IT IS estimated that 20% of the population in West Africa has access to electricity, falling to as low as 4% in Niger and Guinea Bissau; in particular, rural electrification is very low, falling to between 1-2%. Although West Africa possesses vast untapped resources (e.g. the Niger and Volta rivers as well as huge proven crude oil and natural gas reserves in the Gulf of Guinea and surrounding areas), West Africa remains the sub-region with the lowest rate of electricity generation and consumption in the worldi. Total regional electricity consumption is about 32TWh: Nigeria (14.6TWh (45.8%)), Ghana (8.8TWh, 27.8%), Côte d’Ivoire (3TWh, 9.4%) and Sénégal (1.4TWh, 4.4%) are the largest electricity consumersii. Based on an existing generating capacity of about 10,000MW, the region needs to increase its generating capacity by about 17,000MW by 2023 to meet minimum development targets.

The deterrents to investment in the West African power sector are many, including the massive costs associated with rehabilitation works or greenfield developments, weak tariff structures and a lack of credit-worthy customers. In most cases, the markets (with the notable exception of Nigeria) are small and the customers are the cash-strapped electricity parastatals.

It has been recognised by most West African governments that public sector funds and technical capacity are inadequate to increase electricity generation, as well as to improve transmission and distribution efficiencies necessary to close the development gap. As a result, tangible progress towards greater private sector participation (PSP) is being made, primarily through the introduction of independent power projects (IPP’s) (including rehabilitation schemes) and a small number of privatisations. Power sector reforms, at different stages in the region, are being undertaken in most West African countries but have not been sufficiently employed or have not been implemented for long enough to enable definitive conclusions to be drawn. At first glance, neither a significant jump in electricity generation nor an improved quality in supply has been experienced. As Andrew Aldridge, Director of EM Energy Solutions, states: ‘Increasing private sector participation in the West African electricity markets will require a continued improvement in the investment climate, with a particular focus on the turnaround of utility operations and the implementation of transparent and flexible regulation. This will require significant political commitment and the support of the African Development Bank and other multilateral agencies, both for funding and capacity building.’

Various new bodies have been established to regulate the sector in West Africa and improve access to electricity and utilities are becoming better organised and starting to focus on national and region-wide solutions with the support of donors, multilateral agencies and regional organisations (particularly the Economic Community of West African States (ECOWAS)).

Structure of the sector
Electricity in the region is generated by thermal (58.8%) or hydro (41.2%) sources. West Africa has substantial hydro power potential (estimated at 24GW), however, very little – estimated at 4% – of this potential is being tapped. This can be attributed principally to the large capital requirement for hydro power projects and the perceived need of nations dependent upon this source of electricity to reduce their over dependence on hydro. This is perceived as a problem due to supply difficulties as most West African countries are not oil producers. However, with the construction of the West Africa Gas Pipeline looking likely and advances being made in the development of the West Africa Power Pool (WAPP), the region should soon be able to take advantage of the vast oil and gas reserves of the Gulf of Guinea. Initiatives exploiting the region’s hydro potential have taken off more amongst the Zone B countries in WAPPiii (due primarily to the fact that, with a few exceptions, oil and gas reserves are notably lacking), with the success of the Manantali hydro power project, further hydro schemes are planned, including at Sambagalou, Felou and Gouina (to supply Sénégal, The Gambia, Guinea-Bissau and Guineaiv), Fomi and Kaleta in Guinea and Bumbuna in Sierra Leonev.

Privatisation – at what price?
The cases of Sénégal and Cameroon best illustrate the difficulties with privatising state power utilities. The experience of both countries demonstrate that the line between success and failure is a fine one. In the past five years, Sénégal’s state-owned company, Société Nationale d’Electricité (SENELEC), has been privatised, nationalised again and then once more slated for privatisation. The first attempt to privatise SENELEC was in 1999 but the partnership was short-lived, terminating 18 months later with the Sénégalese government buying back the shares in SENELEC. A second attempt, undertaken in 2001vi, also failed due mainly to the crash in world energy markets as a result of the Enron fall-out, creating an adverse climate for investment in the power sector. The sheer size of the investment required to rehabilitate and upgrade SENELEC’s assets and to develop green-field projects under the investment plan, also proved too much for the main bidders, AES and Vivendi, at a time when they were financially vulnerable. The reform process in Sénégal seems to have been rather confused; this is not least because the reform programme (hugely unpopular with trade unions) was presented to the government by the World Bank as a pre-condition to signing new financing measures with the Bank and the IMF. Critics claim that the programme focused on the reforms and institutional changes to the neglect of finding solutions to bridge the financing and development gap.

The failure of the government to sell off a majority stake in SENELEC to a strategic investor has certainly not all been negative. The industry has been restructured with independent generation of electricity introduced on the basis of the single buyer model (buying electricity from Greenwich Turbine Incvii and the Manantali hydro power project) a regulatory body has been established to protect consumers and competition in the market and SENELEC has been transformed into a joint stock company owned by the state, its employees and the public (it is listed on the regional bourse). Government has had success in introducing IPP’s as a result of the reforms, helping to increase the supply to the grid as well as access. Although the World Bank is still encouraging Sénégal to privatise SENELEC and has established a task force to advise on the best method, there is growing consensus that government should resist this. Since its return to public ownership in 2001, annual sales have increased by an average of 10%, power outages between 2001 and 2002 declined by 50% and workers cooperation has improved, resulting in SENELEC raising approximately US$16M on the West African stock exchange in 2003.

A few of the smaller countries in West Africa have been more successful with the privatisation process. Sub-Saharan Africa’s first electricity and water privatisation occurred in 1997, with Vivendi winning a 20-year concession to run Gabon’s state utility (SEEG). This was followed by Gabon’s first initial public offering by a sale of shares in SEEG to the public. SEEG serves 1.2 million people and has a turnover of approximately US$160M; SEEG quickly started making profits, cutting water losses (down to about 12.5%) and increasing public use of electricity and water significantly (by about 10%). Cameroonviii has achieved some success in privatising its power utility, but without so far achieving the results expected in terms of efficiency. Its heavy dependence on hydro power has left the country extremely vulnerable to droughts. In 2000, AES acquired a 56% stake in Société Nationale d’Electricité du Cameroon (now AES-SONEL), the wholly-integrated power utility.

As a start to addressing the country’s capacity problems, AES-SONEL has made inroads in diversifying power supply sources. It has just constructed a new oil-fired plant at Limbe. The Emerging Africa Infrastructure Fund and the Dutch development finance institution, FMO, funded the construction of the 85MW thermal power plant. Construction at the site started in August 2003 and the plant is now commissioned. The new plant should help to alleviate severe power shortages occurring during the dry season and should also provide a reliable long-term power supply. AES is also planning to utilise Cameroon’s so far unexploited gas reserves to greatly increase capacity and reduce the country’s reliance on hydro power. However, with thermal power costing more to produce and AES needing to recoup the cost of its investment, electricity prices are likely to rise at further cost to consumers.ix In a sector that is still vertically integrated, piecemeal investment has led to little perceived improvements. Electricity supply remains unreliable, prices have continued to rise and AES has had difficulties with the unions when trying to right-size the workforce. IPP’s will need to be encouraged alongside such projects to increase production capacity.

Helen Tarnoy, Commercial Director of Aldwych International, a new breed of power developer focusing on African opportunities and the former Director General of AES-Sonel, states: ‘The fundamental problem is one of an imposed ideology: privatisation at all costs, and ‘unbundling’ of utilities in the (probably misguided) belief that this brings efficiency. Many African countries are still struggling to establish democracy and privatisation is a system that requires democracy if it is to succeed. If investors wait for democracy and for successful privatisation, Africa’s power crisis will be exacerbated. Equally, and except in the case of Nigeria, it is hard to see the logic of unbundling a cash-starved national utility with minimum generating capability, most of which (in many countries) is sited on one river. Although the public sector is often mismanaged and under-funded, the private sector generally cannot raise sufficient funds to effect the massive investments that are needed all over Africa to improve the power supply. Debt is also going to be limited, and private sector debt, priced to take into account African risk, is not cheap either.’

More recently, successes have been realised in West Africa through gradual liberalisation. The timeframes required by funding partners for the reform process is often considered as too short (especially considering the time taken by developed economies in a similar exercise). Nonetheless, energy reforms focusing on:

• Unbundling of vertically integrated parastatals for eventual divestiture to the private sector, possibly commencing with the contracting out of the management of the distribution and generation entities,
• Introduction of legislation accommodating PSP in the unbundled sector,
• Introduction of IPPs,
• Consideration of innovative ways of revenue collection, including prepayment meters,
• Reduction of state control by the creation of an autonomous regulator,
are likely to result in long-term gains, if coupled with transparency, a clear understanding of the requirements of the various stakeholders at the outset, continued government support and funding from multilaterals and international financing institutions.

Planned privatisations
Nigeria faces a serious energy crisis due to declining electricity generation from domestic power plants over several years. President Obasanjo has made solving the country’s energy crisis a priority, but progress has been slow due primarily to perceived resistance from the state-owned Nigerian Electric Power Authority (NEPA) itself and the difficulty in pushing through reforms. As a consequence, most Nigerian companies and several households have their own diesel generators and some companies have captive gas-fired power plants. NEPA is heavily dependent upon fuel subsidies, however, energy losses are high (estimated by the World Bank at between 30-35% between generation and billing (with only 80% of customers paying)) and NEPA has historically found it difficult to fund capital projects. The government is, therefore, committed to NEPA’s privatisation and aims at increasing generating capacity to 10,000MW (from about 4000MW) and improving the transmission and distribution systems by 2007. The timetable for NEPA’s privatisation (slated since 2000) provides for it to be split into unitsx, with the generation and distribution units to be sold at the end of 2005. The relatively slow progress made in privatising NEPA has meant that a mix of publicxi and private solutions are being developed whilst the process gets underway.

Nigeria’s neighbour, Benin, is also planning to privatise its distribution network and open the generation network to competition. In July, the World Bank approved an International Development Association (IDA) credit of US$45M to assist the government to reinforce and expand its electricity network and introduce IPP’s and PSP in the distribution of electricity. The funds will be used to construct a 350km, 161kV transmission system between Togo and Benin, to build substations and expand the power lines. The Communauté Electrique du Benin (CEB) is responsible for electricity generation and transmission in Benin and Togo as well as supplying electricity to the power distribution utilities in both countries. In Togo, power distribution was privatised in December 2000. Benin is expected to privatise its electricity distribution network as part of the IDA funded project. It is also planning to introduce IPP’s into the market, although CEB will remain the bulk buyer/offtaker for both Benin and Togo.

Ghana started restructuring its power sector in 1994. The main purpose of the reforms was to unbundle the sector, improve the performance of the unbundled companies, create an enabling framework to attract PSP and create a competitive environment. The most recent reform plansxiii focus on restructuring the Volta River Authority (VRA), the state’s primary provider of power. VRA owns and operates two hydro power plants, as well as the 330MW Takoradi thermal power plant. VRA also operates transmission lines to Togo, Benin and Côte d’Ivoire. Its subsidiary, NED, distributes electricity in the northern regions of Ghana. Government proposes that VRA will be restructured as follows: all hydro power facilities will be transferred to a new state owned company formed to run hydro plants and dams and safeguard and manage the Volta lake; thermal generation will be conducted by a new company, Ghana Power, which will assume all obligations of VRA vis-à-vis its gas purchasing in connection with the West African Gas Pipeline and will own the thermal plants at Takoradi; a new public company is being proposed to manage the entire transmission network, whilst the state-owned Electricity Company of Ghana (ECG) will absorb the NED and carry out the distribution function. One of the results of these reforms would be to ensure that the country’s hydro power assets are protected from creditors, by being precluded from being mortgaged or otherwise encumbered.

Regional co-operation
As regional power utilities recognise their inability to provide adequate and reliable electricity to consumers, regional power integration is becoming a means of addressing shortfalls. Various solutions formed around river basin management programmes have been operating, some since the 1960’s, including the Niger Basin Authority (Benin, Burkina Faso, Côte d’Ivoire, Cameroon, Mali, Niger, Nigeria and Chad) and Volta Development Authority (Burkina Faso, Côte d’Ivoire & Ghana). In particular, as mentioned above, the smaller markets in WAPP (mostly in Zone B) have formed joint development initiatives to exploit common resources. There is the OMVS sub-regional project which brings together countries sharing the Sénégal river and includes the Manantali hydro power project in Mali (finally completed in 2002xiv), and the OMVG framework bringing together countries sharing the River Gambia (Sénégal, The Gambia, Guinea and Guinea-Bissau).

These initiatives have been further developed under the umbrella of WAPP. In November 1999, ECOWAS heads of state signed an agreement launching WAPP to establish interconnected network grids and harmonise regulatory frameworks. WAPP aims to develop reliable and competitively-priced supplies of energy in the region, to increase energy trading amongst member states and to promote investment in the sector. Important steps are being taken to promote investor securityxv and permit investors to realise economies of scale by producing for a larger regional market. Attracting foreign and local investment to finance projects in the sector is the immediate concern. The existing demand and expected rates of growth in the region could be one of the most appealing aspects of WAPP for investors. There are two types of WAPP priority projects: those dealing with interconnection (or the construction of cross-border transmission lines) and those covering generation. Zone A countries are now nearly entirely inter-connected, permitting cross-border electricity trading. A proposed transmission link between Nigeria and Benin will reinforce the potential for trading within Zone A and increase competition amongst suppliers, as should the construction of the West Africa Gas Pipeline. Also, although Côte d’Ivoirexvi is still experiencing political trouble, an agreement has been signed providing for an interconnection between Côte d’Ivoire and Mali, involving the construction of a 234km, 225kV line and two 150kV lines. Other priority high voltage interconnection lines, involving Burkina Faso, Mali, Ghana and Togo are planned before 2008 allowing the interconnection of 10 countries.xvii

Hurdles to the success of WAPP remain, including the establishment of the WAPP institutions (although some progress has been made), such as an independent regulatory agency to regulate the rules governing cross-border trade, the development of the remaining agreements for the operation of WAPP and the development of a common legal framework (the ECOWAS Energy Protocol goes some way to achieving this but has not yet been ratified by most national parliaments in the region). However, electricity trading between West African States should reduce energy costs considerably and increase energy security through strengthened transmission interconnections. It will promote the optimal and sustainable use of available resources, create economies of scale for developers (thus boosting trade) and it should enhance access to electricity services.

Diversification – other regional initiatives
Ghana plans to reduce its reliance on hydro power by increasing and expanding its thermal generating capacityxviii. In April 2003, CMS Energy and VRA announced a US$100M expansion plan of their thermal power plant at Takoradi. The upgrade will convert the plant from burning crude oil to natural gas received from Nigeria through the West Africa Gas Pipeline. When the West African Gas Pipeline (WAGP)xix is completed, VRA plans to convert oil-fired facilities at Takoradi and Tema to natural gas. WAGP has been in the pipeline for more than 10 years, but is now looking likely to be constructed by the middle of 2006. In November 2004, the World Bank board approved a total of US$125M in guarantees supporting the construction of the pipeline. The Multilateral Investment Guarantee Agency (MIGA) is providing US$75M for up to 20 years and the International Development Association (IDA) guarantee is for US$50M for 22 years. The MIGA cover will guarantee 90% of the equity investment of US$83.4M in Ghana by West African Gas Pipeline Company (WAPCo), led by Chevron Texaco, from the risk of breach of contract for a net exposure of US$67.5M. The World Bank Group’s contribution, seemingly small compared to the total cost of the project (US$590M), is seen by private investors as the precursor for their participation in the projectxx. The pipeline will transport gas from Nigeria’s Delta region to Benin, Togo and Ghana and might eventually be extended as far as Sénégal. Initially, it will only supply gas to power stations in Ghana from Nigeria, although it is expected that as demand for gas grows, other oil producing countries in the Gulf of Guinea will be able to take advantage of the pipeline to sell their gas.

A new paradigm
The success of power companies in West Africa, whether in the public or private sector, will depend upon certain economic realities: tariffs will need to be based on real costs (covering at least financing costs, asset replacement costs and margin); revenue-collection mechanisms will need to be improved; in relation to IPP’s, payment will need to be secured; investment in the transmission and distribution systems to minimise loss and wastage is critical; and the performance and management of state-owned utilities needs to be improved.

The offtakers’ credit-worthiness remains all important, but as stated above, there are a number of existing mechanisms that can be used to enhance this and offer investors comfort: these include the use of state and multilateral agency (e.g. the World Bank) guarantees, state collateral (including secured accounts and an effective security pool of assets) and political risk guarantees. As Helen Tarnoy states: ‘A new paradigm has to be developed, in which the public and private sectors work together in a partnership in which both commit to investing in the country’s power supply. The few privatisations hitherto have been based on the premise that the government contributes the assets ‘in kind’ (usually in a lamentable state of disrepair), while the investor contributes cash (usually not very much) and a commitment to fund future development.

‘This makes future development far more costly than it need be, and inevitably leads to confrontation: the government accuses the investor of not investing, the investor responds that the government has not raised tariffs/carried out promised sector reforms to permit it to invest, the government (especially when facing an election) counters that it cannot raise tariffs/antagonise the unions when the quality of service is so poor. Stalemate.’

Successful reforms depend upon the accommodation of the often conflicting concerns of the different stakeholders in the sector. Issues such as the pace and scope of the investments to be made, as well as price adjustments need to be carefully considered in the context of poor service delivery. To be able to secure the levels of finance required to successfully implement planned projects, investors will need to be certain that they will be able to carry out their projects without unnecessary state intervention, lenders will require certainty that there will be effective security in the project from which they can realise value for their loans in the event of default under financing agreements. No amount of reforms or restructurings alone will lead to the kind of investment required to bring long-term improvements to the region’s electricity sector – the focus must be on the whole system, both nationally and regionally, and implementing these reforms, with private sector investment complimenting (rather than substituting) support from multilateral agencies and international financing institutions, public sector funding and government’s strategy.

Author Info:

Constantine Ogunbiyi is a Senior Associate in Cadwalader, Wickersham & Taft LLP’s Project Finance Department and the Deputy Head of the Africa Practice. Ogunbiyi specialises in energy sector and infrastructure projects, having advised governments, sponsors and financiers on a wide range of projects. The author would like to thank Sannie Kakra-Kouamé for all her research and contributions to this article.

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Reference notes

i) Sub-Regional ‘Energy Access’ Study of West Africa, November 2003, Global Network on Energy For Sustainable Development
ii) Source Energy Information Administration
iii) Zone A countries include Benin, Burkina Faso, Cote d’Ivoire, Ghana, Niger, Nigeria and Togo. Zone B countries include The Gambia, Guinea, Guinea-Bissau, Liberia, Mali, Sénégal and Sierra Leone.
iv) Guinea has one of the highest hydroelectric potential estimated at 19.4GWh per year (only a fraction is exploited at the Garafiri hydroelectric plant).
v) The project was stalled many times during the civil war, but now seems to be back on track. Construction of the 50MW plant is expected to re-commence in January 2005. A grant has been provided by the Italian government, and loans are to be provided by the World Bank (a US$31M programme to overhaul Sierra Leone’s energy sector) and the OPEC Fund.
vi) 51% of SENELEC’s shares were being offered up for US$105M, with a requirement on the strategic partner to carry out a significant investment programme.
vii) Greenwich (a GE subsidiary) is the majority equity investor and operator of a 50MW combined cycle plant in Dakar. International Finance Corporation (IFC) holds a minority equity position. Greenwich has entered into credit facilities for the financing with IFC and Credit Commercial de France (CCF). CCF secured credit insurance through a guarantee program of SACE, the Italian export credit agency, and a partial interest subsidy through the Mediocredito Central Subsidy Department (MCSD).
viii) Cameroon has one of the greatest hydro-power potentials in Africa (estimated at 500,000MW)
ix) It is interesting to note reports that Burkina Faso plans to diversify its mostly thermal power as a result of the perceived high costs of thermal power, by connecting to the hydroelectric grids of Cote d’Ivoire and Ghana.
x) NEPA is to be unbundled into six generating companies, 11 distribution companies and one transmission company. The parastatal is currently run by a technical committee until its privatisation.
xi) NEPA has recently put in place plans to construct three power stations, at a cost of approximately US$650M to the state for the development of the first stage of the three projects. The first plant will be built by Siemens and involves an 828MW thermal power plant at Geregu in northern Nigeria. The two others are to be built by Chinese companies, Shandong Power Construction Company and the China Machinery and Equipment Import and Export Company. These are a further two gas powered plants, a 335MW station at Papalanto and a 335MW plant at Omotosho state. The programmes are being partly financed by the Export Import Bank of China through a US$700M loan facility.
xii) As stated above, this has included various IPP’s and emergency power projects. An example is the AES Nigeria Barge project, originally awarded to Enron. Although commissioned in 2002, AES recently succeeded in refinancing the project by raising US$120M from a consortium of four commercial banks and three development finance institutions. Various other gas-fired IPP’s are at different stages of development, including the Agip Oil Power Project in Ughelli, Delta and Rivers IPP in Port-Harcourt.
xiii) Source Ghana Energy Commission, 23 June 2004
xiv) The Manantali dam, built by the Organisation pour la Mise en Valeur du fleuve Sénégal(OMVS) on the Bafing river, the main tributary of the Sénégal river, consists of a 200MW power station and a network of 1300km of transmission lines to the capitals of Mali (Bamako), Mauritania (Nouakchott) and Sénégal (Dakar). The construction of this project, which cost about US$500M, began in 1981 and took nearly 20 years to be completed due to cost overruns, coupled with political and military tensions between Mauritania and Sénégal, as well as disagreements between the riparian states and the donor institutions (Arab governments, the Islamic and African Development Banks, Italy, the French CFD, the European Union, the German KgW, the Canadian CIDA, the World Bank, the West African Development Bank and the Nordic Development Bank). In March 2000, the AfDB kick-started the process again by approving a US$33.5M loan for the Manantali energy project. The facilities came online in December 2001, supplying power to Mali’s grid, then Sénégal in July 2002 and Nouakchott in November 2002. The project is managed by the company Société de gestion du barrage de Manantali – SOGEM. In May 2002, the OMVS signed a new charter to allocate water resources and hydro-electric power, and approved the restructuring of the Manantali Energy Management Company (SOGEM). SOGEM will maintain ownership of infrastructure and equipement at Manantali, but Eskom will handle marketing and distribution of power generated at Manantali.
xv) For example, the ECOWAS Energy Protocol (modelled on the European Energy Charter) provides a legal framework for investment and trade in the sector, by ensuring non-discriminatory rules, free trade of energy, equipment, products and services and dispute resolution. It also protects investors against nationalisation and expropriation and guarantees the convertibility and transferability of funds. In addition, the ECOWAS Energy Information Observatory, the first of WAPP’s permanent bodies, will provide a focus for both systems operation and a source of information to stakeholders and investors. It should also ensure that planning criteria, operating procedures and standards become harmonised.
xvi) The use of gas-fired power plants has resulted in Cote d’Ivoire becoming a regional exporter of electricity. Cote d’Ivoire provides power to Benin, Togo, Mali, Burkina Faso and Ghana. An additional connection to Guinea is being studied and, as mentioned above, an interconnection with Mali is planned. Bouygues’ 51% subsidiary, the privatised Compagnie Ivoirienne d’electricite (CIE), has the monopoly on electricity supply and manages the government-owned generation facilities and transmission and distribution of electricity in the country.
xvii) From West to East, these are Sénégal, Mauritania, Mali, Burkina Faso, Cote d’Ivoire, Ghana, Togo, Benin, Niger and Nigeria.
xviii) The vast majority of Ghana’s generation capacity is hydroelectric (1072GW) with major facilities located at the Akosombo (912MW) and Kpong (160MW). In an effort to increase the capacity of existing generating infrastructure and meet the growing demand, the VRA is renovating the Akosombo dam turbines to increase the capacity of the plant by 15% within 5 years. The Ghanaian government is also considering additional hydroelectric IPP’s, such as the US$700M Bui hydroelectric project, which is planned to be contructed on the Black Volta river and operated by the Brown and Root, Alstom Hydro, Grupo Dragado and Hyundai consortium. Pre-feasibility studies have already been completed. The Bui project will make available to Ghana 400km of electric power and electricity generated from Bui could also be exported to Burkina-Faso, Mali and Cote d’Ivoire.
xix) The pipeline will transport gas from Nigeria’s Delta region initially to Benin, Togo and Ghana and might eventually be extended as far as Sénégal. Initially, it will only supply gas to power stations in Ghana. Prior to the World Bank’s support, the main reasons for the delay in completing the project were the difficulty in ensuring a common legal and fiscal regime, the perceived political risks and the lack of credit-worthy off-takers.
xx) WAPCo, requested the Bank’s involvement, indicating that it will not implement the project without appropriate mitigation of what they perceive as political risks linked to natural gas sales to state-owned power companies in Ghana, Benin and Togo.


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