CHAPTER 2 1 Independent Power Projects in Sub-Saharan Africa: Determinants of Success Anton Eberhard and Katharine Nawal Gratwick t the beginning of the 1990s, virtually all major had the potential to benchmark state-owned supply to power generation providers in Sub-Saharan gradually introduce competition (APEC Energy Working Africa were financed by public coffers, including Group 1997). cAoncessiona ry loans from development finance institutions In 1994 Côte d’Ivoire became one of the first African (DFIs). These publicly financed power generation assets countries to attract a foreign-led IPP to sell power to the were considered one of the core elements of state-owned, national grid under long-term contracts with the state util- vertically integrated power systems. A confluence of fac- ity. Ghana, Kenya, Nigeria, Senegal, Tanzania, and Uganda, tors, however, brought about a significant change in the among others, opened their doors to foreign and local ensuing years. investors in their power sectors shortly thereafter. With insufficient public funds for new power generation Although IPPs were considered part of larger power sec- and decades of poor performance by state-run utilities, tor reform programs in Sub-Saharan Africa, the reforms African countries began to adopt a new model for their were not far-reaching. In most cases, state utilities remained power systems, influenced by pioneering reformers in vertically integrated and maintained a dominant share of Chile, Norway, the United Kingdom, and the United the power generation market, while private investors were States.1 Urged on by multilateral and bilateral develop- allowed to operate only on the margin of the sector.2 Policy ment institutions, which were withdrawing funding from frameworks and regulatory regimes, necessary to maintain a state-owned projects, a number of countries adopted competitive environment, were limited. International com- plans to unbundle their power systems and introduce pri- petitive bids (ICBs) for IPPs were often not conducted vate participation and competition. Independent power because of tight time frames, resulting in limited competi- projects (IPPs)—privately financed, greenfield generation tion for the market and, because of the long-term PPAs, no supported by nonrecourse or limited-recourse loans and competition in the market. These long-term PPAs, along with long-term power purchase agreements (PPAs) with with government guarantees and security arrangements the state utility or another off-taker—thus became a pri- such as escrows and liquidity facilities, exposed countries to ority in overall power sector reform (World Bank 1993; significant exchange rate risks. Finally, while Africa has seen World Bank and USAID 1994). IPPs were considered a continued private participation in greenfield electricity proj- solution to persistent supply constraints, and they also ects, that progress has been erratic, with 2007 representing Anton Eberhard is a professor and Katharine Nawal Gratwick is a PhD graduate at the University of Cape Town Graduate School of Business. 371 the zenith, largely because of the financial close of one large largely state-run utilities, have been developed in Sub- project, Bujagali. Saharan Africa as of early 2010 (table 21.1). In total, about Several factors explain the recent trends in investment four gigawatts (GW) of IPP capacity has been added. With in Africa’s power sector. First, private sector firms were few exceptions,4 these IPPs represent a small fraction of deeply affected by the Asian and subsequent Latin Ameri- total power generation capacity and have mostly comple- can financial crises in the late 1990s and early 2000s. The mented incumbent state-owned utilities. Enron collapse and its aftershocks also influenced U.S.- Nevertheless, IPPs are an important source of new and European-based firms to reduce risk exposure in investment in the power sector in a number of African developing-country markets and to refocus on core activi- countries. In Togo, for example, Centrale Thermique de ties at home. The financial crisis of 2008 and 2009 has also Lomé, the country’s first IPP, will triple the country’s had a toll. Furthermore, DFIs began to reconsider their installed capacity. position of restricted infrastructure investment, a model The majority of IPP contracts in Sub-Saharan Africa that was predominant throughout the 1990s.3 As conces- have been upheld (namely, CIPREL and Azito in Côte sionary funding became available again, many countries d’Ivoire, Takoradi II in Ghana, Iberafrica, Tsavo, OrPower 4, opted for a hybrid solution—part public, part private. and Rabai in Kenya, Afam VI and Aba Integrated in Nigeria, Kenya represents one of the clearest examples of such a and Namanve in Uganda). Although the contracts of the hybrid, with KenGen, the state-owned generator, building two Senegalese projects, GTi Dakar and Kounoune I, remain alongside IPPs, with support from DFIs. largely intact, there are reports of changes in fuel supply Despite this revival of concessionary lending, power arrangements. A number of other IPPs, such as Bui Hydro sector investments have been insufficient in addressing in Ghana, Bujagali in Uganda, and Centrale Thermique de Sub-Saharan Africa’s power needs. Only 25 percent of the Lomé in Togo, have reached financial closure and are under population currently has access to electricity, and poor construction.5 Kenya is in the process of negotiating three supply is the rule, not the exception. The cost of meeting more IPPs after an international competitive tender. Africa’s power sector needs is estimated at $40.8 billion per For all of this progress, however, there have been sev- year, equivalent to 6.35 percent of Africa’s 2005 gross eral high-profile IPP mishaps in Sub-Saharan Africa. Two domestic product (GDP). Approximately two-thirds of the projects—AES Barge in Nigeria and Independent Power spending needed is for capital investment ($26.7 billion Tanzania Limited (IPTL) in Tanzania—are in arbitration. per year), and the remainder for operations and mainte- The costs of Songas, in Tanzania, meanwhile, have nance (O&M). Current spending on power infrastructure escalated as a result of the unplanned, and later disputed, totals approximately $11.6 billion per year. Approximately contracting of IPTL; Songas’s capacity charges were later 80 percent of existing spending is domestically sourced reduced after the government agreed to buy down the from taxes or user charges. The remainder is split among accumulated allowance for funds used during construction official development assistance (ODA) financing (6 percent costs. A dispute about escalating investment costs also of the total); other sources, mainly China (9 percent); and marked the Okpai project in Nigeria. In Kenya changes private sector investment (4 percent). Tackling existing util- may be made in the contracts of OrPower 4, which ity inefficiencies, including system losses, underpricing, reduced its tariff for the second phase of the plant. undercollection of revenue, and overstaffing, would make Another Kenyan project, Westmont, had an initial seven- an additional $8.24 billion available, but a funding gap of year contract that was not renewed. The other early IPP in about $21 billion would still remain (Eberhard and Kenya, IberAfrica, had its contract renewed but with Shkaratan 2010). much lower capacity charges. Closing Africa’s power infrastructure funding gap Following contract changes, IPPs have generally gone on inevitably requires undertaking reforms to reduce or elimi- to make a significant contribution to the countries’ power nate system inefficiencies. This will help existing resources generation—the main exceptions being Westmont, which go farther and create a more attractive investment climate ceased operation, and IPTL, which has operated intermit- for external and private finance, which still has growth tently during its arbitration proceedings. Another high- potential. With the original drivers for market reform still profile failure was the nontransparent procurement process present, future private sector involvement appears inevitable. surrrounding the Richmond/Dowans plant in Tanzania, Approximately 20 grid-connected IPPs, each in excess of which has not been allowed to operate since corruption 40 megawatts (MW) and with long-term PPAs with the charges were filed. Furthermore, there is evidence of stalling 372 CHAPTER 21: INDEPENDENT POWER PROJECTS IN SUB-SAHARAN AFRICA: DETERMINANTS OF SUCCESS Table 21.1 General Project Specifications of Sub-Saharan African IPP Projects Country/ Length of Commercial project Size (MW) Fuel/cycle Contract type contract (years) Project tender operating data East Africa Kenya Westmont 46 Kerosene/gas condensate/gas Turbine (barge-mounted) BOO 7 1996 1997 Iberafrica 109a HFO/medium-speed diesel engine BOO 7/15/25 1996,1999, 2008 1997, 2000, 2009 OrPower 4 48 Geothermal BOO 20 1996 2000, 2009 Tsavo 75 HFO/medium-speed diesel engine BOO 20 1995 2001 Rabai 90 HFO BOOT 20 2006 2009 Tanzania IPTL 100 HFO/medium-speed diesel engine BOO 20 1997 1998 Songas 180 Natgas/open cycle BOO 20 1994 2004 Uganda Namanve 50 HFO BOOT 6 — 2008 Bujagali 250 Hydro BOT 30 2005b — West Africa Côte d’Ivoire CIPREL 210 Natgas/open cycle BOOT 19 1993 1995 Azito 288c Natgas/open cycle BOOT 24 1996 2000 Ghana Takoradi II 220d Light crude/single cycle BOOT 25 1998 2000 Sunon Asogli 200 Combustion engine BOO 20 2007 — Bui Hydroe 400 Hydro BOO — 2005 — Nigeria AES Barge 270 Natgas/open cycle (barge-mounted) BOO 20 (2 parts) 1999 2001 Okpai 450 Natgas/combined cycle BOO 20 2001 2005 Afam VI 630 Natgas/combined cycle BOO 20 2000 2007 Aba Integratedf 140 Natgas/open-cycle BOO 20/15 2005 — Senegal GTi Dakar 52 Diesel/Nafta BOOT 15 1996 1999 Kounoune I 68 HFO BOO 15 2003 2008 Togo Centrale Thermique de Lomé 100 Triple fuel (natgas/HFO/diesel) BOOT 25 — 2010 Source: Authors. Note: Projects included here are greater than 40 MW; have reached financial close; and are under construction, operational, or concluded. BOO = build-own-operate contract; BOOT = build-own- operate-transfer contract; HFO = Heavy fuel oil.