Power is one of the biggest hurdles to stronger growth in the sub-Saharan African region. A number of factors – from dumsor in Ghana and high tariffs in Kenya to a lack of grid access in Gabon – mean that both households and industrial firms are often subject to inconsistent and unreliable electricity supply.
While a number of solutions are being rolled out to address this, from off-grid networks to improved metering systems to new transmission infrastructure, one of the most fundamental and necessary solutions is new generation supply. However, Africa needs far more power than its governments can afford to build: it is estimated that sub-Saharan Africa requires $490bn in new projects to meet a projected four-fold surge in demand. As a result, there has been a major push across the continent to incentivise private sector participation in the power sector.
Although countries are taking a variety of approaches – including privatisation in Nigeria and unbundling in Kenya – to tackling this problem, one of the most common is through IPPs. To be sure, building a power plant and selling it to a state-run distributor presents risks – a 300-MW IPP wind farm in Kenya is now delayed, for example, and payment and contract disputes have also marred the experience of IPP investors in Tanzania and Nigeria – but governments are having some success in mitigating the risks with a range of tools. This situation is pertinent in Côte d’Ivoire, where more than half of its 1600-MW total capacity was provided by IPPs in 2015.
Significant diversity exists in project structuring across Africa’s IPP landscape. Early investors received risk protection in the form of generous power purchase agreements (PPAs), government guarantees and escrow accounts that could be tapped in case of problems with receivables. It is no longer as easy to receive those sorts of assurances now, but as the market evolves, similar tools are available from an increasing number of multilateral and bilateral actors.
IPPs are hardly new to the region. The first was the Ciprel power plant, built in 1994 in Cote d’Ivoire, and it was followed by others in Kenya, Mauritius, Senegal, Tanzania and Ghana by the end of the decade. Currently, South Africa has the largest number of IPPs, with 67 plants providing a total of 11.01 GW of generation capacity. Almost half of that has come in the last four years, through the Renewable Energy Independent Power Producer Procurement Programme, in which investors participate in bidding rounds for new IPPs, the majority of which are under 100 MW. In all other sub-Saharan countries combined there are now a total of 59 IPPs either operational or fully financed and under construction. They are spread across 17 jurisdictions and with a total capacity of 6.8 GW. The list counts power projects that have been developed, financed, built, owned and operated mostly by private interests, and hold a long-term PPA with a major utility or other off-taker.
Beyond South Africa, penetration across the rest of the continent has been focused rather than broad, with roughly a third of countries hosting an IPP. By 2014 Kenya and Uganda had the largest number of ongoing IPP projects, at 11 each; Mauritius had six, Senegal five, and three countries each had four: Nigeria, Ghana and Tanzania, with Côte d’Ivoire likely to join them when a fourth IPP, powered by biomass, begins operations in 2018. Measured by total investment value, Kenya was again the market leader, with roughly $2.3bn in capital absorbed.
Nigeria and Ghana followed, at about $1.7bn each. In terms of generation capacity, however, Nigeria had the most, at 1500 MW, followed by Kenya, Côte d’Ivoire and Ghana, each with about 1000 MW. No other country had surpassed 500 MW.
Some of the largest IPPs on the continent have been in West Africa, such as the 459-MW Azura-Edo IPP in Nigeria, which reached its financial close at the end of 2015, the 543-MW Ciprel IPP in Côte d’Ivoire, and the 430-MW Azito IPP, also in Côte d’Ivoire. IPPs of this size have been a rarity, with just three over 300 MW as of 2014. About half the market at that point was comprised of IPPs under 20 MW of capacity and those between 51 MW and 100 MW. IPPs both extant and planned have not limited themselves to any one energy source, with wind, hydro, bagasse (residual material from the processing of sugar cane), coal, geothermal, methane and biomass included on the roster of energy sources. However, the majority of projects are designed to run on gas or have combined-cycle technologies that can also use heavy fuel oil or diesel.
The market is still in an early phase, however, and as new projects close they are likely to significantly alter the distribution of IPPs across the market, while introducing new trends and market leaders. Uganda, for example, could soon see 10 new IPPs reach financial close, and would at that point account for more than a quarter of total IPO projects. The market is also likely to broaden to other countries as well, with one significant newcomer being Ethiopia, where the first IPP in the country will be a 1000-MW geothermal plant.
One reason why the IPP landscape is expected to change in the coming years is the level of flux being experienced in many utility sectors. A number of governments – from Ghana to Kenya to South Africa – are currently in the process of unbundling, privatising and deregulating legacy structures that were previously composed of a single, vertically-integrated state entity responsible for generation, transmission, distribution and – in some cases – regulation.
The rise of IPPs is crucial in part because of the challenges existing legacy power companies face in amassing capital and financing new projects. Many of the state-owned companies – particularly those who are also involved in distribution and transmission – have long struggled to keep up with funding demands, which is one of the factors driving the trend of unbundling activities, privatising state assets and seeking outside investment.
This is in part a result of underinvestment during the continent’s downturn in the 1980s and 1990s, when utility infrastructure was poorly maintained, leading to a degradation in efficiency and output. The balance sheets of national power companies have also been weighed down by poor collections and outstanding payments – in some cases by other state agencies, as in Ghana, where government accounts represent 60% of distribution company ECG’s outstanding payments – dramatically limiting cash flow.
As a result, capital spending by state-owned bodies as a percentage of total power sector investment has been comparatively low. From 1990 to 2013, except in South Africa, sub-Saharan governments and their utilities accounted for just 51% of total investment in generation, and 43.7% of added capacity. IPPs accounted for 22% of investment and 23.9% of capacity, with foreign governments and their investment vehicles accounting for the rest. Official development assistance, development-finance institutions and Arab countries provided 11.2% of investment and 15.9% of capacity. China, at 15.9% and 16.4%, respectively, therefore stands out as the dominant non-African source of investment.
As for the investors themselves, what has emerged thus far is a mix of actors joining together to make projects happen. IPPs can be led by single companies, who then cobble together minority partners and a financing package, or they can be developed by consortiums with a larger set of principals.
South Africa’s Harith General Partners has been an active participant in the market, for example, in some projects teaming up with UK-based Aldwych International as the lead contractor. Kenya’s Centum Investment, Denmark’s Investment Fund for Developing Countries, Dutch firm KP&P, and US-based Black Rhino Group are among some of the other backers currently involved in IPPs on the continent.
Development finance institutions such as the World Bank, the International Finance Corporation and the African Development Bank (AfDB) have also stepped in to offer partial risk guarantees (PRGs) and financing for IPPs.
A PRG is typically a guarantee to cover a limited amount of an investor’s losses from multiple risks. For an IPP, typically the main one is a power off-taker that does not pay for what they take. This is often structured as a letter of credit or another instrument available from a commercial bank, but routed through the World Bank and with the government as the ultimate provider of the guarantee. If an investor were to call on a PRG, it would collect from the World Bank, via that letter of credit. The World Bank would then have recourse to call on its entire financial relationship with the country if need be in order to recover the funds. However, a PRG has never been called on, with the World Bank always being able to negotiate settlements before the issue proceeded to that ultimate step. These instruments are seen as a good fit with the power sector. When PRGs are taken along with some other types of guarantees the World Bank offers, they account for almost half of the total offered as of 2012, and more than double the amount extended to any other economic sector.
Other multilateral initiatives seek to strengthen financing access elsewhere in the project life cycle. The AfDB, for example, has established a $100m fund for renewables projects, called the Facility for Energy Inclusion. It will provide senior and mezzanine debt to IPPs whose projects cost $30m or less. It also plans to seek funding from others in order to boost available capital to $500m, it said in December 2016.
IPPs on the continent are also supported by a number of bilateral initiatives, including with China, which offers concessional loans from state-owned enterprises such as the China Development Bank or the Export-Import Bank of China. Financing also comes from commercial or quasi-state entities such as the Industrial and Commerce Bank of China and the China Construction Bank. Typically a Chinese firm is selected for engineering, procurement and construction in a bidding process.
A look at project details indicates that China may be largely chasing a different market from commercial investors, and that IPPs are generally not in direct competition with Chinese power projects. From 2001 to 2014, for example, Chinese entities funded six projects with a capacity of 400 MW or more, compared with just one of that size in the IPP market. Four of these were hydropower projects and one a coal-fired power plant. IPP projects are different, being smaller and far more likely to use natural gas.
The US government’s Power Africa programme has also helped play a role in supporting inbound investment, by strengthening government support for US investors in regional power-sector projects, including but not limited to IPPs. The initiative offers investors a range of risk-mitigation tools and financing to overcome last-mile obstacles.
Nigeria’s Azura benefits from a PRG as well as multiple Power Africa benefits, for example, while in Ghana, the US’s Millennium Challenge Corporation is providing up to $498.2m in support to the Electricity Company of Ghana, the state power distributor. This money will be used to help clear up old arrears, train employees, and modernise the company’s operations. It may also include a management contract that would hand over day-to-day operations to an outside expert .
The Power Africa programme follows a model of multilateral and bilateral investment to catalyse private investment in Africa’s power sector. Since 1994 the steady increase in private investment in IPPs – save for a temporary dip after the 2007-08 financial crisis – has largely been a reflection of the involvement of governments and international organisations. Typically a small rise in investment from the latter has had the effect of producing a larger boost in the former.
A number of national governments in the region have sought to roll out similar mechanisms to limit the burden on private sector investors for financing and provide cover for risk in offtake agreements. Nigeria and the investment vehicle for its Azura-Edo IPP, Amaya Capital Partners, negotiated a put/call option on the project – one of the first on a large-scale IPP in Africa – that may provide a model for other projects.
The option frees Azura’s owners from a contractual obligation to sell power to the Nigerian off-taker, Nigerian Bulk Electricity Trading, in the event of gas-supply interruptions to the plant, or if its owners are not paid for the power it produces. The put/ call option also gives the owners the right to sell the plant to the government in such cases.
Instruments like PRGs and put/call options are often embedded in PPAs, while denominating the agreements in dollars or euro is one popular method of limiting currency risk. In some African markets, however, PPAs are getting a second look, particularly in markets where generation capacity is no longer a pressing need. In Kenya, for example, a government committee is reviewing terms and is expected to suggest recommendations about potential adjustments.
One of the biggest challenges facing IPPs in Africa – as in elsewhere in the world – are tariffs. With many sub-Saharan African economies grappling with large low-income and impoverished populations, ensuring affordable access to electricity is key. At the same time, IPP investors also want to ensure tariffs allow for more than just cost recovery. High tariffs may also discourage a different set of prospective investors; manufacturers, who prize access to cheap power.
Finding the balance between the competing interests can be tricky. In Tanzania, senior power sector executives were sacked or demoted in January 2017 after setting tariffs that were deemed too high by politicians, despite having been approved by an independent regulatory agency.
Protests in Côte d’Ivoire over higher-than-expected tariff increases in January 2016 prompted President Alassane Dramane Ouattara to request that utility companies reimburse payments in excess of the previously agreed-on tariff increases.
Even those with PPAs are likely to have exposure to tariff issues, as tariffs have often been set too low for transmission and distribution companies to recover their costs and invest in their assets.
This makes them potentially less able to pay for the power they take, and has given rise to the PRGs, put/ call options and other instruments that have helped investors and their lenders to overcome objections to proposals. Governments have been aiming to reduce their exposure through subsidies, but must ultimately balance competing priorities – offering to pay IPPs enough to incentivise greater investment, but without lifting price points beyond the reach of the market.
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