STRATEGIES FOR ACCELERATING GEOTHERMAL ENERGY DEVELOPMENT TO SPUR KENYA S ECONOMIC GROWTH

Transcription

1 STRATEGIES FOR ACCELERATING GEOTHERMAL ENERGY DEVELOPMENT TO SPUR KENYA S ECONOMIC GROWTH James K. Wahogo Corporate Planning and Strategy Division, Kenya Electricity Generating Company, Ltd. P. O. Box Nairobi, Kenya: jwahogo@kengen.co.ke ABSTRACT The Government is preparing an economic recovery program, which envisages an overall Gross Domestic Product (GDP) growth rate of 6-7 percent per annum. Among the key components of the growth strategy, is the provision of reliable and least-cost electric power. This paper examines some of the key strategies necessary to accelerate geothermal energy development in order to spur economic growth in line with the government s strategic objectives. Key Words: 1. INTRODUCTION The relationship between energy consumption and economic growth is well established in the world over. It is a paradox that Kenya, which is endowed with huge reserves of geothermal energy, has only about 15% of its population with access to electricity. Development of geothermal energy is therefore key to Kenya s economic development. Over the past several years, stakeholders have consistently pointed that, the inadequacy; unreliability and high cost of power are the most critical constraints to Kenya s competitiveness as an investment destination within the region. Following the peaceful general elections of December 2002 and the subsequent transition, the economy is expected to pick up and record higher GDP growth rates than earlier projected in the April 2001 load forecast in the Least Cost Power Development Plan (LCPDP). Supporting this positive GDP growth is the reduced transaction costs of doing business following the renewed effort and commitment by the Government to enhance the fight against corruption and the implementation of key reforms in various sectors of the economy and more so the improvement of the relationship between the government and development partners. The current expected GDP growths are as shown in Table 1.1 below. Table 1.1: Projected GDP Growth for Kenya Year Low Reference High Forecast Forecast Forecast to In addition, the economy is expected to benefit from increased trade within Common Market for Eastern and Southern Africa (COMESA) and the East African Community, particularly in manufactured products. Further, under the American Growth and Opportunities Act (AGOA), Kenya is likely to export more products to the US market, including textile, handicraft, fresh fruits and flowers, leather and leather products. The good performance of the economy will lead to customer growth especially in the commercial/industrial customer category. The increased industrial growth will directly contribute to increased electricity sales. At the moment, all the macroeconomic indicators such as exchange rate, inflation and interest rates have continued to remain stable. In view of this expected economic growth, the Kenya Power & Lighting Company (KPLC) has revised the electricity load forecast for the next twenty years. The forecast, for low, reference and high scenarios is as shown in Table 1.2 below. 2. REVIEW OF PAST GEOTHERMAL DEVELOPMENT STRATEGIES The tremendous potential of the geothermal energy resource has for a long time been identified as a least cost form of energy available in Kenya. The Kenya National Power Development Plan ( ) and the consequent updates have consistently recommended additions of geothermal plants in the power system expansion as outlined in Table 2.0 below. The strategy has been to develop about 500 MW within a 20-year period in steps of 55/64 MW every two/three years. The basic characteristics of the geothermal planning strategy have not changed since the 1986 master plan except for the following highlights: Change of configuration from single 55 MW unit size to 2 x 32 MW units Change of configuration from 2 x 32 MW units to single 1 x 70 MW. As is the case with other power plants, economies of scale dictate that larger sized units offer lower costs per unit as compared to smaller units. In the 1980 s the turbine sizes were technologically limited to a maximum of about 55 MW because of the relatively low pressure and the effect of wet exhaust steam conditions. 162

2 In the case of Olkaria II project, the main reason for choosing the 2 x 32 MW smaller sized units was that, they were supposed to be modular, requiring minimum field assembly and shorter construction period. These features were to enable the project to be developed on a fast track basis owing to the power shortages being experienced in the country at that time. During the 1991 plan formulation, it was envisaged that these units would be commissioned in However, due to delays as a result of various factors, mainly funding, the plant will be commissioned later this year. Table 1.2: Integrated System Sales Forecast Summary Low Forecast Reference High Forecast Forecast Fiscal Annual Annual Annual Year Sales Growth Sales Growth Sales Growth GWhr (%) GWhr (%) GWhr (%) 2002/03 3,871 3,904 3, /04 3, % 4, % 4, % 2004/05 4, % 4, % 4, % 2005/06 4, % 4, % 4, % 2006/07 4, % 4, % 5, % 2007/08 4, % 5, % 5, % 2008/09 4, % 5, % 6, % 2009/10 5, % 6, % 6, % 2010/11 5, % 6, % 7, % 2011/12 5, % 7, % 7, % 2012/13 5, % 7, % 8, % 2013/14 6, % 8, % 8, % 2014/15 6, % 8, % 9, % 2015/16 6, % 9, % 10, % 2016/17 6, % 9, % 11, % 2017/18 7, % 10, % 11, % 2018/19 7, % 11, % 12, % 2019/20 7, % 11, % 13, % 2020/21 8, % 12, % 14, % 2021/22 8, % 13, % 16, % 2022/23 8, % 14, % 17, % 2023/24 9, % 15, % 18, % 2024/25 9, % 16, % 19, % Table 2.0: Generation Additions of Geothermal Plants LCPDP Period Geothermal Additions Unit Size Cost Us/kW MW x 32 = 64 MW * 2,015 1 x 55 MW 1, x 32 = 64 MW * 2,015 1 x 55 MW 1, x 32 =64 MW 2, x 32 =64 MW 2, x 32 =64 MW 2, x 32 = 64 MW * 2 x 18 = 36 # 1 x 70 MW 2,100 *First two units of Olkaria II Project # Olkaria III additional capacity, already generating 12 MW Similarly according to the 1997 LCPDP plan, Olkaria III was to be commissioned in mid This project being developed by an Independent Power Producer (IPPs) has also experienced similar delays. Despite the various geothermal strategies developed over the years, the implementation has been poor due to a number of factors, mainly lack of funding for exploration and power plant construction. 3. CURRENT GEOTHERMAL DEVELOPMENT STRATEGY Currently, single units of 70MW, which have savings due to considerable economies of scale, have been adopted for planning purposes. Over the years technological improvements have made it possible for the construction of larger sized units. The current choice of 70 MW is appropriate with respect to the national power system network and resource development capability. The unit size is nominal, indicative for planning purposes, but may need to be matched to the available resources and characteristics for specific site. Therefore future units may be of various capacities as determined during exploration and appraisal. Future geothermal plants after Olkaria IV will be located away from the Olkaria area. This has cost implications on resources especially the transmission lines. A comparison has been done relating to the future proposed development sites with the cost of proposed transmission line facilities. The preferred locations and possible commissioning dates are as shown in Table 3.0 below. In order to meet this programme, drilling should begin in Table 3.0: Power Plant Possible Commissioning Dates Commissioning Proposed Date Location 1. Olkaria IV 2008 Olkaria Domes 2. Plant V Plant VI Plant VII Plant VIII Plant IX Plant X

3 3.1 Resource Development and Construction Project implementation will be executed through Engineer- Procure-and-Construct (EPC) contract as opposed to the multicontracting method in use currently due to its associated advantages that include: (i) Allows more room for vendor innovation (ii) Reduces cost overrun risks (iii) Are generally faster to execute (iv) Most importantly, gives single point responsibility and liability for plant performance Drilling costs constitute about 30% of the total cost of plant development. These costs can only be reduced if the drilling success rate is high. This could be achieved through use of techniques that are accurate and reduce the chances of failure. A combination of vertical and directional drilling enhances the success rates. KenGen is to acquire a new drilling rig in order to enhance the mix of vertical and directional wells. In the previous least cost update, the transmission lines were assumed to be 4 kilometers long from every new geothermal plant to Olkaria II 132/220 kv sub-station, their interconnection point to the grid. It is expected that Olkaria IV, Longonot and Suswa prospects will be connected to the Olkaria II - Nairobi 220 kv transmission line. In the future, many power plants will be away from the Olkaria II site and as such, a 220 kv line linking the power plants to the north of Olkaria to the proposed Olkaria II - Lessos 220kV line will be required. A double circuit line spanning one prospect to the other is considered to carry the power added at every prospect. These include Menengai and north rift prospects. The estimated cost of a double circuit 220kV transmission line is US$ 120,000 per kilometre. Substation costs estimated at US$ 450,000 per bay have been used. Each power station will require a total of 2 bays (one bay at the sending power station and one bay at the receiving sub-station) at a cost of US$ 900,000 (Table 3.1). 3.2 Project Operation An estimate of the operations and maintenance (O & M) costs for a future 70MW power plant are derived from the Olkaria I data. Adjustments are made to correspond to the proposed plant. An additional 5% of the total O & M Costs was provided for steam field of future power plants and to suffice the need to maintain the re-injection system and monitoring of entire reservoir. The anticipated forced outage rate and scheduled maintenance outage rate together result in an average annual plant availability of 95.7%. For each new 70MW power plant, the steam available at the beginning of operations will be just above 70MW. Thus additional steam will need to be drilled for the 25 years of plant life at a rate of about one well every 4 years. Replacement wells will be drilled and connected as required, and for planning purposes costs will be charged to the project in year two and every four years thereafter. This represents an average annual cost of about US$ 510,000 per year. Assuming an average availability of 95.7%, the replacement wells cost is $/kwh. The geothermal O&M cost data is summarized in Table Comparison of Thermal and Geothermal Plants In order to identify the most appropriate candidate plants within the national power development plan, screening was carried out on thermal and geothermal plants. Pre-screening was first done on the different types of thermal plants in order to obtain the most economic configuration. The most economic thermal plant configurations were then screened alongside geothermal power plants to obtain the final screening results shown in Figure 1. below. The results show that Gas Turbines are least cost for load factors below 25%. Medium Speed Diesel plants are least cost for load factors between 25% and 55% while geothermal plants are least cost when operated above 55%. The price per kwh at a plant utilization of 100% is about 4.8 US cents. Their unit prices are shown in Figure 2 below. Table 3.1: Description Future Geothermal Plants Capital Costs Olkaria IV Plant V Plant VI Plant VII Plant VIII Plant IX Plant X Total (US$) 1 Date of Commissioning Resource Investigation Site Dev.(land, roads, water, etc) Exploration Drilling Appraisal Drilling Production Drilling Well Testing Studies, Reviews & Training Power Plant Construction Steam Field Dev Engineering Services Transmission Line Substation Total Cost (Mln US$) ,

4 Table 3.2: Summary of Geothermal O&M Cost Data Name Configuration Economic life (yrs) Insurance % of Capital Cost Interim replacement % of Capital Cost Scheduled Maintenance (wks/yr) Forced Outage Rate % Unit Plant Fixed ($/kw.yr) O & M Costs Variable ($/kwh) Olkaria I 3 x Olkaria II 2 x Future Geothermal 1 x ,300 1,200 1,100 1, U n it C o s ts ( G a s T u rb in e Combined Cycle G eotherm al 2 x 32 Plants LSD Steam M S D Coal G eotherm al 1 x 70 Plants % 20% 40% 60% 80% 100% P la n t U tiliza tio n (% ) Coal 2 x 100 Steam 2 x 100 LSD 8 x 50 CC 3 x 60 G.T. 2 x 60 G eot 2 x 32 M SD 4 x 20 O lk a ria IV G eo Longonot G e o S u sw a G eo M enengai G e o O l B a n ita G e o A ru s G eo B ogoria Figure 1: Thermal and Geothermal screening results 165

5 US$/kWh MSD 4 x 20 O lkaria IV 1 x 70 G.T. 2 x % 20% 30% 40% 50% 60% 70% 80% 90% 100% Plant Factor (%) Figure 2: Thermal and Geothermal Unit prices 4. PRIVATE SECTOR PARTICIPATION 4.1 International Outlook The last decade saw a wave of liberalization and privatization of infrastructure activities in developing countries. For the period the private sector had undertaken the operating or construction risk (or both) of 1,700 infrastructure projects in developing countries worth US$500 billion. There was a sharp increase in investments from the period Private sector energy investments (mostly in electricity), rose from less than US$2 billion in 1990 to about US$46 billion in However there was a sharp drop in the late nineties due to the financial crises in developing countries - mostly in East Asia and Latin America. The financial crises also made international financial markets reluctant to invest in developing economies. Since 1997, there has been a big decline of longterm private capital flows to developing countries. In the shortterm international financial markets conservative approach has made financing scarce and expensive. According to preliminary World Bank estimate from International Capital Markets long-term funds dropped from a peak of US$151 billion to US$40 billion. In the long-term as funds start flowing again, project developers will become more cautious, focusing on project quality, and taking a more realistic view of long-term project risks, including macroeconomic, political and regulatory risk Problems with Independent Power Producers (IPPs) Recently governments have been running into difficulties with IPPs where they have been subject of protracted legal, political and economic battles. In some countries utilities have been crippled by payments due to IPPs. Contrary to popular belief, using private sector for power generation does not increase the funds available for social services, such as education and healthcare, rather an IPP will absorb large amounts of governments funds through the high prices and sometimes restrictive terms of the Power Purchase Agreements (PPA). 4.2 Kenya s Experience with IPPs In the mid 90 s, the Kenya Government introduced competition in the generation segment of the electricity supply market, so as to improve efficiency and expand the scope of resources mobilization by encouraging private sector participation. IPPs commenced generation in Kenya in 1997, with the first two having short lead-times due to use of balance sheet financing. The subsequent two IPPs had long lead-times of 4 to 5 years due to protracted PPA negotiations. International interest for Kenya s IPP projects has been much lower than expected. So far all IPPs have been on Build Own Operate (BOO) basis. The low competition for IPP investment in Kenya is attributed to high-perceived country risk, high-perceived resource risk for geothermal projects and relatively small sizes of the projects. Furthermore, IPPs using external project financing have demanded onerous payment security packages. Thus PPA negotiations have been very lengthy and IPP bulk supply tariffs high in comparison to other countries. Country risk has been somehow exaggerated since all existing PPAs have been honored without failure. The risk should be lessened much further in view of the new government commitment to fight corruption. 4.3 Impact of Reforms on Geothermal Development Private participation in Kenya has opened up debate on the issue of who should be responsible for exploration and appraisal of the geothermal resource. Thus the question is should KenGen act as the government agency responsible for exploration and appraisal and consequently be allowed to bid for the construction of the power plant alongside IPPs? Some people have argued that KenGen would have an unfair advantage if it would be allowed to do so. But such an argument becomes inconsistent with government s policy objective if exclusion of KenGen reduces competition and consequently results into higher bulk electricity prices from any plant under consideration. As long as all available data/information is availed to all bidders, there is no conflict of interest for KenGen to bid alongside other IPPs for the construction of a particular plant after it has been 166

6 involved in resource exploration/appraisal for the same plant, because: (i) The government s main objective is to obtain a bidder who offers the lowest bulk electricity price (ii) KenGen s participation in the bidding creates more competition and discourages overpricing by IPPs Other important issues brought about by the reforms, include, the retention of expertise and knowledge both within the public and private sectors, and regulation of resource allocation and use. Government policy should encourage public and private sector partnerships that create synergy in the development of the resource. ] 5. CONCLUSIONS Geothermal resource remains the least cost option for supply of base load electricity generation in Kenya. With large unit sizes i.e. 70 MW Geothermal has lower unit price in comparison with other thermal plants for plant utilisation factors above 55 %. Cost reductions in development could be reduced by improvement of exploration and appraisal techniques, which increase the drilling success rates. KenGen is the only organisation in the country that has the requisite skills for resource exploration Private sector participation in the region has been critically low though there has been a general decline worldwide. Private sector is unlikely to take risk of exploration. Country risk has been somehow exaggerated There is large potential market for electricity market in Kenya and the region. Therefore, use of geothermal energy in electricity production offers good investment opportunities 6. RECOMMENDATIONS KenGen should continue in resource exploration on behalf of the government until a time when there is a company established for steam development. KenGen should participate in all future bidding of new power plants in-order to create competition and assist in regulating IPPs overpricing. KenGen should seek private sector partnership and alliances in future plant constructions New power plants by KenGen to be packaged on EPC contract basis, while those by IPP to be on BOT basis. Geothermal fund be created, among the contributors being the geothermal plants themselves, to facilitate and accelerate exploration of the resource Resource development should be prioritized on the basis of having proven potential, proximity to the grid and developed infrastructure. 7. ACKNOWLEDGEMENTS I acknowledge the contributions from, Peter Kinuthia of KPLC and colleagues in the Corporate Planning and Strategy Division of KenGen, for their valuable contribution towards the preparation of this paper. REFERENCES: Acres International, Kenya National Power Development Plan , Ministry of Energy Acres International, Interim Update of Kenya National Power Development Plan , Ministry of Energy Bayliss, K and D. Hall,(Nov.2002) Independent Power Producers: A Review of the Issues, Public Services International Research Unit (PSIRU), University of Greenwich Izaguire, K.I, (May 2000), Private Participation in Energy, The World Bank Kenya Power & Lighting Co. Ltd, The Least Power Development Plan, Years, 1994,1997,2001, 2003(draft) Updates. Kenya Electricity Generating Co. Ltd./ Sinclair Knight Merz, Data Reference Manual for Geothermal Projects