Domestic 38 405 1734.23 18.5ZESA Properties 295 23.37 0.3

Power sector regulatory and institutional framework

The Zimbabwe Electricity Supply Authority (ZESA) was formed by theElectricity Act (1985) following the amalgamation of the previous elec-tric utility companies, namely the Central African Power Corporation(CAPCO), the municipalities of Harare, Bulawayo, Gweru and Mutareand the Electricity Supply Commission (ESC). Only the Central AfricanPower Corporation (CAPCO) was responsible for generation and trans-mission in Zambia and Zimbabwe, while the others were responsiblefor transmission and distribution within their respective licensed areasin Zimbabwe. In 1985 a new Act was enacted establishing a corporatebody, the Zimbabwe Electricity Supply Authority (ZESA).

The regulation of ZESA falls under the Ministry of Transport andEnergy (MTE). The executing arm of the MTE is the Department ofEnergy (DOE). Of the DOE sections, the Economics and PlanningSection is responsible for regulating and supervising the utility. Themain functions of the section are:

• developing and assessing electricity sector policy and ensuring thatit is adhered to;

• regulating ZESA plans and operations;• monitoring the power sector and preparing regular status reports,

Public Sector Investment Programmes, funding, etc.;• Liaising with Zambia on the operations and policies of the Zambezi

River Authority;• Undertaking feasibility studies on rural electrification;• Assessing and approving domestic and international electricity

tariffs.The operations of ZESA are managed and controlled by a board

appointed by the Minister. The board meets whenever it deems

Ikhupuleng Dube 123

Table 6.2 Zimbabwe interconnection

Country Voltage levelkV

Zambia/Zaire 2 × 330South Africa (Matimba) 1 × 420South Africa (Messina) 1 × 132Mozambique (Chikamba) 1 × 110Mozambique (Cabora Bassa) 1 × 420Botswana 1 × 220

necessary to do so, but not less than six times a year. The board givesthe minister all required information relating to the undertakings ofthe Authority and any reports it deems fit. The Minister may bringany such report before the House of Assembly. After consultationwith the board the Minister may give it any directions that appear tobe required in the national interest. The board may establish com-mittees and divest any of its functions it sees fit. The term of theboard is stipulated at three years but the members may be re-appointed after the expiry of the three-year term at the discretion ofthe minister.

The day-to-day operation of ZESA is the responsibility of the chiefexecutive and associated subordinates (directors) each of whom is incharge of a department. The departments are Generation, ConsumerServices, Technical Services, Finance, Corporate Services andTransmission. The planning, audit and public relations functions aredirectly responsible to the chief executive’s office with the functions ofplanning being executed by a senior manager.

The chief executive, who is appointed by the Minister, forms theexecutive management committee together with the heads of depart-ments. This is then responsible for the day-to-day operations of theAuthority. Corporate policy issues are the responsibility of the board.Such issues are referred to the board by the Executive ManagementCommittee. In terms of the Electricity Act (1985), ZESA’s functions are:

– To acquire, generate, transmit, distribute and supply electricity inZimbabwe;

– To investigate new or additional facilities for the generation;transmission, distribution or supply of electricity, and to advise theminister of the result of such investigation;

– To acquire, control and operate other undertakings within Zimbabwe.

The Act authorizes ZESA to make by-laws that may provide for:

– The payment and collection of monies due for electricity suppliedand rentals of meters and other equipment;

– The making of additional charges or the payment of interest inrespect of overdue accounts;

– The fees chargeable by the Authority for services incidental to thetransmission, distribution or supply of electricity;

– The disconnection of electricity supply for non-payment;– Acquisition of land for electricity supply purposes.


The legal framework also deals with issues pertaining to pricing andinvestment. ZESA is required to ensure an annual income sufficient toenable it to meet its obligations and conduct business along soundcommercial lines. Monies not immediately required by the Authoritymay be invested in such a manner as the Minister and Ministry ofFinance may deem fit. The Authority is further required to establish ageneral reserve that may be appropriated from a surplus of income atthe end of the financial year. Such funds may be used for meeting anydeficiency that the Authority may incur and may be used, with theapproval of the Minister, for such purposes as the board may considerexpedient for the proper exercise of the Authority’s functions, includ-ing the development of its assets. The Act stipulates that the board willcomply with any directions that the Minister may give in relation tothe management of the general reserve.

The utility is also required to establish a capital development fund tofinance the capital expenditure of the Authority in creating and replac-ing capital assets. Presently ZESA is charging a 5 per cent levy on salesplus an additional 1 per cent levy on revenue for rural electrification.

The Electricity Act also defines the conditions for provision of powerby private undertakers. Private operators who obtain the prior consentof the Minister and the Authority may transmit, distribute or supplyelectricity to any other person provided that such permission and con-ditions have been granted and that the size of the plant is above100KW. In this case ZESA will be the regulator. Private undertakers witha capacity rating of less than 100 kVA can operate without Ministeriallicensing. At present the only private undertakers in operation are thesugar plantations, which generate about 37 MW for consumptionduring the milling season, and the mini-hydro at Rusitu which has aninstalled capacity of 750 kW. This plant sells its electricity to ZESA.

Another Act with an impact on the regulation of the power sector isthe Audit and Exchequer Act. Section 33 of the Act prevents para-statals, ZESA included, from making payments or expenditure withoutthe approval of the responsible Minister. The Section states that:

subject to the provisions of this Act, no designated corporate bodyshall commit itself to or incur:

– Any capital expenditure unless provision therefore has beenmade in a capital budget or supplementary capital budgetapproved in terms of this part or such expenditure has beenapproved by the appropriate minister;

Ikhupuleng Dube 125

– Expenditure other than capital expenditure unless provisiontherefore has been made in a revenue and expenditure budgetapproved in terms of this part or such expenditure has beenapproved by the appropriate Minister.

In terms of Section 34 of the same Act ZESA is required to prepare andsubmit capital, revenue and expenditure budgets to the Minister forapproval, before the beginning of the financial year. The monitoring ofthis requirement is a shared responsibility between the Ministry ofFinance and the National Economic Planning Commission in thePresident’s Office. Furthermore it is responsible for the para-statalreforms and reviews tariff proposals before approval by Cabinet. It alsoreviews the capital budget and project proposals as well as being repre-sented on the Government Tender Board (GTB) which is responsiblefor decisions related to procurement by government departments andpara-statals.

Decisions on electricity pricing are carried out by the CabinetCommittee on Development on the advice of the line ministries andthe National Economic Planning Commission. The Cabinet Committeeon Development is a committee comprising the Ministers of Industryand Commerce, Mines, Justice, Legal and Parliamentary Affairs,Agriculture, Transport and Energy, Finance and the Attorney General.Other Ministers can be co-opted into the Cabinet Committee onDevelopment on an ad hoc basis. The Cabinet Committee onDevelopment considers issues referred to it by the Working PartyOfficials on the advice of the sector Ministers.

It is therefore noted that the regulatory responsibility is sharedbetween the Authority and the Minister. The fact that the Minister hasoverall control makes it difficult for the Board and management tomake decisions, which are results-driven but do not have ministerialapproval. The Minister regulates such power sector issues as invest-ments, disposal of fixed assets, borrowing and staff conditions ofservice, and provides general directions relating to the performance ofthe Authority’s functions.

Strengths of the existing legal framework

The major strengths of the Electricity Act 1985 have been the adop-tion of a uniform national tariff system and a streamlined manage-ment structure for the electricity sector. Prior to the formation of ZESAthere were over 40 different electricity tariff classes in Zimbabwewhich were extremely complex to co-ordinate and regulate.


Differences existed between utilities. Harare municipality tariffs werebased on long-run marginal-cost pricing whereas tariffs for the otherutilities were based on average cost studies. These are studies in whichthe unit costs represent the average cost to serve all consumers withina class of service and in which the rate of return is based on historicalcosts. A post-amalgamation study carried out in 1987 by consultantsMerz and McLellan recommended a unified tariff structure consistingof seven tariff classes. The simplified tariffs were implementedeffective 1987.

The Act also reduced the number of general managers from five toone, so that the ZESA management structure was smaller than those ofthe former utilities combined. This was important since there was ashortage of technical personnel in the country at the time of amal-gamation. The new structure made it possible to maintain fairly rea-sonable technical performance standards at prices which in real termsare lower than those that were prevailing in the mid 1980s just beforethe enactment of the Act. This has a direct benefit of the economies ofscale achieved by the amalgamation.

A major advantage of the change was the potential efficiency gainswith respect to investment in major generation and transmission facil-ities. The nation was afforded the opportunity to build larger plants,which are more cost-effective to run than the equivalent number ofsmall plants. The power sector in Zimbabwe is in need of large capitalinvestments to meet demand and small fragmented undertakingswould have been difficult to fund. This problem is compounded by thesmall size of the Zimbabwe power system and limited investmentopportunities in the form of developments in Hwange, Sengwa andBatoka.

Another benefit relates to customs and excise duties. Customs regula-tions provide a facility that allows para-statals to import capital goodsfor projects that are accorded national duty free status. As a result ofthe facility ZESA has been able to save over US$60 million in the lasttwo years, in the form of duties for imports of capital goods forMatimba Interconnector and other distribution projects.

Weaknesses of the present framework

The present framework also possesses certain weaknesses. Critical tothe successful management of any business is the management andtechnical competency of the staff, the clarity of performance objec-tives, the transparency of the performance measurement process, andthe defence of autonomy.

Ikhupuleng Dube 127

Unfortunately, these are the areas where the existing legal frameworkhas been least successful. As indicated above, almost every major oper-ational decision requires the consent of the Minister acting alone or inconsultation with the Minister of Finance. This lengthens the decision-making process on critical planning and operational issues affectingbudgets, electricity prices, recruitment and conditions of service ofsenior management, customer relations and investment in major plantand facilities. Unlike ZESA, the ministry does not have the necessaryexpertise to make sound decisions on the operations of the electricityindustry. The section that deals with the power sector has a staff com-plement of five, with not even a single power systems engineer. Thecurrent competitive industrial environment dictates that reasoneddecisions have to be made expeditiously as any delays will increasecosts and cause shortages or loss of the organization’s comparativeadvantage. Due to lack of autonomy the Authority has suffered from ahigh turnover (–1.5 per cent from a total staff of 8000 in 1993) ofskilled managers, engineers, accountants, economists and other profes-sionals. Poor management control systems, unclear strategic direction,poor communications and customer relations were the inevitable resultprior to the implementation of the Performance ImprovementProgramme (PIP), which will be discussed later.

To remove these bottlenecks and improve the performance of theindustry, ZESA and the government are working on a new frameworkthat will be more result-oriented than the present Act.

Reasons for power sector reforms

Four main reasons have triggered power and other sector reforms inZimbabwe. These are:

– Restructuring as a component of the general economic reforms;– Restructuring para-statals to empower historically marginalized

groups;– Restructuring to enhance power sector efficiency;– Restructuring to mobilize finance for capital investment in the

power sector.

Restructuring as a component of the general economic reforms

In the decade commencing with independence in 1980, Zimbabwefollowed a social-political path that resulted in significant progress in terms of human resources and infrastructure development. For


example, enrolments at primary education level rose from 1.2 millionchildren in 1980 to 2.2 million in 1989, while those at secondarylevel rose from 74 000 to 671 000 during the same period. In thehealth sector the percentage of children fully immunized rose from25 per cent to 86 per cent and the infant mortality rate declinedfrom 86 to 61 per 1000 births. Life expectancy increased from 55 to59 years and fertility declined, resulting in a decrease in populationgrowth from 3 per cent to 2.8 per cent. Agriculture, the mainstay ofthe economy, saw a redirection of credit facilities as well as exten-sion and marketing services. Coupled with the maintenance ofappropriate producer prices, these measures led to an increase inmarketed output of small farmers, whose share of marketed maize(Zimbabwe’s staple food) rose from zero in 1980 to more than 70 percent in 1989.

Towards the end of the decade, however, the economy was threat-ened by deepening cycles of low investment, a growing budget deficit,rising unemployment, inflation and economic stagnation. Growth inGross Domestic Product (GDP) during 1980–9 (2.7 per cent per annum)lagged behind population growth. A disproportionate share of thisgrowth was in the provision of social services and public administra-tion. Export growth increased by only 3.4 per cent per annum in realterms between 1980 and 1986. This poor performance, combined withdebt service payment, which rose to a peak of 34 per cent of exportearnings in 1987, severely constrained the growth of imports resultingin a 0.4 per cent growth in real terms between 1980 and 1988. The netresult was the constrained utilization of existing capacity as well asinvestment in new production capability. This resulted in unemploy-ment as high as 26 per cent in 1989. There are now between 200 000and 300 000 school-leavers each year, but only 20 000–30 000 newjobs are being created in the formal sector, with the bulk of additionalemployment being in the government sector, particularly education,health and public administration.

The government’s fiscal deficit was in excess of 10 per cent of GDPduring much of the 1980s and this led to a central government debt of71 per cent of GDP by 1989. Thirty-six per cent of this debt was exter-nal. The government engaged in massive public and external borrow-ing, resulting in interest payments of 6.7 per cent of GDP in the1989/90 financial year. Inflation, which was less than 12 per centthroughout most of the 1980s, rose to over 20 per cent in 1991,peaking at 45 per cent in the 1992/93 period. This resulted in interestrate of above 30 per cent, further constraining investment.

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It was against this background that the government launched theEconomic Structural Adjustment Programme (ESAP) in October 1990.The principal objective of the programme was to generate a higher rateof economic growth, to expand employment opportunities and raisethe standard of living. The specific objectives of the programme were:

– Reduction of the external government deficit from 10–5 per cent ofGDP by 1994–5;

– Reform of public enterprises to eliminate the large budgetary burdencaused by subsidies, by making the enterprises operationallyefficient and more commercially oriented;

– Civil service reform to reduce the wage bill and the number of civilservants;

– Monetary policy and financial sector reform, to strengthen mon-etary management, slow credit creation, reduce inflationary pres-sures, liberalize the operations of the financial sector, encouragesavings and to improve the efficiency of inter mediation activities;

– Trade and exchange market liberalization to create a market-basedforeign exchange system and to shift to a tariff-based system ofprotection;

– Domestic deregulation and investment promotion, to liberalizeinvestment and deregulate prices;

– Implementation of social dimensions of adjustment programmes toprotect the poor and vulnerable groups from negative transitionaleffects of economic reforms.

There has been some progress in the implementation of some key ele-ments of the programme, especially in economic and financial liberal-ization, deregulation of foreign investment and reform of the trade andexchange regimes. However, the benefits of the gains were overshad-owed by the effects of severe droughts, deterioration in the country’sterms of trade, and global recession. Economic expansion was erratic,and unemployment has continued to increase to unsustainable levels.

Slippage in fiscal policy and the reform of public enterprises was amajor source of monetary expansion during the programme andlargely accounted for the persistence of inflationary pressures in theeconomy. Inflation peaked at around 42 per cent at the height of thedrought in 1992 before gradually declining to levels of around 16 percent in February 1997. Given the persistent expansionary fiscal poli-cies, monetary policy bore the main burden of maintainingmacroeconomic stability. As a consequence of the tight monetary poli-


cies, interest rates rose to unprecedented levels (in excess of 40 per centin 1992). Although the interest rates have fallen in response to thedecline in inflation and are currently around 25 per cent, they con-tinue to act as a major barrier to business expansion.

Public enterprise reforms were aimed at reducing the level of directsubsidies from Z$629 million in 1990 to a maximum of Z$40 millionby 1994/95. However, the above targets have not been met. To date,progress has mainly consisted of the introduction of financial measuresin the form of tariff increases and price adjustments to reduce operat-ing losses. However, the point is being reached where such increasesare constraining growth and affecting the competitive position of thecountry’s economy. Para-statals need to move away from priceincreases and be forced to pursue greater internal efficiency in order toenable them to maintain a degree of price stability. Even though thegovernment established a Cabinet Committee on commercializationand privatization in 1994, little progress has been made on this front.The poor performance was caused by factors such as inefficiency, inef-fectiveness, lack of accountability, conflict of objectives and lack ofoperational autonomy. Therefore the main reason for embarking onreforms of public enterprises was to address the considerable adverseimpact of the para-statals on the finances of the country. The totalpara-statal losses amounted to Z$6.5 billion over the last five years. Thegovernment has had to absorb these losses since it is the sole owner ofthe state enterprises. In addition, some of these enterprises have failedto honour their government guaranteed loans, resulting in an addi-tional burden of about Z$2 billion over the last five years. So far thegovernment has commercialized and privatized the Grain MarketingBoard (GMB), Cotton Marketing Board (CMB), Cold StorageCommission (CSC) and Dairy Marketing Board (DMB) through floata-tion of public shares and forcing them to operate under the CompaniesAct. In order to accelerate the commercialization and privatizationprocess government took over debts of the GMB, CMB, and CSCtotalling Z$4 billion to enable them to start on a clean state. Alreadythese three state enterprises have started recording profits. In the lastfiscal year CMB posted an after-tax profit of Z$30.9 million. After-taxprofits for CSC and GMB were Z$50 million. Furthermore, these enter-prises are now required to pay tax and remit 50 per cent of their after-tax profits as dividend. It can thus be concluded that privatization isdesirable to promote sectoral efficiency and competitiveness.

To further enhance the gains of the first phase of the economicreforms and to meet the missed targets, the government unveiled the

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second phase of the economic reforms, the Zimbabwe Programme forEconomic and Social Transformation (ZIMPREST) which foresees accel-eration of the privatization process.

Restructuring para-statals to empower historically marginalizedgroups

For decades the majority of Zimbabweans were precluded from anymeaningful participation in the economy due to the legacies of theUnited Declaration of Independence (UDI), implemented in 1965 bythe ruling minority government of Ian Douglas Smith. The cornerstoneof the policies of UDI were the disfranchisement and racial segregationof the black majority. This prompted the United Nations to imposesanctions against what was then Rhodesia. A war of liberation broughtabout independence in 1980 following the Lancaster HouseAgreement. The UDI prevented the majority of Zimbabweans from par-ticipating in the economy. An economy cannot thrive unless asignificant portion of the population participates in it, in capacitiesother than as labourers. This is not yet the case in Zimbabwe.Independence brought with it political power but did little to pave the way for meaningful participation by the broader population in the economy of the country. Today, 17 years after independence, theremaining white farmers continue to own and occupy 95 per cent ofall the prime agricultural land, while black farmers are left with barrenareas and regions of low potential. Also, of the 63 companies quotedon the Zimbabwe Stock Exchange, only 9 have a black board chairmanand only 8 have black chief executives. This is the case in a country of11 million blacks and 70 000 whites. It is against this background that,with the adoption of the economic reforms in 1990, the indigenousbusiness community started agitating for a parallel economic empow-erment programme. This was expected to level the playing-fieldbetween black and white business people, as well as creating economicopportunities for the marginalized indigenous population. Localindigenous organizations such as the Indigenous Business DevelopmentCentre (IBDC), Affirmative Action Group (AAG) and the IndigenousBusiness Women’s Organization (IBWO) maintain that very little has been achieved in terms of widening the economic base to accom-modate new players. The World Bank has noted that the policyenvironment continued to favour existing enterprises until the 1990s. This prompted the government to accept the policy ofindigenization.


In spite of the government’s efforts, barriers still prevent mostZimbabweans from actively participating in the national economy:

– Lack of access to adequate finance (current finance schemes set asideby government, of the order of Z$500 million, have provided onlyup to Z$400 000 for each project, where serious entry into anymeaningful venture requires an average Z$2.5 million);

– Lack of entrepreneurial awareness and know-how and lack of man-agerial skills among the indigenous people;

– Limited access to industrial and commercial land and infrastructurein urban areas that favours the existing enterprises.

– Excessive reliance on foreign expertise; a hostile environment andracist atitudes prevalent in the established business sector.

– Inadequate land and infrastructural development in rural areas.

After accepting the policy of indigenization, the governmentannounced that an indigenization programme had taken so long toadopt because its focus at the time of independence had been on theprovision of education, health, security and general administration,with limited resources. The government’s view is that the above priori-ties were meant to address the issues as they affected the majority,whilst affirmative action involves giving power to individuals asopposed to the majority of people. Economic reforms, competition andthe dismantling of para-statals has benefited the majority of people, andthe same majority should benefit from the proceeds of privatization.

The government has already initiated processes to pave the way forthe participation of the majority in the economy so as to foster econ-omic development and create employment. A policy document on theissue, has been released sometime this year. In its July 1996 budget thegovernment announced the creation of a National Investment TrustFund (NIT), with an initial provision of Z$200 million. Further fundingis to flow into the Trust from the proceeds of future privatization. Inannouncing the fund, the government propounded a basis for privat-ization founded on two principles.

First, the assets would be sold to black Zimbabweans, and, secondly,the proceeds would go to NIT, to be made available to indigenouspeople who wish to participate in the economy. The government hasstated that privatization forms part of a policy of creating a unitednation with all people having equal opportunities and therefore thepurchasers of para-statals must be indigenous people.

Ikhupuleng Dube 133

Restructuring to enhance power sector efficiency

As highlighted by the following indicators (Table 6.3), the financialperformance of ZESA worsened in the face of increasing inflation,devaluation of the Zimbabwean dollar, high interest rates and declin-ing real electricity prices.

The drought of 1991–2 had a particularly devastating impact onZESA’s operational performance. As a result only 8682 GWh of totalenergy could be supplied, compared with a demand of 10 264 GWh.This represented a 15.4 per cent drop in supply availability. ZESA wasforced to introduce a combination of load-shedding and tariff-basedrationing in order to curtail demand.

Corrective action was constrained by a number of factors. The pricecontrols that used to be a factor of the country’s macroeconomic poli-cies made it difficult, if not impossible, to maintain prices thatreflected the cost of supply. Shortages of foreign currency were alsoendemic. Restricted autonomy on personnel management policiesresulted in continual loss of technical and managerial staff.

The breakdown in management control and the technical reliabilityof the electricity supply service was inevitable. The government com-missioned several committees of inquiry in an attempt to arrest thedownward trend. Such inquiries were also made into the operations ofthe other para-statals resulting in the adoption of a general publicenterprise return as part of the economic reform package.

Reforms and privatization as a means to generate finance for capital investment.

The last reason for the restructuring of the power sector is the need toraise private sector finance for development aimed at meeting future


Table 6.3 ZESA financial indicators

1986/87 1992/93

Debt service ratio 0.82 0.54Interest cover ratio 2.18 0.82Self financing ratio ( per cent) 26 65Return of fixed assets (per cent) 16.9 11.3Borrowing as per cent of annualinvestment 47 21Average tariff – Zc/kWh 4.59 20.5

USc/KWh 2.76 2.40

Source: ZESA Annual Reports.

demand. The future electrical energy consumption in Zimbabwe willdepend on:

• Current energy consumption levels by customers;• The degree of energy under-utilization by customers;• Future customer expansion plans;• Level and impact of demand-side management;• Level and impact of technological innovations and fuel switching;• The impact of tariffs on energy usage;• Availability and pricing of non-electrical energy by urban and rural

communities;• Unserved energy due to ZESA’s constraints;• The impact of rural electrification on the energy consumption;• The extended and future energy use by domestic customers in urban

and growth points;• Anticipated future investments and the economic climate;• Demographic and socioeconomic characteristics;• Climatic conditions.

Furthermore, the future economic climate of the country will have abearing on power demand. The envisaged economic scenarios are asfollows:

Low case scenario

This scenario assumes a recurrence of erratic weather pattern, weakexport prices of primary commodities and growth in international pro-tectionism. With economic reforms assumed to fail, the economywould experience a higher rate of inflation and low levels of invest-ment. As a result of trade liberalization more industries will close undercompetition from imported goods. GDP will rise at 2.5 per cent peryear with the resultant increase in energy averaging 2 per cent.

Base case scenario

According to this scenario the reforms are expected to succeed, withGDP rising at an average of 5 per cent per year and a resultant energydemand of 4.5 per cent. Regional trade will increase. The fluctuationsin export commodity prices would continue and the internationalcompetitiveness of Zimbabwean exports is assumed to be maintainedby continued moderate depreciation of the Zimbabwean dollar.

Under this scenario, weather is expected to be favourable so that thenation will be self-sufficient in basic foodstuffs. It is further assumed

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that the budget deficit would be brought under control with noadverse foreign debt service ratio, however, some major borrowing forcapital projects could be discouraged.

High case scenario

This scenario assumes a GDP increase of about 7.5 per cent per yearfollowing favourable changes in world politics as well as economicpolicies that result in increased flow of financial assistance to the thirdworld, including Zimbabwe. In this scenario the reforms are expectedto achieve overwhelming success resulting in increases in investmentand export performance. The problems of unemployment, under-utilization of capacity and shortages of raw materials will be over.Energy growth is expected to be 6 per cent. To meet the load growththe following planning criteria have been adopted by ZESA and thegovernment:

– The minimum level to be carried by the system should be at least 20 per cent of demand;

– As a long-term objective, the minimum level of internal generationshall have capacity equal to or greater than the demand;

– Imports may exceed the 20 per cent limit as long as the secondcriteria is met and the sources of energy are significantly diversifiedwith respect to both technology and geography and are cost-effective relative to local options.

Taking into consideration the above planning criteria and the needto meet the expected deficit the following plans are expected to beimplemented (Table 6.4).

If ZESA was to build, own and operate Hwange 7 and 8, Batoka andSengwa and extend the present Kariba South Power Station it wouldneed to raise about US$4.6 billion over the next few years. This comes ata time of significant worldwide demand for infrastructure projects. Thedeveloping countries of Latin America and East Asia, eager to build theirmarket economies, need about US$140 billion per annum whilst therequirements of the former nations of Eastern and Central Europe havebeen estimated at US$500 billion. The financial options available toZimbabwe would include debt finance, equity capital and private capital.

Debt finance. Debt finance has played a role in the development of infrastructure with government agencies either guaranteeing theloans or borrowing on their own account, since they are the most


credit-worthy entities. At present, developing countries spend aboutUS$210 billion on infrastructure investment. Approximately 90 percent of this figure is derived from tax revenue or intermediated bygovernment. Debt capital can be sourced in many forms either as bankloans, institutional debt, bonds, project finance or export credits.

A combination of export credit and bank loans is widely used forfunding infrastructure in developing countries because it helps thecountry sponsoring the project to develop its economy, and benefitsthe countries supporting the project by providing a market for theirexports. Another factor that makes this funding structure attractive isthe pooling of resources and sharing of risks across nations. It wouldbe very difficult, for example, for ZESA to find one country or bankthat is willing to provide the whole US$660 million required for theexpansion of Hwange. The basic principle is tied equipment purchase.Contractors winning the tenders must have a financing package thatis normally provided by a bank based in the contractor’s homecountry.

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Table 6.4 Level of investment required to meet zimbabwe’s power needs

Project Local Foreign Year Totalcost cost cost(US$ Mn) (US$ Mn) (US$ Mn)

Old thermal refurbishment 3848 24 271 Completed 28 059Kariba South upgrade 2689 35 947 In progress 38 636Hwange upgrade 25 640 104 380 In progress 130 020Matimba interconnector 8147 33 592 Completed 41 739Cabora Bassa interconnector 5546 30 742 In Progress 36 288Hwange extension 264 000 396 000 1st Unit 660 000

20012nd Unit2003

Batoka Gorge 256 340 844 456 2010 1 100 796Kariba South 80 395 20 593 1998 200 988extensionSengwa 308 352 462 520 2004 770 880

TOTAL 954 956 3 642 490 4597 446

Source: ZESA System Development Plan (1995).

All major power sector projects in Zimbabwe have been largely fundedfrom debt capital. The construction of Kariba Dam and the South BankPower Station in the 1950s were funded from loans of GBP15 millionfrom the Commonwealth Development Corporation and US$7.7 millionfrom the World Bank. Domestic loans were also provided by both theZambian and Zimbabwean governments. The present Hwange PowerStation was also funded by debt capital consisting of commercial bankloans of US$210 million, export credit and syndicated bank loans ofUS$275 million and multilateral agency loans of US$150 million.However, as already outlined, the fiscal constraints of the governmentimpose limits on what it can borrow or broker for the power sector inZimbabwe. This makes it imperative for the government to turn to theprivate sector for power sector investment. Table 6.5 summarizesZimbabwe’s outstanding external debt according to source.

It can be noted from the table that Zimbabwe’s external debt, includ-ing sovereign guarantees, is very high as a percentage of GDP (gener-ally above 65 per cent). This fact, combined with missed deficits targetsat home will limit the government’s ability to borrow or broker fundsfor the power sector in Zimbabwe.


Table 6.5 Zimbabwe: outstanding debt by source

1992 1993 1994 1995Z$ 000 Z$ 000 Z$ 000 Z$ 000

Total outstanding debt 20 901.9 28 596.7 37 483.9 38 996.81. Total and publicly guaranteed 18 285.6 25 769.6 33 477.8 35 701.3A. Public and publicly guaranteed 16 709.7 23 515.8 30 785.0 32 600.1

– Bilateral – – – –– Multilateral 4 867.5 6 691.6 8 813.4 9 820.4– Private creditors 5 829.3 9 601.1 13 422.5 14 694.6– Commercial 6 012.9 7 222.6 8 549.1 8 585.2

B. Private non-guaranteed 4 314.6 5 146.8 6 195.0 6 337.5– Commercial 1 575.9 2 253.8 2 692.8 3 101.2

1 575.9 2 253.8 2 692.8 3 101.2

2. Short-term 2 616.3 2 827.1 4 006.1 3 295.5

A. Public and publicly guaranteed 2 187.9 21 187.9 1 445.5 –

B. Private non-guaranteed 428.4 639.2 2 560.6 3 295.5

Source: Reserve Bank of Zimbabwe September 1996 Quarterly Report.

Internal cash generation. Internal cash generation represents theprofits of an organization in new investments. It is thus a function ofan organization’s profitability and ultimately of its sales and pricingpolicies. If sales can be expanded without a corresponding increase incosts, more cash will be generated internally, and if there is scope toincrease tariffs on sales to the existing base of customers withoutdemand falling in response, then more cash will be generated. In thelate 1980s and early 1990s ZESA was obliged by some of its lenders togenerate funds equal to 40 per cent of the average capital expenditurefor three years from internal sources. This proved to be unattainable,given government control on tariffs. A revised rate of 25 per cent wasthen negotiated. At an internal cash generation rate of 25 per centZESA would have to raise US$685 million from its own sources overthe next 15 years for development projects in the power sector. In realterms this calls for doubling of tariffs over the next 20 years. Thiswould impact negatively on the customer’s ability to pay and also onprojected sales. Table 6.6 below shows the average share of electricityof total production costs.

The share of electricity appears to be quite high, so that any futuretariff increases that exceed the Consumer Price Index (CPI) inflationrate will worsen the customer’s plight. Should tariff increases exceedthe CPI, there is a likelihood of a fall in the demand and utilization ofelectricity. Such a fall in demand could affect the financial situation ofZESA and its capacity to raise the capital needed for expansion from itsown sources alone, thereby requiring private investment to meet futurepower requirements.

Equity capital. Equity capital is attractive to an organization becauseduring lean periods dividends, unlike interest charges, can be passed

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Table 6.6 Share of electricity costs as compared to total production costs

Customer category Per cent share of electricity

Domestic 12Industrial 15Mining 16Commercial 17Farming 20

Source: ZESA Load Forecast 1996.

on and the providers of equity capital are attracted by either the upsidepotential of a project and/or the upside potential of the organizationsponsoring the project. The scope of ZESA to raise equity capital on thelocal financial market is very narrow given the limited size of themarket. In 1994 US$125 million were raised on the Zimbabwe StockExchange, with half of the amount coming from foreign investors. It isestimated that about US$225 million is available annually on theZimbabwe money and capital market. The government absorbs aboutUS$150 million through its stock issues. This leaves US$75 million forthe private sector and para-statals. This net figure is very small in com-parison to the cost of the projects being planned by ZESA. The privatesector alone is estimated to require about US$250 million per annumfor its investment programmes.

Access to private capital. A small financial market is not unique toZimbabwe. It is a common feature of almost all developing countries.Large private utilities in developing countries are beginning to raiseequity capital from international financial markets as shown in Table 6.7.

ZESA’s planned projects are likely to make a huge dent in thenation’s material and financial resources (such as foreign exchange)and might even crowd out planned development projects in othersectors. This will certainly affect other sectors adversely. Furthermore,if traditional sources are used, the levels of ZESA’s external debt servicerequirements will be very high from now onwards, with a peak of 69.4per cent of forecast national debt service in 2004. This is a frighten-ingly high level. ZESA’s external debt service peaked at 26.2 per cent ofthe national debt service and contributed significantly to the debtservice hump. The current view in economic circles is that Zimbabwe ismoving into a debt trap.


Table 6.7 Net inflows of long-term private capital in developing countries(US$ billion)

1990 1991 1992

Foreign direct investment 26.3 36.9 47.30Debt capital 5.56 12.72 23.73Foreign equity securities 3.78 7.55 13.07

Source: World Bank.

Reform strategy

The reform strategy envisaged for the power sector involves two majorcomponents: (a) corporate restructuring of ZESA and (b) opening upthe generation segment of the industry to independent generators,together with equity participation in the existing and future generationplants.

Corporate restructuring

The turning point for ZESA was the board’s adoption of a financialrecovery plan in the 1991/92 fiscal year. The plan comprised bothrevenue maximization and loss minimization strategies. Revenuestrategies consisted of a programme of tariff adjustments and an accel-erated takeover of the revenue collection functions that used to be per-formed by the cities of Harare, Bulawayo, Gweru and Mutare on behalfof ZESA. Cost-minimization strategies included minimization of expen-sive local borrowings, organizational and management restructuringand the implementation of the performance improvement programme(PIP) developed with the assistance of Eletricité de France (EDF). ThePIP consists of a set of simple, easily maintained targets that were tiedto the new management contracts covering finance, customer servicesand management, the distribution, generation and transmission plantsand systems, other technical services and human resources manage-ment. Government support for this recovery has resulted in theAuthority reversing the past trend of losses and achieving positive netsurpluses. The ultimate result of the PIP was the adoption by ZESA ofthe Corporate Business Plan (CBP).

The CBP was a result of a corporate-wide process. It began with anexecutive management workshop that formulated the strategic issuesand objectives of the plan based on the general principles and a visionof ZESA defined by the government. The Board and chief executivestrategic planning workshops were subsequently held at an operationallevel to determine how the different departmental units would con-tribute to the achievement of corporate objectives.

The starting point of the CBP was to define a Corporate Mission thatcaptures the direction defined by the Board and the government. Thiswas done through a brief statement that not only captures ZESA’s rolebut also serves to energize and focus employees on how to fulfil theirroles efficiently and effectively. The following mission statement wasadopted: ‘We are committed to the total electrification of Zimbabwe atworld class standards and competitive prices.’

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Of note are the cultural and ethical standards that are implicit in themission statement which include teamwork (‘We’), commitment,national service, customer service, social responsibility, efficiency andexcellence. To achieve the overall aim the corporate business planimplied:

• Technical and management skills to be attracted and retainedthrough the creation of an appropriate working environment. Thishas been created by improvements in training opportunities andsalary and benefit levels that are comparable to the private sector.

• Achievement of electricity for all in the first half of the twenty-firstcentury by endeavouring to meet demand at competitive prices.This has culminated in the electrification programme of low-incomeenergy groups and rural areas through strategies that are outlinedbelow.

• Attraction of investment in the electricity sector by becoming oneof the ‘blue chip’ corporations in the region. This is being achievedthrough the entry of IPPs into the power sector as well as the envis-aged changes in the ownership structure.

• Achievement of management autonomy through execution ofresponsibility with accountability.

The CBP also defined the critical success factors. These can be summa-rized as follows:

1. Customer Service Quality• reaction time to faults• reliability

2. Price• cost reflective• affordable

3. Staff Competence4. Capital

• physical capital• working capital• cost of capital

The stakeholders are also defined in the plan. Stakeholders include:

i) Customers: the plan recognizes that ZESA exists because of peoplewho need electricity and are prepared to pay for that service;


ii) Shareholders: these are those who have invested to create theorganization, which serves the customer’s needs;

iii) Staff: the plan acknowledges the role of staff, especially theirability to use properly the resources provided by the shareholdersin order to serve the customers;

iv) Government: this is the custodian of the public interest. The gov-ernment provides the regulatory framework to ensure that thebusiness of ZESA is performed in a manner that is consistent withthe expectations of the general public;

v) Supplier: the providers of finance, goods and services are partnersto the success of ZESA’s business;

vi) General Public: ZESA owes it to the community to provide a safeand environmentally friendly service;

vii) Consumers: ZESA owes it to all its users to maintain high standardsof safety in all its operations.

The strategic issues and objectives defined by the CBP are summarizedin Table 6.8. To help monitor progress towards achieving these goals,an operational plan was created. This lays out activities that have to be

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Table 6.8 ZESA strategic objectives

Strategic issues Strategic objective

Corporate direction To provide an excellent and cost effective service as measured by world class standards

Corporate image To create an image befitting the status of a world class utility

Autonomy To provide for decision-making authority which iscommensurate with the level of responsibility. Internal – decentralization and delegation of power and authority: Externally – gained increasedmanagerial autonomy from the shareholder in line with generally accepted business practice

Customer focus To work towards maximum customer satisfactionGrowth To provide electricity for all within the first half of

the 21st centuryHuman resources To create a working environment where staff learn

and developFinancial management To transform ZESA into a blue chip companyPlant capacity To provide adequate and reliable plant capacity to

meet demand at a competitive price

Source: ZESA Corporate Business Plan.

achieved to meet the strategic objectives detailed in the plan. Theremuneration and benefits of senior management are tied to theachievement of these goals. The performance improvement plan hasresulted in ownership/management changes in the form of per-formance contracts that have seen a marked improvement in theAuthority’s operations.

The second form of the ownership/management changes willinvolve management contracts and the disposal of non-core activities.The utility has already undergone departmental restructuring toprepare it for this process. Management contracts are legally bindingcontracts between the government and a qualified firm. Two criteriamust be met for a contractual arrangement to be characterized as amanagement contract:

– Management of the enterprise is transferred to a contractor who isdifferent from the owner;

– the expectations of the two parties are defined in explicit contracts;

As is the case in commercialization, the contract includes performanceindicators, targets, structure of compensation and responsibility forinvestment. That means that the utility can operate more autonomouslyand on a commercial basis.

Private sector participation


The inability of ZESA and the government to raise capital from thenon-traditional sources described earlier led the government to openthe power sector to private sector participation, particularly by foreigninvestors.

Sugar estates in the Lowveld have always generated electricity for theirown consumption. Initially they supplied the grid at an agreed tarifflevel, but this was discontinued because of the increase in demand.Rusitu Hydro, a mini-hydro plant (750 kW) constructed and operated byprivate entrepreneurs, is selling power to ZESA at an agreed tariff. Theagreement between ZESA and Rusitu Power Corporation (RPC) foreseesRPC supplying power to ZESA for a period of 20 years. Thereafter theagreement will be renewed on annual basis. The agreement can be term-inated if the supplier fails to generate for 24 consecutive months. After 10 years ZESA may purchase the plants at an amount equal to their resid-ual value. The operational procedures agreed upon are no different fromthe procedures followed for ZESA’s own generators.


Plans have also been unveiled in 1997 for the building of the largestpower station in Zimbabwe as an IPP. The plant, to be developed atGokwe North (Sengwa), would cost US$1.4 billion. A letter of intent toundertake a detailed feasibility study was issued in April to the projectsponsors, National Power, ZESA and Rio Tinto. The study was com-pleted in September 1997 and was subsequently approved by ZESA. Itsfindings were that the project was technically and financially viable.The UK government had already pledged Z$32 billion to the project,which would consist initially of three 350 MW units, with a fourth tobe commissioned at a later date. The government approved the projectin December 1997. The power station project would be developed by ateam of people from National Power, ZESA and Rio Tinto, who wouldform the Gokwe North Project Development Group, with NationalPower taking the leading role. The project was to be developed asprivate sector project using an open book approach. Most of the agree-ment would be negotiated by this development vehicle with the ex-ception of the Power Purchase Agreement, the Fuel Supply and theOperations and Maintenance Agreements.

ZESA’s main role will be the negotiation of the Power PurchaseAgreement that will be developed in collaboration with National Power,and will take into consideration National Power’s rate of return.Currently the declared return is 18 per cent with a tariff level of 4.63 UScper kWh. It is foreseen that the actual return will be lower than this.

A fuel supply agreement will be negotiated with Rio Tinto. The feas-ibility study assumed US$14.00 per ton. It is also proposed that theoperating and maintenance arrangement for Gokwe North will be con-tracted out via an arm’s-length agreement to an operating company,managed as a joint venture between National Power and ZESA.

National Power and ZESA have underwritten equity with ZESA’sshare being 20 per cent and that of National Power 80 per cent.National Power has committed itself to off-load up to 20 per cent ofshares to the indigenous community. The project displaces the contro-versial YTL – ZESA deal that had been widely criticised.

Regulatory issues

To meet the reforms and privatization goals the new legal and regulatoryframework should be transparent and customer-oriented and provide forprices that are both affordable and competitive. This is best achieved by:

– Changing the status of ZESA from para-statal to a company operat-ing within the Companies Act 1985.

Ikhupuleng Dube 145

– Change the Electricity Act 1985 from an Act that is non-transparentand is prone to intervention to an Act that is results-oriented, so asto create a business culture and accountability that is lacking in apara-statal set-up.

– Create an office of the regulator to control the transmission networkand the dispatch centre, and to be responsible for least-cost plan-ning, setting of standards and customer protection.

– As far as distribution is concerned, a mechanism should be insti-tuted to allow the large customers fed by the 132 and 88 kV net-works (approximately 40 per cent of demand) to buy directly fromgenerators. For other customers there is a need for regional under-takings to plan and purchase their own requirements directly fromthe generators through a bulk supply tariff.

– Allow independent power producers who enter the sector by com-peting for investment in new generation capacity to be defined inthe least-cost system development plan. Such entrance must bethrough a transparent bidding system.

Other relevant issues

Role of demand side management

Faced with overstated forecasts, many utilities in the region havesought bilateral financing tied to restructuring without necessarilyexploiting other cost-effective solutions. They have embarked onmassive investment programmes that have had negative impacts ontheir economies. Demand side management (DSM) can also be utilizedas an alternative investment measure that can attract private invest-ment. Experience from other international utilities has shown thatwhen properly implemented DSM can:

– improve financial performance;– create customer satisfaction/retention;– result in good corporate citizenship;– improve power management.

In Zimbabwe it is envisaged that 2010 GWh could be saved on anannual basis. If energy efficiency were to be taken seriously it woulddisplace or delay the construction of additional capacity. This hasimportant implications nationwide, in that it frees scarce resourcesthat can then be applied elsewhere. DSM should therefore not beviewed separately from other energy supply options. In terms of costs,


energy efficiency can offer cheaper alternatives to building additionalcapacity. Take the case of solar water heaters. It is estimated that solarwater heaters can supply energy at US$400 per kW compared toUS$2000 per kW for a thermal power plant. The added advantage isthat most energy efficiency measures can be implemented in modules,sometimes without requiring foreign currency.

Low urban electrification

The degree of electrification in Zimbabwe ranges from 64 per cent ofthe households in Harare to over 99 per cent in smaller towns.Although most customer have access to low-voltage service lines, thereis a significant proportion that still do not use electricity for their day-to-day energy requirements. This is mainly due to high internal wiringcosts and the unaffordability of the monthly electrical bills. The cost ofinternal wiring is on average Z$6000. A significant number of cus-tomers in un-electrified houses cannot afford this amount.

To solve the problem of low electrification ZESA has introduced theconcept of the Compact Distribution Board (CDB). These are distribu-tion boxes that are ready-wired with socket outlets. The boxes areintended for direct connection to the terminals of an electricity dis-penser or meter, and are installed either in dwellings or in a waterproofenclosure. They are primarily intended to be an alternative to conven-tional wiring. The cost of the compact distribution board together withinstallation is Z$1700. This amount is payable in instalments over atwo-year period. CDBs have proved popular with low-income house-holds and demand for the initial 5000 was overwhelming. A further1000 will be produced to meet the increasing demand.

The second problem that would not necessarily be solved via reformsis the unaffordability of monthly electricity charges. The currentaverage electricity bill for a household of 10 is Z$300. Many house-holds cannot afford to pay this amount on regular basis. To solve theproblem, prepayment meters have been introduced. This enables cus-tomers to pay for electricity when they can afford to. The advantagesof prepayment systems are:

– Customers control their electricity usage;– Flexibility in electrical usage;– Reduction in meter-reading and administration costs;– Forward revenue collection by the utility;– Improvement in energy consumption statistics, which improves

planning.

Ikhupuleng Dube 147

Rural electrification

Rural electrification is by far the largest challenge facing the utility.Low returns on this type of investment mean that rural people areclearly the losers in any privatization attempt, so special mechanismsneed to be put in place to address the energy needs of rural customers.The exploitation of the rural potential is vital for socioeconomicgrowth given the fact that electricity currently accounts for only 12.3per cent of national energy consumption and only 21 per cent ofhouseholds have access to electricity. The following issues characterizerural areas in Zimbabwe:

– Most rural areas have less developed infrastructure, resulting inloads of between 50–100 KVA, which render grid electrification non-viable for most centres. The diffuse nature of the settlements alsomakes grid electrification difficult.

– Most rural centres are not located within the grid infrastructure andlarge investments in the region of Z$1 million per centre will berequired to electrify them.

– The incomes in many areas are seasonal and it is therefore difficultto gather capital for the up-front cost of electrification.

This means that in most cases rural electrification is not a viable busi-ness in Zimbabwe and cannot attract private investment on a largescale. However, the importance of rural electrification cannot be over-emphasized. This has resulted in governmental approval of a ruralelectrification levy of 1 per cent to all electricity customers. At thesame time the government has approved a Rural Electrification MasterPlan – a document that prioritizes areas to be electrified within thenext 15 years. The centres to be electrified are estimated to cost aboutZ$460 million at current prices. ZESA will be expected to raise Z$204 million via the levy, with the government raising the foreigncomponent of Z$204 million through foreign funding. So far the levyhas raised Z$80 million up to the year 2007. A total of 309 centres areexpected to be electrified.

Despite these efforts, at the end of the Master Plan many householdsand small centres will still not be electrified due to viability problems.ZESA has therefore changed its requirement that individual connectioncosts exceeding Z$11 000 be paid in full by the customer, and nowrequires only 60 per cent of the up-front capital cost, which is thenpayable in instalments over 5 years.


In addition, ZESA has started utilizing renewables with the followingobjectives:

– to meet the immediate energy needs of rural areas and other areasthat can not be immediately connected to the grid;

– to utilize renewables to stimulate the demand for power prior togrid electrification;

– to promote investment and capacity-building in the solar industrythrough the opening up of the new solar market, achieved byincreasing demand for the product through low-cost schemes;

– to reduce environmental emissions through the development of sus-tainable least-cost and environmentally friendly energy options inline with ZESA’s role as a good corporate citizen;

– to create a financing mechanism for the electrification of marginal-ized rural groups and institutions through the creation of a revolv-ing fund.

Currently solar systems are being installed throughout the country,with customers required to pay a connection fee of Z$250 whichincludes installation and internal wiring. A cost recovery tariff hasbeen developed, allowing flexibility in payment. The maintenance andreplacement of the systems is the responsibility of the Authority, and aproportion of the monthly payments goes into a revolving fund.

Conclusions

The present legal and regulatory framework is characterized by manygovernment controls in areas such as pricing, budgets and expenditure,procurement, decision-making processes and staffing issues. These in-built bureaucratic procedures compromise the efficient operation of autility. The problem is worsened by a lack of capacity and skills withinthe Department of Energy (DOE). This lack is due to low remunerationin the public sector, with the result that para-statals attract better-qualified personnel than government. A survey conducted inZimbabwe shows that civil servants are generally paid 70 per cent lessthan employees working in comparative posts in para-statals. In actualfact an analysis of the relevant section of the DOE shows that there isnot even one power systems engineer.

In developing a new legal and regulatory framework it must beappreciated that the Zimbabwean system is small in comparison to

Ikhupuleng Dube 149

other countries with privatized para-statals. The maximum demand ofthe Zimbabwean system is only 1800 MW. In conjunction with thelow growth rate of only 4.5 per cent per annum, this may mean thatmany potential customers will require subsidies. The scope for theefficiency gains expected through competition could be limited aspotential entrants may require a guaranteed monopolistic market inorder to make their investment viable. Rural electrification will requirespecial arrangements. Although electricity in some areas is viable froma financial and economic point of view, many areas will continue to becharacterized by viability problems. It might be necessary to continuethe collection of levies to fund such electrification programmes by newentrants.

To meet the growing demand for power in Zimbabwe private financewill need to be raised for capital projects, given the government’s hugebudget deficit and the constraints involved in government-guaranteedsovereign loans to para-statals. This would invariably necessitate theentry of IPPs in Zimbabwe. Zimbabwe should also devise strategies thatfoster efficient use of energy and invest in demand side managementand renewable energy sources as an alternative to grid expansion.

Aside from supporting macroeconomic development and sectoraland enterprise-level efficiency, privatization in Zimbabwe shouldfurther the aim of widespread capital ownership by the majority of theZimbabwean population.

Bibliography

Bacon, R., Restructuring the Power Sector: The Case of a Small System, FDP Note No. 10 World Bank (Washington DC: 1994).

Bacon R. W., Privatization and Reform in the Global Electricity Industry (LincolnCollege, University of Oxford, Oxford, UK: 1995).

Coopers and Lybrand, ‘Financing Africa’s Power Sector: Issues and Options’,Financing Options and Issues (London, UK: 1995).

Dube, I., The Viability of Solar PV Systems for Community Use in Zimbabwe,mimeo, 1996.

Dube, I., ZESA System Load Forecast, 1997, mimeo, 1997.Goodman J. B., Loveman G. W., Does Privatization Serve Public Interest? Trade

Development Institute of Ireland/Ministry of Finance Monitoring andImplementation Unit, Harare: 1994.

Government of Zimbabwe, Budget Statement, 1996, Government Printers,Harare, Zimbabwe: 1996.

Government of Zimbabwe, Zimbabwe A Framework for Economic Reform(1991–1995) Government Printers, Harare: 1991.

Government of Zimbabwe, Zimbabwe Programme for Economic and Social transfor-mation (1996–2000), Government Printers, Harare, Zimbabwe: 1996.


Government of Zimbabwe, Second Year National Development Plan (1991–1995),Government Printers, Harare: 1991.

Maarschalk, P., Financing of Projects in the Power Sector: Fundamentals for RaisingFunding on the Local and Foreign and Financial Markets. Zimbabwe Chapter ofthe World Energy Council, Symposium on Deregulation and Privatizationof the Energy Sector, August 1995 (Harare, Zimbabwe: 1995).

Makina H., Zimbabwe Electricity Efficiency Project – Policy Levers (EDM Consult,Harare: 1995).

Ndoro K. S., ‘Consumer views on Privatization, Zimbabwe National Committeeon the World Energy Council’ in the Proceedings of Symposium onDeregulation and Privatization of the Energy Sector (Harare, Zimbabwe: 1995).

Sunday Mail, Harare, 16 March 1997.Water and Power Consultancy Services (India) Limited, Rural Electrification

Masterplan Study of Zimbabwe (WAPCOS New Delhi, India: 1996).ZESA, Corporate Business Plan, ZESA, Harare, mimeo, 1995.ZESA, System Development Plan 1995, ZESA, Harare: 1995.ZESA, Long Term Economic Forecast 1995, ZESA, Harare: 1997.

Ikhupuleng Dube 151

7Power Sector Reform Experiencesin UgandaJohn E. Mugyenzi

Introduction

At the start of 1986, Uganda’s economy was weak as a result of about15 years of turmoil. When the present government came to power itinstituted economic reform programmes, which have injected a ‘leaseof life’ into the economy. GDP grew at an average annual rate of 6.4 per cent between 1987 and 1995 and per capita income hadreached US$250 by l995. The industrial sector is expanding rapidly andhas a 14 per cent share of GDP. Urbanization is accelerating along witheconomic growth, and this has direct implications for electricitysupply. The government is attempting to rebuild infrastructure thatwas damaged during the years of turmoil. The medium-term publicinvestment strategy is geared towards development, in which the gov-ernment will play a leading role: ensuring cost-effective expenditurewithin the priority sectors, and withdrawing from activities best left tothe private sector. The development plan for 1993–1996 includedUS$232 million for energy sector development (15 per cent of the plan total). Donor assistance to the energy sector development wasUS$216 million, 93 per cent of the total energy sector budget.

Electric power resources

Uganda is well endowed with hydropower resources. The potentialcapacity of the Victoria Nile is estimated at 2000 MW. Only 180 MWare developed at the Owen Falls Power Station (OFPS). Six other majorsites have been identified: Bujagali, Kalagala, Kamdini (Karuma),

152


Murchison Falls, Ayago North and Ayago South. There is also largepotential for small hydropower development, especially along the trib-utaries of the Nile. Numerous micro-hydro sites exist, especially in theparts of western and eastern Uganda.

Geothermal resources estimated at around 450 MW have beenidentified in the western Rift Valley along Uganda’s western boarder.No plans exist for their development. Uganda’s sugar industry hasinvested in nominal co-generation using bagasse. The three sugar factories, Kakira, Lugazi and Kinyara produce 2.5 MW, 1.5 MW and 1.2 MW respectively for their own consumption. With modern tech-nology an estimated 20 MW would be harnessed from this source.

Electricity supply and demand

Uganda’s power needs are met by the Uganda Electricity Board (UEB), amonopoly utility owned by the state. The UEB depends on a singlehydropower source, the Owen Falls Power Station. This station wasopened in 1954 with an installed capacity of 150 MW (10 × 15 MW).The capacity has just been raised to 180 MW and the station is capableof generating 1000–1100 GWh per year under the present operatingarrangements. The Owen Falls station is old and has been undergoingrehabilitation since 1986. Rehabilitation work that was scheduled to becompleted in l990 has only just been completed. Transmission and dis-tribution systems have also benefited from the rehabilitation workduring which many lines were replaced and new transformersinstalled.

The power system in Uganda has been running at or near maximumcapacity for the last three to four years. UEB’s 1995 energy productionof 1057 GWh and its peak load of 161 MW were close to the maximumcapacity of the Owen Falls Power Plant. A number of diesel generatorsare located in remote parts of the country off the national grid. Theyhave capacities ranging from 144 KVA to 500 KVA. UEB also operates amini-hydro plant of one MW capacity in the southwestern part of thecountry.

Domestic peak load is now estimated at 250 MW, leaving a capacityshortfall of about 70 MW. This normally translates into severe load-shedding, uneven voltage and other service problems now common inthe Ugandan power system. A second power plant, the Owen FallsExtension, is under construction. It has an initial installed capacity of80 MW (2 × 40 MW), with provision for an additional 120 MW. Itsanticipated energy production is 500–600 GWh per year, raising thesystem capability to 1500–1700 GWh per year. The project, initially

John E. Mugyenzi 153

scheduled for commercial operation by 1997, is due to be commis-sioned in April 2000.

Only 5 per cent of Uganda’s 18 million people have access to elec-tricity. The average per capita consumption rate is 44 Wh per year. Themajority either cannot afford service or are very remote from the grid.The main categories of consumers are residential (55 per cent), com-mercial (25 per cent) and industrial (20 per cent).

Uganda Electricity Board’s performance – an overview

The system technical losses are estimated to be 20 per cent of thepower generated. Non-technical losses, mainly consumption by unreg-istered or illegally connected consumers, comprise 10 per cent ofpower generated. Power outages, wide voltage fluctuations and brown-outs are frequent. The outages are due to both system breakdowns anddeliberate load-shedding by UEB. In either case they are a cost to theeconomy and to the system’s customers.

UEB’s financial situation is such that it cannot earn an adequate rate ofreturn, service its debts, and contribute significantly to the financingneeded for development investments. At an average of 10 US cents perkWh, UEB’s tariffs are not low. Its financial difficulties are a result of highsystem losses, inaccurate billing and poor collections as well as high staffcosts. In 1989, for instance, salaries and wages made up 22 per cent oftotal operating expenditure; by 1994 they had risen to 43 per cent.

The corruption prevalent in Uganda has also permeated the powersector. The UEB’s system losses of 30 per cent, particularly those associ-ated with the distribution segment of the industry, occur in manyinstances with the collusion of UEB staff. Distribution lines are vandal-ized in search of materials such as copper, aluminium and angle lines.These problems accentuate the acute capacity shortfalls that haveresulted in extensive power cuts in the country.

UEB has been rapidly increasing the number of new connections toits system in an unplanned manner that has further overloaded thesystem. New connections have been effected without paying dueregard to load-balancing and low-voltage lines have been extendedexcessively. To deal with these problems, UEB has introduced a moni-toring team that performs on-the-spot checks. The team is supposed tocheck the system regularly and report any anomalies.

UEB still maintains obsolete equipment. To obtain spare parts, UEB hasto place a special order. In most cases UEB is unable to replace worn-outor damaged parts because of financial reasons. The equipment continues

154 Experiences in Uganda

to affect the quality of service UEB provides. Some of the equipment isreplaced only when it ceases to function. Most of the equipment,however, will be replaced under the rehabilitation programme.

Power sector institutions

In Uganda, the Ministry of Natural Resources (MNR) is responsible forthe management and development of the country’s energy resources.Within the power sector MNR sets broad sector policies and strategies,and has a supervisory and regulatory role. A civil service reform pro-gramme aims to reorganize MNR, redefining its function in order toimprove its effectiveness. However, the pace of restructuring is not fastenough to ensure effective policy-making and supervision of the powersector. For example, only three out of the seven established posts inthe Department of Energy have been filled.

UEB is responsible for the generation, transmission and distributionof power. It is Uganda’s largest state corporation with 3700 employees.With the support of IDA and a number of other multilateral and bilat-eral donors, the government has invested heavily in rehabilitation ofthe power sector’s infrastructure and institutions. UEB, however,remains inefficient and non-profitable. The sector lacks the institu-tional strength to play its role in the economic and social developmentof the country.

Legal and regulatory framework

The Uganda power sector is regulated by the Electricity Act, 1964. TheMNR is responsible for policy formulation and oversees and co-ordinates sector operations. The Electricity Act gives UEB a monopoly ingeneration, transmission and distribution of electricity in Uganda andalso allows it to export power. The Act gives UEB a regulatory functionin that it issues licences and regulates the operations of the licensees.

Although the Act does not bar private sector entry, the multiple rolesof UEB as owner, operator and regulator of the power sector discour-ages private investment. The Minister enjoys a dominant role in thepower sector with the power to enact regulations regarding electricitysupply, and resolve disputes.

Motivation for reform

Rapid economic growth has resulted in fast-growing demand for elec-tricity, thus increasing load-shedding in virtually all load centres.


Power shortages have constrained the country’s economic growth. Thefollowing are major considerations behind the move to reform thepower sector in Uganda:

• There is a shortage of domestic capital to invest in power generationcapacity and expand the existing infrastructure. Any developmentof the power sector would necessitate foreign loans, thereby in-creasing Uganda’s debt burden and exacerbating UEB’s financialdifficulties.

• The institutional structure of UEB limits management’s autonomy,tolerates inefficiency and does not provide sufficient reward for ini-tiative and performance. Thus UEB remains inefficient and finan-cially weak and fails to provide high quality services.

• There is no comprehensive plan for rural electrification.• There is a lack of an appropriate legal and regulatory framework.

UEB enjoys monopoly status and plays the dual role of utility andregulator.

• The shortfall in power supply has resulted in frequent blackouts andthe government (GOU) is attempting to find an interim solution.

The reform process

Reform in Uganda’s Power sector is the result of an evolutionaryprocess rather than a continuous policy implementation. However, thevarious issues have been consolidated into a proposal for a strategicplan for the Uganda power sector.

Initiation of reform

The aim of the Ugandan government is to restructure and commercial-ize the power sector in order to enhance its operational efficiency andfinancial performance, in addition to establishing an independentregulatory agency. The government’s targets are:

• To achieve enhanced economic viability of the power sector outsidethe government budget;

• To improve UEB’s operations and financial performance throughmanagerial autonomy and commercialization;

• To meet growing electricity needs through involvement of privateinvestors and private capital;

• To develop decentralized power systems to meet the ruralelectrification objectives of the government.


A number of studies on different aspects and issues facing the powersector have been undertaken to help develop a framework for reform.The evolution of the reforms started in l985 with a proposal that wasreferred to as Uganda Second Power Project. This involved rehabilita-tion and reconstruction works at OFPS and dam, rehabilitation of thetransmission and distribution system, training of UEB and MNR staff,and various consultancy studies aimed at improving the electricitysupply. The OFPS works have been completed. Rehabilitation of thetransmission and distribution systems continued until materials andfinancial resources were exhausted.

Studies undertaken under the Second Power Project included thefollowing:

• Power Development Study of the Ugandan electricity system;• Assessment of management organization, manpower and training

requirements of UEB;• Selective Staff Development Study and Training Manual; Billing and

Collection Study;• Review of stores and vehicle workshop facilities and procedures;• Feasibility Study of supply of electric power to western Uganda;• Rehabilitation of Kampala network; Household Energy Planning

Programme;• Feasibility of an extension to Owen Falls Power Station;• Rehabilitation and upgrading of Uganda’s electricity system.

Many of the recommendations generated by the above studies haveeither been implemented or are included in the Third Power Project.The need for the Third Power Project was strengthened by a 1989ESMAP mission report which recommended an increase in generationcapacity and improvements in the distribution system in Kampala,the Owen Falls Extension Project, and rehabilitation of the powersystem in Kampala. Other components of the project include: con-struction of the 132 kV Masaka–Mbarara line, construction of the 132 kV Jinja–Kampala double circuit line, support to MNR, ruralelectrification of semi-urban areas, institutional support to UEB andengineering design for the next hydro site to be developed inUganda’s least-cost development study. Work on the Owen FallsExtension (OFE) began at the end of 1993, two years after its sched-uled start date. The 132 kV transmission lines are now completed, asare most of the other activities.


National Electrification Planning Study (NEPS)

This study aimed to find the optimal programme for providing electric-ity to a substantial number of areas throughout the country over thenext 20 years. It contained a long-term electricity demand forecast andanalyzed both available and potential generation facilities. A NationalElectrification Master plan was also formulated. This involved assess-ment of the technical standards in use, the quality of service, and theelectrical and mechanical state of the system.

The main findings of the study were:

• Rehabilitation of Owen Falls may only be sufficient for meetingdemand up to 1995;

• There is lack of protective maintenance of the system;• The network is ageing (for example, there are many rotten poles);• Diesel generation is a significant drain on UEB’s financial resources.

The following recommendations were made:• Eliminate voltage drops affecting the 33 kV and 11 kV networks;• Eliminate diesel generation;• Supply power to areas that have not yet been electrified particularly

in the northern and south western regions.

Customer Services Management Project

The study was undertaken as medium-term initiative directed towardsimproving customer service as well as corporate cashflows, liquidityand profitability. The findings confirm an urgent need for UEB todevelop its organization, systems and work practices in the commercialbusiness area. The project involved review of the Customer AccountingSystem, responsibility structure, adequacy of current ManagementInformation System (MIS) technology and its impact on UEB’s billingand collection performance. The Electricity Supply Board of Ireland(ESBI) was mandated to explore the feasibility of contracting outmeter-reading, bill delivery and revenue collection while retainingoverall responsibility within UEB.

The major recommendations were that UEB should:

• Create a new function of Customer Services incorporating bothdistribution and commercial functions;

• Separate the district of Kampala (which accounts for 70 per cent ofUEB’s customers) from Central Region and give it regional status;


• Divide the district of Kampala into Customer Services Areas. A sub-division into five areas would bring customer services functionscloser to customers;

• Establish appropriate authority levels, guidelines and performancecriteria for the new structure;

• Provide management development and training to support theprocess of structural change;

• Leave the core activities of collection, meter-reading and billdelivery under direct management.

These recommendations were agreed to and are now beingimplemented.

Loss reduction study

This study concluded that technical losses could be reduced to 11 percent by load-balancing. Rehabilitation of the 11 kV system in thecentral region would further reduce technical losses. A further recom-mendation was that all customers should be metered and that bills nolonger be estimated. At the time of the study there were an estimated3000 illegal users in Kampala. No action has been taken to resolve thisproblem due to a poor customer database.

Reform strategy

The long-term power sector strategy for reform involves the followingelements:

• Unbundle the power system with state-owned UEB retainingresponsibility for generation and transmission;

• Establish private, regulated, urban distribution companies;• Retain the rural distribution (electrification) function;• Allow private generation companies (IPPs) in the power sector;• License industrial users;• Establish an autonomous regulatory commission to regulate the

power sector.

Figure 7.1 shows the structure of the power sector envisaged in thereform.

In August 1996, the government reached a decision not to contractout the Uganda Electricity Board’s management to a private manage-ment firm. The government’s reform policy is to open the generationsegment of the industry to other generators while the transmission


segment remains under UEB. The distribution segment would be pri-vatized at a later stage in the reform process.


Uganda has already expressed the intent to solicit for private invest-ment in the power sector. Cabinet has already approved an amend-ment to the Electricity Act 1964 to end UEB’s monopoly status andopen the sector to private investors.

A number of developers have shown interest and have formed part-nerships to develop certain hydropower sites. Table 7.1 shows theIPPs, the hydropower sites and the capacity of the proposed plants.After protracted discussions involving the President, the MNR,Ministry of Finance (MOF) and UEB, a memorandum of understand-ing was executed between the government of Uganda and NileIndependent Power (NIP). NIP was to build, own and operate a hydro-electric plant at Bujagali Falls. The development programme presentedby NIP includes provision for a 290 MW, US$480 million power plant


Figure 7.1 Proposed industry structure

at Bujagali to be operational by the year 2000. Another three develop-ers have also signed memoranda of understanding with the govern-ment to develop other hydropower sites on the Nile River. The mostadvanced of the four developers is negotiating a Power PurchaseAgreement (PPA). All the developers are pursuing Build, Own andOperate (BOO) contracts. IPPs are interested in selling all the powerthey generate. The GOU has now commenced preliminary negotia-tions with Kenya and Tanzania with the aim of increasing exports tothe two countries.

Uganda is primarily interested in closing the supply deficit, raisingsignificant amounts of capital and bringing modern technology andmanagement expertise into the industry. As a result of the absence ofthe type of environment that would attract IPPs and other forms ofprivate sector investment in the power sector, government has optedfor negotiated deals other than competitive bidding. The mostadvanced of the four (NIP) signed a memorandum of understanding in1994, but the PPA negotiations have been stalled.

The PPA has not yet been signed as the parties involved have notbeen able to agree on certain issues. Some of the contentious issues are:

1. NIP is requiring the government of Uganda to guarantee payment ofpower sold to UEB. Such a requirement underlies the inability ofUEB to pay for power purchased because of low tariffs and problemsassociated with billing and revenue collection.

2. Financing is to be on the basis of a concessionary credit to lower thetariff. Concessionary credit is normally associated with a low inter-est rate and could affect the overall cost of the project, and conse-quently the price at which electricity would be sold to UEB. This isrelated to the political nature of tariff increase and the issue ofaffordability by low-income earners.


Table 7.1 New independent power producers

Independent power Site Capacity (MW) Project costproducer US$

Nile Independent Power Bujagali 290 480Pakwach Power Limited Karuma 200 –Arab International Contractors Ltd Kalagala 340 –Rwenzori Tea Growers Ltd Muzizi 60 –

3. The reliability of the transmission and distribution system, theextent to which IPPs would be able to have unconstrained access toit, and the conditions for such access are still being discussed.

4. Other issues such as reliability of load forecast, conditions underwhich IPPs can export power and new legislation for the electricitysector are yet to be resolved.

The inability to resolve these and other issues is delaying the badlyneeded additional capacity. Although there are responses to the GOU’scall for private investors in the power sector, it would be prudent forthe GOU to accept counter guarantees for the commitments by powerpurchasers (in this case UEB). In view of UEB’s less than impressivetrack-record, policy analysts contend that the insistence of NIP andother IPPs that UEB buys all its power and that GOU guaranteespayment is not unreasonable. To strike a balance, GOU could agree toa phased site development programme so that power is available in therequired quantity. For example, if the capacity deficit at the time ofcommissioning the station is expected to be 50 MW, the commitmentwould be to guarantee purchase of 100 MW for a specified period, afterwhich time the limit would be reviewed. However the IPP would notbe limited to 100 MW.

The delays in implementing the first IPP have led the GOU to solicitfor other developers without consideration of the national HydropowerDevelopment Master Plan (HMP), which has ranked hydro sitesthroughout the country. The first IPP has not taken up the site rankednumber one. The maturity period for hydro site development is knownto be 6–8 years. Thus hydro development is not a short-term solutionto capacity shortages. A thermal plant is a cheaper and quicker solutionto the country’s capacity problem and could operate in parallel withthe hydropower development projects until they become operational.The GOU has decided to advertise for a short-term investment in athermal plant to cover the ever-widening generation shortfall. Unlikethe non-transparent process of hydropower sites allocation, the gov-ernment has followed the International Competitive Bidding processto select a company or group of companies to build a thermal plant.The response so far has been poor due to the GOU’s inability toprovide any guarantees on fuel supply. Uganda’s continued powersupply capacity shortage has forced it to advertise a tender for a 60MW thermal plant by an IPP to become operational within 6 months.Bids have now been received. Uganda’s main constraint in this areawill be fuel, since it is a land-locked country, with no known source of


fossil fuel. This makes a reliable fuel supply to the thermal plant(s)extremely difficult to ensure, affecting Uganda’s ability to attract agenuine investor in thermal power generation.

The GOU is concerned that IPPs may off-load all risks associatedwith power development on either the government or the UEB. Thisconcern, while genuine, is causing delays in bringing online addi-tional capacity. The GOU has now obtained advisory services fromthe Commonwealth Fund for Technical Co-operation, for any futurediscussions about the project. Meanwhile NIP has held tentative dis-cussions with Tanzania about power exports. NIP insists that it willnot assume any risks arising out of the site recommendation in theexpected HDMP report. The draft report has now been released andranks the Bujagali site as number three on the least-cost developmentprogramme. NIP states that project financing will be obtained fromCDC but is conditional upon the execution of the PPA. The GOU onthe other hand wishes to see evidence of financiers’ commitments.Meanwhile the advice of the World Bank is that NIP should followthe private financing route, as an IDA-financed project would discour-age other projects. However, the World Bank advised NIP that itwould close any financing gap and support any unallocated risk or‘guarantee’ as a last resort. The World Bank is also committed to sup-porting any investment in the transmission and distribution networkby UEB.


The introduction of a formal regulatory system is an important part ofthe reform strategy. Presently the MNR is the regulator. Reforming theregulatory system would involve the amendment of the Electricity Act1964 to allow formal regulation of power sector actors and allow otherentities to generate and supply electricity, as well as the establishmentof an autonomous regulatory commission. The regulatory commissionis to have a full-time secretariat in MNR and membership will be part-time. It will be funded by levies from electricity fines and penalties.The establishment cost is expected to be donor-funded. An amend-ment to the Act has been approved by Cabinet and is awaiting theapproval of Parliament.

Under the existing system IPPs or any other entrants into the indus-try could be at a competitive disadvantage as the rules of the game arenot clear. This may explain why IPPs are extracting concessions orguarantees from the government. In setting up sector policy all actorsshould be treated as equals. Any agreements reached should neither


burden UEB nor should it give UEB an advantage over IPPs. This onlyemphasizes the need to hasten enactment of a new electricity act andestablishment of a regulatory commission with a clearly definedmandate and minimum government interference. The importance ofthis issue was underscored during a workshop that was organized todiscuss the ESMAP Report (Uganda Energy Sector Assessment (1996),ESMAP, World Bank) recommendations for power sector reform.Among other findings, the workshop stressed that there is the need fornew legislation that would remove UEB’s monopoly of the powersector and create a regulatory body to supervise the operations of thesector.

Decentralized power systems

The decentralization policy will allow private commercial investors toown up to 50 per cent of UEB’s existing distribution and related com-mercial services. The privately owned regional distribution entities willbe responsible for providing electricity services to final consumers inthese areas of Uganda, with an opportunity to expand into surround-ing market areas. In semi-urban and rural areas, private investors willbe encouraged to set up community-based generation and distributionsystems.

The decentralization has so far involved the establishment of a pilotproject in the Kampala area. The Kampala area customer servicesbranch is now operating under the same management semi-autonomously from the rest of UEB. This development has pro-vided better service for customers. Fault reporting, disconnections/reconnections, and settlement of accounts now proceed more rapidly.

It is planned that, eventually, industrial users will be able to generatetheir own power, or purchase power directly from a generator or distri-bution company. UEB will continue to provide transmission services.In the past there were only two independent generators, but in recenttimes three more have entered the market.

Experiences of reform implementation

Institutional reforms

UEB was, until recently, structured along functional lines with thetechnical functions being grouped together and the administrativefunctions forming separate groups. During restructuring in 1992, sepa-rate departments were created for distribution, commercial and devel-


opment function, thus diffusing the customer services function that iskey to UEB’s business success. This fragmentation of customer servicesresponsibility has proved a big disadvantage in terms of decision-making, implementation and monitoring. It is now common for thedistribution department to make new connections without advisingthe commercial department. When this happens, legal customersappear as if they are illegal.

Enabling environment

The absence of an enabling environment has affected the speed atwhich licensing of IPPs can be achieved. Uganda’s primary objective ofinviting IPPs was to add new generation capacity to reduce and ulti-mately eliminate the shortfall in power supply in Uganda. The inabil-ity of government and UEB to attract funds from traditional sourcessuch as the World Bank was another reason for opening up the powersector to private sector participation. All the IPPs that have showninterest are having difficulties putting together project financingpackages.

The absence of a regulatory framework and a transparent competi-tive bidding process has hindered negotiations for a PPA between gov-ernment and NIP. The main reason for this situation is the kind of IPPsthat are planning to invest in the sector. They do not have the type ofcredentials that inspire confidence in financing agencies. Some havetaken on local partners who have no experience in the industry.Furthermore, the absence of a legal and regulatory framework adds tothe lack of confidence financiers have in the process. Hence the insis-tence by financiers that a PPA should be concluded before NIP canobtain funding commitment.

The four IPPs that have shown interest came by invitation or inresponse to the government’s commitment to encourage and assist theentry of private developers into the Ugandan power sector. None ofthe three sites that have been allocated was subject to transparent com-petitive bidding. Such a lack of transparency in the bidding processmay explain the delay in reaching agreements.


Uganda has liberalized its economy, and opened up the power sector toprivate investors. Despite this, several key uncertainties remain forprivate investors. While there is evidence of commitment on the partof government to license private investors, the establishment of a regu-latory framework is ongoing and its provisions are yet to become law.


Thus the creation of an environment attractive to private investors isin progress while the investors are already on the ground. This seemsto be among the issues holding back NIP. The rules governing privateinvestor entry are only just being established. A proposal for a new reg-ulatory framework is before Parliament for approval and this will allowother entities to invest in the Ugandan power sector.

Government has engaged an expert from NORAD to draw up a morecomprehensive power sector reform strategy including a proposal for anappropriate long-term legislative and regulatory framework. The ques-tion of how this framework will operate in practice has been influencedby the availability of resources, both technical and financial. The size ofthe regulatory commission should be determined by the amount ofbusiness to be conducted. This is difficult to estimate. It is also recog-nized that there should be an administrative linkage between the regu-lator and MNR. This introduces the risk of MNR influencing theregulator. The Uganda power sector is small. Although plans for widerepresentation are included in the proposed regulatory framework, therewill be need to review it periodically as the sector expands.

The Minister will appoint the commissioners. While it may not bedifficult to find people of high calibre in the power sector, it is difficultfor such a system to be completely transparent in an economy likeUganda’s. An attempt has been made to frame the laws so as to ensurethat funding does not undermine the autonomy of the regulator.Establishing which function should be mandated by law and whichshould be negotiated is not a simple matter.

The capacity to implement regulatory rules effectively is determinedby the availability of technical skills and the ability to resist improperinfluence or inducements. An issue being mooted now is whether itwill be easy to recruit and retain well-qualified professionals with therequisite technical skills without exempting the commission from civilservice salary rules.

Hydrology of the Nile and reliability of fuel supply

There is no long-term plan that governs the choice of sites for IPPs.The absence of a least-cost hydropower development plan has affectedthe pace and style of the ongoing negotiations. On several occasionsdevelopers have been informed that the HDMP study is in progress andthat the results will determine the next site to be developed. Yet thefour developers on the ground have already been allocated hydro sites.This contradiction has affected NIP’s progress.


The confusion surrounding the hydrology of the Nile and LakeVictoria is further accentuated by the use of different hydrological dataregarding the construction of the Owen Falls Power Station and its pro-posed extension. As a result, the potentials of the various river Nilehydro sites are unclear. This delay in implementing the Bujagali Projectis due to the fact that the developer is not sure of the maximum energyyield of the site. Yet the government insists that the site should bedeveloped to its maximum potential.

Electricity export

An important factor in the decision by IPPs to invest in power projectsin Uganda is the ability to export part of the power generated. Thegovernment is now negotiating with Kenya and Tanzania on exportterms. Government bureaucracy, however, continues to delay theprocess. Developers (NIP) have held informal discussions with bothKenyan and Tanzanian electric power utilities on the power exportissue. Kenya’s main concerns involve the provision of a performanceguarantee in any future agreement.

Rural electrification and system improvement

Diesel generation plants supply some remote parts of Uganda. UEB,however, has decided as a matter of policy to eliminate these stationswhenever possible because of the high cost associated with their opera-tions. Rural electrification through grid connection and a decentralizedsystem based on renewable energy technologies have become optionsto achieve this. But sometimes political pressure has made it difficult toretire these stations.

An economic comparison detailed in the Uganda NationalElectrification Plan Study1 report shows that the 33 kV distributionsystem is the most profitable in Uganda for rural electrification. It alsoestablished that the existing 11 kV network was obsolete. Because of financing problems, UEB is still unable to remove some of the 11 kV lines.

Uneven regional development has influenced which ruralelectrification projects are to be undertaken. Regions with no electricityhave the edge over those that merely require line up-rating/rehabilita-tion. In some cases political and/or management prejudices and inter-ests over-ride logical decisions as to the most profitable ruralelectrification choices. Lines have been constructed for politicalreasons unrelated to serving load centres.


The government policy of rural electrification does not serve UEB’sbusiness interests. It is a social service rather than a profit-orientedsystem expansion. The government has been contributing to the activ-ity in order to ease UEB’s financial commitments. The political stabilityin Uganda and the neighbouring countries continues to influence gov-ernment’s actions and UEB’s system expansion programme. A 132 kVline has been extended to north western Tanzania and a 33 kV line hasbeen connected to Rwanda’s northern region. While there is a poten-tial market in southern Sudan, hostilities between the two countriesremain a barrier. These grid extensions are also facilitating the govern-ment’s rural electrification programme as the grids pass through ruralcommunities.

Landownership can pose a problem for the rural electrificationprogramme. Individuals who object to power lines passing over theirproperty ask for large amounts of compensation. Those who refusecompensation altogether are acting within their legal rights. The subse-quent detours involve delays and expense. Donors in partnership withUEB fund most of the rural electrification projects, providing funds formaterials while UEB does the work. This has tended to compel UEB torecruit more labour, especially when several lines are being constructedconcurrently.

Ownership/management reforms

Implementation of ownership/management reforms has only justbegun. Apart from inviting IPPs, the government has decided to pri-vatize all non-core activities that have hitherto been the responsibil-ity of UEB. So far, UEB’s timber pole plant has been offered fortender. However, it appears that there was little information availablewith respect to the tender and the process is an unfamiliar one inUganda. In addition, there is a widely held suspicion that UEB will beprivatized in the near future. The plant has now been closed foralmost a year and UEB is experiencing difficulties procuring treatedpoles.

Impact of reform

The fundamental objectives of reform are to change actions andmethods in an attempt to bring about improvements in the perform-ance of the power sector in Uganda. Reform must address the long-term implications for the sector. This section analyses the impact ofreform on various stakeholders in the power industry.


Power sector performance

The liberalization of the Ugandan economy has lead to an increase inthe economic growth rate. As a result the power sector is experiencinga high growth of demand. The situation is compounded by the absenceof any new development in supply capacity. The country is experienc-ing severe and worsening load-shedding.

Opening the industry to the private sector has attracted a number ofdevelopers. But for various reasons, such as bureaucratic bottlenecks,the absence of a transparent regulatory system and unreliable informa-tion on the hydrology of the Nile river, none of them is far enoughadvanced to give the country any hope of relief from the shortage insupply capacity.

The reform taking place in the sector is aimed at improving manage-ment of UEB. The restructuring solutions prescribed include:

• Downsizing the workforce in order to improve UEB’s financial per-formance. High staff costs have contributed to UEB’s financialdifficulties. From 1989 to 1993 the number of employees increased by40 per cent to 3374 while the number of customers increased by 17 per cent to 110 000. Salaries and wages have continued to increaseboth in terms of individual employee’s remuneration and as a per-centage of total operating expenses; by 1994 it had risen to 43 percent. The target is to reduce the present workforce of 3700 by 1000workers, i.e. 2700, by the end of 1997. This has created job insecurityamong the staff, and consequently affected their performance.

• The installation of new communications technology has greatlyaided communication between the head office and the regionaloffices and power stations. The newly installed SCADA system hascontributed to improving system performance and data acquisition.

• Redistricting of the central region (Kampala) has created morerevenue collection centres. This has enabled UEB to reach more cus-tomers than before, and it has improved its revenue collection andcustomer services.

• Rehabilitation of the system has improved the quality of service,although blackouts continue.

Government and economy

The government has had to depend on foreign loans to finance pro-jects and studies in the power sector. This has led to a substantial debtburden and an unfair allocation of resources that could have been usedin other sectors.


The government is committed to enacting an electricity law thatwould set the ‘rules of the game’ for industry participants. It isexpected that a regulatory commission will be formed to regulate thepower sector. In the interim, an Electricity Act amendment allowingentrance of IPPs is before Parliament. There is already optimism aboutthe IPPs and the public is entirely supportive of the government’s deci-sion to open up the power sector to private investment. However, thisdoes not allay the fears of foreign private sector control of the industry.

The government realizes that there will be need to maintain somesubsidies and continued rural electrification under the new plannedstructure where the distribution function will be privately owned andoperated. Various options for continuing these programmes are beingconsidered in the government’s strategic plan for the Ugandan powersector. The continuing load-shedding and UEB’s inability to adhere tothe load-shedding programmes it publishes in local gazettes havereduced customer confidence in UEB’s continued operation of thesystem. The general public feeling is that UEB, like some SOEs divestedbefore it, should be privatized.

Electricity pricing

Electricity price rationalization has been an important aspect of thereform. Electricity prices for customer classes have been increased. The current tariffs were a result of IDA conditionalities for lending theUgandan government funds for the extension of the Owen Falls gener-ation facilities. There is a general complaint about the tariff levels.Most customers think it is unrealistically high. The tariff increase madeelectricity unaffordable to some people who already had the service.Some have turned to woodfuel, contributing to accelerated deforesta-tion. Government is actively promoting the development of alternativesources of electricity.

There is also concern over the affordability of cost-covering tariffs.While investors are basing their negotiations on the current tariffs,Uganda Manufacturers Association (UMA) has presented a paper togovernment suggesting that a long-run marginal cost-based tariff islower than the current UEB tariff. This assertion, if it is true, is obvi-ously due to internal inefficiencies within UEB. Government hasrequested UEB to examine the matter.

Customers and customer services

The re-registration of UEB customers has revealed a large number ofillegal consumers and these have now been disconnected.Unfortunately, the offenders have not been prosecuted. The exercise of


re-registration has also enabled UEB to redistribute system connectionsfor load-balancing purposes.

As a part of measures to reduce accounts receivable, government hassettled all its outstanding dues. Government has settled all outstandingbills owed to utilities by all Ministries and various government depart-ments and directed UEB to disconnect any future defaulter without ref-erence to government. Only the arrears carried on the properties thathave been repossessed by returning Asians are still in question. Thenew owners have no legal liability for these arrears.

UEB has established a customer complaint office, which has been well received by the public. As a result of attempts by UEB to improve its revenue collection, a large number of customers have been disconnected. This has resulted in an increase in meter tam-pering. Customers also continue to complain about meter-reading pro-cedures. Some customers will not allow UEB officials to read the meterin their absence. While the quality of service has improved markedly,it is inconsistent. System surges are still a source of complaints by cus-tomers who suffer equipment damage as a result.

Private investors

Private investors are concerned at delays in passing legislation on regu-lation and uncertain as to the nature and scope of their rights. Whilegovernment’s commitment is not in question, there are questions con-cerning how the political climate may affect power sector regulation inthe future. At the moment the driving-force behind the currentreforms is the President of Uganda.

There is a lot of caution on both sides of the negotiating table forfear of insufficient attention to key issues that may emerge later. Inview of the GOU’s zeal to develop additional supply capacity, the newdevelopers have sometimes placed undue pressure on UEB. UEB isobliged to assist with all information at its disposal, and has thereforebeen unable to give full attention to its own activities. Some of the casestudies, such as the one at Bujagali, have been paid for by UEB. Incertain cases, UEB is still repaying the debts from these studies. Thereports have now changed hands at no cost, and the investors have notconducted new research to confirm their findings.

Obstacles to reform implementation

Attempts to reform the Ugandan power sector have encounterednumerous difficulties. The following are among the factors that con-tinue to affect the success of reforms:


1. Inadequate capacity of MNR: MNR has inadequate capacity to regu-late the power sector and perform other tasks that follow thereforms. MNR/GOU have had to hire the services of consultants inthe ongoing negotiations. Observers of the reform process inUganda are of the opinion that UEB’s reforms have not helped it toimprove its performance because of weak MNR supervision.

2. Size of the Market: investors have also shown concerns about thesize of the market. Unless they can export to neighbouring coun-tries, the local market is insufficiently large for the size of projectsbeing considered.

3. Human Capacity Problem: shortage of technical expertise is likely toaffect the regulatory capacity of the proposed regulatory body.During the whole of this period of reform design and implementa-tion, for instance, UEB had engaged experts in some line positionsin the departments of Finance, Commercial, Corporate Planningand MIS to fill key skills gaps. While most of these experts areknowledgeable, not all of them have been central to the reforms.There is conflict between local managers and the experts resultingfrom conflicting work methods, local managers complain of doingmost of the work while experts complain that local managers arelazy. At the same time the big disparity in remuneration and privi-leges, coupled to the reluctance of experts to pass on their skills, hasnot helped UEB’s operations. Experts’ contracts continue to berenewed upon expiring.

4. The level of corruption in government in general is argued to becontributing to the slow pace of the reform.

5. UEB’s current sales data do not provide a reliable indication ofrecent consumption trends. Uganda’s economy has improvedgreatly in the recent past and there is a large suppressed demanddue to capacity constraint. This suggests that a rapid load growthrate could ensue as and when this constraint is eased. This has dis-torted load forecasting and therefore affects planning for powersector expansion. Since reforms began, the various forecasts havetended to give different signals of demand growth trends.

6. The lack of systematic collection of data on service quality hamperstracing the extent of and the trend in technical problems on UEB’spower system. While reform programmes have attempted to planmaintenance, the resulting maintenance programmes have hadlittle impact on system efficiency. A SCADA system with automaticdata recording has been installed and a databank is now being builtup.


7. Legal framework: while the Electricity Act 1964 gives UEB auton-omy, it also gives the Minister in charge of the power sector author-ity to direct UEB on matters of policy, giving approval on tariffchanges and other major measures. Very often UEB managementfinds it difficult to implement changes/reforms that affect customerswithout reference to the minister. Issues like installation of pre-payment meters have had to obtain ministerial approval. The pro-posed legislation for the power sector will establish a newrelationship between the minister and UEB, based on arm’s-lengthregulation of the utility’s operations and finances.

8. Bureaucracy: the bureaucratic procedures of UEB managementhinder quick decision-making. In addition, managers lack theauthority necessary to execute certain decisions. For example,UEB management cannot make a procurement decision of morethan Ush 5 million without the approval of the Board ofDirectors.

9. Politics: changes in political leadership sometimes lead to changesin UEB management, affecting continuity of some of UEB’s pro-grammes. In the last 10 years there have been Cabinet reshufflesthat have changed the minister responsible for the power sectorthree times. On each of these occasions UEB’s areas of emphasis haschanged. It is hoped that the new legal and regulatory frameworkwill eliminate such interference.

Lessons from experience

Over the last 10 years, the government of Uganda has worked hard atimplementing an economic recovery programme that gives high prior-ity to the rehabilitation, expansion and maintenance of the country’sinfrastructure. The economy has responded favourably to the reformprogramme. The following factors have emerged as being critical to thesuccess of reforms in the power sector:

Government commitment

It is of paramount importance that the government shows a strongcommitment in order to eliminate fears of policy reversals. Thisenhances investor confidence in the transparency and fairness of theprocess. The Ugandan government’s commitment has been demon-strated by the successful privatization of other SOE’s with vigoroussupport of the President. So far interested investors are operating in theabsence of a legal and regulatory framework. Government assurances


and concrete moves toward establishing a regulatory regime have con-vinced investors of the seriousness of its intentions. The government’svital role is to create an ‘enabling environment’ in which investors canoperate with confidence. For the country to raise international capital,it must play by international rules and give up certain national prac-tices. Governments need to improve the general climate for foreigninvestment and identify the reforms needed in order to make privatesector participation attractive.

UEB’s chronic need for subsidies and soft loans has convincedgovernment of the need to rid itself of the utility. However, it muststill contend with UEB’s importance in terms of employment and thesignificance of its product.

Public confidence

The Ugandan public is suspicious of foreign participants in the privati-zation process. For example, one of the reasons cited for rejecting theproposal to contract out management of UEB was that the assets couldbe frittered away at minimal value without assurance of replacement.This has happened to privatized SOEs elsewhere in Uganda’s economy.There is also a lack of public awareness of the benefits of changed own-ership. There is little support for reform among management andemployees of UEB. Therefore there is need to raise public awarenessthrough campaigns and discussions with UEB management andemployees.

Regional markets and capacity

Uganda’s vast hydropower potential can be developed for the exportmarket although Uganda exports approximately 25 per cent of its totalgeneration to Kenya, this export market is neither secure nor finan-cially attractive. The power that is exported is the remainder after theneeds of the domestic market have been met. Capacity constraintshave meant that UEB has not met its obligation to Kenya. While theagreement is to supply Kenya with 30 MW of firm power, UEB cannotmanage more than 17 MW off peak. This has given rise to Kenya’sunwillingness to renegotiate the tariff to a more realistic level (nowUS$0.56 per KWh).

Inter-regional connection with the South African grid would enableUganda to tap the reserve capacity in the region in order to meet peakdemand. In the prevailing circumstances, Uganda’s best hope ofmeeting its domestic demand lies in enlisting the assistance of theprivate sector. If Uganda’s power system was interconnected with the


South African regional system the capacity deficit could be covered byimports.

Uganda would therefore benefit from regional interconnection. It isimportant to use trade to minimize energy and capacity costs. Themain constraints to regional trade in electricity and petroleum prod-ucts are political and commercial. Many countries in the region areunwilling to rely on their neighbours for such a key economic input.Failure to agree on a pricing system or to meet or enforce contractualobligations has stalled trade between Uganda and Kenya, despite thefact that it is in both countries’ best interests.

Transparency

Experience from other sectors suggests that transparency is an impor-tant condition for private investment. Private investors are attracted byenabling environment, which can only be created by institutional,legal and regulatory transparency. Uganda’s market is small and thereare no domestic capital markets. The only reasons private investorshave shown interest are the existing macroeconomic stability, lowinflation and government commitment.

However, the absence of a regulatory framework has resulted in alengthy negotiation process. The need to expand access to electricitybeyond the current low levels is at the heart of government concerns,while commercial aspects of power supply, technical performance, theexport market, and the need for cost recovery tariffs, are the mainissues of interest to private investors. There can only be agreementbetween the two sides when the process is transparent.

Legal and regulatory framework

Uganda’s Electricity Act 1964 does not appear to pose significanthurdles for private participation in the power sector. However, themonopoly rights it accords UEB are a threat to any potential competi-tor. The Act allows UEB to license electricity generators and thereforegives it the role of power sector regulator. The legislation does not spellout rules for price-setting, the issue of licences, provision of adequateappeals or the mechanisms for resolving disputes. The regulatorysystem should establish a fair and transparent process.

Note1 This is one of reports on the power sector prepared for the Uganda Electricity

Board by EDF in November 1992.


8Power Sector Reforms in SubSaharan Africa: the Mauritius ExperienceRené Noel

Introduction

During the past 15 years Mauritius has experienced a rapid economicgrowth. This is the result of the pursuance of an industrialization strat-egy that preserves the monoculture-based sugar production. Thegrowth of the economy has resulted in significant increase in energyconsumption in all sectors of the economy. Electricity consumption, inparticular, has grown significantly, from 380 GWh to 1151 GWhduring a 12-year period. This increase, in a small island country withlimited energy resources, has raised the problem of the economicdevelopment of the energy sector in order to ensure the country’s sus-tained development.

This chapter seeks to present and discuss the major the issues in thepower sector. It also examines some of the problems facing the sector,the measures studied and already taken or envisaged to solve them inthe most economical way, without affecting efficiency and security ofsupply.

Historical features and existing framework

Initially composed of small independent private undertakings supply-ing electricity to consumers, the electricity sector grew rapidly to thepoint when the need was felt for a corporate regulatory body. This ledto the creation, in 1952, of a Central Electricity Board (CEB) which,four years later, became the sole public supplier of electricity. As such,

176


the CEB became responsible for the generation, transmission and dis-tribution of electricity throughout the country. As a para-statal body,its role and operating conditions are defined in the Central ElectricityBoard Act 1964 as subsequently amended. It now operates under theaegis of the Ministry of Public Utilities (MPU).

In this context, it can be said that final decisions regarding electricalenergy rest with the CEB board of directors and ultimately with theMPU and the government. However, the definition of an overallenergy policy taking into consideration all related matters must, per-force, involve other important sectors and organizations before beingadopted by government.

Such matters include, inter alia, the search for new energy sources, thereliability and price of it and, pending the implementation of a medium/long-term policy, the adoption of measures intended to guarantee elec-tricity supply to consumers as their requirements increase. This has ledto the involvement in energy-related matters of other Ministries such as Finance, Industry and Commerce, Planning, Agriculture andEnvironment; of para-statal bodies such as Mauritius Sugar Authorityand the University of Mauritius; of the private sector such as MauritiusSugar Producers’ Association and individual sugar companies.

As far as electricity generation is concerned, one major change hasoccurred since the CEB became the sole supplier in 1956. This is thegrowing participation of sugar factories as exporters of energy to thepublic grid, CEB remaining responsible for transmission and distribu-tion. This particular point will be discussed in detail later, but itsimportance is indicated by the fact that, in 1996, this exported energypurchased by the CEB represented as much as 10.3 per cent of the totalelectricity generation. It is in the context of this existing frameworkthat the authorities concerned have to manage the electricity sector,solve its immediate problems, and define a long-term policy. Let usfirst see what is the present and foreseen technical situation.

Electricity supply and consumption

Table 8.1 shows electricity generation by source for the years 1970–96and may be briefly commented upon as follows:

• Electricity generation has increased by 746 per cent since 1970 andis now increasing at an annual rate of some 10 per cent;

• Imported energy-related products, for example fuel-oil, diesel andkerosene, have largely met the growing demand;

René Noel 177

178Table 8.1 Electricity generation by source

Year Hydro Bagasse Coal Fuel-oil/diesel Kerosene TotalGWh % GWh % GWh % GWh % GWh % GWh %

1970 51 37.5 22 16.2 63 46.3 135 1001971 50 33.8 25 16.9 73 49.3 148 1001972 68 41.5 23 14.0 73 44.5 164 1001973 74 39.6 24 12.8 89 47.6 187 1001974 40 19.2 24 11.5 144 69.2 208 1001975 56 25.0 17 7.6 151 67.4 224 1001976 55 20.4 25 9.3 190 70.4 270 1001977 56 18.2 24 7.8 228 74.0 308 1001978 54 16.1 25 7.5 256 76.4 335 1001979 59 16.6 26 7.3 270 76.1 355 1001980 83 23.4 27 7.6 245 69.0 355 1001981 60 16.6 31 8.6 271 74.9 362 1001982 94 25.9 43 11.8 226 62.3 363 1001983 35 9.4 32 8.6 304 81.9 371 1001984 65 17.1 29 7.6 5 1.3 281 73.9 380 1001985 115 29.3 58 14.8 45 11.5 174 44.4 392 1001986 110 25.1 73 16.6 43 9.8 213 48.5 439 1001987 140 28.7 74 15.2 29 6.0 244 50.1 487 1001988 99 18.0 72 13.1 34 6.2 339 61.7 51 0.9 549 1001989 148 25.1 56 9.5 68 11.5 310 52.6 71 1.2 589 1001990 85 12.7 53 7.9 45 6.7 449 67.2 360 5.4 668 1001991 76 10.3 70 9.5 54 7.3 494 67.0 438 5.9 738 1001992 13 14.0 85 10.5 43 5.3 498 61.6 693 8.6 808 1001993 104 12.0 71 8.2 40 4.6 615 70.7 396 4.6 870 1001994 75 7.9 77 8.1 46 4.9 699 74.0 48 5.1 945 1001995 134 12.8 84 8.0 41 3.9 682 65.2 106 10.1 1047 1001996 104 9.0 119 10.3 10 0.1 699 60.7 219 19.0 1151 100

• The hydro potential, limited by the country’s size and topographyand subject to largely varying climatic conditions, may be consid-ered as fully exploited;

• The bagasse share has not followed the overall trend but its contri-bution in quantity has greatly increased, and it is known that itspotential is largely unexploited.

This matter will be addressed in detail in the following section. In the light of the above past consumption statistics and of forecastedtrends based on macroeconomic and other factors, it is now estimatedthat the country’s electricity consumption is likely to reach some 3900 GWh by the year 2020. This sets the size of the problem from apurely generating capacity standpoint.

Up to now, this question of available installed capacity has been ofconstant importance in order to keep pace with industries’ increasingdemand and, as such, it has necessitated recurrent and urgent deci-sions. In particular, these have concerned the past development offuel-oil/diesel power stations and, since 1988, of gas turbine-drivenplants which offered the advantage of prompt delivery.

Urgent decisions, however justified, are of course not always the bestas far as efficiency and costs are concerned and this has prompted thesearch for other sources within the concept of long-term planning.Without prejudging the conclusions of the Long Term National EnergyPlan that is awaiting final completion, a study was initiated. This studywas initiated in collaboration with the then Ministry of Energy, theMauritius Sugar Authority, the Mauritius Sugar Producers’ Association,the Mauritius Chamber of Agriculture and other government andprivate sector bodies, to define the best way of optimizing the bagasse-derived energy potential of the country.

This resulted in the elaboration and adoption of the Bagasse EnergyDevelopment Programme that is now being implemented in a some-what modified form to face practical considerations but whose finalobjectives remain unchanged. This implementation is presented in thefollowing section of this chapter.

Bagasse Energy Development Programme (BEDP)

As already mentioned, the only departure to the role of sole electricityproducer entrusted to the CEB has been the growing participation ofthe sugar industry in the supply of electrical energy to the grid. Startedas far back as 1957, this participation took the form of individual

René Noel 179

purchase agreements between the sugar companies concerned and theCEB, the amount of supply being initially unspecified and the unitprice being the object of case-by-case negotiations.

The unspecified amounts, called ‘énergie à bien plaire’ was meant tobe whatever amount was available as surplus or was needed by the CEBto meet customers’ demand. Bagasse, the fibrous by-product of sugarcane that remains after juice extraction, represents some 30 per cent byweight of the cane crop from which sugar is manufactured. As such itis an important renewable source of energy which, properly managed,far exceeds the energy and process steam requirements of sugarmanufacture.

This high potential, up to now, has never been fully exploited andelectrical energy export to the grid by sugar factories has long beenconsidered more as a way of saving on the costly disposal of surplusbagasse than as a source of revenue. It did, however, reach 16.6 percent of the country’s requirements by 1989 but could not keep thisshare for a number of reasons. Some of these reasons are:

• Rapid increase in electricity demand due to industrialization;• Unsatisfactory pricing structure for bagasse electricity;• Relatively low cost of oil products;• Unreliability of electricity surplus from sugar factories;• Seasonal nature of the sugar industry.

It is the recognition of these factors and of the consequent wastedpotential which gradually led to the definition of different categories ofsuppliers with different conditions of supply and price rates applying.This has ensured a situation whereby, in 1996, surplus energy ex-bagasse has represented a record 119 GWh, or 10.3 per cent of thecountry’s requirements, even before the implementation of the BEDPbecomes largely effective by the turn of the century.

The BEDP, adopted in 1992, defines a strategy for maximizingenergy production from surplus bagasse. This provides for optimiza-tion of all factories’ steam/energy balance, generation of surplusenergy being assumed only by the largest units. These are termed ‘firmsuppliers’ when they use bagasse during the crop season and coalduring the off-crop, or ‘continuous suppliers’ when they use onlybagasse during the crop season including weekends. According to thisconcept, ‘énergie à bien plaire’ as already defined is intended to disap-pear and any surplus bagasse from the smallest factories will be sold tothe largest units.

180 The Mauritius Experience

On this basis, and taking into consideration the centralization policywhereby only some 10 out of 17 factories will remain operative in 10–12 years’ time, it is likely that at least 6 and perhaps 8 units will operate as ‘firm suppliers’. These ‘firm suppliers’, will use themaximum amount of surplus bagasse saved by appropriate improve-ment to the factory equipment, and coal during the off-crop period. Atthe present time of writing, two firm power units were operating and athird one will operate in the year 2000. As from 1998 it was expectedthat there would be not less than seven ‘continuous suppliers’. The endresult by the year 2010 could be the availability of some 250 MWinstalled capacity, generating not less than 660 GWh ex-bagasse and900 GWh ex-coal.

The programme, as presently implemented, is based on a simple co-generation process using a technology well known to the sugar indus-try but using more and more high efficiency equipment as the need forthe replacement of existing plant arises. On this basis and in thecontext of the above mentioned centralization process, not less than110kWh of exportable energy should be available per tonne of canecrushed. This would represent the above mentioned yearly export of660 GWh ex-bagasse, that is, 55 per cent of the present consumptionor 17 per cent of the expected consumption of the year 2020.Expressed in different terms, it also means using a clean, renewablesource of energy to save the import of some 400 000 tonnes of coal oraround 200 000 tonnes of fuel-oil.

Regarding the policy aspect of the implementation of the BEDP, thevery adoption of the Programme meant that the principle of privatiza-tion of an important part of the electricity generation sector was anaccepted fact since only 1 of 17 factories (a smaller than medium unit)is government controlled. This was a valuable factor in decision-making at sugar groups level concerning factory closures and energypolicy; it resulted, through easier negotiations, in some 10 agreementsregarding supply and tariffs between sugar companies and CEB underthe aegis of a Technical Committee of the MPU. Similarly, the always-difficult problems of bagasse pricing and ownership of the new ‘sugar’power stations were resolved during these negotiations. Thus, a‘bagasse transfer price’ was agreed for all bagasse used for purposesother than for sugar manufacture and made payable to cane producers.The question of ownership was also made easier by the existence of thenewly created Sugar Investment Trust which owns 20 per cent of theshare capital of all sugar factories and whose members are the employ-ees and cane growers of the industry.

René Noel 181

In the case of ‘continuous suppliers’, the power stations are part ofthe factory equipment and owned by the sugar company itself. In thecase of ‘firm suppliers’ which are much bigger stations, the same struc-ture occurs in one case; in the others, the sugar companies form, withother partners, an independent generating company whose installa-tions are close to the factory and which purchase bagasse from it andother factories, selling back to it process steam and energy at agreedprices.

Generally speaking, contractually agreed prices between CEB and thepower stations are based on avoided costs and are subject to an indexa-tion formula. Other factors may, of course, be considered as influencedby national policy, itself dictated by strategic reasons linked to self-dependence, environment, balance of payment, and desire to help thesugar industry diversify its sources of revenue.

Power installed and the amount of supplies are also the object of dis-cussions based on the tonnage of cane crushed for crop time genera-tion and on alternative coal burning during the off-crop to meetguarantee of supply requirements. Notwithstanding these changes,there was no modification to the structure of the CEB, which retains itsrole as solely responsible for transmission and distribution.

In conclusion to this section it can be said that no major difficultieswere encountered in the technical evaluation of the bagasse energypotential and in the definition of the guiding principles of the pro-gramme. This was largely facilitated by the national approach and bythe participation of all interested parties adequately represented in thecommittees and subcommittees which dealt with specific problems, aswell as by the acknowledged importance of the problem.

The adoption and implementation of BEDP do not, however, offercomplete solutions to the problems facing the electricity sector in theyears to come although, with its coal alternative component, it shouldmeet some 40 per cent of the country’s requirements by the year 2020.

Requirements of the future

A study of the developments in the electricity sector, identified the fol-lowing as the likely major future requirements of the sector:

• The technical requirements of the sector to meet the consumer’sdemand which is expected to more than triple within the next 25 years;

• The choice of other possible sources of energy;


• The security of supply;• The economic cost of supply;• The ownership and management of the energy sector.

All these are of course closely interrelated and will not be completelyseparated in order to avoid repetition. Furthermore, the very word‘future’ implies unknowns and uncertainties, and meeting long-termfuture requirements does mean pragmatism and correcting measures asdictated by experience and changing conditions.

Future consumption is taken as present trends and what futurechanges may indicate. For example, the possible implementation of alight railway project intended to replace part of the existing publicroad transport system will mean increased electrical energy consump-tion but less diesel consumption and air pollution. The country willneed additional installed power in the future, and maximization ofrenewable bagasse energy by ‘sugar’ power stations will not besufficient. The need, therefore, exists for new sources if they exist or forplanning additional fuel-oil/kerosene plants.

Among new sources to be developed, those which have for manyyears received attention are retention of tidal water in the south of theisland, solar energy, and wind energy. The first source was neverstudied in depth and is not now considered, while the two others areaccepted as potentials, although limited. As an indication, solar energyis used solely for domestic water heating by individual consumersresiding in the sunniest parts of the country and its impact on totalenergy consumption is negligible. Wind energy use has, however,received much attention. Experimental stations have been set up, andestimates have been made of the average potential from some 10 possi-ble sites, which is not expected to exceed 15 GWh per year at a costnot yet known but likely to be high.

Two other renewable sources of energy have also been consideredlately in conjunction with the implementation of the BEDP. Theyconsist of the possible use of other cane biomass, for example canetops and trash as boiler fuel, and of waste product incinerators.Technically feasible, experimental projects are being conducted underthe aegis of the Mauritius Sugar Authority and the use of these prod-ucts, if found financially viable, would be integrated in the BEDP. Theend result could be a sizeable source of energy whose use within theinitial BEDP projects would also help to avoid CEB investments.

Security of supply, another important aspect of any long-term plan,can be improved by the use of these renewable sources which, as such,

René Noel 183

are now receiving all the attention they deserve in order to address allrelated issues. The integrated use of cane biomass in the BEDP ‘sugar’power stations is of course easier to envisage as far as management andownership are concerned, while waste product incinerators presentmore problems of collection, ownership and costs; these can, however,be solved. The neighbouring Réunion Island’s experience in usingwaste incinerators for power generation, now commercially operative,will be of great help in an eventual implementation of such a projectin Mauritius within BEDP. Security of supply was also an importantfactor in the decision to implement the BEDP in its present form withcoal as an alternative fuel for ‘firm’ suppliers. Dual-fired boilers,burning bagasse and coal, are well known to the sugar industry. Coalcan be obtained from near and secure sources, and its use during theoff-crop season offers firm base-load supply to the grid by using steam-and electricity-generating equipment which, otherwise, would remainidle for six months every year.

Once electrical energy supply from BEDP sources, that is bagasse,coal, biomass and waste products, has been fully tapped, the need tomeet the outstanding demand by other sources and to replace obsoleteCEB plant will always remain and has to be faced. And this brings theultimate question about the future structure of the energy sector. Thepolitical aspect of privatization is one which is outside the scope of thischapter. We shall therefore only consider tendencies that are of publicknowledge and shall draw attention to specific points of a technicalnature that will have to be addressed when thinking of private energysuppliers. What is of public knowledge is that the concept of Build,Operate and Transfer, and of Build, Own and Operate is now acceptedand that it may apply to the energy sector as well as to other publicutilities. Independent Power Producers (IPP), as they are called, have ineffect operated, as we have seen, since sugar factories started exportingenergy to the grid. And the procedure to extend the formula to an IPPintended to own and operate two new 24 MW sets within an existingCEB power station was initiated for implementation in 1998. Theinvolvement of IPPs has not materialised as the project has been aban-doned for practical reasons. Instead, CEB has ordered the two new 24 MW sets for its own power station.

As far as is known and as initiated or implemented up to now, thisaspect of privatization concerns only generation, CEB purchasingenergy from the IPPs and remaining the sole responsible body fortransmission and distribution. The advisability or opportunity toextend privatization to transmission and even distribution may be


envisaged but such a change seems difficult to achieve in a smallcountry like Mauritius where all economic and domestic sectors are sointerrelated. From a strictly technical point of view, in the full knowl-edge of the existing public grid structure, of the need to monitor andmeet growth in demand and standby capacity, of carrying out repairsand restoring supply after cyclones, it is difficult to see how security oftransmission and distribution could be maintained across the countryother than by a single authority. Furthermore, because of the need for a national co-ordinating action in a small country, such a co-ordinating authority can hardly be any institution other than a para-statal. This, of course, does not preclude the eventual necessity toreorganize the internal structure of CEB if this proves necessary oruseful in the light of reduced investments and less responsibility forenergy generation.

All these matters are now receiving the constant attention of theauthorities concerned and it is generally expected that the joint effortsof government, CEB and private sector will result in a sustained, econ-omic and technically adapted development of the energy sector tomeet the country’s requirements adequately.

René Noel 185

9Cross-Country ComparisonsJohn K. Turkson and Robert Y. Redlinger

Introduction

There is probably no factor that determines the countries’ individualpower sector experiences more than their economic policy framework,which includes government priorities, the order and effectiveness ofpolicy measures. This factor is so crucial that strategy and impact ofrestructuring of the same industry, that is the electric utility industry,can be radically different in different countries. The country casestudies presented in the foregoing chapters demonstrate the extent anddegree of reform undertaken in the power sectors of these countries. Itis evident from these case studies that the nature, process and imple-mentation of power sector reform varies significantly between coun-tries. In this chapter, an attempt is made to perform a cross-countrycomparison of these countries with respect to: (i) motivations forreform; (ii) the process and types of reform implemented; (iii) paths to reform; (iv) regulatory issues; (v) open competition; (vi) managingthe transition; (vii) power sector reform and rural electrification; (viii) energy efficiency and integrated resource planning and (ix) benefits and deficiencies of the reform.

Motivations for reform

Power sector reforms in the six countries has been motivated by avariety of factors including policy issues as well as economic or practi-cal considerations. One of the fundamental country characteristics isthe economic policy environment in which the reform takes place.Most of the countries have undergone or are about to implementStructural Adjustment Programmes (SAPs). An aspect of this pro-

186


gramme is the liberalization of the macroeconomy. In theory, whengovernments liberalize their markets/economy and pursue soundmacroeconomic management and trade policies, both private andpublic enterprises come under intense pressure to operate efficiently.Of the six countries, Mauritius is, by far, the best managed economy.The rest are at different stages of macroeconomic reform. The SAPshave put pressure on the governments to reform their public utilityindustries such as the power sector, telecommunication, water andpostal services. The reforms, generally, aim at attracting investmentand improving efficiency in the sector. The reforms are also considereda means for the power sector to grow to meet the economic growthand social improvement needs of the countries.

The countries presented consider the reform as a means of address-ing the inefficiencies and deficiencies in the sector. They see reform asstimulating inefficient power sector companies with high productioncosts to become more efficient, and also see it as a means to rectify thepower sector’s inability to deliver reliable, affordable electricity servicesto the population, where existing demand/supply gaps limit access toelectricity and affect reliability.

Another motive for initiating power sector reform is the realizationthat the traditional multilateral sources of funding are not readilyavailable and that alternative sources of funding, mainly from theprivate sector, would be the major future sources for power projectsand infrastructure. Thus, the reform is designed to create an enablingenvironment for private investors to participate in the developmentand growth of the power sector.

In addition there are the various international pressures on countriesto liberalize their energy industries and economies in general.International accords and agreements, themselves driven by politicaland economic liberalization motives, have created a momentum forelectricity sector reform in Ghana, Uganda, Zimbabwe and Kenya.

The case studies demonstrate that reforms in these countries arelargely being driven by a common theme: the need to improveefficiency and the financial performance of utilities, and the need toharness private sector capital to finance investments in power plants,transmission and distribution lines to meet the growing andunsatisfied electricity demand. While there are similarities of driversand motivations for reform in these countries, there are, however,divergences in their responses which include: internal industry reformin Zimbabwe, deliberate reform process preceded by regulatory changesin Ghana, co-generation (as IPPs) in Mauritius, introduction of IPPs in

John K. Turkson & Robert Y. Redlinger 187

Uganda, management contract and introduction of IPPs in Côted’Ivoire.

Process of reform

The unique characteristics of the electric power sector make it neces-sary to tackle the restructuring issue with a long-term vision. Countriesin the region have different needs and thus need to fashion a reformprogramme which takes country-specific conditions into account. Animportant factor in power sector reform is the political commitment ofgovernments to such reform. Such commitment from the politicalauthority calls for countering the ‘myth’ and beliefs regarding theenergy sector in general and the power sector in particular that aredeeply ingrained in the political authority and a large section of thepopulation. Among these beliefs, it is worth mentioning concepts suchas energy self-sufficiency and energy independence, the ‘strategic’nature of certain energy resources, and the common acceptance ofarbitrary subsidies in fuel prices and electricity tariffs due to their being‘essential inputs’. The need to counter such deeply ingrained ideas pro-vides a strong reason to get the public informed and involved in thereform process. Generally, however, the involvement of the public hasbeen very limited in all of the countries studied.

The question of how committed these governments are to reformingtheir electricity industries is not easy to answer. To the extent that effortsare being made to set correct prices that reflect the cost of supply, to fillthe supply gap in power generation by opening the generation segmentto IPPs, and to streamline the regulatory system to provide transparencyin price-setting, one can conclude that there is some commitment onthe part of the governments in these countries. Such commitment hasbeen shown, for example, in Ghana by the creation of a committee tostudy and recommend to government a new industry structure and theregulatory system needed, leading to the passing of legislation to estab-lish the public utility regulatory commission. A very important aspect ofsuch a committee’s work was to acknowledge from the outset that therewere no miraculous short-term, easy, quick and low-cost solutions to thepower sector’s problems, and that it is only possible to handle the taskssuccessfully if there is wide support from all stakeholders in the sector. InKenya such a commitment has been shown in the passing of theElectricity Bill by Parliament.

The reform process has to evolve, and the existence of well-definedgoals and objectives is essential, which shows that the likely difficult

188 Cross-Country Comparisons

measures to be adopted will ensure an evolution in the right directionand will bring concrete, rational, achievable, and fair solutions, ratherthan short-lived improvisation of high cost solutions for narrowsectors of the population.

A look at the strategies adopted by the countries analysed in thesecases indicates two general models of reform. The first model addressesthe revenue problems of the industry within the framework of a verti-cally integrated utility, largely by passing management to a contractorwith more autonomy from government to raise and restructure tariffsand enforce sanctions for non-payment. This model has been used inCôte d’Ivoire. The other strategy has been described as the ‘open com-petitive’ model. This model enforces a reorganization of the sector on acompetitive basis, especially for those segments of the industry mostamenable to competition (primarily generation). It also separates thesegments of generation, transmission and distribution into distinct enti-ties and offers transparent prices between them, possibly through theoperation of an independent regulatory body. Theoretically, the reformsin Ghana, Kenya, Uganda and Zimbabwe will all follow this model.However, each of these countries has adopted a different approach toimplementing this model, with different experiences and results.

The reform process and approaches are as diverse as the six countriesthemselves. There has been a divergence in process ranging betweeninternal utility reform to improve efficiency in Zimbabwe; a deliberateand formal reform process preceded by regulatory changes in Ghana;and regulatory changes subsequent to structural reform in Côted’Ivoire. The approaches adopted range between ‘big bang’ andgradual/incremental approaches. The reforms in most of the countrieswere donor-driven, with varying degrees of local inputs both at theconceptual level and at the implementation level.

Côte d’Ivoire, the first country to initiate a more serious reform of itspower sector, essentially contracted a private company to manage andoperate its state-owned, vertically integrated utility through a manage-ment contract. It further opened the generation segment of the indus-try to independent power producers (IPPs). Côte d’Ivoire has followedan approach of privatizing the utility first, and then gradually definingand refining the regulatory structure as the need arises. For inexplicablereasons, this defining and refining process has led to the proliferationof official institutions with overlapping functions, all with the aim ofregulating and monitoring the privatized entity.

Ghana, on the other hand, adopted a more measured approach toreform. It started by creating a commission to study the sector and


recommend to government a more workable industry structure whichinvolves: (i) the de-integration of the vertically integrated monopolyinto generation, transmission and distribution companies; (ii) enactinglegislation to make all power sector entities limited liability companiesand (iii) the introduction of wholesale competition in the electricitymarket. A regulatory commission has been established to regulate theactors in the industry. This is in sharp contrast to the approachadopted in Côte d’Ivoire, especially with respect to the role of a singleindependent regulatory body in the reformed power sector.

Another contrast is Zimbabwe. Zimbabwe’s approach focused primar-ily on corporate restructuring using performance contracts and com-mercialization to improve efficiency within the continuing operationsof the state-owned vertically integrated utility. Reform of the powersector in Zimbabwe relies more on structural changes than ownershipchanges. While Zimbabwe Electricity Supply Authority’s (ZESA) verti-cally integrated monopoly structure is being maintained, the genera-tion segment of the industry is being opened to private sectorparticipants. The reform also involves the privatization of non-coreactivities of ZESA.

Uganda is still in the process of formulating its reform strategy. It isenvisaged that Uganda Electricity Board (UEB) would be unbundled,IPPs would be allowed into the generation segment, and the privatesector would be encouraged to participate in the distribution segmentin joint ventures with local governments or the national government.

Kenya Power and Light Company (KPLC), which has been operatingon a commercial basis for quite some time, has dominated Kenya’spower sector. It is also one of the few power sector companies inSubSaharan Africa with a history of private sector involvement. KPLChas private sector minority shareholding. External pressures fromdonors such as the World Bank and the International Monetary Fundhave significantly pushed Kenya’s power sector reform. The reform inKenya has involved the re-configuration of the generation facilities(hydro and thermal plants) under a separate company, Kenya PowerCompany (KPC). KPLC is now responsible only for transmission anddistribution and, as in all of the case studies, IPPs are also involved inthe generation segment of the emerging industry structure.

As regards the approach to implementing reforms, Côte d’Ivoire, rel-atively speaking, adopted a ‘big bang’ approach. This is demonstratedby the speed with which the management of the state-owned utilitycompany, Energie Electrique de Côte d’Ivoire (EECI), was contractedout to a private firm before the issues of regulation and supervision


were defined. Ghana, Zimbabwe, Uganda, Kenya and Mauritius, whichhave adopted different reform paths (see next section for detailed dis-cussions), have adopted a more gradual/incremental approach.

Paths of reform

In view of the pressure for reform in SSA and the type of reform beingadvocated by some bilateral and multilateral organizations, two fre-quently asked questions are: ‘is there a single industry structure towardwhich reforms should aim?’ and ‘is there one correct approach toreform?’ The six country case studies demonstrate that there is nosingle successful path or approach to reform. Figure 9.1 shows the pathof reforms in the six countries studied. This may be compared with thesimilar Figure 2.1 showing paths taken by the USA, Chile, New Zealand,and England and Wales. The vertical axis represents utility ownershipand management structure, ranging between complete governmentownership, public (government-owned) corporation, and private own-ership. The horizontal axis represents the industry’s competitive struc-ture, varying between vertically integrated or partially verticallyintegrated monopoly, multiple generators with possible competition inthe generation segment selling to one common purchasing agent (nor-mally the existing vertically integrated monopoly), wholesale competi-tion, and retail competition.

Ownership/management changes

Most electric utilities in SSA are public corporations. Figure 9.1 shows,for example, that Ghana, Côte d’Ivoire, Kenya and Zimbabwe havemoved from government departments to government corporations. Itis at this point that the debate on whether the reform of the industryshould maintain its public ownership or to move further on to involvethe private sector is being engaged. Many of the proposed changes inthe power sector in SSA are in ownership/management. A change thatinvolves the movement from public ownership to private ownership,and the main rationale for such changes, is that privatization of exist-ing power sector companies would improve efficiency and also invest-ment in additional capacity.

The power sector entities in these countries all have a history ofstarting as a government department in one form or another. At thetime when reform was initiated or being contemplated in these coun-tries, all of the countries’ electric utilities were public corporations, andsome still continue in this manner.


Kenya and Côte d’Ivoire have generally followed similar paths. Inboth countries, government-owned vertically integrated monopolieswere converted into corporations with varying degrees of private andpublic ownership. In the case of Côte d’Ivoire, management and opera-tion of the state-owned vertically integrated electricity company, EECI,was contracted out to a private company, Compagnie Ivoirienned’Electricité (CIE), under a long-term management contract arrange-ment, thus moving upwards (in Figure 9.1) on the ownership/manage-ment continuum from public corporation to partial privatization. CIEis majority owned by a French group, but a minority share of CIE’sstock is also traded on the Abidjan Stock Exchange. The governmentalso maintains a minority stake. The Ivorian government also has apolicy to increase the contribution of thermal power generation to theelectricity supply in the country. This policy has also paved the way forIPPs to operate in the generation segment. There are currently two IPPsoperating in Côte d’Ivoire: CIPREL and AZITO.


Figure 9.1 Country power sector reform direction: existing and proposed

Source: Adapted from Hunt and Shuttleworth, 1996: 14.

Kenya, on the other hand, has five state-owned organizationsinvolved in the supply of electricity. With the exception of KPLC, all ofthe organizations were fully state-owned entities. KPLC is the biggest ofthese, and its shareholdings are allocated 59 per cent for the govern-ment and 41 per cent for the private sector. KPLC is listed on the localstock exchange, and, along with CIE in Côte d’Ivoire, represents one ofthe only two electric utility companies with stock market listings in thesix countries studied. Most of the power sector entities in Kenya havebeen commercialized and have introduced performance contracts aspart of the country’s reform process. Figure 5.7 (in Chapter 5) showsthe reform path Kenya has been following, and the future reformscenarios.

Ghana, Zimbabwe, and Uganda are maintaining state-ownership oftheir power sector companies. As part of the reform, however, varyingdegrees of commercialization and performance contracts have beenintroduced. Ghana has passed a legislation making all the power sectorcompanies limited liability companies. There are also plans to organizethe distribution segment of the industry into different concessionzones for high-, medium- and low-density areas, and either encourageprivate sector participation through joint ventures with the existingdistribution company or grant concessions to private companies or co-operatives. Ghana envisages its electric utility landscape to be made upof both private and public operators in the generation and distributionsegments of the industry.

Mauritius provides a unique experience. Its electric utility has longrelied on the sugar industry to generate a significant proportion of thecountry’s electricity supply through co-generation facilities. The state-owned Central Electricity Board, which is also responsible for transmis-sion and distribution of electric power, has been purchasing powerfrom the sugar industry through power purchase agreements since1957.

The ownership/management changes that have taken place to-date,with the exception of Côte d’Ivoire, are quite marginal, in the sensethat there has been very limited private sector involvement in theexisting power sector entities. What most of these countries are doingin terms of private sector involvement is contracting out various ser-vices, beginning with non-core activities. Perhaps this is a deliberatepolicy by governments to limit private sector involvement in the exist-ing entities, but rather to encourage private sector involvement inbuilding new generation capacity and extension and rehabilitation oftransmission and distribution networks.


Industry structural changes

As can be seen in Figure 9.1, all six countries are opening the genera-tion segment of the industry to IPPs. In fact, five of the six – Côted’Ivoire, Kenya, Mauritius, Zimbabwe and Ghana – have IPPs alreadyoperating. Uganda is in the process of finalizing an arrangement withan IPP to develop a hydro site. However, one factor, which is notevident in Figure 9.1 is the current degree of competition, or lackthereof, at the generation level in spite of the appearance of IPPs.Most of the countries have only one IPP currently operating, thoughthere are indications that more IPPs are about to enter the industry.In the countries where only a single IPP is operating, it is not clearwhether their entry was subject to a competitive bidding process orwas based on a political decision to offer a contract to one particularcompany.

Entry by the vertically integrated utility into contractual arrange-ments with one or more IPPs to generate and sell electricity to theexisting monopoly has thus been a major aspect of all case study coun-tries’ reforms. This indicates a realistic approach by the countries, con-sidering the serious shortfall in electricity supply in most countrieswhich must be remedied at a time when governments and electric util-ities face economic and financial crises. There are, however, two coun-tries (Ghana and Kenya) where some form of competition is beingintroduced at the generation level involving all generators, includingIPPs.

Ghana is dispensing with the common purchasing agent typical ofthe other countries and is introducing wholesale competition in whichgenerators compete to sell power to large customers and distributionconcession monopolies through negotiated bilateral contracts and aspot market. To achieve this, Ghana has planned to unbundle its exist-ing utility structure. Uganda also proposes to unbundle its existingelectric utility and allow private investors into both the generation anddistribution segments of the industry, though Uganda is not as faralong this process as Ghana.

Such categorization sometimes makes it difficult to place certainemerging structures. The location of Ghana, Côte d’Ivoire, Kenya andZimbabwe in the ownership/management – industry-structure space infigure 9.1 gives the impression that these countries are restructuringtheir respective utilities along the lines of model 2. The reality is that,even though the introduction of IPPs has increased the number of gen-erators operating in these countries, real competition does not exist


among the generators. Almost all the IPPs are operating under powerpurchase agreements (PPA) with the government or existing state util-ities. The increasing interest of the private sector to participate in theindustry in SSA offers an opportunity for countries to reform theirpower sectors in a way that would encourage and nurture competitionin the sector.

Open competition

Of all the six country studies, only the case studies of Ghana andKenya consider open competition as an aspect of the reform of theirpower sectors. However, an element present in all the reform strategiesof the six countries – the introduction of IPPs – can be a basis for theintroduction of some form of competition, possibly in the form ofcompetition depicted by model 2. This possibility is further enhancedby the fact that the transmission systems of all the countries are inter-connected with their neighbours, with the exception of Mauritius. Thiscan be a reality only if the reforms in these countries allow large con-sumers and distribution companies to buy power from other generatorsoutside their respective countries’ borders. Presently, Ghana, Kenya,Uganda, Côte d’Ivoire and Zimbabwe have agreements with theirneighbours to buy or sell power. These agreements are in most casesbetween state-owned utilities. As these countries pursue the powermarket competition option, there is the need for the countries todevelop their financial, legal and regulatory institutions. The rule oflaw must be respected and enforced, and the broader political andsocioeconomic environment must be enabling to the private sector.

Staying with the issue of introducing competition in the powersectors of these countries, it appears that the size of the system and themarket also matter. Most of the countries presented in the case studieshave systems either less than 1000 MW or just over 1000 MW, and alsoabout 30–40 per cent of their population have access to electricity,with the exception of Mauritius which has close to 90 per cent access-ibility. Thus, while any future private generation would be aiming atsatisfying the suppressed demand for electricity in these countries,opportunities to sell electricity to industries and distribution compa-nies in neighbouring countries would make investments in generationvery attractive indeed for the private investors. In spite of the small sizeof the system in Northern Ireland, for example, competition is ensuredby interconnection to the Scottish system through submarine cables.


Regulatory issues

Regulatory changes cannot be easily portrayed in the ownership/management – industry-structure space portrayed in Figure 9.1. It isnonetheless a very important element of the reform process.Historically, the power sector in most SSA countries has been state-owned. Often, these state-owned entities have been subject to govern-ment involvement in day-to-day operations and the provision of largegovernment subsidies. Such involvement or interference is manifestedin different forms. One form of interference occurs because the variousgovernment agencies and organizations involved in particular aspectsof power company operations (tariff setting, investment and environ-ment) each have, by the nature of their functions, a particular view ofthe power sector. Given that each government organization plays someform of regulatory role, each organization attempts to impose its ownvision (which may be in conflict with others) on the sector.

On the other hand, interference can also arise through the lack ofaccountability of power companies’ top executives. Given the impor-tance of their role in the national economy, these executives are oftenappointed by governments and usually have direct access to thehighest level of political decision-making. As a result, utility executivesare often able to flout ministries’ authority and operate, in effect,outside the realm of regulatory oversight. Furthermore, the powersectors in the region have been characterized by the absence of acoherent, long-term energy and institutional strategy which can existindependently from political interference.

To address this, institutional and legal reforms are aimed at eliminat-ing or considerably reducing government involvement in the dailyoperations of the sector. This has meant the creation of an autonomousbody to regulate those segments of the sector which have naturalmonopoly characteriztics such as transmission and distribution.

Three of the countries studied have passed, or are close to passing,legislation to set up regulatory bodies to regulate the reformed powersectors. Ghana passed a Bill in 1997 to establish an independent regu-latory body, the Public Utilities Regulatory Commission (PURC).Kenya’s Parliament has also passed a Bill to set up a regulatory body,and Côte d’Ivoire is initiating a process to streamline the numerousinstitutions performing regulatory functions. Setting up such a regula-tory body involves the establishment of transparent regulatory mech-anisms such as electricity tariff reform, and development of reliability,accounting, and management standards for the players in the industry,


that is government, consumers and producers. Most importantly, thelegislation establishing regulatory bodies in these countries providesfor the rules of the game and the regulatory system to be transparentand predictable. Creating such a regulatory framework requires the sep-aration between government policy and regulatory responsibilities.Uganda and Zimbabwe are also considering the possibility of creatingsuch independent regulators, but have not yet done so.

Implicit in these reform paths is the issue of whether to institute aregulatory system prior to undertaking any industry restructuring ornot. Kenya and Côte d’Ivoire essentially undertook structural reformsbefore dealing with the regulatory issues. Ghana, on the other hand,adopted a strategy of defining the regulatory system before undertak-ing industry restructuring. Uganda also appears to favour the Ghanaianapproach. The significance and impact of the timing of regulatorychanges in these countries will only be determined in the future.Nevertheless, some discussion of the experiences of other countriesmay help underscore the importance of timing of regulatory changesin relation to industry structural changes.

At issue in the reform process is which of these two – regulatory/institutional reform or privatization – should come first, or should theybe implemented simultaneously? There is no simple answer to this.Different countries have adopted different strategies and have had dif-ferent results. The UK, for instance, created an Office of ElectricityRegulation (OFFER) shortly before divestiture of the state-ownedmonopoly. Chile established the National Energy Commission as anautonomous regulatory body for electricity in 1978 and introduced itsregulatory laws for telecommunication and electricity and divested in1982. Mexico introduced discretionary price regulation almost concur-rently with divestiture (Galal et al., 1994). Chile was thus notable forputting an institutional framework in place long before privatization.This enabled the Chileans to acquire some experience in regulatingmonopolies prior to divestiture, and secondly, contributed to the reli-able provision of electricity at reasonable cost to consumers (Galal etal., 1994; Spiller and Martorell, 1996).

In a region where experience in utility regulation is non-existent andprospective private sector investors are wary of the unpredictability ofthe regulatory system, it is sensible to put a regulatory institution inplace and regulate the corporatized power sector entities for a few yearsbefore divesting. This will also allay the fears of the population thatpublic monopolies are being converted into private monopolieswithout a proper regulatory system in place.


These case studies show that there is no single successful path toreforming the power sector in SubSaharan Africa, and that a widevariety of approaches to implementing the reform can yield positiveresults. However, some common lessons do emerge. These include theneed for clarity in the envisaged industry structure, for a strong regula-tory body and for clear and transparent rules and responsibilities.Equally important for successful reform in SSA are factors such as polit-ical commitment and efficient management during the transitionperiod.

Managing the transition

Having designed the overall picture for the future structure of thesector and its institutional and regulatory systems, the next over-ridingconcern becomes how to manage the transition to a restructured powersector. Some of the major transitional issues are as follows.

a) How can reliable power supply be achieved?

As has been noted earlier, improving performance has been theprimary goal in the discussions of reforming the power sector in SSA. Acritical aspect of the reform is thus how reliability of power supply canbe achieved. Addressing this issue involves examining whether con-sumers have a way of communicating their preferences for reliabilityand whether the industry has the capacity to respond to theseexpressed preferences.

With the exception of Mauritius, the answer to the first question is‘no’ for a majority of customers in all customer classes in the countriesstudied. Prices are set independently of service reliability, as entities inthe sector are used to pricing below cost; and pricing strategies are notreliability-differentiated to enable customers to make choices. This hasled to a situation where electric utilities in the region have notreflected customer preferences for quality of service in their resourceplanning process. This is, in part, due to the structure of the sector andhow they have been managed in the past.

b) What are the criteria for transmission and distributionregulation and pricing?

Posing this question as a transition issue and limiting the regulatoryquestion to only the transmission and distribution segments only pre-supposes that the industry will be de-integrated or unbundled and thatthe generation segment will be open to competition, with conse-


quently little need for regulation. The transmission and distributionsegments, on the other hand, are considered natural monopolies andtherefore must be regulated to prevent misuse of market power. In fact,only Ghana is aiming at this kind of unbundled industry structure. Theremaining countries are either maintaining existing vertically inte-grated systems, as in Zimbabwe, Côte d’Ivoire, Mauritius and Uganda,or are implementing partially vertically integrated systems as in Kenya.Thus, effective regulation of generation will continue to be required inaddition to that for transmission and distribution.

The key issues in pricing transmission and distribution services toenable them to perform efficiently are: pricing should be transparent,that is industry participants (suppliers and consumers) should knowhow the prices for different services are arrived at by the regulator;each generator should have open access to the transmission grid; andfinally, for pricing to be efficient, prices must reflect the cost of service.With the endemic problem of cross-subsidization in vertically inte-grated monopolies, such transparent pricing mechanisms can onlyexist with a strong regulator and functional or accounting separationof the different segments of the vertically integrated monopoly.

c) Institutional challenges

There are institutional challenges that must be met during the transi-tion. Two of these challenges are presented here. The first is to restruc-ture existing utilities into units that can operate in a reformed industrystructure. This is particularly critical to the generation segment as it isopened to competition, but there is also the need to set up anautonomous regulatory body and regulatory framework that providesincentives for efficient operation of transmission and distributionsystems, as discussed above. The second challenge lies in sharing thepain of reform. The question here is ‘who will bear the cost?’ All stake-holders, including electricity suppliers, ratepayers and government, arelikely to bear some costs, but experiences from countries like the UKand Chile suggest that different stakeholders bear the costs of reformsin different proportions. It is beyond the scope of this chapter to assesscosts and benefits for different stakeholders; however, it is important toensure a fair allocation of burdens if reforms are to succeed.

Power sector reform and rural electrification

Though it was not explicitly discussed in some of the country studies,the issue of rural electrification featured prominently in the discussions


at the workshop at which these country studies were presented. Thequestion of ‘how to electrify the rural and low-income communities ina reformed power sector?’ was posed. This question was consideredhighly pertinent because it is perceived that reforming the powersector could imply the reduction or elimination of rural electrificationprogrammes as the utilities are drained of financial resources, as theCôte d’Ivoire experience suggests. Indeed the experiences of Ghana,Zimbabwe, Kenya and Uganda all suggest that politically motivatedrural electrification programmes through grid extension, in the absenceof appropriate tariff structures or collection ability to recover the cost of service, have exacerbated the financial problems of all of thesecountries.

The financial crisis of the utilities has happened in an environmentwhere electricity tariffs have been consistently set below the cost ofsupply. This has been the case in Ghana, Uganda and Kenya. It isplanned that such below-cost tariffs are to give way to marginal-costpricing. Achieving commercial and financial viability of the companiesoperating in the reformed power sector is one of the major objectivesof reform in all countries studied.

Such commercialization, in theory, could help rather than hurt ruralelectrification programmes. By introducing commercial objectives intothe management and operation of state-owned enterprises, commer-cialization will tend to involve the removal of subsidies, as the enter-prises become subject to the same tax laws, prices and accounting rulesas other companies in the private sector. When utilities are required torecover the cost of serving customers, including those in rural areas,they are more likely to adopt appropriate technologies and systemssuch as small-scale renewable energy which is often much less ex-pensive than grid extension for supplying electricity to isolated ruralareas. If retail tariffs accurately reflect generation, transmission and dis-tribution costs, there will be stronger incentives to supply electricity torural communities.

In Kenya, the ineffectiveness of the official electrification programmehas directly contributed to the successful development of a thrivingprivate market for photovoltaic (PV) electricity. This success for PVs inspite of (or perhaps because of) lack of government support indicatesthat, even in rural areas of SubSaharan Africa, the keen demand forbasic electricity service has meant that a sizeable number of Kenyanshave been both willing and able to pay full market prices for electricity(Acker and Kammen, 1996). Concessions for rural electrification con-tracts can also be awarded which encourage the most cost-effective


solutions and which can complement the business strategies of pri-vatized distribution utilities. In South America this has been the case in Argentina, for example.

Thus, commercialization and rural electrification are not incompati-ble. In fact, Kenya has implemented a 5 per cent levy on all electricitycharges that will specifically fund rural electrification within the newindustry structure. The issue in Kenya thus has not been lack of avail-ability of funds, but rather accountability and control over the leviedfunds. Commercialization processes, which improve accountability,should also help improve the effectiveness of electrificationprogrammes.

Energy efficiency and integrated resource planning

Of the six countries studied, only Zimbabwe explicitly mentionedenergy efficiency as an important part of its reform strategy, in whichZESA is both enhancing customer satisfaction and reducing peakdemand through demand-side management (DSM) programmes. Whatrole energy efficiency will play in a restructured power sector is an issuethat has been much debated in developed countries such as the USA.The conventional wisdom in developed countries has been that electricutility industry reform and the advent of competition have led to thedemise of integrated resource planning (IRP), in which all supply-sideand demand-side investments are evaluated on an equal footing toprovide energy services at lowest overall cost (see Swisher et al., 1997).However, in terms of SubSaharan Africa, looking back at Figure 9.1indicates a very different situation compared to that of developedcountries.

The term ‘power sector reform’ means very different things in differ-ent countries. While such reforms may lead to complete retail-levelcompetition in Scandinavia, the UK, or the USA (‘Model 4’), Figure 9.1indicates that only one of the six SSA countries studied currently hasany plans to move beyond Model 2, in which multiple generators sellto a common purchasing agent. This Model 2 framework is preciselythe structure that existed in the USA during the 1980s and early 1990swhen the concepts of DSM and IRP were developed. In fact, one of theoriginal goals of IRP in the USA was to incorporate independent powerproducers such as co-generation facilities into the utility planningprocess. Thus, in the SSA context, there is no conflict between power sector reform and demand-side management or integratedresource planning. With the overall electric resource-planning process


(including generation) continuing to be conducted through thecommon purchasing agent (i.e., the former monopoly utility), coun-tries can still evaluate whether their energy service needs can be more cost-effectively met through supply investments by the utility or IPPs, or through demand-side investments in energy efficiency orload-shifting.

In Zimbabwe, the conclusion has been that DSM is in fact beingstimulated by power sector reform. This is a result of the fact that pricecontrols by the government are being relaxed, allowing both highertariffs in general and the implementation of time-of-use pricing. Withhigher overall tariffs and time-differentiated tariffs, the incentives forcustomers to participate in demand reduction or demand-shiftingprogrammes is greatly increased compared to the past when tariffswere subsidized.

Benefits and deficiencies

The long-term verdict on power sector reform in these six countries,and indeed in SubSaharan Africa, will not be known until some time inthe next century. The reform process is not always smooth, and inap-propriate decisions are often made. There are no guarantees thatreforms will be implemented successfully in any one country. Thedifficulties strewing the path of reform can be considerable, andwithout well-designed strategic interventions, may fall disproportion-ately on vulnerable groups. One of the critical issues is how ruralelectrification programmes can be pursued within the framework ofpower sector reform. There may be opportunities for cherry-picking byprivate investors in the absence of appropriate government interven-tion, but carefully implemented private sector electrification strategiesmay in fact provide greater accessibility at lower cost than expensivegrid expansion programmes pursued in the past.

Reforms that introduce competition at either the generation or retaillevels, or both, do lead to cost reduction as a result of increasedefficiency. However, because almost all of the countries studied havetraditionally set tariffs below marginal costs, power sector reform doeslead to initial increases in tariffs. The benefits of increased efficiency,on the other hand, may not be readily apparent until later. A fair andopen process is thus critical to maintaining public confidence duringthe difficult transition period. Ensuring that the reform process doesnot simply lead to a changeover from public monopoly to a privatemonopoly, duopoly, or oligopoly remains a major task.


Conclusion

The comparative assessment of the reforms in these countries hasshown that power sector reform takes different forms, and moves at adifferent pace in different countries. At the mundane level, we findthat power sector reform in all the countries is motivated by the needto improve efficiency and to attract private capital into the industry.Ownership/management changes, structural changes and regulatoryreform in the electric utility industry may well be the most interestingdevelopments in the countries in SubSaharan Africa in the years ahead.A lot of issues are yet to be played out in countries that have embarkedon reform of their power sectors. It is too early to determine successesand failure. These countries, nevertheless, offer the rest of SSA somelessons to be considered. Whether many more countries in the regionare going to initiate power reform is yet to be seen.

References

Acker, R. A. and D. M. Kammen (1996). ‘The Quiet Energy Revolution:Analysing the Dissemination of Photovoltaic Power Systems in Kenya’,Energy Policy, 24: 1.

Galal, A., Jones, L., Tandon, P. and Vogelsang, I. (1994).Welfare Consequences ofSelling Public Enterprises: An Empirical Analysis (Oxford University Press).

Spiller, P. and Martorell, L. V. (1996). ‘How should it be done? Electricity regula-tion in Argentina, Brazil, Uruguay and Chile’ in R. J. Gilbert and E. P. Kahn(eds), International Comparisons of Electricity Regulation (New York:Cambridge University Press).

Swisher, J. N., Jannuzzi, G. M. and Redlinger, R. Y. (1997). Tools and Methods forIntegrated Resource Planning: Improving Energy Efficiency and Protecting theEnvironment, UNEP Collaborating Centre on Energy and Environment, RisøNational Laboratory, Denmark. Working Paper No. 7, November.


10Conclusions and Policy SummaryJohn K. Turkson

Introduction

The fundamental goal of this book has been to contribute to theongoing debate on power sector reform in developing countries, par-ticularly SubSaharan Africa (SSA), by presenting and analysing thereform process and implementation experiences in six countries inSSA. This task has essentially been accomplished. This chapter seeks toprovide readers with a broad but necessarily tentative assessment ofthese experiences, and some policy-related issues that are critical to thereform of the sector. This assessment must remain tentative as manyaspects of the reform in these countries have yet to be played out.

Changes in the sector are taking place in the region and thesechanges are taking different forms. One of the main difficulties of gov-ernments undergoing market-based reforms is in first accepting andthen explaining to the public the difference between the respectiveresponsibilities of regulator and owner of facilities dedicated to thepublic service. To a public used to subsidized energy prices and toler-ance towards energy theft, the policies of ownership and industryrestructuring may be alarming. The public has a right to expect thatthe government in its new role as regulator is every bit as concernedfor the quality and cost of energy services as it was in its role as owner.

Assessing reform process and implementation

Most electric utilities in SubSaharan Africa have problems in providinghigh quality services to their customers. Power outages and voltagefluctuations are quite high in many cases. Meter-readings are infre-quent and bill collection rates are very poor. This situation has con-

204


tributed greatly to the financial problems of the utilities in the region,and has been a drain on the national economies as governments keepbailing utilities out of their financial crises and also the utilities’ under-taken capital investments in the sector.

In the face of the dismal performance of the utilities, it is quite ironicthat the impetus for reform in countries that have reformed theirpower sector and those considering such reforms, has come not fromthe public, at least not overtly, but from external sources such as multi-lateral and bilateral agencies. In many countries the reform of the elec-tric utility industry has come as part of the Structural AdjustmentProgrammes (SAPs) that countries are implementing to correct thestructural imbalances in their respective macroeconomies.

In general, the focus of the reforms taking place in the region hasbeen on ownership/management changes and attracting privateinvestors into the industry as generators. Industry restructuring issuesas well as regulatory issues are not given equal attention in the reformprocess. Such an attitude towards reform can cut both ways. In onerespect it does not lend confidence to private investors or potentialentrants into the industry, thereby denying the industry the much-needed capital injection from the private sector. In another respect itprovides opportunities to some private investors to capitalize on suchan environment to demand huge concessions and guarantees fromhost governments for their participation in the sector. In such situ-ations the governments end up bearing most of the risk associated withsuch investments without enjoying any financial returns, since all thereturns accrue to the investors.

Ownership/management changes and industry restructuring requiremajor administrative and institutional capacity, and a measuredapproach, given the complexity of the industry. Such capacity may notbe adequate in most of the countries. This point is underscored by thecase of Côte d’Ivoire, where after privatization there was a rush toestablish institutions to regulate and/or supervise the new actors in theindustry. This led to multiplicity of structures with the sole purpose ofregulating the industry.

Critical issues

Notwithstanding the attractions of reforming the power sector indeveloping nations, the process and implementation of the reformrequire the examination of certain critical issues that may be peculiarto developing countries.

John K. Turkson 205

Pricing of electricity in the reform environment has to reflect thecost of supply. This means some significant increase in electricity pricesfor all customer classes. Such price increases are inevitable conse-quences of the reform of the industry. They are, in fact, one of thereasons for reforming the sector. In this situation, it raises the question– how do countries handle the implementation of these priceincreases? For sure, such price increases could cause serious politicalproblems for the governments of reforming countries or countries thathave reformed their power sectors. A case in point is Ghana, wherethere was a public uproar resulting from electricity rate hikes by theelectricity companies. This led to intervention by the President whoordered the suspension of the implementation of the new electricityrates. The Public Utilities Regulatory Commission, which is now dulyconstituted, but was not at the time of the uproar, is engaged in aseries of public hearings in the country to educate and inform the dif-ferent customer classes regarding the reasons for the new rates andhow they are going to be implemented.

Rural electrification and increasing accessibility to the majority of thepopulation are issues that are given little attention and are seldom dis-cussed in the reform of the sector. The Côte d’Ivoire chapter contendsthat the utility’s engagement in rural electrification programmes actuallycontributed in large measure to its financial crises that led to its privatiz-ation. How the rural electrification programme is going to be imple-mented in the new industry environment is not clear. Similarly, there isuncertainty as to how Ghana’s national electrification programme will beput into practice when elements of the power sector reform strategy arefully implemented. Increasing access to electricity in the countries in SSAis an integral part of the sustainable development paths that countries inthe region are following. These are very important issues that remain tobe tackled as the reform of the sector unfolds in the years ahead.

Another element of the reform that has to be prevented is the abilityof some stakeholders to influence the regulatory process to their advan-tage – ‘Regulatory Capture’. ‘Regulatory capture’ has always been aproblem with regulated industries. Regulators are subject to ‘regulatorycapture’, making them servants rather than the masters of the compa-nies they are supposed to regulate. There have been cases where regu-lated firms ‘captured’ their regulators and learned to take advantage ofthe regulatory process, thereby earning significant returns for low-quality services. In other cases, consumer activists ‘captured’ the regu-lators and succeeded in obtaining services at rates insufficient tocompensate investors adequately for their capital investments.

206 Conclusions and Policy Summary

Lessons

Much has been said about potential gains from privatization and otherreforms of the state-owned electric power companies. However, to date,only a few countries in SSA have reformed or initiating reforms. Themajority of the countries are still to undertake reforms. What distin-guishes countries that have reformed from those that have not? This is adifficult question to answer precisely because reform of the power sectorin SSA is at its early stages. It is thus too soon to judge the benefits anddeficiencies of the process. Nevertheless the limited experiences of thecountries presented in this volume provide some significant lessons forcountries in SSA contemplating a reform of their power sectors.

Initiation of the reform process

The reform menu normally includes institutional and regulatoryreforms, commercialization and corporatization of existing powersector entities, management contracting, attracting Independent PowerProducers, unbundling of the vertically integrated electric utility com-panies and privatization – partially or fully – these companies.Countries in the region have different needs and will thus need tofashion a reform programme tailored to their specific conditions. Theexperience of Côte d’Ivoire indicates that restructuring the industrywithout putting a regulatory system in place could create significantproblems that may affect the sharing of gains from the reform. TheIvorian case study suggests that the reform was implemented in haste.This contrasts with the approach followed by Kenya, Ghana andZimbabwe. While the items on the reform menu are sound from aneconomic standpoint, countries have to figure out how to initiate andmanage the reform process. The unique characteristics of the electricpower sector make it necessary to tackle the restructuring issue with along-term vision. There are many changes occurring in the electricpower sectors in SSA. Over the next 5–10 years, the power sectors inthe region have to position themselves to meet the potential demandfor electricity in the region and to support the region’s economic andsocial progress. In preparing to meet the challenges of the comingdecade, the power sectors have to shed the negative image ofinefficiency and actually have to increase efficiency.

Regulatory and policy issues

The experiences of the six country case studies presented in thisvolume suggest that these countries reformed their power sectors with

John K. Turkson 207

varying degrees of emphasis on regulatory reform. In order to accom-plish a successful reform of the power sector, governments need thepolitical will to implement reforms. This will occur only if there issupport throughout all sectors and levels of government. Governments,financial institutions and the private sector need to devise methodsthat allocate risks in a way that makes power sector projects competi-tive with those in other regions of the world. This process includesrelated regulatory and policy issues, such as the establishment of anindependent regulatory process; reduction in subsidies to energy com-panies; electricity rate reform; development of reliability, accountingand management standards; and reduction in energy losses and theft.Furthermore, the rules of the game need to be well established andtransparent, and made equal for state and private enterprises. The regu-latory system must be transparent and predictable. In this regard, thereis a need for bilateral and multilateral co-operation to help createregulatory structures, to train regulators, and to eliminate energy tradebarriers among regional nations.

Some of the options needed to address the issues raised include:

• Independence of Regulatory Establishment: it is essential that gov-ernment policy and regulatory responsibilities should be establishedwithin separate and independent institutions. The independence ofthe regulatory body can be further enhanced by well-functioningand independent judicial and legislative bodies. Thus any unduegovernment influence in the regulatory process can be challenged incourt, and/or the legislature can over-ride government policy thatinfringes on the independence of the regulatory process. A regulatoryentity should be established which is independent from the execu-tive and legislative branches of government. This entity should havefixed terms for top level regulators with appointment based on pro-fessional competence; have a professional well-trained staff; and witha mechanism for independent funding. The regulatory process mustbe transparent. An important element of this process is to establishbasic technical, accounting, performance and legal standards for theregulated industry to ensure reliable, safe and equitable service thatin turn ensure and maintain the financial viability of the industry.

• Pricing and Financial Viability of Industry: the power sector shouldbe self-financing as much as possible, with rates that recover thecost of supply, including an adequate return on investment andrecognition of environmental costs. Government may providefinancial assistance or cross-subsidies to ensure universal service and


to electrify rural communities. These mechanisms, however, shouldbe implemented within the framework of a rural electrification strat-egy, indicating how the mechanisms would be implemented andhow long the cross-subsidies should be in place.

• Development of regional electricity markets: most of the countriesin SSA have small power systems and small domestic markets. Largeinvestments in the sector could be influenced by the size of themarket for power. Consequently, creating a regional electricitymarket that ensures electricity trading across a country’s borderscould promote investment in power sector infrastructure. The gov-ernment has a role in facilitating the creation of regional markets.This involves the exploration of how existing generating capacity insub-regions of SSA can be most effectively utilized through thedevelopment of power pools or interconnected power grids. Oncethe markets are created, governments should allow the electricitymarket to operate as freely as possible on the basis of private andpublic enterprises and competition. Government policies and regu-lation should enhance electricity trading, and should be limited toestablishing basic rules and procedures within which the industrymust operate, and ensuring fair and open competition among allmarket participants.

Financial issues/requirement for power project financing

Issues related to financing power sector projects are of critical impor-tance. The lack of financing is generally perceived to be one of themajor constraints preventing the realization of electricity projects of alltypes. Many countries in SSA still experience levels of country risk thatprevent them from attracting the amount of financing they need to‘grow’ their electric utility industries. This is shown in the risks of cur-rency devaluation, political risks and currency inconvertibility. Whilethese are risks that are specific to the country as a whole and not thepower sector, these problems affect the electricity sector especially hardsince the energy sector is capital intensive with long-term life-cycleinvestments. High levels of country risk cause capital flows to bevolatile, capital inflows to be short-term in nature, and cause there tobe an inadequate amount of capital to meet demand.

Countries that succeed in meeting their electricity requirements willneed to solve the problem of putting their energy sectors on a soundfinancial footing in order to mobilize domestic and foreign capital.Power sector reform and infrastructure development remains stronglylinked to domestic capital market development. There needs to be a

John K. Turkson 209

better base of domestic long-term capital available. However, thereality of the situation in many countries in SSA is that there has notbeen a clear commitment on the part of the governments to privatesector investments in the power sector, particularly in the existingstate-owned electricity companies. The creation of an enabling en-vironment – clear rules for private sector participation and clearlegislative policies on the type of investments allowed – is a necessity.

Countries in SSA have recognized the need to attract capital to thepower sector in order to provide electricity supplies needed to supportsustainable economic development and growth. Those countries thathave implemented reforms have done so to place their power sectorcompanies on a sound financial footing. However, additional steps arenecessary to ensure that needed capital is available for this vital sector.Countries in SSA have to adopt a multi-pronged approach to attractingcapital into the sector. Elements of a multi-pronged approach include:

Corporate strengthening and corporate financing

A dominant feature of the power sector entities is their inability toraise capital on their own account. In that sense sectoral reform shouldbe accompanied by corporate strengthening of the power sector enti-ties. This would present an opportunity for easier and possibly cheaperfinancing in the sense that it provides opportunities for operationalefficiency gains and institutionalization of commercial business focus.All these reduce investment risks by providing additional liquidity andsecurity to capital providers. In a commercial environment, utilitieswill seek to maximize profits. If their revenue is subject to regulation,they can best do this through cost minimization.

A turnaround of utilities from loss-making to profit-making willmake corporate finance of projects feasible in the region. Corporatefinancing relies on the attractiveness of a utility’s balance sheet andprospective cashflows to attract debt and equity. This form of financingcan be used for both existing enterprises and new ones that are beingcreated. Most power utilities in SSA have not been accustomed to theculture of corporate financing of investment projects, thus the intro-duction and internalization of such culture in the management of theutilities would set the basis to attract capital into the power sector.

Creation of capital markets

Weak and nonexistent domestic capital market and institutions haveprevented the channelling of the savings to the power sector and otherproductive sectors of the economy. A well-functioning capital market


can be an invaluable intermediary to financing power sector projects.Presently, there are about 10 capital markets in SSA. The Johannesburgstock exchange is by far the biggest in Africa, controlling about 92 percent and 96 per cent of capitalization and turnover respectively, whilethe Nairobi stock exchange, one of the oldest in Africa, currentlyaccounts for 2 per cent and 1.2 per cent respectively. The Ghana stockexchange, one of the youngest and fastest growing equity markets inAfrica, compares favourably with the Nairobi stock exchange in termsof capitalization and turnover.

Countries in SSA need to make concerted efforts to mobilizedomestic savings by creating attractive investment opportunities. Inspite of the negative impression, there is evidence that indigenousfunds are available in Africa. The question is how to channel them tothe formal sector. For example, a private sector bond issue inCameroon in 1992 raised $9.2 million from Cameroonian nationals.Ghana mobilized approximately $60 million from domestic investorsin its floatation of the Ashanti Goldfields Corporation in 1994.Countries in the region have realized the importance of creating anenabling environment to mobilize domestic resources, and attractingforeign capital. The growth of capital markets bears evidence of thistrend. The Tanzanian and Malawian stock exchanges opened in late1996. The Kampala, Uganda, stock exchange became operational at theend of 1997, and that of Mozambique is expected to be operational bymid 1999. There are indications that establishment of capital marketswith conducive regulatory environment assuring the unhindered oper-ations of private sector concerns is very important to the process ofattracting capital.

With such enabling environments prevailing in the region, the pushfor better profit and more diversification of portfolio would generateinterest in developing markets. A recent research by the World Bankconfirms that cross-country portfolio diversification is more importantthan diversifying across sectors. Similarly, the establishment of capitalmarkets, provision of a conducive environment and the beneficialimpact of wide-ranging structural reforms, legislative as well as econ-omic, should serve to pull international private equity capital into theregion. As some governments in the region have liberalized or elim-inated capital restrictions, improved the flow of financial informationand strengthened investor protection, they have earned the attentionof the investment community.

Experience has shown that private sector participation in the powersector through a well-functioning capital market will open previously

John K. Turkson 211

restricted activities to a universe of new market entrants, such as IPPs(e.g. Tanzania and Uganda) and retail billing and collection contractors(e.g. EDF in Ghana). The potential competition that these new entrantscan engender in the supply chain will reduce capital and financingcosts of investing in power sector projects.

Mobilizing domestic savings

Domestic savings are critical to the sustainability of power sectorfinancing and indeed, financing of economic activities in SSA. In devel-oped countries nearly 90 per cent of the savings are intermediatedthrough financial institutions; in contrast to developing countrieswhere the figure is around 15 per cent. In SSA domestic savings as apercentage of GDP average around 17.6 per cent between 1980 and1988. A critical issue, however, is the capacity of financial institutionsin SSA to perform the role of financial intermediation.

Whether capital is raised from consumers by power utilities throughrealistic electricity prices or through capital market instruments frominvestors, the central issue is the need to tap domestic savings tomobilize enough investment funds for the power sector. Foreigninvestment – direct and indirect – will be seen as a catalyst of thereform process. Thus mobilizing domestic saving is critical to sustain-able long-term investment financing of power sector projects in SSA.

Regional power interconnection and bulk power trading

Regional electric power interconnection is often economically andfinancially attractive. The reason why trade in electric power has notdeveloped faster in the region may be connected with the lack ofcommercial objectives within the utilities themselves. Developmentof regional interconnection and bulk power trading is assisted in anumber of respects by power sector reform. Power sector reformfacilitates the development of a clear commercial mandate. Thisenvironment would reduce or eliminate fear on the part ofprospective investors in the sector that electric power markets inmost countries in the region are too small. The potential for export-ing surplus power makes the argument of small market-size a mootone.

It is relatively easy to develop systems for trading in the supply ofelectric power. It is in the interests of both parties, provided a frame-work can be agreed for sharing the benefits from trade. A concernshared by existing and potential independent power producers is themonopsony power of existing state-owned utilities. If they were faced


with multiple purchasers, they would have greater confidence in theirability to sell power and receive fair price. This re-emphasizes the argu-ment that power sector reform is a critical ingredient in facilitatingelectric power trading in the region.

Other supplementary initiatives such as pricing of bulk power, trans-mission pricing and access, open access and wheeling of power areimportant to bulk power trading and as such have to be studied andmechanisms put in place to facilitate bulk power trading in the region.There is also a problem of weak domestic contract law in SSA countriesand there is some doubt in the cross-border enforcement mechanisms.In view of this, mechanisms must be put in place to enforce cross-border contracts.

Supplementary policies and initiatives

Most utilities in the region have been exempted, by law, from incometax payment to central governments, and formal dividend payment tothe equity holder(s), which are the governments in the region.Removal of these exemptions, and tax and dividend payment require-ments for state-owned utilities, should be put in place as a matter ofpolicy. While this may serve as a catalyst for utilities to pursue a com-mercial business focus, they remove any sources of unfair advantageexisting utilities are likely to have over potential entrants into theindustry. While requiring utilities to pay taxes and dividend, it mustalso be required that in its role as a purchaser of electricity, govern-ments and their agencies should be subjected to exactly the samepricing and payment discipline as other customers.

From the human resource standpoint, there is a need for staff plan-ning and development. Staffing problems in the power utilities in theregion can and should be addressed by proper planning and imple-mentation of a staff management programme. A well-conceived and-developed programme for staff development can identify needs and

how these can be addressed. This will involve determining the presentsituation and comparing it with achievable goals. Defining the utility’sgoals requires assessing the organization structure, work practices, pro-ductivity and the appropriateness of the technology. Once this is done,a decision must be made concerning the skills that are missing in thecompany, and a programme designed to fill them. In the short term, itmay require hiring people from outside. In the wider context of overallpolicy analysis, strategic planning and staffing the regulatory body,there should be a serious effort to fill positions with qualified andcompetent people. The physical creation of institution is only the

John K. Turkson 213

means, but the critical aspect of institution-building is staffing themwith qualified personnel.

More often in SSA, certain commercial decisions within the powersector are left to government to take. This is because power sectorentities are state-owned, and governments have been involved insome way in the management and operations of the entities.Elevating pure commercial and business negotiations between utilitiesin two countries, for instance, into the political realm often prolongnegotiations and have sometimes stalled them. Political differencesbetween countries can cause a profitable commercial venture to beabandoned. In an era where countries in the region are making everyeffort to attract capital into the power sector, the power sector reformsin the region should facilitate business transactions between utilitiesin different countries. Such business transactions could lead to theintegration of the power sectors of the countries concerned throughinvestments in the transmission segment of the industry. It is truethat there is often electric power demand in countries, which gener-ally lack energy resources, and energy resources are concentrated inother countries that have low electricity demand and low growthpotential. The integration of electricity systems in SSA and the jointexploitation of energy resources are, therefore, imperative. Initiativessuch as these could minimize the development and running costs ofthe electricity system, improve its reliability, generate savings or addi-tional income and could strengthen the investment capacity of util-ities and reduce imbalances in foreign trade accounts of countries inthe region

Environmental issues

Issues relating to the environment were not raised in the countrystudies. However, as we look at the lessons of the case studies for othercountries, it is worthwhile to discuss issues of the environment as theyare affected by the reform of the power sector. Sustainable develop-ment of the power sector will support economic growth and improveliving standards. However, sustainable development requires a bal-anced approach to addressing electric power needs. This includesdevelopment and implementation of an integrated approach toresource development; developing a diversified resource portfolio; andincorporating environmental and other social considerations associ-ated with electricity production, transportation and use into resourcedevelopment and electricity pricing mechanisms.


Advanced and clean technologies for power generation are availablein the industrialized countries. Thus countries, as part of the reform oftheir power sectors, should have environmental standards that wouldencourage new generators to use best available technologies that havelow environmental damage. Other technologies can be used toimprove the utilization and efficiency of existing generating and trans-mission capacity, increase reliability, availability and environmentalperformance of existing generating plants, and improve efficiency ofend-use consumption of electricity. In addition, integrated resource-planning and demand-side management programmes can reduce the need for additional generating capacity, thereby reducing theamount of capital investment needed to support sustainable electricitydevelopment.

Furthermore, renewable energy resources offer the opportunity toobtain cleaner, more sustainable energy supplies from indigenoussources. Renewables can be exploited and deployed in many differentelectricity applications, in particular, non-grid applications of renew-ables may be attractive in addressing rural development issues. Theinherent diversity and flexibility of renewables offers a number ofopportunities for meeting a variety of energy needs in a sustainableand environmentally beneficial manner.

Relevance of the six-country experiences to rest of SSA

These countries and the rest of SSA share a common priority withrespect to the power sector, and that is to create sufficient infrastruc-ture and generating capacity to allow rapid expansion in electricity usefor economic and social development. However, countries have theirown specific circumstances, which vary from country to country. Thuscountries in SSA seeking to use or consider certain aspects of the expe-riences from the six countries should bear in this in mind. The organi-zation and size of the power sectors in these countries vary. They areindustries which are growing in terms of generation capacity, spatialcoverage and improvements in reliability and quality of service. Theexperiences of these countries are relevant to the rest of SSA to theextent that they provide opportunities for countries contemplatingreform to assess strategies used by these countries, whether theirapproaches to reform are relevant to them and what lessons theyprovide.

John K. Turkson 215

Concluding remarks

Properly designed and implemented reforms will attract investmentfrom multilateral and private financial organizations, improve systemreliability and technological diversity, increase efficiency, support ruraldevelopment and electrification, and reduce environmental impacts. Inorder to accomplish a successful restructuring effort, governmentsmust be willing to adopt and maintain policies which will provide apositive investment climate. The rules of the game must be clearlydefined, and regulatory systems must be independent, transparent, pre-dictable and based on well-established economic, accounting and legalprinciples. Impacts on the environment must also be considered inrestructuring in order for the development of the power sector to besustainable.


adjusted LRMC 60affordability 3, 170AFREPREN 104African Development Bank 26,

32, 48, 61agro-processing 95, 106arbitration 45arm’s-length regulation 173Ashanti Goldfields 51, 68asymmetries of information 11auto-generators 95, 106autonomous regulatory

commission 159, 163autonomy 127, 131, 166, 173Ayamé 31Azito 38, 192

bagasse 179–80bagasse energy 183bagasse transfer price 181base-load supply 184Batoka 127big bang approach 17,190bilateral contracting 194billing 74, 83, 102, 154biogas 86black-out 97, 156, 169BLT 102Bobodioulasso 28bonus and malus 37BOO 102, 160–1, 184BOOT 38, 102, 184BOUYGUES 34brown-outs 154Bujagali 152, 167bulk power trading 212 bureaucratic bottleneck 169bureaucratic procedure 173Burkina Faso 28, 56business strategies 201business units 51, 78

capacity charges 72

Central Electricity Board (CEB)176–85

cherry-picking 202CIE 26–49, 192–3CINERGY 38–40CIPREL 27, 34–9, 43, 192co-generators 113, 115combined cycle 28commercial accounting standards

101commercialization 13, 33, 64,

101, 105, 131, 144, 190,200–1, 207

common carrier 67common purchasing agent 194,

202comparative advantage 128competition 8–11, 13, 15–19, 51,

64–5, 100, 109, 113, 117–18,133, 150, 189–95, 202

competitive 16, 20, 67, 73, 81,113, 118, 131, 141

bidding 194; prices 142;tendering 101

concession agreement 26, 30,34–5, 41, 45

concessionary credit 161continuous suppliers 180–2contractual arrangement 47, 51,

71–3, 194Corporate Business Plan (CBP)

141, 143corporate planning 172

restructuring 141, 190strengthening 210

corporatization 101, 207cost reduction 20cost-covering tariff 170cost-effective 121, 144, 200cost-minimization 141, 210 cross-border enforcement 213cross-country portfolio

diversification 211

217

Index

cross-subsidies 114, 208cross-subsidization 199

debt finance 136 decision-makers 117 de-integration 8, 22, 78, 190,

198demand-side 7, 135, 146de-regulated market 68, 71, 73deregulation 101, 130distribution concession 50distribution network(s) 53divestiture 52donor-driven 103donor-funded 163downsizing 169drought 32, 53, 56, 85, 98duopoly 202

economic activity 52, 60crisis 32efficiency 8, 68, 74stagnation 52

economies of scale 14, 127EDF 30EECI 26–49, 190efficiency 1, 4, 6, 7, 11–15, 52,

65, 121, 127, 142, 147, 176,179, 181, 190, 215–16

efficient enterprise model 74efficient management 10, 198Electricity Corporation of Ghana

(ECG) 50–64, 68, 69electricity distribution 52, 54electricity pricing mechanism

214enabling environment 22,

42, 165, 174, 175, 206,210–11

energy charges 72Energy Commission 51, 77energy conservation 42environment 14, 18environmental cost 208

damage 215performance 215standards 215

European Investment Bank 26,32

external borrowing 129external debt 52

fairness 173fair play 22fair price 213financial crisis 32, 39, 200financial intermediation 212financial loss 83financial market 140financial performance 61, 96,

121, 187firm suppliers 180–2, 184full privatization 14

geothermal 86, 89, 95, 96Ghana Economic Load Dispatch

Centre 69Ghana National Petroleum

Corporation 54Gitaru 94Gokwe North 145government guarantee 21

interference 2, 164, 173ownership 12, 191, 192

government-owned 94, 111grid operation code 76–8

horizontal unbundling 100Hwange 127, 138hydro potential 179hydroelectric 28, 31, 36hydrology 36, 58, 167, 169hydropower 51, 96, 152, 162,

166, 174

Iberafrica Plant 107illegal connection 97incentive-based 64, 84incentives 14, 20, 21, 60, 115,

200, 202incremental/gradual approach

17, 18, 22, 191independent power generators

30, 51, 164, 182independent power producers

2, 16, 38–9, 45–6, 73, 101–15,144–6, 160–5, 184, 187–95,207

218 Index

independent regulators 197independent regulatory body

156, 190, 196indigenization 132–3industry restructuring 6, 7,

14–17, 21, 197, 204–5industry structural changes 1, 9,

194industry structure 3–4, 7, 17,

23, 66, 191inefficiencies 1, 187inefficiency 8, 12, 131inflationary pressure 130infrastructure 6, 18, 38, 52–53,

74, 133, 137, 148, 152, 215institution-building 214institutional 8, 14, 18–19, 23,

52, 75–8, 84, 87, 96, 157,164, 196,

capacity 8changes 19framework 31, 45, 47, 96, 122reform 197, 207

integrated resource planning201

interconnected grid 98interconnected power grids 209internal cash generation 139 internal efficiency 131internal inefficiencies 60International Competitive

Bidding (ICB) 27, 37–8,114, 162

inter-regional connection 174,212

investment-related liabilities 97

Kalagala 152Kamburu 94Kamdini 152Kariba dam 137Kindaruma 94KPC 83–120, 190KPLC 83–120, 190, 193KVDA 83–120

least-cost 72, 88, 146, 163, 166legal 11, 125

customers 165

environment 75framework 128, 156, 165,

173systems 23

lessons 79, 117, 198, 207liberalization 6, 19, 110, 130,

135, 169, 170lifeline supply tariff 60, 61load-balancing 171load-shedding 26, 32, 98, 134,

153–5, 169, 170long-run marginal cost 60, 105,

113, 127long-term contracts 51, 71–3loss-making 21lower voltage distribution 57low-income 3, 78, 117, 142,

161, 200low-voltage 147, 154

Mali 28management 12, 34, 41, 59, 61,

68, 78–82, 94–6, 99–101, 117,125–6, 156–8, 173–4, 184,189–90

management autonomy 142,156

contract 14, 34, 101,106, 114,144, 192, 207

performance 102restructuring 141standard 196structure 127, 191

market forces 99market rates 97meter-reading 60, 147, 159,

171, 204micro-hydro 153mismanagement 32–3monoculture-based 176monopoly 3–17, 30, 46, 78,

160, 202monopoly power 19monopoly price 20multiple purchasers 213

national electrification scheme53

natural gas 29, 36, 39

Index 219

natural monopolies 199net fixed assets 60, 63, 74network losses 98non-core activities 106, 114,

168, 190, 193non-discriminatory 67non-grid applications 215non-payment 57, 124, 189non-technical losses 57, 154non-transparent 19, 146, 162Northern Electricity department

(NED) 50–7

off-crop period 181–4off-peak 98oilfields 36oligopoly 202Ol-Kaira 86opaque decision-making 104open access 16, 67, 213open competition 186, 195,

209open competitive model 189operational efficiency 156operational expenses 63operational ratio 63–4outsourcing 101, 114Owen Falls Power Station (OFPS)

152–75ownership changes 8, 83, 99,

101ownership structure 7, 142ownership/management 6,

168ownership/management changes

1, 9–11, 144, 191, 193, 203,205

ownership/management structure1, 4, 9, 17, 23

para-statal 131–3, 140, 145,149, 150, 177

partial privatization 14, 192peak demand 53peak load 31performance contract 13, 61, 190performance improvement

programme (PIP) 128, 141PETROCI 39, 43

political climate 171power market 54, 64–5, 74, 106,

113power outages 83, 104, 154power purchase agreement 16,

71, 105, 161, 163, 180, 193power rationing 97power sector 1–3, 96, 98, 103–4,

111–18, 127, 138, 156, 166,169, 172, 186, 190, 196,200–8, 211–12

power sector infrastructure209

power sector reform 12, 166,186, 214

Power Sector Reform Committee65, 79

power shortage 98, 156prepayment meters 147price cap 20price rationalization 170pricing 2, 59, 71–2, 121, 125,

175, 181pricing mechanism 199

strategies 198structure 180

principal–agent theoreticapproach 12

private capital 8enterprise 9, 103equity 83 firm 11, 190investment 50, 79, 155, 160,

170, 175investor 38, 54, 156, 164–6,

171, 175, 187, 194, 197,205

operators 43, 46, 48ownership 11–12, 121, 191power 76sector 11–14, 22, 54, 64, 79,

86, 109, 110, 116, 138,155, 169, 185, 190–5,200–11

private sector participation 31,52, 64, 78, 88, 103, 117, 144,165, 174–175, 211

privatization 6–13, 31, 43–9,64, 99–105, 110, 116, 121,

220 Index

131–4, 145, 150, 174, 181,190–7, 205–7

production-sharing 39profit-making 121property rights 11, 76public choice 11public enterprise 11, 13, 130,

131public limited liability 52public sector 1Public Utilities Regulatory

Commission 51, 69, 75–7,81, 196, 206

rate-of-return regulation 20, 60rate setting 60regional connection 175

development 167electricity market 209, 212

regulated market 68, 71, 73regulation 1, 22, 46, 59, 189, 208regulatory body 81, 84, 96, 118,

176, 197, 213mechanisms 20–1, 64, 118,

196models 21process 21, 64, 208responsibility 126role 81, 155schemes 20, 84agency 21, 100board 96, 108capture 206changes 22, 108, 111, 189, 196commission 164, 166, 170,

187deficiencies 19framework 29, 64–5, 76, 89,

143, 145, 149, 155, 165–6,173, 175, 199

function 155law 75powers 75–6 principles 65reform 1, 7, 19–22, 64, 83,

203, 207–8regimes 11, 174systems 19, 21–3, 163, 169,

175, 187, 197

reliability 9, 69, 77, 134, 166,187, 196, 198, 208, 215

renewable energy 42, 91, 149,167, 180, 215

reserve margin 98restructuring 2, 3, 8, 19, 32, 39,

64–5, 78, 80, 84, 121, 128,132, 134, 144, 155, 169, 186,216

retail competition 16–17, 191Rift valley 153Rio Tinto 145rules of the game 48, 75–6, 163,

170rural electrification 26–8, 31,

38, 42, 78, 91, 116–17, 121,122, 148, 156, 168, 170, 186,199–201, 206

SAUR 34scheduled outage 70security of supply 183–4self-regulating 15self-sufficient 135, 188Sengwa 127service charge 74shortages 102short-run marginal cost 71single purchaser 10Siskaso 28SISP 34size of the market 172size of the system 195small-scale 88, 91social equity 2social responsibility 142state-owned enterprises (SOEs)

1, 13–15, 27, 30, 32, 48, 52,61, 89, 170, 173–4, 190–6,200, 207, 210, 212, 214

stock exchange 114, 132, 192,211

stock market 14structural changes 99, 159, 190,

203subsidies 174, 208subsidization 74sugar-industry-based

autogenerators 106, 179

Index 221

sugar producers’ association177, 179

suppressed demand 172sustainable development 214system losses 97, 154

take or pay (ToP) 37, 39TARDA 90, 92, 94–120tariff reform 196tariffs 21, 30, 35, 38, 59–61, 64,

78–80, 97–8, 105–6, 109–14,122, 126–7, 131, 134, 141,146, 154, 161, 175, 181, 188,200–2

technical efficiencies 6technical integrity 51, 77technical losses 154, 159technical performance 121, 175technological innovations 135thermal plant 29, 51, 54, 71,

91, 147, 162–3, 190time-differentiated tariff 202Togo/Benin 28, 56traditional sources 53, 103, 165traditional structure 9, 15transaction cost 11, 117transferability 11transition 13, 198transparency 45, 64–5, 115,

145, 173, 175, 187transparent prices 189transparent rules 198TRDC 94–120

Uganda Electricity Board (UEB)153–75, 190

unbundled 19, 51, 66, 68, 190,194

unbundled industry structure199

unbundling 15, 83–4, 100, 104,114, 207

uneven voltage 153unmetered 57unreliable 83unscheduled outage 70

Valco 55, 58, 66, 68vertical unbundling 100,104vertically integrated 1, 15–16,

19, 23, 45, 54, 104, 191, 192,199

Volta River Authority (VRA)50–71

Vridi 36

Western Power Company 51,71

wholesale competition 68,190–1

workable industry structure190

World Bank 26, 32, 37, 45, 48,53, 60–6, 102–3, 132, 163,190

ZESA 123–51, 190

222 Index

power sector reform a kenyan case study

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