energy for africa draft study PIDA Study: Phase I Volumes

NEPAD African Union AfDB

C1354 - March 2011 Ref: ONRI.1/PIDA/2010/04

in consortium with

Study on Programme for Infrastructure Development in Africa (PIDA)

Phase I ReportDRAFT

PHASE I ENERGY SECTOR

Study on Programme for Infrastructure Development in Africa (PIDA) Phase 1

SOFRECO Led Consortium : SOFRECO –MWH – NATHAN – SOFRECOM – SYSTRA – ASCON - CABIRA

PIDA Study: Phase I Volumes

Energy Sector

Introduction to PIDA

Phase 1 Overview

Transport Sector

TWRM Sector

ICT Sector

Annexes

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SOFRECO Led Consortium : SOFRECO –MWH – NATHAN – SOFRECOM – SYSTRA – ASCON - CABIRA

FOREWORD

The PHASE I work was carried out by Jean François BAUER (Program Leader), Ananda COVINDASSAMY (Energy Leader), Bernard CHATELIN (Transport Leader), Olivier COGELS (Transboundary Water Resources Leader), Claude de JACQUELOT (ICT Leader) with the support of their respective teams and coordinated by Hichame SELMAOUI (Project Director).

It has taken place in good conditions with the constant support form the PIDA stakeholders: African Union Commission (AUC), NEPAD Planning and Coordinating Agency (NPCA), African Development Bank (AfDB), the Regional Economic Communities (RECs) and the Technical Institutions (Lake and River Basins Organisations –L/RBOs- and Power Pools).

The Consultant would like to express their most sincere thanks to all those who have provided their precious time and advice during this part of the work.

This report is the DRAFT report on Phase 1 of the PIDA Study. The interaction with the stakeholders during the forthcoming meetings will be the opportunity to validate the diagnosis and the assumptions used in modelling.

The PIDA Study is a long term planning exercise. It has been carried on the basis of assumptions, namely that in the coming years the major policy weaknesses in the sectors will be resolved.

In the Transport sector, it is assumed that all the corridors would have reach full efficiency through major changes, including:

The well documented and generally accepted trade facilitation measures are successfully implemented;

The credit worthiness of the railways is restored;

The Yamoussoukro decision is implemented continent wide.

In the Energy sector, the primary assumption concerns the restoration of the credit worthiness of the utilities by the return of the payment discipline in the private and the public sector.

In the Transboundary Water sector, it is assumed that the African countries who share international rivers, lakes and aquifers will have the required political will to mandate and support their basin organizations for the preparation, implementation and operation of optimal joint investments in a shared benefit approach.

In the ICT sector, the main assumptions are the end of monopoly situation on terrestrial infrastructure and on international gateways, with “right of way” provisions for landlocked countries to reach landing stations.

If these policy changes are effective, it is the considerate opinion of the Consultant that the projections presented in this report paint a plausible future for Africa and its regional infrastructure.

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ENERGY Sector - Report I : Policies

SOFRECO Led Consortium : SOFRECO –MWH – NATHAN – SOFRECOM – SYSTRA – ASCON - CABIRA 1

PART I: POLICIES

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2 SOFRECO Led Consortium : SOFRECO –MWH –NATHAN –SOFRECOM –SYSTRA –ASCON -CABIRA

Table of Contents

1. OBJECTIVE AND APPROACH..............................................................................3 1.1 Objectives ...................................................................................................................................................................................... 3 1.2 Approach ........................................................................................................................................................................................ 3

2. SCOPE OF EXISTING CONTINENTAL AND REGIONAL POLICIES .............. 5 2.1 Africa’s Energy Policy-Making Organizations..........................................................................................................5 2.2 Continental Policies................................................................................................................................................................. 6

2.2.1 AUC’s Policy Coordination Role......................................................................................................................7 2.2.2 Large Scale Hydro Development .................................................................................................................11 2.2.3 New and Renewable Energy Sources......................................................................................................12

2.3 Regional Policies......................................................................................................................................................................13 2.3.1 Objectives ...................................................................................................................................................................13 2.3.2 Regional Power Pools .........................................................................................................................................13 2.3.3 Regional Gas Integration .................................................................................................................................23 2.3.4 Regional Cooperation in Petroleum Product Supplies................................................................25

2.4 Policy coherence table .......................................................................................................................................................25 2.4.1 Coverage of Regional Electricity Policies.............................................................................................25 2.4.2 Areas not addressed by Regional Energy Policies........................................................................28

3. STATEMENT CONCERNING THE LEVEL OF ACHIEVEMENT OF POLICY OBJECTIVES .........................................................................................................29

3.1 Methodology of evaluation ...............................................................................................................................................29 3.1.1 Specific Policy Indicators ................................................................................................................................29 3.1.2 Policy Impact Indicators .................................................................................................................................. 30

3.2 Level of achievement by policy.................................................................................................................................... 30 3.2.1 Level of Achievement of Continental Policy Objectives ..............................................................31 3.2.2 Level of Achievement of Regional Policy Objectives ...................................................................32 3.2.3 Level of Achievement of Regional Gas Integration Objectives .............................................35

3.3 Policy Achievement Table.................................................................................................................................................36

4. CAUSAL ANALYSIS .............................................................................................38 4.1 Analysis of Legal and Regulatory Policies .............................................................................................................38 4.2 Analysis of Planning, Operational and Commercial Policies.................................................................... 40 4.3 Regional Electricity Integration: Causal Analysis Synthesis........................................................................41

4.3.1 Energy Security Concerns ...............................................................................................................................41 4.3.2 Regional Autonomy versus National Autonomy ...............................................................................42 4.3.3 Staffing and Funding Weaknesses in Regional and Continental Institutions ..............42 4.3.4 Constraints to Mobilizing Financial Resources.................................................................................42

4.4 Regional Gas Integration: Causal Analysis............................................................................................................43

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1. OBJECTIVE AND APPROACH

1.1 Objectives

The basic objective of the review is to assess the effectiveness of continental and regional energy policies in supporting the integration of energy infrastructure across the African continent.

The review will focus on the effectiveness of different policy initiatives in supporting the integration of Africa’s electricity infrastructure

It will also include an assessment of policies aimed at bringing about the integration of the continent’s natural gas infrastructure. 1.

1.2 Approach

The proposed analytical approach was described in Section 3 of the Inception Report of July 2010. It envisaged a number of steps in assessing the adequacy of existing continental and regional policies against the primary goal of promoting regional energy trade.

The first step involved a review of the scope of existing continental and regional energy policies-as of December 2010- in each of the five regions of Africa.

This information was to be obtained from three main sources:

Visiting the websites of the main continental (AUC) and regional (RECs and Power Pools) institutions responsible for formulating energy policies;

Reviewing the main presentations and/or protocols on regional energy policies agreed by the Conference of African Energy Ministers or between key donors such as the ADB or EU,

Field visits to the Infrastructure and Energy Department of the AUC as well as to a selective number of Regional Economic Communities (RECs) and Power Pools.

The second step involved a review of the extent to which the policy objectives in each region have been achieved, in particular their effectiveness in increasing regional energy trade. This review involved a comparative analysis of existing regional electricity legislation in each of the five regions in Africa against benchmarks generally agreed as essential for establishing successfully operating power pools in other regions of the world.

The analysis focused in particular on policy gaps in the existing legislation of different regions and whether such policy gaps were deterring regional electricity trade.

The third, and final, step of the approach focused on the limiting factors that are impeding achievement of regional energy integration. This review focused on several different factors- including, inter alia, legislative, regulatory, grid code harmonization, financial solvency of

1 Objective listed in the Maputo Declaration of 2010

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national utilities, and energy security concerns in individual countries- that were judged to be impeding further regional energy integration in specific regions.

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2. SCOPE OF EXISTING CONTINENTAL AND REGIONAL POLICIES

2.1 Africa’s Energy Policy-Making Organizations

The African Union Commission (AUC) is the Secretariat of the African Union (AU) and the principal organization for the promotion of socioeconomic integration across the continent. Within the AUC organization, the Infrastructure and Energy (IE) department is the entity responsible for carrying out the AUC’s objectives in energy. The specialized institutions in energy under the AUC i.e. AFREC, AFUR and AFSEC, are intended to be the main instruments for facilitating the energy objectives of the AUC while the United Nations Economic Commission (ECA) and the African Development Bank (ADB) and the NEPAD Secretariats provide advice and support, respectively, to the AUC in its policy coordination activities.

In the area of policy-making, the AUC has responsibility for defining continental-wide polices and strategies on infrastructure development2.

The role of the Regional Economic Communities (RECs) in the energy sector is to promote cooperation between member states in order to develop integrated and cost effective energy infrastructure in support of regional economic development, and particularly regional trade.

The RECs have a primary responsibility for developing a policy and planning framework to achieve the goal of regional cooperation in energy. A key component of the RECs’ strategy is establishing regional power pools to help reduce the cost of energy supply while improving its reliability and security.. The regional power pools have primary responsibility for coordinating, harmonizing, and enforcing the operational rules and standards needed to achieve this goal.

The organizational relationship between these different entities is shown in Figure 1.1 below.

AFUR, African Forum for Utility Regulators

AFREC, African Energy Commission (AFREC)

AFSEC, African Standards Electro-Technical Commission

ECA, Economic Commission for Africa

NEPAD, New Partnership for Africa’s Development

2 Coordination Mechanism for the Development of Infrastructure in Africa, Department of Infrastructure and Energy, African Union, October 2007

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2.2 Continental Policies

The main Continental Policy Objectives have been articulated in different conferences and assemblies of the African Union (AU) since 2000 and reaffirmed recently by Africa’s Ministers in charge of energy in the Maputo Declaration of November 5, 2010.

These objectives are to develop efficient, reliable, cost effective, and environmentally friendly infrastructure for the physical integration of the continent and to enhance access to modern energy services for the majority of the African population. These objectives would be achieved by

Developing major regional and continental hydroelectric projects;

Implementing high capacity oil refineries and oil pipeline projects; and

Developing renewable energy resources.

The main objectives and policy initiatives are summarized below:

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OBJECTIVES STRATEGIC POLICY INITIATIVES

Ensure energy security for economic and social development

Through developing fully Africa’s energy resource potential – in hydropower, petroleum, geothermal, coal, and renewable energy

Achieve energy integration by increasing regional and continental energy trade

Through fostering regional and continental cooperation and by highlighting the importance of regional projects, especially electricity interconnections

Lower the cost of energy to improve access to basic energy services for Africa’s population

Through diversifying the energy mix and by pooling national energy resources so as to deliver energy production at affordable costs

Create a conducive climate for direct investment

Through harmonizing legal and regulatory frameworks for energy trade

Reduce Greenhouse Gas (GHG) emissions and address climate change issues

Through promoting the development of renewable energy, in particular solar energy

2.2.1 AUC’s Policy Coordination Role

The Constitutive Act of the African Union of July 2000 stipulates in Article 13 that the AUC should ‘coordinate policies and take decisions in the fields of energy, industry and mineral resources in view of their importance for Africa’s development’.

AUC sees its role, therefore, as a coordinator and facilitator of regional energy integration whose main responsibilities are to harmonize regional energy policies across the African continent, point out discrepancies, and identify policy bottlenecks. The importance of AUC’s coordination role needs to be seen in the context of the report by UNECA3 , which identifies the lack of coordination between the RECs as an impediment to continental integration since they confine their activities to their own regions, without interaction with other regional areas.

Two guiding principles govern the modus operandi of the AUC in its policy coordination role 4.

The first guiding principle is derived from the Constitutive Act of the African Union which is based on solidarity i.e. to “achieve greater unity and solidarity between African countries and the peoples of Africa”, which implies a sharing of resources.

The second guiding principle is that of subsidiarity between the African Union Commission and other regional and continental institutions in working towards the continent’s development and integration, particularly in regard to the Regional Economic Communities, which remain the pillars of this integration process.

Within the framework of these guiding principles, the African Union Commission has taken the following policy initiatives:

Continental Policy on Electrical Energy for Africa

Regional economic integration and the development of integration infrastructure were identified as two priority areas for action and provision was made for the elaboration of a continental policy on electrical energy5;

3 Report of the Expert Group Meeting on the Ten Year Capacity Building Programme for the African Union, November 2-3, 2010, Addis Ababa 4 Coordination Mechanism for the Development of Infrastructure in Africa, Department of Infrastructure and Energy, African Union, October 2007 5 AUC Strategic Plan, 2004-2007, (Strategic Plan of the Commission, Volume 2);

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Preparation of a report entitled “Common Vision and Strategic Guidelines for a Continental policy relating to the Electrical Energy Sector”, with the following recommendations: (i) to work together to develop Africa’s resources, especially hydropower; (ii) to establish a Coordination Commission for the development of major, integrative,

hydroelectric projects6 ;

Guideline Document for Continental Policy in the Field of Oil and Gas7

The main objective was to develop an African Policy of Cooperation and Solidarity in terms of Hydrocarbons while the main decision taken was to establish an African Petroleum Fund (APF)to assist African oil importing countries.

The issues that would be addressed in developing this policy included:

Proposing strategies for cooperation between African producing and importing nations;

Defining strategies to develop the exchange of oil products between African countries;

Making recommendations on major infrastructure projects for the storage, transport and distribution of oil products; and

Defining the role to be played by major oil companies operating on the African continent as well as by IFIs and donors.

Policy Objectives on New and Renewable Sources of Energy8

The main action agreed was to establish a high level, ministerial policy advocacy group to lead the implementation of the Plan of Action that was outlined in the earlier Dakar Conference, April 16-18, 2008, “Making Renewable Energy Markets Work for Africa”.

6 1st African Union Conference of Ministers responsible for Electrical Energy, March 20-24, 2006, Addis Ababa, Ethiopia; 7 First African Union Conference, Ministers responsible for Hydrocarbons, December 11-15, 2006, Cairo, Egypt 8 African Union Assembly, 12th Ordinary Session, February 1-3, 2009, Addis Ababa, Ethiopia, ‘Infrastructure Development in Africa

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Continental Policy Log Frame

OBJECTIVES

Socio-economic STRATEGIC POLICY

INITIATIVES EXPECTED RESULTS

INDICATORS RISKS and

ASSUMPTIONS

SOURCES OF VERIFICATION

A. Sustain economic growth of 6% p.a.

B. Reduce poverty 50% and facilitate Africa’s integration into global economy

Sector Specific 1. Ensure energy security Develop fully

Africa’s resource potential – esp. large-scale and integrating regional and continental

hydro schemes

Development of hydroelectric hubs

A.West Africa-Niger/Senegal rivers

B.Central Africa- Inga/Congo river C.Southern Africa -Mozambique/Zambezi

D.East Africa-Ethiopia/Nile

Coordination Commission for major hydro is established

ncreased electric. production from Inga or reg.hub

Inter regional power purchase agreements signed

Interconnection of reg. power pools

HIGH Risk. Project management weak and no political consensus to strengthen it. Also, first new production increment from Inga may not be for export to SADC.

Key Assumption:

SNEL management team in place 2012

Annual progress reports on Inga production and other large hydro schemes as provided by donors (ADB, IDA)

2. Achieve regional integration in energy Foster sub-

regional, regional and continental cooperation in energy through pooling of resources

Increased regional electricity trade;

West Africa Gas Pipeline is operational

Number of new regional interconnections in power and gas

Share of power traded in each REC

SUBSTANTIAL Risk.

Key Assumptions

In SADC, national agencies willing to cede planning decisions to regions;

In ECOWAS, political stability in key member nations

Regional power pool annual reports

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OBJECTIVES Socio-economic

STRATEGIC POLICY INITIATIVES

EXPECTED RESULTS

INDICATORS RISKS and

ASSUMPTIONS

SOURCES OF VERIFICATION

3. Lower the cost of energy in order to improve access for the majority of the African people

Promote efficient use of energy infrastructure by diversifying the continent’s energy supply

Development of Africa’s large hydro resources to displace higher cost oil imports

umber of new hydro sites developed;

Share of hydro in Africa’s power generation

SUBSTANTIAL Risk Key Assumptions:

Adequate project management and financing mobilization capacity

Regional power pools and donor reports

4. Promote good governance and harmonize regulations Strengthen and

harmonize legal and regulatory frameworks

Direct private investment in regional electricity

Total PSI investment in regional electricity trade

SUBSTANTIAL Risk

Uneven regional progress to date

Key Assumptions:

SADC and ECOWAS regions successful in attracting PSI for regional projects and sector creditworthiness established in most countries

SAPP and WAPP annual reports

5. Reduce GHG emissions Promote renewable energy potential, especially hydro, geothermal and Sahara solar energy

Finalize studies on development solar potential of Sahara;

Extend studies to other areas of African continent;(iii) Launch geothermal risk mitigation fund

Establish ministerial advocacy group;

annual investment in renewable energy as % of investment derived from fossil fuel sources

HIGH Risk.

Progress in Africa in developing renewable energy slow

Key Assumptions:

Private investors can be mobilized for large hydro schemes and solar energy plants

AU/COMELEC renewable energy monitoring data

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2.2.2 Large Scale Hydro Development

Exploiting the large, untapped hydropower potential of the African continent is the cornerstone of the AU’s strategy to provide low cost electricity to the large numbers of the continent’s population still without access to basic energy services as well as to enhance energy security. The strategy envisages the development of four main hydroelectric hubs (see MAP):

West Africa on the Niger (and Senegal) rivers;

Central Africa on the Congo river, in particular the Grand Inga scheme;

Eastern Africa, the Nile river basin development; and

Southern Africa, the Zambezi river basin development.

A program of integrated development of hydro resources and electricity connections is envisaged to minimize transaction costs, attract investment, and promote energy security9. In support of this concept, as noted in Section 2.2, the first Conference of African Ministers responsible for Electrical Energy10committed itself to support the integrated development of the continent’s power potential through the following actions:

Expedite establishment of a ‘Coordination Commission’ for the development of major integrating hydro power projects;

Expedite the integrated development of the major hydropower potential located at four poles of the continent: Niger, Congo, Nile and Zambezi river basins;

Expedite the interconnection of regional power pools into a continental network.

MAP: Africa’s Four Main Hydropower Hubs

Source: African Union. Infrastructure Consortium for Africa Annual Meeting 2009, Rome, Italy

9 Infrastructure Development in Africa, African Union Assembly, 12th Ordinary Session, 1-3 February 2009, Addis Ababa, Ethiopia 10 Addis Ababa, Ethiopia, March 20-24, 2006

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2.2.3 New and Renewable Energy Sources

Africa’s potential for developing new and renewable energy resources, in particular the solar energy of the Saharan desert and other semi-arid areas of Africa, has been recognized at successive African Union Conferences. The main plan of action for developing the continent’s renewable energy potential emerged from the high level Dakar Conference in April 2008 and was reaffirmed in the Maputo Declaration of November 2010.

The April 2008 Dakar Conference on ‘Renewable Energy in Africa’ adopted a declaration with the goal of raising US$ 10 billion for renewable development during the period 2009-2014. It also drew up a plan of action to create the enabling environment for this investment and to help mobilize the needed financial resources for the program. The AUC, in partnership with UNIDO, was entrusted with responsibility for follow up and monitoring. The following specific actions were proposed:

Establish a high level policy advocacy group at the ministerial level to lead the implementation of the Dakar Plan of Action;

Promote the establishment of New and Renewable Sources of Energy technologies at the regional level in order to make these technologies more affordable;

The harnessing of Africa’s solar energy potential for electricity generation has been given increased attention since the Dakar conference. In February 2010, a resolution on solar energy in the Sahara was adopted at the Assembly of the AU heads of state11 while in November 2010 the Conference of Africa’s Energy Ministers issued a resolution on a solar energy study, which called for ‘close cooperation for the development of solar energy in general and the technologies for utility scale electricity generation in particular’12. In January 2011, an AFREC workshop in Algeria sponsored by the AUC provided an overview of the study plan and layout for harnessing the solar potential of the Sahara desert and the Sahel region13.

Solar The main project concept for developing the solar energy potential of the Sahara is the Desertec project. The objective of the Desertec project is to develop clean, sustainable and climate friendly energy sources from the deserts in North Africa using concentrating solar power (CSP) technology. The solar-based electricity would be supplied to regional markets in Africa and exported to Europe. The project concept is on a massive scale and envisages up to $400 billion investment over the period 2020-2050. Though the concept has been under development for a number of years, it has received further impetus since 2007, with strong European support.

Geothermal Africa’s geothermal potential is concentrated in the Rift Valley countries and is estimated as high as 14,000 MW14. However, less than 200MW of this potential has been developed for electricity generation, mainly in Kenya which had an installed capacity of 167 MW in 2010. While geothermal development has been exclusively for national electricity markets, the geothermal potential, if fully exploited, could also benefit regional markets, in particular in Eastern Africa. With this objective in mind, the Maputo Conference of Energy Ministers committed itself to support the regional cooperation program for geothermal energy development in Eastern Africa15 and requested the AUC ‘launch operationalization’ of the Geothermal Risk Mitigation Fund in Eastern Africa16, the purpose of which is to support the exploration drilling needed to establish the geothermal reserve potential of this region.

11Resolution N° Assembly/AU/Res.2 (XIV) adopted by the AU Heads of State and Government held in Addis Ababa in

February 2010 on the Solar Energy in the Sahara. 12 Resolution on Solar Energy Study, Conference of African Ministers in charge of Energy, 1-5 November 2010, Maputo,

Mozambique; 13 AFREC Workshop on the Study of Harnessing Solar Energy Potential of the Sahara Desert for Electricity Generation,

Algiers, Algeria, January 4-6, 2011 14 Infrastructure Development in Africa, African Union Assembly, Addis Ababa, 1-3 February, 2009 15 Article 25, paragraph e, Maputo Declaration, Maputo, Mozambique, 5 November 2010 16 Article 27, paragraph d, Maputo Declaration, Maputo, Mozambique, 5 November 2010

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2.3 Regional Policies

2.3.1 Objectives

Regional energy policies are aimed at strengthening regional cooperation in the development and utilization of Africa’s energy resources to encourage energy trade. Key socio-economic objectives of the regional economic communities in fostering energy trade have been to support strong economic growth as well as increase access to basic energy, which is fundamental to attaining the longer-term goal of eradicating poverty.

The main focus of such cooperation to date has been on increasing electricity exchanges between neighbouring African countries in order to provide a reliable supply of electricity at a lower and more affordable cost for consumers17. The longer-term goal is to develop regional electricity markets, which would be eventually linked throughout the African continent. Regional cooperation in developing the continent’s growing natural gas potential has also been receiving attention- though more recently.

2.3.2 Regional Power Pools

The strategy adopted by most regional areas of Africa for cooperation in the energy sector has been to create regional power pools. Experience in developing regional power pools in Europe and North America, and more recently in Central America, has recognized the importance of having an adequate policy framework to help achieve the goals of regional integration –namely, lower cost electricity, improved reliability and quality of supply, and enhanced security of supply.

An adequate policy framework, comprising a number of steps or building blocks as shown in Figure 1-2, is important for regional electricity integration and, eventually, for establishing successful operating power pools18.

Figure 1-2: Policy and Institutional Framework for Regional Electricity Integration

In addition, building adequate institutional capacity, addressing energy security concerns, enforcing financial discipline and securing a clear mandate from member countries to plan for and implement regional investments are also essential inputs. Conversely, the absence of

17 The first energy interconnections in Africa date from the 1950s with (i) 220 kV transmission line between Zambia and

the copper producing state of Katanga, DRC; (ii) Kariba South hydroelectric plant (666 MW) and transmission line (330 kV) to Zambia and Zimbabwe. In West Africa, there have been several decades of cross-border electricity trading through bilateral and trilateral agreements even prior to the establishment of the Economic Community of West African States (ECOWAS) in 1979. In North Africa, gas pipeline connections, integrating Algeria with Europe via Tunisia and Morocco, date from the 1960s

18 USAID Sub-Saharan Africa’s Power Pools: A Development Framework. White Paper, 2008

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these building blocks limits electricity trade and poses obstacles to the expansion of a regional market.

These building blocks provide useful reference points against which to measure progress in putting in place the needed policy and institutional framework to foster electricity trade and develop competitive regional electricity markets.

Regional Energy Policies in the Southern Africa Development Community (SADC)

The overall goal of the energy sector in the SADC region is to ensure the availability of sufficient, reliable, least-cost energy services that will assist in the attainment of economic efficiency and the eradication of poverty whilst ensuring the environmentally sustainable use of energy resources19.

The SADC region has a long history of regional electricity integration between its member states. Since 1995, the main policy steps taken and agreements reached by the SADC member states to promote regional cooperation in the energy sector have been the following:

Regional Power Pool Created 1995 (SADC Summit, Johannesburg, South Africa, August 28 1995)

Energy Protocol 1996 (SADC Energy Protocol, August 1996), which provided the legal and policy framework for cooperation in energy. The Energy Protocol aimed at harmonization of national and regional energy policies; cooperation in energy development energy pooling; ensuring the provision of reliable and sustainable energy services; promoting joint development of human resources and organizational capacity building; and cooperation in research, development, dissemination and transfer of low-cost energy technologies.

SADC Energy Cooperation Policy and Strategy/SADC Energy Sector Action Plan (SADC Council of Ministers in 1996 and 1997 respectively), which made the SADC Energy protocol operational. The sub-sectors for cooperation were petroleum, natural gas, electricity, coal, renewable sources, wood fuel, and energy efficiency and conservation.

Regulatory Policy (2002) SADC Energy Ministers established the Regional Electricity Regulators Association of Southern Africa (RERA) as a formal association of electricity regulators in July 2002 and it was officially launched in Windhoek, Namibia in September 2002. RERA's broad mission is to facilitate the harmonization of regulatory policies, legislation, standards and practices as well as to be a platform for effective cooperation among energy regulators within the SADC region with following strategic objectives:

- Capacity Building & Information Sharing;

- Facilitation of Electricity Supply Industry Policy, Legislation, and Regulations; and

- Regional Regulatory Cooperation.

SADC Regional Indicative Strategic Development Plan (2004) emphasized co-operation in infrastructure development. The strategies for achieving this goal in energy were:

- In the Electricity Sub-sector, promoting power pooling through the extension of grid interconnections; and consolidating the transformation of the Southern African Power Pool (SAPP) from a ‘co-operative’ pool, involving bilateral power purchase agreements and coordinated dispatch between countries, to a ‘competitive’ power pool, where dispatch is based on the least- cost merit order;

19 SADC, RISP, Chapter 3, Energy

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- (ii) In the Petroleum and Gas Sub-sector, promoting joint exploration and development of resources; and cooperation in the joint procurement of petroleum products.

Improving energy access is a major goal of energy policy in all SADC Member States. However, within SADC, improving energy access is fundamentally a national rather than a regional responsibility. Efforts made at the regional level are largely supportive of endeavours at the level of Member States.

The log frames below (in Figure 1-3) provides a summary of the main regional policy initiatives of SADC and of SAPP aimed at strengthening regional energy integration. These are shown together with the results expected from these policies, as indicated in the different policy and planning documents of SADC and SAPP.

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Fig 1-3 SADC Region: Regional Policy Log Frame

SAPP OBJECTIVES SAPP POLICY INITIATIVES

EXPECTED RESULTS

INDICATORS RISKS and ASSUMPTIONS

SOURCES of VERIFICATION

Develop world class, robust, safe, efficient, reliable and stable interconnected electrical system in SADC region.

Operational and market rules for regional market;

Competitive electricity market linking all member states by 2012

Spot trading market for electricity exists

Private sector investment (PSI) in regional grid


.All member states commit to regional integration

Regional investment climate conducive to PSI

Spot market risk accepted by PSI

SAPP Annual Market Reports

Co-ordinate and enforce common regional standards of Quality of Supply; measurement and monitoring of systems performance

Common technical and operational standards for interconnected grids

Technical standards agreed on for grid harmonization; .System operator coordinates electricity exchanges/trade

Similar technical standards for trading countries;

MODEST Risk

Key Assumptions:

SAPP given enforcement powers to exact common standards

SAPP Annual Reports

Harmonize relationships between member utilities

Capacity building programs

All member states have planning and regulatory capacity

Bi-annual national investment plans ; 2 National regulatory agencies

MODEST Risk

Key Assumptions:

SAPP has resources for training programs

SAPP Annual Reports

Increase power availability in rural communities

Regional planning framework

70% access for rural households by 2018

Rural access connections

HIGH Risk

Key Assumptions:

Member states have financial resources and management capacity for rural connections

SAPP and SADC regional energy data

Implement strategies in support of sustainable development

Environmental policy guidelines

Environmental assessments undertaken for all regional investments

Environmental impact assessment (EIA) reports

MODEST Risk

Key Assumptions:

SAPP given authority to enforce guidelines

SAPP Reports on Environment

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Regional Energy Policies in Western Africa Region (ECOWAS)

The first step towards regional coordination of energy activities in the ECOWAS region was taken in November 1981 at the symposium, ‘Energy for Survival’, in Freetown, Sierra Leone, which addressed the severe energy issues affecting the 16 member states at that time. Since 2000, regional energy policies in the ECOWAS region have been focused on providing a vision of energy cooperation to 2015, which is shared by member states, and aimed at improving the condition of the ECOWAS rural and peri-urban populations.

The policy steps towards this goal have been the following:

West Africa Power Pool (WAPP) was created in 1999 as a regional power pooling mechanism for integrating national power system operations into a unified regional electricity market. In July 2006, WAPP was formally inaugurated as a regional organization comprising both public and private electric power utilities of the ECOWAS region. 20

ECOWAS Energy Protocol, January 2003, provides the legal framework for cross-border power trading in West Africa. This Protocol aims at promoting long-term co-operation in the energy field, with a view to achieving increased investment in energy and increased energy trade in the West Africa region. Key provisions of this legislation include (i) Protection of foreign investments, (ii) Non-discriminatory conditions for trade in energy, and (iii) Dispute resolution procedures.

Regional Regulator, January 2008. The ECOWAS Regional Electricity Regulatory Authority (ERERA) was established in Accra, Ghana, with the following objectives:

- Develop technical regulations for the management of electricity exchanges between interconnected systems in the ECOWAS region and monitor their application;

- Monitor wholesale electricity sales between various buyers from member States and analyze their efficiency with a view toward avoiding antitrust problems;

- Develop dispute resolution procedures; and

- Establish effective communication between governments, regulators, and electricity companies of member States.

ERERA has two roles:

Regional regulator for cross-border exchanges;

Agency providing assistance to national regulatory entities to ensure regional and national regulations is complementary.

A White Paper Regional Energy Policy was published in October 2005, and subsequently adopted in January 2006, outlining a strategy for increasing access to energy services in rural and peri-urban populations to help achieve the MDG goals. The White paper reflects the commitment of 15 West African member states to a shared energy policy aimed at bringing about a fourfold increase in access to energy over a 10-year period i.e. by 2015.

Since 2008, ECOWAS has been putting in place the core building blocks for successful regional electricity integration21 - namely, a transparent and harmonized policy framework of legal, regulatory and technical standards; a clear institutional framework for regional planning;

20 The Southern African Power Pool (SAPP), with more than 15 years of operational involvement in regional

electricity trade, has helped shape the policy and institutional development of Africa’s more recent regional power pools – in West Africa (1999), in East Africa (2005) and in Central Africa (2003)

21 World Bank Document, Report Number 48877-AFR: Additional Financing for the Felou Hydroelectric Project of the West African Power Pool (APL) Program. July 30, 2009

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and the elaboration of a priority regional investment program. This policy framework is summarized in the log frame below (Figure 1-5) together with the expected results and related indicators.

Fig. 1-5 ECOWAS REGIONAL ENERGY POLICY LOG FRAME

WAPP OBJECTIVES WAPP POLICY INITIATIVES

EXPECTED RESULTS



1. Develop power generation and transmission facilities through regional collaboration with emphasis on cross border projects

Regional planning framework agreed by member states

Regional investment plan prepared, financed and implemented

Four-fold increase in access by 2015

Annual investment plans

Consumer connections


All member states commit to regional investment plan

Capacity/financing to implement plan

WAPP Regional plans and ECOWAS Member State National Plans

2.. Improve the reliability of power system and quality of power supply in the region

Regional planning framework for grid strengthening

Reduction in power outages for interconnected systems

Improved frequency stability for interconnected links

Annual power outages for interconnected system;

Frequency stability data on interconnected links

SUBSTANTIAL Risk

Key Assumptions:

Priority given to investment for power system improvements

WAPP is able to enforce technical and operating standards

WAPP annual Electricity data

3. Create attractive environment for investment

Regional legal and regulatory policy

Private investment in regional generation projects

Level of private investment in regional projects

SUBSTANTIAL Risk

Key Assumption:

Regional investment climate and utilities’ creditworthiness conducive to private investment

ECOWAS data on private investment

4. Create common operating standards and rules

Grid code policy for interconnected grids

Trading countries adopt common standards

Key operating rules and equipment used for interconnections

SUBSTANTIAL Risk

Key Assumption.

Funding available to enable adoption of common standards

National technical data of trading countries

5. Create transparent and reliable mechanism for dispute resolution

Regulatory Guidelines

Regulatory agency set up with requisite authority to resolve disputes

Disputes are satisfactorily resolved

SUBSTANTIAL Risk

Key Assumption

ERERA has needed expertise and independence

ERERA documents

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Regional Energy Policies in Eastern and Southern Africa (COMESA)

The main objective of regional energy policies is to ‘make available for the Eastern African region affordable and reliable electricity by pooling together all available electrical energy resources in the region in an optimized and coordinated manner in order to increase the access rate to electricity and thereby promote regional integration’. Article 3 of the MOU gives emphasis to ‘increased power trading’ and to ‘development of an electricity market in the East Africa region’.

Since 2005, the main policy steps in the COMESA region- Common Market for Eastern and Southern Africa- towards establishing a framework for regional energy cooperation have been:

East Africa Power Pool (EAPP) 2005. It was set up as a specialized institution under COMESA. The initial membership of EAPP comprised the seven countries – Burundi, Egypt, Ethiopia, DRC, Kenya, Rwanda and Sudan- that were signatories to the original intergovernmental MOU22 . Ten utilities from these countries subsequently signed inter-utility MOUs. EAPP’s main responsibilities are:

- Planning- elaborating an investment plan for generation, transmission and distribution of electricity;

- Regulatory-facilitating the introduction of a regulatory framework for cross border electricity trade in Eastern Africa; and

- Capacity Building- coordinating technical assistance and capacity building initiatives to support integration of electricity markets in Eastern Africa.

The East African Community (EAC), comprising Kenya, Uganda and Tanzania, announced its intention in 2007 to establish a sub-regional power pool by constructing interconnections between these countries.

COMESA Energy Programme, December 2005. The main purpose was to promote regional cooperation in energy development, trade and capacity building. The focus of the COMESA Energy Program was on:

- Energy policy and regulatory harmonization;

- Development of regional energy infrastructure;

- Facilitation of trade in energy; and

- Capacity building and co-operation with regional and international organizations as well as with technical institutions.

COMESA Model Energy Policy Framework, April 2008. Its main purpose was to provide COMESA member States with guidelines that would facilitate energy policy harmonization in the region to improve efficiency and increase investment. This document emphasized close cooperation in the development of the region’s energy resources in the following areas:

- Joint exploration/exploitation of hydro and fossil fuels;

- Development of a mechanism for facilitating trade in energy fuels, such as coal, natural gas, petroleum and electricity; and

- Interconnecting national electricity grids.

Regulatory Policy. A regulatory framework is under preparation and expected to be completed in 2011.

22 Potential member countries of the EAPP are Uganda, Djibouti, Eritrea and Libya, with Libya due to become a member on November 27, 2010.

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Fig. 1-6 COMESA REGIONAL ENERGY POLICY LOG FRAME

EAPP OBJECTIVES EAPP POLICY INITIATIVES

EXPECTED RESULTS



1. Increase power supply for the COMESA member countries in order to increase access rate of population to electricity

Put in place regional planning framework

Increased investment in regional electricity projects;

Installed capacity matches demand

Ratio regional investment to total national investment

Available regional power capacity (MW)


Adequate capacity and financing for increased investment program

EAPP planning documents and COMESA Member State National Plans

2. Facilitate long term development of regional electricity market

Put in place a legal, regulatory and commercial framework for electricity exchanges with well-defined market rules

Increased number of electricity interconnections;

Market developed in short term energy trade

Number of new regional electricity interconnections

Share of regional power trade in total generation

SUBSTANTIAL Risk

Key Assumptions:

Member states commit to regional integration

Investment climate conducive to PSI

EAPP and COMESA data on regional electricity trade

3. Optimize usage of the region’s energy resources

Regional investment planning gives priority to hydro development

Region’s main hydro potential is developed, especially Gibe

New regional hydro capacity(MW)

SUBSTANTIAL Risk

Key Assumption:

Project management/ financing found for large hydro schemes

EAPP planning documents and donor reports

4. Reduce electricity cost in the Region by using power system interconnection and increasing power trade

Harmonize operating and technical standards

Reduced outages and increased stability of electricity supply

Key operating rules and equipment used for interconnections

SUBSTANTIAL Risk

Key Assumption.

Funding available to improve quality of electricity supply

EAPP and country utility reports on regional networks

5. Create conducive investment environment for investment

Regulatory and commercial policies

(PSI)Private sector investment in regional generation projects

Volume of PSI in regional integration investments

SUBSTANTIAL Risk

Key Assumption:

Regional investment climate conducive

COMESA and EAPP investment data

Regional Energy Policies in the Central Africa Region (ECCAS)

The Economic Community for Central African States (ECCAS) was created in late 1983 with 11 member states. Within the ECCAS region, there is significant potential for developing abundant, low cost, hydroelectric resources, especially in the DRC, where development of the massive hydro-potential of Inga is underway. The region’s enormous hydro potential provides a strong economic rationale for regional electricity integration, not only within the ECCAS region

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but also with adjoining regional economic communities and power pool networks. As noted above, DRC is a member of both the ECCAS and COMESA regional economic communities, which facilitates the development of regional electricity integration strategies between regions, especially in regard to the development of the hydro potential of Inga. The basic policy objective in the ECCAS region is to develop a regional electricity market in order to provide more reliable and lower cost electricity to consumers. Since 2003, the following agreements have been reached with ECCAS member countries towards this objective:

Regional Power Pool, January 2003 The Central African Power Pool (CAPP) was established as a specialized institution of ECCAS. Currently, CAPP has 10 members since Burundi joined the East African Power Pool. A key objective of CAPP is to develop a regional electricity market to provide more reliable and lower cost electricity supply to consumers in ECCAS states.

Legal Agreements, April 2003 Two legal agreements have been signed by member States:

- Inter-Government Framework Agreement;

- Inter-Utility Agreement.

The Inter-government Framework Agreement defines the members of CAPP as ‘any public, private, or semi-public enterprise engaged in electric energy generation, transmission or distribution of electricity in Central African states’.

These agreements also established the current institutional framework for CAPP with its Permanent Secretariat based in Brazzaville, Congo.

A five year Action Plan (2006-2010) for CAPP has been prepared with two main activities: (i) identification of priority interconnection investments in ECCAS; (ii) technical assistance aimed at (a) putting in place a legal framework for the regional electricity sector; (b) addressing different technical issues such as harmonization of operating rules; (c) establishing a regulatory framework; and (d) drawing up a capacity building program for technical and regulatory staff.

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Fig. 1-6 ECCAS REGIONAL ENERGY POLICY LOG FRAME

CAPP OBJECTIVES CAPP POLICY INITIATIVES

EXPECTED RESULTS



1. Develop the enormous hydroelectric potential of Central Africa to meet demand for electricity both within and outside region

Regional planning framework gives high priority to Inga hydro development

Significant electricity generated from Inga is transmitted for regional trade

Available capacity from Inga for regional electricity exchanges

HIGH Risk

Key Assumptions:

1.Political stability in DRC ;

2. Management capacity and finance mobilized

3. Creditworthiness of utilities and governments

ECCAS, SNEL and donor reports

Develop a regional electricity market to provide more reliable and lower cost electricity supply to consumers in ECCAS

Legal, regulatory, and commercial framework

5 yr action plan to identify priority interconnections

Increased regional interconnections 2.Electricity exchanges within ECCAS region as well to SADC region

Share of electricity trade in ECCAS region

SUBSTANTIAL Risk

Key Assumptions:

Institutional capacity and finance available

ECCAS and CAPP documents

Increase access rate of the population in the ECCAS region

Regional plans give priority to increased consumer access

Consumer access rate improved over 5yr period

Consumer access in key ECCAS countries

HIGH Risk

Key Assumptions:

Sustained investment priority given to access

ECCAS , CAPP and national utility data

Improve the reliability and the quality of electricity supply in the ECCAS region

Common technical and operating standards

Reduced outages and improved frequency control on regional transmission links

Annual outages and frequency fluctuations in key transmission links

HIGH Risk

Key Assumptions:

Institutional capacity and finance available

to enforce compliance

ECCAS technical reports and national utility data

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Regional Energy Policies in North Africa Region, COMELEC

Regional energy trade in North Africa involves primarily trade in natural gas- from Algeria to Europe via transit countries, Tunisia and Morocco. Presently, trans-border trade in electricity between the North African countries and Europe is negligible. Algeria is about to resume exports by trading on the Spanish short-term market, while Morocco purchases electricity by trading in the same market. Bilateral electricity trade between the Maghreb countries is very small and has not grown significantly since 2005.23

The three Maghreb countries are substantively self sufficient in electricity generation with the exception of Morocco, which imports around 10% of its requirements. There is also an important subsea electricity link between Morocco and Spain, built with an initial capacity of 700 MW that has since been expanded to 1400 MW. The subsea link is a vital component of the larger Mediterranean Electricity Ring (Med Ring) concept, which aims at linking Mediterranean countries. In addition, there is an electricity transmission link between Tunisia and Libya but negligible trade between these countries. Finally, Egypt is a large generator and consumer of electricity, though electricity and natural gas exports are small.

In contrast to Sub-Saharan Africa, a regional power pool organization has not been formed in the North Africa region; nor have policy steps been taken to put in place a legal, regulatory, or planning framework for regional trade. Instead, electricity links have first been constructed, followed by bilateral exchange agreements between adjoining countries. With key infrastructure links now in place, the potential for growth in electricity trade in the Maghreb region. However, any future trade growth is likely to be determined more by (i) further availability of Algeria’s large gas reserves for the Maghreb region (and for Moroccan power market, in particular) and (ii) decisions to upgrade the capacity of the transmission network through Morocco to Spain than by putting in place a regional policy or planning framework to encourage electricity trade in North Africa.

2.3.3 Regional Gas Integration

Recent meetings of the African Union have recognized the scope for increasing inter-African trade in natural gas and have emphasized the need for regional cooperation to help develop the continent’s rapidly growing gas potential.24 In contrast to the North African region that already has a well developed gas transmission and distribution network, the AU meetings noted the high proportion of flared gas in sub-Saharan Africa i.e. 25% of worldwide gas flaring, which could be captured and used to generate low cost electricity, thereby reducing global environmental damage from the flaring of gas.

The growing awareness of Africa’s undeveloped gas potential has led to a series of agreed objectives and related actions to exploit this potential:

Establishing a framework to capture and distribute the flared gas to African countries as well as for export;

Expediting the West African Gas Pipeline;

Expediting development of the Trans Saharan Gas Pipeline that would export Nigerian gas to Europe and eventually serve as backbone to expand gas supply to surrounding African countries.

The African continent’s natural gas resource base can be grouped into three main regional areas:

North Africa, comprising the main producing country, Algeria, but also Libya and Egypt;

23 ‘Regional Energy Trade in the Maghreb Region’. Economic Consultants Associates, September 2007 24 Infrastructure Development in Africa, African Union Assembly, 12th Ordinary Session, 1-3 February 2009

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West Africa, comprising the largest producing country, Nigeria, as well as other producing countries such as Equatorial Guinea in the Gulf of Guinea and recently offshore Ghana;

East Africa, where current production is small in comparison with other regional producing areas but where a string of recent offshore gas discoveries in Tanzania, and particularly Mozambique, hold promise for converting this region into an important gas hub, with potential for LNG export to Asian and Middle Eastern markets25.

The differing gas integration challenges of each of these three regional areas are briefly discussed below.

A. North Africa Despite its long production history, Algeria remains one of the main growth areas in gas production in the African continent, though with a primary focus on expanding gas exports to Europe through new pipelines to Italy and Spain that are either already completed, or close to completion; new LNG export facilities are also under construction. In 2009, Algeria accounted for 40% of Africa’s gas production. 26 Smaller volumes of Algerian gas are supplied to Maghreb transit countries (Tunisia and Morocco) via existing gas infrastructure. For example, gas is supplied via a short spur line from the main gas trunk line from Algeria to Spain to a newly constructed 384 MW Tahaddart combined cycle power plant in Morocco. In Libya, gas production in 2009 represented 7.5% of Africa’s total gas production. The main markets for Libyan gas are export markets via pipeline to Italy and LNG export. Finally, Egypt has become an increasingly important gas producer, with its share in Africa’s total gas production having doubled-from 15% to 30% over the past 10 years. However, Egypt is facing greater challenges than other North African countries in balancing surging domestic gas demand with gas for export, even though new export outlets have been recently opened- to Israel, Jordan and into Syria.

B. West Africa This region is emerging as an important natural gas provider in the world market with proven gas reserves having increased by 50% since 199927. Nigeria is the main gas producer, which has been mainly for LNG export28 though domestic gas demand in new power generation is growing rapidly. Equatorial Guinea completed construction of its first LNG production facility in 2007 while the first LNG facility in Angola is expected to come on stream in 2012. The export of natural gas from Nigeria to adjoining West African countries of Benin, Togo and Ghana via gas pipeline has been under consideration for more than 20 years but was only recently completed in early 2010. In general, local and regional gas markets and infrastructure is underdeveloped in the West Africa region though the potential for expanding these markets is considerable, assuming sustained economic growth in the region.

Nigeria, which accounts for more than a third of Africa’s proven gas reserves and about 15% of the continent’s current production, has been in discussion with Algeria and Niger about the construction of a 4,200 km Trans-Saharan gas pipeline that would be connected to European markets. Approximately 400 bcm, or 8%, of proven reserves have been put aside for this project. The project is still at the early planning stage with a tentative start-up date of 2015.

In Ghana, recent oil and gas discoveries in the offshore Jubilee and other fields have opened up the prospect of additional gas resources, not only for the expanding domestic gas market in Ghana but also for adjoining regional markets in Cote D’Ivoire and other West African countries.

C. East Africa Until recently, gas production in this region has been small, mainly in Tanzania, where it has been used for domestic power generation. However, since 2008, increased exploration activity not only in Tanzania but also offshore in Mozambique and onshore in Uganda has led to significant gas discoveries, which could open the possibility of these gas discoveries being developed and transported to regional markets in the Eastern and Southern

25 Africa Energy February 18, 2011 26 BP Statistical Review of World Energy, June 2010 27 BP Statistical Review of World Energy, June 2010 28 Nigeria accounted for 10% of world LNG trade in 2007. IEA, Natural Gas Market Review 2008

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Africa regions as well as for LNG export. In the short term, the main task will be to firm up more precisely the gas potential of these recent discoveries. The longer term challenge will be to put in place a gas utilization strategy that includes the necessary gas infrastructure to supply domestic, regional and export markets.

2.3.4 Regional Cooperation in Petroleum Product Supplies

Recent global energy crises have had severe repercussions on the economies of Africa’s oil importing countries. Several recent analyses have shown that those countries most vulnerable to oil price shocks are low income oil importing countries, which are disproportionately concentrated in Sub-Saharan Africa.29

Africa’s vulnerability to oil price hikes has been recognized for many years. Together with long recognized inefficiencies in the downstream oil sector, it has prompted a keen interest in setting up regional storage and distribution facilities to reduce inefficiencies in the procurement and distribution of petroleum products.30 All productive sectors of an economy can benefit from an efficiently managed downstream petroleum sector, none more so than Africa’s transport networks and power sectors, where costs are already high for a variety of other reasons. At the same time, the small market size of many African economies makes it difficult to achieve efficiency in the downstream petroleum sector, a reality which provides a strong incentive for regional cooperation in the refining, procurement, and distribution of petroleum products.

With this objective in mind, the following actions were proposed at the AU Conference of Ministers in Cairo in 200631, and reaffirmed at the Maputo Conference of Energy ministers in November 201032, to help promote more regional cooperation in Africa’s downstream oil sector.

Establish a strategic framework for cooperation in regional oil procurement, utilization of refineries, storage and distribution facilities;

Expedite the operationalization of the African Petroleum Fund (APF), which is intended to mitigate the effects of the increase in oil prices on African oil importing countries by establishing a high level Task Force Group that ‘will advocate on APF’;

Past studies on Sub-Saharan African economies have provided an indication of the substantial savings that could be realized from more efficient procurement practices in the acquisition of petroleum products, if all sub-Saharan African countries were to adopt such procurement practices.33 The same rationale can be applied to the potential benefits from regional cooperation in oil procurement, particularly for small, oil-importing economies, for which the cost of vital petroleum products remains very high.

2.4 Policy coherence table

2.4.1 Coverage of Regional Electricity Policies

The policy framework being put in place to govern the operation of Africa’s regional power pools follows closely worldwide experience in developing successful regional power pools, especially in Europe and in North America.

29 Petroleum Markets in Sub-Saharan Africa. Masami Kojima et al. ESMAP, World Bank, March 2010 30 First AU Conference of Ministers Responsible for Hydrocarbons, Cairo, Egypt, December 11-14, 2006 31 First AU Conference of Ministers Responsible for Hydrocarbons, Cairo, Egypt, December 11-14, 2006 32 Article 25, paragraph d, Maputo Declaration, November 1-5, 2010 33 First World Bank Workshop on the Petroleum Products Sector in Sub-Saharan Africa, ESMAP, September 2001

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For the most part, these power pools are at a relatively mature stage in terms of operating experience, the size of electricity market, consumer income levels, and the volume of electricity traded.

In contrast, with the exception of the Southern African Power Pool (SAPP), Africa’s experience with power pools is much more limited while the volume of electricity traded is still very small In 2005, the share of regional electricity trade in each of the regional power pools was as follows: SAPP (9.7%); WAPP (5.1%); EAPP (0.9%); and CAPP (0.1%). Since 2005, the shares have declined further, most notably in SAPP where electricity imports fell to below 4% in 2008/200934. It is important, therefore, to keep in mind the current context of Africa’s power pools in assessing the adequacy and completeness of the policy frameworks.

A consensus has emerged in regard to the main policy and institutional building blocks needed to develop a competitive, regional electricity market, including the sequence in which they should be put in place.

The main policy frameworks that have been implemented, or are in the process of being implemented, by Africa’s regional power pools are shown in the Table below. In addition to each particular policy area, the Table also highlights key sub-components that have been incorporated into the policy frameworks of successful regional power pools and that are considered important provisions in realizing the objective of each policy area.

34 www.sapp.co.zw/docs/annualreports

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REGIONAL ECONOMIC COMMUNITY (POWER POOL) ENERGY POLICIES

AUC SADC

(SAPP)

ECOWAS

(WAPP)

COMESA

(EAPP)

ECCAS

(CAPP)

COMELEC

LEGAL

Inter Government MoU

Inter Utility MoU

Regional Law or Energy Protocol X

Private party access/direct purchase X ? X X

REGULATION

Regulatory Institution X X X

Regulatory Guidelines X X X

Regulatory Independence X X X X

PLANNING

Organizational Structure X X

Regional Integration Plan X X

Plan Implementation Mandate X X X

OPERATIONAL

Grid Code X ?

Systems Operation X X X

Regional Dispatch X X X X

COMMERCIAL

Market Rules X X

Yes

X No

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The general conclusion from a review of the above table is that each of the broad policy areas - legal, regulatory, planning, operational, and commercial- are important steps towards establishing a basic framework for regional electricity trade for the following reasons:

First, there is a need for legal agreements between member governments of the power pool to enable the utilities of each country to negotiate contracts for power exchanges and provide guarantees on issues of payment obligations, currency convertibility, and arbitration. A regional legal framework is also important to create a favourable investment climate, protect against monopoly abuse, clarify conditions of access to the grid, and provide mechanisms to resolve disputes.

Second, a separate regulatory framework for regional trade is also needed. In contrast to national regulation, which has a priority focus on protecting the consumer, regional regulation focuses on measures needed to create and protect electricity trade.

Third, regional investment plans that address future generation capacity requirements of the region as well as strategic cross border interconnections need to be prepared and an institution designated- normally the regional power pool- to prepare such plans.

Fourth, harmonization of grid codes and the operating rules of interconnected networks are fundamental to realizing the full benefits of electricity exchanges.

Finally, basic commercial rules governing electricity exchanges need to be defined, irrespective of whether these involve bilateral cooperative contracts or electricity trade in a competitive market.

2.4.2 Areas not addressed by Regional Energy Policies

Notwithstanding the importance of the areas covered in the policy frameworks shown in the Policy Coherence Table, the effectiveness of these policies in fostering regional electricity trade is being constrained by a number of issues. These issues relate to the balance of responsibilities between regional and national agencies in expanding regional electricity trade as well as the adequacy of the incentives for private sector investment in regional electricity networks. More specifically, the main issues that need to be clarified include:

Decision making authority for regional investment plans between regional planning agencies and national utilities or planning authorities;

Responsibilities for mobilizing finance, implementation, and monitoring of priority regional generation and transmission investments;

Regulatory authority and the independence of regional regulatory agencies

Incentives to encourage an increased presence of private providers- and purchasers- of electricity in regionally integrated networks.

Underlying these policy concerns in the planning and regulatory frameworks is a more fundamental concern- namely, reluctance on the part of national agencies to cede authority to regional agencies for planning, regulation, and enforcement of regional grids. While there are more serious, non-policy, constraints impeding the growth of regional electricity trade as discussed in Section 4, the unwillingness to delegate clear planning, regulatory, and operational authority to regional agencies highlights some of the difficulties that still need to be overcome in promoting regional electricity integration.

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3. STATEMENT CONCERNING THE LEVEL OF ACHIEVEMENT OF POLICY OBJECTIVES

3.1 Methodology of evaluation

The main energy policies required for developing a competitive regional electricity market are summarized above in Section 2.4 (Figure 1.8 Policy Coherence Table). Collectively, they provide a framework against which to measure progress being made towards the objective of increased electricity trade in Africa’s regional economic communities (RECs). For this purpose, specific indicators of evaluation have been selected for each policy dimension.

3.1.1 Specific Policy Indicators

Legal and Regulatory

Regional Legal Framework Inter-government and inter-utility MOUs signed by all member countries/utilities. Regional legislation approved by all member countries addressing access to grid, dispute resolution etc.

Regional Regulatory Framework-regulatory agency formally established and minimum staff in place; guidelines drafted and approved by member countries; independent relationship with national regulators;

Systems Planning and Operation

Regional Organizational Structure-an organizational structure, with adequate staff and budget, is in place with responsibility for planning, developing, and operating regional electricity interconnections;

Regional Planning Framework- an agreed framework is in place for preparing regional investment plans, which are reviewed/approved by member countries; the implementation of national investment programs is based on the least cost regional investment plan;

Regional Systems Operation-a framework in place, with agreed set of operational rules, to harmonize technical standards between interconnected networks; a systems operator is in place and responsible for day to day electricity trade;

System Operator with Minimum Capabilities- e.g. a database to measure/monitor basic information associated with bilateral electricity trade;

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Commercial Framework

Regional Market Rules- key principles governing commercial electricity exchanges between two or more countries are defined and agreed; power purchase contracts are concluded between trading countries;

Dispute Resolution Mechanisms-legal framework provides a clearly defined mechanism for dispute resolution of electricity trade transactions; satisfactory resolution in practice of disputed electricity transactions;

Utility and Country Creditworthiness- national utilities are financially solvent and can enter into power purchase contracts and Government can provide political risk guarantee;

Regional Investment Climate-conducive to encourage private investment in regional generation and transmission facilities;

Environmental Policy

Develop Guidelines for Thermal Plant and Transmission Line Investments- status of preparation of environmental guidelines;

Assess Staff Capacity in RECs or Power Pools –minimum staff in RECs or power pools to manage preparation of environmental guidelines for regional investments in power;

3.1.2 Policy Impact Indicators

Number of Regional Electricity Interconnections, 2000-2010-this indicator would measure the number of new transmission interconnections constructed over this 10 years period

Growth in Share of Regional Electricity Trade, 2000-2010 –this indicator would measure the growth of electricity trade over a 10 years period in each regional area.

3.2 Level of achievement by policy

In analyzing the level of achievement of the different continental and regional energy policies, it is important to keep in mind the main objectives and expected outcome of these policies as stated recently by Africa’s Ministers in charge of energy in the Maputo Declaration of November 5, 2010. These objectives are to:

Promote regional and continental cooperation in the development of Africa’s energy resources;

Increase energy trade within, and between, regional areas of the continent; and,

Lower the cost of energy in order to improve access to basic energy services.

Improving access to basic energy services for an increasing proportion of Africa’s 880 million people is a policy objective shared by all the RECs and has been reiterated in declarations by the AUC, NEPAD Secretariat, and the Commission of Energy Ministers for Africa (CEMA).

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3.2.1 Level of Achievement of Continental Policy Objectives

As discussed in Section 2.1, AUC’s role is to coordinate and harmonize regional energy policies across the African continent, point out discrepancies, and identify policy bottlenecks- all with a view to advancing the physical integration of the African continent in energy infrastructure.

The effectiveness of the AUC’s policy coordination role is best measured by the following activities and indicators derived from the continental policy log frame in section 2:

Follow up on specific actions agreed at high level meetings of Energy Ministers on regional integration issues, especially actions related to the development of large hydro schemes that fall outside the responsibility of regional agencies;

Progress made in advancing the physical integration of Africa’s main regional areas- specifically, the increase in the number electricity and natural gas interconnections between regional areas to enable energy exchanges to take place;

Growth of electricity trade over a 10 year period (a) within specific regions; and (b) between different regions;

Progress made in developing renewable energy resources with specific emphasis on (a) large hydro schemes; (b) geothermal resources; and (c) solar-based energy.

The continental policy achievement table below summarizes progress made towards three of the main policy objectives aimed at increasing the number of regional energy infrastructure links and increasing trade between countries in both electricity and natural gas. Progress made is as follows:

Large Scale Hydro Potential: Very little progress has been made since 2005 in developing the potential of Africa’s large scale hydro schemes, in particular the Inga hydro scheme. A decision was taken at the 2006 AUC meeting in Addis Ababa to establish a Coordination Commission for the development of major, integrative, hydroelectric projects. A Continental Coordination Structure was subsequently established in 2008.

Inter-Regional Electricity Infrastructure: No major inter-regional electricity connections have been constructed and, as a result, there is no inter-regional electricity trade ;

Natural Gas Infrastructure: The West Africa Gas Pipeline was commissioned in late 2009-10. The pipeline is currently transporting associated gas from Nigeria to Ghana and the gas throughput is close to capacity. Gas spur links to Benin and Togo are currently under construction. The pipeline was completed nearly 3 years behind the original schedule.

Geothermal: The development of the geothermal potential of the African Rift Valley countries (Kenya, Ethiopia, Djibouti as well as Uganda, Tanzania and Rwanda) has been constrained by (i) limited geo-scientific data and poorly organized data bases ; (ii) absence of a legal framework to help promote private sector interest in geothermal development ; and (iii) a lack of funding for exploration investment. Since 2000, only modest progress has been made in developing the geothermal potential of this region as shown in Kenya : Installed capacity: 2000- 57 MW ; 2010-167 MW Geothermal potential: 3000 MW;

Renewable resources: Solar and wind energy resources make a negligible contribution to commercial energy requirements. However, important wind and solar energy developments are underway in South Africa while major investments in concentrating solar thermal power (CSP) plants are being considered in North Africa.

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Table 1-9: Achievement Table of Main Continental Energy Policies

3.2.2 Level of Achievement of Regional Policy Objectives

Progress made towards the stated policy objectives for each of these policies is summarized below.

Legal Framework for Regional Electricity Integration

In the different regions of Africa, steps have been taken, starting in the mid-1990s, to put in place a regional legal framework to govern electricity trade between adjoining countries, help in fostering an investment climate to support the expansion of regional electricity exchanges, and attract private investment. Progress made in taking these legal steps in each of Africa’s regions is as follows:

35 Powering Industrial Growth: The Challenge of Energy Security for Africa, AU Conference of Industry Ministers, September 24-27, 2007

OBJECTIVES AUC

Continental Objectives

STRATEGIC POLICY

INITIATIVES

EXPECTED RESULTS INDICATORS PROGRESS

2000-2010

1. Ensure energy security35

Develop fully Africa’s resource potential – esp. large-scale and integrating regional and continental

hydro schemes

Development of hydroelectric hubs

West Africa-Niger river

Central Africa- Inga/Congo river

Southern Africa -Mozambique/Zambezi

East Africa-Ethiopia/Nile

Coordination Commission for major hydro is established

Inter regional power purchase agreements signed$

Interconnection of reg. power pools

1(a) Established 2008

None

None

2. Promote intra-African trade in energy

Foster regional and continental cooperation in electricity exchanges and natural gas use

Increased regional electricity and gas inter-connections in near term followed by regional inter-connections

Number of new regional interconnections in power and gas

Share of power traded in each REC

Power-?; Gas-1 Varies from 0.5% to 5% in SADC in 2008

3.Promote global exports in energy

Develop Africa’s hydrocarbon resource potential, especially natural gas

Capture and distribute flared gas for export; (ii) Make WAGP Operational ;

Expedite trans-Sahara gas pipeline

Investment plan for flared gas capture;

Volume gas exported to Ghana

Feasibility study for trans-Sahara pipeline

Completed Gas flowing to Ghana since mid-2010 Feasibility study completed; no further progress

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SADC The main legislative steps were put in place in the period 1995-97: a regional power pool (SAPP) was created in 1995 and signed by member countries (IGMoU) while a framework for energy cooperation (Energy Protocol) was agreed in 1996 by member countries. In 2007, the SAPP Inter-Utility Memorandum of Understanding (IUMoU) was revised to allow membership by independent participants.

ECOWAS The main legislative steps have been put in place. The West African Power Pool (WAPP) was created in December 1999. In January 2003, the ECOWAS Energy Protocol established a unified legal (and regulatory) framework for cross-border power trading in West Africa. In July 2006, WAPP was formally inaugurated as a regional organization of public and private electric utilities.

ECCAS The basic steps towards establishing a legal framework have been taken. The Central African Power Pool (CAPP) was established in January 2003. Two legal agreements were signed by the member States in April 2003: (i) Inter-Government Framework Agreement; (ii) Inter-Utility Agreement. However, virtually no interconnections have as yet taken place in the ECCAS region.

COMESA The basic legal steps towards establishing a regional electricity market in East Africa were taken in February 2005 with the creation of the East Africa Power Pool (EAPP). Seven member countries were signatories to the original intergovernmental MOU36 while ten utilities from these countries have subsequently signed an inter-utility MOU. A more complete legal and regulatory framework is currently under preparation.

Regulatory Framework for Regional Electricity Integration

A regional regulatory framework is recommended for regional electricity trade. The main purpose of regional regulation is distinct from that of national regulation, where the primary emphasis is on safeguarding the consumer. In contrast, a regional regulator’s goal is to harmonize national regulatory standards between trading countries and, to the extent possible, facilitate the further development of an electricity trading market. For this reason, it is recommended that the regional regulator be independent of national regulatory agencies37 .

Progress being made to put in place a regional regulatory framework in the different regions of Africa is as follows:

SADC The Regional Electricity Regulators Association of Southern Africa (RERA) was established as a formal association of member country electricity regulators in July 2002. However, it does not yet function as an independent regional regulatory body. RERA's main role is to facilitate the harmonization of regulatory policies, legislation, and practices and act as platform for effective cooperation among energy regulators within the SADC region.

ECOWAS In January 2008, ECOWAS established a regional regulator, the ECOWAS Regional Electricity Regulatory Authority (ERERA). Some countries in ECOWAS do not have national regulators while others are weak or lack the authority and capacity to regulate cross-border exchanges effectively. Consequently, ERERA has two functions:

- as a regional regulator for cross-border exchanges; and

- as an agency providing assistance to national regulatory entities.

ECCAS No regional regulatory framework exists.

COMESA No regional regulatory framework exists. It is currently under preparation and expected to be completed in 2011.

COMELEC No regional regulatory framework exists.

36 Potential member countries of the EAPP are Uganda, Djibouti, Eritrea and Libya, with Libya due to become a member on November 27, 2010. 37 USAID Sub-Saharan Africa’s Power Pools: A Development Framework. White Paper, May 2008

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Planning and Operational

Regional investment planning in electricity depends on (a) a regional institution- normally a regional power pool- with the institutional capacity to prepare such a plan; (b) a clear mandate from member nations for regional plans to be the main framework for national investment decisions; and (c) the authority to enforce and implement the regional investment plan.

In general, the more established the regional power pool, the greater the institutional capacity to undertake regional planning. Systems operations capacity depends also on the stage of development of a regional electricity market.

Progress made in each African sub-region in building up planning and operational capacity is as follows:

ADC A sound organizational framework for regional planning and operation of the interconnected system has been in place for 15 years. SADC has overall responsibility for approving regional plans. SAPP has responsibility for preparing regional investment plans as well as for operation of the interconnected system. This includes power pool operations based on short and long-term bilateral contracts between member nations as well as a smaller proportion of trading operations involving short term, ‘day-ahead’ contracts in a competitive market (which has been as high as 10% of power exchanges in this regional pool). The main weakness in regional planning is the lack of decision making authority entrusted to the regional planning entities by national power planning agencies- in practice, the national power utilities.

ECOWAS A sound organizational framework for regional electricity planning has been in place for a number of years to guide the development of the West Africa Power Pool (WAPP). WAPP has responsibility for preparing priority generation and transmission projects and securing financing for them. An initial ECOWAS Master Plan was prepared in 1999. A ‘Revised’ Master Plan for the Generation and Transmission of Electrical Power’ was approved in 2005 and has provided the foundation for regional investment programs in electric power in the ECOWAS region. Subsequently, an Emergency Power Supply Security Plan was prepared in 2008; progress reports on the status of priority investments are being prepared regularly. At present, limited electricity exchanges take place between countries since there are few interconnected national systems. The eventual goal is to integrate national power system operations into a unified regional electricity market and to develop a regional transmission system owned and operated at the regional level.

ECCAS The Central African Power Pool (CAPP) has responsibility for implementing regional energy policies and developing regional energy trade in the ECCAS region. In 2006, the first regional electricity market plan for the development of electricity infrastructure was prepared, identifying priority investments and outlining an action plan to build up the needed institutions. No system operational capacity is in place.

COMESA The East African Power Pool (EAPP) is the newest of the regional power pools and was created in 2005. It is a specialized technical institution under COMESA with responsibility for planning and developing a regional electricity market. The preparation of a regional master plan started in December 2009 and expected to be completed in 2011. The region has only limited interconnections and no system operation capacity.

COMELEC A regional power pool organization has not been formed in the North Africa region; nor have policy steps been taken to put in place a legal, regulatory, or planning framework to promote regional trade. At the same time, electricity links have been constructed across all North African countries and provide a direct link, via Morocco and Spain, for electricity exchanges with the European network. Bilateral exchange agreements also exist between adjoining North African countries though the volume of electricity trade between these countries is very small.

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Commercial

There are several commercial issues that need to be addressed to enable electricity exchanges to proceed, depending on the stage of development of the electricity market. The two most basic steps are: (a) to define the ‘market rules’ of the electricity exchange i.e. ensuring an equitable and transparent contractual framework for the different parties involved in electricity trade; agreement also needs to be reached on pricing principles, standards for metering, and mechanisms for resolving disputes. The second step is (b) ensure financial solvency, or ‘creditworthiness’, of the two trading parties, normally national electric utilities and governments for political risk guarantees.

Market Rules In the SADC region, where there is extensive experience with electricity interconnections, the ‘market rules’ governing different bilateral contracts for electricity exchange are well established. In the ECOWAS region too, the commercial framework for electricity exchanges have been defined and agreed to in different bilateral contractual agreements for electricity exchange. In the ECCAS and COMESA regions, there is very limited trade between countries and a commercial framework has yet to be defined. However, in COMESA/EAPP, high priority is being given to defining the market rules for commercial trade transactions and consultants are currently elaborating a commercial framework suitable for electricity exchanges in this region.

Utility Creditworthiness The ‘creditworthiness’ of most national electric utilities in Africa is weak, which restricts their capacity to be ‘creditworthy’ counterparts under regional investment projects. Electricity tariffs are used in most countries as a social policy instrument with dubious efficiency, as it does not ultimately benefit the poor, who do not have access to electricity. Still, it results in tariff levels below the cost of electricity supply. The negative impact of low nominal tariffs is compounded by a culture of non-payment in most countries in conjunction with large public sector accounts receivables. The low level of effective (collected) tariff is the main reasons for the weak financial position of most utilities. Issues of utility creditworthiness constrain the development of a regional electricity networks and regional power plants in all regions since governments have then to provide the power payment guarantee; these governments are, in turn, non-creditworthy or have little capacity to provide suitable guarantees. As a result, financing for regional energy projects has been limited to (a) grant financing from development and international institutions, and (b) concessional financing granted to Governments and pooled for regional projects. So far, there is no example of direct financing of regional energy projects, either in the transmission or generation sectors. Only capacity building projects have benefitted from direct grant financing at the regional level.

3.2.3 Level of Achievement of Regional Gas Integration Objectives

In regard to the three main actions for gas trade development outlined in the African Union Report, “Infrastructure Development for Africa’, prepared during the 12th Ordinary Session in February 2009, progress has been as follows.

Establish a Framework to capture and distribute flared gas to African countries

With the support of the World Bank, EU and a number of bilateral donors, good progress has been made since 2000 in reducing the volume of flared gas in the West Africa region since 2000. The focus of the gas flaring reduction plan has been on Nigerian associated gas, which was being flared offshore. Most of the flared gas is now being captured for (a) domestic power generation in Nigeria and (b) West African Gas Pipeline.

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Expedite the West African Gas Pipeline (WAGP)

The WAGP was commissioned in 2007 and the first gas flows began in early 2010, almost 3 years behind the original schedule. At present, gas flows are approximately 100 MMCFD, with all the gas being supplied at present to the Ghana domestic market; spur links to Benin and Togo are still being completed. No decision has been made to commit to invest in compression facilities to enable increased gas flows, pending a decision by the Nigerian government to release additional gas reserves for export markets. It is also unclear whether Ghana would commit to additional gas supplies, following recent gas discoveries in its own offshore waters.

Expedite Development of the Trans Saharan Gas Pipeline

A pre-feasibility study for this proposed pipeline was completed in the last years. However, since July 2007, no further progress has been made after Nigeria and Algeria launched a promotion campaign for this pipeline to European countries. In the meantime, Algeria has continued to develop its own substantive gas reserves, mainly for European markets, while Nigeria is committing increased gas reserves for power generation in its own domestic market.

3.3 Policy Achievement Table

The Policy Achievement table below provides a summary of progress made in putting in place the different contractual, organizational, operational, and administrative steps that comprise the main regional policy areas- in each regional economic community or power pool.

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Fig. 1.10 Achievements of the Regional Energy Institutions

REGIONAL ECONOMIC COMMUNITY (POWER POOL)

ENERGY POLICIES AUC SADC

(SAPP)

ECOWAS

(WAPP)

COMESA

(EAPP)

ECCAS

(CAPP)

COMELEC

LEGAL

Inter Government MoU

Inter Utility MoU

Regional Law or Energy Protocol X X

Private Party Access/Direct Purchase

? X X

REGULATION

Regulatory Institution X X X

Operational Guidelines X X X

Independent Regulation X X X X

PLANNING

Organizational Structure X X

Regional Integration Plan X X

Regional Planning Mandate X X

OPERATIONAL

Grid Code X ?

Systems Operation X X X

Regional Dispatch X X X X

COMMERCIAL

Market Rules X X

Mobilization of financing X X X X X

ENVIRONMENTAL

Thermal Power Plants/Transmission Lines

? ? ? ?

Fully Achieved

Partially Achieved

Planning Stage

X No Progress

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4. CAUSAL ANALYSIS

The Policy Achievement Table in Section 3.3 provides a summary framework against which to measure progress made in each region in putting in place a set of regional policies to foster energy integration throughout the African continent. This section examines the reasons that have limited achievement of the different policy objectives and impeded progress towards more fully integrated energy infrastructure across the African continent. The primary focus of the causal analysis is electricity integration. The growing importance of natural gas interconnections in Africa is also discussed.

At the outset, it needs to be emphasized that an adequate policy framework is only one of several prerequisites for the growth of energy trade. Economic incentives, energy security concerns, institutional capacity, and the overall investment climate also have an important influence. In this regard, it should be remembered that the first electricity interconnections in Africa took place in the 1950s and 1960s in the absence of any regional policy or institutional framework, motivated only by the mutually shared economic interests of the member countries that signed these first agreements to exchange electricity. Consequently, while political consensus, economic incentives and energy security may be more critical considerations in the early stages of developing energy trade, a sound policy and institutional framework is needed to optimize the full economic benefits from regional energy trade.

4.1 Analysis of Legal and Regulatory Policies

Progress made in establishing a legal and regulatory framework for electricity trade in the five regions of Africa is summarized in Figure 1.11. The main reasons impeding implementation and effectiveness of these regional policies, in terms of power exchanges and development of regional investments, are also indicated.

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Figure1-11: Analysis of Legal and Regulatory Policies

REC/Power Pool Implementation Status

Pending Issues Causal Reasons

SADC/SAPP

Advanced stage with 15 years of experience since first legal agreement

Lacks independent regional regulator

Issue of National versus Regional control of regulatory matters

SA legislation limits imports to 10%

ECOWAS/WAPP

Main legal agreements in place; regulatory body also established

Regulatory guidelines for ERERA under preparation

Stronger commitment to regional trade amongst member states

COMESA/EAPP Regional agencies set

up relatively recently; Limited capacity, staffing and

funding constraining further trade development

Regional focus is recent and untested on issues of regulatory control

ECCAS/CAPP Still at very early

stage Limited capacity, staffing and

funding severely constraining further trade development

Very weak regional institutions

COMELEC

Bilateral trade agreements to trade but without creating any regional agencies

Electricity exchanges being undertaken piecemeal

No political consensus on trade

The main findings emerging from the legal and regulatory analysis are as follows:

There is generally strong commitment in the regional economic communities to establish a basic legal and regulatory framework for regional electricity trade;

Progress made in putting in place the basic legal agreements has been impressive;

Regional regulatory institutions have been established in two regions, with regulatory guidelines currently under preparation (SADC and ECOWAS). In the SADC region, the regional regulator does not have independent authority;

Institutional capacity, staffing and funding are serious constraints in ECCAS and, though to a lesser extent, in COMESA;

COMELEC region has no legislation for electricity trade, which lacks a political consensus for regional trade. The Maghreb countries have proceeded piecemeal, with bilateral links between countries, and exchanges taking place on an emergency basis;

Despite strong commitment and implementation of institutional and regulatory framework, electricity trade remains a small share of power generation in most regions (< 5%) and has not grown measurably over the past decade in SADC region, where its share has been between 5-10% in the best years, down to less than 5% at present.

The development of regional regulations and institutions has failed to attract investment in regional power generation, and has had limited success in attracting direct financing for regional transmission investment.

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4.2 Analysis of Planning, Operational and Commercial Policies

Progress made in preparing and implementing regional investment plans as well in harmonizing operational commercial policies in the five main regional areas is summarized in Figure 1-12.

Figure 1-12: Analysis of Regional Planning, Operational and Commercial Policies

REC/Power Pool Implementation Status Pending Issues Causal Reasons

SADC/SAPP

Regional plan framework well established; sound operational and commercial frameworks

Regional investment plans lack enforcement authority

National versus Regional Plan

ECOWAS/WAPP Priority regional

investment plan is prepared

Financing the regional investment plan

Donor finance limited;no alternative financing sources identified

COMESA/EAPP Regional plan in

preparation Financing likely to be the

main constraint to implementing plan

Donor finance limited;no alternative financing sources identified

ECCAS/CAPP No regional plan No institutional capacity to prepare plan

Very limited staff or funding

COMELEC No regional plan No regional planning agency No political consensus

The main reasons why regional investment plans have had limited impact on investment decisions in most regional areas is due to:

Lack of enforcement authority for the regional plan;

Limited financing capacity of regional agencies.

The main issues in each region are summarized below.

In the SADC region, long term regional investments plans are prepared regularly by SAPP; good progress has also been made in harmonizing operational policies. However, there are still unresolved autonomy issues that nullify the benefits of regional planning:

- Member states have been unwilling to give the regional bodies they created the requisite mandate to implement regional power sector investment plans

- Implementation of regional power projects remains primarily the responsibility of the countries. In practice, national rather than regional investment priorities prevail;

- As a result, member states forego substantial benefits in investment cost savings that regional investment plans have over the aggregate of national investment plans.

In the ECOWAS region, the West African Power Pool (WAPP) has been able to cultivate stronger political buy-in to regional plans by having Heads of State formally endorse, and sign, WAPP regional power investment plans.

In COMESA region, EAPP is preparing regional investment plans following WAPP approach, which may help secure stronger member state commitment to these plans;

In the ECCAS region, a first regional electricity market plan has been prepared but with limited follow up due to institutional capacity weaknesses in CAPP.

In the COMELEC region, there is no regional framework for investment planning. All energy planning is undertaken through national planning agencies.

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4.3 Regional Electricity Integration: Causal Analysis Synthesis

This policy review has identified a number of issues that are impeding regional power system integration in Africa. Not all of these issues are policy concerns. Issues of regional institutional capacity and political commitment to regional integration are also important.

For example, the staffing and funding limitations of most regional institutions-which plan for, implement, operate, and regulate regional energy networks- influence the tempo of energy integration.

Another important issue is the large resource requirements of regional investment plans and the inability of regional institutions to mobilize the financing they need, or convince the national utilities to pool resources for regional investment projects or make the necessary management and governance changes to become credible interlocutors for attracting financing from external sources. The weak financial position of most African electric utilities has inhibited financing being mobilized from non-government sources for the large investment programs, the financing of which far exceeds likely resources available from government and donor sources.

Finally, there continue to be significant differences in the extent of political commitment to regional integration across regions and within member states. Thus, both energy security and national autonomy concerns- reflected in an unwillingness to entrust a country’s energy supply to a neighbouring country or to delegate investment decisions to a regional body-continue to affect the pace of regional electricity integration.

The following issues have been identified as the main constraints to regional energy trade emerging from this review:

4.3.1 Energy Security Concerns

Energy security concerns in individual member countries continue to be a barrier to regional energy integration.

In some countries, national legislation imposes limits on a country’s dependence on imported energy supplies. For example, in South Africa, energy imports are restricted to 10% of the country’s total energy consumption. Similar legislation exists in other countries.

At the same time, especially in smaller member states of the SADC and ECOWAS regions, energy security concerns have been overcome- in countries such as Namibia (25%) and Botswana (60%) which have a high dependency on imported energy but also a price vulnerability to imported oil products. As confidence grows in the reliability and cost benefits of energy supplied through a regionally integrated network, the barriers to importing part of a country’s energy needs can be overcome. However, security concerns (in terms of timely completion of regional projects, reliability of supply, and long term stability or predictability of prices) still need to be addressed in preparing regional investment plans and measures put in place to mitigate them.

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4.3.2 Regional Autonomy versus National Autonomy

Investment Planning. There is a reluctance to entrust regional bodies with decision-making authority in the areas of investment planning. Despite being given authority to prepare regional investment plans, regional bodies are not given a mandate to implement regional investment projects, which remain under the control of national utilities. As a result, regional investment plans are often put aside, despite offering significant benefits in investment cost savings when compared with the alternative costs of national investment programs. For this to change, member country investment decisions must be guided primarily by least cost considerations. In addition, financing institutions could also play an important role in strengthening the standing of the regional plans by entering into a compact to direct their financing, on priority basis, to regional projects, and considering national investments which are not part of the Regional Plan only under exceptional circumstances.

Regulatory Authority Regional regulatory bodies are gradually being established in different regions of Africa where electricity exchanges are taking place- or soon to take place. Regional regulatory guidelines are also being elaborated. However, regional regulatory bodies have yet to be given regulatory authority over regional networks. Instead, they function as an association of national regulatory bodies and focus mainly on building up the capacity of national regulators in those regions where capacities are weak or non-existent.

4.3.3 Staffing and Funding Weaknesses in Regional and Continental Institutions

The capacity of regional and continental institutions is generally weak. These institutions typically lack the minimum funding contributions committed to earlier by member states as well as key staff to undertake their basic mandate. The end result is that regional institutions often become dependent on external funding from bilateral and multilateral agencies to finance minimum staffing needs, which, in turn, runs the risk of their strategic priorities being shaped by bilateral funding agencies, especially in the area of renewable energy. Strong member state commitment to regional and continental institutions in terms of funding and staffing is essential if these institutions are to fulfil the mandate given to them. The SAPP and WAPP regional power pools are examples of stronger regional institutions that are able to carry out the basic planning and operational responsibilities of their regional networks and have minimum operating budgets.

4.3.4 Constraints to Mobilizing Financial Resources

An important challenge to be met in expanding electricity trade is financing the large resource requirement for the preparation, development and construction of the different regional investment programs in generation capacity and transmission interconnections. Multilateral and bilateral donors will be important sources of finance. However, the investment financing needs will far exceed the resources likely to be available from donor sources. Alternative sources of financing will have to be tapped, namely, the power sector’s own cash flow, which should contribute no less than 20% to new investment, as well as commercial sources. At the same time, these sources will be difficult to access since the financial position of most national utilities in Africa is extremely weak. Unless this policy issue is addressed in each region, it will remain an insurmountable constraint to mobilizing the resources needed to finance priority, regional energy investment programs.

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4.4 Regional Gas Integration: Causal Analysis

Positive progress has been made in substantively reducing the volume of flared gas in the West Africa region over the past 10 years for the following reasons:

Strong political commitment by the producing countries- principally Nigeria- supported by both bilateral grants and IFI financing to help achieve this objective;

Well identified and expanding domestic and regional export markets to absorb the flared gas, which provided adequate commercial incentives to the privately-owned gas supply company;

In regard to the WAGP, the gas infrastructure has been completed and gas in now flowing to the main regional market in Ghana. However, the gas pipeline took more than 5 years to complete and was affected by construction delays and environmental issues. Moreover, its future viability remains uncertain for the following reasons: (a) Increased commitment of gas supplies from Nigeria has not been made, pending meeting its own domestic market requirements for gas; (b) Recent discoveries of gas in Ghana, the main market for the WAGP gas. Neither of these developments could have been readily foreseen and they reflect some of the gas reserve, economic, and political uncertainties in developing regional gas grids. At the same time, once the gas infrastructure is in place, its presence provides incentives for a rapid growth of a gas market along the pipeline route, based on experience in Latin America (Brazil- Bolivia) and in Thailand

After a promising start, the Trans-Saharan Gas Pipeline appears to be stalled, with no measurable progress being made since 2007 in developing further this regional proposal. The main reasons appear to be (a) lack of sufficient political commitment to move ahead with this regional concept, particularly in Algeria which continues to expand its own gas potential; (ii) lack of a regional or continental institution, with the requisite funding and staffing as well as representation from the beneficiary countries (Nigeria, Niger and Algeria), to develop the project concept and help mobilize a viable financing plan for this large regional investment.

Conclusion

This policy review raises a fundamental question in regard to the areas of future emphasis in Africa’s strategy to increase energy trade. For nearly a decade or more, the main continental and regional bodies have been actively involved in putting in place a sound policy and institutional framework for promoting regional energy trade. Despite capacity and funding constraints, there has been both strong commitment as well as measurable progress in establishing a policy framework. However, the impact of these regional policies on electricity trade has been negligible, as can be seen from the 2005 regional trade figures in electricity. Since 2005, regional trade has decreased further - to below 5% in the SADC region in 2007 and 2008 -as generation capacity constraints have led to frequent outages and limited the availability of power for export.

Fig. 1-13 Regional Trade in Electricity, 2005 (TWh)

Power Pool Consumption Imports Exports % Share of Trade CAPP 8.80 0.01 1.80 0.1 EAPP 13.41 0.28 0.18 2.1 SAPP 233.97 22.71 25.74 9.7 WAPP 28.63 1.63 2.04 5.7

Source: EIA

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A clear lesson emerges from this regional trade data: regional electricity trade cannot expand without sufficient overall power capacity at the regional level to meet demand. Such capacity shortages occur frequently in almost all regions of Africa due to poor planning and weak sector cash flow to support investment or borrowings. Consequently, there is a priority need to accelerate the construction of generation and transmission facilities in order to expand, and reinforce, the geographical coverage of regional grids.

In conclusion, these findings point to three areas for future emphasis in Africa’s strategy to accelerate regional electricity integration:

Develop a Financing Strategy- by preparing realistic financing plans that examine, inter alia, the feasibility of mobilizing non-government resources from the sector’s own cash flow and external sources38 to help meet the overall financing requirements of the investment plans;

Strengthen Regional Institutions –by addressing the capacity weaknesses and budget needs of key regional institutions for their operation and for the preparation and development of regional projects, with priority given to the East Africa and Central Africa regional agencies for capacity building.

Step Up Regional Investment- through construction of regional generation and transmission facilities based on least cost regional investment plans;

Africa is still at an early stage in its quest for physical energy integration of the continent when measured against levels of integration in other areas of the world. There is also significant variation in the number of physical interconnections between regions. Moreover, worldwide experience suggests that reaching a fully integrated continental market will likely take several decades. At the same time, the rapid progress made in power system integration during the last decade in developing regions such as Central America and South East Asia- in both cases preceded by lengthy periods of uncertainty while a political consensus was being formed-- provides a benchmark, and a challenge, for Africa to emulate.

38 External financing will be forthcoming only if, first, the future sector cash flow is strong enough to contribute to sector investment and service commercial loans directly or indirectly through power purchase agreement.

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ENERGY Sector - Report II : Infrastructures


PART II: REPORT ON INFRASTRUCTURE

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Table of Contents 1. OBJECTIVE..............................................................................................................4

2. REVIEW OF EXISTING REGIONAL INFRASTRUCTURE .................................. 5 2.1 List of Continental and Regional Infrastructure:....................................................................................................5

2.1.1 Transmission .............................................................................................................................................................. 9 2.1.2 Generation ...................................................................................................................................................................11

2.2 Set of relevant infrastructures .........................................................................................................................................13 2.2.1 Power sector .............................................................................................................................................................13

2.3 Impact of Infrastructures on reaching policy objectives...............................................................................14 2.3.1 Outcomes....................................................................................................................................................................16 2.3.2 Outputs..........................................................................................................................................................................16 2.3.3 Inputs..............................................................................................................................................................................18

2.4 Assessment of constrains on efficiency................................................................................................................. 20 2.4.1 Poor technical condition preventing their full or reliable operation.................................. 20 2.4.2 Political and commercial obstacles......................................................................................................... 20 2.4.3 Technical constraints ..........................................................................................................................................21 2.4.4 Commercial efficiency constraints.............................................................................................................21 2.4.5 Economic efficiency constraints..................................................................................................................21 2.4.6 Investment constraints ......................................................................................................................................22 2.4.7 Financial constraints for system operation .........................................................................................22 2.4.8 Institutional constraints .....................................................................................................................................23 2.4.9 Legal-regulatory and policy constraints................................................................................................23

2.5 Potential efficiency gains...................................................................................................................................................23 2.6 Lessons from experience..................................................................................................................................................24

2.6.1 Strong Government Support, in political and financing terms ...............................................24 2.6.2 Political Risk..............................................................................................................................................................25 2.6.3 Institutions for regional projects .................................................................................................................25 2.6.4 Assessing and managing commercial risk..........................................................................................26 2.6.5 Commercial Contractual framework ........................................................................................................26 2.6.6 Commercial viability ............................................................................................................................................27 2.6.7 Governance of regional projects................................................................................................................27 2.6.8 Energy Security ......................................................................................................................................................28 2.6.9 Integration in Regional Plan...........................................................................................................................28

3. REVIEW OF REGIONAL INFRASTRUCTURE/ PROJECTS UNDER IMPLEMENTATION OR PREPARATION (HARD AND SOFT) ........................29

3.1 Inventory of all projects under implementation and preparation (project Brief /Project Sheets) ...........................................................................................................................................................................................29 3.1.1 Project Brief...............................................................................................................................................................29 3.1.2 Project Sheets .........................................................................................................................................................33

3.2 Detailed analysis of a set of infrastructure programme ...............................................................................33 3.3 Lessons learned and recommendations ................................................................................................................34

3.3.1 Suitable Institutional arrangements are decisive for the smooth development of regional projects....................................................................................................................................................34

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3.3.2 The RECs and Pools may play a more proactive role in identifying regional projects early and in developing the ad hoc institutional framework...............................35

3.3.3 An assessment of the creditworthiness of all stakeholders in a regional project needs to be carried out at pre-feasibility stage ..............................................................................38

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1. OBJECTIVE

This second part of the review analyses existing regional and continental infrastructure and associated services, those under implementation and those that are in the pipeline.

It essentially addresses the following objectives:

(i) Contribute to the review of regional and continental policies expressed in the

Report I Policies; (ii) Determine the potential for improving the performance of the existing

infrastructures for longer term development prospects; (iii) Formulate the measures to be taken to improve the efficiency of implementation of

programmes for the development of regional and continental infrastructures; and (iv) Enrich the Client’s information base.

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2. REVIEW OF EXISTING REGIONAL INFRASTRUCTURE

2.1 List of Continental and Regional Infrastructure:

As long as national energy systems are interconnected, as it is the case for mst of the power systems of Africa, except for a few isolated national systems such as Guinea, it is difficult to separate regional infrastructure from national infrastructure. It was therefore decided to review all the major energy infrastructure of the continent with a view to assess the extent to which they have played or could play a role in the development of an integrated continental energy system. The inventory has been conducted on the basis of information available from three main sources:

Information collected under the AICD program in 2007-08

Data available in the long term development plans of the RECs/Pools prepared between 2007 and 2010 depending upon the Regions

Updates collected directly from the RECs and Pools during field visits

Information concerning North Africa was collected from the recent study prepared under EU financing for the integration of the market of the Maghreb countries undertaken by SOFRECO1.

The description presents the power generation plants and the transmission systems by main regional are given below.

1 « Intégration progressive des marchés d'électricité de l'Algérie, du Maroc et de la Tunisie dans le marché intérieur de l'électricité de l'Union Européenne » SOFRECO, Europaid, May 2010

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Eastern African

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Southern Africa Power System

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Western African Power System

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Central African Power System

2.1.1 Transmission

The transmission systems as of 2009, as shown in the Table below do not represent a continental or regional network. They were developed as independent systems, mainly structured from the coast to the interior, except for the Southern Africa system which is structured as a national network. Even the Northern Africa system runs essentially along the Mediterranean coast with a few spurs inland. The map below shows that the Northern Africa and Southern Africa systems could nevertheless allow for significant intra-regional exchanges, while this is not the case for the Western Africa and Eastern Africa systems.

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For transmission lines, the potential to contribute to regional integration depend upon the capacity of the lines. The transmission system is therefore presented distinguishing high capacity power lines with a voltage of 400-500 kV, lines with a voltage between 220-330 kV and between 110-220 kV. The corresponding maps and tables are included in Annex 2.1 and summarized in the map below.

The following maps of the African transmission system have been prepared and are given in Annex 2-1:

Lines with a voltage between110-220 kV

Lines with a voltage between 220 and 330 kV

Lines with a voltage between 400-500 kV

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2.1.2 Generation

The main power plants are presented distinguishing Thermal, Hydro and Other plants and distinguishing between large plants with a capacity above 500 MW, medium size plants with a size between 100 MW and 499 MW, and smaller plants with limited potential regional role with a capacity below 99 MW.

The corresponding maps and supporting tables are given in Annex 2.2 and summarized in the overall map and table below.

The following maps have been prepared:

All Plants

All Thermal Plants

Thermal plants with a capacity below 100 MW

Thermal plants with a capacity included between 101 and 500 MW

Thermal plants with a capacity above 500 MW

All Hydro Plants

Hydro plants with a capacity below 100 MW

Hydro plants with a capacity included between 101 and 500 MW

Hydro plants with a capacity above 500 MW

Other Technology Plants

The total of existing generation capacity is given in the Table below and detailed in Annex 2-2.

Existing Installed Generation Capacity of Africa in MW

Plant Type Installed Capacity

Thermal 75 372

Hydro 30 123

Other 669

Total 106 164

It indicates that most of the existing capacity is thermal (75%) because of the size of the North African and South African systems which are predominantly thermal, whereas the central and Eastern part of Africa has a larger proportion of hydro plants. The small contribution of Other technologies (wind, solar, biomass) is also conspicuous, although the share of Other Technologies in increasing with large developments in Morocco and Egypt in particular.

The overall map of power plants in Africa is given below

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2.2 Set of relevant infrastructures

In the energy sector, there are few infrastructure investments that were built specifically to contribute to regional integration or sharing of energy resources. Power trade, which is the result expected from the development of regional energy infrastructure, has been limited in the past and is at best stagnant in terms of share of energy produced or consumed (see section 1).

The detailed review of a number of existing regional energy projects point to a mixed performance in terms of effectiveness of development (very long gestation and development periods), and sustainability (most regional schemes are facing major financial crisis threatening their sustainability and undermining the trust of countries in regional energy projects).

2.2.1 Power sector

Power generation

Typical investments in regional power plants aiming mainly at supplying more than the domestic market are: Manantali, Cahora Bassa, Ruzizi II, Kariba. Plants like CIPREL and Azito in Côte d’Ivoire export to Burkina Faso, but were not designed mainly for export and power exports are on an ad hoc basis, although they have been going-on for a number of years. The Inga I and II complex exports small amounts of electricity to Congo and sporadically to South Africa and Zambia, but serve mainly Kinshasa and the industries in the Katanga region.

Transmission Systems

There are few transmission systems with a regional dimension. One can nevertheless list the Mediterranean coastal line, which is part of the Mediterranean Ring, the coastal line from Nigeria to Ghana and the RIMA system of OMVS. Most other transmission lines of significant capacity which cross borders were rather aiming at bilateral trade (Côte d’Ivoire-Burkina, Côte d’Ivoire-Ghana, Mozambique-South Africa, RDC-Congo for example). The integration of these bilateral links into a coherent regional transmission system is the challenge being addressed by the Power Pools.

Five existing regional energy infrastructure investments have been selected, on the basis of their contribution to regional integration, their relatively large size, their requirement for cooperation between several countries and the number of years of operation, allowing one to draw conclusions regarding their sustainability and contribution to regional integration objectives. It led to the selection of the following projects: Manantali, WAGP, SINELAC, Cahora Bassa and Nangbeto. The presentation of each of these projects is in Annex 2.3.

The lessons that can be learned in positive and in negative terms for the design and development of future regional projects are summarized below.

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2.3 Impact of Infrastructures on reaching policy objectives

Referring to the Outcomes, Outputs and inputs presented in Section 1, the contribution and alignment of the regional investments with Continental and Regional policies was as follows:

infrastructures Outcome 1: poverty reduction

Outcome 2: intra-africa exchanges

Output 1: cost reduction

Output 2: Increased access

Output 3: Increased regional trading

Input 1: Increase low cost generation

Input 2: develop regional transmission system

Input 3: Trade facilitation

Input 4: Coordinated investment

Manantali

Controversial impact on agriculture

Positive impact on cost of electricity

Positive impact through exports of Mali and development of regional transmission system

Positive: electricity cost USCents 4.5/kWh, but well below actual full cost recovery level

Uncertain: supply still constrained in Mali, Senegal and Mauritania

Positive impact on regional power exchanges

Positive impact: low cost supply

Positive: Regional grid development

Negligible: export through direct contracts

Uncertain: implementation suffered major delays. Schedule of further developments (Gouina and Felou) will be the test

SINELAC

Positive through the production of low cost electricity, but financially unsustainable

Positive through sharing of capacity

Uncertain: the poos still do not have access to electricity

Uncertain. Progress in access limited

Uncertain: increased regional production, but not trading

Positive: Supplied electricity at nearly zero effective tariff, but non-sustainable

No impact No impact No impact.

WAGP

Positive through the production of low cost electricity, but negative because of gas diversion from domestic Nigerian market

Uncertain as gas deliveries seem to be unsustainable

Uncertain because of unsustainable gas deliveries

Positive impact on rural electrification programs in Ghana, but uncertain for the other three countries

No impact Positive because of conversion of power plants in Ghana from oil to gas

Positive, as the WAGP connects Ghana, Togo and Benin to the Nigerian gas market

Positive, as terms of trade are regulated by a complex st of treaties

Investment costs are shared between suppliers and off-takers

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infrastructures Outcome 1: poverty reduction

Outcome 2: intra-africa exchanges

Output 1: cost reduction

Output 2: Increased access

Output 3: Increased regional trading

Input 1: Increase low cost generation

Input 2: develop regional transmission system

Input 3: Trade facilitation

Input 4: Coordinated investment

Nangbeto

Negligible impact on rural electrification but low-cost supply to urban centres

Positive through sharing of generation capacity between Togo and Benin and future trading on the STEM

Uncertain as imported electricity may have been cheaper than domestic production

Uncertain as rural electrification in Togo and Benin has made little progress

Sofar no impact though there may be sales to the STEM in the future

Positive because of substitution of thermal generation by hydro power

No impact No impact as power sharing between Togo and Benin is by long-term agreement

Positive, as investments were coordinated by CEB, which is co-owned by Togo and Benn

The analysis suggests that the development of regional infrastructures may have only marginally contributed to the expected outcomes, outputs or objectives of regional policies, but they played a more decisive role as inputs for policy implementation. Several of them, however, had limited regional integration objectives and focused rather on exchange between two countries (Nangbeto, Cahora Bassa).

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2.3.1 Outcomes

Most regional investments contributed to increased intra-African trade. Their contribution to poverty reduction was rather indirect and is difficult to evaluate. It is reasonable, though, to assume that regional investments, if their services were priced economically, have contributed to lower the cost of supply of electricity, if the lower cost of electricity produced by regional projects has been reflected in lower electricity tariffs. It has to be further assumed that the tariff reduction may have also contributed to improve the standard of living of those (the poor) who didn´t have access to electricity before. It is difficult to link any of the regional investments to accelerated economic growth in their sub-region, in the absence of base-line data and clear emergence of new economic activities in the served sub-region, but in countries such s Mali, the national regulator made sustained effort to ensure that the availability of lower cost electricity from Manantali is reflected in the tariff charged by EDM.

Regarding Manantali, the controversy surrounding the contribution of the project with the Regional outcome of sustainable development relates to the irrigation and fishery activities liked to the project more than the environmental impact of electricity supply. The conclusions of the International Finance Organizations and of the NGOs differ sharply and are difficult to reconcile or assess objectively, even ten years after project completion.

Regional projects are expected to contribute to the accelerated economic growth outcome. Because of the relatively modest size of the regional power projects compared to the market (including Cahora Bassa, regional power projects represent less than 3 000 MW of capacity compared to an overall capacity of Africa of more than 50 000 MW), it is difficult to compare growth before and after the regional investment or to evaluate what may have happen without the regional projects. Regional projects generally allow the supply of electricity at a lower cost than alternative national projects.

This would have a direct impact on growth if tariffs are aligned with cost, and therefore regional projects contribute to lower tariffs, more affordable electricity and more competitiveness for African industries. As the effective tariff are generally well below the economic cost of supply, an evaluation of the impact of the regional projects on growth, had the effective tariff been aligned with economic cost is highly speculative. The contribution of regional projects to lower the fiscal deficit due to power subsidization and freeing fiscal resources for alternative uses is difficult to assess with certainty.

2.3.2 Outputs

The contribution to the objective of cost reduction, if tariffs for regional infrastructure were set economically, was certainly positive in all documented cases. When examining the extent to which regional projects contributed to lower electricity cost, consideration should be given not to the effective tariff paid, but to the economical cost of power supply: the effective tariff was well below economic tariff and unsustainable, set on poor governance principles for Manantali, Nangbeto, SINELAC, and predicated on the assumption (verified in most cases) that ultimately, the debt will be forgiven or not repaid. It is only in the case of Cahora Bassa that the contractual tariff or charge is effectively enforced, although at a very low level. Considering the economic cost of supply, the regional investments have net expectations and contributed to reduce the cost of electricity. The Manantali supply cost of electricity is above the tariff of USCents 4.5/kWh, which takes into account the debt cancellations, but it is well below the cost of the Diesel-based alternatives in Senegal, Mali and Mauritania, which exceed USCents 15/kWh. SINELAC’s economic cost is indeed un-related to the nominal tariff of USCents 2.5 USCents/kWh adopted by its General Assembly of the representatives of the three countries concerned ( and not even paid by the off-takers). Although the economic cost of supply by SINELAC is difficult to estimate ex-post, considering tariff as initially envisaged and the cost of supply from the next plant on the same cascade, it is likely to be about USCents 8/kWh including rehabilitation and proper maintenance cost. This level is well below the cost of

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supply from alternative sources of electricity in Rwanda (about USCents 15/kWh), in Burundi (well above USCents 12/kWh) and in RDC (Kivu) (estimated above USCents 12/kWh). Cahora Bassa has a tariff of about USCents 1.2/kWh, but this tariff does not reflect the economic cost of supply of the plant, but takes into account commercial, political and debt forgiveness factors. It can therefore be safely concluded that regional projects have met their objective to lower the cost of electricity.

The contribution to increased access is doubtful, as there is no indication that access has picked-up at the time regional infrastructures were put in operation. Although increased access is one of the objectives of AUC and the REC/Pools, the connection between regional projects and access is only indirect. Indeed, increased grid-based access requires that more electricity is generated or transported, but the determining and limiting factor is distribution system extension. To the difference of new projects, which generally include specifically an access component for the populations concerned, the earlier generation of regional investment projects did not include such provision, and therefore, did not contribute directly to access locally. In the case of Manantali and Nangbeto, the additional electricity produced served to meet increased demand from existing consumers rather than new connections. In the case of Cahora Bassa, increased supply to the domestic market (Mozambique) as well as increased exports may have contributed to increased access in Mozambique,but the effective access rate being about 4% at present, the impact of Cahora bassa has been limited. At the time Cahora Bassa supply started, the main priority was increased export to South Africa rather than increased domestic access.

In South Africa, the low cost of Cahora Bassa electricity could have contributed to lower tariff in ESKOM (initially, Cahora bassa would have represented about 20% of South Africa’s generation capacity), but the interruption of supply during the civil war made that Cahora Bassa electricity became available only when the South African system had expanded and the share of Cahora Bassa represented less than 5% of supply and therefore had a limited impact on South Afrin tariffs and affordability of electricity. Concerning SINELAC, the commissioning of the plant in 1996 did not coincide with a significant increase in access in Rwanda, Burundi or RDC. In fact, RDC had excess capacity as it could not extend its local distribution system and sold their surplus to Rwanda. The conclusion is that regional projects did not contribute clearly to accelerate access, or at least, there was no clear correlation between the commissioning of regional projects and the acceleration of access.

The contribution of regional projects to regional trade in electricity has been significant inall cases, based on bilateral agreements, particularly in Southern Africa, as most of the electricity generated by Cahora Bassa has been exported to South Africa, in the context of long-term power purchasing agreements, and a small portion was traded on the short-term market operated by the SAPP. In the rest of Africa, regional projects are based on bilateral contracts between the project and utilities, as it is the case for Manantali which had supply agreements with Senegal, Mauritania and Mali; SINELAc which has agreements with Rwanda, Burundi and RDC; Nangbeto, which has supply agreements with Benin and Togo. It is clear that regional projects represent a large share of regional power trade and have been very successful in demonstrating the feasibility and benefits for the purchasing electricity from these schemes, despite the economic managerial and financial challenges they face. The regional schemes, however, are all based on long term bilateral contracts (even if most of them are poorly structured and do not include suitable tariff revision provisions). To the extent bilateral contracts re part of regional trade, regional projects have significantly contributed to the development of a regional market. Their contribution to the development of an open spot market, though, has been nil because spot market trading is hardly compatible with the long term financial commitments regional projects are supposed to comply with.

Nevertheless, the infrastructure developed under regional power and gas transmission and interconnection projects are important pre-conditions for cross-border trade in electricity, which should be understood as exchanges of electricity under long or short term contracts, rather than restricted to trading under short term arrangements, and regional economic integration.

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2.3.3 Inputs

The regional infrastructure contributed to some important inputs of the policies. Their main contribution was

to develop low cost generation potential and

to develop regional transmission systems.

On the institutional side, their contribution was mixed:

Their contribution to trade facilitation and system integration was limited, as there are little institutional impediments to electricity trading between countries with synchronized systems. On the one hand, two of them were the cornerstone for the development of regional power exchanges and the development of coordinated trading regulation and technical standards and a truly regional power exchange system for the future most projects mainly contributed only to the development of bilateral exchanges, which is indeed welcome, but of lesser reach than the integration of power systems (Cahora Bassa, Nangbeto);

Their contribution to regional investment planning and investment planning coordination was indirect. Although the investments were clearly identified as part of the long term investment plan of the regions, their implementation took place following a schedule unrelated to the optimum commissioning date, as all regional projects were affected by major implementation delays. The delays certainly did not encourage countries to subordinate their own national plans to the implementation of regional projects, as it suggests that countries should not rely on the timely implementation on the regional investment in developing their own plans. Regional projects, though, contributed ot the reinforcement of a sub-regional vision for sector investment (Manantali through the RIMA system and the development of the regional investment coordinating function of OMVS and to a lesser extent, SINELAC with the embryo of a regional transmission system connecting Ruzizi II to the three national grids and the development of the capacity of EGL to coordinate regional projects on the Ruzizi river and to coordinate regional investments in the sub-region).

The financing and governance structures of regional projects were complex, requiring special efforts to set-up regional entities such as OMVS and SOGEM for Manantali, SINELAC, CEB for Nangbeto, WAPCO for WAGP, HCB for Cahora Bassa, as the joint support of several countries was required and the compliance with several national legal systems required complex institutional settings. It should be noted that all regional projects examined have widely different institutional structures ranging from an international organization (SINELAC) to a commercial company with regional and international shareholders (WAPCO). The success in setting-up these complex structures, requiring international treaties and even the creation of a multilateral international organization (SINELAC and WAPCO) is the more remarkable. The creativity in structuring regional projects was very successful in addressing the essential political problems related to regional projects. The structures are substantially different and were developed in an ad hoc manner. It is difficult to identify a common institutional approach to structuring regional projects or a learning pattern so far, but it should be noted that regional projects were rare until very recently.

Their performance in terms of resources mobilization is mixed. The various structures, except for WAPCO, are predominantly public and pooled public sector funding, entirely from external aid donors channelled through participating countries. The questions are: is it easier to attract financing for regional projects than for national projected; and is private financing of regional projects easier than for national projects.

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Three conclusions emerge: 1. There is a growing appetite of public and institutional financiers for regional

projects, in light of their strong economic justification and contribution to continental integration. This is evidenced by the acceleration in the number of ad hoc financing instruments for regional projects (“horizontal” Adaptative Programmatic Loans of the World Bank for the WAPP and the SAPP, special Partial Risk Guarantee for the WAGP and the pipeline Mozambique-South Africa in 2001-2004 for example, emulated by other institutions later). In addition, special funds are earmarked for regional projects on top of country allocations with the AfDB and the Word Bank. The World Bank group is also examining new instruments for the management of risk specific to regional projects). The initial observation is therefore that there a strong interest in financing regional energy projects in the public sector and additional funding is being made available, although the amounts remain small compared to the needs (Section 4). But a second observation is that the long gestation period of regional projects due to the time needed to develop a political consensus and special institutional arrangements and high preparation cost to lenders act as a deterrent, making regional project “show case” projects rather the mainstream operations. In this context, one can note the difficulty for development institutions to provide financing on a project finance and limited recourse basis to regional projects because of the multiplicity of obligors under regional projects.

2. The financial track record of regional projects breeds a distrust of public sector financiers toward regional vehicles. Most public sector structures for regional investment have demonstrated that that they are financially and commercially non-viable because of governance weaknesses and continue to function only through a network of reciprocal un-paid debts between the regional entity, the governments and the utilities (SOGEM/Manantali, SINELAC) and the periodical cancellation of debts at the expenses of lenders that is possible only between public sector institutions. An exception is Nangbeto, which is operated by the state-owned Communauté Electrique du Bénin, and operates with few financial issues though there have been occasional problems of collecting arrears from national distribution companies.

3. All of the retained structures (Nangbeto, SINELAC, SOGEM/Manantali and more recently Félou, Cahora Bassa) failed to attract private sector financing, as they were considered unprofitable or non-bankable by private lenders or investors. The likely reason is that in financing power projects in emerging markets, governance, political and regulatory risks, in particular, need to be transferred to Governments. The issue is whether the Governments have the financial capacity to bear these risks. In national projects, lenders and investors can select projects located in countries where these risks can be borne by the host Government. In the case of regional projects involving several countries, each and every government has to present suitable financial guarantees, as Governments would not agree to be jointly and severally responsible for the project. Cases where all countries involved meet sound banking criteria are rare and setting-up counter-guarantee arrangements from international financial institutions with several countries add to the complexity and uncertainty of regional projects from the credit and fiduciary standpoint.

Overall, regional investments in the energy sector in Africa have not performed well in terms of attracting resources for economically attractive regional projects. The discrepancy between the high economic attractiveness of regional projects and their modest performance for attracting public and private financing is the main challenge that needs to be addressed by African continental and regional institutions which need to address upfront sector governance issues, and propose innovative approaches for structuring regional investments in a commercially viable manner.

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2.4 Assessment of constrains on efficiency

All examined existing regional infrastructure in the energy sector rest on a sound economic and commercial justification, which was to lower the cost of energy production. Several of then, however, are not used at full design capacity. The reasons for the under-utilization of most of the regional infrastructure examined in the present review are the following:

2.4.1 Poor technical condition preventing their full or reliable operation

SINELAC (and to a lesser extent, Manantali and Nangbeto, but also Inga 1 and 2), due to financial problems, in turn due to non-payment of services provided by regional energy infrastructure compounded by deliberately under priced services (SINELAC and Cahora Bassa) incompatible with sound and sustainable financial performance. The case studies lead to conclude that the less than top technical performance of regional infrastructure is the result of poor governance and short sighted management by the Governments, jeopardizing the medium term the sustainability of their operation in exchange of short term political gains from under-priced services. The impact of deferred maintenance is estimated to reduce available capacity by as much as 25% for Sub Saharan Africa.

Existing regional infrastructure is severely affected by this issue: in the transmission sub-sector, the line from Inga to Katanga, Zambia and South Africa has a capacity severely constrained by poor maintenance (the present capacity of the line is about 150 MW, compared to a design capacity of 576 MW).

The cost of rehabilitation is estimated at US$ 430 million, to be financed under the World Bank/EIB/ADB SAPMP project under implementation.

Other regional transmission lines in North and Sub-Saharan Africa are reported to be capable of operating at their full potential, even if they are used at less than full capacity, as it is the case for the Morocco-Algeria interconnection.

In the generation sub-sector, several regional power plants are operating below design capacity. For example, the Inga 1 and 2 units are operating at 700 MW of capacity instead of the design capacity of 1 770 MW; the rehabilitation cost is estimated as US$ 550 to 600 million, to be financed in part by several donors including the ADB and the World Bank under the PMEDE program. The regional hydro plant of Ruzizi II run by SINELAC is operating at a production level of 149 GWh instead of the potential level of 170 GWh, that is, 12% below full potential. In addition, its financial performance has been constantly weak and SINELAC has been unable to service its debt and to recover its electricity bills with the national utilities. The Manantali complex is operating at full technical capacity, but has been subject to repeated financial problems due to the non-payment of water for irrigation by farmers and the poor payment performance of national power utilities. The estimated arrears in payments were up to one year of revenues in 2008.

2.4.2 Political and commercial obstacles

Another conclusion from the review of the performance of regional investment is that after the initial development and construction period, participating countries lack a “regional spirit” and tend to act essentially in defence of their domestic political interest, considering regional investment as a bonanza and a free service, happy to push future costs on neighbours or donors (the “free rider” syndrome).

Political and commercial obstacles to the full utilization of regional infrastructure leading to the deliberate under-utilization of the assets, as it is the case for both the Morocco Algeria and the

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Tunisia Algeria 400 kV-lines (used less than 10% of capacity) or the WAGP which is ready technically but not utilized to its full potential for national policy and commercial reasons.

2.4.3 Technical constraints

High unit costs for equipment and spare parts as well as over-sophisticated technical norms and standards, which largely ignore specific local requirements, have tended to increase project costs, which has tended to reduce the projects commercial viability. Though the projects in most cases have contributed to skills development on the part of local contractors as well as operation and maintenance staff and in some cases, there have been maintenance contracts between equipment suppliers and system operators, inadequate maintenance has been a major constraint for even medium-term project sustainability.

A major constraint for sustainable EU-African cooperation in implementing generation and both inter- regional and inter-continental transmission projects, such as DESERTECH, has been the technology gap and inadequate arrangements for technology transfer. In fact, sustainability of projects based on sophisticated renewable energies would appear to depend on arrangements for sustainable technology transfer. These may include manufacturing/supply/service contracts in a context of joint ventures and assistance for developing innovation capacities in the context inter-continental and inter-regional networks of academic institutions dedicated to applied research, developing local trademarks and patents for renewable energies and the commercialization of the results of applied research.

2.4.4 Commercial efficiency constraints

Most regional generation and transmission projects have been commercially unprofitable, as financial internal rates of return (FIRR) have been consistently below the opportunity costs of capital. Low commercial profitability has often been due to low retail tariffs applied by the utilities, as rural consumers have been unable to afford tariff rates based on the real cost of supply. In fact, the cost of supply has been high because of low-density electrification schemes and disproportionately high technology and ensuing maintenance costs. In some cases, not only revenues collected from national distributors and HV customers but also (as in the case of Cahora Bassa) export revenues, as there have been political constraints and long-term power purchasing agreements were concluded at a time of over-supply.

In the case of Nangbeto, the system operator (CEB) has consistently maintained a certain level of commercial profitability, as unsatisfactory sales to the national distributors (SBEE and CEET) have largely been offset by low production costs at the Nangbeto HPP and cheap electricity imports from VRA (Ghana).

Commercial efficiency could have been substantially increased if there had been provisions to renegotiate power purchasing agreements under conditions of supply shortages, least-cost investments in the distribution network had been made and the focus of rural electrification had been on intensification of rural household connections rather than on politically-motivated high-cost grid extension.

2.4.5 Economic efficiency constraints

Economic efficiency has been constrained, as for most regional generation and transmission projects economic internal rates of return (EIRR) have been consistently below the weighted average cost capital (WACC). In fact, economic efficiency deficits have been mainly due to inadequate economic benefits, low poverty impacts, as well as high economic costs, particularly related to the costs for mitigating adverse social and environmental impacts.

Economic benefits have often been restricted to export revenues, which have been consistently below initial estimates, mainly because of political reasons or technical constraints, such as low capacity utilization due to low water levels or technical disruptions. In

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fact, the main economic benefits have often been export revenues, though they have been consistently below initial estimates for economic, political or technical reasons, as in the case of Cahora Bassa.

Benefits from social impacts could have been substantially higher, if there had been more extensive investments in the distribution network and intensification of consumer connections, as social impacts may have been substantial in terms of reduction of income disparities between men and women, rural household lightening, increase of the school enrolment rate, reduction of illiteracy, health improvements, etc.

In most regional projects, economic costs have been higher than initially anticipated, as indirect economic parameters were often not included, such as upstream costs of production and transmission and the costs for environmental and social impact mitigation. Moreover, social and environmental impact mitigation costs have a tendency to increase, if important stakeholders are excluded during project planning, and expensive compensation agreements (e.g. for resettlements) or environmental mitigation measures have to be negotiated after project completion. In fact, in many African countries, large-sized regional generation and transmission projects have resulted in severe environmental degradation, loss of community livelihoods, abuse of human rights, mass impoverishment and abandonment of other sectors of the economy like agriculture, all of which should be included in assessing project impacts.

2.4.6 Investment constraints

Most regional generation projects in Africa have been notorious for significant cost overruns, underachieving economic targets and poor commercial profitability, which has contributed to the reluctance of international financing institutions to support new projects. In fact, financial constraints have been the main cause for the lack of progress in meeting Africa´s suppressed demand by means of generation capacity, intra- and inter-regional connections and rural electrification.

Both generation and transmission (interconnection) projects in the past have primarily been financed through a mix of international non-recourse loan finance, sovereign guarantees and credit risk insurance, e.g. that provided by the World Bank and its private sector insurance arm, the Multilateral Investment Guarantee Agency (MIGA). By contrast, the WAGP scheme is entirely financed by private equity supported by risk insurance.

Loan finance provided by International Financing Institutions has been constrained by complex procedures, difficult to meet equity and co-financing requirements and stringent requirements for social and environmental impact assessment. More recently, requirements to involve a wide range of stakeholders in the project planning process, including local communities, have further delayed the process of securing sources of funding. Securing loan finance from bi-lateral financing institutions, such as Exim-Banks, has often been constrained by the requirement of sovereign guarantees.

2.4.7 Financial constraints for system operation

The financial performance of system operators and indirectly their ability to contribute to investment and loan repayment has been mainly constrained by their off-takers´ inability to fully compensate for energy purchases and transport.

In fact, the financial standing of national distributors is often hampered by policy priorities favouring electrification of rural administrative centers, which in most African countries has resulted in low-density electrification. In fact, grid extension without intensification is one of the main causes for the high cost of rural electrification and the distributors´ inability to recover investment or even operating costs. The situation is aggravated if distributors are compelled to charge rural users exceedingly low lifeline rates, as such rates are a distinct disincentive for distributors to connect low consumption rural household. On the other hand, higher tariffs and connection charges are a disincentive for low-income customers to connect.

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2.4.8 Institutional constraints

In most regional generation and transmission projects, success in reaching policy objectives has been hampered by institutional constraints. In fact, the institutional framework for project implementation has not adequately reflected the respective stakeholders´ weight and ability to affect project outcomes. In regional transmission projects, such as WAGP, national and even more so international suppliers, have been over-represented on the Boards of system operators, while off-takers have been under-represented.

Moreover, the institutional framework has been ineffective in terms of aggregating stakeholder interests. In practically all cases, community members in areas adversely affected by the projects, have not been able to participate in the project planning processes, particularly concerning environmental and social aspects, and in all cases, decision-makers did not engage in a prior dialogue and consultation process with community leaders. In none of the regional generation and transmission projects, aggregation of community interests has been institutionalized, which is a definite requirement for sustainability

After project completion, members of affected communities have often expressed serious reservations and have even been challenging the project in the Federal High Court, as happened in the case of the WAGP in Nigeria. Information dissemination has been inadequate, and important project documentation, such as draft EIA, has not been made accessible. As a rule, contacts between project sponsors and communities were restricted to paying pre-determined amounts as compensation to certain landowners, while excluding the larger community, which has been a sure recipe for communal conflict.

2.4.9 Legal-regulatory and policy constraints

In some African countries, there are still regulatory disincentives for competition and private sector participation in regional energy projects, such as monopoly control of the energy sector, inadequate tariffs, inadequate budget support, inadequate protection of investors´ rights and both import and investment restrictions, which taken together negatively impact the business environment.

Though reform of the energy sector has been completed in most African countries, and the sector has been opened for private sector investment in generation and distribution (though not in transmission) capacity, divesting state assets for either generation or distribution facilities to strategic investors has so far been constrained by the lack of an effective enabling environment, in particular effective regulations concerning sustainable tariffs, licensing requirements, technical norms and requirements for social impact mitigation and mitigation of adverse impacts on the environment.

2.5 Potential efficiency gains

Measures to bring regional investment up to full capacity and financial sustainability are generally well known.

They include:

Enforce payment discipline with utilities, and in turn, with Governments and public sector enterprises

Put in place remedies (beyond interruption of supply) in case of non-payment

Set tariff on the basis of long term costs including financing cost, rather than in an ad hoc manner

Set-up protected reserve accounts for maintenance

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Reinforce Department of Studies in regional investment entities

Isolate governance of regional projects from involvement of Governments and utilities

The implementation of measures to restore performance of regional projects is held-up by institutional issues: solutions involve a change in governance, and in turn, changes in control and ownership, with a high risk of upsetting the fragile political balance between participating countries.

For example, the solution to SINELAC’s problems involves changing the status and governance of the company, which is enshrined in a treaty. A change in status would need a consensus between all participating countries, involving a loss of control by non-paying governments. Such a consensus has been elusive so far, for Manantali as well as for SINELAC.

The recommended measures to improve the efficiency of system operators and sustainability of regional infrastructure, aim at:

Improving governance of regional infrastructure, which is a particularly important through:

- Establishing separate corporate legal entities with a regional mandate for regional transmission systems, drawing on the WAPP experience.

- Reducing the involvement of Governments and utilities in the governance structure of regional infrastructure to ensure they are run on a commercial basis. This could be achieved through divestiture of Governments and utilities from the equity of regional projects, and the transfer of majority ownership to regional institutions or to the private sector.

- Appointing RECs or Pools as monitoring authority for the performance of Regional infrastructure.

- Contractualizing the operation of Regional investments under long term commercial contracts where needed

Ensuring long term sustainability through:

- Retro-fitting to existing regional investment (generation and transmission) security packages to guarantee payment of energy services purchased

- Ensure that entities owning or managing regional infrastructure do not enter into contracts with clients which do not offer investment rating of at least BBB- (investment grade), or a guarantee package suitable to make the transaction rated BBB- by independent rating agencies.

2.6 Lessons from experience

2.6.1 Strong Government Support, in political and financing terms

Strong Government Support, in political and financing terms, is essential for large hydroelectric schemes to be developed successfully. An illustration can be found in the development of the Cahora Bassa which happened because of the clear commitment of Portugal and South Africa who were comfortable with increasing mutual interdependence. The WAGP project is another example of agreed interdependence as a political goal. The perceived risk in terms of energy security did not derail the project. In both cases, the Governments backed their political commitment with financial support as they were the only parties with the capacity to take responsibility for an investment of the size of Cahora Bassa at the time or the political risk of the WAGP.

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A challenge is the continuation of political support for an immutable project scope over the long gestation period of regional projects, which can exceed 15 years. Throughout the seventeen years to complete the conception, planning and implementation cycle of the WAGP project, it proved difficult to keep the stakeholders’ business interests aligned and consistent, and find commonly acceptable solutions for operation of the facilities. The Manantali and WAGP cases, however, demonstrate that project complexity is not an insurmountable obstacle for regional projects.

The development of regional project requires the cooperation of the government of the countries where the project is physically located, as well as the countries where the major off-takers will be located, all of which will benefit from the project. For hydro projects, the Manantali project illustrates the importance of managing the water rights and basin management issues through international agreements and treaties preferably prior to investment project development, but it also shows the danger of developing rigid and too detailed provisions in international agreements, which can hamper future development (Gouina and Felou is proving difficult to develop under PPP due to restrictive provisions of the Manantali and OMVS agreements). Conversely, the lack of such treaty for water rights in the SINELAC case could emerge as a constraint when it has to be addressed ex post for future developments (Ruzizi III).

The cooperation needs to be founded on an international treaty to ensure the support of the highest level in each country and to protect the project against changes in national legislation. The SINELAC, Manantali and WAGP experiences suggest that reaching an agreement on the content of a treaty may be relatively easy and fast when the economic benefits of the projects are well understood by all parties.

The lesson is that at senior political levels, the perceived economic gains of energy trading can trump the concern with energy security and self-reliance for small and mid-size countries.

2.6.2 Political Risk

Immediate political consensus leads to under-estimating the long term potential political risk linked to large regional projects with long distance energy transport. The political consensus leading to the construction of a large project has to hold for the duration of the project, which is several decades.

Cahora Bassa illustrates the fragility of such consensus, the exposure of large high visibility projects and the potentially devastating impact of a change in political alliances on the finance of a regional project. Similarly, in the case of SINELAC, the political consensus during the development and construction phase did not persist through the project operation phase and resulted in each country putting their national political interest ahead of the project’s interest. The WAGP case illustrate another type of political risk, which is the change in Government policies due to economic factors: the lack of gas for domestic uses in Nigeria and the discovery of hydrocarbons in Ghana may result in a change of Government attitude toward the project, which could be highly prejudicial to the project, had it been founded on immediate political consensus, like most public sector projects, rather than on a commercial contractual basis.

An important lesson is that the design of a mechanism to deal with the long term political and policy risks attached to large projects is an essential aspect that needs to be handled prior to integrating such projects into a regional development plan.

2.6.3 Institutions for regional projects

The Governments need to delegate substantial management authority to an ad-hoc entity in charge of project development very early in project preparation. EGL played a key role in the development of the SINELAC project and for consensus building between the three countries involved.

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Regional projects require leadership in negotiations between participating countries and financiers very early in project development. In the case of Manantali, the early designation of OMVS as project developer was instrumental in maintaining the momentum for project development. When an established ad hoc regional institution does not exist from the beginning, as a second best, the countries involved need to agree to designate a credible coordinator for project development at early stages, to be superseded by an ad hoc organization later in the process. This was instrumental in the successful development of the Nangbeto project, where the World Bank played the role of initial project developer. The SINELAC case demonstrates that the project development and construction supervision institution need not be the same as the institution in charge of the operation and management of the project at a later stage. This follows a common practice in the private sector, where the project development company is frequently superseded by a different structure at later project implementation stage.

2.6.4 Assessing and managing commercial risk

Utilities in financial distress cannot be expected to be capable of entering into commercial agreements with a regional project company, even with back-up from the Government, as non-payment will inevitably occur. When there are several off-takers, host or transit utilities/countries, each one of them should be equally creditworthy. Regional projects can operate only between countries where the sector is financially sound, and with credible indication that sector creditworthiness will be maintained in the long-run.

Government commitments to address sector financial issues in the future are cautiously considered by investors and lenders and need to be backed by substantial up-front action. In the case of SINELAC, all three off-takers were in financial distress and had effective tariffs below their production cost. They were unable to operate without Government subsidies, as they had a negative cash flow. It was clear that they could not meet the financial terms of the electricity supply as stated in the Articles of Agreement of SINELAC. The same pattern occurred, although less severely, with Manantali and occasionally, with Nangbeto. Conversely, Cahora Bassa, where the off-taker is ESKOM, no payment issues were noted.

In the case of public sector projects (Manantali), the issue of the creditworthiness of the project sponsor Governments extends to their capacity to meet possible construction cost over-runs. The construction of the second phase of Manantali had to be deferred by nine years because of the inability of the Governments to face large project cost over-runs: the issue is even more complex in the case of multiple participating countries, which need to contribute equally to possible cost over-run. As is the case in private sector project finance, substantial financial reserves should be set-up and funded upfront, funded by the participating Governments to face possible over-run.

2.6.5 Commercial Contractual framework

Even when a regional project is not structured as PPP, its contractual framework needs to be similar to the one of a PPP project in order to guarantee the financial and commercial viability of the project in the long run. The lack of a sound contractual framework with long term contracts led to the unequal renegotiation of the terms of exports for Cahora Bassa, to the financial distress of SINELAC and to a lesser extent, Manantali, as they have no well-structured long term power purchase agreement, take or pay arrangements and dispute resolution mechanisms.

The quality of power purchase agreements is essential and should be the subject of careful review as key project parameters change over time. For example, the terms of the Cahora Bassa purchase agreement resulted in a mis-match between currency of financing and currency of the PPA, and the failure of the pass-through mechanism for repairs due to force majeure, which led to disputes and unfavourable renegotiations, as once large amounts of money are committed, the negotiating power of the seller is limited.

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In general, regional projects owned by Governments or public sector utilities have not been well structured (SINELAC, Manantali, Cahora Bassa, Nangbeto) leading to financial stress or distress. The conclusion is that public sector ownership has never demonstrated its capacity to manage regional projects on a commercial basis, as provisions to ensure financial discipline are weak and can rarely be enforced by public sector regional organizations.

Another lesson from Mananali is that commercial practices should be extended to the procurement of goods and services, which should be organized to minimize overrun and delay risk, rather than splitting responsibilities for procurement between participating countries, with each country procuring for the part of the infrastructure located in its territory, or following the procurement requirements of donors or the constraints on the origin of equipment sometimes imposed by financiers.

2.6.6 Commercial viability

Sustained commercial viability of regional projects requires specific project structuring and is even more challenging than for national projects. Political will to build the project is not sufficient to ensure its long-term viability. In the euphoria of reaching a consensus on the need to build the project and mobilizing financing under complex arrangement, the project fatigue or desire to avoid more potentially controversial negotiations to ensure sustainability with a risk of breaking the consensus reached on other matters has often led to a neglect of sustainability.

Mechanisms need to be put in place to ensure the fully commercial operation of the project in the long run. In the case of SINELAC, Manantali and Nangbeto, the strong political consensus was deemed to be adequate to replace long term contracts and payment/performance securities: experience has demonstrated that this moral commitment is not sufficient and needs to be complemented by long term tariff setting mechanisms and payment guarantees with credible international arbitration arrangements independent from the participating Governments.

For the contractual arrangements of regional projects to be enforced, the project entity and the off-takers should to be fully independent in their management from any of the participating Governments in order to avoid direct or indirect interference at the political level, as happened with SINELAC where the off-takers used their close connection with their respective Governments to put pressure on SINELAC management.

Experience demonstrates that in order to ensure the commercial viability of regional projects, Governments should not set or have authority to revise the tariff, as their main concern is the cost of electricity to their consumers or their political relations with the other Governments involved rather than the financial viability of the regional company. SINELAC, Manantali, Nangbeto and to some extent, Cahora Bassa as ESKOM is represented at the Board of HCB, highlight the conflict of interest of the Governments as owners of the national utilities/indirect suppliers of electricity, and as shareholders.

2.6.7 Governance of regional projects

The Governments of the countries sharing the benefit of a regional project need to be fully informed of the project’s performance. The need for transparency, however, does not require that they hold power in the project management structure, as the project should operate exclusively on the basis of commercial contracts and compliance with national laws. Specific information disclosure agreements between the Governments/regulators and the project companies can ensure adequate information sharing. Alternatively, a minority participation in the equity without veto right may ensure suitable information sharing. The limited interference of the Togolese and Beninese governments in the Nangbeto project management and the relative independence of CEB management has enabled the company to run the Nangbeto scheme fairly effectively while keeping the Governments well informed of the situation and performance of the project. Conversely, in the case of SINELAC, the heavy involvement of

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Governments in the management of the project company has not allowed them to be fully informed of the impact of their decisions on the sustainability of the assets and the company.

2.6.8 Energy Security

The energy supply risk associated with the dependence of a country on regional projects remains a serious concern. It must be addressed effectively if regional energy projects are to develop. The risk has two aspects: the risk of delay in project completion with the possible consequent lack of capacity on the domestic market (regional projects have had longer gestation period than national projects) and the risk of interruption of supply during operation period.

The Cahora Bassa experience illustrates the risk of dependence upon a large source of energy located several thousand kilometres away, with only one transmission route. The Manantali project, illustrate the completion date risk, as the electricity component of the project was delayed by nine years, during which Mali, Mauritania and Senegal had to find alternative sources of electricity, at a higher cost.

In the SINELAC case, Rwanda, Burundi and DC Eastern region are fully aware of the high supply risk due to the inability of SINELAC to maintain adequately the Ruzizi II plant, which is at risk of shutting down any time due to the failure of one of its major transformers.

A conclusion is that the energy supply risk needs to be managed at two levels; (i) at the contractual level, regional contracts need to contain suitable provisions to allocate the supply risk to the operator of a regional project and to compensate the off-taker in case of failure to deliver the energy as scheduled; and (ii) large regional generation projects need to be connected to a regional grid which is suitably designed to accommodate to avoid dependence on a single transmission route.

2.6.9 Integration in Regional Plan

Regional projects need to be integrated in a broader long-term vision of the regional system. Existing regional projects, except possibly Manantali, were rarely designed and implemented as part of a complete regional development plan. Rather, they were developed based on local interests and priorities (Nangbeto, SINELAC, Cahora Bassa) of the countries concerned. The cost-saving potential of more extensive regional interconnection and trans-border trade in the regional context was not explicitly taken into account. It should be recognized, though, that several of the regional projects (Cahora Bassa, Manantali, Nangbeto, Manantali) pre-dated the development of regional institutions for power system integration. Although the OMVS regional scheme was not developed initially as part of the WAPP, it has demonstrated the potential of regional projects to build a consensus around a common vision for the development of the Senegal basin and a regional transmission system.

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3. REVIEW OF REGIONAL INFRASTRUCTURE/ PROJECTS UNDER IMPLEMENTATION OR PREPARATION (HARD AND SOFT)

3.1 Inventory of all projects under implementation and preparation (project Brief /Project Sheets)

3.1.1 Project Brief

A list and map of regional energy projects under implementation, preparation or at planning stage (past conceptual stage) has been prepared and is attached in Annex 2-4. The list of project is presented in Annex 2-4 and Annex 2-5 by REC/Pool in the supporting tables, and by type of project (transmission, hydro power, thermal power, Renewable, capacity building). A distinction has been made between (a) projects in support of the preparation of a physical investment (preparatory studies and capacity building), and (b) projects financing the physical implementation of regional project.

In the case where a project is recognized as a priority by several regional institutions (AUC and RECs), it is listed under the program of both institutions. A major challenge was to obtain information on regional projects from various institutions at the same cut-off date. Information were collected and updated to all extent possible at end-2010 date. Priority was given to projects included in the priority programs of continental and regional institutions. Priority programs of Development partners (IFIs such as AfDB, World Bank, EIB, IDB, DBSA, etc) and bilateral partners (AFD, KfW/GTZ, DFID, China EXIM, etc) were not considered as primary sources of information because they may not reflect exactly the priorities of African political organizations, but used to update the RDC programs when needed.

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Summary maps of Regional projects

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The transmission lines by level of voltage are given below:

Power Lines 220-330 kV

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Power Lines 400-800 kV

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3.1.2 Project Sheets

A set of regional project sheets has been prepared and is given in Annex 2-5 following a standardized format. The sheets cover most of the projects listed in the preceding section, with the exception of projects at conceptual stage which cannot be documented in detail. The sheets are presented by REC and include estimated cost of the preparatory studies as well as estimated investment cost, as well as starting and expected completion dates. Information presented in the sheets was provided by the RECs’ development plans, updated by information provided by financial institutions.

3.2 Detailed analysis of a set of infrastructure programme

A set of regional projects has been selected with particular relevance for

Structuring future regional energy infrastructure for continental integration with a balance between RECs,

Developing or facilitating regional trade and

Lowering the cost of electricity, in line with regional priorities and objectives (see Section 1 above).

The selected projects and their respective potential contribution to Regional objectives are detailed in Annex 2-6 and their main characteristics are given below.

Type Technology Pool/REC

Co

ntributio

n to

R

eg

oina

l Inte

gra

tion

Co

ntributio

n to

tra

de

facilita

tion

Co

ntributio

n to

C

ost R

ed

uction

Mphanda Nkuwa Gen Hydro SAPP Med Medium High

ZIZABONA transmission Trans HV SAPP High High Medium

Ruzizi III Gen Hydro SAPP/CAPP High Medium High

OMVS-SOGEM Gen/trans Hydro+ HV WAPP High Medium High

DESERTECH Gen/trans Sol+HV COMELEC Low High Low

Mmamabula Gen Coal SAPP Med Medium Medium

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3.3 Lessons learned and recommendations

A number of important conclusions emerge from the study of six projects under preparation and development, which will lead to recommendations regarding how to improve the effectiveness of the preparation of regional projects in terms of delay of preparation, finance mobilization and cost control. The main conclusions are presented below.

3.3.1 Suitable Institutional arrangements are decisive for the smooth development of regional projects.

The main obstacles to a faster development of regional projects are

the delay in establishing a single entity in charge of the project; and

the persisting approach of transmission projects from a national standpoint.

Leadership for the development of regional projects is slow to emerge and cooperation between countries and utilities remains informal for long period of time

In several cases (Zizabona, in particular, but also WAPT) the role of the REC or Pool is acknowledged by participating countries and is helpful in ensuring that the project is viewed as a single project. It helps also approaching donors with a coherent vision and project. In general, the collaboration between stakeholder countries and the regional Power Pool and REC is effective. But the projects remain strongly under the control of each country for their section of the project and the resulting lack of leadership and the difference in level of priority granted to the project by the countries involved may result in complications in mobilizing financing for a global approach in preparatory works.

Conversely, the early call on an existing regional institution with experience with regional project development, as it is the case for Gouina/OMVS and Ruzizi III/EGL can contribute to accelerate the project preparation process and facilitate the mobilization of funds for project development and preparation. It should be recognized, though, that the role of the existing regional institutions may need to be revised as they are entrusted with their development. For example, the statutes of OMVS and SOGEM may need to be revised to allow the development of projects under PPP, and the mandate of EGL for Ruzizi III may need to be revised to include the management of the Lake Kivu basin. These experiences demonstrate that the mandate of institutions created for developing regional projects should be flexible and allow future adjustments as the need emerges.

An illustration of the advantage of establishing very early a single institution with strong leadership in charge of a new regional project is given by DESERTECH. In this case, very powerful institutions for project development have been established upfront, even before the feasibility of the project is established. With the DESERTEC Foundation, the Industrial Initiative (DII) GmbH and Medgrid society, a permanent institutional framework has been set up, which has been lobbying for support very effectively.

The emerging recommendation is that a single Project Developer should be designated by all stake holding countries with extensive authority for project development, communication with donors, at a very early stage, as soon as the project is identified, rather than at pre-feasibility stage or even later.

Decision to develop regional projects on a regional basis rather than on a national basis comes often under pressure from donors. Regional projects need to be developed on a regional basis from the beginning and it is the role of the RECs or Pools to ensure that regional projects are recognized as such very early and delegation of authority from the stake holing countries to ad hoc project development institutions is organized at identification stage.

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The Case studies illustrate two cases where the REC/Pools played an important role in ensuring the development of new projects as regional projects integrated in a global regional vision from early stage on: this was the case for Gouina where the WAPP and ECOWAS are playing an important role in defining the project as regional from the beginning; it is also the case for Ruzizi III which has been defined as a regional project early on by CEPGL. Indeed, close contact and interaction with the countries involved and their utilities have been maintained from the beginning to ensure that the countries do not feel dispossessed of the projects. This approach has facilitated the development of a consensus amongst donor to support the projects as multi-national regional projects and contributes to reinforce the credibility of regional projects with individual countries.

A limitation in this approach for an early characterization of a project as regional is illustrated by DESERTECH, where the institutions have become the project whose accomplishments are dominated by lobbying for support rather than producing bankable studies or other tangible progress in terms of technology or financing arrangements.

Conversely, projects like Mmamabula and Zizabuna demonstrate that the continued dominance of a country-level vision over a regional approach does not facilitate or accelerate project preparation.

While the regional plan prepared by SAPP has identified the Mmamabula Energy Project as part of the least cost development plan, the decision to proceed with this investment is being made by national planning and regulatory authorities in South Africa and little alternative market for Mmamabula electricity has been considered. In the case of Zizabuna, the concept is recognized as regional, but there is no corresponding institution for project development, which remains under the control of each country. Despite good collaboration between countries during the planning stage, progress has been slow overall. The project was first identified in 2007 at a time the region was experiencing severe power outages. By 2010, studies are just starting. While power shortages have continued, the project is unlikely to come on stream before end 2012, and most likely, after 2014. This has resulted in slow project development and scheduling uncertainty. Difficulties should be expected at procurement and construction stage to ensure the coordinated and timely implementation of the project.

3.3.2 The RECs and Pools may play a more proactive role in identifying regional projects early and in developing the ad hoc institutional framework.

Responsiveness of institutions in charge of the development of regional projects to countries’ energy availability issues is insufficient and produces a climate of distrust of countries toward regional projects under development

Although institutions in charge of the development of regional projects are aware of the urgent need for low cost additional capacity in participating countries, there is a feeling amongst project countries that once a project is classified as regional, they may lose control over its development and schedule, and that institutions in charge of the development of regional projects may not take sufficiently into account the constraints of needs of their member countries. Illustrations can be found with Ruzizi III, developed by EGL. The sector planning document in Rwanda mentions Ruzizi III as a possibility rather than a priority and is developing alternative investment projects in parallel. Similarly, although Senegal, Mauritania and Mali strongly support the Gouina project, they seem not to rely on the timely implementation of the project to meet their domestic demand and have alternative investment programs under consideration.

The counterpart to the delegation of authority by Governments to a ad hoc institutions created at the initiative of the RECs or Pools is that these institutions deliver regional projects as scheduled. To achieve this goal, the ad hoc institutions need to improve their project development and management capacity to shorten project preparation time, and

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the approach of donors to regional projects needs to become programmatic rather than opportunistic.

Phasing of large regional projects from design stage is important to facilitate their financing, and phased implementation should be included as a requirement in design when it is feasible.

A major problem for regional projects implementation is that their cost is generally very high, above USD 1 or 2 billion, if not tens of billions, because of their size. A purely technical approach often favors a holistic implementation, as being technically optimum and less costly, but experience demonstrates that raising financing of this magnitude from donors or investors is a major challenge, because of the perceived high risk of lumpy projects. In many cases, a phasing of the project is considered, but this approach, which can facilitate financing and faster implementation, often comes as a second thought, late in project preparation. In the case of Mmamabula the envisaged project phasing is a strong point of the project, limiting the upfront financial commitment. Conversely, the reluctance of the project developers to consider a really phased approach in the case of DESERTECH is an obstacle to project development because of the lumpiness of the investment and the significant risk of cost overrun. The design of large regional projects should focus from the beginning on project financial feasibility, risk management and adaptability to changing economic conditions.

For lumpy projects, the possibility of phasing should be built in the project design from the beginning, and project phasing should be a major consideration in the selection of priority regional projects, to maximize their chances of bient implemented on time, or even, at all.

The financial structuring of regional projects needs to be developed in parallel to the physical design and economic/environmental analysis. Entities in charge of the development of regional projects under-estimate financial structuring and schedule it poorly, with resulting major delay in implementation. They either defer financial structuring until all other studies are completed, or rush to select a developer before alternative financing structures have been fully explored

There is a lack of understanding of the importance of financing strategy studies before completing the technical design and approaching potential financiers, from the public or private sector. It may result in hasty selection of private partners, resulting in unfavourable terms for the Governments/the public, incomplete financing plan and delay in project development and implementation. Postponing the analysis of alternative financing strategies until technical studies are completed can not only increase project preparation time, but waste resources, as the scope of technical studies is dependent upon the type of financing that will be retained (detailed engineering prepared by private sponsors, EPC contract multiple procurement package approach depending upon financing structure).

In the case of Mphanda, the sequencing of the technical, economic, financial structuring, commercial arrangements are not optimal. It may result in significant implementation delay, poor financial results for Mozambique as the search for financing becomes more and more pressing and a cause of delay and an excessive share of risks being borne by Mozambique to secure accelerated financing. Mmamabula provides another illustration of project delay and poor timing of the selection of an investor due to lack of a project financing strategy. The mode of selection of the Developer CIC seems to be direct negotiation rather than open competition. The selection of the developer when the project financial structure and the terms of the main off-take were still undefined was premature and has resulted in a developer sitting on a stalled project and has restricted capacity for the Government to redefine the project concept on a truly regional basis.

Another illustration can be found in the Zizabuna project, which is developed as a concept without a clear financing strategy, this aspect being left for each country to handle.

The potentially wasteful impact of poor coordination of preparatory studies can be found in the Ruzizi III project, under which the TOR for the multi-million dollar feasibility study were based on the assumption that the project will be financed entirely by donor money, whereas a PPP financing approach has been ultimately agreed between EGL and the donors, making the component of the engineering study for detailed engineering of little usefulness.

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Conversely, technical, financing strategy and environmental studies have been coordinated in the case of Gouina, in order to avoid delay in project implementation between the time the technical studies are completed and a financing structure is adopted. The project management team, drawing on the experience of Manantali and Félou, dedicated significant resources and called on high level expertise to explore alternative financing structures, in cooperation with potential donors.

Regional projects being particularly complex to finance because of their size and the multiplicity of stakeholders, it is particularly important to ensure that the technical, economic and financing studies progress in parallel and feed into each other. The all too frequent sequential approach where studies on financial structuring follow technical and economic studies is one of the main causes of delay in implementation and poor project commercial sustainability. Awareness of the importance of financial structuring in the RECs and Pools is much higher than a decade ago, and needs to be further increased, particularly when the need for financing of regional projects is bound to far exceed the financing available from traditional sources.

A large number of regional projects seem to be developed under the implicit assumption that they will be financed from concessional aid or grants. As result, the issue of the creditworthiness of the project is not given due consideration early in project design and can becomes a stumbling block and a major cause of delay.

A key consideration for the overall creditworthiness of a regional project is the creditworthiness of the host country, and the creditworthiness of every off-taker of electricity or user of services in case of a transmission line. A particular challenge for regional project is that every off-taker or service user has to be creditworthy, and the creditworthiness of the project is the creditworthiness of the weakest of its stakeholders. In addition, each of the stakeholders needs to be identified and its involvement has to be guaranteed for the life of the project. These fundamental principles are often overlooked in the choice of regional projects to be developed, or early action is not taken to ensure that the creditworthiness conditions are met when the project reaches financial close. For example, the Mphanda project is being developed, and development rights have been given to a developer although the project, if developed under its present structure, is unlikely to be bankable in the absence of an identified and creditworthy off-taker. The concession has been awarded prematurely, and the Government and the developer do not have a common vision regarding the market of the project output, with the Government targeting the domestic market with EDM (non creditworthy) off-taker, and the developer targeting ESKOM who is reluctant to give long term off-take guarantees. Given the size of the project, it can be said with reasonable certainty that it will not proceed until the commercial arrangements with a creditworthy off-taker have been firmed-up.

A similar case is found with Mmamabula. The importance of off-take arrangements being negotiated in principle well in advance was overlooked by the Government, which focused on technical aspects and the early selection of a developer. A fundamental weakness of the project is that it does not have a commitment from a credible purchaser of electricity, with ESKOM indicating they are not ready to commit to purchase power from Mmamabula. Until the issue of finding a creditworthy off-taker is addressed, the project is unlikely to proceed under acceptable conditions for the Government of Botswana.

DESERTEC is another case where the project is being developed without suitable off-take arrangements being explored and put in place upfront, except for assuming that substantial ad-hoc institutional and regulatory changes to the European power market regulation will be made to ensure the profitability of DESERTEC, with a substantial transfer of income between consumers and industrial groups.

On the other hand, in the case of Ruzizi III, the project developer, EGL, has reached agreement in principle with the potential project off-takers and the Governments involved regarding how the issue of the creditworthiness of SNEL, REGIDESO and RECO will be addressed. This issue was flaged at an early stage of project development, in order to ensure it will not be a cause of delay when the project is technically ready for implementation.

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3.3.3 An assessment of the creditworthiness of all stakeholders in a regional project needs to be carried out at pre-feasibility stage

An assessment of the creditworthiness of all stakeholders in a regional project needs ot be carried out at pre-feasibility stage, and a strategy to address the issue, which may take a long time to implement, needs to be developed before a full feasibility study is engaged, as there is little point in fully developing a regional project which has little chances of being financed.

In all cases reviewed, a major cause of delay in project preparation and development was that each stage of project development had to secure its financing upon completion of the previous stage. As the cost of preparation escalate with the degree of detail of the studies needed, financing becomes increasingly difficult to mobilize.

In general, financing of pre-feasibility work seem to have been fairly easy to secure. The search for financing of the next stage, that is, feasibility work is generally initiated only when the pre-feasibility is completed. The negotiation of financing with donors may take a year or more, and the preparation of the selection of the expert for feasibility work may take a year or more, delaying project implementation accordingly. In the case of Zizabona, it took three years to mobilize financing fore the project feasibility study. The same delay was noted for Ruzizi III. Similar situations occurred for Mphanda and Mmamabula.

Project development cost can represent 5% or more of total project cost, and the development cost of large regional projects is particularly high. The financing of regional projects development has been so far dependent upon the goodwill and priorities of donors. For regional projects to be developed over a period of five years of less (compared ot 10 to 5 years at present), a special facility for financing the development of regional projects needs to be put in place. As it is unlikely that such a regional project development facility could be financed up to the necessary level by power utilities or the Governments, funding will have to come from donors. It is not unrealistic to assume that sufficient financing could be mobilized with the donor community, but the key issues to be addressed are that the funding of the regional project financing facility should be funded globally by donors, rather than on a case by case basis (which is the main cause of delay and waste of funds). For that to happen, the donors would have to agree to give priority to regional projects over their preferred political agenda. On the other hand, the RECs would have to agree that the management of the facility will follow strict fiduciary rules and be protected from any political interference. A private management under a Trust structure could be an approach to be considered.

The sharing of benefits from regional projects between the countries involved is rarely considered at development stage and for large regional projects, has been raised at a late stage of project development, generally by donors.

In most regional projects, it is assumed that the services will be provided at cost. This assumption will have to be revised when regional markets develop: on a free market, electricity from regional projects will be sold at market price, with a rent (difference between the production cost of regional projects and market price) that will need to be equitably shared. This issue has been anticipated in the case of Mphanda, where off-grid rural electrification will benefit from a levy applied to exported electricity and managed by FUNAE. This scheme provides an interesting example of how the benefits of regional projects can be applied to social development programs.

As the Pools and RECs progress with the development of regional power markets, they may need to examine how a portion of the benefits arising from the low cost of regional projects will be transferred to society, preferably to being appropriated in totality by export oriented industries or private investors.

Regional project often have a significant socio-environmental impact because of their size. It is noticeable that regional projects are often at the center of heated debates regarding their socio-environmental impact.

The management of the socio-environmental aspects of regional projects needs to be organized carefully from the beginning, with effective communication with all stakeholders to

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avoid regional projects becoming hostages of partisan debates because of their political visibility with the countries as well as with donors. In certain cases, project developers preferred to seek to minimize discussion of the projects’ socio-environmental aspects, as it was the case for Mphanda. At the other end of the spectrum, the developers of DESERTEC are emphasizing the socio-environmental aspects of the project to the point where this dimension has taken precedence over the technical, economic and financial aspects of the project. The lingering debate on the socio-environmental aspects of regional projects such as Manantali, WAGP or Cahora Bassa illustrate the importance of the development and implementation of an effective communication on the socio-environmental aspects of regional projects and the risks of seeking to minimize the debate on the socio-environmental dimension of large regional projects.

To the same extent that the development of a project financing strategy should be undertaken at project pre-feasibility stage, a communication strategy should be designed and implemented in parallel. The communication strategy is different from the project ESIA and requires is own specific means, instruments and actions.

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ENERGY Sector - Report III : Outllook for the Future


PART III - OUTLOOK FOR THE FUTURE AND IDENTIFICATION OF CHOICES CHALLENGES

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Table of Contents

1. OBJECTIVE..............................................................................................................3 1.1 Background .................................................................................................................................................................................. 3

1.1.1 The approach ............................................................................................................................................................ 3 1.1.2 The starting point .................................................................................................................................................... 3

2. Methodology, parameters, assumptions, and tools (methodological brief) ......................................................................................................................... 5

2.1 Energy................................................................................................................................................................................................5 2.1.1 Increase in electricity access. ........................................................................................................................ 6 2.1.2 Outlook for Mineral Resources Development.......................................................................................7

2.2 Capacity .......................................................................................................................................................................................... 8

3. OUTLOOK FOR THE FUTURE ..............................................................................9 3.1 Demand projections................................................................................................................................................................ 9

3.1.1 At the continental level........................................................................................................................................ 9 3.1.2 Electricity Demand, Access ad Investment in Access by REC ...............................................13

3.2 Supply projections...................................................................................................................................................................18 3.2.1 The nuclear option ................................................................................................................................................18 3.2.2 Thermal Power Technologies ........................................................................................................................19

3.3 Analysis of choices and challenges – defining objectives and targets .............................................21 3.3.1 Identification of key issues and challenges.........................................................................................21 3.3.2 The List of Scenarios ...........................................................................................................................................31

3.4 Setting objectives for the Infrastructure development framework and investment program32 3.4.1 Priorities and Objectives ..................................................................................................................................32 3.4.2 Resource Availability for Energy Investment Program ...............................................................................35 3.4.3 First Cost Quantification and Estimated Deadlines.......................................................................37 3.4.4 Preliminary Priority Regional Investment Projects under PIDA...............................................44

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1. OBJECTIVE

1.1 Background

1.1.1 The approach

For the electricity sector, the Outlook will be defined in terms of energy produced and consumed (kWh) and peak demand to be met (kW) through available generation capacity using optimum and least cost technology mix, and high voltage transmission flows through existing, reinforced and new lines. Several Outlooks or sector development scenarios will be established, depending upon key policy decisions, detailed below. Projected demand will be determined primarily through the underlying GDP growth for each country, population growth, access rate to modern energy, and expansion of grid-connected electricity. Outlooks will be prepared at the individual country level, as one of the purposes of the study is to establish the need for energy transport between low cost production centers and demand centers, and consolidated by REC and at the continental level. The Outlook will present a continental vision of how the geographically allocated growth in demand will be met through the development of energy supply centers and of energy transport infrastructure. The energy sector Outlook will be developed using an optimization model for electricity supply-demand balance, with a separate transmission optimization model. The methodology used for the electricity Outlook will be similar to the approach adopted in the recent AICD study and in the Long Term Least Cost Development plans developed by the various power pools over the past three years1, adapted as needed to cover the entire continent and with a focus on regional production/generation and transmission/transport projects, taking into account environmental, financial and energy security considerations.

1.1.2 The starting point

Under-exploited energy resources and under-served demand.

Africa has 15% of the world’s population but accounts for only 3% of the world’s primary energy consumption (renewable energy and waste excluded) and 5-6% of world’s final energy consumption (renewable energy and waste included). Electricity consumption per capita is 1/6 of world overall average. The region therefore needs to make renewed efforts to bring about a major expansion of its already well identified energy potential.

1 The SAPP, WAPP, EAPP, CAPP and the Maghreb countries, in particular

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Figure 1 Electricity consumption per year per capita in Africa

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The incentive to pool energy resources is thus strong and led to the formation of regional power pools in the 1990s. However, cross border power trade has yet to take off outside of the Southern Africa Power Pool (SAPP). In SAPP about 10% of total consumption came from trade activities in 2008, but this share dropped significantly thereafter due to generalized capacity shortages (see Table 2). However, even in the SAPP most of the trade – e.g., South Africa-Mozambique, Zambia-Namibia – is governed primarily by bilateral contracts. In West Africa, power trade is only 5% of total consumption.

Table 2 Regional trade in electricity, 2005

Consumption, TWh Imports, TWh Exports, TWh

Percentage electricity

traded

CAPP 8.80 0.01 1.80 0.1

EAPP 13.41 0.28 0.18 2.1

SAPP 233.97 22.71 25.74 9.7

WAPP 28.63 1.63 2.04 5.7

Source: EIA, 2008.

In the meantime, many sub-Saharan African countries continue to experience an acute shortage in energy supply which will take time to eliminate. This obstacle makes the goal of universal access to electricity by 2040 very challenging for a majority of African countries. Expanding regional energy integration is therefore an essential step to improve affordability by households if these universal access goals are to be achieved.

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2. Methodology, parameters, assumptions, and tools (methodological brief)

The development of a set of Electricity sector Outlooks to feed in the formulation of a Regional Investment program includes the evaluation of the prospects for future demand of energy and the determination of how this demand will be met on the supply side. It will follow three steps:

The formulation of a Regional Energy Demand Outlook, including inter alia energy and capacity demand for the period 2008-2040

The identification of key economic and policy parameters affecting the supply side which will define alternative Outlook scenarios

The discussion of alternative electricity technologies considered in the Outlooks, covering nuclear energy, traditional electricity generation technologies and Renewable Energy technologies

The Formulation of a Regional Energy Demand Outlook and preparation of demand projections is under a time horizon 2008-2040, in annual increments.

2.1 Energy

The energy demand Outlook is determined by country specific macroeconomic forces. Some of these factors can be quantified objectively– e.g., GDP and population growth – while others are more dependent on country policy objectives, such as the target for access to electricity in all countries except North Africa, where access is already close to universal coverage and others are more country specific, such as the development of large and extractive industries, when they are grid-connected.

The energy demand functions that were used for projecting country demand are:

= +

Where:

D is the unconstrained demand; ɛ is the GDP elasticity of electricity demand defined as

;

k is the average annual consumption of electricity of one household;

is the number of new connections in year t ; and

is the additional demand from the natural resources sector in year t to reflect the significant impact on the demand of new mine developments, provided they draw their electricity from the power grid.

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The key quantitative elements of the energy sector Outlook will include the following parameters:

GDP growth. GDP growth scenarios are based on projected annual growth rates for Africa of 6% on average, differentiated by country based on the PIDA Country macroeconomic projections. The GDP projections affect the demand forecast primarily through the income elasticity of demand. The income elasticity parameters will be obtained from a statistical analysis of electricity demand compared to GDP growth over the 2000-2008 period. As the African countries present a diverse population in terms of present situation and recent history, the African countries have been classified into five categories, following the AICD categorization, revised to include North African countries:

Fragile Low Income Countries2

Non-fragile Low income 3

Internediate Income4

Resource rich countries5

North Africa6

In the statistical analysis, only countries where demand was relatively un-constrained by lack of capacity were considered, using the number of hours of load shedding as an indicator of unconstrained demand. The results were compared to the estimates available in the literature, including World Bank7 and academic research8 on electricity income elasticity of demand.

The elasticities evaluated through the Simple Least Square method are: Fragile Low Income Countries: 0.86; Non-fragile Low income: 1.33; Intermediate Income: 1.20; Resource rich countries 1.16; North Africa: 1.18. These estimates are consistent with estimates found in the literature ranging from 1.1 to 1.3 for non-fragile, developing countries, and with the general conclusion that GDP elasticity of electricity demand decreases with per capita GDP.

2.1.1 Increase in electricity access.

The outlook for electricity access will be developed at the country level, based on the objectives of each Government. All countries project significant increases in electricity access rate, but there are national differences, which need to be taken into account to determine the growth of the main demand centers. In broad terms, except for North Africa where the access rate is already high, the electrification rate is projected to increase rapidly between 2008 and 2040, in sharp contrast with the past trend which showed only slow electrification progress. The electrification rate in each country is projected to increase by 2%, in addition to the natural growth of the population, until it reaches 60%; the time required to achieve this level depends upon the starting level specific to each country. Subsequently, access is projected to plateau and increase slowly until 2040.

2 Including CAR, RDC, Liberia, Burundi, Sierra Leone, Guinea Bissau, Côte d’Ivoire, Togo, Djibouti, Eritrea and Somalia

3 Mauritania, Mali, Niger, Senegal, Burkina Faso, Benin, Ghana, Ethiopia, Tanzania, Kenya, Uganda, Mozambique, Rwanda

4 Botswana, Namibia, Swaziland, South Africa, Lesotho

5 Nigeria, Cameroun, Equatorial Guinea, Angola, Zambia, Malawi, Gabon, Chad, Soudan, Congo

6 Morocco, Algeria, Tunisia, Libya, Egypt

7 cf. César Calderón, “Infrastructure and Growth in Africa”, Washington, World Bank, 2009.

8 See, for example, Vishal C. Jaunky, “Income Elasticities of Electric Power Consumption: Evidence from African Countries”, Department of Economics and Statistics, University of Mauritius December 2006

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Electrification rate (indicative estimate)

Continental average 2008: 29% - Continental level: rural: 14%; urban: 54%

2008 2020 2030 2040

Rural Urban

Northern Africa 85% 95% 95% 97% 98%

Southern Africa 10% 64% 40% 60% 75%

Western Africa 2% 66% 38% 55% 68%

Central Africa 1% 21% 15% 20% 30%

Source: AICD Report

Electricity demand per residential household retained in the countries' Long Term Development Plans is typically included between 300 kWh for low income households 500 kWh for middle income households and 900 kWh and more for high income households. The weighted average is 550 kWh. However, one needs to consider the electricity consumption of social and community services associated with electrification. An additional total demand per connection of 750 kWh has been retained in the evaluation of the demand attributable to connections made under the access programs. The annual cost of the accelerated electricity access program was estimated as a by-product of the demand projections, multiplying the number of annual connections needed to achieve the targeted access rate, by a unit cost per connection of US$ 700 per connection9.

2.1.2 Outlook for Mineral Resources Development.

Although a number of mining and natural resources related companies have a strong preference for developing their own captive power generation capacity, future grid-connected demand for electricity will be affected by the outlook for the development of mineral resources. At the same time, building generation capacity in expectation of a mining step-load can be a risky proposition for a national utility. Projects for the development of mineral resources are often highly uncertain and many such investments have been under discussion for decades. In order to reduce the uncertainty that surrounds the accretion of mining sector electricity step loads, the team obtained estimates of the prospects for mining and natural resources related development at the continental level from the AUC. Such estimates are generally considered more reliable than either aggregated national mining development programs, which tend to be optimistic, or information directly from the main international mining groups on their development plans for Africa, which are commercially confidential. Considering that there is a close correlation between GDP growth and the expansion of natural resource based activities through the development of mining and ancillary activities, demand originating from the development of this sector was projected to increase at the same pace as the country's GDP for the future.

An example of a country specific demand projection sheet is given in Annex 3-2

9 Connection cost varies between US$ 300 and US$ 1000 per connection, depending upon the technical standards retained and the configuration of the terrain. Network densification in urban centers is indeed less costly that connecting rural populations in remote areas. The retained value of SU$ 700 per connection is an average, including cost of community and social buildings.

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2.2 Capacity

The country energy demand in MWh was converted into capacity demand in MW using the historical average load factor specific to each country (Annex 3-2), which was assumed to be constant over time.

Starting from the actual served demand in the base year (reflecting possible shortages of capacity), a convergence path toward fully served demand (with no unserved demand) over a period of five years was estimated. The time series of demand starting from the present situation, converging toward fully served demand over five years and following projected unconstrained demand thereafter represents for each country the projected served demand, both in terms of energy (MWh) and capacity (MW).

The next step was to calculate the generation needed to meet the demand. It was evaluated by adding the T&D losses to the demand in MW and in MWH which represents the generation required to meet the served demand. Finally, required reserve capacity and export demand will be added to (and imports deducted from) the production capacity needed to determine the installed capacity needed for each country. The reserve capacity needed to guarantee a Loss of Load probability of 5% was calculated by the optimization model.

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3. OUTLOOK FOR THE FUTURE

3.1 Demand projections

The electricity demand projections were estimated for each country and aggregated by REC and at the continental level. They are detailed in Annex 2-2.

A summary of the demand for electricity by REC is provided below. The detailed figures are provided in Annex 3-2.

3.1.1 At the continental level

Overall for the African continent, the power demand is projected to increase considerably by a factor of eight (800%) over the period. The average energy growth rate of energy demand is 7.1% p.a over the entire period, split between a period of moderate growth from 2008 to 2020 of 6/6% p.a. followed by a period of accelerated growth of 7.9% from 2020 to 2030 and a slow down in growth between 2030 and 2040 to 6.4% p.a. The capacity growth rate over the period is 7.5%, slightly higher than the energy growth rate as the system load factor tends to increase. Capacity growth is 6.7% p.a. over the 2008 to 2020 period, followed by a higher rate over the 2020 to 2030 period of 8% and a slow-down after 2030 to 6.5% p.a. This trend has two explanations:

GDP growth is stronger in the pre-2015, and particularly after 2020 as the African economies catch-up with the rest of the world. As the GDP elasticity of electricity demand is above one on average, electricity demand progresses faster than GDP;

The 2015-2030 period is a period of accelerated access to electricity in all countries, except North Africa, adding to the demand generated by GDP growth. Most African countries see their access rate multiplied by a factor of three or more and by 2025, nearly all countries, except some post-conflict countries, have an access rate above 50% (see Annex 3-2). Under the proposed demand Outlook for energy, the 2011 to 2025 period will see a radical transformation of African society, with electricity reaching low-income households in urban areas, and a majority of households in small urban centers and in rural areas. In fact, the targeted > 50% access rate means that more than 50% of households have access to modern electricity, as multiple connections are not rare in SSA. The electrification effort is expected to be sustained in all countries simultaneously, in line with the priorities spelled out in the AU and REC energy policies (see Section 1). The implications of the accelerated electrification policy at the continental level will have significant financial implications. The preliminary estimate of the investment cost of an African access policy aiming at an access rate above 50% by 2015 is summarized in the table below.

Overall, the continent will need 1 302 GW of additional capacity to reach a capacity of 1 4790 GW in total.

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Summary of Africa's Energy Demand and Access growth 2009-2040

2009 2020 2030 2040 Total

Period

Capacity in GW 167,627 362,189 786,484 1,470,337

Annual Growth rate in Capacity in preceding 10 years

6.91% 8.14% 6.60% 7.13%

Increase over the period MW) 194,562 424,295 683,853 1,302,710

Access Rate 42% 57% 65% 66%

Investment in Access (million US$_ 30,333 27,635 11,488 69,456

The increase in demand for capacity and energy is illustrated in the graph below:

Increase in demand for energy and capacity 2009-2040

The increase in energy and capacity demand includes the additional demand due to the increase in access, which is part of all Governments in Sub-Saharan Africa. Overall access is projected to increase as shown in the graph below, from 42% at present to 66% by 2040.

Overall Electricity Access Rate for Africa Overall Investment in Access for Africa

Electricity Demand, Access and investment in Access by Region

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Capital Investment in Access by Region (In million US$)

The Graph above shows that investment needed in Access for Africa is about US$ 2.5 billion annually over the 2010-2040 period, and about US$ 1.2 billion per year is needed for Low Income countries alone, followed by Resource Rich Countries (because of their large size), and Fragile Low Income Countries which will need about US$ 500 million every year over the period.

The result of the estimated investment presented above is to increase overall access for the whole of Africa from about 38% at present to 64% by 2040, following the path presented in the graph below.

The overall increase in Access is front-end loaded between 2008 and 2030, reflecting the “voluntarist” policy adopted by all countries of SSA, the AU and the RECs concerning access.

Considering each group of countries, the trend of access is given in the graph below:

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Electricity Access Rate by Group of Countries

Under the retained assumptions for increase in electricity access rate, the gap between Fragile Low Income countries and Intermediate Income countries, which is presently from 17% to32%, will narrow to 5%: 53% compared to 58% for Intermediate Income Countries.

Electricity Energy Demand by Region (in TWh)

In terms of capacity demand, the trend in each group of countries is presented in the graph below:

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Electricity Capacity Demand by Region (in MW)

.

3.1.2 Electricity Demand, Access ad Investment in Access by REC

The demand projections by REC are presented below.

COMELEC

Future demand and access rate is summarized below. Capacity is projected to increase by 7.1% over the 2009 to 2040 period and additional capacity will be 551 GW. Access is projected to remain constant at close to 95%.

Summary of COMELEC Energy Demand and Access growth 2009-2040

2009 2020 2030 2040 Total

Period

Capacity in GW 67,237 143,170 311,943 579,182 Annual Growth rate in Capacity preceding 10 years 6.9% 8.2% 6.5% 7.1%

Increase over the period MW) 75,933 168,773 267,239 511,945Access Rate 93.5% 93.5% 93.5% 93.5% 93.5%

Graph Future Energy and Capacity demand COMELEC 2009-2040

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SAPP

With an average annual growth of capacity needed of 6.3%, the system will need an additional 346 GW of capacity to meet a 600% increase of capacity needs over the 2009-2040 period. This additional capacity will be able to sustain an increase in access from 26.9% in 2009 to 56.4% by 2040, provided US$ 15.7 billion are invested in Access.

Summary of SAPP Energy Demand and Access growth 2009-2040

2009 2020 2030 2040 Total

Period

Capacity in GW 57,007 111,134 226,091 403,990 Annual Growth rate Capacity preceding 10 years 5.6% 7.4% 6.1% 6.3%Increase over the period MW) 54,127 114,957 177,899 346,983Access Rate 26% 47% 56% 56% Investment in Access (million US$_ 7,736 6,355 1,661 15,752

Graph Future Energy and Capacity demand SAPP 2009-2040

Access Rate 2009-2040 Investment in Access 2009-2040 (in million $)

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WAPP

With an average annual growth of capacity needed of 8.9%, the system will need an additional 141 GW of capacity to meet a 1 400 % increase of capacity needs over the 2009-2040 period. This high expansion is due to the projected high GDP growth and to the increase in access rate. This additional capacity will be able to sustain an increase in access from 35% in 2009 to 62% by 2040, provided US$ 16.9 billion are invested in Access.

Summary of WAPP Energy Demand and Access growth 2009-2040

2009 2020 2030 2040 Total

PeriodCapacity in GW 10,285 27,488 69,490 151,420 Annual Growth rate Capacity preceding 10 years 9.05% 9.85% 8.26% 8.96%Increase over the period MW) 17,203 42,002 81,930 141,135Access Rate 35% 52% 61% 62% Investment in Access (million US$_ 8,843 5,029 3,037 16,909

Graph Future Energy and Capacity demand WAPP 2009-2040

Access Rate 2009-2040 Investment in Access 2009-2040 (in million $)

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PEAC

With an average annual growth of capacity needed of 7.8%, the system will need an additional 29 GW of capacity to meet a 1 200 % increase of capacity needs over the 2009-2040 period. This high expansion is due to the projected high GDP growth and to the increase in access rate. This additional capacity will be able to sustain an increase in access from 15% in 2009 to 54% by 2040, provided US$ 7 billion are invested in Access.

Summary of PEAC Energy Demand and Access growth 2009-2040

2009 2020 2030 2040 Total

Period


Graph Future Energy and Capacity demand PEAC 2009-2040

Access Rate 2009-2040 Investment in Access 2009-2040 (in million

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EAPP

With an average annual growth of capacity needed of 7.7%, the system will need an additional 273 GW of capacity to meet a 1 000 % increase of capacity needs over the 2009-2040 period. This high expansion is due to the projected high GDP growth and to the increase in access rate. This additional capacity will be able to sustain an increase in access from 41% in 2009 to 65% by 2040, provided US$ 29 billion are invested in Access.

Summary of PEAC Energy Demand and Access growth 2009-2040

2009 2020 2030 2040 Total

Period


Graph Future Energy and Capacity demand PEAC 2009-2040

Access Rate 2009-2040 Investment in Access 2009-2040 (in million

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3.2 Supply projections

In order to meet the demand for energy and capacity presented above, the African countries have a large number of technical options to consider. The characteristics of each of these options are described in detail in the Annex to the present report.

3.2.1 The nuclear option

A special attention was paid to the nuclear option for Africa as a low GHG emission solution (nuclear plants total emissions are five times lower than gas fired plants and 15 times lower than coal fired plants, see Annex 3-3 Figure 2) and a technology which would reduce the dependence on imported hydrocarbon fuels (gas represents 60% of the generation cost of a gas fired plant, whereas uranium represents only 5% of the production cost of a nuclear plant), while increasing the utilization of uranium which is available in Africa (Niger, Namibia, South Africa, for example). The main motivational factors seem to be:

For countries that possess large conventional fossil fuel reserves, the realization that these fossil fuel supplies might one day become exhausted; in several forecasts, oil and gas reserves would approach exhaustion in about three decades, although newer estimates and new discoveries keep extending the time of exhaustion. In this context, diversification of energy sources would be a desirable strategy.

Continuing dependence on fossil fuels could expose, in due course, the country to new price hikes.

Continued reliance on fossil fuel imports, for countries that are currently heavily dependent on them, could expose them to security-of-supply concerns, namely to disruption owing to physical, economic, political and other causes.

Renewable energy sources may be present in many African countries. Solar energy is, generally speaking, abundant. However, solar power is still quite expensive and is not conducive to base-load power, unless good methods of electricity storage become available, technically and economically, which is still not the case. Nuclear power, on the other hand, can supply large quantities of electricity at high reliability and availability levels, at competitive costs.

Introduction of nuclear power could have favourable side effects in the country, namely, increase in the educational level, technical capabilities, and professional skills of the country’s professionals, as well as spin-off effects such as applications of radio-nuclides to agriculture, manufacturing, medicine and other sectors.

As solar and wind may not be adequate for base-load power, nuclear can serve as a carbon-free source of electricity and reduce the country’s carbon emissions that, sooner or later, are expected to be required of all countries.

A number of countries were selected for a closer look in terms of nuclear power prospects. The criteria for this selection were: (i) explicitly presented interest by the country; (ii) the size of the population; (iii) the size of the power system; (iv) corroboration and possible enhancement of this interest by the developed world and expressions of support; and finally (v) the viability of the expressed interest to become reality. With these criteria in mind, nine (9) countries were selected and a table of relevant parameters was compiled, as shown in the Table below. It so happens that the first seven countries in the list have the seven largest (in the order shown in the table) electricity systems in Africa (in terms of installed electric capacity). Kenya is mentioned because of its large population, low per capita consumption, meager local fossil fuel resources, and expressed interest. Namibia is a country with a small population but was

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selected on account of large uranium resources and expressed interest. This list is tentative and needs to be re-examined with additional research.

Relevant Parameters of Selected African Countries

Country

Units South Africa Egypt Algeria Libya Morocco Nigeria Tunisia Kenya Namibia

Population (2008) million 48.8 77.3 33.8 6.2 31.0 146.3 10.4 38.0 2.1

Electricity installed capacity (2008) GW 44.07 23.42 8.13 6.28 6.01 5.90 3.50 1.29 0.26

Electricity Generation (2008) TWh 238.30 123.90 37.84 26.95 19.49 20.13 14.40 6.79 2.20

Electricy consumption (2008) TWh 212.24 109.09 30.50 22.89 21.47 18.14 12.49 5.74 3.93

Net Electricity Exports (2008) TWh 3.60 0.90 0.05 0.05 -4.26 0.00 0.01 0.02 -2.10

Per capita electricity consumption

kWh/y-cap 4,349 1,411 902 3,692 693 124 1,201 151 1,871

Per capita eGDP, PPP basis (2009), est. US$/cap 10,300 5900 7100 13400 4600 2300 9100 1600 6600

Proven Oil Reserves bill. bbl. 0.015 4.3 13.4 47 0.1 37.5 0.42 0 0

Proven Gas Reserves trill. m3 negl. 1.66 4.5 1.45 negl. 5.25 0.65 0 0.06

The countries selected are divided into three groups with descending likelihood for the introduction of nuclear power, each group comprising three countries. South Africa, Egypt and Algeria, are included in the group A because they are considered the most likely to successfully make a bid for nuclear power in their territory. Libya, Morocco and Nigeria form group B, and their prospects are considered lower although they are still likely to attract attention from nuclear power equipment and project vendors. Finally, Group C is composed of Tunisia, Kenya, and Namibia; these countries are sometimes mentioned in the discussion of nuclear power in Africa but are considered unlikely to be seriously considered, as will be explained in Annex 3-3.

The non-nuclear technologies have been examined and assessed as potential solutions to meet future power demand.

3.2.2 Thermal Power Technologies

Thermal power technologies include the following options:

Diesel engines;

Open cycle gas turbines (OCGT);

Combined cycle gas turbines (CCGT);

Steam plants;

Fluidized bed combustion; and

Integrated gasification combined cycle (IGCC)

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Renewable technologies considered include

Wind Power

Concentrated Solar Thermal (CSP)

Photovoltaic (PV)

Geothermal

Biomass combustion (steam plants)

Biomass gasification

Biomass Co-firing

Landfill Gas to Energy

Other technologies

Fuel cell technology;

Tidal power:

Energy storage.

The performance and cost o these technologies are summarized in the table below and discussed in Annex 3-3.

Technology Fuel Size CF Efficiency Aux Power Life Construction Time Capital Fixed O&M Variable O&M NotesType (MW) (%) (%gross) (%) (years) (years) ($/kW) ($/kW-yr) ($/MWh)

Diesel Diesel 0.1 30-80 38 1 20 1 640 20 3 Medium speedDiesel Diesel 5 30-80 43 1 20 1 600 20 3 Low speedGas Turbine Gas 25 10-40 36.6 1 20 1 970 20 2 Aero-derivativeGas Turbine Gas 150 10-40 34 1 20 2 530 12.5 2 Industrial frameCCGT Gas 580 30-90 54 2 25 3 860 20 4 Industrial frameSteam plant (Gas) Gas 300 30-90 42 5 30 3 1040 36 3 SubcriticalSteam plant (Oil) HFO 300 30-90 41 5 30 3 1180 38 3 SubcriticalSteam Sub (Coal) Coal 300 50-90 40.9 7 30 4 1690 45 3.6 SubcriticalSteam Sub (Coal) Coal 500 50-90 41.5 7 30 4 1440 40 3.4 SubcriticalSteam Supercr (Coal) Coal 500 50-90 43.6 6 30 4 1500 43 3.4 SupercriticalSteam USC (Coal) Coal 500 50-90 46.8 6 30 4 1600 47 4 UltrasupercriticalCFB Subcritical Coal 300 50-90 40 7 30 4 1500 40 3 SubcriticalIGCC Coal 500 50-80 48 11 30 5 2500 55 2 Entrained flow gasifierWind 10 10-35 NA NA 20 2 1680 28 0CSP 20 10-35 NA NA 20 3 3500 70 10 Trough without storagePV 0.1 10-35 15 NA 20 1 6000 12.5 0Geothermal 20 60-90 NA NA 30 3 4000 130 0 Moderate temp; direct or flash plantBiomass steam Biomass 50 30-90 26 5 30 3 1700 73 8.5 Fuel consumption: 1.5 kg/kWhGasification Biomass 20 50-75 30 8 30 4 2100 2.5 $/MWh 12 Fuel consumption: 1.5 kg/kWhLandfill Gas Landfill gas 5 50-90 30 2 20 2 3250 1.1 $/MWh 4.3 $/MWh

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3.3 Analysis of choices and challenges – defining objectives and targets

3.3.1 Identification of key issues and challenges

The choice of technologies to meet power demand depends on

The comparative cost of alternative fuels, which affect not only the relative cost competitiveness of alternative thermal technologies, but also their attractiveness compared to hydro technology and nuclear;

The cost or value attributed to GHG emissions, which varies for each technology and can significantly affect the relative competitiveness of technologies, depending whether the value of GHG emissions are taken into account or not; and

A number of regional energy policy options including the priority granted to renewable energies, independently of their cost, the willingness to accept dependence on supply of electricity from the regional market, the interest in PPP financing.

Fuel price projections

The projection of petroleum products prices is made based on future crude oil prices. The methodology proceeds in three steps:

Establishing the relationship between crude oil prices and prices of Diesel, HFO, LNG, gas and coal in the past;

Developing projections for future crude oil prices based on projections prepared by reputable institutions; and

Projecting future petroleum product and coal prices based on future oil prices

Methodology

The model is based on the analysis of the price series for the period 1990-2009, expressed in 2000 US$ and carefully converted in consistent physical units under the International System, that is, in metric tonnes and cubic meters. Based on the observation of oil and petroleum prices in the past (see graph below), the model tests the hypothesis that there is a linear relationship between the price of crude oil and the price of petroleum products, because oil is the main input in the cost structure of petroleum products, which include also refining costs and logistics costs. For coal, it was observed in the past that the price of coal is also affected by crude oil, as when oil and petroleum product prices increase, the demand for coal increases as some of the primary fuel consumption switches from petroleum products to coal.

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Comparison of the price of crude oil and fuels for power generation, 1990-2009

The projection model uses a linear function linking crude oil price with the various fuels used for power generation. For each product, the function is:

P(i,t)= k(i).P(oil,t)+ j(i)

Where P(i,t) is the price of fuel i in year t expressed in year 2000 US$

k(i) is the proportionality factor between crude oil price and the price of fuel i

P(oil,t) is the price of crude oil in year t expressed in year 2000 US$

(i) is a constant specific to each fuel.

The model is therefore based on five fuel price functions (HFO, Diesel, LNG, gas, coal).

HFO DIESEL LNG GAS COAL

PROPORTIONALITY COEFFICIENT

0.81 1.26 0.50 0.59 0.09

CONSTANT 16.1 8.95 89.68 22.98 32.44

R2 0.98 0.99 0.88 0.94 0.44

The calculation shows that Diesel is more affected by fluctuations of oil prices and instable than HFO with a proportionality coefficient of 1.2 and 0.8 respectively; that LNG and gas are less affected by changes in crude oil prices with a proportionality coefficient close of 0.5, and that coal is even less affected by oil price fluctuations. As could be expected, the price component independent of crude oil prices corresponding to logistics and processing cost is larger for coal and gas and mostly LNG than for HFO and Diesel.

Projections

To apply the price functions in the future, crude oil price projections have to be established first. The long term projections of the IEA, the International Energy Outlook of the US EIA and the World Bank were examined (see graph below).

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Projected Crude oil Prices 2009-2040 (in 2000 $ per tonne)

The comparison between the price projections show that the “high” and “low” scenarios of IEO are extreme compared to projections by other institutions. The 2040 range of $ 292 per tonne in the low scenario and $1 261 per tonne in the high scenario is so wide that it becomes essentially meaningless in terms of alternative scenarios. It was therefore decided to use the IEA projection as “high” scenario, and the World Bank projections as “low” scenario.

The corresponding graph is given below.

Crude Oil price projections 2011-2040 (in 2000 US$ per tonne)

Fuel Prices Projections 2011-2040 (in 2000 US$/tonne or tcm)

High scenario Low Scenario

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Price projections for each fuel under the high and low price scenario are given below.

Fuel prices High and Low scenarios (2000 US$/tonne or tcm)

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Carbon value

The justification for including the cost of carbon emissions for sector planning purpose is :

(i) the emission of CO2 (in particular) by power plants causes a damage which may not be reflected in the financial price of fuel, but is an economic cost to be taken into account; and

(ii) it is increasingly likely that some form of tax will be applied in the long run to CO2 emissions and in anticipation, an estimate of the CO2 tax should be included in the cost of fuel of alternative technologies.

The rationale for including CO2 value in fuel costs. In economic theory, pollution or CO2 emissions are considered as negative externalities, a negative effect on a party not directly involved in a transaction, which results in the party causing the negative externality (producing CO2) not paying the full cost to the economy of burning a certain fuel, thereby creating market distortions and skewed investment decisions. The economist Arthur Pigou proposed taxing the goods (in this case CO2 emitting fossil fuels) which were the source of the negative externality (CO2 emissions) so as to accurately reflect the cost of the goods' production (electricity) to society, thereby internalizing the costs associated with electricity production. A tax on a negative externality should equal the marginal damage costs.

In addition to creating incentives for energy conservation, a carbon tax would put renewable energy sources such as wind, solar and geothermal on a more competitive footing, stimulating their growth.

The social cost of carbon (SCC) is the marginal cost of emitting one extra tonne of carbon (as carbon dioxide. If SCC estimates were complete and markets perfect, a carbon tax should be set equal to the SCC. Emission permits would also have a value equal to the SCC. In reality, however, markets are not perfect, and SCC estimates are not complete.

An amount of CO2 pollution is measured by the weight (mass) of the pollution. Estimates of the dollar cost of carbon dioxide pollution is given per tonne, either carbon, $X/tC, or carbon dioxide, $X/tCO2. One tC is roughly equivalent to 4 tCO2.

Value of CO2 emissions. Estimates of the SCC are uncertain. Estimates of the SCC for 2005 had an average value of $43/tC ($12/tCO2). Other estimates of the SCC spanned at least three orders of magnitude, from less than $1/tC ($0.25/tCO2) to over $1,500/tC ($400/tCO2). The true SCC is expected to increase over time. The rate of increase will very likely be 2 to 4% per year.

For planning purposes, it is proposed to use as a proxy for SCC value the price of CO2 credits on the free market. The graph below shows that the market price of CO2 has been increasing steadily over the 2002-2009 period, from $4/tonne of CO2 to about $13 at present. However, the past records also show that market price of CO2 is rather volatile, ranging from $4/tonne to $ 15/tonne. In the future, further increases are projected by experts up to $30 and possibly higher.

Three price scenarios will be explored, covering the range of likely prices of CO2 based on past records and projections for the future. A low carbon price scenario will be based on a price of $ 5/tonne of CO2. An intermediate scenario will be based on the recent price of CO2 of $ 15/tonne, and a high scenario will be based on the assumption that CO2 prices will continue to increase, reaching $30/tonne.

A carbon tax that compensates for the SCC varies by fuel source. The carbon dioxide production of the fuel source per unit mass or volume is multiplied by the SCC to obtain the tax. The table below estimates the tax or surcharge to be applied to various fuels.

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It should be noted that the tax per kWh of electricity depends on the thermal efficiency of the generating power plant, which varies from plant to plant.

Value of CO2 contained in fuels

Regional Policy Options

Renewable Energy Targets

Most of the Energy policies of the AUC, the RECs and the Pools refer to the development of renewable energy as a priority (see section 1). In order to integrate these priorities in the Continental development plan, two issues need to be clarified:

The definition of Renewable Energy is not universal. Certain parties, and particularly some NGOs, limit Renewable Energy to solar, wind, and small hydro (not always), geothermal and selected forms of biomass such as Jatropha. Other parties take a much broader approach and include all hydro. And some people, focusing on CO2 and GHG emissions, propose to include nuclear in the definition and consider large hydro on a case by case basis, arguing that some large hydro projects may release significant amounts of methane, which is even 20 times more harmful than CO2 in terms of contribution to global warming. It is proposed to include in the definition of Renewable Energy all forms of hydro, based on the “intermediate” definition, considering that the focus on Renewable Energy is motivated by the desire to reduce GHG and substitute energy with practically inexhaustible inputs. As uranium supply is not inexhaustible, nuclear would be eliminated as a source of renewable energy.

The second issue is whether an objective in terms of share of renewable energy in the energy mix should apply continent-, REC- or country-wide. Considering that the enforcement of continental or regional objectives for Renewable energy development, it is proposed to consider Renewable Energy development targets at the country level. The table below indicates that the share of renewable energy in national power systems varies considerably from zero to more than 90%, mostly consisting of large hydro power generation. For planning purposes,

- One scenario will not put any constraint on the share of renewable energy in the electricity generation mix.

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- A second scenario will assume that all countries with a share of Renewable energy for power generation below 20% will increase their share of renewable energy by 5% over the planning horizon, which is based on the assumption that there are many countries without hydro power potential and insufficient resources to finance the development of considerably more expensive Renewable Energy sources, such as solar, wind or biomass.

Share of Renewable Energy sources in Power Generation by country

% Renewable

Energy

% Renewable

Energy

% Renewable

Energy

% Renewable

Energy

Algeria 0.7% Cote d'Ivoire 26.5% Lesotho 100.0% Rwanda 94.7%

Angola 66.8% Egypt 12.4% Liberia 0.0% Senegal 10.5%

Benin 1.0% Equatorial

Guinea 10.7% Libya 0.0% Sierra Leone 0.0%

Botswana 0.0% Eritrea 0.3% Malawi 98.0% Somalia 0.0%

Burkina 19.4% Ethiopia 98.3% Mali 54.1% South Africa 0.6%

Burundi 98.5% Gabon 51.9% Mauritania 14.5% Sudan 29.8%

Cameroun 94.7% The Gambia 0.0% Morocco 5.6% Swaziland 42.4%

CAR 78.0% Ghana 77.7% Mozambique 98.8% Tanzania 93.6%

Chad 0.0% Guinea 54.9% Namibia 96.0% Togo 41.5%

RDC 99.9% Guinea Bissau 0.0% Niger 0.0% Tunisia 0.5%

Congo 98.6% Kenya 69.8% Nigeria 33.4% Uganda 99.8%

Zambia 99.4%

Zimbabwe 56.2%

Electricity Trade

An important justification for the PIDA approach is the support to regional energy trading as a means to lower the cost of electricity generation and to integrate the African continent economically. At present, the level of power exchanges between countries varies considerably, with some small countries such as Benin, Congo, Namibia highly dependent upon electricity imports, while others, such as CAR, Chad, or South Africa, import only a small share of their consumption from neighbouring countries. The table below indicates the percentage of consumption met through power imports (purchases of Senegal and Mauritania from regional power plants co-owned by several countries, such as Manantali, are not recorded as imports). In the long term, it is proposed to envisage three scenarios concerning trade and imports of electricity by African countries.

Under the first scenario, each country will not increase its present percentage of imports (see table below). Under this scenario, there is no development of regional electricity trade, and each country pursues its present import policy.

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Under the second scenario, all constraints on electricity imports are lifted, and countries will import electricity without limit, provided there is an incremental advantage. Under this scenario, countries presently importing because of a lack of capacity but with potential for developing production capacity, like Ghana, may reduce their imports, whereas countries with no significant potential for producing electricity economically from domestic resources or imported fuel may increase their imports. This may be the case for countries such as Burkina Faso. Under this scenario, the share of import of some countries may drop to zero or increase to 100%. This represents the ideal scenario under which the cost of supply of electricity is minimized for the continent as there are no obstacles to electricity trading.

A third scenario recognizes that there may be reluctance from some countries, particularly large ones, to depend to a large extent on their neighbours for power supply, as dependence on electricity imports through interconnections may make them vulnerable politically, as illustrated by the Cahora Bassa history (imports of fuels may make these countries less vulnerable to energy security risk, as for countries with a coastal window, fuels can be procured on the world market, with a lesser risk than dependence on electricity transport lines and therefore, energy security concerns may impose restriction on dependence on imports. Under this scenario, it is assumed that certain countries will put a cap on their electricity import dependence (for example, South Africa has indicated to the SAPP planning team that their reliance on import should not exceed 10% of their domestic demand). It is assumed that small countries may be more likely to depend on imports for up to 100% of their needs, whereas medium-size countries may accept no more than a 70% dependence, and large countries, no more than 30% . For South Africa, the limit of 10% has been retained, corresponding to the stated long term policy of the country.

Accepted dependence on electricity imports

%

import %

import %

import %

import

Algeria 30.0% Cote d'Ivoire 30.0% Lesotho 100.0% Rwanda 100.0%

Angola 30.0% Egypt 30.0% Liberia 100.0% Senegal 70.0%

Benin 100.0% Equatorial Guinea 100.0% Libya 30.0% Sierra Leone 100.0%

Botswana 70.0% Eritrea 100.0% Malawi 70.0% Somalia 100.0%

Burkina 70.0% Ethiopia 30.0% Mali 70.0% South Africa 10.0%

Burundi 100.0% Gabon 70.0% Mauritania 70.0% Sudan 30.0%

Cameroun 30.0% The Gambia 100.0% Morocco 30.0% Swaziland 70.0%

CAR 70.0% Ghana 30.0% Mozambique 100.0% Tanzania 30.0%

Chad 70.0% Guinea 30.0% Namibia 70.0% Togo 100.0%

RDC

Congo

30.0%

100%

Guinea Bissau

100.0% Niger

100.0%

Tunisia

30.0%

Kenya 70.0% Nigeria 30.0% Uganda 70.0%

Zambia 70.0%

Zimbabwe 30.0%

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Financing

An important aspect of the planning scenarios is their likelihood of being implemented under reasonable long term assumptions. Actually, the AUC´s and RECs´ capacity to mobilize member countries to contribute to the implementation of the optimum continental investment program and integrate the continental priorities in their national plans is largely dependent upon the likelihood of the regional projects being implemented as scheduled. In turn, implementation depends upon the availability of financing from public as well as private sector sources. The capacity of large regional projects to attract financing depends in particular upon two factors:

The creditworthiness of the sovereign of the country where the project is physically located, as even for a regional and private project, the infrastructure remains under the political and regulatory control of the government of the country, where the project is located. Ultimately, the government of the host country has the capacity to take over any project on its territory, with proper compensation of the owner (expropriation right of the sovereign). The critical element is therefore the compensation capacity of the sovereign to the owners of the project under certain circumstances. As a result, the likelihood of mobilizing financing for a multi-billion project in a large high GDP country is much higher than that of financing the same project in a small low income country. This implicit rule of proportionality between the size of a project and the size of the host country applies to private sector financing because of the financial risk, and also, to a large extent, to IFIs, as they, too, have fiduciary ratios to respect in their financial support programs to diversify their portfolio across countries and sectors within a country.

The capacity of every country involved in a regional project to provide suitable financial guarantees for their purchase contracts. This capacity depends upon the size of the contract, and the creditworthiness of the host country of the purchasing entity, as even under the best project structure (except for purely enclave projects) the creditworthiness of any purchasing entity is capped by the creditworthiness of the host country.

The mapping of the creditworthiness of the sovereign of the African countries is given in the chart below, showing that only a few countries have reached “investment grade” level (marked in green), that is, have the capacity to attract financing from the market, even under the best circumstances, without special guarantees.

Facing a situation where only few African countries are rated as creditworthy by international standards, several IFIs and bilateral institutions have developed guarantee mechanisms to enhance the countries capacity to attract financing. These mechanisms, though, may allow countries with a rating below investment grade to attract financing, without eliminating the constraint of the relationship between the size of an economy and the amount of financing it can attract, as the guarantees offered by the guarantee agencies are commensurate to the size of the economy of the country where the project is located.

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Sovereign Credit Rating of selected African Countries

Country S&P

equivalent rating

Notches below IG

Angola B+ 4

Benin B 5

Botswana A

Burkina B 5

Cameroon B 5

Cape Verde B+ 4

Egypt BB+ 1

Gabon BB- 3

Gambia CCC 8

Ghana B+ 4

Kenya B+ 4

Lesotho BB- 3

Libya BBB+

Malawi CCC+ 7

Mali B- 6

Morocco BBB-

Mozambique B+ 4

Namibia BBB-

Nigeria BB- 3

Rwanda B 5

Senegal B+ 4

South Africa BBB+

Tunisia BBB

Uganda B 5

Based on discussions with various financing institutions, including IFC, PROPARCO, EIB and the private sector, as well as on direct experience, one can conclude that, in general, a project costing more than 3% of the GDP of a country is likely to be considered too big by financiers and difficult to finance, except under special circumstances. The tabulation of the resulting constraint on individual energy investment by country is given in the table in Annex 2 for the years 2010, 2020 and 2030. It indicates that the country limit will vary over time, as country GDP increases. As a result, large regional investment projects will be easier to finance as country GDP increases as projected.

For the preparation of the Continental Plan for the energy sector, two scenarios are considered.

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One scenario assumes that there is no constraint on project financing based on country size and creditworthiness;

A second scenario assumes that the individual energy project country limit applies, and that a project located in a given country will be financeable in any year once it represents less than 3% of the country’s annual GDP. Under this scenario, the larger regional electricity projects may have to be deferred due to financing constraints.

3.3.2 The List of Scenarios

Combining the alternatives described above, the Continental plan explores:

Two fuel price scenarios

Three CO2 price scenarios

Two Renewable Energy scenarios

Three Trade scenarios

Two Financing Capacity scenarios

It generated a total of 72 potential scenarios. However, not all combinations of variables are equally relevant. For the Phase 1 report, the most meaningful scenarios have been retained a starting point. During discussion of the Phase 1 report, guidance will be provided to the Consultant regarding what other scenarios should be developed.

The initial scenarios are:

No integration scenario

- High fuel price

- $15/ton CO2 price

- No Renewable Energy constraint

- Fully restricted Trade

- Financing Capacity constraint

Full integration scenario

- High fuel price

- $15/ton CO2 price


- Unrestricted Trade

- No Financing Capacity constraint

Pragmatic scenario

- High fuel price

- $15/ton CO2 price


- Partly restricted Trade

- Financing Capacity constraint

For the discussion of Phase 1 report, three scenarios will be developed initially. All will be based on the High Fuel price scenario and no carbon value:

The Without trade development scenario will maintain the present share of imports for each country, with limitations on capacity to secure financing

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The Full Integration scenario will remove all limits on trade and on financing

The Pragmatic scenario will put a limit on regional trade as discussed above, and on capacity to secure financing.

The third scenario assumes significant reforms and trade facilitation measures, while recognizing the constraints on regional integration and financing of large regional projects.

3.4 Setting objectives for the Infrastructure development framework and investment program

3.4.1 Priorities and Objectives

1. Recommended Energy Policy Objectives The recommended energy objectives have been predicated on the following considerations which will govern all future growth scenarios of the African continent’s energy sector:

Sustain Economic Growth Average GDP growth across the African continent over the next decade is projected to grow at an annual average rate of 7.5%. Energy demand is expected to grow at higher growth rates, given the elasticity of demand of 1.2 or higher. With an overall shortage of installed power generation capacity, there is a fundamental need for significant investment in new generation capacity simply to keep up with demand;

Improve Access to Basic Energy Services More than 80 % of Africa’s population is lacking in access to basic energy services. Consequently, the provision of low cost energy supplies to an increased number of the continent’s population remains an urgent and overarching socio-economic priority for almost all Africa countries, with the sole exception of the North Africa region.

Increase Amount of Available Financial Resources The investment and financing implications of the challenge to meet both rapid energy demand growth and increased access are daunting. In Africa, where the majority of Africa’s population lacking access is found, an estimated $40 billion per year will be needed in new capital expenditure (excluding investment in transmission), together with a further $17 billion a year in operations and maintenance and $ 250 billion in fuel costs (see below section 3.4.3). Only just one quarter of this amount is currently being invested at present. Consequently, with limits on the availability of increased financial resources from IFIs and bilateral donors, new sources of finance will need to be opened up, in particular domestically generated resources and both domestic and international commercial sources of finance.

Enhance Energy Security Approximately 23 countries, or nearly half of the entire continent, are oil importing countries, most of them low-income developing countries. These countries already pay a high import bill in scarce foreign exchange resources for the imported petroleum products needed to fuel thermal power plants. As such, they continue to be vulnerable to future oil price hikes. Given the abundance of lower cost energy resources in different regions of Africa, there is a priority need to develop these resources, in particular the large scale hydro resources. Development of these hydro resources has the potential to benefit many of the oil importing countries, provided investment is also made in regional energy integration, specifically expanded regional electricity networks and natural gas grids.

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Pursue a low-Carbon Growth Path The African continent is a minor contributor to global greenhouse gas (GHG) emissions, being currently responsible for less than 3%. Even with expanded and sustained economic growth over the next decade or more, the African continent will remain a small contributor to global GHG emissions. Nevertheless, the larger middle income African countries in particular are strongly committed to following low-Carbon growth scenarios in their investment planning and fuel choices to meet future energy demand. In practice, this commitment comprises two areas of emphasis: (i) a concerted effort to move towards a reduction in CO2 intensity in future electricity generation; and (ii) a priority focus on the development of Africa’s main renewable sources of energy, especially large scale hydro sources and, to a lesser extent, geothermal and solar energy sources.

With the aforementioned considerations as background, the following policy objectives in the energy sector are proposed:

2. Reduce the cost of basic energy services, primarily through grid-connected electricity, in order to Improve Access

The essential policy steps needed to lower the cost of basic energy services are the following:

Improve the very low efficiency level of existing grid- based electricity networks in most of Africa;

Develop Africa’s large scale hydro potential found in each of the main sub-Saharan regions;

Undertake energy investment planning at a regional level and insist on least cost investment decisions;

Develop the capacity of the RECs and Power Pools to mobilize financing for regional energy investments;

3. Increase the Volume of Financial Resources in order to bridge the large financing gap in investment requirements

The policy steps needed to achieve this objective are the following:

Take the necessary measures to develop creditworthy national electricity companies;

Require all public sector agencies to meet payments for electricity services;

Improve the overall governance of utilities through board appointments and government regulation;

4. Promote regional integration across the African continent in order to reduce the cost of energy supplies


Adopt regional energy investment plans in all SSA regions

Entrust regional entities such as power pools with authority for project development

5. Enhance energy security of oil-importing countries through development of large scale hydro and other sources


Actively develop large hydro and domestic fuel resources

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Implementation energy efficiency and energy conservation policies;

Develop sustainable energy trading

6. Reduce GHG emissions through investment plans which give priority to low-Carbon growth scenarios


Prepare regional investment plans based on low- Carbon growth scenarios

Promote development of Africa’s main renewable resources with priority given to hydro resources, geothermal, wind and solar resources in regional investment planning;

Take steps to reduce the CO2 intensity of electricity generation, with emphasis on middle income African countries with a high dependence of coal-based power generation

The proposed set of policy steps are summarized in the log frame below, together with the expected outputs and outcomes, as well as the proposed indicators to monitor progress towards each of the recommended objectives

Recommended Continental and Regional Policy Objectives

ENERGY SECTOR

OBJECTIVES

REQUIRED POLICY STEPS

EXPECTED OUTPUTS EXPECTED OUTCOMES

PROGRESS INDICATORS

1. Reduce cost of delivered energy to improve access for the majority of African people

1. Develop low-cost large plants and, particularly, the hydro potential of Africa’s main regional hubs;

2. Reduce T/D losses in priority networks;

3. Increase investment in grid distribution;

4. Enforce regional and domestic investment development plans

5. Develop capacity of RECs and Pools to mobilize financing for regional generation and transmission projects

1. Increased generation from Inga, Gibe, Mpanda, Ruzizi, Kaleta, Felou, and Sambagalou by 2020;

2. Transmission losses in main networks reduced by 50% in 2020;

3. Investment in grid distribution increases x 5 in SSA regions by 2020

4. Financing allocated in priority to the implementation of large regional projects

5. Extension of the role of the RECs and Pools to develop, implement, raise financing for regional projects

Cost of electricity aligned with Long Run Marginal Cost Access to electricity in all SSA regions increases by 10% between 2010-2020 Regional investment projects are implemented according to optimal planning schedule

1.Share of total capacity provided by regional hydro hubs; 2. Reduction in transmission and distribution losses over 10 year period; 3. 5-year investment levels in distribution

2. Mobilize Commercial Financial Resources to bridge the gap of Investment Requirements in ‘Pragmatic’ Scenario

1. Take steps to develop creditworthy national utilities;

2. Improve public sector payment collection;

3. Improve governance of utilities

1.National electricity companies able to borrow, or issue bonds, for investment programs without sovereign guarantee

2.Utilities recognized as creditworthy off-takers by private investors

3. Credit rating of energy sector reaches Investment Grade.

Financial resources from commercial sources with limited recourse ton Governments cover most of the sector financing needs for expanded investment program

Equal shares of regional energy investments financed from commercial sources, internal cash flow and concessional sources

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ENERGY SECTOR

OBJECTIVES

REQUIRED POLICY STEPS

EXPECTED OUTPUTS EXPECTED OUTCOMES

PROGRESS INDICATORS

3. Ensure energy security for all African countries

1. Actively develop Africa’s large hydro and domestic fuel resources

2. Implement energy conservation policies

3. Develop sustainable energy trading

1. Increased share of hydro and indigenous fuels based electricity in Africa’s total capacity by 2025

2. Reduced energy intensity in industry and increased rate of utilization of capacities (load factor)

3. Develop effective cross-support/systems complementarities

1. Reduced continental dependence on imported oil by 2025

2. Existing capacities used more efficiently

3. System reliability is improved

1. Annual volume of imported oil (to African continent) per GWh produced

2. Increased system load factors

3. Reduced load shedding

4. Bring about energy integration of African continent

1.Adopt regional investment plans in all SSA regions and coordinate national with regional plans;

2. Entrust regional entities with authority for project development

1.Increased number of regional energy inter-connections by 2025;

2. Power pools have enhanced responsibility for planning, financing and operation of regional grids, concession award, and investor selection for generation projects

Lower cost and more reliable electricity supplies in all main regional areas;

Share of regional trade in all SSA regions

5. Reduce GHG emissions

1. Regional investment plans adopt low-C growth scenarios;

2. Active promotion of hydro, geothermal and other renewable sources

1. Main African CO2 emitting countries commit to low-C investment plans;

2. Renewable share of regional energy demand increases by 2020;

3. More concessional financing mobilized

Aggregate reduction in Africa’s GHG emissions by 2020

1. Reduction of CO2 intensity of electricity generation;

2. Contribution of renewable energy to demand in Africa’s 5 largest consuming countries;

3.4.2 Resource Availability for Energy Investment Program

As discussed in Section 1 above, the investment requirements in electric power for African countries have been estimated at $40 billion per year. In the North Africa region, investment in electric power is likely to exceed $ 10 billion per year, with Egypt’s investment program alone of the order of $ 6 billion per year. Taking into account also the growing investment needs in pipeline infrastructure to develop fully the continent’s natural gas reserves following further discoveries in offshore Ghana, Mozambique and Tanzania, total investment in energy is likely to exceed $55 billion per year. Even under more pessimistic growth scenarios for the continent of less than 6% per year, the estimates for energy investment needs are unlikely to be reduced below $40-45 billion per year, representing a formidable financing challenge for the African continent.

Official Development Assistance (ODA) has been the single most important source of finance for the power sector’s investment needs over the past decades. Since 2005, both IFIs and donors have increased their commitments to the power sector. Commitments averaged about $1.5 billion per year over the period 2005-07, rising to $2.3 billion in 2007.10 Since 2007, total ODA commitments to the power sector have exceeded $3 billion per year, with the World Bank and the African Development Bank being the two largest financing institutions. For the 5- year period, 2011-15, planned new commitments to the African power sector from the World Bank

10 AICD, Chapter 8, Power : Catching Up

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will average $ 2 billion per year11 while new financing commitments for Africa’s power sector from the African Development Bank will average $ 1 billion per year. Total ODA commitments to Africa’s energy sector during the 5 year period, 2011-2015 should average about $4 billion per year.

Non-OECD Finance has become an increasingly important source of finance since 2005 for infrastructure investment in general, and for the power sector in particular.12 The main sources of non-OECD finance have been the Chinese export-import bank and, to a much lesser extent, the Indian export-import bank. Estimates of financing for energy related investments from these sources (unconfirmed) were about $2 billion per year in 2007 and have increased further since then. Most of the financing from China are expected to be used to help finance large hydropower schemes in Ethiopia, Cameroun, and Mozambique while India has been financing large thermal plants in Nigeria and Sudan and some transmission lines.

Private sources of Finance have contributed smaller but still significant amounts for Africa’s power investment needs, averaging an estimated $1 billion per year over the period 2005-2007, most of it in the more advances African countries with some exceptions (Bujagali, Songo Songo, Senegal, WAGP for example), and helping support investment in independent power generation projects. It is important to emphasize that the continuity of private finance is not assured and depends critically on an investment climate where the potential rewards outweigh the risks. The importance of having creditworthy energy institutions as potential purchasers of electric power cannot be overemphasized.

Estimated External Financing Flows to the Power Sector in Africa ($ billion/year), 2011-2015

ODA 4.0

Non-OECD 3.0

Private 1.0

TOTAL 8.0

Funding Gap Even with optimistic assumptions in regard to financing from ODA, non-OECD countries, and private sources, it is clear that there remains a very large financing gap- of the order $25-30 billion per year, assuming a reasonable growth in ODA and Non-OECD aid and a continued increase in private financing. Unless this financing gap is reduced, the estimated investment requirements will have to be cut back severely, affecting equally middle income African countries as well as low income African countries, including many fragile states.

Key Recommendations

Mobilizing financial resources on the scale indicated will require a major transformation in the management and operation of Africa’s power systems. Under-utilization of installed generation capacity due to ineffective maintenance financing, high transmission and distribution losses, and a culture of non- payment for electricity services across most public sector agencies has severely hindered the expansion of the power sector, weakened the financial capacity of utilities to contribute to investment needs, and resulted in a poor quality of electricity supply in most regional areas of sub-Saharan Africa.

The following actions require priority attention:

11 World Bank Energy Lending, FY 11-15: $ 7.5 billion for SSA; $ 2.5 billion for North Africa African Development Bank Energy Lending 2011-2015: 12 AICD, Chapter 8, Power: Catching Up: Closing the Funding Gap

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Improving creditworthiness of national electricity companies

This a key first step in closing the investment funding gap. The potential benefits are enormous. Not only will national utilities be able to start generating resources internally for self-financing part of their own investment expansion but they will also have the capacity to borrow domestically from commercial sources as well as borrow and issue bonds on the international financial market on a corporate finance basis. In transactions involving private investors, they would become ‘creditworthy’ off-takers in the purchase of power from independent producers, a key prerequisite for private investment under project finance structures. A critical step towards financially viable utilities is prompt payment for electricity by public sector ministries and agencies (which often represent 30 to 40% of sales of African utilities), and accurate billing of industrial and residential clients.

Improving the operational efficiency of power networks

Improving the operational efficiency of power networks is a long term undertaking requiring several different activities. These include (i) rehabilitation investment in generating facilities; (ii) investment in transmission facilities; and (iii) rehabilitation and/or new investment in distribution networks where the highest losses are incurred. Given the magnitude of this task, the investment needs to be undertaken in phases, with priorities set in terms of those segments that provide the highest economic benefits. The overall effect will be to reduce losses and improve the cash flow of electric utilities enabling them to contribute resources to their investment programs.

3.4.3 First Cost Quantification and Estimated Deadlines

The detailed investment programs in generation, transmission and operating costs under each planning scenario will be developed during Phase 2 of the PIDA Study. A preliminary set of estimates is given below, which includes only investment in generation and operating costs, leaving out for the moment investment in transmission, subject to revision, and a preliminary list of priority regional projects under each of the three retained Outlook is given in Annex 3-7.

In order to quantify the investment needs for regional projects under the alternative Outlooks for the sector, an estimate of the total sector investment needs has been prepared, which is further broken down into Regional investments and National level investments. In evaluating the alternative Outlooks, one should consider not only the regional investment needs, but the total sector investment needs and how Regional investments contribute to reduce overall sector investment needs. The preliminary analysis under Phase 1 of the study aims first at evaluating at the continental level the investment program without expansion of regional energy trade, corresponding to a “without increase in Integration” or “Low Integration” scenario. Then this scenario is compared with (i) investment needs under an ideal scenario without constraints on trading or project financing, that is, Maximum Integration and (ii) with the investment needs under the Pragmatic scenario where dependence on imported energy is taken into account, as well as financing constraints on large investments. The conclusion is that investment needs and particularly fuel costs under the Low Integration scenario are higher than under the Maximum Integration and Pragmatic scenarios. The preliminary estimate of investments is given below.

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Outlook 1: Low Integration

Investment and Generation Costs: Low Integration (million US$)

Investments Generation

Invest. Access

Total Investment

O & M Fuel Cost Total Cost

2010-2020 236,856 19,445 256,301 59,118 589,047 904,465

2021-2030 433,139 19,463 452,602 167,964 2,221,171 2,841,738

2031-2040 577,803 41,097 618,900 320,235 5,296,778 6,235,914

2010-2040 1,247,799 80,004 1,327,803 547,317 8,106,996 9,982,117

Investment and Generation Costs per annum: Low Integration (million US$)


Invest. Access

Total Investment O & M Fuel Cost Total Cost

2014-2020 21,532 1,768 23,300 5,374 53,550 82,224

2021-2030 43,314 1,946 45,260 16,796 222,117 284,174

2031-2040 57,780 4,110 61,890 32,024 529,678 623,591

2014-2040 40,252 2,581 42,832 17,655 261,516 322,004

Investment and Generation Costs: Low Integration Scenario

Outlook 2: Maximum Integration

Investment and Generation Costs : Maximum Integration (million US$)


Invest. Access

Total Investment O & M

Fuel Cost

Total Cost

2010-2020 179,786 19,445 199,231 57,621 590,304 847,156

2021-2030 300,790 19,463 320,253 129,941 1,382,600 1,832,794

2031-2040 650,747 41,097 691,844 297,081 3,759,615 4,748,540

2010-2040 1,131,323 80,004 1,211,328 484,643 5,732,519 7,428,490

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Investment and Generation Costs per annum: Maximum Integration


Invest. Access

Total Investment


2010-2020 16,344 1,768 18,112 5,238 53,664 77,014

2021-2030 30,079 1,946 32,025 12,994 138,260 183,279

2031-2040 65,075 4,110 69,184 29,708 375,962 474,854

2010-2040 36,494 2,581 39,075 15,634 184,920 239,629

Investment and Generation Costs: Maximum Integration Scenario

Outlook 3: Pragmatic scenario

Investment and Generation Costs : Pragmatic Scenario (million US$)


Invest. Access

Total Investment


2010-2020 168,005 19,445 187,449 60,129 630,029 877,607

2021-2030 344,186 19,463 363,649 136,295 1,501,475 2,001,418

2031-2040 640,349 41,097 681,446 299,302 3,822,869 4,803,616

2010-2040 1,152,540 80,004 1,232,544 495,725 5,954,373 7,682,642

Investment and Generation Costs per annum: Pragmatic Scenario


Invest. Access

Total Investment


2014‐2020 15,273 1,768 17,041 5,466 57,275 79,782

2021‐2030 34,419 1,946 36,365 13,629 150,147 200,142

2031‐2040 64,035 4,110 68,145 29,930 382,287 480,362

2014‐2040 37,179 2,581 39,759 15,991 192,077 247,827

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Investment and Generation Costs: Pragmatic Scenario

Comparison of the Outlooks

The comparison of the Low Integration and Maximum Integration scenarios shows that the Maximum Integration scenario allows savings of US$ 116 billion over the 2010-2040 period, about 9% compared to the low Integration scenario. The main savings are on fuel costs, as the Maximum Integration scenario brings in the investment program low-cost large hydro projects, whereas the Low Integration scenario brings in a large number of small thermal or hydro plants to meet domestic demand, as large local hydro plants are too large to fit in the national grid (as it is often the care at present). The gain on fuel cost is US$ 2 474 billion over the entire period (a 29% reduction in fuel costs and in import dependence), and the total gain is US$ 2 553 billion,(25.6% of total generation cost compared to the Low Integration scenario), or US$ 85 billion per year.

The comparison of the Low Integration and Pragmatic scenarios shows that the Pragmatic scenario allows savings of US$ 2 299 billion over the 2010-2040 period, about 24 % compared to the low Integration scenario. The main savings are on fuel costs, as in the Maximum Integration scenario, but with lower savings, as the Pragmatic scenario brings in the investment program only medium-size hydro projects, whereas the Low Integration scenario brings in a large number of small thermal or hydro plants to meet domestic demand. The gain on fuel cost is US$ 2 152 billion over the entire period (a 26% reduction in fuel costs and in import dependence). The comparison of the Maximum Integration and Pragmatic scenario highlight the limited impact of the financing constraint on the cost of supply, as the Pragmatic scenario is closer to the Maximum Integration that to the Low Integration scenario, The total cost of introducing financing and trading constraints is US$ 153 billion over the entire period.

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Capital Investment Needs over the 2011-2040 period (billion US$)

2010-2019 2020-2029 2030-2040 Total Annual

Investment

Low Integration 256 452 619 1 328 42.8

Maximum Integration 199 230 691 1 211 39.0

Pragmatic scenario 187 363 681 1232 39.7

Total Expenditures (capital and operations in billion US$)

2010-2019 2020-2029 2030=2040 Total Annual Cost

of Supply

Low Integration 904 2 841 6 235 9 982 322.0

Maximum Integration 847 1 832 4 748 7 428 239.6

Pragmatic scenario 877 2001 4803 7682 547.8

Total Generation Cost per 10-year period under Each scenario (in million US$)

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Total Investment Cost per 10-year period under Each scenario (in million US$)

Total Fuel Cost per 10-year period under each scenario (in million US$)

The production cost structure under each scenario, highlighting the high overall and fuel cost of the Low Integration scenario is presented below.

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Comparative structure of generation costs under alternative scenarios (in US$ million)

Comparing the investment cost and the cost of production under each scenario, it appears that the gains of the Maximum Integration and Pragmatic scenarios compared to the Low integration scenario are:

Benefits of Regional Integration

2010-2019 2020-2029 2030=2040 Total Annual Gain

Maximum Integration 57 1 008 1 487 2 553 85

Pragmatic scenario 26 840 1432 2299 76

The table demonstrates that increased Integration reduces significantly the investment needed to meet the energy demand, in line with the conclusions of the recent AICD Study, but the impact is not so much on capital investment but on fuel cost with the development of large hydro projects which are not considered when each country is focusing on meeting its own demand. A consequence is that particular actions would be needed under this scenario to facilitate the mobilization of resources for large regional projects and enabling the RECs and Pools or ad hoc regional organization to play a more decisive role as project initiators, developers and in certain cases, operator.

The alternatives are either to retain an ambitious but high risk Outlook (maximum integration) or to adopt a cautious approach and prioritize projects more likely to be financed under the likely situation of the sector and economies in Africa (Pragmatic Outlook). An important consideration is that it is the credibility of regional integration with African countries which is at stake, as the failure to deliver on the selected investment program would lead to each country to decline relying on regional integration to meet their future demand supporting regional integration in words but not as a driver for their own investment program, and falling back on the Low integration scenario..

An interesting feature coming out of the investment planning model is that the capital investment requires to raise the electricity access rate from its present level of 15 to 20% (except in North Africa and South Africa) to a continental average of 60% is limited compared to investment needs in generation with a 6 % share of total investment.

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3.4.4 Preliminary Priority Regional Investment Projects under PIDA

A preliminary list and schedule of regional generation projects, to be revised following discussions with the RECs and Pools and when other important parameters are taken into consideration in the additional scenarios (in particular, the environmental dimension through the CO2 price), is given in Annex 3-7.

This list will be completed, including transmission project, capacity and soft projects, and investment projects in gas pipelines and petroleum products during the preparation of Phase 2 of the PIDA Study.

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ENERGY Sector - Report IV : Outline of Development Programme


PART IV - OUTLINE OF DEVELOPMENT PROGRAM

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Table of Contents 1. OBJECTIVE OF THE REPORT ..............................................................................3

2. PRELIMINARY STRATEGIC FRAMEWORK........................................................4 2.1 Political, institutional and legal framework............................................................................................................... 4

2.1.1 Vision ............................................................................................................................................................................... 4 2.1.2 Implementation stakeholders ......................................................................................................................... 4

2.2 Strategic objectives..................................................................................................................................................................5

3. PRELIMINARY OUTLINE OF THE INVESTMENT PROGRAM.......................... 7 3.1 Types of interventions considered and proposed approach for the short term............................7 3.2 Outline of the possible investment program and Priority Action Plan (PAP) .................................... 8

3.2.1 Approach ...................................................................................................................................................................... 8 3.2.2 Preliminary list of potential regional projects based on RECs priority projects and

list of PAP projects. ................................................................................................................................................ 9 3.2.3 Benefits of Regional Integration of Energy Systems and List of economically

optimum regional projects under three alternative policy Outlooks ..................................14 3.3 A first view on possible prioritizing criteria for the selection of Priority Projects..........................14

3.3.1 Joint project...................................................................................................................................................................14 3.3.2 Project as a part of an integrated regional pool development approach.......................15 3.3.3 Project to feed directly or indirectly to the development of a regional power

market............................................................................................................................................................................15 3.4 Implementation strategy .....................................................................................................................................................15

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1. OBJECTIVE OF THE REPORT

This report presents a first outline of a possible investment program based on the diagnostic review of Phase I, which includes:

A review of Energy continental and regional policies presented, analyzed and evaluated in Part I of Phase I Report;

A review of existing and planned Energy infrastructure, programs, and projects presented in Part II of Phase I Report;

A detailed analysis of five existing regional energy investments and six regional energy projects under preparation or implementation;

An outlook for the future and the identification of choices and challenges, as presented in Part III of Phase I Report.

The objective of this report is to serve as a structured basis to start Phase II of the PIDA – Study, which will be fully devoted to (i) the detailed formulation of alternative Energy sector regional investment scenarios; (ii) their evaluation leading to the selection of one preferred scenario; (iii) the identification of key enabling actions for the implementation of the preferred scenario; (iv) the preparation of a preliminary strategic framework, investment program, and implementation strategy for the development and management of Africa’s regional energy potential to the 2040 horizon.

The outline proposed in this report presents the key elements to be considered and further elaborated in order to be able to agree, in a participatory approach with the key stakeholders, on a coherent regional and continental Energy strategy including electricity, gas and petroleum products, a portfolio of investment projects, and an implementation strategy. The following elements will be highlighted:

Political, institutional and legal framework and relevant implementation stakeholders;

Proposed strategic objectives to be discussed;

A project portfolio for short term action.

The first ideas on the implementation strategy are discussed together with the other sectors.

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2. PRELIMINARY STRATEGIC FRAMEWORK

2.1 Political, institutional and legal framework

2.1.1 Vision

In the area of policy-making, the AUC has responsibility for defining continental-wide polices and strategies on infrastructure development1. The continental vision and policy objectives have been articulated in different conferences and assemblies of the African Union (AU) since 2000 and reaffirmed recently by Africa’s Ministers in charge of energy in the Maputo Declaration of November 5, 2010.

The Africa Energy vision is:

To develop efficient, reliable, cost effective, and environmentally friendly infrastructure for the physical integration of the continent and to enhance access to modern energy services for the majority of the African population.

This vision determines policy priorities spelled out as (i) developing major regional and continental hydroelectric projects; (ii) implementing high capacity oil refineries and oil pipeline projects; and (iii) developing renewable energy resources.

2.1.2 Implementation stakeholders

As highlighted in the review of policies and of existing programs, within the AUC organization, the Infrastructure and Energy (IE) department is the entity responsible for carrying out the AUC’s objectives in energy. The specialized institutions in energy under the AUC i.e. AFREC, AFUR and AFSEC, are intended to be the main instruments for facilitating the energy objectives of the AUC while the United Nations Economic Commission (ECA) and the African Development Bank (ADB) and the NEPAD Secretariats provide advice and support, respectively, to the AUC in its policy coordination activities.

At the regional level, the role of the Regional Economic Communities (RECs) in the energy sector is to promote cooperation between member states in order to develop integrated and cost effective energy infrastructure in support of regional economic development, and particularly regional trade. The RECs have a primary responsibility for developing a policy and planning framework to achieve the goal of regional cooperation in energy, in particular through the Power Pools. The regional power pools have primary responsibility for coordinating, harmonizing, and enforcing the operational rules and standards needed to achieve this goal.

The existing Power Pools most often suffer from lack of political motivation and consequently from insufficient financial support from the member states. It is believed that political motivation would probably increase if these institutions would, from the start, put more

1 Coordination Mechanism for the Development of Infrastructure in Africa, Department of Infrastructure and Energy, African Union, October 2007

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emphasis on the identification of concrete investment projects with tangible economic benefits and play an effective role in mobilizing financing for the preparation and implementation of regional investments

2.2 Strategic objectives

The proposed strategy and program takes into account the AUC, RECs and Pools’ strategies. These strategic objectives provide the basis on which the infrastructure development program can be developed, as well as addressing the issues relating to successful implementation.

The AUC and RECs priorities lead to the following strategic objectives for the energy sector:

OBJECTIVES STRATEGIC POLICY INITIATIVES

Ensure energy security for economic and social development

Through developing fully Africa’s energy resource potential – in hydropower, petroleum, geothermal, coal, and renewable energy

Achieve energy integration by increasing regional and continental energy trade

Through fostering regional and continental cooperation and by highlighting the importance of regional projects, especially electricity interconnections

Lower the cost of energy to improve access to basic energy services for Africa’s population

Through diversifying the energy mix and by pooling national energy resources so as to deliver energy production at affordable costs

Create a conducive climate for direct investment

Through harmonizing legal and regulatory frameworks for energy trade

Reduce Greenhouse Gas (GHG) emissions and address climate change issues

Through promoting the development of renewable energy, in particular solar energy

PIDA Energy will aim at meeting the objectives for the energy sector spelled out in the AUC, REC and Pool objectives, listed above, and emphasize three additional dimensions which, based on the evaluation of the performance of the regional energy institutions of Section 1, were found to be important for energy systems integration:

Implement Regional priority Investment owned and managed trough regional institutions from their own financial resources- through construction of regional generation and transmission facilities;

Develop a Financing Strategy for Regional energy infrastructure- by focusing on the feasibility of mobilizing non-government resources from the sector’s own cash flow and external sources2 to ensure timely implementation of projects of regional importance;

Strengthen Regional Institutions planning coordination capacity–through developing their capacity to orient financing from external sources toward priority regional projects.

These strategic objectives will be discussed during the forthcoming workshop. After the workshop, the consultant will:

Carry out additional analyses needed to validate assumptions adopted during the workshop;

Assist the Client to address issues on which agreement was not reached during the workshop;

2 External financing will be forthcoming only if, first, the future sector cash flow is strong enough to contribute to sector investment and service commercial loans directly or indirectly through power purchase agreement.

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Review and if necessary reformulate the strategic objectives and sector policies taking into account the outcome of the workshop;

Finalize a preliminary draft of an African Energy Strategic Framework (including sector policies) on the basis of the guidelines formulated by the workshops and further analyses as necessary;

Outline the measures and other propositions where a consensus was not reached.

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3. PRELIMINARY OUTLINE OF THE INVESTMENT PROGRAM

3.1 Types of interventions considered and proposed approach for the short term

The types of Energy PIDA interventions considered are the following:

N1 : Facilitation projects: initiatives establishing policy, regulatory and institutional frameworks to create a suitable environment for investment and efficient operations of regional assets;

N2: Capacity building projects: initiatives to empower the implementing institutions to perform their expanded role as per section 2.2 above. These projects aim at strengthening the financing mobilization and project implementation capacity, and the planning and plan implementation capacity.

N3: Pre-investment studies aiming at identifying investment opportunities and financeable project structures and preparation of investment projects and programs:

- investment opportunity studies and preparation of investment plans and programs at basin or sub-basin levels;

- detailed design of infrastructure projects and resources mobilization for projects which have been identified within the scope of agreed investment plans;

N4: Investments in regional generation, transmission and pipeline infrastructure on which detailed studies are available and resources mobilization is already at an advanced stage. Infrastructure may be large transmission lines or gas pipelines contributing to structure a regional network, or generation facilities with a regional impact. The projects may involve the extension or improvement/rehabilitation of existing infrastructure, or the construction of new infrastructure.

The proposed approach for the short term is to give priority to N2, N3 and N4 projects with a particular focus on N2 in order to rapidly increase the capacity of regional projects to attract financing on the scale needed and N4 to facilitate the physical development of regional structuring infrastructure. As discussed in the report on existing infrastructure and on ongoing programs, this approach needs also a political decision of the AU and Pools to prioritize strengthening of financing and implementation capacity of concrete investments with direct economic benefits, which is already advanced, but did not deliver as much as expected in terms of fostering the implementation of regional projects.

In line with the analysis and recommendations presented in the report on existing infrastructure and ongoing programs, the Consultant proposes that capacity building projects, environmental diagnostic studies, as well as data collection and knowledge generation activities, although considered very important, would be included but not considered the main priority for PIDA Energy infrastructure development program.

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3.2 Outline of the possible investment program and Priority Action Plan (PAP)

3.2.1 Approach

The draft infrastructure development program, which will be developed in phase II of the PIDA Study, will consist of a pipeline of regional projects, composed of a balanced combination of hard and soft interventions/studies over the short, medium, and long-term horizon that is consistent with the strategic framework, the long-term actual demand and commensurate requirements for supply capacity, and lead to a road map for the implementation of selected flagship projects implementable in the short and medium term. It will include:

An optimized list of regional projects (soft and hard) with cost estimates and timing, recommended implementation and operating arrangements over the three time horizons (2020, 2030, and 2040); a list of regional energy projects will be developed, in close coordination with the national investment programs, and to be determined as the least economic cost investment sequence meeting political priorities to be adopted during the Phase I discussion workshop, The latter will be based on the alternative Outlook parameters which will be presented in Section 3 of the present report, and revised as needed.

A proposed first Priority Action Plan (PAP) including:

Projects and programs ready to go, for which the feasibility has been completed positively, EIA and mitigation plans are available, and the social and institutional aspects have been addressed;

Newly identified short-term projects (mainly soft projects to build institutional capacity and prepare the next PAP). The Priority Action Plan (PAP) will comprise possible priority projects to be undertaken in the period 2012-2020. This PAP will replace the NEPAD STAP and will be designed in a form to be a roll-over action plan.

The Consultant presents below:

A preliminary list of potential regional projects based on the RECs’ priority projects A list of regional projects which are part of an economically optimized regional development plan developed under three alternative supply options :

Constrained trade based on the present flows of exchange, assuming no change in the structure of energy exchanges, without implementation constraints (Low Integration Option);

Unconstrained trade without implementation constraints (Ideal Option)

Moderately constrained trade taking into account the risk of dependence upon imported energy and the constraints on project implementation resulting from financing constraints (the Realistic Option).

The investment cost and operating cost of energy supply will be compared under each Outlook, and the list of priority investments and the resulting PAP under each Outlook will be compared to the RECs priority list.

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3.2.2 Preliminary list of potential regional projects based on RECs priority projects and list of PAP projects.

From the review of the Long Term Development plans of each of the Pools and their list of priority projects, the Consultant will propose a PAP, which will be revised and roll over each time the key parameters for the development of the PIDA Energy Infrastructure Development Plan become available.

Pending the results of the least cost optimized investment plan, the Consultant proposes to consider the following preliminary list of possible PIDA Energy projects, which is closely related to the list of priority projects proposed by the RECs:

N2. Capacity Building N° Title Description

Cost (US$/€)

Sponsors

01 Kenya-Uganda Oil Pipeline Capacity Building US$ 0.45 million COMESA

02 Ithezi-Thezi Hydropower Generation Capacity Building US$ 0.6 million SADC

03 North Kariba Bank Hydropower Generation Capacity Building US$ 0.6 million SADC

04 Zambia-Tanzania-Kenyan Electricity Interconnection

Capacity Building US$ 0.5 million COMESA

05 Ethiopia-Kenya Power Interconnection Capacity Building US$ 1.0 million COMESA

06 Benin –Togo-Ghana Interconnection Capacity Building US$ 0.5 million ECOWAS

07 Ghana-Burkina Faso Interconnection Capacity Building US$ 0.5 million ECOWAS

08 Ethiopia-Kenya Power interconnection Capacity Building US$ 1.0 million IGAD

09 WAPP Connectivity

Leverage excess fiber communication capacity on the HV cross-border power transmission

US$ 0.85 million ECOWAS

N3. Studies N° Title Description

Cost (US$/€)

Sponsors

01 Zambia-Namibia-Zimbabwe-RSA Transmission System

To prepare the Feasibility Study. US$ 0.2 million SADC

02 Kudu CC Plant (800MW) To engage a Transaction Adviser.

US$ 0.1 million SAPP

03 Mpanda Nkuwa (Phase I) (1,300 MW) To update the Feasibility Study. US$ 1.4 million Mozambique 04 HCB North Bank HEP (850 MW) To update the Feasibility Study. US$ 0.77 million Mozambique/HCB

04 Nigeria-Algeria Gas Pipeline (TAGP) Study Study of Construction of gas pipeline Nigeria-Algeria to export 20 billion m3 of gas

US$ 2.5 million

AMU ECOWAS SONATRACH NNPC

05 Guinea - Mali Interconnection Project (Nzerekore -Fomi - Linsan – Bamako)

Interconnection study of the networks of Guinea and Mali for export of lower cost power from Fomi (Feasibility + ESIA + Bidding Docs)

US$ 2.5 million ECOWAS WAPP

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Cost (US$/€)

Sponsors

06 WAPP North Core 330kV Project (Nigeria - Niger - Burkina Faso -Bénin Interconnection)

Feasibility of 330 kV Nigeria-Niger-Benin-Burkina Faso interconnection


07 Souapiti Hydropower 515 MW Feasibility Update + Environmental+ Bidding Docs of Hydropower Dam

US$ 5 million ECOWAS WAPP

08 225 kV Bolgatanga (Ghana)-Ouagadougou (Burkina Faso) Interconnection

Feasibility Update + Environmental Update + Bidding Docs (225 kV, 80 km interconnection line; HV substations in Bolgatanga and Bagré)


09 Ghana- Cote d’Ivoire (2nd Transmission Line Abobo-Prestea)

Feasibility + ESIA + Bidding Docs of 225 kV Interconnector

US$ 2.275 million

ECOWAS WAPP

10 330 kV Aboadze-Prestea-Kumasi-Han Transmission Line

Engineering, ESIA + Bidding Docs of 330 kV Interconnector Aboadze-Prestea-Kumasi-Han Transmission Line

US$ 0.850 million

ECOWAS WAPP

11 Han-Bobo Dioulasso–Sikasso-Bamako Interconnection

Feasibility + ESIA + Bidding Docs of 330 kV Ghana-Burkina Faso-Mali Interconnector


12 DRC – Grand INGA Integrator Study

Exploring the feasibility of power development at Grand INGA, DRC and ensuring power transmission to other sub-regions as well as to Europe and the Middle East.

US$ 16.5 million ECCAS SADC

12 Prefeasibility Study for power interconnection Cameroun-Chad

Update the Feasibility Study and to prepare the tender documents.

US$ 0,8 million ECCAS

13 Tanzania-Kenya Gas pipeline

Feasibility Study for a natural gas pipeline from Dar Salam to Tanga (Tanzania) and Mombasa (Kenya)

US$ 0.486 million EAC

N4. Investment N° Title Description

Cost (US$/€)

Sponsors

01 Tunisia-Libya Gas Pipeline Project New 275 km Gas Pipeline between Mellita (Libya) and Gabes (Tunisia)

US$ 277.4 million

AMU NOC STEG

02 Strengthening of the Morocco-Spain Interconnection

Morocco-Spain interconnection reinforcement project (Part of the European Mediterranean Electricity Ring)

€ 334.7 million AMU ONE REE MEDELEC

04 330 kV Aboadze - Volta Transmission Line

215 km ; 330 kV; 1,000 MVA line to provide capacity for power trade among Nigeria, Benin, Togo, Ghana, Cote d'Ivoire.


05 330 kV Volta - Momé-Hagou - Sakété (Ghana-Togo-Benin Interconnection)

New 330 kV line Ghana-Togo- Bénin to provide capacity for power trade among Nigeria, Benin, Togo, Ghana, Cote d'Ivoire.


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Cost (US$/€)

Sponsors

06 OMVS 60 MW Félou Hydro Power Projects

Hydro Power Projects to augment the power capacity of the OMVS system.


07 225 kV OMVG (Gambia, Guinea Bissau, Senegal, Guinea) + Hydro sites Kaleta and Sambangalou

225 kV interconnection Gambia-Guinea Bissau-Senegal-Guinea-OMVS + Hydro dams at Sambangalou (128 MW) and at Kaleta (240 MW).

US$ 1,325 million

ECOWAS WAPP

08 Ikeja west (Nigéria) – Sakete (Bénin) 330 kV Interconnection Benin–Nigeria to interconnect Nigeria and Niger with rest of the WAPP Zone A.


09 225/150 kV Ferke-Sikasso-Ségou (Mali - Cote d'Ivoire Interconnection)

234 km of 225 kV line Côte d’Ivoire- Mali and 225/150/33/15 kV substation in Mali.


10 Centrale hydroélectrique de Chollet + lignes vers Congo et Cameroun

Dam on Dja River in Congo (600 MW) to supply Congo and Cameroun in priority

? ECCAS

11 Kenya-Uganda Oil Pipeline Project

Nairobi (Kenya)-Kampala (Uganda) Oil Pipeline (Extension of the Mombasa Oil Pipeline to Kampala)

US$ 78.2 million EAC KPC

12 Ethiopia-Kenya Interconnector New 1 200 km / 400 kV / Transmission line interconnecting Ethiopia, Kenya,

€ 797 million IGAD EAC

13 Ethiopia-Sudan Interconnection 230 kV (double circuit) 296 km Ethiopia-Sudan Interconnection

US$ 43.1 million IGAD

14 Projet Hydro-électrique de Rusumo Falls 60 – 80 MW Rusumo Falls on the River Kagera between Tanzania and Rwanda.

US$ 300 million EAC NELSAP NBI

15 Interconnection of grids of Nile Equatorial Lakes Countries

Construction and upgrading of 769 km of 220 kV and 110 kV power lines to interconnect the electric grids of the Fnbi countries.

US$ 272 million EAC NBI NEL

16 Kariba-North and Itezhi Hydropower Expansion

Project in Zambia to expand the existing Kariba-North power station by 360 MW and developing 120 MW at Itezhi-Tezhi on the Kafue River (Zambia)

US$ 510 million COMESA SADC

17 Kariba South Hydropower Plant

Capacity increase of 300 MW to the existing Kariba South Hydropower Plant on the Zambezi River (Zimbabwe)

US$ 200 million SADC

18 Hydropower projects: Gilgel Gibe II; Tekeze; Beles

Hydropower projects (Gilgel Gibe II; Tekeze; Beles)

US$ 1.4 billion COMESA

19 Gilgel Gibe III Gilgel Gibe III Hydropower project and Transmission Line


20 Development of Coal fired thermal power station

3000 MW Coal fired thermal power station in Swaziland

? COMESA

21 Mepanda Uncua Hydropower Project Hydropower Project (1,300 MW in Phase 1 and 2,400 MW in Phase 2) in Mozambique

US$ 2 billion SADC

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Cost (US$/€)

Sponsors

22 Zambia-Namibia-Zimbabwe-RSA Interconnectors

Upgrade of line Kafue-Victoria Falls + New lines: Livingstone-Katima Mulilo + Alaska-Sherwood + Hwange-Livingstone + New Zimbabwe-RSA transmission line

US$ 200 million SADC

23 Kudu Thermal Power Plant and associated transmission lines

New 800 MW combined cycle gas turbine power station in Namibia + lines.

US$ 1.2 billion SADC

24 Zambia-Namibia Interconnector 220 kV Zambia-Namibia Transmission Interconnector US$ 220 million SADC

25 Caprivi Interconnector

Construction of a 200 MW HVDC transmission connection from Zambia to Namibian

€ 302 million SADC

26 Reinforcement Inga-Kolwezi (2x 500 kV DC) Inga-Kolwezi interconnection reinforcement US$ 170 million SADC

27 Second Interconnector ZESA-Eskom (420 kV)

ZESA-Eskom Interconnection US$ 46,1 million SADC

28 Zimbabwe-Botswana-South Africa Interconnector (2nd)

Increase the existing capacity of interconnection between Zimbabwe, Botswana and South Africa

? SADC

29 Mozambique-Zimbabwe Interconnector (2nd)

2nd 400kV interconnector Songo (Mozambique)-Bindura (Zimbabwe).

? SADC

The table below presents a draft list of short term priority projects under PIDA Energy PAP based on the requirement to address at the regional level the most pressing needs for added supply capacity, their potential for making a significant contribution to regional integration of the energy systems, and their level of readiness for accelerated development. The list will be revised after the least cost continental development plan has been finalized under Phase 2 of the PIDA study.

N2. Capacity Building N° Title Description

Cost (US$/€) Sponsors

01 Kenya-Uganda Oil Pipeline Capacity Building US$ 0.45 million COMESA

02 North Kariba Bank Hydropower Generation Capacity Building US$ 0.6 million SADC

03 Zambia-Tanzania-Kenyan Electricity Interconnection Capacity Building US$ 0.5 million COMESA

04 Benin –Togo-Ghana Interconnection Capacity Building US$ 0.5 million ECOWAS

05 Ghana-Burkina Faso Interconnection Capacity Building US$ 0.5 million ECOWAS

06 WAPP Connectivity

Leverage excess fiber communication capacity on the HV cross-border power transmission


Draft





Cost (US$/€)

Sponsors

01 Zambia-Namibia-Zimbabwe-RSA Transmission System

To prepare the Feasibility Study. US$ 0.2 million SADC

02 Mpanda Nkuwa (Phase I) (1,300 MW) To update the Feasibility Study. US$ 1.4 million Mozambique

03 HCB North Bank HEP (850 MW) To update the Feasibility Study. US$ 0.77 million Mozambique/HCB

04 Nigeria-Algeria Gas Pipeline (TAGP) Study Study of Construction of gas pipeline Nigeria-Algeria to export 20 billion m3 of gas

US$ 2.5 million

AMU

ECOWAS SONATRACH

NNPC

05 Guinea - Mali Interconnection Project (Nzerekore -Fomi - Linsan – Bamako)

Interconnection study of the networks of Guinea and Mali for export of lower cost power from Fomi (Feasibility + ESIA + Bidding Docs)


WAPP

06 WAPP North Core 330kV Project (Nigeria - Niger - Burkina Faso -Bénin Interconnection)

Feasibility of 330 kV Nigeria-Niger-Benin-Burkina Faso interconnection


WAPP

07 330 kV Aboadze-Prestea-Kumasi-Han Transmission Line

Engineering, ESIA + Bidding Docs of 330 kV Interconnector Aboadze-Prestea-Kumasi-Han Transmission Line

US$ 0.850 million

ECOWAS

WAPP

08 DRC – Grand INGA Integrator Study

Exploring the feasibility of power development at Grand INGA, DRC and ensuring power transmission to other sub-regions as well as to Europe and the Middle East.

US$ 16.5 million ECCAS

SADC


Cost (US$/€) Sponsors

01 330 kV Volta - Momé-Hagou - Sakété (Ghana-Togo-Benin Interconnection)

New 330 kV line Ghana-Togo- Bénin to provide capacity for power trade among Nigeria, Benin, Togo, Ghana, Cote d'Ivoire.

US$ 105 million ECOWAS

WAPP

02 225 kV OMVG (Gambia, Guinea Bissau, Senegal, Guinea) + Hydro sites Kaleta and Sambangalou

225 kV interconnection Gambia-Guinea Bissau-Senegal-Guinea-OMVS + Hydro dams at Sambangalou (128 MW) and at Kaleta (240 MW).

US$ 1,325 million

ECOWAS

WAPP

03 Kenya-Uganda Oil Pipeline Project

Nairobi (Kenya)-Mombasa (Uganda) Oil Pipeline (Extension of the Mombasa Oil Pipeline to Kampala)

US$ 78.2 million

EAC

KPC

Draft





Cost (US$/€)

Sponsors

04 Kariba-North and Itezhi Hydropower Expansion

Project in Zambia to expand the existing Kariba-North power station by 360 MW and developing 120 MW at Itezhi-Tezhi on the Kafue River (Zambia)

US$ 510 million COMESA

SADC

05 Hydropower projects: Gilgel Gibe II; Tekeze; Beles

Hydropower projects (Gilgel Gibe II; Tekeze; Beles)


06 Zambia-Namibia-Zimbabwe-RSA Interconnectors

Upgrade of line Kafue-Victoria Falls + New lines: Livingstone-Katima Mulilo + Alaska-Sherwood + Hwange-Livingstone + New Zimbabwe-RSA transmission line

US$ 200 million

SADC

07 Kudu Thermal Power Plant and associated transmission lines

New 800 MW combined cycle gas turbine power station in Namibia + lines.

US$ 1.2 billion SADC

3.2.3 Benefits of Regional Integration of Energy Systems and List of economically optimum regional projects under three alternative policy Outlooks

A preliminary list of Priority Regional Investments in generation is given in Annex 3-7 and was discussed in Section 3-4-3 of Part III report.

3.3 A first view on possible prioritizing criteria for the selection of Priority Projects

Under Phase II of the PIDA Study, the projects and programs which are part of the optimized development program under the selected regional policy objectives will be included in the final draft of the PIDA Energy Infrastructure program in relation to their expected contribution to the regional integration objectives. Projects which do not meet the test of contributing to Regional Integration may still be included in the national investment programs.

At this preliminary stage, the following criteria are proposed for discussion:

3.3.1 Joint project

Rationale. A project developed by at least two countries should be considered as a candidate to feature in the list of projects contributing to regional integration. Projects which are only of local interest, such as short- distance, cross-border electrification, may not qualify.

Indicators: expected impact for regional integration and number of countries involved in the planning and/or operation of the project and sharing benefits.

Draft




3.3.2 Project as a part of an integrated regional pool development approach

Rationale. The consultant promotes the concept of regional interconnection, energy pooling and development of continental/regional energy markets. An important criterion should thus be that the investment project would contribute to the implementation of a regional investment strategy for network interconnection e.g. reinforcement of the Ghana transmission system as part of the WAPP transmission development plan would qualify as regional.

Indicator = is the project part of a AU or Pool development plan?

3.3.3 Project to feed directly or indirectly to the development of a regional power market

Rationale. A project located in a given country but with a capacity to meet regional energy imbalances by exporting electricity to neighbouring countries for mutual benefit. Indicator = Is the power plant large compared to the present and medium term demand of the host country (e.g. more than 30% of national demand).

The formulation of a preliminary draft infrastructure development program will also take into account the following elements:

The contribution of the project to a regional multi-sector vision ( linkages with the TWR Sector, the transport strategy, and the ICT strategy);

Preliminary assessments of the financial viability of projects/programs;

Preliminary assessments of the social/environmental (EIA) viability of projects/programs

Refinement of the prioritization criteria to include other relevant factors including (but not limited to):

the stage of development of each program (according to defined milestones);

the prospects for financing e.g. the level of committed finance

role of stakeholders in program implementation, together with human resource availability and capacity building requirements;

prevalence of an appropriate enabling framework for project implementation and the need for complementary policy, institutional, or regulatory measures required to enable efficient and fruitful implementation;

Potential social/environmental impact and other risks and challenges to implementation, which may not be covered in the initial project assessment.

3.4 Implementation strategy

This point is addressed together with the 3 other sectors.

energy for africa draft study PIDA Study: Phase I Volumes

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