Download - 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

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NSE20 UGSINDX KPLC KenGen UMEME

StockBloomberg

Ticker

Current Price

(Aug 20)

Current Mkt

CapFair Price

Upside

(downside)Rating

2013E

EV/EBITDA2013E P/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 UMEM UG Equity UGX 360 UGX 584,596.1m UGX 420 8% Buy

KES 13.00 KES 21,110.4m KES 14.00 17% Buy5.09x 8.99x

Power Sector Report East Africa

23 August 2013

Julie Kariuki [email protected]

Eric Ngure [email protected]

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.

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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

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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.

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0.0%

1.5%

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2006 2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Kenya Uganda

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2006 2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020EKenya 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

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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

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Total = 1,708MW Total = 819MW

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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

Hydro50.7%

Thermal30.5%

Geothermal14.8%

Cogeneration2.7%

Wind1.3%

Large hydro77.0%

Mini hydro6.9%

HFO thermal12.2%

Diesel generators0.3%

Biomass 3.6%

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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

GenerationProject

Expected

Power (MW)Current Status

Commissioning

Date

Olkaria I 140 Ongoing End of 2013

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 PlantCapacity

(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 2014FIT Hydros 21 July 2015

Thika Power 87 June 2013

Gulf Power 85 February 2014

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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

BuserukaKakira

Kinyara 40

Kikagati 16Kabaale (Gas & Test Crude) 53

Kabale Peat 20 - 40Nyamwamba 14

Muzizi 26Nyagak 3 4.5

Karuma 600

Isimba 188Nshungyezi 40

Ayago 600

GEN

ERA

TIO

N P

LAN

TS

Total additional capacity increase: 1,994MW - 2,014MW

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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.

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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).

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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.

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1,000

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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


Hydro23.0%

Thermal27.6%

Geothermal 40.1%

Wind9.3%

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.

Key Business Drivers 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.

Hydro66.0%

Thermal20.8%

Geothermal 12.8%

Wind0.4%

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.

Key Business Drivers 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

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RT BST

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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.

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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.

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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 TPCurrent 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% BuyUMEME

Company KPLC KenGen UMEME

2013E - 2020E Growth 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 of equity 17.08% 20.80% 19.50%

After tax cost of debt 5.19% 5.88% 5.06%

WACC 11.91% 12.99% 17.37%

June June June June June June June June2013E 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 of FCFF (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 June2013E 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 of FCFF 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 December2013E 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 of FCFF (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)

USE Current share price (UGX) 360.00

USE Current share price (USȻ) 13.89

Potential upside to current share price_UGX 17%

Potential upside to current share price_KES 8%

NSE Current share price (KES) 13.00

NSE Current 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


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Figure 48: Peer Companies Price Performance, 30 Nov 2012 to date Base = 4,083.52, NSE20 on 30 Nov 2012


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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 June2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

INCOME STATEMENT

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%

Gross Profit 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%


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 % of total 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



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 Liabilities and 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


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 of property 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 of intangible assets 188,801 - - - - - - - -

Customer capital contributions -

Investment in government securities (1,171,109) - - - - - - - -

Proceed from disposal of PPE 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 of new 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

33


Figure 53: KenGen Income Statement, KES ‘000

Source: KenGen & DBIB estimates

Figure 54: KenGen Balance Sheet, KES ‘000



Revenue 15,999,078 19,345,120 24,329,112 27,903,688 31,474,637 33,667,567 37,967,460 42,647,696 50,239,973

yoy 11.19% 20.91% 25.76% 14.69% 12.80% 6.97% 12.77% 12.33% 17.80%

Electricity Sales 14,773,521 17,893,414 22,513,595 25,828,244 29,134,813 31,168,745 35,149,084 39,480,970 46,504,387

yoy 10.01% 21.12% 25.82% 14.72% 12.80% 6.98% 12.77% 12.32% 17.79%

Power Purchase Agreement's Adjustments 1,098,590 1,337,821 1,670,782 1,920,725 2,188,521 2,353,662 2,677,696 3,031,187 3,602,486

yoy 22.42% 21.78% 24.89% 14.96% 13.94% 7.55% 13.77% 13.20% 18.85%

Revenue from EPP 126,967 113,885 144,735 154,718 151,303 145,160 140,680 135,539 133,101

yoy 101.71% -10.30% 27.09% 6.90% -2.21% -4.06% -3.09% -3.65% -1.80%

Operating Expenses (5,382,785) (6,287,164) (7,911,827) (8,940,342) (10,090,769) (10,632,218) (11,997,717) (13,271,963) (15,644,728)

yoy -0.91% 16.80% 25.84% 13.00% 12.87% 5.37% 12.84% 10.62% 17.88%

Other Income 484,632 580,354 729,873 837,111 944,239 1,010,027 1,139,024 1,279,431 1,507,199

yoy 70.59% 19.75% 25.76% 14.69% 12.80% 6.97% 12.77% 12.33% 17.80%

EBITDA 10,948,114 13,883,582 17,392,431 20,045,730 22,573,381 24,290,650 27,354,039 30,900,437 36,102,445

yoy 13.09% 26.81% 25.27% 15.26% 12.61% 7.61% 12.61% 12.96% 16.83%

Total Depreciation and amortisation (4,883,237) (5,117,780) (5,386,697) (5,655,224) (5,917,759) (6,436,735) (6,590,273) (7,077,526) (7,400,986)

yoy 6.59% 4.80% 5.25% 4.99% 4.64% 8.77% 2.39% 7.39% 4.57%

EBIT 6,064,877 8,765,802 12,005,734 14,390,506 16,655,621 17,853,914 20,763,766 23,822,911 28,701,458

yoy 18.94% 44.53% 36.96% 19.86% 15.74% 7.19% 16.30% 14.73% 20.48%

Net Finance Costs (2,019,687) (6,440,025) (6,155,301) (6,122,213) (6,206,648) (5,650,959) (4,755,299) (3,567,605) (1,908,252)

yoy 39.48% 218.86% -4.42% -0.54% 1.38% -8.95% -15.85% -24.98% -46.51%

Profit Before Tax 4,045,190 2,325,777 5,850,433 8,268,293 10,448,973 12,202,955 16,008,467 20,255,306 26,793,207

yoy 10.79% -42.51% 151.55% 41.33% 26.37% 16.79% 31.19% 26.53% 32.28%

Adjusted Net Income 2,822,600 1,628,044 4,095,303 5,787,805 7,314,281 8,542,069 11,205,927 14,178,714 18,755,245

yoy 35.69% -42.32% 151.55% 41.33% 26.37% 16.79% 31.19% 26.53% 32.28%


Non-current Assets

Property, Plant and Equipment 120,664,699 123,999,744 127,053,688 129,651,864 140,001,273 138,411,756 147,097,292 150,177,084 156,187,023

Prepaid leases on land 35,426 34,480 33,535 32,589 31,644 30,698 29,752 28,807 27,861

Intangible assets 896,335 848,112 799,889 751,666 703,442 655,219 606,996 558,773 510,550

Amount due from Kenya Power_Deferred debt 1,401,133 1,960,922 2,467,243 2,830,493 3,192,856 3,415,753 3,851,954 4,326,682 5,096,371

Treasury bonds 8,050,919 8,050,919 8,050,919 8,050,919 8,050,919 8,050,919 8,050,919 8,050,919 8,050,919

Recoverable foreign exchange adjustment 9,808,295 9,808,295 9,808,295 9,808,295 9,808,295 9,808,295 9,808,295 9,808,295 9,808,295

Non-current Assets 140,856,807 144,702,473 148,213,569 151,125,825 161,788,429 160,372,640 169,445,209 172,950,560 179,681,020

Current Assets

Inventories 1,955,564 620,104 780,665 896,282 1,012,017 1,083,634 1,223,280 1,375,476 1,621,994

Amount due from Kenya Power 7,221,777 3,180,020 3,999,306 4,586,908 5,173,913 5,534,395 6,241,226 7,010,580 8,258,626

Other receivables 6,077,151 3,180,020 3,999,306 4,586,908 5,173,913 5,534,395 6,241,226 7,010,580 8,258,626

Amount due from Ministry of Energy 5,318,021 5,318,021 5,318,021 5,318,021 5,318,021 5,318,021 5,318,021 5,318,021 5,318,021

Treasury bonds 643,203 643,203 643,203 643,203 643,203 643,203 643,203 643,203 643,203

Recoverable foreign exchange adjustment 405,477 405,477 405,477 405,477 405,477 405,477 405,477 405,477 405,477

Corporate tax recoverable 231,154 231,154 231,154 231,154 231,154 231,154 231,154 231,154 231,154

Total cash and bank balances 435,719 517,637 198,520 253,274 634,271 8,693,811 810,505 1,670,768 10,468,488

Current Assets 22,288,066 14,095,635 15,575,651 16,921,226 18,591,969 27,444,089 21,114,093 23,665,259 35,205,589

Total Assets 163,144,873 158,798,108 163,789,220 168,047,051 180,380,398 187,816,729 190,559,302 196,615,819 214,886,608


Borrowings 61,850,220 60,835,944 62,411,800 61,778,170 67,275,629 56,417,096 50,567,050 45,473,004 36,558,212

Operating lease liability 5,000 3,000 1,000 - - - - - -

Retirement benefits liability 93,500 286,100 286,100 286,100 286,100 286,100 286,100 286,100 286,100

Deferred tax liability 16,015,642 16,015,642 16,015,642 16,015,642 16,015,642 16,015,642 16,015,642 16,015,642 16,015,642

Prepaid operating lease - - - - - - - - -

Funds awaiting allotment of shares - - - - - - - - -

Grants - - - - - - - - -

Non-current Liabilities 77,964,362 77,140,686 78,714,542 78,079,912 83,577,371 72,718,838 66,868,792 61,774,746 52,859,954

34


Figure 55: KenGen Balance Sheet, KES ‘000 (Cont’d)


Figure 56: KenGen Cash Flow Statement, KES ‘000



Current Liabilities

Borrowings 7,265,504 6,759,549 6,934,644 6,864,241 7,475,070 6,268,566 5,618,561 5,052,556 4,062,024

Trade and other payables 4,370,312 620,104 780,665 896,282 1,012,017 1,083,634 1,223,280 1,375,476 1,621,994

Amount due to Kenya Power 6,405 6,405 6,405 6,405 6,405 6,405 6,405 6,405 6,405

Operating lease liability 2,000 2,000 2,000 1,000 - - - - -

Leave pay provision 160,415 160,415 160,415 160,415 160,415 160,415 160,415 160,415 160,415

Dividends payable 3,196,321 3,620,368 3,355,565 4,299,846 5,758,280 7,510,531 9,336,934 11,877,319 15,073,878

Current Liabilities 15,000,957 11,168,841 11,239,694 12,228,189 14,412,187 15,029,551 16,345,595 18,472,170 20,924,716

Total Liabilities 92,965,319 88,309,527 89,954,236 90,308,101 97,989,558 87,748,390 83,214,387 80,246,916 73,784,669

Equity

Share capital 5,495,904 5,495,904 5,495,904 5,495,904 5,495,904 17,995,904 17,995,904 17,995,904 30,495,904

Share premium 5,039,818 5,039,818 5,039,818 5,039,818 5,039,818 5,039,818 5,039,818 5,039,818 5,039,818

Capital reserve 8,579,722 8,579,722 8,579,722 8,579,722 8,579,722 8,579,722 8,579,722 8,579,722 8,579,722

Investments revaluation reserve (210,490) (210,490) (210,490) (210,490) (210,490) (210,490) (210,490) (210,490) (210,490)

Property, plant and equipment revaluation reserve 17,954,954 16,379,581 14,804,208 13,228,835 11,653,462 10,078,089 8,502,716 6,927,343 5,351,970

Retained earnings 33,319,646 35,204,046 40,125,822 45,605,161 51,832,424 58,585,297 67,437,245 78,036,606 91,845,015

Total Equity 70,179,554 70,488,581 73,834,984 77,738,950 82,390,840 100,068,340 107,344,915 116,368,903 141,101,939

Total Liabilities and Equity 163,144,873 158,798,108 163,789,220 168,047,051 180,380,398 187,816,729 190,559,302 196,615,819 214,886,608



Profit before tax 4,045,190 2,325,777 5,850,433 8,268,293 10,448,973 12,202,955 16,008,467 20,255,306 26,793,207

Operating Profit before Working Capital Changes 9,952,499 14,128,855 17,637,704 20,291,003 22,818,654 24,535,923 27,599,312 31,145,710 36,102,445

Working capital adjustments (4,675,415) 4,154,952 (2,146,894) (1,540,452) (1,537,375) (943,860) (1,849,865) (2,013,435) (3,265,781)

Cash Flows from Operating Activities 5,277,084 18,283,807 15,490,810 18,750,550 21,281,279 23,592,063 25,749,447 29,132,275 32,836,664

Income tax paid (84,428) (697,733) (1,755,130) (2,480,488) (3,134,692) (3,660,887) (4,802,540) (6,076,592) (8,037,962)

Interest received 863,262 596,483 627,374 653,658 688,718 878,779 906,234 798,848 1,037,192

Interest paid (2,988,302) (7,036,508) (6,782,675) (6,775,871) (6,895,367) (6,529,738) (5,661,533) (4,366,453) (2,945,444)

Net Cash from Operating Activities 3,067,616 11,146,049 7,580,379 10,147,850 11,939,939 14,280,217 16,191,608 19,488,078 22,890,450


Purchase of property, plant and equipment (9,020,497) (8,403,657) (8,391,472) (8,204,231) (16,218,000) (4,798,050) (15,226,640) (10,108,149) (13,361,756)

Purchase of prepaid leasehold land (4,736) - - - - - - - -

Purchase of intangible asset (3,109) - - - - - - - -

Proceeds on sale / redemption of treasury bonds 393,299 - - - - - - - -

Net cash from investing activities (8,635,043) (8,403,657) (8,391,472) (8,204,231) (16,218,000) (4,798,050) (15,226,640) (10,108,149) (13,361,756)


Payment of funds awaiting allotment of shares - - - - - - - - -

Dividends paid (826,681) (894,970) (1,013,703) (939,558) (1,203,957) (1,612,318) (2,102,949) (2,614,341) (3,325,649)

Proceeds from issue of new shares - - - - 12,500,000 - - 12,500,000

Net borrowings 3,731,539 (1,765,504) 1,505,679 (949,307) 5,863,015 (12,310,309) (6,745,324) (5,905,324) (9,905,324)

Net cash from financing activities 2,904,858 (2,660,474) 491,975 (1,888,865) 4,659,058 (1,422,628) (8,848,273) (8,519,666) (730,974)

Net (decrease)/increase in cash and cash equivalents (2,662,569) 81,918 (319,117) 54,754 380,997 8,059,540 (7,883,305) 860,263 8,797,720

35


Figure 57: UMEME Income Statement, UGX m

Source: UMEME & DBIB estimates

Figure 58: UMEME Balance Sheet, UGX m


December December December December December December December December December2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Revenue 859,552 971,777 1,099,076 1,235,898 1,410,635 1,606,188 1,808,288 2,027,112 2,266,733

yoy 88.1% 13.1% 13.1% 12.4% 14.1% 13.9% 12.6% 12.1% 11.8%

Cost of Sales (624,235) (719,878) (785,611) (852,233) (921,077) (1,007,875) (1,102,892) (1,195,838) (1,296,663)

yoy 130.7% 15.3% 9.1% 8.5% 8.1% 9.4% 9.4% 8.4% 8.4%

Gross Profit 235,317 251,899 313,465 383,665 489,558 598,313 705,396 831,274 970,070

yoy 26.2% 7.0% 24.4% 22.4% 27.6% 22.2% 17.9% 17.8% 16.7%

Operating Expenses (125,665) (116,613) (126,394) (135,949) (150,938) (167,044) (182,637) (198,657) (215,340)

yoy 10.0% -7.2% 8.4% 7.6% 11.0% 10.7% 9.3% 8.8% 8.4%

Other Operating Income 4,980 6,608 7,694 8,651 9,874 11,243 12,658 14,190 15,867

yoy -67.5% 32.7% 16.4% 12.4% 14.1% 13.9% 12.6% 12.1% 11.8%

EBITDA 114,632 141,893 194,764 256,367 348,494 442,513 535,417 646,807 770,597

yoy 30.9% 23.8% 37.3% 31.6% 35.9% 27.0% 21.0% 20.8% 19.1%

Total Depreciation and Amortisation (22,248) (26,444) (34,267) (45,462) (62,748) (79,817) (93,755) (107,970) (123,465)

yoy 3.3% 18.9% 29.6% 32.7% 38.0% 27.2% 17.5% 15.2% 14.4%

EBIT 92,384 115,450 160,497 210,905 285,746 362,696 441,662 538,837 647,132

yoy 40.0% 25.0% 39.0% 31.4% 35.5% 26.9% 21.8% 22.0% 20.1%

Net Finance Revenue/Costs (31,463) (22,544) (35,763) (48,114) (51,145) (51,887) (52,123) (52,107) (52,303)

yoy 47.1% -28.3% 58.6% 34.5% 6.3% 1.5% 0.5% 0.0% 0.4%

Profit Before Tax 60,921 92,906 124,734 162,791 234,601 310,809 389,540 486,730 594,830

yoy 36.5% 52.5% 34.3% 30.5% 44.1% 32.5% 25.3% 25.0% 22.2%

Income Tax (3,811) (27,872) (37,420) (48,837) (70,380) (93,243) (116,862) (146,019) (178,449)

Adjusted Net Income 48,926 65,034 87,314 113,954 164,220 217,566 272,678 340,711 416,381

yoy 112.6% 32.9% 34.3% 30.5% 44.1% 32.5% 25.3% 25.0% 22.2%


Non-current Assets

Intangible Assets 279,683 362,652 484,960 681,265 857,236 972,360 1,077,420 1,186,159 1,298,906

Concession Arrangement Financial Asset: Non-current Portion 152,936 155,115 140,124 107,675 87,395 79,225 66,306 57,611 48,699

Deferred Income Tax Asset - - - - - - - - -

Non-current Assets 432,619 517,768 625,084 788,941 944,630 1,051,585 1,143,726 1,243,770 1,347,605

Current Assets

Inventories 36,460 49,307 53,809 58,372 63,087 69,033 75,541 81,907 88,813

Trade and Other Receivables 188,256 145,274 146,868 170,356 140,819 168,716 191,236 218,530 244,374

Current Income Tax Recoverable 3,323 3,323 3,323 3,323 3,323 3,323 3,323 3,323 3,323

Amount Recoverable from Customer Capital Contributions 723 1,446 2,892 5,784 11,568 23,136 46,272 92,544 185,088

Concession Arrangement Financial Asset: Current Portion 43,892 44,733 1,958 3,187 4,541 6,085 7,758 9,581 11,538

Cash and Cash Equivalents 50,660 3,689 248,166 112,693 42,859 3,689 3,689 4,627 5,295

Current Assets 323,314 247,772 457,016 353,715 266,197 273,982 327,818 410,511 538,431

Total Assets 755,933 765,540 1,082,100 1,142,656 1,210,828 1,325,567 1,471,544 1,654,281 1,886,036


Deferred Income Tax Liability 12,100 12,100 12,100 12,100 12,100 12,100 12,100 12,100 12,100

Borrowings 47,093 41,939 378,165 378,165 340,349 302,532 264,716 226,899 189,083

Concession ObIlgation: Non-current Portion 152,936 155,115 140,124 107,675 87,395 79,225 66,306 57,611 48,699

Non-current Liabilities 212,129 209,154 530,389 497,941 439,844 393,858 343,122 296,611 249,881

Current Liabilities

Trade and Other Payables 244,739 118,336 129,142 140,093 151,410 165,678 181,297 196,576 213,150

Current Income Tax Payable - - - - - - - - -

Deferred Construction Income 4,270 9,746 14,206 19,079 24,402 30,218 36,571 39,730 42,860

Customer Security Deposits 3,688 4,647 5,855 7,143 8,715 10,283 12,134 12,134 12,134

Concession Obligation: Current Portion 43,892 44,733 1,958 3,187 4,541 6,085 7,758 9,581 11,538

Borrowings 7,768 6,918 62,378 62,378 56,141 49,903 43,665 37,427 31,189

Overdraft 91,881 - - - 99 2,781 - -

Current Liabilities 304,357 276,261 213,539 231,880 245,208 262,266 284,207 295,449 310,872

Total Liabilities 516,486 485,416 743,928 729,821 685,052 656,124 627,328 592,059 560,753

36


Figure 59: UMEME Balance Sheet, UGX m (Cont’d)


Figure 60: UMEME Cash Flow Statement, UGX m



Equity

Issued Capital 27,748 27,748 27,748 27,748 27,748 27,748 27,748 27,748 27,748

Share Premium 70,292 70,292 70,292 70,292 70,292 70,292 70,292 70,292 70,292

Retained Earnings 141,407 182,083 240,132 314,794 427,735 571,402 746,175 964,181 1,227,242

Total Equity 239,447 280,124 338,172 412,835 525,776 669,443 844,216 1,062,222 1,325,283

Total Liabilities and Equity 755,933 765,540 1,082,100 1,142,656 1,210,828 1,325,567 1,471,544 1,654,281 1,886,036



Profit before taxProfit before tax 60,921 92,906 124,734 162,791 234,601 310,809 389,540 486,730 594,830

Operating profit before working capital adjustments 106,815 141,454 211,747 270,301 360,097 447,394 539,664 647,456 771,349

Working capital adjustments 24,130 (90,556) 8,931 (13,831) 37,249 (23,758) (28,340) (61,494) (105,591)

Cash generated from operations 130,945 50,898 220,678 256,471 397,346 423,636 511,324 585,962 665,758

Interest received from banks 1,914 1,630 2,519 3,609 1,556 465 74 83 99

Impairment provision for bad and doubtful debts (14,470) (33,802) (32,805) (33,095) (29,307) (31,704) (31,388) (35,086)

Current income tax paid (12,000) (27,872) (37,420) (48,837) (70,380) (93,243) (116,862) (146,019) (178,449)

Interest paid on shareholder's loan (11,120) - - - - - - - -

Interest paid on IFC loan (3,042) (2,833) (18,247) (32,851) (31,208) (27,923) (24,638) (21,353) (18,068)

Interest on revolver - (6,432) (3,216) - - (3) (101) (97) -

Net cash from operating activities 106,697 922 130,512 145,585 264,218 273,625 338,093 387,188 434,255


Purchase of intangible assets (98,074) (109,414) (156,575) (241,767) (238,718) (194,941) (198,815) (216,709) (236,213)

Proceeds from disposal of concession assets 164 - - - - - - - -

Recovery of concession arrangement financial asset - 867 17,956 35,505 23,426 11,350 16,208 12,081 12,425

Payment of concession obligation: principal - (867) (17,956) (35,505) (23,426) (11,350) (16,208) (12,081) (12,425)

Net cash from investing activities (97,910) (109,414) (156,575) (241,767) (238,718) (194,941) (198,815) (216,709) (236,213)


Net proceeds from issue of shares (less shares granted to employees) 71,568 - - - - - - - -

Dividends paid (24,358) (29,265) (39,291) (51,279) (73,899) (97,905) (122,705) (153,320)

Repayment of shareholder's loans (74,670) - - - - - - - -

Total proceeds from IFC loans - - 440,544 - - - - - -

Total repayments of IFC loans (6,004) (6,004) (48,857) - (44,054) (44,054) (44,054) (44,054) (44,054)

Net cash from financing activities (9,106) (30,362) 362,422 (39,291) (95,334) (117,954) (141,959) (166,759) (197,374)

Net (decrease)/increase in cash and cash equivalents (319) (138,854) 336,358 (135,473) (69,834) (39,270) (2,682) 3,719 668