The power sector still suffers from an unreliable, poor quality supply and a high cost of electricity. This is despite that, from time to time, the Kenyan government has intervened directly and or indirectly. The reasons for this unsatisfactory performance have very little to do with high load growth, inadequate generation capacity or even poor hydrology in the Tana Basin. To correct these and prevent future problems, Kenya must tackle institutional, implementation and other issues as well as indefinitely postpone a proposed thermal plant.
Electricity in relation to Primary Energy usage in Kenya
In Kenya, electricity generated from natural resources, such as hydro and geothermal, contributes only 8% towards the total primary energy used in the country. Petroleum products, all of which are imported, contribute another 20% (including 2% for power generation). These products mainly serve the transport and aviation sectors. Wood and charcoal, which are largely used for cooking and heating, provide the balance of 72% of total primary energy. (In rural and urban areas, more than 80% of the total population in Kenya half of whom live below the poverty line, use wood and charcoal for cooking.)
Over the past few years, the government has created a number of new institutions with overlapping functions and responsibilities all of which are controlled and, quite often, micro-managed by their parent ministries. This has not only resulted in gross inefficiencies and wastages of material and human resources, but it has also created a significant dent in the exchequer because of direct and indirect subsidies to the power sector which are often at the expense of pressing development issues in other sectors of the economy.
Least Cost Power Development Plans (LCPDPs)
There is also a general lack of understanding about the basic parameters which govern a modern power sector’s planning and operations. The planning and operations should embrace such diverse resources as hydro, geothermal, wind, thermal, biomass, and, in future, coal, gas, solar, nuclear and interconnected hydro supply coming from Ethiopia and other neighbouring countries.
As such, several players, all pushing their own agenda, have haphazardly prepared LCPDP’s on an ad hoc basis with no single entity taking full responsibility for the planning process. Furthermore, these plans have been prepared based on false load growth assumptions. They set unrealistic target dates for project completion, and they do not take due cognisance of the appropriate generation mix and location of the plant.
Basic rules that govern least cost planning:
i. Load forecasting must be realistically prepared based on historic trends and economic growth predictions.
ii. Peak demand (in MW) must be met with effective installed capacity and about 20% reserve margin.
iii. The minimum hydro energy available in a critical drought year and adequate non-hydro plant must meet the annual energy demand (in GWh).
iv. Least cost criteria must be used to determine the generation mix and setting of plants.
v. The plan must be SMART (Specific, Measurable, Achievable, Realistic, and Time bound).
Over the past twenty years or so, the sector’s record on project implementation has been very poor. Whether funded by donor agencies, the public sector, or the private sector (Independent Power Producers or IPP’s), projects are delayed by several years. This is mainly because of poor planning, inordinate delays in funding, protracted Power Purchase Agreements (PPA) negotiations, and lack of government guarantees against political risks, court cases, and other bureaucratic hurdles and procurement bottlenecks.
In fact, these delays have been the single major cause for the installation of 100 MW emergency plant during the three year critical drought of 1998, 1999 and 2000. Then again, another 150 MW emergency plant has been running on base load since 2006-2007 and, until recently, it has used very expensive diesel fuel.
It must be appreciated, however, that although the recent emergency plant cost energy consumers an additional UScts 1.0/kWh in fuel surcharge, Kenya’s demand for electricity was generally met, unlike that of our neighbours, with very little load shedding or power rationing even during the two year ‘severe drought’ of 2008-2009. Yes, Kenya experienced a few outages because of generation shortfalls but those were due to operational reasons. They were not due to lack of generation capacity.
Increased system faults and technical losses
Over the past four to five years, far too much attention has been paid to the increased connectivity of new consumers without corresponding attending to investment in maintenance and reinforcement of the existing distribution facilities, especially at low voltage (LV) and medium voltage (MV) levels (i.e. 415V, 11kV and 33kV network). This has resulted in increased system losses (both technical and non-technical) from 16% in FY 2009/10 to about 18.6% in 2012/13.
During the same three year period, 2009-2011, system faults (mainly on the LV network) have increased from about 6,000 to about 9,000 per month, and transformer failures have increased from about 200 to 300 per month. (Vandals caused including about one-third of these failures.) It is these high system losses, LV faults and transformer failures, not the lack of generation capacity or inadequate reserve margins on which so much emphasis is being unduly placed, which are the major cause of unreliable and poor quality of supply. Moreover, the stand-by or captive diesel plant will continue to serve the industry and large commercial enterprises unabated unless the distribution network and quality of service improves considerably and on a sustained basis.
Electricity tariff in Kenya
Due to the reasons given above, it is generally believed, and quite rightly so, that the Kenyan electricity tariff is amongst the highest in the East African region. However, if the economic cost of load-shedding and direct government subsidies is added to the base tariff, then the overall economic cost of electricity in Kenya is the lowest in the region.
There is a somewhat misplaced perception that electricity represents a major cost both to domestic and industrial consumers. The truth of the matter is that an average domestic consumer spends no more than 3-4% of his or her total household income on electricity. Similarly, for an average industrial consumer, including a large number of manufacturers, expenditure on electricity is between 4-6% of total turnover as most of the raw material is imported. However, for the very large industries that are energy intensive and use local raw material, such as cement works, some paper mills and (in future) steel and metal industries, electricity cost can be as high as about 20%.
Revised LCPDP (2013-2023) and the latest tariff review
The average annual GDP growth between 2003 and 2013 was about 5%, and the demand for electricity grew at about 5.6%. However, the revised Medium Term LCPDP (2012-2016), which formed the basis of the recent tariff approval by ERC, assumes a generous load growth of about 8.3%. As shown in the table below, this 8.3% includes demand created by those Vision 2030 flagship projects which can be realistically completed within the next ten years.
The Plan also includes all generation projects which are already under construction or fully committed and awaiting financial closure. A tentative LCPDP for the next ten years is also illustrated graphically and shows how the new plant added over this period will meet peak demand in MW and annual energy demand in GWh by using different modes of generation.
The above generation programme will not only comfortably meet the demand for electricity, but it will also leave adequate reserve margins for unforeseen contingencies. Within the next four years, the programme will reduce the overall tariff by at least UScts 3.0/kWh from the current level of UScts 18.0/kWh to about UScts 15.0/kWh as most of thermal generation will be displaced by geothermal and wind power sources which are now under construction.
The latest Investment Prospective (2013 to 2016) for a 5,000+ MW Plant
The Ministry of Energy (MoE) launched the latest Investment Prospectus (covering 2013-2016) which is for installing 5,000+ MW generation capacities before 2017. In the prospective, the MoE proposes that approximately 1,500 MW will be from geothermal sources, 500 MW will be from wind, 2,000 MW will be coal-fired, and 1,000 MW will be from a liquefied natural gas (LNG) plant. While the system can comfortably absorb the proposed geothermal and wind plants over the next ten years, as shown in the above tentative LCPDP, the 2,000 MW coal-fired and 1,000 MW LNG plant cannot be justified on technical or economic grounds nor, due to lack of adequate demand, can the system absorb them.
Costing in the region of USD 5 billion, the above mentioned thermal plant of 3,000 MW capacity will, therefore, remain idle for several years. If installed prematurely, it will attract almost USD 600 million (or KES 50 billion) per annum in capacity charges which the state or consumers would have to absorb and which would result in an increased tariff by at least UScts 7.0/kWh to about UScts 22.0/kWh. Either way, this additional cost would be a huge financial burden to the country and would come without any improvement in the quality or security of supply or increase in economic growth.
It is, therefore, pertinent that the proposed 3,000 MW thermal plant using imported coal and LNG be deferred indefinitely. In an orderly manner, the sector must continue with the development of geothermal, wind and other renewable resources including interconnection with Ethiopia and other neighbouring countries.