Document of The World Bank
FOR OFFICIAL USE ONLY
Public Disclosure Authorized Report No: 59310-UG
PROJECT APPRAISAL DOCUMENT
ON A
PROPOSED CREDIT
Public Disclosure Authorized IN THE AMOUNT OF SDR74.1 MILLION (US$120 MILLION EQUIVALENT)
TO THE
REPUBLIC OF UGANDA
FOR AN
Public Disclosure Authorized 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 Public Disclosure Authorized Bank authorization.
CURRENCY EQUIVALENTS
(Exchange Rate Effective 4/30/2011) Currency Unit = Uganda Shillings USh 2381 = US$1 US$ = SDR0.62
FISCAL YEAR January 1 – December 31 (For UETCL) July 1 – 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
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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: Kundhavi Kadiresan Sector Director: Jamal Saghir Sector Manager: S. Vijay Iyer Task Team Leader: Somin Mukherji
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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
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UGANDA
ELECTRICITY SECTOR DEVELOPMENT PROJECT
PROJECT APPRAISAL DOCUMENT
AFRICA
AFTEG
Date: May 27, 2011 Team Leader: Somin Mukherji Country Director: John McIntire Sectors: Power (100%) Sector Director: Jamal Saghir Themes: Infrastructure services for private Sector Manager: S. Vijay Iyer 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 [email protected] 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
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Closing date: February 28, 2017 Does the project depart from the CAS in content or other significant respects? [ ]Yes [X] No Ref. PAD I.C. Does the project require any exceptions from Bank policies? Ref. PAD IV.G. [ ]Yes [X] No Have these been approved by Bank management? [ ]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‖? [X]Yes [ ] No Ref. PAD III.E. Does the project meet the Regional criteria for readiness for implementation? [X]Yes [ ] No Ref. PAD IV.G. 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.
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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
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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.
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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. 2
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.
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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:
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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 5
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. 6
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 112.4 79.2 70 B. Technical assistance to UETCL 7.6 7.6 100 C. Technical assistance to MEMD and Community Support projects 11.8 11.8 100 D. Unallocated 5.6 5.6 100
Total Baseline Costs 137.1 104.2 76 Physical and Price contingencies 15.8 15.8 100
Total Project Costs 153.2 120.0 78 Total Financing Required 153.2 120.0 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. 7
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. 8
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. 9 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
10 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 10to 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) 11 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.
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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
13 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). 14 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). 15 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. 16
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.
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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. Responsibility Description (indicator Data Source/ Cumulative Target Values** Frequency for Data definition etc.) PDO Level Results Methodology Unit of Measure Baseline Collection Indicators* Core YR 1 YR 2 YR3 YR 4 YR5 Indicator One: Improved Un-met demand (a) No. of reliability of supply in the 35 0 0 0 0 10 diminishes to zero after outages per Masaka area on account of UETCL outage UETCL commissioning due to year; reductions in: (a) average Annual statistics the N-1 reliability (b) Outage transmission line outage per 5.7 0 0 0 0 2.6 time (hours); year; (b) average outage time; and and (c) un-met demands of (c) MWh of existing consumers 2.34 0 0 0 0. 0.2 un-met demand
Indicator Two: Increase in flow of electricity through the UETCL
Masaka substation owing to GWh 381 Annual transmission UETCL 0 0 0 0 617.4 increased capacity of data, Masaka
transmission line (i.e. over and MW 65 substation 0 0 0 0 105.2 above those attributable to reduced outages). Indicator Three: Direct Direct project project beneficiaries (number) UETCL beneficiaries are people 0 0 0 0 640013 of which female (%) (a) Number Annual transmission UETCL gaining access to 0 0 0 0 51 (b) % data, Masaka electricity due to the substation 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 Supervision Two: Transmission line (km) km 0 0 0 0 0 137 Semi- missions, PMRs IDA, PMU constructed under the project annual Intermediate Result indicator Reports of Five: Resettlement packages % of PAP 0 5 45 85 95 100 Semi- agency IDA, PMU
provided to all project affected annual implementing persons (PAP) – 13,642 RAP
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. 18
Intermediate Result (Component B): Technical Assistance to UETCL
Intermediate Result indicator Semi- Supervision IDA, PMU Completion of training as a Number 0 0 10 20 30 30 annual missions, PMRs part of capacity building for UETCL (number of people)
Intermediate Result (Component C): Community Support Projects and Technical Assistance to MEMD Intermediate Result indicator One: Social development (a) Number 0 0 1 2 3 3 Semi- Item (c) includes projects completed (a) No. of annual secondary beneficiaries streets lit; (b) No of market (b) Number 0 0 1 2 3 3 Supervision IDA, MEMD who could get the places lit; and (c) no. of missions, PMRs benefits even if the people provide with access to (c) Number 0 0 15,500 31,000 45,500 50,000 transmission line was not electricity under the Project built. Intermediate Result indicator Two: Completion of training Number 0 12 24 36 46 46 Semi Supervision IDA, MEMD as a part of capacity building annual missions, PMRs for MEMD (number of people) Intermediate result indicator Supervision Three; MEMD Sector Yes/No no no no no no yes Semi- missions, PMRs IDA, MEMD
Information Center annual established
*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.
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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:
2 Construction of a 137 km double circuit 220 kV transmission line with 240 mm 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.
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Cost Estimates for Kawanda 220kV sub-station works
Cost Estimates for Transmission Line Unit cost Quanti Description Total Cost US$ US$ ties Details Cost (US$) 250MVA 132/220kV 3,500,000 2 7,000,000 Towers & Supports 9,605,299 Interbus Transformer Foundation Materials 3,938,172 220kV Busbars & Conductor 5,505,324 560,000 1 560,000 OHGW / OPGW 1,491,223 Gantries Insulators 1,613,690 220kV Bus Coupler 1,760,000 1 1,760,000 Line Hardware 864,477 220kV Transformer Bays 1,400,000 2 2,800,000 Total Cost of Materials 23,018,185 Tower Erection Costs US$ 2,468,562 132kV Transformer Bays 875,000 2 1,750,000 Masaka 220kV in coming Conductor Stringing 3,303,194 1,760,000 2 3,520,000 Line Bays and Accessories Easements, ROW & Access Clearance 952,440 Bujagali 220kV in coming 1,760,000 2 3,520,000 Subtotal 29,742,381 Line Bays and Accessories Contingency (20%) 5,948,476 15MVA Reactor 350,000 1 350,000 Total 35,690,857 Reactor 33kV Control Bay 185,000 1 185,000 Average Cost Per km 249,662 Associated Protection, Communication and 715,000 1 715,000 Control Equipment Cost Estimates for Masaka 220kV Sub-station works Civil Works (Including 3,910,000 3,910,000 Plant house) Subtotal 26,070,000 Unit Cost Quanti Total Cost Description US$ ties US$ Contingency (20%) 5,214,000 125MVA 132/220kV 2,800,000 2 5,600,000 Interbus Transformer Total 31,284,000
220kV Busbars & Gantries 1,360,000 1 1,360,000 Cost Estimates for Mbarara Sub-station upgrading works
220kV Bus Coupler 1,760,000 1 1,760,000 Unit Cost Quanti Total Cost Description US$ ties US$ 220kV Transformer Bays 1,400,000 2 2,800,000 15MVA Reactor 350,000 2 700,000 132kV Transformer Bays 875,000 2 1,750,000 Reactor 33kV Control Bay 185,000 2 370,000 132kV Busbars Extension Associated Protection, 476,000 1 476,000 (Busbars & Gantries) Communication and 110,000 1 110,000 Kawanda 220kV in coming Control Equipment 1,760,000 2 3,520,000 Line Bays and Accessories Civil Work 96,000 1 95,000 15MVA Reactor 350,000 2 700,000 Subtotal 1,275,000 Reactor 33kV Control Bay 185,000 2 370,000 Associated Protection, Contingency (20%) 255,000 Communication and Control 820,000 1 820,000 Total 1,530,000 Equipment Civil Works (Including 3,950,000 1 3,950,000 Plant house)
Subtotal 22,106,000
Contingency (20%) 4,421,200 Total 26,527,200
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Project Cost Summary
Foreign Local Cost Cost Total Cost SUB-COMPONENT million US$ 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 Cost included line circuits and installation of 1x15MVAr reactor as a part of the and associated equipment. upgrading Masaka 220kV substation to include: 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 5,305,440 21,221,760 26,527,200 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;
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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
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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 24
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.
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(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.
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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
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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
28 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.
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PROJECT FUNDS FLOW CHART
IDA Other Financing Sources
Project A/C in BOU for Designated accounts in BOU UETCL & MEMD UETCL & MEMD denominated in UGX denominated in US$ Account ability
Project transactions paid in either US$ or local currency
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
30 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 Continuous process UETCL management reports on time for timely submission to Bank. and Board Computerization of the MEMD accounts unit Within six months MEMD after effectiveness.
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 Percentage of Expenditures to be Allocated (in US$ eq.) Financed16
(1) Works, goods, consultants‘ 100% services, training and operating US$ 102.63 million costs under Parts A.1, A.2, A.3, (exclusive of taxes) A.4 and B of the Project
(2) Works, goods, consultants‘ 100% services, training and operating US$11.75 million costs under Part C of the Project (inclusive of taxes)
(3) Unallocated US$ 5.62 million
TOTAL AMOUNT US$ 120.00 million
16 All applicable taxes and duties for Category 1 will be paid by the Borrower/ 31
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 Contract Value Threshold Procurement Contracts Subject to Category (US$) Method Prior Review (US$ ) 1. Works 5,000,000 and above ICB All contracts
Below 5,000,000 NCB As specified in PP
Below 100,000 Shopping None 2. Goods 500,000 and above ICB All contracts
Below 500,000 NCB As specified in PP
Below 50,000 Shopping None 3. Consulting With firms above 200,000 Quality and Cost All contracts Services17 and Based Selection Training With individuals above All Contracts 100,000 Individual
With firms up to 200,000 Qualifications/Other None
With Individuals up to Individual None18 100,000 4. Non-consulting 500,000 and above ICB All contracts Services Below 500,000 NCB As specified in PP
Below 50,000 Shopping None 5. All types of All contracts Sole source / direct contracts contracting and As specified in the PP19 terms of reference
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. 32
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$5.0 million will be allowed for eligible expenditures beginning June 1, 2011.
A summary of the procurement plan for contracts involving international competition is shown below:
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Goods and Works
1 2 3 4 5 6 7 8 Ref No Contract (Description) Estimated Procurement P-Q Domestic Review by Expected Cost Method Preference Bank Bid (US$) (yes/No) (Prior/Post) Opening Date Component A 1 Supply, installation 95,032,057 ICB Post No Prior 17-Sep-11 and line construction for – 220 kV Kawanda - Masaka Transmission line (137 km) and Upgrade of Kawanda and Mbarara substation and Construction of Masaka substation Component C ESDP/GDS/01 Supply and Installation 500,000 ICB Post NO Prior 20-Jul-12 of a Power Sector Information Center ESDP/GDS/02 Supply and Installation 1,400,000 ICB Post NO Prior 10-May-12 of lighting Systems for Streets and Markets in Masaka Township ESDP/GDS/03 Electricity Grid 6,000,000 ICB Post NO Prior 9-Jul-12 Extensions and Connections to Communities along Kawanda - Masaka ESDP/GDS/04 Electricity Grid 1,200,000 Direct Post NO Prior N/A 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
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Consultancy Services
1 2 3 4 5 6 Ref Description of Assignment Estimated Selection Review by Expected No Cost (US$) Method Bank Proposals (Prior/Post) Submission Date
Component B 1 Supervision Consultancy for Design, Tender 3,900,000 QCBS Prior 15-Jun-11 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 2 Consultancy Services for Feasibility Study for 1,500,000 QCBS Prior 22-Jun-11 proposed Lira- Gulu Nebbi-Arua 132 kV Transmission line 3 Consultancy Services for Environment Impact 1,000,000 QCBS Prior 15-Jul-11 Assessment, and Resettlement Policy Framework for the proposed Lira- Gulu Nebbi- Arua 132 kV Transmission lines. Component C 1 Consultancy Services for Reviewing the Power 600,000 QCBS Prior 12-Jul-11 Sector Reforms in Uganda 2 Consultancy Services to design and supervise 200,000 QCBS Prior 26-Jul-11 establishment of a Power Sector Information Center 3 Implementation Support Services (Design and 100,000 CQS Post 05-Aug-11 Supervision) for Street and Market Lighting of Masaka Town 4 Implementation Support Services (needs 200,000 QCBS Prior 12-Jul-11 identification, design, and Supervision) for connection of customers in the peri urban areas along Kawanda - Masaka Transmission Line
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 Regular monitoring of progress Throughout project UETCL procurement with consultancy against the procurement plan by implementation selection taking over 2 years and management goods taking over 1 year due lack of systematic monitoring of procurement Procurement Unit to provide progress against procurement plans regular reports to management on the progress against procurement plans. These
35
Risk Action Timeframe Responsibility reports shall be reviewed and monitored at least bi-monthly by management
Inadequate organizational structure for Head of procurement shall June 2011 the procurement unit, with the participate in Management and procurement staff reporting to the report regularly on procurement Manager, Corporate Affairs, who and inform management represents the function at a strategic decisions as necessary. level in management. This results in inadequate supervision of the UETCL to consider upgrading procurement function and inadequate the Unit to be headed by a participation of the function at a Manager Procurement reporting strategic level in the organization. directly to the Executive Director National procurement procedures are Financing Agreement shall By Negotiation IDA/UETCL not fully consistent with Bank include the exception procedures provisions. Inadequate staffing within the Recruit additional staff / By December 2011 UETCL Technical Departments of Planning consultants in technical and Projects to support procurement departments to augment and contract management existing capacity. These shall include an Electrical Engineer, a Civil Engineer, Surveyor and Safeguards / Project officer Weak contract management with Establish a contract By September UETCL delays in implementation of contracts management system including 2011 and inadequate contract management regularly updating progress in contract implementation using contract management forms and management reports.
Additional staff recruited to support supervision of By December 2011 consultants. UETCL Train UETCL staff especially the technical departments in By December 2011 contract management IDA/UETCL Limited experience in the selection of Procurement Staff to attend Within nine (9) UETCL consultants under IDA procedures training in the selection of months of consultants with the Ghana effectiveness Institute of Management and Public Administration (GIMPA) or East and Southern IDA / UETCL African Management Institute (ESAMI)
Bank conducted training for UETCL project team in selection of February 2011 consultants
Hire part time procurement consultant to train and mentor October 2011 36
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 Ministry to hire Electrical By effectiveness MEMD Power Division implementing the Engineer to support the Power component with existing staff Division in implementing the Throughout project stretched by other regular work and project implementation one position not filled
Delays in procurement due to Regular monitoring of Throughout project MEMD inadequate monitoring of procurement progress against the implementation procurement plan by management
Inadequate contract management Establish a contract By September MEMD leading delays in implementation of management system including 2011 project regularly updating progress in contract implementation using contract management forms and management reports.
Additional Engineer to be recruited to support By December 2011 MEMD supervision of consultants.
Train MEMD staff especially By December 2011 the Power Division in contract IDA/MEMD management
Inadequate experience in Procurement Project to utilize Procurement June 2011 MEMD Unit with IDA financed procurement Specialist hired under predecessor project
PDU staff to attend training in December 2011 IDA procurement with GIMPA or ESAMI
Bank to conduct training for June 2011 World Bank / project team in selection of MEMD consultants
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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 ESMP/CESMP forest reserves 4.11 Physical Cultural Resources Transmission tower construction could Rerouting of transmission impact grave sites line, chance finds provisions site specific plans 4.12 Involuntary resettlement Land acquisition for RoW and tower RAP footprints 4.36 Forests Transmission line passes through some ESMP forest reserves
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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,
39 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
40 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
41 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.
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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 1 Improved reliability of supply in the Masaka area on account of: (a) reduced average transmission line outages per year; (b) Indicators: 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 Risk Category Risk Description Rating Proposed Mitigation Measure 1. Project Stakeholder Risks MI Resettlement issues have proven to be a major (i) Dependence of power evacuation on the Nalubale hurdle for the AfDB/JICA financed BIP section alone is risky and the GoU will resolve these currently under implementation with several issues as soon as possible; (ii) resolution of the RoW issues yet to be resolved. Of the several remaining RoW issues related to the Bujagali– sections of the BIP, satisfactory resolution of all Kawanda section is a condition of effectiveness. RoW issues related to the Bujagali-Kawanda transmission line and its subsequent 1.1 Stakeholder construction is a necessary pre-requisite for the PDO to materialize.
Local populations may react adversely to the (i) Considerable focus has been accorded on impacts of line construction on their homes implementation and monitoring of the RAP which has and livelihoods. The primary concerns relate been disclosed appropriately and necessary public to compensation for lost land and/or income, consultations have been carried out during project and disputes over compensation adequacy that preparation; (ii) An appropriate compensation can slow implementation significantly. package is proposed to cover losses incurred by
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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.
While new generation should be on-line in time The Sector Working Group will coordinate donor to meet the demands of the project areas, a efforts to finance necessary expansion of generation continuing pipeline of investments will be and distribution systems. Plans are underway for a needed to meet demand growth. For the comprehensive review of the rural electrification distribution sector, necessary investments in program to ensure that it is fully integrated with the capacity expansion and system maintenance expansion plans of the transmission and generation must be made to ensure adequate and reliable subsectors. supply to end users. ML Poor implementation capacity especially delays (i)Regular monitoring of progress against in Procurement can cause significant delays in procurement plans by management; (ii) 3. Implementing project implementation thereby causing delays implementing units to be strengthened by Agency Risks in achieving the PDO. procurement specialists; and (iii) training and capacity building 4. Project Risks If load growth or the capacity to meet future (i) An internationally reputed engineering consulting demand does not materialize, the project may firm has prepared the feasibility studies and the be uneconomic and/or may prove to be a preliminary designs; (ii) The main contract for financial burden on the utility as it fails to transmission line construction will be design and generate sufficient revenues to cover its build, ensuring that the contractor is fully responsible incremental costs. Poor design of new for both optimizing the design and ensuring its 4.1 Design transmission links leads to over-engineering performance; (iii) The designs will need to be MI and unnecessary costs or to under-engineering reviewed and cleared by Bank technical specialists; and failure to meet performance specifications. (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 & Failure to properly address the rights and The feasibility study and updated ESIA/RAP/RPF lay ML Environmental concerns of PAPs, or otherwise meet the Bank’s out a comprehensive list of safeguards issues and
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Safeguard requirements can lead to a number proposed mitigation measures, together with a of repercussions including delays to the mitigation budget. The actions and costs are included Project, adverse publicity, negative attention in the implementation plan for the project. Particular on the part of NGOs, abstention at Board attention will be paid on implementation and presentation, etc. 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. Poor coordination among donors leads to The transmission links being financed have been technical incompatibilities in the design of the designed in the context of the national transmission transmission network as well as stranded links plan, including planned links to export partners. 4.3 Program & which fail to fit into the least cost plan. Donor L 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
The main risk is implementation delays linked As noted above, considerable effort has, and will be to implementation of the RAP for the Project. 4.4 Delivery Quality devoted to ensure: (i) resolution of all RoW related ML While these risks could slow the process, they issues on the BIP; and (ii) the smooth and satisfactory are unlikely to affect the achievement of the implementation of the RAP. PDO. Accountability and competence in government agencies will continue to decline, leading to None at the project level except to ensure that the IA 4.5 Other poor value per dollar outcomes from public staff members are familiar with and adhere to Bank
expenditure and failure to overcome critical procurement guidelines. infrastructure bottlenecks
Overall Risk Rating Overall Risk at Preparation Rating During Comments Implementation M-L M-I
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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.
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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 Bank Task Mgmt 5 weeks Procurement Procurement 6 weeks Technical Engineering 4 weeks Environment Biology/Forestry 2 week 2 RAP Social Science 4weeks Financial Management FM 1 week Financial Analysis Finance 2 weeks 2 Year 2 Project Supervision Bank Task Mgmt 4 weeks Procurement Procurement 2 weeks Technical Engineering 2 week RAP Social Science 2.5 weeks Financial Analysis Finance 2 weeks 2 Environnent Biology/Forestry 2 week 2 FM Financial Mgmt 1 week Years 3 - 5 Project Supervision Bank Task Mgmt 4 weeks Procurement Procurement 1 weeks Technical Engineering 1 week RAP Social Science 1.5 weeks Financial Analysis Finance 2 weeks 2 Environnent Biology/Forestry 1 week 2 FM Financial Mgmt 1 week
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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 AFTEG Analyst 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
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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.
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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 132 kV line – low level Avoided cost of coping measures taken – high level of reliability of reliability 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 Capacity to serve new Customer WTP for electricity supply load in Masaka area customers in Masaka applied to the incremental load served as area constrained by a result of the 220 kV line. Individual capacity of 132kV line 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 Unable to serve Export tariff multiplied by the additional growth in exports additional export load load served minus the incremental cost of (assumes no new generation (adjusted for transmission investment in export losses). infrastructure) 4. System Loss Reduction Reduction in system No reduction in system Avoided losses multiplied by the average losses losses economic cost of generation and transmission. 5. Saving in line maintenance costs Line maintenance costs Line maintenance costs Savings in line maintenance costs. approximately 1.5% of per annum to keep capital cost existing line operational
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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
Description 2010 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 51
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.
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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
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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. 54 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.
55
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.
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Table 7.5 Load Forecast, Project Region Year Description 2010 2012 2014 2015 2016 2017 2018 2019 2020 2022 2024 2025 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
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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
58 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. 59
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$204 million has already been disbursed and the remaining undisbursed amount can cover only the capacity payments until June 2011. 26 This is based on the assumption that energy demand grows at an average annual rate of 7.5% and total installed capacity increases to more than double the present capacity of 580MW. With Bujagali 250 MW hydro capacity addition in 2012 and commissioning of two more large hydro projects subsequently, there will be no need for costly thermal power, which currently constitutes about 40% of total supply. 60 been more than five-fold increase in the power purchase costs (including fuel) during FY05-10. Power purchase costs currently constitute about 95% of total operating costs of UETCL, up from about 80% in 2005. Other operating costs (salaries, repairs and maintenance, and administrative overhead) have remained in the range of 6-7% of annual average gross fixed assets during 2005- 2010. Electricity revenues during FY05-10 have increased by an annual average rate of only about 30% compared to the growth rate of about 40% in power purchase costs (including fuel) during the same period.
For the Year Ending December 31 Growth 2005 2006 2007 2008* 2009 2010 (Figures in US$ Million) 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. 61
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$412 million as subsidy during FY11-14, and then no subsidy required during the remaining of the projection period.
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Government Subsidy Requirements (US$ 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 234 194 207 242 270 326 1,473 US$80 Diesel US$120, HFO 263 197 207 250 273 326 1,516 US$100 Diesel US$150, HFO 295 201 207 258 276 326 1,563 US$120 Diesel US$80, HFO 206 191 207 234 266 326 1,429 US$60
19. Because of the reduced dependence on thermal power during the projection period, the impact of oil price variability has been minimal.
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Attachment 1
Assumptions for Financial Projections
Macroeconomic Assumptions 1. The financial projections for FY2011-16 are prepared in current Uganda Shillings, using the inflation and exchange rate forecasts below. Exchange rate of the Uganda Shilling against the US dollar has been projected forward on the basis of inflation differential.
2011 2012 2013 2014 2015 2016 Uganda Inflation 5.9% 5.5% 5.0% 5.0% 5.0% 5.0% International Inflation 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% Exchange Rate (USh/US$) 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 Installe d 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.
Installed Capacity Commissioning Generation Expansion Plan (MW) 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) 2012 (January) (53 MW) Kaiso-Tonya Oil Refinery (Mputa) 250 2013 (July) (+ 97 MW) 2016 (July) (+ 100 MW)
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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 2011 (July) (2 MW) 2011 (October) (+ 2 MW) Kinyara Sugar 2013 (January) (+16 MW) 20 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. 65
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.
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Attachment 2
Uganda Electricity Transmission Company Limited (UETCL) Income Statement (Figures in Million Ush) For the Year Ending December 31 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Actual Provisional Projections 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)
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Uganda Electricity Transmission Company Limited (UETCL) Balance Sheet (Figures in Million Ush) For the Year Ending December 31 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Actual Provisional Projections 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
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Uganda Electricity Transmission Company Limited (UETCL) Cash Flow Statement (Figures in Million Ush) For the Year Ending December 31 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Actual Provisional Projections 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
Uganda Electricity Transmission Company Limited (UETCL) Key Ratios For the Year Ending December 31 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Actual Provisional Projections 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%
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MAP – IBRD #38357
70
IBRD 38357 30°E 32°E 34°E To 0 25 50 75 100 Kilometers SUDAN Juba UGANDA To Faradje ELECTRICITY SECTOR 4°N 0 25 50 75 Miles 4°N KENYA DEVELOPMENT PROJECT
Moyo KOBOKO KAABONG PROPOSED PROJECTS FOR FINANCING
YUMBE O EPC BY WORLD BANK-IDA Y KITGUM Kaabong Yumbe O Koboko M PROPOSED PROJECTS FOR FINANCING Adjumani TECHNICAL ASSISTANCE FOR FEASIBILITY I Kitgum Maracha N STUDIES BY WORLD BANK-IDA A MARACHA M JU D Pader EXISTING PROPOSED ile A KOTIDO Arua N Kotido A 66kV LINE t c r h e w PADER b a l 132kV LINES Kilak k ARUA A o
GULU k ABIM To
O 220kV LINES ra AMURU Lodwar O Gulu Abim 400kV LINES MOROTO Nebbi Moroto SUBSTATIONS an ABUK m 12 o ch HYDRO GENERATING STATIONS DEM. REP. NEBBI 23 OYAM Lo 24 LIRA (SEE LIST OF PROPOSED STATIONS, BELOW) Oyam Lira 21 22 Victoria OLWIYO AMURIA THERMAL GENERATING STATIONS OF CONGO Bulisa Nile PAKWACH Amuria SOLAR GENERATING STATIONS 2°N To Apac KATAKWI 2°N Beni Nakapiripirit BULISA MASINDI APAC DOKOLO Dokolo Katakwi Lake NAKAPIRIPIRIT Lake KATAKWI Kwania Kaberamaido Salisbury Lake DISTRICT CAPITALS 17 Masindi Opeta AMOLATAR Soroti NATIONAL CAPITAL rt Amolatar iti e KABERAMAIDO S lb NA SOROTI MAIN ROADS A K Kumi AS Lake Kyoga 15 16 O Kapchorwa e Hoima N KUMI OPUYO RIVERS k Ka G fu O KAPCHORWA a HOIMA KAYU L NakasongolaNakasongola LA BUKWO DISTRICT BOUNDARIES KINYARA KAFU Sironko PALLISA Bukwo SIRONKO usi N Pallisa INTERNATIONAL BOUNDARIES To Nk KAMULI Bunia KIBOGA NAKASEKE GA KALIRO Budaka Mbale BUDAKA NAMU- 11 KIBAALE Kiboga Kamuli 24 Kaliro TUMBA MBALE 10 Luwero BUTALEJA MANAPWA Busiki Butaleja BubuloBubulo BUNDIBUGYO Kibale LUWERO TORORO 24 PROPOSED HYDRO GENERATING STATIONS: Bundibugyo 20 IGANGA E Nakaseke Kayunga To Fort Portal L Kyenjojo Tororo Lessos O Mubende 1. Ishasha 13. Kikagati 9 R KAMPALAKAMPALA NNORTHORTH Iganga Bugiri A KYENJOJO To 2. Nyamabuye 14. Ruizi B MITYANA JINJA MUBENDE KAWANDAKAWANDA Nakuru A Jinja 8 K Wakiso Busia 3. Haissero 15. Sipi Falls To Beni KAMPALA NORTH FORT PORTAL Mityana NAMUNGOONANAMUNGOONA MukonoMukonNAMANVEo BUSIA 4. Kisisi 16. Biseruka 7 KAMWENGE KAMPALAKAMPAKAWANDALA 6 JINJA 5. Nengo Bridge 17. Waki KASESE Kamwenge Katonga MpigiMpigi KENYA NAMUNGOONA KAMPALA 6. Bugoye 18. Kyambura Kasese MUTUNDWEMUTUNDWE LUGAZI 7. Mubuku 19. Mpanga NKONGE MPIGI WAKISO MAYUGE To SEM LUGOGO BUGIRI Kisumu NKENDA Lake 19 BA KABULASOKE 8. Kakaka 20. Bujagali 0° IBANDA KAHUNGYE Sembabule MUTUNDWE George BU 0° LE 9. Ngete 21. Murchison
KIRUHURA 10. Sogahi 22. Karuma Ibanda ENTEBBE 11. Muzizi 23. Ayago Lake Kiruhura MUKONO 12. Paidha 24. Isimba Edward 18 Masaka BUSHENYI Kalangala
RUK MASAKA Bushenyi MBARARA
U N KALANGALA GIRI 14 Mbarara UGANDA Rakai Isingiro 1 5 Rukungiri RAKAI
KANUNGU ISINGIRO Kanungu Ntungamo NTUNGAMO MIRAMA To 3 4 13 Beni KISORO KABALE Kabale Lake Victoria This map was produced by the Map Design Unit of The World Bank. 2 Kisoro The boundaries, colors, denominations and any other information MAZIBA shown on this map do not imply, on the part of The World Bank TANZANIA Group, any judgment on the legal status of any territory, or any endorsement or acceptance of such boundaries. To TANZANIA To Goma RWANDA To Kigali Nyakanazi 32°E 34°E MARCH 2011