Embed Size (px)
Citation preview
Document of
The World Bank
FOR OFFICIAL USE ONLY
Report No: 59310-UG
PROJECT APPRAISAL DOCUMENT
ON A
PROPOSED CREDIT
IN THE AMOUNT OF
SDR74.1 MILLION
(US$120 MILLION EQUIVALENT)
TO THE
REPUBLIC OF UGANDA
FOR AN
ELECTRICITY SECTOR DEVELOPMENT PROJECT
May 31, 2011
This document has a restricted distribution and may be used by recipients only in the
performance of their official duties. Its contents may not otherwise be disclosed without World
Bank authorization.
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
Pub
lic D
iscl
osur
e A
utho
rized
ii
CURRENCY EQUIVALENTS
(Exchange Rate Effective 4/30/2011)
Currency Unit = Uganda Shillings
USh 2381 = US$1
US$ = SDR0.62
FISCAL YEAR
January 1
July 1
–
–
December 31 (For UETCL)
June 30 (For GoU)
ABBREVIATIONS AND ACRONYMS
AfDB African Development Bank
BHPP Bujagali Hydro Electric Power Project
BIP Bujagli Interconnection Project
BST Bulk Supply Tariff
CAS Country Assistance Strategy
CESMP Contractors‘ Environmental and Social Management Plan
EIRR Economic Internal Rate of Return
EPD Electric Power Division
ERA Electricity Regulatory Authority
ESIA Environmental and Social Impact Assessment
ESMP Environment and Social Management Plan
ESWG Energy Sector Working Group
FIRR Financial Internal Rate of Return
GoU Government of Uganda
GWh Gigawatt hour (million kilowatt hours)
IA Implementing Agency
IDA International Development Agency
IFR Interim Financial Report
IPP Independent Power Producer
kWh Kilowatt hour
MEMD Ministry of Energy and Mineral Development
MoFPED Ministry of Finance, Planning and Economic Development
MW Megawatt
MWh Megawatt hour
NDP National Development Plan
NPV Net Present Value
PMU Project Management Unit
PPA Power Purchase Agreement
RAP Resettlement Action Plan
RE Rural Electrification
REA Rural Electrification Agency
REB Rural Electrification Board
ROE Return on Equity
iii
RPF Resettlement Policy Framework
UEGCL Uganda Electricity Generation Company Limited
UETCL Uganda Electricity Transmission Company Ltd.
UEDCL Uganda Electricity Distribution Company Limited
UMEME Private utility operating distribution networks under concession agreement
USD United States Dollar
USh Uganda Shilling
Regional Vice President: Obiageli K. Ezekwesili
Country Director: John McIntire
Country Manager:
Sector Director:
Sector Manager:
Kundhavi Kadiresan
Jamal Saghir
S. Vijay Iyer
Task Team Leader: Somin Mukherji
iv
TABLE OF CONTENTS
I. Strategic Context ..................................................................................................................... 1
A. Country Context ............................................................................................................... 1
B. Sectoral and Institutional Context .................................................................................... 2
C. Higher Level Objectives to which the Project Contributes .............................................. 4
II. Project Development Objectives............................................................................................. 4
A. PDO .................................................................................................................................. 4
1. Project Beneficiaries ..................................................................................................... 4
2. PDO Level Results Indicators ...................................................................................... 5
III. Project Description.................................................................................................................. 6
A. Project Components ...................................................................................................... 6
B. Project Financing .......................................................................................................... 7
1. Lending Instrument....................................................................................................... 7
2. Project Financing Table ................................................................................................ 7
IV. Implementation ....................................................................................................................... 7
A. Institutional and Implementation Arrangements .......................................................... 7
B. Results Monitoring and Evaluation .............................................................................. 8
C. Sustainability ................................................................................................................ 8
V. Key Risks ................................................................................................................................ 9
VI. Appraisal Summary .............................................................................................................. 10
A. Economic and Financial Analysis (Annexes-7 and 8) ................................................ 10
B. Technical .................................................................................................................... 12
C. Financial Management ............................................................................................... 12
D. Procurement ................................................................................................................ 13
E. Social (including safeguards) ..................................................................................... 13
F. Environment (including safeguards) .......................................................................... 15
G. Other Safeguard Policies (if required) ........................................................................ 16
Annex 1: Results Framework and Monitoring.............................................................................. 18
Annex 2: Detailed Project Description ........................................................................................ 20
Annex 3: Implementation Arrangements ..................................................................................... 27
Annex 4 Operational Risk Assessment Framework (ORAF) ....................................................... 43
Annex 5: Implementation Support Plan (ISP) .............................................................................. 46
Annex 6: Team Composition ........................................................................................................ 48
Annex 7: Economic Analysis........................................................................................................ 49
Annex 8: Financial Analysis ......................................................................................................... 58
Map – IBRD #38357 ......................................................................................................................70
v
UGANDA
ELECTRICITY SECTOR DEVELOPMENT PROJECT
PROJECT APPRAISAL DOCUMENT
AFRICA
AFTEG
Date: May 27, 2011 Team Leader: Somin Mukherji
Country Director: John McIntire
Sector Director: Jamal Saghir
Sector Manager: S. Vijay Iyer
Sectors: Power (100%)
Themes: Infrastructure services for private
sector development (100%)
Project ID: P119737 Environmental category: A Full Assessment
Lending Instrument: Specific Investment Loan Joint IFC:
Joint Level:
Project Financing Data
[ ] Loan [X] Credit [ ] Grant [ ] Guarantee [ ] Other:
For Loans/Credits/Others:
Total Bank financing (US$m.): 120.0
Proposed terms: Grace period (years): 10; Years to maturity: 40; Commitment fee: 0-0.5% per
annum on undisbursed balance of the Credit; and Service Charge: 0.75% per annum on
undisbursed balance of the Credit
On-lending arrangements: Grace period (years) 10; Years to maturity 40; Interest rate: 0.75%
per annum
Financing Plan (US$m)
Source Local Foreign Total
BORROWER/RECIPIENT 33.2 0.0 33.2
International Development Association (IDA) 22.3 97.7 120.0
Total: 55.5 97.7 153.2
Borrower: Republic of Uganda
Responsible Agency: Ministry of Energy and Mineral Development, Kampala, Uganda
Uganda Electricity Transmission Company Ltd. (UETCL)
Plot 10, Hannington Road
PO Box 7625
Uganda
Tel: (256-41) 425-0677 Fax: (256-41) 434-1789
Estimated disbursements (Bank FY/US$m)
FY 2012 2013 2014 2015 2016 2017
Annual 20.0 12.0 49.6 14.8 10.8 12.6
Cumulative 20.0 32.2 81.7 96.6 107.4 120.0
Project implementation period: Start September 1, 2011 End: August 31, 2016
Expected effectiveness date: November 30, 2011
vi
Closing date: February 28, 2017
Does the project depart from the CAS in content or other significant respects?
Ref. PAD I.C. [ ]Yes [X] No
Does the project require any exceptions from Bank policies? Ref. PAD IV.G.
Have these been approved by Bank management?
[ ]Yes [X] No
[ ]Yes [ ] No
Is approval for any policy exception sought from the Board? [ ]Yes [X] No
Does the project include any critical risks rated ―substantial‖ or ―high‖?
Ref. PAD III.E. [X]Yes [ ] No
Does the project meet the Regional criteria for readiness for implementation?
Ref. PAD IV.G. [X]Yes [ ] No
Project development objective Ref. PAD II.C., Technical Annex 3
The project development objective is to improve the reliability of and increase the access to
electricity supply in the southwest region of Uganda
Project description [one-sentence summary of each component] Ref. PAD II.D., Technical
Annex 4
Component A - Construction of 137 km of 220 kV Kawanda-Masaka transmission line and
related substation construction/upgrades and resettlement of displaced persons;
Component B - Technical Assistance in support of project implementation, transmission system
development and capacity building of UETCL; and
Component C - Community Support projects in areas affected by the transmission line
construction and capacity building at MEMD.
Which safeguard policies are triggered, if any? Ref. PAD IV.F., Technical Annex 10
Environmental Assessment (OP/BP 4.01), Natural Habitats (OP/BP 4.04), Physical Cultural
Resources (OP/BP 4.11), Involuntary Resettlement (OP?BP 4.12) and Forests (OP/BP 4.36)
Significant, non-standard conditions, if any, for: Ref. PAD III.F.
Credit effectiveness:
(a) A Subsidiary Agreement has been executed between the Recipient and UETCL.
(b) The Recipient and UETCL have adopted the Project Implementation Manuals.
(c) The Recipient has: (i) made arrangements satisfactory to the Association for the resolution
of outstanding claims by displaced persons affected by the construction of the Bujagali-Kawanda
Transmission Line; and (ii) prepared and adopted an action plan for the implementation of the
Resettlement Action Plan (RAP dated October 15, 2010), satisfactory to the Association.
Covenants applicable to project implementation:
(i) UETCL to submit its annual audit report within six months of the end of each fiscal year;
(ii) UETCL to maintain a debt service coverage ratio of at least 1.0 throughout the
implementation period;
(iii) UETCL to maintain an EBITDA ratio of at least 1% in FY11, 1.5% in FY12-13, 2% in
FY14 and 3% thereafter;
(iv) MEMD and UETCL to submit their annual audited project accounts within six months of
the end of each fiscal year;
(v) The Recipient to install in MEMD a computerized accounting and financial management
system within six months of the Effective Date;
(vi) The Recipient and UETCL to establish procurement monitoring systems and contract
management systems and provide appropriate training and capacity building to their
procurement staff by September 30, 2011; and
(vii) UETCL to undertake a revision of the structure of its procurement unit by June 30, 2011.
vii
Retroactive Financing:
No withdrawal shall be made for payments made prior to the date of the Financing Agreement,
except that withdrawals up to an aggregate amount not to exceed US$5,000,000 equivalent may
be made for payments prior to this date but on or after June 1, 2011 for Eligible Expenditures
1
I. Strategic Context
A. Country Context
1. Despite its numerous geographical disadvantages, as well as political unrest within and
adjacent to its borders, Uganda has sustained one of the world‘s highest per capita economic
growth rates over two decades. In the late 1980s, Uganda was one of the first Sub-Saharan
African countries to embark on liberalization and pro-market policies. Through the 1990s, the
government maintained a stable macro environment and continued to undertake private-sector
oriented reforms. By 2006, Uganda had graduated into a mature reformer, and achieved average
annual GDP growth of 8.1 percent over the six year period from 2002/2003 through 2008/09.
2. High economic growth has contributed to a substantial decline in the proportion of
people living in poverty; the rate fell from 57 percent in 1992/93 to 31 percent in 2005/06.
However, there is substantial and growing urban-rural inequality and inequality between regions.
The rapid population growth of recent years is also likely to continue. The AIDS epidemic in
mid-1980‘s devastated the young adult population at the time, and the country now faces a
demographic challenge where 50 percent of the population is under the age of 14. Maintaining
the growth rates needed to support this young and growing population will require a shift in
economic focus from a largely rural agrarian society to a more urban and commercially oriented
economy. This in turn, will place increasing pressure on the government to close the gap in
access to infrastructure, particularly transport and energy.
3. Uganda has made progress toward establishing a multi-party democracy, although none
of the opposition parties have so far won the Presidential elections. The February 2011 national
elections including the presidential polls granted the current president another five year term.
While there is a strong legal framework in place, Uganda has struggled to translate its anti-
corruption laws into practice. According to a 2009 Africa Peer Review Mechanism Country
Review of Uganda, petty and high-level corruption are prevalent and affect every institution in
the country, and are most rife in procurement, privatization, administration of revenues and
public expenditures, and public service delivery. Despite the government‘s zero tolerance policy
on corruption and its efforts on anti-corruption including the establishment of a dedicated anti-
corruption court, some of the high-level corruption cases are yet to be concluded. Local public
opinion polls indicate that petty corruption is widespread and increasing.
4. The recent discovery of oil in the north-western region offers both opportunity and risk.
Increased government revenues, if used wisely, can help to fund the facilities and services
needed to support a modern and diversified economy. Employment and training opportunities
related to exploration, production and product distribution, as well as more generalized support
services to the petroleum companies will help to absorb some of the surplus labor force and
enhance the overall skills level. At the same time, the discovery of a source of great wealth may
give rise to increased risk of corruption and international and inter-regional tension. Few low-
income countries have succeeded in developing newly-found mineral resources in a transparent
manner to the benefit of the general population, and the challenges facing Uganda in this regard
are considerable. In order to address these issues, the Government of Uganda has put in place a
National Oil and Gas Policy, which is under implementation.
2
5. Like any other country, an adequate and reliable supply of electricity is a necessary
condition for continued development of Uganda. Access to electricity enhances the socio-
economic development of the population through better access to education, health care, and
personal security; it facilitates development of small-scale industrial and commercial enterprises;
and it provides an added incentive to larger-scale industrial and commercial investment in the
country. Yet Uganda has for many years failed to fulfill this need. Despite substantial power
resources, its capacity to provide reliable, cost effective electricity supply has continuously
lagged behind the demands of a growing economy.
B. Sectoral and Institutional Context
6. The Uganda Electricity Board (UEB) was established in 1948 as a vertically integrated
utility with responsibility for all aspects of power sector operations in Uganda. Despite
concerted attempts, UEB failed to improve its efficiency and performance. In the late 90s, the
Government of Uganda (GoU) decided that major efficiency improvements and expansion of
access to electricity could be better accomplished through implementing a comprehensive power
sector reform program which placed the power sector under private management operated on
commercial principles. Since then, the sector has been unbundled1, legal and regulatory reforms
introduced, and operation of the main generation and distribution assets turned over to the
private sector under long-term concession agreements. Nevertheless, the sector still faces some
significant challenges. These include: (i) a lack of adequate and reliable power supply; (ii) weak
sector finances; (iii) a lack of institutional capacity to deal with such issues as integrated least-
cost system planning, increased access, and sustainability of hydro resources; (iv) low level of
access to electricity at less than 10% overall, and (v) high distribution system losses of more than
30%. Failure to meet these challenges has led to poor operating performance and unsustainable
operations.
7. The strategy undertaken by the Government of Uganda (GoU) to address the above
challenges is to: (i) continue to strengthen both public and private sector institutions, (ii)
increase electricity supply through investments in renewables and in energy efficiency, (iii)
develop and implement an updated (2011–2020) Rural Electrification Strategy to increase
electricity access outside major urban centers, and (iv) develop a more diversified generation mix
as well as a strong interconnected national grid with links to neighboring countries for ensuring
security of supply. The key focus areas of the GoU include:
Generation: Completion of the 250 MW Bujagali Hydro Electric Power Project (BHPP)
with capacity additions from other planned major hydro power projects such as Karuma
Hydro Electric Power Project (600 MW), Isimba Hydro Electric Power Project (100
MW), and Ayago Hydro Electric Power Project (600 MW), for which preparatory studies
initiated by the Government are being finalized. In addition, a number of mini-hydro
power projects are under preparation/construction;
1 Three separate corporate entities were created; one each for generation – the Uganda Electricity Generation
Company Ltd. (UEGCL); transmission – the Uganda Electricity Transmission Company Limited (UETCL); and
distribution – the Uganda Electricity Distribution Company Limited (UEDCL). The distribution assets of UEDCL
were subsequently franchised out to UMEME.
3
Transmission and Distribution: Rehabilitation and upgrade of the transmission system
and strengthening of the UMEME distribution network;
Rural Electrification and Renewable Energy Development: Ongoing donor-funded
initiatives including Energy for Rural Transformation and studies to Accelerate Energy
Access in rural areas;
Sector Financial and Operational Performance: Ongoing Power Sector Development
Operation (PSDO); and
Regional Interconnection: Several interconnection projects with neighboring countries
under the East African Power Pool (EAPP) are being initiated.
8. IDA has been closely involved in the development of the power sector for many years,
supporting the institutional strengthening and investments of the original integrated utility, the
subsequent unbundling of the sector, development of the regulatory authority, financing of
government investment in sector infrastructure and helping to bring together, as well as
participating, in major public-private partnerships such as BHPP and other areas of transmission
and distribution development.
9. Work is under way to develop the next generation projects, complete and upgrade the
transmission grid, improve links with export markets, and continue to extend service to rural
areas. At present, development is proceeding concurrently on many fronts with funding
provided both by the private sector and other bilateral and multilateral financial institutions. The
major focus at the moment is completion of BHPP and start-up of construction of other major
hydro power plants. Also, the GoU is aggressively pursuing the development of mini-hydro
systems through the private sector. As for transmission system development, expansion and
strengthening of the national grid to successfully evacuate the incremental energy and distribute
it throughout the country is a consequential developmental priority. In addition to IDA, the other
major Development Partners (DP) include the African Development Bank (AfDB), Japan
International Co-operation Agency (JICA), and Government of Norway who are financing
various segments of the transmission system development plan. On the distribution side, apart
from Bank Group‘s support to the private concessionaire UMEME, the GoU has also sought
Bank‘s help in developing a strategy to accelerate the access to electricity which in turn is
necessary to help absorb the additional generation expected to be made available.
10. Given the number of participants, and the relative weakness of sector institutions, co-
ordination can be a major challenge. Care needs to be taken that development of transmission
and distribution networks do not outpace the development of generation capacity, and vice versa.
‗Master Plans‘ for generation, transmission and rural electrification need to be regularly
reviewed and updated and also be sufficiently flexible to adapt to changing circumstances such
as, for example, new local power demands associated with the oil discoveries in Lake Albert.
IDA continues to work closely with both the GoU and with sector institutions to ensure that
available funding is used in the most efficient manner possible to bridge the gap between
electricity supply and demand in a sustainable manner.
4
11. In order to implement the sector strategy highlighted above, it is essential that close
attention is accorded towards development of each of the components of the sector. The
proposed Project will support this strategy by: (a) improving service quality and reliability to
existing customers by replacing poorly-functioning segments of the existing transmission
system; (b) expanding the capacity of the transmission system to meet growing regional power
demand and (c) reducing system losses. Given that sector reforms have been under
implementation for over ten years, during project preparation, the GoU expressed the need to
review the reform measures adopted and focus on any additional measures to be adopted. The
proposed Project will provide necessary support to inter alia finance such reviews, strengthen
sector institutions and support donor-sector coordination. The proposed Project will also support
several community support measures through the provision of low cost electricity connection to
members of poorer sections of society living within the Project area.
C. Higher Level Objectives to which the Project Contributes
12. The Uganda National Development Plan (NDP), covering the period 2010/11 – 2014/15,
notes that ―limited access and use of energy significantly slows down economic and social
transformation‖. The Plan has, as one of its priorities, improved stock and quality of the
economic infrastructure. Specifically, for the energy sector, the NDP focuses on increasing
access and consumption of electricity by investing in least cost power generation, promotion of
renewable energy and energy efficiency in addition to the associated transmission and
distribution infrastructure. The Country Assistance Strategy (CAS) covering the period from
2011 to 2014 notes specifically that inadequate infrastructure, especially transport and energy, is
Uganda‘s binding constraint for growth and economic transformation. The government needs to
identify and facilitate infrastructure projects that will induce private sector investment in new
products, resulting in increased exports and new jobs. The CAS goes on to include among its
Strategic Objectives to ―Enhance Public Infrastructure‖. It notes that there are three proposed
outcomes: (i) increased access to electricity; (ii) improved access to and quality of roads; and
(iii) improved access to quality water and sanitation services. The proposed Project intends
specifically to address the first of these outcomes by improving transmission links between
power supply sources and electricity markets.
II. Project Development Objectives
A. PDO
13. The project development objective is to improve the reliability of, and increase the
access to, electricity supply in the southwest region of Uganda.
1. Project Beneficiaries
14. The beneficiaries of the proposed Project are:
5
residential, public, commercial and industrial electricity customers who are currently
served by the existing transmission line to Masaka West2 substation but who experience
frequent and prolonged service interruptions owing to the poor condition of the line;
new customers in the southwestern region of Uganda who, without the increase in
transmission capacity by the construction of the 220 kV Kawanda-Masaka transmission
line, would be unable to receive power from the grid; and
potential new customers in peri-urban areas along the transmission line route who wish to
but cannot presently be connected to the grid primarily because of high connection costs.
15. Direct project beneficiaries will include: (a) current consumers who are supplied from
the Masaka substation and receive only intermittent electricity service; and (b) new consumers
that will be connected on account of additional supply to be made available. The total number of
new consumers (increase in access) that is expected to be connected at the end of project
implementation (i.e., after commissioning of the transmission line) is estimated at 1,000,
representing about 7,800 persons of which about 3,978 are estimated to be women. In the longer
term, the higher capacity of the line will allow connection of additional consumers/households in
the region. By 2020, approximately 59,000 new consumers will gain access that will benefit
more than 460,000 persons of which more than 234,000 would be female. By 2025, the figure is
expected to increase to 84,000 new consumers benefiting about 655,000 people of which more
than half would be female. Secondary beneficiaries are those living in the peri-urban areas along
the transmission line route and would include: (a) people living within an existing distribution
area along the transmission corridor but could not get connected because of high connection
costs; (b) people who are resettled under the RAP and who will be provided with alternate living
accommodation; and (c) communities living along the transmission line corridor. Total number
of new consumers under this category is estimated at 8,000 implying total number of
beneficiaries to be more than 62,000 of which more than half would be female.
2. PDO Level Results Indicators
16. The key results of the proposed Project are expected to be:
Improved reliability of supply in the Masaka area on account of reductions in: (a)
average transmission line outages per year; (b) average outage time; and (c) unmet
demands of existing consumers;
Increase in supply through the Masaka substation owing to increased capacity of the
transmission line; and
Increase in project primary beneficiaries measured by increase in access on account
of the Project.
Additional details are included in Annex-1.
2 Masaka is in the southwestern region of Uganda
6
III. Project Description
A. Project Components
17. The proposed Project will finance a time slice of Uganda‘s transmission sector
expansion plan, focusing on high priority investments needed to upgrade and reinforce supply to
the south-western region of the country. The Kawanda-Masaka transmission corridor serves a
significant market south-west of Kampala and is an important segment of the network proposed
to evacuate power from the BHPP. At the same time, this link will serve as a basis for proposed
future transmission interconnections to Tanzania and Rwanda and forms part of the ring around
Lake Victoria for future interconnection with the East African Community grid. The proposed
Project fits very well within the Bank‘s overall engagement in the Sector. The following
paragraphs briefly describe the Project components, details are included in Annex-2.
18. Component A, will involve complementing and ultimately replacing a crumbling and
unreliable 132 kV transmission line between Mutundwe substation (near Kampala) and Masaka
West (near Kampala) substation with 137 km of new double circuit 220 kV transmission line
between Kawanda and Masaka West substations. The existing 132 kV substation at Kawanda
(currently under construction as part of the AfDB-financed project to evacuate power from
BHPP) will be upgraded to 220 kV to accommodate both the incoming lines from Bujagali3 and
the two outgoing lines to Masaka. At Masaka, a new substation will be built adjacent to the
existing one and land for the new substation has already been procured and fenced off. Addition
of shunt reactors is planned for at Mbarara substation. The estimated cost of this component,
including resettlement, is US$128.3 million; of which IDA financing is US$95.0 million4..
19. Component B covers Technical Assistance (TA) to the Implementing Agency (IA), the
Uganda Electricity Transmission Company Limited (UETCL). It will include preparatory
studies for other essential segments of expansion/reinforcement of the transmission network
(specifically the 132 kV Lira–Gulu-Nebbi-Arua transmission line). In addition, it will include
financing of necessary consultancy services for supporting procurement activities and
construction supervision of Component A. The TA will also cover strengthening of UETCL‘s
ability to implement the proposed Project and facilitate strengthening of the planning and
management capacity within UETCL. The estimated cost of this component is US$7.6 million;
and this is fully financed by IDA.
20. Finally, Component C will finance investment and TA activities that are to be
implemented by the Ministry of Energy and Mineral Development (MEMD). The component
includes community support projects that will benefit communities and households in the region
and along the line route who may not benefit directly from the construction of the new
transmission line as well as actions to strengthen the planning and implementation capacity of
the MEMD. Specifically, the investment sub-component consists of: (a) Street and Market
Place lighting in Masaka municipality; (b) Peri-urban electrification along the line route and
affected areas of Kawanda and Masaka; and (c) Establishment of a Power Sector Information
3 The two lines connecting Bujagali switch yard and Kawanda substation will be built at 220 kV but operated
initially at 132 kV. AfDB is using cost savings from their ongoing project to upgrade the 132 kV substation at
Bujagali to 220 kV. 4 This amount of US$95.0 million includes physical and price contingencies.
7
Center (PSIC). These activities are to be adequately supported by necessary TA components
consisting of consultancy services, studies and activities related to sectoral development.
Specifically, the TA sub-component consists of: (a) a review of the Power Sector Reform
Program; (b) Consultancy support for the design and implementation of the investment sub-
components; (c) Support for the Energy and Mineral Development Sector Working Group
(SWG); and (d) Capacity building and training at the MEMD. The estimated cost of this
component is US$11.8 million; and this is fully financed by IDA.5
B. Project Financing
1. Lending Instrument
21. The proposed lending instrument is a Specific Investment Loan (SIL) in the amount of
SDR74.1 million (US$120 million equivalent). The Credit will be repayable over a period of 40
years, including a 10 year grace period. A Service Charge of 0.75% per annum will be charged
on outstanding balances. In addition, a commitment fee of 0 - 0.5% per annum will be charged
on undisbursed balances of the Credit (subject to the discretion of the Board). The GoU will on-
lend US$95.0 6million (or equivalent) to UETCL at an annual interest rate of 0.75% for a period
of 40 years including a grace period of 10 years (same as IDA terms). For the TA components,
the GoU will provide an amount of US$7.6 million to UETCL in the form of a grant.
2. Project Financing Table
22. The table below summarizes the project financing plan.
Project Components Project cost7 IBRD or IDA
Financing
%
Financing
A. Construction of new Kawanda-Masaka transmission line and related upgrades to substations, including resettlement
B. Technical assistance to UETCL
C. Technical assistance to MEMD and Community Support projects D. Unallocated
Total Baseline Costs
Physical and Price contingencies
Total Project Costs
Total Financing Required
112.4
7.6
11.8 5.6
137.1 15.8
153.2 153.2
79.2
7.6
11.8 5.6
104.2 15.8
120.0 120.0
70
100
100 100
76 100
78 78
IV. Implementation
A. Institutional and Implementation Arrangements
23. Components A and B of the proposed Project will be implemented by UETCL, the state-
owned transmission company, which has prior experience in implementing IDA-financed
projects, as well as similar projects financed by other multilateral and bilateral lending agencies.
5 The cost figures for components A, B and C are inclusive of taxes and duties as applicable. In addition, an amount
of about US$5.6 million has been left as unallocated. 6 This is for Component A excluding resettlement cost and applicable taxes and duties.
7 Inclusive of taxes and duties.
8
A Project Management Unit (PMU) established within the UETCL will be specifically
responsible for implementation of these two components. The PMU will comprise existing staff
in the Projects Implementation Department of UETCL, supported by the other user departments
and a few specialist consultants who will be financed through the Credit and will be retained (as
consultants) to ensure efficient implementation. Appropriate Technical Assistance (TA) is
included to support implementation, especially in the areas of procurement processing and
supervision of construction works. Capacity assessments of UETCL in areas of procurement and
financial management were carried out, shortcomings were identified and appropriate remedial
measures have been agreed upon.
24. The MEMD will be responsible for implementation of Component C. Implementation
of some of the strategic studies and functioning of the SWG will be directly managed by the
MEMD. The investment sub-component will be implemented by the Electric Power Division
(EPD) of the MEMD. This would require the EPD to carry out the associated procurement and
disbursement functions as well. The EPD has been implementing IDA financed projects under
two ongoing operations and has the capacity to implement the investment activities of this
component. However, in view of the increased work load on account of major investment
activities planned for in the near future, the EPD capacity would need to be strengthened.
Accordingly, it was agreed that the EPD staff strength would be augmented by a few additional
experts who will be retained as consultants (during the implementation period) and financed by
the Project. Capacity assessments of EPD in areas of procurement and financial management
were carried out, shortcomings identified and remedial measures agreed upon. Additional details
of implementation are included in Annex-3.
B. Results Monitoring and Evaluation
25. The framework for results monitoring and evaluation is detailed in Annex 1. Baseline
values for the key PDO indicators, as well as targets, data sources and responsibilities for data
collection have been agreed with the GoU and the Implementing Agencies (IAs).
C. Sustainability
26. Sustainability of the proposed Project depends first on UETCL having the technical and
financial capacity to meet the demand for electricity in the Project service areas. This in turn
requires that: (i) the Bulk Supply Tariff (BST)8 fully covers the cost of purchasing power from
generation companies plus the prudently incurred costs of operating the transmission network;
(ii) there will be sufficient power available from generators to supply the customers‘ needs and
utilize the network capacity made available by the transmission company; and (iii) the
distribution companies are able to connect new customers, collect monies for services provided
and remit payment to UETCL for wholesale power supply. Long term sustainability also
depends on a program of regular repair and maintenance of the new equipment to ensure that its
operating life is consistent with normal industry expectations. Good institutional practices
(routine maintenance, inventory management, human resource management etc.), adequate
company finances, and a stable political environment are all factors that will contribute to the
project‘s long term success and sustainability.
8 The BST is the tariff at which UETCL sells power to the distribution companies.
9
27. With respect to the BST, the Electricity Regulatory Authority (ERA), at the behest of the
GoU, has held the BST below the level needed to fully cover the costs of bulk power supply on
the grounds that the current reliance on costly thermal generation is a short-term distortion which
will be mitigated after the BHPP comes on line (currently expected in April 2012). Rather than
disrupt the economy by passing these costs to consumers, the GoU has decided to provide
subsidies to UETCL to avoid increasing the BST while covering the cost of capacity and energy
purchases from the thermal plants. In the longer term, the BST should be set at a level which
allows UETCL to recover its prudently incurred costs of service, including its debt service
obligations and its contributions to the financing of capital investments, without having to rely
on government handouts. The Bank, through its ongoing dialogue with the GoU, will press for
the return to full cost-recovery tariff setting as soon as possible. As regards the availability of
adequate generation, Uganda is actively seeking financing for the next plants in its generation
expansion plan. However, in light of recent developments, particularly in the oil sector, the plan
will require continuous monitoring and updating in order to reflect changing expectations for
generation options and load growth. Finally, as regards the financial health of the distribution
company, UMEME enjoys a sufficient margin, and to date inter-company receivables have not
been a major issue.
V. Key Risks
28. The most immediate risk to the Project relates to the construction of the upstream
transmission line from Bujagali switch yard to Kawanda substation. Completion of this line,
which is being financed by AfDB, has been delayed because of unresolved land acquisition
issues. The primary function of Kawanda substation is to evacuate power from Bujagali; delays
in completing this transmission line will cause similar delays in the activation of the substation.
The Kawanda substation is clearly a critical component of the proposed Project. For this reason,
making arrangements satisfactory to the Bank for resolving outstanding claims by displaced
persons relating to the Bujagali–Kawanda transmission line is a condition of effectiveness (para.
53). In addition, based on the lessons learned from implementation of the Bujagali
Interconnection Project (BIP), finalization of a satisfactory plan for implementation of the RAP
for the Kawanda—Masaka transmission line, including confirmation that the necessary funds
have been budgeted and will be made available when needed, is an additional condition of
effectiveness (para 49).
29. Weak financial performance within the power sector institutions is a particular risk to
the viability of the proposed Project. The ongoing dependency of UETCL on subsidies from the
GoU to cover power purchases is particularly undesirable as adjustments to the subsidies often
lag behind changes in energy prices leading to erosion of the company‘s cash resources9. The
reliance on subsidies means that the company‘s – and by association the project‘s – financial
viability is dependent on ongoing budget allocations with no clear source of fiscal revenues to
ensure that funding is available. In theory, as lower cost sources of power such as BHPP come
on line, the need for subsidies should decline, but at present establishing a clear path or
commitment to reduce reliance on government funds is not part of the overall dialogue on
government finances. Another risk is the lack of integrated and coordinated system planning,
9 Very recently, UETCL has started to delay payments to the private power generators as UETCL is not receiving
the required budgetary support from GOU. This is now under review by the Government.
10
leading to sub-optimal investments in both generation and distribution. This can adversely affect
the availability and cost of power supply as well as the adequacy of downstream distribution
capacity and market access initiatives. There is also a risk of non-availability of adequate
generation to meet growing demand for electricity at the national level, which would have
repercussions on the areas to be served by the proposed Project and on the benefits derived.
Ongoing monitoring and dialogue with the GoU will be maintained in order to ensure that issues
related to inadequate generation, timeliness and realism of generation expansion plan etc. are
adequately addressed.
30. In general, the overall implementation efficiency of government agencies in Uganda is
not considered very satisfactory. While there is no reason to assume that this is also true for
UETCL, where the overall level of competency is limited, there is always a risk that the most
competent individuals will become overextended in trying to respond to both internal and
external demands on their time. As such, adequacy of UETCL‘s capacity to execute projects has
been carefully assessed, and necessary support will be provided as part of the consultancy
services financed by the proposed Project.
31. Finally, as discussed later, the construction of the transmission line is expected to
adversely affect about 2,136 households involving 13,596 Project Affected Persons (PAPs), who
will need to be compensated adequately. In order to ensure that the finances necessary for
resettlement are readily available, during negotiations it was agreed that appropriate budgetary
provisions for this purpose will be made at the budget session immediately following the
negotiations. These risks and their mitigation measures have been detailed in Annex-3 and
Annex-4.
VI. Appraisal Summary
A. Economic and Financial Analysis (Annexes-7 and 8)
32. A cost benefit analysis was carried out for Component A of the proposed Project. The
primary benefits that were monetized include reductions in unmet demand on the part of existing
customers in the Masaka service area, increased capacity to meet existing and future demand in
the region, incremental sales to export markets in Rwanda and Tanzania, reductions in system
transmission losses, and savings in repair and maintenance costs of the Kawanda-Masaka
transmission link. The estimated EIRR of the project is 22.2 percent and the NPV at a 12 percent
discount rate is US$133.3 million. Apart from the monetized benefits, the Project will also
contribute to improvements in the socio-economic and environmental well-being of the region.
Access to electricity can benefit local populations through improved health care, education, and
personal security, as well as employment and other income earning opportunities. While this
particular study has not attempted to quantify or assign a monetary value to these benefits, they
should not be ignored in assessing the economic returns from the Project.
33. The financial benefits of the project include incremental tariff revenues accruing as a
result of increased kWh delivered to existing customers in the Masaka area (owing to reduced
outages), incremental transmission tariffs on new domestic and export loads served owing to the
lifting of capacity constraints, savings in transmission losses, and savings in the costs of
11
maintaining the existing transmission line to the Masaka area. The estimated FIRR of the project
is 9.2 percent and the NPV at the weighted average cost of capital (WACC) is US$93.55 million.
Sector Financial Position
34. Prior to 2005, the power demand in Uganda was largely met by hydro, but drought in
2005 caused a sharp fall in hydro output forcing GoU to contract with high-cost rental thermal
plants. Continued depreciation of the local currency and volatility in oil prices are contributing
to the increased costs of power purchases denominated in US$ which is negatively impacting the
overall sector financial position. The current weighted average end-user tariff is USh287/kWh
(USc 12/kWh). Even at this high rate, the tariff is not adequate to cover costs. Effects of
inadequate tariff are compounded by the fact that more than one-third of electricity generated is
not paid for (30% of distribution losses, 4% of transmission losses, and 4% of non-collection).
35. GoU is obligated to meet the contractual costs of power generation and the costs of
distribution franchisee UMEME. To keep the tariff from going up at the consumer level, the
regulator keeps the bulk supply tariff that UETCL charges to UMEME at less than full cost
recovery level. The resulting shortfall is provided by GoU as subsidy to the sector. During the
period FY05-10, GOU provided direct budgetary support of US$528 million 10
to UETCL to
cover for the costs of power purchase. However, budgetary support has not always been paid on
time. In recent months, UETCL has had to resort to delaying payments to power generators as
there has been delay in releasing the necessary budgetary support from GoU. Continued reliance
on the thermal power to meet the growing demand coupled with government‘s strategy of not
passing on the increased costs to consumers will result in increasing requirements for
government subsidy to the sector.
UETCL Financial Position
36. Increasing share of high-cost thermal power in the generation mix has resulted in the
operating costs of UETCL going up. There has been a five-fold increase in power purchase costs
(including fuel) during FY05-10 and it currently constitutes about 95% of the total operating
costs of UETCL, up from about 80% in 2005. Electricity revenues during FY05-10 have
increased by an annual average rate of only about 30% compared to the annual increase of about
40% in power purchase costs (including fuel) during the same period.
37. UETCL is allowed by the regulator to cover only cash operating costs and debt services
from the BST. Non-cash items like depreciation, bad debts, and foreign exchange losses etc., are
not allowed to be recovered. This limits UETCL‘s ability to generate funds for maintenance of
existing assets and for future capital investments. The methodology for setting BST needs to be
reviewed taking into consideration UETCL‘s needs for adequate repair and maintenance of
existing assets and for funding a portion of the investment program and other financial
requirements. This review will be included within the Terms of Reference for the Study on
Review of Sector Reforms.
38. UETCL has drawn up an ambitious investment program of US$1.58 billion during
FY11-16, to keep pace with the generation expansion program that envisages increasing the
10
This includes support from IDA to cover cost of operating Mutundwe plant (para 11, Annex 8)
12
current installed capacity of 580 MW to more than double by FY16. Significant capacity
additions from hydro-power are envisaged for the near future. These include: Bujagali 250 MW
by April 2012, Isimba 100 MW by July 2014, Karuma 600 MW of which, 250 MW is expected
by July 2016. In order to recover the costs of generation, transmission, and distribution of the
additional power during FY11-16, and to adequately maintain the existing assets, the estimated
full cost-recovery end-user tariff in FY16 will have to be significantly higher than the current
average tariff rate of USc12/kWh. If the end-user tariff is to remain at the current level, the
government subsidy requirements will be in the range of US$1.5 billion during FY11-16.
39. UETCL‘s financial analysis for the period FY11-16 is discussed in Annex-8.
Assumptions (as agreed with UETCL) used for preparing the financial projections are included
in Attachment 1. Consolidated financial statements of UETCL (including projections under
base case scenario) are included in Attachment 2.
Financial Targets:
40. UETCL is required to: (i) generate sufficient funds (from revenues charged to UMEME,
export revenues, and GoU transfers) to cover its debt service obligations thus maintaining a debt
service coverage ratio (DSCR) of 1.0 throughout the project period; and (ii) maintain an
EBITDA ratio (Earnings before Interest, Taxes, Depreciation, and Amortization divided by total
revenues) of at least 1% in FY11, 1.5% in FY12-13, 2% in FY14, and 3% in FY15-16.
B. Technical
41. The proposed technical solutions are generally satisfactory and consistent with the long
term least cost plan for the development of the national transmission network.
42. While UETCL has only limited experience with 220 kV networks, the proposed Project
envisages substantial support and training in the detailed design and preparation of technical
specifications, tendering and bid evaluation, and construction management. Construction will be
tendered in one turnkey contract which will place the primary burden for satisfactory completion and
performance on the contractor.
C. Financial Management
43. Financial management (FM) assessments of UETCL and MEMD were carried out in
accordance with the Financial Management Manual for World Bank Financed Investment
Operations issued March 2010. As implementers of the proposed Project, the results from the
assessments indicate that the overall FM risk rating for UETCL and MEMD is Medium with an
associated Low Impact on the PDO. FM arrangements are considered adequate to provide, with
reasonable assurance, accurate and timely information on the status of the Project as required by
IDA.
44. Both MEMD and UETCL have managed various Bank funded projects including the
Fourth Power Generation Project and ERT-I while ongoing projects are Power Sector
Development Operations and Energy for Rural Transformation Phase II. Details of the findings
and conclusions of the assessment are provided in Annex 3.
13
D. Procurement
45. Procurement under the project will follow the Guidelines: Procurement under IBRD
Loans and IDA Credits (May 2004, revised October 2006 and May 2010), Guidelines: Selection
and Employment of Consultants by World Bank Borrowers (May 2004, revised October 2006
and May 2010) and Guidelines on Preventing and Combatting Fraud and Corruption in Projects
Financed by IBRD Loans and IDA Credits and Grants‖ (dated October 15, 2006 and revised in
January 2011). Assessments of the capacity of the national implementing agencies to undertake
procurement activities were carried out by the Bank in October 2010. The assessments reviewed
the organizational structure and functions, past experience, staff skills, quality and adequacy of
supporting and control systems, and legal and regulatory framework. The risk for procurement is
High and reducing to Substantial after mitigation.
46. The national legislation on public procurement as laid out in the Public Procurement and
Disposal of Assets Act is generally consistent with the World Bank‘s guidelines, except for some
provisions that will be addressed during the ongoing exercise of revising the law as part of the
Poverty Reduction Strategy Credit. The exceptions are listed in Annex 3. At the country level,
the major country procurement risks include: (i) limited compliance with the Act as indicated in
audit reports from the Public Procurement and Disposal Authority (PPDA); and (ii) the
inadequate capacity and experience in the implementing entities to conduct procurement. This
risk will be mitigated for the proposed Project by: (a) IDA‘s monitoring through prior review and
post review of contracts and supervision missions; and (b) training of the procurement staff in
the implementing agencies under the project.
47. Procurement for the proposed Project at the national level will be conducted by the
UETCL and the MEMD, for whom procurement capacity has been built under the predecessor
IDA-supported projects. The key risks are: (i) slow processing of procurement; (ii) limited
experience in the selection of consultants using IDA procurement procedures; (iii) the inadequate
structure of the UETCL Procurement Unit to conduct procurement; (iv) inadequate staffing in
the technical departments to support the procurement and contract management; and (v)
inadequate monitoring of procurement progress. These risks shall be mitigated by: (a)
establishment of a procurement monitoring system in UETCL and MEMD; (ii) recruitment of
additional staff/consultants in the technical departments in UETCL and MEMD; (iii) revision of
the structure of the Procurement Unit in UETCL; (iv) establishment of a contract management
system in UETCL and MEMD; and (v) continued training of UETCL and MEMD staff in
procurement.
E. Social (including safeguards)
48. The proposed Project will finance a new 220 kV transmission line with a length of 137
km between Masaka and Kawanda, which has implications on access to land and other assets on
it. Therefore, to mitigate the social impacts associated with land acquisition, a Resettlement
Action Plan (RAP) consistent with national and World Bank Group standards was prepared and
disclosed both in-country and at the World Bank Infoshop in December 2010. The project was
initially categorized as B, as its environmental impacts are moderate and the initial census
indicated some 6-7,000 project-affected people, of which about 10 percent would have to be
permanently resettled. During project preparation, both the technical work and census
14
subsequently indicated that the construction of the transmission line would affect about 2,136
households with 13,596 PAPs, of which 1,152 PAPs (representing 8% of the total) need to be
resettled, with the remainder being compensated for their loss of assets and/or partial loss of
land or access to land. In light of the larger numbers of PAPs, Management decided to upgrade
the project to Category A. All PAPs will be compensated for their losses that include crops and
structures. Compensation will also be made for land within the five meters width that will be
occupied by the towers and the lines. The RAP provides options for both cash and land for land
compensation. UETCL has become innovative in the acquisition of way leaves such that the
17.5 meters on both sides of the towers and lines will not be permanently evacuated of human
activities but regulated to ensure safety and will therefore be temporarily acquired during
construction of the transmission line. In order to facilitate implementation of the RAP, UETCL
is in the process of recruiting consultants. Also, independent monitoring of the RAP execution
will be carried out by the MEMD through support of independent consultants. Construction
related social impacts have been addressed in the ESIA that has been prepared and disclosed
appropriately.
49. A socio-economic survey was undertaken and a database of the affected people with
their expected losses and determined entitlements set up to ensure a transparent and
comprehensive compensation process. The RAP was undertaken in a consultative manner with
the project affected people, local leaders and other relevant stakeholders. A diversion of 33 kms
was made from the earlier identified route in order to avoid highly encumbered areas that
included a cultural entity graveyard. A grievance redress mechanism that uses existing systems
and structures has been clearly described in the RAP and includes the Uganda Courts of Law as a
last resort. Compensation of economically affected people and other resettlement measures will
be carried out before start of construction.11
50. The cost for compensation and resettlement of affected people was initially estimated in
the Feasibility Study Update at US$27 million. However, with the diversion and adoption of
innovative ways of non-acquisition of the maintenance tracks, the estimated RAP budget is
US$12.9 million; this will be financed by the Government.
51. The proposed Project will also finance upgrading of substations at Kawanda (presently
under construction) and Mbarara. In addition, the proposed Project will finance the construction
of a new sub-station at Masaka adjacent to the existing one; the land for the new sub-station has
already been acquired and fenced off. None of these activities involve acquisition of any
additional land and there is no potential loss of private property or means of livelihood.
52. The proposed Project will also finance Community Support projects along the
transmission line. This includes the: (a) provision of lighting on selected streets and market
places in the Masaka municipality; and (b) electrification of peri-urban areas along the
transmission line. The Municipal Council of Masaka has already selected the streets and market
places. The selection for peri-urban electrification will be based on specific selection criteria as
agreed with the MEMD. These activities will enable people enjoy the benefits of electrification
on account of transmission line that will be traversing their area. Implementation of this program
11
The GoU will be required to prepare and adopt an action plan for the implementation of the RAP; in a manner
satisfactory to the Association; this is a condition of effectiveness (para 28).
15
will be undertaken by MEMD. Any land acquisition needs resulting out of the community
support projects will be addressed through the application of the Resettlement Policy Framework
(RPF) prepared and disclosed in-country and at the Bank‘s Infoshop in December 2010. This
RPF will guide the preparation of any resettlement instruments for other future investments in
the sector.
F. Environment (including safeguards)
53. The Project is a Category A, given the magnitude of the land acquisition/involuntary
resettlement. . The proposed 137 km 220 kV Kawanda–Masaka Transmission Line, will connect
the Kawanda Substation (under construction as a component of the Bujagali Interconnection
Project (BIP) and for which an ESIA and RAP are under implementation12
), to the Masaka
Substation, which will be built adjacent to the existing substation at Masaka. The Borrower has
prepared an Environmental and Social Impact Assessment (ESIA) Report, which includes an
analysis of alternatives and the specific and broader environmental and social impacts of
construction of the transmission line, the upgrading of the sub-stations at Kawanda and Mbarara
(for these upgrading activities there are no resettlement issues, as they are on existing premises)
and construction of a new substation at Masaka that will be built adjacent to the existing one.
Necessary land has already been acquired. The transmission line will pass through the fringes of
nine (9) degraded forest reserves of which in total 35 hectares (ha) will be affected by the
transmission line corridor, 12 plantations of which 12.2 ha will need to be cut and 10 wetlands of
which 49.2 ha will be affected. Adequate mitigation measures to protect the remaining part of
the forest reserves have been included in the Environment and Social management Plan (ESMP).
A biodiversity inventory was prepared and as far as it is known the affected natural habitats are
not critical natural habitat as defined under OP4.04.
54. The ESIA has provided detailed information on potential impacts of the transmission
line and mitigation measures for such impacts. The ESIA also includes impact mitigation of the
peri-urban electrification and street and market place lighting at Masaka Township. This
includes measures for Natural Habitats (OP/BP 4.04), Physical Cultural Resources (OP/BP 4.11)
and Forests (OP/BP 4.36). The social sections above (paras 47-51) have addressed the trigger
for OP/BP 4.12 Involuntary Resettlement and the mitigation measures adopted.
55. The initial line route was identified in 2006 by a team of the Feasibility Consultants and
the ESIA Consultants. The losses in forest reserves which cannot be avoided will be
compensated. It is being proposed that these compensation funds be used to strengthen the
management of the remaining forest reserves. Additional biodiversity surveys were carried out
12
Since the power to be transported through the Kawanda–Masaka transmission line will need to be supplied from
the BHPP through the Bujagali-Kawanda section of the BIP, this section is considered associated to the proposed
Project. Resolution of RoW issues of the BIP has been a major problem that has delayed completion of construction
works by more than a year. Through concerted efforts of the GoU, these are now gradually getting resolved and the
total number of disputed cases has come down from 79 as of November 2010 to 24 as of March 2011. Of this, total
number of unresolved issues on the Bujagali-Kawanda section is eight; this includes two on tower spots. Since the
Kawanda–Masaka transmission line can only function when the Bujagali-Kawanda transmission line is operational,
the making of satisfactory arrangements for resolving outstanding claims relating to the Bujagali-Kawanda
transmission line is a condition of effectiveness (para 28).
16
during the finalization of the ESIA in order to identify sensitive ecological areas to be avoided
during the fine tuning of the final line route. Possible impacts on ten (10) graveyards, eight (8)
commercial shrines and a number of possessed trees were further analyzed in the RAP. Public
Consultation was carried out in 2006 and 2010, and has been extended along other parts of the
transmission line. This final round of Public Consultation has been finalized after disclosure and
has been included in the final ESIA. The satisfactory institutional arrangements have been
included in the ESIA. UETCL has gained experience with the implementation of World Bank
safeguard policies under the ongoing BHPP and the BIP. UETCL has its own environmental and
social unit, which still needs strengthening. The ESIA and ESMP will be attached to the bidding
documents, based on which the Contractor will be required to prepare and implement his own
Contractor ESMP (CESMP). The Consultant will be required by contractual arrangement to
supervise the adequate implementation of the CESMP. Most of the costs for the implementation
of the ESMP will be included in the CESMP. ESMP responsibilities to be carried out by
UETCL are included separately in the project budget.
G. Other Safeguard Policies (if required)
56. The safeguard policies which are triggered are: Environmental Assessment OP/BP4.01;
Natural Habitats OP/BP4.04; Physical Cultural Resources OP/BP4.11; Involuntary Resettlement
OP/BP4.12 and Forests OP/BP4.36. Furthermore, the World Bank Group General
Environmental, Health and Safety (EHS) Guidelines and the Electric Transmission and
Distribution EHS Guidelines are also applicable. The compliance with these safeguard policies
and guidelines are demonstrated by the ESIA and the RAP.
57. The Borrower prepared an ESIA in 2006 as part of the feasibility study. The ESIA was
updated in October 2010 by an independent ESIA consultant and disclosed in December 2010.
Table 1: Safeguard Policies Triggered
Safeguard Policies Triggered by the Project Yes No
Environmental Assessment (OP/BP 4.01) [X]
Natural Habitats (OP/BP 4.04) [X]
Pest Management (OP 4.09) [X]
Physical Cultural Resources (OP/BP 4.11) [X]
Involuntary Resettlement (OP/BP 4.12) [X]
Indigenous Peoples (OP/BP 4.10) [X]
Forests (OP/BP 4.36) [X]
Safety of Dams (OP/BP 4.37) [X]
Projects in Disputed Areas (OP/BP 7.60)* [X]
Projects on International Waterways (OP/BP 7.50) [X]
* By supporting the proposed project, the Bank does not intend to prejudice the final determination of the parties' claims on the
disputed areas.
17
58. Disclosure. Both the ESIA and RAP for the transmission line were disclosed in-country
on December 13 and 3, 2010, respectively, and in the Bank‘s Infoshop at Washington, D.C. on
November 30 and December 6, 2010, respectively. The RPF for the community support projects
and other unforeseen land acquisition related concerns was disclosed in country and at the
InfoShop on December 10, 2010.
18
Annex 1: Results Framework and Monitoring
Project Development Objective (PDO): To improve the reliability and increase access of electricity supply in the northeast and southwest regions of Uganda.
PDO Level Results
Indicators* Co
re
Unit of Measure Baseline Cumulative Target Values** Frequency
Data Source/
Methodology
Responsibility
for Data
Collection
Description (indicator
definition etc.)
YR 1 YR 2 YR3 YR 4 YR5
Indicator One: Improved
reliability of supply in the
Masaka area on account of
reductions in: (a) average
transmission line outage per
year; (b) average outage time;
and (c) un-met demands of
existing consumers
(a) No. of
outages per
year;
(b) Outage
time (hours);
and
(c) MWh of
un-met demand
35
5.7
2.34
0
0
0
0
0
0
0
0
0
0
0
0.
10
2.6
0.2
Annual
UETCL outage
statistics
UETCL
Un-met demand
diminishes to zero after
commissioning due to
the N-1 reliability
Indicator Two: Increase in
flow of electricity through the
Masaka substation owing to
increased capacity of
transmission line (i.e. over and
above those attributable to
reduced outages).
GWh
MW
381
65
0
0
0
0
0
0
0
0
617.4
105.2
Annual
UETCL
transmission
data, Masaka
substation
UETCL
Indicator Three: Direct
project beneficiaries (number)
of which female (%)
(a) Number
(b) %
0
0
0
0
0
0
0
0
640013
51
Annual
UETCL
transmission
data, Masaka
substation
UETCL
Direct project
beneficiaries are people
gaining access to
electricity due to the
transmission line
INTERMEDIATE RESULTS
Intermediate Result (Component A): Construction of a 220 kV transmission line from Kawanda to Masaka and related substation upgrading
Intermediate Result indicator
Two: Transmission line (km)
constructed under the project
km
0
0
0
0
0
137
Semi-
annual
Supervision
missions, PMRs
IDA, PMU
Intermediate Result indicator
Five: Resettlement packages
provided to all project affected
persons (PAP) – 13,642
% of PAP
0
5
45
85
95
100
Semi-
annual
Reports of
agency
implementing
RAP
IDA, PMU
13
This is based on the assumption that there will be only 1000 new households connected during the first year of operation, each household is assumed to have 6.4 members.
19
Intermediate Result (Component B): Technical Assistance to UETCL
Intermediate Result indicator
Completion of training as a
part of capacity building for
UETCL (number of people)
Number
0
0
10
20
30
30
Semi-
annual
Supervision
missions, PMRs
IDA, PMU
Intermediate Result (Component C): Community Support Projects and Technical Assistance to MEMD
Intermediate Result indicator
One: Social development
projects completed (a) No. of
streets lit; (b) No of market
places lit; and (c) no. of
people provide with access to
electricity under the Project
(a) Number
(b) Number
(c) Number
0
0
0
0
0
0
1
1
15,500
2
2
31,000
3
3
45,500
3
3
50,000
Semi-
annual
Supervision
missions, PMRs
IDA, MEMD
Item (c) includes
secondary beneficiaries
who could get the
benefits even if the
transmission line was not
built.
Intermediate Result indicator
Two: Completion of training
as a part of capacity building
for MEMD (number of
people)
Number
0
12
24
36
46
46
Semi
annual
Supervision
missions, PMRs
IDA, MEMD
Intermediate result indicator
Three; MEMD Sector
Information Center
established
Yes/No
no
no
no
no
no
yes
Semi-
annual
Supervision
missions, PMRs
IDA, MEMD
*Please indicate whether the indicator is a Core Sector Indicator (see further http://coreindicators)
**Target values should be entered for the years data will be available, not necessarily annually.
20
Annex 2: Detailed Project Description
Component A - Construction of a 220 kV Kawanda-Masaka Transmission Line
1. The new 220 kV Kawanda Masaka transmission line will ensure more reliable electricity
supply to customers in the southwest region of the country, allow connection of additional loads
in the area and also provide a stable foundation for growth in future exports to Rwanda and
Tanzania. This component will compliment and will finally replace an old and unreliable 132
kV transmission line to Masaka which is frequently out of service for extended periods of time.
Investments include:
Construction of a 137 km double circuit 220 kV transmission line with 240 mm2
twin
AAAC conductor per phase from Kawanda to Masaka;
Upgrading of the existing 132 kV sub-station at Kawanda to include 132/220 kV interbus
transformer, 220 kV busbar, 2x220 kV transformer bays, 2x132 kV transformer bays, and
2x220 kV line bays for incoming 220 kV lines from Bujagali;
Extension of the 220 kV sub-station at Kawanda to include 2x220 kV line bays for the
two Kawanda–Masaka 220 kV transmission line circuits;
Construction of a new 220/132 kV sub-station at Masaka adjacent to the existing Masaka
132/33 kV substation. This substation will be equipped with 2x220/132 kV, 60MVA
transformers and associated transformer bays; and 2x220 kV line bays for the two
Masaka–Kawanda 220 kV transmission line circuits;
Installation of 2x15 MVAr, switched shunt reactors and associated equipment at Masaka and
Mbarara substations and 1x15 MVAr, switched shunt reactor and associated equipment at
Kawanda substation for voltage control during light loading conditions;
Implementation of the RAP including resettlement – this activity is being fully financed
by the Government.
2. Details of the investments are included in the following tables.
21
Cost Estimates for Transmission Line
Details Cost (US$)
Towers & Supports 9,605,299
Foundation Materials 3,938,172
Conductor 5,505,324
OHGW / OPGW 1,491,223
Insulators 1,613,690
Line Hardware 864,477
Total Cost of Materials 23,018,185
Tower Erection Costs US$ 2,468,562
Conductor Stringing 3,303,194
Easements, ROW & Access Clearance 952,440
Subtotal 29,742,381
Contingency (20%) 5,948,476
Total 35,690,857
Average Cost Per km 249,662
Cost Estimates for Masaka 220kV Sub-station works
Cost Estimates for Kawanda 220kV sub-station works
Description Unit cost
US$
Quanti
ties Total Cost US$
250MVA 132/220kV
Interbus Transformer 3,500,000 2 7,000,000
220kV Busbars & Gantries
560,000 1 560,000
220kV Bus Coupler 1,760,000 1 1,760,000
220kV Transformer Bays 1,400,000 2 2,800,000
132kV Transformer Bays 875,000 2 1,750,000
Masaka 220kV in coming
Line Bays and Accessories 1,760,000 2 3,520,000
Bujagali 220kV in coming
Line Bays and Accessories 1,760,000 2 3,520,000
15MVA Reactor 350,000 1 350,000
Reactor 33kV Control Bay 185,000 1 185,000
Associated Protection, Communication and
Control Equipment
715,000 1 715,000
Civil Works (Including
Plant house) 3,910,000 3,910,000
Subtotal 26,070,000
Contingency (20%) 5,214,000
Total 31,284,000
Cost Estimates for Mbarara Sub-station upgrading works
Description Unit Cost
US$
Quanti
ties
Total Cost
US$
15MVA Reactor 350,000 2 700,000
Reactor 33kV Control Bay 185,000 2 370,000
Associated Protection,
Communication and
Control Equipment
110,000 1 110,000
Civil Work
96,000 1 95,000
Subtotal 1,275,000
Contingency (20%) 255,000
Total 1,530,000
Description Unit Cost
US$
Quanti
ties
Total Cost
US$
125MVA 132/220kV Interbus Transformer
2,800,000 2 5,600,000
220kV Busbars & Gantries 1,360,000 1 1,360,000
220kV Bus Coupler 1,760,000 1 1,760,000
220kV Transformer Bays 1,400,000 2 2,800,000
132kV Transformer Bays 875,000 2 1,750,000
132kV Busbars Extension
(Busbars & Gantries) 476,000 1 476,000
Kawanda 220kV in coming Line Bays and Accessories
1,760,000 2 3,520,000
15MVA Reactor 350,000 2 700,000
Reactor 33kV Control Bay 185,000 2 370,000
Associated Protection,
Communication and Control Equipment
820,000 1 820,000
Civil Works (Including
Plant house) 3,950,000 1 3,950,000
Subtotal 22,106,000
Contingency (20%) 4,421,200
Total 26,527,200
22
Project Cost Summary
SUB-COMPONENT
Local Cost
million US$
Foreign
Cost Total Cost
million US$ million US$
137 km of Kawanda – Masaka 220kV double circuit
transmission line including engineering, route
clearing and access. 7,138,171 28,552,686 35,690,857
Upgrade of existing Kawanda 132kV substation to
include 220kV busbar, transformer bays and
incoming line bays to accept twin incoming 220kV
lines from Bujagali 6,256,800 25,027,200 31,284,000
Kawanda 220kV substation extension to include
extension of 220kV busbar, installation of 2 x
220kV line bays for the two Masaka transmission
line circuits and installation of 1x15MVAr reactor
and associated equipment.
Cost included
as a part of the
upgrading
Masaka 220kV substation to include:
5,305,440 21,221,760 26,527,200
2 x 220kV line bays to connect two Kawanda
-Masaka lines
2 x 60 MVA, 220/132kV transformers and
Bay equipment.
2 x 15 MVAr, shunt reactors and control
equipment
Mbarara North substation works to install 2 x 15
MVAr, switched shunt reactors and associated
equipment for voltage control. 306,000 1,224,000 1,530,000
Sub Total Excluding local taxes/ duties and RAP 19,006,411 76,025,646 95,032,057
Taxes and duties 20,298,847
20,298,847
Resettlement Action Plan (RAP) Costs 12,950,297 0 12,950,207
Total Costs 52,255,556 76,025,646 128,281,202
Component B – Technical Assistance to UETCL
3. The second component, which will be implemented by UETCL, includes technical
assistance to support the implementation of the proposed Project, to support the institutional
development of UETCL, and to advance preparation of the next phase of implementation of the
transmission expansion plan. The following consultancy assignments are proposed:
Support to UETCL in project implementation. This assignment will provide support as
needed for overall project management and coordination, in particular in the areas of
procurement, construction and safeguard aspects. Preparation of detailed design,
specifications and bidding documents for the Supply and Install contract is in progress.
This assignment is expected to cost about US$3.9 million;
23
Preparation of Feasibility Study, and the ESIA/RAP/RPF: This will be for the 132 kV
Lira-Gulu-Nebbi-Arua transmission link. Construction of this line will complete the
transmission ring encircling the country. These studies are expected to cost about
US$2.5 million.
Technical assistance – capacity building and institutional strengthening of UETCL: This
activity will focus on overall capacity building and institutional strengthening of UETCL
particularly in areas related to procurement, investment planning and management.
Areas to be covered will also include, among others, financial planning including capital
markets and debt management, cost accounting and cost control, integrated system
planning, and project planning and evaluation. This activity is expected to cost about
US$0.3 million; and
Technical Assistance to the UETCL-PMU: In order to strengthen the PMU in its
implementation of the Project, the UETCL will appoint a few additional experts (as short
term consultants) who will be selected on a competitive basis following Bank
Procurement Guidelines. This activity is expected to cost about US$0.9 million.
4. Total estimated cost of Component B is about US$7.6 million.
Component C – Community Support Projects and Technical Assistance to MEMD
5. The third component, to be implemented by the MEMD, includes investment
components, consultant assignments (some to provide implementation support) and necessary
training and capacity building at the MEMD.
A. The investment components include:
(a) Peri-Urban electrification: This contract will include intensification and expansion of
the distribution network, that are managed by the existing licencees (mainly UMEME),
and provision of connection to qualified households that meet the agreed selection
criteria. In both cases, the assets once constructed will become part of UEDCL‘s assets
to be operated by the relevant utility along the transmission line route. The MEMD will
work with the relevant utilities and the communities along the transmission line route and
connect selected poor peri-urban households to the main grid. Apart from financing the
connection, the MEMD, through the relevant utility, will finance pre-payment meters for
these households as well. Unlike the BIP which has experienced significant loss of
materials on account of theft and vandalism, the above initiative is expected to make the
proposed Project more relevant to the communities and convert potential ―project
vandals‖ to ―project protectors‖. The estimated cost of this component is US$7.2
million. Ùnder this sub-component, two categories of peri-urban household connection
will be considered. These are:
(i) Peri-urban electrification within the existing network: This will imply distribution
network intensification and include electrification of qualified households within the
existing distribution network. This activity can include: either a no-pole service
where connection can be made without installation of any new pole or, a one or two
24
pole service that will require installation of one or two poles to provide the
connection. Extension from a pole could connect more than one household in which
case the first household will be regarded as a one-pole service and the rest as no-pole
service. Using the current cost estimates, a summary budget would be:
2000 no pole connection @ US$200 per connection = US$ 400,000
1000 one/two pole service @US$800 per connection = US$ 800,000
Total for 3000 connections the estimated cost of connection = US$1,200,000
(ii) Peri-urban electrification outside the existing network: This will imply distribution
network expansion and will benefit the displaced households for whom UETCL will
provide land for land compensation. UETCL will provide land for these displaced
households, build housing units and provide electricity connection. Apart from the
PAPs, households within existing communities along the transmission line route will
be connected as well. The total number of households to be connected under this
program will be about 5000. For budgeting purposes, assuming that establishing the
network (i.e., extension of 11 kV or 33 kV lines and installing transformers, low
voltage reticulation etc) to cost around US$1200 per connection, total cost of
connecting 5000 new customers would be about US$6.0 million.
(b) Street and Market Lighting at Masaka municipality: With only about 4% of the street
area covered, the roads in Masaka municipality are in dire need of proper lighting.
Additional street lighting will make it safer for people to travel at night and allow more
commercial activities to be carried out beyond day light hours. Also, without any
lighting facility, vendors at market places in the municipality either shut down at dusk or
use kerosene lamps to continue with their business in the evening. This has sometimes
led to fires in which people lose their merchandise and suffer significant financial losses.
Lighting market places will extend market time so that people can come to the market
late after concluding their normal duties and sellers have more business time. This sub-
component will finance lighting of selected streets14
and market places15
in the
municipality; the selections have been confirmed by the Masaka Municipal Council.
Upon completion, the assets built will belong to the Masaka Municipal Council. While
the Council is responsible for payment of street lighting electricity bills, the payment of
bills at market places will be made by the vendors directly. The estimated cost of this
component is US$1.4 million.
(c) Power Sector Information Center: The post power sector reform era left the power
system documentation scattered with no single source center for information
dissemination purposes. Each institution viz., MEMD, UEGCL, UETCL, UEDCL, REA,
ERA, UMEME keeps on undertaking their own studies independent of others. When
finalized, these studies are kept to themselves with little or almost no sharing of
information within the sector agencies. This makes conducting subsequent studies
difficult. There is therefore a need to put in place a central information center where all
information of the Uganda electricity sector can be accessed. Useful information from
14
These include Yellow Knife, Hobart Street Katwe road and Katwe By-pass 15
These include: Ssaza market, Kyabakuza market and Nyendo market Ring Road
25
the UEB era is still maintained at the MEMD. This Information Center will be located
within the premise of the MEMD. The total cost of works including provision of
essential equipment is estimated at US$0.5 million.
B. The consultancy assignments include:
(a) Peri-Urban Electrification: This assignment will facilitate the peri-urban electrification
activity and will include interalia: design, preparation of bid documents, facilitation of
procurement, and supervision of the construction activities on behalf of the MEMD. The
assignment will also include: conducting awareness campaigns and sensitizing
workshops, monitoring and evaluation. The estimated cost of this activity is US$0.2
million.
(b) Street and Market Lighting at Masaka Municipality: This assignment will provide
necessary consultancy services to design, prepare the specifications and prepare the
bidding documents, support the procurement process and supervise the construction
activities on behalf of the MEMD. The estimated cost of this activity is US$0.1 million.
(c) Development of a Power Sector Information Center: The assignment would include
design and implementation of an appropriate center that will have an archival system
with data base available to the public. The assignment will also include setting up of the
centre with necessary training to MEMD staff to run it. The estimated cost of this
assignment is about US$0.2 million.
(d) A review of Power Sector Reforms: This activity will carry out a review of the power
sector reforms with a view to strengthening positive achievements and proposing
solutions to plug weak areas. The review will address the policy and legal framework,
institutional framework and the electricity service structures that is in place. The review
will utilize studies conducted since the reforms were implemented and recommend
follow-up actions. A consultant with experience in conducting similar sector reforms
elsewhere will be engaged to carry out the review and produce a report of findings and
recommendations on Power Sector Reforms that has been adopted by the GoU. The key
output of this study will be recommendations for consideration by Government in the
areas of policy review requirements and further legal/institutional reforms necessary to
strengthen the sector. The estimated cost of this assignment is US$0.6 million.
(e) Support for the Energy Sector Working Group (SWG): Under financing from the Bank
financed Power Sector Development Operations (PSDO), a SWG was set up by the
MEMD in 2007. The purpose of the SWG is to promote coherence and coordination of
various sector plans, improve the coordination between GoU and its development
partners so as to formulate a harmonized sector wide approach in pursuit of overall
development of the Sector in a sustained manner. Support for the Working Group will
end with closing of the PSDO i.e., June 2011. In order for the SWG to continue its
functions, the proposed Project will finance the operating budget of the SWG for a period
of four years starting in July 2011. The estimated cost of this subcomponent is US$0.6
million.
26
(f) Technical Assistance to the EPD: In order to strengthen the EPD in implementing the
investment component, the MEMD will appoint a few specialist consultants (on a fixed
term basis) who will be selected on a competitive basis following Bank Procurement
Guidelines. This activity is expected to cost about US$0.6 million.
(g) Training and Capacity building for MEMD staff will be in areas such as power system
planning, loss reduction, project planning and evaluation. For budgetary purposes, the
amount allocated is about US$0.3 million.
6. Thus, for the Component C, the total estimated cost is about US$11.7 million comprising
cost of consultancy studies at about US$ 2.3 million and cost of works at about US$9.1 million;
an amount of about US$0.3million is earmarked for training and capacity building.
27
Annex 3: Implementation Arrangements
Project Administration Mechanisms
1. Components A and B will be implemented by UETCL, a state-owned transmission
company that will own and operate the assets to be constructed under Component A and will be
the primary beneficiary of the TA under Component B. On behalf of UETCL, these components
will be implemented by a dedicated Project Management Unit (PMU) that will mainly comprise
UETCL staff supported by a few consultants.
2. Component C will be implemented by MEMD through the Electricity Power Division
(EPD) at the MEMD. As indicated earlier (Annex 2), this component includes implementation
of three works contract; these are: (a) Peri-urban electrification along the transmission line route;
(b) Street and market place lighting at Masaka municipality; and (c) Power Sector Information
Center (PSIC). The implementation arrangements for each of these components are discussed
below:
(a) Peri-urban electrification: Under this sub-component, electrification of peri-urban
households along the transmission line route will either involve intensification of
existing network which will imply connections to be contracted to the licensee involved
(such as UMEME) or expansion of a network that will be conducted by contractors
managed by the MEMD. It is anticipated that this component will connect 8000 new
consumers implying about 62,000 beneficiaries. Since provision of connection to these
consumers is not dependent on construction of the transmission line, they are considered
as secondary beneficiaries of the Project. The selection of households/consumers will be
based on the following criteria:
i. Proximity to the line route. Non-electrified households within a maximum
distance of 5 km on either side of the 220 kV transmission line will be considered.
ii. Only households classified as poor under poor income levels will be considered;
iii. For connection to be carried out, a qualified household will need to complete the
necessary internal wiring at its own expense; and
iv. Housing units should be of brick walls with iron sheets or tile roofs. Units of mud or
wattle or wattle walls or of grass thatch will not be selected to avoid fire hazards.
(b) Street and Market place lighting at Masaka Municipality: This activity will be carried out
by one works contract for two lots – one for street lighting and one for market place lighting.
The streets and market places have already been identified by the Masaka Municipal Council.
A consultant will be retained by MEMD to assist in the design and implementation of the
lighting facilities. Necessary coordination with the Municipal Council will be maintained at
all times during the design and implementation phase.
(c) Power Sector Information Center (PSIC): The MEMD will retain the services of a
qualified consultant to design and supervise the implementation of a functional Informational
28
Center at the MEMD. The consultant will need to coordinate with all sector agencies and
prepare necessary comprehensive documentation of all information available, analyze them,
archive them in the Center and develop a user friendly retrieval system for referral purposes.
Financial Management, Disbursements and Procurement
3. Financial Management and Procurement Capacity assessments have been carried out for
UETCL and MEMD and capacity constraints identified and remedial measures agreed upon.
These will be addressed largely through the capacity building activities pertaining to UETCL and
MEMD under the respective TA components.
Financial Management
4. Financial management assessments of UETCL and MEMD were carried out in
accordance with the Financial Management Manual for World Bank Financed Investment
Operations issued March 2010. As proposed implementers of the Project, the results from the
assessment do indicate that the overall FM risk rating for UETCL and MEMD is Medium with
an associated Low Impact on the PDO. FM arrangements are considered adequate to provide,
with reasonable assurance, accurate and timely information on the status of the project required
by World Bank.
Organization and Implementation
5. UETCL is a limited liability company incorporated in Uganda wholly owned by the
government through the Ministry of Finance, Planning and Economic Development headed by a
Chief Executive Officer who will be the ―Accounting Officer‖ for the Project. UETCL is made
up of eight departments of which the Project Implementation Department (PID) will be
responsible for overall implementation through a dedicated Project Management Unit (PMU) to
be created specifically for the Project. The MEMD will be responsible for reporting and
coordinating the component activities being implemented by the ministry. Implementation of the
Project will follow respective Project Implementation Manuals that will include detailed
arrangements on all aspects of project implementation from the beginning until completion.
Both MEMD and UETCL have managed various Bank funded projects including the Fourth
Power Generation Project and Energy for Rural Transformation Phase-I (ERT-1) while ongoing
projects are Power Sector Development Operations and the ERT-II.
Budgeting and Accounting Arrangements:
6. The budgeting arrangements of UETCL are adequately defined in its Financial Policies
and Procedures Manual, which will be adopted for the Project. The budget of the Project will be
approved by the steering committee overseeing the operations of the Project. MEMD will follow
government planning and budgeting procedures which are documented in the government‘s
Treasury Accounting Instructions, 2003. The capacity of the accounting staff to fulfill budgeting
needs of the Project is adequate, and UETCL‘s accounting software can adequately cater for the
budgeting arrangements of the Project.
7. MEMD and UETCL will maintain books of accounts similar to those for other IDA
funded projects. These books should include classification of accounts that match with the
29
categories of expenditures and sources and application of funds as indicated in the Financing
Agreement. These books of accounts will be maintained on a computerized system and shall
include interalia a cash book, ledgers, journal vouchers, fixed asset register and a contracts
register.
Staffing and Information system Arrangements 8. MEMD and UETCL have adequate staff mix to account for the funds of the project.. The
MEMD has one project accountant and one assistant accountant. These designated staff will
report to the Head of EPD. UETCL has an accounting unit headed by the Manager Finance,
Accounts and Sales, who will be responsible for maintaining the Books of Accounts and records
of the Project component funds. Most of the accounting staff dealing with this project are
qualified, experienced and have been trained in World Bank Financial Management and
Disbursement Guidelines. The staff will be advised of any further training requirements as the
need arises. MEMD and UETCL will have to ensure that appropriate staffing arrangements are
maintained throughout the life of the Project.
9. UETCL has an adequate information system (Sun Systems accounting) to account for the
Project funds while MEMD uses Microsoft Excel, it is in the process of acquiring an automated
system.
Internal Control and Internal Auditing
10. The internal controls (including processes for recording and safeguarding fixed assets)
that will be used for the Project are documented in the Financial Management Manuals of
UETCL while MEMD will use the Treasury Accounting Instructions and other guidelines
prepared specifically for Bank project that can be updated to strengthen the internal control
system when the need arises. The other existing manual is the Financial Policies and Procedures
Manual. Internal audit arrangements in UETCL are adequate, with qualified and experienced
Internal Auditors. In addition, UETCL has an Audit Committee, which is a sub-committee of the
Board of Directors. The Manager, Internal Audit and Security reports to this sub-committee,
which provides a level of independence to the internal audit function in the company.
Banking and Funds Flow Arrangements
11. Current funds flow arrangements are appropriate. Two bank accounts (US$ Designated
Account and Project Account-UShs) shall be opened at Bank of Uganda (BoU) by the two
agencies in accordance with the additional instructions included in the Letter of Disbursement.
The account signatories will be as documented in the Financial Management Manual of UETCL
and the Treasury Accounting Instructions for MEMD. An initial six months cash flow forecast
will be made through a withdrawal application upon which the first advance disbursement from
the IDA Credit will be processed.
30
PROJECT FUNDS FLOW CHART
Disbursement and Reporting Arrangements
12. Both UETCL and MEMD have effective financial management and accounting systems,
which will facilitate the use of Report-based Interim Financial Reporting (IFR) disbursements.
The IFRs will be submitted to IDA within 45 days after the end of each quarter to document
expenditures and request for replenishments. The following quarterly Interim Financial Reports
(IFRs) will be produced by UETCL and MEMD:
Sources and Uses of Funds with a summary forecast;
Uses of Funds by Project Activity/Component;
13. In order to support report-based disbursement, each implementing unit is required to
submit to the Bank the following information:
Designated Account Activity Statement;
Bank Statements;
Expenditures for Contracts subject to Prior Review; and
those not subject to Prior Review.
14. In addition to the quarterly IFRs, UETCL and MEMD will produce, for analytical and
audit purposes, annual financial statements for the project.
External Auditing
15. The Auditor General is primarily responsible for auditing all government projects but
may subcontract such work to an acceptable firm of private auditors, with the final report being
issued by the Auditor General. The audits should be done in accordance with International
Standards on Auditing with terms of reference for the external auditor agreed with IDA and
IDA Other Financing
Sources
Designated accounts in BOU
UETCL & MEMD
denominated in US$
Project A/C in BOU for
UETCL & MEMD
denominated in UGX
Project transactions paid in either US$ or local currency
Account
ability
31
credit proceeds may be used to cover audit costs. During negotiations, it was agreed that each of
the IAs will submit annual audit report including the management letter for the project accounts
to IDA within six months of the end of each fiscal year. In addition, it was also agreed that
UETCL will submit each year entity audited accounts together with the management letter
within six months of the end of each fiscal year. MEMD has a good record of auditing
arrangements. Although, UETCL has managed a number of IDA projects, there has been late
submission of audit reports in recent years. Appropriate measures are needed for the UETCL
Board to approve audit reports in time to ensure timely submission to the Bank. The new World
Bank Policy on Access to Information requires that the Borrower disclose the audited financial
statements in a manner acceptable to the Bank and following the Bank's formal receipt of these
statements from the Borrower, the Bank will make them available to the public in accordance
with the new Bank Policy.
Action Plan and Supervision
Action Date Due Responsibility
UETCL Board commits to approving audit
reports on time for timely submission to Bank.
Continuous process UETCL management
and Board
Computerization of the MEMD accounts unit Within six months
after effectiveness. MEMD
16. A supervision mission will be conducted at least once every year, based on the risk
assessment of the Project. The mission‘s objectives will include that of ensuring strong financial
management systems are maintained for the Project throughout its life.
17. The following table specifies the categories of Eligible Expenditures that may be
financed out of the proceeds of the Financing (―Category‖), the allocations of the amounts of the
Financing to each Category, and the percentage of expenditures to be financed for Eligible
Expenditures in each Category:
Category Amount of the Financing
Allocated (in US$ eq.)
Percentage of Expenditures to be
Financed16
(1) Works, goods, consultants‘
services, training and operating
costs under Parts A.1, A.2, A.3,
A.4 and B of the Project
US$ 102.63 million 100%
(exclusive of taxes)
(2) Works, goods, consultants‘
services, training and operating
costs under Part C of the Project
US$11.75 million 100%
(inclusive of taxes)
(3) Unallocated US$ 5.62 million
TOTAL AMOUNT US$ 120.00 million
16
All applicable taxes and duties for Category 1 will be paid by the Borrower/
32
Procurement
Procurement Arrangements
18. Procurement under the project will be conducted by the UETCL for Components A and B
and the MEMD for Component C.
19. Procurement under the project will follow the Guidelines: Procurement under IBRD
Loans and IDA Credits (May 2004, revised October 2006 and May 2010) and Guidelines:
Selection and Employment of Consultants by World Bank Borrowers (May 2004, revised
October 2006 and May 2010).
Procurement Thresholds to be applied in the Procurement Plan (PP)
Expenditure
Category
Contract Value Threshold
(US$)
Procurement
Method
Contracts Subject to
Prior Review
(US$ )
1. Works 5,000,000 and above
Below 5,000,000
Below 100,000
ICB
NCB
Shopping
All contracts
As specified in PP
None
2. Goods 500,000 and above
Below 500,000
Below 50,000
ICB
NCB
Shopping
All contracts
As specified in PP
None
3. Consulting
Services17
and
Training
With firms above 200,000
With individuals above
100,000
With firms up to 200,000
With Individuals up to
100,000
Quality and Cost
Based Selection
Individual
Qualifications/Other
Individual
All contracts
All Contracts
None
None18
4. Non-consulting
Services
500,000 and above
Below 500,000
Below 50,000
ICB
NCB
Shopping
All contracts
As specified in PP
None
5. All types of
contracts
All contracts Sole source / direct
contracting and
terms of reference
As specified in the PP19
17
A shortlist of consultants for services estimated to cost less than US$ 200,000 equivalent per contract may consist
entirely of national consultants in accordance with the provisions of paragraph 2.7 of the Consultant Guidelines. 18
Except for project staff financed by the project 19
Consultancy services estimated to cost below US$ 5,000 equivalent will not be subject to prior review by the
Bank subject to their inclusion in the agreed Procurement Plan.
33
Procurement Plan and Procurement Packages
20. The UETCL and MEMD have prepared procurement plans which were reviewed and
agreed by the Bank. The plans will be updated annually to reflect the current circumstances.
The procurement plans include: (a) Goods: Office equipment and furniture, GPS Units and
Office Stationery; (b) Supply and installation of the 220 kV Kawanda-Masaka transmission line
(137 km) and upgrades to associated substations, supply and installation of street lights and
lighting of selected markets in Masaka Municipality, peri-urban electrification along the
transmission line, and supply and installation of a Power Sector Information Center; and (c)
Consultants: Supervision of supply and installation of the 220 kV Kawanda–Masaka
transmission line, Feasibility Study for the planned 132 kV Lira-Gulu-Nebbi-Arua Transmission
Lines, Environment and Social Impact Assessment, Resettlement and Compensation Plan for the
planned 132 kV Lira-Gulu-Nebbi-Arua Transmission Lines, Individual engineering consultants
to support project implementation, Review of Power Sector Reforms, Design and supervision of
implementation of an Power Sector Information Center, Design and supervision of
implementation of the Masaka street and market lighting and Design and supervision of peri-
urban electrification.
21. The contract for Supply and installation of the 220 kV Kawanda-Masaka transmission
line while estimated to cost US$95 million will be procured through ICB with post-qualification
rather than pre-qualification. The justification for this include: (i) UETCL wishes to minimise
the risk of collusion that could arise with prequalfication of only a few bidders; (ii) to expedite
procurement and implementation and minimise delays especially since the bidding document is
expected to be ready by end of May 2011; and (iii) UETCL recently concluded procurement of a
similar contract for over 100 km of the Bujagali - Kawanda transmission line using post
qualification and this did not deter a large number of bidders from submitting their bids.
22. Electricity connections to beneficiaries along the line will also be procured through direct
procurement for a no-pole to a 2-pole service. This is because there is already an electricity
distribution concessionaire in this area and established connection rates which are reviewed,
approved and published by the Electricity Regulatory Authority. There would therefore not be
any real benefit in competition on this contract. Conncetions requiring grid extensions will be
procured competitively.
23. Retroactive financing: In order to finance essential activities that may be ready for
implementation before effectiveness, retroactive financing for an amount of US$5.0 million will
be allowed for eligible expenditures beginning June 1, 2011.
A summary of the procurement plan for contracts involving international competition is shown
below:
34
Goods and Works
1 2 3 4 5 6 7 8
Ref No Contract (Description) Estimated
Cost
(US$)
Procurement
Method
P-Q Domestic
Preference
(yes/No)
Review by
Bank
(Prior/Post)
Expected
Bid
Opening
Date
Component A
1 Supply, installation
and line construction
for – 220 kV Kawanda
- Masaka
Transmission line (137
km) and Upgrade
of Kawanda and
Mbarara substation
and Construction of
Masaka substation
95,032,057 ICB Post No Prior 17-Sep-11
Component C
ESDP/GDS/01 Supply and Installation
of a Power Sector
Information Center
500,000 ICB Post NO Prior 20-Jul-12
ESDP/GDS/02 Supply and Installation
of lighting Systems
for Streets and
Markets in Masaka
Township
1,400,000 ICB Post NO Prior 10-May-12
ESDP/GDS/03 Electricity Grid
Extensions and
Connections to
Communities along
Kawanda - Masaka
6,000,000 ICB Post NO Prior 9-Jul-12
ESDP/GDS/04 Electricity Grid
Intensification and
Connections of
beneficiaries in peri-
urban areas along the
Transmission Line
Route and in areas of
Kawanda & Masaka
(No Pole & One Pole
Service) by UMEME
1,200,000 Direct Post NO Prior N/A
35
Consultancy Services
1 2 3 4 5 6
Ref No
Description of Assignment Estimated Cost (US$)
Selection Method
Review by Bank
(Prior/Post)
Expected Proposals
Submission Date
Component B
1 Supervision Consultancy for Design, Tender
document Preparation and Supervision of
Works for Kawanda - Masaka (137 km)
transmission line and upgrade of Kawanda and
Mbara substations and construction of a new
sub-station at Masaka
3,900,000 QCBS Prior 15-Jun-11
2 Consultancy Services for Feasibility Study for
proposed Lira- Gulu Nebbi-Arua 132 kV
Transmission line
1,500,000 QCBS Prior 22-Jun-11
3 Consultancy Services for Environment Impact
Assessment, and Resettlement Policy
Framework for the proposed Lira- Gulu Nebbi-
Arua 132 kV Transmission lines.
1,000,000 QCBS Prior 15-Jul-11
Component C
1 Consultancy Services for Reviewing the Power
Sector Reforms in Uganda
600,000 QCBS Prior 12-Jul-11
2 Consultancy Services to design and supervise
establishment of a Power Sector Information
Center
200,000 QCBS Prior 26-Jul-11
3 Implementation Support Services (Design and
Supervision) for Street and Market Lighting of
Masaka Town
100,000 CQS Post 05-Aug-11
4 Implementation Support Services (needs
identification, design, and Supervision) for
connection of customers in the peri urban areas
along Kawanda - Masaka Transmission Line
200,000 QCBS Prior 12-Jul-11
Procurement Risks and mitigation measures
24. The assessment concluded that the overall procurement risk of the UETCL is High and
the proposed risk mitigation measures are summarized below:
Risk Action Timeframe Responsibility
Significant delays in conducting
procurement with consultancy
selection taking over 2 years and
goods taking over 1 year due lack of
systematic monitoring of procurement
progress against procurement plans
Regular monitoring of progress
against the procurement plan by
management
Procurement Unit to provide
regular reports to management
on the progress against
procurement plans. These
Throughout project
implementation
UETCL
36
Risk Action Timeframe Responsibility
reports shall be reviewed and
monitored at least bi-monthly
by management
Inadequate organizational structure for
the procurement unit, with the
procurement staff reporting to the
Manager, Corporate Affairs, who
represents the function at a strategic
level in management. This results in
inadequate supervision of the
procurement function and inadequate
participation of the function at a
strategic level in the organization.
Head of procurement shall
participate in Management and
report regularly on procurement
and inform management
decisions as necessary.
UETCL to consider upgrading
the Unit to be headed by a
Manager Procurement reporting
directly to the Executive
Director
June 2011
National procurement procedures are
not fully consistent with Bank
procedures
Financing Agreement shall
include the exception
provisions.
By Negotiation IDA/UETCL
Inadequate staffing within the
Technical Departments of Planning
and Projects to support procurement
and contract management
Recruit additional staff /
consultants in technical
departments to augment
existing capacity. These shall
include an Electrical Engineer,
a Civil Engineer, Surveyor and
Safeguards / Project officer
By December 2011
UETCL
Weak contract management with
delays in implementation of contracts
and inadequate contract management
Establish a contract
management system including
regularly updating progress in
contract implementation using
contract management forms and
management reports.
Additional staff recruited to
support supervision of
consultants.
Train UETCL staff especially
the technical departments in
contract management
By September
2011
By December 2011
By December 2011
UETCL
UETCL
IDA/UETCL
Limited experience in the selection of
consultants under IDA procedures
Procurement Staff to attend
training in the selection of
consultants with the Ghana
Institute of Management and
Public Administration
(GIMPA) or East and Southern
African Management Institute
(ESAMI)
Bank conducted training for
project team in selection of
consultants
Hire part time procurement
consultant to train and mentor
Within nine (9)
months of
effectiveness
February 2011
October 2011
UETCL
IDA / UETCL
UETCL
37
Risk Action Timeframe Responsibility
procurement unit staff and
provide support during peak
periods
25. The assessment of MEMD concluded that the overall procurement risk of the MEMD is
High and the proposed risk mitigation measures are summarized below:
Risk Action Timeframe Responsibility
Staffing constraints in Electricity
Power Division implementing the
component with existing staff
stretched by other regular work and
one position not filled
Ministry to hire Electrical
Engineer to support the Power
Division in implementing the
project
By effectiveness
Throughout project
implementation
MEMD
Delays in procurement due to
inadequate monitoring of procurement
Regular monitoring of
progress against the
procurement plan by
management
Throughout project
implementation
MEMD
Inadequate contract management
leading delays in implementation of
project
Establish a contract
management system including
regularly updating progress in
contract implementation using
contract management forms
and management reports.
Additional Engineer to be
recruited to support
supervision of consultants.
Train MEMD staff especially
the Power Division in contract
management
By September
2011
By December 2011
By December 2011
MEMD
MEMD
IDA/MEMD
Inadequate experience in Procurement
Unit with IDA financed procurement
Project to utilize Procurement
Specialist hired under
predecessor project
PDU staff to attend training in
IDA procurement with
GIMPA or ESAMI
Bank to conduct training for
project team in selection of
consultants
June 2011
December 2011
June 2011
MEMD
World Bank /
MEMD
38
Frequency of Procurement Supervision
26. In addition to the prior review to be carried out by the Bank, the capacity assessment of
the implementing agency recommends six-monthly supervision missions to visit the field,
including at least one mission to carry out a post review of procurement actions.
Environmental and Social (including safeguards)
27. The main environmental safeguards issues for the proposed Project relate to air and water
pollution, construction waste management, natural habitats, and biodiversity, deforestation and
land clearing. The proposed Project may also have an impact on physical cultural resources such
as graves through tower foot print construction. Land acquisition/involuntary resettlement is
substantial.
28. The proposed Project triggers the OP/BP 4.01 on Environmental Assessment as well as
safeguard policies on Natural Habitats (OP/BP 4.04); Physical Cultural Resources (OP/BP 4.11);
Involuntary Resettlement (OP/BP 4.12) and Forests (OP/BP 4.36).
29. The Project is rated as an environmental assessment Category ―A‖ project.
Safeguard Policies Triggered by the Project Yes No
Environmental Assessment (OP/BP 4.01) [X] [ ]
Natural Habitats (OP/BP 4.04) [X] [ ]
Pest Management (OP 4.09) [ ] [X]
Physical Cultural Resources (OP/BP 4.11) [X] [ ]
Involuntary Resettlement (OP/BP 4.12) [X] [ ]
Indigenous Peoples (OP/BP 4.10) [ ] [X]
Forests (OP/BP 4.36) [X] [ ]
Safety of Dams (OP/BP 4.37) [ ] [X]
Projects in Disputed Areas (OP/BP 7.60) [ ] [X]
Projects on International Waterways (OP/BP 7.50) [ ] [X]
30. A summary of the safeguard policies triggered under the Project, the reasons why they
are triggered and the mitigation measures put in place to minimize any impact is highlighted in
the table below. Details are provided in the subsequent paragraphs.
Ref OP/BP Name Reasons for triggering Mitigation measure (s)
4.01 Environmental Assessment Construction activities ESIA prepared
4.04 Natural Habitats Transmission line passes through some
forest reserves
ESMP/CESMP
4.11 Physical Cultural Resources Transmission tower construction could
impact grave sites
Rerouting of transmission
line, chance finds provisions
site specific plans
4.12 Involuntary resettlement Land acquisition for RoW and tower
footprints
RAP
4.36 Forests Transmission line passes through some
forest reserves
ESMP
39
Environmental Assessment (OP/BP 4.01), Natural Habitats (OP/BP 4.04), Physical
Cultural Resources (OP/BP 4.11) and Forests (OP/BP 4.36)
31. To ensure compliance with the following safeguards policies, OP/BP 4.01, OP/BP 4.04,
OP/BP 4.11, and OP/BP 4.36 an ESIA has been prepared. The ESIA that includes an ESMP has
been consulted upon during preparation and then finally disclosed both in-country and at the
Bank‘s InfoShop in December 2010. The ESIA outlines the key environmental and social
surroundings of the project area and identifies specific and broader construction related
environmental and social impacts of the project together with suggested measures to address
them, including the relevant management and monitoring measures in the implementation of the
project. This includes pollution of air and water, disturbance and degeneration of forest wetland
ecosystems, solid and liquid waste management, alteration of landscapes, analysis of
alternatives, and safety and labor issues. Regarding the implementation of the Borrower
prepared Environmental and Social Management Plan (ESMP), the contractor will be required
by contractual arrangement to prepare his own more detailed Contractor ESMP or CESMP,
which will be based on the ESMP. The Borrower/UETCL will hire an experienced
environmental specialist, who will oversee the implementation of the CESMP or alternatively, as
a preferred option, the Consultant will, by contractual arrangement, be responsible for an
adequate implementation of the CESMP; since this has worked very well elsewhere in other
infrastructure projects, the second option will be adopted. There are no environmental risks that
go beyond the coverage of the safeguards policies.
Natural Habitats (OP 4.04) and Forests (OP 4.36) 32. The OP/BP 4.04 and OP/BP 4.36 are applicable because unmitigated project activities
may have an impact on the remnants of natural habitats and forests. It is however, expected that
no environmentally sensitive habitats especially critically natural habitat, will be converted under
the Project. Adequate environmental management measures have been included in the ESMP to
protect remainder of the affected forest reserves.
Physical Cultural Resources (OP/BP 4.11)
33. Physical cultural resources that may be impacted by the project include grave sites that
would be disturbed through construction of towers. However, UETCL has as much as possible
avoided areas with graveyards. Extensive earthworks and construction activities may lead to
opportunistic finds of archaeological artifacts. Chance find provisions will, therefore, be
included in construction contracts and potential for impact on other physical cultural resources
will be addressed by site-specific Physical Cultural Resources Management Plans.
Involuntary Resettlement (OP/BP 4.12) 34. The OP/BP 4.12 is triggered because the project will support the construction of a
transmission line which implies land acquisition for the right of way and tower foot print. The
construction of the transmission line would affect about 2,136 households with 13,596 PAPs, of
which 1,152 PAPs (representing 8% of the total) need to be resettled, with the remainder being
compensated for their loss of assets and/or partial loss of land or access to land. In light of the
larger numbers of PAPs, the project is Category A. The land requirements for the above purposes
will permanently limit access to both public or private land and other assets by local
communities. During construction of the transmission line, access to land within 17.5 meters on
either side of the right of way corridor of 5 meters will be temporarily limited due to construction
activities and safety reasons. In order to address impacts related to loss of land and other assets,
40
a Resettlement Action Plan (RAP) for the Project was prepared and disclosed both in country
(December 13, 2010) and at the Bank‘s Infoshop (December 6, 2010) respectively. The RAP
outlines the principles and procedures for resettlement and or compensation of the project-
affected people, provides baseline information on the PAPs, and establishes public consultation
and disclosure standards including grievance mechanisms. Furthermore, the RAP outlines both
implementation and monitoring/evaluation arrangements for resettlement related activities.
35. The RAP has been prepared in consultation with the affected individuals and
communities. Resettlement assistance and compensation for losses were also determined
through the same consultative process to ensure that no one is left worse off as a result of the
Project. Preparation of the RAP and its implementation are based on existing laws and
regulations of Uganda as well as the World Bank Policy (OP/BP 4.12). UETCL will retain the
services of consultants to: implement the RAP. MEMD will retain the services of consultants to
independently monitor and report on the progress of implementation of the RAP as the situation
warrants. Terms of reference of both these consultancy assignments have been finalized and
approved by IDA. Monitoring of implementation will also be carried out by UETCL on a
quarterly basis and reports submitted to IDA. There is a need to build up the capacity of UETCL
staff in areas of RAP implementation and monitoring. This will be covered under the Training
and Capacity building component. Total cost related to compensation, cost of the two
consultancy assignments and other resettlement related measures are expected to aggregate about
US$12.9 million; this amount constitutes the counterpart funding that is to be budgeted by the
Borrower.
36. The proposed Project will finance electrification to selected households in peri-urban
areas along the transmission line route. The project will also finance a few community support
sub-projects that will include lighting a few streets and market places in the Masaka
municipality; these have been selected by the Masaka Municipal Council. These activities are to
enable people enjoy the benefits of a transmission line that is traversing the area. These
activities may imply the need for land and in order to address such needs a Resettlement Policy
Framework (RPF) was prepared and disclosed in-country and at the World Bank Infoshop on
December 12, 2010 and December 10, 2010, respectively. The RPF document outlines the
principles and procedures for resettlement and or compensation of subproject-affected people,
and establishes standards for identifying, assessing and mitigating negative impacts of program
supported activities. In addition, the RPF will guide the preparation and implementation of
resettlement action plans (RAPs) for each individual sub project that triggers the involuntary
resettlement policy.
Grievance Mechanisms.
37. The grievance mechanisms are detailed in the RAP, and they utilize the existing systems
and structures from the lowest levels through local authorities. This includes the local councils
and grievance committee at village level with community and representatives of project affected
peoples. If all these channels of handling grievances fail, then, the aggrieved individuals or
communities can resort to the Uganda Courts of Law starting with the local magistrate‘s court.
Stakeholder Consultations.
38. Several consultations have been held with potential PAPs between 2006 and 2010 along
the T-line corridor and adjoining communities. The consultations have revealed that though the
41
people look forward to the project as a sign of development, there are concerns and fears that the
people who may lose assets like land and may not be adequately compensated. This fear had its
roots in ongoing land evictions to pave way for both public and private project development. In
addition, the project affected people were concerned about the illiteracy levels among the
community that is likely to put some of the PAPs at a disadvantage such that they may not fully
understand their entitlements including the procedures to be followed in the resettlement process.
It was therefore proposed that local councilors together with the RAP implementing agency
design appropriate messages using various channels of communication to sensitize the
population. In addition, the entitlement disclosure procedures should include written takeaways
for the PAPs who will also be encouraged to appear with their immediate family members.
39. Therefore, the RAP implementation for this Project will require a competent agency that
will follow up all detail and keep up to date records of all transactions. Further, for the
community enhancement program, possibility of preparing RAPs for sub-projects is very high
and requires extra effort to ensure that people who lose land and other assets on it in this densely
populated, highly encumbered, partly semi-urban and partly traditionally agricultural area are
appropriately and adequately compensated so that they are able to re-establish or even improve
their livelihoods in a timely manner. The updated RAP has been cleared and disclosed by both
the Bank and relevant GOU agencies.
Disclosure of Safeguards Instruments 40. All environmental and social safeguards documents have been cleared by the Bank. The
National Environmental Management Authority (NEMA) has also cleared these safeguard
documents. NEMA‘s authorization has been forwarded to the Bank. The safeguard documents
were disclosed in country on December 3, 2010 (RAP), December 10, 2010 (RPF) and
December 13, 2010 (ESIA), respectively, and at the InfoShop on November 30 (ESIA),
December 6 (RAP) and 10 (RPF), 2010, respectively. The proposed mitigation measures and
their monitoring plans are an integral part of the project design and costs. Site-specific RAPs for
the community enhancement sub-projects will be disclosed once they are prepared during project
implementation.
Borrower Capacity to Implement Safeguard Policies 41. Borrower capacity for environmental and social safeguards implementation and reporting
is mixed, as on the environment side support from competent district environment officers
(DEOs) may be enlisted, while both technical capacity and understanding of involuntary
resettlement to implement the project consistently with the Bank resettlement policy is limited.
Close technical support is being provided by the Bank‘s safeguards specialists during preparation
and will continue during implementation to ensure compliance with not only domestic but also
international good resettlement practice. The capacity strengthening measures will be outlined in
the project safeguards documents and integrated in the project budget, implementation and
monitoring plan.
Safeguards Supervision Plan 42. Given the Borrower‘s mixed (but growing) experience with implementation of
environmental and social safeguards instruments, close safeguards supervision and
implementation support will be carried out during the early stage of project implementation until
42
adequate safeguards experience is developed. The RAP implementation will be undertaken by
an agency while environmental mitigation measures will be undertaken by the contractor and
supervised by the Consultant. In addition, UETCL technical staff in cooperation with NEMA,
DEOs and other relevant local government staff will monitor the implementation of the
safeguards instruments discussed above. IDA supervision will focus on: (i) providing regular
implementation support; (ii) carrying out field reviews of safeguards implementation, and (iii)
monitoring safeguards implementation based on periodic progress reports. IDA supervision will
be carried out by field and HQ based Bank technical staff and complemented by specialist
consultants together with UETCL and NEMA technical staff not only during regular bi-annual
supervision missions but also during interim technical safeguards missions that will respond to
emerging issues or when UETCL requests for assistance.
Safeguards in the Legal Documents 43. Borrower commitment to implement the provisions of the safeguards instruments (ESIA,
EMPs, RAP and RPF) in form and substance satisfactory to IDA have been included as specific
provision in the legal documents. More specifically, the Borrower is required to provide
sufficient funds for payment of resettlement costs as provided for in the RAP. In addition,
signed entitlement certificates will need to be issued to people to be resettled or compensated
under the Project.
Monitoring and Evaluation
44. Virtually, all of the data required to measure the project‘s outcomes and results will come
from the regularly collected operating statistics of UETCL, and from the regular quarterly reports
on project implementation provided by the PMUs. No additional capacity building is needed in
order to obtain the necessary information. An exception is the monitoring of the implementation
of the RAP, where special arrangements will be needed in order to ensure adequate oversight and
tracking of progress.
45. Because of the nature of the proposed Project, the outcomes in terms of the PDO will
only be realized once implementation is completed and cannot therefore be used to measure
progress during implementation. The monitoring indicators therefore include a number of
interim outputs related to completion of procurements and completion of interim outputs
(installations, studies) to allow IDA to monitor the overall progress of implementation against
the planned schedule and to identify and remedy any slippage at an early stage.
43
Annex 4
Operational Risk Assessment Framework (ORAF)
Project Development Objective(s)
To improve the reliability of and increase access to electricity supply in the southwest region of Uganda.
PDO Level Results Indicators:
1 Improved reliability of supply in the Masaka area on account of: (a) reduced average transmission line outages per year; (b) reduced average outage time; and (c) Consequent reductions in un-met demands of existing customers 2. Flow of electricity through the Masaka sub-station owing to increased capacity of transmission line (i.e. over and above those attributable to reduced outages). 3. Primary project beneficiaries measured by increase in access on account of the Project
Risk Category Risk
Rating Risk Description
Proposed Mitigation Measure
1. Project Stakeholder Risks
1.1 Stakeholder
MI
Resettlement issues have proven to be a major hurdle for the AfDB/JICA financed BIP currently under implementation with several RoW issues yet to be resolved. Of the several sections of the BIP, satisfactory resolution of all RoW issues related to the Bujagali-Kawanda transmission line and its subsequent construction is a necessary pre-requisite for the PDO to materialize. Local populations may react adversely to the impacts of line construction on their homes and livelihoods. The primary concerns relate to compensation for lost land and/or income, and disputes over compensation adequacy that can slow implementation significantly.
(i) Dependence of power evacuation on the Nalubale section alone is risky and the GoU will resolve these issues as soon as possible; (ii) resolution of the remaining RoW issues related to the Bujagali–Kawanda section is a condition of effectiveness. (i) Considerable focus has been accorded on implementation and monitoring of the RAP which has been disclosed appropriately and necessary public consultations have been carried out during project preparation; (ii) An appropriate compensation package is proposed to cover losses incurred by
44
While new generation should be on-line in time to meet the demands of the project areas, a continuing pipeline of investments will be needed to meet demand growth. For the distribution sector, necessary investments in capacity expansion and system maintenance must be made to ensure adequate and reliable supply to end users.
persons forced to relocate as a result of the line construction; (iii) Based on lessons learned from Bujagali, consultants will be appointed by UETCL to implement the RAP and independently monitor and report on its implementation progress; and (iv) Community Support Projects will be implemented that will interalia provide electricity to low income households along the transmission corridor. The Sector Working Group will coordinate donor efforts to finance necessary expansion of generation and distribution systems. Plans are underway for a comprehensive review of the rural electrification program to ensure that it is fully integrated with the expansion plans of the transmission and generation subsectors.
3. Implementing Agency Risks
ML Poor implementation capacity especially delays in Procurement can cause significant delays in project implementation thereby causing delays in achieving the PDO.
(i)Regular monitoring of progress against procurement plans by management; (ii) implementing units to be strengthened by procurement specialists; and (iii) training and capacity building
4. Project Risks
4.1 Design
MI
If load growth or the capacity to meet future demand does not materialize, the project may be uneconomic and/or may prove to be a financial burden on the utility as it fails to generate sufficient revenues to cover its incremental costs. Poor design of new transmission links leads to over-engineering and unnecessary costs or to under-engineering and failure to meet performance specifications.
(i) An internationally reputed engineering consulting firm has prepared the feasibility studies and the preliminary designs; (ii) The main contract for transmission line construction will be design and build, ensuring that the contractor is fully responsible for both optimizing the design and ensuring its performance; (iii) The designs will need to be reviewed and cleared by Bank technical specialists; (iv) The project procurement plan will ensure that bidders for the design-build contracts have the necessary technical competence; and (v) The TA component will provide project management support to UETCL in areas of bid evaluation, design review and construction management
4.2 Social & Environmental
ML Failure to properly address the rights and concerns of PAPs, or otherwise meet the Bank’s
The feasibility study and updated ESIA/RAP/RPF lay out a comprehensive list of safeguards issues and
45
Safeguard requirements can lead to a number of repercussions including delays to the Project, adverse publicity, negative attention on the part of NGOs, abstention at Board presentation, etc.
proposed mitigation measures, together with a mitigation budget. The actions and costs are included in the implementation plan for the project. Particular attention will be paid on implementation and monitoring of the RAP. Necessary funds have also been set aside as social development projects for communities that are affected by, but may not directly benefit from the project.
4.3 Program & Donor
L
Poor coordination among donors leads to technical incompatibilities in the design of the transmission network as well as stranded links which fail to fit into the least cost plan.
The transmission links being financed have been designed in the context of the national transmission plan, including planned links to export partners. The team is maintaining close coordination with AfDB who are financing the Bujagali-Kawanda transmission line and construction of the 132kV sub-station at Kawanda
4.4 Delivery Quality
ML
The main risk is implementation delays linked to implementation of the RAP for the Project. While these risks could slow the process, they are unlikely to affect the achievement of the PDO.
As noted above, considerable effort has, and will be devoted to ensure: (i) resolution of all RoW related issues on the BIP; and (ii) the smooth and satisfactory implementation of the RAP.
4.5 Other
Accountability and competence in government agencies will continue to decline, leading to poor value per dollar outcomes from public expenditure and failure to overcome critical infrastructure bottlenecks
None at the project level except to ensure that the IA staff members are familiar with and adhere to Bank procurement guidelines.
Overall Risk Rating at Preparation
Overall Risk Rating During Implementation
Comments
M-L M-I
46
Annex 5: Implementation Support Plan (ISP)
Implementation Strategy (IS):
1. The primary implementation risks relate to weaknesses in the Implementation Agencies
(IAs). While both agencies have prior experience in implementing IDA funded projects, it is
recognized that their implementation capacities are limited in many areas. With respect to
dealing first with the investment components (Component A and part of Component C), the
Project provides for TA to cover both design and construction management. Construction
coordination will be handled by contractors under turnkey contracts. For those areas where the
PMUs will retain responsibility (procurement, financial management), funding is provided both
for training and for the hiring of additional specialist personnel as short-term consultants to
strengthen the units‘ capacities.
2. The Task Team has worked closely with the IAs during project preparation to design
terms of reference (TORs) for the TA components of the project (Component B and part of
Component C). Most of these TORs have now been finalized and are ready to be issued as part
of procurement packages.
3. Stakeholder relations are another critical aspect of implementation, particularly as regards
interaction with PAPs during the implementation of the RAP. Considerable ground-work has
already been carried out to educate the local population on the nature of the impacts and the
proposed compensation packages, and additional public information programs are planned. In
addition, it has been agreed to sub-contract the implementation of the RAP by UETCL to an
independent contractor to ensure that all dealings with PAPs are handled on an impartial basis.
Furthermore, arrangements have been made for independent monitoring of the RAP execution by
the MEMD through support of independent consultants.
4. More general interventions relating to policies and reforms (e.g. with respect to raising
the BST to cost recovery levels, resolving land acquisition issues, and ensuring that the pace of
generation expansion keeps up with growing demand) will be handled as they are at present by
sector specialists stationed at the Country Office supported as required by members of the project
team with expertise in technical, economic, financial, environmental, and social issues.
Implementation Support Plan (ISP):
5. Overall, the primary implementation risks are in the areas of procurement, financial
management, implementation of the RAP, and monitoring the financial sustainability of UETCL.
As noted above, the TA component of the Project will provide substantial support to UETCL in
technical design and project management as well as in procurement. However, in the past, there
have been issues regarding timely compliance with agreed schedules in both procurement and
financial management; it is therefore expected that a moderate degree of ongoing supervision
effort will be needed. A more substantial level of supervision is likely to be needed for the
MEMD component given their relative lack of procurement and financial management capacity.
Since procurement and FM specialists are located at the Country Office, no separate travel will
be necessary and supervision and support can be carried out as part of regular activities.
47
6. Adequate technical support in the areas of electrical and civil engineering will be
required initially to review the main transmission line designs, cost estimates and bidding
documents under Component A. This support will be required during the construction period as
well to monitor progress of the transmission line and substation construction/upgrading. Some
support will also be required to do similar reviews under Component C. This support could be
sought through appropriate consultancy services.
7. Safeguards supervision, particularly implementation of the RAP, is likely to involve a
greater degree of involvement if the experience of the ongoing BIP (financed by AfDB) is a
guide. Careful monitoring of progress in the compensation and resettlement of project affected
people, and an early focus on issues which might delay completion of the process will be critical
to maintaining the overall project implementation schedule.
8. Regular monitoring of the financial results of UETCL will be carried out to ensure that
the company is receiving adequate cash flow to meet its financial obligations under the proposed
Project and to establish a sound financial basis to ensure future sustainability.
9. Apart from the above, the proposed Project will require standard supervision input (at
least two times every year) with respect to regular monitoring of technical and environmental
management issues, and also overall management by the Task Team Leader. The involvement
of the latter is expected to be heavy during the first two years when the RAP issues are likely to
be paramount, tapering off during the latter part of the Project.
10. The table below outlines the main focus in terms of support to implementation during the
periods indicated. The resource estimates are indicative and will be reviewed at least once a year
to ensure that it continues to meet the implementation support needs of the project. This will be
reviewed each year by the task team and authorization for any revision sought from the
Management. This will then be the basis of resource allocation in each fiscal year unless project
circumstances and risks necessitates either an increase or decrease in resource requirements.
Time Focus Skills Needed Resource Estimate Number of Trips
Year 1 Project Supervision
Procurement
Technical
Environment
RAP
Financial Management
Financial Analysis
Bank Task Mgmt
Procurement
Engineering
Biology/Forestry
Social Science
FM
Finance
5 weeks
6 weeks
4 weeks
2 week
4weeks
1 week
2 weeks
2
2
Year 2 Project Supervision
Procurement
Technical
RAP
Financial Analysis
Environnent
FM
Bank Task Mgmt
Procurement
Engineering
Social Science
Finance
Biology/Forestry
Financial Mgmt
4 weeks
2 weeks
2 week
2.5 weeks
2 weeks
2 week
1 week
2
2
Years 3 - 5 Project Supervision
Procurement
Technical
RAP
Financial Analysis
Environnent
FM
Bank Task Mgmt
Procurement
Engineering
Social Science
Finance
Biology/Forestry
Financial Mgmt
4 weeks
1 weeks
1 week
1.5 weeks
2 weeks
1 week
1 week
2
2
48
Annex 6: Team Composition
World Bank staff and consultants who worked on the project:
Name Title Unit
Somin Mukherji Task Team Leader and Sr. Financial
Analyst
AFTEG
Paul Baringaire Sr. Energy Specialist AFTEG
Margaret Wilson Sr. Energy Economist (Consultant) AFTEG
Ju Sung Park Financial Analyst AFTEG
Zubair Sadeque Financial Analyst SASDE
Robert A. Robelus Sr. Environmental Specialist (Consultant) AFTEG
Mary Bitekerezo Sr. Social Development Specialist AFTCS
Alessandra Iorio Lead Counsel LEGFI/LEGLA
Duncan Kiara Sr. Counsel LEGFI/LEGLA
Philip Beauregard Sr. Counsel LEGAF
Rajiv Sondhi Sr. Finance Officer CTRFC
Howard Bariira Centenary Sr. Procurement Specialist AFTPC
Paul Kamuchwazi Sr. Financial Management Specialist AFTFM
Janine Speakman Operations Analyst AFTEG
Rosemary Mugasha Program Assistant AFMUG
49
Annex 7: Economic Analysis
General Approach
1. The economic analysis of the Kawanda-Masaka transmission line is based on a traditional
cost benefit analysis; the primary beneficiaries are the existing and future customers in the areas
served by the transmission line including both Ugandan and export consumers. Existing
customers will enjoy more reliable power supply without the frequent interruptions that they
currently experience. Future customers will be able to obtain access to grid supply which would
not otherwise be possible given the capacity constraints of the existing transmission line. A
secondary beneficiary is the integrated Ugandan power supply system. General reductions in
transmission losses as a result of the higher transmission voltage on the Kawanda-Masaka link
will reduce transmission losses throughout the system and reduce the need for generation to
serve customer demand, while savings in the cost of maintaining the existing line will offset
some of the costs incurred by UETCL in building and operating its replacement.
Selection of the Without Project Case
2. A number of alternatives were considered for the ‗without project‘ case, i.e. the set of
future circumstances which would be used as a basis for comparison with the ‗with project‘ case
and against which the benefits of the project would be measured. The option of simply letting
the line disintegrate was considered inconsistent with prudent utility practice. The alternative of
replacing it with a replica single circuit 132 kV line was also not feasible as UETCL would be
unable to raise capital for a project that was clearly not a least-cost solution. The selected
without-project case was therefore a continuation of the status quo where UETCL would
continue to maintain the existing line, replacing towers and line sections when they failed and
essentially maintaining the same level of service as at the present time.
Estimation of Benefits
3. Table 7.1 summarizes the main categories of benefits and the basis on which their values
will be estimated. The sections that follow briefly outline the key assumptions used in the
derivation of the unit values. No monetary value was assigned to the socio-economic and
environmental benefits of increased electricity access (education, health, employment
opportunities), but these should not be ignored in assessing the project‘s economic viability.
50
Table 7.1 Overview of Methodology for Estimation of Economic Benefits, Kawanda-
Masaka Transmission Line
With Project Without Project Benefit
1. Benefit to Existing Customers in the Masaka Region
220 kV double circuit line
– high level of reliability 132 kV line – low level
of reliability Avoided cost of coping measures taken
by existing consumers – diesel and petrol
generators for commercial and industrial
users, kerosene, LPG, candles, batteries,
car batteries households. Minimum WTP
is the tariff, average includes avoided
cost of substitutes. Estimates of WTP per
kWh/MWh based on observed responses
of consumers to unreliable service. Benefits per kWh are multiplied by the
estimated annual MWh of unserved
energy as a result of failures. The benefit attributable to transmission is
the customer WTP minus the economic
cost of generation minus the economic
cost of distribution. In all cases, costs are
adjusted to account for losses. 2. Benefit to potential new customers in the Masaka region
Able to serve additional
load in Masaka area Capacity to serve new
customers in Masaka
area constrained by
capacity of 132kV line
Customer WTP for electricity supply
applied to the incremental load served as
a result of the 220 kV line. Individual
WTP arguably different from above
because households, commercial
enterprises, etc do not start out with the
expectation of electricity supply. Same adjustment for costs of generation
and distribution. 3. Benefit to export customers
Able to serve modest
growth in exports
(assumes no new
investment in export
infrastructure)
Unable to serve
additional export load Export tariff multiplied by the additional
load served minus the incremental cost of
generation (adjusted for transmission
losses).
4. System Loss Reduction
Reduction in system
losses No reduction in system
losses Avoided losses multiplied by the average
economic cost of generation and
transmission. 5. Saving in line maintenance costs
Line maintenance costs
approximately 1.5% of
capital cost
Line maintenance costs
per annum to keep
existing line operational
Savings in line maintenance costs.
51
Benefit to Existing Customers in the Masaka Region
Cost of Unmet Demand – Existing Customers:
4. Table 7.2 gives the estimated unconstrained breakdown of sales to existing customers in
the area served by the existing Masaka substation. These customers would be most highly
penalized by a continuation of the status quo since they have already invested in electricity
consuming stock (machinery and equipment, appliances, etc) and in many instances have
established business models based on the presumption of electricity supply. The frequent and
prolonged interruptions in electricity supply caused by the limited capacity and poor condition of
the existing line imposes high costs on these customers in terms of the need to provide back-up
generation, to use other costly substitutes, to reduce the prices which they can charge for services
(e.g. in the case of hotels and guest houses), and in some instance to forego business
opportunities.
Table 7.2 Existing Sales in the Masaka Region
2010
Description
Residential (incl unmet demand) GWh 83.1 30.5%
Commercial GWh 30.2 11.1%
Industrial GWh 159.5 58.5%
Total Local Sales in Area GWh 272.8 100.0%
5. The benefits of avoided outages were drawn from three main sources. First, a survey was
carried out of industrial and commercial customers in the Masaka area regarding the nature and
cost of the mitigation measures taken to deal with the frequent supply interruptions currently
experienced. The resultant average coping cost (which excluded any fixed costs of equipment)
was 30.2 US cents/kWh. Because fixed costs were not included, the survey results were adjusted
upwards to 35.5 US cents/kWh - the level used as a cost of unserved energy in the economic and
financial evaluation of the BHPP.20
For residential customers, the cost of unmet demand was
assumed to be the same as the cost of unmet demand for new residential customers, viz the
customer willingness to pay (WTP) for electricity supply or 49.8 US cents/kWh. Derivation of
this WTP figure is discussed below. While it might be argued that using the same WTP for
avoided interruptions as for basic electricity access is an over-statement (on the grounds that the
Masaka residential consumers can in many cases simply time shift their use of electricity and
hence much of their demand is actually met although at a less convenient time), the outages on
the Kawanda Masaka line frequently last for several days at a time, which means that time
shifting is less likely to be an option. In addition, these households must invest in both
electricity consuming equipment and in equipment to be used when electricity is not available
(oil lamps, LPG lamps, battery powered equipment), neither of which will be used on a full time
basis.
20
Power Planning Associates Ltd., International Finance Corporation, Bujagali II: Economic and Financial
Evaluation Study, Final Report, February 2007
52
6. The average cost of un-met demand for existing Masaka area customers was based on the
current split in consumption between residential and industrial/commercial customers given in
Table 7.2 above; the weighted average figure used in the analysis was 39.9 US cents/kWh.
MWh of Unmet Demand
7. The number of MWh of unmet demand was based on outage statistics for the Kawanda
Masaka line for 2009. The without project case assumed that the line would be maintained at the
current level of reliability, so the number of hours of outages was assumed to remain constant.
In addition, in a supply constrained situation, it was assumed that existing customers in the
Masaka area would not increase their demands. Hence, the total unmet demand was assumed to
be constant over the period of evaluation, viz 7.3 GWh per year.
Net Benefit to Transmission Investments
8. Because the benefit of the new transmission line was measure as the value of incremental
electricity delivered to the customer, the economic cost of distribution and generation had to be
deducted from the gross benefit in order to determine the benefit attributable to the transmission
investment. The long run average economic cost of generation was assumed to be 12.5 US cents
per kW, based on continued development of Uganda‘s large hydro resources. While the
estimated cost of developing these resources is actually much lower (in the order of 4.7
cents/kWh), there is considerable uncertainty about whether these would be public sector
projects. Assuming that future large generation projects involve a significant degree of private
sector participation, it is more likely that GoU/UETCL would be acquiring the power under a
PPA at a tariff level which would include a risk-adjusted rate of return that would be
substantially higher than that normally associated with a public sector project. The higher
economic cost of generation reflects this expectation. The economic cost of distribution was
assumed to be the current tariff paid to the distribution concessionaire, UMEME, i.e.
approximately 10 US cents per kWh. The contract with UMEME represents a long term market-
based agreement is therefore considered to be representative of an economic price for
distribution services.
Benefit to New Customers in the Masaka Region
Incremental Supply
9. At present, load growth in the Masaka region is constrained by the capacity of the
transmission line connecting Masaka to the main grid. The single circuit 132kV line is already
operating at full capacity and many of its failures are attributable to overloading. Without
additional capacity, it is impossible to meet new demands in the regions beyond.
10. Table 7.3 summarizes the expected supply from the Masaka susbstation with and without
the project. The difference between the two is incremental demand that can be served as a result
of the project, and is summarized in Table 7.4.
53
Table 7.3 Energy Supply from Masaka Substation With/Without Project
Without project Scenario
With project Scenario
Year Local Demand Exports Total
Year Local Demand Exports Total
(GWh) L/factor (GWh) L/factor (GWh)
(GWh) L/factor (GWh) L/factor (GWh)
2014 193.5 55% 49.3 40% 242.8
2014 272.8 60% 100.1 43% 372.9
2015 195.8 55% 50.1 40% 245.9
2015 295.5 60% 102.6 43% 398.2
2016 198.2 55% 50.8 40% 249
2016 310.4 60% 105.2 43% 415.6
2017 199.1 55% 51.6 40% 250.7
2017 344.8 60% 107.8 43% 452.6
2018 201 55% 52.4 40% 253.4
2018 355.9 60% 110.5 43% 466.5
2019 202 55% 53.1 40% 255.1
2019 372.2 60% 113.3 43% 485.5
2020 205.3 55% 53.9 40% 259.2
2020 388 60% 116.1 43% 504.1
2021 206.2 55% 54.8 40% 261
2021 423.3 60% 119 43% 542.3
2022 208.2 55% 55.6 40% 263.8
2022 461 60% 122 43% 582.9
2023 211.4 55% 56.4 40% 267.8
2023 503.2 60% 125 43% 628.3
2024 214.5 55% 57.3 40% 271.8
2024 547.9 60% 128.2 43% 676
2025 217.7 55% 58.1 40% 275.9
2025 597.6 60% 131.4 43% 728.9
2026 221 55% 59 40% 280
2026 651 60% 134.7 43% 785.7
2027 224.3 55% 59.9 40% 284.2
2027 710 60% 138 43% 848
2028 227.7 55% 60.8 40% 288.5
2028 774.1 60% 141.5 43% 915.6
2029 231.1 55% 61.7 40% 292.8
2029 843.9 60% 145 43% 988.9
2030 234.6 55% 62.6 40% 297.2
2030 920 60% 146.6 43% 1068.6
54
Table 7.4 Incremental Capacity and Energy, Masaka Substation, With Project
Year Demand Energy
Local Export Local Export
(MW) (MW) (GWh) (GWh)
2014 16.8 14.0 79.3 50.8
2015 21.1 14.6 99.7 52.5
2016 23.7 15.0 112.2 54.4
2017 30.8 15.6 145.7 56.2
2018 32.7 16.1 154.9 58.1
2019 36.0 16.7 170.2 60.2
2020 38.6 17.3 182.7 62.2
2021 45.9 17.9 217.1 64.2
2022 53.4 18.6 252.8 66.4
2023 61.7 19.2 291.8 68.6
2024 70.5 19.8 333.4 70.9
2025 80.3 20.6 379.9 73.3
2026 90.9 21.2 430.0 75.7
2027 102.7 22.0 485.7 78.1
2028 115.6 22.7 546.4 80.7
2029 129.5 23.4 612.8 83.3
2030 144.7 24.1 685.4 86.0
Customer WTP
11. Sales were broken down by customer class based on the load forecast for the Masaka
region (see Table 7.5). The benefit of the incremental sales to each customer class was based on
customer WTP. The primary source of data for the WTP estimates was a detailed socio-
economic survey carried out in 2005 as part of the preparation of the Rural Electrification Master
Plan21
. The survey provides data on households, public buildings and small and medium scale
enterprises in selected non-electrified regions (including Mbarra and Masaka, both of which are
in the service area of the project). Among the information provided was the current consumption
and cost of electricity substitutes and the likely consumption of electricity in the event that
service were to be provided. The latter took into account household income and the consequent
limitations on ability to pay.
12. The survey data was used to derive two points on the electricity demand curve for
households in non-electrified areas. For non-electrified households, the survey found the current
consumption of substitutes (P1 and Q1 on the demand curve) to be approximately 3.7
kWh/month at an average cost of US$1.75 per kWh. Again based on the IREMP survey, the
maximum level of affordable consumption (once the market had matured) was estimated to be in
the range of 22 kWh per month. This was used as Q2 on the demand curve, with the current
tariff of 17.5 US cents/kWh as P2). The relatively low level of mature consumption suggests
21
IT Power, ‗Social Survey Summary Report, Annex 1, October 2005.
55
that most electricity use will be replacement of existing non-electric energy sources such as
kerosene (for lighting) and batteries (for information and entertainment), with a likely increase in
the level of consumption of both. Recent research on the demand for these applications indicates
that a demand curve with a constant price elasticity provides an excellent fit for observed
consumer behavior (with adjusted R2 in excess of 80%). Fitting a demand curve with a constant
price elasticity between the 2 points on the demand curve and integrating under the resultant
curve gave an average WTP for new residential customers of 49.8 US cents/kWh.
13. The IREMP survey found that the pattern of energy use of non-electrified small
enterprises and for public services in the Masaka region (churches, health centers, schools, etc) is
very similar to that of households. That is, they use candles and kerosene for lighting and dry
cell, batteries or car batteries for medium-large appliances. It is estimated that these applications
will be replaced by electricity. However, larger enterprises use their own generators as their
main source of electricity and sometimes batteries for medium-small appliances. In these cases,
grid electricity will replace mainly the use of the generator. The survey inventoried the number
and current energy consumption patterns of non-electrified enterprises in the regions. These data
provided a basis for estimating the extent and weighted average cost of substitutes that would be
displaced in the event of increased electricity access (P1 and Q1 for the commercial and
industrial sectors). P2 and Q2 were assumed to be the tariff and the total incremental
consumption of industrial and commercial customers in the region in the ‗with project‘ scenario.
Using a constant price elasticity and integrating under the demand curve, it was estimated that
the average WTP of new residential and commercial customers was 25.0 US cents/kWh.
Net Benefit to Transmission Investments
14. As with benefits to existing customers, the benefits to new customers were adjusted to
reflect the costs of generation and distribution that were associated with the incremental power
supply. The residual benefit was attributed to the project investments.
Increased Sales to Export Customers
Incremental Supply
15. Capacity limitations on the existing Kawanda Masaka line also constrain the ability to
supply power to export customers in Rwanda and Tanzania. While major increases in exports
would require the construction of new transmission lines beyond Masaka, the existing lines to
Rwanda and Tanzania are capable of transporting modest increases in energy if these could be
delivered to the Masaka substation. Tables 7.3 and 7.4 above show, in addition to incremental
domestic volumes, the incremental export volumes that could be accommodated once the
proposed Project is implemented.
Benefit per kWh
16. The benefit of the incremental export sales was taken as the export tariff minus the cost
of generation. At current tariffs, this actually results in a loss to the Ugandan economy.
56
However, the situation is not completely straight-forward. The current arrangements are short
term, and are off-set to a degree by other concessionary arrangements between the countries.
System Loss Reduction
Decline in Transmission Losses
17. Upgrading of the Kawanda Masaka line to 22kV will have repercussions throughout the
transmission network. Based on system modeling, it is estimated that transmission losses will
decline by 3.2 MW at peak load as a result of the project investments. This translated into
annual energy savings of 11.8 GWh.
Benefit per kWh
18. The benefit of loss reduction was valued at the economic cost of generation plus
transmission.
Savings in Line Maintenance
19. As noted at the beginning of the chapter, the Without Project case assumed a continuation
of the status quo where UETCL would continue to maintain the existing line, replacing towers
and line sections when they failed and essentially maintaining the same level of service as at the
present time. In the With-Project case, UETCL would incur normal ongoing maintenance costs
associated with the new line, estimated by the technical specialists at 1.5% of the capital cost.
Based on their experience with maintaining the existing Kawanda Masaka line, UETCL provided
estimates of the likely annual costs of keeping the line operational over the coming years. This
avoided annual cost was taken as a benefit of the project.
Summary of Findings
20. Based on the methodology and assumptions described above, the estimated EIRR of the
project is 22.2 percent and the Net Present Value (NPV) at a 12% discount rate is US$133.3
million. As regards the robustness of the estimated returns, a 3 year delay in completion of the
project would decrease the EIRR to 16.8 percent. The project would also remain viable despite
substantially higher capital costs, or substantially lower benefits. The switching analysis
indicated that a 12% EIRR could be maintained if capital costs increased by 167% or if benefits
decreased by 60%.
21. As noted earlier, the economic analysis did not attempt to assign a monetary value to the
socio-economic and environmental benefits of increased electricity access (education, health,
employment opportunities), but these should not be ignored in assessing the project‘s economic
viability and strengthen the argument in its favor.
57
Table 7.5 Load Forecast, Project Region
Year
2010 2012 2014 2015 2016 2017 2018 2019 2020 2022 2024 2025 Description
Residential (incl unmet demand)GWh 83.1 94.5 108.4 113.3 118.1 128.9 140.4 153.2 166.8 198.2 235.7 256.9
Commercial GWh 30.2 34.3 39.4 41.2 42.9 46.8 51 55.6 60.6 72 85.6 93.3
Industrial GWh 159.5 181.6 208.2 217.7 227 247.6 269.6 294.4 320.5 380.8 452.8 493.6
Sales Annual Growth rate 9.50% 10.00% 9.00% 9.00% 9.00% 9.00% 9.00% 9.00% 9.00% 9.00% 9.00% 9.00%
Total Local Sales in Area GWh 272.8 310.4 355.9 372.2 388 423.3 461 503.2 547.9 651 774.1 843.9
58
Annex 8: Financial Analysis
Background
1. The total installed generation capacity of Uganda is about 580MW with two major hydro
plants at Nalubaale (180MW) and Kiira (200MW) located at the mouth of Lake Victoria, three
thermal plants aggregating 170 MW, mini-hydro plants of about 16 MW capacity in total, and
cogeneration from bagasse (12 MW). The rental thermal plants have been relatively recent
additions in response to the 2005 drought when hydro-power output was severely curtailed.
2. The financial analysis discusses the power sector financial position of Uganda and the
financial position of UETCL. The UETCL financial analysis is based on the historical financial
statements for FY05-09, provisional figures for FY10, and projected financial statements for
FY11-16. Attachment 1 includes the assumptions (agreed with UETCL) for preparing the
financial projections and Attachment 2 presents the consolidated financial statements of
UETCL (including projections under base case scenario).
Power Sector Institutional Structure
3. The power sector of Uganda was unbundled in 2001 with the formation of three separate
corporate entities, one each for generation (the Uganda Electricity Generation Company Ltd,
UEGCL), transmission (the Uganda Electricity Transmission Company Ltd, UETCL), and
distribution (the Uganda Electricity Distribution Company Ltd, UEDCL. An independent
regulator Electricity Regulatory Authority (ERA) has been operating since 2000. Rural
Electrification Agency (REA) was established in 2003 as a semi-autonomous agency to facilitate
achieving the government‘s targets for rural electrification. REA receives its revenue from a 5%
levy charged on the bulk power purchase costs.
4. Subsequent to the unbundling, the private sector was granted separate concessions for the
management of UEGCL‘s and UEDCL‘s assets. In 2003, Eskom, Uganda (a subsidiary of state-
owned Eskom of South Africa) was awarded a 20-year concession for the management of
UEGCL‘s assets (Naulbaale 180MW and Kiira 200MW plants). Also a 20-year concession for
UEDCL‘s assets was awarded through an international competitive bidding to UMEME Ltd, a
private company established in Uganda and owned by Globeleq, UK. This is the first electricity
distribution network concession in Sub-Saharan Africa. The functions of UEGCL (with a staff
of 11) and UEDCL (with a staff of 14) are limited to monitoring the activities of the generation
and distribution concessionaires respectively and they recover their costs through a concession
fee charged to the concessionaires. The concessionaires in turn are allowed to recover their costs
from the retail tariff charged to consumers.
5. The state-owned UETCL is responsible for construction, operation and maintenance of
high voltage network of 66kV and above. It carries out the functions of a system operator
providing bulk supply to the distribution concessionaire (UMEME). UETCL charges a Bulk
Supply Tariff (BST) to the distribution concessionaire, which however has not been cost
59
reflective. As a result, direct and indirect supports from GoU are provided to UETCL to keep
the retail tariff affordable.
6. The power system of Uganda is also regionally connected with imports from and exports
to the neighbouring countries of Kenya, Rwanda, and Tanzania.
Supply-Demand Balance
7. Prior to the 2005 crisis, the power demand in Uganda was largely met by hydro (180 MW
at Nalubaale and 120MW22
at Kiira and about 3 MW of mini-hydro). The drought in 2005
caused a sharp fall in hydro output forcing the Government to contract for rental thermal plants.
A 50 MW diesel-run rental plant was first introduced in 2005 by Aggreko, followed by another
50 MW in 2006. Today, thermal power constitutes about 40% of total power generation in
Uganda, up from just 7% in 2005. This is a significant increase especially when the power
demand itself has grown at an annual average rate of 9% during 2007-2010.
2005 2006 2007 2008 2009 2010
Installed Capacity (MW) 352 403 496 546 548 578
Total Units Sent Out (GWh) 1,888 1,609 1,894 2,096 2,298 2,467
Hydro (%)
91% 74% 68% 67% 56% 54%
Renewable (%)
0.0% 0.0% 0.0% 2.7% 4.1% 3.5%
Thermal (%)
7% 23% 28% 28% 39% 42%
Imports (%)
1% 3% 3% 2% 1% 1%
Transmission Losses (%) 4.8% 4.0% 4.4% 5.3% 5.1% 5.0%
Export Sales (GWh)
64 53 65 67 82 75
Bulk Supply to UMEME
(GWh) 1,468 1,506 1,759 1,942 2,146 2,323
Distribution Losses (%) 38.3% 34.3% 35.3% 34.2% 34.7% 29.5%
Growth in Sales (%)
4.39% -7.92% 14.95% 12.31% 9.56% 17.00%
8. Going forward, significant capacity additions from hydropower plants are envisaged
(Bujagali 250 MW by April 2012, Isimba 100 MW by July 2014, Karuma 600 MW out of which
250 MW expected by July 2016). Assuming these capacity additions, there will be adequate
power generation from hydropower to meet domestic demand (which is estimated to grow at an
annual average of 7.5% under the base case), and some surplus available for new exports by the
year 2014.
Power Sector Financial Position
9. Increasing power purchase obligations denominated in US Dollars resulting from
continued reliance on thermal power is negatively impacting the sector financial position. Two
factors are further aggravating the financial position of the sector: (i) continued depreciation of
the local currency that is causing power purchase costs and other foreign costs to go up in local
currency terms; and (ii) volatility in oil prices in the international market. The exchange rate was
1,811 USh/US$ on December 31, 2005, which went up to its strongest position of
22
After 2005, with the addition of 2x40 MW, installed capacity at Kiira was increased to 200 MW.
60
1,613Ush/USD on June 30, 2007. Since then however, Uganda Shillings continued to depreciate
and it stands at 2,388 USh/USD as of May 10, 2011, losing some 50% of its value since June,
2007. The recent rise in oil prices in the international market is causing power purchase costs to
go up significantly.
10. High costs of thermal power were initially passed on to consumers when retail tariffs
were increased by 37.5% in June 2006 and by another 41% in November 2006. Since then, no
retail tariff adjustments took place until January 2010, when retail tariff was in fact reduced by
6% across all customer categories (9.9% reduction in domestic category). The current weighted
average end-user tariff is USh287/kWh (USc 12/kWh)23
. Even at this high rate, the tariff is not
adequate to cover costs. Effects of inadequate tariff are compounded by the fact that more than
one-third of electricity generated is not paid for (30% of distribution losses, 4% of transmission
losses, and 4% of non-collection24
). The resulting financial gap is met by GoU through direct
budget support to the sector channelled through UETCL.
11. GoU is obligated to meet the contractual costs of power generation and the costs of
distribution concessionaire UMEME. To keep the tariff from going up at the consumer level, the
regulator keeps the bulk supply tariff (BST) that UETCL charges to UMEME at less than full
cost recovery level. The resulting shortfall is provided by GoU as subsidy to the sector. The
capacity payments of the thermal plants are also provided by GoU as subsidy to the sector25
.
During the period FY05-10, GOU provided direct budgetary support of US$528 million to
UETCL to cover for the costs of power purchase. This includes support from IDA Credit to
cover the costs for Mutundwe plant. Continued reliance on the thermal power to meet the
growing demand coupled with government‘s strategy of not passing on the increased costs to
consumers will result in increasing requirements for government subsidy to the sector. If the
tariff remains at the same level as present, under the base case, it is estimated that subsidy
requirements will total about US$1.5 billion during the FY11-16 period26
.
UETCL Financial Position
12. Increasing share of high-cost thermal power in the generation mix has resulted in
operating costs of UETCL going up in recent years. As the following table shows, there has
23
The current domestic tariff is USh 386/kWh (USc17/kWh), average commercial tariff is USh 359/kWh
(USc15/kWh), average tariff for medium industries is USh 333/kWh (USc13.6/kWh), and for large industry is USh
185/kWh (USc 7.3/kWh). About a quarter of current consumption is domestic, about 15% each are commercial and
medium industries, and large industries consume the rest (43%). 24
Distribution losses and collection rates are showing an improving trend however. Distribution losses have
reduced from 34.7% in 2009 to 30% in 2010 and are expected to be around 28% in 2011. The collection rate of
UMEME has improved from 95% in 2009 to 97.2% during April-October 2010 period. The high collection rate is
expected to continue in the future. In 2005 when UMEME commenced operation as the distribution concessionaire,
the distribution losses and collection rates were 38% and 75% respectively. 25
The capacity and energy charges of Aggreko‘s 50MW HFO plant at Mutundwe are being met by the IDA credit
4297. An amount of about US$204 million has already been disbursed and the remaining undisbursed amount can
cover only the capacity payments until June 2011. 26
This is based on the assumption that energy demand grows at an average annual rate of 7.5% and total installed
capacity increases to more than double the present capacity of 580MW. With Bujagali 250 MW hydro capacity
addition in 2012 and commissioning of two more large hydro projects subsequently, there will be no need for costly
thermal power, which currently constitutes about 40% of total supply.
61
been more than five-fold increase in the power purchase costs (including fuel) during FY05-10.
Power purchase costs currently constitute about 95% of total operating costs of UETCL, up from
about 80% in 2005. Other operating costs (salaries, repairs and maintenance, and administrative
overhead) have remained in the range of 6-7% of annual average gross fixed assets during 2005-
2010. Electricity revenues during FY05-10 have increased by an annual average rate of only
about 30% compared to the growth rate of about 40% in power purchase costs (including fuel)
during the same period.
For the Year Ending December 31
(Figures in US$ Million) 2005 2006 2007 2008* 2009 2010
Growth
Rate
Electricity Revenue
42 56 141 137 147 151 29%
Government Subsidy and Tariff Support 21 85 45 91 121 164 50%
Total Revenue
63 141 186 229 269 315 38%
Cost of Power Purchase including Fuel 57 123 166 213 245 299 39%
Other Operating Expenses 13 14 16 42 17 16 4%
Total Operating Expenses 70 138 182 255 262 315 35%
Power Purchase Costs as % of Operating Expenses 82% 90% 91% 84% 94% 95%
13. Recent increases in oil prices in the international market have resulted into significant
increase in power purchase costs from the thermal plants. The required budgetary support from
GoU to cover the costs has not been provided on time causing financial stress for UETCL
forcing UETCL to delay payments to the private power producers. GoU/UETCL are currently
exploring various options including restructuring of UETCL‘s debts as long term measures to
recover from the current financial crisis27
.
14. UETCL is allowed by the regulator to cover only cash operating costs and debt services
from the BST. Non-cash items like depreciation, bad debts, and foreign exchange losses etc are
not allowed to be recovered. This limits UETCL‘s ability to generate funds for maintenance of
existing assets and for future capital investments. The methodology for setting BST needs to be
reviewed taking into consideration UETCL‘s needs for adequate repair and maintenance of
existing assets and for funding a portion of the investment program and other financial
requirements. This review will be included within the Terms of Reference for the Study on
Review of Sector Reforms
Financial Targets for UETCL
UETCL is expected to generate sufficient funds (from revenues charged to UMEME,
export revenues, and GOU transfers) to cover its debt service obligations and thus will be
required to maintain a debt service coverage ratio (DSCR) of 1.0 throughout the project
period.
27
The on-lending terms for the proposed project has been proposed by GoU to be at the same as IDA terms (0.75%
annual interest to be repaid in 40 years including a grace period of 10 years) . UETCL is exploring options to reduce
its debt service obligations by restructuring its existing debt. It is likely to result into a reduced on-lending terms for
its existing debts.
62
UETCL will also be required to have an EBITDA ratio (Earnings before Interest, Taxes,
Depreciation, and Amortization divided by total revenues) of at least 1% in FY11, 1.5%
in FY12-13, 2% in FY14, 3% in FY15-16.
Financial Projections
15. Total installed capacity is expected to increase to about 1,400 MW by 2016 with share of
hydropower in the generation mix is expected to go up to 93% by 2016. UETCL will need to
invest about US$1.58 billion during FY11-16 in transmission assets to evacuate the increased
power. Out of this, about US$285 million is estimated to be local costs (including taxes and
duties), which is assumed to be GOU contribution as equity. The detailed assumptions as agreed
with UETCL, are listed in Attachment 1 to this Annex.
16. As the following table shows, in order to recover the costs of generation, transmission,
and distribution of the additional power during FY11-16, the estimated full cost-recovery end-
user tariff in FY16 is calculated to be double the current average tariff rate of USc12/kWh. If the
end-user tariff is to remain at the current level, the government subsidy requirements will be in
the tune of US$1.47 billion during FY11-16.
Tariff Derivation (Figures in Million US$) 2011 2012 2013 2014 2015 2016
Power Purchase Costs including Fuel 287 265 294 372 396 425
O&M Costs of UETCL (excluding bad debts and
depreciation) 12 12 12 16 24 35
Rural Electrification and Generation Levy 14 13 15 19 20 21
Debt Service 6 6 7 22 40 81
Less: Other Income 4 4 4 3 3 3
Less: Export Revenue 13 14 15 59 60 61
Total Revenue Requirements of UETCL 302 278 311 366 416 498
Distribution Costs to be recovered 154 157 161 164 168 172
Total Revenue Requirements of the Sector 456 436 472 530 585 670
Full-Cost Recovery BST (USc/kWh sent to
UMEME) 12.16 10.44 10.79 11.82 12.48 13.83
Full-Cost Recovery End-user Tariff
(USc/kWh billed to Customers) 25.49 22.38 22.12 22.84 23.05 24.16
Target End-user Tariff (USc/kWh billed to
Customers) 12 12 12 12 12 12
Government Budget Support Requirements 234 194 207 242 270 326
Sensitivity Analysis
17. Sensitivity analyses for various scenarios were carried out. A 5% annual increase in end-
user tariff will reduce the subsidy requirements from GoU to US$1.1 billion and a 10% increase
will reduce the subsidy requirements to about US$720 million. A 15% annual increase will
result in US$412 million as subsidy during FY11-14, and then no subsidy required during the
remaining of the projection period.
63
Government Subsidy Requirements (US$ Million) in different end-user tariff scenarios
US$ Million 2011 2012 2013 2014 2015 2016 Total
5% Increase 223 169 165 180 183 209 1,129
10% Increase 212 143 119 108 77 60 720
15% Increase 201 116 69 26 - - 412
18. Under the base case, diesel prices are assumed be US$100/barrel and HFO prices
US$80/barrel. If the diesel and HFO prices went up to US$120/barrel and US$100/barrel
respectively, and the end-user tariff remained at USc 12/kWh, the total subsidy requirement
during FY11-16 would be over US$1.52 billion. For diesel price of US$150/barrel and HFO
price of US$120/barrel, the subsidy requirement would be over US$1.56 billion.
Government Subsidy Requirements (US$ Million) under Different Oil Price Scenarios
(assuming no changes in end-user tariff) US$ Million 2011 2012 2013 2014 2015 2016 Total
Base Case
Diesel US$100, HFO
US$80 234 194 207 242 270 326 1,473
Diesel US$120, HFO
US$100 263 197 207 250 273 326 1,516
Diesel US$150, HFO
US$120 295 201 207 258 276 326 1,563
Diesel US$80, HFO
US$60 206 191 207 234 266 326 1,429
19. Because of the reduced dependence on thermal power during the projection period, the
impact of oil price variability has been minimal.
64
Attachment 1
Assumptions for Financial Projections
Macroeconomic Assumptions
1. The financial projections for FY2011-16 are prepared in current Uganda Shillings, using
the inflation and exchange rate forecasts below. Exchange rate of the Uganda Shilling against
the US dollar has been projected forward on the basis of inflation differential.
2011 2012 2013 2014 2015 2016
Uganda Inflation 5.9% 5.5% 5.0% 5.0% 5.0% 5.0%
International Inflation 2.5% 2.5% 2.5% 2.5% 2.5% 2.5%
Exchange Rate (USh/US$)
at December 31 2,386 2,456 2,516 2,577 2,640 2,704
Average for the year 2,348 2,421 2,486 2,547 2,609 2,672
Electricity Sent out, Transmission Losses and Bulk Supply (GWh)
2. The assumptions with regard to electricity sent out, transmission losses and bulk supply
are based on the Base Case scenario of the Power Sector Investment Program (PSIP)
summarized below.
2011 2012 2013 2014 2015 2016
Installed Capacity (MW) 718 911 1,024 1,074 1,074 1,374
Total Units Sent Out (GWh) 2,644 2,835 3,055 3,632 3,884 4,158
Hydro (%)
57% 92% 91% 87% 91% 93%
Renewable (%)
4.0% 4.2% 8.0% 6.7% 6.3% 5.9%
Thermal (%)
38% 3% 0% 6% 2% 0%
Imports (%)
1% 1% 1% 1% 1% 1%
Transmission Losses (%) 4.8% 3.5% 3.5% 3.4% 3.3% 3.2%
Bulk Supply to UMEME (GWh) 2,491 2,671 2,884 3,110 3,352 3,615
Distribution Losses (%) 28.0% 27.0% 26.0% 25.0% 24.0% 23.0%
3. The following generation expansion plan was assumed for FY11-16.
Generation Expansion Plan Installed Capacity
(MW)
Commissioning
Year (Month)
Hydro Power Plant
Bujagali Hydro 250 100 MW by Nov 2011 and 250MW by April 2012
Isimba Hydro 100 2014 (July)
Karuma Hydro 600 2016 (July) (250 MW)
Thermal Power Plant
Invespro 50 2012 (January)
Kaiso-Tonya Oil Refinery (Mputa) 250
2012 (January) (53 MW)
2013 (July) (+ 97 MW)
2016 (July) (+ 100 MW)
65
Mini Hydro Power Plant
Mpanga (East Asian Energy) 18 2011 (March)
Buseruka (Hydromax) 9 2011 (October)
Ishasha (Eco Power) 6.5 2011 (April)
Kikagati (Tronder) 10 2012 (January)
Cogeneration Power Plant
Kinyara Sugar
20
2011 (July) (2 MW)
2011 (October) (+ 2 MW)
2013 (January) (+16 MW)
Total 963 (by FY16)
Power Purchase Costs
4. Capacity and energy charges of IPPs are based on contracted prices. Power purchase
costs from Nalubaale/Kiira are assumed to be USh36/kWh throughout the projection period.
Power purchase csots from other large hydro plants expected to commence during FY11-16
(Bujagali 250 MW, Isimba 100 MW, and Karuma 250MW) are estimated to cost of USc12/kWh
(that includes both operating and financing costs). Price of Diesel is assumed to be
US$100/barrel and price of HFO US$80/barrel throughout the projection period.
Other Operating Expenses
5. Salaries and wages are estimated to increase with local inflation. Repair and maintenance
costs are assumed at 2.5% of average gross fixed assets to allow for adequate maintenance of
assets. General and administrative expenses are estimated to increase with local inflation.
Depreciation
6. The depreciation rate is assumed at 3.3% of fixed assets to be consistent with a 30 year
estimated useful life of transmission assets.
Bad Debts
7. Provision for bad debts is assumed at 0.5% of domestic sales, to be consistent with the
recent levels of non-collection.
Rural Electrification Levy and Generation Levy
8. UETCL is required to pay 5% of power purchase costs as rural electrification levy to
Rural Electrification Agency (REA) and 0.3% of export28
revenues as generation levy to the
Electricity Regulatory Agency (ERA).
Other Income
9. These include interest income on short term deposits, income from fiber optic rentals etc
and are assumed to remain at the average of last three years.
28
Existing exports include exports to Kenya, Tanzania and Rwanda and new exports to Democratic Republic of
Congo.
66
Corporate Income Tax
10. Provision is made for corporate income tax based on the present tax rate of 30% and
applied to taxable income according to current legislation. No provision is made for deferred
taxes.
Dividends
11. No dividends were assumed during the projection period.
Capital Investment
12. UETCL capital investment program (summarized below) includes connections to all new
generation projects in the least-cost expansion plan and inter-connections with Kenya, Tanzania,
Rwanda and Congo. For the Kawanda-Masaka transmission line project, foreign financing is
assumed to be on-lent to UETCL at 0.75% annual interest rate to be repaid in 40 years including
a grace period of 10 years; local financing is assumed to be provided through GoU equity. For
all other capital investment projects, foreign costs are assumed to be financed at 6.5% annual
interest rate to be repaid in 20 years including a grace period of 5 years. Interest during
construction is capitalized. Local costs are assumed to be financed through GoU equity.
Summary of Capital Expenditures (US$ Million)
2011 2012 2013 2014 2015 2016 Total
Foreign Costs 118 317 344 248 167 101 1,295
Local Costs 68 90 59 51 16 1 285
Total Expenditure 186 406 403 299 183 103 1,580
Current Assets
13. Minimum cash balance is assumed to be 2 months of cash operating costs. Accounts
receivable is assumed at 3 months of sales equivalent. Advances, deposits and prepayments
assumed at the level of average of last three years. Inventories are assumed at 1.5% of average
gross fixed assets, and are consistent with the level in recent years.
Current Liabilities
14. Accounts payable are assumed at 2 months of power purchase costs. Salaries payable are
assumed at 1 month of salaries. Employee benefit obligations are assumed at 10% of salaries.
67
Attachment 2
For the Year Ending December 31 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Provisional
Electricity Revenue 69,030 90,468 227,010 232,441 256,523 291,108 160,265 204,449 257,973 315,009 382,717 460,322
Export Revenue 7,226 8,853 14,970 18,700 27,037 26,811 30,710 33,557 36,179 151,302 157,000 162,989
Total Electricity Revenue 76,255 99,321 241,981 251,141 283,560 317,919 190,975 238,007 294,152 466,310 539,717 623,312
Government Subsidy and Tariff Support 38,542 150,273 78,191 166,900 233,810 343,864 549,776 469,758 514,363 616,500 703,623 870,332
Total Revenue 114,797 249,594 320,172 418,041 517,371 661,783 740,751 707,765 808,516 1,082,811 1,243,340 1,493,643
Operating Expenses
Cost of Power Purchase including Fuel 103,320 219,043 285,986 390,051 471,444 628,506 673,559 640,899 732,078 946,500 1,034,301 1,136,940
Salaries and Wages 6,704 6,950 7,643 9,931 11,233 12,653 13,399 14,136 14,843 15,585 16,364 17,182
Repair and Maintenance - - 1,825 2,886 2,628 1,910 3,414 3,111 4,158 13,557 32,358 62,194
General and Administrative Expenses 12,017 13,878 12,956 23,133 8,878 10,005 10,595 11,178 11,737 12,324 12,940 13,587
Provision for Bad Debts - - - 33,345 1,594 372 2,498 2,679 2,972 3,752 4,504 5,703
Depreciation 4,703 4,795 4,518 7,220 8,068 8,410 12,105 12,105 12,105 15,668 37,836 67,066
Total Operating Expenses 126,744 244,666 312,928 466,566 503,845 661,856 715,570 684,108 777,892 1,007,386 1,138,302 1,302,672
Rural Electrification & Generation Levy (3,580) (8,285) (11,283) (15,450) (18,765) (21,292) (33,770) (32,146) (36,712) (47,779) (52,186) (57,336)
Other Income (13,204) 4,032 4,987 8,053 8,084 9,520 8,553 8,719 8,930 8,734 8,794 8,820
Earnings Before Interest and Taxes (EBIT) (28,732) 675 947 (55,922) 2,845 (11,845) (36) 230 2,842 36,380 61,646 142,455
Interest Charges (2,320) (2,380) (2,058) (1,850) (1,958) (8,912) (6,179) (5,757) (7,750) (44,631) (90,117) (166,021)
Foreign Exchange Gains/(Losses) 1,270 1,947 1,867 (11,577) 396 (14,911) (12,126) (33,682) (49,645) (65,286) (76,004) (81,699)
Total Finance Charges (1,051) (433) (191) (13,427) (1,563) (23,823) (18,305) (39,439) (57,396) (109,917) (166,121) (247,720)
Earnings Before Taxes (29,783) 242 757 (69,348) 1,283 (35,668) (18,341) (39,208) (54,554) (73,537) (104,476) (105,265)
Income Taxes (10,344) 639 233 (12,327) - - - - - - - -
Net Income (19,438) (397) 524 (57,022) 1,283 (35,668) (18,341) (39,208) (54,554) (73,537) (104,476) (105,265)
Uganda Electricity Transmission Company Limited (UETCL)
Income Statement
(Figures in Million Ush)
Actual Projections
68
For the Year Ending December 31 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Provisional
Gross Fixed Assets 284,983 290,524 335,627 366,592 366,797 366,806 366,806 366,806 474,780 1,146,539 2,032,291 3,638,347
Less: Accumulated Depreciation (192,449) (197,211) (202,067) (208,841) (215,802) (224,213) (236,317) (248,422) (260,526) (276,194) (314,030) (381,096)
Net Fixed Assets 92,534 93,312 133,560 157,751 150,994 142,594 130,489 118,384 214,254 870,345 1,718,262 3,257,251
Work in Progress 16,440 18,766 9,296 28,930 75,825 103,514 556,235 1,576,930 2,514,189 2,627,097 2,241,045 925,495
Intangibles and other Long Term Assets 40 7 7 3,250 2,882 3,818 3,818 3,818 3,818 3,818 3,818 3,818
Cash & Bank Balance 57,093 22,334 29,328 47,235 23,181 47,784 116,828 111,554 127,136 164,661 182,660 204,984
Gross Accounts Receivable 54,138 87,781 61,369 54,706 65,066 72,330 47,744 59,502 73,538 116,578 134,929 155,828
Less: Provision for Bad Debts - - - - (4,621) - (2,498) (5,177) (8,149) (11,901) (16,405) (22,108)
Net Accounts Receivable 54,138 87,781 61,369 54,706 60,444 72,330 45,246 54,324 65,389 104,676 118,524 133,720
Deposits, Advances, Prepayments and Others 51,948 86,190 87,149 39,180 93,654 71,986 68,274 77,971 72,744 72,996 74,570 73,437
Inventories 2,715 2,835 2,720 5,582 5,662 5,848 5,502 5,502 6,312 12,160 23,841 42,530
Total Current Assets 165,894 199,140 180,566 146,703 182,942 197,949 235,849 249,352 271,580 354,494 399,596 454,671
Total Assets 274,908 311,225 323,429 336,635 412,644 447,875 926,391 1,948,484 3,003,842 3,855,754 4,362,721 4,641,235
Paid-up Capital 57,548 57,548 57,548 57,548 57,548 57,548 57,548 57,548 57,548 57,548 57,548 57,548
Retained Earnings 31,365 30,968 31,492 (25,530) (24,247) (59,915) (78,257) (117,465) (172,019) (245,556) (350,032) (455,296)
Total Equity 88,913 88,516 89,040 32,018 33,301 (2,367) (20,709) (59,917) (114,471) (188,008) (292,484) (397,748)
Long Term Debt 50,539 52,053 70,302 116,149 142,013 183,369 470,543 1,274,922 2,173,718 2,828,994 3,277,770 3,515,815
GOU Contribution - - - 9,069 25,570 35,957 292,461 567,760 760,646 957,065 1,056,769 1,074,007
Deferred Taxes 14,359 26,756 13,509 1,183 1,344 10,310 10,310 10,310 10,310 10,310 10,310 10,310
Accounts Payable 115,041 136,277 75,964 106,427 88,173 122,564 113,376 107,995 123,250 159,049 173,747 190,922
Payable to GOU - - 33,819 26,932 61,877 27,033 13,516 - - - - -
Payable to UEGCL - - 30,987 30,987 30,987 30,987 30,987 30,987 30,987 30,987 30,987 30,987
Current Portion of Long Term Debt 5,088 6,984 8,990 12,844 28,204 38,848 14,567 15,014 17,918 55,799 103,985 215,223
Employee Benefit Obligations 969 640 817 1,026 1,174 1,174 1,340 1,414 1,484 1,558 1,636 1,718
Total Current Liabilities 121,097 143,901 150,577 178,217 210,416 220,606 173,787 155,409 173,640 247,394 310,356 438,851
Total Equity and Liabilities 274,908 311,225 323,429 336,636 412,644 447,874 926,391 1,948,484 3,003,842 3,855,753 4,362,721 4,641,235
Uganda Electricity Transmission Company Limited (UETCL)
Balance Sheet
(Figures in Million Ush)
Actual Projections
69
For the Year Ending December 31 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Provisional
Cash Flows from Operating Activities
Operating Income 4,928 7,244 (48,525) 13,526 (73) 25,181 23,657 30,624 75,425 105,037 190,971
Other Income 4,032 4,987 8,053 8,084 9,520 8,553 8,719 8,930 8,734 8,794 8,820
Adjustments
Depreciation 4,762 4,856 6,774 6,961 8,410 12,105 12,105 12,105 15,668 37,836 67,066
Bad Debts - - - 4,621 (4,621) 2,498 2,679 2,972 3,752 4,504 5,703
Rural Electrification and Generation Levy (8,285) (11,283) (15,450) (18,765) (21,292) (33,770) (32,146) (36,712) (47,779) (52,186) (57,336)
Financing Charges (433) (191) (13,427) (1,563) (23,823) (18,305) (39,439) (57,396) (109,917) (166,121) (247,720)
Income Taxes (639) (233) 12,327 - - - - - - - -
Increase/Decrease in receivables other than cash (68,005) 25,568 51,769 (64,914) 14,218 28,645 (21,456) (9,619) (49,140) (31,607) (38,454)
Increase/Decrease in payables and accruals 22,803 6,677 27,640 32,199 10,190 (46,819) (18,377) 18,230 73,754 62,962 128,495
Total Cash Flows from Operating Activities (40,836) 37,625 29,161 (19,849) (7,471) (21,913) (64,258) (30,866) (29,503) (30,781) 57,545
Total Cash Flows from Investing Activities (7,833) (35,634) (53,842) (46,732) (28,634) (452,721) (1,020,695) (1,045,233) (784,666) (499,701) (290,505)
Cash Flows from Financing Activities
Increase in GOU Equity - - 9,069 16,500 10,387 256,503 275,299 192,886 196,419 99,705 17,238
Increase in Long Term Debt 1,513 18,250 45,846 25,865 41,355 287,174 804,380 898,795 655,276 448,776 238,046
Increcase in Deferred Taxes 12,397 (13,247) (12,327) 161 8,966 - - - - - -
Total Cash Flows from Financing Activities 13,911 5,003 42,589 42,526 60,709 543,677 1,079,679 1,091,681 851,695 548,481 255,284
Increase/Decrease in Cash & Cash Equivalents (34,759) 6,994 17,908 (24,055) 24,603 69,043 (5,274) 15,582 37,525 17,999 22,323
Cash Balance at the Beginning of the Year 57,093 22,334 29,328 47,236 23,181 47,784 116,828 111,554 127,136 164,661 182,660
Cash Balance at the End of the Year 22,334 29,328 47,236 23,181 47,784 116,828 111,554 127,136 164,661 182,660 204,984
(Figures in Million Ush)
Actual Projections
Uganda Electricity Transmission Company Limited (UETCL)
Cash Flow Statement
For the Year Ending December 31 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Provisional
EBITDA Margin -20.9% 2.2% 1.7% -11.6% 2.1% -0.5% 1.6% 1.7% 1.8% 4.8% 8.0% 14.0%
Debt Service Coverage Ratio (DSCR) 1.00 1.00 1.00 1.00 1.00 1.00
Operating Profit Margin -10.4% 2.0% 2.3% -11.6% 2.6% 0.0% 3.4% 3.3% 3.8% 7.0% 8.4% 12.8%
Power Purchase Costs as % of Operating Costs 82% 90% 91% 84% 94% 95% 94% 94% 94% 94% 91% 87%
Current Ratio 1.37 1.38 1.20 0.82 0.87 0.90 1.36 1.60 1.56 1.43 1.29 1.04
Quick Ratio 1.37 1.38 1.01 0.88 0.68 0.87 1.19 1.42 1.49 1.51 1.35 1.08
Accounts Receivable (months) 9.4 11.6 3.2 2.8 3.0 3.0 3.6 3.5 3.4 4.4 4.2 4.1
Accounts Payable (months) 12.5 7.2 3.1 3.2 2.2 2.3 2.0 2.0 2.0 2.0 2.0 2.0
Total Asset Turnover 0.70 1.80 3.80 3.02 2.70 2.65 0.81 0.40 0.27 0.30 0.29 0.31
Fixed Asset Turnover 0.28 0.34 0.76 0.76 0.76 0.74 0.28 0.17 0.12 0.14 0.13 0.14
Inventory as a % of Average Gross Fixed Assets 1.0% 1.0% 0.9% 1.6% 1.5% 1.6% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5%
Long Term Debt to Total Capital 36% 37% 44% 78% 81% 101% 105% 105% 106% 107% 110% 113%
Uganda Electricity Transmission Company Limited (UETCL)
Key Ratios
Actual Projections
70
MAP – IBRD #38357
1
3 4 13
14
19
20
21 22
23
24
1516
18
17
5
678
9
1011
12
NakasongolaNakasongola
MpigiMpigi
MukonoMukonoKAMPALAKAMPALA
BubuloBubulo
MUTUNDWEMUTUNDWE
KAWANDAKAWANDA
NAMUNGOONANAMUNGOONA
KAMPALA NORTHKAMPALA NORTH
MAZIBA
ENTEBBE
KABULASOKE
NKONGE
KAFU
KAHUNGYENKENDA
FORT PORTAL
MUTUNDWELUGOGO
LUGAZI
JINJA
OPUYO
OLWIYO
PAKWACH
KATAKWI
ABUK
KAWANDA
NAMUNGOONA
KAMPALA NORTHNAMANVE
MIRAMA
KINYARA
Bundibugyo
Bushenyi
IbandaKiruhura
Ntungamo
Hoima
Iganga
Busia
Sironko
Bugiri
Kabale
KamuliKaliro
Butaleja
Budaka
KayungaKyenjojo
Kapchorwa
Bukwo
Kasese
Kisoro
Kitgum
Pader
Kumi
Kaberamaido
Lira
Luwero
Nakaseke
Nakasongola
Masaka
Kamwenge
Kalangala
Masindi
Mbarara
Kanungu
Moroto
NakapiripiritKatakwi
Amuria
Moyo
Kibale
Pallisa
Soroti
Fort Portal
Arua
Jinja
Bubulo
Mbale
Tororo
Gulu
Nebbi
Apac
Amolatar
Mubende
RukungiriIsingiro Rakai
Sembabule
Mpigi
MukonoMityanaWakiso
Kiboga
Kotido
Kaabong
Adjumani
YumbeKoboko
Kilak
Maracha
Oyam
Dokolo
Busiki
Bulisa
Abim
KAMPALA
MO
YO
ADJU
M
ANI
SIRONKO
KA
YUN
GA
KABA
ROLE
SEMBABULE
KISORO
KAN
UN
GU
RUKUNG
IRI
KAPCHORWABUKWO
MASINDI
HOIMA
KASESE
KABALE
KIBOGA
MITYANA
KIBAALE
MUBENDE
MPIGI
MBARARA
IBAN
DA KIRUHURA
ISINGIRORAKAI
MASAKA
NTUNGAMO
BUSHENYI
APAC
AMOLATARKABERAMAIDO
KAMULI
GULU
NEBBI
LUWERO
NAKASEKE
IGANGA
KALIRO
KALANGALA
MUKONO
JINJA
KUMI
KATAKWI
AMURIA
MOROTO
SOROTI
PALLISA
MBA
LEBUDAKA
MAN
APW
A
L IRA
K I T G U M
ARUA
KOTIDO
KAABONG
TORORO
KAMPALA
YUMBE
KOBO
KO
PADER
MAYU
GE
BUG
IRI
WAKISO
KAMWENGE
KYENJOJO
NAKAPIRIPIRIT
NAKASONGOLA
BUNDIBUGYO
BUSIA
MARACHA
AMURU
OYAM
DOKOLO
ABIM
BULISA
NAMU-TUMBA
BUTALEJA
DEM. REP.OF CONGO
S U D A N
K E N Y A
K E N Y A
TANZANIATANZANIA
RWANDA
Ora
Alb
ert
Nile
Achwa
Oko
k
Locho
man
Siti
Nkusi
Kafu
Victoria
Nile
Katonga
Lake Vic tor ia
LakeEdward
LakeGeorge
LakeKwania
Lake Kyoga
LakeSalisbury Lake
Opeta
Lake
Albe
rt
To Faradje
To Juba
To Lessos
To Lodwar
To Beni
To Bunia
To Beni
To Beni
To Nyakanazi
To Kisumu
To Nakuru
To KigaliTo Goma
30°E
4°N
2°N
0°
4°N
2°N
0°
32°E 34°E
32°E 34°E
0 25 50 75
0 25 50 75 Miles
100 Kilometers
2
UGANDA
IBRD 38357
MARCH 2011
UGANDA
ELECTRICITY SECTORDEVELOPMENT PROJECT
DISTRICT CAPITALS
NATIONAL CAPITAL
MAIN ROADS
RIVERS
DISTRICT BOUNDARIES
INTERNATIONAL BOUNDARIES
1.2.3.4.5.6.7.8.9.
10.11.12.
IshashaNyamabuyeHaisseroKisisiNengo BridgeBugoyeMubukuKakakaNgeteSogahiMuziziPaidha
KikagatiRuiziSipi FallsBiserukaWakiKyamburaMpangaBujagaliMurchisonKarumaAyagoIsimba
13.14.15.16.17.18.19.20.21.22.23.24.
PROPOSED HYDRO GENERATING STATIONS:
66kV LINE
132kV LINES
220kV LINES
400kV LINES
SUBSTATIONS
HYDRO GENERATING STATIONS (SEE LIST OF PROPOSED STATIONS, BELOW)
THERMAL GENERATING STATIONS
SOLAR GENERATING STATIONS
EXISTING PROPOSED
PROPOSED PROJECTS FOR FINANCING EPC BY WORLD BANK-IDA
PROPOSED PROJECTS FOR FINANCING TECHNICAL ASSISTANCE FOR FEASIBILITY STUDIES BY WORLD BANK-IDA
This map was produced by the Map Design Unit of The World Bank. The boundaries, colors, denominations and any other informationshown on this map do not imply, on the part of The World BankGroup, any judgment on the legal status of any territory, or anyendorsement or acceptance of such boundaries.
24
24
