Power Sector Reform in SubSaharan Africa

Power Sector Reform in SubSaharan Africa Edited by John K. Turkson Foreword by John M. Christensen

Power Sector Reform in SubSaharan Africa

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Power Sector Reform in SubSaharan Africa Edited by John K. Turkson Energy Economist UNEP Collaborating Centre on Energy and Environment Risø National Laboratory Roskilde Denmark

Foreword by John M. Christensen Head, UNEP Collaborating Centre on Energy and Environment

First published in Great Britain 2000 by

MACMILLAN PRESS LTD Houndmills, Basingstoke, Hampshire RG21 6XS and London Companies and representatives throughout the world A catalogue record for this book is available from the British Library. ISBN 0–333–75129–9 First published in the United States of America 2000 by ST. MARTIN’S PRESS, INC., Scholarly and Reference Division, 175 Fifth Avenue, New York, N.Y. 10010 ISBN 0–312–22778–7 Library of Congress Cataloging-in-Publication Data Power 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 0–312–22778–7 (cloth) 1. Energy policy—Africa, Sub-Saharan Congresses. 2. Energy industries—Deregulation—Africa, Sub-Saharan Congresses. 3. Privatization—Africa, Sub-Saharan Congresses. I. Turkson, John K. HD9502.A49922P68 1999 333.793'0967—dc21 99–41122 CIP © UNEP Collaborating Centre on Energy and Environment 2000 All rights reserved. No reproduction, copy or transmission of this publication may be made without written permission. No paragraph of this publication may be reproduced, copied or transmitted save with written permission or in accordance with the provisions of the Copyright, Designs and Patents Act 1988, or under the terms of any licence permitting limited copying issued by the Copyright Licensing Agency, 90 Tottenham Court Road, London W1P 0LP. Any person who does any unauthorised act in relation to this publication may be liable to criminal prosecution and civil claims for damages. The authors have asserted their rights to be identified as the authors of this work in accordance with the Copyright, Designs and Patents Act 1988. This book is printed on paper suitable for recycling and made from fully managed and sustained forest sources. 10 09

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Printed and bound in Great Britain by Antony Rowe Ltd, Chippenham, Wiltshire

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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 John K. Turkson

1

2 Power Sector Reform: Conceptual Issues John K. Turkson

6

Introduction Conceptual issues Concluding remarks

6 7 23

3 Privatization of the Power Sector in Côte d’Ivoire Etienne K. N’Guessan Introduction The power sector in Côte d’Ivoire Reasons for power sector reform New institutional and regulatory structure Experiences from implementing reforms Conclusions 4 Power Sector Restructuring in Ghana: Reforms to Promote Competition and Private Sector Participation Michael A. Opam and John K. Turkson Introduction Motivation for reforms Overview of the power sector prior to reforms Regulation and management Reform programme and process New industry structure and trading arrangements Distribution market v

26 26 27 31 40 46 48 50 50 51 54 59 64 66 73

vi Contents

Maintenance of system integrity/regulation Managing the transition Some key lessons and challenges Conclusion

74 78 79 81

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

83

Introduction The energy sector Institutional, legal and regulatory framework Power sector problems Reform options The power sector reform process in Kenya Experiences from implementing reforms Lessons from experiences

83 85 89 96 98 102 110 117

6 Power Sector Reform Experiences in Zimbabwe Ikhupuleng Dube Introduction The Zimbabwean power system Power sector regulatory and institutional framework Reasons for power sector reforms Reform strategy Other relevant issues Conclusions 7 Power Sector Reform Experiences in Uganda John E. Mugyenzi Introduction Electric power resources Uganda electricity board’s performance – an overview Power sector institutions Motivation for reform The reform process Experiences of reform implementation Impact of reform Obstacles to reform implementation Lessons from experience

121 121 122 123 128 141 146 149 152 152 152 154 155 155 156 164 168 171 173

Contents vii

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

176

Introduction Historical features and existing framework Electricity supply and consumption

176 176 177

9 Cross-Country Comparisons John K. Turkson and Robert Y. Redlinger Introduction Motivations for reform Process of reform Paths of reform Open competition Regulatory issues Managing the transition Power sector reform and rural electrification Energy efficiency and integrated resource planning Benefits and deficiencies Conclusion 10 Conclusions and Policy Summary John K. Turkson Introduction Assessing reform process and implementation Critical issues Lessons Relevance of the six-country experiences to rest of SSA Concluding remarks Index

186 186 186 188 191 195 196 198 199 201 202 203 204 204 204 205 207 215 216 217

List of Figures and Tables Figures 2.1 2.2 3.1 4.1 4.2 4.3 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 7.1 9.1

Country power sector reform matrix: ownership and structure Traditional value chain in the power sector Power sector in Côte d’Ivoire Old industry structure New industry structure Contractual arrangements Conceptual framework of the study Energy sources in Kenya Electricity consumption for the years 1991, 1993 and 1995 Major energy institutions KPLC’s organizational structure Structural change and privatization Reform changes in the power sector Past, present and future scenarios for the Kenyan power sub-sector Proposed industry structure Country power sector reform direction: existing and proposed

10 15 44 55 67 70 84 87 88 90 93 99 107 112 160 192

Tables 3.1 4.1 4.2 4.3 4.4 4.5 5.1 5.2 5.3 6.1 6.2

Côte d’Ivoire electricity network Installed generating capacity (MW) Installed distribution lines in Ghana (1991–2) Trends in power supply between Ghana and her neighbours (in GWh) Summary of performance of VRA Summary of performance of ECG (1989–92) Kenya’s installed capacity from 1992–95 Least-cost generation expansion plan Operating income of power sector companies (ksh million) (1986–91) ZESA system parameters Zimbabwe interconnection viii

29 57 57 59 62 63 86 89 97 122 123

List of Figures and Tables ix

6.3 6.4 6.5 6.6 6.7 6.8 7.1 8.1

ZESA financial indicators Level of investment required to meet Zimbabwe’s power needs Zimbabwe: outstanding debt by source Share of electricity costs as compared to total production costs Net inflows of long-term private capital in developing countries (US$ billion) ZESA strategic objectives New independent power producers Electricity generation by source

134 137 138 139 140 143 161 178

Notes on the Contributors Ikhupuleng Dube works as a research engineer at the Zimbabwe Electricity Supply Authority (ZESA), a post he has held since 1993. Prior to this he held the post of Assistant Research Engineer in the same organization. He holds an MSc in electrical engineering from Technische Hochschule Zwickau in Germany. He is a member of the Zimbabwe Institute of Engineers and the Standards Association of Zimbabwe (SAZ). Mr Dube has also been a member of the National Energy Committee where he was in charge of overseeing the implementation of the GEF-funded Zimbabwe Solar Project for Households and Energy Efficiency Programmes. He is also Chairman of the Biomass Technical Committee of Zimbabwe. Currently, he is a Principal Researcher of the African Energy Policy Research Network (AFREPREN) Institutions Theme Group. Stephen Karekezi is the Director of the African Energy Policy Research Network (AFREPREN), as well as the Executive Secretary of the Foundation for Woodstove Dissemination (FWD), Nairobi, Kenya. In 1995, he was appointed member of the Scientific and Technical Advisory Panel (STAP) of the Global Environment Facility (GEF) comanaged by the World Bank, UNDP and UNEP. Stephen Karekezi is an engineer, with post-graduate qualifications in management and economics. He has written, co-authored and edited some 87 publications, journals, papers and reports on sustainable energy development. In 1990, he received the Development Association Award in Stockholm, Sweden, in recognition of his work on the development and dissemination of the Kenya Ceramic Jiko energy-efficient cooking stove. John E. Mugyenzi holds a BSc. in mechanical engineering from Makerere University in Uganda. Currently, he is the Principal Generation Engineer of the Uganda Electricity Board (UEB), a post he has held since 1992. He has held several other posts in UEB since 1982. He has co-ordinated various UEB projects, such as the Owen Falls Extension Project and the Maziba Power Station Rehabilitation Project. John Mugyenzi has attended several workshops on hydro equipment maintenance, industrial techniques and equipment procurement management. Some of the publications he has authored are on power x

Notes on the Contributors xi

sector reform in Uganda. John Mugyenzi is currently a Principal Researcher of the African Energy Policy Research Network (AFREPREN) Institutions Theme Group. Donella Mutiso (BCom) is a social scientist with specialized training in management science. Donella Mutiso has wide experience in energy policy research and energy information and documentation support services. She has worked with the AFREPREN/FWD Secretariat in Nairobi, Kenya for the past four years in various capacities and is currently assisting in the coordination of the AFREPREN Energy Institutions and Power Sector Reform Research Programme. Donella Mutiso has participated as a resource person and research fellow in energy policy workshops and research fellowships in Kenya, Ghana and Denmark. Etienne K. N’Guessan holds a Master’s degree in electrical power engineering (RPI 74), and has taken part in several studies of the electrical grid of Côte d’Ivoire, together with the implementation of numerous projects related to that system. He was first in charge of the implementation of power general equipment and building construction (1974–86), then Technical Director of Distribution (1986–91), Director for Corporate Planning (1991–92) and Director, Assistant to the General Manager of EECI in charge of the co-ordination of the control of the activities of ‘la Compagnie Ivoirienne d’Electricité’. In 1995, Etienne N’GUESSAN was appointed Vice-President of ‘Groupe Projet Energie’, a structure composed of staff from the Ministry, BNETD and EECI, set up to supervise all activities related to the CIPREL project, the first IPP in Côte d’Ivoire. In May 1996, Etienne N’Guessan was appointed Technical Advisor for Energy to the Minister of Economical Infrastructures. René Noel is a chartered engineer, UK. Currently, he is chairman and managing director of a Mauritius sugar consultancy firm, and the Chairman of the Board of Directors of the Mauritius Sugar Industry Research Institute. Prior to this, he held the post of director in several sugar companies, such as Compagnie de Besu Vallon Ltd, Société de Riche en Eau, Mauritius Molasses Co Ltd, Mauritius Sugar Industry Research Institute and Mauritius Sugar Authority. René Noel also held the post of Director in the Central Electricity Board (CEB), Mauritius Electricity Utility. He holds a BSc. in mechanical engineering, from the University of Strathclyde, Scotland and a Diploma from the Mauritius College of Agriculture.

xii Notes on the Contributors

Michael A. Opam is Director of Technical Operations and Rate Economics at the Public Utilities Regulatory Commission in Ghana. He worked previously as the Deputy Director responsible for Policy and Planning at the Ministry of Mines and Energy in Ghana. He played an important role in the power sector reforms in Ghana. He has made several presentations at international fora sponsored by the World Bank and the African Development Bank on Energy Sector Reform in Africa, particularly on the power sector. Robert Y. Redlinger is a senior energy scientist at the UNEP Collaborating Centre on Energy and Environment in Denmark. He has worked previously as an energy consultant with Synergic Resources Corporation and as an environmental engineer with Kennedy/Jenks/ Chilton, Inc., both in the USA. Robert Redlinger has worked throughout the world on energy planning, restructuring, and climate change issues and has taught numerous courses on integrated resource planning, energy analysis, and demand side management. He is co-author of the textbook Integrated Resource Planning: Improving Energy Efficiency and Protecting the Environment (UNEP Centre, 1997) and of an upcoming book on wind energy. Robert Redlinger holds an MSc. in financial economics from the University of London, and an MS in environmental engineering and science and BS in civil engineering from Stanford University. John K. Turkson is a energy economist at the UNEP Collaborating Centre on Energy and Environment (Roskilde, Denmark). He has worked previously as a lecturer in the Department of Planning at the University of Science and Technology in Ghana, and served as a consultant to the World Bank, and United Nations Development Programme (UNDP) and the Ministry of Mines and Energy in Ghana. Dr Turkson is the author of several articles on energy planning and policy issues in the energy sector in Ghana. He has also made several presentations at academic conferences on power sector reforms and the transport sector in SubSaharan Africa. He was a member of the World Energy Council study committee that published the three volumes on Benefits and Deficiencies of Energy Sector Liberalisation. Dr Turkson is a lead author in the Intergovernmental Panel on Climate Change (IPCC) special report on Technology Transfer and the Third Assessment Report. He holds a Ph.D in energy management and policy from the University of Pennsylvania, an MBA from the Catholic University of Leuven in Belgium and a BA in economics from the University of Ghana.

Abbreviations and Acronyms AAG ADB AFREPREN AGC ANFA BCF BEDP BITS BLT BNETD BOAD BOO BOOT BOT ¢ CAA CAPCO CBP CDB CDC CEB CEB CFD CIDA CIE CINERGY CIPREL CMB CPI CSC DAV DDO DEEN

Affirmative Action Group African Development Bank African Energy Policy Research Network Ashanti Goldfields Company Average Re-valued Fixed Assets Billion Cubic Feet Bagasse Energy Development Programme Swedish Agency for International Technical and Economic Cooperation Build, Lease, Transfer Bureau National d’Etudes Techniques et de Dévéloppement La Banque Ouest-Africaine de Dévéloppement Build Own Operate Build Own Operate Transfer Built, Own, Transfer Cedis (Ghanaian currency) Caisse Autonome d’Amortissement Central African Power Corporation Corporate Business Plan Compact Distribution Board Commonwealth Development Corporation Central Electricity Board Communauté Electrique du Benin Caisse Française de Dévéloppement Canadian International Development Agency Compagnie Ivoirienne d’Electricité Côte d’lvoire Energy Compagnie Ivoirienne de Production d’Electricité Cotton Marketing Board Consumer Price Index Cold Storage Commission Distribution Added Value Distillate Diesel Oil La Direction de l’Energie Electrique et des Energies Nouvelles xiii

xiv Abbreviations and Acronyms

DIP DMB DMP DOE DSC DSM EAPLC ECG EDF EECI EIB EIU ERB ERP ESAP ESBI ESC ESI ESMAP FCFA FNEE FWD GBP GDP GEF GELDIC Gibb (EA) GMB GOU GPE GSPER GTB GWh HDMP HV HVO IBDC IBWO ICB ICEA IDA

Direction des Investissements Publics Dairy Marketing Board Direction des Marchés Publics Department of Energy Distribution Service Charge Demand Side Management East African Power and Lighting Company Electricity Corporation of Ghana Electricité de France Energie Electrique de Côte d’Ivoire European Investment Bank Economist Intelligence Unit Electricity Regulatory Board Economic Recovery Programme Economic Structural Adjustment Programme Electricity Supply Board of Ireland Electricity Supply Commission Electricity Supply Industry (Ghana) Energy Sector Management Assistance Programme CFA Franc Fonds National de l’Energie Electrique Foundation for Woodstove Dissemination Great Britain Pound Gross Domestic Product Global Environment Facility Ghana Economic Dispatch Centre Gibb (East Africa) Grain Marketing Board Government of Uganda Groupe Projet Energie Côte d’Ivoire–Banque Mondiale Groupe Spécial Programme Electrification Rurale Government Tender Board Giga watt-hour Hydropower Development Master Plan High Voltage Heavy Vacuum Oil Indigenous Business Development Centre Indigenous Business Women’s Organization International Competitive Bidding Insurance Company of East Africa International Development Association

Abbreviations and Acronyms xv

IFC IMF IPCC IPG IPPs IPS IRP ISDB KFW Km KNAC KPC KPLC Kshs KV KVA KVDA KW Kwh LRMC LV MFCFA MIS MME MNR MOE MOF MOJ MPU MTE MW NED NEMA NEPS NES NIP NIT NORAD NSSF O&M ODA

International Finance Corporation International Monetary Fund Intergovernmental Panel on Climate Change Independent Power Generator Independent Power Producers Industrial Promotion Services Integrated Resource Planning Islamic Development Bank Kreditanstalt für Weideraufbau kilometer Kenya National Assurance Company Kenya Power Company Kenya Power and Lighting Company Kenya Shillings Kilo Volt Kilo-Volt-Ampere Kerio Valley Development Authority (Kenya) Kilowatts Kilowatt-hour Long-run Marginal Cost Low Voltage Million CFA Francs Management Information System Ministry of Mines and Energy Ministry of Natural Resources Ministry of Energy Ministry of Finance Ministry of Justice Ministry of Public Utilities Ministry of Transport and Energy Megawatt Northern Electricity Department National Enviromental Management Authority National Energy Planning Study National Electrification Scheme Nile Independent Power National Investment Trust Norwegian Agency for Development Co-operation National Social Security Fund Operations and Maintenance Overseas Development Assistance

xvi Abbreviations and Acronyms

OECF OFE OFFER OFPS PE PETROCI PFS PIP PNE PPA PROPARCO PSRC PURC PV RDAs RPC SAP SAUR SAZ SCADA SIDA SISP SOE SONABEL SRMC SSA T&D TARDA TOP TOR TRDC TSC UCCEE UDI UEB UIA UK UMA UMC UMIC

Overseas Economic Corporation Fund Owen Falls Extension Office of Electricity Regulation Owen Falls Power Station Public Enterprise National Petroleum Company Power Factor Surcharge Performance Improvement Programme Plan National d’Energie Power Purchase Agreement Société de Promotion et de Participation pour la Coopération Economique Power Sector Reform Committee Public Utilities Regulatory Commission Photovoltaic Regional Development Authorities Rusitu Power Corporation (Zimbabwe) Structural Adjustment Programme Société pour l’Aménagement Urbain et Rural Standards Association of Zimbabwe System Control and Data Aquisition Swedish International Development Agency Société Internationale des Services Publics State-owned Enterprise Société Nationale Burkinabé d’Electricité Short-run Marginal Cost SubSaharan Africa Transmission and Distribution Tana and Athi Rivers Development Authority Take or Pay Terms of Reference Tana River Development Company Transmission Service Charge UNEP Collaborating Centre on Energy and Environment Unilateral Declaration of Independence Uganda Electricity Board Uganda Investment Authority United Kingdom Uganda Manufacturers Association United Meridian Corporation United Meridian International Corporation

Abbreviations and Acronyms xvii

UNDP UNEP USC USh VALCO VRA WB WPC Z$ ZC ZESA ZIMPREST

United Nations Development Programme United Nations Environment Proggramme United States Cent Uganda Shilling Volta Aluminium Company Volta River Authority World Bank Western Power Company Zimbabwe Dollar Zimbabwe Cent Zimbabwe Electricity Supply Authority Zimbabwe Programme for Economic and Social Transformation

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Foreword Over the past few years, countries across the globe have been introducing changes to the structure of their electric utility industry. Once regarded as a natural monopoly and critical ‘national security’ sector best suited for state ownership, the industry has been undergoing a transformation under which the new catch words have become unbundling, privatization and deregulation. Most countries in SubSaharan Africa (SSA) are making serious efforts to turn their economic development away from the path of persistent decline. These efforts have included the restructuring of various sectors of the economy. Encouraged by the World Bank and other financial institutions, the economic reforms taking place in the region have entailed significant increase in private sector participation in previously state-run activities including electric power. This, in part, is due to the recognition of the important role electricity plays in the socioeconomic development of any country. This reflects the recognition that if the countries in the region intend to pursue sustained economic growth and development, reliable supply of electricity is crucial. SSA, in general, is endowed with vast potential primary energy resources – renewable and non-renewable energy – which can be harnessed to meet the electricity needs of the countries in the region. However, electric utilities are confronted with the twin problem of low accessibility to electricity by the majority of their population and lack of financial resources to expand installed generation capacity, transmission and distribution networks. These problems are exacerbated by inefficient management of the electric utility companies. Providing lasting solutions to these problems is a main driver of power sector reforms in SSA. The characteristics of the industry such as size of the system, low maturity of the system and low consumer accessibility to electricity provide interesting challenges and opportunities as well as constraints to the policy-makers in the region as they consider reform of 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 the degree of unbundling (splitting vertically integrated monopolies into separate generation, transmission and distribution entities). In some countries, the state-owned monopoly structure has been fundamenxix

xx Foreword

tally maintained, but private independent power producers (IPPs) have been invited to construct new power plants and sell their power to the state monopoly. Other countries have privatized but maintained the vertically integrated system, while others embark on a more radical approach of unbundling the state monopoly, privatizing the separated entities, and establishing a regulatory body to deal with the segment of the industry which is not amenable to competition. Regardless of the model used, the fundamental objective of power sector restructuring has been the same in all countries: to improve the efficiency of electricity provision, utility financial performance and service. The potential gains through such restructuring and reform of the regulatory system can be enormous, particularly in countries where state utilities are subsidized and currently sell power below the cost of supply. The UNEP Collaborating Centre on Energy and Environment together with the Ministry of Mines and Energy of Ghana and African Energy Policy Research Network has conducted and co-ordinated detailed studies on issues which are central to the power sector restructuring process. The ultimate objective of this work has been to establish a better understanding of the possible economic gains and the social and environmental implications of the restructuring efforts. The regional workshop documented here is part of this activity. The casestudies contained in this volume provide an array of different country experiences which examine the different reform strategies and reform paths adopted. These different experiences provide invaluable lessons for other countries in the region considering reform of their power sectors. Researchers and policy-makers, public policy analysts and researchers and energy economists and planners will welcome this book which addresses key issues and challenges associated with restructuring the power sector in SubSaharan Africa. JOHN M. CHRISTENSEN Head, UNEP Collaborating Centre on Energy and Environment, Denmark

Preface and Acknowledgements

This book contains selected papers from the international workshop of the same title held in Accra, Ghana from 17–19 November 1997. The workshop was sponsored and organized by the UNEP Collaborating Centre on Energy and Environment (UCCEE), Risoe National Laboratory and African Energy and Policy Research Network (AFREPREN), and hosted by the Ministry of Mines and Energy of Ghana. The workshop, in part, was the culmination of UCCEE’s collaboration with the Ministry of Mines and Energy of Ghana in its power sector reform process. The workshop aimed to bring together policymakers and researchers/policy analysts, mainly from Africa, to address one of the most important emerging issues in SubSaharan Africa, reform of the power sector. Designing an efficient and workable industry structure, and incentive-based regulatory mechanisms for a sector which is small and yet to be developed, is a daunting yet a challenging task. The chapters in this book are concerned with the presentation and discussions of different country experiences in the reform of their respective power sectors. Perhaps the most important characteristic of the workshop was the internal balance in the presentations which provided insights of the experiences of countries at different stages of reforming their power sectors and the involvement of Independent Power Producers (IPPs). There are pressures on governments in the region to reform their power sectors, and the papers presented at the workshop gave insights into how different countries at various stages of reform conceptualize and have initiated the reform of their power sector. The structure of the book reflects these reform experiences. The workshop could not have taken place without the guidance of key individuals who identified themes and the countries represented here. Thanks are also due to the international scholars and policymakers who participated. The editor is grateful to Ian. H. Rowlands, Robert Redlinger, Stephen Karekezi, Beverly Ann Brereton and Norbert Wohlgemuth for critical commentary and review of the enclosed xxi

xxii Preface and Acknowlegements

papers. The editor also recognizes John M. Christensen, head of UCCEE, for his support in this undertaking, and the Ministry of Mines and Energy for hosting the workshop. Finally my special thanks for editorial assistance to Cassandra Brooke and Gordon Mackenzie, both of UCCEE. The responsibility for the individual chapters, however, lies solely with the authors identified with each chapter. JOHN K. TURKSON

1 Introduction John K. Turkson

The efficiency of the electric utility industry’s performance is a matter of great public concern in SubSaharan African (SSA) countries. A basic issue is whether or not significant productivity and social welfare gains would result from ownership/management changes, industry structural changes and regulatory reforms of the power sector. The unstructured and ad hoc nature of government ‘regulation’ of the industry, reluctance of governments in the region to allow efficient pricing of electricity and the countries’ serious macroeconomic problems contribute to the power sector inefficiencies which exist in the region at the present time. At independence, most countries in SubSaharan Africa adopted a development strategy that was spearheaded by the public sector. There is no doubt that this approach to power sector development in the region originally sought an efficient and stable functioning of the power sector. However, political and economic circumstances have tended to obscure the distinction between bureaucratic administration and entrepreneurial initiatives. This process gradually hindered all potential private sector activity in the power sector. Government ownership does not relieve the need for supervision, and proper regulation (external or internal) requires clearly defined areas of permissible intervention, a set of operational and monitorable regulatory objectives, auditing and reporting standards to which the regulated utility can be held accountable. Sadly enough in most countries in SSA, regulatory practice is only a shadow of this regulatory ideal. During colonial times and since independence, the power sector in SSA has been organized mainly on the basis of electric utility companies that are vertically integrated or linked by common state-ownership, and governed by the obligation to supply all consumers in their fran1

2 Introduction

chise areas (normally a whole country). This obligation is to be met without price discrimination or the undue preference to any segment of society or the franchise area. Successive governments have used the power sector as part of a strategy to achieve social equity in the development effort. Over the years governments have deliberately provided electricity at very low rates, and consequently the issue of electricity pricing has become a politically sensitive issue. To realize the efficiency and productivity improvement objectives of the power sector in SSA, the issue of reforming the sector in the countries of the region has been at the forefront of the public policy debate. This change in attitude is partly due to the serious financial crises facing a number of electric utilities. These crises have been a drain on national budgets. The entities in the sector, like other public enterprises, are typically asked to meet both social and commercial objectives, which are not always compatible. The magnitude of the deficits accumulated by most power sector companies in SSA is an important element of the debate over the future of the industry. Furthermore there is a consensus that power sectors in most SubSaharan African countries have been performing badly (Gutierréz, 1996). The causes of this dismal performance include poor management, government interference in daily operations and investment and pricing decisions, and opaque regulatory systems. These and other factors, such as the economic crises facing many SSA countries and lack of capital to invest in rehabilitation and expansion of the power systems, are putting pressure on governments in the region to reform their power sectors. Donor agencies (multilateral and bilateral institutions) are also putting pressure on governments to reform their power sectors along the lines of privatization and the introduction of competition. Efforts at restructuring the power sectors in SubSaharan Africa seem to be dominated by a desire to attract Independent Power Producers (IPPs) into the industry. This tends to suggest that there is a single path to reform the industry. Other equally important issues need to be considered as well, such as definition of the direction of reform of the entire industry, efficient regulatory systems, efficient pricing of electricity and which industry and ownership structures to adopt. The six case studies presented in this volume examine the power sector reform experiences in the region together with how the choice of reform path has been made in each case and attempt is made to draw some conclusions from this experience. It is important for countries considering reform of, or already in the process of reforming, their power sectors to

John K. Turkson 3

be clear from the outset what industry structure they are aiming at, and how to get there. Clarity on these issues would enable countries to anticipate and plan for related issues such as abuse of monopoly power by utility companies, improvement in accessibility of electricity to the majority of the population and affordability for low-income groups within the context of reform of the power sector. As countries move to restructure their power sectors, many elements have yet to be played out. Thus assessment of the experience of countries where reasonable restructuring has been implemented is necessarily tentative. In countries where restructuring is now being initiated, the discussions are quite prospective. In countries where restructuring is under way, the assessment at this point can be based on accumulated knowledge, and a much better understanding of the strengths and weaknesses, of the changes in ownership and industry structure. As countries in the region ponder these issues and respond to external pressures to reform the power sector, we felt that it would be worthwhile to study and share the experiences of countries that have implemented some reform of their power sectors as well as those where reform is under way. The prime reason for this book is to inform people, particularly researchers, policy-makers and policy analysts, about the power sector reform experiences in countries in the region and thus provide some perspective on the competing reform strategies proposed by multilateral and bilateral organizations. The importance of conceptualizing and properly designing reform strategies on the one hand and political commitment on the other, needs to be noted, as does the different system sizes, configuration and maturity, and political circumstances. The chapters in this volume reflect the changes that are currently taking place in the power sector in SSA. Although changes are occurring in the energy sector, there is little doubt that the electric utility industry in the region is currently undergoing more ‘upheaval’ than the other public utilities – water, postal services and telecommunications. In the face of declining electric utility industry efficiency, financial crises, and inability of governments in the region to provide the needed investments in the sector, the need to reform the power sector has become paramount. Nevertheless, despite these pressures, only a few countries have initiated or implemented restructuring of their power sectors. Most countries in SSA are, however, either undecided or still considering what reform route they should follow. Thus, power sector reform is just starting in many countries in the region,

4 Introduction

and as such it is too early in the process to undertake an in-depth analysis of the impact of reform on the performance of the power sector in these countries. The reform of the power sector involves changes in both the ownership/management structure and in the industry structure. For many countries in the region, the question still looms, ‘will such changes result in a more efficient governance structure?’ The World Bank and bilateral organizations have been using the positive results of power sector reform in developing countries such as Chile, Argentina and Malaysia to show that power sector reform can lead to more efficient systems. This book attempts to throw light on the experiences of countries in SSA at different stages of reforming their respective power sectors, explaining why and how these changes are taking place. The contributors to this volume continue the debate as to whether the effects of power sector reform will lead to greater efficiency. Implications for the structure of the power sector, as well as the nature of regulation, are discussed. The chapters also consider the challenges posed to regulation by changes in ownership/management and in the structure of the industry. Our objective, therefore, is to tell the story of power sector reform in countries at different stages of the process in SSA with a view to discussing the problems being encountered by these countries and the lessons to be learnt for other countries in the developing world contemplating reform of their power sectors. Chapter 2 by John K. Turkson revisits the question ‘what is power sector reform?’ In doing so he discusses, in a much broader sense, the rationale or the motivation for power sector reform and looks at the conceptual issues underlying the reform debate. Turkson provides an analytical framework for discussing the different elements of ownership/management and industry structure changes. Chapters 3, 4 and 5 present cases of countries that have undertaken substantial reform of their power sectors. The Ivorian case study in Chapter 3, presented by Etienne K. N’Guessan, shows that Côte d'lvoire is the country in SSA that has gone furthest in reforming its power sector. The country study presents an analysis of the reform. The reform actually involves the transfer of the operation of generation, transmission and distribution of electricity to a private company, while the state-owned utility company retains responsibility for the infrastructure of the industry. N’Guessan also discusses the impact of reform on different stakeholders as well as the lessons that have been learned. Opam and Turkson present the Ghanaian case in Chapter 4. The case study emphasizes the importance of initiating the reform

John K. Turkson 5

process, putting the legal and institutional aspects of the reform in place before any major restructuring occurs, that is, unbundling or splitting the distribution companies into a number of distribution zones to be operated by different limited liability companies. Stephen Karekezi and Donella Mutiso discuss Kenya’s experience in Chapter 5. The Kenyan experience involves the unbundling of a vertically integrated industry and private sector involvement in the generation segment of the industry. An analysis of the timing of regulatory/institutional reform and private sector involvement/privatization is also undertaken. Chapter 6 by Ikhupuleng Dube discusses the power sector reform in Zimbabwe. This country study presents a case of reform that emphasizes efficiency improvement of the existing structure, and the involvement of the private sector in the generation segment of the industry. Chapter 7, Power Sector Reform Experiences in Uganda, by John Mugyenzi, presents a case of a country in the process of reforming its power sector, and confronted with such questions as which industry and ownership structures are envisaged. The author discusses how these questions were addressed and what problems were encountered in designing a framework to guide the reform of the power sector in Uganda. Attracting independent power producers into the power sector has been one of the major focuses of the reform of the power sector in SSA. Chapter 8, Power Sector Reform Experiences in Mauritius, by René Noel, presents the Mauritian experience of an IPP dealing with a statutory body that is under direct government control in terms of power procurement, pricing and other issues which affect its operation. John K. Turkson and Robert Redlinger provide, in Chapter 9, a crosscountry comparison of the reform strategies and experiences of the sixcountry studies. They highlight the similarities and differences in the six countries’ approaches to reform of their respective power sectors, and more importantly, in the reform paths that these countries have pursued. Chapter 10, Conclusions and Policy Summary, by John K. Turkson, discusses the policy issues central to the reform strategies in the different countries, and finally presents some reflections on the lessons learned and their relevance for other countries considering reform of their power sectors.

2 Power Sector Reform: Conceptual Issues John 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 trends have been evident in many parts of the world. The first is the revival in economic theorizing about the desirability of market solutions to resource-allocations extending into new areas such as telecommunications, health and other sectors that were previously thought most efficiently dealt with in the political or hierarchical allocation systems (Surrey, 1996). The second is the emergence of a political climate that facilitates advocacy for privatization as the main means of change. A third trend, which is very much evident in developing countries (particularly SubSaharan Africa), is the shortage of capital for infrastructure development, and the poor technical, economic and financial performance of electric utility companies. This has interacted with the first two factors to encourage a growing interest in industry structure and ownership restructuring of public utility industries in these parts of the world. The over-riding issue in the power sector reform debate is how improvement in economic and technical efficiencies in the industry can be achieved. The achievement of such efficiency improvements is being pursued along different lines such as changes in industry structure and ownership/management, and reform of the regulatory system. These changes are not mutually exclusive. However, industry restructuring can take place without privatization (ownership/management 6

John K. Turkson 7

changes) as was the case in New Zealand, Norway and Malaysia. Similarly, privatization of the industry can take place without industry restructuring, as occurred in Scotland. Industry restructuring and privatization can also take place simultaneously as the England and Wales experience shows. The foregoing suggests that there are numerous options or reform paths available, and countries have opted for a particular 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 an enabling environment to attract private investors. From a developing country perspective, public/private sector participation in the reform of industry and regulatory structures are at the top of the hierarchy of decisions to be made about reform of the sector. Thereafter, other efficiency issues that link both operation contracting and market organization through the price mechanism are considered. This chapter presents and discusses some of the major conceptual issues involved in these initial decisions by policy-makers regarding the reform of the power sector.

Conceptual issues Governments in most countries have started to implement changes in their respective power sectors. These changes have involved either ownership structure, industry structure, or both, in an effort to improve efficiency in operations through incentive-based regulatory mechanisms. Countries such as the United Kingdom, Chile, Argentina, Australia and New Zealand have undertaken far-reaching restructuring of their electric utility industries. All these restructuring efforts are, in large measure, consistent with the view that competition should be introduced into the electricity supply industry wherever it is technologically feasible. Achieving the goal of greater economic efficiency in the electricity supply 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 the performance – financial performance, or the extent to which the sector is covering its costs and contributing to future investments; supply-side efficiency, the efficiency with which electricity is produced and delivered to consumers; and demand-side efficiency, the efficiency with which electricity is used by the consumer’ (World Bank, 1994).

8 Conceptual Issues

Reforming the power sector is not only a problem for developing countries. This reform is taking place across the globe. What is different are the drivers of the reforms in countries undertaking them. For developing countries such as Chile, Argentina, Brazil, Pakistan, Malaysia and countries in SubSaharan Africa, the major driving-forces are the need to improve efficiency, inability of governments and utilities to finance expansion and rehabilitation of the existing systems, and the need to attract foreign and domestic private capital into the sector. For developed countries such as the UK, the main drivers are improvement in efficiency as well as the economic philosophy of allowing competition into an industry which, hitherto, has been considered a natural monopoly. There are also differences in the drivers of power sector reform between countries in both developing and developed countries. The differences in motivation and driving-forces behind the reform suggest that countries are likely to adopt different reform strategies. Thus it is the thesis of this chapter that there are many ‘paths’ to reforming the power sector. Another critical aspect of the reform process is the reform of the regulatory system operating in the industry. The experience of power sector reforms in some developing countries such as Chile, Argentina, Bolivia, Brazil, Philippines and Malaysia suggests that setting up a proper regulatory framework is critical to the success of the entire reform process (Galal et al., 1994; Spiller and Martorell, 1996). One of the major issues in the reform process is ownership change. The economic efficiency of the electric utility industry affects a large number of consumers. If the form of the enterprise (that is, municipal, cooperative 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 whether their causes are managerial, undue interference by the political establishments or inadequate institutional capacity. Successful restructuring of the industry to ensure competition requires unbundling the price and other service attributes associated with the stages (from generation to distribution and billing) of electric power supply. Vertical de-integration or separation is central to achieving the benefits of competition. However, if vertical de-integration is done inefficiently (that is, de-integration which leaves undue recontracting or regulatory problems in its wake) it may impede and dissipate all the expected benefits of competition. There are potential problems associated with such inefficiency. Some of these problems are:

John K. Turkson 9

(i) the issue of assuring system stability and integrity and the associated issue of reliability; (ii) structuring an appropriate solution to the stranded cost recovery problem during the transition, and (iii) determining the appropriate structure of ownership, control and regulatory governance of transmission services (Fernando and Kleindorfer, 1996). Whatever the motivations or drivers of power sector reform are, policymakers should ideally be aware of reform alternatives and their likely implications. Ownership/management and industry structure framework The changes taking place in the electric utility industry are too complex to be presented in a simplified framework. Past and current reform experiences are varied, and reforms do not only involve ownership/management and industry structure changes, but also regulatory changes, mixture of public and private enterprises, power pooling, bilateral contracting and others. However, the ownership/ management–industry structure framework is adopted to examine the various issues associated with changes in these dimensions. Reform of the sector has been taking place globally within the ownership/management industry-structure space. This is presented in Figure 2.1 below. The vertical axis presents the ownership/management changes spectrum and the horizontal axis shows the industrystructure changes spectrum, characterized as models 1, 2, 3 and 4 (Hunt and Shuttleworth, 1996). The models are described in detail later in this section. These models suggest different degrees of competition in the industry – from no competition to a high level of competition. The changes along the ownership/management axis involve movement from government department to public corporation, and to private corporation. In principle, a movement from government department to public corporation entails the adoption of commercial principles 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 vertically integrated monopoly. This is presented as model 1. The industry structural changes ultimately aim at competition in the generation and distribution segments of the industry (model 4), as typified by the examples in England and Wales and New Zealand. Between the two ends of the spectrum are different industry structure models that are

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 ownership industry-structure space. Source: This figure is adapted from Hunt and Shuttleworth (1996:14).

characterized as model 2 and model 3. Model 2 represents an industry structure where many generators compete to supply a single purchaser, and model 3 represents a structure where distribution companies and large consumers can choose their supplier. Ownership/management change Ownership/management change is one of the dimensions of the ownership/management-structure space. For countries in SSA, allowing more private participation and control in the power sector can mean more efficient management and new sources of financing. The issue of

John K. Turkson 11

efficiency improvements resulting from such ownership changes, however, is a contentious one. Any ownership restructuring process may change previous market structures. It is a common theoretical assumption – and one with a sound empirical basis – that competition improves the performance of public and private firms. When, for technological reasons, it is desirable that only one firm should occupy a market, it is necessary to consider how to control the benefits accruing from (productive) efficiency so that the firm’s monopoly power does not inflict a loss upon consumers. This, then, raises the question – does ownership 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. A survey of the literature indicates mixed results. Some of the early studies 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), citing more than 50 studies from 5 countries, reports that ‘the findings in most of the studies … are consistent with the notion that public firms have higher unit cost structures’. They imply some slight advantage for private ownership. They further state that it is not so much the difference in the transferability of ownership but the lack of competition that leads to the often observed less efficient production in public firms (most of them in monopoly markets). Boardman and Vining (1989) conclude in their study that there is greater efficiency in a private firm’s operations as compared to the public firm. Other studies have reached similar conclusions (Megginson, Nash and Randenborgh, 1992; Galal et al., 1994). However, another widely cited survey by Millward and Parker (1983) arrives at the conclusion that there is no systematic evidence that public enterprises are less cost-effective than private firms. Boyd (1986) also concludes that there is no systematic difference between performance under public and private ownership. Recent research on efficiency issues relating to ownership changes has adopted the principal-agent approach to analysing the effects of ownership structure and regulatory regimes on allocative and internal efficiencies (Bös, 1991; Vickers and Yarrow, 1988; Bös and Peters, 1991). In a public firm the government operates as the principal whereas in the private firm the shareholders take the lead. In both cases the management can be treated as the agent. In the context of asymmetries of information, when attempting to achieve his goals, the

12 Conceptual Issues

principal is handicapped by lack of information, which the management precisely knows. In state-owned enterprises, the traditional source of inefficiency resides not only in inadequate knowledge and controls but also the gap between managerial and social benefits, which are government’s social objective. The issue here is for the government to make them coincide. Thus, as the government, the principal, defines the reward structure of the management, it has to take into account the agent’s objectives which may lead him to choose effort levels that are not efficient. The principal-agent theoretic approach to state-owned enterprises predicts that in a situation where there is information asymmetry, that is when the manager can observe certain variables 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 betterinformed principal. There are also changes in the objectives of the firm, from welfare maximization to profit maximization; and changes in the character of management. The changes in objectives, information and character lead to differences in incentives and efficiency between the public and the privatized firm. In conclusion, proponents of privatization contend that government interference can be curtailed and improvement in efficiency in public enterprise (PE) can be attained through privatization. Nevertheless, even if a firm is fully privatized, the principal-agent relationship between the government and the firm may not be completely eliminated. For privatized 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 and large systems can take steps along the ownership/management axis, as shown in Figure 2.1. These involve changes from government to private ownership, and private ownership is the end-point of a continuum of changes in management/ownership. Most power sector companies have moved from their status as departments in government ministries (government ownership) to corporate entities (government corporation). The movement from government department to government corporation implies, in principle, that government is one step removed from the day-to-day management of the company. Management is invested in the board of directors of the corporation. The corporation may still be required to pursue government policies but has the objective to operate on a commercial basis. In most developing countries, it has been difficult for most of these government power

John K. Turkson 13

utilities to make the transition from government department to government corporation. The inability to make the transition and the consequent inefficiencies in these corporations represent the drivingforces towards privatization. Nevertheless, not all systems need to privatize completely. The options along the ownership continuum may involve commercialization, performance contract, and management contract and partial privatization. • Commercialization: a public enterprise is said to be commercialized when the government relinquishes detailed control in favour of autonomy for the enterprise and a focus on profitability. The utility also becomes subject to corporate legislation and is required to compete where possible with other private companies on equal terms. This normally involves the adoption of commercial accounting, economic tariffs, and the development of a corporate strategy that enables the enterprise to distinguish between its commercial and social objectives, and to focus more on the commercial objectives. • Performance Contract: this is a contract that defines the relationship between government and public employees managing a state-owned enterprise. The process is obviously part of the effort of the government to enhance efficiency. Performance contracts set targets for state-owned enterprise (SOE) managers to attain. Such contracts also provide bonuses for management and workers based on achievement. In the contracts the government pledges to provide greater autonomy to the utilities or meet other obligations as agreed between the parties to the contract. For a performance contract to be successful, the contract should include three main elements: information, reward and penalty, and commitment. Information issues arise because the contracting parties (government on the one hand and managers of SOEs on the other) have different sets of information, and each side can use the information it holds to improve its bargaining position. Competition is one way the government can gain access to more information about managerial performance, since they can compare a firm’s performance with its competitors. This may not be appropriate in a monopoly situation. In this case the government uses rewards and penalties to induce management to reveal information and to comply with the contract provisions. There is also a need for each party to be convinced of the other party’s commitment to honour its promises.

14 Conceptual Issues

• Management Contract: this is a contract that defines the relationship between a government and a private firm contracted to manage an SOE for a fee. It is often considered the first step towards private sector participation in SOEs. A management contract offers a much better chance of success since governments can use competition to reduce management’s information advantage if the SOEs operate in a competitive environment. In a monopoly situation, the use of competitive bidding to award contracts can also reduce such information advantages. • Partial Privatization: this involves the sale of part of government’s equity holdings in an SOE to the private sector (institutional investors and general public). • Full Privatization: this involves the outright sale of an SOE to a private investor. Incentives for efficiency are considered even greater if management is subject to the discipline of stock market valuation of the company, which happens when the enterprise is privatized. The distinction is never rigid in practice. Any step away from the present 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 traditionally considered to constitute a natural monopoly. Economies of scale in the generation of electricity and the need to extend transmission and distribution networks to deliver it to final consumers seem to favour supply by a single firm for a given geographic area. That school of thought has given way to a consensus that the generation segment of power supply in today’s environment would be more efficient and economical if left to the forces of an open market. In support of this new consensus, Joskow (1987) argues that economies of scale in electricity production at the generation level are exhausted at a unit size of about 500 MW. This and other studies have concluded that scale economies do not exist at the generation level of the industry. Furthermore there is also dissatisfaction with the level of incentives for efficient operation by state-owned utilities, particularly in developing countries. According to this view, even if economies of scale in the production of electricity exist, because of the incentives for input choice provided by state-ownership, the mode of production chosen by the firm does not allow efficiency gains to be realized.

John K. Turkson 15

Many countries have used the industry structural reforms as a means of introducing competition and increasing sector efficiency. In Chile and England, for example, generation assets have been separated from transmission and distribution, and competition introduced. The rationale for industry restructuring has been to enable the introduction of competition. The traditional structure of the industry has been characterized by a supply-side perspective, with self-regulating state-owned utilities that are either fully or partially vertically integrated. Final consumers’ choices are limited, with respect to the purely physical side of such 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-owned monopolies. Traditionally, transmission and distribution have been provided as a bundled service to customers, and priced accordingly. As Fernando et al. (1995) indicate, there is no clear connection between costs and customer valuations of generation, transmission and distribution services. This makes the alignment of investment and operating decisions difficult and clouds the determination and provision of efficient levels of each of these respective services on the supply side. The point of departure in the discussion on industry restructuring is the introduction of competition into the commercial arrangement for selling electricity and separating or unbundling industry structure. Total unbundling and introduction of competition is the end-point of a spectrum of structural changes. The following presents a brief description of each model. It is not our intention to give an exhaustive treatment of these models.1

Figure 2.2

Traditional value chain in the power sector

16 Conceptual Issues

• Model 1: this is usually a vertically integrated monopoly (no competition and no choice of supplier). This model shows a high degree of vertical integration of generation, transmission and distribution. The utility’s monopoly over generation, transmission and distribution, and the service areas may cover a whole country as is the case in most developing countries. In return for this monopoly power in the franchise area, the utility is required to serve customers in the service area, at a regulated price. The emergence of Independent Power Producers in countries with this type of model may suggest a movement towards some form of competition at the generation level, but evidence on the ground suggests no such thing. In many cases contracts awarded to IPPs are not based on a competitive bidding process. The basic arrangement for selling power from IPPs is based on a power purchase agreement (PPA). There may often be a ‘take or pay’ clause which guarantees the IPP a given market. • Model 2: this model of the industry allows a single buyer to choose from a number of generators to encourage competition in generation. All power must be sold to this single buyer. In a situation where countries are interconnected, the single purchaser has the option of buying power from a neighbour. The issue in this model is whether the purchaser should be an existing utility company or an independent entity. This model, or a variant of it, is used in Northern Ireland. It was designed to deal with a relatively small system (2400 MW). This model, as it were, is the precursor of competition in the industry as presented in models 3 and 4. • Model 3: wholesale competition allows distribution companies to buy directly from a producer and deliver over a transmission network (open access). Distribution companies still have a monopoly over final consumers. In this model multiple generators may bid to be dispatched, with the purchaser relying on competition to ensure that their bids approximate their marginal operating costs. However, in small power sectors, as in many SubSaharan African countries, it may be difficult to introduce genuine competition between generators because there are too few plants to form meaningful companies (Bacon and Gutiérrez, 1995). Experience from countries such as Chile, England and Wales has shown that if individual generators control a large share of the market they can often manipulate output or availability to increase profits. • Model 4: this industry model allows the introduction of retail competition into the industry. It facilitates the choice of suppliers by

John K. Turkson 17

consumers. This requires multiple generators to have equal access to the transmission and distribution networks so that they can compete to supply final consumers. The introduction of retail competition requires several suppliers. It also requires that it be economically sensible to split distribution into several entities, so that no single distributor has monopoly power with respect to purchases from producers. As indicated earlier, these models are just broad categorizations of potential industry-structures. The movement on the industry-structure axis towards retail competition would involve changes in contracting relationships, and transmission and distribution will remain regulated. These industry structures, as represented by the four models, can be associated with different ownership/management structures. For example, the restructuring of the electric utility industry toward open competition in the UK, Chile and Argentina involved ownership/ management changes (privatization). In a similar industry restructuring in New Zealand and Norway, ownership/management of the industry has remained predominantly in the public sector. The different locations of countries in the industry-structure – ownership/managementstructure space depicted in Figure 2.1 underscores the point that there are numerous paths to reforming the power sector. One must, however, hasten to stress the dynamic nature of the whole process. The industry-structure models presented suggest that model 4 could possibly be the envisaged end-state industry structure that embodies the characteristics of an efficient, dynamic and competitive market for power. But certain developments in the industry, such as acquisition and mergers, could affect the realization of the ultimate objective of the entire restructuring process, that is, open competition. Choice of industry structure In the face of a plethora of options for industry restructuring, countries reforming their power sectors have to choose which industry structure to adopt. This amounts to deciding whether to aim at introducing competition into the industry or to maintain the existing monopoly structure. If the decision is to introduce competition, the next question is how this can be achieved? In a general sense there are two approaches: an incremental/gradual approach and the ‘big bang’ approach. The former involves a more measured sequential strategy to introducing competition into the industry. This would involve the movement through model 1 to model 4 with thorough assessment of

18 Conceptual Issues

the impact at each stage of the process. The latter would involve a jump from model 1 to either model 4 through model 3 or directly to model 4. The UK, New Zealand, Australia, Chile and Argentina are examples of the ‘big bang’ approach to industry restructuring. It is difficult to suggest ex ante the factors that would influence the choice of a particular approach to introducing competition. However, assessment of countries that have used one or the other approach suggests some factors that might have influenced their choice. For those countries that adopted the ‘big bang’ approach, commitment on the part of the respective governments both to reform the industry and to the economic philosophy of introducing competition was evident in every case. Another factor is that all countries had a relatively welldeveloped institutional foundation. For the most part, the rule of law was respected and enforced, and the broader political and socioeconomic environment was enabling to the private sector. In addition to these institutional characteristics, there were also physical factors in common to these countries. For one, the level of maturity of these countries’ systems was, at the outset of the reform process, quite high. All of them had relatively well-developed infrastructure in the power sector. Moreover, they also had high accessibility rates: for example, the UK at 100 per cent, Norway, 99 per cent, Chile, 92 per cent and Argentina, 97 per cent (Gutierréz, 1996); consequently, only relatively modest demand growth was anticipated. Whether these factors played a role in the successful restructuring of these countries’ power sectors is difficult to determine. There are neither theoretical nor empirical studies to support or reject propositions relating to the influence of level of accessibility and infrastructure development on the success of reforms. Nevertheless, their presence in every case is at least suggestive. For countries that adopted the incremental/gradual approach, either these factors are not present or policy-makers have not been swayed by the arguments in favour of introducing competition into the industry. Consequently, adopting an incremental/gradual approach allows them to assess the effects of the incremental changes before deciding to take the 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 modelled according to the England and Wales system. One of the major reasons was that the size of these systems was not suitable. In Northern Ireland, for example, to ensure some competition at the generation level, the system was interconnected to the Scottish one through sub-

John K. Turkson 19

marine cables. Similarly, a gas pipeline was built from Scotland to ensure that gas was available for power generation (and also for heating and other economic and environmental purposes). The expansion plan of the sector is important in determining the future structure, since a rapidly growing sector may soon be able to accommodate enough firms to make competition possible with time. Furthermore, the configuration of the transmission system must be taken into account in deciding whether there can be effective competition between generators. Where there are weaknesses in the transmission system, one plant can have effective monopoly power despite the pressure of several plants. Thus, an important lesson from the Scottish and Northern Irish reform experiences is that the small size of the system may not necessarily preclude competition. The interconnection between these two systems on the one hand and interconnection with France and England and Wales, on the other, allowed sufficient competition. The arguments for industry restructuring are mixed. Vertically integrated monopolies under government control remain the most common industry structure in industrialized, developing and transition economies. In many countries, the wave of energy sector liberalization is leading countries to adopt industry structures that allow competition. Once the new structure of the power sector has been determined then the regulatory system can be adjusted to match that structure. Regulatory reform Many of the present problems in the SubSaharan African power sector stem from government intervention in price setting, often resulting in low tariff levels. In pursuing their social policies, governments in the region have interfered in both the input and output markets of the sector, through ill-defined regulatory systems. Regulatory tasks and responsibilities in combination with the latitude for informal regulatory actions have led to highly politicized decision-making. Regulatory deficiencies in the sector have worsened the poor performance of the industry. This implies that in the reform of the sector, policy-makers will be faced with the decision to redesign the regulatory system. No matter how private or unbundled the system becomes, the state will maintain the role as a regulator. The regulatory role of the state, as envisaged in the reformed power sector, would be totally different from the present system of regulation. Regulatory and institutional changes that take place in the event of reform of the sector should move away from a non-transparent regulatory system and direct

20 Conceptual Issues

intervention by government administration on pricing and investment decisions in the electric power companies. Regulatory Reform is very critical to the success of the reform of the power sector in developing countries. Regulatory approaches differ considerably around the world, but have underlying similarities. The regulatory mechanisms are intended to mimic the effects of competitive markets, and so ensure that companies in the sector earn a return which is similar to their cost of capital. The two main forms of regulation – American-type regulation (rate-of-return) and price cap – seek to achieve this objective. A vast economic literature exists on rate-of-return regulation (see Averch and Johnson, 1962; Baumol and Klevorick, 1970; Courville, 1974; Peterson, 1975) that examining its effectiveness in providing incentives for efficiency in regulated companies to be efficient. The seminal work of Averch and Johnson supports the claim that cost-plus or rate-ofreturn regulation tends to result in inefficiency in production. In recent times, regulators in various settings have begun to use price cap as a means of regulating the firm. Proponents argue that it offers much better incentives to regulated companies to be more efficient compared to rate-of-return regulation (Mathios and Rogers, 1989). They argue that price-cap regulation provides enhanced incentives for cost reduction. Some opponents argue that the regulated firms may be afforded too much freedom to set prices and plan investments. Acton and Vogelsang (1989) suggest that the interest in price-cap regulation also reflects a growing understanding that governmental regulation is limited in what it can accomplish. One can infer from such a suggestion that firms that are the object of regulation are almost always better informed than the regulators about their costs and the consequences of adopting a particular detailed regulatory scheme for prices or conditions of services. Thus, rather than creating regulation based on the premise of an all-knowing regulator able to set an optional price based on full knowledge of cost and demand, a more realistic regulatory goal is to design incentive mechanisms for the regulated firm such that it will maximize society’s objectives while pursuing self-interest. Both types of regulation provide incentives for cost reduction. With rate-of-return regulation, the firm can earn some extra profit if it manages to reduce its cost while the price is fixed at the original cost level. With price cap regulation, the firm can enjoy a profit if its costs are below the ceiling. In addition, if it can make ‘drastic’ cost reduction, it can charge the monopoly price, thus increasing its profit still further. This second possibility is absent in rate-of-return regulation.

John K. Turkson 21

In reforming the regulatory system, it is important to avoid wholesale adoption of regulatory models designed for entirely different environments without consideration of the specific country circumstances. In the choice or design of a regulatory mechanism, the following must be borne in mind: • It should provide incentives to the utilities to perform more efficiently; • Efficient utilities should be allowed to earn a return on assets equivalent 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 the willingness of the government to restrain itself from interfering with price-setting. Regulatory reform is crucial in influencing the risk perception of would-be investors in the sector in SSA. In the absence of this, countries promoting private sector involvement find potential investors 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 welldesigned and smoothly functioning regulatory regime can, in conjunction with an appropriate commercial/legal framework, greatly reduce the perceived risk in power sector investment. Thus a regulatory process that demonstrates an independence from political decision-making tends to reduce this risk. A regulatory agency whose independence is perceived to be respected by government and which is perceived to be competent and timely in its decisions will significantly reduce the investment risk as perceived by the investor. Once it is obvious that the government is willing to allow electricity tariffs to rise to cover costs from their previous loss-making levels, and that it will continue to do so, there is an incentive for new investment in the industry. Such regulatory reform confers benefits on all stakeholders.

22 Conceptual Issues

The importance of regulatory reform to the success of power sector reform is underscored by the experiences in countries such as the UK and Chile. The UK, as part of the restructuring of the sector, created the Office of Electricity Regulation (OFFER) and introduced a price-cap regulatory system. The Chilean restructuring of the power sector was measured. It began with a regulatory reform that forced the stateowned electricity companies to behave according to the new regulatory rules. This allowed for a critical learning period in which the regulatory agency, for example, was able to gather experience in regulating monopoly enterprises. This was even more significant in view of the fact that Chile had no history of formal electric utility industry regulation. The timing of regulatory reform with respect to that of industry and ownership restructuring is also an important factor to consider. In the UK, reforms were introduced almost simultaneously, probably because the UK had adequate capacity, both human and institutional. The Chilean experience, on the other hand, involved a gradualist approach. Chile started with a regulatory reform that forced the state-owned electricity companies to behave according to the new regulatory rules. This was done before de-integrating and privatizing the companies, and it allowed important learning and experience to accrue. This particular experience of the Chilean power sector reform provides a useful lesson for SSA countries, most of which have no history and experience of formal regulation. An important complement to regulatory reform is the existence of safeguarding 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 transformation of its regulatory structure and institutions, the existence of a well-functioning legal system (including respect for property rights) and a properly functioning independent regulatory body. They indicate that Chile has not only been successful in transferring ownership from government to private hands, but that it has also promoted large private investments in the power sector. Spiller and Mortorell contend that most countries trying to promote private sector participation have an extremely ad hoc regulatory system, which not only generates very large inefficiencies but also lacks the assurances of fair play that private

John K. Turkson 23

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

Concluding remarks This chapter has discussed the conceptual issues associated with reform of the power sector from its current vertically integrated regulated structures to different restructuring models and regulatory systems. The reform strategy involving changes in ownership/management structures, and industry structure and regulatory environments is a complex operation, and a sequence of phases needs to be planned and implemented. There appears to be no single superior model, and different countries have taken different approaches. Each country has to design and articulate the appropriate reform it intends to undertake. For the reform to work, it is necessary that there is political commitment; the ownership and the leadership of the reform process must be local; and there should be resources to respond to the requirement of the programme. For SubSaharan Africa, the issue is not to decide which of these regulatory regimes is better, but to understand what it takes to adopt and implement any regime in terms of institutional and human capacity, legal systems and the cost involved.

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

References Acton, J. and Vogelsang, I. (1989). ‘Symposium on price cap regulation: Introduction’, Rand Journal of Economics, 20, 369–72. 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 Power Sector 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 Return Regulation: An overview of the discussion’, Bell Journal of Economic and Management Science, I, 162–90. Bennett, J. and Johnson, M. H. (1979). ‘Public versus private provision of collective goods and services: garbage collection revisited’, Public Choice, 34, 55–64.

24 Conceptual Issues Boardman, A. E. and Vining, A. R. (1989). ‘Ownership and performance in competitive environments: A comparison of the performance of private, mixed and state-owned enterprises’, Journal of Law and Economics, 32, 1–36. Borcherding, T. E., Pommerehne, W. W. and Schneider, F. (1982). ‘Comparing the efficiency of private and public production: the evidence from five countries’, Zeitschrift für Nationalökonomie, 2, 127–56. Bös, D. (1991). Privatization: A Theoretical Treatment (New York: Oxford University Press). Bös, D. and Peters, W. (1991). ‘A principal-agent approach on manager effort and control in privatised and public firms’ in Attiat Ott and Keith Hartley (eds), Privatization and Economic Efficiency: A comparative analysis of developed and developing countries (Brookfield, Vt., USA: E. Elgar Publishers). Boyd, C. W. (1986). ‘The comparative efficiency of state-owned enterprises’, in Multinational corporation and state-owned enterprises: A new challenge in international business. Vol. 1 of International Business and International Relations, edited by R. Negandhi, H. Thomas and K. L. L. Rao, pp. 179–94. Greenwich Conn. JAI. Courville, L. (1974). ‘Regulation and Efficiency in the Electric Utility Industry’, Bell Journal of Economic and Management Science, 5 (1), 53–74. Davies, D. (1981) ‘Property Rights and economic behaviour in private and government enterprises: the case of Australia’s Banking System’, Research in Law and Economics, 3, 111–42. De Alessi, L. (1996). ‘Some implications of property rights: A review of the evidence’, Research in Law and Economics, 2, 1–47. Fernando, C. S and Kleindorfer, P. R. (1996). Integrating Financial and Physical Contracting in Electric Power Market. Paper presented at Virtual Utility Conference, March 31–April 2. 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 competitive markets 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 Oxford University Press for the World Bank. Oxford University Press.) Gutierréz, L. E. (1996). ‘How do Sub-Saharan African Utilities Compare?’ in Proceedings of Symposium on Power Sector Reform and Efficiency Improvement in Sub-Saharan Africa, ESMAP Report No. 182/96. Hollas, D. R. and Stansell, S. R. (1988). ‘An examination of the effect of ownership form on price efficiency: proprietary, co-operative and municipal electric utilities’, Southern Economic Journal, 55 (2), 336–51. Hunt, S. and Shuttleworth G. (1996). Competition and Choice in Electricity (New York: John Wiley & Sons). Joskow, P. (1987). ‘Productivity growth and technical change in the generation of electricity,’ Energy Journal, 8 (1), 17–38 Mathios, A. and Rogers R. (1989). ‘The impact of alternative forms of state regulation of AT&T on direct long distance’, Rand Journal of Economics, 20 (1). Megginson, W. L., Nash, R. C. and M. Van Randenborgh (1992). Efficiency Gains from Privatization: An international Empirical Analysis (Athens: University of Georgia, Department of Banking and Finance).

John K. Turkson 25 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 Sector Economics (London: Longman). Peterson, H. (1975) ‘An empirical test of regulatory effects’, Bell Journal of Economics 6, 11–26. Spiller, P. (1996). ‘How should it be done? Electricity regulation 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). Surrey, J. (1996). ‘From Public to Private Ownership: Introduction’ in J. Surrey, (ed), The British Electricity Experiment-Privatization: the record, the issues, the lessons (London: Earthscan Publication Limited). Vickers, J. and Yarrow, G. K. (1988). Privatization: An Economic Analysis. (Cambridge, MA: MIT Press). World Bank (1994). Power and Energy Efficiency Status report on the Bank’s Policy and IFC’s Activities, Joint World Bank/IFC Seminar Report.

3 Privatization of the Power Sector in Côte D’ivoire Etienne K. N’Guessan

Introduction Historical background From the country’s independence in 1960 up until the early 1980s, the power sector of Côte d’Ivoire experienced rapid changes. During this 20-year period, the annual electricity demand growth rate was over 10 per cent on average. The financial health of the state-owned electricity company, Energie Electrique de Côte d’Ivoire (EECI), was very good. That financial status enabled EECI to engage in an ambitious programme of rural electrification, which was costly, but very highly appreciated. Today, it is estimated that about 60 per cent of Côte d'lvoire’s 14 million inhabitants have access to electricity, with about 1400 cities and villages electrified. Before 1983, power generation in Côte d’Ivoire was based mostly on hydropower plants. In 1983, a severe drought forced EECI to switch to thermal generation, leading to severe load-shedding and a dramatic increase in fuel consumption. Thus the bill for fuel costs in 1983–1984 was six times the normal level, with adverse consequences for the financial position of EECI. Subsequently, EECI was not able to regain a sound financial strength for more than five years in spite of several adjustment programmes supported by international lenders such as the World Bank, African Development Bank, European Investment Bank and Caisse Française de Développement. In October 1990, the government of Côte d’Ivoire decided to privatize the operations of EECI by signing a Concession Agreement with Compagnie Ivoirienne d’Electricité (CIE). In July 1994 the government 26

Etienne K. N’Guessan 27

authorized a private developer, la Compagnie Ivoirienne de Production d’Electricité (CIPREL) to build, own, operate and transfer a power plant that is to sell electricity to the national grid. In September 1997, the government of Côte d’Ivoire selected the consortium ABB/IPS to build, own, operate and transfer another power plant dedicated to sell electricity to the national grid, following an international competitive bidding process. As can be seen from this short historical overview, the power sector in Côte d’Ivoire has been transformed in the period 1990 to 1997 from a totally state-owned and operated structure, to a structure now almost completely operated by private 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 1990 and 1400 in 1997. This electrification covered all of the 16 administrative 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. Before 1990, rural electrification was not directly supported by the government, but undertaken solely through funds generated by EECI, either from its own assets, or through loans secured from the banks. The main characteristics of the national grid of Côte d’Ivoire are as follows: 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 Côte d’Ivoire), and about 620 MW in total for the five existing hydroelectric plants ii) Transmission and distribution networks are made of 1720 km of 225 kV transmission line, 2526 km of 90 kV line, 11 substations at the voltage level of 225 kV/90 kV/33 kV (or 15 kV), and 30 substations at the voltage level of 90 kV/33 kV (or 15 kV). The 15 kV voltage level is used for distribution in large cities, while the 33 kV voltage level is used for rural distribution over long distances. The distribution network is composed of about 12 300 km of medium voltage line (both 33 and 15 kV), 10 000 km of low voltage distribution line and 180 000 public lighting points.

28 Privatization in Côte d’Ivoire

iii) The national grid of Côte d’Ivoire is interconnected with the national grid of Ghana, through a 225 kV transmission line on the Ivorian side and a 161 kV transmission line on the Ghanaian side. Interconnection with Burkina Faso is planned, to supply electricity to Bobodioulasso in Burkina Faso from the Ivorian network through a 225 kV transmission line. Studies are under way for the supply 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 cent from hydroelectric plants. National consumption was at 2440 GWh, of which 1300 GWh was for domestic consumers and 1110 GWh for industrial consumers. Total low voltage consumers number approximately 586 000 and medium voltage consumers about 2000. Table 3.1 gives a summary of the power system in Côte d’Ivoire. Historically, growth in electricity consumption in Côte d’Ivoire has outpaced related economic variables, largely reflecting a relatively high growth rate of new consumer connections and a resilience of power consumption per customer. It is expected that electricity demand would grow at the pace of 10 per cent from 1997 to 2000, and 8–9 per cent during the following period of five years. For a long period of time, hydroelectric power stations and the thermal plant at Vridi-1 (100 MW gas turbine and 214 MW steam turbine) met power demand growth in Côte d’Ivoire. Since 1985, low availability at the ageing Vridi steam plant combined with lower than anticipated power generation from the hydroelectric plants, in particular during the prolonged drought period of 1983–4, has forced Côte d’Ivoire to supplement domestic electricity generation on occasion with hydroelectric generation from Ghana. Since 1993, electric power generation in Ghana has become increasingly insufficient to meet both domestic demand and its commitment to supply power to Togo/Benin. This has led these countries to increase power import from Côte d’Ivoire. However, the present electricity demand situation in the Ghanaian market has changed since the construction of a 300 MW combined cycle thermal plant in Takoradi and other potential developments are currently under consideration. Although Côte d’Ivoire has been exporting power, its own rapidly expanding domestic power demand due to the recovery of its economy, the rural electrification programme, and the demand from

Etienne K. N’Guessan 29 Table 3.1

Côte d’Ivoire electricity network

EXISTING GENERATION CAPACITY State-owned thermal plants IPP (thermal) Hydroelectric power Total Additional projected thermal plant (1999)

270 MW 210 MW 620 MW 1100 MW 420 MW

TRANSMISSION NETWORK 225 kV line 90 kV line 225/90 kV substations 90 kV/MV substations

1720 km 2526 km 11 30

DISTRIBUTION NETWORK Medium voltage Line Low voltage line Public lighting point

12 300 km 10 000 km 180 000 km

CUSTOMERS Medium voltage Low voltage

2000 584 000

ANNUAL TURNOVER

FCFA 143 000 mn

ANNUAL ENERGY CONSUMPTION Domestic Export

3210 GWh 770 GWh

large mining and industrial concerns is currently creating a deficit in power generation. An additional capacity of 140 MW is now required. Following the discovery of offshore oil and gas fields in 1993–4, Côte d’Ivoire has been able to reduce its dependency on imported fuel by generating electricity from natural gas. Structure The formulation of the general policy for the power sector, as well as the setting of the regulatory framework, has been assigned exclusively to two ministries: i) the Ministry in charge of Energy, for all technical matters relating to the power sector;

30 Privatization in Côte d’Ivoire

ii) the Ministry of Finance, for the supervision of the financial operation of the power sector. Until November 1990, electricity generation, transmission and distribution in Côte d’Ivoire was managed by the state-owned monopoly, Energie Electrique de Côte d’Ivoire (EECI). In addition to the dayto-day operation, EECI was in charge of all activities related to the development 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 billion FCFA, reduced to one billion FCFA in 1992 after the privatization. The share-ownership of EECI, which was not modified after restructuring of the 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 Côte d’Ivoire. This law stipulates and regulates the principles of electricity generation, transmission and distribution. In particular, the law stipulates that: i) electricity transmission, distribution, as well as the importation and exportation of electricity are a state monopoly; ii) the state can contract the above-mentioned monopoly to be operated 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 sold to the public and utilizes fuel sources that are authorized by the state of Côte D’Ivoire. vi) all existing or future equipment earmarked for electricity transmission and distribution shall be incorporated in Concession Agreements as assets belonging to the state of Côte d’Ivoire; vii) electricity tariffs are set by the state, after consultation with the operator of the system. Tariff-setting is made to ensure balance

Etienne K. N’Guessan 31

between all charges of the electricity sector, including provision for rural electrification, network expansion, debt service and payment to the operator of the system. It is very clear that the existence of the above-mentioned law enabled the State of Côte d’Ivoire to privatize EECI in a very short period of time, in spite of some public opposition during the first stage of privatization in 1990. The formal decision to privatize EECI was taken in August 1990 and the new operator had started its activities by 1 November 1990. This quick action was made possible by the government’s commitment to encourage private sector participation in the power sector as well as by the existence of the appropriate institutional framework. As noted earlier, the existence of the law No. 85-583 gave the 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 the thermal plant of Vridi with an installed capacity of 204 MW. Power generation was approximately 60 per cent thermal and 40 per cent hydro. The only existing hydroelectric plants, Ayamé 1 (2 *10 MW), Ayamé 2 (2*15 MW) and Kossou (3*65 MW), were marginal in meeting total demand of about 200 MW at peak load for the following reasons: 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 during the rainy season, from May to about December; ii) Since its commissioning in 1973, the reservoir of Kossou, with a planned maximum capacity of about 26 billion cubic metres, has not 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, power generation switched from a thermal to a hydroelectric base (60 per cent hydro and 40 per cent thermal) following the commissioning of the Taabo hydroelectric plant (3*70 MW) downstream of Kossou, and the Buyo hydroelectric plant (3 *55 MW) in the western area of Côte d’Ivoire.

32 Privatization in Côte d’Ivoire

The 1983–84 severe drought, however, drastically reduced the generating capacity of the hydro plants, leaving the satisfaction of demand to the Vridi plant, which was not able to meet total demand of about 320 MW. This caused EECI to undertake the following actions: i) as early as November 1983, EECI proceeded with load-shedding, with very bad effects on the public, and catastrophic consequences for the national economy as power imports from Ghana through the new interconnection commissioned in October 1983, were not able to solve the problem because Ghana itself was experiencing the same drought; ii) therefore in December of the same year EECI was forced to order four gas turbines of 25 MW each, which were installed and commissioned by mid February 1984. Financial constraints at EECI The financial consequence of this situation was that the total bill for fuel rose from a planned spending of about 6 billion FCFA to 36 billion for the fiscal year October 1983–September 1984. For a company with an annual turnover of about 80 billion FCFA, this was a severe shock to absorb. The financial crisis that followed made the financial structure of EECI very precarious, especially since management continued with the costly rural electrification programme through high interest commercial bank loans. From 1985 to early 1990, several international lending agencies such as the World Bank, African Development Bank, European Investment Bank and Caisse Française de Développement recommended financial restructuring of EECI, but management overlooked most of their recommendations for sound financial management. The financial crises were further exacerbated by the economic crisis resulting from the low international 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 and greater democracy. Pressure was also mounting on the government to do something about the mismanagement of state-owned companies. This included EECI in particular because of power outages in sensitive areas of Abidjan, the capital of Côte d’Ivoire. EECI was the biggest of the stateowned companies, and its restructuring was one of the top priorities of the international lending agencies.

Etienne K. N’Guessan 33

In spite of EECI’s management problems, its technical operation of the power system was very good. EECI had competent and dedicated technical staff made up of Ivorian engineers and technicians, most of whom were trained in the best French engineering and technical schools through scholarships from EECI. The total system loss, that is the 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, because of power plant internal consumption. Total staff of EECI was about 3500, all of whom were properly assigned; hence excess staff was not a major problem. Electricity bill collection for industrial consumers, about 40 per cent of total consumption, was high (90–95 per cent). Bill collection for private and domestic consumers was also good (more than 90 per cent of total bills collected at deadline). However, bill collection from governmental agencies was irregular and insufficient. Nevertheless, urgent maintenance programmes for the thermal power plants were crippled by the lack of liquid financial resources.

Reform of the Ivorian power sector Power sector reform in Côte d’Ivoire was prompted by the need to implement urgent changes in the management of EECI, which had been operating the company since 1967–8, and was headed by a politically powerful general manager. The only specific goals assigned to power sector reform were to stop the financial mismanagement and restore 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 government entrusted to the private company, Compagnie Ivoirienne d’Electricité (CIE), the duty of operation of the national public service for generation, transmission, distribution, commercialization, importation and exportation of electricity in Côte d’Ivoire; ii) by another Agreement signed on 12 December 1990, the government charged EECI with management of the state-owned assets operated by CIE as well as the right of supervision of the technical functioning of CIE;

34 Privatization in Côte d’Ivoire

iii) on 20 July 1995, the government signed an Agreement with the private company, la Compagnie Ivoirienne de Production d’Electricité (CIPREL) by which the government authorized CIPREL to build, own, operate and transfer a thermal plant of 165 MW initial installed capacity; iv) on 5 September 1997 the government signed a new Agreement with a consortium made of ABB Energy Ventures (ABB-EV) and Industrial Promotion Services SA (IPS) to build, own, operate and transfer 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 a private management firm (management contract) and (b) opening up the generation segment of the industry to Independent Power Producers (IPPs). Management contract Campagnie Ivorienne d’Electricité (CIE) is a privately owned company with an initial subscribed capital of 10 billion FCFA. This capital has been 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 et Rural (SAUR), a subsidiary of the French group BOUYGUES and Electricité de France (EDF); ii) 49 per cent for the Ivorian part, of which 20 per cent is for the state, 20 per cent for the Ivorian public share holders through the Abidjan 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 generation units belonging to the state, including isolated small diesel generating units; ii) operation and maintenance of all equipment for transmission and distribution of electricity in Côte d’Ivoire; iii) operation and maintenance of all equipment for importation or exportation of electricity to or from Côte d’Ivoire.

Etienne K. N’Guessan 35

The Concession Agreement with CIE was signed for a duration of 15 years, with a possibility of extension for two more consecutive periods of three years each. The main stipulations of the CIE Concession Agreement are as follows: i) as the operator of the national electricity network, CIE is not in charge of major repairs of the units, their renewal or rehabilitation, nor new investments in the national grid. This duty has been entrusted to EECI; ii) all generation units, transmission and distribution lines as well as all connections to customers are to be operated and maintained in good order by CIE, at its own expense; iii) works of maintenance executed by CIE shall comprise all actions and activities necessary to keep all equipment in good working order to optimize its lifetime which shall not be less than certain specified values contained in the Concession Agreement; iv) major maintenance or renewal of equipment is decided upon by the state after a proposal by CIE. Those major works are contained in periodical subsidiary agreements contracted for a minimum period of one year. The subsidiary agreements outline the sharing of costs between the state and CIE. The electricity tariff is decided by the government in order to maintain a balanced financial structure in the power sector, including the financing of major works, development of the grid and rural electrification. For the fiscal year 1995/6, the average electricity tariff was about 56 FCFA per kWh. The division of the average electricity tariff among the various partners is as follows: i) the share dedicated to pay CIE for the operation and maintenance of the national network includes all elements of the balance sheet of CIE: expenses, profits, risks associated with the operation, taxes, and duties. This share is estimated at about 21 FCFA per kWh; ii) the share for buying fuel (liquid or natural gas) and/or electricity from IPPs is estimated at about 11 FCFA per kWh; iii) the share for the state for debt servicing, financing new investments, major repair and rehabilitation and new development of the grid is estimated at about 24 FCFA per kWh.

36 Privatization in Côte d’Ivoire

Independent power producers The Ivorian government has a policy of increasing the contribution of thermal power generation to the electricity supply in Côte d’Ivoire. This policy shift is mainly a result of increasing uncertainty regarding the hydrology of the river system on which the hydroelectric plants are installed, and the desire to utilize the gas associated with the country’s oilfields. To achieve this policy objective, the government has encouraged IPPs to enter the generation segment of the industry. Independent Power Producers (IPP) are a new feature of the power sector in Côte d’Ivoire. The first IPP project was more of an accident than a planned endeavour for the following reasons: i) 1995 appeared to be a critical year, since the new President was to stand for election; ii) social unrest, the immediate cause of which was the accidental power outages in some sensitive areas of Abidjan; iii) careful evaluation of the network showed that available generating capacity was sufficient to cover demand, but any unplanned outage, or an inability to import energy from Ghana, could lead to the same situation of power shedding that occurred in 1983–4; iv) in early 1994, additional oil fields were discovered off the coast of Côte d’Ivoire. The government planned to commercialize the very substantial quantity of natural gas associated with the crude oil; v) the only alternative for extracting the crude oil without flaring the associated natural gas was to use it for electricity generation; vi) the four 25MW gas turbines of the Vridi plant could be rapidly converted to burn natural gas, while the other steam turbines could not be easily adapted for that kind of transformation; vii) the political decision to build a new power plant with an initial capacity of anywhere from 50 to 150MW was taken by the new President. His goal was to have the new power plant online by March 1995, both to be able to use the natural gas, and to ensure the security of electricity supply for the elections scheduled during the last quarter of 1995. Compagnie Ivoirienne de Production d’Electricité (CIPREL) is the first Independent Power Producer (IPP) to operate in the power sector of Côte d’Ivoire with a capital investment of 9.2 billion FCFA.

Etienne K. N’Guessan 37

The initial installed capacity of CIPREL was set at 165 MW and was to be 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 a total cost of 36.7 billion FCFA. This stage was entirely financed through private resources; ii) the second stage, which was to consist of two additional units of 33 MW each, was to be financed from an International Development Association (IDA – World Bank) credit to the government of Côte d’Ivoire, on loan to CIPREL. This scheme was designed to reduce the overall financial cost of the project in order to reduce the final tariff of the electricity generated by CIPREL. After International Competitive Bidding (ICB), it was decided to acquire a single unit rated at 111 MW for a total cost of about 20 billion FCFA. This second stage has been online since mid July 1997. The final installed capacity of CIPREL has been increased to 210 MW. Under the CIPREL Agreement, the state has pledged to buy all of the electricity generated by CIPREL on an annual ‘Take or Pay’ (TOP) basis for 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 which point the power plant will be transferred to the state. The CIPREL Agreement established a system of bonus and malus, in which the annual energy supplied by CIPREL is either superior (bonus) or inferior (malus) by 5 per cent to the annual contractual quantity of energy. This bonus and malus system does not include the carry over of the energy that was not supplied by CIPREL. When the annual quantity of energy not supplied by CIPREL is greater than 5 per cent of the contractual annual quantity of energy, but less than 50 per cent of the same, the energy that is not delivered by CIPREL is carried over for the future contractual years. However, every four years, the sum of carry-over energy is set to nil. If during two consecutive contractual years the energy delivered by CIPREL is less than the contractual energy, the CIPREL Agreement is automatically cancelled. In other words, when the annual generation by CIPREL is less than 5 per cent below the annual contractual energy, CIPREL is lightly penalized by the state. On the other side, when demand requires CIPREL to generate more than the annual contractual energy by up to 5 per cent, CIPREL is rewarded for this extra effort; by sharing the profit generated with

38 Privatization in Côte d’Ivoire

the state. However, when CIPREL is not able to satisfy its contractual obligations, that is if it is not able to generate at least 95 per cent of the annual contractual energy, CIPREL has the obligation to generate at no cost to the state, the paid energy it was not able to generate during the previous years. The CIPREL project was negotiated by direct agreement: • the first stage of the project was to be built through private financing, 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 implement the second stage of CIPREL; • the combination of commercial loan and soft IDA loan to CIPREL contributed to reduce the tariff from 15 FCFA per kWh for the first stage (private financing), to 11.7 FCFA per kWh for the overall project. The Azito thermal power project, CINERGY, was the second IPP to start operating in Côte d’Ivoire. The project was awarded after following International Competitive Bidding (ICB), preceded by pre-qualification. The Azito project is the natural follow-up to the success of the CIPREL project. The state, following the general world trend, has decided to leave all new investments in the power generation sector to private investors, while concentrating its financial resources on rural electrification, which is socially important, but commercially unattractive. The 420 MW Azito Project, to be developed on an IPP basis, was officially announced by the President of Côte d’Ivoire in February 1996. Development of the project is a key element of the infrastructure investment programme of Côte d’Ivoire, designed to alleviate looming electricity shortfalls and the resulting negative effects on the country’s economic growth. According to the specifications of the ICB issued by the government of Côte d’Ivoire in September 1996, the Azito Project will be developed and implemented by the consortium, ABB/IPS, on a Build Own Operate Transfer (BOOT) basis, for an expected initial ownership term of construction and operation of 24 years. The government of Côte d’Ivoire will act, through the Fonds National de l’Energie Electrique (FNEE), as the electricity off-taker as well as the fuel supplier under long-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;

Etienne K. N’Guessan 39

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 gas turbine or a combined cycle steam turbine of rating 140 MW, is scheduled to be online by June 2002. A 225 kV network to be built as part of the project is to transmit electricity generated by the Azito Project. The government will finance this, but CINERGY is to be responsible for its construction. Fuel supply for thermal plants has always been a major priority for the operating budget of the power sector. During the 1990 restructuring, for instance, a specific amount was set aside for fuel supply, managed on behalf of the state by CIE. The government has also signed production-sharing contracts with the various oil operating companies. In this contract there is a scheme in which the national Petroleum Company, PETROCI, trades off its share of crude oil against natural gas, thus allowing the state to ensure a stable price of natural gas for internal consumption. Whenever there is a financial crisis, allocation is first made for fuel supply before any other spending. The CIPREL project was negotiated on a TOP basis, while the Azito project was negotiated on the payment of a fixed amount for power and operation and maintenance costs, and a variable amount for energy. The highlights of the involvement of IPPs in the power sector of Côte d’Ivoire are as follows: i) an Agreement was signed on 20 July 1995 between CIPREL and the government of Côte d’Ivoire, and another Agreement was signed on 5 September 1997 between the Azito Power Company (CINERGY) and the government of Côte d’Ivoire. Under the terms and conditions of those Agreements, CIPREL and CINERGY are authorized 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 by Fonds National de l’Energie Electrique (FNEE) through CIE; iii) natural gas or liquid fuel is supplied to both CIPREL and CINERGY in accordance with fuel supply protocols agreed with the government. The government has decided to make fuel available to CIPREL and CINERGY and other new IPPs at no cost. The fuel is purchased by the Fonds National de l’Energie Electrique (FNEE), either from the national petroleum company (PETROCI) for natural gas, or from the refinery

40 Privatization in Côte d’Ivoire

(SIR) for liquid fuel: heavy vacuum oil (HVO) or distillate diesel oil (DDO). Currently, three natural gas supply contracts have been signed on a TOP basis with oil operators in association with their national partner, 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 of Texas (USA), for a maximum of 50 BCF per day; ii) the second contract signed with UMIC in March 1997 is also for a maximum of 50 BCF per day, scheduled to start delivery as of July 1998; iii) the third contract was also signed in March 1997 with APACHE and is for a maximum of 50 BCF per day scheduled to start delivery as 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 of supervising all technical structures in the power sector, and the Ministry of Finance, in charge of the financial matters of all operators in the power sector. Under the new structure, EECI has been assigned new responsibilities. The main duties of EECI after 1990 are as follows: i) management of all assets of the state embodied in the Concession Agreement of CIE; ii) management of the financial assets and execution of the general accounting 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 the national grid; vi) engineering and supervision of work executed on the national grid. Under the CIE Concession Agreement the government, in addition to the technical supervision done by EECI, set up three new structures:

Etienne K. N’Guessan 41

i) le Commissaire du Gouvernement in charge of the general supervision of all activities of EECI; ii) the Technical Commission, composed of representatives of the Ministry in charge of Energy, the Bureau National d’Etudes Techniques et de Développement (BNETD), and EECI. This Technical 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 by EECI for the engineering of projects in the Power sector. By a decree signed by the President of Côte d’Ivoire (No. 94-244 of 28 April 1994) the government of Côte d’Ivoire established the Fonds National de l’Energie Electrique (FNEE) to ensure the balanced management of financial resources of the power sector. FNEE was established as part of the Caisse Autonome d’Amortissement (CAA), the State Bank that had been created for the financing and management of the foreign debt of Côte d’Ivoire. Given the need for better tracking and management of the flow of funds within the power sector, the main objectives of FNEE are: i) to service the debt contracted by EECI at the time when it was in charge of the development of the power sector; ii) to make available funds for renewal and new development of equipment; iii) to supervise the regular payment by CIE of amounts due to the state. FNEE is administered by a Managing Committee made of representatives from the Ministry of Energy, the Ministry of Finance, the CAA, the BNETD and EECI. A Technical Committee consisting of representatives from the Ministry of Energy, the BNETD, EECI and CIE assists the Managing Committee on an advisory basis. Since May 1994 a new Department has been created in the Ministry of Energy. The objective of La Direction de l’Energie Electrique et des Energies Nouvelles (DEEN) is to implement the national policy for developing and managing electricity as well as renewable energy. As such, DEEN’s role is:

42 Privatization in Côte d’Ivoire

i) to contribute to and update the execution of the national energy programme ‘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 the Groupe Spécial Programme Electrification Rurale (GSPER) 1995–6 with the main objective of creating the best conditions for the implementation of the rural electrification programme adopted by the government for the period 1995–2000. As such, GSPER: i) gives its approval to the planning and execution of each annual rural 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 of Energy, the Ministry of Finance, the DEEN, the Direction des Investissements 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 the Groupe Projet Energy Côte d’Ivoire – Banque Mondiale (GPE) with the following main objectives:

Etienne K. N’Guessan 43

i) to supervise the implementation of the conditions of the IDA loan obtained for stage 2 of the CIPREL project; ii) to supervise the implementation of the CIPREL project and all other 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 Energy assigned new objectives to GPE in June 1995, including: i) the examination by GPE of all problems related to the capacity of the existing generation units, as well the adequacy of the existing transmission network; ii) the supervision of all matters related to importation and/or exportation of electricity; iii) the provision of advice to the government on all matters in the power sector. From a temporary structure, GPE was transformed within six months into a permanent structure composed of representatives of the Ministry in charge of Energy, BNETD, EECI, PETROCI and CIE (on an advisory basis). As one can see, the organization of the power sector in Côte d’Ivoire has become very complicated since the privatization of EECI in 1990 (see Figure 3.1). While the private operators seem to operate efficiently, things are complicated on the state side by the large number of structures, all of which have the administrative legitimacy required, but which seem to overlap each other when it comes to operation of projects. As strange as it may appear, when one looks at the professionals in charge of each of these public structures, one finds the same persons from the Ministry in charge of Energy, EECI and BNETD. Thus the need for a reorganization of the power sector of Côte d’Ivoire is pressing, and a study is currently under way to optimize its function. It is therefore apparent that because of rapid and unplanned privatization of the power sector in Côte d’Ivoire the institutional framework has become inadequate to deal with the intricacies of the emergent structure. With the introduction of two IPPs in addition to the operator of the Concession Agreement, the need for a new institutional framework has become very urgent. Conscious of the pressing need for reorganization of the power sector, the state of Côte d’Ivoire has

44

POWER SECTOR IN COTE D’IVOIRE Government

CIPREL

Ministry in charge of Energy Ministry in charge of Finances

IPP (210 MW) CINERGY IPP (420 MW)

GPE DEEN FNEE (CAA) Management of Financial Resources of the Power Sector

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

Figure 3.1

The structure of the power sector in Côte d’Ivoire

GSPER BNETD Technical Supervision of EECI in its engineering duties

EECI – 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

Etienne K. N’Guessan 45

launched a World Bank financed study. The conclusions of the study are not yet available, but from the terms of reference (TOR), one can summarize the objectives of the study as follows: i) the proposed new organization of the power sector in Côte d’Ivoire shall take into account all of the new operators introduced since the first privatization in 1990; ii) the main objective of the reorganization shall be to switch, as soon as possible, from the vertically integrated monopoly in which a single operator controls generation, transmission, distribution and commercialization, to a horizontally integrated system in which several promoters operate distinctly in generation, transmission and distribution. The main characteristics of the new organization shall be as follows: i) to ensure transparency of operation and functioning between the three main components of operation, i.e. generation, transmission and distribution; ii) to ensure equal treatment for all of the operators in the power sector, from the operator of the existing equipment owned by the state, to the new IPPs authorized by the government to produce and sell electricity to the national grid; iii) to ensure better transparency in the importation and/or exportation of electricity, which represents an annual value of about 6 billion FCFA. The new organization shall set clear guidelines for state supervision of the functioning of the power sector. The various existing governmental structures should be reorganized to make room for reduced structures in charge of: i) regulation and arbitration of conflicts between private operators and/or between customers and operators; ii) management of financial and physical assets of the power sector and implementation of consolidated accounting of the power sector. On the operator side, the existence of the CIE Agreement, which expires in the year 2005, makes things more delicate in the immediate future. However, it should be possible to accommodate the CIE Agreement

46 Privatization in Côte d’Ivoire

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

Experiences from implementing reforms Regulatory setting As described above, the basis for regulation of the power sector of Côte d’Ivoire is the Law No. 85-583 of 29 July 1985. This law establishes a state monopoly on transmission and distribution of electricity, but allows the possibility of privatization by stating that electricity generation is not a state monopoly and that private operators could participate upon authorization by the government. Although that law allowed the government to introduce private operators into the power sector, it appears that the more private participants in the sector, the more urgent becomes the need to reformulate the law on electricity. Even after privatization, the government continues to set electricity tariffs after consultation with all operators, be they public or private. As indicated earlier, electricity tariffs are set in order to ensure the financial viability of the companies operating in the sector. Today, the operation of the power sector in Côte d’Ivoire is based on the various agreements signed between the government and the operators in the sector. The agreements for IPPs do not appear to pose any significant problem, given that the rights and duties of both the state and the private operators are clearly defined and that the implementation of the agreements is thus facilitated. However, one can note that as long as an IPP is paid regularly and on time, there is no incentive for it to take part in the optimization of the financial operation of the power sector. The EECI Agreement entrusted the management of the power sector as well as the development of assets and equipment to EECI, while CIE was entrusted with the operation and maintenance of the existing network. This sharing of responsibility seems logical at first sight, but in reality, the system has not been functioning as planned for the following reasons: i) there has never been a contractual arrangement between EECI and CIE on how the technical supervision by EECI of the operation of CIE should be carried out; ii) secondly, EECI has neither the means nor the necessary cooperation from other power sector actors needed to correctly perform its mission;

Etienne K. N’Guessan 47

iii) for various reasons, EECI has not been able to execute fully its contractual mission of the general planning of the development of the power sector. Nor was it able to properly implement the general accounting of the power sector; iv) the division of maintenance responsibilities between EECI and CIE is very difficult to implement because of the need to differentiate between day-to-day maintenance and major repair, rehabilitation or replacement of damaged equipment. As a consequence of these kinds of discrepancies, EECI tends to accuse CIE of being responsible for the poor technical performance of certain equipment, with the argument that CIE did not properly execute its preventive maintenance duties. On the other hand, CIE responds with charges that EECI did not execute the programmed investments in due time. The CIE Agreement planned to designate a Commissaire du Gouvernement with the responsibility of supervising the finance and accounting system of CIE. This position was vacant for a long period (the appointment occurred in June 1997), and so there was nobody to ensure that CIE supplied accurate financial information to the government. For example, while the CIE Agreement clearly specifies that payment by CIE to the FNEE shall occur on the fifth day of each month at the latest, CIE never respected this stipulation and has instead chosen to make random payments. There is no means by which the state can verify that the amount paid by CIE is the actual amount due. The existing institutional framework in the power sector, with CIE as the operator of the whole system except for IPPs, and EECI as the state representative for technical supervision, is inoperable. Responsibilities are neither clearly defined nor willingly accepted. The duties of CIE as the operator are not clearly set. With the addition of IPPs, the state must be able to arbitrate conflicts between operators, which is not the case at this time. Multiplicity of government structures At the time of privatization, there was a complete lack of confidence between EECI and the various governmental agencies in charge of setting the new rules of the game. There were recommendations from some of these agencies to dissolve EECI due to accusations of misuse of state monopoly power and mismanagement of power sector assets. But given the high professional quality of the staff at EECI, it was agreed

48 Privatization in Côte d’Ivoire

that EECI was the best-qualified state institution to supervise the technical operation of CIE. Nevertheless, numerous new structures, described above, were established to supervise the activities of EECI and to regulate CIE. Ideally, one or two institutions should regulate the power sector and make transactions with the various private operators on behalf of the government. However, multiple government structures operating in the power sector have resulted in a situation where each private operator can literally pick the government body with which it is comfortable in order to solve its problem with the lowest possible risk. When it comes to real operation of all these governmental structures, one notices that it is always the same people that are acting as representatives of the different companies.

Conclusions As can be seen from this chapter, the privatization of the power sector in Côte d’Ivoire was performed very rapidly, without specific preparation. This privatization was the first major reorganization of the power sector in SubSaharan Africa. It involved a transfer from a state-owned company to a privately owned company and was done without a reduction of staff in the two new companies. After privatization the maintenance programme of the steam units of Vridi-1 power plant was able to resume, with the support of the major financial lending agencies (CFD, ADB and World Bank). Performance of 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 sharp increase expected by privatization; ii) by the account of CIE, the quality of service has been improved by reducing the annual hours of service interruptions from a peak of more than 70 hours to less than 20 hours. Some experts argue that the 70 hours quoted by CIE is for 1990, when the whole country was experiencing political and social turmoil. They maintain that excepting the period 1983–4, the performance of EECI has been less than 18 hours of outage per year. The main conclusion that one can draw from the experience of Côte d’Ivoire is that each country should initiate reforms of its power sector at its own pace. It is crucial to ensure the existence of the appropriate

Etienne K. N’Guessan 49

electricity law and governmental structures to regulate and supervise private operators, avoiding overlapping institutional objectives and mandates. In Côte d’Ivoire, the financial stability of the power sector has been restored, and in this sense one could argue that the privatization was successful in achieving one of its major goals.

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

Introduction The power sector of Ghana was institutionalized in the early 1960s under the Electricity Department of the then Public Works Department of the Ministry of Works and Housing. Since then, the sector has evolved as a public monopoly. In 1967 the Electricity Department was transformed into the Electricity Corporation of Ghana (ECG), also a fully state-owned electricity distribution enterprise. The Volta River Authority (VRA), currently the only power generating company (referred to hereafter as generator), appeared on the scene under the Volta Development Act of 1961. VRA built the first hydropower plant in 1965. This was then followed by the construction of a very extensive national transmission grid under the ownership of VRA. The Northern Electricity Department (NED) was also set up in 1987, as a semi-autonomous distribution company under VRA, to take over responsibility for electricity distribution in the northern part of Ghana from ECG. Quite recently however, a number of significant changes have taken place in the power sector, as part of the process of re-structuring to create competition and encourage private investment in the electricity supply industry. The ECG has been transformed into a private company limited by shares to be subsequently broken up into distribution concession companies. The operations of VRA have also 50

Michael A. Opam & John K. Turkson 51

been unbundled into separate ‘business units’ for its hydropower generation, transmission services and distribution businesses in the NED operational area. The unbundling of VRA’s operations into ‘business units’ is a transition to a fully unbundled power sector. In addition, two new generation entities, Western Power Company Limited and Takoradi Power Company, both thermal plants,being developed as private–public investment ventures, have appeared on the electricity market. The appearance of these new generators would enhance competition in the generation business. On the end-user side, the Ashanti Goldfields Company (AGC), the second largest single consumer of power in Ghana, has put out a request for bids for the supply of power to its gold-mining facilities under a long-term contract. New generators (besides VRA) are free to bid for the supply of power to AGC and would be licensed under the new market arrangements to do so. While all these developments are underway, a new power sector regulatory law has been passed establishing a Public Utilities Regulatory Commission (PURC) to regulate the delivery of public utility services including electricity. An Energy Commission Bill has also been passed by Parliament. The Bill provides legislative backing for the new structure of the electricity market and regulation of the technical aspects of the operations of electric utility companies. The power sector of the country is undergoing sweeping reforms. This chapter discusses the ongoing reforms. It specifically looks at the reasons behind them, the programme and process of their implementation, the contractual and pricing arrangements in the new market, issues related to the maintenance and regulation of the technical integrity 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 and early 1980s, the creation of a dynamic institutional environment in the energy sector, the growing difficulties with traditional financing sources and the imminent appearance of Independent/Private Power Generators have worked together to provide the impetus for the reform of the electric power sector of Ghana. General economic decline and macroeconomic restructuring The Ghanaian economy, which has always depended on the export of primary products, chiefly cocoa, gold and tropical hardwoods and

52 Restructuring in Ghana

lumber, enjoyed the largest per capita income in SubSaharan Africa at independence in 1957. The rapid economic growth after independence could not be sustained at the turn of the 1970s and early 1980s. The worse period of economic stagnation occurred between the mid 1970s to the early 1980s evidenced by negative growth rates in Gross Domestic Product (GDP), decline in agriculture and industrial output and rapid deterioration in infrastructure (Hutchful, 1996). In terms of economic indicators, Ghana registered negative GDP growth rates between 1980 and 1983, during which time per capita Gross National Product declined by about 17 per cent, exports earnings by over 53 per cent, and gross domestic income by about 17 per cent. External debts rose by 17 per cent while the country’s international reserves declined by about 12 per cent (Kapur, et al., 1991). The severe degeneration in the economy triggered the government’s Economic Recovery Programme (ERP) in 1983, which was subsequently consolidated into the Structural Adjustment Programme (SAP) in 1986. Since then the economy has been growing at an average of 5 per cent per annum. The ERP and SAP saw the revamping of the infrastructural and institutional base of the country in which the power sector was given priority attention. The new thinking led to innovative institutional changes in the energy sector of the country. Government divestiture strategy The second factor has been the government policy on divestiture. A very important component of the SAP has been the strategy of privatizing public sector enterprises to reduce government’s involvement in commercial activities. In view of this strategy, Parliament, in 1993, enacted the Statutory Corporations (Conversion to Companies) Act 461 which established the basis for converting 35 state-owned companies into public limited liability companies. Act 461 was enacted as a core element of the government’s strategy to encourage private sector participation and investment, reduce direct government control of operations, improve efficiency, and reduce government expenditure in several spheres of economic activity, including energy services. Included in the 35 state-owned companies covered under Act 461 is the Electricity Corporation of Ghana, the main electricity distribution company in Ghana. The provisions of this Act gave legal backing for

Michael A. Opam & John K. Turkson 53

restructuring of the whole sector in order to redefine the new role of the electricity distribution company. Growing demand and constraints in power supply The third factor that has brought about reforms is the rapidly growing demand and the need to remove bottlenecks in the supply network of electric power. The general deterioration in the economy in the early 1980s combined with the effects of oil price rises and prolonged and severe drought during the period led to the most difficult era in the history of the country’s energy sector. By 1983 power generation had declined to only 30 per cent of its 1980 level and the distribution infrastructure had deteriorated badly. Indeed the power sector has since been characterized by power shortages causing overall productivity losses to the economy. Domestic consumption of electricity has also seen substantial growth in the last few years, spurred on by positive economic growth and the national electrification scheme. At the national level annual growth reached 13 per cent in 1993. Recent load forecast studies suggest that peak demand on the Ghana system would double in 10 years requiring over 2000 MW of peak capacity compared to the present peak demand of 980 MW. Difficulties with traditional financing sources A fourth and indeed a major factor that has inspired reforms are the growing difficulties with financing new infrastructure projects, such as power projects, from traditional sources. It is estimated that over US$1.5 billion will be required over the next decade to finance infrastructure developments in the electricity sector. This involves US$1.2 billion for new generation capacity to meet domestic consumption of electricity, which has been growing at an average rate of about 10 per cent per year in the last decade. Over US$100 million is also required for transmission expansion and reinforcements. The required investment in improving distribution infrastructure alone is estimated to amount to about US$100 million in the next five years while extension of distribution networks would cost several million dollars more. The government is currently pursuing a National Electrification Scheme (NES) which is aimed at providing electricity to all communities of the country by the year 2020. These major investments are needed at a time when the World Bank, which has been the traditional financier of the power sector of

54 Restructuring in Ghana

Ghana, as a matter of policy, has also been pushing for reforms directed towards mobilizing alternative resources for power sector investments. The dwindling financial resources available to meet the huge demand for development projects worldwide have precipitated this push. Appearance of independent power generators The fifth major factor is the appearance on the electric power scene of new independent power generators. A number of power projects that are currently either being constructed and/or planned are expected to be owned by generators other than VRA, which is at present the only generator of power in the country. A 300 MW thermal power plant, which became operational at the end of 1997, was constructed under the joint ownership of VRA and a strategic private investor. Besides the VRA, other power generators are in the process of entering the Ghanaian electric power market. Western Power PLC, a subsidiary of the Ghana National Petroleum Corporation, is financing a 130 MW power plant to be fuelled from indigenous natural gas. The government also plans to develop run-off-the-river hydropower plants in the Tano, Ankobra and Pra river basins (Western Rivers), with a combined capacity of 300 MW, as private sector initiatives. With the eventual appearance of new power generators on the Ghanaian electricity market there is a need to reformulate the ‘rules of the game’ to govern the market and enable the new entrants to compete without any hindrances. Of all the motivations discussed above the most compelling for reforms has been the need for greater financial resources to meet power demand through the private sector.

Overview of the power sector prior to reforms Institutional structure The management of generation and transmission activities was vertically integrated in the VRA while two separate companies performed distribution activities, namely, ECG and NED. Figure 4.1 shows the structure of the electric power market before reforms took place. The Volta River Authority (VRA) was established in 1961 and has been responsible for electric power generation, transmission and sales in bulk. VRA owns and operates the national transmission lines and also a subsidiary, Northern Electricity Department (NED), which is responsi-

Michael A. Opam & John K. Turkson 55

VRA Hydro

Imports

VRA Dispatch Centre

VRA Transmission–Limited Access

HV Consumers Mines, Large Industries

Figure 4.1

Exports (Togo, Benin)

Distributors

Valco NED

ECG

Old industry structure

ble for electricity distribution in the northern parts of the country. There was only one distribution company, Electricity Corporation of Ghana (ECG), in the country until 1987 when NED was created. Currently, ECG provides services to about 400 000 consumers in the southern part of the country. Sixty-seven per cent of ECG’s consumers are concentrated in the three largest cities of Accra, Kumasi and Tema. The second distribution company, (NED), is a semi-autonomous unit, established within VRA to manage the Northern Grid Extension Project and to undertake the distribution of electricity to final consumers in the Northern Regions of the country. Northern Electricity Department (NED) serves about 30 000 consumers in the northern part of the country. Other major consumers supplied directly by VRA, under bulk supply agreements, include: (i) VALCO Aluminium Smelter which consumes about 45 per cent of power generated in Ghana; (ii) several large mining and industrial consumers that are supplied directly from the transmission grid;

56 Restructuring in Ghana

(iii) exports to the power utilities in neighbouring countries (CIE in Côte D’Ivoire and CEB in Togo/Benin). Ghana’s power system is connected with Côte d’Ivoire on the west and Togo/Benin on the east. Future plans include a 225kV line to interconnect the grid to Ouagadougou (SONABEL of Burkina Faso). The Ministry of Energy and Mines (MME) has ministerial oversight responsibility for the power sector. In discharging its functions, the MME also played the role of a regulator especially in the area of electric tariff review and approval. Supply and demand performance Installed capacity and generation The Ghana Electricity Supply Industry (ESI) plays a very important role in the socio-economic development of the country. In 1993 per capita consumption of electricity was estimated at about 190 kilowatt hours (kWh). Per capita electricity consumption has grown steadily in the past five years at an annual average rate of 9 per cent. The total installed generation capacity for public electricity supply in Ghana is estimated at about 1122 Megawatt (MW), of which 95 per cent (1072 MW) is from the Akosombo (912 MW) and Kpong (160 MW) hydropower plants on the Volta River. The construction of the Akosombo station commenced in 1961 and was completed (912 MW capacity) in 1972. Commercial production of power began in 1965. The Akosombo dam has a storage volume of 148 000 million cubic meters and the surface area is almost 8500 square kilometres. Both hydro plants are owned and operated by VRA. Total diesel generation capacity on the grid is less than 50 MW, of which 30 MW is from the Tema Diesel Plant. Table 4.1 shows the installed generating capacity between 1992 and 1996. Electricity generation by the Ghana ESI suffered a serious decline in 1983 as a result of drought. Generation dropped by about 40 per cent between 1982–3. It reached its lowest level in 1984 when generation was only about 36 per cent of the 1982 level. However, it picked up from 1985 upwards and by 1989 had reached its 1982 level. Transmission and distribution system The existing National Transmission Grid System comprises close to 2800 km of 161 kV lines. Transmission losses are estimated at about 3.2 per cent of total energy transmitted. The existing network for

Michael A. Opam & John K. Turkson 57 Table 4.1

Installed generating capacity (MW)

Generating Station

1992

1993

1994

1995

1996

912 160

912 160

912 160

912 160

912 160

–

–

–

–

30

1072

1072

1072

1072

1102

Hydro Systems Akosombo Kpong Thermal Systems Tema Total

Source: VRA Annual Report, 1996.

Table 4.2

Installed distribution lines in Ghana (1991–2) 1991

kV per kilometre installed 225 kV 161 kV 69 kV Transformer capacity

1992

57 221 375

114.8 442.4 749.2

16 043

32 085

Source: VRA Annual Report, 1996.

distribution of electricity comprises over 120 km of 33 kV subtransmission systems, 450 km of 11 kV distribution circuits within the major urban centres, and approximately 900 km of other lower voltage distribution circuits for retailing of electricity. Public electricity supply and distribution in the southern sector of Ghana is operated by the Electricity Corporation of Ghana (ECG), and the VRA’s Northern Electricity Department (NED) handles the northern sector operations. Table 4.2 shows the installed distribution lines in Ghana in 1991 and 1992. Distribution losses are estimated at about 19 per cent. This is made up of technical losses and non-technical losses (commercial losses) due mainly to pilferage, non-payment, theft, un-metered suppliers, and defective meters.

58 Restructuring in Ghana

Trends in electric power consumption Per capita electricity consumption is estimated at less than 200 kWh. Electricity consumption, however, has been growing rapidly over the past decade reaching about 6657 GWh in 1996, outstripping the generation from the country’s available capability which amounted to 6 626 GWh. Ghana has recently become a net importer of electricity from neighbouring Côte d’Ivoire. The largest consumer of electricity in the country is VALCO, an aluminium smelting company. VALCO’s share of total consumption, however, has declined in the last six years, from 59 per cent in 1991 to 39 per cent, as a result of the reduced generating capacity from the hydropower plants caused by unfavourable hydrological conditions. Other industrial consumers, including the mining companies, accounted for about 28 per cent of electricity consumed in the country in 1996. The mines alone accounted for about 13 per cent of total consumption in 1996. VALCO and other industrial consumers including the mines, with a combined share of about 68 per cent, constitute the largest category of consumers of electricity in Ghana. In 1996, the residential sector accounted for 26 per cent of total electricity consumed in Ghana. Electricity consumption by the residential sector has grown consistently over the past six years at an average rate of 14 per cent per year. This sector is expected to continue to show strong growth in the future. Commercial consumers, such as offices, shops, institutions and hotels account for 5–6 per cent of total electricity consumed in the country. This sector, however, has shown consistent growth in consumption 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 a double circuit 161 kV line while a 225 kV line connects Ghana (Prestea) and Côte d’Ivoire. The Ghana–Côte d’Ivoire line is capable of supplying a demand of 100MW and has been in operation since 1983. Table 4.3 shows the supply of power between Ghana and her interconnected neighbours. The power supply position of Ghana, however, has moved from a position of surplus to one of deficit. Since 1994 power supply transactions between Ghana and Côte d’Ivoire has been in favour of Côte d’Ivoire.

Michael A. Opam & John K. Turkson 59 Table 4.3 Trends in power supply between Ghana and her neighbours (in GWh) 1989

1990

1991

1992

1993

1994

1995

1996

319 0

228 0

0 284.8

0 348.1

Imports CIE CEB

8.4 16.51

– 3.52

– 0

– 0

– 0

– 0

Exports CIE CEB

89.85 335.65

12.86 52.08

449 359

409 485

84 311

18 400

Source: VRA Annual Report, 1996.

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 its own tariffs as contained in article 21, section 4. In the case of ECG, the ECG decree of 1967 paragraph 11 (1), (2) and (3) makes provision for it to operate along commercial lines and ECG’s tariffs must cover the full cost of operation but also ensure that it receives a ‘fair value’ of its assets, a reasonable return measured by taking net operating income as a percentage of the fair value of fixed assets in operation plus an appropriate allowance for working capital. In determining what constitutes a reasonable return, all pertinent economic and financial considerations shall be taken into account. The current procedure is that the utilities make tariff proposals to the Ministry of Energy and Mines which reviews and revises the proposed tariffs in consultation with the utilities. Thus the Ministry plays a regulatory role in tariff setting. The agreed tariffs are then submitted to the Cabinet for approval. Following Cabinet approval, the tariffs, especially the level of taxes built into the tariff, are sent to Parliament for final approval. Electricity pricing Electricity tariffs in Ghana have undergone a number of structural changes after Coopers and Lybrand Associates conducted the first major tariff study in 1987. Before then the structure of tariffs in the

60 Restructuring in Ghana

country had remained unchanged since 1976. Following the study, Coopers and Lybrand recommended a new tariff structure based on the Long-run Marginal Cost (LRMC) concept. They also proposed a new classification of consumers based on the groupings of consumers who impose similar costs on the system. The classification had previously been based on economic activity. They further recommended that residential consumers be grouped by level of consumption. The tariffs were progressive with provision for lifeline consumption of 50 kWh per month. After the Coopers and Lybrand study, ACRES International of Canada carried out a major study on tariffs in 1990–2. As part of the study, the Coopers and Lybrand recommendations were reviewed. ACRES International indicated that the inverted block rate structure that was recommended was difficult to administer and was an ongoing source of customer dissatisfaction. ECG had found itself unable to read all meters on an ongoing 30- or 31-day cycle. This tends to push some customer readings over their point at the end of the required cycle, meaning that the incremental consumption is charged at a higher rate than if the meter were read on time. The study recommended the use of ‘Adjusted LRMC’, that is LRMC that is adjusted to cater for the financial requirements of the utilities. They further recommended that apart from the introduction of the lifeline supply tariff, the residential tariff structure be collapsed into a single energy rate. Thus, besides the lifeline, the other four categories be collapsed into one. To address any timing issue associated with meter-reading and the application of a lifeline supply tariff to the first 50 kWh, the lifeline supply could be converted to a daily use (50 kWh per 30 days) and applied to the number of days between meter readings. In January 1992, new tariffs based on Acres recommendation, and actively supported by the World Bank, were introduced. Since 1994, there has been a shift from the LRMC concept to a more financially based tariff concept whereby the only critical factor in tariff formulation is ensuring that the utilities are able to cover all costs and also 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 convenant reached with the World Bank in the provision of a loan facility to construct the Takoradi thermal power plant in Ghana. One of the major problems with this approach to rate-setting is that there is no incentive for the utilities to reduce or eliminate waste (internal inefficiencies) to reduce cost of electricity supply.

Michael A. Opam & John K. Turkson 61

In addition, the residential customers are classified into four categories, including a new lifeline customer class with consumption below 100 kWh per month. The residential customers therefore face an incremental tariff structure similar to that recommended by Coopers and Lybrand. Industrial customers also face a peak and off-peak tariff structure but have the option for time-of-use meters or a flat surcharge while a Power Factor Surcharge (PFS) has also been introduced to support power correction in the industries (mainly HV and LV consumers). Spatial discrimination in tariffs Electricity tariffs are uniform throughout the country. One of the stated objectives of the power sector development is to have uniform rates for all customers who are served under similar conditions, regardless of geographic location or suppliers. The objectives of uniform tariffs are to facilitate regional development and to reduce the imbalances between urban and rural areas. Planning and investments Planning for the total electric power system has been done by the VRA with the assistance of consultants. The participation of other stakeholders has been very limited. Significant investment has occurred in Ghana, most of which has been financed from foreign loans guaranteed by government. Major foreign sources have been the World Bank, the United States of America, the United Kingdom, the Canadian International Development Agency (CIDA) and the African Development Bank, just to mention a few. Cost and financial performance Since 1989, the performance of State-owned Enterprises (SOEs) has been governed by a Performance Contract, which the SOEs sign with government. The performance-contracting concept was created as part of the SOE Reform Programme under the government’s Structural Adjustment Programme introduced in 1986. The performance contracting idea is to ensure that the utilities change their management practices and improve upon their performance. Table 4.4 is a summary of the technical and financial performance of the VRA. VRA’s financial performance before reforms has been generally satisfactory. 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

Financial Sales (¢m) Net Profit (¢m) Operating Ratio (%) Debt Service Current Ratio Receivables Debt/Equity ROR on ANFA (%) Technical Generation (GWh) Energy Sales (GWh) Sales/Employee (GWh) Gen. Availability Akosombo (%) Kpong (%) Transmission Losses (%)

1989

1990

1991

1992

1993

28 899 12 442 44 3.39 1 2.0 0.27 9.6

37 233 11 929 46.7 3.61 1.3 2.0 0.26 10.2

45 872 15 790 57.9 4.07 1.0 2.2 0.22 8.3

58 450 18 940 70.2 4.55 1.0 3.2 0.20 6.7

72 636 16 171 56.3 3.35 1.32 N/A N/A 6.0

1994 89 190 2821 N/A 2.39 1.24 N/A N/A 3.8

5231 5125 2.2

5717 5541 2.0

6106 5912 2.3

6599 6377 2.6

6291 6207 2.5

6101 N/A N/A

92 86 3.2

96 98 3.3

98 98 2.1

N/A N/A

2.4

89 95 3.1

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

1995 170 35 32 303 N/A 1.87 1.87 N/A N/A 6.17 6129 N/A N/A N/A N/A 3.16

1996 213 016 33 926 N/A 2.79 2.57 N/A N/A 5.21 6622 N/A N/A N/A N/A 2.72

Michael A. Opam & John K. Turkson 63

sales revenue given the fact that over 50 per cent of sales are paid in foreign exchange. While sales and net profits have grown, VRA’s rate of return on revalued average fixed assets in operations has declined from 9.6 per cent in 1989 to 6 per cent in 1993. In 1991 the fixed assets of VRA were re-valued and this, combined with the low tariffs approved for 1992, resulted in the low rate of return recorded in 1992. Other reasons for the decline in ROR are the gradual increase in operating expenses, which increased by about three times between 1989–93. The increases in operating expenses were a result of a general escalation in price due to the cedi devaluation (12.6 per cent between 1990–1991), and salaries and wages adjustment. Except for its operating ratio, which has worsened from 44 per cent in 1989 to 70 per cent in 1992 and 57 per cent in 1993, all the other financial and technical indicators have shown consistent improvements over the past five years. Over the same period, ECG recorded increases in sales every year with sales rising from ¢9.633 billion in 1989 to ¢27.678 billion in 1992. Even though sales increased consistently, the corporation’s net profits declined leading to substantial losses in 1990 and 1991 before recovering to positive net profits in 1992. The losses in 1990 have been attributed mainly to depreciation in the value of the local currency (cedi) which resulted in increased loan interest and high exchange fluctuation charges. Table 4.5 is a summary of the financial and technical performance of ECG. Table 4.5

Summary of performance of ECG (1989–92) 1989

1990

1991

1992

Financial Sales (million) Net Profit (million) Operating Ratio (%) Debt Service Ratio Current Ratio Debtor/Sales Ratio Debt/Equity Ratio

9633.2 305.6 78 1.28 3.50 0.42 0.89

10 880. (1121.6) 95 0.29 1.50 0.42 1.14

14 243 (4065.1) 137 2.28 2.28 0.49 0.47

27 946 4151.07 5 2.7 2.75 0.39 0.62

Technical Energy Sales (GWh) Sales (GWh)/Employee Operating Cost/kWh Distribution Losses (%)

1206 0.39 7.10 17

1249 0.42 8.50 20

1403 0.49 12.32 19.90

1565 0.58 14.34 20

Source: ECG Annual Report, 1992.

64 Restructuring in Ghana

Nevertheless, the major problem that ECG has faced over the past five years is basically low tariffs approved by government. The tariffs have often been too low and thus unable to ensure the financial health of the corporation. However, some of the operational difficulties of the utility have to do with the management control of certain operational elements resulting in: (i) high debtor to sales ratio (ii) high operating ratio and (iii) high distribution losses. ECG’s debtor to sales ratio is relatively high (49 per cent in 1992 up from 42 per cent in 1991 and 39 per cent in 1989 and 1990). This is a result of very low debt collection and subsequently low revenue generation for ECG.

Reform programme and process Objectives of the reforms Essentially, the issues that had to be dealt with at the initiation of the reform process were: (i) How to introduce more effective commercialization and competition in the operations of the existing power utilities; (ii) How to encourage private sector investment in the power sector through the establishment of independent power production schemes, and the provision of an ‘open access grid’ to facilitate direct electricity sales by independent power producers to consumers; (iii) How to establish a regulatory framework that would ensure transparency and enable healthy competition to occur in the power market and provide incentive-based regulatory mechanisms for the regulated segment of the industry. The approach used in the re-structuring programme in Ghana has been influenced by the government’s emphasis on ‘private sector participation’ and not outright privatization or sale of assets of existing utilities. The Ghanaian experience recognizes the strengths of the existing public electric power companies and intends to build on them rather than dissipate them. The primary focus, therefore, has been to create a market in which both public and private electric power generators would coexist on the merit of their capacity to perform efficiently. The reform programme was carried out in 3 main phases covering a number of steps and milestones.

Michael A. Opam & John K. Turkson 65

Phase I Diagnostic studies. As a first step in the process, the Ministry of Mines and Energy, in December 1993, engaged the services of a consultant to study the opportunities for restructuring the Ghana power sector to enhance competition and efficiency. The consultants (SYNEX of Santiago, Chile) concluded their study in June 1994 in which they proposed a new power market for the country. Sector policy letter. On the basis of the diagnostic studies, a sector policy letter was prepared. The document laid out the sector objectives, institutional guidelines and regulatory principles. The letter was the actual beginning of a comprehensive policy drive towards reforms in the power sector. Phase II Establishment of the Power Sector Reform Committee (PSRC). Following the work of the consultants and their recommendations, the Ministry of Mines and Energy set up a Power Sector Reform Committee (PSRC) to co-ordinate the design and implementation of reforms in the power sector following the recommendations of the consultants. The PSRC was made up of eight members representing the private sector, the Ministry of Mines and Energy and the electric power utilities (VRA and ECG). The PSRC took over all responsibilities for the reform programme from then onwards. The Terms of Reference (TOR) of the PSRC sought specifically to develop the detailed strategy and agenda for the reforms by (i) defining a regulatory framework for establishing and revising prices and tariffs for public electricity supply in a transparent manner; (ii) establishing a stable and comprehensive legal and institutional framework to enhance transparency in the regulation of power sector operations by the state. The PSRC, in carrying out its work, used Task Forces with members drawn from the utilities and the Ministry of Mines and Energy and chaired by a member of the PSRC. Consultants were used very sparingly. Formation of task forces. On the basis of the report and findings of the diagnostic studies in June 1994, the PSRC established two task forces to

66 Restructuring in Ghana

develop further the recommendations of SYNEX Consultants. Task Force I was to review and develop the necessary tools for the operational technicalities of the reform programme, particularly pricing and commercial organization of the power market. SYNEX Consultants assisted this task force. Task Force II was responsible for reviewing the legal implications of the proposals for the reform and was assisted by LeBeouf, Lamb, Greene and MacRae Attorneys of Washington DC, USA. Following the work of the two task forces, a workshop, involving most of the stakeholders, was organized in August 1996 in Accra to discuss the proposals emerging from the work of Task Forces I and II. Participants were drawn from a cross-section of the business community (both local and foreign), including representatives from the Mines, VALCO and all Energy sector institutions. Also invited for the workshop were some international organizations including the World Bank and International Finance Corporation (IFC). Review task forces. Following the workshop, a number of task forces were set up to address specific issues emerging from the stakeholders’, conference and to make recommendations for implementation. This Review 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 subsequently consolidated the findings of the various task forces into a report and recommendations, which were submitted to government. A secretariat was established to co-ordinate implementation of the recommendations. The secretariat prepared the necessary bills and model contracts for generation and distribution concessions.

New industry structure and trading arrangements The ultimate objective of the reforms is to create a framework for enabling 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 as envisaged under the reforms:

Michael A. Opam & John K. Turkson 67

VRA Hydro

IPG

IPG

Economic Load Dispatch Centre GELDIC

National Transmisson company – ‘Open Access’

Regulated Market (Demand 5 MW) Mines, Large Industries

Capital Concession Exports

VALCO

South Central Concession

South Northern Eastern Concession Concession

South Western Concession Legend VRA – Volta River Authority WPC – Western Powers Co. Ltd IPP – Independent Power Generators GELDIC – Economic Load Dispatch Centre LTC – Long-Term Contract

Figure 4.2

New industry structure

(i) The generation of electricity is open to other generators besides VRA. A framework has been developed to allow competitive market structure to evolve, where electric power supply would be procured on a competitive basis; (ii) The Volta River Authority (VRA) would compete as a generator and would not be privatized. Thus both private and public electric power generators would operate in the market; (iii) Electric power generators can trade power among themselves or sell power directly to distribution enterprises, major consumers, intermediaries, or the system. Transmission The transmission system is to be operated by a publicly owned national grid company as an ‘open access’, ‘non-discriminatory’ facility. This implies that all generators and distributors will have access to its use based on agreements reached with the grid company. The institution of the transmission system as a ‘common carrier’

68 Restructuring in Ghana

facility is critical to enhancing competition in the restructured market. On the other hand, however, the wholesale competition is limited as only distribution concessions and large consumers have access rights to transmission services. Distribution Distribution companies are to provide unbundled transmission at distribution voltages and sell electricity to retail customers within and outside their traditional service areas. Like the transmission company, the distribution companies have a common carrier obligation on their wire services. Some progress has been made at this level with regard to implementation of the reforms. ECG has already been transformed into a limited liability company to be operated initially as a holding company with autonomous distribution concession companies. The country has been divided into five distribution concessions: (i) capital zone (ii) south-central (iii) south-eastern (iv) south-western (v) northern. The distribution concessionaires purchase power in bulk for distribution to smaller consumers within their franchise areas. The division of the country into five concession zones has been based on reasons of economic and management efficiency. Before the reforms the organization of ECG was too centralized, geographically too unwieldy and difficult to manage. Data on customers and assets were not precise, making it extremely difficult for operational and financial management of the corporation. The concession zones were demarcated to ensure that each zone had a revenue base large enough to survive as a separate economic entity. The NED area, which is currently a low density area but fast-growing, was left intact. Breaking it up further would mean the newly created concessions would not have adequate revenue base. As the area grows, however, new concessions could be created. Final consumers Final consumers, on the other hand, have been divided into two main categories: (i) de-regulated market and (ii) regulated market. De-regulated market The de-regulated market would consist of all consumers with demand 5 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).

Michael A. Opam & John K. Turkson 69

Regulated market This market comprises consumers with a demand of less than 5 MW and who are served by the five distribution concessions. This category of consumers consists primarily of residential, commercial and small industrial consumers. There are about 400 000 of such consumers in the five distribution concessions, and over 90 per cent of them are in the categories of residential and commercial consumers. These customers are generally captive to the distribution concession companies as they do not have access to other power suppliers because they do not 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 transactions and physical operations in the market. This activity would be undertaken by the Ghana Economic Load Dispatch Centre (GELDIC) which would specifically be responsible for co-ordination and dispatch in the whole system. The basic objectives of the GELDIC are the following: (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 of all generators, distributors, operators of the transmission grid and the Public Utilities Regulatory Commission. Contractual and commercial arrangements Generation market Before reforms, VRA was the only company that generated electric power in the country. It generated electricity from its own power plants and also imported extra energy from Côte d’Ivoire for sale to VALCO, and to the Electricity Corporation of Ghana for distribution to the domestic market. VRA also sells power to some mines and industries. Under the reforms, the market is going to have a larger number of players, both generators and distributors. The contractual arrangements in the generation market are discussed below. Figure 4.3 shows the framework for such contractual arrangements.

70 Restructuring in Ghana

LTC (PPA)

LTC

LTC

VRA/CMS Thermal (300 MW)

LTC

VRA Hydro

WPC (130 MW)

Economic Dispatch GELDIC

National Transmisson Company – ‘Open Access’

Regulated Market (Demand 5 MW) Mines, Large Industries

Exports

VALCO

Legend VRA – Volta River Authority WPC – Western Powers Co. Ltd LTC–Long-Term Contract

Figure 4.3

Capital Concession

South Central Concession

South Northern Eastern Concession Concession

South Western Concession CMS – CMS Generation, Michigan GELDIC – Economic Load Dispatch Centre

Contractual arrangements

Generator to generator trading Contractual arrangements. Generators can trade power among themselves in the event of unforeseen difficulties afflicting any one of the generators. Such a situation may be one of the following: (i) economy energy, (ii) scheduled outage service, (iii) unscheduled outage service, (iv) deficiency service, and (v) operating reserve service. This would be a mutual agreement among the generators themselves. Indeed the arrangements would be a ‘paper transaction’ since physically there would be no difference. On the other hand, it may sometimes be expedient for hydro facilities in the system to purchase energy from thermal power producers in order to firm up the hydro energy supply. For example, the Takoradi thermal plant, owned by VRA and a strategic investor (CMS Generation), could enter into a long-term contract with VRA hydro to supply power to it in order that VRA can provide the maximum firm energy capability from its hydro plants. It would also enable VRA hydro to supply firm energy close to its long-term average energy of 6100 GWh as against its actual firm energy of 4800 GWh. Pricing for

Michael A. Opam & John K. Turkson 71

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 among themselves, generators can sell power to the de-regulated market on a long-term contract basis. The current arrangements under which VRA sells power to VALCO under a long-term contract (negotiated about 30 years ago) is a typical example of this type of ‘Generator-Direct Customer Arrangement’. The contract was recently renewed for another 20 years and VRA would continue to honour the contract under the reforms. Customers in the de-regulated market are free to negotiate their supply and prices with generators. Generator to regulated market Contractual arrangements. VRA, by law, is required to provide ECG and NED with all their power needs. VRA has since been supplying ECG and NED under contract and would continue to do so under the new market environment. Besides VRA, other generators (private or public) can sell power to the regulated market. An example of a case where another generator besides VRA can sell power to the central dispatch for supply to the regulated market is the current arrangement that Western Power Company Limited (WPC) has entered into. WPC has signed a Power Purchase Agreement (PPA) with the government guaranteeing to supply all the power from its 130 MW barge-mounted power plant through the dispatch centre to complement hydropower. Pricing arrangements Procurement of electric power to serve the public would occur through the regulated market and prices would be regulated on the basis of the system short-run marginal cost (SRMC) concept. The SRMC concept stipulates that the only costs relevant in deciding how much to produce in plants already constructed, with production capacity already installed, are variable costs of operating that plant. This pricing concept is in conformity with the principle of least-cost operation of the power supply system. In terms of actual operations, procurement of power supply would be on the basis of ‘economic merit order dispatch’ under which generating units are dispatched, with priority given to those generating units with the lowest energy payments.

72 Restructuring in Ghana

Generally, bulk power prices to the regulated market would consist of two components:(i) capacity charges and (ii) energy charges. The cost of the single-cycle gas turbine will be used as the benchmark for pricing capacity and energy since it is considered the most efficient source of additional power supply to any well-adapted power supply system. Transmission services Contractual arrangements The transmission company will have a loose type of contractual arrangement with all generators and distributors. This is necessary to provide services for transmitting all their power supply requirements. However, the contractual obligations would be reviewed annually, or when necessary, to conform to the actual requirements of the system. Transmission service pricing Transmission pricing affects the operational and investment decisions made by the entire industry, as the provision of transmission services play a central role in the supply of electricity. The objectives of transmission pricing should, therefore, be to provide a reasonable rate of return to shareholders while maintaining its physical assets in a safe and reliable condition. In terms of operation, transmission prices should be calculated in order to maximize the benefits of the system operation by correctly signalling short-run costs so that users are aware of the costs that their load or generation imposes on the transmission system. Transmission pricing should also meet the objective of fairness. Since electricity transmission is a natural monopoly, the fairness concept is to allocate charges to users fairly. On the basis of these objectives, the appropriate price structure for transmission services can be broken into 1assets-related costs, energy-related charges, and 2transmission network charges. It is important to reflect all these costs in transmission prices. While it is important to ensure fairness in setting transmission prices, it may sometimes be better and less cumbersome to charge uniform average prices for transmission services. In the case of Ghana, transmission services would be on the basis of uniform average prices, at least during the transition to the fully competitive regime when transmission pricing could be based on the SRMC concept. Transmission charges are therefore based on cost recovery of transmission assets and operation

Michael A. Opam & John K. Turkson 73

and maintenance costs averaged over total energy transmitted. The implication is that all kWh of energy transmitted have the same transmission charge.

Distribution market This market is made up of both a de-regulated and a regulated market. De-regulated market Contractual arrangements The customers in the de-regulated market (direct consumers such as the mines and industries whose demand is up to 5 MW and above) are free to enter into contracts with any generator or the transmission company for the supply of its requirements. The primary concern of these consumers is to obtain electric power that is reliable with regard to supply and at prices which are transparent, objective and predictable. A typical case is well illustrated by Ashanti Goldfields Company (AGC). AGC has recently sent out a request for proposals for the supply of 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 of power under this new arrangement. This represents a case where a large consumer in the de-regulated market can source its own power supply from any generator who either has some installed capacity in the system already or is a new generating company. Large consumers such as Wahome Steel Mill are also in the process of finding dedicated power suppliers on a long-term contract basis. Regulated market Contractual arrangements The regulated market is to service the general public through distribution companies. The distribution companies would consist of concession areas. The country has been demarcated into five concession zones or areas: (i) capital concession, (ii) south-central, (iii) south eastern, (iv) south western concession, and (v) northern concession. These concessions would provide electricity to all consumers with demand less than 5 MW including domestic, commercial and small industrial consumers. All concessionaires are obliged to serve all consumers within their concession areas.

74 Restructuring in Ghana

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 reflects the value-added of distribution services they provide. Economic efficiency requires that distribution costs are calculated as the longrun marginal cost (LRMC) of the activity since the magnitude of the non-variable component of distribution costs is small. Furthermore, for a given density of the grid, it is possible to calculate LRMC as the average cost (monthly capital plus O&M costs per kW) of an efficient model distribution grid of that density. These two concepts serve as the basis for distribution pricing under the new electric power market in Ghana. The value-added of distribution service would be regulated on the basis of an efficient enterprise model. The reference model establishes a standard for efficiency for an optimal size in the high-medium or lowdensity zone classifications for power distribution companies. This standard encourages utilities to match or exceed the reference level of operating efficiency, and thus maximize their profits. The DSC has three basic components: (i) distribution infrastructure capital cost; (ii) operation, maintenance, administrative, billing and other costs not related directly to consumption; and (iii) peak period losses. These three components are used in devising formulas for the various tariff options for consumers. This pricing formula would ensure general transparency in tariffs, especially as it tries to separate costs associated with distribution services from those associated with transmission services and generation supply. Before reforms, tariffs had been set based on the concepts of LRMC which also sought to ensure a rate of return of 8 per cent on average re-valued net fixed assets (ANFA) and a minimum debt service ratio requirement of 1.4. Under the reforms, subsidization of lowincome residential consumers (lifeline tariffs is currently practised) would be continued. The subsidization of residential consumption, if necessary, 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.

Michael A. Opam & John K. Turkson 75

Legal environment Even though macroeconomic factors such as stability in interest rates, falling inflation and foreign exchange policy are imperative for a vibrant private capital investment market, the regulatory and legal environments governing the business environment provide a very strong impetus for promoting private capital flow into the economy. This is especially so when investments are in such highly capitalintensive infrastructure sectors as the electric power industry. The legal environment is most critical because it provides the basis for the enforcement of regulations or ‘rules of the game’ governing the operation of the market. Three approaches to the legal issue were considered. The first approach is to enact a single comprehensive electricity law which defines all aspects of the industry in detail, including regulation and institutional arrangements. The electricity laws in the UK and Chile are fashioned along these lines and indeed many private investors are more comfortable with this approach, which does not leave any ambiguity. Another school of thought views this approach to be too rigid and not easily amenable to change if ever it becomes necessary to do so. In the second approach a simple electricity law is enacted to provide just the right framework for the industry but give the executive (for example the Minister responsible for Energy) the mandate to regulate the sector by separate legislative instruments. This enables the executive to change regulations governing the industry easily when they deem it necessary. Private sector investors are generally apprehensive of this approach since the issue of regulation is left with politicians and is not predictable. The third approach is where a comprehensive regulatory law is enacted outside the existing electricity law. The focus of this approach is actually towards formulating an appropriate regulatory framework and leaving the existing electricity law intact, transfering of regulatory powers to an independent regulatory body. The choice of approach will depend to a large extent on the legal environment existing in the country. The third approach has been adopted in Ghana. Two new Acts have been passed: the Public Utilities Regulatory Commission (PURC) Act 1997 and the Energy Commission (EC) Act 1997. These Acts have created two institutions: the Public Utilities Regulatory Commission and the Energy Commission. The

76 Restructuring in Ghana

VRA Act has been amended only to remove the regulatory power of VRA while the Electricity Decree has been repealed with the transformation of ECG into a company limited by shares. Regulatory framework In general, regulatory safeguards in the electric power industry are necessary in four key areas: (i) (ii) (iii) (iv)

Control of entry (Licensing); Price-setting, Prescription of quality and conditions of service; Imposition of an obligation to serve all applicants under reasonable conditions.

The ‘rules of the game’, as regulation may be called, may be stipulated by contract and/or legislation. Where there is limited experience of regulatory institutions, the rules may be set out in detail in the electricity law that creates the regulatory scheme. On the other hand, where there exists an independent judiciary with a reputation for impartiality and enforcement of private property rights and contracts it is best to consider using the license or contract to achieve the same regulatory objectives. Both approaches have their ‘pros and cons’. In any case, it is widely believed that it is crucial to institutionalize the regulatory process in order to reduce the number of conditions that need to be included in contractual arrangements for private power projects. In Ghana regulation has been institutionalized through the PURC law and the EC law. The two institutions (PURC and EC) created under these laws provide the institutional oversight for the regulation of the whole system and the enforcement of compliance of operational obligations. The PURC would also be responsible for the regulation of electricity and water. Telecommunications, petroleum products and natural gas would be added as and when necessary. The regulatory powers of the PURC would specifically cover the following: (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.

Michael A. Opam & John K. Turkson 77

The Energy Commission (EC) would be responsible mainly for licensing and development of rules to cover the technical operation of the utilities. These are to be embodied in a ‘Grid Operations Code’. The EC would also provide policy support for the Ministry of Mines and Energy. Before the reforms, utilities had self-regulating powers. The statute that established VRA gave it the mandate to set its own tariffs and decide its operations. Similarly ECG had the power to set up its own tariffs and also license new generators except VRA. Practically, however, electricity tariffs were regulated both by the Ministry of Mines and Energy and Parliament. The tariff-setting process required that VRA and ECG make tariff proposals to the Ministry of Mines and Energy for approval. The Ministry vets the tariffs in consultation with the utilities, following which it is sent to Parliament for ratification before it becomes effective. Under the reforms the PURC would be directly responsible for providing guidelines on tariff-setting and approving tariffs without recourse to government or Parliament. The PURC is independent and does not report to anybody, not even the President. The PURC in setting tariffs, however, would open the tariff issues to public hearing and special representations from stakeholders. Tariffs are to be set with due consideration for the interest of investors and consumers and the financial integrity of the utility companies. These concerns in setting tariffs have been specified in the PURC law. As discussed earlier in this paper, generation procurement would be based on SRMC, transmission services would be regulated on the basis of a TSC which would reflect SRMC of transmission while distribution tariff regulation would be based on the DAV of a ‘reference efficient’ distribution company. Technical integrity of system operation The technical integrity of the system is regulated by a grid operations code. The grid operations code, in effect, contains the guidelines, rules and procedures for the effective operation of the whole system to safeguard 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

78 Restructuring in Ghana

Committee. Members of the Committee are representatives of all generators, transmission companies and distributors while compliance would be enforced by the Regulatory Commission. The code would be reviewed and updated periodically.

Managing the transition The key transition issues that the reforms present are: (i) institutional engineering; (ii) tariff; (iii) extension of national grid and rural electrification issues. Institutional engineering The primary concern for managing the transition period is to ensure that the institutions can continue to survive financially as the system is moved from wholly monopoly institutions to marketoriented institutions. The transitional arrangements for a fully unbundled system involve the de-integration of VRA generation and transmission into separate ‘business units’ with different accounting and management operations. This involves the de-coupling of generation and transmission assets and operations. ECG will be transformed into a liability company with a new board of directors. The intention is to move ECG towards a more commercial and businesslike operation with the aim of improving ECG’s overall financial standing to attract private sector participation in this segment of the industry. Tariffs Reforms and re-structuring invariably bring about higher tariffs as a key objective of reform is to enhance efficient pricing and tariffs. This objective may be at variance with the bottom-line interest of customers, which is to see tariffs that are reasonable, fair and above all affordable. The objective of ensuring proper transition to the fully restructured market is to minimize the negative impacts of tariff increases, especially for poorer/low-income consumers. During the transition period, cross-subsidies, especially to ensure a reasonable lifeline tariff, are to be maintained. Rural electrification Another transition issue is how to deal with investment in the electrification of rural areas. A major objective of the government’s policy is to make electricity accessible to the entire population of the

Michael A. Opam & John K. Turkson 79

country by the year 2020. Currently it is estimated that 35–40 per cent of the country has access to electricity. Rural electrification would continue to be the prerogative of the government, in which case extension of electricity to rural communities would be carried out with concessionary 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 and reforming the power sector of Ghana that may prove useful to other countries who are in the process of reforming or are contemplating reforms in their electricity supply industry. First, there is the need for the government’s macroeconomic policy to 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) incentives have to be clearly defined. All these are important ingredients for attracting private capital investment. Second, the ‘political will or commitment’ of the government to implement policies must be unambiguously demonstrated. More often than not, politicians themselves have been the most elusive impediments in privatization efforts. Such commitment from the political authority calls for ‘demythifying’ the ‘myth’ and the beliefs regarding the power sector in particular and the energy sector in general, which are deeply ingrained in most political authorities in SSA and a large section of the population. Among these, it is worth mentioning concepts such as energy self-sufficiency and energy independence, the ‘strategic’ nature of certain energy resources and the common acceptance of arbitrary subsidies in fuel prices and electricity tariffs due to their being ‘essential inputs’. Thirdly, there is the need to develop appropriate policy frameworks and implementation plans for reforms. This process, however, should not be exclusively controlled by the utility companies. The group that is mandated to carry out the reforms should be a multidisciplinary (possibly led by the private sector) group. Under no circumstance should the responsibility for the design, development and implementation of reforms be vested in the existing utilities, especially in the case where they are monopolies, simply for the reason that they have a vested interest in the outcome of the exercise. Nevertheless, they should be involved in the exercise. This is exemplified in the setting

80 Restructuring in Ghana

up and the composition of the PSRC. The process has been spearheaded by a multidisciplinary group (Power Sector Reform Committee) made up of private individuals, academics, and the executive arm of government represented by the ministries and the electric power utility agencies. The reform or re-structuring processes in many countries are being led by the public utilities themselves while in other cases reform has occurred by executive orders. A very important aspect of the committee’s work was to acknowledge from the outset that there are no miraculous short-term, easy, quick and low-cost solutions to the power sector problems, and that it is only possible to handle the tasks successfully if there is wide support from all stakeholders in the sector. Fourthly, the management of the whole process is a challenging task, both with regards to conceptualization and implementation, and it requires time. This process has to evolve. This requires the formulation of well-defined goals and objectives that show the difficult measures likely to be adopted. This would ensure that the process evolves in the right direction, and also brings concrete, rational, achievable and fair solutions, rather than short-lived improvisation of high cost solutions for some sectors of the population. The process in Ghana recognizes this fact and therefore opted for a process that relies on careful consideration of all aspects of the reform process. The fifth lesson is the adoption of a realistic strategy for implementing different decisions based on the reform. Implementation strategies must minimize the adverse impacts of decisions such as tariff increases on consumers. Such sensitivities may not have been seriously considered in the recent (May–June 1997) tariff increase which caused a national uproar, and which caused the President to intervene to suspend its implementation. This was clearly an example of a manifestation of bad implementation strategy of a good policy. The issue here is that electricity rates are definitely going to go up and a suitable strategy is needed to implement the tariff increases without causing any negative public reaction. Finally there is the need to seek assistance from people who have been involved in similar exercises before to ensure that avoidable mistakes are not made. Challenges While the government has undertaken an elaborate and meticulous process to restructure the power sector, and mapped out strategies to

Michael A. Opam & John K. Turkson 81

manage the transition, the challenge now is how to guide the implementation process and make the restructured industry work. One of the major challenges is for the Ministry of Mines and Energy to ease itself out of the regulatory role and allow the PURC to function. For the credibility of the reform process and the PURC, involvement of the ministry should be at a minimum. The other challenge is the potential of regulatory capture by the big actors in the market. This is a real possibility in the present situation where the industry has no history of a formal 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 to extract information from the actors in the market (mainly generators, transmission and distribution companies), evaluate the quality of the information, process the information and monitor the performance of the power market.

Conclusion The cornerstone of the reform is to allow competitive market principles to operate in the generation segment of the industry, while the transmission and distribution segments are regulated by an independent regulatory body. This regulatory body would institute incentive regulatory regimes for the operators in those segments of the industry, and also meet the government’s objective of making electricity accessible to all Ghanaians by the year 2020. The reform has the additional objective of improving the quality of service to all classes of customers in the country. The extent to which these objectives are realized will determine the ultimate success of the reform of the power sector.

Notes 1 Asset-related charges consist of a connecting point charge, transmission network charge and demand-related charges. 2 The transmission network charges are constituted by (i) a spinning reserve charge and, (ii) an overhead charge. The spinning reserve charge recovers the cost of providing spinning reserve and interruptible load. Spinning reserve is required to provide cover against sudden losses of generation on the system. The alternative to keeping a spinning load is to shed load without notice for a limited duration which results in much higher costs associated with unserved energy.

82 Restructuring in Ghana

References Hutchful, E. (1996). ‘Ghana 1983–1994’ in Poul Engberg-Pedersen, Peter Gibbon, 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: IMF Occasional Paper No. 86 September). VRA (1996). VRA Annual Report.

5 Power Sector Reform: A Kenyan Case Study Stephen 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 power sector reform (that is ownership changes, unbundling of the utilities, legal and regulatory reform) as an important option for addressing the problems faced by power utilities in Africa and other developing countries. Of particular interest has been some form of private sector participation. This can take place in several forms. Examples include contracting-out services such as rehabilitation, maintenance, meterreading and bill collection etc.; contracts for operation and management of the entity; joint ventures with government utilities, based on competitive bidding; and private equity investment in power 83

84 Experiences in Kenya

corporations or new projects and outright sale of existing power sector companies. Structural changes may take the form of vertical or horizontal unbundling of the power sector. Regulatory reform usually implies some form of institutional restructuring that often results in the establishment of an independent regulatory body and design of incentivebased regulatory schemes as well as related legal reforms. There are thus many options available and choices to be made if Kenya is to choose the reform path that best suits its own economic, political and financial characteristics. The on going reforms in Kenya’s power sector are the focus of this chapter with the aim of sharing Kenya’s experiences in power sector reform with other countries in SubSaharan Africa. Figure 5.1 highlights key elements of the paper’s conceptual framework.

Figure 5.1

Conceptual framework of the study

Stephen Karekezi and Donella Mutiso 85

The energy sector Kenya’s energy sector is one of the most important sectors in the country. 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 the national 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, broad changes in the national economy have a major impact on the country’s electricity industry. For instance, real GDP growth declined between 1989 to 1993 due to structural policies; the 1991–3 drought; foreign exchange shortages (this affected the Kenyan power industry’s ability to import necessary machinery and equipment); and, unfavourable external terms of trade. These factors, in turn, impacted negatively on the energy industry triggering several problems in the sector (Republic of Kenya, 1995a). In Kenya, wood fuel is the most prevalent source of energy for all sectors except the commercial and transport sectors. It accounts for approximately 70 per cent of the total energy demand (Bhushan, 1995; Republic of Kenya, 1995b). Petroleum is in next most important energy source and accounts for about 21 per cent of the total energy demand (EIU, 1996; Republic of Kenya, 1995b). Up until very recently, Kenya had not discovered any exploitable resources of oil or gas. There has been a recent discovery of petroleum that still remains uneconomic to exploit. The Mombasabased Kenya Petroleum Refineries operates the country’s sole oil refinery, which meets most of its crude oil needs from the United Arab Emirates (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 sugar refining in western Kenya and is used for blending with petrol. Since only a small quantity is produced, it is consumed only in Nairobi and nearby areas. Electricity is the third largest in terms of energy demand in the country. It accounts for about 8 per cent of total national energy demand. Installed capacity in 1995 was about 808.7 MW (Central Bureau of Statistics, 1996), a tenfold increase in the installed capacity of 79 MW at independence in 1963. The sources of electricity include

86 Experiences in Kenya Table 5.1 Year/source

1992 1993 1994 1995 1996

Kenya’s installed capacity from 1992–5 Installed capacity (MW) Hydro

Thermal

Geothermal

Total

603.5 603.5 603.5 603.5 599.5

156.3 156.3 159.3 160.2 160.5

45.0 45.0 45.0 45.0 45.0

804.8 804.8 807.8 808.7 805.0

Source: Central Bureau of Statistics, 1996.

hydro, geothermal and thermal/diesel (Bhushan, 1997; Republic of Kenya, 1997). Electricity from the Ol-Karia geothermal plant is expected to supply a larger proportion of the country’s electricity requirements in the future. Currently, geothermal accounts for 45 MW or about 5 per cent of the country’s total installed electricity capacity. It is estimated that the country’s installed capacity of geothermal-based electricity could increase to about 320MW by the year 2015 (Kenya Energy Review, 1990). The table above shows the increase in installed capacity 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 hydrobased installed capacity by 0.7 per cent. This was attributed to mechanical problems at Kindaruma dam. Other alternative energy sources include biogas, solar energy and windpower. A small amount of coal is used in the cement industry where it acts as a substitute for petroleum. Kenya has a large potential of solar and wind energy, which have economic potential for meeting future energy requirements for rural communities. At least 40 000 photovoltaic 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 manufactured locally. KPLC operates a 200 kW wind turbine which in 1995 provided 1.1 GWh to the grid and a 350 kW hybrid wind/diesel system to serve the electricity needs of the surrounding community (World Bank, 1997). Figure 5.2 shows the distribution of the main energy sources in Kenya.

Stephen Karekezi and Donella Mutiso 87

Woodfuel 70.0%

Others 1.0%

Electricity 8.0%

Petroleum 21.0% Figure 5.2 Source:

Energy sources in Kenya

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

Status of the power sector Over the last five years, the power sector has experienced several technical, operational and financial problems. This has led to stagnation in generating capacity expansion and in transmission and distribution system reinforcement. Energy analysts argue that this difficult situation has been caused by a combination of internal deficiencies and inadequate support and investments from donors and multilateral development banks. This section gives an overview of the past and current institutional structure of Kenya’s power sector. It also assesses Kenya’s demand and supply scenario as well as some of the major problems facing the sector, making an attempt to show how they may be linked to 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 consumption has been driven mainly by increased demand for electricity in the

88 Experiences in Kenya

3500

Consumption in kWh m

3000 2500 2000 1500 1000 500 0 1991

1993

1995

Years Street Lighting and Rural Electrification Domestic Figure 5.3 Source:

Off Peak Industrial

Electricity consumption for the years 1991, 1993 and 1995

adapted from Bhushan, 1997.

categories of small-scale enterprises and domestic consumption (Bhushan, 1997). The Kenyan power sector is estimated to require at least 40 MW of additional electricity generation capacity every year, if it is to meet the increasing demand of electricity. The level of investment in the sector in the last five years cannot accommodate such expansion (Kenya Times, 1997b; EIU, 1997). The Least Cost Power Sector Expansion Plan prepared for the Government of Kenya indicates the need for an additional installed capacity of 1288 MW by the year 2013 if projected demand is to be met (Republic of Kenya, 1995b). This implies more than a doubling of current installed capacity. Official government documents envisage that power sector reform combined with private sector participation would assist in mobilizing the required investment to finance this planned expansion and development programme.

Stephen Karekezi and Donella Mutiso 89 Table 5.2

Least cost generation expansion plan

Fiscal year

Generation additions Hydro (MW)

1997–1998 1998–1999 1999–2000 Sondu/Miriu 2000–2001 2001–2002 Ewaso A 2002–2003 Ewaso B 2003–2004 2004–2005 2006–2007 2007–2008 2008–2009 2009–2010 2010–2011 2011–2012 2012–2013 TOTAL

2 × 30 2 × 45 2 × 18 + 2 × 27

Geothermal (MW)

LS Diesel* (MW)

MS Diesel** (MW)

2 × 32

1 × 50

6 × 12.5 6 × 12.5

2 × 32 2 × 32 2 × 32 2 × 32 2 × 32 2 × 32

240 MW

448 MW

1 × 50 2 × 50 1 × 50 1 × 50 1 × 50 2 × 50 450 MW

150 MW

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

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

Institutional, legal and regulatory framework The Kenyan government has traditionally been the pivotal actor in the country’s power sector. The Ministry of Energy is mainly in charge of making policy related to the energy sector as a whole. The supply of electricity in Kenya has been, for a long time, the mandate of the following five organizations, all of which are state-owned entities.

90 Experiences in Kenya

– – – – –

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 electricity sector include existing auto-generators of electricity particularly in the agro-processing industry (e.g. sugar companies), research institu-

Figure 5.4

Major energy institutions

Source: Compiled by authors Notes: KPLC is partly privately owned, but most of the shares are state-owned KPLC Kenya Power and Lighting Company KPC* Kenya Power Company TARDA Tana and Athi Rivers Development Authority TRDC Tana River Development Company NOCK National Oil Corporation of Kenya KPRL Kenya Petroleum Refineries Limited KPC** Kenya Pipeline Company

Stephen Karekezi and Donella Mutiso 91

tions, NGOs and small-scale private solar electricity companies. The agro-processors produce electricity for their own internal purposes. KPLC has always resisted buying electricity generated by other producers (e.g. agro-processors) despite a general feeling within official circles that small-scale generation using indigenous resources should be encouraged. The figure above shows the major institutions in Kenya’s energy 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 programmes; – Development and exploitation of renewable energy technologies such as solar, wind, biogas, geothermal and wood fuel (Okech and Nyoike, 1995). The Ministry has five divisions namely: Finance and Administration, Planning, Geo-exploration, Biomass and Engineering. The Finance and Administration division deals with matters pertaining to finance and personnel. The functions of the Planning division include energy demand forecasting, supply planning, project planning, evaluation and monitoring and pricing. The Geo-exploration division co-ordinates exploration of petroleum and geothermal energy resources. The Biomass division is in charge of woodfuel development and the promotion of efficient cookstoves and biogas. The Engineering Division is in charge of power generation planning; rural electrification; licensing of electrical contractors; energy conservation; and, promotion of solar and wind energy technologies (Okech and Nyoike, 1995). The origins of the Kenya Power and Lighting Company (KPLC) date back to 1922 (Okech and Nyoike, 1995). Before and just after independence (1963), it was known as the East African Power and Lighting Company (EAPLC) which served the whole of East Africa region. The EAPLC was started in 1922 to generate and distribute electricity produced by thermal generators in response to the demand from geographically dispersed urban centres. It changed its name to Kenya Power and Lighting Company (KPLC) in 1983 through a special resolution of shareholders. The present set-up and evolution of KPLC can be

92 Experiences in Kenya

seen to have evolved in response to increasing power demand and the need for a more systematic development of the energy sector. KPLC was responsible for the preparation of the sub-sector’s expansion programmes and was the state’s executing agency for the design, construction and operation of rural electrification schemes. KPLC is a limited liability company quoted on the stock market with the government having majority share holding (Daily Nation, 1997a). The government has 59 per cent of the shares. This includes the shares held by two state corporations, namely the National Social Security Fund (NSSF) and Kenya National Assurance Company (KNAC), currently under liquidation. The rest of the shares are owned by the private 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 been ensured through its majority ownership of the company’s shares and the presence of Permanent Secretaries of the Ministries of Energy and Finance as well as appointees with other political and government connections on KPLC’s Board of Directors (Nyoike and Okech, 1996). Up until June 1997, KPLC held a de facto monopoly in the transmission and distribution of electricity in the country. KPLC is run by a government-appointed board of directors which is answerable to the Ministry of Energy (MOE) on policy matters. KPLC owns and operates hydro plants at Ndula, Sagana, Gogo, Selby and Mesco as well as some thermal plants at Kipevu, all of which total about 174.38MW (about 20.7 per cent of the total installed capacity in Kenya). KPLC had, until recently, the mandate of overseeing and managing the other organizations operating in the power sub-sector, i.e. KPC, TARDA, TRDC and KVDA. The links with these organizations have taken different forms. KPLC provides staff to carry out administrative, technical and management functions in all the projects undertaken by KPC and TRDC. KPLC had the task of maintaining and operating the Masinga and Kiambere power facilities owned by TARDA. The Turkwell power project was managed on the same lines, even though there was no formal agreement on its management by KPLC. These management contracts required KPLC to operate and maintain in good order all plants owned by these companies and to provide the following services: engineering, legal, secretarial, personnel and office accommodation. In return KPC, TRDC and TARDA pay KPLC, in addition to a management fee agreed upon from time to time, an amount equal to the total expenditures incurred by KPLC in carrying out its obligations under such agreements (Nyoike and Okech, 1996).

Stephen Karekezi and Donella Mutiso 93

Figure 5.5 shows KPLC’s organogram. For a long time, KPLC was the only institution licensed to market and distribute electricity and, therefore, effectively owned all the distribution facilities. The Kenya Power Company (KPC) was created in 1954, as a de facto subsidiary 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 Maragua rivers. It was to sell both supplies to what was then EAPL. Until 1970, KPC’s shareholders were the colonial Kenya government, EAPL and the Power Security Corporation Limited (London). The main justification for the establishment of KPC was the need to raise capital from the

KPLC Board

Managing Director

Company Secretary

Deputy Managing Director

Internal audit Project Development Public Relations

Generation Distribution Corporate planning Commercial Rural electrification & internal wiring Research and devt. Finance Credit control Personnel Transport & supplies Administration

Figure 5.5

KPLC’s organizational structure

Source: Nyoike and Okech, 1996.

Executive Committee

94 Experiences in Kenya

international markets to construct the transmission line to Uganda (Nyoike and Okech, 1996). With very little management and staff of its own, KPC was effectively a state-created entity with the primary purpose of attracting investment and loans that are normally restricted to government and government-owned agencies. The bulk of its operational 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 geothermal plant (about 45 MW nominal capacity), two small hydropower plants, Tana (14 MW) and Wanji (7 MW), 132 kV and 66 kV transmission lines from the western border of Kenya to Nairobi (Karekezi et al., 1996; Republic of Kenya, 1995b; East Africa Standard, 1997b). These plants account for 12 per cent of Kenya’s total installed capacity. In June 1997, KPC was separately reconstituted and given the mandate to generate and sell power to KPLC. The Tana River Development Company (TRDC) was created in 1964 to co-ordinate and finance hydroelectric development in the middle Tana river where Kamburu, Gitaru and Kindaruma hydroelectric power stations are located. TRDC was also in charge of the transmission lines from the power stations to Nairobi (ibid, 1995b). The Kindaruma hydroelectric power station (44 MW) was commissioned in 1968. Up until 1970, the shareholding capital of TRDC was a nominal £100 million sterling that was held equally by EAPLC, the Kenya government, the Power Security Corporation and the Commonwealth Development Corporation. In 1970, a decision was made to sell all the equity shareholdings in TRDC to the Kenya government at the original nominal value, to enable the government to get a loan from the World Bank (Nyoike and Okech, 1996) for financing the development of the Kamburu hydropower station. TRDC accounts for the largest electricity generation capacity in the country, with a total of 280.5 MW installed capacity and 273 MW effective capacity (Nyoike and Okech, 1996). Since KPC and TRDC did not have any technical staff to operate and maintain their power facilities, KPLC provided this service and thus, effectively, transformed itself into the most dominant power utility in Kenya (Karekezi et al., 1996). In many respects, KPLC has been the principal de facto, monopoly power sector entity in Kenya. The Tana and Athi Rivers Development Authority (TARDA) was formerly known as Tana River Development Authority (TRDA). TARDA was created in 1974 and established in 1984 to develop the Tana River and Athi River basins. TARDA has two hydropower facilities located at

Stephen Karekezi and Donella Mutiso 95

different sites. It owns and manages the Masinga and Kiambere hydroelectric power stations. Their total capacity is about 184 MW (Nyoike and Okech, 1996). The Kerio Valley Development Authority (KVDA) was created in 1979 with similar objectives to TARDA. It implemented the Turkwell Hydro Plant (106 MW), completed in 1991 (World Bank, 1997). This plant accounts for about 13 per cent of the national installed capacity and about 15 per cent of the national effective capacity (Nyoike and Okech, 1996). KVDA is fully owned by the government. In addition to these bulk producers, there are several auto-generators in the agro-processing industry (e.g. sugar companies and tea estates) as well as institutions and private individuals licensed to generate electricity for their own exclusive use (Republic of Kenya, 1995b). Kenya’s power sector is regulated by the following three principal Acts: – the Electric Power Act; – the State Corporations Act; – the Geothermal Resources Act. The Electric Power Act is an Act of Parliament designed to facilitate and regulate the generation, transmission, transformation, distribution, supply and use of electric energy for lighting and other purposes. The Act 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 generating licensee or an authorized distributor shall generate, transmit, construct, maintain or operate works for such generation or transmission of electrical energy’ (Government Printer, 1986). According to CAP 314 section 10 (1), the Minister of Energy may grant a bulk supply license for a period not exceeding 50 years to any public or local authority, company and person to supply energy in bulk to bulk supply licensees or authorized distributors within the area described in the license. The Minister in any such license may authorize the generation of electricity (Government Printer, 1986). The State Corporations Act gives the President and the responsible Minister wide discretionary powers over state corporations (World Bank, 1997; GOK, 1996). Up until 1997, KPLC and KPC operated under this Act. The Geothermal Resources Act (1982) is meant to regulate the use of Kenya’s geothermal resources. It establishes that geothermal resources belong to the state and confers power to the Minister of

96 Experiences in Kenya

Energy to issue licenses for exploration and exploitation of geothermal resources. 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 sector exists. In effect, the Minister of Energy is the sole regulator of the power sector (World Bank, 1997), but the government is working towards establishing a regulatory board to manage the country’s power sub-sector. The new Electricity Bill, which is discussed in the later section of the chapter, provides for the creation of a regulatory body to regulate the activities of the power sector.

Power sector problems Over the years, Kenya’s power sector has suffered from both institutional and operational (technical and financial) problems. While some of the problems faced by Kenya’s power sector are of a technical and management nature, a large number of constraints faced by the country’s electricity industry can be traced to its unwieldy structure and complex and opaque institutional interrelationships. The management contracts between KPLC and the other organizations (KPC, TRDC and TARDA) discussed in the prior section, seem complex. Whether these companies possess the institutional and technical capability to determine what is a fair value for the services rendered is an open question. On the other hand, debt related to the acquisition of generating assets is not incurred by KPLC but effectively remains with the other state power sector entities. This may, to a significant degree, explain the rather positive financial status of KPLC. TARDA and KVDA are Regional Development Authorities (RDAs) which do not have any specific mandate over activities in the power sector. They seem to be involved in the power sector simply because hydropower resources happen to be in their area of jurisdiction. This complicates the institutional framework. With the exception of KPLC, many of the other state corporations involved in the power sector have been operating at a loss and regularly require injections of financial support from the state treasury. Table 5.3 below shows the operating income of some power sector companies. The trends shown in Table 5.3 indicate poor financial performance, which is partially linked to the complex institutional relationship between the organizations listed. Of particular importance is the

Stephen Karekezi and Donella Mutiso 97 Table 5.3 Operating income of power sector companies (ksh million) from 1986–1991 Year

KPC

TRDC

KPLC

Total

1986/87 1987/88 1988/89 1989/90 1990/91

–23 –86 262 26 64

–209 –109 –51 –330 –167

135 93 309 79 139

–97 –102 520 –225 36

Source: Nyoike and Okech, 1996.

ability of KPLC to pass on investment-related liabilities to other state power corporations while using these assets to generate revenue for itself. Kenya’s power sector has, for a long time, suffered from intermittent electricity supply, frequent blackouts, power rationing and illegal connections. In 1994, the system losses were estimated to be 15.4 per cent (Gutiérrez, 1996) compared to the international standard of about 10–12 per cent. Contrary to popular opinion, power rationing to homes 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 from Uganda (Republic of Kenya, 1995a) and has also experienced capital constraints for new power installations. The decline of the electricity imports from Uganda has been mainly due to increased power demand in Uganda and the continual reluctance to provide power because of the very low tariffs paid by the Kenyan counterparts. According to an agreement made in 1955, Uganda was to supply Kenya with 30MW, daily at a fixed rate, for 50 years (i.e. up to the year 2004). Uganda has been supplying power to Kenya at a rate of two US cents per unit for over 35 years whereas it spends six US cents to produce a unit of electricity. On the other hand the Uganda Electricity Board (UEB) currently supplies Rwanda and Tanzania with power at a cost of 8.25 US cents and 8 US cents per unit, respectively. Ugandans have called upon their Kenyan counterparts to revise these tariffs made through a colonial agreement, by agreeing to pay market rates for the power (The New Vision, 1996a). In October 1996, a new arrangement between the two countries was put into place. Uganda now supplies Kenya with a minimum of 10 MW of power between 5am and 6pm at 6.50 US cents per unit and as much power as Kenya requires at night

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(off-peak times) at 6 US cents per unit (The East African, 1996). Uganda’s domestic and industrial demand for power has shot up to 220 MW, while power generation has slumped (The New Vision, 1996b), thus making it unrealistic for the country to provide as much power to Kenya as it did before. Lack of sufficient maintenance on the interconnected-grid system has led to a number of break-downs. Some of the equipment, such as switch-gear in some substations, are old and underrated. The drought of 1995–6 further aggravated the power shortages. System operations have been constrained due to insufficient reserve margin and further affected by the damage suffered by one of Gitaru’s generating units which took about a year to repair (World Bank, 1997). Because of rapid urban population growth and housing growth, some sections of the distribution network are overloaded. These sections are affected by low voltages and increased network losses (Republic of Kenya, 1995b). The aforementioned 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 capacity necessitated load shedding during the peak hours. Frequent power outages and rationing have had a very negative impact on Kenya’s industry. For example, audited accounts of Kenya’s main cement factory in Mombasa showed that the company had to cancel some vital export business due to power rationing. The company was forced to install large and expensive generators to meet its electricity needs. The increased production costs eroded the return on the company’s turnover substantially (East African Standard, 1997a). For many years, the average electricity tariff remained substantially below the economic and financial cost of supply. As a result, the power sector experienced financial difficulties which impacted on its ability to service external debt obligations (World Bank, 1997).

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

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This chapter subdivides reform options into two categories, namely: structural changes and ownership (privatization) changes. The two terms are often used interchangeably and power reform initiatives are often a mix of the two. For conceptual clarity, this study defines structural change as distinctively different from ownership (privatization) change. Figure 5.6 attempts to portray the two reform paths in a diagrammatic form. In many cases, options on both structural change and ownership change axes are undertaken concurrently but, for reasons of conceptual clarity, this chapter keeps the discussion on the two reform paths separate. The underlying rationale in both cases is to improve the performance of the industry by streamlining management and ensuring more transparent oversight. Another important objective is often the introduction of market forces which should presumably lead to more efficient operation. Several other measures designed to increase market forces include freeing the entry of new actors into the power sector

Complete vertical unbundling

Complete horizontal unbundling (Provincial utilities which are vertically integrated) R e s t r u c t u r i n g

Unbundled generation and distribution

Unbundled generation, common transmission and distribution

Vertically integrated utility

Provincial distribution and generation, national transmission (Common carrier)

Provincial distribution companies, national generation and transmission

National utility

Privatization/Ownership changes Privatization of Corporatization Contract generation and (arm’s-length management distribution relation to government) IPPs – Commercialization Privatization of Parastatal generation

Ministry Department Complete Public Ownership

Figure 5.6

Structural change and privatization

Complate Private Ownership

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market, encouraging competition and permitting joint ventures (Beesley and Littlechild, 1983). The prevailing conventional wisdom largely asserts that private ownership as opposed to public ownership almost 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 unbundling of the system (Reinier Lock, 1996). Vertical unbundling is expected to lead to separate generation, transmission and distribution units which are treated as independent entities. In practice, however, vertical unbundling starts with the separation of generation from transmission and distribution mainly because of the ease with which this can be accomplished without losing oversight and control by a national regulatory agency. In theory, at least, another important objective of vertical unbundling is to separate distribution from generation and transmission (G&T) and free the newly independent distribution entity from G&T management, which often dominates vertically integrated monopolies. This form of vertical unbundling has been rarely implemented in Africa. Vertical unbundling is also designed to bring the distribution function closer to consumers, hopefully leading to improved service. The newly unbundled distribution unit is then expected to adopt a more independent approach and act in the consumers’ interest when negotiating with generation and transmission entities. Splitting generation, transmission and distribution is expected to facilitate relating costs to output and making management decisions and performance more transparent and thus easy to monitor. Horizontal unbundling often involves dividing a national utility into several vertical integrated regional or district utilities (Karekezi, Majoro & Gathu, 1996). Available literature argues that horizontal unbundling can bring utilities closer to the customer and thus prove more responsive to local needs. Depending on the original structure of the utility, horizontal unbundling may prove easy to implement by allowing easy subdivision of important generation, transmission and distribution assets. The main drawbacks of horizontal unbundling include possible increase in commercial inflexibility and re-emergence of monopolistic tendencies at provincial and district level. Ownership (privatization) changes Ownership changes or popularly known as privatization is the transfer of ownership or control from the government to the private sector. The

Stephen Karekezi and Donella Mutiso 101

transfer should be sufficient to vest the private operators or owners with substantive independent power (IFC, 1995). Ownership changes often involve deregulation and competitive tendering, together with the introduction of private ownership and market management. Privatization is likely to come in stages, take considerable time and may never cover the entire power sector (Reinier Lock, 1996). Ownership patterns have evolved over the years from private to public and recently back to private (IEA, 1994). In developing countries, the bulk (57 per cent by value) of privatization took place in the Latin America and Caribbean region, followed by Central Asia with 18.7 per cent. Being late starters, SubSaharan Africa, the Middle East and North Africa have, to date, accounted for a relatively small share of total power privatization although this is changing rapidly (IFC, 1995). In Nigeria, for example, private investment in the power sector was first accepted 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 simultaneously) means that conduct of the business entity is based on commercial principles. Organizations are treated like commercial enterprises 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 also involved. Corporatization and commercialization provide a way of reforming public utilities with the aim of exposing the organization to the discipline enforced by the market, while retaining the advantages of public ownership (Steyn, 1994). The process of corporatization is usually combined with commercialization, with the aim of improving management efficiency. • Contract management usually involves an agreement through which operational control of a company or part of a company is delegated to an external operator. In management lexicon, outsourcing of key company activities can be in the form of a contract management agreement. A contract management agreement is usually formalized through a medium-term contract. In some contract management agreements, personnel from the external operating company occupy some of the companies’ key positions, but the company remains the owner of its installations and controls most investment decisions. The operating company’s intervention is generally limited to service

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provision. In addition to placing high-level personnel within the company’s hierarchy, it may carry out one-off short-term support missions. The operator is paid either by the company it is managing or by financial backers and does not, therefore, bear the risks related to operation. When the operator’s remuneration is linked to management improvement criteria (billing rate, recovery rate, and so on), the contract is called a management performance contract. Contract management has been widely practised in some industrialized countries. It was perceived to be an effective tool for giving utilities more autonomy within the framework of a performance agreement. Utilities were held accountable for desired outcomes, as measured by a negotiated set of performance indicators covering a wider 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 bulk sale to an electricity utility or for retail sale to industrial or other customers. At global level, the introduction of IPPs is becoming a more widespread form of private sector intervention in the electricity industry. IPPs have for some time been a major source of power generation capacity in the United States and, increasingly, in some European countries, notably the United Kingdom and Portugal. The USA has been a leading example both in the volume of capacity added by IPPs and in experience with designing and implementing contracts under which energy and power are sold to the integrated system. Many countries in Africa are also turning to independent power producers to expand their electricity supply. The design of an IPP 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) and Build, Lease, Transfer (BLT)

The power sector reform process in Kenya In the late 1980s, it was foreseen that new investments in Kenya’s power sector were needed in the 1990s if severe supply shortages were to be avoided. The World Bank through its International Development Association (IDA) affiliate could not support new investments in the absence of an agreement on power sector reform policies and implementation programmes (World Bank, 1997). This was, in many respects, the single most important impetus to current ongoing reforms in Kenya’s power sector. The role of World Bank’s IDA to

Stephen Karekezi and Donella Mutiso 103

Kenya’s power sector cannot be overlooked. The World Bank, through its IDA affiliate, provided seven loans and credits totalling about US$212.2 million for financing power investments in Kenya between 1971 and 1988 (World Bank, 1997). It has been, for a long time, the prime financing agency for the electricity sector and has been instrumental in mobilizing investment finance for Kenya’s electricity sector from major bilateral development agencies and banks. The World Bank’s emphasis on power sector reform and involvement of private enterprise in the electricity sector is driven by a belief that the state has generally proven to be a poor manager of productive assets and consequently its role in the productive economy should be sharply curtailed. While this view had been aggressively pursued in other sectors such as industry and agriculture, the encouragement of private sector participation in the power sector of Africa is a more recent development. More recently, Kenya’s principal donor agencies, led by the World Bank, have made it very clear that continued provision of financing support for the power sector is strictly contingent on power sector reform and involvement of the private sector. This has been amply demonstrated by the response of the World Bank and other bilateral donor agencies to the initial power sector reform steps undertaken by government. The World Bank pledged to provide Kshs 7.2 billion for the reinforcement of the power sector, while the Japanese Economic Co-operation Fund committed funds for the development of the two 75 MW diesel power stations at Kipevu (East African Standard, 1997b). Consequently, many independent analysts believe that the power sector reform process in Kenya is largely donor-driven with limited local input both at the conceptual level and at the level of implementation. Existing literature on power sector reform in other developing countries tends to emphasize the role played by other factors such 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 power sector reform process in Kenya, they appeared to be largely of a secondary nature. The primary impetus clearly emanated from the World Bank which was and continues to be the most important champion of power sector reform in Kenya.

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Generally public involvement in the power sector reform process has been very limited and largely restricted to feeble complaints about the increased frequency of power outages and higher tariffs that have been recently implemented. With the exception of AFREPREN researchers such as Okech of the University of Nairobi, the involvement of independent research institutions and NGOs in the power sector debate has been minimal. The authors believe that limited involvement of the public and civil society has contributed to opaque decision-making in the reform of the power sector and may eventually undermine some of the achievements that power sector reform initiative was designed to attain. The reform process A number of studies undertaken with the help of IDA financing and under a Project Preparation Facility led to the preparation of the ongoing Power Development Project. The total cost of the programme is estimated at US$699.9 million equivalent excluding taxes and duties and interest during construction (World Bank, 1997). Many of the power sector reform initiatives in Kenya’s electricity industry have been initiated by this World Bank project. Restructuring Vertical unbundling. Some form of vertical unbundling was already in place in Kenya because many of the country’s electricity generation stations were owned by state river development authorities and not by the country’s dominant utility, Kenya Power and Lighting Company Ltd (KPLC). On the other hand, many of state river development authorities had virtually no technical personnel and staff with the skills to run the power stations. Consequently, most power stations were run by KPLC thus transforming it into a de facto vertically integrated power utility. Early in 1997, KPLC’s generation assets were separated from its distribution and transmission facilities. Its power generation assets as well as those of other main power companies in Kenya were transferred to the newly formed Kenya Power Company (initially, a de facto subsidiary of KPLC), ahead of its possible privatization (Financial times, 1997; Daily Nation, 1997a). KPC will now be exclusively in charge of power generation. The assets that KPC will take over include Masinga, Kamburu, Kindaruma, Kiambere, Gitaru, Turkwell Power station and other minihydro 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

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function will now be confined to transmission and distribution. The government expects the new status of KPC to enable it to compete on an equal footing with the independent power producers for bulk supply of electricity to KPLC (Daily Nation, 1997a; and East African Standard, 1997b). KPC remains wholly owned by the state, but will now have its own management and staff. KPC’s Board and Managing Director were appointed by the Minister of Energy in December 1996. The personnel task force was appointed in February 1997. The power purchase agreements between KPLC and KPC were signed in June 1997 (World Bank, 1997: Annex 7.6). The government expects the takeover of assets and operations by KPC will be conducted gradually to ensure that the transition provides continuity, stability and harmony of operations in both KPC and KPLC, and customer interests are safeguarded. Kenya’s business community are positive that the new changes will reduce the complexity of the relationship between the KPLC and the other power producers. From an investment point of view, Kenyan stockbrokers view the separation of management of generations assets from transmission 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 commercial basis. This is attributed to the involvement of the private sector which owns a substantial chunk of the KPLC’s shares as well as its quotation on the Nairobi Stock Exchange. This exposes it to the oversight of the private sector as a well as state entities that regulate the Nairobi Stock Exchange. The government of Kenya underlined its commitment to the commercialization of the power sector, in a recent Power Sector Policy guide document that requires the power sector to operate on a commercial basis without burdening the government budget by requesting subsidies from the state treasury (World Bank, 1997). Energy analysts, however, pointed out that the low electricity tariffs that prevailed in the country for the long period, undermines the power industry’s ability to run on a commercial basis. In March 1994 tariff adjustment, the government allowed KPLC automatically to adjust the level of consumer tariffs to reflect changes in fuel prices (Republic of Kenya, 1995b; GOK, 1996). In June 1995, the government agreed to higher end-user electricity tariffs and managed to achieve an average tariff equivalent to 67 per cent of the long-run marginal cost of

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electricity supply (Republic of Kenya, 1995b; GOK, 1996). Adjusting the average tariff has enabled the power sector to realize an operational profit and raise some capital to sustain additional investments in the electricity sector. Increased tariffs are expected to attract new entrants into the power market. Contract management. The Kenya Power and Lighting Company (KPLC) has made an attempt at contracting out certain non-core activities. It has contracted out security services and the construction of one 33 kV sub-transmission line (Republic of Kenya, 1995b) and is actively examining the possibility of contracting out additional activities and tasks. On a more conventional note, the Kenya Power Company (KPC) signed an engineering consultancy services contract in 1997. The contract with Nippon Koei Company of Japan is for the implementation of the 60 MW Sondu-Miriu hydropower project (Daily Nation, 1997b). Independent power producers. It can be argued that Kenya has had some kind of independent power industry for some time. These early independent power producers were largely limited to auto-generators of electricity in the agro-processing industry. Most of the auto-generators used the bulk of the electricity generated with very limited sales to the grid. The majority of auto-generators were in the sugar-processing and tea-processing industries. The sugar-industry-based auto-generators used bagasse as the feedstock fuel for their power generation units while the tea-processing industries relied on small hydro schemes to generate electricity for their outlying tea estates and factories. As stop-gap measures designed to address the power sector crisis that was affecting the country in 1995–6, Kenya signed its first private power scheme in September 1996 with Iberafrica of Spain and Westmont Power (Kenya) Limited to generate 43 MW and 46 MW respectively (Financial Times, 1997). The companies would be using thermal power units. The Westmont Power (Kenya) Limited is a limited liability company owned by Malaysian interests. It entered into a power purchase agreement in early 1997 to supply bulk power to KPLC. The generating system (situated in Mombasa) comprises of a barge-mounted combustion turbine generator, operating in single cycle, capable of generating a net electrical output of approximately 46 MW at ISO conditions, together with a 11/33 kV, step-up transformer, dead-end structure and SF6 circuit breakers (Kenya Gazette, 1997). It will undertake generation of electricity and sell it to KPLC for distribution (East African Standard, 1997a).

Stephen Karekezi and Donella Mutiso 107

The Iberafrica Plant, owned by Spanish interests, is situated in Nairobi. The plant is already supplying 24 MW of electricity to KPLC for distribution (EIU, 1997). The Kenya Power employees’ pension fund was used to buy 1 130 000 shares worth Ksh 113 million so as to increase local participation in the Independent Power Producing firms (Daily Nation, 1997c). According to the East African Standard (1997c), one of the country’s leading daily papers, discussions are about to be concluded for two other private power projects. One of the plants is a 75 MW diesel project at Kipevu II and the other, a 64 MW geothermal project (a BOO arrangement for both), at Ol-Karia, Naivasha. Independent Power Producers have been invited to invest $106 million in the Kipevu II project and $195 million in Olkaria III geothermal project. Construction of a geothermal power plant at Olkaria will earmark 800 million Kenya shillings (Indigo Publications, 1997a). The only funding secured for a $699 million expansion programme for 1997–2001 is a loan from the Japanese Government of $83 million for Kipevu 1 for which bids are now being evaluated by the designated consultant in the United Kingdom (EIU, 1997). Figure 5.7 attempts to illustrate various changes in structure and ownership of Kenya’s power

Complete vertical unbundling Unbundled generation and distribution Unbundled generation, common transmission and distribution

Vertically integrated utility

Scenario 2 R e s t r u c t u r i n g

Scenario 1

1997 1995

1996–97

1983 Privatization/Ownership Changes Complete Privatization of Corporatization Contract Private generation and (arm’s-length relation Ownership Management distribution to Government) IPPs – Privatization of Parastatal Commercialization Privatization of generation, generation transmission and distribution

Ministry Department Complete Public Ownership

Figure 5.7

Reform changes in the power sector

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sector that have taken place to date, and the paths the reform is likely to take in the future. Legal and regulatory changes It appears that most of the major changes to the country power sector are relatively recent with the bulk of changes taking place between 1995 and 1997. KPLC and KPC were recently exempted from the State Corporations ACT which severely limited the entities’ management and operational autonomy. The new Electricity Power Bill that has just been passed by Parliament and forwarded to the President for ratification is expected to result in additional power sector structural changes. This Bill amends and consolidates the laws pertaining to the generation, transmission, distribution, supply and use of electrical energy for lighting and other purposes. Some of the key changes that the Bill seeks to realize, as outlined in the Kenya Gazette (Bills No. 17) are reproduced below: • Before applying for a licence, the applicant should give a notice by public advertisement, not more than 90 days and not less than 60 days before the application is to be made. • An application for a licence shall be submitted to the regulatory board for consideration and recommendation to the Minister. • All licence applications for the generation, distribution and transmission of electric power shall be processed within 180 days after the Electricity Regulatory Board confirms to the Minister in writing that the application is materially complete in all respects. • Before granting a licence, the Minister shall give notice in the Kenya Gazette. • Licences to electricity power producers shall be issued for a term of not less than 15 years. Licences to public electricity suppliers shall be issued for a term of not less than 30 years. • The Minister may establish a fund (the imposition of a 5 per cent levy on all electricity consumers in the country) to be known as the Rural Electrification Programme Fund to support the electrification of rural areas and other areas, considered economically not viable for electrification by public electricity suppliers (Republic of Kenya, 1997b). This new Electric Power bill also provides for the establishment of an Electricity Regulatory Board (ERB). The Electricity Regulatory Board

Stephen Karekezi and Donella Mutiso 109

shall be a body corporate with perpetual succession and a common seal and 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 of Kenya, 1997b). According to the Kenya Gazette Supplement No. 61, the functions of the Electricity Regulatory Board will be to: a)

Set, review and adjust tariffs for all persons who transmit or distribute electrical energy for sale; b) Investigate tariff structure even when no specific application for a tariff 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 power producers, public electricity suppliers and large retail customers. Funding of the Board shall be obtained through a levy which the Minister of Energy may impose on electricity sales for this purpose (Republic of Kenya, 1997b). The Minister shall direct the Board on policy relating to the power sector (Republic of Kenya, 1997b). The membership of the ERB, shall comprise persons with a University Degree or its equivalent and not less than 15 years practical experience in matters related to industry, finance, economics, engineering, energy or law (Republic of Kenya, 1997). The Board shall consist 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 recognized by the government as representing organizations for workers, employers and manufacturers. According to the new bill, the Chairman shall hold office for four years and shall be eligible for reappointment for a further term of three

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years. The other members apart from the ex-officio member shall hold office for three years, after which they shall be eligible for reappointment 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 assessment of the reforms that have taken place to date. In general, however, the power sector reform process has had limited involvement of the public and consequently drawn criticism from the independent press for not being a transparent process (EIU, 1997). This may be due to the public’s limited understanding of power sector issues and the absence of sufficiently qualified and interested consumer bodies that are willing to address power sector issues. It would, however, be right to state that the need for power sector reform was not extensively discussed within or outside Parliament. Apart from general policy support for reduced government involvement in production activities of the economy, the case for power sector reform has yet to be made to the general public and it is still unclear whether there exists consensus even within key policy-making bodies, such as the Parliament. In the view of the authors, this omission of public debate may create problems in future. A populist wave could conceivably reverse the ongoing power sector reform initiatives. The situation in Kenya contrasts sharply with Uganda where the government has initiated a very public and highly successful campaign to garner public support for privatization. For each major sector that is slated for reform and privatization, the Ugandan government has made strenuous efforts to make the case to the public and invite public debate and discussion. No such initiative has been undertaken in Kenya for the power sector nor for the economy as a whole. Consequently, the public’s reaction to liberalization and privatization continues to be less than enthusiastic. The case for the advent of the two IPPs was not extensively debated nor was the public fully informed of the negotiation terms that the government agreed upon. The absence of detailed documentation on the two IPPs has fuelled widespread suspicion both within Parliament and with the independent press. Consequently, the two IPPs have become a target of speculation and were recently cited by the independent press as constituting an important impediment to resumption of balance of payment support

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from the International Monetary Fund (IMF) as well as the World Bank (Daily Nation, 1997c). Speculative reports in the press indicate that the negotiated contract period was too short (published newspaper reports cite a seven-year period) resulting in higher-than-normal electricity purchase prices (Daily Nation, 1997c). In the absence of publicly available documentation, it is difficult to assess the extent to which these accusations are correct or are largely driven by competing political interests. This initial controversial experience, however, does not bode well for the future of the power sector reforms. In response to strenuous complaints from Parliamentarians on the negotiation terms of the two IPPs, the government recently hired the international auditing firm, Price Waterhouse, to undertake an indepth evaluation of the agreement between the government of Kenya and the independent power producers. According to recent media reports (Daily Nation, 1997e), the Price Waterhouse report, which was recently submitted to the Ministry of Energy stated, among others, that: ‘KPLC did not fully employ transparent procedures in inviting bids and did not provide adequate information to the bidders to enable them to submit their best bid … attempts to find out the shareholders of the Iberafrica and Westmont power companies have been futile.’ According to the country’s leading daily, the Price Waterhouse report attributes the flaws experienced in awarding the tenders in the initial stages to inexperience by KPLC staff and the emergency situation prevailing in the power sector requiring immediate action (Daily Nation, 1997e). Because of the recent nature of the changes in the power sector and the absence of publicly available documentation, it is very difficult to predict what the electricity industry in Kenya might look like in the future. It is notable that this chapter has been compelled to rely on speculative newspaper articles because of limited availability of relevant documents accessible to the public. The authors have, however, attempted to outline two scenarios that portray alternative future projections 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 the dominant nature of KPLC. The proposed legal and regulatory changes could conceivably lead to two scenarios. The base case scenario assumes the entry of numerous IPPs (including co-generators) competing with the recently reconstituted government-owned Kenya Power Company (KPC), with transmission and distribution being the domain

112

Figure 5.8

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

Stephen Karekezi and Donella Mutiso 113

of KPLC. Currently, this scenario seems to be the most likely in the near to medium term. Essentially, some level of competition will be introduced at the generation stage but the transmission and distribution will remain firmly in the hands of the dominant utility, KPLC. It is envisaged that the recently reconstituted KPC will inherit existing low-cost hydro plants which are largely paid for. This should place KPC at some advantage over new entrants, which may constrain competition at the generation stage. On the other hand, control of transmission and distribution would retain KPLC’s stranglehold on the power industry. With the exception of some limited competition at the generation end, this scenario would not be particularly different from the prevailing situation before the advent of independent power producers. In the high case scenario, more generators are expected to enter Kenya’s power market to compete with KPC and existing co-generators. The transmission system would be jointly controlled by all key actors through a joint-stock company or government-owned but privatesector-managed transmission company. Several distribution companies would compete with KPLC. This is a very competitive structure, which would only be realized if the proposed Regulatory Board proves to be effective and aggressively pursues the goal of establishing a competitive power market in the country. Current developments indicate that the possibility of such a competitive power market being established in the country is fairly limited. It is, however, important to note that continued public support for power sector reform will largely depend on the extent to which the positive impacts of power sector reform are perceived to be significantly more substantive than the negative impacts, the subject of the next section. The next section will, therefore, begin by outlining the beneficial impacts and drawbacks associated with past and current power sector reform measures. Thereafter, the authors attempt to outline what the future structure of the power sector might be and end by drawing lessons 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-run marginal cost (LRMC) of electricity supply. The recent adjustment of the electricity prices (an important pre-requisite for power sector reform initiatives), which allows the utility to attain 67 per cent of the LRMC, has been an important factor in enabling KPLC to realize an operational profit and contribute to the sectors investment

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programme. During the 1995/96 fiscal year, the company registered a pre-tax profit of Sh 1.51 billion equivalent to about US$25 million at the current exchange rate (Kenya Times, 1997a). The government allows KPLC to automatically adjust the level of consumer tariffs to reflect changes in fuel prices. It is also expected that the higher electricity tariff will attract the interest of independent power producers. A staff reduction programme at KPLC is already in progress (Republic of Kenya, 1995a). In 1993, KPLC had 10 616 employees serving 300 000 customers, which translates to a customer employee ratio of 28:1. By December 1994, the ratio was 35.4:1 and currently stands at 50:1. This reduction was achieved mainly through voluntary staff reductions and outsourcing of non-core activities such as security provision through contract management. There are, however, concerns that the staff reduction may have led to the departure of a large number of experienced and skilled professional staff members and left behind a diminished and less skilled staff complement. The decision by the government to split the functions of KPLC, limiting its activities to transmission and distribution of electricity resulted in a positive response from investors who showed their enthusiasm by buying and selling its shares in a frenzy. Both foreign and local investors are fighting to acquire a stakehold in the extremely profitable company. According to stock exchange analysts, this sharebuying frenzy is a ringing endorsement by investors of the policies and abilities of the current chief executive and his excellent track record. The vertical unbundling makes KPLC leaner. This move also does away with cross-subsidies. For instance, if the generating side makes losses, it will not automatically be bailed out by other sections. The advent of the two IPPs has already had a visible impact on power outages which are no longer as frequent as they used to be. Clearly IPPs have greatly assisted in addressing the power crisis that Kenya is facing. The new Electric Power Bill underlines the government’s commitment to private sector participation in the power sector and is a strong message to external power sector investors that the level of high-level policy support is substantial. This should lower the government’s need to allocate its scarce investment funds to the power sector and allow the private sector to carry a larger share of this investment load. As the number of IPPs increase in the power sector, bulk supply tariffs for purchases from IPPs may begin to be based on the International Competitive Bidding (ICB) process (World Bank, 1997) which could conceivably bring down costs and tariffs for bulk purchase of electricity. Similar trends in the recently liberalized petroleum sector

Stephen Karekezi and Donella Mutiso 115

have taken place with substantial price reductions in bulk supply of petroleum products. This, however, has not been the case for retaillevel sale of petroleum products. The new Electrical Power Bill also provides for the separation of policy and regulatory functions, which have both hitherto been exercised by the Minister of Energy. This reduces the government’s direct involvement in the power sector which has been often cited as an important constraint to effective operation and management of the electricity industry. Drawbacks associated with the power sector reform process The reform process has not been very smooth and has experienced some flaws. As mentioned earlier, the IPP awards have been particularly controversial. Several international contractors have questioned the transparency of the awards (EIU, 1997). The method used in awarding the contracts has been a bone of contention between the government and the International Monetary Fund (IMF), with the latter arguing that the seven-year supply period was too short and the unit cost was on the higher side (Daily Nation, 1997c). Even though the new Bill has attempted to reduce the role of the government in regulation, critics of the Bill argue that ultimately the Minister of Energy will effectively remain in charge because of the pivotal role that the Minister will play in selecting board members as well as his role in determining the budget of the board (Republic of Kenya, 1997b). The new Bill provides no special incentives to local cogenerators that would probably limit their participation in the liberalized power market. This may result in limited local support for the power sector reform process. For example, special incentives could have been provided for small-scale independent power producers for plants of less than 20 MW. Many co-generators in the agro-processing industry would have been interested. This would not only garner more local support for the power sector reform process but the aggregated total from all co-generators could constitute a substantial proportion of the country’s electricity generation installed capacity. Independent legal analysis of the proposed Electric Power Bill indicates that substantial barriers to the new entrants will remain and that the licensing procedures are cumbersome. For example, the proposed Bill requires applicants to set up an office in Nairobi even as they await a decision from the board. This is a costly process bearing in mind the fact that the bids could be turned down. In addition, the applicant is supposed to supply a draft of the licence which may be an indication

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that the responsible government agency may not have the necessary expertise. The proposed Bill is also unclear on issues related to acquiring land for the purposes of power generation. The Land Act states that land can only be acquired for ‘public purposes’. The proposed Bill remains silent on whether independent power projects will be considered public or private initiatives. The proposed Bill does not outline the rules and guidelines that the Board will use to evaluate licence applications. The numerous grey areas of the proposed Bill are particularly worrisome because of the rather cumbersome and elaborate objection procedure that the Bill recommends. A highly emotive debate on the proposed Electric Power Bill in Parliament demonstrated that many Parliamentarians were wary of power sector reform and were uncomfortable with the involvement of the private sector in the electricity sector. In a recent Parliamentary debate, a number of Parliamentarians insisted that the new Electric Power Bill would favour the rich and politically connected individuals at the expense of the rural poor (Daily Nation, 1997d). One of the reasons why power sector reform (particularly privatization) continues to face resistance from Parliamentarians and independent energy analysts is the prevalent belief that it may constrain rural electrification, a highly emotive issue that is often a bone of contention among senior decision-makers. Many independent energy analysts argue that the limited revenue that rural electrification will generate for suppliers will make it particularly unattractive to private sector entrants to the power sector. The imposition of a 5 per cent levy on all electricity consumers in the country to enable the Minister to establish a fund for purposes of rural electrification (Republic of Kenya, 1997b) should assist in expanding access to electricity in rural areas. According to the proposed new Bill (Republic of Kenya, 1997b), the fund is to be established to support the electrification of rural and other areas considered economically unviable for electrification by public electricity suppliers. According to this new Bill, nothing is mentioned on how the fund shall be run and most importantly who shall be responsible for it. Independent analysts, however, argue that the fund is likely to remain under the control of the Minister of Energy and may be used to advance political objectives rather than developmental objectives. If this fund is introduced, then the new Bill should make it very clear how the fund is to be managed and run so as to avoid problems in the future, such as those that have arisen in the past in relation to other funds in the energy sector. A number of analysts call for control of the fund by all

Stephen Karekezi and Donella Mutiso 117

the key stakeholders in the power sector to ensure impartial management 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 experience to date. A few tentative conclusions and suggestions can, however, be deduced. The first is the need for public awareness and debate to ensure that the power sector reform process is perceived to be participatory, open and transparent. This would minimize accusations of impropriety and garner broader support for power sector reform measures that might be implemented. It is absolutely vital for the government to ensure that consensus within government is reached on how the power sector reform process should evolve. It then needs to convince the general public and civil society of the benefits of power sector reform. Of particular interest to the public is the impact of power reform on electricity prices and on rural electrification. Secondly, the power sector reform process needs to be preceded by detailed assessment of the potential benefits and drawbacks of various power sector reform measures. This assessment should draw on the experience of other developing countries to ensure that full advantage is taken of lessons learned and experience acquired to date. Of particular interest is the impact of power sector reform on low-income households as well as the potential role of local investors in the liberalized power sector. A clear policy and regulatory framework that encourages local private sector participation would mobilize local support for power sector reform and ensure its long-term continuity and sustainability. In addition, careful assessment needs to be made of the costs and the skills and resource requirements associated with the transaction costs of moving to a new power sector structure. Thirdly, the debate on power sector reform should preferably devolve on the best means of ensuring competition rather than simply ensuring private sector participation. The advent of the competitive market is one of the most compelling rationales for power sector reform. Consequently, decision-makers need to assess carefully the various measures and differing strengths of various key actors to maximize competition and ensure a level playing-field for all actors. Of particular importance is the central role of the transmission and dispatch centre in ensuring competition. To date, reforms in Kenya will result in the dominant utility, KPLC, retaining overall control of

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the transmission and dispatch centre. This is likely to stifle competition and substantially reduce the perceived benefits of power sector reform. Fourthly, it appears important to ensure that an independent and fully functional regulatory mechanism is in place before reform is initiated. In Kenya, the establishment of the regulatory mechanism is being considered after substantial reforms have taken place and IPPs are already operational. This could create future legal problems and deter future independent power investors. A competitive multiple-player power market is a complex undertaking and requires a very resourceful and skilled regulatory body to ensure a level playing-field and the right level of co-ordination.

References Beesley, M. and Littlechild, S. (1983). ‘Privatisation, Principles, Problems and Priorities’, in Lloyds Bank Review, United Kingdom. Bhushan, K. (1995). Kenya 1995–96 Factbook: Uhuru 32, 14th Edition, Newspread International, Nairobi, Kenya. Bhushan, K. (1997). Kenya 1997–1998 Factbook, 15th Edition, Newspread International, Nairobi, Kenya. Central Bureau of Statistics (1996). Economic Survey, Ministry of Planning and National 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, Nation Newspapers Ltd, Nairobi, Kenya. Daily Nation (1997b). ‘Japan Grants Kenya Sh 442m’, 16 July, Nation Newspapers Ltd, Nairobi, Kenya. Daily Nation (1997c). ‘Firm to Probe Electricity Deal’, 8 August, Nation Newspapers Ltd, Nairobi, Kenya. Daily Nation (1997d). ‘Bill Favours the Rich – Ndicho’, 19 September, Nation Newspapers Ltd, Nairobi, Kenya. Daily Nation (1997e). ‘Power Deal Firms Mystery’, 10 November, Nation Newspapers Ltd, Nairobi, Kenya. East African Standard (1977a). ‘Power Cuts Cost Bamburi Dearly’, 9 April, The Standard Ltd, Nairobi, Kenya. East African Standard (1977b). ‘Power Sector Bows to Reform’, 6 May, The Standard Ltd, Nairobi, Kenya. East African Standard (1977c) ‘Power Plant to Start Work’, 31 July, The Standard Ltd, 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.

Stephen Karekezi and Donella Mutiso 119 Financial Times (1997). ‘Global Private Power Update’, Issue 97/2, Financial Times 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’, in Proceedings of Symposium on Power Sector Reform and Efficiency Improvement in SubSaharan Africa, World Bank, Washington DC, USA. Indigo Publications (1997a). ‘Indian Ocean Newsletter No. 768’, 7 June, Indigo Publications, Paris, France. Indigo Publications (1997b). ‘Africa Energy and Mining No. 208’, 2 July, Indigo Publications, Paris, France. Institute of Economic Affairs (IEA) (1994). Agenda ‘94: People, Economic Affairs and 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, Zed Books Ltd, London and New Jersey. Kenya Energy Review, The (1990). ‘Earthly Power’, Jan–Feb, The Kenya Energy Review, Kenwide Media Publications, Nairobi, Kenya. Kenya Gazette (1997). Government Printer, January, Nairobi, Kenya Kenya 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 in Kenya’ 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 Kenyan Energy Sector Institutions: Case Studies and Comparative Analysis of Public, Power and Petroleum Sectors and Implications to Energy and Environmental Management. 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 Donors Meeting in Paris, Government Printer, Nairobi, Kenya. September. Republic of Kenya (1995b). Economic Survey – 1997, Ministry of Planning and National Development, Nairobi, Kenya. Republic of Kenya (1997a). Economic Survey – 1997, Ministry of Planning and National Development, Nairobi, Kenya.

120 Experiences in Kenya Republic of Kenya (1997b). Kenya Gazette Supplement No. 61: The Electric Power Bill, Government Printer, Nairobi, Kenya, 25 August. Steyn, G. (1995). ‘Restructuring the South African Electricity Supply Industry: Appropriate governance in a newly democratised South Africa’. Utilities policy, 5(2), 95–108. The East African (1996). ‘Kenya, Uganda Make Peace on Power Rates’, Nation Newspapers Ltd, Nairobi, Kenya. The New Vision (1996a). ‘Uganda, Kenya in Electricity Bargain’, The New Vision Printing 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 on Rural Electrification’, KENGO Regional Wood Energy Programme for Africa, Nairobi, Kenya. World Bank (1997). Energy Sector Reform and Power Development Project, Staff Appraisal Report Kenya, World Bank, Eastern and Southern Africa Department. 21 May.

6 Power Sector Reform Experiences in Zimbabwe Ikhupuleng Dube

Introduction In the majority of SubSaharan countries there are growing concerns about the inability of most electric utilities to deliver a reliable, affordable and widely available service at acceptable levels of financial and technical performance. This has mainly been attributed to poor performance, a low customer base, poor revenue collection, inadequate power pricing-levels and rigid state control. In order to reverse this negative trend most SubSaharan countries have embarked on the restructuring and privatization of the power sector. This privatization trend has not, however, gone unchallenged. Opponents of privatization contend that private ownership does not necessarily translate into efficiency. It is argued that private sector managers have no compunction about adopting profit-making strategies or corporate practices that make services affordable or available to large segments of the population. They point out that in most SubSaharan countries rural electrification rates are very low, and beset by viability problems that arise from low loads and the long sub-transmission and distribution networks that are needed to connect centres remote from the grid. The problem is further compounded by the low incomes that characterize rural areas. Concern is also voiced over the cost-effectiveness of unbundling small systems. Large-scale retrenchments and the resultant socioeconomic problems are stated as a further reason against privatization. The opponents of privatization argue that the key question is not simply whether ownership is private or public, but under what conditions is ownership most likely to act in the public interest. 121

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

The Zimbabwean power system The Zimbabwe Electricity Supply Authority (ZESA) is responsible for the generation, transmission and distribution of electricity in Zimbabwe. The Authority has an installed capacity of 1961 MW. An additional 68 MW is generated on a seasonal basis by privately owned sugar estates for their own consumption (Triangle: 45 MW; Hippo Valley Estates 23 MW). A small private company, Rusitu Power Corporation, operates a 750 kW mini-hydro plant. The system parameters are shown in Table 6.1. Imports account for up to 30 per cent of demand and are supplied by the interconnectors shown in Table 6.2. Transmission and distribution losses are about 4 per cent and 6 per cent of energy supplied respectively. The system peak is 1824 MW.

Table 6.1

ZESA system parameters

a) Generating capacity Power station Hwange Munyati Harare Bulawayo Kariba b) ZESA sales (1997) Customer group Industrial Mining Commercial Farming Domestic ZESA Properties

Type

Installed capacity (MW)

Thermal Thermal Thermal Thermal Hydro

920 120 135 120 666

Number of customers

Sales (GWh)

Per cent share

1887 693 358 935 10 51 38 405 295

3951.82 1579.10 1385.87 690.48 1734.23 23.37

42.2 16.7 14.8 7.4 18.5 0.3

Ikhupuleng Dube 123 Table 6.2

Zimbabwe interconnection

Country

Voltage level kV

Zambia/Zaire South Africa (Matimba) South Africa (Messina) Mozambique (Chikamba) Mozambique (Cabora Bassa) Botswana

2 × 330 1 × 420 1 × 132 1 × 110 1 × 420 1 × 220

Power sector regulatory and institutional framework The Zimbabwe Electricity Supply Authority (ZESA) was formed by the Electricity Act (1985) following the amalgamation of the previous electric utility companies, namely the Central African Power Corporation (CAPCO), the municipalities of Harare, Bulawayo, Gweru and Mutare and the Electricity Supply Commission (ESC). Only the Central African Power Corporation (CAPCO) was responsible for generation and transmission in Zambia and Zimbabwe, while the others were responsible for transmission and distribution within their respective licensed areas in Zimbabwe. In 1985 a new Act was enacted establishing a corporate body, the Zimbabwe Electricity Supply Authority (ZESA). The regulation of ZESA falls under the Ministry of Transport and Energy (MTE). The executing arm of the MTE is the Department of Energy (DOE). Of the DOE sections, the Economics and Planning Section is responsible for regulating and supervising the utility. The main functions of the section are: • developing and assessing electricity sector policy and ensuring that it 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

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necessary to do so, but not less than six times a year. The board gives the minister all required information relating to the undertakings of the Authority and any reports it deems fit. The Minister may bring any such report before the House of Assembly. After consultation with the board the Minister may give it any directions that appear to be required in the national interest. The board may establish committees and divest any of its functions it sees fit. The term of the board is stipulated at three years but the members may be reappointed after the expiry of the three-year term at the discretion of the minister. The day-to-day operation of ZESA is the responsibility of the chief executive and associated subordinates (directors) each of whom is in charge of a department. The departments are Generation, Consumer Services, Technical Services, Finance, Corporate Services and Transmission. The planning, audit and public relations functions are directly responsible to the chief executive’s office with the functions of planning being executed by a senior manager. The chief executive, who is appointed by the Minister, forms the executive management committee together with the heads of departments. This is then responsible for the day-to-day operations of the Authority. Corporate policy issues are the responsibility of the board. Such issues are referred to the board by the Executive Management Committee. In terms of the Electricity Act (1985), ZESA’s functions are: – To acquire, generate, transmit, distribute and supply electricity in Zimbabwe; – To investigate new or additional facilities for the generation; transmission, distribution or supply of electricity, and to advise the minister 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 supplied and rentals of meters and other equipment; – The making of additional charges or the payment of interest in respect of overdue accounts; – The fees chargeable by the Authority for services incidental to the transmission, distribution or supply of electricity; – The disconnection of electricity supply for non-payment; – Acquisition of land for electricity supply purposes.

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The legal framework also deals with issues pertaining to pricing and investment. ZESA is required to ensure an annual income sufficient to enable it to meet its obligations and conduct business along sound commercial lines. Monies not immediately required by the Authority may be invested in such a manner as the Minister and Ministry of Finance may deem fit. The Authority is further required to establish a general reserve that may be appropriated from a surplus of income at the end of the financial year. Such funds may be used for meeting any deficiency that the Authority may incur and may be used, with the approval of the Minister, for such purposes as the board may consider expedient for the proper exercise of the Authority’s functions, including the development of its assets. The Act stipulates that the board will comply with any directions that the Minister may give in relation to the management of the general reserve. The utility is also required to establish a capital development fund to finance the capital expenditure of the Authority in creating and replacing capital assets. Presently ZESA is charging a 5 per cent levy on sales plus an additional 1 per cent levy on revenue for rural electrification. The Electricity Act also defines the conditions for provision of power by private undertakers. Private operators who obtain the prior consent of the Minister and the Authority may transmit, distribute or supply electricity to any other person provided that such permission and conditions have been granted and that the size of the plant is above 100KW. In this case ZESA will be the regulator. Private undertakers with a capacity rating of less than 100 kVA can operate without Ministerial licensing. At present the only private undertakers in operation are the sugar plantations, which generate about 37 MW for consumption during the milling season, and the mini-hydro at Rusitu which has an installed capacity of 750 kW. This plant sells its electricity to ZESA. Another Act with an impact on the regulation of the power sector is the Audit and Exchequer Act. Section 33 of the Act prevents parastatals, ZESA included, from making payments or expenditure without the approval of the responsible Minister. The Section states that: subject to the provisions of this Act, no designated corporate body shall commit itself to or incur: –

Any capital expenditure unless provision therefore has been made in a capital budget or supplementary capital budget approved in terms of this part or such expenditure has been approved by the appropriate minister;

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–

Expenditure other than capital expenditure unless provision therefore has been made in a revenue and expenditure budget approved in terms of this part or such expenditure has been approved by the appropriate Minister.

In terms of Section 34 of the same Act ZESA is required to prepare and submit capital, revenue and expenditure budgets to the Minister for approval, before the beginning of the financial year. The monitoring of this requirement is a shared responsibility between the Ministry of Finance and the National Economic Planning Commission in the President’s Office. Furthermore it is responsible for the para-statal reforms and reviews tariff proposals before approval by Cabinet. It also reviews the capital budget and project proposals as well as being represented on the Government Tender Board (GTB) which is responsible for decisions related to procurement by government departments and para-statals. Decisions on electricity pricing are carried out by the Cabinet Committee on Development on the advice of the line ministries and the National Economic Planning Commission. The Cabinet Committee on Development is a committee comprising the Ministers of Industry and 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 on Development on an ad hoc basis. The Cabinet Committee on Development considers issues referred to it by the Working Party Officials on the advice of the sector Ministers. It is therefore noted that the regulatory responsibility is shared between the Authority and the Minister. The fact that the Minister has overall control makes it difficult for the Board and management to make decisions, which are results-driven but do not have ministerial approval. The Minister regulates such power sector issues as investments, disposal of fixed assets, borrowing and staff conditions of service, and provides general directions relating to the performance of the Authority’s functions. Strengths of the existing legal framework The major strengths of the Electricity Act 1985 have been the adoption of a uniform national tariff system and a streamlined management structure for the electricity sector. Prior to the formation of ZESA there were over 40 different electricity tariff classes in Zimbabwe which were extremely complex to co-ordinate and regulate.

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Differences existed between utilities. Harare municipality tariffs were based on long-run marginal-cost pricing whereas tariffs for the other utilities were based on average cost studies. These are studies in which the unit costs represent the average cost to serve all consumers within a class of service and in which the rate of return is based on historical costs. A post-amalgamation study carried out in 1987 by consultants Merz and McLellan recommended a unified tariff structure consisting of seven tariff classes. The simplified tariffs were implemented effective 1987. The Act also reduced the number of general managers from five to one, so that the ZESA management structure was smaller than those of the former utilities combined. This was important since there was a shortage of technical personnel in the country at the time of amalgamation. The new structure made it possible to maintain fairly reasonable technical performance standards at prices which in real terms are lower than those that were prevailing in the mid 1980s just before the enactment of the Act. This has a direct benefit of the economies of scale achieved by the amalgamation. A major advantage of the change was the potential efficiency gains with respect to investment in major generation and transmission facilities. The nation was afforded the opportunity to build larger plants, which are more cost-effective to run than the equivalent number of small plants. The power sector in Zimbabwe is in need of large capital investments to meet demand and small fragmented undertakings would have been difficult to fund. This problem is compounded by the small size of the Zimbabwe power system and limited investment opportunities in the form of developments in Hwange, Sengwa and Batoka. Another benefit relates to customs and excise duties. Customs regulations provide a facility that allows para-statals to import capital goods for projects that are accorded national duty free status. As a result of the facility ZESA has been able to save over US$60 million in the last two years, in the form of duties for imports of capital goods for Matimba Interconnector and other distribution projects. Weaknesses of the present framework The present framework also possesses certain weaknesses. Critical to the successful management of any business is the management and technical competency of the staff, the clarity of performance objectives, the transparency of the performance measurement process, and the defence of autonomy.

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Unfortunately, these are the areas where the existing legal framework has been least successful. As indicated above, almost every major operational decision requires the consent of the Minister acting alone or in consultation with the Minister of Finance. This lengthens the decisionmaking process on critical planning and operational issues affecting budgets, electricity prices, recruitment and conditions of service of senior management, customer relations and investment in major plant and facilities. Unlike ZESA, the ministry does not have the necessary expertise to make sound decisions on the operations of the electricity industry. The section that deals with the power sector has a staff complement of five, with not even a single power systems engineer. The current competitive industrial environment dictates that reasoned decisions have to be made expeditiously as any delays will increase costs and cause shortages or loss of the organization’s comparative advantage. Due to lack of autonomy the Authority has suffered from a high turnover (–1.5 per cent from a total staff of 8000 in 1993) of skilled managers, engineers, accountants, economists and other professionals. Poor management control systems, unclear strategic direction, poor communications and customer relations were the inevitable result prior to the implementation of the Performance Improvement Programme (PIP), which will be discussed later. To remove these bottlenecks and improve the performance of the industry, ZESA and the government are working on a new framework that will be more result-oriented than the present Act.

Reasons for power sector reforms Four main reasons have triggered power and other sector reforms in Zimbabwe. 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, Zimbabwe followed a social-political path that resulted in significant progress in terms of human resources and infrastructure development. For

Ikhupuleng Dube 129

example, enrolments at primary education level rose from 1.2 million children in 1980 to 2.2 million in 1989, while those at secondary level rose from 74 000 to 671 000 during the same period. In the health sector the percentage of children fully immunized rose from 25 per cent to 86 per cent and the infant mortality rate declined from 86 to 61 per 1000 births. Life expectancy increased from 55 to 59 years and fertility declined, resulting in a decrease in population growth from 3 per cent to 2.8 per cent. Agriculture, the mainstay of the economy, saw a redirection of credit facilities as well as extension and marketing services. Coupled with the maintenance of appropriate producer prices, these measures led to an increase in marketed output of small farmers, whose share of marketed maize (Zimbabwe’s staple food) rose from zero in 1980 to more than 70 per cent in 1989. Towards the end of the decade, however, the economy was threatened by deepening cycles of low investment, a growing budget deficit, rising unemployment, inflation and economic stagnation. Growth in Gross Domestic Product (GDP) during 1980–9 (2.7 per cent per annum) lagged behind population growth. A disproportionate share of this growth was in the provision of social services and public administration. Export growth increased by only 3.4 per cent per annum in real terms between 1980 and 1986. This poor performance, combined with debt service payment, which rose to a peak of 34 per cent of export earnings in 1987, severely constrained the growth of imports resulting in a 0.4 per cent growth in real terms between 1980 and 1988. The net result was the constrained utilization of existing capacity as well as investment in new production capability. This resulted in unemployment as high as 26 per cent in 1989. There are now between 200 000 and 300 000 school-leavers each year, but only 20 000–30 000 new jobs are being created in the formal sector, with the bulk of additional employment being in the government sector, particularly education, health and public administration. The government’s fiscal deficit was in excess of 10 per cent of GDP during much of the 1980s and this led to a central government debt of 71 per cent of GDP by 1989. Thirty-six per cent of this debt was external. The government engaged in massive public and external borrowing, resulting in interest payments of 6.7 per cent of GDP in the 1989/90 financial year. Inflation, which was less than 12 per cent throughout 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 interest rate of above 30 per cent, further constraining investment.

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It was against this background that the government launched the Economic Structural Adjustment Programme (ESAP) in October 1990. The principal objective of the programme was to generate a higher rate of economic growth, to expand employment opportunities and raise the standard of living. The specific objectives of the programme were: – Reduction of the external government deficit from 10–5 per cent of GDP by 1994–5; – Reform of public enterprises to eliminate the large budgetary burden caused by subsidies, by making the enterprises operationally efficient and more commercially oriented; – Civil service reform to reduce the wage bill and the number of civil servants; – Monetary policy and financial sector reform, to strengthen monetary management, slow credit creation, reduce inflationary pressures, liberalize the operations of the financial sector, encourage savings and to improve the efficiency of inter mediation activities; – Trade and exchange market liberalization to create a market-based foreign exchange system and to shift to a tariff-based system of protection; – Domestic deregulation and investment promotion, to liberalize investment and deregulate prices; – Implementation of social dimensions of adjustment programmes to protect the poor and vulnerable groups from negative transitional effects of economic reforms. There has been some progress in the implementation of some key elements of the programme, especially in economic and financial liberalization, deregulation of foreign investment and reform of the trade and exchange regimes. However, the benefits of the gains were overshadowed by the effects of severe droughts, deterioration in the country’s terms 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 a major source of monetary expansion during the programme and largely accounted for the persistence of inflationary pressures in the economy. Inflation peaked at around 42 per cent at the height of the drought in 1992 before gradually declining to levels of around 16 per cent in February 1997. Given the persistent expansionary fiscal policies, monetary policy bore the main burden of maintaining macroeconomic stability. As a consequence of the tight monetary poli-

Ikhupuleng Dube 131

cies, interest rates rose to unprecedented levels (in excess of 40 per cent in 1992). Although the interest rates have fallen in response to the decline in inflation and are currently around 25 per cent, they continue to act as a major barrier to business expansion. Public enterprise reforms were aimed at reducing the level of direct subsidies from Z$629 million in 1990 to a maximum of Z$40 million by 1994/95. However, the above targets have not been met. To date, progress has mainly consisted of the introduction of financial measures in the form of tariff increases and price adjustments to reduce operating losses. However, the point is being reached where such increases are constraining growth and affecting the competitive position of the country’s economy. Para-statals need to move away from price increases and be forced to pursue greater internal efficiency in order to enable them to maintain a degree of price stability. Even though the government established a Cabinet Committee on commercialization and privatization in 1994, little progress has been made on this front. The poor performance was caused by factors such as inefficiency, ineffectiveness, lack of accountability, conflict of objectives and lack of operational autonomy. Therefore the main reason for embarking on reforms of public enterprises was to address the considerable adverse impact of the para-statals on the finances of the country. The total para-statal losses amounted to Z$6.5 billion over the last five years. The government has had to absorb these losses since it is the sole owner of the state enterprises. In addition, some of these enterprises have failed to honour their government guaranteed loans, resulting in an additional burden of about Z$2 billion over the last five years. So far the government has commercialized and privatized the Grain Marketing Board (GMB), Cotton Marketing Board (CMB), Cold Storage Commission (CSC) and Dairy Marketing Board (DMB) through floatation of public shares and forcing them to operate under the Companies Act. In order to accelerate the commercialization and privatization process government took over debts of the GMB, CMB, and CSC totalling Z$4 billion to enable them to start on a clean state. Already these three state enterprises have started recording profits. In the last fiscal year CMB posted an after-tax profit of Z$30.9 million. After-tax profits for CSC and GMB were Z$50 million. Furthermore, these enterprises are now required to pay tax and remit 50 per cent of their aftertax profits as dividend. It can thus be concluded that privatization is desirable to promote sectoral efficiency and competitiveness. To further enhance the gains of the first phase of the economic reforms and to meet the missed targets, the government unveiled the

132 Experiences in Zimbabwe

second phase of the economic reforms, the Zimbabwe Programme for Economic and Social Transformation (ZIMPREST) which foresees acceleration of the privatization process. Restructuring para-statals to empower historically marginalized groups For decades the majority of Zimbabweans were precluded from any meaningful participation in the economy due to the legacies of the United Declaration of Independence (UDI), implemented in 1965 by the ruling minority government of Ian Douglas Smith. The cornerstone of the policies of UDI were the disfranchisement and racial segregation of the black majority. This prompted the United Nations to impose sanctions against what was then Rhodesia. A war of liberation brought about independence in 1980 following the Lancaster House Agreement. The UDI prevented the majority of Zimbabweans from participating in the economy. An economy cannot thrive unless a significant portion of the population participates in it, in capacities other 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, the remaining white farmers continue to own and occupy 95 per cent of all the prime agricultural land, while black farmers are left with barren areas and regions of low potential. Also, of the 63 companies quoted on the Zimbabwe Stock Exchange, only 9 have a black board chairman and only 8 have black chief executives. This is the case in a country of 11 million blacks and 70 000 whites. It is against this background that, with the adoption of the economic reforms in 1990, the indigenous business community started agitating for a parallel economic empowerment programme. This was expected to level the playing-field between black and white business people, as well as creating economic opportunities for the marginalized indigenous population. Local indigenous organizations such as the Indigenous Business Development Centre (IBDC), Affirmative Action Group (AAG) and the Indigenous Business Women’s Organization (IBWO) maintain that very little has been achieved in terms of widening the economic base to accommodate new players. The World Bank has noted that the policy environment continued to favour existing enterprises until the 1990s. This prompted the government to accept the policy of indigenization.

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In spite of the government’s efforts, barriers still prevent most Zimbabweans from actively participating in the national economy: – Lack of access to adequate finance (current finance schemes set aside by government, of the order of Z$500 million, have provided only up to Z$400 000 for each project, where serious entry into any meaningful venture requires an average Z$2.5 million); – Lack of entrepreneurial awareness and know-how and lack of managerial skills among the indigenous people; – Limited access to industrial and commercial land and infrastructure in urban areas that favours the existing enterprises. – Excessive reliance on foreign expertise; a hostile environment and racist atitudes prevalent in the established business sector. – Inadequate land and infrastructural development in rural areas. After accepting the policy of indigenization, the government announced that an indigenization programme had taken so long to adopt because its focus at the time of independence had been on the provision of education, health, security and general administration, with limited resources. The government’s view is that the above priorities were meant to address the issues as they affected the majority, whilst affirmative action involves giving power to individuals as opposed to the majority of people. Economic reforms, competition and the dismantling of para-statals has benefited the majority of people, and the same majority should benefit from the proceeds of privatization. The government has already initiated processes to pave the way for the participation of the majority in the economy so as to foster economic development and create employment. A policy document on the issue, has been released sometime this year. In its July 1996 budget the government announced the creation of a National Investment Trust Fund (NIT), with an initial provision of Z$200 million. Further funding is to flow into the Trust from the proceeds of future privatization. In announcing the fund, the government propounded a basis for privatization 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 indigenous people who wish to participate in the economy. The government has stated that privatization forms part of a policy of creating a united nation with all people having equal opportunities and therefore the purchasers of para-statals must be indigenous people.

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Restructuring to enhance power sector efficiency As highlighted by the following indicators (Table 6.3), the financial performance of ZESA worsened in the face of increasing inflation, devaluation of the Zimbabwean dollar, high interest rates and declining real electricity prices. The drought of 1991–2 had a particularly devastating impact on ZESA’s operational performance. As a result only 8682 GWh of total energy could be supplied, compared with a demand of 10 264 GWh. This represented a 15.4 per cent drop in supply availability. ZESA was forced to introduce a combination of load-shedding and tariff-based rationing in order to curtail demand. Corrective action was constrained by a number of factors. The price controls that used to be a factor of the country’s macroeconomic policies made it difficult, if not impossible, to maintain prices that reflected the cost of supply. Shortages of foreign currency were also endemic. Restricted autonomy on personnel management policies resulted in continual loss of technical and managerial staff. The breakdown in management control and the technical reliability of the electricity supply service was inevitable. The government commissioned several committees of inquiry in an attempt to arrest the downward trend. Such inquiries were also made into the operations of the other para-statals resulting in the adoption of a general public enterprise 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 to raise private sector finance for development aimed at meeting future Table 6.3

ZESA financial indicators

Debt service ratio Interest cover ratio Self financing ratio ( per cent) Return of fixed assets (per cent) Borrowing as per cent of annual investment Average tariff – Zc/kWh USc/KWh Source: ZESA Annual Reports.

1986/87

1992/93

0.82 2.18 26 16.9

0.54 0.82 65 11.3

47 4.59 2.76

21 20.5 2.40

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demand. The future electrical energy consumption in Zimbabwe will depend 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 a bearing on power demand. The envisaged economic scenarios are as follows: Low case scenario This scenario assumes a recurrence of erratic weather pattern, weak export prices of primary commodities and growth in international protectionism. With economic reforms assumed to fail, the economy would experience a higher rate of inflation and low levels of investment. As a result of trade liberalization more industries will close under competition from imported goods. GDP will rise at 2.5 per cent per year with the resultant increase in energy averaging 2 per cent. Base case scenario According to this scenario the reforms are expected to succeed, with GDP rising at an average of 5 per cent per year and a resultant energy demand of 4.5 per cent. Regional trade will increase. The fluctuations in export commodity prices would continue and the international competitiveness of Zimbabwean exports is assumed to be maintained by continued moderate depreciation of the Zimbabwean dollar. Under this scenario, weather is expected to be favourable so that the nation 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 no adverse foreign debt service ratio, however, some major borrowing for capital projects could be discouraged. High case scenario This scenario assumes a GDP increase of about 7.5 per cent per year following favourable changes in world politics as well as economic policies that result in increased flow of financial assistance to the third world, including Zimbabwe. In this scenario the reforms are expected to achieve overwhelming success resulting in increases in investment and export performance. The problems of unemployment, underutilization of capacity and shortages of raw materials will be over. Energy growth is expected to be 6 per cent. To meet the load growth the following planning criteria have been adopted by ZESA and the government: – 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 generation shall have capacity equal to or greater than the demand; – Imports may exceed the 20 per cent limit as long as the second criteria is met and the sources of energy are significantly diversified with respect to both technology and geography and are costeffective relative to local options. Taking into consideration the above planning criteria and the need to meet the expected deficit the following plans are expected to be implemented (Table 6.4). If ZESA was to build, own and operate Hwange 7 and 8, Batoka and Sengwa and extend the present Kariba South Power Station it would need to raise about US$4.6 billion over the next few years. This comes at a time of significant worldwide demand for infrastructure projects. The developing countries of Latin America and East Asia, eager to build their market economies, need about US$140 billion per annum whilst the requirements of the former nations of Eastern and Central Europe have been estimated at US$500 billion. The financial options available to Zimbabwe 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 the loans or borrowing on their own account, since they are the most

Ikhupuleng Dube 137 Table 6.4

Level of investment required to meet zimbabwe’s power needs

Project

Local Foreign cost cost (US$ Mn) (US$ Mn)

Year

Old thermal refurbishment Kariba South upgrade Hwange upgrade Matimba interconnector Cabora Bassa interconnector Hwange extension

3848 2689 25 640 8147 5546 264 000

24 271 35 947 104 380 33 592 30 742 396 000

Batoka Gorge Kariba South extension Sengwa

256 340 80 395

844 456 20 593

Completed In progress In progress Completed In Progress 1st Unit 2001 2nd Unit 2003 2010 1998

308 352

462 520

2004

TOTAL

954 956

3 642 490

Total cost (US$ Mn) 28 059 38 636 130 020 41 739 36 288 660 000

1 100 796 200 988 770 880 4597 446

Source: ZESA System Development Plan (1995).

credit-worthy entities. At present, developing countries spend about US$210 billion on infrastructure investment. Approximately 90 per cent of this figure is derived from tax revenue or intermediated by government. Debt capital can be sourced in many forms either as bank loans, institutional debt, bonds, project finance or export credits. A combination of export credit and bank loans is widely used for funding infrastructure in developing countries because it helps the country sponsoring the project to develop its economy, and benefits the countries supporting the project by providing a market for their exports. Another factor that makes this funding structure attractive is the pooling of resources and sharing of risks across nations. It would be very difficult, for example, for ZESA to find one country or bank that is willing to provide the whole US$660 million required for the expansion of Hwange. The basic principle is tied equipment purchase. Contractors winning the tenders must have a financing package that is normally provided by a bank based in the contractor’s home country.

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All major power sector projects in Zimbabwe have been largely funded from debt capital. The construction of Kariba Dam and the South Bank Power Station in the 1950s were funded from loans of GBP15 million from the Commonwealth Development Corporation and US$7.7 million from the World Bank. Domestic loans were also provided by both the Zambian and Zimbabwean governments. The present Hwange Power Station was also funded by debt capital consisting of commercial bank loans of US$210 million, export credit and syndicated bank loans of US$275 million and multilateral agency loans of US$150 million. However, as already outlined, the fiscal constraints of the government impose limits on what it can borrow or broker for the power sector in Zimbabwe. This makes it imperative for the government to turn to the private sector for power sector investment. Table 6.5 summarizes Zimbabwe’s outstanding external debt according to source. It can be noted from the table that Zimbabwe’s external debt, including sovereign guarantees, is very high as a percentage of GDP (generally above 65 per cent). This fact, combined with missed deficits targets at home will limit the government’s ability to borrow or broker funds for the power sector in Zimbabwe.

Table 6.5

Zimbabwe: outstanding debt by source

Total outstanding debt 1. Total and publicly guaranteed A. Public and publicly guaranteed – Bilateral – Multilateral – Private creditors – Commercial B. Private non-guaranteed – Commercial

1992 Z$ 000

1993 Z$ 000

1994 Z$ 000

1995 Z$ 000

20 901.9 18 285.6 16 709.7 – 4 867.5 5 829.3 6 012.9

28 596.7 25 769.6 23 515.8 – 6 691.6 9 601.1 7 222.6

37 483.9 33 477.8 30 785.0 – 8 813.4 13 422.5 8 549.1

38 996.8 35 701.3 32 600.1 – 9 820.4 14 694.6 8 585.2

4 314.6 1 575.9 1 575.9

5 146.8 2 253.8 2 253.8

6 195.0 2 692.8 2 692.8

6 337.5 3 101.2 3 101.2 3 295.5

2. Short-term

2 616.3

2 827.1

4 006.1

A. Public and publicly guaranteed

2 187.9

21 187.9

1 445.5

428.4

639.2

2 560.6

B. Private non-guaranteed

Source: Reserve Bank of Zimbabwe September 1996 Quarterly Report.

– 3 295.5

Ikhupuleng Dube 139

Internal cash generation. Internal cash generation represents the profits of an organization in new investments. It is thus a function of an organization’s profitability and ultimately of its sales and pricing policies. If sales can be expanded without a corresponding increase in costs, more cash will be generated internally, and if there is scope to increase tariffs on sales to the existing base of customers without demand falling in response, then more cash will be generated. In the late 1980s and early 1990s ZESA was obliged by some of its lenders to generate funds equal to 40 per cent of the average capital expenditure for three years from internal sources. This proved to be unattainable, given government control on tariffs. A revised rate of 25 per cent was then negotiated. At an internal cash generation rate of 25 per cent ZESA would have to raise US$685 million from its own sources over the next 15 years for development projects in the power sector. In real terms this calls for doubling of tariffs over the next 20 years. This would impact negatively on the customer’s ability to pay and also on projected sales. Table 6.6 below shows the average share of electricity of total production costs. The share of electricity appears to be quite high, so that any future tariff increases that exceed the Consumer Price Index (CPI) inflation rate will worsen the customer’s plight. Should tariff increases exceed the CPI, there is a likelihood of a fall in the demand and utilization of electricity. Such a fall in demand could affect the financial situation of ZESA and its capacity to raise the capital needed for expansion from its own sources alone, thereby requiring private investment to meet future power requirements. Equity capital. Equity capital is attractive to an organization because during lean periods dividends, unlike interest charges, can be passed

Table 6.6

Share of electricity costs as compared to total production costs

Customer category Domestic Industrial Mining Commercial Farming Source: ZESA Load Forecast 1996.

Per cent share of electricity 12 15 16 17 20

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on and the providers of equity capital are attracted by either the upside potential of a project and/or the upside potential of the organization sponsoring the project. The scope of ZESA to raise equity capital on the local financial market is very narrow given the limited size of the market. In 1994 US$125 million were raised on the Zimbabwe Stock Exchange, with half of the amount coming from foreign investors. It is estimated that about US$225 million is available annually on the Zimbabwe money and capital market. The government absorbs about US$150 million through its stock issues. This leaves US$75 million for the private sector and para-statals. This net figure is very small in comparison to the cost of the projects being planned by ZESA. The private sector alone is estimated to require about US$250 million per annum for its investment programmes. Access to private capital. A small financial market is not unique to Zimbabwe. It is a common feature of almost all developing countries. Large private utilities in developing countries are beginning to raise equity capital from international financial markets as shown in Table 6.7. ZESA’s planned projects are likely to make a huge dent in the nation’s material and financial resources (such as foreign exchange) and might even crowd out planned development projects in other sectors. This will certainly affect other sectors adversely. Furthermore, if traditional sources are used, the levels of ZESA’s external debt service requirements will be very high from now onwards, with a peak of 69.4 per cent of forecast national debt service in 2004. This is a frighteningly high level. ZESA’s external debt service peaked at 26.2 per cent of the national debt service and contributed significantly to the debt service hump. The current view in economic circles is that Zimbabwe is moving into a debt trap.

Table 6.7 Net inflows of long-term private capital in developing countries (US$ billion)

Foreign direct investment Debt capital Foreign equity securities Source: World Bank.

1990

1991

1992

26.3 5.56 3.78

36.9 12.72 7.55

47.30 23.73 13.07

Ikhupuleng Dube 141

Reform strategy The reform strategy envisaged for the power sector involves two major components: (a) corporate restructuring of ZESA and (b) opening up the generation segment of the industry to independent generators, together with equity participation in the existing and future generation plants. Corporate restructuring The turning point for ZESA was the board’s adoption of a financial recovery plan in the 1991/92 fiscal year. The plan comprised both revenue maximization and loss minimization strategies. Revenue strategies consisted of a programme of tariff adjustments and an accelerated takeover of the revenue collection functions that used to be performed by the cities of Harare, Bulawayo, Gweru and Mutare on behalf of ZESA. Cost-minimization strategies included minimization of expensive local borrowings, organizational and management restructuring and the implementation of the performance improvement programme (PIP) developed with the assistance of Eletricité de France (EDF). The PIP consists of a set of simple, easily maintained targets that were tied to the new management contracts covering finance, customer services and management, the distribution, generation and transmission plants and systems, other technical services and human resources management. Government support for this recovery has resulted in the Authority reversing the past trend of losses and achieving positive net surpluses. The ultimate result of the PIP was the adoption by ZESA of the Corporate Business Plan (CBP). The CBP was a result of a corporate-wide process. It began with an executive management workshop that formulated the strategic issues and objectives of the plan based on the general principles and a vision of ZESA defined by the government. The Board and chief executive strategic planning workshops were subsequently held at an operational level to determine how the different departmental units would contribute to the achievement of corporate objectives. The starting point of the CBP was to define a Corporate Mission that captures the direction defined by the Board and the government. This was done through a brief statement that not only captures ZESA’s role but also serves to energize and focus employees on how to fulfil their roles efficiently and effectively. The following mission statement was adopted: ‘We are committed to the total electrification of Zimbabwe at world class standards and competitive prices.’

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Of note are the cultural and ethical standards that are implicit in the mission statement which include teamwork (‘We’), commitment, national service, customer service, social responsibility, efficiency and excellence. To achieve the overall aim the corporate business plan implied: • Technical and management skills to be attracted and retained through the creation of an appropriate working environment. This has been created by improvements in training opportunities and salary and benefit levels that are comparable to the private sector. • Achievement of electricity for all in the first half of the twenty-first century by endeavouring to meet demand at competitive prices. This has culminated in the electrification programme of low-income energy groups and rural areas through strategies that are outlined below. • Attraction of investment in the electricity sector by becoming one of the ‘blue chip’ corporations in the region. This is being achieved through the entry of IPPs into the power sector as well as the envisaged changes in the ownership structure. • Achievement of management autonomy through execution of responsibility with accountability. The CBP also defined the critical success factors. These can be summarized as follows: 1. Customer Service Quality • reaction time to faults • reliability 2. Price • cost reflective • affordable 3. Staff Competence 4. 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 people who need electricity and are prepared to pay for that service;

Ikhupuleng Dube 143

ii) Shareholders: these are those who have invested to create the organization, which serves the customer’s needs; iii) Staff: the plan acknowledges the role of staff, especially their ability to use properly the resources provided by the shareholders in order to serve the customers; iv) Government: this is the custodian of the public interest. The government provides the regulatory framework to ensure that the business of ZESA is performed in a manner that is consistent with the expectations of the general public; v) Supplier: the providers of finance, goods and services are partners to the success of ZESA’s business; vi) General Public: ZESA owes it to the community to provide a safe and environmentally friendly service; vii) Consumers: ZESA owes it to all its users to maintain high standards of safety in all its operations. The strategic issues and objectives defined by the CBP are summarized in Table 6.8. To help monitor progress towards achieving these goals, an operational plan was created. This lays out activities that have to be

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 To create an image befitting the status of a world class utility To provide for decision-making authority which is commensurate with the level of responsibility. Internal – decentralization and delegation of power and authority: Externally – gained increased managerial autonomy from the shareholder in line with generally accepted business practice To work towards maximum customer satisfaction To provide electricity for all within the first half of the 21st century To create a working environment where staff learn and develop To transform ZESA into a blue chip company To provide adequate and reliable plant capacity to meet demand at a competitive price

Corporate image Autonomy

Customer focus Growth Human resources Financial management Plant capacity

Source: ZESA Corporate Business Plan.

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achieved to meet the strategic objectives detailed in the plan. The remuneration and benefits of senior management are tied to the achievement of these goals. The performance improvement plan has resulted in ownership/management changes in the form of performance contracts that have seen a marked improvement in the Authority’s operations. The second form of the ownership/management changes will involve management contracts and the disposal of non-core activities. The utility has already undergone departmental restructuring to prepare it for this process. Management contracts are legally binding contracts between the government and a qualified firm. Two criteria must be met for a contractual arrangement to be characterized as a management contract: – Management of the enterprise is transferred to a contractor who is different from the owner; – the expectations of the two parties are defined in explicit contracts; As is the case in commercialization, the contract includes performance indicators, targets, structure of compensation and responsibility for investment. That means that the utility can operate more autonomously and on a commercial basis. Private sector participation Independent power producers The inability of ZESA and the government to raise capital from the non-traditional sources described earlier led the government to open the power sector to private sector participation, particularly by foreign investors. Sugar estates in the Lowveld have always generated electricity for their own consumption. Initially they supplied the grid at an agreed tariff level, but this was discontinued because of the increase in demand. Rusitu Hydro, a mini-hydro plant (750 kW) constructed and operated by private entrepreneurs, is selling power to ZESA at an agreed tariff. The agreement between ZESA and Rusitu Power Corporation (RPC) foresees RPC supplying power to ZESA for a period of 20 years. Thereafter the agreement will be renewed on annual basis. The agreement can be terminated if the supplier fails to generate for 24 consecutive months. After 10 years ZESA may purchase the plants at an amount equal to their residual value. The operational procedures agreed upon are no different from the procedures followed for ZESA’s own generators.

Ikhupuleng Dube 145

Plans have also been unveiled in 1997 for the building of the largest power station in Zimbabwe as an IPP. The plant, to be developed at Gokwe North (Sengwa), would cost US$1.4 billion. A letter of intent to undertake a detailed feasibility study was issued in April to the project sponsors, National Power, ZESA and Rio Tinto. The study was completed in September 1997 and was subsequently approved by ZESA. Its findings 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 to be commissioned at a later date. The government approved the project in December 1997. The power station project would be developed by a team of people from National Power, ZESA and Rio Tinto, who would form the Gokwe North Project Development Group, with National Power taking the leading role. The project was to be developed as private sector project using an open book approach. Most of the agreement would be negotiated by this development vehicle with the exception of the Power Purchase Agreement, the Fuel Supply and the Operations and Maintenance Agreements. ZESA’s main role will be the negotiation of the Power Purchase Agreement 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 USc per kWh. It is foreseen that the actual return will be lower than this. A fuel supply agreement will be negotiated with Rio Tinto. The feasibility study assumed US$14.00 per ton. It is also proposed that the operating and maintenance arrangement for Gokwe North will be contracted 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’s share 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 of shares to the indigenous community. The project displaces the controversial YTL – ZESA deal that had been widely criticised. Regulatory issues To meet the reforms and privatization goals the new legal and regulatory framework should be transparent and customer-oriented and provide for prices that are both affordable and competitive. This is best achieved by: – Changing the status of ZESA from para-statal to a company operating within the Companies Act 1985.

146 Experiences in Zimbabwe

– Change the Electricity Act 1985 from an Act that is non-transparent and is prone to intervention to an Act that is results-oriented, so as to create a business culture and accountability that is lacking in a para-statal set-up. – Create an office of the regulator to control the transmission network and the dispatch centre, and to be responsible for least-cost planning, setting of standards and customer protection. – As far as distribution is concerned, a mechanism should be instituted to allow the large customers fed by the 132 and 88 kV networks (approximately 40 per cent of demand) to buy directly from generators. For other customers there is a need for regional undertakings to plan and purchase their own requirements directly from the generators through a bulk supply tariff. – Allow independent power producers who enter the sector by competing for investment in new generation capacity to be defined in the least-cost system development plan. Such entrance must be through a transparent bidding system.

Other relevant issues Role of demand side management Faced with overstated forecasts, many utilities in the region have sought bilateral financing tied to restructuring without necessarily exploiting other cost-effective solutions. They have embarked on massive investment programmes that have had negative impacts on their economies. Demand side management (DSM) can also be utilized as an alternative investment measure that can attract private investment. Experience from other international utilities has shown that when 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 an annual basis. If energy efficiency were to be taken seriously it would displace or delay the construction of additional capacity. This has important implications nationwide, in that it frees scarce resources that can then be applied elsewhere. DSM should therefore not be viewed separately from other energy supply options. In terms of costs,

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energy efficiency can offer cheaper alternatives to building additional capacity. Take the case of solar water heaters. It is estimated that solar water heaters can supply energy at US$400 per kW compared to US$2000 per kW for a thermal power plant. The added advantage is that 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 of the households in Harare to over 99 per cent in smaller towns. Although most customer have access to low-voltage service lines, there is a significant proportion that still do not use electricity for their dayto-day energy requirements. This is mainly due to high internal wiring costs and the unaffordability of the monthly electrical bills. The cost of internal wiring is on average Z$6000. A significant number of customers in un-electrified houses cannot afford this amount. To solve the problem of low electrification ZESA has introduced the concept of the Compact Distribution Board (CDB). These are distribution boxes that are ready-wired with socket outlets. The boxes are intended for direct connection to the terminals of an electricity dispenser or meter, and are installed either in dwellings or in a waterproof enclosure. They are primarily intended to be an alternative to conventional wiring. The cost of the compact distribution board together with installation is Z$1700. This amount is payable in instalments over a two-year period. CDBs have proved popular with low-income households and demand for the initial 5000 was overwhelming. A further 1000 will be produced to meet the increasing demand. The second problem that would not necessarily be solved via reforms is the unaffordability of monthly electricity charges. The current average electricity bill for a household of 10 is Z$300. Many households cannot afford to pay this amount on regular basis. To solve the problem, prepayment meters have been introduced. This enables customers to pay for electricity when they can afford to. The advantages of 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.

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Rural electrification Rural electrification is by far the largest challenge facing the utility. Low returns on this type of investment mean that rural people are clearly the losers in any privatization attempt, so special mechanisms need to be put in place to address the energy needs of rural customers. The exploitation of the rural potential is vital for socioeconomic growth given the fact that electricity currently accounts for only 12.3 per cent of national energy consumption and only 21 per cent of households have access to electricity. The following issues characterize rural areas in Zimbabwe: – Most rural areas have less developed infrastructure, resulting in loads of between 50–100 KVA, which render grid electrification nonviable for most centres. The diffuse nature of the settlements also makes grid electrification difficult. – Most rural centres are not located within the grid infrastructure and large investments in the region of Z$1 million per centre will be required to electrify them. – The incomes in many areas are seasonal and it is therefore difficult to gather capital for the up-front cost of electrification. This means that in most cases rural electrification is not a viable business in Zimbabwe and cannot attract private investment on a large scale. However, the importance of rural electrification cannot be overemphasized. This has resulted in governmental approval of a rural electrification levy of 1 per cent to all electricity customers. At the same time the government has approved a Rural Electrification Master Plan – a document that prioritizes areas to be electrified within the next 15 years. The centres to be electrified are estimated to cost about Z$460 million at current prices. ZESA will be expected to raise Z$204 million via the levy, with the government raising the foreign component of Z$204 million through foreign funding. So far the levy has raised Z$80 million up to the year 2007. A total of 309 centres are expected to be electrified. Despite these efforts, at the end of the Master Plan many households and small centres will still not be electrified due to viability problems. ZESA has therefore changed its requirement that individual connection costs exceeding Z$11 000 be paid in full by the customer, and now requires only 60 per cent of the up-front capital cost, which is then payable in instalments over 5 years.

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In addition, ZESA has started utilizing renewables with the following objectives: – to meet the immediate energy needs of rural areas and other areas that can not be immediately connected to the grid; – to utilize renewables to stimulate the demand for power prior to grid electrification; – to promote investment and capacity-building in the solar industry through the opening up of the new solar market, achieved by increasing demand for the product through low-cost schemes; – to reduce environmental emissions through the development of sustainable least-cost and environmentally friendly energy options in line with ZESA’s role as a good corporate citizen; – to create a financing mechanism for the electrification of marginalized rural groups and institutions through the creation of a revolving fund. Currently solar systems are being installed throughout the country, with customers required to pay a connection fee of Z$250 which includes installation and internal wiring. A cost recovery tariff has been developed, allowing flexibility in payment. The maintenance and replacement of the systems is the responsibility of the Authority, and a proportion of the monthly payments goes into a revolving fund.

Conclusions The present legal and regulatory framework is characterized by many government controls in areas such as pricing, budgets and expenditure, procurement, decision-making processes and staffing issues. These inbuilt bureaucratic procedures compromise the efficient operation of a utility. The problem is worsened by a lack of capacity and skills within the Department of Energy (DOE). This lack is due to low remuneration in the public sector, with the result that para-statals attract betterqualified personnel than government. A survey conducted in Zimbabwe shows that civil servants are generally paid 70 per cent less than employees working in comparative posts in para-statals. In actual fact an analysis of the relevant section of the DOE shows that there is not even one power systems engineer. In developing a new legal and regulatory framework it must be appreciated that the Zimbabwean system is small in comparison to

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other countries with privatized para-statals. The maximum demand of the Zimbabwean system is only 1800 MW. In conjunction with the low growth rate of only 4.5 per cent per annum, this may mean that many potential customers will require subsidies. The scope for the efficiency gains expected through competition could be limited as potential entrants may require a guaranteed monopolistic market in order to make their investment viable. Rural electrification will require special arrangements. Although electricity in some areas is viable from a financial and economic point of view, many areas will continue to be characterized by viability problems. It might be necessary to continue the collection of levies to fund such electrification programmes by new entrants. To meet the growing demand for power in Zimbabwe private finance will need to be raised for capital projects, given the government’s huge budget deficit and the constraints involved in government-guaranteed sovereign loans to para-statals. This would invariably necessitate the entry of IPPs in Zimbabwe. Zimbabwe should also devise strategies that foster efficient use of energy and invest in demand side management and renewable energy sources as an alternative to grid expansion. Aside from supporting macroeconomic development and sectoral and enterprise-level efficiency, privatization in Zimbabwe should further the aim of widespread capital ownership by the majority of the Zimbabwean 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 (Lincoln College, 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 and Implementation 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 transformation (1996–2000), Government Printers, Harare, Zimbabwe: 1996.

Ikhupuleng Dube 151 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 Raising Funding on the Local and Foreign and Financial Markets. Zimbabwe Chapter of the World Energy Council, Symposium on Deregulation and Privatization of 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 Committee on the World Energy Council’ in the Proceedings of Symposium on Deregulation 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.

7 Power Sector Reform Experiences in Uganda John E. Mugyenzi

Introduction At the start of 1986, Uganda’s economy was weak as a result of about 15 years of turmoil. When the present government came to power it instituted economic reform programmes, which have injected a ‘lease of life’ into the economy. GDP grew at an average annual rate of 6.4 per cent between 1987 and 1995 and per capita income had reached US$250 by l995. The industrial sector is expanding rapidly and has a 14 per cent share of GDP. Urbanization is accelerating along with economic growth, and this has direct implications for electricity supply. The government is attempting to rebuild infrastructure that was damaged during the years of turmoil. The medium-term public investment strategy is geared towards development, in which the government will play a leading role: ensuring cost-effective expenditure within the priority sectors, and withdrawing from activities best left to the private sector. The development plan for 1993–1996 included US$232 million for energy sector development (15 per cent of the plan total). Donor assistance to the energy sector development was US$216 million, 93 per cent of the total energy sector budget.

Electric power resources Uganda is well endowed with hydropower resources. The potential capacity of the Victoria Nile is estimated at 2000 MW. Only 180 MW are developed at the Owen Falls Power Station (OFPS). Six other major sites have been identified: Bujagali, Kalagala, Kamdini (Karuma), 152

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Murchison Falls, Ayago North and Ayago South. There is also large potential for small hydropower development, especially along the tributaries of the Nile. Numerous micro-hydro sites exist, especially in the parts of western and eastern Uganda. Geothermal resources estimated at around 450 MW have been identified in the western Rift Valley along Uganda’s western boarder. No plans exist for their development. Uganda’s sugar industry has invested 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 technology 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), a monopoly utility owned by the state. The UEB depends on a single hydropower source, the Owen Falls Power Station. This station was opened 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 capable of generating 1000–1100 GWh per year under the present operating arrangements. The Owen Falls station is old and has been undergoing rehabilitation since 1986. Rehabilitation work that was scheduled to be completed in l990 has only just been completed. Transmission and distribution systems have also benefited from the rehabilitation work during which many lines were replaced and new transformers installed. The power system in Uganda has been running at or near maximum capacity for the last three to four years. UEB’s 1995 energy production of 1057 GWh and its peak load of 161 MW were close to the maximum capacity of the Owen Falls Power Plant. A number of diesel generators are located in remote parts of the country off the national grid. They have capacities ranging from 144 KVA to 500 KVA. UEB also operates a mini-hydro plant of one MW capacity in the southwestern part of the country. Domestic peak load is now estimated at 250 MW, leaving a capacity shortfall of about 70 MW. This normally translates into severe loadshedding, uneven voltage and other service problems now common in the Ugandan power system. A second power plant, the Owen Falls Extension, is under construction. It has an initial installed capacity of 80 MW (2 × 40 MW), with provision for an additional 120 MW. Its anticipated energy production is 500–600 GWh per year, raising the system capability to 1500–1700 GWh per year. The project, initially

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scheduled for commercial operation by 1997, is due to be commissioned in April 2000. Only 5 per cent of Uganda’s 18 million people have access to electricity. The average per capita consumption rate is 44 Wh per year. The majority either cannot afford service or are very remote from the grid. The main categories of consumers are residential (55 per cent), commercial (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 the power generated. Non-technical losses, mainly consumption by unregistered or illegally connected consumers, comprise 10 per cent of power generated. Power outages, wide voltage fluctuations and brownouts are frequent. The outages are due to both system breakdowns and deliberate load-shedding by UEB. In either case they are a cost to the economy and to the system’s customers. UEB’s financial situation is such that it cannot earn an adequate rate of return, service its debts, and contribute significantly to the financing needed for development investments. At an average of 10 US cents per kWh, UEB’s tariffs are not low. Its financial difficulties are a result of high system losses, inaccurate billing and poor collections as well as high staff costs. In 1989, for instance, salaries and wages made up 22 per cent of total operating expenditure; by 1994 they had risen to 43 per cent. The corruption prevalent in Uganda has also permeated the power sector. The UEB’s system losses of 30 per cent, particularly those associated with the distribution segment of the industry, occur in many instances with the collusion of UEB staff. Distribution lines are vandalized in search of materials such as copper, aluminium and angle lines. These problems accentuate the acute capacity shortfalls that have resulted in extensive power cuts in the country. UEB has been rapidly increasing the number of new connections to its system in an unplanned manner that has further overloaded the system. New connections have been effected without paying due regard to load-balancing and low-voltage lines have been extended excessively. To deal with these problems, UEB has introduced a monitoring team that performs on-the-spot checks. The team is supposed to check the system regularly and report any anomalies. UEB still maintains obsolete equipment. To obtain spare parts, UEB has to place a special order. In most cases UEB is unable to replace worn-out or damaged parts because of financial reasons. The equipment continues

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to affect the quality of service UEB provides. Some of the equipment is replaced 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 for the 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 programme aims to reorganize MNR, redefining its function in order to improve its effectiveness. However, the pace of restructuring is not fast enough to ensure effective policy-making and supervision of the power sector. For example, only three out of the seven established posts in the Department of Energy have been filled. UEB is responsible for the generation, transmission and distribution of power. It is Uganda’s largest state corporation with 3700 employees. With the support of IDA and a number of other multilateral and bilateral donors, the government has invested heavily in rehabilitation of the power sector’s infrastructure and institutions. UEB, however, remains inefficient and non-profitable. The sector lacks the institutional strength to play its role in the economic and social development of the country. Legal and regulatory framework The Uganda power sector is regulated by the Electricity Act, 1964. The MNR is responsible for policy formulation and oversees and coordinates sector operations. The Electricity Act gives UEB a monopoly in generation, transmission and distribution of electricity in Uganda and also allows it to export power. The Act gives UEB a regulatory function in that it issues licences and regulates the operations of the licensees. Although the Act does not bar private sector entry, the multiple roles of UEB as owner, operator and regulator of the power sector discourages private investment. The Minister enjoys a dominant role in the power sector with the power to enact regulations regarding electricity supply, and resolve disputes.

Motivation for reform Rapid economic growth has resulted in fast-growing demand for electricity, thus increasing load-shedding in virtually all load centres.

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Power shortages have constrained the country’s economic growth. The following are major considerations behind the move to reform the power sector in Uganda: • There is a shortage of domestic capital to invest in power generation capacity and expand the existing infrastructure. Any development of the power sector would necessitate foreign loans, thereby increasing Uganda’s debt burden and exacerbating UEB’s financial difficulties. • The institutional structure of UEB limits management’s autonomy, tolerates inefficiency and does not provide sufficient reward for initiative and performance. Thus UEB remains inefficient and financially 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 and regulator. • The shortfall in power supply has resulted in frequent blackouts and the government (GOU) is attempting to find an interim solution.

The reform process Reform in Uganda’s Power sector is the result of an evolutionary process rather than a continuous policy implementation. However, the various issues have been consolidated into a proposal for a strategic plan for the Uganda power sector. Initiation of reform The aim of the Ugandan government is to restructure and commercialize the power sector in order to enhance its operational efficiency and financial performance, in addition to establishing an independent regulatory agency. The government’s targets are: • To achieve enhanced economic viability of the power sector outside the government budget; • To improve UEB’s operations and financial performance through managerial autonomy and commercialization; • To meet growing electricity needs through involvement of private investors and private capital; • To develop decentralized power systems to meet the rural electrification objectives of the government.

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A number of studies on different aspects and issues facing the power sector have been undertaken to help develop a framework for reform. The evolution of the reforms started in l985 with a proposal that was referred to as Uganda Second Power Project. This involved rehabilitation and reconstruction works at OFPS and dam, rehabilitation of the transmission and distribution system, training of UEB and MNR staff, and various consultancy studies aimed at improving the electricity supply. The OFPS works have been completed. Rehabilitation of the transmission and distribution systems continued until materials and financial resources were exhausted. Studies undertaken under the Second Power Project included the following: • 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 have either been implemented or are included in the Third Power Project. The need for the Third Power Project was strengthened by a 1989 ESMAP mission report which recommended an increase in generation capacity and improvements in the distribution system in Kampala, the Owen Falls Extension Project, and rehabilitation of the power system in Kampala. Other components of the project include: construction of the 132 kV Masaka–Mbarara line, construction of the 132 kV Jinja–Kampala double circuit line, support to MNR, rural electrification of semi-urban areas, institutional support to UEB and engineering design for the next hydro site to be developed in Uganda’s least-cost development study. Work on the Owen Falls Extension (OFE) began at the end of 1993, two years after its scheduled start date. The 132 kV transmission lines are now completed, as are most of the other activities.

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National Electrification Planning Study (NEPS) This study aimed to find the optimal programme for providing electricity to a substantial number of areas throughout the country over the next 20 years. It contained a long-term electricity demand forecast and analyzed both available and potential generation facilities. A National Electrification Master plan was also formulated. This involved assessment of the technical standards in use, the quality of service, and the electrical and mechanical state of the system. The main findings of the study were: • Rehabilitation of Owen Falls may only be sufficient for meeting demand 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 towards improving customer service as well as corporate cashflows, liquidity and profitability. The findings confirm an urgent need for UEB to develop its organization, systems and work practices in the commercial business area. The project involved review of the Customer Accounting System, responsibility structure, adequacy of current Management Information System (MIS) technology and its impact on UEB’s billing and collection performance. The Electricity Supply Board of Ireland (ESBI) was mandated to explore the feasibility of contracting out meter-reading, bill delivery and revenue collection while retaining overall responsibility within UEB. The major recommendations were that UEB should: • Create a new function of Customer Services incorporating both distribution and commercial functions; • Separate the district of Kampala (which accounts for 70 per cent of UEB’s customers) from Central Region and give it regional status;

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• Divide the district of Kampala into Customer Services Areas. A subdivision into five areas would bring customer services functions closer to customers; • Establish appropriate authority levels, guidelines and performance criteria for the new structure; • Provide management development and training to support the process of structural change; • Leave the core activities of collection, meter-reading and bill delivery under direct management. These recommendations were agreed to and are now being implemented. Loss reduction study This study concluded that technical losses could be reduced to 11 per cent by load-balancing. Rehabilitation of the 11 kV system in the central region would further reduce technical losses. A further recommendation was that all customers should be metered and that bills no longer be estimated. At the time of the study there were an estimated 3000 illegal users in Kampala. No action has been taken to resolve this problem due to a poor customer database. Reform strategy The long-term power sector strategy for reform involves the following elements: • Unbundle the power system with state-owned UEB retaining responsibility 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 the reform. In August 1996, the government reached a decision not to contract out the Uganda Electricity Board’s management to a private management firm. The government’s reform policy is to open the generation segment of the industry to other generators while the transmission

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Figure 7.1

Proposed industry structure

segment remains under UEB. The distribution segment would be privatized at a later stage in the reform process. Independent power producers Uganda has already expressed the intent to solicit for private investment in the power sector. Cabinet has already approved an amendment to the Electricity Act 1964 to end UEB’s monopoly status and open the sector to private investors. A number of developers have shown interest and have formed partnerships to develop certain hydropower sites. Table 7.1 shows the IPPs, 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 understanding was executed between the government of Uganda and Nile Independent Power (NIP). NIP was to build, own and operate a hydroelectric plant at Bujagali Falls. The development programme presented by NIP includes provision for a 290 MW, US$480 million power plant

John E. Mugyenzi 161 Table 7.1

New independent power producers

Independent power producer

Site

Nile Independent Power Pakwach Power Limited Arab International Contractors Ltd Rwenzori Tea Growers Ltd

Bujagali Karuma Kalagala Muzizi

Capacity (MW) 290 200 340 60

Project cost US$ 480 – – –

at Bujagali to be operational by the year 2000. Another three developers have also signed memoranda of understanding with the government to develop other hydropower sites on the Nile River. The most advanced of the four developers is negotiating a Power Purchase Agreement (PPA). All the developers are pursuing Build, Own and Operate (BOO) contracts. IPPs are interested in selling all the power they generate. The GOU has now commenced preliminary negotiations with Kenya and Tanzania with the aim of increasing exports to the two countries. Uganda is primarily interested in closing the supply deficit, raising significant amounts of capital and bringing modern technology and management expertise into the industry. As a result of the absence of the type of environment that would attract IPPs and other forms of private sector investment in the power sector, government has opted for negotiated deals other than competitive bidding. The most advanced of the four (NIP) signed a memorandum of understanding in 1994, but the PPA negotiations have been stalled. The PPA has not yet been signed as the parties involved have not been able to agree on certain issues. Some of the contentious issues are: 1. NIP is requiring the government of Uganda to guarantee payment of power sold to UEB. Such a requirement underlies the inability of UEB to pay for power purchased because of low tariffs and problems associated with billing and revenue collection. 2. Financing is to be on the basis of a concessionary credit to lower the tariff. Concessionary credit is normally associated with a low interest rate and could affect the overall cost of the project, and consequently the price at which electricity would be sold to UEB. This is related to the political nature of tariff increase and the issue of affordability by low-income earners.

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3. The reliability of the transmission and distribution system, the extent to which IPPs would be able to have unconstrained access to it, and the conditions for such access are still being discussed. 4. Other issues such as reliability of load forecast, conditions under which IPPs can export power and new legislation for the electricity sector are yet to be resolved. The inability to resolve these and other issues is delaying the badly needed additional capacity. Although there are responses to the GOU’s call for private investors in the power sector, it would be prudent for the GOU to accept counter guarantees for the commitments by power purchasers (in this case UEB). In view of UEB’s less than impressive track-record, policy analysts contend that the insistence of NIP and other IPPs that UEB buys all its power and that GOU guarantees payment is not unreasonable. To strike a balance, GOU could agree to a phased site development programme so that power is available in the required quantity. For example, if the capacity deficit at the time of commissioning the station is expected to be 50 MW, the commitment would be to guarantee purchase of 100 MW for a specified period, after which time the limit would be reviewed. However the IPP would not be limited to 100 MW. The delays in implementing the first IPP have led the GOU to solicit for other developers without consideration of the national Hydropower Development Master Plan (HMP), which has ranked hydro sites throughout the country. The first IPP has not taken up the site ranked number one. The maturity period for hydro site development is known to be 6–8 years. Thus hydro development is not a short-term solution to capacity shortages. A thermal plant is a cheaper and quicker solution to the country’s capacity problem and could operate in parallel with the hydropower development projects until they become operational. The GOU has decided to advertise for a short-term investment in a thermal plant to cover the ever-widening generation shortfall. Unlike the non-transparent process of hydropower sites allocation, the government has followed the International Competitive Bidding process to 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 to provide any guarantees on fuel supply. Uganda’s continued power supply capacity shortage has forced it to advertise a tender for a 60 MW thermal plant by an IPP to become operational within 6 months. Bids have now been received. Uganda’s main constraint in this area will be fuel, since it is a land-locked country, with no known source of

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fossil fuel. This makes a reliable fuel supply to the thermal plant(s) extremely difficult to ensure, affecting Uganda’s ability to attract a genuine investor in thermal power generation. The GOU is concerned that IPPs may off-load all risks associated with power development on either the government or the UEB. This concern, while genuine, is causing delays in bringing online additional capacity. The GOU has now obtained advisory services from the Commonwealth Fund for Technical Co-operation, for any future discussions about the project. Meanwhile NIP has held tentative discussions with Tanzania about power exports. NIP insists that it will not assume any risks arising out of the site recommendation in the expected HDMP report. The draft report has now been released and ranks the Bujagali site as number three on the least-cost development programme. NIP states that project financing will be obtained from CDC but is conditional upon the execution of the PPA. The GOU on the other hand wishes to see evidence of financiers’ commitments. Meanwhile the advice of the World Bank is that NIP should follow the private financing route, as an IDA-financed project would discourage other projects. However, the World Bank advised NIP that it would close any financing gap and support any unallocated risk or ‘guarantee’ as a last resort. The World Bank is also committed to supporting any investment in the transmission and distribution network by UEB. Regulatory framework The introduction of a formal regulatory system is an important part of the reform strategy. Presently the MNR is the regulator. Reforming the regulatory system would involve the amendment of the Electricity Act 1964 to allow formal regulation of power sector actors and allow other entities to generate and supply electricity, as well as the establishment of an autonomous regulatory commission. The regulatory commission is to have a full-time secretariat in MNR and membership will be parttime. It will be funded by levies from electricity fines and penalties. The establishment cost is expected to be donor-funded. An amendment to the Act has been approved by Cabinet and is awaiting the approval of Parliament. Under the existing system IPPs or any other entrants into the industry could be at a competitive disadvantage as the rules of the game are not clear. This may explain why IPPs are extracting concessions or guarantees from the government. In setting up sector policy all actors should be treated as equals. Any agreements reached should neither

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burden UEB nor should it give UEB an advantage over IPPs. This only emphasizes the need to hasten enactment of a new electricity act and establishment of a regulatory commission with a clearly defined mandate and minimum government interference. The importance of this issue was underscored during a workshop that was organized to discuss 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 for new legislation that would remove UEB’s monopoly of the power sector and create a regulatory body to supervise the operations of the sector. Decentralized power systems The decentralization policy will allow private commercial investors to own up to 50 per cent of UEB’s existing distribution and related commercial services. The privately owned regional distribution entities will be responsible for providing electricity services to final consumers in these areas of Uganda, with an opportunity to expand into surrounding market areas. In semi-urban and rural areas, private investors will be encouraged to set up community-based generation and distribution systems. The decentralization has so far involved the establishment of a pilot project in the Kampala area. The Kampala area customer services branch is now operating under the same management semiautonomously from the rest of UEB. This development has provided 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 generate their own power, or purchase power directly from a generator or distribution company. UEB will continue to provide transmission services. In the past there were only two independent generators, but in recent times three more have entered the market.

Experiences of reform implementation Institutional reforms UEB was, until recently, structured along functional lines with the technical functions being grouped together and the administrative functions forming separate groups. During restructuring in 1992, separate departments were created for distribution, commercial and devel-

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opment function, thus diffusing the customer services function that is key to UEB’s business success. This fragmentation of customer services responsibility has proved a big disadvantage in terms of decisionmaking, implementation and monitoring. It is now common for the distribution department to make new connections without advising the commercial department. When this happens, legal customers appear as if they are illegal. Enabling environment The absence of an enabling environment has affected the speed at which licensing of IPPs can be achieved. Uganda’s primary objective of inviting IPPs was to add new generation capacity to reduce and ultimately eliminate the shortfall in power supply in Uganda. The inability of government and UEB to attract funds from traditional sources such as the World Bank was another reason for opening up the power sector to private sector participation. All the IPPs that have shown interest are having difficulties putting together project financing packages. The absence of a regulatory framework and a transparent competitive bidding process has hindered negotiations for a PPA between government and NIP. The main reason for this situation is the kind of IPPs that are planning to invest in the sector. They do not have the type of credentials that inspire confidence in financing agencies. Some have taken on local partners who have no experience in the industry. Furthermore, the absence of a legal and regulatory framework adds to the lack of confidence financiers have in the process. Hence the insistence by financiers that a PPA should be concluded before NIP can obtain funding commitment. The four IPPs that have shown interest came by invitation or in response to the government’s commitment to encourage and assist the entry of private developers into the Ugandan power sector. None of the three sites that have been allocated was subject to transparent competitive bidding. Such a lack of transparency in the bidding process may explain the delay in reaching agreements. Regulatory framework Uganda has liberalized its economy, and opened up the power sector to private investors. Despite this, several key uncertainties remain for private investors. While there is evidence of commitment on the part of government to license private investors, the establishment of a regulatory framework is ongoing and its provisions are yet to become law.

166 Experiences in Uganda

Thus the creation of an environment attractive to private investors is in progress while the investors are already on the ground. This seems to be among the issues holding back NIP. The rules governing private investor entry are only just being established. A proposal for a new regulatory framework is before Parliament for approval and this will allow other entities to invest in the Ugandan power sector. Government has engaged an expert from NORAD to draw up a more comprehensive power sector reform strategy including a proposal for an appropriate long-term legislative and regulatory framework. The question of how this framework will operate in practice has been influenced by the availability of resources, both technical and financial. The size of the regulatory commission should be determined by the amount of business to be conducted. This is difficult to estimate. It is also recognized that there should be an administrative linkage between the regulator and MNR. This introduces the risk of MNR influencing the regulator. The Uganda power sector is small. Although plans for wide representation are included in the proposed regulatory framework, there will be need to review it periodically as the sector expands. The Minister will appoint the commissioners. While it may not be difficult to find people of high calibre in the power sector, it is difficult for such a system to be completely transparent in an economy like Uganda’s. An attempt has been made to frame the laws so as to ensure that funding does not undermine the autonomy of the regulator. Establishing which function should be mandated by law and which should be negotiated is not a simple matter. The capacity to implement regulatory rules effectively is determined by the availability of technical skills and the ability to resist improper influence or inducements. An issue being mooted now is whether it will be easy to recruit and retain well-qualified professionals with the requisite technical skills without exempting the commission from civil service 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 affected the pace and style of the ongoing negotiations. On several occasions developers have been informed that the HDMP study is in progress and that the results will determine the next site to be developed. Yet the four developers on the ground have already been allocated hydro sites. This contradiction has affected NIP’s progress.

John E. Mugyenzi 167

The confusion surrounding the hydrology of the Nile and Lake Victoria is further accentuated by the use of different hydrological data regarding the construction of the Owen Falls Power Station and its proposed extension. As a result, the potentials of the various river Nile hydro sites are unclear. This delay in implementing the Bujagali Project is due to the fact that the developer is not sure of the maximum energy yield of the site. Yet the government insists that the site should be developed to its maximum potential. Electricity export An important factor in the decision by IPPs to invest in power projects in Uganda is the ability to export part of the power generated. The government is now negotiating with Kenya and Tanzania on export terms. Government bureaucracy, however, continues to delay the process. Developers (NIP) have held informal discussions with both Kenyan and Tanzanian electric power utilities on the power export issue. Kenya’s main concerns involve the provision of a performance guarantee 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 stations whenever possible because of the high cost associated with their operations. Rural electrification through grid connection and a decentralized system based on renewable energy technologies have become options to achieve this. But sometimes political pressure has made it difficult to retire these stations. An economic comparison detailed in the Uganda National Electrification Plan Study 1 report shows that the 33 kV distribution system is the most profitable in Uganda for rural electrification. It also established 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 rural electrification projects are to be undertaken. Regions with no electricity have the edge over those that merely require line up-rating/rehabilitation. In some cases political and/or management prejudices and interests over-ride logical decisions as to the most profitable rural electrification choices. Lines have been constructed for political reasons unrelated to serving load centres.

168 Experiences in Uganda

The government policy of rural electrification does not serve UEB’s business interests. It is a social service rather than a profit-oriented system expansion. The government has been contributing to the activity in order to ease UEB’s financial commitments. The political stability in Uganda and the neighbouring countries continues to influence government’s actions and UEB’s system expansion programme. A 132 kV line has been extended to north western Tanzania and a 33 kV line has been connected to Rwanda’s northern region. While there is a potential market in southern Sudan, hostilities between the two countries remain a barrier. These grid extensions are also facilitating the government’s rural electrification programme as the grids pass through rural communities. Landownership can pose a problem for the rural electrification programme. Individuals who object to power lines passing over their property ask for large amounts of compensation. Those who refuse compensation altogether are acting within their legal rights. The subsequent detours involve delays and expense. Donors in partnership with UEB fund most of the rural electrification projects, providing funds for materials while UEB does the work. This has tended to compel UEB to recruit more labour, especially when several lines are being constructed concurrently. Ownership/management reforms Implementation of ownership/management reforms has only just begun. Apart from inviting IPPs, the government has decided to privatize all non-core activities that have hitherto been the responsibility of UEB. So far, UEB’s timber pole plant has been offered for tender. However, it appears that there was little information available with respect to the tender and the process is an unfamiliar one in Uganda. In addition, there is a widely held suspicion that UEB will be privatized in the near future. The plant has now been closed for almost a year and UEB is experiencing difficulties procuring treated poles.

Impact of reform The fundamental objectives of reform are to change actions and methods in an attempt to bring about improvements in the performance of the power sector in Uganda. Reform must address the longterm implications for the sector. This section analyses the impact of reform on various stakeholders in the power industry.

John E. Mugyenzi 169

Power sector performance The liberalization of the Ugandan economy has lead to an increase in the economic growth rate. As a result the power sector is experiencing a high growth of demand. The situation is compounded by the absence of any new development in supply capacity. The country is experiencing severe and worsening load-shedding. Opening the industry to the private sector has attracted a number of developers. But for various reasons, such as bureaucratic bottlenecks, the absence of a transparent regulatory system and unreliable information on the hydrology of the Nile river, none of them is far enough advanced to give the country any hope of relief from the shortage in supply capacity. The reform taking place in the sector is aimed at improving management of UEB. The restructuring solutions prescribed include: • Downsizing the workforce in order to improve UEB’s financial performance. High staff costs have contributed to UEB’s financial difficulties. From 1989 to 1993 the number of employees increased by 40 per cent to 3374 while the number of customers increased by 17 per cent to 110 000. Salaries and wages have continued to increase both in terms of individual employee’s remuneration and as a percentage of total operating expenses; by 1994 it had risen to 43 per cent. The target is to reduce the present workforce of 3700 by 1000 workers, i.e. 2700, by the end of 1997. This has created job insecurity among the staff, and consequently affected their performance. • The installation of new communications technology has greatly aided communication between the head office and the regional offices and power stations. The newly installed SCADA system has contributed to improving system performance and data acquisition. • Redistricting of the central region (Kampala) has created more revenue collection centres. This has enabled UEB to reach more customers than before, and it has improved its revenue collection and customer 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 projects and studies in the power sector. This has led to a substantial debt burden and an unfair allocation of resources that could have been used in other sectors.

170 Experiences in Uganda

The government is committed to enacting an electricity law that would set the ‘rules of the game’ for industry participants. It is expected that a regulatory commission will be formed to regulate the power sector. In the interim, an Electricity Act amendment allowing entrance of IPPs is before Parliament. There is already optimism about the IPPs and the public is entirely supportive of the government’s decision to open up the power sector to private investment. However, this does not allay the fears of foreign private sector control of the industry. The government realizes that there will be need to maintain some subsidies and continued rural electrification under the new planned structure where the distribution function will be privately owned and operated. Various options for continuing these programmes are being considered in the government’s strategic plan for the Ugandan power sector. The continuing load-shedding and UEB’s inability to adhere to the load-shedding programmes it publishes in local gazettes have reduced customer confidence in UEB’s continued operation of the system. The general public feeling is that UEB, like some SOEs divested before it, should be privatized. Electricity pricing Electricity price rationalization has been an important aspect of the reform. Electricity prices for customer classes have been increased. The current tariffs were a result of IDA conditionalities for lending the Ugandan government funds for the extension of the Owen Falls generation facilities. There is a general complaint about the tariff levels. Most customers think it is unrealistically high. The tariff increase made electricity unaffordable to some people who already had the service. Some have turned to woodfuel, contributing to accelerated deforestation. Government is actively promoting the development of alternative sources 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 to government suggesting that a long-run marginal cost-based tariff is lower than the current UEB tariff. This assertion, if it is true, is obviously due to internal inefficiencies within UEB. Government has requested UEB to examine the matter. Customers and customer services The re-registration of UEB customers has revealed a large number of illegal consumers and these have now been disconnected. Unfortunately, the offenders have not been prosecuted. The exercise of

John E. Mugyenzi 171

re-registration has also enabled UEB to redistribute system connections for load-balancing purposes. As a part of measures to reduce accounts receivable, government has settled all its outstanding dues. Government has settled all outstanding bills owed to utilities by all Ministries and various government departments and directed UEB to disconnect any future defaulter without reference to government. Only the arrears carried on the properties that have been repossessed by returning Asians are still in question. The new 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 tampering. Customers also continue to complain about meter-reading procedures. Some customers will not allow UEB officials to read the meter in their absence. While the quality of service has improved markedly, it is inconsistent. System surges are still a source of complaints by customers who suffer equipment damage as a result. Private investors Private investors are concerned at delays in passing legislation on regulation and uncertain as to the nature and scope of their rights. While government’s commitment is not in question, there are questions concerning how the political climate may affect power sector regulation in the future. At the moment the driving-force behind the current reforms is the President of Uganda. There is a lot of caution on both sides of the negotiating table for fear of insufficient attention to key issues that may emerge later. In view of the GOU’s zeal to develop additional supply capacity, the new developers have sometimes placed undue pressure on UEB. UEB is obliged to assist with all information at its disposal, and has therefore been unable to give full attention to its own activities. Some of the case studies, such as the one at Bujagali, have been paid for by UEB. In certain cases, UEB is still repaying the debts from these studies. The reports have now changed hands at no cost, and the investors have not conducted new research to confirm their findings.

Obstacles to reform implementation Attempts to reform the Ugandan power sector have encountered numerous difficulties. The following are among the factors that continue to affect the success of reforms:

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1. Inadequate capacity of MNR: MNR has inadequate capacity to regulate the power sector and perform other tasks that follow the reforms. MNR/GOU have had to hire the services of consultants in the ongoing negotiations. Observers of the reform process in Uganda are of the opinion that UEB’s reforms have not helped it to improve its performance because of weak MNR supervision. 2. Size of the Market: investors have also shown concerns about the size of the market. Unless they can export to neighbouring countries, the local market is insufficiently large for the size of projects being considered. 3. Human Capacity Problem: shortage of technical expertise is likely to affect the regulatory capacity of the proposed regulatory body. During the whole of this period of reform design and implementation, for instance, UEB had engaged experts in some line positions in the departments of Finance, Commercial, Corporate Planning and MIS to fill key skills gaps. While most of these experts are knowledgeable, not all of them have been central to the reforms. There is conflict between local managers and the experts resulting from conflicting work methods, local managers complain of doing most of the work while experts complain that local managers are lazy. At the same time the big disparity in remuneration and privileges, coupled to the reluctance of experts to pass on their skills, has not helped UEB’s operations. Experts’ contracts continue to be renewed upon expiring. 4. The level of corruption in government in general is argued to be contributing to the slow pace of the reform. 5. UEB’s current sales data do not provide a reliable indication of recent consumption trends. Uganda’s economy has improved greatly in the recent past and there is a large suppressed demand due to capacity constraint. This suggests that a rapid load growth rate could ensue as and when this constraint is eased. This has distorted load forecasting and therefore affects planning for power sector expansion. Since reforms began, the various forecasts have tended to give different signals of demand growth trends. 6. The lack of systematic collection of data on service quality hampers tracing the extent of and the trend in technical problems on UEB’s power system. While reform programmes have attempted to plan maintenance, the resulting maintenance programmes have had little impact on system efficiency. A SCADA system with automatic data recording has been installed and a databank is now being built up.

John E. Mugyenzi 173

7. Legal framework: while the Electricity Act 1964 gives UEB autonomy, it also gives the Minister in charge of the power sector authority to direct UEB on matters of policy, giving approval on tariff changes and other major measures. Very often UEB management finds it difficult to implement changes/reforms that affect customers without reference to the minister. Issues like installation of prepayment meters have had to obtain ministerial approval. The proposed legislation for the power sector will establish a new relationship between the minister and UEB, based on arm’s-length regulation of the utility’s operations and finances. 8. Bureaucracy: the bureaucratic procedures of UEB management hinder quick decision-making. In addition, managers lack the authority necessary to execute certain decisions. For example, UEB management cannot make a procurement decision of more than Ush 5 million without the approval of the Board of Directors. 9. Politics: changes in political leadership sometimes lead to changes in UEB management, affecting continuity of some of UEB’s programmes. In the last 10 years there have been Cabinet reshuffles that have changed the minister responsible for the power sector three times. On each of these occasions UEB’s areas of emphasis has changed. It is hoped that the new legal and regulatory framework will eliminate such interference.

Lessons from experience Over the last 10 years, the government of Uganda has worked hard at implementing an economic recovery programme that gives high priority to the rehabilitation, expansion and maintenance of the country’s infrastructure. The economy has responded favourably to the reform programme. The following factors have emerged as being critical to the success of reforms in the power sector: Government commitment It is of paramount importance that the government shows a strong commitment in order to eliminate fears of policy reversals. This enhances investor confidence in the transparency and fairness of the process. The Ugandan government’s commitment has been demonstrated by the successful privatization of other SOE’s with vigorous support of the President. So far interested investors are operating in the absence of a legal and regulatory framework. Government assurances

174 Experiences in Uganda

and concrete moves toward establishing a regulatory regime have convinced investors of the seriousness of its intentions. The government’s vital role is to create an ‘enabling environment’ in which investors can operate with confidence. For the country to raise international capital, it must play by international rules and give up certain national practices. Governments need to improve the general climate for foreign investment and identify the reforms needed in order to make private sector participation attractive. UEB’s chronic need for subsidies and soft loans has convinced government of the need to rid itself of the utility. However, it must still contend with UEB’s importance in terms of employment and the significance of its product. Public confidence The Ugandan public is suspicious of foreign participants in the privatization process. For example, one of the reasons cited for rejecting the proposal to contract out management of UEB was that the assets could be 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 ownership. There is little support for reform among management and employees of UEB. Therefore there is need to raise public awareness through campaigns and discussions with UEB management and employees. Regional markets and capacity Uganda’s vast hydropower potential can be developed for the export market although Uganda exports approximately 25 per cent of its total generation to Kenya, this export market is neither secure nor financially attractive. The power that is exported is the remainder after the needs of the domestic market have been met. Capacity constraints have meant that UEB has not met its obligation to Kenya. While the agreement is to supply Kenya with 30 MW of firm power, UEB cannot manage more than 17 MW off peak. This has given rise to Kenya’s unwillingness to renegotiate the tariff to a more realistic level (now US$0.56 per KWh). Inter-regional connection with the South African grid would enable Uganda to tap the reserve capacity in the region in order to meet peak demand. In the prevailing circumstances, Uganda’s best hope of meeting its domestic demand lies in enlisting the assistance of the private sector. If Uganda’s power system was interconnected with the

John E. Mugyenzi 175

South African regional system the capacity deficit could be covered by imports. Uganda would therefore benefit from regional interconnection. It is important to use trade to minimize energy and capacity costs. The main constraints to regional trade in electricity and petroleum products are political and commercial. Many countries in the region are unwilling to rely on their neighbours for such a key economic input. Failure to agree on a pricing system or to meet or enforce contractual obligations has stalled trade between Uganda and Kenya, despite the fact that it is in both countries’ best interests. Transparency Experience from other sectors suggests that transparency is an important condition for private investment. Private investors are attracted by enabling environment, which can only be created by institutional, legal and regulatory transparency. Uganda’s market is small and there are no domestic capital markets. The only reasons private investors have shown interest are the existing macroeconomic stability, low inflation and government commitment. However, the absence of a regulatory framework has resulted in a lengthy negotiation process. The need to expand access to electricity beyond the current low levels is at the heart of government concerns, while commercial aspects of power supply, technical performance, the export market, and the need for cost recovery tariffs, are the main issues of interest to private investors. There can only be agreement between the two sides when the process is transparent. Legal and regulatory framework Uganda’s Electricity Act 1964 does not appear to pose significant hurdles for private participation in the power sector. However, the monopoly rights it accords UEB are a threat to any potential competitor. The Act allows UEB to license electricity generators and therefore gives it the role of power sector regulator. The legislation does not spell out rules for price-setting, the issue of licences, provision of adequate appeals or the mechanisms for resolving disputes. The regulatory system should establish a fair and transparent process. Note 1 This is one of reports on the power sector prepared for the Uganda Electricity Board by EDF in November 1992.

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

Introduction During the past 15 years Mauritius has experienced a rapid economic growth. This is the result of the pursuance of an industrialization strategy that preserves the monoculture-based sugar production. The growth of the economy has resulted in significant increase in energy consumption in all sectors of the economy. Electricity consumption, in particular, has grown significantly, from 380 GWh to 1151 GWh during a 12-year period. This increase, in a small island country with limited energy resources, has raised the problem of the economic development of the energy sector in order to ensure the country’s sustained development. This chapter seeks to present and discuss the major the issues in the power sector. It also examines some of the problems facing the sector, the measures studied and already taken or envisaged to solve them in the most economical way, without affecting efficiency and security of supply.

Historical features and existing framework Initially composed of small independent private undertakings supplying electricity to consumers, the electricity sector grew rapidly to the point when the need was felt for a corporate regulatory body. This led to the creation, in 1952, of a Central Electricity Board (CEB) which, four years later, became the sole public supplier of electricity. As such, 176

René Noel 177

the CEB became responsible for the generation, transmission and distribution of electricity throughout the country. As a para-statal body, its role and operating conditions are defined in the Central Electricity Board Act 1964 as subsequently amended. It now operates under the aegis of the Ministry of Public Utilities (MPU). In this context, it can be said that final decisions regarding electrical energy rest with the CEB board of directors and ultimately with the MPU and the government. However, the definition of an overall energy policy taking into consideration all related matters must, perforce, involve other important sectors and organizations before being adopted by government. Such matters include, inter alia, the search for new energy sources, the reliability and price of it and, pending the implementation of a medium/ long-term policy, the adoption of measures intended to guarantee electricity supply to consumers as their requirements increase. This has led to the involvement in energy-related matters of other Ministries such as Finance, Industry and Commerce, Planning, Agriculture and Environment; of para-statal bodies such as Mauritius Sugar Authority and the University of Mauritius; of the private sector such as Mauritius Sugar Producers’ Association and individual sugar companies. As far as electricity generation is concerned, one major change has occurred since the CEB became the sole supplier in 1956. This is the growing participation of sugar factories as exporters of energy to the public grid, CEB remaining responsible for transmission and distribution. This particular point will be discussed in detail later, but its importance is indicated by the fact that, in 1996, this exported energy purchased by the CEB represented as much as 10.3 per cent of the total electricity generation. It is in the context of this existing framework that the authorities concerned have to manage the electricity sector, solve its immediate problems, and define a long-term policy. Let us first see what is the present and foreseen technical situation.

Electricity supply and consumption Table 8.1 shows electricity generation by source for the years 1970–96 and may be briefly commented upon as follows: • Electricity generation has increased by 746 per cent since 1970 and is now increasing at an annual rate of some 10 per cent; • Imported energy-related products, for example fuel-oil, diesel and kerosene, have largely met the growing demand;

Year

1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

178

Table 8.1

Electricity generation by source Hydro GWh

%

51 50 68 74 40 56 55 56 54 59 83 60 94 35 65 115 110 140 99 148 85 76 13 104 75 134 104

37.5 33.8 41.5 39.6 19.2 25.0 20.4 18.2 16.1 16.6 23.4 16.6 25.9 9.4 17.1 29.3 25.1 28.7 18.0 25.1 12.7 10.3 14.0 12.0 7.9 12.8 9.0

Bagasse GWh

%

22 25 23 24 24 17 25 24 25 26 27 31 43 32 29 58 73 74 72 56 53 70 85 71 77 84 119

16.2 16.9 14.0 12.8 11.5 7.6 9.3 7.8 7.5 7.3 7.6 8.6 11.8 8.6 7.6 14.8 16.6 15.2 13.1 9.5 7.9 9.5 10.5 8.2 8.1 8.0 10.3

Coal GWh

5 45 43 29 34 68 45 54 43 40 46 41 10

%

Fuel-oil/diesel GWh

1.3 11.5 9.8 6.0 6.2 11.5 6.7 7.3 5.3 4.6 4.9 3.9 0.1

63 73 73 89 144 151 190 228 256 270 245 271 226 304 281 174 213 244 339 310 449 494 498 615 699 682 699

% 46.3 49.3 44.5 47.6 69.2 67.4 70.4 74.0 76.4 76.1 69.0 74.9 62.3 81.9 73.9 44.4 48.5 50.1 61.7 52.6 67.2 67.0 61.6 70.7 74.0 65.2 60.7

Kerosene GWh

51 71 360 438 693 396 48 106 219

%

0.9 1.2 5.4 5.9 8.6 4.6 5.1 10.1 19.0

Total GWh

%

135 148 164 187 208 224 270 308 335 355 355 362 363 371 380 392 439 487 549 589 668 738 808 870 945 1047 1151

100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100

René Noel 179

• The hydro potential, limited by the country’s size and topography and subject to largely varying climatic conditions, may be considered as fully exploited; • The bagasse share has not followed the overall trend but its contribution in quantity has greatly increased, and it is known that its potential 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 forecasted trends based on macroeconomic and other factors, it is now estimated that the country’s electricity consumption is likely to reach some 3900 GWh by the year 2020. This sets the size of the problem from a purely generating capacity standpoint. Up to now, this question of available installed capacity has been of constant importance in order to keep pace with industries’ increasing demand and, as such, it has necessitated recurrent and urgent decisions. In particular, these have concerned the past development of fuel-oil/diesel power stations and, since 1988, of gas turbine-driven plants which offered the advantage of prompt delivery. Urgent decisions, however justified, are of course not always the best as far as efficiency and costs are concerned and this has prompted the search for other sources within the concept of long-term planning. Without prejudging the conclusions of the Long Term National Energy Plan that is awaiting final completion, a study was initiated. This study was initiated in collaboration with the then Ministry of Energy, the Mauritius Sugar Authority, the Mauritius Sugar Producers’ Association, the Mauritius Chamber of Agriculture and other government and private sector bodies, to define the best way of optimizing the bagassederived energy potential of the country. This resulted in the elaboration and adoption of the Bagasse Energy Development Programme that is now being implemented in a somewhat modified form to face practical considerations but whose final objectives remain unchanged. This implementation is presented in the following section of this chapter.

Bagasse Energy Development Programme (BEDP) As already mentioned, the only departure to the role of sole electricity producer entrusted to the CEB has been the growing participation of the sugar industry in the supply of electrical energy to the grid. Started as far back as 1957, this participation took the form of individual

180 The Mauritius Experience

purchase agreements between the sugar companies concerned and the CEB, the amount of supply being initially unspecified and the unit price being the object of case-by-case negotiations. The unspecified amounts, called ‘énergie à bien plaire’ was meant to be whatever amount was available as surplus or was needed by the CEB to meet customers’ demand. Bagasse, the fibrous by-product of sugar cane that remains after juice extraction, represents some 30 per cent by weight of the cane crop from which sugar is manufactured. As such it is an important renewable source of energy which, properly managed, far exceeds the energy and process steam requirements of sugar manufacture. This high potential, up to now, has never been fully exploited and electrical energy export to the grid by sugar factories has long been considered more as a way of saving on the costly disposal of surplus bagasse than as a source of revenue. It did, however, reach 16.6 per cent of the country’s requirements by 1989 but could not keep this share 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 wasted potential which gradually led to the definition of different categories of suppliers with different conditions of supply and price rates applying. This has ensured a situation whereby, in 1996, surplus energy exbagasse has represented a record 119 GWh, or 10.3 per cent of the country’s requirements, even before the implementation of the BEDP becomes largely effective by the turn of the century. The BEDP, adopted in 1992, defines a strategy for maximizing energy production from surplus bagasse. This provides for optimization of all factories’ steam/energy balance, generation of surplus energy being assumed only by the largest units. These are termed ‘firm suppliers’ when they use bagasse during the crop season and coal during the off-crop, or ‘continuous suppliers’ when they use only bagasse during the crop season including weekends. According to this concept, ‘énergie à bien plaire’ as already defined is intended to disappear and any surplus bagasse from the smallest factories will be sold to the largest units.

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On this basis, and taking into consideration the centralization policy whereby 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 the maximum amount of surplus bagasse saved by appropriate improvement to the factory equipment, and coal during the off-crop period. At the present time of writing, two firm power units were operating and a third one will operate in the year 2000. As from 1998 it was expected that there would be not less than seven ‘continuous suppliers’. The end result by the year 2010 could be the availability of some 250 MW installed capacity, generating not less than 660 GWh ex-bagasse and 900 GWh ex-coal. The programme, as presently implemented, is based on a simple cogeneration process using a technology well known to the sugar industry but using more and more high efficiency equipment as the need for the replacement of existing plant arises. On this basis and in the context of the above mentioned centralization process, not less than 110kWh of exportable energy should be available per tonne of cane crushed. This would represent the above mentioned yearly export of 660 GWh ex-bagasse, that is, 55 per cent of the present consumption or 17 per cent of the expected consumption of the year 2020. Expressed in different terms, it also means using a clean, renewable source of energy to save the import of some 400 000 tonnes of coal or around 200 000 tonnes of fuel-oil. Regarding the policy aspect of the implementation of the BEDP, the very adoption of the Programme meant that the principle of privatization of an important part of the electricity generation sector was an accepted fact since only 1 of 17 factories (a smaller than medium unit) is government controlled. This was a valuable factor in decisionmaking at sugar groups level concerning factory closures and energy policy; it resulted, through easier negotiations, in some 10 agreements regarding supply and tariffs between sugar companies and CEB under the aegis of a Technical Committee of the MPU. Similarly, the alwaysdifficult 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 purposes other than for sugar manufacture and made payable to cane producers. The question of ownership was also made easier by the existence of the newly created Sugar Investment Trust which owns 20 per cent of the share capital of all sugar factories and whose members are the employees and cane growers of the industry.

182 The Mauritius Experience

In the case of ‘continuous suppliers’, the power stations are part of the factory equipment and owned by the sugar company itself. In the case of ‘firm suppliers’ which are much bigger stations, the same structure occurs in one case; in the others, the sugar companies form, with other partners, an independent generating company whose installations are close to the factory and which purchase bagasse from it and other factories, selling back to it process steam and energy at agreed prices. Generally speaking, contractually agreed prices between CEB and the power stations are based on avoided costs and are subject to an indexation formula. Other factors may, of course, be considered as influenced by national policy, itself dictated by strategic reasons linked to selfdependence, environment, balance of payment, and desire to help the sugar industry diversify its sources of revenue. Power installed and the amount of supplies are also the object of discussions based on the tonnage of cane crushed for crop time generation and on alternative coal burning during the off-crop to meet guarantee of supply requirements. Notwithstanding these changes, there was no modification to the structure of the CEB, which retains its role as solely responsible for transmission and distribution. In conclusion to this section it can be said that no major difficulties were encountered in the technical evaluation of the bagasse energy potential and in the definition of the guiding principles of the programme. This was largely facilitated by the national approach and by the participation of all interested parties adequately represented in the committees and subcommittees which dealt with specific problems, as well as by the acknowledged importance of the problem. The adoption and implementation of BEDP do not, however, offer complete solutions to the problems facing the electricity sector in the years to come although, with its coal alternative component, it should meet 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 following as the likely major future requirements of the sector: • The technical requirements of the sector to meet the consumer’s demand which is expected to more than triple within the next 25 years; • The choice of other possible sources of energy;

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• 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 completely separated in order to avoid repetition. Furthermore, the very word ‘future’ implies unknowns and uncertainties, and meeting long-term future requirements does mean pragmatism and correcting measures as dictated by experience and changing conditions. Future consumption is taken as present trends and what future changes may indicate. For example, the possible implementation of a light railway project intended to replace part of the existing public road transport system will mean increased electrical energy consumption but less diesel consumption and air pollution. The country will need additional installed power in the future, and maximization of renewable bagasse energy by ‘sugar’ power stations will not be sufficient. The need, therefore, exists for new sources if they exist or for planning additional fuel-oil/kerosene plants. Among new sources to be developed, those which have for many years received attention are retention of tidal water in the south of the island, solar energy, and wind energy. The first source was never studied in depth and is not now considered, while the two others are accepted as potentials, although limited. As an indication, solar energy is used solely for domestic water heating by individual consumers residing in the sunniest parts of the country and its impact on total energy consumption is negligible. Wind energy use has, however, received much attention. Experimental stations have been set up, and estimates have been made of the average potential from some 10 possible sites, which is not expected to exceed 15 GWh per year at a cost not yet known but likely to be high. Two other renewable sources of energy have also been considered lately in conjunction with the implementation of the BEDP. They consist of the possible use of other cane biomass, for example cane tops and trash as boiler fuel, and of waste product incinerators. Technically feasible, experimental projects are being conducted under the aegis of the Mauritius Sugar Authority and the use of these products, if found financially viable, would be integrated in the BEDP. The end result could be a sizeable source of energy whose use within the initial 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,

184 The Mauritius Experience

are now receiving all the attention they deserve in order to address all related issues. The integrated use of cane biomass in the BEDP ‘sugar’ power stations is of course easier to envisage as far as management and ownership are concerned, while waste product incinerators present more problems of collection, ownership and costs; these can, however, be solved. The neighbouring Réunion Island’s experience in using waste incinerators for power generation, now commercially operative, will be of great help in an eventual implementation of such a project in Mauritius within BEDP. Security of supply was also an important factor in the decision to implement the BEDP in its present form with coal as an alternative fuel for ‘firm’ suppliers. Dual-fired boilers, burning bagasse and coal, are well known to the sugar industry. Coal can be obtained from near and secure sources, and its use during the off-crop season offers firm base-load supply to the grid by using steamand electricity-generating equipment which, otherwise, would remain idle 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 to meet the outstanding demand by other sources and to replace obsolete CEB plant will always remain and has to be faced. And this brings the ultimate question about the future structure of the energy sector. The political aspect of privatization is one which is outside the scope of this chapter. We shall therefore only consider tendencies that are of public knowledge and shall draw attention to specific points of a technical nature that will have to be addressed when thinking of private energy suppliers. What is of public knowledge is that the concept of Build, Operate and Transfer, and of Build, Own and Operate is now accepted and that it may apply to the energy sector as well as to other public utilities. Independent Power Producers (IPP), as they are called, have in effect operated, as we have seen, since sugar factories started exporting energy to the grid. And the procedure to extend the formula to an IPP intended to own and operate two new 24 MW sets within an existing CEB power station was initiated for implementation in 1998. The involvement of IPPs has not materialised as the project has been abandoned 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, this aspect of privatization concerns only generation, CEB purchasing energy from the IPPs and remaining the sole responsible body for transmission and distribution. The advisability or opportunity to extend privatization to transmission and even distribution may be

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envisaged but such a change seems difficult to achieve in a small country like Mauritius where all economic and domestic sectors are so interrelated. From a strictly technical point of view, in the full knowledge of the existing public grid structure, of the need to monitor and meet growth in demand and standby capacity, of carrying out repairs and restoring supply after cyclones, it is difficult to see how security of transmission and distribution could be maintained across the country other than by a single authority. Furthermore, because of the need for a national co-ordinating action in a small country, such a coordinating authority can hardly be any institution other than a parastatal. This, of course, does not preclude the eventual necessity to reorganize the internal structure of CEB if this proves necessary or useful in the light of reduced investments and less responsibility for energy generation. All these matters are now receiving the constant attention of the authorities concerned and it is generally expected that the joint efforts of government, CEB and private sector will result in a sustained, economic and technically adapted development of the energy sector to meet the country’s requirements adequately.

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

Introduction There is probably no factor that determines the countries’ individual power sector experiences more than their economic policy framework, which includes government priorities, the order and effectiveness of policy measures. This factor is so crucial that strategy and impact of restructuring of the same industry, that is the electric utility industry, can be radically different in different countries. The country case studies presented in the foregoing chapters demonstrate the extent and degree of reform undertaken in the power sectors of these countries. It is evident from these case studies that the nature, process and implementation of power sector reform varies significantly between countries. In this chapter, an attempt is made to perform a cross-country comparison of these countries with respect to: (i) motivations for reform; (ii) the process and types of reform implemented; (iii) paths to reform; (iv) regulatory issues; (v) open competition; (vi) managing the 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 a variety of factors including policy issues as well as economic or practical considerations. One of the fundamental country characteristics is the economic policy environment in which the reform takes place. Most of the countries have undergone or are about to implement Structural Adjustment Programmes (SAPs). An aspect of this pro186

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gramme is the liberalization of the macroeconomy. In theory, when governments liberalize their markets/economy and pursue sound macroeconomic management and trade policies, both private and public 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 SAPs have put pressure on the governments to reform their public utility industries such as the power sector, telecommunication, water and postal services. The reforms, generally, aim at attracting investment and improving efficiency in the sector. The reforms are also considered a means for the power sector to grow to meet the economic growth and social improvement needs of the countries. The countries presented consider the reform as a means of addressing the inefficiencies and deficiencies in the sector. They see reform as stimulating inefficient power sector companies with high production costs to become more efficient, and also see it as a means to rectify the power sector’s inability to deliver reliable, affordable electricity services to the population, where existing demand/supply gaps limit access to electricity and affect reliability. Another motive for initiating power sector reform is the realization that the traditional multilateral sources of funding are not readily available and that alternative sources of funding, mainly from the private sector, would be the major future sources for power projects and infrastructure. Thus, the reform is designed to create an enabling environment for private investors to participate in the development and growth of the power sector. In addition there are the various international pressures on countries to liberalize their energy industries and economies in general. International accords and agreements, themselves driven by political and economic liberalization motives, have created a momentum for electricity sector reform in Ghana, Uganda, Zimbabwe and Kenya. The case studies demonstrate that reforms in these countries are largely being driven by a common theme: the need to improve efficiency and the financial performance of utilities, and the need to harness private sector capital to finance investments in power plants, transmission and distribution lines to meet the growing and unsatisfied electricity demand. While there are similarities of drivers and motivations for reform in these countries, there are, however, divergences in their responses which include: internal industry reform in Zimbabwe, deliberate reform process preceded by regulatory changes in Ghana, co-generation (as IPPs) in Mauritius, introduction of IPPs in

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Uganda, management contract and introduction of IPPs in Côte d’Ivoire.

Process of reform The unique characteristics of the electric power sector make it necessary to tackle the restructuring issue with a long-term vision. Countries in the region have different needs and thus need to fashion a reform programme which takes country-specific conditions into account. An important factor in power sector reform is the political commitment of governments to such reform. Such commitment from the political authority calls for countering the ‘myth’ and beliefs regarding the energy sector in general and the power sector in particular that are deeply ingrained in the political authority and a large section of the population. Among these beliefs, it is worth mentioning concepts such as energy self-sufficiency and energy independence, the ‘strategic’ nature of certain energy resources, and the common acceptance of arbitrary subsidies in fuel prices and electricity tariffs due to their being ‘essential inputs’. The need to counter such deeply ingrained ideas provides a strong reason to get the public informed and involved in the reform process. Generally, however, the involvement of the public has been very limited in all of the countries studied. The question of how committed these governments are to reforming their electricity industries is not easy to answer. To the extent that efforts are being made to set correct prices that reflect the cost of supply, to fill the supply gap in power generation by opening the generation segment to IPPs, and to streamline the regulatory system to provide transparency in price-setting, one can conclude that there is some commitment on the part of the governments in these countries. Such commitment has been shown, for example, in Ghana by the creation of a committee to study and recommend to government a new industry structure and the regulatory system needed, leading to the passing of legislation to establish the public utility regulatory commission. A very important aspect of such a committee’s work was to acknowledge from the outset that there were no miraculous short-term, easy, quick and low-cost solutions to the power sector’s problems, and that it is only possible to handle the tasks successfully if there is wide support from all stakeholders in the sector. In Kenya such a commitment has been shown in the passing of the Electricity Bill by Parliament. The reform process has to evolve, and the existence of well-defined goals and objectives is essential, which shows that the likely difficult

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measures to be adopted will ensure an evolution in the right direction and will bring concrete, rational, achievable, and fair solutions, rather than short-lived improvisation of high cost solutions for narrow sectors of the population. A look at the strategies adopted by the countries analysed in these cases indicates two general models of reform. The first model addresses the revenue problems of the industry within the framework of a vertically integrated utility, largely by passing management to a contractor with more autonomy from government to raise and restructure tariffs and enforce sanctions for non-payment. This model has been used in Côte d’Ivoire. The other strategy has been described as the ‘open competitive’ model. This model enforces a reorganization of the sector on a competitive basis, especially for those segments of the industry most amenable to competition (primarily generation). It also separates the segments of generation, transmission and distribution into distinct entities and offers transparent prices between them, possibly through the operation of an independent regulatory body. Theoretically, the reforms in Ghana, Kenya, Uganda and Zimbabwe will all follow this model. However, each of these countries has adopted a different approach to implementing this model, with different experiences and results. The reform process and approaches are as diverse as the six countries themselves. There has been a divergence in process ranging between internal utility reform to improve efficiency in Zimbabwe; a deliberate and formal reform process preceded by regulatory changes in Ghana; and regulatory changes subsequent to structural reform in Côte d’Ivoire. The approaches adopted range between ‘big bang’ and gradual/incremental approaches. The reforms in most of the countries were donor-driven, with varying degrees of local inputs both at the conceptual level and at the implementation level. Côte d’Ivoire, the first country to initiate a more serious reform of its power sector, essentially contracted a private company to manage and operate its state-owned, vertically integrated utility through a management contract. It further opened the generation segment of the industry to independent power producers (IPPs). Côte d’Ivoire has followed an approach of privatizing the utility first, and then gradually defining and refining the regulatory structure as the need arises. For inexplicable reasons, this defining and refining process has led to the proliferation of official institutions with overlapping functions, all with the aim of regulating and monitoring the privatized entity. Ghana, on the other hand, adopted a more measured approach to reform. It started by creating a commission to study the sector and

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recommend to government a more workable industry structure which involves: (i) the de-integration of the vertically integrated monopoly into generation, transmission and distribution companies; (ii) enacting legislation to make all power sector entities limited liability companies and (iii) the introduction of wholesale competition in the electricity market. A regulatory commission has been established to regulate the actors in the industry. This is in sharp contrast to the approach adopted in Côte d’Ivoire, especially with respect to the role of a single independent regulatory body in the reformed power sector. Another contrast is Zimbabwe. Zimbabwe’s approach focused primarily on corporate restructuring using performance contracts and commercialization to improve efficiency within the continuing operations of the state-owned vertically integrated utility. Reform of the power sector in Zimbabwe relies more on structural changes than ownership changes. While Zimbabwe Electricity Supply Authority’s (ZESA) vertically integrated monopoly structure is being maintained, the generation segment of the industry is being opened to private sector participants. The reform also involves the privatization of non-core activities of ZESA. Uganda is still in the process of formulating its reform strategy. It is envisaged that Uganda Electricity Board (UEB) would be unbundled, IPPs would be allowed into the generation segment, and the private sector would be encouraged to participate in the distribution segment in joint ventures with local governments or the national government. Kenya Power and Light Company (KPLC), which has been operating on a commercial basis for quite some time, has dominated Kenya’s power sector. It is also one of the few power sector companies in SubSaharan Africa with a history of private sector involvement. KPLC has private sector minority shareholding. External pressures from donors such as the World Bank and the International Monetary Fund have significantly pushed Kenya’s power sector reform. The reform in Kenya has involved the re-configuration of the generation facilities (hydro and thermal plants) under a separate company, Kenya Power Company (KPC). KPLC is now responsible only for transmission and distribution and, as in all of the case studies, IPPs are also involved in the generation segment of the emerging industry structure. As regards the approach to implementing reforms, Côte d’Ivoire, relatively speaking, adopted a ‘big bang’ approach. This is demonstrated by the speed with which the management of the state-owned utility company, Energie Electrique de Côte d’Ivoire (EECI), was contracted out to a private firm before the issues of regulation and supervision

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were defined. Ghana, Zimbabwe, Uganda, Kenya and Mauritius, which have adopted different reform paths (see next section for detailed discussions), have adopted a more gradual/incremental approach.

Paths of reform In view of the pressure for reform in SSA and the type of reform being advocated by some bilateral and multilateral organizations, two frequently asked questions are: ‘is there a single industry structure toward which reforms should aim?’ and ‘is there one correct approach to reform?’ The six country case studies demonstrate that there is no single successful path or approach to reform. Figure 9.1 shows the path of reforms in the six countries studied. This may be compared with the similar Figure 2.1 showing paths taken by the USA, Chile, New Zealand, and England and Wales. The vertical axis represents utility ownership and management structure, ranging between complete government ownership, public (government-owned) corporation, and private ownership. The horizontal axis represents the industry’s competitive structure, varying between vertically integrated or partially vertically integrated monopoly, multiple generators with possible competition in the generation segment selling to one common purchasing agent (normally the existing vertically integrated monopoly), wholesale competition, 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 have moved from government departments to government corporations. It is at this point that the debate on whether the reform of the industry should maintain its public ownership or to move further on to involve the private sector is being engaged. Many of the proposed changes in the power sector in SSA are in ownership/management. A change that involves the movement from public ownership to private ownership, and the main rationale for such changes, is that privatization of existing power sector companies would improve efficiency and also investment in additional capacity. The power sector entities in these countries all have a history of starting as a government department in one form or another. At the time when reform was initiated or being contemplated in these countries, all of the countries’ electric utilities were public corporations, and some still continue in this manner.

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Kenya and Côte d’Ivoire have generally followed similar paths. In both countries, government-owned vertically integrated monopolies were converted into corporations with varying degrees of private and public ownership. In the case of Côte d’Ivoire, management and operation of the state-owned vertically integrated electricity company, EECI, was contracted out to a private company, Compagnie Ivoirienne d’Electricité (CIE), under a long-term management contract arrangement, thus moving upwards (in Figure 9.1) on the ownership/management continuum from public corporation to partial privatization. CIE is majority owned by a French group, but a minority share of CIE’s stock is also traded on the Abidjan Stock Exchange. The government also maintains a minority stake. The Ivorian government also has a policy to increase the contribution of thermal power generation to the electricity supply in the country. This policy has also paved the way for IPPs to operate in the generation segment. There are currently two IPPs operating 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.

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Kenya, on the other hand, has five state-owned organizations involved in the supply of electricity. With the exception of KPLC, all of the organizations were fully state-owned entities. KPLC is the biggest of these, and its shareholdings are allocated 59 per cent for the government and 41 per cent for the private sector. KPLC is listed on the local stock exchange, and, along with CIE in Côte d’Ivoire, represents one of the only two electric utility companies with stock market listings in the six countries studied. Most of the power sector entities in Kenya have been commercialized and have introduced performance contracts as part of the country’s reform process. Figure 5.7 (in Chapter 5) shows the reform path Kenya has been following, and the future reform scenarios. Ghana, Zimbabwe, and Uganda are maintaining state-ownership of their power sector companies. As part of the reform, however, varying degrees of commercialization and performance contracts have been introduced. Ghana has passed a legislation making all the power sector companies limited liability companies. There are also plans to organize the distribution segment of the industry into different concession zones for high-, medium- and low-density areas, and either encourage private sector participation through joint ventures with the existing distribution company or grant concessions to private companies or cooperatives. Ghana envisages its electric utility landscape to be made up of both private and public operators in the generation and distribution segments of the industry. Mauritius provides a unique experience. Its electric utility has long relied on the sugar industry to generate a significant proportion of the country’s electricity supply through co-generation facilities. The stateowned Central Electricity Board, which is also responsible for transmission and distribution of electric power, has been purchasing power from the sugar industry through power purchase agreements since 1957. The ownership/management changes that have taken place to-date, with the exception of Côte d’Ivoire, are quite marginal, in the sense that there has been very limited private sector involvement in the existing power sector entities. What most of these countries are doing in terms of private sector involvement is contracting out various services, beginning with non-core activities. Perhaps this is a deliberate policy by governments to limit private sector involvement in the existing entities, but rather to encourage private sector involvement in building new generation capacity and extension and rehabilitation of transmission and distribution networks.

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Industry structural changes As can be seen in Figure 9.1, all six countries are opening the generation segment of the industry to IPPs. In fact, five of the six – Côte d’Ivoire, Kenya, Mauritius, Zimbabwe and Ghana – have IPPs already operating. Uganda is in the process of finalizing an arrangement with an IPP to develop a hydro site. However, one factor, which is not evident in Figure 9.1 is the current degree of competition, or lack thereof, at the generation level in spite of the appearance of IPPs. Most of the countries have only one IPP currently operating, though there are indications that more IPPs are about to enter the industry. In the countries where only a single IPP is operating, it is not clear whether their entry was subject to a competitive bidding process or was based on a political decision to offer a contract to one particular company. Entry by the vertically integrated utility into contractual arrangements with one or more IPPs to generate and sell electricity to the existing monopoly has thus been a major aspect of all case study countries’ reforms. This indicates a realistic approach by the countries, considering the serious shortfall in electricity supply in most countries which must be remedied at a time when governments and electric utilities face economic and financial crises. There are, however, two countries (Ghana and Kenya) where some form of competition is being introduced at the generation level involving all generators, including IPPs. Ghana is dispensing with the common purchasing agent typical of the other countries and is introducing wholesale competition in which generators compete to sell power to large customers and distribution concession monopolies through negotiated bilateral contracts and a spot market. To achieve this, Ghana has planned to unbundle its existing utility structure. Uganda also proposes to unbundle its existing electric utility and allow private investors into both the generation and distribution segments of the industry, though Uganda is not as far along this process as Ghana. Such categorization sometimes makes it difficult to place certain emerging structures. The location of Ghana, Côte d’Ivoire, Kenya and Zimbabwe in the ownership/management – industry-structure space in figure 9.1 gives the impression that these countries are restructuring their respective utilities along the lines of model 2. The reality is that, even though the introduction of IPPs has increased the number of generators operating in these countries, real competition does not exist

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among the generators. Almost all the IPPs are operating under power purchase agreements (PPA) with the government or existing state utilities. The increasing interest of the private sector to participate in the industry in SSA offers an opportunity for countries to reform their power sectors in a way that would encourage and nurture competition in the sector.

Open competition Of all the six country studies, only the case studies of Ghana and Kenya consider open competition as an aspect of the reform of their power sectors. However, an element present in all the reform strategies of the six countries – the introduction of IPPs – can be a basis for the introduction of some form of competition, possibly in the form of competition depicted by model 2. This possibility is further enhanced by the fact that the transmission systems of all the countries are interconnected with their neighbours, with the exception of Mauritius. This can be a reality only if the reforms in these countries allow large consumers and distribution companies to buy power from other generators outside their respective countries’ borders. Presently, Ghana, Kenya, Uganda, Côte d’Ivoire and Zimbabwe have agreements with their neighbours to buy or sell power. These agreements are in most cases between state-owned utilities. As these countries pursue the power market competition option, there is the need for the countries to develop their financial, legal and regulatory institutions. The rule of law must be respected and enforced, and the broader political and socioeconomic environment must be enabling to the private sector. Staying with the issue of introducing competition in the power sectors of these countries, it appears that the size of the system and the market also matter. Most of the countries presented in the case studies have systems either less than 1000 MW or just over 1000 MW, and also about 30–40 per cent of their population have access to electricity, with the exception of Mauritius which has close to 90 per cent accessibility. Thus, while any future private generation would be aiming at satisfying the suppressed demand for electricity in these countries, opportunities to sell electricity to industries and distribution companies in neighbouring countries would make investments in generation very attractive indeed for the private investors. In spite of the small size of the system in Northern Ireland, for example, competition is ensured by interconnection to the Scottish system through submarine cables.

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Regulatory issues Regulatory changes cannot be easily portrayed in the ownership/ management – industry-structure space portrayed in Figure 9.1. It is nonetheless a very important element of the reform process. Historically, the power sector in most SSA countries has been stateowned. Often, these state-owned entities have been subject to government involvement in day-to-day operations and the provision of large government subsidies. Such involvement or interference is manifested in different forms. One form of interference occurs because the various government agencies and organizations involved in particular aspects of power company operations (tariff setting, investment and environment) each have, by the nature of their functions, a particular view of the power sector. Given that each government organization plays some form of regulatory role, each organization attempts to impose its own vision (which may be in conflict with others) on the sector. On the other hand, interference can also arise through the lack of accountability of power companies’ top executives. Given the importance of their role in the national economy, these executives are often appointed by governments and usually have direct access to the highest level of political decision-making. As a result, utility executives are often able to flout ministries’ authority and operate, in effect, outside the realm of regulatory oversight. Furthermore, the power sectors in the region have been characterized by the absence of a coherent, long-term energy and institutional strategy which can exist independently from political interference. To address this, institutional and legal reforms are aimed at eliminating or considerably reducing government involvement in the daily operations of the sector. This has meant the creation of an autonomous body to regulate those segments of the sector which have natural monopoly 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 power sectors. Ghana passed a Bill in 1997 to establish an independent regulatory 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 numerous institutions performing regulatory functions. Setting up such a regulatory body involves the establishment of transparent regulatory mechanisms such as electricity tariff reform, and development of reliability, accounting, and management standards for the players in the industry,

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that is government, consumers and producers. Most importantly, the legislation establishing regulatory bodies in these countries provides for the rules of the game and the regulatory system to be transparent and predictable. Creating such a regulatory framework requires the separation between government policy and regulatory responsibilities. Uganda and Zimbabwe are also considering the possibility of creating such independent regulators, but have not yet done so. Implicit in these reform paths is the issue of whether to institute a regulatory system prior to undertaking any industry restructuring or not. Kenya and Côte d’Ivoire essentially undertook structural reforms before dealing with the regulatory issues. Ghana, on the other hand, adopted a strategy of defining the regulatory system before undertaking industry restructuring. Uganda also appears to favour the Ghanaian approach. The significance and impact of the timing of regulatory changes in these countries will only be determined in the future. Nevertheless, some discussion of the experiences of other countries may help underscore the importance of timing of regulatory changes in 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 they be implemented simultaneously? There is no simple answer to this. Different countries have adopted different strategies and have had different results. The UK, for instance, created an Office of Electricity Regulation (OFFER) shortly before divestiture of the state-owned monopoly. Chile established the National Energy Commission as an autonomous regulatory body for electricity in 1978 and introduced its regulatory laws for telecommunication and electricity and divested in 1982. Mexico introduced discretionary price regulation almost concurrently with divestiture (Galal et al., 1994). Chile was thus notable for putting an institutional framework in place long before privatization. This enabled the Chileans to acquire some experience in regulating monopolies prior to divestiture, and secondly, contributed to the reliable provision of electricity at reasonable cost to consumers (Galal et al., 1994; Spiller and Martorell, 1996). In a region where experience in utility regulation is non-existent and prospective private sector investors are wary of the unpredictability of the regulatory system, it is sensible to put a regulatory institution in place and regulate the corporatized power sector entities for a few years before divesting. This will also allay the fears of the population that public monopolies are being converted into private monopolies without a proper regulatory system in place.

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These case studies show that there is no single successful path to reforming the power sector in SubSaharan Africa, and that a wide variety of approaches to implementing the reform can yield positive results. However, some common lessons do emerge. These include the need for clarity in the envisaged industry structure, for a strong regulatory body and for clear and transparent rules and responsibilities. Equally important for successful reform in SSA are factors such as political commitment and efficient management during the transition period.

Managing the transition Having designed the overall picture for the future structure of the sector and its institutional and regulatory systems, the next over-riding concern becomes how to manage the transition to a restructured power sector. 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 the primary goal in the discussions of reforming the power sector in SSA. A critical aspect of the reform is thus how reliability of power supply can be achieved. Addressing this issue involves examining whether consumers have a way of communicating their preferences for reliability and whether the industry has the capacity to respond to these expressed 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 countries studied. Prices are set independently of service reliability, as entities in the sector are used to pricing below cost; and pricing strategies are not reliability-differentiated to enable customers to make choices. This has led to a situation where electric utilities in the region have not reflected customer preferences for quality of service in their resource planning process. This is, in part, due to the structure of the sector and how they have been managed in the past. b) What are the criteria for transmission and distribution regulation and pricing? Posing this question as a transition issue and limiting the regulatory question to only the transmission and distribution segments only presupposes that the industry will be de-integrated or unbundled and that the generation segment will be open to competition, with conse-

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quently little need for regulation. The transmission and distribution segments, on the other hand, are considered natural monopolies and therefore must be regulated to prevent misuse of market power. In fact, only Ghana is aiming at this kind of unbundled industry structure. The remaining countries are either maintaining existing vertically integrated 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 in addition to that for transmission and distribution. The key issues in pricing transmission and distribution services to enable them to perform efficiently are: pricing should be transparent, that is industry participants (suppliers and consumers) should know how the prices for different services are arrived at by the regulator; each generator should have open access to the transmission grid; and finally, for pricing to be efficient, prices must reflect the cost of service. With the endemic problem of cross-subsidization in vertically integrated monopolies, such transparent pricing mechanisms can only exist with a strong regulator and functional or accounting separation of the different segments of the vertically integrated monopoly. c) Institutional challenges There are institutional challenges that must be met during the transition. Two of these challenges are presented here. The first is to restructure existing utilities into units that can operate in a reformed industry structure. This is particularly critical to the generation segment as it is opened to competition, but there is also the need to set up an autonomous regulatory body and regulatory framework that provides incentives for efficient operation of transmission and distribution systems, as discussed above. The second challenge lies in sharing the pain of reform. The question here is ‘who will bear the cost?’ All stakeholders, including electricity suppliers, ratepayers and government, are likely to bear some costs, but experiences from countries like the UK and Chile suggest that different stakeholders bear the costs of reforms in different proportions. It is beyond the scope of this chapter to assess costs and benefits for different stakeholders; however, it is important to ensure 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

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at the workshop at which these country studies were presented. The question of ‘how to electrify the rural and low-income communities in a reformed power sector?’ was posed. This question was considered highly pertinent because it is perceived that reforming the power sector could imply the reduction or elimination of rural electrification programmes as the utilities are drained of financial resources, as the Côte d’Ivoire experience suggests. Indeed the experiences of Ghana, Zimbabwe, Kenya and Uganda all suggest that politically motivated rural electrification programmes through grid extension, in the absence of appropriate tariff structures or collection ability to recover the cost of service, have exacerbated the financial problems of all of these countries. The financial crisis of the utilities has happened in an environment where electricity tariffs have been consistently set below the cost of supply. This has been the case in Ghana, Uganda and Kenya. It is planned that such below-cost tariffs are to give way to marginal-cost pricing. Achieving commercial and financial viability of the companies operating in the reformed power sector is one of the major objectives of reform in all countries studied. Such commercialization, in theory, could help rather than hurt rural electrification programmes. By introducing commercial objectives into the management and operation of state-owned enterprises, commercialization will tend to involve the removal of subsidies, as the enterprises become subject to the same tax laws, prices and accounting rules as other companies in the private sector. When utilities are required to recover the cost of serving customers, including those in rural areas, they are more likely to adopt appropriate technologies and systems such as small-scale renewable energy which is often much less expensive than grid extension for supplying electricity to isolated rural areas. If retail tariffs accurately reflect generation, transmission and distribution costs, there will be stronger incentives to supply electricity to rural communities. In Kenya, the ineffectiveness of the official electrification programme has directly contributed to the successful development of a thriving private market for photovoltaic (PV) electricity. This success for PVs in spite of (or perhaps because of) lack of government support indicates that, even in rural areas of SubSaharan Africa, the keen demand for basic electricity service has meant that a sizeable number of Kenyans have been both willing and able to pay full market prices for electricity (Acker and Kammen, 1996). Concessions for rural electrification contracts can also be awarded which encourage the most cost-effective

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solutions and which can complement the business strategies of privatized distribution utilities. In South America this has been the case in Argentina, for example. Thus, commercialization and rural electrification are not incompatible. In fact, Kenya has implemented a 5 per cent levy on all electricity charges that will specifically fund rural electrification within the new industry structure. The issue in Kenya thus has not been lack of availability of funds, but rather accountability and control over the levied funds. Commercialization processes, which improve accountability, should also help improve the effectiveness of electrification programmes.

Energy efficiency and integrated resource planning Of the six countries studied, only Zimbabwe explicitly mentioned energy efficiency as an important part of its reform strategy, in which ZESA is both enhancing customer satisfaction and reducing peak demand through demand-side management (DSM) programmes. What role energy efficiency will play in a restructured power sector is an issue that has been much debated in developed countries such as the USA. The conventional wisdom in developed countries has been that electric utility industry reform and the advent of competition have led to the demise of integrated resource planning (IRP), in which all supply-side and demand-side investments are evaluated on an equal footing to provide energy services at lowest overall cost (see Swisher et al., 1997). However, in terms of SubSaharan Africa, looking back at Figure 9.1 indicates a very different situation compared to that of developed countries. The term ‘power sector reform’ means very different things in different countries. While such reforms may lead to complete retail-level competition in Scandinavia, the UK, or the USA (‘Model 4’), Figure 9.1 indicates that only one of the six SSA countries studied currently has any plans to move beyond Model 2, in which multiple generators sell to a common purchasing agent. This Model 2 framework is precisely the structure that existed in the USA during the 1980s and early 1990s when the concepts of DSM and IRP were developed. In fact, one of the original goals of IRP in the USA was to incorporate independent power producers such as co-generation facilities into the utility planning process. Thus, in the SSA context, there is no conflict between power sector reform and demand-side management or integrated resource planning. With the overall electric resource-planning process

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(including generation) continuing to be conducted through the common purchasing agent (i.e., the former monopoly utility), countries 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 or load-shifting. In Zimbabwe, the conclusion has been that DSM is in fact being stimulated by power sector reform. This is a result of the fact that price controls by the government are being relaxed, allowing both higher tariffs in general and the implementation of time-of-use pricing. With higher overall tariffs and time-differentiated tariffs, the incentives for customers to participate in demand reduction or demand-shifting programmes is greatly increased compared to the past when tariffs were 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 in the next century. The reform process is not always smooth, and inappropriate decisions are often made. There are no guarantees that reforms will be implemented successfully in any one country. The difficulties strewing the path of reform can be considerable, and without well-designed strategic interventions, may fall disproportionately on vulnerable groups. One of the critical issues is how rural electrification programmes can be pursued within the framework of power sector reform. There may be opportunities for cherry-picking by private investors in the absence of appropriate government intervention, but carefully implemented private sector electrification strategies may in fact provide greater accessibility at lower cost than expensive grid expansion programmes pursued in the past. Reforms that introduce competition at either the generation or retail levels, or both, do lead to cost reduction as a result of increased efficiency. However, because almost all of the countries studied have traditionally set tariffs below marginal costs, power sector reform does lead to initial increases in tariffs. The benefits of increased efficiency, on the other hand, may not be readily apparent until later. A fair and open process is thus critical to maintaining public confidence during the difficult transition period. Ensuring that the reform process does not simply lead to a changeover from public monopoly to a private monopoly, duopoly, or oligopoly remains a major task.

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Conclusion The comparative assessment of the reforms in these countries has shown that power sector reform takes different forms, and moves at a different pace in different countries. At the mundane level, we find that power sector reform in all the countries is motivated by the need to improve efficiency and to attract private capital into the industry. Ownership/management changes, structural changes and regulatory reform in the electric utility industry may well be the most interesting developments in the countries in SubSaharan Africa in the years ahead. A lot of issues are yet to be played out in countries that have embarked on reform of their power sectors. It is too early to determine successes and failure. These countries, nevertheless, offer the rest of SSA some lessons to be considered. Whether many more countries in the region are 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 of Selling Public Enterprises: An Empirical Analysis (Oxford University Press). Spiller, P. and Martorell, L. V. (1996). ‘How should it be done? Electricity regulation 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 for Integrated Resource Planning: Improving Energy Efficiency and Protecting the Environment, UNEP Collaborating Centre on Energy and Environment, Risø National Laboratory, Denmark. Working Paper No. 7, November.

10 Conclusions and Policy Summary John K. Turkson

Introduction The fundamental goal of this book has been to contribute to the ongoing debate on power sector reform in developing countries, particularly SubSaharan Africa (SSA), by presenting and analysing the reform process and implementation experiences in six countries in SSA. This task has essentially been accomplished. This chapter seeks to provide readers with a broad but necessarily tentative assessment of these experiences, and some policy-related issues that are critical to the reform of the sector. This assessment must remain tentative as many aspects of the reform in these countries have yet to be played out. Changes in the sector are taking place in the region and these changes are taking different forms. One of the main difficulties of governments undergoing market-based reforms is in first accepting and then explaining to the public the difference between the respective responsibilities of regulator and owner of facilities dedicated to the public service. To a public used to subsidized energy prices and tolerance towards energy theft, the policies of ownership and industry restructuring may be alarming. The public has a right to expect that the government in its new role as regulator is every bit as concerned for 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 providing high quality services to their customers. Power outages and voltage fluctuations are quite high in many cases. Meter-readings are infrequent and bill collection rates are very poor. This situation has con204

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tributed greatly to the financial problems of the utilities in the region, and has been a drain on the national economies as governments keep bailing utilities out of their financial crises and also the utilities’ undertaken capital investments in the sector. In the face of the dismal performance of the utilities, it is quite ironic that the impetus for reform in countries that have reformed their power sector and those considering such reforms, has come not from the public, at least not overtly, but from external sources such as multilateral and bilateral agencies. In many countries the reform of the electric utility industry has come as part of the Structural Adjustment Programmes (SAPs) that countries are implementing to correct the structural imbalances in their respective macroeconomies. In general, the focus of the reforms taking place in the region has been on ownership/management changes and attracting private investors into the industry as generators. Industry restructuring issues as well as regulatory issues are not given equal attention in the reform process. Such an attitude towards reform can cut both ways. In one respect it does not lend confidence to private investors or potential entrants into the industry, thereby denying the industry the muchneeded capital injection from the private sector. In another respect it provides opportunities to some private investors to capitalize on such an environment to demand huge concessions and guarantees from host governments for their participation in the sector. In such situations the governments end up bearing most of the risk associated with such investments without enjoying any financial returns, since all the returns accrue to the investors. Ownership/management changes and industry restructuring require major administrative and institutional capacity, and a measured approach, given the complexity of the industry. Such capacity may not be adequate in most of the countries. This point is underscored by the case of Côte d’Ivoire, where after privatization there was a rush to establish institutions to regulate and/or supervise the new actors in the industry. This led to multiplicity of structures with the sole purpose of regulating the industry.

Critical issues Notwithstanding the attractions of reforming the power sector in developing nations, the process and implementation of the reform require the examination of certain critical issues that may be peculiar to developing countries.

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Pricing of electricity in the reform environment has to reflect the cost of supply. This means some significant increase in electricity prices for all customer classes. Such price increases are inevitable consequences of the reform of the industry. They are, in fact, one of the reasons for reforming the sector. In this situation, it raises the question – how do countries handle the implementation of these price increases? For sure, such price increases could cause serious political problems for the governments of reforming countries or countries that have reformed their power sectors. A case in point is Ghana, where there was a public uproar resulting from electricity rate hikes by the electricity companies. This led to intervention by the President who ordered the suspension of the implementation of the new electricity rates. The Public Utilities Regulatory Commission, which is now duly constituted, but was not at the time of the uproar, is engaged in a series of public hearings in the country to educate and inform the different customer classes regarding the reasons for the new rates and how they are going to be implemented. Rural electrification and increasing accessibility to the majority of the population are issues that are given little attention and are seldom discussed in the reform of the sector. The Côte d’Ivoire chapter contends that the utility’s engagement in rural electrification programmes actually contributed in large measure to its financial crises that led to its privatization. How the rural electrification programme is going to be implemented in the new industry environment is not clear. Similarly, there is uncertainty as to how Ghana’s national electrification programme will be put into practice when elements of the power sector reform strategy are fully implemented. Increasing access to electricity in the countries in SSA is an integral part of the sustainable development paths that countries in the region are following. These are very important issues that remain to be tackled as the reform of the sector unfolds in the years ahead. Another element of the reform that has to be prevented is the ability of some stakeholders to influence the regulatory process to their advantage – ‘Regulatory Capture’. ‘Regulatory capture’ has always been a problem with regulated industries. Regulators are subject to ‘regulatory capture’, making them servants rather than the masters of the companies they are supposed to regulate. There have been cases where regulated firms ‘captured’ their regulators and learned to take advantage of the regulatory process, thereby earning significant returns for lowquality services. In other cases, consumer activists ‘captured’ the regulators and succeeded in obtaining services at rates insufficient to compensate investors adequately for their capital investments.

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Lessons Much has been said about potential gains from privatization and other reforms of the state-owned electric power companies. However, to date, only a few countries in SSA have reformed or initiating reforms. The majority of the countries are still to undertake reforms. What distinguishes countries that have reformed from those that have not? This is a difficult question to answer precisely because reform of the power sector in SSA is at its early stages. It is thus too soon to judge the benefits and deficiencies of the process. Nevertheless the limited experiences of the countries presented in this volume provide some significant lessons for countries in SSA contemplating a reform of their power sectors. Initiation of the reform process The reform menu normally includes institutional and regulatory reforms, commercialization and corporatization of existing power sector entities, management contracting, attracting Independent Power Producers, unbundling of the vertically integrated electric utility companies and privatization – partially or fully – these companies. Countries in the region have different needs and will thus need to fashion a reform programme tailored to their specific conditions. The experience of Côte d’Ivoire indicates that restructuring the industry without putting a regulatory system in place could create significant problems that may affect the sharing of gains from the reform. The Ivorian case study suggests that the reform was implemented in haste. This contrasts with the approach followed by Kenya, Ghana and Zimbabwe. While the items on the reform menu are sound from an economic standpoint, countries have to figure out how to initiate and manage the reform process. The unique characteristics of the electric power sector make it necessary to tackle the restructuring issue with a long-term vision. There are many changes occurring in the electric power sectors in SSA. Over the next 5–10 years, the power sectors in the region have to position themselves to meet the potential demand for electricity in the region and to support the region’s economic and social progress. In preparing to meet the challenges of the coming decade, the power sectors have to shed the negative image of inefficiency and actually have to increase efficiency. Regulatory and policy issues The experiences of the six country case studies presented in this volume suggest that these countries reformed their power sectors with

208 Conclusions and Policy Summary

varying degrees of emphasis on regulatory reform. In order to accomplish a successful reform of the power sector, governments need the political will to implement reforms. This will occur only if there is support throughout all sectors and levels of government. Governments, financial institutions and the private sector need to devise methods that allocate risks in a way that makes power sector projects competitive with those in other regions of the world. This process includes related regulatory and policy issues, such as the establishment of an independent regulatory process; reduction in subsidies to energy companies; electricity rate reform; development of reliability, accounting and management standards; and reduction in energy losses and theft. Furthermore, the rules of the game need to be well established and transparent, and made equal for state and private enterprises. The regulatory system must be transparent and predictable. In this regard, there is a need for bilateral and multilateral co-operation to help create regulatory structures, to train regulators, and to eliminate energy trade barriers among regional nations. Some of the options needed to address the issues raised include: • Independence of Regulatory Establishment: it is essential that government policy and regulatory responsibilities should be established within separate and independent institutions. The independence of the regulatory body can be further enhanced by well-functioning and independent judicial and legislative bodies. Thus any undue government influence in the regulatory process can be challenged in court, and/or the legislature can over-ride government policy that infringes on the independence of the regulatory process. A regulatory entity should be established which is independent from the executive and legislative branches of government. This entity should have fixed terms for top level regulators with appointment based on professional competence; have a professional well-trained staff; and with a mechanism for independent funding. The regulatory process must be transparent. An important element of this process is to establish basic technical, accounting, performance and legal standards for the regulated industry to ensure reliable, safe and equitable service that in turn ensure and maintain the financial viability of the industry. • Pricing and Financial Viability of Industry: the power sector should be self-financing as much as possible, with rates that recover the cost of supply, including an adequate return on investment and recognition of environmental costs. Government may provide financial assistance or cross-subsidies to ensure universal service and

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to electrify rural communities. These mechanisms, however, should be implemented within the framework of a rural electrification strategy, indicating how the mechanisms would be implemented and how long the cross-subsidies should be in place. • Development of regional electricity markets: most of the countries in SSA have small power systems and small domestic markets. Large investments in the sector could be influenced by the size of the market for power. Consequently, creating a regional electricity market that ensures electricity trading across a country’s borders could promote investment in power sector infrastructure. The government has a role in facilitating the creation of regional markets. This involves the exploration of how existing generating capacity in sub-regions of SSA can be most effectively utilized through the development of power pools or interconnected power grids. Once the markets are created, governments should allow the electricity market to operate as freely as possible on the basis of private and public enterprises and competition. Government policies and regulation should enhance electricity trading, and should be limited to establishing basic rules and procedures within which the industry must operate, and ensuring fair and open competition among all market participants. Financial issues/requirement for power project financing Issues related to financing power sector projects are of critical importance. The lack of financing is generally perceived to be one of the major constraints preventing the realization of electricity projects of all types. Many countries in SSA still experience levels of country risk that prevent them from attracting the amount of financing they need to ‘grow’ their electric utility industries. This is shown in the risks of currency devaluation, political risks and currency inconvertibility. While these are risks that are specific to the country as a whole and not the power sector, these problems affect the electricity sector especially hard since the energy sector is capital intensive with long-term life-cycle investments. High levels of country risk cause capital flows to be volatile, capital inflows to be short-term in nature, and cause there to be an inadequate amount of capital to meet demand. Countries that succeed in meeting their electricity requirements will need to solve the problem of putting their energy sectors on a sound financial footing in order to mobilize domestic and foreign capital. Power sector reform and infrastructure development remains strongly linked to domestic capital market development. There needs to be a

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better base of domestic long-term capital available. However, the reality of the situation in many countries in SSA is that there has not been a clear commitment on the part of the governments to private sector investments in the power sector, particularly in the existing state-owned electricity companies. The creation of an enabling environment – clear rules for private sector participation and clear legislative policies on the type of investments allowed – is a necessity. Countries in SSA have recognized the need to attract capital to the power sector in order to provide electricity supplies needed to support sustainable economic development and growth. Those countries that have implemented reforms have done so to place their power sector companies on a sound financial footing. However, additional steps are necessary to ensure that needed capital is available for this vital sector. Countries in SSA have to adopt a multi-pronged approach to attracting capital 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 to raise capital on their own account. In that sense sectoral reform should be accompanied by corporate strengthening of the power sector entities. This would present an opportunity for easier and possibly cheaper financing in the sense that it provides opportunities for operational efficiency gains and institutionalization of commercial business focus. All these reduce investment risks by providing additional liquidity and security to capital providers. In a commercial environment, utilities will 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 will make corporate finance of projects feasible in the region. Corporate financing relies on the attractiveness of a utility’s balance sheet and prospective cashflows to attract debt and equity. This form of financing can be used for both existing enterprises and new ones that are being created. Most power utilities in SSA have not been accustomed to the culture of corporate financing of investment projects, thus the introduction and internalization of such culture in the management of the utilities would set the basis to attract capital into the power sector. Creation of capital markets Weak and nonexistent domestic capital market and institutions have prevented the channelling of the savings to the power sector and other productive sectors of the economy. A well-functioning capital market

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can be an invaluable intermediary to financing power sector projects. Presently, there are about 10 capital markets in SSA. The Johannesburg stock exchange is by far the biggest in Africa, controlling about 92 per cent and 96 per cent of capitalization and turnover respectively, while the Nairobi stock exchange, one of the oldest in Africa, currently accounts for 2 per cent and 1.2 per cent respectively. The Ghana stock exchange, one of the youngest and fastest growing equity markets in Africa, compares favourably with the Nairobi stock exchange in terms of capitalization and turnover. Countries in SSA need to make concerted efforts to mobilize domestic savings by creating attractive investment opportunities. In spite of the negative impression, there is evidence that indigenous funds are available in Africa. The question is how to channel them to the formal sector. For example, a private sector bond issue in Cameroon in 1992 raised $9.2 million from Cameroonian nationals. Ghana mobilized approximately $60 million from domestic investors in its floatation of the Ashanti Goldfields Corporation in 1994. Countries in the region have realized the importance of creating an enabling environment to mobilize domestic resources, and attracting foreign capital. The growth of capital markets bears evidence of this trend. The Tanzanian and Malawian stock exchanges opened in late 1996. The Kampala, Uganda, stock exchange became operational at the end of 1997, and that of Mozambique is expected to be operational by mid 1999. There are indications that establishment of capital markets with conducive regulatory environment assuring the unhindered operations of private sector concerns is very important to the process of attracting capital. With such enabling environments prevailing in the region, the push for better profit and more diversification of portfolio would generate interest in developing markets. A recent research by the World Bank confirms that cross-country portfolio diversification is more important than diversifying across sectors. Similarly, the establishment of capital markets, provision of a conducive environment and the beneficial impact of wide-ranging structural reforms, legislative as well as economic, should serve to pull international private equity capital into the region. As some governments in the region have liberalized or eliminated capital restrictions, improved the flow of financial information and strengthened investor protection, they have earned the attention of the investment community. Experience has shown that private sector participation in the power sector through a well-functioning capital market will open previously

212 Conclusions and Policy Summary

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 entrants can engender in the supply chain will reduce capital and financing costs of investing in power sector projects. Mobilizing domestic savings Domestic savings are critical to the sustainability of power sector financing and indeed, financing of economic activities in SSA. In developed countries nearly 90 per cent of the savings are intermediated through financial institutions; in contrast to developing countries where the figure is around 15 per cent. In SSA domestic savings as a percentage of GDP average around 17.6 per cent between 1980 and 1988. A critical issue, however, is the capacity of financial institutions in SSA to perform the role of financial intermediation. Whether capital is raised from consumers by power utilities through realistic electricity prices or through capital market instruments from investors, the central issue is the need to tap domestic savings to mobilize enough investment funds for the power sector. Foreign investment – direct and indirect – will be seen as a catalyst of the reform process. Thus mobilizing domestic saving is critical to sustainable long-term investment financing of power sector projects in SSA. Regional power interconnection and bulk power trading Regional electric power interconnection is often economically and financially attractive. The reason why trade in electric power has not developed faster in the region may be connected with the lack of commercial objectives within the utilities themselves. Development of regional interconnection and bulk power trading is assisted in a number of respects by power sector reform. Power sector reform facilitates the development of a clear commercial mandate. This environment would reduce or eliminate fear on the part of prospective investors in the sector that electric power markets in most countries in the region are too small. The potential for exporting surplus power makes the argument of small market-size a moot one. It is relatively easy to develop systems for trading in the supply of electric power. It is in the interests of both parties, provided a framework can be agreed for sharing the benefits from trade. A concern shared by existing and potential independent power producers is the monopsony power of existing state-owned utilities. If they were faced

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with multiple purchasers, they would have greater confidence in their ability to sell power and receive fair price. This re-emphasizes the argument that power sector reform is a critical ingredient in facilitating electric power trading in the region. Other supplementary initiatives such as pricing of bulk power, transmission pricing and access, open access and wheeling of power are important to bulk power trading and as such have to be studied and mechanisms put in place to facilitate bulk power trading in the region. There is also a problem of weak domestic contract law in SSA countries and there is some doubt in the cross-border enforcement mechanisms. In view of this, mechanisms must be put in place to enforce crossborder contracts. Supplementary policies and initiatives Most utilities in the region have been exempted, by law, from income tax payment to central governments, and formal dividend payment to the equity holder(s), which are the governments in the region. Removal of these exemptions, and tax and dividend payment requirements for state-owned utilities, should be put in place as a matter of policy. While this may serve as a catalyst for utilities to pursue a commercial business focus, they remove any sources of unfair advantage existing utilities are likely to have over potential entrants into the industry. While requiring utilities to pay taxes and dividend, it must also be required that in its role as a purchaser of electricity, governments and their agencies should be subjected to exactly the same pricing and payment discipline as other customers. From the human resource standpoint, there is a need for staff planning and development. Staffing problems in the power utilities in the region can and should be addressed by proper planning and implementation 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 present situation and comparing it with achievable goals. Defining the utility’s goals requires assessing the organization structure, work practices, productivity and the appropriateness of the technology. Once this is done, a decision must be made concerning the skills that are missing in the company, and a programme designed to fill them. In the short term, it may require hiring people from outside. In the wider context of overall policy analysis, strategic planning and staffing the regulatory body, there should be a serious effort to fill positions with qualified and competent people. The physical creation of institution is only the

214 Conclusions and Policy Summary

means, but the critical aspect of institution-building is staffing them with qualified personnel. More often in SSA, certain commercial decisions within the power sector are left to government to take. This is because power sector entities are state-owned, and governments have been involved in some way in the management and operations of the entities. Elevating pure commercial and business negotiations between utilities in two countries, for instance, into the political realm often prolong negotiations and have sometimes stalled them. Political differences between countries can cause a profitable commercial venture to be abandoned. In an era where countries in the region are making every effort to attract capital into the power sector, the power sector reforms in the region should facilitate business transactions between utilities in different countries. Such business transactions could lead to the integration of the power sectors of the countries concerned through investments in the transmission segment of the industry. It is true that there is often electric power demand in countries, which generally lack energy resources, and energy resources are concentrated in other countries that have low electricity demand and low growth potential. The integration of electricity systems in SSA and the joint exploitation of energy resources are, therefore, imperative. Initiatives such as these could minimize the development and running costs of the electricity system, improve its reliability, generate savings or additional income and could strengthen the investment capacity of utilities and reduce imbalances in foreign trade accounts of countries in the region Environmental issues Issues relating to the environment were not raised in the country studies. However, as we look at the lessons of the case studies for other countries, it is worthwhile to discuss issues of the environment as they are affected by the reform of the power sector. Sustainable development of the power sector will support economic growth and improve living standards. However, sustainable development requires a balanced approach to addressing electric power needs. This includes development and implementation of an integrated approach to resource development; developing a diversified resource portfolio; and incorporating environmental and other social considerations associated with electricity production, transportation and use into resource development and electricity pricing mechanisms.

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Advanced and clean technologies for power generation are available in the industrialized countries. Thus countries, as part of the reform of their power sectors, should have environmental standards that would encourage new generators to use best available technologies that have low environmental damage. Other technologies can be used to improve the utilization and efficiency of existing generating and transmission capacity, increase reliability, availability and environmental performance of existing generating plants, and improve efficiency of end-use consumption of electricity. In addition, integrated resourceplanning and demand-side management programmes can reduce the need for additional generating capacity, thereby reducing the amount of capital investment needed to support sustainable electricity development. Furthermore, renewable energy resources offer the opportunity to obtain cleaner, more sustainable energy supplies from indigenous sources. Renewables can be exploited and deployed in many different electricity applications, in particular, non-grid applications of renewables may be attractive in addressing rural development issues. The inherent diversity and flexibility of renewables offers a number of opportunities for meeting a variety of energy needs in a sustainable and environmentally beneficial manner.

Relevance of the six-country experiences to rest of SSA These countries and the rest of SSA share a common priority with respect to the power sector, and that is to create sufficient infrastructure and generating capacity to allow rapid expansion in electricity use for economic and social development. However, countries have their own specific circumstances, which vary from country to country. Thus countries in SSA seeking to use or consider certain aspects of the experiences from the six countries should bear in this in mind. The organization and size of the power sectors in these countries vary. They are industries which are growing in terms of generation capacity, spatial coverage and improvements in reliability and quality of service. The experiences of these countries are relevant to the rest of SSA to the extent that they provide opportunities for countries contemplating reform to assess strategies used by these countries, whether their approaches to reform are relevant to them and what lessons they provide.

216 Conclusions and Policy Summary

Concluding remarks Properly designed and implemented reforms will attract investment from multilateral and private financial organizations, improve system reliability and technological diversity, increase efficiency, support rural development and electrification, and reduce environmental impacts. In order to accomplish a successful restructuring effort, governments must be willing to adopt and maintain policies which will provide a positive investment climate. The rules of the game must be clearly defined, and regulatory systems must be independent, transparent, predictable and based on well-established economic, accounting and legal principles. Impacts on the environment must also be considered in restructuring in order for the development of the power sector to be sustainable.

Index adjusted LRMC 60 affordability 3, 170 AFREPREN 104 African Development Bank 26, 32, 48, 61 agro-processing 95, 106 arbitration 45 arm’s-length regulation 173 Ashanti Goldfields 51, 68 asymmetries of information 11 auto-generators 95, 106 autonomous regulatory commission 159, 163 autonomy 127, 131, 166, 173 Ayamé 31 Azito 38, 192 bagasse 179–80 bagasse energy 183 bagasse transfer price 181 base-load supply 184 Batoka 127 big bang approach 17,190 bilateral contracting 194 billing 74, 83, 102, 154 biogas 86 black-out 97, 156, 169 BLT 102 Bobodioulasso 28 bonus and malus 37 BOO 102, 160–1, 184 BOOT 38, 102, 184 BOUYGUES 34 brown-outs 154 Bujagali 152, 167 bulk power trading 212 bureaucratic bottleneck 169 bureaucratic procedure 173 Burkina Faso 28, 56 business strategies 201 business units 51, 78 capacity charges

72

Central Electricity Board (CEB) 176–85 cherry-picking 202 CIE 26–49, 192–3 CINERGY 38–40 CIPREL 27, 34–9, 43, 192 co-generators 113, 115 combined cycle 28 commercial accounting standards 101 commercialization 13, 33, 64, 101, 105, 131, 144, 190, 200–1, 207 common carrier 67 common purchasing agent 194, 202 comparative advantage 128 competition 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 161 continuous suppliers 180–2 contractual arrangement 47, 51, 71–3, 194 Corporate Business Plan (CBP) 141, 143 corporate planning 172 restructuring 141, 190 strengthening 210 corporatization 101, 207 cost reduction 20 cost-covering tariff 170 cost-effective 121, 144, 200 cost-minimization 141, 210 cross-border enforcement 213 cross-country portfolio diversification 211 217

218 Index

cross-subsidies 114, 208 cross-subsidization 199

external borrowing external debt 52

debt finance 136 decision-makers 117 de-integration 8, 22, 78, 190, 198 demand-side 7, 135, 146 de-regulated market 68, 71, 73 deregulation 101, 130 distribution concession 50 distribution network(s) 53 divestiture 52 donor-driven 103 donor-funded 163 downsizing 169 drought 32, 53, 56, 85, 98 duopoly 202

fairness 173 fair play 22 fair price 213 financial crisis 32, 39, 200 financial intermediation 212 financial loss 83 financial market 140 financial performance 61, 96, 121, 187 firm suppliers 180–2, 184 full privatization 14

economic activity 52, 60 crisis 32 efficiency 8, 68, 74 stagnation 52 economies of scale 14, 127 EDF 30 EECI 26–49, 190 efficiency 1, 4, 6, 7, 11–15, 52, 65, 121, 127, 142, 147, 176, 179, 181, 190, 215–16 efficient enterprise model 74 efficient management 10, 198 Electricity Corporation of Ghana (ECG) 50–64, 68, 69 electricity distribution 52, 54 electricity pricing mechanism 214 enabling environment 22, 42, 165, 174, 175, 206, 210–11 energy charges 72 Energy Commission 51, 77 energy conservation 42 environment 14, 18 environmental cost 208 damage 215 performance 215 standards 215 European Investment Bank 26, 32

129

geothermal 86, 89, 95, 96 Ghana Economic Load Dispatch Centre 69 Ghana National Petroleum Corporation 54 Gitaru 94 Gokwe North 145 government guarantee 21 interference 2, 164, 173 ownership 12, 191, 192 government-owned 94, 111 grid operation code 76–8 horizontal unbundling 100 Hwange 127, 138 hydro potential 179 hydroelectric 28, 31, 36 hydrology 36, 58, 167, 169 hydropower 51, 96, 152, 162, 166, 174 Iberafrica Plant 107 illegal connection 97 incentive-based 64, 84 incentives 14, 20, 21, 60, 115, 200, 202 incremental/gradual approach 17, 18, 22, 191 independent power generators 30, 51, 164, 182 independent power producers 2, 16, 38–9, 45–6, 73, 101–15, 144–6, 160–5, 184, 187–95, 207

Index 219

independent regulators 197 independent regulatory body 156, 190, 196 indigenization 132–3 industry restructuring 6, 7, 14–17, 21, 197, 204–5 industry structural changes 1, 9, 194 industry structure 3–4, 7, 17, 23, 66, 191 inefficiencies 1, 187 inefficiency 8, 12, 131 inflationary pressure 130 infrastructure 6, 18, 38, 52–53, 74, 133, 137, 148, 152, 215 institution-building 214 institutional 8, 14, 18–19, 23, 52, 75–8, 84, 87, 96, 157, 164, 196, capacity 8 changes 19 framework 31, 45, 47, 96, 122 reform 197, 207 integrated resource planning 201 interconnected grid 98 interconnected power grids 209 internal cash generation 139 internal efficiency 131 internal inefficiencies 60 International Competitive Bidding (ICB) 27, 37–8, 114, 162 inter-regional connection 174, 212 investment-related liabilities 97

environment 75 framework 128, 156, 165, 173 systems 23 lessons 79, 117, 198, 207 liberalization 6, 19, 110, 130, 135, 169, 170 lifeline supply tariff 60, 61 load-balancing 171 load-shedding 26, 32, 98, 134, 153–5, 169, 170 long-run marginal cost 60, 105, 113, 127 long-term contracts 51, 71–3 loss-making 21 lower voltage distribution 57 low-income 3, 78, 117, 142, 161, 200 low-voltage 147, 154

Kalagala 152 Kamburu 94 Kamdini 152 Kariba dam 137 Kindaruma 94 KPC 83–120, 190 KPLC 83–120, 190, 193 KVDA 83–120

Mali 28 management 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 102 restructuring 141 standard 196 structure 127, 191 market forces 99 market rates 97 meter-reading 60, 147, 159, 171, 204 micro-hydro 153 mismanagement 32–3 monoculture-based 176 monopoly 3–17, 30, 46, 78, 160, 202 monopoly power 19 monopoly price 20 multiple purchasers 213

least-cost 72, 88, 146, 163, 166 legal 11, 125 customers 165

national electrification scheme 53 natural gas 29, 36, 39

220 Index

natural monopolies 199 net fixed assets 60, 63, 74 network losses 98 non-core activities 106, 114, 168, 190, 193 non-discriminatory 67 non-grid applications 215 non-payment 57, 124, 189 non-technical losses 57, 154 non-transparent 19, 146, 162 Northern Electricity department (NED) 50–7 off-crop period 181–4 off-peak 98 oilfields 36 oligopoly 202 Ol-Kaira 86 opaque decision-making 104 open access 16, 67, 213 open competition 186, 195, 209 open competitive model 189 operational efficiency 156 operational expenses 63 operational ratio 63–4 outsourcing 101, 114 Owen Falls Power Station (OFPS) 152–75 ownership changes 8, 83, 99, 101 ownership structure 7, 142 ownership/management 6, 168 ownership/management changes 1, 9–11, 144, 191, 193, 203, 205 ownership/management structure 1, 4, 9, 17, 23 para-statal 131–3, 140, 145, 149, 150, 177 partial privatization 14, 192 peak demand 53 peak load 31 performance contract 13, 61, 190 performance improvement programme (PIP) 128, 141 PETROCI 39, 43

political climate 171 power market 54, 64–5, 74, 106, 113 power outages 83, 104, 154 power purchase agreement 16, 71, 105, 161, 163, 180, 193 power rationing 97 power sector 1–3, 96, 98, 103–4, 111–18, 127, 138, 156, 166, 169, 172, 186, 190, 196, 200–8, 211–12 power sector infrastructure 209 power sector reform 12, 166, 186, 214 Power Sector Reform Committee 65, 79 power shortage 98, 156 prepayment meters 147 price cap 20 price rationalization 170 pricing 2, 59, 71–2, 121, 125, 175, 181 pricing mechanism 199 strategies 198 structure 180 principal–agent theoretic approach 12 private capital 8 enterprise 9, 103 equity 83 firm 11, 190 investment 50, 79, 155, 160, 170, 175 investor 38, 54, 156, 164–6, 171, 175, 187, 194, 197, 205 operators 43, 46, 48 ownership 11–12, 121, 191 power 76 sector 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,

Index 221

131–4, 145, 150, 174, 181, 190–7, 205–7 production-sharing 39 profit-making 121 property rights 11, 76 public choice 11 public enterprise 11, 13, 130, 131 public limited liability 52 public sector 1 Public Utilities Regulatory Commission 51, 69, 75–7, 81, 196, 206 rate-of-return regulation 20, 60 rate setting 60 regional connection 175 development 167 electricity market 209, 212 regulated market 68, 71, 73 regulation 1, 22, 46, 59, 189, 208 regulatory body 81, 84, 96, 118, 176, 197, 213 mechanisms 20–1, 64, 118, 196 models 21 process 21, 64, 208 responsibility 126 role 81, 155 schemes 20, 84 agency 21, 100 board 96, 108 capture 206 changes 22, 108, 111, 189, 196 commission 164, 166, 170, 187 deficiencies 19 framework 29, 64–5, 76, 89, 143, 145, 149, 155, 165–6, 173, 175, 199 function 155 law 75 powers 75–6 principles 65 reform 1, 7, 19–22, 64, 83, 203, 207–8 regimes 11, 174 systems 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 98 restructuring 2, 3, 8, 19, 32, 39, 64–5, 78, 80, 84, 121, 128, 132, 134, 144, 155, 169, 186, 216 retail competition 16–17, 191 Rift valley 153 Rio Tinto 145 rules of the game 48, 75–6, 163, 170 rural electrification 26–8, 31, 38, 42, 78, 91, 116–17, 121, 122, 148, 156, 168, 170, 186, 199–201, 206 SAUR 34 scheduled outage 70 security of supply 183–4 self-regulating 15 self-sufficient 135, 188 Sengwa 127 service charge 74 shortages 102 short-run marginal cost 71 single purchaser 10 Siskaso 28 SISP 34 size of the market 172 size of the system 195 small-scale 88, 91 social equity 2 social responsibility 142 state-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 14 structural changes 99, 159, 190, 203 subsidies 174, 208 subsidization 74 sugar-industry-based autogenerators 106, 179

222 Index

sugar producers’ association 177, 179 suppressed demand 172 sustainable development 214 system losses 97, 154 take or pay (ToP) 37, 39 TARDA 90, 92, 94–120 tariff reform 196 tariffs 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 6 technical integrity 51, 77 technical losses 154, 159 technical performance 121, 175 technological innovations 135 thermal plant 29, 51, 54, 71, 91, 147, 162–3, 190 time-differentiated tariff 202 Togo/Benin 28, 56 traditional sources 53, 103, 165 traditional structure 9, 15 transaction cost 11, 117 transferability 11 transition 13, 198 transparency 45, 64–5, 115, 145, 173, 175, 187 transparent prices 189 transparent rules 198 TRDC 94–120

Uganda Electricity Board (UEB) 153–75, 190 unbundled 19, 51, 66, 68, 190, 194 unbundled industry structure 199 unbundling 15, 83–4, 100, 104, 114, 207 uneven voltage 153 unmetered 57 unreliable 83 unscheduled outage 70 Valco 55, 58, 66, 68 vertical unbundling 100,104 vertically 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 structure 190 World Bank 26, 32, 37, 45, 48, 53, 60–6, 102–3, 132, 163, 190 ZESA

123–51, 190