Completion Report

Project Number: 43576-013 Loan Numbers: 2892 and 2893 Grant Number: 0303 March 2021

Sri Lanka: Clean Energy and Network Efficiency

Improvement Project

This document is being disclosed to the public in accordance with ADB’s Access to Information Policy.

CURRENCY EQUIVALENTS

Currency unit – Sri Lankan rupees (SLRs)

At Appraisal At Project Completion (14 August 2012) (30 June 2019)

SLRe1.00 = $0.00758 $0.005666 $1.00 = SLRs131.95 SLRs175.50

ABBREVIATIONS ADB – Asian Development Bank APFS – audited project financial statement BSC – breaker switch capacitor CEB – Ceylon Electricity Board CPS – country partnership strategy DMF – design and monitoring framework EIRR – economic internal rate of return EMP – environmental management plan FIRR – financial internal rate of return GSS – grid substation MOP – Ministry of Power OSPF – Office of the Special Project Facilitator PMU – project management unit PPP – public–private partnership SLSEA – Sri Lanka Sustainable Energy Authority SPS – Safeguard Policy Statement TA – technical assistance

WEIGHTS AND MEASURES GWh – gigawatt-hour (1,000 megawatt-hours) km – kilometer kV – kilovolt kW – kilowatt (1,000 watts) kWp – kilowatt-peak MVA – megavolt-ampere MVAr – megavolt-ampere reactive MW – megawatt (1,000 kilowatts) MWh – megawatt-hour (1,000 kilowatt-hours) MWp – megawatt-peak

NOTES

(i) The fiscal year (FY) of the Government of Sri Lanka ends on 31 December. “FY”

before a calendar year denotes the year in which the fiscal year ends, e.g., FY2021 ends on 31 December 2021.

(ii) In this report, “$” refers to United States dollars.

Vice-President Shixin Chen, Operations 1 Director General Kenichi Yokoyama, South Asia Department (SARD) Director Chen Chen, Country Director, Sri Lanka Resident Mission (SLRM),

SARD Team leader Prathaj Haputhanthri, Associate Project Officer, SLRM, SARD

Team members Mohamed Asmi, Project Analyst, SLRM, SARD

Saranga Gajasinghe, Safeguards Officer, SLRM, SARD Indunil Ranatunga, Associate Financial Management Officer, SLRM, SARD

In preparing any country program or strategy, financing any project, or by making any designation of or reference to a particular territory or geographic area in this document, the Asian Development Bank does not intend to make any judgments as to the legal or other status of any territory or area.

CONTENTS

Page

BASIC DATA i

MAP v

I. PROJECT DESCRIPTION 1

II. DESIGN AND IMPLEMENTATION 1

Project Design and Formulation 1 Project Outputs 2 Project Costs and Financing 7 Disbursements 8 Project Schedule 8 Implementation Arrangements 8 Technical Assistance 9 Consultant Recruitment and Procurement 9

Safeguards 10 Monitoring and Reporting 11

III. EVALUATION OF PERFORMANCE 11

Relevance 11 Effectiveness 12 Efficiency 12 Sustainability 12 Development Impact 13 Performance of the Borrower and the Executing Agency 14 Performance of the Asian Development Bank 14 Overall Assessment 14

IV. ISSUES, LESSONS, AND RECOMMENDATIONS 15

Issues and Lessons 15 Recommendations 15

APPENDIXES

1. Design and Monitoring Framework 17

2. Implementation and Management Arrangements 24

3. Project Effectiveness Summary 28

4. Polpitiya-Pannipitiya Transmission Line Grievance and Problem-Solving Process 31

5. Rooftop Solar Power Generation Pilot 44

6. Technical Assistance Completion Report 51

7. Project Cost at Appraisal and Actual 53

8. Project Cost by Financier 54

9. Disbursement of ADB Loan and Grant Proceeds 56

10. Contract Awards of ADB Loan and Grant Proceeds 57

11. Status of Compliance with Loan Covenants 58

12. Economic Reevaluation 67

13. Financial Reevaluation 76

BASIC DATA

A. Loan Identification

1. Country Sri Lanka 2. Loan and grant numbers and

financing sources 2892 (ordinary capital resources) 2893 (concessional OCR lending)

0303 (grant, Clean Energy Fund) 3. Project title Clean Energy and Network Efficiency

Improvement Project 4. Borrower Democratic Socialist Republic of Sri Lanka 5. Executing agency Ministry of Power 6. Amount of loan and grant Loan 2892-SRI: $100.0 million

Loan 2893-SRI: $30.0 million Grant 0303-SRI: $1.50 million

7. Financing modality sovereign project B. Loan Data

1. Appraisal – Date started – Date completed

not applicable1

2. Loan negotiations – Date started – Date completed

30 July 2012 31 July 2012

3. Date of Board approval 18 September 2012

4. Date of loan agreements 8 May 2013

5. Date of loan effectiveness – In loan agreements – Actual – Number of extensions

8 August 2013 30 September 2013 1

6. Project completion date – Appraisal – Actual

30 June 2017 30 June 2019

7. Loan closing date – In loan agreements – Actual – Number of extensions

30 June 2017 30 June 2019 1

8. Financial closing date – Actual

24 March 2020

9. Terms of loan Loan 2892 (OCR)

1 Based on available information, there was no appraisal mission reflected in the processing schedule of the project.

ii

– Interest rate – Maturity – Grace period Loan 2893 (COL) – Interest rate – Maturity – Grace period

London interbank offered rate (LIBOR) plus 0.6% per annum, less credit of 0.2% 20 years 5 years 1.0% during grace period and 1.5% thereafter 32 years 8 years

10. Terms of relending – Interest rate

Sri Lanka average weighted deposit rate, subject to the maximum rate of 10 percent

– Maturity 20 years – Grace period – Second-step borrower

5 years Ceylon Electricity Board

11. Disbursements

a. Dates

Loan 2892 Loan 2893 Grant 0303

Initial Disbursement 14 November 2014 16 December 2014

2 June 2014

Final Disbursement 24 February 2020 6 December 2019 2 November 2018

Time Interval 64 months 60 months 53 months

Loan 2892 Loan 2893 Grant 0303

Effective Date 30 September 2013 30 September 2013 30 September 2013

Actual Closing Date 24 March 2020 24 March 2020 24 March 2020

Time Interval 78 months 78 months 78 months

b. Amount

Loan 2892 ($)

Category

Original Allocation

(1)

Increased during

Implementation (2)

Cancelled during

Implementation (3)

Last Revised

Allocation (4=1+2–3)

Amount Disbursed

(5)

Undisbursed Balance (6 = 4–5)

1. Works 28,750,000 67,630,000 - 96,380,000 87,519,729 8,860,271 2. Equipment 67,630,000 - 66,930,000 700,000 - 700,000 3. Credit Line 1,500,000 - 700,000 800,000 864,327 (64,327) 4. Interest

Charges 2,120,000 - - 2,120,000 2,120,000 -

Total 100,000,000 67,630,000 67,630,000 100,000,000 90,504,056 9,495,944

Loan 2893 ($)a

Category

Original Allocation

(1)

Increased during

Implementation (2)

Cancelled during

Implementation (3)

Last Revised

Allocationb (4=1+2–3)

Amount Disbursed

(5)

Undisbursed Balance (6 = 4–5)

1. Works 14,020,206 15,519,156 - 27,272,420 23,693,699 3,578,720 2. Equipment 15,519,156 15,519,156 - - - 3. Interest

Charges

460,638 - - 429,809 391,888 37,921

Total 30,000,000 15,519,156 15,519,156 27,702,229 24,085,587 3,616,641 a,$L2893 in various currencies equivalent to SDR 19,994,000 at original allocation. b $2.30 million reduction due to currency fluctuation

iii

Grant 0303 ($)

Category

Original Allocation

(1)

Increased during Implementation

(2)

Cancelled during

Implementation (3)

Last Revised

Allocation (4=1+2–3)

Amount Disbursed

(5)

Undisbursed Balance (6 = 4–5)

1A. Equipment (subsidy for private sector)

610,000 - - 610,000 604,232 5,768

1B. Equipment (universities)

580,000 210,000 - 790,000 277,743 512,257

2. Consulting Services

100,000 - - 100,000 98,119 1,881

3.Unallocated 210,000 - 210,000 - - Total 1,500,000 210,000 210,000 1,500,000 980,094 519,906

C. Project Data

1. Project cost ($ million)

Cost Appraisal Estimate Actual Foreign exchange cost 104.24 79.75 Local currency cost 95.76 54.15 Total 200.00 133.91

2. Financing plan ($ million)

Cost Appraisal Estimate Actual Implementation cost Borrower financed 54.63 18.34 ADB financed 128.92 113.05 Other external financing 0.00 0.00 Total implementation cost 183.55 131.39 Interest during construction costs Borrower financed 13.87 0.00 ADB financed 2.58 2.51 Other external financing 0.00 0.00 Total interest during construction cost 16.45 2.51

3. Cost breakdown by project component ($ million)

Component Appraisal Estimate Actual A. Base cost

1. Transmission infrastructure in the Northern province 42.87 31.14 2. Transmission and distribution network efficiency improvement 99.22 97.87 3. Solar rooftop power generation 2.79 1.84

B. Taxes and duties 24.88 0.54 C. Contingencies 13.79 0.00 D. Financing charges during implementation 16.45 2.51 Total 200.00 133.91

4. Project schedule

Item Appraisal Estimate Actual Transmission system strengthening in Northern province Q3 2012–Q4 2015 Q2 2015–Q2 2019 Network energy efficiency improvement Q3 2012–Q4 2015 Q1 2015–Q2 2019 Solar rooftop power generation pilot Q1 2013–Q4 2014 Q4 2015–Q2 2019 Advisory and capacity building support Q1 2013–Q4 2014 Q2 2013–Q3 2015

iv

5. Project performance report ratings

Implementation Period Single Project Rating From 1 January 2013 to 31 December 2013 On Track From 1 January 2014 to 31 March 2014 On Track From 1 April 2014 to 30 September 2014 Potential Problem From 1 October 2014 to 31 December 2014 On Track From 1 January 2015 to 31 March 2015 On Track From 1 April 2015 to 30 September 2015 Potential Problem From 1 October 2015 to 31 December 2015 On Track From 1 January 2016 to 31 December 2016 On Track From 1 January 2017 to 31 December 2017 On Track From 1 January 2018 to 31 December 2018 On Track From 1 January 2019 to 30 June 2019 On Track

D. Data on Asian Development Bank Missions

Name of Mission Date No. of

Persons No. of

Person-Days Specialization of Members

Consultation mission 14–23 May 2012 4 32 a, k, d, e Fact finding mission 29 May–1 Jun 2012 2 8 a, k Procurement review mission 1 19–23 Nov 2012 3 15 a, e, c Procurement review mission 2 182̶2 Feb 2013 3 15 a, b, c Inception mission 1–5 July 2013 4 20 a, b, d, e Project review mission 1 9–13 Dec 2013 4 20 a, b, f, g Project review mission 2 7–11 Apr 2014 4 12 a, b, f, g, Project review mission 3 15–19 Sep 2014 3 15 a, b, g Project review mission 4 18–25 Feb 2015 4 27 a, b, f, g Project review mission 5 19–28 Oct 2015 5 41 a, b, f, g, h, Project review mission 6 29 Feb–4 Mar 2016 2 10 e, i Project review mission 7 21–29 Nov 2016 2 14 e, i Project review mission 8 9–18 May 2017 3 15 i, j, e Project review mission 9 4–8 Dec 2017 4 20 e, i, j, e Project review mission 10 23–31 July 2018 4 28 e, g, l, j Project review mission 11 5–12 Feb 2019 4 24 e, i, j, g Project completion review mission 19–25 Feb 2020 4 12 e, g, i

a = principal energy specialist, b = project officer, c = procurement consultant, d = environmental specialist, e = project analyst, f = energy specialist, g = associate project officer, h = director, i = senior project officer, j = social development officer, k = senior energy specialist, l = environment officer.

P a l k B a y

P a l

k

S t

r a i

t

G ul f o f

M annar

I N D I A N O C E A N

B a y o f B e n g a l

Vavuniya–Kobithigollowa33 kV Express Line

New Anuradhapura–Kahatagastigiliya

33 kV Express Line

Mannar–Vavuniya132 kV Line

Vavuniya–New Anuradhapura

220 kV Line

Kiribath Kumbura–Galaha33 kV Express Line Galmadu Junction–

Akkatapatthu–Pothuvil33 kV Express Line

Thulhiriya–Kegalle132 kV Line

Reconstruction ofKollonawa–Aturugiriya

132 kV Line

Aturugiriya–Padukka132 kV Line

Pannipitiya–New Polpitiya220 kV Double cct. Line

Polpitiya–New Polpitiya132 kV Line

Solar rooftop,University of Jaffna, Kilinochi

Solar rooftop,University of Ruhuna, Galle

Solar rooftop,University of Moratuwa, Moratuwa

Mannar GSS

Solar rooftop,University of Peradeniya, Peradeniya

Kegalle GSS

Padukka GSS

New Polpitiya GSS

Thulhiriya GSS

Polpitiya GSS

Vavuniya

Kiribath Kumbura

Aturugiriya GSS

Bolawatta

Pannala

Horana

Kolonnawa GSS

SRI JAYAWARDENEPURA KOTTE

Pannipitiya

PolpitiyaSapugaskanda

New Anuradhapura

SABARAGAMUWA

SOUTHERN

NORTH

WESTERN

CENTRAL

U V A

EASTERN

WESTERN

NORTHERN

NORTH CENTRAL

Boundaries are not necessarily authoritative.

National Capital

220/132 kV Substation

220/33 kV Substation

132/33 kV Substation

220/132/33 kV Substation

Hydropower Station

Breaker Switched Capacitors

Solar Rooftop Project

33 kV Gantry

220 kV Transmission Line

132 kV Transmission Line

33 kV Line

Provincial Boundary

Kilovolt

Grid Substation

kV

GSS

SRI LANKACLEAN ENERGY AND NETWORK

EFFICIENCY IMPROVEMENT PROJECT

(as completed)

0 10 20 30 40 50

Kilometers

N

81 30'Eo

81 30'Eo80 00'Eo

80 00'Eo

7 00'No 7 00'No

9 00'No 9 00'No

20-0754 20SRI AV

This map was produced by the cartography unit of the Asian Development Bank. The boundaries, colors, denominations, and any other information shown on this map do not imply, on the part of the Asian Development Bank, any judgment on the legal status of any territory, or any endorsement or acceptance of such boundaries, colors, denominations, or information.

vPROJECT MAP

I. PROJECT DESCRIPTION

1. Sri Lanka’s energy sector had made substantial improvements, with the national electrification ratio increasing from 78% in 2006 to 91% in 2011. However, demand growth had been met mainly by oil-fired thermal generation, impacting Sri Lanka’s energy security and increasing greenhouse gas emissions. The challenge was to reduce dependency on expensive fossil fuel energy generation and meet the growing demand for electricity at low cost and with higher technical efficiency and reliability. Against this backdrop, policy was shifting towards increasing energy supply from nonconventional renewable power sources. 2. The Clean Energy and Network Efficiency Improvement Project was designed to strengthen the transmission network to enable future planned power supply increases, meet growing demand in the regions, and integrate renewable energy sources into the grid. On 18 September 2012, the Asian Development Bank (ADB) approved two loans (one from ordinary capital resources and one from the Asian Development Fund) and a grant from the Clean Energy Fund for a total of $131.5 million. The Government of Sri Lanka and the state-owned Ceylon Electricity Board (CEB) were to contribute $68.5 million to the project.1 A technical assistance (TA) grant of $0.9 million was included to provide capacity-building for clean power development.2 The loans became effective in September 2013. The project was to be implemented through CEB and the Sri Lanka Sustainable Energy Authority (SLSEA), both under the Ministry of Power (MOP).3

3. The project was expected to contribute to the improved reliability, adequacy, and affordability of the national power supply for sustainable economic growth and poverty reduction. The planned outcome was ‘improved clean power supply, efficiency, and reliability in the delivery of electricity in seven target provinces.4 Outcome performance indicators were (i) a reduction in technical and commercial losses in the network, (ii) grid connection for a planned 100-megawatt (MW) wind power park, (iii) generation of 1 MW of grid-connected solar power, and (iv) distribution line end voltage fluctuation maintained within 5% in project provinces. 4. The envisaged project outputs were (i) improved transmission infrastructure in the Northern Province, (ii) improved transmission and distribution network efficiency, (iii) development of solar rooftop power generation, and (iv) capacity and advisory support for the development of wind and solar power generation.

II. DESIGN AND IMPLEMENTATION

Project Design and Formulation

5. Design. The project was prepared in 2011 under a project preparatory technical assistance project (para. 34).5 It was consistent with Sri Lanka’s 2008 National Energy Policy and

1 ADB. 2012. Report and Recommendation of the President to the Board of Directors: Proposed Loans, Technical

Assistance Grant and Administration of Grant, Democratic Socialist Republic of Sri Lanka: Clean Energy and Network Efficiency Improvement Project. Manila.

2 ADB. 2012. Technical Assistance to Sri Lanka for the Capacity Building for Clean Power Development. Manila. 3 The Ministry’s name changed intermittently during the project, but this did not affect implementation: Ministry of

Power, Renewable Energy & Petroleum Resources (MOPREPR), Ministry of Power and Renewable Energy (MPRE), Ministry of Power, Energy & Business Development (MOPE&BD). Ministry of Power (MOP) is used in this project completion report.

4 Eastern, Northern, North Central, Central, Southern, and Western provinces; although not specified in the report and recommendation of the President, it also included Sabaragamuwa province.

5 ADB. 2011. Technical Assistance to Sri Lanka for Clean Energy and Network Efficiency. Manila.

2

Strategies6 and the government’s 10-year development strategy Vision for the Future.7 It was also aligned with ADB’s country partnership strategy (CPS) 2012–2016, which aimed to assist the government in addressing the major constraints to sustaining inclusive growth in post-conflict regions.8 The CPS focused on renewable energy development (including wind and other clean energy sources), energy efficiency improvement in transmission and distribution systems, and improving energy access for under developed areas. 6. At completion, the project remained consistent with the government’s 2019 energy policy by providing access to energy services and enhancing the share of renewable energy.9 It also conformed to the 2018–2022 CPS, which included new growth-oriented areas, such as wind and solar energy, the involvement of the private sector using the PPP modality, and support for the institutional management capacity of CEB.10 Its continued alignment to ADB’s Strategy 2030 is evident in its contribution to ADB’s operational priorities (para. 50)

7. Government agencies consulted the communities along the proposed transmission line routes.11 CEB and SLSEA, as the implementing agencies, were closely involved in the preparation of the project design. The designs of the power elements were based on CEB’s proven models. SLSEA’s component for solar rooftop power generation incorporated innovative approaches from the project preparatory TA. A capacity development TA was included in the project to cover advisory and capacity-building support.12 The project lending modality was appropriate given the defined scope of investments complemented by capacity building support. This helped the government meet the financing requirements to substantially deliver the project outcomes and outputs. No major change of scope was required during implementation. 8. Changes in Design. The envisaged outputs were largely achieved, as shown in the design and monitoring framework (DMF) (Appendix 1). The design of the Mannar grid substation (GSS) was upgraded to meet the additional power evacuation needs of new wind power schemes, which resulted in the removal of the augmentation of the Vavuniya 132/33 kV GSS. The provision of equipment for the Solar Research and Development Center was not carried out (para. 24). The original 4-year timeframe proved to be inadequate, and a 2-year extension was necessary given implementation delays (para. 32).13

Project Outputs

9. Outputs 1, 3 and 4 were achieved, with output 2 being substantially achieved. Appendix 3 shows more than 90% achievement of output targets by loan closure using both numerical counting of achievements versus targets, and weights based on cost and percentage of physical completion. In Appendix 1, output achievements are reviewed against the performance targets in the DMF.

6 Ministry of Power and Energy. 2008. National Energy Policy & Strategies of Sri Lanka (2008), Extraordinary Gazette

notification No. 1553/10. Colombo. 7 Department of National Planning. 2010. Mahinda Chintana – Vision for the future. Colombo. 8 ADB. 2011. Country Partnership Strategy: Sri Lanka, 2012–2016. Manila. 9 Ministry of Power, Energy and Business Development. 2019. National Energy Policy and Strategies (NEPS).

Colombo. 10 ADB. 2017. Country Partnership Strategy: Sri Lanka 2018-2022 – Transition to upper-middle country status. Manila. 11 MOP, CEB, SLSEA, Ministry of Land and Land Development, and local administration officials consulted affected

persons, communities, and women groups, using focus group discussions, interviews, and public meetings. This formed an integral part of safeguards planning.

12 ADB. 2012. Technical Assistance to Sri Lanka for the Capacity Building for Clean Power Development. Manila. 13 On 30 June 2017, the country director of the Sri Lanka Resident Mission approved a minor change for the extension

of the loan closing date.

3

Output 1: Transmission Infrastructure Strengthened in Northern Province

10. Mannar grid substation (GSS). The target was achieved. A new 220/33 kV, 45 MVA GSS was constructed at Mannar, upgraded from 132/33 kV, 31.5 MVA capacity at design. The upgrade supported the evacuation of the revised increased wind power generation potential of the region. The consequent alteration to the procurement requirements necessitated two minor changes of scope.14 As a result of this upgrade, the Vavuniya GSS (132/33 kV) did not have to be upgraded, but the changes caused construction and procurement delays. The Mannar GSS was added to the network and energized in February 2020, 8 months after loan closing. The work undertaken after the project closing date was financed through a subsequent loan.15 11. New transmission line. The target was achieved. A transmission line was constructed to link Mannar GSS to New Anuradhapura GSS. This included a double circuit (two zebra), 220 kV transmission line from New Anuradhapura to Vavuniya (55 km) and a double circuit (single zebra), 220 kV line from Vavuniya to Mannar GSS (70 km). Both lines were initially expected to be energized at 132 kV. However, because of the upgrade at Mannar GSS, augmentation at Vavuniya GSS was not carried out, and the lines directly connected the New Anuradhapura and Mannar GSSs, energized at 220 kV. Work was completed in June 2019, after delays caused by poor weather, material shortages, and excessive rock encountered during tower foundation construction. 12. The new Mannar GSS, linked by the new transmission lines from New Anuradhapura, overcame the previously poor quality and reliability of power supply in Mannar. The new transmission lines will evacuate power from the new Mannar wind farm which is to be operational in 2021.16

Output 2: Transmission and Distribution Network Efficiency Improved

Sub-output 2.1: Transmission Network Developed

13. Grid substation capacity. The target was achieved. The installation of two new GSSs in New Polpitiya and Padukka each with 500 MVA capacity, and the augmentation of the Pannipitiya GSS was completed by June 2019, after delays caused by design changes to suit the two sites and heavy rainfall that affected construction. Furthermore, a new 63 MVA GSS was constructed in Kegalle17, and the capacity of the Thulhiriya GSS was augmented; the work was completed in June 2018 and this GSS was energized in September 2018. Delays were due to design, land access, construction, and commissioning issues. 14. 220 kV transmission lines. The target was achieved. Construction of a 72.3 km double circuit 3-phase transmission line from New Polpitiya to Pannipitiya, via Padukka GSS, was delayed by 3 years.18 The main reasons for the delay were the hilly terrain, redesigns to reduce

14 Minor changes in scope were approved by the Director of the South Asia Energy Division on 29 July 2015 and 16

October 2015. 15 ADB. 2016. Report and Recommendations of the President to the Board of Directors: Multitranche Financing Facility

to the Democratic Socialist Republic of Sri Lanka for the Green Power Development and Energy Efficiency Improvement Investment Program (Tranche 2). Manila.

16 ADB. 2017. Report and Recommendation of the President to the Board of Directors: Proposed Loan, Ceylon Electricity Board: Wind Power Generation Project (Guaranteed by the Democratic Socialist Republic of Sri Lanka. Manila

17 The Kegalle GSS also includes a 15 MVAr, 33 kV capacitor bank. 18 The line length increased from the design length of 58.5 km because the location of the New Polpitiya GSS was

changed.

4

environmental damage, wayleave issues in populated areas, access problems in forest areas (drones were used to assist stringing), adverse weather, and the inability to release land on time because of court cases and the suspension of works within the Magammana area (Appendix 4). Construction of the transmission line between New Polpitiya and Padukka was completed by June 2019 and it was energized in February 2020. In the Padukka-Pannipitiya stretch, all towers were erected at loan closure, except for a 4 km section in the Magammana area.19 Work on this link was suspended in 2017, pending intervention by the Office of the Special Project Facilitator (OSPF) and the resolution of court cases (Appendix 4). Construction was also postponed for a 400-meter span in the Arawwala section, because of an objection and legal action concerning the crossing of the transmission line over an individual’s land. Following court clearances for construction, one circuit of the line was completed by 31 January 2021 and ready to be energized, while the other circuit was expected to be completed by April 2021.20 The new link is essential to supplement the existing Biyagama-Kothmale 220 kV line, and to strengthen the network to reduce the frequency of costly outages. 15. 132 kV transmission lines. The target was substantially achieved. Construction was completed of 132 kV double circuit transmission lines: (i) Thulhiriya to Kegalle (22.5 km) and (ii) Polpitiya to New Polpitiya (1.5 km).21 The Thulhiriya to Kegalle transmission line was operational in September 2018, after delays due to difficult terrain, wayleave issues, and legal actions that delayed stringing. The Polpitiya to New Polpitiya line was operational by late 2017. The Athurugiriya to Padukka line, traversing a highly populated area, was delayed three years by wayleave issues and poor weather.22 As of 31 December 2020, the line was over 99% complete with only the connections to the two GSSs pending. Eventually, the line was physically completed in the first week of March 2021 and is expected to be operational by March 2021. Restringing of the 132 kV Athurugiriya to Kolonnawa line (15 km) could not be completed because CEB was unable to arrange a suitable supply interruption until the new 220 kV New Polpitiya to Pannipitiya line had been completed to carry the extra load. 16. All the materials required to complete the 220 kV and 132 kV lines and remaining towers were purchased out of the loans before closure. CEB financed the remaining construction costs. These new links enhance the network and the reliability of power supplies to Greater Colombo consumers. The new 132/33 kV Kegalle GSS and 132 kV transmission line improved the supply quality for about 25,000 customers in Kegalle district and relieved loading on the existing Kiribathkumbura and Thulhiriya GSSs.

Sub-output 2.2: Reactive Power Management Improved

17. The target was achieved. In total, 160 MVAr breaker switch capacitor (BSC) banks were installed at seven GSSs.23 Each included two 33 kV outdoor BSC bays. They were completed in

19 Of the original route, a section (4 km) was rerouted by CEB, as per the instructions received from the divisional

development committee, because of objections raised by the community. The new route was identified based on social, environmental, and financial considerations. However, residents along the new route objected, claiming inadequate consultation; they made a formal objection to ADB Manila and launched a court case against CEB.

20 Court clearance was obtained for Magammana in February 2020 and for Arawwala in January 2021. 21 Reduced line length from the original design of 10 km because of a change in the New Polpitiya GSS’s location. 22 Land had to be acquired, and during this process two Affected Persons were not satisfied with the valuation provided

by the valuation department. One of them agreed to the valuation following discussions with CEB, while the other appealed it to the land acquisition appeals board. Although by law the implementing agency was vested with the land, according to ADB’s Safeguard Policy Statement (2009), they could not proceed with construction until compensation was paid, which resulted in the delay. Although the loan closed before the matter was finally settled, CEB has now completed construction in accordance with government regulations.

23 This was to distribute reactive power injection for better management.

5

March 2019, after a delay of 23 months because of design, land access, contractor management, construction, and commissioning issues. The performance target of ‘175 MVAr installed’ was achieved (160 MVAr under this subcomponent and 15 MVAr at Kegalle GSS). The BSCs contributed to reducing system losses as planned.

Sub-output 2.3: Medium Voltage Network Efficiency Improved

18. The target was achieved. This subcomponent aimed to add new dedicated 33 kV lines and infrastructure to improve power supply quality to nearly 91,000 customers, including poor rural households, and those headed by women. Although the target was achieved, the work was not completed until 2018, rather than by the scheduled date of end-2016. The subcomponent improved the distribution networks, in North Central, Central and Eastern provinces. 19. North Central province. Two new ‘express’ 33 kV double circuit tower lines were constructed: (i) from Vavuniya GSS to Kebithigollewa (23 km), and (ii) from New Anuradhapura GSS to Kahatagasdigiliya (31 km). The infrastructure was completed in July 2017, delayed by poor weather, rerouting, and minor design changes. The quality and reliability of power supplies were improved to meet the needs of 30,500 customers, mainly rural customers in North Central province, including those in post-conflict resettlement areas.

20. Central and Eastern provinces. New ‘express’ 33 kV double circuit tower lines were constructed: (i) from Kiribathkumbura GSS to Galaha (15 km), and (ii) from Galmadu Junction to Akkaraipatthu and Potuvil (60 km). These were completed in May 2018 after delays caused by severe rainfall, objections by affected persons, wayleave permissions, hilly terrain, and technical issues. Completion of the links to Galaha and Potuvil greatly improved the quality and reliability of supplies to 68,000 customers. In addition, the existing mini-hydro power stations were connected to the Galaha gantry, thus increasing supplies. The network improvements will help to meet the demand for post-conflict rural electrification and provide bulk supplies for the development of industry and commerce, especially for tourism in Eastern province. 21. Overall, the subcomponent benefited about 98,500 customers in mainly poor, rural areas, including both male- and female-headed families.

Output 3: Solar Rooftop Power Generation Pilot Developed

22. Output 3 achieved in excess of the target (Appendix 3). This component, implemented by SLSEA, aimed to establish the means for promoting 1 MW of grid-connected solar rooftop power installations, through public–private partnerships (PPPs) and collaboration with universities. The plan was to generate 34.43 gigawatt-hours (GWh) over the 20-year lifetime of the installations and to avoid 1,286 tons of CO2 emissions annually. Completion was originally scheduled for December 2015. 23. By December 2017, 1.99 megawatt-peak (MWp) of solar rooftop systems had been installed and grid-connected, with annual generation in 2018 reaching 2.6 GWh, which was double the design output.24 About 50.0 GWh are expected to be generated over the 20-year lifetime of the installations, and an estimated 2,126 tons of CO2 emissions were avoided during 2018.25 The Clean Energy Fund grant contributed to this output. Appendix 5 provides more details of the pilot approach that was developed and the wider outcomes.

24 Megawatt-peak shows peak power generation capacity because of the intermittent nature of the resource. 25 Sri Lanka Sustainable Energy Authority. 2020. Project Completion Report Loan Nos. 2892/2893 and Grant No 0303,

Clean Energy & Network Efficiency Improvement Project, Solar Rooftop Power Generation Pilot. Colombo, Sri Lanka.

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24. The component had two initial elements, with a third being added later.

(i) Universities. Rooftop solar power systems with a total capacity of 200 kilowatt-peak (kWp) were installed at four universities (Peradeniya – 60 kilowatt (kW), Jaffna – 60 kW, Moratuwa – 40 kW, and Ruhuna – 40 kW). The systems were installed and grid-connected by December 2017. The costs were funded totally from the grant component of the project. Peradeniya and Jaffna universities have included solar power as a subject module in their curricula and the systems are being used for research and in teaching programs.

(ii) Private enterprises. Innovative measures were developed to encourage industrial, hotel, and general-purpose private enterprises to install rooftop solar power systems. This was achieved on a competitive basis, through a PPP approach involving private equity, loan finance, and capital grants. Enterprises that qualified were given a 7-year loan, subject to successful installation, financed from the credit line of the project loan, which was administered by a participating financial institution (Sampath Bank). The enterprise was then entitled to claim a grant payment as per the percentage stated in their original bid (funded under the grant component of the project). A total of 22 private sector rooftop solar systems, with a total capacity of 1.79 MWp, were installed.

(iii) Provision of equipment for the Solar Research and Development Center. This was added through a minor change of scope.26 However, procurement was suspended by ADB in early 2019 because of noncompliance by SLSEA in submitting the audited project financial statement for 2017.27

25. By adopting a competitive approach and securing private equity contributions, mean capital expenditure per kW installation decreased to $954 from an expected $1,500, enabling a near doubling of installation capacity (Appendix 5). The approach and regulatory systems developed under the pilot have been adopted by the government in its Battle for Solar Energy program. This program, aims to scale up rooftop solar power capacity to 1,000 MW by 2025.28 Following the pilot, ADB has been supporting a rooftop power generation project through a credit line facility.29

Output 4: Advisory and Capacity-Building Support for Wind and Solar Power Development

26. The target was achieved. This component was implemented by two firms under an attached TA project (para. 35), with the costs not being included in the project budget. The TA was completed on schedule by the end of July 2015. The TA completion report summarizes the objectives and outcomes (Appendix 6). Five elements related indirectly to the project:

26 The country director of the Sri Lanka Resident Mission approved a minor change in project scope and reallocation

of loan and grant proceeds on 2 March 2018. 27 ADB (South Asia Department). 2019. Loan Review Mission: Clean Energy and Network Efficiency Improvement

Project. Back-to-office report. 14 March (internal). 28 Ministry of Power. Battle for Solar Energy. 29 ADB. Sri Lanka: Rooftop Solar Power Generation Project.

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(i) System stability study. This was completed by Part A TA consultants and submitted to ADB and CEB in May 2014.30 The study enabled CEB to plan capacity for incorporating more renewable energy sources.

(ii) Support to Rooftop Solar Program. Part B TA consultants provided support and training to SLSEA to develop the rooftop solar power program.31

(iii) Renewable energy master plan. Part B TA consultants completed the plan by 2014, with MOP, CEB, and SLSEA as participating agencies.32

(iv) Master plan for the Mannar wind power park. In early 2014, the Part B TA consultants submitted the plan33 and commercial documentation.34 Phase I of the Mannar Wind Power Generation project (100 MW) started commissioning in late 2020 and is expected to be completed in 2021.

(v) Capacity building. Part B TA consultants undertook capacity building in 2014 through a series of workshops for stakeholders. These enabled the consultants to consult stakeholders, build capacity, and disseminate their findings. The workshops involved 282 participants from the government (MOP, CEB, SLSEA, Public Utilities Commission of Sri Lanka) and the private sector. Although 30% of the CEB and SLSEA staff were to be female, no gender disaggregated data was available.

Project Costs and Financing

27. At appraisal, the project cost was estimated at $200.0 million, inclusive of taxes and duties of $24.88 million. ADB was to provide a loan of $100.0 million from its ordinary capital resources, and a loan equivalent to $30.0 million from its Special Fund resources. The Clean Energy Fund under the Clean Energy Financing Partnership Facility was to provide a grant of $1.5 million for the solar rooftop power generation pilot.35 The government and the CEB were to contribute $68.5 million to meet the balance (34.25%) of the total estimated cost (Appendix 7). 28. The total project cost on completion was $133.91 million, including local costs, interest during implementation and commitment charges. The total financing through loan and grant components was $115.56 million, of which ADB financed $114.58 million as loans ($90.50 million from ordinary capital resources and $24.08 million from Special Fund resources) while $0.98 million was from grant funding. Other costs, including land-related costs, project development costs, and taxes were borne by the government. The total foreign exchange cost component of the project was $79.75 million, while the local cost component was $54.15 million (Appendix 7). 29. One of the main reasons for the reduction in project cost compared with the original estimate was the depreciation of the local currency, resulting in lower local costs. While a constant

30 Nexant, in association with Siemens Industry, Siemens Power Technologies International and Resource

Development Consultants. 2014. TA-8167 SRI: Capacity Building for Clean Power Development. Part A: System Stability and Network Planning Studies, Final Report. San Francisco, USA

31 Funded from the Clean Energy Financing Partnership Facility grant. 32 RMA Energy Consultants et al. 2014a. TA-8167 SRI: Capacity Building for Clean Power Development. Part B:

Preparation of Renewable Development and Wind Park Master Plans and Business Model for Wind Park; Part 1: Renewable Energy Master Plan. Colombo.

33 RMA Energy Consultants et al. 2014b. Part 2: Master Plan for wind power development in Mannar District. Colombo. 34 RMA Energy Consultants et al. 2014c. Part 3: Commercial Arrangements andBidding Documents for Wind

Development in Mannar District, Final Report. Colombo. 35 The Clean Energy Fund financing partners were the governments of Australia, Norway, Spain, Sweden, and the

United Kingdom.

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exchange rate of $1.0 = SLRs131.95 was assumed in estimating project costs during appraisal, by project completion, it had risen to $1.0 = SLRs175.50. Robust competition among the bidders and the high engineer’s estimate also resulted in a reduction of the actual cost. The project’s additional scope did not increase costs because it was financed by loan savings.

Disbursements

30. Loan and grant funding was disbursed according to ADB’s Loan Disbursement Handbook (2012, as amended from time to time). Disbursement projections at appraisal were aggressive, assuming most project activities would be completed by 2017. The projections were revised at loan extension because of practical challenges during implementation. Direct payment and commitment procedures were used for disbursement. An advance fund procedure was used by SLSEA for the rooftop solar program for private enterprises, enabling timely release of funds. The actual loan and grant disbursements totaled $115.56 million (Appendix 9), which was only 88% of the $131.5 million estimated at appraisal. This resulted in the cancellation of $9.50 million from loan 2892, $3.62 million from loan 2893, and $0.52 million from grant 0303.36

Project Schedule

31. The project was originally due to start in June 2012 and all components should have been completed by the end of June 2016. Although the documentation for the loans and grant had been prepared, they did not become effective until 30 September 2013 because of delays within the Attorney General’s office.37 Consequently, the project started 1 year late, and physical closure was reset for June 2017. As a result of subsequent implementation delays, the loans and grant were extended to 30 June 2019 and financial closure was set as 24 March 2020 (Appendix 2).

32. The delays were mainly attributable to transmission infrastructure activities under outputs 1 and 2, including (i) delayed procurement processes and port clearances,38 (ii) significant implementation delays by a contractor for one of the packages, (iii) minor changes in the design scope and procurement to meet new requirements,39 and (iv) objections from some communities affected by the changed routes of the transmission lines, which led to OSPF involvement, court cases and suspension of work (Appendix 4). Unforeseen delays in obtaining wayleave, construction difficulties in hilly terrain, and some severe rainfall events hampered construction. CEB also faced delays related to social safeguards, especially along transmission line routes, for which the compensation process for affected parties took up to 3 years to resolve, partly because this included obtaining clearances from multiple governmental agencies. Activities under output 3 were completed by the end of 2017 and output 4 by 2015.

Implementation Arrangements

33. The MOP was the executing agency, with CEB as implementing agency for the transmission and distribution activities (components 1 and 2), which represented about 98.6% of project expenditure. SLSEA was the implementing agency for the rooftop solar energy program

36 See Basic Data, Section B: Loan Data, 11.b Disbursement Amount. 37 Opinion of the Attorney General is sought before the signing of loan agreements between the government and any

international financial institution. A lengthy clarification and negotiation process between the Attorney General’s Office and the executing agencies took place before the final clearance, which delayed loan signing and loan effectiveness.

38 Contractors shipped relatively small consignments of equipment, which increased the overall time spent in port clearances. In addition, a Cabinet Decision in 2016 required all foreign cargo to be imported through Ceylon Shipping Corporation Ltd, which delayed the clearance of shipments already en route.

39 Such as upgrading the Mannar GSS to 220 kV to evacuate power from the new wind power park.

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(component 3). The South Asia Energy Division managed a capacity-building TA project under component 4. The management structure at design was unchanged at completion (Appendix 2). The CEB activities were managed under 4 project management units (PMUs), according to the contract packages. The PMUs were suitably staffed, with each one being headed by a senior CEB engineer as project manager. Three PMUs, responsible for transmission infrastructure, reported to CEB’s deputy general manager of transmission projects, and the PMU covering distribution infrastructure reported to the additional general manager for distribution division 2. Component 3 under SLSEA was headed by a project director, supported by an engineer and a national consultant. In the absence of an overall project director, the 8 subcomponents were managed by 4 separate PMUs. This resulted in a lack of overall project coordination. However, the implementation arrangement was adequate for delivery of the project outputs, due to the independent scope for each PMU.

Technical Assistance

34. The project was prepared under a project preparatory TA project (footnote 5). A comprehensive interim due diligence report, which described the background, key information, and proposed scope of implementation, was submitted before the ADB fact-finding mission. The TA assisted ADB in identifying a suitable project design, the potential risks, and mitigation measures such as the need for capacity building. The TA recommendations helped in formulating a robust project with achievable performance targets. 35. An associated TA project of $0.9 million, funded by the Technical Assistance Special Fund, provided advisory and capacity-building support for wind and solar power development on a PPP basis, under output 4 (para. 26).40 The completion report (Appendix 6) notes that the TA met its targets and was of satisfactory quality. The resource studies, business model development, and network assessments undertaken as part of the TA directly contributed to the development of the 100 MW Mannar wind power project, as well as other renewable energy development in the northern part of Sri Lanka.41 The TA was rated successful, as its major outputs were met and the assigned tasks under the terms of reference were implemented. The TA was rated relevant, effective, and efficient in achieving the outputs and outcome, with the outcome rated as likely to be sustainable.

Consultant Recruitment and Procurement

36. Consultants. CEB implemented its components without consultants. SLSEA recruited a solar specialist for 24 person months, under the grant, to help implement output 3. Recruitment was according to ADB’s Guidelines on the Use of Consultants (2010, as amended from time to time), and the consultant’s performance was satisfactory. 37. Procurement. All equipment, materials, and services were procured in accordance with ADB’s Procurement Guidelines (2010, as amended from time to time). The Standing Cabinet-appointed procurement committee supported MOP’s procurement operations for contracts exceeding SLRs600 million (equivalent to $3.4 million). Most contracts went through the committee. International competitive bidding was used for the 9 major contract packages required for transmission and distribution infrastructure under outputs 1 and 2. The single-stage, two-envelope bidding procedure was adopted. Sampath Bank was contracted as the participating financial institution to support output 3. The original contract award projections were realistic and

40 ADB. 2012. TA 8167-SRI: Capacity Building for Clean Power Development. Manila. 41 Ceylon Electricity Board. 2018. Long Term Generation Expansion Plan 2018-2037. Colombo

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were achieved. All major materials and equipment were supplied by reputable manufacturers, approved at bidding, and were of good quality. Factory acceptance tests for all major equipment were carried out by the manufacturers and witnessed by CEB engineers, as indicated in the contracts. Overall, the contractors’ performance was satisfactory. Safeguards

38. The project was classified as category B for environmental impacts. An initial environmental examination and an environmental management plan (EMP) were prepared during the design of each transmission and distribution infrastructure route, in accordance with ADB’s Safeguard Policy Statement (2009) and government guidelines and regulations. The EMPs identified the precautionary measures that needed to be taken during (i) the design stage to route transmission lines to avoid environmentally and socially sensitive areas, and (ii) the construction stage to minimize public inconvenience and damage to ecosystems. The documents were disclosed locally and on the ADB website. Where possible, transmission line routes crossed paddy fields and marshy and abandoned land to minimize impacts. Drones were used to assist with stringing and to reduce environmental damage in some hilly, forested areas. CEB closely monitored environmental impacts and compliance with the EMP throughout implementation and necessary mitigation actions were taken. The CEB, together with the forest department, carried out compensatory reforestation programs for the trees that were removed. Special attention was given to sound pollution, soil erosion, disposal of garbage, and the avoidance of greenhouse and toxic gases. An environmental compliance monitoring report for each subproject was submitted by the respective PMU bi-annually and posted on ADB’s website. 39. The project was classified as category B for involuntary resettlement and category C for indigenous peoples. CEB prepared and disclosed a resettlement plan in consultation with the people affected by the transmission and distribution line infrastructure. Several issues arose regarding compensation payments and objections to line routes. While the project resulted in economic displacement, no household was physically displaced. Nine persons were affected by CEB’s noncompliance with ADB’s policy on compensation prior to economic displacement. ADB suspended disbursements for Kegalle and New Polpitiya GSSs until CEB showed satisfactory progress on compensation payments according to the resettlement plan. CEB prepared a corrective action plan in early 2019 for settling the claims, and this was posted on ADB’s website in June 2019.42 All compensation has been made to the affected parties.

40. A 4 km section of the New Polpitiya to Pannipitiya transmission line route, which initially traversed a densely populated area, was rerouted by CEB to minimize the social impacts. Although CEB selected an alternative route with minimum environmental and social impacts to comply with the EMP, it failed to record these changes as required by ADB’s Safeguard Policy Statement and disclose them to ADB. The Magammana community organization objected to this rerouting, which led to legal action and the suspension of construction following intervention by the OSPF (Appendix 4). Since the issue cannot be resolved until a legal decision has been made, the loan closed with the work not completed. At loan closure, ADB requested CEB to resolve the issue as had been agreed with ADB, before implementing the remaining work (Appendix 4, para. 43).

42 Ceylon Electricity Board. 2019. Clean Energy and Network Efficiency Improvement Project: Safeguard Due Diligence

and Corrective Action Plan Package 2 Lot A and Package 3 Lot A. Colombo.

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Monitoring and Reporting

41. All loan covenants were complied with, except for (i) partial compliance with updating CEB and SLSEA websites with project information, (ii) delays by CEB in completing compensation payments, (iii) delays in submitting the audited project financial statement (APFS), and (iv) the late submission of selection criteria by SLSEA. Appendix 11 details compliance with key loan covenants. 42. During fact-finding, ADB assessed the implementing agencies’ financial management capabilities to be reasonable. However, delays in the submission of the APFS by both CEB and SLSEA continued throughout project implementation. For CEB, the submission of the APFSs from loan effectiveness to loan closing was delayed on average by 5 months, though the final APFS (2019) was received on time. The National Audit Office gave a qualified audit opinion for every APFS. For SLSEA, the delay in the submission of the APFSs from loan effectiveness to loan closing averaged 13 months. The National Audit Office gave an unqualified opinion for years 2014 and 2018 and a qualified opinion for years 2015, 2016, and 2017. A delay by SLSEA in submitting the 2017 APFS resulted in ADB suspending contract awards and disbursements, precluding SLSEA from some additional work.43 However, by 2018 SLSEA had made progress in resolving audit queries, hence the unqualified opinion for the 2018 APFS.44 PMU staff monitored safeguard compliance and submitted monitoring reports to ADB semiannually. The grievance redress mechanism functioned effectively in addressing the grievances of affected parties.

III. EVALUATION OF PERFORMANCE

Relevance

43. The project is rated relevant. It conformed with government and ADB policies at the start and remained so at conclusion (para. 5). The project design was also consistent with ADB’s Strategy 2030 operational priorities of addressing remaining poverty and reducing inequalities, tackling climate change and enhancing environmental sustainability, and strengthening institutional capacity. The objectives and envisaged impacts of the project were complementary to activities undertaken by other development partners, while duplication was avoided by clear demarcation of outputs. No major changes of scope were required.45 Despite some inconsistencies between the DMF and the main text of the report and recommendation of the President (footnote 1), the DMF’s results chain was generally logical, and indicators were mostly appropriate (Appendix 1). The original design enabled the project to meet its objectives. The project lending modality was appropriate (para. 5). Innovative features of the project included (i) piloting a successful approach to private sector adoption of solar rooftop power generation,46 and (ii) the use of drones to assist in transmission line stringing and reduce environmental impacts in hilly, forested areas. Both innovative elements have subsequently been implemented system-wide, validating the success of the pilots.

43 In early 2018, ADB had approved the use of loan savings for the Solar Research and Development Center at

Hambantota. 44 For SLSEA, APFS 2018 was the final submission, since there were no transactions in 2019. 45 The DMF was modified by the Sri Lanka Resident Mission in early 2018 to include a minor change in component 3

for a Solar Research and Development Center, which was later dropped. 46 This successful pilot was useful in the implementation of Sri Lanka’s rooftop solar program “Battle for Solar Energy

Program (Soorya Bala Sangramaya)”

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Effectiveness

44. The project is rated effective. The outcome envisioned “improved clean power supply, efficiency, and reliability in the delivery of electricity.” Although the achievement of the outcome performance indicators was sometimes delayed, they were all either achieved or substantially achieved. Specifically, (i) network losses were reduced to 8.23% in 2019, exceeding the 12% target; (ii) the transmission infrastructure is ready to evacuate power from the Mannar wind park when it comes online; (iii) 1.99 MWp of solar power was grid-connected, compared with 1.0 MW at design; and (iv) CEB maintains the distribution line end voltage fluctuations within 6%.47 All outputs of the project components (paras. 9-26) were either achieved or substantially achieved, with more than 90% of the output targets achieved at loan closure (Appendix 3). However, the completion dates for most of the outputs were later than envisaged at appraisal, some due to circumstances unforeseen at design. The project adhered to environmental safeguards and was implemented in compliance with the EMP (para. 38). Social safeguards were adhered to, apart from a few that were rectified through a corrective action plan (para. 39). One community objection, which could not be mutually resolved, was settled through a court proceeding (Appendix 4), resulting in the outputs being completed with all safeguard issues resolved. Safeguard categorizations remained unchanged.

Efficiency

45. The project is rated efficient. Project outputs were achieved at a lower cost than estimated. Overall, the project’s anticipated benefits are being realized satisfactorily, despite the delays in implementing project activities. An economic reevaluation was undertaken for the project (Appendix 12), following the same approach adopted at appraisal, but using the project costs and benefits as realized at completion. The reevaluated economic internal rate of return (EIRR) of the overall project was 14.3%, which is higher than the applicable hurdle rate of 12.0% as well as the 12.16% projected at appraisal. The reevaluated EIRRs of the three outputs are 18.7% for output 1, 12.9% for output 2, and 13.6% for output 3. The timely approval of scope changes to use loan savings rather than cancelling funds is an indication of the project’s process efficiency to support additional benefits. The legal proceedings, which were subsequently rejected by the courts, were managed efficiently by the implementing agency, allowing the output and outcome targets to be achieved despite delays. Considering that the reevaluated EIRR of the project accounts for the adverse impacts of these delays, the overall efficiency is assessed as efficient.

Sustainability

46. The project is rated likely sustainable. Based on the financial analysis conducted upon project completion, the financial internal rate of return (FIRR) of the project was reevaluated at 6.16% (Appendix 13). In comparison with the reassessed weighted average cost of capital of 4.85%, the project FIRR is considerably higher, indicating the project’s financial sustainability. The FIRR of the two project outputs implemented by CEB (outputs 1 and 2) are estimated at 5.91% and 6.09%, assuring positive financial returns to CEB. Nevertheless, the project schemes are required to conform to the uniform island-wide tariff applied by CEB. The tariff methodology approved by the Public Utilities Commission of Sri Lanka in 2011 is designed to enable CEB to recover its approved investments through end-user consumer tariffs. However, since this cost-

47 Although not included as outcome indicators in the DMF, the project has generated 2.6 GWh solar power and has

contributed to the reduction of carbon dioxide emissions by 2,126 tons per year.

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reflective tariff is not practiced, CEB will have to exercise its entitlement to government financial support.48 47. CEB is an established government organization, with a turnover of over $1.0 billion. As the sole transmission licensee of the country, CEB is expected to withstand any adverse conditions, considering the importance of electricity transmission to the economy. All project infrastructure outputs were constructed according to CEB’s high-standard technical specifications, meeting the environmental safeguards specified by national laws as well as by ADB’s Safeguard Policy Statement. Therefore, the project is backed by strong institutional and environmental sustainability. To assure future maintenance, responsibility for the energized transmission and distribution line infrastructure will be delegated to the CEB’s Heavy Maintenance Branch, under the purview of the provincial deputy general managers. This department is an integral operational unit within the CEB organizational structure. The costs related to maintenance are incorporated in the electricity tariff methodology, although CEB has yet to be able to practice the tariff revisions.49 The recovery of costs through consumer tariffs and the consequential long-term sustainability of both the project and the entity are presented in Appendix 13.

48. Solar rooftop systems installed by SLSEA were rigorously tested and monitored by SLSEA. They are expected to be sustainable over the 20-year lifetime of the photovoltaic panels, subject to the replacement of inverters. As the pilot contributed to scaling-up through the Battle for Solar Energy (Soorya Bala Sangramaya) program, managed by SLSEA, the approach has been sustained. Given the recalculated FIRR of 12.55%, the component will be sustainable.

Development Impact

49. The development impact is rated satisfactory. The project aimed to improve the national reliability, adequacy, and affordability of power supply for sustainable economic growth and poverty reduction by 2020 (see the DMF in Appendix 1). It contributed to the country’s power sector reliability by improving power supplies to about 123,500 customers in parts of Northern, North Central, Central, Sabaragamuwa, and Eastern provinces.50 This will boost economic development and reduce poverty in former conflict-affected areas and in Kegalle district of Sabaragamuwa province. The project contributed with 2 MW of installed capacity although it was not expected to contribute to any new significant generating capacity. The solar rooftop power pilot developed successful innovative approaches and regulatory systems that led to investment by private sector entities in solar rooftop power generation. These approaches have been adopted in the government’s national Battle for Solar Energy program. The outputs of the advisory and capacity-building support have been adopted by CEB in improving system stability and in developing renewable energy programs, especially wind power. 50. The project supported ADB’s operational priorities with (i) the installation of 1.99 MW additional energy capacity from solar rooftop sources (OP 3.1.4); (ii) the construction or upgrading of 243 km of transmission lines (OP 3.1.5), (iii) the installation of 129 km of distribution lines (OP 3.1.5), (iv) the reduction in annual greenhouse gases (CO2) of 77,680 tons per year (OP 3.1), and (v) energy savings of 85.6 GWh/year (OP 3.1).

48 CEB is entitled to a government subsidy in case the consumer tariff is not sufficient to recover its allowed revenue.

However, this subsidy mechanism is not automatic and may be delayed. 49 Public Utilities Commission of Sri Lanka. 2015. Tariff Methodology. 50 The breakdown of the beneficiaries is as follows: (i) output 1: Northern province, Mannar district 25,000; (ii) sub-

output 2.1: Sabaragamuwa province, Kegalle district 25,000; (iii) sub-output 2.3: North Central province 30,500 and East and Central provinces 68,000 customers.

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Performance of the Borrower and the Executing Agency

51. The borrower was the Government of Sri Lanka and the MOP was the executing agency. On behalf of the government, the MOP oversaw the implementation of the project via two implementing agencies: the CEB and SLSEA. No issues of substance were noted during implementation. Although some process delays were experienced, particularly in reaching loan effectiveness, the contract award targets were met. CEB successfully implemented the project without consultants. It acted as both employer and project manager of the construction contracts, mobilizing its own engineers to monitor work progress. CEB demonstrated an ability to technically formulate, appraise, engineer, and project-manage complex electrical transmission and distribution activities. However, shortcomings regarding safeguards compliance in three of the contract packages resulted in ADB having to supplement safeguards work. Two were addressed through a corrective action plan, while the other was still not settled at loan closure because of legal proceedings (transmission line route via Magammana, Appendix 4). Following loan closure, CEB was granted the right of way and completed the construction work. Counterpart funds were made available on time. SLSEA implemented its component successfully and in a timely manner. Both CEB and SLSEA were late in complying with the submission of the APFSs, except for the last submission of CEB. Both the implementing agencies and the executing agency demonstrated strong ownership of the project and exerted genuine effort to comply with implementation requirements once any shortfall was brought to their notice. The overall performance of the borrower and executing agencies was satisfactory.

Performance of the Asian Development Bank

52. ADB conducted 11 review missions and made multiple visits to many of the project sites. CEB maintained a close relationship with ADB staff, who were cognizant of the nature of the work and issues to be expected, which facilitated the smooth implementation of project activities. The government and implementing agencies appreciated ADB’s efforts in steering the project to successful implementation. ADB (i) promptly facilitated the loan extension, (ii) swiftly acted on the contract scope revisions to ensure smooth progress, (iii) made prompt disbursements to ensure smooth cash flow, and (iv) provided required training on ADB guidelines and regulations. Initially, ADB did not follow up on financial management compliance, but this was subsequently addressed. ADB’s overall performance was satisfactory.

Overall Assessment

53. Overall, the project is rated successful. The project conformed to the government’s and ADB’s policies at appraisal and remained so at completion, making the project a relevant investment for the Sri Lanka energy sector. Implementation of the project was effective, as it delivered the envisaged outcomes by meeting most of the output targets. The project was efficient because of the economic returns expected over the long term and the process followed in its implementation. Considering the projected financial returns, the outlook of the entity’s financials, and the environmental and social dimensions, the project is considered likely sustainable in the long term. Overall Ratings

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Criteria Rating Relevance Relevant Effectiveness Effective Efficiency Efficient Sustainability Overall Assessment Development impact Borrower & executing agency. Performance of ADB

Likely sustainable Successful Satisfactory Satisfactory Satisfactory

Source: Asian Development Bank

IV. ISSUES, LESSONS, AND RECOMMENDATIONS

A. Issues and Lessons

54. Several lessons have been learned:

(i) A change in the transmission line route after appraisal led to significant delays in obtaining right of way. CEB should finalize line routes before contract award, rather than finalizing them after the contractor has prepared the final designs (following detailed surveys).

(ii) Changes of route by CEB without adequate local consultation led to serious objections and legal actions. The PMUs need trained safeguard officers.

(iii) Drones are effective in assisting in stringing in hilly, forested areas, such as along the 220 kV New Polpitiya-Pannipitiya and 33 kV Kiribathkumbura -Galaha lines.

(iv) The solar rooftop power generation pilot successfully demonstrated the benefits of competitive bidding for loan support and capital grants by private entities, enabling a doubling of installed capacity. The pilot has set the standards for scaling-up.

(v) The engagement of the Financial Management Officer in the Sri Lanka Resident Mission in 2019 resulted in the improved financial management of the implementing agencies during the closing of the project.

B. Recommendations

55. Project-related recommendations include:

(i) CEB should focus on advance detailed designs to reduce delays in transmission line projects.

(ii) MOP to introduce a land acquisition and resettlement committee approach for power projects to resolve the grievances of local objectors at District Secretary level.

(iii) CEB to establish a fully functional environmental and social safeguards unit. This unit could address (coordinate, communicate, and resolve) issues related to the environment and involuntary resettlement at project processing and during implementation (including monitoring).

56. Future monitoring. ADB should (i) monitor CEB’s progress in establishing a safeguards unit, and (ii) strengthen its monitoring of financial management compliance by implementing agencies. CEB should continue to monitor and evaluate the project’s impacts and ensure that the facilities and infrastructure are well maintained.

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57. Further action or follow-up. ADB should follow up on the recommendations made to CEB at loan closure regarding the remaining construction work at Magammana. ADB should also assess the grievance redress mechanism practices for technical and capacity building initiatives and provide safeguards implementation training for CEB’s safeguards staff.

58. Timing of the project performance evaluation report. The project performance evaluation report may be carried out any time after the finalization of the project completion report.

Appendix 1 17

DESIGN AND MONITORING FRAMEWORK

1. The design and monitoring (DMF) used in this project completion report (PCR) has been revised based on (i) the intent of the 2012 report and recommendations of the President (RRP)1, and (ii) a minor change in scope of output made in 2018.

Comments and revisions on the DMF

2. The impact statement was reworded as ‘improved national reliability, adequacy and affordability of power supply’ to reflect the desired change. Indicators related to reliability (index to show changes in power outages) and affordability (index to show any change in mean power prices relative to mean national incomes) could have also been included.

3. The outcome statement should reflect the project areas specified in the RRP, i.e., Eastern, North Central, Central, Northern, Southern and Western provinces. Sabaragamuwa province was added on account of construction of Kegalle grid substation (GSS) and the Thulhiria- Kegalle 132 kilovolt (kV) transmission line. For clarity, these areas were reflected in the DMF below. Indicators for quality and reliability of power supplies could have been included as a measure of results given that improvements in transmission and distribution infrastructure are major elements of the design.

4. Changes were made on the structure of the outputs, but the content remains consistent with the RRP.

(i) Output 1: RRP, para. 7 (i) included augmentation of the Vavuniya GSS. This was not shown in the DMF. As these were removed in 2015, the DMF below has not been changed. RRP, para. 7 and footnote 11, the 132 kV transmission lines were to be designed to ‘be ready for future upgrading to 220 kV’ but charged at 132 kV. This was not reflected in the RRP DMF but has been added in the DMF below.

(ii) Output 2: This has been separated into three ‘sub-outputs’ reflecting the three key elements defined under the RRP, para. 7 (ii) (transmission lines, reactive power and medium voltage network improvements). Targets for sub-output 2.1 included a new 63 megavolt-ampere (MVA) 132/33 kV GSS but overlooked the augmentation of the Thulhiriya GSS (RRP, para. 7(ii) (c)). This has been added. The indicators for sub-output 2.3 (medium voltage network efficiency improved) refers to inclusion of households headed by women. As the project was not engaged in creating new connections, the improved supply applied to all existing customers, regardless of gender.

(iii) Output 3: The indicators on expected gigawatt-hour generation and carbon dioxide reduction could be more appropriately reported as outcome indicators. Indicators maintained in the DMF below but reported in the main text.

5. Despite these shortcomings, there is logical linkage in the results chain of the DMF and measures of performance are generally appropriate.

1 ADB. 2012. Report and Recommendation of the President to the Board of Directors: Proposed Loans, Technical

Assistance Grant and Administration of Grant, Democratic Socialist Republic of Sri Lanka: Clean Energy and network Efficiency Improvement Project. Manila.

18 Appendix 1

Design and Monitoring Framework

Design Summary Performance Targets and Indicators with

Baselines Actual Achievements

Impact

Improved national reliability, adequacy, and affordability of power supply for sustainable economic growth and poverty reduction.

System supply capacity increased from 3,139 MW in 2011 to 6,367 MW by 2020

Partially Achieved. The total installed capacity by 2019 was 4,434 MW.a CEB aims to add 585 MW and retire 30 MW of generating capacity during 2020, to a give total installed capacity of 5,317 MW by the end of 2020.a

While this is considered partially achieved compared to the DMF target, this is considered substantially achieved given the revised forecasted generation requirement (5317MW) based on CEB’s biannual generation plan.

.

Electrification rate increased from 91% in 2011 to 100% access to all by 2015

Achieved. Sri Lanka had achieved 100% electrification in 2016 (Sri Lanka Ministry of Power). (Source MOPb)

In-grid energy supply from nonconventional renewable energy (NCRE) sources increased from 4.1% in 2007 to 7.0% by 2012, 10.0% by 2016, and 20.0% by 2020

Substantially Achieved. Contribution by NCRE sources to the total in-grid energy supply was 6.3% in 2012, 8.2% in 2016, and 11.2% in 2018. Forecast for 2020 is 18.4%. (Source CEBa)

500 MW of renewable energy added by 2016 (2007 baseline: 123 MW)

Exceeded. Total installed NCRE generation capacity by end of 2020 was 1,245 MW: 419 MW mini-hydro, 368 MW wind (including 100 MW from Mannar wind park), 410 MW solar (including committed large solar plants and forecast rooftop solar generation) and 48 MW biomass power plants. This exceeds the 2007 baseline by 1,122 MW, achieving the target. (Sources CEBa)

Outcome

Improved clean power supply, efficiency, and reliability in the delivery of electricity in the project provinces (Eastern, North Central, Central, Northern, Southern, Western and Sabaragamuwa).

Technical and commercial losses of the CEB network reduced from 14.6% of net generation in 2009 to 13.0% by 2016 and 12.0% by 2020

Exceeded. Losses successfully reduced to 10.68% in 2012, 9.63% in 2016 and 8.23% in 2019. (Source CEBa).

Transmission infrastructure for connecting 100 MW of wind power to the grid completed by December 2016

Achieved. Transmission infrastructure for evacuating power from Phase I of Mannar wind park, (100 MW) connected February 2020, before the wind park commences generation.

1 MW of solar power connected to the grid by December 2014

Achieved. 1.99 MWpc of solar power connected to grid by Dec 2017

Distribution line end voltage fluctuation maintained within 5% in project areas by

Substantially achieved. Due to the distribution components (33 kV lines), average line end voltage fluctuation is at 4.8%. The following tail end voltage

Appendix 1 19

Design Summary Performance Targets and Indicators with

Baselines Actual Achievements December 2016 fluctuation improvements have been recorded: (i) Vavuniya – Kebithigollewa:

from 11.7% to 4.8%, (ii) Anuradhapura – Kahatagasdigiliya: from 6.2% to 2.8%, (iii) Kiribathkumbura – Galaha: from 19.8% to 5.4%, (iv) Galmadu - Akkaraipatthu: from10.3% to 5%, and (v) Akkaraipatthu – Potuvil: from 25.4% to 6%.

Outputs

Output 1 1. Transmission infrastructure strengthened in Northern province.

Transmission infrastructure strengthened.

31.5 MVA 132/33 kV grid substation (GSS) capacity added to the transmission network by December 2016.

Achieved. A new 220/33 kV, 45 MVA GSS at Mannar constructed (upgraded from 132 kV to 220 kV from the original plan. It was added to the network by February 2020.d

125 km of 132 kV transmission line added to the transmission network (designed to be ready for future upgrading to 220 kV but charged at 132 kV) by December 2016.

Achieved. 55 km double circuit, two Zebra 220 kV New Anuradhapura to Vavuniya transmission line and 70 km double circuit, single Zebra 220 kV Vavuniya to Mannar transmission line completed Jun 2019. e After the project started, and the Mannar GSS was redesigned to 220 kV levels, the transmission line was energized at 220 kV.

Completion of the new Mannar GSS and transmission lines from Anuradhapura to Mannar via Vavuniya should enhance the currently poor reliability and quality of power in Mannar town and ultimately evacuate power from the new Mannar wind power generation project.

Output 2. Transmission and Distribution Network Efficiency Improved

Sub-output 2.1: Power transmission developed.

1,000 MVA 220/132 kV GSS added to the grid by December 2016.

Achieved. 1,000 MVA capacity installed, comprising new GSSs at New Polpitiya (500 MVA) and Padukka (500 MVA), and augmentation/ modification to Pannipitiya GSS. Systems completed by June 2019. e Delays due to design changes to suit sites and heavy rain at the New Polpitiya GSS.

63 MVA 132/33 kV GSS capacity added to the grid and one GSS augmented by December 2016.

Achieved. 63 MVA capacity added at new Kegalle GSS (132 kV/33 kV, 2 x 31.5 MVA), including eight 33 kV line bays and 15 MVAr capacitor banks (33 kV), and capacity of Thulhiriya GSS augmented with two132kV line bays and extension to 145 kV outdoor, air insulated switchgear with single busbar arrangement. Completed June 2018 f but not energized until Sept 2018, pending completion of Thulhiriya to Kegalle 132 kV line. Delays due to design, land access, contractor management, construction and commissioning issues. These GSSs and 132 kV transmission benefited some 25,000 customers in Kegalle district with improved quality of supply.

58.5 km of 220 kV double-circuit transmission lines added to the transmission

Achieved. Construction commenced on 73.2 km of 220 kV double circuit 3-phase transmission line (400mm2 aluminium conductor steel reinforced (ACSR) cables,

20 Appendix 1

Design Summary Performance Targets and Indicators with

Baselines Actual Achievements network by December 2016 with a galvanized and an optical fiber ground wire) from New Polpitiya to

Pannipitiya. Construction was delayed by three years due to hilly terrain, redesigns to reduce environment damage, wayleave issues in populated areas, access problems in forest areas (drones were used for stringing), adverse weather and inability to release land in time due to court cases and ADB’s suspension of works within Magammana. Construction was completed by June 2019, except for 4 km of stringing in the Magammana section,g and in the Arawwala section. Following the clearances received for RoW from the courts the construction been completed within Magammana, and one circuit in Arawwala. Second circuit is expected to be completed by April of 2021. The new link is essential to supplement the existing Biyagama-Kothmale 220 kV line, to strengthen the network and reduce the frequency of costly outages.

57.5 km of 132 kV double- circuit transmission lines added to the transmission network by December 2016.

Substantially Achieved. 24 km 132 kV double circuit, 3-phase transmission lines constructed: (i) Thulhiriya to Kegalle (22.5 km), and (ii) Polpitiya to New Polpitiya (1.5 km). 25 km of 132 kV double circuit, 3-phase transmission lines were partially constructed/rehabilitated: (iii) Athurugiriya to Padukka (10 km), and (iv) Athurugiriya to Kolonnawa (15 km). e The Thulhiriya to Kegalle transmission line was completed in September 2019 after delays due to difficult terrain, way leave issues and legal actions delaying stringing. Polpitiya to New Polpitiya line was operational by late 2017; Athurugiriya to Kolonnawa restringing was not completed as CEB was unable to arrange the required supply interruption and completion pending linking of the 220 kV New Polpitiya to Pannipitiya line. Athurugiriya to Padukka, traversing a highly populated area, was delayed three years by way leave. The construction is complete, and the line is expected to be operational by March 2021. When complete, the new links will enhance the network and reliability of supplies.

Sub-output 2.2. Reactive power management improved.

175 MVAr installed on 33 kV busbar for reactive power management by December 2016. h

Achieved. Total of 160 MVAr breaker switched capacitor (BSC) banks installed at seven GSSs: 30 MVAr at Biyagama, 20 MVAr at Bolawatta, 15 MVAr at Horana, 20 MVAr at Kolonnawa New, 20 MVAr at Kolonnawa Old, 20 MVAr at Pannala, 35 MVAr at Sapugaskanda. Biyagama and Bolawatta GSSs each include two 36 kV outdoor switchgear BSC bays. Completed March 2019, e after 23-months of delays due to design, land access, contractor management, construction and commissioning issues. Once all completed and energized the BSCs actively contributed to reduced system losses as planned. Further 15 MVAr installed at the newly constructed Kegalle GSS. Thus, total installation of 175 MVAr of BCS.

Sub-output 2.3. Medium voltage network efficiency improved.

129 km of new 33 kV lines added to improve power supply quality to about 91,000 customers and poor rural households, including those headed by women, by

Achieved. By 2018, a total of 129 km of new 33 kV double circuit tower lines constructed: (i) 23 km from Vavuniya GSS to a new 33 kV two section single busbar gantry at Kebithigollewa, (ii) 31 km from New Anuradhapura GSS to a new 33 kV two section single busbar gantry at Kahatagasdigiliya, (iii) 15 km

Appendix 1 21

Design Summary Performance Targets and Indicators with

Baselines Actual Achievements December 2015.

from Kiribathkumbura GSS to a new 33 kV three section double busbar gantry at Galaha, and (iv) 60 km from Galmadu Junction gantry to new 33 kV two section single busbar gantries at Akkaraipatthu & Potuvil. e

The Vavuniya, Kebithigollewa, Anuradhapura and Kahatagasdigiliya infrastructure was completed in July 2017, delayed due to weather, rerouting and minor design changes. Quality and reliability of supplies improved to meet demands of 30,500, mainly rural consumers, including those in post-conflict resettlement areas of North Central province.

The Kiribathkumbura, Galaha, Potuvil and Galmadu elements were completed in May 2018 after delays due to weather, objections, wayleave, hilly terrain and technical issues. Completion of the links to Galaha and Potuvil greatly improved the quality and reliability of supplies to 68,000 consumers in Central and Eastern provinces, and will serve demands of post-conflict rural electrification, and bulk supplies for development of industry and commerce, as well as for tourism in Eastern province. Connecting existing mini-hydro stations to the Galaha gantry augmented supplies.

Output 3. Solar rooftop power generation pilot developed.

Solar rooftop power generation developed

1 MW solar rooftop power developed on a PPP basis installed by December 2014, resulting in a total of 34.43 GWh generation.

Achieved. Total of 1.99 MWp solar rooftop systems installed, operational and grid-connected, with 2.6 GWh annual generation by 2018, 50.0 GWh expected over the 20-year lifetime of the panels. (Appendix 5).

(i) A total of 200 kWp capacity was installed under grant funding (G0303) at four universities by Dec 2017: Peradeniya 60 kW, Jaffna 60 kW, Moratuwa 40 kW and Ruhuna 40 kW (Appendix 5). Solar power was included in curricula and being used as a basis for research at Jaffna and Peradeniya (SLSEA).

(ii) Total of 22 private sector rooftop solar systems installed, operational and grid connected, including industrial, hotel and general-purpose enterprises that qualified for part-finance from the credit line of the project loan. A total capacity of 1.79 MWp installed by Dec 2017 (SLSEA).

1,286 tons of carbon dioxide emissions avoided per year.

Achieved. CO2 emissions of 2,126 tons per year avoided by end 2018. (SLSEA).

Solar Research and Development Centre to be constructed by June 2019. i

Not Achieved. Construction was suspended by ADB in early 2019 due to noncompliance by SLSEA.

Output 4. Advisory and capacity building support for wind and solar power development

22 Appendix 1

Design Summary Performance Targets and Indicators with

Baselines Actual Achievements

Support provided for wind and solar power development on a PPP basisj

System stability study finalized by December 2013

Achieved. System stability study completed by TA 8167a Part A consultants and submitted to ADB and CEB in May 2014 (Nexant et al, 2014) (Appendix 7). The study enabled CEB to plan capacity for incorporating more renewable energy sources.

Support for 1 MW solar rooftop pilot provided by December 2015.

Achieved. SLSEA was supported through a consultant in developing the component 3 rooftop solar power program which was completed in 2017.

Medium-term renewable energy master plan prepared.

Achieved. Master plan completed by TA 8167 Part B Consultants (RMA, 2014a), with MOP, CEB and SLSEA as participating agencies. (Appendix 7)

Master plan, a PPP business model, and commercial documentation for a 100 MW wind power park developed.

Achieved. Master plan for Mannar wind power park submitted by TA 8167 Part B consultants in 2014 (RMA, 2014b). Part B.3 consultants submitted commercial documentation in 2014 (RMA, 2014c). (Appendix 7). Mannar Wind Power Generation Project (initially 100 MW with plans for 375 MW) is expected to start generating at full capacity by Mid 2021 and feeding into the Mannar GSS.

CEB and SLSEA capacity for renewable energy development built, including about 60 staff (30% of whom are women) trained by December 2015.

Achieved. A series of workshops were organized for stakeholders during 2014 by Part B consultants, which enabled them to consult, build capacity and disseminate TA findings. These involved 282 participants from government (MOP, CEB, SLSEA, PUCSL) and private sector. Workshop activities were found by participants to be useful and relevant (Appendix 7). No gender disaggregate data were available.

ADB = Asian Development Bank, BCR = Borrower’s completion report, CEB = Ceylon Electricity Board, CEF = Clean Energy Fund, CEFPF = Clean Energy Financing Partnership Facility, CO2 = carbon dioxide, GSS = grid substation, GWh = gigawatt-hour, km = kilometer, kV = kilovolt, kW = kilowatt, MOP = Ministry of Power, MVA = megavolt-ampere, kWp = the peak power of a PV system or panel. MVAr = megavolt-ampere reactive, MW = megawatt, MWp = peak power of a PV system. NCRE = Nonconventional renewable energy, OCR = ordinary capital resources, OSPF = Office of Special Project Facilitator, PPP = public–private partnership, PUCSL = Public Utilities Commission of Sri Lanka, SLSEA = Sustainable Energy Authority, TA = Technical Assistance; TASF-IV = Technical Assistance Special Fund. The DMF is based on the DMF in the RRP 2012, with minor changes shown in italics, as explained in the explanatory notes at the beginning of this Appendix.

Notes: a Total installation incorporates the rooftop solar capacity of 217MW by end of 2019. CEB sources of data: CEB. 2020. Long Term Generation Expansion Plan (2020-2039).; CEB Statistical Digest 2019; CEB Long Term Generation Expansion Plans.

b Ministry of Power. 2017. Sri Lanka MOP, 2016

c MWp Megawatt peak is a measure of the maximum potential output of power. This measurement is used when intermittent resources are applicable.

d ADB loan Nos. 2893-SRI(SF) and 2892-SRI were closed by June 30, 2019, the remaining costs were financed through ADB loan nos. L3483/3484: Green Power Development and Energy Efficiency Improvement Investment Program – Tranche 2. The original plan to augment the Vavuniya GSS was dropped, and the transmission lines by-passed the Vavuniya 132 kV GSS.

Appendix 1 23

e CEB. July 2019. SRI: Clean Energy and Network Efficiency Improvement Project-Environmental Monitoring Report. Colombo.

f CEB. Aug 2018. SRI: Clean Energy and Network Efficiency Improvement Project-Environmental Monitoring Report. Colombo.

g The original Magammana section traversed a high density population area and was rerouted by CEB but in June 2017 residents of the second route objected given inadequate consultations. They proposed a third route and made a formal objection to ADB Manila. OSPF requested CEB to reassess the three routes. CEB objected given the supreme court case launched by affected residents. The case was dropped in February 2020 and CEB has completed one circuit of the transmission line with the other expected to be completed in March of 2021 (Appendix 5).

h The performance target was installation of 175 MVAr. 160 MVAr was installed under this subcomponent and another 15 MVAr at Kegalle GSS, under subcomponent 2.1, totaling 175 MVAr.

i This output and activity were added in early 2018 under a minor change of scope but was dropped in February 2019 due noncompliance by SLSEA in submitting audited project financial accounts for 2017.

j Sri Lanka Sustainable Energy Authority. 2020. Project Completion Report Loan Nos 2892/2893 and Grant No 0303, Clean Energy & Network Efficiency Improvement Project, Solar Rooftop Power Generation Pilot. Colombo, Sri Lanka.

Sources: ADB. 2012. Report and Recommendation of the President to the Board of Directors: Proposed Loans, Technical Assistance Grant and Administration of Grant, Democratic Socialist Republic of Sri Lanka: Clean Energy and network Efficiency Improvement Project. Manila; BCR 1: Ceylon Electricity Board. 2019. Project

Completion Report ADB Loan Nos. 2892/2893, Clean Energy & Network Efficiency Improvement Project: Package 1. Wattala, Sri Lanka; BCR 2: Ceylon Electricity Board. 2019. Project Completion Report ADB Loan No. 2892, Clean Energy & Network Efficiency Improvement Project: Package 2. Pelewatta, Sri Lanka; BCR 3: Ceylon Electricity Board. 2019. Project Completion Report ADB Loan No. 2892, Clean Energy & Network Efficiency Improvement Project: Package 3. Rajagiriya, Sri Lanka; BCR 4A: Ceylon Electricity Board. 2019. Project Completion Report ADB Loan Nos. 2892/2893, Clean Energy & Network Efficiency Improvement Project:

Package 4A: Medium Voltage/ Distribution, Sub Projects - Lot A. Negombo, Sri Lanka; BCR 4B: Ceylon Electricity Board. 2019. Project Completion Report ADB Loan

Nos. 2892/2893, Clean Energy & Network Efficiency Improvement Project: Package 4B: Medium Voltage/ Distribution, Sub Projects - Lot B. Negombo, Sri Lanka; BCR 5: Sri Lanka Sustainable Energy Authority. 2020. Project Completion Report Loan Nos 2892/2893 and Grant No 0303, Clean Energy & Network Efficiency Improvement Project, Solar Rooftop Power Generation Pilot. Colombo, Sri Lanka; Nexant, in association with Siemens Industry, Siemens Power Technologies International and Resource Development Consultants. 2014. TA-8167 SRI: Capacity Building for Clean Power Development. Part A: System Stability and Network Planning Studies, Final Report. San Francisco, USA; RMA Energy Consultants in association with Mercados Energy Markets India Pvt Ltd. 2014a. TA-8167 SRI: Capacity Building for Clean Power Development. Part B: Preparation of Renewable Development and Wind Park Master Plans and Business Model for Wind Park; Part 1: Renewable Energy Master Plan. Colombo; RMA Energy Consultants in association with Mercados Energy Markets India Pvt Ltd. 2014b. TA-8167 SRI: Capacity Building for Clean Power Development. Part B: Preparation of Renewable Development and Wind Park Master Plans and Business Model for Wind Park; Part 2: Master Plan for wind power development in Mannar District. Colombo; RMA Energy Consultants in association with Mercados Energy Markets India Pvt Ltd. 2014c. TA-8167 SRI: Capacity Building for Clean Power Development. Part B: Preparation of Renewable Development and Wind Park Master Plans and Business

Model for Wind Park; Part 3: Commercial Arrangements andBidding Documents for Wind Development in Mannar District, Final Report. Colombo; ADB 2016. Mannar Wind Power Generation Project, Loan 3585. Manila

A0O A0O

24 Appendix 2

IMPLEMENTATION AND MANAGEMENT ARRANGEMENTS

Figure A2.1: Implementation and Management Arrangements

Appendix 2 25

Figure A2.2: Chronology of Main Events and Administrative Milestones

26 Appendix 2

Figure A2.3: Implementation Schedule: at Design (August 2012) and Actual

Appendix 2 27

Figure A2.4: Actual Contractor Implementation Schedule

28 Appendix 3

PROJECT EFFECTIVENESS SUMMARY

1. In assessing the output achievements, using both numerical counting and weights application would lead to more than 90% achievement.

2. Numerical counting. Proper grouping of indicators would lead to a total count of 13 indicators (output 1 with 2 indicators, output 2 with 6 indicators, output 3 with 3 indicators and output 4 with 5 indicators). Based on the design and monitoring framework (DMF) in Appendix 1, 15 out of 16 have been achievement albeit with delay. The project has achieved 93.75% of its target.

3. Application of weights. As explained in Section B of the main text, and in the DMF (Appendix 1) some outputs under components 1 and 2 were not fully completed by project closure (30 June 2019). These comprised:

(i) The grid substation (GSS) at Mannar under component 1. Completion delayed until February 2020, due to design upgrades necessary to meet the power evacuation needs of the new Mannar wind farm,

(ii) Three transmission lines remained to be completed by project closure on 30 June 2019. On the 220 kilovolt (kV) Padukka-Pannipitiya line, all towers were erected, except for a 4-kilometer (km) section in the Magammana area, where objections by affected persons led to postponement of completion pending resolution of court actions (Appendix 5). Restringing of the 132 kV Athurugiriya to Kolonnawa line (15 km) could not be completed because the Ceylon Electricity Board was unable to arrange a suitable supply interruption until the new 220 kV New Polpitiya to Pannipitiya line had been completed to carry the extra load. In addition, the 12 kV Athurugiriya to Padukka line (10 km), which traversed a highly populated area, was delayed three years by way leave and legal actions.

4. To assess the overall effectiveness of the project, the outputs achieved have been reviewed in terms of (i) their percentage physical completion, and (ii) their budget costs, using techniques included in Asian Development Bank’s project performance rating system.1

5. The value of percentage physical completion for component 1 Mannar GSS was derived from the borrower’s completion report.2 Physical completion values for the three incomplete transmission lines under component 2 were given by the respective project management units.3 Each project subcomponent was assigned a weightage, based on its cost in relation to the total contract value. Thereafter, the effectiveness of each of the subcomponents was calculated, based on the percentage physical completion. These were then combined as overall figures to indicate achievement.

6. As illustrated in Table A3, the overall output achievement for the project was 96.3%, with components 1 and 2 scoring 90.8% and 96.6%, respectively.

1 ADB. 2020. Revision of Project Performance Rating (PPR) Methodology under PAI 5.08, Memorandum 6

May 2020: Procurement, Portfolio and Financial Management Department Portfolio Management Division. Manila.

2 Ceylon Electricity Board. 2020. Project Completion Report ADB Loan Nos. 2893 & 2892, Clean Energy & Network Efficiency Improvement Project - Package 1, (6/30/2019). Wattala, Colombo, Sri Lanka

3 PMU Project Monitoring Sheets

Appendix 3 29

7. Overall assessment of effectiveness. Given the level of output achievements are greater than 80% and the 100% achievement of outcome (with 3 indicators achieved and 1 substantially achieved, the project is assessed as effective.

30 Appendix 3

Table A3: Component/ Subcomponent Effectiveness Achievement

Planned Output at Appraisal Increased/ Reduced Output

1.131.5 MVA 132/33 kV grid substation (GSS) capacity added to the transmission network

45 MVA, 220/33kV GSS at Mannar constructed

1.2125 km of 132 kV transmission line added to the transmission network - designed to be

ready for future upgrading to 220 kV

n/c

1,000 MVA 220/132 kV GSS added to grid n/c

63 MVA 132/33 kV GSS capacity added to the grid and one GSS augmented

n/c

58.5 km 220 kV double-circuit transmission lines added to the transmission network

73 km 220kV double circuit 3-phase transmission line

57.5 km 132 kV double- circuit transmission lines added to the transmission network

49km 132kV double circuit lines

2.2175 MVAr installed on 33 kV busbar for reactive power management

n/c

2.3129 km new 33 kV lines added to improve power supply quality to about 91,000 customers and poor rural households.

n/c

1 MW solar rooftop power developed on a PPP basis installed

1.99 MWp solar rooftop systems installed

Solar Research and Development Centre to be constructed by June 2019.

Subcomponent dropped

4Advisory and capacity building support for wind and solar power development

n/c

3

GSS = Grid substation, n/c = no change, PPP = Public-Private Partnership.

Source: Project Completion Report data

Component Outputs

Component 1: Mean weighted achievement

Notes [a] As estimated by the implementing agencies; [b] Contract value/ total value of contracts;

Component 2: Mean weighted achievement

Component 3: Mean weighted achievement

Component 4: Mean weighted achievement

Total Component Weighted Effectiveness

2.1

67% 7.99 6.5% 4.3%

100% 20.53 16.6% 16.6%

100% 39.86 32.3% 32.3%

100% 6.27 5.1% 5.1%

90% 15.21 12.3% 11.1%

80% 7.83 6.3% 5.1%

100% 8.10 6.6% 6.6%

100% 14.51 11.7% 11.7%

199% 1.75 1.4% 2.8%

0% 0.60 0.5% 0.0%

100% 0.90 0.7% 0.7%

123.55 100.0% 96.3%

s; [c] Physial completion % x Weighing; [d] Weeighted Effective

Weighting [b]

Weighted Effectiveness

[c]

Physical Completion

[a]

Contract Value ($ million)

Weighting Weighted Effectivness

Achievement [d]

23.1% 21.0% 90.8%

74.3% 71.8% 96.6%

1.9% 2.8% 148.3%

0.7% 0.7% 100.0%

100.0% 96.3% 96.3%

ctiveness/Weighting.

Overall Component Achieivement

Appendix 4 31

POLPITIYA-PANNIPITIYA TRANSMISSION LINE GRIEVANCE AND PROBLEM-SOLVING PROCESS

Introduction

1. This report summarizes a series of events that revolved around a group of residents who complained that they would be adversely affected by the construction of a short section of the 69.2-kilometer (km) New Polpitiya – Pannipitiya 220 kilovolt (kV) transmission line, and who sought redress for their grievances concurrently from multiple institutions. The events, which unfolded over a period of almost five years between 2015 and 2019, led directly or indirectly to non-completion of two important transmission lines during the course of the loan period.

2. The aggrieved parties were residents of Magammana village1, located in Homagama Divisional Secretariat Division (DSD)2, Colombo District.

3. They approached several institutions to redress their grievances, including:

(i) Ceylon Electricity Board (CEB)3 (ii) Ministry of Power (MOP)4 (iii) Public Utilities Commission of Sri Lanka (PUCSL) (iv) Divisional Secretary of Homagama (v) Central Environment Authority (CEA) (vi) The judiciary (vii) Sri Lanka Resident Mission of the Asian Development Bank (ADB) (viii) ADB’s Accountability Mechanism.

4. This report reviews the processes followed by the different institutions to redress the grievances reported by the affected community, and their final outcomes. Nevertheless, the focus of the report is to highlight how the affected parties had approached the ADB’s accountability mechanism for grievance redress, its response to the complainants and the final outcome. A narrative of events that preceded engagement with the accountability mechanism, is included to illustrate their interconnectivity.

5. The information included in this report is based on a review of documents related to the issue, available at the resident mission and at the project management unit (PMU) of CEB. The documents comprised proceedings of various meetings, awareness raising programs, consultative meetings and field inspection visits, letters exchanged between complainants and the key stakeholders, written communications among different stakeholders, and internal notes maintained by stakeholder agencies.

Background to the Project

6. The ADB-assisted Clean Energy and Network Efficiency Improvement Project commenced in September 2013, under $130 million loans from ADB (L2892/L2893) and a grant of $1.5 million (0303-SRI) provided by the Multi-Donor Clean Energy Fund. The project included four components, as described in the design and monitoring framework (DMF) in Appendix 1.

1 Complainants represented two sub-divisions of Magammana: Magammana West and Magammana East Grama

Niladhari Divisions 2 Divisional Secretariat Division is a sub-district that comprises several Grama Niladhari Divisions (GNDs) 3 Including the Project Management Unit established for the Polpitiya-Pannipitiya transmission line of component 1. 4 The Ministry’s name changed intermittently during the project, but this did not affect implementation: Ministry of

Power, Renewable Energy, Petroleum Resources (MOPREPR), Ministry of Power, Energy & Business Development (MOPE&BD), Ministry of Power and Energy (MOPE), Ministry of Power (MOP) is adopted in this project completion report.

32 Appendix 4

(i) Component 1: Transmission infrastructure strengthening in Northern province. (ii) Component 2: Transmission and Distribution Network Efficiency Improvement,

which included construction of a new 220 kV New Polpitiya to Pannipitiya transmission line (69.2 km) and rehabilitation of the 132 kV Athurugiriya to Kolonnawa line (15 km), to enhance power supplies to Greater Colombo.

(iii) Component 3: A solar rooftop power generation pilot. (iv) Component 4: Advisory and capacity building support for wind and solar power

development.

7. The project was scheduled to finish in June 2017 but was extended to June 2019, due mainly to delays in completing the New Polpitiya to Pannipitiya transmission line. MOP was the executing agency. CEB was the implementing agency for components 1 and 2, with the Sri Lanka Sustainable Energy Authority (SLSEA) responsible for component 3 (Appendix 6) and component 4 implemented by a technical assistance team (Appendix 7).5

8. The complaints and grievances discussed in this report revolved around the New Polpitiya – Pannipitiya 220 kV transmission line constructed under component 2. This line consisted of two sections, (i) New Polpitiya – Padukka, and (ii) Padukka - Pannipitiya. The disputed section of the line, over which the complaints were raised, was a 6 km length of the Padukka – Pannipitiya section of the line.

9. The construction of the transmission line was considered high priority by CEB, to strengthen the transmission network in the country. The reason is that one of the country’s two major hydropower generating complexes 6, the Laxapana complex, with an installed capacity of 350 megawatt (MW), is currently connected to the national transmission network at 132 kV. The construction of the New Polpitiya – Pannipitiya 220 kV transmission line would have enabled connection of the Laxapana complex at 220 kV. This would have provided not only stability to the transmission network but also an enhancement of the network efficiency (footnote 5).

History of the Complaint

10. The CEB, as part of its statutory requirements, had sought environmental approval from CEA for the construction of the New Polpitiya – Pannipitiya transmission line. Accordingly, an Initial Environmental Examination (IEE) was conducted, and its report was submitted to the technical committee headed by CEA in December 2013. During an inspection of the proposed route by members of the technical committee, residents of Niyandagala village in the Homagama area raised objections and complained to CEB, PUCSL, the Divisional Secretary of Homagama, the Minister of Power and the President of Sri Lanka.

11. The transmission line was intended to pass through a 4.5 km densely populated stretch via Niyandagala village. The complaints revolved around several potential risks and threats perceived by the residents, such as (i) the loss or damages to their residential and other structures, (ii) loss of land, (iii) land devaluation, (iv) disruptions to livelihoods, and (v) health and safety risks.

12. The Divisional Secretary of Homagama presented the residents’ objections to the Homagama Divisional Coordinating Committee (DCC)7, held in March 2014, for a review and

5 Status Report on Office of the Special Project Facilitator Eligible Public Complaint, L2892/L2893/G0303 – Sri: Clean

Energy and Network Efficiency Improvement Project, Construction of New Polpitiya-Pannipitiya 220 kV Transmission Line” (undated) Sri Lanka Resident Mission, Colombo

6 The second complex is the Mahaweli Complex, with an installed capacity of 810 MW, which is connected to the national transmission network at 220 kV.

7 A Divisional Coordinating Committee at divisional level is the principal committee responsible for coordination and supervision of all development projects implemented within its respective area.

Appendix 4 33

discussion. The DCC discussed the issues at several sessions and consulted the CEA. Finally, the DCC recommended that the transmission line should be re-routed to avoid any adverse impacts on people and their properties, even if it meant additional costs.8 Meanwhile, the complainants also proposed an alternative route to avoid or minimize the perceived threats and damages.

13. In response to the recommendation by DCC, CEB reviewed all the possible options available for an alternative route and identified the route via Magammana village as one of the routes that had minimal social, economic, and environmental impacts. Following their assessment, CEB arranged a joint inspection visit to the alternative routes including the Magammana route, accompanied by the Assistant Divisional Secretary (ADS) of Homagama and the Grama Niladharis (GN) of the respective area.9 At the end of the inspection visit, all three parties (CEB, ADS and the GNs) considered the Magammana route as the most feasible and posing the least impact. However, the Magammana route was 1.52 km longer than the previous Niayndagala route, and the extra construction cost was estimated to be SLRs30.3 million. Accordingly, in December 2014 CEB revised its IEE report, with the new route via Magammana, and submitted it to CEA for environmental clearance. This revised IEE report received clearance from CEA in April 2015.

14. Subsequently, the Divisional Secretary of Homagama granted conditional clearance for the new Magammana line route. This was in accordance with the powers vested in the Divisional Secretaries by the Sri Lanka Electricity Act (Amendment) No.31 of 2013 [Section 3 (b)], to authorize or prohibit installation of electricity lines on, over or under any land, inquire into the grievances reported by affected parties, resolve such grievances, and to determine compensation for the affected parties as stipulated in items 3, 4, 5 and 6 of Schedule 1 of Sri Lanka Electricity Act No.20 of 2009. In granting his approval, one of the conditions laid down by the Divisional Secretary was that the transmission conductors should not be installed over or close to residential structures that are located within 17.5 meter (m) either side from the center of the transmission line route.10 To fully avoid all built structures was a difficult challenge for CEB to comply with, although they had planned to take the line over paddy fields wherever possible. Additionally, the route could not be confined to only paddy fields; inevitably it would need go over upland areas for limited distances (especially in stretches between two paddy fields). In such situations, it was not possible to avoid the line traversing houses or going close to them, especially in an urban area like Homagama, where the population density is comparatively high. In April 2015, this difficulty of CEB complying with the conditions stipulated was communicated to the Divisional Secretary by the CEA.11

Protests and Complaints

15. During May and June 2015, CEB arranged to issue the ‘D Notices’ to the households that potentially were to be affected by the new transmission line. A ‘D Notice’ seeks the permission of the affected parties for wayleave clearance in terms of entry to the land for inspections and land surveying, removal of trees, installation of towers and conductors, and repair and maintenance work. During the handing over of the D Notice by CEB’s electrical/civil superintendents, households were informed about the proposed transmission line project, its potential impacts, and the clearance requirements of trees located within the right of way (RoW) of the transmission

8 Letter from the Project Manager/CE&NEIP to Project Officer, ADB dated 23rd December 2016. 9 Grama Niladharis are the administrative heads of the smallest administrative unit at village level designated as

Grama Niladhari Divisions. 10 ‘Right of Way’ represents a 35 m corridor, 17.5 m each side of the center line. 11 Letter from the Director (Environmental Impact Assessment), Environmental Management and Appraisal Division,

Central Environment Authority to Divisional Secretary Homagama, 16 April 2015.

34 Appendix 4

line.12 If there was no objection from those who received the D Notice for wayleave clearance, they should notify the project manager of CEB within 21 days of receiving the Notice. On the contrary, if people had any objections to wayleave clearance or else had any alternate suggestions/proposals, they were required to make their submissions to the Divisional Secretary with a copy to the project manager.

16. During the issue of the D Notices, some households raised objections and totally refused to accept the Notices, whereas others accepted it and wanted to respond later. A few others accepted the Notices and signed for their consent (footnote 13). Despite the environmental clearance granted by CEA for the Magammana route, complainants continued to protest against the line route and in May 2015 registered their initial complaints with the PMU of CEB, and the Divisional Secretary of Homagama.13 Besides, they also proposed alternative routes that they thought would avoid adverse impacts on people’s houses and land. 17. At this time, the complainants, in order to consolidate and strengthen their positions, organized themselves into a formal community-based organization (CBO), entitled Magammana harha salasum kala adibala viduli rahanin peedawata patwannange sangamaya (People affected by high voltage power line planned through Magammana). Apart from the complaints submitted to PMU and the Divisional Secretary of Homagama, a substantial number of complaints, written by the complainants or their representatives either collectively or individually on the same issue, had reached several other institutions and persons seeking their intervention to resolve the issue. These included PUCSL, General Manager of CEB, Secretary of MOP, Minister of Power, Leader of the Opposition of the Western Provincial Council.

Complaint to the Divisional Secretary of Homagama and Project Management Unit of Ceylon Electricity Board

18. The complaints to the Divisional Secretary of Homagama and the PMU of CEB included the following grievances:

(i) The line was planned to go through Niyandagala-Katuwana-Mawathagama route. Subsequently, CEB changed the line route, and decided to take the line via Magammana village.

(ii) The deviated section of the transmission line would affect more than 50 households and approximately 250 people in Magammana, who are living within a 50 m corridor to both sides from the center of the line.

(iii) The environmental clearance had not been obtained for the deviated section of the line route.

(iv) People do not want to live in fear under a high voltage line for the rest of their lives. (v) The line traverses narrow stretches of paddy fields and with several curves

(instead of a linear line) leading to an increase in the line length. The estimated length of the previous Niyandagala section was 4.5 km while the Magammana route is 6.0 km.

(vi) The presence of the Magammana water tank at a height of 12.8 m and with a capacity of storing 80,000 liters of water is located 25 m from the center of the line. The tank provides water for about 280 households. This had not been taken into account by CEB.

12 Field notes maintained by Electrical Superintendents during the period 8 May 2015 to 23 June 2016 and available at

PMU/CEB. 13 Complaints submitted on 1 June 2015, 5 June 2015 and 13 March 2016, 9 June 2016 and 13 June 2016 by different

affected parties.

Appendix 4 35

Complaint to ADB’s Sri Lanka Resident Mission

19. In November 2016, the CBO of the Magammana affected parties submitted a complaint to the resident mission, seeking its intervention to prevent any injustices and to secure the rights of people to live safely.

20. The complaint included the following issues.

(i) Objections to the line route, and the alternative routes to be considered were reported to the Divisional Secretary and the PMU since May 2015. They were completely disregarded, and the construction plans were being implemented against the consent of the people. There had been no response to the complaints reported.

(ii) Project would affect the lives, properties, houses and health and safety of the people. The proposed line via Magammana traverses narrow strips of paddy fields and will affect more than 45 households who own 10 perches of lands on average.

(iii) A protest campaign was held by Magammana people in June 2015, and alerted the political authority at the highest level. None of them listened to the complainants.

Recourse to Legal Action

21. The complainants also proceeded to take legal action against CEB, and filed court cases at the Court of Appeal (2017 -04-28) and the District Court (2017-07-23), claiming that CEB did not have the relevant local approvals for the transmission line to pass through Magammana village. In the District Court, the complainants obtained an ‘Enjoining Order’ against CEB to suspend the construction work of the transmission line in the disputed section (2017-07-24). CEB appealed the stay order at the supreme court and was granted interim relief to proceed with construction (2018-05-18).

22. In the Court of Appeal, the complainants sought the Court to issue ‘Writs of Certiorari,14 Prohibition and Mandamus’ to prohibit the construction of the transmission line through the Magammana area. In February 2018, the court of appeal dismissed the application. Thereafter, the complainants appealed to the Supreme Court against the judgment of the Court of Appeal (2018-05-15). This application was dismissed on 2020-02-12 allowing CEB to proceed with the construction of the transmission line.

Complaint to ADB’s Accountability Mechanism

23. ADB’s Accountability Mechanism comprises two separate entities. (i) The Office of the Special Project Facilitator (OSPF). The OSPF is for problem

solving. It assists people who are directly, materially, and adversely affected by problems caused by ADB assisted projects. It uses non-formal, flexible, and consensus-based approaches to solve problems.

(ii) The Compliance Review Panel (CRP). This is for compliance review, which investigates alleged non-compliance by ADB with its operational policies and procedures in any ADB assisted project in the course of the formulation, processing or implementation of the project that directly, materially and adversely affects the local people.15

14 An order of a superior court directing that a record of proceedings in a lower court be sent up for review. 15 ADB (2012) Accountability Mechanism, Manila, the Philippines

36 Appendix 4

24. In August 201716, eight complainants claiming to represent the members of the Magammana affected parties CBO submitted a complaint to the Complaint Reviewing Officer of ADB. The complainants also opted for the problem solving function of the Accountability Mechanism under the OSPF.

25. Apart from presenting their grievances described in the previous sections, the complainants added the following allegations.

(i) Due to pressures from a powerful politician in the area, CEB had decided to abandon their previous line route via Niyandagala, and opted for the Magammana route that traverses their houses.

(ii) CEB was trying to construct the line forcibly, and had entered their area in the night to construct the transmission towers, against which the people complained to the police, and thereafter, demonstrated a protest in front of the Homagama Divisional Secretariat in June 2015. This incident also triggered the people to resort to legal action, one with the District Court, and another with the Appeal Court.

(iii) The map inserted in the IEE report did not show the Magammana route, and the consultations with Magammana people were not reflected in the Sinhala version of the IEE report.

(iv) Residents of Magammana were unaware of the project until the ‘D Notice’ was issued to them in mid-2015. CEB did not share the project related information.

(v) The complainants reported the issues to the Divisional Secretary of Homagama, PMU and the political authority at the highest level but they did not yield any positive response.

(vi) CEB’s acts amount to gross violation of the country’s law and the human rights, and the policies of ADB.

(vii) Complainants had reported the issues to the resident mission in November 2016, and the resident mission officers met with the complainants and visited the site in April 2017. However, since then, there had been no satisfactory response from the resident mission.

26. The complainants anticipated the OSPF to (i) intervene to prevent any injustices and to secure their rights to live safely, (ii) initiate an inquiry, (iii) to bring pressure on CEB to revert to the Niyandagala route, and (iv) to stop all construction work that CEB had been carrying out using ADB funds without the consent of the people.

Interventions to Address the Complaints

Divisional Secretary, Homagama

27. Objections from the complainants continued to escalate, and the Divisional Secretary brought the issue to the notice of the Homagama DCC. However, the DCC avoided making any decision in view of the national importance of this project, and the vital need for improved power supply for the country’s development (footnote 9).

28. In March 2016, the Divisional Secretary of Homagama commenced holding inquiries into the objections raised by the complainants, sessions that continued until the end of the year. The inquiries were also attended by the staff of the CEB PMU. At these inquiries, both the Divisional Secretary and the PMU shared the project related information, and also responded to the issues raised by the complainants. The PMU informed the complainants that all possible alternative routes were considered, assessed and inspected prior to CEA’s approval and the route that had

16 Original complaint dated 4 August 2017 and additional documentation received on 2 September 2017 per the

requirements of Accountability Mechanism.

Appendix 4 37

the minimal impacts was selected in consultation with relevant parties. The clearing width of the RoW of the transmission line, and the requirements for the removal of tall trees were also explained. The Divisional Secretary of Homagama explained the role of the DSD in the project, and specifically in the compensation procedures for any losses and/or damages.17 However, objections from the complainants continued throughout these enquiry sessions.

29. Additionally, in March 2016, the Divisional Secretary conducted a joint field inspection of the alternative route proposed by complainants, together with the ADS of Homagama, the Grama Niladharis of the two GNDs, and the complainants. During the inspection, the following were observed: (i) transmission line would traverse two residential structures in Magammana West GND; (ii) the line would not traverse any residential structures in Magammana East GND; (iii) in the Magammana East GND, the line would traverse 300 m of upland while the rest would be paddy fields; and (iv) the alternative route proposed by the complainants would affect a proposed cricket stadium and several residential structures.18

30. In February 2017, the Divisional Secretary of Homagama once again granted his conditional clearance for the Magammana route, taking into consideration its minimum socioeconomic impacts, and the clearance already given by CEA.19 The conditions laid down by the Divisional Secretary required CEB to:

(i) Comply with the conditions laid down by CEA in granting approval for the IEE report in April 2015.

(ii) Assess the market value of all houses, buildings and land located within the RoW of the transmission line and pay either compensation or take steps to acquire them.

(iii) Pay compensation for people who expressed their consent to allow the transmission line to traverse their land, in accordance with the valuation of their affected properties.

(iv) Pay compensation at market rate for any land devaluation. (v) Pay compensation at market rates for land lost for transmission towers installed in

paddy fields, devaluation of paddy land due to transmission lines, and loss of livelihoods/agricultural activities during the construction period.

(vi) Raise the height of the transmission line when it traverses residential land and the community burial ground.

(vii) Comply with government valuation in the payment of compensation.

Project Management Unit, Ceylon Electricity Board

31. The PMU also took measures to address the complaints reported by the aggrieved parties. They requested the intervention of the Secretary of MOP to resolve the issue.

32. In May 2016, the Secretary convened a meeting with the Divisional Secretary of Homagama and the project officers to discuss the alternative route proposed by the complainants. At this meeting, it transpired that the route proposed by the complainants, via Diyagama/ Jambugasmulla village, was longer than that of the Magammana line. Moreover, its social and economic impacts were comparatively high, including an increase of the construction cost by another SLRs130.90 million. The Divisional Secretary of Homagama affirmed this assessment by CEB. Concluding the meeting, the Secretary of MOP observed that the Magammana route was the one with the least impact, and he therefore requested the Divisional Secretary to hold objection clearance meetings with the affected parties and make his final decision. The Secretary

17 Minutes of the objection clearance inquiries (conducted by the Divisional Secretary) and recorded by the PMU. 18 Minutes of the observations during joint inspection visit as recorded by PMU/CEB, 21 March 2016 19 Letter from the Divisional Secretary to the Project Manager/CE&NEIP, 2 February 2017

38 Appendix 4

also re-assured complainants that any compensation due for affected properties would be paid by CEB (footnote 9).

33. Since the construction of the line could not be further delayed, CEB arranged another discussion between the Deputy Minister of Power and the complainants and their representatives. This meeting was held at the Parliamentary Complex in July 2016. It was also attended by the Divisional Secretary of Homagama, the Additional Secretary of MOP and the CEB officers. At the meeting, the complainants claimed that CEB’s decision to change the line route from Niayndagala to Magammana had affected their lives and properties and wanted CEB to consider an alternative route that would minimize adverse impacts on the people. In response, the PMU explained the comparatively high impacts that would arise if they were to opt for the route proposed by the complainants. Having heard the complainants and the PMU, the Deputy Minister instructed the CEB to survey all the possible routes available and submit an assessment report to him. The Minister also observed that not all impacts could be avoided in this type of national project and advised that affected parties should be paid proper compensation for their losses. The complainants requested a suspension of construction work in the Magammana section until the dispute was resolved, with which CEB agreed.20

34. According to the instructions of the Deputy Minister, the PMU conducted a comprehensive review of the different line options, and in October 2016 presented its report to the Deputy Minister, the Divisional Secretary of Homagama and the other relevant officials. The report concluded that the Magammana route was the most feasible in terms of its comparative advantages of minimal social impacts, reduced line length and construction cost. Table A4 highlights the features of each line route, as cited in CEB’s report.21

35. In this report, CEB assured payment of compensation to affected parties for their land devaluation at market rates as determined by Divisional Secretary, the possibility of raising the height of the conductors to enable people to build their houses, and to design the transmission towers and lines to minimize the potential health and safety impacts in accordance with the standards prescribed by PUCSL.

Table A4: Comparative Assessment of the Line Route Options

Line route Length (km)

Affected houses under the conductor

Affected houses within RoW (17.5 m either side of

center)

Estimated construction cost

(SLRs.)

Approved Magammana route 6.01 2 [a] 5 184.9

Route via Jambugasmulla paddy field (proposed by affected parties)

9.94 1 4 315.8

Route via Niandagala 4.49 14 25 154.6

km = kilometer, RoW = right of way, SLRs = Sri Lana Rupees Note [a]: One of the two residential structures had been built after CEB’s notification of the planned transmission line to the residents. Source: Status report from CEB to Sri Lanka Resident Mission on 23.12.2016

36. The PMU commenced public awareness programs in May 2015, as required under the Electricity Act. The first program (June 2015), held near the public burial ground in Magammana, was attended by the ADS of Homagama, Grama Niladharis of Magammana East and West

20 Minutes of the meeting held with the Deputy Minister of Power and Energy on 21 July 2016 and recorded by

PMU/CEB. 21 Report on the comparative assessment of the approved line route and the alternative line routes conducted on 21

August 2016.

Appendix 4 39

divisions and the officers of the PMU. At this meeting, CEB shared the information on the proposed route, and responded to the issues raised by the villagers. During this awareness raising program, some factions of the villagers raised objections to the transmission line, holding placards.

37. Another consultation meeting was held at the PMU office in February 2016 with a group of representatives of the Magammana complainants. At this meeting, the PMU delivered a presentation that described the project’s objectives and scope, implementation procedures, technical details of the transmission line and towers, proposed line route, potential impacts, land requirements and land utilization for the project. The complainants from Magammana suggested considering alternative routes or underground cabling to minimize adverse impacts on their properties, residential structures and their personal lives. They proposed two alternative routes. The PMU informed the participants that the final route via Magammana was approved by a committee of experts appointed by CEA, following an assessment of the relative social and environmental impacts, as well as the technical feasibility of the different routes.

38. In July 2017, the PMU conducted a third awareness raising program at its headquarters for the representatives of the complainants. This program was organized in order to comply with an interim order issued by the Court of Appeal in June 2017, directing the CEB to take steps to raise awareness among the complainants on the approved route. On this program, the PMU explained the environmental clearance received from CEA in April 2015 for the approved line, the Initial environmental examination report approved by CEA, and the conditions stipulated in CEA’s approval.

Sri Lanka Resident Mission

39. In response to the complaint, the resident mission officers began to gather additional information on the issue from both the PMU and the Divisional Secretary, including a visit to the Divisional Secretariat in March 2017. The resident mission officers also maintained regular telephone communication with the representatives, to ensure that the complainants or their representatives were kept informed of the actions taken by the resident mission on their complaint. Moreover, in early April 2017, the resident mission officers met with the complainants to discuss the contents of their complaint. They also walked along the line route. Following this meeting, the resident mission further reviewed the relevant approvals, and the social, technical and financial information on the approved and the alternative line routes. After careful consideration of all available information and meeting with the complainants, the resident mission considered CEB’s assessment of the Magammana route as the most feasible route in terms of social and financial considerations was correct. In mid-April 2017, the resident mission communicated its observations to a representative of the complainants.22

40. Despite the above observations, the resident mission (and South Asia Department) also held several rounds of discussions with the CEB’s project manager to explore the alternative options. At these meetings, the project manager suggested that if a deviation from the approved line route was to be considered, the issue could be referred to the Official Committee on Economic Management (OCEM) of the Ministry of Finance, chaired by the senior advisor to the Prime Minister. CEB informed that they were willing to consider any technically feasible deviation, subject to direction and approval of higher authorities. The resident mission followed this up with officials at the Ministry of Finance and requested them to discuss the issue at the OCEM. Accordingly, the project was tabled for the OCEM meeting scheduled for July 2017. However, no decision could be made at the OCEM meeting because two court cases filed by the Magammana

22 Complaint Log Sheet- L2892/L2893 Complaint on Polpitiya-Pannipitiya 220 kV Transmission Line, Magammana

(Homagama Divisional Secretary) Social Issue.

40 Appendix 4

affected parties were still pending: (i) at the District Court, and (ii) at the Appeal Court. The OECM did not wish to make a decision that could conflict with those of the courts.

41. Meanwhile, South Asia Department received an assurance from CEB that they would not commence any construction work on the disputed section of the transmission line, and, as advised by their legal department, nor would they undertake any alternative assessments until the court cases were concluded. If the courts decided to direct CEB to find an alternative route, SARD agreed to ensure that CEB would engage in fresh consultations and the required impact assessments, and update the IEE report and the Resettlement Plan in compliance with ADB’s safeguards policies. Additionally, the resident mission recruited two consultants in December 2017 to assist CEB to conduct the necessary social and environmental assessments, and the preparation of safeguards documents as soon as the final judgment was delivered. In the event of courts deciding to move ahead with the approved Magammana route, the resident mission also agreed to ensure that (i) impacts on people’s livelihoods and health and safety would be minimized through consultations and engineering solutions, (ii) all livelihood and other impacts which could not be avoided, and would likely be temporary during construction and operation would be addressed through appropriate mitigation measures consistent with the safeguards policies of the bank, and (iii) adequate compensation would be paid to affected parties prior to the commencement of construction work and any form of displacement.

42. Subsequently, following the involvement of OSPF, the resident mission’s direct involvement with the affected parties ceased. OSPF accepted the complaint as eligible for consideration via ADB’s accountability mechanism. The complainants also requested OSPF not to engage the resident mission staff, whom they considered were biased towards CEB and from whom they had no confidence of an impartial decision. The resident mission staff involvement thereafter was only to coordinate OSPF engagement, to provide necessary technical information and to facilitate discussions with government agencies.

43. At loan closure with OSPF not having a continuing role, ADB recommended CEB to conduct an independent analysis of the alternative routes, disclose the results of the assessment to stakeholders and based on the final route selection, follow the government procedure to propose compensation.

44. In July 2019, (pending court decision) with the help of consultants which had been recruited, the resident mission conducted an independent desk study of the alternative routes, covering, technical, financial, social and environment aspects. The alternatives were ranked, based on multi-criteria analysis, and showed the Magammana route to be the most appropriate.

Office of the Special Project Facilitator

45. Having received the complaint, the OSPF obtained a status report from the project officer of the resident mission in respect of each issue raised by the complainants.23 Additionally, after a review of other relevant documentation, in September 2017 OSPF informed the President of ADB that the complaint had met all the eligibility criteria for the problem-solving process. Moreover, the OSPF remarked that the consultation process may not have been adequate and completed in a timely manner. OSPF also informed the President that it would conduct a detailed review and assessment in the field, followed by a dialog with complainants, ADB and the government to come up with workable solutions that everyone could accept, to resolve the complaint.24

23 Email letter from ADB’s Project Officer to OSPF on 12 September 2017 on the subject of Requesting Information –

Complaint on Loans Nos.2892-3, Grant No.0303 and TA No.8167 SRI: Clean Energy and Network Efficiency Improvement Project – Eligibility of Complaint

24 Memorandum from OSPF to the ADB’s President on 13 September 2017 on the subject of Complaint on Loans Nos.2892-3, Grant No.0303 and TA No.8167 SRI: Clean Energy and Network Efficiency Improvement Project

Appendix 4 41

46. OSPF fielded several missions and agreed with both parties (CEB and the complainants) to undertake an independent alternative assessment managed by ADB for all possible routes. On the instructions of OSPF, CEB reaffirmed the suspension of construction in the disputed section until an agreement was reached. OSPF, with the help of the resident mission, recruited consultants to carry out an independent analysis, and developed a detailed plan for assessment of alternatives and a consultative strategy. The misinterpretation was that ADB had decided to conduct a detailed assessment because CEB’s prior assessment had not been done properly. This action by the complainants agitated CEB management, and they advised OSPF that, CEB would support the alternative assessment only if OSPF confirmed that undertaking such an assessment would not undermine CEB’s position in courts. While OSPF could not reach any agreement with the complainants, CEB, as advised by their legal department, would not support the alternative assessment until the court cases were heard and closed. As both parties were still in the problem-solving mechanism, OSPF remained in the case without any immediate resolution.

47. In July 2019, OSPF informed the Chairperson of the Magammana affected parties’ CBO that OSPF would close the case as it did not progress in ‘facilitated resolution’, nor did it see a continuing role for OSPF in view of the following reasons25:

(i) Supreme Court decision had been delayed at the request of the complainants’ legal counsel.

(ii) CEB was not willing to proceed with the agreed process for evaluating alternatives without the closure of the pending court cases.

(iii) Magammana community was not agreeable to a facilitated discussion with CEB as recommended by OSPF, until the evaluation of alternatives was completed.

(iv) ADB’s loan for this project was closed on 30th June 2019, and ADB would not be financing the portions of the transmission line that had not been completed by the end June. The OSPF also stated that ADB South Asia Department would encourage CEB to follow the proposed process of evaluating the social and environmental issues as well as technical and financial aspects of alternative alignments before making a final decision on the alignment.

The Judiciary

District Court

48. Following the enjoining order obtained by the Magammana affected parties in the District Court, they further proceeded to obtain an injunction order from the same court to suspend the construction work of the transmission line. At this juncture, CEB raised objections against the Court issuing an injunction order, and moreover, questioned the jurisdiction of the District Court to question the decisions of the Attorney General of the Republic of Sri Lanka and of a government official (namely the Divisional Secretary), who were listed as 2nd and 3rd defendants of the case. CEB also pointed to the pending case filed by affected parties at the Court of Appeal. In view of the latter, the District Court suspended their hearings of the case.

Court of Appeal

49. The Court of Appeal, which heard the case, delivered the following judgment in February 2018. “Although it is the submission of the learned Counsel for the Petitioner that the respondents have taken a path other than the approved path, there is no evidence for such a proposition. Petitioner has not been able to satisfy this Court that the respondents have taken steps to

25 Email letter from the Special Project Facilitator to Magammana Api on 3 July 2019 on the subject of Complaint on

Loans Nos.2892-3, Grant No.0303 and TA No.8167 SRI: Clean Energy and Network Efficiency Improvement Project – Eligibility of Complaint – OSPF’s Review and Assessment Mission, 23-30 October 2017

42 Appendix 4

construct this proposed electricity line on a path other than the approved path” (Judgment of the Court of Appeal, 27.2.2018).

Supreme Court

50. Dissatisfied by the judgment of the Court of Appeal, the affected parties contested the judgment of the Appeal Court in the Supreme Court. After a number of postponements of the case at the request of the legal counsel who appeared for the affected parties, the Supreme Court finally rejected the application by the affected parties and confirmed the decision of the Appeal Court.

Conclusion

51. It is a common practice for people affected by development projects to seek redress for their grievances through multiple institutions. The case of Magammana is a good example of how people who were likely to be affected by a transmission line approached a large number of institutions and persons to seek redress for their grievances. 52. As project implementing agency, the CEB had shared information with the public on the proposed RoW for this transmission line and objection clearing inquiries had been conducted in line with the grievance redress mechanism and country law (e.g., inquiry arranged by the DSD of Homagama in December 2016). 53. However, the complaints in Magammana village alleged that they were not consulted adequately and rejected any compensation offered by the project. Their main concern was to avoid the transmission line passing over their village. Though the resident mission tried to perform an independent intermediary role between the complainants and the implementing agency to reach a settlement acceptable to both parties, their attempts did not materialize, mainly because of the staunch position maintained by the complainants. At some point, the complainants were suspicious of the role of the resident mission officers, and alleged that they allied with CEB and supported their decisions. 54. The experiences of the ADB’s OSPF were no different from those of the local agencies. The final outcome of the intervention by the OSPF did not meet the expectations of the complainants, although OSPF did field several missions to reach a negotiated settlement. The OSPF was, however, unable to make a breakthrough for a facilitated resolution, mainly because of the inflexible positions maintained by the complainants on one hand, and the restraints on the CEB to make decisions due to the pending Supreme Court decision on the other hand. In the process, the project reached the termination date of 30 June and the ADB loans were closed. Finally, the OSPF decided to close the case, and to withdraw from the problem-solving process. 55. Development projects of national significance cannot totally avoid adverse impacts on affected communities, despite measures that they would take to avoid or minimize such impacts wherever possible. The lessons learnt through this lengthy and stressful process are the need for ensuring adequate and meaningful consultations with the affected parties and sharing project related information from the very inception of a development project. In this setting, ADB realized the need for capacity building in CEB for efficient and effective safeguards (social and environmental) management in their projects and devised a framework for the establishment and mainstreaming of a safeguard unit within CEB.

Appendix 4 43

56. Further, following to be considered on future projects. (i) Right of Way (wayleave) should be fully secured prior to contract award in order to avoid construction delays, (ii) burial of short segments on transmission lines in order to avoid installation over residential and commercial structures, and (iii) transmission planning to include upgrading of existing lines with advanced conductors to increase network capacity and efficiency, which may result in avoiding or postponing new high voltage lines.

44 Appendix 5

ROOFTOP SOLAR POWER GENERATION PILOT

Introduction

1. The Solar Rooftop Power Generation Pilot formed component 3 of the project. The Sri Lankan Sustainable Energy Authority (SLSEA), an agency of the Ministry of Power (MOP), was the implementing agency.

2. The pilot program was designed under the project preparation technical assistance (PPTA)1, and incorporated into the report and recommendation of the President (RRP).2 The component was intended to develop a pilot program for solar rooftop generation systems and to install 1.0 megawatt (MW) of grid-connected capacity on a net metering basis. Two subcomponents were envisaged: (i) installations on public sector buildings and (ii) on private sector enterprises. The total budget was $3.0 million, comprising:

(i) $1.5 million under Loan L28923 as a credit line to private developers (ii) $1.5 million under Grant G03034, for financing public sector installations, a capital

grant subsidy to private sector projects, and consulting services. 3. The pilot consisted of (i) design, supply and installation of solar photovoltaic (PV) power generation plants at four key universities under Grant G0303, (ii) a credit line under Loan 2892 for private sector solar rooftop development, administered by a participating finance institution (PFI), (iii) a capital subsidy for private sector solar rooftop development under Grant G0303, and (iv) national consultancy services for project management support, under Grant G0303.

4. The PPTA foresaw the pilot project serving as a benchmark for future replication and to address the following barriers for developing solar power in Sri Lanka:

(i) Reducing the high capital cost through a bidding framework. (ii) Encourage private sector participation to create an ecosystem for self-replication. (iii) Contribute to an increase in renewable power generation. (iv) Overcome any policy and regulatory barriers during the implementation.

5. The component commenced in late 2013, headed by the Project Director, at SLSEA headquarters in Colombo. A consultant Solar Specialist was identified through the Asian Development Bank’s (ADB) consultant management services and recruited for a contract of 24 person months, according the ADB’s Guidelines on the Use of Consultants.

6. The component was successfully completed in December 2017 (Figure A5.1)

7. Information contained in this appendix derives from the SLSEA’s borrower’s completion report5, discussions with former PMU members and the former consultant solar specialist.

1 ADB. 2011. Technical Assistance to Sri Lanka: Clean Energy & Network Efficiency Improvement. Manila. 2 ADB. 2012. Report and Recommendation of the President to the Board of Directors: Proposed Loans, Technical

Assistance Grant and Administration of Grant, Democratic Socialist Republic of Sri Lanka: Clean Energy and Network Efficiency Improvement Project. Manila.

3 ADB. 2012, Clean Energy and network Efficiency Improvement Project. Manila. Financed by Ordinary Capital Resources.

4 Financed by the Clean Energy Fund 5 Sri Lanka Sustainable Energy Authority. 2020. Project Completion Report Loan Nos 2892/2893 and Grant No 0303,

Clean Energy & Network Efficiency Improvement Project, Solar Rooftop Power Generation Pilot. Colombo, Sri Lanka

Appendix 5 45

Figure A5.1: Actual Implementation Schedule: Solar Rooftop Power Generation Pilot

University Subcomponent

8. The design envisaged establishing a total of 200 kilowatt-peak (kWp6) solar rooftop PV systems at the key universities of Peradeniya, Jaffna (Kilinochchi campus), Moratuwa and Ruhuna. The PMU circulated the universities, requesting proposals for establishing PV systems. The proposals from Peradeniya and Jaffna were most imaginative, including plans to incorporate solar rooftop technology into undergraduate curricula and as a basis for postgraduate research. Each of these universities were granted 60 kilowatt (kW) systems, Moratuwa and Ruhuna were each allocated 40 kW systems.

9. Systems were installed and grid-connected, with support from the PMU and technical staff of SLSEA. They were fully funded out of the G0303 grant. The total expenditure was approximately $285,000, representing about $1,425/kW installed.

10. All the systems are operational, with a total capacity of 200 kWp. They have been incorporated into the curricula, training and research activities of Peradeniya and Jaffna, aided by a working group set up with SLSEA staff.

Private Sector Subcomponent

Preparation

11. An objective of the subcomponent was to develop an approach that would encourage private sector enterprises, such as hotels, warehouses, small industries, and commercial entities, to install PV systems, as a means for generating clean power. It also aimed to demonstrate the benefits of solar generation to the wider community, to encourage future expansion of solar power generation. The approach was based on a public private partnership, with private enterprise sharing the capital costs, supplemented by loans financed by a credit line under the project Loan 2892.

6 kWp = kilo watt peak, power produced at peak time. kWh = kilo watts per hour generation.

46 Appendix 5

12. Net metering was to be applied.7 However, the design appreciated that, given the tariff rates for private enterprises, there would be a gap between the applicable tariff rates and the cost per unit of solar power generated. Consequently, to incentivize private sector participants, a grant subsidy towards capital costs was provided, based on the validated kilowatt-hour (kWh) performance. SLSEA prepared and maintained a database of solar PV installation service providers.

13. Training was provided for the private sector solar PV technicians and planning engineers attached to Ceylon Electricity Board (CEB) for technical aspects of solar rooftop installation and awareness raising. A course was arranged by the PMU, out of SLSEA funds, and provided by an Australian company, ‘GSES’.8

14. Suitable PFI were sought. Sampath Bank, which was the only institution that fully met requirements, was contracted in October 2015 through the Treasury. The credit line for private sector investment was established and, according to the agreement, Sampath Bank could release loan components until the loan closing date in June 2019. The PMU completed all loan disbursements by the end of 2017. The loans were satisfactorily administered by the bank.

2. Evaluation and Selection of Bidders

15. The PMU developed guidance for competitive tendering by private enterprises. Tenders were invited and evaluated. Bids by shortlisted applicants were vetted by SLSEA teams, involving a series of three inspection visits to each applicant to ensure quality and compliance, before authorizing the payment of loans through the PFI and granting capital subsidies. Rigorous evaluation and monitoring criteria were adopted. Box A5 details the sequence of activities.

16. Bids were received from more than 100 private sector entities. These were evaluated and shortlisted to 28 applicants. A total of 22 enterprises eventually qualified for support (Table A5.1). Their installations were completed and commissioned by end of 2017.

17. The completed installations comprised a total capacity of 1.79 megawatt-peak (MWp), achieving an annual generation of 2.31 megawatt-hour (MWh) during 2018 (Table A5.2). Total expenditure was approximately $1.71 million, or $954 per kW installed. Some hotels installed more capacity, at their own expense, to boost their environmental (green) credentials.

3. Overall Impacts

18. Table A5.2 shows projected and actual outputs. The total grid-connected capacity, including that of the university subcomponent (200 kWp) was therefore 1.99 MWp, and annual power generation of 2.6 gigawatt-hour (GWh), compared to 1.0 MWp and 1.7 GWh at inception, respectively.9

19. Annual carbon dioxide (CO2) emissions avoided were estimated at 2,126 tons in 2018, as compared with 1.286 envisaged at the project inception.

20. Cost savings enabled installation of the extra generating capacity (and consequent greater savings in CO2 emissions. These were possible due to lower prices since appraisal, careful tendering by SLSEA and by adopting competitive bidding by the private sector, whereby loan recipients contributed their own capital. The capital expenditure by the project, per kW installed, was thereby reduced to a mean cost of $954, compared with the PPTA estimate of $2,900.

7 The value of power generated by the PV systems was deducted from the owner’s electricity bills at the grid-supply

tariff that applied. 8 SEA was not aware of any direct training or support provided by TA 8167 consultants, as envisaged in the design

and monitoring framework (DMF) component 4. 9 The design target generation figure was 34.43 GWh over the expected 20-year lifetime of an installation.

Appendix 5 47

Table A5.1: Private Enterprise Installation Capacity and Power Generation, 2018

No Company Location Installed

kWp Expected kWh Actual kWh

C/1 Ark Printing Solutions Jaffna NP 21 29,528 29,954

C/3 Dishan Valley Tea Factory Morawaka SP 100 125.642 127,299

C/4 Brandix Apparel Solutions Koggala SP 100 142.997 140,570

C/5 Miami Clothing Pvt Ltd Pitigala SP 100 124,021 116,940

C/27 Sumanagiri Lanka Ltd Bentota SP 50 66.036 61,020

C/6 Lighthouse Pvt Ltd Galle SP 100 136,835 148,450

C/8 T5 Escapes Pvt Ltd Tangalle SP 13 16,322 13,901

C/9 MAS Intimates Pvt Ltd Kandy CP 100 142,997 144,740

C/10 SG Joseph & Brothers Panwilatenna CP 100 118,304 111,984

C/27 Elpitiya Plantation Pvt Ltd Pussellawa CP 80 99,907 93,190

C/13 Mount Elisa Estate MataleCP 100 119,404 111,927

C/28 Sierra Cables PLC Kaduwela WP 100 130,114 120,139

C/18 City Hotels Pvt Ltd Colombo WP 21 26,476 27,010

C/19 Meezan& Co Pvt Ltd Welampitiya WP 33 40,039 36,317

C/31 Hotel Janaki Colombo WP 100 140,607 140,008

C/21 MJF Teas Pvt Ltd Peliyagoda WP 100 136,006 140,363

C/33 Central Rubber Pvt Ltd Biyagama WP 100 127,731 124,780

C/34 Commercial Export Co Wattala WP 93 119,921 111,762

C/23 Asiabike Industrial Ltd Panadura WP 100 147,600 150,990

C/24 Aitken Spence Hotel Mgt Kalutara WP 80 99,511 94,860

C/6 EB Creasy & Co PLC Millewa WP 100 130,605 129,964

C/37 Country Style Foods Ltd Kadawatha CP 100 133,183 136,537

Total 1,791 2,019,446 2,312,705 CP= Central Province, kWh = kilo watt hour, kWp = kilo watt peak, NP = Northern province, SP = Southern province, WP = Western province. Source: Sustainable Energy Authority (SLSEA).

Table A5.2: Solar Rooftop Power Outputs, Projected and Actual

Universities Private Sector Total

Installed Capacity (MWp) Projected 0.2 0.8 1.0 2018 Actual 0.2 1.8 2.0

Energy Generated (GWh) Projected 0.3 1.4 1.7 2018 Actual 0.3 2.3 2.6

CO2 Reduction (tonne/year) Projected 1.286 2018 Actual 2,126

CO2 = carbon dioxide, GWh = gigawatt-hour, MWp = megawatt-peak

Source: DMF (Appendix 1), PPTA report (2012) and SLSEA (Table A5.1).

48 Appendix 5

Box A5: Sequence of Selecting and Approving Private Enterprise Applicants

Invitations. The private enterprise program was advertised in the press, with guidelines for applicants, who were required to submit bids containing a technical and financial feasibility study, details of their service provider and the size of installation proposed kilowatt. Bids were to include a statement of the equity stake offered by the applicant (up to 30%, with the balance as a loan) and the amount of capital grant subsidy expected (percentage of total installation cost).

Evaluation. Sri Lanka Sustainable Authority (SLSEA) received just over 100 applications. These were evaluated and ranked according to technical and financial criteria. Bids were checked to ensure that proposed production capacities were in line with the technical specifications, not exaggerated.

Ranking. The ranking favored applicants who were prepared to invest the full equity element, and who expected the lowest capital subsidy proportion. Quotas were applied to ensure a wide geographical spread to enhance the promotional and demonstration effect of the pilot. The rankings also considered the business category (hotel, industrial enterprise, tea estate, etc.) to ensure a spread of business types. A total of 28 private sector enterprises were shortlisted.

Participating Financial Institution Evaluation. The participating financial institution (PFI) evaluated the shortlisted companies, from the list provided by the project management unit (PMU), to check their financial strengths to handle the loan component. This was done early in the process to ensure prompt release of funds to the selected enterprises on final approval.

Inspection 1. The SLSEA team made inspection visits to each applicant to verify their bid, to check the suitability of the location (eg: not shaded by trees) and the quality of the roof structure for installing photovoltaic (PV) panels.a These initial inspections confirmed the suitability of 22 of the shortlisted applicants. Details were forwarded to Asian Development Bank for approval and then passed to the PFI to record the loan amounts expected.

Procurement. The selected enterprises were then authorized to order equipment through their service providers, who were required to import the equipment from approved sources, acceptable to SLSEA.

Inspection 2. The PMU team made a second inspection visit when the applicant had set up the mounting structures (before PV panels had been installed). If suitably constructed, the applicant was authorized to proceed with final installation.

Inspection 3. The PMU made a third visit to commission the PV panels. If the installation complied with standards and performance levels, loans were then approved on the basis of measured performance levels (to avoid lending for any unserviceable panels).

Loan Approval. The PMU advised the PFI to extend loans to the qualifying applicants, repayable over 7 years at soft rates of interest. The 7-year period was used, given the expected 10-year average lifetime of the inverters.

Capital Subsidy. The capital subsidy element was then released to each approved applicant, at the rate stated in their original proposal, per kilowatt-hour produced.

a Later, a ‘roof quality report’ was included in bidding guidelines.

Source: Sri Lanka Sustainable Energy Authority (SLSEA) consultant

Appendix 5 49

Hambantota Testing Facility

21. In 2018, The PMU and SLSEA proposed the setting up of a Solar Research and Development Center at the Hambantota solar park for testing of solar panels and inverters, using project loan savings of about $0.6 million from the grant and $0.7 million from the loan component.

22. The additional scope of work was approved by ADB under a minor change of scope.10

However, the center could not be fully implemented because, in February 2019 ADB suspended contract awards and disbursements due to noncompliance by SLSEA in submitting audited project financial statements for 2017.11

23. Subsequently, little progress has been made in establishing the center.

Examples of solar PV arrays installed on private enterprise roofs, and inverter system. (photos by

Madhurika Palatuwa, Sustainable Energy Authority - SLSEA)

Impacts of the Solar Rooftop Pilot

24. The testing and commissioning methods developed, using technical equipment imported under the pilot, were applied to future installations.

25. The pilot was instrumental in popularizing rooftop solar power by raising awareness among different categories of private enterprises and defining standards.

10 ADB. 2018. CENEIP, request for minor change of scope and reallocation of loan and grant proceeds 2 March 2018.

Colombo. 11 ADB. 2019. CENEIP Aide Memoire of review mission 5-12 February 2019. Colombo.

50 Appendix 5

26. The pilot demonstrated that simple solar rooftop systems could be expanded with discipline, incorporating the high standards developed by the project.

27. The pilot contributed to the government’s long term expansion plans for solar rooftop power generation and ADB’s further involvement.

Future Development of Rooftop Solar Generation

28. The pilot contributed directly and indirectly to several subsequent developments in solar rooftop power generation expansion.

29. SLSEA’s technical team had expanded and now includes 50% female staff.

30. Ministry of Power established a technical evaluation committee with members of CEB, SLSEA and the Lanka Electricity Company to develop national guidelines for solar installations. Recommendations were made on the adoption of a feed-in tariff system for solar installations, which were successfully applied in future projects.

31. Key recommendation of the technical evaluation committee suggests that local manufacturers should be involved in provision of mounting and cabling elements of new solar PV installations.

32. The approach developed under the pilot program was adopted by government for scaling up under the ‘Soriya Bala Sangramaya’ (‘Battle for Solar Energy’) program.12 This aims at 1,000 MW of rooftop solar capacity being installed by 2025 and is being managed by SLSEA.13

33. In 2017 the ADB provided a loan to fund a credit line to support a new rooftop power generation program.14

34. As of December 2019, Sri Lanka had a total of 312 MW of solar capacity installed: 261 MW from rooftops and 51 MW from ground-mounted systems. Some 23,000 rooftop installations have been achieved.

12 Ministry of Power and Renewable Energy. 2018. Battle for Solar Energy begins from President’s house. Colombo 13 Soorya Bala Sangramaya. 14 ADB. 2017. Rooftop Solar Power Generation Project L3571 2018-2021. Manila. This is a $50 million credit line facility

to develop 60 MW of rooftop PV installations. By end of 2020, over 3400 subprojects had been approved amounting to nearly 40 MW of total installations. The pilot project of CENEIP was useful in determining the tariff structure for the solar rooftop program in Sri Lanka.

Appendix 6 51

TECHNICAL ASSISTANCE COMPLETION REPORT

TA Number, Country, and Name: Amount Approved: $900,000

TA 8167-SRI: Capacity Building for Clean Power Development

Revised Amount: not applicable

Executing Agency

Source of Funding Amount Undisbursed Amount utilized

Ministry of Power and Energy

Technical Assistance Special Fund (TASF-IV)

$74,573.38 $825,426.62

TA Approval TA Signing Fielding first Consultants

TA Completion Date Date Date Original 31 Dec 2014 Actual 28 Jul 2015 18 Sep 2012 24 Oct 2012 May 2013 Account Closing Date

Original 31 Dec 2015 Actual 28 Jul 2015

Description

Asian Development Bank’s (ADB) Country Operations Business Plan (2012-2014) for Sri Lanka1 envisaged financing of a Clean Energy and Network Efficiency Improvement Project.2

Based on discussions and

consultation with the Government of Sri Lanka and project preparatory studies, an associated technical assistance (TA) had been processed to enhance an expected project impact. The TA supported key initiatives of the government, Ceylon Electricity Board (CEB) and Sustainable Energy Authority (SLSEA) of Sri Lanka in developing clean energy generation from renewable sources, primarily wind and solar, in a comprehensive and planned manner to complement renewable energy interventions of the project. The purpose of the TA was to (i) assist in conducting system stability and network planning studies for smooth integration of intermittent wind and solar power generation in the system, and (ii) support SLSEA in developing the wind and solar potential on a sustainable basis, including through attracting the private sector in power generation from the wind and solar resources.

Expected Impact, Outcome, and Outputs

The expected impact of the TA was increased sustainable, clean and reliable power supply. The anticipated outcome was increased clean energy generation and economic benefits from improved utilization of the renewable resources and better energy security through reduction of reliance on imported fuels. Specific outputs expected from the TA were divided into two parts: (i) Part A focused on system stability and network planning studies, and (ii) Part B concentrated on (a) preparation of country’s renewable energy master plan, (b) preparation of a master plan and a business model for a proposed wind park, and (c) capacity building for development of wind and solar power.

Delivery of Inputs and Conduct of Activities

Consultants were recruited according to the Guidelines on the Use of Consultants by ADB and its Borrowers. The original terms of reference (TORs) were adequately formulated to ensure achievement of the TA outputs. Total requirement for consulting services was 20 person-months for international consultants, and 22 person-months for national consultants. Two consulting firms were engaged to carry out specific tasks: (i) Nexant, USA in association with Siemens Industry, Inc. and Siemens Power Technologies International, USA for Part A: System Stability and Network Planning Studies, and (ii) Resource Management Associates (Private) Limited, Sri Lanka in association with Mercados Energy Markets India Private Limited, India for Part B: Preparation of Renewables Development and Wind Park Master Plans and Business Model for Wind Park. The consultants’ activities were carried out in close coordination with Ministry of Power (MOP),3

the executing

agency; as well as CEB and SLSEA, the implementing agencies.

Consultants performed their tasks in accordance with the TORs. Both TA parts were effectively and efficiently implemented by the consultants. CEB identified a need for additional analysis on system stability modeling results presented in a final report of the Part A consultants from the technical assessment of renewable energy scenarios perspective that have been accomplished by the Part B consulting team. Two individual consultants were engaged to cover specific identified gaps and prepare a draft Grid Code that takes into consideration

1 ADB. 2011. Country Operations Business Plan: Sri Lanka, 2012–2014. Manila. 2 ADB. 2012. Report and Recommendation of the President to the Board of Directors: Proposed Loans, Technical

Assistance Grant, and Administration of Grant to the Democratic Socialist Republic of Sri Lanka for the Clean Energy and Network Efficiency Improvement Project. Manila.

3 Currently Ministry of Power and Renewable Energy.

52 Appendix 6

integration of renewable generation under Part B.

TA completion date was extended from 31 December 2014 to 31 July 2015 to (i) accommodate improvement of reports concerning analyses of specific technical and operational issues, (ii) finalize the Renewable Energy Master Plan, and (iii) complete all payments under the TA.

The TA consultants effectively organized the TA activities delivering the targeted outputs. The Part A consultants’ overall performance was satisfactory, and the overall performance of the Part B consultants was highly satisfactory. MOP, the executing agency, and CEB and SLSEA, the implementing agencies, provided adequate office accommodation and counterpart support. Overall, the performance of the executing and implementing agencies was satisfactory.

ADB closely supervised the TA activities and outputs through regular communication with consultants, tripartite meetings and review missions, at times combined with other project and TA related missions to Sri Lanka, to asses TA progress and resolve implementation issues. ADB staff actively facilitated TA activities, monitored consultants' outputs and provided guidance in the preparation of TA reports. The overall performance of ADB was satisfactory.

Evaluation of Outputs and Achievement of Outcome

The TA outputs met the targets and were of a high quality to the satisfaction of the executing and implementing agencies. Under both Part A and Part B, the relevant consulting firms submitted inception, interim, draft final and final reports. For Part A the final report covered system stability modeling under different scenarios. The final report of the Part B consultants covered eight areas: (i) Part 1: Renewable Energy Master Plan; (ii) Part 2: Master Plan for Wind Power Development in Mannar District; (iii) Part 3: Commercial Arrangements and Bidding Documents for Wind Development in Mannar District; (iv) Part 4: Study of Impacts of the Mannar Power Development Zone; (v) Part 5: Analysis of Steady State and Dynamic Performance; (vi) Part 6: Power System Operations and Dispatch; (vii) Part 7: Financial and Economic Assessment of Renewable Energy Development; and (viii) Part 8: Sri Lanka Grid Code for Intermittent Resource-based Generation. Public-private partnership options for developing renewable energy were described as part of a potential business model and commercial arrangements in the relevant Part B report. The Part B consultants organized workshops for stakeholders to consult, build capacity and disseminate TA findings in February, March, July and September 2014 with a total number of 282 participants from the government, MOP, CEB, SLSEA, Public Utilities Commission of Sri Lanka and the private sector. For each workshop the consultants prepared discussion papers. These workshop activities were found both useful and relevant by participants. The above outputs effectively contributed to the expected TA outcome being achieved.

Overall Assessment and Rating

The TA's overall implementation rating is successful as the TA’s major outputs are met. The TA was relevant, effective and efficient in achieving outputs and outcome. The TA outcome is likely to be sustainable.

Major Lessons

The government should continue its strong commitment towards sustainable power sector development including renewable energy from intermittent sources balanced with stable system operation. Using the wind and solar park approach appears a beneficial option for Sri Lanka.

Recommendations and Follow-Up Actions

ADB's further assistance to the government to develop intermittent wind and solar power generation sources through technical assistance and investment interventions is needed to ensure that the impacts of the TA are sustainable. The government is considering to proceed with a Wind Power Generation Project with ADB financing in 2017. At the government request, a relevant project preparatory TA has been approved by ADB in March 2016.4

ADB = Asian Development Bank, CEB = Ceylon Electricity Board, MOP = Ministry of Power, SLSEA = Sustainable Energy Authority, TA = technical assistance, TORs = terms of reference.

Prepared by: Mukhtor Khamudkhanov Designation and Division: Principal Energy Specialist, SAEN

4 ADB. 2016. Technical Assistance for Preparing Wind Power Generation Project. Manila.

Appendix 7 53

PROJECT COST AT APPRAISAL AND ACTUAL ($ million)

Appraisal Estimate Actual

Item Foreign

Exchange Local

Currency Total Cost Foreign

Exchange Local

Currency Total Cost A. Investment Costs 1. Civil works and erection 22.87 32.23 55.10 30.86 14.33 45.18 2. Equipment 73.55 10.79 84.34 46.28 21.49 67.78 3. Consultants a. Project management 0.00 0.10 0.10 0.10 0.14 0.24

1. Taxes and duties 0.00 24.88 24.88 0.00 0.54 0.54 Subtotal (A) 96.41 68.01 164.42 77.24 36.50 113.74 B. Other Costs 1. Land 0.00 0.00 0.00 0.00 0.00 0.00 2. Environmental & Social Mitigation 0.00 3.98 3.98 0.00 6.19 6.19 3. Project management and construction 0.00 1.36 1.36 0.00 11.46 11.46 supervisor Subtotal (B) 0.00 5.34 5.34 0.00 17.65 17.65 Total Base Cost (A+B) 96.41 73.35 169.76 77.24 54.15 131.39 C. Contingencies 1. Physical 3.77 0.17 3.94 0.00 0.00 0.00 2. Price 1.48 8.38 9.85 0.00 0.00 0.00 Subtotal (C) 5.25 8.54 13.79 0.00 0.00 0.00 D Financial Charges During Implementation

1. Interest during construction 2.21 13.87 16.08 2.51 0.00 2.51

2. Commitment Charges 0.37 0.00 0.37 0.00 0.00 0.00

Subtotal (D) 2.58 13.87 16.45 2.51 0.00 2.51

Total (A+B+C+D) 104.24 95.76 200.00 79.75 54.15 133.91 Source: Asian Development Bank estimates

54 Appendix 8

PROJECT COST BY FINANCIER

Table A8.1: Project Cost at Appraisal by Financier ($ million)

ADB CEF Grant Government/CEB Total Cost

OCR ($

million)

% of cost

category

ADF ($

million)

% of cost

category

Amount ($

million)

% of cost

category

Amount ($

million)

% of cost

category

Amount ($

million)

A. Investment Cost

1 Civil Works and Erection 30.25 54.90% 14.02 25.44% 0.00 0.00% 10.83 19.66% 55.10

2 Equipment 67.63 80.19% 15.52 18.40% 1.19 1.41% 0.00 0.00% 84.34

3 Consultants 0.00 0.00% 0.00 0.00% 0.10 100.00% 0.00 0.00% 0.10

4 Taxes and Duties 0.00 0.00% 0.00 0.00% 0.00 0.00% 24.88 100.00% 24.88

Sub Total (A) 97.88 59.53% 29.54 17.97% 1.29 0.78% 35.71 21.72% 164.42

B. Other Costs 1 Land 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00

2 Environmental and Social Mitigation 0.00 0.00% 0.00 0.00% 0.00 0.00% 3.98 100.00% 3.98

3 Supervision 0.00 0.00% 0.00 0.00% 0.00 0.00% 1.36 100.00% 1.36

Sub Total (B) 0.00 0.00% 0.00 0.00% 0.00 0.00% 5.34 100.00% 5.34

Total Base Cost (A+B) 97.88 0.60 29.54 17.97% 1.29 0.76% 41.05 24.18% 169.76

C. Contingencies 1 Physical 0.00 0.00% 0.00 0.00% 0.00 0.00% 3.94 0.00% 3.94

2 Price 0.00 0.00% 0.00 0.00% 0.21 2.13% 9.64 0.00% 9.85

Sub Total (C) 0.00 0.00% 0.00 0.00% 0.21 1.52% 13.58 0.00% 13.79

D. Implementation 1 Interest During Construction 1.75 10.88% 0.46 2.86% 0.00 0.00% 13.87 86.26% 16.08

2 Commitment Charges 0.37 100.00% 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.37

Sub Total (D) 2.12 12.89% 0.46 2.80% 0.00 0.00% 13.87 84.32% 16.45

Total Project Cost (A+B+C+D) 100.00 50.00% 30.00 15.00% 1.50 0.75% 68.50 34.25% 200.00

Appendix 8 55

Table A8.2: Project Cost at Completion by Financier ($ million)

ADB CEF Grant Government/CEB Total Cost

OCR ($

million)

% of cost

category

ADF ($

million)

% of cost

category

Amount ($

million)

% of cost

category

Amount ($

million)

% of cost

category

Amount ($

million)

A. Investment Cost

1 Civil Works and Erection 35.35 78.24% 9.48 20.98% 0.35 0.78% 0.00 0.00% 45.18

2 Equipment 53.03 78.24% 14.22 20.98% 0.53 0.78% 0.00 0.00% 67.78

3 Consultants 0.00 0.00% 0.00 0.00% 0.10 41.45% 0.14 58.55% 0.24

4 Taxes and Duties 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.54 100.00% 0.54

Sub Total (A) 88.38 77.71% 23.69 20.83% 0.98 0.86% 0.68 0.60% 113.74

B. Other Costs 1 Land 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00

2 Environmental and Social Mitigation 0.00 0.00% 0.00 0.00% 0.00 0.00% 6.19 100.00% 6.19

3 Supervision 0.00 0.00% 0.00 0.00% 0.00 0.00% 11.46 100.00% 11.46

Sub Total (B) 0.00 0.00% 0.00 0.00% 0.00 0.00% 17.65 100.00% 17.65

Total Base Cost (A+B) 88.38 0.78 23.69 20.83% 0.98 0.75% 18.34 13.96% 131.39

C. Contingencies 1 Physical 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00

2 Price 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00

Sub Total (C) 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00

D. Implementation 1 Interest During Construction 2.12 84.40% 0.39 15.60% 0.00 0.00% 0.00 0.00% 2.51

2 Commitment Charges 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00 0.00% 0.00

Sub Total (D) 2.12 84.40% 0.39 15.60% 0.00 0.00% 0.00 0.00% 2.51

Total Project Cost (A+B+C+D) 90.50 67.59% 24.09 17.99% 0.98 0.73% 18.34 13.69% 133.91

56 Appendix 9

DISBURSEMENT OF ADB LOAN AND GRANT PROCEEDS

Table 9.1: Annual and Cumulative Disbursement of ADB Loan Proceeds

($ million) Annual Disbursement Cumulative Disbursement

Year

Amount

($ million) % of Total

Amount

($ million) % of Total

2014 3.63 3.1% 3.63 3.1%

2015 11.60 10.0% 15.23 13.2%

2016 35.21 30.5% 50.41 43.6%

2017 38.12 33.0% 88.53 76.6%

2018 9.98 8.6% 98.51 85.2%

2019 14.10 12.2% 112.61 97.4%

2020 2.93 2.5% 115.57 100%

Total 115.57 100.0%

ADB = Asian Development Bank. Source: ADB.

Figure 9.1: Projection and Cumulative Disbursement of ADB Loan Proceeds ($ million)

Source: ADB. 2012. Project Administration Manual, Clean Energy and Network Efficiency Improvement Project (Number: 43576), Democratic Socialist Republic of Sri Lanka. Manila. Project completion report computations ADB Sri Lanka Resident Mission. Disbursement projections amended at loan/grant extension (Minor Change memo dated 30 June 2017. SLRM, Colombo). The Project was set to end June 2019; no disbursements were envisaged in 2020.

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

2014 2015 2016 2017 2018 2019 2020

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Appendix 10 57

CONTRACT AWARDS OF ADB LOAN AND GRANT PROCEEDS

Table 10.1: Annual and Cumulative Contract Awards of ADB Loan Proceeds

($ million) Annual Contract Awards Cumulative Contract Awards

Year

Amount

($ million) % of Total

Amount

($ million) % of Total

2014 34.093 27.92% 34.093 27.92%

2015 83.956 68.76% 118.049 96.69%

2016 4.045 3.31% 122.094 100.00%

2017 0.00 0.00% 0.00 0.00%

2018 0.00 0.00% 0.00 0.00%

2019 0.00 0.00% 0.00 0.00%

Total 122.094 100.0%

ADB = Asian Development Bank. Source: Asian Development Bank.

Figure 10.1: Projection and Cumulative Contract Awards of ADB Loan Proceeds ($ million)

Note: 2-year extension agreed mid-2017. Source: ADB. 2012. Project Administration Manual, Clean Energy and Network Efficiency Improvement Project (Number: 43576. Manila. Project completion report computations ADB Sri Lanka Resident Mission.

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

2014 2015 2016 2017 2018 2019

$ m

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Year Projected Actual Log. (Actual)

58 Appendix 11

STATUS OF COMPLIANCE WITH LOAN COVENANTS

Covenants Reference Responsible Agencies

Compliance Status

Implementation Arrangements 1. The Borrower, MPRE, CEB and SLSEA shall ensure that the Project is implemented in accordance with the detailed arrangements set forth in the PAM. Any subsequent change to the PAM shall become effective only after approval of such change by the Borrower and ADB. In the event of any discrepancy between the PAM and this Loan Agreement, the provisions of this Loan Agreement shall prevail.

LA-2893, Schedule 5, Para 1

The Borrower, MPRE, CEB, SLSEA

Complied. Implementation was carried out as per stipulated in the PAM. There was no revision to the PAM during implementation.

2. The Borrower shall cause the Project to be carried out with due diligence and efficiency and in conformity with sound applicable technical, financial, business, and development practices.

LA-2892 Article IV Section 4.01 (a)

The Borrower, MPRE, CEB, SLSEA

Complied. All project infrastructure outputs were constructed according to CEB’s high standard technical specifications. Solar rooftop systems installed by SEA were rigorously tested and monitored by SEA.

3. CEB and SLSEA shall carry out the Project with due diligence and efficiency, and in conformity with sound applicable technical, financial, business, and development practices.

PA Article II Section 2.01 (a)

CEB and SLSEA

4. In the carrying out of the Project and operation of the Project facilities, the Borrower shall perform, or cause to be performed, all obligations set forth in Schedule 5 to this Loan Agreement and the Project Agreement.

LA-2892 Article IV Section 4.01 (b)

The Borrower, MPRE, CEB, SLSEA

Complied

5. In the carrying out of the Project and operation of the Project facilities, CEB and SLSEA shall perform all obligations set forth in the Loan Agreements and the Grant Agreement to the extent that they are applicable to CEB and SLSEA.

PA Article II Section 2.01 (b)

CEB and SLSEA

Complied

6. In the carrying out of the Project and operation of the Project facilities, the Recipient shall perform, or cause to be performed, all obligations set forth in Schedule 5 to the Special Operations Loan Agreement and the Project Agreement.

GA-0303 Article IV Section 4.01

The Borrower, MPRE, CEB, SLSEA

Complied

7. In the carrying out of the Project and operation of the Project facilities, the Borrower shall perform, or cause to be performed, all obligations set forth in Schedule 5 to this Loan Agreement and the Project Agreement.

LA-2893 Article IV Section 4.01

The Borrower, MPRE, CEB, SLSEA

Complied

8. The Borrower shall exercise its rights under the CEB Subsidiary Loan Agreement and the SLSEA Subsidiary Loan Agreement in such a manner as to protect the interests of the Borrower and ADB and to accomplish the purposes of the Loan.

LA-2892 Article IV Section 4.06 (a)

The Borrower, MPRE, CEB, SLSEA

Complied

9. The Borrower shall exercise its rights under the CEB Subsidiary Loan Agreement in such a manner as to protect the interests of the Borrower and ADB, and to accomplish the purposes of the Loan.

LA-2893 Article IV Section 4.05 (a)

The Borrower and CEB

Complied

10. The Recipient shall exercise its rights under the SLSEA Subsidiary Grant Agreement in such a manner as to protect the interests of the Recipient and ADB and to accomplish the purposes of the Grant.

GA-0303 Article IV Section 4.05 (a)

The Borrower and SLSEA

Complied

11. No rights or obligations under the CEB Subsidiary Loan Agreement and SLSEA Subsidiary Loan Agreement shall be assigned, amended, abrogated or waived without the prior concurrence of ADB.

LA-2892 Article IV Section 4.06 (b)

The Borrower, MPRE, CEB and SLSEA

Complied

12. No rights or obligations under the CEB Subsidiary Loan Agreement shall be assigned, amended, or waived without the prior concurrence of ADB.

LA-2893 Article IV Section 4.05 (b)

The Borrower, MPRE and CEB,

Complied

Appendix 11 59

Covenants Reference Responsible Agencies

Compliance Status

13. No rights or obligations under the SLSEA Subsidiary Grant Agreement shall be assigned, amended, or waived without the prior concurrence of ADB.

GA-0303 Article IV Section 4.05 (b)

The Borrower, MPRE and SLSEA

Complied

14. In the carrying out of the Project, CEB and SLSEA shall employ competent and qualified consultants and contractors, acceptable to ADB, to an extent and upon terms and conditions satisfactory to ADB.

PA Article II Section 2.03 (a)

The Borrower, MPRE, CEB and SLSEA

Complied. All bid documents, bid evaluations and contracts were reviewed by ADB.

15. Except as ADB may otherwise agree, CEB and SLSEA shall procure all items of expenditures to be financed out of the proceeds of the Loans and the Grant in accordance with the provisions of Schedule 4 to the Special Operations Loan Agreement. ADB may refuse to finance a contract where any such item has not been procured under procedures substantially in accordance with those agreed between the Borrower and ADB or where the terms and conditions of the contract are not satisfactory to ADB.

PA Article II Section 2.03 (b)

The Borrower, MPRE, CEB and SLSEA

16. CEB and SLSEA shall carry out the Project in accordance with plans, design standards, specifications, work schedules and construction methods acceptable to ADB. CEB and SLSEA shall furnish, or cause to be furnished, to ADB, promptly after their preparation, such plans, design standards, specifications and work schedules, and any material modifications subsequently made therein, in such detail as ADB shall reasonably request.

PA Article II Section 2.04

The Borrower, MPRE, CEB and SLSEA

Complied. While bid documents were reviewed by ADB, the IA provided quarterly updates on progress as well as ADB conducted regular missions.

17. CEB and SLSEA shall take out and maintain with responsible insurers, or make other arrangements satisfactory to ADB for, insurance against such risks and in such amounts as shall be consistent with sound practice.

PA Article II Section 2.05 (a)

The Borrower, MPRE, CEB and SLSEA

Complied

18. Without limiting the generality of the foregoing, CEB and SLSEA shall undertake to insure, or cause to be insured, the Goods to be imported for the Project against hazards incident to the acquisition, transportation and delivery thereof to the place of use or installation, and for such insurance any indemnity shall be payable in a currency freely usable to replace or repair such Goods.

PA Article II Section 2.05 (b)

The Borrower, MPRE, CEB and SLSEA

Complied

Counterpart Support 19. The Borrower shall make available, or cause to be made available, promptly as needed, and on terms and conditions acceptable to ADB, the funds, facilities, services, land and other resources, as required, in addition to the proceeds of the Loan, for the carrying out of the Project.

LA-2892 Article IV Section 4.02

The Borrower, MPRE, CEB and SLSEA

Complied

20. The Borrower shall enable ADB's representatives to inspect the Project, the Goods and Works, and any relevant records and documents.

LA-2892 Article IV Section 4.03

The Borrower, MPRE, CEB, SLSEA

Complied, IA’s facilitated ADB missions and provided with all required information and records.

21. The Borrower shall enable ADB's representatives to inspect the Project, the Goods and Works, and any relevant records and documents.

LA-2893 Article IV Section 4.02

The Borrower, MPRE, CEB, SLSEA

22. The Recipient shall enable ADB's representatives to inspect the Project, the Goods and Works, and any relevant records and documents.

GA-0303 Article IV Section 4.02

The Borrower, MPRE, CEB, SLSEA

23. CEB and SLSEA shall enable ADB's representatives to inspect the Project, the Goods and Works and any relevant records and documents.

PA Article II Section 2.10

The Borrower, MPRE, CEB, SLSEA

24. The Borrower shall take all actions which shall be necessary on its part to enable CEB and SLSEA to perform their obligations under the Project Agreement, and shall not take or permit any action which would interfere with the performance of such obligations.

LA-2892 Article IV Section 4.05

The Borrower, MPRE, CEB, SLSEA

Complied

60 Appendix 11

Covenants Reference Responsible Agencies

Compliance Status

25. The Borrower shall take all actions which shall be necessary on its part to enable CEB to perform its obligations under the Project Agreement, and shall not take or permit any action which would interfere with the performance of such obligations.

LA-2893 Article IV Section 4.04

The Borrower, MPRE and CEB

Complied

26. The Recipient shall take all actions which shall be necessary on its part to enable SLSEA to perform its obligations under the Project Agreement and shall not take or permit any action which would interfere with the performance of such obligations.

GA-0303 Article IV Section 4.04

The Borrower, MPRE and SLSEA

Complied

27. CEB and SLSEA shall promptly notify ADB of any proposal to amend, suspend or repeal any provision of their constitutional documents, which, if implemented, could adversely affect the carrying out of the Project or the operation of the Project facilities. CEB and SLSEA shall afford ADB an adequate opportunity to comment on such proposal prior to taking any affirmative action thereon.

PA Article II Section 2.15

The Borrower, MPRE, CEB, SLSEA

Complied

28. The Borrower, MOP, CEB and SLSEA shall makes available all counterpart funds required for the timely and effective implementation of the Project including (a) any funds required to make land and rooftop spaces available for the Project; (b) to mitigate unforeseen environmental, resettlement and other social impacts, and (c) to meet additional costs arising from design changes, price escalations or unforeseen circumstances.

LA-2893, Schedule 5, Para 2

The Borrower, MPRE, CEB, SLSEA

Complied. All counterpart funds were made available on time. Was used for land purchasing, mitigation of social and environmental impacts, staff costs of PMU, and for duties and taxes paid within Sri Lanka.

29. CEB and SLSEA shall make available, promptly as needed, the funds, facilities, services, land and other resources as required, in addition to the proceeds of the Loans and the Grant, for the carrying out of the Project.

PA Article II Section 2.02

The Borrower, MPRE, CEB, SLSEA

Complied Counter parts funds were available on time.

30. ADB, CEB and SLSEA shall cooperate fully to ensure that the purposes of the Loans and the Grant will be accomplished.

PA Article II Section 2.07 (a)

The Borrower, MPRE, CEB, SLSEA

Complied The funds were utilized the project intended purpose. Finances were annually audited by the Auditor General’s department of Sri Lanka.

31. CEB and SLSEA shall promptly inform ADB of any condition which interferes with, or threatens to interfere with, the progress of the Project, the performance of their obligations under this Project Agreement, or the accomplishment of the purposes of the Loans or the Grant.

PA Article II Section 2.07 (b)

The Borrower, MPRE, CEB, SLSEA

Complied

32. ADB, CEB and SLSEA shall from time to time, at the request of either party, exchange views through their representatives with regard to any matters relating to the Project, CEB, SLSEA, the Loans or the Grant.

PA Article II Section 2.07 (c)

The Borrower, MPRE, CEB, SLSEA

Complied

33. CEB and SLSEA shall furnish to ADB all such reports and information as ADB shall reasonably request concerning (i) the Loans and the Grant and the expenditure of the proceeds thereof; (ii) the items of expenditure financed out of such proceeds; (iii) the Project; (iv) the administration, operations and financial condition of CEB and SLSEA; and (v) any other matters relating to the purposes of the Loans and the Grant.

PA Article II Section 2.08 (a)

The Borrower, MPRE, CEB, SLSEA

Complied

34. Without limiting the generality of the foregoing, CEB and SLSEA shall furnish to ADB periodic reports on the execution of the Project and on the operation and management of the Project facilities. Such reports shall be submitted in such form and in

PA Article II Section 2.08 (b)

The Borrower, MPRE, CEB, SLSEA

Complied CEB and SLSEA submitted the

Appendix 11 61

Covenants Reference Responsible Agencies

Compliance Status

such detail and within such a period as ADB shall reasonably request, and shall indicate, among other things, progress made and problems encountered during the period under review, steps taken or proposed to be taken to remedy these problems, and proposed program of activities and expected progress during the following period.

quarterly progress report

35. Promptly after physical completion of the Project, but in any event not later than 6 months thereafter or such later date as ADB may agree for this purpose, CEB and SLSEA shall prepare and furnish to ADB a report, in such form and in such detail as ADB shall reasonably request, on the execution and initial operation of the Project, including its cost, the performance by CEB and SLSEA of their obligations under this Project Agreement and the accomplishment of the purposes of the Loans and the Grant.

PA Article II Section 2.08 (c)

CEB and SLSEA

Complied Submitted the borrower completion report.

36. CEB and SLSEA shall, promptly as required, take all action within their powers to maintain their existence, to carry on their operations, and to acquire, maintain and renew all rights, properties, powers, privileges and franchises which are necessary in the carrying out of the Project or in the conduct of their operations.

PA Article II Section 2.11 (a)

CEB and SLSEA

Complied

37. CEB and SLSEA shall at all times conduct their operations in accordance with sound applicable technical, financial, business, development and operational practices, and under the supervision of competent and experienced management and personnel.

PA Article II Section 2.11 (b)

CEB and SLSEA

Complied

38. CEB and SLSEA shall at all times operate and maintain their plants, equipment and other property, and from time to time, promptly as needed, make all necessary repairs and renewals thereof, all in accordance with sound applicable technical, financial, business, development, operational and maintenance practices.

PA Article II Section 2.11 (c)

CEB and SLSEA

Complied

39. Except as ADB may otherwise agree, CEB and SLSEA shall not sell, lease or otherwise dispose of any of their assets which shall be required for the efficient carrying on of their operations or the disposal of which may prejudice their ability to perform satisfactorily any of their obligations under this Project Agreement.

PA Article II Section 2.12

CEB and SLSEA

Complied

40. Except as ADB may otherwise agree, CEB and SLSEA shall apply the proceeds of the Loans and the Grant to the financing of expenditures on the Project in accordance with the provisions of the Loan Agreements, the Grant Agreement and this Project Agreement, and shall ensure that all items of expenditures financed out of such proceeds are used exclusively in the carrying out of the Project.

PA Article II Section 2.13

CEB and SLSEA

Complied. Finances were annually audited by the Auditor General’s department of Sri Lanka.

41. Except as ADB may otherwise agree (a) CEB shall duly perform all its obligations under the CEB Subsidiary Loan Agreement, and shall not take, or concur in, any action which would have the effect of assigning, amending, abrogating or waiving any rights or obligations of the parties under the CEB Subsidiary Loan Agreement; and (b) SLSEA shall duly perform all its obligations the SLSEA Subsidiary Loan Agreement and the SLSEA Subsidiary Grant Agreement and shall not take, or concur in, any action which would have the effect of assigning, amending, abrogating or waiving any rights or obligations. of the parties under the SLSEA Subsidiary Loan Agreement or the SLSEA Subsidiary Grant Agreement.

PA Article II Section 2.14

The Borrower, MPRE, CEB and SLSEA

Complied

42. CEB and SLSEA shall promptly notify ADB of any proposal to amend, suspend or repeal any provision of their constitutional

PA Article II

CEB and SLSEA

Complied

62 Appendix 11

Covenants Reference Responsible Agencies

Compliance Status

documents, which, if implemented, could adversely affect the carrying out of the Project or the operation of the Project facilities. CEB and SLSEA shall afford ADB an adequate opportunity to comment on such proposal prior to taking any affirmative action thereon.

Section 2.15

Selection of Buildings for Solar Power Generation Pilot

43. Within 90 days of the Effective Date, SLSEA shall submit for ADBs approval the selection criteria for private sector solar developers and PFIs for part 7(i) of the Project. The selection criteria shall include the criteria and methodology to determine the capital subsidy amount payable to private sector solar power developers under Part 7(ii) of the Project.

LA-2893, Schedule 5, Para 3

SLSEA

Complied late. (Original deadline was 31 December 2013. Criteria for selection of private sector developers and PFI’s were submitted after the deadline)

Environment

44. The Borrower shall ensure, or cause CEB and SLSEA to ensure, that the preparation, design, construction, implementation, operation and decommissioning of the Project and all Project facilities comply with (a) all applicable laws and regulations of the Borrower relating to environment, health, and safety; (b) the Environmental Safeguards; (c) all measures and requirements set forth in a respective IEE and EMP, and any corrective or preventative actions set forth in a Safeguards Monitoring Report.

LA-2893, Schedule 5, Para 4

CEB, SLSEA Complied. All activities carried out were in par with the local laws, regulations, and environmental safeguards specified in the IEE and EMP.

Land Acquisition and Involuntary Resettlement 45. The Borrower shall ensure, or cause CEB and SLSEA to ensure, that all land and all rights-of-way required for the Project and all Project facilities are made available to the Works contractor in accordance with the schedule agreed under the related Works contract and all land acquisition and resettlement activities are implemented in compliance with (a) all applicable laws and regulations of the Borrower relating to land acquisition and involuntary resettlement; (b) the Involuntary Resettlement Safeguards; and (c) all measures and requirements set forth in the respective RP, and any corrective or preventative actions set forth in a Safeguards Monitoring Report.

LA-2893, Schedule 5, Para 5

CEB, SLSEA Complied. All activities were carried out as per local laws and guidelines, and the involuntary safeguards as per the RP.

46. Without limiting the application of the Involuntary Resettlement Safeguards, the RF or an RP, the Borrower shall ensure or cause CEB and SLSEA to ensure that no physical or economic displacement takes place in connection with the Project until: (a) compensation and other entitlements have been provided to affected people in accordance with the RP; and (b) a comprehensive income and livelihood restoration program has been established in accordance with the RP.

LA-2893, Schedule 5, Para 6

CEB, SLSEA Complied, with some deviations and delays. Compensation for Polpitiya and Kegalle Grid Substations were delayed.

Indigenous Peoples 47. The Borrower shall ensure, or cause CEB and SLSEA to ensure, that the project does not impact indigenous people within the meaning of Safeguard Policy Statement. If due to unforeseen circumstances, the project impacts indigenous peoples, the Borrower, CEB and SLSEA shall take all steps necessary or desirable to ensure that the Project complies with all applicable laws and regulations of the Borrower and with the Safeguard Policy Statement.

LA-2893, Schedule 5, Para 7

CEB, SLSEA There are no indigenous people in the project areas.

Safeguards – Related Provisions in Bidding Documents and Works Contracts

Appendix 11 63

Covenants Reference Responsible Agencies

Compliance Status

48 The Borrower shall ensure, or cause CEB and SLSEA to ensure, that all bidding documents and contracts for Works contain provisions that require contractors to: (a) comply with the measures and requirements relevant to the contractor set forth in an IEE or EIA, the EMP, the RP and the IPP (to the extent they concern impacts on affected people during construction), and any corrective or preventative actions set out in a Safeguards Monitoring Report; (b) make available a budget for all such environmental and social measures; (c) provide CEB and SLSEA with a written notice of any unanticipated environmental, resettlement or indigenous peoples risks or impacts that arise during construction, implementation or operation of the Project that were not considered in the IEE the EMP, or the RP; (d) adequately record the condition of roads, agricultural land and other infrastructure prior to starting to transport materials and construction; and (e) reinstate pathways, other local infrastructure, and agricultural land to at least their pre-project condition upon the completion of construction.

LA-2893, Schedule 5, Para 8

CEB,SLSEA Complied. Bid documents were reviewed by ADB staff before the bids were advertised.

Safeguards Monitoring and Reporting

49. The Borrower shall do the following or cause CEB and SLSEA to do the following: (a) submit semi-annual Safeguards Monitoring Reports to ADB and disclose relevant information from such reports to affected persons promptly upon submission; (b) if any unanticipated environmental and/or social risks and impacts arise during construction, implementation or operation of the Project that were not considered in the IEE, the EMP, or the RP, promptly inform ADB of the occurrence of such risks or impacts, with detailed description of the event and proposed corrective action plan; and (c) report any actual or potential breach of compliance with the measures and requirements set forth in the EMP, or the RP promptly after becoming aware of the breach.

LA-2893, Schedule 5, Para 9

CEB, SLSEA Complied, with some deviations and delays. CEB complied in terms of submitting the bi-annual safeguard monitoring reports. These were submitted following the award of the first contract. However, CEB failed to disclose the revised IEE and RP in a timely manner.

Prohibited List of Investments 50. The Borrower shall ensure, or cause CEB and SLSEA to ensure, that no proceeds of the Loan are used to finance any activity included in the list of prohibited investment activities provided in Appendix 5 of the Safeguard Policy Statement.

LA-2893, Schedule 5, Para 10

The Borrower, CEB, and SLSEA

Complied. The project activities were monitored by ADB, and the finances were audited annually.

Labor Standards 51. The Borrower shall ensure, or cause CEB and SLSEA to ensure, that all civil works contracts and bidding documents for the Project include specific provisions requiring contractors to (a) comply with all applicable labor laws of the Borrower on the prohibition of child and forced labor; (b) give equal pay for equal work regardless of gender, ethnicity or caste; and (c) disseminate information on sexually transmitted diseases (including HIV/AIDS) and human trafficking to employees and local communities surrounding the Project construction sites.

LA-2893, Schedule 5, Para 11

The Borrower, CEB, and SLSEA

Complied. Bidding documents were reviewed by ADB staff.

Governance and Corruption 52. The Borrower, MPRE, CEB and SLSEA shall comply with ADB’s Anticorruption Policy (1998, as amended to date) and cooperate with any investigation by ADB and extend all

LA-2893, Schedule 5, Para 12

The Borrower, MPRE, CEB, and SLSEA

Complied.

64 Appendix 11

Covenants Reference Responsible Agencies

Compliance Status

necessary assistance for satisfactory completion of such investigation. 53. The Borrower, MPRE, CEB and SLSEA shall ensure that the anticorruption provisions acceptable to ADB are included in all bidding documents and contracts, including provisions specifying the right of ADB to audit and examine the records and accounts of the executing and implementing agencies and all contractors, suppliers, consultants, and other service providers as they relate to the Project.

LA-2893, Schedule 5, Para 1 3

The Borrower, CEB, and SLSEA

Complied. Bid documents were reviewed by ADB staff.

Grievance Redress Mechanism 54. Within 90 days of the Effective Date, CEB and SLSEA shall establish a grievance redress mechanism, acceptable to ADB, to receive and facilitate resolution of affected people’s concerns, complaints and grievances relating to the Project’s land acquisition, resettlement and environmental impacts. The Borrower, through the MPRE, CEB, and SLSEA shall: (a) make the existence of this grievance redress mechanism publicly known; and (b) proactively and constructively review and redress grievances of affected people in relation to the Project.

LA-2893, Schedule 5, Para 14

CEB, SLSEA Complied. A Grievance Redress Mechanism established under the Divisional Secretaries is applicable for all ongoing projects. There is also a grievance redress mechanism established by the PUCSL.

Project Website 55. Within 45 days of the Effective Date, each of CEB and SLSEA shall update its website to include information on (a) bidding procedures, bidders, and contract awards; (b) use of the funds disbursed under the Project; and (c) physical progress of the Project.

LA-2893, Schedule 5, Para 15

CEB, SLSEA Partially Complied. CEB publishes all information related to bidding procedures under a separate link to the CEB corporate webpage. The corporate webpage does not provide information related to items (b) and (c).

Audit Reports 56. ADB shall disclose the annual audited financial statements for the Project and the opinion of the auditors on the financial statements within 30 days of the date of their receipt by posting them on ADB’s website

LA-2892 Article IV Section 4.04

ADB Complied All submitted APFS were disclosed in ADB website. 57. ADB shall disclose the annual audited financial statements

for the Project and the opinion of the auditors on the financial statements within 30 days of the date of their receipt by posting them on ADB’s website

LA-2893 Article IV Section 4.03

ADB

58. ADB shall disclose the annual audited financial statements for the Project and the opinion of the auditors on the financial statements within 30 days of the date of their receipt by posting them on ADB’s website

GA-0303 Article IV Section 4.03

ADB

59. Section 2.09. (a) CEB and SLSEA shall (i) maintain separate accounts and records for the Project; (ii) prepare annual financial statements for the Project in accordance with accounting principles acceptable to ADB; (iii) have such financial statements for the Project audited annually by independent auditors whose qualifications, experience and terms of reference are acceptable to ADB, in accordance with international standards for auditing or the national equivalent acceptable to ADB; (iv) as part of each such audit, have the auditors prepare a report (which includes the auditors’ opinion on the use of the proceeds of the Loans and

PA, Section 2.09

CEB, SLSEA Complied with delay. (i) completeness – For CEB, all annual APFS from effective date to closing received (FYE2013 to 2019). For SLSEA, all APFS received up to last transaction of FYE2018 (except

Appendix 11 65

Covenants Reference Responsible Agencies

Compliance Status

the Grants and compliance with financial covenants of the Loan Agreements and grant Agreements) and a management letter (which sets out the deficiencies in the internal control of the Project that were identified in the course of the audit, if any); and (v) furnish to ADB, no later than 6 months after the close of the fiscal year to which they relate, copies of such audited financial statements, audit report and management letter, all in the English language, and such other information concerning these documents and the audit thereof as ADB shall from time to time reasonably request. (b) ADB shall disclose the annual audited financial statements for the Project and the opinion of the auditors on the financial statements within 30 days of the date of their receipt by posting them on ADB’s website. (c) CEB and SLSEA shall enable ADB, upon ADB's request, to discuss the financial statements for the Project and CEB and its financial affairs where they relate to the Project with the auditors appointed by CEB pursuant to subsections (a) (iii) and (c) hereinabove, and shall authorize and require any representative of such auditors to participate in any such discussions requested by ADB. This is provided that such discussions shall be conducted only in the presence of an authorized officer of CEB, unless CEB shall otherwise agree.

2013, where SLSEA has requested for deferment based on no transactions) to closing received. (ii) timely receipt of reports – CEB delayed by 5 months, SLSEA by 13 months. Final APFS of CEB received on time. (iii) type of audit opinions – for CEB, auditor issued qualified opinions for all years APFS; for SLSEA, auditor issued 2 clean or unqualified opinions (FYE2014 and 2018), 3 qualified (FYE2015, 2016 and 2017). (iv) opinion on use of funds – issued for all years with APFS. (v) Management letter – issued. CEB has confirmed that the deficiencies reported in FY2019 final MR; over recorded exchange losses, unrecorded bills payables and overstatement of IDC and disbursements were resolved and corrected in statutory accounts in FY 2020.The board has decided in FY 2020 to implement PAYE remittance to make in line with notice of Inland revenue.

60. CEB and SLSEA shall maintain, or cause to be maintained, records and accounts adequate to identify the items of expenditure financed out of the proceeds of the Loans and the Grant, to disclose the use thereof in the Project, to record the progress of the Project (including the cost thereof) and to reflect, in accordance with consistently maintained sound accounting principles, its operations and financial condition.

PA Article II Section 2.06

CEB and SLSEA

Complied CEB and SLSEA maintained the records

61. CEB and SLSEA shall (i) maintain separate accounts and records for the Project; (ii) prepare annual financial statements for the Project in accordance with accounting principles

PA Article II

CEB and SLSEA

Complied

66 Appendix 11

Covenants Reference Responsible Agencies

Compliance Status

acceptable to ADB; (iii) have such financial statements for the Project audited annually by independent auditors whose qualifications, experience and terms of reference are acceptable to ADB, in accordance with international standards for auditing or the national equivalent acceptable to ADB; (iv) as part of each such audit, have the auditors prepare a report (which includes the auditors’ opinion on the use of the proceeds of the Loans and the Grant and compliance with the financial covenants of the Loan Agreements and the Grant Agreement) and a management letter (which sets out the deficiencies in the internal control of the Project that were identified in the course of the audit, if any); and (v) furnish to ADB, no later than 6 months after the close of the fiscal year to which they relate, copies of such audited financial statements, audit report and management letter, all in the English language, and such other information concerning these documents and the audit thereof as ADB shall from time to time reasonably request.

Section 2.09 (a)

CEB and SLSEA maintained the records

62. ADB shall disclose the annual audited financial statements for the Project and the opinion of the auditors on the financial statements within 30 days of the date of their receipt by posting them on ADB’s website.

PA Article II Section 2.09 (b)

CEB and SLSEA

Complied All submitted APFS were disclosed in ADB website.

63. CEB and SLSEA shall enable ADB, upon ADB's request, to discuss the financial statements of CEB and SLSEA and their financial affairs where they relate to the Project with the auditors appointed by CEB and SLSEA pursuant to subsection (a)(iii) herein above, and shall authorize and require any representative of such auditors to participate in any such discussions requested by ADB. This is provided that such discussions shall be conducted only in the presence of an authorized officer of CEB and SLSEA, unless CEB and SLSEA shall otherwise agree.

PA Article II Section 2.09 (c)

CEB and SLSEA

Complied

ADB = Asian Development Bank, CEB = Ceylon Electricity Board, EIA = environmental impact assessment, EMP = environmental management plan, HIV/AIDS = human immunodeficiency viruses/ acquired immune deficiency syndrome, IEE = initial environmental examination, IPP = independent power producer PAM = project administration manual, PFI = participating financial institution. PMU = project management unit, PUCSL = Public Utilities Commission of Sri Lanka, RF = resettlement framework, RP = resettlement plan, SLSEA = Sri Lanka Sustainable Energy Authority. MPRE = Ministry of Power and Renewable Energy. Source: ADB

Appendix 12 67

ECONOMIC REEVALUATION

General

1. The economic reevaluation was done to assess and validate the economic efficiency of the Clean Energy and Network Efficiency Improvement Project (project) upon completion. In comparison with the economic evaluation done at the project appraisal stage, project scope, costs and benefits are more evident, allowing an accurate assessment of economic returns of the project. This appendix reviews the major assumptions used in the original economic analysis and presents more realistic forecasts on economic performance of the project based on actual project costs and likely benefits. The economic reevaluation was carried out in accordance with Asian Development Bank’s (ADB) guidelines for economic evaluation of projects.1 2. Increased, efficient and more reliable access to electricity for sustainable economic growth, achieved by strengthening transmission and distribution network is the main impact of the project on the country's economy. The project consists of three outputs: i) transmission infrastructure expansion in the Northern province, ii) transmission and distribution efficiency improvement, and iii) implementing a solar rooftop pilot project. 3. To compare the economic efficiency of the project as realized at project completion against the evaluation done at project appraisal, the economic internal rate of return (EIRR) of each project output and the overall project were recalculated. The economic reevaluation was done for a period covering the full implementation period and an operational period of 25 years. Annual costs were obtained from the audited project financial statements, and all the costs and benefits are stated in constant 2020 Sri Lankan Rupees using the domestic price numeraire.

Demand Analysis

4. As stated in the Sri Lanka Electricity Act No. 20 of 2009 (amended in 2013), developing and maintaining an efficient, coordinated, reliable and economical transmission system is a duty of the Transmission Licensee. The transmission licensee is held by the Ceylon Electricity Board (CEB), the executing agency of the outputs 1 and 2. Preparation of a Long-Term Transmission Development Plan (LTTDP) is one of the responsibilities assigned to the Transmission Licensee.2 The LTTDP is prepared by examining the present transmission network, forecasting the demand to be served and identifying the required network expansions to meet the forecast demand. 5. The Transmission and Generation Planning Branch of the CEB prepares the LTTDP as a 10-year rolling plan which is renewed once in every two years to satisfy the above requirements. The national power and energy demand forecast, the Long-Term Generation Expansion Plan and Medium Voltage Distribution Development Plans (MVDDPs) prepared by the distribution licensees provide inputs to the LTTDP. Planning studies are performed under normal and n-1 contingency conditions to identify violations of voltage, thermal, security, stability, and short circuit criteria, and to propose necessary network expansions and reinforcements to overcome such violations. Since the transmission investments undertaken by the project under outputs 1 and 2 were from the LTTDP, they are expected to be fully utilized to supply the electricity demand forecasts for the future.

1 ADB. 2017. Guidelines for the Economic Analysis of Projects. Manila. 2 Ceylon Electricity Board. 2015. Draft Grid Code. Colombo.

68 Appendix 12

6. Similarly, the five Distribution Licensees conduct the distribution planning studies and prepare the respective MVDDPs. The MVDDPs are 10-year rolling plans for the distribution areas under the purview of each distribution licensee3, which identify the performance of the existing medium voltage network, forecast demand growth, and proposes required network reinforcements to serve both the existing and future demand without violating planning criteria. The distribution related investments made under output 2 of the project being identified investments in the MVDDPs, the network improvements carried out are assured to be fully utilized.

7. The Net Metering scheme for rooftop solar photovoltaic (PV) systems in Sri Lanka was first introduced in 2008. The country could connect only 151 rooftop solar PV systems with a cumulative capacity of 655 kilowatt by the end of 2012.4 The reasons for slow growth in capacity addition were the shortage in local expertise, low-quality workmanship of local contractors, and high capital cost of solar PV equipment. A commercial-scale pilot project that provides solutions to these issues was required, and output 3 of the project addressed this requirement.

Economic Costs

8. Economic costs considered in the assessment mainly comprise the upfront capital investments made on the project over the implementation period and the incremental operation and maintenance costs associated with the assets installed by the project. Furthermore, the cost of replacing solar PV inverters under output 3 and the cost of generation that serves incremental demand were also considered as direct economic costs of the project. 9. Capital costs: The larger share of capital investments made on the project was financed by the ADB. The Government of Sri Lanka (government) disbursed counterpart funding through the executing agencies mainly to meet the local expenses. Expenditure on traded goods and services, non-traded goods and services, skilled labor, unskilled labor and transfers were assigned appropriate conversion factors to adjust the actual (financial) costs to represent their economic costs. 10. To derive the economic cost of traded goods and services from the costs denominated in their border prices, a shadow exchange rate factor of 1.07 was used.5 Similarly, to convert the actual cost of local labor incurred by the project to an economic cost, a shadow wage rate factor of 0.33 was used.6 Costs of non-traded goods and services, and skilled labor were kept unadjusted. The taxes and duties, which are transfer payments, were omitted (assigned a conversion factor of 0) to reflect the national perspective. Financial charges were excluded in the reevaluation. Table A12.1 provides project capital costs in economic terms upon adjusting using the above-mentioned conversion factors.

3 CEB holds five of the six distribution licenses whilst the other distribution license is held by Lanka Electricity Company

(Pvt) Ltd (LECO). 4 ADB. 2017. Report and Recommendation of the President to the Board of Directors: Proposed Loan and

Administration of Technical Assistance Grant. Democratic Socialist Republic of Sri Lanka: Rooftop Solar Power Generation Project. Demand Analysis for Rooftop Solar Systems (accessible from the list of linked documents in Appendix 2). Manila.

5 Shadow Exchange Rate Factor was calculated following approach recommended in Appendix 12 of ADB. 2017. Guidelines for the Economic Analysis of Projects. Manila.

6 Shadow Wage Rate Factor was calculated by taking the ratio of minimum wage paid for unskilled labour in Sri Lanka (SLRs500) and the actual wages paid for project labour (SLRs1,500).

Appendix 12 69

Table A12.1: Economic Capital Costs of the Project (SLR million)

Cost Item Output

1 2 3 Total Civil work and erection 1,492 5,353 107 6,953 Equipment 2,689 9,644 193 12,526 Consultant (Project Management) 1 23 17 40 Environmental and Social Mitigation 254 833 - 1,087 Project Management and Construction Supervision 487 1,539 - 2,026 Total 4,923 17,393 317 22,633

Output 1: Transmission infrastructure expansion in Northern province; Output 2: Transmission and distribution efficiency improvement; Output 3: Implementing solar rooftop pilot.

11. Operation and maintenance cost: An incremental annual operation and maintenance (O&M) cost equivalent to 1.5% of the investment was considered for transmission assets in output 1. For transmission and distribution assets in output 2, 2.0% of the investment was considered as the annual O&M cost. Similarly, O&M cost of solar PV equipment in output 3 was considered as 0.5% of the investment. O&M cost was distributed into the cost categories of; traded goods and services, skilled labor, and transfers and adjusted with relevant conversion factors. 12. Cost of incremental generation: Annual variation in fuel cost of incremental generation in constant terms was considered by calculating average fuel cost using total fuel cost and generation data available in draft Long-Term Generation Expansion Plan 2020-2039. Variable O&M cost, which was calculated as 2% of the fuel cost, was added to calculate the total cost of incremental generation. The incremental social cost of carbon dioxide (CO2) emissions arising from the incremental generation was considered as a negative benefit by subtracting it from environmental benefits. 13. Replacement cost: Solar PV inverters installed under output 3 are expected to be replaced every 10 years and it was assumed that the capital cost of inverters is 5% of the total capital cost of output 3.

Economic Benefits

14. Non-incremental benefits. The main non-incremental economic benefit of the project is the resource cost saving due to the decrease in transmission and distribution losses and increase in renewable energy supply to the system. It was assumed that the decrease in network losses grows annually, following the demand growth profile.7 Fuel and variable O&M cost savings of thermal generation was considered as the non-incremental economic benefit of loss reductions and renewable energy injections facilitated by the project. Environmental benefits achieved by reducing the transmission and distribution losses and increase in renewable energy supply to the system was valued using the social cost of CO2 emissions, estimated at $36.3 per ton of CO2 in 2016 prices, increasing at 2% per year (footnote 1). Reduction of kerosene consumption of unelectrified residential consumers also contribute to the reduction in CO2 emissions at end-user level.8 Reduction in emissions was quantified using a 0.8666 tCO2/MWh grid emission factor.9

7 For subcomponents is Northern Province, demand growth rate of North Central Province (7.7%) was considered.

Demand growth rates of 5.0% and 7.5% were applied for subprojects in Central and Eastern provinces. (Source: Medium Voltage Distribution Development Plan 2019-2028 of Distribution Division 1 and Distribution Division 2)

8 Kerosene consumption of a domestic consumer was estimated at 8 liters per month. Kerosene combustion emits 2.46 kgCO2/liter.

9 Sri Lanka Sustainable Energy Authority. 2018. Sri Lanka Energy Balance 2017. Colombo.

70 Appendix 12

15. Incremental benefits. The project contributed to relieving constraints in the distribution network, enabling providing new electricity supply connections to the consumers in the area. If not for the project, these consumers would not have access to electricity and therefore, the entire additional consumption resulting from the project is considered an incremental demand. The economic benefit of this additional supply was valued at the Willingness to Pay (WTP) for electricity by the different consumer categories served by the project. The WTP was calculated as the average of the cost of diesel driven captive power generation and their respective end-user tariffs. 16. Benefits of Output 1. Prior to the project, electricity consumers in the Mannar district were fed through a 100 kilometer long 33 kilovolt distribution line from Vavuniya grid substation (GSS). Due to the long line length, most areas supplied by this line experienced low voltage conditions, which also prevented supply of new connections. The project was able to avoid this situation and serve additional demand. The incremental demand served by the project was calculated using the forecast demand at Mannar GSS available in the LTTDP 2018-2027 against the supply capacity of the distribution line which fed Mannar without the project. As validated through network simulation studies, in addition to supplying additional demand, output 1 also resulted in reducing network losses.10 It was assumed that the decrease in network losses would grow in parallel to the forecast demand growth. Furthermore, electricity generated by the new 100-megawatt Mannar wind power plant will be transferred towards load centers through Mannar GSS-Vavuniya GSS-New Anuradhapura GSS transmission line. From the total benefit of renewable energy injection from the wind power plant, 10% was apportioned to output 1, based on the cost ratio between the capital cost of the wind power plant and the capital costs of all relevant new transmission assets up to New Anuradhapura GSS.

17. Benefits of Output 2. As per the demand forecast available in LTTDP 2018-2027, without the Kegalle power transmission development work undertaken as part of output 2, demand at Thulhiriya GSS would have exceeded the demand that can be served at a reliability level of n-1.11 Maintaining n-1 reliability at transmission level is a requirement in the grid code and therefore, Kegalle GSS is required to serve incremental demand without violating this operating criterion. Therefore, the excess demand at Thulhiriya GSS, which was valued at WTP, was considered as an incremental benefit of output 2. Incremental demand served by distribution assets of output 2 was estimated using the same values used at the appraisal stage for 2017 and the latest demand growth rates of relevant districts. Similar to output 1, the decrease in network losses due to output 2 was estimated and valued based on power system simulations performed by CEB using with and without project scenarios.

18. Benefits of Output 3. Electricity generation by rooftop solar PV systems financed by the project was estimated using a capacity factor of 17% and an annual capacity degradation factor of 0.5%. This renewable energy generation was valued based on the displaced thermal power generation.

Economic Internal Rate of Return

19. By using the estimated economic costs and benefits mentioned above, the EIRR was calculated for the project. Table A12.2 to Table A12.4 lists the annual costs and benefits of the three project outputs while Table A12.5 gives the overall analysis. As per the economic viability

10 Overall network losses with and without the Project were calculated by CEB using PSS/E software simulations, and

the difference in losses between the with and without project scenarios were used for the benefit valuation. 11 n-1 reliability level implies the ability of the network to supply the demand even if one element (a transmission line,

transformer, switchgear etc.) becomes unavailable.

Appendix 12 71

assessment is summarized in Table A12.6, the overall project yields an EIRR above the hurdle rate of 12.0% used by ADB at the time of project appraisal. Each of the three project outputs also results in EIRR values above the hurdle rate.

Table A12.2: Economic Cost Benefit Analysis of Project Output 1 (SLRs million)

Year

Costs Benefits Net

Benefits Capital O&M Replacement Incremental generation

Incremental

Resource Cost

Saving

Environmental Benefits

2013 16 - - - - - - (16) 2014 112 - - - - - - (112) 2015 677 - - - - - - (677) 2016 665 - - - - - - (665) 2017 1,779 - - - - - - (1,779) 2018 477 - - - - - - (477) 2019 1,196 - - - - - - (1,196) 2020 - 62 - 989 1,212 395 47 602 2021 - 62 - 993 1,354 654 166 1,119 2022 - 62 - 1,068 1,501 647 161 1,179 2023 - 62 - 1,090 1,652 613 156 1,267 2024 - 62 - 1,108 1,807 581 150 1,368 2025 - 62 - 1,095 1,967 539 144 1,493 2026 - 62 - 1,172 2,130 544 138 1,579 2027 - 62 - 1,226 2,236 555 138 1,641 2028 - 62 - 849 2,260 389 146 1,885 2029 - 62 - 1,177 2,284 540 150 1,735 2030 - 62 - 1,182 2,309 543 153 1,761 2031 - 62 - 1,185 2,332 544 157 1,787 2032 - 62 - 1,147 2,357 527 161 1,835 2033 - 62 - 1,108 2,382 509 164 1,885 2034 - 62 - 1,119 2,407 515 168 1,908 2035 - 62 - 1,116 2,433 513 172 1,940 2036 - 62 - 1,129 2,458 520 175 1,962 2037 - 62 - 1,100 2,483 506 179 2,007 2038 - 62 - 1,112 2,510 512 182 2,030 2039 - 62 - 1,088 2,536 501 186 2,074 2040 - 62 - 1,088 2,564 501 190 2,105 2041 - 62 - 1,087 2,591 501 194 2,137 2042 - 62 - 1,087 2,620 501 198 2,170 2043 - 62 - 1,087 2,649 501 202 2,203 2044 - 62 - 1,086 2,679 501 206 2,237

EIRR 18.7% () = negative; EIRR = economic internal rate of return; O&M = operation and maintenance.

Table A12.3: Economic Cost Benefit Analysis of Project Output 2

(SLRs million)

Year

Costs Benefits Net

Benefits Capital O&M Replacement Incremental generation

Incremental

Resource Cost

Saving

Environmental Benefits

2013 70 - - - - - - (70) 2014 694 - - - - - - (694) 2015 1,594 - - - - - - (1,594) 2016 5,667 - - - - - - (5,667) 2017 4,886 - - - - - - (4,886) 2018 1,890 - - - - - - (1,890) 2019 2,052 - - - - - - (2,052) 2020 540 293 - 2,191 3,177 1,281 (326) 1,106 2021 - 293 - 2,167 3,510 1,224 (381) 1,892

72 Appendix 12

Year

Costs Benefits Net

Benefits Capital O&M Replacement Incremental generation

Incremental

Resource Cost

Saving

Environmental Benefits

2022 - 293 - 2,294 3,843 1,264 (435) 2,085 2023 - 293 - 2,329 4,218 1,249 (497) 2,348 2024 - 293 - 2,294 4,486 1,236 (528) 2,607 2025 - 293 - 2,314 4,999 1,195 (623) 2,964 2026 - 293 - 2,578 5,655 1,257 (755) 3,286 2027 - 293 - 2,870 6,337 1,334 (892) 3,616 2028 - 293 - 1,999 6,467 973 (874) 4,274 2029 - 293 - 2,794 6,604 1,351 (902) 3,966 2030 - 293 - 2,828 6,749 1,357 (931) 4,053 2031 - 293 - 2,858 6,895 1,361 (962) 4,143 2032 - 293 - 2,791 7,051 1,318 (995) 4,289 2033 - 293 - 2,721 7,214 1,273 (1,030) 4,443 2034 - 293 - 2,776 7,387 1,287 (1,068) 4,537 2035 - 293 - 2,797 7,568 1,283 (1,107) 4,655 2036 - 293 - 2,862 7,757 1,299 (1,149) 4,751 2037 - 293 - 2,821 7,957 1,265 (1,195) 4,913 2038 - 293 - 2,890 8,168 1,280 (1,243) 5,022 2039 - 293 - 2,865 8,392 1,253 (1,295) 5,192 2040 - 293 - 2,905 8,631 1,253 (1,350) 5,335 2041 - 293 - 2,949 8,885 1,253 (1,410) 5,486 2042 - 293 - 2,996 9,156 1,253 (1,474) 5,645 2043 - 293 - 3,046 9,443 1,253 (1,543) 5,814 2044 - 293 - 3,101 9,752 1,253 (1,617) 5,993

EIRR 12.9% () = negative; EIRR = economic internal rate of return; O&M = operation and maintenance.

Table A12.4: Economic Cost Benefit Analysis of Project Output 3

(SLRs million)

Year

Costs Benefits Net

Benefits Capital O&M Replacement Incremental generation

Incremental

Resource Cost

Saving

Environmental Benefits

2013 - - - - - - - - 2014 6 - - - - - - (6) 2015 13 1 - - - - 0 (14) 2016 98 1 - - - - 1 (99) 2017 128 1 - - - - 5 (124) 2018 36 1 - - - - 12 (26) 2019 15 1 - - - - 17 1 2020 21 1 - - - 48 19 44 2021 - 1 - - - 43 19 61 2022 - 1 - - - 42 19 60 2023 - 1 - - - 39 20 58 2024 - 1 - - - 37 20 55 2025 - 1 12 - - 34 20 41 2026 - 1 - - - 33 20 52 2027 - 1 - - - 33 21 53 2028 - 1 - - - 23 21 43 2029 - 1 - - - 32 21 52 2030 - 1 - - - 32 22 52 2031 - 1 - - - 32 22 52 2032 - 1 - - - 30 22 51 2033 - 1 - - - 29 23 50 2034 - 1 - - - 29 23 51 2035 - 1 8 - - 29 23 43 2036 - 1 - - - 29 24 51 2037 - 1 - - - 28 24 51

Appendix 12 73

Year

Costs Benefits Net

Benefits Capital O&M Replacement Incremental generation

Incremental

Resource Cost

Saving

Environmental Benefits

2038 - 1 - - - 29 24 51 2039 - 1 - - - 28 25 51 2040 - 1 - - - 28 25 51 2041 - 1 - - - 28 25 52 2042 - 1 - - - 27 26 52 2043 - 1 - - - 27 26 52 2044 - 1 - - - 27 26 52

EIRR 13.6% () = negative; EIRR = economic internal rate of return; O&M = operation and maintenance.

Table A12.5: Economic Cost Benefit Analysis of the Overall Project (SLRs million)

Year

Costs Benefits Net

Benefits Capital O&M Replacement Incremental generation

Incremental

Resource Cost

Saving

Environmental Benefits

2013 85 - - - - - - (85) 2014 812 - - - - - - (812) 2015 2,284 1 - - - - 0 (2,285) 2016 6,430 1 - - - - 1 (6,431) 2017 6,793 1 - - - - 5 (6,789) 2018 2,403 1 - - - - 12 (2,393) 2019 3,264 1 - - - - 17 (3,248) 2020 562 356 - 3,181 4,611 1,724 (497) 1,739 2021 - 356 - 3,160 5,118 1,922 (462) 3,061 2022 - 356 - 3,362 5,631 1,954 (553) 3,314 2023 - 356 - 3,420 6,193 1,901 (653) 3,664 2024 - 356 - 3,402 6,652 1,854 (725) 4,023 2025 - 356 12 3,409 7,364 1,768 (861) 4,494 2026 - 356 - 3,749 8,226 1,835 (1,037) 4,918 2027 - 356 - 4,096 9,044 1,923 (1,201) 5,313 2028 - 356 - 2,848 9,212 1,385 (1,185) 6,208 2029 - 356 - 3,972 9,387 1,923 (1,218) 5,763 2030 - 356 - 4,010 9,571 1,931 (1,254) 5,881 2031 - 356 - 4,043 9,755 1,937 (1,291) 6,001 2032 - 356 - 3,938 9,950 1,875 (1,330) 6,200 2033 - 356 - 3,830 10,153 1,812 (1,372) 6,407 2034 - 356 - 3,895 10,366 1,831 (1,416) 6,529 2035 - 356 8 3,913 10,588 1,826 (1,462) 6,675 2036 - 356 - 3,991 10,817 1,848 (1,511) 6,806 2037 - 356 - 3,920 11,058 1,800 (1,564) 7,018 2038 - 356 - 4,003 11,312 1,821 (1,619) 7,155 2039 - 356 - 3,953 11,580 1,781 (1,678) 7,374 2040 - 356 - 3,993 11,862 1,781 (1,741) 7,553 2041 - 356 - 4,036 12,161 1,781 (1,809) 7,741 2042 - 356 - 4,083 12,478 1,781 (1,881) 7,939 2043 - 356 - 4,133 12,812 1,781 (1,957) 8,146 2044 - 356 - 4,187 13,168 1,781 (2,040) 8,365 EIRR 14.3%

() = negative; EIRR = economic internal rate of return; O&M = operation and maintenance.

Table A12.6: Economic Viability of Project Outputs

Output EIRR 1: Transmission infrastructure expansion in Northern province 18.7% 2: Transmission and distribution efficiency improvement 12.9% 3: Implementing solar rooftop pilot 13.6% Overall Project 14.3%

74 Appendix 12

Sensitivity Analysis

20. The economic efficiency of the overall project and the results derived from the economic reevaluation were tested for their sensitivity to adverse changes in project parameters. An increase in O&M cost, and a decrease in capacity factors of rooftop solar systems and the wind power plant does not make a significant impact on the overall project EIRR. Project economic efficiency largely depends on incremental benefits that have been valued at WTP. The price of diesel affects the cost of captive power generation and consequently changes the WTP estimate. Therefore, if the fuel prices do not increase as assumed, project benefits reduce and the EIRR of the project reduces but remains above the threshold. Table A12.7, Table A12.8 and Table A12.9 presents the sensitivity of each project output to these adverse changes whereas Table A12.10 gives the impact of these changes on the overall project. According to the results of the sensitivity analysis, all three project outputs are robust against adverse changes. As summarized in Table A12.10, the overall project efficiency would not be affected under most adverse conditions considered, unless the adverse conditions occur together. Therefore, each project output and the overall project can be considered solid economic investments for Sri Lanka.

Table A12.7: Sensitivity Analysis for Project Output 1 Parameter Change EIRR

Base case 18.7%

Increase in O&M costs by further 1% 18.4%

Decrease in solar and wind capacity factors by further 10% 18.1%

No annual improvement in network loss reduction 18.4%

No real term increase in price of diesel used for captive power generation 14.9%

Combination of all above 15.9%

EIRR = economic internal rate of return; O&M = operation and maintenance.

Table A12.8: Sensitivity Analysis for Project Output 2

Parameter Change EIRR

Base case 12.9%

Increase in O&M costs by further 1% 12.5%

Decrease in solar and wind capacity factors by further 10% 12.9%

No annual improvement in network loss reduction 10.8%

No real term increase in price of diesel used for captive power generation 10.7%

Combination of all above 7.4%

EIRR = economic internal rate of return; O&M = operation and maintenance.

Table A12.9: Sensitivity Analysis for Project Output 3

Parameter Change EIRR

Base case 13.6%

Increase in O&M costs by further 1% 12.5%

Decrease in solar and wind capacity factors by further 10% 12.2%

No annual improvement in network loss reduction 13.6%

No real term increase in price of diesel used for captive power generation 13.6%

Combination of all above 11.0%

EIRR = economic internal rate of return; O&M = operation and maintenance.

Table A12.10: Sensitivity Analysis of the Overall Project Parameter Change EIRR

Base case 13.6%

Increase in O&M costs by further 1% 12.5%

Decrease in solar and wind capacity factors by further 10% 12.2%

Appendix 12 75

No annual improvement in network loss reduction 13.6%

No real term increase in price of diesel used for captive power generation 13.6%

Combination of all above 11.0%

EIRR = economic internal rate of return; O&M = operation and maintenance.

76 Appendix 13

FINANCIAL REEVALUATION

General

1. The financial reevaluation of the Clean Energy and Network Efficiency Improvement Project (project) was performed to reassess and validate the financial sustainability of the project for the executing agencies, upon project completion. The financial reevaluation was conducted using the guidelines for financial analysis and evaluation of projects of the Asian Development Bank (ADB).1 2. Yearly net cash flows generated by the project outputs were estimated, taking the difference between capital, operational and tax outflows against the incremental revenue generated by the project outputs. The financial reevaluation was done for an operational period of 25 years, and respective implementation periods of project outputs. Annual costs were obtained from audited project financial statements, and all cash inflows and outflows to the project were estimated at their constant 2020 prices in Sri Lankan Rupees (SLRs). 3. The three investment related outputs of the project are: i) Transmission infrastructure expansion in Northern province, ii) Transmission and distribution efficiency improvement, and iii) Implementing solar rooftop pilot. The financial reevaluation re-calculated the financial internal rate of returns (FIRRs) of all project outputs and the overall project. The re-calculated FIRRs were compared against the weighted average cost of capital (WACC) of respective project outputs to ascertain whether the investments made on the project yield sufficient returns to meet the financial commitments made by the executing agencies in securing financing for the project.

Project Costs

4. Capital costs: The larger share of capital investments made on the project was financed by ADB. The Government of Sri Lanka (government) disbursed counterpart funding through the executing agencies mainly to meet the local expenses. 5. The capital costs considered in the financial reevaluation included expenditure on civil works, equipment, environmental and social safeguards, project management, implementation consultants and taxes. Actual project costs recorded in their nominal terms were converted to constant 2020 by adjusting for inflation. Table A13.1 shows the annual expenditure made on the project in constant 2020 prices.

Table A13.1: Project Capital Costs

(SLRs million) 2013 2014 2015 2016 2017 2018 2019 2020 Total

Output 1 - 112 729 676 1,805 500 1,217 - 5,039 Output 2 69 725 1,710 5,794 5,070 1,959 2,023 544 17,895 Output 3 - 6 13 99 131 37 15 22 323 Total 69 843 2,451 6,569 7,007 2,497 3,255 566 23,257

Output 1: Transmission infrastructure expansion in Northern province; Output 2: Transmission and distribution efficiency improvement; Output 3: Implementing solar rooftop pilot. Note: Numbers may not sum precisely because of rounding. Sources: Audited Project Financial Statements prepared and submitted to ADB by Ceylon Electricity Board and ADB disbursement records.

1 ADB. 2019. Financial Analysis and Evaluation Technical Guidance Note. Manila.

Appendix 13 77

6. Replacement Cost. Solar photovoltaic (PV) inverters installed under output 3 are expected to be replaced every 10 years. It was assumed that the replacement cost of the inverters would be 5% of the total capital cost of output 3. 7. Operation and maintenance (O&M) costs. An incremental annual operation and maintenance (O&M) cost equivalent to 1.5% of the investment was considered for transmission assets acquired through output 1. For transmission and distribution assets acquired under output 2, 2.0% of the investment was considered as the annual O&M cost. Similarly, O&M cost of solar PV equipment in output 3 was considered as 0.5% of the investment. 8. Tax. Ceylon Electricity Board (CEB), the executing agency of project outputs 1 and 2, is liable to pay a 28% tax on its taxable income.2 On the other hand, new transmission and distribution assets acquired by CEB generates a taxable income equivalent to 2% of the asset value. Assuming a 30-year straight-line depreciation of the new transmission and distribution assets, the incremental taxes payable by CEB due to the project were estimated. However, considering the benefit of output 3 is limited to the reduction in electricity bills paid by the industries taking part in the pilot project, no tax costs were included under output 3.

Project Benefits

9. Benefits of Outputs 1 and 2. According to the Tariff Methodology approved and implemented by the Public Utilities Commission of Sri Lanka in accordance with the Sri Lanka Electricity Act of 2009, the financial benefit of outputs 1 and 2 is the increase in revenue allowed to be recovered by CEB through its consumer tariff. This allowed revenue is the sum of operation and maintenance costs, depreciation, loan interest, a return on the regulatory asset base according to the capital structure, working capital and taxes.3 10. Benefits of Output 3. Financial benefit of output 3 is the decrease in electricity bills paid to the utility by the industrial and commercial electricity consumers who installed solar PV system under project output 3. Therefore, the financial benefit of the electricity generated by the solar PV is valued at the average tariff payable by these consumers (SLRs16.4).4

Financial Internal Rate of Return

11. Net cash flows expected due to the project were estimated for each year over the assessment period from 2013 to 2044 and the FIRR was calculated for each project output separately. Table A13.2, Table A13.3, and Table A13.4 gives the estimated cashflows of the three project outputs while Table A13.5 gives the estimated cashflows of the overall project across the assessment period.

Table A13.2: Cashflow Estimates of Project Output 1 (SLRs million)

Year Costs Benefits

Net Cash Flow Capital Cost

Replacement Cost

O&M Cost

Tax Incremental

Revenue 2013 - - - - - - 2014 112 - - - - (112) 2015 729 - - - 5 (724) 2016 676 - - - 40 (636) 2017 1,805 - - - 83 (1,723)

2 Ceylon Electricity Board. 2017. Annual Report 2016. Colombo. 3 Public Utilities Commission of Sri Lanka. 2015. Tariff Methodology. Colombo. 4 Ceylon Electricity Board. 2019. Sales and Generation Data Book-2018. Colombo.

78 Appendix 13

Year Costs Benefits

Net Cash Flow Capital Cost

Replacement Cost

O&M Cost

Tax Incremental

Revenue 2018 500 - - - 203 (297) 2019 1,217 - - - 223 (994) 2020 - - 76 39 689 574 2021 - - 76 38 689 576 2022 - - 76 37 630 518 2023 - - 76 35 605 494 2024 - - 76 34 588 478 2025 - - 76 33 568 460 2026 - - 76 31 548 441 2027 - - 76 30 528 422 2028 - - 76 29 507 403 2029 - - 76 27 487 384 2030 - - 76 26 467 365 2031 - - 76 25 447 346 2032 - - 76 24 427 328 2033 - - 76 22 407 309 2034 - - 76 21 386 290 2035 - - 76 20 366 271 2036 - - 76 18 346 252 2037 - - 76 17 326 233 2038 - - 76 16 306 214 2039 - - 76 14 293 203 2040 - - 76 13 289 201 2041 - - 76 12 285 198 2042 - - 76 10 281 195 2043 - - 76 9 276 191 2044 - - 76 8 271 188

FIRR 5.91% () = negative; FIRR = financial internal rate of return; O&M = operation and maintenance

Table A13.3: Cashflow Estimates of Project Output 2 (SLRs million)

Year Costs Benefits

Net Cash Flow Capital Cost

Replacement Cost

O&M Cost

Tax Incremental

Revenue 2013 69 - - - (69) 2014 725 - - - (725) 2015 1,710 - - 39 (1,671) 2016 5,794 - - 142 (5,652) 2017 5,070 - - 536 (4,535) 2018 1,959 - - 873 (1,087) 2019 2,023 - - 941 (1,082) 2020 544 314 139 2,483 1,485 2021 - 314 135 2,500 2,051 2022 - 314 130 2,300 1,856 2023 - 314 125 2,210 1,770 2024 - 314 121 2,146 1,711 2025 - 314 116 2,076 1,646 2026 - 314 111 2,003 1,577 2027 - 314 107 1,930 1,509 2028 - 314 102 1,857 1,441 2029 - 314 97 1,785 1,373 2030 - 314 93 1,712 1,305 2031 - 314 88 1,639 1,237 2032 - 314 84 1,567 1,169 2033 - 314 79 1,494 1,101 2034 - 314 74 1,422 1,033 2035 - 314 70 1,349 965

Appendix 13 79

Year Costs Benefits

Net Cash Flow Capital Cost

Replacement Cost

O&M Cost

Tax Incremental

Revenue 2036 - 314 65 1,277 897 2037 - 314 60 1,204 830 2038 - 314 56 1,131 762 2039 - 314 51 1,087 722 2040 - 314 46 1,073 712 2041 - 314 42 1,059 703 2042 - 314 37 1,042 691 2043 - 314 32 1,025 679 2044 - 314 28 1,009 667

FIRR 6.09% () = negative; FIRR = financial internal rate of return; O&M = operation and maintenance

Table A13.4: Cashflow Estimates of Project Output 3 (SLRs million)

Year Costs Benefits

Net Cash Flow Capital Cost

Replacement Cost

O&M Cost

Tax Incremental

Revenue 2013 - - - - - 2014 6 - - - (6) 2015 13 - 1 1 (13) 2016 99 - 1 2 (98) 2017 131 - 1 17 (116) 2018 37 - 1 37 (1) 2019 15 - 1 43 26 2020 22 - 1 45 22 2021 - - 1 45 44 2022 - - 1 45 43 2023 - - 1 44 43 2024 - - 1 44 43 2025 - 12 1 44 31 2026 - - 1 44 42 2027 - - 1 44 42 2028 - - 1 43 42 2029 - - 1 43 42 2030 - - 1 43 42 2031 - - 1 43 41 2032 - - 1 42 41 2033 - - 1 42 41 2034 - - 1 42 41 2035 - 8 1 42 33 2036 - - 1 42 40 2037 - - 1 41 40 2038 - - 1 41 40 2039 - - 1 41 40 2040 - - 1 41 40 2041 - - 1 41 39 2042 - - 1 40 39 2043 - - 1 40 39 2044 - - 1 40 39

FIRR 12.55% () = negative; FIRR = financial internal rate of return; O&M = operation and maintenance

Table A13.5: Project Cashflow Estimates (SLRs million)

Year Costs Benefits

Net Cash Flow Capital Cost

Replacement Cost

O&M Cost

Tax Incremental

Revenue 2013 69 - - - - - (69)

80 Appendix 13

Year Costs Benefits

Net Cash Flow Capital Cost

Replacement Cost

O&M Cost

Tax Incremental

Revenue 2014 843 - - - - - (843) 2015 2,451 - 1 - 45 45 (2,408) 2016 6,569 - 1 - 184 184 (6,386) 2017 7,007 - 1 - 635 635 (6,373) 2018 2,497 - 1 - 1,112 1,112 (1,385) 2019 3,255 - 1 - 1,206 1,206 (2,050) 2020 566 - 391 178 3,217 3,217 2,082 2021 - - 391 172 3,234 3,234 2,671 2022 - - 391 166 2,975 2,975 2,418 2023 - - 391 161 2,859 2,859 2,308 2024 - - 391 155 2,778 2,778 2,232 2025 - 12 391 149 2,688 2,688 2,137 2026 - - 391 143 2,594 2,594 2,061 2027 - - 391 137 2,501 2,501 1,973 2028 - - 391 131 2,408 2,408 1,886 2029 - - 391 125 2,315 2,315 1,799 2030 - - 391 119 2,222 2,222 1,712 2031 - - 391 113 2,129 2,129 1,625 2032 - - 391 107 2,036 2,036 1,538 2033 - - 391 101 1,943 1,943 1,451 2034 - - 391 95 1,850 1,850 1,364 2035 - 8 391 89 1,757 1,757 1,269 2036 - - 391 83 1,664 1,664 1,190 2037 - - 391 77 1,571 1,571 1,103 2038 - - 391 71 1,478 1,478 1,016 2039 - - 391 65 1,421 1,421 965 2040 - - 391 59 1,403 1,403 952 2041 - - 391 54 1,384 1,384 940 2042 - - 391 48 1,363 1,363 924 2043 - - 391 42 1,341 1,341 909 2044 - - 391 36 1,320 1,320 893

FIRR 6.16% () = negative; FIRR = financial internal rate of return; O&M = operation and maintenance

Results of Project Financial Re-evaluation

12. To ascertain the sustainability of the Project in the longer term, the reevaluated project FIRR was compared against the financial opportunity cost of capital (FOCC). Since the financial reevaluation was carried out for the entire project investment financed collectively by the government, the ADB, and the executing agencies, the real post-tax WACC is used as a proxy for the FOCC. 13. The main source of funding for the project was the ADB loan obtained by the government, which was on-lent to the respective executing agencies to implement the project. Nominal costs of debt are the interest rates offered by the government to the borrower executing agencies. Standard yield of 10-year government treasury bonds with an additional 1.5% risk premium was considered as the nominal cost of equity sourced from the government. For the grant funding provided by the ADB, the standard yield of 10-year government treasury bonds was considered as the opportunity cost of capital. The applicable tax rate for Ceylon Electricity Board was used to calculate the tax-adjusted nominal cost of outputs 1 and 2. However, no tax adjustments were made for output 3, as the benefits derived from output 3 does not entail any taxes (para. 8). Real costs of different sources of funds were estimated using the international and domestic inflation

Appendix 13 81

rates of 1.5% and 4.2% respectively.5 As presented in Table A13.6, the WACC of the overall project was estimated at 4.85%.

Table A13.6: Weighted Average Cost of Capital of the Overall Project

ADB Loan (Outputs 1

and 2)

ADB Loan (Output 3)

Grant

Government of Sri Lanka

and Stakeholders

(Equity)

Total

A. Amount (SLR million) 17,402 137

149 29

17,717

B. Weighting 98.22% 0.77% 0.84% 0.16% 100.00% C. Nominal cost 8.85% 8.85% 9.99% 11.49% D. Income tax rate 28.00% 0.00% 0.00% 0.00% E. Tax-adjusted nominal cost [D x (1 - E)] 6.37% 8.85% 9.99% 11.49% F. Inflation rate 1.50% 1.50% 1.50% 4.20% G. Real cost [(1+F) / (1+G) - 1] 4.80% 7.24% 8.36% 7.00% H. Weighted component of WACC 4.72% 0.06% 0.07% 0.01% 4.85%

ADB = Asian Development Bank; SLR = Sri Lanka Rupee; WACC = weighted average cost of capital

14. The reevaluated FIRR of 6.16% exceeds the reassessed project WACC of 4.85%, implying the overall project to be financially sustainable in the long term. Table A13.7 compares the WACC and FIRR of individual project outputs.

Table A13.7: Comparison of FIRR and WACC of Project Outputs Output FIRR WACC 1: Transmission infrastructure expansion in the Northern province 5.91% 4.80% 2: Transmission and distribution efficiency improvement 6.09% 4.80% 3: Implementing solar rooftop pilot 12.55% 7.75% Overall Project 6.16% 4.85%

FIRR = financial internal rate of return; SLR = Sri Lanka Rupee; WACC = weighted average cost of capital

Sensitivity Analysis

15. A sensitivity analysis was performed to test the robustness of the overall project against adverse conditions. An increase in O&M cost, decrease in capacity factors (electricity generation) of rooftop solar systems and the wind power plant do not make significant impacts on the project FIRR. According to the results of the sensitivity analysis conducted of the three project outputs as given in Table A13.8, Table A13.9, and Table A13.10, the financial sustainability of all three project components is expected to be robust against adverse changes to the identified key project parameters. This is mainly because, cashflows related to output 1 and output 2 are based on the tariff methodology which allows these changes to be passed through to the consumers without affecting the financials of the utilities. Therefore, the overall project is financially robust and sustainable, as depicted in the overall sensitivity analysis given in Table A13.11.

Table A13.8: Sensitivity Analysis of Project Component 1

Parameter Variation FIRR

Base case 5.91%

Increase in O&M costs by further 1% 5.91%

Decrease in solar and wind capacity factors by further 10% 5.91%

Combination of above 5.91% FIRR = financial internal rate of return; O&M = operation and maintenance

5 ADB. Inflation Rate in Asia and the Pacific, Asian Development Outlook (ADO). https://data.adb.org/dataset/inflation-

rate-asia-and-pacific-asian-development-outlook (accessed 11 Aug 2020)

82 Appendix 13

Table A13.9: Sensitivity Analysis of Project Component 2

Parameter Variation FIRR

Base case 6.09%

Increase in O&M costs by further 1% 6.09%

Decrease in solar and wind capacity factors by further 10% 6.09%

Combination of above 6.09% FIRR = financial internal rate of return; O&M = operation and maintenance

Table A13.10: Sensitivity Analysis of Project Component 3

Parameter Variation FIRR

Base case 12.55%

Increase in O&M costs by further 1% 11.25%

Decrease in solar and wind capacity factors by further 10% 10.96%

Combination of above 9.67% FIRR = financial internal rate of return; O&M = operation and maintenance

Table A13.11: Sensitivity Analysis of the Overall Project Parameter Variation FIRR

Base case 6.16%

Increase in O&M costs by further 1% 6.15%

Decrease in solar and wind capacity factors by further 10% 6.13%

Combination of above 6.12%

FIRR = financial internal rate of return; O&M = operation and maintenance

Entity Financial Sustainability

16. Apart from the financial assessment of the investment project, the financial sustainability of CEB is also relevant for the overall assessment of project sustainability. With the regulated tariff methodology ensuring the costs to be recovered through tariffs, the financial sustainability of CEB is guaranteed.

17. According to the tariff methodology, if passing through of costs to the end use customers is not fully implemented, the shortfall will be provided by the government, effectively subsidizing the electricity consumers, without burdening CEB. Therefore, the long-term sustainability of CEB is ensured, not only through the ownership of the government, but also through the regulated tariffs, where investments and operational expenses are allowed to be recovered.