By James Anyanzwa
East African governments are reviewing power purchase agreements with independent power producers (IPPs) as part of efforts to lower the cost of energy and attain universal electricity access.
Private investors own and operate plants that generate power for sale mostly by using diesel, an expensive fuel whose cost is passed on to consumers in the form of inflated monthly electricity bills, contributing to the high cost of doing business in the region.
In Rwanda, for example, the government plans to use diesel-generated power to either cover peak demand or serve as a reserve to hedge against the short-term unavailability of generation capacity or imports.
This is because about 80 per cent of the retail electricity tariff amount goes towards recovering the cost of generating electricity.
According to Rwanda’s Energy Sector Strategic plan (2013-2018), using thermal power to serve peak load and backup power demands would help the country reduce over-reliance on IPPs and lower the cost of electricity. Rwanda is seeking to ensure universal electricity access by 2024.
In Uganda, the government plans to review the concession model it has used to run the electricity sector over the past 15 years, with the private investors planning to revert power generation activities to the state-owned Uganda Electricity Generation Company Ltd (UEGCL).
The government plans to terminate the power generation contract it has with South Africa’s utility firm Eskom after the firm failed to deliver on its contractual arrangements.
Eskom, through a locally registered subsidiary, in 2003 won a 20-year concession to manage the then 200MW Kiira power station and the 50 year-old 180MW Nalubaale power station.
However, Eskom has failed to inject $100 million into the business and instead only invested $25 million with five years remaining to the expiry of the concession period.
According to Harrison Mutikanga, the chief executive of UEGCL, electricity access in Uganda is still at about 20 per cent, and many reforms need to be undertaken to attain full connectivity for the people by 2040.
It is estimated that thermal generation remains critical in Uganda’s electricity supply, accounting for 100MW of the country’s 600MW total installed capacity.
Costly diesel-fired plants
Last year, Tanzania’s President John Magufuli blamed costly diesel-fired plants operated by IPPs and emergency power producers for the exorbitant electricity charges, which are beyond the reach of ordinary people.
According to the US Agency for International Development, Tanzania’s high reliance on expensive thermal and emergency generation sources has added to the sector’s financial unviability.
The country’s installed capacity is estimated at over 1,500 MW against an estimated demand of 1,400MW, comprising hydroelectric (568MW), thermal (925MW) and other renewables (82.4MW).
Tanzania’s current electricity access is estimated at 32.7 per cent, with about 7.7 million households connected to the national grid.
The government is working towards producing at least 5,000MW of cheaper power by 2020 in order to transform into an industrialised economy and achieve universal electricity access by 2030.
As of 2015, there were six IPP projects active in the country responsible for 40 per cent of electricity generated, with the national utility company, Tanzania Electric Supply Company (Tanesco), providing the remaining 60 per cent.
In Kenya, President Uhuru Kenyatta in 2016 called for a review of the power purchase agreements with the IPPs in a bid to terminate those that are stifling plans to reduce the cost of electricity as the country seeks to feed more renewable energy such as geothermal, wind, coal and solar into the national grid.
Kenya expects its fuel costs to fall slightly from Ksh17.45 billion ($174.5 million) in 2017, to Ksh15.98 billion ($159.8 million) in 2023, mainly due to a shift to renewable energy sources and the decommissioning of IPPs such as Iberafrica 56.35MW Old Plant, Embakasi and Muhoroni’s Aggreko this year.
This could translate into a decline in the fuel cost component of the monthly power bills from Ksh2.22 ($0.02) /kwh in 2018 to Ksh0.63 ($0.006) /kwh, according to the country’s Least Cost Power Development Plan (2017-2037).
Kenya first turned to emergency power in 2001 after suffering power shortages due to a prolonged drought that exposed the economy’s overreliance on hydropower.
IPPs in the country are entitled to a fixed-capacity charge of $0.04 per kilowatt-hour throughout their remaining contract periods which are often long-term, running for 20 to 25 years.
The fuel cost component in monthly electricity bills has been a major burden for power consumers, accounting for as much as 40 per cent of the total bill.
Last year, Energy Cabinet Secretary Charles Keter said the government will terminate the contracts of three IPPs with a combined capacity of 190MW at an estimated cost of Ksh9 billion ($90 million).
However, failure to raise the compensation cash would mean that the government allow their contacts to expire within five years.
Iberafrica Power Plant’s 56MW contract is set to end in October this year, Tsavo Power’s (74MW) will end in September 2021, while Kipevu Diesel’s 60MW contract runs up to July 2023.
The 310MW Turkana Wind Farm, which was switched on in October 2018, is now injecting up to 240MW into the grid.
Kenya runs 27 thermal power plants with a total capacity of 712 MW, against the country’s total installed capacity of 2,370 MW.
Kenya hopes to connect every household to power through grid expansions and off-grid sources by 2022, from around 73.42 per cent as at the end of April 2018, owing to various national electrification projects that have been undertaken by Kenya Power such as the Last Mile Connectivity Project.