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CHALLENGES FACING THE ELECTRICITY SECTOR INDUSTRY AND FUTURE OUTLOOK

By Eng.Norbert Semitala (Director, Technical Regulation – ERA)

1.0 Introduction

In 1987, the Government of Uganda adopted the Economic Recovery Program in order to

restore macroeconomic stability. The Economic Recovery Program included the liberalization

of the financial sector and privatization of some state owned enterprises. Privatization in

particular was meant to get rid of the inefficient government parastatals and replace them with

more efficient private companies.

The electricity sector as well was inefficient and loads of investment was required to move it to

efficient levels. The Ministry of Natural Resources then, developed a strategic power sector

plan that sought to lead to the provision of affordable and reliable electricity in order to

enhance economic growth and development.

In June 1999, the GOU put in place the Power Sector Restructuring and Privatisation Strategy

(PSRPS), whose principle objectives were having an efficient and financially viable power

sector, meeting demand and expanding coverage, improving quality of electricity and

encouraging private and local investment into the sector.

The Electricity Act of 1999, came in handy to provide the legal framework in order to achieve

objectives of the power sector strategic plan. The main objectives of the Electricity Act were to

remove the monopoly in the electricity sector by privatizing some of the functions of the then

state owned Uganda Electricity Board (UEB), and put in place a regulatory authority to

oversee the activities in the electricity sector.

The Electricity Regulatory Authority was established in 2000, to regulate the activities of the

electricity industry. With the regulatory body in place, UEB was split into Uganda Electricity

Generation Company Ltd (UEGCL), Uganda Electricity Transmission Company Ltd (UETCL),

and Uganda Electricity Distribution Company Ltd (UEDCL). UEGCL took ownership of the

380MW capacity Nalubaale/Kiira plant, UETCL took charge of the transmission

infrastructure, while UEDCL took over the distribution network.

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The figure below shows the Electricity Industry setup.

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UEGCL later concessioned its assets to Eskom (U), while UETCL remains a Government

entity, considering the nature of investments needed in the transmission arm, vis avis the

return, if it were to be operated by a profit motivated company. UEDCL subsequently

concessioned its assets for a 20-year period to Umeme (Ltd).

With the new sector setup, several private companies have since invested particularly in

generation facilities namely; Tronder-Bugoye (13MW), South East Asia Management Systems-

Mpanga (18MW), Aggreko-Mutundwe (50MW), and Jacobsen-Namanve (50MW) among

others. UETCL is the sole transmission company and has the licenses for system operator,

import and export, bulk power supply and operation of high voltage grid. The distribution

companies include Umeme (which accounts for more than 98% of the total end user sales),

Ferdsult Engineering Services (FESL), Kilembe Investments Limited (KIL), Bundibugyo

Energy Cooperative Society (BECS), Pakwach-Abim Community Multi Purpose Energy

Cooperative Society (PACMECS), and West Nile Rural Electrification Company (WENRECO)

among others.

2.0 Tariff Path since 2006.

Prior to 2004, Uganda’s major source of electricity was hydropower. However, due to the

severe drought that affected the country thereafter, the water levels of L.Victoria (which is the

main reservoir for the 380 MW Owen Falls Complex) reduced significantly leading to

insufficient power supply.

A strategic decision that government decided to take at the time was to mitigate the

inadequate electricity supply through short term hire of diesel thermal plants which although

very expensive compared to hydro, can be installed in a very short time and would go a long

way in ensuring the availability of sufficient energy. The Aggreko Lugogo (50MW) was

commissioned in 2005 and later another Aggreko-Kiira (50MW) was also procured in 2006 to

further mitigate the energy shortage. Later in September 2008, another plant Aggreko-

Mutundwe (50MW) was procured through a World Bank loan and this replaced the Aggreko

Lugogo plant.

It was recognized at the time that the costs of running and maintaining these plants is high and

if they were to be passed on and be paid through the tariff, it would impact on the cost of

doing business and render several productive sectors of the economy non-competitive in the

region. A strategic decision was thus adopted by Government to subsidize end user customers.

This strategy would then be supplemented by medium term interventions of encouraging the

private sector through a feed in tariff mechanism to fast rack relatively small hydropower

plants typically up to 20 MW, as the longer term interventions like Bujagali and Karuma

eventually come on board.

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Notwithstanding that decision, it was also necessary that the consumer should pay more than

what was being paid before 2005, given that at the time the consumer was paying far less than

what was required to meet the sector revenue requirements.

As a result, the tariffs were adjusted upwards in April 2005 by 22%, June 2006 by 35% and

November 2006 by 41%. Towards the end of 2009 however, some favourable conditions

prevailed such as lower oil prices and appreciation of the Shilling against the US Dollar, a

situation that necessitated the review of the tariff downwards with the energy subsidy at the

time projected at only Shs 8 billion in Q1 2010. The events that followed immediately thereafter

(i.e at the beginning of 2010) led to the current subsidy requirement levels that are

unsustainable, if the sector is to be self financing.

Table 1: Tariff Levels since 2005

3.0 Current status

a) Electricity demand –supply balance:

- Peak demand has increased to 443MW in May 2011 compared to 380MW in May 2009.

- Shoulder demand has increased to 351MW in May 2011 compared to 280MW in May

2009.

- Off-peak demand has increased to 302MW in May 2011 compared to 230MW in May

2009.

This increase has been largely driven by growth in economic activities in the country.

Electricity supply has however remained constrained due to hydrological constraints, delays in

reaching commissioning by Bujagali and Mini-hydro plants, and lack of supply by Thermal

generators which have switched off due to delays in payment. The current deficit is indicated in

Graph 1 below.

Code 10.1 Code 10.2/10.3

Code

20

Code

30

Code

50 Code 10.1 Code 10.2/10.3

Code

20

Code

30

Code

50

Domestic Commercial

Medium

Industrial

Large

Industrial

Street-

lights Domestic Commercial

Medium

Industrial

Large

Industrial

Street-

lights

Q1 2005 171.4 164.8 150.3 60.4 162.5 171.4 164.8 150.3 60.4 162.5

Q2 2005 256.4 245.7 234.2 109.6 243.0 212.5 204.4 178.9 71.9 201.5

Q2 2006 525.1 475.2 463.5 328.9 487.5 298.2 286.8 261.5 120.8 282.8

Q4 2006 674.6 605.2 593.6 438.0 620.0 426.1 398.8 369.7 187.2 403.0

Q1 2010 713.0 639.9 615.0 488.4 649.2 385.6 358.6 333.2 184.8 364.3

Period

Cost Reflective Tariff Actual Tariff Paid by end-user

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Graph1: Current Load shedding on a typical day

b) Energy mix:

In 2006, thermal generation accounted for 23%, currently thermal generation accounts for

46% of Uganda’s energy mix. Thermal generation costs account for about 85% in 2011

compared to 73 % in 2006.

c) Sector Revenue requirements:

The total sector revenue requirement in 2006 amounted to Shs.420 billion and this increased

to Shs.618 billion in 2010 and Shs.1, 076 billion in 2011. The major drivers of the increase in

revenue requirement are thermal generation costs which increased from Shs.155 billion in

2006 to about Shs.670 billion in 2011 largely due to the depreciation of the Shilling,

increasing fuel prices, and increased dispatch. Please note that contract obligations to all the

thermal generators are denominated in USD.

d) Distribution efficiency:

The number of distribution companies has increased from the two (Umeme and WENRECO)

in 2005 to five in 2011. Of these five, Umeme accounts for more than 98% of the market

share. Therefore Umeme is the major driver of the distribution costs.

Distribution losses (technical and non-technical) have reduced from 35% in 2009 to the

targeted 27% for 2011. Correspondingly, Umeme’s collection rates have improved from

0

50

100

150

200

250

300

350

400

450

500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Total Demand, (MW) Total Generation (MW) Load shedding, MW

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92.5% in 2009 to 96.2% in 2011. Customer connections have increased from 37,000 in 2010

to the targeted 51,000 in 2011.

It is worthwhile noting that on the basis of the 2011 projection of energy sales to Umeme, for

every percentage loss reduced, the corresponding saving is Shs.5.78 billion. Reducing losses

significantly would therefore lead to a huge saving.

e) Electricity projects:

A number of generators already in operation are shown in table 2 below, while Hydromaxx-

Buseruka (9MW-Hydro) is nearing completing and Electro-Maxx-Tororo is increasing its

capacity to 50MW by the end of 2011.

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Table 2: Licensed Operational Generation Companies

No. Plant Installed Capacity(MW)

1 Mpanga 18

2 Hydromax 9

3 Ishasha 6.5

4 KML 5

5 KCCL 9.9

6 Bugoye 13

7 Eskom 380

8 Kakira 22

9 Kinyara 7.5

10 Jacobsen 50

11 Electro-Maxx 16

12 Aggreko IDA 50

Total Capacity 587

4.0 Challenges facing the sector

a. Exchange rate depreciation:

Since November 2009, the Shilling has depreciated by over shs600/US$ from

Shs1874/US$. Currently, the sector revenue requirement is estimated at US$400 million,

of which 80% is foreign currency based. On account of depreciation alone, the sector

revenue requirement has increased by about Shs.192 billion over the past 18 months.

b. Increasing fuel prices:

The international oil prices have increased to reach the highs of US$120/barrel against the

earlier forecast of US$60-70/barrel at the beginning of 2010. This increase has had a

significant impact on sector costs.

c. Fixed tariffs: Our tariff has not been adjusted upwards to absorb the effects of the

exchange rate depreciation and high fuel costs. This is contrary to our neighbor Kenya

where there is an automatic adjustment of the tariff for inflation, exchange rate and fuel

prices on a monthly basis. As a result, our tariffs are now much lower than those of Kenya

and the extra burden of financing has been pushed to government in form of increased

subsidies. Table 3 shows the comparison of tariffs in the E. Africa region.

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Table 3: Tariff Comparison in E. Africa

d. Government subsidies: As a result of unchanged tariffs amidst a depreciating shilling

and increasing fuel prices, the impact on government subsidies has reached unsustainable

levels.

Table of Subsidies (in UShs billion)

2006 2007 2008 2009 2010 2011

107 78 169 229 351 447

e. Constrained Hydrology:

Whereas installed capacity at Kiira and Nalubale is 380MW, the L.Victoria which is with

reservoir is regulated and the allowed water release is usually 800 cumecs, which can only

help generate an average of 138.5MW from the two power stations. There has however

been an increase in the water release to 1000 cumecs in order to mitigate the supply deficit

by generating as much as 172MW.

The issue of hydrology is also affecting mini hydro plants which have just been

commissioned (13MW Bugoye Plant, 18MW Mpanga plant, and the 6.5MW Ishasha

plant).

f. Financing Challenges

There are also challenges related to financing such as the very high interest rates in

Uganda’s financial sector markets. This makes local borrowing difficult hence many

possible investors take long or totally abandon the projects.

Country

Domestic

Consumers Commercial

Medium

Industries

Large

Industries

Street

Lighting

Uganda 0.15 0.14 0.13 0.07 0.14

Kenya 0.18 0.19 0.15 0.14 0.17

Rwanda 0.19 0.19 0.18 0.18 0.19

Tanzania 0.13 0.10 0.06 0.05 0.08

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g. Long licensing process;

There have also been some complaints regarding the licensing process which takes a long

time period. This is due to the statutory requirements that have to be fulfilled before the

conclusion of the licensing process. On a number of occasions, the prospective licensees

also take long to respond to different questions raised hence dragging the licensing process

further.

h. Domestic factors;

Inadequate and poor road networks as well as absence of transmission networks to

evacuate the generated power are seen as high risk factors. In most instances it is not clear

who will construct the power evacuation lines.

i. Lack of skilled manpower locally;

Developers experience problems finding skilled labour especially in the area of

hydropower development.

5.0 FUTURE OUTLOOK

i. Commissioning of Bujagali and more mini hydro plants. With the commissioning of

Bujagali, the sector revenue requirements (sector costs) are expected to reduce from

Shs1075.8bn Q3 2011 to Shs818.1bn in Q1 2012.

Renewable energy generation from Baggasse and other sources is expected to add

about 50MW to the national grid while mini-hydro plants are expected to add 9MW to

the grid in 2012.

ii. De-commissioning of Diesel Generation Plants: The license for Aggreko –Kiira

(50MW) plant is not going to be extended beyond June 30th 2011. Similarly, the

Aggreko Mutundwe Plant is expected to be de-commissioned by December 2011 after

obtaining 100MW from Bujagali. The remaining HFO plants (Jacobsen Namanve

50MW plant and the 20MW Electromaxx plant in Tororo (to be uprated to 50 MW by

the end of the year) are expected to use crude oil from the Albertine Graben region.

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iii. Use of our own crude oil in generating some 50MW from Albertine Graben region at

Kaiso-tonya.

iv. Improving Distribution efficiency: The first seven years of Umeme license are ending

in February 2012. Negotiations are about to commence in order to set Umeme a new

set of performance targets. Having monitored Umeme’s performance over these seven

years and given the greater experience from the region and other countries, ERA is

now in a better position to set Umeme more realistic performance targets on losses,

collection rates, customer connections, investments etc.

v. Improvement in operating efficiency of independent power producers. ERA has

embarked on an exercise to audit all independent power producers. This exercise will

help in future benchmarking to ensure prudently incurred costs are allowed in the

tariff.

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Appendix 1: Permit Holders

Permits

Kyambura HEP,

South Asia Energy Management Systems Nyamwamba Small hydro Power Project, Mini Hydro 14

VS Hydro Siti 1 & 2 Project, Kapchorwa & Bukwo Mini Hydro 25.7

Eco Power (U) Ltd. Rwimi, Kasese/Kabarole Mini Hydro 9.6

LTL Holdings (Pvt) Limited River Nyamagasani Kyarumba Project Mini Hydro 3

Hayleys Industrial Solutions (Pvt) Ltd Kanyampara Hydropower Project Mini Hydro 7.2

Jeyam Hydro Power Limited Sironko Hydropower Project, Mini Hydro 7

Vidullanka Plc River Muvumba Hydropower Project, Mini Hydro 4.5

Elemental Energy Limited Nyamabuye Hydropower Project, Kisoro DistrictMini Hydro 2.2

Carnelian Prime Trust Nyahuka Hydropower Project, Bundibugyo DistrictMini Hydro 1

Sesam Energetics 1 Ltd. Biomass project, Kampala Waste to Energy 33

Kabale Energy Ltd. Generation plant in Kabale Peat 30

Sugar and Allied Industries Limited Generation Plant in Jinja Bagasse cogeneration 20

Energy Systems for Africa Ltd Generation Plant at Namugoga, Busiro Solar-thermal 50

East African Energy Technology Development NetworkRiver Dirigana Project, Sironko Micro Hydro 60kW,

Albatros Energy (U) Limited Generation Plant in Nebbi Heavy-fuel oil 10

Albatros Energy (U) Limited Generation Plant in Tororo Heavy-fuel oil 230

Apac Energy for Agro Processing Centres (U) Ltd Generation plant in Kabale Biomass-fired plant 1

Timex Garments (Pvt) Limited Bukinda Hydropower Project across River Nkusi Mini Hydro 6.5

Red & White Energy Limited Lubilia-3 Hydropower Project, Kasese District Mini Hydro 5

P.A.C.S.P.A Achwa-Agago Hydropower Project Mini Hydro 88.8

Hydraulic & Sanitation Consult Limited Nkusi Hydropower Project Mini Hydro 11

TYAX Holding Incorporated River Nyamagasani Project Mini Hydro 15

Butama Hydro Electricity Company Ltd. Bundibugyo Hydro Project Mini Hydro 7.5

Hydromax (Nkusi) Ltd. Waki, Hoima District Mini Hydro 8-Feb

Greenewus Energy Africa Ltd Kakaka – Kasese District Mini Hydro 7.2

Nsongezi Power Company Limited Nshungyezi HEP Project, Isingiro Mini Hydro (Own distribution & sale to national grid)22

ZIBA Ltd. Mini Hydro 8.3

Jacobsen Elektro AS Nengo Bridge HEP Project, Rukungiri Mini Hydro 6.5 – 7.0

Developer Project Name / Location Technology Option Planned Capacity (MW)