Geothermal projects in East Africa – full steam ahead?

This article was co-authored by Richard Metcalf, partner at Norton Rose Fulbright and Paul Zakkour, Director at Carbon Counts Ltd. It was originally published in the July 2016 issue of Project Finance International.

In one part of the renewable energy industry we appear to be standing at the dawn of a new era. Over the last 10 years, the solar PV industry has defied the sceptics and has gone from being a cottage industry to a major disrupter to all traditional energy sources. Large scale solar PV is now competitive in many different scenarios and markets. The latest pricing signals from the Dubai 800MW tender are stunning - US$0.0299c/kwh was the lowest bid. It was only two years ago when a bid under US$0.10c/kwh was seen as unsustainably low and the market believed there must be hidden subsidies for the equity or debt. At these levels solar PV isn’t just competitive against the very best wind projects but, in many markets, it can now compete against existing coal-fired generation and that is without imposing carbon taxes or caps on emission levels.

In this article we look at another part of the renewable energy industry – geothermal. Over that same 10 year period even the most vociferous advocate of geothermal would be hard pressed to describe the progress in commercialisation of geothermal in the same terms. We look at what is going on in the region and consider some of the factors affecting the pace of development of geothermal projects.

African geothermal hit the headlines in July 2015, when during President Obama's visit to Ethiopia Ethiopian Electric Power and Corbetti Geothermal signed Ethiopia’s first independent power purchase agreement for up to 500 MW of geothermal power from the Corbetti geothermal source. Ethiopian Electric Power was also declared to be negotiating an agreement with Reykjavik Geothermal to develop an additional 500 MW in the Tulu Moye and Abaya areas. But little information has emerged since then about how these projects will be implemented. So, for a view of how geothermal resources might and can be exploited we turn to another country – Kenya.

Kenya was the first African country to establish the utilisation of geothermal power 35 years ago and is the eighth largest geothermal electricity producer in the world. During the financial year 2014/15, KenGen completed the commissioning of geothermal power plants at Olkaria IV and Olkaria I (units 4 and 5), with a total installed capacity of 280MW. KenGen’s investment programme to deliver 720MW by 2020 largely consists of the construction of geothermal power plants. The programme includes the construction of three new geothermal power plants, with a capacity of 140MW each and Olkaria I Unit 6 with a capacity of 70MW.

This snapshot, taken in tight focus, would seem to give a picture of a technology whose time has come and is in the full swing of commercialisation. But this is not the full picture of where geothermal presently stands.

Experiences with geothermal development worldwide show that developing a geothermal industry can be slow. Progress can be hampered by lack of public funding and a reluctance by the private sector to bear exploration risks. Obstacles to overcoming these challenges include institutional, regulatory and legal constraints, a lack of technical and human capacity, as well as economic and financial barriers. Investors need to be sufficiently sure of future baseload demand, particularly given the potential supply of competing sources e.g. other renewables, new hydropower and potentially gas.

The drivers for development of geothermal energy tend to differ around the world. What is common in most countries, however, is that the public sector has been the primary developer for at least the first-of-a-kind geothermal power plant in the country. Most privately-held geothermal power plants today were originally built by public utilities and then privatised. Motivations for public expenditure on geothermal development historically include over-reliance on uncertain or increasingly scarce hydropower resources. This was the case for Kenya.

Despite early progress made in the 1970s and early 1980s, developments in Kenya were slow through the latter part of the 1980s and the1990s. More recently, however, attitudes towards geothermal energy have changed. Concerns over climate change, the volatility of commodity prices, the need to address energy security and the desire to support economic development through improved provision of clean, reliable and affordable base-load electricity means that geothermal resource development is high on the political agenda for many countries where potential exists. Interest is emerging across East Africa, facilitated by a wide range of donor initiatives, In addition to the uptick in activity in Kenya nascent geothermal programmes are developing in, amongst others, Rwanda, Ethiopia (as outlined above), Burundi, Tanzania and Uganda.

Typical costs for geothermal power plant development are cited in the range of US$3-5 million per MW installed. This would mean a capital cost for a 30MW geothermal plant in the region of US$90-150 million. There is also a variability in cost between different technologies, with binary plant generally being more expensive than flash plant.

Publicly available information shows that there is also fairly wide variation in the estimated levelised cost of electricity (LCOE) generated from geothermal, ranging from US¢5/kWh to US¢15/kWh generated. The range in the LCOE reflects a number of variables including assumptions around capital costs, O&M costs, plant capacity factor and weighted average cost of capital (and discount rate i.e. financing costs). In general, however, the range of LCOEs suggest that geothermal power can be competitive with different power generation sources at the lower end of the range. At the upper end, geothermal energy starts to look quite expensive compared to sources such as hydropower or thermal (combined cycle natural gas) plant, and would face challenges to be dispatched to the power grid without an off- take obligation such as might be gained through a REFiT.

The challenge for geothermal energy development, therefore, is keeping costs down to remain competitive in the power mix. Since operating and maintenance costs are low given that the fuel is, putting aside reservoir management and well work-over costs, essentially free, then the greatest effort must be on managing upfront development costs. However, this is the most expensive and challenging part.

The main factors affecting project development costs are resource identification and development costs, risk and financing costs, and higher costs for those projects which have first-of-a-kind elements. Therefore, although geothermal energy can offer a cost competitive source of base-load power generation, its development is not without significant challenges that affect the costs of development.

The risk of geothermal development failure is fairly high. Test drilling is needed to confirm the presence of a viable resource or otherwise, and if no viable resources is found, millions of dollars will be lost. In the case of private sector led development, the costs and risks involved in steamfield identification and development are a major deterrent to investment. As such, it relies on an IPP company or individual investor with a high risk appetite taking on an equity investment since commercial banks are unlikely to provide loans for such high risk prospects. This means the cost of capital will be high, severely affecting overall project economics. This generally leads geothermal development down a public or PPP financing pathway, especially for first-of-its-kind and greenfield projects.

For example, the Kenyan parastatal Geothermal Development Corporation (GDC) has estimated that the break-even tariff required (i.e. the LCOE) for a geothermal power plant developed in full by a private sector developer requiring a return on equity of 25% would be in the range US¢14-17/kWh, whereas for public-sector led development of the early phases ( survey, exploration, test drillings), supported by concessional loans, and an IPP entering at the project planning stage with a return of equity of 25% the required break-even tariff (LCOE) may be reduced to a range of US¢6.5-10.5/kWh. This suggests that only public-, or public-private partnership (PPP)-, led approaches for greenfield projects achieve geothermal energy deployment at LCOEs typical of operational plant around the world. Under such approaches, the risks can be reduced and debt financing may be possible, which would lower the cost of capital to e.g. 10%, further reducing the LCOE for a power plant. Hence, to get projects off the ground in East Africa, significant amount of grant and concessional finance will be necessary. Fortunately, significant efforts are being made on this front, including bilaterally through various UK, New Zealand, US, French, German, Icelandic and Japanese led initiatives, as well as multilateral channels

Kenya provides a strong example of projects that are being developed with a heavy reliance on such multilateral and donor funding to overcome these risks. It is instructive to look at the way that the Menengai steamfield in Kenya has been developed.

The Menengai geothermal project is in advanced stages of development of the eponymous steamfield to ultimately produce enough steam for up to 1600 MW of power. The power from the initial phase of the project will enable electricity generation equivalent to the consumption needs of up to around 185,000 households. Approximately 26,000 of these homes are based in rural areas and 110,000 are small businesses. Additionally, 1,000 GWh will be newly available for businesses and industries. The project is currently expected to become operational in December 2016.

 For the first phase of Menengai steamfield development, GDC, through the Government of Kenya, raised US$746 million to develop the subsurface infrastructure (wells), steam gathering system and grid interconnection for development of at least 200-400MW of new steam field capacity in the area. Sources of finance included the following:

1. African Development Bank (AfDB) - US$120 M (loan)
2. World Bank Scale-up Renewable Energy Program(SREP) - US$ 40 M (loan & grant)
3. World Bank - US$100 M (loan)
4. Agence Française de Développement(AFD) - US$166 M (loan)
5. European Investment Bank - US$ 36 M (loan)
6. GDC/GOK - US$284 M (equity)

 The finance package did not cover power plant development, which is anticipated to emerge from IPPs in response to the establishment of a viable steam field development. In preparing the financing package, GDC issued a call for expression of interest to develop power generation assets, to which around 20 positive responses were received. The selected projects were Sosian Energy (35MW), Quantum Power (35 MW) and OrPower’s (35 MW binary plant).

According to the AfDB project appraisal report, a key part of securing the Menengai loans was the role of KenGen in acting as “steam buyer of last resort”, essentially back-stopping the project with a Government guarantee. However, in 2014 it was necessary for the AfDB to approve a further $12.7 million partial risk guarantee to assist financing for the 105 MW of new IPP development, and further delays have been reported due to lack of Treasury letters of support and Kenya Forest Service approvals for projects. As a result, IPP plants at Menengai are not expected to come on stream until 2017 at the earliest, despite the establishment of a 110 MW of viable steam supply by GDC.

There are variations within public sector-led approaches. In some cases a single entity takes the sole lead on the full project development. This model, whilst common in earlier phases in the history of geothermal development has generally been succeeded by a multi-public entity arrangements, with one parastatal company (such as GDC) being responsible for steamfield exploration and development, and another for the power plant construction. In Kenya we are seeing a further evolution of this approach with the private sector entering the power development phase through the IPP model, while the public sector retains the steamfield development risk.

In March 2016 the launch was announced of the Power Africa KenGen Cooperation Framework. Under this initiative technical expertise will be made available to KenGen with a view to increasing generation capacity via new project and financing structures. One of the stated objectives is to attract private investments into geothermal projects. We watch with interest to see how far and how quickly Kenya and the geothermal sector are able to travel along the road towards the sort of private funding now available to solar PV projects.