POWER SECTOR 5 · Figure 2.1 overview of Tanzania’s electricity industry, 2010 52 Figure 2.2...

Joseph Kapika and Anton Eberhard

Lessons from Kenya, Tanzania, Uganda,Zambia, Namibia and Ghana

POWER-SECTORIN AFRICA

REFORM AND REGULATION

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Published by hsrC PressPrivate bag X9182, Cape Town, 8000, south Africawww.hsrcpress.ac.za

First published 2013

isbN (soft cover) 978-0-7969-2410-0isbN (pdf) 978-0-7969-2411-7isbN (epub) 978-0-7969-2412-4

© 2013 human sciences research Council

This book has undergone a double-blind independent peer-review process overseen by the hsrC Press editorial board.

The views expressed in this publication are those of the authors. They do not necessarily reflect the views or policies of the human sciences research Council (‘the Council’) or indicate that the Council endorses the views of the authors. in quoting from this publication, readers are advised to attribute the source of the information to the individual author concerned and not to the Council.

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POWER SECTOR_5.indb 2 2013/03/18 9:44 AM

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For Violet Chilufya Kapika


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Contents

Figures and tables vAcronyms and abbreviations viiAcknowledgements ixAbout the authors x

Introduction 1 Chapter 1Kenya: Enabling private-sector participation in electricity generation 21

Chapter 2 Tanzania: Learning the hard way 51

Chapter 3 Uganda: Brave reforms and new growth 85

Chapter 4 Zambia: Looking east for additional generation capacity 127

Chapter 5 Namibia: Seeking independent power producers 165

Chapter 6 Ghana: Pursuing the standard model for power-sector reform 195

References 235Index 244

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Figures and tables

FiguresFigure 1 Framework for evaluating electricity regulatory systems 9Figure 2 regulatory governance 10Figure 3 regulatory substance 13Figure 1.1 overview of Kenya’s electricity sector 23Figure 1.2 KenGen’s generation mix, Kenya, 2010 and 2018 28Figure 1.3 overview of the licensing process, Kenya, 2009 37Figure 2.1 overview of Tanzania’s electricity industry, 2010 52Figure 2.2 electricity load forecast, Tanzania, 2009–2019 54Figure 2.3 TANesCo sales compared with cost of sales and power-purchase costs, Tanzania,

2003–2009 61Figure 2.4 structure of electricity demand, Tanzania, 2002–2009 62Figure 2.5 eWUrA’s budgeted and actual income, Tanzania, 2006/07–2008/09 67Figure 3.1 overview of Uganda’s electricity sector, 2010 87Figure 3.2 Water available for electricity generation, Uganda, 2003–2008 88Figure 3.3 electricity load forecast, Uganda, 2010–2020 89Figure 3.4 Maximum demand and energy consumed, Uganda, 2002–2009 97Figure 3.5 Actual compared with target availability of electricity from the Jinja complex,

Uganda, 2003–2008 98Figure 3.6 Actual generation compared with available energy, Uganda, 2003–2008 98Figure 3.7 eskom Uganda’s financial performance, 2005–2009 99Figure 3.8 elements of eskom Uganda’s capacity payment, 2010 113Figure 3.9 Key components of Umeme’s retail tariff, Uganda, 2009 116Figure 3.10 reliability indices, Uganda, January 2006–May 2009 117Figure 3.11 outage durations, Uganda, January 2005–May 2009 118Figure 4.1 overview of Zambia’s electricity sector, 2010 128Figure 4.2 Load forecast, Zambia, 2010–2030 130Figure 4.3 electricity exports from Zambia, 1982–2008 138Figure 4.4 Maximum demand and energy consumption, Zambia, 1983–2011 139Figure 4.5 CeC purchases and total system consumption, Zambia, 1982–2009 140Figure 4.6 The erb’s actual income compared with budgeted income, Zambia, 1999–2007 147Figure 4.7 outline of the erb’s licensing process, Zambia, 2009 151Figure 4.8 summary of the erb’s licence revocation process, Zambia, 2009 152Figure 4.9 The erb’s cost-of-service model, Zambia, 2007 155Figure 5.1 overview of Namibia’s electricity sector, 2010 166Figure 5.2 NamPower’s generation capacity compared with electricity imports, Namibia,

1998–2011 167Figure 5.3 Coal costs per tonne to NamPower and average international crude oil prices,

Namibia, 1998–2011 167Figure 5.4 Maximum demand and electricity consumption, Namibia, 2002–2011 168Figure 5.5 single-buyer model for Namibia recommended in the sAd-eLeC study, 2000 174Figure 5.6 outline of the eCb’s licensing process, Namibia, 2010 181Figure 6.1 overview of Ghana’s electricity sector, 2010 197Figure 6.2 Projected maximum power demand, Ghana, 2009–2018 198Figure 6.3 Projected energy consumption, Ghana, 2009–2018 199Figure 6.4 Water inflow into the Volta reservoir, Ghana, 1965–2010 206Figure 6.5 Volta reservoir regulation, Ghana, 1995–2007 207Figure 6.6 Power-sector structure for Ghana, as proposed by synex, 1994 210


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TablesTable 1 Land area and population of Africa and selected regions, 2008 1Table 2 Generation capacity and capacity per million people in Africa and selected regions,

2008 2Table 3 standard model of power-sector reform 5Table 4 Typical peer review week 8Table 1.1 KPLC’s key performance and financial indicators, Kenya, 2000–2010 25Table 1.2 KenGen’s power plants and installed capacity, Kenya, 2011 27Table 1.3 KenGen’s performance and financial indicators, Kenya, 2005–2010 28Table 1.4 sources of erC funding, Kenya (Us$ million) 34Table 1.5 electricity generation companies licensed to operate in Kenya, 2012 39Table 2.1 installed generation capacity by plant, Tanzania, 2012 53Table 2.2 electricity tariffs, Tanzania, 1988–2000 56Table 2.3 TANesCo’s financial performance indicators, Tanzania, 2003–2009 (Us$ million) 61Table 2.4 TANesCo tariff categories, Tanzania, 2010 62Table 2.5 summary of the regulatory and rule-making powers of the minister and eWUrA,

Tanzania 65Table 2.6 eWUrA’s income by revenue source, Tanzania, 2006/07–2008/09 68Table 2.7 electricity outages by voltage level, Tanzania, January–september 2009 78Table 3.1 installed generation capacity, Uganda, 2012 88Table 3.2 UeTCL’s accumulated surplus/deficit, Uganda, 2006–2008 100Table 3.3 indicators of Umeme’s financial performance, Uganda, 2007–2011 100Table 3.4 erA’s revenue by funding source, Uganda, 2002–2009 (Us$ ’000) 104Table 4.1 installed generation capacity, Zambia, 2010 129Table 4.2 ZesCo’s financial performance indicators, Zambia, 2004–2011 140Table 4.3 indicators of CeC’s financial performance, Zambia, 2005–2011 141Table 4.4 erb fees as a proportion of total operational income, Zambia, 1998–2007 146Table 4.5 erb staff costs as a proportion of total operational income, Zambia, 1998–2007 148Table 4.6 Generation projects in the pipeline, Zambia, 2012 153Table 4.7 The erb’s projected path to cost-reflective tariffs by 2011, Zambia 155Table 4.8 ZesCo’s tariff yield (average tariff), Zambia, 2006–2011 156Table 4.9 Key performance indicators for ZesCo, Zambia, 2011–2014 157Table 4.10 spending on rural electrification projects, Zambia, 2006–2009 160Table 5.1 NamPower’s financial performance, Namibia, 2002–2011 168Table 5.2 eCb’s budgeted income, Namibia, 2006–2009 178Table 6.1 installed electricity generation capacity, Ghana, 2011 197Table 6.2 Key milestones in the electrification of Ghana up to 1964 200Table 6.3 salient features of Ghana’s power-sector development policy, 1994 209Table 6.4 Performance indicators for the Volta river Authority, Ghana, 2005–2009 212Table 6.5 Performance indicators for the electricity Corporation of Ghana, 2005–2009 213Table 6.6 Primary functions of the Public Utilities regulatory Commission and the energy

Commission, Ghana 214Table 6.7 Commissioners appointed to Ghana’s regulatory bodies 218Table 6.8 Licence duration by licence type, Ghana, 2010 221Table 6.9 expansion options for Ghana’s electricity sector, 2006–2020 223Table 6.10 Generation project pipeline, Ghana, 2012 224Table 6.11 Technical rules and regulations of the energy Commission, Ghana, until 2010 230


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Acronyms and abbreviations

List of acronymsAesNP Aes Nile PowerbsA bulk-supply agreement CAPCo Central African Power CorporationCCC Consumer Consultative Council (Tanzania)CeC Copperbelt energy Corporation (Zambia)CeNored Central red (Namibia)Ceo Chief executive officerCFL Compact fluorescent light bulbCPC Copperbelt Power Company (Zambia)drC democratic republic of CongoeAP&L east African Power and Lighting CompanyeC energy Commission (Ghana)eCb electricity Control board (Namibia)eCG electricity Company of Ghana edF Électricité du France ePC engineering, procurement and constructionerA electricity regulatory Authority (Uganda)erb electricity regulatory board (Kenya)erb energy regulation board (Zambia)erC energy regulatory Commission (Kenya)esb electricity supply board (ireland)esMAP energy sector Management Assistance Programme (World bank)eWUrA energy and Water Utilities regulatory AuthorityGCC Government Consultative Council (Tanzania)GdC Geothermal development CompanyGdP Gross domestic product GridCo Ghana Grid Company hiPC highly indebted Poor CountryhFo heavy fuel oiliCT information and communication technologyiFC international Finance CorporationiMF international Monetary FundiPP independent power produceriPTL independent Power Tanzania LtdKenGen Kenya electricity Generating CompanyKeTrACo Kenya electricity Transmission CompanyKNbC Kariba North bank Company (Zambia)KPi Key performance indicator KPLC Kenya Power and Lighting CompanyMeP Mtwara energy ProjectNamCor National Petroleum Corporation of NamibiaNeb National energy board (Ghana)Ned Northern electricity department (Ghana) NedCo Northern electricity distribution Company (Ghana)NGo Non-governmental organisation


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Nored Northern red (Namibia)NssF National social security Fund o&M operations and maintenanceoeCd organisation for economic Cooperation and developmentoPPPi office for the Promotion of Private Power investment (Zambia)PUrC Public Utilities regulatory Commission (Ghana)reA rural electrification Authority (Zambia)reb rural electrification board (Uganda)red regional electricity distribution company (Namibia)reF rural electrification Fund (Uganda)sAPP southern African Power PoolTANesCo Tanganyika electricity supply Company (later Tanzania electric supply Company Ltd)UCT University of Cape TownUeb Uganda electricity boardUedCL Uganda electricity distribution Company Ltd UeGCL Uganda electricity Generation Company LtdUeTCL Uganda electricity Transmission Company Ltd UK United KingdomUs/UsA United states of AmericaVrA Volta river Authority (Ghana) WACC Weighted average cost of capitalZesCo Zambia electricity supply Corporation

List of unitsGWh Gigawatt hourkm KilometreKm2 square kilometrekV KilovoltkVA Kilovolt-ampereskWh Kilowatt hourm Metrem3 Cubic metreMW MegawattN$ Namibian dollarTsh Tanzanian shillingUsc Us CentUs$ Us dollarUsh Ugandan shillingV VoltZMK Zambian Kwacha


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Acknowledgements

This book is the outcome of the African electricity regulator Peer review and Learning Network (Peer Learning Network), an initiative of the Management Programme in infrastructure reform and regulation (Mir) at the University of Cape Town (UCT) Graduate school of business (Gsb). The Peer Learning Network was made possible by a grant from the royal Norwegian embassy, Pretoria, south Africa.

The authors would like to thank the numerous individuals with whom we held discussions/meetings in each of the six countries covered in this volume and who made it possible to gain an in-depth understanding of power sector reform and regulation in Africa. This includes government ministers and senior officials, the boards and management of regulatory agencies, utility chief executives and their staff, existing and prospective private investors in the power sector, development finance institutions, consumer groups and media representatives.

special thanks are due to stephen Adu, silvester hibajene, haruna Masebu, Kaburu Mwirichia, siseho simasiku and Frank sebbowa who served as the chief executive officers of the regulatory agencies in the six countries covered in this volume and who were members of the Peer Learning Network during the period 2008 to 2010 when the bulk of the work on which this book is based was carried out.

Lastly the authors wish to thank Mary ralphs who edited and made comments to the initial drafts of this book.


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About the authors

Joseph Kapika is a researcher and Phd candidate with the Management Programme in infrastructure reform and regulation (Mir) at the University of Cape Town Graduate school of business. he is also the coordinator of the programme’s African electricity regulator Peer review and Learning Network. Joseph’s experience in the electric power sector spans more than 15 years. he previously worked in Zambia at the energy regulation board, the national utility ZesCo Limited and the Power division of Zambia Consolidated Copper Mines Limited (now Copperbelt energy Corporation). he holds a beng (hons) in electronics and electrical engineering from Loughborough University in england, and an Msc in economic Management and Policy from the University of strathclyde in scotland.

Anton Eberhard is a professor at the University of Cape Town, where he directs the Management Programme in infrastructure reform and regulation at the Graduate school of business. his research and teaching focus on the restructuring and regulation of the electricity and water sectors, investment challenges and linkages to sustainable development. he has worked in the energy sector for more than 30 years and was the founding director of the energy and development research Centre. Prof. eberhard has a Phd from the University of edinburgh. he is a foundation member of the Academy of science of south Africa and currently serves on the country’s National Planning Commission. Previously he served for seven years on the board of the National electricity regulator of south Africa. Prof. eberhard has more than 100 peer-reviewed publications to his credit and has undertaken numerous assignments (both locally and abroad) for governments, utilities, regulatory authorities, and donor and multilateral agencies.


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Introduction

sub-saharan Africa’s electricity sector has been in the midst of a multifaceted crisis for more than two decades, the central challenge of which has been its lack of generation capacity.1 As Table 1 shows, Africa covers an area roughly equivalent to that of Australia, europe and south America combined. Moreover, the total population of these three regions is just slightly smaller than that of the African continent. remarkably, however, Africa’s total installed electricity-generation capacity, at just 122 GW, is equal to that of France alone. if North Africa is excluded (that is, Algeria, egypt, Libya, Morocco, sudan, Tunisia and Western sahara), the figure for sub-saharan Africa drops to 77 GW; and if south Africa is excluded, installed capacity is a mere 33 GW – equal to that of sweden.2

Table 1 Land area and population of Africa and selected regions, 2008

Region Area (km2) Population (million)Africaa 30 359 049 980 europe 4 252 474 460 south America 17 809 276 390 Australia 7 617 930 22

sources: CiA (2009); UN Population division (2011)Note: a. These figures exclude Mayotte, the seychelles and st helena.

in terms of generation capacity, Africa ranks poorly even when compared with other developing regions (see Table 2). At 125 MW per million people, its generation capacity is lower than that of developing regions in Asia. Making matters worse, about 25 per cent of its capacity is unavailable due to poor servicing and maintenance (Foster & briceño-Garmendia, 2010). since the 1980s, when sub-saharan Africa’s generation capacity per million was roughly equivalent to that of southern Asia, Africa has lagged behind impressive progress in this and other regions (Foster & briceño-Garmendia, 2010).

strangely enough, there is no shortage of primary energy sources. The continent has more than its fair share. For example, the democratic republic of Congo and ethiopia are estimated to have hydropower potential of 100 GW (World bank, 2004) and 30 GW (World bank, 2006a) respectively. Furthermore, in addition to the proven reserves of oil and natural gas in Angola, Nigeria and sudan that have been exploited for many years, commercially significant discoveries of oil and natural gas have been made in recent years in Ghana, Kenya, Namibia, Uganda and Tanzania.3

The investment required to overcome the challenge of generation capacity in Africa is daunting. eberhard et al. (2011) estimated that to meet suppressed demand, keep pace with projected economic growth, and provide the additional capacity required to fulfil


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electrification aspirations, a staggering 7 000 MW in new generation capacity would be required per annum between 2005 and 2015! They noted that this would cost around Us$15 billion to build and that a further Us$5 billion per annum would be required for the rehabilitation of existing generation and transmission assets. historically, however, the expansion in generation capacity has been a fraction of this. For example, an average of just 1 000 MW per annum in capacity was added between 1995 and 2005.

Table 2 Electricity generation capacity and capacity per million people in Africa and selected regions, 2008

Region Generation capacity (MW)Generation capacity per million people (MW/million)

sub-saharan Africa (excluding south Africa) 33 116 46 sub-saharan Africa 77 191 99 Africa 122 453 125 Caribbean 21 658 522 Central America 67 687 441 south America 208 603 535 south-eastern Asia 135 632 232 south-Central Asia 302 210 175 europe 786 304 1 711

sources: Us energy information Administration (2008); UN Population division (2011)

A second feature of Africa’s power crisis is that the supply of electricity is often unreliable. At the time of writing, World bank enterprise surveys of private-sector firms revealed that sub-saharan Africa experienced 10 days of power outages in a typical month, each of which lasted an average of seven hours (World bank, 2010a).4 Clearly this comes at great economic cost through loss of business and damage to equipment. As a result, numerous firms across the continent have had to install back-up diesel generators, the running costs of which may be three times as high as that of grid-supplied electricity (Foster & steinbuks, 2008).

electricity prices in Africa also tend to be high. eberhard et al. (2011) observed that, at Us$0.12 per kWh, residential electricity in sub-saharan Africa costs about twice as much as in other developing regions and is roughly equal to that in high-income countries. For many countries, the high price of electricity is linked to their being compelled to resort to costly emergency-power rental in response to the lack of generation capacity. (There are exceptions to this, notably in southern Africa, where, in countries such as Zambia, prices have been low for many years and are only just beginning to rise as authorities seek to have tariffs match the costs incurred in delivering electricity.) remarkably, however, even in countries where tariffs are high, utilities hardly ever manage to recover their costs due to underpricing and inefficiencies in revenue collection. Poor cost recovery prevents such utilities from making the necessary investments in increasing generation capacity, expanding and reinforcing networks and thus improving quality and reliability.


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I n t r o d u c t I o n

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The situation is further aggravated by the increasing incidence of drought in regions that are dependent on hydropower, as well as high oil prices and civil war. More recently, high economic growth in some countries has led to sharp increases in demand, and this has put further pressure on the need to expand generation capacity and to refurbish and build new networks.

Under these circumstances, it is hardly surprising that access to electricity remains low. banerjee et al. (2008) estimated that in the early 2000s, overall access in sub-saharan Africa was 31 per cent. however, this figure masks significant disparities between urban and rural dwellers. For example, in Namibia urban access stands at 75 per cent, but for rural dwellers the figure drops to 10 per cent (banerjee et al., 2008). indeed, without access to electricity, which is essential for the provision of modern basic services such as health and communications, economic prosperity is likely to remain elusive for many on the continent.

In the beginning...

seek ye first the political kingdom and all else shall be added unto you. (Kwame Nkrumah, quoted in Meredith, 2006)

For much of Africa, the 1950s and 1960s were a time of great hope and optimism. The fight for liberation was bearing fruit, and new nations were being born amidst the promise of a more prosperous future. Given the incontrovertible link between electricity supply and economic growth and modernisation, it is not surprising that numerous projects to expand electricity supply and access were initiated during this period. Many of these projects were funded, at least in part, by the World bank, which has played an instrumental role in shaping power-sector policy in many countries on the continent. Uganda was among the first beneficiaries of power-sector funding from the World bank when it received Us$8.1 million in credit in 1961 towards a project to ‘build up the load on the owen Falls station by improving and expanding the existing transmission and distribution systems’ (ibrd, 1961a). As a result of such projects, availability and access to electricity increased, and in many countries the power sector became ‘better organised and performed better than most other sectors of the economy’ (World bank, 1993a). This did not last, however, and by the mid-1970s, performance had begun declining for three main reasons:• Exogenousfactorssuchasthe1970sspikeinworldoilprices, lackofaccessto

foreign capital, high interest rates and inflation;• Internal factors such as inappropriate national policies on energy pricing,

infrastructure investments, institutional development and methods of governance; and

• Enterprise-relatedfactors,includingconflictingobjectivesandlackofmanagementaccountability, which led to technical, operational and financial problems.

With the economic difficulties that much of sub-saharan Africa began to face after the 1973 oil crisis, performance deteriorated further, and by the mid-1990s the power sector was in a fully fledged crisis.


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Gutierrez (1995) identified the poor financial state of power utilities as a key problem, arguing that this prevented them from meeting the rising consumption demands of existing customers and from expanding access to electricity. The determinants of this poor financial performance were two-fold. Firstly, in terms of revenue, tariff levels were inadequate and tariff structures distorted and uneconomic. The problem was compounded by poor commercial practices such as inefficient meter reading, billing and revenue collection. secondly, cost containment was weak, with overstaffing, inefficient corporate structures, managerial deficiencies, shoddy operations, and poor maintenance of plant and equipment all commonplace. As a result, utilities had insufficient funds to fulfil their operations and maintenance obligations, let alone the required revenue to invest in meeting rising demand from customers.

With the power sector in such poor health, and based partly on reform experiences in other parts of the world, policy-makers and the donor community began to consider options for reform. in a major review of its policy towards power-sector lending in 1993, the World bank stated that: ‘Under these circumstances, neither the developing countries nor the bank can continue with a “business as usual” approach to managing the power sector’ (World bank, 1993a).

Standard model of power-sector reformCentral to the World bank’s revised policies for lending to the power sector were the following requirements for power-sector restructuring (World bank, 1993a):• Transparent regulation: There were explicit moves by countries to establish

satisfactory legal frameworks and regulatory processes, which would be independent of the power suppliers and prevent government interference in day-to-day power-utility operations; the government would retain responsibility for setting objectives and articulating overall policies and for planning and co-ordinating sector development.

• Importation of services: in some of the least-developed countries, the bank would assist in financing the importation of power services to improve efficiency; this would include management contracts, twinning with other utility companies and contracting out of specific utility services, such as plant maintenance, billing and revenue collection.

• Commercialisation and corporatisation: Power sectors in developing countries should actively pursue private-sector participation; power companies should be treated as commercial enterprises, pay interest and taxes, and earn commercially competitive rates of return on equity capital; power companies should have the autonomy to manage their own budgets, borrowing, procurement and employment conditions.

These new polices meant that World bank funding for electric power would focus on the countries with a clear commitment to improving sector performance in line with these principles. For its part, the bank undertook to use some of its financial resources to encourage and facilitate the involvement of private investors. it had been established that the key risks that private investors were concerned about


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were the security and price of fuel supplies, timely payments for the purchase of power by state-owned power companies, and possible delays in the conversion of local currency into foreign exchange. The bank undertook to help governments to develop financial mechanisms to mitigate some of these risks and to work with the Multilateral investment Guarantee Agency (MiGA) and the international Finance Corporation (iFC) in relation to sovereign risk.

by 1999, power-sector reform had gained traction, and a set of measures that came to be known as the ‘standard prescription’ or the ‘standard model’ was being widely advocated (Gratwick & eberhard, 2008). outlined in Table 3, the standard model bears significant resemblance to the principles for power-sector restructuring issued by the World bank.

Table 3 Standard model of power-sector reformMilestone DescriptionCorporatisation Transforming the power utility company into a separate legal entity (separate

from the ministry or the government), with all associated rights and obligations including governance structures; managing budgets, borrowing, procurement, labour employment, payment of taxes and dividends

Commercialisation introducing cost-recovery pricing and improvements in metering, billing and revenue collection, adopting internationally accepted accounting practices, and accounting for all subsidies

requisite legislation Passing legislation that provides a legal mandate for restructuring and allows private as well as foreign participation and ownership in the sector

independent regulator/s establishing regulatory bodies that are able to ensure efficiency, transparency and fairness in the management of the sector, as well as to prevent anti-competitive activity, incentivise appropriate investment and protect consumers

sector restructuring Unbundling incumbent (state-owned) utilities vertically and/or horizontally into separate generation, transmission and distribution companies in readiness for privatisation of (profitable) assets and the introduction of competition

independent power producers

securing new, private investment in generation, anchored by long-term power-purchase agreements

divestiture of generation assets

divesting state ownership (in part or in full) of generation assets to the private sector

divestiture of distribution assets

divesting state ownership (in part or in full) of distribution assets to the private sector

Competition introducing wholesale and retail markets

source: Adapted from Gratwick & eberhard (2008)

Experience of reformWhile it was recognised that the implementation of the standard model would not be feasible in some of the smaller countries, it is striking that almost 20 years since it was first advocated, the model has not been fully realised anywhere in Africa. reform has taken place to varying extents though, driven ostensibly by the unique circumstances of each country and its national priorities. The most pervasive features of power-sector reform have been the corporatisation and commercialisation of state-owned


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utilities and the introduction of independent regulatory bodies, which this book covers in some detail.

With reform having progressed only partially, and the envisaged end-state of the standard reform model unlikely to be reached for the foreseeable future, Gratwick and eberhard (2008) have described the emerging structure of the power sector in much of sub-saharan Africa as ‘hybrid power markets’, in which dominant incumbent state-owned utilities operate alongside independent power producers (iPPs). As a result, fledgling independent regulatory agencies have been forced to grapple with regulating power sectors structured in a manner that was not envisaged when the standard model was first advocated. Full implementation of the standard model would have meant regulators overseeing an unbundled power sector comprising mainly profit-seeking privately owned entities. in hybrid power markets, however, regulators have to contend with the dominance of state-owned utilities and devise means by which traditional regulatory tools, which are designed to incentivise privately owned profit-seeking utilities, can be adapted.

African Electricity Regulator Peer Review and Learning NetworkAt the time of writing, there were 26 regulatory agencies charged with overseeing the electric power sector in various countries across sub-saharan Africa. The oldest of these agencies had been in operation since the mid-1990s. independent regulation has therefore established a track record on the continent. For this reason, the Management Programme in infrastructure reform and regulation (Mir) at the University of Cape Town’s (UCT’s) Graduate school of business initiated the African electricity regulator Peer-review and Learning Network (afterwards referred to as the Peer Learning Network) in 2008, with the aim of developing a deeper understanding of the practice of regulation in sub-saharan Africa.

in its first phase, the Peer Learning Network comprised the electricity regulatory agencies of Kenya, Tanzania, Uganda, Zambia, Namibia, and Ghana. These agencies were chosen partly on the basis of their geographic spread and their willingness to participate in the initiative, but mainly because of the diversity they represent regarding the reforms carried out and the industry structure prevailing in each country. This volume details power-sector reform and regulation in these six countries, and draws conclusions based on discussions with members of the Peer Learning Network as well as over a hundred meetings and interviews with industry stakeholders. An account of the historical evolution of the electricity-supply industry in each country is provided, and insights into some of Africa’s most topical power projects, such as the bujagali hydropower project in Uganda, are included.

Approach

The Peer Learning Network was primarily designed to facilitate experiential learning by the Ceos of regulatory agencies, whose workload and seniority meant that they were unlikely to be available for typical classroom programmes. Learning was


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achieved through conducting in-depth peer reviews of the regulatory system in each of the countries. Five Ceos, with administrative assistance from the Management Programme in infrastructure reform and regulation at UCT’s Graduate school of business, would visit the country of the sixth Ceo, and spend an entire week analysing relevant documentation and data at the regulatory agency, as well as conducting interviews with the minister responsible for energy, board members and senior management of the regulatory agency, Ceos of regulated utility companies, private investors in iPPs, consumer groups and members of the press, among others.5 This afforded the visiting team a ‘360-degree’ view of the regulatory system that the host regulatory agency was not always able to discern. At the end of this rare exploratory opportunity, the visiting team would give initial feedback and recommendations to the board, Ceo and senior management of the regulatory agency, and after further discussion and comment, a final report would be prepared. The programme for a typical peer review week, with meetings held and issues discussed, is shown in Table 4.

The peer review process made possible an in-depth interrogation of each host regulator’s procedures and practices. during the peer review week, visiting Ceos would offer critique, share information based on their own experiences, and acknowledge issues that they were unaware of, or practices that they believed might be useful to their own institutions and power sectors. in some cases, impromptu requests were made for an official at the regulator being peer reviewed to visit another and help build capacity in a specific aspect of regulation. Though not by design, some of the Ceos found the recommendations of the peer reviews so useful that they used them as the basis for developing new strategic plans for their organisations, and in some cases consultants were hired to advise regulators on specific issues identified as requiring further attention. An important aspect of the design of the peer reviews was that meetings with external stakeholders were held in the absence of the host regulator. This allowed for frank and open discussion and provided insights into the impact and performance of the host regulatory agency that it would otherwise have been unaware of.

When the Peer Learning Network was being designed, it was understood that the rigour with which internal practices and processes at the host regulator would be interrogated could be a source of discomfort for members of the network. Without exercising some caution, the peer review process could be misconstrued as assessing the leadership that the Ceos were providing. This concern was countered by first building a high degree of trust among the Ceos through specifically tailored workshops and informal gatherings, in which they could share the day-to-day challenges and experiences of regulation in their respective countries. The exercise could easily have become one in which the regulatory agencies began ranking one another. While informal benchmarking inevitably took place through the identification of areas in which each institution was more competent than others, the focus remained on providing the Ceos with a unique and relevant learning experience through which they could each become better equipped to respond to the regulatory challenges they faced. indeed this was learning in action!


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Table 4 Typical peer review weekDay Morning meetings Afternoon meetingsMonday Minister responsible for the power sector,

senior government officials and regulatory board/commission and senior management:•Policyenvironmentandkeycountry-specific

power-sector issues•Regulatorygovernancearrangements

senior management at regulator:•Relationshipwiththegovernment•Appointmentprocessforboard

members/commissioners•Regulatoryindependence•Accountability•Transparency•Predictability

Tuesday senior management at regulator:•Licensing•Tariffdetermination•Tariffstructure•Treatmentofnewinvestment•Accountingsystems

senior management at regulator:•Networkexpansionandruralelectrification•Pro-poorregulation•Gridaccessforthirdparties•Qualityofservice•Consumercomplaintshandling•Publicoutreach

Wednesday Ceos of regulated utilities:•Demand/supplybalance•Utility’sfinancialperformance•Tariffdeterminationandstructures•Prevailingtarifflevels•Utilitytechnicalperformance•Ruralelectrification•Predictabilityofregulatorydecisions•Accountabilityofregulator•Transparencyofregulator

Ceos of independent power producers:•Tenderingandbiddingprocesses•Licensing•Power-purchaseagreementnegotiations•Power-purchaseagreementapprovals

Thursday Consumer groups (commercial, industrial, retail):•Tariffdetermination•Tarifflevelsandstructures•Pro-poorissues•Predictabilityofregulatorydecisions•Accountabilityofregulator•Transparencyofregulator

Non-governmental organisations and media:•Tariffdetermination•Tarifflevelsandstructures•Pro-poorissues•Predictabilityofregulatorydecisions•Accountabilityofregulator•Transparencyofregulator

Friday Feedback to host Ceo and board or commission and senior management of the regulator

debriefing session with Peer Learning Network members

source: African electricity regulator Peer review and Learning Network (2008)

The Peer Learning Network provided an excellent opportunity for in-depth assessments of power-sector reform and regulation in selected countries from which many lessons were gleaned. These are discussed in the six chapters that follow, where we focus on the unique features of each country’s power sector, how it has evolved over time, including reform processes, and how the sector is actually regulated. We should note that, in an effort to highlight the aspects of power-sector reform and regulation that are unique to each country, some issues are covered in more detail than others. While a single framework was applied in our analysis of how regulation is applied in each case, we made no attempt at a point-by-point comparison across the six countries.


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Evaluating regulatory systemsThe peer reviews were carried out based on an adaptation of the framework developed by brown et al. (2006) for the evaluation of regulatory systems. These authors define the regulatory system as ‘the combination of institutions, laws, and processes that give government control over the operating and investment decisions of enterprises that supply infrastructure services (2006: 17). They argue that any evaluation of such a system should take into account three interrelated dimensions as depicted in Figure 1, namely, regulatory governance, regulatory substance and regulatory impact. As these three dimensions were used to inform our analysis of each country, they are described in some detail.

Figure 1 Framework for evaluating electricity regulatory systems

Regulatory governance

Clarity of roles and functionsLegislative / legal design and institutional arrangements of regulatory system and processes of decision-making

Credibility, legitimacy and transparency of regulatory decisions

Cost-effective, reliable infrastructure services, financial viability of utilities, attraction of new investments

Quality and robustness of regulatory decisions

Content of regulation:• tariff-setting methodologies and practices• technical and commercial quality of service

standards• Pro-poor and increasing access issues

Regulatory substance

Regulatory impact

source: Adapted from brown et al. (2006)

Regulatory governanceAccording to Newbery (1997: 2), the ‘central problem of regulation is to agree a regulatory compact which assures investors that their sunk capital will be adequately rewarded, and they will be protected from populist pressure to reduce prices’. however, in the context of hybrid power markets and Africa’s overarching desire to develop as a region, pricing is not the only problem that preoccupies regulators. The need to ensure that services are reliable, utilities are viable, and new investments from both the public and private sectors are attracted is of key importance. Achieving these goals requires an institutional and legal framework through which independent regulatory decisions can be made. it is the characteristics of such a framework that define regulatory governance – the ‘how’ of regulation.

in essence, regulatory governance should limit arbitrary decision-making. This is the underlying theme of Levy and spiller’s (1994) seminal contribution in which they observe that performance can be satisfactory (that is, that sustained private-sector investment can


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take place) provided that three complementary mechanisms are put in place to restrain arbitrary administrative action, namely: ‘(a) substantive restraints on the discretion of the regulator, (b) formal or informal constraints on changing the regulatory system, and (c) institutions that enforce the above formal-substantive or procedural-constraints’ (1994: 202). This does not imply that regulators should have no discretion, but that it is crucial to establish governance procedures that allow for bounded and accountable discretion (stern & Cubbin, 2005). To achieve this, regulatory governance should provide for accountability, transparency, predictability and proportionality, as depicted in Figure 2, as these features lend credibility and legitimacy to regulatory decisions.

Figure 2 Regulatory governance

Legal framework

Clarity of roles and functions

Credibility, legitimacy and transparency of regulatory decisions

Decision-makingindependence

Financial and managementindependence

Transparency PredictabilityAccountability Proportionality

source: Authors' compilation

based on the preceding definition, regulatory governance in each of the six countries was interrogated. Without exception, each country’s regulatory authority exists as a separate legal and independent entity outside of the ministry responsible for energy and, in general, the core legislative arrangements that govern the regulators are in line with best practice. Their roles and functions are clearly articulated and the requisite powers are provided for, including licensing authority, the approval and enforcement of tariffs, the approval of power-purchase agreements, and the enforcement of quality and reliability standards.

There are some anomalies, however. For example, Ghana has two regulatory agencies. one is mandated to set tariffs and enforce standards, and the other to license power-sector participants and develop technical standards, but there are areas where their responsibilities seem to overlap, and it is questionable whether this arrangement is the best possible one. Meanwhile, in Namibia, the regulator does not have full licensing authority, and can only recommend to the energy minister that a licence be granted.


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Independence

internationally accepted best practice for ensuring independent decision-making includes defined-term limits for members of regulatory agencies (that is, members appointed to boards or commissions), as well as clear grounds upon which they can be dismissed (such as criminal conviction). in all six countries studied, the legislation contains such provisions, and the energy ministers in each country unanimously expressed support for regulation. however, there have been cases where boards have been dismissed before the end of their term through the use of parallel legislation governing state agencies – a reflection of the fact that a determined government can almost always find legal means to effect dismissals if they really want to. There has been a case in which police searched the offices of a regulatory agency in order to ascertain what was perceived to be fraud in the pricing of electricity. These examples illustrate that legislation alone is insufficient to ensure independent decision-making. Legislation thus needs to be backed by high-level and sustained political commitment.

As prerequisites for quality and robust decision-making, regulators must also be adequately resourced and able to achieve financial and management independence; that is, regulators must be able to determine the appropriate structure for their agency and to afford to hire and retain high-calibre staff. Funding through a levy on electricity sales that is passed on to consumers, is the favoured means of achieving financial independence. This mechanism provides a defined source of income that is paid for by consumers of electricity, who are the intended beneficiaries of regulation. While all six regulators studied are funded through levies, none had full authority to determine remuneration levels. Adjustments have to be made either in consultation with the government or in accordance with pre-set limits. While it is understandable that political principals are wary of handing regulators ‘a blank cheque’, this must be balanced with the need for effective regulation, for which a key prerequisite is competent staff.

Transparency

enhancing the transparency with which a regulator operates ensures that greater credibility is accorded to the regulatory process. Credibility and legitimacy are crucial for nurturing awareness among the wider community about the benefits of regulatory independence. in this respect, the Tanzanian legislation arguably represents the ‘gold standard’ for stakeholder engagement. Tanzania is unique in having a formal structure through which the public can engage with the regulator. Tanzania’s Government Consultative Council (GCC) comprises high-ranking representatives from key government ministries and the prime minister’s office. of course, it would be naïve to believe that no informal consultations occur outside of the GCC, but at least there is a forum where both the regulator and the wider public can formally be made aware of the government’s position and concerns, especially when licensing and tariff-related matters are under consideration. The GCC is augmented by the Consumer Consultative Council (CCC), a body funded from the levy on consumers; the CCC includes representatives from consumer groups as well


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as vulnerable communities. While these initiatives are commendable, the extent of Africa’s power crisis and the difficult regulatory decisions that lie ahead, particularly in relation to pricing, mean that these forums must be buttressed by sustained engagement with the wider public. regulators cannot be viewed as credible and legitimate if the public does not understand how prices are determined or the variables that drive costs.

Namibia offers another unique example of stakeholder engagement in that meetings of the regulatory board are open to the public, and its minutes are published. Public meetings may not be possible in all jurisdictions, but all regulators should at least publish their decisions (including background rationales) in a timely and regular manner if they wish to encourage public confidence and counter perceptions that regulators serve only to ‘rubber-stamp’ tariff decisions agreed upon elsewhere.

Accountability

The question of ‘who regulates the regulator?’ often crops up. it is not a trivial question. regulators are funded by public money and must therefore be accountable to the public if they wish to be viewed as credible and legitimate. in all six countries featured, the regulators prepare annual accounts that are submitted to committees of Parliament or the minister responsible for energy. Furthermore, some regulators are required to appear before committees of Parliament where pertinent matters are discussed on an ad hoc basis. Accountability could be enhanced if regulators also appeared before such committees in order to review their performance on an annual basis, for example. There also appears to be scope for ex post regulatory impact assessments to assess sector performance in relation to regulatory decisions.

Natural justice demands that parties that are aggrieved by regulatory decisions have the right to appeal to a court of law. beyond this, however, it makes sense for the regulatory system itself to incorporate an appeal mechanism to deal with such cases expeditiously. At the time of writing, of the six countries covered in this volume, only the three east African countries had regulatory systems that included specialised courts or tribunals. The others were still developing mechanisms through which appeals would be handled. There have, however, been very few appeals to date, so existing dispute-resolution mechanisms have not really been tested.

Predictability and proportionality

The regulatory system should be credible in the eyes of the electricity supply industry and potential investors, and legitimate in the eyes of consumers. one way that this can be achieved is through the assurance of its predictability. in order to achieve this, the rationale behind regulatory decisions pertaining to matters of a similar nature should be consistent with previous decisions. in the event that the regulatory agency intends to depart from this, the reasons for doing so should be announced beforehand, and interested parties should be allowed to comment on the proposed departure.


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Furthermore, regulation should not be excessive and should therefore only be exercised in the pursuit of ‘efficiency and fairness’, and ‘where regulatory actions are necessary, they should be well targeted, proportionate to the problem being addressed, and measured against the alternatives’ (brown et al., 2006: 67). The legislative framework within which regulatory agencies operate should thus reasonably enable the varying of methodologies and processes to suit specific circumstances as they arise.

Regulatory substanceregulatory substance is the content of regulation. it is also referred to as the ‘what’ of regulation. Much of the literature on the rationale for regulation is premised on the theory of natural monopoly. infrastructure industries, such as the electricity supply sector, are highly capital intensive and are characterised by large sunk and specific investments, typically with lifespans of 20 to 30 years. For some parts of the electricity industry, particularly transmission and distribution, these characteristics lead to decreasing average cost as output increases. in other words, it is less costly to have a single electricity grid as opposed to multiple grids supplying the same number of customers. Competition and its promise of bringing prices down are therefore not applicable under these circumstances. As a result, a firm with natural monopoly power could extract economic rents and price its services at a profit-maximising level. regulation is therefore viewed as a justifiable intervention through which prices can be administered by a government agency. regulators are not concerned only with tariffs and pricing, however. Facilitating market access through licensing and the setting and enforcing of quality and reliability standards are also important functions. Furthermore, given the low levels of access and the extent of poverty in Africa, regulators should incentivise increased access to electricity, and incorporate mechanisms that take the special interests of the poor into account in regulatory decisions. As Figure 3 shows, regulatory substance determines the quality and robustness of regulatory decisions.

Figure 3 Regulatory substance

Content of regulation

Quality and robustness of regulatory decisions

Market entry, licensing and

licensing process

Technical and commercial quality

of service

Tariff-setting methodologies and

practices

Social considerations, environmental

issues and energy efficiency



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The natural starting point for understanding regulatory substance is market access, which regulators control through licensing. Five of the six regulators studied have full licensing authority provided for by law. The licensing processes are described in particularly clear detail in the Kenyan and Ugandan legislation. however, all the regulators could further aid potential investors by publishing simplified versions of their licensing processes and making these available as brochures, on their websites and through other means.

Planning and procurement

The emergence of hybrid power markets presents challenges with respect to allocating responsibility for developing and enforcing a national standard related to security of supply, planning to ensure security of supply, the allocation of new build opportunities between incumbent state-owned utilities and independent power producers (iPPs), and timely procurement, negotiation and contracting. Clarity on where these responsibilities lie is an important ingredient in attracting iPPs. of the six countries studied, it is only in Kenya and Tanzania that the legislation specifically allocates responsibility for planning. in Kenya, this responsibility has been allocated by law to the regulator, which chairs a stakeholder committee for this purpose, and in Tanzania the legislation requires that this be carried by the system operator. At the time of writing, however, the power market in Tanzania had yet to be restructured, and there was no system operator. The country’s power-sector planning function was therefore in limbo.

Negotiations for power-purchase agreements

An issue debated at great length by members of the Peer Learning Network was when regulatory involvement should occur in power-purchase agreement negotiations with independent power producers. initially it was thought appropriate that regulators should become involved at the end of negotiations to review the power-purchase agreement and grant ‘no objection’ or otherwise. however, on further reflection, it was found that in many cases the capacity in terms of size of new generation plants is significant compared to existing capacity, and that given Africa’s generation-capacity problems, most new power-generation projects are viewed favourably by the authorities and the public at large well before negotiations are complete. Under these circumstances, raising objections after months, or possibly years, of negotiation is likely to be untenable, and the regulator could thus be left with no option but to ‘rubber-stamp’ the agreement. Thus to make regulatory approval of power-purchase agreements more meaningful, it may be worth considering making the regulator an observer at, but not party to, negotiations about such agreements. in this way, the regulator would gain an appreciation of the context, and potentially problematic areas could be flagged in good time. After the research for this study had been completed, such a practice was adopted in Kenya, and it will be interesting to assess whether it provides the envisaged benefits to the regulatory process.


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Tariffs

electricity tariffs in Africa are a challenging and emotive issue. in some cases they are very low, and below the cost of service, while in others they are very high relative to the quality of service provided. Yet, regardless of tariff levels, the tariffs in many countries do not recover the costs incurred in supplying electricity. All six regulators studied use the rate-of-return/cost-plus regulation method6 to determine prices and tariffs – with slight variations, such as in Ghana where price caps are applied to transmission and distribution tariffs. Although tariffs are such a topical issue, the limited extent to which regulators engaged with the public on the matter was surprising. Most of the regulators covered in this volume did not have a publicly available document that explained the tariff methodology and laid out the key drivers of cost in simple terms. Moreover, some regulatory staff seemed unsure of the finer details of the tariff methodology, which was probably a reflection of the involvement of external consultants in developing the models.

Although the rate-of-return methodology is intuitively simple, its application can be contentious. For example, utilities argued that the rates of return that regulators declared in their tariff awards were insufficient, and this was exacerbated by post-award calculations showing that actual levels of return were even lower. Another contentious issue is how to account for the valuation and depreciation of utility assets. in general, valuation can be based on three costing methods: historical costs, replacement costs and modern-equivalent asset costs. if historical costs are applied, then utilities, which typically hold a significant portion of very old assets on their books, would not earn sufficient returns on capital or depreciation to renew their assets – a situation that ultimately compromises the quality and reliability of electricity supply. however, if either of the other two methods were applied fully in any of the countries studied, tariffs would rise steeply. A gradual progression towards replacement or modern-equivalent asset values might be a more prudent approach.

Quality of supply and service

With the exception of urban Namibia, the quality and reliability of electricity supply in the countries studied was unsatisfactory. Although all the regulators had developed and published technical standards, oversight and enforcement were lacklustre. some utilities also argued that certain standards were not fit for purpose, and that compliance would require expensive retrofits and hence create further upward pressure on tariffs. There might therefore be a case for revising existing standards to make them more relevant to local contexts and then progressively raising them as utility performance improves. it is pointless to publish standards that utilities cannot adhere to and regulators cannot enforce. While acknowledging these difficulties, regulators do need to increase their monitoring capabilities. Most are simply unaware of the extent to which technical quality and reliability are poor, or whether they are improving or deteriorating.


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Pro-poor regulation

The continent’s regulators also need to take into account the unique needs of those on low incomes for whom access to electricity would improve livelihoods and potentially increase incomes, but who may simply be unable to afford the cost of a new connection let alone monthly electricity charges. The measures that regulators can use to promote access include: • imposinguniversalserviceobligationsonutilities;• definingconnectiontargetsforutilities;• callingfortheprovisionofcreditfornewconnections;• allowingfornewconnectionstobesubsidised;and• incentivisingutilitiestousetechnologiesthatareappropriateandfitforpurpose.

For low-income consumers that are already connected, regulators can promote affordability through subsidies embedded in tariff structures or through technologies that limit consumption to available incomes, such as pre-paid metering.

All six countries covered in this volume have active rural-electrification programmes that are being implemented either by the government or autonomous agencies. Generally, such programmes build grant-funded network extensions (funded by the government or donors) into rural areas and provide subsidies for new connections. The promotion of technologies such as solar energy also tends to be a feature of these programmes. regulatory involvement at this level is limited to ensuring that grant-funded assets are included in the regulatory asset base not so as to earn a return, but so that their operations and maintenance expenses are allowed for.

To promote affordability, the retail electricity tariff structure in all the countries covered (with the exception of Namibia) incorporated a lifeline tariff – whereby the first 50 or 100 units of electricity consumed were supplied free or at a subsidised rate. in all six countries, much more could be done in terms of understanding affordability. This might include determining the appropriate subsistence allowance (lifeline consumption) for electricity, and the proportion of total expenditure that this would account for in low-income households. Armed with such data, regulators would then be able to design tariff structures and enable subsidies that more effectively target those in need. There is much debate about the affordability of infrastructure services in developing countries, but ultimately such services can be financed through only two sources: fiscal transfers from the treasury or user fees charged to consumers (tariffs). Although pre-paid metering presents potential benefits for low-income consumers, in that they are perhaps better able to match their consumption with their means, its deployment by utilities is largely a response to debt management rather than a pro-poor initiative.

Environmental issues and energy efficiency

The six regulators acknowledged the need to take environmental considerations into account in their decision-making. however, such considerations were generally limited to making favourable environmental impact assessments a condition of awarding licences for generation, transmission or distribution. Most countries had


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embarked on programmes to replace incandescent light bulbs with lower-energy compact fluorescent light bulbs (CFLs) as a demand-side management measure. in general, however, there was no direct regulatory involvement in such initiatives, although the cost of providing free CFLs to consumers was regarded as one that could legitimately be recovered in the utility’s revenue requirements.

environmental matters are gathering momentum in investment decisions, particularly in relation to new power-generation projects. The experience of the bujagali hydropower project in Uganda is a case in point (see Chapter 3). obtaining funding from multilateral institutions such as the World bank for projects that are deemed to be environmentally damaging (coal-fired power stations, for example) is likely to face increasing resistance from the environmental lobby. Countries may therefore be wise to consider greener alternatives. in this regard, Kenya is making great strides; if the country’s geothermal and wind-energy ambitions come to fruition, it will meet the bulk of its electricity needs from green sources in the not-too-distant future.

Regulatory impactregulatory impact is a consequence of regulatory governance and regulatory substance. The key stakeholders in the regulatory system are consumers and utilities. regulatory impact should therefore strike a balance between the expectations and interests of these two groups. electricity consumers are ultimately concerned about having access to a reliable and competitively priced service of satisfactory quality. This is only possible, however, if utilities are financially viable, and if the electricity-supply industry is able to attract new investment. This is consistent with the views of stern, who states that the ‘key objective of economic regulation of infrastructure industries is to ensure the continuous supply, over the long-term, of unspecified infrastructure services of defined quality at the minimum necessary cost (and prices) to the population and industry of the country’ (2009: 15).

After more than 15 years of electricity regulation in Africa, what has been the impact? The quality and reliability of electricity supplies remain poor. Prices are mostly uncompetitive and not cost related. The financial viability of state-owned incumbents is often questionable, and most countries are still failing to attract sufficient independent power producers and increase generation capacity. one might therefore assume that regulation has failed. on closer inspection, however, and in spite of the complex challenges that African regulators face every day, encouraging signs of progress are beginning to emerge.

regulators have long understood the need to raise tariffs to cost-recovery levels and are making increasingly bold tariff decisions. For example, in the period 2009 to 2010, tariffs in Tanzania and Namibia increased by 18 per cent, those in Zambia by 25 per cent, and those in Ghana by 42 per cent. This means that utilities that have long complained of inadequate tariffs should become increasingly financially viable and thus be able to afford the requisite maintenance, refurbishment and system-expansion works. As consumers face higher prices, however, they will also


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demand greater reliability and quality of service. regulators need to incentivise these improvements, and the incorporation of key performance indicators into tariff awards, as pioneered in Zambia, holds promise as a means of extracting efficiency and performance gains from a state-owned utility. As the overall price of electricity increases, regulators will have to design tariff structures to ensure that each consumer category (including domestic, commercial, industrial and mining) pays only for the costs that they impose on the power system. Where subsidies are required, for example, in order to supply electricity more cheaply to poorer sectors of the population, international best practice is for these to be sourced from within the same consumer category (for example, better-off domestic consumers subsidise those with fewer means) or, better, through transparent fiscal transfers.

Progress is even evident in increasing generating capacity, Africa’s most significant power-related challenge. The experience of Kenya and Uganda, where independent power producers have become a significant portion of the generation mix over a relatively short period, should not be ignored. Clear and unambiguous allocation of planning, procurement and contracting responsibilities, including the building of capacity to undertake these functions, as well as structures that ensure equity and fairness in power dispatch, may well be crucial in resolving Africa’s power crisis.

Furthermore, investment from non-oeCd countries, especially China and india, is an increasingly important element in Africa’s quest to expand electricity-generation capacity. Projects that have long been stalled are being unlocked with funding from these new sources, including the Kariba North bank extension and the itezhi Tezhi project (both in Zambia) and the bui hydro project (in Ghana). The cynical view is that construction of such projects has proceeded based merely on the signing of a memorandum of understanding between the respective governments in exchange for commodities. in reality, while non-oeCd-funded projects appear to reach the construction phase much more rapidly than those funded by Western-backed investment companies and/or multilateral institutions such as the World bank, their project packaging is just as complex. Though beyond the scope of this volume, it will be important for future research to be carried out into how deals from this increasingly important source of funding are structured, including how risk is assessed and apportioned, how finance is arranged, and how procurement is undertaken.

Africa’s power marketsPower-sector reform in Africa has taken place in varying ways and to different extents, but nowhere has the standard model been implemented in its entirety. While there are rare examples of unbundling and divestiture, such as in Uganda, no country on the continent can boast of wholesale or retail competition in its electricity industry. instead, hybrid power markets are prevalent, state actors remain dominant, and independent power producers (iPPs) have been allowed entry to the margins of the sector. These markets raise new issues regarding how and where responsibilities for planning, procurement and contracting should be allocated.


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it is also noteworthy that in the two countries that have been the most successful in attracting iPPs, Kenya and Uganda, the generation function is separate from that of transmission, and the entity responsible for generation is in no way involved in contracting processes for new iPPs. in many countries, power-sector unbundling is seen as a precursor to privatisation, and its mere mention can provoke negative political consequences. While most countries have abandoned plans for privatisation, the unbundling of generation from power procurement and dispatch is worth considering if it is intended that iPPs should play a meaningful role in increasing electricity-generation capacity.

electricity utility regulation in Africa is still in its formative stages. While its methods are premised on decades of experience in more developed electricity markets, this volume constitutes the first study we are aware of to detail and compare the practice of electricity regulation in Africa. Undertaking this research has afforded us an opportunity to document the unique and fascinating histories of the electricity sectors in each of the six countries. We hope that this volume will provide a deeper understanding of Africa’s electricity sector and how it is regulated among a diverse audience, including regulators, utility practitioners, researchers, investors, financiers and policy-makers. Lastly, given the complexity of the issues facing Africa’s power sector, it would be naïve to suggest that regulation is all that will be required to ensure the universal provision of competitively priced, quality and reliable electricity. Clear policy frameworks, investment climates and well-structured projects are equally important. That said, we do believe that regulation can be an important element of the interventions available to those involved in responding to Africa’s enduring power crisis.

Notes1 detailed accounts of Africa’s power crisis are given in Foster and briceño-Garmendia (2010)

and eberhard et al. (2011).

2 based on 2008 Us energy information Administration data, http://www.eia.gov/

3 biryabarema e, This thing called oil, Daily Monitor, 2 July 2006, http://allafrica.com/stories/200607030365.html; iddrisu A, oil at last, The Accra Daily Mail, 18 June 2007, http://allafrica.com/stories/200706190564.html; Kruger A, Namibia: implications of oil find, AllAfrica.com, 26 July 2011, http://allafrica.com/stories/201107261659.html

4 see http://www.enterprisesurveys.org

5 The interests of residential consumers, including those not yet on the grid, were considered to be included by our meetings with consumer groups, and unions were represented among the non-governmental organisations we met.

6 That is, rr = rAb × ror + e + d + T where rr = revenue requirement, rAb = regulatory asset base, ror = rate of return, e = operations and maintenance expenses, d = depreciation and T = taxes.


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Kenya: Enabling private-sector participation in electricity generation

inadequate electricity-generation capacity and an unreliable power supply have been perennial problems in Kenya for over a decade. As in other African countries, a lack of integration between planning and implementation has plagued the industry. For example, a 328 MW expansion in capacity planned for the period 1996 to 2000 saw only 205 MW actually being installed, leaving a significant shortfall (Nyoike, 2002). in recent years, however, power sector reforms have led to greater co-ordination between planning and implementation, and hence an increasing number of independent power producers (iPPs) and public sector-funded capacity-expansion projects are being developed.

hydropower has long dominated Kenya’s generation capacity; in 2010 it supplied almost 55 per cent of the country’s electricity. however, severe droughts in the 1990s virtually paralysed the industry, and the drought of 1999 was the worst since 1949, leading to a 79 per cent decrease in hydro capacity between July and december of the following year1 (Nyoike, 2002). The effect of the droughts was widespread power cuts, and commerce and industry consequently suffered significant losses. ironically, the effect of the power outages on domestic consumers was mitigated by the fact that only 18 per cent of Kenyan households had access to electricity.

in response to what seemed to be perennial drought, the Kenyan government in 1997 commissioned two iPPs with combined capacity of 100 MW. When the 1999 drought exacerbated existing problems, an additional 105 MW of emergency thermal generation was deployed in 2000.2 These two interventions proved costly, and the price paid by consumers for electricity rose considerably. electricity prices in Kenya remain higher than those in much of east and southern Africa. At the time of writing, however, prices were deemed to reflect the cost of producing and delivering electricity to end consumers. Although the countries in these two regions have stated ambitions for their tariffs to be cost reflective, this goal remains elusive for most of the countries.

While the persistent drought forced the government to introduce stopgap measures, a more fundamental reform of the electricity sector had, in fact, been initiated in 1996. This saw the establishment of an independent regulator, and the unbundling and liberalisation of the electricity sector (described in more detail later in this chapter). As a result, by 2011 Kenya had been able to attract a significant 347 MW of generation capacity from iPPs (that is, 23 per cent of installed generation capacity), which at the time was more capacity from iPPs than any other sub-saharan African country. Furthermore, at the time of writing, plans for a further six iPP developments had reached an advanced stage. These were for three medium-speed diesel plants that were the outcome of an international competitive-bidding process, two wind-power plants that were being contracted on an unsolicited basis and the extension to an

1


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existing geothermal iPP plant. The combined contribution of these proposed plants would add a total of approximately 700 MW3 to the country’s installed generation capacity. This, coupled with capacity expansion, reinforcement and electrification being undertaken by the two dominant utilities, the Kenya electricity Generating Company (KenGen) and the Kenya Power and Lighting Company (KPLC),4 means that Kenya is making progress towards overcoming the challenge of inadequate and unreliable electricity supply.

This chapter first outlines the growth and role of the key players in Kenya’s electricity industry. We then attempt to analyse whether the country’s electricity regulatory system has contributed to strengthening the industry, and to highlight areas that would benefit from further attention.

Kenya’s electricity industryThe structure of Kenya’s electricity-supply industry can be traced back to the reforms that swept the industry in the mid-1990s. A policy paper on economic reforms (Government of Kenya, 1996) set out the government’s intention to separate the regulatory and commercial functions of the sector, facilitate restructuring and promote private-sector investment. Consequently, the electric Power Act of 1997 was passed. The government’s primary function, through the Ministry of energy, became policy formulation, and its regulatory authority was devolved to the newly established electricity regulatory board (erb), which became functional in 1998 (see eberhard & Gratwick, 2005). At industry level, rationalisation and unbundling translated into a redefinition of the scope of KPLC’s activities such that it now focuses only on the transmission and distribution5 of electricity, while KenGen, which was established in 1997, has taken over all the generation activities that KPLC had previously managed. While a number of iPPs have subsequently entered the industry, KenGen and KPLC (which are both referred to as state-owned entities even though they have significant private shareholding) remain the dominant players.

in its 2003 strategy document on economic recovery, the government expressed its dissatisfaction with the performance of the sector (Government of Kenya, 2003), conceding that electricity in Kenya remained unreliable and expensive despite the reforms that had been introduced. To remedy this, the strategy recommended measures to deepen reforms in the power sector. These were subsequently detailed in the national energy policy of 2004 (Government of Kenya, 2004). This included an action plan for the period 2004 to 2007 that set out the government’s commitment to:6• establish a rural electrification authority;• facilitate the development of a competitive market structure for the generation,

supply and distribution of electricity;• establish the Geothermal development Company (GdC) to undertake an assessment

of Kenya’s geothermal resources, including steam-field appraisal and development;• enact new legislation to, among other things, dissolve the electricity regulatory

board and create a new energy-sector regulator, the energy regulatory Commission (erC);


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K e n ya : e n a b l i n g p r i vat e - s e c t o r pa r t i c i pat i o n i n e l e c t r i c i t y g e n e r at i o n

23

• increase the rural electrification rate to 10 per cent per annum; and• partially privatise KenGen through an initial public offering of 30 per cent of its

equity through the Nairobi stock exchange.

by 2011, most of these measures had been implemented; exceptions were the development of a competitive market structure and the ambitious rural-electrification target. in addition, in late 2008 the government incorporated the Kenya electricity Transmission Company (KeTrACo) to construct, operate and maintain new, publicly funded, high-voltage electricity transmission networks.

The emergence of the key players in the electricity sector is briefly described, and Figure 1.1 provides an overview of the structure of the industry.

Figure 1.1 Overview of Kenya’s electricity sector

Ministry of Energy

Energy Regulatory Commission (ERC)

Rural Electrification Authority (REA)

Geothermal Development Company (GDC)

Consumers

Kenya Electricity Transmission Company (KETRACO)

Kenya Electricity Generating Company (KenGen)

Independent power producers

Kenya Power and Lighting Company (KPLC)

Industry

source: Authors' compilationNote: GdC drills steam-wells, and the actual power generation is done either by KenGen or iPPs.

Kenya Power and Lighting Company

KPLC’s history dates back to 1922 when the Mombasa electric Power and Lighting Company merged with the Nairobi Power and Lighting syndicate to form the east African Power and Lighting Company (eAP&L). A decade later, eAP&L extended its geographical reach with the acquisition of a controlling stake in the Tanganyika electric supply Company (TANesCo). eAP&L attained its maximum reach across east Africa in 1936, when it acquired a licence to generate and


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distribute electricity in Uganda. This lasted only until 1948, however, when the Ugandan government established its own vertically integrated Uganda electricity board. eAP&L’s geographical spread was further curtailed in 1964 when it sold its stake in TANesCo to the Tanzanian government. Acknowledging that its operations had been confined to Kenya, eAP&L was renamed the Kenya Power and Lighting Company in 1983.7 As already mentioned, Kenya’s electricity industry was unbundled in 1997. since then, KPLC has been responsible only for the transmission and distribution of electricity in Kenya.8

KPLC is still partially privately owned, although its largest shareholder is the government of Kenya with a stake of 50.1 per cent. For this reason, the company is considered a parastatal or state-owned enterprise, and it is subject to the requirements of the state Corporations Act of 1987 (as revised in 2009), which governs state-owned enterprises in Kenya, in addition to the reporting and corporate governance tenets prescribed by the Nairobi stock exchange.

Key indicators of KPLC’s performance over the ten-year period 2000 to 2010 are shown in Table 1.1. in 2004, the company emerged from a period of sustained loss-making and has remained profitable since then. since its return to profitability in 2004, revenues from sales have increased by over 200 per cent. however, this increase disguises the fact that the base tariff (that is, when fuel pass-through costs are stripped from the average retail tariff) has been relatively stagnant in nominal terms. The only significant change to the base tariff occurred in 2009 when the erC approved an increase of around 30 per cent following a tariff application from KPLC that was partly motivated by the coming into force of a new set of power-purchase agreements with KenGen.

The impact of drought on the Kenyan electricity supply industry is apparent from the extremely low annual sales/consumption figures in 2000 and 2001; operations at Kenya’s hydro plants were severely curtailed by the lack of water, and power was simply unavailable.10 The reduced growth rates for both demand and sales in 2003, 2006, 2008 and 2009 can also partly be linked to low rainfall levels. The violent aftermath of the 2007 elections, which depressed economic activity, was another factor in the lower sales and demand recorded in 2008 and 2009. system losses, comprising both technical and commercial losses, have been steadily reduced since peaking at 21.5 per cent in 2000. KPLC’s stated target of 14.5 per cent by 2005, with additional annual reductions of 1 per cent thereafter (KPLC, 2003), has remained elusive, however.

The target date for reaching this level has since been revised to 2013 (Ministry of energy of Kenya, 2010). These figures may seem high by international standards, but in Africa it is not uncommon for total losses to be well in excess of 20 per cent (see also Chapter 3 on Uganda).


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Tabl

e 1.

1 K

PLC’

s key

per

form

ance

and

fina

ncia

l ind

icato

rs, K

enya

, 200

0–20

10

Perf

orm

ance

indi

cato

rs20

0020

0120

0220

0320

0420

0520

0620

0720

0820

0920

10Pe

ak d

eman

d (M

W)

708

724

760

786

830

884

916

987

1036

1070

1107

Ann

ual d

eman

d gr

owth

(%)

(3.5

)2.

3

5.0

3.

4 5.

6 6.

5

3.6

7.8

5.0

3.3

3.5

el

ectr

icity

pur

chas

ed (G

Wh)

4 4

61

4 08

1 4

564

4 75

0 5

035

5 34

7 5

697

6 16

9 6

385

6 46

3 6

665

elec

tric

ity sa

les/

cons

umpt

ion

(GW

h)3

504

3 21

2 3

628

3 80

1 4

090

4 37

9 4

580

5 06

5 5

322

5 43

2 5

624

Ann

ual s

ales

/con

sum

ptio

n gr

owth

(%)

-5.7

-8.3

13.0

4.8

7.6

7.1

4.6

10.6

5.1

2.1

3.5

syst

em lo

sses

(%)

21.5

21.3

20.5

20.0

18.8

18.1

19.6

17.9

16.6

16.0

15.6

Fina

ncia

l ind

icat

ors

Fu

el c

osts

(U

s$ m

illio

n)—

—77

.71

51.6

4—

85.0

016

3.0

196.

925

3.6

373.

143

4.5

Fuel

cos

t per

uni

t of t

otal

pu

rcha

sed

ener

gy (U

sc/k

Wh)

——

2921

—36

5153

5859

62en

ergy

-pur

chas

e co

sts (

Us$

m

illio

n)—

—26

4.5

245.

8—

236.

931

9.8

371.

343

5.6

637.

170

0.5

Aver

age

gene

ratio

n ta

riff (

Usc

/kW

h)—

—5.

85.

2—

4.4

5.6

6.0

6.8

9.9

10.5

reve

nue

from

ele

ctric

ity sa

les

(Us$

mill

ion)

308.

835

8.6

315.

630

2.8

294.

636

5.8

462.

753

9.5

620.

885

8.3

953.

9Av

erag

e ba

se ta

riff (

less

fuel

pa

ss-t

hrou

gh c

osts

) (U

sc/k

Wh)

8.8

11.2

8.7

8.0

7.2

8.4

10.1

10.7

11.7

15.8

17.0

Aver

age

reta

il ta

riff (

Usc

/kW

h)8.

811

.27.

06.

97.

26.

87.

27.

57.

710

.010

.4

Prof

it be

fore

tax

(Us$

mi ll

ion)

-33.

7-5

2.2

-36.

2-5

3.8

11.1

25.6

34.1

37.7

41.7

63.0

77.6

sour

ces:

KPL

C A

nnua

l rep

orts

and

Fin

anci

al s

tate

men

ts, 2

002/

03, 2

005/

06–2

010/

119

Not

e: C

erta

in fi

nanc

ial i

ndic

ator

s for

200

0, 2

001

and

2004

wer

e no

t ava

ilabl

e at

the

time

of w

ritin

g.


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Kenya Transmission Company

As stated earlier, KeTrACo, which was established in 2008, is a relatively recent entrant to the transmission portion of the industry. The establishment of KeTrACo was premised on the need to overcome the difficulties that KPLC’s ownership structure (private and state) created in relation to the government’s plans for the development of the electricity grid. Mixed ownership had ostensibly increased the level of commercial discipline, aided cost containment and efficiency, and enhanced the profitability of the sector. however, being partly privately owned does present a potential barrier to raising public and donor funds for the expansion of the transmission grid. in addition, in the event of the Kenyan authorities deciding to unbundle the sector further by separating KPLC’s transmission and distribution businesses, KPLC’s ownership structure is likely to increase the complexity and costs of such an undertaking. To overcome the potential difficulties that KPLC’s ownership presents, the wholly state-owned KeTrACo was set up to undertake all new transmission projects. KeTrACo’s role in the Kenyan power sector was summed up by senior government and industry officials who stated that, ‘The transmission grid is like the roads network. building new roads is government’s responsibility. That will be KeTrACo’s role.’11 While KeTrACo’s mandate is to design, construct, operate and maintain new high-voltage electricity-transmission lines, at the time of writing it was still unclear whether it would also take over KPLC’s system operations and planning functions. either way, KeTrACo’s roles and responsibilities need to be clearly distinguished from those of KPLC.

Kenya Electricity Generating Company

KenGen traces its history back to 1954 when the Kenya Power Company (KPC) was formed (KenGen, 2010). KPC was set up to construct an electric power interconnector to transmit power from the owen Falls Power station in Uganda and to develop electricity generation facilities in Kenya. From its inception, KPC was operated by KPLC through a management contract. This arrangement continued until 1997, when the electricity industry was unbundled. KenGen was then established and incorporated KPC’s generation assets.

KenGen remained wholly state-owned until 2006 when it was partially privatised. This was in line with the government’s 2003 economic strategy, which acknowledged that electricity supply in Kenya was expensive and unreliable and that some form of public–private partnership would be necessary to ‘mobilise the investment needed for expanding generation capacity’ (Government of Kenya, 2003: 20). Consequently, 30 per cent of the company’s equity was floated on the Nairobi stock exchange in 2006. The initial public offering, which was oversubscribed by 233 per cent, raised Ksh26 billion (Us$325 million) (Njoroge, 2006). At the time, it was the largest-ever initial public offering on the Nairobi stock exchange.12

The success of the share offer meant that both KenGen and KPLC were listed on the local stock exchange and their shares were publicly traded. This is an unusual


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ownership structure for state-owned utilities in Africa and has two important implications. Firstly, the two utilities are obliged to adhere to the reporting and governance requirements of the stock exchange. secondly, although their private shareholders are profit seeking, they are also consumers of electricity who expect a quality, reliable and competitively priced service.

Generation capacity

KenGen’s installed capacity as at June 2011 was 1 180.8 MW, 65 per cent of which was supplied from hydropower,13 as shown in Table 1.2. due to the occurrence of drought, Kenya’s dependence on hydro-generation represents a risk not only to the country’s electricity supplies but also to KenGen’s future revenue stream. This, and the ever-present need to increase capacity, have led KenGen to plan for the diversification of its generation mix over the medium term, and hydropower is expected to account for just 28 per cent of KenGen’s installed capacity by 2018. As shown in Figure 1.2, increased exploitation of the country’s geothermal and wind-energy resources is expected to drive this diversification.

Table 1.2 KenGen’s power plants and installed capacity, Kenya, 2011

Hydro MW Thermal MW Geothermal MW Wind MWGitaru 225.0 Kipevu i diesel 73.5 olkaria i 45.0 Ngong 5.5Kiambere 164.0 Kipevu iii diesel 120.0 olkaria ii 105.0Turkwel 106.0 Kipevu gas turbines 60.0Kamburu 94.2 Garissa and Lamu 8.9sondu Miriu 60.0Kindaruma 40.0Masinga 40.0Tana 20.0other (small) 13.7subtotal 762.9 262.4 150.0 5.5Total MW 1 180.8

source: KenGen (2011)14

Geothermal energy in Kenya has the potential to provide an abundant, reliable and relatively environmentally friendly source of electricity. A portion of the east African rift runs through Kenya and contains more than 14 high-potential geothermal sites with estimated capacity of between 7 000 and 10 000 MW, of which only 202 MW has been exploited. To fast-track the development of this resource, the Kenyan government established the Geothermal development Company (GdC) in 2008 as a wholly state-owned enterprise. GdC’s main role is to conduct surface exploration and to drill steam-wells. GdC plans to drill wells sufficient for the generation of up to 5 000 MW by 2030 (GdC, 2012).


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Figure 1.2 KenGen’s generation mix, Kenya, 2010 and 2018

Geothermal11%

Wind0.04%

Wind5%

Planned: 2018 (3 189 MW)Actual: 2010 (1 056 MW)

Hydro74%

Hydro28%Thermal

15%

Thermal18%

Geothermal49%

source: KenGen, personal communication (2010)

Operations and performance

KenGen’s performance and financial indicators for the period 2005 to 2010 are shown in Table 1.3. despite the steady rise in installed generation capacity since 2007, there was an 11 per cent drop in electricity sold between 2008 and 2009, reflecting the risks associated with Kenya’s dependence on hydro-electricity. The conclusion of new power-purchase agreements with KPLC during the same period did, however, mitigate the associated financial loss.15 in fact, over the six-year period, KenGen remained profitable and is well positioned to raise the funding required for its ambitious generation-expansion programme, which seeks to double generation capacity by 2018.16 As part of this expansion drive, KenGen issued a public infrastructure bond offer in 2009 in order to raise funds from the Kenyan financial market. The success of this offer, which raised Ksh15 billion (Us$200 million), with an option for a further Ksh10 billion, may be a reflection of the positive view that the markets have of KenGen’s performance, its long-term future and that of the electricity industry as a whole.

Table 1.3 KenGen’s performance and financial indicators, Kenya, 2005–2010

Performance indicators 2005 2006 2007 2008 2009 2010installed capacity (MW) 1 007 1 007 947 1 006 1 018 1 057 Units sold (GWh ’000) 4 280 4 538 4 599 4 818 4 339 3 594 Average generation tariff (Usc/kWh) 2.27 2.40 3.36 3.59 3.19 3.16electricity sales (Us$ million) 96.50 108.80 154.30 173.00 151.60 128.00 Profit before tax (Us$ million) 33.80 50.70 67.10 46.80 60.00 31.50 Financial ratios income for the year as % of average capital employed 2.46 5.70 3.23 3.63 4.60 2.10Profit before tax, dividend and exceptional items/net fixed assets in service (%) 7.00 7.00 7.00 3.35 4.92 2.36return on total assets (%) 4.00 6.00 3.00 3.52 4.89 2.20


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Performance indicators 2005 2006 2007 2008 2009 2010Profit before tax, dividend (less exceptional items)/capital employed (%) 2.00 4.00 1.00 1.11 3.37 1.77Current ratio 2.60 2.30 2.00 1.40 2.17 4.68debt service coverage ratio 3.10 3.30 5.40 4.99 3.90 4.50

source: KenGen (2010)

Kenya’s independent power producers

by 2010, reforms in the energy sector were clearly bearing fruit in Kenya, and the 347 MW of additional generation capacity that iPPs were providing to the electricity supply industry was greater than the combined capacity of iPPs in any other sub-saharan African country. The introduction of iPPs got off to a shaky start, however. iPP procurement began in 1995 when the Kenyan energy ministry offered two 20-year ‘build, own and operate contracts’ for a geothermal plant on an international competitive-bidding basis (olkaria iii at 48 MW) and a diesel-fired thermal plant (Kipevu ii at 74 MW). Lengthy negotiations took place, and eventually olkaria iii, developed by orPower 4, began commercial operations in 2000, but it took until 2003 before it ramped up to full capacity. similarly, Kipevu, developed by Tsavo, only commenced commercial operations in 2001.

Meanwhile, faced with a drought that had diminished generation capacity, and insufficient public funds to build power plants, KPLC ordered two stopgap iPPs in 1996, both on seven-year power-purchase agreement contracts (eberhard & Gratwick, 2005). before the end of the following year, the barge-mounted kerosene-fired Westmont (46 MW) and the medium-speed diesel iberAfrica17 (44 MW) plants were in operation. The haste with which these two plants were procured (through a selective tender process) and the short duration of the power-purchase agreements, led to the cost of the power from the two plants being excessive.18 These costs became a sticking point and, at the end of their respective contracts, re-negotiations led to iberAfrica decreasing its charges by 50 per cent, while Westmont failed to reach agreement with KPLC and disinvested (eberhard & Gratwick, 2005).

despite these events, the authorities continued to pursue iPPs, and in 2006 KPLC put out a tender on an international competitive-bidding basis for a 20-year ‘build, own, operate and transfer’ 90 MW heavy-fuel-oil plant at rabai in Mombasa (eberhard & Gratwick, 2010). Aldwych international won the bid,19 and the plant was commissioned in 2009. Also in 2009, a co-generator, Mumias sugar Company, increased its supply to KPLC from 3 MW to 26 MW.20

having established a track record, a good reputation and ever-increasing competence in deal-structuring, KPLC was negotiating with the following by mid-2010:• three iPPs, as the outcome of an international competitive-bidding process, for

generation capacity of 80 MW each;• three iPPs, on a direct-negotiation basis, for two wind projects totalling 360 MW; and • orPower 4 for a 52 MW extension.21


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Wind power

As at 2011, Kenya had installed wind-power capacity of 5.3 MW from KenGen’s wind farm at Ngong on the outskirts of Nairobi. however, the north-western part of the country has the highest potential for wind power. here, in the districts of Marsabit and Turkana, wind speeds of over 9 m/s at 50 m elevation have been measured (GeNi, 2009). There are consequently plans to build the largest wind farm on the African continent in Turkana. Ground breaking for the 300 MW, Us$800 million Lake Turkana Project was scheduled for April 2012, but by october 2012 this had not taken place due to delays in reaching financial close.22 With national peak demand at just over 1 000 MW, the commissioning of the Lake Turkana project would significantly enhance Kenya’s ‘green’ electricity credentials.

Electricity regulationWe now examine the regulation of the electricity sector in Kenya, beginning with an overview of regulatory governance arrangements, and followed by an assessment of what the regulatory authority in Kenya does, that is, the core of the authority’s work and its impact.

Energy Regulatory Commission

At the heart of the regulatory system is Kenya’s independent energy regulatory Commission (erC), an important outcome of sector reforms. The predecessor to the erC was the electricity regulatory board established under the electric Power Act of 1997, but the passing of the energy Act of 2006 resulted in its dissolution and the birth of the erC. in contrast to the electricity regulatory board, the erC’s mandate extends beyond electricity and includes natural gas (including petroleum), renewables and all other forms of energy.

The objectives and functions of the erC are set out in Clause 5 of the 2006 energy Act, which states that:

5. The objects and functions of the Commission shall be to:a) regulate:

i) importation, exportation, generation transmission, distribution, supply and use of electrical energy;

ii) importation, exportation, transportation, refining, storage and sale of petroleum and petroleum products;

iii) Production, distribution, supply and use of renewable and other forms of energy;

b) Protect the interests of consumers, investors and other stakeholders;c) Maintain a list of accredited energy auditors as may be prescribed;d) Monitor, ensure the implementation and the observance of the principles of fair

competition in the energy sector, in co-ordination with other statutory authorities;e) Provide such information and statistics to the Minister as may from time to

time be required;


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f) Collect and maintain energy data;g) Prepare the indicative national energy plan;h) Perform any other function that is incidental or consequential to its functions

under this Act or any other written law.

For our purposes, the most crucial of these functions is Clause 5(a)(i) ,which deals with the regulation of the supply and use of electricity. Protecting consumer interests, promoting and ensuring competition, and preparing the national energy plan are also important functions of the erC.

The World bank’s Handbook for Evaluating Infrastructure Regulatory Systems (brown et al., 2006) lists 15 minimum functions and powers that legislation should provide in order for independent regulators to carry out their mandates effectively. essentially, legislation should empower regulators to facilitate market access through licensing, set tariffs at economically efficient levels, set and monitor technical standards, resolve consumer complaints and adjudicate disputes that may arise among industry participants. in addition, regulators should have powers to promulgate rules, compel licensed entities to provide information in a prescribed manner, promote competition and monitor performance. regulators should also ensure the adequacy of electricity supply, monitor or undertake planning for new capacity, and oversee its procurement. in general, the energy Act gives the erC the requisite powers. The three areas in which the erC does not have specific authority are discussed in the following sections.

Subsidiary policy and rule making

While the erC does not have the authority to promulgate subsidiary legislation, such as statutory instruments,23 it can ‘make proposals to the minister, of regulations which may be necessary or expedient for the regulation of the energy sector or for carrying out the objects and purposes of the Act’ in terms of Clause 6(b) of the energy Act. With varied and urgent competing demands on their time, government ministers are not always well placed to understand or appreciate the technical complexity of some regulatory matters, and in practice this arrangement can result in delays. For example, Kenya’s electricity Grid Code was finalised by the erC in 2008 and subsequently forwarded to the Minister of energy for promulgation in the form of regulations. The Attorney General’s chambers indicated that publishing the code in its current form would be problematic and suggested, to the discomfort of the erC, the separate publication of each chapter of the code. As a result, by 2010 the code remained unpublished, and the technical requirements for ensuring open access to the transmission grid that it contains, among other things, cannot be enforced.24

Accounting standards and performance monitoring

regulators often seek accounting information in a prescribed manner. standard accounting statements are not always useful either to the regulator or to the regulated entity. some utilities are involved in unregulated businesses such as the


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provision of internet bandwidth, real estate and social clubs. While it is the duty of the regulator to ensure that these additional activities do not have an adverse effect on the provision of electricity, their inclusion in financial statements would distort tariff derivation.25 in Kenya, the energy Act places no explicit obligations on licensees to adopt erC-designed accounting standards and reporting. however, the Act does grant the erC wide-ranging authority and powers, and there does appear to be sufficient scope for the institution of such standards if they are deemed useful. similarly, the Act makes no explicit mention of the erC’s role in monitoring the performance of industry players, but this is implicit in the objectives, powers and functions allocated to the regulator.

Legal independence of the ERC

According to the energy Act, the erC is ‘a body corporate with perpetual succession and a common seal’ (Clause 4(2)). The same clause further states that the erC is capable of:• suing and being sued;• taking, purchasing or otherwise acquiring, holding, charging or disposing of

movable and immovable property;• borrowing and lending money; and• doing or performing all other things or acts for the furtherance of the provisions

of the Act which may be lawfully done or performed by a body corporate.

While this in essence makes the erC independent of the government, this is further entrenched by Clause 4(3), which states: ‘except as otherwise provided in this Act the Commission shall be independent in the performance of its functions and duties and exercise of its powers and shall not be subject to the direction or control of any person or authority.’

Board of commissioners

The erC is led by a board of commissioners headed by a chairperson appointed by the president for a four-year term, which is renewable once. seven other commissioners are appointed on three-year terms that are also renewable once, namely, the permanent secretary in the ministry responsible for energy, the director-general of the erC, and five other commissioners appointed by the minister to represent the private sector in general.

As a prerequisite for their appointment, commissioners should possess a recognised university degree in engineering, physical sciences, law, finance, economics or energy. in addition, they should have at least seven years’ experience in a relevant field, of which at least five should have been at a senior level.

on the advice of the erC’s board, the appointment of the chairperson and the commissioners can be terminated by the president or the minister. such termination must, however, be based on the grounds set out in Clause 11 of the energy Act, which include: bankruptcy; conviction on a criminal offence involving dishonesty, fraud or


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moral turpitude; absenteeism from commission meetings without reasonable cause; and failure to declare their interest in a matter before the commission.

These provisions are intended to enable commissioners to make regulatory decisions without fear of dismissal. even so, the supreme law governing the operations of all statutory and state-owned institutions is the state Corporations Act of 1987 (as amended in 2009), Clause 7(3) of which contains the following provision:

Notwithstanding the provisions of any other written law or the articles of association establishing and governing a board, the President may, if at any time it appears to him that a board has failed to carry out its functions in the national interest, revoke the appointment of any member of the board and may himself nominate a new member for the remainder of the period of office of that member or he may constitute a new board for such period as he shall, in consultation with the Committee determine.26

Through the invocation of this clause, the forerunner to the erC, the electricity regulatory board, had no fewer than five chairpersons during its eight-year existence. it appears, therefore, that if the authorities are intent on terminating the term of a commissioner they will do so, and legally. Moreover, this situation is applicable in all the countries covered in this volume, which serves to emphasise the point that an effective regulatory system requires a high degree of political consistency and commitment. Notably, since the erC came into being there have been no abrupt terminations of the commissioners’ terms in office.

Administrative independence of the ERC

The erC’s management team is headed by a director-general who, as stated, is also an ex officio member of the board of commissioners. The energy Act provides that the erC may, through a competitive process, submit a shortlist of three names to the minister from among whom the appointment of the director-general may be made. This is interpreted to mean that the minister may follow the recommendations of the board in making the appointment, but is not obliged to do so.

The energy Act also gives the erC’s board of commissioners the power to determine the structure and establishment of the erC, recruit staff and determine their terms and conditions of service through Clause 15(1):

subject to subsection (2), the Commission may appoint such directors, inspectors, officers or other staff for the proper discharge of the functions of the Commission under this Act, on such terms and conditions of service as the Commission may determine.

however, Clause 5(3) of the state Corporations Act (1987) also refers to staffing in the following manner:

A state corporation may engage and employ such number of staff, including the Chief executive, on such terms and conditions of service as the Minister may, in consultation with the Committee, approve.


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since the state Corporations Act was passed before the energy Act, the former takes precedence in the event of any contradiction between the two Acts. The erC’s board of commissioners is therefore restricted in the manner in which, and the extent to which, it can make staffing-related decisions. in order to limit disparities in the terms and conditions of staff working for entities that have similar scope, responsibilities and stature, and which fall under the state Corporations Act, each entity is assigned a ranking under this law. high-ranking entities are allowed to pay their staff higher salaries and offer more attractive terms and conditions of service than their lower-ranked counterparts. The board of commissioners can therefore not approve terms and conditions of service without taking the erC’s ranking into consideration. As of 2011, the erC’s ranking was lower than that of the two other dominant players in the industry, KenGen and KPLC. This could prevent the erC from attracting high-calibre staff, and may create a ‘revolving-door problem’ if employees are tempted to seek employment from the utilities that they regulate. despite such a possibility, it is notable that staff turnover at the erC has remained relatively low, with just ten staff having left the organisation between 2005 and 2011 compared to a staff establishment of 60 as at 2012.

While it would be preferable for the board of commissioners to have greater freedom in the setting of remuneration and other terms and conditions this should not be at the expense of accountability. The erC is funded by the electricity consuming (and those consuming the other forms of energy that it regulates) public who deserve to know how their money is being spent.

Financial independence of the ERC

The erC prepares its own budget, which is approved by the board of commissioners. The budget is then submitted to the Minister of energy, who gives final approval in consultation with the Minister of Finance. over the period 2000 to 2009, levies on sales of electricity, petroleum and other energy sources accounted for by far the largest proportion of the erC’s funding, as shown in Table 1.4. This has insulated the erC from direct government funding, which tends to be associated with late and below-budget disbursement, and is consistent with best practice for independent regulators.

Table 1.4 Sources of ERC funding, Kenya (US$ million)

Funding source 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

electricity levy 2.0 1.4 1.3 1.3 1.5 1.6 1.8 2.0 2.3 2.2

Petroleum levya – – – – – – – – – 2.2

Government transfers – – – – – – – 0.3 0.2 0.7

Total 2.0 1.4 1.3 1.3 1.5 1.6 1.8 2.3 2.5 5.1

source: erC, personal communication (2010)Note: a. The petroleum levy came into effect after the 2006 energy Act and was first applied in 2009.

The energy Act provides for three other sources of funding for the erC, namely, interest from bank deposits; revenue from sources such as loans, grants, gifts or


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donations approved by the minister; and such moneys as may, from time to time, be appropriated by Parliament.

Accountability

energy regulators can only be effective if they are found to be credible and legitimate by all stakeholders. Financial accountability forms a key factor in developing such credibility.

According to the energy Act, the erC’s accounts have to be submitted to the auditor-general within three months of the financial year end. The audit should be concluded within six months of the financial year end, and a report should be submitted to the board of commissioners and the minister. The minister is then required to lay the audit report before Kenya’s National Assembly ‘as soon as reasonably practicable’ (Clause 22).

The energy Act also requires that a report on the operations and activities of the erC be submitted to the minister within three months of the financial year end ‘in such form and detail as the Minister shall from time to time determine’ (Clause 22.13). This report is also laid before the National Assembly ‘as soon as practicable’ (Clause 22.11). in practice, the accounts and the report on operations and activities for the year form a single annual report that is available to the public.

The office of the auditor-general is also at liberty to carry out an inspection of the erC’s accounts or records whenever it deems this necessary. such inspections (or audits) are carried out at least every six months.

in several other African countries, the regulator is frequently instructed to appear before committees of Parliament. This is not the case in Kenya, although the erC has indicated that it intends to engage more proactively with lawmakers in future.27 such engagement will add to the erC’s credibility and legitimacy, both of which are important in carving out regulatory independence.

The way in which appeals are dealt with is another important element of accountability. Anyone aggrieved by a decision of the erC may appeal to the energy Tribunal, a specialist court established by the energy Act.

Energy Tribunal

The existence of the energy Tribunal enhances the overall accountability of the erC and provides an avenue for expeditious dispute resolution. The tribunal comprises five members, who are required to have a university degree and at least 15 years’ experience in matters related to electricity, petroleum, finance, economics, engineering, energy or law. The chairperson and vice-chairperson are appointed by the president in consultation with the Judicial service Commission from among persons qualified to be judges of the high court. The minister, in consultation with the attorney-general, appoints the other three members. The members serve for three-year terms, which are renewable once.


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ordinarily, appeals should be filed within 30 days of any decision that is regarded as problematic, but this can be extended if sufficient cause is shown to apply. surprisingly, the tribunal can rule not only on process but also on matters of substance such as tariff structures and levels. These rulings may require the tribunal to draw on a great deal of specialist skills and resources. it may therefore be preferable for substantive issues to be referred back to the erC, which already possesses the requisite skills and resources, or at least is better placed to procure them.

one of the very first appeals heard by the tribunal was a matter in which KenGen was aggrieved with a decision made by the erC on its power-purchase agreement with KPLC. in establishing its case before the tribunal, KenGen made the erC a party to its appeal. Although the matter was eventually settled outside the tribunal, important legal questions arise, since regulators make decisions in a quasi-judicial capacity. The erC, which believes that its being party to such an appeal was an anomaly, gave the following example: ‘When a party appeals to a superior court, does the subordinate court become party to the appeal?’28 At the time of writing, this issue had not been resolved, and the tribunal had dealt with only two cases; it therefore remains to be seen how it will rule on these matters in future.

Transparency and participation

As in many other African countries, erC meetings are not open to the public, and as per Kenyan practice for the government and state bodies, the minutes of erC meetings are confidential. however, tariff decisions are published in the national gazette. Furthermore, the electricity levy, which forms the erC’s largest income stream, is shown on all consumer electricity bills. in discussions with staff at the erC, there was general willingness for greater transparency and public participation.

it is a requirement that notification of any intention to apply for a licence be published in the national press. in the event that any objections to such an application are received, the erC conducts hearings at which the public may air their views. At the time of writing, such hearings did not extend to what is ostensibly the most contentious of regulatory decisions, namely tariff structures and levels. The erC did, however, indicate that as part of their plans for greater transparency and participation, they would in future hold public hearings for tariff reviews. in the meantime, extensive behind-the-scenes consultations have taken place during tariff reviews, during which key stakeholders, such as the Kenya Association of Manufacturers, have been active.

The erC’s website offers stakeholders another access route to the organisation. The website is well presented and informative, although links to the energy policy, a layperson’s guide to the licensing process, and an outline of the procurement process for potential iPP developers might be useful additions.

Regulatory substanceAs discussed in the introduction to this volume, regulatory substance is concerned with the intellectual and technical context of a regulator’s decisions in areas such


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as issuing licences, setting tariffs and setting and enforcing quality and service standards.

Licensing

in Kenya, the generation, transmission, distribution, supply, import and export of electricity can only be carried out by parties in possession of a licence or a permit issued by the erC. in the event that the capacity involved is more than 1 MW but does not exceed 3 MW, a permit is required as opposed to a licence (permits having less onerous conditions than licences).29

The extension of licences to various private electricity-generation companies has been key to the role played by iPPs in increasing Kenya’s electricity-generation capacity, so the efficiency of this process is crucial to the industry as a whole. such efficiency has been facilitated by the fact that clear information about responsibilities and timeframes is given for each stage of the licensing process (see Figure 1.3).

Figure 1.3 Overview of the licensing process, Kenya, 2009

Serve notice to apply on affected local authorities

Once application accepted as complete, remaining

process cannot exceed 90 days

Advertise intention to apply in national press

Lodge application with ERC

Application successful?

Decision on objections

Application considered by Commission

Public hearing/s

Licence award No licence

Public hearings?

Objections?

Application complete?

source: based on the 2006 energy Act

≥ 15-day notice period

≥ 15-day notice period

≤ 15 days

≤ 30 days


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The erC can suspend or revoke a licence or permit on the following grounds:• Where the undertaking or work related to the undertaking has not commenced

after 24 months• operating in a manner deemed to be a wilful or negligent disregard of the

conditions of the licence;• bankruptcy; or• representation by the licensee to the erC that its operations cannot continue

profitably, and upon the erC satisfying itself with such representation.

Prior to suspending or revoking a licence, the erC is required to give the licensee 45 days’ notice to show why the action should not be taken. The erC then makes a determination within 90 days of the notice having expired.

The minister also has the power to take over the operations of a licensed undertaking. This may occur in the event that a licensee fails to meet its obligations under the energy Act even after being notified and given up to 60 days in which to resolve the matter. in such cases, Clause 35.2 of the energy Act states:

subject to subsection (3), if a licensee or permit holder fail to comply with the requirements of the notice, the Minister may, on the recommendation of the Commission, enter upon and take possession of the undertaking of the licensee or permit holder and operate the undertaking for and on account of the licensee or permit holder and at the risk and expense of the licensee or permit holder, remitting the balance, if any, of the net income derived from the undertaking to the licensee or permit holder.

Furthermore, in the event that a suspension or revocation of a licence could lead to an interruption in the generation, transmission, distribution, supply, import or export of electricity, the minister may, in consultation with the owners of an undertaking, declare that it must continue operations while negotiating with another party to take over the facility within a reasonable time. if the owners refuse to do so, the minister can, after a valuation, dispose of the facility through an open tender.

Existing licence holders

by June 2010, the erC had licensed 13 electricity-generation companies (see Table 1.5). KPLC remains the sole licensee for electricity transmission, but it is expected that KeTrACo will be licensed to perform this role in the medium term. KPLC is also the sole licensee for electricity distribution, but this is likely to change as mini-grids that form part of the rural electrification drive become operational. No licences have yet been issued for the import or export of electricity, although interregional trade is taking place. This is an anomaly that will need to be addressed.

Pricing and tariffs

Two statements in the national energy policy (Government of Kenya, 2004) guide electricity pricing in Kenya:

Where the market structure permits, energy prices will be determined by the


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market mechanism. however, where it is necessary to regulate prices because of the nature of the energy services such as electricity distribution, which is by nature a virtual monopoly, Government will ensure efficiency pricing and a fair return on investments. (Government of Kenya, 2004: section 6.6.5, Clause 1)

Table 1.5 Electricity generation companies licensed to operate in Kenya, 2012

Licensee Technology Location of plantCapacity

(MW)KenGen hydro, geothermal and wind Various 1003.8Lake Turkanaiberafrica

WindThermal

MarsabitNairobi

300.0108.5

rabai Power Thermal Mombasa 90.0Thika PowerTriumphGulf PowerTsavo Power

ThermalThermalThermalThermal

Mang’u areaAthi riverAthi riverKipevu, Mombasa

87.083.080.074.0

Kinangop WindorPower 4

WindGeothermal

Kinangopolkaria iii

60.148.0

Mumias sugar Companya bagasse co-generation Mumias 26.0base Titanium Limited Thermal Kwale 16.0Pan African Paper Mills Thermal Webuye 9.0KPrLJames Finlay

Thermalhydro and thermal

MombasaKericho

8.56.7

oserian development Company Geothermal Naivasha 3.7Unilever Tea Kenya hydro and thermal Kericho 3.8sotik Tea Company Thermal Arroket 1.5sotik highlands Tea estate Thermal sotik highlands 1.1

source: erC (2009); erC, personal communication (2012)Note: a. Plans are in place to expand capacity to 38 MW.

electricity tariffs will reflect the cost of supply and also be efficient. in addition, consumer tariffs must also meet the social equity objective of affordability for the underprivileged members of our population. The lifeline tariff that currently applies to the first 50 kWh will therefore be continued but consumers will be expected to pay a tariff that at least covers the cost of generation, as is the practice in some countries. however, its administration will be streamlined to achieve better targeting, thereby delivering the intended benefits to the needy and vulnerable members of society. (Government of Kenya, 2004: section 6.6.5, Clause 4)

in addition, the 2006 energy Act requires that the tariffs contained in power-purchase agreements between and among licensees, and between licensees and large retail consumers, are just and reasonable and have the approval of the erC. in this context, the energy Act defines a ‘just and reasonable’ tariff as one that enables a licensee to maintain its financial integrity, attract investment capital, operate efficiently and fully compensate investors for risks taken.


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A further requirement of the energy Act is that ‘the tariff structure and terms for the supply of electrical energy shall be in accordance with principles prescribed by the Commission’. in this regard, the electricity regulatory board published the retail electricity Tariffs review Policy in 2005 (erb, 2005). The policy details the elements of tariff determination and includes the methodology applied, customer categories and the tariff structure. There is also mention of a marginal-cost pricing philosophy that could possibly come into force in the longer term if competition within the electricity market begins to occur.

Setting prices and tariffs

The underlying tariff methodology for the assessment and approval of power-purchase agreements and the determination of KPLC’s retail electricity tariffs is the widely used revenue-requirement formulation, namely:

rr = rAb × ror + e + d + T

Where rr = revenue requirement, rAb = regulatory asset base; ror = rate of return; e = operations and maintenance expenses;d = depreciation; T = taxes.

According to the tariffs review policy, the rate of return (ror) shall be computed as the weighted average cost of capital (WACC), which is defined as:

WACC = debt × cost of debt + equity × cost of equity

The computation assumes a target capital structure (or debt-to-equity ratio) of 70:30 using the actual cost of debt. The determination of the cost of equity does, however, present a challenge. Although the tariff policy recommends the adoption of a modified capital asset pricing model (CAPM) to determine the return on equity, data limitations have led to the abandonment of the entire WACC regime. in its place, the erC applies the treasury recommendation of a 15 per cent (before tax) rate of return for public companies on the revenue requirements of KenGen and KPLC. This has been a bone of contention for KenGen, however, which argues that, whereas the erC has allowed KPLC to earn the target rate, its own allowed rate of return in the power-purchase agreements approved by the erC in 2009 is 15 per cent after tax. For iPPs, the rate of return is determined on a case-by-case basis, and is largely influenced by the source and terms of funding.

The most recent tariffs review policy of 2005 states that: ‘depreciation of the regulatory asset base shall be based on the licensee’s depreciation policies, which shall be consistent with industry best practice and the prevailing tax law’ (erb, 2005: 14). The tariffs review policy does not explicitly state whether historical values or the modern equivalent asset method should be used in determining the regulatory asset base. The use of historical values could result in utilities not accruing sufficient funds to replace depreciated assets. At the same time, the use of the modern equivalent asset method or replacement costs could result in tariff spikes and, in the absence of robust controls, there is no guarantee that the depreciation account would be expended only on the replacement of assets.


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Generation tariffs

Generation tariffs drive power-purchase costs, which constitute the single most important cost element in Kenya’s retail electricity tariffs, as shown in Table 1.1. in the financial year 2008/09, power-purchase costs (including fuel) accounted for over 70 per cent of the expenses in KPLC’s income statement (KPLC, 2009). Given the significance of power-purchase costs in Kenya, it is crucial that all the other elements of the generation tariff are prudently applied and, where possible, cost reductions are incentivised.

in general, the tariffs in power-purchase agreements are structured to comprise capacity charges, energy charges, fuel pass-through costs and the applicable inflation index (erb, 2005). each of these elements is discussed in more detail below:• Capacity and energy charges: These represent the fixed and variable costs respectively

for electricity-generating companies. For new iPP projects that are procured through international competitive bidding, it can be assumed that these charges are competitive. The benchmarking with local and international markets that these costs undergo provides further reassurance of their competitiveness. Furthermore, with thermal iPPs having established a track record, the erC is building a pool of local data that can be used to benchmark potential entrants. once agreement has been reached on the costs, they are locked into the power-purchase agreements.

• Pass-through costs: For thermal generators that primarily use diesel or heavy fuel oil, fuel costs represent an important component of their variable costs. To ensure that fuel costs are incurred prudently, the fuel-supply agreements entered into with fuel suppliers are subject to the Public Procurement and disposal Act (2005), and KPLC audits these fuel-supply agreements. Given the exogenous nature of this cost, Kenyan iPPs do not assume the risk that this cost represents; instead the risk is borne by consumers by means of a cost pass-through regime that is calculated on a monthly basis by KPLC. This implies that for the same level of consumption, a consumer’s bill may vary from month to month. it is worth noting, however, that the 2005 tariffs review policy proposed other options for risk sharing between consumers, KPLC and the iPPs be investigated (erb, 2005). This has yet to be explored.

• Inflation indexing: Generation tariffs are subject to escalation at the prevailing rate of inflation. however, in order to incentivise cost containment, escalation is calculated less an efficiency factor (in the fashion of the rPi-X regulatory philosophy).30 This approach is also applicable to KPLC tariffs.

Transmission and distribution tariffs

KPLC’s retail electricity tariffs are reviewed once every three years. The transmission and distribution businesses of KPLC are ring-fenced; that is, separate regulatory accounts are maintained for the two businesses. The erC uses a postage-stamp method to derive the wheeling charge.31 in 2009, the wheeling charge was approximately 1.01 Usc/kWh.

KPLC’s allowable expenses include power-purchase costs, operations and maintenance, and technical and commercial losses. Power-purchase costs have been discussed. The base value of operations and maintenance expenses are capped for


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each period, and cost escalation (for local inflation) is subject to an efficiency factor in a manner similar to rPi-X regulation.

Total system losses are capped in the tariff at progressively lower levels as another means of cost containment, since lower losses in any case mean increased revenue. These levels were 16.4 per cent, 15.9 per cent and 15.4 per cent for 2009, 2010 and 2011 respectively. Actual achievement in 2009 was 16.3 per cent. The target loss level in the 2010 Least Cost Power development Plan is 14.5 per cent by 2013 (Ministry of energy, 2010).

Power-sector planning

detailed long-term planning is often neglected in the urgency of power-sector reform, but Kenya seems to have successfully avoided this trap. The 2006 energy Act states that one of the objectives of the erC is to ‘prepare indicative national energy plans’ (Clause 5(g)). This emphasis may stem from the fact that planning was previously undertaken by the Ministry of energy as one of its regulatory functions and not by the pre-reformed, vertically integrated power utility (as tends to be the case in many other African countries).

building on the previous experience of the ministry, and to fulfil its planning mandate, the erC constituted the Least Cost Power development Planning Committee in 2009.32 The committee comprises representatives from:• the erC (who chairs the committee and provides its secretariat);• KPLC, KenGen, KeTrACo and GdC;• the Ministry of energy;• the Ministry for state for Planning, National development and Vision 2030;• the rural electrification Authority; and• Kenya’s National bureau of statistics.

This stakeholder-committee approach enables the erC to leverage the diverse skills and resources (including data) required for robust planning. in addition, the committee provides a platform for consensus building, a crucial ingredient for ensuring the credibility of the Least Cost Power Development Plan (Ministry of energy of Kenya, 2010).

New build opportunities

The Least Cost Power development Plan does not identify any explicit criteria for the allocation of new build opportunities. The erC does contend, however, that the public sector should undertake projects that may not be attractive to the private sector, for example where returns may be too low. in practice, KenGen has the de facto right of first refusal and, if KenGen fails to raise the requisite funding, the private sector is invited to participate in an international competitive-bidding process that adheres to the requirements of the Public Procurement and Asset disposal Act of 2005. Typically, bids are invited by KPLC, although in some cases, such as for the emergency thermal generators required in 2000, and more recently in 2011, procurement was handled by the government through its appointed agent,


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KenGen. The government, through the Ministry of energy, may also consider unsolicited bids provided that they adhere to the public procurement legislation.

As has been shown, various iPPs have been persuaded to complement government-funded expansion of Kenya’s electricity-generation facilities. Various factors have contributed to this: • barring the unfortunate political upheaval in 2007, the country’s good investment

climate, as evidenced by its vibrant and well-entrenched local private sector, encourages new investors.

• Power-sector reform is well supported by the government and championed by the Permanent secretary and the Minister of energy.

• Procurement has been streamlined by the clear assignment of the key responsibilities of planning, tendering and contracting, with strong linkages between these functions.

• over time, through successive iPP bids, the capacity to undertake efficient procurement and negotiate effectively has been developed in KPLC.

• Crucially, though financiers have required security in the form of ‘comfort’ letters or escrow accounts, KPLC as off-taker has never defaulted on any power- purchase agreement with an iPP. As a result, Kenya now has an established track record with iPPs. broadly, the government (and its agents), project developers and financiers alike know what to expect in the procurement process, and previous successes are breeding new success.

The erC’s role in procurement seems to be restricted to planning at the front-end and licensing at the back-end. however, given the cost and security-of-supply implications of these deals, there may be merit in a greater involvement in the in-between stages of the process. if such involvement occurs in future, steps should be taken to ensure that this does not compromise regulatory independence or the final approvals that the erC has to give on licence applications and power-purchase agreements.

Regulatory impactdespite the successes of the sector in increasing the involvement of iPPs, the reliability and quality of electricity supply remain problematic. The Africa infrastructure Country diagnostic (AiCd) study estimates an average of 53 days of outages per year, the economic cost of which is close to 2 per cent of GdP (AiCd, 2010). While insufficient generation capacity is a factor in this state of affairs, the World bank has argued that:

The transmission and distribution networks have limited coverage and inadequate capacity to transmit electricity from power plants to consumers. This has led to an unreliable electricity service and unnecessarily high technical losses in the public electricity system. The reasons for these conditions include underinvestment over a long period of time and narrow focus of service expansion to rural areas without a matching effort to strengthen the backbone transmission and distribution networks. (World bank, 2010b: 5)

These factors make regulating the quality of electricity supply a challenge for the erC, although comfort may be drawn from the fact that this is a challenge common to most, if not all, of the independent regulators in Africa.


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Grid codeThe regulatory framework and the detailed provisions that provide the basis for regulating the quality of supply are contained in the Kenya electricity Grid Code (erC, 2008). The primary objective of a grid code is to establish the technical and engineering rules that ensure open access to the electricity grid while ensuring that safety and quality are not compromised. The stated objectives of the code in respect of technical and industry operations are to provide:

3) detailed operational requirements, including power-system operations and power-system security, emergency operations, metering, including metering obligations of the distribution-network service provider, and maintenance scheduling;

4) Terms and conditions of access and technical standards that will apply for connection to the network;…

6) regulation of the supply of electricity to consumers and terms of supply to consumers;…

7) regulation of the supply of electricity to or from the distribution-network service providers’ distribution systems. (erC, 2008: section 1.4)

Although the grid code was first published in 2008, by the time of writing, it had yet to be gazetted, and some questions remain about the suitability and enforceability of the code. some licensees question the code’s suitability to Kenyan conditions and argue that the 2008 Kenya electricity Grid Code is a replica of the Ugandan code. They also point out that part of their regular reporting to the erC includes supplying information on their technical performance. Another issue raised is whether, and how, the erC could act against a licensee whose performance was at variance with the grid code’s technical standards.33 in the meantime, the Kenya Association of Manufacturers acknowledged that although quality of supply was ‘bad’, it had previously been ‘a lot worse’.34

Increasing access to electricityAccess35 to electricity in Kenya is ‘far below that of other African countries with similar per capita income levels’ (PPiAF, 2010). A breakdown of Kenya’s overall access rate of 18 per cent (AiCd, 2010) is revealing; while urban access is estimated to be at 51 per cent, access in rural areas is just 4 per cent, despite the fact that rural electrification programmes have been ongoing since 1973.36 The Kenyan government’s Vision 2030 development plan has set the ambitious target of 100 per cent access by 2030 (Government of Kenya, 2007). To achieve this, KPLC will have to reach a new-connections rate of 200 000 per annum,37 of which 28 00038 connections are for rural customers. encouragingly, by mid-2011 KPLC seemed likely to achieve this ambitious target.

Through the energy Act, the Kenyan government established the rural electrification Authority (reA) to focus specifically on the rural areas. reA plans and builds rural electrification projects through labour and transport contractors or turnkey contracts. For projects that are connected to the grid, reA retains ownership of the


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assets, while KPLC undertakes the operations and maintenance. Grant-funded rural electrification assets do not earn a rate of return in the KPLC revenue requirement for tariff purposes, but depreciation and operations and maintenance expenses are allowed on these assets.39 The rural electrification Programme Fund finances the programme. According to Clause 79(2) of the energy Act, this fund comprises:• a levy of up to 5 per cent on electricity sales;• fees and other charges levied by the erC;• appropriations by parliament;• donations, grants and loans; and• all other monies lawfully received or made available for the programme as the

minister may approve.

reA plans to reach its 2030 target in three phases. The aim of the first phase is to increase rural access to 22 per cent by electrifying all public facilities (such as markets, secondary schools and health centres) between 2008 and 2012. The second phase, running from 2013 to 2022, targets households, aiming to increase access to 65 per cent, and the third phase from 2022 to 2030 aims to increase the electrification rate to 100 per cent (Munyu, 2009). The resource requirements for reaching these targets are significant. For example, Munyu (2009) estimates that close to Us$1.3 million will be required just for the period 2009 to 2013.

Loans and subsidies for the poor

The electrification drive does not fund the cost of connections to consumers. For consumers within a 600 m radius of a transformer, KPLC charges a uniform Ksh35 000 per connection. For many, this amount is a barrier to connectivity. To overcome this, KPLC in partnership with local banks has the stimaLoan facility, the advertising campaign for which, in swahili, is Pata stima lipa pole pole, meaning: ‘Get electricity, pay slowly, slowly’. The facility allows consumers to get connected by paying 30 per cent of the connection fee up front and repaying the balance over a maximum of 36 months at 15 per cent interest on the reducing balance. For potential consumers who find even these terms onerous, KPLC is piloting another stimaLoan facility that works on a revolving-fund basis with a 20 per cent up-front payment plus a once-off 5 per cent administration fee; there is no interest charge, and the amount is repaid over a maximum of 24 months.

Consumption of electricity up to 50 kWh is charged at the so-called ‘lifeline tariff ’, that is, a subsidised rate of Ksh2 per kWh.40 Although this tariff is intended for the poor, it benefits all domestic consumers. The subsidy is funded by domestic consumers whose consumption is above 1 500 kWh, that is, the highest band in the tariff structure. in addition, since there is a policy of implementing uniform tariffs across the country, rural consumers are effectively subsidised by those in urban areas.


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Conclusionelectricity-sector reforms in Kenya have achieved many successes, not least in attracting new capital to fund the expansion of generation plants. The erC does, however, need to strengthen its role and participate more fully in this success story. in general, stakeholders view the erC positively, but there is a belief that the regulator is beholden to the government and not sufficiently independent. stakeholders want to see the credibility, robustness and sustainability of its decisions enhanced, especially with respect to the enforcement of tariffs and technical standards. Communication: it would be beneficial to the erC to embark upon a sustained communication strategy. Firstly, licensees need to be regularly engaged so that all the industry players achieve a common understanding of regulatory matters. secondly, Kenyans need to be made aware of the erC’s role in protecting consumers while ensuring that utilities are financially viable and able to expand their services. Thirdly, even though this might be viewed as alien to Kenyan culture, the erC should consider conducting public hearings, especially around tariff setting, as a means of engendering greater transparency and public participation.Planning and investment: The energy Act clearly assigns responsibility for planning to the erC, and it is crucial that the commission entrenches its leadership role in this area. To avoid confusion and mixed signals that could delay the sector’s expansion, the Least Cost Power Development Plan, generated under the stewardship of the erC, needs to be accepted as the national plan for the sector; it cannot be seen as subservient to the in-house plans of utilities or other arms of the government. Furthermore, criteria for the allocation of new build opportunities between the public and private sector need to be clarified. The erC could issue guidelines for the investment community to clarify this and lay out the framework for power-expansion planning, tendering, contracting as well as for the procedures to be followed for licence applications and for obtaining power-purchase agreement approvals.Market structure and licensing: one of the erC’s responsibilities is to promote competition in the sector. While recognising that establishing competition in power markets is a challenging undertaking, the energy Act does allow for third-party access to the transmission grid. if this was clarified by the erC, it could provide some competition in the sector by allowing large consumers to contract directly with generators, but this cannot take place without resolving the outstanding issues related to the grid code. With regard to licensing, it was surprising that despite the fact that the energy Act clearly states that licences are required for the import and export of electricity, these activities continued to take place even though no party was licensed to undertake them. This raises credibility concerns and should be resolved as a matter of urgency.Power-purchase agreements: regulators find themselves in a difficult position during negotiations for power-purchase agreements. it is generally accepted that they should give final approval to these agreements and that in order to do so impartially, they should not be party to the negotiations. however, regulators have a role to play in


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ensuring the security of supply and in protecting consumers from excessive pricing. because power-generation projects typically have long lead times, the non-approval of a particular power-purchase agreement by the regulator could put the supply of electricity at risk. Under such circumstances, the regulator ought to be fully informed of the key issues, and a mechanism should be developed for erC staff to attend negotiations as observers. This would allow the erC to provide non-binding views on elements of the power-purchase agreement as required by the parties, without losing their right to make the final decision on the power-purchase agreement.

A striking feature of Kenya’s electricity-generation expansion plans is the extent to which green energy sources (namely, geothermal, biomass and wind) are expected to be exploited. if these plans come to fruition, approximately half the country’s installed capacity will come from these sources – a significant accomplishment for any country.

Kenya gives cause for hope in terms of electricity regulation in Africa. if the lessons learnt from its power-sector reform process were applied elsewhere, it is likely that significant progress would be made towards ridding the continent of the stigma of darkness.

Notes1 depending on water-storage capabilities, the effects of drought can take some time to

impact on power generation in a hydropower system.2 by the end of 2001, the 105 MW had been decommissioned. however, with the return of

drought in 2006, a further 110 MW of emergency thermal generation was contracted, and at the end of 2009 a total of 290 MW was in operation. As dam levels rose again towards the end of 2009 and in 2010, the emergency plants began to be retired, and by July 2010 only 60 MW of emergency supply was in service.

3 see http://www.lb-energy.com/new-power-plants4 both KenGen and KPLC are majority state owned, with significant private shareholding.5 in some jurisdictions there is a distinction between distribution and supply. Throughout this

volume the term ‘distribution’ refers collectively to both the distribution and supply functions.6 For a full list of the short-term measures for the electricity sector, see Government of Kenya (2004).7 More on KPLC’s history can be found at http://www.kplc.co.ke/index.php?id=1288 These responsibilities include system operations.9 KPLC (Kenya Power and Light Company) (2003). Annual report and Accounts, 2002/03. Nairobi:

KPLC. KPLC. Annual report and Financial statements, 2005/06–2010/11. Nairobi: KPLC.10 For example, in 2009 reuters reported that a 14 MW hydro plant at Masinga had been

forced to shut down due to inadequate water; see http://af.reuters.com/article/kenyaNews/idAFLU26595120090630

11 Personal communication (2010).12 According to an article in the Daily Nation, ‘All the signs indicate we are on course to

recovery’ (4 January 2010), cellular operator safaricom surpassed this record in 2008 when its initial public offering raised Ksh50 billion.

13 KenGen (Kenya electricity Generating Company) (2011). 59th Annual report and Financial statements. Nairobi: KenGen.


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14 KenGen (Kenya electricity Generating Company) (2011). 59th Annual report and Financial statements. Nairobi: KenGen.

15 in Kenyan shilling terms, electricity sales were in fact higher by 10 per cent for the period 2008/09 than in the previous year. however, this is not reflected in Table 2.4 due to depreciation against the Us dollar over the same period.

16 KenGen, personal communication (2010).17 As of 2010, the capacity of this plant had been increased to 108.5 MW.18 eberhard and Gratwick (2005) estimate the cost to have been approximately twice that of

the orPower 4 and Tsavo plants.19 one of the other three bidders, simba energy, subsequently filed an objection to the

awarding of the tender with the Public Procurement Complaints, review and Appeals board, which ruled against the objection. simba energy then initiated proceedings in the high court in Nairobi, but the matter was settled out of court.

20 Mumias sugar Company. half-year results to 31 december 2007, http://www.nse.co.ke/newsite/pdf/Announcement%202008/Mumias_sugar.pdf

21 Personal communication.22 see http://www.bloomberg.com/news/2012-10-16/kenya-s-lake-turkana-wind-project-

delayed-again-by-lending-talks.html23 in law, a statutory instrument is a form of delegated or secondary legislation that can be

enacted to give effect to higher-level legislation.24 Kenya’s grid code is discussed in more detail in a later section of chapter 2. interestingly,

neighbouring Uganda published its grid code as a unitary instrument in 2003.25 Tariffs are discussed in more detail in a later section of chapter 2.26 The committee referred to here is the state Corporations Advisory Committee, which is

appointed by the president to advise on matters and perform any functions as required by the state Corporations Act.

27 Personal communication (2010).28 Personal communication (2010).29 With security of supply not always assured in Kenya, it is common for individuals and

businesses to own generators for their own use. Permits are not required in these cases, provided that these generators are not installed in a manner that would allow electricity to be conveyed to the national grid.

30 rPi-X regulatory philosophy acknowledges that many consumer costs tend to rise at the level of inflation or the retail price index (rPi), but makes an allowance for rPi less an efficiency factor (X). This is intended to incentivise cost containment.

31 in the postage-stamp method, the total transmission costs of the electricity grid are spread evenly over all users, and each user pays the same rate per unit irrespective of the cost that they impose on the system, or the benefit that they derive from it.

32 A similar committee was in place when planning was the responsibility of the Ministry of energy.33 Personal communication (2010).34 Personal communication (2010).35 The Kenyan authorities distinguish between access and connectivity. here the two terms are

used interchangeably.


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36 oyuke J, rural population lack electricity, The Standard, 29 october 2008. 37 Turana o, KenGen receives Ksh26 billion for Geothermal Power, Business Daily, 7 July 2010.38 reA, personal communication (2010).39 For example, if the electrification of a school or a clinic is donor funded, KPLC does not

earn a return on the asset, but the erC allows for related operations and maintenance costs as well as the cost of depreciation.

40 As at June 2008, excluding fuel pass-through costs.

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Tanzania: Learning the hard way

Almost every day there are one or two power failures. – An official from the Confederation of Tanzania industries1

despite Tanzania opening its electricity sector to independent power producers (iPPs) more than a decade ago, failures in the planning and implementation of generation-expansion projects have created two main power-supply problems. Firstly, in a country where less than 20 per cent of the population have access to electricity, installed generation capacity is insufficient to meet existing demand, let alone carry the reserves required for prudent system operations. secondly, over 50 per cent of installed generation capacity is hydro-based and the country is increasingly drought prone. significant droughts since the early 1990s have made power cuts of up to 14 hours at a time a frequent fact of life for Tanzanians (Keeler, 2010). For example, in May 2011 the national utility, Tanzania electric supply Company Ltd (TANesCo), announced that consumers would experience power cuts daily from 08:00 to 23:00.2 These power cuts only subsided when the government procured a total of 300 MW3 of expensive interim thermal generation through its emergency Power Plan announced in August of the same year.

The Tanzanian government has tried to remedy the situation and find a sustainable solution to the electricity woes through ongoing reforms in the power sector. These interventions have, however, had limited impact so far. TANesCo’s fortunes have continued to dwindle, and efforts to augment state intervention with private-sector investments have been dogged by inefficiencies or mired in controversy. Lessons from the procurement of Tanzania’s first two iPPs have not been incorporated into subsequent projects. Probably the most dramatic example of this is the 100 MW richmond/dowans emergency power plant, which has been described as ‘the biggest corruption and political scandal in the country’s history’4 and led to the 2008 resignation of the prime minister and the dissolution of the Cabinet.

Most of the reform measures and attempts to involve the private sector were initiated before a statutory regulating authority had been established. The energy and Water Utilities regulatory Authority (eWUrA) came into being in 2006. since then, eWUrA has ridden on a wave of goodwill. The principal legislation is innovative in granting eWUrA powers that are not common in other regulatory institutions covered in this volume, such as the initiation of the procurement of new capacity for the electricity-supply industry. The legislation also presents a unique mechanism that allows for more transparent and formal engagement with government and consumer groups. Most stakeholders are positive about eWUrA’s potential impact, but the regulator clearly faces monumental challenges if it is to turn the fortunes of Tanzania’s electricity sector around.

2


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Overview of Tanzania’s electricity sectorThe structure of Tanzania’s power sector is depicted in Figure 2.1. As in all the countries in this volume, the government, through the Ministry of energy and Minerals, is responsible for formulating energy policy. regulation of the sector is the preserve of an independent regulatory agency, eWUrA and, as is increasingly the case across Africa, an autonomous body, the rural energy Agency (reA), has been charged with scaling up rural electrification.

At industry level, all the defining features of a hybrid electricity market are visible. state-owned and vertically integrated TANesCo dominates the sector, while iPPs (songas and independent Power Tanzania Ltd [iPTL]) provide additional generation capacity on the margins of the industry, and the Mtwara energy Project (MeP) is a remote rural gas-to-electricity generation and distribution concession planned for the south of the country, the agreement for which has yet to be formalised.

Figure 2.1 Overview of Tanzania’s electricity industry, 2010

Energy and Utilities Regulatory Authority

Independent power producers (Songas, IPTL)Mtwara Energy

Project (MEP)

TANESCO

Consumers

Industry

Islanded generation and distribution concession

Ministry of Energy and Minerals

Rural Energy Agency


Generation capacity and demand forecast

At the time of writing, Tanzania’s total installed generating capacity was 1 184.2 MW, of which 47 per cent was hydropower. shortages in hydropower have been exacerbated by the diversion of water for irrigation (iMF, 2006) and the steadily increasing demand for electricity. The contribution of thermal power to Tanzania’s total generation, which was just 7 per cent in 2002, averaged 37 per cent over the period 2002 to 2009 and peaked at 58 per cent in 2007, due in part to the contribution of short-term emergency power generators. Table 2.1 lists installed power generation plants and their capacities in 2009.


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Ta n z a n i a : L e a r n i n g T h e h a r d way

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Table 2.1 Installed generation capacity by plant, Tanzania, 2012

Ownership PlantInstalled

capacity (MW) Type

TANesCo Kidatu 204.0

hydro (47%)

Kihansi 180.0Mtera 80.0New Pangani Falls 68.0hale 21.0Nyumba ya Mungu 8.0Uwemba 0.8Ubungo GasUbungo Gas ii

102.0105.0 Thermal (gas)

(21%)Tegeta Gas 45.0

other (small, stand-alone diesel generators) 46.9 diesel (4%)iPPs songas 189.0

Thermal (gas) (26%)Tegeta iPTL 100.0

Mtwara (Wentworth resources) 12.0sPPs Tanganyika Wattle Company Ltd (TANWAT) 2.5 Thermal (biomass)

(2%)TPC Ltd 20.0 Total 1 184.2

sources: eWUrA Annual report, 2010;5 eWUrA (2013); Jacobsen elektro As (2012)Note: The installed generation capacity excludes emergency power supply.

Given the regularity of drought and the availability of natural gas reserves, the long-term and least-cost security of power supply for Tanzania seems likely to require a more optimised mix between hydro- and thermal generation.

The load forecast for the period 2010 to 2019 is shown in Figure 2.2. it is estimated that future growth in both demand and consumption will be strong, averaging approximately 10 per cent per annum. if this forecast actualises, serving the resulting demand will require the doubling of Tanzania’s existing generating capacity within the current decade, that is, an additional 1 000 MW. Given that only about 400 MW of additional capacity has been realised over the period 2000 to 2012, TANesCo’s ability to invest its own funds and to attract private-sector investors requires significant scaling-up to meet the projected demand.

Power-sector reformelectricity was first introduced to Tanzania (then Tanganyika) in 1908 when the colonial authorities installed electric power to run the railway workshops in dar es salaam, but in the early 1930s, the colonial government decided to withdraw from the provision of electricity services. The dar es salaam and district electric supply Company (dAresCo) and the Tanganyika electric supply Company (TANesCo) were then established.6 both utilities grew, and when Tanganyika achieved independence in 1961,7 TANesCo was exporting power to Mombasa in Kenya.8


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Figure 2.2 Electricity load forecast, Tanzania, 2009–2019

2 500

2 000

1 500

1 000

500

0

Energy

Peak

dem

and

(MW

)

Ener

gy (

GW

h)

Peak demand

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

12 000

10 000

8 000

6 000

4 000

2 000

0

source: ridgeway Capital Projects (2010)

At the time of independence, the government expressed its desire to acquire both of these electricity utilities, and a protracted nationalisation process took place from 1964 to 1975. during that time, the two utilities merged to form the Tanzania electric supply Company (also known as TANesCo). TANesCo performed adequately in the 1960s and 1970s, the two decades after independence, but from the 1980s ‘electricity-sector services deteriorated’ (Ghanadan & eberhard, 2007: 6), and performance since then has generally been poor.

Acting on the advice of the World bank and the international Monetary Fund (iMF), the government initiated a macro-economic structural adjustment programme in the early 1990s. This, combined with the drought of 1992, prompted a wave of reforms in the electricity sector.

Although the structure of the industry has changed little in recent years, despite a series of reforms that began in 1992 with the publication of a new energy policy (Ministry of Water, energy and Minerals of Tanzania, 1992), it is still useful to examine the reforms in some detail before we briefly describe the major players in the industry.

The focus of the 1992 reform policy was on the development and use of indigenous energy sources, and on increasing per capita electricity consumption. To achieve these broad objectives, the policy states that ‘while TANesCo is the major producer of electricity, the Government has given a mandate to other organisations to exploit the hydropower resources and to install thermal-based generation. in all cases the Ministry responsible for energy regulates the development through the powers vested in it by the electricity ordinance’ (Ministry of Water, energy and Minerals, 1992: 26). With this statement, electricity generation in Tanzania was liberalised, and the following year bids were invited for the country’s first two iPPs.

The policy also stated that ‘where TANesCo has not established a public power-supply system, private electricity generation and distribution will be encouraged.


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The tariffs applicable to such schemes will be reviewed by the government’ (Ministry of Water, energy and Minerals of Tanzania, 1992: 27). This made it possible for the private sector to invest in remote rural power systems (such as the Mtwara energy Project discussed later). Tanzania was also among the first African countries to attract iPPs in the form of iPTL and songas (also discussed later in this chapter).

interestingly, the policy did not envisage the establishment of an independent regulator (eWUrA was set up in 2006). And despite the policy changes and various private-sector initiatives, the performance of the electricity sector remained poor. A 1999 iMF paper on Tanzania stated that:

in recent years, the economy has suffered from power shortages and blackouts, owing to load shedding by the electricity parastatal, TANesCo, during the dry season. These interruptions have a high cost in terms of foregone output and incomes. The current drive to address these problems will require further investments by TANesCo. To this end, concerted efforts will be made to solve the problems of long lags [delays] in electricity billings, customers’ non-payment for services, and delays in adjusting tariffs by the government. (iMF, 1999: para. 39)

As a result, and under pressure from the both the iMF and the World bank, the Tanzanian government committed itself to further and more explicit reform measures:

The government has decided, as part of an action plan to improve the security, reliability, and efficiency of power supply, to…rationalise TANesCo’s operations and introduce private operation and ownership into these operations, beginning with power distribution. other measures include developing a power sector regulatory policy and plan, which is expected to be in place in June 1999. Under this plan, foremost priority will be given to promoting private sector entry based on competitive bidding and autonomous regulatory arrangements. The power system under TANesCo will be unbundled into generation, transmission and distribution segments, and privatised distribution will be in place by end-2000, followed by the generation and transmission segments. A simple but effective regulatory framework will be put in place by december 1999. (iMF, 1999: para. 40)

Thus activities to restructure TANesCo and prepare it for eventual privatisation began to take place. Progress was slow, however, to the frustration of the World bank, which believed that both the government and TANesCo management were not doing all in their power to turn the company around. This was in spite of power tariffs having increased by over 100 per cent in nominal terms over the period 1988 to 2000 (see Table 2.2), reaching 9 Usc/kWh, which was among the highest tariffs in Africa at the time (World bank, 2003). Mounting operational losses were compounded by significant unpaid electricity accounts by the government and state-owned enterprises (iMF, 2001a). Furthermore, in 2001, the outcome of an arbitration case on the costs of the iPTL power plant added to TANesCo’s financial burden (iMF, 2001b).


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Table 2.2 Electricity tariffs, Tanzania, 1988–2000

Year Tariff (USc/kWh) Year Tariff (USc/kWh)1988 3.99 1993 8.001989 4.34 1994 8.431990 5.38 1995 8.731991 6.15 1999 9.001992 6.17 2000 9.00

source: Marandu (2002)

With electricity costs high, quality and reliability of supplies poor, and the financial standing of the state utility still weak, attention focused increasingly on TANesCo’s management. in 2001, the government reconstituted TANesCo’s board and initiated the procurement of a firm to manage the company (iMF, 2001a).

Experiment in outsourcing utility management

in 2002, the government of Tanzania retained the services of a south African-based company, NeTGroup solutions, to manage TANesCo.9 originally the contract was for a period of two years but it was later extended and eventually ran until december 2006. broadly, the objective of the contract was to achieve TANesCo’s commercial turnaround in readiness for privatisation. When the contract came up for extension in 2004, its scope was widened to include improvements in technical performance.

Private sector involvement in Tanzania’s electricity industry has tended to raise controversy, and the NeTGroup management contract was no exception. The tendering process was shrouded in allegations of impropriety. TANesCo’s board of directors expressed reservations about the transparency of the negotiations, and the Minister of energy and Minerals questioned the selection process. Workers threatened industrial action, and even sabotage, if they were not paid retrenchment packages before the start of the contract.10 There was also criticism of the ‘high’ salaries paid to the NeTGroup managers11 (hall, 2007).

The results achieved by NeTGroup were mixed. The most positive outcome was the increase in TANesCo’s revenues which, in the first phase of the contract (May 2002 to July 2004), ‘increased from Us$10–12 million per month in 2001, to Us$16 million per month by mid-2004’ (Ghanadan & eberhard, 2007: 19).12 The World bank hailed this as an ‘immediate improvement in the utility’s financial and operational performance’ (World bank, 2003), and by mid-2004 revenue collection had reached Us$22–24 million per month (Ghanadan & eberhard, 2007). improvements in technical performance were elusive, however. system losses, quality and reliability of supply, and the rate of new electricity connections, did not improve.

Policy revisions since 2003

Almost a year after NeTGroup’s management contract began, the government published the National energy Policy (Ministry of energy and Minerals of Tanzania, 2003). The


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new policy acknowledged the structural changes that had taken place in Tanzania’s transition from a centrally planned economy to one that was market driven and, in comparison to the 1992 policy, it was more explicit about the government’s power-sector reform agenda. it took into consideration the need to ‘reform the market for energy services and establish an adequate institutional framework, which facilitates investment, expansion of services, efficient pricing mechanisms and other financial incentives’ (Ministry of energy and Minerals, 2003: 5). The key aspects of the policy were as follows:• Competition was acknowledged to be a fundamental operating principle for the

sector in an attempt to improve efficiency.• open access to the grid was guaranteed in order to facilitate competition.• Generation of electric power was fully opened to private and public investors

as well as independent power producers. (it is envisaged that investment will be based on economic and financial criteria, taking into consideration access to regional networks, balanced domestic supply and environmental impacts.)

• regional co-operation and integration are given priority in investment to ensure reliable supply, the exploitation of low-cost energy sources for regional trade and a balancing of the erratic availability of hydropower.

• Priority is given to developing domestic power-generation capacity based on indigenous resources in order to meet increases in demand – a common theme in national energy policies.

• A commitment is made to participating in national and international research, development and application of commercially viable, large-scale technologies for renewable sources of electricity generation (Ministry of energy and Minerals of Tanzania, 2003).

in 2005, a general election was held; the incoming government reversed its earlier decision on TANesCo and delisted it from privatisation. This fundamentally altered an underlying objective of the management contract. in 2006, the government announced that NeTGroup’s management contract would not be extended. Widespread public acrimony was a factor in this decision, and the Minister of energy and Minerals was quoted as saying that ‘Tanzania was dissatisfied with the quality of management provided by NeTGroup solutions…government was obliged to listen to the views of the public following complaints about the quality of service being offered by TANesCo’.13

Then, in 2008, the electricity Act was passed. Prior to this, the sector had been regulated in accordance with the provisions of the electricity ordinance Amendment of 1957. With respect to the structure of the electricity industry, Clause 4(1) of the 2008 Act states that:

The Minister shall provide supervis[ion] and oversight in the electricity supply industry and shall in that respect…(c) take all measures necessary to reorganise and restructure the electricity supply industry with a view to attracting private sector and other participation, in such parts of the industry, [in] phases or time frames as he deems proper.


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Tanzania has experienced nearly two decades of reforms with shifting commitments to private sector participation. however the electricity Act of 2008 appears to signal a renewal of the government’s commitment to ongoing reform in the sector.

Independent power producers

independent power producers (iPPs) in Tanzania have had a chequered history. in 1993, the government first invited bids for the exploitation of the songo songo gas reserves. The project concept was extensive and included the development of infrastructure for the extraction, processing and pipeline transportation of gas, as well as the construction of a gas-to-power facility at the Ubungo power plant in dar es salaam. Negotiations with songas shareholders commenced in 1994, just as the country entered another year of drought.14

Also in 1994, the Tanzanian government signed a memorandum of understanding with independent Power Tanzania Ltd (iPTL) to provide electricity as a ‘fast-track measure’, and by mid-1995, a 20-year 100 MW power-purchase agreement between iPTL and TANesCo was signed (Cooksey, 2006). The iPTL plant was initially to be run on heavy fuel oil and, like the Ubungo turbines, was expected to be able to process natural gas once this was available. The contract with iPTL was finalised in 1997, but soon became shrouded in allegations of impropriety, negligence and corruption (Cooksey, 2006), exacerbated by the fact that it had never been subject to open tender. The plant had been planned to run on expensive slow-speed engines, but cheaper, medium-speed engines were actually installed – a change that TANesCo contended it had not been properly advised of or benefited from. As a result, and with the support of the World bank, TANesCo served a notice of default on iPTL with the intention of terminating their agreement.15 This culminated in a request for arbitration on behalf of TANesCo at the World bank’s international Centre for settlement of investment disputes (iCsid) (Gratwick et al., 2007). A decision on the matter was reached in 2000, with the iCsid ruling that the power-purchase agreement should not be terminated, but that a portion of the power tariff (capacity charge) should be lowered to match actual costs. The plant was eventually commissioned late in 2000 and, although capacity charges did come down,16 a survey by Gratwick et al. (2007) found that power from the iPTL plant was the most expensive in sub-saharan Africa at the time.

iPTL began commercial operations early in 2003, two years after their plant was commissioned. Four years later, in 2007, iPTL was embroiled in another dispute, this time between its local and foreign project sponsors,17 with accusations of misappropriation of the proceeds from power sales.18 At the time of writing, this conflict was still unresolved, iPTL was under administration, and the plant had hardly been operational since 2007.19 To complicate matters further, in 2008 iPTL sued TANesCo in a New York court demanding Us$70 million in unpaid capacity charges.20

While the electricity-supply industry was immersed in the iCsid process, the songas project was put on hold for three years. The project was, however, incurring interest charges on funds that songas equity holders had provided for start-up activities


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(known as the allowance for funds used during construction).21 eventually in 2001, the songas power-purchase agreement was finalised, and in 2004, commercial operations commenced with the conversion of the jet-fuel plants at Ubungo to natural-gas processing plants, ownership of which was transferred to songas. The following year, two additional 36 MW LM6000 power-generation units were commissioned, and the capacity of the songas plant increased to 189 MW.

Emergency power suppliers

both songas and iPTL eventually began to contribute significantly to Tanzania’s generation capacity, but this was insufficient to prevent load shedding when yet another drought occurred in 2006. Consumers were subjected to power outages for up to 18 hours at a time (Gratwick et al., 2007), and TANesCo resorted to renting emergency power plants from multinational companies, Aggreko, APr energy and the richmond development Corporation. Aggreko provided 40 MW of gas-fired power from october 2006 to october 2008, and APr energy provided an additional 20 MW from March 2007 to March 2008, but it was the contract for the provision of 100 MW by richmond that caused a major scandal.

in terms of TANesCo’s contract with richmond, which was allegedly signed in controversial circumstances,22 the company was expected to supply 100 MW of emergency power fuelled by songo songo gas for two years, starting with 20 MW in september 2006 and adding an additional 80 MW in February 2007. richmond proved to have neither the technical expertise nor the capacity to undertake the project. The initial 20 MW was deployed a month behind schedule and only after the government had advanced funds to richmond (Gratwick et al., 2007). in late 2006, dowans holdings took over the contract in an arrangement that has been described as ‘a desperate attempt by richmond to hang on to the … contract’.23 eventually dowans provided the full 100 MW, but by then the drought was over and the emergency capacity was no longer needed. Nonetheless, in terms of the contract, TANesCo was obliged to pay daily ‘take-or-pay’ capacity charges. This led to a public outcry.24 Following a parliamentary probe into the contract in 2008, the prime minister and two Cabinet ministers resigned and the president then dissolved the Cabinet.

The 2006 drought was unfortunately not the last. Following a season of low rainfall that had left hydropower-generation reservoirs running dry, TANesCo in May 2011 began to effect daily power cuts of up to 15 hours. in order to alleviate the harm that the power rationing was having on the economy (the cost of unserved energy in Tanzania is estimated to be Us$1.10/kWh25), the government announced in August of the same year that 455 MW of emergency power supply would be procured for a period of two years at a staggering cost of Tsh1.24 trillion (Us$800 million) under what was termed the emergency Power Plan. The emergency power was to be provided by symbion Power (205 MW), Aggreko (100 MW) and a tender process funded and managed by the National social security Fund (NssF) for 150 MW. in addition, the government announced that part of the existing symbion power plant (formerly dowans) would be converted to run on Jet A1, and as a result the total generation capacity of the plant


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would be ramped up to 112 MW.26 by November 2012, Aggreko had commissioned the 100 MW that had been earmarked for the firm under the plan,27 while symbion had yet to reach the 205 MW mark but had installed an additional 105 MW28, 29 of capacity, and tendering under the NssF programme had yet to be concluded.30

Mtwara Energy Project

The remote rural Mtwara energy Project (MeP) is a unique feature of the Tanzanian electricity industry. The project was initiated in 1994 when the UK-based oil and gas exploration and development firm, Tullow oil, was selected by the Tanzanian government to exploit the Mnazi bay gasfield located on the south-eastern tip of the country, close to the border with Mozambique. The project lay dormant for some time, however, and eventually Tullow oil pulled out. in 2004, the Artumas Group31 signed a gas-production agreement with the government (Ghanadan & eberhard 2007). Following the development of three wells, MeP became commercially operational in 2006.

MeP is an integrated gas-to-power project, with an installed generation capacity of 18 MW, to supply a distribution network leased from TANesCo for a period of 20 years.32 electricity demand in the area served has been estimated at 24 MW, and the possibility of setting up a 300 MW electricity generation facility, for export into TANesCo’s main grid, has been mooted (Anthony, 2007). As things stand, the project supplies electricity to the towns of Mtwara and Lindi and the surrounding districts, which were previously served by TANesCo using diesel-fired generators. by means of an interim power-purchase agreement, the project sells bulk power to TANesCo, which still owns the distribution network in the area. Negotiations are in progress with respect to MeP’s taking a 20-year lease on the distribution network.

From the controversies outlined in this section, it is easy to understand why government and others might view new private-sector investment in Tanzania’s electricity industry with suspicion; however, the provision of adequate, quality and reliable electricity supplies in Tanzania remains a sizeable undertaking. Given the government’s limited resources, the private sector could be an important partner in this endeavour. it is therefore crucial to draw lessons from the unsavoury experiences of the past and to ensure that private-sector participation is not stifled. in our view, robust planning that initiates timely procurement, the use of international competitive-bidding processes, and the development of high levels of competency in negotiation are key to more positive future outcomes.

Financial indicators and tariff structuresKey financial indicators for TANesCo over the period 2003 to 2009 are shown in Table 2.3 and reveal a utility in crisis. it is striking that, over this seven-year period, TANesCo’s total revenue from electricity sales was generally lower and, at best, just sufficient to cover its overall cost of sales (see Figure 2.3).33 An important constituent of the cost of sales is the purchase of power from iPPs and emergency power suppliers, which in


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2006 exceeded total electricity revenue. Given the significance of power-purchase costs, it might be expected that the trend in this cost element would correlate with the overall cost of sales, but that was not the case. The cost of sales increased steadily over the period, whereas power-purchase costs diminished after 2006, but a spike in international petroleum prices (from 2006 to 2008) meant that the costs of TANesCo’s own gas-fired and stand-alone diesel generation (used in rural areas) increased.

TANesCo’s enduring financial difficulties weigh heavily against the need to refurbish and expand the system and increase access to electricity. While iPPs can play an important role in this regard, a more creditworthy utility would increase the chances of such a strategy being successful.

Table 2.3 TANESCO’s financial performance indicators, Tanzania, 2003–2009 (US$ million)Indicator 2003 2004 2005 2006 2007 2008 2009electricity sales 158.85 173.03 196.26 185.38 234.27 310.04 313.47Power-purchase costs 68.03 114.44 155.94 186.85 195.36 161.54 141.45Total cost of sales 182.88 244.42 250.34 289.73 308.33 306.50 326.31operating profit (loss) (62.83) (32.55) (22.15) (125.45) (50.75) 2.26 (2.42)Profit (loss) before tax (214.05) (104.13) 43.06 (125.45) (53.94) (18.04) (36.14)Average tariff (Usc/kWh) 6.83 7.02 7.47 6.69 7.35 9.18 9.00

source: TANesCo Annual reports, 2003–200934

Note: Tsh/Us$ exchange rates based on annual rates provided by eWUrA.

Figure 2.3 TANESCO sales compared with cost of sales and power-purchase costs, Tanzania, 2003–2009

2003

2004

2005

2006

2007

2008

2009

0 100 200 300 400

Electricity sales Total cost of salesPower-purchase costs

sources: TANesCo Annual reports, 2003–200935

Note: Tsh/Us$ exchange rates based on annual rates provided by eWUrA.

US$ million


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Tariff structures

The high-voltage and general-usage categories in TANesCo’s tariff structure have consistently consumed the most power since 2002, and in 2009 accounted for 34 per cent and 28 per cent of total consumption respectively (see Figure 2.4).

Figure 2.4 Structure of electricity demand, Tanzania, 2002–2009

2002

2003

2004

2005

2006

2007

2008

2009

0 10 20 30 40 50 60 70 80 90 100

Percentage

Gold mines High-voltage supplyLow-voltage supply

General use

Domestic low usage

Zanzibar

source: TANesCo Annual reports, 2002–200936

Note: The tariff structure changed during the course of 2003 to include the category ‘domestic low usage’.

TANesCo’s tariff categories are described in Table 2.4. The general-usage category is a curious one. in cost-reflective tariff design, the object is, to the extent possible, to charge consumers based on the costs that they impose on the grid. This is almost impossible in the general-use tariff category since it consists of very diverse consumer groups whose usage and consumption patterns vary considerably.

Table 2.4 TANESCO tariff categories, Tanzania, 2010

Tariff category Descriptiondomestic low usage (1-phase 230 V) residential consumers, with the first 50 kWh

enjoying a ‘lifeline subsidy’General usage (1-phase 230 V or 3-phase 400 V) residential, small commercial, light industrial use,

public lighting, billboards etc. Low-voltage maximum demand (supplied at 400 V) industrial consumers with monthly consumption

greater than 7 500 kWh and demand less than 500 kVA

high-voltage maximum demand (11 kV and above) industrial consumers

source: TANesCo37


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Regulatory governanceAs part of Tanzania’s transition to a market economy, the government published the Competition and Utilities regulation Policy in 1999. The policy sought to establish a framework for regulating competition in general, and the utility and infrastructure sectors in particular. Consequently, the energy and Water Utilities regulatory Authority Act (the eWUrA Act) of 2001 was passed. This paved the way for the establishment of an independent regulator for the electricity-supply industry. As its name suggests, the energy and Water Utilities regulatory Authority (eWUrA) is responsible for the regulation of four interrelated sectors, namely, electricity, petroleum, natural gas and water.

Although the Act was passed in 2001, eWUrA only became operational in 2006. For independent regulatory authorities to be free to make decisions, within the confines of primary policy, and without political pressure, requires a well-defined relationship between the government and the regulatory agency. in the run-up to the passing of the Tanzanian legislation, it had been recommended that eWUrA be answerable to a government ministry with no direct relationship to any of the sectors it was to regulate. This became a contentious issue, with the World bank making funding conditional upon its acceptance, while the water and energy ministries argued that they were ceding too much power.

eventually a compromise was reached and it was agreed that, although Tanzanian legislation allocates specific policy responsibilities to the energy minister, eWUrA would report to the water ministry, which is responsible for only one of the four sectors regulated. This has the advantage of limiting the direct influence that the Minister of energy and Minerals has over regulatory decisions in the electricity-supply industry, and thus helps to entrench regulatory independence. The arrangement appears to be working well, and in an assessment of the regulator’s performance, the Minister of energy and Minerals remarked that ‘government appreciates that eWUrA is fulfilling its mandate’ and that issues that had been challenging were now being overcome.38 This was echoed in discussions with media representatives who, in general, seem to consider eWUrA independent. indeed, some journalists were of the opinion that eWUrA’s presence had brought a ‘semblance of sanity’ to the petroleum sector, where previously you ‘could get away with anything’.39

Legislative framework

The duties (and objectives) of eWUrA are laid out in Clause 6 of the eWUrA Act as follows: it shall be the duty of the Authority that in carrying out its functions it shall strive

to enhance the welfare of Tanzanian society by –a) promoting effective competition and economic efficiency;b) protecting the interests of consumers;c) protecting the financial viability of efficient suppliers;d) promoting the availability of regulated services to all consumers including low

income, rural and disadvantaged consumers;


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e) enhancing public knowledge, awareness and understanding of the regulated sectors including:i. the rights and obligations of consumers and regulated suppliers;ii. the ways in which complaints and disputes may be initiated and resolved; andiii. the duties, functions and activities of the Authority;

f) taking into account the need to protect and preserve the environment.

independent regulation is premised on the need to depoliticise potentially sensitive issues such as licensing and tariff setting through the separation of the policy-making and regulatory roles. While this separation is implicit in most countries, Clause 4(1) of the electricity Act of 2008, which complements the eWUrA Act and further clarified the roles and functions of eWUrA in relation to the electricity sector, states that: The Minister shall provide supervision and oversight in the electricity supply

industry and shall in that respect – a) develop and review government policies in the electricity supply industry;b) prepare, publish and revise policies, plans and strategies for development of

the electricity subsector;c) take all measures necessary to reorganise and restructure the electricity supply

industry with a view to attracting private sector and other participation in such parts of the industry, phases or time frames as he deems proper.

EWURA’s powers and functions

The core functions of regulation are licensing (or regulating access to the market), tariff setting and the establishment and monitoring of technical standards that promote quality and reliability in electricity service provision. eWUrA has responsibilities in all these areas as stated in Clause 5 of the electricity Act:

The Authority shall have powers to – a) award licences to entities undertaking or seeking to undertake a licensed

activity;b) approve and enforce tariffs and fees charged by licensees;c) approve licensees’ terms and conditions of electricity supply; andd) approve initiation of the procurement of new electricity supply installations.

it is notable, however, that in terms of the eWUrA Act, the regulator cannot award or cancel a licence of five or more years’ duration without prior consultation with the minister. This is at variance with the view that ‘regulators should, by law, be free to make decisions within their scope of authority without having to obtain prior approval from other officials or agencies of the government’ (brown et al., 2006: 59).

Clause 6(1) of the electricity Act assigns specific functions to eWUrA in relation to the electricity-supply industry to protect customers’ interests, promote competition in the sector to ensure access and affordablility, promote improvements in operational and technical efficiency and reliablity, improve health and safety standards, and ensure that environmental protection is integrated into industry practices.


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Regulatory independence

brown et al. observe that while the law sets out the primary policy that the regulator is obliged to follow, ‘inevitably…the primary policy will prove to be lacking in detail and will have to be fleshed out in greater detail in order for the regulator to make actual decisions’ (2006: 91). in addition, it is difficult to predict future market behaviour, and changing the primary law (usually a lengthy process) in response to market conditions is likely to be inefficient. it is therefore considered best practice for the regulator to be responsible, within certain limits, for some subsidiary policy and rule making. Consistent with this rationale, the electricity Act sets out the specific areas in which the minister can make regulations and eWUrA can make rules (see Table 2.5).

Table 2.5 Summary of the regulatory and rule-making powers of the minister and EWURA, Tanzania

The minister can make regulations that: EWURA can make rules that:ensure that electricity supplies are sufficient to meet expected demandProtect the public from the dangers arising from the generation, transmission or supply of electricity, or from the installation, maintenance or use of any electrical equipment Promote access to electricity in rural areas in accordance with the rural energy Act Promote research into, and the development of, new technologies relating to electricity supply

regulate the activities of licenseesdetermine tariffs and feesstandardise accounting and reporting proceduresset standards for customer serviceensure non-discriminatory access to transmission or distribution facilities designated for common carriage Prescribe the operation and management of the transmission and distribution system (the grid code)Prescribe how electricity is traded (market rules)ensure that technical and safety standards are monitored.Govern the inspection of licensees’ accounts and premisesdetermine terms and conditions for the granting of licences

source: eWUrA Act

Administrative and financial independence

brown et al. (2006) suggest that three institutional building blocks facilitate decision-making independence for regulatory bodies, namely:• organisational independence (the regulatory agency being separate from existing

ministries and departments);• Management independence (autonomy over internal administration and

protection from dismissal without due cause); and• Financial independence (an earmarked, secure and adequate source of funding).

As discussed in more detail below, the provisions of the eWUrA Act for staffing, funding and budgeting within the regulating authority are generally consistent with international best practice and promote independent decision-making.

EWURA’s board and staff

The eWUrA board comprises seven members who are all non-executive with the exception of the director-general (who also acts as the Ceo). The chairperson is appointed by Tanzania’s president, and the other members are appointed by the


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Minister of Water and irrigation. Appointments to the board can only be made from a shortlist of nominees compiled by a nominations committee, which is chaired by the permanent secretary of the Ministry of Water and irrigation and includes a representative from a body that represents private-sector interests, as well as a person nominated by the Consumer Consultative Council.40 This infuses an element of transparency into the board recruitment process, which is augmented by the provision in Clause 10(2) of the eWUrA Act that allows the nomination committee to advertise ‘in the news media widely circulating within and outside Tanzania’s mainland’. Furthermore, all nominees are required to be graduates of a recognised university and have at least ten years’ experience in management, law, finance, economics and/or engineering.

board members are appointed on four-year terms. For the first board, however, the legislation made special provision for the terms of various members to run for three, four or five years, thus staggering the entry of new members. The aim was to preserve board memory and competencies, and to facilitate the sustainability of the structure and the predictability of regulatory decisions.41

The eWUrA Act also provides specific and limited conditions under which a member can be removed from the board. Consistent with international best practice, these include bankruptcy, criminal conviction, conflicts of interest, ill health and failure to attend board meetings. As of 2010, no-one had been removed from the board before the end of their term. This could be an indication of the government’s commitment to the regulatory process or simply a reflection of the fact that eWUrA is still in its formative stages.

eWUrA’s organisational structure and staffing is determined by the board of directors. Unlike other countries discussed in this volume, no ministerial approvals are required in relation to staff appointments. This helps to enhance the independence of the institution. The eWUrA Act specifies that divisional directors (in other words, senior-level staff) be appointed on renewable five-year contracts, and that the recruitment process has to be carried out on a competitive basis. in addition, and to prevent a ‘revolving-door’ syndrome, the law prevents members of the board and staff of eWUrA from entering into any form of contract (employment or otherwise) or acquiring a financial interest in any entity under eWUrA’s jurisdiction for a period of 18 months after leaving eWUrA’s employment. To compensate for this, management offers competitive conditions of service. The low annual staff turnover, which averaged three out of 55 over the period 2007 to 2009, seems to indicate that employees are reasonably satisfied with the terms and conditions of their employment.

As at 2010, a draft code of conduct was available on the eWUrA website. The code is extensive, defining conflicts of interest and outlining the processes to be followed by members of the eWUrA board and its staff in declaring their interests, dealing with gifts from external parties, handling confidential information and interfacing with the public. The code also prevents board members and staff from being employed by any of the companies regulated by eWUrA for a period of 18 months after leaving its employment.


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Budgeting and funding sources

Consistent with best practice provisions for independent regulation, eWUrA determines its own budget. once approved by eWUrA’s board of directors, the budget is submitted to the Minister of Water and irrigation, but only for information purposes. The minister does not have any direct power to approve or veto the budget, but can request eWUrA to commission its auditor to assess whether the budget is fair and reasonable. if such a test proves that the budget is unreasonable, the minister can request that the budget be revised.

A comparison between budgeted and actual income from eWUrA’s inception to 2008/09 (Figure 2.5) reveals that in financial years 2006/07 and 2007/08, actual income was below budget by approximately 30 per cent and at the end of the period by about 10 per cent. by eWUrA’s own admission, this discrepancy is probably more reflective of a fledgling institution’s working out its modus operandi than any real problem with obtaining funding for the institution.42

Figure 2.5 EWURA’s budgeted and actual income, Tanzania, 2006/07–2008/09

Tanz

ania

n sh

illin

g (t

hous

ands

)

0 2 000 4 000 6 000 8 000 10 000 12 000 14 000

Budget Actual

2008/09

2007/08

2006/07

source: eWUrA, personal communication (2010)

The eWUrA Act allocates four sources of funding for the authority, namely:• fees, including those payable for the granting and renewal of licences;• regulatory levies collected from regulated suppliers;• payments or property due in respect of any matter incidental to its functions; and• grants, donations, bequests or other contributions.

The regulatory levy can be up to a maximum of one per cent of the gross annual operating revenues of licensed operators in the sectors that eWUrA regulates. The levy can be set at different levels across sectors (electricity, water, petroleum and natural gas), but must be uniform within each sector. As at 2010, the regulatory levy for the electricity sector had been set at the maximum of one per cent. As shown in Table 2.6, the regulatory levy is a significant source of funds for eWUrA,


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contributing 26 per cent, 80 per cent and 75 per cent to total income in financial years 2006/07, 2007/08 and 2008/09 respectively.

Table 2.6 EWURA’s income by revenue source, Tanzania, 2006/07–2008/09

Revenue stream

2006/07 2007/08 2008/09Tanzanian

Shilling %Tanzanian

Shilling %Tanzanian

Shilling %

regulatory levy 1 230 558 26 6 797 926 80 8 745 598 75

operating grant 3 346 529 71 1 361 466 16 2 517 690 21

Licence and application fees 102 100 2 167 040 2 62 894 1

other income 1 575 0.03 200 263 2 399 566 3

Total 4 680 762 8 526 695 11 725 748

source: eWUrA, personal communication (2010)

While this apparent reliance on a single source of income could be perceived as a risk to eWUrA, it is not necessarily problematic. After all, most government agencies tend to rely on just one major source of income, the national treasury.

Accountability

Accountability is obviously crucial to the credibility of a regulator. The law requires eWUrA to keep its books in accordance with commercial accounting standards, and to appoint an external auditor to carry out an audit at the end of each financial year. The audited accounts form part of an annual report, which has to provide detailed information on how eWUrA has carried out its mandate and exercised its powers during the preceding 12 months. The annual report has to be submitted to the Minister of Water and irrigation within three months of the financial year end and be tabled in Parliament as soon as possible thereafter. eWUrA also frequently appears before various parliamentary committees.

The controller and auditor-general43 is also required to undertake a performance audit of eWUrA at least once every two years. Clause 28 of the Public Audit Act of 2008 prescribes that the performance audit shall ‘enquire into, examine, investigate and report’, in so far as this is considered necessary, on: the expenditure of public monies and the use of resources; the conduct and performance of accounting officers, heads of department and the Ceo; compliance with environmental laws, regulations and other policies and standards; and other activity undertaken by such entities.

since some stakeholders interviewed are of the opinion that the one per cent regulatory levy imposed by eWUrA is excessive and are seeking evidence of its ‘value for money’, these performance audits could be extended to include assessments of the regulatory impact of eWUrA’s decisions on the sectors that it regulates. Alternatively, eWUrA’s board of directors could consider initiating such impact assessments themselves.


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Appeal processes

While common law provides an avenue for parties to approach the courts of law on almost any grievance, the expeditious resolution of disputes requires that regulatory systems have clear channels for matters of appeal. The eWUrA Act sets out two formal appeal mechanisms depending on whether the decision being appealed was made under delegated power (in other words, by an employee or a division within eWUrA) or by eWUrA’s board of directors.

if a party is aggrieved by a decision made by a division (department) of eWUrA, or one or more of its board members or employees, they can (within 14 days of receiving the decision) apply to have eWUrA review the issue. such an application invokes an internal review process described in Clause 27 of the eWUrA Act. Under the review process, interested parties, including the applicant, the relevant sector minister, the Consumer Consultative Council44 and any other party considered relevant, are invited to make recommendations to the eWUrA board (within 21 days of receiving the invitation). The board may then endorse, alter or dismiss the recommendations. As at 2010, the authority had not effected any formal delegation and the internal review had never been invoked.

For decisions made by eWUrA as a whole (that is, by its board of directors), including those arising out of the internal-review process, aggrieved parties may appeal to the Fair Competition Tribunal, which is a multisectoral specialised court. The tribunal consists of seven members appointed by the president in consultation with the attorney-general. A judge of the high court chairs the tribunal, which includes six other members who should have experience in the relevant industry, commerce, economics, law or public administration. Judgements and orders of the tribunal are final, and are executed in the same manner and have the same powers as those of the high court.

Given the specialised nature of infrastructure regulation, brown et al. (2006: 74) recommend that, if an ‘appellate forum reverses or changes the decision of the regulatory agency, the preferable course is for the matter to be sent back to the regulatory agency to conclude a remedy consistent with the decision of the appellate forum’. This is not the case in Tanzania, however. instead, decisions of the tribunal depend on the relief sought by the applicant.45 This means that the tribunal could, for example, alter a licensing or tariff decision, and this could in turn impact adversely on regulatory predictability.

Transparency and stakeholder engagement

Clear processes that are open to participation by a range of stakeholders can play an important role in the development of independent regulators. essentially, the more that stakeholders understand about regulatory mechanisms, and the greater the evidence that their views are taken into account when decisions are made, the greater the likelihood that they will deem the regulatory system relevant. eWUrA recognises this and, as a result, ‘all key stakeholder groups are actively, openly and routinely consulted before major regulatory decisions are made’.46 This is made


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possible primarily through two innovative structures, the Consumer Consultative Council (CCC) and the Government Consultative Council (GCC).

The CCC was set up within eWUrA itself in accordance with Clause 31 of the eWUrA Act. its functions are to:• represent the interests of consumers by making submissions to, providing views

and information to, and consulting with, eWUrA, the water minister and other sector ministers;

• receive and disseminate information and views on matters of interest to consumers of regulated goods and services;

• establish local, regional and sector consumer committees and consult with them;• consult with industry, the government and other consumer groups on matters of

interest to consumers of regulated goods and services.

The CCC comprises between six and ten members drawn from a shortlist provided by the business community and organisations recognised as being representative of private-sector interests, and appointed by the government for three-year renewable terms.47 The composition of the CCC is intended to represent the interests of low-income, rural and disadvantaged persons, industrial and business users, as well as government and community organisations.

The CCC is funded by parliamentary appropriation, by eWUrA and through grants and donations. A full-time secretariat of four persons services the CCC under the leadership of an executive secretary. The CCC functions independently of eWUrA. The establishment of the Government Consultative Council (GCC) was driven by eWUrA’s desire for a structured and transparent avenue of engagement with the government under the remit of Clause 23(1) of the eWUrA Act, which states:

The Authority shall, before the start of each year, establish an annual programme for consultation with such persons and organisations as the Authority may consider necessary or desirable to consult for the purpose of effectively carrying out its functions.

As at 2010, the GCC, appointed by the permanent secretary in the Ministry of Water and irrigation, was made up of representatives of the prime minister’s office, the Ministry of Water and irrigation, the Ministry of energy and Minerals, the Ministry of Trade and Marketing, the Ministry of Finance and economic development, the Ministry of infrastructure development, and the attorney-general’s chambers.

Members of the GCC that were interviewed believed that it provided a ‘productive’ means of engagement with eWUrA, the performance of which had been ‘commendable’ since inception. however, like other stakeholders, they expressed frustration with the poor quality of electricity supply.48

Public register and public access to information

eWUrA is required by law to keep a public register at its head office, and to make this available for public inspection during office hours. The Minister of Water and irrigation


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(advised by eWUrA) determines the categories of decisions and information held on the register. As of 2010, these included tariff applications, proposed rules, a complaints register and a draft code of conduct. A replica of the public register is available on the eWUrA website,49 which also provides access to a wealth of other information on relevant legislation, applicable technical standards and licence-application forms. A useful addition to the website would be an outline of the licensing process for potential investors. Given the generally low public understanding of the tariff-setting methodology,50 a layperson’s guide to electricity tariffs would also be useful.

eWUrA is required to publish its draft code of conduct in the government gazette (prior to finalisation), as well as any rules or regulations that it formulates, summaries of tariff decisions and any other information that it deems necessary. in practice, this kind of information is also published in national newspapers.

Public inquiriesA public inquiry is defined on the eWUrA website as ‘an official review of events or investigation held as part of legal proceedings over public concern for a particular issue’, and is a requirement for all tariff applications. Although in all inquiries, public notices are given and stakeholder views are solicited, a public hearing is not a requirement (eWUrA, 2009). in the event that a public hearing does take place, the applicant is afforded an opportunity to support their application, and stakeholders are invited to comment and respond verbally and in writing. The applicant is then given time to respond to stakeholders’ views and may be required to provide additional information.

Regulatory substancehaving examined the regulatory governance arrangements in Tanzania, we now turn to issues of regulatory substance, namely licensing, planning and tariff setting.

Licensing

Unless exempted by eWUrA, the 2008 electricity Act requires that a licence be obtained for the following activities: generation,51 transmission, distribution; supply, systems operation, cross-border trade in electricity, physical and financial trade in electricity, and electrical installations.52

however, eWUrA’s licensing system has not yet been fully implemented. only one full licence had been issued; the remainder of the licences issued were provisional (provisional licences allow a licensee to carry out ‘assessments, studies and any other activities necessary for application for a licence’ in terms of Clause 12(2) of the electricity Act). even TANesCo has yet to be awarded full licences for its activities, because it holds a 55-year licence that was due to expire in 2012. eWUrA has also exempted two other operators from licensing.

Furthermore, Clause 41(7) of the electricity Act precluded iPPs that were involved in electricity supply prior to its promulgation (including parties that have since assumed


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the assets and or rights of such iPPs) from being granted a licence for a period of five years. Clearly, Tanzania’s chequered history with iPPs and emergency power providers provided the motivation for this clause. however, this provision had the potential to harm the industry by preventing the expansion of existing operators and the use of existing assets. For example, in terms of this clause, the Cyprus-based independent Power Corporation (iPC), which purchased the controversial dowans assets in 2010, was not licensed to operate them in Tanzania and planned to ship the plant out of the country.53 The law was thus amended during the parliamentary session in July 2010.

Unlike in Kenya, the electricity Act does not set out the procedure for licensing or the timeframes that should be adhered to from the time of application to the awarding of a licence. however, Clause 8(3) of the Act does state that ‘the Authority shall, by rules, make procedures for application of a licence’. These rules have yet to be published, although the drafting has been completed and stakeholder consultation has commenced.54 The eWUrA Act also makes it mandatory for a public inquiry to be conducted prior to the awarding, renewing or cancelling of a licence, as already mentioned.

Notwithstanding the lack of a clear licensing procedure, the electricity Act sets out the matters that should be taken into account when a licence application is under consideration:• The contribution of the proposed activities to meeting the future electricity needs

of customers;• The consistency of the proposed activities with power-system expansion plans

and rural electrification strategies;• The contribution of the proposed activities to competitive conditions within the

sector;• Any likely social and environmental impacts;• The health and safety of employees and the public;• The legal, technical, economic and financial capacity of the applicant;• The costs of the activities and the effect on electricity prices;• Any representations and objections made by the public; and • other public interests that may be affected by the proposed activities.

Provision is also made for licences to be transferable on condition that the party to which the licence is being transferred makes an application to eWUrA and that eWUrA is satisfied with their legal, technical, economic and financial capacity. Clause 11(4) of the electricity Act states that: A licensee shall not transfer a licence without prior written consent of the

Authority, where – a) The transfer is made to another person who is not a licensee;b) The transfer relates to the assets which the licensee requires to conduct its

licensed activity; orc) A third party becomes, by virtue of the transfer, a majority shareholder to the

licensee.

eWUrA is also empowered to suspend or revoke a licence if its terms and conditions, or any regulations or rules, are violated. such violation would be any act


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that inflicts significant damage on public or private interests, or renders the licensee unable to fulfil its obligations.

Industry restructuringA crucial issue that has yet to be fully addressed by eWUrA and which could influence future licensing decisions is the structure of the electricity market in Tanzania. rather curiously, Clause 41(a) of the electricity Act places the following time constraint on the energy minister in relation to restructuring the electricity market: The Minister shall within one year after the coming into force of this Act prepare

and publish a policy for the reorganisation of the electricity market which policy shall stipulate – a) The parts of the electricity market that shall be subject to competition;b) The form of competition that shall be introduced in each relevant part of the

electricity market; andc) The timeframes for the introduction of competition.

in carrying this out, the minister is also required to take into account the need to restructure existing entities in the electricity-supply industry to give effect to competition. As at 2010, the policy had not been promulgated, creating a level of uncertainty in the industry. This is not entirely surprising given typical timeframes associated with policy formulation, especially when stakeholder consultation is a prerequisite. ideally, policy should be clarified before legislation is passed.

Generation planning and investmentregulators can play a proactive role in ensuring that sufficient new investment is made in generation facilities and transmission networks in order to secure the adequacy of supply. in hybrid electricity markets, explicit attention needs to be given to planning, allocation of new build opportunities (between public and private players), procurement and contracting. Although Clause 20(2) of the electricity Act clarifies responsibility for power-system planning, stating that ‘the system operator shall update on an annual basis, a Power system expansion Plan taking into consideration: a) policies plans and strategies for the electricity sub-sector; and b) proposed developments in generation and demand’, the absence of a system-operator licensee makes this difficult to effect and institutionalise. As at 2010, therefore, the Ministry of energy and Minerals remains the de facto custodian of planning, which is implemented by TANesCo with the help of outside consultants. A power master plan was concluded in 2008 and updated in 2009.

No explicit criteria exist for the allocation of new build opportunities between the public and private sectors. TANesCo retains the ‘right of first refusal’ and, in the event that it cannot raise the requisite funding from the government or donors, iPPs are then invited to bid. The consequence of this is clear from the fact that the last international competitive bid for independent power generation in Tanzania was won by songas in 1993.


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Generation procurement

Clause 5(d) of the electricity Act gives eWUrA the authority to ‘approve initiation of the procurement of new electricity supply installations’, making Tanzania one of the few countries, and the only one in this volume, where this authority is explicitly stated in the law. While this is commendable, the entity responsible for the initiation and management of the procurement process was not specified. To remedy this, eWUrA is in discussions with the energy ministry to develop a framework for the procurement of iPPs and guidelines for potential investors.55 To enhance regulatory certainty, it would be preferable that standard bid documents and power-purchase agreements form part of the framework and that the framework itself be promulgated. As experience in Kenya has proved, the building of local capacity in relation to iPP procurement processes enhances the competitiveness and therefore the sustainability of the process. This is particularly important for Tanzania.

Power-purchase agreements

eWUrA is required to approve all power-purchase agreements, as provided for under Clause 25 of the electricity Act. At the time of writing, eWUrA was in the process of compiling a set of rules related to this clause. As we stress in this volume, it is advisable for regulators to ensure that these kinds of rules include a mechanism for making regulatory staff privy to negotiations between potential iPPs and the off-taker (in this case, TANesCo). This ensures that the staff of the regulator fully understand the context in which power-purchase agreements are concluded, and are able to shield consumers from adverse tariff surprises. in our view, it is crucial for eWUrA to ensure that it retains the right to approve power-purchase agreements.

Small power projects

in order to ease the regulatory requirements on the developers of renewable-energy projects of up to 10 MW in capacity, eWUrA published a draft framework for small power projects in 2010.56 The framework minimises the amount of information required for regulatory approvals and offers a standardised power-purchase agreement and tariff-setting methodology. This standardisation is expected to make the analysis of applications to eWUrA less onerous and to simplify negotiations between the relevant parties.

Pricing and tariffs

Like many other regulators, eWUrA uses the internationally accepted revenue-requirement method57 to determine electricity tariffs and adheres to the principles of tariff setting contained in Clause 23(2) of the electricity Act, namely:• Tariffs should reflect the cost of efficient business operations;• Tariffs should allow licensees to recover a fair return on their investments,

provided that such investments have been approved by the Authority;


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• Costs covered by subsidies or grants provided by the government or donor agencies shall not be reflected in the cost of business operations;

• Tariff adjustments shall, to the extent possible, ensure price stability;• Access charges for the use of a transmission or distribution system shall be based

upon comparable charges for comparable use;• No class of customers should pay more to a licensee than is justified by the costs

it imposes upon such a licensee; and • Tariffs should enhance efficiency in electricity consumption and should encourage

adequate supply to satisfy demand.

These principles, which provide unambiguous guidance to the regulator, should help to ensure that tariffs remain cost reflective and economically efficient. They are consistent with best practice for electricity tariff determination. however, the absence of any mention of the special needs of low-income consumers seems to be an anomaly.

based on these tariff-setting principles, eWUrA published its Tariff Application Guidelines (eWUrA, 2009). These principles and guidelines explain the application of the revenue-requirement methodology. The various elements included in arriving at tariff calculations are now explored in some detail, since tariff setting is one of the most contentious areas in electricity regulation.

Operations and maintenance expenses: The ‘used and useful’ test, where the regulator determines whether a particular cost element was incurred appropriately and is necessary for the delivery of the service, is applied to operations and maintenance expenses. eWUrA also examines trends in operations and maintenance expenses over previous years. in addition, the Tariff Application Guidelines require that tariff applicants that are already in business ‘provide eWUrA with independently verifiable evidence of the actual costs recently incurred in providing the regulated service, the continued provision of which is to be covered by the proposed rate or charge’ (eWUrA 2009: 1–2). interestingly, TANesCo retained external consultants to compile this evidence for its 2010 tariff application. This arrangement could, however, bring the intention of independent verifiability into question, and the retention of the consultants by the regulator itself, at a cost that could be included in the tariff, may in future prove more credible.

Depreciation: The depreciation expense in the revenue requirement includes all assets regardless of type or source of funds. The straight-line depreciation method is used in determining depreciation as follows:

rdet = CFAt - rVt / ULA

Where det = regulatory depreciation expenses during year t in Us$; CFAt = cost of fixed assets during year t in Us$; rVt = residual (salvage or scrap) value expressed in Us$ (determined by dividing the free cash flow in the last year of the analysis period by the discount rate); and ULA = useful economic life of assets expressed in years.


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As at 2010, depreciation was not being fully expensed in an effort to keep TANesCo tariffs low. Given the perception that tariffs were excessive, the motivation for this is obvious, but it does put the replacement of existing assets at risk. it is noteworthy that TANesCo’s 2010 tariff application indicated a plan to fully reinstate depreciation by 2014.

Approval of capital investment: For new investments, eWUrA carries out a prudence and reasonableness test on cost estimates supplied, and undertakes a cost–benefit analysis that assesses the economic, financial and technical viability of the project as well as its environmental impact.

Rate of return: The rate of return applied to the regulatory asset base is based on a weighted average rate of return on the applicable source of funds, that is, debt and equity. The cost of equity is determined using a modified capital asset pricing model, and the cost of debt on actual lender’s rates, provided that these pass a prudency test. A capital structure of 60:40 (debt to equity) is assumed in an effort to reduce the pass through of expensive equity costs to electricity consumers.

Regulatory asset base: This is determined as follows:

rAbclt = rAbopt+ PCet– AdWt– rdet– ePCt

Where rAbclt = closing balance of the regulatory asset base at the end of year t; rAbopt = opening balance of the regulatory asset base determined at the beginning of year t; PCet = forecast prudent capital expenditure for year t; AdWt = forecast asset disposals and write-offs during year t; rdet = regulatory depreciation expense for the year t; and ePCt = external contributions, that is, customers, government subsidies and grants, during year t.

The valuation of assets is based on historical values. Although this is common accounting practice, for infrastructure assets with a long life-span operating in an inflationary environment, and with a devaluating local currency, the use of historical values is likely to result in significant tariff increases when major assets are due for replacement. The use of replacement values in asset valuation is therefore worth considering. Although this could place immediate upward pressure on the tariff, it would shield consumers from excessive tariff increases in the future.

Losses: eWUrA allows for some technical and non-technical losses in the tariff determination process. however, TANesCo has conceded that making the distinction between the two loss categories was a challenge and therefore a study was required to ascertain this (TANesCo, 2010b). The allowance for losses would therefore remain a composite figure until such a study was completed. For 2009, transmission and distribution losses were set at 4.5 per cent and 18 per cent respectively. our calculations, based on TANesCo data, suggest that the actual total losses in 2009 were 1 300 GWh. This is equivalent to 27 per cent and, in monetary


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terms, almost Us$120 million! According to eWUrA officials, the authority is contemplating withdrawing the entire allowance for non-technical losses in future tariff calculations in an effort to incentivise better performance in this area.58

Pass-through costs: eWUrA is also considering the development of a mechanism that would allow automatic adjustment for exogenous factors such as fuels costs, exchange rates and inflation.59

Tariffs for small power projects: The tariff methodology for small power projects, which is technology free, is based on avoided generation costs. For grid-connected systems, the feed-in tariffs are derived from an assumed seasonal mix of hydro- and thermal generation, whereas those for isolated systems are from islanded diesel-generation costs. in 2010, the feed-in tariffs for grid-connected and off-grid systems were 7.9 Usc/kWh and 26.5 Usc/kWh respectively.60

Tariff application (2010)

in May 2010, TANesCo filed a tariff application with eWUrA seeking average adjustments of 34.6 per cent in 2011, 13.8 per cent in 2012 and 13.9 per cent in 2013 in order to reach cost reflectivity.61 These figures were based on a cost-of-service study that TANesCo had commissioned in accordance with the requirements of the Tariff Application Guidelines.62

The cost-of-service study determined that for 2011, if all of TANesCo’s 11 expense categories were accounted for,63 the full cost-recovery average tariff would be 197.3 Tsh/kWh (15 Usc/kWh), that is, 66 per cent higher than the 2010 average tariff of Tsh 119/kWh (9 Usc/kWh) (ridgeway Capital Projects, 2010). The 2011 long-run marginal-cost average tariff was estimated to be 255 Tsh/kWh (19 Usc/kWh) (Vernstrom, 2010).

in order to limit the ‘rates shock’ that would arise if these tariffs were applied, it was recommended that the financial cost of service be adjusted by excluding the depreciation charge until 2013, when it would be partially expensed, and then fully reinstated in 2014. Furthermore, it was proposed that the repairs and maintenance expenses reach their full benchmark rate of 12 per cent in 2013, increasing from 3 per cent in 2011 to 6 per cent in 2012. The last adjustment was to forego return on equity over the period 2011 to 2014 (richmond Capital Projects, 2010). TANesCo’s 2010 tariff application was based on these recommendations, and, if approved, would have resulted in an average tariff of 160 Tsh/kWh (12 Usc/kWh) for 2011.

eWUrA did not grant TANesCo the tariff that it had requested, however, and instead approved in december 2012 an average increase of 18.5% that raised the tariff to 141 Tsh/kWh (10.6 Usc/kWh). in its ruling, eWUrA refused to grant TANesCo a tariff for a three-year period and deferred such a decision until what it termed a ‘credible’ cost-of-service study had been carried out by experts engaged by eWUrA. The cost-of-service study commissioned by TANesCo was found not to be credible, since TANesCo had not ascertained the cost of service of generation, transmission and distribution to eWUrA’s satisfaction; eWUrA contended that


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most of the assumptions, concepts and data used fell short of those required to determine the cost of service, and the cost drivers used were theoretically derived and not clearly defined for assessment of their prudency.64

Emergency tariff application (2011)

The procurement of emergency power tends to be a costly enterprise, and this was made evident when, in November 2011, TANesCo made an emergency tariff application to eWUrA that sought to raise tariffs by a massive 155%. in its application, TANesCo cited its difficult liquidity position due to the emergency power supply contracts and stated that by its calculations, an average tariff of 359 Tsh/kWh would reflect the costs that it was incurring in providing electricity, as compared to the 141 Tsh/kWh that it was currently charging.65

in January 2012, eWUrA ruled on the tariff application and awarded TANesCo an average tariff increase of 40.29% applicable for the six-month period to 30 June 2012. The reduction of the tariff award from the 155% that TANesCo had applied for was premised on two grounds. Firstly, eWUrA adjusted TANesCo’s projected costs and related assumptions to levels that were deemed prudent. secondly, the government made a commitment to continue settling capacity charges due to iPTL, exempted taxes on fuel used for power generation, and converted an outstanding loan it had extended to TANesCo into a grant.

in July 2012, the period that the emergency tariff would remain in force was extended by three months,66 and in october 2012 a further extension until the end of the year was announced.67

Regulatory impacthaving been in operation since only 2006, it is perhaps too early to fairly assess eWUrA’s impact on the electricity-sector industry as a whole, but it is true to say that the reliability and quality of electricity supply in Tanzania remains a major issue. ‘Load shedding is an all-too-frequent occurrence and can be linked to insufficient installed generation capacity and high distribution losses. Furthermore, customers are subjected to regular unplanned outages which are often the result of a lack of repairs and maintenance across the distribution network’ (ridgeway Capital Projects, 2010: 1). Table 2.7 shows the number and duration of outages recorded from January to september 2009.

Table 2.7 Electricity outages by voltage level, Tanzania, January–September 2009Voltage level (kV) Number of outages Total duration (hours)

220 104 115132 47 51 66 2 1 33 4 980 9 633 11 4 032 6 323

source: eWUrA official, personal communication (2010)


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eWUrA clearly has a significant role in remedying the poor quality of electricity supply in Tanzania. As at 2010, no specific standards had been put in place to regulate technical quality and reliability, but eWUrA had constituted a working group to draft a set of standards that will ultimately be promulgated by Tanzania’s bureau of standards. Adherence to these standards should form part of the conditions involved in the granting and renewal of operating licences, and should determine performance indicators for industry players and incentivise improvements across the sector.

Service standards

since the passing of the electricity Act in 2008, responsibility for the development of service standards and complaints handling has fallen to the holders of distribution licences. According to Clause 29(1) of the electricity Act, these licence holders are required to develop customer-protection standards, service-quality standards, performance standards, procedures that are appropriate to the customers of the licensee (including simplified procedures for customers in rural areas) and programmes to inform customers about related issues.

in fulfilment of this requirement, TANesCo published its Customer service Charter in 2010 in terms of which it is obliged to adhere to prescribed service levels for new connections, metering, power interruptions and complaints handling (TANesCo, 2010a). TANesCo plans to report to eWUrA on its performance against these standards. An official that was interviewed regarded the initial levels at which the standards had been set as ‘light’ and ‘achievable’, and expected the standards to become progressively more onerous and to increasingly benefit consumers.68

Pro-poor regulation

We now assess how the special needs of low-income consumers of electricity are responded to. Generally there tend to be two forms of policy intervention that governments adopt for this purpose, namely, extending access to electricity to communities that have not previously had access, and promoting affordability through subsidy schemes and appropriate tariff design.

According to ridgeway Capital Projects (2010), only 14 per cent of Tanzania’s population have access to electricity, and for rural areas, this figure has been estimated at a mere two per cent (banks et al., 2008). it is therefore not surprising that the government has set an ambitious target in its Power system Master Plan study of making 100 000 new grid connections per year between 2009 and 2014 (United republic of Tanzania, 2008). in 2009, only 60 000 new grid connections were made, a reflection of the challenge that fulfilling the target presents.69

Furthermore, by 2010, only ten projects had been undertaken by the rural energy Agency, a figure that will need to be increased significantly if any meaningful impact on access to electricity is to be made in relation to rural communities.


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The d1 tariff category is applicable to low-income consumers. This category does not attract a monthly fixed charge, and the first 50 kWh are charged at a subsidised rate. An excellent feature of the d1 tariff is inbuilt price escalation such that if consumption exceeds 283.4 kWh, the consumer pays more than the tariff in the next tariff category. This is an effective means of preventing high-use consumers from taking advantage of the scheme while specifically targeting low-income consumers.

ConclusionTanzania’s regulatory governance systems are excellent and should entrench the independence, accountability and transparency of the regulator and encourage public participation – the key determinants of regulatory credibility. in this respect, two features are notable. The first is the unique manner in which the reporting lines to the government have been separated between policy and administrative matters. by law, the minister responsible for the electricity sector (the Minister of energy and Minerals) is responsible for providing policy guidance to eWUrA, while administrative matters (such as appointing board members or the chief executive officer or ensuring the quality of annual reporting) are the preserve of the Minister of Water and irrigation. in theory, government policy should be coherent, and this arrangement should simply afford eWUrA a measure of insulation from political pressure. in practice, however, government ministries tend to be fairly monolithic and, as eWUrA is a fledgling organisation, the enduring benefits of this arrangement remain to be seen.

The second notable feature is the GCC, which aims to streamline eWUrA’s interactions with the government on regulatory issues. regulators across Africa, as well as the government ministries or departments responsible for their oversight, have grappled with the concept of regulatory independence since the start of the current wave of power-sector reform. in fact, many governments argue that regulators cannot be independent as they are quasi-governmental in nature. This has led to an increasing use of the more politically correct term ‘autonomous’. An important element of the relationship between the government and the independent regulator is the manner in which the government shares its views on matters before the board. For many regulators, this takes the form of informal consultations The GCC, however, is an attempt to formalise this engagement and make it more transparent, and there could be a lesson here for other African countries.

While the regulatory governance arrangements of Tanzania’s energy sector are commendable, the performance of the sector has been poor for many years and remains so. eWUrA is the youngest of the regulatory agencies covered in this volume. it has huge potential to play a positive role in turning Tanzania’s electricity industry around.

The authority has to rise to the challenge of facilitating new investment and overseeing improvements in the quality of electricity supply. Forward planning will be essential in order to meet unserved and future demand, and eWUrA’s role in relation to this needs urgent clarification. With responsibility for planning allocated to a yet-to-be-established system operator, eWUrA could play an oversight role in


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ensuring ongoing planning and flagging the initiation of procurement processes as the need arises. Given the controversies of the past, procurement should be based on international competitive bidding. in the event that circumstances do not permit this, safeguards should be put in place to ensure that outcome is close to that of international competitive bidding.

A grid code and technical standards need to be finalised to allow eWUrA to better enforce compliance within the industry and improve the quality of supply.

Prices must be set at cost-reflective levels, and efficiency benchmarks will have to be stipulated in the tariff-determination process to ensure that operations and maintenance costs for TANesCo are factored in at prudent levels. Furthermore, with TANesCo’s total losses estimated at over 20 per cent, there is a case for embedding stronger loss-reduction incentives into the tariff determination.

Notes1 Personal communication (2010).2 Tanesco announces 15-hour daily power cuts, The Citizen, 8 May 2011. http://allafrica.com/

stories/201105090340.html3 see discussion later in chapter 2 on emergency thermal power suppliers.4 The dark side of the richmond power generation scandal, ThisDay, 27 July 2010.

http://www.thisday.co.tz/?l=109065 eWUrA (2010). Annual report for the Year ended 30 June 2010. dar es salaam: eWUrA.6 A detailed account of TANesCo’s history and development can be found at http://www.

tanesco.co.tz/index.php?option=com_content&view=article&id=38&itemid=1267 Tanganyika gained independence from britain on 9 december 1961. on 19 december

1963, britain transferred its power over the neighbouring island territories of Zanzibar to the sultan of oman. on 12 January 1964, Zanzibaris revolted and installed their own revolutionary government. on 26 April 1964, Tanganyika united with Zanzibar to form the United republic of Tanganyika and Zanzibar, which was renamed the United republic of Tanzania on 29 october of the same year.

8 Power exports to Mombasa ceased in 1965.9 This section is based largely on Ghanadan and eberhard (2007), who give a detailed account

of the TANesCo management contract.10 debate raging over NeTGroup’s tenure at TANesCo, The East African, 14 March 2006.11 in the first two years of the contract, there were three expatriate managers, after which an

additional two were brought in.12 The second phase of the contract ran from its renewal in August 2004 until december 2006.13 Mande M, TANesCo contract: sA firm fights back, The East African, 30 May 2006.14 in response to the 1994 drought, two additional 36 MW LM6000 jet-A1-fuel turbines were

procured for Ubungo, increasing capacity to 115 MW in 1995. by that time, financial close on the songas deal had yet to be reached owing to the complexity of the project structure, changes in the project sponsors and the equity structure of the project company, among other factors.

15 it is important to note that by that time, the drought had receded, and with the capacity extensions that had been made at Ubungo, on the songas project, on a 180 MW hydro scheme at Kihansi and on the iPTL project itself, there was a relative abundance of capacity.


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16 The total investment cost was reduced from Us$150 million to Us$120 million, as a result of which capacity charges dropped from Us$3.6 million/month to Us$2.6 million/month (eWUrA, personal communication, 2010).

17 iPTL is a joint venture between a Malaysian company, Mechmar, and a local partner, ViP engineering and Marketing Ltd.

18 eWUrA, personal communication (2010).19 Malaysia firm loses in iPTL case, Daily News, 16 May 2010.20 edwin W, Tanzania says it has been overpaying power firm iPTL, The East African, 14 July 2008.21 The rationale for this arrangement was to limit delays while financial close on the deal was

reached, and to commit equity owners in songas to the project. The allowance for funds used during construction was to be capitalised at the end of the project and thus be included as a portion of the capacity charge. however, in order to limit the capacity charge, the Tanzanian government and TANesCo effected a buy-down of the funds in 2003, which by that time had reached Us$103 million.

22 The dark side of the richmond power generation scandal, ThisDay, 27 July 2010.23 Athumani r, richmond: briefcase firm that won lucrative tender, The Citizen, 7 February 2008.24 Mosoba T, TANesCo now halts dowans contract, The Citizen, 1 July 2008.25 see http://www.ewura.com/pdf/public%20notices/electricity/TANesCo%20emergency%20

Tariff-1.pdf26 see http://www.thecitizen.co.tz/sunday-citizen/40-sunday-citizen-news/13745-state-unveils-

sh12-trillion-emergency-power-proposal.html27 see http://africa.aggreko.com/news-events/press-releases/power-plant-inauguration/28 see http://www.symbion-power.com/experience/power-plant-projects/symbion-power-

plant-dodoma29 see http://www.ippmedia.com/frontend/index.php/hl=23tion=com_content.com/29rontend/

n=com_contenascom/el=2301.co208/x/s/?l=4139830 see http://allafrica.com/stories/201112140455.html31 The Artumas Group merged with an Australian firm in mid-2010 and is now known as

Wentworth resources Ltd. it is publicly listed on the oslo stock exchange.32 As at 2010.33 The cost of sales includes generation and transmission costs, the costs of purchased electricity

(from iPPs and emergency-power sources) as well as distribution and depreciation costs.34 TANesCo Annual report and Accounts, 2003–2009. dar es salaam: TANesCo.35 TANesCo Annual report and Accounts, 2003–2009. dar es salaam: TANesCo.36 TANesCo Annual report and Accounts, 2002–2009. dar es salaam: TANesCo.37 see http://www.tanesco.co.tz/index.php?option=com_content&view=article&id=63&itemid=20538 Personal communication (2010).39 Personal communication (2010).40 The Consumer Consultative Council is discussed in more detail later in the chapter.41 This is outlined in the First schedule of the eWUrA Act.42 eWUrA, personal communication (2010).43 The equivalent of the controller and auditor-general in other countries is the auditor-general.44 The Consumer Consultative Council is discussed in more detail in the section on

transparency and stakeholder participation.


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45 eWUrA, personal communication (2010).46 eWUrA, personal communication (2010).47 As at 2010, efforts were under way for the minister to pass regulations governing the

recruitment, tenure and duties of CCC members.48 Personal communication (2010).49 see http://www.ewura.com/register.html50 According to local journalists interviewed in 2010.51 This applies only to installations with capacity greater than 1 MW. installations with

capacity of between 100 kW and 1 MW are required to register with eWUrA, but are not required to apply for a licence.

52 The regulation of electrical installations is important in ensuring the safety of the public, but it is questionable whether this function, which requires competencies related to factory and household safety, should fall under the remit of a regulator, the core mandate of which is market access, pricing and technical standards in the provision of electricity.

53 dowans generators sold for sh101bn, The Citizen, 11 April 2010. http://www.thecitizen.co.tz/news/4-national-news/1320-dowans-generators-sold-for-sh101bn.html

54 eWUrA, personal communication (2010).55 eWUrA, personal communication (2010).56 see http://www.ewura.com/sppselectricity.html57 rr = rAb×ror+e+d+T, where rr = revenue requirement, rAb = regulatory asset base, ror

= rate of return, e = operations and maintenance expenses, d = depreciation and T = taxes.58 Personal communication (2010).59 eWUrA, personal communication (2010).60 eWUrA, personal communication (2010).61 in response to previous applications, eWUrA awarded TANesCo increases of 6 per cent in

2006 and 21.7 per cent in 2008.62 Two studies were commissioned and were conducted by separate consultants; the first was

a cost-of-service study covering the period 2011 to 2013 and the second was a long-run marginal-cost study.

63 The 11 categories are: tax, return on expenditure, other expenses, capital investment, provision for doubtful debts, depreciation, financing, staffing, repairs, maintenance and electricity purchases.

64 see http://www.ewura.com/pdf/oders/TANesCo%20Adjustment%20order%20Number%20010-019%20of%202010.pdf

65 see http://www.ewura.com/pdf/public%20notices/electricity/TANesCo%20emergency%20Tariff-1.pdf

66 see http://allafrica.com/stories/201207130441.html67 see http://thecitizen.co.tz/business/13-local-business/26582-no-relief-in-sight-for-buyers.html68 Personal communication (2010).69 reA, personal communication (2010).


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Uganda: Brave reforms and new growth

For decades Uganda has suffered from inadequate power supply. A disruptive civil war (from 1971 to 1986) and decreasing water levels in Lake Victoria, the main reservoir for the country’s hydro-dominated electric-power system, exacerbated this problem and led to a 60 per cent decrease in the country’s available generation capacity. it is therefore not surprising that as at 2009, overall access to electricity in Uganda was a low 11 per cent (41 per cent in urban areas and 4 per cent in rural areas),1 resulting in one of the lowest per capita electricity consumption rates in Africa. Another feature of the supply crisis is the high level of distribution losses, which were as high as 40 per cent in 1988; by 2012, these had been reduced to 27 per cent.

To deal with the crisis, the government in 1999 embarked upon the most extensive power-sector reform programme ever witnessed on the African continent. The state-owned and vertically integrated Uganda electricity board (Ueb) was unbundled, and generation and distribution were subsequently privatised through 20-year concession agreements. An independent regulator, the electricity regulatory Authority (erA), was established, together with the electricity disputes Tribunal and the rural electrification Fund. in the meantime, the country’s main hydropower station was rehabilitated, and an additional one was built nearby, bringing installed capacity to 380 MW. As a consequence of the reforms, the workforce became leaner and more professional and overall productivity in the electricity-supply industry has increased.

With generation liberalised, negotiations for the development of the first independent power producer (iPP), the 250 MW bujagali hydro project, began. Financial close on the bujagali project proved elusive however, and the negotiations became lengthy and controversial. Generating output at the two main power stations was increasingly limited by the low level of Lake Victoria, and the supply crisis deepened. in 2006, the government resorted to emergency thermal generation. inevitably, there was a rapid increase in electricity tariffs, and soon retail electricity tariffs in Uganda were among the highest in Africa. Meanwhile, following the enron debacle and allegations of impropriety, the sponsors of the bujagali project withdrew. The reforms were not yielding the desired effect.

Government remained committed to the reform process, however, and soon new developers were identified for the bujagali project. Given the long lead times required for such a large project, additional emergency generation had to be procured, but with regulatory and licensing frameworks now established, the first thermal iPP, run on cheaper heavy fuel oil, was licensed in 2007 and entered service the following year, thus displacing some of the need for emergency power. other smaller plants also began to be licensed, and by 2010, approximately 30 per cent of available generation capacity was supplied by iPPs. inroads into the power-supply deficit were steadily being made. in 2011, however, the country entered a new period of prolonged and widespread load

3


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shedding when the government, which had hitherto subsidised the cost of power from thermal generators (iPPs and emergency), ceased to do so, leading to the withdrawal of thermal generation capacity. This lasted until the much-awaited bujagali power station was commissioned in June 2012. retail electricity prices, the level of distribution losses and access to electricity are likely to remain challenging in Uganda, however.

in this chapter we detail the story of power-sector reform in Uganda, examine the elements of the regulatory system that have facilitated the process, and highlight aspects of the system that could assist the electricity sector to overcome its remaining challenges.

Uganda’s electricity sectorFrom a policy-making and regulatory perspective, Uganda’s electricity sector (depicted in Figure 3.1) has elements in common with all the countries covered in this volume – the government, through the Ministry of energy and Minerals development (MeMd), is primarily responsible for policy, and the independent electricity regulatory Authority (erA) provides regulatory oversight. A rural electrification Agency and an electricity disputes Tribunal have also been established, but the impact and extent of the reform process is most evident at industry level.

What is most striking is that, although the government has retained varied degrees of involvement in generation, transmission and distribution, the formerly wholly state-owned and vertically integrated power utility has been completely unbundled, and private-sector involvement has increased significantly. Thus, while the state-owned Uganda electricity Generation Company Ltd (UeGCL) has retained ownership of the assets at the Kiira and Nalubaale power stations,2 operations at both plants are managed by eskom Uganda3 under a concession agreement.

The state’s only operational involvement in the sector is through the Uganda electricity Transmission Company (UeTCL), which owns and operates the transmission grid. UeTCL is still wholly state owned, acts as the single buyer, and carries out the system-operator functions.

The country’s electricity distribution assets are owned by the government, through the wholly state-owned Uganda electricity distribution Company Ltd (UedCL), but distribution and consumer services are managed and operated by Umeme Ltd, a private firm which, like eskom Uganda, operates under the terms of a concession agreement.4

Additional generation capacity is provided by iPPs, the largest of which is Jacobsen elektro’s 50 MW heavy-fuel-oil-fired facility, the Namanve power station, located on the outskirts of Kampala. As at 2011, a total of seven other smaller iPPs provided an additional 83 MW, the primary fuel for some of which was derived from bagasse – a by-product of the country’s large sugar industry. Like most of the countries covered in this volume, Uganda has also had to resort to emergency thermal power. As of mid-2011, the capacity provided by emergency power supplier, Aggreko, had been reduced from 150 MW to 100 MW following the lapse of one of its three power-purchase agreements with UeTCL.


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in remote areas that are beyond the current reach of the interconnected electricity grid, small licensed generation and distribution companies supply rural concession areas, the largest of which is the West Nile rural electrification Company.

Figure 3.1 Overview of Uganda’s electricity sector, 2010


Generation capacity and load forecast

in 2012, installed generation capacity stood at 769 MW (see Table 3.1). The country is dependent on hydro resources, with approximately 89 per cent of installed generation capacity tapped from this source. The largest hydro facility is the eskom-operated 380 MW Nalubaale and Kiira hydropower stations,5 followed by the 250 MW bujagali hydropower station that was commissioned in 2012.

Ministry of Energy and Minerals Development

Consumers

Remote rural mini-grid

Industry

Uganda Electricity Generation Company (UEGCL)

Uganda Electricity Distribution Company (UEDCL)

Uganda Electricity Transmission Company

(UETCL)

IPPs

Jacobsen

Electro-Maxx

Mpanga hydroTronderPowerKasese cobaltKilembe minesKakira sugar

Kinyara sugar

Emergency power

Aggreko

Imports

West Nile Rural Eletrification Company

Umeme

Rural Electrification AgencyElectricity Regulatory Authority

Electricity Disputes Tribunal

Eskom (Uganda)


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Table 3.1 Installed generation capacity, Uganda, 2012Ownership Planta Installed MW Typeeskom (Concession)b Kiira

Nalubaale200.0180.0 hydro

IPPsbujagali energy Ltd bujagali 250.0 hydroJacobsenelectro-Maxx

NamanveTororo

50.020.0 Thermal (heavy fuel oil)

sAeMsc

TronderPower LtdKasese Cobalt Co. LtdKilembe Mineseco Power Uganda

Mpangabugoye Mubuku iii Kilembeishasha

18.013.0

9.55.06.5

small hydro

Kakira sugar WorksKinyara sugar Ltd

KakiraKinyara

12.05.0 Co-generation (bagasse)

source: erA (2012); personal communication (2011)Notes: a. This list excludes remote stand-alone systems. b. due to water constraints, the combined available capacity at the two eskom-managed plants is much lower than the installed capacity (for example, in 2010 combined available capacity at the two stations was only 138 MW. c. sAeMs = south Asia energy Management systems.

Figure 3.2 Water available for electricity generation, Uganda, 2003–2008

Actual Directive

0 10 000 20 000 30 000 40 000 50 000

Million m3

2003

2004

2005

2006

2007

2008

source: eskom Uganda, personal communication (2009)

Understandably, therefore, hydrological conditions are an important factor in the operations of the sector. From 1998 to 2008, the average water level in Lake Victoria, the main reservoir for the Nalubaale and Kiira power stations (the Jinja complex), dropped by a significant 1.5 m (Minakawa et al., 2008) and at the end of 2005, reached its lowest


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level since 1951 (Kull, 2006). This was attributed to the extended drought that occurred from 2003 to 2006, and to the ‘over abstraction of water for power generation’ (World bank, 2006b) due to non-adherence to the Agreed Curve Treaty between Uganda and egypt in terms of which the water from the lake is managed.6 Consequently, in 2006 a directive was issued ensuring that the amount of water available for power generation was cut (see Figure 3.2). This reduced power output to approximately 135 MW at the time, although strict adherence to the Agreed Curve Treaty would have meant reducing it still further to 91 MW (World bank, 2006c). hydrological conditions improved towards the end of 2006, however, and as at 2009, firm power output from the Jinja complex had risen to 175 MW, taking total available capacity in the Ugandan system at the time up to 369.5 MW (including emergency thermal power).7

The load forecast for the period 2010 to 2020 is shown in Figure 3.3. As in the other countries discussed in this volume, demand and consumption growth are both expected to be strong, averaging 6 per cent and 10 per cent per annum respectively.

Figure 3.3 Electricity load forecast, Uganda, 2010–2020

7 000

6 000

5 000

4 000

3 000

2 000

1 000

0

Peak

dem

and

(MW

)

Ener

gy (

GW

h)

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

1 200

1 000

800

600

400

200

0

source: erA, personal communication (2010)

The projected demand over the period exceeds the 2012 installed capacity, and while the commissioning of the 250 MW bujagali hydropower project in 2012 brought much relief to the power sector, the forecast shows that by 2017 the country could be facing yet another power deficit. The situation could be alleviated by capacity additions arising from the discoveries of oil and gas in 2009,8 the planned 600 MW Karuma hydropower station and other smaller generation plants.

Power-sector reformbefore outlining key aspects of the reforms in Uganda’s electricity sector since 1999, it is useful to briefly review the history of the sector. in 1936, the Kenyan-based east African Power and Lighting Company (eAP&L) was granted a licence to generate


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and distribute electricity in Uganda. Two thermal (diesel) generating stations were installed in Kampala and entebbe in 1938, marking the start of commercial electricity supply in Uganda. Later, a third thermal generating station was commissioned by eAP&L at Jinja east of Kampala. eAP&L’s presence in Uganda lasted only until 1948, when the state-owned Ueb was formed, and took over its operations (Gore, 2009).

With demand for electricity projected to rise, the government decided to build a large hydropower plant at Nalubaale (Jinja) on the White Nile. Construction commenced in 1950, and in 1954, the first two generators were commissioned, each with a capacity of 15 MW (engurait, 2005). over time, additional units of similar rating were added until the tenth and last one, installed in 1968, brought total capacity at the plant to 150 MW (engurait, 2005). At the time, this was sufficient to meet the country’s demand and to provide a surplus for export.

The 1971 coup d’état, which saw the emergence of idi Amin as leader and the start of civil war, marked the beginning of a period of decline for the power sector. by 1986, when political stability was restored (see Khadiagala, 1993), the Ueb was in serious operational and financial difficulty, and available generation capacity at Nalubaale had fallen to a paltry 60 MW (engurait, 2005). A technical audit was run by the World bank’s energy sector Management Assistance Programme (esMAP) in 1988 and found that:• the system had deteriorated due to inadequate preventive maintenance and the

lack of foreign exchange to replace equipment; • losses were running at 40 per cent of net generation, and the significant

proportion of these were non-technical; • numerous outages had significantly diminished system reliability; • staff motivation and productivity were low; and• underlying Ueb’s financial difficulties was the fact that tariffs were ‘unrealistically’

low (esMAP, 1988a).

As Uganda’s economy began to grow again in the late 1980s, demand for power quickly outstripped supply, and by 1988 load shedding had to be introduced (engurait, 2005). rehabilitation, upgrading and expansion of the power system were initiated, and when the first of several World bank-funded projects was completed in 1996,9 the installed generation capacity of the Nalubaale plant was increased to 180 MW. realising that this would still be insufficient to meet demand, however, (engurait, 2005), another project partially funded by the World bank, the 200 MW Kiira (owen Falls extension) project, consisting of five 40 MW units, was embarked upon.10 The first two units were commissioned in 2001, the third in 2002 and the last two in 2007 (World bank, 2009). These additions reduced the need for load shedding to a degree, but not entirely.

by 1993, almost a decade after the end of civil war, Ueb’s performance continued to be poor. Most of the issues that had been highlighted in the 1988 esMAP audit continued to plague the utility. system losses remained high at over 30 per cent, and from 1991 to 1993, the number of employees increased by over 50 per cent11 (World bank, 2002a). electricity tariffs that had not been adjusted for many years were increased to an average of 7.3 Usc/kWh in 1993.12 however, in what Gore (2009)


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describes as the ‘most glaring illustration’ of Ueb’s poor financial performance, the collections rate was just 58 per cent in 1997, and dropped even further to 50 per cent in 1998, largely due to non-payment of electricity bills by the government (Government of Uganda, 1999). Given the Ueb’s financial and operational difficulties, it is not surprising that poor quality and inadequacy of supply were highlighted as the most binding constraints on private-sector investment in Uganda’s economy (World bank, 2000). it has been estimated that, as the economy began to pick up, firms lost an average of 90 operating days per annum due to power cuts – in fact, so many businesses installed standby power generators that their combined capacity at the time was approximately one third that of the Ueb (engurait, 2005).

The World bank argued that the ‘major cause for the poor state of the power sector was the lack of management and financial autonomy of Ueb from the government’ (World bank, 2000). interestingly, however, although the World bank was instrumental, it was the government itself that in 1998 ‘became the driving force behind the implementation of a comprehensive power sector reform program’ (World bank, 2002a: 10). had the government not ‘owned the process’, it seems unlikely that the reforms would have been as extensive as they were.

Strategic plan of 1998

in what was described as an ‘unprecedented step to rectify Ueb’s poor management performance’ (World bank, 2002a: 10), the government replaced the managing director and made other sweeping changes to the management of the utility in 1998. This signalled a paradigm shift in government policy, and in June 1999, the government released the Uganda Power sector restructuring and Privatisation: New strategy Plan and implementation Plan (Government of Uganda, 1999).13 The new strategic plan was developed to enable the government to: • make the power sector financially viable without subsidies; • increase efficiency; • improve commercial performance; • meet the growing demand for electricity and increase the coverage area; • improve the reliability and quality of supply; • attract private capital; and • take advantage of opportunities to export electricity.

The poor performance of the power sector was acknowledged in the plan, in particular the Ueb’s: • poor financial position, which made it unable to provide a reasonable return on

investment, service debts or finance necessary investment, and made it dependent on government support;

• poor commercial performance, evident in its low collections rate (approximately 50 per cent of sales), high losses (in excess of 30 per cent) and high accounts receivable, which in 1998 were in excess of nine months; and

• low rate of coverage, with only 5 per cent of the population having access to electricity from the grid (Government of Uganda, 1999).


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in order to turn the fortunes of the sector around, the strategic plan outlined a series of proposals related to generation, transmission, distribution, rural electrification and regulation, as outlined on the following page.

Generation: The development of new generation facilities would be facilitated through international competitive bidding by the private sector on an iPP basis. The facilities at the Nalubaale and Kiira power stations would continue to be owned by the public sector, but they would be let out to the private sector through concession agreements. Co-generation would be encouraged.

Transmission: A separate transmission company would be established and would be responsible for network maintenance, system operations and dispatch, planning and bulk purchase, and the supply of electricity. bulk purchase and supply (the single-buyer function) would be undertaken by a ring-fenced business unit operating within the transmission company, which would purchase capacity from competing providers under long-term power-purchase agreements. it was envisaged that the transmission company would initially be state-owned and run, and that it would be let out to the private sector under a concession arrangement in the medium term. This entity would also:• assess potential generating projects against a least-cost expansion plan, taking the

costs of associated transmission developments into account;• suggest the location and magnitude of likely generating shortfalls to potential

generators;• consider both solicited and unsolicited proposals for the development of new

generation capacity;• carry out demand forecasting and publish the outcomes; and• undertake financial settlements and market clearing.

Distribution: The restructuring of the distribution system to make it financially viable and to improve its commercial performance was seen as the key to the success of the reform programme. it was proposed that a number of financially viable distribution companies be created out of the Ueb’s existing distribution structures. While it was recognised that this could result in some loss of economies of scale given the small size of the Ugandan market, the government was swayed by the view that any losses would be outweighed by the benefits of ‘benchmark competition’ that would arise.14

Rural electrification: When the new strategy was published, only one per cent of the population in rural areas had access to electricity. The government intended to increase this level through a focus on private-sector participation with the aim that rural communities would have access to electricity either from the national grid or isolated power networks. To achieve this, it was proposed that:• a simple, non-bureaucratic licensing framework be developed to encourage

small, independent electricity-service providers;• retail tariffs be set at the levels required to ensure the financial viability of the

local electricity service providers;• a mechanism be developed to ensure appropriate engineering of rural

electrification schemes and their minimisation of costs; and • a legal framework be developed in light of the new policy.


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Regulation: This was identified as a key component of the reform strategy in helping to rebuild the confidence of the private sector and consumers in the electricity sector. it was proposed that an authority be established to carry out the regulatory function independent of political influence. The stated objectives of regulation were to protect consumers, ensure the financial viability of companies operating in the electricity sector, promote competition and collect and disseminate information.

The strategic plan was approved by the Ugandan Cabinet in 1999, paving the way for its implementation, and three years later, in 2002, the government released its energy Policy for Uganda (Government of Uganda, 2002) which largely reconfirmed the measures contained in the plan.

Implementation of the strategy

Given that the reforms proposed in the strategic plan were far-reaching, the swiftness with which they were implemented was remarkable and may have reflected the extent of public dissatisfaction with the level of electricity service provision that had built up over time.

in late 1999, soon after Cabinet’s approval of the strategic plan, a new electricity Act was passed. The Act enabled private participation in the power sector, established the electricity regulatory Authority (erA), permitted the privatisation of the Ueb, and provided guidelines and an institutional/policy framework for rural electrification. The erA became operational in 2000, and the following year, the Ueb was unbundled and three new companies were formed to own and operate previous Ueb assets, namely, the Uganda electricity Generation Company Ltd (UeGCL), the Uganda electricity Transmission Company Ltd (UeTCL) and the Uganda electricity distribution Company Ltd (engurait, 2005).

in 2003, while UeGCL retained the assets of both utilities, the responsibility for operations at Nalubaale and Kiira was handed over to eskom Uganda under a 20-year concession agreement. eskom Uganda is wholly owned by the south African electricity utility giant, eskom holdings (World bank, 2009). For the distribution sector, however, there were delays in handing over operations to a private party. After protracted negotiations lasting over two years,15 a joint-venture agreement was eventually signed by eskom holdings (44 per cent) and Globeleq16 (56 per cent) to establish Umeme.17 Umeme then signed a 20-year concession agreement with the government for the distribution of electricity in Uganda18 and assumed UedCL’s operations in 2005 (World bank, 2009). As at 2010, responsibility for the transmission of electricity was still held by UeTCL, which has remained a publicly owned and operated company, and this seems likely to continue for the foreseeable future.

The 1999 electricity Act also established the rural electrification Fund (reF) with the aim of expanding rural electrification. in order to provide a mechanism for managing the reF, the energy minister, in 2001, published statutory instrument No. 75, which established the rural electrification board (reb). The reb is served by a secretariat, the rural electrification Agency (reA), which became operational in 2003.


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Increasing the role of independent power producers

A notable feature of the strategic plan was the assertion that all future electricity generation would be developed by iPPs. by 2012 a total of ten iPPs had been commissioned with a combined installed capacity of 389MW representing 51% of Uganda’s total installed capacity (see Table 3.1). The most significant of these is the 250 MW bujagali project. Given its sheer size and the fact that it has had a controversial history, it is instructive to delve into this project in some detail.

Bujagali hydropower project

in 2001, two years after the approval of the strategic plan for Uganda’s power sector, the Us-based Aes Corporation announced that the Ugandan government had granted final approval to its subsidiary, Aes Nile Power (AesNP), and its local partner, Madhvani international, for the 200 MW Us$550 million bujagali project on the White Nile, 10 km north of Lake Victoria.20 The announcement, which coincided with the World bank’s approval of a Us$215 million funding package for the project (World bank, 2001a), followed lengthy negotiations that had taken place after the 1994 signing of a memorandum of understanding between AesNP and the government (World rain Forest Movement, 2002). The bujagali project faced significant resistance, however, from non-governmental organisations (NGos) and environmentalists. These included the international rivers Network, which launched a global campaign against the project, arguing that bujagali was environmentally and socially harmful, and would produce power that would be too expensive for most Ugandans.21 so intense was this opposition that a few months before AesNP and Madhvani’s december announcement, the National Association of Professional environmentalists, the save bujagali Crusade and other organisations wrote to the World bank’s inspection Panel seeking a review of the project in order that funding could be withheld.22 The review did take place, but the funding was not withheld. instead, in June 2002, the executive board of the World bank approved measures proposed by its management in response to the inspection Panel’s report (World bank, 2002b).

The bujagali project was also subject to allegations of impropriety and corruption, and the fact that it was never subject to a competitive bid helped to stoke this sentiment. suspicion about the manner in which the project had been structured extended even into the Ugandan Parliament, and for nine months parliamentarians repeatedly refused to approve the power-purchase agreement. Approval was only granted on 8 November 1999, after the original tariff had been reduced, and the attendant hydrological risk reallocated between the government and AesNP.23 The power-purchase agreement remained a confidential document, however, to the dismay of NGos that suspected that it was skewed in AesNP’s favour.24 The NGos decided to take the issue to court; eventually, in late 2002, the high court ruled that the power-purchase and the implementation agreements be made public.25 The international rivers Network then commissioned an independent review of the power-purchase agreement, which found that the project was excessively priced.26


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The project continued, but the claims of corruption that had dogged it from the start became serious enough for the president of the World bank to make a statement in April 2002 that there was no evidence to support the allegations.27 remarkably, however, it was following concerns raised by the World bank itself that the Us department of Justice launched an investigation into possible corruption on the project, ostensibly because Aes is registered in the UsA.28 This led to the astonishing discovery that a government minister had in 1999 received a payment from the subsidiary of the project’s main contractor, Norwegian-based Veidekke. Following this damning revelation, the World bank suspended its support for the project in July 2002,29 and Veidekke announced that it was withdrawing from the project citing ‘increased workload’ in its other overseas projects.30 The following year, the swedish-based electrical contractor, skanska, also withdrew.31 The project was beginning to unravel, and it was thus with an air of inevitability that AesNP, still the lead sponsor of the project, announced in August 2003 that they too were withdrawing after spending Us$75 million in preparation costs.32

The government did not give up, however, and the energy minister stated that the project would proceed without Aes.33 The World bank made a significant statement soon after the withdrawal of the Aes indicating that it remained committed to bujagali in view of its potential benefits for Uganda.34 in efforts to find a new developer, the government departed from the single-sourcing process used in the Aes deal, and instead opted to follow international competitive-bidding. bids were invited in 2004 and, after pre-qualification, three were successfully submitted.35 The following year, a consortium, bujagali energy Ltd, led by Nairobi-based industrial Promotion services,36 was announced as the winning bidder.37 some disquiet remains with respect to the environmental and social aspects of the project, and in fact the National Association of Professional environmentalists again requested that the World bank’s inspection Panel review the project in an attempt to prevent it from going ahead. This goal was not achieved, however (World bank, 2008a). The winning consortium credited this outcome to the manner in which it had limited negative perceptions of the project by enhancing transparency through greater engagement with all stakeholders.38 Financial close on the Us$860 million project was reached in 2007 (eberhard & Gratwick, 2010), with the World bank providing Us$360 million in loans and guarantees (World bank, 2007a). bujagali was commissioned in June 2012.

Other IPPs

At the time of writing, the largest thermal iPP in Uganda was the 50 MW heavy-fuel-oil-fired Namanve Power station on the outskirts of Kampala. Like bujagali, it has also attracted some controversy, albeit for a much shorter period. The erA invited bids for the power station in 2006. bids were received from Norway’s Jacobsen elektro and from two local firms, electro-Maxx and African Power initiative. Following the bid-evaluation process, the project was awarded to Jacobsen elektro, which was expected to commission the plant in June 2007. however electro-Maxx disputed the


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outcome of the bid evaluation and approached the government inspector-general,39 who halted the issuing of a licence to Jacobsen elektro on the grounds that the process was fraught with illegalities and irregularities. A re-evaluation of the bids was ordered, which reconfirmed Jacobsen as the best bidder. electro-Maxx was still not satisfied, however, and took the matter to the high court, which issued an order that again restrained the erA from proceeding with issuing the licence. Jacobsen elektro was finally licensed in mid-2007 after months of legal wrangling, which pushed the planned commissioning of the plant back by a year.40 The Us$93-million power station began operating in 2008, on a six-year build-own-operate-and-transfer basis, and displaced 50 MW of more expensive emergency thermal generation. The erA was later cleared of any wrongdoing by the government inspector-general.41

There are eight other iPPs in operation in Uganda, all of which have arguably been less contentious. Two of these were set up by state-owned mining companies, Kasese Cobalt and Kilembe mines. They have been generating electricity in Uganda’s Kasese district for their own use, and both feed surplus electricity into the national grid. Kasese district is also home to the 13 MW bugoye power station owned by TronderPower Ltd42 and commissioned in 2009 at a cost of Us$55 million (NorAd, 2010). Also in 2009, electro-Maxx, the firm that had disputed the outcome of the procurement process for the 50 MW Namanve plant, built a 20 MW heavy-fuel-oil-fired plant, Tororo power station, at a cost of over Us$32 million.43 in 2011, two small hydropower plants were commissioned – the 18 MW Mpanga hydropower station developed by south Asia energy Management systems (sAeMs) at a cost of Us$23 million44 and the 6.5 MW Us$14 million ishasha hydropower station developed by eco Power, a sri Lankan firm.45 in the West Nile subregion, which is not connected to the main power grid, the 3.5 MW Nyagak hydropower station developed by West Nile rural electrification Corporation (WeNreCo), a subsidiary of bujagali developer iPs, was commissioned in 2012.46 Uganda is also home to co-generation iPPs – Kakira sugar Works and Kinyara sugar Ltd are both fired by bagasse, the residue from sugar-cane processing. The capacity of the Kakira plant is in excess of 20 MW, but only 12 MW is sold on to the power grid; the remainder is reserved for Kakira’s own use.47 similarly, at state-owned Kinyara, installed capacity is 7.5 MW, of which 5 MW is sold on to the grid (erA, 2008). Kakira began supplying the grid in 2008, and Kinyara in 2009. Power-sector reform in Uganda has thus not only opened up the sector for traditional iPPs, but also for co-generators that provide useful capacity additions for overcoming the power-supply deficit.

Emergency power

in 2005, faced with reduced available generation capacity from the Jinja complex and rapidly increasing demand estimated at 8 per cent per annum (World bank, 2006c), the government, through a competitive-bidding process, procured 50 MW of emergency diesel-fired generation from scottish-based Aggreko, which was installed at Lugogo.48 The following year, the government extended Aggreko’s contract, and the company increased its capacity by 50 MW, installing an additional emergency diesel


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plant at Kiira.49 Under a separate contract, financed by the World bank, another 50 MW emergency diesel facility was established at Mutundwe in 2008 (World bank, 2007c). The introduction of emergency thermal generation put upward pressure on electricity tariffs in Uganda. Tariffs increased by an average of 37.5 per cent in June 2006, and 41 per cent in November 2006, bringing the average tariff level to 17.2 Usc/kWh, which was high by both regional and global standards (World bank, 2007b). When the Namanve power station began operating in 2008 and was able to supply electricity more cheaply, the Lugogo plant was decommissioned.50

Post-reform performance having examined the backgrounds of some of the key players in Uganda’s electricity sector, it is interesting to look at the sector’s performance over the last decade or so. in general, the performance of the Ugandan power system has improved since the onset of reforms, with the most significant manifestation being the reduction in the extent of load shedding. Maximum demand and energy consumption related to the interconnected Ugandan power grid for the period 2002 to 2009 are shown in Figure 3.4. it is evident that from 2002 to 2007, growth in both demand and consumption was flat. This was related to the limited availability of water at the Jinja complex and the lack of alternative generation capacity. With increased water supply, however, and the entry into service of additional plants, maximum demand and energy consumption leaped by 34 per cent and 71 per cent respectively between 2007 and 2008, reflecting the extent to which load shedding had suppressed demand. in 2009, growth in both demand and energy supply continued to be strong, averaging around 10 per cent.

Figure 3.4 Maximum demand and energy consumed, Uganda, 2002–2009

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source: erA, personal communication (2010)


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Generation

other than in 2005, Uganda’s major electricity-generation company, eskom Uganda, managed to keep the availability of electricity from the Jinja complex above target levels between 2003 and 2008 (see Figure 3.5), and actual generation output matched the calculated target level from the available water (see Figure 3.6).

Figure 3.5 Actual compared with target availability of electricity from the Jinja complex, Uganda, 2003–2008

Percentage

2003

2004

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2007

200890 91 92 93 94 95 96 97

Actual availability Target availability


Figure 3.6 Actual generation compared with available energy, Uganda, 2003–2008

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despite the reduction in the water available for generation that occurred in 2006, eskom Uganda’s revenues continued to grow and the company remained profitable, as shown in Figure 3.7. This was due mainly to the take-or-pay structure of the power-purchase agreement between eskom Uganda and UeTCL, which effectively guarantees payment to eskom Uganda for its fixed costs, but also for improvements in operational efficiency. investments were also made in the maintenance and refurbishment of equipment.

Figure 3.7 Eskom Uganda’s financial performance, 2005–2009

US$ millions

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Sales Total expenditure Profit before tax

source: eskom Uganda, personal communication (2009)Note: The 2009 figures are based on projections.

eskom Uganda’s performance has been augmented by the generation capacity provided by iPPs and emergency thermal generation. in the short to medium term, as new iPP plants enter into service, most notably bujagali, the emergency-generation fleet will be retired, providing much-needed relief for electricity prices in Uganda.

Transmission

Following the unbundling of the power sector, UeTCL has performed well and has been able to establish a strong financial position due to allowances that the new bulk-supply tariff regime provided for depreciation and return on equity, intended to fund capital investments. by avoiding new investment, UeTCL built up its cash surpluses. between 2003 and 2005, provisions were made for a tariff-stabilisation fund and an escrow account for the bujagali liquidity fund. These two funds accumulated Us$27.1 million and Us$5.4 million respectively (World bank, 2009). however, with the advent of high thermal-power costs in June 2005, these funds and UeTCL’s cash surplus were depleted in an attempt to shield consumers from increased electricity tariffs. Table


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3.2 shows UeTCL’s accumulated surplus over the period 2006 to 2008. since 2006, UeTCL’s power purchases have been supported by government subsidies and, for the emergency plant at Mutundwe, a World bank facility (World bank, 2009).

Table 3.2 UETCL’s accumulated surplus/deficit, Uganda, 2006–2008 2006 2007 2008

surplus/deficit (Us$) 16 909 213 18 272 200 -14 838 961

source: office of the Auditor General of Uganda (2010)51

Distribution

Umeme inherited a very high level of distribution losses from the Ueb, and this still presents a significant challenge for the company and indeed for Uganda’s electricity sector as a whole. estimates made in 2009 put total losses at 35 per cent, of which 12 to 15 per cent were technical and the remainder non-technical and largely linked to electricity theft through illegal connections (World bank, 2009). These loss levels are similar to those that prevailed before the reform process. At 2009 tariff levels, the monetary value of non-technical losses was a staggering Us$20 million per annum. Although this has a direct impact on Umeme’s revenues, the company’s underlying costs are largely shielded within the framework of its concession agreement with the government, as shown later in this chapter in the discussion of tariffs. Umeme’s return on its own invested capital was 7 per cent in 2007 and 14.1 per cent in 2006 (World bank, 2009). Table 3.3 provides an overview of Umeme’s performance between 2007 and 2011.

Table 3.3 Indicators of Umeme’s financial performance, Uganda, 2007–2011Performance indicators 2007 2008 2009 2010 2011Number of customers 303 444 304 867 354 839 405 459 457 808electricity purchases (GWh) 1 759 1 941 2 146 2 324 2 387sales (GWh) 1 137 1 278 1 401 1 627 1 735Average retail tariff (Usc/kWh) 18 18 18 18 –Umeme component of retail tariff (%) 10.3 11.4 8.2 6.1 –Losses (%) 35 34 35 30 27operating costs (Us$ million) 30.7 39 32 48.7 44.4earnings before interest, taxes, depreciation and amortisation (Us$ million)

29.8 32.5 35.1 33.5 41.2

Capex (Us$ million) 17.7 22.8 25.8 36.1 23.3Cash generation (Us$ million) 3 -2 16.8 20.2 24.0

sources: Personal communication (2009); Umeme Annual reports, 2011 and 201252

2011 crisis

Although Uganda’s power-sector reforms have been seen as progressive by some commentators and co-operating partners, load shedding together with tariffs that are perceived to be high have generated considerable disquiet among the general


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public. This negative sentiment was stoked when, in July 2011, distribution company Umeme announced a return to widespread load shedding. Under the programme, and in similar fashion to conditions in an era that was thought to be long gone, most of Umeme’s consumers were warned to expect 12-hour power cuts every other day.53 The reason given was a generation-capacity shortfall of 50 MW during the day and 120 MW during the evening peak-demand period. however, unlike the load shedding of previous years, much of the shortfall was caused not by a lack of generation capacity but by the failure of UeTCL and the government to pay thermal iPPs and emergency-power producers, resulting in the withdrawal of their capacity. The government claimed that the depreciation of the Ugandan currency and increasing oil prices meant that the thermal power plants had become too costly to run.54 An amount of Us$75 million was reported as outstanding.55 The effect of the withdrawal of the thermal iPPs was compounded by a fire at a major substation that resulted in a total deficit of approximately 250 MW during the evening peak.56 With such a significant deficit, customers experienced prolonged load shedding, with outages of up to 24 hours being typical. No doubt this enraged the public, leading to demonstrations in the capital Kampala and other towns such as Lira, Masaka and Mbale.57

in June 2012, the long-awaited bujagali hydropower station was commissioned, providing an additional 250 MW generation capacity. As a result, occurrences of load shedding declined sharply, providing much relief to consumers. Uganda’s extensive reform path may finally be bearing tangible fruit.

Regulatory governanceWe now explore the role of Uganda’s electricity regulatory Authority (erA) by looking firstly at issues of regulatory governance, secondly at regulatory substance, and thirdly at regulatory impact.

Uganda has a clear legislative framework for electricity regulation that is anchored by the electricity Act of 1999. The Act established the erA, set out its functions and powers and provided for key elements of its administration. The Act also provided the legal basis for the liberalisation of the electricity sector and the unbundling of the vertically integrated and state-owned Ueb.

The erA became operational in 2000. its functions, as set out in Clause 11 of the electricity Act, are as follows:• To issue licences for the generation, transmission, distribution or sale of

electricity, and for the ownership or operation of transmission systems;• To receive and process applications for licences;• To prescribe conditions and terms of licences issued under the Act;• To modify licences issued under the Act;• To make and enforce directions to ensure compliance with licences issued under

the Act;• To establish a tariff structure and to investigate tariff charges, whether or not a

specific complaint has been made for a tariff adjustment;


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• To approve rates of charges, and terms and conditions, of electricity services provided by transmission and distribution companies;

• To review the organisation of generation, transmission and distribution of electricity to the extent that the organisation affects or is likely to affect the operation of the electricity sector and the efficient supply of electricity;

• To develop and enforce performance standards for the generation, transmission and distribution of electricity;

• To encourage the development of uniform electricity industry standards and codes of conduct;

• To establish a uniform system of accounts for licensees;• To advise the minister regarding the need for electricity-sector projects;• To prepare industry reports and to gather information from generation,

transmission and distribution companies;• To prescribe and collect licence fees;• To provide for the procedure for investment programmes by transmission and

distribution companies;• To approve standards for the quality of electricity supply services provided;• To approve codes of conduct in respect of the operation of transmission and

distribution systems;• To acquire information and carry out investigations relating to any of its

functions; and• To perform any other function that is incidental or consequential to its functions.

From this list, it is clear that Uganda’s regulatory authority follows established best practice, and, with the exception of dispute resolution, which falls under the jurisdiction of the electricity disputes Tribunal, is empowered to facilitate market access through licensing, to set tariffs at economically efficient levels, and to develop, promulgate and monitor technical standards.

The issue of independence as opposed to accountability is one that all regulatory organisations face. As in other countries, the legal, financial and administrative independence of the erA has to be delicately balanced with issues of transparency, public accountability and the fact that ultimately it reports to the government.

Legal independence and accountability

Clause 2 of the electricity Act states that the erA is a body corporate, with perpetual succession and a common seal that may acquire, hold and dispose of moveable and immoveable property, sue and be sued in its corporate name, and do all the other things that a body corporate may do. This, in essence, makes the erA independent of the government, but there are a number of ways in which the erA remains accountable and subject to the government through the Ministry of energy and Minerals development. For example, the five members the erA’s board of directors, known as the ‘Authority’, are appointed by the Minister of energy and Minerals development, and their appointments are approved by Cabinet. in some of the other countries discussed in this volume (Tanzania, for example), the process of determining the short-list of potential appointees to the Authority is laid out in the


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legislation, but this is not the case in Uganda, where a degree of secrecy pervades the process.58 Clause 6(1) of the electricity Act specifies that Authority appointees should be of ‘high moral character and proven integrity and competence’. They should also have proven experience in engineering, law, administration, management, finance, economics, the energy industry or in environmental matters. The energy minister designates a chairperson from among the five appointees.

Members of the Authority are appointed on five-year terms, which are renewable once. No specific provision was made to allow for sequential appointments to the erA (a device that helps preserve institutional memory and practice). As only three appointments were made to the Authority when it was initially set up in 2000, and the two remaining vacancies were only filled in 2008, an informal sequencing did take place. however, when the first three members of the Authority retired in 2010 (after reaching their two-term limit) one of the newer members also resigned,59 leaving the Authority with only one experienced member.

Consistent with international best practice, the conditions under which the appointment of a member of the Authority can be terminated are laid out in the electricity Act, namely: bankruptcy; becoming a public officer, a member of Parliament or a member of a local government council; being convicted of an offence and sentenced to a term of six months or more; being absent for three consecutive Authority meetings; being incapable of performing their duties; information that could have led to the vetting of a member during the appointment process being brought to the attention of the minister; neglecting the duties of being a member or conducting oneself in a way that is unbecoming of a member. by late 2010, no appointments had ever been terminated.

Clause 18 of the Act provides further evidence of the government’s commitment to the overall independence of the erA by requiring that any policy directive issued by the energy minister to the erA must be done in writing and gazetted. The relevant clauses state:

1) The Minister may, from time to time, give directions in writing to the Authority with respect to the policy to be observed and implemented by the Authority; except that the policy shall not adversely affect or interfere with the performance of the functions and exercise of powers of the Authority under this Act.

2) The Minister shall cause a copy of any direction given to the Authority under subsection (1) to be published in the Gazette.

in practice, however, this commitment has at times been questionable. For example, on 25 June 2009 the police raided the offices of the erA, UeTCL, Umeme and several government officials. Following these raids, a local newspaper quoted a police spokesperson as follows: ‘The Government lost a lot of money in the power sector through mismanagement. i cannot go into details because we have opened an enquiry…The Government has invested a lot of money in the power sector but it has lost almost the whole of that money.’60 The same report also quoted an anonymous source as saying: ‘somebody thinks that the tariffs are not competitive. Therefore they want to compute for themselves and establish the true price.’


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subsequently, on 14 July 2009, the Minister of energy and Mineral development instituted a special committee to investigate tariff levels in Uganda with a view to reducing them. Undoubtedly, the police are best placed to handle issues of fraud, but, issues relating to electricity tariffs and tariff structures lie at the core of the erA’s mandate, and a high level of specialised skill is required to adequately analyse these issues. Using avenues that fall outside the existing legal and regulatory framework to investigate and possibly determine tariffs is likely to undermine the credibility and independence of the erA.

Another important aspect of accountability is that the erA can and has been summoned before committees of Parliament from time to time to report on its activities and present its views on key issues affecting the sector.

Financial independence and accountability

To further secure their independence from the government, regulators require an assured source of income. Clause 23 of the electricity Act provides for a range of possible sources of funding for the erA:• Money allocated by Parliament to the Authority;• Fees including those prescribed for the processing of licence applications and

annual fees payable by licensees as prescribed by the electricity Act;• A levy not exceeding 0.3 per cent on the revenue received from generated electric

energy;• Loans from financial institutions; and• Grants from the government and grants, gifts or donations from other sources

acceptable to the energy minister and the minister responsible for finance.

of these sources, licence fees account for the greatest portion of total revenue, followed by the levy on generated electricity (see Table 3.4). in the 2008/09 financial year, these two sources accounted for 97 per cent of erA’s total revenue, typical of the funding trend for most of the regulatory institutions covered in this volume.

Table 3.4 ERA’s revenue by funding source, Uganda, 2002–2009 (US$ ’000)Funding source 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09Licence fees 796 825 922 926 1 018 1 257 1 350Levy 234 265 299 393 505 799 711 Application fees 10 8 7 20 20 15 24 Wire permits – 4 7 7 5 9 9 rental income – – 13 13 16 21 20 interest income – – – 7 15 10 17 donor grants 665 265 209 – – – –Total revenue 1 705 1 367 1 457 1 366 1 579 2 111 2 131

source: erA, personal communication (2009)Note: exchange rate conversions based on bank of Uganda official rates.

The electricity Act requires that after taking contingencies into account, any surpluses should be declared to the finance minister and then accrued to the rural electrification Fund. by 2009, no surpluses had yet been declared.


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The erA’s annual budget process is another area over which the energy minister has oversight. in terms of Clause 24 of the electricity Act, the Ceo is required to submit the budget for the following year to the Authority for approval two months prior to the end of the financial year. once approved internally, the budget is submitted to the energy minister who, in consultation with the finance minister, grants final approval.

in addition, in terms of Clause 29 of the Act, the erA is required to submit its annual accounts no later than four months after the financial year end to the auditor-general’s office or to their appointee. Thereafter, an audit has to be completed within two months and the audited accounts submitted to the energy minister, who presents them to Parliament as soon as possible. Furthermore, Clause 116(1) of the electricity Act stipulates that the erA submit an annual report to the minister within four months of each financial year end. As at 2009, these reports were not readily available to the public, but a report spanning the years 2004 to 2008 had been published and is available on the erA’s website.

Administrative independence and accountability

The electricity Act specifies that a Ceo should be appointed by the Authority for a five-year term that can be renewed once. The Ceo should be a person of high standards of integrity and maturity, who has substantial qualifications or experience in administration, economics, finance, law, management, environment or technical knowledge relating to the electricity industry. The Act also requires the Authority to appoint a secretary. beyond these two positions, the Authority has the freedom to determine its own organisational structure. in addition to the Authority, the erA has a secretariat that handles most of the day-to-day work of regulation and, by 2009, it had a Ceo and approximately 30 staff members.

one of the greatest challenges facing regulators is their ability to retain highly skilled and competent staff. in this regard, Clause 22(2) of the electricity Act states that ‘the Authority shall, with the approval of the Minister, make regulations governing the terms and conditions of employment of the staff of the Authority’.

While this might be seen as ceding some of the erA’s independence to the minister, in practice, it has not proved problematic, as proposed terms and conditions for staff have always gained ministerial approval.61 it is worth noting, however, that while conditions of service at the erA were initially viewed as competitive, which might explain the erA’s relatively low staff turnover (ten since 2000), over time this advantage seems to have been eroded to some extent.62

Code of ethics

since regulatory authorities are funded by the public and ultimately serve in the public’s interest, they have to ascribe to the highest standards of accountability and corporate governance in order to establish and preserve their credibility. in order to ensure that


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the highest standards of personal integrity are maintained, the Authority and senior members of erA staff subscribe to the Code of Conduct and ethics for Uganda Public service (Government of Uganda, 2005), which is applicable to the entire public service. The code deals with matters such as attendance to duty, time management, absence from duty, sexual harassment, customer care, conflicts of interest and accountability.

To augment this, we suggest that it would be useful for the erA to develop a code that deals with matters specific to the regulatory arena, such as the manner and conduct of the relationship between the regulator and regulated entities. This could be subscribed to by erA’s entire staff complement, not just by its senior officials.

Electricity Disputes Tribunal

As in all the east African countries covered in this volume, Uganda has a specialised court, the electricity disputes Tribunal, with the powers of a high court. This is where erA decisions can be appealed and disputes arising in the sector are adjudicated. The jurisdiction of the tribunal is defined in Clause 110 of the electricity Act, which states:

1) The Tribunal shall have jurisdiction to hear and determine all matters referred to it, relating to the electricity sector.

2) For the avoidance of doubt, the jurisdiction of the Tribunal does not include the trial of any criminal offence or the hearing of any dispute that a licensee and any other party may have agreed to settle in accordance with their agreement.

in most countries, when an appeal on a regulatory decision is heard by a court of law, rulings are made only on matters of procedural fairness, ostensibly because of the specialised nature of regulation. The wide jurisdiction accorded to the Ugandan tribunal implies that it can rule on both process and substance, namely, tariff levels, licence awards and other such regulatory matters, and it remains to be seen what precedents will be set in this regard.

The tribunal is headed by a chairperson and vice-chairperson who are qualified at the level of high court judges. They are appointed by the energy minister, in consultation with the Judicial service Commission. The minister also appoints the other members of the tribunal, but this time in consultation with the Public service Commission. These members should have high moral character, proven integrity and proven experience in at least one of the following: generation, transmission or distribution of electricity; law or administration; finance or economics; the energy industry; or environmental affairs. The minister, in consultation with the Judicial service Commission, may remove members on grounds similar to those for members of the Authority.

surprisingly, the electricity Act does not specify how many ordinary members can be appointed to the tribunal. The Act does, however, state that in order for proceedings to take place, at least three members must be present. Members of the tribunal are appointed on a full-time or part-time basis. The tribunal can also seek technical advice from persons with specialised knowledge or experience. The tribunal is funded through parliamentary appropriations and grants, or donations from sources acceptable to the finance minister. its day-to-day administration is the responsibility of its registrar. by


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2010, the tribunal had dealt with very few cases since its inception. one of the reasons for this seems to be an apparent lack of resources evidenced by the fact that the tribunal is located within the Ministry of energy and Mineral development and has only a part-time registrar working on secondment from the Ministry of Justice. As a result, the erA has tended to play an informal dispute-resolution role within the sector.

Clause 111 of the electricity Act sets out the process to be followed by any person aggrieved by a decision of the tribunal. This includes asking the tribunal to review its judgements and orders, or appealing to the high court within 30 days from the date of the tribunal’s decision or order. if the person is then aggrieved by the decision of the high court, they may, within 30 days of the decision of the appeal, take the matter to Uganda’s Court of Appeal.

Transparency and public participation

The public can play an important role in building regulatory accountability if they gain sufficient understanding of regulatory processes and mechanisms, and have evidence that their views are taken into account when decisions are made. The internet provides a useful and efficient means through which the public can be kept abreast of the workings of the regulator. As in all the countries covered in this volume, the erA has a website (www.era.org.ug) on which key documents such as Uganda’s energy policy, relevant legislation and technical reports can be accessed, as well as information about technical standards and approved tariffs. The erA also undertook to publish all major decisions of the Authority on its website. some stakeholders indicated that they believed the erA could do more with respect to information dissemination.63 it would therefore be prudent for the erA to ensure that the website remains regularly updated and that other channels of communication are maintained. For example, the erA’s annual workshops with the media could be augmented by making publications on various erA activities readily available, and in addition to public hearings held for tariff reviews, public meetings could be held on key issues that affect the sector.

The erA follows a more deliberate strategy of engagement with the public when it comes to licence applications and proposals for tariff reviews. These are published in local newspapers with requests for comments and objections. in the case of tariff reviews, public meetings are also held, at which consumers are afforded an opportunity to air their views. by opening its meetings to the public, Namibia’s regulatory authority provides an interesting option that the erA could consider. Although public attendance is woefully low in Namibia, the fact that the public are free to attend has helped to dissipate suspicion regarding regulatory decisions, particularly those pertaining to licensing and tariffs.

Regulatory substanceAs noted in the other chapters, regulatory substance is concerned with licensing, planning, the setting of tariffs and technical standards, and addressing the issue of electricity access in poor communities.


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Licensing

When electricity generation and distribution were privatised, the government negotiated concession and other agreements with eskom Uganda and Umeme, the concessionaires.64 These agreements were concluded prior to the issuing of licences by the erA. The licence conditions have therefore generally been made consistent with the provisions of the concession agreements. As a result, the erA’s regulatory discretion has been curtailed, and a significant degree of regulation in Uganda occurs by contract.

This does not mean that the erA is altogether handicapped in the regulation of eskom Uganda and Umeme, as existing legal provisions and the important monitoring roles that the concession agreements assign to the regulator (and to the asset-holding companies, UedCL and UeGCL), for asset renewal and investment, provide avenues for incentivising good performance. For future transactions of this nature, the erA has drafted a model concession agreement that takes into account its ideal licensing requirements. Late in 2010, however, this had yet to be applied.

Within this context, the electricity Act stipulates that a licence is required for generation, transmission and distribution. in addition, the holder of the transmission licence, namely UeTCL, is also licensed as the system operator. The Act also makes provision for a bulk-supply licence (for the bulk sale of electricity to distribution and supply companies), a sale-of-electricity licence (for the supply of electricity) and export and import licences. The extent to which each step of the licensing process has been elaborated in the legislation is notable and serves as an excellent guide for prospective investors. The process is clearly set out in Part V of the electricity Act and is summarised below.

Project brief: First, the prospective licensee (applicant) should submit a project brief to the erA that contains:• the financial and legal status of the applicant, their experience and their technical

and industrial competence;• a description of the project and the time-line for its implementation;• a review of the land use involved in the project and its relation to local authorities;• a review of public and private measures necessary to carry out the project;• information relating to permissions required from public authorities;• a description of the impact of the project on electricity supply, socio-economics,

cultural heritage, the environment, natural resources and wildlife; and• any other relevant information that the erA may request.

Upon receipt of the project brief, the erA is required to publish it in the national press and solicit comments from the public and all directly affected parties.

Permit award: After the project brief has been published and comment has been solicited, the erA issues a permit to the prospective licensee. The permit enables relevant studies and other activities necessary for the preparation of a licence application to be conducted.65

Licence application: A licence application is required to contain:• the legal and financial status of the applicant;


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• a technical and economic description of the project;• a description of how the projects fit in with the existing and planned power-

supply system;• the planned time of commencement and completion of the construction of the

project;• a view of the project’s adaptation to the landscape, including necessary maps and

drawings;• the impact of the project on public interest and possible mitigation;• the results and reports of assessments, including environmental impact assessments,

and any other studies carried out;• the potential impacts of the project on private interests, including the interests of

affected landowners and other rights holders; and• all relevant consents and permits required under any other law.

The licence application should also include an evaluation of all the comments received at the permit stage.

if the licence application is deemed complete by the erA, the applicant may be required to execute some form of security for the performance and observance of the conditions to which the licence may be subject, or to take out insurance cover against liabilities that may occur. Thereafter, the erA publishes a notice of the licence application in the government gazette, and affected parties and the public have the opportunity to lodge any objections to the application.

Consideration of applications and awarding of licences: The erA then makes a decision on whether to grant the licence or not. in making the decision, the following issues are taken into consideration:• The energy needs of the country, region or community;• The impact of the operation of the undertaking on the social, cultural and

recreational life of the community;• The need to protect the environment and to conserve natural resources;• Land use and the siting or route of the project;• The costs of the project;• The ability of the applicant to operate in a manner designed to protect the health and

safety of users of the service for which the licence is required and other members of the public who would be affected by the operations of the prospective licensee;

• The technical, economic and financial capacity of the applicant to render the service for which the licence is required;

• energy efficiency;• Any representations and objections from the public;• other public and private interests affected by the operation for which the licence

is required; and• The price or tariff offered.

Licences are granted for the duration determined by the erA. Within three years prior to expiry, a licensee may apply for renewal. This does not apply to hydropower facilities with capacity greater than 10 MW. These revert to the government on


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expiry of the licence. Licences are transferable, although the erA has to satisfy itself of the legal, technical and financial competence of the party to which the licence is to be transferred. The licence transfer provision is also applicable when there are changes with respect to the control of a company, for example, in share ownership.

in the event that a licence is not granted, the erA must give the applicant a statement of its reasons for the refusal. if the prospective licensee is aggrieved by the refusal, an appeal may be lodged with the electricity disputes Tribunal. There is no limitation on the number of licences that can be held by one party except where this could harm efficiency and fair competition.

Licence modification: either the erA or the licensee can initiate a process to modify an aspect of an existing licence. For the erA to do this, the electricity Act states that ‘the benefits of public interest’ should ‘significantly exceed the disadvantages of the licensee’. As for the licensee, in the event that ‘a condition of its licence has become unduly onerous and is impacting on its ability to fulfil its obligations under the licence’, it may apply to the erA for modification of the licence. in either case, if the licensee is aggrieved by the decision of the erA, an appeal may be lodged with the electricity disputes Tribunal.

Licence revocation: if a licensee is not operating in accordance with the terms and conditions of their licence, the erA may revoke the licence. before doing so, the licensee would be notified, the notice would be published in the government gazette and in a national newspaper, and the licensee would be given an opportunity to respond. The erA would then make a decision after considering all the facts. The licensee may appeal against the decision at the electricity disputes Tribunal. When a licence is revoked, the erA is required to take all necessary actions to ensure that the service to consumers is not unduly interrupted.

Licensed projects

one of the greatest achievements of power-sector reform in Uganda has been the number of iPPs that have been attracted into the market, including those of relatively small capacity. by 2012, a total of 389 MW, 51 per cent of installed generation capacity, was being provided by ten private developers. in addition, erA had also issued permits, the combined generation capacity of which was in excess of 200 MW.

Clearly, the power-supply deficit has been a major factor in attracting new investors into the sector, but the investor interest is also a testament to the track record and credibility established by the erA.

Power-sector planning and investment procurement

To keep the existing systems running, all the players in the industry carry out operational planning as a matter of course, but longer-term system-development planning is crucial for ensuring sustained power supply and will be key to the success of the government’s development agenda for Uganda. in theory, long-term planning is the responsibility of UeTCL.


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in practice, however, several industry stakeholders revealed that there tends to be a lack of clarity in terms of where actual responsibilities and oversight lie.66 UeTCL does carry out transmission planning and is in charge of the demand forecast. Nevertheless, as of 2009, the power-system master plan for Uganda was outdated. What seems to be required, therefore, is a more formal allocation of the planning role to UeTCL, perhaps by the inclusion of a long-term system-planning function in UeTCL’s system-operator licence. With the significance that this function has for ensuring the adequacy of Uganda’s electricity system, the erA could also set up an oversight committee of key stakeholders.

it is also crucial that system-development plans are strongly linked to the procurement process. Although there are guidelines on the procedures for new investors relating to concession agreements, power-purchase agreements and licensing, there is no formal mechanism for initiating a bid, based on the output of planning processes. With Uganda apparently poised to emerge from its decades-long power-supply deficit, such a mechanism could ensure that this turnaround is sustained.

Uganda’s own experience and that of other countries discussed in this volume clearly exposes the potential pitfalls of unsolicited bids. Mechanisms should therefore be developed to ensure that the outcome would be a close proxy to that of a competitive-bidding process if single sourcing becomes unavoidable.

There are two final points to make on the issue of planning and both relate valuable lessons learned from the bujagali project. The first is that a governmental stakeholder committee can be a useful means through which requisite approvals from various agencies can be facilitated in the case of large power projects. The second is that there is great merit in the regulator having observer status in negotiations relating to power-purchase agreements, an issue that we have stressed several times in this book.

Pricing and tariffs

As a basis for determining tariffs, the erA published the electricity (Tariff Code) regulations in 2003.67 These contain the following set of objectives:• To provide consumers with fair and reasonable price structures consistent with the

maintenance of a financially and operationally secure electricity-supply system;• To structure the costs reflected in the tariff in such a way as to encourage consumers

to make efficient use of generating, transmission and distribution assets;• To encourage operators towards efficient use of electrical plant and increased

operational effectiveness based on financial benefits and penalties;• To provide all licensed participants in the public electricity industry with a fair and

reasonable return for their service and production, including a reasonable profit;• To encourage consumers towards efficient and economical use of energy based

on price signals;• To provide a structure that accommodates future progress towards a commercially

competitive market system;• To provide for a tariff structure and regulatory environment that gives confidence

to current and prospective investors in the Uganda electricity industry; and


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• To separate components of costs and tariffs that relate to natural monopolies from those components that could eventually become market based.

The Tariff Code also sets out guiding principles that should be applied in order to achieve these objectives:• Tariffs shall be based on accurate cost information provided by operators and a

transparent formulation and review process;• Tariffs shall reflect short-term variations in costs to reflect the fact that electricity

as a commodity cannot be stored;• Tariffs shall be structured and developed in such a way as to reflect variations in

costs imposed on the system by the time of use, seasonal factors, consumer load profile, voltage levels and similar factors; and

• Tariffs shall reflect the true cost of service and provide clear price signals to the consumers on the economic and efficient use of energy.

since the generation, transmission and distribution aspects of electricity delivery are separated in Uganda, different formulae are required to calculate the costs and relevant tariffs for each step of the process. it is therefore interesting to study these formulae in some detail.

Generation tariffs

Eskom Uganda: As already noted, a significant portion of regulation in Uganda occurs as a result of existing concession agreements, and methods for the determination of tariffs are set out in those contracts. The power-purchase agreement between eskom Uganda and UeTCL provides for a capacity-only, take-or-pay tariff, which is referred to as the capacity price. The core components of this are an allowance for a return on capital investment that eskom Uganda puts into the plant, which is allowed to earn a return of 12 per cent; operations and maintenance (o&M) costs as originally bid for; and the concession fee. The o&M component is adjusted quarterly for the Us dollar/Uganda shilling exchange rate and inflation. The effective capacity payment is inversely proportional to the target availability for the plant, which is set by the erA, and was at 96.5 per cent in 2009. The capacity-payment derivation is described below and in Figure 3.8. The formula for the capacity payment is:

PMT = CP × AC

Where PMT = capacity payment in Ugandan shillings;CP = capacity price in Ugandan shillings per kW; andAC = available capacity in kW.

The capacity price for each hour is determined as follows: iN + oM + CF

TC × 8 760 × TA

Where iN = investment component;oM = o&M component;


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CF = concession fee component;TC = tested capacity in kW; andTA = target availability.

The investment component is the costs associated with eskom’s capital investments. These are calculated in Us dollars and converted to Ugandan shillings quarterly for pricing purposes. A rate of return of 12 per cent is earned on these investments.

The O&M component is the operations and maintenance costs as bid at the time of procurement plus the regulatory fees due to the erA. The nominal costs are fixed but adjusted quarterly for inflation and the Us dollar/Ugandan shilling exchange rate.

The concession fee is set out in the concession agreement.

The target availability is set annually by the erA at between 94 per cent and 97 per cent. As at 2009, it was set at 96.5 per cent.

Figure 3.8 Elements of Eskom Uganda’s capacity payment, 2010

Capacity payment = CP x AC

Capacity price

= IN + OM + CF TC x 8 760 x TA

12% return

Cost

Capacity payment

As declared on a daily basis

O&M

USh

USD

RF

TC

TA

CF

AC

UEGCL administrative budget and loan repayment

(pass-through cost)

Plant health

Agreed with UETCL

CP

IN

source: eskom Uganda, personal communication, 2010Note: AC = available capacity in kW; CF = concession fee component; CP = capacity price in Ugandan shillings per kW; iN = investment component; oM = o&M component; rF = regulatory fees; TA = target availability; TC = tested capacity in kW; Us$ = Us dollars; Ush = Ugandan shillings

A salient feature of the power-purchase agreement is that UeTCL assumes responsibility for the hydrological risk, and eskom Uganda is therefore guaranteed


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its capacity payment, regardless of the amount of water discharged from Lake Victoria. it should be noted that such provisions are not uncommon in this type of agreement. in certain respects, they are a response to funders’ requirements and can help lower the cost of financing such projects. eskom Uganda’s generation tariff was due for renegotiation in 2009, with revised charges being applicable from 2010.

Thermal power plants: The cost of thermal power is a significant factor in Uganda’s energy mix. According to one news report, ‘it contributes about 49 per cent of power generated, and almost 90 per cent of the money collected (from consumers) goes back to finance the operations of the thermal plants’.68 For these plants, a two-part tariff is in force. The tariff comprises a capacity charge to cover fixed costs, and an energy charge that covers variable costs (including o&M and primary fuel such as dieselorheavyfueloil).Quarterlyadjustmentstakeintoaccountinflation,exchangerate movements and, in this case, the cost of primary fuel.

Bulk-supply tariffs

in the absence of any concession contract that binds UeTCL’s bulk-supply tariff, the erA has some freedom to regulate tariffs. The erA applies the revenue-requirement method 69 in determining the bulk-supply tariff. however, in its application of the method, the erA does not include a rate of return on UeTCL’s asset base; neither does it provide for depreciation. ordinarily, only grant or government-funded assets would be excluded from earning a return, but even these would be included in the depreciation account to ensure their replacement. it seems that the reason for this anomaly is the pressure on the erA not to increase already-high prices. in support of this, the erA argues that UeTCL’s expansion and re-investment programme would always be funded by the government. Furthermore, there was some unease as to whether the increased revenue that would accrue to UeTCL, should these factors be included in the determination, would be appropriately utilised.70 As mentioned earlier, however, there is evidence that UeTCL did build up healthy cash reserves in the initial years of reform. regardless of these concerns, it would be beneficial for the erA to understand the true cost of providing the bulk-supply service, as this would provide the government with a robust basis for its continued funding of UeTCL.

in effect, therefore, UeTCL’s revenue requirement comprises only the allowed o&M plus tax. determining the prudency of this expense presents a challenge to many regulators. in 2010, the erA was planning to undertake some form of international benchmarking in this regard,71 which should provide an objective means of addressing this challenge.

Distribution tariffs

The retail tariff charged by Umeme is as contained in its concession agreement with the government. in discussing the Umeme tariff, it is important to note that the drought and subsequent reduction of energy generated at the Jinja Falls complex in 2006 meant a drop of about 20 per cent in the energy supply available to Umeme of


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about 20 per cent (World bank, 2007b). As a result, Umeme had less energy to sell, and its ability to recover fixed costs was undermined to the extent that its ongoing viability became questionable. For this reason, in december 2006, the government restructured the distribution concession in order to provide some compensation to Umeme (World bank, 2007b).

The retail tariff is derived as follows for each customer class:retail tariff = (PsP + dP) / (1 – TUCF)Where PsP = power supply price;dP = distribution price; andTUCF = target uncollected debt factor, currently 7.5 per cent.

The power-supply tariff is the bulk-supply tariff from UeTCL, plus any amounts outstanding from the previous period, plus an allowance for distribution losses:

PsP = (bsT + r) / (1 – LF)Where PsP = power supply tariff;bsT = bulk-supply tariff;r = reconciling amount; andLF = target distribution losses.

The distribution price is the distribution costs allocated to each customer class based on assumed usage:

ds = oPN + iNdX + LPWhere ds = distribution costs;oPN = operating costs;iNdX = costs related to capital investments; LP = lease repayments.oPN = doMCadj + rF – or

Where doMCadj = operating costs in Us$ as bid, split into local and foreign components and then adjusted according to foreign exchange and inflation movements;rF = regulatory fees; andor = other revenues (such as connection charges as billed in the previous year).

iNdX = Cr + ri + TX

Where Cr = the amount equivalent to the annual depreciation charge on the current allowable capital investments; andTX = income taxes payable with respect to the return on capital investments.ri = (Ni + WC) × roi

Where Ni = net un-depreciated allowable capital investments;WC = working capital on the basis of target days’ lag; androi = return on investment at 20 per cent on a reducing-balance basis,72 the return on capital investment as contained in the bid for the concession.


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Three features embedded in the retail tariff should be noted. Firstly, the calculation includes an allowance set by the erA for uncollected revenue, the target uncollected debt factor (TUCF). This compensates Umeme for unpaid electricity bills, and in 2009 this was set at 7.5 per cent. secondly, the distribution loss factor (LF) provides Umeme with a shield from distribution losses in the various consumer categories. in 2009, this was set at between 9 and 36 per cent depending on the customer class. Allowance is also made for quarterly adjustments to reflect exchange rate, inflation and bulk-supply tariff fluctuations.

Umeme pays a form of rental for using the government’s distribution assets through a lease payment. This covers the following items: • debt servicing on UedCL’s current loans from the international development

Association and the African development bank;• debt servicing on UedCL’s arrears, dating from before the concession;• an administrative fee, for UedCL’s operating budget;• a return on UedCL’s equity invested in the distribution network as allowed by

the erA; and• an amount equivalent to the depreciation that UedCL incurs on assets it

acquired prior to the start of the concession.

The lease payment, which is similar in structure to that applicable to eskom Uganda in relation to UeGCL’s debt servicing and other expenses, accrues to an escrow account with a ceiling of Us$20 million. Umeme can draw on this account if the government defaults on the payment of its electricity bills.

The proportions of the key components in the tariff, as at 2009, are shown in Figure 3.9.

Figure 3.9 Key components of Umeme’s retail tariff, Uganda, 2009Lease repayment

7%

Operating costs 14%

Investment returns 12%

source: Umeme (2010)73

over the period 2006 to 2009, tariffs to consumers did not change. This was made possible by government and World bank subsidies, which were estimated at Us$129 million for the 2007/08 fiscal year (World bank, 2007b). in december 2009, the erA announced a 10 per cent average reduction in retail tariffs,74 but the

Power supply price 67%


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subsidies remained in place. To effect this, the following variables in Umeme’s tariff derivations were adjusted: targeted distribution losses were reduced from an average of 31.6 per cent in 2009 to 28 per cent; the collection target was increased from 93 per cent to 95 per cent; and the working-capital allowance was reduced from 60 days to 30 days. increased generation as a result of iPPs, as well as the strengthening of the Ugandan shilling against the Us dollar, also drove the reduction in tariffs. For domestic consumers, the tariff changed from 426.1 Ush/kWh to 385.6 Ush/kWh, which as of october 2010 was equivalent to 18 Usc/kWh – a figure that was still high by regional and international standards.

Technical standards

The erA draws its mandate for the regulation of technical standards from Clause 11(i), (j), (p) and (q) of the electricity Act.75 in 2003, the following statutory instruments were promulgated by the erA: the Primary Grid Code, the safety Code, theQualityofServiceCodeandInstallationPermits.

in general, the codes are detailed and clearly state the minimum standards that should be adhered to. however, the quality and reliability of electricity supply in Uganda has remained poor, and there has been no discernible improvement since Umeme was established in 2005, with the possible exception of the time it takes to restore supply (see Figures 3.10 and 3.11).

Figure 3.10 Reliability indices, Uganda, January 2006–May 200912.00

10.00

8.00

6.00

4.00

2.00

0.00

SAIDI

SAIFI

CAIDI

Jan

2006

Mar

200

6

May

200

6

Jul 2

006

Sept

200

6

Nov

200

6

Jan

2007

Mar

200

7

May

200

7

Jul 2

007

Sept

200

7

Nov

200

7

Jan

2008

Mar

200

8

May

200

8

Jul 2

008

Sept

200

8

Nov

200

8

Jan

2009

Mar

200

9

May

200

9

Inde

x

source: Umeme, personal communication (2009)Notes: sAidi (system average interruption duration index) is designed to provide information about the average time that service to customers is interrupted, i.e. sAidi = customer interruption durations/total number of customers served. sAiFi (system average interruption frequency index) is designed to give information about the average frequency of sustained service interruptions per customer over a predefined area, i.e. sAiFi = total number of customer interruptions/total number of customers served). CAidi (customer average interruption duration index) represents the average time required to restore service to the average customer per sustained interruption, i.e. CAidi = customer service interruption durations/total number of customer interruptions.


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The drought of 2006, and the subsequent power crisis, impacted heavily on available capacity. This, together with the poor state of power networks, especially for distribution, have adversely affected the reliability and quality of supply, but the erA could still enhance its oversight effort in this regard. For example, the technical codes issued by the erA require that licensees regularly report on their technical performance to the regulator. Compliance with this provision is generally poor, however, with some reports being up to six months late.76 There should be sanctions for this. Notwithstanding the ‘power crisis’, the erA should consider re-examining the overall regime for monitoring and enforcing compliance according to standards of quality and reliability. This would be consistent with the wishes of some stakeholders who would prefer more visibility on the part of the erA in this area.77

Figure 3.11 Outage durations, Uganda, January 2005–May 2009

Load shedding

Shut down

30 000

25 000

20 000

15 000

10 000

5 000

0

Jan

2005

Mar

200

5

May

200

5

Jul 2

005

Sept

200

5

Nov

200

5

Jan

2006

Mar

200

6

May

200

6

Jul 2

006

Sept

200

6

Nov

200

6

Jan

2007

Mar

200

7

May

200

7

Jul 2

007

Sept

200

7

Nov

200

7

Jan

2008

Mar

200

8

May

200

8

Jul 2

008

Sept

200

8

Nov

200

8

Jan

2009

Mar

200

9

May

200

9

Hou

rs

source: Umeme, personal communication (2009)

Pro-poor initiatives

Various initiatives within Uganda’s power sector specifically target the unique needs of the poor. For example, all domestic consumers benefit from a lifeline tariff at the rate of 4.6 Usc/kWh78 for the first 15 kWh of consumption per month. This is assumed to be sufficient to power three energy-saving bulbs and a radio.79 Additional consumption is charged at the full rate of 18 Usc/kWh.80 in 2007, the government launched an initiative whereby 800 000 subsidised energy-efficient compact fluorescent light bulbs (CFLs) were exchanged for incandescent bulbs at a rate of three per household. This resulted in a reduction of 28 MW in the country’s peak demand, and electricity bills were cut significantly. Unfortunately, not all consumers benefited from the exchange, and there are now concerns about the safe disposal of the CFLs.

Furthermore, in accordance with the electricity Act, a levy of 5 per cent is applied to all bulk electricity sales, and the money accrues to the rural electrification Fund


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(reF). other sources of funds for the reF, which is administered by the rural electrification Agency, include parliamentary appropriations, surpluses from the operations of the erA, grants from donors and loans. For rural electrification projects, the reF subsidises 100 per cent of the cost of transformer installations and 15 per cent of the cost of a new connection. This enables rural households to be connected at a reduced rate of Us$25 per connection.81

in some remote rural concessions, pre-payment metering has been installed, and as at 2010, Umeme had commissioned a feasibility study into the countrywide deployment of this technology.

Extending electrification

in 2001, under World bank-led assistance, the energy for rural Transformation (erT) project was commissioned. The project aims to develop the energy and iCT sectors in rural areas in order that they can more meaningfully contribute to the quality of life of households. A key objective of this project was to increase the electrification rate in rural areas from one per cent (as of 2001) to 10 per cent over ten years. An electrification master plan was developed and provides a basis for donors to fund projects. Projects of a more ad hoc nature are funded exclusively by the government. since its inception, 30 000 new connections have been made. The project has recently been extended to 15 years.

Unique to the erT project are its rural concessions. originally it was intended that these be bid for on a turnkey basis. This failed, however, and the reA now engages its own contractors to build the network and thereafter issues a tender for the concession. bids are assessed based on the proposed tariff, o&M costs, lease fees, new connection costs and the expected number of new connections. The concessions are granted for a period of 10 years and are subject to an annual erA tariff review. by 2010, 11 such rural concessions had been set up. small generation projects with capacity of less than 20 MW are also funded under the erT programme.

in terms of extending the grid and increasing access to electricity, Umeme is permitted to expand its network by up to one kilometre from where the grid was when the concession agreement was put in place, and in rural areas, the reF subsidises Umeme’s expansion. over the period 2005 to 2008, approximately 93 000 new connections were made.82 This exceeded the target of 60 000 included in Umeme’s concession agreement, but was insufficient to satisfy the demand for new connections given the low access rate that prevails in Uganda. A further 75 000 new connections are expected to be made between 2010 and 2013.83

ConclusionThe extensive power-sector reform that has taken place in Uganda presents useful lessons for the rest of the continent, not least by revealing the importance of long-term government commitment if such an undertaking is to yield positive outcomes. The Ugandan government remained true to its initial reform agenda, even when


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faced with the controversies that surrounded the bujagali and Namanve projects, and the need to install expensive emergency generation capacity. however, the 2009 police searches at the offices of the erA, the institution of an ad hoc committee to investigate electricity tariffs, and the failure to settle bills with iPPs pose the risk of undermining not only the credibility of the regulator but the country’s electricity sector in general, as well as the entire reform process.

A decade after the reforms began, there has been a flurry of interest in investment in the power sector, and with the commissioning of bujagali in 2012, capacity additions from iPPs have eclipsed pre-reform installed generation capacity, a feat that no other country featured in this volume is likely to attain in the short term. The initial difficulties encountered with the first two iPPs seems to have set the Ugandan authorities on a steep learning curve, and they have since increased their competencies and established a good track record in the areas of tendering, licensing and contracting. however, UeTCL’s failure to settle its dues to iPPs in 2011 casts a dark shadow over the future of the country’s power sector.

Uganda’s electricity sector remains small, and the literature questions the merits of unbundling smaller power systems, where the benefits of economies of scale are less evident. however, restructuring in Uganda has improved levels of professionalism and financial transparency in the sector. Cost drivers such as the emergency thermal generators and high distribution losses are clearly evident, as are the performance levels of the various industry players. Privatisation has also seen an increase in productivity, as the industry-wide staffing level decreased from approximately 3 000 in 1999 to 2 000 in 2009.84 An additional outcome of privatisation has been the progressive liquidation of the legacy of debt incurred by Ueb for its capital-expansion programmes.

These remarks should not convey the impression that the sector has overcome all its challenges. The quality and reliability of power supply remain unsatisfactory, while technical and commercial losses remain high. These are areas that require the erA to improve upon its incentives, and the 2010 reduction in the allowance for losses in Umeme’s tariff is a significant first step. high electricity tariffs are also a major issue in Uganda, and all options for sustained cost reduction need to be explored. Granted that the commissioning of bujagali is likely to bring about long-desired tariff relief, all options for sustaining this tariff reduction should be explored. one such avenue could be restructuring repayments on the Ueb’s debt, which is factored into eskom Uganda and Umeme’s lease agreements and accrues to the government. in the event that these lease payments could be waived, there would be room to provide additional relief to electricity consumers.

increasing access to electricity also presents a considerable challenge for Uganda. The rural concessions supported by the energy for rural Transformation Project and the rural energy Fund provide important avenues for meeting this challenge. They should be augmented by imposing onerous but achievable connection targets on Umeme, with appropriate incentive structures and adequate monitoring by the erA and UedCL.


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The Ugandan power sector has made considerable progress since unbundling and privatisation, but this could all be reversed in the absence of the government commitment that has made it all possible.

Notes1 see http://www.eac.int/energy/index.php?option=com_docman&task=doc_

download&gid=62&itemid=702 This gives the government a 70 per cent stake in Uganda’s generation capacity, but it plays

no operational role in running the plants. 3 A subsidiary of the south African national electricity utility, eskom.4 Umeme is a swahili term that means ‘lightning’ or ‘electricity’.5 Nalubaale and Kiira were previously known as owen Falls and owen Falls extension respectively,

and are now referred to collectively as the Jinja complex, since Jinja is the nearest town.6 The discharge of water from Lake Victoria is regulated by the two dams at Nalubaale and

Kiira in accordance with the Agreed Curve Treaty, an agreement between Uganda and egypt that is over 50 years old and is intended to simulate the natural discharge of the lake in the absence of the dam infrastructure. discharges in 2004 and 2005 were found to be higher than the Agreed Curve level, however, (Kull, 2006). it has been argued that the Kiira dam and power station are over-sized, and do not adequately take into account the long-term average water level in the lake, including droughts that have occurred over the last 100 years.

7 erA, personal communication (2009).8 Pagnamenta r, Fresh Uganda oil find ‘Africa’s biggest’, The Times, 14 January 2010,

http://business.timesonline.co.uk/tol/business/industry_sectors/natural_resources/article5512531.ece

9 These included Power ii (Us$28.8 million), Power iii (Us$125 million) and the Power iV (Us$62 million) projects among others.

10 other funders of the Kiira project were the Norwegian Agency for development Assistance (NorAd) and the swedish international development Agency (sidA).

11 in 2001, staffing was reduced again to a level lower than that of 1991 (World bank, 2002a).12 The government was required to raise tariffs by an amount equivalent to 5 per cent per

annum in Us dollar terms from 1993 onwards in accordance with a World bank agreement. however, no tariff increases took place until 2001, due to, among other factors, an appreciation in the value of the Uganda shilling and public discontent with increased load shedding (World bank, 2002a).

13 This plan updated a previous plan that had been drafted in 1997.14 in other words, while distributors could not compete directly, they could be benchmarked

against one another, which would provide a proxy for competition.15 Chadbourne represented Globeleq, eskom and Umeme in Uganda electricity distribution

deal, 8 March 2005, http://www.chadbourne.com/newsevents/Newsdetail.aspx?news=27416 At the time, Globeleq was owned by CdC Capital Ventures.17 At the end of 2006, eskom’s interest in Umeme was taken over by Globeleq, which became the

100 per cent shareholder, and after further ownership restructuring, private equity firm, Actis Capital, majority owned by CdC Capital Ventures, assumed Globeleq’s interest in Umeme.


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18 Wakabi W, Umeme to run Uganda’s power supply, East African, 2 August 2004, http://www.theeastafrican.co.ke/business/-/2560/243958/-/item/0/-/b55gwp/-/index.html

19 excluding emergency generation.20 Aes completes development of $550 million bujagali power project in Uganda, Business

Wire, 20 december 2001, http://www.allbusiness.com/energy-utilities/utilities-industry-electric-power/6196354-1.html

21 see bujagali bid still on, New Vision, 19 december 2002, http://allafrica.com/stories/200212190213.html

irN comments on bujagali large hydro project (Uganda), 19 August 2002, http://www.internationalrivers.org/node/1323

22 The inspection panel is an independent entity within the World bank that reports directly to the board of executive directors. its mandate is to ascertain, in response to requests for inspection related to specific projects, whether the bank has complied with all applicable policies and procedures with respect to project design, appraisal and supervision. see Notice of registration: request for inspection, Uganda. http://siteresources.worldbank.org/eXTiNsPeCTioNPANeL/resources/UgandaNor.pdf

23 ochieng h, Aes gets go ahead, The Monitor, 9 November 1999, http://allafrica.com/stories/199911090082.html

24 Kaiza d, bujagali dam: Make agreement public, The East African, 10 June 2002, http://allafrica.com/stories/200206100893.html

25 Angelo i, Green Watch wins bujagali PPA case, The Monitor, 12 November 2002, http://allafrica.com/stories/200211130598.html

26 see World bank dam in Uganda overpriced by $280 million, 20 November 2002, http://www.internationalrivers.org/follow-money/world-bank/world-bank-dam-uganda-overpriced-by-280-million

27 Kamagara A, bujagali project clean so far – World bank, The Monitor, 17 April 2002, http://allafrica.com/stories/200204170218.html

28 The department of Justice investigation ended in 2003 without any charges being laid. see Abbey Y & J Namutebi, bujagali dam gets go-ahead, The New Vision, 21 April 2003, http://allafrica.com/stories/200304210070.html

29 Pallister d, Africa dam’s passage ‘eased by bribes’, The Guardian, 3 November 2003, http://www.guardian.co.uk/uk/2003/nov/03/davidpallister

30 Mulumba bd, Norwegian firm pulls out of bujagali dam, The Monitor, 5 september 2002, http://allafrica.com/stories/200209050390.html

31 Abbey Y, Contractors pull out of bujagali project, The New Vision, 4 June 2003, http://allafrica.com/stories/200306040290.html

32 it should be noted that the negative sentiment that had been stirred up on the environmental and social aspects of the project and the allegations of impropriety notwithstanding, AesNP’s withdrawal occurred at a time when its share price was low, enron had collapsed and its Ceo had been replaced (esty & sesia, 2005).

33 Mulumba bd, bujagali power dam project must go on; eskom cited in fresh plans, The Monitor, 15 August 2003, http://allafrica.com/stories/200308150075.html

34 eremu J, World bank to fund bujagali power project, The New Vision, 16 August 2003, http://allafrica.com/stories/200308180191.html


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35 The three bids successfully submitted were from bujagali energy Ltd (a consortium led by industrial Promotion services), the Wakisi Consortium (led by Aldwych international) and stucky Consulting engineers Ltd.

36 bujagali energy Ltd (beL) is owned by industrial Promotion services (Kenya), an affiliate of the Aga Khan Fund for economic development (AKFed), and sG bujagali holdings Ltd, an affiliate of sithe Global Power, LLC (UsA).

37 Uganda gives iPs Group bid the green light, Daily Nation, 10 May 2005, http://allafrica.com/stories/200505091685.html

38 industrial Promotion services, personal communication (2010).39 The government inspector-general investigates cases of corruption and abuses of office and

authority within the government.40 The disputes and court processes are documented in various news media including:

Among b, Country’s third thermal power plant is launched, East African, 10 october 2006; Kasita i, Namanve thermal power costs rise to Ush145bn, New Vision, 17 June 2007; Kasita i, Court stops Namanve thermal power deal, New Vision, 10 May 2007; Kasita i, hearing of thermal power award starts on August 17, New Vision, 22 July 2007.

41 erA, personal communication (2010).42 TronderPower Ltd is owned by Trøndeenergi and Norfund, both of Norway.43 see Tororo thermal plant to be commissioned in August, New Vision, 23 June 2009; Power

cuts to go – Museveni, New Vision, 24 June 2010. 44 see http://ppi.worldbank.org/explore/PPireport.aspx?Projectid=517145 see http://allafrica.com/stories/201111220279.html46 see http://allafrica.com/stories/201209150319.html47 see http://www.kakirasugar.com/48 Ministry of energy and Mineral development of Uganda Annual report, 2005,

http://www.energyandminerals.go.ug/pdf/Ar2005.pdf49 Ministry of energy and Mineral development of Uganda Annual report, 2006,

http://www.energyandminerals.go.ug/pdf/Ar2006.pdf50 Ministry of energy and Mineral development of Uganda Annual report, 2008,

http://www.energyandminerals.go.ug/pdf/Annual%20report%202008%20.pdf51 office of the Auditor General of Uganda (2010). Annual report of the auditor general on

the financial statements of statutory authorities and state enterprises for the year ended 30th June 2009, http://www.oag.go.ug/uploaded_files/1271768253Vol4%202008-2009%20statutory%20Corporations.pdf

52 Umeme Annual reports, 2011 and 2012. Kampala: Umeme.53 UeTCL announces generation shortfall leading to load-shedding,

http://www.umeme.co.ug/index.php?page=MTM354 Crude oil prices increased to Us$120 per barrel during 2010. Forecasts made at the

beginning of the year had pegged oil prices at Us$60–70 per barrel.55 Kasita i, Govt moves to cut power expenses, AllAfrica.com, 14 July 2011,

http://allafrica.com/stories/201107180066.html56 Umeme Annual report, 2011. Kampala: Umeme.57 Umeme Annual report, 2011. Kampala: Umeme.


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58 erA, personal communication (2010).59 Citing increased responsibilities elsewhere.60 Police raid power companies, Saturday Vision, 26 June 2009,

http://www.newvision.co.ug/d/8/13/68601761 erA, personal communication (2009).62 erA, personal communication (2009).63 Personal communication (2010).64 For example, Umeme’s agreements with the government include an implementation

(Concession) Agreement, a special Provisions Period Agreement and a power-purchase agreement that sets out the terms on which it purchases electricity from UeTCL.

65 The erA may of its own volition also invite applications through a fair and open competitive process in accordance with prescribed procedures for any licence prescribed by the electricity Act.

66 Various stakeholders, personal communication (2009).67 see http://www.era.or.ug/Pdf/electricity_Tariff_Code_regulations,_2003.pdf68 Kasita iPs, onek make up, New Vision, 12 November 2009,

http://www.newvision.co.ug/d/8/13/70100769 Where rr = revenue requirement, rAb = regulatory asset base, ror = rate of return,

e = operations and maintenance expenses, d = depreciation and T = taxes.70 erA, personal communication (2010).71 erA, personal communication (2009).72 The internal rate of return (irr) is estimated at 6 per cent.73 Umeme Annual report, 2010. Kampala: Umeme.74 Approved tariffs for the period January to March 2010,

http://www.era.or.ug/Pdf/Approved%20tariffs%20for%20the%20period%20of%20January%20to%20March%202010%20NoTiCe.pdf

75 see the section on regulatory governance earlier in chapter 3 for a summary of the provisions of Clause 11.

76 erA, personal communication (2009).77 Various stakeholders, personal communication (2009).78 As at 2010, and based on the average bank of Uganda exchange to october 2010.79 erA, personal communication (2009).80 As at 2010, and based on the average bank of Uganda exchange to october 2010.81 reA, personal communication (2009).82 Umeme, personal communication (2009).83 Umeme, personal communication (2009).84 Ministry of energy and Minerals, personal communication (2009).


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Zambia: Looking east for additional generation capacity

established in 1995, Zambia’s energy regulation board (erb) is one of the oldest electricity regulatory agencies in Africa. despite this, and while the financial performance of Zambia’s national state-owned utility improved significantly over the period 2004–2011, technical performance has deteriorated. by 2012, tariffs were not cost reflective, and although they had for many years been among the lowest in the world, since 2008 the erb has granted the Zambia electricity supply Corporation (ZesCo) significant tariff awards. For many years, the Zambian government was reluctant to allow tariffs to rise. There was surplus generation capacity in the early 1980s, and consumption and demand growth were stagnant as a result of economic decline; therefore there seemed no reason to increase prices. Towards the end of the 1990s, Zambia’s economic fortunes changed for the better. in the first decade of the new millennium, the country was recording robust economic growth, as evidenced by rapidly rising demand for electricity. however, with tariffs below economic levels, investment in power system expansion and requisite refurbishments was constrained, leading to a decline in power quality and reliability and making load shedding and even nationwide power blackouts an increasingly common phenomenon. both the erb and the government have since recognised the need to raise tariffs to levels that will make the electricity-supply industry sustainable and contribute more meaningfully to economic development. Above-inflation increases were awarded in 2008 and 2009, and a path towards cost-reflective tariffs was mooted in 2010. Greater effort has also been made to improve ZesCo’s performance, and a set of key performance indicators has been developed against which the company is measured by the erb.

Meanwhile, the successful privatisation of the Copperbelt energy Corporation (CeC) (which supplies electricity to the Zambian copper mines), and its subsequent resale to a consortium led by local investors, has provided an example of new avenues through which the sector can be funded, and has facilitated the emergence of an indigenous, private managerial class. Nonetheless, with the exception of remote stand-alone concessions, there has been no private-sector participation in greenfield generation projects, even though the sector was liberalised in 1995. Kariba North bank, commissioned in 1977, remains the country’s newest plant.

The second decade of the millennium may herald the start of a brighter future, however. ZesCo has entered into new partnerships with state-backed Chinese and indian investors. For example, the Kariba North bank hydropower station, which is owned by ZesCo, is being expanded with the assistance of the sino-hydro Corporation, the export-import bank of China and the development bank of southern Africa. Chinese interests are also being courted for the development of the Kafue lower gorge hydro

4


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scheme. Upstream of the Kafue river from the existing power station, The itezhi-Tezhi hydro plant is being developed by Tata Power from india. Alternative models for financing the power-supply deficit are thus emerging. Meanwhile, the construction of two independent power producers (iPPs) had commenced by 2012 – a 300 MW coal-fired plant at Maamba in southern Zambia and a 50 MW heavy fuel oil (hFo) plant in the Copperbelt province – and further projects were in the pipeline.

it is a time of great hope; and the continent’s oldest regulator has a key role to play in ensuring that the Zambian power sector becomes more viable, efficient and able to reliably provide quality electricity not only to the country, but also to the region, given the potential that the country holds.

Overview of Zambia’s electricity sectorThe institutional arrangement of Zambia’s electricity sector is depicted in Figure 4.1. The Ministry of energy and Water development (MeWd) is responsible for policy development. The energy regulation board (erb) is the independent regulator. As in Kenya, Tanzania and Uganda, there is a quasi-independent body charged with extending electrification in the rural areas, the rural electrification Authority (reA). The office for the Promotion of Private Power investment (oPPPi) is a distinctive feature of the Zambian set-up. oPPPi is a specialised unit within the energy ministry that aims to promote private-sector investment in generation and transmission, and to manage the attendant and complex planning, procurement and contracting processes.

Figure 4.1 Overview of Zambia’s electricity sector, 2010

Consumers

Imports from the DRC

Ministry of Energy and Water Development

Lunsemfwa Hydro Power Company

Exports to the Southern African Power Pool (SAPP)

Copperbelt mining companies

Remote rural mini-grids

Industry

Energy Regulation BoardRural Electrification Authority

Zenagamina Hydro Power Company

North West Energy Corporation

ZESCO Ltd (generation, transmission

and distribution)

Copperbelt Energy Corporation


Zambia’s hybrid electricity market1 is dominated by the state-owned and vertically integrated ZesCo Ltd. As at 2010, the only private generation into the grid was provided by Lunsemfwa hydro Power Company (LhPC), which owns two small


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hydropower plants just outside the Central Province town of Kabwe. There are also two rural concessions: Zenagamina hydro Power Company (ZhPC) runs a remote rural network in the North Western Province, and North West energy Corporation distributes electricity to a rural mining community. A unique feature is that the power supply to Zambia’s largest load centre, the mines of Copperbelt province, is provided by a private company, the Copperbelt energy Corporation (CeC). CeC purchases power from ZesCo and supplies the mines, smelters and refineries by means of its own transmission system.

The Zambian power system is also connected to that of the democratic republic of Congo (drC) to the north (where electricity generation potential is estimated at 100 000 MW),2 and to the power systems of Namibia and Zimbabwe to the south. These interconnections enable power imports and exports, but more crucially position Zambia as the gateway for the flow of power from the drC to countries to the south including south Africa, which is by far the largest consumer of electricity on the continent.


With an estimated 6 000 MW3 of potential capacity, Zambia has an abundance of hydro resources. it is therefore not surprising that installed generating capacity is almost entirely based on hydropower.4 As shown in Table 4.1, Zambia’s total installed capacity in 2010 was 1 889 MW. hydrological constraints, and the state of hydro-electric equipment, mean that available generation capacity is slightly lower.

Table 4.1 Installed generation capacity, Zambia, 2010

Ownership Plant Installed capacity (MW)

Type

ZesCo Kafue GorgeKariba North bankVictoria Falls

990.0720.0 108.0

hydro

LusiwasiMusonda FallsChishimba FallsLunzua

12.05.06.00.8

small hydro

LhPC LunsemfwaMulungushi

18.029.0

small hydro

Total capacity 1 888.8

source: ZesCo, personal communication (2010)

Zambia’s dependence on hydropower puts the country at risk in the event of drought. over the period 1982 to 2008, the most significant drought event occurred between 1991 and 1992 (Tiffen & Mulele, 1994), when gross generation output decreased by almost 30 per cent. There were also intermittent droughts during the first five years of the new millennium (Nyambe & Feilberg, 2009). other than in 1991 and 1992, however, the impact of drought has not been as severe as experienced by the east


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African countries discussed in this volume. This is due to Zambia’s water-storage capabilities5 and electricity imports from southern African Power Pool countries, which have helped alleviate the shortfalls in power generation.6

As expected in a developing country, the load forecast for the period 2010 to 2030 (Figure 4.2) shows strong growth, with maximum demand and energy growth averaging 4.5 per cent and 3.9 per cent per annum respectively. it is noteworthy that the maximum demand forecast for 2010 (1 801 MW7) is perilously close to actual installed capacity, and if this level of demand materialises, the reserve margin will be insufficient for prudent system operation.

Figure 4.2 Load forecast, Zambia, 2010–2030

Energy

Max

imum

dem

and

(MW

)

Ener

gy (

GW

h)

Maximum demand

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

25 000

20 000

15 000

10 000

5 000

0

4 500

4 000

3 500

3 000

2 500

2 000

1 500

1 000

500

0


Power-sector reformTo provide some context to the reform process in Zambia, it is helpful to trace the complex history of Zambia’s power sector, the development of which spanned three countries, was largely driven by the need for a reliable electricity supply to the mining industry, and has been significantly influenced by the World bank (which has been the industry’s most important funder for over half a century). indeed, as for all of the countries in this volume, it can be argued that power-sector reform was not an event but is an ongoing process.

History of the power sector

in 1906, Zambia’s first power station, a thermal plant, was built in Livingstone, the country’s southernmost town and home of the Victoria Falls. Later, several stand-alone generating stations were installed on the Copperbelt in the period leading up to the second World War (Mihalyi, 1977). hydropower only began to be harnessed when a 2 MW generator was installed at Mulungushi power station in 1925, followed


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by two other 6 MW generators in 1927.8 This hydropower was used to supply electricity to the lead and zinc mine at Kabwe (broken hill) (Mihalyi, 1977).

surprisingly, despite proposals to exploit the Victoria Falls that date as far back as 1895,9 it was only in 1938 that a hydro-electric plant was installed at the third gorge below the falls.10 From then on, hydropower took hold. A further 6 MW unit was installed at Mulungushi in 1941,11 and four years later, two generators rated at 6 MW each were commissioned at Lunsemfwa power station, 47 km north-east of Mulungushi, to supplement supply to the lead and zinc mines at Kabwe. The 1950s saw three important developments in the sector. Firstly, interconnected grid supply was initiated through the connection of four power stations with a combined capacity of 120 MW on the Copperbelt.12 secondly, hydropower began being imported in 1956 when a transmission line was laid from Katanga in the neighbouring drC (then the belgian Congo) to Kitwe on the Copperbelt.13 This led to the establishment of the rhodesia Congo border Power Company by the mining companies for the purpose of operating the transmission line and distributing power on the Copperbelt.14 This company was renamed the Copperbelt Power Company (CPC) in 1964.15 Thirdly, an event that has left a lasting impression on the country and region’s power sector was the decision by the government of the Federation of rhodesia and Nyasaland16 to construct a dam on the Zambezi river at Kariba gorge, which would straddle northern and southern rhodesia and create a reservoir from which to supply hydro-electricity to the mines on the Copperbelt (Jarosz, 1992).

The construction of Kariba dam began in 1954, and the 666 MW Kariba south bank power station was commissioned in 1962.17 At the time, Lake Kariba was the largest reservoir in the world (Jarosz, 1992). Kariba south bank power station came to be owned and operated by the Central African Power Corporation (CAPCo), which was set up by the governments of Zambia (Northern rhodesia) and southern rhodesia in 1963. CAPCo was established to take responsibility for bulk-power generation and transmission, and therefore also owned the power lines and high-voltage substations en route to the Copperbelt. in Zambia, CAPCo, which supplied almost all the country’s power requirements, had two customers: the Central energy Corporation supplying Lusaka and surrounds; and CPC on the Copperbelt.

in 1967, three years after Zambia’s independence, work began on the first indigenous large hydropower project, the 600 MW Kafue gorge power station,18 which was completed in 1972 (Mihalyi, 1977). in 1973, work began on a dam 250 km upstream of the Kafue river to increase capacity at Kafue gorge by a further 300 MW. by 1977, capacity at Kafue gorge had been increased to 900 MW, and Zambia was home to a new reservoir at itezhi-Tezhi (World bank, 1985a). Meanwhile, the second (60 MW b station) and third (40 MW C station) plants at Victoria Falls were commissioned in 1969 and 1973 respectively (Mihalyi, 1977).

At the beginning of december 1969, the government formed the Zambia electricity supply Corporation (ZesCo) to take responsibility for the generation, transmission and distribution of electricity throughout the country, with the exception of the areas


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supplied by CAPCo. The following year, the Zambia electricity supply Act of 1970 became effective, and by statutory order of the minister responsible for electricity, the rights, obligations and assets of existing electricity utilities became vested in ZesCo. Thus on 1 July 1970, ZesCo acquired the Central energy Corporation, the Northern electricity supply Corporation, which supplied small towns by means of isolated diesel-generating stations, and the Victoria Falls electricity board (VFeb), which owned the power stations at the falls. Two years later, on 1 July 1972, ZesCo acquired municipal operations in Livingstone and Ndola undertaken by the VFeb and Ndola Council electricity respectively (World bank, 1985a). Later the same year, five other similar operations were taken over on the Copperbelt, and by 1985, ZesCo was supplying the entire country with the exception of the Copperbelt mines and the lead and zinc mines at Kabwe (World bank, 1985a).

The last major generating plant constructed in Zambia was the 600 MW Kariba North bank power station (KNb). ordinarily, the construction would have been undertaken directly by CAPCo, but the Unilateral declaration of independence by southern rhodesia in 1965, which Zambia did not recognise, meant that southern rhodesia’s appointments to the CAPCo board, and to the higher Power Authority19 to which the board reported, were also not recognised (ibrd & idA, 1970). As a result, CAPCo could not be authorised to procure funds for the project. To overcome this, the Zambian government formed the Kariba North bank Company (KNbC) to procure a loan from the World bank and to own the power station. KNbC in turn contracted CAPCo to construct the power station, and on completion CAPCo agreed to lease the facility for a consideration adequate to meeting KNbC’s debt service and reasonable administration costs (idA, 1974). The Kariba North bank power station was commissioned in 1977, the year that two additional generators at Kafue Gorge also came into service. With these additions, total installed capacity in Zambia reached 1 608 MW, which was well above its maximum demand at the time. in fact, as late as 1982, Zambia’s maximum demand was reportedly only 846 MW.20

in a curious arrangement, ZesCo sold all the electricity it generated to CAPCo, which then sold it back for onward distribution to ZesCo’s customers throughout the country (idA, 1974). This arrangement ceased in 1977 when the relationship between ZesCo and CAPCo was restructured. Thereafter it was agreed that: • ZesCo would cease purchasing power from CAPCo; • the benefits and costs of the Kariba Complex would be shared equally between

the two parties; • CAPCo’s transmission costs in Zambia would be reimbursed by ZesCo; • power supply to CPC would be undertaken by ZesCo; and • the arrangement whereby ZesCo had been purchasing power from CPC for its

northern area operations would be replaced with a rental (wheeling) charge for the use of CPC’s transmission network on the Copperbelt (World bank, 1985a).

in 1982, CPC became the Power division of the newly formed and majority state-owned mining conglomerate, Zambia Consolidated Copper Mines (ZCCM),21 and in 1987, CAPCo was dissolved by the simultaneous passing of the Zambezi river


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Authority Act in the parliaments of Zambia and Zimbabwe. The Act provided for CAPCo’s electricity generation and transmission activities to be taken over by ZesCo and KNbC, and its responsibilities related to dam infrastructure reverted to a new entity, the Zambezi river Authority.22

Technically, ZesCo had performed well since its establishment, and the quality and reliability of electricity service was maintained to high standards (esMAP, 1988b). by 1988, however, these standards were at risk. demand was declining due to a reduction in power exports, and23 local consumption growth was flat; the combination created a strain on ZesCo’s finances. The Zambian economy was in an overall state of decline, limiting access to the foreign exchange required to ensure adequate maintenance of its plants, and ZesCo faced increasing difficulty in attracting and retaining key staff (esMAP, 1988b). These difficulties were compounded by the fact that tariff levels were insufficient to provide adequate cash reserves for operations and maintenance, tariff adjustment procedures were lengthy and did not provide the flexibility required in an environment of rapidly rising inflation, and low employee productivity had made billing and metering problematic (esMAP, 1988b). despite the fact that these risks had been flagged in 1988, by 1993 the company was headed for ‘financial disaster’ (ranganathan & Mbewe, 1995).

in 1991, the government changed hands. The United National independence Party (UNiP) that had led Zambia since independence in 1964, and had followed statist policies of economic management, was voted out of power. The Movement for Multiparty democracy, a party that had based its campaign on economic liberalisation and greater private-sector involvement in the economy, came to power. With this paradigm shift in economic management came a flurry of new economic policy statements. hence, in 1994 the government published the National energy Policy (Ministry of energy and Water development of Zambia, 1994), the first such statement wholly dedicated to the energy sector.

1994 Energy PolicyThe policy’s stated objective was:

Promoting optimum supply and utilisation of energy, especially indigenous forms, to facilitate the socioeconomic development of the country and maintenance of a safe and healthy environment [which would require] establishing a viable institutional structure. (Ministry of energy and Water development of Zambia, 1994: 20)

To achieve this objective, the policy outlined five measures specific to the electricity sector. The most far-reaching of these was the first, which stated that the electricity industry would be restructured to improve service delivery by: • liberalisation so that other companies could be involved in the electricity

business;• ensuring that the operations of ZesCo would be commercialised; and• the immediate privatisation of ZesCo’s distribution function.


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The policy also called for the removal of bottlenecks to accessing electricity by, for example: reducing connection charges and deploying low-cost technologies; the promotion of the electrification of productive areas and social institutions; the development of the country’s hydro-potential and taking advantage of Zambia’s strategic location in the region; and a review of existing legislation so that it would conform to the changed economic landscape (Ministry of energy and Water development of Zambia, 1994).

Pricing received special mention in the policy, which stated that it should be based on fairness and equity that entailed:• allocating costs among consumers according to the burden they impose on a

delivery system;• assuring a reasonable degree of stability and avoiding large price fluctuations

from year to year;• providing a minimum level of service to persons who are unable to afford the

full cost; and• providing a real return on the investment.

specifically for the electricity sector, it was stated that tariffs would be based on long-run marginal costs, taking into account investment costs; operational costs; incentives for efficiency, reliability, safety and environmental standards; and profit.

The policy sought to clarify institutional roles and responsibilities with the withdrawal of the government from operational activities in the energy sector. The government through the Ministry of energy and Water development would:• provide and articulate policy guidelines for the energy sector;• develop and implement policy;• monitor developments in the energy sector;• integrate the energy sector into the national and regional developments; and• regularly review energy-related legislation to bring it in line with developments

in the sector and the economy as a whole.

The policy also called for the establishment of an independent regulatory body that would:• receive representations from consumers and other interested parties on energy-

price adjustments and levels;• ensure that energy price adjustments and levels are justified;• consider appeals from individuals and institutions not satisfied with services

provided by any energy company;• arbitrate between the various stakeholders in the energy sector, and ensure that

the interests of energy users and the public are safeguarded; and• regulate against monopoly practices.

The World bank was instrumental in the development of the policy, which was crafted at a time when power-market reforms were seen as important for increasing economic productivity (esMAP, 1996). it was therefore not surprising that a key gathering of African ministers of energy and finance with utility managers, including the Zambian energy minister and ZesCo’s managing director, held in Johannesburg, south Africa in 1995, echoed the Zambian policy with the following statement:


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Most sub saharan African power sectors need to reform. The challenge is, once…pricing issues have been addressed, how to ensure that efficient pricing will be sustainable. experience around the world suggests that the only way efficient pricing can be sustainable is by reforming the sector along market lines, removing governments from the business of producing and selling energy; allowing the private sector under competitive conditions to enter the sector, and, when competition is unlikely, regulating private companies as if they were under competition (i.e. incentive regulation). All of this requires a well-defined legal, institutional and regulatory framework, however. (esMAP, 1996)

With the policy released, the government proceeded swiftly with its implementation and repealed the 1970 Zambia electricity supply Act, which had been the foundation of ZesCo’s establishment and its statutory monopoly. in its place, the 1995 electricity Act became law. The provisions of this Act are elaborated on later in the chapter, but fundamentally its effect was to liberalise the power sector. The 1995 energy regulation Act was enacted simultaneously and led to the establishment of one of the first independent regulatory institutions in english-speaking sub-saharan Africa, the energy regulation board (erb), which became operational in 1996.

Privatisation of mining and electricity-sector assets

Also in 1996, as part of the economic reform programme, the government initiated the sale of its majority interests in its mining and some of its electricity assets (Coakley, 1997). The most significant of these electricity assets was ZCCM’s Power division, the privatisation of which became possible since the 1995 electricity Act had liberalised the sector. There was considerable international interest in the Power division, and in 1997, it was purchased for Us$50 million by a consortium (led by the UK’s National Grid Company and the Us-based Cynergy Corporation) and renamed the Copperbelt energy Corporation (CeC) (Craig, 2001).

CeC became the first private player to enter Zambia’s electricity market since 1970. between 1995 and 1996, ZCCM’s power consumption, which was supplied by CeC, was approximately 5 000 GWh, with a peak demand of 500 MW. in order to meet the demand, CeC was purchasing two-thirds of ZesCo’s total generation (Coakley, 1997). This arrangement was anchored on a bulk-sale agreement entered into between CeC and ZesCo at the time of privatisation. Later, in 2006, the National Grid Company and the Cynergy Corporation divested from CeC, and their interests were taken up by a consortium mainly comprising local investors known as the Zambia energy Corporation.

Also included in the assets earmarked for privatisation were the Mulungushi and Lunsemfwa power stations. These two plants were acquired in 2001 by Lunsemfwa hydro Power Company (LhPC), which was owned by a consortium comprising eskom (51 per cent), local investors degarnier (29 per cent) and Wand Gorge investment (20 per cent). in 2008, eskom disposed of its interests in LhPC to local investors and the management team. At the time of writing, LhPC with an installed capacity of 38 MW was the only private electricity generator in Zambia.24


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The attempt to privatise ZESCO

by 1998, ZesCo was performing poorly. Although its transmission network was generally regarded as efficient, generator availability was low, and distribution was characterised by high losses.25 Commercially, performance was described as ‘extremely poor’; the rate of return on assets was unsatisfactory, and the inability to settle debts was exacerbated by very low tariff levels and overstaffing. ZesCo’s financial position was too weak to finance new investments; this made increasing access to electricity, which at the time reached just 14 per cent of the population, almost impossible (World bank, 1998).

it was therefore not surprising that ZesCo’s performance began to feature increasingly prominently in both the World bank’s and international Monetary Fund’s (iMF) programmes in Zambia. After continued poor performance despite government-led turnaround initiatives – including a performance contract signed with ZesCo in 1996 that emphasised ‘commercial operation and efficient technical supply’ (World bank 1998: 4) – the World bank and iMF made the privatisation of ZesCo a condition of Zambia’s obtaining debt relief under the highly indebted Poor Country (hiPC) initiative.26 The two multilateral institutions stated that:

Attention has also focused on the need to complete the program of divestiture27 in order to reduce the fiscal burden of public enterprises and extend the provision and quality of essential services. in that context the privatisation of ZesCo, the national power company, is particularly important in order to improve efficiency, reduce tariffs, and facilitate future economic growth. (iMF & idA, 2000)

A study was thus commissioned to investigate options for the privatisation of ZesCo, on the basis of which the government would make a decision by the end of 2000 (iMF & idA, 2000). The study was completed early in 2001 and proposed that ZesCo be privatised in two stages, namely, a 10-year master concession followed by the outright sale or further concessioning of unbundled business units. The study recommended that during the master concession:• ZesCo should be unbundled into generation, transmission, distribution and

rural electrification business units;• rural electrification should operate under a negative sub-concession during

the master concession period once the master concessionaire had developed a programme plan in conjunction with the Ministry of energy and Water development. (Under a negative sub-concession, the concessionaire would be paid a combination of an up-front and annual fee.)

The disposal of the remaining assets at the end of the master concession should be as follows:• outright sale of small hydropower stations (Lusiwasi, Musonda Falls and

Chishimba Falls), with preference for local investors;• Joint-venture sale of a majority stake in Victoria Falls and Kafue Gorge power

stations;


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• Concession of the high-voltage grid and wholesale marketing functions; and • Concession or joint-venture sale of majority stake in the distribution subsidiary

(Nexant, 2001).

Meanwhile, the erb had in 1999 initiated its own investigation into options for restructuring the power sector, the report of which was presented to the government in November 2002. The erb recommended what was termed the ‘semi-competitive model’.28 This entailed the vertical unbundling of generation, transmission and distribution, and allowed for horizontal separation across the three functions. it made provision for an independent system operator, a power pool for short-term electricity trading, and wholesale competition through contracting among generators, distribution companies and large consumers (Kapika, 2004).

Popular resistance to privatisation was rising, however. An editorial in the Zambian daily newspaper, The Post, made the following observation:

despite having liberalized its markets, as dictated by the iMF and the World bank, Zambia has still not started benefiting from it…Why should we privatize Zambia National Commercial bank, Zesco Limited (electricity) and Zamtel (telecommunications) simply because the iMF and the World bank want us to do so, even when the great majority of Zambians are opposed to it because they believe it is not in their best interest?29

by 2003, privatisation was becoming increasingly risky politically, and after intense negotiations, the government agreed with the World bank and the iMF to put the divestiture in ZesCo on hold. 30 it was decided instead to pursue a plan to commercialise ZesCo in the hope that this would achieve the same objectives as privatisation. it was also agreed that the performance of ZesCo against the plan would be reviewed in 2005, and if it proved unsatisfactory, privatisation would be placed back on the agenda (iMF & idA, 2005). The commercialisation plan entailed the following broad measures:• Legal: Amendment of ZesCo’s articles of association and the composition of its

board to ensure independence from political interference and enhance commercial operation; amendments to the electricity and energy regulation Acts in order to impart greater regulatory independence to the erb; development of a framework that would allow ZesCo to enter into partnerships with the private sector.

• Commercial: The formulation of a business plan; the collection of the government’s unpaid electricity bills; operating without financial support from the government; constraining government guarantees on ZesCo’s concessional debt to a limit of Us$40 million until the end of 2005; the settlement of outstanding tax liabilities (iMF & idA, 2005).31

in 2005, Zambia obtained debt relief under the hiPC initiative. This was made possible partly by the fact that progress as measured against the ZesCo commercialisation plan was deemed satisfactory (iMF & idA 2005). A year earlier, on 15 June 2004, the government had announced the merger of ZesCo with KNbC.32 ZesCo’s dominant position in the power sector was now well entrenched; privatisation was banished and unbundling abandoned.


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Sector performancehaving detailed the history and initiatives to reform Zambia’s power sector, we now examine the performance of the electricity industry as a whole and that of the two major players, ZesCo and CeC.

it is important to remember that for several years, Zambia was a regional powerhouse of electricity exports, as shown in Figure 4.3. but due to increased economic activity Zambia no longer enjoys that status with electricity exports at the time of writing only a fraction of what they were in the 1980s. in two decades, ZesCo has moved from a situation where a lack of demand growth adversely affected its financial position to one in which a lack of funds is preventing the capacity expansions required to serve rising demand. in fact, ‘with the rapid development of new mines and industries, and growing household electricity needs, the country is experiencing power shortage[s] and load shedding’ (World bank, 2008). National power blackouts, unheard of in the 1980s and 1990s, have become more common having occurred in 2006, 2007, 2008 and 2009.33

Figure 4.3 Electricity exports from Zambia, 1982–2008

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Figure 4.4 shows maximum demand and energy consumption over the period 1983 to 2009.

ZESCO’s financial performance

ZesCo’s financial performance has been less than stellar since the early 1990s. At the end of a substantial rehabilitation project in 2006, the World bank remarked that ‘ZesCo’s financial situation is unsustainable, and will, if allowed to continue, undermine its commercialization efforts and the viability of the power sector. There is urgent need for action on tariffs, including re-opening of the sales contracts with the mines’ (World bank, 2006d).

Figure 4.4 Maximum demand and energy consumption, Zambia, 1983–2011

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ZesCo’s tariff to CeC was increased by 33 per cent in 2008, while retail tariffs were increased by 35 per cent in 2008 and 26 per cent in 2009. ZesCo’s financial performance over the period 2004 to 2010 is shown in Table 4.2.


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Table 4.2 ZESCO’s financial performance indicators, Zambia, 2004–2011Financial indicator 2004 2005 2006 2007 2008 2009 2010 2011Net profit margin (%) 6 5 6 -18 4 3 21 16return on capital employed (%) 3 2 2 -10 0 7 5 9Current ratio 1.26 1.14 1.07 0.97 0.82 0.93 1.01 1.32Quickratio 1.16 1.06 0.98 0.92 0.79 0.89 0.95 1.19interest cover 7.34 3.32 11.76 0.85 -0.41 10.69 8.61 29.39debt/equity ratio (%) 58 62 65 71 74 78 53 69Gearing ratio (%) 22 25 23 31 33 35 23 30debtor days 172 189 168 176 147 136 89 97Asset turnover 0.34 0.28 0.26 0.28 0.29 0.35 0.43 0.48

sources: ZesCo Annual reports, 2004, 2004/5, 2005/6, 2006/734; ZesCo, personal communication (2010 and 2012)

The indicators for 2011 seem to suggest that ZesCo may be turning its poor financial performance around. The net profit margin increased, influenced by tariff increases. With interest cover at 29 (times), the company is now better placed to settle the interest on its existing debt, which is a far cry from the situation that prevailed in 2007/08. it is important that debtor days have trended downwards since 2004, although the increase in this indicator for 2011 should be a matter of concern. it is also notable that distribution losses have also trended downwards from around 24% in 2007 to 15% in 2011.35

CEC’s performance

CeC is ZesCo’s single largest customer. As Figure 4.5 shows, in the early 1980s, CeC purchased approximately 70 per cent of ZesCo’s generation output. over the years, this proportion has declined, but in 2009, sales to CeC accounted for 36 per cent of total generation, which was still a significant amount. This reduction has come about due to growth in other areas of the economy, but also because ZesCo is directly supplying mining operations that have started up outside the Copperbelt area that is supplied by CeC.

Figure 4.5 CEC purchases and total system consumption, Zambia, 1982–200910 000

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CeC’s performance over the period 2005 to 2009 is shown in Table 4.3. it is difficult to make comparisons of its performance with that of ZesCo, however, since it supplies electricity to a niche market of mining houses that are small in number and consume electricity in bulk.

Table 4.3 Indicators of CEC’s financial performance, Zambia, 2005–20112005 2006 2007 2008 2009 2010 2011

sales (Us$ ’000) 122 164 127 280 131 746 177 486 154 169 167 294 197 539Gross profit (Us$ ’000) 36 367 37 383 38 746 49 526 42 371 45 856 52 081Profit before interest and taxes (Us$ ’000)

15 240 12 745 13 306 17 222 19 126 19 602 35 205

Acid-test ratio 0.74 0.67 1.24 1.26 0.95 0.76 0.98return on equity (%) 12 12 16 26 8 8 12earnings before interest, taxes, depreciation and amortisation (ebiTdA) (Us$ ’000)

24 202 21 293 22 152 26 419 28 682 30 293 48 877

Total assets (Us$ ’000) 136 505 131 453 150 745 178 977 274 711 277 585 307 995earnings per share (Usc) 0.82 0.79 0.73 1.01 1.19 1.27 2.06return on assets (%) 6.0 6.0 4.6 5.7 4.4 4.6 6.70Net profit (Us$ ’000) 8 241 7 915 7 251 10 143 11 920 12 719 20 613equity (Us$ ’000) 68 021 65 680 45 630 39 573 158 273 160 992 169 315Current assets (Us$ ’000) 19 746 17 395 35 151 53 579 36 500 36 316 68 218inventory (Us$ ’000) 1 028 1 136 1 307 3 443 3 506 3 462 3 933Current liabilities (Us$ ’000) 25 206 24 332 26 149 39 786 34 847 43 466 65 746

source: CeC Annual reports36

Regulatory governanceAs mentioned above, the passing of the energy regulation Act in 1995 paved the way for the establishment of the energy regulation board (erb). The erb regulates both the electricity sector (including renewables) and the petroleum sector in an arrangement similar to that of the energy regulatory Commission (erC) in Kenya. For the purposes of this chapter, however, we will focus on the work it carries out in relation to electricity regulation.

The erb’s powers and responsibilities are set out in the energy regulation Act and the electricity Act, both of which were passed in 1995. both Acts were amended in 2003; and in 2009, the erb was drafting revised energy regulation and electricity Acts. Thus, this section refers to the 1995 Acts, the 2003 amendments and the 2009 draft legislation.

Powers and functions of the ERB

The laws on which regulatory governance is founded should give the requisite powers to the regulator to enable it to carry out its core functions. As we stress throughout this volume, the core functions of regulators are: • facilitating market access through licensing;


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• setting tariffs in an objective manner that is devoid of political influences; • setting and monitoring technical standards for the industry that promote quality

and reliability in service provision; • resolving consumer complaints and adjudicating disputes among players in the sector;

and• taking into account the special interests of low-income consumers and facilitating

new connections. This is particularly important for developing countries where access to electricity is low.

in comparison with international best practice (see brown et al., 2006), Zambia’s legislation generally provides the erb with sufficient powers to carry out its functions. There are, however, four areas where the erb’s authority could be further clarified and enhanced, namely: tariff setting, power-purchase agreements, subsidiary policy and rule making, and the authority to carry out administrative functions. The problematic issues relating to these four areas are briefly outlined below.

Tariff setting

The erb determines all retail electricity tariffs in Zambia, and its decision on these is final. however, this key responsibility of the regulatory authority is not specifically stated in the primary legislation, and the erb relies on the interpretation of Clauses 8(2) to 8(4)(a) of the electricity Act in order to set retail tariffs. Clause 6(1)(c) of the energy regulation Act states that the erb should:

receive and investigate complaints from consumers on price adjustments by any undertaking, and regulate such adjustments by the attachment of appropriate conditions to licences held by undertakings or by such other means as the board considers appropriate.

Clause 8 of the electricity Act reads as follows:2) if an operator considers it expedient to vary or alter charges in respect of any

supply of electricity, the operator shall give notice to the consumer of the proposal to vary or alter those charges, as the case may be.

3) if the consumer does not make any application under subsection (4) within thirty days of the date of notice referred to in subsection (2), the variation or alteration, as the case may be, shall, unless the operator of the undertaking and the consumer otherwise agree, come into effect thirty days after the date of that notice or from such later date as the operator may in that notice fix.

4) The board shall, on an application by a consumer, review a proposal referred to in subsection (2), taking into consideration any submissions made by the consumer.(a) The board may, if it considers it appropriate, on its own motion review a

notice by an operator of an undertaking to vary or alter charges in respect of any supply of electricity.

Clause 6 of the draft energy regulation Act of 2009 provides greater clarity and states that the erb shall:

1) (c) receive, investigate and determine complaints from consumers on prices and


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quality of services provided by any licensed enterprise and regulate such prices and quality of services as provided under this Act or any other written law…(l) regulate prices, charges and tariffs in the energy sector.

in addition, the proposed new legislation contains the electricity (determination of electricity Tariffs) regulations, which clearly detail how tariff applications should be made and the process that the erb should follow in their considerations, including the maximum length of time it should take and the key principles and methodologies that should be used.


regulatory oversight of power-purchase agreements is an important function, given the influence that these agreements have on end-user prices, and the adequacy and availability of electricity. in Zambia, this is particularly important, as over half of ZesCo’s capacity is contracted through a single power-purchase agreement. existing legislation makes no specific reference to power-purchase agreements or to the erb’s role in their approval. in practice, however, the erb has to certify that it has no objection to the initial drafts of power purchase agreements based on the conditions attached to the licences that it issues.


Contrary to the cases of Uganda and Tanzania, Zambia’s legislation does not grant the erb the authority to craft subsidiary legislation such as statutory instruments. however, Clause 27(1) of the energy regulation Act states that:

The Minister may, by statutory instrument, make regulations for or with respect to any matter that by this Act is required or permitted to be prescribed, or that is necessary or expedient to be prescribed for carrying out or giving effect to this Act.

The erb may therefore make representations to the Minister of energy and Water development regarding proposals for regulations that should be issued. in practice, however, there tend to be delays in this process. This provision remains in the proposed legislation, but with the inclusion of Clause 48, which states:

The board shall issue and publish in the Gazette such guidelines, bulletins or other regulatory statements as the board may consider necessary or desirable for the administration or execution of this Act.

in Zambia, the making of subsidiary legislation has traditionally been the responsibility of the respective minister and, in general, such power has never devolved to statutory institutions.37

Authority to carry out administrative functions

The erb has the authority to carry out the general administrative functions that are required of any body corporate, such as the preparation and approval of budgets and the determination of organisational structure and the hiring of staff. even so,


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through the following three clauses of the energy regulation Act, it is the minister who gives final approval:

3 A(2) The terms and conditions of service of the executive director38 shall be determined by the board with the approval of the Minister.4 (1) There shall be a secretary to the board who shall be appointed on such terms and conditions as the board may, with the approval of the Minister determine.4 (3) The board may appoint, on such terms and conditions as it may, with the approval of the Minister, determine, such other staff as it considers necessary for the performance of its functions under this Act.

This goes against the principles of regulatory independence. The proposed new legislation seeks to remedy this situation.

Adjudication of disputes

The erb adjudicates disputes based on the interpretation of Clause 6(1)(d) of the energy regulation Act:

receive or investigate complaints from consumers and licensed undertakings on services provided by the undertaking and regulate such services by the attachment of appropriate conditions to the licences held by undertakings or by such other means as the board considers appropriate.

it was recognised that this was an area that required greater clarity, and the proposed legislation was therefore expected to enhance the powers of the erb in the mediation of disputes and to provide greater clarity and certainty to the industry. As at 2010, however, there had been no progress in converting these proposals into law. What appears to be an excellent initiative to further the development of the Zambian power sector is therefore at risk of not being implemented.

Regulatory independence

For regulators to be independent, it is widely accepted that the law should provide clarity on the manner in which those charged with the responsibility of making regulatory decisions are appointed. The legislation should also provide regulators with security of tenure even in the face of difficult or sensitive decisions. regulators should also have guaranteed sources of funding, preferably outside of the governmental fiscal regime, as well as the authority to apply such funds as they deem fit in carrying out their duties. Like any other corporate body, regulators should have the freedom to make administrative decisions.

The board

in 1996, five of the seven board members that the Act provided for were appointed. Three of these were full-time appointments, and the energy ministry appointed the chairperson in accordance with the law at the time.39 The erb became operational in 1996, albeit with a skeleton staff. While in similar regulatory institutions, such as


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in Tanzania for example, the executive director (Ceo) is also a member of the board, this is not the case in Zambia, where the executive director is an ex officio member of the board who ‘may’ attend its meetings.

The 2003 amendment to the Act provides for the board to elect the chairperson and vice-chairperson from among its members. bearing in mind that this would be the very first business of any new board, it seems likely that the members would not know one another sufficiently to gauge experience and qualifications to the extent required to make an informed decision. such a decision might therefore be better made by the minister, who would be privy to the information used in the appointment of the board members.

According to the 1995 energy regulation Act, the board of the erb should comprise seven part-time members appointed by the Minister of energy and Water development for a term of three years. This term is renewable once. board members should be eminent persons with adequate knowledge, experience and qualifications in the fields of engineering, finance, law, natural-resource management, the electricity or petroleum industries, or the administration of these.

The 1995 energy regulation Act makes no provision for staggered terms of office for board members. This practice is useful for the purposes of continuity and regulatory policy stability. The draft legislation does provide for this, however. The proposed legislation also seeks to increase the length of tenure from three to five years on account of the length of time it takes board members to become completely familiar with regulatory processes.

Clause 6 of the same Act states that no person may be appointed to the board who:a) is an undischarged bankrupt;b) has been convicted of an offence involving fraud or dishonesty;c) has been convicted of an offence under this Act or any other written law and

sentenced to a term of imprisonment of not less than six months, without the option of a fine;

d) is an office bearer or employee of any political party; ore) is the holder of a licence or has any interest in a licence or in a partnership or

corporation that is a holder of a licence.

The 1995 Act also provides the following grounds on which membership of the board may be terminated:

a) if the member is absent without reasonable excuse from three consecutive meetings of the board of which the member has had notice;

b) if the member acquires a licence in the energy sector;c) if the member becomes mentally or physically incapable of performing the

duties of a member of the board or;d) if the member is declared bankrupt.

in spite of these provisions, the energy minister has on at least two occasions dissolved the board before members had reached their three-year tenure limit, for reasons that did seem to have anything to do with those provided for in the Act.


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Legally, this was made possible by Clause 26 of the interpretation and General Provisions Act of 1994, which states:

26. Where, by any written law, a power to make any appointment is conferred, the authority having the power to make the appointment shall also have the power (subject to any limitations or qualifications which affect the power of appointment) to remove, suspend, reappoint or reinstate any person appointed in the exercise of the power.

however, the fact that the minister removed members from the board for unspecified reasons does call into question the government’s commitment to regulatory certainty. While the minister in reference to the board has remarked that he ‘would want them to be as independent as possible’,40 several industry stakeholders have stated that they do not see the erb as independent but rather as beholden to the government.41

Financial independence

The energy regulation Act states that the erb can be funded by parliamentary allocations, grants and donations, and through funds that vest in and accrue to the board as a result of its work. by far the largest proportion of erb funding is derived from ‘funds that vest in and accrue to the board’ by means of licence and application fees.

Licence application fees are calculated at 0.1 per cent of the start-up costs (in the case of a new venture), 0.1 per cent of most recent annual turnover (in the case of the renewal of a licence) or a minimum of ZMK1 million (Us$267).42 As of 2010, annual licence fees were calculated at 0.7 per cent of the actual annual turnover of the licensed business, and the law provides for the possibility of this figure being increased to a maximum of 0.8 per cent. of the total amount collected by the erb for licence and application fees, 20 per cent is due to the government and 80 per cent is retained. in order to safeguard the erb’s financial and administrative independence, it is important that this practice receives the full backing of the law and is taken into account in the proposed legislation.

The licence and application fees retained by the erb over the period 1998 to 2007 are shown in Table 4.4. over this period, fees averaged 83 per cent of the erb’s total income, and if the year 2000 when the government gave the erb with an extraordinary waiver is excluded from the calculation, this figure rises to 86 per cent.

Table 4.4 ERB fees as a proportion of total operational income, Zambia, 1998–2007Year 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

operational income (Us$) 799 662 1 505 178 2 906 209 1 879 747 2 207 870 2 289 963 3 200 909 5 368 625 5 771 756 7 063 437

Fees (Us$) 639 775 1 127 372 1 790 973 1 659 984 1 674 663 2 003 746 2 881 036 4 522 553 5 553 711 6 629 140

Fees as % of income 80.0 74.9 61.6 88.3 75.8 87.5 90.0 84.2 96.2 93.9

source: erb, personal communication (2009)Note: The currency conversions are based on the 12-month average calculated at the end of december of each year using bank of Zambia statistics.


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While such reliance on a single source of income could pose a risk to the erb, this practice is not uncommon to regulatory institutions. in any case, the erb’s actual income was less than budgeted for in only three years during the period 1999 to 2007 (see Figure 4.6). This means that, by and large, the erb has been adequately funded, which could be interpreted as a sign of the government’s commitment to the regulatory process.

Figure 4.6 The ERB’s actual income compared with budgeted income, Zambia, 1999–2007

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source: erb, personal communication (2009)

it is important to note that because the erb is a multisectoral regulator, its mandate extends to the petroleum, coal and renewable energy industries. however, the erb does not distinguish between these industries in its annual financial reporting, and the figures given in Table 4.4 and Figure 4.6 thus reflect consolidated amounts and include data from the energy sector as a whole. even so, the contribution of coal and renewables to total income was negligible. in 2008, the petroleum industry’s contribution was approximately 77 per cent, and the remainder was derived largely from the electricity industry.43

Although licence fees are ultimately paid for by consumers of energy-related services in Zambia, erb fees are not indicated on consumer electricity bills. Consumers, who actually finance the erb, should ideally know how much they are contributing to its operations. This would make the erb more accountable to the public, and since there are instances when licensed operators fail to remit fees on time, it would give operators an added incentive to be more disciplined.

Administrative independence

The erb’s Ceo (executive director) is appointed by the board, which also approves the organisational structure of the institution and the appointment of senior staff. in 2009, the erb had a staff complement of 61, which is a sizeable workforce, but it should be remembered that the erb regulates the whole of the energy sector. Nevertheless, approximately 50 per cent of these positions were administrative, which raises the question of whether there might be scope for this balance to be shifted in favour of professional staff.

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The board also determines the terms and conditions of service of staff at the erb, but with the passing of the 2003 amendment to the energy regulation Act, final approval became the preserve of the minister. The government has since issued an additional directive stating that the Cabinet office should sanction conditions and terms of service.44 This has the potential of equating erb conditions of service with those of government employees and could hamper the employment of suitable talent. such an eventuality would be at variance with the very rationale of setting up an independent regulatory body.

between 1997 and 2008, staff turnover averaged 5.8 per cent. This relatively low figure masks the fact that key skills have been lost, particularly in the area of economic regulation.45 The main reason for staff attrition appears to be inadequate remuneration. staff costs were the single highest expenditure item, consistent with other similar institutions, ranging between 25 per cent and 57 per cent of total operational income over the period 1998 to 2007, as shown in Table 4.5.

Table 4.5 ERB staff costs as a proportion of total operational income, Zambia, 1998–2007

Year 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

operational income (Us$) 799 662 1 505 178 2 906 209 1 879 747 2 207 870 2 289 963 3 200 909 5 368 625 5 771 756 7 063 437

staff costs (Us$) 197 331 644 438 864 240 917 896 918 619 946 911 1 348 299 1 888 986 3 303 046 3 042 300

staff costs as % of income 25 43 30 49 42 41 42 35 57 43

source: erb, personal communication (2009)Notes: The currency conversions are based on the 12-month average calculated at the end of december of each year using bank of Zambia statistics. As the erb is a multisectoral regulator, the staff complement has to deal with the energy sector as a whole, not just the electricity industry.

Accountability

The erb is required to produce an annual report that includes audited accounts prepared by an auditor appointed by the board with the concurrence of the minister within six months of its financial year end on 31 december. Thereafter, the annual report is required be presented to Parliament within 21 days of the start of the next sitting. The auditor-general also audits the operations of the erb from time to time. Apart from these formal requirements, there is regular informal contact between the erb’s executive director, the energy minister and the permanent secretary at the energy ministry.

The erb also appears before parliamentary committees on an ad hoc basis, to make representations on various matters affecting the energy sector. such representation has included the erb’s views on the commercialisation of ZesCo, and on the performance of the electricity sector and the issue of electricity tariffs. however, no parliamentary committee has specifically reviewed the erb’s performance. such reviews could enhance accountability and keep legislators, policy-makers and the public at large better informed of the erb’s activities.


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Furthermore, although various consultants have reviewed the erb’s systems in the past, as at 2009, there had been no independent impact assessments or performance audits conducted in the erb. These are useful tools that could further enhance the public accountability of the erb, and given the erb’s autonomy with respect to budgeting, value-for-money audits would help to reassure stakeholders that expenditure was being prudently managed.

Appeals

in the event that a party to an erb decision is aggrieved, the energy regulation Act provides for an appeal to the high court. Clause 16 of the 1995 Act makes provision for this specifically with respect to decisions pertaining to licensing:

1) Any person who is aggrieved by the revocation of a licence, or by the board’s refusal to renew a licence, may appeal to the high Court within thirty days of receiving notification of the revocation of, or the board’s refusal to renew, a licence.

2) due lodgement of an appeal shall stay any revocation against which the appeal is brought, pending the outcome of the appeal, and in the case of a refusal of renewal, the licence if expired shall be deemed to have been renewed on the same terms and conditions pending that outcome.

in determining such an appeal, the high court undertakes a judicial review of the process used to arrive at the initial decision and does not decide on the substantive matter. The high court can therefore request that the erb reconsider the decision only on the grounds of not having fully followed due process.

These provisions do not preclude aggrieved parties from seeking a judicial review on the basis of natural justice on all other matters dealt with by the erb, such as tariffs and standards. by 2009, the erb had never been taken to court on such grounds.46 in the past, the erb accommodated informal appeals even on decisions related to tariff levels, but this practice has been discontinued. in response, industry representatives have bemoaned the lack of a formal process through which they can appeal specifically against tariff decisions.47

Transparency

Major decisions of the erb are published in the newspapers and on its website (http://www.erb.org.zm), but it is difficult to find documentation detailing the procedure used in responding to licence applications and determining tariffs, or summaries of decisions made at erb meetings. These could be useful additions to the website. such public disclosure could counter the view among some stakeholders that the erb’s decisions are ‘generally unpredictable’.48

The erb holds public hearings in the case of tariff applications where objections are heard and the respective utility is afforded an opportunity to make its case and respond to the objectors. some stakeholders view these public hearings as public-relations exercises,


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however, and indicated that they believe that the views presented are not really taken in to account, and that decisions are made prior to the hearings. other stakeholders believe that the erb does not engage with them sufficiently on tariffs and other matters.49 The erb has subsequently endeavoured to make hearings more meaningful by summarising tariff requests and posing specific questions to the public for comment. This approach was applied in the case of ZesCo’s tariff requests for 2008 and 2009.

For general information-dissemination purposes, the erb holds public meetings across the country from time to time. At the time of the research for this volume in 2009, the board was considering opening up licensing-related meetings to the public

Ethics

The erb board and staff subscribe to a code of ethics that prohibits the acceptance of gifts with a value in excess of Us$200, the use of confidential information for personal advantage, self-enrichment through the use of one’s position at the erb, and the use of one’s position to gain employment for others. The code is consistent with international best practice and is an important element of regulatory accountability and transparency.

Regulatory substancein discussing the area of regulatory substance relative to the erb, the focus is on licensing and market access (a crucial function if Zambia is to overcome the challenges of generation capacity), as well as tariff setting (upon which the current and future sustainability of the sector is premised). Technical quality and reliability standards, as well as pro-poor regulation, are also covered.

Market access and licensing

Any entity that seeks to carry out entrepreneurial activity in the Zambian power sector has to be licensed by the erb. in this respect, the erb issues four types of licences, namely, for generation (greater than 100 kW), transmission, distribution and supply. The generation and transmission licenses are valid for 30 years, while those for distribution and supply are for 15 and 5 years respectively.50 Given the likelihood of additional players entering the sector, the licensing of an independent system operator and a power-market operator would help ensure a level playing field across the sector. The erb’s licensing process is outlined in Figure 4.7. in essence, applicants for new licences are subjected to a financial, economic and technical assessment based on their business case, while for renewals, the same type of assessment is carried out based on past performance.

Licences are issued subject to certain conditions, and in the event that a licensee defaults on any of these, the erb undertakes to follow the actions shown in its enforcement pyramid (4.8), where the ultimate action is licence revocation. The erb does not have the authority to revoke a licence, however. That power is vested in the minister, who can revoke a licence only on the basis of a recommendation from the erb. The circumstances under which a licence may be revoked are determined in the legislation as follows:


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• repeated contravention of the provisions of the energy regulation Act or the conditions of the licence;

• contravention of a condition in the licence that is expressed in the licence to be a condition whose contravention may result in revocation or suspension of the licence; or

• being the subject of such complaints by the public as in the opinion of the board warrants revocation.

As of 2010, the erb had not revoked any licences in the electricity sector.

Figure 4.7 Outline of the ERB’s licensing process, Zambia, 2009

Financial, economic and technical assessment

Application fee at 0.1% of investment

determined

Applicant may appeal to High Court Board issues licence

New business?

Purchase, complete and submit application form

Attach supporting documentation:• Certificate of incorporation• List of directors• Technical designs and data

Board considers application

30-day gazette notice issued for objections from public

Board refuses application

Objections?

Applicant pays within 7 days

Pay requisite fee and lodge objection

Board calls public hearing if deemed fit

Applicant afforded opportunity to

respond

1. Audited financial statements (most recent)2. 3-year business plan

• Cashflow • Balance sheet • Operating statement

3. Evidence of financial capability to sustain operations

1. 5-year business plan • Sales • Cashflow • Operating statement • Balance sheet

2. Proof of funds

No

No

Yes

Yes

source: Authors’ compilation based on energy regulation Act and erb, personal communication (2009)


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Figure 4.8 Summary of the ERB’s licence revocation process, Zambia, 2009

Licence revocation

Licence suspension

Criminal penalty (court)

Penalty/Order

Warning letter

Discussion/Persuasion


Power-sector planning and the procurement of new capacity

Planning is crucial for ensuring orderly market entry and the adequacy and reliability of power supplies. in hybrid power markets such as Zambia’s, where there is a dominant, vertically integrated state-owned utility and private companies that operate on the margins of the sector, the issue of who exactly is responsible for planning can easily become nebulous. Furthermore, it is crucial that those responsible for planning work closely with those responsible for procurement processes, so that the planning of new capacity is co-ordinated with the initiation of new bids.

in Zambia, the energy ministry is responsible for planning, a function that was previously performed by ZesCo. The procurement of new generation (and transmission) capacity is managed by the office for the Promotion of Private Power investment (oPPPi). in 2009, the ministry finalised its Power system development Master Plan (Chubu electric Power Company, 2009). This was the first plan since a 1998 ZesCo master plan that had since hardly been revised – a clear indication of how easily the planning function can be neglected in hybrid power markets. The 2009 plan will have to be regularly updated, and there might be some benefit in a committee of stakeholders (including the government, erb, ZesCo and private operators) being established to oversee this. such a committee could also draw on the planning capabilities that exist in ZesCo and CeC. Alternatively, if significant capacity constraints are identified within the ministry, the erb could specify the planning function in, for example, the yet-to-be-issued system operator licence. interestingly, however, the erb’s generic transmission licence contains the following:

The Licensee shall be obligated to perform long term planning for the development of the integrated generation and transmission system. such plans, in the form of an Annual system opportunity statement as prescribed by the erb, shall be developed in accordance with the Grid Code and any other relevant codes, rules and standards prescribed or approved by the erb. such plans should be of assistance to potential power system developers and authorised electricity operators in identifying areas for system development and augmentation.


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The Licensee shall produce such plans on a regular basis but not less than bi-annually. The plans shall be reviewed with the erb and published for comments from other Licensees and interested parties. Final plans shall be made publicly available.

The forward time horizon for such plans shall be no less than 15 years.

by 2012, neither ZesCo nor CeC, the two companies with transmission licences, were producing Annual system opportunity statements (in effect system plans) with any regularity.51

With regard to procurement of new generation capacity, there is no policy that articulates the allocation of new build opportunities between ZesCo and the private sector. Moreover, oPPPi, which ostensibly runs bid processes, is under resourced; in 2012, it employed only three professional staff, and its lack of a legal mandate could hinder its operations and pose a threat to the timely and efficient procurement of new capacity. in 2012, oPPPi was spearheading the government’s project preparation and negotiations for the Kalungwishi project and the Zambia–Tanzania–Kenya transmission interconnector project. Table 4.6 lists generation projects in the pipeline for Zambia as at 2012.

Table 4.6 Generation projects in the pipeline, Zambia, 2012

Project Capacity (MW)

Cost (US$ million)

Developer Comments

Kafue Gorge Lower(hydro)

600–750 2 000 Joint venture between ZesCo and sino-hydro

Negotiations for the establishment of joint venture company ongoingexport credit (Us$1 billion) plus others

Kariba North bank extension(hydro)

360 420 Wholly owned ZesCo subsidiary

export-import bank of China (Us$360 million) and development bank of southern Africaengineering, procurement and construction (ePC) contractor – sino-hydro

itezhi-Tezhi(hydro)

120 240 Joint venture between ZesCo (50%) and Tata (50%)

Concessional loan from indian government and othersCivil works 30% completeYet to reach financial close

Maamba(Coal)

300 725 Nava bharat existing coal mine being revivedequity of Us$210 millionePC contract awardedincludes 28 km transmission lineFirst unit to be commissioned in 2014, and second unit in 2015Financial close targeted for first half of 2013

Kabompo Gorge(hydro)

40 190 CeC Yet to reach financial close

Kalungwishi(hydro)

247 500 Lunzua Power Authority

ePC contract negotiations ongoingYet to reach financial close


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Project Capacity (MW)

Cost (US$ million)

Developer Comments

Ndola(hFo)

50 75 Ndola energy Us$20 million debtUs$55 million equityTo be commissioned in first quarter of 2013

Muchinga Power(hydro)

120 272 Lunsemfwa hydro Power Company

Project preparation ongoing

sources: CeC, ZesCo, Maamba Collieries, Ndola energy and oPPPi, personal communication (2010 and 2012)

Table 4.6 reveals the increasing influence of China and india on Zambia’s power market. The Chinese-supported projects, financed primarily through export-credit arrangements, provide an alternative to traditional project financing. Though not competitively bid, what appears to be attractive to the government is the swiftness with which project preparation is done and financial close is reached, thus increasing the likelihood of a quick start of construction. For example, in 2007, the Zambian government retained the World bank affiliate, international Finance Corporation (iFC), as advisors on the Kafue Gorge Lower project.52 iFC recommended an international competitive-bidding process through which it would have taken 36 months to reach financial close after all feasibility studies had been concluded. in 2010, at the end of iFC’s contract for advisory services, the government announced that it had entered into an agreement with the China-Africa development Fund, the China development bank and the sino-hydro Corporation for the development of Kafue Gorge Lower. At the time of writing, geotechnical feasibility studies were being undertaken, but financial close had yet to be reached. This had been delayed ostensibly by the decision of the new government to change the equity structure of the joint venture company.53 54

As at 2012, none of the projects listed in Table 4.6 had been licensed by the erb. Nonetheless, given the size of most of these projects and their potential impact on pricing as well as the adequacy and reliability of generation, it would be prudent for the erb to develop mechanisms through which it can be kept abreast of developments. As we have stressed in other chapters, and as evidenced in Uganda’s bujagali project, the presence of regulators in an observer capacity during power-purchase agreement negotiations can aid in clarifying potential stumbling blocks and understanding the context even before initial agreements are sent through the regulatory no-objection process. Nonetheless, such observer status should not imply that the regulator has ceded its right to approve the power-purchase agreement.

Tariffs

The erb uses the revenue-requirement method to determine tariffs,55 and this is embedded in the cost-of-service model depicted in Figure 4.9.


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Figure 4.9 The ERB’s cost-of-service model, Zambia, 2007

Sum

mar

y as

sess

men

t

Supply/Demand Balance

Total demand energy and capacity

Regulatory asset value

Capital expenditure

Cost of capital

Supply/Demand balance drives some capital

expenditure elements

Supply/Demand balance drives some operating

costs

Cost reflective Equal on aggregate

Equal for each product group

Regulatory asset value

rollover

Taxation

Depreciation

Return

Operating costs

Revenues by customer group

Revenue requirements

By business unit

By customer group

Investment finance costs

Tariff framework

Demand by customer group

Customer numbers by

customer group

source: iPA energy Consulting, Norton rose & Pb Power (2007)

in theory, the revenue-requirement method allows for full cost recovery but, as of 2010, this had yet to be achieved. As already mentioned, Zambia’s electricity tariffs have been among the lowest in the world, which has been a significant challenge to the goal of cost recovery. The government’s aim is to reach cost-reflective tariffs by 2011.56 The erb has projected that the cost-reflective tariff for residential consumers in 2011 will be approximately 6.57 Usc/kWh, as shown in Table 4.7.

Table 4.7 The ERB’s projected path to cost-reflective tariffs by 2011, Zambia

Customer category 2008 2009 2010 2011residential % changeUnit price (Usc/kWh)

26.80 4.79

16.605.59

11.906.25

5.006.57

Commercial % changeUnit price (Usc/kWh)

1.305.14

0.305.16

0.305.18

4.405.40

services % changeUnit price (Usc/kWh)

6.803.89

1.903.97

1.904.05

7.004.33

small power % changeUnit price (Usc/kWh)

16.203.26

5.503.44

4.503.59

5.703.80


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Customer category 2008 2009 2010 2011Large power % changeUnit price (Usc/kWh)

27.502.76

16.603.22

2.203.29

6.303.50


by 2012, the proposed tariff levels had not been reached. Table 4.8 shows ZesCo’s tariff yield (average tariff) over the period 2006 to 2011. by comparison with other countries in sub-saharan Africa, including all the others covered in this volume, this is a low tariff. The figures in Table 4.8, however, mask the unique structure of Zambia’s electricity industry, in that approximately 50% of the power is consumed by a single customer at high voltage (CeC). even when the average tariff solely on account of retail consumers is calculated (5.7 Usc/kWh for 201157), however, Zambia’s tariffs are low by regional comparison. This has implications for the time it will take to reach cost reflectivity and acceptance by the electricity-consuming public of increases in the price of electricity. Low tariffs may also prove to be a stumbling block for the entry of iPPs and the expansion and maintenance of ZesCo’s infrastructure.

Table 4.8 ZESCO’s tariff yield (average tariff), Zambia, 2006–2011

2006 2007 2008 2009 2010 2011revenue (Us$ million) 172.3 241.1 235.5 346.5 327.2 433.5energy consumed (GWh) 8 421 9 014 9 440 9 631 9 619 10 315Tariff yield (Usc/kWh) 2.05 2.68 2.49 3.60 3.40 4.20


Asset valuation

An important factor in the revenue-requirement determination is the method used to determine asset values, as this influences the return earned on assets and depreciation expenses. There has been some debate within the erb as to whether the valuation should be based on historical or replacement values. The two approaches would probably yield widely differing tariff outcomes. With regard to depreciation in particular, valuations based on historical costs would not enable ZesCo to build up the reserves required to replace plants when required, and would mean significant tariff increases to support plant refurbishments. The erb also needs to adopt an internationally recognised means of valuation for Zambia’s old hydropower assets.

Containment of ZESCO costs

The need to increase tariffs to cost-reflective levels presents a dilemma for the erb in that, while there was a legitimate need for increases, there was also a need for firm guarantees that the additional revenue generated by ZesCo would not lead to wasteful expenditure. Any tariff award to ZesCo would therefore have to be accompanied by additional robust oversight as well as incentives and sanctions to ensure prudence. in this regard, the erb has developed a set of key performance


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indicators (KPis), shown in Table 4.9, against which ZesCo’s performance is measured. At the time of writing, the KPis did not impact on tariff awards to ZesCo, but for future tariff reviews the erb planned to take them into consideration.58

Table 4.9 Key performance indicators for ZESCO, Zambia, 2011–2014

Performance indicator Target measures

New connections and metering

All standard new residential connections to be made within 30 days after payment has been received from the consumerinstall 25 000 pre-paid meters per quarterAll unmetered consumers to be metered by 2013

Collections reduce non-government debtor days to not more than 60 days by March 2013reduce government debtor days to not more than 90 days by March 2013

debt/equity ratio Move debt/equity ratio to 70:30 by March 2016

Cost containment

improve customer–employee ratio to 100:1 by March 2012reduce staff costs to 45% of operating costs by March 2013Maintain transmission losses to 5% or lessreduce distribution losses to 14% by March 2012

Quality(maximum levels applicable from April 2011)

dry season sAidids – 27 hoursWet season sAidiWs – 36 hourssAiFids – 5 timessAiFiWs – 5.5 timesCAidids – 5 hoursCAidiWs – 7 hoursAsAi – 90%

source: erb, personal communication (2012)Note: sAidi = Total customer hours of interruptions Total customers served sAiFi = Total customer interruptions Total customers served CAidi = Total customer hours of interruptions Total customer interruptions AsAi = interrupted customer hours Available customer hours


The relationship between ZesCo and CeC is governed by a bulk-supply agreement (bsA), a power-purchase agreement that is due to lapse in 2020. Given that CeC is ZesCo’s principal customer, this agreement is by far the most important power-purchase agreement in Zambia’s power sector. The erb has no regulatory oversight of the bsA, however, as it was signed before the regulator became operational. While applying regulatory policies in retrospect is at variance with best practice and raises pertinent regulatory commitment and certainty issues, the significant degree to which the bsA contract has the potential to distort the Zambian power market is sufficient reason to seek to institute the means by which the erb’s regulatory oversight could extend to it. in any case, it has been widely recognised that the pricing of the bsA was not favourable to ZesCo and led to the 2008 upward revision in the tariff to CeC. it is possible that there will be further revisions to the agreement before it expires, and in that event, the erb should play a more active role.


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Notwithstanding the challenge that arises from the bsA, conditions in the generic transmission and generation licences provide ample scope for the regulatory oversight of power-purchase agreements in general. The following clauses are common to both licences:

18.1 The Licensee shall provide for the erb’s prior review of all contracts and agreements:a) With other licensees or with retail or wholesale customers;b) For the import or export of power or energy; c) For the transmission or the purchase or sale of bulk power or energy,

including any and all contracts or agreements for the purchase or sale of electricity being entered into for the purposes of enabling or securing financing for new or expanded capacity.

18.2 Any such contracts or agreements concluded without the erb’s prior approval of their pricing provisions shall be considered null and void for the purposes of the erb’s determination of tariffs.

18.3 The erb has the right to retain copies of such contracts and agreements.

in addition, the following conditions are specific to the generation licence:4.1 The Licensee shall enter into electricity sales contracts in accordance with

the Grid Code. All electricity sales contracts, including those for the export market, shall be approved by the erb.

4.2 The price at which generated electricity may be sold shall be determined in accordance with procedures prescribed by the erb, and actual tariffs shall be subject to prior approval by the erb.

4.3 The Licensee shall comply with its obligations under its electricity sales contracts and shall, upon request, provide full information relating to its contractual obligations to the erb.

4.4 The Licensee shall enter into an ancillary service agreement with the system operator in accordance with the Grid Code.

4.5 The Licensee shall, if necessary, enter into a distribution use-of-system and connection charging agreement with the distribution Licensee.

The following conditions are specific to the transmission licence:3.1 before levying or quoting any tariffs, fees or charges for the provision of

transmission use of system or connection services, the Licensee shall develop and submit to the erb for approval within the first 30 days of each calendar year a methodology for determining fair and equitable transmission use of system fees and tariffs and connection charges, and a schedule of proposed fees, tariffs and charges for various standard connection designs.

3.2 The methodology shall appropriately reflect recovery of all reasonable and prudent material and labour costs, including an appropriate return on investment, necessary in operating the network or putting in place a connection, and shall also include guidance on how to apportion charges among multiple connections at a single off-take point.


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Technical standards

The erb uses standard Zs387 (developed by the Zambia bureau of standards) to regulate the quality and reliability of electricity in Zambia. The standard, based largely on the south African standard Nrs048, was developed through a consultative process with various stakeholders spearheaded by the erb. Zs387 contains quality levels that the electricity-supply industry should adhere to in terms of frequency, voltage deviation, voltage harmonics, forced interruptions and planned interruptions.

implementation and monitoring of these standards has proved difficult, however, and in 2010, the erb was in the process of hiring a consultant to determine the base level at which the power system was operating in relation to these standards prior to developing a monitoring regime.

There is also a separate standard for consumer service, Zs397. its development was also spearheaded by the erb through a consultative process. Although the monitoring of performance against this standard has also been difficult,59 the standard provides minimum levels for various consumer service parameters including:• processing of requests for service;• meter reading;• location of pre-payment metering vending stations;• service faults;• notification of planned interruptions;• telephone response times;• treatment of consumer complaints; and• street lighting.

Pro-poor initiatives

Rural electrification

by 2012, only 4.5 per cent of the rural population in Zambia had access to electricity. With the strong link between access to electricity and poverty alleviation, the government is keen to rapidly expand electrification in rural areas. The rural electrification Authority (reA), which was established in 2003, has an ambitious target to increase rural access to electricity to 51 per cent by 2030. if achieved, this would improve the overall electrification rate in the country from 23 per cent to 66 per cent. As might be expected, the funding required for an electrification programme of this size is significant. Current estimates are that in order to reach the target, a total of Us$1.1 billion would need to be spent at an annual rate of Us$50 million. The electrification programme is funded by a 3-per-cent levy on all electricity bills, transfers from the government treasury and donor grants. The rural electrification challenge remains a formidable task. spending between 2006 and 2008 fell far short of the target, and projected expenditure for 2009 was therefore more than double the amount spent in the previous two years (Table 4.10).


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Table 4.10 Spending on rural electrification projects, Zambia, 2006–2009

Currency 2006 2007 2008 2009 (projected)

rural electrification spend (ZMK billion) 10.5 21.0 21.4 88.0rural electrification spend (Us$ million) 2.9 5.2 5.7 16.7

source: reA, personal communicationNote: exchange rates are based on annual bank of Zambia averages and for 2009 on the prevailing mid-rate on 15 May 2009.

Pro-poor tariffs

ZesCo’s increasing block tariff is structured as follows:• r1: 0–100 kWh;• r2: 101–400 kWh; and• r3: >401 kWh.

The first block, r1, also referred to as the lifeline tariff, is based on the rationale that 100 kWh per month is required to meet the basic electricity requirements of a household. This amount is generous by international standards. Arguably, subsidised electricity should be provided only to those with insufficient means. however, the block tariff structure allows the basic subsidy to accrue to all residential consumers. Moreover, given the low access to electricity and the fact that tariffs are below economic levels, it is something of a contradiction to subsidise tariffs. Alternative and more sustainable poverty-alleviation methods would be worth exploring.

ConclusionThe erb faces considerable challenges. The most significant is that tariffs remain too low for economic sustainability. in the absence of direct equity injections from the government, ZesCo will continue struggling to raise funds for plant renewal and capacity expansions even in the light of the Chinese and indian alternatives earmarked for specific projects. The erb therefore has to devise means of making tariffs reach cost-reflective levels without this being disruptive to the overall economy. A key element of this puzzle is the CeC bulk-supply agreement, which should be priced to ensure that the mining community pays their fair share for the burden they impose on Zambia’s power system.

however, given the questions raised about ZesCo’s levels of efficiency, there is a danger that increased tariffs may merely allow wasteful expenditure and might not necessarily result in improved investment in the quality and reliability of the services provided. The erb’s increasing emphasis on measuring ZesCo’s performance against agreed indicators provides scope for curtailing excess losses provided that consequences for poor performance are incorporated into this regime. Tariff increases will also require an effective communication strategy to ensure that the public receive clear explanations for tariff increases.

With such an emphasis on tariffs, it is tempting to believe that tariff increases are the panacea for all the sector’s woes. such a theory is disproved by the Tanzanian example,


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however, where tariffs are high but new investment remains difficult to attract. Tariffs must therefore be seen in the context of a package of regulatory measures.

An area in which there seems to be scope for the erb to play a more active role is in the procurement of new capacity. Mechanisms that keep the regulator abreast of developments should be developed, rather than the regulator being involved only in granting approval for power-purchase agreements at the very end of the process. For example, a system-adequacy standard could be included in the licence conditions for transmission (or for system operation, in the event that the erb issues a separate system operation) against which the erb could ensure that current and planned generation and import capacity are sufficient. in addition, the erb, in conjunction with the office for the Promotion of Private Power investment (oPPPi), could develop a set of guidelines outlining the processes for licensing and the approval of power-purchase agreements to enable potential investors to understand the regulatory environment more clearly from the start.

The Zambian power sector is in an exciting phase of its development, and the continent’s oldest regulator must be part of that excitement.

Notes1 For a discussion of hybrid power markets, see Gratwick & eberhard (2008).2 see http://www.engineeringnews.co.za/article/uncertainty-looms-over-hydroelectric-project-

eskoms-involvement-2009-12-043 see http://www.mewd.gov.zm/index.php?option=com_content&task=view&id=106&itemid=1424 ZesCo does own a fleet of stand-alone diesel-fired generators that supply remote rural

areas, but as at 2010, their combined capacity of 7.3 MW was a negligible fraction of total installed capacity. CeC also owns a sizeable 80 MW of grid-connected diesel-fired generation units, but these are reserved for emergencies on account of mining requirements, which necessitate that critical underground water-pumping stations and ventilation equipment are kept running if the main grid supply fails.

5 Kariba North bank power station is fed by water from one of the largest reservoirs in the world, Lake Kariba, and Kafue Gorge, as well as Lake itezhi-Tezhi.

6 For a full list of southern African Power Pool countries, see http://www.sapp.co.zw7 ZesCo, personal communication (2010).8 see http://africanhydrosymposium.org/pdf/2008/LhPC%20hYdro%20sYMPosiUM%20

-%20MPs%20UPGrAde.pdf9 The Victoria Falls Power Company was established in 1906 with the aim of meeting the

electricity requirements of the Witwatersrand, the area that is famous as the source of most of south Africa’s gold mines. in the year it began, the Victoria Falls Power Company bought out rand Central electric Works and the General electric Power Company. in 1909, the company was renamed the Victoria Falls and Transvaal Power Company, by which time the plan for drawing hydropower from Victoria Falls had been abandoned in favour of exploiting the coal reserves found in what was then the Transvaal. For more info, see http://www.eskom.co.za/live/content.php?item_id=495&revision=en%2F0 and http://www.vaaltriangleinfo.co.za/history/resources/electricity_1.htm


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10 see http://www.zesco.co.zm/index.php?option=com_content&task=view&id=13&itemid=911 see http://africanhydrosymposium.org/pdf/2008/LhPC%20hYdro%20sYMPosiUM%20

-%20MPs%20UPGrAde.pdf12 see see http://www.zesco.co.zm/index.php?option=com_content&task=view&id=13&itemid=913 see http://www.cecinvestor.com/milestones.aspx14 see http://www.cecinvestor.com/milestones.aspx15 see http://www.cecinvestor.com/milestones.aspx16 The Federation of rhodesia and Nyasaland, also known as the Central African Federation

(CAF), was a semi-independent state in southern Africa that existed from 1953 until the end of 1963, comprising the former self-governing colony of southern rhodesia and the british protectorates of Northern rhodesia and Nyasaland. Northern rhodesia gained independence in 1964 and was renamed Zambia. southern rhodesia gained independence in 1980 and was renamed Zimbabwe.

17 see http://www.zesco.co.zm/index.php?option=com_content&task=view&id=13&itemid=918 see http://www.zesco.co.zm/index.php?option=com_content&task=view&id=13&itemid=919 The higher Power Authority comprised two ministers from each country.20 ZesCo, personal communication (2009).21 ZCCM was the result of the merger of Nchanga Consolidated Copper Mines and roan

Consolidated Mines, companies that were formed in 1969 when the copper industry was nationalised. ZCCM’s major shareholders were the Zambian government (60.3 %) and the Anglo American Corporation (27.3%), http://www.cecinvestor.com/milestones.aspx.

22 see http://www.zaraho.org.zm/history.html23 in the mid-1980s, Zimbabwe imported up to 40 per cent of its requirements from Zambia

(esMAP, 1988b).24 CeC’s emergency generation facilities are not included in this count, nor are remote rural

stand-alone schemes such as the 700kW Zengamina project in North West province.25 distribution losses in 1988 were at an internationally acceptable level of 10.1 per cent, but by

1995 they had risen to 28.4 per cent (World bank, 2006d).26 The hiPC initiative was a programme of the iMF and World bank designed for debt to be

brought down to sustainable levels in developing countries that had high levels of poverty.27 Government had earlier committed to the privatisation of ZesCo, but increasing public

dissatisfaction with the divestiture programme was beginning to make its political viability questionable.

28 see http://www.narucpartnerships.org/documents/Zambian%20Power%20Market.pdf29 World bank colonialism, The Post, 2 december 2002, http://allafrica.com/stories/200212020222.html30 Admittedly, ZesCo managers were themselves not in support of privatisation or

unbundling and, given their access to political principals, may have helped shape the change of policy that ultimately occurred.

31 some World bank officials criticised the lack of objective measurables against which the commercialisation process could be gauged (World bank, personal communication, 2007).

32 Chambwa K, Merger of Zesco: ‘KNbC to cut production costs’, says Mpombo, The Post, 16 June 2004, http://allafrica.com/stories/200406160690.html


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33 Mfula C & s shacinda, Zambia copper mines suspend output after blackout.’ Africa Report, 18 June 2010, http://www.theafricareport.com/last-business-news/

34 ZesCo Annual reports, 2004, 2004/5, 2005/6, 2006/7. Lusaka, ZesCo.35 ZesCo, personal communication (2012).36 see http://www.cecinvestor.com/37 erb, personal communication (2009).38 The executive director is the equivalent of a Ceo.39 The 1995 energy regulation Act provided for the appointment of three full-time members

with experience and qualifications in electricity, petroleum and renewables respectively, and four part-time members from among whom the energy minister would appoint a chairperson. only five members were ever appointed to the erb’s first board. At the end of their first term, none of these appointments were renewed, and a new board consisting of three part-time members was appointed in 2001.

40 Kenneth Konga, Minister of energy and Water development, personal communication (2009).41 Members of industry associations, personal communications, 2009.42 based on the bank of Zambia’s average exchange rate for 2008.43 erb, personal communication (2009).44 The Cabinet office serves as the secretariat to Zambia’s Cabinet.45 erb, personal communication (2009).46 erb, personal communication (2009).47 Personal communications (2009).48 Personal communications (2009).49 Personal communications (2009).50 distribution and supply licences are valid for shorter times to avoid their becoming a

hindrance in the event of industry restructuring.51 ZesCo, personal communication (2009).52 Personal communication (2010).53 state, Chinese team up to develop Kafue Gorge, Times of Zambia, 14 August 2010,

http://allafrica.com/stories/201008160637.html; oPPPi personal communication (2010).54 ZesCo and oPPPi, personal communication (2012).55 Where rr = revenue requirement, rAb = regulatory asset base, ror = rate of return,

e = operations and maintenance expenses, d = depreciation and T = taxes.56 erb, personal communication (2010).57 ZesCo, personal communication (2012).58 erb, personal communication (2010).59 erb, personal communication (2010).


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Namibia: Seeking independent power producers

Namibia’s power sector faces some unique challenges. Firstly, of the countries featured in this volume, Namibia is the only one that imports more electricity than it generates. This is not necessarily a disadvantage, but since 2007, when the last agreement expired, Namibia has been unable to finalise long-term contracts with its major supplier, south Africa’s national utility, eskom. This, combined with the rapidly declining surplus capacity within the southern African region, exposes the country to a degree of insecurity in relation to the availability and cost of future imports. secondly, although access to electricity in urban areas is above 75 per cent, only about 10 per cent of rural households are connected to the grid – a reflection of the deep inequalities that exist in Namibia. Thirdly, retail tariffs have yet to reach cost-reflective levels, which has major implications for the long-term sustainability of the sector. Finally, for a relatively small country with a population of around two million, there are over 20 different entities (mostly municipalities) responsible for the distribution of electricity. Further complicating matters is the fact that municipalities are allowed to add a discretionary tax on electricity consumption, which they may use to fund the provision of other municipal services.

The sector is, however, anchored by the state-owned national utility NamPower, which has a solid technical and financial track record and is arguably the regional leader in this regard. Moreover, as we show later in the chapter, Namibia’s industry regulator, the electricity Control board (eCb), has incorporated best practice into its regulatory methods and made a commitment to reaching cost-reflective tariffs in the short term. despite the strengths of these two organisations and the fact that the sector was liberalised in 2000, private-sector participation in Namibia’s electricity industry is almost non-existent; Namibia is the only country featured in this volume where this is the case. Given the generation-capacity crunch experienced in the southern African region since 2005, the development of new indigenous generation capacity is seen as crucial by Namibia’s government, yet expectations that independent power producers (iPPs) would form an important part of achieving this goal remain unfulfilled, and the country’s flagship Kudu gas-to-power project has faced ongoing delays. The eCb has made much progress in its short history, but there is more to be done before Namibia’s electricity industry achieves sustainable security of supply.

Power-sector overviewNamibia’s Ministry of Mines and energy is responsible for energy-policy formulation and direction, and the eCb is mandated to regulate the energy sector. As shown in Figure 5.1, the electricity industry is dominated by the state-owned and vertically

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integrated NamPower, which owns and operates all the country’s generation and transmission assets as well as some distribution facilities in the rural areas of central and southern Namibia. The bulk of electricity distribution is undertaken by the City of Windhoek (the country’s largest distributor). The remainder is managed by three regional electricity distribution companies (reds)1 – Northern red (Nored), which covers most of the northern part of the country stretching to the Caprivi strip, erongo red, which covers the central coastal region in the west of the country including Walvis bay and swakopmund, and CeNored that covers the otjozondupa and Kunene regions of central-northern Namibia, and by numerous small municipal distribution operations. Like Ghana, Namibia has no specialist agency responsible for rural electrification.

Figure 5.1 Overview of Namibia’s electricity sector, 2010

Ministry of Mines and Energy

Electricity Control Board

Industry

NamPowera

Ruacana(249 MW)

Van Eck(120 MW)

Paratus(24 MW)

NOREDErongo

RED CENORED

Large usersCustomers

Municipalities

TRANSMISSION(single buyer)

SAPP imports(600 MW)

source: Authors' compilation Note: a. NamPower also distributes electricity to remote rural areas in central and southern Namibia.

Generation capacity

Total installed generation capacity in Namibia is 393 MW. This comprises the ruacana hydro facility (249 MW), the Van eck (120 MW) coal-fired power station located just outside Windhoek, and the Paratus (24 MW) diesel plant at Wavis bay. in 2009, the maximum demand experienced was 443 MW, which was well in excess of the country’s installed capacity. NamPower has therefore imported a significant proportion of its electricity requirements for many years, mainly from south Africa,


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but also from Zambia, Zimbabwe and Mozambique – thus benefitting from being a member of the southern African Power Pool (sAPP). in fact, as Figure 5.2 shows, electricity imports have exceeded NamPower’s own generation since 2004.

Figure 5.2 NamPower’s generation capacity compared with electricity imports, Namibia, 1998–2011

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source: NamPower Financial statements, 1998–20112

The rapid increase in the price of coal (see Figure 5.3) and oil since 2003 has meant that NamPower has opted to draw power from its Van eck and Paratus plants quite sparingly. For example, of the total generation into the system in 2009, ruacana’s contribution was 38 per cent, while imports contributed 60 per cent.3

Figure 5.3 Coal costs per tonne to NamPower and average international crude oil prices, Namibia, 1998–2011

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Coal per tonne (US$) Crude oil per barrel (US$)

sources: NamPower Annual report, 20094; iMF5

Note: oil prices were calculated from the average of daily quotes for brent, dubai and West Texas intermediate.

US$


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Sector performance since 2002

Figure 5.4 shows maximum demand and electricity consumption in Namibia over the period 2002 to 2011. For the two variables, namely, maximum demand and energy consumed, growth averaged 4.1 and 3.0 per cent per annum respectively, placing growing pressure on the country to secure its future electricity supplies.

Figure 5.4 Maximum demand and electricity consumption, Namibia, 2002–2011

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2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Consumption (GWh) Maximum demand (MW)

source: NamPower Annual reports, 2002–20116

in terms of generation, NamPower’s financial performance over the years has been solid (see Table 5.1), and it was assigned a bbb credit rating, which is considered investment grade, by the Fitch ratings global agency in 2005.7 This rating has been reaffirmed in subsequent years, which has enabled the company to raise loans on reasonably favourable terms. NamPower’s credit rating has also facilitated its issuing of corporate bonds. The first long-term bond, due to mature in 2020, was issued on the Namibian stock exchange and the bond exchange of south Africa in 2007, raising N$500 million (approximately Us$70 million).8 A further bond for N$250 million (approximately Us$30 million) was issued in 2009 and will mature in 2019.

Table 5.1 NamPower’s financial performance, Namibia, 2002–2011Indicators 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

revenue (Us$ ’000)

7 760 97 340 138 392 161 096 170 036 184 769 197 735 250 902 246 537 319 986

Cost of electricitya (Us$ ’000)

– – – – 44 733 48 726 64 118 82 098 104 503 139 945

Gross profit (Us$ ’000)

10 295 15 499 13 207 12 770 30 673 35 347 92 425 100 936 142 034 180 041

Average price per unit (Usc/kWh)

2.06 3.68 4.68 5.32 5.16 5.44 5.31 6.19 8.05 9.41

source: NamPower Annual reports, 2002–20119

Note: a. The cost of electricity was not reported as a line item in NamPower’s annual statements until 2006.


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With tariffs not yet at cost-reflective levels, the longer-term viability of the distribution sector is a concern. in 2008, both the City of Windhoek and CeNored emphasised that they were not earning sufficient return on their assets.10 in addition, the fact that two of the reds have not yet been formed continues to create problems in relation to economies of scale, efficiency and the viability of distributors in those regions.

Development of Namibia’s electricity sectorGiven its sparse population, vast distances between settlements and generally low levels of economic development, the establishment of a countrywide integrated power-supply system in Namibia was first mooted as late as the mid-1960s. in 1964, when Namibia was still occupied by south Africa, the industrial development Corporation of south Africa established the south West Africa Water and electricity Corporation (Pty) Ltd (sWAWeK) to harness the waters of the Kunene river for hydropower and to install electricity distribution lines down to Windhoek.11 soon plans were in place for the development of the ruacana hydropower plant.

The Kunene river lies along the border with Angola, however, and the Portuguese government (the colonial authority in power in Angola at that time) took until 1969 to give permission for the hydropower station to be built. As an interim measure, it was proposed that a 90 MW coal-fired station (comprising three 30 MW generators) be built, and by 1972, the first two generators had been commissioned at the Van eck power station just outside Windhoek. Angola’s war of independence from Portugal (1961–1975) created further delays for ruacana, so a third unit was installed at Van eck power station in 1973, and the power grid was also extended so that Windhoek, otjiwarango, Tsumeb, outjo, Grootfontein, Walvis bay and swakopmund were all connected.

by 1976, with ruacana still delayed, sWAWeK decided to build an additional power plant, and four 6 MW diesel-fired generators were installed at what would become the Paratus power station.12 A further 22 MW gas turbine was added to Paratus in 1978 (but later decommissioned) and, also in 1978, ruacana was finally commissioned with a capacity of 249 MW. by 1982, however, generation at ruacana was limited by the ongoing war in Angola, creating a shortage of electricity in the face of rising demand. in response, a fourth generator was installed at Van eck, and a 220 kV transmission line was laid from Van eck to Namaqualand in south Africa’s Northern Cape province.13 Thus Namibia began importing electricity from south Africa as early as 1982. After Namibia’s independence from south Africa in 1990, sWAWeK was transferred to the Namibian government, and the company was later renamed NamPower. in 1996, it was announced that a 400 kV power line would be constructed from Aries, near Kenhardt in south Africa, to Auas, outside Windhoek. This project was completed in 2000, making 600 MW of power available to Namibia from south Africa and other countries in the southern African Power Pool.

one of Namibia’s few experiences of private participation in the power sector occurred in 1996, when a company known as Northern electricity began to operate the distribution system in the north of the country under a concession agreement.


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Under Northern electricity’s management, collection rates improved, electricity theft declined, power-system reliability improved and the connection rate increased. despite the apparent success of the concession, the agreement was not renewed when it lapsed in 2002, ostensibly due to pressure from NamPower, from the government department responsible for municipalities (most of which supply electricity), as well as from the local authorities in the area (Clark et al., 2005). Northern electricity closed down.

Kudu gas-to-power project

Many countries in Africa, including some of those covered in this volume, have a ‘flagship’ electricity project. Namibia’s big one is the Kudu gas project, the story of which has been one of promise and disappointment amidst an ever-changing list of exploration contracts and potential developers.

The Kudu gasfield was discovered in 1974 after a consortium led by the Us-owned oil company, Chevron, drilled an off-shore exploratory well 170 km west of the town of oranjemund (Csir, 1999). it was not until 1988, however, when Namibia’s state-owned petroleum company, sWAKor, drilled a further two wells and estimated that the well contained a reserve of at least five trillion cubic feet of gas, that the discovery was considered commercially significant (Csir, 1999).

After Namibia achieved independence in 1990, petroleum prospecting and exploration gathered new momentum and, in 1993, shell exploration and Production Namibia (shell) and energy Africa were awarded a licence to explore and exploit the Kudu gasfield (Tullow oil & NamCor, 2006). Four years later, in 1997, it was announced that a joint venture (comprising NamPower, eskom and shell) would build a 750 MW combined-cycle gas turbine plant at oranjemund, which was expected to cost N$4 billion (approximately Us$620 million) and run on gas from the Kudu field.14 The size of the proposed plant, more than twice the country’s maximum demand at the time,15 meant that at completion in 2002, Namibia would finally be self-sufficient in electricity supply and would become a significant exporter of electricity to the region. in addition, it was envisaged that in the second phase of the project, gas would be supplied by means of pipelines to a 1 000 MW power plant to be built in south Africa’s Western Cape province.16

however, after the completion of further feasibility studies in 1998, eskom began to express disquiet about the high cost of electricity from the proposed power station, and early in 1999, eskom announced that it was withdrawing from the joint venture.17 This threw the project into disarray, since a significant regional off-taker was a prerequisite for the commercial viability of the power plant. Frantic efforts were made to bring eskom back on board, and overtures were made to other potential regional customers, but to no avail. in 2002, the project suffered yet another setback when shell opted to relinquish its rights in the Kudu gasfield to its partners ChevronTexaco and energy Africa.18 shell’s main reason for withdrawing from the project was that the discovery that actual gas reserves amounted to just 1.3 trillion cubic feet – substantially lower than the estimated five trillion cubic feet, and


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the amount that shell needed to justify its gas-export strategy and the building of a liquefied natural-gas plant.19

Following further feasibility studies on the gasfield, energy Africa announced in 2003 that the project showed ‘considerable potential’ for an 800 MW gas-fired power plant, with reserves sufficient for a 20-year operation.20 despite this optimism, ChevroTexaco withdrew from the concession in late 2003, ceding its rights to energy Africa, and soon thereafter the government, through the state-owned Namibia Petroleum Corporation (NamCor), acquired a 10 per cent stake in the concession.21 The following year another significant change in the rights to the concession occurred when, through an acquisition, energy Africa became a wholly owned subsidiary of Tullow oil, a London stock exchange-listed company with interests in recent oil discoveries in Uganda and Ghana (Tullow oil & NamCor, 2006). Also in 2004, eskom returned to the fold and signed a memorandum of understanding with NamPower committing itself to negotiating a power-purchase agreement with NamPower as well as other agreements related to the operations and maintenance of the proposed power plant. At the same time, energy Africa, NamCor and NamPower entered into a joint development agreement, and it was expected that the power plant would be operational by the end of 2009.22 by 2007, negotiations for the power-purchase agreement between NamPower and eskom were ongoing. however, the negotiations for the gas-supply agreement between NamPower and the-concessionaires led by energy Africa became an obstacle to progress. energy Africa proposed that the gas be paid for in Us dollars at ruling international prices, whereas NamPower viewed the currency risk that this presented as too great for it to carry, and refused to allow domestic electricity prices to be subject to exchange-rate fluctuations. instead, NamPower proposed that the gas-supply agreement be in Namibia’s local currency and subject to a project-specific pricing mechanism.23

in 2007, a new developer appeared on the scene when energy Africa sold a 20 per cent stake in the Kudu concession to the Japanese firm, itochu.24 Although this generated renewed hope in the scheme, the project suffered another setback when energy Africa announced that the sinking of a new well in search of further reserves had not yielded positive results.25 by this time, NamPower had begun to publicly express its frustration with the project (and particularly with the negotiations around the gas-supply agreement). NamPower’s managing director, Paulinus shilamba, stated that ‘the Kudu power project is marginal and not a commercially viable stand-alone project, as it is characterised by a high Us-dollar-denominated gas price – meaning that the foreign exchange hedging cost will translate into high electricity tariffs’.26 The utility thus began to actively pursue other generation-capacity and import options.

by 2009, with currency risk still a stumbling block in the negotiations, Namibia’s energy minister, erkki Nghimtina, announced that the Kudu plant was unlikely to be commissioned until 2013. Then russian energy giant, Gazprom, expressed an interest in the project, and in 2010, Gazprom acquired a 54 per cent stake in the Kudu concession.27 At the time of writing, the estimated project cost had escalated to over Us$1 billion, and neither the upstream gas-supply agreement nor the power-


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purchase agreement between NamPower and eskom had been concluded. When Gazprom had acquired its stake in the Kudu concession, it had indicated that this did not guarantee its future support for the project, and that an investment decision on the project would be made before the end of 2011.28 Following the conclusion of its appraisal, Gazprom ‘silently’ withdrew from the project in 2011, making the realisation of Kudu gas uncertain once again.29 in response, the government in 2012 undertook to issue NamPower and NamCor with government guarantees in order to mitigate the risk that the two state entities presented as off-takers of electricity and gas respectively to potential upstream investors in the project.30 At the time of writing, it was unclear whether any such investors were forthcoming, but what was certain was that the project had yet again been delayed.

Namibia’s energy policyThe 1998 White Paper on energy Policy signalled Namibia’s first attempt at a formal co-ordinated policy for the energy sector. relevant to the energy sector as a whole, the goals of the policy were to: • institute effective governance systems (policy, legislative and regulatory frameworks); • secure the supply of energy through diversity, competitive and reliable supply,

and indigenous sources; • provide affordable energy to households and communities; • contribute to the country’s economic competitiveness; and • ensure the sustainable use of natural resources (Government of Namibia, 1998).specifically for the electricity sector, the policy acknowledged that the industry faced challenges in improving efficiency and security of supply, as well as access to the grid, especially in rural areas. The policy noted that the sector had not yet taken its place as a key driver of investment and economic growth, nor had it achieved its potential in terms of environmental and socio-economic sustainability, alleviating primary energy-resource constraints; or developing an efficient and appropriate governance framework and structure.

To address these challenges, the White Paper made 12 policy pronouncements:• options to improve sector efficiency through restructuring the electricity-supply

industry would be investigated.• An institutional system with both regulatory and policy-making functions would

be introduced to monitor and regulate electricity prices.• electricity-tariff structures would be based on sound economic principles, generally

and as a whole, reflecting the long-run marginal cost of electricity supply.• Licences for the distribution of electricity in urban areas would include provisions

for electrification and a fair tariff structure that facilitates increased access among low-income consumers.

• The rural-electrification programme would be based on transparent planning and evaluation criteria for new projects.

• electricity supply in Namibia would be based on a balance of economically efficient and sustainable electricity sources including gas, hydropower other renewable-energy sources and imported electricity.


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• dialogue with private investors and financiers would be promoted, with a view to facilitating economically viable and competitive investments in the electricity sector, while ensuring that the necessary legal, regulatory, fiscal and environmental frameworks were established to create a favourable investment climate.

• Through co-ordination between the government, the electricity-supply industry, the private sector and education institutions, a sufficiently skilled human resource base to sustain the sector would be created.

• economic empowerment would be promoted.• A modern, legal and regulatory framework for the sector would be implemented

through the creation and resourcing of a competent institution to regulate the sector’s operations.

• Government’s relationship with state-owned companies in the sector would be formalised through performance contracts.

• Adequate protection of licensees and end users of electricity would be provided through the regulatory institution (Government of Namibia, 1998).

Industry restructuringA year before the White Paper was published, the Ministry of Mines and energy had been instructed to commission a study on the restructuring of the electricity industry. The White Paper added new impetus to this project, and the study was undertaken by consulting firm, sAd-eLeC and concluded in 2000. The study proposed the following key objectives for the industry:• to source power supplies in the most cost-effective manner, including the

optimum use of local generating assets;• to ensure a reliable supply of power that promotes economic growth and

development; and• to increase the diversity of supply and promote the use of local energy resources

(sAd-eLeC, 2000).Prominent among the objectives of restructuring was to attract iPPs into the sector. in this respect, the proposed new structure made provision for iPPs to supply the Namibian power market through a single buyer, and to enter into contracts directly with third parties for exports (see Figure 5.5). To create ‘a level playing field’, sAd-eLeC proposed that NamPower’s generation, transmission and (at the time) distribution functions be ring-fenced as separate business units. The industry regulator would monitor bulk-sale agreements to ensure that the utility, as single buyer, was not favouring its own generation over that of iPPs. The new structure also called for a fundamental transformation of the country’s electricity distribution industry. The White Paper had recognised that with 46 publicly owned electricity-distribution entities (local authorities) in the country, efficiency gains were likely if some consolidation and rationalisation took place. in fact, the distribution of electricity had long been plagued by a lack of ‘resources and capacity to deliver and extend acceptable levels of service’ (Clark et al, 2005: 17). sAd-eLeC therefore proposed that a gradual transition to regional electricity distributors (reds) take place, with an emphasis on financial viability and the need to expand electrification


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in rural areas. Furthermore, as noted, many local authorities were using revenues from the distribution of electricity to underwrite the provision of other municipal services, and it recommended that this be taken into consideration during the restructuring process. initially, it was recommended that Nored and erongo red be established, with reds in other parts of the country to follow later.

The Namibian government accepted sAd-eLeC’s proposals and, in 2001, NamPower reported that it had ring-fenced all its business units, and that all of the company’s distribution assets would be held by a newly formed subsidiary, Premier electric.31 The process of creating reds began with the establishment of Nored in 2002.32 This was followed by CeNored to serve the area around the town of otjiwarongo, which became operational in 2005, and erongo red, also in 2005 (eCb, 2005). by 2010, the formation of two reds remained outstanding, including the Central red that was expected to serve NamPower’s largest customer, the City of Windhoek. The City of Windhoek has, however, long questioned the viability of reds, arguing that, being profit driven, they will raise electricity costs for consumers.33 The last outstanding red, southern red, was expected to cover the southern part of the country.

Figure 5.5 Single-buyer model for Namibia recommended in the SAD-ELEC study, 2000

Erongo RED

Northern RED

Other REDs

Other distributors

SAPP imports

Kunene river IPP

Kudu gas IPP

NamPower generation

Large users

Customers Customers Customers Customers

SINGLE BUYER

source: sAd-eLeC (2000: 6)

Enabling legislation

To create the legislation that would facilitate the restructuring process, the government repealed the 1922 electric Power Proclamation and passed the electricity Act of 2000. Central to the new legislation was the establishment of the


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independent regulator, the eCb. The electricity Act also laid out the first licensing regime for electricity-industry operators. No sooner had the Act been passed, however, than its deficiencies were identified. Firstly, the Act made no provision for the promulgation of technical codes (such as the grid code), market rules, pricing and other mechanisms that protect private investment. secondly, it did not facilitate the transfer of assets from municipalities to the reds that were being formed. Thirdly, the eCb was not given full regulatory authority over distribution; instead, this was shared with the Ministry of regional and Local Government and housing. This meant, for example, that because tariffs were included as part of municipal budgets, the Minister of regional and Local Government and housing had the power to approve or veto tariff increases. Fourthly, the Act made no provision for the crucial role that electricity revenues played in the provision of other municipal services, which would suffer if this income were lost in the restructuring process.

it was deemed prudent that the Act should be flexible enough to allow for the regulation of an evolving market structure, and there were areas around tariff setting and quality of supply that required revisiting in order to make regulation effective (scholz, 2006). A process to repeal the law was initiated and eventually led to the new electricity Act being passed in 2007. The details of the new Act that pertain to the eCb are discussed later in this chapter.

Regulatory governanceWe now turn to examining the role that Namibia’s electricity regulatory system has played in the sector since it was established. The electricity Act of 2007 established the independent regulator, the eCb, and provides for its powers and functions, as well as for the requirements and conditions related to obtaining a licence to provide electricity, and for the powers and obligations of licensees.

The law is clearly set out and is unambiguous in its allocation of powers and responsibilities to the various actors in the electricity industry. Crucially, the eCb has the requisite powers for the determination of tariffs, but not for licensing or for the establishment of rules and codes for the power sector. Clause 3(2) of the electricity Act states that:

in order to achieve its objects the board –a) must make recommendations to the Minister [emphasis added] with regard to –

i. the issue, transfer, amendment, renewal, suspension and cancellation of licences; and

ii. the approval of the conditions on which electricity may be provided by a licensee.

Futhermore, Clause 3(4) states that:subject to this Act and the prior approval of the Minister [emphasis added], the board may by notice in the Gazette make such rules and codes as it considers necessary in order to further its objects mentioned in subsection (1), including, rules and codes relating to –


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a) the establishment, operation and administration of electricity markets, and the licensees and other persons operating on such markets and any other matter relating thereto, which includes the issuing of safety code and a grid code, the latter setting out the reciprocal obligations of users of the transmission and distribution networks and the operation of the interconnected power system;

b) the introduction of market rules, the board’s market responsibilities, prudential requirements, the establishment and regulation of spot markets, regions and regional reference nodes, network losses and constraints, projected assessment of system adequacy, central dispatch and spot market operation, spot price determination, ancillary services, reliability safety net, market information, administrative price cap and market suspension, settlements, participant compensation fund, software and settlement residue actions, registered bid and offer data, methods for determining loss factors and principles for determining credit limits;

c) power system security and safety;d) network connections;e) network and market pricing mechanisms;f) metering;g) good corporate governance and rules relating to objectivity, transparency and

independency;h) administrative matters;i) any other matter it is authorized in terms of this Act to make rules or codes

about; andj) any matter with regard to which the Minister may prescribe regulations under

this Act subject thereto that in the event of any regulation so prescribed conflicting with a rule or code of the board the regulation prevails.

Through these clauses, the energy minister retains a significant proportion of the final decision-making authority that ordinarily rests with a regulator. This is at variance with the essence of the independent-regulator model, which seeks to devolve licensing decisions away from the political realm. however, the eCb does not see this arrangement as problematic, contending that, in the Namibian context, there is need for political backing in order to effectively regulate the large NamPower, and that these provisions in the Act allow for this.34

Another issue that requires political backing is the formation of the reds (given the potential for their creation to adversely impact on the revenues of local authorities). According to the eCb, the political environment with respect to the issue of the reds was ‘charged’ at the time that the electricity Act was being drafted and, in that context, it would have been ill advised to seek further independence for the regulator. eCb representatives indicated that once the restructuring of the industry had been concluded and reasonable levels of competition had been achieved, the eCb might seek to increase its level of independence.35

Board independence

Legislation relating to regulators should foster an environment that allows for independent thought within the institution and prevent interference from stakeholders,


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including the government. one way of achieving this is to make the appointment of board members transparent and to provide clear grounds on which appointments may be terminated. As in all the countries discussed in this volume (with the exception of Tanzania), the process used by the Namibian government to nominate and vet potential board members is masked in secrecy. The electricity Act does, however clarify the grounds for board members to be removed from office. These are consistent with similar legislation elsewhere, and include resignation, repeated absence from board meetings without permission, physical or mental incapacitation and death.

The eCb’s board consists of five part-time members, appointed by the energy minister for four-year terms, renewable without limit. The minister also appoints both the chairperson and the vice-chairperson. The electricity Act identifies the fields in which board members should have appropriate expertise and experience, namely, the electricity industry, law, economics or the environment. in making appointments to the board, the minister is required to pay due regard to section 15 of the state-owned enterprises Governance Act. This Act provides for a centralised vetting process for all appointments to boards in the public sector, through the state-owned enterprises Governing Council (soeGC), which is chaired by Namibia’s prime minister.

in an environment that seeks to attract significant capital for the purposes of system expansion, the consistency of regulatory decision making is crucial in creating a predictable climate for investment, and helps to augment the credibility and legitimacy of the regulator. one practical means of promoting consistency is through the staggering of board appointments. This helps to ensure continuity and the preservation of institutional memory. While the electricity Act is not explicit in this regard, eCb appointments have so far been staggered informally.

With the raft of responsibilities placed upon them, such as licensing, determining tariffs, promulgating rules and codes, adjudicating disputes, not to mention their administrative and corporate governance duties, the boards of regulatory institutions tend to meet more frequently than those of typical corporate organisations. however, the eCb board does not meet as often as one might expect, and the reason given was that the board is made up of ‘very busy’ individuals.36 While it is to be expected that the board is made up of individuals whose stature places significant demands on their time, a balance should be sought to ensure that crucial regulatory decisions are not delayed, and that all members of the board remain fully abreast of decisions that have been taken and with any matters pending. board members must also be remunerated at a level that is consistent with national norms and with the effort that is required of them.

Financial and administrative independence

The eCb prepares its own budget. While the Act does not require its budget to be approved by the energy minister, the eCb has maintained this practice for reasons of accountability and transparency.37

The Act provides for the eCb’s operations to be funded by:• levies imposed on the provision or consumption of electricity;


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• fees payable to the board in terms of the Act;• loans raised with the approval of the energy minister and the concurrence of the

finance minister;• donations or grants made to the board with the approval of the energy minister

and concurrence of the finance minister;• interest from investments;• appropriations to the board that may be made by Parliament from time to time;

and• funds accruing to the board from any other source.

of the above, the electricity levy tends to be the main source of income, accounting for over 90 per cent of total budgeted income between 2006 and 2009 (see Table 5.2). The levy is determined by the eCb and approved by the energy minister in accordance with the electricity Act. in 2010, a levy of approximately 0.1 Usc/kWh was applied to all electricity sales in Namibia. Given the structure of Namibia’s electricity industry, the most convenient way to apply the levy is on sales to NamPower’s single buyer. Arguably, the eCb’s reliance on this single source of income presents a potential risk, but NamPower’s superior creditworthiness minimises the risk to some extent.

Table 5.2 ECB’s budgeted income, Namibia, 2006–2009Income 2006 2007 2008 2009Total income (Us$) 1 536 717.18 1 839 264.89 2 028 739.72 2 314 535.41Levy income (Us$) 1 486 730.33 1 805 218.23 1 984 530.22 2 173 051.99 Levy as % of total income 96.75 98.15 97.82 93.89

source: eCb, personal communication (2009)

Staffing

The eCb board has the authority to appoint a Ceo and to determine the organisational structure of the eCb. in 2010, eCb’s staff complement stood at a lean 20 employees, and external consultants were extensively relied upon for ad hoc assignments. Although the eCb’s terms and conditions of service are competitive and staff turnover has been low, the eCb has lost some key personnel since its establishment, including the general managers for finance and administration, economic regulation and general regulation, a manager of corporate communication and legal services and a financial analyst. These losses reflect the challenge that regulators face globally in retaining competent staff.

Accountability

The eCb is indirectly accountable to parliament through the Minister of Mines and energy. As in Kenya, appearing before parliament is not usual for such organisations, and as of 2010, the eCb had never been asked to appear before any committee of parliament either to present its annual report or to articulate its position on matters relevant to the electricity industry. There is, however, a mandatory requirement for the annual report, containing audited financial statements compiled by a private


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firm on behalf of the auditor-general, to be submitted to parliament via the energy minister’s office. The eCb has also made numerous representations to Cabinet,38 and the Ceo maintains regular informal contact with both the minister and the permanent secretary of the Ministry of Mines and energy. beyond the annual report, no independent assessments of the eCb’s performance or regulatory impact had been carried out by 2010. Periodic assessments are recommended, as they highlight areas where the regulatory process can be enhanced and can reassure stakeholders that the regulatory body is indeed adding value to the industry.

Code of ethics

The eCb has an in-house Corporate Governance handbook,39 which contains the institution’s code of ethics, to which board and staff members must subscribe. The code allows for the acceptance of small personal gifts from external parties ‘where refusal might offend’. With respect to employees that terminate their employment with the eCb, there is no ‘cooling off ’ provision to prevent their recruitment by any of the regulated entities, and eCb management was of the opinion that were such a provision to be introduced, it would have to be linked to appropriate compensation for potential loss of income.40

Appeals

if a party to an eCb decision is aggrieved, the electricity Act permits such a party to approach the courts of law for judicial review. in this instance, the court would rule only on whether the decision was made in a way that was valid or invalid in terms of the principles of administrative justice. The court would not consider the facts of the case and try to arrive at its own interpretation, as might be the case in a criminal matter, for example. in the event that a judicial review finds the eCb to have made a decision ultra vires, the court can rule that the eCb reconsider the matter in a manner that is consistent with the law.

in addition to the provisions provided for under the electricity Act, the eCb is seeking to develop a complaints procedure whereby an aggrieved party would be able to submit a complaint to the eCb, and this would then be investigated. if this is approved, aggrieved parties would retain the right to approach the courts for judicial review, but the complaints procedure would provide an alternative means for parties to resolve disputes with the regulator.

Transparency

Namibian common law and existing statutory provisions require a degree of transparency and stakeholder consultation in the eCb’s activities. over and above these requirements, the eCb posts notices of its regulatory meetings on its website (http://www.ecb.org.na) and on the public notice board at its offices. The public are free to attend board meetings, although, by 2010, attendance had generally been poor.41 Apart from notifications about upcoming meetings, the eCb’s website


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includes minutes of board meetings, links to relevant legislation, information on the licensing process, approved tariffs and technical standards, as well as various application forms and a host of other miscellaneous documents and studies.

The eCb also allows licence applications to be viewed by third parties on request. although in such instances, ‘sensitive commercial information’ is removed.42 The electricity Act requires that public hearings be held in the event of objections to a licence application, or when regulatory action would lead to expropriation. remarkably, this requirement does not extend to tariff determinations. While in theory the eCb could conduct such hearings within its existing mandate and authority, procedures that would enable this to occur had still not been developed by 2010.

The stakeholders that were consulted reported that, in general, they find the eCb accessible, and that they are satisfied with the ways in which they are able to interact with the regulator.43

Regulatory substanceAs noted in other chapters, the key regulatory functions are to facilitate market access through licensing, to determine tariffs that are competitive and ensure the viability of industry, and to set and monitor technical standards. other key functions are to take the interests of low-income consumers into account and to adjudicate disputes among industry participants. in this section, we examine how the eCb undertakes each of these functions.

Licensing

The electricity Act requires that the generation, trading, transmission, supply, distribution, and import or export of electricity be carried out only by parties in possession of a licence issued by the eCb, but the Act provides exemption for parties with installations of less than 500 kVA.

The eCb’s licensing process is outlined in Figure 5.6. At the time of lodging an application, potential licensees are required to advertise their applications in the local media in order to allow potentially aggrieved parties a chance to air their concerns. Following a 30-day objection period, any objections are reviewed by the eCb and a determination is made on their reasonableness or otherwise. reasonable objections are subjected to further scrutiny and could lead to a public hearing on the matter. While regulators should not encourage frivolous or vexatious objections, the eCb should make clear the basis on which the reasonableness of an objection to an application is determined.

in addition, Clause 21(2) requires that the following are taken into consideration when evaluating a licence application:• Possible adverse effects on the environment and the rights and operations of others;• The applicant’s technical viability and competence;• The adequacy of the applicant’s financial resources;


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• The applicant’s ability to provide an effective level of service to customers; and• Public-interest considerations.

Figure 5.6 Outline of the ECB’s licensing process, Namibia, 2010

Receipt of application

Recorded in register

ECB issues licence

Notify applicant to ensure compliance

Formal evaluation commences

Submission by board to minister

Minister informs applicant

Conduct public hearing (optional)

Amendment by secretariat

Approval of application by

minister?

Approval of secretariat

recommendations by board?

Reasonable objections after 30-day

advert?

Does application meet

requirements?

source: eCb, personal communication (2009)

The eCb then makes a recommendation to the energy minister on the licence application, based on the technical and financial evaluation carried out, and taking into account objections that may have been received, including the outcome of any related public hearings. if ministerial approval is given, the eCb issues a licence containing conditions that detail the obligations and requirements of the licensee. if approval is withheld, the minister informs the applicant that the application has been unsuccessful. The electricity Act also clearly outlines the criteria for the awarding or amending, cancellation or revocation of a licence.

in areas where the formation of reds is pending, the eCb has decided to issue distribution licences of particularly short duration, such as one year, in an effort to pressurise the remaining distributors to form an red. however, licences of short duration are likely to disincentivise capital investment and may lead to inadequate maintenance and refurbishment of distribution equipment. The eCb contends that most distributors had never implemented good maintenance routines in any case.44 At the time of writing, the future of reds was still uncertain, with some reports questioning


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their operational sustainability. For example, in 2010, it was reported that the southern red, which had yet to commence operations, would be liquidated.45 in the same year, the Walvis bay municipality announced that it would relinquish its 50 per cent interest in erongo red;46 at the company’s annual general meeting in 2011, a motion to liquidate the company was tabled, leading to the postponement of the meeting.47

Licensing new generation capacity

As noted earlier, the generation-capacity crisis experienced in southern Africa since 2005, coupled with Namibia’s dependence on electricity imports, has made the development of indigenous generation capacity a key priority for the industry. To facilitate this, the eCb published guidelines for the licensing of iPP projects.48 The eCb has the authority to approve all power-purchase agreements entered into by electricity industry participants, but, as of 2010, there was not a single iPP in Namibia. A significant reason for this was the difficulty that potential developers experienced in securing off-take (power-purchase) agreements with NamPower. The lack of clarity about the responsibility for planning and allocation of new build opportunities between the public (NamPower) and the private was arguably an additional factor.

Proposals received for the development of iPP projects in Namibia have mostly been unsolicited, but there are no specific processes within the energy ministry or the eCb for dealing with power procurement in this manner.49 in an environment where the authorities are keen to expedite the development of new generation capacity, it would be understandable if such proposals, which essentially do away with a lengthy bid process, were to be well received. The potential perils of such bids have been highlighted in previous chapters, however, and, as shown, the international competitive-bidding process is more likely to deliver cost and technological effectiveness, and hence a greater likelihood of favourable long-term outcomes related to tariffs, quality and reliability. in the event that accepting an unsolicited bid becomes unavoidable, a procurement process that mirrors the competitive outcome as closely as possible should be developed.

Licensing imports, exports and third-party access

As of 2010, NamPower was the only organisation in Namibia involved in importing and exporting electricity. Although the 2007 electricity Act requires that this trading function be licensed separately, this had yet to be done. NamPower had been allowed to trade in this way on account of the provisions of its existing transmission and supply licence. The eCb plans to issue a trading licence only once the formal trading rules have been developed and accepted by all concerned parties.50 NamPower does not fully disclose the terms of its electricity-import agreements with its foreign partners, arguing that parts of these agreements are confidential and could have an adverse impact on its operations if disclosed to third parties.51 This situation is unusual and unacceptable, as it could well distort both the determination of consumer tariffs in Namibia and NamPower’s own revenue requirement.


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The electricity Act permits third-party access to the transmission network and hence allows potential choice for bulk consumers. in practice, this provision has not been utilised, with the exception of a mining operation in the south of the country that sourced electricity from south Africa. in an attempt to make bulk consumers aware of this provision in the legislation, the eCb has increased its awareness-raising activities and is encouraging potential iPPs to consider this possibility as they seek additional off-takers.52

Electricity tariffs and pricing

Tariff structures and electricity price determinations by the eCb are guided by the White Paper on energy Policy (Government of Namibia, 1998), which states that electricity tariffs in Namibia should:• be based on sound economic principles;• be cost reflective as far as possible;• reflect long-run marginal costs of supply; and• offer existing and potential electricity industry participants a level playing field.

Consistent with the restructuring of the electricity industry in Namibia in 2000, tariffs for generation transmission and distribution are determined separately.

Generation tariffs

Generation tariffs are determined using import-parity pricing, which prices locally generated electricity at the cost of imported electricity. The motivation for this is that a significant proportion of the country’s electricity needs are met through imports from neighbouring countries. This pricing method allows ruacana power station to accrue windfall profits on its relatively low-cost hydro generation. According to the eCb,53 NamPower could use these profits to subsidise the more expensive operations at the Van eck and Paratus power stations. however, during emergency periods, such as when the river flow at ruacana is low or when electricity imports are limited and the Van eck and Paratus power stations have to make up the shortfall, import-parity pricing is suspended, and actual generation costs are taken into account in such emergency-pricing measures. The Van eck and Paratus plants have significantly higher running costs, which are exacerbated when the prices of coal or diesel are high on international commodity markets. When emergency pricing is in force, under- or over-recoveries can occur due to fluctuations in coal or diesel prices; these costs are thus discounted or allowed in the cost build-up for the ensuing tariff-review period.

in future, the eCb expects to move away from import-parity pricing and instead adopt a cost-plus/revenue-requirement regime that will closely resemble what has been termed ‘emergency pricing’ above. With adequate cost oversight and scrutiny by the eCb, such a regime would be better placed to achieve more equitable generation tariffs, particularly if iPPs form part of the country’s generation mix in the future.


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Transmission and distribution tariffs

The eCb uses the widely applied revenue-requirement or cost-plus methodology to determine both transmission and distribution tariffs.54 This should allow for full cost recovery, but at the time of writing, this had not been achieved, and cost-reflective tariffs were being phased in. The government had taken a decision that bulk tariffs would reach full cost recovery by 2010 or 2011.55 For transmission, and following a 2005 review of the methodology, the eCb intended to continue with the cost-plus approach but move from the postage-stamp method to a load-flow one in its derivation of transmission charges for generators. such a move is likely to coincide with similar changes in the pricing regime used by the southern African Power Pool.56

All transmission and distribution utilities in Namibia are required to publish connection-charge policies as approved by the eCb. To streamline the manner in which these charges are arrived at, the eCb provides guidance on the features that are expected to be common in these policies across all distributors, namely, that:57 • the shallow connection-charge approach should be adopted;• the insurance, operations and maintenance costs of dedicated connection assets

should be included in the standard tariff; and• there should be no additional charges in the event of premature replacement of

connection assets.

Cost containment

The revenue-requirement methodology provides few incentives for regulated utilities to improve their efficiency. in order to limit this, the eCb in its scrutiny of operating expenditure makes comparisons with the previous year while giving maintenance expenditure a generally favourable view. in addition, for the distribution sector, non-technical losses are capped at a stringent 1.25 per cent of revenue requirements or at the level of the previous year (whichever was less) in order to incentivise commercial performance. Furthermore, technical losses are capped at 10 to 15 per cent, depending on distributor type and location. The other electricity sectors covered in this volume could benefit from stringent incentives such as these.

Asset valuation and tariffs

Asset values are a crucial component of the revenue-requirement methodology. For transmission and distribution, the eCb has an impressive process in place. in both cases, the current replacement value recalculated every five years is used in the determination (as opposed to the historical cost). Given the likelihood of significant new investments in Namibia’s electricity industry, this method of asset valuation has the potential of limiting the impact of electricity-tariff increases as new capital is invested.

Tariffs are renewed on an annual basis, and consequently the regulatory asset base for transmission and distribution requires annual updating and revaluing. A highly effective customised software tool, known as the Namibia electricity Network Assets register (NeNA), has streamlined and aided reds and local authority distributors in the


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updating and revaluing of all distribution assets. straight-line depreciation is employed in the asset valuations for both transmission and distribution. electrification assets provided through grants from donors or the government are not permitted to earn a rate of return but are expensed for depreciation (as is consistent with best practice).

Multiplicity of retail tariffs

The eCb approves the tariffs of 32 distribution companies that all have differing tariff structures. While the eCb contends that this is necessary on account of volatile fuel prices and increasing generation prices as the reserve margin in the region diminishes, it places intense pressure on the eCb and is unlikely to be sustainable in the longer term. At the time of writing, the eCb had proposed that the following tariff structure be adopted by all distribution companies:• a basic charge;• an energy charge;• a capacity charge (for small customers); and• a demand charge (for large customers).

if adopted, this would also limit the extent of cross-subsidisation across and within different customer groupings.

Local-authority surcharges

Local authorities in Namibia are entitled to tax electricity-service provision through the application of a local-authority surcharge, the proceeds from which are used to contribute to the overall budget requirements for local-government service provision. As this tax is discretionary, it varies widely across the country from less than 1 Usc/kWh to more than 6 Usc/kWh.58 This charge clouds the profitability or otherwise of local-authority distributors, making it difficult to regulate them effectively. Given its significance in the revenue stream of local authorities, this surcharge is regarded as a very political issue; it is the most important impediment to the establishment of additional reds.

Resource planning and technical standards

Little new generation capacity has been developed in southern Africa over the past 20 years, and demand growth has depleted any excess generation capacity that existed before 1990. The resulting shortfalls have led to load shedding in south Africa and Zambia, Namibia’s most important electricity trading partners. Given that load shedding creates a drag on economic activity, and that the absence of adequate generation capacity can be attributed to a failure of planning, or of co-ordination between planning and procurement, it is crucial that these matters are addressed in a nationally integrated resource plan for Namibia.

exactly where the responsibility lies for the development of such a plan is not entirely clear though. For example, in 2008, NamPower was in the process of developing a plan, but the eCb did not recognise it as a nationally integrated plan and referred to it as


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merely a ‘NamPower system expansion plan’.59 At the same time, the eCb itself was in the process of commissioning a development plan. in our view, the energy ministry should consider allocating clear responsibility for the development of such a plan. both the eCb and NamPower could play more co-ordinated roles in such a process, and the regulator could oversee a committee of stakeholders that undertakes the task.

As a bare minimum, the plan should be based on a generation resource adequacy standard that includes measures such as the loss-of-load expectation60 (from which the appropriate reserve margin for Namibia could be determined), and an assessment of electricity imports compared with local generation (including the reliability benefits of interconnectors to neighbouring countries). such clear and transparent indicators would afford the regulator and policy-makers alike with a credible tool with which to monitor the status of national electricity-supply security, and to provide timely signals for the need to develop new capacity (in generation, transmission and interconnections), thus limiting power constraints and shortfalls.

Technical standards

In 2004, the ECB published its Quality-of-Supply Standard and Quality-of-service standard (adapted from the south African Nrs048 and Nrs047 standards respectively).61 The quality-of-supply standard specifies the range within which various technical parameters should lie for the supply of electricity in Namibia (across various voltage categories and to varying consumer groups) to ensure system quality and reliability. The quality-of-service standard defines the service categories provided to consumers by licensees, and the minimum standards that should be adhered to in their provision. The publishing of these standards was aimed at providing an objective means against which the erb could consider licence applications, monitor the performance of licensees and assess consumer complaints.

The standards have yet to be fully applied in the Namibian electricity industry. For the quality-of-supply standard, some of the data-acquisition requirements are onerous and require investment in instrumentation equipment and relevant skills. The eCb outsourced the process of data collection to the three reds and the City of Windhoek for a period of two years from 2007 while NamPower embarked on a similar process internally. This process was expected to lead to the existing electricity quality level’s being identified prior to the eCb’s issuing any sanctions for non-compliance. For the quality-of-service standard, there is great scope for a general improvement in the reporting, monitoring and resolution of consumer complaints, and in 2008 the eCb hired additional personnel for this purpose.

some of the measures in the standards have been included as key performance indicators in the Financial and Technical Performance Management and Monitoring Framework for Namibia (eCb, 2007). The eCb intends to use this framework to ensure that its ongoing regulatory objectives in the sector are met in accordance with the goals of efficiency, security of supply, investment (including growth) and sustainability, as set out in the 1998 White Paper on energy Policy. by 2010, it was


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not yet possible to gauge the likely impact of the monitoring framework, as data collected in 2009 were still being analysed to establish trends.

Grid code

The eCb has initiated a process of developing a grid code for the Namibian electricity industry. The grid code will specify the technical requirements for connection to the electricity grid by third parties such as iPPs and independent distribution entities. While a draft document was concluded as early as 2005, the code had not been published by late 2010. The delay was attributed to stakeholder consultations that were ongoing, and included discussions on the structure that Namibia’s electricity supply industry would finally take, whether it would incorporate reds, and whether NamPower would have a formal single-buyer role.

Initiatives for low-income consumers

The government’s central treasury disburses annual grants to the various electricity distributors for electrification purposes. The grants are made in accordance with the government’s rural electrification master plan (which includes connection targets) and are linked to the rural-development initiatives identified in the government’s Third National development Plan (Government of Namibia, 2008). however, these grants have so far been insufficient to reach the targets set. NamPower has also provided a separate subsidy for rural electrification, but surprisingly this is not being recovered in NamPower’s approved tariffs. The eCb stated that ‘NamPower absorbs any cost mismatches within itself ’,62 but the long-term sustainability of such an arrangement is clearly questionable.

Pro-poor tariffs

Namibia is the only country in this volume where the tariff structure makes no allowance for low-income consumers. This is surprising in a country where poverty continues to present a serious challenge. At the time of writing, the eCb was awaiting the results of a study that the regional electricity regulatory Association of southern Africa was undertaking on pro-poor tariff schemes across the region. existing retail tariffs were structured in such a manner that, within reds, urban areas subsidise rural areas, and in general, industry subsidises residential areas. These measures do provide some relief for the poor, albeit limited and not targeted exclusively at low-income households.

Demand-side management

in 2006, the eCb identified the following six demand-side management options for Namibia:63

• Launching a consumer awareness and education campaign;• introducing time-of-use electricity tariffs;• distributing compact fluorescent light bulbs;• encouraging the replacement of electric water heaters with solar water heaters;


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• expanding ripple-control systems that are able to centrally disconnect electric water heaters; and

• Conducting energy audits in the commercial and industrial sectors.

Consequently, NamPower began distributing compact fluorescent light bulbs (CFLs) in 2007. These were free to consumers and cost NamPower approximately Us$2 million. NamPower estimated that this initiative reduced peak demand by between 12 and 20 MW.64 While the benefits of using CFLs are unquestionable, particularly at a time of tight reserve margins, the sustainability of the programme is not guaranteed, as the costs were not recovered through tariffs.

in 2008, time-of-use tariffs were launched in Namibia for large consumers of electricity. Under this regime, the electricity tariff varies with the day of the week and time of day, reflecting variations in the demand for electricity and applying the highest charges during peak periods. This initiative was launched as part of a series of demand-side management measures that were aimed at countering the effect of reduced imports from south Africa that eskom had threatened due to security of supply difficulties in south Africa.

some ripple-control capacity, whereby water heaters (geysers) can remotely be switched on and off, has also been established in Namibia, and its expansion could provide an additional effective means of demand-side management.

Renewable energy

While the use of renewable-energy technologies was actively being pursued for various purposes, including rural electrification, as of 2010, there were no explicit targets for renewable-energy use. The eCb is not keen to develop feed-in tariffs for renewable-energy technologies, as these are not considered to be economically efficient. A bidding or auction process, whereby a target for renewable-energy capacity is set and competing offers assessed based on cost and/or technology, seems to be the eCb’s preferred option for renewable energy.65

ConclusionThe Namibian case presents a dichotomy between the possibilities and challenges of intra-regional trade in electricity. The fact that the country has relied on imports to satisfy electricity demand since its independence in 1990 shows the benefit of cross-border power-system interconnections. however, the protracted negotiations for the Kudu gas-to-power project also reveal the difficulties presented by a large natural-resource endowment, the commercial exploitation of which leads to output that is far in excess of what can be consumed domestically. Although, at the time of writing, it was unclear if or when financial close would be achieved on the Kudu project, the main concern of Namibia’s electricity sector in the short to medium term remains the looming power shortages due to reduced availability of imports and the failure to increase domestic generation capacity.


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The eCb could be more proactive in responding to the potential power shortages by (in collaboration with other stakeholders) leading the development of a national security-of-supply standard that would provide an objective means of determining system adequacy in the country. once such a standard is developed, it would be crucial for the eCb to allocate responsibility for its oversight and enforcement. As a neutral party, the eCb could also lead the process of developing a national power-system expansion plan and ensure that this is regularly updated. Granted, the eCb may not necessarily possess the required technical and other resources, but the Kenyan energy regulatory Commission is an example of how a regulator can play a leading role in such a process. Given Namibia’s dependency on electricity imports, greater regulatory oversight of the power-purchase agreements entered into with regional utilities is essential, along with full disclosure to the eCb on the part of NamPower (rather than pleading confidentiality). it is also important that the eCb develop a framework to manage unsolicited bids for new power-generation projects.

despite opening up its electricity sector to private-sector participation in 2000, there were no iPPs in operation in Namibia by 2012. it is interesting to note that of the countries covered in this volume, the two that have excelled at attracting iPPs, namely Kenya and Uganda, have off-takers that are independent of the electricity-generating function. While we are by no means advocating privatisation, it is however apparent measures that ensure more impartial purchasing, and dispatch decisions by the off-taker/single buyer may well encourage the entry of iPPs. options for achieving this could include unbundling, a separate licence for the system operator/single-buyer function with credible conditions attached, or a governance framework specific to this function.

As is the case for much of southern Africa, electricity prices will have to rise if NamPower and the other utilities are to earn an adequate rate of return on their operations, in order to ensure that necessary refurbishment and new investments can be undertaken. rising commodity prices and increases in the cost of electricity imports, primarily those from south Africa, are likely to place additional upward pressure on prices. No doubt the eCb will face public resistance in effecting such price revisions, and it will therefore be necessary to engage stakeholders in a sustained manner to ensure that they understand the underlying need for increases and how the prices are determined. As prices move to cost reflectivity, it will be equally important for the eCb to ensure prudence in calculating the utilities’ expenses, allowing only those costs that necessarily have to be passed on to consumers – the discretionary local-authority surcharges for example, serve only to further burden electricity consumers. Consideration should be given to funding local governments through more typical sources such as property rates and direct fiscal transfers so that discretionary surcharges can be removed from the retail-tariff derivations.

With such large disparity between urban and rural dwellers, the eCb could be more proactive about facilitating rural electrification. For example, connection targets with sanctions could be incorporated into distribution licences, and a light-handed regulatory framework for rural and off-grid electrification could be developed


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that includes a regime for competitive bidding for state-subsidised electrification projects. in addition, an assessment of the affordability of cross-subsidies between high-consuming and low-income domestic consumers should be made in order to test the sustainability of incorporating a lifeline tariff in the tariff structure.

in comparison with other countries in sub-saharan Africa, Namibia’s electricity sector has performed reasonably well. however, there is much to be done in ensuring security of supply and increasing access to electricity in rural areas. The eCb should play a meaningful role in overcoming these challenges.

Notes1 reds are asset-based companies that are responsible for distributing electricity to consumers

within a defined geographical area. reds are discussed in more detail later in the chapter.2 NamPower Financial statements, www.nampower.com.na3 NamPower Annual report, 2009, http://www.nampower.com.na/pages/annual_report_2009.asp4 NamPower Annual report, 2009, http://www.nampower.com.na/pages/annual_report_2009.asp5 Coal prices are from the NamPower Annual report, 2009, http://www.nampower.com.na/

pages/annual_report_2009.asp oil prices are from the iMF primary commodity prices, http://www.imf.org/external/np/res/

commod/faq/index.htm6 NamPower Annual reports, http://www.nampower.com.na/pages/7 see sibeene P, Namibia: Power deficit could stunt growth’ 13 december 2005, AllAfrica.com,

http://allafrica.com/stories/200512130460.html. The Fitch Group’s long-term credit ratings are assigned on an alphabetical basis from AAA to d. The rating ‘bbb’ refers to ‘Good credit quality…expectations of default risk are currently low (see http://www.fitchratings.com).

8 see http://www.nampower.com.na/docs/07_dir_report.pdf9 NamPower Annual report, http://www.nampower.com.na/pages/10 Personal communication (2008).11 This historical account of the development of NamPower is adapted from NamPower (2008).12 Paratus, meaning ‘always ready’ in Latin, was so named as it was built primarily to provide

peaking power.13 The south African Northern Cape did not become a separate province until 1994. in 1982, it

was still part of the Cape Province.14 Maletsky C, Kudu, epupa ‘twin projects’, The Namibian, 28 November 1997.

http://allafrica.com/stories/199711280063.html15 Maximum demand in 1997 was 321 MW (eCb, personal communication, 2008).16 Maletsky C, Kudu Power could put epupa out of business, The Namibian, 21 July 1998,

http://allafrica.com/stories/199807210043.html17 Moyo, delay could hit Kudu gas plant, The Namibian, 7 december 1998.

http://allafrica.com/stories/199812070022.html Kudu gas project ‘hangs in balance’, The Namibian, 13 January 1999,

http://allafrica.com/stories/199901130006.html


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18 When the licence was awarded in 1993, shares in the joint venture were held by shell (75 per cent) and energy Africa (25 per cent). in 1996, ChevronTexaco acquired 60 per cent of energy Africa’s interest in the gas (petroleum) field. The withdrawal of shell meant a re-allotment of interest to ChevronTexaco (60 per cent) and energy Africa (40 per cent).

19 see Marrs d, shell opts out of Kudu gas field, Business Day, 6 August 2002, http://allafrica.com/stories/200208060005.html

20 see Marrs d, ‘Namibia’s gas field exploration shows promise, Business Day, 27 May 2003, http://allafrica.com/stories/200305270548.html

21 see ellis h, ChevronTexaco pulls out of Kudu gas project, The Namibian, 3 december 2003, http://allafrica.com/stories/200312030304.html

22 see Tjaronda W, Kudu gas looks all set to go, New Era, 9 July 2004, http://allafrica.com/stories/200407090124.html

23 sibeene P, ‘Kudu Gas on-stream next year?’, New Era, 8 december 2006, http://allafrica.com/stories/200612080696.html

24 sibeene P, Japanese join Kudu Gas project, New Era, 28 June 2008, http://allafrica.com/stories/200706280627.html

25 Kaira C, Tullow finds no gas in Kudu’s second well, Namibia Economist, 21 september 2007, http://allafrica.com/stories/200709210643.html

26 Paulinus shilamba, NamPower Managing director, quoted in Maletsky C, NamPower puts Kudu Gas on backburner, The Namibian, 17 december 2007, http://allafrica.com/stories/200712170916.html

27 This transaction led to a new apportionment of interest in the concession between Gazprom (54 per cent), energy Africa (31 per cent) and itochu (15 per cent). see duddy J-M, Kudu Gas field closer to lift-off – Nghimtina, The Namibian, 12 June 2009, http://allafrica.com/stories/200906150826.html

Maletsky C & J-M duddy, russia joins oil hunt, The Namibian, 26 June 2009, http://allafrica.com/stories/200906260682.html

duddy J-M, Tullow oil loses control of Kudu, The Namibian, 11 March 2010, http://allafrica.com/stories/201003110105.html

28 Gazprom to decide on gas project, TradeInvest Africa, 3 November 2010, http://allafrica.com/stories/201011031036.html

29 see http://allafrica.com/stories/201201200944.html30 see http://allafrica.com/stories/201201200944.html31 NamPower Annual report, 2001, http://www.nampower.com.na.32 Usually, the independent electricity distribution companies in a region become shareholders

in the new red.33 see Weidlich b, City wary of joining red, 3 July 2007,

http://www.namibian.com.na/index.php?id=28&tx_ttnews[tt_news]=35468&no_cache=1 bracing for red-hot electricity, Namibia Economist, 30 June 2006,

http://www.economist.com.na/index.php?option=com_content&view=article&id=14770:bracing-for-red-hot-electricity&catid=554:archives

34 eCb, personal communication (2008).35 eCb, personal communication (2008).


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36 eCb, personal communication (2008).37 eCb, personal communication (2008).38 eCb, personal communication (2008).39 eCb, personal communication (2008)40 eCb, personal communication (2008).41 eCb, personal communication (2008).42 eCb, personal communication (2008).43 Various stakeholders, personal communication (2008).44 eCb, personal communication (2008).45 Cloete L, First red set to be dissolved, AllAfrica.com, 12 November 2010,

http://allafrica.com/stories/201011120749.html46 hartman A, Walvis dumps erongo red, AllAfrica.com, 28 october 2010,

http://allafrica.com/stories/201010280123.html47 duddy J-M, Lights dim for erongo red, AllAfrica.com, 24 February 2011,

http://allafrica.com/stories/201102240722.html48 The guidelines are available on the eCb website. (see also the conclusions of Namibia IPP

and Investment Market Framework, a report compiled by Core international inc. in 2006, and available at http://www.ecb.org.na/downloads.php?m=6&sm=0&op=show&cat_id=23)

49 eCb, personal communication (2008).50 eCb, personal communication (2008).51 NamPower, personal communication (2008).52 eCb, personal communication (2008).53 eCb, personal communication (2008).54 Where rr = revenue requirement, rAb = regulatory asset base, ror = rate of return,

e = operations and maintenance expenses, d = depreciation and T = taxes.55 eCb, personal communication (2010).56 eCb, personal communication (2008).57 eCb, personal communication (2008)58 eCb, personal communication (2010).59 eCb, personal communication (2008).60 The North American electric reliability Corporation defines ‘loss-of-load expectation’ as

‘the expected number of days in the year when the daily peak-demand exceeds the available generating capacity. it is obtained by calculating the probability of daily peak-demand exceeding the available capacity for each day, and adding these probabilities for all the days of the year’.

61 both standards can be downloaded at http://www.ecb.org.na/download.php?fl_id=2262 eCb, personal communication (2010).63 eCb (2006), demand side Management study for Namibia,

http://www.ecb.org.na/download.php?fl_id=5664 NamPower Annual report, 2008 (http://www.nampower.com.na/pages/annual-report-2008.asp).65 eCb, personal communication (2008).


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Ghana: Pursuing the standard model for power-sector reform

Tariff increases are not being matched with increases in quality. – An official from the Association of Ghana industries1

When the Akosombo hydropower station in the Volta river basin was commissioned in the late 1960s, it seemed to promise newly independent Ghana a supply of abundant and cheap electricity for years to come. Further assurance of the adequacy of electricity supply came a decade later when Kpong hydropower station was developed just downstream of Akosombo, but the vulnerability of Ghana’s power system to the vagaries of the weather was exposed just a few years later. The rains failed in 1981, heralding an era of frequent and widespread power outages. As recently as 2007, Ghana faced severe power shortages and widespread load shedding. The first power crisis brought the realisation that it would be prudent to diversify Ghana’s electricity-generation mix. Plans to infuse thermal power into the grid were discussed in the early 1980s but it took over a decade before they were implemented and, by the mid-1990s, demand had increased so substantially that costly emergency thermal generation had to be procured as a stopgap measure. Adding to the sector’s problems, the country’s distribution network was underperforming significantly.

in response to this dire state of affairs, the Ghanaian government began to explore ways of reforming the power sector. At that time, the standard model of reform had some traction, and proposals were made that followed the standard model fairly closely: • The state-owned generation and transmission company, the Volta river Authority

(VrA) was to be unbundled into separate generation and transmission entities; • independent power producers (iPPs) would be allowed to enter the market; • The state-owned distribution company, the electricity Company of Ghana (eCG)

was to be horizontally unbundled2 and its successors privatised; and • An independent regulator was to be established.

As of late 2010, the government had gone some way towards implementing these reforms. VrA’s electricity transmission responsibilities had been separated into the Ghana Grid Company (GridCo), and two regulatory bodies had been established to oversee the sector, namely, the energy Commission (eC) and the Public Utilities regulatory Commission (PUrC). Furthermore, the private sector has been involved in power generation since 1999, when, through a joint venture with the government, a 220 MW thermal plant was built in Takoradi, the capital of Ghana’s Western region. More recently, a 200 MW iPP (sunon Asogli power plant) was commissioned at Tema, Ghana’s main industrial port.

despite the restructuring, the Ghanaian government remains by far the largest player in the industry. Further testament to this is the fact that a new 400 MW hydro-

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electric project at bui, which is being constructed upstream of Akosombo and is expected to be commissioned in 2013, is being funded by the governments of Ghana and China. This does not imply that the role of the private sector is unimportant. The realisation of the government’s stated goal of increasing installed generation capacity to 5 000 MW by 2015 will require the mustering of all possible capital, and, judging from its 2010 policy document (Government of Ghana, 2010), the Ghanaian government is well aware of this. For now, however, like other countries covered in this volume, it can be argued that Ghana’s electricity sector displays all the characteristics of a hybrid power market.

The 2007 discovery of crude oil and natural gas in the Jubilee field off-shore of Cape Three Points makes this a time of great promise for Ghana’s energy sector. These new sources of energy, coupled with the ongoing reforms, may well put a stop to the country’s power crisis. To this end, an effective regulatory environment has the potential to facilitate the significant investments required while ensuring that prices are kept competitive, and that quality and reliability of supply attain acceptable standards. in order to understand how Ghana’s regulatory bodies are rising to this challenge, this chapter begins with an overview of the electricity sector as of 2010, and then provides some insight into the history that led the industry to this point, including the development of the major hydropower plants, the various reform strategies attempted since the 1990s and the evolution of the country’s energy policy. Ghana’s regulatory frameworks are then analysed in some detail.

Power-sector overviewFigure 6.1 gives an overview of the power sector in Ghana. As in most countries, the government, through the Ministry of energy, is responsible for formulating policy related to the electricity sector and for implementing certain aspects of those policies. Ghana is unique in having two separate bodies responsible for regulatory oversight of the power sector, namely, the Public Utilities regulatory Commission (PUrC) and the energy Commission (eC); their respective roles are discussed later in the chapter. Like Namibia, Ghana’s energy ministry does not have a specialist agency responsible for rural electrification.

At industry level, the VrA, GridCo and eCG state-owned entities dominate the sector: VrA is mainly a power-generation company, but it carries out limited distribution functions through its subsidiary, the Northern electricity distribution Company (NedCo); GridCo is responsible for transmission and system operations; and eCG is the national distribution utility. iPPs have begun to enter the industry, but remain relatively marginal. it is noteworthy that VrA was the first to initiate cross-border electricity trade in West Africa. First, the company built a transmission line to Togo and benin in 1972, and then in 1984, another line was commissioned linking Ghana with Côte d’ivoire, which has been an important source of electricity imports ever since.


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G h a n a : P u r s u i n G t h e s ta n d a r d m o d e l f o r P o w e r - s e c t o r r e f o r m

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Figure 6.1 Overview of Ghana’s electricity sector, 2010

Ministry of Energy

Energy Commission (EC)

Imports

Industry

Volta River Authority (VRA)

Residential, commercial, industry

Independent power producers (IPPs)

Public Utilities Regulatory Commission (PURC)

Ghana Grid Company (GridCo)

Exports (Communauté

Electrique du Bénin)

Northern Electricity Distribution Company

(NEDCo) (VRA subsidiary)

Electricity Company of Ghana (ECG)

Bulk customers



in 2011, total installed generation capacity in Ghana was 2 186 MW (see Table 6.1). of this, approximately 400 MW was unavailable due to various technical and hydrological constraints. Given the severe impact of droughts, the country’s generation mix has incorporated thermal generation since the late 1990s. Ghana’s electricity system, which was wholly dependent on hydropower in the 1970s, now derives only 50 per cent of total installed capacity from this technology.

Table 6.1 Installed electricity generation capacity, Ghana, 2011

Type Plant Capacity (MW)hydro Akosombo

Kpong1 020

160Thermal(Fuel:*Light crude oil/natural gas/diesel**Natural gas/diesel***Natural gas)

Takoradi Power Company (TAPCo)*Takoradi international Company (TiCo)*Tema Thermal Plant 1*Tema Thermal Plant 2**sunon-Asogli***Mines reserve Plant**

330220126

50200

80Total 2 186

source: energy Commission of Ghana (2012)


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The peak demand and energy consumption forecasts for Ghana over the period 2009–2018 are shown in Figures 6.2 and 6.3. it is projected that peak demand will rise from the 2009 level of 1 423 MW to 2 856 MW and energy consumption from 10 116 GWh to 19 469 GWh over the period (Power systems energy Consulting, 2010). This implies annualised growth rates of 8.6 per cent and 7.6 per cent for peak demand and energy consumption respectively. Although such growth rates are high by any standard, they were overshadowed by the actual figures for 2010 to 2011, which recorded increases in maximum demand and energy consumption of 15.8 per cent and 9.5 per cent respectively (energy Commission, 2012). This significant increase in the use of electricity is consistent with the growth of Ghana’s gross domestic product (GdP), which was 13.4 per cent in 2011. The effect of demand that could not be met due to insufficient primary energy in previous years could also have helped drive the increase in consumption and maximum demand. Ghana’s economic growth trajectory has been bolstered by the discovery in 2007 of oil in the off-shore Jubilee field and the extraction and processing activities that have ensued. Clearly, such high growth has implications for the electricity sector and is testament to why we advocate, throughout this volume, the need to regularly update power-sector plans, including the revision of load forecasts, a primary input into the development of least cost generation and transmission expansion plans.

Figure 6.2 Projected maximum power demand, Ghana, 2009–2018

3 000

2 500

2 000

1 500

1 000

500

0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Exports

VALCO

VRA/Mines

NED/NEDCo

ECG

Pow

er d

eman

d (M

W)

source: Power systems energy Consulting (2010)


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Figure 6.3 Projected energy consumption, Ghana, 2009–2018

20 000

18 000

16 000

14 000

12 000

10 000

8 000

6 000

4 000

2 000

0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Ener

gy c

onsu

mpt

ion

(GW

h)

Exports

VALCO

VRA/Mines

NED/NEDCo

ECG

source: Power systems energy Consulting (2010)

Development of Ghana’s electricity sectorduring colonial rule (1821–1957), Ghana was known as the Gold Coast. The british colonial administration sponsored the installation of Ghana’s first public electricity supply to power its facilities in the coastal town of sekondi in 1914 (ibrd, 1968). sekondi was an important gateway into Ghana’s interior and the termination point for the Gold Coast railway that transported timber and minerals from the hinterland. The capital city, Accra, had to wait a further eight years before it was gradually electrified – with a limited direct-current supply in 1922, followed by an alternating-current network in 1924 (rCeer, 2005). Gradually, stand-alone public electricity installations were set up in various parts of the country (see Table 6.2). by 1968, diesel-generating capacity at 29 locations across Ghana totalled 90 MW (ibrd, 1968). This included the 35 MW power station at the port of Tema, which, at the time, was reputed to be the largest diesel-fired plant in Africa.

Volta river project

Although it was thermal power that drove Ghana’s electrification process until the mid-1960s, the history of hydropower in the country dates back to the early years of the 20th century, when geologist Albert Kitson was tasked by the colonial authorities to discover what mineral wealth, in addition to gold, lay concealed beneath the forests and mountain tops of the still little-known interior of the Gold Coast (okoampa-Ahoofe, 2009). in 1914, Kitson found deposits of bauxite, the primary raw material for aluminium production, in the Volta river basin. The viability of an


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aluminium industry was dependent on the availability of low-cost electricity and, during a canoeing trip down the Volta river in 1915, Kitson came upon the gorge at Akosombo, which he suspected might be suitable for the building of a dam and hydro-electric generation facilities (Gorman et al., 1999).

Table 6.2 Key milestones in the electrification of Ghana up to 1964 Year Event1914 Gold Coast railway Administration introduced electricity supply to sekondi1922 Public Works department commissioned direct-current supply to Accra1924 Public Works department commissioned alternating-current supply in Accra1926 electricity supply commenced in Koforidua1927 Public lighting commissioned in Kumasi1927 electricity supply commenced in Winneba1929 electricity supply commenced in Tamale1932 Cape Coast power station commissioned1938 Tamale power station commissioned1947 electricity department was created within the Ministry of Works and housing and took

responsibility for the electricity-related functions formerly managed by the Gold Coast railway Administration and the Public Works department

1948 swedru power station commissioned, and electricity supply commenced in bolgatanga, dunkwa and oda

1949 First major transmission line commissioned (11 kV) from Tema to Nsawam1955 Keta power station commissioned1956 Tema power station commissioned (2 MW)1961–1964 Tema power station expanded to 35 MW

source: rCeer (2005)Note: With the exception of Tema power station, the majority of Ghana’s thermal stations were decommissioned once cheaper hydropower from Akosombo became available.

The realisation of what became known as the Volta river project was a protracted process. in 1924, Kitson wrote a paper entitled ‘The possible sources of power for industrial purposes in the Gold Coast, british West Africa’, which was subsequently published in the Gold Coast Geological Survey (see hart, 1980). it was not until 1938, however, when duncan rose, a civil engineer based in south Africa, came across the paper in a Johannesburg library (Gorman et al., 1999) that it received real attention. rose formed the African Aluminium syndicate,3 which concluded a feasibility study on the project by the end of 1939 (hart, 1980). The onset of the second World War in 1939 prevented further detailed investigations, but the time was used to solicit interest in the project, and when the war ended in 1945, the African Aluminium syndicate was transformed into West African Aluminium Ltd. in 1946, british Unilever acquired a financial interest in the new company through one of its subsidiaries (Gorman et al., 1999).

The end of the war saw increasing demand for aluminium in britain, and the project began to be seen as integral to the development of the Volta river basin, with potential spin-offs for Ghana as a whole. hence, when the colonial government


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retained consulting engineers, halcrow and Partners, in 1949, their terms of reference included advising ‘on the wider aspect of development of the whole Volta basin’ (special correspondent, 1956: 287). in 1950, the colonial government established the Volta river Project Preparatory Commission. When the commission made its recommendations in 1956 (a year before Ghana achieved independence from britain), it endorsed halcrow and Partners’ recommendation that a dam be constructed at Ajena (hart, 1980; ibrd, 1961b), but still the project did not proceed. in 1958, further advice was sought, this time from Kaiser engineers and Constructors, who were asked to review ‘the earlier proposals and reconsider the justification for a power–aluminium development’ (ibrd, 1961b: 2). Kaiser engineers recommended that the proposed dam be moved from Ajena to Akosombo, where the narrowness of the river and an increased head height would make construction less costly and yield higher generation output (ibrd, 1961b). At this point, it was envisaged that the hydro-electric generation scheme would be developed by the Ghanaian government and that the private sector would develop the aluminium industry. To this end, the Volta Aluminium Company (VALCo) was formed in 1959 (hart, 1980).4

The hydro scheme presented serious challenges, however. Apart from the complex engineering involved,5 its financial viability was far from clear. The capacity of the plant would be 588 MW – almost 10 times the country’s maximum electricity demand, which stood at just 70 MW in 1960 (ibrd, 1961b). Furthermore, half of the country’s existing demand was from the mining industry, and the cost of electricity transmission to their operations along a 700 km grid extension was prohibitive (ibrd, 1960).6 ordinarily, an energy-intensive consumer, such as the proposed aluminium smelter, would improve the financial outlook for this kind of project, but the viability of the aluminium plant was itself premised on the availability of abundant low-cost electricity. While it was clear that the whole project would provide wider economic benefit to the country from increased employment, the development of skilled labour, the diversification of the country’s industry and the substantial increase in electricity supply, Ghana was cautioned as follows:

The government must decide whether these benefits would be sufficient to outweigh the uncertainties faced and the income foregone when so considerable an investment is made in a single project. it is clear that there would be no net gain, and probably a net loss, during the first decade of operation, when financial returns would be very low and net tax benefits, if any, would be small. (ibrd, 1960)

After extensive negotiations, driven partly by the government’s desire for rapid development following Ghana’s independence from britain in 1957, financing arrangements for the Volta scheme were concluded in 1962. The Ghanaian government funded 50 per cent of the project cost, and the remainder was financed by loans from the international bank for reconstruction and development (ibrd – now the World bank),7 the United states Agency for international development (UsAid), the export-import bank of the United states and the UK government’s export Credits Guarantee department.


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Meanwhile, in 1961, the government passed the Volta development Act, thereby establishing the Volta river Authority (VrA). VrA’s primary function was to plan, execute and manage the hydropower scheme. Clause 10(1) of the Act set out this mandate as follows:

a) The generation of electrical power for the operation of an aluminium industry, and for general industrial and domestic uses, by the means determined by the VrA, and in particular in the first instance, by the construction and operation of a dam and hydro-electric generating station in the vicinity of Akosombo;

b) The construction and operation of a transmission system for the distribution of the electrical power generated by the VrA;

c) The supply of the electrical power generated by the VrA to:i. A government department or a public corporation responsible for the

supply of electrical power to the public;ii. The township of Akosombo; andiii. Any other consumer in the republic or elsewhere under the arrangements

agreed on between the government, the VrA and the electricity Company of Ghana.

d) The provision, when and so far as practical, of facilities and assistance for the development of the lake as a source of fish, and as a route for the transportation of goods passengers; and

e) The development of the lakeside area for the health and well being of the inhabitants, and people living adjacent to that area.

in anticipation of the financing arrangements being concluded, the government awarded the main construction contract in 1961, and preparatory work on the Akosombo dam commenced in the same year (ibrd, 1961b). by 1965, the power station comprising four 147 MW generating units with a total capacity of 588 MW had been completed, and the power station was officially commissioned in the following year (rCeer, 2005). The Akosombo dam created the Volta reservoir (Lake Volta), one of the largest water reservoirs in the world, with a total surface area of approximately 8 500 km2 (comparable in size to the island of Cyprus), an average length and width of 400 km and 25 km respectively, and a holding capacity of 148 000 million m3 (iLeC, 2011).

The agreement signed between the government, VALCo and others in 1962 for the development of the aluminium smelter included a power-supply agreement, known as the Power Contract (Government of Ghana, 2003). in terms of this agreement, VrA was obliged to supply a minimum of 158 MW to the smelter in the first year of operation, and this was to be increased to 315 MW by the sixth year (although there were options for reaching 315 MW earlier, and for an increased supply of 370 MW between the fourth and the tenth year) (ibrd, 1961b). When non-smelter demand-growth and system-reserve requirements were taken into account, it was clear that VrA would require additional capacity by 1972 (ibrd, 1969). Accordingly, the power station at Akosombo was built to accommodate two additional generating units, and with financial assistance from the governments of Canada and italy, as well as UsAid and the World bank, two additional units were commissioned in 1972. Total installed capacity at Akosombo thus increased to 912 MW8 (ibrd, 1969; rCeer, 2005).


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With excess capacity available at the Akosombo power station, VrA pioneered cross-border electricity trade in West Africa when it commissioned a transmission interconnector linked to Togo and benin in 1972. Meanwhile, in 1971, VrA had commissioned a least-cost power-system expansion study, The Ghana Power Study: Engineering and Economic Evaluation of Alternative Means of Meeting VRA Electricity Demands to 1985 (see rCeer, 2005). The study recommended that the next power plant in Ghana should be the Kpong hydroelectric project, which would further exploit the potential of the Volta river. in 1977, construction began on the Kpong project. The power station is located just 24 km downstream of the Akosombo dam, and was completed in 1982. its four generating units added 160 MW to the capacity of Ghana’s power system (rCeer, 2005).

The Volta river project was not without controversy, however. For example, although VALCo’s electricity consumption averaged around 60 per cent of VrA’s output during its first 10 years of operation (World bank, 1977), under the terms of the power-supply agreement, VALCo contributed only 30 per cent of the utility’s revenue (ibrd, 1969). soon after the Akosombo power station was commissioned, it became apparent that the terms of the power-supply agreement were unsustainable. The agreement allowed VALCo a tariff of 0.2625 Usc/kWh fixed for 30 years from 1967 (ibrd, 1961; 1969). Then inflation rose, and the local currency lost value against major international currencies, putting further strain on the project. Thus, barely five years into the operation of the Akosombo plant, VrA began courting VALCo for a tariff increase, and requested it to make provision for future escalation. in 1972, VALCo agreed to an adjustment of the tariff to 0.275 Usc/kWh, and the following year an interim tariff of 0.3125 Usc/kWh was agreed. While the interim tariff was in force, negotiations continued until 1977, when it was agreed to retrospectively increase the tariff to 0.325 Usc/kWh for the period 1973 to 1975, and 0.45 Usc/kWh for 1976. This was to be followed by gradual increases up to 0.5 Usc/kWh in 1981. Agreement was also reached on an escalation mechanism that would shield VrA from increases in operating costs and foreign-exchange exposure in relation to its outstanding debt (World bank, 1977). despite these increases, VrA (and hence the Ghanaian government) and its lenders remained dissatisfied, and in 1984 the tariff was again renegotiated and increased to 2.0 Usc/kWh, with a provision for quinquennial reviews. Crucially, it was also agreed that the domestic market would take priority over supplies to VALCo, and that the amount of energy that could be supplied to the smelter would be capped (World bank, 1985b).

in 1997, the 30-year power contract expired, giving the parties an opportunity to negotiate afresh. VrA and VALCo failed to reach agreement, however. Power supply to the smelter continued despite the fact that no minimum tariff had been agreed, and a dispute soon arose over the accumulation of arrears. in 2003, VALCo suspended its operations and filed for arbitration with the international Chamber of Commerce (Government of Ghana, 2003).9 With the relationship between the parties at an all-time low, it was not surprising that in 2004, the Ghanaian government assumed Kaiser’s majority (90 per cent) interest in VALCo.10 An era had ended.


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in 2005, operations resumed at the smelter, but at only 30 per cent capacity due to power shortages. The smelter has operated intermittently over short periods since then, and as of March 2011, the plant was not operational. ironically, although the development of the Akosombo complex was spurred on by the discovery of bauxite, the VALCo smelter always depended almost entirely on imported alumina (refined bauxite) for its feedstock.

Electricity distribution: the establishment of the Electricity Corporation of Ghana

As part of the World bank loan for the construction of the Volta river project in 1962, the Ghanaian government agreed to reorganise the electricity division in the Ministry of Works and housing (ibrd, 1968). The electricity department (the forerunner to the division) was responsible for the diesel-generating stations and for the distribution of electricity across the country. it was proposed that the electricity division be transformed into ‘an autonomous corporation comparable to VrA to be operated as a public utility on a sound commercial basis’ (ibrd, 1968: 4). Consequently, the 1967 electricity Corporation decree established the electricity Corporation of Ghana (eCG) (rCeer, 2005). The decree authorised eCG to purchase electricity from VrA, undertake its own generation, and distribute and supply electricity throughout Ghana (excluding VALCo, the Akosombo township and certain mines). eCG was also mandated to regulate the generation and supply of electricity by other parties, including statutory agencies, with the exception of VrA (ibrd, 1968).

eCG was expected to develop into an autonomous entity, run on commercial principles, like VrA. but a decade and a half after it had been established, the organisation’s management was still not meeting its responsibilities, and the utility had lost the confidence of both the government and consumers (World bank, 1985b). Granted, eCG’s business was larger and more complex than that of VrA, and it has been argued that its transition from being a government department to a commercial entity was so badly managed as to prevent it from becoming effective (World bank, 1989). As discussed later in the chapter, this poor state of affairs was partly what prompted the Ghanaian government to initiate reforms in the power sector in the mid-1980s.

Droughts, power crises and the overdrawing of the reservoir

during the 1970s, Ghana rode a wave of cheap and abundant hydro-electric power. This was remarkably short-lived, however. even with the extra capacity provided by Kpong from 1982, the World bank (1977) forecast that additional generation would be required by 1985. Long before this, however, a severe drought, which lasted from 1981 to 1984, brought about the country’s first power crisis and exposed the country’s overdependence on hydro-electric generation (ofori-sarpong 1986; rCeer, 2005). The rains over that period were so poor that inflows into the reservoir dropped to ‘less than 15 per cent of the long-term expected total’ (rCeer, 2005: 20). exacerbating the situation was a deliberate drawdown from the Volta reservoir that had taken place to avert an energy shortfall prior to the commissioning of Kpong (World bank, 1977). With the water


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in the reservoir depleted, VrA was left with no option but to limit its power output at Akosombo, which had a knock-on effect downstream at the Kpong power station. in the absence of immediate alternative sources, power rationing was initiated nationwide and, in 1984, production at the VALCo smelter was suspended (rCeer, 2005). Although normal rains fell in 1984, power rationing continued until 1986 when water levels in the reservoir recovered (intergovernmental Panel on Climate Change, 2001).

Thermal generation: a rebirth

in 1983, as power shortages ravaged the country’s economy, VrA commissioned the Ghana Generation Planning study to determine the optimal path for expanding generation capacity (rCeer, 2005). As might expected, the study recommended that thermal power be added to the country’s electricity generation mix to mitigate the effects of poor rainfall (Koffi, 2009).11Quiteapartfromtheriskofdrought,thestudyobserved that the Volta river routinely experiences highly variable flows, thus further supporting the need for thermal generation (rCeer, 2005). it was over a decade before any new generation came on stream, however. VrA eventually installed the first 110 MW unit at Takoradi thermal power station in late 1997. A similarly rated unit followed early the following year. The last unit was commissioned in 1999, bringing total installed capacity at the power station to 330 MW (rCeer, 2005).

hot on the heels of this development, and in response to further power shortages in 1997 and 1998 (see the next section), the government (through VrA) entered into a joint venture with a Us-based company, CMs energy.12 Together they formed the Takoradi international Company (TiCo) in 1999 and put plans in place to add two further 110 MW units to the Takoradi power station. The two units entered commercial service in 2000, expanding total capacity at the plant to 550 MW (rCeer, 2005).13

Recurring power crises

The delays in commissioning the required thermal generation in Ghana were ostensibly due to a lack of funding, the raising of which was hindered by the low tariffs afforded to VALCo and other electricity consumers. Amidst these delays, demand for electricity grew, spurred on by the fact that Ghana’s economy had been buoyant for well over a decade. To compound matters, rainfall levels dropped slightly in 1997 (Gorman et al., 1999). This, combined with a reduction in power imports from Côte d’ivoire, led to a major power crisis in 1998. As a means of limiting the adverse impact of the crisis, the Volta reservoir was deliberately overdrawn in order that more electricity could be generated.

Although the rainfall realised in the Volta river basin in 1997 was lower than expected, it was not as severe as the 1981 drought had been. in fact, inflow into the reservoir in 1997 was 71 per cent of the long-term average and higher than that recorded in 15 different years since the mid-1940s (UsAid, 1999). however, increased demand brought about by an economy that had been buoyant since 1984, a reduction in power imports from Côte d’ivoire and delays in commissioning the last unit at Takoradi


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placed strain on the available generation capacity. Left with few options, the Volta reservoir was once again overdrawn to the extent that by mid-1998 at Akosombo ‘the power intakes were exposed, vortexes were forming at the intakes, and air was being drawn into the penstocks to the detriment of the units’ (UsAid, 1999: 10).

by then, power rationing had been reintroduced and electricity supplies to VALCo again cut off. in the meantime, the government had resorted to emergency thermal generation and procured 30 MW each from Aggreko and Cummins (rCeer, 2005). Although Aggreko’s 18-month contract was executed in time to help mitigate the crisis, the Cummins plant, for which there was a 24-month take-or-pay contract, became fully operational only after the worst of the crisis had passed. This led to a dispute, and by 2007, Cummins was demanding Us$20 million from the Ghanaian government in unpaid bills (Malgas, 2008).14

Further power shortages occurred in 2002 and in 2006 to 2007, while poor rainfall tended to be the official explanation for the power shortages, the overdrawing of the Volta reservoir was also a factor since, in the absence of adequate rainfall, this depleted the water available for power generation in the following years. indeed, water inflows into the reservoir during the crisis years were not as low as those in some non-crisis years (see Figure 6.4) Yet, in each of those years, the level of the reservoir was drawn down below the minimum operating level (see Figure 6.5). As the 2006/2007 power crisis ravaged the country, VrA acknowledged its role in the crisis, noting that ‘there has been tremendous pressure on the hydro system to meet the demand, which has led to drawing the reservoir down below the technically prescribed minimum operating level’ (VrA, 2007). by the end of 2010, the reservoir level had recovered to over 82 metres, but lower-than-expected rainfall in any given year continues to present a risk for Ghana, as the country still relies on hydropower for approximately half its generating capacity.

Figure 6.4 Water inflow into the Volta reservoir, Ghana, 1965–2010

1 200 000

1 000 000

800 000

600 000

400 000

200 000

0

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

Annu

al n

et in

flow

(cu

bic

feet

per

sec

ond)

source: brew-hammond & Kemausuor (2007)Note: Years in which there was a power crisis are circled.


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Figure 6.5 Volta reservoir regulation, Ghana, 1995–2007

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

270

265

260

255

250

245

240

235

Elev

atio

n (f

eet)

NLC

Minimum reservoir elevation

Source: Brew-Hammond & Kemausuor (2007)Note: Years in which there was a power crisis are circled.

Power-sector reformPower-sector reform in Ghana can be traced to the 1980s when the country was faced with its first power crisis. Since then, various ways of managing and organising the sector have been considered. Over the past 30 years, Ghana’s electricity sector has implemented a variety of reform strategies, including performance monitoring and management contracts for the utilities. In more recent times, the government has embarked on reforming the power sector in accordance with the prescripts of the standard reform model. The reforms began in the early 1980s, spurred on by the impact of the country’s first major power crisis. With encouragement from the World Bank, the Ghanaian government began to consider options for more effective organisation of the power sector (World Bank, 1985b). The establishment of the National Energy Board (NEB) in 1983 was one of the first attempts at reorganising the sector and strengthening its management capacity (Edjekumhene et al., 2001). The NEB provided advice to the government and was responsible for collecting statistical data on energy resources, production and consumption, developing policy, conducting studies and co-ordinating renewable-energy-related activities (World Bank, 1985b). The NEB was short-lived however; it became operational in 1985, but was abolished in 1991 ‘under unexplained circumstances’, and its role was transferred to the Ministry of Energy (Davidson & Sokona, 2002).

First management contract

Concurrent with the establishment of the NEB in 1983, and on the recommendation of the World Bank, Ireland’s Electricity Supply Board (ESB) was commissioned to assess Ghana’s electricity sector. This included reviewing relevant legislation and

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the management and operations of ECG and VRA. ESB was expected to make recommendations on the merits or otherwise of merging the two utilities, to develop an institutional rehabilitation plan, and to assist in its implementation (World Bank, 1989).

In 1985, a merger of the two utilities (ECG and VRA) was recommended, but the recommendation was made just as the government and the World Bank were negotiating a major expansion of electricity distribution networks in the north.15 During these negotiations, it had already been agreed that, given ECG’s poor performance, VRA would undertake and manage the expansion project, and it was thought that a merger might prove a distraction to the implementation of the expansion plan. Instead, the Northern Electricity Department (NED), a ring-fenced subsidiary of VRA to which ECG ceded its responsibilities in the affected northern regions, was formed in 1987. The arrangement was viewed as a short-term measure that would not prevent any longer-term reorganisation of the sector (World Bank 1987; 1993b), and in 2011 the NED became a fully fledged subsidiary of VRA when the Northern Electricity Distribution Company (NEDCo) was incorporated.16

The ESB made some further recommendations on sector management and legislation that focused on improving the performance of ECG and, in this context, a performance contract was agreed between the government and ECG (World Bank, 1989). The most significant support offered by the Irish, however, was when, through a ‘technical assistance team’, the ESB provided the services of a managing director, project manager and director of operations in a de facto management contract that ran from 1987 to 1989 (World Bank, 1989). As a result of this contract, improvements were made in ECG’s engineering and project-supervision functions, but by the end of the contract, there had been little improvement in ECG’s commercial operations (metering, billing and revenue collection) or financial management (World Bank, 1992; 1993b).

Second management contract

In the 1990s, more fundamental changes began to take place. First, the World Bank concluded its energy-sector review of Ghana in 1992 and, at the same time, the Ghanaian government drafted a policy document entitled ‘Energy and Ghana’s socio-economic development’ (World Bank, 1993b). These documents provided the framework for Ghana’s power-sector policy and aimed to achieve:• effective planning within the power sector;• efficient structuring and organisation of power-sector institutions;• appropriate growth of services;• electricity pricing that reflects the value of resources committed to the growth of

power supply; and• financial viability and efficiency of electricity utilities (World Bank, 1993b).

In line with these objectives, it was agreed that World Bank funding would be granted to Ghana’s National Electrification Project on condition that the Ghanaian government:• depoliticise the tariff-making process and adopt a formula for adjustments;


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• consider establishing a regulatory regime that would operate at arm’s length from political processes;

• improve the internal efficiency of critical commercial operations at ECG by engaging a contractor on a performance-based management contract; and

• engage a consultant to advise on the improvement of staff productivity at both VRA and ECG (World Bank, 1993b).

Apart from incorporating independent regulation (a development that was in line with changes happening across the continent in power-sector reform), these measures also involved a second management contract which, this time, specifically targeted the commercial viability of ECG. To this end, ECG was reorganised, and the functions of metering, billing and revenue collection fused into a new customer-service department that was outsourced to the management contractor, Électricité du France (EDF), in 1994. The EDF team reported to ECG’s managing director, and their remuneration was linked to performance (World Bank, 1993b). Although they had made some progress by the time their contract ended four years later,17 their interventions were assessed as having been only ‘marginally satisfactory’ (World Bank, 2001b: 6). The World Bank reported that:

(i) System losses were at 21% at the end of the contract period instead of the target level of 18%; (ii) the contract had been designed to be self-financing, but it was assessed that the productivity gains had been less than the cost of the commercial loan used to finance the contract; and (iii) the infrastructure set up in the Consumer Services Department (including the human expertise, management procedures and incentives) had not been effective to maintain or improve commercial performance in the period after the management contract (2001b: 6).

Emergence of the standard reform model

As part of the negotiations around funding the construction and installation of the Takoradi thermal power plant, the World Bank began to insist on more deep-rooted reforms. As a result, the government published the Ghana Power Sector Development Policy18 in early 1994 (the key aspects of which are summarised in Table 6.3), which built on the reform measures proposed just a few years earlier. In the same year, the Chilean firm Synex was retained to advise on the implementation of this policy. In line with the ‘standard reform model’, Synex recommended the industry structure shown in Figure 6.6.

Table 6.3 Salient features of Ghana’s power-sector development policy, 1994

Focus area Policy interventionGeneration Hydro resources related to the Volta reservoir to be further developed by VRA or in

conjunction with the private sectorIPPs to be allowed to develop sources of hydropower on the country’s western rivers, namely, the Pra, Tano and Ankobra riversGeneration mix to include thermal IPPs

System operations

Rules to be established to facilitate economical generation dispatch between VRA and IPPsAn open-access regime to be set up to facilitate IPP sales to bulk consumers


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Focus area Policy interventionDistribution A framework for greater private participation in delivering ECG’s commercial operations

to be formulatedConcessions for electricity distribution to be allocated

Pricing and tariffs

Regulated marginal-cost nodal pricing to be effected for generation and transmissionRegulated consumer tariffs to be based on node prices plus efficient distribution costs

Regulation Independent regulatory body to be formed to:maintain competition;award and monitor concession agreements for generation and distribution;regulate prices; andmonitor performance agreements of state-owned enterprises

Source: Adapted from Edjekumhene et al. (2001)

Figure 6.6 Power-sector structure for Ghana, as proposed by Synex, 1994

IPPs

Transmission company – VRA owned (Open access, common carrier)

Distribution company 1

Distribution company 2

VRA generation

Spot market(and economic load

dispatch centre)

Bulk customers:VALCO, mines etc.

Regulated market Deregulated

market

Power flows

Financial flows

System operations

Source: Adapted from Edjekumhene et al. (2001)

Interestingly, Synex did not suggest unbundling VRA’s generation and transmission functions, but proposed instead that VRA and any IPPs that entered the market should have open access to the network. In the proposed structure, IPPs could sell directly to the spot market, or enter into long-term contracts with VRA (for generation), the distribution companies and/or large consumers in the deregulated market. An independent regulator would set prices in the regulated market and determine the wheeling charge for the use of VRA’s transmission assets. Initially, ECG and NED would be the only distribution companies, but it was envisaged that new companies or subsidiaries of ECG would be created to serve new concessions in the medium term (Edjekumhene et al., 2001).

Following the Synex proposals, the Ghanaian government formed a Power-Sector Reform Committee in 1994, and in 1997, the reform committee presented its recommendations to the government. The key proposals were:


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• the establishment of an institutional framework for regulation of the sector; • restructuring the power sector in order to remove VRA’s monopoly and allow for

private-sector participation; and • the creation of a separate transmission utility in order to provide ‘open access’ to

all power market players (World Bank, 2007d).

As a result of these recommendations and following further consultation, the government passed the Public Utilities Regulatory Commission Act (PURC Act) and the Energy Commission Act (EC Act), thus establishing two regulatory bodies for the power sector in 1997. Among the electricity sectors analysed in this volume, Ghana is unique in having two regulatory bodies, and it is questionable whether this arrangement is optimal. It has been argued, however, that the need for two regulators stems from Clause 269(1) of the Constitution, which states:

Subject to the provisions of this Constitution, Parliament shall, by or under an Act of Parliament, provide for the establishment, within six months after Parliament first meets after the coming into force of this Constitution, of a Minerals Commission, a Forestry Commission, Fisheries Commission and such other Commissions as Parliament may determine, which shall be responsible for the regulation and management of the utilization of the natural resources concerned and the co-ordination of the policies in relation to them.

Understandably, the energy sector was identified as requiring such a commission. However it was expected that these commissions would serve largely as advisory bodies to government ministries or departments, a role that is not entirely amenable to the concept of regulatory independence. This conundrum led the government to establish the PURC and mandate it to set and revise tariffs, among other things (Edjekumhene et al., 2001).

In terms of unbundling, the government considered splitting VRA into two separate companies, focusing on hydro- and thermal generation respectively, but so far this has not been implemented (World Bank, 2007d). The EC Act provided for the licensing of a separate utility to manage power transmission in Ghana, but it took until 2006 before GridCo was formed. GridCo became operational in 2008, and assumed VRA’s transmission and system-operations responsibilities. In terms of distribution, the EC Act dismantled the statutory monopoly of the Electricity Corporation of Ghana, and the utility was renamed the Electricity Company of Ghana (ECG). The government was committed to a merger between ECG and the NED, planning to form a single holding company that would comprise five geographically distinct business units (World Bank, 2007d). Furthermore, it was envisaged that the private sector would play an increasing role in both generation and distribution.

Emergence of a hybrid power market

At the time of writing, VRA had not been unbundled and the merger between ECG and NEDCo had not taken place. However, a new energy policy has been published that seeks to establish wholesale and retail electricity markets (Government of


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Ghana, 2010), implying full implementation of the standard reform model. As experience around the continent has shown, however, this is unlikely to be achieved for some time, given the difficulties that the privatisation of utilities would present.

The 2010 energy policy also commits the government to increasing installed generation capacity to 5 000 MW by 2015 and achieving universal access to electricity by 2020 (Government of Ghana, 2010). It is acknowledged in the policy that attaining such ambitious goals will require both public and private investment, and the entry of IPPs into the sector is evidence of this. Given that the state owns VRA (and NEDCo), GridCo, ECG and any successor entities, the state’s role in the power sector is likely to remain a dominant one. Ghana’s power sector therefore exhibits the defining characteristics of a hybrid power market.

Performance of the power sector since the reforms of the late 1990s

Performance indicators for the VRA are shown in Table 6.4 for the period 2005 to 2009. Notably, the VRA posted losses between 2005 and 2008, and the organisation’s return on equity was negative over the period (including in 2009 when VRA did make a profit). Indeed, the World Bank estimated that the negative return on the government’s equity in VRA amounted to a drop of US$220 million in 2006 alone (World Bank, 2007e). The lower-than-anticipated water flows in the Volta basin catchment area, which created a reliance on more costly thermal power generation, certainly increased VRA’s cost of sales. However, the fact that tariffs are not cost reflective, combined with increasing demand and inefficiencies and a lack of financial accountability, have also contributed to the company’s poor financial state (World Bank, 2007e). VRA management have acknowledged the organisation’s poor financial situation, but stated that the situation had begun to improve, and that through annual submissions to the PURC tariff-review process, a gradual move towards cost recovery is expected.19

Table 6.4 Performance indicators for the Volta River Authority, Ghana, 2005–2009

Indicator 2005 2006 2007 2008 2009Revenue from electricity sales (US$ ’000)

357 766 466 093 398 795 508 151 526 374

Profit before tax (US$ ’000) -10 973 -174 194 -317 428 -71 449 7 873Return on average equity -0.78 -11.55 -19.68 -4.64 -0.53Current assets ratio 1.79 1.46 1.13 1.55 1.49Debt service ratio 0.79 -1.66 -1.69 -0.1 0.31Energy sent outa (GWh) 7 560 9 007 7 092 8 144 9 126

Source: VRA Annual Reports, 2005–200920

Note: a. Includes imports and other purchases less own use.

ECG achieved positive gross profits each year between 2005 and 2009, as shown in Table 6.5. However, the below-cost tariffs for power purchases from VRA and direct subsidies to ECG from the government in lieu of applying PURC retail tariff


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increases in full may have aided this profitability. Furthermore, ECG’s technical and non-technical losses averaged 25 per cent over the period, and its debtor days stood at 122 days (four months of billing) in 2009, both of which are high, indicating that there was room for performance enhancement within the utility.

Table 6.5 Performance indicators for the Electricity Corporation of Ghana, 2005–2009

Indicators 2005 2006 2007 2008 2009Revenue (US$ ’000) 244 571 312 301 392 581 529 188 460 981Gross profit (US$ ’000) 56 073 60 098 80 655 147 755 132 097Maximum demand (MW) – – 889 927 1 036Energy sales (GWh) 3 762 3 978 3 909 4 316 4 481Losses (%) 25.44 24.3 24.3 25.6 26Debtor days 179 138 162 130 122Average tariff (USc/kWh) 6.5 7.9 10.0 12.3 10.3

Source: ECG Annual Reports, 2005–200921

In 2010, the 200 MW gas-fired Sunon-Asogli power station was commissioned in Tema, becoming the first traditional IPP in Ghana. However, by mid-2012, the plant was not yet operating at full capacity because the West African gas pipeline (installed to supply gas from the Niger delta in Nigeria to Togo, Benin and Ghana) had not yet been fully pressurised.

Regulatory governanceHaving explored the history of Ghana’s power sector and its reforms, we turn now to how the industry is regulated, focusing first on regulatory governance and then on issues of regulatory substance and impact.

The legislative framework for the regulation of Ghana’s electricity sector is set out in the PURC Act and the EC Act, both of 1997. The PURC, also known as the ‘economic regulator’, is primarily responsible for tariff setting, performance monitoring, promotion of competition and complaints handling. The EC, often referred to as the ‘technical regulator’, is responsible for licensing, technical standards and performance monitoring. The EC also renders policy advice on the energy sector to the energy ministry. It is important to note that the purview of both regulatory agencies extends beyond the electricity sector – the PURC’s includes water resources, while the EC’s includes petroleum and gas. Table 6.6 summarises their core functions as set out in the legislation.

Requisite powers: dissecting the roles and responsibilities of the regulatory commissions

In terms of best practice, independent regulatory agencies should be given the authority to make decisions without having to seek the approval of other agencies or arms of the government. In Ghana, the legislation does not grant the EC such unequivocal independence, but this is to be expected given its role as a governmental advisory body.


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Section 3 of the EC Act specifically grants the Minister of Energy the power to give directions to the commission as follows: ‘The Minister may give to the Commission such directions of a general character as appear to him [sic] to be required in the public interest relating to the discharge of the functions of the Commission.’

Table 6.6 Primary functions of the Public Utilities Regulatory Commission and the Energy Commission, Ghana

Energy Commission (EC)a Public Utilities Regulatory Commission (PURC)Recommend national policies for the development and use of indigenous energy sources

Provide guidelines on tariffs chargeable for utility services

Advise the energy minister on national policies for the efficient, economical and safe supply of electricity products, having regard for the national economy

Examine and approve tariffs chargeable for utility services

Periodically prepare, review and update indicative national plans to ensure that all reasonable demands for energy are met

Monitor performance standards for the provision of services

Secure a comprehensive database on the extent of the development and use of available energy resources

Initiate and conduct investigations into the quality of service given to consumers

Receive and assess licence applications, and grant licences to public utilities for the transmission, wholesale supply, distribution, and sale of electricity and natural gas

Promote fair competition among public utilities

In consultation with the PURC, establish and enforce performance standards for public utilities engaged in the transmission, wholesale supply, distribution and sale of electricity and natural gas

Conduct studies relating to the efficiency of public utilities

Promote and ensure uniform rules of practice for the transmission, wholesale supply, distribution and sale of electricity and natural gas

Value the assets of public utilities as may be considered necessary Collect and compile such data on public utilities as considered necessary for the performance of its functionsMaintain a register of public utilities

Note: a. Functions specifically related to the petroleum and natural gas sectors have been omitted from this table.

In contrast, the PURC’s independence is enshrined in Section 4 of the PURC Act which reads: ‘Subject to the provisions of this Act, the Commission shall not be subject to the direction or control of any person or authority in the performance of its functions.’ However, the Minister of Energy has cautioned that this independence should be seen within the context of the fact that the PURC is funded by the treasury. This may explain why some industry stakeholders indicated that they do not regard the PURC as an independent body.

Collectively, however, the PURC and the EC do have the minimum requisite legal powers. However, the fact that there are two separate regulatory agencies means that effective regulation in Ghana calls for comprehensive co-ordination between the two


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bodies to ensure clarity in their respective roles and responsibilities, and that licensees adhere to their licensing conditions. Where such co-ordination is not achieved, the resulting uncertainties have the potential to seriously undermine the industry, thus potential areas of confusion are highlighted in the following discussion.


The PURC Act grants the PURC the authority to make subsidiary laws and regulations as follows: ‘The Commission may by legislative instrument make such regulations as it considers necessary for the implementation of this Act’ (Section 48, Clause 1). The EC does not have such powers and can advise the Minister of Energy only on which regulations to enact, and only in the following areas:• conservation of electricity;• expansion, planning, safety criteria, reliability and cost effectiveness of the

interconnected transmission systems;• minimum standards and procedures for construction, operations and maintenance

of facilities and installations;• protection of mains, electrical installations and services;• protection of life and property and the general safety of the public in respect of

electricity services; and• operation of the electricity transmission utility.22

The power to promulgate subsidiary legislation limits potential delays in processes and the potential for external agencies to influence regulatory authorities. However, in Ghana’s case, the legislation appears to grant the PURC limitless discretion in this regard, a situation that is open to abuse. The approach taken by the EC Act, in which specific areas are delimited, seems to support greater regulatory certainty.

Technical and commercial standards setting

The EC Act gives the EC the power to set commercial and technical standards as follows: ‘Without prejudice to subsection (1) of this section, the Commission shall…Establish and enforce, in consultation with the Public Utilities Regulatory Commission, standards of performance for public utilities engaged in the transmission, wholesale supply, distribution and sale of electricity and natural gas’ (EC Act, Section 2, Clause 2f).

The PURC Act states that:1. The Commission shall monitor standards of performance established by the

licensing authorities of public utilities for compliance by public utilities.2. Where a public utility fails to meet any required standard of performance,

it shall pay such compensation as the Commission in consultation with the licensing authority may determine to any person adversely affected as a result of the failure.

3. The requirement for payment of compensation under this section…(b) Does not preclude the Commission from taking any other measure or imposing any other sanction that the Commission has a right to impose in respect of the Act


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or omission that constitutes the failure. (PURC Act, Section 13, Clauses 1, 2 and 3b)

From the above, it is clear that authority to set performance standards rests with the EC. However, the legislation grants both the EC and the PURC enforcement powers, albeit in consultation with one another. In the absence of a clear framework for co-ordination between the two regulators, such overlap may contribute to a level of uncertainty in the industry.

Adjudication of disputes

The EC cannot adjudicate in disputes arising between licensees. However an aggrieved party can request the EC to set up an arbitration panel in accordance with Section 21 of the EC Act, which reads:

The Commission shall at the request of any person licensed under this Act set up an arbitration panel under the Arbitration Act, 1961 (Act 38) to arbitrate and settle any dispute arising between licensees where the parties cannot reach an agreement.

In the PURC Act, the only specific reference to the word ‘dispute’ is in Section 23, which states that:

1. A public utility may permit the joint use of its equipment and facilities by another public utility for a reasonable compensation where such arrangement is convenient or necessary and the use will not result in damage to the owner or other users of the equipment.

2. Where a dispute arises with respect to any such arrangement, a complaint may be made by any of the parties to the Commission which shall settle the dispute.

However, Section 14 of the PURC Act does seem to provide the PURC with the power to adjudicate a wide range of disputes, including those between licensees and between consumers and licensees:

1. Where a public utility has entered into an agreement with any institution or body corporate for the provision, development or expansion of the service to be provided or being provided by the public utility and the implementation of the agreement is not effected within a reasonable time in any material respect without reasonable excuse, the institution or body may make a complaint to the Commission.

2. Where the Commission, after giving the complainant and the public utility against which the complaint is made a reasonable opportunity of being heard, is satisfied that the public utility concerned has failed or refused to implement the terms of the agreement within a reasonable time, the Commission may –a) direct the public utility to pay to the institution or body such sum as it

considers reasonable in the circumstances of the case; orb) recommend to the licensing authority of the public utility, the cancellation

or suspension of its licence; orc) give such other directions as it considers just in the circumstances of the case.


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Financial and administrative independence

Funding sources

Parliament approves the EC’s annual budgets. The organisation accrues income in the performance of its functions, and can apply for other grants, but its primary source of funding is the Energy Fund established under the EC Act. The Energy Fund is financed by a government levy on petroleum products, electricity and natural gas as determined by Cabinet and approved by Parliament. The EC Act permits the proceeds from the Energy Fund to be applied to:• the promotion of energy efficiency and the productive uses of electricity, natural

gas and petroleum products;• the promotion of projects for the development and use of renewable-energy

resources, including solar energy;• human resource development in the energy sector; and• any other relevant purposes as determined by the Commission.

This implies that most if not all of the EC’s operations can be financed from the fund, which is managed and administered by the EC with the oversight of the finance ministry’s accountant-general. In its management of the fund, the EC is required to determine the fund’s annual targets, formulate policies to generate money for the fund, and determine the allocations made towards its objectives. The EC has generally been adequately funded. This is not surprising given the steady revenue stream guaranteed by the levy on energy services and the extent of the EC’s freedom in the application of the proceeds of the fund.

The PURC Act specifies four sources of funding for the PURC, namely, government subvention, loans and grants, and any monies accruing to the commission in the course of the performance of its functions. Government subvention has been the single-largest source of PURC funding since the organisation’s inception. This is followed by donor funding, which has been sizeable at times given the scope of the projects funded.

The PURC Act does not detail procedures for budget approvals or disbursements. In interviews with PURC management, it was learnt that the PURC approves a budget that is sent to the Minister of Finance for approval. Over the 10-year period from 1999 to 2008, the approved budget was, on average, 47 per cent lower than the amount proposed by the commission. To make matters worse, in six of these years, actual government disbursements fell short of the approved level. Given the shortage of funds, it is not surprising that PURC’s terms and conditions of service are not competitive. Of a total of 51 staff recruited since the PURC was established in 1997, 21 employees had left, with most citing the terms and conditions of service as their reason for leaving.23

In 2010, however, the PURC Act and the EC Act were amended to allow for a levy on the sales of electricity and natural gas to fund the operations of the two agencies (Government of Ghana, 2010). This should improve funding to the two institutions, especially the PURC, which has not had access to the Energy Fund.


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Accountability

Like the other regulators described in this volume, both the PURC and the EC are expected to prepare annual reports including audited financial statements. The financial statements have to be submitted for auditing three months after the financial year end, and the annual report has to be submitted to Parliament within six months of the year end. Similarly, as public bodies, the PURC and the EC are occasionally requested to appear before committees of Parliament to make representations on issues that fall within their mandate, as are most of the other regulators covered in this volume.

As of 2010, the PURC was in the process of developing a clearly defined appeals process for parties that might be aggrieved by its decisions. By law, however, the PURC has final decision-making authority. Although appeals can be lodged with the high court, these can be on matters of a procedural nature only; the courts cannot make a ruling on the substance of a regulatory decision, but may instead request the PURC to reconsider it.

Independence of commissioners

The president of Ghana, in consultation with the Council of State, appoints both the commissioners of both the EC and the PURC, but has to include representatives from various sectors of society, as shown in Table 6.7.

Table 6.7 Commissioners appointed to Ghana’s regulatory bodies

Energy Commission (EC) Public Utilities Regulatory Commission (PURC)ChairExecutive Secretary Representative of National Development Planning CommissionFour other persons with knowledge in matters relevant to the functions of the Commission

ChairExecutive Secretary Representative of domestic consumers Representative from the Trade Union Congress Representative from the Association of Ghana Industries Four other persons with knowledge in matters relevant to the functions of the Commission

Source: EC Act, PURC Act

Tenure for commissioners at both the institutions is five years, renewable without limit. To stagger the terms of office, Clause 5 of Section 5 (Tenure of Office of Members of the Commission) of the EC Act states:

A member of the Commission other than the Executive Secretary shall be appointed for a period not exceeding five years and shall on the expiration of that period be eligible for re-appointment; except that of the members first appointed, the Chairman [sic] and two other members shall hold office for a period of five years, two for a period of four years and one for a period of three years.

This contrasts with the PURC Act, which does not contain any specific provision for the staggering of terms. In practice, however, a change of government has triggered the appointment of new commissioners to the positions of the ‘four other persons


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with knowledge in matters relevant to the functions of the Commission’. Since interest-group representation has tended to remain the stable, this has in effect fulfilled the role of staggering the terms.

Removal from office

Commissioners at the EC and the PURC can be removed from office for repeated absenteeism from commission meetings, inability to perform the functions of their office or any misconduct. In addition, commissioners may be removed for ‘any just cause’. This raises the prospect of arbitrary removal from the commissions, but in practice this has not yet occurred.

Carrying out of administrative functions

The chief executives of the EC and the PURC (known as executive secretaries) are charged with responsibility for the day-to-day administration of both institutions. Section 45, Clause 4 of the EC Act states that: ‘The Executive Secretary shall be responsible for the organisation of the Commission’, thus suggesting that the EC’s executive secretary can determine the size and structure of the institution. For the PURC, the legislation does not specify where this power lies. It is notable, however, that Section 34, Clauses 1 and 2 of the PURC Act and Section 46, Clauses 1 and 2 of the EC Act read as follows:

1. The President may, acting in accordance with the advice of the Commission given in consultation with the Public Services Commission, appoint such officers and employees as may be necessary for the effective implementation of the functions of the Commission.

2. The President may delegate the powers of appointment of public officers in accordance with Article 195 (2) of the Constitution.

This implies that Ghana’s president appoints all staff, and unless this power is delegated to senior management in the regulators, this could cause inordinate delays in the appointment of even relatively junior staff. The difficulty that this provision presents is evidenced by the fact that the PURC is unable to quickly fill vacancies.

Transparency

Like most of the regulators featured in this volume (with the exception of Namibia), the EC’s and the PURC’s board meetings are not open to the public. There is no legislation preventing the meetings from being held in public, but as is the case elsewhere, closed meetings have become accepted practice.

The EC and the PURC use the internet to improve their accessibility and transparency to some degree; both organisations have websites from which information and documentation can be downloaded. There is, however, scope for them to improve the quality of the information they disseminate. For example, although elements of the methodology applied in the determination of tariffs are available on the PURC


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website, some stakeholders were of the view that a fuller disclosure was required. A sustained awareness programme on these and other core regulatory matters could prove useful for the PURC, and may help to change the perceptions held by some stakeholders that the PURC is beholden to the government. This would be in addition to public meetings that the PURC holds across the country when an application for a tariff revision is under consideration. Such a programme could take advantage of the PURC’s novel initiative for engagement with the media – the 10-member press corps comprising journalists from prominent electronic and print-media organisations.

Regulatory substanceWe now explore regulatory substance, focusing on licensing, planning, the setting of tariffs and technical standards, as well as pro-poor interventions.

Licensing

The power to grant licences is arguably the most significant leverage mechanism available to regulatory bodies, as licences facilitate entry into the power sector and are issued with conditions that must be adhered to. The mandate to issue licences in Ghana’s power sector lies with the EC. Section 11 of the EC Act states: ‘Except expressly exempted under this Act, no person shall engage in any business or any commercial activity for: the transmission, wholesale supply, distribution or sale of electricity…unless he is authorised to do so by a licence granted under this Act.’ Furthermore, licences may be granted only to citizens of Ghana, a body corporate registered under the Companies Code or any other law of Ghana, or to a partnership registered under the Incorporated Private Partnerships Act.

As of 2010, the EC issued four types of licence in the power sector:• Wholesale supply and operations licence: This grants authority to the licence-holder

to install and operate facilities to produce or to procure electricity for sale to bulk customers or to a distribution company for onward sale to consumers. A wholesale licence may be issued for thermal or hydro-generation or wholesale supply.

• Transmission licence: In accordance with the EC Act, the EC may grant a transmission licence to a single operator only (referred to in the legislation as the ‘Electricity Transmission Utility’ – a role currently played by GridCo). The licence grants the operator the authority to monitor and control the operation of the national grid for the transmission of electricity within Ghana, and to ensure the safe, reliable and economic dispatch of all electricity generation facilities connected to the grid. The licensee is also required to provide non-discriminatory ‘open-access’ to the grid to all other power-sector licensees, including the power system of the Economic Community of West African States, within relevant international protocols.

• Distribution and sale licence: This grants the licensee the authority to operate an electricity distribution network by means of which electricity can be sold or retailed in a non-discriminatory manner. The distribution licence is specific to a particular area, and its geographical limits and scope are clearly stated. In


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the event that a licensee intends to engage in a similar operation at a different location, or to expand operations beyond the boundaries stated in its current licence, a fresh application has to be lodged with the EC.

• Embedded or distributed-generation licence: This licence is a specialised form of the wholesale licence. It grants authority to generate electricity at an agreed point of injection into the distribution network by means of a ‘small scale’ embedded or distributed generation facility and to sell such electricity to bulk customers, distribution licensees or specific other parties in accordance with agreed terms and conditions, and in line with the national energy policy (Energy Commission of Ghana, 2006a).

Licensing procedure

In order to establish a level of certainty in the energy industry, the EC Act clearly sets out the procedures and timeframes involved in the granting of licences.24 According to Section 14 of the EC Act, applications for a licence shall be granted unless there are ‘compelling reasons founded on technical data, national security, public safety or other reasonable justification which shall be communicated to the applicant’.

As noted, licences are issued with conditions. Section 15 of the EC Act notes that these may require the licensee to interconnect its facilities and installations to any transmission systems to which the licence relates, and to provide the EC with such documents, accounts, estimates, returns or other information ‘in such manner and at such times as may be reasonably required’ to allow the EC to exercise its functions. Licences are not transferable except with the prior written consent of the EC.

Licences are issued for specific periods (see Table 6.8) and may be renewed. The process for renewal is set out in Section 17 of the EC Act. Renewal applications must be lodged at least 60 days before the licence expires. The law states that in the event that a licensee fails to renew a licence or that a renewal application is rejected by the EC, the licensee should cease providing the related service. Given the critical nature of electricity supplies, it would be preferable for the legislation to make specific provision to guarantee the continuity of supply. In Uganda, for example, generation facilities greater than 10 MW revert to the state upon expiry of the licence; and in the event of a suspension or revocation, the regulator is required to take all steps necessary to ensure that there are no interruptions in the electricity supply.

Table 6.8 Licence duration by licence type, Ghana, 2010

Licence Maximum duration (years)Wholesale supply (power generation) 25 (hydro)

20 (thermal)Transmission 20Distribution 20Embedded or distributed generation 15

Source: Energy Commission of Ghana, personal communication (2010)


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The EC may modify licences, but only if this is permissible under the terms of the licence issued or is in the public interest. Prior to undertaking a modification, the EC is required to give at least 60 days’ notice to all parties likely to be affected, stating the effect of the proposed change. These parties have to be granted an opportunity to make representations or raise objections before the modification. Any loss or damage that arises can be expensed as part of the licensee’s capital account.

A licensee that is not complying, or has not complied, with any of the conditions of a licence may have its licence suspended or cancelled by the EC. Prior to this, the EC is required to give notice to the licensee stating the condition (or conditions) not being complied with, and outlining the action that may be taken to resolve the situation. The licensee is then given an opportunity to be heard and, if appropriate, may be granted some time in which to remedy the situation. In effecting a licence suspension or cancellation, the EC is required to take into account the extent to which ‘a person’ (EC Act, Section 19.4) is likely to sustain loss or damage as a result. Licences that have not been used one year from the date of issue may be cancelled provided that the licensee is given at least 30 days’ notice.

Ministerial interventionParties that are aggrieved by a decision of the EC to refuse to grant, renew or modify a licence, or with a decision to suspend or cancel a licence, may lodge a complaint with the Minister of Energy. Curiously, the legislation does not specify the period, from the date of the initial decision, within which such a complaint should be lodged. However, the Minister has 30 days to respond to the complaint, failing which the aggrieved party can seek relief from the high court.

Issued licencesAlthough the EC has been in existence since 1997, by 2010, only the Tema Osonor power plant and Sunon-Asogli Power Company had been fully licensed (for wholesale supply). VRA has long existed as a quasi-autonomous enclave that is, by law, exempt from the licensing of its facilities in the Volta river basin. The other state-owned utilities, ECG and GridCo, were operating under provisional licences. With the major players in the power sector not fully licensed, the EC is not taking full advantage of its mandate, and until it does so, effectively regulating the sector may prove challenging.

Power-sector planning and the procurement of new capacitySection 2(2)(c) of the EC Act states: ‘The Commission shall prepare, review and update periodically indicative national plans to ensure that reasonable demands for energy are met.’ This makes Ghana and Kenya the only two countries discussed in this volume with legislation that clearly allocates responsibility for power-sector planning. In fulfilment of this mandate, the EC produced the Strategic National Energy Plan 2006–202025 in 2006. The plan covers the electricity, petroleum, wood-fuel and renewables sectors; for electricity, the strategic plan identifies three expansion options for meeting projected demand to 2020, as outlined in Table 6.9.


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Table 6.9 Expansion options for Ghana’s electricity sector, 2006–2020Option 1 Option 2 Option 3660 MW gas plant at Takoradi 330 MW gas plant at Takoradi

200 MW Bui hydropower project335 MW nuclear-power station200 MW Bui hydropower project

Plus660 MW gas plant at Tema125 MW Osagyefo Barge at Effasu converted to a 187 MW combined-cycle gas plantPercentage renewables in generation mix: 5 per cent by 2008; 9 per cent by 2015; 10 per cent by 2020130 MW gas-fired co-generation by 2015

Source: Energy Commission of Ghana (2006b)

The development of the strategic plan represents an important step towards securing future electricity supplies. It is surprising, however, that the plan offers three expansion options. This is not beneficial for a sector that demands a level of certainty given the long lead times that are typical from initiating procurement through to the commissioning of a project. While considering options and consulting with stakeholders are integral to the planning process, a single expansion path that incorporates stakeholders’ comments, and allows for some flexibility in dealing with changes in demand forecasts and/or the incorporation of new primary energy sources or technological advancements, is preferable. In addition, although the Energy Commission Act only requires that an indicative plan is prepared, the security of future energy supplies would be enhanced if the strategic plan were to provide some approximate timelines as to when new plants were expected to come on stream and an indication of the party (private sector or VRA/government) to which the development of each plant would be allocated. This would allow procurement processes to be initiated in good time to avoid subjecting the country to further power shortages.

The EC is also the custodian of the IPP solicitation procedure that is activated when there is increased demand by a bulk consumer, growth in demand caused by a distribution company or general system-demand growth and diminishing reserves. However, there is no publicly available document detailing the process that is applied. Moreover, in contrast to the situation in Kenya and Uganda, IPPs in Ghana have, to date, been procured by means of unsolicited bids.26 The lack of competition makes it difficult to reach the best technological and pricing outcomes. In any case, the initiation of the procurement process that competition demands would be greatly aided by a more definitive generation-expansion plan.

Despite the ambiguity of the strategic plan, by 2012 two power generation projects were under construction and the procurement of a further two had commenced, although financial close had yet to be reached, as shown in Table 6.10. The largest of these was the Bui hydropower project (which features in options 2 and 3 of the strategic plan), the construction of which began in 2008 with a re-sized capacity of 400 MW. The potential that the Bui site holds for power generation was identified as early as in the 1920s, and although various feasibility studies were undertaken and potential developers courted, the project remained all but shelved until it was


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unlocked with the assistance of the Chinese government. The project is expected to cost US$622 million, funded by a US$263.5 million concessional loan from the government of China, a US$298.5 million buyer’s credit facility from the Export-Import Bank of China, and US$60 million from the Ghanaian government.27 A special-purpose vehicle, the Bui Power Authority, has been established to manage the construction and operation of the project. The Bui hydropower complex is expected to be commissioned in 2014.

The second project under construction was Takoradi 3, a VRA-sponsored 132 MW combined-cycle thermal-power plant located in the vicinity of the utility’s existing plant, which was expected to be commissioned at the end of 2012. A further two projects, namely, Kpone thermal power plant and Takoradi 2 expansion, were under discussion but had yet to reach financial close.

Table 6.10 Generation project pipeline, Ghana, 2012

Project Capacity (MW) Fuel Status Commissioning date

Bui 400 Hydro Under construction 2014Takoradi 3 132 Light crude oil/gas/

dieselUnder construction 2012

Kpone 230 Gas/diesel Not reached financial close 2015Takoradi 2 expansion

110 Light crude oil/gas/diesel

Not reached financial close 2015

Source: VRA (2012)

Pricing and tariffs

Electricity tariff setting in Ghana is governed by the PURC Act, which requires that utilities set tariffs in accordance with guidelines issued by the PURC. These guidelines are required to take into account: consumer interest; investor interest; the cost of production/the service which the PURC can investigate to determine whether it is just and reasonable; and the assurance of the financial integrity of the utility.

Tariffs cannot be charged by utilities without the approval of the PURC. In addition, the law empowers the PURC to impose uniform tariffs or other charges throughout the country, a region or a district on account of the country’s population distribution, the need to optimise the country’s resources, or due to the economic development imperative.

Based on the provisions of the Act, the PURC in 1999 published its Electricity Rate Setting Guidelines (PURC, 1999), which state that tariff setting in Ghana should take into account:• fair apportionment of the total cost of supply to various classes of consumers and

the provision of a minimum level of service (or lifeline supply) at an ‘affordable’ price to residential customers who may not be able to pay the full cost;

• an appropriate rate of return on investments to satisfy the interests of investors in the national interconnected system;


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• the setting of the bulk-supply tariff to ensure that distribution utilities procure electricity at least cost from wholesale power suppliers for distribution and retail to regulated customers;

• the setting of the transmission service charge to ensure economically efficient, reliable and secure operation of the transmission system by the electricity transmission utility (namely, GridCo);

• the setting of the distribution service charge to ensure the economically efficient, reliable and secure operation of the distribution system by distribution utilities (namely, ECG and NED);

• the provision of adequate revenue to ensure financial viability of the power utilities;• an allowance for ‘special rates’ for priority consumers whose activities may

enhance economic development; and• an allowance for a tariff structure that incorporates uniform rates for all

consumers within a particular category regardless of geographic location.

As a result, the PURC determines separate tariffs for generation, transmission and distribution, with end users paying an aggregation of these charges. Such an arrangement is appropriate given the extent to which the power sector in Ghana has been unbundled.

Generation tariffsIn theory, electricity-generation companies are free to sell electricity directly to large customers, and the power-purchase agreements arising from such transactions are not subject to regulatory control. In practice, as of 2010, generation for domestic consumption was purchased by either ECG or NED, and any surpluses arising from daily system operations were exported.The tariffs that generation companies charge their customers, such as ECG and NED, comprise a capacity charge and an energy charge. The PURC computes VRA’s capacity charge based on the widely used revenue-requirement approach,28 which takes into account the capital cost of VRA’s asset base and a reasonable return on this, plus operational costs and depreciation. VRA’s revenue requirement excludes tax, as VRA is, by law, exempt from this liability. With respect to the rate of return, the PURC contends that it grants VRA eight per cent, although the utility disputes this figure and believes that actual awards are lower. 29

For IPPs, the capacity charge is based on the actual capital costs of the plant, an agreed rate of return, plus fixed operations and maintenance expenses. IPPs are awarded a greater rate of return of between 15 per cent and 19 per cent as a reflection of higher debt-service costs and expected returns on equity.The PURC guidelines define the energy charge as the short-run marginal cost of energy required to meet Ghanaian demand, based on merit-order dispatch from available plant. The key driver of this cost is thus the primary energy source, such as diesel, heavy fuel oil or natural gas. However, in the case of VRA’s Akosombo and Kpong assets, there is no energy charge – this implies that there are no costs associated with the water used for power generation at the two facilities. For electricity derived from thermal sources, the relevant primary energy cost is included in the calculation.


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Individual generation tariffs are then aggregated by means of the bulk-generation charge, which takes into account the prevailing generation mix.

BGC = [X1Hc + X2P2 + X3P3 + X4P4] + nKWhere BGC = bulk-generation charge;X1 = proportion of hydro in generation mix;HC = hydro cost;X2 = proportion of simple-cycle plant in generation mix;P2 = variable energy price of simple-cycle plant;X3 = proportion of combined-cycle plant in generation mix;P3 = variable energy price of combined-cycle plant;X4 = proportion of imports in generation mix;P4 = price of imports;n = proportion of thermal capacity contribution to system demand; andK = system capacity price.

In the event that the forecast generation mix does not materialise, this (depending on the actual mix) is treated as an over- or under-recovery that is deducted or added to the bulk-generation charge in the next period.

Transmission and distribution costs

The PURC guidelines state that the RPI-X regulatory methodology shall be applied in the determination of both transmission and distribution charges (PURC, 1999). In this method, the revenue requirement30 is calculated, on the basis of which, a tariff is awarded for the first year. Subsequently, and for a set number of years (three in this case), the revenue requirement is not recalculated, but prices are adjusted with inflation less (or plus31) an efficiency factor (X) as shown in generic form below:

Pt = Pt-1 × [1+(It-1 ± X)]Where Pt = average price in next period;Pt-1 = average price in previous period;It-1 = inflation index at end of previous period; for example, consumer price index (CPI); producer price index (PPI); andX = efficiency factor.

The revenue requirement component of the transmission service charge includes:• the cost of transmission assets, including additions and less retirements, with

revaluations conducted every five years;• operations and maintenance expenses;• an allowance for losses (at the time of writing, this had been 2.8 per cent since 2000); • ancillary services; and• a rate of return on the assets.32


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For annual adjustments to the transmission service charge, the guidelines provide the following formula:

TSC = Annuity × (1 + CAF) + O&M × (1 + CPI – G) ± QSP

Transmission system coincident peak demand (MW)Where TSC = transmission service charge;Annuity = annuitised rate base;CAF = cost-of-capital adjustment factor;O&M = operations and maintenance expenditure;CPI = US consumer price index;G = productivity (efficiency) factor that takes into account the factors of production (such as labour, materials and transport); andQSP = penalties and rewards for quality of service.

The derivation of the distribution service charge replicates that for transmission. Thus, the revenue requirement components include:• the cost of distribution assets, including additions and less retirements, with

revaluations conducted every five years;• operations and maintenance expenses;• an allowance for losses (set at 21 per cent in 2009 – 10 per cent technical and 11

per cent non-technical);• user fees for metering and billing;• a revenue-collection ratio (set at 95 per cent in 2009); and• a rate of return on assets.

Annual adjustments to the distribution service charge are based on the following:

DSC = Annuity × (1 + CAF) + O&M × (1 + CPI – G) ± QSP

Distribution system maximum demand (MW)Where DSC = distribution service charge;Annuity = annuitised rate base;CAF = cost-of-capital adjustment factor;O&M = operations and maintenance expenditure;CPI = US consumer-price index;G = productivity (efficiency) factor that takes into account the factors of production (such as labour, materials and transport); andQSP = penalties and rewards for quality of service.

Consistent with best practice, distribution assets that arise from the self-help electrification programme, which is jointly funded by the government and consumers, are not included as part of the annuity amount that earns a rate of return. These assets are, however, operated and maintained by ECG or NED, and therefore the PURC does allow for this expense in the distribution service charge.


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The PURC also endeavours to ensure that consumers are charged according to the costs that they impose on the distribution network. For this purpose, two broad categories of consumer are identified in the rate-setting guidelines: low-voltage and medium-voltage consumers. The PURC then determines the ‘appropriate distribution cost allocations in respect of low-voltage and medium-voltage customers in the calculation of the distribution service charge for various end-use customers’ (PURC, 1999: 12).

End-user tariffs

The penultimate step in the tariff-determination process is the calculation of the bulk-supply tariff, that is, the price of electricity at a bulk-supply point.33 This tariff aims to recover capacity and energy charges from generation, plus transmission charges. Thus:

BST = BGC + TSCWhere BST = bulk-supply tariff;BGC = bulk-generation charge; andTSC = transmission service charge.

Finally, the end-user tariff is calculated, using the bulk-supply tariff plus the distribution service charge:

EUT = BST + DSCWhere EUT = end-user tariff;BST = bulk-supply tariff; andDSC = distribution service charge.

Quarterly automatic adjustments

In order to shield the electricity industry from factors beyond its control (primary energy costs, exchange-rate fluctuations and inflation), the PURC instituted an automatic tariff-adjustment regime in 2003. Under this regime, it was expected that the magnitude of the tariff changes that would be effected would be smaller, and hence more amenable for end consumers to cope with, since adjustments would be made quarterly as opposed to the old practice of reviewing tariffs annually or at even longer intervals. The regime allowed the energy charge for thermal generators to be adjusted every quarter based on the following formula:

Padjust = aFP + ßCPI

FP0 CPI0

Where Padjust = adjusted energy price;a = annual fuel coefficient;FP = fuel price; P0 = base thermal variable energy price;34


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FP0 = base fuel price;35

ß = annual CPI coefficient;CPI = USA consumer price index;CPI0 = base consumer price index.

A variation in the base fuel price of ± US$1.50 would initiate the above adjustment.

The distribution service charge also allowed for adjustments in line with exchange-rate fluctuations:

DSCt = DSCt-1 × EXCHt

EXCHt-1 Where DSCt = distribution service charge for next period;DSCt-1 = distribution service charge for previous period;EXCHt = average projected exchange rate for next period;36 andEXCHt-1 = average exchange rate used by the PURC for previous period;

The automatic tariff adjustment regime was discontinued in 2006, however. The reason for this was that, even though crude oil prices surged over the period, no major tariff adjustments were actually required due to better-than-anticipated hydrological conditions, leading to a reduction in the use of fossil fuels in the country’s generation mix and relative stability in the local currency (Cedi) exchange rate with the US Dollar. In addition, the PURC wanted to afford the utilities an opportunity to justify the need for further tariff adjustments.37 The PURC stated that future tariff revisions would be considered on the basis of ‘legitimate costs, external developments in the global energy industry and the operational exigencies of the utility companies’.38

Four years later, in 2010, the PURC announced the re-introduction of quarterly automatic tariff adjustments, citing changes in macro-economic conditions and escalating global crude-oil prices. However, this was not intended to substitute for major tariff reviews, which were expected to take place every four to five years following a detailed evaluation of utility costs.39

Technical standards

Section 27 of the EC Act states that:1. The Commission in consultation with the Public Utilities Regulatory

Commission shall by legislative instrument prescribe standards of performance for the supply, distribution and sale of electricity or natural gas to consumers by licensed public utilities.

2. The standards of performance shall a) in respect of electricity include matters relating to i. voltage stability; ii. maximum number of scheduled and unscheduled outages; iii. number and duration of load shedding periods; and iv. metering.


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The EC is therefore charged with setting standards, while the PURC has a monitoring and enforcement role, as provided for in Section 13 of the PURC Act, which states:

1. The Commission shall monitor standards of performance established by the licensing authorities of public utilities for compliance by public utilities.

2. Where a public utility fails to meet any required standard of performance, it shall pay such compensation as the Commission in consultation with the licensing authority may determine to any person adversely affected as a result of the failure.

3. The requirement for payment of compensation under this sectiona) does not limit the right to any other remedy at law which may be available

to the complainant;b) does not preclude the Commission from taking any other measure or

imposing any other sanction that the Commission has a right to impose in respect of the act or omission that constitutes the failure.

As of 2010, the EC had promulgated the rules and regulations shown in Table 6.11 with respect to the electricity sector.

Table 6.11 Technical rules and regulations of the Energy Commission, Ghana, until 2010

Name of the rule/regulation DescriptionElectricity Supply and Distribution (Technical and Operation) Rules, 2005

Standards for new connections and metering, quality of supply, service outages and billing

Electricity Transmission (Technical, Operational and Standards of Performance) Rules, 2008

Requirements procedures, practices and standards that govern the development, operation, maintenance and use of the high-voltage national interconnected system.

Electricity Regulations, 2008 Sets out the National Grid Code, which establishes the wholesale electricity market, defines the functions and responsibilities of the electricity transmission utility (GridCo) and institutes a market oversight mechanism

Electricity Supply and Distribution (Standards of Performance) Regulations, 2008

Standards for reliability of electricity supply, complaints handling and metering

Source: Energy Commission of Ghana, personal communication (2010)

Based on these standards, the PURC has developed a set of performance indicators for generation, transmission and distribution that it monitors on a daily, monthly, quarterly and annual basis. However, compliance by the utilities with set benchmarks is low. For example, over the period 2005 to 2008, the outage hours per customer for both ECG and NED was higher than the benchmark maximum of 88 hours. Transmission and distribution losses over the same period were also higher than the benchmarks of 2.8 per cent and 21 per cent40 respectively. Non-compliance with set technical standards is a common feature in all the countries covered in this volume. One of the reasons for this could be lax monitoring and enforcement. However, it is possible, as argued by a non-Ghanaian utility, that the standards are too onerous and require extensive retrofits; meeting these would exert upward pressure on tariffs. If this is the case in Ghana, there would be a need for close co-ordination between the PURC and the EC in order that the relevant feedback is obtained from the utilities and the requisite revisions are made, firstly to the standards, and subsequently to the industry performance indicators.


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Improving access to electricity and pro-poor considerations

Ghana has an enviable electricity access rate of 60 per cent.41 This is much higher than the sub-Saharan Africa average of around 20 per cent (Foster & Briceño-Garmendia, 2010). Remarkably, in the early 1990s access was just 24 per cent (World Bank 1993b). The increase in access has been largely due to the 1989 national electrification scheme, which aims to achieve universal access by 2020. Under this scheme, a master plan was developed in which the initial goal was to extend the electricity network to all of the country’s district capitals. Thereafter, electrification projects have been prioritised based on whether an area is a commercial market centre, its potential for industrial and tourism activities, political factors and historical importance. The scheme also subsidises connection charges, the full cost of which can be in excess of US$200. Under the scheme, rural households are required to pay only US$50 for a connection.42 The national electrification scheme is funded by a one per cent levy on electricity sales, as well as by the government and bilateral and multilateral partners. It is housed within the Ministry of Energy.

Complementing the national electrification scheme is the self-help electrification programme that was introduced in the early 1990s. Under this programme, communities that signal commitment to electrification can ‘jump’ the electrification master-plan queue. To qualify, a community must be within 20 km of an existing 11 kV or 33 kV supply that is suitable for further extension, erect all the low-voltage poles required for the local network, and have at least a third of all households wired and ready to receive electricity.

Although poverty levels and overall funding present huge challenges to these programmes, their impact has been impressive. Before 1989, a total of 478 towns and villages were connected to the national grid. By 2008, this figure had risen to 3 448, of which 1 900 had been connected in terms of the Strategic National Energy Plan.43 At this rate, Ghana’s goal of universal access by 2020 might not be far-fetched, but supplying these new consumers with a reliable and good quality service will require ever greater investment in generation and network capacity, and refurbishments of existing plant.

The PURC is not actively involved in making electricity more accessible to the poor. However, the electricity-tariff structure does include a subsidised lifeline tariff. To receive the benefit of a lifeline tariff, consumption cannot exceed 50 kWh per month. As soon as this amount is exceeded, the customer’s entire consumption is subject to the unsubsidised tariff.

ConclusionAs in many other African countries, the greatest challenge facing Ghana’s power sector is attracting new investment to assure current and future electricity supply. Ghana’s has embarked on wholesale reform of the power sector, following the standard model of reform fairly closely. Remarkably, Ghana unbundled its state-owned generating company, VRA, in 2008, when the standard model was on the wane around the continent. This was a bold step and signalled the government’s


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ongoing commitment to reform. Furthermore, the separation of the VRA’s system operations and transmission functions is helping to create a ‘level playing field’ for current and future IPPs. However, major privatisation of the power sector seems unlikely in the near future and, despite the recent proliferation of entities in the electricity sector, the government looks set to remain the dominant player.

As observed in other chapters, hybrid power markets create imperatives for the government, its agencies and the private sector to ensure that all parties have clear roles and responsibilities. In Ghana too, there is a need for clarity in the regulatory system. Independent regulation can play a meaningful role in attracting new investment by providing market access through licensing and ensuring the viability of the electricity industry, while protecting consumers through competitive pricing and ensuring that services are delivered to an acceptable standard. For these functions to be carried out effectively, however, clarity and certainty in the regulatory system are crucial.

In Ghana, the fact that there are two regulatory bodies has the potential to create confusion, and close co-operation between the PURC and the EC is required to make the regulatory system work effectively. For instance, although the PURC sets tariffs and monitors technical standards, the fact that it does not have licensing authority makes it difficult for the PURC to ensure that incentives or sanctions with respect to tariffs and the monitoring and enforcement of technical standards are included in licensing conditions. The EC is also constrained in that it does not monitor or enforce the technical standards that it sets for the sector. Admittedly, the EC plays an important advisory role in relation to the government, but this need not incorporate any core regulatory functions. In our view, the PURC would be strengthened as an independent regulator if it were to assume the role of licensing and technical-standards setting. At the same time, and while maintaining its advisory role, the EC’s planning function could be strengthened to allow it to develop and regularly update more detailed plans. In addition, the EC could assume the procurement function that has not yet been clearly allocated, and which is a crucial aspect of ensuring security of supply in hybrid power markets.

With respect to industry viability, the 1999 Electricity Rate Setting Guidelines (PURC, 1999) imply that tariff adjustments should take place at least annually. However, this has not been the case since 2006 when automatic tariff adjustment was abandoned. It may well be time to revise the rate-setting guidelines. Furthermore, ECG has been shielded from the effects of low tariffs through a direct government subsidy, but this has been done at the expense of VRA. This has eroded the government’s own equity in VRA. Given their sheer size, the financial viability of both ECG and VRA is crucial to the performance of the electricity industry as a whole. The poor financial health of either or both of these utilities will make emergence from the spate of power crises more difficult.

Much has been done to set a new course, and Ghana’s power sector shows considerable promise, but the future of the country’s electricity supplies is not entirely secure.


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Notes1 Personal communication (2009).2 Horizontal unbundling refers to the process whereby one national company would be split

into two or more companies covering separate geographical regions.3 The syndicate consisted of Rose, another engineer and a financial advisor.4 At inception, VALCO was owned by Kaiser Aluminium and Chemical Corporation (Kaiser),

Alcan, Aluminium Company of America, Olin Mathieson and Reynolds Metals. By 1961, only Kaiser and Reynolds Metals remained as shareholders, holding 90 per cent and 10 per cent respectively (Hart, 1980).

5 The hydropower scheme was comparable to the largest in the world at the time (IBRD, 1961b).6 The transmission grid was included in the scope final project and built as planned.7 This marked the first of the World Bank’s loans to Ghana.8 In 1999, a retrofit and uprating of each unit at the plant commenced and, when completed

in 2005, total installed capacity at Akosombo had increased to 1 020 MW.9 Ghana News Agency, Govt, VALCO to talk about power supplies, 20 May 2003,

http://www.ghanaweb.com/GhanaHomePage/NewsArchive/artikel.php?ID=3664910 Akrasi L, Parliament approves sale of Valco shares, The Chronicle, 29 October 2004,

http://allafrica.com/stories/200410290421.html11 By this time, Ghanaian electricity generation was effectively all hydro, since most of the

smaller legacy power stations had been decommissioned.12 The Ghanaian government owns 10 per cent, and CMS Energy owns 90 per cent of the

venture (Malgas, 2008).13 Due to its joint ownership structure, TICO is not strictly an IPP; however, it is frequently

referred to as Ghana’s first IPP.14 Furthermore, three other firms (Global Aero Design, Faroe Atlantic, and Stone & Webster),

which had commenced negotiations but ultimately did not supply any emergency power, also sued the Ghanaian government (Malgas, 2008).

15 That is, in the Brong-Ahofo, Northern, Upper East and Upper West regions.16 See http://vraghana.com/about%20us/more.php17 The progress made included a three per cent reduction in commercial losses, a decrease in

the debtor/sales ratio from 198 to 109 days, the establishment of a decentralised and efficient customer-service system, and the production of accurate monthly bills (World Bank, 2001b).

18 From Edjekumhene et al. (2001).19 Personal communication, 2009.20 See http://www.vraghana.com21 See http://www.ecgonline.info22 Some areas specific to natural gas have been omitted from this list.23 PURC, personal communication, 2010.24 Once an application is lodged, the EC has to acknowledge receipt within 10 days. Thereafter

the EC has a maximum of 60 days to consider the application and inform the applicant of its decision.

25 See http://new.energycom.gov.gh/downloads/Technical%20Reports/SNEP.zip


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26 Personal communication, 2011.27 Selby H, Frequent power outages to be saved by the Bui hydropower dam project, AllAfrica.

com, 25 August 2010. http://allafrica.com/stories/201008260774.html28 RR = RAB × RoR + E + D + T, where RR = revenue requirement, RAB = regulatory asset base,

RoR = rate of return, E = operations and maintenance expenses, D = depreciation and T = taxes.29 PURC, personal communication, 2010.30 RR = RAB × RoR + E + D + T, where RR = revenue requirement, RAB = regulatory asset

base, RoR = rate of return, E = operations and maintenance expenses, D = depreciation and T = taxes.

31 There are cases where regulators find it desirable for prices to rise higher than inflation in such a regulatory regime.

32 At the time of writing, GridCo representatives proposed that the appropriate rate of return be set at 16 per cent (GridCo, personal communication, 2009), but the PURC, quoting a World Bank recommendation, has limited this to eight per cent (PURC, personal communication, 2010).

33 Consumers of large amounts of electricity, such as heavy industry and distribution utilities, are afforded this tariff.

34 This relates to the technology used (that is, simple cycle or combined cycle), and is dependent on the cost of the primary energy used.

35 Based on a widely accessible reference, for example, for liquid fuels, the reference was the price of Bonny Light crude oil.

36 Based on Bank of Ghana projections.37 See http://www.purc.com.gh/purc/sites/default/files/

feburaryautomaticadjustmentformula2011.docx38 See http://www.ghanaweb.com/public_agenda/article.php?ID=572939 See http://www.purc.com.gh/purc/sites/default/files/

feburaryautomaticadjustmentformula2011.docx40 The ECG benchmark is 21 per cent, while the benchmark for NED is 25 per cent.41 PURC, personal communication (2009).42 PURC, personal communication (2009) (exchange rate as at 2009).43 These statistics are from a presentation made by a technical advisor to Ghana’s energy

ministry, Clement Abavana, to the annual meeting of CLUB-ER in Bamako, 8–12 April 2008, http://www.google.com/url?sa=t&source=web&cd=3&ved=0CCcQFjAC&url=http%3A%2F%2Fwww.club-er.org%2Fupload%2FDOCAT306.ppt&rct=j&q=ghana%20self%20help%20electrification%20project&ei=bSEcTvCrL4GYmQXqzt3hBw&usg=AFQjCNEVx7ga_4Ql_gA9dfxjclvyxoh8lQ&cad=rja


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IndexEntries are listed in letter-by-letter alphabetical order . The page references in bold indicate where you can find information in a table. The page references in italics indicate where you will find a figure.

244

1994 Energy Policy, Zambia 133–135

1995 Electricity Act, Zambia 1351998 White Paper on Energy

Policy, Namibia 172–173Aaccountability 12, 35, 68, 105,

148–149, 178–179, 218administrative independence

33–34, 65, 105, 147–148, 177–178, 217

appeals 69, 149, 179asset valuation 156, 184–185Bboard 65–66board independence 176–177board of commissioners 32–33Bujagali hydropower project 85,

94–95, 101CCentral African Power

Corporation (CAPCO), Zambia 131, 132

commercialisation 4, 5–6Consumer Consultative Council

(CCC), Tanzania 70Copperbelt Energy Corporation

(CEC) performance, Zambia 140–141

corporatisation 4, 5–6Ddemand forecast 129, 197–198distribution 100distribution costs 226–229distribution tariffs 42, 114–117,

184drought 21–22, 24, 59, 88–89,

129, 204EEast African Power and Lighting

(EAP&L), Uganda 89–90economic difficulties 3Electricity Act of 2007, Namibia

175, 177Electricity Act of 2008, Tanzania

58Electricity Company of Ghana

(ECG) 196, 204Electricity Corporation of Ghana

204electricity pricing 2Electricity Regulatory Authority

(ERA) 85, 93, 101–107, 108electricity regulatory systems,

framework 9

electricity sector 87, 128–130, 128, 166, 169–172, 197, 199–207

electricity supply 2 electricity tariffs 183–185Energy Africa 171Energy and Water Utilities

Regulatory Authority (EWURA) Act, Tanzania 51, 63–71

Energy Commission (EC), Ghana 196

Energy Commission functions, Ghana 214, 215–216, 218

energy efficiency 16–17Energy for Rural Transformation

(ERT), Uganda 119Energy Regulation Act, Zambia

141Energy Regulations Board (ERB),

Zambia 127, 141–144Energy Regulatory Commission

(ERC), Kenya 30–36environmental issues 16–17Eskom, Namibia 170Eskom, Uganda 93, 98–99, 112–

113, 113Ffinancial independence 34–35, 65,

146–147, 177–178, 217Ggeneration capacity 98, 129, 129,

166–167, 197–198generation tariffs 4, 184, 225–226Ghana 195–232

accountability 218administrative independence

217commission independence

218–219demand forecast 197–198distribution costs 226–229drought 204Electricity Corporation of

Ghana (ECG) 196, 204electricity milestones 200electricity sector 197, 199–207Energy Commission (EC) 196,

214, 215–216, 218financial independence 217generation capacity 197–198generation tariffs 225–226Ghana Power Sector

Development Policy 209–211

GridCo 196 hybrid power market 211–212

licensing 220–222management contracts

207–209ministerial intervention 222National Energy Board (NEB)

207new capacity procurement

222–224performance indicators 213power crisis 204, 205–206power sector development

pricing 207–213, 210, 222–224

pricing 224–225Public Utilities Regulatory

Commission (PURC) functions196, 214, 215–216, 218

regulatory governance 213–220

reservoir overdrawing 204–205standard reform model 209,

209–210tariffs 224–225technical standards 229–231thermal generation 205transmission costs 226–229transparency 212–220Volta Aluminum Company

(VALCO) 203Volta river project 199–204Volta River Authority (VRA)

195, 196, 202, 203, 204Ghana Power Sector Development

Policy 209–211Government Consultative Council

(GCC), Tanzania 70GridCo, Ghana 196Hhybrid power markets 6Iimportation of services 4independence 11Independent Power Producer

(IPP) 6Independent Power Tanzania

Limited (IPTL), Tanzania 58IPPs, Kenya 29Itezhi-Tezhi hydro plant 128KKafue 131Kariba Dam 131Kariba North Bank 127KenGen 22, 26, 28, 28Kenya 21–47


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245

accountability 35accounting standards 31administrative independence

33–34board of commissioners 32–33distribution tariffs 42drought 21–22, 24electricity access 44–45electricity industry 22, 23Energy Regulatory Commission

(ERC), Kenya 30–36financial independence 34–35geothermal energy 27, 28hydropower 21IPPs 29KenGen 22, 26, 28, 28Kenya Electricity Transmission

Company (KETRACO) 26Kenya Power and Light

Company (KPLC) 22, 23, 29

legal independence 32licensing 37, 37performance monitoring 31power-sector planning

regulatory impact 43–45pricing 38–42regulatory substance 36–43rule making 31staffing 33–34Stima Loan 45subsidiary policy 31tariffs 38thermal energy 35–36transmission tariffs 41–42wind power 27, 28, 30

Kenya Electricity Transmission Company (KETRACO) 26

Kenya Power and Light Company (KPLC) 22, 23, 29

Kudu gas-to-power project 170–171LLake Victoria 85, 94licensing 37, 37, 71–72, 108–110,

150–152, 180–181, 181, 220–221MMtwara Energy Project 60NNamibia 165–190

1998 White Paper on Energy Policy 172–173

accountability 178–179administrative independence

177–178 appeals 179asset valuation and tariffs

184–185board independence 176–177code of ethics 179cost containment 184

demand-side management 187–188

distribution tariffs 184Electricity Act 180Electricity Act of 2007 175, 177Electricity Council Board

(ECB) 165electricity sector 166, 169–172electricity tariffs 183–185Energy Africa 171energy policy 172Eskom 170financial independence

177–178generation capacity 166–167generation tariffs 184grid code 187Kudu gas-to-power project

170–171legislation 174–175licensing 180–181, 181, 182–183local authority surcharges 185low-income customer

initiatives 187NamPower 165Premier Electric 174pro-poor tariffsRegional Electricity

Distribution Company (RED) 174, 181

regulatory governance 175–180regulatory substance 180–188renewable energy 188resource planning 185–186retail tariffs 184sector performance 168–169South West Africa Water and

Electricity Corporation (Pty) Ltd (SWAWEK), Namibia 169

technical standards 186–187third-party access 182–183transmission tariffs 184transparency 179–180Windhoek 169

Namanve Power Station 95NamPower 165National Energy Board (NEB),

Ghana 207NETgroup 55–57new capacity procurement 152–

154, 153, 222–224PPeer Learning Network 6–7, 8performance monitoring 31, 127,

213power markets 18–19power-purchase agreements 14power-sector decline 3power-sector development pricing

209–211

power-sector planning 110–111, 152–153, 153, 222–224

power-sector reform 53, 89–97, 130–137, 207–213

power-sector reform model 4, 5power-sector restructuring 4, 5predictability 12Premier Electric, Namibia 174pricing 38–42, 74, 111–117, 224–225pro-poor regulation 16pro-poor tariffs 79, 118–119,

159–160proportionality 12–13Public Utilities Regulatory

Commission (PURC) functions, Ghana 196, 214, 215–216, 218

RRegional Electricity Distribution

Company (RED), Namibia 174, 181

regulatory governance 9, 9,10, 63, 141–150, 175–180, 213–220

regulatory impact 9, 17–18regulatory independence 65, 65,

144–148regulatory substance 9, 13, 13,

36–43, 71–78, 107–119, 150–160, 180–188

Rural Electricity fund (REF), Uganda 93

Ssector performance 138–139,

168–169South West Africa Water and

Electricity Corporation (Pty) Ltd (SWAWEK), Namibia 169

Stima Loan 45Strategic Plan of 1998, Uganda

91–93subsidiary policy 31, 143supply quality 15–16TTanzania 51–81

accountability 68administrative independence 65appeal processes 69board 65–66budgeting sources 67–68Consumer Consultative

Council (CCC) 70drought 59Electricity Act of 2008 58electricity industry 52, 52emergency power supplies 59Energy and Water Utilities

Regulatory Authority (EWURA) 51, 63–71

Energy Regulatory Commission (ERC), Kenya 30–36


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financial independence 65functions 64funding sources 67–68generation planning 73generation procurement 74Government Consultative

Council (GCC) 70Independent Power Tanzania

Ltd (IPTL) 58industry restructuring 73legislative framework 63licensing 71–72Mtwara Energy Project 60NETgroup 55–57powers 64power-sector reform 53pricing 74pro-poor regulation 79public information 70–71regulatory governance 63regulatory impact 78–80regulatory independence 65, 65regulatory substance 71–78service standards 79staff 65–66stakeholder engagement 69–70Tanganyika Electricity Supply

Company (TANESCO) 54–57, 60

tariffs 62, 62, 77–78thermal energy, Kenya 35–36transparency 69–70

Tanganyika Electricity Supply Company (TANESCO) 54–57, 60

tariffs 15, 38, 62, 62, 77–78, 111–117, 142–143, 154–157, 224–225

technical standards 159, 117–118, 186–187, 229–231

thermal energy, 35–36, 206transmission tariffs 41–42, 99,

184, 226–229transparency 11, 69–70, 107,

149–150, 179–180, 212–220transparent regulation 4UUganda 85–121

accountability 105administrative independence

105Bujagali hydropower project

85, 94–95, 101bulk-supply tariffs 114distribution 100distribution tariffs 114–117drought 88–89East African Power and Light

(EAP&L) 89–90Electricity Disputes Tribunal

85, 106–107

246


appeals 149asset valuation 156Central African Power

Corporation (CAPCO) 131, 132

Copperbelt Energy Corporation (CEC) performance 140–141

cost-of-service model 155cost-reflective tariffs 155demand forecast 129dispute adjudication 144drought 129Electricity Regulatory Board

(ERB) 127, 141–144electricity sector 128–130, 128electricity-sector assets 135–137Energy Regulation Act 141ethics 150financial independence 146–147financial performance 139–141generation capacity 129, 129Itezhi-Tezhi hydro plant 128Kafue 131Kariba dam 131Kariba North Bank 127key performance indicators 157licensing 150–152market access 150–152new capacity procurement

152–154, 153performance indicators 127power-purchase agreements

143, 157–158power-sector planning 152–

153, 153power-sector reform 130–137privatisation of mining 135–137pro-poor initiatives 159–160regulatory governance 141–150regulatory independence

144–148regulatory substance 150–160rule making 143rural electrification 159–160sector performance 138–139subsidiary policy 143tariff setting 142–143tariffs 154–157technical standards 159transparency 149–150Victoria Falls 131

Zambia Electricity Supply Corporation (ZESCO) 127, 131, 132, 135, 137, 139–141, 156–157

ZESCO, Zambia 127, 131, 132, 135, 137, 139–141, 156

Electricity Regulatory Authority (ERA) 85, 93, 101–107, 108

electricity sector 87emergency power 96–97Energy for Rural

Transformation (ERT) 119Eskom 93, 98–99, 112–113, 113generation 98investment procurement

110–111Lake Victoria 85, 94licensing 108–110load shedding 97, 101Namanve Power Station 95post-reform performance

97–101power sector reform 89–97power-sector planning 110–111pricing 111–117pro-poor initiatives 118–119public participation 107regulatory substance 107–119Rural Electricity Fund (REF) 93Strategic Plan of 1998 91–93tariffs 111–117technical standards 117–118transmission 99transparency 107Uganda Electricity Board

(UAB) 85, 91, 93Uganda Electricity Board

(UAB) 85, 91, 93Uganda Electricity

Distribution Company Ltd (UEDCL) 86, 93, 116

Uganda Electricity Generation Company Ltd (UEGCL) 86, 93, 116

Uganda Electricity Transmission Company Ltd (UETCL) 93, 99, 111, 114

VVictoria Falls 131 Volta Aluminum Company

(VALCO), Ghana 203Volta River project 199–204Volta River Authority (VRA),

Ghana 195, 196, 202, 203, 204WWindhoek 169World Bank 3World Bank policies 4ZZambia 127–161

1994 Energy Policy 133–1351995 Electricity Act 135 accountability 148–149 administrative independence

147–148


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POWER SECTOR 5 · Figure 2.1 overview of Tanzania’s electricity industry, 2010 52 Figure 2.2...

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