Power Sector Report_Final

Figure 1: Power Companies Price Performance – 3 Months
Base = 4,960.30, NSE20 Share Index on 20 May 2013
Source: NSE, USE & DBIB estimates
Figure 2: Summary Valuations
Source: Bloomberg, NSE, USE & DBIB estimates
3,500
4,000
4,500
5,000
5,500
6,000
6,500
20-May-13
27-May-13
3-Jun-13
10-Jun-13
17-Jun-13
24-Jun-13
1-Jul-13
8-Jul-13
15-Jul-13
22-Jul-13
29-Jul-13
5-Aug-13
12-Aug-13
19-Aug-13
26-Aug-13
NSE20 UGSINDX KPLC KenGen UMEME
Stock
Bloomberg
Ticker
Current Price
(Aug 20)
Current Mkt
Cap
Fair Price
Upside
(downside)
Rating
2013E
EV/EBITDA
2013EP/E
KPLC KPLL KN Equity KES 14.40 KES 28,101.1m KES 12.90 -10% Sell 6.97x 9.72x
KenGen KEGC KN Equity KES 16.90 KES 37,152.3m KES 16.80 -1% Hold 8.39x 16.70x
UMEME UMEMUG Equity UGX 360 UGX 584,596.1m UGX 420 8% Buy
KES 13.00 KES 21,110.4m KES 14.00 17% Buy
5.09x 8.99x
Power Sector Report
East Africa
23 August 2013
Julie Kariuki
jkariuki@dyerandblair.com
Eric Ngure
engure@dyerandblair.com
We initiate coverage of the three power sector companies
operating in East Africa:
 Kenya: We project peak electricity demand to grow at an
eight-year CAGR of 11.30% from 1,344MW in 2012 to
3,163MW in 2020E supported by strong economic
performance. We also project Kenya’s inflation to fall from
7.0% in 2012 to 5.0% in 2020E.
 Uganda: We expect steady economic performance to drive
peak demand to 948MW by 2020E, representing CAGR of
8.75% over the eight-year period. Uganda is also expected
to maintain inflation at 5.0% between 2013E and 2020E,
following a decline from 5.9% in 2012.
 Significant power sector growth potential: The commercial
exploitation of petroleum in power generation, capacity
additions, system refurbishments and distribution network
improvements, renewable electricity generation, increased
private sector participation and enabling legislative and
policy frameworks are potential enablers to the attainment
of power sector targets for both countries.
 We rate Kenyan companies Kenya Power Lighting Company
Limited (KPLC; TP KES12.90, downside 10%) SELL; and
Kenya Electricity Generating Company Limited (KenGen;
KES16.80, downside 1%) HOLD on account of prevailing
tariff limitations to cost effective operations and capacity
investments.
 We rate Umeme Limited, the Ugandan company (UMEME;
TP UGX420, upside 17% and KES14.00, upside 8%) BUY on
account of strong Concession safeguards that curb against
negative regulatory actions and political interference.
Dyer & Blair may do business with companies covered in its research reports. Although the views expressed in this document are solely those of the Research Department
and are subject to change without notice, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors
should consider this report as only a single factor in making their investment decision. We do not guarantee the accuracy or completeness, nor will the company be held
liable whatsoever for the information contained herein. Dyer & Blair may deal as principal in or own or act as market maker for securities/instruments mentioned or may
advise the issuers. Members of the firm may have pecuniary interest in the listed companies. The document is exclusively for our clients and duplication is not allowed.

2
23 August 2013 Power Sector Report Dyer & Blair Investment Bank
Contents
Executive Summary .......................................................................................................................................................................3
Power Sector Overview.................................................................................................................................................................4
Kenya Power & Lighting Limited .................................................................................................................................................12
Kenya Generating Company Limited...........................................................................................................................................17
UMEME Limited...........................................................................................................................................................................21
Valuation and Performance.........................................................................................................................................................26
Appendix......................................................................................................................................................................................31

3
Executive Summary
Key investment highlights
Power sector expected to track economic growth. We expect strong economic growth to drive power demand with commercial
exploitation of petroleum in power production further expected to facilitate cost-effective power generation, keeping overall inflation at
acceptable levels.
Infrastructural developments to deepen electricity access. We expect the timely commissioning of additional capacity, system
refurbishments and distribution network (DN) improvements to drive electricity connectivity, reduce the power demand-supply deficit and
improve electricity affordability as both Kenyan and Ugandan governments decisively implement measures to develop their respective
power sectors under the Vision 2030 and Vision 2040 development plans.
Quality power supply. Alongside infrastructural improvements, the shift from weather-dependent hydro-electric power (hydro power) and
expensive thermal generation to renewable energy sources is expected to increase power output, improve electricity supply, build up
adequate reserve generation capacity, reduce load shedding and prevent electricity shortages and supply disruptions.
Promotion of private sector participation. Efforts by both governments to enhance private sector development and financing of energy
generation projects are expected to contribute to the achievement of the power sector targets enshrined in the two development plans.
Ongoing reforms in energy sector legislative and policy frameworks are also expected to cultivate an enabling environment.
In summary, there exists significant potential for power sector companies. Prospects of rising electricity sales on the back of strong
economic performance, population growth and system loss reductions point to strong potential performance. This is however highly
dependent on the actual price of electricity: maintaining commercially viable power prices that reflect business costs while preserving
end user affordability will therefore remain a challenge.

4
0.0%
1.5%
3.0%
4.5%
6.0%
7.5%
9.0%
2006 2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Kenya Uganda
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
2006 2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Kenya Uganda
Power Sector Overview
Electricity is a key macroeconomic enabler
The International Monetary Fund’s, World Economic Outlook Database for April 2013 (IMF WEO for April 2013) projects Kenya’s gross
domestic product (GDP) at 5.85 percent and 6.24 percent for 2013E and 2014E respectively. GDP growth is expected to peak to 6.64 percent
in 2016E then slowdown in 2017E to 5.82 percent. The onset of commercial oil production is expected to boost economic growth beyond
2020E as Kenya rolls out the power implementation plan for delivering the Vision 2030 power sector targets. Power demand correlates
strongly to economic growth and as such we project peak electricity demand to grow at an eight-year compound annual growth rate (CAGR)
of 11.30 percent from 1,344MW in 2012 to 3,163MW in 2020E.
Uganda’s GDP is set to recover from the dip experienced in 2012 and grow by 4.84 percent in 2013E. Economic growth is expected to
accelerate to 7.0 percent in 2015E supported by the exploitation of petroleum deposits and hold steady at this rate until 2020E. We expect
this to drive peak demand to 948MW by 2020E, representing CAGR of 8.75 percent over the eight-year period.
Figure 3: Real GDP Growth, % Figure 4: Inflation1
(end of period consumer prices), %
Source: IMF WEO April 2013 (up to 2018E) & DBIB estimates (2019E-2020E) Source: IMF WEO April 2013 (up to 2018E) & DBIB estimates (2019E-2020E)
Energy has strongly bearing on consumer prices
Kenya and Uganda maintain similar inflation baskets with food and fuel constituting a significant proportion of total weight. Both countries
experienced high inflation in 2011 on account of increased food and power costs occasioned by poor weather and high international crude
oil prices. Kenya’s overall inflation during 2012 is estimated at 7.0 percent, which rate is projected to fall to 5.0 percent in 2020E.
Uganda is also expected to maintain inflation at 5.0 percent between 2013E and 2020E, dropping from 5.9 percent in 2012. Although
drought is erratic and unpreventable, energy costs could be contained by increasing renewable power generation. Both countries plan to
shift away from expensive thermal power to geothermal production alongside other renewable modes of generation. The discovery of oil
is also expected to reduce reliance on expensive fuel imports, containing inflation and driving down food prices further.
Electricity access in Kenya and Uganda below par
The International Energy Agency’s World Energy Outlook 2011 (IEA WEO 2011) estimates Kenya’s and Uganda’s 2009 electrification rates at
16.1 percent and 9.0 percent respectively against the Sub-Saharan Africa (SSA) average of 30.5 percent. Kenya is however ranked 11th in
Africa in terms of GDP by the IMF WEO for April 2013, making it economically larger than Ghana, Zimbabwe and Zambia despite these
nations having electrification rates in excess of 18 percent.
1 End of period consumer prices

5
Figure 5: Electricity Access in Africa (2009), % Figure 6: African Countries’ Contribution to GDP, %
Source: IEA WEO 2011 Source: IMF WEO for April 2013
This implies that electrification is to some extent dependent on other factors beyond economic development. Countries with oil, natural
gas or coal deposits such as North African nations, Nigeria, Cameroon, Cote d’Ivoire, Sudan, Benin, Angola and Zimbabwe generate cheap
thermal electricity leading to high national electricity access.
Population also has a bearing on electrification rates with less densely populated countries not requiring extensive DNs to supply power.
Rapid electrification in both Kenya and Uganda will likely outpace population growth over the eight-year period to 2020E, estimated at
CAGR of 2.84 percent and 3.30 percent respectively, as aggressive efforts to deepen electricity access in both countries bear fruit.
However, despite extensive DN expansion in both Kenya and Uganda, growth in electricity connectivity has not been commensurate with
network growth, with Kenya’s national electricity access rate currently estimated at 15 percent. This low electrification rate, largely
attributed to the high connectivity fees, has muted Kenya’s energy per capita consumption (PCC) which in 2010 was estimated at 156kWh
(about 26 percent of the Africa average) by the IEA 2012 Key World Energy Statistics. Uganda’s PCC is much lower at approximately 80kWh.
Figure 7: Population, mn Figure 8: Energy PCC, kWh
Source: IMF WEO April 2013 (up to 2018E) & DBIB estimates (2019E-2020E) Source: IEA 2012 Key World Energy Statistics
Electricity largely from hydro sources
Total installed generation capacity for Kenya and Uganda in 2012 is estimated at 1,708MW and 819MW respectively, comprising 50.7
percent and 83.9 percent of hydro power respectively. Hydro power’s dependence on rainfall makes it unreliable as poor hydrology
necessitates the use of expensive thermal generation, as was the case when Kenya was struck by drought in 2011.
Energy generation is considered a key macroeconomic enabler to Kenya’s Vision 2030 and Uganda’s Vision 2040, which project total
required installed capacity at 15,026MW and 41,738MW respectively by 2030E and 2040E respectively.
0% 15% 30% 45% 60% 75% 90%
Uganda
Tanzania
Kenya
Ethiopia
Zambia
SSA
Zimbabwe
Africa
Nigeria
Ghana
South Africa
0% 5% 10% 15% 20% 25%
Ghana
Kenya
Ethiopia
Tunisia
Sudan
Libya
Morocco
Angola
Algeria
Egypt
Nigeria
Other countries
South Africa
25
30
35
40
45
50
55
2006 2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Kenya Uganda
0 750 1,500 2,250 3,000 3,750 4,500 5,250
Ethiopia
Nigeria
Sudan
Kenya
Angola
Ghana
Av. Africa
Morocco
Algeria
Tunisia
Egypt
Libya
South Africa

6
Total = 1,708MW Total = 819MW
1,500
2,500
3,500
4,500
5,500
6,500
7,500
2007 2008 2009 2010 2011 2012
Uganda (GWh) Kenya (GWh)
400
1,000
1,600
2,200
2,800
3,400
2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Uganda (MW) Kenya (MW)
Figure 9: Kenya_Installed Capacity, MW Figure 10: Uganda_Installed Capacity, MW2
Source: Economic Survey 2013 Highlights & KenGen Source: Uganda’s Energy Report
Generating capacity for both countries increased significantly in 2012 following the commissioning of Kenya’s Olkaria I & IV 280MW, the
world’s largest single geothermal power project and the Bujagali Hydroelectric Power Plant (HPP) which injected an additional 250MW to
Uganda’s national grid. Improved supply in Uganda further allowed the decommissioning of some diesel generating plants and the
elimination of load shedding. Electricity generation in 2012 for Kenya and Uganda is estimated at 7,464GWh and 2,618GWh respectively,
over six percent higher than prior year generation for both countries. Most of the electricity generated is consumed locally with negligible
exports to neighbouring countries.
Figure 11: Total Energy Generated, GWh3
Figure 12: Projected Peak Load, MW
Source: Uganda’s Energy Report, UETCL & KPLC Source: Uganda’s Energy Report, LCPDP & DBIB estimates
Demand for electricity has been growing on the back of strong economic growth and increase in electricity consumers. Kenya’s Updated
Least Cost Power Development Plan 2011-2030 (LCPDP) and Uganda’s Energy Report 2011-2012 (Uganda’s Energy Report) estimate 2012
peak demand at 1,344MW and 507MW respectively, representing approximately 79 percent and 62 percent of total installed capacity for
the two countries respectively.
2 As at September 2012
3
Uganda’s total 2012 generation is extrapolated from estimated generation for the first nine months. Kenya’s generation calendarised
Hydro
50.7%
Thermal
30.5%
Geothermal
14.8%
Cogeneration
2.7%
Wind
1.3%
Large hydro
77.0%
Mini hydro
6.9%
HFO thermal
12.2%
Diesel generators
0.3%
Biomass
3.6%

7
This indicates that generation capacity expansion has yet to deliver sufficient headroom, as best practice requires between 15 percent and
30 percent of reserve generation capacity to facilitate off-line maintenance and additional demand requirements. This strain is evident even
at distribution level, with KPLC flagging the country’s lack of reserve margin as at January 2013. The actual situation could be much worse
given that current demand levels are suppressed, indicating that peak demand could be much higher on account of this unmet demand.
The highest peak power consumption to date is 1,347MW, representing 86 percent of the company’s peak capacity. This reiterates the
country’s overall precariously limited capacity.
Consistent with Kenya’s Vision 2030 targets, KPLC’s Five Year Strategic Plan 2011/12 to 2015/16 (the Strategic Plan) projects peak demand
of 2,243MW by 2015/16, supported by 1,749MW of additional generation capacity between 2011/2012 and 2015E/2016E, which would
push reserve capacity to 32 percent by 2015E/2016E.
Electricity demand continues to outpace supply for both countries, with the public sources estimating Kenya’s power deficit at four percent
against a minimum threshold of 15 percent. Electricity shortages and supply disruptions resulting from excessive demand continue to remain
a key obstacle to economic activity. This sustained shortfall in generation relative to energy demand will likely continue as generation
capacity struggles to match rising demand over 2013E-2020E period. As a result, we project peak demand to increase to approximately
3,100MW and 950MW for Kenya and Uganda respectively by 2020E.
Aggressive capacity expansion
The government of Kenya (GoK) identifies nine projects as key pillars to the successful implementation of Vision 2030. These are expected
to push the country’s energy requirements by about 890MW, with highest demand expected from the Konza City ICT Park (440MW) and
Meru’s iron and steel smelting industry (315MW).
The LCPDP is the Ministry of Energy (MoE’s) power implementation plan for delivering the power sector targets outlined in Vision 2030.
Under the LCPDP, Kenya’s generation capacity is projected to increase to 19,220MW by 2030E, with geothermal contributing a quarter of
Kenya’s total installed capacity and hydro power dropping ten-fold to about 5 percent. The plan also highlights nuclear power as a potential
power source, with an inaugural 1,000MW plant planned for 2022E. Commissioning of subsequent nuclear plants is expected to increase
nuclear power generation to 3,000MW by 2030E.
KPLC’s Updated Retail Tariff Application on 7 February 2013 (the Tariff Application) also identifies an additional 851MW of generation
capacity expected to be developed by independent power producers (IPPs) (private companies which generate and sell electricity). IPPs
account for about 26 percent of the Kenya’s installed capacity thereby bridging the demand gap.
Figure 13: Vision 2030 Flagship Energy Generation Projects Figure 14: IPP Committed Power Plants
Source: LCPDP Source: LCPDP
Mode of
Generation
Project
Expected
Power (MW)
Current Status
Commissioning
Date
Olkaria I 140 Ongoing End of2013
Olkaria II 35 Completed April 2010
Olkaria III 85 Behind schedule
Olkaria IV 140 Ongoing
Eburu 2 Completed
Wellhead generators Behind schedule
Menengai 1,000 Ongoing
Diesel Kipevu 120 Completed January 2011
Dongu Kundu 600 Behind schedule
Athi River 19 Behind schedule
Kiambere 82 Completed October 2009
Tana 20 Behind schedule
Sangoro 21 Completed November 2011
Kindaruma 32 Ongoing Mid 2013
Ngong 5 Completed July 2009
Lake Turkana 300 Ongoing 2015
Ngong I 7 Behind schedule
Ngong II 14 Behind schedule
Rural electrification programme Ongoing
Hydro
Wind
Geothermal
Coal
IPP Plant
Capacity
(MW)
In Service Year
OrPower 36 March 2013
OrPower 16 March 2014
Triump Generating
Plant
87 June 2013
Aeolus Wind 160 November 2012
Lake Turkana Wind 300 July 2013
Kipeto 100 July 2015
Prunus 50 July 2015
Kwale Sugar 18 December 2014
FITHydros 21 July 2015
Thika Power 87 June 2013
GulfPower 85 February 2014

8
These power generation projects are also expected to reduce reliance on expensive thermal plants, possibly displacing the country’s 120MW
of emergency power though thermal generation will continue to mitigate power shortfalls.
GoK efforts to support increased generation capacity through the expansion of the national grid between 2013E and 2017E are expected to
cost an estimated KES200 billion. Some of the high-capacity transmission lines expected to be constructed include the Mombasa-Nairobi
(475km), Kenya-Tanzania (100km), Loiyangalani-Suswa (430km) and Ethiopia-Kenya (686km). These will facilitate efficient transmission of
power from large generation plans such as KenGen’s 280MW Olkaria I & IV and the 300MW Lake Turkana wind project, significantly pushing
down system losses (revenue leaks resulting from system inefficiencies) which in 2012 were estimated at 17.3 percent (a loss of about KES
8 billion annually).
An additional 1,530MW is expected into Uganda’s national grid by 2020E on completion of various projects under the Ministry of Energy
and Mineral Development’s (MEMD’s) medium-term generation pipeline. These include the Karuma Hydropower Project (600MW), the
Isimba Hydropower Project (180MW) and the Ayago Hydropower Project (600MW). Heavy fuel oil (HFO) based electricity supply generated
by the Jacobsen Uganda Power Plant Company Limited, JUPPCL and Electro-Maxx (U) Limited) plants is expected to continue bridging
demand-supply shortfall despite the scaling down of thermal generation.
Figure 15: Uganda’s Generation Capacity Additions
Source: Uganda’s Energy Report
Both Kenyan and Ugandan governments are committed to the timely commissioning of additional generating capacity to mitigate demand-
supply shortfalls. By diversifying the sources of energy, the two countries are expected to better meet rising demand and build up reserve
capacity.
Power sector players
The restructuring of Kenya’s power sector began in 1997 with the unbundling of KPLC into distinct entities each responsible for the various
aspects of the electricity supply value chain. KenGen took charge of publicly owned power generating plants in 1998, with other power
sector institutions created on the authority of Sessional Paper No. 4 of 2004 and the Energy Act (2006). These include the Rural Electrification
Authority (REA), the Geothermal Development Company (GDC), the Energy Regulatory Commission (ERC) and the Kenya Electricity
Transmission Company (KETRACO).
2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Buseruka
Kakira
Kinyara 40
Kikagati 16
Kabaale (Gas & Test Crude) 53
Kabale Peat 20 - 40
Nyamwamba 14
Muzizi 26
Nyagak 3 4.5
Karuma 600
Isimba 188
Nshungyezi 40
Ayago 600
GENERATIONPLANTS
Total additional capacity increase: 1,994MW - 2,014MW

9
Figure 16: Kenya’s Power Sector Players
Stage Providers
Generation KenGen, IberAfrica Power (E.A.) Co. Ltd, Tsavo Power Co. Ltd., Mumias Sugar Co. Ltd., OrPower 4
Inc., Rabai Power Co. Ltd., Imenti Tea Factory Small hydros.
Transmission KETRACO
Distribution KPLC
Source: Draft Energy Policy 2012
Uganda’s electricity sector was liberalised in 1999 following the enactment of the Electricity Act (1999). This led to the restructuring of the
Uganda Electricity Board (UEB) into three utilities responsible for generation, transmission and distribution. Power sector government
institutions include the Electricity Dispute Tribunal (EDT), the Electricity Regulatory Authority (ERA), the Rural Electrification Agency (REA),
UMEME, Uganda Electricity Distribution Company Ltd (UEDCL), UETCL and Uganda Electricity Generation Company Ltd (UEGCL).
Figure 17: Uganda’s Power Sector Players
Stage Providers
Generation Bujagali HPP, Eskom/UEGCL, Jacobsen, Electro-Maxx, TrØnderEnergi, Kakira Sugar
Transmission UETCL
Distribution UMEME, Ferdsult, WENRECo and URECL
Source: UMEME IPO Prospectus & Uganda’s Energy Report
Key sector trends
a. Rural electrification
The objective of rural electrification projects (REPs) is to provide electricity in areas that are commercially unviable and therefore not
covered by the national grid. This is because low population densities arising from dispersed rural settlements limit economies of scale
for connection to the grid, thereby increasing the PCC cost of REPs.
Kenya’s REPs are owned by the REA with KPLC connecting the customers and maintaining the network under Service Level Agreement
(SLA). KPLC is currently undertaking KES 1.3 billion worth of REP projects in line with Vision 2030 energy generation projects that project
complete nation-wide electricity access by 2030E. The Government of Uganda’s (GoU’s) Rural Electrification Strategy and Plan (2012-
2021) aims to achieve 22 percent rural electrification by 2021E (currently 4 percent), towards national electrification of 80 percent by
2040E up from the current estimated 12 percent.
b. Renewable energy
Kenya and Uganda have refocused their energy mix to favour renewable energy development, particularly geothermal power. Apart
from being naturally available, geothermal also delivers high utilization and conversion rates, while mitigating climate change and
preserving the environment.
Kenya’s LCPDP aims to diversify power generation away from weather-dependent hydropower and fuel-reliant thermal generation to
greener, cheaper and sustainable sources. Kenya’s Draft Energy Policy 2012 estimates geothermal potential within the Great Rift Valley
at between 7,000MW and 10,000MW. The GDC, a state-owned Special Purpose Vehicle (SPV) established for the development of
geothermal resources in Kenya, recently invited bids for the development of 90MW of geothermal power in the Menengai field within
the Rift Valley by 2014E. In addition to supporting the GDC, the GoK is also expected to create a Directorate to oversee renewable energy
policy and a Renewable Energy Lead Agency to undertake the promotion of this resource, with a target 5,000MW of geothermal power
expected by 2030E.
The GoU is also exploiting potential geothermal energy resources so as to reduce reliance on hydro power, currently contributing over
80 percent of total generating capacity. To date, three companies have been granted exploration rights in the Katwe and Buranga regions
of the Western Rift Valley.

10
c. Private sector participation
Various efforts are underway to promote private sector investment in the development of new power generation and transmission
projects.
The MoE’s mandates within Kenya’s Vision 2030 include increasing private sector participation in the power sector. This is expected to
increase power output, improve electricity supply, expand the reserve margin and reduce the price of power making resulting in overall
business confidence, particularly amongst investors in power-intensive industries. The 2010 revision of Kenya’s Feed-in-Tariff generated
significant interest in the country’s renewable energy sources. By April 2013, the ERC had received 80 expressions of interest from
private sector investors seeking to generate 1,900MW from a variety of sources. The passing of Kenya’s Public Private Partnership (PPP)
Act in February 2013 is also expected to foster more power sector joint ventures (JVs).
Uganda’s GET FiT East Africa Program – Uganda Pilot is expected to boost PPP engagement in the financing and development of
renewable energy generation projects thereby unlocking an additional 60- 125MW of renewable energy within the next two to five
years.
d. Exploitation of petroleum in power generation
The commercial exploitation of Uganda’s estimated 3.5 billion barrels of crude oil is expected to start in 2017E following discovery of oil
in 2006. Kenya struck commercial oil deposits in 2013, necessitating the alteration of Vision 2030 to factor in the discovery through the
inclusion of mining and petroleum as the seventh pillar of the development plan. Kenya is expected to begin commercial production in
2020E although actual production potential is yet to be appraised by Tullow Oil.
The two countries expect to generate cheap HFO thermal power once refinement of crude oil begins. This new power source has
potential to accelerate electricity penetration rates to rates in excess of 80 percent, which are prevalent in oil producing North and West
African countries.
Uganda’s planned Invespro (50MW), Hoima-Kabaale (53MW) and Hoima (50MW) thermal generation projects are not yet operational
due to delays in commercialisation and lack of a refinery.
e. Regional interconnection projects
Kenya is expected to connect to Ethiopia so as to tap power from the 6,000MW Grand Ethiopian Renaissance Dam expected to be
commissioned in 2017E. The transmission project linking the two countries via 1,068km of high-voltage (HV) power lines will allow Kenya
to import 400MW. The USD1.26 billion project is already underway, funded by various development partners including the African
Development Bank and the World Bank.
Construction of the 127km 220kV Bujagali-Tororo-Lessos transmission line expected to connect the Bujagali HPP to Kenya’s national grid
is already underway. This project, the second link between Kenya and Uganda will allow Kenya to import 350MW. Completion is expected
in 2014E.
f. Enabling policies and legal framework
Both governments are committed to undertaking enabling reforms in their energy sector legislative and policy frameworks.
The passing of The Constitution of Kenya in 2010 altered the governance structure of the country thereby necessitating the review of
the energy sector framework. This led to the review of the Energy Policy (Sessional Paper No. 4 of 2004), the Energy Act (2006) and
related Subsidiary Legislation in light of The Constitution, culminating in the Draft Energy Policy 2012.
In addition to the Electricity Act (1999), the GoU has formulated various policies that are geared at improving availability and accessibility
of affordable and environmentally sustainable energy. These include the Energy Policy for Uganda (2002), Renewable Energy Policy for
Uganda (2007), National Development Plan (NDP) and the Power Sector Investment Plan (PSIP).

11
Sector challenges
a. Reliability and adequacy of electricity supply
Kenya and Uganda suffer high system losses and power system instabilities due to network inefficiencies, out dated technology, ageing
infrastructure, limited geographical coverage of existing networks and limited reserve margins. These contribute to supply-demand
deficits resulting in load shedding and erosion of revenue which by extension hinder power affordability, as significant investments are
required to mitigate these challenges.
Power theft, meter tampering and vandalism of network infrastructure also contribute to system losses, causing downtime, black outs
and power surges. Measures expected to curb against these include prepayment metering, enactment of prohibitive laws and
introduction of stiffer penalties to reduce illegal connections and network interference.
b. High cost of energy
Electricity is expensive right from the onset as high connectivity rates lock out potential customers. Affordability is further compounded
for communities living in low population density areas as households are also forced to invest in their own transformers due to extended
lead times for geographical coverage.
High capital outlays incurred by power sector investors necessitate substantive returns on investment with Bulk Supply Tariffs (BST)
determined by investors’ need to recoup their investment in the capital intensive plants. This pushes up the cost of electricity
considerably both at the bulk supply and retail levels, though government’s regulation of the sector does in some cases result in BST not
being reflective of actual power purchase costs.
Tariffs are also affected by negative regulatory action following governments’ efforts to bridge budget deficits using additional taxes and
levies. Kenya’s Vision 2030 considers the energy sector a key contributor to fiscal revenues, with overall contribution to tax revenue for
2010 by the sector estimated at 20 percent (4 percent of GDP). Withdrawal of government subsidies also leads to tariff increases.
Other factors that exert pressure on the price of electricity include unfavourable foreign exchange (forex) movements, inflationary
pressure on costs and high international oil prices.
c. High capital outlay and long investment lead times
The power sector is capital intensive, requiring massive financial resources to develop power projects. Mobilising of resources to
undertake such projects is a challenge resulting in the under-exploitation of natural energy sources as renewable energy technologies
such as solar development and geothermal plants have high upfront costs.
The cost of acquiring land for infrastructure development, high way-leave fees and compensation to displaced communities also drive
up investment cost and (in some cases) tariffs.
Continued private sector investment will likely push up retail prices for electricity as private power generators seek higher returns to
recoup investments profitably given the long investment cycles.
The commissioning process, from conception to electricity generation takes a minimum five years, with delays causing higher than
anticipated demand-supply shortfalls. Mobilisation of funds also takes time, with financing often pegged on government guarantees
resulting in long-drawn-out negotiations, pushing up the cost of capital. In 2012, the World Bank resolved to provide guarantees to
commercial banks that issue letters of credit to five of Kenya’s IPPs so as to boost the country’s electricity generation.

12
1,000
3,000
5,000
7,000
9,000
11,000
13,000
15,000
6,000
7,500
9,000
10,500
12,000
13,500
15,000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Energy demand Projected sales
3.0
6.0
9.0
12.0
15.0
18.0
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Average yield Fuel cost charge
Kenya Power & Lighting Limited
Business Overview
KPLC is a state corporation with GoK shareholding of 50.1 percent and private shareholding of 49.9 percent as at FY12. KPLC carries out
transmission, distribution, supply and retail of electric power purchased from KenGen, Kenya’s six IPPs, the Tanzania Electricity Supply
Company Limited (TANESCO), UETCL and Ethiopian Electric Power Corporation (EEPCO) through ERC-approved Power Purchase Agreements
(PPAs). KPLC also has a SLA with KETRACO covering technical and engineering services for some of the transmission projects.
According to KPLC’s Strategic Plan, the company expects to contribute to Vision 2030 by growing electricity sales and customer base to
10,000GWh and 2,663,639 respectively by 2016E which would increase national electricity access to 39 percent of the population. This is
expected to be achieved through DN reinforcements upgrade projects and timely implementation of new projects.
Key Business Drivers
KPLC’s performance will likely suffer significant setbacks following the negative outcome of two key proposals made earlier this year:
1. KPLC’s Tariff Application to the ERC sought to double the cost of electricity for the March 2013E-July 2015E review period in support of
heavy capital expenditure and rising maintenance costs.
2. The recent directive by Cabinet that reverts connectivity charges for single-phase and three-phase connections located within a 600-
meter radius of a transformer to the initial KES34,980 and KES49,080 respectively. This led to KPLC’s withdrawal from the REP in August
2013.
Press reports indicate that the GoK is considering various options that could cushion the negative effects of these actions to KPLC by
providing additional cash flow while safeguarding consumers. These include governmental subsidies, giving cash in exchange for shares,
debt financing and diversifying KPLC’s revenue streams.
KPLC is leveraging the 1,200km Supervisory Control and Data Acquisition (SCADA) infrastructure by leasing 18 of the 24 pairs of fibre optic
cable to licensed telecommunication operations. KPLC plans include fibre optic capacity to all new transmission lines thereby boosting the
revenue potential of its DN.
Based on our analysis of the effects of the foregoing, relevant press reports and publicly available information on KPLC, we project the
company’s performance over the eight year period to 2020E.
Electricity unit sales
We expect electricity sales to continue growing in tandem with Kenya’s GDP forecasts, KPLC’s widening customer base and reductions in
distribution losses. We therefore forecast unit sales to grow at a CAGR of 9.3 percent during the 2012-2020E period to about 12,962 GWh
by 2020E from 6,341 GWh in FY12. The addition of 351MW in geothermal power from KenGen’s Olkaria project and portable geothermal
power plants to the national grid in 2014E will likely push up unit sales significantly reducing the long-running power deficit.
Figure 18: Demand, Sales vs. Losses, % & GWh Figure 19: RT Assumptions, KES/kWh
Source: DBIB estimates Source: DBIB estimates

13
60,000
70,000
80,000
90,000
100,000
110,000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Retail tariff
KPLC’s end user tariff comprises a basic tariff (the non-fuel yield) and a fuel cost adjustment which KPLC collects on behalf of KenGen and
IPPs. The non-fuel yield represents actual revenue to KPLC and comprises a fixed charge and a consumption charge. KPLC also collects Value
Added Tax (VAT), the ERC Levy (charged at 3 Kenya cents/kWh) and the REP levy (about five percent of total unit sales) all combined into
the retail tariff (RT).
KPLC’s current RT is not reflective of actual business costs, having been set in July 2008. The ERC considers tariff adjustments every three
years indicating that KPLC’s RT will likely be next reviewed in 2016E. We therefore conservatively project that the non-fuel yield shall remain
at the current level during the 2012-2020E period.
Increased electricity production using renewable energy and potentially cost effective HFO generation will likely deliver significant cost
savings in terms of fuel costs recovered. This could translate to a drop in the fuel cost component of the RT.
While the Tariff Application projects fuel recovery costs as a proportion of total income to decline from 43.8 percent in FY12 to 4.8 percent
in 2016E on account of reduced fuel-reliant thermal generation, our forecasts are less aggressive. We therefore project the fuel cost charge
to drop by a CAGR of 7.1 percent which as a proportion of the RT declines from 43.8 percent in FY12 to 31.0 percent in 2020E.
The overall effect of the likely reduction in the fuel recovery costs is a drop in average yield by a CAGR of negative 1.6 percent during the
eight-year period.
Power purchase costs
The power sector is capital intensive, with investors requiring substantial return on investment and security from potential default and
political risks as prerequisites to undertaking power projects. The cost of power during the forecast period will therefore largely be dictated
by the BST negotiated under new PPAs for additional power, with KPLC likely struggling to afford the incremental cost of power.
We conservatively assume power purchase costs will grow marginally in the absence of additional revenue to support new power. This
could likely increase power costs by a CAGR of 4.0 percent from KES69.9 billion in FY12 to about KES96.0 billion in 2020E.
While we agree that our power purchase cost assumption is relatively simplistic, the RT adjustment proposed in the Tariff Application was
expected to cover additional power generation costs implying that KPLC will struggle to meet incremental power purchase costs without
additional revenue. The LCPDP also indicates that costs arising from additional power supply would necessitate additional revenue to KPLC
during the Review Period. It is therefore likely that future reviews to existing PPAs by the ERC could increase the BST drastically.
Figure 20: Power Purchase Costs, KESm Figure 21: System Efficiency
81.0%
82.0%
82.9%
83.9%
84.8%
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

14
1,000
6,000
11,000
16,000
21,000
26,000
10%
13%
15%
18%
20%
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Operating expenses Opex % revenue
System efficiency (sales % power purchase).
Following the rejection Tariff Application, the GoK directed KPLC to address system inefficiencies and explore cheap, efficient power supply
to avoid increasing the cost of living through the proposed increase to electricity prices.
System losses remain a key challenge to KPLC, with the company failing to meet efficiency targets outlined in the Strategic Plan for
2011/2012 and 2015E/2016E with dire consequences as each percentage point system loss is estimated to shave KES800 million from gross
profit (based on 2011 prices). The ERC allows KPLC to reclaim a maximum of 15 percent in system losses, forcing the company to absorb the
excess, which in FY12 was 2.3 percent, about KES 9,410 billion worth of electricity sales.
One of the causes of technical losses is the mismatch between transmission and generation capacity as additional generating capacity is
commissioned without corresponding increase to transmission capacity. The commissioning of the 115MW Kipevu Medium-Speed-Diesel
(MSD) plant in FY11 pushed up transmission losses on various lines as the system struggled to support the additional capacity. The
completion of the 400kV Nairobi-Mombasa transmission line in 2013E is expected to reduce these system losses considerably.
The Strategic Plan outlines KES7.1 billion in loss reduction projections planned for the five year period to 2016E which include new
substations, system upgrades, underground cables, automation technologies and switching from oil type to dry type transformers. KPLC is
also expected to hold a significant stake in a JV for the local manufacture of transformers starting 2014E.
KPLC has also announced plans to reduce commercial losses by taking legal action against defaulters. Press reports indicate that the
company seeks to recover KES8.02 billion of bad debts (almost double the FY12 net income) through the courts.
The Tariff Application indicates that KPLC does not expect loss reduction efforts to have significant impact until 2015E/2016E. We agree
with KPLC’s assumptions regarding further system losses and expect the company to face challenges in reducing these from 17.3 percent in
FY12 to 16.9 percent in 2016E, inspite of significant growth in electricity sales and customer base. We therefore project a marginal 128 basis
point drop in distribution losses from 17.3 percent in FY12 to about 16.1 percent by 2020E.
Cost management
KPLC expects to improve operational efficiency by undertaking tight cost management. The largest component of KPLC’s operating expenses
(opex) is staff costs, which in FY12 amounted to 74.2 percent of total opex. KPLC’s efforts to enhance customer service standards through
a 62-outlet branch network across the country will however need to be implemented cautiously to avoid eroding the benefits of various
efforts being employed to bring down staff costs. These include encouraging alternative payment options such as mobile money payment,
commercial banks, supermarkets, post offices, Mpesa and Airtel Money which are expected to push down the staff-to-customer ratio.
We therefore project staff costs to consume 12 and 15 percent of revenue for the eight-year period to 2020E as operating costs increase in
tandem with customer base and unit sales expansions.
In line with cost cutting, KPLC plans to spend KES1.3 billion on free bulbs to low income households and Stimaloan customers with support
from the GoK and Agence Francaise de Developpement (AfD). This would also earn the company about KES 100 million in the carbon market.
Figure 22: Operating Expenses, KESm Figure 23: Customer Base
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

15
Customer base
Although KPLC’s REP customers account for 18.8 percent of the FY12 customer base, this translated to only 4.9 percent of total unit sales.
It is therefore likely that KPLC’s withdrawal from the REP scheme will not affect total sales significantly, with marketing efforts likely
refocused to urban areas towards achieving the Strategic Plan customer base targets.
KPLC has grown its customer base by 25,000 new users each month, effectively doubling its customer base over the last four years to the
current 2.1 million. The company’s present growth momentum would translate to a customer base of 4.4 million by 2020E against our 2020E
projection of 4.1 million, contributing significantly to Kenya’s target electrification rate of 40 percent by 2020E.
We believe this is achievable given the company’s plans to grow the customer base through effective technologies such as AMR and prepaid
meters with the aim of making one million installations between 2012/2013E and 2015E/2016e and complete roll out to the existing
customers by 2015E. Installation of smart metering for 100,000 customers is also under way.
KPLC’s partnerships with AfD and Equity Bank aimed at improving connectivity charges through Stimaloan and the Umeme Pamoja project
will also continue to contribute to connectivity.
Financing
KPLC’s Capital Investment Programme (CIP) is funded using retained earnings and loans under various programmes such as the Energy
Sector Recovery Project (ESRP), and the Kenya Electricity Expansion Programme (KEEP), with the GoK’s majority stake improving investment
attractiveness (sovereign guarantees are required for larger loans). As at FY12, loans from various lenders including Equity Bank, the World
Bank’s International Development Association, the GoK, the European Investment Bank and Standard Chartered Bank had been fully
disbursed, forcing the company to rely on internally generated funds.
KPLC received KES5.04 billion (USD60 million) from Rand Merchant Bank with an additional KES5.0 billion (USD60 million) secured from
FirstRand Bank earlier this year towards the capital expenditure (capex) plan. The company also expects USD50 million from the
International Finance Corporation (IFC) and KES29.3 billion from the Export-Import Bank of China (China Exim Bank) by the end of the year.
Cabinet’s decision to keep connectivity charges at 2004 levels effectively forces KPLC to continue subsidising connection charges using
borrowed funds thereby compromising capex investment. Should the various options for raising additional revenue not boost revenue
considerably, actual borrowings could be much higher as KPLC struggles to fund investment using retained earnings.
Press reports indicate KPLC had an overdraft of KES5.3 billion in February 2013. We expect the company to continue using overdrafts to
plug funding shortfalls should the company not secure debt funding timeously.
We project total borrowings to increase to around KES 213 billion by FY20 and assume loan tenure of 25 years for any additional borrowings
and interest of 7.25 percent on account of KPLC’s limited debt carrying capacity.
Capital investment
During the past seven years to FY12, KPLC has expanded its DN in pursuit of high quality power supply, lower system losses and additional
capacity for new customer connections, making significant gains towards the country’s Vision 2030 nation-wide electricity access target via
a country-wide supply network covering all 47 counties. These projects have been financed by the USD225.8 million ESRP, the USD102
million World Bank funded KEEP and the KES9.1 billion rights issue undertaken in FY10.
KPLC expects to spend KES80 billion annually on capex over the next five years to be funded by retained earnings and debt. However, efforts
to add 4,066km of transmission lines and 2,421MWA of substations are expected to cost as much as KES109 billion (USD1.241 billion) by
2016E. While we expect KPLC to borrow heavily, with the resulting high financing costs likely affecting liquidity and profitability considerably,
our projections indicate that without the RT adjustment, KPLC would struggle to undertake any significant capex additions as the operational
requirements the company would also have to be supported by debt. We therefore conservatively forecast total capex for the eight year
period to 2020E of around KES271.8 billion.

16
1,000
3,000
5,000
7,000
9,000
11,000
13,000
15,000
25,000
50,000
75,000
100,000
125,000
150,000
175,000
200,000
225,000
250,000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Interest payments Outstanding debt
45,000
52,500
60,000
67,500
75,000
82,500
90,000
0
1,000
2,000
3,000
4,000
5,000
6,000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Revenue Adjusted net income
Figure 24: Additional Debt, KES m Figure 25: Electricity Sales & Adjusted Net Income, KES m
Source: : DBIB estimates Source: DBIB estimates
Performance Outlook
KPLC earns revenue from electricity sales with forex adjustments attributable to the company’s operations reclaimed from consumers.
Other components of the RT are passed on to the GoK, the ERC, the REP and the power generators.
Our projections assume that the RT is maintained at the current level and project KPLC’s electricity sales to grow at CAGR of 9.3 percent, on
account of rising unit sales. However, growing operational costs and substantial borrowings against constrained revenue will likely affect
profitability drastically.
The Tariff Application projects KPLC’s profit before tax to drop to KES3.9 billion in 2013E from KES8.5 billion FY12. We however caution that
this could much lower at around KES1.2 billion, less than half of KPLC’s expectation, and project adjusted net income to decline at a 16.8
negative CAGR between 2012 and 2020E, likely affecting dividend payout.
Based on this, the review of the KPLC’s RT and positive conclusion of the cost-analysis for long distance connections are crucial to mitigating
future decline in KPLC’s performance.
Potential Risks
KPLC’s former Chief Executive Officer (CEO) Joseph Njoroge left in June 2013, with Dr Ben Chumo, the Chief Manager, Human Resources
and Administration taking up the position in an acting capacity. The government’s failure to fill this position seems to have lowered investor
confidence with the company’s share price performing poorly over the past two months, dropping to a 12-month low. This is against the
backdrop of Cabinet’s recent decision to strip off KPLC’s monopoly status and push connection fees back to the commercially unviable level.
While Cabinet’s decision to liberalise power distribution would significantly accelerate nation-wide electricity penetration, this would have
far reaching effects on KPLC’s performance in addition to the present challenges. This, coupled with limited revenues would likely affect
KPLC’s financing costs and ability to contain rising operating costs.
The ERC is charged with enforcing regulations, licensing power companies, facilitating customer protection, approving PPAs and conducting
tariff reviews. The government’s direct rejection of the Tariff Application and Cabinet’s intrusion into matters concerning KPLC’s connectivity
charges question the regulator’s independence and indicate risk of further political interference. Such action, especially with regards to
KPLC’s revenues could further impede the amount that can be generated from electricity sales.
The issues between KPLC and KenGen regarding existing PPAs are yet to be resolved. This could push up power purchase costs further
should the Energy Tribunal rule in favour of KenGen.

17
Hydro
23.0%
Thermal
27.6%
Geothermal
40.1%
Wind
9.3%
Kenya Generating Company Limited
Business Overview
KenGen is a state corporation with GoK shareholding of 70.0 percent and private shareholding of 30.0 percent as at FY12. The company
develops, manages and operates power generation plants to supply electric power to the Kenyan market. KenGen, the largest electricity
bulk supplier in Kenya generates power from hydro, geothermal, thermal and wind sources. The company’s FY12 installed capacity was
1,231MW, representing 72 percent of the country’s total capacity.
KenGen is responsible for the country’s Vision 2030 energy supply targets. Towards this, the company plans to deliver 10,000MW of the
23,000MW energy requirement by 2030E. The LCPDP sets out flagship energy generation projects that are crucial to the Vision 2030 targets,
which envisions the mobilisation of private sector capital in the development of electricity generation projects. KenGen’s appointment of
Barclays Group, KPMG, HHM and Dyer & Blair (together, the Consortium) as adviser to raise KES420 billion (USD5 billion) in 2012 in one
such example. This is also consistent with the provisions in the Energy Act (2006) that seeks to ensure KenGen maintain its financial integrity
thereby attracting capital to fund its operations.
KenGen’s Good-to-Great (G2G) Transformation Strategy established in 2007 aims at reducing costs, expediting development of new
capacity, driving innovation, improving efficiency and increasing employee productivity. The G2G strategy is also a blue print for KenGen’s
attainment of the Vision 2030 objectives in two phases: Horizon 1 Projects (those implemented and commissioned between July 2009 and
June 2013) and Horizon 2 Projects (those between July 2013 and 2019E).
This strategy aims to grow KenGen’s capacity from 1,236MW to 3,000MW by 2018E at an estimated cost of KES450 billion (USD5 billion)
delivering least cost projects, establishing a substantial reserve margin and improving the generation mix thereby enhancing electricity
security.
We project KenGen’s performance in light of phase two of the G2G strategy, capacity additions forecasted in the LCPDP, relevant press
reports and publicly available information on KenGen over the eight year period to 2020E.
Production capacity
The commissioning of the 115MW Kipevu III Power Plant together with other generation facilities in FY12 increased KenGen’s capacity by
7.3 percent to 1,231MW from 1,147MW the previous year.
Figure 26: Generation Mix (2012), % Figure 27: Projected Generation Mix (2020E), %
Source: KenGen Source: LCPDP & DBIB estimates
KenGen, Africa’s largest geothermal producer expects to grow geothermal power’s contribution to generation mix considerably, with the
LCPDP projecting this at 25 percent of total installed capacity by 2030E.
Hydro
66.0%
Thermal
20.8%
Geothermal
12.8%
Wind
0.4%

18
12,500
17,500
22,500
27,500
32,500
37,500
42,500
47,500
52,500
12,500
17,500
22,500
27,500
32,500
37,500
42,500
47,500
52,500
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Revenue Electricity sales
Press reports indicate that completion of Olkaria I & IV commissioned in December 2012 has been fast tracked to April 2014E. This
geothermal power project is expected to add 280MW to the national grid, earning the company KES1.1 billion annually in carbon credits.
Further exploitation of the Olkaria area is expected to continue with KenGen engaging foreign energy firms to develop 585MW of the
1,500MW potential geothermal power in the area by 2016E. The proposed Menengai power plant is expected to add 400MW of electricity
to the national grid by 2017E. We therefore project geothermal generation to contribute about 40 percent of total installed capacity by
2020E from 12.8 percent in FY12, compared to KenGen’s projection of 50 percent geothermal power by 2018E.
KenGen also plans to produce over 100MW of wind power by 2015E with oil and coal deposits providing low-cost thermal energy. The
diversification towards renewable sources will significantly reduce Kenya’s reliance on hydro sources and 120MW of emergency generating
capacity especially during seasons of poor hydrology.
We forecast KenGen’s total installed capacity to grow to about 4,036MW by 2020E from 1,231MW in FY12 (16 percent CAGR) with
renewable power sources contributing about 72 percent of total generation.
Figure 28: Capacity (MW) & Generation (GWh) Figure 29: Revenue & Electricity Sales, KES mn
Source: KenGen & DBIB estimates Source: : KenGen & DBIB estimates
Generated units
KenGen operates in a competitive single-buyer market following the 1996 liberalisation of the power sector. KenGen competes with IPPs,
with the power purchase price (the BST) fixed by PPAs entered into with KPLC. In June 2009, KenGen and KPLC entered into a hybrid 20-
year PPA that fixed the overall yield per unit implied by the five PPAs specific to the different modes of generation to KES2.42/ kWh.
Energy sales are expected to grow on the back of strong demand forecasts, additions to capacity and sustained capacity optimisation. We
therefore forecast net generated units to grow at a CAGR of 10.0 percent during the 2012-2020E period to about 11,745 GWh by 2020E
from 5,497 GWh in FY12.
Electricity sales
KenGen’s electricity sales comprise of capacity revenue and energy revenue which combined contributed 92.3 percent of total KES15.9
billion revenue in FY12. Total revenue comprises electricity sales, revenue from EPP and PPA adjustments to cover forex differences resulting
from foreign-denominated borrowings, which are passed on to KPLC for onward recovery through the RT. KenGen’s PPAs with KPLC restrict
the BST to a pre-agreed level and do not allow increases in the selling price of electricity units despite rising cost of generation, including
the incremental cost of new generation capacity.
While our projections conservatively assume that the average BST remains fixed at KES2.42/kWh during the forecast period, the LCPDP
reiterates that KenGen’s additional capacity would require a review of the RT to ensure that the price is reflective of incremental power
costs. Outstanding issues between KPLC and KenGen regarding the existing PPAs would also need to be resolved, with commercially
acceptable tariffs for the sale of additional power negotiated with KPLC.
We therefore project electricity sales to increase by a CAGR of 15.4 percent from KES14.8 billion in FY12 to KES46.5 billion in 2020E mainly
on account of increased capacity. There is potential for higher sales should the BST be adjusted upward, thereby driving energy revenue as
the fixed price is currently dampening energy revenue despite rising energy demand.
1,000
1,750
2,500
3,250
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Installed capacity Net generated units

19
Capital raising exercise
KenGen’s KES425 billion (USD5 billion) proposed capital raise is the biggest fundraising exercise in Kenya to date. The financing is expected
over a six-year period with the Consortium advising on the most optimal quantum of debt and equity capital to deliver the desired 70
percent debt and 30 percent equity capital structure.
KenGen’s ambitious investment requirement cannot be sufficiently met by public funding or donors. For this reason, the capital raising
exercise is expected to target both local and international debt markets and consider various financing options including syndicated loan,
JVs, PPPs and bonds, with GoK’s majority shareholding proving an implicit credit guarantee.
In FY12, KenGen’s total debt was KES 69.1 billion comprising both market rate and concessionary lending from a variety of institutions
including the Japan Bank for International Cooperation, Agence Francaise de Development, European Investment Bank and Citibank NA.
Interest expenses in FY12 was up 49 percent resulting in a debt-equity ratio of 98.5 percent. This indicates KenGen’s limited capacity to take
on additional debt in the absence of higher tariff or significant revenue flowing from additional income sources such as carbon credits.
We conservatively project the total financing requirement at KES84.3 billion, comprising debt of KES59.3 billion and equity of KES25.0 billion
at the required 70:30 debt-equity ratio on account of a fixed BST during the eight-year period to 2020E. Our projections assume 7.0 percent
interest rate and loan tenure of 25 years. The projected KES63.2 billion financing requirement to 2018E represents only 15 percent of the
capital raise target indicating that KenGen’s successful negotiation of commercially viable tariffs will be key to the overall success of the
proposed capital raising exercise.
Capital expenditure
KenGen’s capacity expansion programme delivered 316MW of the planned 500MW by FY12. An additional 1,500MW of capacity is expected
by 2018E, at an estimated capital investment of KES425 billion for the five-year period to 2018E. The actual requirement could however be
lower depending on the Consortium’s recommendation.
In addition to the various capital intensive Horizon 2 projects, KenGen also plans to ramp up generation capacity by modernizing the Tana
River hydro plants and to construct a KES25 million natural health spa at its Olkaria geothermal fields. Completion of the spa is expected in
February 2014E following KenGen will earn additional revenue from the recreation facility. Based on KenGen’s limited debt carrying
capacity, we project total capex for the period 2013E to 2020E at KES84.7 billion, a conservative estimate that safeguards the company’s
profitability.
Figure 30: Additional Debt, KES m Figure 31: Electricity Sales & Adjusted Net Income, KES m
Performance outlook
KenGen expects to increase earnings six-fold over the next five years on account of additional generation capacity to about KES11.1 billion
by 2017E from KES1.8 billion in FY12. The achievement of this ambitious performance target will be largely dependent on the negotiation
of cost reflective power purchase tariffs, optimal quantum of capital required to support the Horizon 2 expansion plan and competitive
pricing of the additional capital following the capital raising exercise.
KenGen’s revenue comprises electricity sales, PPA adjustments to cater for forex movements and revenue from EPPs. We project total
revenue and adjusted net income to grow at CAGR of 15.4 percent and 26.7 percent respectively between 2012 and 2020E.
2,000
3,000
4,000
5,000
6,000
7,000
8,000
35,000
42,500
50,000
57,500
65,000
72,500
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
1,000
4,000
7,000
10,000
13,000
16,000
19,000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Revenue Adjusted net income

20
Potential Risks
KenGen’s financial performance and debt-carrying capacity is largely determined by electricity sales. The outstanding issues between KPLC
and KenGen regarding existing PPAs will need to be resolved to preserve future revenues. Additionally, negotiation of commercially viable
BST will be crucial to ensuring that the rising cost of generation is sufficiently covered through future PPAs with KPLC.
Additional capital will be key to actualising KenGen’s Horizon 2 targets. However, the KES297.5 billion of potential additional debt implied
by KenGen’s ambitious capital raising exercise could be detrimental to the company’s future financial performance, adding pressure to the
bottom line given its highly leveraged status.
Delays in the commissioning of planned power plants could affect KenGen’s production targets and timelines, driving up construction costs
and exceeding the set budgets. This could also compromise the company’s Vision 2030 energy supply mandate, with far reaching
implications to Kenya’s entire economy.
KenGen’s exploitation of 585MW in Olkaria is expected to push geothermal generation contribution to total capacity to 50 percent by 2018E.
The entry of the GDC and other geothermal IPPs raises competition particularly if the new entrants generate power more cost effectively,
thereby adding pressure on the company to match their pricing.

21
UMEME Limited
Business Overview
UMEME is 60.1 percent owned by UMEME Holdings Limited, a subsidiary of investment fund Actis Infrastructure 2 LP, with eight institutional
investors collectively holding 23.9 percent of UMEME. The remaining 16.0 percent constitutes the free float owned by around 6,000
shareholders.
In 2005, UMEME was awarded a 20-year Concession to distribute and supply electricity in Uganda. UMEME was licensed to manage and
operate UEDCL’s DN which was leased to UMEME under the Concession Agreements. Under the terms of the Concession, any investments
in the DN are rendered intangible assets (rather than fixed assets) and amortised off UMEME’s financial statements. At the end of the
Concession, UMEME is expected to return control of the DN and any new investments to UEDCL in exchange of a buy-out amount equivalent
to 105 percent of the un-depreciated investments.
UMEME’s performance is incentivised through a contractually allowed 20 percent dollar-equivalent return on investment (RoI) and
outperformance of pre-agreed energy loss and collection targets. As such UMEME’s core strategies focus on safety, loss reduction (both
commercial and technical), business efficiency and customer service delivery.
In computing our forecasts, we consider:
 The GoU’s planned capacity additions and energy demand projections.
 Performance targets outlined in UMEME’s Concession Agreement with the REA.
 UMEME’s 1H2013 performance and management’s view of the company’s medium-term performance.
Loss reduction
Following the February 2012 expiry of UMEME’s seven-year performance targets, new targets were set for a subsequent five-year period
ending 2018E. These focus on reducing technical and commercial losses, improving collection rates and maintaining UMEME’s distribution
operation and maintenance costs (DOMC) at pre-agreed levels. The ERA also amended UMEME’s Supply License to allow for automatic tariff
adjustment.
UMEME is regulated by the ERA with the following pre-agreed tariff parameters:
Figure 32: Annualised Regulatory Targets
Source: UMEME
UMEME’s technical losses reduced from 38 percent in 2005 to 26.1 percent in FY12. Ongoing network refurbishment and the completion
of the Lubowa and Waligo substations pushed technical losses further during 1H13 to 24.9 percent against a full year target of 20.8 percent
Management expects further reduction to 14.7 percent by 2018E, a commercially viable threshold during the remaining life of the
Concession. However, UMEME has struggled to reduce energy losses due to the pervasive effects of the DN’s poor condition prior to the
Concession and has consistently missed distribution loss targets set by the ERA despite loss reducing investments in the DN. We therefore
project distribution losses to decline at a slower pace than projected by management, to about 15.9 percent by 2020E.
UMEME’s loss reduction strategy improved cash collection rates from 75 percent in 2005 to 97.0 percent in FY12. 1H13 revenue collection
was 102.7 percent, following the GoU’s payment of outstanding arrears brought about by the FY12 52 percent RT increase. As such,
collection rate exceeding 100 percent would ideally only be expected in the event of further significant tariff increments.
With the exception of FY13, we expect UMEME’s collection rates for the eight-year period to 2020E to closely track the ERA targets,
supported UMEME’s prepayment metering and AMR system roll out, with the uncollected debt level to expected to hold steady at 1.6% by
2020E.
2013E 2014E 2015E 2016E 2017E 2018E
Distribution Losses 20.8% 18.7% 17.3% 16.0% 15.0% 14.7%
DOMC (USD mn) 44.5 45.8 47.3 48.9 50.7 50.7
Uncollected Debt 2.6% 2.4% 2.2% 1.9% 1.6% 1.5%

22
Figure 33: Distribution Losses (Target, Actual & Projected), % Figure 34: Collection Rates (Target, Actual & Projected), %
Source: UMEME & DBIB estimates Source: UMEME & DBIB estimates
Electricity tariffs
Uganda’s electricity tariff is structured to offset total sector costs (i.e. generation, transmission and distribution costs), with UMEME
collecting revenue on behalf of the other sector players. As such, the RT comprises UMEME’s distribution price (DP) and the BST (i.e. the
price that UMEME pays for electricity sold to customers and which represents generation and transmission costs), with the GoU providing
subsidies to thermal generators for capacity payments.
The DP is a function of UMEME’s distribution, operating and maintenance costs (DOMC) and prior year energy sales, grossed up to meet
the uncollected debt target.
The prevailing RT is set by the ERA in accordance with the UMEME’s licences and the Concession Agreements. Annual reviews of the RT
ensure that it reasonably captures total sector costs), mitigates against foreign exchange and inflation effects and provides for UMEME’s 20
percent RoI.
In FY12, the ERA reviewed the RT following high fuel prices, inflationary pressure on the shilling and increased load shedding. The RT review
also removed most of the government subsidies that had been key to maintaining power affordability. This led to a 52 percent increase in
overall end-user tariffs for FY 2012.
We forecast 2012-2020E RT CAGR at 3.5% which assumes marginal increases to the RT to UGX567.8/GWh to cover macro-economic
pressures (inflation, exchange rate and fuel prices) and minor changes to the BST. Our projections further assume that future RT adjustments
will sufficiently cover UMEME’s capex and additional financing requirements, thereby achieving the target RoI of 19 percent over the eight
year period to 2020E.
Figure 35: Projected Tariffs, UGX/kWh Figure 36: Energy Sales, GWh
Source: Uganda’s Energy Report & DBIB estimates Source: : Uganda’s Energy Report & DBIB estimates
Energy Sales
Energy sales are energy purchases less distribution losses resulting from operational inefficiencies in the DN. According to management,
unit sales are expected to continue rising on the back of increasing demand particularly from industrial customers engaged in power-
intensive sectors. Industrial, commercial and GoU customers accounted for 72 percent of the 1,937GWh sold in FY12.
12%
16%
20%
24%
28%
32%
36%
2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Annualised targets Actual & projected losses
0%
3%
5%
8%
10%
2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Annualised targets Actual & projected rates
200
300
400
500
600
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
RT BST
1,500
2,000
2,500
3,000
3,500
4,000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

23
Management expects total industrial load to increase by 171MW between 2012 and 2014E, with four industrial customers expected to
collectively demand an additional 102MW of power per annum.
UMEME’s customer base is also expected to grow from 513,000 in FY12 to one million customers by 2018E, representing a CAGR of 11.7
percent. We forecast energy sales for the 2012-2020E period to increase at a CAGR of 9.4 percent to around 3,987GWh by 2020E.
Capital Expenditure
Before the Concession, UEDCL’s DN was in a state of disrepair following years of financial neglect. The network assets included 60 sub-
stations which were extensively rehabilitated by UMEME during the formative years of the Concession. As at FY12, the DN consisted of
about 25,000km of medium-and low-voltage lines across Uganda. UMEME completed the USD4 million construction of two sub-stations
during 1H13, with an additional 16 sub-stations planned over the next six years.
UMEME’s medium-term capex plan is expected to support growing demand and reduce losses through various projects which include:
 Roll out of prepayment metering for domestic customers and AMR system for industrial customers;
 Replacing of Low Voltage open cables with aerial bundled cables (ABCs); and
 Refurbishing of all Medium Voltage cables to minimise technical losses.
During 1H13, UMEME installed 32,000 of the 50,000 prepayment metres targeted for FY13, with coverage to the entire Kampala region and
the rest of Uganda expected by 2016E and 2018E respectively. This is expected to improve operating efficiency by reducing non-collection,
lowering DOMC, minimising fatalities and improving customer relations.
Total cumulative investment by FY12 was UGX446.7 billion (USD166 million) including undepreciated assets of UGX342.3 billion (USD127
million). UMEME invested UGX98.1 billion (USD36 million) in FY12 and is, expected to invest USD440 million between the 2013E and 2020E.
We therefore forecast total capex for the eight year period to 2020E of UGX1,593.1 billion (USD614.8 million) bringing projected cumulative
investment to UGX1,904.6 billion by 2020E.
Financing
UMEME is currently negotiating a UGX440.5 billion (USD170 million) loan from the IFC, in support of the medium-term capex plan. The
existing IFC loan, which in FY12 was outstanding at UGX 54.8 billion, is expected to be refinanced with only USD152 million coming in as
new debt. We assume a two-year moratorium period on the new loan, interest rate of six months LIBOR + 7 percent and a ten-year loan
term. We therefore project outstanding debt by 2020E at UGX 220.3 billion with the debt-to-equity ratio ranging between 17 percent and
130 percent during the eight-year period.
Figure 37: Additional Debt, UGX bn Figure 38: RoI (%) & Adjusted Net Income (UGX bn)
Return to Shareholders
Under the terms of the Concession, UMEME earns a contractual 20 percent RoI which can fluctuate with performance against the targets
set by ERA. The RoI is measured as the ratio of net income (adjusted for any non-recurring items) and UMEME’s undepreciated asset base
which makes it sensitive to capex and the cost of borrowings.
40
45
50
55
60
65
0
75
150
225
300
375
450
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
0%
8%
15%
23%
30%
38%
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
-
50
100
150
200
250
300
350
400
450
Adjusted net income RoI

24
Based on our capex and financing assumptions, we expect the RoI to exceed the target 19 percent during the eight-year period to 2020E.
Future RT increments will however be necessary to curb against potential RoI erosion should actual capex exceed management’s projected
capex requirements.
Performance Outlook
UMEME collects revenue on behalf of Uganda’s electricity sector. For this reason, revenue does not accurately reflect UMEME’s top line
performance as it includes the cost of sales captured by the BST. Gross profit is therefore a better indicator as it represents UMEME’s
distribution price.
UMEME released strong 1H13 results attributing the 17.6 percent rise in h-o-h revenue to growth in sales units and a 3.6 percent rise in the
average sales price. Reduced energy losses, lower financing costs and tight cost management led to net income growth of 52.8 percent over
the same period.
Figure 39: Gross Profit & Adjusted Net Income, UGX bn
Source: DBIB estimates
UMEME’s performance will be highly dependent on actual capital investment and financing costs during the eight-year period to 2020E.
There however exists potential for solid performance that would deliver the desired 20 percent RoI and maintain dividend payout at 50
percent for the medium-term. As such, we project gross profit and adjusted net income to grow at CAGR of 19.4 percent and 30.7 percent
respectively between 2012 and 2020E on the back of increasing electricity sales, the ERA approved loss reduction strategy, improved
efficiency following DN investments and tight internal cost management.
Potential Risks
As a highly regulated utility company, UMEME faces a number of risks particularly from unfavourable regulatory action or political
interference. UMEME’s Concession however provides a number of safeguards against this, entrenched in the following concession
agreements:
i. Lease and Assignment Agreement: This is between UMEME and UEDCL and covers UMEME’s management of UEDCL assets by laying
out UMEME’s leasehold interest in the DN and any other UEDCL property utilised electricity distribution. Under this agreement, an
amount equivalent to the minimum of USD20 million or four-times UMEME’s DOMC is in escrow and provides recourse in the event of
non-payment by GoU entities. The escrow account also provides protection against negative regulatory action such as ERA’s failure to
approve RT applications and financial effects of disallowed amounts within tariff or investment submissions.
ii. Power Sales Agreement: This is between UMEME and UETCL and provides the framework for power purchase. It offers UMEME recourse
should the BST increase by over 10 percent of the RT during a given year by allowing UMEME to recoup losses from the BST (i.e. amounts
payable for power supply). It also provides for the BST to be withheld in the event of GoU non-payment.
200
400
600
800
1,000
0
100
200
300
400
500
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Gross profit Adjusted net income

25
iii. Support Agreement: This is between UMEME and the GoU and regulates this relationship with regards to UMEME’s management,
operation and maintenance of the DN. This agreement provides protection in the event of any negative amendments to UMEME’s
licenses or Concession framework. A key provision of the Support Agreement is the structuring of the Buy Out Amount following the
expiry of the 20-year Concession.
iv. License for Supply and Distribution: This license from the ERA lays out UMEME’s obligations as licensee and the tariff setting process
including the pre-determined but negotiable targets on distribution losses, uncollected debt and DOMC. UMEME objected ERA’s
amendment of the tariff methodology in FY12 and is seeking recourse through the Electricity Disputes Tribunal. On 5 August, the ERA
informed UMEME of the planned implementation of Amendment No. 4 to UMEME’s License for the Supply of Electricity. UMEME had
not yet responded to the ERA’s planned action at the time of writing this report.
High commercial and technical losses continue to challenge UMEME’s operations. While various in-house efforts are underway to curb
these through heavy investment in the DN, legislation should be tightened to curb the rampant electricity theft and vandalism.

26
Valuation and Performance
DCF Valuation
Our standard approach to value power sector companies is to use a DCF valuation, as we believe this is the most effective way to capture
inherent growth opportunities in the power sector such as government-backed capacity additions and prevailing electricity prices. Based
on this approach, we summarise our estimate of the target price (TP), potential upside/downside, recommendation and the key value
drivers we expect to impact KPLC, KenGen and UMEME going forward.
Figure 40: DCF Valuation & Recommendation Figure 41: Key DCF Valuation Assumptions
Source: DBIB estimates Source: CBK, BoU, Damodaran Betaemerge & DBIB estimates
We expect sustained growth in sales and improved system efficiencies to contribute significantly to the companies’ performance during the
eight-year forecast period. However, potential for strong performance is heavily dependent on potential amendments to electricity tariffs
during the forecast period and the following outstanding matters:
‒ The outcome of future RT reviews by the ERC and the implementation of KPLC’s connections’ cost-analysis recommendations;
‒ Negotiation of commercially viable BST for KenGen’s sale of additional power to KPLC and the resolution of outstanding PPA issues; and
‒ The EDT’s decision following UMEME’s objection to ERA’s amendment of the tariff methodology in FY12.
Figure 42: KPLC’s DCF Valuation, KES ‘000
Source: NSE, CBK & DBIB estimates
Company TP
Current Price
(Aug 20)
Potential (%) Rating
KPLC KES 12.90 KES 14.40 -10% Sell
KenGen KES 16.80 KES 16.90 -1% Hold
UGX 420 UGX 360 8% Buy
KES 14.00 KES 13.00 17% Buy
UMEME
Company KPLC KenGen UMEME
2013E-2020EGrowth Assumptions
Unit sales (CAGR) 8.87% 11.58% 9.14%
Yield per units sold (CAGR) 3.01% 0.00% 3.50%
System losses (average) 16.46% 1.22% 16.47%
WACC Assumptions
Risk free rate 12.70% 12.70% 14.70%
Market risk premium 6.00% 6.00% 7.00%
Relevered beta 0.65 0.88 0.80
Cost ofequity 17.08% 20.80% 19.50%
After tax cost ofdebt 5.19% 5.88% 5.06%
WACC 11.91% 12.99% 17.37%
June June June June June June June June
2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
EBIT 7,721,572 12,204,742 14,546,302 14,840,005 14,887,748 15,671,452 16,719,078 18,915,940
Tax on EBIT (2,316,472) (3,661,422) (4,363,891) (4,452,001) (4,466,325) (4,701,436) (5,015,724) (5,674,782)
Operating cash flow 5,405,101 8,543,319 10,182,411 10,388,003 10,421,424 10,970,016 11,703,355 13,241,158
Depreciation expense and amortisation 6,887,975 8,275,776 9,595,661 11,189,311 12,674,404 13,860,485 14,734,118 15,339,832
Working capital movement (18,140,178) (1,710,038) (929,882) (357,942) (246,932) (371,240) (352,361) (590,440)
Net capital expenditure (28,219,425) (28,562,362) (34,094,016) (34,017,565) (30,902,460) (27,281,655) (24,033,462) (20,653,303)
Free Cash Flow to Firm (FCFF) (34,066,527) (13,453,304) (15,245,825) (12,798,192) (8,053,563) (2,822,394) 2,051,649 7,337,246
Discount period (years) (0.14) 0.86 1.86 2.86 3.86 4.86 5.86 6.87
WACC 11.91%
Present value factor 1.02 0.91 0.81 0.72 0.65 0.58 0.52 0.46
PV ofFCFF (34,606,243) (12,212,332) (12,366,979) (9,274,073) (5,214,984) (1,633,148) 1,060,850 3,389,169
Enterprise Value 91,112,864
Net debt/(cash) 65,954,151
Equity value 25,158,713
Fair value per share (KES) 12.90
Fair value per share (USȻ) 14.74
Current share price (KES) 14.40
Current share price (USȻ) 16.45
Potential downside to current share price -10%

27
Figure 43: KenGen’s DCF Valuation, KES ‘000
Source: NSE, CBK & DBIB estimates
Figure 44: UMEME’s DCF Valuation, UGX mn
Source: USE, BOU & DBIB estimates
June June June June June June June June
2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
EBIT 8,765,802 12,005,734 14,390,506 16,655,621 17,853,914 20,763,766 23,822,911 28,701,458
Tax on EBIT (2,629,741) (3,601,720) (4,317,152) (4,996,686) (5,356,174) (6,229,130) (7,146,873) (8,610,438)
Operating cash flow 6,136,062 8,404,014 10,073,354 11,658,935 12,497,740 14,534,636 16,676,038 20,091,021
Depreciation expense and amortisation 5,117,780 5,386,697 5,655,224 5,917,759 6,436,735 6,590,273 7,077,526 7,400,986
Other gains and losses 245,273 245,273 245,273 245,273 245,273 245,273 245,273 -
Working capital movement 4,154,952 (2,146,894) (1,540,452) (1,537,375) (943,860) (1,849,865) (2,013,435) (3,265,781)
Net capital expenditure (8,403,657) (8,391,472) (8,204,231) (16,218,000) (4,798,050) (15,226,640) (10,108,149) (13,361,756)
Free Cash Flow to Firm (FCFF) 7,005,137 3,252,345 5,983,895 (178,680) 13,192,566 4,048,404 11,631,979 10,864,470
Discount period (years) (0.14) 0.86 1.86 2.86 3.86 4.86 5.86 6.87
WACC 12.99%
PV ofFCFF 7,125,687 2,928,015 4,767,900 (125,962) 8,231,143 2,235,534 5,684,830 4,697,790
Enterprise Value 188,119,968
Net debt/(cash) 67,077,856
Borrowings 67,595,493
Bank overdraft -
Cash and equivalents 517,637
Equity value 121,042,112
Fair value per share (USȻ) 19.19
Current share price (KES) 16.90
Current share price (USȻ) 19.31
Potential downside to current share price -0.6%
December December December December December December December December
2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
EBIT 115,450 160,497 210,905 285,746 362,696 441,662 538,837 647,132
Tax on EBIT (34,635) (48,149) (63,271) (85,724) (108,809) (132,499) (161,651) (194,140)
Operating cash flow 80,815 112,348 147,633 200,022 253,887 309,164 377,186 452,993
Depreciation expense and amortisation 26,444 34,267 45,462 62,748 79,817 93,755 107,970 123,465
Working capital movement (90,556) 8,931 (13,831) 37,249 (23,758) (28,340) (61,494) (105,591)
Net capital expenditure (109,414) (156,575) (241,767) (238,718) (194,941) (198,815) (216,709) (236,213)
Free Cash Flow to Firm (FCFF) (92,711) (1,029) (62,502) 61,301 115,005 175,763 206,954 234,654
Discount period (years) 0.36 1.36 2.36 3.37 4.37 5.37 6.37 7.37
WACC 17.37%
PV ofFCFF (87,457) (827) (42,803) 35,754 57,152 74,422 74,663 72,100
Enterprise Value 818,628
Net debt/(cash) 137,049
Equity value 681,578
Fair value per share (UGX) 420.00
Fair value per share (UGX to USȻ) 16.21
Fair value per share (KES to USȻ)
USECurrent share price (UGX) 360.00
USECurrent share price (USȻ) 13.89
Potential upside to current share price_UGX 17%
Potential upside to current share price_KES 8%
NSECurrent share price (KES) 13.00
NSECurrent share price (USȻ) 43.93

28
Interest rate sensitivity
KPLC, KenGen and UMEME plan to partly finance their respective capex plans using additional borrowings. We project interest rates on
additional borrowings during the forecast period at 7.25 percent, 7.00 percent and six months LIBOR + 7 percent for the three companies
respectively. We perform a sensitivity analysis on additional borrowings, to assess the effect of varying interest rates on their respective fair
value.
Figure 45: Sensitivity Analysis of Interest Rates on Additional Borrowings
The sensitivity analysis indicates that the pricing of the additional borrowings is especially significant for KPLC’s fair value, causing the TP to
range from KES1.70-27.10/share, a 176 percent differential.
Trading Multiples
KPLC, KenGen and UMEME are the only listed power sector companies in East Africa limiting our universe of potential comparables. Using
calendarised financials for the three companies, we compare their respective Enterprise Value to EBITDA4
(EV/EBITDA) and Price to Equity
(P/E) multiples.
Figure 46: Peer Companies Multiples
The trading multiples valuation broadly supports our DCF valuation of the three companies, particularly for UMEME which appears to be
trading at a discount on both metrics for 2013E and 2014E, which thereby justifies our BUY rating.
4
Earnings before interest, tax, depreciation and amortisation
KPLC
4.25% 5.25% 6.25% 7.25% 8.25% 9.25% 10.25%
Fair value, KES/share 27.10 21.95 17.25 12.90 8.90 5.20 1.70
Potential upside/downside 88% 52% 20% -10% -38% -64% -88%
Interest rate
KenGen
4.00% 5.00% 6.00% 7.00% 8.00% 9.00% 10.00%
Fair value, KES/share 18.60 18.00 17.40 16.80 16.25 15.75 15.25
Potential upside/downside 10% 7% 3% -1% -4% -7% -10%
Interest rate
UMEME
6-month LIBOR + 4.00% 5.00% 6.00% 7.00% 8.00% 9.00% 10.00%
Fair value, UGX/share 427.00 425.00 422.00 420.00 417.00 415.00 412.00
Potential upside/downside 19% 18% 17% 17% 16% 15% 14%
Interest rate
2013E 2014E 2013E 2014E
KPLC 6.97x 6.42x 9.72x 11.10x
Average for peers 6.74x 5.39x 12.84x 9.84x
KenGen 8.39x 6.80x 16.70x 12.98x
UMEME 5.09x 3.99x 8.99x 6.70x
EV/EBITDA, x P/E, x

29
Share Price Performance
KPLC’s price has been declining over the 52-week period (21 August 2012 to 20 August 2013) following political interference and negative
regulatory action, despite a strong three month stint beginning August 2012 during which the stock outperformed both Kenya and Uganda
equity markets as proxied by the NSE20 Share Index (the NSE20) and the USE All Share Index (the UGSINDX). The company’s 1H12 results
were positive, with electricity sales growing by 5.39 percent and net income 35.61 percent. Between December 2012 and January 2013,
KPLC’s share price largely tracked the NSE20 but the stock’s performance took a downturn in February 2013 following the government’s
rejection of the Tariff Application. The stock was dealt a second blow in July 2013 when the Cabinet voted to liberalize power distribution.
As a result, the share price dropped by 10.0 percent from KES 16.00 to KES 14.40 during the period.
KenGen was the top performer of the three companies during the review period. The price appreciated by 102.4 percent, from KES8.35 to
KES16.90 outpacing both the NSE20 and the UGSINDX respectively significantly. Despite low trading price for most of 2012, KenGen’s
positive 1H12 results in which revenue and net profit grew by 7.99 percent and 11.34 percent respectively drove its price up considerably,
with increased investor confidence also attributed to power station upgrades, capacity expansion and the appointment of the Consortium
to advise on KenGen’s USD5 billion capital raising exercise.
UMEME listed on the USE on 30th November 2013 and has to date lagged behind the UGSINDX while outperforming the NSE20. The stock
gained 30.91 percent from UGX275 to UGX360 compared to the UGSINDX and NSE20 which appreciated by 40.72 percent and 27.10 percent
respectively. UMEME’s trading on the USE is erratic relative to its Kenyan peers which trade consistently. UMEME’s first and only transaction
on the NSE was the 31 July trading of 1,000 shares following the launch of the Regional Inter-depository Transfer Mechanism (RITM), the
electronic platform linking Kenya’s Central Depository & Settlement Corporation (CDSC) and Uganda’s Securities Central Depository (SCD).
The shares traded at KES 13.00, a 30 percent gain from the Kenyan IPO price of KES 10.00 during this inaugural trading session.
Figure 47: Peer Companies Price Performance, 52 Weeks
Base = 3,808.47, NSE20 on 20 Aug 2012
1,500
2,500
3,500
4,500
5,500
6,500
7,500
8,500
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
NSE20 UDSINDX KPLL KEGC UMEME

30
Figure 48: Peer Companies Price Performance, 30 Nov 2012 to date
Base = 4,083.52, NSE20 on 30 Nov 2012
1,500
2,500
3,500
4,500
5,500
6,500
7,500
8,500
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
NSE20 UGSINDX KPLL KEGC UMEME

31
Appendix
Figure 49: KPLC Income Statement, KES ‘000
Source: KPLC & DBIB estimates
Figure 50: KPLC Balance Sheet, KES ‘000
June June June June June June June June June
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
INCOMESTATEMENT
Revenue 95,662,427 104,628,006 136,109,484 149,206,624 150,384,513 149,088,523 149,750,861 149,672,850 153,099,340
yoy 30.8% 9.4% 30.1% 9.6% 0.8% -0.9% 0.4% -0.1% 2.3%
Power Purchase Costs (69,962,179) (75,281,555) (96,360,305) (103,800,665) (102,801,073) (100,002,915) (98,406,879) (96,185,337) (96,019,982)
yoy 40.5% 7.6% 28.0% 7.7% -1.0% -2.7% -1.6% -2.3% -0.2%
GrossProfit 25,700,248 29,346,450 39,749,179 45,405,959 47,583,440 49,085,608 51,343,982 53,487,513 57,079,358
yoy 10.0% 14.2% 35.4% 14.2% 4.8% 3.2% 4.6% 4.2% 6.7%
Gross profit margin 26.9% 28.0% 29.2% 30.4% 31.6% 32.9% 34.3% 35.7% 37.3%
Operating Expenses (15,116,188) (16,829,463) (22,331,124) (24,994,162) (25,689,698) (25,996,111) (26,678,948) (27,272,867) (28,564,812)
yoy 9.2% 11.3% 32.7% 11.9% 2.8% 1.2% 2.6% 2.2% 4.7%
Other Income 1,788,118 2,092,560 3,062,463 3,730,166 4,135,574 4,472,656 4,866,903 5,238,550 5,741,225
yoy 26.6% 17.0% 46.4% 21.8% 10.9% 8.2% 8.8% 7.6% 9.6%
Other income % Revenue 1.9% 2.0% 2.25% 2.50% 2.75% 3.00% 3.25% 3.50% 3.75%
EBITDA 12,372,178 14,609,547 20,480,518 24,141,963 26,029,316 27,562,153 29,531,936 31,453,196 34,255,772
yoy 13.2% 18.1% 40.2% 17.9% 7.8% 5.9% 7.1% 6.5% 8.9%
Total depreciation and amortisation (4,563,658) (6,887,975) (8,275,776) (9,595,661) (11,189,311) (12,674,404) (13,860,485) (14,734,118) (15,339,832)
yoy 18.6% 50.9% 20.1% 15.9% 16.6% 13.3% 9.4% 6.3% 4.1%
EBIT 7,808,520 7,721,572 12,204,742 14,546,302 14,840,005 14,887,748 15,671,452 16,719,078 18,915,940
yoy 10.3% -1.1% 58.1% 19.2% 2.0% 0.3% 5.3% 6.7% 13.1%
Net finance revenue/costs 698,173 (6,061,033) (6,634,917) (8,205,776) (10,219,501) (11,776,036) (13,215,294) (14,431,252) (15,429,711)
yoy -184.4% -968.1% 9.5% 23.7% 24.5% 15.2% 12.2% 9.2% 6.9%
Profit Before Tax 8,506,693 1,660,540 5,569,825 6,340,526 4,620,504 3,111,713 2,456,158 2,287,826 3,486,229
yoy 36.0% -80.5% 235.4% 13.8% -27.1% -32.7% -21.1% -6.9% 52.4%
Income tax (3,889,577) (498,162) (1,670,948) (1,902,158) (1,386,151) (933,514) (736,847) (686,348) (1,045,869)
Effective tax rate 30% 30% 30% 30% 30% 30% 30% 30% 30%
Adjusted Net Income 4,617,116 1,162,378 3,898,878 4,438,368 3,234,353 2,178,199 1,719,310 1,601,478 2,440,360
yoy 9.4% -74.8% 235.4% 13.8% -27.1% -32.7% -21.1% -6.9% 52.4%
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Non-current Assets
Property and equipment 105,671,370 127,022,156 147,328,078 171,845,769 194,693,359 212,940,750 226,381,257 235,699,937 241,032,744
Prepaid leases on land 131,709 131,654 131,599 131,544 131,489 131,434 131,379 131,324 131,269
Deffered tax - - - - - - - - -
Fixed interest investment - - - - - - - - -
Intangible assets 169,520 150,239 130,958 111,677 92,396 73,115 53,834 34,553 15,272
Unquoted investment - - - - - - - - -
Non-current Assets 105,972,599 127,304,049 147,590,635 172,088,990 194,917,244 213,145,299 226,566,470 235,865,814 241,179,285
yoy 23.2% 20.1% 15.9% 16.6% 13.3% 9.4% 6.3% 4.1% 2.3%
Current Assets
Inventories 10,286,376 12,375,050 15,840,050 17,063,123 16,898,807 16,438,835 16,176,473 15,811,288 15,784,107
yoy 14.8% 20.3% 28.0% 7.7% -1.0% -2.7% -1.6% -2.3% -0.2%
Trade and other receivables 14,211,800 17,199,124 22,374,162 24,527,116 24,720,742 24,507,702 24,616,580 24,603,756 25,167,015
yoy -12.7% 21.0% 30.1% 9.6% 0.8% -0.9% 0.4% -0.1% 2.3%
Tax recoverable - - - - - - - - -
Investment in government securities 1,171,109 1,171,109 1,171,109 1,171,109 1,171,109 1,171,109 1,171,109 1,171,109 1,171,109
Short term deposits 506,168 506,168 506,168 506,168 506,168 506,168 506,168 506,168 506,168
Cash and bank balances 1,983,931 207,277 6,770,914 6,583,991 13,576,746 18,158,902 25,518,767 33,889,223 43,790,735
Cash and bank balances % oftotal borrowings 7.1% 0.3% 7.4% 5.8% 9.6% 11.2% 14.0% 17.0% 20.5%
Current Assets 28,159,384 31,458,728 46,662,403 49,851,507 56,873,571 60,782,717 67,989,097 75,981,544 86,419,133
yoy -19.9% 11.7% 48.3% 6.8% 14.1% 6.9% 11.9% 11.8% 13.7%
Total Assets 134,131,983 158,762,777 194,253,038 221,940,497 251,790,815 273,928,016 294,555,567 311,847,358 327,598,419

32
Figure 51: KPLC Balance Sheet, KES ‘000 (Cont’d)
Figure 52: KPLC Cash Flow Statement, KES ‘000
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Non-current Liabilities
Deferred tax 9,496,455 9,496,455 9,496,455 9,496,455 9,496,455 9,496,455 9,496,455 9,496,455 9,496,455
yoy 46.1% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Trade and other payables 15,823,485 12,375,050 15,840,050 17,063,123 16,898,807 16,438,835 16,176,473 15,811,288 15,784,107
Borrowings 21,512,025 52,000,725 71,606,297 88,506,577 110,171,481 126,917,646 142,402,081 155,484,117 166,226,152
yoy 8.9% 141.7% 37.7% 23.6% 24.5% 15.2% 12.2% 9.2% 6.9%
Non-current borrowings % total borrowings 77.49% 78.00% 78.00% 78.00% 78.00% 78.00% 78.00% 78.00% 78.00%
Preferences shares 43,000 43,000 43,000 43,000 43,000 43,000 43,000 43,000 43,000
Deferred income 12,362,327 12,362,327 12,362,327 12,362,327 12,362,327 12,362,327 12,362,327 12,362,327 12,362,327
59,237,292 86,277,557 109,348,129 127,471,482 148,972,070 165,258,263 180,480,337 193,197,187 203,912,040
Current Liabilities
Trade and other payables 21,990,795 12,375,050 15,840,050 17,063,123 16,898,807 16,438,835 16,176,473 15,811,288 15,784,107
yoy -0.9% -43.7% 28.0% 7.7% -1.0% -2.7% -1.6% -2.3% -0.2%
Tax payable 37,886 37,886 37,886 37,886 37,886 37,886 37,886 37,886 37,886
Deferred income - - - - - - - - -
Retirement benefits obligation - - - - - - - - -
Provision for leave pay 989,378 989,378 989,378 989,378 989,378 989,378 989,378 989,378 989,378
Total borrowings 7,939,895 14,666,871 20,196,648 24,963,394 31,074,008 35,797,285 40,164,690 43,854,494 46,884,299
Dividends payable on ordinary shares 425,184 425,184 425,184 425,184 425,184 425,184 425,184 425,184 425,184
Dividends payable (7.85% preference shares) - - - - - - - - -
31,383,138 28,494,369 37,489,146 43,478,965 49,425,262 53,688,568 57,793,611 61,118,231 64,120,854
Total Liabilities 90,620,430 114,771,926 146,837,275 170,950,447 198,397,332 218,946,832 238,273,947 254,315,417 268,032,894
Equity
Ordinary share capital 4,878,668 4,878,668 4,878,668 4,878,668 4,878,668 4,878,668 4,878,668 4,878,668 4,878,668
Redeemable preference share capital - - - - - - - - -
Share premium 22,021,219 22,021,219 22,021,219 22,021,219 22,021,219 22,021,219 22,021,219 22,021,219 22,021,219
Reserves 16,611,667 17,090,964 20,515,877 24,090,163 26,493,596 28,081,298 29,381,733 30,632,054 32,665,638
Total Equity 43,511,553 43,990,851 47,415,764 50,990,050 53,393,483 54,981,185 56,281,620 57,531,941 59,565,525
Total Liabilitiesand Equity 134,131,983 158,762,778 194,253,038 221,940,497 251,790,815 273,928,016 294,555,567 311,847,358 327,598,419
2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
Operating Activities
Net income 4,617,116 1,162,378 3,898,878 4,438,368 3,234,353 2,178,199 1,719,310 1,601,478 2,440,360
Depreciation & Amortisation 4,563,658 6,887,975 8,275,776 9,595,661 11,189,311 12,674,404 13,860,485 14,734,118 15,339,832
Working capital adjustments (3,292,620) (18,140,178) (1,710,038) (929,882) (357,942) (246,932) (371,240) (352,361) (590,440)
Net cash from operating activities 11,853,074 (10,089,825) 10,464,616 13,104,147 14,065,722 14,605,672 15,208,556 15,983,235 17,189,752
Investing Activities
Purchase ofproperty and equipment (23,969,485) (28,219,425) (28,562,362) (34,094,016) (34,017,565) (30,902,460) (27,281,655) (24,033,462) (20,653,303)
Acquisition ofintangible assets 188,801 - - - - - - - -
Customer capital contributions -
Investment in government securities (1,171,109) - - - - - - - -
Proceed from disposal ofPPE 23,295 - - - - - - - -
Net cash from investing activities (24,928,498) (28,219,425) (28,562,362) (34,094,016) (34,017,565) (30,902,460) (27,281,655) (24,033,462) (20,653,303)
Financing Activities
Dividends paid (494,271) (683,080) (473,965) (864,082) (830,920) (590,497) (418,875) (351,157) (406,777)
Proceeds from issue ofnew shares - - - - - - - - -
Restructuring costs (20,785) - - - - - - - -
Net borrowings 5,095,308 38,905,283 25,135,349 21,667,027 27,775,518 21,469,442 19,851,840 16,771,840 13,771,840
Net cash from financing activities 4,580,252 38,222,203 24,661,383 20,802,945 26,944,598 20,878,945 19,432,965 16,420,683 13,365,063
Net (decrease)/increase in cash and cash (8,495,172) (87,047) 6,563,638 (186,923) 6,992,755 4,582,157 7,359,865 8,370,455 9,901,512

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